Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAbout219-087MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE:Friday, November 24, 2023
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Guy Cook
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
Hilcorp Alaska, LLC
M-13
MILNE PT UNIT M-13
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 11/24/2023
M-13
50-029-23638-00-00
219-087-0
W
SPT
3884
2190870 1500
686 686 689 689
4YRTST P
Guy Cook
10/10/2023
Testing completed with a Little Red Services pump truck and calibrated gauges. Mono-bore
30 MinPretestInitial15 Min
Well Name
Type Test
Notes:
Interval P/F
Well
Permit Number:
Type Inj TVD
PTD Test psi
API Well Number Inspector Name:MILNE PT UNIT M-13
Inspection Date:
Tubing
OA
Packer Depth
319 1704 1637 1616IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitGDC231009152346
BBL Pumped:1.6 BBL Returned:1.6
Friday, November 24, 2023 Page 1 of 1
Hilcorp Alaska, LLC Post Office Box 244027
Anchorage, AK 99524-4027
3800 Centerpoint Drive
Suite 1400
Anchorage, AK 99503
Phone: 907/777-8547
September 29, 2023
Mr. Mel Rixse
Alaska Oil and Gas Conservation Commission
333 West 7th Avenue, Suite 100
Anchorage, Alaska 99501
Re: Milne Point Conductor Annulus Corrosion Inhibitor Treatments 6/9 to 9/27/2023
Dear Mr. Rixse,
Enclosed please a copy of a spreadsheet with a list of thirteen Milne Point wells that were treated
with corrosion inhibiting casing filler in the surface casing by conductor annulus. The heavier than
water “grease-like” filler displaces water to prevent external casing corrosion that could result in
a surface casing leak. The attached spreadsheets include the well names, field, API and PTD
numbers, treatment dates and volumes.
If you have any additional questions, please contact me at 907-777-8406 or
dhorner@hilcorp.com.
Sincerely,
Darci Horner
Regulatory Tech
Hilcorp Alaska, LLC
Digitally signed by Darci Horner
(c-100048)
DN: cn=Darci Horner (c-100048)
Date: 2023.09.29 09:45:20 -
08'00'
Darci Horner
(c-100048)
Well Field API PTD
Initial Top
of Cement
(ft.)
Volume of
Cement
Pumped
(bbls)
Final Top of
Cement (ft.)
Cement
Pump Date
Corrosion
Inhibitor
Fill Volume
(gal)
Final CI Top
(ft.)
Corrosion
Inhibitor
Treatment
Date
Comments
MPB-35 MPU 50029237240000 2220850 14' 0 14' N/A 50 surface 9/27/2023 Drilled Sept/Oct 2022.
MPB-39 MPU 50029237470000 2230120 1'6" 0 1'6" N/A 10 surface 6/10/2023 Drilled Mar 2023.
MPI-20 MPU 50029236790000 2200490 10' 1 1 7/2/2023 5 surface 9/27/2023 Completed Apr 8, 2021.
MPI-29 MPU 50029237080000 2220060 6' 0.5 3 7/2/2023 15 surfce 9/27/2023
Drilled in March 2022. Completeted
on 4/30/22.
MPL-60 MPU 50029236780000 2200480 1' 0 1' N/A 10 surface 6/26/2023 Drilled in 2020.
MPL-62 MPU 50029236850000 2200590 1' 0 1' N/A 10 surface 6/26/2023 Drilled in 2020.
MPM-13 MPU 50029236380000 2190870 20' 3.5 2' 8/2/2023 10 surface 9/27/2023 Drilled in 2019.
MPM-27 MPU 50029237160000 2220490 2' 0 2' N/A 20 surface 6/11/2023 Monobore. Drilled June 2022.
MPM-30 MPU 50029237300000 2221180 1' 0 1' N/A 10 surface 6/11/2023 Drilled in Oct 2022.
MPM-43 MPU 50029236710000 2200200 1' 0 1' N/A 10 surface 6/11/2023 Drilled in 2020.
MPM-62 MPU 50029237440000 2230060 1' 0 1' N/A 10 surface 6/11/2023 Completed May 2023.
MPS-45 MPU 50029236930000 2210420 1' 0 1' N/A 10 surface 6/12/2023 Drilled in June 2021.
MPS-47 MPU 50029236960000 2210470 4' 0 4' N/A 20 surface 6/12/2023 Drilled in August 2021.
Notes:
The 4" conductor outlets are any where from 1 to 3' down from the top of the conductor
Surface Casing by Conductor Annulus Cement Top Job and Fill Coat Corrosion Inhibitor (CI) Applications
Cement to surface means cement is up to the 4" outlets below the wellhead. From the 4" outlets up to the top of conductor was filled with Fill Coat #7
Initial top of cement footage measurement was taken from the 4" outlet down to the TOC
RBDMS JSB 100323
MPM-13 MPU 50029236380000 2190870 20'3.5 2'8/2/2023 10 surface 9/27/2023 Drilled in 2019.
DATA SUBMITTAL COMPLIANCE REPORT
11/12/2019
Permit to Drill 2190870 Well Name/No. MILNE PT UNIT M-13
MD 16300 TVD 4035
REQUIRED INFORMATION
Operator Hilcorp Alaska LLC
Completion Date 8/4/2019 Completion Status 1WINJ
Mud Log No
Samples No
DATA INFORMATION
List of Logs Obtained: ROP/ABG/DGR/EWR/ADR 2"/5" MID ... ABG/DGR/EWR/ADR 2"/5' TVD
Well Log Information:
Log/ Electr
Data Digital Dataset Log Log Run Interval OH I
Type Med/Frmt Number Name Scale Media No Start Stop CH
ED C 31169 Digital Data 105 16300
ED C 31169 Digital Data
ED C 31169 Digital Data
ED C 31169 Digital Data
ED C 31169 Digital Data
ED
C
31169 Digital Data
ED
C
31169 Digital Data
ED
C
31169 Digital Data
ED
C
31169 Digital Data
ED
C
31169 Digital Data
ED
C
31169 Digital Data
ED
C
31169 Digital Data
ED
C
31169 Digital Data
ED
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31169 Digital Data
ED
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31169 Digital Data
ED
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31169 Digital Data
ED
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31169 Digital Data
ED
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31169 Digital Data
ED
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31169 Digital Data
4917 16262
API No. 50-029-23638-00-00
Current Status 1WINJ UIC Yes
Directional Survey Yes Z
(from Master Well Data/Logs)
Received Comments
9/3/2019 Electronic Data Set, Filename: MPU M-13 LWD
AOGCC Page 1 oft Tuesday, November 12, 2019
Final.las
9/3/2019
Electronic Data Set, Filename: MPU M-13 ADR
Quadrants All Curves.las
9/3/2019
Electronic File: MPU M-13 LWD Final MD.ogm
9/3/2019
Electronic File: MPU M-13 LWD Final TVD.cgm
9/3/2019
Electronic File: MPU M-13—Definitive Survey
Report.pdf
9/3/2019
Electronic File: MPU M-13—Definitive Survey.txt
9/3/2019
Electronic File: MPU M-13_GIS.bd
9/3/2019
Electronic File: MPU M-13_Plan.pdf
9/3/2019
Electronic File: MPU M-13_VSec.pdf
9/3/2019
Electronic File: MPU M-13 LWD Final MD.emf
9/3/2019
Electronic File: MPU M-13 LWD Final TVD.emf
9/3/2019
Electronic File: MPU M-13 Geosteedng.dlis
9/3/2019
Electronic File: MPU M-13 Geosteering.ver
9/3/2019
Electronic File: MPU M-13 LWD Final MD.pdf
9/3/2019
Electronic File: MPU M-13 LWD Final TVD.pdf
9/3/2019
Electronic File: MPU M-13 LWD Final MD.tif
9/3/2019
Electronic File: MPU M-13 LWD Final TVD.tif
9/3/2019
Electronic File: EMFView3_1.zip
9/3/2019
Electronic File: Readme.txl
AOGCC Page 1 oft Tuesday, November 12, 2019
DATA SUBMITTAL COMPLIANCE REPORT
11/12/2019
Permit to Drill 2190870 Well NamelNo. MILNE PT UNIT M-13 Operator Hilcorp Alaska LLC API No. 50.029.23638-00-00
MD 16300 TVD 4035 Completion Date 8/4/2019 Completion Status 1WINJ Current Status 1WINJ UIC Yes
Log 31169 Log Header Scans 0 0 2190870 MILNE PT UNIT M-13 LOG HEADERS
Well Cores/Samples Information:
Sample
Interval Set
Name Start Stop Sent Received Number Comments
INFORMATION RECEIVED
Completion Report YD
Production Test Information Y /(9
Geologic Markers/Tops (D
COMPLIANCE HISTORY
Completion Date: 8/4/2019
Release Date: 6/12/2019
Description
Comments:
Directional / Inclination Data 0 Mud Logs, Image Files, Digital Data /Y 16) Core Chips Y /&)
Mechanical Integrity Test Information Y / NA Composite Logs, Image, Data Files Core Photographs Y /C)
Daily Operations Summary V Cuttings Samples Y & Laboratory Analyses Y / NA l
Date Comments
Compliance Reviewed By: 1 ' V Date:
A0(iCC Page 2 of 2 'Tuesday, November 12, 2019
MEMORANDUM
TO: Jim Regg
P.I. Supervisor
I IOf74(lti
FROM: Lou Laubenstein
Petroleum Inspector
State of Alaska
Alaska Oil and Gas Conservation Commission
DATE: Monday, October 21, 2019
SUBJECT: Mechanical Integrity Tests
Hilcoip Alaska LLC
M-13
MILNE PT UNIT M-13
Src: Inspector
Reviewed By:
P.I. Supry
NON -CONFIDENTIAL Comm
Well Name MILNE PT UNIT M-13 API Well Number 50-029-23635-00-00 Inspector Name: Lou Laubenstein
Permit Number: 219-087-0 Inspection Date: 10/17/2019
Insp Num: mitLOL191017163619
Rel Insp Num:
Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min
M-13 Type Inj W ;TVD 3884 Tubing) 489 ago 489 71 490
2190870 Tvpe Test SPT Test psi 1500 IA 116 1655 - 1577 - 1555
Pumped: 2 BBL Returned: 2.2 OA
vaI INITAL PIF P --
Notes:
Monday, October 21, 2019 Page I of I
H
F{]Irnrp AlnvAa. LLf.
DATE: 8/30/2019
Deb. _ Judean Hilcorp Alaska, LLC
GeoTech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: 907 777-8337
Fax: 907 777-8510
E-mail: doudean@hilcorp.com
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Ste 100
Anchorage, AK 99501
tMPU
TRANSMITTA,, M-1.4 PTD 219-087
CD: HALLIBURTON 30 Jul 2019
M-13 DGR ABG EWR ADR Wellbore Profile MD & TVD
_Log Viewers
8./30/201910:39 AM
CGM
8130/201910:41 AM
Definitive Survey
8130/201910:41 AM
EMF
8./301201910:41 AM
LAS
81301201910:41 AM
PDF
8/30/201910:41 AM
TIFF
8/30/201910:41 AM
RECEIVED
SEP 0 3 2019
AOGCC
File folder
File folder
File folder
File folder
File folder
File folder
File folder
Please include current contact information if different from above.
219037
31169
Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
1a. Well Status: Oil ❑ Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended
20AAC 25.105 20MC 25.110
GINJ ❑ WINJ 0 , WAG[-] WDSPL ❑ No. of Completions: 1
1b. Well Class:
Development ❑ Exploratory ❑
Service ❑Z - Stratigraphic Test ❑
2. Operator Name:
Hilcorp Alaska, LLC
6. Date Comp., Susp., or
Abend.: 8/4/2019
14. Permit to Drill Number / Sundry:
219-087
3. Address:
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
7. Date Spudded:
July 12, 2019
15. API Number:
50-029-23638-00-00
4a. Location of Well (Governmental Section):
Surface: 4913' FSL, 171' FEL, Sec 14, T13N, R9E, UM, AK r
Top of Productive Interval:
1730' FNL, 2146' FWL, Sec 13, T13N, R9E, UM, AK
Total Depth:
2494' FSL, 685' FWL, Sec 20, T13N, R10E, UM, AK
8. Date TD Reached:
July 25, 2019
16. Well Name and Number:
MPU M-13 '
9. Ref Elevations: KB: 58.8'
GL:24.7' BF: 24.7'
17. Field / Pool(s): Milne Point Field
Schrader Bluff Oil Pool
10. Plug Back Depth MD/TVD:
16,295' MD / 4,035' ND
18. Property Designation: ,
ADL025514 / ADL025515
4b. Location of Well (State Base Plane Coordinates, NAD 27):
Surface: x- 533993 y- 6027765 ' Zone- 4
TPI: x- 536318 y- 6026413 r Zone- 4
Total Depth: x- 545394 y- 6020128 ( Zone- 4
11. Total Depth MD/TVD:
16,300' MD / 4,035' TVD
19. DNR Approval Number:
LONS 16-004
12, SSSV Depth MD/TVD:
N/A
20. Thickness of Permafrost MD/TVD:
1,984' MD / 1,884' TVD
5. Directional or Inclination Survey: Yes e (attached) No El
Submit electronic and printed information per 20 AAC 25.050
13. Water Depth, if Offshore:
N/A (ft MSL)
21. Re-drill/Lateral Top Window MD/TVD:
I N/A "
22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days
of completion, 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 locator, jewelry, and
perforation record. Acronyms may be used. Attach a separate page if necessary
ROP/ABG/DGR/EWR/ADR 2"/5" MD
ABG/DGR/EWR/ADR 2"/5" TVD
23. CASING, LINER AND CEMENTING RECORD
CASING
WT. PER
FT
GRADE
SETTING DEPTH MD SETTING DEPTH ND
HOLE SIZE
AMOUNT
CEMENTING RECORD PULLED
TOP
BOTTOM TOP BOTTOM
20"
215#
X-52
Surface
114' Surface 114'
42"
±270 ft3
9-5/8"
40#
L-80
Surface
4,927' Surface 3,896'
12-1/4"
Stg 1 L - 300 sx / T - 400 sx
Stg 2 L - 393 sx / T - 270 sx 200 bbls
3-1/2"
9.2#
L-80
Surface
4,736' Surface 3,886'
Tieback
Tieback Tubing
4-1/2"
13.5#
L-80
4,722'
16,300' 3,884' 4,035'
8-1/2"
Injection Liner w/ ICDs &
Swell Packers
24. Open to production or injection? Yes 0 No ❑
If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation
Size and Number; Date Perfd):
"Please see attached schematic for ICD & Swell Packer Detail—
COMPLETION
DATE
VERIFI D
25. TUBING RECORD
SIZE DEPTH SET (MD) PACKER SET (MD/TVD)
3-1/2" 3,886' 4,722' MD / 3,884' TVD
Liner Top Packer
26. ACID, FRACTURE, CEMENT SQUEEZE, ETC.
Was hydraulic fracturing used during completion? Yes LJ No �
Per 20 AAC 25.283 (i)(2) attach electronic and printed information
DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED
27. PRODUCTION TEST
Date First Production:
N/A
Method of Operation (Flowing, gas lift, etc.):
N/A
Date of Test:
Hours Tested:
Production for
Test Period
Oil -Bbl:
Gas -MCF:
Water -Bbl:
Choke Size:
Gas -Oil Ratio:
Flow Tubing
Press.
Casing Press:
I
Calculated
24 -Hour Rate
Oil -Bbl:
Gas -MCF:
Water -Bbl:
Oil Gravity - API (corr):
Form 10-407 Revised 5/2017(c�. (. (`1 CONTI ON PAGE 2 Submit ORIGINIAL o y
N to 2,12L4 'e •� RBDMS1�ti AUG 3 0 2019 JWp101R lea
28. CORE DATA Conventional Corals): Yes ❑ No ❑� Sidewall Cores: Yes ❑ No Q
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.
29. GEOLOGIC MARKERS (List all formations and markers encountered):
30. FORMATION TESTS
NAME
MD
TVD
Well tested? Yes ❑ No ❑✓
If yes, list intervals and formations tested, briefly summarizing test results.
Permafrost - Top
Permafrost - Base
1,984'
1,884'
Attach separate pages to this form, if needed, and submit detailed test
Top of Productive Interval
5,235' SB OA
3,898'
information, including reports, per 20 AAC 25.071.
SV5
1,381'
1,341'
SV1
2,026'
1,922'
Ugnu LA3
3,416'
3,154'
SB NA
4,130'
3,676' '
SB OA
4,793'
3,890'
Formation at total depth:
SB OA '
31. List of Attachments: Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Report.
Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis,
paleontological report, production or well test results, per 20 AAC 25.070.
32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge.
Authorized Name: Monty Myers Contact Name: Cody Dinger
Authorized Title: Drilling Manager Contact Email: cdinger@hilcorl2.com
Authorized Q Contact Phone: 777-8389
Signature: — - Date: o . _`9i -
INSTRUCTIONS
General: This form and the required atta�chmen rovide 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.
Item 1 a: 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.
Item 1 b: Well Class - Service wells: Gas Injection, Water Injection, Water -Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection,
Observation, or Other.
Item 4b: TPI (Top of Producing Interval),
Item 9: 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.
Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00).
Item 19: 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.
Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29.
Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of
completion, suspension, or abandonment, whichever occurs first.
Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool.
Item 24: 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).
Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain).
Item 28: 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.
Item 30: 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.
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
othertests as required including, but not limited to: core analysis, paleontological report, production or well test results.
Form 10-407 Revised 5/2017 Submit ORIGINAL Only
K
Mlcnrp Alaska, LLC
Orig KB Elev.: 58.8'/ GL Elev.: 24.7
TD=16,3W (MD)/TD=4,0350VD)
PBTD=16,295' (MD) / PBTD=4,035 M)
Schematic
Milne Point Unit
Well: MPU M-13
PTD: 219-087
API: 50-029-23638-00-00
TREE & WELLHEAD
Tree I Cameron 3 1/8" 5M w/ 4-1/16" SM Cameron Wing
Wellhead I Cameron 11"5Kx sliplock bottom w/(2) 2-1/16" 5K outs
OPEN HOLE / CEMENT DETAIL
42"
50 bbls (10 Yards Pilecrete dumped down backside)
12-1/4"
Stg 1-300 sx Lead 12 ppg / 400 sx Tail 15.8 ppg
Top
Stg 2 — 393 sx Lead 10.7 ppg / 270 sx Tail 15.8 ppg (200 bbl to surface)
8-1/2"
Cementless Injection Liner in 8-1/2" hole
CASING DETAIL
Size
Type
Wt/ Grade/ Conn
Drift ID
Top
Btm
BPF
20"x34"
Conductor (insulated)
215.5/X-42/Weld
N/A
Surface
114'
N/A
9-5/8"
Surface
40/L-80/TXP
8.679"
Surface
4,927'0.0758
3,916'
4-1/2"
Liner
13.5 / L-80 / Hyd 625
3.795"
4,722'
16,300'
0.0149
TUBING DETAIL
3-1/2" Tubing 9.3/L-80/EUE8RD 1 2.867" 1 Surf 1 4,736' 1 0.0870
WELL INCLINATION DETAIL
KOP @ 578'
Hole Angle @ XN = 66 deg
Hole Angle @ Liner Top = 83 deg
Max Hole Angle = 92 deg
JEWELRY DETAIL
No
Top MD
Item
ID
Upper Completion
1 2,315' 3.5" X Nipple (2.813" Packing Bore) 2.813"
2 4,377' 3.5" XN Nipple (2.813" Packing Bore; 2.75" No -Go) 2.750"
3 4,671' 3.5" Gauge Mandrel SGM-%PQG w/ Y." Wire 2.896"
4 4,725' 8.26" No Go Locater w/ 7.375" Seal Assembly 2.992"
5 1 4,726' 7.375" Tieback above the SLZXP Liner Top Packer (Btm @ 4,736') 2.992"
Lower Completion
6
1 4,722'
ZXPLiner Top Packer
-
7
16,295'
WIV(Ball on Seat/Closed)
3,922'
Depth
ND
ICD/Swell Packer Detail
Depth
MD
Depth
ND
ICD/Swell Packer Detail
3,896'
Tendeka Water Swell Packer
11,123'
3,932'
Tendeka Water Swell Packer
3,898' r
ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625
11,559'
3,922'
ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625
3,902'
Tendeka Water Swell Packer
11,872'
3,922'
Tendeka Water Swell Packer
3,916'
ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625
12,228'
3,923'
ICD w/ 250L mesh, Sliding Sleeve 13,5# bxp 625
3,934'
Tendeka Water Swell Packer
12,621'
3,940'
Tendeka Water Swell Packer
3,949'
ICD w/ 250L mesh, Sliding Sleeve 13.50 bxp 625
13,056'
3,962'
ICD w/ 250L mesh, Sliding Sleeve 13.59 bxp 625
3,945'
Tendeka Water Swell Packer
13,398'
3,974'
Tendeka Water Swell Packer
3,943'
ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625
13,626'
3,977'
ICD w/ 250L mesh, Sliding Sleeve 13.5# bxp 625
3,930'
Tendeka Water Swell Packer
14,102'
3,980'
Tendeka Water Swell Packer
3,917'
ICD w/ 250L mesh, Sliding Sleeve 13.59 bxp 625
14,250'
3,974'
ICD w/ 250L mesh, Sliding Sleeve 13.59 bxp 625
3,917'
Tendeka Water Swell Packer
14,562'
ka Water Swell Packer
3,920'
ICD w/ 250L mesh, SlidingSleeve 13.5# bxp625
15,080'
/ 250L mesh, Sliding Sleeve 13.54 bxp625
3,929'
Tendeka Water Swell Packer
15,474
ka Water Swell Packer
3,937'
ICD w/ 250L mesh, SlidingSleeve 13.5# bx 625
1511,826'
W41,022'ICD
/ 250L mesh, Sliding Sleeve 13.5# bxp 625
3,935'
Tendeka Water Swell Packer
3,941'
ICD w/ 250L mesh, Sliding Sleeve 13.59 bxp 625
GENERAL WELL INFO
API#: 50.029-23638-00-00
Completed by Doyon 14: 8/4/19
Revised By: CID 8/26/2019
Hilcorp Energy Company Composite Report
Well Name: MP M-13
Field: Milne Point
County/State: , Alaska
i (LAT/LONG):
ovation (RKB):
API #:
Spud Date:
Job Name: 1911312D MPU M-13 Drilling
Contractor Doyon 14
AFE #:
AFE $:
Activity Date.
Ops Summary.... _ _. _......
7/11/2019
See M-04 for details., Skid floor into moving position and move Rig off Well M-04 and around the pad. Transfer matting boards from previous well to next, lay
containment liner for Rig then spot, shim & level Rig over Well M-13.; Skid rig floor into drilling position, R/U diverter system, Tel bolts on surface stack. Spot
third party units. Work on rig acceptance checklist.
7/12/2019
Continue to R/U diverter system. Tq bolts on surface stack. Spot third party units. R/U rig floor, gas buster and mud lines. N/U bell nipple and riser.;Spot
cuttings box and rock washer. Prep pits for spud mud, install accumulator lines on annular and knife valve. Load 5 " DP into shed, record serial #, strap and tally
same.;Continue to process 5" DP, spot fuel trailer, work on rig acceptance checklist. Accept rig @ 10:00 hm.;Continue to process 216 jts DP, prep shakers and
pits to spud well. R/U and function test pump house and water tanks. Prep cellar berm for conveyer, fill pit 4 w/ water for conductor cleanout. Load pits with
580 bbls 8.5 ppg 300 vis spud mud.;PJSM, Drift and P/U 5" DP using mouse hole & racking stands in derrick. Continue to complete items on acceptance
checklist.;Perform diverter function test on 5" drill pipe. Test gas alarms and PVT sys. Closest ignition source 81' away, light on wellhouse. Test witnessed
waived by AOGCC rep Adam Earl @ 10:08 am, 07/12/2019. Knife valve opened in 14 seconds & annular closed in 40 seconds.;Accumulators: 3000 PSI
system, 1850 PSI after closure, 37 sec. 200 PSI, full recharge, 158 sec. full recharge. 6 bottle average = 1984 psi.;Continue to Drift and P/U 5" DP using
mouse, racking stands in derrick.;Continue MW and rack back stands of 5" drill pipe. 72 total stands racked back. M/U and rack back 6 stands HWDP and
Drilling Jars.;Hold Pre -Spud meeting with all parties on the Rig.;M/U new 12-1/4" Kymera bit, 8" SperryDrill motor set at 1.5°, XO sub and stand of 5" HWDP.
RI at tag bottom on depth at 111'. Flood lines and pressure test to 3500 PSI - good test.;Clean out conductor U 114' and proceed to drill 12-1/4" surface hole
from 114' to 185', 71' drilled, 71'/hour AROP. 420 GPM = 350 PSI, 40 RPM = 1 K TQ, 3K WOB. PU 50K / SO 50K / ROT SOK. 8.8 ppg MW, 300+ vis.
7/13/2019
Drill 12-1/4" surface hole from 185'to 221',. 420 GPM = 350 PSI, 40 RPM = 1 K TQ, 3K WOB.;CBU @ 418 GPM - 420 psi. Back ream 1 std @ 40 RPM U
127'. Continue POOH on elevators U Motor @ 34'.;M/U Remaining Directional BHA 91 with DM Collar, DGR, EWR, PWD HUM & TM Collar, Carry Scribe and
upload MWD. P/U 3 NMFC & RIH to 177'.;Establish circulation and wash down U 221'@ 415 gpm, 750 psi No fill observed. PU 62K / SO 67K / ROT 65K.
8.9 ppg MW, 300+ vis.;Drill 12-1/4" surface hole F/ 221' T1363' ( 142') avg ROP 71 fph. 443 GPM = 810 PSI, 40 RPM= 2K TQ, 5-8K WOB. 9.1 ppg MW,
300 vis. ECD 9.5, max gas Ou. PU 63K / SO 66K / ROT 65K.;Drill 12-1/4" surface hole F/ 363' T/ 950' ( 587' ) avg ROP 97.8 fph, 445 GPM = 940 PSI, 60
RPM = 24K TO, 5-7K WOB. 9 ppg MW, 198 vis. ECD 9.8, max gas Ou PU 67K / SO 83K / ROT 87K.;At 490' kickoff 3 deg/100', at 720' build 4 14100'. At
500' start lowering vis f/ 300 to 200.;DHII 12-1/4" surface hole F/ 950' T/ 1490'(540') avg ROP 90 fph, 493 GPM = 1360 PSI, 60 RPM = 4-7K TQ, 8-20K
WOB. 9.1 ppg MW, 209 vis. ECD 10.6, max gas 17u PU 92K 150 90K / ROT 92K.;EOB @ 1260'w/ 27° inclination. Base of Permafrost @ 1984'/ 1685'
TVD.;Drill 12-1/4" surface hole F/ 1490' T/ 2346'(856') avg ROP 142 fph, 500OPM = 1470 PSI, 60 RPM = 6-8K TQ,7-15K WOB. 9.2 ppg MW, 174 vis. ECD
10.4, max gas 102u. PU 120K / SO 98K / ROT 106K.;Pumped high vis sweep at 2060', 20% increase and back on calculated strokes. last survey at 2288.31'
MD / 2153' TVD, 27.5° inc, 113.9° az, 6.2' from plan, 4' high and 4.7' right.; Hauled 440 bbls H2O from M -Pad (Nopoint Creek) for total= 1000 dials
Hauled 0 bbls heated H2O from G&I for total = 0 bible
Hauled 1093 bbls cutting/liquids to MPU G&I for total= 1093 bbls
Hauled 270 bbls Pit Water from A -Pad for total = 650 bbls
7114/2019
Drill 12-1/4" surface hole F/2346' T/ 3014' (668') avg ROP 111.3 fph, Drilling tangent section holding 27 deg inc. 595 GPM = 1870 PSI, 80 RPM= 9K TO,
10K WOB. 9.2 ppg MW, 92 vis. ECD 10.1, max gas 103u. PU 135K/ SO 107K/ ROT 119K.;Pump 30 bbl hi vis sweep @ 2526, sweep back on time with
50% increase at shakers. Top of Ugnu came in @ 2454' MD, 2391' TVD.;Ddll 12-1/4" surface hole F/3014' T/ 3706' (692') avg ROP 115.3 fph, 586 GPM =
2010 PSI, 80 RPM = 10-12K TQ, 7-8K WOB. 9.1 ppg MW, 113 vis. ECD 9.9, max gas 23u. PU 151K /SO 115K /ROT 130K.;Drill tangent section holding 27
deg inc, to 3394', start build 4 deg/100' targeting 87 deg inc. Crossed coal 1 @ 3014' MD, 2798' TVD, LA3 Sand in lower Ugnu came in @ 3416' MD, 3154'
TVD. Pump 30 bbl hi vis sweeps @ 3090 & 3675', 1st sweep back on time w/ 50% increase, 2nd no increase.; Drill 12-1/4" surface hole F/3706' T/4126
(419') avg ROP 69.8 fph, 585 GPM = 2190 PSI, 80 RPM = 15-17K TO, 9-15K WOB. 9.1 ppg MW, 182 vis. ECD 9.9, max gas 28u. PU 152K'/ SO 109K /
ROT 130K.;Drill 12-1/4" surface hole F/4125' T/ 4631'(506') avg ROP 84.3 fph, 550 GPM = 2080 PSI. 80 RPM= 15-17K TQ, 15K WOB. 9.25 ppg MW, 73
vis. ECD 10.1, max gas 51u. PU 152K/ SO 111K/ ROT 127K.;Continue build at 4°/100'. SB -N logged at 4130' MD, 3677' TVD. Drilled through fault at 4458'1
40' Throw DTE. Pumped high vis sweep at 4573', no increase and back on calculated strokes. Last survey at 4572.85' MD/3854.87' TVD, 75.40' inc, 125.32'
so, 4.3' from plan, 0.6' high and 4.3' right.;Hauled 590 bbls H2O from M -Pad (Nopoint Creek) for total= 1590 bbls
Hauled 430 bbis H2O from L -Pad Lake for total = 430
Hauled 0 bbls heated H2O from G&I for total = 0 bbls
Hauled 2649 dials cutting/liquids to MPU G&I for total= 3742 bbls
Hauled 1160 bbls Pit Water from A -Pad for total = 1520 bbls
7/15/2019
Drill 12-1/4" surface hole F/ 4631' T/ 4934' md, 3896'tvd (303') avg ROP 75.7 fph, TD in OA sand. 555 GPM = 2080 PSI, 80 RPM = 16K TO, 10-16K
WOB. 9.25 ppg MW, 70 vis. ECD 10.2, max gas 51u. PU 155K / SO 110K / ROT 125K.;Maintain 4°/100' BR to 88" inc @ 4805' into OA- sand, build to 91
deg TD in OA -1. Final survey = 4875.30' md, 3895.03'tvd, 88.51' inc, 124.14 az. 6.4' above the line, 7.7' right.; Pump 30 bbl hi vis sweep w/ nut plug marker
while back reaming slowly 600 gpm, 1870 psi, 80 rpm, 14k tq , sweep back on time w/ no increase, circulate and condition mud racking 1 std back ea. BU to
4633', lower vis f/ 70 to 50 (3 BU total) run back to bttm.; Flow check well, static. BROOH from 4934' to 732' at 550 GPM, 1450 PSI, 80 RPM, 13-16K TO,
9.78 ppg ECD pulling 10 min per std increasing to 5 min std, Slowing down as hole dictates.;POOH on elevators f/ 732' t/86' Racking HWDP & Jars in the
Derrick and laying down the flex collars.;Down load MWD data, UD BHA & Drain motor. Break out bit. Bit grade- 1 -2 -CT -G -E -1 -NO -TD. Clean and clear rig
floor.;Clear & Clean rig floor. R/U to tun 9-5/8"" Casing with Doyon casing. M/U Volant tool with Cmt swivel to TD & install bail extensions. Install XO on
FOSV. 2 bbl/hr static loss rate.;P/U 9-5/8" shoe track to 161'. Baker Loc shoe track and torque to 20,960 fillies. Two 9-5/8" x12-1/4" Expand-o-lizers on shoe
joint and 1 each on spacer and float collarjoint. Check floats. Good. Pump through with Volant.;Run 9-5/8" 40# L-80 TXP BTC -SR casing as per tally, filling on
the fly with Volant and breaking circ every 10 joints F/ 161' T/ 835'. Torque to 20,960 Nlbs w/ Volant. One centralizer per joint. 20-407min running speed. 9 bbls
Iost.;Hauled 1410 bbls H2O from M -Pad (Nopoint Creek) for total= 3000 bbls
Hauled 0 bbls H2O from L -Pad Lake for total = 430
Hauled 0 bbls heated H2O from G&I for total = 0 bbls
Hauled 2219 bbls cutting/liquids to MPU G&I for total= 5961 bbls
Hauled 580 bbls Pit Water from A -Pad for total = 2110 bbls
7116/2019
Run 9-5/8" 409 L-80 TXP BTC -SR casing as per tally, filling on the fly with Volant and breaking circ every 10 joints F/ 835' T/ 1310', C/O damaged collar on jt
29. UD jt 30 damaged pin, Continue R I H f/ jt 131 to 1741'. Change out damage collar on jt j# 35. C/O jts # 36 & 37 due to damaged threads.;Torque to 20,960
ftllbs w/ Volant. One centralizer per joint to jt #21 then every other jL;Run 9-5/8" 40# L-80 TXP BTC -SR casing as per tally, filling on the fly with Volant and
breaking circ every 10 joints F/1741' T/ 2168. Torque to 20,960 Ill w/ Volant. One centralizer every other joint to #59.;Circulate bottoms up below the
permafrost at 2168'. Stage up pumps from 1.5 BPM, 130 PSI to 6 BPM, 210 PSI.;Continue to R I H with 9 5/8" Casing F/ 2168' T/ 4873'. Place Halliburton
ESC II between joints #65 & 66 @ 2190'. Filling on the fly with Volant and breaking circ every 10 joints. Torque to 20,960 ft/lbs w/ Volant. Centralizer on every
other joint to #116..;; ash down last full jt & 20' pup it @ 2 bpm, 160 psi to to set depth @ 4927'. Circ 3x btm up at 6 BPM, 250 Psi conditioning mud. Work
pipe f/ 4903't/ 4930'. while ROT at 20 RPM, 20k Tq. Conduct PJSM on cmt job & finish rigging up HES. P/U 245K, SIO 145K.;120 joints of 9-5/8" casing,
80 each 9-5/8"x12-1/4" Expand-o-lizers and 12 stop rings ran. 32.8 bbls loss during casing run.;Line up to HES. Flood lines with water and test lines to 4000
psi. Good. Mix & pump 60 bbl Tuned Spacer. Drop Plug. Pump 125.5 bbl 300 SX 12# Lead cmt. Mix & Pump 82 bb1400 SX 15.8# Tail cmt. Drop top plug.
Chase with 20 bbl H2O. Displace with 168.2 bbl mud with the rig then line up to HES.; Pump 80 bbl Tuned spacer. Displace with 92 bbl 9.3 PPG mud &
bump plug @ 2572 skis. (44 stks early) Pressure up to 500 over at 1100 psi, Final lift at 570 psi. Bleed down and check floats. Good. Pump at 3 bpm
pressuring to 2600 si shiftingESC II open and start getting good returns.; Increase to 6 BPM, pressure increase to 2800 psi before starting to slowly drop. to
normal pressure. Full returns t roughout. CIP at 01:18. Rotate and reciprocate throughout cement job. No losses recorded during cement job.;Circulate thm
ESC @ 2190' staging pump to 6 bpm, 500 psi, at 915 silks start dumping mud interface, 60 bbls of tuned spacer, 15 bbls of cement & 70 bbls tuned spacer
#2. At 2678 stks dump 100 bbl mud interface, 3728 stks divert clean mud to phs.;Continue to circulate through cementer 6 bpm, 630 psi, circulating a hi -vis
sweep around. Sweep back on calculated strokes with no additional cuttings or clabbored mud returned.;Shut down pumps, remove hydraulic hoses f/ knife
valve, cycle bag and flush stack and lines with black water. Continue circulating @ 6 BPM, 340 psi.;Hauled 200 bbls H2O from M -Pad (Nopoint Creek) for
total= 3200 bbls
Hauled 0 bbls H2O from L -Pad Lake for total = 430
Hauled 650 bbls heated H2O from G&I for total = 650 bbls
Hauled 597 bbls cutting/liquids to MPU G&I for total= 6558 bbis
Hauled 0 bbls Pit Water from A -Pad for total = 2110 bbls
7/17/2019
Continue to circ at 4-6 bpm while waiting on cmt. Conduct PJSM at 0800. ( Had First Aid in the pipe shed with pinched fingers). Break out volant and clean
p
and re engage. Line up to HES.;Pump Tuned Spacer 60 bbl at 10 PPG. Add 4# red die and Pol E Flake in first 10 bbl. Pump 393 SKS ( 305 bbll at 10.7
,/
PPG Perm L Lead. Pum 270 SKS 56.2 BBL of 15.8 . Dro closin lug. Chase with 20 bbl H2O From HES. Swap [o the rig and displace with 146 bbl
[_7,rry�
mud. Lost returns at 1200 stks.;Slow pumps and attempt to regain circ as returns were diminishing. unable to gain circ. No increase in pressure. Bumped plug
on calculated strokes. Close tool at 1510 psi. Final lift was 380 psi at 3 bpm before bump. Bleed down and Check For flow. Static- 200 bbl need cmt and
mud push back.;CIP 10:54, Lost returns 25 bbl before bump.;Flush surface equipment. Function annular.;Lift stack, Set slips with 100 k on slips, Cut pipe. Cut
joint 18.49 laid down. Empty mud pits and start cleaning. Break down 200 riser, Knife valve and 16" diverter equipment.;lnstall Well Head and test T103
connection t/ 500 psi - 5 min, 2470 psi - 15 min. Test casing head t/ 500 psi - 5 min, 5000 psi -15 min. Prep spacer spool/BOPE for install.;Nipple up BOP
stack. Install 24", 13-5/8" Spacer spool. Clean and inspect Ram cavities, N/U SOPE ram doors, installl annular koomey hose. SimOps: Prep rig floor for BOP
testing. Install MPD trip nipple, M/U kill line.;lnstall mouse hole, M/U test plug to lest joint, RIH & install. RILDS & Tq to 200 ft/lbs. Fill stack and check for
leaks. Perform body test on BOPE.;Move HWDP in Derrick, M/U 7 stands of 5" Drill Pipe and rack in Derrick.
7/18/2019
Continue build stands of 5" drillpipe and rack in Derrick (14 stands total); I nstall test joint, Flood stack and lines with water, purge air out and hold PJSM on
testing BOPE. "' Notified AOGCC of initial BOP test on 7-17-2019 at 07:27 "';Test BOP equipment as per PTD & AOGCC requirements. AOGCC rep
Matthew Herrera witnessed testing. All tests performed w/ fresh water against test plug. All tests performed to 250 PSI low / 3000 PSI high. All tests held for 5
min each & charted.;#1: Annular on 5" test joint, choke valves 12,13,14, 3" kill Demco & upper IBOP. #2: Top 4.5"x7" VBR on 5" test joint, choke valves 1,
9,11, HCR kill & lower IBOP. #3: Choke valves 5,8, 10, manual kill #4: Choke valves 4,6,7 & 5" TIW #1.;#5: Choke valve 2 & 5" TIW #2 #6: HCR choke & 5"
dart valve #7: Manual Choke #8: Lower 2-718"x5" VBR on 5" test joint. #9: Blind rams & choke valve 3;#10: Man choke B #11: Body test flanges on new choke
valve, choke HCR & choke valves 3,6, 9 912: Hyd choke A. Accumulator test: 3000 PSI system pressure, 1750 PSI after closure. 39 sec for 200 PSI recharge,
185 sec for full PSI recharge. 1975 PSI six nitrogen bottle average.;Super Choke Fail/Pass. Installed new super choke - re-tested flange connections 250/3000
good, re-tested super choke - good.;R/D test equipment and blow down lines. Install 10" I.D. wear bushing.;M/U 8-1/2" cleanout BHA. Used 8-112" Smith XR+
bit, 7" mud motor, float sub, 2x 5" HWDP & jars V 584'. Single in the hole w/ 5" drill pipe from the pipe shed f/ 680' t/ 2452'.;Single in the hole w/ 5" drill pipe
from the pipe shed f/ 584' t/ 2140'.;Wash down f/ 2140'. Tag up @ 2186'w/ Sk WOB. Establish rotary parameters and drill out ES Cementer @ 2190'. 3-7k
WOB, 350 GPM - 530 psi. Dress up then work through V 2235' 2x with no pumps/rotary - Clean -.;Continue single in the hole w/ 5" DP from 2239 t/ 4679. Fill
pipe every 20 stands.;Ream down V 4747' where hard cement was tagged w/ 10k WOB. Started seeing stringers @ 4694'w/ 5-8k WOB. 184 GPM - 500 psi,
60 RPM - 15k Tq. Start getting thick mud returns, Mud thinned out with bottoms up. 233 GPM - 580 psi, Rot/Recip 60 RPM-14k Tq while CBU.;R/U & Test
or 0 min. Good. Bleed down and blow down surface equipment. 4.5 bbls pumped and bled back.;Wash & Ream F/ 4747' T/ 4805'. Tag bfl
adaptor on depth. 400 GPM - 1040 PSI, 50 rpm, 16-18K Tq, 9K WOB.;Drill Battle adaptor, Float Collar & shoe on depth. Good cmt. Drill rat hole out T/_
4934'. Drill 20' New hole F! 4934' T/ 4954'. 50 RPM, 18K To, 400 GPM, 1040 PSi. Dress shoe and FE, work through with no rotary - clean -;Pull in to shoe &
\
Bring pumps to 550 GPM. Work pipe 60', circulating until good mud in and out. Mud weight - 9.25 in and out.�Perform FIT to 12 PPG EMW. 586 PSi. Good
test. Held for 10 min. Bled down 39 psi. Good test. Blow down surface equipment. MW 9.25 EMW 12 557 PSI 3894' TVD 0.9 bbl pumped, 0.9 bbis bled
back.;Hauled 150 bbls H2O from M-Pad (Nopoint Creek) for total= 3510 bbls
Hauled 0 bbis H2O from L-Pad Lake for total = 430
Hauled 0 bbls heated H2O from G&I for total = 865 bbis
Hauled 53 bbis cutting/liquids to MPU G&I for total= 8656 bbis
Hauled 0 bbis Pit Water from A-Pad for total = 2110 bbis
7/19/2019
Monitor Well - Static -, POOH F/ 4868' T/ 584'. Observed high drag causing surface vibration while tripping. Slow pulling speed until vibration diminished.;Rack
back one stand HWDP w/ jars, lay down 15 jts HWDP to shed. Break bit and UD mud motor. Bit Graded: 1-1-WT-A-E-I-NO-BHA.;M/U 8-112" production
drilling BHA to 86: 8.5" NOV PDG bit, NRP sleeve, Geo-Pilot, MWD (ADR/DGR/PWD/DM/TM), 3x NMFC, 2x HWDP and Jars.;Pick up single of 5" drill pipe
and RI V 306". Perform MWD shallow pulse test.;Single in the hole with 5" drill pipe from the pipe shed f/306' V 4367'. Fill pipe every 20 stands. TIH w/
stands from the Derrick V 4747'.; PJSM. Remove trip nipple and install MPD RCD.;Wash down to bottom @ 4954', no fill observed. PSJM & Pump 35 bbls Hi
Vis spacer and displace wellbore from 9.3 ppg spud mud to 8.8 ppg Flo-Pro NT at 7 BPM, 480 PSI, 30 RPM, 13K TO. Reciprocate pipe 46' from 4874' to
4920'.;Obtain SPR's, Lay down working single of drillpipe and rack back a stand.;Cut and slip 53' of drilling line. Service Drawworks, and TopDrive.;Drill 8-1/2"
production hole f! 4954'Y 5534' (3903' TVD), 580' drilled, 96.66/hr AROP. 550 GPM, 1440 PSI, 110 RPM, 15-17K TQ, 15K WOB. 155K PU / 70K SO / 110K
ROT. 8.9, MW, 44 vis, 10.14 ppg, ECD, 152u max gas. Maintain trajectory in the OA-1 sand.;MPD chokes full open while drilling, closed on connections with
no pressure observed. Lost 15 bbls seepage loss to formation during trips and displacement..
Last survey @ 5438' MD / 3900.61' TVD, 88.98° Inc, 125.73" azm, 24.5 from plan, 24.5' high & 0.5' right.;Hauled 185 bbis H2O from M-Pad (Nopoint Creek)
for total= 3695 blots
Hauled 0 bbls H2O from L-Pad Lake for total = 430
Hauled 0 bbis heated H2O from G&I for total = 865 bbls
Hauled 628 bbls cutting/liquids to MPU G&I for total= 9284 bbis
Hauled 0 bbis Pit Water from A-Pad for total = 2110 bbls
7/20/2019
Drill 8-1/2" production hole f/ 5534' V 6176' (3930' TVD), 642' drilled, 1077hr AROP. 550 GPM, 1360 PSI, 115 RPM, 20K TO, 7K WOB. 165K PU / 70K SO !
113K ROT. 9.05 MW, 42 vis, 10.17 ppg ECD, 159u max gas. MPD chokes full open while drilling, closed on connections w/ no pressure obsewed.;Drill 8-1/2"
production hole f/ 6176 V 6557' (3952' TVD), 381' drilled, 63.57hr AROP. 550 GPM, 1550 PSI, 100 RPM, 19K TO, 10K WOB, 157K PU / 77K SO / 115K
ROT. 8.8 MW, 45 vis, 10.07 ppg ECD, 52u max gas.;Ream out excessive DL f/ 6485't/ 6515'- ABI showing an 10' average Dog Leg of 10.4'/100', reamed
down to an 8.4° DogLeg;Drilled in the OA-3 from 6285'to 6526' where the trajectory dropped into the OA-4. MPD chokes full open while drilling, closed on
connections w/ no pressure observed.Pumped hi vis sweep @ 6365', 60% increase back on calculated strokes. Add .25% LoTurq V system. Tq drop f! 19k V
15k.;Drill 8-1/2" production hole f/ 6557't/ 6936'(3946 TVD), 379' drilled, 63.27hr AROP. 550 GPM, 1650 PSI, 120 RPM, 17K TO, 4K WOB. 153K PU / 76K
SO / 113K ROT. 8.8 MW, 47 vis, 10.2 ppg ECD, 12u max gas.;Drilled in the OA-4 f/ 6526'd 6717'(191') where the OA-3 was reacquired MPD chokes full
open while drilling, closed on connections w/ no pressure observed. Maintain 0.25% Iubes.;Drill 8-1/2" production hole V 6936' V 7698' (3933' TVD), 762' drilled,
1277hr AROP. 540 GPM, 1640 PSI, 120 RPM, 18K TQ, 12K WOB. 155K PU 176K SO / 111 K ROT. 8.85 MW, 43 vis, 10.31 ppg ECD, 538u max gas.
Pumped hi vis sweep @ 7510', 50% increase back on calculated strokes.;Maintain trajectory in the OA-3. Start undulation for OA-1 @ 7415' MPD chokes full
open while drilling, closed on connections w/ no pressure observed. Maintain 0.25% lubes.; Drilled 26 concretions for a total thickness of 138' (5.16% of the
lateral)
Last survey @ 7629.47' MD / 3937.71' TVD, 92.60° Inc, 127.59' mm, 13.96' from plan, 13.45.' high & 3.76 left
Losses today (midnight) to hole= 0 bbls. Total losses for interval= 15;Hauled 570 bbls H2O from M-Pad (Nopoint Creek) for total= 4265 bbls
Hauled 0 bbis H2O from L-Pad Lake for total = 430
Hauled 0 bbis heated H2O from G&I for total = 865 bbis
Hauled 776 bbls cutting/liquids to MPU G&I for total= 10060 bbis
7/21/2019
Drill 8-1/2" production hole f/ 7698' t/ 8270' (3918' TVD), 572 drilled, 95'/hr AROP. 550 GPM, 1790 PSI, 120 RPM, 24K TO, 15K WOB. 155K PU /75K SO/
114K ROT. 8.9 MW, 44 vis, 10.65 ppg ECD, 627u max gas.; Pumped Hi -Vis sweep at 8173'. No increase in returns at surface. MPD chokes full open while
drilling, closed on connections w/ no pressure observed. Undulate up from the OA -3 and enter the OA -1 @ 7953'.;Dril 18-1/2" production hole f/ 8270' t/ 8875'
(3918' TVD), 605' drilled, 101'/hr AROP. 550 GPM, 1820 PSI, 120 RPM, 21 K TQ, 9K WOB. 155K PU / 63K SO/ 108K ROT, 8.8 MW, 45 vis, 10.75 ppg
ECD, 670u max gas.;Pumped Hi -Vis sweep at 8745'. 70% increase in returns, back on calculated strokes. MPD chokes full open while drilling, closed on
connections w/ 40 psi build observed. Continue trajectory through the OA -1 lobe. Maintain 0.25% LoTorq Lube.;Drill 8-112" production hole V 8875' t/ 9487'
(3934' TVD), 612' drilled, 102'/hr AROP. 550 GPM, 1940 PSI, 120 RPM, 22K TO, 12K WOB. 159K PU / 51 K SO / 106K ROT. 8.9 MW, 47 vis, 10.91 ppg
ECD, 597u max gas.;Pumped Hi -Vis sweep at 9319'. 40% increase in returns, back on calculated strokes. MPD chokes full open while drilling, closed on
connections w/ 50 psi build observed. Undulate down from the OA -1 and entered the OA -3 @ 9490'.;Drill 8-1/2" production hole f/ 9487' V 10266' (3934' TVD),
779' drilled, 13071hr AROP, 550 GPM, 1980 PSI, 120 RPM, 23K TQ, 5K WOB. 170K PU / 42K SO / 104K ROT. 9.0 MW, 41 vis, 10.82 ppg ECD, 693u max
gas.;Pumped Hi -Vis sweep at 10080'. 70% increase in returns, back on calculated strokes. MPD chokes full open while drilling, closed on connections w/ 60 psi
build observed. Increase LoTorq to 0.5%. Tq drop from 24k to 21 k.;Drilled 52 concretions for a total thickness of 25T (4.9% of the lateral)
Last survey @ 10102.46' MD 13935.78' TVD, 90.63° inc, 126.46° azm, 16.01' from plan, 15.78' high & 2.7' left
Losses today (midnight) to hole= 22.5 Wis. Total losses for interval= 69.5 bbls;Hauled 450 bbls H2O from M -Pad (Nopoint Creek) for total= 4715 bbis
Hauled 575 bbls H2O from L -Pad Lake for total = 1005 bbls
Hauled 0 bola heated H2O from G&I for total = 865 bbls
Hauled 1050 bbls cutting/liquids to MPU G&I for total= 11110 bbls
Hauled 0 able Pit Water from A- Pad for total = 2110
7/22/2019
Drill 8-1/2" production hole f/ 10266' t/ 10745' (3939' ND), 479' drilled, 80'/hr AROP. 550 GPM, 1960 PSI, 120 RPM, 23K TO, 7K WOB. 175K PU / 0 SO /
106K ROT. 8.9 MW, 42 vis, 10.89 ppg ECD, 457u max gas.;MPD chokes full open while drilling, closed on connections w/ 60 psi build observed. Pumped Hi -
Vis sweep at 10648'. 75% increase in returns, back 100 strokes late. Lost SO Wt @ 103651.;Drill 8-1/2" production hole f/ 10745 V 11345' (3922' TVD), 600'
drilled, 100'/hr AROP. 550 GPM, 1970 PSI, 120 RPM, 24K TO, 13K WOB. 165K PU /103K ROT. 8.9 MW, 48 vis, 10.89 ppg ECD, 432u max gas. 5 BPH
losses to formation.;MPD chokes full open while drilling, closed on connections w/ 60 psi build observed. Pumped Hi -Vis sweep at 11125'. 50% increase in
returns, back 200 strokes late. Undulate up from the OA -3 into the OA -1 at 11237'.;Drill 8-1/2" production hole f/ 11345't/ 11886' (3922' TVD), 541' drilled,
907hr AROP. 550 GPM, 2020 PSI, 110 RPM, 24K TO, 4K WOB. 171 K PU / 108K ROT. 8.9 MW, 42 vis, 10.84 ppg ECD, 453u max gas.;MPD chokes full
open while drilling, closed on connections w/ 60 psi build observed. Pumped Hi -Vis sweep at 11697'. 50% increase in returns, back 200 strokes late. Maintain
trajectory through the OA -1 sand. Increase lube V 1 %.;Drill 8-1/2" production hole f/ 11886' V 12307 (3924' TVD), 421' drilled, 70'/hr AROP. 550 GPM, 2030
PSI, 120 RPM, 25K TO, 15K WOB. 176K PU / 105K ROT. 8.9 MW, 40 vis, 10.91 ppg ECD, 552u max gas. Loss continue @ 5 BPH.;Drilled 76 concretions
for a total thickness of 422' (5.72% of the lateral)
Last survey @ 12197.42 MD / 3923.30' ND, 89.69 inc, 125.43" azm, 12.64' from plan, 11.24' high & 5.79 left
Losses today (midnight) to hole= 129.5 bbls. Total losses for interval= 152.;Hauled 0 bible H2O from M -Pad (Nopoint Creek) for total= 4715 bbls
Hauled 915 bbls H2O from L -Pad Lake for total = 1920 bible
Hauled 0 bbls heated H2O from G&I for total = 865 bbls
Hauled 930 bible cutting/liquids to MPU G&I for total= 12040 bible
Hauled 0 bbls Pit Water from A -Pad for total = 2110 bible
7/23/2019
Drill 8-1/2" production hole H 12307' V 12745' (3948' TVD), 438' drilled, 737hr AROP. 545 GPM, 2160 PSI, 120 RPM, 26K TQ, 12K WOB, 170K PU / 106K
ROT. 9.0 MW, 40 vis, 11.18 ppg ECD, 390u max gas. Increase lube to 1.5% @ 12637'. 30 bbl hi -vis sweep @ 12742' had 40% increase. 11 BPH losses
avg.;Drilled in OA -1 then entered OA -2 at 12567' and OA -3 at 12738'.;Drill 8-1/2" production hole f/ 12745't/ 13262' (3969' TVD), 517drilled, 86'/hr AROP.
545 GPM, 2230 PSI, 100-120 RPM, 27K TO, 7K WOB, 176K PU / 105K ROT. 9.0 MW, 43 vis, 11.28 ppg ECD, 532u max gas. 30 bbl hi -vis sweep @ 13220'
had 25% increase. 10 BPH losses avg.;Drill 8-1/2" production hole f/ 13262' U 13678' (3976' TVD), 416' drilled, 697hr AROP. 545 GPM, 2240 PSI, 100 RPM,
27K TO, 8K WOB, 183K PU / 105K ROT. 8.9 MW, 42 vis, 11.05 ppg ECD, 645u max gas. 7 BPH losses to the formation.;Perfonned 290 bbl new mud
dilution at 13316. Torque reduction from 28K to 25K & ECD from 11.3 to 11.0 ppg. Torque climbed to 28K at 13650', reduced RPM to 100 due to torque
Iimit.;DHII 8-1/2" production hole 1113676 V 14077' (3979' TVD), 399 drilled, 677hr AROP 500-550 GPM, 1910-2240 PSI, 120 RPM, 27K TO, 8K WOB, 184K
PU / 109K ROT. 9.0 MW, 41 vis, 10.91 ppg ECD, 645u max gas. 8 BPH losses to the formation.;30 bbl hi -vis sweep @ 13790' had 40% increase. Add 0.25%
776 lube @ 138201, torque reduced from 28K to 25K.;Drilled 101 concretions for a total thickness of 536' (5.9% of the lateral).
Last survey @ 14077.15' MD 13981.98' TVD, 90.51° inc, 124.97 azm, 25.45' from plan, 25.35' low, 2.29' left.
Losses today (midnight) to hole = 215 tools. Total losses for interval = 367 bbls.;Hauled 0 bats H2O from M -Pad (Nopoint Creek) for total= 4715 bbls
Hauled 820 bbls H2O from L -Pad Lake for total = 2740 bbls
Hauled 0 bbls heated H2O from G&I for total = 865 bbls
Hauled 828 bbls cutting/liquids to MPU G&I for total= 12868 bbls
Hauled 0 bbls Pit Water from A -Pad for total = 2110 bbls
7/2 412 01 9
Drill 8-1/2" production hole If 14077't/ 14459' (3970' TVD), 382' drilled, 647hr AROP. 545 GPM, 2180 PSI, 120 RPM, 25K TQ, 1 O WOE, 175K PU / 105K
ROT. 8.9 MW, 46 vis, 11.03 ppg ECD, 413u max gas. Sweep @ 14266' 30% increase, 300 strokes late. Increase lubes to 2% @ 14340', 8 BPH losses
avg.;Drill 8-1/2" production hole V 14459't/ 14935' (3983' TVD), 476' drilled, 79' /hr AROP. 545 GPM, 2180 PSI, 110-120 RPM, 28K TQ, 9K WOE, 180K PU /
103K RT. 9.0 MW, 38 vis, 11.13 ppg ECD, 361 a max gas. Sweep @ 14849, 50% increase, 300 strokes late.; 10 BPH losses avg. Exited out the top of OA -1
from 14518' to 14612'.; Drill 8-112" production hole f/ 14935' V 15220' (3992' TVD), 285' drilled, 487hr AROP. 510 GPM, 2210 PSI. 100 RPM, 26.51K TO. 9K
WOB, 173K PU / 104K ROT. 8.9 MW, 43 vis, 10.97 ppg ECD, 361u max gas. Perform 290 bbl mud dilution @ 14984'& increase lube to 2.5%. 7 BPH losses
avg.;Begin steering down 87" inc @ 15205'.;Drill 8-1/2" production hole f/ 15220'V 15485' (4008' TVD), 265' drilled, 44'/hr AROP. 550 GPM, 2170 PSI, 100
RPM, 28K TO. 8K WOB, 180K PU / 109K SO. 8.9 MW, 42 vis, 11.05 ppg ECD, 460u max gas. 9 BPH losses avg. Sweep @ 15316', 30% increase, back on
strokes. Entered OA -2 @ 15370'.;Ddlled 128 concretions for a total thickness of 722' (6.9% of the lateral). Last survey @ 15340.41'/ 3997.84' TVD, 86.73° inc,
129.05° azm, 41.99' from plan, 41.54' low, 6.17' left. Daily losses (midnight) = 178 bbls. Cumulative losses for interval = 545 bbls.;Hauled 0 bbls H2O from M -
Pad (Nopoint Creek) for total= 4715 bbls
Hauled 835 bola H2O from L -Pad Lake for total = 3575 bbls
Hauled 0 bbls heated H2O from G&I for total = 865 bible
Hauled 875 bbls cutting/liquids to MPU G&I for total= 13743 bola
Hauled 0 bbIs Pit Water from A -Pad for total = 2110 bbl
ROT. 9.0 MW, 40 vis, 10.99 ppg ECD, 250u max gas. Increase lube to 4% total, 2% Lo-Torq & 2% 776. Entered OA-3 @ 15598'. 5 BPH losses avg.;Drill 8.5"
production lateral f/ 15660't/ 15884' (4020' TVD), 224' drilled, 56' /hr AROP. 545 GPM, 2220 PSI, 100-120 RPM, 27K TO, 13K WOB, 175K PU / 111 K ROT.
9.0 MW, 44 vis, 11.1 ppg ECD, 430u max gas. 5 BPH losses avg.;Change out top drive swivel packing. Circulate through cement line at 5 BPM, 710 PSI.;DnII
8.5" production lateral f/ 15884' U 16197' (4030' TVD), 31S drilled, 527hr AROP. 510 GPM, 2040 PSI, 100 RPM, 28K TO, 10K WOB, 175K PU 1106K ROT.
9.0 MW, 41 vis, 11.12 ppg ECD, 554u max gas. Sweep @ 15979'30% increase, 200 stks late. 8 BPH losses avg.;DdII 8.5" production lateral f/ 16197 t/
16300'(4034- TVD) the TD of the well, 103' drilled, 1037hr AROP. 540 GPM, 2290 PSI, 95 RPM, 28K TO, 10K WOB, 177K PU / 110K ROT. 9.0 MW, 42 vis,
11.05 ppg ECD, 303u max gas. Obtain final survey.;Last survey at 16229.10' MD / 4032.70' TVD, 88.03' inc, 126.05° azm, 68.53' from plan, 68.53' low and
0.40' right. 157 concretions were drilled in the lateral, for a total thickness of 913'(8%). Daily losses (midnight) = 151 bbls, cumulative losses for interval = 696
bbls.;Pump low vis sweep followed by a high vis sweep. 25% increase of cutting observed, 200 stks late. 540 GPM, 2350 PSI, 120 RPM, 27.5K TO, 11.01
ECD. Continue to circulate 4 bottoms up while preparing mud pits for SAPP pills & brine displacement. Rack back a stand every bottoms up f/ 16300' t/
16066.; Hauled 0 bbls H2O from M-Pad (Nopoint Creek) for total= 4715 bbls
Hauled 700 bbls H2O from L-Pad Lake for total = 4275 bbls
Hauled 0 bbls heated H2O from G&I for total = 865 bbls
Hauled 538 bbls cutting/liquids to MPU G&I for total= 14281 bbls
Hauled 0 bbls Pit Water from A-Pad for total = 2110 bbls
H
Well Name: MP M-13
Field: Milne Point
County/State: , Alaska
(LAT/LONG):
ovation (RKB):
API M
Hilcorp Energy Company Composite Report
Spud Date:
Job Name: 1911312C MPU M-13 Completion
Contractor
APE #:
APE $
Activity Date
., Opt Summary
7/26,'2019
Finished pumping 4 bottoms up at 550 GPM, 2200 PSI, 120 RPM, 27.5K TQ, 11.01 ppg ECD. RIH H 16066't' 16300'., Pump SAPP pill treatment 25 bbl hi -
vis spacer, 50 bbls seawater, 30 bbis SAPP #1, 50 bbls seawater, 30 bats SAPP #2, 50 bbls seawater, 30 bbls SAPP #3, 25 bbls hi -vis spacer then 280 bats
seawater. Displace w/ 8.45 ppg 4% lube viscosifed brine 6 BPM, 870 PSI ICP, 750 PSI FCP, 40-120 RPM, 25-30K TQ. Good PST tests: 3.15 sec avg x 3
tests in & 4.7 sec avg x 3 tests out. 185K PU (200K pumps off) 60K SO after displacement., BROOH f/ 16300't/ 11887' at 5 mind stand. 550 GPM,1740 PSI
start, 1650 PSI end, 100 RPM, 25K TQ start, 18K TQ end. 155K PU / 75K SO. 7 BPH loss average.,BROOH f/ 11887' V 9315' at 5 min / stand. 545 GPM,
1620 PSI start, 1550 PSI end, 100-110 RPM, 16K TO start, 13K TO end. 149K PU / 84K SO. 11 BPH loss average.,Daily (midnight) losses to formation = 102
bbls, cumulative losses for interval = 798 bbls-Hauled 0 bbls H2O from M -Pad (Nopoint Creek) for total= 4715 bbls
Hauled 590 bbls H2O from L -Pad Lake for total = 4865 bbls
Hauled 0 bbls heated H2O from G&I for total = 865 bbls
Hauled 2297 blots cutting/liquids to MPU G&I for total= 16578 bbls
Hauled 0 bbls Pit Water from A -Pad for total = 2110 bbls
7/27/2019
BROOH f/ 9316Y 6652'@ 5 min/stand. 550 GPM, 1300 PSI, 120 RPM, 1 OK TO. 9.81 ppg ECD. 141 K PU / 97K SO.,BROOH f/ 6652't/ 4906' @ 5
ministand. 550 GPM, 1200 PSI, 110 RPM, 5K TQ„Shut down with closed MPD chokes. Observe 125 PSI. Bleed off 1 bbl over 5 min. then shut in at 14 PSI
and built to 42 PSI over 15 min. Bleed of for 5 min. then shut in at 14 PSI and built to 29 PSI over 15 min. Decided to weight up to 9.1 ppg..Pump hi -vis
sweep followed by 9.1 ppg brine, 8 BPM, 640 PSI, 80 RPM, 3K TO while reciprocating pipe 60'. Observed non-magnetic metal cuttings/shavings back with
sweep, 50% increase of cuttings. Circulate until good 9.1 ppg brine in and out. Shut down and observe no flow or pressure build up with MPD. Open 2” bleeder,
observe slight breathing starting at 2.14 BPH and static in 20 min.,PJSM w/ Beyond and Doyon. Remove MPD RCD and install trip nipple.,Slip and cut 92' of
drilling line. Monitor well on the trip tank.,PJSM, mobilize thread protectors to the rig floor. Install stripping rubber and air slips. UD 5" drill pipe ft 493T t/ 4843'.
130K PU / 120K SO. 2 BPH Iosses.,Service top drive, draw works and blocks. 2 BPH Iosses.,Rig repair. Replace wiring for pipe skate control on the rig floor. 2
BPH losses., UD 5" drill pipe f/ 4843' U 1020'. 73K PU / 71 K SO. 3.5 BPH losses., Hauled 0 bible H2O from M -Pad (Nopoint Creek) for total= 4715 bbls
Hauled 425 bbls H2O from L -Pad Lake for total = 5290 bible
Hauled 0 bbls heated H2O from G&I for total = 865 bbis
Hauled 169 bbls cutting/liquids to MPU G&I for total= 16747 bbls
Hauled 0 bbls Pit Water from A -Pad for total = 2110 bbls,Daily (midnight) losses to formation = 120 bats, cumulative losses for interval = 918 bbls. "' Notified
AOGCC of upcoming BOP test at 05:20 on 7/27/2019 "`"
7/2x/2019
TOOH laying down 5" drill pipe f 1020'to 274'. UD jars, HWDP & drill collars to 86'. Read MWD tools - 100% recovery of data. L/D remainder of BHA f/ 861.
Bit graded 1 -1 -BT -A -C -1 -NO -TD. Wear observed on all wear bands and stabilizers. 4 BPH loss average.,Clean and clear rig floor. M/U stack washer and flush
stack. Pull wear bushing.,Rig up to test BOP equipment. Install test plug and test joint. Fill stack and choke manifold. Obtain good body test.'"" State's right to
witness testing was waived by AOGCC inspector Austin McLeod at 08:11 on 28 July 2019'"',Test BOPS as per PTD and AOGCC requirements. All test
performed with fresh water to 250 PSI low / 3000 PSI high. #1.Upper 4-1/2"x7" VBR with 5" test joint, Upper IBOP, 3" Demco kill, choke valves 1, 12,13 & 14
(passed) #2.HCR Kill, choke valves 9 & 11, Lower ISOP (passed) #3.Manual Will, 5" FOSV, choke valves 5, 8 & 10 (fail/pass o -ring on FOSV test cap) #4 5" dart
valve, choke valves 4, 6 & 7 (passed)_#5. Choke valve #2 (passed) #6HCR choke (passed) #71 -ower 2-7/8"x5" VBR on 5" test joint (passed) #8 Annular on
3-1/2" test joint and manual choke (passed) #91ower 24/8"x5" VBR on 3-1/2" test joint (passed) #10 Blind rams and choke valve 3 (passed) #11 Hydraulic
choke A (passed) #12 Manual choke B (passed).,Accumulator Test: System pressure = 3100 psi, Pressure after closure = 1800 psi, 200 psi attained in 39
seconds, Full pressure attained in 183 seconds, Nitrogen Bottles - 6 at 2050 psi.,R/D test equipment, pull test plug and install wear bushing. Blow down all
lines. Remove split bushings and install master bushings. Start hole fill with trip tank.,L/D 27 stands of 5" drill pipe from the derrick in the mousehole. 3.5 BPH
loss average.,Load 60 joints of 5" HWDP in the pipe shed. WU Johnny Wacker. RIH with 60 singles of 5" HWDP to 1820'. 115K PU / 115K SO. POOH racking
back 20 stands of 5" HWDP. 2.5 BPH loss average.,Clear rig floor of thread protectors. Mobilize 4-1/2" casing equipment to the rig floor. R/U elevators, slips
and Doyon casing double stack tongs. M/U 4-1/2" IF x 4-1/2" H625 XO to FOSV. 2.5 BPH loss average.,Hauled 0 blots H2O from M -Pad (Nopoint Creek) for
total= 4715 bbls
Hauled 160 bbls H2O from L -Pad Lake for total = 5450 bbls
Hauled 0 bbls heated H2O from G&I for total = 865 obis
Hauled 110 bible cutting/liquids to MPU G&I for total= 16857 bats
Hauled 0 bbls Pit Water from A -Pad for total = 2110 bbls
Hauled 100 bbls H2O from L-2 Lake for total = 100 bbls, Daily (midnight) losses to formation = 60.6 bbls, cumulative losses for interval = 978.6 bbis.
7/29/2019
PJSM. M/U 4-1/2" shoe joint: float shoe, WIV, tubing joint w/ 2 each 7.1" centralizers, pack -off and XO pup joint to 40'. Run 4-1/2" 13.5# L-80 Hydril 625
Wedge liner as per tally f/ 40' V 1678'. Torque to 9600 ft/lbs w/ Doyon double stack tongs. One stop ring & 7.5" O.D. centralizer on each joint. 2 BPH avg.
losses., Rig service. Repair pipe skate carriage idler gear. 2 BPH avg. Iosses.,Run 4-112" 13.5# L-80 Hydril 625 Wedge liner as per tally f/ 1678' t/ 4914'. Torque
to 9600 ft/lbs w/ Doyon double stack tongs. One stop ring & 7.5" O.D. centralizer on each joint. 90K PU / 80K SO at the 9.5/8" casing shoe. 3 BPH avg.
Iosses.,Rig repair: Pipe skate hydraulic cooling fan blade broke. Remove fan motor assembly and replace. 2.5 BPH avg. losses., Run 4-112" 13.5# L-80 Hydril
625 Wedge liner as per tally f/ 4914' U 8066'. Torque to 9600 ft/lbs w/ Doyon double stack tongs. One stop ring & 7.5" O.D. centralizer on each joint. 95K PU /
70K SO 2.5 BPH avg. losses., Run 4-1/2" 13.5# L-80 Hydril 625 Wedge liner as per tally f/ 8066' t1 11551'. Torque to 9600 ft/lbs w/ Doyon double stack longs.
One stop ring & 7.5" O.D. centralizer on each joint. 110K PU / 68K SO. 3 BPH avg. losses.,262 joints of 4-1/2" liner ran, 277 each 7.5" O.D. centralizers and
277 stop rings free-floating on the liner and [CDs. 2 each 7.1" O.D. centralizer with 4 stop rings on the 4.5" shoe joint., Hauled 0 bbis H2O from M -Pad (Nopoint
Creek) for total= 4715 bbls
Hauled 0 blols H2O from L -Pad Lake for total = 5450 bbis
Hauled 0 bbis heated H2O from G&I for total = 865 bbis
Hauled 0 bbis cutting/liquids to MPU G&I for total= 16857 bbls
Hauled 0 bbis Pit Water from A -Pad for total = 2110 bbis
Hauled 40 Jobs, H2O from L-2 Lake for total = 140 bbl, Dail midni ht losses to formation = 59 bbl, cumulative losses for interval = 1034.
7/30/2019
PJSM, With liner set in compression. Prep to run inner string. Load tools to rig floor. C/O to 2-3/8" handling equipment, R/U false table and power tongs. Install
swivel on safety jt with triple connect.,M/U slick stick, coupling and XO, drift, P/U and RIH with 2-3/8" 4.7# H503 inner string to 5773'. Torque to 1800 ft/lbs
with Doyon double stack tongs.
Monitor well with trip tank, 1.5 bph static loss rate
63K PU / 57K SO with inner string,P/U 5" safety joint & break off triple connect. UD safety joint. C/O elevators & and tongs. P/U 5" drill pipe joint. MIU triple
connect.
Break over 4-112" liner string with 130K. 120K PU 185K SO.
RID triple connect. UD 5" drill pipe joint, C/O elevators and tongs. P/U 5" safety joint & M/U triple connect.,Run 2-3/8" 4.7# H503 inner string f/ 5773' 1111527"
observed slick stick entering pack -off at 11513' and tagged no go w/ 5K at 11527'.
Torque to 1800 ft/lbs with Doyon double stack tongs.
Monitor well with trip tank, 1.6 bph static loss rate,Space out: UD two joints and pick-up 4 pup joints: 10.12% 4.13', 4.12' & 4.07' with 4-112" cross over w/ 2-
3/8"swivel and XO to 2-3/8" inner string.
M/U Baker 7"x9-5/8" SLZXP liner top packer w/ 7.375 seal, bore 7" x 9-5/8". Hyd setting tool - 8x 1/2" screws set at 2648 psi, 15% Brass.
RIH to 11588'. 130K PU / 80K SO.
1.5 BPH losses., Hauled 0 bbis H2O from M -Pad (Nopoint Creek) for total= 4715 bola
Hauled 25 bbls H2O from L -Pad Lake for total = 5475 bbis
Hauled 0 blots heated H2O from G&I for total = 865 bola
Hauled 0 bbls cutting/liquids to MPU G&I for total= 16857 bbis
Hauled 0 bbis Pit Water from A -Pad for total = 2110 blots
W ... I.H n Kh1s H20 from L-2 Lake for total = 140 bbIs.Da ly (m dn aht) losses to formation = 59 bbls. cumulative losses for interval = 10936
7/31/201
" in'ectio r on 5" HWDP f/ 11 588' t/ 11650'. Verify pipe not filling through WIV. Obtain parameters: 125K PU / 85K SO 1110 ROT, 20 RPM,
71K TO. Pump 1 BPM, 600 PSI, 2 BPM, 850 PSI, 3 BPM, 1340 PSI. Pumped 5 bbls to ensure clear flow path„RIH w/ 4-1/2" injection liner on 5" HWDP f/
11650' U 16218' at 30' per min. ( 90 jts and 20 stds HWDP ) WU std OP, tag TO on depth @ 16300', set down 20k to verify on bottom. PU to 240k putting
string in tension. Fill pipe on the fly and top off every 5 stands. PU 245K, SO 145K 135.6 blot total losses running Iiner.,Drop 1.25" phenolic ball, m/u top drive,
R/U test pump and chart recorder. Pump 15 bbl hi vis sweep, Pump down at 3 BPM, 1350 PSI. Slow to 2 BPM, 1160 PSI for last 10 blols. Ball on seat at 752
strokes. Pressure up to 2700 psi close WIV and set packer. Pressure to 3000 psi hold 5 min. Slack off from 225K to 75K.,Pressure up & neutralize pusher tool
@ 4900 PSI w/ test pump. S/O to 40K and hold for 5 min, bleed off pressure. Break over w/ 235K PU. Close upper pipe rams & test annulus x 7"x 9-5/8"
packer to 1600 PSI for 10 min. - good test. Open UPR, P/U to 16272' & verify release. TOL @ 4722'.,UD single, Blow down kill and choke lines, RID test
equipment. Mix and pump dry job, BD TD. Static loss rate 3 bph.,PJSM, TOOH UD 2jts 5" OP, UD 5" HWDP f/ 16218' U 15566'. 3 BPH loss rate.,Rig repair:
Change out operating lever for pipe skate control on the rig floor.,TOOH UD 5" HWDP f/ 15566' U 11588'. 65K PU. i BPH loss rate.,Clear rig floor & mobilize 2-
3/8" equipment and thread protectors to the rig floor. R/U 2-3/8" tongs, slips and elevators. 2 BPH loss rate.,Break down and UD Baker running tool. UD 4
tubing pup joints. Changed double stack casing dies multiple times to break out XOs on running tool. 2 BPH loss rate.,UD 2-3/8" inner string tubing f/ 11490' t/
10945' with Doyon double stack tongs. Pipe wet, spin out slow due to brine spraying out of threads. 2 BPH loss rate.,Well control drill. PIU safety joint and
secure well in 2 min. 40 sec. Pump 5 bbl 10.1 ppg dry job, blow down and UD safety joint. 2 BPH loss rate.,UD 2-3/8" inner string tubing f/ 10945' t/ 10669'
with Doyon double stack tongs. 2 BPH loss rate.,Hauled 0 bbls H2O from M -Pad (Nopoint Creek) for total= 4715 bbis
Hauled 20 bbis H2O from L -Pad Lake for total = 5495 bbis
Hauled 0 blots heated H2O from G&I for total = 865 bbis
Hauled 55 bola cutting/liquids to MPU G&I for total= 16912 bbis
Hauled 0 bbis Pit Water from A -Pad for total = 2110 blols
Hauled 0 bbis H2O from L-2 Lake for total = 140 bbls,Daily (midnight) losses to the formation = 53 bbis, cumulative losses for interval = 1146.60
8/1/2019
TOOH UD 2-3/8" inner string tubing H 10669' to 5771' with Doyon double stack tongs. 2 BPH loss rate.,Continue UD 2-3/8" inner string tubing f/ 5771' to 16'
with Doyon double stack tongs. UD XO and slick stick. 2 bph loss rate.,R/D 2-3/8" casing equipment. Clean & clear rig floor. Break down safety joint. 1.5 BPH
loss rate -Remove wear bushing. Perform dummy run with 3-1/2" hanger on 5" drill pipe landing joint. Mark landing joint for completion run. UD landing joint
and hanger. Re -install wear bushing. M/U FOSV, pump in sub & 5' pup joint on landing joint for upcoming completion. 1 BPH loss rate., UD 44 stands of 5" drill
pipe from the derrick via the mouse hole. 2 BPH loss rate., Hauled 0 bbis H2O from M -Pad (Nopoint Creek) for total= 4715 bbis
Hauled 120 bbis H2O from L -Pad Lake for total = 5615 bbls
Hauled 0 bbls heated H2O from G&I for total = 865 bbis
Hauled 145 bbis cutting/liquids to MPU G&I for total= 17057 bbis
Hauled 0 bbis Pit Water from A -Pad for total = 2100 bbls
Hauled 0 bbis H2O from L-2 Lake for total = 240 bbls,Daily (midnight) losses to the formation = 40 bbis, cumulative losses for interval = 1186.60
8/2/2019
M/U 3 1/2" perforated cleanout tool with 8.25" nogo and XO, TIH with stands 5" DP to 4685', M/U stand #50 and top drive. Correct displacement on TIH. PU
127K, SO 115K.,Pump 2 bpm, 150 psi, wash down with wash tool entering TOL @ 4722', wash down 14tagging nogo on depth, P/U nogo just off TOL,
increase to 7 bpm, 220 psi flushing out seal bore, P/U to 4719' with wash tool just above TOL., PJSM, Pump 30 bbl hi vis spacer, Displace w/ 406 bbls clean
9.1 ppg brine 7 bpm, 140 psi. 30 rpm, 4k torque reciprocating pipe, take dirty returns to rock washer, pumped 83 bbls over calculated displacement until clean
returns. Observed 25% increase across the shakers of sand when spacer came back. No losses -Get new SPRs both mud pumps, Flow check well, 1 bph
static Ions rate, UD 3 singles to 4676', BD TD.,Hang blocks, slip and cut 60' drilling line, re -calibrate block height. Monitor well, 3/4 bph loss rate.,PJSM, TOOH
UD 5" drill pipe f/ 4676' to surface, Break down and UD Flush tool and nogo. Loss rate 2 bph TOOH - 11 bbis total for trip out. Note: AOGCC rep Adam Earl
waived witness @ 15:28 today for upcoming MIT.,Pull wear bushing. Install XO on FOSV. R/U 3-1/2" elevators, slips and hydraulic double stack tongs.
Mobilize Schlumberger equipment to the rig floor. Hang sheave and R/U TEC wire. i BPH lOsses.,PJSM with all parties involved. P/U and run Baker bullet seal
assembly, 1 jt. of 3-1/2" tubing, Schlumberger gauge mandrel and 1 jt. of 3-1/2" tubing to 106. Install SLB gauge and pressure test to 5700 PSI for 5 min. -
good test. 1 BPH Iosses.,Run 3-1/2" 9.3# L-80 EUE tubing f/ 105' t/ 4075' as per tally. Torque to 3100 ft/lbs with Doyon double stack tongs. Install cross
coupler Cannon clamp on everyjoint to secure TEC wire. Continuous monitoring of gauge while running. 1 BPH Iosses.,Hauled 0 bbls H2O from M -Pad
(Nopoint Creek) for total= 4715 bbls
Hauled 0 bbis H2O from L -Pad Lake for total = 5615 bbis
Hauled 0 bbls heated H2O from G&I for total = 865 bbis
Hauled 603 bbis cutting/liquids to MPU G&I for total= 17660 bbis
Hauled 0 bbls Pit Water from A -Pad for total = 2100 bbis
Hauled 0 bbis H2O from L-2 Lake for total = 410 bbls, Daily (midnight) losses to the formation = 27 bbis, cumulative losses for the interval = 1207.6 bbis.
Rig fuel (gallons) = 0 received, 945. used, 3770 on hand.
8/3/2019
Run 3-1/2" 9.3# L-80 EUE tubing f/ 4075' U 4718' at R 152, Torque to 3100 fl/lbs with Doyon double stack tongs. Install cross coupler Cannon clamp on every
joint to secure TEC wire. Continuous monitoring of gauge while running. 1 BPH losses., M/U jt 153. RI and no go out 19' in @ 4736', close bag and pressure
up 400 psi on backside to verify seals engaged, good, bleed off pressure, open bag. 7.5 bbl total losses running tbg. PU 75K, SO 70K.,UD jts 153, 152 and
151, space out with 3 pup joints 6.56', 4.34' and 2.16', M/U jt 151, C/O to 5" elevators, M/U hanger with pup and landing jt. SLB get final reading and
terminate tech wire to hanger. Drain stack. Land with mule shoe @ 4735.52' (1.45' off no go ) P/U 2.5', R/U FOSV, circ sub and 5' pup it. close bag and
\
pressure up to 500 psi, P/U and observe pressure bleed off thru circulation ports.,152 cross coupler Cannon clamps and 2 half clamps mn.,PJSM with Doyon,
M-1 and Peak. Test lines to 3000 psi. Reverse circulate 180 bbis corrosion inhibited 9.1 ppg brine @ 3.2 BPM, 350 PSI, Pump down OA taking returns out of
the 3 1/2" tbg, Line up and reverse circ 135 bbls diesel from vac truck 3 bpm, 260 psi ICP freeze protecting 9 5/8" x 3 1/2" annulus to 2100' FCP 500 psi,
\
SIO closing ports, drain stack to cellar. Land hanger w/ 30k on Hanger, RILDS.,R/D pump in sub and XO, R/U test equipment, pre-injection MIT 31/2" x 9 5/8
annulus with diesel to 3000 psi for 30 charted min. good test, bleed off pressure. AOGCC representative Adam Earl waived witness of the test.,R/D test
equipment, Blow down choke and kill lines, drain gas buster, back out and UD landing jt, WH rep install BPV.,Flush flowline, R/D drip pan, MPD head and 4"
line., had to remove accumulator lines to lower MPD head. Re -attached accumulator Iines.,Open ram cavity doors, function rams to closed position, remove
rams, clean cavities and close ram doors., PJSM, install "potato masher' on annular. Utilize rig tongs to break annular cap through potato masher and back out
one full turn. UD potato masher.,Attach bridge cranes, remove turnbuckles and N/D BOP stack., Hauled 0 bbis H2O from M -Pad (Nopoint Creek) for total= 4715
bbis
Hauled 0 bbis H2O from L -Pad Lake for total = 5615 bbis
Hauled 0 bbis heated H2O from G&I for total = 865 bbis
Hauled 400 bbis cutting/liquids to MPU G&I for total= 18060 bbls
Hauled 0 bbls Pit Water from A -Pad for total = 2100 bbis
Hauled 0 bbis H2O from L-2 Lake for total = 410 bbis
Hauled 260 bbis H2O from 6 Mile for total = 260 bbls,Daily (midnight) losses to the formation = 12.5 bbis, cumulative losses for interval = 1220.1 bbls.
U LSD fuel (gallons): received = 41 W. used = 420, on hand = 7530
8/4/2019
Install dart in BPV, set adaptor flange and tree on wellhead, SLB rep terminate tech wire to adaptor flange, take final reading, ( pressure 1728.31 psi, temp
76.17 ) NIU adaptor flange and tree, WH rep test hanger void to 250 psi f/ 5 min, 5000 psi f/ 10 min., R/U test equipment, test tree with diesel to 250/5000 psi 5
min each.,WH rep remove dart from BPV. R/D test equipment.,Crew change, PJSM, freeze protect 3 1/2" tubing to 2100', bull head 19 bbls diesel down tubing
2 bpm, ICP 360 psi, FCP 460 psi, secure tree.,Blow down pumps & rig down lines. Clean out cellar box and secure cellar area. Clean in pits„RID floor and skid
into move position, move rock washer.,Jack up rig, pull shims, move off well, set matting boards over buried flow lines, remove herculite, clear rig mats from
around well. Move to other side of the pad and stage on rig mats/containment for maintenance. Skid rig floor into drilling position.,Rig maintenance: prepare
outside of the rig and begin taking hopper room apart.,Clear rig floor of bails, mousehole and XO's. Disassembly top drive grabber, saver sub, lower and upper
IBOP's. Drain oil from mud pumps. Remove mix hoppers, plumbing and agitator from the hopper room. Clean and prepare for welder. Begin disassembling
BOP stack for inspection.,Hauled 0 bbis H2O from M -Pad (Nopoint Creek) for total= 4715 bbls
Hauled 0 bbls H2O from L -Pad Lake for total = 5615 bbis
Hauled 0 bbis heated H2O from G&I for total = 865 bbis
Hauled 295 bbls cutting/liquids to MPU G&I for total= 18355 bbis
Hauled 0 bbls Ph Water from A -Pad for total = 2100 bbis
Hauled 0 bbls H2O from L-2 Lake for total = 410 bbls
Hauled 40 bbls H2O from 6 Mile for total = 300 bbls,Rig fuel (gallons): recd = 0, used = 575, on hand = 6955
Daily losses to the formation = 19 bbis, cumulative losses for interval = 1239.1 bbis.
Rig released at 06:00 815/2019.
Hilcorp Alaska, LLC
Milne Point
M Pt Moose Pad
MPU M-13i
500292363800
Sperry Drilling
Definitive Survey Report
29 July, 2019
HALLIBURTON
Sperry Drilling
Halliburton
Definitive Survey Report
Company:
Hilcorp Alaska, LLC
Local Co-ordinate Reference:
Well MPU W13
Project:
Milne Point
TVD Reference:
MPU M-13 Actual RKB @ 58.85usft
Site:
M Pt Moose Pad
MD Reference:
MPU M-13 Actual RKB @ 58.85usft
Well:
MPU M-13
North Reference:
True
Wellbore:
MPU M -13i
Survey Calculation Method:
Minimum Curvature
Design:
MPU M-13
Database:
NORTH US+CANADA
3roject Milne Point, ACT, MILNE POINT
Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level
Seo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point
Map Zone: Alaska Zone 04 Using geodetic scale factor
Well MPU M-13
Well Position +NIS 0.00 usft Northing:
+E/ -W 0.00 usft Easting:
Position Uncertainty 0.00 usft Wellhead Elevation:
Wellbore MPU M -13i
Magnetics Model Name Sample Date
BGGM2018 7/15/2019
6,027,765.70 usfl Latitude: 70° 29'12.776 N
533,993.84 usfl Longitude: 149'43'19.766 W
0.00 usfl Ground Level: 24.70 usft
Declination Dip Angle Field Strength
(% V) (nT)
16.55 80.95 57,420.18296261
Design MPU M-13
Date
Audit Notes:
Version: 1.0
Phase:
ACTUAL
Vertical Section:
Depth From (TVD)
+NIS
(usft)
(usft)
34.15
0.00
Tie On Depth: 34.15
+E/ -W Direction
(usft) (1)
0.00 124.92
Survey Program
Date
7/26/2019
From
To
(usft)
(usft)
Survey (Wellbore)
Tool Name
Description
Survey Dale
208.52
4,875.30 MPU
M-13 MWD+IFR2+MS+sag
(1) (MP 2_MWD+IFR2+MS+Sag
A013Mb: IIFR dec & multi -station analysis +sa 06/28/2019
4,900.00
16,229.10
MPU
M-13 MWD+IFR2+MS+Sag
(2) (MF
2_MWD+IFR2+MS+Sag
A013Mb: IIFR dec & multi
-station analysis + sa 07/19/2019
Survey
Map
Map
Vertical
MD
Inc
Azi
TVD
TVDSS
+N/S
+FJ -W
Northing
Easting
DLS
Section
(usft)
V)
(1)
(usft)
(usft)
(usft)
(usft)
(ft)
(ft)
(°1100')
(ft) Survey Tool Name
34.15
0.00
0.00
34.15
-24.70
0.00
0.00
6,027,765.70
533,993.84
0.00
0.00 UNDEFINED
208.52
0.37
44.98
208.52
149.67
0.40
0.40
6,027,766.10
533,994.24
0.21
0.10 2_MWD+IFR2+MS+Sag (1)
303.82
0.57
57.26
303.82
244.97
0.87
1.01
6,027,766.58
533,994.85
0.23
0.33 2_MWD+IFR2+MS+Sag(1)
392.55
0.51
62.60
392.54
333.69
1.29
1.74
6,027,767.00
533,995.57
0.09
0.68 2_MWD+IFR2+MS+Sag(1)
486.82
0.75
91.89
486.81
427.96
1.47
2.73
6,027,767.18
533,996.56
0.42
1.40 2_MWD+IFR2+MS+Sag(1)
578.24
2.57
146.68
578.19
519.34
-0.27
4.45
6,027,765.45
533,998.29
2.43
3.80 2_MWD+IFR2+MS+Sag(1)
671.79
5.43
155.28
671.50
612.65
-6.04
7.45
6,027,759.69
534,001.32
3.12
9.57 2_MWD+IFR2+MS+Sag(1)
765.66
7.95
147.93
764.73
705.88
-15.58
12.76
6,027,750.18
534,006.67
2.83
19.38 2_MWD+IFR2+MS+Sag(1)
862.65
12.06
138.92
860.23
801.38
-28.91
22.98
6,027,736.90
534,016.95
4.52
35.39 2_MWD+IFR2+MS+Sag(1)
956.49
14.65
126.97
951.54
892.69
43.44
38.91
6,027,722.44
534,032.95
4.02
56.77 2 MWD+IFR2+MS+Sag(1)
1,052.36
18.06
118.95
1,043.53
984.68
-57.93
61.61
6,027,708.06
534,055.71
4.26
83.68 2_MWD+IFR2+MS+Sag(1)
1,146.60
22.56
115.66
1,131.89
1,073.04
-72.84
90.70
6,027,693.29
534,084.87
4.92
116.07 2_MWD+IFR2+MS+Sag(1)
1,243.00
27.76
114.68
1,219.11
1,160.26
-90.23
127.80
6,027,676.06
534,122.03
5.41
156.44 2_MWD+IFR2+MS+Sag(1)
7/292019 6:01:46PM
Page 2
COMPASS 5000.15 Build 91
Survey
Halliburton
Definitive Survey Report
Map
Company:
Hilcorp Alaska, LLC
Local Co-ordinate Reference:
Well MPU M-13
Project:
Milne Point
TVD Reference:
MPU M-13 Actual RKB @ 58.85usft
Site:
M Pt Moose Pad
MD Reference:
MPU M-13 Actual RKB @ 58.85usft
Well:
MPU M-13
North Reference:
True
Wellbore:
MPU M -13i
Survey Calculation Method:
Minimum Curvature
Design:
MPU M-13
Database:
NORTH US+CANADA
Survey
Map
Map
Vertical
MD
Inc
Azi
TVD.
TVDSS
+NIS
+E/ -W
Northing
Easting
DLS
Section
(usft)
(°)
(°)
(usft)
(usft)
(usft)
(usft)
(ft)
(ft)
(°I10o')
(ft) Survey Tool Name
1,337.14
28.86
118.65
1,302.00
1,243.15
-110.28
167.66
6,027,656.20
534,161.99
2.32
200.60 2_MWD+IFR2+MS+Sag (1)
1,431.80
26.60
118.55
1,385.78
1,326.93
-131.36
206.33
6,027,635.29
534,200.75
2.39
244.38 2_MWD+IFR2+MS+Sa9 (1)
1,526.66
25.61
119.25
1,470.96
1,412.11
-151.53
242.87
6,027,615.30
534,237.38
1.09
285.88 2_MWD+IFR2+MS+Sag(1)
1,621.38
25.49
117.68
1,556.42
1,497.57
-171.00
278.78
6,027,595.99
534,273.37
0.73
326.47 2_MWD+IFR2+MS+Sag(1)
1,716.18
25.02
116.40
1,642.16
1,583.31
-189.39
314.80
6,027,577.77
534,309.47
0.76
366.54 2_MWD+IFR2+MS+Sag(1)
1,811.27
24.55
115.16
1,728.49
1,669.64
-206.73
350.69
6,027,560.59
534,345.44
0.74
405.89 2_MWD+IFR2+MS+Sag(1)
1,906.85
25.31
115.67
1,815.17
1,756.32
-224.02
387.08
6,027,543.47
534,381.90
0.83
445.63 2_MWD+IFR2+MS+Sag(1)
2,001.67
26.99
116.72
1,900.28
1,841.43
-242.48
424.57
6,027,525.19
534,419.47
1.84
486.93 2_MWD+IFR2+MS+Sag(1)
2,096.89
28.41
116.46
1,984.58
1,925.73
-262.29
464.15
6,027,505.56
534,459.14
1.50
530.73 2_MWD+IFR2+MS+Sag(1)
2,192.69
28.02
116.30
2,069.00
2,010.15
-282.41
504.73
6,027,485.62
534,499.80
0.41
575.52 2_MWD+IFR2+MS+Sag(1)
2,288.31
27.50
113.90
2,153.62
2,094.77
-301.31
545.05
6,027,466.91
534,540.21
1.29
619.39 2_MWD+IFR2+MS+Sag(1)
2,383.68
27.11
114.14
2,238.36
2,179.51
-319.12
585.01
6,027,449.29
534,580.24
0.42
662.35 2_MWD+IFR2+MS+Sag (1)
2,478.73
27.03
114.51
2,323.00
2,264.15
-336.93
624.42
6,027,431.66
534,619.74
0.20
704.87 2_MWD+IFR2+MS+Sag(1)
2,573.40
27.02
115.02
2,407.33
2,348.48
-354.95
663.48
6,027,413.82
534,658.87
0.25
747.21 2_MWD+IFR2+MS+Sag(1)
2,668.23
26.36
115.39
2,492.06
2,433.21
-373.09
702.02
6,027,395.86
534,697.49
0.72
789.19 2_MWD+IFR2+MS+Sag(1)
2,764.36
27.21
115.48
2,577.87
2,519.02
-391.70
741.14
6,027,377.43
534,736.69
0.89
831.92 2_MWD+IFR2+MS+Sag(1)
2,859.33
27.93
116.57
2,662.06
2,603.21
410.99
780.64
6,027,358.33
534,776.27
0.93
875.35 2_MWD+IFR2+MS+Sag(1)
2,953.90
28.55
116.44
2,745.37
2,686.52
330.96
820.68
6,027,338.54
534,816.40
0.66
919.61 2_MWD+IFR2+MS+Sag(1)
3,050.03
27.36
113.95
2,830.29
2,771.44
350.15
861.44
6,027,319.53
534,857.24
1.73
964.02 2_MWD+IFR2+MS+Sag(1)
3,144.71
27.44
113.83
2,914.34
2,855.49
367.80
901.28
6,027,302.07
534,897.16
0.10
1,006.79 2_MWD+IFR2+MS+Sag(1)
3,240.36
27.10
114.61
2,999.36
2,940.51
385.77
941.25
6,027,284.28
534,937.20
0.52
1,049.85 2_MWD+IFR2+MS+Sag(1)
3,335.94
28.16
115.02
3,084.04
3,025.19
-504.38
981.48
6,027,265.86
534,977.52
1.13
1,093.49 2_MWD+IFR2+MS+Sag(1)
3,432.04
30.93
115.39
3,167.64
3,108.79
-524.56
1,024.35
6,027,245.87
535,020.47
2.89
1,140.19 2_MWD+IFR2+MS+Sag(1)
3,525.14
34.32
115.68
3,246.04
3,187.19
-546.20
1,069.63
6,027,224.45
535,065.85
3.65
1,189.71 2_MWD+IFR2+MS+Sag(1)
3,622.17
37.06
116.96
3,324.84
3,265.99
-571.32
1,120.35
6,027,199.57
535,116.68
2.93
1,245.67 2_MWD+IFR2+MS+Sag(1)
3,719.75
40.77
119.02
3,400.75
3,341.90
-600.12
1,174.44
6,027,171.02
535,170.90
4.03
1,306.51 2_MWD+IFR2+MS+Sag(1)
3,812.20
44.06
121.08
3,469.00
3,410.15
-631.36
1,228.39
6,027,140.02
535,224.98
3.86
1,368.63 2_MWD+IFR2+MS+Sag(1)
3,907.50
45.24
122.37
3,536.80
3,477.95
-666.59
1,285.35
6,027,105.06
535,282.09
1.56
1,435.50 2_MWD+IFR2+MS+Sag(1)
4,003.37
49.33
122.92
3,601.82
3,542.97
-704.58
1,344.64
6,027,067.34
535,341.55
4.29
1,505.87 2_MWD+IFR2+MS+Sag(1)
4,098.24
55.86
120.99
3,659.42
3,600.57
-744.40
1,408.57
6,027,027.82
535,405.66
7.07
1,581.08 2_MWD+IFR2+MS+Sag(1)
4,192.95
60.19
123.57
3,709.57
3,650.72
-787.32
1,476.44
6,026,985.21
535,473.72
5.12
1,661.30 2_MWD+IFR2+MS+Sag(1)
4,285.31
63.05
122.77
3,753.46
3,694.61
-831.77
1,544.46
6,026,941.08
535,541.93
3.19
1,742.52 2_MWD+IFR2+MS+Sag(1)
4,383.25
66.52
125.12
3,795.18
3,736.33
-881.26
1,617.93
6,026,891.93
535,615.62
4.15
1,831.09 2_MWD+IFR2+MS+Sag(1)
4,478.05
72.31
126.06
3,828.50
3,769.65
-932.90
1,690.06
6,026,840.63
535,687.98
6.18
1,919.79 2_MWD+IFR2+MS+Sag(1)
4,572.85
75.40
125.32
3,854.86
3,796.01
-986.01
1,764.02
6,026,787.86
535,762.17
3.34
2,010.83 2_MWD+IFR2+MS+Sag(1)
4,668.58
79.50
125.35
3,875.66
3,816.81
-1,040.04
1,840.23
6,026,734.18
535,838.62
4.28
2,104.25 2_MWD+IFR2+MS+Sag(1)
4,763.42
85.30
125.07
3,888.20
3,829.35
-1,094.22
1,917.00
6,026,680.36
535,915.64
6.12
2,198.22 2_MWD+IFR2+MS+Sag(1)
4,859.53
87.28
124.25
3,894.41
3,835.56
-1,148.76
1,995.89
6,026,626.19
535,994.76
2.23
2,294.12 2_MWD+IFR2+MS+Sag(1)
4,875.30
88.51
124.14
3,894.99
3,836.14
-1,157.62
2,008.92
6,026,617.39
536,007.83
7.83
2,309.88 2_MWD+IFR2+MS+Sag(1)
4,961.69
90.81
123.59
3,895.51
3,836.66
-1,205.75
2,080.65
6,026,569.59
536,079.77
2.74
2,396.25 2_MWD+IFR2+MS+Sag (2)
7/292019 6:01:46PM
Page 3
COMPASS 5000.15 Build 91
Survey
Halliburton
Definitive Survey Report
Map
Company:
Hilcorp Alaska, LLC
Local Coordinate Reference:
Well MPU M1-13
Project:
Milne Point
TVD Reference:
MPU M-13 Actual RKB @ 58.85usft
Site:
M Pt Moose Pad
MD Reference:
MPU M-13 Actual RKB @ 58.85usft
Well:
MPU M-13
North Reference:
True
Wellbore:
MPU M -13i
Survey Calculation Method:
Minimum Curvature
Design:
MPU M-13
Database:
NORTH US+CANADA
Survey
Map
Map
vertical
MD
Inc
AzI
TVD
TVDSS
+N/ -S
+EI -W
Northing
Easting
DLS
Section
(usft)
(1
(`)
(usft)
(usft)
(usft)
(usft)
(ft)
(ft)
(°/100')
(ft) Survey Tool Name
5,056.56
89.63
122.80
3,895.14
3,836.29
-1,257.69
2,160.04
6,026,518.02
536,159.39
1.50
2,491.07 2_MWD+IFR2+MS+Sag(2)
5,152.30
89.08
123.54
3,896.22
3,837.37
-1,310.07
2,240.17
6,026,466.01
536,239.75
0.96
2,586.76 2_MWD+IFR2+MS+Sag (2)
5,247.37
88.71
124.72
3,898.05
3,839.20
-1,363.40
2,318.85
6,026,413.05
536,318.67
1.30
2,681.80 2_MWD+IFR2+MS+Sag(2)
5,342.72
89.64
126.61
3,899.43
3,840.58
-1,418.98
2,396.30
6,026,357.82
536,396.37
2.21
2,777.13 2_MWD+IFR2+MS+Sag(2)
5,438.60
88.96
125.73
3,900.60
3,841.75
-1,475.57
2,473.70
6,026,301.60
536,474.01
1.16
2,872.97 2_MWD+IFR2+MS+Sag (2)
5,533.84
88.09
124.11
3,903.05
3,844.20
-1,530.06
2,551.76
6,026,247.47
536,552.31
1.93
2,968.18 2_MWD+IFR2+MS+Sag (2)
5,627.05
88.22
123.37
3,906.05
3,847.20
-1,581.81
2,629.23
6,026,196.08
536,630.01
0.81
3,061.32 2_MWD+IFR2+MS+Sag (2)
5,723.29
87.47
123.20
3,909.67
3,850.82
-1,634.59
2,709.62
6,026,143.67
536,710.64
0.80
3,157.45 2_MWD+IFR2+MS+Sag (2)
5,818.90
89.15
124.09
3,912.49
3053.64
-1,687.53
2,789.18
6,026,091.10
536,790.43
1.99
3,252.99 2_MWD+IFR2+MS+Sag (2)
5,914.08
87.97
123.55
3,914.88
3,856.03
-1,740.49
2,868.23
6,026,038.51
536,869.71
1.36
3,348.12 2_MWD+IFR2+MS+Sag(2)
6,009.78
85.67
124.90
3,920.19
3,861.34
-1,794.23
2,947.23
6,025,985.14
536,948.95
2.79
3,443.66 2_MWD+IFR2+MS+Sag(2)
6,105.18
86.43
126.26
3,926.76
3,867.91
-1,849.60
3,024.63
6,025,930.12
537,026.59
1.63
3,538.82 2_MWD+IFR2+MS+Sag(2)
6,200.03
86.30
126.30
3,932.77
3,873.92
-1,905.62
3,100.94
6,025,874.46
537,103.15
0.14
3,633.46 2_MWD+IFR2+MS+Sag (2)
6,295.56
86.55
126.35
3,938.73
3,879.88
-1,962.10
3,177.75
6,025,818.34
537,180.21
0.27
3,728.77 2_MWD+IFR2+MS+Sag (2)
6,391.08
86.36
126.45
3,944.64
3,885.79
-2,018.67
3,254.49
6,025,762.12
537,257.20
0.22
3,824.08 2_MWD+IFR2+MS+Sag (2)
6,486.68
88.47
126.97
3,948.95
3,890.10
-2,075.76
3,331.05
6025,705.40
537,334.01
2.27
3,919.53 2_MWD+IFR2+MS+Sag (2)
6,581.85
90.44
127.20
3,949.85
3,891.00
-2,133.14
3,406.96
6,025,648.37
537,410.18
2.08
4,014.62 2_MWD+IFR2+MS+Sag (2)
6,676.82
90.44
126.20
3,949.13
3,890.28
-2,189.89
3,483.10
6,025,591.97
537,486.57
1.05
4,109.54 2_MWD+IFR2+MS+Sag (2)
6,771.65
91.87
126.43
3,947.21
3,888.36
-2,246.04
3,559.50
6,025,536.17
537,563.21
1.53
4,204.32 2_MWD+IFR2+MS+Sag(2)
6,867.62
89.94
125.14
3,945.70
3,886.85
-2,302.15
3,637.33
6,025,480.43
537,641.30
2.42
4,300.26 2_MWD+IFR2+MS+Sag(2)
6,962.97
90.50
124.33
3,945.33
3,886.48
-2,356.47
3,715.69
6,025,426.47
537,719.89
1.03
4,395.61 2_MWD+IFR2+MS+Sag(2)
7,058.19
90.50
123.90
3,944.50
3,885.65
-2,409.88
3,794.52
6,025,373.43
537,798.96
0.45
4,490.82 2_MWD+IFR2+MS+Sag(2)
7,153.00
90.13
123.17
3,943.98
3,885.13
-2,462.25
3,873.55
6,025,321.42
537,878.22
0.86
4,585.60 2_MWD+IFR2+MS+Sag(2)
7,248.44
90.19
122.55
3,943.71
3,884.86
-2,514.04
3,953.72
6,025,270.01
537,958.62
0.65
4,680.97 2_MWD+IFR2+MS+Sag(2)
7,343.85
90.01
122.88
3,943.55
3,884.70
-2,565.60
4,033.99
6,025,218.82
538,039.12
0.39
4,776.31 2_MWD+IFR2+MS+Sag (2)
7,439.41
90.13
123.57
3,943.43
3,884.58
-2,617.96
4,113.93
6,025,166.83
538,119.29
0.73
4,871.83 2_MWD+IFR2+MS+Sag(2)
7,534.32
92.11
125.27
3,941.57
3,882.72
-2,671.59
4,192.20
6,025,113.56
538,197.79
2.75
4,966.71 2_MWD+IFR2+MS+Sag(2)
7,629.47
92.60
127.59
3,937.66
3,878.81
-2,728.05
4,268.69
6,025,057.46
538,274.53
2.49
5,061.74 2_MWD+IFR2+MS+Sag(2)
7,725.30
92.79
127.42
3,933.16
3,874.31
-2,786.33
4,344.62
6,024,999.53
538,350.72
0.27
5,157.37 2_MWD+IFR2+MS+Sag(2)
7,820.57
92.23
127.07
3,928.99
3,870.14
-2,843.93
4,420.39
6,024,942.28
538,426.75
0.69
5,252.47 2_MWD+IFR2+MS+Sag(2)
7,915.77
92.23
127.36
3,925.28
3,866.43
-2,901.46
4,496.15
6,024,885.10
538,502.76
0.30
5,347.52 2_MWD+IFR2+MS+Sag(2)
8,009.99
92.60
127.27
3,921.31
3,862.46
-2,958.53
4,571.02
6,024,828.39
538,577.88
0.40
5,441.57 2_MWD+IFR2+MS+Sag(2)
8,105.34
90.56
126.49
3,918.68
3,859.83
-3,015.73
4,647.25
6,024,771.54
538,654.37
2.29
5,536.82 2_MWD+IFR2+MS+Sag(2)
8,199.43
90.62
126.37
3,917.71
3,858.86
-3,071.60
4,722.95
6,024,716.02
538,730.32
0.14
5,630.88 2 MWD+IFR2+MS+Sag(2)
8,295.20
90.13
124.01
3,917.09
3,858.24
-3,126.78
4,801.21
6,024,661.20
538,808.82
2.52
5,726.64 2_MWD+IFR2+MS+Sag(2)
8,390.27
89.63
122.27
3,917.29
3,858.44
-3,178.76
4,880.81
6,024,609.60
538,888.65
1.90
5,821.66 2_MWD+IFR2+MS+Sag (2)
8,484.37
90.88
122.71
3,916.87
3,858.02
-3,229.30
4,960.18
6,024,559.42
538,968.24
1.41
5,915.67 2_MWD+IFR2+MS+Sag (2)
8,579.99
89.63
122.01
3,916.44
3,857.59
-3,280.48
5,040.95
6,024,508.62
539,049.23
1.50
6,011.19 2_MWD+IFR2+MS+Sag (2)
8,674.88
89.33
120.48
3,917.30
3,858.45
-3,329.69
5,122.07
6,024,459.78
539,130.57
1.64
6,105.88 2_MWD+IFR2+MS+Sag(2)
8,771.36
89.45
121.54
3,918.33
3,859.48
-3,379.40
5,204.76
6,024,410.46
539,213.47
1.11
6,202.13 2_MWD+IFR2+MS+Sag (2)
7/292019 6:01:46PM
Page 4
COMPASS 5000.15 Build 91
Halliburton
Definitive Survey Report
Company:
Hilwrp Alaska, LLC
Local Co-ordinate Reference: Well
MPU X-13
Project:
Milne Point
TVD Reference:
MPU
M-13 Actual RKB @ 58.85usft
Site:
M Pt
Moose Pad
MD Reference:
MPU
M-13 Actual RKB @ 58.85usft
Well:
MPU
M-13
North Reference:
True
Wellbore:
MPU
M-13i
Survey Calculation Method: Minimum
Curvature
Design:
MPU
M-13
Database:
NORTH
US+CANADA
Survey
Map
Map
Vertical
MD
Inc
Azi
TVD
TVDSS
+N/-S
+E/-W
Northing
Easting
DLS
Section
(usft)
(°)
(`)
(usft)
(usft)
lush)
(usft)
(ft)
(ft) (`/100')
(ft) Survey Tool Name
8,865.66
88.77
122.05
3,919.79
3,860.94
-3,429.07
5,284.90
6,024,361.15
539,293.83
0.90
6,296.27 2_MWD+IFR2+MS+Sag (2)
8,961.98
90.19
123.50
3,920.67
3,861.82
-3,481.21
5,365.87
6,024,309.39
539,375.04
2.11
6,392.52 2_MWD+IFR2+MS+Sag (2)
9,057.25
91.62
125.48
3,919.16
3,860.31
-3,535.15
5,444.38
6,024,255.82
539,453.79
2.56
6,487.77 2FMWD+IFR2+MS+Sag (2)
9,150.83
89.08
125.02
3,918.59
3,859.74
-3,589.15
5,520.80
6,024,202.17
539,530.44
2.76
6,581.33 2_MWD+IFR2+MS+Sag (2)
9,245.83
87.23
127.17
3,921.65
3,862.80
-3,645.08
5,597.51
6,024,146.60
539,607.40
2.98
6,676.26 2 MWD+IFR2+MS+Sag (2)
9,338.01
87.10
127.99
3,926.21
3,867.36
5,701.23
5,670.48
6,024,090.79
539,680.61
0.90
6,768.22 2_MWD+IFR2+MS+Sag(2)
9,436.43
87.22
126.89
3,931.09
3,872.24
5,760.99
5,746.52
6,024,031.39
539,758.93
1.12
6,866.42 2_MWD+IFR2+MS+Sag(2)
9,533.91
88.09
125.96
3,935.08
3,876.23
-3,818.82
5,826.89
6,023,973.93
539,837.55
1.31
6,963.79 2_MWD+IFR2+MS+Sag(2)
9,628.36
89.58
125.56
3,937.00
3,878.15
-3,874.00
5,903.52
6,023,919.10
539,914.42
1.63
7,058.21 2_MWD+IFR2+MS+Sag(2)
9,724.16
90.26
124.69
3,937.13
3,878.28
-3,929.12
5,981.87
6,023,864.35
539,993.02
1.15
7,154.00 2_MWD+IFR2+MS+Sag(2)
9,818.78
89.82
124.06
3,937.06
3,878.21
-3,982.54
6,059.97
6,023,811.29
540,071.35
0.81
7,248.62 2_MWD+IFR2+MS+Sag (2)
9,913.36
89.76
123.22
3,937.41
3,878.56
4,034.94
6,138.71
6,023,759.26
540,150.32
0.89
7,343.17 2_MWD+IFR2+MS+Sag (2)
10,004.54
90.81
124.88
3,936.96
3,878.11
4,085.99
6,214.25
6,023,708.56
540,226.08
2.15
7,434.34 2_MWD+IFR2+MS+Sag (2)
10,102.46
90.63
126.46
3,935.73
3,876.88
3,143.08
6,293.79
6,023,651.84
540,305.86
1.62
7,532.24 2_MWD+IFR2+MS+Sag (2)
10,197.07
90.63
127.60
3,934.69
3,875.84
3,200.05
6,369.31
6,023,595.22
540,381.65
1.20
7,626.78 2_MWD+IFR2+MS+Sag(2)
10,295.13
88.77
129.45
3,935.20
3,876.35
-4,261.12
6,446.02
6,023,534.50
540,458.63
2.68
7,724.63 2_MWD+IFR2+MS+Sag (2)
10,389.79
89.08
128.76
3,936.98
3,878.13
4,320.82
6,519.46
6,023,475.15
540,532.34
0.80
7,819.02 2_MWD+IFR2+MS+Sag(2)
10,483.88
89.02
127.83
3,938.54
3,879.69
3,379.12
6,593.30
6,023,417.19
540,606.43
0.99
7,912.94 2_MWD+IFR2+MS+Sag(2)
10,579.59
89.58
126.97
3,939.70
3,880.85
3,437.25
6,669.32
6,023,359.42
540,682.71
1.07
8,008.55 2_MWD+IFR2+MS+Sag(2)
10,673.51
89.51
127.83
3,940.45
3,881.60
3,494.29
6,743.93
6,023,302.72
540,757.58
0.92
8,102.38 2_MWD+IFR2+MS+Sag (2)
10,769.28
89.70
126.93
3,941.11
3,882.26
3,552.43
6,820.03
6,023,244.94
540,833.93
0.96
8,198.05 2_MWD+IFR2+MS+Sag(2)
10,864.42
90.19
123.26
3,941.20
3,882.35
3,607.12
6,897.86
6,023,190.61
540,912.00
3.89
8,293.18 2_MWD+IFR2+MS+Sag(2)
10,958.41
92.11
122.19
3,939.32
3,880.47
3,657.92
6,976.91
6,023,140.18
540,991.28
2.34
8,387.07 2_MWD+IFR2+MS+Sag(2)
11,053.05
92.79
121.31
3,935.27
3,876.42
-4,707.67
7,057.31
6,023,090.80
541,071.90
1.17
8,481.48 2_MWD+IFR2+MS+Sag (2)
11,150.18
92.41
121.43
3,930.86
3,872.01
3,758.18
7,140.16
6,023,040.67
541,154.97
0.41
8,578.32 2_MWD+IFR2+MS+Sag (2)
11,245.33
92.60
121.31
3,926.71
3,867.86
3,807.67
7,221.32
6,022,991.56
541,236.35
0.24
8,673.20 2_MWD+IFR2+MS+Sag(2)
11,341.18
91.30
121.09
3,923.44
3,864.59
3,857.29
7,303.26
6,022,942.32
541,318.50
1.38
8,768.79 2 MWD+IFR2+MS+Sag(2)
11,435.83
89.82
121.11
3,922.52
3,863.67
3,906.17
7,384.30
6,022,893.81
541,399.76
1.56
8,863.22 2_MWD+IFR2+MS+Sag(2)
11,530.66
90.69
125.18
3,922.10
3,863.25
3,958.01
7,463.68
6,022,842.34
541,479.37
4.39
8,957.99 2_MWD+IFR2+MS+Sag(2)
11,625.38
89.32
125.95
3,922.09
3,863.24
-5,013.10
7,540.73
6,022,787.61
541,556.66
1.66
9,052.70 2_MWD+IFR2+MS+Sag(2)
11,721.99
89.82
125.34
3,922.81
3,863.96
-5,069.40
7,619.24
6,022,731.68
541,635.41
0.82
9,149.30 2_MWD+IFR2+MS+Sag(2)
11,816.09
90.44
125.28
3,922.60
3,863.75
-5,123.79
7,696.02
6,022,677.64
541,712.44
0.66
9,243.39 2_MWD+IFR2+MS+Sag(2)
11,911.53
90.01
123.74
3,922.23
3,863.38
-5,177.86
7,774.67
6,022,623.94
541,791.32
1.68
9,338.83 2_MWD+IFR2+MS+Sag(2)
12,006.85
88.89
122.57
3,923.14
3,864.29
-5,229.99
7,854.46
6,022,572.18
541,871.35
1.70
9,434.09 2_MWD+IFR2+MS+Sag (2)
12,101.10
90.63
125.25
3,923.53
3,864.68
-5,282.56
7,932.67
6,022,519.97
541,949.79
3.39
9,528.32 2_MWD+IFR2+MS+Sag (2)
12,197.42
89.69
125.43
3,923.27
3,864.42
-5,338.27
8,011.24
6,022,464.62
542,028.60
0.99
9,624.63 2_MWD+IFR2+MS+Sag (2)
12,292.47
88.84
125.79
3,924.49
3,865.64
-5,393.61
8,088.51
6,022,409.64
542,106.12
0.97
9,719.67 2_MWD+IFR2+MS+Sag (2)
12,388.00
87.22
127.03
3,927.77
3,868.92
5,450.28
8,165.34
6,022,353.34
542,183.20
2.14
9,815.10 2_MWD+IFR2+MS+Sag(2)
12,483.78
87.60
126.74
3,932.10
3,873.25
-5,507.71
8,241.87
6,022,296.26
542,259.98
0.50
9,910.73 2_MWD+IFR2+MS+Sag(2)
12,579.06
86.11
125.95
3,937.32
3,878.47
-5,564.09
8,318.50
6,022,240.24
542,336.86
1.77
10,005.83 2_MWD+IFR2+MS+Sag(2)
7/292019 6:01:46PM
Page 5
COMPASS 5000.15 Build 91
Halliburton
Definitive Survey Report
Company:
Hilcorp Alaska, LLC
Local Coordinate Reference: Well
MPU M1-13
Project:
Milne Point
TVD Reference:
MPU
M-13 Actual RKB @ 58.85usft
Site:
M Pt
Moose Pad
MD Reference:
MPU
M-13 Actual RKB @ 58.85usft
Well:
MPU
M-13
North Reference:
True
Wellbore:
MPU
M-131
Survey Calculation Method: Minimum
Curvature
Design:
MPU
M-13
Database:
NORTH US+CANADA
Survey
Map
Map
Vertical
MD
Inc
Azi
TVD
TVDSS
+W -S
+EI -W
Northing
Easting
DLS
Section
(usft)
(1)
(1)
(usft)
(usft)
(usft)
(usft)
(ft)
(ft) (.1100')
(ft) Survey Tool Name
12,674.36
86.24
124.99
3,943.68
3,884.83
-5,619.26
8,395.94
6,022,185.42
542,414.54
1.01
10,100.91 2_MWD+IFR2+MS+Sag(2)
12,769.56
86.67
124.45
3,949.57
3,890.72
-5,673.38
8,474.04
6,022,131.67
542,492.88
0.72
10,195.93 2_MWD+IFR2+MS+Sag(2)
12,865.26
87.48
123.58
3,954.45
3,895.60
-5,726.85
8,553.26
6,022,078.57
542,572.34
1.24
10,291.49 2_MWD+IFR2+MS+Sag (2)
12,959.71
87.78
123.01
3,958.36
3,899.51
.5,778.65
8,632.14
6,022,027.13
542,651.44
0.68
10,385.82 2_MWD+IFR2+MS+Sag(2)
13,054.81
87.41
123.19
3,962.35
3,903.50
-5,830.54
8,711.73
6,021,975.61
542,731.27
0.43
10,480.79 2_MWD+IFR2+MS+Sag(2)
13,149.71
87.91
125.22
3,966.22
3,907.37
-5,883.84
8,790.15
6,021,922.68
542,809.92
2.20
10,575.60 2_MWD+IFR2+MS+Sag(2)
13,244.54
88.28
125.60
3,969.38
3,910.53
-5,938.76
8,867.39
6,021,868.12
542,887.41
0.56
10,670.37 2_MWD+IFR2+MS+Sag(2)
13,340.39
87.97
125.10
3,972.51
3,913.66
.5,994.18
8,945.53
6,021,813.06
542,965.79
0.61
10,766.17 2_MWD+IFR2+MS+Sag(2)
13,435.40
89.51
125.85
3,974.60
3,915.75
-6,049.31
9,022.88
6,021,758.29
543,043.38
1.80
10,861.15 2_MWD+IFR2+MS+Sag(2)
13,531.17
89.51
125.67
3,975.42
3,916.57
-6,105.27
9,100.59
6,021,702.69
543,121.34
0.19
10,956.90 2_MWD+IFR2+MS+Sag(2)
13,626.75
88.65
124.52
3,976.96
3,918.11
-6,160.22
9,178.78
6,021,648.11
543,199.78
1.50
11,052.47 2_MWD+IFR2+MS+Sag(2)
13,721.30
89.64
124.47
3,978.37
3,919.52
-6,213.76
9,256.70
6,021,594.93
543,277.93
1.05
11,147.01 2_MWD+IFR2+MS+Sag(2)
13,815.52
89.58
124.36
3,979.01
3,920.16
-6,267.01
9,334.43
6,021,542.04
543,355.89
0.13
11,241.22 2_MWD+IFR2+MS+Sag(2)
13,911.58
88.21
124.81
3,980.86
3,922.01
-6,321.52
9,413.50
6,021,487.89
543,435.20
1.50
11,337.26 2_MWD+IFR2+MS+Sag(2)
14,007.15
90.51
124.97
3,981.93
3,923.08
-6,376.18
9,491.88
6,021,433.60
543,513.82
2.41
11,432.81 2_MWD+IFR2+MS+Sag(2)
14,101.49
92.17
125.64
3,979.72
3,920.87
-6,430.68
9,568.84
6,021,379.45
543,591.03
1.90
11,527.12 2 MWD+IFR2+MS+Sag (2)
14,197.41
92.05
126.28
3,976.19
3,917.34
-6,486.97
9,646.43
6,021,323.52
543,668.86
0.68
11,622.96 2_MWD+IFR2+MS+Sag(2)
14,293.00
91.55
125.27
3,973.19
3,914.34
-6,542.83
9,723.94
6,021,268.03
543,746.63
1.18
11,718.49 2_MWD+IFR2+MS+Sag (2)
14,387.11
92.11
124.35
3,970.18
3,911.33
-6,596.52
9,801.17
6,021,214.69
543,824.09
1.14
11,812.55 2_MWD+IFR2+MS+Sag (2)
14,483.34
90.99
123.46
3,967.58
3,908.73
.6,650.18
9,881.01
6,021,161.41
543,904.16
1.49
11,908.73 2_MWD+IFR2+MS+Sag(2)
14,578.85
87.84
122.13
3,968.55
3,909.70
-6,701.90
9,961.28
6,021,110.06
543,984.66
3.58
12,004.16 2_MWD+IFR2+MS+Sag(2)
14,674.10
86.73
121.94
3,973.07
3,914.22
-6,752.37
10,041.93
6,021,059.97
544,065.54
1.18
12,099.18 2_MWD+IFR2+MS+Sag(2)
14,768.79
87.41
121.75
3,977.91
3,919.06
-6,802.26
10,122.26
6,021,010.44
544,146.09
0.75
12,193.61 2_MWD+IFR2+MS+Sag(2)
14,864.02
88.15
122.44
3,981.59
3,922.74
-6,852.82
10,202.88
6,020,960.26
544,226.93
1.06
12,288.65 2_MWD+IFR2+MS+Sag (2)
14,958.43
87.91
122.94
3,984.84
3,925.99
-6,903.78
10,282.29
6,020,909.67
544,306.56
0.59
12,382.93 2_MWD+IFR2+MS+Sag (2)
15,054.36
88.21
125.09
3,988.09
3,929.24
-6,957.41
10,361.75
6,020,856.40
544,386.26
2.26
12,478.79 2_MWD+IFR2+MS+Sag (2)
15,149.95
89.02
129.42
3,990.40
3,931.55
-7,015.25
10,437.80
6,020,798.92
544,462.56
4.61
12,574.25 2_MWD+IFR2+MS+Sag(2)
15,245.35
87.66
128.75
3,993.16
3,934.31
-7,075.37
10,511.81
6,020,739.15
544,536.84
1.59
12,669.35 2 MWD+IFR2+MS+Sag (2)
15,340.41
86.73
129.05
3,997.81
3,938.96
-7,134.99
10,585.70
6,020,679.87
544,611.00
1.03
12,764.07 2_MWD+IFR2+MS+Sag(2)
15,435.52
86.17
128.10
4,003.70
3,944.85
-7,194.18
10,659.92
6,020,621.02
544,685.47
1.16
12,858.80 2_MWD+IFR2+MS+Sag(2)
15,530.13
87.04
126.69
4,009.31
3,950.46
.7,251.53
10,734.95
6,020,564.02
544,760.76
1.75
12,953.15 2_MWD+IFR2+MS+Sag(2)
15,626.45
87.78
125.64
4,013.66
3,954.81
-7,308.31
10,812.63
6,020,507.60
544,838.69
1.33
13,049.35 2_MWD+IFR2+MS+Sag(2)
15,721.42
87.10
124.46
4,017.90
3,959.05
-7,362.80
10,890.29
6,020,453.48
544,916.60
1.43
13,144.22 2_MWD+IFR2+MS+Sag(2)
15,816.71
88.53
123.03
4,021.53
3,962.68
-7,415.69
10,969.47
6,020,400.95
544,996.00
2.12
13,239.42 2 MWD+IFR2+MS+Sag(2)
15,910.78
88.28
123.43
4,024.15
3,965.30
-7,467.22
11,048.12
6,020,349.79
545,074.89
0.50
13,333.41 2_MWD+IFR2+MS+Sag(2)
16,005.21
87.72
124.13
4,027.45
3,968.60
-7519.69
11,126.56
6,020,297.68
545,153.56
0.95
13,427.76 2_MWD+IFR2+MS+Sag(2)
16,100.88
89.08
124.88
4,030.12
3,971.27
-7,573.86
11,205.37
6,020,243.87
545,232.60
1.62
13,523.39 2_MWD+IFR2+MS+Sag(2)
16,196.20
88.90
125.98
4,031.80
3,972.95
-7,629.11
11,263.03
6,020,188.99
545,310.50
1.17
13,618.69 2 MWD+IFR2+MS+Sag(2)
16,229.10
88.03
126.05
4,032.68
3,973.83
-7,648.45
11,309.63
6,020,169.77
545,337.19
2.65
13,651.57 2_MWD+IFR2+MS+Sag(2)
16,300.00
88.03
126.05
4,035.12
3,976.27
.7,690.15
11,366.92
6,020,128.34
545,394.66
0.00
13,722.42 PROJECTED to TD
729/1019 6:01:46PM
Page 6
COMPASS 5000.15 Build 91
Company:
Hilcorp Alaska, LLC
Project:
Milne Point
Site:
M Pt Moose Pad
Well:
MPU M-13
Wellbore:
MPU M -13i
Design:
MPU M-13
Halliburton
Definitive Survey Report
Local Co-ordinate Reference:
ND Reference:
MD Reference: -
North Reference:
Survey Calculation Method:
Database:
Well MPU M-13
MPU M-13 Actual RKB @ 58.85usft
MPU M-13 Actual RKB @ 58.85usft
True
Minimum Curvature
NORTH US + CANADA
Checked By: Chelsea Wright ==='.—
Approved By: Mitch Laird — Date: 07-29-2019
729!1019 6:01:46PM Page 7 COMPASS 5000.15 Build 91
I
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No. MP M-13 Dale Run 16 -Jul -19
County State Alaska Supv. D. Yessak/J. Vanderpool
CASING RECORD
Surface �
Tn d 4n4 Mf Rhna nenlhtr 4497 M PRTn'
Gag Wt. On Hook: Type Float Collar: No. Hrs to Run:
Gag Wt. On Slips: 100,000 Type of Shoe: Casing Crew: Doyon
Rotate Csg X Yes No Recip Csg X Yes No Ft. Min. 9.3 PPG
Fluid Description: Spud Mud
Liner hanger Info(Make/Model): Liner top Packer?: _Yes No
Liner hanger test pressure: Floats Held X Yes No
CEMENTING REPORT
Shoe @ 4927
FC @ 4,847.00
Casing (Or Liner) Detail
fly (ppg) 15.8
're0ush (Spacer)
Setting
Depths
its.
Component
Size
Wt.
Grade
THD
Make
Length
Bottom
Top
1
Shoe
103/4
50.0
1510
TXP BTC -SR
Innovex
1.57
4,927.00
4,925.43
2
Casing
95/8
40.0
L-80
TXP BTC -SR
Tenaris
77.58
4,925.43
4,847.85
1
Float Collar
103/4
50.0
82
TXP 3TC -SR
Innovex
1.33
4,847.85
4,846.52
1
Casing
95/8
40.0
L-80
TXP BTC -5R
Tenaris
40.17
4,846.52
4,806.35
1
Baffle Adapter
103/4
50.0
4
TXP BTC -SR
HES
1.59
4,806.35
4,804.76
66
Casing
95/8
40.0
L-80
TXP BTC -SR
Tenaris
2,599.58
4,804.76
2,205.18
1
Pup Joint
95/8
40.0
L-80
TXP BTC -SR
Tenaris
11.85
1 2,205.18
2,193.33
1
ES Cementer II
103/4
Closure OK Y
TXP BTC -SR
HES
2.86
2,193.33
2,190.47
1
Pup Joint
95/8
40.0
L-80
TXPBTC-SR
Tenaris
19.61
2,190.47
2,170.86
57
Casing
95/8
40.0
L-80
TXP BTC -SR
Tenaris
2,117.37
2,170.86
53.49
1
Casing Cut Joint
95/8
40.0
L-80
TXP BTC -SR
Tenaris
21.07
53.49
32.42
Gag Wt. On Hook: Type Float Collar: No. Hrs to Run:
Gag Wt. On Slips: 100,000 Type of Shoe: Casing Crew: Doyon
Rotate Csg X Yes No Recip Csg X Yes No Ft. Min. 9.3 PPG
Fluid Description: Spud Mud
Liner hanger Info(Make/Model): Liner top Packer?: _Yes No
Liner hanger test pressure: Floats Held X Yes No
CEMENTING REPORT
Shoe @ 4927
FC @ 4,847.00
Top of Liner
fly (ppg) 15.8
're0ush (Spacer)
56
Mixing / Pumping Rate (bpm): _
Flush (Spacer)
ype: Tuned Spacer
Density (ppg)
10
Volume pumped (BBLs)
60
ead Slurry
lacement:
ype: Lead
9.3 Rate (bpm):
1510
Sacks: 300 Yield:
2.35
lenity (ppg) 12
Volume pumped (BBLs)
125.5
Mixing / Pumping Rale (bpm):
4
all Slurry
No % Returns during job _
_Yes
ant returns to surface' X
Yes No Spacer retums7
X Yes
ype: Tail
ant In Place At: 10:54
Date: 7/17/2019
Sacks: 400 Yield:
1.16
Density (ppg) 15.8
Volume pumped (BBLs)
82
Mixing / Pumping Rate (bpm):
4
ost Flush (Spacer)
ype:
Density (ppg)
Rate (bpm): Volume:
�Isplacement
ype: Mud Density (ppg)
9.3 Rale (bpm):
4
Volume (actual / calculated):
360/0
CP (psi): 570 Pump used for disp: Rig
Bump Plug?
X Yes -No Bump press 1100
asing Rotated? Yes
X No Reciprocated?
Yes X
No % Returns during job
100
emem retums to surtace? _Yes
X No Spacer returns?
X Yes
_No Vol to Surf:
0
emem In Place At 1:18
Date: 7/17/2019
Estimated TOC:
2,190
lethod Used To Determine TOC:
ESCementer
Stage Collar@ 2190
Type ES Cementer
Closure OK Y
re8ush (Spacer)
ype: Tuned Spacer Density (ppg)
10
Volume pumped (BBLs)
60
ead Slurry
ype: Perm L
Sacks: 393 Yield:
4.4
ensity (ppg) 10.7
Volume pumped (BBLs)
305
Mixing / Pumping Rate (bpm):
5
all Slurry
Tail
Sacks: 270 Yield:
fly (ppg) 15.8
Volume pumped (BBLs)
56
Mixing / Pumping Rate (bpm): _
Flush (Spacer)
Density (ppg)
Rate (bpm): Volume: _
lacement:
Mud Density (ppg)
9.3 Rate (bpm):
1510
Volume (actual / calculated): _
(psi): 380 Pump used for
disp: Rig
Bump Plug?
X Yes -No Bump press
ig Rotated?
X No Reciprocated?
Yes X
No % Returns during job _
_Yes
ant returns to surface' X
Yes No Spacer retums7
X Yes
_No Vol to Surt: 200
ant In Place At: 10:54
Date: 7/17/2019
Estimated TOC: 0
ad Used To Determine TOC:
Visual/Retums
THE STATE
°fALASKA
GOVERNOR MIKE DUNLEAVY
Monty Myers
Drilling Manager
Hilcorp Alaska, LLC.
3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.olasko.gov
Re: Milne Point Field, Schrader Bluff Oil Pool, MPU M-13
Hilcorp Alaska, LLC.
Permit to Drill Number: 219-087
Surface Location: 4913' FSL, 171' FEL, SEC. 14, T13N, R9E, UM, AK
Bottomhole Location: 2488' FSL, 698' FWL, SEC. 20, T13N, R10E, UM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced service well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well
logs run must be submitted to the AOGCC within 90 days after completion, suspension or
abandonment of this 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, `�
YCeelowski
Commissioner
DATED this 12- day of June, 2019.
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL JUN 0 6 2019
20 AAC 25.005
1a. Type of Work:
11b. Proposed Well Class: Exploratory - Gas ❑
Service - WAG ❑ Service - Disp ❑
1c.v 'I sed for:
Drill ❑Q ' Lateral ElStratigraphic
Test ElDevelopment -Oil ❑
Service - Winj ❑✓ Single Zone ❑✓ •
Coalbed Gas LJ Gas Hydrates ❑
Redrill ❑ Reentry ❑
Exploratory - Oil ❑ Development - Gas ❑
Service - Supply ❑ Multiple Zone ❑
Geothermal ❑ Shale Gas ❑
2. Operator Name:
5. Bond: Blanket Q Single Well ❑
11. Well Name and Number:
Hilcorp Alaska, LLC
Bond No. 022035244
MPU M-13
3. Address:
6. Proposed Depth:
12. Field/Pool(s):
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
MD: 16,246' • TVD: 3,964'
Milne Point Field
Schrader Bluff Oil Pool
4a. Location of Well (Governmental Section):
7. Property Designation:
Surface: 4913' FSL, 171' FEL, Sec 14, T13N, R9E, UM, AK
ADL025514, ADL025515
Top of Productive Horizon:
8. DNR Approval Number:
13. Approximate Spud Date:
1593' FNL, 1938' FWL, Sec 13, T13N, R9E, UM, AK
LONS 16-004
6/14/2019
9. Acres in Property:
14. Distance to Nearest Property:
Total Depth:
2488' FSL, 698' FWL, Sec 20, T13N, R10E, UM, AK
5104
2509' to nearest unit boundary
4b. Location of Well (State Base Plane Coordinates - NAD 27):
10. KB Elevation above MSL (ft): 58.4.
15. Distance to Nearest Well Open
Surface: x- 533993 • y- 6027765 Zone -4
GL / BF Elevation above MSL (ft): 24.7 •
to Same Pool: 760'to MPU M-12 '
16. Deviated wells: Kickoff depth: 500 feet
17. Maximum Potential Pressures in prig (see 20 AAC 25.035)
Maximum Hole Angle: 93.2 degrees
Downhole: 1727 Surface:
1338 '
18. Casing Program: Specifications
Top - Setting Depth - Bottom
Cement Quantity, c.f. or sacks
Hole Casing Weight
Grade
I Coupling
Length
MD
TVD
MD
TVD
(including stage data)
Cond 20" • 215.5#
X-42
Weld
114'
Surface
Surface
114'
114'
-270 ft3
Sig 1-L-570 ft3/T-458 0
12-1/4" 9-5/8" - 40#
L-80
TXP SR
4,900'
Surface
Surface
4,900'
3,936'
Sig 2 - L - 1937 ft3 / T - 314 ft3
8-1/2" 4-1/2" 13.5#
L-80
Hyd 625
11,496'
4,750'
3,907'
16,246.
3,964'
•Cementless; Injection Liner ICDs
Tialiaek 3-1/2" 9.3#
L-80
EUE 8RD
4,750'
Surface
Surface
4,750'
3,907'
Tieback
19.. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations)
Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured):
Effect. Depth MD (ft): Effect. Depth ND (ft): Junk (measured):
Casing Length Size
Cement Volume
MD TVD
Conductor/Structural
Surface
Intermediate
Production
Liner
Perforation Depth MD (ft):
Perforation Depth TVD (ft):
Hydraulic Fracture planned? Yes ❑ No ❑�
20. Attachments: Property Plat O BOP Sketch
Drilling
Program Time v. Depth Plot
Shallow Hazard Analysis
Diverter Sketch
B✓
Seabed Report e Drilling Fluid Program B✓
20 AAC 25.050 requirementse
21. Verbal Approval: Commission Representative:
Dale
22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be
deviated from without prior written approval.
Contact Name:
Joe Engel
Authorized Name: Monty Myers
Contact Email:
'en el hilCOr .COm
Authorized Title: Drilling Manager
Contact Phone:
777-8395
� Morv7Y MY�r=5
12
Authorized Signature:
Date: 616 -PI
Commission Use Only
Permit to Drill 77 7API
umbe
D� 23
Permit Approval
2
01
See cover letter for other
Number: L1 9 � /
50- O C-cJ
csz-�
Date:
requirements.
Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, as hydrates,
or gas contained in shales: ,_,/
a
Other: .jf 3Ma ,1sS �� P '—]�St-
r c
Samples req'd: Yes ❑ No[�
Mud log req'd: Yes❑ oF✓1
VNor❑1
H,S measures: Yes ❑ No
Directional svy req'd: Yes
��/
Spacing exception req'd: Yes ❑ No L� Inclination -only svy req'd: Yes ❑ No LI
Post initial injection MIT req'd: Yes VNo ❑
1
APPROVED BY
Date:
Approved by:
COMMISSIONER THE COMMISSION
G't ermi �1 \ � � / 1 \ � ` m�For Form
Form t 1 Revised 5/2017 This permit is valid for 4 t proval per 20 5(g) Altach is in Duplicate, /
iy %
H
Hilcorp
&o comp
6.6.2019
Commissioner
Alaska Oil & Gas Conservation Commission
333 W. r Avenue
Anchorage, Alaska 99501
Re: Application for Permit to Drill MPU M-13
Dear Commissioner,
Joe Engel Hilcorp Alaska, LLC
Drilling Engineer P.O. Box 244027
Anchorage, AK 99524-4027
Tel 907 777 8395
Email: jengel@hilcorp.com
Hilcorp Alaska, LLC hereby submits for review and approval for a Permit to Drill an onshore injection
well at Milne Point'M' Pad, well slot 13.
MPU M-13 is a grassroots injector planned to be drilled in the Schrader Bluff OA sand. M-13 is part of
a multi well program targeting the Schrader Bluff sand on M -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 OA sand. An 8.5" lateral section will then be drilled. A 4-1/2" ICD 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 July 2, 2019, however M-13 could be
drilled ahead of M-20 if wellbore easement approval is not received. In this case, spud date could be
June 14, 2019.
Please find attached the Form 10-401, Application For Permit to Drill per 20 AAC 25.005 (a) and the
drilling program for MPU M-10, which includes information required by 20 AAC 25.005 (c).
If you have any questions, or require further information, please do not hesitate to contact myself (Joe
Engel) at 777-8395 or jengel@hilcorp.com or Monty Myers at 777-8431 or mmyers@hilcorp.com.
Sincerely,
J Engel
Drilling Engineer
Hilcorp Alaska, LLC Page 1 of 1
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Hilcorp Alaska, LLC
Milne Point Unit
(MPU) M-13
Drilling Program
Version 1
6/6/2019
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.....................................................................................................21
14.0
BOP N/U and Test.........................................................................................................................26
15.0
Drill 8-1/2" Hole Section...............................................................................................................27
16.0
Run 4-1/2" Injection Liner (Lower Completion)........................................................................32
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 OA Sand Offset MW vs TVD Chart ..................................................................54
33.0
Drill Pipe Information 5"19.5# 5-135 DS -50 & NC50...............................................................55
n
Hilcorp
Envgy Compuy
1.0 Well Summary
Milne Point Unit
M-13 SB Injector
Drilling Procedure
Well
MPU M-13
Pad
Milne Point "M" Pad
Planned Completion Type
3-1/2" Injection Tubing
Target Reservoirs
Schrader Bluff OA Sand '
Planned Well TD, MD / TVD
16,246' MD / 3,963' TVD
PBTD, MD / TVD
16,236' MD / 3,963' TVD
Surface Location (Governmental)
4913' FSL, 171' FEL, Sec 14, TON, R9E, UM, AK
Surface Location (NAD 27)
X= 533,993.84, Y= 6,027,765.7
Top of Productive Horizon
(Governmental)
1593' FNL, 1938' FWL, Sec 13, T13N, R9E, UM, AK
TPH Location INAD 27)
X= 536,110 Y= 6,026,549.27
BHL (Governmental)
2488' FSL, 698' FWL, Sec 20, T13N, R10E, UM, AK
BHL (NAD 27)
X= 545,407 Y=6,020,112
AFE Number
1911312M (D,C,F)
AFE Drilling Das
17 days
AFE Completion Das
7 days
AFE Drilling Amount
$4,068,280
AFE Completion Amount
$1,840,720
AFE Facility Amount
$391,000
Maximum Anticipated Pressure
Surface
1338 psig
Maximum Anticipated Pressure
Downhole/Reservoir
1727 psig
Work String
5" 19.5# S-135 DS -50 & NC 50
KB Elevation above MSL:
33.7 ft + 25.0 ft = 58.7 ft -
GL Elevation above MSL:
25.0 ft -
BOP Equipment
13-5/8" x 5M Annular, (3) ea 13-5/8" x 5M Rams
Page 2
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HilcO2
M. r
2.0
Milne Point Unit
M-13 SB Injector
Drilling Procedure
Management of Change Information
H
Hilcorp Alaska, LLC Hilcorp
� c22
Changes to Approved Permit to Drill
Date: 6/6/2019
Subject: Changes to Approved Permit to Drill for MPU M-13
File #: MPU M-13 Drilling and Completion Program
Any modifications to MPU M-13 Drilling & Completion Program will be documented and approved below.
Changes to an approved APD will be approved in advance to the AOGCC.
Approval:
Prepared:
Page 3
Drilling Manager
Drilling Engineer
Date
Date
H
Hilcorp
Euop C®pmy
3.0 Tubular Program:
Milne Point Unit
M-13 SB Injector
Drilling Procedure
4.0 Drill Pipe Information:
Hole
OD
ID (in)
TJ ID
TJ OD
Wt
Grade
Conn
M/U
M/U
Tension
Section
in
in
in
#/ft
in
Max(k-lbs)
Surface &
5"
4.276"
3.25"
6.625"
19.5
S-135
GPDS50
36,100
43,100
560klb
Production
5"
4.276"
3.25"
6.625"
19.5
S-135
NC50
31,032
34,136
560k1b
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
Page 4
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Hilcorp
E,u 22
C
5.0 Internal Reporting Requirements
Milne Point Unit
M-13 SB Injector
Drilling Procedure
5.1 Fill out daily drilling report and cost report on Wel1Ez.
• Report covers operations from 6am to 6am
• Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left
of the data entry area — this will not save the data entered, and will navigate to another data entry.
• Ensure time entry adds up to 24 hours total.
• Try to capture any out of scope work as NPT. This helps later on when we pull end of well
reports.
• Enter the MD and TVD depths EVERY DAY whether you are making hole or not.
5.2 Afternoon Updates
• Submit a short operations update each work day to pmazzolini@hilcoM.com, mmyers hilcorp,
jengel@hilcoM.com and cdinger@hilcorp.com
5.3 Intranet Home Page Morning Update
• Submit a short operations update each morning by 7am on the company intranet homepage. On
weekend and holidays, ensure to have this update in before 5am.
5.4 EHS Incident Reporting
• Health and Safety: Notify EHS field coordinator.
• Environmental: Drilling Environmental Coordinator
• Notify Drilling Manager & Drilling Engineer on all incidents
• Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
• Send final "As -Rud' Casing tally to mmyers e hilcorp,com ieneelna hilcorp.com and
cdinizer@hilco!:p.com
5.6 Casing and Cement report
• Send casing and cement report for each string of casing to mmyers@hilcorp.com
jenael enael@hilcon2.com and cdinizer@hileorp.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
length@hilcorp.com
Completion Engineer
Taylor Wellman
907.777.8449
907.947.9533
twellman@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
caiones@hilcorp.com
Drilling Tech
Cody Dinger
907.777.8389
509.768.8196
cdinger@hilcorp.com
Page 5
Milne Point Unit
M-13 SB Injector
HilcoTp Drilling Procedure
� O�wor
6.0 Planned Wellbore Schematic
IN
C ft 95 ftE :s"AL Eea.:10,
9db�
CT.TCQ
25m M)
1D=14ZV1Nq/1D=39WrW0
mm= 142W (Nq /F81D=3:J64'lTi'D}
Page 6
Milne Point Unit
Well: MPU M-13
Proposed Schematic PTD: TBD
API- TBD
r__________________________________________________
TREE &WELLHEAD
Tree Cameran3SM w•/4-1/I6"SM CanermWhV
Wellhead Cameron Ir5Ka yWn,jbd1Wmv/121 2-I/16"5Naub
OPEN HOLE /CEMENT DETAIL
dr' SObu-:LK Yards dumped basinb laid
12-1/d" Stg I- 5 M" luad 7658 N3 I WE 18pp8
5182-1937 h3 Lmd 10.78R/ 314 tt3 Tai 15.6
6-112"CmcuVg, InieAw liner ie, a-Vr hate
CASING DETAIL
Size
Type
V.o Gmde/Conn
Drill lG
Top
BJII
BPF
XTx34"
CenduRorpmulatedl
215.5/%-42 W. ld
N/A
Sudace
114'
WA
9-578"
Surlam
40/480/TIP
8.679"
Sudace
6,900'
OD758
6-1/r I
liner
I 13.5/1.-80 625 I
37W 1
4,7
16.246'.
OA749
f
AM
TUBING DETAIL
2.992"
UYb2r CAmp ban
3-17r, I
TubinK
93/1.-80/CUC11RD..
2867"
Sud
6750'
0.0670
WELL INCUNATION DETAIL
KOP LS TIED
I Ide RnOlr � IW =7B6
Ude An •Ir h+liner TOp=TBD
Max Iluk An81e =TBO
JEWELRY DETAIL
No
Top MO
Item
ID
Upper compebon
1
12,30D'
2.813"
2
24,eW
3.5" %N Nip a(1813" Packi Bore; 2.75" ho -G-)
1750"
3
s4,7OD'
3.5" G". w/%"Wire
2.996"
4
x4.742'
8.26'NDC boater W 737FS-M lnsem6
2.992"
5
AM
I 7.375"Tldback above the SUMP Liner Top Packer Iftm0 TW
2.992"
UYb2r CAmp ban
6
47
ZBP Unn TOP Pecker
'
7
16,241'
14Vl8al On Seat) Oesedl
-
7.0 Drilling / Completion Summary
Milne Point Unit
M-13 SB Injector
Drilling Procedure
MPU M-13 is a grassroots injector planned to be drilled in the Schrader Bluff OA sand. M-13 is part of a
multi well program targeting the Schrader Bluff sand on M -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 OA sand. An 8.5" lateral section will then be drilled. A 4-1/2" ICD 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 July 2, 2019, however M-13 could be drilled
ahead of M-20 if wellbore easement approval is not received. In this case, spud date could be June 14, 2019.
Surface casing will be run to 4,900 MD / 3,936' 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, NIU & 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/TJ Tree, RDMO.
Reservoir Evaluation Plan:
1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res f i
2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering)
Page 7
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Hilcorp
Milne Point Unit
M-13 SB Injector
Drilling Procedure
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.
• BOPs shall be tested at (2) week intervals during the drilling and completion of MPU M-13. Ensure
to provide AOGCC 24 hrs notice prior to testing BOPs.
• The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment
will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial
and subsequent tests). Confirm that these test pressures match those specified on the APD.
• If the BOP is used to shut in on the well in a well control situation or control fluid flow from the
well bore, AOGCC is to be notified and we must test all BOP components utilized for well control
prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP
test.
• All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program
and drilling fluid system".
• All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements".
o Ensure the diverter vent line is at least 75' away from potential ignition sources
• Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
AOGCC Regulation Variance Requests:
Hilcorp Alaska LLC does not request any variances at this time.
Page 8
Milne Point Unit
M-13 SB Injector
Hilcorp Drilling Procedure
E, C®pavy
Summary of BOP Equipment & Notifications
Hole Section
Equipment
Test Pressure(psi)
12 1/4"
21-1/4" 2M Diverter w/ 16" Diverter Line
Function Test Only
• 13-5/8" x 5M Hydril "GK" Annular BOP
• 13-5/8" x 5M Hydril MPL Double Gate
Initial Test: 250/
3
o Blind ram in him cavity
• Mud cross w/ 3" x 5M side outlets
8-1/2"
13-5/8" x 5M Hydril MPL Single ram
• 3-1/8" x 5M Choke Line
Subsequent Tests:
2 5 0/4 9 66 3 ooa
• 3-1/8" x 5M Kill line
• 3-1/8" x 5M Choke manifold
• Standpipe, floor valves, etc
Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit.
Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air
pump, and emergency pressure is provided by bottled nitrogen.
The remote closing operator panels are located in the doghouse and on accumulator unit.
Required AOGCC Notifications:
• Well control event (BOPS utilized to shut in the well to control influx of formation fluids).
• 24 hours notice prior to spud.
• 24 hours notice prior to testing BOPS.
• 24 hours notice prior to casing running & cement operations.
• Any other notifications required in APD.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (0): 907-793-1236 / Email: jim.reRR@alaska.gov
Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartz@alaska.g_ov
Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: Victoria.loeppna,alaska.gov
Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / (C): 907-223-3605 / Email: melvin.rixse(a alaska.gov
Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov
Test/Inspection notification standardization format: hup://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)
Page 9
H
Hilo
U=
9.0 R/U and Preparatory Work
Milne Point Unit
M-13 SB Injector
Drilling Procedure
9.1 M-13 will utilize a newly set 20" conductor on M -Pad. Ensure to review attached surface plat
and make sure rig is over appropriate conductor.
9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor.
9.3 Install landing ring.
9.4 Insure (2) 4" nipples are installed on opposite sides of the conductor with ball valves on each.
9.5 Level pad and ensure enough room for layout of rig footprint and R/U.
9.6 Rig mat footprint of rig.
9.7 MIRU Doyon 14. Ensure rig is centered over conductor to prevent any wear to BOPE or
wellhead.
9.8 Mud loggers WILL NOT be used on either hole section.
9.9 Mix spud mud for 12-1/4" surface hole section. Ensure mud temperatures are cool (<800F).
9.10 Ensure 6" liners in mud pumps.
• Continental EMSCO FB -1600 mud pumps are rated at 4665 psi, 462 gpm @ 110 spm @
95% volumetric efficiency.
Page 10
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Hilcorp
E^ GmY^Y
10.0 NX 21-1/4" 2M Diverter System
Milne Point Unit
M-13 SB Injector
Drilling Procedure
10.1 N/U 21-1/4" Hydril MSP 2M Diverter System (Diverter Schematic attached to program).
• N/U 16-3/4" 3M x 21-1/4" 2M DSA on 16-3/4" 3M wellhead.
• N/U 21-1/4" diverter "T".
• Knife gate, 16" diverter line.
• Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
• Diverter line must be 75 ft from nearest ignition source
• Place drip berm at the end of diverter line.
10.2 Notify AOGCC. Function test diverter. Ensure that the knife gate and annular are operated on
the same circuit so that knife gate opens prior to annular closure.
10.3 Ensure to set up a clearly marked "warning zone" is established on each side and ahead of the
vent line tip. "Warning Zone" must include:
• A prohibition on vehicle parking
• A prohibition on ignition sources or running equipment
• A prohibition on staged equipment or materials
• Restriction of traffic to essential foot or vehicle traffic only.
Page I 1
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Hilcorp
.rp
10.4 Rig & Diverter Orientation:
a May change on location
Milne Point Unit
M-13 SB Injector
Drilling Procedure
75' Radius Clear of Ignition Sources
Diverter Line
MPU M -Pad *Drawing Not To Scale
Page 12
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Milne Point Unit
M-13 SB Injector
Drilling Procedure
75' Radius Clear of Ignition Sources
Diverter Line
MPU M -Pad *Drawing Not To Scale
Page 12
11.0 Drill 12-1/4" Hole Section
Milne Point Unit
M-13 SB Injector
Drilling Procedure
11.1 P/U 12-1/4" directional drilling assembly:
• Ensure BHA components have been inspected previously.
• Drift and caliper all components before MAJ. Visually verify no debris inside components
that cannot be drifted.
• Ensure TF offset is measured accurately and entered correctly into the MWD software.
• Be sure to run a UBHO sub for wireline gyro
• Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TEA is attached below.
• Drill string will be 5" 19.5# 5-135.
• Run a solid float in the surface hole section.
11.2 Begin drilling out from 20" conductor at reduced flow rates to avoid broaching the conductor.
Consider using a trash bit to clean out conductor to mitigate potential damage from debris in
conductor.
11.3 Drill 12-1/4" hole section to section TD, in the Schrader OA sand. Confirm this setting depth
with the Geologist and Drilling Engineer while drilling the well.
• Monitor the area around the conductor for any signs of broaching. If broaching is observed,
Stop drilling (or circulating) immediately notify Drilling Engineer.
• Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100.
• Hold a safety meeting with rig crews to discuss:
• Conductor broaching ops and mitigation procedures.
• Well control procedures and rig evacuation
• Flow rates, hole cleaning, mud cooling, etc.
• Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
• Keep mud as cool as possible to keep from washing out permafrost.
• Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can
handle the flow rate.
• Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoffs, increase in pump pressure or changes in hookload are seen
• Slow in/out of slips and while tripping to keep swab and surge pressures low
• Ensure shakers are functioning properly. Check for holes in screens on connections.
• Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea
gravel, clay balling or packing off.
• Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2
minimum at TD (pending MW increase due to hydrates). ✓
• Perform wireline gyros until clean MWD surveys are seen. Take MWD surveys every stand
drilled.
Page 13
Milne Point Unit
M-13 SB Injector
Hilco Drilling Procedure
Gas hydrates have not been seen on M -Pad. However, be prepared for them. In MPU they
have been encountered typically around 2100-2400' TVD (just below permafrost). Be
prepared for hydrates:
• Gas hydrates can be identified by the gas detector and a decrease in MW or ECD
• Monitor returns for hydrates, checking pressurized & non -pressurized scales
• Past wells on E pad have increased MW and added 1-1.5ppb of Lecithin & .5% lube.
After drilling through hydrate sands, MW was cut back to normal
• 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.
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.
11.4 12-1/4" hole mud program summary
• Density: Weighting material to be used for the hole section will be barite. Additional
barite or spike fluid will be on location to weight up the active system (1) ppg above ✓
highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and
TD with 9.2+
Depth Interval MW
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
• PVT System: MD Totco PVT will be used throughout the drilling and completion phase.
Remote monitoring stations will be available at the driller's console, Co Man office,
Toolpusher office, and mud loggers office.
• Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system
with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times
while drilling. Be prepared to increase the YP if hole cleaning becomes an issue.
• Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10
ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling
the surface interval to prevent losses and strengthen the wellbore.
• Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are
recommended to reduce the incidence of bit balling and shaker blinding when penetrating the
high -clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A.
Maintain the pH in the 8.5 — 9.0 range with caustic soda. Daily additions of ALDACIDE G / X-
CIDE 207 MUST be made to control bacterial action.
Page 14
V/
H
Hilcorp
Milne Point Unit
M-13 SB Injector
Drilling Procedure
• 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 Aquaget/freshwater spud mud
Properties.
Section
4Density
Viscosity
Plastic Viscosity
Yield Point
API FL
I pH
I Tem
Surface
I 8.8-9.8A
75-175
1 20-40
25-45
<10
1 8.5 - 9.0
1 <_ 70 F
System Formulation: Gel + FW spud mud
Product- Surface hole
Size
Pkg
ppb or (% liquids)
M -I Gel
50
ib SX
25
Soda Ash
50
lb sx
0.25
Pol Pac 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
• Pump at full drill rate (400-600 gpm), and maximize rotation.
• Pull slowly, 5 — 10 ft / minute.
• Monitor well for any signs of packing off or losses.
• Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay
balling.
• If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until
parameters are restored.
11.7 TOOH and LD BHA
11.8 No open hole logging program planned. -
Page 15
/
Milne Point Unit
M-13 SB Injector
Hilcorp Drilling Procedure
Enn ,va
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)
• Ensure 9-5/8" TXP x DS50 XO on rig floor and M/U to FOSV.
• Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
• R/U of CRT if hole conditions require.
• R/U a fill up tool to fill casing while running if the CRT is not used.
• Ensure all casing has been drifted to 8.75" on the location prior to running.
• Be sure to count the total # of joints on the location before running.
• Keep hole covered while R/U casing tools.
• 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
• Ensure bypass baffle is correctly installed on top of float collar.
This end up.
Bypass Baffle
NON
• Ensure proper operation of float equipment while picking up.
• Ensure to record S/N's of all float equipment and stage tool components.
Page 16
ff
Hilcorp
U c.. ,
12.5 Float equipment and Stage tool equipment drawings:
Type H ES Cementer
Part No.
SO No.
Closing Sleeve
No. Shear Pins
Dpening Sleeve
No. Shear Pins
ES Cementer
Depth
T.
Baffle Adapter (if used)
ID
Depth
Bypass or Shut-off Baffle
ID
Depth
Float Collar
Depth
Float Shoe
Depth
Hole To
"Reference Casing
Sales Manual
Seen 5
"A
Overall Length
B
Mn. ID After Drillout
C
Va..TeiOD
D
0penan7 Beat ID
E
Closing Seat ID
Plug Set
Part No.
SO No.
Closirig Plug
OD
Opening Plug
OD
OD
Shutoff Plug
00
Bypass Plug
(d used)
OD
Milne Point Unit
M-13 SB Injector
Drilling Procedure
Page 17 i'
Hi" WI Itunnul Order
ELII Cementer
QShut
on PIK
Batik Adapter
V
-y� -
Bypass Aug
(,.
By pats BatHe
rbzt CclW
Float Shoe
Page 17 i'
H
Hilcorp
U�
Milne Point Unit
M-13 SB Injector
Drilling Procedure
12.6 Continue running 9-5/8" surface casing
• Fill casing while running using fill up line on rig floor.
• Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
• Centralization:
• Verify epth of lowest Ugnu water sand for isolation with Geologist
Depth Interval Centralization
Shoe —1000' Above Shoe 1/'t
1000' above Shoe — 2000' above Shoe 1/ 2 its
(Top of Ugnu)
Utilize a collar clamp until weight is sufficient to keep slips set properly.
Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
• Any packing off while running casing should be treated as a major problem. It is preferable
to POH with casing and condition hole than to risk not getting cement returns to surface.
12.7 Install the Halliburton Type H ES -II Stage tool so that it is positioned at least 100' TVD below
the permafrost (— 2,500_' MD). (Halliburton ESIPC with packer element may be used).
• Install centralizers over couplings on 5 joints below and 5 Joints above stage tool.
• Do not place tongs on ES cementer, this can cause damaged to the tool.
• Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi.
• ESIPC: Ensure tool is pinned properly. ESIPC packer to inflate at — 2080 psi, and the tool to
open at — 3000 psi. Reference ESIPC Procedure.
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
Page 18
Milne Pont Unit
M-13 SB Injector
Me Drilling Procedure
TXP8'BTC
Orrtside Diameter
9.625m.
Min Nall
97.5%
Conaseson OD
k(ake-up Less
nIkkness
coupling Length
Threads per m
I") Gntla L80
Connection 10
Connection OD Option
8,823m
REGULAR
Type 1
Wall Thickness
a395m.
Connection OD
REGULAR
Option
Co9PLMc
eody Red
Grade
LBO Type i•
Drill
AN standard
1st BaM_Brown
2nd Band -
Type
Casing
3rdSand :-
:11 1
GEOMETRY
Na i nal OD
9.625 in
VVinght
40 Met
Draft
Nominal lD
8.835in.
YJan Thickness
0395.
Plain End Weight
OD Tdssanoe
API
Page 19
�,—..1110812016
ass
PIPE BODY
Ist Band: Red
2nd Band:
Brown
3rd Band: -
41h Band. -
8.679 in
39.971bs'R
PERFORMANCE
Body Yiedd Starg-h 916x1000ke Inlemal Yatd 5750 psi smfs 69000 psi
Ccs':s{3a 3090 psi
GEOMETRY
Conaseson OD
k(ake-up Less
10.625 in.
4891 in.
coupling Length
Threads per m
10925.
5
Connection 10
Connection OD Option
8,823m
REGULAR
PERFORMANCE
Ts^,Bion EAniency 100.0% Birt Yrsld stsoi 916.000x1000 Inhs.1Premm CaP3pllyf'I 5790.000 psi
We
Compression Eirelenee 1005: Compression stei 916000x1000 kax. Ailo"M Gentling 38'1100It
Its
Edsmal Pressure Capauty 3090.00) psi
MAKE-UP TORQUES
htirmum 198600-itz Optieium 20960 No-- hfasinum 23M ft4bs
OPERATION LIMIT TORQUES
Opeatng Torqua 356004 -Ys Yield Torque 43400 F. -1b5
Notes
This connection is fully interchangeable with
TXP8 BTC - 9.625 in - 36143.5147153.5158.4 IbsAt
[1] Internal Pressure Capacity related to structural resistance only. Internal pressure leak resistance as per section 10.3 API
5C31ISO 10400 - 2007.
Datasheet is also valid for Special Bevel option when applicable - except for Coupling Face Load, which will be reduced.
Please contact a local Tenans technical sales representative.
H
Hilcorp
FuvgY CmopmY
Milne Point Unit
M-13 SB Injector
Drilling Procedure
12.8 Continue running 9-5/8" surface casing
• Fill casing while running using fill up line on rig floor.
• Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
• Centralization:
o 1 centralizer every 2 joints to base of conductor
12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.10 Slow in and out of slips.
12.11 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10' from TD. Strap the
landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference
when getting the casing on depth.
12.12 Lower casing to setting depth. Confirm measurements.
12.13 Have slips staged in cellar, along with necessary equipment for the operation.
12.14 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement
job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible
reciprocate casing string while conditioning mud.
Page 20
n
Hilcorp
Envy E,
13.0 Cement 9-5/8" Surface Casing
Milne Point Unit
M-13 SB Injector
Drilling Procedure
13.1 Hold a pre job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
• How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
• Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
• Ensure adequate amounts of water for mix fluid is heated and available in the water tanks.
• Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
• Review test reports and ensure pump times are acceptable.
• Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
13.2 Document efficiency of all possible displacement pumps prior to cement job.
13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
13.5 Fill surface cement lines with water and pressure test.
13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.7 Drop bottom plug (flexible bypass plug) — HEC rep to witness. Mix and pump cement per below
calculations for the 1" 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 111 Stage Total Cement Volume:
Page 21
Section
Calculation
Vol (bbl)
Vol (ft3)
12-1/4" OH x 9-5/8"
(3,900'- 2500') x .0558 bpf x 1.3 =
101.5
570.2
J
Casing
Total Lead
101.5
570.2
12-1/4" OH x 9-5/8"
(4,900'- 3,900') x .0558 bpf x 1.3 =
72.5
407
Casing
~
9-5/8" Shoe Track
120'x .0758 bpf =
9.1
51.09
Total Tail
81.6
458
Page 21
n
Hilcorp
Milne Point Unit
M-13 SB Injector
Drilling Procedure
Cement Slurry Design (1St Stage Cement Job):
Note: Lead Cement Viscosity to be lowered to prevent poor interface once stage tool is opened
and cement is circulated to surface
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.
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
4,780' x.0758 bpf = 362.3 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, f4.5 bbis 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
Page 22
Lead Slurry
Tail Slurry
System
ExtendaCEM TM System •
SwiftCEM TM System
Density
11.7 lb/gal
15.8 lb/gal
Yield
4.298 ft3/sk
1.16 ft3/sk
Mixed
Water
21.13 gal/sk
5.04 gal/sk
Note: Lead Cement Viscosity to be lowered to prevent poor interface once stage tool is opened
and cement is circulated to surface
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.
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
4,780' x.0758 bpf = 362.3 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, f4.5 bbis 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
Page 22
Milne Point Unit
M-13 SB Injector
Drilling Procedure
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.
If ESIPC is ran, pressure up to 3000 psi to open tool and function as an ES -II Stage tool
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.
Page 23
Milne Point Unit
M-13 SB Injector
Hilcorp Drilling Procedure
Ems®ComPUY
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 211 Stage Total Cement Volume:
Cement Slurry Design (2nd stage cement job):
Section
Calculation
Vol (bbl)
Vol (ft3)
Permafrost L
20" Conductorx 9-5/8" Casing
(110') x .26 bpf x 1=
28.6
161
J
12-1/4" OH x 9-5/8" Casing
(2000'- 110') x .0558 bpf x 3 =
316.4
1776.3
5.08 gal/sk
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
314
Cement Slurry Design (2nd stage cement job):
Page 24
41 sb SA
'27os
Lead Slurry
Tail Slurry
System
Permafrost L
SwiftCEM TI System (Hal Cem)
Density
10.7 lb/gal
15.8 lb/gal
Yield
4.3279 ft3/sk
1.16 ft3/sk
Mixed
Water
21.405 gal/sk
5.08 gal/sk
Page 24
41 sb SA
'27os
H
Hilcorp
Milne Point Unit
M-13 SB Injector
Drilling Procedure
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 o L`
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:
• Pre flush type, volume (bbls) & weight (ppg)
• Cement slurry type, lead or tail, volume & weight
• Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
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 jenkel@hilcorp.com and
cdinger@hilcoW.com This will be included with the EOW documentation that goes to the AOGCC.
Page 25
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:
• BOP configuration from top down: 13-5/8" x 5M annular / 13-5/8" x 5M double gate / 13-
5/8" x 5M mud cross / 13-5/8" x 5M single gate
• Double gate ram should be dressed with 2-7/8" x 5" VBRs in top cavity, blind ram in
bottom cavity.
• Single ram can be dressed with 2-7/8" x 5" VBRs
• N/U bell nipple, install flowline.
• Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to
mud cross).
• Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual
valve
14.3 Run 5" BOP test plug
14.4 Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min.
• Test 5" test joints
• Confirm test pressures with PTD
• Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure
is trapped underneath test plug
• Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech
14.5 R/D BOP test equipment
14.6 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.7 Mix 8.9 ppg FloPro 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.
Page 26
Milne Point Unit
M-13 SB Injector
H
E,
M2
Drilling Procedure
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:
• BOP configuration from top down: 13-5/8" x 5M annular / 13-5/8" x 5M double gate / 13-
5/8" x 5M mud cross / 13-5/8" x 5M single gate
• Double gate ram should be dressed with 2-7/8" x 5" VBRs in top cavity, blind ram in
bottom cavity.
• Single ram can be dressed with 2-7/8" x 5" VBRs
• N/U bell nipple, install flowline.
• Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to
mud cross).
• Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual
valve
14.3 Run 5" BOP test plug
14.4 Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min.
• Test 5" test joints
• Confirm test pressures with PTD
• Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure
is trapped underneath test plug
• Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech
14.5 R/D BOP test equipment
14.6 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.7 Mix 8.9 ppg FloPro 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.
Page 26
n
Hilcorp
Env q y
15.0 Drill 8-1/2" Hole Section
15.1 M/U 8.5" Cleanout BHA (Milltooth Bit & 1.22° PDM)
Milne Point Unit
M-13 SB Injector
Drilling Procedure
15.2 TIH w/ 8-1/2" cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out
stage tool or ESIPC.
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 volumP pressure (every '''A 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 l�pg EMW. Chart Test. Ensure test is recorded on same chart as FIT.
VDocument incremental volume pumped (and subsequent pressure) and volume returned.
15.8 POOH & LD Cleanout BHA
15.9 P/U 8-1/2" directional BHA.
• Ensure BHA components have been inspected previously.
• Drift and caliper all components before M/ J. Visually verify no debris inside components that
cannot be drifted.
• Ensure TF offset is measured accurately and entered correctly into the MWD software.
• Ensure MWD is R/U and operational.
• Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
• Drill string will be 5" 19.5# 5-135 DS50 & NC50.
• Run a ported float in the production hole section.
15.10 8-1/2" hole section mud program summary:
Density: Weighting material to be used for the hole section will be calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg
above highest anticipated MW. Use appropriate SAFECARB blend on this well
Page 27
H
Hilcorp
Milne Point Unit
M-13 SB Injector
Drilling Procedure
• Solids Concentration: It is imperative that the solids concentration be kept low while
drilling the production hole section. Keep the shaker screen size optimized and fluid
running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure
we are running the finest screens possible.
• Rheology: Keep viscosifier additions to an absolute minimum (N -VIS). Data suggests
excessive viscosifier concentrations can decrease return permeability. Do not pump high
vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for
sufficient hole cleaning
• Run the centrifuge continuously while drilling the production hole, this will help with
solids removal.
• Dump and dilute as necessary to keep drilled solids to an absolute minimum.
• MD Totco PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller's console, Co Man office, &
Toolpusher office.
System Type: 8.9 — 9.5 ppg HoPro drilling fluid
Pro erties:
Interval
Densit
PV
YP
LSYP
Total Solids
MBT
HPHT
Hardness
Production
8.9-9.5
15-25 - ALAP
1 15-30
1 4-6
1 <10%
1 <8
1 <1 1.0
<100
System Formulation:
Product- production
Size
Pkg
ppb or (% liquids)
Busan 1060
55
gal dm
0.095
FLOTROL
55
lb sx
6
CONQOR404 WH (8.5 gal/100
bbls)
55
gal dm
0.2
FLO-VIS PLUS
25
lb sx
0.7
KCl
50
lb sx
10.7
SMB
50
lb sx
0.45
LOTORQ
55
gal dm
1.0
SAFE-CARB 10 (verify)
50
lb sx
10
SAFE -GARB 20 (verify)
50
lb sx
10
Soda Ash
50
lb sx
0.5
Page 28
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Hilcorp
15.11 TIH with 8-1/2" directional assembly to bottom
15.12 Displace wellbore to 8.9 ppg Flo Pro drilling fluid
Milne Point Unit
M-13 SB Injector
Drilling Procedure
15.13 Begin drilling 8.5" hole section, on -bottom staging technique:
• Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k.
• Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations
• If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to P/U
off bottom and restart on bottom staging technique. If stick slip continues, consider adding
.5% lubes
15.14 Drill 8-1/2" hole section to section TD per Geologist and Drilling Engineer.
• Flow Rate: 350-550 gpm, target min. AV's 200 ft/min, 385 gpm
• RPM: 120+
• Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly
wet to maximize solids removal efficiency. Check for holes in screens on every connection.
• Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
• Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection --
• Monitor Torque and Drag with pumps on every 5 stands
• Monitor ECD, pump pressure & hookload trends for hole cleaning indication
• Surveys can be taken more frequently if deemed necessary.
• Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible and avoid stopping with the
BHA across the sand for any extended period of time.
• Use ADR to stay in section. Reservoir plan is to undulate between Schrader OA & OA3
lobes in 1000-1500' MD increments, and keeping DLS <3° when moving between lobes
• 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.
• Target ROP is as fast as we can clean the hole without having to backream connections
• Offset injection Pressure from F-110 & L-50 has been seen on recent M -Pad wells. ✓-
Watch for higher than expected pressure. MPD will be utilized to monitor pressure
build up on connections
• AC: There are no wells with a separation factor of <l.
• Fluid Loss:
• Losses have been seen after crossing a fault and drilling into the depleted reservoir near
J-24. M-13 will not cross the same fault and losses are not expected. If losses are seen,
LCM pills have healed losses.
• Schrader Bluff OA Concretions: 5-10% of lateral
L-47: 6%, L-50 9.5%
F-106: 6.1%, F-107: 4.7%, F-018: 9.9%, F-109: 10%, F-110: 10.1%
15.15 Reference: Open hole sidetracking practice:
Page 29
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Hilcorp
En C22
Milne Point Unit
M-13 SB Injector
Drilling Procedure
• If a known fault is coming up, put a slight "kick-off ramp" in wellbore ahead of the fault so
we have a nice place to low side.
• Attempt to lowside in a fast drilling interval where the wellbore is headed up.
• Orient TF to low side and dig a trough with high flowrates for the first 10 ft, working string
back and forth. Trough for approx. 30 min.
• Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the
openhole sidetrack is achieved.
15.16 Once TD is reached, swap to the completion AFE
15.17 At TD, CBU at least 4 times at 200 ft/min AV (385+ gpm) and rotation (120+ rpm). Pump
tandem sweeps if needed
• Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent
stream, circulate more if necessary
• Ensure mud has necessary lube % for running liner
• If seepage losses are seen while drilling, consider reducing MW at TD to 9.Oppg minimum
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 (0 350ml samples passing through the screen in the same
amount of time which will indicate no plugging of the screen). Reference PST Test
Procedure
• Injection Control Devices (ICDs) are wire wrapped, and require passing PST with 250µ
Coupons
• Circulate and condition mud as much as needed to pass the production screen test
• If not passing after first test, call Completion Engineer
15.19 BROOH with the drilling assembly to the 9-5/8" casing shoe
• Circulate at full drill rate (385 gpm max).
• Rotate at maximum rpm that can be sustained.
• Limit pulling speed to 5 — 10 min/std (slip to slip time, not including connections).
• 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
Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to
determine if well is breathing, treat all flow as an influx until proven otherwise
If necessary, increase MW at shoe for any higher than expected pressure seen
15.22 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball
drops.
Page 30
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Hilcorp
Milne Point Unit
M-13 SB Injector
Drilling Procedure
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.
Page 31
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Hilcorp
16.0 Run 4-1/2" Injection Liner (Lower Completion)
Milne Point Unit
M-13 SB Injector
Drilling Procedure
16.1. Well control preparedness: In the event of an influx of formation fluids while running the 4-
1/2" liner with ICD and swell packers, the following well control response procedure will be
followed:
• With ICD 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.
• 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. Well control preparedness: In the event of an influx of formation fluids while running the 2-
3/8" inner string inside the 4-1/2" liner:
/ • P/U & M/U the 5" safety joint (with 4-1/2" x 2-3/8" lled on
V/ bottom, TIW valve in open position on top, 2-3/8" handling joint above TIW). M/U 2-3/8"
and then 4-1/2" to triple connect.
• This joint shall be fully M/U with crossovers and available prior to running the first joint
• Slack off and position the 5" DP across the BOP, shut in ram or annular on 5" DP. Close
TIW valve. Proceed with well kill operations.
16.4. R/U 4-1/2" liner running equipment.
• Ensure 4-1/2" Hydril 625 x DS -50 crossover is on rig floor and M/U to FOSV.
• Ensure the liner has been drifted on the deck prior to running.
• Be sure to count the total # of joints on the deck before running.
• Keep hole covered while R/U casing tools.
• Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info.
16.5. Run 4-1/2" injection liner.
• 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 ICDs.
• Utilize a collar clamp until weight is sufficient to keep slips set properly.
• Use lift nubbins and stabbing guides for the liner run.
• Fill 4-'/z" liner with PST passed mud (to keep from plugging ICDs with solids)
• Install ICDs and swell packers as per the Running Order
• (From Completion Engineer post TD).
• Do not place tongs or slips on swell packer elements or ICDs.
• ICD and swell packer placement ±40'
• The ICD connection is 4-1/2" 13.5# Hydril 625
• Remove protective packaging on swell packers just prior to picking up
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
Page 32
H
Hilcorp
Ems CmuY^Y
Milne Point Unit
M-13 513 Injector
Drilling Procedure
• 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
Page 33
H
Hilcow
Emra'ComP..Y
For the latest performance data. always visit our website: www.tenaris.com
Wedge 625®
Milne Point Unit
M-13 SB Injector
Drilling Procedure
n...m.121042017
OUKide Diameter
d-500..
Nin. WA
07.5%
SPAYS
101 psi
C fla,ee
Isla In
Tkidkness
PI Gratle Lb
aw
C'.ONNECTION DATP,.
Type 1
Well Thickness
0050 �_
Con.hi OD
REGOIAR
Cdnrecdon OD
4714..
opt..
3.849 h.
CODPDND
PIPE BODY
Threatis win
3,59
Canrecdwe 00 Opkdn
REGOLHR
Body Red
IM Bared: Red
Grade
L00 Type P
Drill
HPI Standard
td Band: Brown
3rW Band:
T. Efts
514%
bim Yeb Sven001
279370.1000
Tnd Ba" -
Brown
TW
Casino
aro Band -
3M Band: -
Co�ryressidn El5c
315%
Cmryressim Soenp.
290.115.109
Max Abwa0le Bendng
9D Band: -
PIPE BODY DATA
GEOMETRY
Nomnal DD 4.500.. Noirvnal Weiyn 1350 DNR DNF 3795 n.
Nomrwl ID 3.920.. WnThicYness 01 n. Pa. End Weielrc 1345 DNR
CO Tctewloe HPI
PERFORMANCE
BA, Yeb Sdeeip
307.IMIbs
Intimal Yield
5020 W.
SPAYS
101 psi
C fla,ee
Isla In
C'.ONNECTION DATP,.
GEOMETRY
Cdnrecdon OD
4714..
Connection ID
3.849 h.
Make-up Loss
4.830..
Threatis win
3,59
Canrecdwe 00 Opkdn
REGOLHR
PERFORMANCE
T. Efts
514%
bim Yeb Sven001
279370.1000
IntmWPrassure Capavty
902041l,e
lbs
Co�ryressidn El5c
315%
Cmryressim Soenp.
290.115.109
Max Abwa0le Bendng
T1.7-11 It
Ibs
EaOernal Pressure Capadty
851041 psi
MAKE-UPTORQUES
Min in
8100Es
Cob—
961 ft b-
Maumum
1281 Ribs
OPERATION LIMIT TORQUES
Oteratig Tarple 122INN" Ydd Tanpw 1501 RJbs
Notes
For further information on concepts ind iwted in this datasheet, download the Datasheet Manual from www tenans.com
16.6. Ensure that the liner top packer is set — 150' MD above the 9-5/8" shoe.
• AOGCC regulations require a minimum 100' overlap between the inner and outer strings as
per 20 AAC 25.030(d)(6). Ensure hanger/packer will not be set in a 9-5/8" connection.
16.7. R/U false rotary and run 2-3/8" 6.4#/ft inner string.
Page 34
H
Hilcorp
��
Milne Point Unit
M-13 SB Injector
Drilling Procedure
16.8. 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.
16.9. 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.
16.10. Note weight of liner. Run liner in the hole one stand and pump through liner hanger to ensure a
clear flow path exists.
16.11. 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.
16.12. The liner and inner string will prevent the DP from auto filling. Fill DP every 5 stands, more
frequently if SOW trend indicates.
16.13. 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.
16.14. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
16.15. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
16.16. Rig up to pump down the work string with the rig pumps.
16.17. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill
pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger.
16.18. Rig up to pump down the work string with the rig pumps.
16.19. Break circulation and begin displacing wellbore to —9.2 ppg KCl/NaCI (adjust brine weight if
needed). Note the large OD on the ICDs. Begin circulating at —1 BPM and monitor pump
pressures. Slowly bring rate up while circulating the lateral clean.
16.20. Monitor pump pressures closely and adjust pump rate if the well appears to be packing off at the
ICDs. Note all losses. Catch mud for future use if feasible.
16.21. Monitor the returned fluids carefully and when no more filter cake appears at the shaker begin
pumping SAPP pill.
16.22. Mix and pump 3 tandem 40 bbl 10 ppb SAPP pills (120 bbl total SAPP pill) with 100 bbl in
between. Keep circulation rate low to keep from packing off around the ICDs. Monitor shakers
for returns of mud filter cake and calcium carbonate. Circulate the well clean.
Page 35
n
Hileorp
Esc iT
16.23. Repeat pumping SAPP pills as needed until the wellbore is clean.
Milne Point Unit
M-13 SB Injector
Drilling Procedure
Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being
removed, including an increase in the loss rate.
Monitor the returned fluids to ensure as much mud and wall cake has been removed from the
wellbore as possible so as to not impact wellbore injectivity.
16.24. Displace 1.5 OH & Liner volumes.
16.25. Shut down pumps. Drop setting ball down the workstring and pump slowly (1-2 bpm). Slow
pump before the ball seats. Do not allow ball to slam into ball seat. Pressure up to 1,500 psi to
shift the wellbore isolation valve closed.
16.26. 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.
16.27. 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,
16.28. PU to neutral weight, close BOP and test annulus to 1500 psi for 10 min and chart record same.
16.29. 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.
16.30. Displace 2-3/8" x Liner, pump 2 circulations.
16.31. POOH, L/D and inspect running tools. If setting of liner hanger/packer proceeded as planned,
LDDP on the TOIL L/D 2-3/8" inner string. Rack back enough 5" drill pipe for liner top clean
out run
16.32. Make up 3.5" wash tool & RIH on 5" DP to 4.5" liner top.
16.33. Flush liner top at max rate while displacing out well to clean brine.
16.34. POOH LD Remaining 5" DP.
Page 36
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
wrivardghilcorp.com for submission to AOGCC.
17.2 M/U injection assembly and RIH to setting depth. TIH no faster than 90 ft/min.
• Ensure wear bushing is pulled.
• Ensure 3-'/z" EUE 8RD x NC -50 crossover is on rig floor and M/U to FOSV.
• Ensure all tubing has been drifted in the pipe shed prior to running.
• Be sure to count the total # of joints in the pipe shed before running.
• Keep hole covered while R/U casing tools.
• Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info.
• Monitor displacement from wellbore while RIH.
3-1/2" 9.3# L-80 EUE 8RD
Casing OD
Minimum
Milne Point Unit
Maximum
Operating Torque
3.5"
2,350 ft -lbs
M-13 SB Injector
3,910 ft -lbs
Hil 2o7
Eno®' Cpay
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
wrivardghilcorp.com for submission to AOGCC.
17.2 M/U injection assembly and RIH to setting depth. TIH no faster than 90 ft/min.
• Ensure wear bushing is pulled.
• Ensure 3-'/z" EUE 8RD x NC -50 crossover is on rig floor and M/U to FOSV.
• Ensure all tubing has been drifted in the pipe shed prior to running.
• Be sure to count the total # of joints in the pipe shed before running.
• Keep hole covered while R/U casing tools.
• Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info.
• Monitor displacement from wellbore while RIH.
3-1/2" 9.3# L-80 EUE 8RD
Casing OD
Minimum
Optimum
Maximum
Operating Torque
3.5"
2,350 ft -lbs
3,130 ft -lbs
3,910 ft -lbs
3-%" Upper Completion Running Order
• 3-`/z" Baker Ported Bullet Nose seal (stung into the tie back receptacle)
• 3 joints (minimum, more as needed) 3-%" 9.3#/ft, L-80 EUE 8RD tubing
• 3-`h" "X -N" nipple at TBD
• 3-'/2" 9.3#/ft, L-80 EUE 8RD tubing
• 3-'/2" "X" nipple at TBD MD
• 3-%2" 9.3#/ft, L-80 EUE 8RD space out pups
• 1 joint 3-'/z" 9.3#/ft, L-80 EUE 8RD tubing
• 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 (+/- V to 2' above No -Go). Place all
space out pups below the first full joint of the completion.
Page 37
H
Hilo
17.5 Makeup the tubing hanger and landing joint.
Milne Point Unit
M-13 SB Injector
Drilling Procedure
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 I% corrosion inhibitor.
17.8 Freeze protect the tubing and IA to 3000' MD with ±210 bbl of diesel. �1
h 17.9 Land hanger. RILDs and test hanger. �`
r\f' 17.10 Continue pressurizing the annulus to 000 p '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.
I IIU
18. RDMO Doyon 14
Page 38
H
HilcoR
19.0 Doyon 14 Diverter Schematic
214W 2M R,w-
21414' 2M—
D"a `T'
21-V<• 2A
Spx r Spa
16.&4,3u ,
21-V4' 2M DSO
Page 39
Milne Point Unit
M-13 SB Injector
Drilling Procedure
-16' FO Opc+eng KnFG V V.e
16'Dne LIM
Milne Point Unit
M-13 SB Injector
Hilcox Drilling Procedure
20.0 Doyon 14 BOP Schematic
Kill Line --"---_
Page 40
2-7/8" x 5" VBR
Blind Rams
x 5M HCR
hoke Lim
tl Gate valve
2-7/8" x 5" VBR
H
Hilcorp
E, c22
21.0 Wellhead Schematic
Milne Point Unit
M-13 SB Injector
Drilling Procedure
Ncae: Dimw7cmat infranamare9cfel
ea this drxxu�; arz estim ud
Page 41
}„
Milne Point Unit
M-13 SB Injector
Hilcorp Drilling Procedure
Em E my
22.0 Days Vs Depth
m
C[C811]
Z O,
12000
14000
16000
0
Page 42
MPU M-13 SB OA Injector
Days vs Depth
5 10 15 20
Days
jector
25 30
n
Hilcorp
Enugy Carp
23.0 Formation Tops & Information
Milne Point Unit
M-13 SB Injector
Drilling Procedure
MPU M-13 Formations
(wp05)
MD
(ft)
TVDss
(ft)
TVD
(ft)
Formation Pressure
(psi)
EMW
(ppg)
Base Permafrost
1963
-1823
1878
826.32
8.46
LA3
3374
-3109
3164
1392.16
8.46
Schrader Bluff NA
4075
-3630
3685
1621.4
8.46
Schrader Bluff OA
4735
-3869
3924
1726.56
8.46
L -Pad Data Sheet Formation Description (Closest & Most Analogous MPU Pad to Moose Pad)
GENERALIZED GEOLOGICAL
FORECAST
SS
TVD
FM
LITH
GEOLOGICAL
COMMENTS
DESCRIPTION
.0
NOTE: See Ind W.I WellPma®m for
7y�„v
Gubi
specdic casing design, depths, sues,
.,m
1W
weights. grades and connections.
o
'
cans. b mMbmand am small gavel
g
;•
mv, hhr .ift
•td, moor einatans.
1,000'
a"
IF SIGNIFICANT AMOUNTS OF GRAVEL
ARE ENCOUNTERED WHEN DRILLING THE
♦e SURFACE HOLE, THE VISCOSITY OF THE
MUD SYSTEM SHOULD IMMEDIATELY BE
RAISED TO 150 SEC TO ENSURE
EFFECTIVE HOLE CLEANING.
,Iso•
Base permafrost
hlerbM. e} exam, cleYt am Mnabnee vdth oonalpal
20001
slow a cal. Wabh possible sldvtn c ng rNN
we.Nne'namtny LJl aL•15.
s,g..
timalk
No hydrates encountered on L•Pad wells
drilled to date.
Coalnaa INaI»aa of um. iley. am en
oc..bnel.hent of coal. Traces of pyrib at •I. 3too It
3,000•
hbrval at N- 340(1 it can be tacky and tight (1.41).
s between a n
Clay hinbed300111 45
C
34 -
r
L
A
3157'
Runs
Y
UGNU: Sema a+c.n.nlrg n and sands bhmh•ra
(Ali
mads W at (bem top Is bent.) mam sand fine sand,
al ty inch eeaer bvalopa0 h4ervminp states as ya
UGNU
pnpess lydo the Lab Y(d.epexl
Ilgnutnd Schridde Bluff: Pa.lae MdrmerbonenmltW
Leu,i
b SWcorner of Milne tlaMlopment Na tarn dna ii
(Aa)
d rstmcttaeaM wet.
'3131'
Wands
(+ 9)
.Oat,.
(NA)
Schrader Bluff Sands: ✓
4,000'
N.Lrd.
( Kk o.
Coniaed levering canenhg -pramM
saasabaw -411--Schrader Bluff: Possible lost circulation
E'n
except mon cademod aro wln«ea.mntt coal. zone while drilling long strings and running
•4170'
os.neIct
Pa.iiblulhydnmaroone nmded casing. Recommend sleep setting surface
tl`gaa dSchrader 8101k.. ON
IoM
ItK
mswcornerofbunea..emanent wram L-a5an casing for Kuparuk long strings. Also, the
mmpleled in an SNnbr Blaf... d Nanhemanaa Schrader Bluff sands are a potential
SchraderL-PW
Is d mtmctwe am rel.
differential stuck pipe interval if left un -cased
Bluff
Surlaos..IN polo h state bier for Kuparuk long strings.
Sands:
sdnradar alit one sand ler longer ..h ..Iii
Page 43
n
Hilcorp
U c��,
24.0 Anticipated Drilling Hazards
Milne Point Unit
M-13 SB Injector
Drilling Procedure
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 f
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. Add 1.0 — 2.0 ppb
Lecithin to the system to help thin the mud and release the gas. 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. M-13
has a close approach with a potential future well plan, which does not pose any risk.
Wellbore stability (Permafrost, running sands and gravel, conductor broaching):
Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of
time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH
speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and
swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching.
Maintain mud parameters and increase MW to combat running sands and gravel formations.
H2S:
Treat every hole section as though it has the potential for H2S. No H2S events have been documented
on drill wells on this pad.
Page 44
H
Hilcorp
Milne Point Unit
M-13 SB Injector
Drilling Procedure
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 112S detection equipment meeting the requirements J
of 20 AAC 25.066.
3. In the event 1-12S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Page 45
n
Hilcorp
Ute,
8-1/2" Hole Section:
Milne Point Unit
M-13 SB Injector
Drilling Procedure
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 1-12S 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 1-12S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event 1-12S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Abnormal Pressures and Temperatures: 1
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. There are no wells with a separation factor of <l.
Page 46
25.0 Doyon 14 Layout
Page 47
saw
LE
Milne Point Unit
M•13 SB Injector
Drilling Procedure
H
Hilc'm22orp
.
E
Milne Point Unit
M-13 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.
Page 48
H
Hilc
T —orp
rp
27.0 Doyon 14 Choke Manifold Schematic
Milne Point Unit
M•13 SB Injector
Drilling Procedure
_ = Z
v u n w 0
a
=wx> m°ti°
N y
ZA
vv
ZS
C
U/
n N
N C o
y n p
r
P GD < P
S
A O d
� p
Ow
ao 3
<
a u
a
3 D 3
3 '
;a
M
c
E
_
L1 A �
Q
W
V
C
W
N
O
J
W
r
o
a'
A
,p
Gam'
'til �
coo
h
r
5'
Ln
.o
a
0
A� =
O CL
Page 49
H
Hilcorp
�-22,
Milne Point Unit
M-13 SB Injector
Drilling Procedure
28.0 Casing Design
n
Hilc2 p
Calculation & Casing Design Factors
DATE: 6.6.2019
WELL: MPU M-13
DESIGN BY: Joe Engel
Criteria:
Hole Size 12-1/4" Mud Density: 9.2 ppg
Hole Size 8-1/2" Mud Density: 9.2 ppg
Hole Size Mud Density:
Drilling Mode
MASP:
MASP:
1338 psi (see attached MASP determination &
Production Mode
MASP: 1338 psi (see attached MASP determination & calculation)
Collapse Calculation:
Section Calculation
1 Normal gradient external stress (0.494 psi/ft) and the casing evacuated for the internal stress
Page 50
Casing Section
Calculation/Specification
1
2 3 4
Casing OD
9-5/8"
4-1/2"
Top (MD)
0
4,900
Top (TVD)
0
3,936
Bottom (MD)
4,900
16,250
Bottom (TVD)
3,936
3,963
Length
41900
11,350
Weight (ppf)
40
13.5
Grade
L-80
L-80
Connection
TV
H625
Weight w/o Bouyancy Factor (lbs)
- 196,000
153,225 =
Tension at Top of Section (Ibs)
196,000
153,225
Min strength Tension (1000 lbs)
916
279
Worst Case Safety Factor (rension)
4.67 J
1.82/
Collapse Pressure at bottom (Psi)
1,944
1,958
Collapse Resistance w/o tension (Psi)
3,090
8,540
Worst Case Safety Factor (Collapse)
1.59 ✓
4.36
MASP (psi)1,338
1,338
Minimum Yield (psi)
5,750
9,020
Worst case safety factor (Burst)
1 4.30 ✓J
6.74
Page 50
29.0 8-1/2" Hole Section MASP
Maximum Anticipated Surface Pressure Calculation
11 8-1/2" Hole Section
Hitcorp
MPU M-13
Milne Point Unit
MD TVD
Planned Top: 4900 3936
Planned TD: 16246 3963
Anticipated Formations and Pressures:
Formation TVD Est Pressure Oil/Gas/Wet PPG Grad
Schrader Bluff OA Sandi 3,936 1732 1 Oil 1 8.46 0.440
Offset Well Mud Densities
Well MW range Top (TVD) Bottom (TVD) Date
L-50
Milne Point Unit
Surface
M-13 SB Injector
Hilc
B c�Po
Drilling Procedure
29.0 8-1/2" Hole Section MASP
Maximum Anticipated Surface Pressure Calculation
11 8-1/2" Hole Section
Hitcorp
MPU M-13
Milne Point Unit
MD TVD
Planned Top: 4900 3936
Planned TD: 16246 3963
Anticipated Formations and Pressures:
Formation TVD Est Pressure Oil/Gas/Wet PPG Grad
Schrader Bluff OA Sandi 3,936 1732 1 Oil 1 8.46 0.440
Offset Well Mud Densities
Well MW range Top (TVD) Bottom (TVD) Date
L-50
8.8-9.1
Surface
4125
2015
L-49
9.0-9.2
Surface
4196
2015
L-48
8.9-9.2
Surface
4147
2015
L-47
8.8-9.0
Surface
4158
2015
L-46
9.0-9.3
Surface
4177
2015
Assumptions:
1. Field test data suggests the Fracture Gradient in the Schrader Bluff is btwn 11.5 and 15 ppg EMW.
2. Maximum planned mud density for the 8-1/2" hole section is 9.5 ppg.
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:
3,936 (ft) x 0.78(psi/ft)= 3070
3070(psi) - [0.1(psi/ft)*3936(ft)]= 2676 psi
MASP from pore pressure (complete evacuation of wellbore togas from Schrader_Bluff OA saRa--
3936 (ft) x 0.44(psi/ft)= 1732 psi �}
1732(psi)-0.1(psi/ft)*3936(ft) 1338 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.
Page 51
30.0 Spider Plot (NAD 27) (Governmental Sections)
Milne Point Unit
M-13 SB Injector
Drilling Procedure
Milne Point Unit
Adaska State Plane Zone 4 NAD 1927
(7rrr�
MPU M-13 Well 0 1,500 3.000
wpb :c,v wp_05 Feet
Page 52
g9JFe, t LC31Pc1
-F,
ADL388235 Sea 12i
t /
ADL025509 .-5e,'-,
,•
''
ADL355023
`s.':
'♦� t/,
i �i
_-_"
.. F,�. ..,...,.
' ♦
• L%3' � � �
It, , // w r,
.Y �^ + is � `/a, ='PAD PIPELINE TiEE-IN P
,-r4-- •5.-.;�sre: —
♦.•'
1(PU NI -Bi -SHL
;• , �
♦� ♦N�
\IPU W13i TPH
=FSrn...,��s.¢n,
1
```
•/n�
, •
t 4.IJi ♦ �
/ i , LJSP=i
F.',C ` F..9] ,
`
I / I
.Sac. 13 /'
`
/ I SPC 1F ''• 1 `,SPC. 11
'� +
+ 1 I63D,
I LIS
tl
\• r ,
1 MI E
I
Of TUNR I'. "`�' `
I •s ra.,cFe
%4 ,
r` , ,
•U013NO09E '� �u'�
, + j` U013NB10E %\
'
.``
1 / /I
`ADL025515 � `•
AL •vren
1 I
vt
fJr
Sec 19 �•+.; Sea 26
Sec. 23
1 Sec/
633}
1
1 ♦�`
` Ms
1
f
`l:
3ii.L -.
.SaLI IFI itt
• _ _ _ _.L�__Y 1 yl'.P51
1L
--
Legend
• naPU M-13i_SHL Other Surface Holes (SHL)
ADL025519
``
X MPU M-13i_TPH Other Boom Holes(BHL)
Sec. 26
Sec. 25
AD - - - Other Well Paths IN
1
"e- MPU M-13i_BHL _ Coastline (USGS 1:63k) ;_
,KUPARUK RIVER UNR
r. r
:s
Q OH and Gas Unit Boundary •Y
/
Pad Footprint
Milne Point Unit
Adaska State Plane Zone 4 NAD 1927
(7rrr�
MPU M-13 Well 0 1,500 3.000
wpb :c,v wp_05 Feet
Page 52
H
Hilcorp
IT. C,
31.0 Surface Plat (As Built) (NAD 27)
Milne Point Unit
M-13 SB Injector
Drilling Procedure
Page 53
7FIBPA0JECT
"�
I
p
A
SEG 12
13
fn�l �4j
_
SEC. 11 I
_SEC
SEC u
M PA9�
1
.-to■
M-11 ■
+ M_,3
II
M-12 ■
IM-14
I
23
1
� MBE SITE E
M-15
I
M-16
I
I
VTCI NTMAP
S
II
G: M
I
(
� AS-SiMRD COWI1CiCR
■ EXISTI110 cmXXTm
II
M-0■
1�II STAR PLWE COCROEUTES AIE NI .ERE
4.
2. CEOEEIIC P09f'b6 ARE WRIT.
1 BARS W NOIAZCNTAL ANO \ERUCIC p]N1RM IS MOOSE
PAD MbAlBlrt 0R2
S DABS IF "' ... 1ANtlA 2D2S B 31,
I
A. BEfpRMQ IEID 8D NO1S-M P 47-0A.
GRAPHIC SCALE
o Iw400
MOOSE PAD
( IN FEET 1
I nen . 200 It,
LOCATED
WITHIN PROTRACTED SEC. 14,
T. 13 N., R. 9 E., UMIAT MERIDIAN, ALASKA
WELL
A.S.P.
PLANT
GEODETIC
GEODETIC
SECTION
PAD
CELLAR
BASE
NO.
COORDINATES
COORDINATES
POSITION DMS
POSITION D.DD
OFFSETS
ELEVATION
BOX EL.
FLANGE EL.
M-13
Y. 6.027,765.69
N- 1,168.04
70'29'12.776'
70.4868822'
4.913' FSL
25.0'
N/A
N/A
X= 533,993.80
E= 1,994.99
14943'19.767"
149.7221575'
171' FEL
M-14
Y= 6,027,765.66
N- 1,168.00
70'29'12.780"
70.4868833'
4,913' FSL
25.0•
N/A
N/A
X. 533.903.81
E• 1,90aOO
149'43'22.415"
149.7228931'
261' FEL
M-15
Y= 6,027,765.69
N= 1,168.04
70'29'12.784"
70.4868844'
4,914' FSL
25.1'
N/A
N/A
X. 533.813.68
E- 1,814.85
14943'25.067"
1497235297'
351' FEL
M-16
Y= 6,027,765.63
N= 1.167.98
70'29'12.787'
70.4868853'
4,914' FSL
25.1'
N/A
N/A
X- 533.723.83
1 E- 1.724.99
149'43'27.710"
149.7243639'
441' FEL
Hilcorp Alaska
:. .
MPU MOOSE PAD
L
P B
a.0
1111
AS -STAKED CONDUCTORS
E Lam
WELLS 13,14,15,16,18
t v 1
Page 53
H
HilcoR
U�
Milne Point Unit
M-13 SB Injector
Drilling Procedure
32.0 Schrader Bluff OA Sand Offset MW vs TVD Chart
Schrader Bluff OA Sand Offset MW vs TVD
mw, PPB
8.5 8.7 8.9 9.1 9.3 9.5 9.7 9.9 10.1 10.3 10.5
0 111111
iQ:4U]
1500
2000
x
0
2500
KiCH1]
3500
4500
Page 54
-MPU L-46 (2015)
-MPU L-47 (2015)
-MPU L-48 (2015)
MPU L-49 (2015)
-MPU L-50 (2015)
-MPU F-106 (2017)
-MPU F-107 (2017)
-MPU F-108 (2017)
-MPU F-109 (2017)
-MPU F-110 (2017)
n
Hilcorp
En CtT
Milne Point Unit
M-13 SB Injector
Drilling Procedure
33.0 Drill Pipe Information 5" 19.5# S-135 DS -50 & NC50
Drill Pipe Configuration
Pipe Body OD
w 5.000
Pipe Body Wall Thidmess
m 0.362
Pipe Body Grade
S-135
Drill Pipe Length
Range2
Connection
GPOS50
Tool Joint OD
6.625
Tod Joint to
m: 3.250
Pin Tong
9
Box Tong
m'. 12
BO % impaction Class
Nominal Weight Designation
19.50
Drill Pipe Approximate Length
and 31.5
SrnoothEOge Height
(w)Y32 Rased
Tool Joint SMYS
aa+ 120 000
Upset Type
t0
Max Upset OD (DTE)
un. 5.125
Friction Factor
1.0
N. Tcra :w[e may 1-1. nNP tlN.
Drill Pipe Performance
Nominal
80 % Inspection Class
API Premium Glass
Drill -Pipe Length Rangel
ow 712,100
560800
Performance of Drill Pipe with Roe Bcdv at
Pipe Torsional Strenp
Best Estimates
Nominal
58.100
80
% Inspection Class
1.24
1.24
y¢n,o l +w°so¢"`�01 `�""'��""
59.310
rmrn¢ra+nm
Opere[bnel
Mez Teosim
Drill Pili Adlld Weigh
24.11
2329
Cdlapse
roue m+e¢f
To ue pn+nsl
10.029
Fluid Disolacement
tw+m 0.37
0.36
4.855
Wall Thickness
Tension Onty 0
560,8(10
Fluid D'Is atenlent
nooks.
0.0065
nan:x¢¢m .aur
43.100
c[.narca rn¢¢¢r 39.6Q0
410,500
Fluid Ca
tl�m 0.70
0.72
wzi 19.635
18.514
18.514
Cross Sectional Area of to
Fluid Ca
+eurinu 0.0169 0.0167
0.0172
na,.nli„ roar
36,100
Tension On 0
560.800
DnR Size
+Inn 3.125
6.953
18.953
cwnarc¢�uamw 32.100
467.400
a,[ an nn�¢mmr you ar us omuc.
w,, Dull wo. i::e.nun+'�w�.Rar[yernrr.��¢m.:r.¢raampx
mey mn mrr�r..s.im[rwlpiamecwnno y.¢ounri�wr..
Connection Performance
GPDS50 (
6.625 mn OD X
3.250 - ID )
120,000 +rwn
n[«. ro mn.rne[ [000nn[m wemnn[I m..... NJr rta+- rr.xo<n�mr¢n¢um x aa�ra
Tod Jdnt Torsipna Sbeni rn.l=a, 71,800
Tod Jam Tensile Stren oth �¢I 1,250,000
Elevator Shoulder Information
SmoothEtlge Height
3+32 Raised
Box OD on+ 8.812
Elevator capacity M11,656,000
Assumed Elevator Bore Diameter 1-15-219
Pipe Body Slip Crushing Capacity
Q r
Ae
Tool Joint Dimensions
1886 d OD oN' 6.435
wrmun rod �mnconuN 5.930
rmminm cuss Im
1FrVnun Tod Jflllmmr 5.93
can¢m¢i¢ nn1
0.01 z mn
Worn to Ain TJ OD to
API Premium Class
Nall: Ele.afir [.yaE) ¢.v� ¢m aiunc¢ Ekv¢tif Som, eW Y!¢t hcb. anE [mla'� :Irex4M 11¢.lOGpil.
rvm[ n mm[n ee.mar oo Irux�'Fsemval�r [��.u�m m.cin¢ mane.w mm:n.
Pipe Body Gonfgumidw ( 5 tm> OD 0.362 en> Wall S-135)
Pipe Body Performance
Page 55
Pipe Body Ccnfiguned+m( 5m) Do 0-362+mr Wall S-135)
Nc«: N¢miul euz
<�um¢ m o-.3•, sew
qr PPl
Nominal
80 % Inspection Class
API Premium Glass
Pipe Tensille strength
ow 712,100
560800
560.800
Pipe Torsional Strenp
74,100
58.100
58.100
TJ+PipeBody Torsional Ratio
0.97
1.24
1.24
80% Pipe Torsional Strength
59.310
46.500
46.500
Burst
+aN 17,105
15.638
15,635
Cdlapse
tai 15.672
10,029
10.029
Pipe OD
en 5.000
4.855
4.855
Wall Thickness
!m+ 0.362
0290
x290
Nominal Pipe ID
ami 4276
4276
14.zfo
Cross Sectiooel Area of Pipe Body
tow 5275
4.154
4.154
Crass Sectional Area of DD
wzi 19.635
18.514
18.514
Cross Sectional Area of to
tu-zr 14.360
14.
14.360
S+scSan ModUWs
wsn 5.706
4.476
14.476
Polar Section Modulus
war IIA15
6.953
18.953
Nc«: N¢miul euz
<�um¢ m o-.3•, sew
qr PPl
Hilcorp Alaska, LLC
Milne Point
M Pt Moose Pad
Plan: MPU M -13i
MPU M -13i
Plan: MPU M -13i wp05
Standard Proposal Report
30 May, 2019
HALLIBURTON
Sperry Drilling Services
Project; Milne Point
Site: M Pf Moase Pad
Well: Plan: MPUM-131
34 15N5.15
Wellbore: MPUM-13i
MA"IBURTaN
Design: MPU M -13i wp05
10640.30
AS
81-a, a
tLCCFF
+U..
IAlpn m CurvawreError
ASon
5w
VSeel Te,el
App l� 30Eno,
000
.1rvaWemiy
3J 10
elio
000
'E 750 P
p O .i p
1500 AGS ,�" n OS b R SJ P°430 yF'O K
p O p q .fes c
^q.&' F� OFit' n .,p pyKZ� yea F",�m°£a F�^ .° °b b4 m' S•
A, V w6 O. F 0,7 ^y.0 �q �° 9 o S ° 5 m° P
02250 9.5p0
F300D oy3o "°>a 8° &oQ"BT;
11p p dFj b� e41
3]50 A d0 .' 4112'xe ill°
SB -0A 9518'x12114'
4500 e " e 0 0 o e o o a e o 0 0 . MPU MA31 Mg05
uw MnuFd fD7
M%1 MI]upO51M14py 111 13 ufO1 CC1 NPUNI 11CM MY MI]Ap401 NW Mt]M1C1 MA, I3CPS IiYM13 v1/al [P3 INI
111h Apd
STT
0 750 1500 2250 MOO 3750 450 5250 8000 8]50 7500 0250 9000 9750 10500 11250 12000 12750 13500 14250
Vertical Section at 124.92'(1500 uI
CASING DETAILS
34 15N5.15
SECTION 0
9856ID
MOIrc
10640.30
AS
ND
-N]-5
+U..
IN,
T.-
VSeel Te,el
1 33.70
000
0.00
3J 10
0.00
000
000000
-179.59 12039.52 Eld Dir : 15310.68'
9.00 1938438 SYn 0071100':
MD. 3956.76' ND
16.43TIA.39IG.
z MODS
090
0.00
500..
0.00
0.90
0.00
0.00
oDo
3 71667
6S0
1600
)1 620
-11N
410
3.00
18000
1005
41361.62
3103
117.04
1342.0
-126.94
1]201
4.00
-51.88
21438
5 MASA1
31.03
117.04
3TIASL
E4B.RB
1194..
0.00
0.00
1350.29
6 MMA6
8400
12492
3940.69
122631
2110.8
400
979
243267
7 .89.46
MOD
12492
MAR 37
-1311.61
2233.11
090
000
2581.85 MPJ M -13u EHeel
8 5348 ]fi
90.41
12492
3864.18
-1403.31
2384.33
490
-0.01
2)41.H
0 6207.63
BOA1
12482
395)30
-1951.49
3149.72
0.00
00
3898 ]E
10 6242.93
8990
124.92
395]17
-19]1]0
9178.8)
400
1)8.95
3.5.02 MN M-13 uT04 CP1
it 6247.53
69.13
IM.92
395].55
.19)4]4
3183.
3..
-1.M
3]39.62
12 8599.32
89.13
:24
13492
3962.73
4169.95
34626)
0.0
00
40813)
13 Pb4J.05
9075
992
396E.)9
-800.]0
3508.)]
9.
0.12
.35.10
14 Md3.05
.35
12092
3949.70
-7)308
4326.61
0.00
0.00
513502 MPUM-13 ANSI CP2
15 T7267>
9336
18491
3046.7)
48. .88
4]0531
30
Ott
521888
18 )93845
93.28
124.91
38]464
-20079
4588.87
0.00
090
542802
17 111
..05
114.82
3931.]5
-90]2..
4664.80
3.00
79.90
553591
10 924350
80.05
74.92
3.070
-368885
5630.55
000
000
673501 MPU Md3 Ap"CP3
19 93650
038
12491
3934.51
-375896
5738.8]
300
-17981
865731
20 953363
SAM
12491
384504
585410
M.
000
000
7023.]2
21 8644.01
88.72
12492
3848.84
3911.91
588855
390
0.10
)135.02
44
22 108 01
89 72
12492
3954 ]0
< 0441
NI
000
0.00
8335.01 MPU M-13 SO4 CP4
23 109MAS
93.35
12492
3951.47
46735)
7049.54
3.00
L9]
8455.81
24 11141.34
8335
124.9E
39/1.17
ST)4]4
]19].81
000
000
SON 87
25 112.44
9015
124.03
393184
403377
77818
3GO
179.91
873501
28 1N4444
90.25
12492
3932.
-MaRM
628341
0..
O.A.
993590 MPUM-13 AT14 CPS
27 12554 fi5
88.84
124.91
303540
358314
8352.75
3..
-17881
100di17
28 12759 65
86 94
124 91
3946.33
-570.01
85..61
0.0
0.00
10249.87
M 12844.87
89.50
124.92
]94897
3749.88
11 14
80
0.12
10]]504
30 19844.8]
8950
18498
395]]0
£322.0)
9410.]8
090
0.00
11335.. MPUM-13I CP6
31 13928.93
01.85
12488
39566]
3358.75
94)).23
390
-0108
11416.55
32 1425693
33 1434515
9195
8930
12492
12492
394544
M.46
$55).61
-86]830
9)16.08
A. 41
0.00
300
000
1]992
11)48.68
1189507
'E 750 P
p O .i p
1500 AGS ,�" n OS b R SJ P°430 yF'O K
p O p q .fes c
^q.&' F� OFit' n .,p pyKZ� yea F",�m°£a F�^ .° °b b4 m' S•
A, V w6 O. F 0,7 ^y.0 �q �° 9 o S ° 5 m° P
02250 9.5p0
F300D oy3o "°>a 8° &oQ"BT;
11p p dFj b� e41
3]50 A d0 .' 4112'xe ill°
SB -0A 9518'x12114'
4500 e " e 0 0 o e o o a e o 0 0 . MPU MA31 Mg05
uw MnuFd fD7
M%1 MI]upO51M14py 111 13 ufO1 CC1 NPUNI 11CM MY MI]Ap401 NW Mt]M1C1 MA, I3CPS IiYM13 v1/al [P3 INI
111h Apd
STT
0 750 1500 2250 MOO 3750 450 5250 8000 8]50 7500 0250 9000 9750 10500 11250 12000 12750 13500 14250
Vertical Section at 124.92'(1500 uI
CASING DETAILS
34 15N5.15
8030 12442
9856ID
-7100.60
10640.30
000
0.00 12&3.5.0 MPU N-13 A04 CP) .1 Oil T/IDP:
1.45.15 M0. FIGS. ND
NO
TVOSS
NOfive Name
]5 15N95S
3fi 15904..
89.16 7402
68.18 iN.92
3956]6
3983.40
-718338
-7.3.88
10644.01
11018.88
3.00
090
-179.59 12039.52 Eld Dir : 15310.68'
9.00 1938438 SYn 0071100':
MD. 3956.76' ND
16.43TIA.39IG.
993603
98]).89
48... 9 A B5A 21N'
9] 15646.b
90.00 134.82
]80130
-748].5)
1105134
309
00] 13338.7 En80ir :15fiW3fi'NO,
39837 ND
MATTO
30530
19248.38 4-1n 41n'x 810°
39 1ONS 38
AS, 1N 92
3963]0
4NSA55
113)933
090
0. 13)38.1] Sbneval 1. ..4 ID41 DI 161 MD. TROY TVD
-]50
SURVEY PROGRAM
WELL
DETAILS: Man: MPU M -i 31
Gmun6 L -T: 21.70
Oale:2ol]-n.l4T. oo:. Y1§e.ke:vm Vembn:
N.rAlM
EMO,
LeMIUEe
No"..
DepA From OegM1 To SurvrylPhn
Tool
0
Smn dr9'/t.':500'MD.500'NO 090
R. 602])69.)0
53]89361
N?Y 7.]]fi1N
149°99'19.]858
39.]0 9..00 MPUM-13i ug151MPU M19i1
950.00 490000 MPUM-13iv4A51MPU M-130
1_GymN5 Cwl roller
3G,,ANS 2+NS+Sep
Man Dl4'i,W 71661MD.7I6TND
40000 1624638 MPD M -131A asDPU M7i
RMWO+ffR2NMS1SM
FM ar: 1351 AT MG, 134393NO
'E 750 P
p O .i p
1500 AGS ,�" n OS b R SJ P°430 yF'O K
p O p q .fes c
^q.&' F� OFit' n .,p pyKZ� yea F",�m°£a F�^ .° °b b4 m' S•
A, V w6 O. F 0,7 ^y.0 �q �° 9 o S ° 5 m° P
02250 9.5p0
F300D oy3o "°>a 8° &oQ"BT;
11p p dFj b� e41
3]50 A d0 .' 4112'xe ill°
SB -0A 9518'x12114'
4500 e " e 0 0 o e o o a e o 0 0 . MPU MA31 Mg05
uw MnuFd fD7
M%1 MI]upO51M14py 111 13 ufO1 CC1 NPUNI 11CM MY MI]Ap401 NW Mt]M1C1 MA, I3CPS IiYM13 v1/al [P3 INI
111h Apd
STT
0 750 1500 2250 MOO 3750 450 5250 8000 8]50 7500 0250 9000 9750 10500 11250 12000 12750 13500 14250
Vertical Section at 124.92'(1500 uI
Project:
Milne Point
Site:
MPtMoose Pad
Well:
Plan: MPU M -13i
Wellbore:
MPUM-13l
Design:
MPUM-13i WP0
p 0 O p gg�p P n>o
dZ "' A]o a� ^Y y,� rv�^: ^y FO' � �rvb. �Q �p A $F �1 bg• b � ;C
Fp' _Fo o"' donF n' ,•Ia' F a"' o"' enP "' o abO Fo n¢ �O' A ,L'p Zo O A
o' yam.
a" nm oe gbb Zo b o
Cr o' d" a o
5,
1,7
9518'. 12 116'-
WELL DEFAILS'. Plan: MPU M -13i
�R.,wioOWw
HALLIBURTOIJ
-
mre.mv.nnaaomm wmwe: na wmm:
a^'^" o• °"' .xLs
O.W
.F/ -w Nonnn9
0.00 601]]65.]0
Grwne Lwal: 2470
Eesun9 La1nIWu Im9iwee
53]893N TO' 29' 13.T]fii N 149' 0.T 19.]658 W
Win Finn Oen' imo a rveyrtn.n TCG
IX >tIO m uF0 LNY vgf51MIY1 AN11 x_ yren
Mann uu131 u9os IMPU M.uO x Or
ym.m 1 x Mulx yu'm,
a
REFERENCE INFORMAT014
FORMATION TOP DETAILS
®
DDI -/D74
,vele(WEI Pelermm: Wall Plan MW M -13i. Two NOM
Vertlml(NOj flelemnre: M-11 D14 RKR-W C.E a 58A0us
MeuuleO 0e01n Rekrenm:M-IN DI4 RKB-W Car 6540US
TY➢Pa1M1 TVOasPaW MDPeN FOrmalien
3945.90 3587.50 498929 SOA
Gku2lm MCNoi Mi.— Cu.Mna
p 0 O p gg�p P n>o
dZ "' A]o a� ^Y y,� rv�^: ^y FO' � �rvb. �Q �p A $F �1 bg• b � ;C
Fp' _Fo o"' donF n' ,•Ia' F a"' o"' enP "' o abO Fo n¢ �O' A ,L'p Zo O A
o' yam.
a" nm oe gbb Zo b o
Cr o' d" a o
5,
1,7
Vertical Section at 124.92° (1500 usf1b)
9518'. 12 116'-
3940
o
g
Y8M M1]upO4 LP]
f MPG M-13 anoM
950
on
MPU bI] uaaM CP2
- -
412'x812"
3960
MPU M-13 W4 CP4
MPU AL13 uyw CPT
-MPU M13 wC 5 Heel
o
- - -MPU M-131 o,05
a
OMPU
MPU M -ti xy0. CR
". r
o P $tonewl Tm uyOl
3970
M93 xy3a CPt
g
3980Hl9swp
C0.51N0 DETAl15
Abele, uC
NO
N035 MO Sire Na"GbAaOon
o8
lAeWq: Mlnlmum Grvdra
3fiW
3 4900.09 9 -SM 95/B'x 121N'
Ermr Syabm: I5LW3A
63P0
J905.J0 18348.38 4913 diff z6ln'
Smn 51Wo'I: Clanot 4DP 30
Error J aoa. PNM Curve
3990
Wemin MCYW: Ermr Rab
1500 2250
3000 3750
4500
5250 6000 6750 7500 8250 9000 9750
10500 11250 12000 1950
43500 14250 15009 15750
Vertical Section at 124.92° (1500 usf1b)
i/{J^'QR SW DnPl100
r
. Pe: 61J15JMD. 395, 55' TVD
-1500
ProSite: Milne Point
SunJW:658932'MD,3M3.]3TVO
w]. ¢DEPM3: wn: MPU M -Ili
Site: M Pt MDose Pad
c lever: x4m
I _:
SWrI tirA/IOY': M1]A$'MD, J9J9TJVO
Well: Plan: MPU M-131
'x -s .v -w
—II.. R,:nw plimw Imgluh
—wills,
sw Dul"/IIIIY:SOP FO,SW'IVD
Wellbore: MPU MAX
10 5]]99183 ]0"Pli]]61N IJT 3]'1911
Plan: MPU M-131 wp05
REFERENCE INFORMATION
sun Dix:IdY: ]Ifi6T6N, 116.3"Nn
NAWBYiiTON
�.Irvel 81W MIS.T-NMA
p
II, .
: oeLa"O.uax.9l'Tw
........
]
5'A0 2J919'ND
-'sue Dir 3 -IW: MIS MD, IDIarrVD
®P• nY Oelnln9
N' �oWmFeIeWSW, Mn,mPO'ap B�aY[�®m.<pall
BE O SS.JOwII
Om [uwtw
Fntl Oir: 9)9.K'Mq lW0.6V ND
SeutnvY/I W':5099A6'M161. 3956 J]TVD
'FM Die : SSa9]6'Mn. 39N.18'1W
^� Sun Pr J'/IN': 6]0]6SMD,19571
Surtdrl"ICtl:63IE 91'MQ 19s]GTND
TVD NDSS Mm Si. Nam.
3936.03 38]].6l J9M.00 9-5]8 95/d"x1IIA
3963.]0 3905.30 1624638 i-1/1 I@"IF""
950 0 750 1500 2^-50 3000 3750 4506 5250 6000 6150 7500 81_50 9000 9750 10500 11250 12000 12750 13500
West(-)/Eazt(+) (15001Ls�n)
95A"n 11111"��_
. Pe: 61J15JMD. 395, 55' TVD
-1500
19U M-13 •Pu5 W �I
SunJW:658932'MD,3M3.]3TVO
Eo:66110a`AID , 3963 ]9TlT
..tlOv D,
I _:
SWrI tirA/IOY': M1]A$'MD, J9J9TJVO
FUE de :]]M.]T MD, 39M77 TVD
-31$0
MP1I M'N xy1M CP1
Sw Die Pn m:]9J YMR,, 3934,M VD
Erd Dir : 8MS5' MD..111s' J
-'sue Dir 3 -IW: MIS MD, IDIarrVD
C. -3000
MW3AY'3
uTp `P1 Fnd Mir :1111 aeND, oU45VWD
sun Dirlll., 95J26TMD,J9JSW'M1
N
. FM Dir :969a.01'M0. J9J&B4'TVD
Dv]•/I W': IOBu.01•MD. l95J.TfVO
-3750
_" "_."SIm
AIPU A41I xpM CPI Fntltir :ID: 0 19334N,V
s
Si- Do-3'uUll': a u1.N'MD. 1911.1'IIVD
11141.
BMW u3JJ.Jr MD.391]sJ'Tw
3500
_ Sun DD3•nar: G,RR.44'I,034uT
MPV a -u xpk CPJ - EOJDu :1u5l6s MR 39Jt YTw
m
sw OV J•rlfd ax]s9.6r.W). 19J6JJ•ND
-5250
. "Fntl Oir :IS9H8TA0, ]9J99TND
$IaaWl°/IW':II8N.8TMD. )95T1'ND
MPDM13 nTW CPS BWDu 11916.IJ'MD.39566TTVD
4000
Sun Oiv J'/IpY:l4i 6.9)'6n ),INS M'ND
Fntl Dir :I J3J5. 15' MD, )9M4S'TVD
-Sun Du P/1 W': ISN315'MD. 1956.TJVD
MPV Mn clAJ CP606 Du: I"9'e' 19s6.]6TW
L]50
$un D'v Y/IPtl: ISAAJ.59' MD, I9Sl <TVD
En6 Du:Isei638'MD. 396)TTVD
MN I-IJxW CT] 1 _ " T.mlhg6: 16]1618' MD, I96J1M
9500
6RIIM-IJi gTpS
GIR"r91/3"
950 0 750 1500 2^-50 3000 3750 4506 5250 6000 6150 7500 81_50 9000 9750 10500 11250 12000 12750 13500
West(-)/Eazt(+) (15001Ls�n)
HALLIBURTON
Database:
NORTH US + CANADA
Company:
Hilcorp Alaska, LLC
Project:
Milne Point
Site:
M Pt Moose Pad
Well:
Plan: MPU M-131
Wellbore:
MPU M -13i
Design:
MPU M-1 3i wp05
Halliburton
Standard Proposal Report
Local Co-ordinate Reference: Well Plan: MPU M-1 3i
TVD Reference:
M-131 D14 RKB - w/ CBE @ 58.40usft
MD Reference:
M-131 D14 RKB - w/ CBE @ 58.40usft
North Reference:
True
Survey Calculation Method:
Minimum Curvature
Project Milne Point, ACT, MILNE POINT
Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level
Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point
Map Zone: Alaska Zone 04 Using geodetic scale factor
Wellbore
Magnetics
Design
Audit Notes:
Version:
Vertical Section:
6,027,877.65usft Latitude:
533,363.92usft Longitude:
13-3/16" Grid Convergence:
6,027,765.70 usft Latitude:
533,993.84 usft Longitude:
0.00 usn Ground Level:
MPU M-131
Model Name Sample Date Declination
BGGM2018 7/15/2019 16.55
MPU M -13i wp05
Dip Angle
80.95
70' 29'13.9052 N
149` 43'38.2855 W
0.26 °
70° 29' 12.7761 N
149° 43' 19.7658 W
24.70 usft
Field Strength
(nT)
57,420.18296261
Phase:
PLAN
Site M Pt Moose Pad
Depth From (TVD)
Site Position:
Northing:
From: Map
Easting:
Position Uncertainty: 0.00 usft
Slot Radius:
Well Plan: MPU M -13i
0.00 124.92
Well Position +NI -S 0.00 usft
Northing:
+E/ -W 0.00 usft
Easting:
Position Uncertainty 0.00 usft
Wellhead Elevation:
Wellbore
Magnetics
Design
Audit Notes:
Version:
Vertical Section:
6,027,877.65usft Latitude:
533,363.92usft Longitude:
13-3/16" Grid Convergence:
6,027,765.70 usft Latitude:
533,993.84 usft Longitude:
0.00 usn Ground Level:
MPU M-131
Model Name Sample Date Declination
BGGM2018 7/15/2019 16.55
MPU M -13i wp05
Dip Angle
80.95
70' 29'13.9052 N
149` 43'38.2855 W
0.26 °
70° 29' 12.7761 N
149° 43' 19.7658 W
24.70 usft
Field Strength
(nT)
57,420.18296261
Phase:
PLAN
Tie On Depth: 33.70
Depth From (TVD)
+N/ -S
+E/ -W Direction
(usft)
(usft)
(usft) (")
33.70
0.00
0.00 124.92
5/30/2019 12:53:57PM Page 2 COMPASS 5000.15 Build 91
Halliburton
H A L L I B U R TO N Standard Proposal Report
Database:
NORTH US + CANADA
Local Co-ordinate Reference: Well Plan: MPU M -13i
Company:
Hilcorp Alaska, LLC
TVD Reference:
M -13i D14 RKB - w/
CBE @ 58.40usft
Project:
Milne Point
MD Reference:
M -13i
014 RKB - w/
CBE @ 58.40usft
Site:
M Pt Moose Pad
North Reference:
True
Well:
Plan: MPU M-131
Survey Calculation
Method: Minimum
Curvature
Wellbore:
MPU M -13i
Design:
MPU M -13i
wp05
Plan Sections
Measured
Vertical
TVD
Dogleg
Build
Turn
Depth
Inclination Azimuth
Depth
System
+N/ -S
+E/ -W
Rate
Rate
Rate Tool Face
(usft)
(°)
(°)
(usft)
usft
(usft)
(usft)
(°/100usft)
(°/100usft)
(°/100usft)
(°)
33.70
0.00
0.00
33.70
-2470
0.00
0.00
0.00
0.00
0.00
0.00
500.00
0.00
0.00
500.00
441.60
0.00
0.00
0.00
0.00
0.00
0.00
716.67
6.50
160.00
716.20
65780
-11.54
4.20
3.00
3.00
0.00
160.00
1,381.82
31.03
117.04
1,342.93
1,284.53
-126.94
172.81
4.00
3.69
-6.46
-51.66
3,606.51
31.03
117.04
3,249.29
3,190.89
-648.29
1,194.20
0.00
0.00
0.00
0.00
4,939.46
84.00
124.92
3,940.69
3.66229
-1,226.21
2,110.79
4.00
3.97
0.59
9.79
5,089.46
84.00
124.92
3,956.37
3,897.97
-1,311.61
2,233.11
0.00
0.00
0.00
0.00
5,249.76
90.41
124.92
3,964.18
3,905.78
-1,403.21
2,364.33
4.00
4.00
0.00
-0.01
6,207.62
90.41
124.92
3,957.29
3,898.89
-1,951.49
3,149.72
0.00
0.00
0.00
0.00
6,242.93
89.00
124.92
3,957.47
3,899.07
-1,971.70
3,178.67
4.00
-4.00
0.00
179.95
6,247.53
89.13
124.92
3,957.55
3,899.15
-1,974.34
3,182.44
3.00
2.83
-0.08
-1.55
6,589.32
89.13
124.92
3,962.73
3,904.33
-2,169.95
3,462.67
0.00
0.00
0.00
0.00
6,643.05
90.75
124.92
3,962.79
3,904.39
-2,200.70
3,506.73
3.00
3.01
0.01
0.12
7,643.05
90.75
124.92
3,949.70
3,891.30
-2,773.09
4,326.61
0.00
0.00
0.00
0.00
7,726.77
93.26
124.91
3,946.77
3,868.37
-2,820.98
4,395.21
3.00
3.00
-0.01
-0.12
7,936.45
93.26
124.91
3,934.84
3,876.44
-2,940.79
4,566.87
0.00
0.00
0.00
0.00
8,043.50
90.05
124.92
3,931.75
3,873.35
-3,002.03
4,654.60
3.00
-3.00
0.01
179.90
9,243.50
90.05
124.92
3,930.70
3,872.30
-3,688.95
5,638.55
0.00
0.00
0.00
0.00
9,365.88
86.38
124.91
3,934.51
3,876.11
-3,758.96
5,738.83
3.00
-3.00
0.00
-179.91
9,532.63
86.38
124.91
3,945.04
3,886.64
-3,854.20
5,875.29
0.00
0.00
0.00
0.00
9,644.01
89.72
124.92
3,948.84
3,890.44
-3,917.91
5,966.55
3.00
3.00
0.01
0.10
10,844.01
89.72
124.92
3,954.70
3,896.30
4,604.82
6,950.48
0.00
0.00
0.00
0.00
10,964.88
93.35
124.92
3,951.47
3,893.07
-4,673.97
7,049.54
3.00
3.00
0.00
-0.07
11,141.24
93.35
124.92
3,941.17
3,882.77
-4,774.74
7,193.91
0.00
0.00
0.00
0.00
11,244.44
90.25
124.92
3,937.94
3,879.54
-4,833.77
7,278.48
3.00
-3.00
0.00
179.91
12,444.44
90.25
124.92
3,932.70
3,874.30
-5,520.68
8,262.41
0.00
0.00
0.00
0.06
12,554.65
86.94
124.91
3,935.40
3,877.00
-5,583.74
8,352.75
3.00
-3.00
0.00
-179.91
12,759.65
86.94
124.91
3,946.33
3,887.93
-5,700.91
8,520.61
0.00
0.00
0.00
0.00
12,844.87
89.50
124.92
3,948.97
3,890.57
-5,749.66
8,590.44
3.00
3.00
0.01
0.12
13,844.87
89.50
124.92
3,957.70
3,899.30
-6,322.07
9,410.36
0.00
0.00
0.00
0.00
13,926.43
91.95
124.92
3,956.67
3,698.27
-6,368.75
9,477.23
3.00
3.00
0.00
-0.08
14,256.93
91.95
124.92
3,945.44
3,887.04
-6,557.81
9,748.08
0.00
0.00
0.00
0.00
14,345.15
89.30
124.92
3,944.48
3,886.08
-6,608.30
9,820.41
3.00
-3.00
0.00
179.92
15,345.15
89.30
124.92
3,956.70
3,898.30
-7,180.69
10,640.30
0.00
0.00
0.00
0.00
15,349.68
89.16
124.92
3,956.76
3,898.36
-7,183.28
10,644.01
3.00
-3.00
-0.02
-179.59
15,804.59
89.16
124.92
3,963.40
3,905.00
-7,443.66
11,016.99
0.00
0.00
0.00
0.00
15,846.38
90.00
124.92
3,963.70
3,905.30
-7,467.57
11,051.24
2.00
2.00
0.00
0.07
16,246.38
90.00
124.92
3,963.70
3,905.30
-7,696.55
11,379.23
0.00
0.00
0.00
0.00
&302019 12:53:57PM Page 3 COMPASS 5000.15 Build 91
HALLIBURTON
Database:
NORTH US+CANADA
Company:
Hilcorp Alaska, LLC
Project:
Milne Point
Site:
M Pt Moose Pad
Well:
Plan: MPU M -13i
Wellbore:
MPU M -13i
Design:
MPU M-1 3i wp05
Planned Survey
Measured
Map
Vertical
Depth
Inclination Azimuth
Depth
TVDss
(usft)
(°)
(I
(usft)
usft
(usft)
33.70
0.00
0.00
(usft)
33.70
-24.70
-24.7C
100.00
0.00
0.00
100.00
41.6C
0.00
200.00
0.00
0.00
6,027,765.70
200.00
533,993.84
141.60
0.00
300.00
0.00
0.00
0.00
300.00
241.6C
400.00
0.00
0.00
0.00
400.00
6,027,765.70
341.6C
533,993.84
500.00
0.00
0.00
500.00
0.00
441.60
Start Dir
3°1100' : 500'
MD,
500'TVD
0.00
0.00
600.00
3.00
160.00
599.95
0.00
541.55
-2.46
700.00
6.00
160.00
533,994.75
699.63
3.00
641.23
716.67
6.50
160.00
716.21
657.81
8.56
Start Dir 4°/100' : 716.67'
MD,
716.2'TVD
6,027,754.18
800.00
8.96
142.97
10.05
798.78
-21.15
740.38
6,027,744.60
900.00
12.45
132.33
4.00
897.04
838.64
22.38
1,000.00
16.18
126.41
993.92
38.18
935.52
-50.16
1,100.00
20.01
122.69
534,035.64
1,088.96
4.00
1,030.56
1,200.00
23.89
120.13
1,181.70
1,123.30
93.84
1,300.00
27.81
118.25
6,027,679.07
1,271.67
534,093.35
1,213.27
4.00
1,381.82
31.03
117.04
137.20
1,342.93
1,284.53
End Dir
: 1381.82' MD, 1342.93' TVD
-126.93
172.81
1,400.00
31.03
117.04
1,358.51
214.36
1,300.11
-131.20
1,500.00
31.03
117.04
534,175.57
1,444.20
0.00
1,385.80
1,600.00
31.03
117.04
1,529.89
1,471.49
274.70
1,700.00
31.03
117.04
6,027,588.90
1,615.58
534,267.60
1,557.18
0.00
1,800.00
31.03
117.04
318.89
1,701.27
1,642.87
1,900.00
31.03
117.04
-224.93
1,786.96
6,027,542.46
1,728.56
534,359.63
2,000.00
31.03
117.04
1,872.66
410.71
1,814.26
2,100.00
31.03
117.04
478.94
1,958.35
-271.80
1,899.95
6,027,496.01
2,200.00
31.03
117.04
0.00
2,044.04
1,985.64
502.54
2,300.00
31.03
117.04
2,129.73
581.06
2,071.33
-318.67
2,400.00
31.03
117.04
534,543.68
2,215.42
0.00
2,157.02
2,500.00
31.03
117.04
2,301.11
2,242.71
683.18
2,600.00
31.03
117.04
6,027,403.12
2,386.80
534,635.71
2,328.40
0.00
2,700.00
31.03
117.04
686.18
2,472.49
2,414.09
2,800.00
31.03
117.04
-412.41
2,558.18
6,027,356.68
2,499.78
534,727.74
2,900.00
31.03
117.04
2,643.87
778.01
2,585.47
3,000.00
31.03
117.04
887.42
2,729.56
-459.28
2,671.16
6,027,310.23
3,100.00
31.03
117.04
0.00
2,815.26
2,756.86
869.83
3,200.00
31.03
117.04
2,900.95
989.54
2,842.55
-506.15
3,300.00
31.03
117.04
534,911.79
2,986.64
0.00
2,928.24
3,400.00
31.03
117.04
3,072.33
3,013.93
1,091.66
3,500.00
31.03
117.04
6,027,217.34
3,158.02
535,003.82
3,099.62
0.00
3,606.51
31.03
117.04
1,053.48
3,249.29
3,190.89
Start Dir 411100' : 3606.51' MD,
3249.29'TVD
3,700.00
34.72
118.16
3,327.79
3,269.39
1,244.84
3,800.00
38.68
119.14
6,027,147.68
3,407.96
535,141.86
3,349.56
0.00
Local Co-ordinate Reference:
TVD Reference:
MD Reference:
North Reference:
Survey Calculation Method:
Halliburton
Standard Proposal Report
Well Plan: MPU M-131
M -13i D14 RKB - wl CBE @ 58.40usft
M -13i D14 RKB - w/ CBE @ 58.40usft
True
Minimum Curvature
-671.81 1,239.15 6,027,099.62 535,235.93 4.00 1,400.61
-700.48 1,291.57 6,027,071.20 535,288.47 4.00 1,460.00
&302019 12:53.57PM Page 4 COMPASS 5000.15 Build 91
Map
Map
+N/ -S
+E1 -W
Northing
Easting
DLS
Vert Section
(usft)
(usft)
(usft)
(usft)
-24.70
0.00
0.00
6,027,765.70
533,993.84
0.00
0.00
0.00
0.00
6,027,765.70
533,993.84
0.00
0.00
0.00
0.00
6,027,765.70
533,993.84
0.00
0.00
0.00
0.00
6,027,765.70
533,993.84
0.00
0.00
0.00
0.00
6,027,765.70
533,993.84
0.00
0.00
0.00
0.00
6,027,765.70
533,993.84
0.00
0.00
-2.46
0.90
6,027,763.24
533,994.75
3.00
2.14
-9.83
3.58
6,027,755.89
533,997.46
3.00
8.56
-11.54
4.20
6,027,754.18
533,998.09
3.00
10.05
-21.15
9.72
6,027,744.60
534,003.66
4.00
20.08
-34.63
22.38
6,027,731.18
534,016.38
4.00
38.18
-50.16
41.57
6,027,715.73
534,035.64
4.00
62.80
-67.68
67.19
6,027,698.33
534,061.33
4.00
93.84
-87.09
99.12
6,027,679.07
534,093.35
4.00
131.13
-108.31
137.20
6,027,658.03
534,131.52
4.00
174.50
-126.93
172.81
6,027,639.57
534,167.21
4.00
214.36
-131.20
181.15
6,027,635.35
534,175.57
0.00
223.64
-154.63
227.07
6,027,612.12
534,221.59
0.00
274.70
-178.06
272.98
6,027,588.90
534,267.60
0.00
325.76
-201.50
318.89
6,027,565.68
534,313.62
0.00
376.82
-224.93
364.80
6,027,542.46
534,359.63
0.00
427.88
-248.37
410.71
6,027,519.23
534,405.64
0.00
478.94
-271.80
456.62
6,027,496.01
534,451.66
0.00
530.00
-295.24
502.54
6,027,472.79
534,497.67
0.00
581.06
-318.67
548.45
6,027,449.57
534,543.68
0.00
632.12
-342.11
594.36
6,027,426.34
534,589.70
0.00
683.18
-365.54
640.27
6,027,403.12
534,635.71
0.00
734.24
-388.98
686.18
6,027,379.90
534,681.73
0.00
785.30
-412.41
732.09
6,027,356.68
534,727.74
0.00
836.36
-435.85
778.01
6,027,333.46
534,773.75
0.00
887.42
-459.28
823.92
6,027,310.23
534,819.77
0.00
938.48
-482.72
869.83
6,027,287.01
534,865.78
0.00
989.54
-506.15
915.74
6,027,263.79
534,911.79
0.00
1,040.60
-529.59
961.65
6,027,240.57
534,957.81
0.00
1,091.66
-553.02
1,007.56
6,027,217.34
535,003.82
0.00
1,142.72
576.46
1,053.48
6,027,194.12
535,049.84
0.00
1,193.78
-599.89
1,099.39
6,027,170.90
535,095.85
0.00
1,244.84
-623.33
1,145.30
6,027,147.68
535,141.86
0.00
1,295.90
-648.29
1,194.20
6,027,122.94
535,190.87
0.00
1,350.29
-671.81 1,239.15 6,027,099.62 535,235.93 4.00 1,400.61
-700.48 1,291.57 6,027,071.20 535,288.47 4.00 1,460.00
&302019 12:53.57PM Page 4 COMPASS 5000.15 Build 91
HALLIBURTON
Database:
NORTH US + CANADA
Company:
Hilcorp Alaska, LLC
Project:
Milne Point
Site:
M Pt Moose Pad
Well:
Plan: MPU M -13i
Wellbore:
MPU M -13i
Design:
MPU M-13iwp05
Planned Survey
Measured Vertical
Depth Inclination Azimuth Depth TVDss
(usft) (°) (°) (usft) usft
3,900.00 42.64 119.97 3,483.81 3,425.41
4,000.00 46.61 120.68 3,554.97 3,496.57
4,100.00 50.58 121.30 3,621.09 3,562.69
4,200.00 54.56 121.86 3,681.86 3,623.46
4,300.00 58.53 122.36 3,736.98 3,678.58
4,400.00 62.51 122.83 3,786.18 3,727.78
4,500.00 66.49 123.26 3,829.21 3,770.81
4,600.00 70.48 123.66 3,865.88 3,807.48
4,700.00 74.46 124.05 3,896.00 3,837.60
4,800.00 78.44 124.42 3,919.42 3,861.02
4,900.00 • 82.43 124.78 3,936.03 3,877.63
9 518" x 12 114"
4,939.46 84.00 124.92 3,940.69 3,882.29
End Dir : 4939.46' MD, 3940.69' TVD
4,989.29 84.00 124.92 3,945.90 3,887.50
SB OA
5,000.00 84.00 124.92 3,947.02 3,888.62
5,089.46 84.00 124.92 3,956.37 3,897.97
Start Dir 4°1100' : 5089.46' MD, 3956.37'TVD
5,100.00 84.42 124.92 3,957.43 3,899.03
5,200.00 88.42 124.92 3,963.67 3,905.27
5,249.76 90.41 124.92 3,964.18 3,905.78
End Dir : 5249.76' MD, 3964.18' TVD
5,300.00 90.41 124.92 3,963.82 3,905.42
5,400.00 90.41 124.92 3,963.10 3,904.70
5,500.00 90.41 124.92 3,962.38 3,903.98
5,600.00 90.41 124.92 3,961.66 3,903.26
5,700.00 90.41 124.92 3,960.94 3,902.54
5,800.00 90.41 124.92 3,960.22 3,901.82
5,900.00 90.41 124.92 3,959.50 3,901.10
6,000.00 90.41 124.92 3,958.78 3,900.38
6,100.00 90.41 124.92 3,958.06 3,899.66
6,207.62 90.41 124.92 3,957.29 3,898.89
Start Dir 401100' : 6207.62' MD, 3957.29'TVD
6,242.93 89.00 124.92 3,957.47 3,899.07
Start Dir 3°!100' : 6242.93' MD, 3957.47'TVD
6,247.53 89.13 124.92 3,957.55 3,899.15
End Dir : 6247.53' MD, 3957.55' TVD
6,300.00 89.13 124.92 3,958.34 3,899.94
6,400.00 89.13 124.92 3,959.86 3,901.46
6,500.00 89.13 124.92 3,961.38 3,902.98
6,589.32 89.13 124.92 3,962.73 3,904.33
Start Dir 3°1100' : 6589.32' MD, 3962.73'TVD
6,600.00 89.45 124.92 3,962.87 3,904.47
Local Co-ordinate Reference:
TVD Reference:
MD Reference:
North Reference:
Survey Calculation Method:
Halliburton
Standard Proposal Report
Well Plan: MPU M -13i
MAN D14 RKB - wl CBE @ 58.40usft
M-131 D14 RKB - wl CBE @ 58.40usft
True
Minimum Curvature
5/302019 12:53.57PM Page 5 COMPASS 5000.15 Build 91
Map
Map
+N/ -S
+FJ -W
Northing
Easting
DLS
Vert Section
(usft)
(usft)
(usft)
(usft)
3,425.41
-732.63
1,348.22
6,027,039.32
535,345.27
4.00
1,524.86
-768.10
1,408.84
6,027,004.13
535,406.03
4.00
1,594.86
-806.72
1,473.12
6,026,965.80
535,470.48
4.00
1,669.68
-848.31
1,540.74
6,026,924.53
535,538.29
4.00
1,748.93
-892.66
1,611.39
6,026,880.51
535,609.14
4.00
1,832.25
-939.55
1,684.72
6,026,833.95
535,682.67
4.00
1,919.22
-988.76
1,760.36
6,026,785.09
535,758.53
4.00
2,009.41
-1,040.05
1,837.96
6,026,734.17
535,836.35
4.00
2,102.39
-1,093.16
1,917.13
6,026,681.42
535,915.76
4.00
2,197.71
-1,147.84
1,997.49
6,026,627.11
535,996.35
4.00
2,294.90
-1,203.83
2,078.64
6,026,571.50
536,077.75
4.00
2,393.49
-1,226.22
2,110.79
6,026,549.26
536,110.01
4.00
2,432.67
-1,254.59
2,151.43
6,026,521.08
536,150.77
0.00
2,482.23
-1,260.68
2,160.16
6,026,515.03
536,159.53
0.00
2,492.88
-1,311.61
2,233.11
6,026,464.44
536,232.70
0.00
2,581.85
-1,317.61
2,241.71
6,026,458.48
536,241.33
4.00
2,592.34
-1,374.73
2,323.53
6,026,401.74
536,323.40
4.00
2,692.12
-1,403.21
2,364.33
6,026,373.45
536,364.32
4.00
2,741.88
-1,431.97
2,405.52
6,026,344.88
536,405.64
0.00
2,792.12
-1,489.21
2,487.51
6,026,288.02
536,487.89
0.00
2,892.11
-1,546.45
2,569.51
6,026,231.16
536,570.14
0.00
2,992.11
-1,603.69
2,651.50
6,026,174.30
536,652.38
0.00
3,092.11
-1,660.93
2,733.50
6,026,117.44
536,734.63
0.00
3,192.11
-1,718.17
2,815.49
6,026,060.58
536,816.88
0.00
3,292.10
-1,775.41
2,897.49
6,026,003.72
536,899.12
0.00
3,392.10
-1,832.65
2,979.48
6,025,946.87
536,981.37
0.00
3,492.10
-1,889.89
3,061.47
6,025,890.01
537,063.62
0.00
3,592.10
-1,951.49
3,149.72
6,025,828.82
537,152.13
0.00
3,699.71
-1,971.70
3,178.67
6,025,808.74
537,181.17
4.00
3,735.02
-1,974.34
3,182.44
6,025,806.12
537,184.96
2.83
3,739.62
-2,004.37
3,225.46
6,025,776.29
537,228.11
0.00
3,792.09
-2,061.60
3,307.45
6,025,719.44
537,310.35
0.00
3,892.07
-2,118.83
3,389.44
6,025,662.59
537,392.59
0.00
3,992.06
-2,169.95
3,462.67
6,025,611.81
537,466.05
0.00
4,081.37
-2,176.06
3,471.43
6,025,605.74
537,474.83
3.00
4,092.05
5/302019 12:53.57PM Page 5 COMPASS 5000.15 Build 91
Halliburton
HALLIBURTON
Standard
Proposal
Report
Database:
NORTH US + CANADA
Local Co-ordinate Reference: Well
Plan: MPU Ml
Company:
Hilcorp Alaska, LLC
TVD Reference:
M-13i
D14 RKB - wi
CBE @ 58.40usft
Project:
Milne Point
MD Reference:
M-13i
D14 RKB - wl
CBE @ 58.40usft
Site:
M Pt Moose Pad
North Reference:
True
Well:
Plan: MPU M-13i
Survey
Calculation
Method: Minimum
Curvature
Wellborn:
MPU M-131
Design:
MPU M-1 3i wp05
Planned Survey
Measured
Vertical
Map
Map
Depth
Inclination Azimuth
Depth
TVDss
+NIS
+E1-W
Northing
Easing
DLS
Vert Section
(usft)
0 r)
(usft)
usft
(usft)
(usft)
(usft)
(usft)
3,904.39
6,643.05
90.75 124.92
3,962.79
3,904.39
-2,200.70
3,506.73
6,025,581.26
537,510.24
3.02
4,135.10
End Dir
: 6643.05' MD, 3962.79' TVD
6,700.00
90.75 124.92
3,962.04
3,903.64
-2,233.30
3,553.42
6,025,548.88
537,557.08
0.00
4,192.05
6,800.00
90.75 124.92
3,960.74
3,902.34
-2,290.54
3,635.41
6,025,492.03
537,639.32
0.00
4,292.04
6,900.00
90.75 124.92
3,959.43
3,901.03
-2,347.78
3,717.39
6,025,435.17
537,721.56
0.00
4,392.03
7,000.00
90.75 124.92
3,958.12
3,899.72
-2,405.02
3,799.38
6,025,378.31
537,803.80
0.00
4,492.02
7,100.00
90.75 124.92
3,956.81
3,898.41
-2,462.25
3,881.37
6,025,321.45
537,886.04
0.00
4,592.01
7,200.00
90.75 124.92
3,955.50
3,897.10
-2,519.49
3,963.36
6,025,264.60
537,968.28
0.00
4,692.00
7,300.00
90.75 124.92
3,954.19
3,895.79
-2,576.73
4,045.35
6,025,207.74
538,050.52
0.00
4,791.99
7,400.00
90.75 124.92
3,952.88
3,894.48
-2,633.97
4,127.34
6,025,150.88
538,132.76
0.00
4,891.99
7,500.00
90.75 124.92
3,951.57
3,893.17
-2,691.21
4,209.32
6,025,094.02
538,215.00
0.00
4,991.98
7,600.00
90.75 124.92
3,950.26
3,891.86
-2,748.45
4,291.31
6,025,037.17
538,297.25
0.00
5,091.97
7,643.05
90.75 124.92
3,949.70
3,891.30
-2,773.09
4,326.61
6,025,012.69
538,332.65
0.00
5,135.02
Start Dir 3°1100' : 7643.05' MD,
3949.7'TVD
7,700.00
92.46 124.92
3,948.11
3,889.71
-2,805.67
4,373.29
6,024,980.32
538,379.47
3.00
5,191.94
7,726.77
93.26 124.91
3,946.77
3,888.37
-2,820.97
4,395.21
6,024,965.12
538,401.46
3.00
5,218.68
End Dir
: 7726.77' MD, 3946.77' TVD
7,800.00
93.26 124.91
3,942.60
3,884.20
-2,862.82
4,455.16
6,024,923.55
538,461.60
0.00
5,291.79
7,900.00
93.26 124.91
3,936.91
3,878.51
-2,919.96
4,537.03
6,024,866.79
538,543.72
0.00
5,391.63
7,936.45
93.26 124.91
3,934.84
3,876.44
-2,940.79
4,566.87
6,024,846.10
538,573.65
0.00
5,428.02
Start Dir 3-1100': 7936.45' MD,
3934.84TVD
8,000.00
91.36 124.92
3,932.28
3,873.88
-2,977.13
4,618.93
6,024,810.00
538,625.88
3.00
5,491.51
8,043.50
90.05 124.92
3,931.75
3,873.35
-3,002.03
4,654.60
6,024,785.27
538,661.65
3.00
5,535.01
End Dir
: 8043.5' MD, 3931.75'
TVD
8,100.00
90.05 124.92
3,931.70
3,873.30
-3,034.37
4,700.93
6,024,753.14
538,708.12
0.00
5,591.51
8,200.00
90.05 124.92
3,931.61
3,873.21
-3,091.62
4,782.92
6,024,696.28
538,790.37
0.00
5,691.51
8,300.00
90.05 124.92
3,931.52
3,873.12
-3,148.86
4,864.92
6,024,639.42
538,872.62
0.00
5,791.51
8,400.00
90.05 124.92
3,931.44
3,873.04
-3,206.10
4,946.91
6,024,582.55
538,954.87
0.00
5,891.51
8,500.00
90.05 124.92
3,931.35
3,872.95
-3,263.35
5,028.91
6,024,525.69
539,037.11
0.00
5,991.51
8,600.00
90.05 124.92
3,931.26
3,872.86
-3,320.59
5,110.90
6,024,468.83
539,119.36
0.00
6,091.51
8,700.00
90.05 124.92
3,931.17
3,872.77
-3,377.83
5,192.90
6,024,411.97
539,201.61
0.00
6,191.51
8,800.00
90.05 124.92
3,931.09
3,872.69
-3,435.08
5,274.89
6,024,355.11
539,283.86
0.00
6,291.51
8,900.00
90.05 124.92
3,931.00
3,872.60
-3,492.32
5,356.89
6,024,298.24
539,366.11
0.00
6,391.51
9,000.00
90.05 124.92
3,930.91
3,872.51
-3,549.56
5,438.88
6,024,241.38
539,448.35
0.00
6,491.51
9,100.00
90.05 124.92
3,930.83
3,872.43
-3,606.81
5,520.88
6,024,184.52
539,530.60
0.00
6,591.51
9,200.00
90.05 124.92
3,930.74
3,872.34
-3,664.05
5,602.87
6,024,127.66
539,612.85
0.00
6,691.51
9,243.50
90.05 124.92
3,930.70
3,872.30
-3,688.95
5,638.54
6,024,102.92
539,648.63
0.00
6,735.01
Start Dir 3°1100' : 9243.5' MD, 3930.77VD
9,300.00
88.36 124.92
3,931.49
3,873.09
-3,721.29
5,684.86
6,024,070.80
539,695.09
3.00
6,791.50
9,365.88
86.38 124.91
3,934.51
3,876.11
-3,758.95
5,738.83
6,024,033.39
539,749.22
3.00
6,857.31
End Dir
: 9365.88' MD, 3934.51' TVD
9,400.00
86.38 124.91
3,936.67
3,878.27
-3,778.44
5,766.75
6,024,014.03
539,777.23
0.00
6,891.36
9,500.00
86.38 124.91
3,942.98
3,884.58
-3,835.56
5,848.59
6,023,957.29
539,859.32
0.00
6,991.16
9,532.63
86.38 124.91
3,945.04
3,886.64
-3,854.20
5,875.29
6,023,938.77
539,886.10
0.00
7,023.72
Start Dir 3°1100' : 9532.63' MD,
3945.04'TVD
5/30/2019 12:53.,57PM
Page 6
COMPASS 5000.15 Build 91
HALLIBURTON
Database:
NORTH US+CANADA
Company:
Hiicorp Alaska, LLC
Project:
Milne Point
Site:
M Pt Moose Pad
Well:
Plan: MPU M -13i
Wellbore:
MPU M -13i
Design:
MPU M -13i wp05
Planned Survey
Measured
M -13i D14 RKB - w/ CBE @ 58.40usft
MD Reference:
M -13i D14 RKB - w/ CBE @ 58.40usft
Vertical
True
Depth
Minimum Curvature
Inclination Azimuth
Depth
TVDss
(usft)
Northing
(°)
(°)
(usft)
usft
9,600.00
88.40
124.92
3,948.11
3,889.71
9,644.01
89.72
124.92
5,930.47
3,948.84
3,890.44
End
Dir
: 9644.01' MD, 3948.84' TVD
7,091.02
9,700.00
89.72
124.92
3,949.11
3,890.71
9,800.00
7,135.02
89.72
124.92
6,012.46
3,949.60
3,891.20
9,900.00
89.72
124.92
-4,007.20
3,950.09
3,891.69
10,000.00
89.72
124.92
0.00
3,950.58
3,892.18
10,100.00
6,176.45
89.72
124.92
540,188.19
3,951.06
3,892.66
10,200.00
-4,121.69
89.72
124.92
6,023,673.07
3,951.55
3,893.15
10,300.00
0.00
89.72
124.92
3,952.04
3,893.64
10,400.00
540,352.69
89.72
124.92
7,591.01
3,952.53
3,894.13
10,500.00
6,023,559.34
89.72
124.92
3,953.02
3,894.62
10,600.00
89.72
124.92
3,953.51
3,895.11
10,700.00
7,791.01
89.72
124.92
6,586.42
3,954.00
3,895.60
10,800.00
89.72
124.92
-4,407.90
3,954.48
3,896.08
10,844.01
89.72
124.92
0.00
3,954.70
3,896.30
Start Dir 301100' : 10844.01'
MD, 3954.7'iVD
6,023,331.90
10,900.00
540,763.92
91.40
124.92
8,091.00
3,954.15
3,895.75
10,964.88
6,023,275.04
93.35
124.92
3,951.47
3,893.07
End
Dir
: 10964.88' MD, 3951.47'
TVD
11,000.00
93.35
124.92
-4,604.82
3,949.42
3,891.02
11,100.00
93.35
124.92
0.00
3,943.58
3,885.18
11,141.24
6,996.39
93.35
124.92
541,010.66
3,941.17
3,882.77
Start Dir
W1100' : 11141.24'
MD, 3941.177VD
11,200.00
6,023,124.46
91.58
124.92
3,938.65
3,880.25
11,244.44
90.25
124.92
3,937.94
3,879.54
End
Dir
: 11244.44' MD,
3937.94'
TVD
6,023,047.77
11,300.00
541,174.92
90.25
124.92
8,590.71
3,937.69
3,879.29
11,400.00
6,023,024.36
90.25
124.92
3,937.26
3,878.86
11,500.00
90.25
124.92
3,936.82
3,878.42
11,600.00
8,690.58
90.25
124.92
7,278.48
3,936.38
3,877.98
11,700.00
90.25
124.92
-4,865.58
3,935.95
3,877.55
11,800.00
90.25
124.92
0.00
3,935.51
3,877.11
11,900.00
7,406.03
90.25
124.92
541,421.56
3,935.08
3,876.68
12,000.00
-4,980.06
90.25
124.92
6,022,820.40
3,934.64
3,876.24
12,100.00
0.00
90.25
124.92
3,934.20
3,875.80
12,200,00
541,586.06
90.25
124.92
9,090.57
3,933.77
3,875.37
12,300.00
6,022,706.68
90.25
124.92
3,933.33
3,874.93
12,400.00
90.25
124.92
3,932.89
3,874.49
12,444.44
9,290.57
90.25
124.92
7,816.00
3,932.70
3,874.30
Start Dir 301100': 12444.44'
MD, 3932.7'TVD
0.00
12,500.00
-5,266.28
88.58
124.92
6,022,536.09
3,933.27
3,874.87
12,554.65
0.00
86.94
124.91
3,935.40
3,877.00
End
Dir
: 12554.65' MD,
3935.4'
TVD
-5,380.76
12,600.00
8,061.99
86.94
124.91
542,079.54
3,937.82
3,879.42
Halliburton
Standard Proposal Report
Local Coordinate Reference: Well Plan: MPU M -13i
TVD Reference:
M -13i D14 RKB - w/ CBE @ 58.40usft
MD Reference:
M -13i D14 RKB - w/ CBE @ 58.40usft
North Reference:
True
Survey Calculation Method:
Minimum Curvature
5/302019 12:53:57PM Page 7 COMPASS 5000.15 Build 91
Map
Map
+N/ -S
+E/ -W
Northing
Easting
DLS
Vert Section
(usft)
(usft)
(usft)
(usft)
3,889.71
-3,892.72
5,930.47
6,023,900.51
539,941.46
3.00
7,091.02
-3,917.91
5,956.55
6,023,875.49
539,977.65
3.00
7,135.02
-3,949.96
6,012.46
6,023,843.65
540,023.70
0.00
7,191.01
-4,007.20
6,094.46
6,023,786.79
540,105.94
0.00
7,291.01
4,064.44
6,176.45
6,023,729.93
540,188.19
0.00
7,391.01
-4,121.69
6,258.44
6,023,673.07
540,270.44
0.00
7,491.01
-4,178.93
6,340.44
6,023,616.20
540,352.69
0.00
7,591.01
-4,236.17
6,422.43
6,023,559.34
540,434.93
0.00
7,691.01
-4,293.41
6,504.43
6,023,502.48
540,517.18
0.00
7,791.01
-4,350.66
6,586.42
6,023,445.62
540,599.43
0.00
7,891.01
-4,407.90
6,668.42
6,023,388.76
540,681.67
0.00
7,991.00
-4,465.14
6,750.41
6,023,331.90
540,763.92
0.00
8,091.00
-4,522.38
6,832.40
6,023,275.04
540,846.17
0.00
8,191.00
-4,579.63
6,914.40
6,023,218.17
540,928.41
0.00
8,291.00
-4,604.82
6,950.48
6,023,193.15
540,964.61
0.00
8,335.01
-4,636.87
6,996.39
6,023,161.32
541,010.66
3.00
8,391.00
-4,673.97
7,049.54
6,023,124.46
541,063.97
3.00
8,455.82
-4,694.04
7,078.29
6,023,104.53
541,092.81
0.00
8,490.88
-4,751.18
7,160.15
6,023,047.77
541,174.92
0.00
8,590.71
-4,774.74
7,193.91
6,023,024.36
541,208.79
0.00
8,631.88
-4,808.34
7,242.05
6,022,990.98
541,257.07
3.00
8,690.58
-4,833.77
7,278.48
6,022,965.72
541,293.62
3.00
8,735.01
-4,865.58
7,324.04
6,022,934.13
541,339.31
0.00
8,790.57
-4,922.82
7,406.03
6,022,877.26
541,421.56
0.00
8,890.57
-4,980.06
7,488.02
6,022,820.40
541,503.81
0.00
8,990.57
-5,037.31
7,570.02
6,022,763.54
541,586.06
0.00
9,090.57
-5,094.55
7,652.01
6,022,706.68
541,668.30
0.00
9,190.57
-5,151.79
7,734.01
6,022,649.82
541,750.55
0.00
9,290.57
-5,209.03
7,816.00
6,022,592.96
541,832.80
0.00
9,390.57
-5,266.28
7,898.00
6,022,536.09
541,915.04
0.00
9,490.57
-5,323.52
7,979.99
6,022,479.23
541,997.29
0.00
9,590.56
-5,380.76
8,061.99
6,022,422.37
542,079.54
0.00
9,690.56
-5,438.01
8,143.98
6,022,365.51
542,161.79
0.00
9,790.56
-5,495.25
8,225.97
6,022,308.65
542,244.03
0.00
9,890.56
-5,520.69
8,262.41
6,022,283.38
542,280.58
0.00
9,935.00
-5,552.49
8,307.97
6,022,251.79
542,326.28
3.00
9,990.56
-5,583.74
8,352.74
6,022,220.74
542,371.19
3.00
10,045.16
-5,609.66
8,389.88
6,022,195.00
542,408.44
0.00
10,090.45
5/302019 12:53:57PM Page 7 COMPASS 5000.15 Build 91
5/302019 12: 53:57PM Page 8 COMPASS 5000.15 Build 91
Halliburton
HA LL I B U R TO N
Standard Proposal Report
Database:
NORTH US+CANADA
Local
Co-ordinate Reference: Well Plan: MPU M-131
Company:
Hilcorp Alaska, LLC
TVD Reference:
M -13i
D14 RKB - w/
CBE @ 58.40usft
Project:
Milne Point
MD Reference:
M -13i
D14 RKB - wl
CBE @ 58.40usft
Site:
M Pt Moose Pad
North
Reference:
True
Well:
Plan: MPU M -13i
Survey Calculation
Method: Minimum
Curvature
Wellbore:
MPU M-131
Design:
MPU M -13i wp05
Planned Survey
Measured
Vertical
Map
Map
Depth Inclination Azimuth
Depth
TVDss
+N/ -S
+E/ -W
Northing
Easting
DLS
Vert Section
(usft)
(°) (°)
(usft)
usft
(usft)
(usft)
(usft)
(usft)
3,884.75
12,700.00
86.94 124.91
3,943.15
3,884.75
-5,666.82
8,471.76
6,022,138.22
542,490.58
0.00
10,190.31
12,759.65
86.94 124.91
3,946.33
3,887.93
-5,700.91
8,520.61
6,022,104.36
542,539.57
0.00
10,249.87
Start Dir 3°1100' : 12759.65' MD, 3946.33'TVD
12,800.00
88.15 124.92
3,948.05
3,889.65
-5,723.98
8,553.66
6,022,081.44
542,572.73
3.00
10,290.18
12,844.87
89.50 124.92
3,948.97
3,890.57
-5,749.66
8,590.44
6,022,055.93
542,609.62
3.00
10,335.04
End Dir :
12844.87' MD, 3948.97' ND
12,900.00
89.50 124.92
3,949.45
3,891.05
-5,781.22
8,635.65
6,022,024.58
542,654.97
0.00
10,390.17
13,000.00
89.50 124.92
3,950.33
3,891.93
-5,838.46
8,717.64
6,021,967.72
542,737.21
0.00
10,490.17
13,100.00
89.50 124.92
3,951.20
3,892.80
-5,895.70
8,799.63
6,021,910.86
542,819.46
0.00
10,590.16
13,200.00
89.50 124.92
3,952.07
3,893.67
-5,952.94
8,881.62
6,021,854.00
542,901.70
0.00
10,690.16
13,300.00
89.50 124.92
3,952.95
3,894.55
-6,010.18
8,963.61
6,021,797.14
542,983.95
0.00
10,790.16
13,400.00
89.50 124.92
3,953.82
3,895.42
-6,067.42
9,045.61
6,021,740.28
543,066.19
0.00
10,890.15
13,500.00
89.50 124.92
3,954.69
3,896.29
-6,124.66
9,127.60
6,021,683.42
543,148.43
0.00
10,990.15
13,600.00
89.50 124.92
3,955.56
3,897.16
-6,181.90
9,209.59
6,021,626.56
543,230.68
0.00
11,090.14
13,700.00
89.50 124.92
3,956.44
3,898.04
-6,239.15
9,291.58
6,021,569.70
543,312.92
0.00
11,190.14
13,800.00
89.50 124.92
3,957.31
3,898.91
-6,296.39
9,373.58
6,021,512.84
543,395.17
0.00
11,290.14
13,844.87
89.50 124.92
3,957.70
3,899.30
-6,322.07
9,410.37
6,021,487.33
543,432.07
0.00
11,335.01
Start Dir 3°/100' : 13844.87' MD, 3957.7'TVD
13,900.00
91.15 124.92
3,957.39
3,898.99
-6,353.63
9,455.57
6,021,455.98
543,477.41
3.00
11,390.13
13,926.43
91.95 124.92
3,956.67
3,898.27
-6,368.75
9,477.23
6,021,440.96
543,499.14
3.00
11,416.55
End Dir :
13926.43' MD, 3956.67' TVD
14,000.00
91.95 124.92
3,954.17
3,895.77
-6,410.83
9,537.52
6,021,399.16
543,559.62
0.00
11,490.08
14,100.00
91.95 124.92
3,950.77
3,892.37
-6,468.04
9,619.47
6,021,342.33
543,641.83
0.00
11,590.02
14,200.00
91.95 124.92
3,947.38
3,888.98
-6,525.24
9,701.43
6,021,285.51
543,724.03
0.00
11,689.96
14,256.93
91.95 124.92
3,945.44
3,887.04
-6,557.81
9,748.08
6,021,253.16
543,770.83
0.00
11,746.86
Start Dir 311100' : 14256.93' MD, 3945.44'TVD
14,300.00
90.65 124.92
3,944.47
3,886.07
-6,582.46
9,783.39
6,021,228.67
543,806.24
3.00
11,789.92
14,345.15
89.30 124.92
3,944.48
3,886.08
-6,608.30
9,820.41
6,021,203.00
543,843.38
3.00
11,835.07
End Dir :
14345.15' MD, 3944.46' TVD
14,400.00
89.30 124.92
3,945.15
3,886.75
-6,639.70
9,865.38
6,021,171.82
543,888.49
0.00
11,889.91
14,500.00
89.30 124.92
3,946.37
3,887.97
-6,696.94
9,947.37
6,021,114.96
543,970.73
0.00
11,989.91
14,600.00
89.30 124.92
3,947.60
3,889.20
-6,754.18
10,029.36
6,021,058.10
544,052.97
0.00
12,089.90
14,700.00
89.30 124.92
3,948.82
3,890.42
-6,811.41
10,111.35
6,021,001.24
544,135.21
0.00
12,189.89
14,800.00
89.30 124.92
3,950.04
3,891.64
-6,868.65
10,193.34
6,020,944.38
544,217.46
0.00
12,289.88
14,900.00
89.30 124.92
3,951.26
3,892.86
-6,925.89
10,275.32
6,020,887.53
544,299.70
0.00
12,389.88
15,000.00
89.30 124.92
3,952.48
3,894.08
-6,983.13
10,357.31
6,020,830.67
544,381.94
0.00
12,489.87
15,100.00
89.30 124.92
3,953.70
3,895.30
-7,040.37
10,439.30
6,020,773.81
544,464.18
0.00
12,589.86
15,200.00
89.30 124.92
3,954.93
3,896.53
-7,097.61
10,521.29
6,020,716.95
544,546.42
0.00
12,689.85
15,300.00
89.30 124.92
3,956.15
3,897.75
-7,154.85
10,603.28
6,020,660.09
544,628.66
0.00
12,789.85
15,345.15
89.30 124.92
3,956.70
3,898.30
-7,180.69
10,640.30
6,020,634.42
544,665.80
0.00
12,834.99
Start Dir 3-1100': 15345.15' MD, 3956.7'TVD
15,349.68
89.16 124.92
3,956.76
3,898.36
-7,183.28
10,644.01
6,020,631.85
544,669.52
2.99
12,839.52
End Dir :
15349.68' MD, 3956.76' TVD
15,400.00
89.16 124.92
3,957.49
3,899.09
-7,212.09
10,685.27
6,020,603.24
544,710.90
0.00
12,889.84
15,500.00
89.16 124.92
3,958.95
3,900.55
-7,269.32
10,767.26
6,020,546.38
544,793.15
0.00
12,989.83
5/302019 12: 53:57PM Page 8 COMPASS 5000.15 Build 91
HALLIBURTON
Halliburton
Standard Proposal Report
Database: NORTH US + CANADA
Local Co-ordinate Reference: Well Plan: MPU M-131
Company: Hilcorp Alaska, LLC
TVD Reference:
M -13i 014 RKB - w/ CBE @ 58.40usft
Project: Milne Point
MD Reference:
M -13i D14 IRKS - w/ CBE @ 58.40usft
Site: M Pt Moose Pad
North Reference:
True
Well: Plan: MPU M -1 3i
Survey Calculation Method: Minimum
Curvature
Wellbore: MPU M-131
Design: MPU M-131 wp05
Planned Survey
Measured
Vertical
Map
Map
Depth Inclination Azimuth
Depth
TVDss
+N/ -S +E/ -W
Northing
Easting DLS
Vert Section
(usft) (°) (°)
(usft)
usft
(usft) (usft)
(usft)
(usft) 3,902.01
15,600.00 89.16 124.92
3,960.41
3,902.01
-7,326.56 10,849.24
6,020,489.53
544,875.39 0.00
13,089.82
15,700.00 89.16 124.92
3,961.87
3,903.47
-7,383.79 10,931.23
6,020,432.67
544,957.63 0.00
13,189.81
15,804.59 89.16 124.92
3,963.40
3,905.00
-7,443.66 11,016.98
6,020,373.21
545,043.64 0.00
13,294.39
Start Dir 2°1100' : 15804.59' MD, 3963.4'TVD
15,846.38 90.00 124.92
3,963.70
3,905.30
-7,467.58 11,051.25
6,020,349.45
545,078.01 2.00
13,336.17
End Dir : 15846.38' MD, 3963.7' TVD
15,900.00 90.00 124.92
3,963.70
3,905.30
-7,498.27 11,095.21
6,020,318.96
545,122.11 0.00
13,389.79
16,000.00 90.00 124.92
3,963.70
3,905.30
-7,555.51 11,177.21
6,020,262.10
545,204.36 0.00
13,489.79
16,100.00 90.00 124.92
3,963.70
3,905.30
-7,612.76 11,259.20
6,020,205.23
545,286.61 0.00
13,589.79
16,200.00 90.00 124.92
3,963.70
3,905.30
-7,670.00 11,341.20
6,020,148.37
545,368.86 0.00
13,689.79
16,246.38 - 90.00 124.92
3,963.70 •
3,905.30
-7,696.55 11,379.23
6,020,122.00
545,407.00 0.00
13,736.17
Total Depth : 16246.38' MD, 3963.7' TVD
Targets
Target Name
- hittmiss target
Dip Angle
Dip Dir. TVD
+N/ -S +El -W
Northing
Easting
-Shape
(")
(°) (usft)
(usft) (usft)
(usft)
(usft)
MPU M-13 wp04 CP1
0.00
0.00 3,957.47
-1,971.70 3,178.67
6,025,808.74
537,181.17
- plan hits target center
- Point
MPU M-13 wp04 CP2
0.00
0.00 3,949.70
-2,773.09 4,326.61
6,025,012.69
538,332.65
- plan hits target center
- Point
MPU M-13 wp05 Heel
0.00
0.00 3,956.37
-1,311.61 2,233.11
6,026,464.44
536,232.70
- plan hits target center
- Point
Stonewall Toe wp04
0.00
0.00 3,963.70
-7,696.55 11,379.23
6,020,122.00
545,407.00
- plan hits target center
- Point
MPU M-13 w004 CPS
0.00
0.00 3,932.70
-5,520.68 8,262.41
6,022,283.38
542,280.58
- plan hits target center
- Point
MPU M-13 wp04 CP7
0.00
0.00 3,956.70
-7,180.69 10,640.30
6,020,634.42
544,665.80
- plan hits target center
- Point
MPU M-13 wp04 CP3
0.00
0.00 3,930.70
-3,688.95 5,638.55
6,024,102.92
539,648.63
- plan hits target center
- Point
MPU M•13 wp04 CP6
0.00
0.00 3,957.70
-6,322.07 9,410.36
6,021,487.33
543,432.07
- plan hits target center
- Point
MPU M-13 wp04 CP4
0.00
0.00 3,954.70
4,604.82 6,950.48
6,023,193.15
540,964.61
- plan hits target center
- Point
5/302019 12:53:57PM
Page 9
COMPASS 5000.15 Build 91
Plan Annotations
Measured
Vertical
Halliburton
HALLIBURTON
Depth
Standard Proposal Report
Database: NORTH US + CANADA
Local Co-ordinate Reference:
Well Plan: MPU M -13i
Company: Hilcorp Alaska, LLC
TVD Reference:
M -13i 014 RKB - w/ CBE @ 58.40usft
Project: Milne Point
MO Reference:
M -13i D14 RKB - w/ CBE @ 58.40usft
Site: M Pt Moose Pad
North Reference:
True
Well: Plan: MPU M -13i
Survey Calculation Method:
Minimum Curvature
Wellbore: MPU M -13i
4.20
Start Dir 4-/100': 716.67' MD, 716.2'TVD
Design: MPU M -13i wp05
1,342.93
-126.93
Casing Points
End Dir : 1381.82' MD, 1342.93' TVD
3,606.51
Measured Vertical
-648.29
Casing Hale
Depth Depth
4,939.46
Diameter Diameter
(usft) (usft)
Name
(") (")
16,246.38 3,963.70 41/2"x81/2"
3,956.37
4-112 8-1/2
4,900.00 3,936.03 9 5/8" x 12 1/4"
Start Dir 4°/100' : 5089.46' MD, 3956.37'TVD
9-5/8 12-1/4
Formations
-1,403.21
2,364.33
Measured Vertical Vertical
6,207.62
Dip
Depth Depth Depth SS
3,149.72
Dip Direction
(usft) (usft)
Name
Lithology (I (I
4,989.29 3,945.90 SB_OA
Start Dir 3-1100': 6242.93' MD, 3957.47'TVD
0.00
Plan Annotations
Measured
Vertical
Local Coordinates
Depth
Depth
+N/ -S
+E/ -W
(usft)
(usft)
(usft)
(usft)
Comment
500.00
500.00
0.00
0.00
Start Dir 3'/100': 500' MD, 500'TVD
716.67
716.21
-11.54
4.20
Start Dir 4-/100': 716.67' MD, 716.2'TVD
1,381.82
1,342.93
-126.93
172.81
End Dir : 1381.82' MD, 1342.93' TVD
3,606.51
3,249.29
-648.29
1,194.20
Start Dir 4°/100': 3606.51'MD, 3249.29'TVD
4,939.46
3,940.69
-1,226.22
2,110.79
End Dir : 4939.46' MD, 3940.69' TVD
5,089.46
3,956.37
-1,311.61
2,233.11
Start Dir 4°/100' : 5089.46' MD, 3956.37'TVD
5,249.76
3,964.18
-1,403.21
2,364.33
End Dir : 5249.76' MD, 3964.18' TVD
6,207.62
3,957.29
-1,951.49
3,149.72
Start Dir 4-/100': 6207.62' MD, 3957.29'TVD
6,242.93
3,957.47
-1,971.70
3,178.67
Start Dir 3-1100': 6242.93' MD, 3957.47'TVD
6,247.53
3,957.55
-1,974.34
3,182.44
End Dir : 6247.53' MD, 3957.55' TVD
6,589.32
3,962.73
-2,169.95
3,462.67
Start Dir 3-/100': 6589.32' MD, 3962.73'TVD
6,643.05
3,962.79
-2,200.70
3,506.73
End Dir : 6643.05' M0, 3962.79' TVD
7,643.05
3,949.70
-2,773.09
4,326.61
Start Dir 3°/100': 7643.05' MD, 3949.7f1/D
7,726.77
3,946.77
-2,820.97
4,395.21
End Dir : 7726.77' MD, 3946.77' TVD
7,936.45
3,934.84
-2,940.79
4,566.87
Start Dir 3-1100': 7936.45' MD, 3934.84'TVD
8,043.50
3,931.75
-3,002.03
4,654.60
End Dir : 8043.5' MD, 3931.75' TVD
9,243.50
3,930.70
-3,688.95
5,638.54
Start Dir 30/100': 9243.5' MD, 3930.7'TVD
9,365.88
3,934.51
-3,758.95
5,738.83
End Dir : 9365.88' MD, 3934.51' TVD
9,532.63
3,945.04
-3,854.20
5,875.29
Start Dir 3-/100': 9532.63' MD, 3945.04'TVD
9,644.01
3,948.84
-3,917.91
5,966.55
End Dir : 9644.01' MD, 3948.84' TVD
10,844.01
3,954.70
-4,604.82
6,950.48
Start Dir 30/100': 10844.01' MD, 3954.7'TVD
10,964.88
3,951.47
-4,673.97
7,049.54
End Dir : 10964.88' MD, 3951.47' TVD
11,141.24
3,941.17
-4,774.74
7,193.91
Start Dir 3-/100': 11141.24' MD, 3941.17'TVD
11,244.44
3,937.94
-4,833.77
7,278.48
End Dir : 11244.44' MD, 3937.94' TVD
12,444.44
3,932.70
-5,520.69
8,262.41
Start Dir 3-/100': 12444.44' MD, 3932.7'TVD
12,554.65
3,935.40
-5,583.74
8,352.74
End Dir : 12554.65' MD, 3935.4' TVD
12,759.65
3,946.33
-5,700.91
8,520.61
Start Dir 3-/100': 12759.65' MD, 3946.33'TVD
12,844.87
3,948.97
-5,749.66
8,590.44
End Dir : 12844.87' MD, 3948.97' TVD
13,844.87
3,957.70
-6,322.07
9,410.37
Start Dir 3-/100': 13844.87' MD, 3957.7'TVD
13,926.43
3,956.67
-6,368.75
9,477.23
End Dir : 13926.43' MD, 3956.67' TVD
14,256.93
3,945.44
-6,557.81
9,748.08
Start Dir 3-/100': 14256.93' MD, 3945.44'TVD
14,345.15
3,944.48
-6,608.30
9,820.41
End Dir : 14345.15' MD, 3944.48' TVD
15,345.15
3,956.70
-7,180.69
10,640.30
Start Dir 3'/100': 15345.15' MD, 3956.7'TVD
15,349.68
3,956.76
-7,183.28
10,644.01
End Dir : 15349.68' MD, 3956.76' TVD
15,804.59
3,963.40
-7,443.66
11,016.98
Start Dir 211100': 15804.59' MD, 3963.4'TVD
15,846.38
3,963.70
-7,467.58
11,051.25
End Dir : 15846.38' MD, 3963.7' TVD
16,246.38
3,963.70
-7,696.55
11,379.23
Total Depth: 16246.38' MD, 3963.7' TVD
5/3012019 12:53:57PM Page 10 COMPASS 5000.15 Build 91
Hilcorp Alaska, LLC
Milne Point
M Pt Moose Pad
Plan: MPU M -13i
MPU M -13i
MPU M -13i wp05
Sperry Drilling Services
Clearance Summary
Anticollision Report
30 May, 2019
Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)
Reference Design: M Pt Moose Pad - Plan: MPU M -13i - MPU M -13i -MPU M -13i wp05
Well Coordinates: 6,027,765,70 N, 533,993.84 E (70" 29' 1238" N, 149° 43' 1977' W)
Datum Height: M -13i D14 RKB- wl CRE @58.40usft
Scan Range: 33.70 to 4,900.00 usft. Measured Depth.
Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft
Geodetic Scale Factor Applied
Version: 5000.15 Build: 91
Scan Type:
Scan Type: 2500 e
HALLIBURTON
Sperry Drilling Services
HALLIBURTON
Anticollision Report for Plan: MPU M-131 - MPU M -13i wp05
Hilcorp Alaska, LLC
Milne Point
Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)
1,218.16
4,900.00
Reference Design: MPt Moase Pad - Plan: MPU M -131 -MPU M -13i -MPU M-131 wp05
11,798.92
9.795
Scan Range: 33.70104,900.00 ustt. Measured Depth.
Pass -
4,433.70
Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usfl
4,433.70
Measured Minimum
@Measuretl Ellipse
(]Measured Clearance Summary Based on
Site Name Depth Distance
Depth Separation
Depth Factor Minimum Separation Warning
Comparison Well Name- Wellbore Name -Design (usfl) (usfl)
(ustt) (usfl)
usfl
M Pt L Pad
MPL-20 - MPL-20 - MPL-20
MPL-32 - MPL-32 - MPL-32
MPLJ2 - MPL-32 - MPL-32
M Pt Moose Pad
MPU M-10 - MPU M-10 - MPU M-10
MPU M-10 - MPU M-10 - MPU M-10
MPU M-10 - MPU M-10 - MPU M-10
MPU M-10 - MPU M-10PB1 - MPU M-1013131
MPU M -10 -MPU M-10PB1 - MPU M-10PB1
MPU M -10 -MPU M -10P81 -MPU M-I0PB1
MPU M-10 - MPU M-10PB2 - MPU M-10PB2
MPU M-10 - MPU M-10PB2 - MPU M-10PB2
MPU M -10 -MPU M-10PB2-MPU M-n)PB2
MPU M-10 - MPU M-10PB3 - MPU M-10PB3
MPU M -10 -MPU M-10PB3-MPU M-10PB3
MPU M-10 - MPU M-10PB3 - MPU M-10PB3
MPU M-11 - MPU M-11 - MPU M-11
MPU M-11 - MPU M-11 - MPU M-11
MPU M-11 - MPU M-11 - MPU M-11
MPU M-12 - MPU M-12 - MPU M-12
MPU M-12 - MPU M-12 - MPU M-12
MPU M-12 - MPU M-12 - MPU M-12
MPU M -12 -MPU M-12PB1 -MPU M-12PB1
MPU M -12 -MPU M-12PB1 -MPU M-12PB7
MPU M -12 -MPU M-12PB1 -MPU M-12PB1
MPU M-12 - MPU M-12PB2 - MPU M-12PB2
MPU M-12 - MPU M-12PB2 - MPU M-12PB2
4,900.00
1,218.16
4,900.00
1,093.80
11,798.92
9.795
Clearence Factor
Pass -
4,433.70
968.04
4,433.70
874.61
12,239.90
10.362
Clearance Factor
Pass -
4,900.00
709.69
4,900.00
653.36
12,088.60
12.599
Ellipse SepamOon
Pass -
234.44
172.40
234.44
170.17
234.97
77.390
Centre Distance
Pass -
308.70
172.68
308.70
169.88
307.95
61.682
Ellipse Sepa abon
Pass -
3,28370
1,260.67
3,283.70
1,220.29
2,855.44
31.219
Clearance Factor
Pass -
234.44
172.40
234.44
170.17
234.97
77.390
Centre Distance
Pass -
308.70
172.68
308.70
169.88
307.95
61.682
Ellipse Separation
Pass -
3,283.70
1,260.67
3,283.70
1,220.28
2,855.44
31.217
Clearance Factor
Pass -
234.44
172.40
234.44
170.17
234.97
77.390
Centre Distance
Pass -
308.70
172.68
308.70
169.88
307.95
61,682
Ellipse Separation
Pass -
3,283.70
1,260.67
3,283.70
1,220.29
2,855.44
31.219
Clearance Factor
Pass -
234.44
172.40
234.44
170.17
234.97
77.390
Centre Distance
Pass -
30870
172.68
30870
169.88
307.95
61.682
Ellipse Separation
Pass -
3,283.70
1,260.67
3,283.70
1,220.29
2,855.44
31.219
Clearance Factor
Pass -
408.98
123.02
408.98
119.53
409.97
35.256
Centre Distance
Pass -
433.70
123.10
433.70
119.42
433.99
33.482
Ellipse Separation
Pass -
4,208.70
1,491.27
4,208.70
1,428.06
3,879.50
23.594
Clearance Factor
Pass -
33.70
137.64
33.70
136.92
34.55
151.029
Centre Distance
Pass -
283.70
138.99
283.70
135.88
283.18
44.746
Ellipse Separation
Pass -
4,900.00
753.42
4,900.00
672.24
5,583.32
9.281
Clearance Factor
Pass -
33.70
137.84
33.70
136.92
34.55
151.029
Genne Distance
Pass -
28370
138.99
283.70
13588
211
44.746
Ellipse Separation
Pass -
4,533.70
786.56
4,533.70
691.40
5,107.00
8.265
Clearance Factor
Pass -
33.70
137.84
33.70
136.92
34.55
151.029
Cents Distance
Pass -
283.70
138.99
283.70
135.88
283.18
44.746
Ellipse Separation
Pass -
30 May, 2019 - 12:56 Page 2 of COMPASS
Hilcorp Alaska, LLC
HALLIBURTON
Milne Point
Anticollision Report for Plan: MPU
M-131 - MPU M-131 wp05
Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)
Reference Design: M Pt Moose Pad - Plan: MPU M -13i - MPU M -13i - MPU
M -13i woos
Scan Range: 33.70 to 4,900.00 part. Measured Depth.
Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited.
Max Ellipse
Separation is 1,500.00 usft
Measured
Minimum
@Measured
Ellipse
®Measured
Clearance Summary Based on
Site Name
Depth
Distance
Depth Separation
Depth
Factor Minimum
Separation Warning
Comparison Well Name- Wellbore Name - Design
(usff)
(usn)
(usrt)
(usR)
usrt
MPUM-I2-MPUM-12PB2- MPU M-12PW
4,900.00
753.42
4,900.00
672.13
5,583.32
9.268 Clearance Factor
Pass -
MPU M-I4-MPUM-I4-MPUM-14
811.44
63.16
811.44
56.21
818.86
9.064 Cenhe Distance
Pass -
MPU M-I4-MPUM-I4- MPU M-14
83370
63.34
833.70
56.19
840.95
8.853 Ellipse Separation
Pass -
MPU W14-MPUM-I4- MPU M-14
908.70
66.74
908.70
58.91
914.%
8.530 Clearance Factor
Pass -
MPUM-I6-MPU MA6- MPU M-16
80333
264.15
803.73
257.49
830.02
39.650 Centre Distance
Pass -
MPU M-16 - MPU M -I6 - MPU M-16
808.70
264.16
808.70
257.46
835.10
39.411 Ellipse Separation
Pass -
MPUM-I6-MPUM-I6- MPU M-16
1,958.70
553.56
1,958.70
532.74
1,925.52
26.587 Clearance Factor
Pass-
Plan: MPU M-07WSW - MPU M-07 (WSW) - M-07WS
2,395.57
125.05
2,395.57
83.51
2,735.51
3.011 Clearance Factor
Pass -
Plan: MPU M-10 P2 - Mt05 Phase 2 - M-10 P2 wp02
261.28
194.95
261.28
191.86
261.58
62.975 Centre Distance
Pass -
Plan: MPU M-10 P2 -M105 Phase 2-M-10 P2 wp02
308.70
195.14
308.70
191.68
306.47
56.450 Ellipse Separation
Pass -
Plan :MPU M-10 P2 -M105 Phase 2-M-10 P2 wp02
1,608.70
516.53
1,608.70
490.68
1,386.29
19.983 Clearance Factor
Pass -
Plan: MPU M-11 i P2 - M106 Phase2 - M -11i P2 wp02
261.28
138.11
261.28
134.99
261.59
44.352 Centre Distance
Pass -
Plan: MPU M-11 i P2 - M106 Phase2 - M-11 i P2 wp02
283.70
138.11
283.70
134.82
283.73
42.014 Ellipse Separation
Paas -
Plan :MPUM-11i P2-M106Phase2-M-11i P2wp02
4,900.00
1.461.62
4,900.00
1,368.83
4,604.81
15752 Clearance Factor
Pass-
Plan: MPU MA2 P2 -M107 Phase 2-M-12 p2 wp02
333]0
127.84
333.70
124.17
334.00
34A0 Centre Distance
Pass -
Plan: MPU M-12 P2 - M107 Phase 2 - M-12 p2 wp02
358.70
127.91
358.70
124.114
358.12
33.068 Ellipse Separation
Pass -
Plan :MPUM-12 P2 -M107 Phase 2-M-12 p2 wp02
4,900.00
804.69
4,900.00
706.27
5,334.40
8.176 Clearance Factor
Pass -
Plan: MPU M-13iP2 - M-13 Phase 2 - M -13i P2 wp02
iiiiiiiiiiiiiiiit
-
Plan: MPU M-14 P2 - M-14 Phase2 - M-14 P2 wp02
483.93
58.84
483.93
54.03
464.62
12.232 Centre Distance
Pass -
Plan: MPU M-14 P2 - M-14 Phase2 - M-14 P2 wp02
508.70
58.90
508.70
53,90
509.22
11.778 Ellipse Separation
Pass -
Plan: MPU M-14 P2 - M-14 Phase2 - M-14 P2 wp02
4,900.00
828.04
4,900.00
734.87
4,725.03
8.888 Clearance Factor
Pass -
Plan: MPU M-15i-M-15i-N415i wp04
757.84
178.08
757.84
171.05
769.78
25.334 Centre Distance
Paas -
Plan :MPU M -15i -M -15i -M-151 sanN
783.70
178.18
783.70
170.93
797.30
24.570 Ellipse Separation
Pass-
PIan:MPU M -151 -M -151-M-1 Si wp04
4,658.70
1,496.05
4,658.70
1,417.74
4,342)3
19.105 Clearance Factor
Pass -
Plan: MPU M-15iP2 - M-15 Phase 2 - M -15i P2 wp02
80000
143.08
800.00
135.73
813.49
19 476 Centre Distance
Pass -
Plan: MPU M -15i P2 - M-15 Phase 2 - M -15i P2 wp02
833.70
143.31
833.70
135.66
848.47
18.750 Ellipse Separation
Pass -
Plan; MPU M -15i P2 -M-15 Phase 2-M-151 P2 wp02
1,033.70
156.50
1,033.70
147.25
1,050.82
16.917 Clearance Factor
Pass-
PIan:MPUM-i6P2-M-16Phase2-MPUM-16P2w
812.52
229.58
812.52
222.10
836.58
30.679 Centre Distance
Pass -
Plan: MPU M-i6P2-M-16 Phase 2- MPU M-16 P2
83370
229.69
833.70
222.02
858.67
29.955 Ellipse Separation
Pass -
Plan :MPUM-15P2-M-16Phsse2-MPUM-i6P2.
1,583.70
395.21
1,583.70
379.63
1,572.21
25366 Clearance Factor
Pass -
Plan: MPU M-20- MPU M-20- MPU M-20 wp04
385.88
194.70
385.68
191.05
385.98
53.367 Centre Distance
Pass-
30 May, 2019 - 12:56
Page 3of7
COMPASS
r
HALLIBURTON
r Hilcorp Alaska, LLC
Milne Point
Anticollision Report for Plan: MPU M -13i - MPU M-131 wp05
456.70
60.17
458.70
56.00
Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)
14.423 Centre Distance
pass -
Plan :MPUM-27-M-27-M-27 wp02
483.70
60.24
Reference Design: M Pt Moose Pad- Plan: MPU M -iii -MPU MAW -MPU M -13i wp05
55.88
463.92
13.816 Ellipse Separation
Pass -
Plan: MPUM-27-M-27-M-27 wp02
Scan Range: 33.70 to 4,900.00 usft. Measured Depth.
78.36
858.70
71.25
824.00
11.016 Clearance Factor
Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 seat
Plan :MPU M -28i -M -28i -M -28i wp01
409.23
90.17
409.23
Measured Minimum
@Measured
Ellipse
@Measured
Clearance Summary Based on
433.70
Site Name Depth Distance
Depth Separation
Depth
Factor Minimum
Separation Warning
Comparison Well Name- Wellbore Name -Design (usft) (usft)
(usft)
(usft)
ush
4,900.00
1,254.89
Plan: MPU M -20 -MPU M -20 -MPU M-20 "N 433.70 194.84
433.70
190.83
432.36
48.525 Ellipse Separation
Pass -
Plan :MPU M -20 -MPU M -20 -MPU M-20 wp04 4,133.70 564.00
4,133.70
516.17
5,995.55
11.792 Clearance Factor
Pass -
Plan: MPU W20 P2- M-20 Phase 2 - M-20 P2 wp03 483.70 172 66
463.70
167.84
484.00
35.656 Centre Distance
Pass -
Plan: MPU 10-20 P2- M-20 Phase 2-M-20 P2 wp03 508.70 172.70
508.70
167.67
508.78
34.291 Ellipse Separation
Pas. -
Plan :MPU M-20 P2 -M-20 Phase 2-M-20 P2 wp03 4,058.70 592.48
4,058.70
544.09
5,338.26
12.245 Clearance Factor
Pass -
Plan : MPU M -27 -M -27-M-27 wp02
456.70
60.17
458.70
56.00
439.30
14.423 Centre Distance
pass -
Plan :MPUM-27-M-27-M-27 wp02
483.70
60.24
483.70
55.88
463.92
13.816 Ellipse Separation
Pass -
Plan: MPUM-27-M-27-M-27 wp02
858.70
78.36
858.70
71.25
824.00
11.016 Clearance Factor
Pass -
Plan :MPU M -28i -M -28i -M -28i wp01
409.23
90.17
409.23
86.38
389.83
23.811 Centre Distance
Pass -
Plan: MPU M -28i - M -28i - M -28i wp01
433.70
90.22
433.70
86.25
413.66
22.703 Ellipse Separation
Pass -
Plan :MPU M -28i -M -281 -M -28i wp01
4,900.00
1,334.59
4,900.00
1,254.89
4,181.52
16.746 Clements Factor
Pass-
Plan: MPU M -29 -M -29-M-29 wp02
409.23
120.17
409.23
116.39
389.83
31.733 Centre Distance
Pass -
Plan: MPUM-29-10-29-10-29 wp02
433]0
120.21
433.70
116.24
413.69
30.256 Ellipse Separation
Pass -
Plan: MPUM-29-M-29-M-29 wp02
958.70
154.01
958.70
146.37
900.00
20.143 Clearance Factor
Pass -
Plan: MPU M-30i-M30i-ld 0i wp02
285.43
150.18
285.43
147.35
266.03
53168 Centre Distance
Pass -
Plan :MPU M-30i-M-301-M-Wi wp02
333.70
150.32
333.70
147.14
312.99
47.141 Ellipse Separation
Pass -
Plan: MPUM-30i-M30i-10301 wp02
908.70
197.85
908.70
190.55
835.35
27.115 Clearance Factor
Pass-
Plan: MPU M-57 (SMGO) - Slot 36 -MPU M -57-M57
483.70
218.62
483.70
214.20
473.30
49.562 Centre Distance
Pass -
Plan: MPU M57(SMGO)-Slot 36 -MPU 10-57-M-57
508.70
21863
508.70
214A3
498.30
47.473 Ellipse Separation
Pass -
Plan: MPU M-57(SMGO)-Slot 36 -MPU 10-57-M-57
908.70
258.20
908.70
250.42
900.20
33.205 Clearance Factor
Pass -
Proposal: MPU M-09DSW-AP Hill -M-09DSW-APH
2,236.99
280.94
2,236.99
244.06
2,729.23
7.618 Centre Distance
Pass -
ProposatMPUM-09DSW-AP Hill -M419DSW-APH
2,258.70
281.27
2,258.70
243.42
2,746.10
7.430 Ellipse Separation
Pass -
prop osal:MPUM-09DSW-AP Hill -M-09DSW-APH
2,383.70
295.73
2,383.70
253.60
2,843.21
7.019 Clearance Factor
Pass -
Slot 33-Placeholder-Slot 33-Placeholder-Slot 33-
483]0
209.86
483.70
205.45
446.30
47.585 Centre Distance
Pass -
Slot 33-Placeholder-Slot 33-Placehalder-Slot 33-
533.70
209.96
53370
205.17
496.30
43.752 Ellipse Separation
Pass -
Slot 33-Placeholder-Slot 33-Placeholder-Slot 33-
908.70
236.59
908.70
228.86
868.13
30.625 Clearance Factor
Pass -
Slot 39-Placeholder-Slot 39-Placehalder-Slot 39-
483.70
119.85
483.70
115.44
446.30
27.176 Centre Distance
Pa" -
Slot 39-Placeholder-Slot 39-Plawholder-Slot 39-
533.70
119.96
533.70
115.16
496.30
24.996 Ellipse Separation
Pass -
Slot 39-Placeholder-Slot 39-Placeholder-Slot 39-
858.70
139.40
858.70
132.05
819.20
18.966 Clearance Factor
Pass-
Slot 42-Placeholder-Slot 42-Placeholder-Slot 42-
483.70
152.34
483.70
147.93
446.30
34.542 Centre Distance
Pass -
30 May, 2019 - 12:56 Page 4 of 7 COMPASS
HALLIBURTON
Anticollision Report for Plan: MPU M -13i - MPU M-131 wp05
Hilcorp Alaska, LLC
Milne Point
Closest Approach 30 Proximity Scan on Current Survey Data (North Reference)
508.70
152.36
Reference Design: MPt Moose Pad - Plan: MPU MAN -MPU M -13i -MPU M -13i wp05
147.75
471.30
Scan Range: 33.70 to 4,900.00 usft. Measured Depth.
Ellipse Separation
Pass -
Scan Radius is Unlimited. Clearance Factor cutoff Is Unlimited. Max Ellipse Separation is 1,500.00 usft
883.70
Measured Minimum
@Measured Ellipse
@Measured Clearance Summary Based on
She Name Depth Distance
Depth Separation
Depth Factor Minimum Separation Warning
Comparison Well Name - Wellbore Name - Design (usft) (usft)
(usft) (usft)
usft
Slot 42-Placeholder-Slot 42-Placeholder-Slot 42-
508.70
152.36
508.70
147.75
471.30
33.087
Ellipse Separation
Pass -
Slot 42-Placeholder-Slot 42-Placeholder-Slot 42-
883.70
190.17
883.70
182.58
843.70
25.056
Clearance Factor
Pass -
Slot 48-Placeholder-Slot 48-Placeholder-Slot 48-
483.70
124.31
483.70
119.90
446.30
28.187
Centre Distance
Pass -
Slot 48-Placeholder-Slot 48-Placeholder-Slot 48-
508.70
124.33
508.70
119.73
471.30
27.000
Ellipse Separation
Pass -
Slot 48-Placeholder-Slot 48-Placeholder-Slot 48-
883.70
157.77
883.70
150.19
843]0
20.822
Clearance Factor
Pass-
Slot 49-Placeholder-Slot 49-Placeholder-Slot 49-
697.13
28.40
697.13
2233
659.38
4.681
Centre Distance
Pass -
Slot 49-Placeholder-Slot 49-Placeholder-Slot 49-
733.70
28.62
733.70
22.27
695.72
4.506
Ellipse Separation
Pass -
Slot 49-Placeholder-Slot 49-Placeholder-Slot 49-
808.70
29.77
808.70
22.83
769.97
4.289
Clearance Factor
Pass -
Slot 54-Placeholder-Slot 54-Placeholder-Slot 54-
483.70
153.57
483.70
149.16
446.30
34.821
Centre Distance
Pass -
Slot 54-Placeholder-Slot 54-Placeholder-Slot 54-
533.70
153.74
533.70
148.94
496.30
32.032
Ellipse Separation
Pass -
Slot 54-Placeholder-Slot 54-Placeholder-Slot 54-
1,008.70
18174
1,008.70
173.46
964.87
21.941
Clearance Factor
Pass -
From To SuroeyfPlan
Survey Tool
(usft) (usft)
33.70 950.00 MPU M-131 wp05
2_Gyro-NS-GC_Drill collar
950.00 4,900.00 MPU M -13i wp05
2_MWD+IFR2+MS+Sag
4,900.00 16,246.38 MPU M -13i wp05
2_MWD+IFR2+MS+Sag
Ellipse error terms are correlated across survey tool tie -on points.
Calculated ellipses incorporate surface errors.
Separation is the actual distance between ellipsoids.
Distance Between centres is the straight line distance between wellbore centres.
Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation).
All station coordinates were calculated using the Minimum Curvature method.
30 May, 2019 - 12:56 Page 5 of COMPASS
MAUUBURTON
Project Milne Poon[
REFERENCE INFORMATION
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Site: MPt Moose Pad
Well: Plan: MPU M -73i
Wellbore: MPU M -13i
Gt�Rtl, �.xDU.
m"m "'°'°
rv",�6
O.w 6� m2n6 m m99384 l0'H Q.1161N 149.41.19.1658
Plan: MPU M -13i wp05
SUIFT-11147 PRWRAM
46 aelw4on fl filYnni mlYna
NO GLOBAL FILTER: using70
Gale:201J-11-04TOO.U0:00 Wlitlaled Va Versbn:
®
To 16
33]0 To 16246 38
MING DETAILS
Ladder/S.F, Plots
Oeplh From Nnh To SUry "Ph, TOGGouulrmaNNS5GGCC
p��I1
SH 2)
85000 4900A0 MPU M-13ixy05 (MPU M-1]ij-MWO�IFR2M5'ISl9
TVD TVDSS MD Si74 Name
(1 of
4900.00 1624638 NPUM-131ap051MWM-la) 2MNDe1FR2rMi
3936.03 38]]63 490000 9-5/3 9SM" x121/4^
3963.70 390530 16246.38 4.m ala^ x e m^
f
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-
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02
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6120.00—
120.00
s
a >9 -PV aMMr
-281 wpp
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-
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i
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i
I
II`
y 30.00
51
9-PlacaMlder
0,00
0 250 500 750 1000 1250 1500 1750 2000 2250 2500 2750 3000 3250 3500 3750 4000 4260 4500 4750
Measured Depth (500 usftfln)
i
o
3,00—
LL
c
D
n
Collision Risk Procedures Req.
N 1.50
Collision Avoidance Req.
No -Go Zone - Stop Drilling
NOERRORS
0,00—
a 300 600 900 1200 1500 1800 2100 2400 2700 3000 3300 3600 3900 4200 4500 4800 5100
Measured Depth
Hilcorp Alaska, LLC
Milne Point
M Pt Moose Pad
Plan: MPU M -13i
MPU M -13i
MPU M -13i wp05
Sperry Drilling Services
Clearance Summary
Anticollision Report
30 May, 2019
Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)
Reference Design: MPt Moose Pad - Plan: MPU M -13i -MPU M -13i -MPU M -13i wp05
Well Coordinates: 6,02],]65 70 N, 533,993.04 E (]0° 29' 12 76" N, 149° 43' 19 ]T' W)
Datum Height: M -13i D14 RKB, wl GIBE @58.40usft
Scan Range. 4,900.00 to 16,24638 usR. Measured Depth.
Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500 00 usff
Geodetic Scale Factor Applied
Version: 5000.15 Build 91
Scan Type:
Scan Type: 25.00 e
HALLIBURTON
Sperry Drilling 9ervieee
HALLIBURTON
Anticollision Report for Plan: MPU M -13i - MPU M -13i wp05
Hilcorp Alaska, LLC
Milne Point
Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)
292.30
6,131.08
Reference Design: MPt MoosePad - Plan: MPU M -13i -MPU M -131 -MPU MA31 wp05
11,447.18
3.791
Scan Range: 4,900.00 to 16,246.36 usn. Measured Depth.
Pass -
6,17500
Scan Radius Is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usn
6,175.00
Measured Minimum
®Measured Ellipse
@Measured Clearance Summary Based an
Site Name Depth Distance
Depth Separation
Depth Factor Minimum Separation Warning
Comparison Well Name -Wellbore Name - Design (usft) (usn)
(usn) (usn)
usft
M Pt L Pad
MPL-20 - MPL-20 - MPL-20
MPL-20 - MPL-20 - MPL-20
MPL-20 - MPL-20 - MPL-20
MPLJ2 - MPL-32 - MPL-32
MPL412 - MPL-32 - MPL-32
MPL-32 - MPL-32 - MPL-32
MPL-34 - MPL-34 - MPL-34
MPL-34 - MPL-34 - MPL-34
MPL-34 - MPL-34 - MPL-34
MPL35-MPL-35-MPL-35
MPLJ5-MPL-35-MPL-35
MPLJ5 - MPL-35 - MPLJ5
MPLJ5 - MPL-35A- MPLJSA
MPL-35 - MPL-35A- MPL-35A
MPL-35 - MPL-35A- MPL-35A
MPL-35-MPLJSAPBI -MPL-35APBI
MPL-35 - MPLJ5APB1 - MPL-35APBI
MPLJ5 - MPL-35APB1 - MPL-35APB1
MPL-35 - MPL-35APB2 - MPL-35APB2
MPL-35 - MPL-35APB2 - MPL-35APB2
MPLJ5 - MPL-35APB2 - MPL-35APB2
MPLJ5 - MPL-MAPB.3 - MPL-35APB3
MPLJ5 - MPL-35APB3 - MPL-35APB3
MPL-35 - MPL-35APB3 - MPL-35APB3
MPL-36 - MPL-36 - MPL-36
MPL-36 - MPL-36 - MPL-36
MPL-36 - MPLJ6 - MPL-36
MPL46 - MPL-36L1 - MPL-36L1
6,131.08
292.30
6,131.08
215.19
11,447.18
3.791
Centre Distance
Pass -
6,17500
295.31
6,175.00
213.01
11,434.52
3.588
Ellipse Separation
Pass -
6,30000
332.84
6,300.00
230.85
11,402.10
3264
Clearance Factor
Pass -
5,053.42
694]5
5,053.42
625.51
12,032.57
10.034
Centre Distance
Pass -
5,150.00
701.71
5,150.00
616.87
11,99704
8.271
Ellipse Separation
Pass -
5,550.00
864.80
5,550.00
725.14
11,837.61
6.192
Clearance Factor
Pass -
7,623.95
855.99
7,623.95
803.61
11,59T70
16.340
Centre Distance
Pass -
7,650.00
85639
7,650.00
803.06
11,592.23
16.059
Ellipse Separation
Pass -
8,250.00
1,063.63
8,250.00
972.39
11,494.84
11.657
Clearance Factor
Pass -
9,353.27
462.20
9,353.27
370.50
10,996.81
5.040
Centre Distance
Pass -
9,375.00
462.59
9,375.00
370.26
10,997.92
5.010
Ellipse Separation
Pass -
9,525.00
491.88
9,525.00
390.51
11,005.84
4.852
Clearance Factor
Pass -
9,353.27
462.20
9,353.27
370.50
10,997.61
5.040
Centre Distance
Pass -
9,375.00
462.59
9,375.00
370.26
10,998.72
5.010
Ellipse Separation
Pass -
9,525.00
491.88
9,525.00
390.51
11,006.64
4.852
Clearance Factor
Pass -
9,353.27
462.20
9,353.27
370.39
10,997.61
5AM
Centre Distance
Pass -
9,375.00
462.59
9,375.00
370.15
10,998.72
5.004
Ellipse Separation
Pass -
9,52500
491.88
9,525.00
390.41
11,006.64
4.847
Clearance Factor
Pass -
9,353.27
462.20
9,353.27
370.39
10,997.61
5.034
Centre Distance
Pass -
9,375.00
462.59
9,375.00
370.15
10,998.72
5.004
Ellipse Separation
Pass -
9,5250C
491.88
9,525.00
390.41
11.006.64
4.847
Clearance Factor
Pass -
9,353.27
462.20
9,353.27
370.39
10,99261
5.034
Centre Distance
Pass -
9,375.00
462.59
9,37500
370.15
10,998.72
5.004
Ellipse Separation
Pass -
9,525.00
491.88
9,525.00
390.41
11,006.64
4.847
Clearance Factor
Pass -
7,097.93
260.59
7,097.93
190.93
11,456.63
3.741
Centre Distance
Pass -
7,150.00
265.52
7,150.00
188.82
11,445.69
3.461
Ellipse Separation
Pass -
7,275.00
312.97
7,275.00
211.88
11,420.59
3.096
Clearance Factor
Pass -
7,097.93
260.59
7,097.93
190.93
11,456.63
3.741
Centre Distance
Pass -
30 May, 2019 - 13:00 Page 2 of 7 COMPASS
HALLIBURTON
Hileorp Alaska, LLC
Milne Point
Anticollision Report for Plan: MPU M -13i - MPU M-131 wp05
7,097.93
260.59
7,097.93
190.93
Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)
3.741 Centre Distance
Pass -
MPL-36 - MPL-36PB1 - MPL-36PB1
7,150.00
265.52
Reference Design: MPt Moose Pad - Plan: MPU M -13i -MPU M -131 -MPU M43i wp05
188.82
11,445.69
3.461 Ellipse Separation
Pass -
MPL-36 - MPL-36PB1 - MPL-36PB1
Scan Range: 4,900.00 to 16,246.3a usft. Measured Depth.
312.97
7,275.00
211.88
11,420.59
3.096 Clearance Factor
Scan Radius is Unlimited. Clearance Factor cutoff Is Unlimited. Max Ellipse Separation is 1,500.00 usfl
MPL-37-MPL-37-MPL-37
9,301.72
946.31
9,301.72
Measured Minimum
gMeasured
Ellipse
@Measured
Clearance Summary Based on
9,400.00
Site Name Depth Distance
Depth Separation
Depth
Factor Minimum
Separation Warning
Comparison Well Name - Wellbore Name - Design lush) (usft)
(usft)
(usft)
usft
9,900.00
987.13
MPL-36-MPL-36LI-MPL36L1 7,150.00 26552
7,150.00
188.50
11,445.69
3.447 Ellipse Separation
Pass -
MPL56-MPL-36LI-MPL-36LI 7,275.00 312.97
7,275.00
210.27
11,420.59
3.047 Clearance Factor
Pass-
MPL-36-MPL-36Li PBI -MPL-36Li P0t 7,097.93 260.59
7,097.93
190.92
11,456.63
3.741 Centre Distance
Pass -
MPL-36 - MPL-361-1 PBI -MPL-36LI Pat 7,150.00 265.52
7,150.00
188.25
11,445.69
3.436 Ellipse Separation
Pass -
MPL-36 - MPL-36LI FBI -MPL-36Li PBI 7,275.00 312.97
7,275.00
209.05
11,420.59
3.012 Clearance Factor
Pass -
MPL-36-MPL-36P81-MPL-36PB1
7,097.93
260.59
7,097.93
190.93
11,456.63
3.741 Centre Distance
Pass -
MPL-36 - MPL-36PB1 - MPL-36PB1
7,150.00
265.52
7,150.00
188.82
11,445.69
3.461 Ellipse Separation
Pass -
MPL-36 - MPL-36PB1 - MPL-36PB1
7,275.00
312.97
7,275.00
211.88
11,420.59
3.096 Clearance Factor
Pass -
MPL-37-MPL-37-MPL-37
9,301.72
946.31
9,301.72
860.72
11,256.44
11.057 Centre Distance
Pass-
MPL-37-MPL57-MPL-37
9,400.00
949.25
9,400.00
858.70
11,252.45
10.483 Ellipse Separation
Pass-
MPL-37-MPL-37-MPL-37
9,900.00
1,118.39
9,900.00
987.13
11,226.28
8.520 Clearance Factor
Pass-
MPL-37-MPL-37A-MPL-37A
9,293.36
974.63
9,293.36
886.21
11,209.51
11.022 Centre Distance
Pass-
MPL57-MPL-37A-MPL-37A
9,40000
977.78
9,400.00
882.81
11,190.38
10.295 Ellipse Separation
Pass-
MPL-37-MPL-37A-MPL-37A
9,900.00
1,141.32
9,900.00
1,006.39
11,126.74
8.459 Clearance Factor
Pass -
MPU L-51 -MPU L-51 -MPU L-51
11,575.00
201.60
11,575.00
77.72
11,588.68
1 627 Clearance Factor
Pass -
MPU L-51 -MPU L-51 -MPU L-51
11,600.00
188,67
11,600.00
74.89
11,597.58
1.658 Ellipse Separation
Pass -
MPU L-51 -MPU L-51 -MPU L-51
11,706.17
161.53
11,706.17
96.40
11,638.47
2.480 Centre Distance
Pass -
MPU L -52 -MPU L -52 -MPU L-52
10,100.00
217.42
10,100.00
101.75
11,828.48
1.880 Clearance Factor
Pass -
MPU L52 -MPU L -52 -MPU L-52
10,15000
192.13
10,150.00
95.03
11,847.36
1.979 Ellipse Separation
Pass -
MPU L -52 -MPU L -52 -MPU L-52
10,24591
170.42
10,24591
110.57
11,88336
2.848 Centre Distance
Pass -
MPU L -53 -MPU L -53 -MPU L-53
8,598.85
149.59
8,598.85
79.60
12,202.45
2.137 Centre Distance
Pass -
MPU L -53 -MPU L -53 -MPU L-53
8,625.00
151.61
8,625.00
79.38
12,210.84
2.099 Ellipse Separation
Pass -
MPU L -53 -MPU L -53 -MPU L-53
8,67500
165.96
8,675.00
84.07
12,226,65
2.027 Clearance Factor
Pass -
MPU L -54 -MPU L -64 -MPU L-64
12,55000
165.76
12,550.00
23.70
11,991.78
1.167 Clearance Factor
Pass -
MPU L -54 -MPU L -54 -MPU L-54
12,656.59
13544
12,656.59
63.20
12,038.80
1.875 Centre Distance
Pass -
MPU L -56 -MPU L56 -MPU L-56
9,325.00
198.55
9,325.00
86.40
11,934.31
1.770 Clearance Faolor
Pass -
MPU L -56 -MPU L56 -MPU L56
9,375.00
172.37
9,375.00
79.04
11,952.12
1.847 Ellipse Separation
Pass -
MPU L -56 -MPU L56 -MPU L-56
9,458.97
153.29
9,458.97
95.89
11,981.14
2.670 Centre Distance
Pass-
MPU L -57 -MPU L57 -MPU L-57
10,850.00
218.93
10,850.00
98.27
11,714.45
1.814 Clearance Factor
Pass-
MPUL-57-MPU L57 -MPU L-57
10,900.00
194.03
10,900.00
92.75
11,733.03
1.916 Ellipse Separation
Pass -
30 May, 2019 - 13:00 Page 3of7 COMPASS
HALLIBURTON
Anticollision Report for Plan: MPU M-131 - MPU MAN wp05
Hileorp Alaska, LLC
Milne Point
Closest Approach 3D Pmxlmity Scan on Current Survey Data (North Reference)
4,900.09
75342
4,900.00
672.24
5,583.32
Reference Design: MPt Moose Pad - Plan: MPU M -13i -MPU M -13i -MPU M -13i wipes
Pass -
Men M -I2 -MPU M -I2 -MPU M-12
16,075.00
829.81
16,075.00
Scan Range: 4,900.00 to 16,246.38 usft. Measured Depth.
16,792.00
1.473 Clearance Factor
Pass -
MPUM-I2-MPU M-12PB1-MPU M-12PB7
4,90000
Scan Radius is Unlimited. Clearance Factorcutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft
4,900.00
824.57
5,10700
10.049 Clearance Factor
Measured Minimum
(gMeasumd
Ellipse
(glMeasured
Clearance Summary Based on
672.13
Site Name Depth Distance
Depth
Separation
Depth
Factor Minimum
Separation Warning
Comparison Well Name -Wellbore Name - Design (usft) (usft)
(usft)
(usft)
..it
Pass-
MPU M -I4 -MPU M -I4 -MPU M-14
MPU L57 -MPU L -57 -MPU L-57 11004.45 169.48
11,004.45
106.95
11,773.57
2.710 Centre Distance
Pass -
MPU L57 -MPU L-57PBI -MPU L57PB1 10,850.00 218.93
10,850.00
98.26
11,714.45
1.814 Clearance Factor
Pass -
MPU L-57 -MPU L-57PB1 - MPU L57PB1 10,900.00 194.03
10,900.00
92.75
11,733.03
1.916 Ellipse Separation
Pass -
MPU L-57 -MPU L-57PBI - MPU L-57PB1 11,004.45 169.48
11,004.45
106.95
11,773.57
2.710 Centre Distance
Pass -
M Pt Moose Pad
MPU M -I2 -MPU M -I2 -MPU M-12
4,900.09
75342
4,900.00
672.24
5,583.32
9.281 Centre Distance
Pass -
Men M -I2 -MPU M -I2 -MPU M-12
16,075.00
829.81
16,075.00
266.52
16,792.00
1.473 Clearance Factor
Pass -
MPUM-I2-MPU M-12PB1-MPU M-12PB7
4,90000
91569
4,900.00
824.57
5,10700
10.049 Clearance Factor
Pass -
MPU M -I2 -MPU M -12P82 -MPU M-12PM
4,90000
753.42
4,900.00
672.13
5,583.32
9.268 Centre Distance
Pass -
MPU M -I2 -MPU M-12PB2-MPU M-12PB2
15,925.00
944.72
15,925.00
272.06
18,843.00
1.475 Clearance Factor
Pass-
MPU M -I4 -MPU M -I4 -MPU M-14
12,034.45
788.62
12,034.45
414.95
12,103,77
2.110 Centre Distance
Pass -
MPU M -14 -MPU M -I4 -MPU M-14
16,246.38
816.71
16,246.38
241.55
16,323.68
1.420 Clearance Factor
Pass -
Plan :MPUM-07WSW-MPU M-07 MSWI-M-07WS
4,900.00
1,227.21
4,900.00
1,209.98
3,927.96
71.241 Clearance Factor
Pass -
Plan:MPU M -11i P2 -M106 Phase2-M-11i P2 wp02
4,900.00
1,461.62
4,900.00
1,368.83
4,604.81
15.752 Ellipse Separation
Pass -
Plan :MPU M -11i P2 -M106 Phase2-M-11i P2 wp02
5,02560
1,495.04
5,025.00
1,399.26
4,71247
15.609 Clearance Factor
Pass -
Plan: MPU M-12 P2 - M107 Phase 2 - M-12 p2 wp02
4,900.00
804.69
4,900.00
706.27
5,334.40
8.176 Centre Distance
Pass -
Plan: MPU M-12 P2 - M107 Phase 2 - M-12 P2 wp02
15,650.00
823.62
15,650.00
239.81
16,070.59
1.411 Clearance Factor
Pass -
Plan: MPU M-14 P2 - M-14 Phase2 - M-14 P2 wp02
1466362
80233
14,663.62
276.72
14,47000
1.526 Centre Distance
Pass -
Plan :MPU M-14 P2 -M-14 Phase2-M-14 P2 wp02
14,675.00
80241
14,675.00
276.47
44,470.04
1.526 Clearance Factor
Pass -
PIan:MPU M -20 -MPU M -20 -MPU M-20 wp04
4,90000
1,108,13
4,900.00
1,048.37
6,334.19
19.152 Clearance Factor
Pass -
Plan: MPU M -20 -MPU M -20 -MPU M-20 wp04
4,900.00
1,106.13
4,900.00
1,048.37
6,334.19
19.152 Ellipse Separation
Pass -
Plan: MPU M-20 P2 -M-20 Phase 2-M-20 P2 wp03
4,900.00
1,203.44
4,900.00
1,142.79
5,711.00
19.840 Clearance Factor
Pass -
Plan :MPU M -27 -M -27-M-27 wp02
4,900.00
1,241.64
4,900.09
1,177.95
3,971.36
19.495 Clearance Factor
Pass -
Plan :MPU M -28i -M -28i -M -28i wp01
4,900.00
1,334.59
4,900.00
1,254.89
4,181.52
16.746 Ellipse Separation
Pass -
Plan: MPU M-261 - M-281 - M -28i wpOl
4,925.00
1,340.56
4,925.00
1,260.8
4,200.00
16.656 Clearance Factor
Pass -
Proposal: MPU M-09DSW-AP Hill -M-09DSW-APH
5,364.75
1,295.88
5,364.75
1,172.72
5,804.51
10.522 Centre Distance
Pass -
Proposal: MPU M-09DSW-AP Hill -M-09DSW-APH
5,450.00
1,297.86
5,450.00
1,170.88
5,860.05
10.221 Ellipse Separation
Pass -
Proposal: MPU M-09DSW-AP Hiil-M-09DSW-APH
5,775.00
1,343.87
5,775.00
1,206.11
6,028.34
9.755 Clearance Factor
Pass -
30 May, 2019 - 13:00 Page 4 of 7 COMPASS
HALLIBURTON
Anticollision Report for Plan: MPU M-11 - MPU M-131 wp05
$urvev tool Program
From
(usfl)
33.70
950.00
4,900.00
To
(-aft)
950.00 MPU M -13i wp05
4,900.00 MPU M -13i woos
16,246.38 MPU M -13i wags
SurveylPlan
Ellipse error terms are correlated across survey tool tie -on points.
Calwlated ellipses incorporate surface errors.
Separation is the actual distance between ellipsoids.
Distance Between centres is the straight line distance beMreen wellbore centres.
Clearance Factor= Distance Between Profiles / (Distance Between Profiles - Ellipse Separation).
All station mordinates were calculated using the Minimum Curvature method.
Survey Tool
2_Gyrc-NS-GC_Drill collar
2 MWD+IFR2+MS+Sag
2_MWD+IFR2+MS+Sag
Hilcorp Alaska, LLC
Milne Point
30 May, 2019 - 1300 Page 6 o/ 7 COMPASS
NALLIBURTON Project: Milne Point
REFERENCE INFORMATION
1, JEIAD384m:MPVM13i NAD 19 NATCOVCO`US) Alukv7-04
��-N Re�.�,wn PK¢MFU M -IU INml,
m]DI R.Ww: M+Nm.wce90se.m.n
--"'
crou.a l<+'a: 2a.79
Site: MPt Moose Pad
Elpv....nu,.e Well: Plan: MPU M -13i
..1, ®a.amn
MmWDpN RMaruw'. M.+ouD+4 Rlm..0Co.
.w -s +ri-u• may. Fssros oe�.a< Mal.x
Wellbore: MPU M-131
..,A. o.-m�..
u.w o0o y)znu �I vw
s3.sa m^zs l,+]MN lora'l9.)esx
Plan: MPU M.13i wp05
SURVEY MA
NO GLOBALFILTER: Usi3,70unir ealeGpnBfiltenM uilere
1I4TWGOG
DaN:201]-1114T000000 191itlefetl: Vc Venlm:
Em
T.Eefined
J].]0 To 18246.38
1 addn.dC C Olnfe
Depth From Cloth To &—lAPbn Tool
CASING OLTAIM
y]0 95000 M1U.13i,05(IJPUM-03r) 3Gpa-N9.GC_DMI
PH 2)
95000 490000 MPUMA3ixy4.5(MPUM-131) 3MWDNFR2-Ml
TVD TVDSS MD Siss Nan.
(2 of
490000 16246]8 MPUM13iw (MPUM4S) 2_MWD.IFR21M65
3936.03 38]].63 4900.00 95R 95/8"x121/4"
3963.70 3"530 16246.38 4 -IC 41/P'xelc•
--"MPU
150.D0
.� ---
L
I
o
o
p 20.00
.__-'--_'-_..,
�._-............_....--_
rn
I
60.00
II
0
1
U
0.00
5400 6000 6600 7200 7800 8400 9000 9600 10200 1oa00 11400 12000 12600 13200 13800 14400 15000 15600 1620
Measured Depth (1200 usftrin)
4.50
—
`o
I
aoo
LL
o
Collision
Risk Procedures
Req.
Collision Avoidance Req
�
I
NO-GO Zane - Stop Diik
g
NOERRORS
1100
5200 585o 6500 7150 7800 8450 9100 9750 10400 11050 11700 12350 13000 13650 14300 149W 15600 1620
Measured Depth (1200 usft/in)
Davies, Stephen F (CED)
From: Joe Engel <jengel@hilcorp.com>
Sent: Tuesday, June 11, 2019 2:55 PM
To: Davies, Stephen F (CED)
Cc: Boyer, David L (CED); Cody Dinger
Subject: RE: [EXTERNAL] RE: MPU M-13 (PTD 219-087) - AOR Question
Steve —
Talking with our Geo, Kevin, none of the wells you listed (L-32, L-34, L-35, L-37, L-39), are within 1320' (1/4 miles) of the
M-13 OA injection interval.
Please let me know if you have any questions.
Thank you for your time.
-Joe
Joe Engel I Drilling Engineer I Hilcorp Alaska, LLC
3800 Centerpoint Dr., Ste. 1400 1 Anchorage I AK 199503
Office: 907.777.8395 1 Cell: 805.235.6265
From: Joe Engel
Sent: Monday, June 10, 2019 10:10 AM
To: 'Davies, Stephen F (CED)' <steve.davies@alaska.gov>
Cc: Boyer, David L (CED) <david.boyer2@alaska.gov>
Subject: RE: [EXTERNAL] RE: MPU M-13 (PTD 219-087) - AOR Question
Steve —
M-13 will not be pre -produced.
Regarding the AOR question, I will consult with our Geo and get back to you once they review.
Thanks.
Joe Engel I Drilling Engineer I Hilcorp Alaska, LLC
3800 Centerpoint Dr., Ste. 1400 1 Anchorage I AK 199503
Office: 907.777.8395 1 Cell: 805.235.6265
From: Davies, Stephen F (CED) [mailto:steve.davies@alaska.gov
Sent: Friday, June 7, 2019 1:30 PM
To: Joe Engel <iengel@hilcorp.com>
Cc: Boyer, David L (CED) <david boyer2@alaska.gov>
Subject: [EXTERNAL] RE: MPU M-13 (PTD 219-087) - AOR Question
Joe,
An additional question: Will M-13 be pre -produced for a significant length of time (30 days or longer), or will it be briefly
flowed back for clean up only?
Thanks again,
Steve Davies
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.daviesPalaska.eov,
From: Davies, Stephen F (CED)
Sent: Friday, June 7, 2019 1:18 PM
To: Joe Engel <ieneel@hilcoro.com>
Cc: Boyer, David L (CED) <david.boyer2@alaska.gov>
Subject: MPU M-13 (PTD 219-087) - AOR Question
Joe,
The isolation -status table for the MPU M-13 Area of Review (AOR) includes wells L-20 and L-36. Do any of the following
wells open any portion of the OA sand within one-quarter mile of the OA infection interval that will be open in M-13: L-
32, L-34, L-35, L-37, or L-39? If so, please revise the table and submit copy as soon as practical.
Thank you,
Steve Davies
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.
The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this
communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review,
dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and
permanently delete the copy you received.
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.
Davies, Stephen F (CED)
From: Davies, Stephen F (CED)
Sent: Friday, June 7, 2019 1:30 PM
To: Joe Engel
Cc: Boyer, David L (CED)
Subject: RE: MPU M-13 (PTD 219-087) - AOR Question
Joe,
An additional question: Will M-13 be pre -produced for a significant length of time (30 days or longer), or will it be briefly
flowed back for clean up only?
Thanks again,
Steve Davies
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.daviesPalaska.aov.
From: Davies, Stephen F (CED)
Sent: Friday, June 7, 2019 1:18 PM
To: Joe Engel <jengel@hilcorp.com>
Cc: Boyer, David L (CED) <david.boyer2@alaska.gov>
Subject: MPU M-13 (PTD 219-087) - AOR Question
Joe,
The isolation -status table for the MPU M-13 Area of Review (AOR) includes wells L-20 and L-36. Do any of the following
wells open any portion of the OA sand within one-quarter mile of the OA infection interval that will be open in M-13: L-
32, L-34, L-35, L-37, or L-39? If so, please revise the table and submit copy as soon as practical.
Thank you,
Steve Davies
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(Malaska.eov.
TRANSMITTAL LETTER CHECKLIST
WELL NAME: /6 : i�j - / E
PTD: '2-12 —(�O 7
Development ✓ Service _ Exploratory _ Stratigraphic Test _ Non -Conventional
FIELD:/I///t L. 'r ` Z POOL: � `� r �_6 C may` r
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
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OPTIONS
TEXT FOR APPROVAL LETTER
MULTI
The permit is for a new wellbore segment of existing well Permit
LATERAL
No. , API No. 50- _-
(If last two digits
Production should continue to be reported as a function of the original
in API number are
API number stated above.
between 60-69
In accordance with 20 AAC 25.005(f), all records, data and logs
acquired for the pilot hole must be clearly differentiated in both well
Pilot Hole
name ( PH) and API number (50—
from from records, data and logs acquired for well
name on permit).
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce/inject is contingent upon issuance of a conservation
Spacing Exception
order approving a spacing exception. (Company Name) Operator
assumes the liability of any protest to the spacing exception that may
occur.
All dry ditch sample sets submitted to the AOGCC must be in no greater
Dry Ditch Sample
than 30' sample intervals from below the permafrost or from where
samples are first caught and 10' sample intervals through target zones.
Please note the following special condition of this permit:
production or production testing of coal bed methane is not allowed for
Non -Conventional
(name of well) until after (Company Name) has designed and
Well
implemented a water well testing program to provide baseline data on
water quality and quantity. (Company Name) must contact the AOGCC
to obtain advance approval of such water well testing program.
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of
well logs to be run. In addition to the well logging program proposed by
(Company Name) in the attached application, the following well logs are
also required for this well:
Well Logging
Requirements
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for well logs run must be submitted to the AOGCC
within 90 days after completion, suspension or abandonment of this well.
Revised 2/2015
WELL PERMIT CHECKLIST Field & Pool MILNE POINT, SCHRADER BLFF OIL - 525140
_ Well Name: MILNE PT UNIT M-13 -------Program SER Well bore seg
PTD#:2190870 Company HILCORP ALASKA LLC Initial Class/Type
_—SER / PEND __GeoArea 890 Unit 11_32B___ — On/Off Shore On Annular Disposal _
Administration
1
Permit fee attached _ _
NA..
2
Lease number appropriate.
Yes
3
Unique well name and number _ _ ......
Yes
4
Well located in defined pool _ _ _ _ _ _ _ _ _ _ _ _ _ _
Yes
_ _ _ _ Milne Point Schrader Bluff Oil Pool (52514Q), governed by CO 477, amended by CO 477,05. _
5
Well located proper distance from drilling unit boundary _ _ _
Yes
CO 477.05 specifies:. "There are no restrictions as to well spacing except that no pay shall.. _
6
Well located proper distance. from other wells. _ _ _
Yes
be. opened. in a well closer than 500 feet from the exterior boundary of the affected area."
7
Sufficient acreage available in drilling unit_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Yes
_ _ _ As planned, well conforms to spacing requirements, ... ........
8
If deviated, is wellbore plat included _ _ _ _ .. _ _
Yes
9
Operator only affected party. _ _ _ _ _ _ _ _ _ _ _ _
Yes
10
Operator has. appropriate bond in force _ _ _ _ _ _ _ _ _
Yes
11
Permit can be issued without conservation order. _ ..... _
Yes
... . ........ . .
Appr Date
12
Permit. can be issued without administrative_ approval _ _ _ _ _
Yes
13
Can permit be approved before 15 -day waif _ _ _ _ _ _ _ _
Yes
SFD 6/12/2019
14
Well located within area and strata authorized by Injection Order # (put 0# in comments) (For.
Yes
_ _ Area Injection Order No. 10-B
15
All wells within 1/4. mile area of review identified (For service well only).. _ _ _ _
Yes
MPU L-20,. L-36, M-12, M-14._
16
Pre -produced injector duration of pre production less than 3 months (For service well only) _ _
No
. . . . . ... . ....
17
Nonconven, gas conforms to AS31.05,030(j.1.A),Q,2.A-D) ......
NA
18
Conductor string,provided _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Yes
_ conductor set at 114 it..
Engineering
19
Surface casing. protects all known USDWs _ _ _ . _ _ _ _ _ _
NA
20
CMT.vol adequate.to circulate. on conductor.8i surf csg ....... _ .....
Yes
.... using.ES.cementer.for2.stage job. Set at about 2000 ft..
21
CMT vol adequate to tie-in long string to surf csg. . _ _ _ _
Yes
22
CMT. will cover all known_ productive horizons_ _ _ _ _ _ _ _ _ _
Yes
_ Slotted liner will be set_ across injection interval..
23
Casing designs adequate for C, T, B &. permafrost..... _ _ ... ....
Yes
BTC calcs provided....
24
Adequate tankage or reserve pit _ _ _ _ _ _ _ _ _
Yes
_ _ Rig has steel pits.
25
If. a_re-drill, has.a 10-403 for abandonment been approved _ _ _ _ _ _ _ _ _ _
NA_____
26
Adequate wellbore separation proposed _ _ _ _ _ _ _ _ _
Yes
_ _ _ _ No issues. .. . . .......
27
Ifdiverter required, does it meet regulations . _ .... _ ...
Yes
Appr Date
28
Drilling fluid program schematic & equip list adequate_ _ _ _ _
Yes
_ Max form pressure 1700 psi (. 8.6 ppg_EMW). will drill with 8.9-9.5 ppg mud _
GLS 6/11/2019
29
BOPEs, do they meet regulation _ _ _ _ _ _ _
Yes
Doyon has 5000 psi WE BOPS
30
BOPE.press rating appropriate; test to (put psig in comments)_ _ ..
Yes
_ MASP = 1340,psi will test BOPE to 3000 psi ............ .
31
Choke manifold complies w/API_RP-53 (May 84) . . .. ....... . . _ _
Yes
32
Work will occur without operation shutdown_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Yes
_ _ _ _ _ _ ........... _ ................ .
33
Is presence of H2S gas probable .. _ . _ .. ... ..
No
34
Mechanical_ condition of wells within AOR verified (For service well only) _ _ _ _ .....
Yes
..... AOR .. Two Kuparuk.producer from Lpad bisect the injection corridor._ Cemented_off_with ES collar.... _
35
Permitcan be issued w/o hydrogen. sulfide measures .... .. ..... _
Yes .......
H2$ not anticipated from drilling of offset wells; however, rig will have 1-125 sensors and alarms._
Geology
36
Data.presented on potential overpressure zones _ . , _ _ _ _ _ _ _ _
Yes _
_ _ Gas hydrates not expected from drilling.of offset wells. However, mitigation measures are discussed.in .
Appr Date
37
Seismic analysis of shallow gas zones _ _ _ _ _ _ _ _ _ _ _ _
NA
_ _ _ "Anticipated Drilling Hazards" section. Abnormal pressure up to 11.5 ppg EMW has. been encountered in
SFD 6/7/20193,38
Seabed condition survey (if off -shore) _ _ _ _ _ _ _ _ _ _ .
NA
_ _ M -Pad wells due to. nearby injection, Managed. Pressure Drilling will be used to monitor.and control..... .
1
139
Contact name/phone for weeklyprogressreports [exploratory only] _ _ _ _ _
NA
_ _ _ _ pressure. Onsite materials sufficientto build system to_1 ppg above highest anticipated mud weight.
Geologic : Engineering Dale Public Date Grassroots SB injector for Moose pad. Drilling with Doyon 14. gis
Date
Commissioner: Commissioner: Commissioner
Ofs 6(tz� 17 �V?Iel 6l12�l107
