Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAbout220-051MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE:Tuesday, April 22, 2025
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Kam StJohn
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
Hilcorp Alaska, LLC
I-21
MILNE PT UNIT I-21
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 04/22/2025
I-21
50-029-23681-00-00
220-051-0
W
SPT
3996
2200510 1500
724 721 721 723
4YRTST P
Kam StJohn
3/16/2025
Monobore
30 MinPretestInitial15 Min
Well Name
Type Test
Notes:
Interval P/F
Well
Permit Number:
Type Inj TVD
PTD Test psi
API Well Number Inspector Name:MILNE PT UNIT I-21
Inspection Date:
Tubing
OA
Packer Depth
476 1705 1649 1633IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitKPS250316165913
BBL Pumped:1.8 BBL Returned:1.8
Tuesday, April 22, 2025 Page 1 of 1
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9
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James B. Regg Digitally signed by James B. Regg
Date: 2025.04.22 14:28:48 -08'00'
MEMORANDUM
State of Alaska
Inspector Name: Lou Laubenstein
Alaska Oil and Gas Conservation Commission
TO: Jim ReggDATE:
5' 31za,(
Thursday, April 22, 2021
P.1. Supervisor ' \e
SUBJECT: Mechanical Integrity Tests
Hilcorp Alaska, LLC
Rel Insp Num:
1-21
FROM: Lou Laubenstein
MANE Pr UNIT 1-21
Petroleum Inspector
Packer Depth Pretest Initial
Src: Inspector
Well 1-21
Reviewed By:
w yD - 3996 Tubing 6S5 691,
P.I. Supry
NON -CONFIDENTIAL
Comm
Well Name MILNE PT UNIT I-21
API Well Number 50-029-23681-00-00
Inspector Name: Lou Laubenstein
Permit Number: 220-051-0
Inspection Date: 3/1/2021 '
Insp Num: mi[LOL210301165726
Rel Insp Num:
Packer Depth Pretest Initial
15 Min 30 Min 45 Min 60 Min
Well 1-21
ITypeInj I
w yD - 3996 Tubing 6S5 691,
699. 689
PTD 2200510
Type Test I
SPT' Test psi 1500 IA 1 51 1639
- 1571, 1555
BBL Pumped: 122
BBL Returned: 2 OA
Interval
OJITAL
- p/F P ✓
Notes: Good test.
Thursday, April 22, 2021 Page 1 o1 I
DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23681-00-00Well Name/No. MILNE PT UNIT I-21Completion Status1WINJCompletion Date2/3/2021Permit to Drill2200510Operator Hilcorp Alaska, LLCMD14580TVD4155Current Status1WINJ3/1/2021UICYesWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:ROP, AGR, ABG, DGR, EWR, ADR MD & TVDNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF2/9/2021155 14580 Electronic Data Set, Filename: MPU I-21 LWD Final.las34677EDDigital DataDF2/9/20215750 14542 Electronic Data Set, Filename: MPU I-21 ADR Quadrants All Curves.las34677EDDigital DataDF2/9/2021 Electronic File: MPU I-21 LWD Final MD.cgm34677EDDigital DataDF2/9/2021 Electronic File: MPU I-21 LWD Final TVD.cgm34677EDDigital DataDF2/9/2021 Electronic File: MPU I-21i_Definitive Survey Report.pdf34677EDDigital DataDF2/9/2021 Electronic File: MPU I-21i_Definitive Surveys.txt34677EDDigital DataDF2/9/2021 Electronic File: MPU I-21i_Definitive Surveys.xlsx34677EDDigital DataDF2/9/2021 Electronic File: MPU I-21i_GIS.txt34677EDDigital DataDF2/9/2021 Electronic File: MPU I-21i_Plan.pdf34677EDDigital DataDF2/9/2021 Electronic File: MPU I-21i_VSec.pdf34677EDDigital DataDF2/9/2021 Electronic File: MPU I-21 LWD Final MD.emf34677EDDigital DataDF2/9/2021 Electronic File: MPU I-21 LWD Final TVD.emf34677EDDigital DataDF2/9/2021 Electronic File: MPU_I-21_Geosteering.dlis34677EDDigital DataDF2/9/2021 Electronic File: MPU_I-21_Geosteering.ver34677EDDigital DataDF2/9/2021 Electronic File: MPU I-21 LWD Final MD.pdf34677EDDigital DataDF2/9/2021 Electronic File: MPU I-21 LWD Final TVD.pdf34677EDDigital DataDF2/9/2021 Electronic File: MPU I-21 LWD Final MD.tif34677EDDigital DataDF2/9/2021 Electronic File: MPU I-21 LWD Final TVD.tif34677EDDigital DataMonday, March 1, 2021AOGCCPage 1 of 3MPU I-21 LWDFinal.las
DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23681-00-00Well Name/No. MILNE PT UNIT I-21Completion Status1WINJCompletion Date2/3/2021Permit to Drill2200510Operator Hilcorp Alaska, LLCMD14580TVD4155Current Status1WINJ3/1/2021UICYesWell Cores/Samples Information:ReceivedStart Stop CommentsTotalBoxesSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments:Mud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date:2/3/2021Release Date:6/11/20200 0 2200510 MILNE PT UNIT I-21 LOG HEADERS2200510 MILNE PT UNIT I-21 LOG HEADERS34677LogLog Header ScansDF2/9/2021 Electronic File: MPU I-21 EOW Geosteering Log.emf34678EDDigital DataDF2/9/2021 Electronic File: MPU I-21 EOW Geosteering Log.pdf34678EDDigital DataDF2/9/2021 Electronic File: MPU I-21 EOW Geosteering Log.tiff34678EDDigital DataDF2/9/2021 Electronic File: MPU I-21 EOW Geosteering Report.pdf34678EDDigital DataDF2/9/2021 Electronic File: MPU I-21 Post-Well Geosteering X-Section Summary.pdf34678EDDigital Data0 0 2200510 MILNE PT UNIT I-21 LOG HEADERS34678LogLog Header ScansMonday, March 1, 2021AOGCCPage 2 of 3
DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23681-00-00Well Name/No. MILNE PT UNIT I-21Completion Status1WINJCompletion Date2/3/2021Permit to Drill2200510Operator Hilcorp Alaska, LLCMD14580TVD4155Current Status1WINJ3/1/2021UICYesCompliance Reviewed By:Date:Monday, March 1, 2021AOGCCPage 3 of 3M. Guhl3/1/2021
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David Douglas Hilcorp Alaska, LLC
GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal or fax to 907 777-8510.
Received By: Date:
Date: 02/09/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
MPU I-21 (PTD 220-051)
FINAL EOW REPORT – GEOSTEERING LOGS (01/25/2021 to 01/29/2021)
SFTP Transfer - Data Folders:
Please include current contact information if different from above.
Received by the AOGCC 02/09/2021
PTD: 2200510
E-Set: 34678
02/09/2021
David Douglas Hilcorp Alaska, LLC
GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal or fax to 907 777-8510.
Received By: Date:
Date: 02/09/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
MPU I-21 (PTD 220-051)
FINAL LWD FORMATION EVALUATION LOGS (01/16/2021 to 01/29/2021)
•ROP, DGR, AGR, ABG, EWR-M5, ADR, Horizontal Presentation
(2” & 5” MD/TVD Color Logs)
•Final Definitive Directional Survey
SFTP Transfer - Data Folders:
Please include current contact information if different from above.
Received by the AOGCC 02/09/2021
PTD: 2200510
E-Set: 34677
02/09/2021
STATE OF ALASKA
Reviewed B •r Ili 1/
OIL AND GAS CONSERVATION COMMISSION P.I. Suprs�t
BOPE Test Report for: MILNE PT UNIT 1-21 Comm
Contractor/Rig No.: Hilcorp Innovation PTD#: 2200510 ' DATE: 1/24/2021 Inspector Austin McLeod Insp Source
Operator: Hilcorp North Slope, LLC Operator Rep: Lott/Amend Rig Rep: Courson/Leslic Inspector
Type Operation: DRILL Sundry No: Test Pressures: Inspection No: bopSAM210124104932
Rams: Annular: Valves: MASP:
Type Test INIT 250/5000 250/5000 " 250/5000 " 1359 ✓ Related Insp No:
TEST DATA
MISC. INSPECTIONS:
MUD SYSTEM:
ACCUMULATOR SYSTEM:
P/F
Upper Kelly
P/F
P
Visual
Alarm
Time/Pressure P/F
Location Gen.:
P
Trip Tank
P
P
System Pressure 3000
P
Housekeeping:
P _
Pit Level Indicators
P
P
Pressure After Closure _ _ 1.450
P '
PTD On Location
P
Flow Indicator
P
P
200 PSI Attained 25
P
Standing Order Posted
P
Meth Gas Detector
P
P
Full Pressure Attained 96
P
Well Sign
P
H2S Gas Detector
P
P
Blind Switch Covers: All stations
P -
Drl. Rig
P
MS Mise
0
NA
Nitgn. Bottles (avg): 6(a,2350
P
Hazard Sec.
P
NA
(Valid for Coil Rigs Only)
ACC Mise 0
NA
Misc
NA
Quantity
P/F
HCR Valves
2
3-1/8"
FLOOR SAFTY VALVES:
Quantity
P/F
Upper Kelly
I
P
Lower Kelly
1
P
Ball Type
2
P
Inside BOP
I
P
FSV Misc
0
NA
BOP STACK:
CHOKE MANIFOLD:
Quantity
Size
P/F
Quantity
P/F
Stripper
0
NA
No. Valves 15 _
P
Annular Preventer
1
13-5/8" -
P
Manual Chokes 1
P
#1 Rams
I
2-7/8"x5-1/2"
P
Hydraulic Chokes 1
P
#2 Rams
_ 1
Blinds IP
CH Misc 0
NA
#3 Rams
1
2-7/8"x5-1/2"
P
#4 Rams
0
NA
#5 Rams
0
NA
INSIDE REEL VALVES:
#6 Rams
0
NA
(Valid for Coil Rigs Only)
Choke Ln. Valves
1
3-1/8"
P
Quantity
P/F
HCR Valves
2
3-1/8"
FP ✓
Inside Reel Valves 0
NA
Kill Line Valves _
2
3-1/8"
P
Check Valve
0
NA
BOP Misc
0
NA
Number of Failures: 2 ✓ Test Results Test Time 7
Remarks: 3-1/2" & 5" joints. Annular on both. New stack. Requested 5000psi test. Operator decided to lest all components to 5k- Both
HCR's needed grease -passed retest.
STATE OF ALASKA Reviewed By:
OIL AND GAS CONSERVATION COMMISSION P.I. Supry JB2 21wj`-Z,
DIVERTER Test Report for: MILNE PT UNIT 1-21 Comm
Contractor/Rig No.: Hilcorp Innovation *PTD#: 2200510 DATE: 1/15/2021 ' Inspector Guy Cook Insp Source
Operator: Hilcorp Alaska, LLC Operator Rep: James Lott Rig Rep: Matt Courson Inspector
Well Class: DEV - Inspection No: divGDC210113142508
MISC. INSPECTIONS:
GAS DETECTORS:
Visual Alarm
Methane: PP"
Hydrogen Sulfide: _P P
Gas Detectors Misc: NA NA
TEST DATA
MUD SYSTEM:
Visual Alarm
Trip Tank:
P/F
Location Gen.:
P -
Housekeeping:
- P
Warning Sign
P_
24 hr Notice:
P
Well Sign:
_P '
Drlg. Rig.
_P "
Misc:
NA_
GAS DETECTORS:
Visual Alarm
Methane: PP"
Hydrogen Sulfide: _P P
Gas Detectors Misc: NA NA
TEST DATA
MUD SYSTEM:
Visual Alarm
Trip Tank:
NA
NA_
Mud Pits:
P -
P
Flow Monitor:
P -
P '
Mud System Mise:
NA
NA
ACCUMULATOR SYSTEM:
Time/Pressure
P/F
Systems Pressure: 3100 '
P -
Pressure After Closure: 1900 '
P
200 psi Recharge Time: 17
P -
Full Recharge Time: 60
P
Nitrogen Bottles (Number of): 6
P
Avg. Pressure: 2225_-
P '
Accumulator Misc: 0
NA
Related Insp No:
DIVERTER SYSTEM:
Size
P/F
Designed to Avoid Freeze-up?_____
_P-"
Remote Operated Diverter?
P
No Threaded Connections?
P "
Vent line Below Diverter?
P "
Diverter Size: 13.625 -
P -
Hole Size: 12.25
P -
Vent Lines) Size: 16 ___-
p,
Vent Line(s) Length: 203.9
P -
Closest Ignition Source: 75 _ _
P '
Outlet from Rig Substructure: 190
P
Vent Lines) Anchored: _ P
Turns Targeted / Long Radius: NA
Divert Valves) Full Opening: P
Valve(s) Auto & Simultaneous:_
Annular Closed Time: 8 _ 1'
Knife Valve Open Time: 7 P
Diverter Misc: 0 - NA
Number of Failures: 0 ✓ Test Time: 1.5
Remarks: S' drill pipe was used for testing.
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M. Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Re: Milne Point Field, Schrader Bluff Oil Pool, MPU I-21
Hilcorp Alaska, LLC
Permit to Drill Number: 220-051 revised
Surface Location: 2324' FSL, 3597' FEL, Sec 33, T13N, R10E, UM, AK
Bottomhole Location: 1724' FSL, 1848' FWL, Sec 21, T13N, R10E, UM
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Jeremy M. Price
Chair
DATED this ___ day of January, 2021.
y,
19
1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for:
Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates
Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas
2. Operator Name: 5. Bond: Blanket Single Well 11. Well Name and Number:
Bond No.
3. Address: 6. Proposed Depth: 12. Field/Pool(s):
MD: 16,500' TVD: 4,229'
4a. Location of Well (Governmental Section): 7. Property Designation:
Surface:
Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date:
Total Depth: 9. Acres in Property: 14. Distance to Nearest Property:
4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 60.2' 15. Distance to Nearest Well Open
Surface: x-551774 y- 6009440 Zone-4 33.7' to Same Pool: 170' to MPU J-16
16. Deviated wells: Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 90 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
Cond 20" 129.5 X-56 Weld 107' Surface Surface 107' 107'
9-5/8" 47# L-80 TXP 2000' Surface Surface 2000' 1949'
9-5/8" 40# L-80 TXP 3845' 2000' 1949' 5845' 4015'
8-1/2" 4-1/2" 13.5# L-80 Hydril 625 10805' 5695' 16500' 4009' 4229'
19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations)
Junk (measured):
TVD
Hydraulic Fracture planned? Yes No
20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis
Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements
Contact Name:
Contact Email:
Contact Phone:
Date:
Permit to Drill API Number: Permit Approval
Number: 50-029-23681-00-00 Date:
Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales:
Samples req'd: Yes No Mud log req'd: Yes No
H2S measures: Yes No Directional svy req'd: Yes No
Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No
Post initial injection MIT req'd: Yes No
APPROVED BY
Approved by: COMMISSIONER THE COMMISSION Date:
Sr Pet Eng Sr Pet Geo Sr Res Eng
12-1/4"
GL / BF Elevation above MSL (ft):
6/8/2020
See cover letter for other
requirements.220-051
Perforation Depth MD (ft):
21. I hereby certify that the foregoing is true and the procedure approved herein will not be
deviated from without prior written approval.
Perforation Depth TVD (ft):
Commission Use Only
Effect. Depth MD (ft):
Authorized Signature:
Production
Liner
Casing
Intermediate
Surface
Uncemented Screen Liner
Stg 1 L - 955 ft3 / T - 458 ft3
Effect. Depth TVD (ft):
Conductor/Structural
Length
1767
Total Depth MD (ft): Total Depth TVD (ft):
Cement Quantity, c.f. or sacks
Cement Volume MDSize
Plugs (measured):
(including stage data)
Driven
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005 REVISED Change TD over 500'
Stg 2 L - 1937 ft3 / T - 314 ft3
1359
1775' FSL, 1205' FWL, Sec 33, T13N, R10E, UM, AK
1724' FSL, 1848' FWL, Sec 21, T13N, R10E, UM, AK
LONS 88-004
3840
MPU I-21
Milne Point Field
Schrader Bluff Oil Pool
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
Hilcorp Alaska, LLC
2324' FSL, 3597' FEL, Sec 33, T13N, R10E, UM, AK ADL025906, ADL315848
022224484
1,775'
1/15/2021
Authorized Name: Monty Myers
Authorized Title: Drilling Manager
Joe Engel
jengel@hilcorp.com
777-8395
18. Casing Program: Top - Setting Depth - BottomSpecifications
Form 10-401 Revised 3/2020 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
By Samantha Carlisle at 8:11 pm, Jan 13, 2021
Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp Alaska, LLC, ou=Technical
Services - AK Drilling,
email=mmyers@hilcorp.com
Reason: I am approving this document
Date: 2021.01.13 16:54:00 -09'00'
Monty M
Myers
4008 16500 SFD 1/14/2021
1359
MGR14JAN2021
BOPE test to 3000 psi. Annular to 2500 psi.
Submit FIT data with 10-407
SFD 1/15/2021 DSR-1/14/2114JAN2021
1/19/21
06/11/2020
21209
282930
3231
I
J
J-05
J-07
J-06
J-09J-09A
J-08
J-08A J-10
J-11
J-12
J-13
G-15
I-08
I-06
J-21
J-17
J-20
J-20A
J-18
J-22
J-15
I-09
I-10
J-23
J-24
4L1
3
G-14
G-14L1
I-11
1L1
I-12
G-17
J-26
J-26L1
J-26L2
J-25
I-17
I-17L1
I-17L2
I-14
I-14L1
I-14L2
I-19
I-19L1
I-16
H-18
H-18L1
H-18L2
I-18
WSAK 25
I-03
J-01
J-01A
J-01AL1
J-03
I-07
J-19
J-19A
J-16
3L1
M-12
M-11
M-14
M-15
M-13
I-35
I-36
I-21
L-62
I-20
I-38
I-39
I-40
I-37
I-38PB2
HILCORP ALASKA LLC
MILNE POINT FIELD
AOR MAP
I-21 OBa Sand Injector (Proposed)
FEET
0 1,000 2,000
POSTED WELL DATA
Well Number
WELL SYMBOLS
Active Oil
Location
Shut In Oil
INJ Well (Water Flood)
P&A Oil
Abandoned Injector
Plug Back
Producer Location
Shut In INJ
WATER SOURCE
REMARKS
Well Sybols at top of Schrader Bluff OBa Sand. Wells
that did not reach as deep as the OBa have symbols at
TD.
Black dash circle = 1320' radius from predicted OBa
sand in heel and toe of proposed I-21 drill well
1-21 well plan is highlighted in red
By: R. Emerson 1/8/2021
January 14, 2021
PETRA 1/14/2021 2:22:35 PM
Area of Review MPI-21 (wp11)PTD API WELL STATUSTop of SBOBa (MD)Top of SBOBa (TVD)CBL Top ofCement(MD)CBL Top ofCement(TVD)Schrader OBastatusZonal Isolation194-114 50-029-22502-00-00 MPU J-11 Kuparuk WINJ 5416' 4125' 3900' 3166' ClosedCased and Cemented - 51bbls of cement pumped thrustage collar at 5,739' MD.194-118 50-029-22506-00-00 MPU J-12SB OA/OB WINJ Shutin4515' 4029' 3533' 3245' ClosedCased and Cemented - 30bbls of cement pumped thrustage collar at 4,861' MD.195-169 50-029-22615-00-00 MPU J-16 Kuparuk WINJ Shut in 6180' 4127' 2998' 2529' ClosedCased and Cemented - 38bbls of cement pumped thrustage collar at 4681' MD.190-095 50-029-22070-00-00 MPU J-01 Well Sidetracked 4257' 4080' 3000' 2837' ClosedCement Retainer set at3,670' MD, 18 bbls cementpumped below.199-111 50-029-22070-01-00 MPU J-01A OA Lateral Shut in N/A N/A N/A N/A Closed N/A201-021 50-029-22070-60-00 MPU J-01AL1 OBa lateral Shut in 5155' 4105' N/A N/A ClosedCement top @2932'(Suspended)194-095 50-029-22493-00-00 MPU J-06 Kuparuk Prod 4526' 4089' 3640' 3435' ClosedCased and Cemented - ~31bbls of cement pumped thrustage collar at 5,013' MD.194-106 50-029-22497-00-00 MPU J-08 P&Ad Sidetracked N/A N/A N/A N/A N/A Not open lateral in OA199-17750-029-22497-01-00MPU J-08A SB OB Prod Shut in 5788' 4110' 4714' 3808' Open Open to Injection Support204-073 50-029-23207-00-00 MPU J-25 NB Lateral N/A N/A N/A N/A Not Open Lateral in above NB Sand195-151 50-029-22602-00-00 MPU I-07 Shut in SB Producer3994' 3970' 3100' 2977' OpenOpen to Injection Support204-135 50-029-23218-00-00 MPU I-19 OBa lateral P&Ad7758' 4091' 3334' 2680' P&Ad35 bbls of 15.8 ppg cmtpumped in lateral from9,679' - 7,380' MD.204-136 50-029-23218-60-00 MPU I-19L1 N/A OA Lateral P&A'd N/A N/A N/A N/A N/A77 bbls of 15.8 ppg cmtpumped in lateral from12,000' - 7,104' MD. TOCtagged at 7200' MD 4/15/20.220-034 50-029-23675-00-00 MPU I-35 NB WINJN/A N/A N/A N/A Not Open N/A
Area of Review MPI-21 (wp11)220-047 50-029-23677-00-00 MPU I-36 NB ProdN/A N/A N/A N/A Not Open N/A220-055 50-029-23682-00-00 MPU I-37 NB WINJN/A N/A N/A N/A Not Open N/ATBD TBD MPU I-28 OB WINJ (planned) N/A N/A N/A N/ANot Open N/A190-097 50-029-22072-00-00 MPU J-03 NB / OB Producer 5133' 4013' 2927' 2532'Not OpenCement top @4633'(Suspended)220-049 50-029-23679-00-00 MPU I-20 OBa Producer 4923' 3950' Surface SurfaceOpenNot Completed (OpShutdown)204-073 50-029-23207-70-00 MPU J-25PB1 Plugback4592' 4086' N/A N/AClosedPlugback - Sidetrack aboveOBa Sands and Cemented
21209
282930
3231
I
J
J-05
J-07
J-06
J-09J-09A
J-08
J-08A J-10
J-11
J-12
J-13
G-15
I-08
I-06
J-21
J-17
J-20
J-20A
J-18
J-22
J-15
I-09
I-10
J-23
J-24
4L1
3
G-14
G-14L1
I-11
1L1
I-12
G-17
J-26
J-26L1
J-26L2
J-25
I-17
I-17L1
I-17L2
I-14
I-14L1
I-14L2
I-19
I-19L1
I-16
H-18L1
H-18L2
I-18
WSAK 25
I-03
J-01
J-01A
J-01AL1
J-03
I-07
J-19
J-19A
J-16
3L1
M-12
M-11
M-14
M-15
M-13
I-35
I-36
I-21
L-62
I-20
I-38
I-39
I-40
I-37
I-38PB2
I-28
HILCORP ALASKA LLC
MILNE POINT FIELD
AOR MAP
I-21 OBa Sand Injector (Proposed)
FEET
01,0002,000
POSTED WELL DATA
Well Number
WELL SYMBOLS
Active Oil
Location
Shut In Oil
INJ Well (Water Flood)
P&A Oil
Abandoned Injector
Plug Back
Injector Location
Producer Location
Shut In INJ
WATER SOURCE
REMARKSWell Sybols at top of Schrader Bluff OBa Sand. Wells
that did not reach as deep as the OBa have symbols atTD.Black dash circle = 1320' radius from predicted OBasand in heel and toe of proposed I-21 drill well
1-21 well plan is highlighted in red
By: R. Emerson 1/8/2021
January 10, 2021
PETRA 1/10/2021 4:47:59 PM
Oba isolatedOba Open
Nb Winj
Oba Open
Oba isolated
Nb Prod
Oba isolation
planned
Ob Planned
Nb Winj
Oba P&A'd
Oba isolated
Oba isolated
Oba Not Reached
Oba Not Reached
OBa Op
Oba Not Reached
Oba Open
Oba Not Reached
Oba Isolated
Superseded 1/14/2021
SFD
Area of Review MPI-21 (wp11)PTD API WELL STATUSTop of SBOBa (MD)Top of SBOBa (TVD)CBL Top ofCement(MD)CBL Top ofCement(TVD)Schrader OBastatusZonal Isolation194-114 50-029-22502-00-00 MPU J-11 Kuparuk WINJ 5416' 4125' 3900' 3166' ClosedCased and Cemented - 51bbls of cement pumped thrustage collar at 5,739' MD.194-118 50-029-22506-00-00 MPU J-12SB OA/OB WINJ Shutin4515' 4029' 3533' 3245' ClosedCased and Cemented - 30bbls of cement pumped thrustage collar at 4,861' MD.195-169 50-029-22615-00-00 MPU J-16 Kuparuk WINJ Shut in 6180' 4127' 2998' 2529' ClosedCased and Cemented - 38bbls of cement pumped thrustage collar at 4681' MD.190-095 50-029-22070-00-00 MPU J-01 Well Sidetracked 4257' 4080' 3000' 2837' ClosedCement Retainer set at3,670' MD, 18 bbls cementpumped below.199-111 50-029-22070-01-00 MPU J-01A OA Lateral Shut in N/A N/A N/A N/A Closed N/A201-021 50-029-22070-60-00 MPU J-01AL1 OBa lateral Shut in 5155' 4105' N/A N/A OpenSundry currently beingprepared to fully abandonreservoir. Plan is to conductthis work prior to injecting into MPU I-21194-095 50-029-22493-00-00 MPU J-06 Kuparuk Prod 4526' 4089' 3640' 3435' ClosedCased and Cemented - ~31bbls of cement pumped thrustage collar at 5,013' MD.194-106 50-029-22497-00-00 MPU J-08 P&Ad Sidetracked N/A N/A N/A N/A N/A Not open lateral in OA199-17750-029-22497-01-00MPU J-08A SB OB Prod Shut in 5788' 4110' 4714' 3808' Open Open to Injection Support204-073 50-029-23207-00-00 MPU J-25 NB Lateral N/A N/A N/A N/A Not Open Lateral in above NB Sand195-151 50-029-22602-00-00 MPU I-07 Shut in SB Producer3994' 3970' 3100' 2977' OpenOpen to Injection Support204-135 50-029-23218-00-00 MPU I-19 OBa lateral P&Ad7758' 4091' 3334' 2680' P&Ad35 bbls of 15.8 ppg cmtpumped in lateral from9,679' - 7,380' MD.Shut in Open to Injection SupportOpen to Injection Supportthis work prior to injecting inPlan is to conductto MPU I-21Superseded 1/15/2021 SFD
Area of Review MPI-21 (wp11)204-136 50-029-23218-60-00 MPU I-19L1 N/A OA Lateral P&A'd N/A N/A N/A N/A N/A77 bbls of 15.8 ppg cmtpumped in lateral from12,000' - 7,104' MD. TOCtagged at 7200' MD 4/15/20.220-034 50-029-23675-00-00 MPU I-35 NB WINJN/A N/A N/A N/A Not Open N/A220-04750-029-23677-00-00MPU I-36 NB ProdN/A N/A N/A N/A Not Open N/A220-055 50-029-23682-00-00 MPU I-37 NB WINJN/A N/A N/A N/A Not Open N/ATBD TBD MPU I-28 OB WINJ (planned) N/A N/A N/A N/ANot Open N/ASuperseded 1/15/2021
Milne Point Unit
(MPU) I-21
Drilling Program
Version 3
1/13/2021
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 ................................................................................................ 6
8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 8
9.0 RU and Preparatory Work ...................................................................................................... 10
10.0 NU 13-5/8” 5M Diverter Configuration .................................................................................. 11
11.0 Drill 12-1/4” Hole Section ........................................................................................................ 13
12.0 Run 9-5/8” Surface Casing ...................................................................................................... 17
13.0 Cement 9-5/8” Surface Casing ................................................................................................. 23
14.0 BOP NU and Test..................................................................................................................... 28
15.0 Drill 8-1/2” Hole Section .......................................................................................................... 29
16.0 Run 4-1/2” Injection Liner (Lower Completion) .................................................................... 34
17.0 Run 3-1/2” Tubing (Upper Completion) ................................................................................. 38
18.0 Innovation Rig Diverter Schematic ......................................................................................... 40
19.0 Innovation Rig BOP Schematic ............................................................................................... 41
20.0 Wellhead Schematic ................................................................................................................. 42
21.0 Days Vs Depth .......................................................................................................................... 43
22.0 Formation Tops & Information............................................................................................... 44
23.0 Anticipated Drilling Hazards .................................................................................................. 46
24.0 Innovation Rig Layout ............................................................................................................. 49
25.0 FIT Procedure .......................................................................................................................... 50
26.0 Innovation Rig Choke Manifold Schematic ............................................................................ 51
27.0 Casing Design ........................................................................................................................... 52
28.0 8-1/2” Hole Section MASP ....................................................................................................... 53
29.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 54
30.0 Surface Plat (As Built) (NAD 27) ............................................................................................. 55
Page 2 Version 2
Milne Point Unit
I-21 SB Injector
Drilling Procedure
1.0 Well Summary
Well MPU I-21
Pad Milne Point “I” Pad
Planned Completion Type 3-1/2” Injection Tubing
Target Reservoir(s) Schrader Bluff Ob Sand
Planned Well TD, MD / TVD 16,500’ MD / 4,228’ TVD
PBTD, MD / TVD 16,490’ MD / 4,228’ TVD
Surface Location (Governmental) 2324' FSL, 3597' FEL, Sec 33, T13N, R10E, UM, AK
Surface Location (NAD 27) X= 551,774 Y=6,009,440
Top of Productive Horizon
(Governmental)1775' FSL, 1205' FWL, Sec 33, T13N, R10E, UM, AK
TPH Location (NAD 27) X= 551,300 Y=6,008,887
BHL (Governmental) 1724' FNL, 1848' FWL, Sec 21, T13N, R10E, UM, AK
BHL (NAD 27) X= 551,826 Y=6,021,231
AFE Number 2011857
AFE Drilling Days 17 days
AFE Completion Days 3 days
AFE Drilling Amount $3,628,670
AFE Completion Amount $1,515,889
AFE Facility Amount $292,800
Maximum Anticipated Pressure
(Surface) 1,359 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 1,767 psig
Work String 5”, 19.5#, S-135, DS-50 & NC 50
KB Elevation above MSL: 26.5 ft + 33.4 ft = 59.9 ft
GL Elevation above MSL: 33.4 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
Page 3 Version 2
Milne Point Unit
I-21 SB Injector
Drilling Procedure
2.0 Management of Change Information
by the AOGCC
SFD 1/14/20221
Page 4 Version 2
Milne Point Unit
I-21 SB Injector
Drilling Procedure
3.0 Tubular Program:
Hole
Section
OD (in)ID (in)Drift
(in)
Conn OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 20” 19.250”---X-52Weld
12-1/4”9-5/8” 8.835”8.679”10.625”40 L-80 TXP 5,750 3,090 916
9-5/8” 8.681”8.525”10.625”47 L-80 TXP 6,870 4,750 1,086
8-1/2” 4-1/2” 3.960”3.795”4.714”13.5 L-80 H625 9,020 8,540 279
Tubing 3-1/2” 2.992”2.897”4.500”9.3 L-80
TXP-SR 9,289 7,399 163
4.0 Drill Pipe Information:
Hole
Section
OD
(in)
ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn M/U
(Min)
M/U
(Max)
Tension
(k-lbs)
Surface &
Production
5”4.276” 3.25” 6.625” 19.5 S-135 GPDS50 36,100 43,100 560klb
5”4.276”3.25” 6.625”19.5 S-135 NC50 31,032 34,136 560klb
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
Page 5 Version 2
Milne Point Unit
I-21 SB Injector
Drilling Procedure
5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on WellEz.
x Report covers operations from 6am to 6am
x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left
of the data entry area – this will not save the data entered, and will navigate to another data entry.
x Ensure time entry adds up to 24 hours total.
x Try to capture any out of scope work as NPT. This helps later on when we pull end of well
reports.
x Enter the MD and TVD depths EVERY DAY whether you are making hole or not.
5.2 Afternoon Updates
x Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers@hilcorp,
nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com
5.3 Intranet Home Page Morning Update
x Submit a short operations update each morning by 7am on the company intranet homepage. On
weekend and holidays, ensure to have this update in before 5am.
5.4 EHS Incident Reporting
x Health and Safety: Notify EHS field coordinator.
x Environmental: Drilling Environmental Coordinator
x Notify Drilling Manager & Drilling Engineer on all incidents
x Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
x Send final “As-Run” Casing tally to mmyers@hilcorp,com nathan.sperry@hilcorp.com and
joseph.lastufka@hilcorp.com
5.6 Casing and Cement report
x Send casing and cement report for each string of casing to mmyers@hilcorp.com
nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com
5.7 Hilcorp Milne Point Contact List:
Title Name Work Phone Cell Phone Email
Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmyers@hilcorp.com
Drilling Engineer Joe Engel 907.777.8395 805.235.6265 jengel@hilcorp.com
Drilling Engineer Nate Sperry 907.777.8450 907.301.8996 nathan.sperry@hilcorp.com
Completion Engineer Ian Toomey 907.777.8434 907.903.3987 itoomey@hilcorp.com
Geologist Rebecca Emerson 907.777.8491 907.590.0648 Rebecca.emerson@hilcorp.com
Reservoir Engineer Reid Edwards 907.777.8421 907.250.5081 reedwards@hilcorp.com
Drilling Env. Coordinator Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com
EHS Manager Carl Jones 907.777.8327 907.382.4336 cajones@hilcorp.com
Drilling Tech Joe Lastufka 907.777.8400 907.227.8496 Joseph.Lastufka@hilcorp.com
Page 6 Version 2
Milne Point Unit
I-21 SB Injector
Drilling Procedure
6.0 Planned Wellbore Schematic
Page 7 Version 2
Milne Point Unit
I-21 SB Injector
Drilling Procedure
7.0 Drilling / Completion Summary
MPU I-21 is a grassroots injector planned to be drilled in the Schrader Bluff Ob sand. I-21 is part of a multi
well program targeting the Schrader Bluff sand on I-Pad
The directional plan is a catenary well path build, 12-1/4” hole with 9-5/8” surface casing set into the top of
the Schrader Bluff Ob sand. An 8-1/2” lateral section will then be drilled. A 4-1/2” screened injection liner
will be run in the open hole section.
The Innovation Rig will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately January 15th 2021, pending rig schedule.
Surface casing will be run to 5,845 MD / 4,015’ 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 Innovation to well site
2. NU & Test 13-5/8” 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. ND diverter, NU & test 13-5/8” x 5M BOP.
5. Drill 8-1/2” lateral to well TD. Run 4-1/2” injection liner.
6. Run 3-1/2” tubing.
7. ND BOP, NU Tree, RDMO.
Reservoir Evaluation Plan:
1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res
2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering)
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8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations,
specific regulations are listed below. If additional clarity or guidance is required on how to comply with
a specific regulation, do not hesitate to contact the Anchorage Drilling Team.
x BOPs shall be tested at (2) week intervals during the drilling and completion of MPU I-21. Ensure
to provide AOGCC 24 hrs notice prior to testing BOPs.
x The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment
will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial
and subsequent tests).Confirm that these test pressures match those specified on the APD.
x If the BOP is used to shut in on the well in a well control situation or control fluid flow from the
well bore, AOGCC is to be notified and we must test all BOP components utilized for well control
prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP
test.
x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program
and drilling fluid system”.
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”.
o Ensure the diverter vent line is at least 75’ away from potential ignition sources
x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
x Notify the AOGCC at least 24 hours in advance of the IA pressure test after running the completion
as per 20 AAC 25.412 (e). Record pressure test on 10-426 form and email to wrivard@hilcorp.com
for submission to AOGCC.
x Hilcorp Alaska proposes to demonstrate isolation of the injected fluid as required under 20 AAC
25.412 (d) through cement job operational reports of a complete two stage cement job on the 9-5/8”
surface casing. Planned surface cement volumes and cement returns to surface seen during both
stages will indicate placement of cement in the entire surface casing annulus. A successful FIT after
surface casing drill out will demonstrate isolation of injection fluid.
AOGCC Regulation Variance Requests:
Hilcorp Alaska LLC does not request any variances at this time.
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Summary of BOP Equipment and Test Requirements
Hole Section Equipment Test Pressure (psi)
12 1/4”x 13-5/8” 5M CTI Annular BOP w/ 16” diverter line Function Test Only
8-1/2”
x 13-5/8” x 5M Control Technology Inc Annular BOP
x 13-5/8” x 5M Control Technology Inc Double Gate
o Blind ram in btm cavity
x Mud cross w/ 3” x 5M side outlets
x 13-5/8” x 5M Control Technology Single ram
x 3-1/8” x 5M Choke Line
x 3-1/8” x 5M Kill line
x 3-1/8” x 5M Choke manifold
x Standpipe, floor valves, etc
Initial Test: 250/3,000
Subsequent Tests:
250/3,000
Primary closing unit: Control Technology Inc. (CTI), 6 station, 3,000 psi, 220 gallon accumulator unit.
Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an electric
triplex pump on a different electrical circuit and emergency pressure is provided by bottled nitrogen.
The remote closing operator panels are located in the doghouse and on accumulator unit.
Required AOGCC Notifications:
x Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
x 24 hours notice prior to spud.
x 24 hours notice prior to testing BOPs.
x 24 hours notice prior to casing running & cement operations.
x Any other notifications required in APD.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov
Guy Schwartz / Petroleum Engineer / (O): 907-793-1226 / (C): 907-301-4533 / Email:guy.schwartz@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov
Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov
Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov
Test/Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
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9.0 RU and Preparatory Work
9.1 I-21 will utilize a newly set 20” conductor on I-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 RU.
9.6 Rig mat footprint of the rig.
9.7 MIRU Innovation Rig. Ensure rig is centered over conductor to prevent any wear to BOPE or
wellhead.
9.8 Mud loggers WILL NOT be used on either hole section.
9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80qF).
9.10 Set test plug in wellhead prior to NU diverter to ensure nothing can fall into the wellbore if it is
accidentally dropped.
9.11 Ensure 5” liners in mud pumps.
x White Star Quattro 1300 HP mud pumps are rated at 4,097 psi, 381 gpm @ 140 spm @
96.5% volumetric efficiency.
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10.0 NU 13-5/8” 5M Diverter Configuration
10.1 NU 13-5/8” CTI BOP stack in diverter configuration (Diverter Schematic attached to program).
x NU 20” x 13-5/8” DSA
x NU 13 5/8”, 5M diverter “T”.
x NU Knife gate & 16” diverter line.
x Ensure diverter RU complies with AOGCC reg 20.AAC.25.035(C).
x Diverter line must be 75 ft from nearest ignition source
x Place drip berm at the end of diverter line.
x Utilized extensions if needed.
10.2 Notify AOGCC. Function test diverter.
x Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens
prior to annular closure.
x Ensure that the annular closes in less than 30 seconds (API Standard 64 3rd edition March 2018
section 12.6.2 for packing element ID less than or equal to 20”)
10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the
vent line tip. “Warning Zone” must include:
x A prohibition on vehicle parking
x A prohibition on ignition sources or running equipment
x A prohibition on staged equipment or materials
x Restriction of traffic to essential foot or vehicle traffic only.
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10.4 Rig & Diverter Orientation:
*Orientation may differ on location
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11.0 Drill 12-1/4” Hole Section
11.1 Consider PU 12-1/4” short collar directional only BHA:
x This is for surface A/C and accurate gyro surveys closer to bit
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before MU. Visually verify no debris inside components
that cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x GWD will be used. Be sure to run a UBHO sub for backup wireline gyro.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
x Drill string will be 5”, 19.5#, S-135 DS50 & NC50.
x Run a solid float in the surface hole section.
11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor.
11.3 Drill 12-1/4” hole section to section to the end of build and/or until clean MWD surveys are
seen.
x Monitor the area around the conductor for any signs of broaching. If broaching is observed,
Stop drilling (or circulating) immediately notify Drilling Engineer.
x Efforts should be made to minimize dog legs in the surface hole.
x Hold a safety meeting with rig crews to discuss:
x Conductor broaching ops and mitigation procedures.
x Well control procedures and rig evacuation
x Flow rates, hole cleaning, mud cooling, etc.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Keep mud as cool as possible to keep from washing out permafrost.
x Pump at 400-600 GPM. Monitor shakers closely to ensure shaker screens and return lines
can handle the flow rate.
x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoffs, increase in pump pressure or changes in hookload are seen
x Slow in/out of slips and while tripping to keep swab and surge pressures low
x Ensure shakers are functioning properly. Check for holes in screens on connections.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea
gravel, clay balling or packing off.
x Adjust MW and viscosity as necessary to maintain hole stability
x GyroData Quest GWD will be used to drill this section. Take MWD surveys every stand
drilled.
11.4 CBU and BROOH
x POOH on elevators if possible
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11.5 Make up remainder of full directional and LWD BHA
11.6 RIH
11.7 Drill 12-1/4” hole section to section TD, in the Schrader Ob sand. Confirm this setting depth
with the Geologist and Drilling Engineer while drilling the well.
x Monitor the area around the conductor for any signs of broaching. If broaching is observed,
Stop drilling (or circulating) immediately notify Drilling Engineer.
x Efforts should be made to minimize dog legs in the surface hole.
x Hold a safety meeting with rig crews to discuss:
x Conductor broaching ops and mitigation procedures.
x Well control procedures and rig evacuation
x Flow rates, hole cleaning, mud cooling, etc.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Keep mud as cool as possible to keep from washing out permafrost.
x Pump at 400-600 GPM. Monitor shakers closely to ensure shaker screens and return lines
can handle the flow rate.
x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoffs, increase in pump pressure or changes in hookload are seen
x Slow in/out of slips and while tripping to keep swab and surge pressures low
x Ensure shakers are functioning properly. Check for holes in screens on connections.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea
gravel, clay balling or packing off.
x Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2
minimum at TD (pending MW increase due to hydrates).
x Perform wireline gyros until clean MWD surveys are seen. Take MWD surveys every stand
drilled.
x Gas hydrates may be present on I-Pad. Historically encountered hydrates are typically
around 2,100-2,400’ TVD (just below permafrost). Be prepared for hydrates:
x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD
x Monitor returns for hydrates, checking pressurized & non-pressurized scales
x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by
washing out additional permafrost. Attempt to control drill (150 FPH MAX) through the
zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be
reduced to prevent mud from belching over the bell nipple. Consider adding Lecithin to
allow the gas to break out.
x Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the
well. MW will not control gas hydrates, but will affect how gas breaks out at surface
x A/C:
x There are not wells with a clearance factor < 1.0
11.8 12-1/4” hole mud program summary:
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x Density: Weighting material to be used for the hole section will be barite. Additional
barite or spike fluid will be on location to weight up the active system (1) ppg above
highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and
TD with 9.2+ ppg.
Depth Interval MW (ppg)
Surface – Base Permafrost 8.9+
Base Permafrost - TD 9.2+ (For Hydrates if need based on offset wells)
MW can be cut once ~500’ below hydrate zone
x PVT System: MD Totco PVT will be used throughout the drilling and completion phase.
Remote monitoring stations will be available at the driller’s console, Co Man office,
Toolpusher office, and mud loggers office.
x Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system
with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at
all times while drilling. Be prepared to increase the YP if hole cleaning becomes an
issue.
x Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background
LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the
system while drilling the surface interval to prevent losses and strengthen the wellbore.
x Wellbore and mud stability:Additions of CON DET PRE-MIX/DRIL N SLIDE are
recommended to reduce the incidence of bit balling and shaker blinding when penetrating
the high-clay content sections of the Sagavanirktok and the heavy oil sections of the
UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of
ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action.
x Casing Running:Reduce system YP with DESCO as required for running casing as
allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and
swab pressures. Reduce the system rheology once the casing is landed to a YP < 20
(check with the cementers to see what YP value they have targeted).
System Type:8.8 – 9.8 ppg Pre-Hydrated Aquagel/freshwater spud mud
Properties:
Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp
Surface 8.8 – 9.8 75-175 20 - 40 25-45 <10 8.5 – 9.0 70 F
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System Formulation:Gel + FW spud mud
Product Concentration
Fresh Water
soda Ash
AQUAGEL
caustic soda
BARAZAN D+
BAROID 41
PAC-L /DEXTRID LT
ALDACIDE G
0.905 bbl
0.5 ppb
15 - 20 ppb
0.1 ppb (8.5 – 9.0 pH)
as needed
as required for 8.8 – 9.2 ppg
if required for <10 FL
0.1 ppb
11.9 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity.
x This is to prevent washing out directional work to land the well
11.10 RIH to bottom, proceed to BROOH to HWDP
x Pump at full drill rate (400-600 GPM), and maximize rotation.
x Pull slowly, 5 – 10 FPM.
x Monitor well for any signs of packing off or losses.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay
balling.
x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until
parameters are restored.
11.11 TOOH and LD BHA
11.12 No open hole logging program planned.
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12.0 Run 9-5/8” Surface Casing
12.1 RU and pull wearbushing.
12.2 RU Weatherford 9-5/8” casing running equipment (CRT & Tongs)
x Ensure 9-5/8” TXP x DS50 XO on rig floor and MU to FOSV.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x RU of CRT if hole conditions require.
x RU a fill up tool to fill casing while running if the CRT is not used.
x Ensure all casing has been drifted to 8.750” on the location prior to running.
x Top 2000’ of casing 47# drift 8.525”
x Be sure to count the total # of joints on the location before running.
x Keep hole covered while RU casing tools.
x Record OD’s, ID’s, lengths and SN’s of all components with vendor & model info.
12.3 PU shoe joint, visually verify no debris inside joint.
12.4 Continue MU & 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 with stop rings
1 joint –9-5/8” TXP, 1 Centralizer mid joint with stop ring
9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’
1 joint –9-5/8” TXP, 1 Centralizer mid joint with stop ring
9-5/8” HES Baffle Adaptor
x Ensure bypass baffle is correctly installed on top of float collar.
x Ensure proper operation of float equipment while picking up.
x Ensure to record SN’s of all float equipment and stage tool components.
This end up.
Bypass Baffle
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12.5 Float equipment and Stage tool equipment drawings:
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12.6 Continue running 9-5/8” surface casing
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization: Verify depth of lowest Ugnu water sand for isolation with Geologist
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
x Any packing off while running casing should be treated as a major problem. It is preferable
to POOH with casing and condition hole than to risk not getting cement returns to surface.
12.7 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below
the permafrost (~ 2,500’ MD).
x Install centralizers over couplings on 5 joints below and 10 joints above stage tool.
x Do not place tongs on ES cementer, this can cause damaged to the tool.
x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi.
9-5/8”, 40#, L-80, TXP MU Torques:
Casing OD Minimum Optimum Maximum
9-5/8”18,860 ft-lbs 20,960 ft-lbs 23,060 ft-lbs
9-5/8” 47# L-80 TXP MUT:
Casing OD Minimum Optimum Maximum
9-5/8” 21,440 ft-lbs 2,3820 ft-lbs 26,200 ft-lbs
Depth Interval Centralization
Shoe – 1000’ Above Shoe 1/joints
1000’ above Shoe –2000’ above Shoe (Top of Ugnu)1/ 2 joints
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12.8 Continue running 9-5/8” surface casing
x 9-5/8” 47# from 2000’ to surface
x Centralizers: 1 centralizer every 3rd joint to 200’ from surface
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only with paint brush.
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 PU landing joint and MU 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 MU water are available to achieve this. If possible
reciprocate casing string while conditioning mud.
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13.0 Cement 9-5/8” Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
x Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks.
x Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
x Review test reports and ensure pump times are acceptable.
x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
13.2 Document efficiency of all possible displacement pumps prior to cement job.
13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
13.5 Fill surface cement lines with water and pressure test.
13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below
calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached.
13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead &
tail, TOC brought to stage tool.
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Estimated 1st Stage Total Cement Volume:
Section Calculation Vol (bbl) Vol (ft3)
12-1/4" OH x 9-5/8"
Casing (4,845' - 2,500') x .0558 bpf x 1.3 = 170.1 955
Total Lead 170.1 955
12-1/4" OH x 9-5/8"
Casing (5,845' - 4,845') x .0558 bpf x 1.3 = 72.5 407
9-5/8" Shoe Track 120' x .0758 bpf = 9.1 51.09
Total Tail 81.6 458LeadTail
Cement Slurry Design (1st Stage Cement Job):
13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue
with the cement job.
13.9 After pumping cement, drop top plug (shutoff plug) and displace cement with spud mud out of
mud pits, spotting water across the HEC stage cementer.
x Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
13.10 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very
accurate using 0.0625 bps (5” liners) for the Quattro pump output. To operate the stage tool
hydraulically, the plug must be bumped.
13.11 Displacement calculation:
5,480’ x .0758 bpf = 415.38 bbls
80 bbls of tuned spacer to be left behind stage tool,confirm fluid is compatible with cement
behind stage tool
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.
Lead Slurry Tail Slurry
Density 12.0 lb/gal 15.8 lb/gal
Yield 2.35 ft3/sk 1.16 ft3/sk
Mixed
Water 13.92 gal/sk 4.98 gal/sk
((5845 - 120- 2000) * 0.0758) + (2000 * 0.0732) = 428.77 bbl
394 sx
407 sx
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13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over
displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling
Engineer.
13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening
plug is available if needed. This is the back-up option to open the stage tool if the plugs are not
bumped.
13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened.
13.16 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher pressure
may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns
to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation
for the 2nd stage of the cement job.
13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker
bypass line to the cuttings tank. Have black water available and vac trucks ready to assist.
Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact
with the cement.
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Second Stage Surface Cement Job:
13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive
strength. (If ESIPC is used and packer element inflated, CBU x1 minimum before pumping
second stage). Hold pre-job safety meeting.
x Minimize pump shutdowns while circulating through stage tool and keep shutdowns
to 30 minutes or less. Longer shutdowns have lead to the stage tool packing off and
losing circulation
x If circulation is lost, slowly stage up pumps to 2000psi and gently work/stretch pipe to
regain circulation. Contact drilling engineer if unable to gain circulation at 2000 psi
13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing
head.
13.20 Fill surface lines with water and pressure test.
13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.22 Mix and pump cmt per below recipe for the 2
nd stage.
13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail).
Job will consist of lead & tail, TOC brought to surface. However cement will continue to be
pumped until clean spacer is observed at surface.
Estimated 2nd Stage Total Cement Volume:
Section Calculation Vol (bbl) Vol (ft3)
20" Conductor x 9-5/8" Casing (110') x .26 bpf x 1 = 28.6 161
12-1/4" OH x 9-5/8" Casing (2,000' - 110') x .0558 bpf x 3 = 316.4 1776.3
Total Lead 345 1937
12-1/4" OH x 9-5/8" Casing (2,500' - 2,000') x .0558 bpf x 2 = 55.8 314
Total Tail 55.8 314LeadTail
Cement Slurry Design (2nd stage cement job):
13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail.
Lead Slurry Tail Slurry
System Permafrost L
Density 10.7 lb/gal 15.8 lb/gal
Yield 4.41 ft3/sk 1.17 ft3/sk
Mixed
Water 22.02 gal/sk 5.08 gal/sk
440 sx
268 sx
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13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out
of mud pits.
13.26 Displacement calculation:
2,500’ x .0758 bpf = 190 bbls mud
13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side
outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out
fluid from cellar. Have black water available to retard setting of cement.
13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should
circulate approximately 100 - 150 bbls of cement slurry to surface.
13.29 Land closing plug on stage collar and pressure up to 1,000 – 1,500 psi to ensure stage tool closes.
Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool
has closed. Slips will be set as per plan to allow full annulus for returns during surface cement
job. Set slips
13.30 Make initial cut on 9-5/8” final joint. L/D cut joint. Make final cut on 9-5/8”. Dress off stump.
Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule.
Ensure to report the following on wellez:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight
& type of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement , actual displacement volume, whether plug bumped &
bump pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final
circulating pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
x Note calculated top of cement
x Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to nathan.sperry@hilcorp.com and
joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the
AOGCC.
(2000 * .0732) + (500 .0758) = 184.3 bbls
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14.0 BOP NU and Test
14.1 ND the diverter T, 16” knife gate, 16” diverter line & NU 11” x 13-5/8” 5M casing spool.
14.2 NU 13-5/8” x 5M CTI BOP as follows:
x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13-
5/8” x 5M mud cross / 13-5/8” x 5M single gate
x Double gate ram should be dressed with 2-7/8” x 5-1/2” VBRs in top cavity,blind ram in
bottom cavity.
x Single ram should be dressed with 2-7/8” x 5-1/2” VBRs or 5” Solid Body Rams
x NU bell nipple, install flowline.
x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to
mud cross).
x Install (1) manual valve & HCR valve on choke side of mud cross. (manual valve closest to
mud cross)
14.3 Run 5” BOP test plug (if not installed previously).
x Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min.
x Confirm test pressures with PTD
x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure
is trapped underneath test plug
x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech
14.4 RD BOP test equipment
14.5 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.6 Mix 8.9 ppg Baradrill-N fluid for production hole.
14.7 Set wearbushing in wellhead.
14.8 Rack back as much 5” DP in derrick as possible to be used while drilling the hole section.
14.9 Ensure 5” liners in mud pumps.
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15.0 Drill 8-1/2” Hole Section
15.1 MU 8-1/2” Cleanout BHA (Milltooth Bit & 1.22° PDM)
15.2 TIH with 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on morning report. Drill
out stage tool.
15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report.
15.4 RU and test casing to 2,500 psi for 30 minutes charted. Ensure to record volume / pressure and
plot on FIT graph. AOGCC reg is 50% of burst = 6870 / 2 = ~3500 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. Circulate at least 1 high vis sweep surface to surface at max
rate.
15.7 Conduct FIT to 12 ppg EMW. Chart Test. Ensure test is recorded on same chart as FIT.
Document incremental volume pumped (and subsequent pressure) and volume returned.
15.8 POOH & LD Cleanout BHA
15.9 PU 8-1/2” directional BHA.
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before MU. Visually verify no debris inside components that
cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Ensure MWD is RU and operational.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
x Drill string will be 5”, 19.5#, S-135, DS50 & NC50.
x Run a ported float in the production hole section.
15.10 8-1/2” hole section mud program summary:
x Density: Weighting material to be used for the hole section will be calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg
above highest anticipated MW.
Digital casing test and FIT data to AOGCC. Include in 10-407 completion report.
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x Solids Concentration: It is imperative that the solids concentration be kept low while
drilling the production hole section. Keep the shaker screen size optimized and fluid
running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure
we are running the finest screens possible.
x Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests
excessive viscosifier concentrations can decrease return permeability. Do not pump high
vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for
sufficient hole cleaning
x Run the centrifuge continuously while drilling the production hole, this will help with
solids removal.
x Dump and dilute as necessary to keep drilled solids to an absolute minimum.
x MD Totco PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, &
Toolpusher office.
System Type:8.9 – 9.5 ppg Baradrill-N drilling fluid
Properties:
Section Density Plastic Viscosity Yield Point Total Solids MBT HPHT
Production 8.9-9.5 15-25 20-25 <10% <7 <11.0
System Formulation:Baradrill-N
Product Concentration
Water
KCL
KOH
N-VIS
DEXTRID LT
BARACARB 5
BARACARB 25
BARACARB 50
BARACOR 700
BARASCAV D
X-CIDE 207
0.955 bbl
11 ppb
0.1 ppb
1.0 – 1.5 ppb
5 ppb
4 ppb
4 ppb
2 ppb
1.0 ppb
0.5 ppb
0.015 ppb
15.11 TIH with 8-1/2” directional assembly to bottom
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15.12 Displace wellbore to 8.9 ppg Baradrill-N drilling fluid
15.13 Begin drilling 8-1/2” hole section, on-bottom staging technique:
x Tag bottom and begin drilling with 100 - 120 RPMs at bit. Allow WOB to stabilize at 5-8K.
x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations.
x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU
off bottom and restart on bottom staging technique. If stick slip continues, consider adding
0.5% lubes.
15.14 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer.
x Flow Rate: 350-550 GPM, target min. AV’s 200 FPM, 385 GPM
x RPM: 120+
x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly
wet to maximize solids removal efficiency. Check for holes in screens on every connection.
x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
x Monitor Torque and Drag with pumps on every 5 stands
x Monitor ECD, pump pressure & hookload trends for hole cleaning indication
x Surveys can be taken more frequently if deemed necessary.
x Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible and avoid stopping with the
BHA across the sand for any extended period of time.
x Use ADR to stay in section.
x Limit maximum instantaneous ROP to < 250 FPH. The sands will drill faster than this, but
when concretions are hit when drilling this fast, cutter damage can occur.
x Target ROP is as fast as we can clean the hole without having to backream connections
x Schrader Bluff Ob Concretions: 4-6% of lateral
x A/C, wells with < 1.0 clearance factor:
x I-19/L1/PB1/PB2 – A cemented and reservoir abandoned SB dual lateral. TOC at 6620’
MD on 4/17/2020. The only risk is damage to the bit.
x J-16 - is a long term shut in Kuparuk injector. We will control drill past and watch for
magnetic interference. The directional plan will be updated to increase separation with J-
16 to CF >1.0. An update will be sent out.
15.15 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons
learned and best practices. Ensure the DD is referencing their procedure.
x Patience is key! Getting kicked off too quickly might have been the cause of failed liner
runs on past wells.
x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so
we have a nice place to low side.
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x Attempt to lowside in a fast drilling interval where the wellbore is headed up.NOTE: In
Nb sand wells, it helps to pick a siltier section to help mitigate junction collapse.
x Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working
string back and forth. Trough for approximately 30 minutes.
x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the
openhole sidetrack is achieved.
15.16 At TD, CBU at least 4 times at 200 FPM AV (385+ GPM) and rotation (120+ RPM). Pump
tandem sweeps if needed
x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a
consistent stream, circulate more if necessary
x Ensure mud has necessary lube % for running liner
x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum
15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP
pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter
cake and calcium carbonate. Circulate the well clean. Losses during the cleanup of the wellbore
are a good indication that the mud filter cake is being removed, including an increase in the loss
rate.
15.18 Displace 1.5 OH + Liner volume with viscosified brine.
x Proposed brine blend (same as used on M-16, aiming for an 8 on the 6 rpm reading) -
KCl: 7.1bbp for 2%
NaCl: 60.9 ppg for 9.4 ppg
Lotorq: 1.5%
Lube 776: 1.5%
Soda Ash: as needed for 9.5 pH
Busan 1060: 0.42ppb
Flo-Vis Plus: 1.25 ppb
x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further
discussion needed prior to BROOH.
x Record SO, PU weights and rotating torque to compare to pre-brine values in report.
15.19 Monitor the returned fluids carefully while conditioning the mud. After 1 (or more if needed)
BU, perform production screen test (PST). The mud has been properly conditioned when the
mud will pass the production screen test (x3 350ml samples passing through the screen in the
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same amount of time which will indicate no plugging of the screen). Reference PST Test
Procedure
x 250 Coupons
x Circulate and condition mud as much as needed to pass the production screen test
x If not passing after first test, call Completion Engineer
15.20 BROOH with the drilling assembly to the 9-5/8” casing shoe
x Circulate at full drill rate (385 gpm max).
x Rotate at maximum rpm that can be sustained.
x Limit pulling speed to 5 – 10 min/std (slip to slip time, not including connections).
x When pulling across any OHST depths, turn pumps off and rotary off to minimize
disturbance. Trip back in hole past OHST depth to ensure liner will stay in correct
hole section, check with ABI compared to as drilled surveys
15.21 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while
BROOH.
15.22 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps.
15.23 Monitor well for flow. Increase mud weight if necessary
x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to
determine if well is breathing, treat all flow as an influx until proven otherwise
x If necessary, increase MW at shoe for any higher than expected pressure seen
x Ensure fluid coming out of hole has passed a PST at the possum belly
15.24 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball
drops.
Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any
additional logging runs conducted.
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16.0 Run 4-1/2” Injection Liner (Lower Completion)
16.1.Well control preparedness: In the event of an influx of formation fluids while running the 4-
1/2” liner with screen joints, the following well control response procedure will be followed:
x With screen joint across the BOP: PU & MU 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 MU and available prior to running the first joint of 4-1/2” liner.
x With 4-1/2” solid joint across BOP: Slack off and position the 4-1/2” solid joint to MU the
TIW valve. Shut in ram or annular on 4-1/2” solid joint. Close TIW valve.
16.2. Confirm VBR have been tested on 3-1/2” and 5” test joints to 250/3,000 psi.
16.3. RU 4-1/2” liner running equipment.
x Ensure 4-1/2” Hydril 625 x DS-50 crossover is on rig floor and M/U to FOSV.
x Ensure the liner has been drifted on the deck prior to running.
x Be sure to count the total # of joints on the deck before running.
x Keep hole covered while RU casing tools.
x Record OD’s, ID’s, lengths and SN’s of all components with vendor & model info.
16.4. Run 4-1/2” injection liner.
x Use API Modified or “Best O Life 2000 AG”thread compound. Dope pin end only with
paint brush. Wipe off excess. Thread compound can plug the screens.
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Use lift nubbins and stabbing guides for the liner run.
x Fill 4-1/2” liner with PST passed brine (to keep from plugging screens with solids)
x Install screen joints as per the Running Order (Estimate 8 evenly spaced, Operations
Engineer to provide confirmation of set depths).
x Do not place tongs or slips on screen joint body
x Screen joint placement ±40’
x The screen joint connection is 4-1/2”, 13.5#, L-80, Hydril 625.
x Remove protective packaging on swell packers just prior to picking up
x If liner length exceeds surface casing length, ensure centralizers are placed 1/joint for each
joint outside of the surface shoe. This is to mitigate difference sticking risk while running
inner string.
x Obtain PU and SO weights of the liner before entering open hole. Record rotating torque at
10 and 20 RPM
4-1/2”, 13.5#, L-80, Hydril 625 MU Torques
Casing OD Minimum Optimum Maximum
Operating Torque
Yield Torque
4-1/2”8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs 15,000 ft-lbs
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16.6. Ensure that the liner top packer is set ~150’ MD above the 9-5/8” shoe.
x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as
per 20 AAC 25.030(d)(6). Ensure hanger/packer will not be set in a 9-5/8” connection.
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16.7. Before picking up Baker SLZXP liner hanger/packer assembly, count the # of joints on the pipe
deck to make sure it coincides with the pipe tally.
16.8. MU Baker SLZXP liner hanger/packer to 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
minutes for mixture to set up.
16.9. Note weight of liner. Run liner in the hole one stand and pump through liner hanger to ensure a
clear flow path exists.
16.10. RIH with liner on all 5” HWDP no faster than 30 FPM – this is to prevent buckling the liner and
drill string. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow
down running speed if necessary.
16.11. The liner will prevent the DP from auto filling. Fill DP every 5 stands, more frequently if SOW
trend indicates.
16.12. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe
depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to
bottom.
16.13. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
16.14. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
16.15. Rig up to pump down the work string with the rig pumps.
16.16. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill
pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger.
16.17. Drop setting ball down the workstring and pump slowly (1-2 BPM). Slow pump before the ball
seats. Do not allow ball to slam into ball seat. Pressure up to 1,500 psi to shift the wellbore
isolation valve closed.
16.18. Continue pressuring up to 2,700 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 4,100 psi to neutralize and release
running tools.
16.19. Bleed DP pressure to 0 psi, Pick up to expose rotating dog sub and set down 50K without pulling
sleeve packoff. Contingency (if suspected not released from running tool) - Pick back up
without pulling sleeve packoff, begin rotating at 10-20 RPM and set down 50K again.
16.20. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted.
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16.21. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If
packer did not test, rotating dog sub can be used to set packer. If running tool cannot be
hydraulically released, apply LH torque to mechanically release the setting tool.
16.22. POOH laying down DP then rack back enough 5” DP for the liner top cleanout run. LD and
inspect the liner running tools.Once running tools are LD, swap to the Completion AFE.
16.23. Make up 3-1/2” wash tool and RIH on 5” DP to the liner top.
16.24. Flush liner top at max rate while displacing out well to clean brine.
16.25. POOH LD remaining 5” DP.
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17.0 Run 3-1/2” Tubing (Upper Completion)
17.1 Notify the AOGCC at least 24 hours in advance of the IA pressure test after running the
completion as per 20 AAC 25.412 (e). Record pressure test on 10-426 form and email to
wrivard@hilcorp.com for submission to AOGCC.
17.2 MU injection assembly and RIH to setting depth. TIH no faster than 90 FPM.
x Ensure wear bushing is pulled.
x Ensure 3-1/2” EUE 8rd x NC-50 crossover is on rig floor and MU to FOSV.
x Ensure all tubing has been drifted in the pipe shed prior to running.
x Be sure to count the total # of joints in the pipe shed before running.
x Keep hole covered while RU casing tools.
x Record OD’s, ID’s, lengths and SN’s of all components with vendor & model info.
x Monitor displacement from wellbore while RIH.
3-1/2” Upper Completion Running Order:
x 7.30” Baker Ported Bullet Nose seal (stung into the tie back receptacle, crossover to 3-1/2”,
9.3#, EUE 8rd)
x 3 joints (minimum, more as needed), 3-1/2”, 9.3#, EUE 8rd tubing
x 3-1/2” “XN” nipple at TBD (less than 70° hole angle)
x 1 joints, 3-1/2”, 9.3#, EUE 8rd tubing
x 3-1/2” Baker gauge mandrel
o Cross collar clamps: Every joint for first 10 joints, every other joint beyond this to
surface
x XX Joints, 3-1/2”, 9.3#, EUE 8rd tubing
x Space out pup(s), 3-1/2”, 9.3#, EUE 8rd tubing
x 1 joint, 3-1/2”, 9.3#, EUE 8rd tubing
x Tubing hanger with 3-1/2” EUE 8rd pin down
17.3 Locate and no-go out the seal assembly. Close annular and test to 500 psi to confirm seals
engaged.
17.4 Bleed pressure and open annular. Space out the completion (±2’ above No-Go). Place all space
out pups below the first full joint of the completion.
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17.5 MU the tubing hanger and landing joint.
17.6 RIH. Close annular and test to 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 corrosion inhibited brine.
17.8 Freeze protect the IA to ~2,000’ TVD (base on actual well deviation) with diesel.
17.9 Land hanger and RILDS.
17.10 PT the IA to 2,500 psi for 30 minutes charted.
i. Note this test must be witnessed by the AOGCC representative.
17.11 Set BPV, ensure new body seals are installed each time.
17.12 ND BOPE and install the plug off tool into the BPV.
17.13 NU the tubing head adapter and NU the tree.
17.14 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi.
17.15 Pull the plug off tool from the BPV.
17.16 Bullhead diesel down the tubing to ~2,000’ TVD (base on actual well deviation).
17.17 Install all tree gauges. Secure the tree and cellar. Release the rig.
17.18 RDMO the Innovation Rig.
17.19 Turn the well over to operations via handover form.
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18.0 Innovation Rig Diverter Schematic
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19.0 Innovation Rig BOP Schematic
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20.0 Wellhead Schematic
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21.0 Days Vs Depth
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22.0 Formation Tops & Information
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22.0 Formation Tops & Information
Superseded 1/15/2021
SFD
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Superseded 1/14/2021
SFD
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23.0 Anticipated Drilling Hazards
12-1/4” Hole Section:
Lost Circulation
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Gas Hydrates
Gas hyrates have been seen on I Pad on past wells (2002), but recent wells drilled on I pad (2019/2020)
have not seen hydrates. Remember that hydrate gas behave differently from a gas sand. Additional fluid
density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas
hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as
quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the
hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of
hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh
mud with both a pressurized and non-pressurized mud scale. The non-pressurized scale will reflect the
actual mud cut weight. Isolate/dump contaminated fluid to remove hydrates from the system.
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize
solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs
to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is
critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to
avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide
intervals. Do not out drill our ability to clean the hole.
Anti-Collison:
There are a number of wells in close proximity. Take directional surveys every stand, take additional
surveys if necessary. Continuously monitor proximity to offset wellbores and record any close
approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in
adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well.
Well Specific A/C:
x There are no wells with a clearance factor of <1.0
Wellbore stability (Permafrost, running sands and gravel, conductor broaching):
Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of
time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH
speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and
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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.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
No H2S events have been documented
on drill wells on this pad.
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8-1/2” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor
ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe
moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation
after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300
gpm
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
There is at least (1) fault that will be crossed while drilling the well. There could be others and the
throw of these faults is not well understood at this point in time. When a known fault is coming up,
ensure to put a “ramp” in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed,
we’ll need to either drill up or down to get a look at the LWD log and determine the throw and then
replan the wellbore.
H2S:
Treat every hole section as though it has the potential for H2S. No H2S events have been documented
on drill wells on this pad.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Abnormal Pressures and Temperatures:
Abnormal pressure has been seen on past well on I-Pad, however recent wells have not see any
abnormal pressure. 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.
xx A/C, wells with < 1.0 clearance factor:
x I-19/L1/PB1/PB2 – A cemented and reservoir abandoned SB dual lateral. TOC at 6620’
MD on 4/17/2020. The only risk is damage to the bit.
at least (1) fault that will be crossed while drilling the well.
No H2S events have been documented
on drill wells on this pad.
Page 49 Version 2
Milne Point Unit
I-21 SB Injector
Drilling Procedure
xx J-16 - is a long term shut in Kuparuk injector. We will control drill past and watch for
magnetic interference. The directional plan will be updated to increase separation with J-
16 to CF >1.0. An update will be sent out.
Page 46 Version 2
Milne Point Unit
I-21 SB Injector
Drilling Procedure
23.0 Anticipated Drilling Hazards
12-1/4” Hole Section:
Lost Circulation
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Gas Hydrates
Gas hyrates have been seen on E Pad. 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.
Well Specific A/C:
x There are no wells with a clearance factor of <1.0
Wellbore stability (Permafrost, running sands and gravel, conductor broaching):
Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of
time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH
speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and
swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching.
Maintain mud parameters and increase MW to combat running sands and gravel formations.
H2S:
Superseded 1/14/2021
SFD
Page 47 Version 2
Milne Point Unit
I-21 SB Injector
Drilling Procedure
Treat every hole section as though it has the potential for H2S. No H2S events have been documented
on drill wells on this pad.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
. No H2S events have been documentedy
on drill wells on this pad.
Superseded 1/14/2021
SFD
Page 48 Version 2
Milne Point Unit
I-21 SB Injector
Drilling Procedure
8-1/2” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor
ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe
moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation
after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300
gpm
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
There is at least (1) fault that will be crossed while drilling the well. There could be others and the
throw of these faults is not well understood at this point in time. When a known fault is coming up,
ensure to put a “ramp” in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed,
we’ll need to either drill up or down to get a look at the LWD log and determine the throw and then
replan the wellbore.
H2S:
Treat every hole section as though it has the potential for H2S. No H2S events have been documented
on drill wells on this pad.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Abnormal Pressures and Temperatures:
Abnormal pressure has been seen on E-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.
x A/C, wells with < 1.0 clearance factor:
x I-19/L1/PB1/PB2 – A cemented and reservoir abandoned SB dual lateral. TOC at 6620’
MD on 4/17/2020. The only risk is damage to the bit.
No H2S events have been documentedy
on drill wells on this pad.
p
Abnormal pressure has been seen on E-Pad. Utilize MPD to mitigate any abnormal pressure seen.
g
at least (1) fault that will be crossed wat least (1) fault that will be crossed while drilling the well. at least (1) fault that will be crossed w
No H2S events have been documented
on drill wells on this pad.
Superseded 1/14/2021
SFD
Page 49 Version 2
Milne Point Unit
I-21 SB Injector
Drilling Procedure
x J-16 - is a long term shut in Kuparuk injector. We will control drill past and watch for
magnetic interference. The directional plan will be updated to increase separation with J-
16 to CF >1.0. An update will be sent out.
24.0 Innovation Rig Layout
Superseded 1/14/2021
SFD
Page 50 Version 2
Milne Point Unit
I-21 SB Injector
Drilling Procedure
25.0 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 51 Version 2
Milne Point Unit
I-21 SB Injector
Drilling Procedure
26.0 Innovation Rig Choke Manifold Schematic
Page 52 Version 2
Milne Point Unit
I-21 SB Injector
Drilling Procedure
27.0 Casing Design
Page 53 Version 2
Milne Point Unit
I-21 SB Injector
Drilling Procedure
28.0 8-1/2” Hole Section MASP
Page 54 Version 2
Milne Point Unit
I-21 SB Injector
Drilling Procedure
29.0 Spider Plot (NAD 27) (Governmental Sections)
Page 55 Version 2
Milne Point Unit
I-21 SB Injector
Drilling Procedure
30.0 Surface Plat (As Built) (NAD 27)
09 January, 2021
Plan: MPU I-21i wp11
Milne Point
M Pt I Pad
Plan: MPU I-21i
MPU I-21i
Project:
Company:
Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt I Pad
Standard Proposal Report
Well:
Wellbore:
Plan: MPU I-21i
MPU I-21i
Survey Calculation Method:Minimum Curvature
MPU I-21i As-built RKB @ 60.20usft
Design:MPU I-21i wp11
Database:NORTH US + CANADA
MD Reference:MPU I-21i As-built RKB @ 60.20usft
North Reference:
Well Plan: MPU I-21i
True
Map System:
Geo Datum:
Project
Map Zone:
System Datum:US State Plane 1927 (Exact solution)
NAD 1927 (NADCON CONUS)
Milne Point, ACT, MILNE POINT
Alaska Zone 04
Mean Sea Level
Using Well Reference Point
Using geodetic scale factor
Site Position:
From:
Site
Latitude:
Longitude:
Position Uncertainty:
Northing:
Easting:
Grid Convergence:
M Pt I Pad, TR-13-10
usft
Map usft
usft
°0.39Slot Radius:"0
6,008,388.010
550,245.830
5.00
70° 26' 1.282 N
149° 35' 25.422 W
Well
Well Position
Longitude:
Latitude:
Easting:
Northing:
usft
+E/-W
+N/-S
Position Uncertainty
usft
usft
usftGround Level:
Plan: MPU I-21i, Slot I-23
usft
usft
0.00
0.00
6,009,440.210
551,774.010
33.40Wellhead Elevation:33.70 usft0.50
70° 26' 11.528 N
149° 34' 40.361 W
Wellbore
Declination
(°)
Field Strength
(nT)
Sample Date Dip Angle
(°)
MPU I-21i
Model NameMagnetics
IFR 1/28/2021 15.65 80.84 57,353.90000000
Phase:Version:
Audit Notes:
Design MPU I-21i wp11
PLAN
Vertical Section: Depth From (TVD)
(usft)
+N/-S
(usft)
Direction
(°)
+E/-W
(usft)
Tie On Depth:26.50
6.880.000.0026.50
1/9/2021 2:23:12AM COMPASS 5000.15 Build 91E Page 2
Project:
Company:
Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt I Pad
Standard Proposal Report
Well:
Wellbore:
Plan: MPU I-21i
MPU I-21i
Survey Calculation Method:Minimum Curvature
MPU I-21i As-built RKB @ 60.20usft
Design:MPU I-21i wp11
Database:NORTH US + CANADA
MD Reference:MPU I-21i As-built RKB @ 60.20usft
North Reference:
Well Plan: MPU I-21i
True
Inclination
(°)
Azimuth
(°)
+E/-W
(usft)
Tool Face
(°)
+N/-S
(usft)
Measured
Depth
(usft)
Vertical
Depth
(usft)
Dogleg
Rate
(°/100usft)
Build
Rate
(°/100usft)
Turn
Rate
(°/100usft)
Plan Sections
TVD
System
usft
0.000.000.000.000.000.0026.500.000.0026.50 -33.70
0.000.000.000.000.000.00280.000.000.00280.00 219.80
315.000.003.003.00-4.164.16429.85315.004.50430.00 369.65
161.3818.40-2.763.00-6.496.84484.09325.003.00484.36 423.89
0.000.000.000.00-10.9913.27633.88325.003.00634.36 573.68
180.000.00-3.003.00-12.4915.41733.840.000.00734.36 673.64
0.000.000.000.00-12.4915.41873.840.000.00874.36 813.64
165.000.004.004.0019.56-104.211,456.45165.0024.001,474.36 1,396.25
40.913.953.434.0031.34-375.541,885.00185.1641.491,984.42 1,824.80
0.000.000.000.0018.02-523.102,052.53185.1641.492,208.06 1,992.33
151.797.131.305.00-647.13-230.763,729.36336.0069.004,323.31 3,669.16
0.000.000.000.00-685.10-145.473,765.20336.0069.004,423.31 3,705.00
51.802.762.273.50-833.50368.593,906.66351.3581.634,979.42 3,846.46
0.000.000.000.00-926.68980.863,997.75351.3581.635,605.40 3,937.55
-3.62-0.223.493.50-963.681,216.634,015.20350.8290.005,844.91 3,955.00
94.311.99-0.152.00-995.391,845.844,020.413.4189.066,476.22 3,960.21
0.000.000.000.00-779.115,473.864,080.193.4189.0610,111.17 4,019.99
90.362.00-0.012.00-740.945,799.274,085.699.9789.0210,439.03 4,025.49
0.000.000.000.00-269.508,481.214,132.179.9789.0213,162.49 4,071.97
-90.07-2.000.002.00-250.768,603.214,134.277.5089.0213,285.95 4,074.07
0.000.000.000.00-55.0010,090.164,159.937.5089.0214,785.95 4,099.73
-135.74-1.40-1.432.00-44.2810,179.074,162.476.2587.7414,875.55 4,102.27
0.000.000.000.00114.7411,631.404,220.206.2587.7416,337.69 4,160.00
135.560.93-0.951.33134.5111,792.264,228.787.7686.2016,500.00 4,168.58
1/9/2021 2:23:12AM COMPASS 5000.15 Build 91E Page 3
Project:
Company:
Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt I Pad
Standard Proposal Report
Well:
Wellbore:
Plan: MPU I-21i
MPU I-21i
Survey Calculation Method:Minimum Curvature
MPU I-21i As-built RKB @ 60.20usft
Design:MPU I-21i wp11
Database:NORTH US + CANADA
MD Reference:MPU I-21i As-built RKB @ 60.20usft
North Reference:
Well Plan: MPU I-21i
True
Measured
Depth
(usft)
Inclination
(°)
Azimuth
(°)
+E/-W
(usft)
Map
Northing
(usft)
Map
Easting
(usft)
+N/-S
(usft)
Planned Survey
Vertical
Depth
(usft)
TVDss
usft
DLS
-33.70
Vert Section
26.50 0.00 26.50 0.00 0.000.00 551,774.0106,009,440.210-33.70 0.000 0.00
100.00 0.00 100.00 0.00 0.000.00 551,774.0106,009,440.21039.80 0.000 0.00
200.00 0.00 200.00 0.00 0.000.00 551,774.0106,009,440.210139.80 0.000 0.00
280.00 0.00 280.00 0.00 0.000.00 551,774.0106,009,440.210219.80 0.000 0.00
Start Dir 3º/100' : 280' MD, 280'TVD
300.00 0.60 300.00 0.07 -0.07315.00 551,773.9356,009,440.284239.80 3.000 0.06
400.00 3.60 399.92 2.66 -2.66315.00 551,771.3276,009,442.856339.72 3.000 2.33
430.00 4.50 429.85 4.16 -4.16315.00 551,769.8196,009,444.344369.65 3.000 3.63
484.36 3.00 484.09 6.84 -6.49325.00 551,767.4766,009,447.001423.89 3.000 6.01
End Dir : 484.36' MD, 484.09' TVD
500.00 3.00 499.71 7.51 -6.96325.00 551,767.0026,009,447.668439.51 0.000 6.62
600.00 3.00 599.57 11.79 -9.96325.00 551,763.9716,009,451.933539.37 0.000 10.52
634.36 3.00 633.88 13.27 -10.99325.00 551,762.9296,009,453.399573.68 0.000 11.86
Start Dir 3º/100' : 634.36' MD, 633.88'TVD
700.00 1.03 699.48 15.16 -12.31325.00 551,761.5926,009,455.281639.28 3.000 13.57
734.36 0.00 733.84 15.41 -12.490.00 551,761.4136,009,455.533673.64 3.000 13.80
End Dir : 734.36' MD, 733.84' TVD
800.00 0.00 799.48 15.41 -12.490.00 551,761.4136,009,455.533739.28 0.000 13.80
874.36 0.00 873.84 15.41 -12.490.00 551,761.4136,009,455.533813.64 0.000 13.80
Start Dir 4º/100' : 874.36' MD, 873.84'TVD
900.00 1.03 899.48 15.19 -12.43165.00 551,761.4746,009,455.311839.28 4.000 13.59
1,000.00 5.03 999.32 10.09 -11.07165.00 551,762.8756,009,450.224939.12 4.000 8.69
1,100.00 9.03 1,098.55 -1.72 -7.90165.00 551,766.1226,009,438.4361,038.35 4.000 -2.65
1,200.00 13.03 1,196.68 -20.19 -2.95165.00 551,771.1986,009,420.0031,136.48 4.000 -20.40
1,300.00 17.03 1,293.24 -45.23 3.76165.00 551,778.0806,009,395.0161,233.04 4.000 -44.45
1,358.91 19.38 1,349.20 -63.00 8.52165.00 551,782.9666,009,377.2761,289.00 4.000 -61.53
SV5
1,400.00 21.03 1,387.76 -76.71 12.19165.00 551,786.7336,009,363.5971,327.56 4.000 -74.69
1,474.36 24.00 1,456.45 -104.21 19.56165.00 551,794.2916,009,336.1521,396.25 4.000 -101.11
1,500.00 24.78 1,479.80 -114.47 22.15166.60 551,796.9576,009,325.9071,419.60 4.000 -110.99
1,600.00 27.98 1,569.38 -158.11 30.27172.02 551,805.3746,009,282.3301,509.18 4.000 -153.34
1,700.00 31.35 1,656.27 -207.32 35.17176.39 551,810.6106,009,233.1581,596.07 4.000 -201.62
1,800.00 34.84 1,740.05 -261.87 36.82179.97 551,812.6406,009,178.6291,679.85 4.000 -255.57
1,861.95 37.05 1,790.20 -298.22 36.21181.89 551,812.2846,009,142.2781,730.00 4.000 -291.73
BPRF
1,900.00 38.42 1,820.29 -321.48 35.22182.97 551,811.4546,009,119.0111,760.09 4.000 -314.95
1,984.42 41.49 1,885.00 -375.54 31.34185.16 551,807.9536,009,064.9321,824.80 4.000 -369.08
End Dir : 1984.42' MD, 1885' TVD
2,000.00 41.49 1,896.67 -385.82 30.41185.16 551,807.0966,009,054.6471,836.47 0.000 -379.40
2,100.00 41.49 1,971.58 -451.80 24.45185.16 551,801.5986,008,988.6341,911.38 0.000 -445.62
2,208.06 41.49 2,052.53 -523.10 18.02185.16 551,795.6576,008,917.3011,992.33 0.000 -517.17
Start Dir 5º/100' : 2208.06' MD, 2052.53'TVD
2,300.00 37.49 2,123.48 -581.11 11.03188.73 551,789.0736,008,859.2432,063.28 5.000 -575.61
2,388.25 33.77 2,195.20 -631.60 1.51192.81 551,779.9076,008,808.6972,135.00 5.000 -626.87
SV0
1/9/2021 2:23:12AM COMPASS 5000.15 Build 91E Page 4
Project:
Company:
Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt I Pad
Standard Proposal Report
Well:
Wellbore:
Plan: MPU I-21i
MPU I-21i
Survey Calculation Method:Minimum Curvature
MPU I-21i As-built RKB @ 60.20usft
Design:MPU I-21i wp11
Database:NORTH US + CANADA
MD Reference:MPU I-21i As-built RKB @ 60.20usft
North Reference:
Well Plan: MPU I-21i
True
Measured
Depth
(usft)
Inclination
(°)
Azimuth
(°)
+E/-W
(usft)
Map
Northing
(usft)
Map
Easting
(usft)
+N/-S
(usft)
Planned Survey
Vertical
Depth
(usft)
TVDss
usft
DLS
2,144.80
Vert Section
2,400.00 33.29 2,205.00 -637.92 0.04193.41 551,778.4786,008,802.3652,144.80 5.000 -633.32
2,500.00 29.30 2,290.45 -687.75 -14.40199.24 551,764.3856,008,752.4412,230.25 5.000 -684.52
2,600.00 25.64 2,379.18 -730.22 -32.18206.65 551,746.9006,008,709.8502,318.98 5.000 -728.82
2,700.00 22.47 2,470.52 -765.02 -53.17216.14 551,726.1576,008,674.9172,410.32 5.000 -765.88
2,800.00 20.00 2,563.77 -791.86 -77.20228.20 551,702.3136,008,647.9082,503.57 5.000 -795.41
2,900.00 18.54 2,658.22 -810.56 -104.10242.73 551,675.5496,008,629.0272,598.02 5.000 -817.19
3,000.00 18.32 2,753.15 -820.96 -133.65258.57 551,646.0716,008,618.4192,692.95 5.000 -831.06
3,100.00 19.39 2,847.84 -823.00 -165.64273.74 551,614.1016,008,616.1642,787.64 5.000 -836.91
3,200.00 21.55 2,941.57 -816.64 -199.82286.67 551,579.8836,008,622.2802,881.37 5.000 -834.70
3,207.13 21.74 2,948.20 -815.87 -202.33287.49 551,577.3636,008,623.0352,888.00 5.000 -834.23
UG_COAL1
3,300.00 24.52 3,033.62 -801.95 -235.93296.98 551,543.6786,008,636.7202,973.42 5.000 -824.44
3,400.00 28.04 3,123.30 -779.03 -273.69305.02 551,505.7616,008,659.3743,063.10 5.000 -806.21
3,500.00 31.93 3,209.93 -748.06 -312.82311.33 551,466.4216,008,690.0693,149.73 5.000 -780.15
3,600.00 36.07 3,292.83 -709.27 -353.02316.36 551,425.9576,008,728.5733,232.63 5.000 -746.45
3,604.17 36.24 3,296.20 -707.49 -354.72316.54 551,424.2486,008,730.3463,236.00 5.000 -744.88
LA3
3,700.00 40.38 3,371.39 -662.96 -393.98320.46 551,384.6776,008,774.5923,311.19 5.000 -705.38
3,800.00 44.81 3,445.00 -609.49 -435.40323.89 551,342.8956,008,827.7763,384.80 5.000 -657.25
3,881.89 48.50 3,501.20 -560.64 -469.43326.31 551,308.5296,008,876.3823,441.00 5.000 -612.83
UGNU MB
3,900.00 49.33 3,513.10 -549.25 -476.95326.81 551,300.9296,008,887.7203,452.90 5.000 -602.43
4,000.00 53.91 3,575.18 -482.70 -518.32329.36 551,259.0996,008,953.9673,514.98 5.000 -541.32
4,100.00 58.54 3,630.77 -410.36 -559.20331.63 551,217.7236,009,026.0153,570.57 5.000 -474.40
4,200.00 63.21 3,679.43 -332.78 -599.28333.69 551,177.1166,009,103.3133,619.23 5.000 -402.17
4,300.00 67.90 3,720.80 -250.53 -638.24335.58 551,137.5876,009,185.2753,660.60 5.000 -325.19
4,323.31 69.00 3,729.36 -230.76 -647.13336.00 551,128.5606,009,204.9843,669.16 5.000 -306.62
End Dir : 4323.31' MD, 3729.36' TVD
4,398.20 69.00 3,756.20 -166.89 -675.57336.00 551,099.6846,009,268.6503,696.00 0.000 -246.62
SB_NA
4,400.00 69.00 3,756.85 -165.35 -676.25336.00 551,098.9896,009,270.1823,696.65 0.000 -245.17
4,423.31 69.00 3,765.20 -145.47 -685.10336.00 551,090.0016,009,289.9983,705.00 0.000 -226.49
Start Dir 3.5º/100' : 4423.31' MD, 3765.2'TVD
4,463.16 69.87 3,779.20 -111.23 -699.93337.17 551,074.9386,009,324.1313,719.00 3.500 -194.28
SB_NB
4,500.00 70.67 3,791.64 -79.15 -713.08338.23 551,061.5616,009,356.1163,731.44 3.500 -164.00
4,600.00 72.90 3,822.90 9.90 -746.08341.08 551,027.9476,009,444.9303,762.70 3.500 -79.54
4,700.00 75.16 3,850.42 101.56 -775.02343.86 550,998.3746,009,536.3813,790.22 3.500 7.99
4,800.00 77.45 3,874.09 195.49 -799.79346.58 550,972.9556,009,630.1283,813.89 3.500 98.28
4,900.00 79.77 3,893.84 291.34 -820.30349.25 550,951.7836,009,725.8203,833.64 3.500 190.98
4,979.42 81.63 3,906.67 368.59 -833.50351.35 550,938.0476,009,802.9683,846.47 3.500 266.09
End Dir : 4979.42' MD, 3906.66' TVD
5,000.00 81.63 3,909.66 388.72 -836.57351.35 550,934.8456,009,823.0733,849.46 0.000 285.71
5,100.00 81.63 3,924.21 486.53 -851.45351.35 550,919.2826,009,920.7683,864.01 0.000 381.03
5,200.00 81.63 3,938.76 584.34 -866.34351.35 550,903.7196,010,018.4623,878.56 0.000 476.35
1/9/2021 2:23:12AM COMPASS 5000.15 Build 91E Page 5
Project:
Company:
Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt I Pad
Standard Proposal Report
Well:
Wellbore:
Plan: MPU I-21i
MPU I-21i
Survey Calculation Method:Minimum Curvature
MPU I-21i As-built RKB @ 60.20usft
Design:MPU I-21i wp11
Database:NORTH US + CANADA
MD Reference:MPU I-21i As-built RKB @ 60.20usft
North Reference:
Well Plan: MPU I-21i
True
Measured
Depth
(usft)
Inclination
(°)
Azimuth
(°)
+E/-W
(usft)
Map
Northing
(usft)
Map
Easting
(usft)
+N/-S
(usft)
Planned Survey
Vertical
Depth
(usft)
TVDss
usft
DLS
3,893.11
Vert Section
5,300.00 81.63 3,953.31 682.15 -881.22351.35 550,888.1576,010,116.1573,893.11 0.000 571.67
5,400.00 81.63 3,967.86 779.96 -896.11351.35 550,872.5946,010,213.8513,907.66 0.000 666.99
5,422.96 81.63 3,971.20 802.41 -899.53351.35 550,869.0216,010,236.2833,911.00 0.000 688.88
SB_OA
5,500.00 81.63 3,982.41 877.77 -911.00351.35 550,857.0326,010,311.5463,922.21 0.000 762.32
5,605.40 81.63 3,997.74 980.86 -926.68351.35 550,840.6296,010,414.5163,937.54 0.000 862.79
Start Dir 3.5º/100' : 5605.4' MD, 3997.75'TVD
5,700.00 84.94 4,008.80 1,073.70 -940.99351.14 550,825.6826,010,507.2483,948.60 3.500 953.25
5,800.00 88.43 4,014.59 1,172.30 -956.56350.92 550,809.4326,010,605.7233,954.39 3.500 1,049.27
5,844.91 90.00 4,015.20 1,216.63 -963.68350.82 550,801.9996,010,650.0043,955.00 3.500 1,092.43
Start Dir 2º/100' : 5844.91' MD, 4015.2'TVD - 9 5/8" x 12 1/4"
5,900.00 89.92 4,015.24 1,271.10 -971.95351.92 550,793.3556,010,704.4053,955.04 2.000 1,145.51
6,000.00 89.77 4,015.52 1,370.33 -984.28353.91 550,780.3366,010,803.5393,955.32 2.000 1,242.55
6,100.00 89.62 4,016.05 1,469.93 -993.15355.91 550,770.7756,010,903.0643,955.85 2.000 1,340.37
6,200.00 89.47 4,016.85 1,569.77 -998.55357.90 550,764.6836,011,002.8613,956.65 2.000 1,438.85
6,300.00 89.32 4,017.91 1,669.74 -1,000.47359.90 550,762.0696,011,102.8063,957.71 2.000 1,537.87
6,400.00 89.17 4,019.23 1,769.72 -998.911.89 550,762.9346,011,202.7793,959.03 2.000 1,637.31
6,463.18 89.08 4,020.20 1,832.83 -996.133.15 550,765.2756,011,265.9043,960.00 2.000 1,700.31
SB_OBa (Heel)
6,476.22 89.06 4,020.41 1,845.84 -995.393.41 550,765.9316,011,278.9213,960.21 1.999 1,713.32
End Dir : 6476.22' MD, 4020.41' TVD
6,500.00 89.06 4,020.80 1,869.58 -993.973.41 550,767.1816,011,302.6633,960.60 0.000 1,737.05
6,600.00 89.06 4,022.45 1,969.39 -988.023.41 550,772.4376,011,402.5013,962.25 0.000 1,836.85
6,700.00 89.06 4,024.09 2,069.20 -982.073.41 550,777.6946,011,502.3403,963.89 0.000 1,936.65
6,800.00 89.06 4,025.74 2,169.01 -976.123.41 550,782.9506,011,602.1783,965.54 0.000 2,036.46
6,900.00 89.06 4,027.38 2,268.82 -970.173.41 550,788.2076,011,702.0173,967.18 0.000 2,136.26
7,000.00 89.06 4,029.03 2,368.63 -964.223.41 550,793.4636,011,801.8553,968.83 0.000 2,236.06
7,100.00 89.06 4,030.67 2,468.43 -958.273.41 550,798.7196,011,901.6943,970.47 0.000 2,335.87
7,200.00 89.06 4,032.31 2,568.24 -952.323.41 550,803.9766,012,001.5323,972.11 0.000 2,435.67
7,300.00 89.06 4,033.96 2,668.05 -946.373.41 550,809.2326,012,101.3713,973.76 0.000 2,535.47
7,400.00 89.06 4,035.60 2,767.86 -940.423.41 550,814.4896,012,201.2093,975.40 0.000 2,635.28
7,500.00 89.06 4,037.25 2,867.67 -934.473.41 550,819.7456,012,301.0483,977.05 0.000 2,735.08
7,600.00 89.06 4,038.89 2,967.48 -928.523.41 550,825.0026,012,400.8863,978.69 0.000 2,834.88
7,700.00 89.06 4,040.54 3,067.29 -922.573.41 550,830.2586,012,500.7253,980.34 0.000 2,934.69
7,800.00 89.06 4,042.18 3,167.10 -916.623.41 550,835.5156,012,600.5633,981.98 0.000 3,034.49
7,900.00 89.06 4,043.83 3,266.91 -910.673.41 550,840.7716,012,700.4023,983.63 0.000 3,134.29
8,000.00 89.06 4,045.47 3,366.72 -904.723.41 550,846.0286,012,800.2403,985.27 0.000 3,234.10
8,100.00 89.06 4,047.12 3,466.53 -898.773.41 550,851.2846,012,900.0793,986.92 0.000 3,333.90
8,200.00 89.06 4,048.76 3,566.34 -892.823.41 550,856.5406,012,999.9173,988.56 0.000 3,433.70
8,300.00 89.06 4,050.40 3,666.15 -886.873.41 550,861.7976,013,099.7563,990.20 0.000 3,533.51
8,400.00 89.06 4,052.05 3,765.96 -880.923.41 550,867.0536,013,199.5943,991.85 0.000 3,633.31
8,500.00 89.06 4,053.69 3,865.76 -874.973.41 550,872.3106,013,299.4333,993.49 0.000 3,733.11
8,600.00 89.06 4,055.34 3,965.57 -869.023.41 550,877.5666,013,399.2713,995.14 0.000 3,832.92
8,700.00 89.06 4,056.98 4,065.38 -863.073.41 550,882.8236,013,499.1103,996.78 0.000 3,932.72
8,800.00 89.06 4,058.63 4,165.19 -857.123.41 550,888.0796,013,598.9483,998.43 0.000 4,032.52
1/9/2021 2:23:12AM COMPASS 5000.15 Build 91E Page 6
Project:
Company:
Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt I Pad
Standard Proposal Report
Well:
Wellbore:
Plan: MPU I-21i
MPU I-21i
Survey Calculation Method:Minimum Curvature
MPU I-21i As-built RKB @ 60.20usft
Design:MPU I-21i wp11
Database:NORTH US + CANADA
MD Reference:MPU I-21i As-built RKB @ 60.20usft
North Reference:
Well Plan: MPU I-21i
True
Measured
Depth
(usft)
Inclination
(°)
Azimuth
(°)
+E/-W
(usft)
Map
Northing
(usft)
Map
Easting
(usft)
+N/-S
(usft)
Planned Survey
Vertical
Depth
(usft)
TVDss
usft
DLS
4,000.07
Vert Section
8,900.00 89.06 4,060.27 4,265.00 -851.173.41 550,893.3366,013,698.7874,000.07 0.000 4,132.33
9,000.00 89.06 4,061.92 4,364.81 -845.223.41 550,898.5926,013,798.6254,001.72 0.000 4,232.13
9,100.00 89.06 4,063.56 4,464.62 -839.273.41 550,903.8486,013,898.4644,003.36 0.000 4,331.93
9,200.00 89.06 4,065.21 4,564.43 -833.323.41 550,909.1056,013,998.3024,005.01 0.000 4,431.74
9,300.00 89.06 4,066.85 4,664.24 -827.373.41 550,914.3616,014,098.1414,006.65 0.000 4,531.54
9,400.00 89.06 4,068.49 4,764.05 -821.423.41 550,919.6186,014,197.9794,008.29 0.000 4,631.34
9,500.00 89.06 4,070.14 4,863.86 -815.473.41 550,924.8746,014,297.8184,009.94 0.000 4,731.15
9,600.00 89.06 4,071.78 4,963.67 -809.523.41 550,930.1316,014,397.6564,011.58 0.000 4,830.95
9,700.00 89.06 4,073.43 5,063.48 -803.573.41 550,935.3876,014,497.4954,013.23 0.000 4,930.75
9,800.00 89.06 4,075.07 5,163.29 -797.623.41 550,940.6446,014,597.3334,014.87 0.000 5,030.56
9,900.00 89.06 4,076.72 5,263.09 -791.673.41 550,945.9006,014,697.1724,016.52 0.000 5,130.36
10,000.00 89.06 4,078.36 5,362.90 -785.723.41 550,951.1566,014,797.0114,018.16 0.000 5,230.16
10,100.00 89.06 4,080.01 5,462.71 -779.773.41 550,956.4136,014,896.8494,019.81 0.000 5,329.97
10,111.17 89.06 4,080.19 5,473.86 -779.113.41 550,957.0006,014,908.0014,019.99 0.000 5,341.12
Start Dir 2º/100' : 10111.17' MD, 4080.19'TVD
10,200.00 89.05 4,081.66 5,562.43 -772.455.19 550,963.0446,014,996.6014,021.46 2.000 5,429.84
10,300.00 89.04 4,083.33 5,661.82 -761.677.19 550,973.1306,015,096.0624,023.13 2.000 5,529.81
10,400.00 89.03 4,085.02 5,760.79 -747.439.19 550,986.6826,015,195.1104,024.82 2.000 5,629.77
10,439.03 89.02 4,085.69 5,799.27 -740.949.97 550,992.9096,015,233.6304,025.49 2.000 5,668.75
End Dir : 10439.03' MD, 4085.69' TVD
10,500.00 89.02 4,086.73 5,859.31 -730.389.97 551,003.0456,015,293.7374,026.53 0.000 5,729.62
10,600.00 89.02 4,088.44 5,957.78 -713.079.97 551,019.6696,015,392.3214,028.24 0.000 5,829.46
10,700.00 89.02 4,090.14 6,056.26 -695.769.97 551,036.2936,015,490.9054,029.94 0.000 5,929.30
10,800.00 89.02 4,091.85 6,154.73 -678.459.97 551,052.9186,015,589.4884,031.65 0.000 6,029.14
10,900.00 89.02 4,093.56 6,253.21 -661.149.97 551,069.5426,015,688.0724,033.36 0.000 6,128.98
11,000.00 89.02 4,095.26 6,351.68 -643.839.97 551,086.1676,015,786.6564,035.06 0.000 6,228.82
11,100.00 89.02 4,096.97 6,450.16 -626.529.97 551,102.7916,015,885.2404,036.77 0.000 6,328.66
11,200.00 89.02 4,098.68 6,548.64 -609.219.97 551,119.4166,015,983.8244,038.48 0.000 6,428.50
11,300.00 89.02 4,100.38 6,647.11 -591.909.97 551,136.0406,016,082.4084,040.18 0.000 6,528.34
11,400.00 89.02 4,102.09 6,745.59 -574.599.97 551,152.6656,016,180.9924,041.89 0.000 6,628.18
11,500.00 89.02 4,103.79 6,844.06 -557.289.97 551,169.2896,016,279.5754,043.59 0.000 6,728.02
11,600.00 89.02 4,105.50 6,942.54 -539.979.97 551,185.9136,016,378.1594,045.30 0.000 6,827.86
11,700.00 89.02 4,107.21 7,041.01 -522.669.97 551,202.5386,016,476.7434,047.01 0.000 6,927.70
11,800.00 89.02 4,108.91 7,139.49 -505.359.97 551,219.1626,016,575.3274,048.71 0.000 7,027.54
11,900.00 89.02 4,110.62 7,237.96 -488.049.97 551,235.7876,016,673.9114,050.42 0.000 7,127.38
12,000.00 89.02 4,112.33 7,336.44 -470.739.97 551,252.4116,016,772.4954,052.13 0.000 7,227.22
12,100.00 89.02 4,114.03 7,434.92 -453.429.97 551,269.0366,016,871.0794,053.83 0.000 7,327.06
12,200.00 89.02 4,115.74 7,533.39 -436.119.97 551,285.6606,016,969.6624,055.54 0.000 7,426.90
12,300.00 89.02 4,117.45 7,631.87 -418.809.97 551,302.2856,017,068.2464,057.25 0.000 7,526.74
12,400.00 89.02 4,119.15 7,730.34 -401.499.97 551,318.9096,017,166.8304,058.95 0.000 7,626.58
12,500.00 89.02 4,120.86 7,828.82 -384.189.97 551,335.5346,017,265.4144,060.66 0.000 7,726.42
12,600.00 89.02 4,122.57 7,927.29 -366.879.97 551,352.1586,017,363.9984,062.37 0.000 7,826.26
12,700.00 89.02 4,124.27 8,025.77 -349.569.97 551,368.7826,017,462.5824,064.07 0.000 7,926.10
12,800.00 89.02 4,125.98 8,124.25 -332.259.97 551,385.4076,017,561.1664,065.78 0.000 8,025.94
12,900.00 89.02 4,127.69 8,222.72 -314.949.97 551,402.0316,017,659.7494,067.49 0.000 8,125.78
1/9/2021 2:23:12AM COMPASS 5000.15 Build 91E Page 7
Project:
Company:
Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt I Pad
Standard Proposal Report
Well:
Wellbore:
Plan: MPU I-21i
MPU I-21i
Survey Calculation Method:Minimum Curvature
MPU I-21i As-built RKB @ 60.20usft
Design:MPU I-21i wp11
Database:NORTH US + CANADA
MD Reference:MPU I-21i As-built RKB @ 60.20usft
North Reference:
Well Plan: MPU I-21i
True
Measured
Depth
(usft)
Inclination
(°)
Azimuth
(°)
+E/-W
(usft)
Map
Northing
(usft)
Map
Easting
(usft)
+N/-S
(usft)
Planned Survey
Vertical
Depth
(usft)
TVDss
usft
DLS
4,069.19
Vert Section
13,000.00 89.02 4,129.39 8,321.20 -297.639.97 551,418.6566,017,758.3334,069.19 0.000 8,225.62
13,100.00 89.02 4,131.10 8,419.67 -280.329.97 551,435.2806,017,856.9174,070.90 0.000 8,325.46
13,162.49 89.02 4,132.17 8,481.21 -269.509.97 551,445.6696,017,918.5224,071.97 0.000 8,387.85
Start Dir 2º/100' : 13162.49' MD, 4132.17'TVD
13,200.00 89.02 4,132.81 8,518.19 -263.259.22 551,451.6626,017,955.5414,072.61 2.000 8,425.32
13,285.95 89.02 4,134.27 8,603.21 -250.767.50 551,463.5646,018,040.6384,074.07 2.000 8,511.22
End Dir : 13285.95' MD, 4134.27' TVD
13,300.00 89.02 4,134.52 8,617.14 -248.927.50 551,465.3016,018,054.5774,074.32 0.000 8,525.27
13,400.00 89.02 4,136.23 8,716.27 -235.877.50 551,477.6626,018,153.7864,076.03 0.000 8,625.25
13,500.00 89.02 4,137.94 8,815.40 -222.827.50 551,490.0236,018,252.9944,077.74 0.000 8,725.23
13,600.00 89.02 4,139.65 8,914.53 -209.777.50 551,502.3846,018,352.2034,079.45 0.000 8,825.21
13,700.00 89.02 4,141.36 9,013.66 -196.727.50 551,514.7456,018,451.4114,081.16 0.000 8,925.19
13,800.00 89.02 4,143.07 9,112.79 -183.677.50 551,527.1066,018,550.6204,082.87 0.000 9,025.17
13,900.00 89.02 4,144.78 9,211.92 -170.627.50 551,539.4676,018,649.8294,084.58 0.000 9,125.15
14,000.00 89.02 4,146.49 9,311.05 -157.577.50 551,551.8286,018,749.0374,086.29 0.000 9,225.13
14,100.00 89.02 4,148.20 9,410.18 -144.527.50 551,564.1896,018,848.2464,088.00 0.000 9,325.11
14,200.00 89.02 4,149.91 9,509.31 -131.477.50 551,576.5506,018,947.4544,089.71 0.000 9,425.09
14,300.00 89.02 4,151.62 9,608.44 -118.427.50 551,588.9116,019,046.6634,091.42 0.000 9,525.06
14,400.00 89.02 4,153.33 9,707.57 -105.377.50 551,601.2726,019,145.8714,093.13 0.000 9,625.04
14,500.00 89.02 4,155.04 9,806.70 -92.317.50 551,613.6336,019,245.0804,094.84 0.000 9,725.02
14,600.00 89.02 4,156.75 9,905.83 -79.267.50 551,625.9946,019,344.2894,096.55 0.000 9,825.00
14,700.00 89.02 4,158.46 10,004.96 -66.217.50 551,638.3556,019,443.4974,098.26 0.000 9,924.98
14,785.95 89.02 4,159.93 10,090.16 -55.007.50 551,648.9806,019,528.7674,099.73 0.000 10,010.92
Start Dir 2º/100' : 14785.95' MD, 4159.93'TVD
14,800.00 88.82 4,160.19 10,104.09 -53.197.30 551,650.6926,019,542.7084,099.99 2.000 10,024.96
14,875.55 87.74 4,162.47 10,179.08 -44.286.25 551,659.0816,019,617.7474,102.27 2.000 10,100.48
End Dir : 14875.55' MD, 4162.47' TVD
14,900.00 87.74 4,163.43 10,203.36 -41.626.25 551,661.5716,019,642.0484,103.23 0.000 10,124.90
15,000.00 87.74 4,167.38 10,302.69 -30.746.25 551,671.7566,019,741.4404,107.18 0.000 10,224.82
15,100.00 87.74 4,171.33 10,402.02 -19.876.25 551,681.9416,019,840.8324,111.13 0.000 10,324.74
15,200.00 87.74 4,175.28 10,501.35 -8.996.25 551,692.1266,019,940.2244,115.08 0.000 10,424.65
15,300.00 87.74 4,179.23 10,600.68 1.896.25 551,702.3116,020,039.6164,119.03 0.000 10,524.57
15,400.00 87.74 4,183.17 10,700.00 12.766.25 551,712.4966,020,139.0084,122.97 0.000 10,624.48
15,500.00 87.74 4,187.12 10,799.33 23.646.25 551,722.6816,020,238.4004,126.92 0.000 10,724.40
15,600.00 87.74 4,191.07 10,898.66 34.516.25 551,732.8666,020,337.7914,130.87 0.000 10,824.32
15,700.00 87.74 4,195.02 10,997.99 45.396.25 551,743.0516,020,437.1834,134.82 0.000 10,924.23
15,800.00 87.74 4,198.97 11,097.32 56.266.25 551,753.2366,020,536.5754,138.77 0.000 11,024.15
15,900.00 87.74 4,202.92 11,196.65 67.146.25 551,763.4216,020,635.9674,142.72 0.000 11,124.06
16,000.00 87.74 4,206.87 11,295.97 78.026.25 551,773.6066,020,735.3594,146.67 0.000 11,223.98
16,100.00 87.74 4,210.81 11,395.30 88.896.25 551,783.7916,020,834.7514,150.61 0.000 11,323.90
16,200.00 87.74 4,214.76 11,494.63 99.776.25 551,793.9766,020,934.1424,154.56 0.000 11,423.81
16,300.00 87.74 4,218.71 11,593.96 110.646.25 551,804.1616,021,033.5344,158.51 0.000 11,523.73
16,337.69 87.74 4,220.20 11,631.40 114.746.25 551,807.9996,021,070.9954,160.00 0.000 11,561.39
Start Dir 1.33º/100' : 16337.69' MD, 4220.2'TVD
16,400.00 87.15 4,222.98 11,693.24 121.836.83 551,814.6576,021,132.8794,162.78 1.327 11,623.63
1/9/2021 2:23:12AM COMPASS 5000.15 Build 91E Page 8
Project:
Company:
Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt I Pad
Standard Proposal Report
Well:
Wellbore:
Plan: MPU I-21i
MPU I-21i
Survey Calculation Method:Minimum Curvature
MPU I-21i As-built RKB @ 60.20usft
Design:MPU I-21i wp11
Database:NORTH US + CANADA
MD Reference:MPU I-21i As-built RKB @ 60.20usft
North Reference:
Well Plan: MPU I-21i
True
Measured
Depth
(usft)
Inclination
(°)
Azimuth
(°)
+E/-W
(usft)
Map
Northing
(usft)
Map
Easting
(usft)
+N/-S
(usft)
Planned Survey
Vertical
Depth
(usft)
TVDss
usft
DLS
4,168.58
Vert Section
16,500.00 86.20 4,228.78 11,792.26 134.517.76 551,826.6436,021,231.9774,168.58 1.327 11,723.46
Total Depth : 16500' MD, 4228.78' TVD
Target Name
- hit/miss target
- Shape
TVD
(usft)
Northing
(usft)
Easting
(usft)
+N/-S
(usft)
+E/-W
(usft)
Tar gets
Dip Angle
(°)
Dip Dir.
(°)
MPI-Shiloh wp08 CP5 4,220.20 6,021,071.000 551,808.00011,631.40 114.740.00 0.00
- plan hits target center
- Point
MPI-Shiloh wp08 CP1 3,765.20 6,009,290.000 551,090.000-145.47 -685.100.00 0.00
- plan hits target center
- Point
MPI-Shiloh wp08 CP3 4,080.19 6,014,908.000 550,957.0005,473.86 -779.110.00 0.00
- plan hits target center
- Point
MPI-Shiloh wp08 CP2 3,960.20 6,009,752.580 550,880.180318.60 -891.730.00 0.00
- plan misses target center by 88.07usft at 4949.12usft MD (3902.07 TVD, 339.01 N, -828.79 E)
- Point
MPI-Shiloh wp08 CP4 4,159.93 6,019,528.770 551,648.98010,090.16 -55.000.00 0.00
- plan hits target center
- Point
MPI-Shiloh wp10 CP1 - HEEL 4,015.20 6,010,650.000 550,802.0001,216.63 -963.680.00 0.00
- plan hits target center
- Circle (radius 30.00)
Vertical
Depth
(usft)
Measured
Depth
(usft)
Casing
Diameter
(")
Hole
Diameter
(")Name
Casing Points
4 1/2" x 8 1/2"4,228.7816,500.00 4-1/2 8-1/2
9 5/8" x 12 1/4"4,015.205,844.91 9-5/8 12-1/4
1/9/2021 2:23:12AM COMPASS 5000.15 Build 91E Page 9
Project:
Company:
Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt I Pad
Standard Proposal Report
Well:
Wellbore:
Plan: MPU I-21i
MPU I-21i
Survey Calculation Method:Minimum Curvature
MPU I-21i As-built RKB @ 60.20usft
Design:MPU I-21i wp11
Database:NORTH US + CANADA
MD Reference:MPU I-21i As-built RKB @ 60.20usft
North Reference:
Well Plan: MPU I-21i
True
Measured
Depth
(usft)
Vertical
Depth
(usft)
Dip
Direction
(°)Name Lithology
Dip
(°)
Formations
Vertical
Depth SS
2,388.25 2,195.20 SV0
4,398.20 3,756.20 SB_NA
5,422.96 3,971.20 SB_OA
3,604.17 3,296.20 LA3
1,861.95 1,790.20 BPRF
6,463.18 4,020.20 SB_OBa (Heel)
3,881.89 3,501.20 UGNU MB
4,463.16 3,779.20 SB_NB
1,358.91 1,349.20 SV5
3,207.13 2,948.20 UG_COAL1
Measured
Depth
(usft)
Vertical
Depth
(usft)
+E/-W
(usft)
+N/-S
(usft)
Local Coordinates
Comment
Plan Annotations
280.00 280.00 0.00 0.00 Start Dir 3º/100' : 280' MD, 280'TVD
484.36 484.09 6.84 -6.49 End Dir : 484.36' MD, 484.09' TVD
634.36 633.88 13.27 -10.99 Start Dir 3º/100' : 634.36' MD, 633.88'TVD
734.36 733.84 15.41 -12.49 End Dir : 734.36' MD, 733.84' TVD
874.36 873.84 15.41 -12.49 Start Dir 4º/100' : 874.36' MD, 873.84'TVD
1,984.42 1,885.00 -375.54 31.34 End Dir : 1984.42' MD, 1885' TVD
2,208.06 2,052.53 -523.10 18.02 Start Dir 5º/100' : 2208.06' MD, 2052.53'TVD
4,323.31 3,729.36 -230.76 -647.13 End Dir : 4323.31' MD, 3729.36' TVD
4,423.31 3,765.20 -145.47 -685.10 Start Dir 3.5º/100' : 4423.31' MD, 3765.2'TVD
4,979.42 3,906.67 368.59 -833.50 End Dir : 4979.42' MD, 3906.66' TVD
5,605.40 3,997.74 980.86 -926.68 Start Dir 3.5º/100' : 5605.4' MD, 3997.75'TVD
5,844.91 4,015.20 1,216.63 -963.68 Start Dir 2º/100' : 5844.91' MD, 4015.2'TVD
6,476.22 4,020.41 1,845.84 -995.39 End Dir : 6476.22' MD, 4020.41' TVD
10,111.17 4,080.19 5,473.86 -779.11 Start Dir 2º/100' : 10111.17' MD, 4080.19'TVD
10,439.03 4,085.69 5,799.27 -740.94 End Dir : 10439.03' MD, 4085.69' TVD
13,162.49 4,132.17 8,481.21 -269.50 Start Dir 2º/100' : 13162.49' MD, 4132.17'TVD
13,285.95 4,134.27 8,603.21 -250.76 End Dir : 13285.95' MD, 4134.27' TVD
14,785.95 4,159.93 10,090.16 -55.00 Start Dir 2º/100' : 14785.95' MD, 4159.93'TVD
14,875.55 4,162.47 10,179.08 -44.28 End Dir : 14875.55' MD, 4162.47' TVD
16,337.69 4,220.20 11,631.40 114.74 Start Dir 1.33º/100' : 16337.69' MD, 4220.2'TVD
16,500.00 4,228.78 11,792.26 134.51 Total Depth : 16500' MD, 4228.78' TVD
1/9/2021 2:23:12AM COMPASS 5000.15 Build 91E Page 10
09 January, 2021Milne PointM Pt I PadPlan: MPU I-21iMPU I-21i5002923681MPU I-21i wp11Reference Design: M Pt I Pad - Plan: MPU I-21i - MPU I-21i - MPU I-21i wp11Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Well Coordinates: 6,009,440.21 N, 551,774.01 E (70° 26' 11.53" N, 149° 34' 40.36" W)Datum Height: MPU I-21i As-built RKB @ 60.20usftScan Range: 26.50 to 5,844.91 usft. Measured Depth.Geodetic Scale Factor AppliedVersion: 5000.15 Build: 91EScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftGLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of referenceScan Type:Scan Type:25.00
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-21i - MPU I-21i wp11Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 26.50 to 5,844.91 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt I Pad - Plan: MPU I-21i - MPU I-21i - MPU I-21i wp11MeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt I PadMPI-01 - MPI-01 - MPI-01 42.28 1,036.61 32.54 1,049.89 4.3381,036.61Centre Distance Pass - MPI-01 - MPI-01 - MPI-0142.38 1,051.50 32.53 1,064.23 4.3031,051.50Ellipse Separation Pass - MPI-01 - MPI-01 - MPI-01 43.01 1,076.50 33.01 1,088.23 4.3011,076.50Clearance Factor Pass - MPI-02 - MPI-02 - MPI-0282.90 1,085.00 72.69 1,112.55 8.1141,085.00Ellipse Separation Pass - MPI-02 - MPI-02 - MPI-0284.60 1,126.50 73.95 1,151.60 7.9401,126.50Clearance Factor Pass - MPI-03 - MPI-03 - MPI-0375.66 2,325.45 57.57 2,283.05 4.1832,325.45Centre Distance Pass - MPI-03 - MPI-03 - MPI-0375.66 2,326.50 57.57 2,284.04 4.1812,326.50Ellipse Separation Pass - MPI-03 - MPI-03 - MPI-0376.34 2,351.50 58.03 2,307.81 4.1692,351.50Clearance Factor Pass - MPI-04 - MPI-04 - MPI-04246.41 967.97 237.14 995.14 26.572967.97Centre Distance Pass - MPI-04 - MPI-04 - MPI-04246.44 976.50 237.09 1,003.32 26.347976.50Ellipse Separation Pass - MPI-04 - MPI-04 - MPI-04264.42 1,151.50 253.40 1,158.98 23.9981,151.50Clearance Factor Pass - MPI-04 - MPI-04A - MPI-04A246.41 967.97 237.14 995.14 26.572967.97Centre Distance Pass - MPI-04 - MPI-04A - MPI-04A246.44 976.50 237.09 1,003.32 26.347976.50Ellipse Separation Pass - MPI-04 - MPI-04A - MPI-04A264.42 1,151.50 253.40 1,158.98 23.9981,151.50Clearance Factor Pass - MPI-04 - MPI-04AL1 - MPI-04AL1246.41 967.97 237.14 995.14 26.572967.97Centre Distance Pass - MPI-04 - MPI-04AL1 - MPI-04AL1246.44 976.50 237.09 1,003.32 26.347976.50Ellipse Separation Pass - MPI-04 - MPI-04AL1 - MPI-04AL1264.42 1,151.50 253.40 1,158.98 23.9981,151.50Clearance Factor Pass - MPI-04 - MPI-04APB1 - MPI-04APB1246.41 967.97 237.14 995.14 26.572967.97Centre Distance Pass - MPI-04 - MPI-04APB1 - MPI-04APB1246.44 976.50 237.09 1,003.32 26.347976.50Ellipse Separation Pass - MPI-04 - MPI-04APB1 - MPI-04APB1264.42 1,151.50 253.40 1,158.98 23.9981,151.50Clearance Factor Pass - MPI-04 - MPI-04PB1 - MPI-04PB1246.41 967.97 237.14 995.14 26.572967.97Centre Distance Pass - MPI-04 - MPI-04PB1 - MPI-04PB1246.44 976.50 237.09 1,003.32 26.347976.50Ellipse Separation Pass - MPI-04 - MPI-04PB1 - MPI-04PB1 264.42 1,151.50 253.40 1,158.98 23.9981,151.50Clearance Factor Pass - MPI-05 - MPI-05 - MPI-05140.85 1,358.24 130.49 1,391.98 13.6061,358.24Ellipse Separation Pass - MPI-05 - MPI-05 - MPI-05146.06 1,451.50 134.93 1,481.48 13.1161,451.50Clearance Factor Pass - MPI-06 - MPI-06 - MPI-06239.49 676.35 233.02 675.88 37.037676.35Centre Distance Pass - MPI-06 - MPI-06 - MPI-06239.63 701.50 232.95 700.00 35.881701.50Ellipse Separation Pass - MPI-06 - MPI-06 - MPI-06516.65 1,976.50 496.94 1,822.40 26.2131,976.50Clearance Factor Pass - 09 January, 2021- 2:25COMPASSPage 2 of 8
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-21i - MPU I-21i wp11Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 26.50 to 5,844.91 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt I Pad - Plan: MPU I-21i - MPU I-21i - MPU I-21i wp11MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPI-09 - MPI-09 - MPI-09102.86 728.48 95.93 731.83 14.853728.48Ellipse Separation Pass - MPI-09 - MPI-09 - MPI-09 108.26 876.50 100.48 874.29 13.904876.50Clearance Factor Pass - MPI-10 - MPI-10 - MPI-1053.80 566.32 48.72 566.60 10.584566.32Centre Distance Pass - MPI-10 - MPI-10 - MPI-1054.00 601.50 48.61 601.37 10.026601.50Ellipse Separation Pass - MPI-10 - MPI-10 - MPI-1063.50 876.50 55.76 874.68 8.203876.50Clearance Factor Pass - MPI-15 - MPI-15 - MPI-1533.72 654.82 28.56 657.28 6.539654.82Centre Distance Pass - MPI-15 - MPI-15 - MPI-1533.81 676.50 28.50 678.79 6.374676.50Ellipse Separation Pass - MPI-15 - MPI-15 - MPI-1536.67 801.50 30.52 803.05 5.960801.50Clearance Factor Pass - MPI-15 - MPI-15L1 - MPI-15L133.72 654.82 28.56 657.28 6.539654.82Centre Distance Pass - MPI-15 - MPI-15L1 - MPI-15L133.81 676.50 28.50 678.79 6.374676.50Ellipse Separation Pass - MPI-15 - MPI-15L1 - MPI-15L136.67 801.50 30.52 803.05 5.960801.50Clearance Factor Pass - MPI-15 - MPI-15PB1 - MPI-15PB133.72 654.82 28.56 657.28 6.539654.82Centre Distance Pass - MPI-15 - MPI-15PB1 - MPI-15PB133.81 676.50 28.50 678.79 6.374676.50Ellipse Separation Pass - MPI-15 - MPI-15PB1 - MPI-15PB136.67 801.50 30.52 803.05 5.960801.50Clearance Factor Pass - MPI-16 - MPI-16 - MPI-1614.59 101.50 12.71 109.65 7.789101.50Centre Distance Pass - MPI-16 - MPI-16 - MPI-1614.90 201.50 12.28 209.54 5.680201.50Ellipse Separation Pass - MPI-16 - MPI-16 - MPI-1617.46 301.50 14.01 309.03 5.062301.50Clearance Factor Pass - MPI-17 - MPI-17 - MPI-1715.59 26.50 13.74 34.65 8.44326.50Centre Distance Pass - MPI-17 - MPI-17 - MPI-1715.78 101.50 13.64 109.62 7.376101.50Ellipse Separation Pass - MPI-17 - MPI-17 - MPI-1736.98 1,703.36 19.69 1,687.20 2.1381,703.36Clearance Factor Pass - MPI-17 - MPI-17L1 - MPI-17L115.59 26.50 13.74 34.65 8.44326.50Centre Distance Pass - MPI-17 - MPI-17L1 - MPI-17L115.78 101.50 13.64 109.62 7.376101.50Ellipse Separation Pass - MPI-17 - MPI-17L1 - MPI-17L1 36.98 1,703.36 19.69 1,687.20 2.1381,703.36Clearance Factor Pass - MPI-17 - MPI-17L1PB1 - MPI-17L1PB115.59 26.50 13.74 34.65 8.44326.50Centre Distance Pass - MPI-17 - MPI-17L1PB1 - MPI-17L1PB115.78 101.50 13.64 109.62 7.376101.50Ellipse Separation Pass - MPI-17 - MPI-17L1PB1 - MPI-17L1PB136.98 1,703.36 19.69 1,687.20 2.1381,703.36Clearance Factor Pass - MPI-17 - MPI-17L2 - MPI-17L215.59 26.50 13.74 34.65 8.44326.50Centre Distance Pass - MPI-17 - MPI-17L2 - MPI-17L215.78 101.50 13.64 109.62 7.376101.50Ellipse Separation Pass - MPI-17 - MPI-17L2 - MPI-17L236.98 1,703.36 19.69 1,687.20 2.1381,703.36Clearance Factor Pass - MPI-18 - MPI-18 - MPI-1843.31 1,843.40 26.67 1,808.16 2.6031,843.40Centre Distance Pass - 09 January, 2021- 2:25COMPASSPage 3 of 8
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-21i - MPU I-21i wp11Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 26.50 to 5,844.91 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt I Pad - Plan: MPU I-21i - MPU I-21i - MPU I-21i wp11MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPI-18 - MPI-18 - MPI-1843.44 1,851.50 26.50 1,815.40 2.5651,851.50Clearance Factor Pass - MPI-19 - MPI-19 - MPI-19 75.82 26.50 73.97 35.37 41.05426.50Ellipse Separation Pass - MPI-19 - MPI-19 - MPI-1991.36 976.50 82.14 984.71 9.903976.50Clearance Factor Pass - MPI-19 - MPI-19L1 - MPI-19L175.82 26.50 73.97 35.37 41.05426.50Ellipse Separation Pass - MPI-19 - MPI-19L1 - MPI-19L191.36 976.50 82.14 984.71 9.903976.50Clearance Factor Pass - MPI-19 - MPI-19PB1 - MPI-19PB175.82 26.50 73.97 35.37 41.05426.50Ellipse Separation Pass - MPI-19 - MPI-19PB1 - MPI-19PB191.36 976.50 82.14 984.71 9.903976.50Clearance Factor Pass - MPI-19 - MPI-19PB2 - MPI-19PB275.82 26.50 73.97 35.37 41.05426.50Ellipse Separation Pass - MPI-19 - MPI-19PB2 - MPI-19PB291.36 976.50 82.14 984.71 9.903976.50Clearance Factor Pass - MPU I-35i - MPU I-35i - MPU I-35i18.07 1,269.76 8.67 1,269.13 1.9221,269.76Clearance Factor Pass - MPU I-36 - MPU I-36 - MPU I-3682.27 569.42 77.95 566.64 19.065569.42Centre Distance Pass - MPU I-36 - MPU I-36 - MPU I-3682.36 651.50 77.56 648.60 17.148651.50Ellipse Separation Pass - MPU I-36 - MPU I-36 - MPU I-36493.30 5,844.91 439.44 5,054.03 9.1605,844.91Clearance Factor Pass - MPU I-36 - MPU I-36PB1 - MPU I-36PB182.27 569.42 77.95 566.64 19.065569.42Centre Distance Pass - MPU I-36 - MPU I-36PB1 - MPU I-36PB182.36 651.50 77.56 648.60 17.148651.50Ellipse Separation Pass - MPU I-36 - MPU I-36PB1 - MPU I-36PB1493.30 5,844.91 439.44 5,054.03 9.1605,844.91Clearance Factor Pass - MPU I-36 - MPU I-36PB2 - MPU I-36PB282.27 569.42 77.95 566.64 19.065569.42Centre Distance Pass - MPU I-36 - MPU I-36PB2 - MPU I-36PB282.36 651.50 77.56 648.60 17.148651.50Ellipse Separation Pass - MPU I-36 - MPU I-36PB2 - MPU I-36PB2493.30 5,844.91 439.48 5,054.03 9.1665,844.91Clearance Factor Pass - MPU I-37i - MPU I-37i - MPU I-37i200.65 519.92 196.60 513.60 49.486519.92Centre Distance Pass - MPU I-37i - MPU I-37i - MPU I-37i200.66 526.50 196.57 519.60 49.028526.50Ellipse Separation Pass - MPU I-37i - MPU I-37i - MPU I-37i1,513.61 5,844.91 1,448.53 4,828.38 23.2565,844.91Clearance Factor Pass - MPU I-37i - MPU I-37PB1 - MPU I-37PB1200.65 519.92 196.60 513.60 49.486519.92Centre Distance Pass - MPU I-37i - MPU I-37PB1 - MPU I-37PB1200.66 526.50 196.57 519.60 49.028526.50Ellipse Separation Pass - MPU I-37i - MPU I-37PB1 - MPU I-37PB11,513.61 5,844.91 1,448.52 4,828.38 23.2545,844.91Clearance Factor Pass - MPU I-38 - MPU I-38 - MPU I-38260.82 572.24 256.48 564.20 60.176572.24Centre Distance Pass - MPU I-38 - MPU I-38 - MPU I-38260.93 601.50 256.42 591.58 57.916601.50Ellipse Separation Pass - MPU I-38 - MPU I-38 - MPU I-38288.42 951.50 281.97 903.01 44.712951.50Clearance Factor Pass - MPU I-38 - MPU I-38PB1 - MPU I-38PB1260.82 572.24 256.48 564.20 60.176572.24Centre Distance Pass - MPU I-38 - MPU I-38PB1 - MPU I-38PB1260.93 601.50 256.42 591.58 57.916601.50Ellipse Separation Pass - 09 January, 2021- 2:25COMPASSPage 4 of 8
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-21i - MPU I-21i wp11Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 26.50 to 5,844.91 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt I Pad - Plan: MPU I-21i - MPU I-21i - MPU I-21i wp11MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPU I-38 - MPU I-38PB1 - MPU I-38PB1288.42 951.50 281.97 903.01 44.712951.50Clearance Factor Pass - MPU I-38 - MPU I-38PB2 - MPU I-38PB2 260.82 572.24 256.48 564.20 60.176572.24Centre Distance Pass - MPU I-38 - MPU I-38PB2 - MPU I-38PB2260.93 601.50 256.42 591.58 57.916601.50Ellipse Separation Pass - MPU I-38 - MPU I-38PB2 - MPU I-38PB2288.42 951.50 281.97 903.01 44.712951.50Clearance Factor Pass - Plan: MPI-07 - MPI-07 - MPI-07288.70 883.22 281.70 886.99 41.249883.22Centre Distance Pass - Plan: MPI-07 - MPI-07 - MPI-07288.76 901.50 281.63 904.61 40.541901.50Ellipse Separation Pass - Plan: MPI-07 - MPI-07 - MPI-07663.99 4,776.50 625.04 3,887.92 17.0474,776.50Clearance Factor Pass - Plan: MPI-07 - Plan: MPU I-07A - MPU I-07A wp05288.70 883.22 281.70 883.99 41.248883.22Centre Distance Pass - Plan: MPI-07 - Plan: MPU I-07A - MPU I-07A wp05288.76 901.50 281.63 901.61 40.541901.50Ellipse Separation Pass - Plan: MPI-07 - Plan: MPU I-07A - MPU I-07A wp05962.61 5,151.50 918.56 3,800.60 21.8505,151.50Clearance Factor Pass - Plan: MPU I-22 - MPU I-22 - MPU I-22 wp03110.24 470.61 106.42 467.38 28.862470.61Centre Distance Pass - Plan: MPU I-22 - MPU I-22 - MPU I-22 wp03110.25 476.50 106.40 473.07 28.610476.50Ellipse Separation Pass - Plan: MPU I-22 - MPU I-22 - MPU I-22 wp03917.45 5,844.91 855.69 5,508.75 14.8555,844.91Clearance Factor Pass - Plan: MPU I-23i - MPU I-23i - MPU I-23i wp03163.85 663.18 158.89 660.11 33.046663.18Centre Distance Pass - Plan: MPU I-23i - MPU I-23i - MPU I-23i wp03163.89 676.50 158.85 673.14 32.532676.50Ellipse Separation Pass - Plan: MPU I-23i - MPU I-23i - MPU I-23i wp031,390.39 5,844.91 1,327.94 4,157.31 22.2665,844.91Clearance Factor Pass - Plan: MPU I-24 - MPU I-24 - MPU I-24 wp02234.17 441.11 230.53 429.74 64.366441.11Centre Distance Pass - Plan: MPU I-24 - MPU I-24 - MPU I-24 wp02234.17 451.50 230.47 439.46 63.312451.50Ellipse Separation Pass - Plan: MPU I-24 - MPU I-24 - MPU I-24 wp021,842.47 5,651.50 1,796.76 3,468.51 40.3115,651.50Clearance Factor Pass - Plan: MPU I-27 - MPU I-27 - MPU I-27 wp0453.76 1,324.09 44.54 1,324.76 5.8291,324.09Centre Distance Pass - Plan: MPU I-27 - MPU I-27 - MPU I-27 wp0453.77 1,326.50 44.53 1,327.15 5.8211,326.50Ellipse Separation Pass - Plan: MPU I-27 - MPU I-27 - MPU I-27 wp0454.23 1,351.50 44.86 1,351.86 5.7871,351.50Clearance Factor Pass - Plan: MPU I-28i - MPU I-28 - MPU I-28i wp05 24.39 719.32 19.08 719.40 4.592719.32Centre Distance Pass - Plan: MPU I-28i - MPU I-28 - MPU I-28i wp0524.41 726.50 19.05 726.54 4.558726.50Ellipse Separation Pass - Plan: MPU I-28i - MPU I-28 - MPU I-28i wp05240.15 5,844.91 185.20 4,891.56 4.3705,844.91Clearance Factor Pass - Plan: MPU I-29 - MPU I-29 - MPU I-29 wp0355.99 428.60 52.40 425.91 15.599428.60Ellipse Separation Pass - Plan: MPU I-29 - MPU I-29 - MPU I-29 wp0360.49 526.50 56.32 520.90 14.490526.50Clearance Factor Pass - Plan: MPU I-30i - MPU I-30i - MPU I-30i wp04143.95 436.39 140.33 430.17 39.719436.39Centre Distance Pass - Plan: MPU I-30i - MPU I-30i - MPU I-30i wp04144.01 451.50 140.29 444.57 38.782451.50Ellipse Separation Pass - Plan: MPU I-30i - MPU I-30i - MPU I-30i wp04170.88 726.50165.53 700.00 31.945726.50Clearance Factor Pass - 09 January, 2021- 2:25COMPASSPage 5 of 8
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-21i - MPU I-21i wp11Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 26.50 to 5,844.91 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt I Pad - Plan: MPU I-21i - MPU I-21i - MPU I-21i wp11MeasuredDepth(usft)Summary Based on MinimumSeparation WarningRig: MPU I-20 - MPU I-20 - MPU I-20 wp0789.92 26.50 88.01 26.50 47.04326.50Centre Distance Pass - Rig: MPU I-20 - MPU I-20 - MPU I-20 wp07 95.95 1,251.50 87.50 1,247.42 11.3581,251.50Ellipse Separation Pass - Rig: MPU I-20 - MPU I-20 - MPU I-20 wp07101.24 1,376.50 91.74 1,369.90 10.6621,376.50Clearance Factor Pass - Rig: MPU I-20 - MPU I-20 - MPU I-2089.92 26.50 88.01 26.45 47.04326.50Centre Distance Pass - Rig: MPU I-20 - MPU I-20 - MPU I-2095.95 1,251.50 87.50 1,247.37 11.3581,251.50Ellipse Separation Pass - Rig: MPU I-20 - MPU I-20 - MPU I-20101.24 1,376.50 91.74 1,369.85 10.6621,376.50Clearance Factor Pass - M Pt J PadMPJ-03 - MPJ-03 - MPJ-031,468.95 5,844.91 1,410.90 5,448.00 25.3045,844.91Clearance Factor Pass - Survey tool programFrom(usft)To(usft)Survey/Plan Survey Tool26.50 2,000.00 MPU I-21i wp11 3_Gyro-MWD90+Sag2,000.00 5,844.91 MPU I-21i wp11 3_MWD+IFR2+MS+Sag5,844.91 16,500.00 MPU I-21i wp11 3_MWD+IFR2+MS+SagEllipse error terms are correlated across survey tool tie-on points.Separation is the actual distance between ellipsoids.Calculated ellipses incorporate surface errors.Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation).Distance Between centres is the straight line distance between wellbore centres.All station coordinates were calculated using the Minimum Curvature method.09 January, 2021- 2:25COMPASSPage 6 of 8
09 January, 2021Milne PointM Pt I PadPlan: MPU I-21iMPU I-21i5002923681MPU I-21i wp11Reference Design: M Pt I Pad - Plan: MPU I-21i - MPU I-21i - MPU I-21i wp11Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Well Coordinates: 6,009,440.21 N, 551,774.01 E (70° 26' 11.53" N, 149° 34' 40.36" W)Datum Height: MPU I-21i As-built RKB @ 60.20usftScan Range: 5,844.91 to 16,500.00 usft. Measured Depth.Geodetic Scale Factor AppliedVersion: 5000.15 Build: 91EScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftNO GLOBAL FILTER: Using user defined selection & filtering criteriaScan Type:Scan Type:25.00
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-21i - MPU I-21i wp11Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 5,844.91 to 16,500.00 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt I Pad - Plan: MPU I-21i - MPU I-21i - MPU I-21i wp11MeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt I PadMPI-04 - MPI-04 - MPI-04 1,720.94 5,844.91 1,658.26 3,735.26 27.4565,844.91Ellipse Separation Pass - MPI-04 - MPI-04 - MPI-041,841.34 6,544.91 1,771.72 4,016.41 26.4516,544.91Clearance Factor Pass - MPI-04 - MPI-04A - MPI-04A 1,720.94 5,844.91 1,658.26 3,735.26 27.4565,844.91Ellipse Separation Pass - MPI-04 - MPI-04A - MPI-04A1,841.34 6,544.91 1,771.72 4,016.41 26.4516,544.91Clearance Factor Pass - MPI-04 - MPI-04AL1 - MPI-04AL11,720.94 5,844.91 1,658.26 3,735.26 27.4565,844.91Ellipse Separation Pass - MPI-04 - MPI-04AL1 - MPI-04AL11,820.54 7,369.91 1,726.84 5,535.00 19.4297,369.91Clearance Factor Pass - MPI-04 - MPI-04APB1 - MPI-04APB11,720.94 5,844.91 1,658.26 3,735.26 27.4565,844.91Ellipse Separation Pass - MPI-04 - MPI-04APB1 - MPI-04APB11,841.34 6,544.91 1,771.72 4,016.41 26.4516,544.91Clearance Factor Pass - MPI-04 - MPI-04PB1 - MPI-04PB11,720.94 5,844.91 1,658.15 3,735.26 27.4085,844.91Ellipse Separation Pass - MPI-04 - MPI-04PB1 - MPI-04PB11,794.28 6,319.91 1,727.16 3,916.25 26.7326,319.91Clearance Factor Pass - MPI-09 - MPI-09 - MPI-091,041.03 6,426.04 977.48 4,334.79 16.3826,426.04Centre Distance Pass - MPI-09 - MPI-09 - MPI-091,056.42 6,669.91 968.40 4,539.71 12.0026,669.91Ellipse Separation Pass - MPI-09 - MPI-09 - MPI-091,351.39 7,669.91 1,174.56 5,254.48 7.6437,669.91Clearance Factor Pass - MPI-17 - MPI-17 - MPI-171,380.92 5,844.91 1,327.15 4,529.75 25.6825,844.91Clearance Factor Pass - MPI-17 - MPI-17L1 - MPI-17L11,380.92 5,844.91 1,327.15 4,529.75 25.6825,844.91Clearance Factor Pass - MPI-17 - MPI-17L1PB1 - MPI-17L1PB11,380.92 5,844.91 1,327.15 4,529.75 25.6825,844.91Clearance Factor Pass - MPI-17 - MPI-17L2 - MPI-17L21,380.92 5,844.91 1,327.15 4,529.75 25.6825,844.91Clearance Factor Pass - MPI-19 - MPI-19 - MPI-197.6010,519.91-86.268,103.560.08110,519.91Ellipse SeparationFAIL - MPI-19 - MPI-19 - MPI-193.5510,544.91-79.308,128.210.04310,544.91Clearance FactorFAIL - MPI-19 - MPI-19 - MPI-192.0810,560.78-41.548,143.820.04810,560.78Centre DistanceFAIL - MPI-19 - MPI-19L1 - MPI-19L146.239,874.473.147,449.741.0739,874.47Centre DistancePass - MPI-19 - MPI-19L1 - MPI-19L151.4710,044.910.287,619.481.00510,044.91Clearance FactorPass - MPI-19 - MPI-19PB1 - MPI-19PB16.759,893.50-33.887,473.450.1669,893.50Centre DistanceFAIL - MPI-19 - MPI-19PB1 - MPI-19PB16.759,894.91-33.947,474.810.1669,894.91Clearance FactorFAIL - MPI-19 - MPI-19PB1 - MPI-19PB156.5410,219.91-52.037,798.150.52110,219.91Ellipse SeparationFAIL - MPI-19 - MPI-19PB2 - MPI-19PB24.2910,727.83-40.958,311.470.09510,727.83Centre DistanceFAIL - MPI-19 - MPI-19PB2 - MPI-19PB210.2910,769.91-116.078,352.500.08110,769.91Clearance FactorFAIL - MPU I-35i - MPU I-35i - MPU I-35i569.65 14,519.91 312.97 13,130.00 2.21914,519.91Clearance Factor Pass - 09 January, 2021- 2:27COMPASSPage 2 of 8
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-21i - MPU I-21i wp11Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 5,844.91 to 16,500.00 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt I Pad - Plan: MPU I-21i - MPU I-21i - MPU I-21i wp11MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPU I-35i - MPU I-35i - MPU I-35i569.49 14,533.35 313.28 13,130.00 2.22314,533.35Centre Distance Pass - MPU I-36 - MPU I-36 - MPU I-36 293.91 10,320.83 193.44 9,532.04 2.92510,320.83Centre Distance Pass - MPU I-36 - MPU I-36 - MPU I-36294.07 10,344.91 193.23 9,553.89 2.91610,344.91Ellipse Separation Pass - MPU I-36 - MPU I-36 - MPU I-36384.45 15,069.91 195.70 14,265.00 2.03715,069.91Clearance Factor Pass - MPU I-36 - MPU I-36PB1 - MPU I-36PB1306.74 10,346.57 195.83 9,560.32 2.76610,346.57Centre Distance Pass - MPU I-36 - MPU I-36PB1 - MPU I-36PB1307.80 10,394.91 195.13 9,599.53 2.73210,394.91Ellipse Separation Pass - MPU I-36 - MPU I-36PB1 - MPU I-36PB1361.94 11,119.91 221.13 10,300.00 2.57011,119.91Clearance Factor Pass - MPU I-36 - MPU I-36PB2 - MPU I-36PB2298.01 10,247.20 197.94 9,452.38 2.97810,247.20Centre Distance Pass - MPU I-36 - MPU I-36PB2 - MPU I-36PB2298.21 10,269.91 197.83 9,471.71 2.97110,269.91Ellipse Separation Pass - MPU I-36 - MPU I-36PB2 - MPU I-36PB2355.07 10,994.91 231.25 10,163.00 2.86810,994.91Clearance Factor Pass - MPU I-37i - MPU I-37i - MPU I-37i916.51 16,275.50 639.42 15,797.00 3.30816,275.50Centre Distance Pass - MPU I-37i - MPU I-37i - MPU I-37i916.71 16,294.91 638.98 15,797.00 3.30116,294.91Ellipse Separation Pass - MPU I-37i - MPU I-37i - MPU I-37i917.58 16,319.91 639.26 15,797.00 3.29716,319.91Clearance Factor Pass - MPU I-37i - MPU I-37PB1 - MPU I-37PB11,258.43 13,295.55 1,024.24 12,809.00 5.37413,295.55Centre Distance Pass - MPU I-37i - MPU I-37PB1 - MPU I-37PB11,259.40 13,344.91 1,023.58 12,809.00 5.34013,344.91Ellipse Separation Pass - MPU I-37i - MPU I-37PB1 - MPU I-37PB11,264.56 13,419.91 1,027.01 12,809.00 5.32313,419.91Clearance Factor Pass - MPU I-38 - MPU I-38 - MPU I-381,822.35 14,980.92 1,569.91 15,500.00 7.21914,980.92Centre Distance Pass - MPU I-38 - MPU I-38 - MPU I-381,822.76 15,019.91 1,569.41 15,500.00 7.19515,019.91Ellipse Separation Pass - MPU I-38 - MPU I-38 - MPU I-381,829.71 15,144.91 1,574.15 15,500.00 7.15915,144.91Clearance Factor Pass - Plan: MPI-07 - MPI-07 - MPI-071,273.52 5,844.91 1,239.35 4,047.00 37.2715,844.91Clearance Factor Pass - Plan: MPI-07 - Plan: MPU I-07A - MPU I-07A wp051,292.35 5,844.91 1,244.75 3,999.12 27.1535,844.91Clearance Factor Pass - Plan: MPU I-22 - MPU I-22 - MPU I-22 wp03791.77 14,823.82 526.02 14,568.95 2.97914,823.82Centre Distance Pass - Plan: MPU I-22 - MPU I-22 - MPU I-22 wp03 792.00 14,844.91 525.32 14,568.95 2.97014,844.91Ellipse Separation Pass - Plan: MPU I-22 - MPU I-22 - MPU I-22 wp03792.85 14,869.91 525.41 14,568.95 2.96514,869.91Clearance Factor Pass - Plan: MPU I-23i - MPU I-23i - MPU I-23i wp031,390.39 5,844.91 1,327.94 4,157.31 22.2665,844.91Centre Distance Pass - Plan: MPU I-23i - MPU I-23i - MPU I-23i wp031,534.94 14,394.91 1,283.15 13,977.74 6.09614,394.91Ellipse Separation Pass - Plan: MPU I-23i - MPU I-23i - MPU I-23i wp031,541.63 14,494.91 1,287.38 13,977.74 6.06414,494.91Clearance Factor Pass - Plan: MPU I-27 - MPU I-27 - MPU I-27 wp04648.92 14,837.05 385.43 13,739.49 2.46314,837.05Centre Distance Pass - Plan: MPU I-27 - MPU I-27 - MPU I-27 wp04659.75 15,944.91 366.78 14,847.22 2.25215,944.91Clearance Factor Pass - Plan: MPU I-29 - MPU I-29 - MPU I-29 wp03647.52 16,354.48 344.45 16,118.98 2.13716,354.48Centre Distance Pass - 09 January, 2021- 2:27COMPASSPage 3 of 8
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-21i - MPU I-21i wp11Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 5,844.91 to 16,500.00 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt I Pad - Plan: MPU I-21i - MPU I-21i - MPU I-21i wp11MeasuredDepth(usft)Summary Based on MinimumSeparation WarningPlan: MPU I-29 - MPU I-29 - MPU I-29 wp03647.72 16,369.91 344.00 16,118.98 2.13316,369.91Clearance Factor Pass - Plan: MPU I-30i - MPU I-30i - MPU I-30i wp04 1,289.67 16,406.40 985.27 16,493.16 4.23716,406.40Centre Distance Pass - Plan: MPU I-30i - MPU I-30i - MPU I-30i wp041,290.37 16,444.91 984.83 16,493.16 4.22316,444.91Ellipse Separation Pass - Plan: MPU I-30i - MPU I-30i - MPU I-30i wp041,293.37 16,494.91 986.81 16,493.16 4.21916,494.91Clearance Factor Pass - Rig: MPU I-20 - MPU I-20 - MPU I-20 wp07699.58 14,848.34 420.98 13,613.37 2.51114,848.34Centre Distance Pass - Rig: MPU I-20 - MPU I-20 - MPU I-20 wp07708.27 16,500.00 385.39 15,264.85 2.19416,500.00Clearance Factor Pass - Rig: MPU I-20 - MPU I-20 - MPU I-20890.74 5,844.91 828.53 4,773.36 14.3205,844.91Centre Distance Pass - Rig: MPU I-20 - MPU I-20 - MPU I-20901.18 6,194.91 817.99 5,121.00 10.8336,194.91Clearance Factor Pass - Rig: MPU I-20 - MPU I-20 - MPU I-20900.87 6,219.91 817.93 5,121.00 10.8636,219.91Ellipse Separation Pass - M Pt J PadMPJ-01 - MPJ-01 - MPJ-01783.56 11,319.91 664.25 4,300.81 6.56811,319.91Clearance Factor Pass - MPJ-01 - MPJ-01 - MPJ-01783.12 11,344.91 664.05 4,309.62 6.57711,344.91Ellipse Separation Pass - MPJ-01 - MPJ-01 - MPJ-01783.12 11,348.13 664.08 4,310.75 6.57911,348.13Centre Distance Pass - MPJ-01 - MPJ-01A - MPJ-01A101.3312,810.6325.945,736.891.34412,810.63Centre DistancePass - MPJ-01 - MPJ-01A - MPJ-01A113.0113,019.9120.865,940.741.22613,019.91Ellipse SeparationPass - MPJ-01 - MPJ-01A - MPJ-01A122.3213,119.9121.546,035.561.21413,119.91Clearance FactorPass - MPJ-01 - MPJ-01AL1 - MPJ-01AL1194.4112,269.9147.965,203.111.32712,269.91Clearance FactorPass - MPJ-01 - MPJ-01AL1 - MPJ-01AL1191.3612,324.4851.255,240.521.36612,324.48Centre DistancePass - MPJ-03 - MPJ-03 - MPJ-03 583.81 7,194.91 455.96 5,445.66 4.5667,194.91Clearance Factor Pass - MPJ-03 - MPJ-03 - MPJ-03582.72 7,219.91 455.65 5,428.274.5867,219.91Ellipse Separation Pass - MPJ-03 - MPJ-03 - MPJ-03582.11 7,256.84 456.52 5,402.60 4.6357,256.84Centre Distance Pass - MPJ-06 - MPJ-06 - MPJ-06415.42 11,394.91 275.25 4,618.03 2.96411,394.91Clearance Factor Pass - MPJ-06 - MPJ-06 - MPJ-06408.54 11,444.91 271.53 4,647.67 2.98211,444.91Ellipse Separation Pass - MPJ-06 - MPJ-06 - MPJ-06405.53 11,505.98 274.68 4,682.45 3.09911,505.98Centre Distance Pass - MPJ-08 - MPJ-08 - MPJ-08403.53 11,529.60 344.72 4,502.51 6.86111,529.60Centre Distance Pass - MPJ-08 - MPJ-08 - MPJ-08423.11 11,719.91 328.68 4,650.80 4.48111,719.91Ellipse Separation Pass - MPJ-08 - MPJ-08 - MPJ-081,123.48 15,669.91 762.17 8,593.00 3.11015,669.91Clearance Factor Pass - MPJ-08 - MPJ-08A - MPJ-08A403.53 11,529.60 344.72 4,503.31 6.86111,529.60Centre Distance Pass - MPJ-08 - MPJ-08A - MPJ-08A423.11 11,719.91 328.68 4,651.60 4.48111,719.91Ellipse Separation Pass - MPJ-08 - MPJ-08A - MPJ-08A508.84 11,994.91 365.73 4,854.29 3.55611,994.91Clearance Factor Pass - 09 January, 2021- 2:27COMPASSPage 4 of 8
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-21i - MPU I-21i wp11Survey tool programFrom(usft)To(usft)Survey/Plan Survey Tool26.50 2,000.00 MPU I-21i wp11 3_Gyro-MWD90+Sag2,000.00 5,844.91 MPU I-21i wp11 3_MWD+IFR2+MS+Sag5,844.91 16,500.00 MPU I-21i wp11 3_MWD+IFR2+MS+SagEllipse error terms are correlated across survey tool tie-on points.Separation is the actual distance between ellipsoids.Calculated ellipses incorporate surface errors.Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation).Distance Between centres is the straight line distance between wellbore centres.All station coordinates were calculated using the Minimum Curvature method.09 January, 2021- 2:27COMPASSPage 6 of 8
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-21i - MPU I-21i wp11Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 5,844.91 to 16,500.00 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt I Pad - Plan: MPU I-21i - MPU I-21i - MPU I-21i wp11MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPJ-09 - MPJ-09 - MPJ-091,103.19 11,205.36 1,020.44 4,204.30 13.33311,205.36Centre Distance Pass - MPJ-09 - MPJ-09 - MPJ-09 1,110.77 11,344.91 1,013.59 4,254.57 11.43011,344.91Ellipse Separation Pass - MPJ-09 - MPJ-09 - MPJ-091,562.56 12,494.91 1,342.92 5,321.09 7.11412,494.91Clearance Factor Pass - MPJ-09 - MPJ-09A - MPJ-09A1,103.19 11,205.36 1,020.45 4,204.57 13.33411,205.36Centre Distance Pass - MPJ-09 - MPJ-09A - MPJ-09A1,110.77 11,344.91 1,013.61 4,254.84 11.43211,344.91Ellipse Separation Pass - MPJ-09 - MPJ-09A - MPJ-09A1,562.56 12,494.91 1,343.38 5,321.38 7.12912,494.91Clearance Factor Pass - MPJ-11 - MPJ-11 - MPJ-11323.42 13,319.91 179.39 5,503.02 2.24613,319.91Clearance Factor Pass - MPJ-11 - MPJ-11 - MPJ-11321.79 13,344.91 179.10 5,521.06 2.25513,344.91Ellipse Separation Pass - MPJ-11 - MPJ-11 - MPJ-11320.97 13,379.06 180.99 5,545.71 2.29313,379.06Centre Distance Pass - MPJ-12 - MPJ-12 - MPJ-121,250.39 11,868.26 1,103.21 4,515.04 8.49511,868.26Centre Distance Pass - MPJ-12 - MPJ-12 - MPJ-121,250.61 11,894.91 1,103.16 4,528.77 8.48211,894.91Ellipse Separation Pass - MPJ-12 - MPJ-12 - MPJ-121,253.34 11,969.91 1,105.30 4,572.19 8.46611,969.91Clearance Factor Pass - MPJ-15 - MPJ-15 - MPJ-151,152.98 13,158.69 985.81 5,270.98 6.89713,158.69Centre Distance Pass - MPJ-15 - MPJ-15 - MPJ-151,173.18 13,519.91 960.12 5,530.59 5.50613,519.91Ellipse Separation Pass - MPJ-15 - MPJ-15 - MPJ-151,431.80 14,544.91 1,119.09 6,389.70 4.57914,544.91Clearance Factor Pass - MPJ-16 - MPJ-16 - MPJ-16241.7813,742.9748.686,092.421.25213,742.97Centre DistancePass - MPJ-16 - MPJ-16 - MPJ-16254.5013,894.913.186,220.721.01313,894.91Clearance FactorPass - MPJ-18 - MPJ-18 - MPJ-181,339.58 11,373.35 1,280.43 3,866.96 22.64811,373.35Centre Distance Pass - MPJ-18 - MPJ-18 - MPJ-181,346.51 11,544.91 1,274.38 3,975.77 18.66711,544.91Ellipse Separation Pass - MPJ-18 - MPJ-18 - MPJ-181,840.47 12,969.91 1,645.71 4,855.49 9.45012,969.91Clearance Factor Pass - MPJ-22 - MPJ-22 - MPJ-22958.71 9,904.52 903.14 3,946.08 17.2519,904.52Centre Distance Pass - MPJ-22 - MPJ-22 - MPJ-22959.53 9,944.91 902.21 3,953.64 16.7389,944.91Ellipse Separation Pass - MPJ-22 - MPJ-22 - MPJ-22 1,133.87 10,494.91 1,043.65 4,043.13 12.56810,494.91Clearance Factor Pass - MPJ-25 - MPJ-25 - MPJ-25340.59 11,061.67 286.35 4,178.76 6.27911,061.67Centre Distance Pass - MPJ-25 - MPJ-25 - MPJ-25345.18 11,119.91 284.16 4,190.16 5.65711,119.91Ellipse Separation Pass - MPJ-25 - MPJ-25 - MPJ-25383.70 11,244.91 304.33 4,224.40 4.83411,244.91Clearance Factor Pass - MPJ-25 - MPJ-25PB1 - MPJ-25PB1317.35 11,088.51 244.77 4,265.02 4.37211,088.51Centre Distance Pass - MPJ-25 - MPJ-25PB1 - MPJ-25PB1326.47 11,169.91 238.18 4,291.99 3.69811,169.91Ellipse Separation Pass - MPJ-25 - MPJ-25PB1 - MPJ-25PB1360.48 11,269.91 254.75 4,323.85 3.40911,269.91Clearance Factor Pass - 09 January, 2021- 2:27COMPASSPage 5 of 8
1
Davies, Stephen F (CED)
From:Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Sent:Friday, January 15, 2021 12:56 PM
To:Davies, Stephen F (CED)
Cc:Rebecca Emerson
Subject:MPU i-21 Table update.pdf
Attachments:MPU i-21 Table update.pdf
Steve,
Please see attached for Formation Table update.
Thanks!
Joe
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Page 44 Version 2
Milne Point Unit
I-21 SB Injector
Drilling Procedure
22.0 Formation Tops & Information
1
Davies, Stephen F (CED)
From:Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Sent:Friday, January 15, 2021 12:23 PM
To:Davies, Stephen F (CED); Rebecca Emerson
Cc:Rixse, Melvin G (CED)
Subject:RE: [EXTERNAL] FW: REVISED MPU I-21 (PTD #220-051)
Attachments:AOR for MPI-21 1-15-21.pdf
Steve,
Please see attached for revised AOR review table for MPU I‐21 including J‐25PB1. If you have questions or need
additional information, please let me know. Thanks!
Thanks,
Joe Lastufka
Sr. Drilling Technologist
Hilcorp North Slope, LLC
Office: (907)777-8400, Cell:(907)227-8496
From: Davies, Stephen F (CED) <steve.davies@alaska.gov>
Sent: Friday, January 15, 2021 11:36 AM
To: Rebecca Emerson <Rebecca.Emerson@hilcorp.com>
Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Rixse, Melvin G (CED) <melvin.rixse@alaska.gov>
Subject: RE: [EXTERNAL] FW: REVISED MPU I‐21 (PTD #220‐051)
Hi Rebecca,
This mistake was mine: When I drew my AOR yesterday the radius was wrong—it was too large, so the Oba intercepts
for most of the wells on my most recent list lie outside of the actual AOR. So, I agree with your revised list with three
exceptions, I‐17 and I‐17L1 (which on my map will lie about 1200’ from the Oba intercept for I‐21) and the J‐25 plugback
wellbore, which lies about 500’ from the I‐21 injection interval. Let me know if you disagree.
Thanks and stay safe,
Steve Davies
Alaska Oil and Gas Conservation Commission (AOGCC)
CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission
(AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use
or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding
it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov.
From: Rebecca Emerson <Rebecca.Emerson@hilcorp.com>
Sent: Friday, January 15, 2021 9:21 AM
To: Davies, Stephen F (CED) <steve.davies@alaska.gov>
Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Subject: RE: [EXTERNAL] FW: REVISED MPU I‐21 (PTD #220‐051)
Hi Steve,
2
I don’t think we have met – I am the geologist working Milne Point Schrader Bluff. I came over to Hilcorp from BP in
July.
Joe Lastufka asked me to clarify some more information for the I‐21 AOR about this list of wells that you provided him. I
thought it might be easier if I talked directly to you.
The well paths for the list of wells below do lie within the AOR, but they are the surface hole sections in the overburden
above the Schrader Bluff, so it is my understanding that they do not need to be reviewed. I am trying to show this by
placing the well symbols at the OBa (injection sand for I‐21) top location so that you can follow the wall path and see
that it is outside of the AOR by the time we get to the zone. (example 1 on my screenshot below)
For wells that don’t have an OBa top because they don’t ever get that deep, the well symbol plots at the bottom hole
location, and when that falls within the AOR I list it on the AOR list to make clear that they are not in the injection
sand. (example 2 on my screenshot below)
The wells which are in the zone and within the AOR have their points shown midway along the wellbore. (example 3 on
my screenshot below)
Hopefully this helps to clarify a bit – I will give you a call shortly to follow up and answer any more questions you have.
Thank you,
Rebecca
3
4
5
Rebecca Emerson
Geoscientist ‐ Alaska North Slope
Hilcorp Alaska, LLC
907‐590‐0648 (cell)
JL Tower 13070
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
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While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission,
opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and
the recipient should carry out such virus and other checks as it considers appropriate.
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed
above, then promptly and permanently delete this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission,
opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and
the recipient should carry out such virus and other checks as it considers appropriate.
1
Davies, Stephen F (CED)
From:Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Sent:Thursday, January 14, 2021 3:00 PM
To:Davies, Stephen F (CED)
Subject:RE: [EXTERNAL] FW: REVISED MPU I-21 (PTD #220-051)
Attachments:MPI-21 AOR Map Extended_Fixed.pdf; AOR for MPI-21 1-14-21.pdf
Steve,
MPU J‐04A is actually MPU J‐01A. Please see the updated map for a more legible label. J‐01A and J‐01AL1 are on the
initial AOR. Both wells are currently in suspended status. They have been permanently abandoned since the initial AOR
and this is reflected in the updated table.
MPU I‐17 and I‐17L1 were erroneously shown within the AOR circle on the AOR Map submitted yesterday but these
wells are outside the AOR and in a different fault block; this is fixed on the updated map.
MPU I‐20 has been added to the AOR table. It is the producer which I‐21 will support. It’s surface hole was drilled in
June and the lateral will be drilled shortly after I‐21 is drilled. The map has been updated to show the lateral as well as
the surface section.
MPU J‐03 (suspended) has been added to the AOR table.
Thanks again for bringing this to my attention and please don’t hesitate to let me know if you have any additional
questions. Thanks!
Thanks,
Joe Lastufka
Sr. Drilling Technologist
Hilcorp North Slope, LLC
Office: (907)777-8400, Cell:(907)227-8496
From: Davies, Stephen F (CED) <steve.davies@alaska.gov>
Sent: Thursday, January 14, 2021 9:49 AM
To: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Subject: [EXTERNAL] FW: REVISED MPU I‐21 (PTD #220‐051)
Joe,
On the Area of Review (AOR) illustration, I notice that there are several well intercepts that appear to lie within the AOR
that are not included in the Area of Review table. They are, from north to south: J‐04A, J‐03, I‐20, I‐17, and I‐17L1. Since
Hilcorp is requesting quick turnaround for the AOGCC’s review of this application, any information Hilcorp can provide
regarding these wells will be most helpful. Please submit a revised AOR table if necessary.
Thanks and stay safe,
Steve Davies
Alaska Oil and Gas Conservation Commission (AOGCC)
2
CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission
(AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use
or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding
it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov.
From: Davies, Stephen F (CED) <steve.davies@alaska.gov>
Sent: Thursday, January 14, 2021 8:59 AM
To: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Cc: Boyer, David L (CED) <david.boyer2@alaska.gov>
Subject: RE: REVISED MPU I‐21 (PTD #220‐051)
Joe,
Thanks for the digital directional data, it is appreciated.
Quick questions:
On page 46, Hilcorp states: “Gas hydrates have been seen on E‐Pad.” On page 48, Hilcorp states: “Abnormal
pressure has been seen on E‐Pad.” Are these cut‐and‐paste errors or oversights? Have hydrates, abnormal
pressures, or abnormal temperatures been encountered on I‐Pad?
Also on page 47 and 48, Hilcorp states that no H2S has not been encountered in wells drilled on this pad. In light
of the “E‐Pad” reference above, please confirm that this statement is accurate for I‐Pad wells.
Is the Generalized Geological Forecast illustration presented on page 45 accurate for I‐Pad? All wells mentioned
on that forecast illustration are E‐Pad wells.
Please confirm that all other drilling hazards information presented in the application is accurate for I‐Pad and
specifically for well I‐21.
Thanks and stay safe,
Steve Davies
Alaska Oil and Gas Conservation Commission (AOGCC)
CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission
(AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use
or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding
it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov.
From: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Sent: Wednesday, January 13, 2021 5:02 PM
To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov>
Cc: Davies, Stephen F (CED) <steve.davies@alaska.gov>; Boyer, David L (CED) <david.boyer2@alaska.gov>
Subject: REVISED MPU I‐21 (PTD #220‐051)
Hello,
Please see attached REVISED Permit to Drill for MPU I‐21. Please expedite if possible. If you have any questions, please
let me know. Thanks!
Thanks,
Joe Lastufka
3
Sr. Drilling Technologist
Hilcorp North Slope, LLC
Office: (907)777-8400, Cell:(907)227-8496
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed
above, then promptly and permanently delete this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission,
opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and
the recipient should carry out such virus and other checks as it considers appropriate.
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed
above, then promptly and permanently delete this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission,
opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and
the recipient should carry out such virus and other checks as it considers appropriate.
1
Davies, Stephen F (CED)
From:Joseph Engel <jengel@hilcorp.com>
Sent:Thursday, January 14, 2021 9:45 AM
To:Joseph Lastufka
Cc:Davies, Stephen F (CED)
Subject:RE: [EXTERNAL] RE: REVISED MPU I-21 (PTD #220-051)
Attachments:MPU i-21 Drilling Program Version 3, pages 45-49.pdf
Steve –
Thanks for the email. My apologies on the mix‐up with E pad writing and formation notes, Those were overlooked.
Attached are the updated pages 45‐49 with reference to I pad and i‐21.
Hydrates and abnormal pressures have been noted on I pad in the past (2002ish), but of the recent wells we
have drilled on ipad in 2019/2020 (i‐35,36,38,39) we have not seen any hydrates or abnormal pressure.
Precautionary measures will still be in place in case they are see on i‐21.
No H2s has been documented or seen on I pad.
General Geologic Forecast has been update for I pad and I pad wells.
All other hazard information is specifc to I pad and i‐21.
Sorry for the mix up. Please let me know if you have any other questions .
Thank you for your time.
‐Joe Engel
From: Davies, Stephen F (CED) <steve.davies@alaska.gov>
Sent: Thursday, January 14, 2021 8:59 AM
To: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Cc: Boyer, David L (CED) <david.boyer2@alaska.gov>
Subject: [EXTERNAL] RE: REVISED MPU I‐21 (PTD #220‐051)
Joe,
Thanks for the digital directional data, it is appreciated.
Quick questions:
On page 46, Hilcorp states: “Gas hydrates have been seen on E‐Pad.” On page 48, Hilcorp states: “Abnormal
pressure has been seen on E‐Pad.” Are these cut‐and‐paste errors or oversights? Have hydrates, abnormal
pressures, or abnormal temperatures been encountered on I‐Pad?
Also on page 47 and 48, Hilcorp states that no H2S has not been encountered in wells drilled on this pad. In light
of the “E‐Pad” reference above, please confirm that this statement is accurate for I‐Pad wells.
Is the Generalized Geological Forecast illustration presented on page 45 accurate for I‐Pad? All wells mentioned
on that forecast illustration are E‐Pad wells.
Please confirm that all other drilling hazards information presented in the application is accurate for I‐Pad and
specifically for well I‐21.
Thanks and stay safe,
2
Steve Davies
Alaska Oil and Gas Conservation Commission (AOGCC)
CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission
(AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use
or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding
it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov.
From: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Sent: Wednesday, January 13, 2021 5:02 PM
To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov>
Cc: Davies, Stephen F (CED) <steve.davies@alaska.gov>; Boyer, David L (CED) <david.boyer2@alaska.gov>
Subject: REVISED MPU I‐21 (PTD #220‐051)
Hello,
Please see attached REVISED Permit to Drill for MPU I‐21. Please expedite if possible. If you have any questions, please
let me know. Thanks!
Thanks,
Joe Lastufka
Sr. Drilling Technologist
Hilcorp North Slope, LLC
Office: (907)777-8400, Cell:(907)227-8496
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed
above, then promptly and permanently delete this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission,
opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and
the recipient should carry out such virus and other checks as it considers appropriate.
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed
above, then promptly and permanently delete this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission,
opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and
the recipient should carry out such virus and other checks as it considers appropriate.
Revised 2/2015
TRANSMITTAL LETTER CHECKLIST
WELL NAME: ______________________________________
PTD: _____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD: ____________________________ POOL: ______________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
No. _____________, API No. 50-_______________________.
Production should continue to be reported as a function of the original
API number stated above.
Pilot Hole
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 name (_______________________PH) and API number
(50-_____________________) from records, data and logs acquired for
well (name on permit).
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce/inject is contingent upon issuance of
a conservation order approving a spacing exception.
(_____________________________) as Operator assumes the liability
of any protest to the spacing exception that may occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in no greater
than 30' sample intervals from below the permafrost or from where
samples are first caught and 10' sample intervals through target zones.
Non-
Conventional
Well
Please note the following special condition of this permit:
Production or production testing of coal bed methane is not allowed for
well ( ) until after ( )
has designed and implemented a water well testing program to provide
baseline data on water quality and quantity.
(________________________) must contact the AOGCC to obtain
advance approval of such water well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by (_______________________________) in the attached application,
the following well logs are also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for well logs run must be submitted to the AOGCC
within 90 days after completion, suspension or abandonment of this
well.
MPU I-21
X
220-051
Schrader Bluff OilMilne Point
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Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M. Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Re: Milne Point Field, Schrader Bluff Oil Pool, MPU I-21
Hilcorp Alaska, LLC
Permit to Drill Number: 220-051
Surface Location: 2324' FSL, 3597' FEL, Sec 33, T13N, R10E, UM, AK
Bottomhole Location: 1854' FSL, 1569' FWL, Sec 21, 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,
Jeremy M. Price
Chair
DATED this ___ day of June, 2020.
y,
11
1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for:
Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates
Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas
2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number:
Bond No.
3. Address:6. Proposed Depth: 12. Field/Pool(s):
MD: 13,921' TVD: 4,160'
4a. Location of Well (Governmental Section):7. Property Designation:
Surface:
Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date:
Total Depth:9. Acres in Property: 14. Distance to Nearest Property:
4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 60.2' 15. Distance to Nearest Well Open
Surface: x-551774 y- 6009440 Zone-4 33.7' to Same Pool: 170' to MPU J-16
16. Deviated wells:Kickoff depth: 280 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 89 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
Cond 20" 129.5 X-56 Weld 107' Surface Surface 107' 107'
9-5/8" 47# L-80 TXP 2,000' Surface Surface 2,000' 1,949'
9-5/8" 40# L-80 TXP 2,998' 2,000' 1,949' 4,998' 4,010'
8-1/2" 4-1/2" 13.5# L-80 Hydril 625 9,073' 4,848' 3,984' 13,921' 4,160'
Tieback 3-1/2" 9.3 L-80 EUE 8Rd 4,848' Surface Surface 4,848' 3,984'
19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations)
Junk (measured):
TVD
Hydraulic Fracture planned?Yes No
20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis
Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements
Contact Name:
Contact Email:
Contact Phone:
Date:
Permit to Drill API Number: Permit Approval
Number:50- Date:
Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales:
Samples req'd: Yes No Mud log req'd: Yes No
H2S measures: Yes No Directional svy req'd: Yes No
Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No
Post initial injection MIT req'd: Yes No
APPROVED BY
Approved by: COMMISSIONER THE COMMISSION Date:
Sr Pet Eng Sr Pet Geo Sr Res Eng
3452' to nearest unit boundary
7/10/2020
Authorized Name: Monty Myers
Authorized Title: Drilling Manager
Joe Engel
jengel@hilcorp.com
777-8395
18. Casing Program:Top - Setting Depth - BottomSpecifications
MPU I-21
Milne Point Field
Schrader Bluff Oil Pool
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
Hilcorp Alaska, LLC
2324' FSL, 3597' FEL, Sec 33, T13N, R10E, UM, AK ADL025906, ADL315848
022224484
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
Stg 2 L - 1937 ft3 / T - 314 ft3
1363
1738' FNL, 723' FWL, Sec 33, T13N, R10E, UM, AK
1854' FSL, 1569' FWL, Sec 21, T13N, R10E, UM, AK
LONS 88-004
3840
1764
Total Depth MD (ft):Total Depth TVD (ft):
Cement Quantity, c.f. or sacks
Cement Volume MDSize
Plugs (measured):
(including stage data)
Driven
Stg 1 L - 610 ft3 / T - 458 ft3
Effect. Depth TVD (ft):
Conductor/Structural
Length
Cementless Liner w/ ICDs and Pkrs
Tieback Assy.
Production
Liner
Casing
Intermediate
Commission Use Only
Effect. Depth MD (ft):
Authorized Signature:
See cover letter for other
requirements.
Perforation Depth MD (ft):
21. I hereby certify that the foregoing is true and the procedure approved herein will not be
deviated from without prior written approval.
Surface
Perforation Depth TVD (ft):
GL / BF Elevation above MSL (ft):
6/8/2020
12-1/4"
es N
ype of W
L
l R
L
1b
S
Class:
os N es No
s N o
D s
s
s
D
84
o
:
well is p
G
S
S
20
S S
S
es No s No
S
G
E
S
es No
s
Form 10-401 Revised 3/2020 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
By Samantha Carlisle at 12:06 pm, Jun 08, 2020
Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp AK, ou=Drilling Manager,
email=mmyers@hilcorp.com
Reason: I am approving this document
Location: Anchorage AK
Date: 2020.06.08 10:50:29 -08'00'
Monty M
Myers
X
220-051
Service - WinjSS
X
X
gls 6/10/20
*3000 psi BOPE test
* Submit FIT data with 10-407 X
DLB 06/09/2020
X
029-23681-00-00
DSR-6/8/2020
X
X
X
s6/10/20s6/10/20
6/11/2020
6/11/2020
Area of Review MPI-21PTD API WELL STATUSTop of SB OBa (MD)Top of SB OBa (TVD)CBL Top of Cement (MD)CBL Top of Cement (TVD)Schrader OBa statusZonal Isolation194-11450-029-22502-00-00 MPU J-11 Kuparuk WINJ5416' 4125' 3900' 3166' ClosedCased and Cemented - 51 bbls of cement pumped thru stage collar at 5,739' MD. 194-11850-029-22506-00-00 MPU J-12SB OA/OB WINJ Shut in4515' 4029' 3533' 3245' ClosedCased and Cemented - 30 bbls of cement pumped thru stage collar at 4,861' MD. 195-16950-029-22615-00-00 MPU J-16 Kuparuk WINJ Shut in6180' 4127' 2998' 2529' ClosedCased and Cemented - 38 bbls of cement pumped thru stage collar at 4681' MD. 190-09550-029-22070-00-00 MPU J-01 Well Sidetracked4257' 4080' 3000' 2837' ClosedCement Retainer set at 3,670' MD, 18 bbls cement pumped below. 199-11150-029-22070-01-00 MPU J-01A OA Lateral Shut inN/A N/A N/A N/A Closed N/A201-02150-029-22070-60-00 MPU J-01AL1 OBa lateral Shut in5155' 4105' N/A N/A OpenSundry currently being prepared to fully abandon reservoir. Plan is to conduct this work prior to injecting in to MPU I-21194-09550-029-22493-00-00 MPU J-06 Kuparuk Prod4526' 4089' 3640' 3435' ClosedCased and Cemented - ~31 bbls of cement pumped thru stage collar at 5,013' MD. 194-106 50-029-22497-00-00 MPU J-08 P&Ad SidetrackedN/A N/A N/A N/A N/A Not open lateral in OA199-17750-029-22497-01-00MPU J-08A SB OB Prod Shut in 5788' 4110' 4714' 3808' Open Open to Injection Support204-073 50-029-23207-00-00 MPU J-25 NB Lateral N/A N/A N/A N/A Not Open Lateral in above NB Sand195-151 50-029-22602-00-00 MPU I-07 Shut in SB Producer3994' 3970' 3100' 2977' OpenOpen to Injection Support204-135 50-029-23218-00-00 MPU I-19 OBa lateral P&Ad7758' 4091' 3334' 2680' P&Ad35 bbls of 15.8 ppg cmt pumped in lateral from 9,679' - 7,380' MD.MPU J-01AClose crossing with J-01 and I-19MPU I-19OBa lateral P&AdNOTE: J-01A / L1 will beP&A'dMPU J-01AL1
Area of Review MPI-21204-13650-029-23218-60-00 MPU I-19L1 N/A OA Lateral P&A'dN/A N/A N/A N/A N/A77 bbls of 15.8 ppg cmt pumped in lateral from 12,000' - 7,104' MD. TOC tagged at 7200' MD 4/15/20. 220-034 50-029-23675-00-00 MPU I-35 NB WINJN/A N/A N/A N/A Not Open N/A220-047 50-029-23677-00-00 MPU I-36 NB Prod (In progress)N/A N/A N/A N/A Not Open N/AN/A OA Lateral P&A'dMPU I-19L1
IJ2128293332J-0J-07J-06J-09J-08J-08AJ-10J-11J-12J-13I-05G-15I-08J-21J-1720J-22J-15I-09G-14I15G-17J-26J-26L1J-25I-17I-17L1I-14I-19I-16H-18H-16I-18WSAK 25I-04I-04AJ-01J-01AL1J-03I-07J-19J-19AJ-16I-35I-36I-21 wp03aHILCORP ALASKA LLCMILNE POINTAOR MAPI-21 Injector (Proposed)FEET0 1,000 2,000WELL SYMBOLSActive OilShut In OilINJ Well (Water Flood)P&A OilAbandoned InjectorInjector LocationProducer LocationShut In INJREMARKSWell Symbols at top of Schrader Bluff OBa Sand.Black dash circle = 1320' radius from OBa sand in heeland toe of proposed I-21 drill well. Well symbols at TDo fwell denote well that never reached OBa sand but isin the Schrader BluffJune 5, 2020PETRA 6/5/2020 8:04:33 AMI--I-199-199-P &A'd SBdual lateralshut-inKup InjJ-16J11-66
Milne Point Unit
(MPU) I-21
Drilling Program
Version 1
6/5/2020
Table of Contents
1.0 Well Summary ........................................................................................................................... 2
2.0 Management of Change Information ........................................................................................ 3
3.0 Tubular Program:...................................................................................................................... 4
4.0 Drill Pipe Information: .............................................................................................................. 4
5.0 Internal Reporting Requirements ............................................................................................. 5
6.0 Planned Wellbore Schematic ..................................................................................................... 6
7.0 Drilling / Completion Summary ................................................................................................ 7
8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 8
9.0 RU and Preparatory Work ...................................................................................................... 10
10.0 NU 13-5/8” 5M Diverter Configuration .................................................................................. 11
11.0 Drill 12-1/4” Hole Section ........................................................................................................ 13
12.0 Run 9-5/8” Surface Casing ...................................................................................................... 17
13.0 Cement 9-5/8” Surface Casing ................................................................................................. 23
14.0 BOP NU and Test..................................................................................................................... 28
15.0 Drill 8-1/2” Hole Section .......................................................................................................... 29
16.0 Run 4-1/2” Injection Liner (Lower Completion) .................................................................... 34
17.0 Run 3-1/2” Tubing (Upper Completion) ................................................................................. 38
18.0 Innovation Rig Diverter Schematic ......................................................................................... 40
19.0 Innovation Rig BOP Schematic ............................................................................................... 41
20.0 Wellhead Schematic ................................................................................................................. 42
21.0 Days Vs Depth .......................................................................................................................... 43
22.0 Formation Tops & Information............................................................................................... 44
23.0 Anticipated Drilling Hazards .................................................................................................. 45
24.0 Innovation Rig Layout ............................................................................................................. 48
25.0 FIT Procedure .......................................................................................................................... 49
26.0 Innovation Rig Choke Manifold Schematic ............................................................................ 50
27.0 Casing Design ........................................................................................................................... 51
28.0 8-1/2” Hole Section MASP ....................................................................................................... 52
29.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 53
30.0 Surface Plat (As Built) (NAD 27) ............................................................................................. 54
Innovation Rig Choke Manifold Schematic ............................................................................ 5
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Drilling Procedure
1.0 Well Summary
Well MPU I-21
Pad Milne Point “I” Pad
Planned Completion Type 3-1/2” Injection Tubing
Target Reservoir(s) Schrader Bluff Ob Sand
Planned Well TD, MD / TVD 13,921’ MD / 4,010’ TVD
PBTD, MD / TVD 13,911’ MD / 4,010’ TVD
Surface Location (Governmental) 2324' FSL, 3597' FEL, Sec 33, T13N, R10E, UM, AK
Surface Location (NAD 27) X= 551,774 Y= 6,009,440
Top of Productive Horizon
(Governmental) 1738' FNL, 723' FWL, Sec 33, T13N, R10E, UM, AK
TPH Location (NAD 27) X= 550,802 Y= 6,010,651
BHL (Governmental) 1854' FSL, 1569' FWL, Sec 21, T13N, R10E, UM, AK
BHL (NAD 27) X= 551,564 Y=6,019,528
AFE Number 2011857
AFE Drilling Days 17 days
AFE Completion Days 3 days
AFE Drilling Amount $3,628,670
AFE Completion Amount $1,515,889
AFE Facility Amount $292,800
Maximum Anticipated Pressure
(Surface) 1,363 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 1,764 psig
Work String 5”, 19.5#, S-135, DS-50 & NC 50
KB Elevation above MSL: 26.5 ft + 33.4 ft = 59.9 ft
GL Elevation above MSL: 33.4 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
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I-21 SB Injector
Drilling Procedure
2.0 Management of Change Information
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I-21 SB Injector
Drilling Procedure
3.0 Tubular Program:
Hole
Section
OD (in) ID (in) Drift
(in)
Conn OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 20” 19.250” - - - X-52 Weld
12-1/4” 9-5/8” 8.835” 8.679” 10.625” 40 L-80 TXP 5,750 3,090 916
8-1/2” 4-1/2” 3.960” 3.795” 4.714” 13.5 L-80 H625 9,020 8,540 279
Tubing 3-1/2” 2.992” 2.897” 4.500” 9.3 L-80 TXP-SR 9,289 7,399 163
4.0 Drill Pipe Information:
Hole
Section
OD
(in)
ID (in) TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn M/U
(Min)
M/U
(Max)
Tension
(k-lbs)
Surface &
Production
5” 4.276” 3.25” 6.625” 19.5 S-135 GPDS50 36,100 43,100 560klb
5” 4.276” 3.25” 6.625” 19.5 S-135 NC50 31,032 34,136 560klb
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
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I-21 SB Injector
Drilling Procedure
5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on WellEz.
x Report covers operations from 6am to 6am
x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left
of the data entry area – this will not save the data entered, and will navigate to another data entry.
x Ensure time entry adds up to 24 hours total.
x Try to capture any out of scope work as NPT. This helps later on when we pull end of well
reports.
x Enter the MD and TVD depths EVERY DAY whether you are making hole or not.
5.2 Afternoon Updates
x Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers@hilcorp,
jengel@hilcorp.com and cdinger@hilcorp.com
5.3 Intranet Home Page Morning Update
x Submit a short operations update each morning by 7am on the company intranet homepage. On
weekend and holidays, ensure to have this update in before 5am.
5.4 EHS Incident Reporting
x Health and Safety: Notify EHS field coordinator.
x Environmental: Drilling Environmental Coordinator
x Notify Drilling Manager & Drilling Engineer on all incidents
x Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
x Send final “As-Run” Casing tally to mmyers@hilcorp,com jengel@hilcorp.com and
cdinger@hilcorp.com
5.6 Casing and Cement report
x Send casing and cement report for each string of casing to mmyers@hilcorp.com
jengel@hilcorp.com and cdinger@hilcorp.com
5.7 Hilcorp Milne Point Contact List:
Title Name Work Phone Cell Phone Email
Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmyers@hilcorp.com
Drilling Engineer Joe Engel 907.777.8395 805.235.6265 jengel@hilcorp.com
Completion Engineer Ian Toomey 907.777.8434 907.903.3987 itoomey@hilcorp.com
Geologist Kevin Eastham 907.777.8316 907.360.5087 keastham@hilcorp.com
Reservoir Engineer Reid Edwards 907.777.8421 907.250.5081 reedwards@hilcorp.com
Drilling Env. Coordinator Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com
EHS Manager Carl Jones 907.777.8327 907.382.4336 cajones@hilcorp.com
Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinger@hilcorp.com
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I-21 SB Injector
Drilling Procedure
6.0 Planned Wellbore Schematic
ES tool
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Milne Point Unit
I-21 SB Injector
Drilling Procedure
7.0 Drilling / Completion Summary
MPU I-21 is a grassroots injector planned to be drilled in the Schrader Bluff Ob sand. I-21 is part of a multi
well program targeting the Schrader Bluff sand on I-Pad
The directional plan is a catenary well path build, 12-1/4” hole with 9-5/8” surface casing set into the top of
the Schrader Bluff Ob sand. An 8-1/2” lateral section will then be drilled. A 4-1/2” ICD injection liner will
be run in the open hole section.
The Innovation Rig will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately July 10, 2020, pending rig schedule.
Surface casing will be run to 4,998’ MD / 4,010’ 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 Innovation to well site
2. NU & Test 13-5/8” Diverter and 16” diverter line
3. Drill 12-1/4” hole to TD of surface hole section. Run and c ement 9-5/8” surface casing.
4. ND diverter, NU & test 13-5/8” x 5M BOP.
5. Drill 8-1/2” lateral to well TD. Run 4-1/2” injection liner.
6. Run 3-1/2” tubing.
7. ND BOP, NU Tree, RDMO.
Reservoir Evaluation Plan:
1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res
2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering)
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I-21 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.
x BOPs shall be tested at (2) week intervals during the drilling and completion of MPU I-21. Ensure
to provide AOGCC 24 hrs notice prior to testing BOPs.
x The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment
will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial
and subsequent tests). Confirm that these test pressures match those specified on the APD.
x If the BOP is used to shut in on the well in a well control situation or control fluid flow from the
well bore, AOGCC is to be notified and we must test all BOP components utilized for well control
prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP
test.
x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program
and drilling fluid system”.
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”.
o Ensure the diverter vent line is at least 75’ away from potential ignition sources
x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
x Notify the AOGCC at least 24 hours in advance of the IA pressure test after running the completion
as per 20 AAC 25.412 (e). Record pressure test on 10-426 form and email to wrivard@hilcorp.com
for submission to AOGCC.
x Hilcorp Alaska proposes to demonstrate isolation of the injected fluid as required under 20 AAC
25.412 (d) through cement job operational reports of a complete two stage cement job on the 9-5/8”
surface casing. Planned surface cement volumes and cement returns to surface seen during both
stages will indicate placement of cement in the entire surface casing annulus. A successful FIT after
surface casing drill out will demonstrate isolation of injection fluid.
AOGCC Regulation Variance Requests:
Hilcorp Alaska LLC does not request any variances at this time.
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I-21 SB Injector
Drilling Procedure
Summary of BOP Equipment and Test Requirements
Hole Section Equipment Test Pressure (psi)
12 1/4” x 13-5/8” 5M CTI Annular BOP w/ 16” diverter line Function Test Only
8-1/2”
x 13-5/8” x 5M Control Technology Inc Annular BOP
x 13-5/8” x 5M Control Technology Inc Double Gate
o Blind ram in btm cavity
x Mud cross w/ 3” x 5M side outlets
x 13-5/8” x 5M Control Technology Single ram
x 3-1/8” x 5M Choke Line
x 3-1/8” x 5M Kill line
x 3-1/8” x 5M Choke manifold
x Standpipe, floor valves, etc
Initial Test: 250/3,000
Subsequent Tests:
250/3,000
Primary closing unit: Control Technology Inc. (CTI), 6 station, 3,000 psi, 220 gallon accumulator unit.
Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an electric
triplex pump on a different electrical circuit and emergency pressure is provided by bottled nitrogen.
The remote closing operator panels are located in the doghouse and on accumulator unit.
Required AOGCC Notifications:
x Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
x 24 hours notice prior to spud.
x 24 hours notice prior to testing BOPs.
x 24 hours notice prior to casing running & cement operations.
x Any other notifications required in APD.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email: jim.regg@alaska.gov
Guy Schwartz / Petroleum Engineer / (O): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartz@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email: Victoria.loepp@alaska.gov
Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email: melvin.rixse@alaska.gov
Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov
Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
Page 10
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I-21 SB Injector
Drilling Procedure
9.0 RU and Preparatory Work
9.1 I-21 will utilize a newly set 20” conductor on I-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 RU.
9.6 Rig mat footprint of the rig.
9.7 MIRU Innovation Rig. Ensure rig is centered over conductor to prevent any wear to BOPE or
wellhead.
9.8 Mud loggers WILL NOT be used on either hole section.
9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80qF).
9.10 Set test plug in wellhead prior to NU diverter to ensure nothing can fall into the wellbore if it is
accidentally dropped.
9.11 Ensure 5” liners in mud pumps.
x White Star Quattro 1300 HP mud pumps are rated at 4,097 psi, 381 gpm @ 140 spm @
96.5% volumetric efficiency.
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I-21 SB Injector
Drilling Procedure
10.0 NU 13-5/8” 5M Diverter Configuration
10.1 NU 13-5/8” CTI BOP stack in diverter configuration (Diverter Schematic attached to program).
x NU 20” x 13-5/8” DSA
x NU 13 5/8”, 5M diverter “T”.
x NU Knife gate & 16” diverter line.
x Ensure diverter RU complies with AOGCC reg 20.AAC.25.035(C).
x Diverter line must be 75 ft from nearest ignition source
x Place drip berm at the end of diverter line.
x Utilized extensions if needed.
10.2 Notify AOGCC. Function test diverter. Ensure that the knife gate and annular are operated on
the same circuit so that knife gate opens prior to annular closure.
10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the
vent line tip. “Warning Zone” must include:
x A prohibition on vehicle parking
x A prohibition on ignition sources or running equipment
x A prohibition on staged equipment or materials
x Restriction of traffic to essential foot or vehicle traffic only.
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I-21 SB Injector
Drilling Procedure
10.4 Rig & Diverter Orientation:
*Orientation may differ on location
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Milne Point Unit
I-21 SB Injector
Drilling Procedure
11.0 Drill 12-1/4” Hole Section
11.1 Consider PU 12-1/4” short collar directional only BHA:
x This is for surface A/C and accurate gyro surveys closer to bit
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before MU. Visually verify no debris inside components
that cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Be sure to run a UBHO sub for wireline gyro
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
x Drill string will be 5”, 19.5#, S-135 DS50 & NC50.
x Run a solid float in the surface hole section.
11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor.
11.3 Drill 12-1/4” hole section to section to the end of build and/or until clean MWD surveys are
seen,
x Monitor the area around the conductor for any signs of broaching. If broaching is observed,
Stop drilling (or circulating) immediately notify Drilling Engineer.
x Efforts should be made to minimize dog legs in the surface hole.
x Hold a safety meeting with rig crews to discuss:
x Conductor broaching ops and mitigation procedures.
x Well control procedures and rig evacuation
x Flow rates, hole cleaning, mud cooling, etc.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Keep mud as cool as possible to keep from washing out permafrost.
x Pump at 400-600 GPM. Monitor shakers closely to ensure shaker screens and return lines
can handle the flow rate.
x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoffs, increase in pump pressure or changes in hookload are seen
x Slow in/out of slips and while tripping to keep swab and surge pressures low
x Ensure shakers are functioning properly. Check for holes in screens on connections.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea
gravel, clay balling or packing off.
x Adjust MW and viscosity as necessary to maintain hole stability
x Perform wireline gyros until clean MWD surveys are seen . Take MWD surveys every
stand drilled.
11.4 CBU and BROOH
x POOH on elevators if possible
11.5 Make up remainder of full directional and LWD BHA
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Drilling Procedure
11.6 RIH
11.7 Drill 12-1/4” hole section to section TD, in the Schrader Ob sand. Confirm this setting depth
with the Geologist and Drilling Engineer while drilling the well.
x Monitor the area around the conductor for any signs of broaching. If broaching is observed,
Stop drilling (or circulating) immediately notify Drilling Engineer.
x Efforts should be made to minimize dog legs in the surface hole.
x Hold a safety meeting with rig crews to discuss:
x Conductor broaching ops and mitigation procedures.
x Well control procedures and rig evacuation
x Flow rates, hole cleaning, mud cooling, etc.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Keep mud as cool as possible to keep from washing out permafrost.
x Pump at 400-600 GPM. Monitor shakers closely to ensure shaker screens and return lines
can handle the flow rate.
x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoffs, increase in pump pressure or changes in hookload are seen
x Slow in/out of slips and while tripping to keep swab and surge pressures low
x Ensure shakers are functioning properly. Check for holes in screens on connections.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea
gravel, clay balling or packing off.
x Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2
minimum at TD (pending MW increase due to hydrates).
x Perform wireline gyros until clean MWD surveys are seen. Take MWD surveys every stand
drilled.
x Gas hydrates may be present on I-Pad. Historically encountered hydrates are typically
around 2,100-2,400’ TVD (just below permafrost). Be prepared for hydrates:
x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD
x Monitor returns for hydrates, checking pressurized & non-pressurized scales
x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by
washing out additional permafrost. Attempt to control drill (150 FPH MAX) through the
zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be
reduced to prevent mud from belching over the bell nipple. Consider adding Lecithin to
allow the gas to break out.
x Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the
well. MW will not control gas hydrates, but will affect how gas breaks out at surface
x A/C:
x There are not wells with a clearance factor < 1.0
11.8 12-1/4” hole mud program summary:
x Density: Weighting material to be used for the hole section will be barite. Additional
barite or spike fluid will be on location to weight up the active system (1) ppg above
highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and
TD with 9.2+ ppg.
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I-21 SB Injector
Drilling Procedure
Depth Interval MW (ppg)
Surface – Base Permafrost 8.9+
Base Permafrost - TD 9.2+ (For Hydrates if need based on offset wells)
MW can be cut once ~500’ below hydrate zone
x PVT System: MD Totco PVT will be used throughout the drilling and completion phase.
Remote monitoring stations will be available at the driller’s console, Co Man office,
Toolpusher office, and mud loggers office.
x Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system
with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at
all times while drilling. Be prepared to increase the YP if hole cleaning becomes an
issue.
x Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background
LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the
system while drilling the surface interval to prevent losses and strengthen the wellbore.
x Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are
recommended to reduce the incidence of bit balling and shaker blinding when penetrating
the high-clay content sections of the Sagavanirktok and the heavy oil sections of the
UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of
ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action.
x Casing Running: Reduce system YP with DESCO as required for running casing as
allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and
swab pressures. Reduce the system rheology once the casing is landed to a YP < 20
(check with the cementers to see what YP value they have targeted).
System Type: 8.8 – 9.8 ppg Pre-Hydrated Aquagel/freshwater spud mud
Properties:
Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp
Surface 8.8 – 9.8 75-175 20 - 40 25-45 <10 8.5 – 9.0 70 F
System Formulation: Gel + FW spud mud
Product Concentration
Fresh Water
soda Ash
AQUAGEL
caustic soda
BARAZAN D+
BAROID 41
PAC-L /DEXTRID LT
0.905 bbl
0.5 ppb
15 - 20 ppb
0.1 ppb (8.5 – 9.0 pH)
as needed
as required for 8.8 – 9.2 ppg
if required for <10 FL
NOTE: EMW needed=8.46 ppg. DLB
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Drilling Procedure
ALDACIDE G 0.1 ppb
11.9 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity.
x This is to prevent washing out directional work to land the well
11.10 RIH to bottom, proceed to BROOH to HWDP
x Pump at full drill rate (400-600 GPM), and maximize rotation.
x Pull slowly, 5 – 10 FPM.
x Monitor well for any signs of packing off or losses.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay
balling.
x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until
parameters are restored.
11.11 TOOH and LD BHA
11.12 No open hole logging program planned.
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Drilling Procedure
12.0 Run 9-5/8” Surface Casing
12.1 RU and pull wearbushing.
12.2 RU Weatherford 9-5/8” casing running equipment (CRT & Tongs)
x Ensure 9-5/8” TXP x DS50 XO on rig floor and MU to FOSV.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x RU of CRT if hole conditions require.
x RU a fill up tool to fill casing while running if the CRT is not used.
x Ensure all casing has been drifted to 8.750” on the location prior to running.
x Top 2000’ of casing 47# drift 8.525”
x Be sure to count the total # of joints on the location before running.
x Keep hole covered while RU casing tools.
x Record OD’s, ID’s, lengths and SN’s of all components with vendor & model info.
12.3 PU shoe joint, visually verify no debris inside joint.
12.4 Continue MU & 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 with stop rings
1 joint – 9-5/8” TXP, 1 Centralizer mid joint with stop ring
9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’
1 joint – 9-5/8” TXP, 1 Centralizer mid joint with stop ring
9-5/8” HES Baffle Adaptor
x Ensure bypass baffle is correctly installed on top of float collar.
x Ensure proper operation of float equipment while picking up.
x Ensure to record SN’s of all float equipment and stage tool components.
This end up.
Bypass Baffle
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Drilling Procedure
12.5 Float equipment and Stage tool equipment drawings:
2500 ft
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Drilling Procedure
12.6 Continue running 9-5/8” surface casing
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization: Verify depth of lowest Ugnu water sand for isolation with Geologist
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
x Any packing off while running casing should be treated as a major problem. It is preferable
to POOH with casing and condition hole than to risk not getting cement returns to surface.
12.7 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below
the permafrost (~ 2,500’ MD).
x Install centralizers over couplings on 5 joints below and 10 joints above stage tool.
x Do not place tongs on ES cementer, this can cause damaged to the tool.
x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi.
9-5/8”, 40#, L-80, TXP MU Torques:
Casing OD Minimum Optimum Maximum
9-5/8” 18,860 ft-lbs 20,960 ft-lbs 23,060 ft-lbs
9-5/8” 47# L-80 TXP MUT:
Casing OD Minimum Optimum Maximum
9-5/8” 21,440 ft-lbs 2,3820 ft-lbs 26,200 ft-lbs
Depth Interval Centralization
Shoe – 1000’ Above Shoe 1/joints
1000’ above Shoe – 2000’ above Shoe (Top of Ugnu) 1/ 2 joints
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Drilling Procedure
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Drilling Procedure
12.8 Continue running 9-5/8” surface casing
x 9-5/8” 47# from 2000’ to surface
x Centralizers: 1 centralizer every 3rd joint to 200’ from surface
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only with paint brush.
x
g g
9-5/8” 47# from 2000’ to surface
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Drilling Procedure
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 PU landing joint and MU 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 MU water are available to achieve this. If possible
reciprocate casing string while conditioning mud.
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Drilling Procedure
13.0 Cement 9-5/8” Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
x Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks.
x Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
x Review test reports and ensure pump times are acceptable.
x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
13.2 Document efficiency of all possible displacement pumps prior to cement job.
13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
13.5 Fill surface cement lines with water and pressure test.
13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below
calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached.
13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead &
tail, TOC brought to stage tool.
Estimated 1st Stage Total Cement Volume:
Section Calculation Vol (bbl) Vol (ft3)
12-1/4" OH x 9-5/8"
Casing (3,998' - 2,500') x .0558 bpf x 1.3 = 108.6 610.1
Total Lead 108.6 610.1
12-1/4" OH x 9-5/8"
Casing (4,998' - 3,998') x .0558 bpf x 1.3 = 72.5 407
9-5/8" Shoe Track 120' x .0758 bpf = 9.1 51.09
Total Tail 81.6 458LeadTail
Estimated 1st Stage Total Cement Volume:
260 sx
394 sx
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Drilling Procedure
Cement Slurry Design (1st Stage Cement Job):
13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue
with the cement job.
13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of
mud pits, spotting water across the HEC stage cementer.
x Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
13.10 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very
accurate using 0.0625 bps (5” liners) for the Quattro pump output. To operate the stage tool
hydraulically, the plug must be bumped.
13.11 Displacement calculation:
4,878’ x .0758 bpf = 369.8 bbls
80 bbls of tuned spacer to be left behind stage tool, confirm fluid is compatible with cement
behind stage tool
13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any
point during the job. Be prepared to pump out fluid from cellar. Have black water available to
contaminate any cement seen at surface.
13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over
displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling
Engineer.
13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening
plug is available if needed. This is the back-up option to open the stage tool if the plugs are not
bumped.
Lead Slurry Tail Slurry
Density 12.0 lb/gal 15.8 lb/gal
Yield 2.35 ft3/sk 1.16 ft3/sk
Mixed
Water 13.92 gal/sk 4.98 gal/sk
p
4,878’ x .0758 bpf = 369.8 bbls
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Drilling Procedure
13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened.
13.16 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher pressure
may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns
to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation
for the 2nd stage of the cement job.
13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker
bypass line to the cuttings tank. Have black water available and vac trucks ready to assist.
Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact
with the cement.
Increase pressure to 3,300 psi to open circulating ports in stage collar.
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Drilling Procedure
Second Stage Surface Cement Job:
13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive
strength. (If ESIPC is used and packer element inflated, CBU x1 minimum before pumping
second stage). Hold pre-job safety meeting.
x Minimize pump shutdowns while circulating through stage tool and keep shutdowns
to 30 minutes or less. Longer shutdowns have lead to the stage tool packing off and
losing circulation
x If circulation is lost, slowly stage up pumps to 2000psi and gently work/stretch pipe to
regain circulation. Contact drilling engineer if unable to gain circulation at 2000 psi
13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing
head.
13.20 Fill surface lines with water and pressure test.
13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.22 Mix and pump cmt per below recipe for the 2nd stage.
13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail).
Job will consist of lead & tail, TOC brought to surface. However cement will continue to be
pumped until clean spacer is observed at surface.
Estimated 2nd Stage Total Cement Volume:
Section Calculation Vol (bbl) Vol (ft3)
20" Conductor x 9-5/8" Casing (110') x .26 bpf x 1 = 28.6 161
12-1/4" OH x 9-5/8" Casing (2,000' - 110') x .0558 bpf x 3 = 316.4 1776.3
Total Lead 345 1937
12-1/4" OH x 9-5/8" Casing (2,500' - 2,000') x .0558 bpf x 2 = 55.8 314
Total Tail 55.8 314LeadTail
Cement Slurry Design (2nd stage cement job):
Lead Slurry Tail Slurry
System Permafrost L
Density 10.7 lb/gal 15.8 lb/gal
Yield 4.41 ft3/sk 1.17 ft3/sk
Mixed
Water
22.02 gal/sk 5.08 gal/sk
440sx
268 sxclass G
permafrost
Estimated 2nd Stage Total Cement Volume:
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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:
2,500’ x .0758 bpf = 190 bbls mud
13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side
outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out
fluid from cellar. Have black water available to retard setting of cement.
13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should
circulate approximately 100 - 150 bbls of cement slurry to surface.
13.29 Land closing plug on stage collar and pressure up to 1,000 – 1,500 psi to ensure stage tool closes.
Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool
has closed. Slips will be set as per plan to allow full annulus for returns during surface cement
job. Set slips
13.30 Make initial cut on 9-5/8” final joint. L/D cut joint. Make final cut on 9-5/8”. Dress off stump.
Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule.
Ensure to report the following on wellez:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight
& type of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement , actual displacement volume, whether plug bumped &
bump pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final
circulating pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
x Note calculated top of cement
x Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to jengel@hilcorp.com and
cdinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC.
p
2,500’ x .0758 bpf = 190 bbls m
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Drilling Procedure
14.0 BOP NU and Test
14.1 ND the diverter T, 16” knife gate, 16” diverter line & NU 11” x 13-5/8” 5M casing spool.
14.2 NU 13-5/8” x 5M CTI BOP as follows:
x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13-
5/8” x 5M mud cross / 13-5/8” x 5M single gate
x Double gate ram should be dressed with 2-7/8” x 5-1/2” VBRs in top cavity, blind ram in
bottom cavity.
x Single ram should be dressed with 2-7/8” x 5-1/2” VBRs or 5” Solid Body Rams
x NU bell nipple, install flowline.
x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to
mud cross).
x Install (1) manual valve & HCR valve on choke side of mud cross. (manual valve closest to
mud cross)
14.3 Run 5” BOP test plug (if not installed previously).
x Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min.
x Confirm test pressures with PTD
x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure
is trapped underneath test plug
x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech
14.4 RD BOP test equipment
14.5 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.6 Mix 8.9 ppg Baradrill-N fluid for production hole.
14.7 Set wearbushing in wellhead.
14.8 Rack back as much 5” DP in derrick as possible to be used while drilling the hole section.
14.9 Ensure 5” liners in mud pumps.
y)
Test annular to 250/2,500 psi for 5/5 min.
pg( p
Test BOP to 250/3,000 psi for 5/5 min.
Initial
BOPE test
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Drilling Procedure
15.0 Drill 8-1/2” Hole Section
15.1 MU 8-1/2” Cleanout BHA (Milltooth Bit & 1.22° PDM)
15.2 TIH with 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on morning 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 RU and test casing to 2,500 psi for 30 minutes charted. Ensure to record volume / pressure and
plot on FIT graph. AOGCC reg is 50% of burst = 6870 / 2 = ~3500 psi, but max test pressure on
the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent
pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry
Guidance Bulletin 17-001.
15.5 Drill out shoe track and 20’ of new formation.
15.6 CBU and condition mud for FIT.
15.7 Conduct FIT to 12 ppg EMW. Chart Test. Ensure test is recorded on same chart as FIT.
Document incremental volume pumped (and subsequent pressure) and volume returned.
15.8 POOH & LD Cleanout BHA
15.9 PU 8-1/2” directional BHA.
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before MU. Visually verify no debris inside components that
cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Ensure MWD is RU and operational.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
x Drill string will be 5”, 19.5#, S-135, DS50 & NC50.
x Run a ported float in the production hole section.
15.10 8-1/2” hole section mud program summary:
x Density: Weighting material to be used for the hole section will be calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg
above highest anticipated MW.
FIT
RU and test casing to 2,500 psi for 30 minutes charted.
MIT casing
* submit FIT data to AOGCC by email and include in 10-407 report
Conduct FIT to 12 ppg EMW.
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Drilling Procedure
x Solids Concentration: It is imperative that the solids concentration be kept low while
drilling the production hole section. Keep the shaker screen size optimized and fluid
running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure
we are running the finest screens possible.
x Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests
excessive viscosifier concentrations can decrease return permeability. Do not pump high
vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for
sufficient hole cleaning
x Run the centrifuge continuously while drilling the production hole, this will help with
solids removal.
x Dump and dilute as necessary to keep drilled solids to an absolute minimum.
x MD Totco PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, &
Toolpusher office.
System Type: 8.9 – 9.5 ppg Baradrill-N drilling fluid
Properties:
Section Density Plastic Viscosity Yield Point Total Solids MBT HPHT
Production 8.9-9.5 15-25 20-25 <10% <7 <11.0
System Formulation: Baradrill-N
Product Concentration
Water
KCL
KOH
N-VIS
DEXTRID LT
BARACARB 5
BARACARB 25
BARACARB 50
BARACOR 700
BARASCAV D
X-CIDE 207
0.955 bbl
11 ppb
0.1 ppb
1.0 – 1.5 ppb
5 ppb
4 ppb
4 ppb
2 ppb
1.0 ppb
0.5 ppb
0.015 ppb
15.11 TIH with 8-1/2” directional assembly to bottom
15.12 Displace wellbore to 8.9 ppg Baradrill-N drilling fluid
NOTE: EMW needed=8.46 ppg. DLB
8.9-9.5
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Drilling Procedure
15.13 Begin drilling 8-1/2” hole section, o n-bottom staging technique:
x Tag bottom and begin drilling with 100 - 120 RPMs at bit. Allow WOB to stabilize at 5-8K.
x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations.
x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU
off bottom and restart on bottom staging technique. If stick slip continues, consider adding
0.5% lubes.
15.14 Drill 8-1/2” hole section to section TD per Geologi st and Drilling Engineer.
x Flow Rate: 350-550 GPM, target min. AV’s 200 FPM, 385 GPM
x RPM: 120+
x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly
wet to maximize solids removal efficiency. Check for holes in screens on every connection.
x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
x Monitor Torque and Drag with pumps on every 5 stands
x Monitor ECD, pump pressure & hookload trends for hole cleaning indication
x Surveys can be taken more frequently if deemed necessary.
x Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible and avoid stopping with the
BHA across the sand for any extended period of time.
x Use ADR to stay in section.
x Limit maximum instantaneous ROP to < 250 FPH. The sands will drill faster than this, but
when concretions are hit when drilling this fast, cutter damage can occur.
x Target ROP is as fast as we can clean the hole without having to backream connections
x Schrader Bluff Ob Concretions: 4-6% of lateral
x A/C, wells with < 1.0 clearance factor:
x I-19/L1/PB1/PB2 – A cemented and reservoir abandoned SB dual lateral. TOC at 6620’
MD on 4/17/2020. The only risk is damage to the bit.
x J-16 - is a long term shut in Kuparuk injector. We will control drill past and watch for
magnetic interference. The directional plan will be updated to increase separation with J-
16 to CF >1.0. An update will be sent out.
15.15 Reference: Open hole sidetracking practice:
x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so
we have a nice place to low side.
x Attempt to lowside in a fast drilling interval where the wellbore is headed up.
x Orient TF to low side and dig a trough with high flowrates for the first 10 ft, working string
back and forth. Trough for approximately 30 minutes.
x Time drill at 4 to 6 FPH with high flow rates. Gradually increase ROP as the openhole
sidetrack is achieved.
15.16 At TD, CBU at least 4 times at 200 FPM AV (385+ GPM) and rotation (120+ RPM). Pump
tandem sweeps if needed
Begin drilling 8-1/2” hole section,
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Drilling Procedure
x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a
consistent stream, circulate more if necessary
x Ensure mud has necessary lube % for running liner
x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum
15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP
pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter
cake and calcium carbonate. Circulate the well clean. Losses during the cleanup of the wellbore
are a good indication that the mud filter cake is being removed, including an increase in the loss
rate.
15.18 Displace 1.5 OH + Liner volume with viscosified brine.
x Proposed brine blend (same as used on M-16, aiming for an 8 on the 6 rpm reading) -
KCl: 7.1bbp for 2%
NaCl: 60.9 ppg for 9.4 ppg
Lotorq: 1.5%
Lube 776: 1.5%
Soda Ash: as needed for 9.5 pH
Busan 1060: 0.42ppb
Flo-Vis Plus: 1.25 ppb
x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further
discussion needed prior to BROOH.
x Record SO, PU weights and rotating torque to compare to pre-brine values in report.
15.19 BROOH with the drilling assembly to the 9-5/8” casing shoe
x Circulate at full drill rate (less if losses are seen, 350 GPM).
x Rotate at maximum rpm that can be sustained.
x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as
dictated by hole conditions
x If backreaming operations are commenced, continue backreaming to the shoe
15.20 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while
BROOH.
15.21 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps.
15.22 Monitor well for flow / pressure build up with MPD. Increase fluid weight if necessary
Monitor well for flow / pressure build up with MPD.
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Drilling Procedure
x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to
determine if well is breathing, treat all flow as an influx until proven otherwise
15.23 POOH and LD BHA.
15.24 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit
diameter is sufficient for future ball drops.
Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any
additional logging runs conducted.
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Drilling Procedure
16.0 Run 4-1/2” Injection Liner (Lower Completion)
16.1. Well control preparedness: In the event of an influx of formation fluids while running the 4-
1/2” liner with ICD and swell packers, the following well control response procedure will be
followed:
x With ICD across the BOP: PU & MU 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 MU and available prior to running the first joint of 4-1/2” liner.
x With 4-1/2” solid joint across BOP: Slack off and position the 4-1/2” solid joint to MU the
TIW valve. Shut in ram or annular on 4-1/2” solid joint. Close TIW valve.
16.2. Confirm VBR have been tested on 3-1/2” and 5” test joints to 250/3,000 psi.
16.3. RU 4-1/2” liner running equipment.
x Ensure 4-1/2” Hydril 625 x DS-50 crossover is on rig floor and /U to FOSV.
x Ensure the liner has been drifted on the deck prior to running.
x Be sure to count the total # of joints on the deck before running.
x Keep hole covered while RU casing tools.
x Record OD’s, ID’s, lengths and SN’s of all components with vendor & model info.
16.4. Run 4-1/2” injection liner.
x Use API Modified or “Best O Life 2000 AG” thread compound. Dope pin end only with
paint brush. Wipe off excess. Thread compound can plug the ICDs.
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Use lift nubbins and stabbing guides for the liner run.
x Fill 4-1/2” liner with PST passed mud (to keep from plugging ICDs with solids)
x Install ICDs and swell packers as per the Running Order (Estimate 8 evenly spaced,
Operations Engineer to provide confirmation of set depths).
x Do not place tongs or slips on swell packer elements or ICDs.
x ICD and swell packer placement ±40’
x The ICD connection is 4-1/2”, 13.5#, L-80, Hydril 625.
x Remove protective packaging on swell packers just prior to picking up
x If liner length exceeds surface casing length, ensure centralizers are placed 1/joint for each
joint outside of the surface shoe. This is to mitigate difference sticking risk while running
inner string.
x Obtain PU and SO weights of the liner before entering open hole. Record rotating torque at
10 and 20 RPM
4-1/2”, 13.5#, L-80, Hydril 625 MU Torques
Casing OD Minimum Optimum Maximum
Operating Torque
Yield Torque
4-1/2” 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs 15,000 ft-lbs
Well control preparedness:
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16.6. Ensure that the liner top packer is set ~150’ MD above the 9-5/8” shoe.
x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as
per 20 AAC 25.030(d)(6). Ensure hanger/packer will not be set in a 9-5/8” connection.
16.7. Before picking up Baker SLZXP liner hanger/packer assembly, count the # of joints on the pipe
deck to make sure it coincides with the pipe tally.
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16.8. MU Baker SLZXP liner hanger/packer to 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
minutes for mixture to set up.
16.9. Note weight of liner. Run liner in the hole one stand and pump through liner hanger to ensure a
clear flow path exists.
16.10. RIH with liner on all 5” HWDP no faster than 30 FPM – this is to prevent buckling the liner and
drill string. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow
down running speed if necessary.
16.11. The liner will prevent the DP from auto filling. Fill DP every 5 stands, more frequently if SOW
trend indicates.
16.12. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe
depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to
bottom.
16.13. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
16.14. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
16.15. Rig up to pump down the work string with the rig pumps.
16.16. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill
pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger.
16.17. Drop setting ball down the workstring and pump slowly (1-2 BPM). Slow pump before the ball
seats. Do not allow ball to slam into ball seat. Pressure up to 1,500 psi to shift the wellbore
isolation valve closed.
16.18. Continue pressuring up to 2,700 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 4,100 psi to neutralize and release
running tools.
16.19. Bleed DP pressure to 0 psi, Pick up to expose rotating dog sub and set down 50K without pulling
sleeve packoff. Contingency (if suspected not released from running tool) - Pick back up
without pulling sleeve packoff, begin rotating at 10-20 RPM and set down 50K again.
16.20. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted.
16.21. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If
packer did not test, rotating dog sub can be used to set packer. If running tool cannot be
hydraulically released, apply LH torque to mechanically release the setting tool.
and test annulus to 1,500 p
Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer.
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16.22. POOH laying down DP then rack back enough 5” DP for the liner top cleanout run. LD and
inspect the liner running tools. Once running tools are LD, swap to the Completion AFE.
16.23. Make up 3-1/2” wash tool and RIH on 5” DP to the liner top.
16.24. Flush liner top at max rate while displacing out well to clean brine.
16.25. POOH LD remaining 5” DP.
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17.0 Run 3-1/2” Tubing (Upper Completion)
17.1 Notify the AOGCC at least 24 hours in advance of the IA pressure test after running the
completion as per 20 AAC 25.412 (e). Record pressure test on 10-426 form and email to
wrivard@hilcorp.com for submission to AOGCC.
17.2 MU injection assembly and RIH to setting depth. TIH no faster than 90 FPM.
x Ensure wear bushing is pulled.
x Ensure 3-1/2” EUE 8rd x NC-50 crossover is on rig floor and MU to FOSV.
x Ensure all tubing has been drifted in the pipe shed prior to running.
x Be sure to count the total # of joints in the pipe shed before running.
x Keep hole covered while RU casing tools.
x Record OD’s, ID’s, lengths and SN’s of all components with vendor & model info.
x Monitor displacement from wellbore while RIH.
3-1/2” Upper Completion Running Order:
x 7.30” Baker Ported Bullet Nose seal (stung into the tie back receptacle, crossover to 3-1/2”,
9.3#, EUE 8rd)
x 3 joints (minimum, more as needed), 3-1/2”, 9.3#, EUE 8rd tubing
x 3-1/2” “XN” nipple at TBD (less than 70° hole angle)
x 1 joints, 3-1/2”, 9.3#, EUE 8rd tubing
x 3-1/2” Baker gauge mandrel
o Cross collar clamps: Every joint for first 10 joints, every other joint beyond this to
surface
x XX Joints, 3-1/2”, 9.3#, EUE 8rd tubing
x Space out pup(s), 3-1/2”, 9.3#, EUE 8rd tubing
x 1 joint, 3-1/2”, 9.3#, EUE 8rd tubing
x Tubing hanger with 3-1/2” EUE 8rd pin down
17.3 Locate and no-go out the seal assembly. Close annular and test to 500 psi to confirm seals
engaged.
17.4 Bleed pressure and open annular. Space out the completion (±2’ above No-Go). Place all space
out pups below the first full joint of the completion.
Notify the AOGCC at least 24 hours in advance of the IA pressure test after r
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17.5 MU the tubing hanger and landing joint.
17.6 RIH. Close annular and test to 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 corrosion inhibited brine.
17.8 Freeze protect the IA to ~2,000’ TVD (base on actual well deviation) with diesel.
17.9 Land hanger and RILDS.
17.10 PT the IA to 2,500 psi for 30 minutes charted.
i. Note this test must be witnessed by the AOGCC representative.
17.11 Set BPV, ensure new body seals are installed each time.
17.12 ND BOPE and install the plug off tool into the BPV.
17.13 NU the tubing head adapter and NU the tree.
17.14 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi.
17.15 Pull the plug off tool from the BPV.
17.16 Bullhead diesel down the tubing to ~2,000’ TVD (base on actual well deviation).
17.17 Install all tree gauges. Secure the tree and cellar. Release the rig.
17.18 RDMO the Innovation Rig.
17.19 Turn the well over to operations via handover form.
PT the IA to 2,500 psi for 30 minutes charted. Witnessed
MIT-IA
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18.0 Innovation Rig Diverter Schematic
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19.0 Innovation Rig BOP Schematic
Blinds
VBR or5"
VBR
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20.0 Wellhead Schematic
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21.0 Days Vs Depth
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22.0 Formation Tops & Information
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23.0 Anticipated Drilling Hazards
12-1/4” Hole Section:
Lost Circulation
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Gas Hydrates
Gas hyrates have been seen on E Pad. 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.
Well Specific A/C:
x There are no wells with a clearance factor of <1.0
Wellbore stability (Permafrost, running sands and gravel, conductor broaching):
Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of
time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH
speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and
swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching.
Maintain mud parameters and increase MW to combat running sands and gravel formations.
Anti-Collison:
There are a number of wells in close proximity. Take directional surveys every stand, take additionalpy yy,
surveys if necessary. Continuously monitor proximit y to offset wellbores and record any closeyy ypy y
approaches on AM report. Discuss offset wellbores with production foreman and consider shutting inpp p p
adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. j
Well Specific A/C:
x
p
There are no wells with a clearance factor of <1 .0
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H2S:
Treat every hole section as though it has the potential for H2S. No H2S events have been documented
on drill wells on this pad.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
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8-1/2” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor
ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe
moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation
after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300
gpm
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
There is at least (1) fault that will be crossed while drilling the well. There could be others and the
throw of these faults is not well understood at this point in time. When a known fault is coming up,
ensure to put a “ramp” in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed,
we’ll need to either drill up or down to get a look at the LWD log and determine the throw and then
replan the wellbore.
H2S:
Treat every hole section as though it has the potential for H2S. No H2S events have been documented
on drill wells on this pad.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Abnormal Pressures and Temperatures:
Abnormal pressure has been seen on E-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.
x A/C, wells with < 1.0 clearance factor:
x I-19/L1/PB1/PB2 – A cemented and reservoir abandoned SB dual lateral. TOC at 6620’
MD on 4/17/2020. The only risk is damage to the bit.
x J-16 - is a long term shut in Kuparuk injector. We will control drill past and watch for
magnetic interference. The directional plan will be updated to increase separation with J-
16 to CF >1.0. An update will be sent out.
J-16 - is a long term shut in Kuparuk injector. We will control drill past and watch for gpj p
magnetic interference. The directional plan will be updated to increase separation with J-
MD on 4/17/2020. The only risk is damage to the bit.ygI-19
J-16
,
I-19/L1/PB1/PB2 – A cemented and reservoir abandoned SB dual lateral.–TOC at 6620’
Anti-Collision
16 to CF >1.0. An update will be sent out.
gp
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24.0 Innovation Rig Layout
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25.0 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.
*submit FIT to AOGCC by email and include in 10-407 report
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26.0 Innovation Rig Choke Manifold Schematic
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27.0 Casing Design
12-1/4"Mud Density:9.2 ppg
8-1/2"Mud Density:9.2 ppg
Mud Density:
1363 psi (see attached MASP determination & calculation)
1363 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
1234
9-5/8"4-1/2"
04,998
04,010
4,998 13,921
4,010 4,160
4,998 8,923
40 13.5
L-80 L-80
TXP H625
199,920 120,461
199,920 120,461
916 307
4.58 2.55
1,981 2,055
3,090 8,540
1.56 4.16
1,363 1,363
5,750 9,020
4.22 6.62
Collapse Resistance w/o tension (Psi)
Top (TVD)
Tension at Top of Section (lbs)
Grade
Connection
Weight w/o Bouyancy Factor (lbs)
Min strength Tension (1000 lbs)
DATE: 6/5/2020
WELL: MPU I-21
DESIGN BY: Joe Engel
Hole Size
Hole Size
Casing Section
Design Criteria:
Calculation & Casing Design Factors
Calculation/Specification
Casing OD
Bottom (MD)
Bottom (TVD)
Top (MD)
MASP:
Drilling Mode
MASP:
Hole Size
Worst case safety factor (Burst)
MASP:
Production Mode
Minimum Yield (psi)
Weight (ppf)
MASP (psi)
Worst Case Safety Factor (Tension)
Collapse Pressure at bottom (Psi)
Worst Case Safety Factor (Collapse)
Length
4.58 2.55
1,981 2,055
3,090 8,540
1.56 4.16
1,363 1,363
5,750 9,020
4.22 6.62
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28.0 8-1/2” Hole Section MASP
MD TVD
Planned Top: 4998 4010
Planned TD: 13921 4160
Anticipated Formations and Pressures:
Formation Est Pressure Oil/Gas/Wet PPG Grad
Schrader Bluff OB Sand 1764 Oil 8.46 0.440
Offset Well Mud Densities
Well Sand MW range Top (TVD) Bottom (TVD) Date
M-35 8.8-9.2 Surface 3943 2020 2020
M-34 8.8-9.1 Surface 3900 2020 2019
J-23 9.1 Surface 3864 2000 2019
Assumptions:
1. Field test data suggests the Fracture Gradient in the Schrader Bluff is btwn 11.5 and 15 ppg EMW.
3. Calculations assume full evacuation of wellbore to gas
Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface:
4010 (ft) x 0.78(psi/ft)= 3127.8
3127.8(psi) - [0.1(psi/ft)*4010(ft)]= 2727 psi
MASP from pore pressure (complete evacuation of wellbore to gas from Schrader Bluff sand)
4010 (ft) x 0.44(psi/ft)= 1764 psi
1764(psi) - 0.1(psi/ft)*4010(ft) 1363 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.
Maximum Anticipated Surface Pressure Calculation
2. Maximum planned mud density for the 8-1/2" hole section is 9.5 ppg.
8-1/2" Hole Section
MPU I-21
Milne Point Unit
TVD
4,010
NOTE: DLB
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29.0 Spider Plot (NAD 27) (Governmental Sections)
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30.0 Surface Plat (As Built) (NAD 27)
19 May, 2020
Plan: MPU I-21i wp05
Milne Point
M Pt I Pad
Plan: MPU I-21i
MPU I-21
075015002250300037504500True Vertical Depth (1500 usft/in)-1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500Vertical Section at 6.88° (1500 usft/in)MPI-Shiloh wp02 CP1MPI-Shiloh wp02 HeelMPI-Shiloh wp02 Toe9 5/8" x 12 1/4"4 1/2" x 8 1/2"500100015002000250030003500400045005000
5500
6000
6500
7000
7500
8000
8500
9000
9500
1000 0
10500
11 0 0 0
115 00
1200 0
1250 0
130 00
13500
13922MPU I-21i wp05Start Dir 3º/100' : 280' MD, 280'TVDEnd Dir : 547.2' MD, 546.74' TVDStart Dir 3º/100' : 697.2' MD, 696.54'TVDEnd Dir : 797.2' MD, 796.49' TVDStart Dir 4º/100' : 887.2' MD, 886.49'TVDEnd Dir : 1087.2' MD, 1085.84' TVDStart Dir 4º/100' : 1197.2' MD, 1194.77'TVDEnd Dir : 1613.53' MD, 1594.77' TVDStart Dir 4º/100' : 2519.6' MD, 2426.34'TVDEndDir :4898.45' MD, 4001.47'TVDStartDir3º/100':4998.45'MD, 4010.19'TVDEndDir :5136.01' MD, 4017.24'TVDStartDir3º/100':9175.57'MD, 4078.82'TVDEndDir :9357.49' MD, 4081.85'TVDTotal Depth:13921.29' MD,4160.19'TVDHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Pedal CurveWarning Method: Error RatioWELL DETAILS: Plan: MPU I-21i33.40+N/-S +E/-WNorthingEastingLatittudeLongitude0.000.006009440.21551774.01 70° 26' 11.528 N 149° 34' 40.361 WSURVEY PROGRAMDate: 2020-03-27T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool26.50 800.00 MPU I-21i wp05 (MPU I-21) 3_Gyro-GC_Csg800.00 4998.45 MPU I-21i wp05 (MPU I-21) 3_MWD+IFR2+MS+Sag4998.45 13921.29 MPU I-21i wp05 (MPU I-21) 3_MWD+IFR2+MS+SagFORMATION TOP DETAILSNo formation data is availableREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU I-21i, True NorthVertical (TVD) Reference:MPU I-21i As-built RKB @ 60.20usftMeasured Depth Reference:MPU I-21i As-built RKB @ 60.20usftCalculation Method:Minimum CurvatureProject:Milne PointSite:M Pt I PadWell:Plan: MPU I-21iWellbore:MPU I-21Design:MPU I-21i wp05CASING DETAILSTVD TVDSS MD SizeName4010.19 3949.99 4998.45 9-5/8 9 5/8" x 12 1/4"4160.19 4099.99 13921.29 4-1/2 4 1/2" x 8 1/2"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 26.50 0.00 0.00 26.50 0.00 0.00 0.00 0.00 0.002 280.00 0.00 0.00 280.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 280' MD, 280'TVD3 450.00 5.10 300.00 449.78 3.78 -6.55 3.00 300.00 2.974 547.20 3.00 330.00 546.74 8.14 -11.56 3.00 149.04 6.70 End Dir : 547.2' MD, 546.74' TVD5 697.20 3.00 330.00 696.54 14.94 -15.49 0.00 0.00 12.98 Start Dir 3º/100' : 697.2' MD, 696.54'TVD6 797.20 0.00 0.00 796.49 17.21 -16.80 3.00 180.00 15.07 End Dir : 797.2' MD, 796.49' TVD7 887.20 0.00 0.00 886.49 17.21 -16.80 0.00 0.00 15.07 Start Dir 4º/100' : 887.2' MD, 886.49'TVD8 1087.20 8.00 220.00 1085.84 6.53 -25.76 4.00 220.00 3.40 End Dir : 1087.2' MD, 1085.84' TVD9 1197.20 8.00 220.00 1194.77 -5.20 -35.60 0.00 0.00 -9.42 Start Dir 4º/100' : 1197.2' MD, 1194.77'TVD10 1613.53 23.40 247.06 1594.77 -60.00 -131.02 4.00 39.07 -75.26 End Dir : 1613.53' MD, 1594.77' TVD11 2519.60 23.40 247.06 2426.34 -200.26 -462.36 0.00 0.00 -254.20 Start Dir 4º/100' : 2519.6' MD, 2426.34'TVD12 4898.45 85.00 2.48 4001.47 1117.10 -967.99 4.00 115.39 993.10 End Dir : 4898.45' MD, 4001.47' TVD13 4998.45 85.00 2.48 4010.19 1216.63 -963.68 0.00 0.00 1092.43 MPI-Shiloh wp02 Heel Start Dir 3º/100' : 4998.45' MD, 4010.19'TVD14 5136.01 89.13 2.46 4017.24 1353.84 -957.77 3.00 -0.32 1229.36 End Dir : 5136.01' MD, 4017.24' TVD15 9175.57 89.13 2.46 4078.82 5389.22 -784.62 0.00 0.00 5256.43 Start Dir 3º/100' : 9175.57' MD, 4078.82'TVD16 9260.41 89.02 5.00 4080.19 5473.86 -779.11 3.00 92.42 5341.12 MPI-Shiloh wp02 CP117 9357.49 89.02 7.91 4081.85 5570.31 -768.19 3.00 90.09 5438.18 End Dir : 9357.49' MD, 4081.85' TVD18 13921.29 89.02 7.91 4160.19 10089.98 -139.99 0.00 0.00 10000.56 MPI-Shiloh wp02 Toe Total Depth : 13921.29' MD, 4160.19' TVD
-1500
-750
0
750
1500
2250
3000
3750
4500
5250
6000
6750
7500
8250
9000
9750
10500
11250
South(-)/North(+) (1500 usft/in)-5250 -4500 -3750 -3000 -2250 -1500 -750 0 750 1500 2250 3000 3750 4500
West(-)/East(+) (1500 usft/in)
MPI-Shiloh wp02 Toe
MPI-Shiloh wp02 Heel
MPI-Shiloh wp02 CP1
9 5/8" x 12 1/4"
4 1/2" x 8 1/2"1750250032503 7 5 0
4000
4160
MPU I-21i wp05
Start Dir 3º/100' : 280' MD, 280'TVD
End Dir : 547.2' MD, 546.74' TVD
Start Dir 3º/100' : 697.2' MD, 696.54'TVD
End Dir : 797.2' MD, 796.49' TVD
Start Dir 4º/100' : 887.2' MD, 886.49'TVD
End Dir : 1087.2' MD, 1085.84' TVD
Start Dir 4º/100' : 1197.2' MD, 1194.77'TVD
End Dir : 4898.45' MD, 4001.47' TVD
Start Dir 3º/100' : 4998.45' MD, 4010.19'TVD
End Dir : 5136.01' MD, 4017.24' TVD
Start Dir 3º/100' : 9175.57' MD, 4078.82'TVD
End Dir : 9357.49' MD, 4081.85' TVD
Total Depth : 13921.29' MD, 4160.19' TVD
CASING DETAILS
TVD TVDSS MD Size Name
4010.19 3949.99 4998.45 9-5/8 9 5/8" x 12 1/4"
4160.19 4099.99 13921.29 4-1/2 4 1/2" x 8 1/2"
Project: Milne Point
Site: M Pt I Pad
Well: Plan: MPU I-21i
Wellbore: MPU I-21
Plan: MPU I-21i wp05
WELL DETAILS: Plan: MPU I-21i
33.40
+N/-S +E/-W Northing Easting Latittude Longitude
0.00 0.00 6009440.21 551774.01 70° 26' 11.528 N 149° 34' 40.361 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: MPU I-21i, True North
Vertical (TVD) Reference:MPU I-21i As-built RKB @ 60.20usft
Measured Depth Reference:MPU I-21i As-built RKB @ 60.20usft
Calculation Method:Minimum Curvature
Project:
Company:
Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt I Pad
Halliburton
Standard Proposal Report
Well:
Wellbore:
Plan: MPU I-21i
MPU I-21
Survey Calculation Method:Minimum Curvature
MPU I-21i As-built RKB @ 60.20usft
Design:MPU I-21i wp05
Database:NORTH US + CANADA
MD Reference:MPU I-21i As-built RKB @ 60.20usft
North Reference:
Well Plan: MPU I-21i
True
Map System:
Geo Datum:
Project
Map Zone:
System Datum:US State Plane 1927 (Exact solution)
NAD 1927 (NADCON CONUS)
Milne Point, ACT, MILNE POINT
Alaska Zone 04
Mean Sea Level
Using Well Reference Point
Using geodetic scale factor
Site Position:
From:
Site
Latitude:
Longitude:
Position Uncertainty:
Northing:
Easting:
Grid Convergence:
M Pt I Pad, TR-13-10
usft
Map usft
usft
°0.39Slot Radius:"0
6,008,388.01
550,245.83
0.00
70° 26' 1.282 N
149° 35' 25.422 W
Well
Well Position
Longitude:
Latitude:
Easting:
Northing:
usft
+E/-W
+N/-S
Position Uncertainty
usft
usft
usftGround Level:
Plan: MPU I-21i, Slot I-23
usft
usft
0.00
0.00
6,009,440.21
551,774.01
33.40Wellhead Elevation:33.70 usft0.50
70° 26' 11.528 N
149° 34' 40.361 W
Wellbore
Declination
(°)
Field Strength
(nT)
Sample Date Dip Angle
(°)
MPU I-21
Model NameMagnetics
BGGM2020 6/27/2020 15.95 80.84 57,376.45193575
Phase:Version:
Audit Notes:
Design MPU I-21i wp05
PLAN
Vertical Section: Depth From (TVD)
(usft)
+N/-S
(usft)
Direction
(°)
+E/-W
(usft)
Tie On Depth:26.50
6.880.000.0026.50
5/19/2020 6:32:14PM COMPASS 5000.15 Build 91E Page 2
Project:
Company:
Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt I Pad
Halliburton
Standard Proposal Report
Well:
Wellbore:
Plan: MPU I-21i
MPU I-21
Survey Calculation Method:Minimum Curvature
MPU I-21i As-built RKB @ 60.20usft
Design:MPU I-21i wp05
Database:NORTH US + CANADA
MD Reference:MPU I-21i As-built RKB @ 60.20usft
North Reference:
Well Plan: MPU I-21i
True
Inclination
(°)
Azimuth
(°)
+E/-W
(usft)
Tool Face
(°)
+N/-S
(usft)
Measured
Depth
(usft)
Vertical
Depth
(usft)
Dogleg
Rate
(°/100usft)
Build
Rate
(°/100usft)
Turn
Rate
(°/100usft)
Plan Sections
TVD
System
usft
0.000.000.000.000.000.0026.500.000.0026.50 -33.70
0.000.000.000.000.000.00280.000.000.00280.00 219.80
300.000.003.003.00-6.553.78449.78300.005.10450.00 389.58
149.0430.86-2.163.00-11.568.14546.74330.003.00547.20 486.54
0.000.000.000.00-15.4914.94696.54330.003.00697.20 636.34
180.000.00-3.003.00-16.8017.21796.490.000.00797.20 736.29
0.000.000.000.00-16.8017.21886.490.000.00887.20 826.29
220.000.004.004.00-25.766.531,085.84220.008.001,087.20 1,025.64
0.000.000.000.00-35.60-5.201,194.77220.008.001,197.20 1,134.57
39.076.503.704.00-131.02-60.001,594.77247.0623.401,613.53 1,534.57
0.000.000.000.00-462.36-200.262,426.34247.0623.402,519.60 2,366.14
115.394.852.594.00-967.991,117.104,001.472.4885.004,898.45 3,941.27
0.000.000.000.00-963.681,216.634,010.192.4885.004,998.45 3,949.99
-0.32-0.023.003.00-957.771,353.844,017.242.4689.135,136.01 3,957.04
0.000.000.000.00-784.625,389.224,078.822.4689.139,175.57 4,018.62
92.423.00-0.133.00-779.115,473.864,080.195.0089.029,260.41 4,019.99
90.093.000.003.00-768.195,570.314,081.857.9189.029,357.49 4,021.65
0.000.000.000.00-139.9910,089.984,160.197.9189.0213,921.29 4,099.99
5/19/2020 6:32:14PM COMPASS 5000.15 Build 91E Page 3
Project:
Company:
Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt I Pad
Halliburton
Standard Proposal Report
Well:
Wellbore:
Plan: MPU I-21i
MPU I-21
Survey Calculation Method:Minimum Curvature
MPU I-21i As-built RKB @ 60.20usft
Design:MPU I-21i wp05
Database:NORTH US + CANADA
MD Reference:MPU I-21i As-built RKB @ 60.20usft
North Reference:
Well Plan: MPU I-21i
True
Measured
Depth
(usft)
Inclination
(°)
Azimuth
(°)
+E/-W
(usft)
Map
Northing
(usft)
Map
Easting
(usft)
+N/-S
(usft)
Planned Survey
Vertical
Depth
(usft)
TVDss
usft
DLS
-33.70
Vert Section
26.50 0.00 26.50 0.00 0.000.00 551,774.016,009,440.21-33.70 0.00 0.00
100.00 0.00 100.00 0.00 0.000.00 551,774.016,009,440.2139.80 0.00 0.00
200.00 0.00 200.00 0.00 0.000.00 551,774.016,009,440.21139.80 0.00 0.00
280.00 0.00 280.00 0.00 0.000.00 551,774.016,009,440.21219.80 0.00 0.00
Start Dir 3º/100' : 280' MD, 280'TVD
300.00 0.60 300.00 0.05 -0.09300.00 551,773.926,009,440.26239.80 3.00 0.04
400.00 3.60 399.92 1.88 -3.26300.00 551,770.736,009,442.07339.72 3.00 1.48
450.00 5.10 449.78 3.78 -6.55300.00 551,767.446,009,443.94389.58 3.00 2.97
500.00 3.89 499.62 6.01 -9.74311.45 551,764.236,009,446.16439.42 3.00 4.80
547.20 3.00 546.74 8.14 -11.56330.00 551,762.396,009,448.27486.54 3.00 6.70
End Dir : 547.2' MD, 546.74' TVD
600.00 3.00 599.47 10.54 -12.94330.00 551,760.996,009,450.66539.27 0.00 8.91
697.20 3.00 696.53 14.94 -15.49330.00 551,758.426,009,455.04636.33 0.00 12.98
Start Dir 3º/100' : 697.2' MD, 696.54'TVD
700.00 2.92 699.33 15.07 -15.56330.00 551,758.356,009,455.17639.13 3.00 13.10
797.20 0.00 796.49 17.21 -16.80330.00 551,757.106,009,457.30736.29 3.00 15.07
End Dir : 797.2' MD, 796.49' TVD
800.00 0.00 799.29 17.21 -16.800.00 551,757.106,009,457.30739.09 0.00 15.07
887.20 0.00 886.49 17.21 -16.800.00 551,757.106,009,457.30826.29 0.00 15.07
Start Dir 4º/100' : 887.2' MD, 886.49'TVD
900.00 0.51 899.29 17.17 -16.83220.00 551,757.066,009,457.26839.09 4.00 15.03
1,000.00 4.51 999.17 13.81 -19.65220.00 551,754.276,009,453.88938.97 4.00 11.36
1,087.20 8.00 1,085.84 6.53 -25.76220.00 551,748.216,009,446.561,025.64 4.00 3.40
End Dir : 1087.2' MD, 1085.84' TVD
1,100.00 8.00 1,098.51 5.17 -26.90220.00 551,747.086,009,445.191,038.31 0.00 1.91
1,197.20 8.00 1,194.77 -5.20 -35.60220.00 551,738.456,009,434.771,134.57 0.00 -9.42
Start Dir 4º/100' : 1197.2' MD, 1194.77'TVD
1,200.00 8.09 1,197.54 -5.49 -35.85220.50 551,738.206,009,434.471,137.34 3.99 -9.75
1,300.00 11.49 1,296.08 -16.82 -48.39233.12 551,725.746,009,423.051,235.88 4.00 -22.50
1,400.00 15.18 1,393.37 -29.38 -67.68239.86 551,706.546,009,410.371,333.17 4.00 -37.27
1,500.00 18.99 1,488.95 -43.10 -93.64243.98 551,680.686,009,396.471,428.75 4.00 -54.00
1,600.00 22.87 1,582.33 -57.91 -126.13246.75 551,648.306,009,381.431,522.13 4.00 -72.61
1,613.53 23.40 1,594.77 -60.00 -131.02247.06 551,643.436,009,379.311,534.57 4.00 -75.26
End Dir : 1613.53' MD, 1594.77' TVD
1,700.00 23.40 1,674.13 -73.38 -162.64247.06 551,611.906,009,365.711,613.93 0.00 -92.34
1,800.00 23.40 1,765.91 -88.86 -199.21247.06 551,575.446,009,349.971,705.71 0.00 -112.09
1,900.00 23.40 1,857.69 -104.34 -235.78247.06 551,538.996,009,334.241,797.49 0.00 -131.84
2,000.00 23.40 1,949.46 -119.82 -272.35247.06 551,502.536,009,318.511,889.26 0.00 -151.58
2,100.00 23.40 2,041.24 -135.30 -308.92247.06 551,466.076,009,302.781,981.04 0.00 -171.33
2,200.00 23.40 2,133.02 -150.78 -345.49247.06 551,429.616,009,287.052,072.82 0.00 -191.08
2,300.00 23.40 2,224.80 -166.26 -382.06247.06 551,393.166,009,271.322,164.60 0.00 -210.83
2,400.00 23.40 2,316.57 -181.74 -418.62247.06 551,356.706,009,255.582,256.37 0.00 -230.58
2,500.00 23.40 2,408.35 -197.22 -455.19247.06 551,320.246,009,239.852,348.15 0.00 -250.33
2,519.60 23.40 2,426.34 -200.26 -462.36247.06 551,313.096,009,236.772,366.14 0.00 -254.20
Start Dir 4º/100' : 2519.6' MD, 2426.34'TVD
5/19/2020 6:32:14PM COMPASS 5000.15 Build 91E Page 4
Project:
Company:
Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt I Pad
Halliburton
Standard Proposal Report
Well:
Wellbore:
Plan: MPU I-21i
MPU I-21
Survey Calculation Method:Minimum Curvature
MPU I-21i As-built RKB @ 60.20usft
Design:MPU I-21i wp05
Database:NORTH US + CANADA
MD Reference:MPU I-21i As-built RKB @ 60.20usft
North Reference:
Well Plan: MPU I-21i
True
Measured
Depth
(usft)
Inclination
(°)
Azimuth
(°)
+E/-W
(usft)
Map
Northing
(usft)
Map
Easting
(usft)
+N/-S
(usft)
Planned Survey
Vertical
Depth
(usft)
TVDss
usft
DLS
2,440.27
Vert Section
2,600.00 22.20 2,500.47 -210.47 -491.73254.77 551,283.816,009,226.352,440.27 4.00 -267.86
2,700.00 21.27 2,593.40 -216.93 -528.04265.29 551,247.546,009,219.642,533.20 4.00 -278.62
2,800.00 21.03 2,686.70 -216.43 -563.97276.37 551,211.616,009,219.892,626.50 4.00 -282.43
2,900.00 21.52 2,779.92 -208.97 -599.33287.33 551,176.216,009,227.102,719.72 4.00 -279.26
3,000.00 22.68 2,872.61 -194.60 -633.95297.52 551,141.496,009,241.242,812.41 4.00 -269.14
3,100.00 24.41 2,964.31 -173.37 -667.66306.55 551,107.646,009,262.222,904.11 4.00 -252.10
3,200.00 26.61 3,054.58 -145.41 -700.30314.32 551,074.816,009,289.962,994.38 4.00 -228.25
3,300.00 29.17 3,142.97 -110.83 -731.70320.90 551,043.166,009,324.323,082.77 4.00 -197.68
3,400.00 32.00 3,229.07 -69.81 -761.73326.46 551,012.866,009,365.123,168.87 4.00 -160.56
3,500.00 35.04 3,312.44 -22.55 -790.22331.18 550,984.046,009,412.183,252.24 4.00 -117.05
3,600.00 38.24 3,392.68 30.72 -817.05335.21 550,956.856,009,465.253,332.48 4.00 -67.38
3,700.00 41.55 3,469.40 89.74 -842.07338.71 550,931.426,009,524.093,409.20 4.00 -11.78
3,800.00 44.96 3,542.23 154.22 -865.18341.77 550,907.876,009,588.413,482.03 4.00 49.47
3,900.00 48.44 3,610.81 223.85 -886.25344.48 550,886.326,009,657.883,550.61 4.00 116.08
4,000.00 51.97 3,674.81 298.30 -905.18346.92 550,866.876,009,732.193,614.61 4.00 187.72
4,100.00 55.56 3,733.91 377.19 -921.88349.12 550,849.626,009,810.953,673.71 4.00 264.04
4,200.00 59.17 3,787.84 460.14 -936.27351.15 550,834.666,009,893.793,727.64 4.00 344.67
4,300.00 62.82 3,836.32 546.75 -948.28353.03 550,822.046,009,980.313,776.12 4.00 429.22
4,400.00 66.49 3,879.11 636.60 -957.86354.78 550,811.856,010,070.083,818.91 4.00 517.27
4,500.00 70.18 3,916.02 729.24 -964.94356.45 550,804.126,010,162.673,855.82 4.00 608.40
4,600.00 73.89 3,946.86 824.24 -969.51358.03 550,798.906,010,257.623,886.66 4.00 702.17
4,700.00 77.60 3,971.48 921.12 -971.53359.56 550,796.206,010,354.473,911.28 4.00 798.11
4,800.00 81.33 3,989.76 1,019.41 -971.001.05 550,796.056,010,452.763,929.56 4.00 895.76
4,898.45 85.00 4,001.48 1,117.10 -967.992.48 550,798.386,010,550.453,941.28 4.00 993.10
End Dir : 4898.45' MD, 4001.47' TVD
4,900.00 85.00 4,001.61 1,118.64 -967.932.48 550,798.446,010,552.003,941.41 0.01 994.64
4,998.45 85.00 4,010.19 1,216.62 -963.682.48 550,802.006,010,650.003,949.99 0.00 1,092.42
Start Dir 3º/100' : 4998.45' MD, 4010.19'TVD - 9 5/8" x 12 1/4"
5,000.00 85.05 4,010.32 1,218.17 -963.612.48 550,802.066,010,651.543,950.12 2.99 1,093.96
5,100.00 88.05 4,016.35 1,317.88 -959.312.46 550,805.676,010,751.273,956.15 3.00 1,193.47
5,136.01 89.13 4,017.24 1,353.85 -957.772.46 550,806.966,010,787.243,957.04 3.00 1,229.37
End Dir : 5136.01' MD, 4017.24' TVD
5,200.00 89.13 4,018.21 1,417.77 -955.022.46 550,809.266,010,851.183,958.01 0.00 1,293.16
5,300.00 89.13 4,019.74 1,517.67 -950.742.46 550,812.856,010,951.093,959.54 0.00 1,392.85
5,400.00 89.13 4,021.26 1,617.56 -946.452.46 550,816.456,011,051.013,961.06 0.00 1,492.54
5,500.00 89.13 4,022.78 1,717.46 -942.162.46 550,820.046,011,150.923,962.58 0.00 1,592.23
5,600.00 89.13 4,024.31 1,817.36 -937.882.46 550,823.636,011,250.833,964.11 0.00 1,691.92
5,700.00 89.13 4,025.83 1,917.25 -933.592.46 550,827.226,011,350.753,965.63 0.00 1,791.61
5,800.00 89.13 4,027.36 2,017.15 -929.312.46 550,830.816,011,450.663,967.16 0.00 1,891.30
5,900.00 89.13 4,028.88 2,117.04 -925.022.46 550,834.416,011,550.583,968.68 0.00 1,990.99
6,000.00 89.13 4,030.41 2,216.94 -920.732.46 550,838.006,011,650.493,970.21 0.00 2,090.68
6,100.00 89.13 4,031.93 2,316.84 -916.452.46 550,841.596,011,750.413,971.73 0.00 2,190.37
6,200.00 89.13 4,033.46 2,416.73 -912.162.46 550,845.186,011,850.323,973.26 0.00 2,290.06
6,300.00 89.13 4,034.98 2,516.63 -907.882.46 550,848.786,011,950.233,974.78 0.00 2,389.75
6,400.00 89.13 4,036.50 2,616.53 -903.592.46 550,852.376,012,050.153,976.30 0.00 2,489.44
5/19/2020 6:32:14PM COMPASS 5000.15 Build 91E Page 5
Project:
Company:
Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt I Pad
Halliburton
Standard Proposal Report
Well:
Wellbore:
Plan: MPU I-21i
MPU I-21
Survey Calculation Method:Minimum Curvature
MPU I-21i As-built RKB @ 60.20usft
Design:MPU I-21i wp05
Database:NORTH US + CANADA
MD Reference:MPU I-21i As-built RKB @ 60.20usft
North Reference:
Well Plan: MPU I-21i
True
Measured
Depth
(usft)
Inclination
(°)
Azimuth
(°)
+E/-W
(usft)
Map
Northing
(usft)
Map
Easting
(usft)
+N/-S
(usft)
Planned Survey
Vertical
Depth
(usft)
TVDss
usft
DLS
3,977.83
Vert Section
6,500.00 89.13 4,038.03 2,716.42 -899.302.46 550,855.966,012,150.063,977.83 0.00 2,589.14
6,600.00 89.13 4,039.55 2,816.32 -895.022.46 550,859.556,012,249.983,979.35 0.00 2,688.83
6,700.00 89.13 4,041.08 2,916.22 -890.732.46 550,863.146,012,349.893,980.88 0.00 2,788.52
6,800.00 89.13 4,042.60 3,016.11 -886.442.46 550,866.746,012,449.803,982.40 0.00 2,888.21
6,900.00 89.13 4,044.13 3,116.01 -882.162.46 550,870.336,012,549.723,983.93 0.00 2,987.90
7,000.00 89.13 4,045.65 3,215.91 -877.872.46 550,873.926,012,649.633,985.45 0.00 3,087.59
7,100.00 89.13 4,047.18 3,315.80 -873.592.46 550,877.516,012,749.553,986.98 0.00 3,187.28
7,200.00 89.13 4,048.70 3,415.70 -869.302.46 550,881.116,012,849.463,988.50 0.00 3,286.97
7,300.00 89.13 4,050.23 3,515.60 -865.012.46 550,884.706,012,949.383,990.03 0.00 3,386.66
7,400.00 89.13 4,051.75 3,615.49 -860.732.46 550,888.296,013,049.293,991.55 0.00 3,486.35
7,500.00 89.13 4,053.27 3,715.39 -856.442.46 550,891.886,013,149.203,993.07 0.00 3,586.04
7,600.00 89.13 4,054.80 3,815.28 -852.152.46 550,895.476,013,249.123,994.60 0.00 3,685.73
7,700.00 89.13 4,056.32 3,915.18 -847.872.46 550,899.076,013,349.033,996.12 0.00 3,785.42
7,800.00 89.13 4,057.85 4,015.08 -843.582.46 550,902.666,013,448.953,997.65 0.00 3,885.11
7,900.00 89.13 4,059.37 4,114.97 -839.302.46 550,906.256,013,548.863,999.17 0.00 3,984.80
8,000.00 89.13 4,060.90 4,214.87 -835.012.46 550,909.846,013,648.774,000.70 0.00 4,084.49
8,100.00 89.13 4,062.42 4,314.77 -830.722.46 550,913.446,013,748.694,002.22 0.00 4,184.18
8,200.00 89.13 4,063.95 4,414.66 -826.442.46 550,917.036,013,848.604,003.75 0.00 4,283.88
8,300.00 89.13 4,065.47 4,514.56 -822.152.46 550,920.626,013,948.524,005.27 0.00 4,383.57
8,400.00 89.13 4,066.99 4,614.46 -817.872.46 550,924.216,014,048.434,006.79 0.00 4,483.26
8,500.00 89.13 4,068.52 4,714.35 -813.582.46 550,927.806,014,148.344,008.32 0.00 4,582.95
8,600.00 89.13 4,070.04 4,814.25 -809.292.46 550,931.406,014,248.264,009.84 0.00 4,682.64
8,700.00 89.13 4,071.57 4,914.15 -805.012.46 550,934.996,014,348.174,011.37 0.00 4,782.33
8,800.00 89.13 4,073.09 5,014.04 -800.722.46 550,938.586,014,448.094,012.89 0.00 4,882.02
8,900.00 89.13 4,074.62 5,113.94 -796.432.46 550,942.176,014,548.004,014.42 0.00 4,981.71
9,000.00 89.13 4,076.14 5,213.84 -792.152.46 550,945.776,014,647.924,015.94 0.00 5,081.40
9,100.00 89.13 4,077.67 5,313.73 -787.862.46 550,949.366,014,747.834,017.47 0.00 5,181.09
9,175.57 89.13 4,078.82 5,389.22 -784.622.46 550,952.076,014,823.334,018.62 0.00 5,256.43
Start Dir 3º/100' : 9175.57' MD, 4078.82'TVD
9,200.00 89.10 4,079.20 5,413.62 -783.423.19 550,953.116,014,847.744,019.00 3.00 5,280.79
9,260.41 89.02 4,080.19 5,473.86 -779.115.00 550,957.006,014,908.004,019.99 3.00 5,341.12
9,300.00 89.02 4,080.87 5,513.26 -775.256.19 550,960.596,014,947.424,020.67 3.00 5,380.69
9,357.49 89.02 4,081.85 5,570.31 -768.197.91 550,967.246,015,004.514,021.65 3.00 5,438.17
End Dir : 9357.49' MD, 4081.85' TVD
9,400.00 89.02 4,082.58 5,612.40 -762.347.91 550,972.806,015,046.644,022.38 0.00 5,480.67
9,500.00 89.02 4,084.30 5,711.44 -748.587.91 550,985.886,015,145.764,024.10 0.00 5,580.64
9,600.00 89.02 4,086.02 5,810.47 -734.817.91 550,998.956,015,244.884,025.82 0.00 5,680.61
9,700.00 89.02 4,087.73 5,909.50 -721.057.91 551,012.036,015,343.994,027.53 0.00 5,780.58
9,800.00 89.02 4,089.45 6,008.54 -707.287.91 551,025.116,015,443.114,029.25 0.00 5,880.55
9,900.00 89.02 4,091.17 6,107.57 -693.527.91 551,038.186,015,542.234,030.97 0.00 5,980.51
10,000.00 89.02 4,092.88 6,206.60 -679.757.91 551,051.266,015,641.344,032.68 0.00 6,080.48
10,100.00 89.02 4,094.60 6,305.64 -665.997.91 551,064.336,015,740.464,034.40 0.00 6,180.45
10,200.00 89.02 4,096.32 6,404.67 -652.227.91 551,077.416,015,839.584,036.12 0.00 6,280.42
10,300.00 89.02 4,098.03 6,503.70 -638.467.91 551,090.486,015,938.694,037.83 0.00 6,380.39
10,400.00 89.02 4,099.75 6,602.74 -624.697.91 551,103.566,016,037.814,039.55 0.00 6,480.36
5/19/2020 6:32:14PM COMPASS 5000.15 Build 91E Page 6
Project:
Company:
Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt I Pad
Halliburton
Standard Proposal Report
Well:
Wellbore:
Plan: MPU I-21i
MPU I-21
Survey Calculation Method:Minimum Curvature
MPU I-21i As-built RKB @ 60.20usft
Design:MPU I-21i wp05
Database:NORTH US + CANADA
MD Reference:MPU I-21i As-built RKB @ 60.20usft
North Reference:
Well Plan: MPU I-21i
True
Measured
Depth
(usft)
Inclination
(°)
Azimuth
(°)
+E/-W
(usft)
Map
Northing
(usft)
Map
Easting
(usft)
+N/-S
(usft)
Planned Survey
Vertical
Depth
(usft)
TVDss
usft
DLS
4,041.26
Vert Section
10,500.00 89.02 4,101.46 6,701.77 -610.937.91 551,116.646,016,136.934,041.26 0.00 6,580.33
10,600.00 89.02 4,103.18 6,800.80 -597.167.91 551,129.716,016,236.044,042.98 0.00 6,680.30
10,700.00 89.02 4,104.90 6,899.84 -583.407.91 551,142.796,016,335.164,044.70 0.00 6,780.27
10,800.00 89.02 4,106.61 6,998.87 -569.637.91 551,155.866,016,434.284,046.41 0.00 6,880.24
10,900.00 89.02 4,108.33 7,097.90 -555.877.91 551,168.946,016,533.404,048.13 0.00 6,980.20
11,000.00 89.02 4,110.05 7,196.94 -542.107.91 551,182.026,016,632.514,049.85 0.00 7,080.17
11,100.00 89.02 4,111.76 7,295.97 -528.347.91 551,195.096,016,731.634,051.56 0.00 7,180.14
11,200.00 89.02 4,113.48 7,395.00 -514.577.91 551,208.176,016,830.754,053.28 0.00 7,280.11
11,300.00 89.02 4,115.20 7,494.04 -500.817.91 551,221.246,016,929.864,055.00 0.00 7,380.08
11,400.00 89.02 4,116.91 7,593.07 -487.047.91 551,234.326,017,028.984,056.71 0.00 7,480.05
11,500.00 89.02 4,118.63 7,692.10 -473.287.91 551,247.406,017,128.104,058.43 0.00 7,580.02
11,600.00 89.02 4,120.35 7,791.14 -459.517.91 551,260.476,017,227.214,060.15 0.00 7,679.99
11,700.00 89.02 4,122.06 7,890.17 -445.757.91 551,273.556,017,326.334,061.86 0.00 7,779.96
11,800.00 89.02 4,123.78 7,989.20 -431.987.91 551,286.626,017,425.454,063.58 0.00 7,879.93
11,900.00 89.02 4,125.50 8,088.23 -418.227.91 551,299.706,017,524.564,065.30 0.00 7,979.89
12,000.00 89.02 4,127.21 8,187.27 -404.457.91 551,312.776,017,623.684,067.01 0.00 8,079.86
12,100.00 89.02 4,128.93 8,286.30 -390.697.91 551,325.856,017,722.804,068.73 0.00 8,179.83
12,200.00 89.02 4,130.64 8,385.33 -376.927.91 551,338.936,017,821.914,070.44 0.00 8,279.80
12,300.00 89.02 4,132.36 8,484.37 -363.167.91 551,352.006,017,921.034,072.16 0.00 8,379.77
12,400.00 89.02 4,134.08 8,583.40 -349.397.91 551,365.086,018,020.154,073.88 0.00 8,479.74
12,500.00 89.02 4,135.79 8,682.43 -335.637.91 551,378.156,018,119.264,075.59 0.00 8,579.71
12,600.00 89.02 4,137.51 8,781.47 -321.867.91 551,391.236,018,218.384,077.31 0.00 8,679.68
12,700.00 89.02 4,139.23 8,880.50 -308.107.91 551,404.316,018,317.504,079.03 0.00 8,779.65
12,800.00 89.02 4,140.94 8,979.53 -294.337.91 551,417.386,018,416.614,080.74 0.00 8,879.62
12,900.00 89.02 4,142.66 9,078.57 -280.577.91 551,430.466,018,515.734,082.46 0.00 8,979.59
13,000.00 89.02 4,144.38 9,177.60 -266.807.91 551,443.536,018,614.854,084.18 0.00 9,079.55
13,100.00 89.02 4,146.09 9,276.63 -253.047.91 551,456.616,018,713.964,085.89 0.00 9,179.52
13,200.00 89.02 4,147.81 9,375.67 -239.277.91 551,469.696,018,813.084,087.61 0.00 9,279.49
13,300.00 89.02 4,149.53 9,474.70 -225.517.91 551,482.766,018,912.204,089.33 0.00 9,379.46
13,400.00 89.02 4,151.24 9,573.73 -211.747.91 551,495.846,019,011.314,091.04 0.00 9,479.43
13,500.00 89.02 4,152.96 9,672.77 -197.987.91 551,508.916,019,110.434,092.76 0.00 9,579.40
13,600.00 89.02 4,154.68 9,771.80 -184.217.91 551,521.996,019,209.554,094.48 0.00 9,679.37
13,700.00 89.02 4,156.39 9,870.83 -170.457.91 551,535.066,019,308.664,096.19 0.00 9,779.34
13,800.00 89.02 4,158.11 9,969.87 -156.687.91 551,548.146,019,407.784,097.91 0.00 9,879.31
13,900.00 89.02 4,159.82 10,068.90 -142.927.91 551,561.226,019,506.904,099.62 0.00 9,979.28
13,921.29 89.02 4,160.19 10,089.98 -139.997.91 551,564.006,019,528.004,099.99 0.00 10,000.56
Total Depth : 13921.29' MD, 4160.19' TVD
5/19/2020 6:32:14PM COMPASS 5000.15 Build 91E Page 7
Project:
Company:
Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt I Pad
Halliburton
Standard Proposal Report
Well:
Wellbore:
Plan: MPU I-21i
MPU I-21
Survey Calculation Method:Minimum Curvature
MPU I-21i As-built RKB @ 60.20usft
Design:MPU I-21i wp05
Database:NORTH US + CANADA
MD Reference:MPU I-21i As-built RKB @ 60.20usft
North Reference:
Well Plan: MPU I-21i
True
Target Name
- hit/miss target
- Shape
TVD
(usft)
Northing
(usft)
Easting
(usft)
+N/-S
(usft)
+E/-W
(usft)
Tar gets
Dip Angle
(°)
Dip Dir.
(°)
MPI-Shiloh wp02 Heel 4,010.19 6,010,650.00 550,802.001,216.63 -963.680.00 0.00
-plan hits target center
- Circle (radius 30.00)
MPI-Shiloh wp02 Toe 4,160.19 6,019,528.00 551,564.0010,089.98 -139.990.00 0.00
-plan hits target center
- Point
MPI-Shiloh wp02 CP1 4,080.19 6,014,908.00 550,957.005,473.86 -779.110.00 0.00
-plan hits target center
- Point
Vertical
Depth
(usft)
Measured
Depth
(usft)
Casing
Diameter
(")
Hole
Diameter
(")Name
Casing Points
9 5/8" x 12 1/4"4,010.194,998.45 9-5/8 12-1/4
4 1/2" x 8 1/2"4,160.1913,921.29 4-1/2 8-1/2
Measured
Depth
(usft)
Vertical
Depth
(usft)
+E/-W
(usft)
+N/-S
(usft)
Local Coordinates
Comment
Plan Annotations
280.00 280.00 0.00 0.00 Start Dir 3º/100' : 280' MD, 280'TVD
547.20 546.74 8.14 -11.56 End Dir : 547.2' MD, 546.74' TVD
697.20 696.53 14.94 -15.49 Start Dir 3º/100' : 697.2' MD, 696.54'TVD
797.20 796.49 17.21 -16.80 End Dir : 797.2' MD, 796.49' TVD
887.20 886.49 17.21 -16.80 Start Dir 4º/100' : 887.2' MD, 886.49'TVD
1,087.20 1,085.84 6.53 -25.76 End Dir : 1087.2' MD, 1085.84' TVD
1,197.20 1,194.77 -5.20 -35.60 Start Dir 4º/100' : 1197.2' MD, 1194.77'TVD
1,613.53 1,594.77 -60.00 -131.02 End Dir : 1613.53' MD, 1594.77' TVD
2,519.60 2,426.34 -200.26 -462.36 Start Dir 4º/100' : 2519.6' MD, 2426.34'TVD
4,898.45 4,001.48 1,117.10 -967.99 End Dir : 4898.45' MD, 4001.47' TVD
4,998.45 4,010.19 1,216.62 -963.68 Start Dir 3º/100' : 4998.45' MD, 4010.19'TVD
5,136.01 4,017.24 1,353.85 -957.77 End Dir : 5136.01' MD, 4017.24' TVD
9,175.57 4,078.82 5,389.22 -784.62 Start Dir 3º/100' : 9175.57' MD, 4078.82'TVD
9,357.49 4,081.85 5,570.31 -768.19 End Dir : 9357.49' MD, 4081.85' TVD
13,921.29 4,160.19 10,089.98 -139.99 Total Depth : 13921.29' MD, 4160.19' TVD
5/19/2020 6:32:14PM COMPASS 5000.15 Build 91E Page 8
19 May, 2020Milne PointM Pt I PadPlan: MPU I-21iMPU I-21MPU I-21i wp05Reference Design: M Pt I Pad - Plan: MPU I-21i - MPU I-21 - MPU I-21i wp05Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Well Coordinates: 6,009,440.21 N, 551,774.01 E (70° 26' 11.53" N, 149° 34' 40.36" W)Datum Height: MPU I-21i As-built RKB @ 60.20usftScan Range: 26.50 to 4,998.45 usft. Measured Depth.Geodetic Scale Factor AppliedVersion: 5000.15 Build: 91EScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftNO GLOBAL FILTER: Using user defined selection & filtering criteriaScan Type:Scan Type:25.00surface to 5000 ftScan Range: 26.50 to 4,998.45 usft. Measured Depth.
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-21i - MPU I-21i wp05Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 26.50 to 4,998.45 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt I Pad - Plan: MPU I-21i - MPU I-21 - MPU I-21i wp05MeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt I PadMPI-01 - MPI-01 - MPI-0144.71 977.54 36.51 990.49 5.456977.54Ellipse Separation Pass - MPI-01 - MPI-01 - MPI-0145.15 1,001.50 36.82 1,013.17 5.4231,001.50Clearance Factor Pass - MPI-02 - MPI-02 - MPI-0264.19 1,120.93 54.93 1,141.88 6.9331,120.93Centre Distance Pass - MPI-02 - MPI-02 - MPI-0264.23 1,126.50 54.93 1,146.91 6.9031,126.50Ellipse Separation Pass - MPI-02 - MPI-02 - MPI-0265.53 1,151.50 56.02 1,169.33 6.8931,151.50Clearance Factor Pass - MPI-03 - MPI-03 - MPI-03172.77 1,113.83 163.60 1,115.69 18.8461,113.83Centre Distance Pass - MPI-03 - MPI-03 - MPI-03172.84 1,126.50 163.58 1,127.22 18.6681,126.50Ellipse Separation Pass - MPI-03 - MPI-03 - MPI-03180.55 1,251.50 170.48 1,239.30 17.9281,251.50Clearance Factor Pass - MPI-04 - MPI-04 - MPI-04235.35 1,080.56 226.32 1,096.59 26.0551,080.56Ellipse Separation Pass - MPI-04 - MPI-04 - MPI-04252.92 1,276.50 242.44 1,262.66 24.1261,276.50Clearance Factor Pass - MPI-04 - MPI-04A - MPI-04A235.35 1,080.56 226.32 1,096.59 26.0551,080.56Ellipse Separation Pass - MPI-04 - MPI-04A - MPI-04A252.92 1,276.50 242.44 1,262.66 24.1261,276.50Clearance Factor Pass - MPI-04 - MPI-04AL1 - MPI-04AL1235.35 1,080.56 226.32 1,096.59 26.0551,080.56Ellipse Separation Pass - MPI-04 - MPI-04AL1 - MPI-04AL1252.92 1,276.50 242.44 1,262.66 24.1261,276.50Clearance Factor Pass - MPI-04 - MPI-04APB1 - MPI-04APB1235.35 1,080.56 226.32 1,096.59 26.0551,080.56Ellipse Separation Pass - MPI-04 - MPI-04APB1 - MPI-04APB1252.92 1,276.50 242.44 1,262.66 24.1261,276.50Clearance Factor Pass - MPI-04 - MPI-04PB1 - MPI-04PB1235.35 1,080.56 226.32 1,096.59 26.0551,080.56Ellipse Separation Pass - MPI-04 - MPI-04PB1 - MPI-04PB1252.92 1,276.50 242.44 1,262.66 24.1261,276.50Clearance Factor Pass - MPI-05 - MPI-05 - MPI-0537.86 1,467.65 27.96 1,474.93 3.8241,467.65Ellipse Separation Pass - MPI-05 - MPI-05 - MPI-0538.13 1,476.50 28.11 1,482.52 3.8051,476.50Clearance Factor Pass - MPI-06 - MPI-06 - MPI-06229.19 1,867.96 215.33 1,775.84 16.5321,867.96Centre Distance Pass - MPI-06 - MPI-06 - MPI-06229.22 1,876.50 215.31 1,783.34 16.4771,876.50Ellipse Separation Pass - MPI-06 - MPI-06 - MPI-06231.54 1,951.50 217.21 1,850.00 16.1561,951.50Clearance Factor Pass - MPI-07 - MPI-07 - MPI-07153.67 1,830.16 141.29 1,789.94 12.4111,830.16Ellipse Separation Pass - MPI-07 - MPI-07 - MPI-07155.83 1,876.50 143.09 1,827.38 12.2331,876.50Clearance Factor Pass - MPI-09 - MPI-09 - MPI-0998.79 754.47 92.34 756.68 15.299754.47Ellipse Separation Pass - MPI-09 - MPI-09 - MPI-09101.99 851.50 95.09 850.58 14.772851.50Clearance Factor Pass - MPI-10 - MPI-10 - MPI-1050.76 561.59 46.17 561.98 11.053561.59Centre Distance Pass - 19 May, 2020-18:26COMPASSPage 2 of 7
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-21i - MPU I-21i wp05Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 26.50 to 4,998.45 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt I Pad - Plan: MPU I-21i - MPU I-21 - MPU I-21i wp05MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPI-10 - MPI-10 - MPI-1050.83 576.50 46.13 576.47 10.805576.50Ellipse Separation Pass - MPI-10 - MPI-10 - MPI-1057.85 851.50 51.08 850.25 8.545851.50Clearance Factor Pass - MPI-15 - MPI-15 - MPI-1530.89 633.46 26.40 635.85 6.888633.46Centre Distance Pass - MPI-15 - MPI-15 - MPI-1530.97 651.50 26.39 653.75 6.754651.50Ellipse Separation Pass - MPI-15 - MPI-15 - MPI-1532.27 701.50 27.39 703.21 6.605701.50Clearance Factor Pass - MPI-15 - MPI-15L1 - MPI-15L130.89 633.46 26.40 635.85 6.888633.46Centre Distance Pass - MPI-15 - MPI-15L1 - MPI-15L130.97 651.50 26.39 653.75 6.754651.50Ellipse Separation Pass - MPI-15 - MPI-15L1 - MPI-15L132.27 701.50 27.39 703.21 6.605701.50Clearance Factor Pass - MPI-15 - MPI-15PB1 - MPI-15PB130.89 633.46 26.40 635.85 6.888633.46Centre Distance Pass - MPI-15 - MPI-15PB1 - MPI-15PB130.97 651.50 26.39 653.75 6.754651.50Ellipse Separation Pass - MPI-15 - MPI-15PB1 - MPI-15PB132.27 701.50 27.39 703.21 6.605701.50Clearance Factor Pass - MPI-16 - MPI-16 - MPI-1614.59 101.50 12.74 109.65 7.904101.50Centre Distance Pass - MPI-16 - MPI-16 - MPI-1614.90 201.50 12.39 209.54 5.931201.50Ellipse Separation Pass - MPI-16 - MPI-16 - MPI-1617.43 301.50 14.18 309.04 5.368301.50Clearance Factor Pass - MPI-17 - MPI-17 - MPI-1715.59 26.50 13.74 34.65 8.43626.50Centre Distance Pass - MPI-17 - MPI-17 - MPI-1715.79 101.50 13.58 109.57 7.137101.50Ellipse Separation Pass - MPI-17 - MPI-17 - MPI-17177.12 3,426.50 130.74 3,626.13 3.8193,426.50Clearance Factor Pass - MPI-17 - MPI-17L1 - MPI-17L115.59 26.50 13.74 34.65 8.43626.50Centre Distance Pass - MPI-17 - MPI-17L1 - MPI-17L115.79 101.50 13.58 109.57 7.137101.50Ellipse Separation Pass - MPI-17 - MPI-17L1 - MPI-17L1177.12 3,426.50 130.74 3,626.13 3.8193,426.50Clearance Factor Pass - MPI-17 - MPI-17L1PB1 - MPI-17L1PB115.59 26.50 13.74 34.65 8.43626.50Centre Distance Pass - MPI-17 - MPI-17L1PB1 - MPI-17L1PB115.79 101.50 13.58 109.57 7.137101.50Ellipse Separation Pass - MPI-17 - MPI-17L1PB1 - MPI-17L1PB1177.12 3,426.50 130.74 3,626.13 3.8193,426.50Clearance Factor Pass - MPI-17 - MPI-17L2 - MPI-17L215.59 26.50 13.74 34.65 8.43626.50Centre Distance Pass - MPI-17 - MPI-17L2 - MPI-17L215.79 101.50 13.58 109.57 7.137101.50Ellipse Separation Pass - MPI-17 - MPI-17L2 - MPI-17L2177.12 3,426.50 130.74 3,626.13 3.8193,426.50Clearance Factor Pass - MPI-18 - MPI-18 - MPI-1845.36 26.50 43.51 29.50 24.56726.50Centre Distance Pass - MPI-18 - MPI-18 - MPI-1845.58 101.50 43.44 104.28 21.299101.50Ellipse Separation Pass - MPI-18 - MPI-18 - MPI-18300.18 2,751.50 265.86 2,833.46 8.7462,751.50Clearance Factor Pass - MPI-19 - MPI-19 - MPI-1975.82 26.50 73.97 35.37 41.05426.50Ellipse Separation Pass - 19 May, 2020-18:26COMPASSPage 3 of 7
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-21i - MPU I-21i wp05Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 26.50 to 4,998.45 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt I Pad - Plan: MPU I-21i - MPU I-21 - MPU I-21i wp05MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPI-19 - MPI-19 - MPI-1992.85 951.50 84.84 961.56 11.601951.50Clearance Factor Pass - MPI-19 - MPI-19L1 - MPI-19L175.82 26.50 73.97 35.37 41.05426.50Ellipse Separation Pass - MPI-19 - MPI-19L1 - MPI-19L192.85 951.50 84.84 961.56 11.601951.50Clearance Factor Pass - MPI-19 - MPI-19PB1 - MPI-19PB175.82 26.50 73.97 35.37 41.05426.50Ellipse Separation Pass - MPI-19 - MPI-19PB1 - MPI-19PB192.85 951.50 84.84 961.56 11.601951.50Clearance Factor Pass - MPI-19 - MPI-19PB2 - MPI-19PB275.82 26.50 73.97 35.37 41.05426.50Ellipse Separation Pass - MPI-19 - MPI-19PB2 - MPI-19PB292.85 951.50 84.84 961.56 11.601951.50Clearance Factor Pass - MPU I-35i - MPU I-35i - MPU I-35i wp0829.69 276.50 27.13 276.40 11.605276.50Ellipse Separation Pass - MPU I-35i - MPU I-35i - MPU I-35i wp0852.17 1,451.50 44.73 1,461.12 7.0101,451.50Clearance Factor Pass - MPU I-35i - MPU I-35i - MPU I-35i29.69 26.50 27.78 26.75 15.53426.50Ellipse Separation Pass - MPU I-35i - MPU I-35i - MPU I-35i54.53 1,451.50 45.68 1,461.24 6.1611,451.50Clearance Factor Pass - Plan: MPU I-20 - MPU I-20 - MPU I-20 wp0589.92 276.50 87.36 276.50 35.142276.50Ellipse Separation Pass - Plan: MPU I-20 - MPU I-20 - MPU I-20 wp05119.28 1,126.50 112.93 1,124.75 18.7771,126.50Clearance Factor Pass - Plan: MPU I-22 - MPU I-22 - MPU I-22 wp03107.67 505.15 104.05 500.81 29.743505.15Ellipse Separation Pass - Plan: MPU I-22 - MPU I-22 - MPU I-22 wp03917.42 4,998.45 869.75 5,508.31 19.2464,998.45Clearance Factor Pass - Plan: MPU I-27 - MPU I-27 - MPU I-27 wp0459.75 276.50 57.19 276.40 23.350276.50Ellipse Separation Pass - Plan: MPU I-27 - MPU I-27 - MPU I-27 wp0498.03 1,326.50 91.27 1,333.63 14.5091,326.50Clearance Factor Pass - Plan: MPU I-28i - MPU I-28 - MPU I-28i wp0320.51 750.21 15.63 749.35 4.201750.21Centre Distance Pass - Plan: MPU I-28i - MPU I-28 - MPU I-28i wp0320.51 751.50 15.62 750.64 4.196751.50Ellipse Separation Pass - Plan: MPU I-28i - MPU I-28 - MPU I-28i wp0320.72 776.50 15.71 775.48 4.134776.50Clearance Factor Pass - Plan: MPU I-29 - MPU I-29 - MPU I-29 wp0354.46 462.11 51.04 458.73 15.900462.11Ellipse Separation Pass - Plan: MPU I-29 - MPU I-29 - MPU I-29 wp0357.03 526.50 53.29 521.14 15.219526.50Clearance Factor Pass - Rig: MPU I-36 - MPU I-36 - MPU I-36 wp0775.84 672.76 71.37 670.35 16.967672.76Centre Distance Pass - Rig: MPU I-36 - MPU I-36 - MPU I-36 wp0775.85 676.50 71.36 673.99 16.897676.50Ellipse Separation Pass - Rig: MPU I-36 - MPU I-36 - MPU I-36 wp07487.76 4,998.45 443.45 5,054.18 11.0084,998.45Clearance Factor Pass - M Pt J PadMPJ-03 - MPJ-03 - MPJ-031,469.65 4,998.45 1,417.81 5,448.00 28.3494,998.45Clearance Factor Pass - 19 May, 2020-18:26COMPASSPage 4 of 7
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-21i - MPU I-21i wp05Survey tool programFrom(usft)To(usft)Survey/Plan Survey Tool26.50 800.00 MPU I-21i wp05 3_Gyro-GC_Csg800.00 4,998.45 MPU I-21i wp05 3_MWD+IFR2+MS+Sag4,998.45 13,921.29 MPU I-21i wp05 3_MWD+IFR2+MS+SagEllipse error terms are correlated across survey tool tie-on points.Separation is the actual distance between ellipsoids.Calculated ellipses incorporate surface errors.Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation).Distance Between centres is the straight line distance between wellbore centres.All station coordinates were calculated using the Minimum Curvature method.19 May, 2020-18:26COMPASSPage 5 of 7
0.001.002.003.004.00Separation Factor0 275 550 825 1100 1375 1650 1925 2200 2475 2750 3025 3300 3575 3850 4125 4400 4675 4950 5225Measured Depth (550 usft/in)MPU I-28i wp03No-Go Zone - Stop DrillingCollision Avoidance Req.Collision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: MPU I-21i NAD 1927 (NADCON CONUS)Alaska Zone 0433.40+N/-S +E/-W Northing Easting Latittude Longitude0.000.006009440.21551774.0170° 26' 11.528 N 149° 34' 40.361 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU I-21i, True NorthVertical (TVD) Reference:MPU I-21i As-built RKB @ 60.20usftMeasured Depth Reference:MPU I-21i As-built RKB @ 60.20usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2020-03-27T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.50 800.00 MPU I-21i wp05 (MPU I-21) 3_Gyro-GC_Csg800.00 4998.45 MPU I-21i wp05 (MPU I-21) 3_MWD+IFR2+MS+Sag4998.45 13921.29 MPU I-21i wp05 (MPU I-21) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 275 550 825 1100 1375 1650 1925 2200 2475 2750 3025 3300 3575 3850 4125 4400 4675 4950 5225Measured Depth (550 usft/in)MPU I-35iMPU I-27 wp04MPU I-36 wp07MPI-17MPI-19MPI-16MPI-10MPI-15MPU I-29 wp03MPI-18MPU I-28i wp03NO GLOBAL FILTER: Using user defined selection & filtering criteria26.50 To 13921.62Project: Milne PointSite: M Pt I PadWell: Plan: MPU I-21iWellbore: MPU I-21Plan: MPU I-21i wp05Ladder / S.F. Plots1 of 2CASING DETAILSTVD TVDSS MD Size Name4010.19 3949.99 4998.45 9-5/8 9 5/8" x 12 1/4"4160.19 4099.99 13921.29 4-1/2 4 1/2" x 8 1/2"
19 May, 2020Milne PointM Pt I PadPlan: MPU I-21iMPU I-21MPU I-21i wp05Reference Design: M Pt I Pad - Plan: MPU I-21i - MPU I-21 - MPU I-21i wp05Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Well Coordinates: 6,009,440.21 N, 551,774.01 E (70° 26' 11.53" N, 149° 34' 40.36" W)Datum Height: MPU I-21i As-built RKB @ 60.20usftScan Range: 4,998.45 to 13,921.29 usft. Measured Depth.Geodetic Scale Factor AppliedVersion: 5000.15 Build: 91EScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftNO GLOBAL FILTER: Using user defined selection & filtering criteriaScan Type:Scan Type:25.00Scan Range: 4,998.45 to 13,921.29 usft. Measured Depth.5000 ft to 13900 ft
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-21i - MPU I-21i wp05Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 4,998.45 to 13,921.29 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt I Pad - Plan: MPU I-21i - MPU I-21 - MPU I-21i wp05MeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt I PadMPI-07 - MPI-07 - MPI-071,273.53 4,998.45 1,240.29 4,041.90 38.3034,998.45Clearance Factor Pass - MPI-09 - MPI-09 - MPI-091,076.91 5,518.51 1,017.05 4,250.95 17.9905,518.51Centre Distance Pass - MPI-09 - MPI-09 - MPI-091,088.39 5,748.45 1,008.08 4,432.12 13.5525,748.45Ellipse Separation Pass - MPI-09 - MPI-09 - MPI-091,408.57 6,873.45 1,238.35 5,267.90 8.2756,873.45Clearance Factor Pass - MPI-17 - MPI-17 - MPI-171,382.56 4,998.45 1,293.35 4,525.81 15.4994,998.45Clearance Factor Pass - MPI-17 - MPI-17L1 - MPI-17L11,382.56 4,998.45 1,293.35 4,525.81 15.4994,998.45Clearance Factor Pass - MPI-17 - MPI-17L1PB1 - MPI-17L1PB11,382.56 4,998.45 1,293.35 4,525.81 15.4994,998.45Clearance Factor Pass - MPI-17 - MPI-17L2 - MPI-17L21,382.56 4,998.45 1,293.35 4,525.81 15.4994,998.45Clearance Factor Pass - MPI-19 - MPI-19 - MPI-195.409,673.45-140.628,107.900.0379,673.45Ellipse SeparationFAIL - MPI-19 - MPI-19 - MPI-192.439,698.45-138.228,132.640.0179,698.45Clearance FactorFAIL - MPI-19 - MPI-19 - MPI-192.089,706.72-94.048,140.820.0229,706.72Centre DistanceFAIL - MPI-19 - MPI-19L1 - MPI-19L146.219,031.77-2.077,458.060.9579,031.77Centre DistanceFAIL - MPI-19 - MPI-19L1 - MPI-19L156.159,248.45-50.117,672.980.5289,248.45Clearance FactorFAIL - MPI-19 - MPI-19L1 - MPI-19L157.579,273.45-51.297,698.740.5299,273.45Ellipse SeparationFAIL - MPI-19 - MPI-19PB1 - MPI-19PB16.369,048.63-53.507,479.520.1069,048.63Centre DistanceFAIL - MPI-19 - MPI-19PB1 - MPI-19PB18.629,073.45-102.437,503.550.0789,073.45Clearance FactorFAIL - MPI-19 - MPI-19PB1 - MPI-19PB113.199,098.45-112.117,527.900.1059,098.45Ellipse SeparationFAIL - MPI-19 - MPI-19PB2 - MPI-19PB21.369,904.55-85.358,339.810.0169,904.55Clearance FactorFAIL - MPI-19 - MPI-19PB2 - MPI-19PB23.899,923.45-152.738,358.360.0259,923.45Ellipse SeparationFAIL - MPU I-35i - MPU I-35i - MPU I-35i606.17 4,998.45 565.80 4,490.41 15.0134,998.45Centre Distance Pass - MPU I-35i - MPU I-35i - MPU I-35i652.86 13,673.45 390.68 13,130.00 2.49013,673.45Clearance Factor Pass - Plan: MPU I-20 - MPU I-20 - MPU I-20 wp05784.42 13,921.29 525.27 13,532.03 3.02713,921.29Clearance Factor Pass - Plan: MPU I-22 - MPU I-22 - MPU I-22 wp03709.00 13,921.29 448.17 14,565.45 2.71813,921.29Clearance Factor Pass - Plan: MPU I-27 - MPU I-27 - MPU I-27 wp04660.89 4,998.45 616.33 4,792.04 14.8344,998.45Centre Distance Pass - Plan: MPU I-27 - MPU I-27 - MPU I-27 wp04733.57 13,921.29 474.25 13,678.19 2.82913,921.29Clearance Factor Pass - Plan: MPU I-29 - MPU I-29 - MPU I-29 wp03674.66 13,921.29 415.15 14,583.21 2.60013,921.29Clearance Factor Pass - Rig: MPU I-36 - MPU I-36 - MPU I-36 wp07327.28 13,921.29 121.14 14,017.75 1.58813,921.29Clearance Factor Pass - 19 May, 2020-18:28COMPASSPage 2 of 7see noteson 8 1/2" holesection.pg. 47
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-21i - MPU I-21i wp05Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 4,998.45 to 13,921.29 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt I Pad - Plan: MPU I-21i - MPU I-21 - MPU I-21i wp05MeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt J PadMPJ-01 - MPJ-01 - MPJ-01810.63 10,464.58 696.49 4,299.90 7.10210,464.58Ellipse Separation Pass - MPJ-01 - MPJ-01 - MPJ-01810.67 10,473.45 696.52 4,303.05 7.10210,473.45Clearance Factor Pass - MPJ-01 - MPJ-01A - MPJ-01A168.5311,887.758.145,669.061.05111,887.75Centre DistancePass - MPJ-01 - MPJ-01A - MPJ-01A168.9411,923.457.595,700.611.04711,923.45Clearance FactorPass - MPJ-01 - MPJ-01AL1 - MPJ-01AL1254.20 11,456.26 106.84 5,229.91 1.72511,456.26Centre Distance Pass - MPJ-01 - MPJ-01AL1 - MPJ-01AL1254.60 11,473.45 106.69 5,247.00 1.72111,473.45Clearance Factor Pass - MPJ-03 - MPJ-03 - MPJ-03538.33 6,348.45 421.99 5,435.89 4.6276,348.45Clearance Factor Pass - MPJ-03 - MPJ-03 - MPJ-03537.45 6,373.45 421.92 5,418.56 4.6526,373.45Ellipse Separation Pass - MPJ-03 - MPJ-03 - MPJ-03537.18 6,397.29 422.56 5,402.04 4.6876,397.29Centre Distance Pass - MPJ-06 - MPJ-06 - MPJ-06441.09 10,573.45 305.94 4,642.03 3.26410,573.45Clearance Factor Pass - MPJ-06 - MPJ-06 - MPJ-06439.15 10,598.45 304.82 4,656.26 3.26910,598.45Ellipse Separation Pass - MPJ-06 - MPJ-06 - MPJ-06437.98 10,638.18 305.48 4,679.05 3.30510,638.18Centre Distance Pass - MPJ-08 - MPJ-08 - MPJ-08388.57 10,728.04 314.89 4,561.97 5.27410,728.04Centre Distance Pass - MPJ-08 - MPJ-08 - MPJ-08407.10 10,923.45 293.48 4,716.15 3.58310,923.45Ellipse Separation Pass - MPJ-08 - MPJ-08 - MPJ-08909.42 13,898.45 601.99 7,761.56 2.95813,898.45Clearance Factor Pass - MPJ-08 - MPJ-08A - MPJ-08A388.57 10,728.04 314.89 4,562.77 5.27410,728.04Centre Distance Pass - MPJ-08 - MPJ-08A - MPJ-08A407.10 10,923.45 293.48 4,716.95 3.58310,923.45Ellipse Separation Pass - MPJ-08 - MPJ-08A - MPJ-08A463.25 11,123.45 319.18 4,870.73 3.21611,123.45Clearance Factor Pass - MPJ-09 - MPJ-09 - MPJ-091,089.33 10,389.26 999.49 4,233.71 12.12510,389.26Centre Distance Pass - MPJ-09 - MPJ-09 - MPJ-091,096.20 10,523.45 991.89 4,289.98 10.50910,523.45Ellipse Separation Pass - MPJ-09 - MPJ-09 - MPJ-091,472.82 11,573.45 1,259.16 5,318.49 6.89311,573.45Clearance FactorPass - MPJ-09 - MPJ-09A - MPJ-09A1,089.33 10,389.26 999.50 4,233.98 12.12710,389.26Centre Distance Pass - MPJ-09 - MPJ-09A - MPJ-09A1,096.20 10,523.45 991.91 4,290.25 10.51110,523.45Ellipse Separation Pass - MPJ-09 - MPJ-09A - MPJ-09A1,472.82 11,573.45 1,259.38 5,318.76 6.90011,573.45Clearance Factor Pass - MPJ-11 - MPJ-11 - MPJ-11413.69 12,523.45 198.51 5,551.49 1.92312,523.45Clearance Factor Pass - MPJ-11 - MPJ-11 - MPJ-11412.58 12,569.77 199.28 5,585.79 1.93412,569.77Centre Distance Pass - MPJ-12 - MPJ-12 - MPJ-121,296.02 10,954.94 1,154.35 4,483.38 9.14910,954.94Centre Distance Pass - MPJ-12 - MPJ-12 - MPJ-121,296.12 10,973.45 1,154.14 4,492.08 9.12910,973.45Ellipse Separation Pass - MPJ-12 - MPJ-12 - MPJ-121,304.02 11,123.45 1,159.98 4,573.78 9.05311,123.45Clearance Factor Pass - 19 May, 2020-18:28COMPASSPage 3 of 7
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-21i - MPU I-21i wp05Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 4,998.45 to 13,921.29 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt I Pad - Plan: MPU I-21i - MPU I-21 - MPU I-21i wp05MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPJ-15 - MPJ-15 - MPJ-151,084.41 12,401.30 900.51 5,359.81 5.89712,401.30Centre Distance Pass - MPJ-15 - MPJ-15 - MPJ-151,101.11 12,698.45 880.23 5,585.29 4.98512,698.45Ellipse Separation Pass - MPJ-15 - MPJ-15 - MPJ-151,263.30 13,423.45 970.18 6,195.79 4.31013,423.45Clearance Factor Pass - MPJ-16 - MPJ-16 - MPJ-16153.6912,923.49-79.086,133.020.66012,923.49Centre DistanceFAIL - MPJ-16 - MPJ-16 - MPJ-16155.8512,973.45-88.656,175.510.63712,973.45Clearance FactorFAIL - MPJ-16 - MPJ-16 - MPJ-16158.4712,998.45-89.646,196.870.63912,998.45Ellipse SeparationFAIL - MPJ-22 - MPJ-22 - MPJ-22959.66 9,063.60 902.31 3,946.83 16.7349,063.60Centre Distance Pass - MPJ-22 - MPJ-22 - MPJ-22961.45 9,123.45 901.20 3,958.83 15.9589,123.45Ellipse Separation Pass - MPJ-22 - MPJ-22 - MPJ-221,151.66 9,673.45 1,058.63 4,044.71 12.3799,673.45Clearance Factor Pass - MPJ-25 - MPJ-25 - MPJ-25331.91 10,220.21 272.28 4,188.52 5.56610,220.21Centre Distance Pass - MPJ-25 - MPJ-25 - MPJ-25341.16 10,298.45 267.56 4,224.40 4.63510,298.45Ellipse Separation Pass - MPJ-25 - MPJ-25 - MPJ-25353.92 10,348.45 275.95 4,224.40 4.53910,348.45Clearance Factor Pass - MPJ-25 - MPJ-25PB1 - MPJ-25PB1304.19 10,251.43 222.87 4,282.67 3.74110,251.43Centre Distance Pass - MPJ-25 - MPJ-25PB1 - MPJ-25PB1311.56 10,323.45 216.64 4,307.23 3.28210,323.45Ellipse Separation Pass - MPJ-25 - MPJ-25PB1 - MPJ-25PB1333.83 10,398.45 228.06 4,332.96 3.15610,398.45Clearance Factor Pass - Survey tool programFrom(usft)To(usft)Survey/Plan Survey Tool26.50 800.00 MPU I-21i wp05 3_Gyro-GC_Csg800.00 4,998.45 MPU I-21i wp05 3_MWD+IFR2+MS+Sag4,998.45 13,921.29 MPU I-21i wp05 3_MWD+IFR2+MS+Sag19 May, 2020-18:28COMPASSPage 4 of 7(shut in Kup Inj)see page 47
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-21i - MPU I-21i wp05Ellipse error terms are correlated across survey tool tie-on points.Separation is the actual distance between ellipsoids.Calculated ellipses incorporate surface errors.Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation).Distance Between centres is the straight line distance between wellbore centres.All station coordinates were calculated using the Minimum Curvature method.19 May, 2020-18:28COMPASSPage 5 of 7
0.001.002.003.004.00Separation Factor4750 5225 5700 6175 6650 7125 7600 8075 8550 9025 9500 9975 10450 10925 11400 11875 12350 12825 13300 13775Measured Depth (950 usft/in)MPJ-03MPI-19PB1MPI-19PB2MPI-19MPI-19L1MPJ-16No-Go Zone - Stop DrillingCollision Avoidance Req.Collision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: MPU I-21i NAD 1927 (NADCON CONUS)Alaska Zone 0433.40+N/-S +E/-W Northing Easting Latittude Longitude0.000.006009440.21551774.0170° 26' 11.528 N149° 34' 40.361 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU I-21i, True NorthVertical (TVD) Reference:MPU I-21i As-built RKB @ 60.20usftMeasured Depth Reference:MPU I-21i As-built RKB @ 60.20usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2020-03-27T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.50 800.00 MPU I-21i wp05 (MPU I-21) 3_Gyro-GC_Csg800.00 4998.45 MPU I-21i wp05 (MPU I-21) 3_MWD+IFR2+MS+Sag4998.45 13921.29 MPU I-21i wp05 (MPU I-21) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)4750 5225 5700 6175 6650 7125 7600 8075 8550 9025 9500 9975 10450 10925 11400 11875 12350 12825 13300 13775Measured Depth (950 usft/in)MPI-19PB2MPI-19MPI-19L1NO GLOBAL FILTER: Using user defined selection & filtering criteria26.50 To 13921.62Project: Milne PointSite: M Pt I PadWell: Plan: MPU I-21iWellbore: MPU I-21Plan: MPU I-21i wp05Ladder / S.F. Plots2 of 2CASING DETAILSTVD TVDSS MD Size Name4010.19 3949.99 4998.45 9-5/8 9 5/8" x 12 1/4"4160.19 4099.99 13921.29 4-1/2 4 1/2" x 8 1/2"
1
Carlisle, Samantha J (CED)
From:Joseph Engel <jengel@hilcorp.com>
Sent:Wednesday, June 10, 2020 11:19 AM
To:Schwartz, Guy L (CED)
Subject:HAK MPU i-21 (PTD: TBD) Directional and AC Pressures
Attachments:MPU I-21i wp06.txt; MPU I-21i wp06 Proposal Report.pdf
Guy–
AttachedistheupdateddirectionalplanthatshowsthelateralbeingnudgedtoincreaseseparationwithJͲ16.Thatisthe
onlychange.
WeattemptedtodriftJͲ16togetagyroonitforthiscloseapproach,butwereunabletogetpastschmooat~2400’.
Atthattimeoftherigup,WHPonJͲ16was591psi;wesuspectitispluggedupwithsomething,aswepressuredupto
2500psi.
Nearbywell,JͲ06,hasaSBHPof1965psiat5900tvd,6.4ppgEMW.
Pleaseletmeknowifyouhaveanyquestions.
Thankyouforyourtime.
ͲJoe
Joe Engel | Drilling Engineer | Hilcorp Alaska, LLC
3800 Centerpoint Dr., Ste. 1400 | Anchorage | AK | 99503
Office: 907.777.8395 | Cell: 805.235.6265
05 June, 2020
Plan: MPU I-21 wp06
Milne Point
M Pt I Pad
Plan: MPU I-21i
MPU I-21
-1500
-750
0
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3750
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South(-)/North(+) (1500 usft/in)-5250 -4500 -3750 -3000 -2250 -1500 -750 0 750 1500 2250 3000 3750 4500
West(-)/East(+) (1500 usft/in)
MPI-Shiloh wp02 CP1
MPI-Shiloh wp02 Toe
MPI-Shiloh wp02 Heel
9 5/8" x 12 1/4"
4 1/2" x 8 1/2"15002000250032503 7 5 0
4000
4160
MPU I-21 wp06
Start Dir 3º/100' : 280' MD, 280'TVD
End Dir : 520' MD, 519.6' TVD
Start Dir 3º/100' : 670' MD, 669.39'TVD
End Dir : 770' MD, 769.35' TVD
Start Dir 4º/100' : 860' MD, 859.35'TVD
End Dir : 1060' MD, 1058.7' TVD
Start Dir 4º/100' : 1170' MD, 1167.63'TVD
End Dir : 1584.12' MD, 1565.61' TVD
Start Dir 4º/100' : 2521.79' MD, 2426.79'TVD
End Dir : 4899.32' MD, 4001.47' TVD
Start Dir 3º/100' : 4999.32' MD, 4010.19'TVD
End Dir : 5138.29' MD, 4017.3' TVD
Start Dir 3º/100' : 9086.4' MD, 4077.26'TVD
End Dir : 9268' MD, 4080.19' TVD
Start Dir 3º/100' : 13016.8' MD, 4144.31'TVD
End Dir : 13050.13' MD, 4144.88' TVD
Total Depth : 13930' MD, 4159.93' TVD
CASING DETAILS
TVD TVDSS MD Size Name
4010.19 3949.99 4999.32 9-5/8 9 5/8" x 12 1/4"
4159.93 4099.73 13930.00 4-1/2 4 1/2" x 8 1/2"
Project: Milne Point
Site: M Pt I Pad
Well: Plan: MPU I-21i
Wellbore: MPU I-21
Plan: MPU I-21 wp06
WELL DETAILS: Plan: MPU I-21i
33.40
+N/-S +E/-W Northing Easting Latittude Longitude
0.00 0.00 6009440.21 551774.01 70° 26' 11.528 N 149° 34' 40.361 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: MPU I-21i, True North
Vertical (TVD) Reference:MPU I-21i As-built RKB @ 60.20usft
Measured Depth Reference:MPU I-21i As-built RKB @ 60.20usft
Calculation Method:Minimum Curvature
075015002250300037504500True Vertical Depth (1500 usft/in)-1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500Vertical Section at 6.88° (1500 usft/in)MPI-Shiloh wp02 HeelMPI-Shiloh wp02 ToeMPI-Shiloh wp02 CP19 5/8" x 12 1/4"4 1/2" x 8 1/2"500100015002000250030003500400045005000
5500
6000
6500
7000
7500
8000
8500
9000
9500
10000
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12000
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13000
13500
13930MPU I-21 wp06Start Dir 3º/100' : 280' MD, 280'TVDEnd Dir : 520' MD, 519.6' TVDStart Dir 3º/100' : 670' MD, 669.39'TVDEnd Dir : 770' MD, 769.35' TVDStart Dir 4º/100' : 860' MD, 859.35'TVDEnd Dir : 1060' MD, 1058.7' TVDStart Dir 4º/100' : 1170' MD, 1167.63'TVDEnd Dir : 1584.12' MD, 1565.61' TVDStartDir4º/100':2521.79'MD,2426.79'TVDEndDir :4899.32' MD, 4001.47'TVDStartDir3º/100':4999.32'MD, 4010.19'TVDEndDir : 5138.29' MD, 4017.3'TVDStartDir3º/100':9086.4'MD, 4077.26'TVDEndDir : 9268' MD, 4080.19'TVDStartDir3º/100':13016.8'MD, 4144.31'TVDEndDir : 13050.13' MD, 4144.88'TVDTotal Depth:13930'MD,4159.93' TVDHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Pedal CurveWarning Method: Error RatioWELL DETAILS: Plan: MPU I-21i33.40+N/-S +E/-WNorthingEastingLatittudeLongitude0.000.006009440.21551774.01 70° 26' 11.528 N 149° 34' 40.361 WSURVEY PROGRAMDate: 2020-03-27T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool26.50 700.00 MPU I-21 wp06 (MPU I-21) 3_Gyro-GC_Csg700.00 4999.32 MPU I-21 wp06 (MPU I-21) 3_MWD+IFR2+MS+Sag4999.32 13930.00 MPU I-21 wp06 (MPU I-21) 3_MWD+IFR2+MS+SagFORMATION TOP DETAILSNo formation data is availableREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU I-21i, True NorthVertical (TVD) Reference:MPU I-21i As-built RKB @ 60.20usftMeasured Depth Reference:MPU I-21i As-built RKB @ 60.20usftCalculation Method:Minimum CurvatureProject:Milne PointSite:M Pt I PadWell:Plan: MPU I-21iWellbore:MPU I-21Design:MPU I-21 wp06CASING DETAILSTVD TVDSS MD SizeName4010.19 3949.99 4999.32 9-5/8 9 5/8" x 12 1/4"4159.93 4099.73 13930.00 4-1/2 4 1/2" x 8 1/2"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 26.50 0.00 0.00 26.50 0.00 0.00 0.00 0.00 0.002 280.00 0.00 0.00 280.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 280' MD, 280'TVD3 450.00 5.10 335.00 449.78 6.85 -3.20 3.00 335.00 6.424 520.00 3.00 335.00 519.60 11.33 -5.28 3.00 180.00 10.62 End Dir : 520' MD, 519.6' TVD5 670.00 3.00 335.00 669.39 18.45 -8.60 0.00 0.00 17.28 Start Dir 3º/100' : 670' MD, 669.39'TVD6 770.00 0.00 0.00 769.35 20.82 -9.71 3.00 180.00 19.51 End Dir : 770' MD, 769.35' TVD7 860.00 0.00 0.00 859.35 20.82 -9.71 0.00 0.00 19.51 Start Dir 4º/100' : 860' MD, 859.35'TVD8 1060.00 8.00 220.00 1058.70 10.14 -18.67 4.00 220.00 7.83 End Dir : 1060' MD, 1058.7' TVD9 1170.00 8.00 220.00 1167.63 -1.59 -28.51 0.00 0.00 -4.99 Start Dir 4º/100' : 1170' MD, 1167.63'TVD10 1584.12 23.30 247.09 1565.61 -55.92 -123.15 4.00 39.20 -70.27 End Dir : 1584.12' MD, 1565.61' TVD11 2521.79 23.30 247.09 2426.79 -200.31 -464.84 0.00 0.00 -254.55 Start Dir 4º/100' : 2521.79' MD, 2426.79'TVD12 4899.32 85.00 2.48 4001.47 1117.10 -967.99 4.00 115.37 993.10 End Dir : 4899.32' MD, 4001.47' TVD13 4999.32 85.00 2.48 4010.19 1216.63 -963.68 0.00 0.00 1092.43 MPI-Shiloh wp02 Heel Start Dir 3º/100' : 4999.32' MD, 4010.19'TVD14 5138.29 89.13 3.05 4017.30 1355.23 -956.98 3.00 7.90 1230.83 End Dir : 5138.29' MD, 4017.3' TVD15 9086.40 89.13 3.05 4077.26 5297.28 -746.75 0.00 0.00 5169.69 Start Dir 3º/100' : 9086.4' MD, 4077.26'TVD16 9268.00 89.02 8.50 4080.19 5477.86 -728.49 3.00 91.20 5351.15 MPI-Shiloh wp02 CP1 End Dir : 9268' MD, 4080.19' TVD17 13016.80 89.02 8.50 4144.31 9184.95 -174.46 0.00 0.00 9097.91 Start Dir 3º/100' : 13016.8' MD, 4144.31'TVD18 13050.13 89.02 7.50 4144.88 9217.94 -169.82 3.00 -90.01 9131.23 End Dir : 13050.13' MD, 4144.88' TVD19 13930.00 89.02 7.50 4159.93 10090.16 -54.99 0.00 0.00 10010.92 Total Depth : 13930' MD, 4159.93' TVD
Project:
Company:
Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt I Pad
Halliburton
Standard Proposal Report
Well:
Wellbore:
Plan: MPU I-21i
MPU I-21
Survey Calculation Method:Minimum Curvature
MPU I-21i As-built RKB @ 60.20usft
Design:MPU I-21 wp06
Database:NORTH US + CANADA
MD Reference:MPU I-21i As-built RKB @ 60.20usft
North Reference:
Well Plan: MPU I-21i
True
Map System:
Geo Datum:
Project
Map Zone:
System Datum:US State Plane 1927 (Exact solution)
NAD 1927 (NADCON CONUS)
Milne Point, ACT, MILNE POINT
Alaska Zone 04
Mean Sea Level
Using Well Reference Point
Using geodetic scale factor
Site Position:
From:
Site
Latitude:
Longitude:
Position Uncertainty:
Northing:
Easting:
Grid Convergence:
M Pt I Pad, TR-13-10
usft
Map usft
usft
°0.39Slot Radius:"0
6,008,388.01
550,245.83
0.00
70° 26' 1.282 N
149° 35' 25.422 W
Well
Well Position
Longitude:
Latitude:
Easting:
Northing:
usft
+E/-W
+N/-S
Position Uncertainty
usft
usft
usftGround Level:
Plan: MPU I-21i, Slot I-23
usft
usft
0.00
0.00
6,009,440.21
551,774.01
33.40Wellhead Elevation:33.70 usft0.50
70° 26' 11.528 N
149° 34' 40.361 W
Wellbore
Declination
(°)
Field Strength
(nT)
Sample Date Dip Angle
(°)
MPU I-21
Model NameMagnetics
BGGM2020 6/27/2020 15.95 80.84 57,376.45193575
Phase:Version:
Audit Notes:
Design MPU I-21 wp06
PLAN
Vertical Section: Depth From (TVD)
(usft)
+N/-S
(usft)
Direction
(°)
+E/-W
(usft)
Tie On Depth:26.50
6.880.000.0026.50
6/5/2020 6:09:28PM COMPASS 5000.15 Build 91E Page 2
Project:
Company:
Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt I Pad
Halliburton
Standard Proposal Report
Well:
Wellbore:
Plan: MPU I-21i
MPU I-21
Survey Calculation Method:Minimum Curvature
MPU I-21i As-built RKB @ 60.20usft
Design:MPU I-21 wp06
Database:NORTH US + CANADA
MD Reference:MPU I-21i As-built RKB @ 60.20usft
North Reference:
Well Plan: MPU I-21i
True
Inclination
(°)
Azimuth
(°)
+E/-W
(usft)
Tool Face
(°)
+N/-S
(usft)
Measured
Depth
(usft)
Vertical
Depth
(usft)
Dogleg
Rate
(°/100usft)
Build
Rate
(°/100usft)
Turn
Rate
(°/100usft)
Plan Sections
TVD
System
usft
0.000.000.000.000.000.0026.500.000.0026.50 -33.70
0.000.000.000.000.000.00280.000.000.00280.00 219.80
335.000.003.003.00-3.206.85449.78335.005.10450.00 389.58
180.000.00-3.003.00-5.2811.33519.60335.003.00520.00 459.40
0.000.000.000.00-8.6018.45669.39335.003.00670.00 609.19
180.000.00-3.003.00-9.7120.82769.350.000.00770.00 709.15
0.000.000.000.00-9.7120.82859.350.000.00860.00 799.15
220.000.004.004.00-18.6710.141,058.70220.008.001,060.00 998.50
0.000.000.000.00-28.51-1.591,167.63220.008.001,170.00 1,107.43
39.206.543.704.00-123.15-55.921,565.61247.0923.301,584.12 1,505.41
0.000.000.000.00-464.84-200.312,426.79247.0923.302,521.79 2,366.59
115.374.852.594.00-967.991,117.104,001.472.4885.004,899.32 3,941.27
0.000.000.000.00-963.681,216.634,010.192.4885.004,999.32 3,949.99
7.900.412.973.00-956.981,355.234,017.303.0589.135,138.29 3,957.10
0.000.000.000.00-746.755,297.284,077.263.0589.139,086.40 4,017.06
91.203.00-0.063.00-728.495,477.864,080.198.5089.029,268.00 4,019.99
0.000.000.000.00-174.469,184.954,144.318.5089.0213,016.80 4,084.11
-90.01-3.000.003.00-169.829,217.944,144.887.5089.0213,050.13 4,084.68
0.000.000.000.00-54.9910,090.164,159.937.5089.0213,930.00 4,099.73
6/5/2020 6:09:28PM COMPASS 5000.15 Build 91E Page 3
Project:
Company:
Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt I Pad
Halliburton
Standard Proposal Report
Well:
Wellbore:
Plan: MPU I-21i
MPU I-21
Survey Calculation Method:Minimum Curvature
MPU I-21i As-built RKB @ 60.20usft
Design:MPU I-21 wp06
Database:NORTH US + CANADA
MD Reference:MPU I-21i As-built RKB @ 60.20usft
North Reference:
Well Plan: MPU I-21i
True
Measured
Depth
(usft)
Inclination
(°)
Azimuth
(°)
+E/-W
(usft)
Map
Northing
(usft)
Map
Easting
(usft)
+N/-S
(usft)
Planned Survey
Vertical
Depth
(usft)
TVDss
usft
DLS
-33.70
Vert Section
26.50 0.00 26.50 0.00 0.000.00 551,774.016,009,440.21-33.70 0.00 0.00
100.00 0.00 100.00 0.00 0.000.00 551,774.016,009,440.2139.80 0.00 0.00
200.00 0.00 200.00 0.00 0.000.00 551,774.016,009,440.21139.80 0.00 0.00
280.00 0.00 280.00 0.00 0.000.00 551,774.016,009,440.21219.80 0.00 0.00
Start Dir 3º/100' : 280' MD, 280'TVD
300.00 0.60 300.00 0.09 -0.04335.00 551,773.976,009,440.30239.80 3.00 0.09
400.00 3.60 399.92 3.42 -1.59335.00 551,772.396,009,443.61339.72 3.00 3.20
450.00 5.10 449.78 6.85 -3.20335.00 551,770.776,009,447.04389.58 3.00 6.42
500.00 3.60 499.63 10.29 -4.80335.00 551,769.146,009,450.47439.43 3.00 9.64
520.00 3.00 519.60 11.33 -5.28335.00 551,768.656,009,451.50459.40 3.00 10.62
End Dir : 520' MD, 519.6' TVD
600.00 3.00 599.49 15.13 -7.05335.00 551,766.856,009,455.29539.29 0.00 14.17
670.00 3.00 669.39 18.45 -8.60335.00 551,765.286,009,458.60609.19 0.00 17.28
Start Dir 3º/100' : 670' MD, 669.39'TVD
700.00 2.10 699.36 19.66 -9.17335.00 551,764.716,009,459.80639.16 3.00 18.42
770.00 0.00 769.35 20.82 -9.710.00 551,764.166,009,460.96709.15 3.00 19.51
End Dir : 770' MD, 769.35' TVD
800.00 0.00 799.35 20.82 -9.710.00 551,764.166,009,460.96739.15 0.00 19.51
860.00 0.00 859.35 20.82 -9.710.00 551,764.166,009,460.96799.15 0.00 19.51
Start Dir 4º/100' : 860' MD, 859.35'TVD
900.00 1.60 899.34 20.39 -10.07220.00 551,763.806,009,460.53839.14 4.00 19.04
1,000.00 5.60 999.12 15.58 -14.10220.00 551,759.806,009,455.69938.92 4.00 13.78
1,060.00 8.00 1,058.70 10.14 -18.67220.00 551,755.276,009,450.22998.50 4.00 7.83
End Dir : 1060' MD, 1058.7' TVD
1,100.00 8.00 1,098.31 5.88 -22.25220.00 551,751.726,009,445.931,038.11 0.00 3.17
1,170.00 8.00 1,167.63 -1.59 -28.51220.00 551,745.526,009,438.431,107.43 0.00 -4.99
Start Dir 4º/100' : 1170' MD, 1167.63'TVD
1,200.00 8.96 1,197.30 -4.84 -31.50224.87 551,742.556,009,435.151,137.10 4.00 -8.58
1,300.00 12.47 1,295.55 -16.50 -45.89235.39 551,728.246,009,423.401,235.35 4.00 -21.88
1,400.00 16.20 1,392.42 -29.35 -67.01241.23 551,707.226,009,410.401,332.22 4.00 -37.16
1,500.00 20.04 1,487.45 -43.33 -94.76244.91 551,679.566,009,396.221,427.25 4.00 -54.37
1,584.12 23.30 1,565.61 -55.92 -123.15247.09 551,651.276,009,383.441,505.41 4.00 -70.27
End Dir : 1584.12' MD, 1565.61' TVD
1,600.00 23.30 1,580.20 -58.37 -128.93247.09 551,645.506,009,380.951,520.00 0.00 -73.39
1,700.00 23.30 1,672.04 -73.77 -165.38247.09 551,609.176,009,365.301,611.84 0.00 -93.05
1,800.00 23.30 1,763.88 -89.16 -201.82247.09 551,572.846,009,349.651,703.68 0.00 -112.70
1,900.00 23.30 1,855.73 -104.56 -238.26247.09 551,536.516,009,334.011,795.53 0.00 -132.35
2,000.00 23.30 1,947.57 -119.96 -274.70247.09 551,500.186,009,318.361,887.37 0.00 -152.00
2,100.00 23.30 2,039.41 -135.36 -311.14247.09 551,463.856,009,302.711,979.21 0.00 -171.66
2,200.00 23.30 2,131.25 -150.76 -347.58247.09 551,427.526,009,287.062,071.05 0.00 -191.31
2,300.00 23.30 2,223.09 -166.16 -384.02247.09 551,391.196,009,271.412,162.89 0.00 -210.96
2,400.00 23.30 2,314.94 -181.55 -420.46247.09 551,354.866,009,255.762,254.74 0.00 -230.61
2,500.00 23.30 2,406.78 -196.95 -456.90247.09 551,318.536,009,240.112,346.58 0.00 -250.27
2,521.79 23.30 2,426.79 -200.31 -464.84247.09 551,310.616,009,236.702,366.59 0.00 -254.55
Start Dir 4º/100' : 2521.79' MD, 2426.79'TVD
6/5/2020 6:09:28PM COMPASS 5000.15 Build 91E Page 4
Project:
Company:
Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt I Pad
Halliburton
Standard Proposal Report
Well:
Wellbore:
Plan: MPU I-21i
MPU I-21
Survey Calculation Method:Minimum Curvature
MPU I-21i As-built RKB @ 60.20usft
Design:MPU I-21 wp06
Database:NORTH US + CANADA
MD Reference:MPU I-21i As-built RKB @ 60.20usft
North Reference:
Well Plan: MPU I-21i
True
Measured
Depth
(usft)
Inclination
(°)
Azimuth
(°)
+E/-W
(usft)
Map
Northing
(usft)
Map
Easting
(usft)
+N/-S
(usft)
Planned Survey
Vertical
Depth
(usft)
TVDss
usft
DLS
2,438.75
Vert Section
2,600.00 22.13 2,498.95 -210.24 -493.31254.61 551,282.226,009,226.572,438.75 4.00 -267.82
2,700.00 21.20 2,591.92 -216.77 -529.50265.16 551,246.086,009,219.792,531.72 4.00 -278.63
2,800.00 20.95 2,685.26 -216.33 -565.30276.28 551,210.286,009,219.982,625.06 4.00 -282.49
2,900.00 21.44 2,778.54 -208.95 -600.54287.28 551,174.996,009,227.122,718.34 4.00 -279.38
3,000.00 22.59 2,871.28 -194.64 -635.04297.51 551,140.406,009,241.182,811.08 4.00 -269.31
3,100.00 24.33 2,963.04 -173.49 -668.64306.57 551,106.666,009,262.102,902.84 4.00 -252.33
3,200.00 26.53 3,053.37 -145.59 -701.17314.36 551,073.946,009,289.772,993.17 4.00 -228.53
3,300.00 29.10 3,141.82 -111.07 -732.47320.95 551,042.406,009,324.063,081.62 4.00 -198.02
3,400.00 31.93 3,227.98 -70.12 -762.39326.51 551,012.206,009,364.813,167.78 4.00 -160.94
3,500.00 34.97 3,311.42 -22.92 -790.79331.23 550,983.476,009,411.803,251.22 4.00 -117.49
3,600.00 38.17 3,391.73 30.29 -817.53335.26 550,956.376,009,464.823,331.53 4.00 -67.86
3,700.00 41.49 3,468.52 89.25 -842.47338.76 550,931.026,009,523.603,408.32 4.00 -12.31
3,800.00 44.90 3,541.42 153.68 -865.50341.81 550,907.556,009,587.873,481.22 4.00 48.90
3,900.00 48.38 3,610.07 223.26 -886.50344.52 550,886.076,009,657.293,549.87 4.00 115.46
4,000.00 51.92 3,674.14 297.66 -905.37346.95 550,866.686,009,731.553,613.94 4.00 187.06
4,100.00 55.51 3,733.32 376.51 -922.02349.15 550,849.486,009,810.273,673.12 4.00 263.35
4,200.00 59.13 3,787.31 459.42 -936.37351.17 550,834.566,009,893.083,727.11 4.00 343.95
4,300.00 62.78 3,835.86 546.00 -948.35353.04 550,821.986,009,979.563,775.66 4.00 428.47
4,400.00 66.45 3,878.73 635.82 -957.90354.80 550,811.826,010,069.303,818.53 4.00 516.49
4,500.00 70.14 3,915.70 728.44 -964.96356.45 550,804.116,010,161.863,855.50 4.00 607.60
4,600.00 73.85 3,946.61 823.41 -969.52358.04 550,798.896,010,256.803,886.41 4.00 701.35
4,700.00 77.57 3,971.29 920.28 -971.54359.56 550,796.196,010,353.633,911.09 4.00 797.27
4,800.00 81.29 3,989.63 1,018.56 -971.021.04 550,796.036,010,451.913,929.43 4.00 894.91
4,899.32 85.00 4,001.47 1,117.10 -967.992.48 550,798.386,010,550.463,941.27 4.00 993.10
End Dir : 4899.32' MD, 4001.47' TVD
4,999.32 85.00 4,010.19 1,216.63 -963.682.48 550,802.006,010,650.003,949.99 0.00 1,092.43
Start Dir 3º/100' : 4999.32' MD, 4010.19'TVD - 9 5/8" x 12 1/4"
5,100.00 87.99 4,016.34 1,317.00 -958.972.90 550,806.026,010,750.393,956.14 3.00 1,192.64
5,138.29 89.13 4,017.30 1,355.23 -956.983.05 550,807.746,010,788.633,957.10 3.00 1,230.83
End Dir : 5138.29' MD, 4017.3' TVD
5,200.00 89.13 4,018.24 1,416.84 -953.703.05 550,810.596,010,850.263,958.04 0.00 1,292.40
5,300.00 89.13 4,019.76 1,516.69 -948.373.05 550,815.226,010,950.133,959.56 0.00 1,392.16
5,400.00 89.13 4,021.28 1,616.53 -943.053.05 550,819.866,011,050.003,961.08 0.00 1,491.93
5,500.00 89.13 4,022.80 1,716.38 -937.723.05 550,824.496,011,149.873,962.60 0.00 1,591.69
5,600.00 89.13 4,024.32 1,816.23 -932.403.05 550,829.126,011,249.753,964.12 0.00 1,691.46
5,700.00 89.13 4,025.83 1,916.07 -927.073.05 550,833.756,011,349.623,965.63 0.00 1,791.22
5,800.00 89.13 4,027.35 2,015.92 -921.753.05 550,838.386,011,449.493,967.15 0.00 1,890.99
5,900.00 89.13 4,028.87 2,115.77 -916.423.05 550,843.016,011,549.363,968.67 0.00 1,990.75
6,000.00 89.13 4,030.39 2,215.61 -911.103.05 550,847.646,011,649.233,970.19 0.00 2,090.52
6,100.00 89.13 4,031.91 2,315.46 -905.773.05 550,852.276,011,749.103,971.71 0.00 2,190.28
6,200.00 89.13 4,033.43 2,415.31 -900.453.05 550,856.906,011,848.973,973.23 0.00 2,290.05
6,300.00 89.13 4,034.95 2,515.15 -895.123.05 550,861.536,011,948.853,974.75 0.00 2,389.82
6,400.00 89.13 4,036.46 2,615.00 -889.803.05 550,866.176,012,048.723,976.26 0.00 2,489.58
6,500.00 89.13 4,037.98 2,714.85 -884.473.05 550,870.806,012,148.593,977.78 0.00 2,589.35
6,600.00 89.13 4,039.50 2,814.69 -879.153.05 550,875.436,012,248.463,979.30 0.00 2,689.11
6/5/2020 6:09:28PM COMPASS 5000.15 Build 91E Page 5
Project:
Company:
Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt I Pad
Halliburton
Standard Proposal Report
Well:
Wellbore:
Plan: MPU I-21i
MPU I-21
Survey Calculation Method:Minimum Curvature
MPU I-21i As-built RKB @ 60.20usft
Design:MPU I-21 wp06
Database:NORTH US + CANADA
MD Reference:MPU I-21i As-built RKB @ 60.20usft
North Reference:
Well Plan: MPU I-21i
True
Measured
Depth
(usft)
Inclination
(°)
Azimuth
(°)
+E/-W
(usft)
Map
Northing
(usft)
Map
Easting
(usft)
+N/-S
(usft)
Planned Survey
Vertical
Depth
(usft)
TVDss
usft
DLS
3,980.82
Vert Section
6,700.00 89.13 4,041.02 2,914.54 -873.833.05 550,880.066,012,348.333,980.82 0.00 2,788.88
6,800.00 89.13 4,042.54 3,014.39 -868.503.05 550,884.696,012,448.203,982.34 0.00 2,888.64
6,900.00 89.13 4,044.06 3,114.23 -863.183.05 550,889.326,012,548.073,983.86 0.00 2,988.41
7,000.00 89.13 4,045.57 3,214.08 -857.853.05 550,893.956,012,647.953,985.37 0.00 3,088.17
7,100.00 89.13 4,047.09 3,313.93 -852.533.05 550,898.586,012,747.823,986.89 0.00 3,187.94
7,200.00 89.13 4,048.61 3,413.77 -847.203.05 550,903.216,012,847.693,988.41 0.00 3,287.71
7,300.00 89.13 4,050.13 3,513.62 -841.883.05 550,907.856,012,947.563,989.93 0.00 3,387.47
7,400.00 89.13 4,051.65 3,613.47 -836.553.05 550,912.486,013,047.433,991.45 0.00 3,487.24
7,500.00 89.13 4,053.17 3,713.31 -831.233.05 550,917.116,013,147.303,992.97 0.00 3,587.00
7,600.00 89.13 4,054.69 3,813.16 -825.903.05 550,921.746,013,247.183,994.49 0.00 3,686.77
7,700.00 89.13 4,056.20 3,913.01 -820.583.05 550,926.376,013,347.053,996.00 0.00 3,786.53
7,800.00 89.13 4,057.72 4,012.85 -815.253.05 550,931.006,013,446.923,997.52 0.00 3,886.30
7,900.00 89.13 4,059.24 4,112.70 -809.933.05 550,935.636,013,546.793,999.04 0.00 3,986.06
8,000.00 89.13 4,060.76 4,212.55 -804.603.05 550,940.266,013,646.664,000.56 0.00 4,085.83
8,100.00 89.13 4,062.28 4,312.39 -799.283.05 550,944.896,013,746.534,002.08 0.00 4,185.59
8,200.00 89.13 4,063.80 4,412.24 -793.953.05 550,949.536,013,846.404,003.60 0.00 4,285.36
8,300.00 89.13 4,065.31 4,512.09 -788.633.05 550,954.166,013,946.284,005.11 0.00 4,385.13
8,400.00 89.13 4,066.83 4,611.93 -783.303.05 550,958.796,014,046.154,006.63 0.00 4,484.89
8,500.00 89.13 4,068.35 4,711.78 -777.983.05 550,963.426,014,146.024,008.15 0.00 4,584.66
8,600.00 89.13 4,069.87 4,811.63 -772.653.05 550,968.056,014,245.894,009.67 0.00 4,684.42
8,700.00 89.13 4,071.39 4,911.47 -767.333.05 550,972.686,014,345.764,011.19 0.00 4,784.19
8,800.00 89.13 4,072.91 5,011.32 -762.003.05 550,977.316,014,445.634,012.71 0.00 4,883.95
8,900.00 89.13 4,074.43 5,111.17 -756.683.05 550,981.946,014,545.504,014.23 0.00 4,983.72
9,000.00 89.13 4,075.94 5,211.01 -751.363.05 550,986.576,014,645.384,015.74 0.00 5,083.48
9,086.40 89.13 4,077.26 5,297.28 -746.753.05 550,990.576,014,731.664,017.06 0.00 5,169.68
Start Dir 3º/100' : 9086.4' MD, 4077.26'TVD
9,100.00 89.12 4,077.46 5,310.86 -745.983.46 550,991.256,014,745.244,017.26 3.00 5,183.25
9,200.00 89.06 4,079.05 5,410.46 -737.346.46 550,999.216,014,844.894,018.85 3.00 5,283.17
9,268.00 89.02 4,080.19 5,477.87 -728.498.50 551,007.596,014,912.364,019.99 3.00 5,351.16
End Dir : 9268' MD, 4080.19' TVD
9,300.00 89.02 4,080.74 5,509.51 -723.768.50 551,012.106,014,944.034,020.54 0.00 5,383.14
9,400.00 89.02 4,082.45 5,608.40 -708.988.50 551,026.196,015,043.014,022.25 0.00 5,483.08
9,500.00 89.02 4,084.16 5,707.28 -694.208.50 551,040.286,015,141.984,023.96 0.00 5,583.03
9,600.00 89.02 4,085.87 5,806.17 -679.428.50 551,054.376,015,240.964,025.67 0.00 5,682.97
9,700.00 89.02 4,087.58 5,905.06 -664.648.50 551,068.466,015,339.944,027.38 0.00 5,782.92
9,800.00 89.02 4,089.29 6,003.95 -649.868.50 551,082.556,015,438.924,029.09 0.00 5,882.86
9,900.00 89.02 4,091.00 6,102.83 -635.088.50 551,096.646,015,537.904,030.80 0.00 5,982.81
10,000.00 89.02 4,092.71 6,201.72 -620.318.50 551,110.736,015,636.874,032.51 0.00 6,082.76
10,100.00 89.02 4,094.42 6,300.61 -605.538.50 551,124.826,015,735.854,034.22 0.00 6,182.70
10,200.00 89.02 4,096.13 6,399.49 -590.758.50 551,138.916,015,834.834,035.93 0.00 6,282.65
10,300.00 89.02 4,097.84 6,498.38 -575.978.50 551,153.006,015,933.814,037.64 0.00 6,382.59
10,400.00 89.02 4,099.55 6,597.27 -561.198.50 551,167.096,016,032.784,039.35 0.00 6,482.54
10,500.00 89.02 4,101.26 6,696.15 -546.418.50 551,181.186,016,131.764,041.06 0.00 6,582.48
10,600.00 89.02 4,102.97 6,795.04 -531.638.50 551,195.276,016,230.744,042.77 0.00 6,682.43
10,700.00 89.02 4,104.68 6,893.93 -516.858.50 551,209.366,016,329.724,044.48 0.00 6,782.37
6/5/2020 6:09:28PM COMPASS 5000.15 Build 91E Page 6
Project:
Company:
Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt I Pad
Halliburton
Standard Proposal Report
Well:
Wellbore:
Plan: MPU I-21i
MPU I-21
Survey Calculation Method:Minimum Curvature
MPU I-21i As-built RKB @ 60.20usft
Design:MPU I-21 wp06
Database:NORTH US + CANADA
MD Reference:MPU I-21i As-built RKB @ 60.20usft
North Reference:
Well Plan: MPU I-21i
True
Measured
Depth
(usft)
Inclination
(°)
Azimuth
(°)
+E/-W
(usft)
Map
Northing
(usft)
Map
Easting
(usft)
+N/-S
(usft)
Planned Survey
Vertical
Depth
(usft)
TVDss
usft
DLS
4,046.19
Vert Section
10,800.00 89.02 4,106.39 6,992.82 -502.088.50 551,223.456,016,428.694,046.19 0.00 6,882.32
10,900.00 89.02 4,108.10 7,091.70 -487.308.50 551,237.546,016,527.674,047.90 0.00 6,982.26
11,000.00 89.02 4,109.81 7,190.59 -472.528.50 551,251.646,016,626.654,049.61 0.00 7,082.21
11,100.00 89.02 4,111.52 7,289.48 -457.748.50 551,265.736,016,725.634,051.32 0.00 7,182.15
11,200.00 89.02 4,113.23 7,388.36 -442.968.50 551,279.826,016,824.614,053.03 0.00 7,282.10
11,300.00 89.02 4,114.94 7,487.25 -428.188.50 551,293.916,016,923.584,054.74 0.00 7,382.05
11,400.00 89.02 4,116.65 7,586.14 -413.408.50 551,308.006,017,022.564,056.45 0.00 7,481.99
11,500.00 89.02 4,118.36 7,685.03 -398.628.50 551,322.096,017,121.544,058.16 0.00 7,581.94
11,600.00 89.02 4,120.08 7,783.91 -383.858.50 551,336.186,017,220.524,059.88 0.00 7,681.88
11,700.00 89.02 4,121.79 7,882.80 -369.078.50 551,350.276,017,319.494,061.59 0.00 7,781.83
11,800.00 89.02 4,123.50 7,981.69 -354.298.50 551,364.366,017,418.474,063.30 0.00 7,881.77
11,900.00 89.02 4,125.21 8,080.57 -339.518.50 551,378.456,017,517.454,065.01 0.00 7,981.72
12,000.00 89.02 4,126.92 8,179.46 -324.738.50 551,392.546,017,616.434,066.72 0.00 8,081.66
12,100.00 89.02 4,128.63 8,278.35 -309.958.50 551,406.636,017,715.414,068.43 0.00 8,181.61
12,200.00 89.02 4,130.34 8,377.24 -295.178.50 551,420.726,017,814.384,070.14 0.00 8,281.55
12,300.00 89.02 4,132.05 8,476.12 -280.398.50 551,434.816,017,913.364,071.85 0.00 8,381.50
12,400.00 89.02 4,133.76 8,575.01 -265.628.50 551,448.906,018,012.344,073.56 0.00 8,481.45
12,500.00 89.02 4,135.47 8,673.90 -250.848.50 551,462.996,018,111.324,075.27 0.00 8,581.39
12,600.00 89.02 4,137.18 8,772.78 -236.068.50 551,477.086,018,210.294,076.98 0.00 8,681.34
12,700.00 89.02 4,138.89 8,871.67 -221.288.50 551,491.176,018,309.274,078.69 0.00 8,781.28
12,800.00 89.02 4,140.60 8,970.56 -206.508.50 551,505.276,018,408.254,080.40 0.00 8,881.23
12,900.00 89.02 4,142.31 9,069.45 -191.728.50 551,519.366,018,507.234,082.11 0.00 8,981.17
13,000.00 89.02 4,144.02 9,168.33 -176.948.50 551,533.456,018,606.204,083.82 0.00 9,081.12
13,016.80 89.02 4,144.31 9,184.95 -174.468.50 551,535.816,018,622.834,084.11 0.00 9,097.91
Start Dir 3º/100' : 13016.8' MD, 4144.31'TVD
13,050.13 89.02 4,144.88 9,217.95 -169.827.50 551,540.226,018,655.864,084.68 3.00 9,131.23
End Dir : 13050.13' MD, 4144.88' TVD
13,100.00 89.02 4,145.73 9,267.38 -163.317.50 551,546.396,018,705.344,085.53 0.00 9,181.09
13,200.00 89.02 4,147.44 9,366.51 -150.267.50 551,558.756,018,804.554,087.24 0.00 9,281.07
13,300.00 89.02 4,149.15 9,465.64 -137.217.50 551,571.116,018,903.754,088.95 0.00 9,381.05
13,400.00 89.02 4,150.86 9,564.77 -124.167.50 551,583.476,019,002.964,090.66 0.00 9,481.03
13,500.00 89.02 4,152.57 9,663.90 -111.117.50 551,595.836,019,102.174,092.37 0.00 9,581.00
13,600.00 89.02 4,154.28 9,763.03 -98.067.50 551,608.196,019,201.384,094.08 0.00 9,680.98
13,700.00 89.02 4,155.99 9,862.16 -85.017.50 551,620.556,019,300.594,095.79 0.00 9,780.96
13,800.00 89.02 4,157.70 9,961.29 -71.967.50 551,632.916,019,399.804,097.50 0.00 9,880.94
13,900.00 89.02 4,159.41 10,060.42 -58.917.50 551,645.276,019,499.014,099.21 0.00 9,980.92
13,930.00 89.02 4,159.93 10,090.16 -54.997.50 551,648.986,019,528.774,099.73 0.00 10,010.92
Total Depth : 13930' MD, 4159.93' TVD - 4 1/2" x 8 1/2"
6/5/2020 6:09:28PM COMPASS 5000.15 Build 91E Page 7
Project:
Company:
Local Co-ordinate Reference:
TVD Reference:
Site:
Hilcorp Alaska, LLC
Milne Point
M Pt I Pad
Halliburton
Standard Proposal Report
Well:
Wellbore:
Plan: MPU I-21i
MPU I-21
Survey Calculation Method:Minimum Curvature
MPU I-21i As-built RKB @ 60.20usft
Design:MPU I-21 wp06
Database:NORTH US + CANADA
MD Reference:MPU I-21i As-built RKB @ 60.20usft
North Reference:
Well Plan: MPU I-21i
True
Target Name
- hit/miss target
- Shape
TVD
(usft)
Northing
(usft)
Easting
(usft)
+N/-S
(usft)
+E/-W
(usft)
Tar gets
Dip Angle
(°)
Dip Dir.
(°)
MPI-Shiloh wp02 Heel 4,010.19 6,010,650.00 550,802.001,216.63 -963.680.00 0.00
-plan hits target center
- Circle (radius 30.00)
MPI-Shiloh wp02 Toe 4,160.19 6,019,528.00 551,564.0010,089.98 -139.990.00 0.00
-plan misses target center by 84.25usft at 13918.74usft MD (4159.73 TVD, 10078.99 N, -56.46 E)
- Point
MPI-Shiloh wp02 CP1 4,080.19 6,014,908.00 550,957.005,473.86 -779.110.00 0.00
-plan misses target center by 49.51usft at 9257.44usft MD (4080.01 TVD, 5467.42 N, -730.02 E)
- Point
Vertical
Depth
(usft)
Measured
Depth
(usft)
Casing
Diameter
(")
Hole
Diameter
(")Name
Casing Points
4 1/2" x 8 1/2"4,159.9313,930.00 4-1/2 8-1/2
9 5/8" x 12 1/4"4,010.194,999.32 9-5/8 12-1/4
Measured
Depth
(usft)
Vertical
Depth
(usft)
+E/-W
(usft)
+N/-S
(usft)
Local Coordinates
Comment
Plan Annotations
280.00 280.00 0.00 0.00 Start Dir 3º/100' : 280' MD, 280'TVD
520.00 519.60 6.85 -3.20 End Dir : 520' MD, 519.6' TVD
670.00 669.39 11.33 -5.28 Start Dir 3º/100' : 670' MD, 669.39'TVD
770.00 769.35 18.45 -8.60 End Dir : 770' MD, 769.35' TVD
860.00 859.35 20.82 -9.71 Start Dir 4º/100' : 860' MD, 859.35'TVD
1,060.00 1,058.70 20.82 -9.71 End Dir : 1060' MD, 1058.7' TVD
1,170.00 1,167.63 10.14 -18.67 Start Dir 4º/100' : 1170' MD, 1167.63'TVD
1,584.12 1,565.61 -1.59 -28.51 End Dir : 1584.12' MD, 1565.61' TVD
2,521.79 2,426.79 -55.92 -123.15 Start Dir 4º/100' : 2521.79' MD, 2426.79'TVD
4,899.32 4,001.47 -200.31 -464.84 End Dir : 4899.32' MD, 4001.47' TVD
4,999.32 4,010.19 1,117.10 -967.99 Start Dir 3º/100' : 4999.32' MD, 4010.19'TVD
5,138.29 4,017.30 1,216.63 -963.68 End Dir : 5138.29' MD, 4017.3' TVD
9,086.40 4,077.26 1,355.23 -956.98 Start Dir 3º/100' : 9086.4' MD, 4077.26'TVD
9,268.00 4,080.19 5,297.28 -746.75 End Dir : 9268' MD, 4080.19' TVD
13,016.80 4,144.31 5,477.87 -728.49 Start Dir 3º/100' : 13016.8' MD, 4144.31'TVD
13,050.13 4,144.88 9,184.95 -174.46 End Dir : 13050.13' MD, 4144.88' TVD
13,930.00 4,159.93 9,217.95 -169.82 Total Depth : 13930' MD, 4159.93' TVD
6/5/2020 6:09:28PM COMPASS 5000.15 Build 91E Page 8
05 June, 2020Milne PointM Pt I PadPlan: MPU I-21iMPU I-21MPU I-21 wp06Reference Design: M Pt I Pad - Plan: MPU I-21i - MPU I-21 - MPU I-21 wp06Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Well Coordinates: 6,009,440.21 N, 551,774.01 E (70° 26' 11.53" N, 149° 34' 40.36" W)Datum Height: MPU I-21i As-built RKB @ 60.20usftScan Range: 26.50 to 4,999.32 usft. Measured Depth.Geodetic Scale Factor AppliedVersion: 5000.15 Build: 91EScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftGLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of referenceScan Type:Scan Type:25.00
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-21i - MPU I-21 wp06Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 26.50 to 4,999.32 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt I Pad - Plan: MPU I-21i - MPU I-21 - MPU I-21 wp06MeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt I PadMPI-01 - MPI-01 - MPI-0147.46 1,009.07 39.18 1,021.47 5.7331,009.07Ellipse Separation Pass - MPI-01 - MPI-01 - MPI-0147.75 1,026.50 39.36 1,037.78 5.6941,026.50Clearance Factor Pass - MPI-02 - MPI-02 - MPI-0266.30 1,130.38 57.01 1,151.55 7.1381,130.38Ellipse Separation Pass - MPI-02 - MPI-02 - MPI-0266.93 1,151.50 57.46 1,170.51 7.0661,151.50Clearance Factor Pass - MPI-03 - MPI-03 - MPI-03176.68 1,120.07 167.51 1,121.60 19.2641,120.07Centre Distance Pass - MPI-03 - MPI-03 - MPI-03176.69 1,126.50 167.47 1,127.46 19.1631,126.50Ellipse Separation Pass - MPI-03 - MPI-03 - MPI-03187.39 1,301.50 177.00 1,283.04 18.0291,301.50Clearance Factor Pass - MPI-04 - MPI-04 - MPI-04239.05 1,087.85 230.03 1,103.62 26.5051,087.85Centre Distance Pass - MPI-04 - MPI-04 - MPI-04239.13 1,101.50 230.00 1,115.74 26.1911,101.50Ellipse Separation Pass - MPI-04 - MPI-04 - MPI-04254.40 1,276.50 243.88 1,262.95 24.2001,276.50Clearance Factor Pass - MPI-04 - MPI-04A - MPI-04A239.05 1,087.85 230.03 1,103.62 26.5051,087.85Centre Distance Pass - MPI-04 - MPI-04A - MPI-04A239.13 1,101.50 230.00 1,115.74 26.1911,101.50Ellipse Separation Pass - MPI-04 - MPI-04A - MPI-04A254.40 1,276.50 243.88 1,262.95 24.2001,276.50Clearance Factor Pass - MPI-04 - MPI-04AL1 - MPI-04AL1239.05 1,087.85 230.03 1,103.62 26.5051,087.85Centre Distance Pass - MPI-04 - MPI-04AL1 - MPI-04AL1239.13 1,101.50 230.00 1,115.74 26.1911,101.50Ellipse Separation Pass - MPI-04 - MPI-04AL1 - MPI-04AL1254.40 1,276.50 243.88 1,262.95 24.2001,276.50Clearance Factor Pass - MPI-04 - MPI-04APB1 - MPI-04APB1239.05 1,087.85 230.03 1,103.62 26.5051,087.85Centre Distance Pass - MPI-04 - MPI-04APB1 - MPI-04APB1239.13 1,101.50 230.00 1,115.74 26.1911,101.50Ellipse Separation Pass - MPI-04 - MPI-04APB1 - MPI-04APB1254.40 1,276.50 243.88 1,262.95 24.2001,276.50Clearance Factor Pass - MPI-04 - MPI-04PB1 - MPI-04PB1239.05 1,087.85 230.03 1,103.62 26.5051,087.85Centre Distance Pass - MPI-04 - MPI-04PB1 - MPI-04PB1239.13 1,101.50 230.00 1,115.74 26.1911,101.50Ellipse Separation Pass - MPI-04 - MPI-04PB1 - MPI-04PB1254.40 1,276.50 243.88 1,262.95 24.2001,276.50Clearance Factor Pass - MPI-05 - MPI-05 - MPI-0538.02 1,467.25 28.02 1,473.18 3.8021,467.25Ellipse Separation Pass - MPI-05 - MPI-05 - MPI-0538.34 1,476.50 28.21 1,481.02 3.7851,476.50Clearance Factor Pass - MPI-06 - MPI-06 - MPI-06226.14 1,865.49 212.14 1,772.83 16.1501,865.49Centre Distance Pass - MPI-06 - MPI-06 - MPI-06226.18 1,876.50 212.11 1,782.51 16.0811,876.50Ellipse Separation Pass - MPI-06 - MPI-06 - MPI-06230.32 1,976.50 215.77 1,867.68 15.8261,976.50Clearance Factor Pass - MPI-07 - MPI-07 - MPI-07152.48 1,826.84 139.92 1,785.03 12.1441,826.84Ellipse Separation Pass - 05 June, 2020-18:16COMPASSPage 2 of 7
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-21i - MPU I-21 wp06Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 26.50 to 4,999.32 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt I Pad - Plan: MPU I-21i - MPU I-21 - MPU I-21 wp06MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPI-07 - MPI-07 - MPI-07154.95 1,876.50 142.01 1,825.24 11.9711,876.50Clearance Factor Pass - MPI-09 - MPI-09 - MPI-09104.21 752.39 97.82 755.56 16.315752.39Ellipse Separation Pass - MPI-09 - MPI-09 - MPI-09108.24 876.50 101.41 875.05 15.849876.50Clearance Factor Pass - MPI-10 - MPI-10 - MPI-1056.32 552.02 51.81 552.71 12.464552.02Ellipse Separation Pass - MPI-10 - MPI-10 - MPI-1074.70 1,026.50 67.03 1,017.89 9.7331,026.50Clearance Factor Pass - MPI-15 - MPI-15 - MPI-1538.48 626.82 34.03 629.40 8.641626.82Centre Distance Pass - MPI-15 - MPI-15 - MPI-1538.60 651.50 34.01 653.91 8.404651.50Ellipse Separation Pass - MPI-15 - MPI-15 - MPI-1541.83 776.50 36.56 777.94 7.938776.50Clearance Factor Pass - MPI-15 - MPI-15L1 - MPI-15L138.48 626.82 34.03 629.40 8.641626.82Centre Distance Pass - MPI-15 - MPI-15L1 - MPI-15L138.60 651.50 34.01 653.91 8.404651.50Ellipse Separation Pass - MPI-15 - MPI-15L1 - MPI-15L141.83 776.50 36.56 777.94 7.938776.50Clearance Factor Pass - MPI-15 - MPI-15PB1 - MPI-15PB138.48 626.82 34.03 629.40 8.641626.82Centre Distance Pass - MPI-15 - MPI-15PB1 - MPI-15PB138.60 651.50 34.01 653.91 8.404651.50Ellipse Separation Pass - MPI-15 - MPI-15PB1 - MPI-15PB141.83 776.50 36.56 777.94 7.938776.50Clearance Factor Pass - MPI-16 - MPI-16 - MPI-1614.59 101.50 12.74 109.65 7.904101.50Centre Distance Pass - MPI-16 - MPI-16 - MPI-1614.90 201.50 12.39 209.54 5.931201.50Ellipse Separation Pass - MPI-16 - MPI-16 - MPI-1616.45 276.50 13.39 284.23 5.377276.50Clearance Factor Pass - MPI-17 - MPI-17 - MPI-1715.59 26.50 13.74 34.65 8.43626.50Centre Distance Pass - MPI-17 - MPI-17 - MPI-1715.79 101.50 13.58 109.57 7.137101.50Ellipse Separation Pass - MPI-17 - MPI-17 - MPI-1719.80 451.50 14.52 460.04 3.753451.50Clearance Factor Pass - MPI-17 - MPI-17L1 - MPI-17L115.59 26.50 13.74 34.65 8.43626.50Centre Distance Pass - MPI-17 - MPI-17L1 - MPI-17L115.79 101.50 13.58 109.57 7.137101.50Ellipse Separation Pass - MPI-17 - MPI-17L1 - MPI-17L119.80 451.50 14.52 460.04 3.753451.50Clearance Factor Pass - MPI-17 - MPI-17L1PB1 - MPI-17L1PB115.59 26.50 13.74 34.65 8.43626.50Centre Distance Pass - MPI-17 - MPI-17L1PB1 - MPI-17L1PB115.79 101.50 13.58 109.57 7.137101.50Ellipse Separation Pass - MPI-17 - MPI-17L1PB1 - MPI-17L1PB119.80 451.50 14.52 460.04 3.753451.50Clearance Factor Pass - MPI-17 - MPI-17L2 - MPI-17L215.59 26.50 13.74 34.65 8.43626.50Centre Distance Pass - MPI-17 - MPI-17L2 - MPI-17L215.79 101.50 13.58 109.57 7.137101.50Ellipse Separation Pass - MPI-17 - MPI-17L2 - MPI-17L219.80 451.50 14.52 460.04 3.753451.50Clearance Factor Pass - MPI-18 - MPI-18 - MPI-1845.36 26.50 43.51 29.50 24.56726.50Centre Distance Pass - 05 June, 2020-18:16COMPASSPage 3 of 7
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-21i - MPU I-21 wp06Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 26.50 to 4,999.32 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt I Pad - Plan: MPU I-21i - MPU I-21 - MPU I-21 wp06MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPI-18 - MPI-18 - MPI-1845.58 101.50 43.44 104.28 21.299101.50Ellipse Separation Pass - MPI-18 - MPI-18 - MPI-18300.24 2,751.50 265.59 2,833.69 8.6662,751.50Clearance Factor Pass - MPI-19 - MPI-19 - MPI-1975.82 26.50 73.97 35.37 41.05426.50Ellipse Separation Pass - MPI-19 - MPI-19 - MPI-1984.36 926.50 76.66 937.47 10.959926.50Clearance Factor Pass - MPI-19 - MPI-19L1 - MPI-19L175.82 26.50 73.97 35.37 41.05426.50Ellipse Separation Pass - MPI-19 - MPI-19L1 - MPI-19L184.36 926.50 76.66 937.47 10.959926.50Clearance Factor Pass - MPI-19 - MPI-19PB1 - MPI-19PB175.82 26.50 73.97 35.37 41.05426.50Ellipse Separation Pass - MPI-19 - MPI-19PB1 - MPI-19PB184.36 926.50 76.66 937.47 10.959926.50Clearance Factor Pass - MPI-19 - MPI-19PB2 - MPI-19PB275.82 26.50 73.97 35.37 41.05426.50Ellipse Separation Pass - MPI-19 - MPI-19PB2 - MPI-19PB284.36 926.50 76.66 937.47 10.959926.50Clearance Factor Pass - MPU I-35i - MPU I-35i - MPU I-35i29.69 26.50 27.78 26.75 15.53426.50Ellipse Separation Pass - MPU I-35i - MPU I-35i - MPU I-35i53.75 1,426.50 44.98 1,435.15 6.1291,426.50Clearance Factor Pass - Plan: MPU I-20 - MPU I-20 - MPU I-20 wp0689.92 276.50 87.36 276.50 35.142276.50Centre Distance Pass - Plan: MPU I-20 - MPU I-20 - MPU I-20 wp0689.98 301.50 87.31 301.50 33.765301.50Ellipse Separation Pass - Plan: MPU I-20 - MPU I-20 - MPU I-20 wp06888.14 4,999.32 840.43 4,786.05 18.6134,999.32Clearance Factor Pass - Plan: MPU I-22 - MPU I-22 - MPU I-22 wp03112.39 460.10 108.99 457.05 33.052460.10Ellipse Separation Pass - Plan: MPU I-22 - MPU I-22 - MPU I-22 wp03917.42 4,999.32 869.03 5,508.31 18.9594,999.32Clearance Factor Pass - Plan: MPU I-27 - MPU I-27 - MPU I-27 wp0459.75 276.50 57.19 276.40 23.350276.50Centre Distance Pass - Plan: MPU I-27 - MPU I-27 - MPU I-27 wp0459.81 301.50 57.15 301.40 22.443301.50Ellipse Separation Pass - Plan: MPU I-27 - MPU I-27 - MPU I-27 wp0490.08 1,251.50 83.14 1,255.27 12.9641,251.50Clearance Factor Pass - Plan: MPU I-28i - MPU I-28 - MPU I-28i wp0327.22 726.96 22.49 726.23 5.757726.96Ellipse Separation Pass - Plan: MPU I-28i - MPU I-28 - MPU I-28i wp03239.16 4,999.32 195.24 4,890.38 5.4454,999.32Clearance Factor Pass - Plan: MPU I-29 - MPU I-29 - MPU I-29 wp0356.66 230.25 54.28 229.95 23.869230.25Centre Distance Pass - Plan: MPU I-29 - MPU I-29 - MPU I-29 wp0357.04 376.50 54.03 374.79 18.962376.50Ellipse Separation Pass - Plan: MPU I-29 - MPU I-29 - MPU I-29 wp0361.55 501.50 57.92 496.27 16.959501.50Clearance Factor Pass - Rig: MPU I-36 - MPU I-36 - MPU I-36 wp0781.94 650.25 77.59 648.20 18.822650.25Centre Distance Pass - Rig: MPU I-36 - MPU I-36 - MPU I-36 wp0782.06 676.50 77.58 673.76 18.303676.50Ellipse Separation Pass - Rig: MPU I-36 - MPU I-36 - MPU I-36 wp07487.76 4,999.32 442.76 5,054.18 10.8404,999.32Clearance Factor Pass - Rig: MPU I-36 - MPU I-36 - MPU I-3684.48 501.04 80.96 498.53 24.017501.04Centre Distance Pass - Rig: MPU I-36 - MPU I-36 - MPU I-3684.56 526.50 80.91 523.91 23.216526.50Ellipse Separation Pass - 05 June, 2020-18:16COMPASSPage 4 of 7
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-21i - MPU I-21 wp06Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 26.50 to 4,999.32 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)Reference Design: M Pt I Pad - Plan: MPU I-21i - MPU I-21 - MPU I-21 wp06MeasuredDepth(usft)Summary Based on MinimumSeparation WarningRig: MPU I-36 - MPU I-36 - MPU I-36491.16 4,999.32 447.33 5,053.60 11.2054,999.32Clearance Factor Pass - Rig: MPU I-36 - MPU I-36PB1 - MPU I-36PB184.48 501.04 80.96 498.53 24.017501.04Centre Distance Pass - Rig: MPU I-36 - MPU I-36PB1 - MPU I-36PB184.56 526.50 80.91 523.91 23.216526.50Ellipse Separation Pass - Rig: MPU I-36 - MPU I-36PB1 - MPU I-36PB1491.16 4,999.32 447.29 5,053.60 11.1954,999.32Clearance Factor Pass - Rig: MPU I-36 - MPU I-36PB2 - MPU I-36PB284.48 501.04 80.96 498.53 24.017501.04Centre Distance Pass - Rig: MPU I-36 - MPU I-36PB2 - MPU I-36PB284.56 526.50 80.91 523.91 23.216526.50Ellipse Separation Pass - Rig: MPU I-36 - MPU I-36PB2 - MPU I-36PB2491.16 4,999.32 447.33 5,053.60 11.2054,999.32Clearance Factor Pass - M Pt J PadMPJ-03 - MPJ-03 - MPJ-031,469.65 4,999.32 1,418.33 5,448.00 28.6364,999.32Clearance Factor Pass - Survey tool programFrom(usft)To(usft)Survey/Plan Survey Tool26.50 700.00 MPU I-21 wp06 3_Gyro-GC_Csg700.00 4,999.32 MPU I-21 wp06 3_MWD+IFR2+MS+Sag4,999.32 13,930.00 MPU I-21 wp06 3_MWD+IFR2+MS+SagEllipse error terms are correlated across survey tool tie-on points.Separation is the actual distance between ellipsoids.Calculated ellipses incorporate surface errors.Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation).Distance Between centres is the straight line distance between wellbore centres.All station coordinates were calculated using the Minimum Curvature method.05 June, 2020-18:16COMPASSPage 5 of 7
0.001.002.003.004.00Separation Factor0 275 550 825 1100 1375 1650 1925 2200 2475 2750 3025 3300 3575 3850 4125 4400 4675 4950 5225Measured Depth (550 usft/in)No-Go Zone - Stop DrillingCollision Avoidance Req.Collision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: MPU I-21i NAD 1927 (NADCON CONUS)Alaska Zone 0433.40+N/-S +E/-W Northing Easting Latittude Longitude0.000.006009440.21551774.0170° 26' 11.528 N 149° 34' 40.361 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU I-21i, True NorthVertical (TVD) Reference:MPU I-21i As-built RKB @ 60.20usftMeasured Depth Reference:MPU I-21i As-built RKB @ 60.20usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2020-03-27T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.50 700.00 MPU I-21 wp06 (MPU I-21) 3_Gyro-GC_Csg700.00 4999.32 MPU I-21 wp06 (MPU I-21) 3_MWD+IFR2+MS+Sag4999.32 13930.00 MPU I-21 wp06 (MPU I-21) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 275 550 825 1100 1375 1650 1925 2200 2475 2750 3025 3300 3575 3850 4125 4400 4675 4950 5225Measured Depth (550 usft/in)MPI-10MPI-15MPI-16MPI-17MPI-18MPI-19MPU I-35iMPU I-20 wp06MPU I-27 wp04MPU I-28i wp03MPU I-29 wp03MPU I-36GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference26.50 To 13930.00Project: Milne PointSite: M Pt I PadWell: Plan: MPU I-21iWellbore: MPU I-21Plan: MPU I-21 wp06Ladder / S.F. Plots1 of 2CASING DETAILSTVD TVDSS MD Size Name4010.19 3949.99 4999.32 9-5/8 9 5/8" x 12 1/4"4159.93 4099.73 13930.00 4-1/2 4 1/2" x 8 1/2"
05 June, 2020Milne PointM Pt I PadPlan: MPU I-21iMPU I-21MPU I-21 wp06Reference Design: M Pt I Pad - Plan: MPU I-21i - MPU I-21 - MPU I-21 wp06Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Well Coordinates: 6,009,440.21 N, 551,774.01 E (70° 26' 11.53" N, 149° 34' 40.36" W)Datum Height: MPU I-21i As-built RKB @ 60.20usftScan Range: 4,999.32 to 13,930.00 usft. Measured Depth.Geodetic Scale Factor AppliedVersion: 5000.15 Build: 91EScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftNO GLOBAL FILTER: Using user defined selection & filtering criteriaScan Type:Scan Type:25.00
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-21i - MPU I-21 wp06Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 4,999.32 to 13,930.00 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt I Pad - Plan: MPU I-21i - MPU I-21 - MPU I-21 wp06MeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt I PadMPI-07 - MPI-07 - MPI-071,273.53 4,999.32 1,240.25 4,041.90 38.2644,999.32Clearance Factor Pass - MPI-09 - MPI-09 - MPI-091,079.32 5,490.36 1,021.54 4,216.32 18.6825,490.36Centre Distance Pass - MPI-09 - MPI-09 - MPI-091,087.88 5,699.32 1,011.83 4,379.13 14.3045,699.32Ellipse Separation Pass - MPI-09 - MPI-09 - MPI-091,412.46 6,849.32 1,244.04 5,245.87 8.3876,849.32Clearance Factor Pass - MPI-17 - MPI-17 - MPI-171,382.56 4,999.32 1,293.84 4,525.81 15.5844,999.32Clearance Factor Pass - MPI-17 - MPI-17L1 - MPI-17L11,382.56 4,999.32 1,293.84 4,525.81 15.5844,999.32Clearance Factor Pass - MPI-17 - MPI-17L1PB1 - MPI-17L1PB11,382.56 4,999.32 1,293.84 4,525.81 15.5844,999.32Clearance Factor Pass - MPI-17 - MPI-17L2 - MPI-17L21,382.56 4,999.32 1,293.84 4,525.81 15.5844,999.32Clearance Factor Pass - MPI-19 - MPI-19 - MPI-1925.719,149.32-106.867,584.030.1949,149.32Ellipse SeparationFAIL - MPI-19 - MPI-19 - MPI-1924.379,174.32-104.837,608.530.1899,174.32Clearance FactorFAIL - MPI-19 - MPI-19 - MPI-1923.969,199.65-99.797,633.530.1949,199.65Centre DistanceFAIL - MPI-19 - MPI-19L1 - MPI-19L163.018,999.32-31.937,435.240.6648,999.32Ellipse SeparationFAIL - MPI-19 - MPI-19L1 - MPI-19L147.869,099.32-27.267,532.600.6379,099.32Clearance FactorFAIL - MPI-19 - MPI-19L1 - MPI-19L138.099,258.10-15.787,687.440.7079,258.10Centre DistanceFAIL - MPI-19 - MPI-19PB1 - MPI-19PB18.069,224.32-126.127,659.760.0609,224.32Ellipse SeparationFAIL - MPI-19 - MPI-19PB1 - MPI-19PB16.059,249.32-121.607,684.430.0479,249.32Clearance FactorFAIL - MPI-19 - MPI-19PB1 - MPI-19PB15.629,267.30-106.077,702.230.0509,267.30Centre DistanceFAIL - MPI-19 - MPI-19PB2 - MPI-19PB224.379,174.32-104.967,608.530.1889,174.32Clearance FactorFAIL - MPI-19 - MPI-19PB2 - MPI-19PB219.479,499.81-76.287,934.860.2039,499.81Centre DistanceFAIL - MPI-19 - MPI-19PB2 - MPI-19PB237.279,774.32-108.678,205.390.2559,774.32Ellipse SeparationFAIL - MPU I-35i - MPU I-35i - MPU I-35i569.49 13,674.32 310.70 13,130.00 2.20113,674.32Clearance Factor Pass - MPU I-35i - MPU I-35i - MPU I-35i569.48 13,677.40 310.72 13,130.00 2.20113,677.40Centre Distance Pass - Plan: MPU I-20 - MPU I-20 - MPU I-20 wp06700.04 13,930.00 441.93 13,542.00 2.71213,930.00Clearance Factor Pass - Plan: MPU I-22 - MPU I-22 - MPU I-22 wp03792.57 13,930.00 532.34 14,570.85 3.04613,930.00Clearance Factor Pass - Plan: MPU I-27 - MPU I-27 - MPU I-27 wp04649.25 13,930.00 391.04 13,688.39 2.51413,930.00Clearance Factor Pass - Plan: MPU I-29 - MPU I-29 - MPU I-29 wp03758.02 13,930.00 499.25 14,598.81 2.92913,930.00Clearance Factor Pass - Rig: MPU I-36 - MPU I-36 - MPU I-36 wp07376.22 9,209.13 262.11 9,278.40 3.2979,209.13Centre Distance Pass - Rig: MPU I-36 - MPU I-36 - MPU I-36 wp07394.60 13,930.00 171.29 14,035.40 1.76713,930.00Clearance Factor Pass - 05 June, 2020-18:19COMPASSPage 2 of 7
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-21i - MPU I-21 wp06Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 4,999.32 to 13,930.00 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt I Pad - Plan: MPU I-21i - MPU I-21 - MPU I-21 wp06MeasuredDepth(usft)Summary Based on MinimumSeparation WarningRig: MPU I-36 - MPU I-36 - MPU I-36343.29 9,344.28 229.10 9,414.10 3.0069,344.28Centre Distance Pass - Rig: MPU I-36 - MPU I-36 - MPU I-36344.24 9,499.32 227.04 9,561.45 2.9379,499.32Ellipse Separation Pass - Rig: MPU I-36 - MPU I-36 - MPU I-36348.28 9,599.32 229.07 9,650.19 2.9229,599.32Clearance Factor Pass - Rig: MPU I-36 - MPU I-36PB1 - MPU I-36PB1358.35 9,478.77 233.56 9,549.18 2.8729,478.77Centre Distance Pass - Rig: MPU I-36 - MPU I-36PB1 - MPU I-36PB1358.87 9,524.32 232.62 9,585.81 2.8429,524.32Ellipse Separation Pass - Rig: MPU I-36 - MPU I-36PB1 - MPU I-36PB1396.03 10,249.32 239.19 10,300.00 2.52510,249.32Clearance Factor Pass - Rig: MPU I-36 - MPU I-36PB2 - MPU I-36PB2344.03 9,271.80 230.88 9,341.32 3.0419,271.80Centre Distance Pass - Rig: MPU I-36 - MPU I-36PB2 - MPU I-36PB2345.22 9,374.32 230.40 9,436.58 3.0079,374.32Ellipse Separation Pass - Rig: MPU I-36 - MPU I-36PB2 - MPU I-36PB2388.90 10,124.32 246.56 10,162.26 2.73210,124.32Clearance Factor Pass - M Pt J PadMPJ-01 - MPJ-01 - MPJ-01746.32 10,469.65 633.27 4,301.96 6.60210,469.65Clearance Factor Pass - MPJ-01 - MPJ-01A - MPJ-01A101.7511,922.44-31.805,706.290.76211,922.44Centre DistanceFAIL - MPJ-01 - MPJ-01A - MPJ-01A103.4811,999.32-36.835,778.870.73811,999.32Clearance FactorFAIL - MPJ-01 - MPJ-01A - MPJ-01A119.4812,174.32-41.445,949.180.74212,174.32Ellipse SeparationFAIL - MPJ-01 - MPJ-01AL1 - MPJ-01AL1179.9111,449.3233.745,227.581.23111,449.32Clearance FactorPass - MPJ-01 - MPJ-01AL1 - MPJ-01AL1179.8211,458.8833.925,233.971.23211,458.88Centre DistancePass - MPJ-03 - MPJ-03 - MPJ-03523.82 6,412.10 409.11 5,389.58 4.5666,412.10Centre Distance Pass - MPJ-03 - MPJ-03 - MPJ-03524.51 6,449.32 408.79 5,363.69 4.5326,449.32Ellipse Separation Pass - MPJ-03 - MPJ-03 - MPJ-03525.73 6,474.32 409.49 5,346.32 4.5236,474.32Clearance Factor Pass - MPJ-06 - MPJ-06 - MPJ-06376.48 10,574.32 242.99 4,632.60 2.82010,574.32Clearance Factor Pass - MPJ-06 - MPJ-06 - MPJ-06374.61 10,599.32 242.26 4,647.00 2.83010,599.32Ellipse Separation Pass - MPJ-06 - MPJ-06 - MPJ-06373.80 10,629.78 243.31 4,664.53 2.86510,629.78Centre Distance Pass - MPJ-08 - MPJ-08 - MPJ-08417.32 10,656.65 346.48 4,472.20 5.89110,656.65Centre Distance Pass - MPJ-08 - MPJ-08 - MPJ-08437.24 10,849.32 329.32 4,623.89 4.05210,849.32Ellipse Separation Pass - MPJ-08 - MPJ-08 - MPJ-08997.39 13,930.00 689.96 7,786.29 3.24413,930.00Clearance Factor Pass - MPJ-08 - MPJ-08A - MPJ-08A417.32 10,656.65 346.48 4,473.00 5.89110,656.65Centre Distance Pass - MPJ-08 - MPJ-08A - MPJ-08A437.24 10,849.32 329.32 4,624.69 4.05210,849.32Ellipse Separation Pass - MPJ-08 - MPJ-08A - MPJ-08A527.83 11,149.32 378.96 4,849.80 3.54611,149.32Clearance Factor Pass - MPJ-09 - MPJ-09 - MPJ-091,126.95 10,356.75 1,039.07 4,179.15 12.82310,356.75Centre Distance Pass - MPJ-09 - MPJ-09 - MPJ-091,134.58 10,499.32 1,032.39 4,232.87 11.10210,499.32Ellipse Separation Pass - 05 June, 2020-18:19COMPASSPage 3 of 7
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-21i - MPU I-21 wp06Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usftSite NameScan Range: 4,999.32 to 13,930.00 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt I Pad - Plan: MPU I-21i - MPU I-21 - MPU I-21 wp06MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPJ-09 - MPJ-09 - MPJ-091,573.08 11,649.32 1,358.11 5,324.22 7.31811,649.32Clearance Factor Pass - MPJ-09 - MPJ-09A - MPJ-09A1,126.95 10,356.75 1,039.08 4,179.42 12.82510,356.75Centre Distance Pass - MPJ-09 - MPJ-09A - MPJ-09A1,134.58 10,499.32 1,032.41 4,233.14 11.10410,499.32Ellipse Separation Pass - MPJ-09 - MPJ-09A - MPJ-09A1,552.29 11,599.32 1,340.54 5,283.73 7.33111,599.32Clearance Factor Pass - MPJ-11 - MPJ-11 - MPJ-11330.51 12,499.32 191.69 5,529.88 2.38112,499.32Clearance Factor Pass - MPJ-11 - MPJ-11 - MPJ-11329.51 12,537.41 192.21 5,557.26 2.40012,537.41Centre Distance Pass - MPJ-12 - MPJ-12 - MPJ-121,226.66 10,969.69 1,085.79 4,493.86 8.70810,969.69Centre Distance Pass - MPJ-12 - MPJ-12 - MPJ-121,226.93 10,999.32 1,085.60 4,507.88 8.68110,999.32Ellipse Separation Pass - MPJ-12 - MPJ-12 - MPJ-121,233.71 11,124.32 1,090.73 4,578.48 8.62911,124.32Clearance Factor Pass - MPJ-15 - MPJ-15 - MPJ-151,145.37 12,338.91 963.57 5,292.14 6.30012,338.91Centre Distance Pass - MPJ-15 - MPJ-15 - MPJ-151,166.14 12,649.32 947.41 5,526.39 5.33112,649.32Ellipse Separation Pass - MPJ-15 - MPJ-15 - MPJ-151,352.00 13,449.32 1,059.28 6,182.83 4.61913,449.32Clearance Factor Pass - MPJ-16 - MPJ-16 - MPJ-16239.2112,873.8710.446,081.821.04612,873.87Centre DistancePass - MPJ-16 - MPJ-16 - MPJ-16245.0912,974.320.736,165.951.00312,974.32Clearance FactorPass - MPJ-22 - MPJ-22 - MPJ-22982.22 9,051.78 925.91 3,909.03 17.4469,051.78Centre Distance Pass - MPJ-22 - MPJ-22 - MPJ-22983.35 9,099.32 924.99 3,918.17 16.8499,099.32Ellipse Separation Pass - MPJ-22 - MPJ-22 - MPJ-221,182.41 9,674.32 1,092.40 3,988.09 13.1379,674.32Clearance Factor Pass - MPJ-25 - MPJ-25 - MPJ-25363.53 10,203.85 299.29 4,160.08 5.65910,203.85Centre Distance Pass - MPJ-25 - MPJ-25 - MPJ-25366.16 10,249.32 296.20 4,168.92 5.23410,249.32Ellipse Separation Pass - MPJ-25 - MPJ-25 - MPJ-25421.52 10,424.32 331.60 4,224.40 4.68810,424.32Clearance Factor Pass - MPJ-25 - MPJ-25PB1 - MPJ-25PB1347.47 10,228.22 267.97 4,234.59 4.37110,228.22Centre Distance Pass - MPJ-25 - MPJ-25PB1 - MPJ-25PB1353.78 10,299.32 262.45 4,259.64 3.87310,299.32Ellipse Separation Pass - MPJ-25 - MPJ-25PB1 - MPJ-25PB1382.55 10,399.32 278.29 4,294.61 3.66910,399.32Clearance Factor Pass - 05 June, 2020-18:19COMPASSPage 4 of 7
Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU I-21i - MPU I-21 wp06Survey tool programFrom(usft)To(usft)Survey/Plan Survey Tool26.50 700.00 MPU I-21 wp06 3_Gyro-GC_Csg700.00 4,999.32 MPU I-21 wp06 3_MWD+IFR2+MS+Sag4,999.32 13,930.00 MPU I-21 wp06 3_MWD+IFR2+MS+SagEllipse error terms are correlated across survey tool tie-on points.Separation is the actual distance between ellipsoids.Calculated ellipses incorporate surface errors.Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation).Distance Between centres is the straight line distance between wellbore centres.All station coordinates were calculated using the Minimum Curvature method.05 June, 2020-18:19COMPASSPage 5 of 7
0.001.002.003.004.00Separation Factor4750 5225 5700 6175 6650 7125 7600 8075 8550 9025 9500 9975 10450 10925 11400 11875 12350 12825 13300 13775Measured Depth (950 usft/in)MPI-19MPI-19L1MPI-19PB1MPI-19PB2MPJ-03MPJ-16No-Go Zone - Stop DrillingCollision Avoidance Req.Collision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: MPU I-21i NAD 1927 (NADCON CONUS)Alaska Zone 0433.40+N/-S +E/-W Northing Easting Latittude Longitude0.000.006009440.21551774.0170° 26' 11.528 N149° 34' 40.361 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU I-21i, True NorthVertical (TVD) Reference:MPU I-21i As-built RKB @ 60.20usftMeasured Depth Reference:MPU I-21i As-built RKB @ 60.20usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2020-03-27T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.50 700.00 MPU I-21 wp06 (MPU I-21) 3_Gyro-GC_Csg700.00 4999.32 MPU I-21 wp06 (MPU I-21) 3_MWD+IFR2+MS+Sag4999.32 13930.00 MPU I-21 wp06 (MPU I-21) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)4750 5225 5700 6175 6650 7125 7600 8075 8550 9025 9500 9975 10450 10925 11400 11875 12350 12825 13300 13775Measured Depth (950 usft/in)MPI-19MPI-19L1MPI-19PB2MPJ-01ANO GLOBAL FILTER: Using user defined selection & filtering criteria26.50 To 13930.00Project: Milne PointSite: M Pt I PadWell: Plan: MPU I-21iWellbore: MPU I-21Plan: MPU I-21 wp06Ladder / S.F. Plots2 of 2CASING DETAILSTVD TVDSS MD Size Name4010.19 3949.99 4999.32 9-5/8 9 5/8" x 12 1/4"4159.93 4099.73 13930.00 4-1/2 4 1/2" x 8 1/2"
Revised 2/2015
TRANSMITTAL LETTER CHECKLIST
WELL NAME: ______________________________________
PTD: _____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD: ____________________________ POOL: ______________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
No. _____________, API No. 50-_______________________.
Production should continue to be reported as a function of the original
API number stated above.
Pilot Hole
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 name (_______________________PH) and API number
(50-_____________________) from records, data and logs acquired for
well (name on permit).
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce/inject is contingent upon issuance of
a conservation order approving a spacing exception.
(_____________________________) as Operator assumes the liability
of any protest to the spacing exception that may occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in no greater
than 30' sample intervals from below the permafrost or from where
samples are first caught and 10' sample intervals through target zones.
Non-
Conventional
Well
Please note the following special condition of this permit:
Production or production testing of coal bed methane is not allowed for
well ( ) until after ( )
has designed and implemented a water well testing program to provide
baseline data on water quality and quantity.
(________________________) must contact the AOGCC to obtain
advance approval of such water well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by (_______________________________) in the attached application,
the following well logs are also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for well logs run must be submitted to the AOGCC
within 90 days after completion, suspension or abandonment of this
well.
MPU I-21 (injector)
220-051
X
Milne Point Schrader Bluff Oil
X
X
WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:MILNE PT UNIT I-21Initial Class/TypeSER / PENDGeoArea890Unit11328On/Off ShoreOnProgramSERField & PoolWell bore segAnnular DisposalPTD#:2200510MILNE POINT, SCHRADER BLFF OIL - 525140NA1 Permit fee attachedYes2 Lease number appropriateYes3 Unique well name and numberYes4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitYes Area Injection Order No. 10-B14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For Yes15 All wells within 1/4 mile area of review identified (For service well only)Yes No pre-producing of MPU I-21.16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes 20" conductor at 107 ft18 Conductor string providedNA No aquifers19 Surface casing protects all known USDWsYes using 2 stage cement job. ES at 2500 ft md20 CMT vol adequate to circulate on conductor & surf csgNA lateral will have swell packers and ICD's ( no cement)21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes BTC calcs are supplied . All withing industry standards.23 Casing designs adequate for C, T, B & permafrostYes Rig has steel pits.24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes J-16 is close crossing (SI Kup Injector) .. .may move directional plan to avoid.26 Adequate wellbore separation proposedYes 16" conductor on Inno rig. Map of layout is provided.27 If diverter required, does it meet regulationsYes Max form pressure = 1765 psi (8.6 ppg EMW) Will drill with 8.9- 9.5 ppg mud (MPD for wellbore breathing.)28 Drilling fluid program schematic & equip list adequateYes Inno has 13 5/8" BOPE 5000 psi WP29 BOPEs, do they meet regulationYes MASP = 1363 psi will test BOPE to 3000 psi30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo Not expected .33 Is presence of H2S gas probableYes AOR review completed. (No issues with well integrity.)34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S not anticipated from drilling of offset wells; however, rig has H2S sensors and alarms.35 Permit can be issued w/o hydrogen sulfide measuresYes36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprDLBDate6/8/2020ApprGLSDate6/10/2020ApprDLBDate6/8/2020AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJMP6/11/2020dts 6/11/2020JLC 6/11/2020
