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Alaska Oil and Gas Conservation Commission
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MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE:Wednesday, October 16, 2024
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Austin McLeod
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
Hilcorp Alaska, LLC
J-43
MILNE PT UNIT J-43
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 10/16/2024
J-43
50-029-23788-00-00
224-038-0
W
SPT
3808
2240380 2000
162 164 164 162
INITAL P
Austin McLeod
8/28/2024
2000psi per PTD 2240380. Monobore.
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-43
Inspection Date:
Tubing
OA
Packer Depth
441 2210 2141 2120IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitSAM240828193121
BBL Pumped:2.5 BBL Returned:2.5
Wednesday, October 16, 2024 Page 1 of 1
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9PTD 2240380
James B. Regg Digitally signed by James B. Regg
Date: 2024.10.16 14:52:14 -08'00'
By Grace Christianson at 8:08 am, Jul 10, 2024
Completed
6/19/2024
JSB
RBDMS JSB 071724
GDSR-7/18/24MGR23DEC2025
Drilling Manager
07/09/24
Monty M
Myers
Digitally signed by Taylor
Wellman (2143)
DN: cn=Taylor Wellman (2143)
Date: 2024.07.09 15:11:48 -
08'00'
Taylor Wellman
(2143)
_____________________________________________________________________________________
Revised By: JNL 6/21/2024
SCHEMATIC
Milne Point Unit
Well: MPU J-43
Last Completed: 6/19/2024
PTD: 224-038
5-1/2” x 4-1/2”SLOTTED LINER DETAIL
Size Top
(MD)
Top
(TVD)
Btm
(MD)
Btm
(TVD)
5-1/2” 5893’ 3865’ 7080’ 3918’
4-1/2” 7160’ 3919’ 16460’ 4185’
CASING DETAIL
Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF
20" Conductor 129.5 / X-52 / Weld N/A Surface 165’ N/A
9-5/8" Surface 47 / L-80 / TXP 8.525” Surface 2,442’ 0.0732
9-5/8" Surface 40 / L-80 / TXP 8.679” 2,442’ 5,727’ 0.0758
5-1/2” Slotted Liner 17 / L-80 / JFE Bear 4.892” 5,528’ 7,080’ 0.0232
4-1/2” Slotted Liner 13.5 / L-80 / Hyd 625 3.920” 7,080’ 16,580’ 0.0149
TUBING DETAIL
3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.992” Surface 5,536’ 0.0087
OPEN HOLE / CEMENT DETAIL
24” x Driven 10 yds Cement
12-1/4"Stg 1 –Lead 416 sx / Tail 400 sx
Stg 2 –Lead 701 sx / Tail 270 sx
8-1/2” Uncemented Slotted Liner
TREE & WELLHEAD
Tree Cameron 3 1/8" 5M w/ 3-1/8” 5M Cameron Wing
Wellhead FMC 11” x 4-1/2” Tubing Hanger, 4-1/2” TCII
GENERAL WELL INFO
API#: 50-029-23788-00-00
Completion Date: 6/19/2024
WELL INCLINATION DETAIL
KOP @ 210’
90° Hole Angle = 6,783’ MD
TD =16,580’(MD) / TD =4,202’(TVD)
20”
Orig. KB Elev.:66.15’ / GL Elev.: 32.5’
3-1/2”
6
2
9-5/8”
1
3/4
See
Drilled/
Slotted
Liner
Detail
PBTD = 16,579’(MD) / PBTD = 4,202’(TVD)
9-5/8” ‘ES’
Cementer @
2,426’
5-1/2” x
4-1/2”
5
JEWELRY DETAIL
No Top MD Item
ID
Upper Completion
1 5,218’ Baker Zenith Gauge 2.992”
2 5,275’ XN Nipple, 2.813”, 2.75” No-Go 2.750”
3 5,525’ Locater Sub, 8.25” No Go (bottom of locator spaced out 3.11’) 6.190”
4 5,526’ Bullet Seals – TXP Top Box x Mule Shoe (Bottom @ 5,536’) 6.190”
Lower Completion
5 5,528’ SLZXP Liner Top Packer 6.190”
6 16,579’ Shoe
CAUTION: This email originated from outside the State of Alaska mail system. Do not
click links or open attachments unless you recognize the sender and know the content
is safe.
From:Darci Horner - (C)
To:Regg, James B (OGC); Brooks, Phoebe L (OGC); Wallace, Chris D (OGC)
Cc:Ryan Thompson; Taylor Wellman; Alaska NS - Milne - Wells Foreman; Alaska NS - Milne - Wellsite Supervisors;
Roger Allison; Matthew Ross; Jess Hall; Brian Glasheen; Todd Sidoti; Alaska NS - Milne - Field Operator Leads
Subject:MIT-IA for Milne Point wells I-23, J-43 and M-44
Date:Tuesday, July 2, 2024 12:27:17 PM
Attachments:MIT MPU I-23 6-25-24.xlsx
MIT MPU I-23 6-26-24.xlsx
MIT MPU J-43 6-19-2024.xlsx
MIT MPU M-44 6-25-24.xlsx
All,
Milne Point wells I-23 (PTD #2240120), J-43 (PTD # 2240380), and M-44 (PTD # 2200300)
successfully passed MIT-IAs on June 26, 19, and 25 2024, respectively.
Please note that I-23 was mistakenly tested to 1500 psi before being tested to 2000 psi the
next day so both tests are being submitted.
Please reach myself or Ryan Thompson (907-564-5280) with any questions.
Regards,
Darci Horner
Technologist
Office: (907) 777-8406
Cell: (907) 227-3036
Email: dhorner@hilcorp.com
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the
individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby
notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please
immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the
onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility
is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
0LOQH3RLQW8QLW-
37'
Submit to:
OOPERATOR:
FIELD / UNIT / PAD:
DATE:
OPERATOR REP:
AOGCC REP:
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD 2240380 Type Inj N Tubing 0000 Type TestP
Packer TVD 3807 BBL Pump 17.0 IA 0 3630 3550 3525 Interval O
Test psi 3500 BBL Return 17.0 OA Result P
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes
W = Water P = Pressure Test I = Initial Test P = Pass
G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail
S = Slurry V = Required by Variance I = Inconclusive
I = Industrial Wastewater O = Other (describe in notes)
N = Not Injecting
Notes:
Hilcorp Alaska, LLC
Milne Point / MPU / J
Mark Brouillet
06/19/24
Notes:On rig MIT-IA to 3500 psi per PTD# 224-038. Completion does not have an OA. Witness waived 6/18/24 @ 23:04 by Guy Cook.
Notes:
Notes:
Notes:
J-43
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
MMechanical Integrity Test
jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov
Notes:
Notes:
Notes:
Form 10-426 (Revised 01/2017)2024-0619_MIT_MPU_J-43
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- 5HJJ
David Douglas Hilcorp Alaska, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 07/02/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL:
WELL: MPU J-43
PTD: 224-038
API: 50-029-23788-00-00
FINAL LWD FORMATION EVALUATION + GEOSTEERING (05/31/2024 to 06/14/2024)
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.
224-038
T39105
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.07.03 09:05:17 -08'00'
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-43
Hilcorp Alaska, LLC
Permit to Drill Number: 224-038
Surface Location: 2616' FSL, 3360' FEL, Sec 028, T13N, R10E, UM, AK
Bottomhole Location: 1412' FSL, 2199' FWL, Sec 35, T13N, R10E, UM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well
logs run must be submitted to the AOGCC within 90 days after completion, suspension, or
abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Brett W. Huber, Sr.
Chair, Commissioner
DATED this day of May 2024. 13th
Drilling Manager
04/25/24
Monty M
Myers
By Grace Christianson at 9:57 am, Apr 25, 2024
* BOPE test to 3000 psi. Annular to 2500 psi.
* AOGCC to witness MIT-IA to 3200 psi or maximum power fluid header pressure.
24 hour notice for AOGCC to witness.
* MIT-IA to 2000 psi after 10 days of stabilized injection.
MGR08MAY2024 DSR-4/29/24
50-029-23788-00-00
A.Dewhurst 10MAY24
224-038
JLC 5/13/2024
PTD API WELL STATUSTop of SB NB (MD)Top of SB NB (TVD)Top of Cement (MD)Top of Cement (TVD) Schrader NB statusZonal Isolation190-097 50-029-22072-00-00 MPU J-03SB Injector - Reservoir P&A 4856 3822 Surface Surface Closed9-7/8" hole with 7" casing. Stage 1 pumped 184 bbls perm E and 95 bbls class G w/ no losses.Circulated ~60 bbls off top of ES cementer prior to stage 2.Stage 2 pumped 303 bbls perm E and 34 bbls perm C. 120 bbls circulated to surface. 220-034 50-029-23675-00-00 MPU I-35SB NB Injector- Active 4842 3812 Surface Surface Open9-5/8" Cemented to surface via 2 stage cement jobs with 200 bbls returned to surface. 221-013 50-029-23692-00-00 MPU I-27 SB OA Producer- Active4124 3784 Surface Surface Closed9-5/8" Cemented to surface via 2 stage cement jobs with 255 bbls returned to surface. 220-049 50-029-23679-00-00 MPU I-20 SB OBa Producer- Active4066 3810 Surface Surface Closed9-5/8" Cemented to surface via 2 stage cement jobs with 226 bbls returned to surface. 190-093 50-029-22068-00-00 MPU I-04SB Producer- Sidetracked 4412 3886 2992 2676 Closed7" cemented with 260 sx class G cement. Assuming 20% washout, estimated TOC is 2992'. 190-093 50-029-22068-70-00 MPU I-04PB1 SB Plugback4438 3890 4003 3522 ClosedPilot hole. Pumped 34 bbls 16.7ppg balanced plug. Kickoff assembly tagged at 4,003' MD. 201-092 50-029-22068-01-00 MPU I-04ASB N Sand/OBA (OBA is Horiz) Injector - Active N/A N/A N/A N/A N/A Sidetracked below the NB. 201-092 50-029-22068-71-00 MPU I-04APB1SB OBA plugback N/A N/A N/A N/A N/A Sidetracked below the NB. 201-093 50-029-22068-60-00 MPU I-04AL1SB Oa Horiz injector- Active N/A N/A N/A N/A N/A Sidetracked below the NB. 204-190 50-029-23227-00-00 MPU H-16SB N Sand/OBA Horiz Producer- Active 5800 3893 3855 2976 Closed7-5/8" cemented with 123 bbls Class G cement. Assuming 20% washout, TOC estimated at 3,855' MD. 204-190 50-029-23227-70-00 MPU H-16PB1SB OBA Plugback N/A N/A N/A N/A N/A Sidetracked below the NB. 204-190 50-029-23227-71-00 MPU H-16PB2SB OBA Plugback N/A N/A N/A N/A N/A Sidetracked below the NB. 204-190 50-029-23227-72-00 MPU H-16PB3SB OBA Plugback N/A N/A N/A N/A N/A Sidetracked below the NB. 204-191 50-029-23227-60-00 MPU H-16L1SB Oa Horiz Producer- Active N/A N/A N/A N/A N/A Sidetracked below the NB. 190-091 50-029-22066-00-00 MPU I-02SB N Sands/OA/OBA Injector- Shut in 5740 3921 5450 3700OpenUsit logged cement at 5450' MD190-089 50-029-22064-00-00 MPU H-04SB N Sands/OA/OBA Injector- Shut in 4082 3973 2811 2762Open7" cemented with 211 sacks of class G cement. Assuming 20% washout, TOC estimated at 2,811' MD. 190-088 50-029-22063-00-00 MPU H-03SB N Sands/OA/OBA Producer- Shut in5019 4079 37503130Open7" cemented with 54 bbls class G. Assuming 20% washout, TOC estimated at 3,750' MD. 197-150 50-029-22796-00-00 MPU H-14SB N Sands/OA/OBA Producer- P&A'd5532 3977 Surface SurfaceClosed9-5/8" cemented via 2 stage cement job. Stage 1 pumped 358 bbls and stage 2 pumped 471 bbls with 170 bbls returned to surface.Well is currently P&A's with cement to surface in 9-5/8'' casing.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 returned to surface during stage 2. H-13A was abandoned in 2015.190-087 50-029-22062-00-00 MPU H-02SB N Sands/OA/OBA Producer- Reservoir P&A'd5640 3986 4500 3219 Closed7" cemented with 386 sx class G cement. Assuming 20% washout, estimated TOC is 3400'. Well file notes an estimated TOC at 4,500' MD. 197-117 50-029-22779-00-00 MPU G-09SB N Sands/OA/OBA Injector- Active7855 4050 Surface Surface Open7" cemented to surface via 2 stage cement job. The daily drilling reports reported cement returns to surface during stage 2.197-170 50-029-22807-00-00 MPU H-12SB N Sands/OA/OBA Producer- P&A'd7896 4095 Surface Surface Closed7" cemented to surface via 2 stage cement job. The daily drilling reports reported cement circulated to surface off the ES cementer and cement returns to surface during stage 2.221-044 50-029-23694-00-00 MPU S-44SB NB Horiz Injector- Active5161 4106Surface SurfaceOpen9-5/8" cemented to surface via 2 stage cement job. 230 bbls returned to surface. Area of Review MPU J-43 SB NB
202-19550-029-23119-00-00 MPU S-29 SB OBA Horiz Producer- Shut in 7863 4013 Surface Surface ClosedPumped 1351 bbls 10.7ppg lead cement, 123 bbls 15.8ppg tail cement. Lost returns 1300 bbls into lead. Performed top job and found green cement at 110' prior to top job. Pumped 34 bbls 10.7ppg lead.202-196 50-029-23119-60-00 MPU S-29L1SB OA Horiz Producer- Shut in N/A N/A N/A N/A N/A See S-2950-029-232-84-00-00 MPU H-15SB N Sand/Oa/OBa Horiz Injector- Shut In 4298 3920 3307 3092 Open 7" top of cement logged at 3,307' MD via USIT in 2005. 50-029-231-06-00-00 MPU I-15SB N Sand/OBA Horiz Producer- Active 4516 3837 2678 2427 Open7" cemented with 189 sacks of 12ppg lead and 84 sacks of 15.8ppg tail. The job was pumped with full returns. Assuming 20% washout, the calculated TOC is 2,678' MD. 50-029-231-06-60-00 MPU I-15PB1SB OBA Plugback N/A N/A N/A N/A N/A Sidetracked below the NB. 50-029-231-06-70-00 MPU I-15L1SB Oa Horiz Producer- Active 4516 3837 2678 2427 Open7" cemented with 189 sacks of 12ppg lead and 84 sacks of 15.8ppg tail. The job was pumped with full returns. Assuming 20% washout, the calculated TOC is 2,678' MD. 50-029-233-71-60-00 MPU H-19L1SB Oa Horiz Producer- Active N/A N/A N/A N/A Closed Sidetracked below the NB. 50-029-233-71-00-00 H-19SB All zones, never perfed, collected pressure samples 6677 4083 3957 2980 ClosedThe 7-5/8" was cemented with 170 bbls of 15.8ppg cement inside 9-7/8" hole. The daily report does not mention any losses during the job. Assuming 20% washout, the TOC is estimated at 3,957' MD. TBDTBD MPU J-44Future NB Horizontal Producer TBD TBD TBD TBD Will be Open Not drilled yetTBDTBD MPU J-42Future NB Horizontal Producer TBD TBD TBD TBD Will be Open Not drilled yet
PTD API WELLSTATUSTop of SBNB (MD)Top of SBNB (TVD)Top ofCement(MD)Top ofCement(TVD)Schrader NBstatusZonal Isolation190-097 50-029-22072-00-00 MPU J-03SB Injector - Reservoir P&A 4856 3822 Surface Surface Closed9-7/8" hole with 7" casing.Stage 1 pumped 184 bbls perm E and 95 bbls class G w/ no losses.Circulated ~60 bbls off top of ES cementer prior to stage 2.Stage 2 pumped 303 bbls perm E and 34 bbls perm C. 120 bbls circulated tosurface.220-034 50-029-23675-00-00 MPU I-35SB NB Injector- Active 4842 3812 Surface Surface Open9-5/8" Cemented to surface via 2 stage cement jobs with 200 bbls returnedto surface.221-013 50-029-23692-00-00 MPU I-27 SB OA Producer- Active4124 3784 Surface Surface Closed9-5/8" Cemented to surface via 2 stage cement jobs with 255 bbls returnedto surface.220-049 50-029-23679-00-00 MPU I-20 SB OBa Producer- Active4066 3810 Surface Surface Closed9-5/8" Cemented to surface via 2 stage cement jobs with 226 bbls returnedto surface.190-093 50-029-22068-00-00 MPU I-04SB Producer- Sidetracked 4412 3886 2992 2676 Closed7" cemented with 260 sx class G cement. Assuming 20% washout,estimated TOC is 2992'.190-093 50-029-22068-70-00 MPU I-04PB1 SB Plugback4438 3890 4003 3522 ClosedPilot hole. Pumped 34 bbls 16.7ppg balanced plug. Kickoff assembly taggedat 4,003' MD.201-092 50-029-22068-01-00 MPU I-04ASB N Sand/OBA (OBA is Horiz)Injector - Active N/A N/A N/A N/A N/A Sidetracked below the NB.201-092 50-029-22068-71-00 MPU I-04APB1SB OBA plugback N/A N/A N/A N/A N/A Sidetracked below the NB.201-093 50-029-22068-60-00 MPU I-04AL1SB Oa Horiz injector- Active N/A N/A N/A N/A N/A Sidetracked below the NB.204-190 50-029-23227-00-00 MPU H-16SB N Sand/OBA Horiz Producer-Active 5800 3893 3855 2976 Closed7-5/8" cemented with 123 bbls Class G cement. Assuming 20% washout,TOC estimated at 3,855' MD.204-190 50-029-23227-70-00 MPU H-16PB1SB OBA Plugback N/A N/A N/A N/A N/A Sidetracked below the NB.204-190 50-029-23227-71-00 MPU H-16PB2SB OBA Plugback N/A N/A N/A N/A N/A Sidetracked below the NB.204-190 50-029-23227-72-00 MPU H-16PB3SB OBA Plugback N/A N/A N/A N/A N/A Sidetracked below the NB.204-191 50-029-23227-60-00 MPU H-16L1SB Oa Horiz Producer- Active N/A N/A N/A N/A N/A Sidetracked below the NB.190-091 50-029-22066-00-00 MPU I-02SB N Sands/OA/OBA Injector- Shutin 5740 3921 5450 3700OpenUsit logged cement at 5450' MD190-089 50-029-22064-00-00 MPU H-04SB N Sands/OA/OBA Injector- Shutin 4082 3973 2811 2762Open7" cemented with 211 sacks of class G cement. Assuming 20% washout,TOC estimated at 2,811' MD.190-088 50-029-22063-00-00 MPU H-03SB N Sands/OA/OBA Producer- Shutin5019 4079 37503130Open7" cemented with 54 bbls class G. Assuming 20% washout, TOC estimatedat 3,750' MD.197-150 50-029-22796-00-00 MPU H-14SB N Sands/OA/OBA Producer-P&A'd5532 3977 Surface SurfaceClosed9-5/8" cemented via 2 stage cement job. Stage 1 pumped 358 bbls andstage 2 pumped 471 bbls with 170 bbls returned to surface.Well is currently P&A's with cement to surface in 9-5/8'' casing.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 2015.190-087 50-029-22062-00-00 MPU H-02SB N Sands/OA/OBA Producer-Reservoir P&A'd5640 3986 4500 3219 Closed7" cemented with 386 sx class G cement. Assuming 20% washout,estimated TOC is 3400'. Well file notes an estimated TOC at 4,500' MD.197-117 50-029-22779-00-00 MPU G-09SB N Sands/OA/OBA Injector- Active7855 4050 Surface Surface Open7" cemented to surface via 2 stage cement job. The daily drilling reportsreported cement returns to surface during stage 2.197-170 50-029-22807-00-00 MPU H-12SB N Sands/OA/OBA Producer-P&A'd7896 4095 Surface Surface Closed7" cemented to surface via 2 stage cement job. The daily drilling reportsreported cement circulated to surface off the ES cementer and cementreturns to surface during stage 2.Area of Review MPU J-43 SB NBSuperseded by updated AOR list. -A.Dewhurst 10MAY2024
71MPU I-04PB1MPU I-04APB170
221-044 50-029-23694-00-00 MPU S-44SB NB Horiz Injector- Active5161 4106Surface SurfaceOpen9-5/8" cemented to surface via 2 stage cement job. 230 bbls returned tosurface.202-19550-029-23119-00-00 MPU S-29SB OBA Horiz Producer- Shut in 7863 4013 Surface Surface ClosedPumped 1351 bbls 10.7ppg lead cement, 123 bbls 15.8ppg tail cement. Lostreturns 1300 bbls into lead.Performed top job and found green cement at 110' prior to top job.Pumped 34 bbls 10.7ppg lead.202-196 50-029-23119-60-00 MPU S-29L1SB OA Horiz Producer- Shut in N/A N/A N/A N/A N/A See S-29TBDTBD MPU J-44Future NB Horizontal Producer TBD TBD TBD TBD Will be Open Not drilled yetTBDTBD MPU J-42Future NB Horizontal Producer TBD TBD TBD TBD Will be Open Not drilled yet
Superseded by updated AOR list. -A.Dewhurst 10MAY2024
Milne Point Unit
(MPU) J-43
Application for Permit to Drill
Version 1
4/10/2024
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 N/U BOP and Test.................................................................................................................... 28
15.0 Drill 8-1/2 Hole Section .......................................................................................................... 29
16.0 Run 5-1/2 x 4-1/2 Injection Liner (Lower Completion) ...................................................... 34
17.0 Run 3-1/2 Tubing (Upper Completion) ................................................................................. 39
18.0 RDMO ...................................................................................................................................... 40
19.0 Post-Rig Work ......................................................................................................................... 41
20.0 Doyon 14 Diverter Schematic .................................................................................................. 42
21.0 Doyon 14 BOP Schematic ........................................................................................................ 43
22.0 Wellhead Schematic ................................................................................................................. 44
23.0 Days Vs Depth .......................................................................................................................... 45
24.0 Formation Tops & Information............................................................................................... 46
25.0 Anticipated Drilling Hazards .................................................................................................. 47
26.0 Doyon 14 Layout ...................................................................................................................... 50
27.0 FIT Procedure .......................................................................................................................... 51
28.0 Doyon 14 Choke Manifold Schematic ..................................................................................... 52
29.0 Casing Design ........................................................................................................................... 53
30.0 8-1/2 Hole Section MASP ....................................................................................................... 54
31.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 55
32.0 Surface Plat (As-Built) (NAD 27) ............................................................................................ 56
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1.0 Well Summary
Well MPU J-43
Pad Milne Point I Pad
Planned Completion Type 3-1/2 Injection Tubing
Target Reservoir(s) Schrader Bluff NB Sand
Planned Well TD, MD / TVD 16,627 MD / 4,140 TVD
PBTD, MD / TVD 16,627 MD / 4,140 TVD
Surface Location (Governmental) 2616' FSL, 3360' FEL, Sec. 28, T13N, R10E, UM, AK
Surface Location (NAD 27) X= 551958 Y= 6015014
Top of Productive Horizon
(Governmental)804' FNL, 2467' FEL, Sec 33, T13N, R10E, UM, AK
TPH Location (NAD 27) X= 552883 Y= 6011599
BHL (Governmental) 1412' FSL, 2199' FEL, Sec 35, T13N, R10E, UM, AK
BHL (NAD 27) X= 562857 Y=6008614
AFE Drilling Days 21 days
AFE Completion Days 3 days
Maximum Anticipated Pressure
(Surface) 1321 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 1709 psig
Work String 5 19.5# S-135 DS-50 & NC 50
KB Elevation above MSL: 33.7 ft + 32.4 ft = 66.1 ft
GL Elevation above MSL: 32.4 ft
BOP Equipment 13-5/8 x 5M Annular, (3) ea 13-5/8 x 5M Rams
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2.0 Management of Change Information
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3.0 Tubular Program:
Hole
Section
OD (in)ID
(in)
Drift
(in)
Conn OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 20 19.25 - - - X-52 Weld
12-1/49-5/8 8.681 8.525 10.625 47 L-80 TXP 6,870 4,750 1,086
9-5/8 8.835 8.67910.62540 L-80 TXP 5,750 3,090 916
8-1/25-1/2 4.892 4.767 6.050 17 L-80 JFE Bear 7,740 6,290 397
4-1/2 3.9603.795 4.714 13.5 L-80 H625 9020 8540 279
Tubing 3-1/2 2.992 2.867 4.500 9.3 L-80
EUE 8RD 9289 7399 163
4.0 Drill Pipe Information:
Hole
Section
OD
(in)
ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn M/U
(Min)
M/U
(Max)
Tension
(k-lbs)
Surface &
Production
54.276 3.25 6.625 19.5 S-135 GPDS50 36,100 43,100 560
54.276 3.25 6.625 19.5 S-135 NC50 31,032 34,136 560
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
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5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on WellEz.
Report covers operations from 6am to 6am
Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left
of the data entry area this will not save the data entered, and will navigate to another data entry.
Ensure time entry adds up to 24 hours total.
Try to capture any out of scope work as NPT. This helps later on when we pull end of well
reports.
Enter the MD and TVD depths EVERY DAY whether you are making hole or not.
5.2 Afternoon Updates
Submit a short operations update each work day to mmyers@hilcorp,
nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com
5.3 Intranet Home Page Morning Update
Submit a short operations update each morning by 7am on the company intranet homepage. On
weekend and holidays, ensure to have this update in before 5am.
5.4 EHS Incident Reporting
Health and Safety: Notify EHS field coordinator.
Environmental: Drilling Environmental Coordinator
Notify Drilling Manager & Drilling Engineer on all incidents
Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
Send final As-Run Casing tally to nathan.sperry@hilcorp.com and
joseph.lastufka@hilcorp.com
5.6 Casing and Cement report
Send casing and cement report for each string of casing to mmyers@hilcorp.com
nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com
5.7 Hilcorp Milne Point Contact List:
Title Name Work Phone Email
Drilling Manager Monty Myers 907.777.8431 mmyers@hilcorp.com
Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com
Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com
Completion Engineer Brian Glasheen 907.564.5277 Brian.glasheen@hilcorp.com
Geologist Katie Cunha 907.564.4786 Katharine.cunha@hilcorp.com
Reservoir Engineer Almas Aitkulov 907.564.4250 aaitkulov@hilcorp.com
EHS Director Laura Green 907.777.8314 lagreen@hilcorp.com
Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com
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6.0 Planned Wellbore Schematic
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7.0 Drilling / Completion Summary
MPU J-43 is a grassroots injector planned to be drilled in the Schrader Bluff NB sand. J-43 is part of a multi
well program targeting the Schrader Bluff sand on J-pad. J-43 will be pre-produced for 30 days.
The directional plan is a horizontal well with 12-1/4 surface hole with 9-5/8 surface casing set into the top
of the Schrader Bluff 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 June 6th, 2024, pending rig schedule.
Surface casing will be run to 6,080 MD / 3,884 TVD and cemented to surface via a 2 stage primary cement
job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed,
necessary remedial action will be discussed with AOGCC authorities.
All cuttings & mud generated during drilling operations will be hauled to the Milne Point B pad G&I facility.
General sequence of operations:
1. MIRU Doyon 14 to well site
2. N/U & Test 21-1/4 Diverter and 16 diverter line
3. Drill 12-1/4 hole to TD of surface hole section. Run and cement 9-5/8 surface casing
4. N/D diverter, N/U & test 13-5/8 x 5M BOP. Install MPD Riser
5. Drill 8-1/2 lateral to well TD.
6. Run 4-1/2 injection liner.
7. Run 3-1/2 tubing.
8. N/D BOP, N/U Tree, RDMO.
Reservoir Evaluation Plan:
1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res
2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering)
p
J-43 will be pre-produced for 30 days
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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.
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.
BOPs shall be tested at (2) week intervals during the drilling and completion of MPU J-43. Ensure
to provide AOGCC 24 hrs notice prior to testing BOPs.
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.
If the BOP is used to shut in on the well in a well control situation or control fluid flow from the
well bore, AOGCC is to be notified and we must test all BOP components utilized for well control
prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP
test.
All AOGCC regulations within 20 AAC 25.033 Primary well control for drilling: drilling fluid
program and drilling fluid system.
All AOGCC regulations within 20 AAC 25.035 Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements.
o Ensure the diverter vent line is at least 75 away from potential ignition sources
Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,A casing pressure test
must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a
minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test
pressure must show stabilizing pressure and may not decline more than 10 percent within 30
minutes. The results of this test and any subsequent tests of the casing must be recorded as required
by 20 AAC 25.070(1).
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AOGCC Regulation Variance Requests:
1) None
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Summary of BOP Equipment & Notifications
Hole Section Equipment Test Pressure (psi)
12 1/421-1/4 2M Diverter w/ 16 Diverter Line Function Test Only
8-1/2
13-5/8 x 5M Hydril GK Annular BOP
13-5/8 x 5M Hydril MPL Double Gate
o Blind ram in btm cavity
Mud cross w/ 3 x 5M side outlets
13-5/8 x 5M Hydril MPL Single ram
3-1/8 x 5M Choke Line
3-1/8 x 5M Kill line
3-1/8 x 5M Choke manifold
Standpipe, floor valves, etc
Initial Test: 250/3000
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:
Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
24 hours notice prior to spud.
24 hours notice prior to testing BOPs.
24 hours notice prior to casing running & cement operations.
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-43 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 (<80 F).
9.10 Ensure 6 liners in mud pumps.
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).
N/U 16-3/4 3M x 21-1/4 2M DSA on 16-3/4 3M wellhead.
N/U 21-1/4 diverter T.
Knife gate, 16 diverter line.
Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
Diverter line must be 75 ft from nearest ignition source
Place drip berm at the end of diverter line.
10.2 Notify AOGCC. Function test diverter.
Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens
prior to annular closure.
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:
A prohibition on vehicle parking
A prohibition on ignition sources or running equipment
A prohibition on staged equipment or materials
Restriction of traffic to essential foot or vehicle traffic only.
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10.4 Rig & Diverter Orientation:
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:
Ensure BHA components have been inspected previously.
Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
Use GWD until MWD surveys are clean.
Ensure TF offset is measured accurately and entered correctly into the MWD software.
Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
Drill string will be 5 19.5# S-135.
Run a solid float in the surface hole section.
11.2 Begin drilling out from 20 conductor at reduced flow rates to avoid broaching the conductor.
Consider using a trash bit to clean out conductor to mitigate potential damage from debris in
conductor.
11.3 Drill 12-1/4 hole section to section TD in the Schrader NB sand. Confirm this setting depth with
the Geologist and Drilling Engineer while drilling the well.
Monitor the area around the conductor for any signs of broaching. If broaching is observed,
Stop drilling (or circulating) immediately notify Drilling Engineer.
Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100.
Hold a safety meeting with rig crews to discuss:
Conductor broaching ops and mitigation procedures.
Well control procedures and rig evacuation
Flow rates, hole cleaning, mud cooling, etc.
Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
Keep mud as cool as possible to keep from washing out permafrost.
Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can
handle the flow rate.
Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoffs, increase in pump pressure, or changes in hookload are seen
Slow in/out of slips and while tripping to keep swab and surge pressures low
Ensure shakers are functioning properly. Check for holes in screens on connections.
Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea
gravel, clay balling or packing off.
Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2
minimum at TD (pending MW increase due to hydrates).
Drill ahead using GWD. Take MWD surveys every stand drilled and swap to MWD when
MWD surveys clean up.
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:
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Gas hydrates can be identified by the gas detector and a decrease in MW or ECD
Monitor returns for hydrates, checking pressurized & non-pressurized scales
Do not stop to circulate out gas hydrates this will only exacerbate the problem by
washing out additional permafrost. Attempt to control drill (150 fph MAX) through the
zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be
reduced to prevent mud from belching over the bell nipple.
Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well.
MW will not control gas hydrates, but will affect how gas breaks out at surface.
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 drillers console, Co Man office, Toolpusher office, and mud
loggers office.
Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but
reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared
to increase the YP if hole cleaning becomes an issue.
Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total)
can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore.
Wellbore and mud stability:Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to
reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of
the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 9.0 range with
caustic soda. Daily additions of ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action.
Casing Running:Reduce system YP with DESCO as required for running casing as allowed (do not
jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the
system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value
they have targeted).
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System Type:8.8 9.2 ppg Pre-Hydrated Aquagel/freshwater spud mud
Properties:
Section Density Viscosity Plastic
Viscosity Yield Point API FL pH
Temp
Surface 8.8 9.8 75-175 20 - 40 25-45 <10 8.5 9.0 70 F
System Formulation: Gel + FW spud mud
Product- Surface hole Size Pkg ppb or (% liquids)
M-I Gel 50 lb sx 25
Soda Ash 50 lb sx 0.25
PolyPac Supreme UL 50 lb sx 0.08
Caustic Soda 50 lb sx 0.1
SCREENCLEEN 55 gal dm 0.5
11.4 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity.
11.5 RIH to bottom, proceed to BROOH to HWDP
Pump at full drill rate (400-600 gpm), and maximize rotation.
Pull slowly, 5 10 ft / minute.
Monitor well for any signs of packing off or losses.
Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay
balling.
If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until
parameters are restored.
11.6 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)
Ensure 9-5/8 TXP x NC50 XO on rig floor and M/U to FOSV.
Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
R/U of CRT if hole conditions require.
R/U a fill up tool to fill casing while running if the CRT is not used.
Ensure all casing has been drifted to 8-1/2 on the location prior to running.
Note that 47# drift is 8.525
Be sure to count the total # of joints on the location before running.
Keep hole covered while R/U casing tools.
Record ODs, IDs, lengths, S/Ns 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
Ensure bypass baffle is correctly installed on top of float collar.
Ensure proper operation of float equipment while picking up.
Ensure to record S/Ns 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
Fill casing while running using fill up line on rig floor.
Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
Centralization:
1 centralizer every joint to ~ 1000 MD from shoe
1 centralizer every 2 joints to ~2,000 above shoe (Top of Lowest Ugnu)
Utilize a collar clamp until weight is sufficient to keep slips set properly.
Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
Any packing off while running casing should be treated as a major problem. It is preferable
to POH with casing and condition hole than to risk not getting cement returns to surface.
12.6 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100 TVD below
the permafrost.
Install centralizers over couplings on 5 joints below and 5 joints above stage tool.
Do not place tongs on ES cementer, this can cause damage to the tool.
Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi.
9-5/8 40# L-80 TXP Make-Up Torques:
Casing OD Minimum Optimum Maximum
9-5/818,860 ft-lbs 20,960 ft-lbs 23,060 ft-lbs
9-5/8 47# L-80 TXP MUT:
Casing OD Minimum Optimum Maximum
9-5/821,440 ft-lbs 23,820 ft-lbs 26,200 ft-lbs
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12.7 Continue running 9-5/8 surface casing
Centralizers: 1 centralizer every 3rd joint to 200 from surface
Fill casing while running using fill up line on rig floor.
Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
Centralization:
o 1 centralizer every 2 joints to base of conductor
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12.8 Ensure the permafrost is covered with 9-5/8 47# from BPRF to surface
Ensure drifted to 8.525
12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.10 Slow in and out of slips.
12.11 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10 from TD. Strap the
landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference
when getting the casing on depth.
12.12 Lower casing to setting depth. Confirm measurements.
12.13 Have slips staged in cellar along with all necessary equipment for the operation.
12.14 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement
job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible
reciprocate casing string while conditioning mud.
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13.0 Cement 9-5/8 Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
Ensure adequate amount of water for mix fluid is heated and available in the water tanks.
Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
Review test reports and ensure pump times are acceptable.
Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
13.2 Document efficiency of all possible displacement pumps prior to cement job.
13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
13.5 Fill surface cement lines with water and pressure test.
13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.7 Drop bottom plug (flexible bypass plug) HEC rep to witness. Mix and pump cement per below
calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached.
13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead &
tail, TOC brought to stage tool.
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Estimated 1st Stage Total Cement Volume:
Cement Slurry Design (1st Stage Cement Job):
13.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets sticky, cease pipe reciprocation and continue
with the cement job.
13.10 After pumping cement, drop top plug (shutoff plug) and displace cement with spud mud out of
mud pits, spotting water across the HEC stage cementer.
a. Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
13.11 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the plug
must be bumped.
13.12 Displacement calculation is in the Stage 1 Table in step 13.7.
80 bbls of tuned spacer to be left on top of stage tool so that the first fluid through the
ES cementer is tuned spacer to minimize the risk of flash setting cement
13.13 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any
point during the job. Be prepared to pump out fluid from cellar. Have black water available to
contaminate any cement seen at surface.
13.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Over
displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling
Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up
option to open the stage tool if the plugs are not bumped.
Lead Slurry Tail Slurry
System EconoCem HalCem
Density 12.0 lb/gal 15.8 lb/gal
Yield 2.35 ft3/sk 1.16 ft3/sk
Mix Water 13.92 gal/sk 4.98 gal/sk
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13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened.
13.16 Increase pressure to 3300 psi to open circulating ports in stage collar. Slightly higher pressure
may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns
to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation
for the 2nd stage of the cement job.
13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker
bypass line to the cuttings tank. Have black water available and vac trucks ready to assist.
Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact
with the cement.
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Second Stage Surface Cement Job:
13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive
strength. Hold pre-job safety meeting.
13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing
head.
13.20 Fill surface lines with water and pressure test.
13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.22 Mix and pump cmt per below recipe for the 2
nd stage.
13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail).
Job will consist of lead & tail, TOC brought to surface. However cement will continue to be
pumped until clean spacer is observed at surface.
Estimated 2nd Stage Total Cement Volume:
Cement Slurry Design (2nd stage cement job):
13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail.
13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out
of mud pits.
13.26 Displacement is in the Stage 2 table in step 13.23.
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 wellez:
Pre flush type, volume (bbls) & weight (ppg)
Cement slurry type, lead or tail, volume & weight
Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
Note if casing is reciprocated or rotated during the job
Calculated volume of displacement, actual displacement volume, whether plug bumped & bump
pressure, do floats hold
Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
Note if pre flush or cement returns at surface & volume
Note time cement in place
Note calculated top of cement
Add any comments which would describe the success or problems during the cement job
Send final As-Run casing tally & casing and cement report to 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 N/U BOP 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:
BOP configuration from top down: 13-5/8 x 5M annular / 13-5/8 x 5M double gate / 13-
5/8 x 5M mud cross / 13-5/8 x 5M single gate
Double gate ram should be dressed with 2-7/8 x 5 VBRs in top cavity,blind ram in
bottom cavity.
Single ram can be dressed with 2-7/8 x 5 VBRs
N/U bell nipple, install flowline.
Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to
mud cross).
Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual
valve
14.3 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.
Test 2-7/8 x 5 rams with the 3-1/2 and 5 test joints
Confirm test pressures with PTD
Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure
is trapped underneath test plug
Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech
14.5 R/D BOP test equipment
14.6 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.7 Mix 8.9 ppg FloPro NT fluid for production hole.
14.8 Set wearbushing in wellhead.
14.9 If needed, rack back as much 5 DP in derrick as possible to be used while drilling the hole
section.
14.10 Ensure 6 liners in mud pumps.
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15.0 Drill 8-1/2 Hole Section
15.1 M/U 8.5 Cleanout BHA (Milltooth Bit & 1.22° PDM)
15.2 TIH w/ 8-1/2 cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out
stage tool.
15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report.
15.4 R/U and test casing to 2500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and
plot on FIT graph. AOGCC reg is 50% of burst = 5750 / 2 = ~2875 psi, but max test pressure on
the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent
pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry
Guidance Bulletin 17-001.
15.5 Drill out shoe track and 20 of new formation.
15.6 CBU and condition mud for FIT. Pump at least one high vis sweep at maximum rate to surface to
clean up debris.
15.7 Conduct FIT to 12.0 ppg EMW. Chart test. Ensure test is recorded on same chart as FIT.
Document incremental volume pumped (and subsequent pressure) and volume returned.
12.0 ppg desired to cover shoe strength for expected ECDs. A 9.9 ppg FIT is the minimum
required to drill ahead
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.
Ensure BHA components have been inspected previously.
Drift and caliper all components before M/U. Visually verify no debris inside components that
cannot be drifted.
Ensure TF offset is measured accurately and entered correctly into the MWD software.
Ensure MWD is R/U and operational.
Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
Drill string will be 5 19.5# S-135 DS50 & NC50.
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
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15.10 8-1/2 hole section mud program summary:
Density: Weighting material to be used for the hole section will be calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg
above highest anticipated MW.
Solids Concentration: It is imperative that the solids concentration be kept low while
drilling the production hole section. Keep the shaker screen size optimized and fluid
running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure
we are running the finest screens possible.
Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests
excessive viscosifier concentrations can decrease return permeability. Do not pump high
vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for
sufficient hole cleaning
Run the centrifuge continuously while drilling the production hole, this will help with
solids removal.
Dump and dilute as necessary to keep drilled solids to an absolute minimum.
MD Totco PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the drillers 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:
Product- production Size Pkg ppb or (% liquids)
Busan 1060 55 gal dm 0.095
FLOTROL 55 lb sx 6
CONQOR 404 WH (8.5 gal/100 bbls)55 gal dm 0.2
FLO-VIS PLUS 25 lb sx 0.7
KCl 50 lb sx 10.7
SMB 50 lb sx 0.45
LOTORQ 55 gal dm 1.0
SAFE-CARB 10 (verify)50 lb sx 10
SAFE-CARB 20 (verify)50 lb sx 10
Soda Ash 50 lb sx 0.5
15.11 TIH with 8-1/2 directional assembly to bottom
15.12 Displace wellbore to 8.9 ppg FloPro drilling fluid
15.13 Begin drilling 8-1/2 hole section, on-bottom staging technique:
Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k.
Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations
If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to 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.
Flow Rate: 350-550 gpm, target min. AVs 200 ft/min, 385 gpm
RPM: 120+
Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly
wet to maximize solids removal efficiency. Check for holes in screens on every connection.
Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
Monitor Torque and Drag with pumps on every stand (confirm frequency with co man)
Monitor ECD, pump pressure & hookload trends for hole cleaning indication
Surveys can be taken more frequently if deemed necessary.
Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible and avoid stopping with the
BHA across the sand for any extended period of time.
Use ADR to stay in section.
Limit maximum instantaneous ROP to < 250 fph. The sands will drill faster than this, but
when concretions are hit when drilling this fast, cutter damage can occur.
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Target ROP is as fast as we can clean the hole (under 250 fph) without having to backream
connections
Watch for higher than expected pressure. MPD will be utilized to monitor pressure build up
on connections
8-1/2 Lateral A/C:
All wells have a clearance factor >1.0.
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.
Patience is key! Getting kicked off too quickly might have been the cause of failed liner
runs on past wells.
If a known fault is coming up, put a slight kick-off ramp in wellbore ahead of the fault so
we have a nice place to low side.
Attempt to sidetrack low and right in a fast drilling interval where the wellbore is headed up.
Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working
string back and forth. Trough for approximately 30 minutes.
Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the
openhole sidetrack is achieved.
15.16 At TD, CBU (minimum 4X, more if needed) at 200 ft/min AV (385+ gpm) and rotation (120+
rpm). Pump tandem sweeps if needed
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.
Monitor BU for increase in cuttings. Cuttings in laterals will come back in waves and not a
consistent stream so circulate more if necessary
If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum
15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP
pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter
cake and calcium carbonate. Circulate the well clean.
Losses during the cleanup of the wellbore are a good indication that the mud filter cake is
being removed, including an increase in the loss rate.
15.18 Displace 1.5 OH + Liner volume with viscosified brine.
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%
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Drilling Procedure
Lube 776: 1.5%
Soda Ash: as needed for 9.5pH
Busan 1060: 0.42 ppb
Flo-Vis Plus: 1.25 ppb
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.
Circulate at full drill rate unless losses are seen (350 gpm minimum if on losses)
Rotate at maximum rpm that can be sustained.
Target pulling speed of 5 10 min/std (slip to slip time, not including connections), but
adjust as hole conditions dictate.
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
Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to
determine if well is breathing, treat all flow as an influx until proven otherwise
If necessary, increase MW at shoe for any higher than expected pressure seen
Ensure fluid coming out of hole has passed a PST at the possum belly
15.22 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball
drops.
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16.0 Run 5-1/2 x 4-1/2 Injection Liner (Lower Completion)
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:
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.
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 VBRs 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.
Ensure 5-1/2 and 4-1/2 Hydril 625 x DS-50 crossovers are on rig floor and M/U to FOSV.
Ensure the liner has been drifted on the deck prior to running.
Be sure to count the total # of joints on the deck before running.
Keep hole covered while R/U casing tools.
Record ODs, IDs, lengths, S/Ns of all components w/ vendor & model info.
16.4. Run 5-1/2 x 4-1/2 injection liner.
Injection liner will be a combination of slotted and solid joints. Every third joint in the open
hole is to be a slotted joint. Confirm with OE.
Make up the lower 9,500 of 4-1/2 and make up the remainder with 5-1/2.
Use API Modified or Best O Life 2000 AGthread compound. Dope pin end only w/ paint
brush. Wipe off excess. Thread compound can plug the screens
Utilize a collar clamp until weight is sufficient to keep slips set properly.
Use lift nubbins and stabbing guides for the liner run.
Obtain up and down weights of the liner before entering open hole. Record rotating torque at
10 and 20 rpm
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5-1/2 17# L-80 JFE Bear
Casing OD Minimum Optimum Maximum
Operating Torque
5.5 6,660 ft-lbs 7,400 ft-lbs 8,140 ft-lbs
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Drilling Procedure
4-1/2 13.5# L-80 H625
Casing OD Minimum Optimum Maximum
Operating Torque
4.5 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs
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16.6. Ensure that the liner top packer is set ~150 MD above the 9-5/8 shoe.
AOGCC regulations require a minimum 100 overlap between the inner and outer strings as
per 20 AAC 25.030(d)(6). Ensure hanger/packer will not be set in a 9-5/8 connection.
16.7. Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck
to make sure it coincides with the pipe tally.
16.8. M/U Baker SLZXP liner top packer to 4-1/2 liner.
16.9. Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner
hanger to ensure a clear flow path exists.
16.10. RIH with liner no faster than 30 ft/min this is to prevent buckling the liner and drill string and
weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and
avoid surging the hole or buckling the liner. Slow down running speed if necessary.
Ensure 5 DP/HWDP has been drifted
There is no inner string planned to be run, as opposed to previous wells. The DP should auto
fill. Monitor FL and if filling is required due to losses/surging.
16.11. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe
depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to
bottom.
16.12. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
& 20 RPM.
16.13. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
16.14. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
16.15. Rig up to pump down the work string with the rig pumps.
16.16. Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed
1,600 psi while circulating.Pusher tool is set at 2,100 psi with 5% shear screws but it should be
discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker
16.17. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill
pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger.
16.18. Shut down pumps. Drop setting ball down the workstring and pump slowly (1-2 BPM). Slow
pump before the ball seats. Do not allow ball to slam into ball seat.
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Drilling Procedure
16.19. Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes.
Slack off 20K lbs on the SZXP liner hanger/packer to ensure the HRDE setting tool is in
compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi
to release the HRDE running tool.
16.20. Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without
pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20
RPM and set down 50K again.
16.21. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted.
16.22. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If
packer did not test, rotating dog sub can be used to set packer. If running tool cannot be
hydraulically released, apply LH torque to mechanically release the setting tool.
16.23. PU pulling running tool free of the packer and displace with at max rate to wash the liner top.
Pump sweeps as needed.
16.24. POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned,
LD DP on the TOOH.
Note: Once running tool is LD, swap to the completion AFE.
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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.
Ensure wear bushing is pulled.
Ensure 3-½ EUE 8RD x NC-50 crossover is on rig floor and M/U to FOSV.
Ensure all tubing has been drifted in the pipe shed prior to running.
Be sure to count the total # of joints in the pipe shed before running.
Keep hole covered while R/U casing tools.
Record ODs, IDs, lengths, S/Ns of all components w/ vendor & model info.
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
3-½ Baker Ported Bullet Nose seal (stung into the tie back receptacle)
3 joints (minimum, more as needed) 3-½ 9.3#/ft, L-80 EUE 8RD tubing
3-½ XN nipple at TBD (Set below 70 degrees)
1 joint 3-½ 9.3#/ft, L-80 EUE 8RD tubing
3-½ SGM-FS XDPG Gauge at TBD
1 joint 3-½ 9.3#/ft, L-80 EUE 8RD tubing
3-1/2 Sliding sleeve TBD
3-½ 9.3#/ft, L-80 EUE 8RD tubing
3-½ 9.3#/ft, L-80 EUE 8RD space out pups
1 joint 3-½ 9.3#/ft, L-80 EUE 8RD tubing
Tubing hanger with 3-1/2 EUE 8RD pin down
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Drilling Procedure
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.
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
19.1 POI
19.2 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-43 Formations TVD
(ft)
TVDss
(ft)
MD
(ft)
Formation Pressure
(psi)
EMW
(ppg)
BPRF 1920 1854 2255 845 8.46
SV1 2115 2049 2557 930 8.46
UG4 3343 3277 4473 1471 8.46
UG_MB 3563 3497 4867 1567 8.46
SCHRADER NB 3788 3722 5431 1666 8.46
SCHRADER NB 3883 3817 6070 1708 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
behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but
can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of
the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching.
Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate
formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud
circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized
mud scale. The non-pressurized scale will reflect the actual mud cut weight. Isolate/dump
contaminated fluid to remove hydrates from the system.
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize
solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs
to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is
critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to
avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide
intervals. Do not out drill our ability to clean the hole.
Anti-Collison:
There are a number of wells in close proximity. Take directional surveys every stand, take additional
surveys if necessary. Continuously monitor proximity to offset wellbores and record any close
approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in
adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Well
specific A/C:
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.
H2S:
Page 48
Milne Point Unit
J-43 SB Injector
Drilling Procedure
Treat every hole section as though it has the potential 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.
Page 49
Milne Point Unit
J-43 SB Injector
Drilling Procedure
8-1/2 Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
appropriately to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to
determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is
critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to
avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide
intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300 gpm
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
There will be multiple 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,
well 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. 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:
There are no wells with a CF <1.0.
Page 50
Milne Point Unit
J-43 SB Injector
Drilling Procedure
26.0 Doyon 14 Layout
Page 51
Milne Point Unit
J-43 SB Injector
Drilling Procedure
27.0 FIT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental
volume pumped and returned during test.
Page 52Milne Point Unit J-43 SB InjectorDrilling Procedure28.0 Doyon 14 Choke Manifold Schematic
Page 53
Milne Point Unit
J-43 SB Injector
Drilling Procedure
29.0 Casing Design
Page 54
Milne Point Unit
J-43 SB Injector
Drilling Procedure
30.0 8-1/2 Hole Section MASP
Page 55
Milne Point Unit
J-43 SB Injector
Drilling Procedure
31.0 Spider Plot (NAD 27) (Governmental Sections)
Page 56
Milne Point Unit
J-43 SB Injector
Drilling Procedure
32.0 Surface Plat (As-Built) (NAD 27)
1
Dewhurst, Andrew D (OGC)
From:Dewhurst, Andrew D (OGC)
Sent:Friday, May 10, 2024 08:28
To:Nathan Sperry; Joseph Lastufka
Cc:Davies, Stephen F (OGC); Guhl, Meredith D (OGC); Rixse, Melvin G (OGC); Roby, David S (OGC)
Subject:RE: [EXTERNAL] MPU J-43 PTD (224-038) Question
Nate,
Understood. Thank you.
Andy
From: Nathan Sperry <Nathan.Sperry@hilcorp.com>
Sent: Thursday, May 9, 2024 21:49
To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Rixse,
Melvin G (OGC) <melvin.rixse@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov>
Subject: RE: [EXTERNAL] MPU J-43 PTD (224-038) Question
Sorry, I-15, not I-19.
The table was labeled correctly but my e-mail men oned 15 instead of 19.
Nate Sperry
Drilling Engineer
Hilcorp Alaska, LLC
From: Nathan Sperry <Nathan.Sperry@hilcorp.com>
Sent: Thursday, May 9, 2024 9:41 PM
To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Rixse,
Melvin G (OGC) <melvin.rixse@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov>
Subject: RE: [EXTERNAL] MPU J-43 PTD (224-038) Question
Andy,
I forwarded your ques on to our subsurface team. They reviewed the wells and yes, H-15, I-19/L1, and H-19/L1 fall
within a quarter mile. We apologize for missing these in our original submission and we appreciate your diligence!
S-57 is outside of a quarter mile (1420). Our team double checked that in mul ple mapping programs.
We have updated the AOR table and I have a ached it to this e-mail.
Thank you,
Nate Sperry
CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open
attachments unless you recognize the sender and know the content is safe.
2
Drilling Engineer
Hilcorp Alaska, LLC
From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Sent: Wednesday, May 8, 2024 4:40 PM
To: Nathan Sperry <Nathan.Sperry@hilcorp.com>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Rixse,
Melvin G (OGC) <melvin.rixse@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov>
Subject: [EXTERNAL] MPU J-43 PTD (224-038) Question
Nate,
I am comple ng the review of the MPU J-43 PTD and have one ques on:
Would you please double-check the following o set wells to see if they fall into the ¼ mile AOR:
o MPU H-15 (50-029-23284-00-00)
o MPU I-15/L1 (50-029-23106-00-00 and 50-029-23106-60-00)
o MPU H-19L1 (50-029-23371-60-00)
o MPU S-57 (50-029-23666-00-00)
Thanks,
Andy
Andrew Dewhurst
Senior Petroleum Geologist
Alaska Oil and Gas Conserva on 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
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the recipient should carry out such virus and other checks as it considers appropriate.
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
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.
MPU J-43
SCHRADER BLFF OILMILNE POINT
224-038
WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:MILNE PT UNIT J-43Initial Class/TypeSER / PENDGeoArea890Unit11328On/Off ShoreOnProgramSERField & PoolWell bore segAnnular DisposalPTD#:2240380MILNE 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 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-B14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForYes15 All wells within 1/4 mile area of review identified (For service well only)Yes Up to 30 days16 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 113'18 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 rig has adequate tankage and good trucking support24 Adequate tankage or reserve pitYes 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 12 3-1/8" piper ball valves, 1 manual and 1 remote hydraulic choke.31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo Monitors will be in place33 Is presence of H2S gas probableYes34 Mechanical condition of wells within AOR verified (For service well only)Yes J-10 had 10ppm H2S (2013)35 Permit can be issued w/o hydrogen sulfide measuresYes Target formation anticipated to be normally pressured. 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]ApprADDDate5/10/2024ApprMGRDate5/8/2024ApprADDDate5/6/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 5/13/2024
