Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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From:Wallace, Chris D (OGC)
To:AOGCC Records (CED sponsored)
Subject:FW: MPL-59 (PTD# 2200500) - 4 year MIT-IA
Date:Tuesday, September 3, 2024 8:09:03 AM
From: Ryan Thompson <Ryan.Thompson@hilcorp.com>
Sent: Friday, August 30, 2024 10:44 AM
To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>
Cc: Derek Weglin <Derek.Weglin@hilcorp.com>; Roger Allison <Roger.Allison@hilcorp.com>; Alaska
NS - Milne - Wells Foreman <AlaskaNS-WellsForeman@hilcorp.com>; Ryan Lewis
<Ryan.Lewis@hilcorp.com>
Subject: MPL-59 (PTD# 2200500) - 4 year MIT-IA
Mr. Wallace,
PWI injector MPL-59 is due for its 4 year AOGCC MIT-IA this month. The well was shut in and
freeze protected in support of the MPL-54 RWO on 8/11/24. The RWO was completed on
8/27/24.
MPL-59 was placed back on injection following completion of the RWO and has been
stabilizing. Notification has been sent for a planned AOGCC MIT-IA tomorrow 8/31/24.
The intent of this email is to notify you of the background, and if any operational issues arise
tomorrow where the MIT-IA is not able to be completed, we will plan to leave the well online
and complete the witnessed MIT-IA as soon as operationally possible.
If this occurs, our WSL will send an update to this email with the reasoning and plan forward.
Thanks,
Ryan Thompson
Milne / Islands Well Integrity Engineer
907-564-5005
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility
is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23680-00-00Well Name/No. MILNE PT UNIT L-59Completion Status1WINJCompletion Date7/15/2020Permit to Drill2200500Operator Hilcorp Alaska, LLCMD13599TVD3809Current Status1WINJ10/14/2020UICYesWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:ROP, AGR, ABG, DGR, EWR, ADR MD & TVD, PB1: ROP, AGR, ABG, DGR, EWR, ADR MD & TVDNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF10/5/2020 Electronic File: MPU L-59 Geosteering EOWR.pdf34040EDDigital DataDF10/5/2020 Electronic File: MPU L-59 Geosteering log.emf34040EDDigital DataDF10/5/2020 Electronic File: MPU L-59 Geosteering log.pdf34040EDDigital DataDF10/5/2020 Electronic File: MPU L-59 Geosteering log.tif34040EDDigital DataDF10/5/2020 Electronic File: MPU L-59 Post-Well Geosteering X-Section Summary.pdf34040EDDigital Data0 0 2200500 MILNE PT UNIT L-59 LOG HEADERS34040LogLog Header Scans0 0 2200500 MILNE PT UNIT L-59 LOG HEADERS34041LogLog Header ScansDF10/5/2020122 13599 Electronic Data Set, Filename: MPU L-59 LWD Final.las34041EDDigital DataDF10/5/20207119 13562 Electronic Data Set, Filename: MPU L-59 ADR Quadrants All Curves.las34041EDDigital DataDF10/5/2020 Electronic File: MPU L-59 LWD Final MD.cgm34041EDDigital DataDF10/5/2020 Electronic File: MPU L-59 LWD Final TVD.cgm34041EDDigital DataDF10/5/2020 Electronic File: MPU L-59i_Definitive Survey Report.pdf34041EDDigital DataDF10/5/2020 Electronic File: MPU L-59i_DSR.txt34041EDDigital DataDF10/5/2020 Electronic File: MPU L-59i_GIS.txt34041EDDigital DataDF10/5/2020 Electronic File: MPU L-59 LWD Final MD.emf34041EDDigital DataDF10/5/2020 Electronic File: MPU L-59 LWD Final TVD.emf34041EDDigital DataDF10/5/2020 Electronic File: MPU_L-59_Geosteering.dlis34041EDDigital DataDF10/5/2020 Electronic File: MPU_L-59_Geosteering.ver34041EDDigital DataWednesday, October 14, 2020AOGCCPage 1 of 3PB1MPU L-59 LWD Final.las
DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23680-00-00Well Name/No. MILNE PT UNIT L-59Completion Status1WINJCompletion Date7/15/2020Permit to Drill2200500Operator Hilcorp Alaska, LLCMD13599TVD3809Current Status1WINJ10/14/2020UICYesWell Cores/Samples Information:ReceivedStart Stop CommentsSentSample SetNumberNameIntervalINFORMATION RECEIVEDDF10/5/2020 Electronic File: MPU L-59 LWD Final MD.pdf34041EDDigital DataDF10/5/2020 Electronic File: MPU L-59 LWD Final TVD.pdf34041EDDigital DataDF10/5/2020 Electronic File: MPU L-59 LWD Final MD.tif34041EDDigital DataDF10/5/2020 Electronic File: MPU L-59 LWD Final TVD.tif34041EDDigital Data0 0 2200500 MILNE PT UNIT L-59 PB1 LOG HEADERS34046LogLog Header ScansDF10/5/2020122 9210 Electronic Data Set, Filename: MPU L-59PB1 LWD Final.las34046EDDigital DataDF10/5/20207119 9172 Electronic Data Set, Filename: MPU L-59PB1 ADR Quadrants All Curves.las34046EDDigital DataDF10/5/2020 Electronic File: MPU L-59PB1 LWD Final MD.cgm34046EDDigital DataDF10/5/2020 Electronic File: MPU L-59PB1 LWD Final TVD.cgm34046EDDigital DataDF10/5/2020 Electronic File: MPU L-59PB1_Definitive Survey Report.pdf34046EDDigital DataDF10/5/2020 Electronic File: MPU L-59PB1_DSR.txt34046EDDigital DataDF10/5/2020 Electronic File: MPU L-59PB1_GIS.txt34046EDDigital DataDF10/5/2020 Electronic File: MPU L-59PB1 LWD Final MD.emf34046EDDigital DataDF10/5/2020 Electronic File: MPU L-59PB1 LWD Final TVD.emf34046EDDigital DataDF10/5/2020 Electronic File: MPU_L-59PB1_Geosteering.dlis34046EDDigital DataDF10/5/2020 Electronic File: MPU_L-59PB1_Geosteering.ver34046EDDigital DataDF10/5/2020 Electronic File: MPU L-59PB1 LWD Final MD.pdf34046EDDigital DataDF10/5/2020 Electronic File: MPU L-59PB1 LWD Final TVD.pdf34046EDDigital DataDF10/5/2020 Electronic File: MPU L-59PB1 LWD Final MD.tif34046EDDigital DataDF10/5/2020 Electronic File: MPU L-59PB1 LWD Final TVD.tif34046EDDigital DataWednesday, October 14, 2020AOGCCPage 2 of 3MPU L-59PB1 LWD Final.las
DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23680-00-00Well Name/No. MILNE PT UNIT L-59Completion Status1WINJCompletion Date7/15/2020Permit to Drill2200500Operator Hilcorp Alaska, LLCMD13599TVD3809Current Status1WINJ10/14/2020UICYesCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments:Compliance Reviewed By:Date:Mud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date: 7/15/2020Release Date:6/9/2020Wednesday, October 14, 2020AOGCCPage 3 of 3M. Guhl10/14/2020
David Douglas Hilcorp Alaska, LLC
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 or fax to 907 777-8510.
Received By: Date:
DATE 10/05/2020
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Ste 100
Anchorage, AK 99501
DATA TRANSMITTAL
MPU L-59, MPU L-59PB1 (PTD 220-050)
FINAL LWD LOGS (11JUL2020):
EWR-M5, AGR, ADR, DGR, ABG, WELLBORE PROFILE (MD/TVD)
AND DEFINITIVE DIRECTIONAL SURVEY
Final CD Main Folders:
Subfolders:
PTD: 2200500
E-Set:34041
Received by the AOGCC 10/05/2020
Abby Bell 10/06/2020
David Douglas Hilcorp Alaska, LLC
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 or fax to 907 777-8510.
Received By: Date:
DATE 10/05/2020
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Ste 100
Anchorage, AK 99501
DATA TRANSMITTAL
MPU L-59, MPU L-59PB1 (PTD 220-050)
FINAL LWD LOGS (11JUL2020):
EWR-M5, AGR, ADR, DGR, ABG, WELLBORE PROFILE (MD/TVD)
AND DEFINITIVE DIRECTIONAL SURVEY
Final CD Main Folders:
Subfolders:
PTD: 2200500
E-Set:34046
Received by the AOGCC 10/05/2020
Abby Bell 10/06/2020
David Douglas Hilcorp Alaska, LLC
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 or fax to 907 777-8510.
Received By: Date:
DATE 10/05/2020
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Ste 100
Anchorage, AK 99501
DATA TRANSMITTAL
MPU L-59 (PTD 220-050)
FINAL GEOSTEERING LOGS, EOW REPORTS (11JUL2020):
Final GEOSTEERING CD:
PTD: 2200500
E-Set:T34040
Received by the AOGCC 10/05/2020
Abby Bell 10/06/2020
MEMORANDUM
TO: Jim Regg
P.I. Supervisor �e, l
FROM: Bob Noble
Petroleum Inspector
Well Name MILNE PT UNIT L-59
Insp Num: mitRCN200811125157
Rel Insp Num:
State of Alaska
Alaska Oil and Gas Conservation Commission
DATE: Monday, August 17, 2020
SUBJECT: Mechanical Integrity Tests
Hilcorp Alaska, LLC
L-59
MILNE PT UNIT L-59
Src: Inspector
Reviewed By:
P. 1. SuprV (3
NON -CONFIDENTIAL Comm
API Well Number 50-029-23680-00-00 Inspector Name: Bob Noble
Permit Number: 220-050-0 Inspection Date: 8/10/2020 -
Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min
L -s9 j Type Test SPT, Test psi lsoo Tubing' 167 - � 162 - 167- 164
Well T e In w TVD 3966
PTD 2200500 Typep IA 163 1720 - 1663 - 1648
BBL Pumped: 2.8 BBL Returned: 2.7-
Interval INITAL
PAF — P _ . OA
Notes:
Monday, August 17, 2020 Page 1 of I
1a. Well Status:Oil SPLUG Other Abandoned Suspended
1b. Well Class:
20AAC 25.105 20AAC 25.110 Development Exploratory
GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test
2. Operator Name:6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry:
Aband.:
3. Address:7. Date Spudded: 15. API Number:
4a. Location of Well (Governmental Section):8. Date TD Reached: 16. Well Name and Number:
Surface:
Top of Productive Interval:9. Ref Elevations: KB: 17. Field / Pool(s):
GL: 15.5 BF:
Total Depth:10. Plug Back Depth MD/TVD: 18. Property Designation:
4b. Location of Well (State Base Plane Coordinates, NAD 27):11. Total Depth MD/TVD: 19. DNR Approval Number:
Surface: x- y- Zone- 4
TPI:x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD:
Total Depth:x- y- Zone- 4
5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD:
Submit electronic information per 20 AAC 25.050 (ft MSL)
22.Logs Obtained:
23.
BOTTOM
20" X-52 114'
L-80 1933'
L-80 3966'
4-1/2"L-80 3809'
24. Open to production or injection? Yes No 25.
26.
Was hydraulic fracturing used during completion? Yes No
DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED
27.
Date First Production:Method of Operation (Flowing, gas lift, etc.):
Hours Tested: Production for Gas-MCF:
Test Period
Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr):
Press. 24-Hour Rate
ADL 025509 & 025515
88-002
2454' / 2032'
N/AN/A
None
13599' / 3809'
Sr Res EngSr Pet GeoSr Pet Eng
Oil-Bbl:Water-Bbl:
Oil-Bbl:
suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray,
caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar l ocator, jewelry, and perforation
record. Acronyms may be used. Attach a separate page if necessary
N/A
4-1/2" Screen Liner 7/14/2020
***Please see attached Schematic for detail***
Water-Bbl:
PRODUCTION TEST
N/A
Date of Test:
Flow Tubing
215#
47#
114'
2222'7130'
Gas-Oil Ratio:Choke Size:
Per 20 AAC 25.283 (i)(2) attach electronic information
40#
13599'
1933'
3965'
DEPTH SET (MD)
6946' / 3965'
PACKER SET (MD/TVD)
CASING WT. PER
FT.GRADE
13.5#
544184
542910
TOP
SETTING DEPTH MD
Surface
6946'
SETTING DEPTH TVD
6020429
BOTTOM TOP
Surface
Surface
ROP, AGR, ABG, DGR, EWR, ADR MD & TVD
PB1: ROP, AGR, ABG, DGR, EWR, ADR MD & TVD
HOLE SIZE AMOUNT
PULLED
15.7
50-029-23680-00-00
MPU L-59
544633 6031945
1174' FNL, 459' FEL, Sec. 18, T13N, R10E, UM, AK
CEMENTING RECORD
6027012
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
7/19/2020
3757' FSL, 5243' FEL, Sec. 08, T13N, R10E, UM, AK
2470' FNL, 1796' FEL, Sec. 19, T13N, R10E, UM, AK
220-050
Milne Point Field, Schrader Bluff Oil Pool
49.3
13599' / 3809'
7/11/2020
6/29/2020
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
Hilcorp Alaska, LLC
WAG
Gas
42"
Surface 2222'Stg 1 L - 640 sx / T - 400 sx
±270 ft3
Stg 2 L - 364 sx / T - 270 sx
Liner Top Packer
6966'3-1/2" 9.2# L-80
SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation
Size and Number; Date Perfd):
9-5/8"12-1/4"
ACID, FRACTURE, CEMENT SQUEEZE, ETC.
CASING, LINER AND CEMENTING RECORD
List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion,
Uncemented Screen Liner w/8-1/2"
TUBING RECORD
Swell Packer
G
s d 1
0 p
d P
l
L
(att
Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment
By Samantha Carlisle at 9:50 am, Aug 06, 2020
+(:
Completion Date
7/15/2020
HEW
RBDMS HEW 8/6/2020
DLB 08/10/2020
DSR-8/6/2020MGR10AUG2020
G
Conventional Core(s): Yes No Sidewall Cores:
30.
MD TVD
18' 18'
2472' 2050'
Top of Productive Interval 6926' 3963'
1519' 1437'
2649' 2130'
5456' 3455'
6688' 3938'
6926' 3963'
SB NB 6926' 3963'
31. List of Attachments:
32. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Contact Name: Joe Lastufka
Contact Email:joseph.lastufka@hilcorp.com
Authorized Contact Phone:
General:
Item 1a:
Item 1b:
Item 4b:
Item 9:
Item 15:
Item 19:
Item 20:
Item 22:
Item 23:
Item 24:
Item 27:
Item 28:
Item 30:
Item 31:Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and
other tests as required including, but not limited to: core analysis, paleontological report, production or well test results.
Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29.
Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool.
If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the
producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced,
showing the data pertinent to such interval).
Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit
detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity,
permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology.
The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements
given in other spaces on this form and in any attachments.
The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00).
Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain).
Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical
laboratory information required by 20 AAC 25.071.
Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion,
suspension, or abandonment, whichever occurs first.
Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection,
Observation, or Other.
Formation at total depth:
Ugnu LA3
Plugback Summary, Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Report
Signature w/Date:
Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345),
and/or Easement (ADL 123456) number.
INSTRUCTIONS
Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each
segregated pool is a completion.
TPI (Top of Producing Interval).
Yes No
Well tested? Yes No
28. CORE DATA
If yes, list intervals and formations tested, briefly summarizing test results.
Attach separate pages to this form, if needed, and submit detailed test
information, including reports, per 20 AAC 25.071.
NAME
SB NA
SV5
SV1
This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram
with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical
reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted.
Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inc lination survey, core analysis,
paleontological report, production or well test results, per 20 AAC 25.070.
If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form,
if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071.
Authorized Name: Monty Myers
Authorized Title: Drilling Manager
SB NB
Permafrost - Base
29. GEOLOGIC MARKERS (List all formations and markers encountered):FORMATION TESTS
Permafrost - Top
N
Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment
8.6.2020 777.8431Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp Alaska, LLC, ou=Technical
Services - AK Drilling,
email=mmyers@hilcorp.com
Reason: I am approving this document
Date: 2020.08.06 06:45:54 -08'00'
Monty M
Myers
_____________________________________________________________________________________
Revised By: JNL 7/31/20
Proposed Schematic
Milne Point Unit
Well: MPU L-59
PTD: 220-050
API: 50-029-23680-00-00
4-1/2” SOLID Liner Detail 4-1/2” SCREEN Liner Detail
Jts Top
(MD)
Top
(TVD)
Btm
(MD)
Btm
(TVD)
6 6627’ 3930’ 7238’ 3960’
15 7280’ 3959’ 7889’ 3940’
15 7930’ 3938’ 8540’ 3921’
6 8581’ 3921’ 8824’ 3919’
13 8866’ 3919’ 9391’ 3900’
13 9432’ 3899’ 9959’ 3880’
17 10000’ 3879’ 10683’ 3856’
12 10725’ 3854’ 11210’ 3839’
30 11252’ 3838’ 12461’ 3826’
9 12503’ 3827’ 12866’ 3816’
12 12908’ 3815’ 13394’ 3810’
3 13436’ 3809’ 13557’ 3809’
Jts Top
(MD)
Top
(TVD)
Btm
(MD)
Btm
(TVD)
1 7238’ 3960’ 7280’ 3959’
1 7889’ 3940’ 7930’ 3938’
1 8540’ 3921’ 8581’ 3921’
1 8824’ 3919’ 8866’ 3919’
1 9391’ 3900’ 9432’ 3899’
1 9959’ 3880’ 10000’ 3879’
1 10683’ 3856’ 10725’ 3854’
1 11210’ 3839’ 11252’ 3838’
1 12461’ 3826’ 12503’ 3827’
1 12866’ 3816’ 12908’ 3815’
1 13394’ 3810’ 13436’ 3809’
J
1
1
1
1
1
1
3
1
CASING DETAIL
Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF
20" Conductor 215 / X-52 / Weld N/A Surface 114’ N/A
9-5/8" Surface 47 / L-80 / TXP 8.525” Surface 2,222’ 0.0732
9-5/8" Surface 40 / L-80 / TXP 8.679” 2,222’ 7,130’ 0.0758
4-1/2” Liner 250ђ Screens 13.5 / L-80 / Hyd 625 3.920” 6,946’ 13,599’ 0.0149
TUBING DETAIL
3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.867” Surf 6,966’ 0.0087
JEWELRY DETAIL
No Top MD Item ID
Upper Completion
1 6,241’ 3-1/2” SGM-FS, XDPG 2.898”
2 6,293’ XN Landing Nipple w/ 2.813” Packing Bore 2.750”
3 6,955’ 8.25” No Go Locater Sub (2.06’ off No-go) 6.190”
4 6,956’ Bullet Seals – Mule Shoe bottom @ 6,966’ MD 6.190”
Lower Completion
5 6,946’ 9-5/8” SLZXP Liner Top Packer 6.190”
6 7,184’ Tendeka Water Swell Packer 3.850”
7 13,597’ Shoe Bottom @ 13,599’ MD 4.121”
OPEN HOLE / CEMENT DETAIL
42” ±270 ft3
12-1/4" Stg 1 –Lead 640 sx / Tail 400 sx
Stg 2 –Lead 364 sx / Tail 270 sx
8-1/2” Cementless Injection Liner in 8-1/2” hole
WELL INCLINATION DETAIL
KOP @ 354’
Hole Angle @ XN = 67°
Hole Angle @ Liner Top = 85°
Max Hole Angle = 94°
TREE & WELLHEAD
Tree Cameron 3 1/8" 5M w/ 3-1/8” 5M Cameron Wing
Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs
GENERAL WELL INFO
API#: 50-029-23680-00-00
Completed by Doyon14: 7/15/2020
Depth
MD
Depth
TVD ICD/Swell Packer Detail
5,020’ 3,826’ Tendeka Water Swell Packer
5,245’ 3,823’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge
5,348’ 3,822’ Tendeka Water Swell Packer
5,985’ 3,820’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge
6,253’ 3,820’ Tendeka Water Swell Packer
6,767’ 3,833’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge
7,076’ 3,831’ Tendeka Water Swell Packer
8,002’ 3,887’ Tendeka Water Swell Packer
8,144’ 3,895’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge
8,531’ 3,908’ Tendeka Water Swell Packer
8,838’ 3,918’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge
8,938’ 3,922’ Tendeka Water Swell Packer
9,322’ 3,900’ Tendeka Water Swell Packer
9,583’ 3,890’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge
9,985’ 3,890’ Tendeka Water Swell Packer
10,300’ 3,897’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge
10,819’ 3,915’ Tendeka Water Swell Packer
11,085’ 3,920’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge
11,558’ 3,928’ Tendeka Water Swell Packer
11,942’ 3,933’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge
12,292’ 3,936’ Tendeka Water Swell Packer
12,765’ 3,953’ Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625 Wedge
PB1
TD 9210' MD / 3871' TVD
KOP 8650' MD / 3920' TVD
Date 7/8/2020
MPU L-59 OH Sidetrack Summary
PTD: 220-050 / API: 50-029-23680-70-00
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:MPU L-59 Date:7/6/2020
Csg Size/Wt/Grade:9.625"40# x 47#, L-80 Supervisor:Yessak/Vanderpool
Csg Setting Depth:7130 TMD 3964 TVD
Mud Weight:9.3 ppg LOT / FIT Press =556 psi
.
LOT / FIT =12.00 ppg Hole Depth =7160 md
Fluid Pumped=2.2 Bbls Volume Back =2.0 bbls
Estimated Pump Output:0.101 Barrels/Stroke
LOT / FIT DATA CASING TEST DATA
Enter Strokes Enter Pressure Enter Strokes Enter Pressure
Here Here Here Here
->00 ->00
->233 ->10 60
->450 ->20 190
->679 ->30 490
->8157 ->35 680
->10 200 ->40 900
->12 247 ->45 1120
->14 309 ->50 1410
->16 363 ->55 1630
->18 422 ->60 1900
->20 504 ->65 2200
->22 564 ->70 2450
->24 ->75 2615
->26 ->
Enter Holding Enter Holding Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0556 ->0 2615
->1519 ->5 2605
->2505 ->10 2600
->3505 ->15 2600
->4503 ->20 2600
->5502 ->25 2600
->6489 ->26 2600
->7487 ->27 2600
->8487 ->28 2600
->9486 ->29 2600
->10 486 ->30 2600
->11 486 ->
->12 ->
->13 ->
->14
->15
->16
0 2 4 6
8
10
12
14
16
18
20
22
0
10
20
30
35
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45
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55
60
65
70
75
0
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600
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1400
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1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
0102030Pressure (psi)Strokes (# of)
LOT / FIT DATA CASING TEST DATA
556519505505503502489487487486486486
2615 2605 2600 2600 2600 260026002600260026002600
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
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1700
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2200
2300
2400
2500
2600
2700
2800
2900
3000
0 5 10 15 20 25 30 35Pressure (psi)Time (Minutes)
LOT / FIT DATA CASING TEST DATA
Activity Date Ops Summary
6/28/2020 See L-60 report for details.;Clear and secure cellar, move rock washer and fuel trailer. Pick up all landings.
PJSM for rig move. Skid rig floor into moving position.
SimOps: Welder cap 90' mousehole.;Move Rig off L-60 and down to opposite end of pad. Install stairs on back end of Rig. Hang surface annular preventer in Cellar
and remove speedhead from Diverter Tee. Install Diverter Tee on L-59 and spot Rig over Well.;Skid rig floor into drilling position. Spot fuel tank, service company
out buildings and rock washer.;Make up stand of HWDP, level and shim rig.
N/U surface annular and diverter system
Work on rig acceptance checklist.
** AOGCC notified of Diverter test on 06/28/2020 @ 06:50 **
6/29/2020 Spot water pump house and upright, C/O saver sub and inspect grabber dies, service top drive, perform derrick inspection, work on acceptance checklist.
Load HWDP into shed along with BHA, install 30’ & 90' mouse holes;Cont work on acceptance checklist. Load pits w/ 580 bbls 8.7+ ppg spud mud. Electrician
tested Rig gas alarms. Load 5'' DP into shed. C/O all Liners, Swabs, valves and seats on both Mud Pumps.;Function test annular diverter on 5" drill pipe - 26 sec.
knife valve opening, 32 sec. annular closing.
Test accumulator - 3000 PSI system pressure, 1975 PSI after closure, 200 PSI recharge in 37 sec, full recharge in 147 sec, 6 nitrogen bottle avg of 2142 PSI.;183'
total diverter line, one 22° target Tee, 175' from outside Rig. 86.5' from closest ignition source (Nitrogen Silo)
AOGCC representative Bob Noble witnessed test.
** Rig on high line power at 15:00 **;Slip and cut 73' drilling line. Calibrate blocks and TopDrive Tq, service TopDrive and inspect Drawworks breaks & chains.;M/U
one three stand of HWDP w/ jars and rack in derrick. Mobilize BHA components to the rig floor.;Hold pre spud meeting, Review rig evacuation plan with all parties.
M/U 12 1/4'' Kymera bit and mud motor.
M/U stand HWDP;RIH and tag up @ 112’. Flood stack and lines, test lines to 3500 psi from TopDrive IBOP to mud pumps, good, completing last item on
acceptance checklist.;Clean out conductor t/ 114’, spud Well and drill to 124’ with water, displace to spud mud on the fly.
Drill to 220' pumping 500 gpm, 650 psi, 50 rpm, 1k Tq, 3k WOB
Circulate BU and Pump out of hole one stand, pull next stand on elevators.
Pull bit to surface, inspect and clean same.;PJSM, M/U DM collar and scribe RFO from motor. Continue M/U MWD tools, scribe to UBHO. Adjust UBHO to motor as
per DD. Plug in, Initialize and upload MWD.
Initialize and upload MWD, RIH w/ 3 NMFCs, XO to 180', M/U std HWDP, wash/ream to 220'
R/U Gyro while uploading MWD;Drill 12-1/4" hole f/ 220' t/ 457', (457’ TVD) 237' drilled, 67.7’/hr AROP.
475 GPM, 940 PSI, 40 RPM, 1k TQ, 5k WOB
MW 9.1+ ppg in / out, vis 300 in /out, 9.6 ECD.
70k PU / 70k SO / k ROT
Kick off @ 330', build 3°/100'
Gyro surveys at connections;H²O from A-Pad: 540 bbls / 540 bbls Total
6/30/2020 Drill 12-1/4" hole f/ 457' t/ 895', (518’ TVD) 438' drilled, 73’/hr AROP.
439 GPM, 1030 PSI, 40 RPM, 1k TQ, 8-10k WOB
MW 9.1 ppg in / out, vis 200 in / 210 out, 9.8 ECD.
81k PU / 81k SO / 81k ROT;Build 3 deg/100' to 740' then build 4 deg/100'
Gyro survey at connections;Drill 12-1/4" hole f/ 895' t/ 1310', (1259’ TVD) 415' drilled, 69.16’/hr AROP.
450 GPM, 1140 PSI, 40 RPM, 2k TQ, 5-15k WOB
MW 9.1 ppg in / 9.2 ppg out, vis 231 in / 248 out, 9.8 ECD. max gas 18u
88k PU / 85k SO / 86k ROT;Build 4 deg/100', Gyro survey every connection, had a clean MWD survey @ 1175' then seen magnetic interference @ 1270', continue
w/ Gyro surveys;Drill 12-1/4" hole f/ 1310' t/ 1761', (1635’ TVD) 451' drilled, 75.17’/hr AROP.
475 GPM, 1220 PSI, 60 RPM, 4k TQ, 5-15k WOB
MW 9.1 ppg in / 9.2 ppg out, vis 151 in / 281 out, 10.1 ECD. max gas 52u
98k PU / 88k SO / 91k ROT;Continue target Build @ 4°/100’
Last Gyro survey at 1303’;Drill 12-1/4" hole f/ 1761' t/ 2735', (2166’ TVD) 974' drilled, 162.33’/hr AROP.
485 GPM, 1350 PSI, 60 RPM, 7k TQ, 5-15k WOB
MW 9.3 ppg in / 9.3 ppg out, vis 90 in / 105 out, 10.37 ECD. max gas 91u
106k PU / 82k SO / 95k ROT
Build with 4°/100’ to 2316’ were 62.5° tangent started.;Base of permafrost logged at 2,184’ md/ 1,913’ tvd
Last survey @ 2600.32' MD / 2108.31' TVD, 63.79° inc, 181.60° azm, 13.13' from plan, 6.46’ Low, 11.43' Right;No losses recorded on the day
H2O from A-Pad: 1,165 bbls Daily/ 1,705 bbls Total
H2O from G&I Source Water: 0 bbls Daily/ 0 bbls Total
Cuttings/mud/cement to MPU G&I: 1,326 bbls Daily / 1,326 bbls Total
Well Name:
Field:
County/State:
MPU L-59
Milne Point Field
Hilcorp Energy Company Composite Report
Alaska
6/29/2020Spud Date:
7/1/2020 Drill 12-1/4" hole f/ 2735' t/ 3877', (2656’ TVD) 1142' drilled, 190.3’/hr AROP.
550 GPM, 1970 PSI, 80 RPM, 6k TQ, 5k WOB
MW 9.5 ppg in / out, vis 167 in / 148 out, 10.9 ECD. max gas 107u
120k PU / 85k SO / 100k ROT
Continue to hold 62.5° tangent;Pumped our first 30 bbl hi vis sweep @ 2830', back 200 stks late and no increase, another at 3493', 200 stks late and no
increase;Drill 12-1/4" hole f/ 3877' t/ 4755', (3121’ TVD) 878' drilled, 146.3’/hr AROP.
550 GPM, 2190 PSI, 80 RPM, 11k TQ, 5-15k WOB
MW 9.5 ppg in / out, vis 154 in / 161 out, 10.51 ECD. max gas 62u
145k PU / 90k SO / 110k ROT
Continue to hold 62.5° tangent;Pump 30 bbl hi vis sweep @ 4550', back 380 stks late w/ 10% increase;Drill 12-1/4" hole f/ 4755' t/ 5424', (3439’ TVD) 669' drilled,
111.5’/hr AROP.
550 GPM, 2160 PSI, 80 RPM, 13k TQ, 5-15k WOB
MW 9.4 ppg in / 9.5 ppg out, vis 118 in / 157 out, 10.70 ECD. max gas 84u
160k PU / 90k SO / 115k ROT
Hold 61.2° tangent;Start Pre-Treat mud system with 0.5% screenkleen @ 5400'.
AC unit went down in TopDrive VFD house, TopDrive rotary started kicking out due to overheating. Open doors and set up fans to cool VFD house;Drill 12-1/4"
hole f/ 5424' t/ 6194', (3810’ TVD) 770' drilled, 128.33’/hr AROP.
550 GPM, 2200 PSI, 80 RPM, 15k TQ, 5-15k WOB
MW 9.3 ppg in / 9.3 ppg out, vis 84 in / 91 out, 10.67 ECD. max gas 291u
175k PU / 90k SO / 125k ROT;Hold 61.2° tangent t/6159' then start 4°/100’ build & turn for landing.
Pump 30 bbl hi vis sweep @ 5494', back 380 stks late w/ 10% increase
@ 5600' Shakers blinding from Ugnu oil, sweep was not recognized at surface as shaker running wet.
Reduce flow t/ 400 GPM due to losing mud over shakers;Flow reduction had minimal effect on losses.
Screen down t/ 80’s on first two rows of shakers and increase screenkleen to 1%.
Transfer clean mud losses from rockwasher over pit shakers and back into active system
Screen back up t/ 120's across all shakers once cleaned up.;Top of Ugnu (UG4) @ 3254' MD / 2408' TVD
Top of Ugnu_MB @ 6023’ MD / 3730’ TVD
Last survey @ 6121.36' MD / 3776.53' TVD, 62.26° inc, 182.90° azm, 8.52' from plan, 5.24’ High, 6.72' Right;No losses recorded on the day
H²O from A-Pad: 1,955 bbls / 3,660 bbls Total
Cuttings/mud/cement to MPU G&I: 1,554 bbls / 2,880 bbls Total
7/2/2020 Drill 12-1/4" hole f/ 6194' t/ 6581', (’ 3921' TVD) 387' drilled, 64.5’/hr AROP.
554 GPM, 2290 PSI, 80 RPM, 17k TQ, 23k WOB
MW 9.2 ppg in / 9.2+ ppg out, vis 75 in / 122 out, 10.2 ECD. max gas 41u
185k PU / 85k SO / 125k ROT
Continue to build and turn 4°/100';Pump 30 bbl hi vis sweep @ 6445', back 1400 stks late w/ 20% increase;Drill 12-1/4" hole f/ 6581' t/ 7140', (3967’ TVD) at TD,
559' drilled, 93.16’/hr AROP.
550 GPM, 2350 PSI, 80 RPM, 17k TQ, 7-16k WOB
MW 9.3 ppg in / 9.4 ppg out, vis 90 in / 116 out, 10.4 ECD. max gas 195u
185k PU / 80k SO / 115k ROT;Continue to build and turn 4°/100'. TD section ±10’ TVD into the SB_NB sand.
Top of SB_NA 6,692’ MD / 3,939’ TVD.
Top of SB_NB @ 6940' MD / 3965' TVD.
Top of NB Clay @ 7,032’ MD / 3,970’ TVD.;Pump Hi-Vis sweep w/ nut plug marker & circulate hole clean while BROOH f/ 7140’ t/ 6955'. 550 GPM, 2300 PSI, 80
RPM, 20K Tq, Total of 2x BU circ
TopDrive rotary start tripping repeatedly. Install extra fan in VFD house. No issues after.
Sweep returned 1500 stks late w/ 10% icrease. Final YP: 23;BROOH f/ 7140' t/ 3340' at 5-10 min. stand, 550 GPM, 1730 PSI, 80 RPM, 13K TQ, slow down as
needed to cleanup tight areas.
130k PU / 82k SO / 105k ROT, max gas 58u.
No shaker blinding or hole unloading experienced.;Last survey @ 7101.31' MD / 3967.70' TVD, 94.62° inc, 189.87° azm, 2.83’ from plan, 2.51' high, 1.30' right.
Projection to TD 7140' MD / 3964.59' TVD, 5.64' from plan, 5.63' high, 0.38' right.;Interval Daily (Midnight) Loss = 0 bbls, Cumulative losses = 0 bbls
H²O from A-Pad: 1,870 bbls / 5,530 bbls Total
Cuttings/mud/cement to MPU G&I: 1,616 bbls / 4,496 bbls Total
7/3/2020 BROOH f/ 3440'' t/ HW @ 740' pulling 5-10 min. stand, 550 GPM, 1730 PSI, 80 RPM, 13K TQ, slow down as needed to cleanup tight areas.
Note: Pull 2 stds slow CBU before pulling thru BOPF @ 2184', unloaded @ 1500', pull slow until clean.
23.4 bbls losses BROOH.;PJSM, L/D BHA #1. Pull on elevators f/ 740. rack 6 stds HWDP including jar stand, L/D NMDCs, unable to breakout connection
between last 2 FCs.;Pull last 2 FCs and set in short mousehole, slowly breakout w/ iorn ruffneck, threads severly gauled, L/D same
Read MWD tools, L/D remaining BHA f/ 85', Bit grade=: 2-2-LT-M-E-I-BT-TD.
ILS undercut 1'' on upper/lower blades
Total losses TOOH = 40.4 bbls.;BD TD. Clear rig floor and mobilize casing equipment to the rig floor. Ready FOSV and XO.
R/U 9-5/8" Volant and handling tools. PJSM for running casing.
Monitor well-Static loss rate 5 bph;M/U 9-5/8" casing shoe track: round nose float shoe, jt#1, Baker-Loc jt#2, float collar, jt#3 w/ bypass baffle installed to 123'. Pump
thru shoe track to check floats - good.
M/U baffle adapter & jt#4 to 165'. Torqued all connections to 21,000 ft/lbs w/ Volant tool & Baker-Loc first 4 connections.;Two 9-5/8" x 12-1/4" centralizer & 4 stop
rings on shoe joint, 1 free floating centralizer on Baker-Loc joint, 1 centrailizer w/ 2 stop rings on the float collar and baffle adapter joints.;Run 9-5/8" 40# L-80 TXP-
BTC casing f/ 165' t/ 1726'.
Torque to 21,000 ft/lbs with the Volant tool. Install 9-5/8" x 12-1/4" bowspring centralizers on jts #5-25 then every other joint
Fill casing on the fly & top off every 10 joints.
6.5 BPH loss rate.;Run 9-5/8" 40# L-80 TXP-BTC casing f/ 1726' t/ 2404'. Torque to 21,000 ft/lbs with the Volant tool.
Install 9-5/8" x 12-1/4" bow spring centralizer on every other jt f/ jt 27 to 49, then 1 every 3rd jt
Fill casing on the fly & top off every 10 joints.
6 BPH loss rate;CBU at 2404', stage pump to 5 bpm, 150 psi, work string 15'
3 bbl losses;Continue to run 9-5/8" 40# L-80 TXP-BTC casing f/ 2404' t/ 3962' @ jt #99. Torque to 21,000 ft/lbs with the Volant tool.
Install 1-9-5/8" x 12-1/4" bow spring centralizer every 3rd joint
Fill casing on the fly & top off every 10 joints.
6 BPH loss rate.;Daily (midnight) losses = 88 bbls, Cumulative losses = 88
H²O from A-Pad: 690 bbls / 6,220 bbls Total
H²O from G&I Source Water: 400 bbls / 400 bbls Total
Cuttings/mud/cement to MPU G&I: 799 bbls / 5,295 bbls Total
7/4/2020 Continue to run 9-5/8" 40# L-80 TXP-BTC casing f/ 3962' t/ 4718' @ jt #118. Torque to 21,000 ft/lbs with the Volant tool, Install 1-9-5/8" x 12-1/4" bow spring
centralizer every 3rd joint. Fill casing on the fly & top off every 10 joints. 6 BPH loss rate. Baker lock and M/U ESC with pups as per HES rep, verify 6 pins set @
3300 psi, Continue to run 9-5/8" 40# L-80 TXP-BTC casing f/ 4733' t/ 4907' @ jt #122. Torque to 21,000 ft/lbs with the Volant tool, install 1 centralizer ea jt f/ jt 115
to jt 122 Run 9-5/8" 47# L-80 TXP-BTC casing f/ 4907' t/ 7116' to joint #54.TQ to 24,000 ft/lbs with the Volant tool, fill on the fly and top off every 10 jts ran. Install 1
centralizer ea jt to jt #5 then every 3rd jt to jt #50. 4-5 BPH loss rate M/U 20' pup, wash to depth @ 7130', verify pipe count, 8 jts 40# and 1 jt 47# left out. 129 bbl
losses running casing. 89- 9-5/8" x 12-1/4" bow spring centralizer ran as per tally. PU 310k, SO 95k Stage pump f/ 3 bpm to 6 bpm, 330 psi. Start rotary w/ torque
limit set at 20K, 1-2 RPM when reciprocating. Reciprocate 20', cementers rigged up. Condition mud for cement job. MW 9.4 in/out, 41 vis, YP 14. Circulated a total
of 1.5x bottoms up. Submit 24 hr BOP test notification to AOGCC Cementers finished rigging up and filled cement water tank w/ 75°. PJSM. Blow down top drive &
R/U cement lines. Pre-treat mud in pit #4. Hold PJSM for cement job. Pump 50 bbls of pre-treated mud, 6 BPM, 130 PSI. 5 bbls losses while circulating. Pump 5
bbls water. PT lines to 1300 psi / 4200 psi. Mix and pump 60 bbl tuned spacer w/ 4# red dye & 5# Pol-E-Flake in 1st 10 bbls, 4.14 BPM, 195 psi. Drop Bypass
bottom plug. Mix & Pump 268 bbl 12 ppg Lead type I/II cmt (640 sx, 2.349 ft^3/sk yield), 6.2 BPM, 410 psi. Mix & Pump 82 bbl 15.8 ppg Premium G tail cement
(400 sx1.151 ft^3/sk yield) 5.2 BPM, 620 psi. Drop shutoff plug. Chase with 20 bbl fresh water. Rig displace with 320 bbl 9.4 ppg spud mud at 6 BPM, 200 psi.
HES pump 80 bbl 9.4 ppg tuned spacer, 5.1 BPM, 370 psi. Displace 107.6 BBLS w/ rig at 6 bpm – 610 psi 9.4 ppg mud. Park w/ string in tension @ 7130', slow to
3 bpm on last 20 bbls, FCP 720 psi. Bump plug @ 4234 strokes. 14 strokes over calculated. Pressure 500 psi over FCP @ 1200 psi, hold 3 min. Good. Bleed
down and check floats- good. CIP @ 21:53 Pol-E-Flake seen at shakers at opening. Circulate hole clean through ES cementer at 2394'. Displace out 60 bbl spacer,
trace cmt and 70 bbl chase spacer. Thick interface with moderate clabbored mud on both sides of spacers. Send all to rockwasher, 195 bbls total dumped
15 bbls loss while cementing Take mud returns back to pits. Circulate 4x bottoms up. Clean returns. Shut down. Flush and clean surface equipment, Drain stack.
Disconnect knife valve accumulator lines. Flush stack w/ black water functioning annular 3 times. Circ at 6 bpm, 311 psi while waiting on cmt and preparing for
second stage. SimOps: L/D 90' Mousehole. Open upper ram doors on BOP stack, Load BHA into Shed. Processing 5" DP & 5" HWDP. Hold PJSM @ 5AM with all
parties involved
No losses while circulating. Perform 2nd stage cement job through ES cementer at 2394'. Pump 5 bbls of water
Mix & pump 60 bbls of 10.0 ppg Tuned spacer w/ 4# red dye & 5# Pol-E-Flake in 1st 10 bbls, 5 BPM, 335 psi. Daily (midnight) loss = 95 bbl, Cumulative loss = 183
bbl
H²O from A-Pad: 125 bbls / 6,345 bbls Total
H²O from L-Pad: 140 bbls / 140 bbls Total
H²O from G&I Source Water: 0 bbls / 400 bbls Total
Cuttings/mud/cement to MPU G&I: 991 bbls / 6,286 bbls Total
7/5/2020 Continue w/ 2nd stage cement job through ES cementer at 2394'. finish pumping 60 bbls of 10.0 ppg Tuned spacer w/ 4# red dye & 5# Pol-E-Flake in 1st 10 bbls,
5 BPM, 335 psi.
Pump 286 bbls 10.7 ppg Perm L lead (364 sks) 5 bpm, 318 psi pump 37 bbls, 10.7 ppg ArcticCem lead ( 70 sks ) 5 bpm, 444 psi, Observed spacer at 180 bbls
and good cement back @ 286 bbls of lead pumped. Mix & pump 56 bbls of 15.8 ppg tail cement (270 sks), 5 BPM, 546 PSI. Drop closing plug. Pump 20 bbls of
water Displace w/ #1 rig pump with 156.4 bbls 9.2 ppg spud mud. 6 bpm, 340 psi ICP, 770 psi FCP. 230 psi final lift. Slow to 3 bpm, 570 psi for last 10 bbls. Plug
bumped at 1549 stks. 270 bbls of cement to surface. CIP at 08:08. Pressure up & shift ESC closed at 1750 psi. Pressure held good, bleed off to verify cementer
closed. No flow back - good. No losses. BD and R/D cementers Drain stack to the cellar. Disconnect knife valve accumulator lines. Function annular and flush w/
black water. Rig vac fluid out of casing to cellar level. Disconnect & begin N/D diverter line. Back out speed head LDS on diverter adapter, hoist stack. Install 9-5/8"
casing slips and set with 110K on slips. Cut 9-5/8" casing (47# Jt 54 = 40.75' - 18.47' = 22.28' left in hole). Set stack down. N/D annular & diverter tee, remove from
cellar. Sim-ops: clean pits, R/D and load out csg tools. **Rig on Gen power @ 14:00** Dress casing stump. WH rep N/U Cameron T-103 nipple and test seal to 500
psi for 5 min & 3880 PSI for 10 min. N/U T-103 tubing spool, test void to 500 psi for 5 min/ 5000 psi for 10 min, good tests. Sim-ops: continue to clean pits, load out
cement Silos. **Rig on Hi-Line @ 17:30** Install Test Plug and RILDS. N/U adapter flange, spacer spool and BOP stack. Install MPD trip nipple and kill line. Rig
electrician tested rig gas alarms.SimOps: C/O #2 Cuttings Conveyor Change upper rams from 7-5/8" to 4-1/2"X7" VBR. Install 30' & 90' mouseholes. Rig up test
equipment, Flush flow line. Fill stack and lines.-no leaks. Perform BOP shell test, good. Test BOP equipment to 250 PSI low / 3000 PSI high. Tests held for 5 min
each & charted. AOGCC inspector Jeff Jones verbally waived witness at 19:57 on 5 July 2020. All tests performed with fresh water against a test plug.
1. Lower 3.5"x6" VBR on 3.5" test joint & Lower IBOP 2. Annular on 3.5" test joint, choke valves 1, 12, 13, 14, kill Demco & Upper IBOP
3. Upper 4.5"x7" VBR on 4.5” test joint, choke valves 9, 11, HCR kill & 5" dart valve
4. Upper 4.5"x7" VBR on 5” test joint, choke valves 5, 8, 10, manual kill & 5" FOSV #1
5. Choke valves 4, 6, 7 & 5" FOSV #2 6. Choke valve 2 & 3.5” dart valve
7. HCR choke & 3.5” FOSV
8. Manual choke
9. Lower 3.5" x 6" VBR on 5" test joint
10. Blind rams & choke valve 3
11. Manual choke A
12. Manual choke B Perform Accumulator test: 3025 PSI sys pressure, 1650 PSI after closure, 200 PSI recovery in 43 sec, full recovery in 192 sec, 6 N2 bottle avg
= 2100 PSI. Daily losses (midnight) = 20 bbls, Cumulative losses = 203 bbls.
H²O from A-Pad: 0 bbls / 6,345 bbls Total
H²O from L-Pad: 330 bbls / 470 bbls Total
H²O from G&I Source Water: 320 bbls / 720 bbls Total
Cuttings/mud/cement to MPU G&I: 1,260 bbls / 7,546 bbls Total
7/6/2020 R/D test equipment, BD choke and kill lines, pull test plug, install 10'' ID wear bushing.;PJSM, M/U 8 1/2'' cleanout BHA, 8 1/2'' mill tooth bit, 1.5 deg mud motor, 5
stands 5'' HWDP with jar stand to 592', TIH on elevators to 2379',
Note: tag cmt stringer @ 54', wash thru easily, wash pipe leaking, C/O same;M/U top drive, wash and ream down f/ 2379' to 2389' tagging on depth , 445 gpm, 780
psi, 40 rpm, 5k tq, drill plugs and ESC f/ 2389' to 2397', 2-6K wob. Ream 4 times, pass thru w/ pumps off and no rotary, good
PU 95K, SO 65K, ROT 90K;TIH f/ 2397' to 6966', fill pipe every 2000', wash last joint down to 6995' just above the baffle adaptor.
PU 215K, SO 70K;CBU, 465 gpm, 1150 psi, 40 rpm, 17k torque, work pipe 30', circulate out thick mud;R/U test equipment. Pressure test 9-5/8" casing to 2600 PSI
for 30 minutes on chart - good test.
Blow down choke & kill lines. R/D test equipment.;Drill 9-5/8" shoe track w/ 450 GPM, 1250 PSI, 40 RPM, 18K TQ.
Drill cement f/ 6995', baffle adapter f/ 7005' t/ 7006' w/ 5-10K WOB, Float collar f/7046' t/ 7048' w/ 5-10k.
Drill shoe f/ 7128' to 7130’ w/ 2-3K WOB, then cleanout rathole to 7140'.;Reamed through baffle adapter, float collar and shoe 2x times each, pass through each 2x
w/ no rotary/pumps.;Drill 8-1/2" production hole f/ 7140' t/ 7160', 450 GPM, 1250 PSI, 40 RPM, 18K TQ, 4-8K WOB.
225k PU 65k SO 118k ROT;Rack a stand back to 7125'. Circulate wellbore clean until 9.3 ppg MW in/out, 2x bottoms up at 450 GPM, 1250 PSI, 40 RPM, 457u
max gas. Work string 60’;Rig up test equipment, flood lines and purge choke and kill lines.
Perform FIT to 12.0 ppg EMW with 9.3 ppg MW at 3964' TVD. Pressure up to 556 PSI, 2.2 bbls pumped, 2.0 bbls bled back.
R/D test equipment and blow down lines.;Perform 5 min. flow check - static. POOH on elevators f/ 7125' t/ 6680', good displacement. Pump 20 bbls 11.5 ppg dry
job. Blow down top drive.
POOH on elevators f/ 6680' t/ 592', rack back jar stand and L/D excess HWDP. L/D cleanout BHA #2, 8 1/2'' MT bit grade= 1-1-NO-A-E-I-NO-BHA,
12 bbls loss;Install split master bushing, Load tools to rig floor;PJSM. M/U 8-1/2" NOV SK616M-J1D bit, NBS, 7600 Geo-Pilot, MW D w/ ADR, ILS, DGR, PWD,
directional collars and spiral blade stabilizer to 88'. Test & initialize MWD tools.;Interval Daily (Midnight) Loss = 0 bbls, Cumulative losses = 0 bbls
H2O from A-Pad: 85 bbls Daily/ 6,685 bbls Total
H2O from L-Pad: 60 bbls Daily/ 275 bbls Total
H2O from G&I Source Water: 0 bbls Daily/ 720 bbls Total
Cuttings/mud/cement to MPU G&I: 173 bbls Daily / 7,719 bbls Total
7/7/2020 Finish initializing MWD. M/U remaining BHA #3, float sub, 3 NMFCs & 2nd float sub t/ 183'. RIH w/ HWDP & jar stand to 277'.
Note: corrosion ring installed at top NMFCs,;M/U stand DP and TD, shallow test MWD. Pressure test Geo-Span to 3000 psi. Pressure test MPD lines to 250/ 1300
psi-good. TIH to 6873', Fill drill pipe every 2000', break in Geo-Pilot seals.
Correct displacement TIH.;PJSM, Remove trip nipple, install RCD bearing, no leaks. Single in f/ 6873' to 7127', M/U stand in mouse hole and top drive, wash/ream
to bottom @ 7160'
Held PJSM for displacing
PU 220K, SO 55K;Pump 30 bbl hi vis spacer then displace w/504 bbls new 8.8 ppg Flo-Pro mud w/ 1.5% screen kleen and .5% lube added, 300 gpm, 800 psi, 30
rpm, 19K TQ,
w/ new mud out bit, set std in mousehole, finsh displacing in casing f/ 7127' to 7032' working pipe 90';Dump spud mud and interface returns to rock washer. In
spud mud PU 220K, SO 55K, ROT 110K / In Flo-Pro mud PU 185K, SO 95K, ROT 185K, 11K TQ at 40 rpm.
No losses displacing
Obtain new SPRs;Parked at 7123', PJSM, slip and cut 59' drilling line. re-calibrate block height, inspect saver sub and grabber dies, service rig.
SimOps: clean pit 4 and under shakers.
Monitor MPD for pressure build;Drill 8-1/2" production hole f/ 7160' t/ 7575' (3952' TVD) 415' drilled, 75.45'/hr AROP.
450 GPM, 1250 PSI, 80 RPM, 13K TQ, 5-15K WOB.
8.8 ppg MW, 44 vis, 10.07 ECD, 268u max gas.
148K PU / 82K SO / 112K ROT.
Holding 60 PSI on connections w/ MPD, 60 PSI line restriction w/ choke open drilling.;Drill 8-1/2" production hole f/ 7575' t/ 8077' (3926' TVD) 502' drilled, 83.67'/hr
AROP.
505 GPM, 1530 PSI, 110 RPM, 14K TQ, 5-14K WOB.
8.8 ppg MW, 42 vis, 10.39 ECD, 367u max gas.
145K PU / 80K SO / 107K ROT.
Holding 60 PSI on connections w/ MPD, 65 PSI line restriction w/ choke open drilling.;Pumped 25 bbl high vis sweep at 7982', 300 stks late w/ 40% increase.
Targeting 92° -92.5° inclination
Drilled 14 concretions for a total thickness of 71' (8.4% of the lateral).
Last survey at 7911.52' MD / 3938.80' TVD, 93.02° inc, 198.67° azm, 5.96' from plan, 5.67' high and 1.82' right.;Daily losses (midnight) = 12 bbls, Cumulative
lateral losses = 12 bbls
H2O from A-Pad: 445 bbls Daily/ 7,130 bbls Total
H2O from L-Pad: 0 bbls Daily/ 275 bbls Total
H2O from G&I Source Water: 0 bbls Daily/ 720 bbls Total
Cuttings/mud/cement to MPU G&I: 675 bbls Daily / 8,394 bbls Total
7/8/2020 Drill 8-1/2" production hole f/ 8077' t/ 8630' (3921' TVD) 553' drilled, 92.1'/hr AROP.510 GPM, 1770 PSI, 110 RPM, 15K TQ, 5-10K WOB.8.85 ppg MW, x45vis,
10.54 ECD, 319u max gas.148K PU / 80K SO / 108K ROT.
Holding 60 PSI on connections w/ MPD, 65 PSI line restriction w/ choke open drilling. Drill in the NB sand targeting 90 to 91.5 deg Drill 8-1/2" production hole f/
8630' t/ 9025' (3893' TVD) 395' drilled, 65.8'/hr AROP.
500 GPM, 1800 PSI, 110 RPM, 15K TQ, 14K WOB.8.9 ppg MW, 45 vis, 10.74 ECD, 298u max gas.145K PU / 75K SO / 105K ROT. Holding 60 PSI on
connections w/ MPD, 65 PSI line restriction w/ choke open drilling. Drill in the NB sand targeting 91.8°, suspect to have entered the NB clay @ 8675', possibly
crossed fault, target 94° to get back in the NB sand Drill 8-1/2" production hole f/ 9025' t/ 9210' (3869' TVD) 185' drilled, 61.67'/hr AROP. 500 GPM, 1860 PSI,
115 RPM, 15K TQ, 10-15K WOB. 8.9 ppg MW, 44 vis, 10.76 ECD, 64u max gas. 143K PU / 75K SO / 105K ROT. Holding 60 PSI on connections w/ MPD, 65 PSI
line restriction w/ choke open drilling. Target 97° climbing to confirm wellbore placement. Logs showed that had actually entered NA Base at 8675' and NA sand at
9063'. Decision made to POOH and perform openhole sidetrack at 8650'.
Projection at 9210' MD / 3869' TVD, 97.11° inc, 188.99° azm, 30.33' from plan, 28.27' high and 10.98' right. Obtain final survey then BROOH f/ 9210' t/ 9122', 500
GPM, 1840 PSI, 115 RPM, 15K TQ. Line up rig pump for backpressure. POOH on elevators f/ 9122' t/ 8553' holding 120 PSI back pressure w/ MPD dynamic & 60
PSI on connecitons. Service rig while MWD prepares computer for sidetrack. Blow down injection line.
Verify depth against pipe tally and stands in the derrick. Finish preparing for sidetrack. Ream with 100% defleciton at 160L toolface f/ 8555' t/ 8650' two times, then
f/ 8620' t/ 8650' three times. 460 GPM, 1470 PSI, 60 RPM, 8K TQ, 160K PU / 92K SO / 110K ROT. Make connection. Trough f/ 8640' t/ 8670' three times at
100'/hr, 50'/hr and 10-20'/hr. Observed At Bit Inclination drop 0.88° from 91.72° to 90.84°. Time drill f/ 8670' t/ 8675' at 1'/hour. 460 GPM, 1400 PSI, 60 RPM, 7K
TQ, 4K WOB. 8.85 ppg MW, 39 vis, 10.14 ECD, 76u max gas. 160K PU / 92K SO / 110K ROT. Holding 60 PSI on connections w/ MPD, 60 PSI line restriction w/
choke open drilling. Drilled 20 concretions for a total thickness of 99' (6.4% of the lateral). Daily (midnight) losses = 45 bbls, cumulative lateral losses = 57 bbls H2O
from A-Pad: 745 bbls Daily/ 7,875 bbls Total H2O from L-Pad: 0 bbls Daily/ 275 bbls Total H2O from G&I Source Water: 0 bbls Daily/ 720 bbls Total
Cuttings/mud/cement to MPU G&I: 865 bbls Daily / 9,259 bbls Total
7/9/2020 Continue w/ sidetrack, time drill f/ 8675' t/ 8680' @ 2 fph, 8680' to 8685' @ 3 fph w/ 1.2 deg separation f/ old wellbore, increase to 20 fph to 8690', then 50 fph to
8745'
Drop to 89.5 deg, start to turn left towards the plan.
463 GPM, 1400 PSI, 100 RPM, 10K TQ, 3-5K WOB.;Holding 60 PSI on connections w/ MPD, 60 PSI line restriction w/ choke open drilling.
8.85 ppg MW, 38 vis, 10.14 ECD,;BROOH to above sidetrack point f/ 8745' to 8575', run to bttm with pumps off and no rotary, no issues, survey, repeat a 2nd time,
good
463 GPM, 1400 PSI, 100 RPM, 10K TQ;Drill 8-1/2" production hole f/ 8745' t/ 9220' (3901' TVD) 475' drilled, 105.6'/hr AROP.
500 GPM, 1720 PSI, 110 RPM, 9K TQ, 5-15K WOB.
9.0 ppg MW, 43 vis, 10.70 ECD, 384u max gas.
145K PU / 77K SO / 106K ROT.
Holding 90 PSI on connections w/ MPD, 65 PSI line restriction w/ choke open drilling.;Pump 30 bbl hi vis sweep @ 9028', back 200 stks late w/ 40% increase.
Drilled NB clay f/ 8936' t/ 9095', 159' out of zone.
Drill in NB sand, target 93.5 deg.;Drill 8-1/2" production hole f/ 9220' t/ 9955' ( 3877' TVD) 735' drilled, 122.5'/hr AROP.
500 GPM, 1630 PSI, 120 RPM, 10K TQ, 5-15K WOB.
8.9 ppg MW, 42 vis, 10.56 ECD, 345u max gas.
145K PU / 75K SO / 111K ROT.
Holding 95 PSI on connections w/ MPD, 65 PSI line restriction w/ choke open drilling.;290 bbl new mud dump & dilute at 9575', MBT reduced from 6.5 to 4.5#/bbl.
Drill in NB sand, target 92°.;Drill 8-1/2" production hole f/ 9955' t/ 10776' (3848' T VD) 821' drilled, 136.83'/hr AROP.
425 GPM, 1440 PSI, 110 RPM, 10K TQ, 5-10K WOB.
8.85 ppg MW, 39 vis, 10.77 ECD, 604u max gas.
150K PU / 65K SO / 108K ROT.
Holding 100 PSI on connections w/ MPD, 70 PSI line restriction w/ choke open drilling.;Drill in NB sand, target 93°.
Pumped 30 bbl hi vis sweep @ 9980', back 300 stks late w/ 20% increase.
Drilled 33 concretions for a total thickness of 134' (3.9% of the lateral).
Last survey @ 10673.14' MD / 3856.05' TVD, 93.39° inc, 192.03° azm, 10.06' from plan, 0.9' low & 10.02' right.;Daily losses = 0 bbls, Cumulative lateral losses =
57 bbls
H2O from A-Pad: 285 bbls Daily/ 8,160 bbls Total
H2O from L-Pad: 0 bbls Daily/ 275 bbls Total
H2O from G&I Source Water: 0 bbls Daily/ 720 bbls Total
Cuttings/mud/cement to MPU G&I: 845 bbls Daily / 10,104 bbls Total
7/10/2020 Drill 8-1/2" production hole f/ 10776' t/ 11384' (3830' TVD) 608' drilled, 101.3'/hr AROP.
455 GPM, 1550 PSI, 110 RPM, 9-11K TQ, 6-11K WOB.
8.9 ppg MW, 38 vis, 10.6 ppg ECD, 528u max gas.
154K PU / 60K SO / 106K ROT.
Drill in NB-sand, Target 91- 92.5 deg;Holding 100 PSI on connections w/ MPD, 70 PSI line restriction w/ choke open drilling.
Pump 30 bbl hi vis sweep @ 11122', back 600 stks late with 100% increase.;Drill 8-1/2" production hole f/ 11384' t/ 11980' (3819' TVD) 596' drilled, 99.3'/hr AROP.
477 GPM, 1800 PSI, 110 RPM, 13K TQ, 14K WOB.
8.8 ppg MW, 42 vis, 11 ppg ECD, 346u max gas.
159K PU / 59K SO / 103K ROT.;Drilling in the NB sand targeting 89.5 deg.;Drill 8-1/2" production hole f/ 11980' t/ 12579' (3829' TVD) 599' drilled, 99.83'/hr
AROP.
440 GPM, 1740 PSI, 110 RPM, 13K TQ, 2-12K WOB.
9.0 ppg MW, 43 vis, 11.3 ECD, 197u max gas.
160K PU / 53K SO / 100K ROT.
Pump 30 bbl hi vis sweep at 11980', back 900 stks late w/ 25% increase.;Crossed fault #1 at 12000' with 15' DTS throw. Target 89° inclination to re-acquire the NB
sand at 12440'.
Drilled out of zone in NB clays f/ 12000' t/ 12440'.
Holding 100 PSI on connections w/ MPD, 50 PSI line restriction w/ choke open drilling.;Drill 8-1/2" production hole f/ 12579' t/ 13313' (3816' TVD) 734' drilled,
122.33'/hr AROP.
435 GPM, 1760 PSI, 110 RPM, 15K TQ, 6-11K WOB.
9.0 ppg MW, 41 vis, 11.71 ECD, 433u max gas.
160K PU / no SO / 102K ROT.
Perform 290 bbl new mud dilution at 12870'.;Pump 30 bbl hi vis sweep at 13026', back 800 stks late w/ 100% increase. Lost slack off weight at 13026'.
Holding 100 PSI on connections w/ MPD, 50 PSI line restriction w/ choke open drilling.
Drilled 49 concretions for a total thickness of 180' (3.0% of the lateral).;Drilling in NB sand, targeting 92° inc.
Last survey @ 13148.04' MD / 3814.50' TVD, 89.37° inc, 188.28° azm, 27.44' from plan, 27.28' low and 2.95' left.;Daily losses = 5 bbls, Cumulative lateral losses =
62 bbls
H2O from A-Pad: 870 bbls Daily/ 9,030 bbls Total
H2O from L-Pad: 140 bbls Daily/ 415 bbls Total
H2O from G&I Source Water: 0 bbls Daily/ 720 bbls Total
Cuttings/mud/cement to MPU G&I: 1036 bbls Daily / 11,140 bbls Total
7/11/2020 Drill 8-1/2" production hole f/ 13313' t/ 13599' at TD (3813' TVD) 286' drilled, 143'/hr AROP.
465 GPM, 1980 PSI, 110 RPM, 15K TQ, 6-11K WOB.
9.0 ppg MW, 41 vis, 11.55 ECD, 434u max gas.
170K PU / no SO / 100K ROT.
49 concretions were drilled in the lateral, for a total thickness of 180' (2.8%).;Take final survey, 32.58' low and 4.99' left of plan, pump 30 bbl ea tandem lo vis/hi vis
sweep cleaning up the wellbore, 500 gpm, 2200 psi, 110 rpm, 16k torque,
Sweep back 900 stks late w/ 20% increase, circulate total 4.5 BU, rack std back each BU to 13160'
Prep pits for displacing;Ream to bottom due to no slack off weight f/ 13160' t/ 13599' pumping 270 gpm, 900 PSI, 40 RPM, 13k Torque.;PJSM for displacing.
Ready pits, Pump SAPP pill treatment, 30 bbl hi vis spacer, 3- 20 bbl SAPP pills with 50 bbl seawater spacers, chase with 300 bbls seawater 6 bpm, 1020 psi, 35
rpm, 15-17k torque.;Pump 30 bbl hi vis spacer. Displace w/ 905 bbls 8.45 ppg, 3% lubed vissed brine 290 gpm, 1015 PSI, slow to 250 GPM, 750 PSI.
Observe interface @ 13900 stls. Take lubricated brine back to pits @ 14300 stks, only 122 stks beyond calculated. Max gas 1127u
160K PU / 63K SO / 111K ROT w/ lubricated brine;Increase to 350 GPM, 1060 PSI, 40 RPM, 13 TQ - PST tests in & out did not pass.
Increase to 500 GPM, 1390 PSI - 2nd set of PST tests in & out did not pass
Circulated a total of 11847 stks, 1.33 bottoms up. PST out failed, PST in passed, 4.6, 4.62 & 4.65 sec.
Max gas 253u. No losses. Obtain new SPRs.;Perform pressure test with MPD. Trap 70 PSI, pressure built to 114 PSI in 5 min. Bleed to 70 PSI, pressure built to 94
PSI in 7 min.
8.6 ppg MW out, 3966' TVD at shoe with 94 PSI = 9.1 ppg EMW.
Sim-ops: service rig;BROOH f/ 13599' t/ 12590' at 5-10 min/stand as conditions allow. L/D drill pipe in the mousehole.
500 GPM, 1450 PSI, 100 RPM, 16K TQ, 10.3 ECD, max gas 126u.
MPD hold 160 PSI on connections with 55 PSI line pressure while BROOH.
165K PU / no SO / 115K ROT;BROOH f/ 12590' t/ 9962' at 5-10 min/stand as conditions allow. L/D drill pipe in the mousehole.
500 GPM, 1400 PSI, 100 RPM, 13 TQ, 10.11 ECD, max gas 351u.
MPD hold 160 PSI on connections with 55 PSI line pressure while BROOH.
145K PU / 85K SO / 110K ROT;Preformed PST while BROOH @ 03:30 / 11123', mud out did not pass, mud in passed with all 3 samples ±5.5 sec.
37.9 bbls lost while BROOH.;Daily losses = 0 bbls, Cumulative lateral losses = 62 bbls
H2O from A-Pad: 285 bbls Daily/ 9,315 bbls Total
H2O from L-Pad: 50 bbls Daily/ 465 bbls Total
H2O from G&I Source Water: 0 bbls Daily/ 720 bbls Total
Cuttings/mud/cement to MPU G&I: 3,007 bbls Daily / 14,147 bbls Total
7/12/2020 BROOH f/ 9962' t/ 8644' just above sidetrack point at 8650', pass thru with pumps off and no rotary to 8740', survey to confirm wellbore, continue to BROOH to
7793' pulling 5 min/stand as conditions allow. L/D drill pipe in the mousehole.
500 GPM, 1280 PSI, 100 RPM, 5-6 TQ, 9.8 ECD, max gas 347u.;MPD hold 165 PSI on connections with 55 PSI line pressure while BROOH.
135K PU / 95K SO / 115K ROT;Continue to BROOH f/ 7793' to 7130' at the 9 5/8'' shoe, at 7218' slow to 40 rpm pulling BHA into casing
500 GPM, 1280 PSI, 100 RPM, 5-6 TQ, 9.8 ECD, max gas 78u.
MPD hold 165 PSI on connections with 50 PSI line pressure while BROOH.
135K PU / 105K SO / 120K ROT
1 bbl losses;Pump 30 bbl high vis sweep, 500 GPM, 1340 PSI, 40 RPM, 6K TQ, reciprocate 90'.
Sweep on time w/ 25% increase. Circulate until clean 2.25 BU total
Perform PST, all 3 samples passing in/out at 4 seconds;Monitor MPD for pressure build 2 times, bleed off to 0 psi, 1st building f/ 10 psi to 49 psi in 10 min, 2nd to
50 psi in 10 min.
W ith 8.7 ppg MW= 8.94 ppg, static. decision to weight up to 9.1+ with 0 .2 ppg trip margin.;Weight up lubricated brine from 8.7 to 9.1+ ppg over 1.5 circulations
with oilfield salt, 445 GPM, 980 PSI, 40 RPM, 4K TQ. Reciprocate 90'.;With a good 9.1+ in/out Shut down pumps and monitor well, with choke open, flow slowed
from 3 gpm to very slight trickle in 4 min, then static in 1 hr.;PJSM, remove MPD RCD and install trip nipple. Fill stack, check for leaks - none.;POOH f/ 7127' t/
6654' laying down 5" drill pipe. Pump dry job, then continue laying down 5" drill pipe to 2655'.
Drop 2.34' drift. POOH racking back 25 stands of 5" drill pipe f/ 2655' t/ 277'.
16.7 bbls lost on trip out.;Perform flow check - slight losses. L/D 2 HWDP, jars, 3 flex collars, float sub & stab to 83'.
Read MWD tools. L/D MWD tools, Geo-Pilot and bit. Bit graded 1-3-BT-NS-X-I-WT-TD
Excessive wear on string stab and ILS.
3.5 BPH losses.;Clear rig floor. Mobilize and R/U 4-1/2" liner casing equipment: slips, double stack tongs and elevators.
3.5 BPH losses.;PJSM. P/U 4-1/2" Eccentric bull nose shoe on XO shoe joint to 40'.
Run 4-1/2" 13.5# L-80 Hydril 625 liner f/ 40' t/ 82' as per tally.
Torque to 9,600 ft/lbs with Doyon double stack tongs. Install 7.5" centralizer & stop ring free floating on each joint.;Daily losses = 11 bbls, cumulative lateral losses =
73 bbls
H2O from A-Pad: 215 bbls Daily/ 9,530 bbls Total
H2O from L-Pad: 50 bbls Daily/ 515 bbls Total
H2O from G&I Source Water: 0 bbls Daily/ 720 bbls Total
Cuttings/mud/cement to MPU G&I: 604 bbls Daily / 14,751 bbls Total
7/13/2020 Run 4-1/2" 13.5# L-80 Hydril 625 liner f/ 82' t/ 4530' as per tally. Torque to 9,600 ft/lbs with Doyon double stack tongs. Utilize dog collar clamp and BOL 2000 pipe
dope. Install 7.5" centralizer & stop ring free floating on each joint. PU 80K, SO 70K. Loss rate 3.5 bph slowing to .5 bph Run 4-1/2" 13.5# L-80 Hydril 625 liner f/
4530' to 6400' as per tally at jt 147, M/U 8 1/2'' swell packer w/ pups, RIH to 6626'. Torque to 9,600 ft/lbs with Doyon double stack tongs. Install 7.5" centralizer &
stop ring free floating on each joint, Verify pipe count. (152 jts 4.5'' liner, 11 -250 mesh screens, 1- 8 1/2'' tendeka swell packer with pups ran) (154- 4 1/2'' x 7 1/4''
centralizers with 156 stop rings ran). Loss rate continues at .5 bph, 12.5 bbls total. PJSM, C/O handling equipment to 5''. M/U Baker 7" x 9-5/8" SLZXP liner top
packer assy as per BOT rep, verify 9 pins w/ shear set @ 44100#, pusher tool 8 pins @ 2648 psi, PU 100K, SO 80K TIH w/ 4 1/2'' liner on stds of 5'' DP f/ 6665' to
7046', M/U TD, pump 10 bbls at 3 bpm, 180 psi to ensure clear flow path, get parameters before exiting shoe @ 7130', 20 rpm, 3k torque. PU 105k, SO 82K, ROT
90K TIH with 4 1/2'' Liner conveyed on total 24 std 5'' DP f/ 7046' to 8948' no faster than 30 fpm, easy in/out of the slips, pipe auto filling slow, fill on the fly, top off
every 10 stds. Slow down going past side track point at 8650', no issues at this point. Loss rate avg .5 bph Single in with 5'' HWDP f/ 8948' to 13564' no faster than
30 fpm, easy in/out of the slips, pipe auto filling slow, fill on the fly, top off every 10 stds. Pass the PB1 depth at 9210'.*** Notified AOGCC of pre-injection MIT at
18:35. AOGCC inspector Matthew Herrera waived witness at 05:19 *** Fill pipe, 238K PU / 150K SO. RIH w/ stand out of derrick f/ 13564' & tag bottom w/ 5K at
13607'.P/U & break over pipe, on depth at 13599'. Stage up pumps to 6 BPM, 860 PSI & circulate drill pipe volume. Drop 29/32" ball & pump down with high vis pill
3 BPM, 320 PSI. Slow to 1.7 BPM, 270 PSI at 550 stks, ball on seat at 744 stks. Pressure up & observe packer set @ 2740 PSI. Pressure up to 3000 PSI & hold for
5 min. Slack off 25K. Pressure up to 3800 PSI w/ rig pump then test pump & observe tool neutralize @ 4440 PSI. P/U 1' with 215K, 23K less weight to verify
release. Close UPR on 5" drill pipe & test 5" x 9-5/8" annulus to packer to 1700 PSI for 10 min. on chart - good test.
R/D test equipment. P/U out of pack-off. Liner set at 13599' / Top of liner at 6946' Pump 8 BPM, 780 PSI through circ sub from 6957' to 6946' to cleanout tieback
sleeve. Increase to 9.6 BPM, 1060 PSI in 9-5/8" casing f/ 6946' t/ 6943'. Blow down choke & kill lines. Cont. to circ casing clean at 10 BPM, 1150 PSI while
reciprocating f/ 6943' t/ 6851'.
Light sand at bottoms up. Pump 30 bbl high vis spacer then displace wellbore to clean PST passing 9.15 ppg 2% KCl/NaCl brine.
9.7 BPM, 1310 PSI while taking returns to the pits, 7.7 BPM, 805 PSI while taking returns to the rock washer.
Reciprocate f/ 6943' t/ 6851'. Pumped 508 bbls of brine, 419 bbls calculated, 89 bbls of interface.
Blow down top drive. Perform flow check - static.
PU 215K / SO 175K 39.2 bbls daily losses, 112.2 bbls cumulative lateral losses
H2O from A-Pad: 0 bbls Daily/ 9,530 bbls Total
H2O from L-Pad: 65 bbls Daily/ 580 bbls Total
H2O from G&I Source Water: 0 bbls Daily/ 720 bbls Total
Cuttings/mud/cement to MPU G&I: 57 bbls Daily / 14,808 bbls Total
7/14/2020 PJSM, POOH L/D 1 std 5'' DP and 150 jts HWDP F/ 6940' T/ 2326', L/D 5" DP to 1850'
Note: Pump dry job at 5830'
11 bbl losses at this point.;Swap to Completions AFE @ 12:00, see completions report for details
Activity Date Ops Summary
7/14/2020 POOH laying down HWDP and drill pipe. See drilling report for details.
Switch to completions AFE @ 12:00,Continue to TOOH L/D 5'' DP f/ 1850' to surface, L/D and inspect liner running tool, circ sub sheared, rupture disc intact, clear
rig floor.
17.3 bbl losses.,Pull 10'' ID wear bushing, M/U wash tool on joint DP, flush stack. Make tubing hanger dummy run as per WH rep. L/D hanger & landing joint. Load
tools to rig floor.
R/U casing tongs and TEC wire spooler. Ready FOSV and XO. PJSM for running tubing.
1.5 bph loss rate,P/U Baker 7" bullet seal assembly with 8.25'' no-go, XO and pup joint to 18'. Run 3-1/2" 9.3# L-80 EUE tubing as per tally. M/U XN nipple assy at
671' and Centrilift Zenith gauge assy at 734'. Install TEC wire & test gauge - good.
Torque connections to 3100 ft/lbs w/ Doyon double stack tongs.
1.5 bph loss rate,Run 3-1/2" 3-1/2" 9.3# L-80 EUE tubing as per tally f/ 734' t/ 6950'
Torque connections to 3100 ft/lbs w/ Doyon double stack tongs. Install cross-coupler Cannon clamp on 1st five connections above gauge then every other
connection.,Slowly RIH f/ 6950', observed seal drag start at 6959'. No-go on 17.55' in on joint #226 at 6967.73' with 5K.
P/U 6', close annular & pressure up to 400 PSI to verify seals engaged. L/D joints #226, 225 & 224' to 6889'.
P/U 10.18' pup joint, joint 224, hanger w/ pup & landing joint. Perform hanger penetration w/ TEC wire.,Final Zenith gauge readings: 1837 PSI, 1841 PSI, 79°, 79°
& 20.1 volts.
Total of 224 joints, one pup joint and 116 cross coupler Cannon clamps installed.
18.2 bbls lost running tubing.,Drain stack. RIH & land hanger, 81K PU / 64K SO. R/U to reverse circulate.,Daily losses = 73 bbls, Cumulative lateral losses = 185.2
bbls
H2O from A-Pad: 0 bbls Daily/ 9,530 bbls Total
H2O from L-Pad: 85 bbls Daily/ 665 bbls Total
H2O from G&I Source Water: 0 bbls Daily/ 720 bbls Total
Cuttings/mud/cement to MPU G&I: 725 bbls Daily / 15,533 bbls Total
7/15/2020 P/U break over tubing w/ 81K then P/U additional 3'. Close annular, pressure up to 400 PSI to verify seals engaged.
P/U to 6962' exposing ports, PJSM, Pressure test lines.,Reverse circulate 285 bbls of 9.1+ ppg Conqor 303A inhibited brine at 5 BPM, 780 PSI. Reverse circulate
154 bbls of diesel freeze protect at 3.5 bpm, 320 psi ICP, 640 psi FCP. Slack off t/ 1’ above landing hanger, closing ports.
Bleed off trapped annulus pressure to cuttings tank. Blow down diesel in BOP stack to the cuttings tank. BD choke /kill lines.,Land tubing hanger with 24K on
hanger, run in lock down screws as per WH rep..
EOP at 6965.67', locator sub 2.06' off no-go.,Line up to perform IA MIT. Pressure test lines to 3000 PSI - good. Perform 2500 PSI MIT on 3-1/2" x 9-5/8" annulus for
30 minutes on chart - good test. 5 bbls pumped, 5 bbls bled back.
AOGCC inspector Matt Herrera waived witness of IA MIT at 05:19 on 7/14/2020.
SimOps: clear rig floor of casing equipment and TEC spooler,L/D circulating subs, BD and R/D lines, L/D landing joint. WH rep Set BPV with Tee bar. L/D both
mouse holes, PJSM, N/D BOPE, set on stump.,N/U adapter flange and Cameron tree. Feed Centrilift TEC wire through adapter flange, take final readings - Tbg
1688.16 psi, annulus 1587.60 psi, Tbg 77.2 °F, Ann 77 °F, BX= 0, BZ = 0, BT=20.6 volts
Sim-ops: Empty mud pits and rock washer. Move rock washer.,Test hanger void to 500 PSI for 5 min / 5000 PSI for 10 min - good tests.Wellhead rep install BPV
dart. R/U test equipment, test tree to 250/5000 PSI for 5 min each - good tests. R/D test equipment. Pull BPV dart.,R/U to freeze protect tubing, Bullhead 25 bbls
diesel down tbg freeze protecting to 2500', 3 bpm, 150 psi ICP, 2.3 bpm, 1040 psi FCP. Secure tree, Flush lines with water, blow down line to cuttings box, R/D
same.
Clean out cuttings box, Welder cut and cap mouse hole in cellar.
Note: 800 psi under BPV
Release rig @ 18:00,R/D and move rig to L-61. See L-61 report for details.
6/29/2020Spud Date:
Well Name:
Field:
County/State:
MPU L-59
Milne Point Field
Hilcorp Energy Company Composite Report
Alaska
14 July, 2020
Milne Point
M Pt L Pad
MPU L-59i
500292368000
Project:
Company: Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt L Pad
Halliburton
Definitive Survey Report
Well:
Wellbore:
MPU L-59i
MPU L-59i Survey Calculation Method:Minimum Curvature
MPU L-59 Actual RKB @ 49.30usft
Design:MPU L-59i Database:NORTH US + CANADA
MD Reference:MPU L-59 Actual RKB @ 49.30usft
North Reference:
Well MPU L-59i
True
Map System:
Geo Datum:
Project
Map Zone:
System Datum:US State Plane 1927 (Exact solution)
NAD 1927 (NADCON CONUS)
Milne Point, ACT, MILNE POINT
Alaska Zone 04
Mean Sea Level
Using Well Reference Point
Using geodetic scale factor
Well
Well Position
Longitude:
Latitude:
Easting:
Northing:
usft
+E/-W
+N/-S
Position Uncertainty
usft
usft
usftGround Level:
MPU L-59i
usft
usft
0.00
0.00
6,031,945.12
544,633.15
15.50Wellhead Elevation:15.70 usft0.50
70° 29' 53.330 N
149° 38' 5.984 W
Wellbore
Declination
(°)
Field Strength
(nT)
Sample Date Dip Angle
(°)
MPU L-59i
Model NameMagnetics
IFR 7/4/2020 15.97 80.92 57,374.00000000
Phase:Version:
Audit Notes:
Design MPU L-59i
1.0 ACTUAL
Vertical Section: Depth From (TVD)
(usft)
+N/-S
(usft)
Direction
(°)
+E/-W
(usft)
Tie On Depth:8,579.78
191.320.000.0033.60
From
(usft)
Survey Program
DescriptionTool NameSurvey (Wellbore)
To
(usft)
Date 7/14/2020
Survey Date
3_Gyro-GC_Csg H049Gb: North seeking on wireline in casing100.00 1,303.00 MPU L-59PB1 E-line Gyro (MPU L-59PB 06/15/2020
3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sa1,366.01 7,074.34 MPU L-59PB1 MWD_IFR2+MS+Sag (1) 07/01/2020
3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sa7,149.63 8,579.78 MPU L-59PB1 MWD+IFR2+MS+Sag (2) 07/08/2020
3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sa8,650.00 13,530.37 MPU L-59i MWD+IFR2+MS+Sag (3) (MP 07/09/2020
MD
(usft)
Inc
(°)
Azi
(°)
+E/-W
(usft)
+N/-S
(usft)
Survey
TVD
(usft)
TVDSS
(usft)
Map
Northing
(ft)
Map
Easting
(ft)
Vertical
Section
(ft)
DLS
(°/100')Survey Tool Name
33.60 0.00 0.00 33.60 0.00 0.00-15.70 6,031,945.12 544,633.15 0.00 0.00 UNDEFINED
100.00 0.28 215.27 100.00 -0.13 -0.0950.70 6,031,944.99 544,633.06 0.42 0.15 3_Gyro-GC_Csg (1)
168.00 0.36 218.78 168.00 -0.43 -0.32118.70 6,031,944.68 544,632.83 0.12 0.49 3_Gyro-GC_Csg (1)
261.00 0.50 231.53 261.00 -0.91 -0.82211.70 6,031,944.20 544,632.33 0.18 1.06 3_Gyro-GC_Csg (1)
354.00 1.68 238.17 353.98 -1.89 -2.30304.68 6,031,943.22 544,630.86 1.27 2.30 3_Gyro-GC_Csg (1)
449.00 3.62 233.24 448.87 -4.42 -5.89399.57 6,031,940.67 544,627.29 2.05 5.49 3_Gyro-GC_Csg (1)
542.00 5.05 226.07 541.60 -9.01 -11.19492.30 6,031,936.04 544,622.02 1.64 11.03 3_Gyro-GC_Csg (1)
633.00 8.28 221.45 631.98 -16.71 -18.41582.68 6,031,928.31 544,614.84 3.60 19.99 3_Gyro-GC_Csg (1)
733.00 11.90 221.70 730.41 -29.80 -30.04681.11 6,031,915.14 544,603.29 3.62 35.12 3_Gyro-GC_Csg (1)
827.00 14.03 221.51 822.01 -45.57 -44.04772.71 6,031,899.29 544,589.39 2.27 53.33 3_Gyro-GC_Csg (1)
923.00 19.17 221.32 913.98 -66.14 -62.17864.68 6,031,878.61 544,571.38 5.35 77.06 3_Gyro-GC_Csg (1)
7/14/2020 6:20:58PM COMPASS 5000.15 Build 91E Page 2
Project:
Company: Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt L Pad
Halliburton
Definitive Survey Report
Well:
Wellbore:
MPU L-59i
MPU L-59i Survey Calculation Method:Minimum Curvature
MPU L-59 Actual RKB @ 49.30usft
Design:MPU L-59i Database:NORTH US + CANADA
MD Reference:MPU L-59 Actual RKB @ 49.30usft
North Reference:
Well MPU L-59i
True
MD
(usft)
Inc
(°)
Azi
(°)
+E/-W
(usft)
+N/-S
(usft)
Survey
TVD
(usft)
TVDSS
(usft)
Map
Northing
(ft)
Map
Easting
(ft)
Vertical
Section
(ft)
DLS
(°/100')Survey Tool Name
1,018.00 22.81 221.94 1,002.66 -91.56 -84.78953.36 6,031,853.06 544,548.92 3.84 106.42 3_Gyro-GC_Csg (1)
1,113.00 28.03 219.10 1,088.44 -122.60 -111.191,039.14 6,031,821.86 544,522.71 5.64 142.04 3_Gyro-GC_Csg (1)
1,207.00 30.25 217.62 1,170.54 -158.50 -139.581,121.24 6,031,785.80 544,494.54 2.48 182.82 3_Gyro-GC_Csg (1)
1,303.00 29.88 215.30 1,253.62 -197.17 -168.161,204.32 6,031,746.96 544,466.20 1.27 226.35 3_Gyro-GC_Csg (1)
1,366.01 30.63 214.67 1,308.05 -223.19 -186.361,258.75 6,031,720.84 544,448.15 1.29 255.42 3_MWD+IFR2+MS+Sag (2)
1,417.45 32.01 212.48 1,352.00 -245.47 -201.131,302.70 6,031,698.47 544,433.51 3.48 280.17 3_MWD+IFR2+MS+Sag (2)
1,461.46 32.85 210.03 1,389.14 -265.64 -213.371,339.84 6,031,678.23 544,421.40 3.54 302.36 3_MWD+IFR2+MS+Sag (2)
1,556.58 35.71 204.25 1,467.75 -313.31 -237.701,418.45 6,031,630.42 544,397.36 4.55 353.87 3_MWD+IFR2+MS+Sag (2)
1,650.44 35.70 200.73 1,543.98 -363.90 -258.641,494.68 6,031,579.71 544,376.72 2.19 407.59 3_MWD+IFR2+MS+Sag (2)
1,746.03 39.61 196.80 1,619.65 -419.19 -277.331,570.35 6,031,524.31 544,358.37 4.80 465.47 3_MWD+IFR2+MS+Sag (2)
1,840.41 44.98 192.41 1,689.46 -480.63 -293.211,640.16 6,031,462.79 544,342.86 6.49 528.83 3_MWD+IFR2+MS+Sag (2)
1,936.32 46.72 189.84 1,756.26 -548.14 -306.461,706.96 6,031,395.20 544,330.01 2.64 597.63 3_MWD+IFR2+MS+Sag (2)
2,031.88 49.97 186.99 1,819.78 -618.75 -316.871,770.48 6,031,324.53 544,320.04 4.07 668.91 3_MWD+IFR2+MS+Sag (2)
2,127.25 52.60 185.75 1,879.42 -692.70 -325.111,830.12 6,031,250.55 544,312.24 2.94 743.04 3_MWD+IFR2+MS+Sag (2)
2,220.98 58.05 184.80 1,932.73 -769.43 -332.171,883.43 6,031,173.78 544,305.64 5.87 819.66 3_MWD+IFR2+MS+Sag (2)
2,316.91 63.20 183.39 1,979.77 -852.78 -338.111,930.47 6,031,090.41 544,300.20 5.52 902.56 3_MWD+IFR2+MS+Sag (2)
2,410.63 62.91 181.88 2,022.24 -936.24 -341.951,972.94 6,031,006.94 544,296.86 1.47 985.15 3_MWD+IFR2+MS+Sag (2)
2,506.26 62.69 181.96 2,065.95 -1,021.24 -344.802,016.65 6,030,921.92 544,294.52 0.24 1,069.06 3_MWD+IFR2+MS+Sag (2)
2,600.32 63.79 181.60 2,108.30 -1,105.19 -347.412,059.00 6,030,837.97 544,292.42 1.22 1,151.88 3_MWD+IFR2+MS+Sag (2)
2,696.88 63.93 182.02 2,150.84 -1,191.83 -350.152,101.54 6,030,751.33 544,290.20 0.42 1,237.37 3_MWD+IFR2+MS+Sag (2)
2,793.06 64.26 179.56 2,192.87 -1,278.33 -351.342,143.57 6,030,664.83 544,289.53 2.33 1,322.42 3_MWD+IFR2+MS+Sag (2)
2,887.63 62.46 179.61 2,235.27 -1,362.85 -350.732,185.97 6,030,580.32 544,290.65 1.90 1,405.18 3_MWD+IFR2+MS+Sag (2)
2,982.96 62.07 180.45 2,279.63 -1,447.23 -350.772,230.33 6,030,495.95 544,291.11 0.88 1,487.93 3_MWD+IFR2+MS+Sag (2)
3,078.32 62.11 180.77 2,324.27 -1,531.49 -351.672,274.97 6,030,411.69 544,290.72 0.30 1,570.73 3_MWD+IFR2+MS+Sag (2)
3,172.89 61.74 181.79 2,368.78 -1,614.91 -353.532,319.48 6,030,328.27 544,289.36 1.03 1,652.89 3_MWD+IFR2+MS+Sag (2)
3,268.05 61.34 181.98 2,414.13 -1,698.53 -356.282,364.83 6,030,244.65 544,287.11 0.46 1,735.42 3_MWD+IFR2+MS+Sag (2)
3,363.02 61.13 182.11 2,459.83 -1,781.72 -359.252,410.53 6,030,161.45 544,284.64 0.25 1,817.58 3_MWD+IFR2+MS+Sag (2)
3,457.87 62.05 180.98 2,504.96 -1,865.12 -361.502,455.66 6,030,078.05 544,282.89 1.43 1,899.79 3_MWD+IFR2+MS+Sag (2)
3,553.77 61.90 181.35 2,550.02 -1,949.75 -363.222,500.72 6,029,993.41 544,281.68 0.37 1,983.12 3_MWD+IFR2+MS+Sag (2)
3,646.98 62.34 181.58 2,593.60 -2,032.12 -365.322,544.30 6,029,911.04 544,280.07 0.52 2,064.29 3_MWD+IFR2+MS+Sag (2)
3,744.55 62.33 181.26 2,638.90 -2,118.51 -367.472,589.60 6,029,824.65 544,278.45 0.29 2,149.42 3_MWD+IFR2+MS+Sag (2)
3,839.32 62.97 182.03 2,682.44 -2,202.65 -369.882,633.14 6,029,740.51 544,276.54 0.99 2,232.40 3_MWD+IFR2+MS+Sag (2)
3,934.36 64.63 181.30 2,724.40 -2,287.88 -372.362,675.10 6,029,655.27 544,274.57 1.88 2,316.46 3_MWD+IFR2+MS+Sag (2)
4,029.91 62.76 180.47 2,766.75 -2,373.52 -373.692,717.45 6,029,569.63 544,273.76 2.11 2,400.70 3_MWD+IFR2+MS+Sag (2)
4,124.70 60.49 178.27 2,811.80 -2,456.91 -372.792,762.50 6,029,486.26 544,275.16 3.15 2,482.28 3_MWD+IFR2+MS+Sag (2)
4,219.82 59.67 177.08 2,859.24 -2,539.28 -369.442,809.94 6,029,403.92 544,279.00 1.39 2,562.40 3_MWD+IFR2+MS+Sag (2)
4,314.96 59.86 177.65 2,907.15 -2,621.39 -365.672,857.85 6,029,321.84 544,283.27 0.55 2,642.17 3_MWD+IFR2+MS+Sag (2)
4,409.60 60.37 178.59 2,954.30 -2,703.40 -362.982,905.00 6,029,239.85 544,286.45 1.02 2,722.06 3_MWD+IFR2+MS+Sag (2)
4,505.12 61.50 178.62 3,000.71 -2,786.86 -360.942,951.41 6,029,156.41 544,288.98 1.18 2,803.50 3_MWD+IFR2+MS+Sag (2)
4,598.86 62.12 178.54 3,044.99 -2,869.46 -358.902,995.69 6,029,073.84 544,291.53 0.67 2,884.08 3_MWD+IFR2+MS+Sag (2)
7/14/2020 6:20:58PM COMPASS 5000.15 Build 91E Page 3
Project:
Company: Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt L Pad
Halliburton
Definitive Survey Report
Well:
Wellbore:
MPU L-59i
MPU L-59i Survey Calculation Method:Minimum Curvature
MPU L-59 Actual RKB @ 49.30usft
Design:MPU L-59i Database:NORTH US + CANADA
MD Reference:MPU L-59 Actual RKB @ 49.30usft
North Reference:
Well MPU L-59i
True
MD
(usft)
Inc
(°)
Azi
(°)
+E/-W
(usft)
+N/-S
(usft)
Survey
TVD
(usft)
TVDSS
(usft)
Map
Northing
(ft)
Map
Easting
(ft)
Vertical
Section
(ft)
DLS
(°/100')Survey Tool Name
4,694.89 59.99 180.22 3,091.47 -2,953.48 -357.973,042.17 6,028,989.83 544,292.95 2.69 2,966.29 3_MWD+IFR2+MS+Sag (2)
4,789.32 61.20 181.18 3,137.83 -3,035.74 -358.983,088.53 6,028,907.58 544,292.44 1.56 3,047.14 3_MWD+IFR2+MS+Sag (2)
4,884.65 61.13 181.95 3,183.81 -3,119.21 -361.263,134.51 6,028,824.10 544,290.66 0.71 3,129.44 3_MWD+IFR2+MS+Sag (2)
4,980.30 61.55 180.55 3,229.68 -3,203.12 -363.093,180.38 6,028,740.19 544,289.33 1.36 3,212.08 3_MWD+IFR2+MS+Sag (2)
5,075.32 62.05 181.43 3,274.58 -3,286.85 -364.543,225.28 6,028,656.46 544,288.39 0.97 3,294.46 3_MWD+IFR2+MS+Sag (2)
5,170.77 60.95 180.01 3,320.13 -3,370.72 -365.603,270.83 6,028,572.59 544,287.83 1.74 3,376.91 3_MWD+IFR2+MS+Sag (2)
5,265.43 62.34 180.21 3,365.09 -3,454.02 -365.763,315.79 6,028,489.30 544,288.17 1.48 3,458.62 3_MWD+IFR2+MS+Sag (2)
5,360.91 62.10 180.43 3,409.59 -3,538.50 -366.233,360.29 6,028,404.84 544,288.21 0.32 3,541.55 3_MWD+IFR2+MS+Sag (2)
5,455.84 60.64 180.03 3,455.07 -3,621.82 -366.573,405.77 6,028,321.52 544,288.37 1.58 3,623.31 3_MWD+IFR2+MS+Sag (2)
5,550.72 61.51 180.82 3,500.96 -3,704.86 -367.193,451.66 6,028,238.49 544,288.25 1.17 3,704.86 3_MWD+IFR2+MS+Sag (2)
5,645.70 60.35 181.67 3,547.11 -3,787.85 -368.993,497.81 6,028,155.49 544,286.95 1.45 3,786.59 3_MWD+IFR2+MS+Sag (2)
5,741.25 60.34 182.09 3,594.39 -3,870.84 -371.713,545.09 6,028,072.50 544,284.72 0.38 3,868.50 3_MWD+IFR2+MS+Sag (2)
5,835.41 60.99 182.51 3,640.52 -3,952.86 -375.013,591.22 6,027,990.47 544,281.92 0.79 3,949.57 3_MWD+IFR2+MS+Sag (2)
5,930.62 61.89 183.53 3,686.04 -4,036.36 -379.423,636.74 6,027,906.95 544,278.01 1.33 4,032.32 3_MWD+IFR2+MS+Sag (2)
6,026.16 61.34 182.33 3,731.46 -4,120.30 -383.713,682.16 6,027,822.99 544,274.22 1.25 4,115.47 3_MWD+IFR2+MS+Sag (2)
6,121.36 62.26 182.90 3,776.44 -4,204.12 -387.543,727.14 6,027,739.16 544,270.89 1.10 4,198.40 3_MWD+IFR2+MS+Sag (2)
6,216.72 64.27 183.19 3,819.34 -4,289.16 -392.073,770.04 6,027,654.11 544,266.88 2.13 4,282.67 3_MWD+IFR2+MS+Sag (2)
6,312.57 69.76 183.71 3,856.75 -4,377.20 -397.393,807.45 6,027,566.04 544,262.09 5.75 4,370.05 3_MWD+IFR2+MS+Sag (2)
6,406.45 72.84 184.45 3,886.85 -4,465.89 -403.723,837.55 6,027,477.32 544,256.30 3.36 4,458.26 3_MWD+IFR2+MS+Sag (2)
6,502.35 78.82 185.77 3,910.32 -4,558.46 -412.013,861.02 6,027,384.72 544,248.56 6.38 4,550.65 3_MWD+IFR2+MS+Sag (2)
6,597.51 82.26 188.73 3,925.96 -4,651.54 -423.863,876.66 6,027,291.57 544,237.27 4.74 4,644.25 3_MWD+IFR2+MS+Sag (2)
6,693.42 82.02 190.86 3,939.08 -4,745.16 -440.033,889.78 6,027,197.86 544,221.67 2.21 4,739.22 3_MWD+IFR2+MS+Sag (2)
6,788.54 84.63 191.76 3,950.13 -4,837.79 -458.553,900.83 6,027,105.13 544,203.70 2.90 4,833.69 3_MWD+IFR2+MS+Sag (2)
6,884.23 84.24 192.22 3,959.41 -4,930.96 -478.343,910.11 6,027,011.86 544,184.48 0.63 4,928.92 3_MWD+IFR2+MS+Sag (2)
6,978.63 85.86 192.56 3,967.56 -5,022.81 -498.523,918.26 6,026,919.90 544,164.85 1.75 5,022.95 3_MWD+IFR2+MS+Sag (2)
7,074.34 92.15 191.21 3,969.22 -5,116.40 -518.213,919.92 6,026,826.20 544,145.72 6.72 5,118.59 3_MWD+IFR2+MS+Sag (2)
7,149.63 94.14 189.21 3,965.09 -5,190.38 -531.543,915.79 6,026,752.15 544,132.84 3.74 5,193.75 3_MWD+IFR2+MS+Sag (3)
7,244.67 91.96 186.62 3,960.03 -5,284.37 -544.603,910.73 6,026,658.09 544,120.34 3.56 5,288.47 3_MWD+IFR2+MS+Sag (3)
7,341.10 92.65 187.68 3,956.15 -5,379.97 -556.603,906.85 6,026,562.43 544,108.92 1.31 5,384.56 3_MWD+IFR2+MS+Sag (3)
7,436.31 91.28 189.45 3,952.89 -5,474.06 -570.773,903.59 6,026,468.27 544,095.32 2.35 5,479.60 3_MWD+IFR2+MS+Sag (3)
7,531.52 92.34 191.15 3,949.88 -5,567.68 -587.783,900.58 6,026,374.55 544,078.87 2.10 5,574.74 3_MWD+IFR2+MS+Sag (3)
7,628.80 91.10 192.06 3,946.96 -5,662.93 -607.343,897.66 6,026,279.20 544,059.88 1.58 5,671.98 3_MWD+IFR2+MS+Sag (3)
7,721.47 91.29 194.00 3,945.03 -5,753.19 -628.233,895.73 6,026,188.83 544,039.54 2.10 5,764.58 3_MWD+IFR2+MS+Sag (3)
7,816.05 91.66 197.48 3,942.59 -5,844.18 -653.873,893.29 6,026,097.69 544,014.44 3.70 5,858.83 3_MWD+IFR2+MS+Sag (3)
7,911.52 93.02 198.67 3,938.69 -5,934.86 -683.473,889.39 6,026,006.85 543,985.40 1.89 5,953.56 3_MWD+IFR2+MS+Sag (3)
8,008.10 92.58 198.01 3,933.97 -6,026.42 -713.823,884.67 6,025,915.11 543,955.60 0.82 6,049.30 3_MWD+IFR2+MS+Sag (3)
8,103.02 91.65 195.87 3,930.47 -6,117.15 -741.463,881.17 6,025,824.22 543,928.51 2.46 6,143.69 3_MWD+IFR2+MS+Sag (3)
8,198.86 91.96 192.08 3,927.45 -6,210.09 -764.593,878.15 6,025,731.15 543,905.94 3.97 6,239.36 3_MWD+IFR2+MS+Sag (3)
8,294.70 91.10 190.37 3,924.89 -6,304.06 -783.243,875.59 6,025,637.08 543,887.86 2.00 6,335.16 3_MWD+IFR2+MS+Sag (3)
8,388.92 91.35 190.51 3,922.88 -6,396.70 -800.303,873.58 6,025,544.35 543,871.35 0.30 6,429.35 3_MWD+IFR2+MS+Sag (3)
7/14/2020 6:20:58PM COMPASS 5000.15 Build 91E Page 4
Project:
Company: Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt L Pad
Halliburton
Definitive Survey Report
Well:
Wellbore:
MPU L-59i
MPU L-59i Survey Calculation Method:Minimum Curvature
MPU L-59 Actual RKB @ 49.30usft
Design:MPU L-59i Database:NORTH US + CANADA
MD Reference:MPU L-59 Actual RKB @ 49.30usft
North Reference:
Well MPU L-59i
True
MD
(usft)
Inc
(°)
Azi
(°)
+E/-W
(usft)
+N/-S
(usft)
Survey
TVD
(usft)
TVDSS
(usft)
Map
Northing
(ft)
Map
Easting
(ft)
Vertical
Section
(ft)
DLS
(°/100')Survey Tool Name
8,484.60 90.54 191.69 3,921.30 -6,490.58 -818.723,872.00 6,025,450.38 543,853.50 1.50 6,525.02 3_MWD+IFR2+MS+Sag (3)
8,579.78 90.11 190.09 3,920.76 -6,584.04 -836.703,871.46 6,025,356.82 543,836.08 1.74 6,620.19 3_MWD+IFR2+MS+Sag (3)
8,650.00 91.35 190.93 3,919.87 -6,653.07 -849.513,870.57 6,025,287.72 543,823.69 2.13 6,690.39 3_MWD+IFR2+MS+Sag (4)
8,673.51 90.61 191.21 3,919.46 -6,676.14 -854.023,870.16 6,025,264.62 543,819.31 3.37 6,713.90 3_MWD+IFR2+MS+Sag (4)
8,768.85 89.74 189.01 3,919.17 -6,769.99 -870.763,869.87 6,025,170.68 543,803.14 2.48 6,809.21 3_MWD+IFR2+MS+Sag (4)
8,864.43 89.93 188.06 3,919.45 -6,864.51 -884.943,870.15 6,025,076.09 543,789.53 1.01 6,904.68 3_MWD+IFR2+MS+Sag (4)
8,960.13 91.78 188.38 3,918.02 -6,959.22 -898.623,868.72 6,024,981.31 543,776.42 1.96 7,000.22 3_MWD+IFR2+MS+Sag (4)
9,054.64 93.08 189.07 3,914.01 -7,052.55 -912.953,864.71 6,024,887.91 543,762.66 1.56 7,094.55 3_MWD+IFR2+MS+Sag (4)
9,150.60 93.14 188.79 3,908.81 -7,147.20 -927.823,859.51 6,024,793.17 543,748.35 0.30 7,190.28 3_MWD+IFR2+MS+Sag (4)
9,245.93 92.33 188.82 3,904.26 -7,241.30 -942.403,854.96 6,024,699.00 543,734.34 0.85 7,285.41 3_MWD+IFR2+MS+Sag (4)
9,339.55 91.10 188.51 3,901.46 -7,333.81 -956.493,852.16 6,024,606.42 543,720.80 1.35 7,378.89 3_MWD+IFR2+MS+Sag (4)
9,435.40 92.09 189.40 3,898.79 -7,428.45 -971.413,849.49 6,024,511.69 543,706.46 1.39 7,474.62 3_MWD+IFR2+MS+Sag (4)
9,531.03 91.90 190.51 3,895.46 -7,522.58 -987.933,846.16 6,024,417.48 543,690.51 1.18 7,570.16 3_MWD+IFR2+MS+Sag (4)
9,626.98 92.52 192.15 3,891.76 -7,616.59 -1,006.763,842.46 6,024,323.37 543,672.24 1.83 7,666.03 3_MWD+IFR2+MS+Sag (4)
9,720.81 92.46 192.55 3,887.68 -7,708.16 -1,026.813,838.38 6,024,231.68 543,652.74 0.43 7,759.76 3_MWD+IFR2+MS+Sag (4)
9,819.07 92.52 191.64 3,883.41 -7,804.15 -1,047.383,834.11 6,024,135.59 543,632.75 0.93 7,857.92 3_MWD+IFR2+MS+Sag (4)
9,911.91 90.66 191.19 3,880.84 -7,895.11 -1,065.753,831.54 6,024,044.52 543,614.93 2.06 7,950.72 3_MWD+IFR2+MS+Sag (4)
10,007.53 92.27 191.25 3,878.39 -7,988.87 -1,084.353,829.09 6,023,950.66 543,596.90 1.68 8,046.30 3_MWD+IFR2+MS+Sag (4)
10,101.74 91.59 191.90 3,875.22 -8,081.11 -1,103.243,825.92 6,023,858.32 543,578.56 1.00 8,140.46 3_MWD+IFR2+MS+Sag (4)
10,196.55 91.16 192.42 3,872.94 -8,173.77 -1,123.213,823.64 6,023,765.55 543,559.15 0.71 8,235.23 3_MWD+IFR2+MS+Sag (4)
10,291.66 92.65 193.08 3,869.78 -8,266.48 -1,144.183,820.48 6,023,672.73 543,538.74 1.71 8,330.25 3_MWD+IFR2+MS+Sag (4)
10,387.58 91.96 193.26 3,865.92 -8,359.80 -1,166.023,816.62 6,023,579.29 543,517.46 0.74 8,426.05 3_MWD+IFR2+MS+Sag (4)
10,482.23 91.78 193.14 3,862.84 -8,451.90 -1,187.623,813.54 6,023,487.07 543,496.42 0.23 8,520.59 3_MWD+IFR2+MS+Sag (4)
10,577.27 91.53 191.97 3,860.09 -8,544.63 -1,208.273,810.79 6,023,394.23 543,476.32 1.26 8,615.57 3_MWD+IFR2+MS+Sag (4)
10,673.14 93.39 192.03 3,855.98 -8,638.31 -1,228.193,806.68 6,023,300.43 543,456.98 1.94 8,711.34 3_MWD+IFR2+MS+Sag (4)
10,768.62 91.78 191.90 3,851.67 -8,731.62 -1,247.963,802.37 6,023,207.02 543,437.76 1.69 8,806.72 3_MWD+IFR2+MS+Sag (4)
10,863.75 91.66 190.94 3,848.81 -8,824.82 -1,266.793,799.51 6,023,113.71 543,419.50 1.02 8,901.80 3_MWD+IFR2+MS+Sag (4)
10,958.85 92.21 189.67 3,845.60 -8,918.33 -1,283.793,796.30 6,023,020.11 543,403.06 1.45 8,996.83 3_MWD+IFR2+MS+Sag (4)
11,053.53 91.04 189.21 3,842.92 -9,011.69 -1,299.313,793.62 6,022,926.67 543,388.10 1.33 9,091.42 3_MWD+IFR2+MS+Sag (4)
11,149.76 91.29 191.49 3,840.96 -9,106.33 -1,316.593,791.66 6,022,831.94 543,371.39 2.38 9,187.61 3_MWD+IFR2+MS+Sag (4)
11,244.97 92.34 192.87 3,837.95 -9,199.35 -1,336.673,788.65 6,022,738.81 543,351.87 1.82 9,282.76 3_MWD+IFR2+MS+Sag (4)
11,339.47 93.02 193.26 3,833.53 -9,291.30 -1,358.013,784.23 6,022,646.74 543,331.09 0.83 9,377.11 3_MWD+IFR2+MS+Sag (4)
11,434.83 92.58 192.82 3,828.87 -9,384.09 -1,379.503,779.57 6,022,553.83 543,310.16 0.65 9,472.31 3_MWD+IFR2+MS+Sag (4)
11,529.32 90.97 191.43 3,825.94 -9,476.42 -1,399.343,776.64 6,022,461.39 543,290.88 2.25 9,566.74 3_MWD+IFR2+MS+Sag (4)
11,623.54 89.43 188.88 3,825.61 -9,569.15 -1,415.953,776.31 6,022,368.57 543,274.83 3.16 9,660.93 3_MWD+IFR2+MS+Sag (4)
11,719.93 90.11 188.36 3,826.00 -9,664.45 -1,430.393,776.70 6,022,273.20 543,260.95 0.89 9,757.21 3_MWD+IFR2+MS+Sag (4)
11,816.75 91.10 188.35 3,824.98 -9,760.24 -1,444.463,775.68 6,022,177.34 543,247.46 1.02 9,853.90 3_MWD+IFR2+MS+Sag (4)
11,911.14 89.80 189.18 3,824.24 -9,853.52 -1,458.843,774.94 6,022,083.98 543,233.64 1.63 9,948.19 3_MWD+IFR2+MS+Sag (4)
12,005.32 90.61 188.82 3,823.90 -9,946.54 -1,473.583,774.60 6,021,990.88 543,219.47 0.94 10,042.29 3_MWD+IFR2+MS+Sag (4)
12,101.25 89.43 189.41 3,823.87 -10,041.26 -1,488.773,774.57 6,021,896.09 543,204.84 1.38 10,138.14 3_MWD+IFR2+MS+Sag (4)
7/14/2020 6:20:58PM COMPASS 5000.15 Build 91E Page 5
Project:
Company: Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt L Pad
Halliburton
Definitive Survey Report
Well:
Wellbore:
MPU L-59i
MPU L-59i Survey Calculation Method:Minimum Curvature
MPU L-59 Actual RKB @ 49.30usft
Design:MPU L-59i Database:NORTH US + CANADA
MD Reference:MPU L-59 Actual RKB @ 49.30usft
North Reference:
Well MPU L-59i
True
MD
(usft)
Inc
(°)
Azi
(°)
+E/-W
(usft)
+N/-S
(usft)
Survey
TVD
(usft)
TVDSS
(usft)
Map
Northing
(ft)
Map
Easting
(ft)
Vertical
Section
(ft)
DLS
(°/100')Survey Tool Name
12,195.95 89.25 190.80 3,824.96 -10,134.48 -1,505.393,775.66 6,021,802.77 543,188.79 1.48 10,232.81 3_MWD+IFR2+MS+Sag (4)
12,292.47 90.17 191.57 3,825.45 -10,229.16 -1,524.113,776.15 6,021,707.99 543,170.64 1.24 10,329.33 3_MWD+IFR2+MS+Sag (4)
12,382.28 89.93 191.93 3,825.37 -10,317.09 -1,542.403,776.07 6,021,619.96 543,152.88 0.48 10,419.14 3_MWD+IFR2+MS+Sag (4)
12,481.00 88.75 192.77 3,826.50 -10,413.52 -1,563.513,777.20 6,021,523.42 543,132.35 1.47 10,517.83 3_MWD+IFR2+MS+Sag (4)
12,576.93 90.42 194.75 3,827.20 -10,506.68 -1,586.333,777.90 6,021,430.13 543,110.10 2.70 10,613.67 3_MWD+IFR2+MS+Sag (4)
12,672.79 91.90 194.05 3,825.26 -10,599.51 -1,610.163,775.96 6,021,337.17 543,086.82 1.71 10,709.36 3_MWD+IFR2+MS+Sag (4)
12,766.31 93.39 193.45 3,820.94 -10,690.25 -1,632.363,771.64 6,021,246.31 543,065.17 1.72 10,802.70 3_MWD+IFR2+MS+Sag (4)
12,863.54 92.21 193.13 3,816.19 -10,784.76 -1,654.693,766.89 6,021,151.67 543,043.41 1.26 10,899.75 3_MWD+IFR2+MS+Sag (4)
12,957.95 90.73 191.32 3,813.77 -10,876.99 -1,674.673,764.47 6,021,059.33 543,023.99 2.48 10,994.11 3_MWD+IFR2+MS+Sag (4)
13,053.87 89.55 187.99 3,813.54 -10,971.54 -1,690.753,764.24 6,020,964.70 543,008.47 3.68 11,089.98 3_MWD+IFR2+MS+Sag (4)
13,148.04 89.37 188.28 3,814.42 -11,064.76 -1,704.083,765.12 6,020,871.41 542,995.71 0.36 11,184.00 3_MWD+IFR2+MS+Sag (4)
13,242.87 90.92 190.60 3,814.18 -11,158.29 -1,719.633,764.88 6,020,777.79 542,980.72 2.94 11,278.77 3_MWD+IFR2+MS+Sag (4)
13,338.56 92.22 191.99 3,811.56 -11,252.09 -1,738.373,762.26 6,020,683.89 542,962.55 1.99 11,374.42 3_MWD+IFR2+MS+Sag (4)
13,434.44 90.29 191.57 3,809.46 -11,345.93 -1,757.933,760.16 6,020,589.95 542,943.55 2.06 11,470.27 3_MWD+IFR2+MS+Sag (4)
13,530.37 89.99 192.16 3,809.23 -11,439.80 -1,777.663,759.93 6,020,495.97 542,924.39 0.69 11,566.19 3_MWD+IFR2+MS+Sag (4)
13,599.00 89.99 192.16 3,809.24 -11,506.89 -1,792.113,759.94 6,020,428.80 542,910.34 0.00 11,634.81 PROJECTED to TD
Approved By:Checked By:Date:
7/14/2020 6:20:58PM COMPASS 5000.15 Build 91E Page 6
Chelsea Wright Digitally signed by Chelsea
Wright
Date: 2020.07.14 15:26:48 -08'00'
Benjamin Hand Digitally signed by Benjamin Hand
Date: 2020.07.14 17:21:45 -08'00'
14 July, 2020
Milne Point
M Pt L Pad
MPU L-59PB1
500292368070
Project:
Company: Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt L Pad
Halliburton
Definitive Survey Report
Well:
Wellbore:
MPU L-59i
MPU L-59PB1 Survey Calculation Method:Minimum Curvature
MPU L-59 Actual RKB @ 49.30usft
Design:MPU L-59PB1 Database:NORTH US + CANADA
MD Reference:MPU L-59 Actual RKB @ 49.30usft
North Reference:
Well MPU L-59i
True
Map System:
Geo Datum:
Project
Map Zone:
System Datum:US State Plane 1927 (Exact solution)
NAD 1927 (NADCON CONUS)
Milne Point, ACT, MILNE POINT
Alaska Zone 04
Mean Sea Level
Using Well Reference Point
Using geodetic scale factor
Well
Well Position
Longitude:
Latitude:
Easting:
Northing:
usft
+E/-W
+N/-S
Position Uncertainty
usft
usft
usftGround Level:
MPU L-59i
usft
usft
0.00
0.00
6,031,945.12
544,633.15
15.50Wellhead Elevation:15.70 usft0.50
70° 29' 53.330 N
149° 38' 5.984 W
Wellbore
Declination
(°)
Field Strength
(nT)
Sample Date Dip Angle
(°)
MPU L-59PB1
Model NameMagnetics
IFR 7/4/2020 15.97 80.92 57,374.00000000
Phase:Version:
Audit Notes:
Design MPU L-59PB1
1.0 ACTUAL
Vertical Section: Depth From (TVD)
(usft)
+N/-S
(usft)
Direction
(°)
+E/-W
(usft)
Tie On Depth:33.60
191.320.000.0033.60
From
(usft)
Survey Program
DescriptionTool NameSurvey (Wellbore)
To
(usft)
Date 7/9/2020
Survey Date
3_Gyro-GC_Csg H049Gb: North seeking on wireline in casing100.00 1,303.00 MPU L-59PB1 E-line Gyro (MPU L-59PB 06/15/2020
3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sa1,366.01 7,074.34 MPU L-59PB1 MWD_IFR2+MS+Sag (1) 07/01/2020
3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sa7,149.63 9,139.48 MPU L-59PB1 MWD+IFR2+MS+Sag (2) 07/08/2020
MD
(usft)
Inc
(°)
Azi
(°)
+E/-W
(usft)
+N/-S
(usft)
Survey
TVD
(usft)
TVDSS
(usft)
Map
Northing
(ft)
Map
Easting
(ft)
Vertical
Section
(ft)
DLS
(°/100')Survey Tool Name
33.60 0.00 0.00 33.60 0.00 0.00-15.70 6,031,945.12 544,633.15 0.00 0.00 UNDEFINED
100.00 0.28 215.27 100.00 -0.13 -0.0950.70 6,031,944.99 544,633.06 0.42 0.15 3_Gyro-GC_Csg (1)
168.00 0.36 218.78 168.00 -0.43 -0.32118.70 6,031,944.68 544,632.83 0.12 0.49 3_Gyro-GC_Csg (1)
261.00 0.50 231.53 261.00 -0.91 -0.82211.70 6,031,944.20 544,632.33 0.18 1.06 3_Gyro-GC_Csg (1)
354.00 1.68 238.17 353.98 -1.89 -2.30304.68 6,031,943.22 544,630.86 1.27 2.30 3_Gyro-GC_Csg (1)
449.00 3.62 233.24 448.87 -4.42 -5.89399.57 6,031,940.67 544,627.29 2.05 5.49 3_Gyro-GC_Csg (1)
542.00 5.05 226.07 541.60 -9.01 -11.19492.30 6,031,936.04 544,622.02 1.64 11.03 3_Gyro-GC_Csg (1)
633.00 8.28 221.45 631.98 -16.71 -18.41582.68 6,031,928.31 544,614.84 3.60 19.99 3_Gyro-GC_Csg (1)
733.00 11.90 221.70 730.41 -29.80 -30.04681.11 6,031,915.14 544,603.29 3.62 35.12 3_Gyro-GC_Csg (1)
827.00 14.03 221.51 822.01 -45.57 -44.04772.71 6,031,899.29 544,589.39 2.27 53.33 3_Gyro-GC_Csg (1)
923.00 19.17 221.32 913.98 -66.14 -62.17864.68 6,031,878.61 544,571.38 5.35 77.06 3_Gyro-GC_Csg (1)
1,018.00 22.81 221.94 1,002.66 -91.56 -84.78953.36 6,031,853.06 544,548.92 3.84 106.42 3_Gyro-GC_Csg (1)
7/14/2020 6:20:00PM COMPASS 5000.15 Build 91E Page 2
Project:
Company: Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt L Pad
Halliburton
Definitive Survey Report
Well:
Wellbore:
MPU L-59i
MPU L-59PB1 Survey Calculation Method:Minimum Curvature
MPU L-59 Actual RKB @ 49.30usft
Design:MPU L-59PB1 Database:NORTH US + CANADA
MD Reference:MPU L-59 Actual RKB @ 49.30usft
North Reference:
Well MPU L-59i
True
MD
(usft)
Inc
(°)
Azi
(°)
+E/-W
(usft)
+N/-S
(usft)
Survey
TVD
(usft)
TVDSS
(usft)
Map
Northing
(ft)
Map
Easting
(ft)
Vertical
Section
(ft)
DLS
(°/100')Survey Tool Name
1,113.00 28.03 219.10 1,088.44 -122.60 -111.191,039.14 6,031,821.86 544,522.71 5.64 142.04 3_Gyro-GC_Csg (1)
1,207.00 30.25 217.62 1,170.54 -158.50 -139.581,121.24 6,031,785.80 544,494.54 2.48 182.82 3_Gyro-GC_Csg (1)
1,303.00 29.88 215.30 1,253.62 -197.17 -168.161,204.32 6,031,746.96 544,466.20 1.27 226.35 3_Gyro-GC_Csg (1)
1,366.01 30.63 214.67 1,308.05 -223.19 -186.361,258.75 6,031,720.84 544,448.15 1.29 255.42 3_MWD+IFR2+MS+Sag (2)
1,417.45 32.01 212.48 1,352.00 -245.47 -201.131,302.70 6,031,698.47 544,433.51 3.48 280.17 3_MWD+IFR2+MS+Sag (2)
1,461.46 32.85 210.03 1,389.14 -265.64 -213.371,339.84 6,031,678.23 544,421.40 3.54 302.36 3_MWD+IFR2+MS+Sag (2)
1,556.58 35.71 204.25 1,467.75 -313.31 -237.701,418.45 6,031,630.42 544,397.36 4.55 353.87 3_MWD+IFR2+MS+Sag (2)
1,650.44 35.70 200.73 1,543.98 -363.90 -258.641,494.68 6,031,579.71 544,376.72 2.19 407.59 3_MWD+IFR2+MS+Sag (2)
1,746.03 39.61 196.80 1,619.65 -419.19 -277.331,570.35 6,031,524.31 544,358.37 4.80 465.47 3_MWD+IFR2+MS+Sag (2)
1,840.41 44.98 192.41 1,689.46 -480.63 -293.211,640.16 6,031,462.79 544,342.86 6.49 528.83 3_MWD+IFR2+MS+Sag (2)
1,936.32 46.72 189.84 1,756.26 -548.14 -306.461,706.96 6,031,395.20 544,330.01 2.64 597.63 3_MWD+IFR2+MS+Sag (2)
2,031.88 49.97 186.99 1,819.78 -618.75 -316.871,770.48 6,031,324.53 544,320.04 4.07 668.91 3_MWD+IFR2+MS+Sag (2)
2,127.25 52.60 185.75 1,879.42 -692.70 -325.111,830.12 6,031,250.55 544,312.24 2.94 743.04 3_MWD+IFR2+MS+Sag (2)
2,220.98 58.05 184.80 1,932.73 -769.43 -332.171,883.43 6,031,173.78 544,305.64 5.87 819.66 3_MWD+IFR2+MS+Sag (2)
2,316.91 63.20 183.39 1,979.77 -852.78 -338.111,930.47 6,031,090.41 544,300.20 5.52 902.56 3_MWD+IFR2+MS+Sag (2)
2,410.63 62.91 181.88 2,022.24 -936.24 -341.951,972.94 6,031,006.94 544,296.86 1.47 985.15 3_MWD+IFR2+MS+Sag (2)
2,506.26 62.69 181.96 2,065.95 -1,021.24 -344.802,016.65 6,030,921.92 544,294.52 0.24 1,069.06 3_MWD+IFR2+MS+Sag (2)
2,600.32 63.79 181.60 2,108.30 -1,105.19 -347.412,059.00 6,030,837.97 544,292.42 1.22 1,151.88 3_MWD+IFR2+MS+Sag (2)
2,696.88 63.93 182.02 2,150.84 -1,191.83 -350.152,101.54 6,030,751.33 544,290.20 0.42 1,237.37 3_MWD+IFR2+MS+Sag (2)
2,793.06 64.26 179.56 2,192.87 -1,278.33 -351.342,143.57 6,030,664.83 544,289.53 2.33 1,322.42 3_MWD+IFR2+MS+Sag (2)
2,887.63 62.46 179.61 2,235.27 -1,362.85 -350.732,185.97 6,030,580.32 544,290.65 1.90 1,405.18 3_MWD+IFR2+MS+Sag (2)
2,982.96 62.07 180.45 2,279.63 -1,447.23 -350.772,230.33 6,030,495.95 544,291.11 0.88 1,487.93 3_MWD+IFR2+MS+Sag (2)
3,078.32 62.11 180.77 2,324.27 -1,531.49 -351.672,274.97 6,030,411.69 544,290.72 0.30 1,570.73 3_MWD+IFR2+MS+Sag (2)
3,172.89 61.74 181.79 2,368.78 -1,614.91 -353.532,319.48 6,030,328.27 544,289.36 1.03 1,652.89 3_MWD+IFR2+MS+Sag (2)
3,268.05 61.34 181.98 2,414.13 -1,698.53 -356.282,364.83 6,030,244.65 544,287.11 0.46 1,735.42 3_MWD+IFR2+MS+Sag (2)
3,363.02 61.13 182.11 2,459.83 -1,781.72 -359.252,410.53 6,030,161.45 544,284.64 0.25 1,817.58 3_MWD+IFR2+MS+Sag (2)
3,457.87 62.05 180.98 2,504.96 -1,865.12 -361.502,455.66 6,030,078.05 544,282.89 1.43 1,899.79 3_MWD+IFR2+MS+Sag (2)
3,553.77 61.90 181.35 2,550.02 -1,949.75 -363.222,500.72 6,029,993.41 544,281.68 0.37 1,983.12 3_MWD+IFR2+MS+Sag (2)
3,646.98 62.34 181.58 2,593.60 -2,032.12 -365.322,544.30 6,029,911.04 544,280.07 0.52 2,064.29 3_MWD+IFR2+MS+Sag (2)
3,744.55 62.33 181.26 2,638.90 -2,118.51 -367.472,589.60 6,029,824.65 544,278.45 0.29 2,149.42 3_MWD+IFR2+MS+Sag (2)
3,839.32 62.97 182.03 2,682.44 -2,202.65 -369.882,633.14 6,029,740.51 544,276.54 0.99 2,232.40 3_MWD+IFR2+MS+Sag (2)
3,934.36 64.63 181.30 2,724.40 -2,287.88 -372.362,675.10 6,029,655.27 544,274.57 1.88 2,316.46 3_MWD+IFR2+MS+Sag (2)
4,029.91 62.76 180.47 2,766.75 -2,373.52 -373.692,717.45 6,029,569.63 544,273.76 2.11 2,400.70 3_MWD+IFR2+MS+Sag (2)
4,124.70 60.49 178.27 2,811.80 -2,456.91 -372.792,762.50 6,029,486.26 544,275.16 3.15 2,482.28 3_MWD+IFR2+MS+Sag (2)
4,219.82 59.67 177.08 2,859.24 -2,539.28 -369.442,809.94 6,029,403.92 544,279.00 1.39 2,562.40 3_MWD+IFR2+MS+Sag (2)
4,314.96 59.86 177.65 2,907.15 -2,621.39 -365.672,857.85 6,029,321.84 544,283.27 0.55 2,642.17 3_MWD+IFR2+MS+Sag (2)
4,409.60 60.37 178.59 2,954.30 -2,703.40 -362.982,905.00 6,029,239.85 544,286.45 1.02 2,722.06 3_MWD+IFR2+MS+Sag (2)
4,505.12 61.50 178.62 3,000.71 -2,786.86 -360.942,951.41 6,029,156.41 544,288.98 1.18 2,803.50 3_MWD+IFR2+MS+Sag (2)
4,598.86 62.12 178.54 3,044.99 -2,869.46 -358.902,995.69 6,029,073.84 544,291.53 0.67 2,884.08 3_MWD+IFR2+MS+Sag (2)
4,694.89 59.99 180.22 3,091.47 -2,953.48 -357.973,042.17 6,028,989.83 544,292.95 2.69 2,966.29 3_MWD+IFR2+MS+Sag (2)
7/14/2020 6:20:00PM COMPASS 5000.15 Build 91E Page 3
Project:
Company: Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt L Pad
Halliburton
Definitive Survey Report
Well:
Wellbore:
MPU L-59i
MPU L-59PB1 Survey Calculation Method:Minimum Curvature
MPU L-59 Actual RKB @ 49.30usft
Design:MPU L-59PB1 Database:NORTH US + CANADA
MD Reference:MPU L-59 Actual RKB @ 49.30usft
North Reference:
Well MPU L-59i
True
MD
(usft)
Inc
(°)
Azi
(°)
+E/-W
(usft)
+N/-S
(usft)
Survey
TVD
(usft)
TVDSS
(usft)
Map
Northing
(ft)
Map
Easting
(ft)
Vertical
Section
(ft)
DLS
(°/100')Survey Tool Name
4,789.32 61.20 181.18 3,137.83 -3,035.74 -358.983,088.53 6,028,907.58 544,292.44 1.56 3,047.14 3_MWD+IFR2+MS+Sag (2)
4,884.65 61.13 181.95 3,183.81 -3,119.21 -361.263,134.51 6,028,824.10 544,290.66 0.71 3,129.44 3_MWD+IFR2+MS+Sag (2)
4,980.30 61.55 180.55 3,229.68 -3,203.12 -363.093,180.38 6,028,740.19 544,289.33 1.36 3,212.08 3_MWD+IFR2+MS+Sag (2)
5,075.32 62.05 181.43 3,274.58 -3,286.85 -364.543,225.28 6,028,656.46 544,288.39 0.97 3,294.46 3_MWD+IFR2+MS+Sag (2)
5,170.77 60.95 180.01 3,320.13 -3,370.72 -365.603,270.83 6,028,572.59 544,287.83 1.74 3,376.91 3_MWD+IFR2+MS+Sag (2)
5,265.43 62.34 180.21 3,365.09 -3,454.02 -365.763,315.79 6,028,489.30 544,288.17 1.48 3,458.62 3_MWD+IFR2+MS+Sag (2)
5,360.91 62.10 180.43 3,409.59 -3,538.50 -366.233,360.29 6,028,404.84 544,288.21 0.32 3,541.55 3_MWD+IFR2+MS+Sag (2)
5,455.84 60.64 180.03 3,455.07 -3,621.82 -366.573,405.77 6,028,321.52 544,288.37 1.58 3,623.31 3_MWD+IFR2+MS+Sag (2)
5,550.72 61.51 180.82 3,500.96 -3,704.86 -367.193,451.66 6,028,238.49 544,288.25 1.17 3,704.86 3_MWD+IFR2+MS+Sag (2)
5,645.70 60.35 181.67 3,547.11 -3,787.85 -368.993,497.81 6,028,155.49 544,286.95 1.45 3,786.59 3_MWD+IFR2+MS+Sag (2)
5,741.25 60.34 182.09 3,594.39 -3,870.84 -371.713,545.09 6,028,072.50 544,284.72 0.38 3,868.50 3_MWD+IFR2+MS+Sag (2)
5,835.41 60.99 182.51 3,640.52 -3,952.86 -375.013,591.22 6,027,990.47 544,281.92 0.79 3,949.57 3_MWD+IFR2+MS+Sag (2)
5,930.62 61.89 183.53 3,686.04 -4,036.36 -379.423,636.74 6,027,906.95 544,278.01 1.33 4,032.32 3_MWD+IFR2+MS+Sag (2)
6,026.16 61.34 182.33 3,731.46 -4,120.30 -383.713,682.16 6,027,822.99 544,274.22 1.25 4,115.47 3_MWD+IFR2+MS+Sag (2)
6,121.36 62.26 182.90 3,776.44 -4,204.12 -387.543,727.14 6,027,739.16 544,270.89 1.10 4,198.40 3_MWD+IFR2+MS+Sag (2)
6,216.72 64.27 183.19 3,819.34 -4,289.16 -392.073,770.04 6,027,654.11 544,266.88 2.13 4,282.67 3_MWD+IFR2+MS+Sag (2)
6,312.57 69.76 183.71 3,856.75 -4,377.20 -397.393,807.45 6,027,566.04 544,262.09 5.75 4,370.05 3_MWD+IFR2+MS+Sag (2)
6,406.45 72.84 184.45 3,886.85 -4,465.89 -403.723,837.55 6,027,477.32 544,256.30 3.36 4,458.26 3_MWD+IFR2+MS+Sag (2)
6,502.35 78.82 185.77 3,910.32 -4,558.46 -412.013,861.02 6,027,384.72 544,248.56 6.38 4,550.65 3_MWD+IFR2+MS+Sag (2)
6,597.51 82.26 188.73 3,925.96 -4,651.54 -423.863,876.66 6,027,291.57 544,237.27 4.74 4,644.25 3_MWD+IFR2+MS+Sag (2)
6,693.42 82.02 190.86 3,939.08 -4,745.16 -440.033,889.78 6,027,197.86 544,221.67 2.21 4,739.22 3_MWD+IFR2+MS+Sag (2)
6,788.54 84.63 191.76 3,950.13 -4,837.79 -458.553,900.83 6,027,105.13 544,203.70 2.90 4,833.69 3_MWD+IFR2+MS+Sag (2)
6,884.23 84.24 192.22 3,959.41 -4,930.96 -478.343,910.11 6,027,011.86 544,184.48 0.63 4,928.92 3_MWD+IFR2+MS+Sag (2)
6,978.63 85.86 192.56 3,967.56 -5,022.81 -498.523,918.26 6,026,919.90 544,164.85 1.75 5,022.95 3_MWD+IFR2+MS+Sag (2)
7,074.34 92.15 191.21 3,969.22 -5,116.40 -518.213,919.92 6,026,826.20 544,145.72 6.72 5,118.59 3_MWD+IFR2+MS+Sag (2)
7,149.63 94.14 189.21 3,965.09 -5,190.38 -531.543,915.79 6,026,752.15 544,132.84 3.74 5,193.75 3_MWD+IFR2+MS+Sag (3)
7,244.67 91.96 186.62 3,960.03 -5,284.37 -544.603,910.73 6,026,658.09 544,120.34 3.56 5,288.47 3_MWD+IFR2+MS+Sag (3)
7,341.10 92.65 187.68 3,956.15 -5,379.97 -556.603,906.85 6,026,562.43 544,108.92 1.31 5,384.56 3_MWD+IFR2+MS+Sag (3)
7,436.31 91.28 189.45 3,952.89 -5,474.06 -570.773,903.59 6,026,468.27 544,095.32 2.35 5,479.60 3_MWD+IFR2+MS+Sag (3)
7,531.52 92.34 191.15 3,949.88 -5,567.68 -587.783,900.58 6,026,374.55 544,078.87 2.10 5,574.74 3_MWD+IFR2+MS+Sag (3)
7,628.80 91.10 192.06 3,946.96 -5,662.93 -607.343,897.66 6,026,279.20 544,059.88 1.58 5,671.98 3_MWD+IFR2+MS+Sag (3)
7,721.47 91.29 194.00 3,945.03 -5,753.19 -628.233,895.73 6,026,188.83 544,039.54 2.10 5,764.58 3_MWD+IFR2+MS+Sag (3)
7,816.05 91.66 197.48 3,942.59 -5,844.18 -653.873,893.29 6,026,097.69 544,014.44 3.70 5,858.83 3_MWD+IFR2+MS+Sag (3)
7,911.52 93.02 198.67 3,938.69 -5,934.86 -683.473,889.39 6,026,006.85 543,985.40 1.89 5,953.56 3_MWD+IFR2+MS+Sag (3)
8,008.10 92.58 198.01 3,933.97 -6,026.42 -713.823,884.67 6,025,915.11 543,955.60 0.82 6,049.30 3_MWD+IFR2+MS+Sag (3)
8,103.02 91.65 195.87 3,930.47 -6,117.15 -741.463,881.17 6,025,824.22 543,928.51 2.46 6,143.69 3_MWD+IFR2+MS+Sag (3)
8,198.86 91.96 192.08 3,927.45 -6,210.09 -764.593,878.15 6,025,731.15 543,905.94 3.97 6,239.36 3_MWD+IFR2+MS+Sag (3)
8,294.70 91.10 190.37 3,924.89 -6,304.06 -783.243,875.59 6,025,637.08 543,887.86 2.00 6,335.16 3_MWD+IFR2+MS+Sag (3)
8,388.92 91.35 190.51 3,922.88 -6,396.70 -800.303,873.58 6,025,544.35 543,871.35 0.30 6,429.35 3_MWD+IFR2+MS+Sag (3)
8,484.60 90.54 191.69 3,921.30 -6,490.58 -818.723,872.00 6,025,450.38 543,853.50 1.50 6,525.02 3_MWD+IFR2+MS+Sag (3)
7/14/2020 6:20:00PM COMPASS 5000.15 Build 91E Page 4
Project:
Company: Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt L Pad
Halliburton
Definitive Survey Report
Well:
Wellbore:
MPU L-59i
MPU L-59PB1 Survey Calculation Method:Minimum Curvature
MPU L-59 Actual RKB @ 49.30usft
Design:MPU L-59PB1 Database:NORTH US + CANADA
MD Reference:MPU L-59 Actual RKB @ 49.30usft
North Reference:
Well MPU L-59i
True
MD
(usft)
Inc
(°)
Azi
(°)
+E/-W
(usft)
+N/-S
(usft)
Survey
TVD
(usft)
TVDSS
(usft)
Map
Northing
(ft)
Map
Easting
(ft)
Vertical
Section
(ft)
DLS
(°/100')Survey Tool Name
8,579.78 90.11 190.09 3,920.76 -6,584.04 -836.703,871.46 6,025,356.82 543,836.08 1.74 6,620.19 3_MWD+IFR2+MS+Sag (3)
8,674.43 91.78 191.22 3,919.20 -6,677.04 -854.203,869.90 6,025,263.73 543,819.14 2.13 6,714.81 3_MWD+IFR2+MS+Sag (3)
8,770.03 94.51 191.57 3,913.95 -6,770.60 -873.063,864.65 6,025,170.06 543,800.85 2.88 6,810.26 3_MWD+IFR2+MS+Sag (3)
8,865.77 94.56 189.35 3,906.38 -6,864.45 -890.383,857.08 6,025,076.12 543,784.09 2.31 6,905.68 3_MWD+IFR2+MS+Sag (3)
8,961.04 95.86 188.35 3,897.73 -6,958.20 -904.983,848.43 6,024,982.30 543,770.06 1.72 7,000.47 3_MWD+IFR2+MS+Sag (3)
9,056.80 95.18 188.04 3,888.52 -7,052.54 -918.573,839.22 6,024,887.88 543,757.04 0.78 7,095.64 3_MWD+IFR2+MS+Sag (3)
9,139.48 97.11 188.99 3,879.67 -7,133.83 -930.743,830.37 6,024,806.53 543,745.36 2.60 7,177.74 3_MWD+IFR2+MS+Sag (3)
9,210.00 97.11 188.99 3,870.94 -7,202.95 -941.673,821.64 6,024,737.35 543,734.84 0.00 7,247.66 PROJECTED to TD
Approved By:Checked By:Date:
7/14/2020 6:20:00PM COMPASS 5000.15 Build 91E Page 5
Chelsea Wright Digitally signed by Chelsea
Wright
Date: 2020.07.14 15:25:23 -08'00'
Benjamin Hand Digitally signed by Benjamin Hand
Date: 2020.07.14 17:18:18 -08'00'
TD Shoe Depth: PBTD:
No. Jts. Returned
RKB RKB to BHF RKB to THF
Jts.
1
2
1
1
1
115
1
1
1
53
1
X Yes No X Yes No
Fluid Description:
Liner hanger Info (Make/Model): Liner top Packer?: Yes No
Liner hanger test pressure:X Yes No
Centralizer Placement:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:X Yes No
Casing Rotated?X Yes No Reciprocated?X Yes No % Returns during job
Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:X Yes No
Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job
Cement returns to surface?X Yes No Spacer returns? Yes X No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Post Job Calculations:
Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped:
Cmt returned to surface: Calculated cement left in wellbore:
OH volume Calculated: OH volume actual: Actual % Washout:
1.17
7/6/2020 36
Spud Mud
Lead Type I/II 640 2.35
Premium G Tail 400 1.15
6.2
2,379.32
Casing 9 5/8 47.0 L-80 TXP BTC-SR Tenaris 2,324.83 2,379.32 54.49
2,397.00 2,394.16
Pup Joint 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 14.84 2,394.16
14.77 2,411.77 2,397.00
ES II Cementer 10 3/4 TXP BTC-SR HES 2.84
Pup Joint 9 5/8 40.0 L-80 TXP BTC-SR Tenaris
7,005.41
Casing 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 4,593.64 7,005.41 2,411.77
7,046.27 7,006.86
Baffle Adapter 10 3/4 TXP BTC-SR HES 1.45 7,006.86
1.36 7,047.63 7,046.27
Casing 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 39.41
Float Collar 10 3/4 TXP BTC-SR Innovex
89 total 9-5/8"x12-1/4" bowspring centralizers ran.
2 on joint #1 with 4 stop rings. 1 free floating on joint #2. 1 each mid-joint on #3&4 wit 4 stop rings.
1 each free floating on joints #5 to 25.
1 each free floating every other joint #27 to 49.
1 each free floating every third joint #49 to 112.
1 each free floating on joint #115 to 118.
1 each on pup joint above and below ES cementer w/ 2 stop rings.
1 each free floating on joint #119 to 127.
1 each free floating every third joint #127 to 172
Casing 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 80.75 7,128.38 7,047.63
www.wellez.net WellEz Information Management LLC ver_04818br
5.2
Ftg. Returned
Ftg. Cut Jt.22.28 Ftg. Balance
No. Jts. Delivered 181 No. Jts. Run 172
Length Measurements W/O
Threads
Ftg. Delivered Ftg. Run
33.37 RKB to CHF
Type of Shoe:Innovex Casing Crew:Doyon
12 268
ES II Cementer Closure OK
56
Perm L Lead
Type
Premium G 270
Tuned Spacer
364 4.41
Stage Collar @
60
Bump press
100
270
7,130.007,140.00
CEMENTING REPORT
Csg Wt. On Slips:110,000
Spud Mud
21:53 7/4/2020 2,394
2394
15.8 82
Bump press
Returns to surface
Bump Plug?
Y
4
9.4 6 176.4/176.2
527.6/526.2
1200
0.5
RigFIRST STAGE10Tuned Spacer 60
15.8
570
9.4 6
1750
10
10.7 286 5
99.9
720
Bump Plug?
Csg Wt. On Hook:310,000 Type Float Collar:Innovex No. Hrs to Run:21
9 5/8 47.0 L-80 TXP BTC-SR Tenaris
TXP BTC-SR Innovex 1.62 7,130.00 7,128.38
22.28 54.49 32.21
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.MP L-59 Date Run 3-Jul-20
CASING RECORD
County State Alaska Supv.D. Yessak / J. Vanderpool
7,046.00
Floats Held
436.3 730
270 460
Spud Mud
Rotate Csg Recip Csg Ft. Min. PPG9.4
Shoe @ 7130 FC @ Top of Liner
SECOND STAGERig
8:08
Returns to surface
427.1 450.8 5.5
Casing (Or Liner) Detail
Shoe
Cut Joint of Casing
10 3/4
1
Davies, Stephen F (CED)
From:Davies, Stephen F (CED)
Sent:Thursday, July 9, 2020 2:33 PM
To:Joseph Engel
Cc:Boyer, David L (CED); Rixse, Melvin G (CED)
Subject:RE: HAK MP L-59 (PTD: 220-050) Update
Hi Joe,
Please label all directional survey, well log, and other information recorded for the abandoned section of hole with the
API Number of 50‐029‐23680‐70‐00 and the well name of MPU L‐59 PB1. Submit this information to the AOGCC along
with the Well Completion Report and other data recorded for well L‐59 in accordance with regulation 20 AAC 25.071.
Please let me know if you have any questions.
Best Regards,
Steve Davies
Alaska Oil and Gas Conservation Commission (AOGCC)
CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission
(AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use
or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding
it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov.
From: Rixse, Melvin G (CED) <melvin.rixse@alaska.gov>
Sent: Thursday, July 9, 2020 2:24 PM
To: Joseph Engel <jengel@hilcorp.com>
Cc: Boyer, David L (CED) <david.boyer2@alaska.gov>; Davies, Stephen F (CED) <steve.davies@alaska.gov>
Subject: RE: HAK MP L‐59 (PTD: 220‐050) Update
Joseph,
I have no questions. I will let the AOGCC Geologists know.
Mel Rixse
Senior Petroleum Engineer (PE)
Alaska Oil and Gas Conservation Commission
907‐793‐1231 Office
907‐223‐3605 Cell
CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),
State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or
disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it,
and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907‐793‐1231 ) or (Melvin.Rixse@alaska.gov).
cc. Steve Davies and David Boyer
From: Joseph Engel <jengel@hilcorp.com>
Sent: Thursday, July 9, 2020 2:07 PM
To: Rixse, Melvin G (CED) <melvin.rixse@alaska.gov>
Subject: HAK MP L‐59 (PTD: 220‐050) Update
2
Mel –
I wanted to give you an update on L‐59. While drilling ahead in the NB sand, we inadvertently drilled out of zone and
drilled up to confirm our position. Geologists made the decision to pull back and OHST to regain the NB Sand. Sidetrack
details are below.
OH Sidetrack Date Depth Interval (ft) Length (ft)
PB1 7/8/2020 8650’ – 9210’ 560
Please let me know if you have any questions.
Thank you for your time.
‐Joe
Joe Engel | Drilling Engineer | Hilcorp Alaska, LLC
3800 Centerpoint Dr., Ste. 1400 | Anchorage | AK | 99503
Office: 907.777.8395 | Cell: 805.235.6265
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of 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.
1
Guhl, Meredith D (CED)
From:Doug Yessak - (C) <dyessak@hilcorp.com>
Sent:Wednesday, July 15, 2020 1:31 PM
To:Regg, James B (CED); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (CED); Wallace, Chris D (CED)
Cc:Ian Toomey - (C); Nathan Sperry; Wyatt Rivard; Cody Dinger; Claude Demoski - (C)
Subject:Doyon 14 MIT test report
Attachments:MIT MPU L-59.xlsx
Doug Yessak
Hilcorp DSM
Doyon Rig 14
907‐670‐3090
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed
above, then promptly and permanently delete this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission,
opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and
the recipient should carry out such virus and other checks as it considers appropriate.
Submit to:
OPERATOR:
FIELD / UNIT / PAD:
DATE:
OPERATOR REP:
AOGCC REP:
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD 220-050 Type Inj N Tubing 0 0 0 0 Type Test
Packer TVD 3965 BBL Pump 5.0 IA 0 2640 2600 2595 Interval O
Test psi 1500 BBL Return 5.0 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, L Pad
Doug Yessak
07/15/20
Notes:Witness waived by Matt Herrera on 07/14/2020 at 05:19 AM. Initial, pre-injection MIT-IA performed on the rig. Monobore injector, no OA.
Notes:
Notes:
Notes:
MPU L-59
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
Mechanical Integrity Test
jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov
Notes:
Notes:
Notes:
Form 10-426 (Revised 01/2017)MIT MPU L-59.xlsx
S A,TE OF ALASKA Reviewed Bv: /
OIL ANu GAS CONSERVATION COMMISSION P.I. Supry
DIVERTER Test Report for: MILNE PT UNIT L-59 - Comm
Contractor/Rig No.: Doyon 14 PTD#: 2200500 ' DATE: 6/29/2020 Inspector Bob Noble Insp Source
Operator: Hilcorp Alaska, LLC Operator Rep: Sunderland Rig Rep: Carlo Inspector
Well Class: DEV Inspection No: divRCN2006301 1 1 1 52
Related Insp No:
M ISC. INSPECTIONS:
GAS DETECTORS:
Visual Alarm
Methane: P P
Hydrogen Sulfide: P ' P
Gas Detectors Misc: NA NA
TEST DATA
MUD SYSTEM:
P/F
Location Gen.:
P _
Housekeeping:
_P_
Warning Sign
P
24 hr Notice:
P
Well Sign:
P
Drlg. Rig.
P
Misc:
NA
GAS DETECTORS:
Visual Alarm
Methane: P P
Hydrogen Sulfide: P ' P
Gas Detectors Misc: NA NA
TEST DATA
MUD SYSTEM:
P/F
Visual
Alarm
Trip Tank:
P
P__ -
Mud Pits:
P
P
Flow Monitor:
P
P
Mud System Misc:
NA
NA
ACCUMULATOR SYSTEM:
P/F
Time/Pressure
P/F
Systems Pressure: 3000
P ,
Pressure After Closure: 1975
P '
200 psi Recharge Time: 37 _
P
Full Recharge Time: 147_ '_
P
Nitrogen Bottles (Number of): 6
P
Avg. Pressure: 2142_
P
Accumulator Misc: 0
NA
Number of Failures: 0 i// Test Time:
Remarks: There was a targeted T in the vent line. 22 deg and I have a picture of it if needed.
DIVERTER SYSTEM:
Size
P/F
Designed to Avoid Freeze-up?
P
Remote Operated Diverter?
P
No Threaded Connections?
P
Vent line Below Diverter?
P
Diverter Size: 21.25
P
Hole Size: 12.25
P
Vent Line(s) Size: 16
P
Vent Line(s) Length: 183
P
Closest Ignition Source: 86.5
P
Outlet from Rig Substructure: 175
P
Vent Line(s) Anchored:
P
Turns Targeted / Long Radius:
P
Divert Valve(s) Full Opening:
P
Valve(s) Auto & Simultaneous:
Annular Closed Time: 32
P
Knife Valve Open Time: 26
P
Diverter Misc: 0
NA
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 L-59
Hilcorp Alaska, LLC
Permit to Drill Number: 220-050
Surface Location: 3757' FSL, 5243' FEL, Sec 8, T13N, R10E, UM, AK
Bottomhole Location: 2485' FNL, 1802' FEL, Sec 19, T13N, R10E, UM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced service well.
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,
Jeremy M. Price
Chair
DATED this ___ day of June, 2020.
Jeremy M Price
9
1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for:
Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates
Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas
2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number:
Bond No.
3. Address:6. Proposed Depth: 12. Field/Pool(s):
MD: 13,607' TVD: 3,774'
4a. Location of Well (Governmental Section):7. Property Designation:
Surface:
Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date:
Total Depth:9. Acres in Property: 14. Distance to Nearest Property:
4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 49.2' 15. Distance to Nearest Well Open
Surface: x-544633 y- 6031945 Zone-4 15.5' to Same Pool: 130' to MPU L-47
16. Deviated wells:Kickoff depth: 330 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 92 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
Cond 20" 216# A53 Weld 114' Surface Surface 114' 114'
9-5/8" 47# L-80 TXP 2,000' Surface Surface 2,000' 1,796'
9-5/8" 40# L-80 TXP 4,868' 2,000' 1,796' 6,868' 3,959'
8-1/2" 4-1/2" 13.5# L-80 Hydril 625 6,889' 6,718' 3,946' 13,607' 3,774'
Tieback 3-1/2" 9.3 L-80 EUE 8Rd 6,718' Surface Surface 6,718' 3,946'
19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations)
Junk (measured):
TVD
Hydraulic Fracture planned?Yes No
20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis
Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements
Contact Name:
Contact Email:
Contact Phone:
Date:
Permit to Drill API Number: Permit Approval
Number:50- Date:
Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales:
Samples req'd: Yes No Mud log req'd: Yes No
H2S measures: Yes No Directional svy req'd: Yes No
Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No
Post initial injection MIT req'd: Yes No
APPROVED BY
Approved by: COMMISSIONER THE COMMISSION Date:
Sr Pet Eng Sr Pet Geo Sr Res Eng
4418 to nearest unit boundary
6/17/2020
Authorized Name: Monty Myers
Authorized Title: Drilling Manager
Joe Engel
jengel@hilcorp.com
777-8395
18. Casing Program:Top - Setting Depth - BottomSpecifications
MPU L-59
Milne Point Field
Schrader Bluff Oil Pool
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
Hilcorp Alaska, LLC
3757' FSL, 5243' FEL, Sec 8, T13N, R10E, UM, AK ADL025509, ADL025515
022224484
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
Stg 2 L - 1937 ft3 / T - 314 ft3
1386
1191' FNL, 464' FEL, Sec 18, T13N, R10E, UM, AK
2485' FNL, 1802' FEL, Sec 19, T13N, R10E, UM, AK
LONS 88-002
5077
1742
Total Depth MD (ft):Total Depth TVD (ft):
Cement Quantity, c.f. or sacks
Cement Volume MDSize
Plugs (measured):
(including stage data)
~270 ft3
Stg 1 L - 1372 ft3 / T - 458 ft3
Effect. Depth TVD (ft):
Conductor/Structural
Length
Cementless Liner w/ ICDs and Pkrs
Tieback Assy.
Production
Liner
Casing
Intermediate
Commission Use Only
Effect. Depth MD (ft):
Authorized Signature:
See cover letter for other
requirements.
Perforation Depth MD (ft):
21. I hereby certify that the foregoing is true and the procedure approved herein will not be
deviated from without prior written approval.
Surface
Perforation Depth TVD (ft):
GL / BF Elevation above MSL (ft):
6/3/2020
12-1/4"
es N
ype of W
L
l R
L
1b
S
Class:
os N es No
s N o
D s
s
s
D
84
o
:
well is p
G
S
S
20
S S
S
es No s No
S
G
E
S
es No
s
Form 10-401 Revised 3/2020 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
By Samantha Carlisle at 8:59 am, Jun 04, 2020
Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp Alaska, LLC, ou=Technical
Services - AK Drilling,
email=mmyers@hilcorp.com
Reason: I am approving this document
Date: 2020.06.03 22:43:01 -08'00'
Monty M
Myers
220-050
SFD 6/5/2020 DSR-6/4/2020
50-029-23680-00-00
(NB sand)
*3000 psi BOPE test
gls 6/9/20
tubing
*Submit FIT data to AOGCC
6/9/2020
6/9/2020
L
M
712
1813
19
L-01
L-02
L-03
L-17
L-32
L-34
L-35
L-39
L-20
L-36
L-40
L-28
L-42
L-37
L-45
F-81
LIVIANO 1
LIVIANO 1A
PESADO 1
PESADO 1A
L-10
L-
L-50
L-47
L-46
L-49
L-48L-51
L-53
L-56
L-54
L-57
L-52
F-109
F-110
M-10PB3
M-12
M-11
M-14
M-15
M-13
M-10
M-16
M-20
M-21
M-35
M-44
M-45 M-43
L-59 wp02
L-60 wp08
HILCORP ALASKA LLC
MILNE POINT FIELD
AOR MAP
L-59 Injector (Proposed)
FEET
0 1,000 2,000 3,000
POSTED WELL DATA
Well Number
WELL SYMBOLS
Active Oil
D&A
Shut In Oil
INJ Well (Water Flood)
P&A Oil
Abandoned Injector
J&A
Plug Back
Injector Location
Producer Location
Shut In INJ
REMARKS
Well Symbols at top of Schrader Bluff NB Sand.
Black dash circle = 1320' radius from NB sand in heel
and toe of proposed L-59 drill well
June 3, 2020
PETRA 6/3/2020 4:33:32 PM
L-59 wp02wp0552
(PTD 220-048)
close approach at 6800 ft
L-454-44L
closec ap
Area of Review MPL-59PTDAPI WELL STATUSTop of SB NB (MD)Top of SB NB (TVD)CBL Top of Cement (MD)CBL Top of Cement (TVD)Schrader NB statusZonal Isolation218-165 50-029-23617-00-00 MPM-10 OA Prod5754' 3836' Surface Surface Cased/CementedLateral in OA219-010 50-029-23621-00-00 MPM-11 OA WINJ4734' 3789' Surface Surface Cased/CementedLateral in OA218-176 50-029-23619-00-00 MPM-12 OA Prod4157' 3747' Surface Surface Cased/CementedLateral in OA219-087 50-029-23638-00-00 MPM-13 OA WINJ4206' 3716' Surface Surface Cased/CementedLateral in OA219-040 50-029-23625-00-00 MPM-14 OA Prod4301' 3713' Surface Surface Cased/CementedLateral in OA219-141 50-029-23653-00-00 MPM-15 OA WINJ4966' 3675' Surface Surface Cased/CementedLateral in OA218-066 50-029-23607-00-00 MPL-54 NB Producer6846' 3957' Surface Surface Open to NBOpen to Injection Support215-120 50-029-23552-00-00 MPL-48 OA WINJ6003' 3987' Surface Surface Cased/CementedLateral in OA215-117 50-029-23550-00-00 MPL-47 OA Prod6923' 3956' Surface Surface Cased/CementedLateral in OA215-132 50-029-23555-00-00 MPL-50 OA WINJ7583' 3910' Surface Surface Cased/CementedLateral in OA198-169 50-029-22913-00-00 MPL-45 OA P&A'd6995' 3942' Surface Surface P&A'd to surfaceLateral in OA218-014 50-029-23596-00-00 MPF-109 OA Prod5646' 3928' Surface Surface Cased/CementedLateral in OA* L-60 (PTD 220-048)not drilled yet218-06650-029-23607-00-00MPL-54NB Producer6846'3957'SurfaceSurfaceOpen to NBOpen to Injection Support
Milne Point Unit
(MPU) L-59
Drilling Program
Version 1
6/3/2020
Table of Contents
1.0 Well Summary ........................................................................................................................... 2
2.0 Management of Change Information ........................................................................................ 3
3.0 Tubular Program:...................................................................................................................... 4
4.0 Drill Pipe Information: .............................................................................................................. 4
5.0 Internal Reporting Requirements ............................................................................................. 5
6.0 Planned Wellbore Schematic ..................................................................................................... 6
7.0 Drilling / Completion Summary ................................................................................................ 7
8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 8
9.0 R/U and Preparatory Work ..................................................................................................... 10
10.0 N/U 21-1/4” 2M Diverter System ............................................................................................. 11
11.0 Drill 12-1/4” Hole Section ........................................................................................................ 13
12.0 Run 9-5/8” Surface Casing ...................................................................................................... 16
13.0 Cement 9-5/8” Surface Casing ................................................................................................. 22
14.0 BOP N/U and Test.................................................................................................................... 27
15.0 Drill 8-1/2” Hole Section .......................................................................................................... 28
16.0 Run 4-1/2” Injection Liner (Lower Completion) .................................................................... 33
17.0 Run 3-1/2” Tubing (Upper Completion) ................................................................................. 37
18.0 RDMO ...................................................................................................................................... 38
19.0 Doyon 14 Diverter Schematic .................................................................................................. 39
20.0 Doyon 14 BOP Schematic ........................................................................................................ 40
21.0 Wellhead Schematic ................................................................................................................. 41
22.0 Days Vs Depth .......................................................................................................................... 42
23.0 Formation Tops & Information............................................................................................... 43
24.0 Anticipated Drilling Hazards .................................................................................................. 44
25.0 Doyon 14 Layout ...................................................................................................................... 47
26.0 FIT Procedure .......................................................................................................................... 48
27.0 Doyon 14 Choke Manifold Schematic ..................................................................................... 49
28.0 Casing Design ........................................................................................................................... 50
29.0 8-1/2” Hole Section MASP ....................................................................................................... 51
30.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 52
31.0 Surface Plat (As Built) (NAD 27) ............................................................................................. 53
32.0 Schrader Bluff NB Sand Offset MW vs TVD Chart ............................................................... 54
Page 2
Milne Point Unit
L-59 SB Injector
Drilling Procedure
1.0 Well Summary
Well MPU L-59
Pad Milne Point “L” Pad
Planned Completion Type 3-1/2” Injection Tubing
Target Reservoir(s) Schrader Bluff Nb Sand
Planned Well TD, MD / TVD 13,607’ MD / 3,774’ TVD
PBTD, MD / TVD 13,597’ MD / 3,774’ TVD
Surface Location (Governmental) 3757' FSL, 5243' FEL, Sec 8, T13N, R10E, UM, AK
Surface Location (NAD 27) X= 544633 Y= 6031945
Top of Productive Horizon
(Governmental) 1191' FNL, 464' FEL, Sec 18, T13N, R10E, UM, AK
TPH Location (NAD 27) X= 544179 Y= 6026994
BHL (Governmental) 2485' FNL, 1802' FEL, Sec 19, T13N, R10E, UM, AK
BHL (NAD 27) X= 542903 Y=6020414
AFE Number 2011921M (D,C,F)
AFE Drilling Days 19 days
AFE Completion Days 3 days
AFE Drilling Amount $3,305,876
AFE Completion Amount $886,286
AFE Facility Amount $245,300
Maximum Anticipated Pressure
(Surface) 1386 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 1742 psig
Work String 5” 19.5# S-135 DS-50 & NC 50
KB Elevation above MSL: 33.7 ft + 15.5 ft = 49.2 ft
GL Elevation above MSL: 15.5 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
1742 psig
Page 3
Milne Point Unit
L-59 SB Injector
Drilling Procedure
2.0 Management of Change Information
Page 4
Milne Point Unit
L-59 SB Injector
Drilling Procedure
3.0 Tubular Program:
Hole
Section
OD (in) ID
(in)
Drift
(in)
Conn OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 20” 19.25” - - - X-52 Weld
12-1/4” 9-5/8” 8.681” 8.525” 10.625” 47 L-80 TXP 6,870 4,750 1,086
9-5/8” 8.835” 8.679” 10.625” 40 L-80 TXP 5,750 3,090 916
8-1/2” 4-1/2” 3.96” 3.795” 4.714” 13.5 L-80 H625 9020 8540 279
Tubing 3-1/2” 2.992” 2.867” 4.500” 9.3 L-80 EUE 8RD 9289 7399 163
4.0 Drill Pipe Information:
Hole
Section
OD
(in)
ID (in) TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn M/U
(Min)
M/U
(Max)
Tension
(k-lbs)
Surface &
Production
5” 4.276” 3.25” 6.625” 19.5 S-135 GPDS50 36,100 43,100 560klb
5” 4.276” 3.25” 6.625” 19.5 S-135 NC50 31,032 34,136 560klb
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
Page 5
Milne Point Unit
L-59 SB Injector
Drilling Procedure
5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on WellEz.
x Report covers operations from 6am to 6am
x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left
of the data entry area – this will not save the data entered, and will navigate to another data entry.
x Ensure time entry adds up to 24 hours total.
x Try to capture any out of scope work as NPT. This helps later on when we pull end of well
reports.
x Enter the MD and TVD depths EVERY DAY whether you are making hole or not.
5.2 Afternoon Updates
x Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers@hilcorp,
jengel@hilcorp.com and cdinger@hilcorp.com
5.3 Intranet Home Page Morning Update
x Submit a short operations update each morning by 7am on the company intranet homepage. On
weekend and holidays, ensure to have this update in before 5am.
5.4 EHS Incident Reporting
x Health and Safety: Notify EHS field coordinator.
x Environmental: Drilling Environmental Coordinator
x Notify Drilling Manager & Drilling Engineer on all incidents
x Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
x Send final “As-Run” Casing tally to mmyers@hilcorp,com jengel@hilcorp.com and
cdinger@hilcorp.com
5.6 Casing and Cement report
x Send casing and cement report for each string of casing to mmyers@hilcorp.com
jengel@hilcorp.com and cdinger@hilcorp.com
5.7 Hilcorp Milne Point Contact List:
Title Name Work Phone Cell Phone Email
Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmyers@hilcorp.com
Drilling Engineer Joe Engel 907.777.8395 805.235.6265 jengel@hilcorp.com
Completion Engineer Ian Toomey 907.777.8434 907.903.3987 itoomey@hilcorp.com
Geologist Kevin Eastham 907.777.8316 907.360.5087 keastham@hilcorp.com
Reservoir Engineer Reid Edwards 907.777.8421 907.250.5081 reedwards@hilcorp.com
Drilling Env. Coordinator Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com
EHS Manager Carl Jones 907.777.8327 907.382.4336 cajones@hilcorp.com
Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinger@hilcorp.com
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6.0 Planned Wellbore Schematic
Note: submit
FIT data to AOGCC
Jet pump completion
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7.0 Drilling / Completion Summary
MPU L-59 is a grassroots injector planned to be drilled in the Schrader Bluff NB sand. L-59 is part of a
multi well program targeting the Schrader Bluff sand on L-Pad.
The directional plan is a catenary well path build, 12.25” hole with 9-5/8” surface casing set into the top of
the Schrader Bluff NB/NC sand. An 8.5” lateral section will then be drilled. A 4-1/2” 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 17, 2020, pending rig schedule.
Surface casing will be run to 6,868 MD / 3,959’ TVD and cemented to surface via a 2 stage primary cement
job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed,
necessary remedial action will then be discussed with AOGCC authorities.
All cuttings & mud generated during drilling operations will be hauled to the Milne Point “B” pad G&I facility.
General sequence of operations:
1. MIRU Doyon 14 to well site
2. N/U & Test 21-1/4” Diverter and 16” diverter line
3. Drill 12-1/4” hole to TD of surface hole section. Run and cement 9-5/8” surface casing
4. N/D diverter, N/U & test 13-5/8” x 5M BOP. Install MPD Riser
5. Drill 8-1/2” lateral to well TD. Run 4-1/2” injection liner.
6. Run 3-1/2” tubing.
7. N/D BOP, N/U Tree, RDMO.
Reservoir Evaluation Plan:
1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res
2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering)
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8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations,
specific regulations are listed below. If additional clarity or guidance is required on how to comply with
a specific regulation, do not hesitate to contact the Anchorage Drilling Team.
x BOPs shall be tested at (2) week intervals during the drilling and completion of MPU L-59. Ensure
to provide AOGCC 24 hrs notice prior to testing BOPs.
x The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment
will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial
and subsequent tests). Confirm that these test pressures match those specified on the APD.
x If the BOP is used to shut in on the well in a well control situation or control fluid flow from the
well bore, AOGCC is to be notified and we must test all BOP components utilized for well control
prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP
test.
x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program
and drilling fluid system”.
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”.
o Ensure the diverter vent line is at least 75’ away from potential ignition sources
x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
AOGCC Regulation Variance Requests:
Hilcorp Alaska LLC does not request any variances at this time.
The initial test of BOP equipment will be to 250/3000 p
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Summary of BOP Equipment & Notifications
Hole Section Equipment Test Pressure (psi)
12 1/4” x 21-1/4” 2M Diverter w/ 16” Diverter Line Function Test Only
8-1/2”
x 13-5/8” x 5M Hydril “GK” Annular BOP
x 13-5/8” x 5M Hydril MPL Double Gate
o Blind ram in btm cavity
x Mud cross w/ 3” x 5M side outlets
x 13-5/8” x 5M Hydril MPL Single ram
x 3-1/8” x 5M Choke Line
x 3-1/8” x 5M Kill line
x 3-1/8” x 5M Choke manifold
x Standpipe, floor valves, etc
Initial Test: 250/3000
Subsequent Tests:
250/3000
Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit.
Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air
pump, and emergency pressure is provided by bottled nitrogen.
The remote closing operator panels are located in the doghouse and on accumulator unit.
Required AOGCC Notifications:
x Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
x 24 hours notice prior to spud.
x 24 hours notice prior to testing BOPs.
x 24 hours notice prior to casing running & cement operations.
x Any other notifications required in APD.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email: jim.regg@alaska.gov
Guy Schwartz / Petroleum Engineer / (O): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartz@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email: Victoria.loepp@alaska.gov
Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email: melvin.rixse@alaska.gov
Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov
Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
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9.0 R/U and Preparatory Work
9.1 L-59 will utiliz e a newly set 20” conductor on L-Pad. Ensure to review attached surface plat and
make sure rig is over appropriate conductor.
9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor.
9.3 Install landing ring.
9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each.
9.5 Level pad and ensure enough room for layout of rig footprint and R/U.
9.6 Rig mat footprint of rig.
9.7 MIRU Doyon 14. Ensure rig is centered over conductor to prevent any wear to BOPE or
wellhead.
9.8 Mud loggers WILL NOT be used on either hole section.
9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80qF).
9.10 Ensure 6” liners in mud pumps.
x Continental EMSCO FB-1600 mud pumps are rated at 4665 psi, 462 gpm @ 110 spm @
95% volumetric efficiency.
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10.0 N/U 21-1/4” 2M Diverter System
10.1 N/U 21-1/4” Hydril MSP 2M Diverter System (Diverter Schematic attached to program).
x N/U 16-3/4” 3M x 21-1/4” 2M DSA on 16-3/4” 3M wellhead.
x N/U 21-1/4” diverter “T”.
x Knife gate, 16” diverter line.
x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
x Diverter line must be 75 ft from nearest ignition source
x Place drip berm at the end of diverter line.
10.2 Notify AOGCC. Function test diverter. Ensure that the knife gate and annular are operated on
the same circuit so that knife gate opens prior to annular closure.
10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the
vent line tip. “Warning Zone” must include:
x A prohibition on vehicle parking
x A prohibition on ignition sources or running equipment
x A prohibition on staged equipment or materials
x Restriction of traffic to essential foot or vehicle traffic only.
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10.4 Rig & Diverter Orientation:
x May change on location
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11.0 Drill 12-1/4” Hole Section
11.1 P/U 12-1/4” directional drilling assembly:
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Be sure to run a UBHO sub for wireline gyro
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
x Drill string will be 5” 19.5# S-135.
x Run a solid float in the surface hole section.
11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor.
x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in
conductor.
11.3 Drill 12-1/4” hole section to section TD, in the Schrader NB sand. Confirm this setting depth
with the Geologist and Drilling Engineer while drilling the well.
x Monitor the area around the conductor for any signs of broaching. If broaching is observed,
Stop drilling (or circulating) immediately notify Drilling Engineer.
x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100.
x Hold a safety meeting with rig crews to discuss:
x Conductor broaching ops and mitigation procedures.
x Well control procedures and rig evacuation
x Flow rates, hole cleaning, mud cooling, etc.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Keep mud as cool as possible to keep from washing out permafrost.
x Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can
handle the flow rate.
x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoffs, increase in pump pressure or changes in hookload are seen
x Slow in/out of slips and while tripping to keep swab and surge pressures low
x Ensure shakers are functioning properly. Check for holes in screens on connections.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea
gravel, clay balling or packing off.
x Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2
minimum at TD (pending MW increase due to hydrates).
x Perform wireline gyros until clean MWD surveys are seen. Take MWD surveys every stand
drilled.
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x Gas hydrates have not been seen on L-Pad. However, be prepared for them. In MPU they
have been encountered typically around 2100-2400’ TVD (just below permafrost). Be
prepared for hydrates:
x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD
x Monitor returns for hydrates, checking pressurized & non-pressurized scales
x Past wells on E pad have increased MW.After drilling through hydrate sands, MW was
cut back to normal
x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by
washing out additional permafrost. Attempt to control drill (150 fph MAX) through the
zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be
reduced to prevent mud from belching over the bell nipple. Consider adding Lecithin to
allow the gas to break out.
x Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well.
MW will not control gas hydrates, but will affect how gas breaks out at surface.
x AC:
x L-45 has a CF of .7. L-45 is fully abandoned at the reservoir and to surface. The
only risk is damage to the bit.
11.4 12-1/4” hole mud program summary:
x Density: Weighting material to be used for the hole section will be barite. Additional
barite or spike fluid will be on location to weight up the active system (1) ppg above
highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and
TD with 9.2+ ppg.
Depth Interval MW (ppg)
Surface – Base Permafrost 8.9+
Base Permafrost - TD 9.2+ (For Hydrates if need based on offset wells)
MW can be cut once ~500’ below hydrate zone
x PVT System: MD Totco PVT will be used throughout the drilling and completion phase.
Remote monitoring stations will be available at the driller’s console, Co Man office,
Toolpusher office, and mud loggers office.
x 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.
x Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10
ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling
the surface interval to prevent losses and strengthen the wellbore.
x 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.
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x Casing Running: Reduce system YP with DESCO as required for running casing as allowed
(do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures.
Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to
see what YP value they have targeted).
System Type: 8.8 – 9.2 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
11.5 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity.
11.6 RIH t/ bottom, proceed to BROOH t/ HWDP
x Pump at full drill rate (400-600 gpm), and maximize rotation.
x Pull slowly, 5 – 10 ft / minute.
x Monitor well for any signs of packing off or losses.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay
balling.
x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until
parameters are restored.
11.7 TOOH and LD BHA
11.8 No open hole logging program planned.
8.8 – 9.8
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12.0 Run 9-5/8” Surface Casing
12.1 R/U and pull wearbushing.
12.2 R/U Weatherford 9-5/8” casing running equipment (CRT & Tongs)
x Ensure 9-5/8” TXP x DS50 XO on rig floor and M/U to FOSV.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x R/U of CRT if hole conditions require.
x R/U a fill up tool to fill casing while running if the CRT is not used.
x Ensure all casing has been drifted to 8.75” on the location prior to running.
x Top 2000’ of casing from surface 47# drift 8.525” min
x Be sure to count the total # of joints on the location before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
12.3 P/U shoe joint, visually verify no debris inside joint.
12.4 Continue M/U & thread locking 120’ shoe track assembly consisting of:
9-5/8” Float Shoe
1 joint – 9-5/8” TXP, 2 Centralizers 10’ from each end w/ stop rings
1 joint – 9-5/8” TXP, 1 Centralizer mid joint w/ stop ring
9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’
1 joint – 9-5/8” TXP, 1 Centralizer mid joint with stop ring
9-5/8” HES Baffle Adaptor
x Ensure bypass baffle is correctly installed on top of float collar.
x Ensure proper operation of float equipment while picking up.
x Ensure to record S/N’s of all float equipment and stage tool components.
This end up.
Bypass Baffle
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12.5 Float equipment and Stage tool equipment drawings:
2500 ft
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12.6 Continue running 9-5/8” surface casing
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
x Verify depth of lowest Ugnu water sand for isolation with Geologist
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
x Any packing off while running casing should be treated as a major problem. It is preferable
to POH with casing and condition hole than to risk not getting cement returns to surface.
12.7 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below
the permafrost (~ 2,500’ MD).
x Install centralizers over couplings on 5 joints below and 5 joints above stage tool.
x Do not place tongs on ES cementer, this can cause damaged to the tool.
x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi.
9-5/8” 40# L-80 TXP Make Up Torques:
Casing OD Minimum Optimum Maximum
9-5/8” 18,860 ft-lbs 20,960 ft-lbs 23,060 ft-lbs
9-5/8” 47# L-80 TXP MUT:
Casing OD Minimum Optimum Maximum
9-5/8” 21,440 ft-lbs 2,3820 ft-lbs 26,200 ft-lbs
Depth Interval Centralization
Shoe – 1000’ Above Shoe 1/jt
1000’ above Shoe – 2000’ above Shoe
(Top of Ugnu)
1/ 2 jts
Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below yp
the permafrost (~ 2,500’ MD).
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12.8 Continue running 9-5/8” surface casing
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
o 1 centralizer every 2 joints to base of conductor
12.9 The last 2000’ of 9-5/8” will be 47#, from 2000’ to Surface
x Ensure drifted to 8.525” min
The last 2000’ of 9-5/8” will be 47#, from 2000’ to Surface
x Ensure drifted to 8.525” min
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12.10 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.11 Slow in and out of slips.
12.12 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the
landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference
when getting the casing on depth.
12.13 Lower casing to setting depth. Confirm measurements.
12.14 Have slips staged in cellar, along with necessary equipment for the operation.
12.15 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement
job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible
reciprocate casing string while conditioning mud.
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13.0 Cement 9-5/8” Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
x Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks.
x Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
x Review test reports and ensure pump times are acceptable.
x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
13.2 Document efficiency of all possible displacement pumps prior to cement job.
13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
13.5 Fill surface cement lines with water and pressure test.
13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below
calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached.
13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead &
tail, TOC brought to stage tool.
Estimated 1st Stage Total Cement Volume:
Section Calculation Vol (bbl) Vol (ft3)
12-1/4" OH x 9-5/8"
Casing (5,868' - 2500') x .0558 bpf x 1.3 = 244.3 1371.7
Total Lead 244.3 1371.5
12-1/4" OH x 9-5/8"
Casing (6,868' - 5,868') x .0558 bpf x 1.3 = 72.5 407
9-5/8" Shoe Track 120' x .0758 bpf = 9.1 51.09
Total Tail 81.6 458LeadTail
582 sx
Estimated 1st Stage Total Cement Volume:
394 sx
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Cement Slurry Design (1st Stage Cement Job):
13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue
with the cement job.
13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of
mud pits, spotting water across the HEC stage cementer.
x Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
13.10 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the plug
must be bumped.
13.11 Displacement calculation:
6,868’ x .0758 bpf = 520.6 bbls
80 bbls of tuned spacer to be left behind stage tool, confirm spacer is compatible with cement
behind stage tool & that sufficient spacer will be above the tool to exit when circulation is
established.
13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any
point during the job. Be prepared to pump out fluid from cellar. Have black water available to
contaminate any cement seen at surface.
13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over
displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling
Engineer.
13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening
plug is available if needed. This is the back-up option to open the stage tool if the plugs are not
bumped.
13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
Lead Slurry Tail Slurry
Density 12.0 lb/gal 15.8 lb/gal
Yield 2.35 ft3/sk 1.16 ft3/sk
Mixed
Water 13.92 gal/sk 4.98 gal/sk
Note: Lead Cement Viscosity to be lowered to prevent poor interface once stage tool is opened
and cement is circulated to surface
p
6,868’ x .0758 bpf = 520.6 bbls x
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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.
open ES
Increase pressure to 3300 psi to open circulating ports in stage collar.
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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 2nd 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:
Section Calculation Vol (bbl) Vol (ft3)
20" Conductor x 9-5/8" Casing (110') x .26 bpf x 1 = 28.6 161
12-1/4" OH x 9-5/8" Casing (2000' - 110') x .0558 bpf x 3 = 316.4 1776.3
Total Lead 345 1937
12-1/4" OH x 9-5/8" Casing (2500' - 2000') x .0558 bpf x 2 = 55.8 314
Total Tail 55.8 314LeadTail
Cement Slurry Design (2nd stage cement job):
Lead Slurry Tail Slurry
System Permafrost L
Density 10.7 lb/gal 15.8 lb/gal
Yield 4.41 ft3/sk 1.17 ft3/sk
Mixed
Water
22.02 gal/sk 5.08 gal/sk
440 sx
268 sx
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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 calculation:
2500’ x .0758 bpf = 190 bbls mud
13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side
outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out
fluid from cellar. Have black water available to retard setting of cement.
13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should
circulate approximately 100 - 150 bbls of cement slurry to surface.
13.29 Land closing plug on stage collar and pressure up to 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
13.30 Make initial cut on 9-5/8” final joint. L/D cut joint. Make final cut on 9-5/8”. Dress off stump.
Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule.
Ensure to report the following on wellez:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
a. Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
b. Note if casing is reciprocated or rotated during the job
c. Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
d. Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
e. Note if pre flush or cement returns at surface & volume
f. Note time cement in place
g. Note calculated top of cement
h. Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to jengel@hilcorp.com and
cdinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC.
6 Displacement calculation:p
2500’ x .0758 bpf = 190 bbls mud
Make initial cut on 9-5/8” final joint.
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14.0 BOP N/U and Test
14.1 N/D the diverter T, knife gate, diverter line & N/U 11” x 13-5/8” 5M casing spool.
14.2 N/U 13-5/8” x 5M BOP as follows:
x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13-
5/8” x 5M mud cross / 13-5/8” x 5M single gate
x Double gate ram should be dressed with 4-1/2” x 7” VBRs in top cavity, blind ram in
bottom cavity.
x Single ram can be dressed with 3-1/2” x 6” VBRs
x N/U bell nipple, install flowline.
x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to
mud cross).
x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual
valve
14.3 Run 5” BOP test plug
14.4 Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min.
x Test 5” test joints
x Confirm test pressures with PTD
x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure
is trapped underneath test plug
x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech
14.5 R/D BOP test equipment
14.6 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.7 Mix 8.9 ppg FloPro 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.
Test BOP to 250/3000 psi for 5/5 min.
initial BOPE test
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Drilling Procedure
15.0 Drill 8-1/2” Hole Section
15.1 M/U 8.5” Cleanout BHA (Milltooth Bit & 1.22° PDM)
x Based on results from M-44 & 45, RSS drillouts have left debris in bit and bit sleeve, may have
damaged cutters, and may have impacted our ability to steer. A dedicated motor drill out is
preferred.
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.
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.
15.8 POOH & LD Cleanout BHA
15.9 P/U 8-1/2” RSS directional BHA.
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components that
cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Ensure MWD is R/U and operational.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
x Drill string will be 5” 19.5# S-135 DS50 & NC50.
x Run a ported float in the production hole section.
15.10 8-1/2” hole section mud program summary:
R/U and test casing to 2500 psi / 30 min.
FIT
Conduct FIT to 12.0 ppg EMW.
2500 psi
MIT for surface
casing
NOTE : submit FIT data by email to AOGCC (injector requirement)
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Drilling Procedure
x Density: Weighting material to be used for the hole section will be calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg
above highest anticipated MW. Use appropriate SAFECARB blend on this well
x Solids Concentration: It is imperative that the solids concentration be kept low while
drilling the production hole section. Keep the shaker screen size optimized and fluid
running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure
we are running the finest screens possible.
x Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests
excessive viscosifier concentrations can decrease return permeability. Do not pump high
vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for
sufficient hole cleaning
x Run the centrifuge continuously while drilling the production hole, this will help with
solids removal.
x Dump and dilute as necessary to keep drilled solids to an absolute minimum.
x MD Totco PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be avai lable at the driller’s console, Co Man office, &
Toolpusher office.
System Type: 8.9 – 9.5 ppg FloPro drilling fluid
Properties:
Interval Density PV YP LSYP Total Solids MBT HPHT Hardness
Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100
System Formulation:
Product- production 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
8.9-9.5
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Drilling Procedure
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 Flo Pro drilling fluid
15.13 Begin drilling 8.5” hole section, on-bottom staging technique:
x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k.
x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations
x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to P/U
off bottom and restart on bottom staging technique. If stick slip continues, consider adding
.5% lubes
15.14 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer.
x Flow Rate: 350-550 gpm, target min. AV’s 200 ft/min, 385 gpm
x RPM: 120+
x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly
wet to maximize solids removal efficiency. Check for holes in screens on every connection.
x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
x Monitor Torque and Drag with pumps on every 5 stands
x Monitor ECD, pump pressure & hookload trends for hole cleaning indication
x Surveys can be taken more frequently if deemed necessary.
x Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible and avoid stopping with the
BHA across the sand for any extended period of time.
x Use ADR to stay in section. Reservoir plan is to undulate between Schrader OA1 & OA3
lobes in 1000-1500’ MD increments, and keeping DLS <3° when moving between lobes
x Limit maximum instantaneous ROP to < 250 fph. The sands will drill faster than this, but
when concretions are hit when drilling this fast, cutter damage can occur.
x Target ROP is as fast as we can clean the hole without having to backream connections
x Watch for higher than expected pressure. MPD will be utilized to monitor pressure build up
on connections
x AC:
x L-45 has a CF of .7. L-45 is fully abandoned at the reservoir and to surface. The only risk is
damage to the bit.
x Schrader Bluff Concretions: 5-10% of lateral
15.15 Reference: Open hole sidetracking practice:
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x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so
we have a nice place to low side.
x Attempt to lowside in a fast drilling interval where the wellbore is headed up.
x Orient TF to low side and dig a trough with high flowrates for the first 10 ft, working string
back and forth. Trough for approx. 30 min.
x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the
openhole sidetrack is achieved.
15.16 At TD, CBU at least 4 times at 200 ft/min AV (385+ gpm) and rotation (120+ rpm). Pump
tandem sweeps if needed
x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent
stream, circulate more if necessary
x Ensure mud has necessary lube % for running liner
x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0ppg minimum
15.17 Once hole is clean, displace to lubricated, viscosified 8.8 ppg 2% KCl brine.
15.18 Monitor the returned fluids carefully while conditioning the mud. After 4 (or more) BU,
Perform production screen test (PST). The mud has been properly conditioned when the mud
will pass the production screen test (x3 350ml samples passing through the screen in the same
amount of time which will indicate no plugging of the screen). Reference PST Test
Procedure
x 250 Coupons
x Circulate and condition mud as much as needed to pass the production screen test
x If not passing after first test, call Completion Engineer
15.19 BROOH with the drilling assembly to the 9-5/8” casing shoe
x Circulate at full drill rate (385 gpm max).
x Rotate at maximum rpm that can be sustained.
x Limit pulling speed to 5 – 10 min/std (slip to slip time, not including connections).
x If backreaming operations are commenced, continue backreaming to the shoe
15.20 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps.
15.21 Monitor well for flow. Increase mud weight if necessary
x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to
determine if well is breathing, treat all flow as an influx until proven otherwise
x If necessary, increase MW at shoe for any higher than expected pressure seen
15.22 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball
drops.
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15.23 Continue to POH and stand back BHA if possible. Rabbit DP on TOH, ensure rabbit diameter is
sufficient for future ball drops.
Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any
additional logging runs conducted.
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16.0 Run 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 joints of screens, the following well control response procedure will be
followed:
x With a screen joint across the 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.
x With 4-1/2” solid joint across BOP: Slack off and position the 4-1/2” solid joint to MU the
TIW valve. Shut in ram or annular on 4-1/2” solid joint. Close TIW valve.
16.2. Confirm VBR have been tested on 4-1/2” and 5” test joints to 250 psi low/3000 psi high.
16.3. R/U 4-1/2” liner running equipment.
x Ensure 4-1/2” Hydril 625 x DS-50 crossover is on rig floor and M/U to FOSV.
x Ensure the liner has been drifted on the deck prior to running.
x Be sure to count the total # of joints on the deck before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
16.4. Run 4-1/2” injection liner.
x Injection liner will be solid pipe and single screen joints spaced every ~ 800’. Confirm with
OE
x Use API Modified or “Best O Life 2000 AG” thread compound. Dope pin end only w/ paint
brush. Wipe off excess. Thread compound can plug the screens
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Use lift nubbins and stabbing guides for the liner run.
x Fill 4-½” liner with PST passed mud (to keep from plugging screens with solids)
x Install screen joints as per the Running Order
x (From Completion Engineer post TD).
x Do not place tongs or slips on screen joints
x Screen placement ±40’
x The Screen connection is 4-1/2” 13.5# Hydril 625
x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint
outside of the surface shoe. This is to mitigate difference sticking risk while running inner
string.
x Obtain up and down weights of the liner before entering open hole. Record rotating torque at
10 and 20 rpm
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
Well control preparedness:
m VBR have been tested on 4-1/2” and 5” test joints t
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Drilling Procedure
16.6. Ensure that the liner top packer is set ~ 150’ MD above the 9-5/8” shoe.
x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as
per 20 AAC 25.030(d)(6). Ensure hanger/packer will not be set in a 9-5/8” connection.
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Drilling Procedure
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 inner string and 4-1/2” liner. Fill liner tieback sleeve with
“Pal mix”, ensure mixture is thin enough to travel past the HRD tool and down to the packoff.
Wait 30 min for mixture to set up.
16.9. Note weight of liner. Run liner in the hole one stand and pump through liner hanger to ensure a
clear flow path exists.
16.10. RIH w/ liner on DP no faster than 30 ft/min – this is to prevent buckling the liner and drill string.
Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down
running speed if necessary.
16.11. The liner and inner string will prevent the DP from auto filling. Fill DP every 5 stands, more
frequently if SOW trend indicates.
16.12. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe
depth + S/O depth every stand. Record torque value if it becomes necessary to rotate the string
to bottom.
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. 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.
16.17. 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. Pressure up to 1,500 psi to shift the wellbore
isolation valve closed.
16.18. Continue pressuring up to 2700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes.
Slack off 20K lbs on the ZXP to ensure the HRDE setting tool is in compression for release from
the SLZXP liner hanger/packer. Continue pressuring up 4100 psi to neutralize and release
running tools.
16.19. Bleed DP pressure to zero, 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,
16.20. PU to neutral weight, close BOP and test annulus to 1500 psi for 10 min and chart record same.
Continue pressuring up to 2700 psi to set the SLZXP liner hanger/packer.
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Drilling Procedure
16.21. 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.
16.22. With running tool line liner top, flush liner top at max rate
16.23. POOH, L/D and inspect running tools. If setting of liner hanger/packer proceeded as planned,
LDDP on the TOH.
16.24. LD Remaining 5” DP.
16.25. Once running tools are L/D, Swap to Completion AFE.
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Drilling Procedure
17.0 Run 3-1/2” Tubing (Upper Completion)
17.1 Notify the AOGCC at least 24 hours in advance of the IA pressure test after running the
completion as per 20 AAC 25.412 (e). Record pressure test on 10-426 form and email to
wrivard@hilcorp.com for submission to AOGCC.
17.2 M/U injection assembly and RIH to setting depth. TIH no faster than 90 ft/min.
x Ensure wear bushing is pulled.
x Ensure 3-½” EUE 8RD x NC-50 crossover is on rig floor and M/U to FOSV.
x Ensure all tubing has been drifted in the pipe shed prior to running.
x Be sure to count the total # of joints in the pipe shed before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
x Monitor displacement from wellbore while RIH.
3-1/2” 9.3# L-80 EUE 8RD
Casing OD Minimum Optimum Maximum
Operating Torque
3.5” 2,350 ft-lbs 3,130 ft-lbs 3,910 ft-lbs
3-½” Upper Completion Running Order
x 3-½” Baker Ported Bullet Nose seal (stung into the tie back receptacle)
x 3 joints (minimum, more as needed) 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x 3-½” “XN” nipple at TBD
x 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x 3-½” “X” nipple at TBD MD
x 3-½” 9.3#/ft, L-80 EUE 8RD space out pups
x 1 joint 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x Tubing hanger with 3-1/2” EUE 8RD pin down
17.3 Locate and no-go out the seal assembly. Close annular and test to 400 psi to confirm seals
engaged.
17.4 Bleed pressure and open annular. Space out the completion (+/- 1’ to 2’ above No-Go). Place all
space out pups below the first full joint of the completion.
AOGCC at least 24 hours in advance of the IA pressure te
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Drilling Procedure
17.5 Makeup the tubing hanger and landing joint.
17.6 RIH. Close annular and test to 400 – 500 psi to confirm seals are engaged. Bleed pressure down
to 250 psi. PU until ports in seal assembly exposed.
17.7 Reverse circulate the well with brine and 1% corrosion inhibitor.
17.8 Freeze protect the tubing and IA to ~3000’ MD with ±210 bbl of diesel.
17.9 Land hanger. RILDs and test hanger.
17.10 Continue pressurizing the annulus to 2500 psi and test for 30 charted minutes.
i. Note this test must be witnessed by the AOGCC representative.
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
Notify
Inspector
Continue pressurizing the annulus to 2500 psi and test for 30 charted minutes.
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Drilling Procedure
19.0 Doyon 14 Diverter Schematic
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Drilling Procedure
20.0 Doyon 14 BOP Schematic
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21.0 Wellhead Schematic
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22.0 Days Vs Depth
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23.0 Formation Tops & Information
MPU L-59 Formations
(wp09)
MD
(ft)
TVDss
(ft)
TVD
(ft)
Formation Pressure
(psi)
EMW
(ppg)
Base Permafrost 2119 -1810 1859 817.96 8.46
LA3 5454 -3406 3455 1520.2 8.46
Ugnu MB 6025 -3678 3727 1639.88 8.46
Schrader Bluff NA 6800 -3877 3926 1727.44 8.46
Schrader Bluff NB 6950 -3883 3932 1730.08 8.46
L-Pad Data Sheet Formation Description (Closest & Most Analogous MPU Pad to Moose Pad)
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Drilling Procedure
24.0 Anticipated Drilling Hazards
12-1/4” Hole Section:
Lost Circulation
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Gas Hydrates
Gas hyrates have not been seen on Moose pad. However, be prepared for them. Remember that hydrate
gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates,
but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come
out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching.
Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate
formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud
circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized
mud scale. The non-pressurized scale will reflect the actual mud cut weight. Isolate/dump
contaminated fluid to remove hydrates from the system.
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize
solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs
to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is
critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to
avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide
intervals. Do not out drill our ability to clean the hole.
Anti-Collison:
There are a number of wells in close proximity. Take directional surveys every stand, take additional
surveys if necessary. Continuously monitor proximity to offset wellbores and record any close
approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in
adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Well
specific A/C:
x L-45 has a CF of .7. L-45 is fully abandoned at the reservoir and to surface. The only
risk is damage to the bit.
Wellbore stability (Permafrost, running sands and gravel, conductor broaching):
Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of
time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH
speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and
swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching.
Maintain mud parameters and increase MW to combat running sands and gravel formations.
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Drilling Procedure
H2S:
Treat every hole section as though it has the potential for H2S. No H2S events have been documented
on drill wells on this pad.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
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8-1/2” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor
ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe
moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation
after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300
gpm
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
There is at least (1) fault that will be crossed while drilling the well. There could be others and the
throw of these faults is not well understood at this point in time. When a known fault is coming up,
ensure to put a “ramp” in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed,
we’ll need to either drill up or down to get a look at the LWD log and determine the throw and then
replan the wellbore.
H2S:
Treat every hole section as though it has the potential for H2S. No H2S events have been documented
on drill wells on this pad.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Abnormal Pressures and Temperatures:
Reservoir pressures are expected to be normal. Abnormal (offset injection) pressure has been seen on M-
Pad. Utilize MPD to mitigate any abnormal pressure seen.
Anti-Collision
Take directional surveys every stand, take additional surveys if necessary. Continuously monitor
drilling parameters for signs of magnetic interference with another well. Reference A/C report in
directional plan. Well specific AC:
x L-45 has a CF of .7. L-45 is fully abandoned at the reservoir and to surface. The only risk is
damage to the bit.
Utilize MPD to mitigate any abnormal pressure seen.
p
Reservoir pressures are expected to be normal. pp
NOTE:
pp
L-45 has a CF of .7. L-45 is fully abandoned at the reservoir and to surface.
L-45 runs parallel to L-59
Page 47
Milne Point Unit
L-59 SB Injector
Drilling Procedure
25.0 Doyon 14 Layout
Page 48
Milne Point Unit
L-59 SB Injector
Drilling Procedure
26.0 FIT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental
volume pumped and returned during test.
NOTE: submit FIT data to AOGCC . include in 10-407 report also.
Page 49
Milne Point Unit
L-59 SB Injector
Drilling Procedure
27.0 Doyon 14 Choke Manifold Schematic
Page 50
Milne Point Unit
L-59 SB Injector
Drilling Procedure
28.0 Casing Design
12-1/4"Mud Density:9.2 ppg
8-1/2"Mud Density:9.2 ppg
Mud Density:
1386 psi (see attached M ASP determination & calculation)
1386 psi (see attached M ASP determination & calculation)
Collapse Calculation:
Section Calculation
1 Normal gradient external stress (0.494 psi/ft) and the casing evacuated for the internal stress
1234
9-5/8"4-1/2"
06,868
03,959
6,868 13,607
3,959 3,774
6,868 6,739
40 12.6
L-80 L-80
DWC H625
274,720 84,911
274,720 84,911
916 279
3.33 3.29
1,956 1,864
3,090 8,540
1.58 4.58
1,386 1,386
5,750 9,020
4.15 6.51
Design Criteria:
Hole Size
Grade
Connection
Calculation & Casing Design Factors
Calculation/Specification
Casing OD
Bottom (MD)
Bottom (TVD)
Top (MD)
MASP:
Drilling Mode
MASP:
Hole Size
DATE: 6.3.2020
WELL: MPU L-59
DESIGN BY: Joe Engel
Hole Size
Casing Section
Collapse Resistance w/o tension (Psi)
Worst case safety factor (Burst)
MASP:
Production Mode
Minimum Yield (psi)
Weight (ppf)
MASP (psi)
Worst Case Safety Factor (Tension)
Collapse Pressure at bottom (Psi)
Worst Case Safety Factor (Collapse)
Length
Top (TVD)
Tension at Top of Section (lbs)
Weight w/o Bouyancy Factor (lbs)
Min strength Tension (1000 lbs)
4.15
3.33 3.29
5 6.51
1.58 4.58
Page 51
Milne Point Unit
L-59 SB Injector
Drilling Procedure
29.0 8-1/2” Hole Section MASP
MD TVD
Planned Top: 6868 3959
Planned TD: 1607 3774
Anticipated Formations and Pressures:
Formation TVD TVDss Est Pressure Oil/Gas/Wet PPG Grad
Schrader Bluff NB Sand 3,959 3,917 1742 Oil 8.46 0.440
Offset Well Mud Densities
Well MW range Top (TVD) Bottom (TVD) Date
MPU L-52 8.8-9.35 Surface 3952 2017
MPU L-51 8.9-9.3 Surface 3930 2017
MPU L-53 9-9.25 Surface 3891 2017
MPU J-27 9-9.3 Surface 3666 2015
MPU J-28 9-9.3 Surface 3617 2015
MPI - 19 9 - 9.3 ppg Surface 4,079 2004
MPI - 18 9 - 10 ppg Surface 3,848 2011
MPI - 17 9 - 9.5 ppg Surface 3,864 2004
Assumptions:
1. Field test data suggests the Fracture Gradient in the Schrader Bluff is btwn 11.5 and 15 ppg EMW.
3. Calculations assume full evacuation of wellbore to gas
Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface:
3959 (ft) x 0.78(psi/ft)= 3088
3088(psi) - [0.1(psi/ft)*3959(ft)]= 2693 psi
MASP from pore pressure (complete evacuation of wellbore to gas from Schrader Bluff NB sand)
3959 (ft) x 0.45(psi/ft)= 1781.5 psi
1781.5(psi) - 0.1(psi/ft)*3959(ft) 1386.0 psi
Summary:
1. MASP while drilling 8-1/2" production hole is governed by pore pressure and evacuation
of entire wellbore to gas at 0.1 psi/ft.
2. Maximum planned mud density for the 8-1/2" hole section is 9.5 ppg.
Maximum Anticipated Surface Pressure Calculation
8-1/2" Hole Section
MPU L-59
Milne Point Unit
ok
Page 52
Milne Point Unit
L-59 SB Injector
Drilling Procedure
30.0 Spider Plot (NAD 27) (Governmental Sections)
L-45
Page 53
Milne Point Unit
L-59 SB Injector
Drilling Procedure
31.0 Surface Plat (As Built) (NAD 27)
Page 54
Milne Point Unit
L-59 SB Injector
Drilling Procedure
32.0 Schrader Bluff NB Sand Offset MW vs TVD Chart
03 June, 2020
Plan: MPU L-59i wp09
Milne Point
M Pt L Pad
Plan: MPU L-59i
MPU L-59i
0750150022503000375045005250True Vertical Depth (1500 usft/in)-750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500 14250Vertical Section at 191.32° (1500 usft/in)MPI-L-59 wp01 ToeMPI-L-59 wp01 Heel50010001500200025003000350040004500500055006000650070 00
750 0
80 0 0
85 0 0
90 00
950 0
1 0 0 0 0
10 5 0 0
11 0 0 0
11 5 0 0
12 0 00
1 2 5 0 0
1 3 0 0 01350013607MPU L-59i wp09Start Dir 2.85º/100' : 330' MD, 330'TVDStart Dir 4º/100' : 730' MD, 727.37'TVDEnd Dir : 1249.48' MD, 1209.26' TVDStart Dir 4º/100' : 1375' MD, 1317.96'TVDEnd Dir : 2337.95' MD, 1982.46' TVDStart Dir 4º/100' : 3400' MD, 2472.86'TVDEnd Dir : 3439.35' MD, 2491.42' TVDStartDir4º/100':6070.87'MD,3758.93'TVDEndDir:6717.83'MD,3946.13'TVDStartDir3º/100':6867.83'MD,3959.2'TVDEndDir:7101.41'MD,3965.31'TVDStartDir3º/100':9001.41'MD,3899'TVDEndDir:9022.74'MD,3898.34'TVDTotalDepth:13606.75'MD,3774.2'TVDHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Pedal CurveWarning Method: Error RatioWELL DETAILS: Plan: MPU L-59i15.50+N/-S +E/-WNorthingEastingLatittudeLongitude0.000.006031945.12544633.15 70° 29' 53.330 N 149° 38' 5.984 WSURVEY PROGRAMDate: 2020-05-06T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool33.50 1000.00 MPU L-59i wp09 (MPU L-59i) 3_Gyro-GC_Csg1000.00 6867.83 MPU L-59i wp09 (MPU L-59i) 3_MWD+IFR2+MS+Sag6867.83 13606.75 MPU L-59i wp09 (MPU L-59i) 3_MWD+IFR2+MS+SagFORMATION TOP DETAILSNo formation data is availableREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU L-59i, True NorthVertical (TVD) Reference:MPU L-59i as-built rkb @ 49.20usftMeasured Depth Reference:MPU L-59i as-built rkb @ 49.20usftCalculation Method:Minimum CurvatureProject:Milne PointSite:M Pt L PadWell:Plan: MPU L-59iWellbore:MPU L-59iDesign:MPU L-59i wp09CASING DETAILSTVD TVDSS MD SizeName3959.20 3910.00 6867.83 9-5/8 9 5/8" x 12 1/4"3774.20 3725.00 13606.75 6-5/8 6 5/8" x 8 1/2"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 33.50 0.00 0.00 33.50 0.00 0.00 0.00 0.00 0.002 330.00 0.00 0.00 330.00 0.00 0.00 0.00 0.00 0.00 Start Dir 2.85º/100' : 330' MD, 330'TVD3 730.00 11.40 225.00 727.37 -28.05 -28.05 2.85 225.00 33.00 Start Dir 4º/100' : 730' MD, 727.37'TVD4 1030.00 23.40 225.00 1013.12 -91.37 -91.37 4.00 0.00 107.525 1249.48 30.00 212.00 1209.26 -168.87 -151.38 4.00 -47.47 195.30 End Dir : 1249.48' MD, 1209.26' TVD6 1375.00 30.00 212.00 1317.96 -222.09 -184.64 0.00 0.00 254.01 Start Dir 4º/100' : 1375' MD, 1317.96'TVD7 2337.95 62.50 181.60 1982.46 -878.04 -329.63 4.00 -46.12 925.67 End Dir : 2337.95' MD, 1982.46' TVD8 3400.00 62.50 181.60 2472.86 -1819.73 -355.94 0.00 0.00 1854.19 Start Dir 4º/100' : 3400' MD, 2472.86'TVD9 3439.35 61.21 180.58 2491.42 -1854.42 -356.60 4.00 -145.54 1888.34 End Dir : 3439.35' MD, 2491.42' TVD10 6070.87 61.21 180.58 3758.93 -4160.44 -380.11 0.00 0.00 4154.12 Start Dir 4º/100' : 6070.87' MD, 3758.93'TVD11 6717.83 85.00 191.32 3946.13 -4770.30 -447.40 4.00 25.16 4765.32 End Dir : 6717.83' MD, 3946.13' TVD12 6867.83 85.00 191.32 3959.20 -4916.83 -476.73 0.00 0.00 4914.75 MPI-L-59 wp01 Heel Start Dir 3º/100' : 6867.83' MD, 3959.2'TVD13 7101.41 92.00 191.00 3965.31 -5145.77 -521.89 3.00 -2.62 5148.10 End Dir : 7101.41' MD, 3965.31' TVD14 9001.41 92.00 191.00 3899.00 -7009.72 -884.21 0.00 0.00 7046.92 Start Dir 3º/100' : 9001.41' MD, 3899'TVD15 9022.74 91.55 191.46 3898.34 -7030.63 -888.36 3.00 134.46 7068.23 End Dir : 9022.74' MD, 3898.34' TVD16 13606.75 91.55 191.46 3774.20 -11521.65 -1798.54 0.00 0.00 11650.55 MPI-L-59 wp01 Toe Total Depth : 13606.75' MD, 3774.2' TVD
-12000
-11250
-10500
-9750
-9000
-8250
-7500
-6750
-6000
-5250
-4500
-3750
-3000
-2250
-1500
-750
0
750
South(-)/North(+) (1500 usft/in)-6000 -5250 -4500 -3750 -3000 -2250 -1500 -750 0 750 1500 2250 3000 3750 4500
West(-)/East(+) (1500 usft/in)
MPI-L-59 wp01 Heel
MPI-L-59 wp01 Toe 10001750
2000
2250
2500
2750
3000
3250
3500
3750
MPU L-59i wp09
Start Dir 2.85º/100' : 330' MD, 330'TVD
Start Dir 4º/100' : 730' MD, 727.37'TVD
End Dir : 2337.95' MD, 1982.46' TVD
Start Dir 4º/100' : 6070.87' MD, 3758.93'TVD
Start Dir 3º/100' : 6867.83' MD, 3959.2'TVD
End Dir : 7101.41' MD, 3965.31' TVD
Start Dir 3º/100' : 9001.41' MD, 3899'TVD
End Dir : 9022.74' MD, 3898.34' TVD
Total Depth : 13606.75' MD, 3774.2' TVD
CASING DETAILS
TVD TVDSS MD Size Name
3959.20 3910.00 6867.83 9-5/8 9 5/8" x 12 1/4"
3774.20 3725.00 13606.75 6-5/8 6 5/8" x 8 1/2"
Project: Milne Point
Site: M Pt L Pad
Well: Plan: MPU L-59i
Wellbore: MPU L-59i
Plan: MPU L-59i wp09
WELL DETAILS: Plan: MPU L-59i
15.50
+N/-S +E/-W Northing Easting Latittude Longitude
0.00 0.00 6031945.12 544633.15 70° 29' 53.330 N 149° 38' 5.984 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: MPU L-59i, True North
Vertical (TVD) Reference:MPU L-59i as-built rkb @ 49.20usft
Measured Depth Reference:MPU L-59i as-built rkb @ 49.20usft
Calculation Method:Minimum Curvature
Project:
Company:
Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt L Pad
Halliburton
Standard Proposal Report
Well:
Wellbore:
Plan: MPU L-59i
MPU L-59i
Survey Calculation Method:Minimum Curvature
MPU L-59i as-built rkb @ 49.20usft
Design:MPU L-59i wp09
Database:NORTH US + CANADA
MD Reference:MPU L-59i as-built rkb @ 49.20usft
North Reference:
Well Plan: MPU L-59i
True
Map System:
Geo Datum:
Project
Map Zone:
System Datum:US State Plane 1927 (Exact solution)
NAD 1927 (NADCON CONUS)
Milne Point, ACT, MILNE POINT
Alaska Zone 04
Mean Sea Level
Using Well Reference Point
Using geodetic scale factor
Site Position:
From:
Site
Latitude:
Longitude:
Position Uncertainty:
Northing:
Easting:
Grid Convergence:
M Pt L Pad, TR-13-10
usft
Map usft
usft
°0.34Slot Radius:"0
6,029,799.28
544,529.55
0.00
70° 29' 32.230 N
149° 38' 9.412 W
Well
Well Position
Longitude:
Latitude:
Easting:
Northing:
usft
+E/-W
+N/-S
Position Uncertainty
usft
usft
usftGround Level:
Plan: MPU L-59i
usft
usft
0.00
0.00
6,031,945.12
544,633.15
15.50Wellhead Elevation:15.70 usft0.50
70° 29' 53.330 N
149° 38' 5.984 W
Wellbore
Declination
(°)
Field Strength
(nT)
Sample Date Dip Angle
(°)
MPU L-59i
Model NameMagnetics
BGGM2020 8/6/2020 15.96 80.89 57,383.93754061
Phase:Version:
Audit Notes:
Design MPU L-59i wp09
PLAN
Vertical Section: Depth From (TVD)
(usft)
+N/-S
(usft)
Direction
(°)
+E/-W
(usft)
Tie On Depth:33.50
191.320.000.0033.50
Inclination
(°)
Azimuth
(°)
+E/-W
(usft)
Tool Face
(°)
+N/-S
(usft)
Measured
Depth
(usft)
Vertical
Depth
(usft)
Dogleg
Rate
(°/100usft)
Build
Rate
(°/100usft)
Turn
Rate
(°/100usft)
Plan Sections
TVD
System
usft
0.000.000.000.000.000.0033.500.000.0033.50 -15.70
0.000.000.000.000.000.00330.000.000.00330.00 280.80
225.000.002.852.85-28.05-28.05727.37225.0011.40730.00 678.17
0.000.004.004.00-91.37-91.371,013.12225.0023.401,030.00 963.92
-47.47-5.923.014.00-151.38-168.871,209.26212.0030.001,249.48 1,160.06
0.000.000.000.00-184.64-222.091,317.96212.0030.001,375.00 1,268.76
-46.12-3.163.384.00-329.63-878.041,982.46181.6062.502,337.95 1,933.26
0.000.000.000.00-355.94-1,819.732,472.86181.6062.503,400.00 2,423.66
-145.54-2.58-3.294.00-356.60-1,854.422,491.42180.5861.213,439.35 2,442.22
0.000.000.000.00-380.11-4,160.443,758.93180.5861.216,070.87 3,709.73
25.161.663.684.00-447.40-4,770.303,946.13191.3285.006,717.83 3,896.93
0.000.000.000.00-476.73-4,916.833,959.20191.3285.006,867.83 3,910.00
-2.62-0.143.003.00-521.89-5,145.773,965.31191.0092.007,101.41 3,916.11
0.000.000.000.00-884.21-7,009.723,899.00191.0092.009,001.41 3,849.80
134.462.14-2.103.00-888.36-7,030.633,898.34191.4691.559,022.74 3,849.14
0.000.000.000.00-1,798.54-11,521.653,774.20191.4691.5513,606.75 3,725.00
6/3/2020 2:47:13PM COMPASS 5000.15 Build 91E Page 2
Project:
Company:
Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt L Pad
Halliburton
Standard Proposal Report
Well:
Wellbore:
Plan: MPU L-59i
MPU L-59i
Survey Calculation Method:Minimum Curvature
MPU L-59i as-built rkb @ 49.20usft
Design:MPU L-59i wp09
Database:NORTH US + CANADA
MD Reference:MPU L-59i as-built rkb @ 49.20usft
North Reference:
Well Plan: MPU L-59i
True
Measured
Depth
(usft)
Inclination
(°)
Azimuth
(°)
+E/-W
(usft)
Map
Northing
(usft)
Map
Easting
(usft)
+N/-S
(usft)
Planned Survey
Vertical
Depth
(usft)
TVDss
usft
DLS
-15.70
Vert Section
33.50 0.00 33.50 0.00 0.000.00 544,633.156,031,945.12-15.70 0.00 0.00
100.00 0.00 100.00 0.00 0.000.00 544,633.156,031,945.1250.80 0.00 0.00
200.00 0.00 200.00 0.00 0.000.00 544,633.156,031,945.12150.80 0.00 0.00
300.00 0.00 300.00 0.00 0.000.00 544,633.156,031,945.12250.80 0.00 0.00
330.00 0.00 330.00 0.00 0.000.00 544,633.156,031,945.12280.80 0.00 0.00
Start Dir 2.85º/100' : 330' MD, 330'TVD
400.00 2.00 399.99 -0.86 -0.86225.00 544,632.296,031,944.25350.79 2.85 1.01
500.00 4.85 499.80 -5.08 -5.08225.00 544,628.106,031,940.01450.60 2.85 5.98
600.00 7.70 599.19 -12.80 -12.80225.00 544,620.436,031,932.24549.99 2.85 15.06
700.00 10.55 697.91 -24.01 -24.01225.00 544,609.296,031,920.97648.71 2.85 28.25
730.00 11.40 727.37 -28.05 -28.05225.00 544,605.286,031,916.91678.17 2.85 33.00
Start Dir 4º/100' : 730' MD, 727.37'TVD
800.00 14.20 795.62 -39.01 -39.01225.00 544,594.386,031,905.88746.42 4.00 45.91
900.00 18.20 891.63 -58.73 -58.73225.00 544,574.786,031,886.04842.43 4.00 69.12
1,000.00 22.20 985.46 -83.15 -83.15225.00 544,550.516,031,861.48936.26 4.00 97.85
1,030.00 23.40 1,013.12 -91.37 -91.37225.00 544,542.346,031,853.22963.92 4.00 107.52
1,100.00 25.37 1,076.87 -112.66 -110.87220.18 544,522.966,031,831.811,027.67 4.00 132.23
1,200.00 28.42 1,166.06 -148.66 -138.16214.43 544,495.896,031,795.641,116.86 4.00 172.89
1,249.48 30.00 1,209.25 -168.87 -151.38212.00 544,482.806,031,775.361,160.05 4.00 195.30
End Dir : 1249.48' MD, 1209.26' TVD
1,300.00 30.00 1,253.00 -190.29 -164.76212.00 544,469.556,031,753.861,203.80 0.00 218.93
1,375.00 30.00 1,317.95 -222.09 -184.64212.00 544,449.876,031,721.951,268.75 0.00 254.01
Start Dir 4º/100' : 1375' MD, 1317.96'TVD
1,400.00 30.70 1,339.53 -232.89 -191.20210.59 544,443.386,031,711.111,290.33 4.00 265.88
1,500.00 33.64 1,424.18 -279.88 -216.12205.49 544,418.746,031,663.971,374.98 4.00 316.86
1,600.00 36.76 1,505.90 -332.82 -238.84201.14 544,396.346,031,610.911,456.70 4.00 373.22
1,700.00 40.02 1,584.28 -391.43 -259.25197.40 544,376.286,031,552.181,535.08 4.00 434.70
1,800.00 43.38 1,658.95 -455.44 -277.25194.13 544,358.666,031,488.071,609.75 4.00 501.00
1,900.00 46.82 1,729.53 -524.52 -292.76191.25 544,343.576,031,418.901,680.33 4.00 571.79
2,000.00 50.33 1,795.70 -598.36 -305.69188.69 544,331.086,031,345.001,746.50 4.00 646.72
2,100.00 53.88 1,857.11 -676.57 -315.99186.37 544,321.266,031,266.731,807.91 4.00 725.44
2,200.00 57.48 1,913.48 -758.79 -323.61184.26 544,314.146,031,184.471,864.28 4.00 807.55
2,300.00 61.11 1,964.53 -844.62 -328.50182.30 544,309.766,031,098.631,915.33 4.00 892.67
2,337.95 62.50 1,982.46 -878.05 -329.63181.60 544,308.836,031,065.201,933.26 4.00 925.67
End Dir : 2337.95' MD, 1982.46' TVD
2,400.00 62.50 2,011.11 -933.06 -331.17181.60 544,307.626,031,010.181,961.91 0.00 979.92
2,500.00 62.50 2,057.29 -1,021.73 -333.65181.60 544,305.686,030,921.502,008.09 0.00 1,067.34
2,600.00 62.50 2,103.46 -1,110.40 -336.12181.60 544,303.736,030,832.832,054.26 0.00 1,154.77
2,700.00 62.50 2,149.64 -1,199.06 -338.60181.60 544,301.796,030,744.162,100.44 0.00 1,242.20
2,800.00 62.50 2,195.81 -1,287.73 -341.08181.60 544,299.846,030,655.492,146.61 0.00 1,329.63
2,900.00 62.50 2,241.99 -1,376.40 -343.55181.60 544,297.906,030,566.822,192.79 0.00 1,417.06
3,000.00 62.50 2,288.16 -1,465.06 -346.03181.60 544,295.966,030,478.152,238.96 0.00 1,504.48
3,100.00 62.50 2,334.34 -1,553.73 -348.51181.60 544,294.016,030,389.482,285.14 0.00 1,591.91
3,200.00 62.50 2,380.51 -1,642.40 -350.98181.60 544,292.076,030,300.812,331.31 0.00 1,679.34
3,300.00 62.50 2,426.69 -1,731.06 -353.46181.60 544,290.126,030,212.142,377.49 0.00 1,766.77
6/3/2020 2:47:13PM COMPASS 5000.15 Build 91E Page 3
Project:
Company:
Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt L Pad
Halliburton
Standard Proposal Report
Well:
Wellbore:
Plan: MPU L-59i
MPU L-59i
Survey Calculation Method:Minimum Curvature
MPU L-59i as-built rkb @ 49.20usft
Design:MPU L-59i wp09
Database:NORTH US + CANADA
MD Reference:MPU L-59i as-built rkb @ 49.20usft
North Reference:
Well Plan: MPU L-59i
True
Measured
Depth
(usft)
Inclination
(°)
Azimuth
(°)
+E/-W
(usft)
Map
Northing
(usft)
Map
Easting
(usft)
+N/-S
(usft)
Planned Survey
Vertical
Depth
(usft)
TVDss
usft
DLS
2,423.66
Vert Section
3,400.00 62.50 2,472.86 -1,819.73 -355.94181.60 544,288.186,030,123.462,423.66 0.00 1,854.19
Start Dir 4º/100' : 3400' MD, 2472.86'TVD
3,439.35 61.21 2,491.42 -1,854.42 -356.60180.58 544,287.736,030,088.782,442.22 4.00 1,888.34
End Dir : 3439.35' MD, 2491.42' TVD
3,500.00 61.21 2,520.64 -1,907.57 -357.14180.58 544,287.506,030,035.632,471.44 0.00 1,940.56
3,600.00 61.21 2,568.80 -1,995.20 -358.04180.58 544,287.146,029,948.002,519.60 0.00 2,026.66
3,700.00 61.21 2,616.97 -2,082.83 -358.93180.58 544,286.776,029,860.382,567.77 0.00 2,112.76
3,800.00 61.21 2,665.14 -2,170.46 -359.82180.58 544,286.406,029,772.752,615.94 0.00 2,198.86
3,900.00 61.21 2,713.30 -2,258.09 -360.72180.58 544,286.046,029,685.132,664.10 0.00 2,284.97
4,000.00 61.21 2,761.47 -2,345.72 -361.61180.58 544,285.676,029,597.502,712.27 0.00 2,371.07
4,100.00 61.21 2,809.64 -2,433.35 -362.50180.58 544,285.306,029,509.872,760.44 0.00 2,457.17
4,200.00 61.21 2,857.80 -2,520.98 -363.40180.58 544,284.936,029,422.252,808.60 0.00 2,543.27
4,300.00 61.21 2,905.97 -2,608.61 -364.29180.58 544,284.576,029,334.622,856.77 0.00 2,629.37
4,400.00 61.21 2,954.13 -2,696.25 -365.18180.58 544,284.206,029,246.992,904.93 0.00 2,715.47
4,500.00 61.21 3,002.30 -2,783.88 -366.07180.58 544,283.836,029,159.372,953.10 0.00 2,801.58
4,600.00 61.21 3,050.47 -2,871.51 -366.97180.58 544,283.476,029,071.743,001.27 0.00 2,887.68
4,700.00 61.21 3,098.63 -2,959.14 -367.86180.58 544,283.106,028,984.113,049.43 0.00 2,973.78
4,800.00 61.21 3,146.80 -3,046.77 -368.75180.58 544,282.736,028,896.493,097.60 0.00 3,059.88
4,900.00 61.21 3,194.97 -3,134.40 -369.65180.58 544,282.376,028,808.863,145.77 0.00 3,145.98
5,000.00 61.21 3,243.13 -3,222.03 -370.54180.58 544,282.006,028,721.243,193.93 0.00 3,232.08
5,100.00 61.21 3,291.30 -3,309.66 -371.43180.58 544,281.636,028,633.613,242.10 0.00 3,318.19
5,200.00 61.21 3,339.47 -3,397.29 -372.33180.58 544,281.276,028,545.983,290.27 0.00 3,404.29
5,300.00 61.21 3,387.63 -3,484.93 -373.22180.58 544,280.906,028,458.363,338.43 0.00 3,490.39
5,400.00 61.21 3,435.80 -3,572.56 -374.11180.58 544,280.536,028,370.733,386.60 0.00 3,576.49
5,500.00 61.21 3,483.96 -3,660.19 -375.01180.58 544,280.166,028,283.103,434.76 0.00 3,662.59
5,600.00 61.21 3,532.13 -3,747.82 -375.90180.58 544,279.806,028,195.483,482.93 0.00 3,748.69
5,700.00 61.21 3,580.30 -3,835.45 -376.79180.58 544,279.436,028,107.853,531.10 0.00 3,834.80
5,800.00 61.21 3,628.46 -3,923.08 -377.69180.58 544,279.066,028,020.233,579.26 0.00 3,920.90
5,900.00 61.21 3,676.63 -4,010.71 -378.58180.58 544,278.706,027,932.603,627.43 0.00 4,007.00
6,000.00 61.21 3,724.80 -4,098.34 -379.47180.58 544,278.336,027,844.973,675.60 0.00 4,093.10
6,070.87 61.21 3,758.93 -4,160.45 -380.11180.58 544,278.076,027,782.873,709.73 0.00 4,154.12
Start Dir 4º/100' : 6070.87' MD, 3758.93'TVD
6,100.00 62.26 3,772.73 -4,186.10 -380.49181.14 544,277.846,027,757.223,723.53 4.00 4,179.35
6,200.00 65.90 3,816.43 -4,275.96 -383.76182.99 544,275.116,027,667.353,767.23 4.00 4,268.11
6,300.00 69.56 3,854.32 -4,368.27 -390.00184.73 544,269.426,027,575.013,805.12 4.00 4,359.85
6,400.00 73.24 3,886.21 -4,462.58 -399.19186.39 544,260.806,027,480.653,837.01 4.00 4,454.13
6,500.00 76.93 3,911.94 -4,558.44 -411.29187.99 544,249.286,027,384.743,862.74 4.00 4,550.49
6,600.00 80.63 3,931.39 -4,655.36 -426.24189.53 544,234.926,027,287.743,882.19 4.00 4,648.46
6,700.00 84.34 3,944.47 -4,752.88 -443.95191.05 544,217.796,027,190.123,895.27 4.00 4,747.57
6,717.83 85.00 3,946.13 -4,770.30 -447.40191.32 544,214.456,027,172.693,896.93 4.00 4,765.32
End Dir : 6717.83' MD, 3946.13' TVD
6,800.00 85.00 3,953.29 -4,850.56 -463.46191.32 544,198.876,027,092.333,904.09 0.00 4,847.18
6,867.83 85.00 3,959.20 -4,916.82 -476.73191.32 544,186.006,027,026.003,910.00 0.00 4,914.75
Start Dir 3º/100' : 6867.83' MD, 3959.2'TVD - 9 5/8" x 12 1/4"
6,900.00 85.96 3,961.73 -4,948.27 -483.01191.28 544,179.916,026,994.523,912.53 3.00 4,946.82
6/3/2020 2:47:13PM COMPASS 5000.15 Build 91E Page 4
Project:
Company:
Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt L Pad
Halliburton
Standard Proposal Report
Well:
Wellbore:
Plan: MPU L-59i
MPU L-59i
Survey Calculation Method:Minimum Curvature
MPU L-59i as-built rkb @ 49.20usft
Design:MPU L-59i wp09
Database:NORTH US + CANADA
MD Reference:MPU L-59i as-built rkb @ 49.20usft
North Reference:
Well Plan: MPU L-59i
True
Measured
Depth
(usft)
Inclination
(°)
Azimuth
(°)
+E/-W
(usft)
Map
Northing
(usft)
Map
Easting
(usft)
+N/-S
(usft)
Planned Survey
Vertical
Depth
(usft)
TVDss
usft
DLS
3,916.96
Vert Section
7,000.00 88.96 3,966.16 -5,046.26 -502.42191.14 544,161.086,026,896.433,916.96 3.00 5,046.71
7,101.41 92.00 3,965.31 -5,145.76 -521.89191.00 544,142.226,026,796.823,916.11 3.00 5,148.10
End Dir : 7101.41' MD, 3965.31' TVD
7,200.00 92.00 3,961.87 -5,242.48 -540.69191.00 544,124.006,026,700.003,912.67 0.00 5,246.63
7,300.00 92.00 3,958.38 -5,340.59 -559.76191.00 544,105.526,026,601.793,909.18 0.00 5,346.57
7,400.00 92.00 3,954.89 -5,438.69 -578.83191.00 544,087.046,026,503.583,905.69 0.00 5,446.50
7,500.00 92.00 3,951.40 -5,536.79 -597.90191.00 544,068.566,026,405.383,902.20 0.00 5,546.44
7,600.00 92.00 3,947.91 -5,634.90 -616.97191.00 544,050.096,026,307.173,898.71 0.00 5,646.38
7,700.00 92.00 3,944.42 -5,733.00 -636.04191.00 544,031.616,026,208.973,895.22 0.00 5,746.32
7,800.00 92.00 3,940.93 -5,831.10 -655.11191.00 544,013.136,026,110.763,891.73 0.00 5,846.25
7,900.00 92.00 3,937.44 -5,929.20 -674.18191.00 543,994.656,026,012.553,888.24 0.00 5,946.19
8,000.00 92.00 3,933.95 -6,027.31 -693.25191.00 543,976.176,025,914.353,884.75 0.00 6,046.13
8,100.00 92.00 3,930.46 -6,125.41 -712.32191.00 543,957.706,025,816.143,881.26 0.00 6,146.07
8,200.00 92.00 3,926.97 -6,223.51 -731.39191.00 543,939.226,025,717.943,877.77 0.00 6,246.00
8,300.00 92.00 3,923.48 -6,321.62 -750.45191.00 543,920.746,025,619.733,874.28 0.00 6,345.94
8,400.00 92.00 3,919.99 -6,419.72 -769.52191.00 543,902.266,025,521.523,870.79 0.00 6,445.88
8,500.00 92.00 3,916.50 -6,517.82 -788.59191.00 543,883.786,025,423.323,867.30 0.00 6,545.82
8,600.00 92.00 3,913.01 -6,615.92 -807.66191.00 543,865.316,025,325.113,863.81 0.00 6,645.75
8,700.00 92.00 3,909.52 -6,714.03 -826.73191.00 543,846.836,025,226.913,860.32 0.00 6,745.69
8,800.00 92.00 3,906.03 -6,812.13 -845.80191.00 543,828.356,025,128.703,856.83 0.00 6,845.63
8,900.00 92.00 3,902.54 -6,910.23 -864.87191.00 543,809.876,025,030.493,853.34 0.00 6,945.57
9,001.41 92.00 3,899.00 -7,009.72 -884.21191.00 543,791.136,024,930.903,849.80 0.00 7,046.91
Start Dir 3º/100' : 9001.41' MD, 3899'TVD
9,022.74 91.55 3,898.34 -7,030.63 -888.36191.46 543,787.116,024,909.973,849.14 3.00 7,068.23
End Dir : 9022.74' MD, 3898.34' TVD
9,100.00 91.55 3,896.25 -7,106.32 -903.70191.46 543,772.226,024,834.193,847.05 0.00 7,145.46
9,200.00 91.55 3,893.54 -7,204.30 -923.56191.46 543,752.966,024,736.113,844.34 0.00 7,245.43
9,300.00 91.55 3,890.83 -7,302.27 -943.41191.46 543,733.696,024,638.033,841.63 0.00 7,345.39
9,400.00 91.55 3,888.12 -7,400.24 -963.27191.46 543,714.436,024,539.953,838.92 0.00 7,445.35
9,500.00 91.55 3,885.42 -7,498.21 -983.12191.46 543,695.166,024,441.873,836.22 0.00 7,545.32
9,600.00 91.55 3,882.71 -7,596.18 -1,002.98191.46 543,675.906,024,343.803,833.51 0.00 7,645.28
9,700.00 91.55 3,880.00 -7,694.15 -1,022.83191.46 543,656.636,024,245.723,830.80 0.00 7,745.24
9,800.00 91.55 3,877.29 -7,792.12 -1,042.69191.46 543,637.376,024,147.643,828.09 0.00 7,845.21
9,900.00 91.55 3,874.58 -7,890.10 -1,062.54191.46 543,618.106,024,049.563,825.38 0.00 7,945.17
10,000.00 91.55 3,871.88 -7,988.07 -1,082.40191.46 543,598.846,023,951.483,822.68 0.00 8,045.13
10,100.00 91.55 3,869.17 -8,086.04 -1,102.26191.46 543,579.576,023,853.403,819.97 0.00 8,145.10
10,200.00 91.55 3,866.46 -8,184.01 -1,122.11191.46 543,560.316,023,755.323,817.26 0.00 8,245.06
10,300.00 91.55 3,863.75 -8,281.98 -1,141.97191.46 543,541.046,023,657.243,814.55 0.00 8,345.02
10,400.00 91.55 3,861.04 -8,379.95 -1,161.82191.46 543,521.786,023,559.163,811.84 0.00 8,444.98
10,500.00 91.55 3,858.33 -8,477.93 -1,181.68191.46 543,502.516,023,461.083,809.13 0.00 8,544.95
10,600.00 91.55 3,855.63 -8,575.90 -1,201.53191.46 543,483.256,023,363.003,806.43 0.00 8,644.91
10,700.00 91.55 3,852.92 -8,673.87 -1,221.39191.46 543,463.986,023,264.923,803.72 0.00 8,744.87
10,800.00 91.55 3,850.21 -8,771.84 -1,241.24191.46 543,444.726,023,166.843,801.01 0.00 8,844.84
10,900.00 91.55 3,847.50 -8,869.81 -1,261.10191.46 543,425.456,023,068.763,798.30 0.00 8,944.80
11,000.00 91.55 3,844.79 -8,967.78 -1,280.96191.46 543,406.196,022,970.683,795.59 0.00 9,044.76
6/3/2020 2:47:13PM COMPASS 5000.15 Build 91E Page 5
Project:
Company:
Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt L Pad
Halliburton
Standard Proposal Report
Well:
Wellbore:
Plan: MPU L-59i
MPU L-59i
Survey Calculation Method:Minimum Curvature
MPU L-59i as-built rkb @ 49.20usft
Design:MPU L-59i wp09
Database:NORTH US + CANADA
MD Reference:MPU L-59i as-built rkb @ 49.20usft
North Reference:
Well Plan: MPU L-59i
True
Measured
Depth
(usft)
Inclination
(°)
Azimuth
(°)
+E/-W
(usft)
Map
Northing
(usft)
Map
Easting
(usft)
+N/-S
(usft)
Planned Survey
Vertical
Depth
(usft)
TVDss
usft
DLS
3,792.89
Vert Section
11,100.00 91.55 3,842.09 -9,065.75 -1,300.81191.46 543,386.926,022,872.603,792.89 0.00 9,144.73
11,200.00 91.55 3,839.38 -9,163.73 -1,320.67191.46 543,367.666,022,774.523,790.18 0.00 9,244.69
11,300.00 91.55 3,836.67 -9,261.70 -1,340.52191.46 543,348.396,022,676.453,787.47 0.00 9,344.65
11,400.00 91.55 3,833.96 -9,359.67 -1,360.38191.46 543,329.136,022,578.373,784.76 0.00 9,444.61
11,500.00 91.55 3,831.25 -9,457.64 -1,380.23191.46 543,309.866,022,480.293,782.05 0.00 9,544.58
11,600.00 91.55 3,828.55 -9,555.61 -1,400.09191.46 543,290.606,022,382.213,779.35 0.00 9,644.54
11,700.00 91.55 3,825.84 -9,653.58 -1,419.94191.46 543,271.336,022,284.133,776.64 0.00 9,744.50
11,800.00 91.55 3,823.13 -9,751.56 -1,439.80191.46 543,252.076,022,186.053,773.93 0.00 9,844.47
11,900.00 91.55 3,820.42 -9,849.53 -1,459.66191.46 543,232.806,022,087.973,771.22 0.00 9,944.43
12,000.00 91.55 3,817.71 -9,947.50 -1,479.51191.46 543,213.546,021,989.893,768.51 0.00 10,044.39
12,100.00 91.55 3,815.00 -10,045.47 -1,499.37191.46 543,194.276,021,891.813,765.80 0.00 10,144.36
12,200.00 91.55 3,812.30 -10,143.44 -1,519.22191.46 543,175.016,021,793.733,763.10 0.00 10,244.32
12,300.00 91.55 3,809.59 -10,241.41 -1,539.08191.46 543,155.746,021,695.653,760.39 0.00 10,344.28
12,400.00 91.55 3,806.88 -10,339.38 -1,558.93191.46 543,136.486,021,597.573,757.68 0.00 10,444.24
12,500.00 91.55 3,804.17 -10,437.36 -1,578.79191.46 543,117.216,021,499.493,754.97 0.00 10,544.21
12,600.00 91.55 3,801.46 -10,535.33 -1,598.65191.46 543,097.956,021,401.413,752.26 0.00 10,644.17
12,700.00 91.55 3,798.76 -10,633.30 -1,618.50191.46 543,078.686,021,303.333,749.56 0.00 10,744.13
12,800.00 91.55 3,796.05 -10,731.27 -1,638.36191.46 543,059.426,021,205.253,746.85 0.00 10,844.10
12,900.00 91.55 3,793.34 -10,829.24 -1,658.21191.46 543,040.156,021,107.173,744.14 0.00 10,944.06
13,000.00 91.55 3,790.63 -10,927.21 -1,678.07191.46 543,020.896,021,009.103,741.43 0.00 11,044.02
13,100.00 91.55 3,787.92 -11,025.19 -1,697.92191.46 543,001.636,020,911.023,738.72 0.00 11,143.99
13,200.00 91.55 3,785.22 -11,123.16 -1,717.78191.46 542,982.366,020,812.943,736.02 0.00 11,243.95
13,300.00 91.55 3,782.51 -11,221.13 -1,737.63191.46 542,963.106,020,714.863,733.31 0.00 11,343.91
13,400.00 91.55 3,779.80 -11,319.10 -1,757.49191.46 542,943.836,020,616.783,730.60 0.00 11,443.88
13,500.00 91.55 3,777.09 -11,417.07 -1,777.35191.46 542,924.576,020,518.703,727.89 0.00 11,543.84
13,606.75 91.55 3,774.20 -11,521.65 -1,798.54191.46 542,904.006,020,414.003,725.00 0.00 11,650.55
Total Depth : 13606.75' MD, 3774.2' TVD
Target Name
- hit/miss target
- Shape
TVD
(usft)
Northing
(usft)
Easting
(usft)
+N/-S
(usft)
+E/-W
(usft)
Tar gets
Dip Angle
(°)
Dip Dir.
(°)
MPI-L-59 wp01 Heel 3,959.20 6,027,026.00 544,186.00-4,916.83 -476.730.00 0.00
-plan hits target center
- Point
MPI-L-59 wp01 Toe 3,774.20 6,020,414.00 542,904.00-11,521.65 -1,798.540.00 0.00
-plan hits target center
- Point
6/3/2020 2:47:13PM COMPASS 5000.15 Build 91E Page 6
Project:
Company:
Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt L Pad
Halliburton
Standard Proposal Report
Well:
Wellbore:
Plan: MPU L-59i
MPU L-59i
Survey Calculation Method:Minimum Curvature
MPU L-59i as-built rkb @ 49.20usft
Design:MPU L-59i wp09
Database:NORTH US + CANADA
MD Reference:MPU L-59i as-built rkb @ 49.20usft
North Reference:
Well Plan: MPU L-59i
True
Vertical
Depth
(usft)
Measured
Depth
(usft)
Casing
Diameter
(")
Hole
Diameter
(")Name
Casing Points
6 5/8" x 8 1/2"3,774.2013,606.75 6-5/8 8-1/2
9 5/8" x 12 1/4"3,959.206,867.83 9-5/8 12-1/4
Measured
Depth
(usft)
Vertical
Depth
(usft)
+E/-W
(usft)
+N/-S
(usft)
Local Coordinates
Comment
Plan Annotations
330.00 330.00 0.00 0.00 Start Dir 2.85º/100' : 330' MD, 330'TVD
730.00 727.37 -28.05 -28.05 Start Dir 4º/100' : 730' MD, 727.37'TVD
1,249.48 1,209.25 -168.87 -151.38 End Dir : 1249.48' MD, 1209.26' TVD
1,375.00 1,317.95 -222.09 -184.64 Start Dir 4º/100' : 1375' MD, 1317.96'TVD
2,337.95 1,982.46 -878.05 -329.63 End Dir : 2337.95' MD, 1982.46' TVD
3,400.00 2,472.86 -1,819.73 -355.94 Start Dir 4º/100' : 3400' MD, 2472.86'TVD
3,439.35 2,491.42 -1,854.42 -356.60 End Dir : 3439.35' MD, 2491.42' TVD
6,070.87 3,758.93 -4,160.45 -380.11 Start Dir 4º/100' : 6070.87' MD, 3758.93'TVD
6,717.83 3,946.13 -4,770.30 -447.40 End Dir : 6717.83' MD, 3946.13' TVD
6,867.83 3,959.20 -4,916.82 -476.73 Start Dir 3º/100' : 6867.83' MD, 3959.2'TVD
7,101.41 3,965.31 -5,145.76 -521.89 End Dir : 7101.41' MD, 3965.31' TVD
9,001.41 3,899.00 -7,009.72 -884.21 Start Dir 3º/100' : 9001.41' MD, 3899'TVD
9,022.74 3,898.34 -7,030.63 -888.36 End Dir : 9022.74' MD, 3898.34' TVD
13,606.75 3,774.20 -11,521.65 -1,798.54 Total Depth : 13606.75' MD, 3774.2' TVD
6/3/2020 2:47:13PM COMPASS 5000.15 Build 91E Page 7
03 June, 2020Milne PointM Pt L PadPlan: MPU L-59iMPU L-59iMPU L-59i wp09Reference Design: M Pt L Pad - Plan: MPU L-59i - MPU L-59i - MPU L-59i wp09Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Well Coordinates: 6,031,945.12 N, 544,633.15 E (70° 29' 53.33" N, 149° 38' 05.98" W)Datum Height: MPU L-59i as-built rkb @ 49.20usftScan Range: 33.50 to 6,867.83 usft. Measured Depth.Geodetic Scale Factor AppliedVersion: 5000.15 Build: 91EScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftNO GLOBAL FILTER: Using user defined selection & filtering criteriaScan Type:Scan Type:25.000- 6867ft MD
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU L-59i - MPU L-59i wp09Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 33.50 to 6,867.83 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt L Pad - Plan: MPU L-59i - MPU L-59i - MPU L-59i wp09MeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt L PadMPL-03 - MPL-03 - MPL-03125.07 1,763.79 110.44 1,753.39 8.5471,763.79Clearance Factor Pass - MPL-13 - MPL-13 - MPL-13188.51 1,386.74 176.94 1,416.42 16.2931,386.74Ellipse Separation Pass - MPL-13 - MPL-13 - MPL-13201.69 1,483.50 188.12 1,479.72 14.8721,483.50Clearance Factor Pass - MPL-16 - MPL-16 - MPL-16167.06 690.59 160.95 694.63 27.367690.59Centre Distance Pass - MPL-16 - MPL-16 - MPL-16167.17 708.50 160.92 711.58 26.764708.50Ellipse Separation Pass - MPL-16 - MPL-16 - MPL-16180.99 858.50 173.57 844.16 24.390858.50Clearance Factor Pass - MPL-16 - MPL-16A - MPL-16A167.06 690.59 160.95 688.84 27.367690.59Centre Distance Pass - MPL-16 - MPL-16A - MPL-16A167.17 708.50 160.92 705.79 26.764708.50Ellipse Separation Pass - MPL-16 - MPL-16A - MPL-16A180.99 858.50 173.57 838.37 24.390858.50Clearance Factor Pass - MPL-17 - MPL-17 - MPL-17208.97 347.05 206.19 349.42 74.986347.05Centre Distance Pass - MPL-17 - MPL-17 - MPL-17209.11 383.50 206.12 385.44 69.809383.50Ellipse Separation Pass - MPL-17 - MPL-17 - MPL-17278.38 1,008.50 271.32 994.20 39.4521,008.50Clearance Factor Pass - MPL-20 - MPL-20 - MPL-2063.92 1,673.47 51.61 1,675.65 5.1921,673.47Clearance Factor Pass - MPL-21 - MPL-21 - MPL-21186.21 33.50 184.79 30.50 131.66333.50Centre Distance Pass - MPL-21 - MPL-21 - MPL-21186.71 358.50 183.30 354.85 54.720358.50Ellipse Separation Pass - MPL-21 - MPL-21 - MPL-21238.01 858.50 230.67 833.92 32.423858.50Clearance Factor Pass - MPL-24 - MPL-24 - MPL-24117.44 697.97 111.19 700.66 18.799697.97Centre Distance Pass - MPL-24 - MPL-24 - MPL-24117.64 733.50 111.11 735.95 18.019733.50Ellipse Separation Pass - MPL-24 - MPL-24 - MPL-24127.15 883.50 119.36 882.27 16.332883.50Clearance Factor Pass - MPL-25 - MPL-25 - MPL-25161.18 372.00 158.29 370.45 55.694372.00Centre Distance Pass - MPL-25 - MPL-25 - MPL-25161.20 383.50 158.24 381.94 54.429383.50Ellipse Separation Pass - MPL-25 - MPL-25 - MPL-25206.80 883.50 200.65 874.65 33.621883.50Clearance Factor Pass - MPL-28 - MPL-28 - MPL-2880.20 698.66 73.94 701.05 12.828698.66Centre Distance Pass - MPL-28 - MPL-28 - MPL-2880.22 708.50 73.89 710.74 12.674708.50Ellipse Separation Pass - MPL-28 - MPL-28 - MPL-2886.61 833.50 79.27 833.02 11.806833.50Clearance Factor Pass - MPL-28 - MPL-28A - MPL-28A80.20 698.66 73.94 701.05 12.828698.66Centre Distance Pass - MPL-28 - MPL-28A - MPL-28A80.22 708.50 73.89 710.74 12.674708.50Ellipse Separation Pass - MPL-28 - MPL-28A - MPL-28A86.61 833.50 79.27 833.02 11.806833.50Clearance Factor Pass - 03 June, 2020-14:48COMPASSPage 2 of 9
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU L-59i - MPU L-59i wp09Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 33.50 to 6,867.83 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt L Pad - Plan: MPU L-59i - MPU L-59i - MPU L-59i wp09MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPL-29 - MPL-29 - MPL-29142.47 33.50 141.06 36.28 100.76033.50Centre Distance Pass - MPL-29 - MPL-29 - MPL-29142.50 58.50 141.04 60.94 97.43858.50Ellipse Separation Pass - MPL-29 - MPL-29 - MPL-29187.93 758.50 182.60 748.28 35.242758.50Clearance Factor Pass - MPL-32 - MPL-32 - MPL-3250.28 1,003.85 41.47 1,006.77 5.7111,003.85Centre Distance Pass - MPL-32 - MPL-32 - MPL-3250.28 1,008.50 41.45 1,011.44 5.6911,008.50Ellipse Separation Pass - MPL-32 - MPL-32 - MPL-3251.34 1,133.50 42.04 1,137.68 5.5191,133.50Clearance Factor Pass - MPL-33 - MPL-33 - MPL-33125.41 33.50 124.00 35.02 88.72533.50Centre Distance Pass - MPL-33 - MPL-33 - MPL-33125.83 358.50 122.29 360.21 35.520358.50Ellipse Separation Pass - MPL-33 - MPL-33 - MPL-33160.06 808.50 152.97 815.05 22.581808.50Clearance Factor Pass - MPL-34 - MPL-34 - MPL-34369.46 1,864.15 358.54 1,758.34 33.8231,864.15Centre Distance Pass - MPL-34 - MPL-34 - MPL-34369.59 1,883.50 358.54 1,774.10 33.4411,883.50Ellipse Separation Pass - MPL-34 - MPL-34 - MPL-341,578.61 4,883.50 1,515.04 4,722.67 24.8344,883.50Clearance Factor Pass - MPL-35 - MPL-35 - MPL-35269.21 3,270.71 247.71 3,071.52 12.5173,270.71Centre Distance Pass - MPL-35 - MPL-35 - MPL-35269.28 3,283.50 247.64 3,083.28 12.4403,283.50Ellipse Separation Pass - MPL-35 - MPL-35 - MPL-35355.87 3,808.50 307.91 3,563.99 7.4203,808.50Clearance Factor Pass - MPL-35 - MPL-35A - MPL-35A269.21 3,270.71 247.71 3,072.32 12.5173,270.71Centre Distance Pass - MPL-35 - MPL-35A - MPL-35A269.28 3,283.50 247.64 3,084.08 12.4403,283.50Ellipse Separation Pass - MPL-35 - MPL-35A - MPL-35A355.87 3,808.50 307.91 3,564.79 7.4203,808.50Clearance Factor Pass - MPL-35 - MPL-35APB1 - MPL-35APB1269.21 3,270.71 247.71 3,072.32 12.5173,270.71Centre Distance Pass - MPL-35 - MPL-35APB1 - MPL-35APB1269.28 3,283.50 247.64 3,084.08 12.4403,283.50Ellipse Separation Pass - MPL-35 - MPL-35APB1 - MPL-35APB1355.87 3,808.50 307.91 3,564.79 7.4203,808.50Clearance Factor Pass - MPL-35 - MPL-35APB2 - MPL-35APB2269.21 3,270.71 247.71 3,072.32 12.5173,270.71Centre Distance Pass - MPL-35 - MPL-35APB2 - MPL-35APB2269.28 3,283.50 247.64 3,084.08 12.4403,283.50Ellipse Separation Pass - MPL-35 - MPL-35APB2 - MPL-35APB2355.87 3,808.50 307.91 3,564.79 7.4203,808.50Clearance Factor Pass - MPL-35 - MPL-35APB3 - MPL-35APB3269.21 3,270.71 247.71 3,072.32 12.5173,270.71Centre Distance Pass - MPL-35 - MPL-35APB3 - MPL-35APB3269.28 3,283.50 247.64 3,084.08 12.4403,283.50Ellipse Separation Pass - MPL-35 - MPL-35APB3 - MPL-35APB3355.87 3,808.50 307.91 3,564.79 7.4203,808.50Clearance Factor Pass - MPL-36 - MPL-36 - MPL-36364.36 2,383.50 343.31 2,307.29 17.3072,383.50Ellipse Separation Pass - MPL-36 - MPL-36 - MPL-36364.35 2,388.90 343.33 2,313.00 17.3302,388.90Centre Distance Pass - MPL-36 - MPL-36 - MPL-36675.24 3,508.50634.95 3,381.15 16.7623,508.50Clearance Factor Pass - 03 June, 2020-14:48COMPASSPage 3 of 9
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU L-59i - MPU L-59i wp09Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 33.50 to 6,867.83 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt L Pad - Plan: MPU L-59i - MPU L-59i - MPU L-59i wp09MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPL-36 - MPL-36L1 - MPL-36L1364.36 2,383.50 343.31 2,307.29 17.3072,383.50Ellipse Separation Pass - MPL-36 - MPL-36L1 - MPL-36L1364.35 2,388.90 343.33 2,313.00 17.3302,388.90Centre Distance Pass - MPL-36 - MPL-36L1 - MPL-36L1675.24 3,508.50 634.95 3,381.15 16.7623,508.50Clearance Factor Pass - MPL-36 - MPL-36L1 PB1 - MPL-36L1 PB1364.36 2,383.50 343.31 2,307.29 17.3072,383.50Ellipse Separation Pass - MPL-36 - MPL-36L1 PB1 - MPL-36L1 PB1364.35 2,388.90 343.33 2,313.00 17.3302,388.90Centre Distance Pass - MPL-36 - MPL-36L1 PB1 - MPL-36L1 PB1675.24 3,508.50 634.95 3,381.15 16.7623,508.50Clearance Factor Pass - MPL-36 - MPL-36PB1 - MPL-36PB1364.36 2,383.50 343.31 2,307.29 17.3072,383.50Ellipse Separation Pass - MPL-36 - MPL-36PB1 - MPL-36PB1364.35 2,388.90 343.33 2,313.00 17.3302,388.90Centre Distance Pass - MPL-36 - MPL-36PB1 - MPL-36PB1675.24 3,508.50 634.95 3,381.15 16.7623,508.50Clearance Factor Pass - MPL-37 - MPL-37 - MPL-37486.21 4,015.72 452.68 4,018.64 14.4994,015.72Centre Distance Pass - MPL-37 - MPL-37 - MPL-37487.19 4,058.50 451.60 4,046.45 13.6874,058.50Ellipse Separation Pass - MPL-37 - MPL-37 - MPL-37603.86 4,558.50 544.59 4,423.05 10.1884,558.50Clearance Factor Pass - MPL-37 - MPL-37A - MPL-37A486.21 4,015.72 452.68 4,027.84 14.4994,015.72Centre Distance Pass - MPL-37 - MPL-37A - MPL-37A487.19 4,058.50 451.59 4,055.65 13.6864,058.50Ellipse Separation Pass - MPL-37 - MPL-37A - MPL-37A603.86 4,558.50 544.59 4,432.25 10.1884,558.50Clearance Factor Pass - MPL-39 - MPL-39 - MPL-39121.80 2,058.50 103.21 1,939.68 6.5502,058.50Clearance Factor Pass - MPL-39 - MPL-39 - MPL-39120.21 2,091.88 101.96 1,967.54 6.5892,091.88Ellipse Separation Pass - MPL-40 - MPL-40 - MPL-40209.22 2,183.50 189.61 2,055.57 10.6722,183.50Clearance Factor Pass - MPL-40 - MPL-40 - MPL-40208.43 2,207.10 188.93 2,072.09 10.6882,207.10Ellipse Separation Pass - MPL-43 - MPL-43 - MPL-43237.12 33.50 235.71 35.10 167.66333.50Centre Distance Pass - MPL-43 - MPL-43 - MPL-43237.48 258.50 234.80 258.57 88.491258.50Ellipse Separation Pass - MPL-43 - MPL-43 - MPL-43325.33 958.50 318.42 919.35 47.068958.50Clearance Factor Pass - MPL-43 - MPL-43PB1 - MPL-43PB1237.12 33.50 235.71 35.10 167.66333.50Centre Distance Pass - MPL-43 - MPL-43PB1 - MPL-43PB1237.48 258.50 234.80 258.57 88.491258.50Ellipse Separation Pass - MPL-43 - MPL-43PB1 - MPL-43PB1325.33 958.50 318.42 919.35 47.068958.50Clearance Factor Pass - MPL-45 - MPL-45 - MPL-45166.566,468.70-35.686,669.970.8246,468.70Centre DistanceFAIL - MPL-45 - MPL-45 - MPL-45177.206,833.50-51.297,035.980.7766,833.50Clearance FactorFAIL - MPL-45 - MPL-45 - MPL-45178.296,858.50-51.337,060.230.7766,858.50Ellipse SeparationFAIL - MPL-46 - MPL-46 - MPL-46684.15 33.50 682.73 31.75 482.04333.50Centre Distance Pass - MPL-46 - MPL-46 - MPL-46684.56 283.50 680.92 276.60 188.462283.50Ellipse Separation Pass - 03 June, 2020-14:48COMPASSPage 4 of 9see collision notes:
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU L-59i - MPU L-59i wp09Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 33.50 to 6,867.83 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt L Pad - Plan: MPU L-59i - MPU L-59i - MPU L-59i wp09MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPL-46 - MPL-46 - MPL-46850.90 6,133.50 784.87 6,959.19 12.8876,133.50Clearance Factor Pass - MPL-46 - MPL-46 PB1 - MPL-46 PB1684.15 33.50 682.73 31.75 482.04333.50Centre Distance Pass - MPL-46 - MPL-46 PB1 - MPL-46 PB1684.56 283.50 680.92 276.60 188.462283.50Ellipse Separation Pass - MPL-46 - MPL-46 PB1 - MPL-46 PB1850.90 6,133.50 784.70 6,959.19 12.8536,133.50Clearance Factor Pass - MPL-47 - MPL-47 - MPL-4786.20 3,008.50 54.88 2,952.76 2.7523,008.50Clearance Factor Pass - MPL-47 - MPL-47 - MPL-4776.38 3,058.50 50.39 2,997.12 2.9383,058.50Ellipse Separation Pass - MPL-47 - MPL-47 - MPL-4772.63 3,110.49 52.06 3,043.26 3.5313,110.49Centre Distance Pass - MPL-47 - MPL-47 PB1 - MPL-47 PB186.20 3,008.50 54.88 2,952.76 2.7523,008.50Clearance Factor Pass - MPL-47 - MPL-47 PB1 - MPL-47 PB176.38 3,058.50 50.39 2,997.12 2.9383,058.50Ellipse Separation Pass - MPL-47 - MPL-47 PB1 - MPL-47 PB172.63 3,110.49 52.06 3,043.26 3.5313,110.49Centre Distance Pass - MPL-48 - MPL-48 - MPL-48208.65 3,130.99 190.96 3,096.33 11.7983,130.99Centre Distance Pass - MPL-48 - MPL-48 - MPL-48208.65 3,133.50 190.96 3,098.30 11.7933,133.50Ellipse Separation Pass - MPL-48 - MPL-48 - MPL-48283.18 6,608.50 217.41 7,523.22 4.3066,608.50Clearance Factor Pass - MPL-48 - MPL-48PB1 - MPL-48PB1137.62 3,158.50 118.04 3,105.30 7.0293,158.50Ellipse Separation Pass - MPL-48 - MPL-48PB1 - MPL-48PB1137.60 3,162.39 118.07 3,108.55 7.0453,162.39Centre Distance Pass - MPL-48 - MPL-48PB1 - MPL-48PB1181.20 3,358.50 149.17 3,264.74 5.6583,358.50Clearance Factor Pass - MPL-48 - MPL-48PB2 - MPL-48PB2137.62 3,158.50 118.04 3,105.30 7.0293,158.50Ellipse Separation Pass - MPL-48 - MPL-48PB2 - MPL-48PB2137.60 3,162.39 118.07 3,108.55 7.0453,162.39Centre Distance Pass - MPL-48 - MPL-48PB2 - MPL-48PB2181.20 3,358.50 149.17 3,264.74 5.6583,358.50Clearance Factor Pass - MPL-48 - MPL-48PB3 - MPL-48 PB3208.65 3,130.99 190.96 3,096.33 11.7983,130.99Centre Distance Pass - MPL-48 - MPL-48PB3 - MPL-48 PB3208.65 3,133.50 190.96 3,098.30 11.7933,133.50Ellipse Separation Pass - MPL-48 - MPL-48PB3 - MPL-48 PB3283.18 6,608.50 217.24 7,523.22 4.2956,608.50Clearance Factor Pass - MPL-50 - MPL-50 - MPL-50436.45 3,208.50 416.80 2,856.42 22.2073,208.50Ellipse Separation Pass - MPL-50 - MPL-50 - MPL-50436.40 3,220.93 416.82 2,867.89 22.2913,220.93Centre Distance Pass - MPL-50 - MPL-50 - MPL-50816.09 4,633.50 754.73 4,105.20 13.2994,633.50Clearance Factor Pass - MPU L-41 - MPU L-41 - MPU L-41209.08 801.58 203.98 803.08 40.970801.58Centre Distance Pass - MPU L-41 - MPU L-41 - MPU L-41209.10 808.50 203.96 809.50 40.646808.50Ellipse Separation Pass - MPU L-41 - MPU L-41 - MPU L-41220.24 958.50 214.37 943.96 37.505958.50Clearance Factor Pass - MPU L-41 - MPU L-41PB1 - MPU L-41PB1209.08 801.58 203.98 803.08 40.970801.58Centre Distance Pass - MPU L-41 - MPU L-41PB1 - MPU L-41PB1209.10 808.50 203.96 809.50 40.646808.50Ellipse Separation Pass - MPU L-41 - MPU L-41PB1 - MPU L-41PB1220.24 958.50 214.37 943.96 37.505958.50Clearance Factor Pass - 03 June, 2020-14:48COMPASSPage 5 of 9
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU L-59i - MPU L-59i wp09Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 33.50 to 6,867.83 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt L Pad - Plan: MPU L-59i - MPU L-59i - MPU L-59i wp09MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPU L-51 - MPU L-51 - MPU L-5142.20 655.02 37.86 645.58 9.731655.02Centre Distance Pass - MPU L-51 - MPU L-51 - MPU L-5142.20 658.50 37.84 648.99 9.687658.50Ellipse Separation Pass - MPU L-51 - MPU L-51 - MPU L-5143.66 733.50 38.89 721.66 9.143733.50Clearance Factor Pass - MPU L-52 - MPU L-52 - MPU L-5229.88 33.50 28.47 27.30 21.16633.50Ellipse Separation Pass - MPU L-52 - MPU L-52 - MPU L-5234.12 783.50 29.27 778.30 7.035783.50Clearance Factor Pass - MPU L-53 - MPU L-53 - MPU L-5314.91 200.23 12.67 192.63 6.647200.23Centre Distance Pass - MPU L-53 - MPU L-53 - MPU L-5315.11 283.50 12.35 275.83 5.475283.50Ellipse Separation Pass - MPU L-53 - MPU L-53 - MPU L-5322.58 583.50 17.86 573.75 4.778583.50Clearance Factor Pass - MPU L-54 - MPU L-54 - MPU L-5465.34 3,133.50 44.08 3,203.14 3.0733,133.50Ellipse Separation Pass - MPU L-54 - MPU L-54 - MPU L-5463.72 3,188.96 45.16 3,256.32 3.4333,188.96Centre Distance Pass - MPU L-54 - MPU L-54 - MPU L-5496.48 3,483.50 58.90 3,540.31 2.5673,483.50Clearance Factor Pass - MPU L-56 - MPU L-56 - MPU L-5685.93 842.12 76.88 871.55 9.495842.12Ellipse Separation Pass - MPU L-56 - MPU L-56 - MPU L-5689.63 983.50 79.86 1,018.61 9.179983.50Clearance Factor Pass - MPU L-57 - MPU L-57 - MPU L-57113.78 33.50 112.37 34.00 80.60033.50Centre Distance Pass - MPU L-57 - MPU L-57 - MPU L-57114.31 283.50 112.00 283.10 49.510283.50Ellipse Separation Pass - MPU L-57 - MPU L-57 - MPU L-57208.21 1,708.50 192.47 1,799.75 13.2351,708.50Clearance Factor Pass - MPU L-57 - MPU L-57PB1 - MPU L-57PB1113.78 33.50 112.37 34.00 80.60033.50Centre Distance Pass - MPU L-57 - MPU L-57PB1 - MPU L-57PB1114.31 283.50 112.00 283.10 49.510283.50Ellipse Separation Pass - MPU L-57 - MPU L-57PB1 - MPU L-57PB1208.21 1,708.50 192.47 1,799.75 13.2351,708.50Clearance Factor Pass - Plan: MPU L-58 - MPU L-58 - MPU L-58 wp05238.00 647.17 229.86 647.88 29.256647.17Centre Distance Pass - Plan: MPU L-58 - MPU L-58 - MPU L-58 wp05238.03 658.50 229.76 658.53 28.796658.50Ellipse Separation Pass - Plan: MPU L-58 - MPU L-58 - MPU L-58 wp05255.01 858.50 244.65 834.64 24.601858.50Clearance Factor Pass - Plan: MPU L-61i - MPU L-61i - MPU L-61i wp06 - AC n198.99 308.50 196.32 308.20 74.508308.50Centre Distance Pass - Plan: MPU L-61i - MPU L-61i - MPU L-61i wp06 - AC n199.06 358.50 196.16 358.20 68.810358.50Ellipse Separation Pass - Plan: MPU L-61i - MPU L-61i - MPU L-61i wp06 - AC n1,560.77 6,867.83 1,417.26 7,518.02 10.8766,867.83Clearance Factor Pass - Rig: MPU L-60 - MPU L-60 - MPU L-60 wp09655.52 260.79 653.03 261.89 263.355260.79Centre Distance Pass - Rig: MPU L-60 - MPU L-60 - MPU L-60 wp09655.52 283.50 652.94 283.53 253.848283.50Ellipse Separation Pass - Rig: MPU L-60 - MPU L-60 - MPU L-60 wp09793.85 6,867.83 662.26 6,384.23 6.0326,867.83Clearance Factor Pass - 03 June, 2020-14:48COMPASSPage 6 of 9
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU L-59i - MPU L-59i wp09Survey tool programFrom(usft)To(usft)Survey/Plan Survey Tool33.50 1,000.00 MPU L-59i wp09 3_Gyro-GC_Csg1,000.00 6,867.83 MPU L-59i wp09 3_MWD+IFR2+MS+Sag6,867.83 13,606.75 MPU L-59i wp09 3_MWD+IFR2+MS+SagEllipse error terms are correlated across survey tool tie-on points.Separation is the actual distance between ellipsoids.Calculated ellipses incorporate surface errors.Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation).Distance Between centres is the straight line distance between wellbore centres.All station coordinates were calculated using the Minimum Curvature method.03 June, 2020-14:48COMPASSPage 7 of 9
0.001.002.003.004.00Separation Factor0 350 700 1050 1400 1750 2100 2450 2800 3150 3500 3850 4200 4550 4900 5250 5600 5950 6300 6650Measured Depth (700 usft/in)MPL-45MPL-47MPL-47 PB1MPU L-54No-Go Zone - Stop DrillingCollision Avoidance Req.Collision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: MPU L-59i NAD 1927 (NADCON CONUS)Alaska Zone 0415.50+N/-S +E/-W Northing Easting Latittude Longitude0.000.00 6031945.12544633.1570° 29' 53.330 N149° 38' 5.984 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU L-59i, True NorthVertical (TVD) Reference:MPU L-59i as-built rkb @ 49.20usftMeasured Depth Reference:MPU L-59i as-built rkb @ 49.20usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2020-05-06T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.50 1000.00 MPU L-59i wp09 (MPU L-59i) 3_Gyro-GC_Csg1000.00 6867.83 MPU L-59i wp09 (MPU L-59i) 3_MWD+IFR2+MS+Sag6867.83 13606.75 MPU L-59i wp09 (MPU L-59i) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 350 700 1050 1400 1750 2100 2450 2800 3150 3500 3850 4200 4550 4900 5250 5600 5950 6300 6650Measured Depth (700 usft/in)MPL-28MPL-32MPU L-51MPU L-52MPU L-53NO GLOBAL FILTER: Using user defined selection & filtering criteria33.50 To 13606.75Project: Milne PointSite: M Pt L PadWell: Plan: MPU L-59iWellbore: MPU L-59iPlan: MPU L-59i wp09Ladder / S.F. Plots1 of 2CASING DETAILSTVD TVDSS MD Size Name3959.20 3910.00 6867.83 9-5/8 9 5/8" x 12 1/4"3774.20 3725.00 13606.75 6-5/8 6 5/8" x 8 1/2"
03 June, 2020Milne PointM Pt L PadPlan: MPU L-59iMPU L-59iMPU L-59i wp09Reference Design: M Pt L Pad - Plan: MPU L-59i - MPU L-59i - MPU L-59i wp09Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Well Coordinates: 6,031,945.12 N, 544,633.15 E (70° 29' 53.33" N, 149° 38' 05.98" W)Datum Height: MPU L-59i as-built rkb @ 49.20usftScan Range: 6,867.83 to 13,606.75 usft. Measured Depth.Geodetic Scale Factor AppliedVersion: 5000.15 Build: 91EScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftNO GLOBAL FILTER: Using user defined selection & filtering criteriaScan Type:Scan Type:25.006800 to 13600 ft md
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU L-59i - MPU L-59i wp09Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 6,867.83 to 13,606.75 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt L Pad - Plan: MPU L-59i - MPU L-59i - MPU L-59i wp09MeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt L PadMPL-45 - MPL-45 - MPL-45178.746,867.83-51.267,069.280.7776,867.83Clearance FactorFAIL - MPL-46 - MPL-46 - MPL-461,401.08 6,867.83 1,321.88 7,322.27 17.6926,867.83Clearance Factor Pass - MPL-46 - MPL-46 PB1 - MPL-46 PB11,401.08 6,867.83 1,321.71 7,322.27 17.6546,867.83Clearance Factor Pass - MPL-47 - MPL-47 - MPL-47168.50 7,483.65 122.05 8,219.23 3.6287,483.65Centre Distance Pass - MPL-47 - MPL-47 - MPL-47168.70 7,492.83 121.79 8,223.47 3.5967,492.83Ellipse Separation Pass - MPL-47 - MPL-47 - MPL-47194.28 7,592.83 134.20 8,270.85 3.2347,592.83Clearance Factor Pass - MPL-47 - MPL-47 PB1 - MPL-47 PB1168.50 7,483.65 121.88 8,219.23 3.6147,483.65Centre Distance Pass - MPL-47 - MPL-47 PB1 - MPL-47 PB1168.70 7,492.83 121.62 8,223.47 3.5837,492.83Ellipse Separation Pass - MPL-47 - MPL-47 PB1 - MPL-47 PB1194.28 7,592.83 134.03 8,270.85 3.2257,592.83Clearance Factor Pass - MPL-48 - MPL-48 - MPL-48447.93 6,867.83 367.76 7,647.56 5.5876,867.83Clearance Factor Pass - MPL-48 - MPL-48PB1 - MPL-48PB11,476.15 6,867.83 1,379.41 6,232.00 15.2586,867.83Clearance Factor Pass - MPL-48 - MPL-48PB2 - MPL-48PB21,142.48 6,867.83 1,051.52 6,627.00 12.5606,867.83Clearance Factor Pass - MPL-48 - MPL-48PB2 - MPL-48PB21,142.48 6,867.83 1,051.52 6,627.00 12.5606,867.83Ellipse Separation Pass - MPL-48 - MPL-48PB3 - MPL-48 PB3447.93 6,867.83 367.59 7,647.56 5.5756,867.83Clearance Factor Pass - MPL-50 - MPL-50 - MPL-50183.55 8,701.64 130.69 9,405.32 3.4728,701.64Centre Distance Pass - MPL-50 - MPL-50 - MPL-50184.13 8,717.83 130.19 9,412.36 3.4148,717.83Ellipse Separation Pass - MPL-50 - MPL-50 - MPL-50211.15 8,817.83 143.81 9,457.87 3.1358,817.83Clearance Factor Pass - MPU L-54 - MPU L-54 - MPU L-54743.24 12,577.44 510.07 12,644.74 3.18812,577.44Centre Distance Pass - MPU L-54 - MPU L-54 - MPU L-54750.75 13,442.83 495.43 13,500.00 2.94013,442.83Clearance Factor Pass - Plan: MPU L-61i - MPU L-61i - MPU L-61i wp06 - AC n1,516.21 13,606.75 1,256.56 14,258.68 5.83913,606.75Clearance Factor Pass - Rig: MPU L-60 - MPU L-60 - MPU L-60 wp09728.93 12,240.99 508.34 11,757.68 3.30512,240.99Centre Distance Pass - Rig: MPU L-60 - MPU L-60 - MPU L-60 wp09729.90 12,317.83 507.50 11,816.10 3.28212,317.83Ellipse Separation Pass - Rig: MPU L-60 - MPU L-60 - MPU L-60 wp09771.16 13,606.75 519.24 13,099.38 3.06113,606.75Clearance Factor Pass - M Pt Moose PadMPU M-10 - MPU M-10 - MPU M-10219.46 9,492.83 81.40 12,675.01 1.5909,492.83Clearance Factor Pass - MPU M-10 - MPU M-10 - MPU M-10205.33 9,517.83 78.77 12,683.16 1.6229,517.83Ellipse Separation Pass - MPU M-10 - MPU M-10 - MPU M-10169.81 9,640.31 113.51 12,723.81 3.0169,640.31Centre Distance Pass - 03 June, 2020-14:49COMPASSPage 2 of 6see collision notes:
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU L-59i - MPU L-59i wp09Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 6,867.83 to 13,606.75 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt L Pad - Plan: MPU L-59i - MPU L-59i - MPU L-59i wp09MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPU M-10 - MPU M-10PB1 - MPU M-10PB1242.479,467.8376.8712,630.001.4649,467.83Clearance FactorPass - MPU M-10 - MPU M-10PB1 - MPU M-10PB1229.629,492.8374.1212,630.001.4779,492.83Ellipse SeparationPass - MPU M-10 - MPU M-10PB1 - MPU M-10PB1202.16 9,601.72 106.02 12,630.00 2.1039,601.72Centre Distance Pass - MPU M-10 - MPU M-10PB2 - MPU M-10PB2275.15 9,442.83 122.54 12,627.98 1.8039,442.83Clearance Factor Pass - MPU M-10 - MPU M-10PB2 - MPU M-10PB2249.02 9,492.83 116.74 12,649.97 1.8839,492.83Ellipse Separation Pass - MPU M-10 - MPU M-10PB2 - MPU M-10PB2213.23 9,634.00 152.90 12,709.96 3.5349,634.00Centre Distance Pass - MPU M-10 - MPU M-10PB3 - MPU M-10PB3221.71 9,492.83 92.29 12,667.56 1.7139,492.83Ellipse Separation Pass - MPU M-10 - MPU M-10PB3 - MPU M-10PB3185.08 9,626.51 127.15 12,722.66 3.1959,626.51Centre Distance Pass - MPU M-10 - MPU M-10PB3 - MPU M-10PB3255.42 9,817.83 100.81 12,795.12 1.6529,817.83Clearance Factor Pass - MPU M-11 - MPU M-11 - MPU M-11206.6310,342.8325.2713,212.221.13910,342.83Clearance FactorPass - MPU M-11 - MPU M-11 - MPU M-11155.73 10,491.53 88.33 13,272.90 2.31110,491.53Centre Distance Pass - MPU M-12 - MPU M-12 - MPU M-12192.8111,267.832.1013,810.831.01111,267.83Clearance FactorPass - MPU M-12 - MPU M-12 - MPU M-12147.46 11,400.72 73.63 13,858.68 1.99711,400.72Centre Distance Pass - MPU M-12 - MPU M-12PB2 - MPU M-12PB2192.8111,267.831.9713,810.831.01011,267.83Clearance FactorPass - MPU M-12 - MPU M-12PB2 - MPU M-12PB2147.46 11,400.72 73.51 13,858.68 1.99411,400.72Centre Distance Pass - MPU M-13 - MPU M-13i - MPU M-13203.3412,167.8311.1713,507.511.05812,167.83Clearance FactorPass - MPU M-13 - MPU M-13i - MPU M-13156.93 12,309.28 81.97 13,564.96 2.09412,309.28Centre Distance Pass - MPU M-14 - MPU M-14 - MPU M-14206.0413,042.831.3813,865.401.00713,042.83Clearance FactorPass - MPU M-14 - MPU M-14 - MPU M-14156.52 13,188.47 76.38 13,921.54 1.95313,188.47Centre Distance Pass - MPU M-15i - MPU M-15 - MPU M-15i463.48 13,606.75 209.84 13,984.49 1.82713,606.75Clearance Factor Pass - MPU M-16 - MPU M-16 - MPU M-161,253.31 13,606.75 985.50 14,100.14 4.68013,606.75Clearance Factor Pass - 03 June, 2020-14:49COMPASSPage 3 of 6
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU L-59i - MPU L-59i wp09Survey tool programFrom(usft)To(usft)Survey/Plan Survey Tool33.50 1,000.00 MPU L-59i wp09 3_Gyro-GC_Csg1,000.00 6,867.83 MPU L-59i wp09 3_MWD+IFR2+MS+Sag6,867.83 13,606.75 MPU L-59i wp09 3_MWD+IFR2+MS+SagEllipse error terms are correlated across survey tool tie-on points.Separation is the actual distance between ellipsoids.Calculated ellipses incorporate surface errors.Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation).Distance Between centres is the straight line distance between wellbore centres.All station coordinates were calculated using the Minimum Curvature method.03 June, 2020-14:49COMPASSPage 4 of 6
0.001.002.003.004.00Separation Factor6750 7125 7500 7875 8250 8625 9000 9375 9750 10125 10500 10875 11250 11625 12000 12375 12750 13125 13500Measured Depth (750 usft/in)MPL-45MPU M-10MPU M-10PB1No-Go Zone - Stop DrillingCollision Avoidance Req.Collision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: MPU L-59i NAD 1927 (NADCON CONUS)Alaska Zone 0415.50+N/-S +E/-W Northing Easting Latittude Longitude0.000.006031945.12544633.1570° 29' 53.330 N 149° 38' 5.984 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU L-59i, True NorthVertical (TVD) Reference:MPU L-59i as-built rkb @ 49.20usftMeasured Depth Reference:MPU L-59i as-built rkb @ 49.20usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2020-05-06T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.50 1000.00 MPU L-59i wp09 (MPU L-59i) 3_Gyro-GC_Csg1000.00 6867.83 MPU L-59i wp09 (MPU L-59i) 3_MWD+IFR2+MS+Sag6867.83 13606.75 MPU L-59i wp09 (MPU L-59i) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)6750 7125 7500 7875 8250 8625 9000 9375 9750 10125 10500 10875 11250 11625 12000 12375 12750 13125 13500Measured Depth (750 usft/in)MPL-47NO GLOBAL FILTER: Using user defined selection & filtering criteria33.50 To 13606.75Project: Milne PointSite: M Pt L PadWell: Plan: MPU L-59iWellbore: MPU L-59iPlan: MPU L-59i wp09Ladder / S.F. Plots2 of 2CASING DETAILSTVD TVDSS MD Size Name3959.20 3910.00 6867.83 9-5/8 9 5/8" x 12 1/4"3774.20 3725.00 13606.75 6-5/8 6 5/8" x 8 1/2"L-45
WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:MILNE PT UNIT L-59Initial Class/TypeSER / PENDGeoArea890Unit11328On/Off ShoreOnProgramSERField & PoolWell bore segAnnular DisposalPTD#:2200500MILNE POINT, SCHRADER BLFF OIL - 525140NA1 Permit fee attachedYes Surface location in ADL0025509; top prod interval and TD in ADL00255152 Lease number appropriateYes3 Unique well name and numberYes Milne Point Schrader Bluff Oil Pool (525140), governed by CO 477, amended by CO 477.05.4 Well located in a defined poolYes CO 477.05 specifies: “There are no restrictions as to well spacing except that no pay shall5 Well located proper distance from drilling unit boundaryYes be opened in a well closer than 500 feet from the exterior boundary of the affected area.”6 Well located proper distance from other wellsYes As planned, well conforms to spacing requirements.7 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) (For Yes15 All wells within 1/4 mile area of review identified (For service well only)No16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes 20" Conductor has been preset.18 Conductor string providedNA No aquifers in area19 Surface casing protects all known USDWsYes 9 5/8" caisng will be fully cemented. ES tool at 2500 ft for 2 stage20 CMT vol adequate to circulate on conductor & surf csgNA lateral will be swellpacker with ICD. No cement21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes BTC calc provided.23 Casing designs adequate for C, T, B & permafrostYes Rig has steel pits. All waste to approved disposal well.24 Adequate tankage or reserve pitNA grass roots well25 If a re-drill, has a 10-403 for abandonment been approvedYes L-45 has close crossing but is P & A'd26 Adequate wellbore separation proposedYes Map of diverter layout is provided.27 If diverter required, does it meet regulationsYes Max form pressure = 1800 psi will drill with 8.9 - 9.5 ppg mud28 Drilling fluid program schematic & equip list adequateYes Doyon 14 had 13 5/8" 5000 psi WP BOPE29 BOPEs, do they meet regulationYes MASP = 1300 psi will test BOPE to 3000 psi ( 2500 psi annular test )30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo H2S not expected .33 Is presence of H2S gas probableYes AOR table provided.. No issues with offset wells.34 Mechanical condition of wells within AOR verified (For service well only)Yes None observed in offset wells. Rig will have functioning, automatic detectors.35 Permit can be issued w/o hydrogen sulfide measuresYes Hydrates or geo-pressure not expected from drilling of offset wells.36 Data presented on potential overpressure zonesNA Planned mud program appears adequate to control operator's forecast formation pressures.37 Seismic analysis of shallow gas zonesNA Managed Pressure Drilling will be used to monitor and mitigate any abnormal pressure encountered.38 Seabed condition survey (if off-shore)NA Other mitigation measures are discussed in drilling hazards section on pages 44-46.39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate6/5/2020Appr DateApprSFDDate6/5/2020AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJMP6/9/2020dts 6/9/2020JLC 6/9/2020
