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MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE:Thursday, July 25, 2024
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Josh Hunt
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
Hilcorp Alaska, LLC
I-23
MILNE PT UNIT I-23
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 07/25/2024
I-23
50-029-23780-00-00
224-012-0
W
SPT
4001
2240120 2000
707 702 706 705
INITAL P
Josh Hunt
6/26/2024
Second MIT. They tested to the wrong psi on the previous MIT and didn’t catch it till afterwards.
30 MinPretestInitial15 Min
Well Name
Type Test
Notes:
Interval P/F
Well
Permit Number:
Type Inj TVD
PTD Test psi
API Well Number Inspector Name:MILNE PT UNIT I-23
Inspection Date:
Tubing
OA
Packer Depth
181 2259 2170 2139IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitJDH240626135513
BBL Pumped:4.4 BBL Returned:4.3
Thursday, July 25, 2024 Page 1 of 1
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tested to the wrong psi on the previous MIT
VHH,QVSHFWLRQ5SWPLW-'+
James B. Regg Digitally signed by James B. Regg
Date: 2024.07.25 15:30:17 -08'00'
MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE:Thursday, July 25, 2024
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Josh Hunt
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
Hilcorp Alaska, LLC
I-23
MILNE PT UNIT I-23
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 07/25/2024
I-23
50-029-23780-00-00
224-012-0
W
SPT
4001
2240120 1500
757 762 761 761
INITAL I
Josh Hunt
6/25/2024
This well is a Monobore well design and completion. There is no OA. Test result deemed inconclusive due to testing to the wrong pressure
requirement; see MIT on 6/26/24.
30 MinPretestInitial15 Min
Well Name
Type Test
Notes:
Interval P/F
Well
Permit Number:
Type Inj TVD
PTD Test psi
API Well Number Inspector Name:MILNE PT UNIT I-23
Inspection Date:
Tubing
OA
Packer Depth
0 1760 1686 1661IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitJDH240625133448
BBL Pumped:4.2 BBL Returned:4
Thursday, July 25, 2024 Page 1 of 1
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inconclusive due to testing to the wrong pressure
1500
James B. Regg Digitally signed by James B. Regg
Date: 2024.07.25 15:20:46 -08'00'
By Grace Christianson at 3:27 pm, Jun 03, 2024
Completed
4/19/2024
JSB
RBDMS JSB 060524
GDSR-6/18/24MGR19DEC2025
Digitally signed by Taylor
Wellman (2143)
DN: cn=Taylor Wellman (2143)
Date: 2024.06.03 15:07:32 -
08'00'
Taylor Wellman
(2143)Drilling Manager
06/03/24
Monty M
Myers
_____________________________________________________________________________________
Revised By: JNL 4/23/2024
PROPOSED SCHEMATIC
Milne Point Unit
Well: MPU I-23
Last Completed: 4/19/2024
PTD: 224-012
4-1/2” Slotted Liner
Top (MD) Top (TVD) Btm (MD) Btm (TVD)
6,999’ 4,008’ 15,461’ 4,165’
CASING DETAIL
Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF
20" Conductor 129.5 / X-52 / Weld N/A Surface 164’ N/A
9-5/8" Surface 47 / L-80 / TXP 8.835” Surface 2,172’ 0.0732
9-5/8" Surface 40 / L-80 / TXP 8.681” 2,172’ 6,958’ 0.0758
4-1/2” Slotted Liner 13.5 / L-80 / Hyd 625 3.920” 6,766’ 15,500’ 0.0149
TUBING DETAIL
3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.992” Surface 6,780’ 0.0087
OPEN HOLE / CEMENT DETAIL
24” x Driven 7 yds Concrete
12-1/4"Stg 1 –Lead 661 sx / Tail 400 sx
Stg 2 –Lead 702 sx / Tail 270 sx
8-1/2” Uncemented Slotted Liner
TREE & WELLHEAD
Tree Cameron 3 1/8" 5M w/ 3-1/8” 5M Cameron Wing
Wellhead FMC 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs
GENERAL WELL INFO
API#: 50-029-23780-00-00
Completion Date: 4/19/2024
WELL INCLINATION DETAIL
KOP @ 394’
Max Hole Angle = 92° @ 7,026’ MD
TD =18,000’(MD) / TD =4,215’(TVD)
20”
Orig. KB Elev.:67.54’ / GL Elev.: 32.9’
3-1/2”
7
2
9-5/8”
1
4/5
3
See
Slotted
Liner
Detail
PBTD =15,499’(MD) / PBTD = 4,165’(TVD)
9-5/8” ‘ES’
Cementer @
2,149’
4-1/2”
6
JEWELRY DETAIL
No Top MD Item
ID
Upper Completion
1 5,171’ Viking Sliding Sleeve (Opens Down) 2.813”
2 5,223 Baker Zenith Gauge Carrier 2.992”
3 5,271’ XN Nipple, 2.813”, 2.75” No-Go 2.750”
4 6,769’ Locater Sub, 8.24” No Go (bottom of locator spaced out 2.36’) 6.190”
5 6,770’ Bullet Seals – TXP Top Box x Mule Shoe Bottom @ 6,780’ 6.190”
Lower Completion
6 6,766’ 9-5/8” SLZXP Liner Top Packer 6.190”
7 15,499’ Shoe
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:MPU I-23 Date:4/10/2024
Csg Size/Wt/Grade:9.625", 40# & 47#, L-80 Supervisor:Murphy/Toomey
Csg Setting Depth:6958 TMD 4008 TVD
Mud Weight:9.4 ppg LOT / FIT Press =542 psi
LOT / FIT =12.00 Hole Depth =6987 md
Fluid Pumped=1.20 Bbls Volume Back =1.20 bbls
Estimated Pump Output:0.101 Barrels/Stroke
LOT / FIT DATA CASING TEST DATA
Enter Strokes Enter Pressure Enter Strokes Enter Pressure
Here Here Here Here
->0 0 ->0 0
->1 37 ->4 31
->2 70 ->8 53
->3 92 ->12 81
->4 124 ->16 127
->5 179 ->20 210
->6 229 ->24 330
->7 284 ->28 491
->8 340 ->32 674
->9 385 ->40 1038
->10 433 ->48 1397
->11 488 ->56 1807
->12 543 ->64 2227
->13 ->72 2683
Enter Holding Enter Holding Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0 543 ->0 2683
->1 521 ->5 2652
->2 504 ->10 2640
->3 492 ->15 2631
->4 482 ->20 2625
->5 471 ->25 2618
->6 462 ->30 2613
->7 454 ->31 2612
->8 447 ->32 2611
->9 440 ->33 2610
->10 433 ->34 2610
->11 428 ->35 2609
->12 422 ->
->13 416 ->
->14 412
->15 408
->
01 234
5
6
7
8
9
10
11
12
0 4 8 12
16
20
24
28
32
40
48
56
64
72
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
0 1020304050607080
Pr
e
s
s
u
r
e
(
p
s
i
)
Strokes (# of)
LOT / FIT DATA CASING TEST DATA
Pr
e
s
s
u
r
e
(
p
s
i
)
543521504492482471462454447440433428422416412408
2683 2652 2640 2631 2625 2618 261326122611261026102609
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
0 5 10 15 20 25 30 35
Pr
e
s
s
u
r
e
(
p
s
i
)
Time (Minutes)
LOT / FIT DATA CASING TEST DATA
702
ACTIVITYDATE SUMMARY
4/19/2024
Wellhead - Pick up 4-1/2" TC-II tubing hagner (P156963) Install tech line and cap off,
Land off tubing hanger varify via I/A vlave, RILDS, Rig tested back side, Set 4" H CTS
BPV, Nipple down BOPs nipple up tree / adapter, Tested adapter to 500 / 5000 psi for
10 mins, Rig tested tree to 250 / 5000 for 5 mins. All tests were good. Pull CTS BPV
with dry rod. No Issues.
4/20/2024
*** WELL SHUT-IN ON ARRIVAL.***
SHIFT VIKING-SS OPEN AT 5,170' MD W/ 3-1/2" 42BO.
APPLY 700psi TO IA, PRESSURE FALLS TO 100psi AFTER SHIFT SLEEVE.
SET 3-1/2" JETPUMP (ratio: 13C) IN VIKING-SS AT 5,170' MD.
*** WELL SHUT-IN ON DEPARTURE, PAD OP NOTIFIED.***
5/29/2024 Freeze Protect, Pumped 15 bbls diesel down Tubing, Pumped 75 bbls diesel down IA
6/1/2024
*** WELL S/I ON ARRIVAL ***
PULLED JET PUMP FROM SSD @ 5171' MD
CLOSE SSD @ 5171' MD
MIT-IA PASS
*** WELL LEFT S/I ON DEPARTURE ***
6/1/2024
T/I/O=400/10 Assist Slickline (Post RWO) Pumped 140 bbls of 1% inhibited KCL
followed by 175 bbls diesel down IA to load. Slickline closed sleeve. MIT-IA PASSED
to 2115 psi. Pressured up IA to 2243 psi with 8 bbls diesel. 1st 15 min IA lost 90
psi.2nd 15 min IA lost 38 psi for a total loss of 128 psi in 30 min. Bled back 4 bbls.
Final Whps=406/100
Daily Report of Well Operations
PBU MPI-23
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Chelsea Wright Digitally signed by Chelsea
Wright
Date: 2024.04.16 10:01:41 -08'00'
Benjamin Hand Digitally signed by Benjamin Hand
Date: 2024.04.16 11:11:47 -08'00'
CAUTION: This email originated from outside the State of Alaska mail system. Do not
click links or open attachments unless you recognize the sender and know the content
is safe.
Some people who received this message don't often get email from mark.brouillet@hilcorp.com. Learn why this is
important
From:Brooks, Phoebe L (OGC)
To:Mark Brouillet - (C)
Cc:Regg, James B (OGC)
Subject:RE: MIT Test Well MPU I-23, Milne Point, Doyon 14, Hilcorp
Date:Thursday, May 23, 2024 10:54:50 AM
Attachments:MIT MPU I-23 04-19-24.xlsx
Mark,
I made some minor revisions, changing the PTD # format (2240120), adding the well name/#, and
leaving the AOGCC Rep blank (waived remarks are fine in the Notes). Please update your copy.
Thanks,
Phoebe
Phoebe Brooks
Research Analyst
Alaska Oil and Gas Conservation Commission
Phone: 907-793-1242
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 Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov.
From: Mark Brouillet - (C) <Mark.Brouillet@hilcorp.com>
Sent: Friday, April 19, 2024 4:50 PM
To: Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay
<doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>;
Wallace, Chris D (OGC) <chris.wallace@alaska.gov>
Cc: Ian Toomey - (C) <itoomey@hilcorp.com>
Subject: MIT Test Well MPU I-23, Milne Point, Doyon 14, Hilcorp
My apologies I sent the unfinished form first this is the completed form please replace the previous
form with this one.
Thank you
Mark Brouillet
Hilcorp Alaska, LLC
Doyon Rig 14
0LOQH3RLQW8QLW,
37'
evisions, changing the PTD # format (2240120), adding the well name/#, and
leaving the AOGCC Rep blank (waived remarks are fine in the Notes
Office: 907-670-3090
Doghouse: 907-670-3092
Cell: 907-631-9850
mark.brouillet@Hilcorp.com
From: Mark Brouillet - (C)
Sent: Friday, April 19, 2024 11:00 AM
To: jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov;
chris.wallace@alaska.gov
Cc: Ian Toomey - (C) <itoomey@hilcorp.com>
Subject: MIT Test Well MPU I-23, Milne Point, Doyon 14, Hilcorp
Good morning,
Here is the 10-426 form for the MIT performed on MPU I-23 well.
Any questions let me know please.
Mark Brouillet
Hilcorp Alaska, LLC
Doyon Rig 14
Office: 907-670-3090
Doghouse: 907-670-3092
Cell: 907-631-9850
mark.brouillet@Hilcorp.com
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the
individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby
notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please
immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the
onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility
is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
Submit to:
OOPERATOR:
FIELD / UNIT / PAD:
DATE:
OPERATOR REP:
AOGCC REP:
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD 2240120 Type Inj W Tubing 0 0 0 0 Type Test P
Packer TVD 4001 BBL Pump 7.0 IA 0 3800 3700 3670 Interval O
Test psi 3500 BBL Return 7.0 OA Result P
0
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes
W = Water P = Pressure Test I = Initial Test P = Pass
G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail
S = Slurry V = Required by Variance I = Inconclusive
I = Industrial Wastewater O = Other (describe in notes)
N = Not Injecting
Notes:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
MMechanical Integrity Test
jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov
Notes:
Notes:
Notes:
Hilcorp Alaska, LLC
Milne Point Unit, I Pad.
Mark Brouillet
04/19/24
Notes:MIT-IA to 3,500 psi per PTD# 224-012. Pressure gauge put on landing joint to monitor Tubing pressure. Completion does not have an OA. Witness waived by AOGCC
Rep Guy Cook 4/19/22 @ 05:47
Notes:
Notes:
Notes:
I-23
Form 10-426 (Revised 01/2017)2024-0419_MIT_MPU_I-23
5(9,6('
-5HJJ
David Douglas Hilcorp Alaska, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 05/06/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL:
WELL: MPU I-23
PTD: 224-012
API: 50-029-23780-00-00
FINAL LWD FORMATION EVALUATION + GEOSTEERING (04/02/2024 to 04/15/2024)
x ROP, AGR, ABG, DGR, EWR-M5, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
x Final Geosteering and EOW Report/Plots
SFTP Transfer – Main Folders:
FINAL LWD Subfolders:
FINAL Geosteering Subfolders:
Please include current contact information if different from above.
224-012
T38768
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.05.13 11:33:52 -08'00'
CAUTION: This email originated from outside the State of Alaska mail system. Do not
click links or open attachments unless you recognize the sender and know the content
is safe.
From:Mark Brouillet - (C)
To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC)
Cc:Ian Toomey - (C)
Subject:MIT Test Well MPU I-23, Milne Point, Doyon 14, Hilcorp
Date:Friday, April 19, 2024 4:50:43 PM
Attachments:10-426 MPU I-23.xlsx
You don't often get email from mark.brouillet@hilcorp.com. Learn why this is important
My apologies I sent the unfinished form first this is the completed form please replace the previous
form with this one.
Thank you
Mark Brouillet
Hilcorp Alaska, LLC
Doyon Rig 14
Office: 907-670-3090
Doghouse: 907-670-3092
Cell: 907-631-9850
mark.brouillet@Hilcorp.com
From: Mark Brouillet - (C)
Sent: Friday, April 19, 2024 11:00 AM
To: jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov;
chris.wallace@alaska.gov
Cc: Ian Toomey - (C) <itoomey@hilcorp.com>
Subject: MIT Test Well MPU I-23, Milne Point, Doyon 14, Hilcorp
Good morning,
Here is the 10-426 form for the MIT performed on MPU I-23 well.
Any questions let me know please.
Mark Brouillet
Hilcorp Alaska, LLC
Doyon Rig 14
Office: 907-670-3090
Doghouse: 907-670-3092
Cell: 907-631-9850
mark.brouillet@Hilcorp.com
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, please
Milne Point Unit I-23
PTD 2240120
immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
Submit to:
OPERATOR:
FIELD / UNIT / PAD:
DATE:
OPERATOR REP:
AOGCC REP:
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 224-012 Type Inj W Tubing 0 0 0 0 Type Test P
Packer TVD 4001 BBL Pump 7.0 IA 0 3800 3700 3670 Interval O
Test psi 3500 BBL Return 7.0 OA Result P
0
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes
W = Water P = Pressure Test I = Initial Test P = Pass
G = Gas O = Other (describe in Notes)4 = Four Year Cycle F = Fail
S = Slurry V = Required by Variance I = Inconclusive
I = Industrial Wastewater O = Other (describe in notes)
N = Not Injecting
Notes:
Hilcorp
Milne Point Unit, I Pad.
Waived by AOGCC Rep Guy Cook
Mark Brouillet
04/19/24
Notes:MIT-IA to 3,500 psi per PTD# 224-012. Pressure gauge put on landing joint to monitor Tubing pressure. Completion does not have an OA. Witness waived by AOGCC
Rep Guy Cook 4/19/22 @ 05:47
Notes:
Notes:
Notes:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
Mechanical Integrity Test
jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov
Notes:
Notes:
Notes:
Form 10-426 (Revised 01/2017)2024-0419_MIT_MPU_I-23
J. Regg; 5/13/2024
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:Alaska NS - Doyon 14 - DSMs
To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC)
Subject:Doyon 14 Diverter MPU I-23 3/30/24
Date:Wednesday, April 3, 2024 8:49:54 AM
Attachments:Doyon14 Diverter Report I-23.xlsx
Thank You and Best Regards,
Jay Murphy/ DSM
Hilcorp Alaska, LLC
Doyon Rig 14
Office: 907-670-3090
Doghouse: 907-670-3092
Cell: 907-715-9211
Jay.Murphy@Hilcorp.com
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the
individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby
notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please
immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the
onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility
is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
0LOQH3RLQW8QLW,
37'
Date: 3/30/2024 Development: X Exploratory:
Drlg Contractor: Rig No. 14 AOGCC Rep:
Operator:Oper. Rep:
Field/Unit/Well No.:Rig Rep:
PTD No.: 2240120 Rig Phone:
Rig Email:
MMISCELLANEOUS:DIVERTER SYSTEM:
Location Gen.: P Well Sign: P Designed to Avoid Freeze-up? P
Housekeeping: P Drlg. Rig. P Remote Operated Diverter? P
Warning Sign P Misc: NA No Threaded Connections? P
24 hr Notice: P Vent line Below Diverter? P
AACCUMULATOR SYSTEM:Diverter Size: 21-1/4" in.
Systems Pressure: 3000 psig P Hole Size: 12-1/4" in.
Pressure After Closure: 1825 psig P Vent Line(s) Size: 16 in. P
200 psi Recharge Time: 34 Seconds P Vent Line(s) Length: 268 ft. P
Full Recharge Time:151 Seconds P Closest Ignition Source: 104 ft. P
Nitrogen Bottles (Number of): 6 Outlet from Rig Substructure: 260 ft. P
Avg. Pressure: 1940 psig P
Accumulator Misc: NA
Vent Line(s) Anchored: P
MMUD SYSTEM:Visual Alarm Turns Targeted / Long Radius: P
Trip Tank: P P Divert Valve(s) Full Opening: P
Mud Pits: P P Valve(s) Auto & Simultaneous:
Flow Monitor: P P Annular Closed Time: 23 sec P
Mud System Misc: 0 NA Knife Valve Open Time: 17 sec P
Diverter Misc: NA
GGAS DETECTORS:Visual Alarm
Methane: P P
Hydrogen Sulfide: P P
Gas Detectors Misc: 0 NA
Total Test Time: 1 hrs Non-Compliance Items: 0
Remarks:
Submit to:
rig14@doyondrilling.com
TTEST DATA
J Hansen / N Hamilton
phoebe.brooks@alaska.gov
Hilcorp
Test performed with 5" HWDP, 18 Accumulator bottles @ 1005 psi precharge. AOGCC Rep Kam St John waived test witness.
0
M Brouilliet / J Vanderpool
0
907-670-3096
TTEST DETAILS
jim.regg@alaska.gov
AOGCC.Inspectors@alaska.gov
Milne Point Unit I-23
SSTATE OF ALASK A
AALASK A OIL AND GAS CONSERVATION COMMISSION
DDi verter Sys t ems In sp ectio n Report
GGENERAL INFORMATION
WaivedDoyon
**All Diverter repo rts are du e to t he agency w i th in 5 days of test in g*
Form 10-425 (Revised 05/2021)2024-0330_Diverter_Doyon14_MPU_I-23
+LOFRUS$ODVND//&MEU
9
9
9
9
-5HJJ
Some people who received this message don't often get email from twellman@hilcorp.com. Learn why this is
important
From:Wallace, Chris D (OGC)
To:AOGCC Records (CED sponsored)
Subject:FW: [EXTERNAL] MPU I-23 (PTD 224-012) - Questions
Date:Monday, April 1, 2024 9:41:45 AM
Attachments:MPU_j-16_WFL_28-MAR-24.pdf
PTD 2240120 and 1951690.
From: Taylor Wellman <twellman@hilcorp.com>
Sent: Monday, April 1, 2024 8:46 AM
To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Nathan Sperry
<Nathan.Sperry@hilcorp.com>
Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Guhl, Meredith D (OGC)
<meredith.guhl@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov>; Davies, Stephen F
(OGC) <steve.davies@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Katharine
Cunha <Katharine.Cunha@hilcorp.com>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Subject: RE: [EXTERNAL] MPU I-23 (PTD 224-012) - Questions
Andy,
Please see the attached Water Flow Log / Oxygen Activation Log run on MPU J-16 (PTD 195-169).
Sorry for the delay as it was affected by weather and the service provider’s unit repairs but the
attached log indicates zero flow behind the casing at the top of the Schrader. Please let me know if
this is sufficient to prove isolation and allow for injection into MPU I-23 (PTD 224-012) upon
completion as per the COA’s in the PTD.
Thank you,
Taylor
Taylor Wellman
Hilcorp Alaska, LLC: Wells Manager – Milne Point
Office: (907) 777-8449
Cell: (907) 947-9533
Email: twellman@hilcorp.com
From: Taylor Wellman <twellman@hilcorp.com>
Sent: Thursday, March 7, 2024 1:17 PM
To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Nathan Sperry
<Nathan.Sperry@hilcorp.com>
Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Guhl, Meredith D (OGC)
<meredith.guhl@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov>; Davies, Stephen F
(OGC) <steve.davies@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Katharine
Cunha <Katharine.Cunha@hilcorp.com>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Subject: RE: [EXTERNAL] MPU I-23 (PTD 224-012) - Questions
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
Chris and Andrew,
The type of log we are aiming to run is a waterflow log or an oxygen activation log. I’m currently
working on scheduling the job but target to have this log completed in the next 2 weeks. If there are
any issues with this timeline I will make sure to provide an update with the reasoning.
Thank you,
Taylor
Taylor Wellman
Hilcorp Alaska, LLC: Wells Manager – Milne Point
Office: (907) 777-8449
Cell: (907) 947-9533
Email: twellman@hilcorp.com
From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Sent: Thursday, March 7, 2024 8:13 AM
To: Taylor Wellman <twellman@hilcorp.com>; Nathan Sperry <Nathan.Sperry@hilcorp.com>
Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Guhl, Meredith D (OGC)
<meredith.guhl@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov>; Davies, Stephen F
(OGC) <steve.davies@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Katharine
Cunha <Katharine.Cunha@hilcorp.com>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Subject: RE: [EXTERNAL] MPU I-23 (PTD 224-012) - Questions
Taylor and Nathan,
In addition to the email reply stating the specifics on the proposed mitigation plan, would you please
submit a revised AOR and for the MPU I-23 PTD calling out the issue in J-16 with the mitigation plan
detailed. Please identify the well in the updated AOR map. I will splice those revised pages into the
final PTD document.
Thank you,
Andy
From: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>
Sent: Wednesday, March 6, 2024 15:26
To: Taylor Wellman <twellman@hilcorp.com>; Dewhurst, Andrew D (OGC)
<andrew.dewhurst@alaska.gov>
Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Guhl, Meredith D (OGC)
<meredith.guhl@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov>; Davies, Stephen F
(OGC) <steve.davies@alaska.gov>; Nathan Sperry <Nathan.Sperry@hilcorp.com>; Katharine Cunha
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.
<Katharine.Cunha@hilcorp.com>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Subject: RE: [EXTERNAL] MPU I-23 (PTD 224-012) - Questions
Taylor,
We didn’t talk about the type of log to be run on J-16 and estimated date it may be completed - so if
you could reply here, we will attach these emails to the I-23 PTD approval for the record.
Thanks and Regards,
Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue,
Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chris.wallace@alaska.gov
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information
from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the
sole use of the intended recipient(s). It may contain confidential and/or privileged information.
The unauthorized review, use or disclosure of such information may violate state or federal law. If
you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding
it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Chris Wallace at
907-793-1250 or chris.wallace@alaska.gov.
From: Taylor Wellman <twellman@hilcorp.com>
Sent: Monday, March 4, 2024 4:03 PM
To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Wallace, Chris D (OGC)
<chris.wallace@alaska.gov>
Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Guhl, Meredith D (OGC)
<meredith.guhl@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov>; Davies, Stephen F
(OGC) <steve.davies@alaska.gov>; Nathan Sperry <Nathan.Sperry@hilcorp.com>; Katharine Cunha
<Katharine.Cunha@hilcorp.com>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Subject: RE: [EXTERNAL] MPU I-23 (PTD 224-012) - Questions
Chris and Andrew,
With regards to MPU J-16 (PTD 195-169 / API 50-029-22615-00-00) you are correct. After further
review of the original cementing records, the first stage cement job on the 7” casing would not have
come high enough to have isolation across the Schrader Bluff in this well. The condition of the
isolation within J-16 has been a miss for multiple well penetrations through time. Below is a
summary table of injectors in the proximity of MPU J-16 and details about them.
Well Distance to J-
16 (ft)
Pool - Sands
Open
Start
Inj
Stop Inj Vol
(MMBW)
Status
J-15 1,154 Schrader (Nb,
Oa, Ob)
1999 2018 6.9 Cmt to surf 10/8/2020
J-17 4,275 Schrader (Nb,
Nc, Oa, Ob)
1998 2020 7.9 Shut In - Operable
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN
senders.
J-18 2,776 Schrader (Nb,
Oa, Ob)
2005 2019 2.9 Shut In - Not Operable
(MIT-IA allowed to lapse,
Mechanically good)
J-19A 2,848 Schrader (Nb,
Nc, Oa, Ob)
2009 2020 2.3 Shut In - Not Operable
(MIT-IA allowed to lapse,
Mechanically good)
I-21 268 Schrader (Oba)2021 N/A 1.5 Horizontal Well - On
Injection
I-28 243 Schrader (Oa)2021 N/A 1.8 Horizontal Well - On
Injection
I-35 770 Schrader (Nb)2020 N/A 1.9 Horizontal Well - On
Injection
I-37 1032 Schrader (Nb)2020 N/A 3.3 Horizontal Well - On
Injection
We would like to propose keeping all wells currently online and injecting, while concurrently running
a Water Flow Log in MPU J-16 to check for water flow between the Schrader and Ugnu sands.
Keeping the injection wells online will provide the actual conditions that could lead to crossflow and
have the highest chance for detection. Once that data is obtained, it will be provided back to you
and further actions can be enacted if needed.
We are open to coming over to your offices to discuss anything about these wells if you would like.
Thank you,
Taylor
Taylor Wellman
Hilcorp Alaska, LLC: Wells Manager – Milne Point
Office: (907) 777-8449
Cell: (907) 947-9533
Email: twellman@hilcorp.com
From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Sent: Friday, March 1, 2024 5:36 PM
To: Nathan Sperry <Nathan.Sperry@hilcorp.com>
Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Rixse, Melvin G (OGC)
<melvin.rixse@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl,
Meredith D (OGC) <meredith.guhl@alaska.gov>; Roby, David S (OGC)
<dave.roby@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov>
Subject: [EXTERNAL] MPU I-23 (PTD 224-012) - Questions
Nathan,
I am completing my review of the MPU I-23 PTD and have a few questions:
1. Regarding the Area of Review: I have a question about one of the offset wells:
MPU J-16 (50-029-22615-00-00).
From what I can tell, the original plan for this well was to run 7” casing to TD
(12,212’ MD) and do a 2-stage cement job: stage 1 across Kuparuk and stage 2
across Schrader Bluff. But they couldn’t get the 7” past 10,553’ MD, so they set
it there and ran a 5” liner from the base of the 7” to TD.
I see from your notes on this well that the stage collar was set 4,681’ MD with a
TOC of 2,998’MD. But the depth of the stage collar appears shallower to the
Schrader Bluff by over 1,000’ MD.
Do you have any information (volumetrics, quality, etc.) about the first stage
job that would support isolation across the Schrader Bluff?
2. I noticed there are conflicts between the H2S hazard description in the 12-1/4”
hole (p.48) vs. the 8-1/2” hole (p.50). Would you please clarify?
Thanks,
Andy
Andrew Dewhurst
Senior Petroleum Geologist
Alaska Oil and Gas Conservation Commission
333 W. 7th Ave, Anchorage, AK 99501
andrew.dewhurst@alaska.gov
Direct: (907) 793-1254
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 the
onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility
is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
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 responsibilityis 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: Milne Point Field, Schrader Bluff Oil Pool, MPU I-23
Hilcorp Alaska, LLC
Permit to Drill Number: 224-012
Surface Location: 2332' FSL, 3740' FEL, Sec 33, T13N, R10E, UM, AK
Bottomhole Location: 560' FNL, 819' FWL, Sec 16, T13N, R10E, UM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well
logs run must be submitted to the AOGCC within 90 days after completion, suspension, or
abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Brett W. Huber, Sr.
Chair, Commissioner
DATED this day of March 2024.
Brett W.
Huber, Sr.
Digitally signed by Brett
W. Huber, Sr.
Date: 2024.03.08
08:54:34 -09'00'
8
Drilling Manager
02/14/24
Monty M
Myers
By Kayla Junke at 2:47 pm, Feb 15, 2024
50-029-23780-00-00
* BOPE test to 3000 psi. Annular to 2500 psi.
* MIT-IA to 3500 psi. 24 hour notice to AOGCC for opportunity to witness.
* AOGCC to witness MIT-IA after 7 days of stabilized injection.
* Variance to 200' packer placement above the top of perforations approved.
* Approved for 30 days of preproduction.
A.Dewhurst 07MAR24
DSR-2/15/24MGR01MAR2024
224-012
Injection operations can not begin until MPU J-16 monitoring plan has been approved by AOGCC. -A.Dewhurst 07MAR24
JLC 3/8/2024
Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr.
Date: 2024.03.08 08:58:16 -09'00'
03/08/24
03/08/24
Future I-22 Oba Producer
(Not drilled yet)
Future I-24 Oba Producer
(Not drilled yet, directly
underneath I-32 Oa producer)
I-23 AOR MAP
•All wells that penetrate the Schrader Bluff OBa labelled at top Oba
intersection point
•Wells that did not penetrate the Schrader Bluff OBa are labelled at TD
•(NB is ~210’ shallower than OBa, Oa is ~67’ shallower than Oba)
•Green lines represent the footage in wells that are within the Schrader
•Bluff OBa inside the ¼ mile radius of proposed injector, I-23
•Both Nb and Oa wells (above target zone) are shown on map but not
•highlighted so map is less busy- included on AOR spreadsheet
•NOTE: Future I-22 through I-24 wells are almost directly underneath I-
•29 through I-31 Oa wells
Future I-25 Oba Injector
(Not drilled yet, not within ¼
mile, shown for reference)
Future I-26 Oba Producer
(Not drilled yet, not within ¼
mile, shown for reference)
I-23 Proposed Injector
OBa intersection point
I-23 Proposed Injector
OBa TD location
J-16 Well
PTD API WELLSTATUSTop of SBOBA (MD)Top of SBOBA (TVD)CBL Top ofCement(MD)CBL Top ofCement(TVD)Schrader OBAstatusZonal Isolation197-192 50-029-22821-00-00 MPU I-08SB Injector Shut in 5660 3987 N/A N/A Open9-7/8" hole with 7" casing.Stage 1 pumped 184 bbls perm E and 95 bbls class G w/ no losses.Circulated ~60 bbls off top of ES cementer prior to stage 2.Stage 2 pumped 303 bbls perm E and 34 bbls perm C. 120 bbls circulated tosurface.Open Injector in NB, Oa, Oba; not currently active200-103 50-029-22964-00-00 MPU I-09Prince Creek Source Water well 6346 4007 N/A N/A ClosedShut off Schrader Bluff sands with 39 Bbls cement, est. top 5518' MD. Nowis a Prince Creek Source Water Well204-098 50-029-23212-60-00 MPU I-17 NB Prod Lateral5069 3953 N/A N/A Closed9-7/8" hole with 7-5/8" cemented with 765 sx Class G. Assuming 20%washout, TOC is 2332' MD.204-099 50-029-23212-60-00 MPU I-17L1 Oba Lateral5069 3953 N/A N/A Open9-7/8" hole with 7-5/8" cemented with 765 sx Class G. Assuming 20%washout, TOC is 2332' MD.204-099 50-029-23212-70-00 MPU I-17L1PB1OBA Plugback 5068 3953 N/A N/A Open9-7/8" hole with 7-5/8" cemented with 765 sx Class G. Assuming 20%washout, TOC is 2332' MD.204-100 50-029-23212-61-00 MPU I-17L2 OA LateralN/A N/A N/A N/A N/A9-7/8" hole with 7-5/8" cemented with 765 sx Class G. Assuming 20%washout, TOC is 2332' MD.204-135 50-029-23218-00-00 MPU I-19Suspended OB Producer 7558 4089 3334' 2680' ClosedSuspended with 107 Bbls cement, tagged at 6620' MD.204-135 50-029-23218-70-00 MPU I-19PB1OBA Plugback 7717 4094 3334' 2680' ClosedSuspended with 107 Bbls cement, tagged at 6620' MD.204-135 50-029-23218-71-00 MPU I-19PB2OBA Plugback 7557 4089 3334' 2680' ClosedSuspended with 107 Bbls cement, tagged at 6620' MD.204-136 50-029-23218-60-00 MPU I-19L1Suspended OA Lateral N/A N/A 3334' 2680' N/A Not Open in OBA222-006 50-029-23708-00-00 MPU I-29OA Lateral ProducerN/A N/A N/A N/A N/ANot Open in OBA222-023 50-029-23708-00-00 MPU I-30OA Lateral InjectorN/A N/A N/A N/A N/ANot Open in OBA223-066 50-029-23710-00-00 MPU I-31OA Lateral ProducerN/A N/A N/A N/A N/ANot Open in OBA220-047 50-029-23677-00-00 MPU I-36NB Prod Lateral N/A N/A N/A N/AN/ANot Open in OBA220-047 50-029-23677-70-00 MPU I-36PB1NB Plugback N/A N/A N/A N/AN/ANot Open in OBA220-047 50-029-23677-71-00 MPU I-36PB2NB Plugback N/A N/A N/A N/AN/ANot Open in OBA220-055 50-029-23682-00-00 MPU I-37NB Lateral InjectorN/A N/A N/A N/A N/ANot Open in OBA220-055 50-029-23682-70-00 MPU I-37PB1NB PlugbackN/A N/A N/A N/A N/ANot Open in OBA220-057 50-029-23684-00-00 MPU I-38NB Lateral ProducerN/A N/A N/A N/A N/ANot Open in OBA220-057 50-029-23684-70-00 MPU I-38PB1NB PlugbackN/A N/A N/A N/A N/ANot Open in OBA220-057 50-029-23684-71-00 MPU I-38PB2NB PlugbackN/A N/A N/A N/A N/ANot Open in OBA220-060 50-029-23686-00-00 MPU I-39NB Lateral InjectorN/A N/A N/A N/A N/ANot Open in OBA194-106 50-029-22497-00-00 MPU J-08 Oa Lateral - SidetrackedN/A N/AN/A N/AN/ACmtr @ 4890', squeezed 23 bbls beneath.199-117 50-029-22497-01-00 MPU J-08A OB Prod Shut in 5788 4110 4714' 3808' ClosedReservoir abandoned via coil cement job in January 2024. Coil pumped 117bbls 12.5ppg G cement. Slickline tagged TOC at 4,850 SLMD.194-101 50-029-22495-00-00 MPU J-09 SB Producer P&A'd / Sidetracked 5776 4111 N/A N/A Closed7" in 8-1/2" hole cemented with 15.8ppg class G. TOC with 20% washoutestimated at 4,595' MD.Cmt Rtnr @ 5,360', Could not inject beneath retainer, PT 7" to 3000psi f/ 30min, AOGCC approval to sidetrack well. J-09 P&A'dArea of Review MPU I-23 SB OBA
199-114 50-029-22495-01-00 MPU J-09A OA Producer N/A N/A N/A N/A N/A97sks of cement pumped with bonzai completion, packer depth 5,199',cement valve 6,013'.Reservoir abandoned 3/27/22 via coil tubing by pumping 50 bbls 15.8ppgclass G. Tagged TOC at 5,237' CTMD.199-107 50-029-22952-00-00 MPU J-15 SB Injector P&A'd 6917 4159 N/A N/A Closed Fully abandoned with cement on 10/8/2020.195-169 50-029-22615-00-00 MPU J-16 Kuparuk WINJ Shut in 6180 4127 2998' 2529' Open*Cased and Cemented - 38 bbls of cement pumped thru stage collar at 4681'MD.*Bottom of cement is above the top of the Schrader. Mitigation plan, ifnecessary, is pending results of water flow log and discussion with theAOGCC (updated 3/7/2024).195-159 50-029-22607-00-00 MPU J-19 P&A'd / Sidetracked 6625 4076 3693 2860 Closedbalanced plug from 6390' MD to 5490'MD , 5450' MD to 4500' MD, and4290' MD to 3600' MD195-170 50-029-22607-01-00 MPU J-19A NB/OA/OB Inj Shut in 5498 4081 3693 2860 Open Open Injector197-200 50-029-22825-00-00 MPU J-21 OA/OB Prod Shut in 5985 4000Surface SurfaceOpen 295 bbls cmt pumped, returns to surface through stage tool at 2112' MD198-124 50-029-22897-00-00 MPU J-22 SB Prod P&A'd 5389 4066 Surface Surface Closed Abandoned on 4/2/2004204-073 50-029-23207-00-00 MPU J-25 Suspended NB Producer N/A N/A N/A N/A N/A Suspended with 93 Bbls cement. Tagged at 3,887' MD.204-073 50-029-23207-70-00 MPU J-25PB1 Schrader pilot hole (TD'd below Oba) 4592 4086 N/A N/A Closed Suspended with 131 bbls class G cement. Tagged at 3,937' MD.204-064 50-029-23205-00-00 MPU J-26 NB Prod Lateral Producer 5554 4027 3105' 2624' Closed9-7/8" hole with 7-5/8" cemented with 278 sx Class G. Assuming 20%washout, TOC is 5154' MD.Reservoir abandoned by coil on August 10, 2020. 48 Bbls cement pumped,milled cement to 5582' MD.204-064 50-029-23205-70-00 MPU J-26PB1 NB Plug back 5554 4027 N/A N/A Closed9-7/8" hole with 7-5/8" cemented with 278 sx Class G. Assuming 20%washout, TOC is 5154' MD.Reservoir abandoned by coil on August 10, 2020. 48 Bbls cement pumped,milled cement to 5582' MD.204-064 50-029-23205-71-00 MPU J-26PB2 NB Plug back 5554 4027 N/A N/A Closed9-7/8" hole with 7-5/8" cemented with 278 sx Class G. Assuming 20%washout, TOC is 5154' MD.Reservoir abandoned by coil on August 10, 2020. 48 Bbls cement pumped,milled cement to 5582' MD.204-066 50-029-23205-60-00 MPU J-26L1 OBa Lateral Producer 5556 4027 N/A N/A Closed Lateral isolated via iso sleeve and NB/OA reservoir abandonments.204-067 50-029-23205-61-00 MPU J-26L2 OA Lateral Producer N/A N/A N/A N/A N/AOA reservoir P&A'd on 4/4/2022. Coil pumped 105 bbls 15.8ppg class Gcement. Washed to 5,100' MD.215-118 50-029-23551-00-00 MPU L-46 OA Producer N/A N/A N/A N/A N/ANot Open182-027 50-029-20719-00-00 WSAK 25 Exploration Well; P&A'd (WEST SAK 4289 4014 2680' 2650' Closed Abandoned224-001 50-029-23778-00-00 MPU I-24Future OBA lateral ProducerTBD TBD TBD TBD Will be OpenNot Drilled YetTBD TBD MPU I-22Future OBA lateral ProducerTBD TBD TBD TBD Will be OpenNot Drilled Yet*Bottom of cement is above the top of the Schrader. Mitigation plan, ifnecessary, is pending results of water flow log and discussion with theAOGCC (updated 3/7/2024).Open*See attached email discussion for details on mitigation plan for MPU J-16. -A.Dewhurst 07MAR24MPU J-16
Future I-22 Oba Producer
(Not drilled yet)
Future I-24 Oba Producer
(Not drilled yet, directly
underneath I-32 Oa producer)
I-23 AOR MAP
•All wells that penetrate the Schrader Bluff OBa labelled at top Oba
intersection point
•Wells that did not penetrate the Schrader Bluff OBa are labelled at TD
•(NB is ~210’ shallower than OBa, Oa is ~67’ shallower than Oba)
•Green lines represent the footage in wells that are within the Schrader
•Bluff OBa inside the ¼ mile radius of proposed injector, I-23
•Both Nb and Oa wells (above target zone) are shown on map but not
•highlighted so map is less busy- included on AOR spreadsheet
•NOTE: Future I-22 through I-24 wells are almost directly underneath I-
•29 through I-31 Oa wells
Future I-25 Oba Injector
(Not drilled yet, not within ¼
mile, shown for reference)
Future I-26 Oba Producer
(Not drilled yet, not within ¼
mile, shown for reference)
I-23 Proposed Injector
OBa intersection point
I-23 Proposed Injector
OBa TD location
Superseded with updated AOR map.
-A.Dewhurst 07MAR24
PTD API WELL STATUS
Top of SB
OBA (MD)
Top of SB
OBA (TVD)
CBL Top of
Cement
(MD)
CBL Top of
Cement
(TVD)
Schrader OBA
status Zonal Isolation
197-192 50-029-22821-00-00 MPU I-08 SB Injector Shut in 5660 3987 N/A N/A Open
9-7/8" hole with 7" casing.
Stage 1 pumped 184 bbls perm E and 95 bbls class G w/ no losses.
Circulated ~60 bbls off top of ES cementer prior to stage 2.
Stage 2 pumped 303 bbls perm E and 34 bbls perm C. 120 bbls circulated to
surface.
Open Injector in NB, Oa, Oba; not currently active
200-103 50-029-22964-00-00 MPU I-09 Prince Creek Source Water well 6346 4007 N/A N/A Closed
Shut off Schrader Bluff sands with 39 Bbls cement, est. top 5518' MD. Now
is a Prince Creek Source Water Well
204-098 50-029-23212-60-00 MPU I-17 NB Prod Lateral 5069 3953 N/A N/A Closed
9-7/8" hole with 7-5/8" cemented with 765 sx Class G. Assuming 20%
washout, TOC is 2332' MD.
204-099 50-029-23212-60-00 MPU I-17L1 Oba Lateral 5069 3953 N/A N/A Open
9-7/8" hole with 7-5/8" cemented with 765 sx Class G. Assuming 20%
washout, TOC is 2332' MD.
204-099 50-029-23212-70-00 MPU I-17L1PB1 OBA Plugback 5068 3953 N/A N/A Open
9-7/8" hole with 7-5/8" cemented with 765 sx Class G. Assuming 20%
washout, TOC is 2332' MD.
204-100 50-029-23212-61-00 MPU I-17L2 OA Lateral N/A N/A N/A N/A N/A
9-7/8" hole with 7-5/8" cemented with 765 sx Class G. Assuming 20%
washout, TOC is 2332' MD.
204-135 50-029-23218-00-00 MPU I-19 Suspended OB Producer 7558 4089 3334' 2680' Closed Suspended with 107 Bbls cement, tagged at 6620' MD.
204-135 50-029-23218-70-00 MPU I-19PB1 OBA Plugback 7717 4094 3334' 2680' Closed Suspended with 107 Bbls cement, tagged at 6620' MD.
204-135 50-029-23218-71-00 MPU I-19PB2 OBA Plugback 7557 4089 3334' 2680' Closed Suspended with 107 Bbls cement, tagged at 6620' MD.
204-136 50-029-23218-60-00 MPU I-19L1 Suspended OA Lateral N/A N/A 3334' 2680' N/A Not Open in OBA
222-006 50-029-23708-00-00 MPU I-29 OA Lateral Producer N/A N/A N/A N/A N/A Not Open in OBA
222-023 50-029-23708-00-00 MPU I-30 OA Lateral Injector N/A N/A N/A N/A N/A Not Open in OBA
223-066 50-029-23710-00-00 MPU I-31 OA Lateral Producer N/A N/A N/A N/A N/A Not Open in OBA
220-047 50-029-23677-00-00 MPU I-36 NB Prod Lateral N/A N/A N/A N/A N/A Not Open in OBA
220-047 50-029-23677-70-00 MPU I-36PB1 NB Plugback N/A N/A N/A N/A N/A Not Open in OBA
220-047 50-029-23677-71-00 MPU I-36PB2 NB Plugback N/A N/A N/A N/A N/A Not Open in OBA
220-055 50-029-23682-00-00 MPU I-37 NB Lateral Injector N/A N/A N/A N/A N/A Not Open in OBA
220-055 50-029-23682-70-00 MPU I-37PB1 NB Plugback N/A N/A N/A N/A N/A Not Open in OBA
220-057 50-029-23684-00-00 MPU I-38 NB Lateral Producer N/A N/A N/A N/A N/A Not Open in OBA
220-057 50-029-23684-70-00 MPU I-38PB1 NB Plugback N/A N/A N/A N/A N/A Not Open in OBA
220-057 50-029-23684-71-00 MPU I-38PB2 NB Plugback N/A N/A N/A N/A N/A Not Open in OBA
220-060 50-029-23686-00-00 MPU I-39 NB Lateral Injector N/A N/A N/A N/A N/A Not Open in OBA
194-106 50-029-22497-00-00 MPU J-08 Oa Lateral - Sidetracked N/A N/A
N/A N/A N/A Cmtr @ 4890', squeezed 23 bbls beneath.
199-117 50-029-22497-01-00 MPU J-08A OB Prod Shut in 5788 4110 4714' 3808' Closed
Reservoir abandoned via coil cement job in January 2024. Coil pumped 117
bbls 12.5ppg G cement. Slickline tagged TOC at 4,850 SLMD.
194-101 50-029-22495-00-00 MPU J-09 SB Producer P&A'd / Sidetracked 5776 4111 N/A N/A Closed
7" in 8-1/2" hole cemented with 15.8ppg class G. TOC with 20% washout
estimated at 4,595' MD.
Cmt Rtnr @ 5,360', Could not inject beneath retainer, PT 7" to 3000psi f/ 30
min, AOGCC approval to sidetrack well. J-09 P&A'd
Area of Review MPU I-23 SB OBA
MPU I-30 (50-029-23710-00-00)
MPU I-31 (50-029-23763-00-00) -A.Dewhurst 06MAR24
Superseded with updated AOR table. -A.Dewhurst 07MAR24
199-114 50-029-22495-01-00 MPU J-09A OA Producer N/A N/A N/A N/A N/A
97sks of cement pumped with bonzai completion, packer depth 5,199',
cement valve 6,013'.
Reservoir abandoned 3/27/22 via coil tubing by pumping 50 bbls 15.8ppg
class G. Tagged TOC at 5,237' CTMD.
199-107 50-029-22952-00-00 MPU J-15 SB Injector P&A'd 6917 4159 N/A N/A Closed Fully abandoned with cement on 10/8/2020.
195-169 50-029-22615-00-00 MPU J-16 Kuparuk WINJ Shut in 6180 4127 2998' 2529' Closed
Cased and Cemented - 38 bbls of cement pumped thru stage collar at 4681'
MD.
195-159 50-029-22607-00-00 MPU J-19 P&A'd / Sidetracked 6625 4076 3693 2860 Closed
balanced plug from 6390' MD to 5490'MD , 5450' MD to 4500' MD, and
4290' MD to 3600' MD
195-170 50-029-22607-01-00 MPU J-19A NB/OA/OB Inj Shut in 5498 4081 3693 2860 Open Open Injector
197-200 50-029-22825-00-00 MPU J-21 OA/OB Prod Shut in 5985 4000 Surface Surface
Open 295 bbls cmt pumped, returns to surface through stage tool at 2112' MD
198-124 50-029-22897-00-00 MPU J-22 SB Prod P&A'd 5389 4066 Surface Surface Closed Abandoned on 4/2/2004
204-073 50-029-23207-00-00 MPU J-25 Suspended NB Producer N/A N/A N/A N/A N/A Suspended with 93 Bbls cement. Tagged at 3,887' MD.
204-073 50-029-23207-70-00 MPU J-25PB1 Schrader pilot hole (TD'd below Oba) 4592 4086 N/A N/A Closed Suspended with 131 bbls class G cement. Tagged at 3,937' MD.
204-064 50-029-23205-00-00 MPU J-26 NB Prod Lateral Producer 5554 4027 3105' 2624' Closed
9-7/8" hole with 7-5/8" cemented with 278 sx Class G. Assuming 20%
washout, TOC is 5154' MD.
Reservoir abandoned by coil on August 10, 2020. 48 Bbls cement pumped,
milled cement to 5582' MD.
204-064 50-029-23205-70-00 MPU J-26PB1 NB Plug back 5554 4027 N/A N/A Closed
9-7/8" hole with 7-5/8" cemented with 278 sx Class G. Assuming 20%
washout, TOC is 5154' MD.
Reservoir abandoned by coil on August 10, 2020. 48 Bbls cement pumped,
milled cement to 5582' MD.
204-064 50-029-23205-71-00 MPU J-26PB2 NB Plug back 5554 4027 N/A N/A Closed
9-7/8" hole with 7-5/8" cemented with 278 sx Class G. Assuming 20%
washout, TOC is 5154' MD.
Reservoir abandoned by coil on August 10, 2020. 48 Bbls cement pumped,
milled cement to 5582' MD.
204-066 50-029-23205-60-00 MPU J-26L1 OBa Lateral Producer 5556 4027 N/A N/A Closed Lateral isolated via iso sleeve and NB/OA reservoir abandonments.
204-067 50-029-23205-61-00 MPU J-26L2 OA Lateral Producer N/A N/A N/A N/A N/A
OA reservoir P&A'd on 4/4/2022. Coil pumped 105 bbls 15.8ppg class G
cement. Washed to 5,100' MD.
215-118 50-029-23551-00-00 MPU L-46 OA Producer N/A N/A N/A N/A N/A Not Open
182-027 50-029-20719-00-00 WSAK 25 Exploration Well; P&A'd (WEST SAK 4289 4014 2680' 2650' Closed Abandoned
224-001 50-029-23778-00-00 MPU I-24 Future OBA lateral Producer TBD TBD TBD TBD Will be Open Not Drilled Yet
TBD TBD MPU I-22 Future OBA lateral Producer TBD TBD TBD TBD Will be Open Not Drilled Yet
Superseded with updated AOR table. -A.Dewhurst 07MAR24
Milne Point Unit
(MPU) I-23
Drilling Program
Version 1
2/14/2024
Table of Contents
1.0 Well Summary ........................................................................................................................... 2
2.0 Management of Change Information ........................................................................................ 3
3.0 Tubular Program:...................................................................................................................... 4
4.0 Drill Pipe Information: .............................................................................................................. 4
5.0 Internal Reporting Requirements ............................................................................................. 5
6.0 Planned Wellbore Schematic ..................................................................................................... 6
7.0 Drilling / Completion Summary ................................................................................................ 7
8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 8
9.0 R/U and Preparatory Work ..................................................................................................... 11
10.0 N/U 21-1/4” 2M Diverter System ............................................................................................. 12
11.0 Drill 12-1/4” Hole Section ........................................................................................................ 14
12.0 Run 9-5/8” Surface Casing ...................................................................................................... 17
13.0 Cement 9-5/8” Surface Casing ................................................................................................. 23
14.0 BOP N/U and Test.................................................................................................................... 28
15.0 Drill 8-1/2” Hole Section .......................................................................................................... 29
16.0 Run 5-1/2” x 4-1/2” Injection Liner (Lower Completion) ...................................................... 35
17.0 Run 3-1/2” Tubing (Upper Completion) ................................................................................. 40
18.0 RDMO ...................................................................................................................................... 41
19.0 Post-Rig Work ......................................................................................................................... 42
20.0 Doyon 14 Diverter Schematic .................................................................................................. 43
21.0 Doyon 14 BOP Schematic ........................................................................................................ 44
22.0 Wellhead Schematic ................................................................................................................. 45
23.0 Days Vs Depth .......................................................................................................................... 46
24.0 Formation Tops & Information............................................................................................... 47
25.0 Anticipated Drilling Hazards .................................................................................................. 48
26.0 Doyon 14 Layout ...................................................................................................................... 51
27.0 FIT Procedure .......................................................................................................................... 53
28.0 Doyon 14 Choke Manifold Schematic ..................................................................................... 54
29.0 Casing Design ........................................................................................................................... 55
30.0 8-1/2” Hole Section MASP ....................................................................................................... 56
31.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 57
32.0 Surface Plat (As-Built) (NAD 27) ............................................................................................ 58
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1.0 Well Summary
Well MPU I-23
Pad Milne Point “I” Pad
Planned Completion Type 3-1/2” Injection Tubing
Target Reservoir(s) Schrader Bluff OBa Sand
Planned Well TD, MD / TVD 19,547’ MD / 4,340’ TVD
PBTD, MD / TVD 19,547’ MD / 4,340’ TVD
Surface Location (Governmental) 2332' FSL, 3740' FEL, Sec. 33, T13N, R10E, UM, AK
Surface Location (NAD 27) X= 551630 Y= 6009447
Top of Productive Horizon
(Governmental)1382' FNL, 1220' FEL, Sec 32, T13N, R10E, UM, AK
TPH Location (NAD 27) X= 548856 Y= 6010994
BHL (Governmental) 560' FSL, 819' FWL, Sec 16, T13N, R10E, UM, AK
BHL (NAD 27) X= 550776 Y=6023508
AFE Drilling Days 21 days
AFE Completion Days 3 days
Maximum Anticipated Pressure
(Surface) 1360 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 1760 psig
Work String 5” 19.5# S-135 DS-50 & NC 50
KB Elevation above MSL: 33.7 ft + 32.9 ft = 66.6 ft
GL Elevation above MSL: 32.9 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
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2.0 Management of Change Information
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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” 8.681”8.525”10.625”47 L-80 TXP 6,870 4,750 1,086
9-5/8” 8.835”8.679”10.625”40 L-80 TXP 5,750 3,090 916
8-1/2”5-1/2” 4.892”4.767”6.050”17 L-80 JFE Bear 7,740 6,290 397
4-1/2” 3.960”3.795”4.714”13.5 L-80 H625 9020 8540 279
Tubing 3-1/2” 2.992”2.867”4.500”9.3 L-80
EUE 8RD 9289 7399 163
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 GPDS50 36,100 43,100 560
5”4.276”3.25” 6.625”19.5 S-135 NC50 31,032 34,136 560
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
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5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on WellEz.
x Report covers operations from 6am to 6am
x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left
of the data entry area – this will not save the data entered, and will navigate to another data entry.
x Ensure time entry adds up to 24 hours total.
x Try to capture any out of scope work as NPT. This helps later on when we pull end of well
reports.
x Enter the MD and TVD depths EVERY DAY whether you are making hole or not.
5.2 Afternoon Updates
x Submit a short operations update each work day to mmyers@hilcorp,
nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com
5.3 Intranet Home Page Morning Update
x Submit a short operations update each morning by 7am on the company intranet homepage. On
weekend and holidays, ensure to have this update in before 5am.
5.4 EHS Incident Reporting
x Health and Safety: Notify EHS field coordinator.
x Environmental: Drilling Environmental Coordinator
x Notify Drilling Manager & Drilling Engineer on all incidents
x Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
x Send final “As-Run” Casing tally to nathan.sperry@hilcorp.com and
joseph.lastufka@hilcorp.com
5.6 Casing and Cement report
x Send casing and cement report for each string of casing to mmyers@hilcorp.com
nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com
5.7 Hilcorp Milne Point Contact List:
Title Name Work Phone Email
Drilling Manager Monty Myers 907.777.8431 mmyers@hilcorp.com
Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com
Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com
Completion Engineer Brian Glasheen 907.564.5277 Brian.glasheen@hilcorp.com
Geologist Katie Cunha 907.564.4786 Katharine.cunha@hilcorp.com
Reservoir Engineer Almas Aitkulov 907.564.4250 aaitkulov@hilcorp.com
EHS Director Laura Green 907.777.8314 lagreen@hilcorp.com
Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com
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6.0 Planned Wellbore Schematic
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7.0 Drilling / Completion Summary
MPU I-23 is a grassroots injector planned to be drilled in the Schrader Bluff OBa sand. I-23 is part of a
multi well program targeting the Schrader Bluff sand on I-Pad. I-23 will be pre-produced for 30 days.
The directional plan is a horizontal well with 12-1/4” surface hole with 9-5/8” surface casing set into the top
of the Schrader Bluff OBa sand. An 8-1/2” lateral section will be drilled. An injection liner will be run in
the open hole section.
The Doyon 14 will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately March 21st, 2024, pending rig schedule.
Surface casing will be run to 7,090’ MD / 4,001’ 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 be discussed with AOGCC authorities.
All cuttings & mud generated during drilling operations will be hauled to the Milne Point “B” pad G&I facility.
General sequence of operations:
1. MIRU Doyon 14 to well site
2. N/U & Test 21-1/4” 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 & test 13-5/8” x 5M BOP. Install MPD Riser
5. Drill 8-1/2” lateral to well TD.
6. Run 4-1/2” injection liner.
7. Run 3-1/2” tubing.
8. N/D BOP, N/U Tree, RDMO.
Reservoir Evaluation Plan:
1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res
2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering)
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8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that all drilling and completion operations comply with all applicable AOGCC regulations.
Operations stated in this PTD application may be altered based on sound engineering judgement as
wellbore conditions require, but no AOGCC regulations will be varied from without prior approval from
the AOGCC. If additional clarity or guidance is required on how to comply with a specific regulation,
do not hesitate to contact the Anchorage Drilling Team.
x Review all conditions of approval of the PTD on the 10-401 form. Ensure that the conditions of
approval are captured in shift handover notes until they are executed and complied with.
x BOPs shall be tested at (2) week intervals during the drilling and completion of MPU I-23. Ensure
to provide AOGCC 24 hrs notice prior to testing BOPs.
x The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment
will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial
and subsequent tests).Confirm that these test pressures match those specified on the APD.
x If the BOP is used to shut in on the well in a well control situation or control fluid flow from the
well bore, AOGCC is to be notified and we must test all BOP components utilized for well control
prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP
test.
x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid
program and drilling fluid system”.
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”.
o Ensure the diverter vent line is at least 75’ away from potential ignition sources
x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
x Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test
must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a
minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test
pressure must show stabilizing pressure and may not decline more than 10 percent within 30
minutes. The results of this test and any subsequent tests of the casing must be recorded as required
by 20 AAC 25.070(1)”.
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AOGCC Regulation Variance Requests:
1) Hilcorp is requesting approval for a test period of pre-producing up to 30 days via a reverse circulating jet
pump completion. This will allow us to measure skin and evaluate the benefits of pre-producing our injectors
in the future. During flow back, Hilcorp will have a 24/7 man watch while the well is online and producing.
Section 19 details the steps required to make this happen. Note also that the MIT-IA has been changed from
2,500 psi to 3,500 psi.
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Summary of BOP Equipment & Notifications
Hole Section Equipment Test Pressure (psi)
12 1/4”x 21-1/4” 2M Diverter w/ 16” Diverter Line Function Test Only
8-1/2”
x 13-5/8” x 5M Hydril “GK” Annular BOP
x 13-5/8” x 5M Hydril MPL Double Gate
o Blind ram in btm cavity
x Mud cross w/ 3” x 5M side outlets
x 13-5/8” x 5M Hydril MPL Single ram
x 3-1/8” x 5M Choke Line
x 3-1/8” x 5M Kill line
x 3-1/8” x 5M Choke manifold
x Standpipe, floor valves, etc
Initial Test: 250/3000
Subsequent Tests:
250/3000
Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit.
Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air
pump, and emergency pressure is provided by bottled nitrogen.
The remote closing operator panels are located in the doghouse and on accumulator unit.
Required AOGCC Notifications:
x Well control event (BOP’s utilized to shut in the well to control influx of formation fluids).
x 24 hours notice prior to spud.
x 24 hours notice prior to testing BOPs.
x 24 hours notice prior to casing running & cement operations.
x Any other notifications required in PTD.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov
Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov
Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov
Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
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9.0 R/U and Preparatory Work
9.1 I-23 will utilize a newly set 20” conductor on I-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 Doyon 14. Ensure rig is centered over conductor to prevent any wear to BOPE or
wellhead.
9.8 Mud loggers WILL NOT be used on either hole section.
9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80qF).
9.10 Ensure 6” liners in mud pumps.
x Continental EMSCO FB-1600 mud pumps are rated at 4665 psi, 462 gpm @ 110 spm @
95% volumetric efficiency.
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10.0 N/U 21-1/4” 2M Diverter System
10.1 N/U 21-1/4” Hydril MSP 2M Diverter System (Diverter Schematic attached to program).
x N/U 16-3/4” 3M x 21-1/4” 2M DSA on 16-3/4” 3M wellhead.
x N/U 21-1/4” diverter “T”.
x Knife gate, 16” diverter line.
x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
x Diverter line must be 75 ft from nearest ignition source
x Place drip berm at the end of diverter line.
10.2 Notify AOGCC. Function test diverter.
x Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens
prior to annular closure.
x Ensure that the annular closes in less than 45 seconds (API Standard 64 3rd edition March 2018
section 12.6.2 for packing element ID greater than 20”)
10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the
vent line tip. “Warning Zone” must include:
x A prohibition on vehicle parking
x A prohibition on ignition sources or running equipment
x A prohibition on staged equipment or materials
x Restriction of traffic to essential foot or vehicle traffic only.
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10.4 Rig & Diverter Orientation:
x May change on location
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11.0 Drill 12-1/4” Hole Section
11.1 P/U 12-1/4” directional drilling assembly:
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
x Use GWD until MWD surveys are clean.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
x Drill string will be 5” 19.5# S-135.
x Run a solid float in the surface hole section.
11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor.
x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in
conductor.
11.3 Drill 12-1/4” hole section to section TD, in the Schrader OA sand. Confirm this setting depth
with the Geologist and Drilling Engineer while drilling the well.
x Monitor the area around the conductor for any signs of broaching. If broaching is observed,
Stop drilling (or circulating) immediately notify Drilling Engineer.
x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100.
x Hold a safety meeting with rig crews to discuss:
x Conductor broaching ops and mitigation procedures.
x Well control procedures and rig evacuation
x Flow rates, hole cleaning, mud cooling, etc.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Keep mud as cool as possible to keep from washing out permafrost.
x Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can
handle the flow rate.
x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoff’s, increase in pump pressure, or changes in hookload are seen
x Slow in/out of slips and while tripping to keep swab and surge pressures low
x Ensure shakers are functioning properly. Check for holes in screens on connections.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea
gravel, clay balling or packing off.
x Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2
minimum at TD (pending MW increase due to hydrates).
x Drill ahead using GWD. Take MWD surveys every stand drilled and swap to MWD when
MWD surveys clean up.
x Gas hydrates have not been seen on I-Pad. However, be prepared for them. In MPU they
have been encountered typically around 2100’-2400’ TVD (just below permafrost). Be
prepared for hydrates:
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x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD
x Monitor returns for hydrates, checking pressurized & non-pressurized scales
x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by
washing out additional permafrost. Attempt to control drill (150 fph MAX) through the
zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be
reduced to prevent mud from belching over the bell nipple.
x Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well.
MW will not control gas hydrates, but will affect how gas breaks out at surface.
x AC:
x All wells have a clearance factor >1.0.
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 9.2+ ppg.
Depth Interval MW (ppg)
Surface – Base
Permafrost
8.9+
Base Permafrost - TD 9.2+
MW can be cut once ~500’ below hydrate
zone
PVT System: 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, 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)
can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore.
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).
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System Type:8.8 – 9.2 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- Surface hole Size Pkg ppb or (% liquids)
M-I Gel 50 lb sx 25
Soda Ash 50 lb sx 0.25
PolyPac Supreme UL 50 lb sx 0.08
Caustic Soda 50 lb sx 0.1
SCREENCLEEN 55 gal dm 0.5
11.4 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity.
11.5 RIH to bottom, proceed to BROOH to HWDP
x Pump at full drill rate (400-600 gpm), and maximize rotation.
x Pull slowly, 5 – 10 ft / minute.
x Monitor well for any signs of packing off or losses.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay
balling.
x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until
parameters are restored.
11.6 TOOH and LD BHA
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12.0 Run 9-5/8” Surface Casing
12.1 R/U Weatherford 9-5/8” casing running equipment (CRT & Tongs)
x Ensure 9-5/8” TXP x NC50 XO on rig floor and M/U to FOSV.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x R/U of CRT if hole conditions require.
x R/U a fill up tool to fill casing while running if the CRT is not used.
x Ensure all casing has been drifted to 8-1/2” on the location prior to running.
x Note that 47# drift is 8.525”
x Be sure to count the total # of joints on the location before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
12.2 P/U shoe joint, visually verify no debris inside joint.
12.3 Continue M/U & thread locking 120’ shoe track assembly consisting of:
9-5/8” Float Shoe
1 joint – 9-5/8” TXP, 2 Centralizers 10’ from each end w/ stop rings
1 joint –9-5/8” TXP, 1 Centralizer mid joint w/ stop ring
9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’
1 joint –9-5/8” TXP, 1 Centralizer mid joint with stop ring
9-5/8” HES Baffle Adaptor
x Ensure bypass baffle is correctly installed on top of float collar.
x Ensure proper operation of float equipment while picking up.
x Ensure to record S/N’s of all float equipment and stage tool components.
This end up.
Bypass Baffle
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12.4 Float equipment and Stage tool equipment drawings:
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12.5 Continue running 9-5/8” surface casing
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
x 1 centralizer every joint to ~ 1000’ MD from shoe
x 1 centralizer every 2 joints to ~2,000’ above shoe (Top of Lowest Ugnu)
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
x Any packing off while running casing should be treated as a major problem. It is preferable
to POH with casing and condition hole than to risk not getting cement returns to surface.
12.6 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below
the permafrost.
x Install centralizers over couplings on 5 joints below and 5 joints above stage tool.
x Do not place tongs on ES cementer, this can cause damage to the tool.
x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi.
9-5/8” 40# L-80 TXP Make-Up Torques:
Casing OD Minimum Optimum Maximum
9-5/8”18,860 ft-lbs 20,960 ft-lbs 23,060 ft-lbs
9-5/8” 47# L-80 TXP MUT:
Casing OD Minimum Optimum Maximum
9-5/8”21,440 ft-lbs 23,820 ft-lbs 26,200 ft-lbs
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12.7 Continue running 9-5/8” surface casing
x Centralizers: 1 centralizer every 3rd joint to 200’ from surface
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
o 1 centralizer every 2 joints to base of conductor
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12.8 Ensure the permafrost is covered with 9-5/8” 47# from BPRF to surface
x Ensure drifted to 8.525”
12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.10 Slow in and out of slips.
12.11 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.
12.12 Lower casing to setting depth. Confirm measurements.
12.13 Have slips staged in cellar along with all necessary equipment for the operation.
12.14 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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13.0 Cement 9-5/8” Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
x Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Ensure adequate amount of water for mix fluid is heated and available in the water tanks.
x Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
x Review test reports and ensure pump times are acceptable.
x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
13.2 Document efficiency of all possible displacement pumps prior to cement job.
13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
13.5 Fill surface cement lines with water and pressure test.
13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below
calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached.
13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead &
tail, TOC brought to stage tool.
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Estimated 1st Stage Total Cement Volume:
Cement Slurry Design (1st Stage Cement Job):
13.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue
with the cement job.
13.10 After pumping cement, drop top plug (shutoff plug) and displace cement with spud mud out of
mud pits, spotting water across the HEC stage cementer.
a. Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
13.11 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the plug
must be bumped.
13.12 Displacement calculation is in the Stage 1 Table in step 13.7.
80 bbls of tuned spacer to be left on top of stage tool so that the first fluid through the
ES cementer is tuned spacer to minimize the risk of flash setting cement
13.13 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any
point during the job. Be prepared to pump out fluid from cellar. Have black water available to
contaminate any cement seen at surface.
13.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Over
displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling
Engineer. 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.
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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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.
13.16 Increase pressure to 3300 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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Second Stage Surface Cement Job:
13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive
strength. Hold pre-job safety meeting.
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. However cement will continue to be
pumped until clean spacer is observed at surface.
Estimated 2nd Stage Total Cement Volume:
Cement Slurry Design (2nd stage cement job):
13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail.
13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out
of mud pits.
13.26 Displacement is in the Stage 2 table in step 13.22.
Lead Slurry Tail Slurry
System ArcticCem HalCem
Density 10.7 lb/gal 15.8 lb/gal
Yield 2.88 ft3/sk 1.17 ft3/sk
Mixed
Water 22.02 gal/sk 5.08 gal/sk
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Drilling Procedure
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 Land closing plug on stage collar and pressure up to 1000 – 1500 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
13.29 Make initial cut on 9-5/8” final joint. L/D cut joint. Make final cut on 9-5/8”. Dress off stump.
Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule.
Ensure to report the following on wellez:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement, actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
x Note calculated top of cement
x Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to nathan.sperry@hilcorp.com and
joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the
AOGCC.
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14.0 BOP N/U and Test
14.1 N/D the diverter T, knife gate, diverter line & N/U 11” x 13-5/8” 5M casing spool.
14.2 N/U 13-5/8” x 5M BOP as follows:
x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13-
5/8” x 5M mud cross / 13-5/8” x 5M single gate
x Double gate ram should be dressed with 2-7/8” x 5” VBRs in top cavity,blind ram in
bottom cavity.
x Single ram can be dressed with 2-7/8” x 5” VBRs
x N/U bell nipple, install flowline.
x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to
mud cross).
x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual
valve
14.3 Run 5” BOP test plug
14.4 Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min.
x Test 2-7/8” x 5” rams with the 3-1/2” and 5” test joints
x Confirm test pressures with PTD
x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure
is trapped underneath test plug
x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech
14.5 R/D BOP test equipment
14.6 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.7 Mix 8.9 ppg Baradrill-N fluid for production hole.
14.8 Set wearbushing in wellhead.
14.9 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole
section.
14.10 Ensure 6” liners in mud pumps.
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15.0 Drill 8-1/2” Hole Section
15.1 M/U 8.5” 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 R/U and test casing to 2500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and
plot on FIT graph. AOGCC reg is 50% of burst = 5750 / 2 = ~2875 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. Pump at least one high vis sweep at maximum rate to surface to
clean up debris.
15.7 Conduct FIT to 12.0 ppg EMW. Chart test. Ensure test is recorded on same chart as FIT.
Document incremental volume pumped (and subsequent pressure) and volume returned.
x 12.0 ppg desired to cover shoe strength for expected ECD’s. A 9.9 ppg FIT is the minimum
required to drill ahead
x 9.9 ppg provides >25 bbls based on 9.5ppg MW, 8.46ppg PP (swab kick at 9.5ppg BHP)
15.8 POOH & LD Cleanout BHA
15.9 P/U 8-1/2” RSS directional BHA.
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components that
cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Ensure MWD is R/U and operational.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
x Drill string will be 5” 19.5# S-135 DS50 & NC50.
x Run a ported float in the production hole section.
Schrader Bluff Bit Jetting Guidelines
Formation Jetting TFA
NB 6 x 14 0.902
OA 6 x 13 0.778
OB 6 x 13 0.778
Email casing test and digital data to AOGCC immediately upon completion of FIT.
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15.10 8-1/2” hole section mud program summary:
x Density: Weighting material to be used for the hole section will be calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg
above highest anticipated MW.
x Solids Concentration: It is imperative that the solids concentration be kept low while
drilling the production hole section. Keep the shaker screen size optimized and fluid
running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure
we are running the finest screens possible.
x Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests
excessive viscosifier concentrations can decrease return permeability. Do not pump high
vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for
sufficient hole cleaning
x Run the centrifuge continuously while drilling the production hole, this will help with
solids removal.
x Dump and dilute as necessary to keep drilled solids to an absolute minimum.
x MD Totco PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, &
Toolpusher office.
System Type:8.9 – 9.5 ppg FloPro drilling fluid
Properties:
Interval Density PV YP LSYP Total Solids MBT HPHT Hardness
Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100
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Drilling Procedure
System Formulation:
Product- production Size Pkg ppb or (% liquids)
Busan 1060 55 gal dm 0.095
FLOTROL 55 lb sx 6
CONQOR 404 WH (8.5 gal/100 bbls)55 gal dm 0.2
FLO-VIS PLUS 25 lb sx 0.7
KCl 50 lb sx 10.7
SMB 50 lb sx 0.45
LOTORQ 55 gal dm 1.0
SAFE-CARB 10 (verify)50 lb sx 10
SAFE-CARB 20 (verify)50 lb sx 10
Soda Ash 50 lb sx 0.5
15.11 TIH with 8-1/2” directional assembly to bottom
15.12 Displace wellbore to 8.9 ppg FloPro drilling fluid
15.13 Begin drilling 8-1/2” hole section, on-bottom staging technique:
x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k.
x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations
x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to P/U
off bottom and restart on bottom staging technique. If stick slip continues, consider adding
0.5% lubes
15.14 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer.
x Flow Rate: 350-550 gpm, target min. AV’s 200 ft/min, 385 gpm
x RPM: 120+
x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly
wet to maximize solids removal efficiency. Check for holes in screens on every connection.
x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
x Monitor Torque and Drag with pumps on every stand (confirm frequency with co man)
x Monitor ECD, pump pressure & hookload trends for hole cleaning indication
x Surveys can be taken more frequently if deemed necessary.
x Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible and avoid stopping with the
BHA across the sand for any extended period of time.
x Use ADR to stay in section.
x Limit maximum instantaneous ROP to < 250 fph. The sands will drill faster than this, but
when concretions are hit when drilling this fast, cutter damage can occur.
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x Target ROP is as fast as we can clean the hole (under 250 fph) without having to backream
connections
x Watch for higher than expected pressure. MPD will be utilized to monitor pressure build up
on connections
x 8-1/2” Lateral A/C:
x I-08 has a 0.769 CF. This is an NB, OA, and OB water injector that has been shut-in
since March 2020. There is no HSE associated with a collision. The risk is financial as a
collision would result in a bit trip and open hole sidetrack. The plan is to geosteer away
from I-08 to minimize the collision risk.
x I-09 has a 0.361 CF. I-09 was abandoned below 5,518’ MD and re-completed in Prince
Creek uphole. The close approach occurs below the TOC in the abandoned portion of the
well. There is no HSE risk. Collision would result in a bit trip and open hole sidetrack.
x I-19L1 has a 0.777 CF. This is an OA/OB multilateral that has been P&A’d with cement
in both laterals. There is no HSE associated with a collision. The risk is financial as a
collision would result in a bit trip and open hole sidetrack.
x I-30 has a 0.805 CF. I-30 is a Schrader OA injector. I-30 will be shut-in and we will
geosteer away to maintain geologic separation.
x J-08A has a 0.018 CF. This is a Schrader OB producer in the same pressure regime. J-
08A has been reservoir abandoned via a coil cement job. The plan is to geosteer away
from J-08A to minimize the collision risk.
x J-09 has a 0.836 CF. This well was abandoned for the J-09A sidetrack. There is no HSE
risk. The risk is financial as a collision would result in a bit trip and open hole sidetrack.
x J-15 has a 0.087 CF. This is an NB/OA/OB well that has been P&A’d to surface. There
is no HSE risk. The risk is financial as a collision would result in a bit trip and open hole
sidetrack.
x J-22 has a 0.272 CF. J-22 has been abandoned. There is no HSE risk. The risk is
financial as a collision would result in a bit trip and open hole sidetrack.
x Schrader Bluff OBa Concretions: 4-6%
15.15 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons
learned and best practices. Ensure the DD is referencing their procedure.
x Patience is key! Getting kicked off too quickly might have been the cause of failed liner
runs on past wells.
x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so
we have a nice place to low side.
x Attempt to sidetrack low and right in a fast drilling interval where the wellbore is headed up.
x Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working
string back and forth. Trough for approximately 30 minutes.
x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the
openhole sidetrack is achieved.
15.16 At TD, CBU (minimum 4X, more if needed) at 200 ft/min AV (385+ gpm) and rotation (120+
rpm). Pump tandem sweeps if needed
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x Rack back a stand at each bottoms up and reciprocate a full stand in between (while
circulating the BU). Keep the pipe moving while pumping.
x Monitor BU for increase in cuttings. Cuttings in laterals will come back in waves and not a
consistent stream so circulate more if necessary
x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum
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.
x Losses during the cleanup of the wellbore are a good indication that the mud filter cake is
being removed, including an increase in the loss rate.
15.18 Displace 1.5 OH + Liner volume with viscosified brine.
x Proposed brine blend (aiming for an 8 on the 6 RPM reading) -
KCl: 7.1bbp for 2%
NaCl: 60.9 ppg for 9.4 ppg
Lotorq: 1.5%
Lube 776: 1.5%
Soda Ash: as needed for 9.5pH
Busan 1060: 0.42 ppb
Flo-Vis Plus: 1.25 ppb
x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further
discussion needed prior to BROOH.
15.19 BROOH with the drilling assembly to the 9-5/8” casing shoe. Note: PST test is NOT required.
x Circulate at full drill rate unless losses are seen (350 gpm minimum if on losses)
x Rotate at maximum rpm that can be sustained.
x Target pulling speed of 5 – 10 min/std (slip to slip time, not including connections), but
adjust as hole conditions dictate.
x When pulling across any OHST depths, turn pumps off and rotary off to minimize
disturbance. Trip back in hole past OHST depth to ensure liner will stay in correct
hole section, check with ABI compared to as drilled surveys
15.20 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps.
15.21 Monitor well for flow. Increase mud weight if necessary
x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to
determine if well is breathing, treat all flow as an influx until proven otherwise
x If necessary, increase MW at shoe for any higher than expected pressure seen
x Ensure fluid coming out of hole has passed a PST at the possum belly
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15.22 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball
drops.
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16.0 Run 5-1/2” x 4-1/2” Injection Liner (Lower Completion)
NOTE: If an open hole sidetrack was performed, drop the centralizers on the lowermost 2-3 joints and
run them slick.
16.1.Well control preparedness: In the event of an influx of formation fluids while running the 4-
1/2” injection liner with slotted liner, the following well control response procedure will be
followed:
x With a 5-1/2” joint across the BOP: P/U & M/U the 5” safety joint (with 5-1/2” crossover
installed on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW).
This joint shall be fully M/U and available prior to running the first joint of 5-1/2” liner.
x With 4-1/2” joint across BOP: P/U & M/U the 5” safety joint (with 4-1/2” crossover installed
on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW). This joint
shall be fully M/U and available prior to running the first joint of 4-1/2” liner.
16.2. Confirm VBR’s have been tested to cover 3-1/2” and 5” pipe sizes to 250 psi low/3000 psi high.
16.3. R/U 5-1/2” and 4-1/2” liner running equipment.
x Ensure 5-1/2” and 4-1/2” Hydril 625 x DS-50 crossovers are on rig floor and M/U to FOSV.
x Ensure the liner has been drifted on the deck prior to running.
x Be sure to count the total # of joints on the deck before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
16.4. Run 5-1/2” x 4-1/2” injection liner.
x Injection liner will be a combination of slotted and solid joints. Every third joint in the open
hole is to be a slotted joint. Confirm with OE.
x Lowermost 9,500’ will be 4-1/2”.
x 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
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Use lift nubbins and stabbing guides for the liner run.
x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each jt
outside of the surface shoe. This is to mitigate sticking risk while running inner string.
x Obtain up and down weights of the liner before entering open hole. Record rotating torque at
10 and 20 rpm
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5-1/2” 17# L-80 JFE Bear
Casing OD Minimum Optimum Maximum
Operating Torque
5.5” 6,660 ft-lbs 7,400 ft-lbs 8,140 ft-lbs
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Drilling Procedure
4-1/2” 13.5# L-80 H625
Casing OD Minimum Optimum Maximum
Operating Torque
4.5” 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs
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16.6. Ensure that the liner top packer is set ~150’ MD above the 9-5/8” shoe.
x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as
per 20 AAC 25.030(d)(6). Ensure hanger/packer will not be set in a 9-5/8” connection.
16.7. 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.
16.8. M/U Baker SLZXP liner top packer to 4-1/2” liner.
16.9. 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.
16.10. RIH with liner no faster than 30 ft/min – this is to prevent buckling the liner and drill string and
weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and
avoid surging the hole or buckling the liner. Slow down running speed if necessary.
x Ensure 5” DP/HWDP has been drifted
x There is no inner string planned to be run, as opposed to previous wells. The DP should auto
fill. Monitor FL and if filling is required due to losses/surging.
16.11. 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.
16.12. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
& 20 RPM.
16.13. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
16.14. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
16.15. Rig up to pump down the work string with the rig pumps.
16.16. 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
16.17. 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.
16.18. Shut down pumps. Drop setting ball down the workstring and pump slowly (1-2 BPM). Slow
pump before the ball seats. Do not allow ball to slam into ball seat.
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16.19. 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.
16.20. 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.
16.21. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted.
16.22. 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.
16.23. PU pulling running tool free of the packer and displace with at max rate to wash the liner top.
Pump sweeps as needed.
16.24. 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 40
Milne Point Unit
I-23 SB Injector
Drilling Procedure
17.0 Run 3-1/2” Tubing (Upper Completion)
17.1 Notify the AOGCC at least 24 hours in advance of the IA pressure test after running the
completion as per 20 AAC 25.412 (e).
17.2 M/U injection assembly and RIH to setting depth. TIH no faster than 90 ft/min.
x Ensure wear bushing is pulled.
x Ensure 3-½” EUE 8RD x NC-50 crossover is on rig floor and M/U to FOSV.
x Ensure all tubing has been drifted in the pipe shed prior to running.
x Be sure to count the total # of joints in the pipe shed before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
x Monitor displacement from wellbore while RIH.
3-1/2” 9.3# L-80 EUE 8RD
Casing OD Minimum Optimum Maximum
Operating Torque
3.5” 2,350 ft-lbs 3,130 ft-lbs 3,910 ft-lbs
3-½” Upper Completion Running Order
x 3-½” Baker Ported Bullet Nose seal (stung into the tie back receptacle)
x 3 joints (minimum, more as needed) 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x 3-½” “XN” nipple at TBD (Set below 70 degrees)
x 1 joint 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x 3-½” SGM-FS XDPG Gauge at TBD
x 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x 3-½” 9.3#/ft, L-80 EUE 8RD space out pups
x 1 joint 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x Tubing hanger with 3-1/2” EUE 8RD pin down
17.3 Locate and no-go out the seal assembly. Close annular and test to 400 psi to confirm seals
engaged.
17.4 Bleed pressure and open annular. Space out the completion (+/- 1’ to 2’ above No-Go). Place all
space out pups below the first full joint of the completion.
Page 41
Milne Point Unit
I-23 SB Injector
Drilling Procedure
17.5 Makeup the tubing hanger and landing joint.
17.6 RIH. Close annular and test to 400 – 500 psi to confirm seals are engaged. Bleed pressure down
to 250 psi. PU until ports in seal assembly exposed.
17.7 Reverse circulate the well with brine and 1% corrosion inhibitor.
17.8 Freeze protect the tubing and IA to ~3000’ MD with ±210 bbl of diesel.
17.9 Land hanger. RILDs and test hanger.
17.10 Continue pressurizing the annulus to 3500 psi and test for 30 charted minutes.
i.Provide proper notification to the AOGCC for the right to witness the test.
ii. Complete form 10-426 and submit to the required recipients. Copy
nathan.sperry@hilcorp.com and ryan.thompson@hilcorp.com on the e-mail.
17.11 Set BPV, ensure new body seals are installed each time. ND BOPE and NU adapter flange and
tree.
17.12 Pull BPV. Set TWC. Test tree to 5000 psi.
17.13 Pull TWC. Set BPV. Bullhead tubing freeze protect.
17.14 Secure the tree and cellar.
18.0 RDMO
18. RDMO Doyon 14
Page 42
Milne Point Unit
I-23 SB Injector
Drilling Procedure
19.0 Post-Rig Work
Operations-Convert well on surface with hard line to a jet pump producer.
19.1 MU surface lines from power fluid header to existing IA.
a. Pressure test lines at existing power fluid header pressure (3,600 psi)
19.2 Rig up hardline to neighboring wells production header and test header. Pressure test to 3600 psi.
19.3 MIRU SL and Little Red Pumping Unit. PT lines to 3,000 psi.
19.4 Shift Sliding sleeve open
19.5 Set 12B jet pump
19.6 RDMO
SL/FB- After 30 days of production
19.7 MIRU SL and Little Red Pumping Unit. PT lines to 3,000 psi.
19.8 FB circ IA with corrosion inhibited brine down to SS with a FP cap down to 2000’ on IA
19.9 Pull Jet Pump
19.10 Shift SS closed
19.11 MIT-IA test to 2000 psi
19.12 POI
19.13 After 5 days of stabilized injection MIT-IA to 2000 psi (Charted and state witnessed)
Page 43
Milne Point Unit
I-23 SB Injector
Drilling Procedure
20.0 Doyon 14 Diverter Schematic
Page 44
Milne Point Unit
I-23 SB Injector
Drilling Procedure
21.0 Doyon 14 BOP Schematic
2-7/8” x 5” VBR
Page 45
Milne Point Unit
I-23 SB Injector
Drilling Procedure
22.0 Wellhead Schematic
Page 46
Milne Point Unit
I-23 SB Injector
Drilling Procedure
23.0 Days Vs Depth
Page 47
Milne Point Unit
I-23 SB Injector
Drilling Procedure
24.0 Formation Tops & Information
MPU I-23 Formations TVD
(ft)
TVDss
(ft)
MD
(ft)
Formation Pressure
(psi)
EMW
(ppg)
BPRF 1804 1737 1985 794 8.46
SV1 2011 1944 2238 885 8.46
UG4 2291 2224 2590 1008 8.46
UG_MB 3479 3412 4915 1531 8.46
SCHRADER NB 3724 3657 5620 1638 8.46
SCHRADER OBa 3997 3930 6841 1758 8.46
I-pad Data Sheet Formation Description
Page 48
Milne Point Unit
I-23 SB Injector
Drilling Procedure
25.0 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
Gas hyrates have not been seen on Moose pad. However, be prepared for them. Remember that hydrate
gas behave 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 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 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 a number of wells in close proximity. Take directional surveys every stand, take additional
surveys if necessary. Continuously monitor proximity to offset wellbores and record any close
approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in
adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Well
specific A/C:
x All wells pass AC.
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. I-04A had 36ppm H2S (2012).
Page 49
Milne Point Unit
I-23 SB Injector
Drilling Procedure
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Page 50
Milne Point Unit
I-23 SB Injector
Drilling Procedure
8-1/2” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
appropriately 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:
There is at least (5) faults that will be crossed while drilling the well. There could be others and the
throw of these faults is not well understood at this point in time. When a known fault is coming up,
ensure to put a “ramp” in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed,
we’ll need to either drill up or down to get a look at the LWD log and determine the throw and then
replan the wellbore.
H2S:
Treat every hole section as though it has the potential for H2S. No H2S events have been documented
on drill wells on this pad.
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.
Abnormal Pressures and Temperatures:
Reservoir pressures are expected to be normal. Abnormal (offset injection) pressure has been seen on M-
Pad. Utilize MPD to mitigate any abnormal pressure seen.
See emails. -A.Dewhurst 06MAR24
Page 51
Milne Point Unit
I-23 SB Injector
Drilling Procedure
Anti-Collision
Take directional surveys every stand, take additional surveys if necessary. Continuously monitor
drilling parameters for signs of magnetic interference with another well. Reference A/C report in
directional plan. Well specific AC:
8-1/2” Lateral A/C:
x I-08 has a 0.769 CF. This is an NB, OA, and OB water injector that has been shut-in
since March 2020. There is no HSE associated with a collision. The risk is financial as a
collision would result in a bit trip and open hole sidetrack. The plan is to geosteer away
from I-08 to minimize the collision risk.
x I-09 has a 0.361 CF. I-09 was abandoned below 5,518’ MD and re-completed in Prince
Creek uphole. The close approach occurs below the TOC in the abandoned portion of the
well. There is no HSE risk. Collision would result in a bit trip and open hole sidetrack.
x I-19L1 has a 0.777 CF. This is an OA/OB multilateral that has been P&A’d with cement
in both laterals. There is no HSE associated with a collision. The risk is financial as a
collision would result in a bit trip and open hole sidetrack.
x I-30 has a 0.805 CF. I-30 is a Schrader OA injector. I-30 will be shut-in and we will
geosteer away to maintain geologic separation.
x J-08A has a 0.018 CF. This is a Schrader OB producer in the same pressure regime. J-
08A has been reservoir abandoned via a coil cement job. The plan is to geosteer away
from J-08A to minimize the collision risk.
x J-09 has a 0.836 CF. This well was abandoned for the J-09A sidetrack. There is no HSE
risk. The risk is financial as a collision would result in a bit trip and open hole sidetrack.
x J-15 has a 0.087 CF. This is an NB/OA/OB well that has been P&A’d to surface. There
is no HSE risk. The risk is financial as a collision would result in a bit trip and open hole
sidetrack.
x J-22 has a 0.272 CF. J-22 has been abandoned. There is no HSE risk. The risk is
financial as a collision would result in a bit trip and open hole sidetrack.
Page 52
Milne Point Unit
I-23 SB Injector
Drilling Procedure
26.0 Doyon 14 Layout
Page 53
Milne Point Unit
I-23 SB Injector
Drilling Procedure
27.0 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 54Milne Point Unit I-23 SB InjectorDrilling Procedure28.0 Doyon 14 Choke Manifold Schematic
Page 55
Milne Point Unit
I-23 SB Injector
Drilling Procedure
29.0 Casing Design
Page 56
Milne Point Unit
I-23 SB Injector
Drilling Procedure
30.0 8-1/2” Hole Section MASP
Page 57
Milne Point Unit
I-23 SB Injector
Drilling Procedure
31.0 Spider Plot (NAD 27) (Governmental Sections)
Page 58
Milne Point Unit
I-23 SB Injector
Drilling Procedure
32.0 Surface Plat (As-Built) (NAD 27)
6WDQGDUG3URSRVDO5HSRUW
)HEUXDU\
3ODQ 038,ZS
+LOFRUS$ODVND//&
0LOQH3RLQW
03W,3DG
3ODQ 038,L
038,L
0
750
1500
2250
3000
3750
4500True Vertical Depth (1500 usft/in)-750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500
Vertical Section at 356.92° (1500 usft/in)
MPU I-23 wp07 Heel
MPU I-23 wp07 CP02
MPU I-23 wp07 CP03
MPU I-23 wp07 CP04
MPU I-23 wp07 CP05
MPU I-23 wp07 CP06
MPU I-23 wp07 CP07
MPU I-23 wp07 CP08
MPU I-23 wp07 CP09
MPU I-23 wp07 CP10
MPU I-23 wp07 CP11
MPU I-23 wp07 CP12
MPU I-23 wp07 CP13
MPU I-23 wp07 CP14
MPU I-23 wp07 CP15
MPU I-23 wp07 CP16
MPU I-23 wp07 CP17
MPU I-23 wp07 Toe
9 5/8" x 12 1/4"
4 1/2" x 8 1/2"
500
1000
1
5
0
0
2000
2500
3 000
3 5 0 0
4000450050005500600065007000750080008500900095001000010500110001150012000125001300013500140001450015000155001600016500170001750018000185001900019547MPU I-23 wp08
Start Dir 2º/100' : 350' MD, 350'TVD
Start Dir 3º/100' : 450' MD, 449.98'TVD
Start Dir 4º/100' : 750' MD, 747.74'TVD
End Dir : 4007.65' MD, 3163.59' TVD
Start Dir 5º/100' : 5609.43' MD, 3719.96'TVD
End Dir : 6740.83' MD, 3987.88' TVD
Start Dir 3.2º/100' : 6840.83' MD, 3996.6'TVD
End Dir : 7087.02' MD, 4001.16' TVD
Begin geosteering lateral
Total Depth : 19547.06' MD, 4339.6' TV
SV6
Base Permafrost
SV1
UG4
UG_MB
SB_NB
SB_OBA
Hilcorp Alaska, LLC
Calculation Method:Minimum Curvature
Error System:ISCWSA
Scan Method: Closest Approach 3D
Error Surface: Ellipsoid Separation
Warning Method: Error Ratio
WELL DETAILS: Plan: MPU I-23i
32.90
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 6009447.21 551630.03 70° 26' 11.6064 N 149° 34' 44.5855 W
SURVEY PROGRAM
Date: 2023-08-25T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
33.70 1200.00 MPU I-23 wp08 (MPU I-23i) GYD_Quest GWD
1200.00 7090.00 MPU I-23 wp08 (MPU I-23i) 3_MWD+IFR2+MS+Sag
7090.00 19547.06 MPU I-23 wp08 (MPU I-23i) 3_MWD+IFR2+MS+Sag
FORMATION TOP DETAILS
TVDPath TVDssPath MDPath Formation
828.60 762.00 832.88 SV6
1803.60 1737.00 1985.18 Base Permafrost
2010.60 1944.00 2237.92 SV1
2290.60 2224.00 2590.31 UG4
3478.60 3412.00 4914.55 UG_MB
3723.60 3657.00 5619.92 SB_NB
3996.60 3930.00 6840.83 SB_OBA
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: MPU I-23i, True North
Vertical (TVD) Reference:MPU I-23 as built @ 66.60usft
Measured Depth Reference:MPU I-23 as built @ 66.60usft
Calculation Method: Minimum Curvature
Project:Milne Point
Site:M Pt I Pad
Well:Plan: MPU I-23i
Wellbore:MPU I-23i
Design:MPU I-23 wp08
CASING DETAILS
TVD TVDSS MD Size Name
4001.01 3934.41 7090.00 9-5/8 9 5/8" x 12 1/4"
4339.60 4273.00 19547.06 4-1/2 4 1/2" x 8 1/2"
SECTION DETAILS
Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation
1 33.70 0.00 0.00 33.70 0.00 0.00 0.00 0.00 0.00
2 350.00 0.00 0.00 350.00 0.00 0.00 0.00 0.00 0.00 Start Dir 2º/100' : 350' MD, 350'TVD
3 450.00 2.00 178.00 449.98 -1.74 0.06 2.00 178.00 -1.74 Start Dir 3º/100' : 450' MD, 449.98'TVD
4 750.00 11.00 178.00 747.74 -35.65 1.24 3.00 0.00 -35.66 Start Dir 4º/100' : 750' MD, 747.74'TVD
5 1480.00 40.20 178.00 1398.98 -347.48 12.13 4.00 0.00 -347.63
6 2430.00 37.96 240.10 2164.56 -816.88 -239.75 4.00 118.00 -802.82
7 4007.65 69.68 312.07 3163.59 -533.93 -1321.04 4.00 89.03 -462.20 End Dir : 4007.65' MD, 3163.59' TVD
8 5609.43 69.68 312.07 3719.96 472.53 -2436.02 0.00 0.00 602.70 Start Dir 5º/100' : 5609.43' MD, 3719.96'TVD
9 6740.83 85.00 8.20 3987.88 1467.98 -2777.63 5.00 82.35 1615.06 End Dir : 6740.83' MD, 3987.88' TVD
10 6840.83 85.00 8.20 3996.60 1566.58 -2763.43 0.00 0.00 1712.75 MPU I-23 wp07 Heel Start Dir 3.2º/100' : 6840.83' MD, 3996.6'TVD
11 7087.02 92.88 8.25 4001.16 1810.00 -2728.23 3.20 0.39 1953.93 End Dir : 7087.02' MD, 4001.16' TVD
12 7231.96 92.88 8.25 3993.88 1953.26 -2707.45 0.00 0.00 2095.87
13 7311.33 93.30 10.60 3989.60 2031.44 -2694.47 3.00 79.71 2173.24 MPU I-23 wp07 CP02
14 7751.32 86.71 359.00 3989.54 2468.89 -2657.73 3.03 -119.49 2608.09
15 8054.03 86.71 359.00 4006.89 2771.07 -2662.99 0.00 0.00 2910.11
16 8197.25 85.00 3.00 4017.24 2913.86 -2660.50 3.03 113.40 3052.56
17 8247.25 85.00 3.00 4021.60 2963.60 -2657.89 0.00 0.00 3102.09 MPU I-23 wp07 CP04
18 8528.08 93.22 1.14 4025.97 3243.96 -2647.77 3.00 -12.79 3381.50
19 8722.58 93.22 1.14 4015.05 3438.11 -2643.91 0.00 0.00 3575.16
20 9026.87 91.00 10.00 4003.84 3740.44 -2614.42 3.00 103.86 3875.47
21 9326.87 91.00 10.00 3998.60 4035.83 -2562.33 0.00 0.00 4167.64 MPU I-23 wp07 CP06
22 9551.00 86.78 5.98 4002.94 4257.65 -2531.19 2.60 -136.40 4387.47
23 10677.73 86.78 5.98 4066.22 5376.48 -2414.01 0.00 0.00 5498.39
24 10718.39 86.50 7.00 4068.60 5416.82 -2409.43 2.60 105.42 5538.42 MPU I-23 wp07 CP08
25 11105.65 90.70 16.16 4078.08 5795.59 -2331.80 2.60 65.51 5912.47
26 11432.11 90.70 16.16 4074.08 6109.13 -2240.97 0.00 0.00 6220.68
27 11682.24 88.60 10.00 4075.61 6352.64 -2184.40 2.60 -108.85 6460.81
28 12582.24 88.60 10.00 4097.60 7238.70 -2028.17 0.00 0.00 7337.20 MPU I-23 wp07 CP10
29 12728.01 88.62 5.63 4101.14 7383.04 -2008.36 3.00 -89.82 7480.26
30 13235.44 88.62 5.63 4113.38 7887.88 -1958.63 0.00 0.00 7981.70
31 13547.86 88.74 15.00 4120.60 8194.82 -1902.78 3.00 89.36 8285.20 MPU I-23 wp07 CP11
32 13589.21 88.32 14.05 4121.66 8234.84 -1892.41 2.50 -113.74 8324.60
33 14749.65 88.32 14.05 4155.60 9360.07 -1610.75 0.00 0.00 9433.08 MPU I-23 wp07 CP12
34 14790.48 88.29 12.99 4156.81 9399.75 -1601.21 2.60 -91.71 9472.19
35 15724.48 88.29 12.99 4184.63 10309.44 -1391.33 0.00 0.00 10369.29
36 15878.58 88.30 17.00 4189.22 10458.19 -1351.48 2.60 89.95 10515.69
37 16228.58 88.30 17.00 4199.60 10792.75 -1249.19 0.00 0.00 10844.27 MPU I-23 wp07 CP13
38 16507.12 88.26 10.03 4207.98 11063.29 -1184.16 2.50 -90.46 11110.92
39 17185.13 88.26 10.03 4228.60 11730.61 -1066.09 0.00 0.00 11770.94 MPU I-23 wp07 CP14
40 17378.36 83.37 8.85 4242.70 11920.66 -1034.48 2.60 -166.47 11959.02
41 17654.62 83.37 8.85 4274.58 12191.81 -992.25 0.00 0.00 12227.51
42 17820.70 87.00 6.50 4288.52 12355.78 -970.16 2.60 -32.97 12390.06
43 18070.70 87.00 6.50 4301.60 12603.83 -941.90 0.00 0.00 12636.23 MPU I-23 wp07 CP16
44 18098.56 86.87 7.19 4303.09 12631.45 -938.58 2.50 100.49 12663.63
45 18529.62 86.87 7.19 4326.60 13058.49 -884.74 0.00 0.00 13087.17 MPU I-23 wp07 CP17
46 18630.41 89.39 7.23 4329.88 13158.42 -872.10 2.50 1.02 13186.27
47 19547.06 89.39 7.23 4339.60 14067.73 -756.74 0.00 0.00 14088.07 MPU I-23 wp07 Toe Total Depth : 19547.06' MD, 4339.6' TVD
-3000
-2000
-1000
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
10000
11000
12000
13000
14000
15000
16000
South(-)/North(+) (2000 usft/in)-8000 -7000 -6000 -5000 -4000 -3000 -2000 -1000 0 1000 2000 3000 4000 5000
West(-)/East(+) (2000 usft/in)
MPU I-23 wp07 Toe
MPU I-23 wp07 CP17
MPU I-23 wp07 CP16
MPU I-23 wp07 CP15
MPU I-23 wp07 CP14
MPU I-23 wp07 CP13
MPU I-23 wp07 CP12
MPU I-23 wp07 CP11
MPU I-23 wp07 CP10
MPU I-23 wp07 CP09
MPU I-23 wp07 CP08
MPU I-23 wp07 CP07
MPU I-23 wp07 CP06
MPU I-23 wp07 CP05
MPU I-23 wp07 CP04
MPU I-23 wp07 CP03
MPU I-23 wp07 CP02
MPU I-23 wp07 Heel
9 5/8" x 12 1/4"
4 1/2" x 8 1/2"
750
1500
2
0
0
025
0030003250350037504000
4250
4340
MPU I-23 wp08
Start Dir 2º/100' : 350' MD, 350'TVD
Start Dir 3º/100' : 450' MD, 449.98'TVD
Start Dir 4º/100' : 750' MD, 747.74'TVD
End Dir : 4007.65' MD, 3163.59' TVD
Start Dir 5º/100' : 5609.43' MD, 3719.96'TVD
End Dir : 6740.83' MD, 3987.88' TVD
Start Dir 3.2º/100' : 6840.83' MD, 3996.6'TVD
End Dir : 7087.02' MD, 4001.16' TVD
Begin geosteering lateral
Total Depth : 19547.06' MD, 4339.6' TVD
CASING DETAILS
TVD TVDSS MD Size Name
4001.01 3934.41 7090.00 9-5/8 9 5/8" x 12 1/4"
4339.60 4273.00 19547.06 4-1/2 4 1/2" x 8 1/2"
Project: Milne Point
Site: M Pt I Pad
Well: Plan: MPU I-23i
Wellbore: MPU I-23i
Plan: MPU I-23 wp08
WELL DETAILS: Plan: MPU I-23i
32.90
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 6009447.21 551630.03 70° 26' 11.6064 N
149° 34' 44.5855 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: MPU I-23i, True North
Vertical (TVD) Reference:MPU I-23 as built @ 66.60usft
Measured Depth Reference:MPU I-23 as built @ 66.60usft
Calculation Method:Minimum Curvature
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0.00
1.00
2.00
3.00
4.00
Separation Factor0 375 750 1125 1500 1875 2250 2625 3000 3375 3750 4125 4500 4875 5250 5625 6000 6375 6750 7125
Measured Depth (750 usft/in)
MPI-03
MPU I-22 wp06
MPI-09MPI-18
MPU I-37iMPI-02
MPI-08
WSAK-25
MPI-16
MPI-17L1
MPI-17
No-Go Zone - Stop Drilling
Collision Avoidance Required
Collision Risk Procedures Req.
NOERRORS
WELL DETAILS:Plan: MPU I-23i NAD 1927 (NADCON CONUS)Alaska Zone 04
32.90
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 6009447.21 551630.03 70° 26' 11.6064 N 149° 34' 44.5855 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: MPU I-23i, True North
Vertical (TVD) Reference:MPU I-23 as built @ 66.60usft
Measured Depth Reference:MPU I-23 as built @ 66.60usft
Calculation Method:Minimum Curvature
SURVEY PROGRAM
Date: 2023-08-25T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
33.70 1200.00 MPU I-23 wp08 (MPU I-23i) GYD_Quest GWD
1200.00 7090.00 MPU I-23 wp08 (MPU I-23i) 3_MWD+IFR2+MS+Sag
7090.00 19547.06 MPU I-23 wp08 (MPU I-23i) 3_MWD+IFR2+MS+Sag
0.00
30.00
60.00
90.00
120.00
150.00
180.00
Centre to Centre Separation (60.00 usft/in)0 375 750 1125 1500 1875 2250 2625 3000 3375 3750 4125 4500 4875 5250 5625 6000 6375 6750 7125
Measured Depth (750 usft/in)
MPI-03
MPU I-22 wp06
MPU I-29
MPI-09
MPI-10
MPU I-28i
MPI-05MPI-01
MPU I-37i
MPI-06
MPI-02
MPU I-21i
MPI-15
MPU I-31
MPU I-38
MPI-04
MPI-16
MPI-07
MPU I-36
MPU I-30i
MPU I-24 wp08
MPU I-35i
MPI-17
NO GLOBAL FILTER: Using user defined selection & filtering criteria
33.70 To 19547.06
Project: Milne Point
Site: M Pt I Pad
Well: Plan: MPU I-23i
Wellbore: MPU I-23i
Plan: MPU I-23 wp08
Ladder / S.F. Plots
1 of 2
CASING DETAILS
TVD TVDSS MD Size Name
4001.01 3934.41 7090.00 9-5/8 9 5/8" x 12 1/4"
4339.60 4273.00 19547.06 4-1/2 4 1/2" x 8 1/2"
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0.00
1.00
2.00
3.00
4.00
Separation Factor7150 7800 8450 9100 9750 10400 11050 11700 12350 13000 13650 14300 14950 15600 16250 16900 17550 18200 18850 19500
Measured Depth (1300 usft/in)
MPJ-15
MPU I-22 wp06
MPU I-25 wp11
MPU I-29
MPJ-16
MPJ-22
MPI-09
MPU I-32
MPJ-08A
MPU I-37i
MPI-19L1
MPJ-19A
MPJ-25 MPJ-09
MPJ-09AMPJ-26L1
MPU I-31
MPJ-21
MPI-08
MPU I-24 wp08
No-Go Zone - Stop Drilling
Collision Avoidance Required
Collision Risk Procedures Req.
WELL DETAILS:Plan: MPU I-23i NAD 1927 (NADCON CONUS)Alaska Zone 04
32.90
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 6009447.21 551630.03 70° 26' 11.6064 N 149° 34' 44.5855 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: MPU I-23i, True North
Vertical (TVD) Reference:MPU I-23 as built @ 66.60usft
Measured Depth Reference:MPU I-23 as built @ 66.60usft
Calculation Method:Minimum Curvature
SURVEY PROGRAM
Date: 2023-08-25T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
33.70 1200.00 MPU I-23 wp08 (MPU I-23i) GYD_Quest GWD
1200.00 7090.00 MPU I-23 wp08 (MPU I-23i) 3_MWD+IFR2+MS+Sag
7090.00 19547.06 MPU I-23 wp08 (MPU I-23i) 3_MWD+IFR2+MS+Sag
0.00
30.00
60.00
90.00
120.00
150.00
180.00
Centre to Centre Separation (60.00 usft/in)7150 7800 8450 9100 9750 10400 11050 11700 12350 13000 13650 14300 14950 15600 16250 16900 17550 18200 18850 19500
Measured Depth (1300 usft/in)
MPU I-30i
NO GLOBAL FILTER: Using user defined selection & filtering criteria
33.70 To 19547.06
Project: Milne Point
Site: M Pt I Pad
Well: Plan: MPU I-23i
Wellbore: MPU I-23i
Plan: MPU I-23 wp08
Ladder / S.F. Plots
2 of 2
CASING DETAILS
TVD TVDSS MD Size Name
4001.01 3934.41 7090.00 9-5/8 9 5/8" x 12 1/4"
4339.60 4273.00 19547.06 4-1/2 4 1/2" x 8 1/2"
1
Dewhurst, Andrew D (OGC)
From:Taylor Wellman <twellman@hilcorp.com>
Sent:Thursday, March 7, 2024 13:17
To:Dewhurst, Andrew D (OGC); Nathan Sperry
Cc:Rixse, Melvin G (OGC); Guhl, Meredith D (OGC); Roby, David S (OGC); Davies, Stephen F (OGC); Wallace, Chris D
(OGC); Katharine Cunha; Joseph Lastufka
Subject:RE: [EXTERNAL] MPU I-23 (PTD 224-012) - Questions
Chris and Andrew,
The type of log we are aiming to run is a waterflow log or an oxygen activation log. I’m currently working on scheduling
the job but target to have this log completed in the next 2 weeks. If there are any issues with this timeline I will make
sure to provide an update with the reasoning.
Thank you,
Taylor
Taylor Wellman
Hilcorp Alaska, LLC: Wells Manager – Milne Point
Office: (907) 777-8449
Cell: (907) 947-9533
Email: twellman@hilcorp.com
From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Sent: Thursday, March 7, 2024 8:13 AM
To: Taylor Wellman <twellman@hilcorp.com>; Nathan Sperry <Nathan.Sperry@hilcorp.com>
Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Roby,
David S (OGC) <dave.roby@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Wallace, Chris D (OGC)
<chris.wallace@alaska.gov>; Katharine Cunha <Katharine.Cunha@hilcorp.com>; Joseph Lastufka
<Joseph.Lastufka@hilcorp.com>
Subject: RE: [EXTERNAL] MPU I-23 (PTD 224-012) - Questions
Taylor and Nathan,
In addition to the email reply stating the specifics on the proposed mitigation plan, would you please submit a revised
AOR and for the MPU I-23 PTD calling out the issue in J-16 with the mitigation plan detailed. Please identify the well in
the updated AOR map. I will splice those revised pages into the final PTD document.
Thank you,
Andy
From: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>
Sent: Wednesday, March 6, 2024 15:26
To: Taylor Wellman <twellman@hilcorp.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Roby,
David S (OGC) <dave.roby@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Nathan Sperry
<Nathan.Sperry@hilcorp.com>; Katharine Cunha <Katharine.Cunha@hilcorp.com>; Joseph Lastufka
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Dewhurst, Andrew D (OGC)
From:Nathan Sperry <Nathan.Sperry@hilcorp.com>
Sent:Thursday, March 7, 2024 13:35
To:Dewhurst, Andrew D (OGC); Taylor Wellman
Cc:Rixse, Melvin G (OGC); Guhl, Meredith D (OGC); Roby, David S (OGC); Davies, Stephen F (OGC); Wallace, Chris D
(OGC); Katharine Cunha; Joseph Lastufka
Subject:RE: [EXTERNAL] MPU I-23 (PTD 224-012) - Questions
Attachments:MPI-23_AOR__Map and AOR 3-7-24.pdf
Andy,
I have attached the updated AOR and map, per your request.
Regards,
Nate Sperry
Drilling Engineer
Hilcorp Alaska, LLC
From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Sent: Thursday, March 7, 2024 8:13 AM
To: Taylor Wellman <twellman@hilcorp.com>; Nathan Sperry <Nathan.Sperry@hilcorp.com>
Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Roby,
David S (OGC) <dave.roby@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Wallace, Chris D (OGC)
<chris.wallace@alaska.gov>; Katharine Cunha <Katharine.Cunha@hilcorp.com>; Joseph Lastufka
<Joseph.Lastufka@hilcorp.com>
Subject: RE: [EXTERNAL] MPU I-23 (PTD 224-012) - Questions
Taylor and Nathan,
In addition to the email reply stating the specifics on the proposed mitigation plan, would you please submit a revised
AOR and for the MPU I-23 PTD calling out the issue in J-16 with the mitigation plan detailed. Please identify the well in
the updated AOR map. I will splice those revised pages into the final PTD document.
Thank you,
Andy
From: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>
Sent: Wednesday, March 6, 2024 15:26
To: Taylor Wellman <twellman@hilcorp.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Roby,
David S (OGC) <dave.roby@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Nathan Sperry
<Nathan.Sperry@hilcorp.com>; Katharine Cunha <Katharine.Cunha@hilcorp.com>; Joseph Lastufka
<Joseph.Lastufka@hilcorp.com>
Subject: RE: [EXTERNAL] MPU I-23 (PTD 224-012) - Questions
Taylor,
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2
We didn’t talk about the type of log to be run on J-16 and estimated date it may be completed - so if you could reply
here, we will attach these emails to the I-23 PTD approval for the record.
Thanks and Regards,
Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7 th Avenue, Anchorage, AK 99501,
(907) 793-1250 (phone), (907) 276-7542 (fax), chris.wallace@alaska.gov
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the
Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended
recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or
disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail,
please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending
it to you, contact Chris Wallace at 907-793-1250 or chris.wallace@alaska.gov.
From: Taylor Wellman <twellman@hilcorp.com>
Sent: Monday, March 4, 2024 4:03 PM
To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov>
Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Roby,
David S (OGC) <dave.roby@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Nathan Sperry
<Nathan.Sperry@hilcorp.com>; Katharine Cunha <Katharine.Cunha@hilcorp.com>; Joseph Lastufka
<Joseph.Lastufka@hilcorp.com>
Subject: RE: [EXTERNAL] MPU I-23 (PTD 224-012) - Questions
Chris and Andrew,
With regards to MPU J-16 (PTD 195-169 / API 50-029-22615-00-00) you are correct. After further review of the original
cementing records, the first stage cement job on the 7” casing would not have come high enough to have isolation
across the Schrader Bluff in this well. The condition of the isolation within J-16 has been a miss for multiple well
penetrations through time. Below is a summary table of injectors in the proximity of MPU J-16 and details about them.
Well Distance to J-16
(ft)
Pool - Sands Open Start Inj Stop Inj Vol (MMBW) Status
J-15 1,154 Schrader (Nb, Oa, Ob) 1999 2018 6.9 Cmt to surf 10/8/2020
J-17 4,275 Schrader (Nb, Nc, Oa,
Ob)
1998 2020 7.9 Shut In - Operable
J-18 2,776 Schrader (Nb, Oa, Ob) 2005 2019 2.9 Shut In - Not Operable (MIT-IA
allowed to lapse, Mechanically
good)
J-19A 2,848 Schrader (Nb, Nc, Oa,
Ob)
2009 2020 2.3 Shut In - Not Operable (MIT-IA
allowed to lapse, Mechanically
good)
I-21 268 Schrader (Oba) 2021 N/A 1.5 Horizontal Well - On Injection
I-28 243 Schrader (Oa) 2021 N/A 1.8 Horizontal Well - On Injection
I-35 770 Schrader (Nb) 2020 N/A 1.9 Horizontal Well - On Injection
I-37 1032 Schrader (Nb) 2020 N/A 3.3 Horizontal Well - On Injection
We would like to propose keeping all wells currently online and injecting, while concurrently running a Water Flow Log
in MPU J-16 to check for water flow between the Schrader and Ugnu sands. Keeping the injection wells online will
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3
provide the actual conditions that could lead to crossflow and have the highest chance for detection. Once that data is
obtained, it will be provided back to you and further actions can be enacted if needed.
We are open to coming over to your offices to discuss anything about these wells if you would like.
Thank you,
Taylor
Taylor Wellman
Hilcorp Alaska, LLC: Wells Manager – Milne Point
Office: (907) 777-8449
Cell: (907) 947-9533
Email: twellman@hilcorp.com
From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Sent: Friday, March 1, 2024 5:36 PM
To: Nathan Sperry <Nathan.Sperry@hilcorp.com>
Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com >; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>;
Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC)
<meredith.guhl@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov>; Wallace, Chris D (OGC)
<chris.wallace@alaska.gov>
Subject: [EXTERNAL] MPU I-23 (PTD 224-012) - Questions
Nathan,
I am completing my review of the MPU I-23 PTD and have a few questions:
1. Regarding the Area of Review: I have a question about one of the offset wells: MPU J-16 (50-
029-22615-00-00).
From what I can tell, the original plan for this well was to run 7” casing to TD (12,212’ MD) and
do a 2-stage cement job: stage 1 across Kuparuk and stage 2 across Schrader Bluff. But they
couldn’t get the 7” past 10,553’ MD, so they set it there and ran a 5” liner from the base of the
7” to TD.
I see from your notes on this well that the stage collar was set 4,681’ MD with a TOC of
2,998’MD. But the depth of the stage collar appears shallower to the Schrader Bluff by over
1,000’ MD.
Do you have any information (volumetrics, quality, etc.) about the first stage job that would
support isolation across the Schrader Bluff?
2. I noticed there are conflicts between the H2S hazard description in the 12-1/4” hole (p.48) vs.
the 8-1/2” hole (p.50). Would you please clarify?
Thanks,
Andy
Andrew Dewhurst
Senior Petroleum Geologist
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Alaska Oil and Gas Conservation Commission
333 W. 7th Ave, Anchorage, AK 99501
andrew.dewhurst@alaska.gov
Direct: (907) 793-1254
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
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While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission,
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the recipient should carry out such virus and other checks as it considers appropriate.
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
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the recipient should carry out such virus and other checks as it considers appropriate.
Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME:______________________________________
PTD:_____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD:__________________________POOL:____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in nogreater
than 30-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot sample intervals through target
zones.
Non-
Conventional
Well
Please note the following special condition of this permit: Production or
production testing of coal bed methane is not allowed for this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a water-well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by the Operator in the attached application, the following well logs are
also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
SCHRADER BLUFF OIL POOL
MPU I-23
224-012
MILNE POINT
X
WELL PERMIT CHECKLISTCompanyHilcorp North Slope, LLCWell Name:PRUDHOE BAY UN ORIN L-291Initial Class/TypeSER / PENDGeoArea890Unit11650On/Off ShoreOnProgramSERField & PoolWell bore segAnnular DisposalPTD#:2240020PRUDHOE BAY, SCHRADER BLUF OIL - 640135NA1 Permit fee attachedYes ADL028239, ADL047449, and ADL0474462 Lease number appropriateYes3 Unique well name and numberYes PRUDHOE BAY, SCHRADER BLUF OIL - 640135 - governed by 505C4 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 waitYes Governed by AIO 26B, issued May 4, 201014 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For sYes15 All wells within 1/4 mile area of review identified (For service well only)No16 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 grouted to 107'18 Conductor string providedYes 3 string design. Fully cemented surface casing. Aquifer excemption.19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes Intermediate casing will have adequate cement to isolate hydrocarbon zones21 CMT vol adequate to tie-in long string to surf csgYes Intermediate casing will have adequate cement to isolate hydrocarbon zones22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes Innovation rig has adequate tankage and good trucking support.24 Adequate tankage or reserve pitNA Grassroots well.25 If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collision scan identifies no close approaches.26 Adequate wellbore separation proposedYes 16" diverter below BOPE/27 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 2-9/16" piper ball valves, 1 manual and 1 remote hydraulic choke.31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownYes PBU L pad has H2S history. Monitoring will be required.33 Is presence of H2S gas probableYes34 Mechanical condition of wells within AOR verified (For service well only)No H2S measures required. L-Pad Orion development wells have recorded 16 to 80 ppm H2S.35 Permit can be issued w/o hydrogen sulfide measuresYes Normal pressure gradient expected (8.5 ppg or less). MPD will mitigate any abnormal pressures encountered36 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]ApprADDDate2/5/2024ApprMGRDate1/31/2024ApprADDDate2/2/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 3/8/2024
