Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE:Tuesday, March 18, 2025
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Bob Noble
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
Hilcorp Alaska, LLC
J-47
MILNE PT UNIT J-47
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 03/18/2025
J-47
50-029-23801-00-00
224-120-0
W
SPT
3956
2241200 2000
129 128 129 128
INITAL P
Bob Noble
2/3/2025
MIT-IA to 2000 psi per PTD, following stabilized injection. Monobore completion.
30 MinPretestInitial15 Min
Well Name
Type Test
Notes:
Interval P/F
Well
Permit Number:
Type Inj TVD
PTD Test psi
API Well Number Inspector Name:MILNE PT UNIT J-47
Inspection Date:
Tubing
OA
Packer Depth
152 2171 2086 2062IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitRCN250203160109
BBL Pumped:3 BBL Returned:3
Tuesday, March 18, 2025 Page 1 of 1
9
9
9
9 9
9
9
999
9 9
9
9
9
MIT-IA to 2000 psi per PTD,
James B. Regg Digitally signed by James B. Regg
Date: 2025.03.18 09:47:37 -08'00'
10/21/2024
11/4/2024
By James Brooks at 1:01 pm, Jan 02, 2025
Complete
11/11/2024
JSB
RBDMS JSB 010925
G
DSR-4/7/25SFD 3/24/2025MGR03OCT2025
Digitally signed by Sean
McLaughlin (4311)
DN: cn=Sean McLaughlin (4311)
Date: 2025.01.02 10:56:18 -
09'00'
Sean
McLaughlin
(4311)
Digitally signed by Scott
Pessetto (9864)
DN: cn=Scott Pessetto (9864)
Date: 2025.01.02 12:07:33 -
09'00'
Scott Pessetto
(9864)
_____________________________________________________________________________________
Revised By: JNL 11/20/2024
SCHEMATIC
Milne Point Unit
Well: MPU J-47
Last Completed: 11/11/2024
PTD: 224-120
5-1/2” x 4-1/2”SCREENED LINER DETAIL
Size Top
(MD)
Top
(TVD)
Btm
(MD)
Btm
(TVD)
5-1/2” 4869’ 3983’ 5885’ 4020’
4-1/2” 6008’ 4020’ 15818’ 4299’
CASING DETAIL
Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF
20" Conductor 129.5 / X-52 / Weld N/A Surface 170’ N/A
9-5/8" Surface 47 / L-80 / TXP 8.525” Surface 2,116’ 0.0732
9-5/8" Surface 40 / L-80 / TXP 8.679” 2,116’ 4,856’ 0.0758
5-1/2” Liner 250ђ Screens 17 / L-80 / JFE Bear 4.892” 4,666’ 5,928’ 0.0232
4-1/2” Liner 150ђ Screens 13.5 / L-80 / Hyd 625 3.920” 5,928’ 15,933’ 0.0149
TUBING DETAIL
3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.992” Surface 4,675’ 0.0087
OPEN HOLE / CEMENT DETAIL
24” x Driven 10 yds Concrete
12-1/4"Stg 1 –Lead 303 sx / Tail 400 sx
Stg 2 –Lead 680 sx / Tail 270 sx
8-1/2” Uncemented Screen Liner
TREE & WELLHEAD
Tree Cameron 3 1/8" 5M w/ 3-1/8” 5M Cameron Wing
Wellhead FMC 11” x 4-1/2” Tubing Hanger, 4-1/2” TCII
GENERAL WELL INFO
API#: 50-029-23801-00-00
Completion Date: 11/11/2024
WELL INCLINATION DETAIL
KOP @ 1151’
90° Hole Angle = 5,633’ MD
TD =15,936’(MD) / TD =4,313’(TVD)
3
20”
Orig. KB Elev.: 66.54’ / GL Elev.: 33.0’
3-1/2”
7
2
9-5/8”
1
4/5
See
Screened
Liner
Detail
PBTD =15,932’(MD) / PBTD = 4,313’(TVD)
9-5/8” ‘ES’
Cementer @
2,107’
4-1/2”
5-1/2” x
4-1/2”
6
JEWELRY DETAIL
No Top MD Item
ID
Upper Completion
1 4,257’ Viking Sliding Sleeve 2.813” X Profile (Opens Down) 2.810”
2 4,310’ Zenith Gauge Carrier 2.992”
3 4,365’ XN Nipple, 2.813”, 2.75” No-Go 2.750”
4 4,664’ Locater Sub, 8.25” No Go (bottom of locator spaced out 3.52’) 6.261”
5 4,665’ Bullet Seals – TXP Top Box Up x Mule Shoe (Bottom @ ~4,675’) 6.261”
Lower Completion
6 4,666’ HES MatchSet Liner Top Packer 6.300”
7 15,932’ Shoe
0 1 2
3
4
5
6
7
8
9
10
3
6
9
12
15
18
21
24
27
30
33
36
37
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
010203040
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
)
598
557521498484473465457451445440435431426422418
2700 2700 2700 2685 2685 2685
27002700270027002700
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
ACTIVITYDATE SUMMARY
11/10/2024
WELLHEAD: MU 4 1/2 TC11 x over to LJ and Tbg Hgr. Cut and terminate 1/4" tech
line through hgr. Five ft into profile RKB 31.04', RILDS. Set 4" CTS BPV. SB for ND
BOP. Clean hgr void, install CTS plug and RX54 gasket. PU tree/adapter, term tech
line through adapter and land. Torque and test hgr void 500/5000 (PASS). RIG test
tree, pull CTS/Bpv with T bar. Well secured.
11/10/2024 Freeze Protect Doyon, Pumped 50 bbls diesel down IA
11/12/2024
Freeze Protect Post Rig, Pumped 5 bbls 60/40 followed by 20 bbls Hot Diesel down
Tubing
11/13/2024
*** WELL S/I ON ARRIVAL ***
RAN 3.5" 42BO(keys down), SHIFT S/S OPEN @ 4224' SLM (4257'MD)
RAN 2.81" XLOCK, JP(12b ratio, screen, 69" oal lih) SET IN X @ 4225' SLM.
*** WELL LEFT S/I ON DEPARTURE, DSO NOTIFIED ***
11/14/2024
T/I/O=0/0/0 Freeze Protect IA (Post RWO) Pumped 120 bbls diesel down IA. Final
Whps=0/0/0
11/16/2024
MPU Well Support set foundation and tied well into process as a sundried Producer.
2" hardline on PF and 3" to Test/Production. Serviced wellhead and PT'd all lines. No
issues
12/1/2024 Assist Slickline, Pumped 40 bbls diesel down Tubing
12/1/2024
***WELL FLOWING ON ARRIVAL***(jpco)
PULLED 3" JET PUMP ASSY(Ratio:12B) W/ SCREEN FROM 'VIKING' SSD @
4,257' MD.
BRUSH & FLUSHED TBG W/ 3-1/2" BRUSH & 2.61" GAUGE RING TO 4,250' SLM.
LRS PUMPED 40 BBLS OF DIESEL DOWN TBG.
***CONT'D ON 12/2/24 WSR***
12/2/2024
***CONT'D FROM 12/1/24 WSR***(jpco)
CONFIRMED 'VIKING' SSD OPEN W/ SHIFTING TOOL.(open)
SET 3" JET PUMP ASSY W/ SCREEN(Ratio:12B) IN 'VIKING' SSD @ 4,257' MD.
***WELL FLOWING ON DEPARTURE, PAD-OP NOTIFIED OF WELL STATUS***
12/3/2024 Assist Slickline, Pumped 40 bbls diesel down Tubing
12/3/2024
***WELL FLOWING ON ARRIVAL***(jpco)
PULLED 3" JET PUMP ASSY W/ SCREEN(Ratio:12B) FROM 'VIKING' SSD @
4,257' MD.
LRS DISPLACED WELL W/ 40 BBLS OF DIESEL.
CONFIRMED SSD OPEN W/ SHIFTING TOOL.(open)
SET 3" JET PUMP ASSY W/ SCREEN(Ratio:13B) IN 'VIKING' SSD @ 4,257' MD.
***WELL FLOWING ON DEPARTURE, PAD-OP NOTIFIED OF WELL STATUS***
12/17/2024
*** WELL SHUT-IN ON ARRIVAL.***
PULL 3-1/2" JETPUMP (ratio: 13B) FROM VIKING-SS AT 4,257' MD.
LRS FREEZE PROTECT TUBING W/ 25bbls DIESEL.
LRS LOADED 115bbls BRINE, 150bbls DIESEL DOWN IA.
SHIFT VIKING-SS CLOSED AT 4,257' MD W/ 3-1/2" 42BO.
LRS PERFORMED PASSING MIT-IA TO 2000psi (see lrs log).
*** WELL SHUT-IN ON DEPARTURE, PAD OP NOTIFIED.***
Daily Report of Well Operations
MPU J-47
Daily Report of Well Operations
MPU J-47
12/17/2024
T/I/O=134/122 Load & Test IA. Freeze Protected TBG with 25 bbls 160* diesel.
Flushed Hard line with 10 bbls 160* diesel. Loaded IA with 115 bbls inhibited 1% kcl
and 150 bbls diesel. Slickline closed sleeve. MIT-IA passed to 2235 psi. Pressured
up IA to 2262 psi with 3.2 bbls diesel. 1st 15 min IA lost 25 psi. 2nd 15 min IA lost 2
psi for a total loss of 27 psi in 30 min. Bled back 3 bbls. Final Whps=50/100
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: 12/05/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20241205
Well API #PTD #Log Date Log
Company Log Type AOGCC
ESet
AN 15(GRANITE PT
ST 18742 15) 50733200700000 167082 11/18/2024 AK E-LINE Perf
BRU 221-26 50283202010000 224098 10/24/2024 AK E-LINE Perf
BRU 233-23T 50283202000000 224088 10/21/2024 AK E-LINE Perf
BRU 233-23T 50283202000000 224088 10/30/2024 AK E-LINE Perf
BRU 241-23 50283201910000 223061 11/8/2024 AK E-LINE Perf
BRU 241-26 50283201970000 224068 11/12/2024 AK E-LINE Plug/Perf
END 2-72 50029237810000 224016 10/16/2024 HALLIBURTON COILFLAG
END 2-72 50029237810000 224016 10/18/2024 HALLIBURTON COILFLAG
MGS-ST 17595-05 50733100710000 165038 10/6/2024 AK E-LINE CBL
MPU F-109 50029235960000 218014 10/28/2024 READ CaliperSurvey
MPU J-02 50029220710000 190096 11/16/2024 READ CaliperSurvey
MPU J-47 50029238010000 224120 11/9/2024 READ LeakPointSurvey
MPU D-01 50029206640000 181144 10/23/2024 AK E-LINE TubingPunch
MPU F-02 50029226730000 196070 11/18/2024 READ CaliperSurvey
MPU I-08 50029228210000 197192 10/22/2024 AK E-LINE TubingPunch
MPU I-08 50029228210000 197192 10/26/2024 HALLIBURTON JETCUT
MPU L-60 50029236780000 220048 10/26/2024 HALLIBURTON MFC24
MRU M-25 50733203910000 187086 11/15/2024 AK E-LINE Plug
NCIU A-21 50883201990000 224086 11/9/2024 AK E-LINE Perf
NCIU A-21 50883201990000 224086 10/19/2024 AK E-LINE Perf
NCIU A-21 50883201990000 224086 10/30/2024 AK E-LINE Perf
NCIU A-21 50883201990000 224086 10/30/2024 AK E-LINE Plug/Perf
PBU 06-07A 50029202990100 224043 9/30/2024 HALLIBURTON RBT
PBU 14-41A 50029222900100 224076 11/8/2024 HALLIBURTON RBT
PBU H-36A 50029226050100 200025 10/26/2024 HALLIBURTON RBT
PCU 02A 50283200220100 224110 11/24/2024 AK E-LINE Perf
Please include current contact information if different from above.
T39808
T39809
T39810
T39810
T39811
T39812
T39813
T39813
T39814
T39815
T39816
T39817
T39818
T39819
T39820
T39820
T39821
T39822
T39823
T39823
T39823
T39823
T39824
T39825
T39826
T39827
MPU J-47 50029238010000 224120 11/9/2024 READ LeakPointSurvey
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.12.05 14:52:46 -09'00'
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: 11/22/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL:
WELL: MPU J-47
PTD: 224-120
API: 50-029-23801-00-00
FINAL LWD FORMATION EVALUATION + GEOSTEERING (10/21/2024 to 11/03/2024)
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: g
Please include current contact information if different from above.
224-120
T39799
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.11.22 14:36:19 -09'00'
,uAt Pots- I Lt� T- 47
Regg, James B (OGQ
From: Mark Brouillet - (C) <Mark.Brouillet@hilcorp.com>
Sent: Monday, November 11, 2024 12:43 PM
To: Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace,
Chris D (OGC)
Cc: Ian Toomey - (C)
Subject: MIT MPU J-47 Doyon 14 D7M�—
Attachments: 10-426 form MPU J-47 Doyon 14 MIT.xlsx
CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open
attachments unless you recognize the sender and know the content is safe.
Good Afternoon,
Here is the completed 10-426 form for your review and records.
Thankyou
Mark Brouillet
NI-lilcorp Alaska, LI.,C
Doyon Rig 14
Office: 907-670-3090
Doghouse:907-670-3092
Cell:907-631-9850
mark brouilletCrlHilcorp com
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed
above, then promptly and permanently delete this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission,
opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and
the recipient should carry out such virus and other checks as it considers appropriate.
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
Mechanical Integrity Test
Submit to: iim.reaauttalaska.aov: AOGCC.InsoectorsAalaaka.QQE ohoetebrooksdlialaska.aov
OPERATOR: Hitcorp Alaska LLC
FIELD/UNIT/PAD: Milne Point/MPU/J
DATE: 11/10/24
OPERATOR REP: M. Brouillet 11. Toomey
AOGCC REP: Waived by Brain Bixby
Well
J47
Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD
22d120D
Type inj
N
TubinB
0
0
0
0
Type Test
P
Packer TVO
3956
BBL Pump
4.3
IA
0
3I00
3800
3560
Interval
0
Test psi
3500
BBLReturn
4.0
OA
I
Result
P
Netea:
MIT -IA to 3500 psi per PTD 224-120 performed on Doyon 14 post lending completion. Witness Weived by AOGCC Rep Kam St an. Monobom completion.
Well
Pressures: Pretest Initial 15 Min, 30 Min. 45 Min. 60 Min.
PTD
Type lnj
I I
Tubing
Type Tesl
Packer TVD
BBL Pump
IIA
Interval
Test psi
BBL Return
OA
Result
Notes:
well
Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD
Type Inj
Tubing
Type Test
Packer TVD
BBL Pump
IA
Interval
Test psi
BBL Return
OA
Result
Notes:
Wall
Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD
Type Inj
Tubing
Type Test
Packer TVD
BBLPump
IA
Interval
Test psi
BBL Return
OA
Result
Notes:
Well
Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD
Type Inj
Tubing
Type Test
Packer TVD
BBL Pump
IA
Interval
Test psi
BBL Return
OA
Result
Notes:
Well
Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD
Type Inj
Tubing
Type Test
Packer TVD
BBLPumpl
IIA
Interval
Test psi
BBL Return
OA
Result
Notes:
Well
Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD
Type Inj
Tubing
Type Test
Packer TVD
EELPump
IA
Interval
Test psi
BBL Return
OA
Result
Notes:
Well
Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD
Type lnl
Tubing
Type Test
Packer TVD
BBL Pump
IA
Interval
Test psi
BBL Return
OA
Result
Notes:
TYPE INJ codes
W = Water
G=Gas
S = slurry
1= Industrial Wotexater
N=NM lnpctitg
TYPE TEST Codes
P=Pnsente Tot
O =Other (describe in Notes)
IMERVnLcedee
1= Initial TOM
<=Four Vear one,
v= Required ey Variance
O = Other (describe in real
ResutCodet
P = Pao
F - Fell
1=lnconcliaive
Fonn 10426 (Revised O112017) 10428 form MPU dsv Doyon 10 MIT
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M. Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK, 99503
Re: Milne Point Field, Schrader Bluff Oil Pool, MPU J-47
Hilcorp Alaska, LLC
Permit to Drill Number: 224-120
Surface Location: 2562' FSL, 3336' FEL, Sec 28, T13N, R10E, UM, AK
Bottomhole Location: 36' FSL, 1387' FEL, Sec 26, T13N, R10E, UM, AK
DearMr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
PerStatute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well
logs run must be submitted to the AOGCC within 90 days after completion, suspension, or
abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the 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,
-HVVLH/&KPLHORZVNL
Commissioner
DATED thisth day of October 2024.
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2024.10.17 13:20:10
-08'00'
RBDMS JSB 102224
Drilling Manager
08/30/24
Monty M
Myers
By Grace Christianson at 11:01 am, Aug 30, 2024
50-029-23801-00-00
MGR10OCT2024
224-120
* BOPE test to 3000 psi. Annular to 2500 psi.
* AOGCC to witness MIT-IA to 3500 psi or maximum power fluid header pressure.
24 hour notice for AOGCC to witness.
* MIT-IA to 2000 psi after 5 days of stabilized injection.
DSR-9/5/24
3:32 pm, Oct 11, 2024
A.Dewhurst 16OCT24
* Approved for 30 days of pre-injection production utilizing a reverse circulating jet pump.
SJC for GCW 10/17/24
Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski
Date: 2024.10.17 13:20:21 -08'00'
10/17/24
10/17/24
262728353433JHGA-01A-02A-02ACFP-2CFP-1E-02B-22AG-02G-01G-04G-03G-03AJ-05J-07J-06J-08J-08AJ-10J-11J-12J-13E-15E-13E-13BE-20E-20AE-20AL1H-05H-06I-05E-18G-09G-10G-11G-13G-12H-10H-14H-11H-12H-08H-08AH-13H-13AE-24AL1E-33J-15E-2E-25AE-25L1E-26G-14G-14L1I-15I-15L1S-29L1S-19S-19AS-18G-16G-16L1G-17G-18G-18L1J-25I-19I-19L1H-18H-18L1H-18L2H-16H-16L1G-19H-15H-17H-19H-19L1KP 32-25E-03H-01H-02H-03H-04I-01I-02I-04I-04AI-04AL1J-01J-01AJ-01AL1J-02J-03J-04G-05G-06G-07G-08G-08AE-07J-19J-19AE-16E-14E-19E-13APB1E-20AL1PB1H-14PB1E-25PB1E-29PB1I-15PB1S-19APB1G-16PB1G-18PB1J-26PB1J-25PB1I-19PB1H-16PB1H-08BPB1E-25PB2C-41PB2G-16PB2-19PB2H-16PB2I-04APB1E-25PB3H-16PB3E-25L1PB1E-13BLSS-18LSE-13BSSS-18SSE-38E-42E-42L1E-38 PB1E-38 PB2I-36PB1I-36PB2I-28H-17PB1S-44S-46PB1I-28PB1E-19AJ-43J-42J-42PB1J-41J-41PB1J-44_wp07J-45_wp03HILCORP ALASKA LLCMILNE POINT FIELDJ-47 AORSchrader Bluff Nb Drill WellFEET05001,0001,500POSTED WELL DATAWell NumberWELL SYMBOLSACTIVE OILD&ALocationShut In OilINJ Well (W ater Flood)P&A OilP&A Oil/GasAbandoned InjectorSWDJ&ATemporarily AbandonedPlug BackPilot WellInjector LocationProducer LocationInjector GasShut In INJWATER SOURCELEADREMARKSPosting all wells that penetrate the Schrader BluffFormation.Nb Penetration Points labelled with well symbols atTop Nb.Other Schrader Bluff wells that never penetrated the Nb(mostly sidetracked wells) are labelled at TDDashed black circles and red outline illustrates 1/4 Mileradii from proposed wellBy: K. CunhaAugust 19, 2024E-28J-47 AOR Map•All wells that penetrate the Schrader Bluff Nb labelled at top Nb intersection point•Green lines represent the footage in wells that are within the Schrader Bluff Nb sandinside the ¼ mile radius of proposed injector, J-47•Note: Future J-Pad wells shown in dark green and blue lines (producers and injectors,respectively)J-47 Expected Top Nbintersection pointJ-45 (not drilled yet)Expected Top Nbintersection pointFutureJ-45InjectorFutureJ-46ProducerJ-47 expected TD locationJ-47 Proposed Well
PTD API WELLSTATUSTop of SBNB (MD)Top of SBNB (TVD)Top ofCement(MD)Top ofCement(TVD)Schrader NBstatusZonal Isolation191-095 50-029-22196-00-00 MPU J-05SB N Sands/OA/OBA Injector- ShutIn4424 3977 3004 2902 OpenThe 9-5/8" was cemented with 634 sx class G cement. Assuming 20%washout, TOC is 3,004' MD. No losses are noted on the daily report.204-013 50-029-23192-00-00 MPU G-17 SB /OA/OBA Injector- Shut in 6178 3973 5256 3284 N/AThe 7" was cemented with 226 sx class G cement. Assuming 20% washout,TOC is 4950' MD. No losses are noted on the daily report.A CBL was run on 2/12/2004 and TOC was picked at 5256' MD.190-096 50-029-22071-00-00 MPU J-02Prince Creek Water Source Well-Active (Res abandoned SB Injector)5611 3997 3580 2740 ClosedThe 7" was cemented with 306 sx class G cement. Assuming 20% washout,TOC is 3936' MD. No losses are noted on the daily report.A CBL was run on 10/31/2016 and TOC was picked at 3,580' MD.191-097 50-029-22198-00-00 MPU J-07SB N Sands/OA/OBA Producer-P&A'd4161 3988 2130 2111 ClosedThe 7" was cemented with 350 sx class G cement. Assuming 20% washout,TOC is 2130' MD. No losses are noted on the daily report.204-174 50-029-23224-00-00 MPU H-18 SB tri-lat (OBa lat) Producer- Shut In 6205 3965 4244 3057 N/AThe 7-5/8" (shoe at 6909' MD) was cemented with 604 sx class G cement.Assuming 20% washout, TOC is 4244' MD. No losses are noted on the dailyreport.204-175 50-029-23224-60-00 MPU H-18L1 SB tri-lat (Oa lat) Producer- Shut In 6205 3965 4244 3057 N/AThe 7-5/8" was cemented with 604 sx class G cement. Assuming 20%washout, TOC is 4244' MD. The bottom of the 7-5/8" OA window is 6554'MD. No losses are noted on the daily report.204-176 50-029-23224-61-00 MPU H-18L2 SB tri-lat (Nb lat) Producer- Shut In 6442 3967 4244 3057 OpenThe 7-5/8" was cemented with 604 sx class G cement. Assuming 20%washout, TOC is 4244' MD. Note: The bottom of the 7-5/8" NB window is6084' MD/3837' TVDss. The NB window is 14' TVD below the top of thepool. No losses are noted on the daily report.191-023 50-029-22138-00-00 MPU G-05SB N Sands/OA/OBA Injector- Shutin4201* 3963 4021 3795 Open*Top of NB is 4284' MD / 4040' TVD. The top of the pool per the G-01reference log is 4201' MD / 3963' TVD. The 7" shoe is at 4200' MD. A USIT across the 7" casing shows goodcement from TD to 3,312' MD.The 7" was set above the Schrader NB. The 4-1/2" was cemented with 122sx class G. The drilling summary does not give any details about theprimary liner job. A 10bbl cement squeeze was pumped on 1/8/92 througha retainer at 4,570' MD. A usit was run in the 4-1/2" before the squeezejobs and the log shows poorly bonded cement.A 16bbl squeeze was pumped at the TOL on 1/12/92 at 3982' MD.They reported hard cement in the returns upon cleaning out on 1/13/92and 1/14/92.On 1/14/92, after cleaning out the liner, it was pressure tested to 300 psi.197-142 50-029-22792-00-00 MPU G-12SB N Sands/OA/OBA Producer- Shutin4079 3986 Surface Surface OpenThe 9-5/8" was cemented to surface via a 2 stage cement job with 110 bblsto surface.189-029 50-029-21927-00-00 MPU G-01SB N Sands/OA/OBA Injector- Shutin4164 4001 2994 2866 Open7" cemented with 50 bbls of class G cement. Assuming 20% washout, TOCestimated at 2,994' MD. The cement report says the plug was bumped andfloats and there were full returns during the job.204-020 50-029-23194-00-00 MPU G-18SB dual-lat (OBa lat) Producer-Active5170 4045 3730 2849 N/AThe 7-5/8" was cemented with 420 sx of Class G cement in 9-7/8" hole.Assuming 20% washout, TOC is 3730' MD. The daily drilling report saysthey had "full returns and good pressure increase".Area of Review MPU J-47 SB NB
204-021 50-029-23194-60-00 MPU G-18L1 SB dual-lat (Oa lat) Producer- Active 5170 4045 3730 2849 N/AThe 7-5/8" was cemented with 420 sx of Class G cement in 9-7/8" hole.Assuming 20% washout, TOC is 3730' MD. The daily drilling report saysthey had "full returns and good pressure increase".204-020 50-029-23194-70-00 MPU G-18PB1 SB OBa plugback 5170 4045 3730 2849 N/AThe 7-5/8" was cemented with 420 sx of Class G cement in 9-7/8" hole.Assuming 20% washout, TOC is 3730' MD. The daily drilling report saysthey had "full returns and good pressure increase".189-028 50-029-21926-00-00 MPU G-02 SB N Sands Producer- Active 5056 4095 3405 2884 OpenThe 7" was cemented with 65bbls of class G cement in 8-1/2" hole.Assuming 20% washout, TOC is 3405' MD. No losses are noted on the dailyreport.191-024 50-029-22139-00-00 MPU G-06 SB Nb Producer- P&A'd 5181 4144 3900 3237 ClosedThe 7" was cemented with 82 bbls class G cement in 8-1/2" hole. Assuming20% washout, TOC is 2854' MD. A drilling summary page says "bumped plugat 1000 psig over circulating pressure. Floats held." A sundry on the AOGCCwebsite estimates TOC at 3900'.203-210 50-029-23189-00-00 MPU G-16SB dual-lat (OBa lat) Producer-Active5299 4136 3295 3109 N/AThe 7-5/8" was cemented with 670 sx of Class G cement in 9-7/8" hole.Assuming 20% washout, TOC is 3295' MD. The cement reports says "floatsheld, full returns throughout job."203-211 50-029-23189-60-00 MPU G-16L1 SB dual-lat (Oa lat) Producer- Active 5299 4136 3295 3109 N/AThe 7-5/8" was cemented with 670 sx of Class G cement in 9-7/8" hole.Assuming 20% washout, TOC is 3295' MD. The cement reports says "floatsheld, full returns throughout job."203-210 50-029-23189-70-00 MPU G-16PB1 SB OBa plugback 5299 4136 3295 3109 N/AThe 7-5/8" was cemented with 670 sx of Class G cement in 9-7/8" hole.Assuming 20% washout, TOC is 3295' MD. The cement reports says "floatsheld, full returns throughout job."203-210 50-029-23189-71-00 MPU G-16PB2 SB OBa plugback 5299 4136 3295 3109 N/AThe 7-5/8" was cemented with 670 sx of Class G cement in 9-7/8" hole.Assuming 20% washout, TOC is 3295' MD. The cement reports says "floatsheld, full returns throughout job."197-186 50-029-22818-00-00 MPU H-13SB N Sands/OA/OBA Producer-Sidetracked6071 3992 Surface Surface Closed9-5/8" cemented to surface via 2 stage cement job. Over 50 bbls returnedto surface during stage 2.H-13A was abandoned in 2015.A CBL was run on 6/3/1998 but our records department has been unable tolocated a copy of it thus far.202-167 50-029-22818-01-00 MPU H-13A SB Nb Producer- Suspended 6667 4006 5083 3453 Closed7" cemented with 230 sacks of class G cement. Assuming 20% washout,TOC estimated at 5,083' MD. The drilling report does not mentioned losses.They bumped the plug and the floats held. The cement report says theyhad full returns. The cement report estimated TOC is 4,810'.205-055 50-029-23259-00-00 MPU E-28 SB Nb Producer-Suspended 7673 4251 5200 3312 OpenThe 7-5/8" was cemented with 487 sx of Class G cement in 9-7/8" hole.Assuming 20% washout, TOC is 5539' MD.A CBL was run on 5/13/2011 and TOC was 5200' MD.TBD TBD MPU J-46 Future NB Horizontal Producer TBD TBD TBD TBD Will be Open Not drilled yet
Milne Point Unit
(MPU) J-47
Application for Permit to Drill
Version 2
10/11/2024
Table of Contents
1.0 Well Summary .......................................................................................................................... 2
2.0 Management of Change Information ....................................................................................... 3
3.0 Tubular Program:..................................................................................................................... 4
4.0 Drill Pipe Information: ............................................................................................................. 4
5.0 Internal Reporting Requirements ............................................................................................ 5
6.0 Planned Wellbore Schematic .................................................................................................... 6
7.0 Drilling / Completion Summary ............................................................................................... 7
8.0 Mandatory Regulatory Compliance / Notifications ................................................................. 8
9.0 R/U and Preparatory Work .................................................................................................... 11
10.0 N/U 21-1/4” 2M Diverter System ............................................................................................ 12
11.0 Drill 12-1/4” Hole Section ....................................................................................................... 14
12.0 Run 9-5/8” Surface Casing ..................................................................................................... 17
13.0 Cement 9-5/8” Surface Casing ................................................................................................ 23
14.0 BOP N/U and Test................................................................................................................... 28
15.0 Drill 8-1/2” Hole Section ......................................................................................................... 29
16.0 Run Injection Liner (Lower Completion) .............................................................................. 34
17.0 Run 3-1/2” Tubing (Upper Completion) ................................................................................ 40
18.0 RDMO ..................................................................................................................................... 41
19.0 Post-Rig Work ........................................................................................................................ 42
20.0 Doyon 14 Diverter Schematic ................................................................................................. 43
21.0 Doyon 14 BOP Schematic ....................................................................................................... 44
22.0 Wellhead Schematic ................................................................................................................ 45
23.0 Days Vs Depth ......................................................................................................................... 46
24.0 Formation Tops & Information.............................................................................................. 47
25.0 Anticipated Drilling Hazards ................................................................................................. 48
26.0 Doyon 14 Layout ..................................................................................................................... 51
27.0 FIT Procedure ......................................................................................................................... 52
28.0 Doyon 14 Choke Manifold Schematic .................................................................................... 53
29.0 Casing Design .......................................................................................................................... 54
30.0 8-1/2” Hole Section MASP ...................................................................................................... 55
31.0 Spider Plot (NAD 27) (Governmental Sections) ..................................................................... 56
32.0 Surface Plat (As-Staked) (NAD 27) ........................................................................................ 57
Page 2
Milne Point Unit
J-47 SB Injector
Drilling Procedure
1.0 Well Summary
Well MPU J-47
Pad Milne Point “J” Pad
Planned Completion Type 3-1/2” Injection Tubing
Target Reservoir(s) Schrader Bluff NB Sand
Planned Well TD, MD / TVD 16,651’ MD / 4,287’ TVD
PBTD, MD / TVD 16,651’ MD / 4,287’ TVD
Surface Location (Governmental) 2563' FSL, 1943' FWL, Sec. 28, T13N, R10E, UM, AK
Surface Location (NAD 27) X= 551982 Y= 6014960
Top of Productive Horizon
(Governmental)2239' FSL, 2057' FEL, Sec 28, T13N, R10E, UM, AK
TPH Location (NAD 27) X= 553264 Y= 6014645
BHL (Governmental) 36' FSL, 1387' FEL, Sec 26, T13N, R10E, UM, AK
BHL (NAD 27) X= 564514 Y=6012531
AFE Drilling Days 19 days
AFE Completion Days 3 days
Maximum Anticipated Pressure
(Surface) 1362 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 1763 psig
Work String 5” 19.5# S-135 DS-50 & NC 50
KB Elevation above MSL: 33.7 ft + 33.4 ft = 67.1 ft
GL Elevation above MSL: 33.4 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
Page 3
Milne Point Unit
J-47 SB Injector
Drilling Procedure
2.0 Management of Change Information
Page 4
Milne Point Unit
J-47 SB Injector
Drilling Procedure
3.0 Tubular Program:
Hole
Section
OD (in)ID
(in)
Drift
(in)
Conn OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 20” 19.25” - - - X-52 Weld
12-1/4”9-5/8” 8.681” 8.525” 10.625” 47 L-80 TXP 6,870 4,750 1,086
9-5/8” 8.835” 8.679”10.625”40 L-80 TXP 5,750 3,090 916
8-1/2”
5-1/2”
Solid 4.892” 4.767” 6.050” 17 L-80 JFE Bear 7,740 6,290 397
5-1/2”
Screen 4.892” 4.767” 6.050” 17 L-80 JFE Bear 7,740 6,290 397
4-1/2”
Solid 3.958” 3.833” 5.000” 12.6 L-80 JFE Bear 8430 7500 288
4-1/2”
Screen 3.920” 3.795” 5.051” 13.5 L-80
JFE Bear 9020 8540 307
Tubing 3-1/2” 2.992” 2.867” 4.500” 9.3 L-80
EUE 8RD 9289 7399 163
4.0 Drill Pipe Information:
Hole
Section
OD
(in)
ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn M/U
(Min)
M/U
(Max)
Tension
(k-lbs)
Surface &
Production
5”4.276” 3.25” 6.625” 19.5 S-135 GPDS50 36,100 43,100 560
5”4.276” 3.25” 6.625” 19.5 S-135 NC50 31,032 34,136 560
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
Page 5
Milne Point Unit
J-47 SB Injector
Drilling Procedure
5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report in WellView.
x Report covers operations from 6am to 6am
x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left
of the data entry area – this will not save the data entered and will navigate to another data entry.
x Ensure time entry adds up to 24 hours total.
x Try to capture any out-of-scope work as NPT. This helps later on when we pull end of well
reports.
x Enter the MD and TVD depths EVERY DAY whether you are making hole or not.
5.2 Afternoon Updates
x Submit a short operations update each work day to mmyers@hilcorp,
nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com
5.3 Intranet Home Page Morning Update
x Submit a short operations update each morning by 7am on the company intranet homepage. On
weekend and holidays, ensure to have this update in before 5am.
5.4 EHS Incident Reporting
x Health and Safety: Notify EHS field coordinator.
x Environmental: Drilling Environmental Coordinator
x Notify Drilling Manager & Drilling Engineer on all incidents
x Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
x Send final “As-Run” Casing tally to nathan.sperry@hilcorp.com and
joseph.lastufka@hilcorp.com
5.6 Casing and Cement report
x Send casing and cement report for each string of casing to mmyers@hilcorp.com
nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com
5.7 Hilcorp Milne Point Contact List:
Title Name Work Phone Email
Drilling Manager Monty Myers 907.777.8431 mmyers@hilcorp.com
Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com
Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com
Completion Engineer Todd Sidoti Todd.sidoti@hilcorp.com
Geologist Katie Cunha 907.564.4786 Katharine.cunha@hilcorp.com
Reservoir Engineer Almas Aitkulov 907.564.4250 aaitkulov@hilcorp.com
Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com
_____________________________________________________________________________________
Revised By: JNL 8/29/2024
PROPOSED SCHEMATIC
Milne Point Unit
Well: MPU J-47
Last Completed: TBD
PTD: TBD
5-1/2” x 4-1/2”SCREENED LINER DETAIL
Size Top
(MD)
Top
(TVD)
Btm
(MD)
Btm
(TVD)
4-1/2”
5-1/2”
CASING DETAIL
Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF
20" Conductor 129.5 / X-52 / Weld N/A Surface 170’ N/A
9-5/8" Surface 47 / L-80 / TXP 8.525” Surface 2,500’ 0.0732
9-5/8" Surface 40 / L-80 / TXP 8.679” 2,500’ 5,022’ 0.0758
5-1/2” Liner 250ђ Screens 17 / L-80 / JFE Bear 4.892” 5,022’ 6,572’ 0.0232
4-1/2” Liner 150ђ Screens 13.5 / L-80 / Hyd 625 3.920” 6,572’ 16,652’ 0.0149
TUBING DETAIL
3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.992” Surface 5,022’ 0.0087
OPEN HOLE / CEMENT DETAIL
Driven
12-1/4"Stg 1 –Lead 264 sx / Tail 395 sx
Stg 2 –Lead 673 sx / Tail 268 sx
8-1/2” Uncemented Screen Liner
TREE & WELLHEAD
Tree Cameron 3 1/8" 5M w/ 3-1/8” 5M Cameron Wing
Wellhead FMC 11” x 4-1/2” Tubing Hanger, 4-1/2” TCII
GENERAL WELL INFO
API#: TBD
Completion Date: TBD
WELL INCLINATION DETAIL
KOP @ 1150’
90° Hole Angle = 5,374’ MD
TD =16,652’(MD) / TD =4,287’(TVD)
3
20”
Orig. KB Elev.:67.1’ / GL Elev.: 33.4’
3-1/2”
7
2
9-5/8”
1
4/5
See
Screened
Liner
Detail
PBTD = 16,652’(MD) / PBTD = 4,287’(TVD)
9-5/8” ‘ES’
Cementer @
~2,500’
4-1/2”
5-1/2” x
4-1/2”
6
JEWELRY DETAIL
No Top MD Item
ID
Upper Completion
1 ~4,960’ Sliding Sleeve 2.992”
2 ~4,980’ Zenith Gauge Carrier 2.992”
3 ~5,000’ XN Nipple, 2.813”, 2.75” No-Go 2.750”
4 ~5,022’ Locater Sub, 8.25” No Go (bottom of locator spaced out 3.11’) 6.190”
5 ~5,022’ Bullet Seals – TXP Top Box x Mule Shoe (Bottom @ ~5,022’) 6.190”
Lower Completion
6 ~5,022’ SLZXP Liner Top Packer 6.190”
7 16,652’ Shoe
Page 7
Milne Point Unit
J-47 SB Injector
Drilling Procedure
7.0 Drilling / Completion Summary
MPU J-47 is a grassroots injector planned to be drilled in the Schrader Bluff NB sand. J-47 is part of a multi
well program targeting the Schrader Bluff sand on J-pad. J-47 will be pre-produced.
The directional plan is a horizontal well with 12-1/4” surface hole with 9-5/8” surface casing set into the top
of the Schrader Bluff NB sand. An 8-1/2” lateral section will be drilled. An injection liner will be run in the
open hole section.
The Doyon 14 will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately October 18th , 2024, pending rig schedule.
Surface casing will be run to 5,022’ MD / 4,007’ TVD and cemented to surface via a 2-stage primary cement
job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed,
necessary remedial action will be discussed with AOGCC authorities.
All cuttings & mud generated during drilling operations will be hauled to the Milne Point “B” pad G&I facility.
General sequence of operations:
1. MIRU Doyon 14 to well site
2. N/U & Test 21-1/4” Diverter and 16” diverter line
3. Drill 12-1/4” hole to TD of surface hole section. Run and cement 9-5/8” surface casing
4. N/D diverter, N/U & test 13-5/8” x 5M BOP. Install MPD Riser
5. Drill 8-1/2” lateral to well TD.
6. Run 5-1/2” x 4-1/2” injection liner.
7. Run 3-1/2” tubing.
8. N/D BOP, N/U Tree, RDMO.
Reservoir Evaluation Plan:
1. Surface hole: No mud logging. Remote geologist. LWD: GR + Res
2. Production Hole: No mud logging. Remote geologist. LWD: GR + ADR (For geo-steering)
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8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that all drilling and completion operations comply with all applicable AOGCC regulations.
Operations stated in this PTD application may be altered based on sound engineering judgement as
wellbore conditions require, but no AOGCC regulations will be varied from without prior approval from
the AOGCC. If additional clarity or guidance is required on how to comply with a specific regulation,
do not hesitate to contact the Anchorage Drilling Team.
x Review all conditions of approval of the PTD on the 10-401 form. Ensure that the conditions of
approval are captured in shift handover notes until they are executed and complied with.
x BOPs shall be tested at (2) week intervals during the drilling and completion of MPU J-47. Ensure
to provide AOGCC 24 hrs notice prior to testing BOPs.
x The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment
will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial
and subsequent tests).Confirm that these test pressures match those specified on the APD.
x If the BOP is used to shut in on the well in a well control situation or control fluid flow from the
well bore, AOGCC is to be notified and we must test all BOP components utilized for well control
prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP
test.
x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid
program and drilling fluid system”.
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”.
o Ensure the diverter vent line is at least 75’ away from potential ignition sources
x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
x Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test
must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a
minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test
pressure must show stabilizing pressure and may not decline more than 10 percent within 30
minutes. The results of this test and any subsequent tests of the casing must be recorded as required
by 20 AAC 25.070(1)”.
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AOGCC Regulation Variance Requests:
1) Hilcorp is requesting approval for a test period of pre-producing up to 30 days via a reverse circulating jet
pump completion. This will allow us to measure skin and evaluate the benefits of pre-producing our injectors
in the future. During flow back, Hilcorp will have a 24/7 man watch while the well is online and producing.
Section 19 details the steps required to make this happen. Note also that the MIT-IA has been changed from
2,500 psi to 3,500 psi.
1) Hilcorp is requesting approval for a test period of pre-producing up to 30 days via a reverse circulating jetpq gpp p pp gp y gj
pump completion. This will allow us to measure skin and evaluate the benefits of pre-producing our injectorspp p pp g j
in the future. During flow back, Hilcorp will have a 24/7 man watch while the well is online and producing.g,p pg
Section 19 details the steps required to make this happen. Note also that the MIT-IA has been changed from
2,500 psi to 3,500 psi.
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Summary of BOP Equipment & Notifications
Hole Section Equipment Test Pressure (psi)
12 1/4”x 21-1/4” 2M Diverter w/ 16” Diverter Line Function Test Only
8-1/2”
x 13-5/8” x 5M Hydril “GK” Annular BOP
x 13-5/8” x 5M Hydril MPL Double Gate
o Blind ram in btm cavity
x Mud cross w/ 3” x 5M side outlets
x 13-5/8” x 5M Hydril MPL Single ram
x 3-1/8” x 5M Choke Line
x 3-1/8” x 5M Kill line
x 3-1/8” x 5M Choke manifold
x Standpipe, floor valves, etc
Initial Test: 250/3000
Subsequent Tests:
250/3000
Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit.
Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air
pump, and emergency pressure is provided by bottled nitrogen.
The remote closing operator panels are located in the doghouse and on accumulator unit.
Required AOGCC Notifications:
x Well control event (BOP’s utilized to shut in the well to control influx of formation fluids).
x 24 hours notice prior to spud.
x 24 hours notice prior to testing BOPs.
x 24 hours notice prior to casing running & cement operations.
x Any other notifications required in PTD.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov
Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov
Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov
Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
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9.0 R/U and Preparatory Work
9.1 J-47 will utilize a newly set 20” conductor on J-pad. Ensure to review attached surface plat and
make sure rig is over appropriate conductor.
9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor.
9.3 Install landing ring.
9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each.
9.5 Level pad and ensure enough room for layout of rig footprint and R/U.
9.6 Rig mat footprint of rig.
9.7 MIRU Doyon 14. Ensure rig is centered over conductor to prevent any wear to BOPE or
wellhead.
9.8 Mud loggers WILL NOT be used on either hole section.
9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80qF).
9.10 Ensure 6” liners in mud pumps.
x Continental EMSCO FB-1600 mud pumps are rated at 4665 psi, 462 gpm @ 110 spm @
95% volumetric efficiency.
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10.0 N/U 21-1/4” 2M Diverter System
10.1 N/U 21-1/4” Hydril MSP 2M Diverter System (Diverter Schematic attached to program).
x N/U 16-3/4” 3M x 21-1/4” 2M DSA on 16-3/4” 3M wellhead.
x N/U 21-1/4” diverter “T”.
x Knife gate, 16” diverter line.
x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
x Diverter line must be 75 ft from nearest ignition source
x Place drip berm at the end of diverter line.
10.2 Notify AOGCC. Function test diverter.
x Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens
prior to annular closure.
x Ensure that the annular closes in less than 45 seconds (API Standard 64 3rd edition March 2018
section 12.6.2 for packing element ID greater than 20”)
10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the
vent line tip. “Warning Zone” must include:
x A prohibition on vehicle parking
x A prohibition on ignition sources or running equipment
x A prohibition on staged equipment or materials
x Restriction of traffic to essential foot or vehicle traffic only.
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10.4 Rig & Diverter Orientation:
x May change on location
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11.0 Drill 12-1/4” Hole Section
11.1 P/U 12-1/4” directional drilling assembly:
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
x Use GWD until MWD surveys are clean.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
x Drill string will be 5” 19.5# S-135.
x Run a solid float in the surface hole section.
11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor.
x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in
conductor.
11.3 Drill 12-1/4” hole section to section TD in the Schrader NB sand. Confirm the 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 minimize washing out permafrost.
x Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can
handle the flow rate.
x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoff’s, increase in pump pressure, or changes in hookload are seen
x Slow in/out of slips and while tripping to keep swab and surge pressures low
x Ensure shakers are functioning properly. Check for holes in screens on connections.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea
gravel, clay balling or packing off.
x Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2
minimum at TD (pending MW increase due to hydrates).
x Gas hydrates have not been seen on J-pad. However, be prepared for them. In MPU they
have been encountered typically around 2100’-2400’ 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 AC: All wells have a clearance factor greater than 1.0 in the surface interval.
12-1/4” hole mud program summary:
Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid
will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with
a simple gel + FW spud mud at 8.8 ppg and TD with 9.2+ ppg.
Depth Interval MW (ppg)
Surface – Base
Permafrost
8.9+
Base Permafrost - TD 9.2+
MW can be cut once ~500’ below hydrate
zone
PVT System: MD Totco PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud
loggers office.
Rheology:MI Gel and CF Desco II should be used to maintain rheology. Begin system with a 75 YP but
reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared
to increase the YP if hole cleaning becomes an issue.
Fluid Loss: MI PAC UL should be used for filtrate control. Background LCM (10 ppb total) can be used in
the system while drilling the surface interval to prevent losses and strengthen the wellbore.
Wellbore and mud stability:Additions of 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 Busan 1060 MUST be made to control bacterial action.
Casing Running:Reduce system YP with DESCO as required for running casing as allowed (do not
jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the
system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value
they have targeted).
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System Type:8.8 – 9.2 ppg Pre-Hydrated Aquagel/freshwater spud mud
Properties:
Section Density Viscosity Plastic
Viscosity Yield Point API FL pH
Temp
Surface 8.8 –9.8 75-175 20 - 40 25-45 <10 8.5 –9.0 70 F
System Formulation: Gel + FW spud mud
Product- Surface hole Size Pkg ppb or (% liquids)
M-I Gel 50 lb sx 25
Soda Ash 50 lb sx 0.25
PolyPac Supreme UL 50 lb sx 0.08
Caustic Soda 50 lb sx 0.1
SCREENCLEEN 55 gal dm 0.5
11.4 At TD, PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity.
11.5 RIH to bottom, proceed to BROOH to HWDP
x Pump at full drill rate (400-600 gpm) and maximize rotation.
x Pull slowly, 5 – 10 ft / minute.
x Monitor well for any signs of packing off or losses.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay
balling.
x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until
parameters are restored.
11.6 TOOH and LD BHA
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12.0 Run 9-5/8” Surface Casing
12.1 R/U Weatherford 9-5/8” casing running equipment (CRT & Tongs)
x Ensure 9-5/8” TXP x NC50 XO on rig floor and M/U to FOSV.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x R/U of CRT if hole conditions require.
x R/U a fill up tool to fill casing while running if the CRT is not used.
x Ensure all casing has been drifted to 8-1/2” on the location prior to running.
x Note that 47# drift is 8.525”
x Be sure to count the total # of joints on the location before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, and lengths of all components w/ vendor & model info.
12.2 P/U shoe joint, visually verify no debris inside joint.
12.3 Continue M/U & thread locking 120’ shoe track assembly consisting of:
9-5/8” Float Shoe
1 joint – 9-5/8” TXP, 2 Centralizers 10’ from each end w/ stop rings
1 joint –9-5/8” TXP, 1 Centralizer mid joint w/ stop ring
9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’
1 joint –9-5/8” TXP, 1 Centralizer mid joint with stop ring
9-5/8” HES Baffle Adaptor
x Ensure bypass baffle is correctly installed on top of float collar.
x Ensure proper operation of float equipment while picking up.
x Ensure to record S/N’s of all float equipment and stage tool components.
This end up.
Bypass Baffle
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12.4 Float equipment and Stage tool equipment drawings:
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12.5 Continue running 9-5/8” surface casing
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
x 1 centralizer every joint to ~ 1000’ MD from shoe
x 1 centralizer every 2 joints to ~2,000’ above shoe (Top of Lowest Ugnu)
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
x Any packing off while running casing should be treated as a major problem. It is preferable
to POOH with casing and condition hole than to risk not getting cement returns to surface.
12.6 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below
the permafrost.
x Install centralizers on 5 joints below and 5 joints above stage tool.
x Do not place tongs on ES cementer, this can cause damage to the tool.
x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi.
9-5/8” 40# L-80 TXP Make-Up Torques:
Casing OD Minimum Optimum Maximum
9-5/8”18,860 ft-lbs 20,960 ft-lbs 23,060 ft-lbs
9-5/8” 47# L-80 TXP MUT:
Casing OD Minimum Optimum Maximum
9-5/8”21,440 ft-lbs 23,820 ft-lbs 26,200 ft-lbs
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12.7 Continue running 9-5/8” surface casing
x Centralizers: 1 centralizer every 3rd joint to 200’ from surface
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
o 1 centralizer every 2 joints to base of conductor
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12.8 Ensure the permafrost is covered with 9-5/8” 47# from BPRF to surface
x Ensure drifted to 8.525”
12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.10 Slow in and out of slips.
12.11 P/U pup joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the
landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference
when getting the casing on depth.
12.12 Lower casing to setting depth. Confirm measurements.
12.13 Have slips staged in cellar along with all necessary equipment for the operation.
12.14 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement
job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible
reciprocate casing string while conditioning mud.
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13.0 Cement 9-5/8” Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
x Ensure a plan is in place to handle cement returns at surface. Ensure vac trucks are on
standby and ready to assist.
x Ensure relevant personnel know rig pumps will be utilized for displacement
x Ensure an adequate amount of water for mix fluid is heated and available in the water tanks.
x Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
x Review test reports and ensure pump times are acceptable.
x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
13.2 Document efficiency of all possible displacement pumps prior to cement job.
13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
13.5 Fill surface cement lines with water and pressure test.
13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below
calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached.
13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead &
tail with the TOC brought to the stage tool.
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Estimated 1st Stage Total Cement Volume:
Cement Slurry Design (1st Stage Cement Job):
13.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue
with the cement job.
13.10 After pumping cement, drop top plug (shutoff plug) and displace cement with spud mud out of
mud pits, spotting water across the HEC stage cementer.
a. Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep, and HES Cementers during the entire job.
13.11 Ensure rig pump is used to displace cement. The plug must be bumped to operate the stage tool
hydraulically,
13.12 Displacement calculation is in the Stage 1 Table in step 13.8.
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 the
Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the
back-up option to open the stage tool if the plugs are not bumped.
Lead Slurry Tail Slurry
System EconoCem HalCem
Density 12.0 lb/gal 15.8 lb/gal
Yield 2.35 ft3/sk 1.16 ft3/sk
Mix Water 13.92 gal/sk 4.98 gal/sk
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13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up the string to final circulating pressure and hold
until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final
circulating pressure if pressure must be held. This is to ensure the stage tool is not prematurely
opened.
13.16 Increase pressure to 3300 psi to open circulating ports in stage collar. Slightly higher pressure
may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns
to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation
for the 2nd stage of the cement job.
13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker
bypass line to the cuttings tank. Have black water available and vac trucks ready to assist.
Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact
with the cement.
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Second Stage Surface Cement Job:
13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive
strength. Hold pre-job safety meeting.
13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing
head.
13.20 Fill surface lines with water and pressure test.
13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.22 Mix and pump cmt per below recipe for the 2
nd stage.
13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail).
The job will consist of lead & tail slurries with TOC brought to surface. Cement will continue to
be pumped until clean spacer is observed at surface.
Estimated 2nd Stage Total Cement Volume:
Cement Slurry Design (2nd stage cement job):
13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail.
13.25 After pumping cement, drop the ES Cementer closing plug and displace cement with spud mud
out of mud pits.
13.26 Displacement is in the Stage 2 table in step 13.23.
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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13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side
outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out
fluid from cellar. Have black water available to retard setting of cement.
13.28 Land closing plug on stage collar and pressure up to 1000 – 1500 psi to ensure stage tool closes.
Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool
has closed. Slips will be set as per plan to allow full annulus for returns during surface cement
job. Set slips
13.29 Make initial cut on 9-5/8” final joint. L/D cut joint. Make final cut on 9-5/8”. Dress off stump.
Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule.
Ensure to report the following on WellView:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight
& type of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement, actual displacement volume, whether plug bumped &
bump pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final
circulating pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
x Note calculated top of cement
x Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to nathan.sperry@hilcorp.com and
joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the
AOGCC.
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14.0 BOP N/U and Test
14.1 N/D the diverter T, knife gate, diverter line & N/U 11” x 13-5/8” 5M casing spool.
14.2 N/U 13-5/8” x 5M BOP as follows:
x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13-
5/8” x 5M mud cross / 13-5/8” x 5M single gate
x Double gate ram should be dressed with 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 N/U bell nipple, install flowline.
x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to
mud cross).
x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual
valve
14.3 Run 5” BOP test plug
14.4 Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min.
x Test 2-7/8” x 5” rams with the 3-1/2” and 5” test joints
x Test the 4-1/2” x 7” rams with 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
14.5 R/D BOP test equipment
14.6 Set wearbushing in wellhead.
14.7 Ensure 6” liners in mud pumps.
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15.0 Drill 8-1/2” Hole Section
15.1 M/U 8.5” Cleanout BHA (Milltooth Bit & 1.22° PDM)
15.2 TIH w/ 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out
stage tool.
15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report.
15.4 R/U and test casing to 2500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and
plot on FIT graph. AOGCC reg is 50% of burst = 5750 / 2 = ~2875 psi, but max test pressure on
the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent
pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry
Guidance Bulletin 17-001.
15.5 Drill out shoe track and 20’ of new formation.
15.6 CBU and condition mud for FIT. Pump at least one high vis sweep at maximum rate to surface to
clean up debris.
15.7 Conduct FIT to 12.0 ppg EMW. Chart test. Ensure test is recorded on same chart as FIT.
Document incremental volume pumped (and subsequent pressure) and volume returned.
x 12.0 ppg desired to cover shoe strength for expected ECD’s. A 9.9 ppg FIT is the minimum
required to drill ahead
x 9.9 ppg provides >25 bbls based on 9.5ppg MW, 8.46ppg PP (swab kick at 9.5ppg BHP)
15.8 POOH & LD Cleanout BHA
15.9 P/U 8-1/2” RSS directional BHA.
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components that
cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Ensure MWD is R/U and operational.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
x Drill string will be 5” 19.5# S-135 DS50 & NC50.
x Run a ported float in the production hole section.
Schrader Bluff Bit Jetting Guidelines
Formation Jetting TFA
NB 6 x 14 0.902
OA 6 x 13 0.778
OB 6 x 13 0.778
* Email casing test and FIT digital data to AOGCC immediately upon completion of FIT. - mgr
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15.10 8-1/2” hole section mud program summary:
x Density: Weighting material to be used for the hole section will be calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg
above highest anticipated MW.
x Solids Concentration: It is imperative that the solids concentration be kept low while
drilling the production hole section. Keep the shaker screen size optimized and fluid
running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure
we are running the finest screens possible.
x Rheology: Keep viscosifier additions to an absolute minimum (DUO-VIS). Data
suggests excessive viscosifier concentrations can decrease return permeability. Do not
pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter)
for sufficient hole cleaning
x Run the centrifuge continuously while drilling the production hole, this will help with
solids removal.
x Dump and dilute as necessary to keep drilled solids to an absolute minimum.
x MD Totco PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, &
Toolpusher office.
System Type:8.9 – 9.5 ppg FloPro drilling fluid
Properties:
Interval Density PV YP LSYP Total Solids MBT HPHT Hardness
Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100
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System Formulation:
15.11 TIH with 8-1/2” directional assembly to bottom
15.12 Displace wellbore to 8.9 ppg FloPro drilling fluid. Clean pits and ship excess spud mud to G&I
for disposal.
15.13 Begin drilling 8-1/2” hole section, on-bottom staging technique:
x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k.
x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations
x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to P/U
off bottom and restart on bottom staging technique. If stick slip continues, consider adding
0.5% lubes
15.14 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer.
x Flow Rate: 350-550 gpm, target min. AV’s 200 ft/min, 385 gpm
x RPM: 120+
x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly
wet to maximize solids removal efficiency. Check for holes in screens on every connection.
x GWD will be the primary surveying tool.
x Monitor torque and drag with pumps on every stand (confirm frequency with co man)
x Monitor ECD, pump pressure, & hookload trends for indications of poor hole cleaning
x Surveys can be taken more frequently if necessary.
x Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible.
x Use ADR to stay in section.
x Limit maximum instantaneous ROP to < 250 fph. The sands will drill faster than this but
when concretions are hit while drilling this fast, cutter damage can occur.
x Target ROP is as fast as we can clean the hole (under 250 fph) without having to backream
connections.
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x 8-1/2” Lateral A/C:
x There are no wells with a SF <1.0.
x Schrader Bluff NB Concretions: 4-6% Historically
15.15 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons
learned and best practices. Ensure the DD is referencing their procedure.
x Patience is key! Getting kicked off too quickly might have been the cause of failed liner
runs on past wells.
x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so
we have a nice place to low side.
x Attempt to sidetrack low and right in a fast drilling interval where the wellbore is headed up.
x Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working
string back and forth. Trough for approximately 30 minutes.
x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the
openhole sidetrack is achieved.
15.16 At TD, CBU (minimum 4X, more if needed) at 200 ft/min AV (385+ gpm) and rotation (120+
rpm). Pump tandem sweeps if needed
x Rack back a stand at each bottoms up and reciprocate a full stand in between (while
circulating the BU). Keep the pipe moving while pumping.
x Monitor BU for increase in cuttings. Cuttings in laterals will come back in waves and not a
consistent stream so circulate more if necessary
x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum
15.17 Trip back to bottom. Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system
and circulate three SAP pills with 50 bbl in between. Displace out SAP pills. Monitor shakers
for returns of mud filter cake and calcium carbonate. Circulate the well clean.
x Losses during the cleanup of the wellbore are a good indication that the mud filter cake is
being removed, including an increase in the loss rate.
15.18 Displace 1.5 OH + Liner volume with viscosified brine.
x Proposed brine blend (aiming for an 8 on the 6 RPM reading) -
KCl: 7.1bbp for 2%
NaCl: 60.9 ppg for 9.4 ppg
Lotorq: 1.5%
Lube 776: 1.5%
Soda Ash: as needed for 9.5pH
Busan 1060: 0.42 ppb
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Flo-Vis Plus: 1.25 ppb
x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further
discussion needed prior to BROOH.
15.19 BROOH with the drilling assembly to the 9-5/8” casing shoe. Note: PST test is NOT required.
x Circulate at full drill rate unless losses are seen (350 gpm minimum if on losses)
x Rotate at maximum rpm that can be sustained.
x Target pulling speed of 5 – 10 min/std (slip to slip time, not including connections), but
adjust as hole conditions dictate.
x When pulling across any OHST depths, turn pumps off and rotary off to minimize
disturbance. Trip back in hole past OHST depth to ensure liner will stay in correct
hole section, check with ABI compared to as drilled surveys
15.20 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps.
15.21 Monitor well for flow. Increase mud weight if necessary
x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to
determine if well is breathing, treat all flow as an influx until proven otherwise
x If necessary, increase MW at shoe for any higher than expected pressure seen
x Ensure fluid coming out of hole has passed a PST at the possum belly
15.22 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball
drops.
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16.0 Run Injection Liner (Lower Completion)
16.1.Well control preparedness: In the event of an influx of formation fluids while running the 4-
1/2” injection liner with slotted liner, the following well control response procedure will be
followed:
x With a 5-1/2” joint across the BOP: P/U & M/U the 5” safety joint (with 5-1/2” crossover
installed on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW).
This joint shall be fully M/U and available prior to running the first joint of 5-1/2” liner.
x With 4-1/2” joint across BOP: P/U & M/U the 5” safety joint (with 4-1/2” crossover installed
on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW). This joint
shall be fully M/U and available prior to running the first joint of 4-1/2” liner.
16.2. Confirm VBR’s have been tested to cover 3-1/2” and 5” pipe sizes to 250 psi low/3000 psi high.
16.3. R/U 5-1/2” and 4-1/2” liner running equipment.
x Ensure 5-1/2” and 4-1/2” crossovers to NC50 are on rig floor and M/U to FOSV.
x Ensure the liner has been drifted on the deck prior to running.
x Be sure to count the total # of joints on the deck before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, and lengths of all components.
16.4. Run 5-1/2” x 4-1/2” injection liner.
x Injection liner will be a combination of screened and solid joints. Every third joint in the
open hole is to be a screened joint.
x The 4-1/2” will be 150 micron screens and the 5-1/2” will be 250 micron screens. Confirm
with OE.
x If JFE Bear is a mix of standard and Clear Run, confirm compatibility with the
operations engineer.
x Make up the lower 9,500’ of 4-1/2” and make up the remainder with 5-1/2”.
x Use API Modified or “Best O Life 2000 AG”thread compound. Dope pin end only w/ paint
brush. Wipe off excess. Thread compound can plug the screens/slotted joints.
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 Obtain up and down weights of the liner before entering open hole. Record rotating torque at
10 and 20 rpm
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5-1/2” 17# L-80 JFE Bear
Casing OD Minimum Optimum Maximum
Operating Torque
5.5” 6,660 ft-lbs 7,400 ft-lbs 8,140 ft-lbs
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16.6. Ensure that the liner top packer is set ~150’ MD above the 9-5/8” shoe.
x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as
per 20 AAC 25.030(d)(6). Ensure hanger/packer will not be set in a 9-5/8” connection.
16.7. Before picking up Baker SLZXP liner hanger / packer assembly, 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
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. Confirm all pressures with Baker
16.17. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill
pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger.
16.18. Shut down pumps. Drop setting ball down the workstring and pump slowly (1-2 BPM). Slow
pump before the ball seats. Do not allow ball to slam into ball seat.
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16.19. Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes.
Slack off 20K lbs on the SZXP liner hanger/packer to ensure the HRDE setting tool is in
compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi
to release the HRDE running tool.
16.20. Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without
pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20
RPM and set down 50K again.
16.21. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes.
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 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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17.0 Run 3-1/2” Tubing (Upper Completion)
17.1 Notify the AOGCC at least 24 hours in advance of the IA pressure test after running the
completion as per 20 AAC 25.412 (e).
17.2 M/U injection assembly and RIH to setting depth. TIH no faster than 90 ft/min.
x Ensure wear bushing is pulled.
x Ensure 3-½” EUE 8RD x NC-50 crossover is on rig floor and M/U to FOSV.
x Ensure all tubing has been drifted in the pipe shed prior to running.
x Be sure to count the total # of joints in the pipe shed before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
x Monitor displacement from wellbore while RIH.
3-1/2” 9.3# L-80 EUE 8RD
Casing OD Minimum Optimum Maximum
Operating Torque
3.5” 2,350 ft-lbs 3,130 ft-lbs 3,910 ft-lbs
3-½” Upper Completion Running Order
x 3-½” Baker Ported Bullet Nose seal (stung into the tie back receptacle)
x 3 joints (minimum, more as needed) 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x 3-½” “XN” nipple at TBD (Set below 70 degrees)
x 1 joint 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x 3-½” SGM-FS XDPG Gauge at TBD
x 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x 3-½” 9.3#/ft, L-80 EUE 8RD space out pups
x 1 joint 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x Tubing hanger with 3-1/2” EUE 8RD pin down
17.3 Locate and no-go out the seal assembly. Close annular and test to 400 psi to confirm seals
engaged.
17.4 Bleed pressure and open annular. Space out the completion (+/- 1’ to 2’ above No-Go). Place all
space out pups below the first full joint of the completion.
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17.5 Makeup the tubing hanger and landing joint.
17.6 RIH. Close annular and test to 400 – 500 psi to confirm seals are engaged. Bleed pressure down
to 250 psi. PU until ports in seal assembly exposed.
17.7 Reverse circulate the well with brine and 1% corrosion inhibitor.
17.8 Freeze protect the tubing and IA to ~3000’ MD with ±210 bbl of diesel.
17.9 Land hanger. RILDs and test hanger.
17.10 Continue pressurizing the annulus to 3500 psi and test for 30 charted minutes.
i.Provide proper notification to the AOGCC for the right to witness the test.
ii. Complete form 10-426 and submit to the required recipients. Copy
nathan.sperry@hilcorp.com and ryan.thompson@hilcorp.com on the e-mail.
17.11 Set BPV, ensure new body seals are installed each time. ND BOPE and NU adapter flange and
tree.
17.12 Pull BPV. Set TWC. Test tree to 5000 psi.
17.13 Pull TWC. Set BPV. Bullhead tubing freeze protect.
17.14 Secure the tree and cellar.
18.0 RDMO
18. RDMO Doyon 14
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19.0 Post-Rig Work
Operations-Convert well on surface with hard line to a jet pump producer.
19.1 MU surface lines from power fluid header to existing IA.
a. Pressure test lines at existing power fluid header pressure (3,600 psi)
19.2 Rig up hardline to neighboring wells production header and test header. Pressure test to 3600 psi.
19.3 MIRU SL and Little Red Pumping Unit. PT lines to 3,000 psi.
19.4 Shift Sliding sleeve open
19.5 Set 12B jet pump
19.6 RDMO
SL/FB- After 30 days of production
19.7 MIRU SL and Little Red Pumping Unit. PT lines to 3,000 psi.
19.8 FB circ IA with corrosion inhibited brine down to SS with a FP cap down to 2000’ on IA
19.9 Pull Jet Pump
19.10 Shift SS closed
19.11 MIT-IA test to 2000 psi
19.12 POI
19.13 After 5 days of stabilized injection MIT-IA to 2000 psi (Charted and state witnessed)
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20.0 Doyon 14 Diverter Schematic
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21.0 Doyon 14 BOP Schematic
2-7/8” x 5” VBR
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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
MPU J-47 Formations TVD
(ft)
MD
(ft)
Formation Pressure
(psi)
EMW
(ppg)
BPRF 1927 1960 848 8.46
SV1 2132 2179 938 8.46
UGLA3 3367 3485 1481 8.46
UG_MB 3605 3813 1585 8.46
SCHRADER NA 3967 4697 1745 8.46
SCHRADER NB 4007 5022 1763 8.46
J-pad Data Sheet Formation Description
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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 hyrates have not been seen on this pad; however, be prepared for them! 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 ECDs
to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is
critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to
avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide
intervals. Do not out drill our ability to clean the hole.
Anti-Collison:
There are a few wells in close proximity. Take directional surveys every stand, take additional surveys
if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on
AM report. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if
necessary. Monitor drilling parameters for signs of collision with another well. Well specific A/C:
x AC: All wells have a clearance factor greater than 1.0 in the surface interval.
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. MPU J-pad is not known for H2S. J-10
had 10ppm H2S (2013) and J-18 had 9.6 (2009).
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
appropriately to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to
determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is
critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to
avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide
intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300 gpm
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
There is at least (5) faults that will be crossed while drilling the well. There could be others and the
throw of these faults is not well understood at this point in time. When a known fault is coming up,
ensure to put a “ramp” in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed,
we’ll need to either drill up or down to get a look at the LWD log and determine the throw and then
replan the wellbore.
H2S:
Treat every hole section as though it has the potential for H2S. MPU J-pad is not known for H2S. J-10
had 10ppm H2S (2013) and J-18 had 9.6 (2009).
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Abnormal Pressures and Temperatures:
Reservoir pressures are expected to be normal. Abnormal (offset injection) pressure has been seen on M-
Pad. Utilize MPD to mitigate any abnormal pressure seen.
Anti-Collision
Take directional surveys every stand, take additional surveys if necessary. Continuously monitor
drilling parameters for signs of magnetic interference with another well. Reference A/C report in
directional plan. Well specific AC:
8-1/2” Lateral A/C:
AC: All wells have a clearance factor greater than 1.0 in the surface interval.
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26.0 Doyon 14 Layout
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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.
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29.0 Casing Design
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J-47 SB Injector
Drilling Procedure
30.0 8-1/2” Hole Section MASP
Page 56
Milne Point Unit
J-47 SB Injector
Drilling Procedure
31.0 Spider Plot (NAD 27) (Governmental Sections)
Page 57
Milne Point Unit
J-47 SB Injector
Drilling Procedure
32.0 Surface Plat (As-Staked) (NAD 27)
1
Dewhurst, Andrew D (OGC)
From:Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Sent:Monday, 14 October, 2024 09:36
To:Rixse, Melvin G (OGC); Dewhurst, Andrew D (OGC); Nathan Sperry; AOGCC Permitting (CED sponsored)
Cc:Davies, Stephen F (OGC); Guhl, Meredith D (OGC); Katharine Cunha; Roby, David S (OGC); Frank Roach
Subject:RE: [EXTERNAL] Missing Directional Plan - MPU J-47 PTD (224-120): Questions
Attachments:MPU J-47 wp02_Proposal report.pdf; MPU J-47 wp02.txt
Follow Up Flag:Follow up
Flag Status:Flagged
Mel,
Andy requested just the changes to the PTD and AOR, since the drilling plan didn’t change I did not include it. I apologize for the confusion, please see
attached and let me know if anyone needs anything else. Thanks!
Thanks,
Joe Lastufka
Sr. Drilling Technologist
Hilcorp North Slope, LLC
Office: (907)777-8400, Cell:(907)227-8496
From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Sent: Monday, October 14, 2024 9:29 AM
To: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Nathan Sperry
<Nathan.Sperry@hilcorp.com>; AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov>
Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Katharine Cunha
<Katharine.Cunha@hilcorp.com>; Roby, David S (OGC) <dave.roby@alaska.gov>
Subject: [EXTERNAL] Missing Directional Plan - MPU J-47 PTD (224-120): Questions
Joe,
There is no Halliburton directional program in this PTD package.
Mel Rixse
Senior Petroleum Engineer (PE)
Alaska Oil and Gas Conservation Commission
907-793-1231 OƯice
907-297-8474 Cell
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the
intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient
of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov).
From: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Sent: Friday, October 11, 2024 3:13 PM
To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Nathan Sperry <Nathan.Sperry@hilcorp.com>; AOGCC Permitting (CED sponsored)
<aogcc.permitting@alaska.gov>
Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC)
<meredith.guhl@alaska.gov>; Katharine Cunha <Katharine.Cunha@hilcorp.com>
Subject: RE: [EXTERNAL] MPU J-47 PTD (224-120): Questions
All,
Please see updated permitting package with pre-producing information and updated AOR (please supersede prior submitted permit package sent 8/30)
for MPU J-47 (PTD #224-120). Please note the updated MOC (page 6) for updates / changes and new expected start date (October 18th). Please let me
know if you have any questions or need any additional information. We appreciate all of your help and eƯort. Thanks!
Thanks,
Joe Lastufka
Sr. Drilling Technologist
Hilcorp North Slope, LLC
Office: (907)777-8400, Cell:(907)227-8496
From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Sent: Thursday, October 10, 2024 2:49 PM
To: Nathan Sperry <Nathan.Sperry@hilcorp.com>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC)
<meredith.guhl@alaska.gov>
Subject: RE: [EXTERNAL] MPU J-47 PTD (224-120): Questions
Nate,
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
2
Yes, for many of the wells, no informaƟon is available. However, please disƟnguish between “no informaƟon” and zero losses reported/full returns.
Thanks,
Andy
From: Nathan Sperry <Nathan.Sperry@hilcorp.com>
Sent: Thursday, 10 October, 2024 13:14
To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC)
<meredith.guhl@alaska.gov>
Subject: RE: [EXTERNAL] MPU J-47 PTD (224-120): Questions
Andy,
No, we are not planning to pre-produce.
For many of the wells on the AOR, the daily reports list the volumes pumped. They do not list returns or losses.
Is it going to be acceptable to say “No losses noted on the daily report” for the wells where this statement is true?
Nate Sperry
Drilling Engineer
Hilcorp Alaska, LLC
From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Sent: Thursday, October 10, 2024 11:55 AM
To: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Cc: Nathan Sperry <Nathan.Sperry@hilcorp.com>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl,
Meredith D (OGC) <meredith.guhl@alaska.gov>
Subject: [EXTERNAL] MPU J-47 PTD (224-120): Questions
Joe,
I am reviewing the MPU J-47 PTD and have two quesƟons:
x The AOR aƩached to the MPU J-47 provides an esƟmated TOC with an assumpƟon of 20% washout for most oīset wells. Would you please update the
table with any available informaƟon regarding:
o Losses
o Returns
o CBLs
o Remedial cement work
o Etc.
Of parƟcular interest, it appears that there was remedial cement work done on the 4-1/2” producƟon liner at G-05.
x Also, are you planning to pre-produce this well?
Andy
Andrew Dewhurst
Senior Petroleum Geologist
Alaska Oil and Gas ConservaƟon Commission
333 W. 7th Ave, Anchorage, AK 99501
andrew.dewhurst@alaska.gov
Direct: (907) 793-1254
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have
received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email
or telephone if the sender's phone number is listed above, then promptly and permanently delete this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not
adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have
received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email
or telephone if the sender's phone number is listed above, then promptly and permanently delete this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not
adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have
received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email
or telephone if the sender's phone number is listed above, then promptly and permanently delete this message.
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3
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not
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Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME: ______________________________________
PTD: _____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD: __________________________ POOL: ____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in no greater
than 30-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot sample intervals through target
zones.
Non-
Conventional
Well
Please note the following special condition of this permit: Production or
production testing of coal bed methane is not allowed for this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a water-well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by the Operator in the attached application, the following well logs are
also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
MILNE POINT SCHRADER BLUFF OIL
224-120
MPU J-47
WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:MILNE PT UNIT J-47Initial Class/TypeSER / PENDGeoArea890Unit11328On/Off ShoreOnProgramSERField & PoolWell bore segAnnular DisposalPTD#:2241200MILNE POINT, SCHRADER BLFF OIL - 525140NA1 Permit fee attachedYes ADL025906 and ADL0255182 Lease number appropriateYes3 Unique well name and numberYes MILNE POINT, SCHRADER BLFF OIL - 525140 - governed by CO 477, 477.0054 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitYes Area Injection Order No. 10-C14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For sYes15 All wells within 1/4 mile area of review identified (For service well only)No16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes 20" 129.5# X-52 driven to 170'18 Conductor string providedYes 9-5/8" L-80 47# to BOPF, 9-5/8" L-80 40# to SB reservoir19 Surface casing protects all known USDWsYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.20 CMT vol adequate to circulate on conductor & surf csgYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.21 CMT vol adequate to tie-in long string to surf csgYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.22 CMT will cover all known productive horizonsYes 9-5/8" L-80 47# to BOPF, 9-5/8" L-80 40 to SB reservoir23 Casing designs adequate for C, T, B & permafrostYes Doyon 14 rig has adequate tankage and good trucking support24 Adequate tankage or reserve pitNA This is a grassroots well.25 If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collision scan shows no close approaches with HSE risk.26 Adequate wellbore separation proposedYes 16" Diverter27 If diverter required, does it meet regulationsYes All fluids overbalanced to expected pore pressure.28 Drilling fluid program schematic & equip list adequateYes 1 annular, 3 ram stack tested to 3000 psi.29 BOPEs, do they meet regulationYes 13-5/8" , 5000 psi stack tested to 3000 psi.30 BOPE press rating appropriate; test to (put psig in comments)Yes Doyon 14 has 14 x 3-1/8" manual gate valves, 1 x 3-1/8" manual choke and 1 x 3-1/16" remote hydraulic choke.31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo No history of H2S on J pad. Monitoring required33 Is presence of H2S gas probableYes34 Mechanical condition of wells within AOR verified (For service well only)Yes Rig will have detection equipment. J-10 had 10ppm H2S (2013).35 Permit can be issued w/o hydrogen sulfide measuresYes Reservoir anticipated to be normally pressured (8.45 ppg EMW). MPD to be employed. Multiple faults expected.36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate10/16/2024ApprMGRDate10/10/2024ApprADDDate10/3/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateSJC for GCW 10/17/24JLC 10/17/2024
