Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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Received by James B
on 12/10/2024 at 9:20am
Completed
11/13/2024
JSB
RBDMS JSB 121624
G
JJL 5/6/25 A.Dewhurst 04MAR25 DSR-4/7/25
Digitally signed by Sean
McLaughlin (4311)
DN: cn=Sean McLaughlin (4311)
Date: 2024.12.09 17:19:09 -
09'00'
Sean
McLaughlin
(4311)
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: 12/04/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL:
PBU M-206
PTD: 224-130
API: 50-029-23804-00-00
FINAL LWD FORMATION EVALUATION + GEOSTEERING (10/21/2024 to 11/05/2024)
x ROP, BaseStar & ABG Gamma Ray, ResiStar &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-206 LWD Subfolders:
PBU M-206 Geosteering Subfolders:g
Please include current contact information if different from above.
224-130
T39805
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.12.04 13:45:57 -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: 11/15/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL :
PBU M-206
PTD: 224-130
API: 50-029-23804-00-00
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
SFTP Transfer – Main Folders:
Please include current contact information if different from above.
224-130
T39773
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.11.15 11:23:46 -09'00'
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________PRUDHOE BAY UN POL M-206
JBR 12/19/2024
MISC. INSPECTIONS:
FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK:
ACCUMULATOR SYSTEM:MUD SYSTEM:
P/F P/F
P/FP/FP/F
Visual Alarm
QuantityQuantity
Time/Pressure
SizeQuantity
Number of Failures:2
Took a while to get a good shell test after ND diverter and NU stack. Tested BOPE with 3 1/2",5" and 7" test joints. FP on test 2
Upper rams, C/O upper seal and retest , Pass. FP on on inside kill test #4, grease retest and pass. Tested H2s and pvt's . Gas
alarms calibrated 10/28/24. No other issues
Test Results
TEST DATA
Rig Rep:Matt VanhooseOperator:Hilcorp North Slope, LLC Operator Rep:Chris Yearout
Rig Owner/Rig No.:Hilcorp Innovation PTD#:2241300 DATE:10/29/2024
Type Operation:DRILL Annular:
250/3000Type Test:INIT
Valves:
250/3000
Rams:
250/3000
Test Pressures:Inspection No:bopSTS241031055120
Inspector Sully Sullivan
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 8
MASP:
1740
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 FP
#2 Rams 1 Blinds P
#3 Rams 1 7" solid P
#4 Rams 0 NA
#5 Rams 0 P
#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"FP
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P3000
Pressure After Closure P1475
200 PSI Attained P32
Full Pressure Attained P110
Blind Switch Covers:Pall stations
Bottle precharge P
Nitgn Btls# &psi (avg)P6@ 2300
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
FP
FP
Took a while to get a good shell test after ND diverter and NU stack. Tested BOPE with 3 1/2",5" and 7" test joints. FP on test 2
Upper rams, C/O upper seal and retest , Pass. FP on on inside kill test #4, grease retest and pass. Tested H2s and pvt's . Gas Upper rams, C/O upper seal and retest , Pass. FP on on inside kill test #4, grease retest and pass. Tested H2s and pvt's . Gas
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:20241024 1134 PBU M-206 (PTD: 224-130) Diverter Variance Request
Date:Monday, October 28, 2024 10:56:58 AM
From: Rixse, Melvin G (OGC)
Sent: Thursday, October 24, 2024 11:34 AM
To: Joseph Engel <jengel@hilcorp.com>
Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; DOA AOGCC Prudhoe Bay
<doa.aogcc.prudhoe.bay@alaska.gov>
Subject: RE: HAK PBU M-206 (PTD: 224-130) Diverter Variance Request
Joe,
Hilcorp is approved to temporarily remove a 20’ section of diverter as described
below.
Mel Rixse
Senior Petroleum Engineer (PE)
Alaska Oil and Gas Conservation Commission
907-793-1231 Office
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: Joseph Engel <jengel@hilcorp.com>
Sent: Monday, October 21, 2024 7:03 PM
To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Subject: HAK PBU M-206 (PTD: 224-130) Diverter Variance Request
Mel –
Once the Innovation rig moved in and rigged up on PBU M-206, it was found that the
diverter line would be blocking the side of the rig where the cement silos, vac trucks, and
pump truck are staged for the surface cement job. We were able to stage the silos ahead
of time, however the pump unit and vac trucks were not able to be stranded for the ~7
days between spud and pumping cement. The Innovation is requesting a diverter
variance on M-206, similar to what has been approved in the past.
Specifically, the Innovation is requesting a variance on PBU M-206 to temporarily remove
a 20’ section of vent line after running 9-5/8” casing to surface TD. The section of vent
line would be removed once casing is on depth and a minimum of 1.5 bottoms up have
been circulated to ensure any and all gas/hydrocarbons have been cleared from the
wellbore. The section of vent line needs to be removed to gain access to the side of the
location for cement equipment to be placed to perform the surface cement job. The 20
foot section would be removed in the middle of the line and would put the nearest end of
the break roughly 40’ from the wellhead. The section would be removed long enough to
mobilize cement equipment (units, vac trucks, etc) and then would be reinstalled prior
to pumping the first stage cement job. The rig will continue to circulate while the section
is removed, and mud weight will not be reduced while the diverter has been shortened.
The diverter section will be re-installed prior to cementing.
Attached is the approval email from MPU S-46 in 2021 when a similar variance was
approved.
Please let me know if you have any questions.
Thank you for your time.
-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 deletethis message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility
is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M. Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK, 99503
Re: Prudhoe Bay Field, Polaris Oil Pool, PBU M-206
Hilcorp Alaska, LLC
Permit to Drill Number: 224-130
Surface Location: 3599' FSL, 4695' FEL, Sec 06, T11N, R13E, UM, AK
Bottomhole Location: 1166' FNL, 800' FWL, Sec 26, T12N, R12E, UM, AK
DearMr. Myers:
Enclosed is the approved application for the permit to drill the above referenced 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 an AOGCCorder, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
-HVVLH/&KPLHORZVNL
Commissioner
DATED this 17th day of October 2024.
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2024.10.17 13:20:57
-08'00'
Digitally signed by Sean
McLaughlin (4311)
DN: cn=Sean McLaughlin (4311)
Date: 2024.10.08 15:45:27 -
08'00'
Sean
McLaughlin
(4311)
2
7
1166 800
12784 19154
By Grace Christianson at 4:15 pm, Oct 08, 2024
See attached emails.
-A.Dewhurst 16OCT24
* BOPE pressure test to 3000 psi. Annular to 2500 psi.
* Casing test and FIT digital data to AOGCC immediately upon completion of
performing FIT.
7,589
A.Dewhurst 16OCT24 DSR-10/10/24
& ADL028282
224-130 50-029-23804-00-00
MGROCT172024
* Gyro MWD to be utilized when drilling past 10,000' MD or when proximity to offset well M-200
is less than 70' center to center.
* Approved to utilize geo-steering and gyro MWD to twin offset well PBU M-200 which fails standard proximity scans. Gyro MWD to be utilized to
assure azimuthal uncertainty within industry standards.
SJC for GCW 10/17/24
Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski
Date: 2024.10.17 13:21:10 -08'00'
10/17/24
10/17/24
RBDMS JSB 102124
Prudhoe Bay West
(PBU) M-206
Drilling Permit
Version 1
10/3/2024
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 .................................................................................................... 10
10.0 N/U 13-5/8” 5M Diverter System ............................................................................................ 11
11.0 Drill 12-1/4” Hole Section ....................................................................................................... 13
12.0 Run 9-5/8” Surface Casing ..................................................................................................... 16
13.0 Cement 9-5/8” Surface Casing ................................................................................................ 22
14.0 ND Diverter, NU BOPE, & Test ............................................................................................. 27
15.0 Drill 8-1/2” Hole Section ......................................................................................................... 28
16.0 Run 5-1/2” x 4-1/2” Screen Liner ........................................................................................... 33
17.0 Run 7” Tieback ....................................................................................................................... 38
18.0 Run Upper Completion/ Post Rig Work ................................................................................ 41
19.0 Innovation Rig Diverter Schematic ........................................................................................ 44
20.0 Innovation Rig BOP Schematic .............................................................................................. 45
21.0 Wellhead Schematic ................................................................................................................ 46
22.0 Days Vs Depth ......................................................................................................................... 47
23.0 Formation Tops & Information.............................................................................................. 48
24.0 Anticipated Drilling Hazards ................................................................................................. 49
25.0 Innovation Rig Layout ............................................................................................................ 53
26.0 FIT Procedure ......................................................................................................................... 54
27.0 Innovation Rig Choke Manifold Schematic ........................................................................... 55
28.0 Casing Design .......................................................................................................................... 56
29.0 8-1/2” Hole Section MASP ...................................................................................................... 57
30.0 Spider Plot (NAD 27) (Governmental Sections) ..................................................................... 58
31.0 Surface Plat (As Staked) (NAD 27) ........................................................................................ 59
Page 2
Prudhoe Bay West
M-206 SB Producer
Drilling Procedure
1.0 Well Summary
Well PBU M-206
Pad Prudhoe Bay M Pad
Planned Completion Type 3-1/2” Gas Lift
Target Reservoir(s) Schrader Bluff OA Sand
Planned Well TD, MD / TVD 19,154’ MD / 5162’ TVD
PBTD, MD / TVD 19,144’ MD / 5162’ TVD
Surface Location (Governmental) 3599' FSL, 4695' FEL, Sec 06, T11N, R13E, UM, AK
Surface Location (NAD 27) X= 629,007.23,Y=5,974,689.03
Top of Productive Horizon
(Governmental)882' FNL, 2371' FWL, Sec 01, T11N, R12E, UM, AK
TPH Location (NAD 27) X=625889.8, Y=5975434.7
BHL (Governmental) 1166' FNL, 800' FWL, Sec 26, T12N, R12E, UM, AK
BHL (NAD 27) X= 618864.2, Y= 5985595.6
AFE Number 241-00158
AFE Drilling Days 25
AFE Completion Days 4
Maximum Anticipated Pressure
(Surface) 1740 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 2272 psig
Work String 5” 19.5# S-135 NC 50
Innovation KB Elevation above MSL: 26.5 ft + 25.0 ft = 51.7 ft
GL Elevation above MSL: 25.2 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
Page 3
Prudhoe Bay West
M-206 SB Producer
Drilling Procedure
2.0 Management of Change Information
Page 4
Prudhoe Bay West
M-206 SB Producer
Drilling Procedure
3.0 Tubular Program:
Hole
Section
OD (in)ID
(in)
Drift
(in)
Conn OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 20” 19.25”---X-52Weld
12-1/4”9-5/8” 8.835” 8.679”10.625”40 L-80 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-80 563 7,240 5,410 604
8-1/2” 5-1/2” 4.892 4.767 6.05 17 L-80 JFEBear 7740 6290 318
4-1/2” 3.958 3.833 5 12.6 L-80 JFEBear 8430 7500 288
Tubing 3-1/2” 2.992 2.867 3.883 9.2 L-80
JFEBear 10160 10540 207
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-206 SB Producer
Drilling Procedure
5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on WellEz.
Report covers operations from 6am to 6am
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.
Ensure time entry adds up to 24 hours total.
Try to capture any out of scope work as NPT. This helps later on when we pull end of well
reports.
Enter the MD and TVD depths EVERY DAY whether you are making hole or not.
5.2 Afternoon Updates
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
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
Health and Safety: Notify EHS field coordinator.
Environmental: Drilling Environmental Coordinator
Notify Drilling Manager & Drilling Engineer on all incidents
Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
Send final “As-Run” Casing tally to mmyers@hilcorp,com jengel@hilcorp.com and
joseph.lastufka@hilcorp.com
5.6 Casing and Cement report
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 Wyatt Rivard 907.777.8547 wrivard@hilcorp.com
Geologist Kevin Eastham 907.777.8316 keastham@hilcorp.com
Reservoir Engineer Michael Mayfield 907.564.5097 mmayfield@hilcorp.com
Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com
_____________________________________________________________________________________
Revised By: TJS 10/7/2024
PROPOSED SCHEMATIC
Prudhoe Bay Unit
Well: PBU M-206
Last Completed: TBD
PTD: TBD
TD =19,154’ (MD) / TD =5,162’ (TVD)
5
20”
Orig. KB Elev.: 51.5’ / GL Elev.: 25.0’
4
7
9-5/8”
1
2
3
See
Screen
Liner
Detail
14
PBTD = 19,144’ (MD) / PBTD = 5,162’ (TVD)
9-5/8”‘ES’
Cementer @
±2,500’
11
12
13
10
6
9
8
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20" Conductor 129.5 / X52 / Weld N/A Surface 110’ 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’ 6,500’ 0.0758
7” Tieback 26 / L-80 / H563 6.276 Surface 6,350’ 0.0383
5-1/2” Liner 17 / L-80 / JFE Bear 4.892 6,370’ 10,250’ 0.0232
4-1/2” Liner 12.6 / L-80 / JFE Bear 3.958 10,250’ 19,154’ 0.0152
TUBING DETAIL
3-1/2" Tubing 9.2# / L-80 / JFE Bear 2.992 Surface 5,740’ 0.0087
3-1/2” Tubing 9.2# / 13Cr / JFE Bear 2.992 5,740’ 6,390’ 0.0087
OPEN HOLE / CEMENT DETAIL
Driven Conductor
12-1/4"Stg 1 – Lead – 519 sx / Tail – 395 sx
Stg 2 – Lead – 763 sx / Tail – 270 sx
8-1/2” Cementless Liner
WELL INCLINATION DETAIL
KOP @ 300’
90° Hole Angle = @ 7,900’ 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 2,700 X Nipple 2.813”
2 3,200 GLM 2.950”
3 4,300 GLM 2.950”
4 4,900 GLM 2.950”
5 5,650 GLM 2.950”
6 5,680 X Nipple 2.813”
7 5,710 Pressure Gauge 2.867”
8 5,740 Production Packer 3.860”
9 5,800 X Nipple 2.813”
10 6,390 WLEG / Muleshoe 2.990”
11 6,350 7” x 9-5/8” Liner Hanger w/ Tieback Sleeve 6.160”
12 6,350 Liner Top Packer 6.180”
13 6,370 7” x 5-1/2” XO 4.860”
14 10,250 5-1/2” x 4-1/2” XO 3.920”
*All depths are approximate and are subject to change based on actual drilled
depths.
Screen Detail
Size SPF Top (MD) Btm (MD) Type
5-1/2” SOLID 6,370 6,500 Base Pipe
5-1/2” SCRN 6,500 10,250 100
4-1/2” SCRN 10,250 19,167 100
Page 7
Prudhoe Bay West
M-206 SB Producer
Drilling Procedure
7.0 Drilling / Completion Summary
PBU M-206 is a grassroots producer planned to be drilled in the Schrader Bluff OA sands. M-206 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. A screen liner will be run in the open hole section,
followed by a 7” tieback and 3-1/2” gas lift tubing.
The Innovation Rig will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately October 18, 2024, pending rig schedule.
Surface casing will be run to 6,500’ MD / 5,119’ 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 screen 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-206 SB Producer
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.
BOPs shall be tested at (2) week intervals during the drilling and completion of PBU M-206.
Ensure to provide AOGCC 24 hrs notice prior to testing BOPs.
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.
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.
All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program
and drilling fluid system”.
All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”.
o Ensure the diverter vent line is at least 75’ away from potential ignition sources
Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
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)”.
AOGCC Regulation Variance Requests:
No variances requested at this time.
Page 9
Prudhoe Bay West
M-206 SB Producer
Drilling Procedure
Summary of Innovation BOP Equipment & Test Requirements
Hole Section Equipment Test Pressure (psi)
12-1/4”13-5/8” 5M CTI Annular BOP w/ 16” diverter line Function Test Only
8-1/2”
13-5/8” x 5M Control Technology Inc Annular BOP
13-5/8” x 5M Control Technology Inc Double Gate
o Blind ram in btm cavity
Mud cross w/ 3” x 5M side outlets
13-5/8” x 5M Control Technology Single ram
3-1/8” x 5M Choke Line
3-1/8” x 5M Kill line
3-1/8” x 5M Choke manifold
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:
Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
24 hours notice prior to spud.
24 hours notice prior to testing BOPs and changing rams
24 hours notice prior to casing running & cement operations.
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)
Page 10
Prudhoe Bay West
M-206 SB Producer
Drilling Procedure
9.0 R/U and Preparatory Work
9.1 M-206 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 (<80 F).
Cold mud temps are necessary to mitigate hydrate breakout
9.10 Ensure 5” liners in mud pumps.
White Star Quattro 1,300 HP mud pumps are rated at 4,097 psi, 381 gpm @ 140 spm @
96.5% volumetric efficiency.
Page 11
Prudhoe Bay West
M-206 SB Producer
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).
N/U 20” x 13-5/8” DSA
N/U 13 5/8”, 5M diverter “T”.
NU Knife gate & 16” diverter line.
Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
Diverter line must be 75 ft from nearest ignition source
Place drip berm at the end of diverter line.
Utilized extensions if needed.
10.2 Notify AOGCC with 24 hour notice to witness. Function test diverter.
Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens
prior to annular closure – AOGCC Regulation requirement
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:
A prohibition on vehicle parking
A prohibition on ignition sources or running equipment
A prohibition on staged equipment or materials
Restriction of traffic to essential foot or vehicle traffic only.
Page 12
Prudhoe Bay West
M-206 SB Producer
Drilling Procedure
10.4 Rig & Diverter Orientation:
May change on location
Page 13
Prudhoe Bay West
M-206 SB Producer
Drilling Procedure
11.0 Drill 12-1/4” Hole Section
11.1 P/U 12-1/4” directional drilling assembly:
Ensure BHA components have been inspected previously.
Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
Ensure TF offset is measured accurately and entered correctly into the MWD software.
Consider running a UBHO sub for wireline gyro.GWD will be the primary gyro tool.
Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
Drill string will be 5” 19.5# S-135.
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.
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.
Monitor the area around the conductor for any signs of broaching. If broaching is observed,
Stop drilling (or circulating) immediately notify Drilling Engineer.
Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100.
Hold a safety meeting with rig crews to discuss:
Conductor broaching ops and mitigation procedures.
Well control procedures and rig evacuation
Flow rates, hole cleaning, mud cooling, etc.
Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
Keep mud as cool as possible to keep from washing out permafrost.
Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can
handle the flow rate.
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.
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
Slow in/out of slips and while tripping to keep swab and surge pressures low
Ensure shakers are functioning properly. Check for holes in screens on connections.
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.
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.
Perform gyro surveys until clean MWD surveys are seen. Take MWD surveys every stand
drilled.
Page 14
Prudhoe Bay West
M-206 SB Producer
Drilling Procedure
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:
Keep mud temperature as cool as possible, Target 60-70*F.
Dump and dilute as necessary to maintain temp, utilize cold water on the rig as well as
cold pre-made mud on trucks ready.
Drill through hydrate sands and quickly as possible, do not backream.
Gas hydrates can be identified by the gas detector and a decrease in MW or ECD
Monitor returns for hydrates, checking pressurized & non-pressurized scales
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.
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.
Take MWD and GWD surveys every stand until magnetic interference cleans up. After
MWD surveys show clean magnetics, only take MWD surveys.
Surface Hole AC, CF <1.0 :
M-06PB1 is an open hole plugback, there is no risk
11.4 12-1/4” hole mud program summary:
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)
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.
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.
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.
Page 15
Prudhoe Bay West
M-206 SB Producer
Drilling Procedure
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.
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
Pump at full drill rate (400-600 gpm), and maximize rotation.
Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions
Monitor well for any signs of packing off or losses.
Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay
balling.
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.
Page 16
Prudhoe Bay West
M-206 SB Producer
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)
Ensure 9-5/8” TXP x NC50 XO on rig floor and M/U to FOSV.
Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
R/U of CRT if hole conditions require.
R/U a fill up tool to fill casing while running if the CRT is not used.
Ensure all casing has been drifted to 8.75” on the location prior to running.
Top 2,500’ of casing 47# drift 8.525”
Actual depth to be dependent upon base of permafrost and stage tool
Be sure to count the total # of joints on the location before running.
Keep hole covered while R/U casing tools.
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
Ensure bypass baffle is correctly installed on top of float collar.
Ensure proper operation of float equipment while picking up.
Ensure to record S/N’s of all float equipment and stage tool components.
This end up.
Bypass Baffle
Page 17
Prudhoe Bay West
M-206 SB Producer
Drilling Procedure
12.5 Float equipment and Stage tool equipment drawings:
Page 18
Prudhoe Bay West
M-206 SB Producer
Drilling Procedure
12.6 Continue running 9-5/8” surface casing
Fill casing while running using fill up line on rig floor.
Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
Centralization:
Bowspring Centralizers only
1 centralizer every joint to ~ 1000’ MD from shoe
1 centralizer every 2 joints to ~2,000’ above shoe (Top of Lowest Ugnu)
Verify depth of lowest Ugnu water sand for isolation with Geologist
Utilize a collar clamp until weight is sufficient to keep slips set properly.
Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
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)
Install centralizers over couplings on 5 joints below and 5 joints above stage tool.
Do not place tongs on ES cementer, this can cause damaged to the tool.
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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M-206 SB Producer
Drilling Procedure
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12.8 Continue running 9-5/8” surface casing
Centralizers: 1 centralizer every 3rd joint to 200’ from surface
Fill casing while running using fill up line on rig floor.
Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
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
Actual length of 47# may change due to depth of permafrost as drilled
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.
How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
Ensure adequate amounts of water for mix fluid is heated and available in the water tanks.
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
Review test reports and ensure pump times are acceptable.
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 (6500'-1,000'-2,500') x 0.0558 bpf x 1.3 217.5 1220.5
Total Lead 217.5 1220.5 519.3
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.
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 + (6,500’-120’-2500’) x .0758 bpf =
= 477.3 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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M-206 SB Producer
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.
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:
Pre flush type, volume (bbls) & weight (ppg)
Cement slurry type, lead or tail, volume & weight
Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
Note if casing is reciprocated or rotated during the job
Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
Note if pre flush or cement returns at surface & volume
Note time cement in place
Note calculated top of cement
Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to 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:
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
Double gate ram should be dressed with 4-1/2” x 7” VBRs in top cavity,blind ram in
bottom cavity.
Single ram can be dressed with 2-7/8” x 5-1/2” VBRs or 5” solid body rams
NU bell nipple, install flowline.
Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to
mud cross).
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.
Test with 5” test joint and test VBR’s with 3-1/2” test joint
Confirm test pressures with PTD
Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure
is trapped underneath test plug
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.
12.0 ppg desired to cover shoe strength for expected ECDs. A 9.8 ppg FIT is the minimum
required to drill ahead
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.
Ensure BHA components have been inspected previously.
Drift and caliper all components before MU. Visually verify no debris inside components that
cannot be drifted.
Ensure TF offset is measured accurately and entered correctly into the MWD software.
Ensure MWD is RU and operational.
Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
Drill string will be 5” 19.5# S-135 NC50.
Run a ported float in the production hole section.
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:
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.
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.
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
Run the centrifuge continuously while drilling the production hole, this will help with
solids removal.
Dump and dilute as necessary to keep drilled solids to an absolute minimum.
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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M-206 SB Producer
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
Density may change based upon TD of surface hole section
15.14 Begin drilling 8-1/2” hole section, on-bottom staging technique:
Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K.
Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations
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.
Flow Rate: 350-550 GPM, target min. AV’s 200 ft/min, 385 GPM
RPM: 120+
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.
Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
Monitor Torque and Drag with pumps on every 5 stands
Monitor ECD, pump pressure & hookload trends for hole cleaning indication
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.
Use ADR to stay in section. Reservoir plan is to stay in OA sand.
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.
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Drilling Procedure
Target ROP is as fast as we can clean the hole without having to backream connections
Schrader Bluff OA Concretions: 4-6% Historically
MPD will be utilized to monitor pressure build up on connections.
8-1/2” Lateral A/C, CF < 1.0:
M-200 is a well in the SB Oba sand, we will have geologic separation from this well.
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.
Patience is key! Getting kicked off too quickly might have been the cause of failed liner
runs on past wells.
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.
Attempt to lowside in a fast drilling interval where the wellbore is headed up.
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.
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
Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent
stream, circulate more if necessary
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.
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%
Soda Ash: as needed for 9.5pH
Busan 1060: 0.42ppb
Flo-Vis Plus: 1.25ppb
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Drilling Procedure
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
Circulate at full drill rate (less if losses are seen, 350 GPM minimum).
Rotate at maximum RPM that can be sustained.
Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as
dictated by hole conditions
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.
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
If necessary, increase MW at shoe for any higher than expected pressure seen
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.
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 5-1/2” x 4-1/2” Screen 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
screen liner, the following well control response procedure will be followed:
P/U & M/U the 5” safety joint (with 4-1/2” or 5-1/2” crossover installed on bottom, TIW
valve in open position on top, 4-1/2” or 5-1/2” handling joint above TIW). This joint shall be
fully M/U and available prior to running the first joint of liner.
Slack off and with 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW.
Proceed with well kill operations.
16.3 R/U liner running equipment.
Ensure all casing has been drifted on the deck prior to running.
Be sure to count the total # of joints on the deck before running.
Keep hole covered while R/U casing tools.
Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
16.4 Run 5-1/2” x 4-1/2” liner
Use API Modified or “Best O Life 2000 AG”thread compound. Dope pin end only w/ paint
brush. Wipe off excess. Thread compound can plug the screens
Utilize a collar clamp until weight is sufficient to keep slips set properly.
Use lift nubbins and stabbing guides for the liner run.
Install joints as per the Running Order (From Completion Engineer post TD).
If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint
outside of the surface shoe.
Obtain up and down weights of the liner before entering open hole. Record rotating torque at
10 and 20 rpm
Screen Liner Torque – ftlbs
OD PPF Connection Minimum Optimum Maximum Yield
Torque
5-1/2 17 JFEBear 6660 7400 8140 11100
4-1/2 12.6 JFEBear 4860 5400 5940 8100
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M-206 SB Producer
Drilling Procedure
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16.6. For buckling mitigation, the last ~ 3400’ MD of screen liner will be 5-1/2”, ensure XO is
available
16.7. Ensure to run enough liner to provide for sufficient overlap inside 9-5/8” casing for gas lift
completion. Tentative liner set depth ~ 6,350’ MD
Confirm set depth with completion engineer.
3-5 joints of 7” may be ran under the liner hanger for the production packer. Confirm with
completion engineer.
16.8. Ensure hanger/pkr will not be set in a 9-5/8” connection.
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.
16.9. Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck
to make sure it coincides with the pipe tally.
16.10. M/U Baker SLZXP liner top packer to liner.
Confirm with OE any 7” joints between liner top packer and screen liner for GLM
and packer setting depth
16.11. 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.
16.12. 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.
Ensure 5” DP/HWDP has been drifted
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.
Use HWDP as needed for running liner
16.13. 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.
16.14. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
& 20 RPM.
16.15. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
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Drilling Procedure
16.16. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
16.17. Rig up to pump down the work string with the rig pumps.
16.18. Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed
1,600 psi while circulating.Pusher tool is set at 2,100 psi with 5% shear screws but it should be
discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker
16.19. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill
pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger.
16.20. Shut down pumps. Drop setting ball (ball seat now located in HRDE setting tool and not at the
WIV) down the workstring and pump slowly (1-2 BPM). Slow pump before the ball seats. Do
not allow ball to slam into ball seat.
16.21. Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes.
Slack off 20K lbs on the SZXP liner hanger/packer to ensure the HRDE setting tool is in
compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi
to release the HRDE running tool.
16.22. 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.
16.23. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted.
16.24. 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.
16.25. PU pulling running tool free of the packer and displace with at max rate to wash the liner top.
Pump sweeps as needed.
16.26. POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned,
LD DP on the TOOH.
Note: Once running tool is LD, swap to the completion AFE.
Page 38
Prudhoe Bay West
M-206 SB Producer
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.
Ensure XO to DP made up to FOSV and ready on rig floor.
Rig up computer torque monitoring service.
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 H563 tieback to position seal assembly two joints above tieback sleeve.
Record PU and SO weights.
17.7 Tieback to be Torque turned.
7”, 26#, L-80, H563
=Casing OD Torque (Min) Torque (Opt)Torque (Max) Operating
7”7800 9400 13700 33000
Page 39
Prudhoe Bay West
M-206 SB Producer
Drilling Procedure
Page 40
Prudhoe Bay West
M-206 SB Producer
Drilling Procedure
17.8 MU 7” to DP crossover.
17.9 MU stand of DP to string, and MU top drive.
17.10 Break circulation at 1 BPM and begin lowering string.
17.11 Note seal assembly entering tieback sleeve with a pressure increase, stop pumping and bleed off
pressure. Leave standpipe bleed off valve open.
17.12 Continue lowering string and land out on no-go. Set down 5 – 10K and mark the pipe as “NO-
GO DEPTH”.
17.13 PU string & remove unnecessary 7” joints.
17.14 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.
17.15 PU and MU the 7” casing hanger.
17.16 Ensure circulation is possible through 7” string.
17.17 RU and circulation corrosion inhibited brine in the 9-5/8” x 7” annulus.
17.18 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).
17.19 SO and land hanger. Confirm hanger has seated properly in wellhead. Make note of actual
weight on hanger on morning report.
17.20 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.
17.21 RD casing running tools.
17.22 PT 9-5/8” x 7” annulus to 1,500 psi for 30 minutes charted.
Page 41
Prudhoe Bay West
M-206 SB Producer
Drilling Procedure
18.0 Run Upper Completion/ Post Rig Work
18.1 RU to run 3-1/2”, 9.2#, L-80 JFEBear tubing.
Ensure wear bushing is pulled.
Ensure 3-1/2”, 9.2#, L-80 JFEBear x NC50 crossover is on rig floor and M/U to FOSV.
Ensure all tubing has been drifted in the pipe shed prior to running.
Be sure to count the total # of joints in the pipe shed before running.
Keep hole covered while RU casing tools.
Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info.
Monitor displacement from wellbore while RIH.
18.2 PU, MU and RIH with the following 3-1/2” completion jewelry (tally to be provided by
Operations Engineer):
Tubing Jewelry to include:
1x X Nipple
4x GLM
1x X Nipple
1x Pressure Gauge
1x Production Packer
i. Confirm packer set depth with OE for post rig wire line ball and rod retrieval.
1x X Nipple
XXX joints, 3-1/2”, 9.2#, L-80 JFEBear
WLEG
Page 42
Prudhoe Bay West
M-206 SB Producer
Drilling Procedure
Page 43
Prudhoe Bay West
M-206 SB Producer
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.
18.16 RDMO Innovation
i. POST RIG WELL WORK
1. Slickline
a. Change out GLV per GL ENGR
b. Pull ball and rod and RHC
2. Well Tie in
Page 44
Prudhoe Bay West
M-206 SB Producer
Drilling Procedure
19.0 Innovation Rig Diverter Schematic
Page 45
Prudhoe Bay West
M-206 SB Producer
Drilling Procedure
20.0 Innovation Rig BOP Schematic
Page 46
Prudhoe Bay West
M-206 SB Producer
Drilling Procedure
21.0 Wellhead Schematic
Page 47
Prudhoe Bay West
M-206 SB Producer
Drilling Procedure
22.0 Days Vs Depth
Page 48
Prudhoe Bay West
M-206 SB Producer
Drilling Procedure
23.0 Formation Tops & Information
Reference Plan:
G1 Gravels Water/Ice 371.7 371.7 -320 164
SV6 Sand Ice 1,724.1 1,627.7 -1576 716
BPRF Sand Ice 1,990.4 1,862.7 -1811 820
SV5 Sand Gas Hydrates 2,440.3 2,259.7 -2208 994
SV4 Sand Gas Hydrates 2,645.5 2,440.7 -2389 1074
SV3 Sand Gas Hydrates 3,090.9 2,833.7 -2782 1247
SV2 Sand 3,274.5 2,995.7 -2944 1318
SV1 Sand 3,637.1 3,315.7 -3264 1459
UG4 Sand Heavy Oil 3,982.8 3,620.7 -3569 1593
UG4A Sand Heavy Oil 4,020.2 3,653.7 -3602 1608
UG3 Sand Heavy Oil 4,399.9 3,988.7 -3937 1755
UG1 Sand Heavy Oil 5,040.9 4,535.7 -4484 1996
MF Sand Oil / Water 5,766.4 4,969.7 -4918 2187
NB Sand Oil 5,946.7 5,033.7 -4982 2215
OA_MF Sand Oil 6,232.2 5,094.7 -5043 2242
OA (Heel) Sand Oil 6,471.2 5,116.7 -5065 2251
SURFACE CASING Oil 6,500.0 5,129.2 -5076 2257
OA (Toe) 19,167.0 5,163.2 -5110 2272
EASTING Est.
Pressure GradientEXPECTED
FLUID
MD
(FT)
TVD
(FT)
TVDSS
(FT)NORTHING
M-206_WP09ANTICIPATED FORMATION TOPS & GEOHAZARDS
TOP NAME LITHOLOGY
Page 48
Prudhoe Bay West
M-206 SB Producer
Drilling Procedure
23.0 Formation Tops & Information
Reference Plan:
G1 Gravels Water/Ice 386 373.2 -320 164 8.46
SV6 Sand Ice 1,673 1,628.8 -1576 717 8.46
BPRF Sand Ice 1,919 1,864.0 -1811 820 8.46
SV5 Sand Gas Hydrates 2,334 2,260.8 -2208 995 8.46
SV4 Sand Gas Hydrates 2,523 2,441.8 -2389 1074 8.46
SV3 Sand Gas Hydrates 2,934 2,835.4 -2782 1248 8.46
SV2 Sand 3,104 2,997.4 -2944 1319 8.46
SV1 Sand 3,438 3,317.1 -3264 1460 8.46
UG4 Sand Heavy Oil 3,757 3,622.3 -3569 1594 8.46
UG4A Sand Heavy Oil 3,791 3,655.0 -3602 1608 8.46
UG3 Sand Heavy Oil 4,142 3,990.1 -3937 1756 8.46
UG1 Sand Heavy Oil 4,734 4,537.5 -4484 1997 8.46
MF Sand Oil / Water 5,387 4,971.1 -4918 2187 8.46
NB Sand Oil 5,544 5,035.2 -4982 2215 8.46
OA_MF Sand Oil 5,935 5,096.2 -5043 2242 8.46
OA (Heel) Sand Oil 6,492 5,118.2 -5065 2252 8.46
SURFACE CASING Oil 6,500 5,129.2 -5076 2257 8.46
OA (Toe) 19,167 5,163.2 -5110 2272 8.46
EASTING Est.
Pressure GradientEXPECTED
FLUID
MD
(FT)
TVD
(FT)
TVDSS
(FT)NORTHING
M-206_WP09ANTICIPATED FORMATION TOPS & GEOHAZARDS
TOP NAME LITHOLOGY
Superseded by updated geo prog. -A.Dewhurst 16OCT24
Page 49
Prudhoe Bay West
M-206 SB Producer
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.
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:
M-06PB1 is an open hole plugback, there is no risk
Page 50
Prudhoe Bay West
M-206 SB Producer
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 51
Prudhoe Bay West
M-206 SB Producer
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 52
Prudhoe Bay West
M-206 SB Producer
Drilling Procedure
Abnormal Pressures and Temperatures:
Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen.
Anti-Collision
Take directional surveys every stand, take additional surveys if necessary. Continuously monitor
drilling parameters for signs of magnetic interference with another well. Reference A/C report in
directional plan.
Well Specific A/C:
M-200 is a well in the SB Oba sand, we will have geologic separation from this well.M-200 is a well in the SB Oba sand, we will have geologic separation from this well.
Page 53
Prudhoe Bay West
M-206 SB Producer
Drilling Procedure
25.0 Innovation Rig Layout
Page 54
Prudhoe Bay West
M-206 SB Producer
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 55
Prudhoe Bay West
M-206 SB Producer
Drilling Procedure
27.0 Innovation Rig Choke Manifold Schematic
Page 56
Prudhoe Bay West
M-206 SB Producer
Drilling Procedure
28.0 Casing Design
Page 57
Prudhoe Bay West
M-206 SB Producer
Drilling Procedure
29.0 8-1/2” Hole Section MASP
6WDQGDUG3URSRVDO5HSRUW
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3UXGKRH%D\
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Superceded on subsequent
PropoSuperceded on
subsequent
Proposal Report sal Report
080016002400320040004800True Vertical Depth (1600 usft/in)0 800 1600 2400 3200 4000 4800 5600 6400 7200 8000 8800 9600 10400 11200 12000 12800 13600 14400 15200Vertical Section at 318.06° (1600 usft/in)M-206 wp02 tgt2M-206 wp02 tgt3M-206 wp02 tgt5M-206 wp02 tgt6M-206 wp08 tgt1M-206 wp08 tgt2.59 5/8" x 12 1/4"4 1/2" x 8 1/2"5001000150020002500300035004000450050005500600065007000750080008500900095001000010500110001150012000125001300013500140001450015000155001600016500170001750018000185001900019154M-206 wp09Start Dir 3º/100' : 300' MD, 300'TVDStart Dir 3.8º/100' : 950' MD, 937.52'TVDEnd Dir : 1175.6' MD, 1143.77' TVDStart Dir 3.7º/100' : 4698.53' MD, 4252.24'TVDEnd Dir : 6292.22' MD, 5101.07' TVDBegin GeosteeringTotal Depth : 19154.09' MD, 5162.06' TVDG1SV6BPRFSV5SV4SV3SV2SV1UG4UG4AUG3UG1MFNBOAOA_MFHilcorp North Slope, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS:25.20+N/-S+E/-WNorthingEastingLatittudeLongitude0.000.005974689.03629007.23 70° 20' 20.5721 N 148° 57' 11.3474 WSURVEY PROGRAMDate: 2024-09-24T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool26.50 500.00 M-206 wp09 (M-206) GYD_Quest GWD500.00 6500.00 M-206 wp09 (M-206) 3_MWD+IFR2+MS+Sag6500.00 19154.09 M-206 wp09 (M-206) 3_MWD+IFR2+MS+SagFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation371.70 320.00 371.72 G11627.70 1576.00 1724.05 SV61862.70 1811.00 1990.39 BPRF2259.70 2208.00 2440.32 SV52440.70 2389.00 2645.45 SV42833.70 2782.00 3090.85 SV32995.70 2944.00 3274.45 SV23315.70 3264.00 3637.12 SV13620.70 3569.00 3982.78 UG43653.70 3602.00 4020.18 UG4A3988.70 3937.00 4399.85 UG34535.70 4484.00 5040.90 UG14969.70 4918.00 5766.39 MF5033.70 4982.00 5946.74 NB5094.70 5043.00 6232.18 OA_MF5116.70 5065.00 6471.57 OAREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: M-206, True NorthVertical (TVD) Reference:M-206 as built @ 51.70usftMeasured Depth Reference:M-206 as built @ 51.70usftCalculation Method:Minimum CurvatureProject:Prudhoe BaySite:MWell:Plan: M-206Wellbore:M-206Design:M-206 wp09CASING DETAILSTVD TVDSS MD SizeName5119.16 5067.46 6500.00 9-5/8 9 5/8" x 12 1/4"5162.06 5110.36 19154.09 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 0.002 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 300' MD, 300'TVD3 550.00 7.50 278.50 549.29 2.42 -16.16 3.00 278.50 12.604 950.00 19.50 278.50 937.52 16.19 -108.34 3.00 0.00 84.45 Start Dir 3.8º/100' : 950' MD, 937.52'TVD5 1175.60 28.07 278.24 1143.77 29.39 -198.29 3.80 -0.84 154.38 End Dir : 1175.6' MD, 1143.77' TVD6 4698.53 28.07 278.24 4252.24 266.85 -1839.03 0.00 0.00 1427.55 Start Dir 3.7º/100' : 4698.53' MD, 4252.24'TVD7 6292.22 85.00 298.90 5101.07 747.39 -3010.36 3.70 24.22 2567.82 End Dir : 6292.22' MD, 5101.07' TVD8 6492.22 85.00 298.90 5118.50 843.68 -3184.79 0.00 0.00 2756.02 M-206 wp08 tgt19 6697.84 91.17 298.73 5125.37 942.67 -3364.77 3.00 -1.62 2949.9410 7819.12 91.17 298.73 5102.56 1481.47 -4347.85 0.00 0.00 4007.7411 8556.45 90.51 317.15 5091.70 1932.78 -4926.79 2.50 91.90 4730.38 M-206 wp08 tgt2.512 9122.08 90.51 317.15 5086.70 2347.45 -5311.45 0.00 0.00 5295.92 M-206 wp02 tgt213 9183.67 90.37 318.68 5086.23 2393.16 -5352.73 2.50 94.99 5357.5114 12033.47 90.37 318.68 5067.70 4533.52 -7234.18 0.00 0.00 8207.08 M-206 wp02 tgt315 12476.35 89.52 327.50 5068.12 4887.29 -7499.89 2.00 95.52 8647.8216 12976.35 89.52 327.50 5072.31 5308.97 -7768.53 0.00 0.00 9141.0317 13316.40 89.35 336.00 5075.66 5608.23 -7929.32 2.50 91.19 9471.1118 13366.40 89.35 336.00 5076.23 5653.91 -7949.66 0.00 0.00 9518.6819 13566.39 89.35 342.00 5078.50 5840.51 -8021.29 3.00 90.03 9705.3620 13666.39 89.35 342.00 5079.64 5935.61 -8052.19 0.00 0.00 9796.7621 13896.44 87.90 337.63 5085.17 6151.42 -8131.52 2.00 -108.45 10010.3122 14932.05 87.90 337.63 5123.17 7108.46 -8525.34 0.00 0.00 10985.4323 15087.59 89.50 340.30 5126.70 7253.59 -8581.14 2.00 59.02 11130.69 M-206 wp02 tgt524 15139.38 89.95 341.24 5126.95 7302.49 -8598.20 2.00 64.56 11178.4625 16825.04 89.95 341.24 5128.57 8898.55 -9140.45 0.00 0.00 12728.1326 16920.27 89.16 339.50 5129.31 8988.23 -9172.44 2.00 -114.35 12816.2327 18720.27 89.16 339.50 5155.70 10674.06 -9802.75 0.00 0.00 14491.53 M-206 wp02 tgt628 19154.09 89.16 339.50 5162.06 11080.37 -9954.66 0.00 0.00 14895.30 Total Depth : 19154.09' MD, 5162.06' TVD
Superceded on
subsequent
Proposal Report
-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-206 wp08 tgt2.5
M-206 wp08 tgt1
M-206 wp02 tgt6
M-206 wp02 tgt5
M-206 wp02 tgt3
M-206 wp02 tgt2
9 5/8" x 12 1/4"
4 1/2" x 8 1/2"
2501250175022502750325037504250475050005162M-2 0 6 w p 0 9
Start Dir 3º/100' : 300' MD, 300'TVD
Start Dir 3.8º/100' : 950' MD, 937.52'TVD
End Dir : 1175.6' MD, 1143.77' TVD
Start Dir 3.7º/100' : 4698.53' MD, 4252.24'TVD
End Dir : 6292.22' MD, 5101.07' TVD
Begin Geosteering
Total Depth : 19154.09' MD, 5162.06' TVD
CASING DETAILS
TVD TVDSS MD Size Name
5119.16 5067.46 6500.00 9-5/8 9 5/8" x 12 1/4"
5162.06 5110.36 19154.09 4-1/2 4 1/2" x 8 1/2"
Project: Prudhoe Bay
Site: M
Well: Plan: M-206
Wellbore: M-206
Plan: M-206 wp09
WELL DETAILS: Plan: M-206
25.20
+N/-S +E/-W Northing Easting Latittude Longitude
0.00 0.00 5974689.03 629007.23
70° 20' 20.5721 N 148° 57' 11.3474 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: M-206, True North
Vertical (TVD) Reference: M-206 as built @ 51.70usft
Measured Depth Reference:M-206 as built @ 51.70usft
Calculation Method:Minimum Curvature
Superceded on subsequent
Proposal Report
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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)M-15M-16M-30M-204M-06M-06PB1No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: M-206 NAD 1927 (NADCON CONUS)Alaska Zone 0425.20+N/-S +E/-W Northing EastingLatittudeLongitude0.000.005974689.03 629007.2370° 20' 20.5721 N148° 57' 11.3474 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: M-206, True NorthVertical (TVD) Reference:M-206 as built @ 51.70usftMeasured Depth Reference:M-206 as built @ 51.70usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2024-09-24T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.50 500.00 M-206 wp09 (M-206) GYD_Quest GWD500.00 6500.00 M-206 wp09 (M-206) 3_MWD+IFR2+MS+Sag6500.00 19154.09 M-206 wp09 (M-206) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre 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-15M-16M-19M-20M-18GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference26.50 To 19154.09Project: Prudhoe BaySite: MWell: Plan: M-206Wellbore: M-206Plan: M-206 wp09Ladder / S.F. Plots1 of 2CASING DETAILSTVD TVDSS MD Size Name5119.16 5067.46 6500.00 9-5/8 9 5/8" x 12 1/4"5162.06 5110.36 19154.09 4-1/2 4 1/2" x 8 1/2"Superceded on subsequentProposal Report
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0.001.002.003.004.00Separation Factor7000 7700 8400 9100 9800 10500 11200 11900 12600 13300 14000 14700 15400 16100 16800 17500 18200 18900 19600Measured Depth (1400 usft/in)S-104S-108S-105S-42PB1S-11AS-14M-201S-121S-111S-122M-200S-13M-204M-205S-32AS-35No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: M-206 NAD 1927 (NADCON CONUS)Alaska Zone 0425.20+N/-S +E/-W Northing EastingLatittudeLongitude0.000.005974689.03629007.2370° 20' 20.5721 N148° 57' 11.3474 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: M-206, True NorthVertical (TVD) Reference:M-206 as built @ 51.70usftMeasured Depth Reference:M-206 as built @ 51.70usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2024-09-24T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.50 500.00 M-206 wp09 (M-206) GYD_Quest GWD500.00 6500.00 M-206 wp09 (M-206) 3_MWD+IFR2+MS+Sag6500.00 19154.09 M-206 wp09 (M-206) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)7000 7700 8400 9100 9800 10500 11200 11900 12600 13300 14000 14700 15400 16100 16800 17500 18200 18900 19600Measured Depth (1400 usft/in)M-200GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference26.50 To 19154.09Project: Prudhoe BaySite: MWell: Plan: M-206Wellbore: M-206Plan: M-206 wp09Ladder / S.F. Plots2 of 2CASING DETAILSTVD TVDSS MD Size Name5119.16 5067.46 6500.00 9-5/8 9 5/8" x 12 1/4"5162.06 5110.36 19154.09 4-1/2 4 1/2" x 8 1/2"Superceded on subsequentProposal ReportSuperceded
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080016002400320040004800True Vertical Depth (1600 usft/in)0 800 1600 2400 3200 4000 4800 5600 6400 7200 8000 8800 9600 10400 11200 12000 12800 13600 14400 15200Vertical Section at 318.06° (1600 usft/in)M-206 wp02 tgt2M-206 wp02 tgt3M-206 wp02 tgt5M-206 wp02 tgt6M-206 wp08 tgt1M-206 wp08 tgt2.59 5/8" x 12 1/4"4 1/2" x 8 1/2"5001000150020002500300035004000450050005500600065007000750080008500900095001000010500110001150012000125001300013500140001450015000155001600016500170001750018000185001900019154M-206 wp09Start Dir 3º/100' : 300' MD, 300'TVDStart Dir 3.8º/100' : 950' MD, 937.52'TVDEnd Dir : 1175.6' MD, 1143.77' TVDStart Dir 3.7º/100' : 4698.53' MD, 4252.24'TVDEnd Dir : 6292.22' MD, 5101.07' TVDBegin GeosteeringTotal Depth : 19154.09' MD, 5162.06' TVDG1SV6BPRFSV5SV4SV3SV2SV1UG4UG4AUG3UG1MFNBOAOA_MFHilcorp North Slope, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Rig: M-20625.20+N/-S+E/-WNorthingEastingLatitudeLongitude0.000.005974689.03629007.23 70° 20' 20.5721 N 148° 57' 11.3474 WSURVEY PROGRAMDate: 2024-09-24T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool26.50 500.00 M-206 wp09 (M-206) GYD_Quest GWD500.00 6500.00 M-206 wp09 (M-206) 3_MWD+IFR2+MS+Sag6500.00 19154.09 M-206 wp09 (M-206) GYD_Quest GWDFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation371.70 320.00 371.72 G11627.70 1576.00 1724.05 SV61862.70 1811.00 1990.39 BPRF2259.70 2208.00 2440.32 SV52440.70 2389.00 2645.45 SV42833.70 2782.00 3090.85 SV32995.70 2944.00 3274.45 SV23315.70 3264.00 3637.12 SV13620.70 3569.00 3982.78 UG43653.70 3602.00 4020.18 UG4A3988.70 3937.00 4399.85 UG34535.70 4484.00 5040.90 UG14969.70 4918.00 5766.39 MF5033.70 4982.00 5946.74 NB5094.70 5043.00 6232.18 OA_MF5116.70 5065.00 6471.57 OAREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Rig: M-206, True NorthVertical (TVD) Reference:M-206 as built @ 51.70usftMeasured Depth Reference:M-206 as built @ 51.70usftCalculation Method:Minimum CurvatureProject:Prudhoe BaySite:MWell:Rig: M-206Wellbore:M-206Design:M-206 wp09CASING DETAILSTVD TVDSS MD SizeName5119.16 5067.46 6500.00 9-5/8 9 5/8" x 12 1/4"5162.06 5110.36 19154.09 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 0.002 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 300' MD, 300'TVD3 550.00 7.50 278.50 549.29 2.42 -16.16 3.00 278.50 12.604 950.00 19.50 278.50 937.52 16.19 -108.34 3.00 0.00 84.45 Start Dir 3.8º/100' : 950' MD, 937.52'TVD5 1175.60 28.07 278.24 1143.77 29.39 -198.29 3.80 -0.84 154.38 End Dir : 1175.6' MD, 1143.77' TVD6 4698.53 28.07 278.24 4252.24 266.85 -1839.03 0.00 0.00 1427.55 Start Dir 3.7º/100' : 4698.53' MD, 4252.24'TVD7 6292.22 85.00 298.90 5101.07 747.39 -3010.36 3.70 24.22 2567.82 End Dir : 6292.22' MD, 5101.07' TVD8 6492.22 85.00 298.90 5118.50 843.68 -3184.79 0.00 0.00 2756.02 M-206 wp08 tgt19 6697.84 91.17 298.73 5125.37 942.67 -3364.77 3.00 -1.62 2949.9410 7819.12 91.17 298.73 5102.56 1481.47 -4347.85 0.00 0.00 4007.7411 8556.45 90.51 317.15 5091.70 1932.78 -4926.79 2.50 91.90 4730.38 M-206 wp08 tgt2.512 9122.08 90.51 317.15 5086.70 2347.45 -5311.45 0.00 0.00 5295.92 M-206 wp02 tgt213 9183.67 90.37 318.68 5086.23 2393.16 -5352.73 2.50 94.99 5357.5114 12033.47 90.37 318.68 5067.70 4533.52 -7234.18 0.00 0.00 8207.08 M-206 wp02 tgt315 12476.35 89.52 327.50 5068.12 4887.29 -7499.89 2.00 95.52 8647.8216 12976.35 89.52 327.50 5072.31 5308.97 -7768.53 0.00 0.00 9141.0317 13316.40 89.35 336.00 5075.66 5608.23 -7929.32 2.50 91.19 9471.1118 13366.40 89.35 336.00 5076.23 5653.91 -7949.66 0.00 0.00 9518.6819 13566.39 89.35 342.00 5078.50 5840.51 -8021.29 3.00 90.03 9705.3620 13666.39 89.35 342.00 5079.64 5935.61 -8052.19 0.00 0.00 9796.7621 13896.44 87.90 337.63 5085.17 6151.42 -8131.52 2.00 -108.45 10010.3122 14932.05 87.90 337.63 5123.17 7108.46 -8525.34 0.00 0.00 10985.4323 15087.59 89.50 340.30 5126.70 7253.59 -8581.14 2.00 59.02 11130.69 M-206 wp02 tgt524 15139.38 89.95 341.24 5126.95 7302.49 -8598.20 2.00 64.56 11178.4625 16825.04 89.95 341.24 5128.57 8898.55 -9140.45 0.00 0.00 12728.1326 16920.27 89.16 339.50 5129.31 8988.23 -9172.44 2.00 -114.35 12816.2327 18720.27 89.16 339.50 5155.70 10674.06 -9802.75 0.00 0.00 14491.53 M-206 wp02 tgt628 19154.09 89.16 339.50 5162.06 11080.37 -9954.66 0.00 0.00 14895.30 Total Depth : 19154.09' MD, 5162.06' 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-206 wp08 tgt2.5
M-206 wp08 tgt1
M-206 wp02 tgt6
M-206 wp02 tgt5
M-206 wp02 tgt3
M-206 wp02 tgt2
9 5/8" x 12 1/4"
4 1/2" x 8 1/2"
2501250175022502750325037504250475050005162M-2 0 6 w p 0 9
Start Dir 3º/100' : 300' MD, 300'TVD
Start Dir 3.8º/100' : 950' MD, 937.52'TVD
End Dir : 1175.6' MD, 1143.77' TVD
Start Dir 3.7º/100' : 4698.53' MD, 4252.24'TVD
End Dir : 6292.22' MD, 5101.07' TVD
Begin Geosteering
Total Depth : 19154.09' MD, 5162.06' TVD
CASING DETAILS
TVD TVDSS MD Size Name
5119.16 5067.46 6500.00 9-5/8 9 5/8" x 12 1/4"
5162.06 5110.36 19154.09 4-1/2 4 1/2" x 8 1/2"
Project: Prudhoe Bay
Site: M
Well: Plan: M-206
Wellbore: M-206
Plan: M-206 wp09
WELL DETAILS: Plan: M-206
25.20
+N/-S +E/-W Northing Easting Latittude Longitude
0.00 0.00 5974689.03 629007.23
70° 20' 20.5721 N 148° 57' 11.3474 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: M-206, True North
Vertical (TVD) Reference: M-206 as built @ 51.70usft
Measured Depth Reference:M-206 as built @ 51.70usft
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)M-15M-16M-30M-204M-06M-06PB1No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:Rig: M-206 NAD 1927 (NADCON CONUS)Alaska Zone 0425.20+N/-S +E/-W Northing EastingLatitudeLongitude0.000.005974689.03629007.2370° 20' 20.5721 N148° 57' 11.3474 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Rig: M-206, True NorthVertical (TVD) Reference: M-206 as built @ 51.70usftMeasured Depth Reference:M-206 as built @ 51.70usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2024-09-24T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.50 500.00 M-206 wp09 (M-206) GYD_Quest GWD500.00 6500.00 M-206 wp09 (M-206) 3_MWD+IFR2+MS+Sag6500.00 19154.09 M-206 wp09 (M-206) 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-15M-16M-19M-20M-18GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference26.50 To Project: Prudhoe BaySite: MWell: Rig: M-206Wellbore: M-206Plan: M-206 wp09Ladder / S.F. Plots1 of 2CASING DETAILSTVD TVDSS MD Size Name5119.16 5067.46 6500.00 9-5/8 9 5/8" x 12 1/4"5162.06 5110.36 19154.09 4-1/2 4 1/2" x 8 1/2"
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0.001.002.003.004.00Separation Factor7000 7700 8400 9100 9800 10500 11200 11900 12600 13300 14000 14700 15400 16100 16800 17500 18200 18900 19600Measured Depth (1400 usft/in)S-104S-108S-105AS-42AS-09AS-11AS-121S-111S-122PB3M-200M-204M-205S-35No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:Rig: M-206 NAD 1927 (NADCON CONUS)Alaska Zone 0425.20+N/-S +E/-W Northing EastingLatitudeLongitude0.000.005974689.03629007.2370° 20' 20.5721 N148° 57' 11.3474 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Rig: M-206, True NorthVertical (TVD) Reference: M-206 as built @ 51.70usftMeasured Depth Reference:M-206 as built @ 51.70usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2024-09-24T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.50 500.00 M-206 wp09 (M-206) GYD_Quest GWD500.00 6500.00 M-206 wp09 (M-206) 3_MWD+IFR2+MS+Sag6500.00 19154.09 M-206 wp09 (M-206) GYD_Quest GWD0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)7000 7700 8400 9100 9800 10500 11200 11900 12600 13300 14000 14700 15400 16100 16800 17500 18200 18900 19600Measured Depth (1400 usft/in)M-200M-200M-200M-200M-204GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference26.50 To 19154.09Project: Prudhoe BaySite: MWell: Rig: M-206Wellbore: M-206Plan: M-206 wp09Ladder / S.F. Plots2 of 2CASING DETAILSTVD TVDSS MD Size Name5119.16 5067.46 6500.00 9-5/8 9 5/8" x 12 1/4"5162.06 5110.36 19154.09 4-1/2 4 1/2" x 8 1/2"
1
Dewhurst, Andrew D (OGC)
From:Dewhurst, Andrew D (OGC)
Sent:Wednesday, 16 October, 2024 13:12
To:'Joseph Engel'; Joseph Lastufka
Cc:Rixse, Melvin G (OGC); Davies, Stephen F (OGC); Guhl, Meredith D (OGC)
Subject:RE: [EXTERNAL] PBU M-206 PTD (224-130): Questions
Joe,
Updated table received. Thank you.
Andy
From: Joseph Engel <jengel@hilcorp.com>
Sent: Wednesday, 16 October, 2024 13:05
To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Cc: 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] PBU M-206 PTD (224-130): Questions
Andrew –
Updated table attached.
Please let me know if you have any more questions.
-Joe
From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Sent: Wednesday, October 16, 2024 12:16 PM
To: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Joseph Engel <jengel@hilcorp.com>
Cc: 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] PBU M-206 PTD (224-130): Questions
Joe,
Will you please provide an updated geo prog table with the corrected MD depths?
Thanks,
Andy
From: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Sent: Wednesday, 16 October, 2024 11:34
To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Joseph Engel <jengel@hilcorp.com>
Cc: 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] PBU M-206 PTD (224-130): Questions
Andrew,
Please let me know if this satisƱes your questions. I apologize for any confusion.
x Would you please double-check the prognosed formaƟon tops? The MD/TVD relaƟonships do not align with the provided direcƟonal plan.
Please use the TVDss values as they are the same.
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
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
x Would you conĮrm the lease on which the SHL is located? It appears that it is on ADL 028282.
You are correct, I apologize for missing the surface SHL ADL which is 028282 and changes the Acres in Property (sec. 9) to 7589 instead of 5120.
Please see aƩached PBU M-06PB1 in both pdf and text.
Please let me know if you have any addiƟonal quesƟons or need anything else. Thanks!
Thanks,
Joe Lastufka
Sr. Drilling Technologist
Hilcorp North Slope, LLC
Office: (907)777-8400, Cell:(907)227-8496
From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Sent: Wednesday, October 16, 2024 10:20 AM
To: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Joseph Engel <jengel@hilcorp.com>
Cc: 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] PBU M-206 PTD (224-130): Questions
Joe,
I am compleƟng my review of the PBU M-206 PTD and have a few quesƟons:
x Would you please double-check the prognosed formaƟon tops? The MD/TVD relaƟonships do not align with the provided direcƟonal plan.
x Would you conĮrm the lease on which the SHL is located? It appears that it is on ADL 028282.
x Would you please provide a copy of the direcƟonal survey for the M-06PB1 (menƟoned in the anƟ-collision paragraph for the surface hole)? I was not
able to Įnd a record of it.
Thanks,
Andy
Andrew Dewhurst
Senior Petroleum Geologist
Alaska Oil and Gas ConservaƟon Commission
333 W. 7th Ave, Anchorage, AK 99501
andrew.dewhurst@alaska.gov
Direct: (907) 793-1254
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Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME: ______________________________________
PTD: _____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD: __________________________ POOL: ____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in 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.
PBU M-206
PRUDHOE BAY
224-130
POLARIS OIL
WELL PERMIT CHECKLISTCompanyHilcorp North Slope, LLCWell Name:PRUDHOE BAY UN POL M-206Initial Class/TypeDEV / PENDGeoArea890Unit11650On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2241300PRUDHOE BAY, POLARIS OIL - 640160NA1 Permit fee attachedInCmpt ADL028260, ADL028257, and ADL0282822 Lease number appropriateYes3 Unique well name and numberYes PRUDHOE BAY, POLARIS OIL - 640160 - governed by CO 484A4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For sNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes 20" 129.5# X-52 driven to 170'18 Conductor string providedYes 9-5/8" L-80 47# to BOPF, 9-5/8" L-80 40# to SB reservoir19 Surface casing protects all known USDWsYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.20 CMT vol adequate to circulate on conductor & surf csgYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.21 CMT vol adequate to tie-in long string to surf csgYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.22 CMT will cover all known productive horizonsYes 9-5/8" L-80 47# to BOPF, 9-5/8" L-80 40 to SB reservoir23 Casing designs adequate for C, T, B & permafrostYes Hilcorp Innvovation rig has adequate tankage and good trucking support24 Adequate tankage or reserve pitNA This is a grassroots well.25 If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collision scan identifies M-200 offset close appr- utilize Gyro MWD26 Adequate wellbore separation proposedYes 16" Diverter27 If diverter required, does it meet regulationsYes All fluids overbalanced to expected pore pressure.28 Drilling fluid program schematic & equip list adequateYes 1 annular, 3 ram stack tested to 3000 psi.29 BOPEs, do they meet regulationYes 13-5/8" , 5000 psi stack tested to 3000 psi.30 BOPE press rating appropriate; test to (put psig in comments)Yes Innovation has 10X 2-9/16"" manual gate valves, 1 x 3-1/8" manual choke and 1 x 3-1/8" remote hyd choke31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownYes Monitoring will be required33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)No H2S measures required.35 Permit can be issued w/o hydrogen sulfide measuresYes No abnormally geo-pressured strata are anticipated. MPD to mitigate any abnormal pressures.36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]Appr DateApprMGRDate10/17/2024ApprADDDate10/15/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateSJC for GCW 10/17/24JLC 10/17/2024
