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Alaska Oil and Gas Conservation Commission
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LETTER OF TRANSMITTAL
DETAIL
QTY DESCRIPTION
Well clean up data for 19 wells
Details are provided on following pages with well name and API
table as reference.
Received by:_____________________________ Date: _____________
Please sign and return one copy to:
Santos
ATTN: Shannon Koh
601 W 5th Ave., Anchorage, AK 99501
shannon.koh@santos.com
DATE: 11/20/2025
From:
Shannon Koh
Santos
601 W 5th Ave.
Anchorage, AK 99501
To:
Gavin Glutas
AOGCC
333 W. 7th Avenue, Suite 100
Anchorage, AK 99501
TRANSMISSION TYPE:
܈External Request
܆Internal Request
TRANSMISSION METHOD:
܆CD ܆ Thumb Drive
܆Email ܆SharePoint/Teams
܆Hardcopy ܈Other - FTP
REASON FOR TRANSMITTAL:
܆Approved
܆Approved with Comments
܆For Approval
܈Information Only
܆For Your Review
܆For Your Use
܆To Be Returned
܆With Our Comments
܆Other
COMMENTS:
Gavin
Gluyas
Digitally signed by
Gavin Gluyas
Date: 2025.11.21
09:00:44 -09'00'
LETTER OF TRANSMITTAL
Well API
NDB-010 50103209200000
NDB-011 50103209160000
NDBi-014 50103208690000
NDBi-016 50103208920000
NDBi-018 50103208880000
NDB-024 50103208620000
NDB-025 50103208770000
NDBi-030 50103208730000
NDB-031 50103209120000
NDB-032 50103208600000
NDBi-036 50103209080000
NDB-037 50103208950000
NDBi-043A 50103208590100
NDBi-044 50103208650000
NDBi-046L1 50103208830000
NDB-048 50103209020000
NDBi-049 50103208940000
NDBi-050 50103209040000
NDB-051 50103208800000
جؐؐؐNDB-010
ؒ Santos_Pikka_NDB-010_End of Well Data Report_1 min_FINAL (1).xlsx
ؒ Santos_Pikka_NDB-010_End of Well Data Report_30 min_FINAL (1).xlsx
ؒ WT-XAK-0127.5_NDB-010_Rev A (1).pdf
ؒ
جؐؐؐNDB-011
ؒ Santos_Pikka_NDB-011_End of Well Data Report_1 min_FINAL (1).xlsx
ؒ Santos_Pikka_NDB-011_End of Well Data Report_30 Min_FINAL (1).xlsx
ؒ WT-XAK-0127.5_NDB-011_Rev A (1).pdf
ؒ
جؐؐؐNDB-014
ؒ Santos_Pikka_NDBi-014_End of Well Clean-up Data Report_30 Minute_Final Data.xlsx
ؒ Santos_Pikka_NDBi-014__End of Well Clean-up Data Report_1 Minute_Final Data.xlsx
ؒ WT-XAK-0127.3_NDBi-014_Rev A_Signed.pdf
ؒ
جؐؐؐNDB-024
ؒ Santos_Pikka_NDB-024_End of Well Clean-Up Data Report_ 30-min_Final (2).xlsx
ؒ Santos_Pikka_NDB-024_End of Well Clean-Up Data Report_1-min_Final (2).xlsx
ؒ WT-XAK-0127.2_End of Well Clean-Up Data Report_NDB-024_Rev A_Signed.pdf
225-061
T41152
225-048
T41153
223-076
T39828
223-105
T39831
NDB-032 50103208600000
LETTER OF TRANSMITTAL
ؒ
جؐؐؐNDB-025
ؒ Santos_Pikka_NDB-025_End of Well Clean-up Data Report_1-min_Final Data.xlsx
ؒ Santos_Pikka_NDB-025_End of Well Clean-up Data Report_30-min_Final Data.xlsx
ؒ WT-XAK-0127.4_NDB-025_Rev A signed End of Well Clean-up Data Report.pdf
ؒ
جؐؐؐNDB-031
ؒ Santos_Pikka_NDB-031_End of Well Clean-up Data Report_1 min_FINAL.xlsx
ؒ Santos_Pikka_NDB-031_End of Well Clean-up Data Report_30 min_FINAL.xlsx
ؒ WT-XAK-0127.5_NDB-031_Rev A Signed (1).pdf
ؒ
جؐؐؐNDB-032
ؒ Santos_Pikka_NDB-032_End of Well Clean-up Data Report_ 30 min_Final Data (1).xlsx
ؒ Santos_Pikka_NDB-032_End of Well Clean-up Data Report_1 min_Final Data (1).xlsx
ؒ WT-XAK-0127.3_NDB-032_Rev A_Signed (2).pdf
ؒ
جؐؐؐNDB-037
ؒ Santos_Pikka_NDB-037_End of Well Clean-up Data Report_1-min_FINAL (1).xlsx
ؒ Santos_Pikka_NDB-037_End of Well Clean-up Data Report_30-min_FINAL (1).xlsx
ؒ WT-XAK-0127.5_NDB-037_Rev A_Signed (2).pdf
ؒ
جؐؐؐNDB-048
ؒ Santos_Pikka_NDB-048_End of Well Clean-up Data Report_1 min_FINAL.xlsx
ؒ Santos_Pikka_NDB-048_End of Well Clean-up Data Report_30 min_FINAL (1).xlsx
ؒ WT-XAK-0127.5_NDB-048_Rev A_Signed (2).pdf
ؒ
جؐؐؐNDB-051
ؒ Santos_Pikka_NDB-051_End of Well Clean-up Data Report_1 min_Final Data.xlsx
ؒ Santos_Pikka_NDB-051_End of Well Clean-up Data Report_30 min_Final Data.xlsx
ؒ WT-XAK-0127.4_NDB-051_Rev A_Signed.pdf
ؒ
جؐؐؐNDBi-016
ؒ Santos_Pikka_NDBi-016_End of Well Clean-Up_ Data Report_ 1 min_Final Data.xlsx
ؒ Santos_Pikka_NDBi-016_End of Well Clean-Up_ Data Report_30 min_Final Data.xlsx
ؒ WT-XAK-0127.4_NDBi-016_Rev A_Signed.pdf
ؒ
جؐؐؐNDBi-018
ؒ Santos_Pikka_NDBi-018_End of Well Clean-up_Build-up Data Report_1 min_Final.xlsx
ؒ Santos_Pikka_NDBi-018_End of Well Clean-up_Build-up Data Report_30 min_Final.xlsx
ؒ WT-XAK-0127.4_NDBi-018_Rev A_Signed.pdf
ؒ
جؐؐؐNDBi-030
224-006
T41154
225-028
T41155
224-124
T41156
224-143
T41157
224-105
T41158
224-085
T41159
224-013
T39830
223-006
T39829
223-120
T39832
NDB-032
LETTER OF TRANSMITTAL
ؒ Santos_Pikka_NDBi-030_End of Well Clean-up Data Report_1-min_Final Data.xlsx
ؒ Santos_Pikka_NDBi-030_End of Well Clean-up Data Report_30 minute_Final Data.xlsx
ؒ WT-XAK-0127.3_NDBi-030_Rev A_Signed.pdf
ؒ
جؐؐؐNDBi-036
ؒ Santos_Pikka_NDBi-036_End of Well Clean-up Data Report_1 min_FINAL.xlsx
ؒ Santos_Pikka_NDBi-036_End of Well Clean-up Data Report_30 min_FINAL.xlsx
ؒ WT-XAK-0127.5_NDBi-036_Rev A Signed (1).pdf
ؒ
جؐؐؐNDBi-043A
ؒ Santos_Pikka_NDBi-043_Daily Well Test Data Report_09152023_0830 - 09202023_2200_Final (1).xlsx
ؒ WT-XAK-0127.1_NDBI-043_End of Well Report_Rev A (1).pdf
ؒ
جؐؐؐNDBi-044
ؒ Santos_Pikka_NDBi-044_End of Well Clean-Up Data Report_1-min_Final .xlsx
ؒ Santos_Pikka_NDBi-044_End of Well Clean-Up Data Report_30-min_Final.xlsx
ؒ WT-XAK-0127.3_End of Well Report_NDBi-044_Rev A_Signed.pdf
ؒ
جؐؐؐNDBi-046L1
ؒ Santos_Pikka_NDBi-046_End of Well Clean-up Data Report_1 min_Final Data.xlsx
ؒ Santos_Pikka_NDBi-046_End of Well Clean-up Data Report_30 min_Final Data.xlsx
ؒ WT-XAK-0127.4_NDBi-046_Rev A_Signed.pdf
ؒ
جؐؐؐNDBi-049
ؒ Santos_Pikka_NDBi-049_End of Well Clean-up Data Report_1-min_Final.xlsx
ؒ Santos_Pikka_NDBi-049_End of Well Clean-up Data Report_30-min_Final.xlsx
ؒ WT-XAK-0127.5_NDBi-049_Rev A Signed.pdf
ؒ
ؤؐؐؐNDBi-050
Santos_Pikka_NDBi-050_End of Well Clean-up Data Report_1-min_FINAL.xlsx
Santos_Pikka_NDBi-050_End of Well Clean-up_Data Report_30-min_FINAL.xlsx
WT-XAK-0127.5_NDBi-050_Rev A_Signed (1).pdf
225-012
T41160
224-119
T41161
224-154
T41162
223-052
T39834
223-087
T39835
224-029
T39837
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Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 09/19/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20250919
Well API #PTD #Log Date Log
Company Log Type AOGCC
E-Set#
BRU 212-35T 50283200970000 198161 8/10/2025 AK E-LINE PPROF
T40899
BRU 223-34T 50283202060000 225059 8/17/2025 AK E-LINE CBL
T40900
BRU 234-27 50283202070000 225065 9/12/2025 AK E-LINE CBL
T40901
BRU 242-04 50283201640000 212041 6/9/2025 AK E-LINE Perf
T40902
KBU 11-08Z 50133206290000 214044 9/8/2025 AK E-LINE Perf
T40903
MPU H-03 50029220630000 190088 9/9/2025 AK E-LINE SetPacker
T40904
MPU H-11 50029228020000 197163 2/9/2025 AK E-LINE Caliper
T40905
MPU M-62 50029237440000 223006 8/31/2025 AK E-LINE LDL
T40906
NCIU A-06 50883200260000 169050 8/25/2025 AK E-LINE TubingCut
T40907
NCIU A-21A 50883201990100 225075 8/26/2025 AK E-LINE Perf
T40908
ODSK-33 50703205620000 207183 9/10/2025 READ Caliper Survey
T40909
ODSN-01a 50703206480100 216008 9/8/2025 READ Caliper Survey
T40910
ODSN-06 50703207150000 215098 9/9/2025 READ Jewelry Log
T40911
PBU C-34C 50029217850300 225068 8/25/2025 BAKER MRPM
T40912
PBU Q-06A 50029203460100 198090 8/21/2025 BAKER SPN
T40913
TBU M-25 50733203910000 187086 8/31/2025 AK E-LINE Drift
T40914
Please include current contact information if different from above.
MPU M-62 50029237440000 223006 8/31/2025 AK E-LINE LDL
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.09.22 13:22:50 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 09/10/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20250910
Well API #PTD #Log Date Log
Company Log Type AOGCC
E-Set#
BRU 213-26T 50283202040000 225038 6/14/2025 AK E-LINE CBL
MPU C-21 50029207530000 182081 7/8/2025 AK E-LINE Caliper
MPU M-62 50029237440000 223006 6/23/2025 READ Caliper Survey
PBU 01-13A 50029202700100 225052 8/17/2025 BAKER MRPM
PBU 01-30A 50029216060100 225050 8/7/2025 BAKER MRPM
PBU 07-24A 50029209450100 225045 8/3/2025 BAKER MRPM
PBU N-12 50029205570000 181014 8/5/2025 BAKER SPN
PBU PSI-09 50029230950000 202124 7/17/2025 HALLIBURTON WFL-TMD3D
Please include current contact information if different from above.
T40860
T40861
T40862
T40863
194-080
T40864
T40865
T40866
T40867
MPU M-62 50029237440000 223006 6/23/2025 READ Caliper Survey
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.09.10 11:27:53 -08'00'
Hilcorp Alaska, LLC Post Office Box 244027
Anchorage, AK 99524-4027
3800 Centerpoint Drive
Suite 1400
Anchorage, AK 99503
Phone: 907/777-8547
September 29, 2023
Mr. Mel Rixse
Alaska Oil and Gas Conservation Commission
333 West 7th Avenue, Suite 100
Anchorage, Alaska 99501
Re: Milne Point Conductor Annulus Corrosion Inhibitor Treatments 6/9 to 9/27/2023
Dear Mr. Rixse,
Enclosed please a copy of a spreadsheet with a list of thirteen Milne Point wells that were treated
with corrosion inhibiting casing filler in the surface casing by conductor annulus. The heavier than
water “grease-like” filler displaces water to prevent external casing corrosion that could result in
a surface casing leak. The attached spreadsheets include the well names, field, API and PTD
numbers, treatment dates and volumes.
If you have any additional questions, please contact me at 907-777-8406 or
dhorner@hilcorp.com.
Sincerely,
Darci Horner
Regulatory Tech
Hilcorp Alaska, LLC
Digitally signed by Darci Horner
(c-100048)
DN: cn=Darci Horner (c-100048)
Date: 2023.09.29 09:45:20 -
08'00'
Darci Horner
(c-100048)
Well Field API PTD
Initial Top
of Cement
(ft.)
Volume of
Cement
Pumped
(bbls)
Final Top of
Cement (ft.)
Cement
Pump Date
Corrosion
Inhibitor
Fill Volume
(gal)
Final CI Top
(ft.)
Corrosion
Inhibitor
Treatment
Date
Comments
MPB-35 MPU 50029237240000 2220850 14' 0 14' N/A 50 surface 9/27/2023 Drilled Sept/Oct 2022.
MPB-39 MPU 50029237470000 2230120 1'6" 0 1'6" N/A 10 surface 6/10/2023 Drilled Mar 2023.
MPI-20 MPU 50029236790000 2200490 10' 1 1 7/2/2023 5 surface 9/27/2023 Completed Apr 8, 2021.
MPI-29 MPU 50029237080000 2220060 6' 0.5 3 7/2/2023 15 surfce 9/27/2023
Drilled in March 2022. Completeted
on 4/30/22.
MPL-60 MPU 50029236780000 2200480 1' 0 1' N/A 10 surface 6/26/2023 Drilled in 2020.
MPL-62 MPU 50029236850000 2200590 1' 0 1' N/A 10 surface 6/26/2023 Drilled in 2020.
MPM-13 MPU 50029236380000 2190870 20' 3.5 2' 8/2/2023 10 surface 9/27/2023 Drilled in 2019.
MPM-27 MPU 50029237160000 2220490 2' 0 2' N/A 20 surface 6/11/2023 Monobore. Drilled June 2022.
MPM-30 MPU 50029237300000 2221180 1' 0 1' N/A 10 surface 6/11/2023 Drilled in Oct 2022.
MPM-43 MPU 50029236710000 2200200 1' 0 1' N/A 10 surface 6/11/2023 Drilled in 2020.
MPM-62 MPU 50029237440000 2230060 1' 0 1' N/A 10 surface 6/11/2023 Completed May 2023.
MPS-45 MPU 50029236930000 2210420 1' 0 1' N/A 10 surface 6/12/2023 Drilled in June 2021.
MPS-47 MPU 50029236960000 2210470 4' 0 4' N/A 20 surface 6/12/2023 Drilled in August 2021.
Notes:
The 4" conductor outlets are any where from 1 to 3' down from the top of the conductor
Surface Casing by Conductor Annulus Cement Top Job and Fill Coat Corrosion Inhibitor (CI) Applications
Cement to surface means cement is up to the 4" outlets below the wellhead. From the 4" outlets up to the top of conductor was filled with Fill Coat #7
Initial top of cement footage measurement was taken from the 4" outlet down to the TOC
RBDMS JSB 100323
MPM-62 MPU 50029237440000 2230060 1'0 1'N/A 10 surface 6/11/2023 Completed May 2023.
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: 05/25/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL :
WELL: MPU M-62
PTD: 223-006
API: 50-029-23744-00-00
FINAL LWD FORMATION EVALUATION LOGS (04/12/2023 to 04/29/2023)
x EWR-M5, AGR, ABG, DGR, 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.
PTD: 223-006
T37672
Kayla Junke
Digitally signed by Kayla
Junke
Date: 2023.05.25 16:17:29
-08'00'
MILNE POINT FIELD /
SCHRADER BLUFF OIL POOL
By James Brooks at 9:36 am, May 23, 2023
Completed
5/7/2023
JSB
RBDMS JSB 052523
GMGR08AUG2023DSR-6/12/23
5.22.2023
Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp Alaska, LLC, ou=Technical
Services - AK Drilling,
email=mmyers@hilcorp.com
Reason: I am approving this document
Date: 2023.05.22 16:24:28 -08'00'
Monty M
Myers
_____________________________________________________________________________________
Edited By: JNL 5/10/2023
SCHEMATIC
Milne Point Unit
Well: MPU M-62
Last Completed: 5/7/2023
PTD: 223-006
TD =20,227’(MD) / TD =4,115’(TVD)
4
20”
Orig. KB Elev.: 59.64’ / GL Elev.: 25.1’
7”
12
6
109-5/8”
11
1
2
3
See
Screen/
Solid
Liner
Detail
PBTD =20,225’(MD) / PBTD =4,115’(TVD)
9-5/8” ‘ES’
Cementer @
2,748’
5
7
9
12
8
4-1/2”
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20" Conductor 129.5 / X56 / Weld N/A Surface 114’ N/A
9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,731’ 0.0732
9-5/8” Surface 40 / L-80 / TXP 8.835 2,731’ 9,048’ 0.0758
7” Tieback 26 / L-80 / TXP 6.276 Surface 8,886’ 0.0383
5-1/2” Liner 100ђ Screens 17 & 20 / L-80 / JFE & EZGO 4.778 8,875’ 11,792’ 0.0222
4-1/2” Liner 100ђ Screens 13.5 / L-80 / Hyd 625 3.920 11,792’ 20,227’ 0.0149
TUBING DETAIL
4-1/2" Tubing 12.6# / L-80 / TXP 3.958 Surface 8,886’ 0.0152
OPEN HOLE / CEMENT DETAIL
42” 14 yds Concrete
12-1/4" Stg 1 Lead – 890 sx / Tail – 400 sx
Stg 2 Lead – 675 sx / Tail 270 sx
8-1/2” Cementless Screened Liner
WELL INCLINATION DETAIL
KOP @ 250’
90° Hole Angle = @ 9,659’
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: 50-029-23744-00-00
Completion Date: 5/7/2023
JEWELRY DETAIL
No. MD Item ID
1 Surface 4-1/2” FMC TC-1A TC-II Tubing Hanger two 3/8” CCL Ports 4.500”
2 7,350’ Viking Sliding Sleeve (opens down) 3.813”
3 7,413’ X Nipple, 3.813” 3.813”
4 7,471’ Baker Zenith Gauge Carrier 3.865”
5 7,536’ Baker Retrievable Packer 3.960”
6 7,606’ XN Nipple, 3.813”, 3.725” No Go 3.725”
7 8,851’ WLEG/Mule Shoe 3.958”
8 8,875’ SLZXP Liner Top Packer 6.220”
9 8,896’ 7” H563 x 4.5” TSH 625 XO 4.800”
10 9,051’ 5-1/2” 17# JFE Bear xo 5-1/2” 20# EZGO 4.892”
11 11,792’ 5-1/2” 20# EZGO xo 4-1/2” 13.5# Hyd 625 3.920”
12 20,225’ Shoe
5-1/2” x 4-1/2”SCREENS LINER DETAIL
Size Top
(MD)
Top
(TVD)
Btm
(MD)
Btm
(TVD)
5-1/2” 9055’ 4038’ 11792’ 4062’
4-1/2” 11834’ 4063’ 20185’ 4114’
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:MPU M-62 Date:4/22/2023
Csg Size/Wt/Grade:9.625", 40# & 47#, L-80 Supervisor:Yessak/Vanderpoo
Csg Setting Depth:9048 TMD 4036 TVD
Mud Weight:9.3 ppg LOT / FIT Press =567 psi
.
LOT / FIT =12.00 Hole Depth =9073 md
Fluid Pumped=2.00 Bbls Volume Back =1.75 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
->00 ->00
->273 ->8 340
->4 151 ->16 680
->6 201 ->24 975
->8 267 ->28 1125
->10 323 ->32 1275
->12 380 ->36 1450
->14 443 ->40 1650
->16 503 ->44 1780
->17 520 ->48 1950
->18 535 ->52 2117
->19 556 ->56 2300
->20 570 ->60 2470
-> ->63 2580
Enter Holding Enter Holding Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0 570 ->0 2580
->1 535 ->5 2575
->2 456 ->10 2574
->3 414 ->15 2572
->4 380 ->20 2570
->5 367 ->25 2569
->6 361 ->26 2568
->7 357 ->27 2568
->8 353 ->28 2567
->9 347 ->29 2567
->10 344 ->30 2567
->11 342 ->
->12 340 ->
->13 339 ->
->14 337
->15 336
->16
0
2
4
6
8
10
12
14
1617181920
0
8
16
24
28
32
36
40
44
48
52
56
60
63
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 10203040506070
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
)
570535
456
414380367361357353347344342340339337336
2580 2575 2574 2572 2570 256925682568256725672567
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
Activity Date Ops Summary
4/11/2023 Finish setting mats around well. Spot wellhead equipment, tree and squeeze manifold behind the rig. Remove booster tires. NU the diverter tee and hang the
surface annular. Spot the rig and center over well M-62. Shim and level the rig. PJSM. Skid the rig floor into drilling position. RU service lines to the rig floor. NU the
surface annular and knife valve. NU the diverter line. Spot the slop tank. Work on rig acceptance check list. SimOps: Remove the collar finger/landing from the
derrick. Work on rig acceptance check list. Spot the rock washer and RU. Install the surface bell nipple and riser. Thaw out the mouse hole. NU the diverter line.
Install the 4" conductor valves. SimOps: Prep the derrick for the new collar finger/landing installation. Rig on highline power at 18:30 hours. Work on rig acceptance
check list. Ready pit for taking on fluid and load the hopper room with mud product. NU the diverter line. Load HWDP and BHA into the DS pipe shed. Load DP in
the ODS pipe shed. SimOps: Install the new collar finger/landing in the derrrick.
4/12/2023 Work on acceptance checklist. Finish installing the remaining diverter line. Load row of 5 DP into shed. SimOps: Complete collar finger repair and magnaflux same.
Clear rig floor. Mobilize bits, XO & lift sub to floor. M/U stand of HWDP for Diverter test. Test gas alarms and pit sensors. AOGCC inspector Sean Sullivan on-site for
witness. Seals leaking on accumulator air pump. Replace pump. Change out accumulator air pump. Install mousehole in rotary table. M/U and rack back 3 stds 5
HWDP. Perform Diverter function test. performed on 5" HWDP. Knife valve open in 11 second, annular closed in 27 seconds. 3000 psi system pressure, 1900 psi
after closing. 200 psi recovery = 39 seconds & full recovery = 154 seconds. 6 N2 bottle avg= 1912 psi. 16" diverter line length= 443', from substructure= 435'.
Nearest ignition source= 96'. Re-install mousehole in rotary table. Continue to P/U 5'' HWDP and rack back. Total of 6 stands of HWDP and jars. L/D mousehole,
install jt 5 DP in rotary table. C/O saversub and grabber dies. Service Topdrive. Install 90 mousehole. Pre-spud meeting with all parties involved. Discussed well
objectives and surface hole hazards. Table top diverter drill. M/U 12-1/4" tri-cone bit, 8" mud motor with 1.5 AKO and XO sub to 36'. M/U stand of 5" HWDP to top
drive. RIH with stand and tag up @ 38' MD. Flood system with water and ensure no leaks. Pressure test high pressure mud line, with H2O, to 3500 PSI. Good test.
Engage pumps and rotary clean, out conductor to 114' pumping 360 gpm, 290 psi, 30 rpm, 1k tq, 1-2k WOB. Drill 12-1/4" surface hole from 114' to 220'. 400 GPM,
490 PSI, 30 RPM, 1-2K ft/lbs TQ, 5-8K WOB. 48K PU / 48K SO / 48K ROT. 8.7 ppg MW, 262 vis. Pump out of hole f/ 220' t/ 127' then pull out on elevators to
surface. Inspect bit - No damage, cones rotate freely. Change out bit to 12-1/4 Kymera, M/U remaining BHA with GWD, directional, gamma and resistivity. Initialize
MWD tools. Finish M/U remaining BHA with NMFCs & bottle neck XO to 191'. M/U first stand of HWDP. Obtain gyro survey at 154'. Drill 12-1/4" surface hole from
220' to 282' (282' TVD). Drilled 62' = 41'/hr AROP. 420 GPM, 1200 psi, 50 RPM, 1-4K ft/lbs torque, WOB 11K. PU 65K, SO 70K, ROT 70K. MW = 8.9 ppg, Vis
300, ECD 9.56 ppg. Start 3/100' build at 250'. Daily disposal to G&I = 0 bbls. Total disposal to G&I = 0 bbls. Daily water hauled from L-Lake = 505 bbls. Total water
hauled from L-Lake = 505 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 0 bbls.
4/13/2023 Drill 12-1/4" surface hole from 282' to 840' (826' TVD). Drilled 558' = 93'/hr AROP. 450 GPM, 1090 psi, 40 RPM, 1-4K ft/lbs torque, WOB 7K. PU 78K, SO 83K,
ROT 81K. MW = 9.1 ppg, Vis 300, ECD 9.67 ppg. Start 4/100' build at 650'. Drill 12-1/4" surface hole from 840' to 1501' (1393' TVD). Drilled 661' = 110'/hr AROP.
450 GPM, 1360 psi, 60 RPM, 3-6K ft/lbs torque, WOB 6-15K. PU 88K, SO 86K, ROT 88K. MW = 9.2+ ppg, Vis 300, ECD 10.6 ppg. Drill 12-1/4" surface hole f/
1501' t/ 2100' (1730' TVD). Drilled 599' = 100'/hr AROP. 450 GPM, 1430 psi, 60 RPM, 5-7K Tq, WOB 10-12K. MW = 9.4 ppg, Vis 116, ECD 10.22 ppg, Max Gas
= 157u. PU 100K, SO 85K, ROT 90K. Drill 12-1/4" surface hole f/ 2100' t/ 3070' (2093' TVD). Drilled 970' = 161'/hr AROP. 550 GPM, 1940 psi, 80 RPM, 7K Tq,
WOB 8-10K. MW = 9.4 ppg, Vis 125, ECD 10.96 ppg, Max Gas = 146u. PU 100K, SO 75K, ROT 87K. Start 70.45 deg tangent at 2364'. BOPF logged at 2406' MD
/ 1878' TVD. Last Gyro survey at 992.36' MD, Swap to MWD surveys. Last survey 2978.79' MD / 2063.11' TVD, 70.72 deg inc, 90.75 deg azm, 24.91' from plan,
22.14' Low and 11.43' Right. Daily disposal to G&I = 1006 bbls. Total disposal to G&I = 1006 bbls. Daily water hauled from L-Lake = 860 bbls. Total water hauled
from L-Lake = 1365 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 0 bbls.
4/14/2023 Drill 12-1/4" surface hole f/ 3070' t/ 3640' (2264' TVD). Drilled 570' = 95'/hr AROP. 450 GPM, 1690 psi, 80 RPM, 6-8K Tq, WOB 7-10K. MW = 9.5 ppg, Vis 129,
ECD 11.1 ppg, Max Gas = 130u. PU 105K, SO 78K, ROT 92K. Top of UG4 logged at 3372 MD / 2178' TVD. Sweep @ 3602' back on time, 50% increase in
cuttings. Drill 12-1/4" surface hole f/ 3640' t/ 4100' (2415' TVD). Drilled 460' = 77'/hr AROP. 400 GPM, 1430 psi, 80 RPM, 7-10K Tq, WOB 5-7K. MW = 9.3 ppg,
Vis 114, ECD 11.07 ppg, Max Gas = 132u. PU 110K, SO 75K, ROT 91K. Drill with only #2 MP while troubleshoot discharge noise from #1 MP. Find 1" rock in fluid
end, getting stuck under suction valve. Drill 12-1/4" surface hole f/ 4100' t/ 4772' (2631' TVD). Drilled 672' = 112'/hr AROP. 525 GPM, 1890 psi, 80 RPM, 8-12K
Tq, WOB 5-10K. MW = 9.3 ppg, Vis 113, ECD 10.55 ppg, Max Gas = 107u. PU 125K, SO 82K, ROT 100K. Sweep @ 4552' back 100 stks late, 20% increase in
cuttings. Drill 12-1/4" surface hole f/ 4772' t/ 5615' (2933' TVD). Drilled 843' = 140'/hr AROP. 540 GPM, 2490 psi, 80 RPM, 15K Tq, WOB 5-15K. MW = 9.45 ppg,
Vis 180, ECD 10.5 ppg, Max Gas = 149u. PU 143K, SO 73K, ROT 105K. Last survey 5546.28' / 2911.09' TVD, 71.04 deg inc, 91.09 deg azm, 20.32' from plan,
10.80' Low and 17.21' Left. Daily disposal to G&I = 1244 bbls. Total disposal to G&I = 2250 bbls. Daily water hauled from L-Lake = 1385 bbls. Total water hauled
from L-Lake = 2750 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 0 bbls.
4/15/2023 Drill 12-1/4" surface hole f/ 5615' t/ 6174' (3112' TVD). Drilled 559' = 93.2 ft/hr AROP. 544 GPM, 2470 psi, 80 RPM, 13-17K Tq, WOB 10-15K. MW = 9.4 ppg, Vis
228, ECD 10.9 ppg, Max Gas = 157u. PU 154K, SO 75K, ROT 108K. Begin 4.2/100 drop and turn at 5845'. Drill 12-1/4" surface hole f/ 6174' t/ 6592' (3277' TVD).
Drilled 418' = 70'/hr AROP. 550 GPM, 2240 psi, 80 RPM, 14-18K Tq, WOB 5-18K. MW = 9.3 ppg, Vis 104, ECD 10.20 ppg, Max Gas = 157u. PU 163K, SO 75K,
ROT 112K. Add 1.25% screenkleen in prep for UG_L&M heavy oil. Drill 12-1/4" surface hole f/ 6592' t/ 6930' (3410' TVD). Drilled 338' = 56'/hr AROP. 550 GPM,
2170 psi, 80 RPM, 16-18K Tq, WOB 2-15K. MW = 9.3 ppg, Vis 112, ECD 10.18 ppg, Max Gas = 158u. PU 183K, SO 80K, ROT 120K. Sweep @ 6643' back 200
stks late, no increase in cuttings. Top of UG_LA3 logged at 6670 MD / 3314' TVD. Drill 12-1/4" surface hole f/ 6930' t/ 7538' (3704' TVD). Drilled 608' = 101'/hr
AROP. 550 GPM, 2400 psi, 80 RPM, 17-20K Tq, WOB 10-15K. MW = 9.35 ppg, Vis 158, ECD 10.5 ppg, Max Gas = 232u. PU 187K, SO 75K, ROT 124K. Last
survey 7446.14' / 3667.98' TVD, 65.48 deg inc, 15.81 deg azm, 24.14' from plan, 21.31' High and 11.35' Left. Daily disposal to G&I = 1764 bbls. Total disposal to
G&I = 4014 bbls. Daily water hauled from L-Lake = 1505 bbls. Total water hauled from L-Lake = 4255 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 0 bbls.
50-029-23744-00-00API #:
Well Name:
Field:
County/State:
MP M-62
Milne Point
Hilcorp Energy Company Composite Report
, Alaska
4/12/2023Spud Date:
4/16/2023 Drill 12-1/4" surface hole f/ 7538' t/ 7831' (3810' TVD). Drilled 293' = 49'/hr AROP. 550 GPM, 2440 psi, 80 RPM, 18-23K Tq, WOB 10-18K. MW = 9.3 ppg, Vis
181, ECD 10.40 ppg, Max Gas = 93u. PU 205K, SO 73K, ROT 125K. Sweep @ 7593' back 200 stks late, no increase in cuttings. Drill 12-1/4" surface hole f/ 7831'
t/ 8224' (3933' TVD). Drilled 393' = 65'/hr AROP. 550 GPM, 2450 psi, 80 RPM, 18-20K Tq, WOB 10-16K. MW = 9.4 ppg, Vis 116, ECD 10.78 ppg, Max Gas =
375u. PU 190K, SO 78K, ROT 123K. Add 0.25% Lube 776 to aid in sliding. Top of SB_NA logged at 7964 MD / 3858' TVD. Drill 12-1/4" surface hole f/ 8224' t/
8607' (4006' TVD). Drilled 383' = 64'/hr AROP. 550 GPM, 2360 psi, 80 RPM, 17-19K Tq, WOB 10-15K. MW = 9.4 ppg, Vis 107, ECD 10.40 ppg, Max Gas = 418u.
PU 187K, SO 77K, ROT 125K. Drill 12-1/4" surface hole f/ 8607' t/ 8853' (4024' TVD). Drilled 246' = 41'/hr AROP. 550 GPM, 2350 psi, 80 RPM, 20-22K Tq, WOB
10-17K. MW = 9.3 ppg, Vis 68, ECD 10.38 ppg, Max Gas = 126u. PU 190K, SO 77K, ROT 124K. Last survey 8779.19' / 4020.69' TVD, 86.44 deg inc, 324.25 deg
azm, 17.46' from plan, 15.80' High and 7.42' Left. Daily disposal to G&I = 1702 bbls. Total disposal to G&I = 5716 bbls. Daily water hauled from L-Lake = 1875
bbls. Total water hauled from L-Lake = 6130 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 0 bbls.
4/17/2023 Drill 12-1/4" surface hole f/ 8853' t/ 9053' (4038' TVD). Drilled 200' = 40'/hr AROP. 550 GPM, 2500 psi, 80 RPM, 20-22K Tq, WOB 10-20K. MW = 9.3 ppg, Vis 71,
ECD 10.38 ppg, Max Gas = 533u. PU 192K, SO 75K, ROT 123K. Geo called TD at 9053', ~3' below top of OA, projected at ~88 inc. Final survey 8969.85' /
4034.61' TVD, 86.47 deg inc, 323.48 deg azm, 18.72' from plan, 16.56' High and 8.74' Right. Circulate and condition mud, rotating and reciprocating pipe F/9045'
T/8860' alternating stop points. 550 GPM, 2320-2270 psi, 60 RPM, 18-20K Tq. Sweep came back 200 stks late with no increase in cuttings. Circulate a total of ~3x
bottoms up strokes. MW (in/out) 9.3+/9.4+ ppg, Vis (in/out) 59/122 sec. Run in the hole on elevators F/ 8959' T/ 9053' (1 stand), no issues and no fill on bottom.
Ream out and lay down single to get back on even stands. Monitor well prior to coming out of the hole - static. BROOH from 9019' to 6078' pulling 5-10
minutes/stand slowing as needed to clean up slides/tight spots. 550 GPM = 1900 psi, 60 RPM = 15-21K ft-bs TQ, ECD= 10.14 ppg, max gas = 553u. PU = 175K,
SO = 75K, ROT = 115K. BROOH from 6078' to 3696' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight spots. 550 GPM = 1610 psi, 60 RPM =
10K ft-bs TQ, ECD= 10.20 ppg, max gas = 75u. PU = 125K, SO = 78K, ROT = 95K. Daily disposal to G&I = 1296 bbls. Total disposal to G&I = 7012 bbls. Daily
water hauled from L-Lake = 1875 bbls. Total water hauled from L-Lake = 6130 bbls. Daily fluid loss = 2 bbls. Total fluid loss = 2 bbls.
4/18/2023 BROOH from 3696' to 755', to the HWDP, pulling 5-10 minutes/stand slowing as needed to clean up slides/tight spots. 450-550 GPM = 1000-1500 psi, 60 RPM =
10K ft-bs TQ, ECD= 10.20 ppg, max gas = 75u. PU = 110K, SO = 75K, ROT = 95K. Stand back HWDP and jars in derrick, lay down flex collars to pipe shed.
Download MWD and lay down. Break out bit and lay down motor. PDC: 1-2-WT-T-X-2-CT-TD. Roller Cone: 2-2-WT-A-E-2-NO-TD. Lost 45.7 bbls over trip out.
Current loss rate ~3 bph. Clear and clean the rig floor. Mobilize casing running tools to the rig floor. RU Volant CRT, bail extensions, 9-5/8" handling equipment and
casing tongs. M/U crossover to FOSV. MU 9-5/8", 40#, L-80, TXP-BTC shoe track to 165' Baker Lok connections 1-4 with 21K ft-lbs TQ. HES rep installed top hat
above float collar. Pump through shoe track and check floats - good. Static loss rate = 3.5 BPH. RIH with 9-5/8", 40#, L-80, TXP-BTC casing from 165' to 902'. TQ =
21K ft-lbs with Volant tool. Fill on the fly and top off every 10 joints. Installing centralizer per tally. Loss rate 5 bph. Continue to RIH with 9-5/8", 40#, L-80, TXP-BTC
casing from 902' to 2706'. TQ = 21K ft-lbs with Volant tool. Fill on the fly and top off every 10 joints. Installing centralizer per tally. Loss rate 6-10 bph. PU= 135K,
SO= 85K. Circulate a string volume, staging to 6 BPM = 200 psi and working pipe from 2706' to 2686'. Lost 7 bbl while circulating. Continue to RIH with 9-5/8",
40#, L-80, TXP-BTC casing from 2706' to 3321'. TQ = 21K ft-lbs with Volant tool. Fill on the fly and top off every 10 joints. Installing centralizer per tally. Loss rate 3-
8 bph. PU= 140K, SO= 93K. Daily disposal to G&I = 518 bbls. Total disposal to G&I = 7530 bbls. Daily water hauled from L-Lake = 830 bbls. Total water hauled
from L-Lake = 8235 bbls. Daily fluid loss = 42 bbls. Total fluid loss = 44 bbls.
4/19/2023 Continue to RIH with 9-5/8", 40#, L-80, TXP-BTC casing from 3321' to 5790' and 40#, L-80, DWC/C from 5790' to 5871'. Torque TXP = 21K ft-lbs / DWC/C =
32.3k ft-bs with Volant tool. Fill on the fly and top off every 10 joints. Installing centralizer per tally. Loss rate 4-8 bph. PU= 220K, SO= 75K. Continue to RIH with 9-
5/8", 40#, L-80, DWC/C casing from 5871 to 6279'. TQ = 32.3K ft-lbs with Volant tool. Fill on the fly and top off every 10 joints. Install centralizer per tally. Pump
down f/ 5912 t/ 6279, at 6 BPM - 320 psi, obtaining a BU over 10 jts. Loss rate 4-8 bph. PU= 330K, SO= 85K. Baker loc & MU the ES cementer to 6317, HES rep
verify pinned correctly (6x brass screws set for 3300 psi shear). RIH with 9-5/8", 47# casing from 6317' to 9048' on depth, verify pipe count. TQ 47# to 24K ft-lbs,
Fill on the fly, top off every 10 joints. Loss rate 5-8 bph, 155.5 bbls total loss. Establish circulation 1 BPM 580 psi ICP. Attempt to work string, P/U wt in excess of
425k. Park on depth at 9048'. Stage pumps slowly from 1 BPM to 6 BPM. Condition mud for cementing with 3x BU, Final 6 BPM = 250 psi with MW 9.3 ppg, YP =
15. SimOps: Spot and R/U cementers. Shut down pump, B/D TD and breakout Volant. R/U plug valves and cement hose. Re-dope and M/U Volant. Close upper
and lower IBOP. Re-establish circulation @ 4 BPM, 110 psi. Remove bail extensions. 2.5 BPH losses circulating. Hold PJSM with all parties involved. HES batch
up while finish getting the pits ready. Blow air to cement unit. Pump 50 bbls mud treated with Desco, HES filled lines with 5 bbls fresh water. PT surface lines to
1,300/4,300 psi, good. Pump 1st stage cement job: Mix & pump 60 bbls of 10 ppg tuned spacer with 4# red dye & 5# Pol-E-Flake in 1st 10 bbls at 5 BPM = 400
psi. Drop bypass plug. Mix and pump 372 bbls of 12.0 ppg lead cement (EconoCem, Type I/II), 2.347ft^3/sk yield, 890 sks total) at 5 BPM = 575 psi. Daily disposal
to G&I = 727 bbls. Total disposal to G&I = 8257 bbls. Daily water hauled from L-Lake = 435 bbls. Total water hauled from L-Lake = 8670 bbls. Daily fluid loss = 120
bbls. Total fluid loss = 164 bbls.
4/20/2023 Continue to pump first stage cement: Mix and pump 82 bbls of 15.8 ppg tail cement (HalChem type 1-2 cement, 1.156 ft^3/sk yield, 400 sks total) at 4.2 BPM = 850
psi. Drop shut off plug. HES pump 20 bbls water at 5 BPM = 450 psi. Displace with 438 bbls of 9.3 ppg spud mud from the rig at 6.5 BPM = 170 psi ICP & 680 psi
FCP. Pumped 80 bbls of 9.4 ppg tuned spacer from Halliburton at 4.2 BPM = 600 psi. Pumped 137.8 bbls 9.3 ppg mud from the rig at 6 BPM = 870 psi ICP &
1,090 psi FCP. Slow rate to 3 BPM for last 10 bbls = 870 psi FCP, Bumped the plug at 5,702 stks, 5.8 bbls late, CIP @ 8:27. Pressure to 1,400 psi, Hold 3 min,
bleed off pressure, floats held. Pressure to 2,870 psi shifting ESC open. Shoe set at 9,048'. 17 bbl losses cementing and displacing. Stage to 6 BPM = 480 psi.
Circulate through ES cementer at 2,750', see trace Pol-E-Flake at 500 stks, 1,120 stks see cement, 1,900 stks see spacer. Dump 78 bbls cement, 60 bbls spacer,
123 bbls interface. Take returns to pits. Circ 5 BU total. FCP= 260 psi. Submit 24 hr notice to AOGCC for BOP test. Disconnect knife valve accumulator lines. Drain
stack and flush with black water 3 times. Re-connect knife valve accumulator lines. Clean rig floor cement valves. Break out the Volant, clean same and re-dope the
cup, MU the Volant. Continue to circulate through the ES cementer at 2,750' pumping 6 BPM = 260 psi while prepping for the 2nd stage cement job. Hold PJSM
with all parties involved. Break out the Volant, dope the cup and MU the Volant. Clean both pumps suction screens. Blow air through the cement line to the cement
unit. Pump 2nd stage cement job: Pump 5 bbls of water, test lines to 1,300 psi and 3750 psi. Mix & pump 60 bbls of 10.0 ppg Tuned Spacer w/ 4# red dye & 5# Pol-
E-Flake in 1st 10 bbls at 4 BPM, 300 psi. Mix & pump total 346 bbls 10.7 ppg ArcticCem lead cement (675 sx at 2.855 ft^3/sk yield) at 5.7 BPM, ICP= 630, FCP=
700 psi. At 282 bbls pumped, seeing spacer interface, dump returns to rockwasher, good cement at 380 bbls pumped (31 bbls early of calculated). Mix & pump 56
bbls of 15.8 ppg HalCem tail cement (270 sx at 1.156 ft^3/sk yield) at 3.7 BPM= 600 psi. Drop the closing plug. Pump 20 bbls of 8.34 ppg fresh water at 5 BPM =
750 psi. Displace with 182.5 bbls 9.35 ppg spud mud at 5 BPM = 350 psi ICP, Slow to 3 BPM at 135 bbls pumped, 850 psi FCP. Bumped the plug at 1.5 bbls over
calc. CIP at 20:30. Pressure to 2000 psi shifting ESC closed (observe shift at 1760 psi), hold for 5 min, bleed off psi, open block valve to casing, no flow. 98 BBLS
spacer & interface and 272.5 bbls good 10.7 ppg cement returned, 100% returns. Blow down cement line. R/D the Volant tool. Suck out casing joint. Disconnect the
koomey lines from the knife valve. Drain the cement from the stack into the cellar box. Flush the stack with black water 3x. Power down the accumulator and
disconnect lines from diverter annular. Start R/D diverter line. Hoist the diverter stack. Center casing & Install the casing slips per wellhead rep with 100K on the
slips. Remove 4" conductor valves and install 4" conductor outlet caps. Welder cut the 9-5/8" casing. L/D the cut jt and 19' pup jt. Cut jt length = 18.89'. Set bag
back down. ND diverter stack/tee and knife valve. Remove equipment from cellar & mobilize wellhead equipment into cellar. SimOps: Clear the rig floor of casing
running equipment & clean the mud pits. Install the slip lock casing head and tubing spool. PT the void to 500 psi for 5 minutes and 3,800 psi. SimOps: Continue
clean the mud pits. Daily disposal to G&I = 1921 bbls. Total disposal to G&I = 10178 bbls. Daily water hauled from L-Lake = 370 bbls. Total water hauled from L-
Lake = 9040 bbls. Daily fluid loss = 17 bbls. Total fluid loss = 181 bbls.
4/21/2023 NU adaptor spool. NU the BOP stack, install turn buckles. Install the kill and choke lines along with the orbit valve and trip nipple. SimOps: continue cleaning the
mud pits. Spot and RU MPD unit. Record RKB's, install 1502 flanges on annulus valves, RU koomey lines to stack, load test tools to the rig floor. Install mouse hole.
Continue to clean in pits. RU BOPE testing equipment. Install test plug and 4 1/2'' test joint, flood stack and lines with fresh water. Adjust stack to align trip nipple,
no leaks. Mechanic removed stripped out 1/2'' plug in grease port on upper IBOP, service valve, install new plug also troubleshoot and adjust super choke timing to
open and close correctly. Perform BOP shell test to 250/3000 psi, good test. Conduct initial BOPE test to 250/3,000 psi: LPR (2-7/8 x 5 VBRs) with 4-1/2 & 5 test
joints, UPR (4-1/2 x 7 VBRs) with 4-1/2 & 7 test joints, annular with 4-1/2 test joints, accumulator drawdown test, test gas alarms & PVT. All tests performed with
fresh water against test plug. AOGCC state inspector Brian Bixby on location to witness Test. Tests: 1. Annular on 4.5 test joint, Choke valves 1, 12, 13, 14, Kill
Demco & 5 Dart Valve. 2. Upper 4.5x7 VBR on 4.5 test joint, Choke valves 9 & 11, & 5 FOSV. 3. Lower 2.875x5 VBR on 4.5 test joint. 4. Upper 4.5x7 VBR, Choke
valves 5, 8 & 10, HCR kill & Upper IBOP. 5. Choke valve 4, 6, 7, Manual kill & Lower IBOP. 6. Choke valve 2. 7. HCR Choke & 3.5 Dart Valve. 8. Manual Choke &
3.5 FOSV. 9. Lower 2.875x5 VBR on 4.5 test joint. 10. Blind rams & Choke valve 3. 11. Hyd, Super Choke A. 12. Manual Super Choke B. Accumulator Test:
System pressure = 3,050 psi. Pressure after closure = 1,700 psi. 200 psi attained in 40 seconds. Full pressure attained in 185 seconds. Nitrogen Bottles - 6 at
2,000 psi. Blow down and RD BOPE testing equipment. Vac fluid from trip nipple and remove same. Install MPD test cap and test MPD orbit valve flange to 1400
psi. Install trip nipple and check for leaks. Pull the test plug. M/U the wear ring running tool. Install the wear ring (ID = 9-1/16"). Lay down the wear ring running tool.
Blow down the choke & kill lines. M/U 8-1/2", Smith XR+ mill tooth bit, 6.75" mud motor with 1.5 AKO. 17 joints HWDP and hydraulic jars to 587. TIH with stands of
5 DP from 587' to 2683. 98k PU, 65k SO, 85k ROT. Wash and ream from 2,683' to 2735' pumping 450 GPM = 930 psi, 40 RPM = 5-8K ft-lbs Tq. Drill cement
stringers to 2749', tagging ES Cementer on depth. Daily disposal to G&I = 360 bbls. Total disposal to G&I = 10609 bbls. Daily water hauled from L-Lake = 370 bbls.
Total water hauled from L-Lake = 9400 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 181 bbls.
4/22/2023 Drill ESC on depth from 2,749' to 2,751' pumping 450 gpm, 40 rpm, 5-8k torque, 8-10k WOB, ream through ESC 4x, drift through with no pumps or rotary, good.
PU 98K, SO 65K, ROT 85K. Blow down top drive, RIH on elevators from 2,775' to 8,769' with no more SO wt, fill pipe every 2000'. MU top drive, wash and ream
from 8,769' to 8,894' pumping 450 gpm, 1360 psi, 40 rpm, 20-23k torque. PU 250K, SO none, ROT 120K. Circulate BU pumping 450 gpm, 40 rpm, working pipe
30'. Simops: RU and test MPD lines to 1400 psi, BD lines. Parked at 8,892'. Blow down the top drive. RU head pin, cement line and testing equipment. Flood the
lines and purge the air. PT the 9-5/8" casing to 2,500 psi for 30 minutes charted - good test. Pumped 6.3 bbls & bled back 6.3 bbls. Blow down and RD testing
equipment. Wash/ream down, Tag and drill cement and F/E from 8,913' to 9,040' at 450 GPM = 1,450 psi, 40 RPM = 20-25K ft-lbs TQ, WOB = 5-10K. Wash and
ream through all equipment 3 times. Drill out rat hole from 9,040' to 9,053'. Note: FE drilled 8' higher than casing tally depth. PU = 250K, ROT = 120K. MU single,
Drill 20' of new formation from 9,053' to 9,073' at 444 GPM = 1,430 psi, 40 RPM = 23K ft-lbs TQ, WOB = 10-15K, LD 2 singles to 9,019'. Circulate and condition
the mud for the FIT at 450 GPM = 1,460 psi, 40 RPM = 19-23K ft-lbs TQ reciprocating 60'. Add 4 drums 776 lube @ 1/2% to the system to reduce drag. Even 9.3
ppg MW in/out. RU testing equipment, flood the lines and purge the air. Close the UPR on 5" DP, pump down the DP and the kill line. Perform FIT to 12.0 ppg, with
9.3 ppg MW at 4,036' TVD, 567 psi applied at surface. Mud appears to be aired/foamed up. Discuss results with engineer. R/D and blow down testing equip.
Continue circulating a bottoms up, attempt to treat out aired/foamed mud with defoamer and screenkleen, little to no positive results. R/U testing equipment, flood
the lines and purge the air. Close the UPR on 5" DP, pump down the DP and the kill line. Perform FIT again with similar results. RD and blow down testing
equipment. Monitor Well. Pump dry job and blow down lines. MU single to get back on even stands. 250k PUW, no SOW. TOOH from 9010 to 682. Monitor Well
on last stand DP- Static. Rack last stand DP in Derrick. L/D 5" HWDP from 587' to 278'. Stand back the jar stand. Continue to LD HWDP from 216' to 31'. L/D mud
motor and bit. Bit grade: 1-1-WT-A-E-I-NO-BHA. Lost 17 bbls while TOOH. Mobilize BHA components to the rig floor. Remove the master bushings, jet the flow line
clean and install the split bushings. MU 8-1/2" NOV PDC bit, NRP-A2 bit sleeve, 7600 Geo-Pilot, LWD (ADR & DGR), PWD, GWD, Directional tools and stabilizer
to 104'. Daily disposal to G&I = 114 bbls. Total disposal to G&I = 10723 bbls. Daily water hauled from L-Lake = 95 bbls. Total water hauled from L-Lake = 9495
bbls. Daily fluid loss = 0 bbls. Total fluid loss = 181 bbls.
4/23/2023 Plug in and initialize MWD, MU remaining BHA #4, NM float sub, 3 NM flex collars, NM float sub and 2 HWDP with jars to 292'. TIH with 8-1/2" lateral BHA from
292' to 2,198' with stands of 5'' drill pipe. MU top drive fill pipe, Break in geo pilot seals, shallow pulse test tools, 450 gpm, 1080 psi, 40 rpm, 5K torque, good.
Unable to downlink, mud aired up, test on next pipe fill, BD TD. PU 95K, SO 75K, ROT 80K. TIH from 2,198' to 4,103', MU top drive, PT rebuilt 2'' demco valve on
mud manifold, good. Fill pipe, attempt to downlink, mud aired up, BD top drive. Will downlink next fill,. TIH from 4,103' to 7,901' with stands 5'' drill pipe. fill pipe,
perform successful downlink, BD top drive, continue TIH to 8,757', fill pipe, BD TD, single in with 5'' DP to 8,946'. Correct displacement TIH. PU 275K, SO 50K.
PJSM. Drain the riser. Pull the MPD riser and install the MPD RCD. Install the RCD head skirt for the drip pan - no leaks. PJSM, Pump pit 4 empty. Pump spacer.
Wash to TD. Displace the well from 9.3 ppg spud mud to 8.8 ppg FloPro at 6 BPM = 770 psi ICP, 40 RPM = 24K ft-lbs TQ. With new mud out the bit pull into the 9
5/8' casing. FCP= 430 psi and final TQ= 15K ft-lbs. PU 235K, SO 80K, ROT 125K. Obtain SPRs. Rig up and perform FIT to 12.0 ppg, double check results against
previous spud mud. Good test. Blow down lines. Slip and cut 92' drilling of line. Service blocks & Topdrive. Inspect saversub and grabber dies. Calibrate block
height. SimOps: Clean underneath shakers and pits. Monitor Well against shut in MPD choke, 2 psi build. RIH with a single jt to 9043', make up stand drillpipe.
Wash/Ream down to bottom at 9073'. 450 GPM 1220 psi, 80 RPM 14k Tq. Drill 8-1/2" lateral from 9073' to 9097' (4040' TVD), 24' drilled, 48'/hr AROP. 450 GPM =
1220 PSI, 80 RPM = 12-13K ft-lbs Tq, 5-10K WOB. MW = 8.75 ppg, vis = 44, ECD = 9.91, max gas = 53u. PU = 180K, SO = 80K & ROT = 125K. Shakers start
blinding off. Reduce flow to 400 GPM, no improvement. Pull into shoe & screen down from 120s to 100s attempt to circulate at reduced rate - 200 GPM, still
blinding. Screen down to 80s & circulate at 200 GPM until shakers cleaning up. Stg pumps up to 400 GPM as allowed. Pumps off, make connection and RIH to
9097'. Drill 8-1/2" lateral from 9097' to 9423' (4063' TVD), 326' drilled, 72.4'/hr AROP. 550 GPM = 1820 PSI, 80 RPM = 17K ft-lbs Tq, 10-16K WOB. MW = 8.8
ppg, vis = 53, ECD = 10.5, max gas = 853u. PU = 160K, SO = 75K & ROT = 115K. Drilling with MPD chokes open, Trapping 150 psi on connection. Last survey at
9354.94' MD / 4055.50' TVD, 86.02 deg inc, 325.20 deg azm, 16.16' from plan, 15.10' high and 5.76' right. We have drilled 1 concretion for a total thickness of 28'
(9.3% of the lateral). Daily disposal to G&I = 860 bbls. Total disposal to G&I = 11583 bbls. Daily water hauled from L-Lake = 155 bbls. Total water hauled from L-
Lake = 9650 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 181 bbls.
4/24/2023 Drill 8-1/2" lateral from 9,423' to 9,864' (4,054' TVD), 441' drilled, 73.5'/hr AROP. 550 GPM = 1,750 PSI, 120 RPM = 16K ft-lbs Tq, 9-11K WOB. MW = 8.8 ppg, vis
= 42, ECD = 10.3, max gas = 960u. PU = 163K, SO = 81K & ROT = 114K. Drilling with MPD chokes open, Trapping 150 psi on connections. Drill in the OA-3
targeting 90 deg to 9592', undulate up targeting 92 deg. Drill 8-1/2" lateral from 9,864' to 10565' (4038' TVD), 701' drilled, 117'/hr AROP. 550 GPM = 1850 PSI,
120 RPM = 13K ft-lbs Tq, 5-10K WOB. MW = 8.8 ppg, vis = 38, ECD = 10.44, max gas = 655u. PU = 157K, SO = 80K & ROT = 116K. Drilling with MPD chokes
open, Trapping 130 psi on connections. Target 92 deg, Exit the OA-3 top at 9,934', crossing the OA-2, enter the OA-1 @ 10,021' leveling out and targeting 90.5
deg. Pump 30 bbl hi vis sweep @ 9,995', back on time with 100% increase. Drill 8-1/2" lateral from 10565' to 11196' (4043' TVD), 631' drilled, 105'/hr AROP. 550
GPM = 1890 PSI, 120 RPM = 14K ft-lbs Tq, 5-8K WOB. MW = 8.8 ppg, vis = 39, ECD = 10.65, max gas = 775u. PU = 165K, SO = 70K & ROT = 117K. Drilling
with MPD chokes open, Trapping 130 psi on connections. Maintain the OA-1 as per Geologist. Pump 30 bbl hi vis sweep @ 10946', back on time with 100%
increase. Drill 8-1/2" lateral from 11196' to 11899' (4062' TVD), 703' drilled, 117'/hr AROP. 550 GPM = 2120 PSI, 120 RPM = 15K ft-lbs Tq, 14-16K WOB. MW =
8.8 ppg, vis = 43, ECD = 10.4, max gas = 808u. PU = 170K, SO = 68K & ROT = 115K. Drilling with MPD chokes open, Trapping 130 psi on connections. Drill
down section from the OA-1 to the OA-3. Target formation dip of 89 deg to maintain OA-3. Last survey at 11827.21' MD / 4062.69' TVD, 89.19 deg inc, 331.90 deg
azm, 57.42' from plan, 27.27' high and 50.53' right. We have drilled 19 concretions for a total thickness of 191' (6.8% of the lateral). Daily disposal to G&I = 1130
bbls. Total disposal to G&I = 12713 bbls. Daily water hauled from L-Lake = 1090 bbls. Total water hauled from L-Lake = 10740 bbls. Daily fluid loss = 0 bbls. Total
fluid loss = 181 bbls.
4/25/2023 Drill 8-1/2" lateral from 11,899' to 12,277' (4,071' TVD), 378' drilled, 63'/hr AROP. 550 GPM = 2,100 PSI, 120 RPM = 17K ft-lbs Tq, 16K WOB. MW = 8.8 ppg, vis
= 39, ECD =10.8 max gas = 557u. PU = 170K, SO = 60K & ROT = 115K. Drilling with MPD chokes open, Trapping 130 psi on connections. Pump 30 bbl hi vis
sweep @ 11,899', back on time with 100% increase. Drill in the OA-3 target 89 deg, at 12,812' target 87.5 deg. Drill 8-1/2" lateral from 12277' to 12740' (4079'
TVD), 463' drilled, 77'/hr AROP. 550 GPM = 2120 PSI, 120 RPM = 20K ft-lbs Tq, 15-18K WOB. MW = 8.8 ppg, vis = 38, ECD = 10.65, Max gas = 585u. PU =
175K, SO = 0K & ROT = 115K. Continue to target 87.5 deg, at 12,415' target 89.5 deg. Drilling with MPD chokes open, Trapping 130 psi on connections. Lost S/O
Wt @ 12660'. Drill 8-1/2" lateral from 12740' to 13201' (4060' TVD), 461' drilled, 77'/hr AROP. 550 GPM = 2260 PSI, 120 RPM = 16K ft-lbs Tq, 10-16K WOB. MW
= 8.8 ppg, vis = 39, ECD = 10.91, Max gas = 701u. PU = 165K, SO = 0K & ROT = 112K. Drilling with MPD chokes open, Trapping 150 psi on connection. Pump
30 bbl hi vis sweep @ 13037', back on time with 100% increase. Start steering up at 12657'. Drill 8-1/2" lateral from 13201' to 13785' (4069' TVD), 584' drilled,
97'/hr AROP. 550 GPM = 2310 PSI, 120 RPM = 17K ft-lbs Tq, 10-17K WOB. MW = 8.9 ppg, vis = 43, ECD = 11.30, Max gas = 601u. PU = 185K, SO = 0K & ROT
= 110K. Drilling with MPD chokes open, Trapping 150 psi on connection. Enter the OA-1 @ 13208'.
Encountered fault #1 with a 12 DTW throw at 13250', moving the Wellbore from the base of OA-1 to the top of the zone. Exited the top of OA-1 at 13312' and
reacquired it at 13413' for 101' drilled above the zone. Last survey at 13632.72' MD / 4068.30' TVD, 89.19 deg inc, 333.13 deg azm, 16.10' from plan, 15.34' high
and 4.90' right. We have drilled 38 concretions for a total thickness of 460' (9.9% of the lateral). Daily disposal to G&I = 865 bbls. Total disposal to G&I = 13578
bbls. Daily water hauled from L-Lake = 1090 bbls. Total water hauled from L-Lake = 10740 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 181 bbls.
4/26/2023 Drill 8-1/2" lateral from 13,785' to 14,310' (4,067' TVD). Drilled 525' = 87.5'/hr AROP. 544 GPM = 2,460 psi, 120 RPM = 18K ft-lbs TQ, WOB =11K. PU = 180K,
SO = 0K & ROT = 110K. MW = 8.9 ppg, Vis = 41, ECD = 11.5 ppg, Max gas = 533 units. Drilling with MPD chokes open and trapping 150 psi on connection. Drill
in the OA-1 targeting 89.5 deg Begin planned undulation down at 14,082' and exited the OA-1 at 14,127'. Pump 30 bbl hi-vis sweep at 13,988', back on time with
40% increase. Drill 8-1/2" lateral from 14,310' to 14,918' (4,102' TVD). Drilled 608' = 101.3'/hr AROP. 550 GPM = 2,320 psi, 120 RPM = 19K ft-lbs TQ, WOB =10-
15K. PU = 180K, SO = 0K & ROT = 116K. MW = 8.9 ppg, Vis = 40, ECD = 11.14 ppg, Max gas = 533 units. Drilling with MPD chokes open and trapping 150 psi
on connection. Perform 450 bbl dump & dilute with new 8.8 ppg Flo pro mud at 14,480'. Lowering MBT from 6.5 to 4.25. Continue to undulate down entering the OA-
3 at 14,325' and leveling out at 14,418' targeting 89.5 deg. Exited the OA-3 at 14,864 and reentered the OA-3 at 14,885'. Drill 8-1/2" lateral from 14,918' to 15,319'
(4,093' TVD). Drilled 401' = 66.8'/hr AROP. 550 GPM = 2,450 psi, 120 RPM = 17-19K ft-lbs TQ, WOB =5-7K. PU = 185K, SO = 0K & ROT = 110K. MW = 8.9 ppg,
Vis = 39, ECD = 11.25 ppg, Max gas = 625 units. Drilling with MPD chokes open and trapping 150 psi on connection. Pump 30 bbl hi-vis sweep at 15,033', back on
time with 60% increase. Drill 8-1/2" lateral from 15,319' to 15,889' (4,085' TVD). Drilled 570' = 95'/hr AROP. 550 GPM = 2,480 psi, 120 RPM = 18K ft-lbs TQ, WOB
= 5-15K. PU = 195K, SO = 0K & ROT = 110K. MW = 8.8+ ppg, Vis = 38, ECD = 11.2 ppg, Max gas = 630 units. Drilling with MPD chokes open and trapping 150
psi on connection. Drilled 54 concretions for a total thickness of 602 (8.8% of the lateral). Last survey at 15,630.31 MD / 4,089.32 TVD, 90.51 deg INC, 335.95 deg
AZM. Distance from WP09 = 14.34, 14.3 high & 0.5 right.
4/27/2023 Drill 8-1/2" lateral from 15,889' to 16,271' (4,064' TVD). Drilled 382' = 63.66'/hr AROP. 536 GPM = 2,430 psi, 120 RPM = 19K ft-lbs TQ, WOB = 14K. PU = 194K,
SO = 0K & ROT = 110K. MW = 8.8 ppg, Vis = 39, ECD = 11.2 ppg, Max gas = 633 units. Drilling with MPD chokes open and trapping 150 psi on connections.
Pump 30 bbl hi-vis sweep at 15,988', back on time with 100% increase. Drill in the OA-3 targeting 92 deg to planned undulation up at 15,984'. Drill 8-1/2" lateral
from 16,271' to 16,839' (4,049' TVD). Drilled 568' = 94.7'/hr AROP. 550 GPM = 2,610 psi, 120 RPM = 18K ft-lbs TQ, WOB = 9K. PU = 190K, SO = 0K & ROT =
110K. MW = 8.9 ppg, Vis = 40, ECD = 11.42 ppg, Max gas = 605 units. Drilling with MPD chokes open and trapping 150 psi on connections. Drill in the OA-3
undulating up, exiting the OA-3 at 16,302', entering the OA-1 at 16,404' and leveled out targeting 92 deg. Drill 8-1/2" lateral from 16,839' to 17,235' (4,042' TVD).
Drilled 396' = 66'/hr AROP. 550 GPM = 2,580 psi, 120 RPM = 20K ft-lbs TQ, WOB = 18K. PU = 195K, SO = 0K & ROT = 110K. MW = 8.9 ppg, Vis = 40, ECD =
11.29 ppg, Max gas = 626 units. Drilling with MPD chokes open and trapping 150 psi on connections. Pump 30 bbl hi-vis sweep at 17,030', back 100 strokes late
with 80% increase. Drill 8-1/2" lateral from 17,235' to 17,792' (4,060' TVD). Drilled 557' = 92.8'/hr AROP. 550 GPM = 2,800 psi, 120 RPM = 19K ft-lbs TQ, WOB =
15K. PU = 198K, SO = 0K & ROT = 108K. MW = 8.8 ppg, Vis = 40, ECD = 11.4 ppg, Max gas = 590 units. Drilling with MPD chokes open and trapping 150 psi on
connections. Drilled in the OA-1 to planned undulation at 17,314', exiting the OA-1 at 17,468' and entering the OA-3 at 17,660'. Continue undulating down in
preparation of upcoming fault. Drilled 72 concretions for a total thickness of 757 (8.7% of the lateral). Last survey at 17,624.61 MD / 4,050.12 TVD, 88.17 deg INC,
331.74 deg AZM. Distance from WP09 = 20.42, 12.66 high & 16.02 right.
4/28/2023 Drill 8-1/2" lateral from 17,792' to 18,041' (4,056' TVD). Drilled 249' = 41.5'/hr AROP. 550 GPM = 2,730 psi, 120 RPM = 22K ft-lbs TQ, WOB = 16K. PU = 204K,
SO = 0K & ROT = 109K. MW = 8.8 ppg, Vis = 38, ECD = 11.2 ppg, Max gas = 584 units. Drilling with MPD chokes open and trapping 150 psi on connections. Drill
in the OA-3 undulating down leveling out targeting 90 deg in preparation of upcoming fault. Pump 30 bbl hi vis sweep at 17,980', back 400 strokes late with 75%
increase. Drill 8-1/2" lateral from 18,041' to 18,429' (4,058' TVD). Drilled 388' = 64.7'/hr AROP. 550 GPM = 2,500 psi, 120 RPM = 22K ft-lbs TQ, WOB = 19K. PU =
200K, SO = 0K & ROT = 111K. MW = 8.8 ppg, Vis = 38, ECD = 11.15 ppg, Max gas = 546 units. Drilling with MPD chokes open and trapping 150 psi on
connections. At 18,133' perform 580 bbl dump & dilute with new 8.8 ppg Flo Pro mud reducing the MBT from 6.75 to 4.75. Drill in the OA-3 targeting 90 deg. Drill 8-
1/2" lateral from 18,429' to 18,760' (4,058' TVD). Drilled 331' = 55.2'/hr AROP. 550 GPM = 2,690 psi, 120 RPM = 19K ft-lbs TQ, WOB = 19K. PU = 195K, SO = 0K
& ROT = 112K. MW = 8.8+ ppg, Vis = 37, ECD = 11.14 ppg, Max gas = 537 units. Drilling with MPD chokes open and trapping 150 psi on connections.
Encountered fault #2 at 18,405' with 26' DTW throw moving the wellbore from the middle of the OA-3 to the top of the OA-1. Encountered fault #3 at 18,505' with 40'
DTW throw moving the wellbore from the upper OA-1 to the NF clays. Drill 8-1/2" lateral from 18,760' to 19,170' (4,113' TVD). Drilled 410' = 68.3'/hr AROP. 550
GPM = 2,840 psi, 120 RPM = 19K ft-lbs TQ, WOB = 12K. PU = 197K, SO = 0K & ROT = 109K. MW = 8.9 ppg, Vis = 39, ECD = 11.5 ppg, Max gas = 852 units.
Drilling with MPD chokes open and trapping 150 psi on connections. Reacquired the OA-1 at 18,942'. Exited the OA-1 at 19,050' and entered the OA-3 at 19,080'.
Pump 30 bbl hi vis sweep at 19,028', back 400 strokes late with 30% increase. Drilled 85 concretions for a total thickness of 952 (9.4% of the lateral). Last survey at
18,957.27 MD / 4,100.13 TVD, 84.34 deg INC, 334.89 deg AZM. Distance from WP09 = 5.16, 1.93 high & 4.79 left.
4/29/2023 Drill 8-1/2" lateral from 19,170' to 19,535' (4,113' TVD). Drilled 365' = 60.8'/hr AROP. 550 GPM = 2,810 psi, 120 RPM = 21K ft-lbs TQ, WOB = 6K. PU = 216K, SO
= 0K & ROT = 116K. MW = 8.8 ppg, Vis = 37, ECD = 11.4 ppg, Max gas = 758 units. Drilling with MPD chokes open and trapping 150 psi on connections. Drill in
the OA-3 targeting 91 deg. Drill 8-1/2" lateral from 19,535' to 19,999' (4,012' TVD). Drilled 464' = 77.3'/hr AROP. 550 GPM = 2,870 psi, 120 RPM = 22K ft-lbs TQ,
WOB = 20K. PU = 225K, SO = 0K & ROT = 135K. MW = 8.8+ ppg, Vis = 37, ECD = 11.17 ppg, Max gas = 724 units. Drilling with MPD chokes open and trapping
150 psi on connections. Drill in the OA-3 targeting 90-91 deg. Drill 8-1/2" lateral from 19,999' to TD at 20,227' (4,114' TVD). Drilled 228' = 38'/hr AROP. 550 GPM =
2,850 psi, 120 RPM = 21K ft-lbs TQ, WOB = 10K. PU = 227K, SO = 0K & ROT = 138K. MW = 8.8+ ppg, Vis = 38, ECD = 11.08 ppg, Max gas = 635 units. Drilling
with MPD chokes open and trapping 150 psi on connections. Drilled 103 concretions for a total thickness of 1,137 (10.2% of the lateral). Obtain SPR's and final
survey. Downlink Geo-Pilot to home position. Last survey at 20,227 MD / 4,114.7 TVD, 88.22 deg INC, 328.37 deg AZM. Distance from WP09 = 59.76, 56.75 low &
18.72 right. Pump 30 bbl hi-vis sweep, back 400 strokes late with 30% increase in cuttings. Circulated a total of 4 BU at 550 GPM = 3,010 psi, 120 RPM = 19K ft-
lbs TQ. ECD = 10.97 ppg with 8.9 ppg MW. Reciprocate DP alternating end points. PJSM. Trip back to bottom
4/30/2023 Pump 30 bbls hi-vis spacer, 25 bbls 8.45 ppg vis brine, 30 bbls SAPP pill #1, 25 bbls brine, 30 bbls SAPP pill #2, 25 bbls brine, 30 bbls SAPP pill #3 then 30 bbls
high vis spacer. Displace with 995 bbls of 8.45 ppg viscosified brine with 3% lubes (1.5% 776 and 1.5% LoTorq). PU= 240K & ROT= 140K. 7 BPM = 1,160 psi
(ICP), 40 RPM = 21K ft-lbs TQ & 7 BPM = 830 psi (FCP), 40 RPM = 18K ft-lbs TQ, reciprocating 90' alternating stopping points. Shut down the pumps with clean
8.45 ppg viscosified brine to surface. No losses. PU= 225K, SO= 0K, ROT= 145K. Obtain passing PST: 2.4, 2.4 & 2.5 seconds per 1L sample. Mousehole a stand
and blow down top drive. MU stand and TD. Monitor the wellbore pressure with MPD choke 3 times 5 minutes each = 61, 53 & 46 psi. EMW = 8.7 ppg. Obtain new
SPRs. Wash and ream to TD. SimOps:Clean pit #3 and load 8.45 ppg 3% lube brine in pits #3 & 4. BROOH from 20,227' to 17,317' pulling 5-10 minutes/stand
slowing as needed to clean up slides/tight spots. Rack back 12 stands HWDP on DS then Laying down DP in the mouse hole. 475 GPM = 1,580 psi, 120 RPM =
23 ft-lbs TQ, max gas = 107 units. PU = 205K, SO = 0K & ROT = 112K. Start BROOH 550 GPM and had to stage pumps down to 450 GPM due to loss rate of 168
BPH. Slow to 400 GPM with loss rate slowing to 64 BPH. At 18,850' loss rate slowing to 8 BPH. At 18,250', stage pumps up to 475 GPM. BROOH from 17,137' to
14,273' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight spots. Laying down DP in the mouse hole. 450 GPM = 1,350 psi, 120 RPM = 20K ft-
bs TQ, ECD= 10.03 ppg, max gas = 203 units. PU = 192K, SO = 70K, ROT = 117K. Regained SO weight at 15,036'. BROOH from 14,273' to 11,041' pulling 5-10
minutes/stand slowing as needed to clean up slides/tight spots. Laying down DP in the mouse hole. 450 GPM = 1,190 psi, 120 RPM = 15K ft-bs TQ, ECD= 9.84
ppg, max gas = 362 units. PU = 165K, SO = 80K, ROT = 115K.
5/1/2023 BROOH from 11,041' to 9,232' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight spots. Laying down DP in the mouse hole. 450 GPM = 1,240
psi, 120 RPM = 13K ft-bs TQ, ECD= 9.8 ppg, max gas = 209 units. PU = 160K, SO = 100K, ROT = 125K. Loss rate 4-6 bph. Pump into the shoe without rotary
from 9,232 to 9,034' at 450 GPM = 1,240 psi. 5k drag pulling into the shoe. Lost 293 bbls while BROOH. Pump 30 bbl hi-vis sweep at 450 GPM = 1,130 psi, 60
RPM = 8-9K ft-lbs TQ reciprocating 90' and circulate the casing clean with 2 BU. Sweep back on time with no increase. Obtain passing PST. MW in/out = 8.6 ppg.
LD single, BD TD, Monitor the wellbore pressure with MPD choke 4 times 5 minutes each = 71, 68, 63, & 60 psi. EMW = 8.9 ppg. Weight up the surface system to
8.9 ppg. Circulate 8.9 ppg while weighting up the returns on the fly to 8.9 ppg at 6 BPM = 490 psi, 60 RPM = 5-8K ft-lbs TQ reciprocating 90' until good 8.9 ppg
in/out. Shut down and BD TD, Monitor MPD for pressure build 3 times 5 minutes each = 40, 34 & 30 psi. MU TD. Weight up surface system to 9.1 ppg. Circulate
9.1 ppg while weighting up the returns on the fly to 9.1 ppg at 8 BPM = 700 psi, 60 RPM = 7K ft-lbs TQ reciprocating 90' until good 9.1 ppg in/out. Shut down and
BD TD, Monitor MPD for pressure build 5 minutes each, 40, 19 and final 4 psi, open 2'' valve at the RCD head and monitor the well, 1/4'' stream and going static in
40 minutes. PJSM. Slip and cut 106' (16 wraps) of drilling line. Remove burr on draw works drum kick plate. Service the top drive and calibrate the block height.
PJSM. Remove the RCD and install the MPD riser. The well is on a slight vac. Fill the riser and no leaks. POOH laying down 5" DP from 9,013' to 7,934'. Pump dry
job and blow down the top drive. Drop 2.45" OD drift on 100' of wire. TOOH from 7,934' to 292' standing back 5" DP. Lost 28.5 bbls while TOOH. Monitor the well -
on a slight vac. Remove drift on wire. Lay down HWDP.
5/2/2023 Lay down jar, HWDP, Non-Mag Flex collars and float subs to 104'. Plug in and read MWD tools, LD stabilizer, MWD tools, Geo-Pilot and 8-1/2'' bit. Bit grade = 5-2-
BT-C-X-I-CT-TD. Normal wear on BHA from Drilling and BR. Mobilize casing equipment and crossovers to the rig floor. Remove split bushings and install master
bushings. RU 4-1/2" double stack tongs, elevators and slips. MU crossover sub on FOSV. Static loss rate = 4 BPH. PJSM with all parties involved. PU round nose
float shoe on 4 1/2'' crossover joint (H625 box x BTC pin) to 42'. PJSM with oncoming crew, RIH with Superior 4-1/2", 13.5#, L-80, Hydril 625, 100-micron screens
from 42' to 3,867'. Torque to 9,600 ft-lbs with Doyon double stack tongs and verify MU mark. Loss rate = 3-4 BPH. RIH with Cal IV 4-1/2", 13.5#, L-80, Hydril 625,
100-micron screens from 3,867' to 4,432'. Torque to 9,600 ft-lbs with Doyon double stack tongs and verify MU mark. Hydraulic leak on the pipe skate. Replace o-
ring. RIH with Cal IV 4-1/2", 13.5#, L-80, Hydril 625, 100-micron screens from 4,432' to 8,433'. Torque to 9,600 ft-lbs with Doyon double stack tongs and verify MU
mark. PU = 120K & SO = 85K. Loss rate = 3 BPH. MU 5-1/2" EZGO box x 4-1/2" H625 pin crossover. Change handling equipment to 5-1/2". Change FOSV
crossover to 5-1/2" EZGO. RIH with Delta 5-1/2", 20#, L-80, EZGO HT, 100-micron screens per tally from 8,433' to 10,833'. Torque to EZGO HT to 8,850 ft-lbs &
JFE Bear to 7,400 ft-lbs with Doyon double stack tongs. Loss rate = 3 BPH.
5/3/2023 RIH with Delta 5-1/2"", 20#, L-80, EZGO HT, 100-micron screens per tally from 10,833' to 11,326'. Torque to EZGO HT to 8,850 ft-lbs & JFE Bear to 7,400 ft-lbs
with Doyon double stack tongs. PU = 150K & SO = 88K. Lost 53 bbls while RIH with screen liner. Change elevators to 5" DP and remover crossover from FOSV.
MU Baker SLZXP liner top packer to 11,363' then RIH with one stand of DP to 11,455'. Pump 10 bbls at 3 BPM = 190 psi to ensure clear flow path through the
packer. Attempt to obtain rotational parameters. Only would rotate slowly at 7.4K ft-lbs TQ limit while moving pipe. Blow down the top drive. TIH with 4-1/2" x 5-1/2"
screen liner on 5" DP from 11,455' to 17,831'. TIH with 4-1/2" x 5-1/2" screen liner on 5" HWDP from 17,831' to 18,935'. Single in the hole with 4-1/2" x 5-1/2"
screen liner on 5" HWDP from 18,935' to 19,488'. TIH with 4-1/2" x 5-1/2" screen liner on 5" DP from 19,488' to tag at TD at 20,227' with 15K down. PU = 260K &
SO = 80K. Lost 34 bbls while running liner. Lay down two joints and space out with 10' pup joint. Break circulation at 3 BPM = 420 psi. Drop 1.125" OD phenolic
setting ball. RU FOSV, side entry sub & 5' pup joint. RU circulating equipment and cement line. PT lines to 4,300 psi - good test. Place liner in tension at 20,227'
set depth. Pump ball down with 30 bbl hi-vis sweep at 3 BPM = 430 psi. Ball on seat 117 strokes early at 1,247 strokes. Pressure up to 2,000 psi, observer set at
1,970 psi & hold for 3 minutes. Set down 40K to confirm set. Pressure up & observe release at 3,070 psi. Continue to pressure up with rig pump and observe ball
seat shear at 4,030 psi. PU & observe travel at 145K to confirm release. Top of liner at 8,874.86'. Open kill line & purge air. Close the annular & PT the LTP to
1,500 psi for 10 minutes charted - good test. Bleed off the pressure & open the annular. Blow down & RD circulating equipment. Pump out of the LTP at 2 BPM =
150 psi. Once the liner running tool is out of the LTP bring pumps up to 444 GPM = 1,380 psi and circulate the sweep out of the hole. Sweep back on time with 0%
increase. Lay down a single and 10' pup joint to 8,858'. Pump 10.2 ppg dry job and blow down the top drive. POOH laying down 5" DP to the pipe shed from 8,858'
to 8,159'. RIH with 4 stand of 5" DP from the derrick from 8,159' to 8,507'. POOH laying down 5" DP from 8,507' to 8,159'. POOH laying down 5" HWDP from
8,159' to 6,530'. POOH laying down 5" DP from 6,530' to 1,173'. Loss rate = 1.5 BPH.
Activity Date Ops Summary
5/4/2023 POOH laying down 5"" DP from 1,173' to 33'. Lost 19 bbls while POOH laying down DP. Lay down liner running tool. MU wear ring pulling tool on 5" DP and pull
the wear ring. Lay down wear ring pulling tool and 5" DP. Change handling equipment to 7". Drain stack and make dummy run with 7-5/8" hanger. Mark landing
joint and lay down. Mobilize casing equipment to the rig floor. Rig up 7" slips, elevators and Doyon double stack tongs. MU crossover to FOSV. PJSM. PU 7" tie
back seal assembly and RIH with 7", 26#, L-80, TXP-BTC casing from 21' to 5,216' TQ = 14,750 ft-lbs. Slip and cut the pipe skate hose reel counterweight cable.
RIH with 7", 26#, L-80, TXP-BTC casing from 5,216' to no-go at 8,887' with 5K down. Set down 10K to confirm. TQ = 14,750 ft-lbs. PU = 170K & SO =105K. Lost
22 bbls while RIH with 7" casing. LD 3 joints. MU pup joints 7.61', 3.84' & 11.80'. MU joint #216. MU 7-5/8" mandrel casing hanger with 7" crossover pup and
landing joint. Land the casing hanger 1.78' off no-go. Change to DP elevators. MU crossover, FOSV, side entry sub and 10' DP pup joint. RU cement hose and
circulating equipment. Flood lines. PT to 1,000 psi - good test. PU and expose port. Break circulation confirming returns. Close the annular and reverse circulate
confirming returns. PJSM. Reverse circulate 180 bbls of 9.1 ppg corrosion inhibited brine at 6 BPM = 1,250 psi followed by 64 bbls diesel at 5 BPM = 850 psi and
chase with 8 bbl of CI brine to clear the lines. Strip through the annular, closing the ports and land the casing hanger with 65K on the hanger (1.78' off no-go). Bleed
off the pressure and drain the BOP stack. Blow down and RD the circulating lines and equipment. Lay down the landing joint. MU 2 joints of 5" HWDP and pack-off
running tool. Install 7-5/8" pack-off and RILDS.
5/5/2023 PT pack-off void to 500 psi for 5 minutes and 5,000 psi for 10 minutes - good test. LD HWDP and pack-off running tool. Rig up injection line and test equipment to
the OA. Pressure test 7" X 9-5/8" OA. Utilize rig pump and pressure up to 1,500 psi, hold test for 30 minutes on chart. 2.53 bbls pumped. Bleed off pressure. RD
circulating and test equipment. Mobilize 4-1/2" handling equipment, double stack, spooling unit with Tec wire, job box, cannon clamps, crossovers, pup joint and
tubing hanger. MU crossover to 3-1/2" TIW. Monitor well with the trip tank. Static loss rate = 1 BPH. PJSM. PU mule shoe joint and RIH on 4-1/2", 12.6#, L-80, TXP-
BTC tubing to 1,270'. Torque to 6,170 ft-lbs with Doyon double stack tongs. MU XN nipple, 1 joint, Baker Premier Packer, 1 joint and Gauge carrier. MU Zenith
gauge and Tec wire. MU 1 joint and sliding sleeve with covered ports for Tec wire bypass to 1,544'. RIH on 4-1/2", 12.6#, L-80, TXP-BTC tubing from 1,544' to
8,790' spooling TEC wire, installing cannon clamps per tally and checking electrical continuity of the TEC wire every 1,000'. Torque to 6,170 ft-lbs with Doyon
double stack tongs. Lost 34 bbls while RIH. Change elevator to 5". MU tubing hanger with BPV installed, crossover and 5" DP landing joint. Terminate the TEC wire
and feed through the tubing hanger. Land tubing on hanger with mule shoe at 8,886' with 35K on hanger. RLIDS. Lay down the landing joint. RD and demobilize
completion running equipment.
5/6/2023 Continue to RD and demobilize completion running equipment. Clean and clear rig floor. PJSM and nipple down BOPE stack. Rack back stack on stump. Install
CTS plug into BPV. Nipple up the tubing head adapter and tree to wellhead. PT tubing hanger void to 500 psi for 5 minutes and 5,000 psi for 10 minutes - good
test. Splice TEC wire for length. Obtain final Centrilift readings: Pt = 1,726 psi, Tt = 74.3 deg. Rig up to test, fill tree with diesel and purge the air. PT the tree to
250/5,000 psi - good test. RD testing equipment. Drain the diesel from the tree through the wing valve. Pull the CTS plug. Check for pressure under the BPV - the
well is on a slight vac. Pull the BPV with dry rod. Rig off highline and on generators at 15:00 hours. RU the squeeze manifold to be able to reverse circulate and u-
tube. PT lines to 3,700 psi. PJSM. Reverse circulate 141 bbls 9.1 ppg CI brine down the 4-1/2" x 7" IA, 2.5 BPM = 620 followed by 92 bbls of diesel at 4 BPM =
1,000 psi. Place the tubing and IA in communication. Allow the diesel to u-tube and equalize. Close the master valve, bleed off the pressure and drain the tree
through the wing valve. Set the 1-7/8" ball & rod on top of the master valve. Install the lubricator extension. Open the master valve dropping the ball & rod allowing it
to gravitate to seat. Close the master valve and RD the lubricator extension. Pressure up on the tubing to 3,500 psi setting the Premier packer at 2,100 psi. PT the
tubing to 3,500 psi for 30 minutes - good test. Bleed the tubing to 2,000 psi. Pressure up on the 4-1/2" x 7" annulus to 3,650 psi. High pressure hose developed a
pin hole leak. Close the wing valve and bleed off the pressure on the hose. High pressure hose that developed a pin hole leak was a brand new 6,100 psi hose.
Blow down the hose. Remove the hose and install a replacement high pressure hose. PT the line to 3,700 psi - good test. Pressure up on the annulus to 3,650 psi.
PT the 4-1/2" x 7" annulus to 3,650 psi for 30 minutes charted - good test. Bleed the IA to 0 psi and bleed the tubing to 250 psi. Secure the tree. Blow down and RD
the squeeze manifold and circulating lines.
5/7/2023 Clean the cellar box. Rig welder cut off the mouse hole extension and seal weld. SimOps: Prep the rig floor for skidding. Rig released at 03:00 hours.
50-029-23744-00-00API #:
Well Name:
Field:
County/State:
MP M-62
Milne Point
Hilcorp Energy Company Composite Report
, Alaska
Pressure up on the tubing to 3,500 psi setting the Premier packer at 2,100 psi. PT the
tubing to 3,500 psi for 30 minutes - good test.
Pressure up on the annulus to 3,650 psi.
PT the 4-1/2" x 7" annulus to 3,650 psi for 30 minutes charted - good test.
TD Shoe Depth: PBTD:
No. Jts. Returned
RKB RKB to BHF RKB to THF
Jts.
1
1
1
1
1
12
1
1
1
66
2
1
1
Yes X No Yes X No
Fluid Description:
Liner hanger Info (Make/Model): Liner top Packer?: Yes No
Liner hanger test pressure:X Yes No
Centralizer Placement:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:X Yes No
Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job
Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:X Yes No
Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job
Cement returns to surface?X Yes No Spacer returns? Yes X No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Post Job Calculations:
Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped:
Cmt returned to surface: Calculated cement left in wellbore:
OH volume Calculated: OH volume actual: Actual % Washout:
1.16
4/20/2023 Surface
Spud Mud
EconoCem Type I/II Cement 890 2.35
HalCem Type I/II Cement 400 1.16
5
2,731.10
Casing 9 5/8 47.0 L-80 TXP Tenaris 2,604.98 2,731.10 126.12
2,751.09 2,748.27
Casing Pup Joint 9 5/8 40.0 L-80 TXP 17.17 2,748.27
17.55 2,768.64 2,751.09
ES Cementer 10 3/4 TXP Halliburton 2.82
Casing Pup Joint 9 5/8 40.0 L-80 TXP
8,922.10
Casing 9 5/8 40.0 L-80 DWC/C Tenaris 6,153.46 8,922.10 2,768.64
8,964.68 8,923.50
Baffle Adapter 10 3/4 TXP Halliburton 1.40 8,923.50
1.30 8,965.98 8,964.68
Casing 9 5/8 40.0 L-80 TXP Tenaris 41.18
Float Collar 10 3/4 TXP Innovex
103 total 9-5/8" x 12"1/4" bowspring centralizers ran. Two in shoe joint w/ stop rings 10' from each end. One floating on
joint #2. One each with stop rings mid-joint on joint #3 & 4. One each on joints #5 to 25, every other joint to #47 then
every third joint to #146. One each on joints #149 to #159. One each with stop rings on pup joints above and below ES
cementer. One each on every third joint #162 to #219.
Casing 9 5/8 40.0 L-80 TXP Tenaris 80.48 9,046.46 8,965.98
www.wellez.net WellEz Information Management LLC ver_04818br
4.2
Ftg. Returned
Ftg. Cut Jt.18.89 Ftg. Balance
No. Jts. Delivered 232 No. Jts. Run 221 11
Length Measurements W/O
Threads
Ftg. Delivered Ftg. Run
34.54 RKB to CHF
Type of Shoe:Innovex Casing Crew:Doyon
12 372
ES Cementer Closure OK
56
ArcticCem Type I/II Cement
Type
HalCem Type I/II Cement 270
Tuned Spacer
675 2.85
Stage Collar @
60
Bump press
100
272.5
9,048.009,053.00
CEMENTING REPORT
Csg Wt. On Slips:100,000
Spud Mud
8:27 4/20/2023 2,751
2748.27
15.8 82
Bump press
Returns to Surface
Bump Plug?
3.7
9.35 5 182.5/181
655.8/650.1
1400
78
Rig
FI
R
S
T
S
T
A
G
E
10Tuned Spacer 60
15.8
850
9.3 6
2000
10
10.7 346 5.7
98.5
1090
Bump Plug?
Csg Wt. On Hook:425,000 Type Float Collar:Innovex No. Hrs to Run:25.5
18.09
51.31
9 5/8 47.0 L-80 TXP
9 5/8 47.0 L-80 TXP
88.609 5/8 47.0 L-80 TXP Tenaris 37.29
TXP Innovex 1.54 9,048.00 9,046.46
51.31 33.22
37.52 126.12 88.60
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.MP M-62 Date Run 18-Apr-23
CASING RECORD
County State Alaska Supv.B. Anderson / J. Vanderpool
8,964.68
Floats Held
538.3 856
350 505.5
Spud Mud
Rotate Csg Recip Csg Ft. Min. PPG9.3
Shoe @ 9048 FC @ Top of Liner
SE
C
O
N
D
S
T
A
G
E
Rig
20:30
Cement Returns to Surface
498.4 465.5 -6.6
Cut joint
Casing (Or Liner) Detail
Shoe
Casing Pup Joint
Casing
10 3/4
98.5
Returns to Surface
2,751
X
100
78
Cement Returns to Surface
X
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Chelsea Wright Digitally signed by Chelsea Wright
Date: 2023.05.01 09:45:00 -08'00'Benjamin Hand Digitally signed by Benjamin Hand
Date: 2023.05.02 10:06:58 -08'00'
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________MILNE PT UNIT M-62
JBR 05/23/2023
MISC. INSPECTIONS:
FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK:
ACCUMULATOR SYSTEM:MUD SYSTEM:
P/F P/F
P/FP/FP/F
Visual Alarm
QuantityQuantity
Time/Pressure
SizeQuantity
Number of Failures:0
Tested with 4 1/2", 5" and 7" Test Joints, Tested all gas alarms and PVT's.
Test Results
TEST DATA
Rig Rep:Williams / HamiltonOperator:Hilcorp Alaska, LLC Operator Rep:Yessak / Vanderpool
Rig Owner/Rig No.:Doyon 14 PTD#:2230060 DATE:4/21/2023
Type Operation:DRILL Annular:
250/3000Type Test:INIT
Valves:
250/3000
Rams:
250/3000
Test Pressures:Inspection No:bopBDB230422161836
Inspector Brian Bixby
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 6.5
MASP:
1397
Sundry No:
Control System Response Time (sec)
Time P/F
Housekeeping:P
PTD On Location P
Standing Order Posted P
Well Sign P
Hazard Sec.P
Test Fluid W
Misc NA
Upper Kelly 1 P
Lower Kelly 1 P
Ball Type 2 P
Inside BOP 2 P
FSV Misc 0 NA
14 PNo. Valves
1 PManual Chokes
1 PHydraulic Chokes
0 NACH Misc
Stripper 0 NA
Annular Preventer 1 13 5/8"P
#1 Rams 1 4 1/2"x7"P
#2 Rams 1 Blinds P
#3 Rams 1 2 7/8"x5"P
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 1 3 1/8"P
HCR Valves 2 3 1/8"P
Kill Line Valves 2 3 1/8"P
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P3050
Pressure After Closure P1700
200 PSI Attained P40
Full Pressure Attained P185
Blind Switch Covers:PYES
Bottle precharge P
Nitgn Btls# &psi (avg)P6@2000
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
P PMeth Gas Detector
P PH2S Gas Detector
0 NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P22
#1 Rams P8
#2 Rams P8
#3 Rams P8
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P2
HCR Kill P2
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
DIVERTER Test Report for:
Reviewed By:
P.I. Suprv
Comm ________MILNE PT UNIT M-62
JBR 05/12/2023
MISC. INSPECTIONS:
GAS DETECTORS:
DIVERTER SYSTEM:MUD SYSTEM:
P/F
P/F
P/F
Alarm
Visual Alarm
Visual Time/Pressure
Size
Number of Failures:6
Remarks:Vent line had 1 45degree bend @ 220'. H2S detector at driller panel failed and head was changed out (pass), LEL detector in cellar needed
calibrated, Calibrated and passed. Rig was in excellent condition and crew was busy with maintenance while I was on site. Kumi air pump not
operating, replace , second pump not operating correctly , getting a third pump. Operator did not know how long a third pump would take to
arrive. Head back to DH (operator sent recharge times at 1800 hrs of 39 sec. at 200 psi and 154 sec for full recovery . Third pump working
correctly.
TEST DATA
Rig Rep:J. CharleeOperator:Hilcorp Alaska, LLC Operator Rep:Bret Anderson
Contractor/Rig No.:Doyon 14 PTD#:2230060 DATE:4/12/2023
Well Class:DEV Inspection No:divSTS230411190122
Inspector Sully Sullivan
Inspector
Insp Source
Related Insp No:
Test Time:4
ACCUMULATOR SYSTEM:
Location Gen.:P
Housekeeping:P
Warning Sign P
24 hr Notice:P
Well Sign:P
Drlg. Rig.P
Misc:NA
Methane:FP FP
Hydrogen Sulfide:FP FP
Gas Detectors Misc:0 NA
Designed to Avoid Freeze-up?P
Remote Operated Diverter?P
No Threaded Connections?P
Vent line Below Diverter?P
Diverter Size:21.25 P
Hole Size:12.25 P
Vent Line(s) Size:16 P
Vent Line(s) Length:443 P
Closest Ignition Source:96 P
Outlet from Rig Substructure:435 P
Vent Line(s) Anchored:P
Turns Targeted / Long Radius:P
Divert Valve(s) Full Opening:P
Valve(s) Auto & Simultaneous:
Annular Closed Time:27 P
Knife Valve Open Time:11 P
Diverter Misc:0 NA
Systems Pressure:P3000
Pressure After Closure:P1900
200 psi Recharge Time:F0
Full Recharge Time:F0
Nitrogen Bottles (Number of):P6
Avg. Pressure:P1912
Accumulator Misc:NA0
P PTrip Tank:
P PMud Pits:
P PFlow Monitor:
0 NAMud System Misc:
9
999
9
9
9
9
9
FP FP
FP FP
F
F
H2S detector at driller panel failed LEL detector in cellar
Kumi air pump not
operating, replace
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 North Slope, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Re: Milne Point Field, Schrader Bluff Oil Pool, MPU M-62
Hilcorp North Slope, LLC
Permit to Drill Number: 223-006
Surface Location: 5038' FSL, 351' FEL, Sec. 14, T13N, R09E, UM, AK
Bottomhole Location: 1249' FSL, 321' FEL, Sec. 35, T14N, R09E, 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 February, 2023. 16
Brett W. Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.02.16 14:24:05 -09'00'
1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for:
Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates
Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas
2. Operator Name: 5. Bond: Blanket Single Well 11. Well Name and Number:
Bond No.
3. Address:6. Proposed Depth:12. Field/Pool(s):
MD: 20132' TVD: 4076'
4a. Location of Well (Governmental Section): 7. Property Designation:
Surface:
Top of Productive Horizon:8.DNR Approval Number: 13.Approximate Spud Date:
Total Depth: 9. Acres in Property: 14. Distance to Nearest Property:
4b. Location of Well (State Base Plane Coordinates - NAD 27):10.KB Elevation above MSL (ft): 58.8'15.Distance to Nearest Well Open
Surface: x-533814 y- 6027890 Zone- 4 25.1' to Same Pool: 398'
16.Deviated wells: Kickoff depth: 250 feet 17.Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 96 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
42" 20" 129.5# X-56 80' Surface Surface 114' 114'
47# L-80 TXP 2500' Surface Surface 2500' 1895'
40# L-80 TXP 6400' 2500' 1895' 8900' 4049'
Tieback 7" 26# L-80 TXP 8750' Surface Surface 8750' 4038'
8-1/2"5-1/2'x4-1/2"20#/13.5# L-80
JFE Bear /
Hyd 625 11382' 8750' 4038' 20132' 4076'
19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations)
Junk (measured):
TVD
Hydraulic Fracture planned? Yes No
20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis
Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements
Contact Name: Nathan Sperry
Monty Myers Contact Email:nathan.sperry@hilcorp.com
Drilling Manager Contact Phone:907-777-8450
Date:
Permit to Drill API Number: Permit Approval
Number:Date:
Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales:
Samples req'd: Yes No Mud log req'd: Yes No
H2S measures: Yes No Directional svy req'd: Yes No
Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No
Post initial injection MIT req'd: Yes No
APPROVED BY
Approved by: COMMISSIONER THE COMMISSION Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
February 28, 2023
3824'
12-1/4" 9-5/8"
21. I hereby certify that the foregoing is true and the procedure approved herein will not be
deviated from without prior written approval.
Surface
Perforation Depth TVD (ft):
GL / BF Elevation above MSL (ft):
Perforation Depth MD (ft):
Uncemented Tieback
Uncemented Screen Liner
Effect. Depth MD (ft): Effect. Depth TVD (ft):
Authorized Title:
Authorized Signature:
Production
Liner
Intermediate
Authorized Name:
Conductor/Structural
LengthCasing Cement Volume MDSize
Plugs (measured):
(including stage data)
~270 ft3
Stg 1 L - 936 sx / T - 395 sx
9563
18.Casing Program: Top - Setting Depth - BottomSpecifications
1808
Total Depth MD (ft): Total Depth TVD (ft):
22224484
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
Stg 2 L - 673 sx / T - 268 sx
1397
1827' FSL, 438' FEL, Sec. 12. T13N, R09E, UM, AK
1249' FSL, 321' FEL, Sec. 35, T14N, R09E, UM, AK
16-004
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
Hilcorp Alaska, LLC
5038' FSL, 351' FEL, Sec. 14, T13N, R09E, UM, AK ADL 025514, 388235 & 355018
MPU M-62
Milne Point Field
Schrader Bluff Oil Pool
Cement Quantity, c.f. or sacks
Commission Use Only
See cover letter for other
requirements.
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
1.26.2023
By Samantha Carlisle at 3:41 pm, Jan 26, 2023
Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp Alaska, LLC, ou=Technical
Services - AK Drilling,
email=mmyers@hilcorp.com
Reason: I am approving this document
Date: 2023.01.26 15:29:19 -09'00'
Monty M
Myers
MGR15FEB2023
50-029-23744-00-00
X
XX
* BOPE test to 3000 psi. Annular to 2500 psi.
* Casing test of 9-5/8" surface casing and FIT digital data to
AOGCC immediately upon performing FIT.
DLB 02/06/2023
X
22-006
X
1397
DSR-1/26/23
X
X
GCW 02/16/23JLC 2/16/2023
2/16/23
2/16/23Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr.
Date: 2023.02.16 14:24:32 -09'00'
RBDMS JSB 021723
Milne Point Unit
(MPU) M-62
Drilling Program
Version 1
1/26/2023
Table of Contents
1.0 Well Summary ........................................................................................................................... 2
2.0 Management of Change Information ........................................................................................ 3
3.0 Tubular Program:...................................................................................................................... 4
4.0 Drill Pipe Information: .............................................................................................................. 4
5.0 Internal Reporting Requirements ............................................................................................. 5
6.0 Planned Wellbore Schematic ..................................................................................................... 6
8.0 Drilling / Completion Summary ................................................................................................ 7
9.0 Mandatory Regulatory Compliance / Notifications .................................................................. 8
10.0 R/U and Preparatory Work ..................................................................................................... 10
11.0 N/U 13-5/8” 5M Diverter System ............................................................................................. 11
12.0 Drill 12-1/4” Hole Section ........................................................................................................ 13
13.0 Run 9-5/8” Surface Casing ...................................................................................................... 16
14.0 Cement 9-5/8” Surface Casing ................................................................................................. 22
15.0 ND Diverter, NU BOPE, & Test .............................................................................................. 27
16.0 Drill 8-1/2” Hole Section .......................................................................................................... 28
17.0 Run 5-1/2” x 4-1/2” Screened Liner ........................................................................................ 33
18.0 Run 7” Tieback ........................................................................................................................ 38
19.0 Run Upper Completion – Jet Pump ........................................................................................ 41
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 .................................................................................................. 49
26.0 Doyon 14 Rig Layout ............................................................................................................... 52
27.0 FIT Procedure .......................................................................................................................... 53
28.0 Doyon 14 Rig 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
Page 2
Milne Point Unit
M-62 SB Producer
PTD Application
1.0 Well Summary
Well MPU M-62
Pad Milne Point “M” Pad
Planned Completion Type Jet Pump
Target Reservoir(s) Schrader Bluff OA Sand
Planned Well TD, MD / TVD 20,132’ MD / 4,076’ TVD
PBTD, MD / TVD 20,132’ MD / 4,076’ TVD
Surface Location (Governmental) 242’ FNL, 351’ FEL, Sec. 14, T13N, R9E, UM, AK
Surface Location (NAD 27) X= 533813, Y=6029984
Top of Productive Horizon
(Governmental)1827’ FSL, 438’ FEL, Sec. 12, T13N, R9E, UM, AK
TPH Location (NAD 27) X= 538994, Y=6029984
BHL (Governmental) 1249' FSL, 321' FEL, Sec 35, T14N, R9E, UM, AK
BHL (NAD 27) X= 533780, Y=6039939
AFE Drilling Days 22
AFE Completion Days 4
Maximum Anticipated Pressure
(Surface) 1397 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 1808 psig
Work String 5” 19.5# S-135 NC 50
Doyon 14 KB Elevation above MSL: 33.7 ft + 25.1 ft = 58.8 ft
GL Elevation above MSL: 25.1 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
Page 3
Milne Point Unit
M-62 SB Producer
PTD Application
2.0 Management of Change Information
Page 4
Milne Point Unit
M-62 SB Producer
PTD Application
3.0 Tubular Program:
Hole
Section
OD (in)ID
(in)
Drift
(in)
Conn OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 20” 19.25”---X-52Weld
12-1/4”9-5/8” 8.835”8.679”10.625”40 L-80 TXP 5,750 3,090 916
9-5/8” 8.681”8.525”10.625”47 L-80 TXP 6,870 4,750 1,086
Tieback 7” 6.276” 6.151” 7.656” 26 L-80 TXP 7,240 5,410 604
8-1/2”
5-1/2”
Screens 4.780” 4.653” 6.000” 20.0 L-80
EZGO HT 9,190 8,830 466
4-1/2”
Screens 3.920” 3.795” 4.714” 13.5 L-80 Hydril 625 9,020 8,540 279
Tubing 4-1/2" 3.958”3.833”4.729”12.6 L-80 TXP 8,430 7,500 288
4.0 Drill Pipe Information:
Hole
Section
OD
(in)
ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn M/U
(Min)
M/U
(Max)
Tension
(k-lbs)
Surface &
Production
5”4.276”3.25” 6.625”19.5 S-135 DS50 36,100 43,100 560klb
5”4.276”3.25” 6.625”19.5 S-135 NC50 30,730 34,136 560klb
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
Page 5
Milne Point Unit
M-62 SB Producer
PTD Application
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 nathan.sperry@hilcorp.com and
joseph.lastufka@hilcorp.com
5.7 Hilcorp Milne Point Contact List:
Title Name Work Phone Cell Phone Email
Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmyers@hilcorp.com
Drilling Engineer Nate Sperry 907.777.8450 907.301.8996 nathan.sperry@hilcorp.com
Drilling Engineer Joe Engel 907.777.8395 805.235.6265 jengel@hilcorp.com
Completion Engineer Todd Sidoti 907.777.8443 907.632.4113 Todd.Sidoti@hilcorp.com
Geologist Katie Cunha 907.564.4786 907.802.0078 Katharine.cunha@hilcorp.com
Reservoir Engineer Reid Edwards 907.777.8421 907.250.5081 reedwards@hilcorp.com
Drilling Env. Coordinator Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com
EHS Director Laura Green 907.777.8314 907.342.7511 lagreen@hilcorp.com
Drilling Tech Joe Lastufka 907.777.8400 907.227.8496 Joseph.Lastufka@hilcorp.com
Page 6
Milne Point Unit
M-62 SB Producer
PTD Application
6.0 Planned Wellbore Schematic
7.0
Page 7
Milne Point Unit
M-62 SB Producer
PTD Application
8.0 Drilling / Completion Summary
MPU M-62 is a grassroots producer planned to be drilled in the Schrader Bluff OA sand. M-62 is part of a
multi-well program targeting the Schrader Bluff sand on M-pad
The directional plan is 12-1/4” surface hole with 9-5/8” surface casing set in the top of the Schrader Bluff
OA sand. An 8-1/2” lateral section will be drilled and completed with a 4-1/2” liner. The well will be
produced with a jet pump.
Doyon 14 will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately February 28th, 2023, pending rig schedule.
Surface casing will be run to 8,900’ MD / 4,049’ TVD and cemented to surface via a 2 stage primary cement
job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed,
necessary remedial action will then be discussed with AOGCC authorities.
All cuttings & mud generated during drilling operations will be hauled to 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 wellhead, NU 13-5/8” 5M BOP & Test
5. Drill 8-1/2” lateral to well TD
6. Run 4-1/2” production liner
7. Run 7” tieback
8. Run Upper Completion
9. N/D BOP, N/U Tree, RDMO
Reservoir Evaluation Plan:
1. Surface hole: No mud logging. 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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9.0 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 M-62. Ensure
to provide AOGCC 24 hrs notice prior to testing BOPs.
x The initial test of BOP equipment will be to 250/3,000 psi & subsequent tests of the BOP equipment
will be to 250/3,000 psi for 5/5 min (annular to 50% rated WP, 2,500 psi on the high test for initial
and subsequent tests).Confirm that these test pressures match those specified on the APD.
x If the BOP is used to shut in on the well in a well control situation or control fluid flow from the
well bore, AOGCC is to be notified and we must test all BOP components utilized for well control
prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP
test.
x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid
program and drilling fluid system”.
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”.
o Ensure the diverter vent line is at least 75’ away from potential ignition sources
x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
x Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test
must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a
minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test
pressure must show stabilizing pressure and may not decline more than 10 percent within 30
minutes. The results of this test and any subsequent tests of the casing must be recorded as required
by 20 AAC 25.070(1)”.
AOGCC Regulation Variance Requests:
x None
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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 (BOPs utilized to shut in the well to control influx of formation fluids).
x 24 hours notice prior to spud.
x 24 hours notice prior to testing BOPs.
x 24 hours notice prior to casing running & cement operations.
x Any other notifications required in APD.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov
Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov
Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov
Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
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10.0 R/U and Preparatory Work
9.1 M-62 will utilize a newly set 20” conductor on M-pad. Ensure to review attached surface plat
and make sure rig is over appropriate conductor.
9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor.
9.3 Install landing ring.
9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each.
9.5 Level pad and ensure enough room for layout of rig footprint and R/U.
9.6 Rig mat footprint of rig.
9.7 MIRU 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).
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11.0 N/U 13-5/8” 5M 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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12.0 Drill 12-1/4” Hole Section
11.1 P/U 12-1/4” directional drilling assembly:
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x GWD will be the primary gyro tool. Take gyro surveys until MWD cleans up.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
x Drill string will be 5” 19.5# S-135.
x Run a solid float in the surface hole section.
11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor.
x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in
conductor.
11.3 Drill 12-1/4” hole section to section TD in the Schrader OA sand. Confirm this setting depth
with the Geologist and Drilling Engineer while drilling the well.
x Monitor the area around the conductor for any signs of broaching. If broaching is observed,
stop drilling (or circulating) immediately notify Drilling Engineer.
x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100.
x Hold a safety meeting with rig crews to discuss:
x Conductor broaching ops and mitigation procedures.
x Well control procedures and rig evacuation
x Flow rates, hole cleaning, mud cooling, etc.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Keep mud as cool as possible to keep from washing out permafrost.
x Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can
handle the flow rate.
x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoffs, increase in pump pressure or changes in hookload are seen
x Slow in/out of slips and while tripping to keep swab and surge pressures low
x Ensure shakers are functioning properly. Check for holes in screens on connections.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea
gravel, clay balling or packing off.
x Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2
minimum at TD (pending MW increase due to hydrates).
x Perform gyros until clean MWD surveys are seen. Take MWD surveys every stand drilled.
x Be prepared for gas hydrates. In MPU they have been encountered typically around 2,100-
2,400’ TVD (just below permafrost). Be prepared for hydrates:
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
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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 Surface Hole AC:
x There are no wells with a clearance factor of <1.0
11.4 12-1/4” hole mud program summary:
x Density: Weighting material to be used for the hole section will be barite. Additional
barite or spike fluid will be on location to weight up the active system (1) ppg above
highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and
TD with 9.2+ ppg.
Depth Interval MW (ppg)
Surface –Base Permafrost 8.9+
Base Permafrost - TD 9.2+ (For Hydrates if need based on offset wells)
MW can be cut once ~500’ below hydrate zone
x PVT System: PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, Toolpusher
office, and mud loggers office.
x Rheology: M-I gel should be used to maintain rheology. Begin system with a 75 YP but
reduce this once clays are encountered. Maintain a minimum 25 YP at all times while
drilling. Be prepared to increase the YP if hole cleaning becomes an issue.
x Fluid Loss: DEXTRID and/or PAC UL should be used for filtrate control. Background
LCM (10 ppb total) nut plug fine & medium, M-I-X II fine & medium can be used in the
system while drilling the surface interval to prevent losses and strengthen the wellbore.
x Wellbore and mud stability:Additions of SCREENKLEEN are recommended to reduce
the incidence of bit balling and shaker blinding when penetrating the high-clay content
sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the
pH in the 8.5 – 9.0 range with caustic soda. Daily additions of ALDACIDE G / X-CIDE
207 MUST be made to control bacterial action.
x Casing Running:Reduce system YP with TANNATHIN / CF DESCO II as required for
running casing as allowed (do not jeopardize hole conditions). Run casing carefully to
minimize surge and swab pressures. Reduce the system rheology once the casing is
landed to a YP < 20 (check with the cementers to see what YP value they have targeted).
System Type:8.8 – 9.2 ppg Pre-Hydrated M-I gel / freshwater spud mud
Minimum EMW needed = 8.46 ppg. DLB
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Properties:
Section Density Viscosity
Plastic
Viscosity Yield Point API FL pH
Temp
Surface 8.8 –
9.8
75-175 20 - 40 25-45 <10 8.5 –
9.0
70 F
System Formulation: Gel + FW spud mud
Product Concentration
Fresh Water
soda Ash
M-I GEL
caustic soda
SCREENKLEEN
MI WATE
PAC-UL /DEXTRID LT
ALDACIDE G
0.967 bbl
0.125 ppb
35 ppb
0.1 ppb (8.5 – 9.0 pH)
as needed
as required for 8.8 – 9.2 ppg
if required for <10 FL
0.1 ppb
11.5 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem
sweeps and drop viscosity.
11.6 RIH to bottom, proceed to BROOH to HWDP
x Pump at full drill rate (400-600 gpm), and maximize rotation.
x Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions
x Monitor well for any signs of packing off or losses.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay
balling.
x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until
parameters are restored.
11.7 TOOH and LD BHA
11.8 No open hole logging program planned.
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13.0 Run 9-5/8” Surface Casing
12.1 R/U and pull wearbushing.
12.2 R/U 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 8.5” 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.
12.3 P/U shoe joint, visually verify no debris inside joint.
12.4 Continue M/U & thread locking 120’ shoe track assembly consisting of:
9-5/8” Float Shoe
1 joint – 9-5/8” 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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12.5 Float equipment and Stage tool equipment drawings:
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12.6 Continue running 9-5/8” surface casing
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
x 1 centralizer every joint to ~ 1000’ MD from shoe
x 1 centralizer every 2 joints to ~2,000’ above shoe (Top of Lowest Ugnu)
x Verify depth of lowest Ugnu water sand for isolation with Geologist
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
x Any packing off while running casing should be treated as a major problem. It is preferable
to POH with casing and condition hole than to risk not getting cement returns to surface.
12.7 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below
the permafrost.
x Install centralizers over couplings on 5 joints below and 5 joints above stage tool.
x Do not place tongs on ES cementer, this can cause damaged to the tool.
x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi.
9-5/8” 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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12.8 Continue running 9-5/8” surface casing
x Centralizers: 1 centralizer every 3rd joint to 200’ from surface
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
o 1 centralizer every 2 joints to base of conductor
12.9 Ensure the permafrost is covered with 9-5/8” 47# from BPRF to Surface
x Ensure drifted to 8.525”
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12.10 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.11 Slow in and out of slips.
12.12 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the
landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference
when getting the casing on depth.
12.13 Lower casing to setting depth. Confirm measurements.
12.14 Have slips staged in cellar, along with necessary equipment for the operation.
12.15 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement
job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible
reciprocate casing string while conditioning mud.
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14.0 Cement 9-5/8” Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
x Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks.
x Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
x Review test reports and ensure pump times are acceptable.
x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
13.2 Document efficiency of all possible displacement pumps prior to cement job.
13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
13.5 Fill surface cement lines with water and pressure test.
13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below
calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached.
13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead &
tail, TOC brought to stage tool.
Estimated 1st Stage Total Cement Volume:
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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.
x Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
13.11 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 step 13.8 above.
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.
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 3,300 psi to open circulating ports in stage collar. Slightly higher pressure
may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns
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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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 2
nd stage as necessary. Circulate until first stage reaches sufficient compressive
strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre-job safety
meeting.
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.
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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13.26 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.
13.27 Decide ahead of time what will be done with cement returns once they are at surface. We should
circulate approximately 100 - 150 bbls of cement slurry to surface.
13.28 Land closing plug on stage collar and pressure up to 1,000 – 1,500 psi to ensure stage tool closes.
Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool
has closed. Slips will be set as per plan to allow full annulus for returns during surface cement
job. Set slips.
13.29 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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15.0 ND Diverter, NU BOPE, & Test
14.1 ND the diverter T, knife gate, diverter line & NU 11” x 13-5/8” 5M casing spool.
14.2 NU 13-5/8” x 5M BOP as follows:
x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13-
5/8” x 5M mud cross / 13-5/8” x 5M single gate
x Double gate ram should be dressed with 4-1/2” x 7” VBRs in top cavity,blind ram in
bottom cavity.
x Single ram can be dressed with 2-7/8” x 5” VBRs
x NU bell nipple, install flowline.
x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to
mud cross).
x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual
valve
14.3 RU MPD RCD and related equipment
14.4 Run 5” BOP test plug
14.5 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min.
x Test 4-1/2” x 7” rams with 4-1/2” and 7” test joints
x Test 2-7/8” x 5” rams with the 4-1/2” 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
14.6 RD BOP test equipment
14.7 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.8 Mix 8.9 ppg FLOPRO NT fluid for production hole.
14.9 Set wearbushing in wellhead.
14.10 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole
section.
14.11 Ensure 5” liners in mud pumps.
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16.0 Drill 8-1/2” Hole Section
15.1 MU 8-1/2” Cleanout BHA (Milltooth Bit & 1.22° PDM)
15.2 TIH w/ 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out
stage tool.
15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report.
15.4 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and
plot on FIT graph. AOGCC reg is 50% of burst = 5,750 / 2 = ~2,875 psi, but max test pressure
on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent
pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry
Guidance Bulletin 17-001.
15.5 Drill out shoe track and 20’ of new formation.
15.6 CBU and condition mud for FIT.
15.7 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test.
Document incremental volume pumped (and subsequent pressure) and volume returned.
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 and LD cleanout BHA
15.9 PU 8-1/2” directional BHA.
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before MU. Visually verify no debris inside components that
cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Ensure MWD is RU and operational.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
x Drill string will be 5” 19.5# S-135 NC50.
x 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 FIT digital data to AOGCC upon completion of FIT. email: melvin.rixse@alaska.gov
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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 a minimum. 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
System Formulation:
Product- production ppb or (% liquids)
Water 0.916 bbls/bbl
Soda Ash 0.17 ppb
FLO-VIS PLUS 0.5 –0.75 ppb
FLO-TROL 6.0 ppb
Potassium Chloride (KCl)10.7 ppb
SCREENKLEEN 0.5% v/v
SAFE-CARB 20 10 ppb
SAFE-CARB 40 10 ppb
SALT As needed
Onyxide 200 2.1 gals/100 bbls
Sodium Metabisulfite 0.25 ppb
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15.11 TIH with 8-1/2” directional assembly to bottom
15.12 Install MPD RCD
15.13 Displace wellbore to 8.9 ppg FloPro drilling fluid
15.14 Begin drilling 8-1/2” hole section, on-bottom staging technique:
x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K.
x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations
x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU
off bottom and restart on bottom staging technique. If stick slip continues, consider adding
0.5% lubes
15.14 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer.
x Flow Rate: 350-550 GPM, target min. AV’s 200 ft/min, 385 GPM
x RPM: 120+
x Include GWD in the BHA
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 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 Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible and avoid stopping with the
BHA across the sand for any extended period of time.
x Use ADR to stay in section. Reservoir plan is to stay in OA sand.
x Limit maximum instantaneous ROP to < 250 FPH. The sands will drill faster than this, but
when concretions are hit when drilling this fast, cutter damage can occur.
x Target ROP is as fast as we can clean the hole without having to backream connections
x Schrader Bluff OA Concretions: 4-6% Historically
x MPD will be utilized to monitor pressure build up on connections.
x 8-1/2” Lateral A/C:
x There are no wells with a clearance factor <1.0.
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.
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x Attempt to lowside in a fast drilling interval where the wellbore is headed up.
x Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working
string back and forth. Trough for approximately 30 minutes.
x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the
openhole sidetrack is achieved.
15.16 At TD, CBU at least 4 times at 200 ft/min AV (385+ GPM) and rotation (120+ RPM). Pump
tandem sweeps if needed
x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent
stream, circulate more if necessary
x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum
15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP
pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter
cake and calcium carbonate. Circulate the well clean.
Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being
removed, including an increase in the loss rate.
15.18 Displace 1.5 OH + Liner volume with viscosified brine.
x Proposed brine blend (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.
15.15 Monitor the returned fluids carefully while displacing to brine. After 1 (or more if needed) BU,
Perform production screen test (PST). The brine has been properly conditioned when it will pass
the production screen test (x3 350 ml samples passing through the screen in the same amount
of time which will indicate no plugging of the screen). Reference PST Test Procedure
15.19 BROOH with the drilling assembly to the 9-5/8” casing shoe
x Circulate at full drill rate (less if losses are seen, 350 GPM minimum).
x Rotate at maximum RPM that can be sustained.
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x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as
dictated by hole conditions
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 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while
BROOH.
15.21 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps.
15.22 Monitor well for flow/pressure build up with MPD. Increase fluid weight if necessary.
x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to
determine if well is breathing, treat all flow as an influx until proven otherwise
x If necessary, increase MW at shoe for any higher than expected pressure seen
x Ensure fluid coming out of hole has passed a PST at the possum belly
15.23 POOH and LD BHA.
15.24 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit
diameter is sufficient for future ball drops.
Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any
additional logging runs conducted.
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17.0 Run 5-1/2” x 4-1/2” Screened Liner
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
screened liner, the following well control response procedure will be followed:
x P/U & M/U the 5” safety joint (with 5-1/2” crossover installed on bottom, TIW valve in open
position on top, 5-1/2” handling joint above TIW). This joint shall be fully M/U and
available prior to running the first joint of 5-1/2” screened liner.
x 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” screened liner.
x Slack off and with 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW.
x Proceed with well kill operations.
16.2 R/U liner running equipment.
x Ensure 5-1/2” 20# EZGO-HT x NC50 and 4-1/2” 13.5# Hydril 625 x NC50 crossovers are on
rig floor and M/U to FOSV.
x Ensure all casing has been drifted on the deck prior to running.
x Be sure to count the total # of joints on the deck before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
16.3 Run screened production liner
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 Fill liner with PST passed mud (to keep from plugging screens with solids)
x Install screen joints as per the Running Order (From Operations Engineer post TD).
o Do not place tongs or slips on screen joints
o Screen placement ±40’
x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint
outside of the surface shoe. This is to mitigate difference 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” 20# L-80 EZGO HT MU Torque
OD Minimum Maximum
5-1/2 6,997 ft-lbs 10,728 ft-lbs
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4-1/2” 13.5# L-80 Hydril 625 Torque
OD Minimum Optimum Maximum
4-1/2 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs
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16.6. Ensure to run enough liner to provide for approx 150’ overlap inside 9-5/8” casing. Ensure
hanger/pkr will not be set in a 9-5/8” connection.
x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as
per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8” connection.
16.7. 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 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.
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16.18. Shut down pumps. Drop setting ball (ball seat now located in HRDE setting tool) down the
workstring and pump slowly (1-2 BPM). Slow pump before the ball seats. Do not allow ball to
slam into ball seat.
16.19. 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.
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18.0 Run 7” Tieback
17.1 RU and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder
to be used for tie-back space out calculation. Install 7” solid body casing rams in the upper ram
cavity. RU testing equipment. PT to 250/3,000 psi with 7” test joint. RD testing equipment.
17.2 RU 7” casing handling equipment.
x Ensure XO to DP made up to FOSV and ready on rig floor.
x Rig up computer torque monitoring service.
x String should stay full while running, RU fill up line and check as appropriate.
17.3 PU 7” tieback seal assembly and set in rotary table. Ensure 7” seal assembly has (4) 1” holes
above the first seal. These holes will be used to spot diesel freeze protect in the 9-5/8” x 7”
annulus.
17.4 MU first joint of 7” to seal assy.
17.6 Run 7”, 26#, L-80 TXP tieback tieback to position seal assembly two joints above tieback sleeve.
Record PU and SO weights.
7”, 26#, L-80, TXP
=Casing OD Torque (Min) Torque (Opt)Torque (Max)Torque (Operating)
7”13,280 ft-lbs 14,750 ft-lbs 16,230 ft-lbs 20,000 ft-lbs
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17.7 MU 7” to DP crossover.
17.8 MU stand of DP to string, and MU top drive.
17.9 Break circulation at 1 BPM and begin lowering string.
17.10 Note seal assembly entering tieback sleeve with a pressure increase, stop pumping and bleed off
pressure. Leave standpipe bleed off valve open.
17.11 Continue lowering string and land out on no-go. Set down 5 – 10K and mark the pipe as “NO-
GO DEPTH”.
17.12 PU string & remove unnecessary 7” joints.
17.13 Space out with pups as needed to leave the no-go 1 ft above fully no-go position when the casing
hanger is landed. Ensure one full joint is below the casing hanger.
17.14 PU and MU the 7” casing hanger.
17.15 Ensure circulation is possible through 7” string.
17.16 RU and circulation corrosion inhibited brine in the 9-5/8” x 7” annulus.
17.17 With seals stabbed into tieback sleeve, spot diesel freeze protection from 2,500’ TVD to surface
in 9-5/8” x 7” annulus by reverse circulating through the holes in the seal assembly. Ensure
annular pressure are limited to prevent collapse of the 7” casing (verify collapse pressure of 7”
tieback seal assembly).
17.18 SO and land hanger. Confirm hanger has seated properly in wellhead. Make note of actual
weight on hanger on morning report.
17.19 Back out the landing joint. MU packoff running tool and install packoff on bottom of landing
joint. Set casing hanger packoff and RILDS. PT void to 3,000 psi for 10 minutes.
17.20 RD casing running tools.
17.21 PT 9-5/8” x 7” annulus to 1,500 psi for 30 minutes charted.
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19.0 Run Upper Completion – Jet Pump
18.1 RU to run 4-1/2”, 12.6#, L-80 TXP tubing.
x Ensure wear bushing is pulled.
x Ensure 4-1/2”, L-80, 12.6#, TXP x XT-39 crossover is on rig floor and M/U to FOSV.
x Ensure all tubing has been drifted in the pipe shed prior to running.
x Be sure to count the total # of joints in the pipe shed before running.
x Keep hole covered while RU casing tools.
x Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info.
x Monitor displacement from wellbore while RIH.
18.2 PU, MU and RH with the following 4-1/2” JP completion (confirm tally with Operations
Engineer):
x WLEG/Mule shoe
x Joints, 4-1/2”, 12.6#, L-80, TXP
x Handling Pup, 4-1/2” TXPM Box x 4-1/2” TXP Pin
x Nipple, 3.813” XN profile (3.750” no-go), 4-1/2”, TXPM (RHC plug body installed,Set
Below 70 degrees)
x Handling Pup, 4-1/2”, TXP Box x 4-1/2”, TXP Pin
x 1 joint, 4-1/2”, 12.6#, L-80, TXP
x Crossover Pup, 4-1/2” TC-II Box x 4-1/2” TXP Pin
x Retrievable Packer, Baker, 4-1/2”, 12.6#, L-80, TC-II (NOTE: Set Below 70 degrees)
x Crossover Pup, 4-1/2”, TXP Box x 4-1/2”, TC-II Pin
x 1 joint, 4-1/2”, 12.6#, L-80, TXP
x Handling Pup, 4-1/2” TXPM Box x 4-1/2” TXP Pin
x Nipple, 3.813” X profile 4-1/2”, TXPM
x Handling Pup, 4-1/2”, TXP Box x 4-1/2”, TXP Pin
x 1 joint, 4-1/2”, 12.6#, L-80, TXP
x Crossover, 4-1/2”, EUE 8rd Box x 4-1/2”, TXP Pin
x Gauge Carrier, 4-1/2”, 12.6#, L-80, EUE 8rd
x Crossover, 4-1/2”, TXP Box x 4-1/2”, EUE 8rd Pin
x 1 joint, 4-1/2”, 12.6#, L-80, TXP
x Pup joint, 4-1/2”, 12.6#, L-80, TXP
x Sliding Sleeve, 4-1/2”, 12.6#, L-80 TXP
x Pup joint, 4-1/2”, 12.6#, L-80, TXP
x XXX joints, 4-1/2”, 12.6#, L-80, TXP
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18.3 PU and MU the 4-1/2” tubing hanger. Make final splice of the TEC wire and ensure any unused
control line ports are dummied off.
18.4 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with
band/clamp summary.
18.5 Land the tubing hanger and RILDS. Lay down the landing joint.
18.6 Install 4” HP BPV. ND BOP. Install the plug off tool.
18.7 NU the tubing head adapter and NU the tree.
18.8 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi.
18.9 Pull the plug off tool and BPV.
18.10 Reverse circulate the well over to corrosion inhibited source water follow by diesel freeze protect
to 2,500’ MD.
18.11 Drop the ball & rod.
18.12 Pressure up on the tubing to 3,500 psi to set the packer. PT the tubing to 3,500 psi for 30
minutes.
18.13 Bleed the tubing pressure to 2,000 psi and PT the IA to 3,650 psi for 30 minutes (charted). Bleed
both the IA and tubing to 0 psi.
18.14 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over
with valve alignment as per operations personnel.
18.15 RDMO
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20.0 Doyon 14 Diverter Schematic
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21.0 Doyon 14 BOP Schematic
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22.0 Wellhead Schematic
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23.0 Days Vs Depth
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24.0 Formation Tops & Information
TOP
NAME
TVDSS
(FT)
TVD
(FT)
MD
(FT)
Formation
Pressure
(psi)
EMW
(ppg)
Base
Permafrost 1886.8 1828 2474.8 804 8.46
SV1 1923.8 1865 2582.4 820 8.46
UG4 2182.8 2124 3335.8 934 8.46
UG_MB 3619.8 3561 7229.9 1,566 8.46
SB NB 3885.8 3827 7936.6 1,684 8.46
SB OA 4046.8 3988 8857.7 1,754 8.46
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L-Pad Data Sheet Formation Description (Closest & Most Analogous MPU Pad to Moose Pad)
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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 hydrates are generally not seen on M-pad. Remember that hydrate gas behaves differently from a
gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the
breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill
through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation
time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing
which can increase the amount of hydrates released into the wellbore. Keep the mud circulation
temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale.
The non-pressurized scale will reflect the actual mud cut weight. Isolate/dump contaminated fluid to
remove hydrates from the system.
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize
solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor
ECD’s to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPM’s when CBU, and keep pipe
moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after
slide intervals. Do not out drill our ability to clean the hole.
Anti-Collison:
There are no known wells with a clearance factory <1.0. Take directional surveys every stand, take
additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any
close approaches on AM report.
Well Specific A/C:
x There are no wells with a clearance factor of <1.0
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.
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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.
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8-1/2” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor
ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe
moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation
after slide intervals. Do not out drill our ability to clean the hole. Maint. 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 are three (possibly four) planned fault crossings for M-62. The maximum expected throw for a
fault is 50’ on the fault crossed mid-lateral.
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. Utilize MPD to mitigate any abnormal pressure seen.
Anti-Collision
Take directional surveys every stand, take additional surveys if necessary. Continuously monitor
drilling parameters for signs of magnetic interference with another well. Reference A/C report in
directional plan.
Well Specific AC:
x There are no wells with a clearance factor less than 1.0.
DLB
No H2S events have been documentedy
on drill wells on this pad.
Page 52
Milne Point Unit
M-62 SB Producer
PTD Application
26.0 Doyon 14 Rig Layout
Page 53
Milne Point Unit
M-62 SB Producer
PTD Application
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 54
Milne Point Unit
M-62 SB Producer
PTD Application
28.0 Doyon 14 Rig Choke Manifold Schematic
Page 55
Milne Point Unit
M-62 SB Producer
PTD Application
29.0 Casing Design
Page 56
Milne Point Unit
M-62 SB Producer
PTD Application
30.0 8-1/2” Hole Section MASP
DLB
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L-03
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L-33
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F-80
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F-84A
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F-81
F-83
F-82
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F-86
F-87
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F-99
PESADO 1
PESADO 1A
F-96
L-08
L-13
F-02
F-58
F-53PB1
F-84APB1
F-82PB1
F-99PB1
F-21PB1
F-110
M-04 M-12PB1
M-06
M-24PB1
F-05L1
F-05L1-01
F-05L1PB1
KUPARUK
RIVER UNIT
MILNE
POINT UNIT
ADL025515
ADL025514
ADL025509
ADL388235
ADL355023
ADL355018
Sec. 35
Sec. 1
Sec. 36
Sec. 11
Sec. 13
Sec. 2
Sec. 14
Sec. 12
Sec. 6
(625)
Sec. 31
(622)
Sec. 7
(628)
Sec. 18
(630)
U013N009E
U013N010E
U014N010EU014N009E
MPU F
MPU
MOOSE PAD
MPU M-62_SHL
MPU M-62_TPH
MPU M-62_BHL
Map Date: 1/26/2023
Milne Point Unit
MPU M-62 Well
wp06
E0 1,000 2,000
Feet
Legend
$)MPU M-62_BHL
!MPU M-62_SHL
D MPU M-62_TPH
!Other Surface Holes (SHL)
$)Other Bottom Holes (BHL)
Other Well Paths
Coastline (USGS 1:63k)
Oil and Gas Unit Boundary
Pad Footprint
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Page 58
Milne Point Unit
M-62 SB Producer
PTD Application
32.0 Surface Plat (As Built) (NAD 27)
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-2250 -1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250
West(-)/East(+) (1500 usft/in)
M-62 wp02 Oa1 tgt1
MPU M-62 wp06 tgt24 OA1
MPU M-62 wp06 tgt23 Oa1
MPU M-62 wp06 tgt22 OA3
MPU M-62 wp06 tgt21 OA3
MPU M-62 wp06 tgt20 OA1
MPU M-62 wp06 tgt19 OA3
MPU M-62 wp06 tgt18 OA1
MPU M-62 wp06 tgt17 Oa1
MPU M-62 wp06 tgt16 OA3
MPU M-62 wp06 tgt15 OA3
MPU M-62 wp06 tgt14 OA3
MPU M-62 wp06 tgt13 OA1
MPU M-62 wp06 tgt12 Oa1
MPU M-62 wp06 tgt11 OA3
MPU M-62 wp06 tgt10 OA3
MPU M-62 wp06 tgt09 OA1
MPU M-62 wp06 tgt01 Oa1
MPU M-62 wp06 tgt08 Oa1
MPU M-62 wp06 tgt07 Oa3
MPU M-62 wp06 tgt06 Oa3
MPU M-62 wp06 tgt05 Oa1
MPU M-62 wp06 tgt04 Oa1
MPU M-62 wp06 tgt03 Oa3
MPU M-62 wp06 tgt02 Oa3
9 5/8" x 12 1/4"
4 1/2" x 8 1/2"
1000
1500
175
0
2000
2250
2500
2750
3000
3
2
5
0
3
5
0
0
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M P U M -6 2 w p 0 6
Start Dir 3º/100' : 250' MD, 250'TVD
Start Dir 3.71º/100' : 700' MD, 695.85'TVD
Start Dir 4º/100' : 1100' MD, 1072.18'TVD
End Dir : 2202.83' MD, 1793.33' TVD
Start Dir 4.4º/100' : 5956.88' MD, 3083.82'TVD
End Dir : 8653.26' MD, 4029.63' TVD
Begin Geosteering Lateral
Total Depth : 20132.12' MD, 4075.8' TVD
CASING DETAILS
TVD TVDSS MD Size Name
4049.19 3990.39 8900.00 9-5/8 9 5/8" x 12 1/4"
4075.80 4017.00 20132.11 4-1/2 4 1/2" x 8 1/2"
Project: Milne Point
Site: M Pt Moose Pad
Well: Plan: MPU M-62
Wellbore: MPU M-62
Plan: MPU M-62 wp06
WELL DETAILS: Plan: MPU M-62
25.10
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 6027889.700 533813.820 70° 29' 14.0038 N 149° 43' 25.0461 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: MPU M-62, True North
Vertical (TVD) Reference:MPU M-62 as built rkb @ 58.80usft
Measured Depth Reference:MPU M-62 as built rkb @ 58.80usft
Calculation Method:Minimum Curvature
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Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME:______________________________________
PTD:_____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD:__________________________POOL:____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in 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.
X
X
Milne Point Unit
223-006
MPU M-62
X
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s
e
n
s
o
r
s
a
n
d
a
l
a
r
m
s
.
35
P
e
r
m
i
t
c
a
n
b
e
i
s
s
u
e
d
w
/
o
h
y
d
r
o
g
e
n
s
u
l
f
i
d
e
m
e
a
s
u
r
e
s
Ye
s
36
D
a
t
a
p
r
e
s
e
n
t
e
d
o
n
p
o
t
e
n
t
i
a
l
o
v
e
r
p
r
e
s
s
u
r
e
z
o
n
e
s
NA
37
S
e
i
s
m
i
c
a
n
a
l
y
s
i
s
o
f
s
h
a
l
l
o
w
g
a
s
z
o
n
e
s
NA
38
S
e
a
b
e
d
c
o
n
d
i
t
i
o
n
s
u
r
v
e
y
(
i
f
o
f
f
-
s
h
o
r
e
)
NA
39
C
o
n
t
a
c
t
n
a
m
e
/
p
h
o
n
e
f
o
r
w
e
e
k
l
y
p
r
o
g
r
e
s
s
r
e
p
o
r
t
s
[
e
x
p
l
o
r
a
t
o
r
y
o
n
l
y
]
Ap
p
r
DL
B
Da
t
e
2/
6
/
2
0
2
3
Ap
p
r
MG
R
Da
t
e
2/
1
4
/
2
0
2
3
Ap
p
r
DL
B
Da
t
e
2/
6
/
2
0
2
3
Ad
m
i
n
i
s
t
r
a
t
i
o
n
En
g
i
n
e
e
r
i
n
g
Ge
o
l
o
g
y
Ge
o
l
o
g
i
c
Co
m
m
i
s
s
i
o
n
e
r
:
Da
t
e
:
En
g
i
n
e
e
r
i
n
g
Co
m
m
i
s
s
i
o
n
e
r
:
Da
t
e
Pu
b
l
i
c
Co
m
m
i
s
s
i
o
n
e
r
Da
t
e
JL
C
2
/
1
6
/
2
0
2
3
Gr
e
g
o
r
y
W
i
l
s
o
n
Di
g
i
t
a
l
l
y
s
i
g
n
e
d
b
y
G
r
e
g
o
r
y
Wi
l
s
o
n
Da
t
e
:
2
0
2
3
.
0
2
.
1
6
0
9
:
3
4
:
5
4
-
0
9
'
0
0
'
