Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAbout221-049MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE:Wednesday, October 22, 2025
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Austin McLeod
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
Hilcorp Alaska, LLC
S-48
MILNE PT UNIT S-48
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 10/22/2025
S-48
50-029-23697-00-00
221-049-0
W
SPT
3879
2210490 1500
850 851 851 852
4YRTST P
Austin McLeod
9/15/2025
MITIA. 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 S-48
Inspection Date:
Tubing
OA
Packer Depth
685 1707 1654 1630IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitSAM250915185418
BBL Pumped:1.4 BBL Returned:1.4
Wednesday, October 22, 2025 Page 1 of 1
DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23697-00-00Well Name/No. MILNE PT UNIT S-48Completion Status1WINJCompletion Date9/19/2021Permit to Drill2210490Operator Hilcorp Alaska, LLCMD14899TVD4066Current Status1WINJ11/30/2021UICYesWell 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/DataTypeLogScaleDF10/4/2021105 14899 Electronic Data Set, Filename: MPU S-48 LWD Final.las35736EDDigital DataDF10/4/2021 Electronic File: MPU S-48 LWD Final MD.cgm35736EDDigital DataDF10/4/2021 Electronic File: MPU S-48 LWD Final TVD.cgm35736EDDigital DataDF10/4/2021 Electronic File: MPU S-48i_Definitive Survey Report.pdf35736EDDigital DataDF10/4/2021 Electronic File: MPU S-48i_DSR.txt35736EDDigital DataDF10/4/2021 Electronic File: MPU S-48i_GIS.txt35736EDDigital DataDF10/4/2021 Electronic File: MPU S-48i_Plan.pdf35736EDDigital DataDF10/4/2021 Electronic File: MPU S-48i_Surveys.xlsx35736EDDigital DataDF10/4/2021 Electronic File: MPU S-48i_VSec.pdf35736EDDigital DataDF10/4/2021 Electronic File: MPU S-48 LWD Final MD.emf35736EDDigital DataDF10/4/2021 Electronic File: MPU S-48 LWD Final TVD.emf35736EDDigital DataDF10/4/2021 Electronic File: MPU S-48 LWD Final MD.pdf35736EDDigital DataDF10/4/2021 Electronic File: MPU S-48 LWD Final TVD.pdf35736EDDigital DataDF10/4/2021 Electronic File: MPU S-48 LWD Final MD.tif35736EDDigital DataDF10/4/2021 Electronic File: MPU S-48 LWD Final TVD.tif35736EDDigital Data0 0 2210490 MILNE PT UNIT S-48 LOG HEADERS35736LogLog Header Scans0 0 2210490 MILNE PT UNIT S-48 PB1 LOG HEADERS35737LogLog Header ScansDF10/4/2021105 12515 Electronic Data Set, Filename: MPU S-48 PB1 LWD Final.las35737EDDigital DataTuesday, November 30, 2021AOGCCPage 1 of 3MPU S-48 PB1 LWD Final.lasMPU S-48 LWDFinal.las
DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23697-00-00Well Name/No. MILNE PT UNIT S-48Completion Status1WINJCompletion Date9/19/2021Permit to Drill2210490Operator Hilcorp Alaska, LLCMD14899TVD4066Current Status1WINJ11/30/2021UICYesDF10/4/2021 Electronic File: MPU S-48 PB1 LWD Final MD.cgm35737EDDigital DataDF10/4/2021 Electronic File: MPU S-48 PB1 LWD Final TVD.cgm35737EDDigital DataDF10/4/2021 Electronic File: MPU S-48PB1_Definitive Survey Report.pdf35737EDDigital DataDF10/4/2021 Electronic File: MPU S-48PB1_DSR.txt35737EDDigital DataDF10/4/2021 Electronic File: MPU S-48PB1_GIS.txt35737EDDigital DataDF10/4/2021 Electronic File: MPU S-48 PB1 LWD Final MD.emf35737EDDigital DataDF10/4/2021 Electronic File: MPU S-48 PB1 LWD Final TVD.emf35737EDDigital DataDF10/4/2021 Electronic File: MPU S-48 PB1 LWD Final MD.pdf35737EDDigital DataDF10/4/2021 Electronic File: MPU S-48 PB1 LWD Final TVD.pdf35737EDDigital DataDF10/4/2021 Electronic File: MPU S-48 PB1 LWD Final MD.tif35737EDDigital DataDF10/4/2021 Electronic File: MPU S-48 PB1 LWD Final TVD.tif35737EDDigital DataDF10/4/20216588 14862 Electronic Data Set, Filename: MPU S-48 ADR Quadrants All Curves.las35738EDDigital DataDF10/4/2021 Electronic File: MPU S-48 Geosteering End of Well Report.pdf35738EDDigital DataDF10/4/2021 Electronic File: MPU S-48 Geosteering EOW Plot.emf35738EDDigital DataDF10/4/2021 Electronic File: MPU S-48 Geosteering EOW Plot.pdf35738EDDigital DataDF10/4/2021 Electronic File: MPU S-48 Geosteering EOW Plot150.tif35738EDDigital DataDF10/4/2021 Electronic File: MPU S-48 Geosteering EOW Plot300.tif35738EDDigital DataDF10/4/2021 Electronic File: MPU S-48 Post-Well Geosteering X-Section Summary.pdf35738EDDigital DataDF10/4/2021 Electronic File: MPU_S-48_Geosteering.dlis35738EDDigital DataDF10/4/2021 Electronic File: MPU_S-48_Geosteering.ver35738EDDigital Data0 0 2210490 MILNE PT UNIT S-48 LOG HEADERS35738LogLog Header ScansTuesday, November 30, 2021AOGCCPage 2 of 3
DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23697-00-00Well Name/No. MILNE PT UNIT S-48Completion Status1WINJCompletion Date9/19/2021Permit to Drill2210490Operator Hilcorp Alaska, LLCMD14899TVD4066Current Status1WINJ11/30/2021UICYesWell Cores/Samples Information:ReceivedStart Stop CommentsTotalBoxesSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments:Compliance Reviewed By:Date:Mud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date:9/19/2021Release Date:7/21/2021DF10/4/20216588 12478 Electronic Data Set, Filename: MPU S-48 PB1 ADR Quadrants All Curves.las35739EDDigital DataDF10/4/2021 Electronic File: MPU_S-48PB1_Geosteering.dlis35739EDDigital DataDF10/4/2021 Electronic File: MPU_S-48PB1_Geosteering.ver35739EDDigital Data0 0 2210490 MILNE PT UNIT S-48 PB1 LOG HEADERS35739LogLog Header ScansTuesday, November 30, 2021AOGCCPage 3 of 3M. Guhl 11/30/2021
1a. Well Status:Oil SPLUG Other Abandoned Suspended
1b. Well Class:
20AAC 25.105 20AAC 25.110 Development Exploratory
GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test
2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry:
Aband.:
3. Address: 7. Date Spudded: 15. API Number:
4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number:
Surface:
Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s):
GL: 37.9' BF:
Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation:
4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number:
Surface: x- y- Zone- 4
TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD:
Total Depth: x- y- Zone- 4
5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD:
Submit electronic information per 20 AAC 25.050 (ft MSL)
22.Logs Obtained:
23.
BOTTOM
20" X-52 117'
L-80 1,956'
L-80 3,884'
6-5/8" L-80 4,066'
24. Open to production or injection? Yes No 25.
26.
Was hydraulic fracturing used during completion? Yes No
DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED
27.
Date First Production: Method of Operation (Flowing, gas lift, etc.):
Hours Tested: Production for Gas-MCF:
Test Period
Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr):
Press. 24-Hour Rate
9-5/8"12-1/4"
ACID, FRACTURE, CEMENT SQUEEZE, ETC.
CASING, LINER AND CEMENTING RECORD
List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion,
Uncemented Slotted Liner8-1/2"
TUBING RECORD
w/ Swell Packers
Liner Top Packer
6,455'3-1/2" 9.3# L-80
SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation
Size and Number; Date Perfd):
Stg 2 L - 870 sx / T - 270 sx
44"
Surface 2,493' Stg 1 L - 587 sx / T - 400 sx
18.5 yds Concrete
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
Hilcorp Alaska, LLC
WAG
Gas
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
9/19/2021
3171' FSL, 721' FEL, Sec. 12, T12N, R10E, UM, AK
2577' FSL, 2312' FWL, Sec. 02, T12N, R10E, UM, AK
221-049
Milne Point Field / Schrader Bluff Oil Pool
64.62'
14,897' / 4,066'
HOLE SIZE AMOUNT
PULLED
50-029-23697-00-00
MPU S-48
565291 5999834
875' FSL, 834' FWL, Sec. 12, T12N, R10E, UM, AK
CEMENTING RECORD
5997507
SETTING DEPTH TVD
6004457
BOTTOM TOP
Surface
Surface
CASING WT. PER
FT.GRADE
20#
561586
557723
TOP
SETTING DEPTH MD
Surface
6,447'
Per 20 AAC 25.283 (i)(2) attach electronic information
40#
14,899'
1,956'
3,879'
DEPTH SET (MD)
6,447' / 3,879'
PACKER SET (MD/TVD)
129.5#
47#
117'
2,493' 6,597'
Gas-Oil Ratio:Choke Size:Water-Bbl:
PRODUCTION TEST
Not on Injection
Date of Test:
Flow Tubing
Oil-Bbl:
suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray,
caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation
record. Acronyms may be used. Attach a separate page if necessary
N/A
***Please see Schematic for Details***
ROP, AGR, ABG, DGR, EWR, ADR MD & TVD
Sr Res EngSr Pet GeoSr Pet Eng
Oil-Bbl: Water-Bbl:
9/14/2021
9/1/2021
ADL 380109
01-001
2,249' / 1,799'
N/AN/A
None
14,899' / 4,066'
Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment
By Samantha Carlisle at 11:19 am, Oct 21, 2021
RBDMS HEW 9/28/2021
Completion Date
9/19/2021
HEW
GMGR21OCT2021SFD 10/25/2021 DSR-10/21/21
Conventional Core(s): Yes No Sidewall Cores:
30.
MD TVD
41' 41'
2290' 1840'
Top of Productive Interval 6500' 3881'
1600' 1436'
2957' 2200'
5088' 3431'
6284' 3863'
6500' 3881'
10893' 3898'
10955' 3908'
11234' 3957'
11417' 3987'
11689' 4019'
12003' 4041'
13306' 4019'
13622' 4039'
SB NB 13622' 4039'
31. List of Attachments:
32. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Contact Name: Joe Lastufka
Contact Email:joseph.lastufka@hilcorp.com
Authorized Contact Phone: 777-8400
General:
Item 1a:
Item 1b:
Item 4b:
Item 9:
Item 15:
Item 19:
Item 20:
Item 22:
Item 23:
Item 24:
Item 27:
Item 28:
Item 30:
Item 31:
If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form,
if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071.
Authorized Name: Monty Myers
Authorized Title: Drilling Manager
Schrader Bluff NC
Schrader Bluff NE
Permafrost - Base
29. GEOLOGIC MARKERS (List all formations and markers encountered): FORMATION TESTS
Permafrost - Top
Schrader Bluff NB
SV 1
Ugnu LA3
SV 5
This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram
with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical
reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted.
Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis,
paleontological report, production or well test results, per 20 AAC 25.070.
Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each
segregated pool is a completion.
TPI (Top of Producing Interval).
Yes No
Well tested? Yes No
28. CORE DATA
If yes, list intervals and formations tested, briefly summarizing test results.
Attach separate pages to this form, if needed, and submit detailed test
information, including reports, per 20 AAC 25.071.
NAME
Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical
laboratory information required by 20 AAC 25.071.
Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion,
suspension, or abandonment, whichever occurs first.
Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection,
Observation, or Other.
Schrader Bluff OA
Formation at total depth:
Schrader Bluff NA
LOT / FIT Data Sheet, Drilling and Completion Reports, Csg and Cmt Report, Definitive Directional Surveys, Wellbore
Schematic
Signature w/Date:
Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345),
and/or Easement (ADL 123456) number.
INSTRUCTIONS
The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements
given in other spaces on this form and in any attachments.
The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00).
Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain).
Schrader Bluff NA (Fault)
Schrader Bluff NB
Schrader Bluff NA (Fault)
Schrader Bluff NB
Schrader Bluff NF
Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and
other tests as required including, but not limited to: core analysis, paleontological report, production or well test results.
Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29.
Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool.
If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the
producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced,
showing the data pertinent to such interval).
Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit
detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity,
permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology.
Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment
10.21.2021Digitally 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: 2021.10.21 08:33:52 -08'00'
Monty M
Myers
_____________________________________________________________________________________
Revised By: JNL 9/27/21
PROPOSED SCHEMATIC
Milne Point Unit
Well: MPU S-48
PTD: 221-049
API: 50-029-23697-00-00
Plugback Detail
KOP: 11,800’ MD / 4,026’ TVD
TD: 12,515’ MD / 3,972’ TVD
TD =14,899’(MD) /TD =4,066’(TVD)
20”
Orig. KB Elev.:64.62’ / GL Elev.: 37.9’
3-1/2”
6
2
9-5/8”
1
3/4
8
See
Slotted
Liner
Detail
PBTD =14,897’(MD) / PBTD =4,066’(TVD)
9-5/8” ‘ES’
Cementer @
2,497’
7
6-5/8”
5
CASING DETAIL
Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF
20" Conductor 129.5 / X-52 / Weld N/A Surface 117’ N/A
9-5/8" Surface 47 / L-80 / TXP 8.525” Surface 2,493’ 0.0732
9-5/8" Surface 40 / L-80 / TXP 8.679” 2,493’ 6,597’ 0.0758
6-5/8” Liner 20 / L-80 / Hyd 625 6.049” 6,447’ 14,899’ 0.0355
TUBING DETAIL
3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.992” Surf 6,455’ 0.0870
JEWELRY DETAIL
No Top MD Item
ID
Upper Completion
1 5,716’ Zenith G6 Gauge 400 Bar 150C, 2 Press 2 Temp 2.500”
2 5,768’ XN Nipple, 2.813” Packing Bore, 2.85” No-Go 2.813”
3 6,444’ No Go Locater Sub (1.9’ off No-go) 6.270”
4 6,445’ Bullet Seals – TXP Top Box x Mule Shoe 6.270”
Lower Completion
5 6,447’ 9-5/8” SLZXP Liner Top Packer 6.210”
6 10,888’ 8-1/4” X 4-1/2” Swell Packer 3.920”
7 11,972’ 8-1/4” X 4-1/2” Swell Packer 3.920”
8 14,897’ Shoe
OPEN HOLE / CEMENT DETAIL
44” 18.5 yds Concrete
12-1/4"Stg 1 –Lead 587 sx/ Tail 400 sx
Stg 2 –Lead 870 sx / Tail 270 sx
8-1/2” Cementless Screen Liner
WELL INCLINATION DETAIL
KOP @ 300’ MD
Max Hole Angle = 92° @6,756’
TREE & WELLHEAD
Tree Cameron 3 1/8" 5M w/ 4-1/16” 5M Cameron Wing
Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs
GENERAL WELL INFO
API#: 50-029-23697-00-00
Completed by Innovation: 9/19/2021
Plugback Detail
KOP: 11,800’ MD / 4,026’ TVD
TD: 12,515’ MD / 3,972’ TVD
Page 2 of 2 Revised By: JNL 9/27/21
6-5/8” Slotted Liner
Jts Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)
1 6595’ 6635’ 3884’ 3885’
1 6676’ 6715’ 3885’ 3884’
1 6756’ 6796’ 3883’ 3882’
1 6837’ 6877’ 3880’ 3879’
1 6919’ 6959’ 3878’ 3878’
1 7000’ 7041’ 3878’ 3878’
1 7082’ 7124’ 3879’ 3879’
1 7163’ 7204’ 3880’ 3880’
1 7246’ 7286’ 3880’ 3880’
1 7328’ 7369’ 3879’ 3879’
1 7410’ 7452’ 3879’ 3879’
1 7491’ 7532’ 3878’ 3878’
1 7573’ 7615’ 3878’ 3878’
1 7656’ 7698’ 3878’ 3879’
1 7738’ 7779’ 3880’ 3881’
1 7821’ 7862’ 3882 3884’
1 7903’ 7944’ 3885’ 3886’
1 7985’ 8026’ 3888’ 3889’
1 8067’ 8107’ 3890’ 3891’
1 8148’ 8190’ 3893’ 3893’
1 8231’ 8272’ 3894’ 3894’
1 8313’ 8353’ 3893’ 3893’
1 8395’ 8435’ 3892’ 3891’
1 8477’ 8518’ 3891’ 3890’
1 8559’ 8601’ 3888’ 3887’
1 8642’ 8683’ 3886’ 3884’
1 8723’ 8764’ 3882’ 3881’
1 8805’ 8846’ 3879’ 3877’
1 8887’ 8927’ 3875’ 3874’
1 8966’ 9007’ 3872’ 3871’
1 9048’ 9089’ 3870’ 3869’
1 9130’ 9171’ 3868’ 3868’
1 9212’ 9252’ 3868’ 3868’
1 9294’ 9334’ 3868’ 3868’
1 9375’ 9415’ 3868’ 3868’
1 9456’ 9496’ 3868’ 3867’
1 9537’ 9578’ 3867’ 3867’
1 9619’ 9660’ 3867’ 3866’
1 9699’ 9739’ 3866’ 3865’
1 9781’ 9821’ 3864’ 3864’
1 9862’ 9901’ 3863’ 3862’
1 9943’ 9983’ 3862’ 3861’
1 10025’ 10066’ 3861’ 3861’
1 10107’ 10147’ 3861’ 3862’
1 10187’ 10228’ 3863’ 3864’
1 10269’ 10310’ 3864’ 3864’
1 10351’ 10392’ 3864’ 3864’
1 10433’ 10474’ 3864’ 3865’
1 10515’ 10556’ 3866’ 3868’
1 10595’ 10636’ 3869’ 3871’
1 10677’ 10717’ 3874’ 3878’
1 10759’ 10799’ 3881’ 3886’
32 12029’ 13313’ 4043’ 4019’
19 13602’ 14369’ 4037’ 4049’
9 14535’ 14897’ 4054’ 4066’
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:MPU S-48 Date:9/8/2021
Csg Size/Wt/Grade: 9.625 40#/47# L-80 Supervisor:Barber / Amend
Csg Setting Depth:6,597 3,884 TVD
Mud Weight:8.95 ppg LOT / FIT Press =622 psi
LOT / FIT =12.03 ppg Hole Depth =6627 md
Fluid Pumped=1.0 Bbls Volume Back =0.7 bbls
Estimated Pump Output:0.062 Barrels/Stroke
LOT / FIT DATA CASING TEST DATA
Enter Strokes Enter Pressure Enter Strokes Enter Pressure
Here Here Here Here
->266 ->028
->4135 ->8242
->6216 ->16 503
->8282 ->24 729
->10 342 ->32 978
->12 397 ->40 1249
->14 459 ->48 1445
->16 505 ->56 1800
->18 566 ->64 2084
->20 607 ->72 2367
->22 622 ->76 2522
->24 ->78 2581
->26 ->80 2630
->28 ->
Enter Holding Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0622 ->02630
->1587 ->52604
->2564 ->10 2593
->3547 ->15 2582
->4533 ->20 2574
->5519 ->25 2568
->6510 ->30 2562
->7500 ->
->8492 ->
->9484 ->
->10 477 ->
-> ->
-> ->
-> ->
2
4
6
8
10
12
1416
182022
0
8
16
24
32
40
48
56
64
72
76
7880
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
3100
3200
3300
3400
3500
3600
3700
3800
3900
4000
0 102030405060708090Pressure (psi)Strokes (# of)
LOT / FIT DATA
622587564547533519510500492484477
2630 2604 2593 2582 2574 2568 2562
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
3100
3200
3300
3400
3500
3600
3700
3800
3900
4000
0 5 10 15 20 25 30Pressure (psi)Time (Minutes)
LOT / FIT DATA
Activity Date Ops Summary
8/30/2021 Walk sub over to S-48, spot, shim and set. Spot modules and begin rigging up. Old shaker beds were removed from pits and new beds mobilized to pits via crane
while mods separated. Begin working on Rig acceptance checklist and installing new shaker beds. Scope Derrick up and bridle down. Work on rig acceptance
checklist. Set stack on diverter T, install bolts and line up. Torque all flanges. Install bell nipple, knife valve and diverter line and torque up all flanges. SIMOPS:
Continue install new shaker beds. Daily disposal to G&I: 77 bbl. Total disposal to G&I: 77 bbl. Daily H2O f/ S-Pad: 80 bbl. Total H2O S-Pad: 80 bbl. Daily H2O f/ A-
Pad: 0 bbl. Total H2O A-Pad: 0 bbl. Daily Metal: 0 lbs. Total Metal: 0 lbs. Daily Fluid Loss: 0 bbl. Total Loss: 0 bbl.
8/31/2021 N/U Diverter system: Install 4” valves on conductor, Tighten Nuts on speed head. Install drip pan hoses. Install Diverter Vent line Sections in front of rig. Continue
with Shaker installation. Obtain RKB's Speed Head 27.20', Ground 26.72, Knife 22.50, Bag 11.27, R/U Mezz Lines and all piping removed for Shaker Bed Swap.
Work on Rig acceptance Check List. Swap to Hi Line Power @ 08:00 hrs. Flood and PT all Surface. Continue Install shaker Mtrs. Change Out Saver Sub. Simops:
Weld Bracket for Stand Pipe in Pits. Rig accepted @ 12:00 Hrs Test Diverter System . Witness Waived by Jeff Jones. Knife open 5 sec, Bag closed 8 Sec, System
Pressure 3000 psi, after close 2000 psi, 200 psi build 17 sec, Full recovery 53 sec, Test all gas alarms/PVT/Trip and Flow alarms. Install mouse hole in Rotary. M/U
and rack back 115 stds 5" NC50, 19.5# S-135 drill pipe (3.125” Drift). M/U and rack back w/ jars 9 stds of 5" NC50 HWDP 49.3#, S-135 (2.75” Drift). Service top
drive, blocks, crown, IBOP, spinners, iron roughneck and rig floor equipment. Check oil level in TD and inspect extend frame welds. Mobilize 3rd party tools to rig
floor. Dress Rig tongs for making up 12-1/4" cleanout assembly. Hold PJSM/Pre-Spud Meeting with Crew. Make up 12-1/4" Kymera Bit, 1.5° motor, XO and stand
of 5" HWDP. Tag bottom of conductor at 107' MD from rig floor. Fill surface equipment, lines, and stack with water. Verify no leaks. Verify bull plug on divert line is
out and no leaks. Drill ahead F/ 107' - T/ 220' MD per DD. 400 gpm, 300 psi, 40 rpm, 3k Tor, 4k WOB, 44k up, 44k dn, 43k rot. Pull out of the hole f/220' MD to
surface with 12-1/2" cleanout assembly, racking back 3 stands of 5" HWDP. Make up lift sub, pick up and inspect bit - good. Make up remainder of 12-1/2" drilling
assembly, GWD, DM, EWR-M5, top stabilizer and TM collar. Obtain rig floor offsets. Upload to MWD tools per MWD. DM did not pass confidence test. L/D TM &
M5 Collars on pipe skate. L/D DM collar to floor and MWD Rep C/O DM Probe. Daily disposal to G&I: 0 bbl. Total disposal to G&I: 77 bbl. Daily H2O f/ S-Pad: 620
bbl. Total H2O S-Pad: 700 bbl. Daily H2O f/ A-Pad: 0 bbl. Total H2O A-Pad: 0 bbl. Daily Metal: 0 lbs. Total Metal: 0 lbs. Daily Fluid Loss: 0 bbl. Total Loss: 0 bbl.
9/1/2021 PJSM Cont P/U M/U 12.25" Surface BHA 8" DM, 8" EWR-M5, 8" TM, 2 ea 8" NM FC, 8" Bottle Neck X/O & 5" HWDP to 220' MD. No fill. P/U 51k SLK 51k. Slide/
Rot 12.25" Surface Hole W/ 5" HWDP & 6.5" SLB Hydra Jar & 1 ea 5" HWDP F/ 220' to 406' MD Total 186’ (AROP 53.2’) 500 GPM, 1,120 psi 40 RPM, TRQ on
1.3k, TRQ off 1k, F/O 60%, WOB 8k. ECD 9.0. Max Gas 14u. P/U 60K, SLK 58K, ROT 59K. Jet flowline every other stand. Back ream full stands. Build & turn at
220' MD 3°/100 as per plan.. Slide/ Rot 12.25" Surface Hole W/ 10 ea 5" HWDP & 5" 19.5# S-135 NC50 F/ 406' to 910' MD ( 888' TVD) Total 504’ (AROP 84’) 500
GPM, 1,170 psi 60 RPM, TRQ on 4k, TRQ off 2k, F/O 56%, WOB 8-12k. ECD 9.3. Max Gas 14u. P/U 73K, SLK 72K, ROT 70K. Jet flowline every other stand. BHA
total length 720.45'. Went to MWD surveys at 618' MD. Back ream full stands. Build & turn 3°/100 to 550' MD, start build turn 4°/100 at 550' MD. Slide/ Rot 12.25"
Surface Hole 5" 19.5# S-135 NC50 D.P. F/ 910' to 1,480' MD (1,335' TVD) Total 570’ (AROP 95’) 550 GPM, 1,360 psi 60 RPM, TRQ on 4-5k, TRQ off 2-3k, F/O
68%, WOB 8-12k. ECD 9.8. Max Gas 14u. P/U 82K, SLK 74K, ROT 76K. Jet flowline every other stand. Slide/ Rot 12.25" Surface Hole 5" D.P. F/ 1,480' to 2,090'
MD (1,727' TVD) Total 610’ (AROP 101.6’) 525 GPM, 1,430 psi 60 RPM, TRQ on 5-6k, TRQ off 4-5k, F/O 68%, WOB 5-15k. ECD 10.3. Max Gas 106u. P/U 90K,
SLK 67K, ROT 77K. Jet flowline as needed Back ream full stands. End build turn and started tangent at 1,715' MD. Distance to WP 08a: 12.51', 8.18' High, 9.47'
Right. ROT Hrs 6.03. SLD Hrs 6.75 Daily disposal to G&I: 917 bbl. Total disposal to G&I: 994 bbl. Daily H2O f/ S-Pad: 0 bbl. Total H2O S-Pad: 700 bbl. Daily H2O
f/ A-Pad: 700 bbl. Total H2O A-Pad: 700 bbl. Daily Metal: 0 lbs. Total Metal: 0 lbs. Daily Fluid Loss: 0 bbl. Total Loss: 0 bbl.
9/2/2021 Slide/ Rot 12.25" Surface Hole 5" D.P. F/ 2,087' to 2,687' MD (2,068' TVD) Total 600’ (AROP 100’) 500 GPM, 1,240 psi 60 RPM, TRQ on 6-7k, TRQ off 5-6k, F/O
56%, WOB 2-5k. ECD 10.5. Max Gas 244u. P/U 100K, SLK 67K, ROT 83K. Jet flowline as needed. Log base of Permafrost @ 2292' MD, 1842' TVD. Slide/ Rot
12.25" Surface Hole 5" D.P. F/ 2,687' to 3,323' MD (2,434' TVD) Total 636’ (AROP 106’) 525 GPM, 1,580 psi 80 RPM, TRQ on 7-9k, TRQ off 5-7k, F/O 55%,
WOB 5-12k. ECD 10.6. Max Gas 244u. P/U 114K, SLK 71K, ROT 88K. Jet flowline as needed. Back ream 60'. Slide as needed to maintain tangent. Slide/ Rot
12.25" Surface Hole 5" D.P. F/ 3,323' to 3,959' MD (2,796' TVD) Total 636’ (AROP 106’) 550 GPM, 1,575 psi 80 RPM, TRQ on 7-8k, TRQ off 7.5k, F/O 63%,
WOB 5-12k. ECD 10.5. Max Gas 361u. P/U 120K, SLK 77K, ROT 96K. Jet flowline as needed. Back ream 60'. Slide as needed to maintain tangent. Slide/ Rot
12.25" Surface Hole 5" D.P. F/ 3,959' to 4,531' MD (3,122' TVD) Total 572’ (AROP 95.4’) 525 GPM, 1,680 psi 80 RPM, TRQ on 10-12k, TRQ off 9-10k, F/O 59%,
WOB 7-15k. ECD 10.5. Max Gas 284u. P/U 142K, SLK 76K, ROT 100K. Jet flowline as needed. Back ream 60'. Slide to maintain tangent. Distance to WP 08a:
2.46', 0.73' High, 2.35' Right. ROT Hrs 11.34. SLD Hrs 2.27 Daily disposal to G&I: 1254 bbl. Total disposal to G&I: 2248 bbl. Daily H2O f/ S-Pad: 0 bbl. Total H2O
S-Pad: 700 bbl. Daily H2O f/ A-Pad: 980 bbl. Total H2O A-Pad: 1680 bbl. Daily Metal: 0 lbs. Total Metal: 0 lbs. Daily Fluid Loss: 0 bbl. Total Loss: 0 bbl.
9/3/2021 Drill 12.25" Surface Hole 5" D.P. F/ 4,531' to 4,975' MD (3,371' TVD) Total 444’ (AROP 74’) 550 GPM, 1,670 psi 80 RPM, TRQ on 12-14k, TRQ off 11-12k, F/O
60%, WOB 8-18k. ECD 10.0. Max Gas 186u. P/U 153K, SLK 78K, ROT 105K. Back ream 60'. Slide to maintain tangent to 4658'. Start 4°/100 build/Turn. Slide/
ROT 12.25" Surface Hole 5" D.P. F/ 4,975' to 5,358' MD (3,566' TVD) Total 383’ (AROP 74’) 550 GPM, 1,710 psi 80 RPM, TRQ on 12-14k, TRQ off 11-12k, F/O
60%, WOB 8-18k. ECD 10.0. Max Gas 196u. P/U 151K, SLK 80K, ROT 106K. Jet flowline as needed. Back ream 60'. Cont W/ 4°/100 build/turn. Slide/ ROT12.25"
Surface Hole 5" D.P. F/ 5,358' to 5,675' MD (3,698' TVD) Total 317’ (AROP 52.8’) 550 GPM, 1,620 psi 80 RPM, TRQ on 14-15k, TRQ off 13-14k, F/O 58%, WOB
4-12k. ECD 10.1. Max Gas 565u. P/U 157K, SLK 77K, ROT 108K. Jet flowline as needed. Back ream 60'. Cont W/ 4°/100 build/turn. Slide/ ROT 12.25" Surface
Hole 5" D.P. F/ 5,675' to 6,057' MD (3,823' TVD) Total 382’ (AROP 63.7’) 550 GPM, 1,550 psi 80 RPM, TRQ on 14-16k, TRQ off 14-15k, F/O 66%, WOB 5-15k.
ECD 9.9. Max Gas 512u. P/U 162K, SLK 78K, ROT 110K. Jet flowline as needed. Back ream 60'. Cont W/ 4°/100 build/turn. Distance to WP 08a: 3.45', 0.34' Low,
3.44' Left. ROT Hrs 6.51. SLD Hrs 8.12 Daily disposal to G&I: 798 bbl. Total disposal to G&I: 3046 bbl. Daily H2O f/ S-Pad: 0 bbl. Total H2O S-Pad: 700 bbl. Daily
H2O f/ A-Pad: 1260 bbl. Total H2O A-Pad: 2940 bbl. Daily Metal: 0 lbs. Total Metal: 0 lbs. Daily Fluid Loss: 0 bbl. Total Loss: 0 bbl.
50-029-23697-00-00API #:
Well Name:
Field:
County/State:
MP S-48
Milne Point
Hilcorp Energy Company Composite Report
, Alaska
9/1/2021Spud Date:
9/4/2021 Slide/ ROT 12.25" Surface Hole 5" D.P. F/6,057' to 6,375' MD (3,875' TVD) Total 318’ (AROP 53’) 550 GPM, 1,700 psi 80 RPM, TRQ on 15-17k, TRQ off 15-16k,
F/O 66%, WOB 7-15k. ECD 10.2, Max Gas 560u. P/U 160K, SLK 75K, ROT 110K. Jet flowline as needed. Back ream 60'. Cont W/ 4°/100 build/turn. Slide/ ROT
12.25" Surface Hole 5" D.P. F/6,375' to 6,607' MD (3,884' TVD) Total 232’ (AROP 42’) 550 GPM, 1,950 psi 80 RPM, TRQ on 16-17k, TRQ off 13-14k, F/O 66%,
WOB 14-15k. ECD 10.2, Max Gas 161u. P/U 162K, SLK 75K, ROT 111K. Jet flowline as needed. Back ream 60' Reached surface section TD of 6,607’ md about
5’ TVD below top of the NB-Sand with extrapolated bit inclination of 90.5°. Final Survey 3,884’ TVD Inc 88.52° Azi 296.4°. BROOH F/ 6,607' to 6,444' MD (2
stands) Circ Cond Mud ~25 YP. Pump 37 bbl 9.2 ppg 400 Vis sweep 550 gpm, 1,650 psi, 60 rpm Trq 15k F/O 64% Max Gas 114u. Did not see sweep come back.
Wash down to 6,567' MD. ROT REC Pump 35 bbl 9.2 ppg 200 Vis 2 ppb Nut Plug sweep. 550 gpm, 1,435 psi, 65 rpm Trq 16k F/O 64% Max Gas 31u. Sweep
back 600 stks early, increase in cuttings 50%. 27 YP. CBU 2.5X total. Wash down to 6,607' MD. No Fill. Monitor well 10 min, static. BROOH F/ 6,607' to 5,932' MD.
550 gpm 1,475 psi 65 rpm TRQ 15-16k F/O 65% ECD 9.8 Max Gas 13u. Pull speed 20-25 ft/min as hole dictates. No losses BROOH F/ 6,607' to 2,626' MD. 550
gpm 1,300 psi 65 rpm TRQ 7-9k F/O 63% ECD 10.2 Max Gas 13u. Pull speed 40-60 ft/min as hole dictates. P/U 112k SLK 70k ROT 80k No Losses CBU Prior to
base of perma frost. F/ 2,626' to 2,499' MD. 550 gpm 1,240 psi 65 rpm TRQ 7-8k F/O 63% ECD 10.09 Max Gas 21u. No losses Cont BROOH F/ 2,499' to 2,246'
MD. 550 gpm 1,250 psi 65 rpm TRQ 7-10k F/O 63% ECD 10.1 Max Gas 16u. Pull speed 40-60 ft/min as hole dictates. P/U 111k SLK 70k ROT 80k No Losses
Distance to WP 08a: 10.13', 10.10' High, 0.83' Right. ROT Hrs 2.14. SLD Hrs 6.30 Daily disposal to G&I: 1150 bbl. Total disposal to G&I: 4196 bbl. Daily H2O f/ S-
Pad: 0 bbl. Total H2O S-Pad: 700 bbl. Daily H2O f/ A-Pad: 980 bbl. Total H2O A-Pad: 3920 bbl. Daily Metal: 0 lbs. Total Metal: 0 lbs. Daily Fluid Loss: 0 bbl. Total
Loss: 0 bbl.
9/5/2021 Continue to BROOH from 2246' to 720'. (HWDP) 550 gpm, 1100 psi, 65 rpm, 3-4K Tq, Max Gas @ 21u, ECD 10.4, Pulling speed 20-40 fpm, PUW 64K, SOW
64K, Rot 64K. POOH on elevators racking back 9 stds HWDP from 720' to 157'. See 20K Drag pulling HWDP. Jet Possum Belly, blow down Top Drive and Geo-
Span. PJSM, L/D NM-Drill Collar, plug in and down load MWD Tools. L/D Remaining BHA as per Sperry. Bit Graded: (PDC-1-8-BT-S-X-3-BT-TD)(Tricone-1-1-NO-
A-F-3-NO-TD). Clean and Clear Rig Floor RU to run 9-5/8" Surface casing. RD hydraulic elevators and swing ST-80 into storage position. Make up Volant CRT to
top drive and RU bail extensions w/ side door elevators. Rig up power tongs and bring up centralizers to rig floor. MU shoe track and check floats - good. Fill casing
and drop by-pass baffle. Continue RIH with 9-5/8", 40#/47# TXP BTC, L-80 Surface casing from 125' to 1,200' MD @ 15-40 fpm. Cont RIH W/ 9.625" 40# L-80
TXP BTC F/ 1,200' to 2,622' MD Run speed 25 ft/min. Trq 40# 20,960 ft/lb Install Centralizers as per tally. Fill every 5 jnts and break circ every 10 jnts. Max Gas
14u. Calc 34.8 bbl Actual -1.6, lost 36.4 bbl. P/U 127k SLK 78k. PJSM CBU at 2,622’ MD. Break Circ and stage up F/ 1-6 bpm 150 psi. Rot/Rec F/ 2,622’ to 2,590’
MD 6 rpm broke over at 15k. ROT 6 RPM Trq 8-11.3k 252 gpm 150 psi Max Gas 15u F/O 37%. Heavy sand and clabbered mud seen at shakers ½ way through
BU. Shakers clean at BU. No losses. P/U 115k SLK 80k ROT 93 Cont RIH W/ 9.625" 40# L-80 TXP BTC F/ 2,622' to 3,450' MD Run speed 20-25 ft/min. Trq 40#
20,960 ft/lb Install Centralizers as per tally. Fill every 5 jnts and top off every 10 jnts. Max Gas 14u. Calc 11.2 bbl Actual -2.2, lost 13.4 bbl. P/U 156k SLK 81k. Cont
RIH W/ 9.625" 40# L-80 TXP BTC F/ 3,450' to 4,646' MD Install Centralizers as per tally. Fill every 5 jnts and top off every 10 jnts. Max Gas 14u. P/U M/U ES as
per Halliburton rep onsite. Switch to 47# Csg. Run speed 25 ft/min. Trq 40# 20,960 ft/lb/ 47# 24k. Calc 25.2 bbl Actual 14.5, lost 10.7 bbl. P/U 205k SLK 85k.
PJSM CBU at 4,646’ MD. Break Circ and stage up F/ 1-6 bpm ICP 230 psi FCP 290 psi. Rot/Rec F/ 4,646’ to 4,609’ MD Trq stall set at 15K, rotating 1-2 rpm while
moving. 252 gpm 290 psi Max Gas 15u F/O 56%. Light sand and clay at shakers. Shakers cleaned up at BU. No losses. P/U 194k SLK 98k ROT 105k Cont RIH
W/ 9.625" 40# L-80 TXP BTC F/ 4,648' to 5,797' MD Install Centralizers as per tally. Fill every 5 jnts and top off every 10 jnts. Max Gas 17u. Calc 38 bbl Actual 16,
lost 22 bbl. Run speed 25 ft/min. P/U 250k SLK 98k. Trq 47# 24k ft/lb. Went to Gen Power at 04:30. Daily disposal to G&I: 342 bbl. Total disposal to G&I: 4538 bbl.
Daily H2O f/ S-Pad: 0 bbl. Total H2O S-Pad: 700 bbl. Daily H2O f/ A-Pad: 560 bbl. Total H2O A-Pad: 4480 bbl. Daily Metal: 0 lbs. Total Metal: 0 lbs. Daily Fluid
Loss: 36 bbl. Total Loss: 36 bbl.
9/6/2021 Cont RIH W/ 9.625" 40# L-80 TXP BTC F/ 45,797' to 6,597' MD Install Centralizers as per tally. Fill every 5 jnts and top off every 10 jnts breaking circulation back
to Pits. RIH 25 fpm. Ran total of 78 free floating centralizers. PUW 270K, SOW 85K. Wash last Jt to bottom and stage rate to 6 bpm/420 psi. Circulate and condition
mud for cement job, lower YP to ~20. CBU x 1-1/2. Reciprocated pipe 35" to 5962'. Final circulating pressure @ 6 bpm/320 psi. Monitor Well for 30 min as per
AOGCC prior to removing Vent line section. SIMOPS: R/U cement line to Volant, Clean out overboard Line. Check 4" Valves and R/U Black waterline, Shut all drain
valves in prep for cement Job. Blow down Top Drive, Close upper and lower IBOP's Remove diverter section to get cement trucks spotted on other side of rig. Re-
install diverter section and torque to spec after getting trucks through. Continue to circulate through cement line @ 6 bpm/275 psi, PUW 270K, Sow 115K . HES
Prep for cement Job. HES pump 5 bbls fresh water, 2 BPM, 80 PSI. PT lines to 1000 PSI low / 4000 PSI high. Mix & pump 70 bbls of 10.0 ppg Tuned Spacer w/ 4#
red dye & 5# Pol-E-Flake in 1st 10 bbls, 3.9 BPM, 250 PSI. Drop by-pass plug. Mix & pump 245 bbls of 12.0 ppg lead cmt (587 sks @ 2.347^3/sk yield), 5.4 BPM,
450 PSi Mix & pump 85 bbls of 15.8 ppg tail cmt (400 sks @ 1.15^3/sk yield), 3.5 BPM, 450 PSI. Drop shut-off plug. Pump 20 bbls fresh water, 6 BPM, 355 PSI.
Displace cmt with 272 bbls, 9.4 ppg spud mud with rig pumps 7 BPM, 260 PSI (Chase CMT) HES pump 85 bbls 9.4 ppg tuned spacer, 4.5 BPM, 306 PSI. Cont
displace from rig 133 bbls, 5.5 bpm, 628 psi. (Calc 113 bbl). Reduce rate to 3 bpm, 430 psi. Did not Bump Plug. Check Floats. Good. Drop Opening Bomb and
wait 15 min. Pressure up and see Tool open @ 877 psi. Circ through ES staging up pump F/ 1 to 6 bpm 260 psi. Observed Pol-E-Flak at surface 890 stks into
pumping. At 3,067 stks started overboard clabbered and trace cement. During circ 5 BU adjusting flow rates and dumping clabber and cement overboard, About 20
bbls of cement was seen at surface. Circ a total of 6.5 BU with no losses. Shut down. Disconnect Knife Valve and drain stack. Flush stack W/ Black Water and H2O,
function Annular. Reinstall knife valve lines and cont circ at 6 bpm 305 psi. Wait on cement. Dumped a total of 247 bbls. Looked into MP #2 and found valve guide
bolt on suction side Pod 3 was broken and valve was not functioning. This is why we were unable to bump plug. PJSM Cont Circ W OC 6 bpm 350 psi. Function 4"
valve to ensure free. Blow down cement line back to HES. Un sting from Volant and sting back in to ensure good. PJSM, Wet lines w/ 5 bbls H2O (HES) Pump 2nd
stage cement job as follows: 60 bbls 10 ppg Tuned spacer w/ 4# red dye & 5 lb/bbl poly flake (1st 10 bbls). ArcticCem 446 bbls 10.7 ppg Lead cmt, 2.883 yld, 4.5
bpm, 410 PSI. SwiftCem 57.7 bbls 15.8 ppg Tail cmt, 1.17 yld, 3 bpm 275 PSI. Un sting from Volant and drop closing plug. Displace w/ 20 bbls H2O (HES) 5 bpm
306 PSI then turn over to rig. Rig disp w/ 162.5 bbls / Calc 163 bbls 9.5 ppg spud mud, 5 bpm 624 PSI. Reduced rate last 10 bbls to 2 bpm, FCP 450 PSI. ES
Cementer shifted shut at 1,480 PSI. Held pressure for 3 minutes, check floats - good. CIP 05:02 hrs. Full returns throughout job. Saw spacer at surface 35 bbls
early. Dumped 322 bbls of green cement. PJSM Wash up surface Equip and stack W/ Black Water. Disconnected knife valve and function Annular. Blow down
cement line. R/D cement lines. R/D Volant tool. Daily disposal to G&I: 1610bbl. Total disposal to G&I: 6149 bbl. Daily H2O f/ S-Pad: 0 bbl. Total H2O S-Pad: 700
bbl. Daily H2O f/ A-Pad: 1120 bbl. Total H2O A-Pad: 5600 bbl. Daily Metal: 0 lbs. Total Metal: 0 lbs. Daily Fluid Loss: 53 bbl. Total Loss: 89 bbl.
Did not Bump Plug.
9/7/2021 PJSM R/D diverter section F/ Tee to catwalk. Bleed down Koomey. Loosen speed head. P/U stack W/ bridge cranes and center 9.625" Csg in conductor. Set
emergency slips W/ 115K. Cut and L/D 9.625" Csg. (cut 29.90') Set down stack and Johnny whack W/ 50 bbls black H2O 8 bpm. 10 rpm. B/D TD. Remove Knife
Valve, Rack Back Stack, Pull Diverter Tee and Speed Head and send outside. Assist welder with dressing casing stub. Send out all casing tools. Clean surface
equipment in pits. PJSM install T-103 and fill W/ plastic as per NOS rep. PT to 3,760 psi for 10 min. Install tubing spool and test plug. PT 500 psi/ 5 min, 5,000 psi/
10 min. Continue to Clean Pits. Install MPD Head, DSA, Riser spool, and test plug, Set stack and trq. Secure turn buckles and install drip pan. Hook up koomey
lines. Install choke and kill lines. Press koomey. Install 1502 flange on IA. Simops: Clean pits. C/O liner/swab MP1, Pods 1 & 4. RKB's LDS 23.68' LPR's 19.25'
UPR's 14.42' Ann 11.95'. Went to highline at 15:30. PJSM Flood MPD lines. Test MPD Equip 500 psi low and 1,200 psi high as per Beyond rep onsite. Good test.
Pull MPD test plug and install riser. PJSM Shell test to 3,000 psi. Test W/ 5" test jnt to 250 psi/ 3,000 psi 5 min on chart. Tested CMV's 1-15, 5" Dart, 2 ea 5" TIW,
Upper & Lower IBOP, Annular, UPR (2.875" X 5" VRB's), F/P LPR (2.875" X 5" VRB's) Functioned 3X. Blinds, HCR & Manual Kill, Mezz Kill, F/P Super Choke
Performed dynamic rolling test to 700 psi to 1,500 psi. Tested Manual to 1,600 psi. Witnessed by AOGCC rep Matt Herrera. Cont testing W/ 3.5" test jnt, Annular,
HCR & manual choke, LPR (2.875" X 5" VRB's). Test H2S 10-20 ppm, LEL 20-40%, PVT high/ low level alarms. Checked PVT sensors and return flow. Koomey
draw drown Initial System 3,000 PSI, Manifold 1,550 PSI, Annular 1,300 PSI, after System 1,600 PSI, Man 1,500 PSI, Annular 1,375 PSI. 200 PSI increase 24 Sec,
full charge 84 sec. Nitrogen 6 bottle average 2,308 PSI. Witnessed by AOGCC Matt Herrera. R/D test Equip. Blow down Choke and kill. Pull test plug and install
wear bushing (OD 10 .8" ID 10" Lng 12.8") PJSM P/U M/U Clean Out BHA. RR 8.5" XR-CPS Tricone Bit (0.9419 TFA) 6.75" StrataForce Lobe 6.7 - 6 stg 1.5°
Motor, 10 ea 5" HWDP, 6.75" Hydra Jar and 7 ea 5" HWDP 582.16'. Cont single in hole W/ 5" 19.5# S-135 NC50 D.P. F/ 582' to 2,468' MD. Wash down 350 gpm
525 psi F/ 2,468' to ES plug at 2,496' set down 5k. Drift OD 3.125" OD. P/U 92k SLK 66k. Drill ES plug F/ 2,496' to 2,497' MD. 350 gpm 425 psi 30 rpm Trq 4-6k
WOB 2k. P/U 92k SLK 66k ROT 79k. Rubber seen at shakers. Daily disposal to G&I: 1196bbl. Total disposal to G&I: 7345 bbl. Daily H2O f/ S-Pad: 0 bbl. Total
H2O S-Pad: 700 bbl. Daily H2O f/ A-Pad: 700 bbl. Total H2O A-Pad: 6300 bbl. Daily Metal: 0 lbs. Total Metal: 0 lbs. Daily Fluid Loss: 0 bbl. Surface Loss: 89 bbl.
9/8/2021 Continue drill HES stg tool @ 2496' MD (on depth). 350 gpm, 425 psi, 30 rpm, 4-6k tq, WOB 2k. 92k up, 66k dn, 78k rot. Rubber observed @ shakers. Tripped
thru clean. Continue single in with 5" NC50, S-135 drill pipe F/ 2496' - T/ 5770' tag depth. Set dn 20k. Fill pipe and establish parameters. 185k up, 77k dn,
Tagged 706' high from expected tag depth @ BFL adapter (6476' as per tally). Drill hard cmt F/ 5770' - T/ 5780' MD. 400 gpm, 890 psi, 30 rpm, 12k tq on, 11k tq
off, 185k up, 76k dn, 106k rot. 6k wob. Circulate STS @ 5780' MD. 400 gpm, 500 psi, 30 rpm, 13.5k tq. Recip/Rot pipe. Overboard ~10 bbls cmt contaminated
mud @ btms up. 168k up, 78k dn after conditioning mud. R/U @ 5780' MD and pressure test 9-5/8" surface casing to 2500 psi w/ 30 min hold (Test good). Chart
and record same. 4.6 bbls pumped, 4.4 bbls bled back. Drill hard cmt F/ 5780' - T/ 6435' MD. 550 gpm, 1500 psi, 40 rpm, 14.5k tq on, 14k tq off, 168k up, 72k dn,
109k rot. 10-12k wob. ROP 220-300 fph. Saw rubber @ shakers @ 5840' MD. CBU ROT REX F/ 6,435' to 6,3910' MD 550 gpm 1,410 psi 40 rpm Trq 13-14k
F/O 58% P/U 168k LSK 68K ROT 108k PJSM Blow through kill and choke lines confirm no cement debris. L/D single joint. R/U test Equip. flood lines. Test 9.625"
Csg to 2,500 psi for 30 min on chart, good. Bump 4.8 bbl bled back 4.8 bbl. R/D Equip. Cont drilling Shoe track, BFA 6,475', FC 6,515', Shoe 6,597' all on depth.
Drill F/ 6,597' to 6,627 MD including 20' of new hole. 550 gpm 1,400 psi 40 rpm Trq 14k F/O 59% WOB 4-8k Max Gas 14u. Displace 9.5 ppg Spud Mud W/ 8.9
ppg BaraDril N. Pump 36 bbl 8.95 ppg 300 Vis sweep chase W/ 8.95 BaraDril. Work through shoe at 6,597' MD 3X no issue. 550 gpm 1,510 psi 40 rpm Trq 7-8k
F/O 59% Max Gas 74u. P/U 165k SLK 72k ROT 106k. SPR. Monitor 10 min, static. PJSM R/U Test Equip, flood lines. Perform FIT 12 EMW W/ 8.95 ppg MW
3,884' TVD 616 psi Pumped 1 bbl bled back 0.7 bbl. PJSM Blow down surface Equip and R/D test Equip. Pump dry job and blow down top drive. PJSM POOH
rack back 5" D.P. F/ 6,566' to 592' MD. P/U 152k SLK 74k. No losses. PJSM L/D 5" HWDP (14 jnts) rack back 2 stands 5" HWDP W/ Jar. Milk motor and break off
8.5" RR Bit. Bit Grade 1-1-WT-A-E-1-NO-BHA Clean and clear rig floor. P/U working single and Johnny Whack the stack 420 gpm 100 psi. L/D single and Johnny
Whacker. R/U floor tongs. PJSM P/U M/U 8.5" SK616M-J1D (6X14)(0.9020 TFA) 8.5" Hycalog NRP, 7.625" Geo-Pilot 7600 XL 25KSI, 6.75" ADR, 8.375" ILS,
6.75" DGR & 6.75" PWD total 64.01' MD. Daily disposal to G&I: 1196bbl. Total disposal to G&I: 7345 bbl. Daily H2O f/ S-Pad: 0 bbl. Total H2O S-Pad: 700 bbl.
Daily H2O f/ A-Pad: 560bbl. Total H2O A-Pad: 8860 bbl. Daily Metal: 10 lbs. Total Metal: 10 lbs. Daily Fluid Loss: 0 bbl. Surface Loss: 89 bbl.
9/9/2021 Continue M/U 8.5" RSS assy. M/U MWD and download. M/U 2x flex DCs w/ 2 solid plunger float sub between. 3x 5" NC50 HWDP w/ SLB 6.5" jars T/ 280.62'
MD. Shallow pulse test @ 400 gpm, 480 psi (test good). TIH with 5" NC50, S-135, 19.5# singles F/ 280' - T/ 3013' MD. Drift 3.125". Fill pipe and Break in Geo
Pilot @ 3013' MD. No losses. Continue TIH out of derrick with 5" dp F/ 3013' - T/ 4286' MD. 100k up, 80k dn. No losses. Continue TIH out of derrick with 5" dp
F/ 4286' - T/ 6320' MD. 135k up, 94k dn. No losses. Monitor well (static). Proper displacement for trip. PJSM, Remove MPD trip nipple, install MPD RCD head as
per Beyond rep. Tighten clamp. Pump thru surface lines (no leaks). 400 gpm, 875 psi. PJSM, Cut and slip drilling line. Inspect drawworks and perform monthly
EAM on sheave wobble. Calibrate blocks. Grease and service traveling equipment. Check fluids in TDS (good). Service handling equipment. TIH F/ 6320' - T/
6627' MD. Drill 8.5" lateral in "NB" as per Geo F/ 6627' - T/ 6710' MD (3884' TVD). 450 gpm, 1100 psi, 3K wob, 80 rpm, 9k tq on, 9k tq off, BGG 14u, 10 ECD,
135k up, 85k dn, 99k rot. Cont Drill 8.5" Hole F/ 6,710' to 7,209' MD ( 3,879' TVD) Total 499’ (AROP 83.2’) 525 GPM/ MPD 521, 1,460 psi, 110 RPM, TRQ on 11-
12k, TRQ off 11k, WOB 8-10k. ECD 10.3. Max Gas 2230u. P/U 138k, SLK 68k, ROT 98k. MPD 100% open. Back ream full stand. Ungulate in NB as per Geo.
Cont Drill 8.5" Hole F/ 7,209' to 7,715' MD ( 3,876' TVD) Total 506’ (AROP 84.3’) 500-525 GPM/ MPD 530, 1,525 psi, 100-120 RPM, TRQ on 10-11k, TRQ off 9-
10k, WOB 6-12k. ECD 10.4. Max Gas 1,316u. P/U 128k, SLK 78k, ROT 99k. MPD 100% open. Back ream full stand. Possible Fault at 7,449' MD waiting for Geo
confirmation. Start 4°/ 100 turn at 7,484' MD. Distance to WP08a: 24.56', 24.56' High, 0.15' Right 2 concretions for a total thickness of 10' (1.0% of the lateral).
Footage NB Sand 1,033' Daily disposal to G&I: 285bbl. Total disposal to G&I: 8959 bbl. Daily H2O f/ S-Pad: 0 bbl. Total H2O S-Pad: 700 bbl. Daily H2O f/ A-Pad:
240bbl. Total H2O A-Pad: 7100 bbl. Daily Metal: 10 lbs. Total Metal: 20 lbs. Daily Fluid Loss: 0 bbl. Surface Loss: 89 bbl.
9/10/2021 Cont Drill 8.5" Hole F/ 7715' to 8288' MD ( 3,896' TVD) Total 573’ (AROP 96’) 550 GPM / MPD 550, 1750 psi, 120 RPM, TRQ on 10-12k, TRQ off 7-8k, WOB 5-
14k. ECD 10.75. Max Gas 1247u. P/U 122k, SLK 83k, ROT 95k. MPD 100% open. Back ream full stand. 10 ppb background LCM, 2.5% lubes. Start turn 2°/100
at 7,938' MD. Cont Drill 8.5" Hole F/ 8288' to 8922' MD ( 3,875' TVD) Total 634’ (AROP 106’) 550 GPM / MPD 550, 1950 psi, 120 RPM, TRQ on 11-13k, TRQ off
12k, WOB 10-14k. ECD 11.3. Max Gas 829u. P/U 131k, SLK 71k, ROT 94k. MPD 100% open. Back ream full stand. 10 ppb background LCM, 2.5% lubes. Cont
Drill 8.5" Hole F/ 8,922' to 9,496' MD ( 3,867' TVD) Total 574’ (AROP 95.7’) 550 GPM / MPD 550, 1960 psi, 120 RPM, TRQ on 8-12k, TRQ off 12k, WOB 6-13k.
ECD 11.13. Max Gas 978u. P/U 123k, SLK 72k, ROT 94k. MPD 100% open. Back ream full stand.12 ppb background LCM, Perform clean up cycle 2X BU F/
9,302' to 9,429' MD to control ECD F/ 11.35 to 11.15. Cont turn 2°/100. Cont Drill 8.5" Hole F/ 9,496' to 10,107' MD ( 3,860' TVD) Total 611’ (AROP 101.9’) 500-
550 GPM / MPD 550, 1775 psi, 120 RPM, TRQ on 10k, TRQ off 9k, WOB 6-12k. ECD 11.44. Max Gas 1591u. P/U 130k, SLK 67k, ROT 95k. MPD 100% open.
Back ream full stand. Distance to WP08a: 62.18', 61.92' High, 5.73' Right Fault #1 at 7,499' MD DTW ~10'. 13 concretions for a total thickness of 63' (1.8% of the
lateral). Footage NB Sand 3,418' Daily disposal to G&I: 684 bbl. Total disposal to G&I: 9643 bbl. Daily H2O f/ S-Pad: 0 bbl. Total H2O S-Pad: 700 bbl. Daily H2O f/
A-Pad: 810bbl. Total H2O A-Pad: 7910 bbl. Daily Metal: 10 lbs. Total Metal: 30 lbs. Daily Fluid Loss: 0 bbl. Surface Loss: 89 bbl.
9/11/2021 Cont Drill 8.5" Hole F/ 10107' to 10609' MD ( 3,869' TVD) Total 502’ (AROP 84’) 550 GPM / MPD 550, 2100 psi, 120 RPM, TRQ on 10k, TRQ off 9k, WOB 8k.
ECD 11.46. Max Gas 1589u. P/U 130k, SLK 63k, ROT 96k. MPD 100% open. Back ream full stand. Built contingency sidetrack point @ ~10190' MD. Drilled up in
section then turned down to exit base of "NB" with ~5° deflection from formation dip. Exited clean @ 10807' MD without issue. Cont Drill 8.5" Hole F/ 10609' to
11147' MD ( 3942' TVD) Total 538’ (AROP 90’) 550 GPM / MPD 550, 2190 psi, 120 RPM, TRQ on 13k, TRQ off 11k, WOB 8-11k. ECD 11.51. Max Gas 1483u.
P/U 142k, SLK 61k, ROT 95k. MPD 100% open. Back ream full stand. Control drill @ 175 max ROP starting @ 11100' due to high ECD's (11.7 EMW). Screen
both shaers with 1x screen from 170 to 200. MPS-32 - 14.08' C to C at 10760' MD, mag Interference at survey 10,823.26' MD with 350.19° Azi Interpolated. Cont
Drill 8.5" Hole F/ 11,147' to 11,658' MD (4,016' TVD) Total 511’ (AROP 85.2’) 525 GPM / MPD 526, 2,060 psi, 120 RPM, TRQ on 11-13k, TRQ off 11k, WOB 6-
12k. ECD 11.51. Max Gas 1,239u. P/U 143k, SLK 63k, ROT 99k. MPD 100% open. Back ream full stand. Control drill 175 ft/hr for ECD's. Cont Drill 8.5" Hole F/
11,658' to 11,798' MD (4,027' TVD) Total 140’ (AROP 93.3’) 525 GPM / MPD 525, 2,120 psi, 120 RPM, TRQ on 13k, TRQ off 10k, WOB 6-10k. ECD 11.55. Max
Gas 998u. P/U 145k, SLK 60k, ROT 99k. MPD 100% open. Back ream full stand. Control drill 175 ft/hr for ECD's. Crossed Fault #2 11,689’ MD 120’ DTW. After
the fault appears we crossed the ND top so far. Currently directional steering 100% deflection to find NB Sand. ROT REC Discuss with geology about sidetrack,
decision was made to go 100% deflection W/ 3-4° DLS to find NB Sand. If unable to find NB Sand will perform sidetrack around 11,450' MD. Rot Rec F/ 11,798' to
11,778' MD 525 GPM / MPD 525, 2,075 psi, 120 RPM, TRQ 11.5-13k BGG 192u. Cont Drill 8.5" Hole F/ 11,798 to 12,039' MD (4,023' TVD) Total 241’ (AROP
68.9’) 525 GPM / MPD 525, 2,115 psi, 120 RPM, TRQ on 12-14.3k, TRQ off 11.5k, WOB 6-16k. ECD 11.67. Max Gas 858u. P/U 152k, SLK 55k, ROT 98k. MPD
100% open. Back ream full stand. Control drill 175 ft/hr for ECD's. Currently holding 90% deflection. Distance to WP08a: 4.82', 3.89' Low, 2.85' Right Fault #1 at
7,499' MD DTW ~10'. Fault #2 is at 11,689’ MD ~120' DTW. 20 concretions for a total thickness of 93' (1.7% of the lateral). Footage NB Sand 4,210', Out of zone
1,166'. Total 5,376' Daily disposal to G&I: 912 bbl. Total disposal to G&I: 10555 bbl. Daily H2O f/ S-Pad: 0 bbl. Total H2O S-Pad: 700 bbl. Daily H2O f/ A-Pad:
1080bbl. Total H2O A-Pad: 8990 bbl. Daily Metal: 3 lbs. Total Metal: 30 lbs. Daily Fluid Loss: 0 bbl. Surface Loss: 89 bbl.
9/12/2021 Cont Drill 8.5" Hole F/ 12,039' - T/ 12483' MD (3979' TVD) Total 444’ (AROP 74’) 500 GPM / MPD 500, 2090 psi, 120 RPM, TRQ on 16k, TRQ off 12.5k, WOB 8-
10k. ECD 11.73. Max Gas 905u. P/U 148k, SLK N/A (12483' no dn wt) ROT 98k. MPD 100% open. B/R full stand. Control drill 175 ft/hr for ECD's. Continue drill
down in section to 11841'with geological uncertainty, turn up and build to ~95.5° Inclination. Hold and climb in section in an attempt to reacquire "NB" sand. Cont
Drill 8.5" Hole F/ 12483' - T/ 12512' MD (3971' TVD) Total 29’ (AROP 58’) 500 GPM / MPD 500, 2090 psi, 120 RPM, TRQ on 16k, TRQ off 12.5k, WOB 8-10k.
ECD 11.73. Max Gas 567u. P/U 148k, SLK N/A , ROT 95k. MPD 100% open. B/R full stand. Rot/Recip @ 12512' MD while waiting on orders due to geological
uncertainty. 500 gpm, 2010 psi, 11.42 ECD's w/ 9.25 MW. 120 rpm, 13k tq. P/U 144k, No Dn wt, ROT 95k. Obtain final survey and SPR's. Decision made to
pull back to ~11800' MD and sidetrack drilling down in section to find "NB" sand BROOH F/ 12512' - T/ 11798' MD. 500 gpm, 2050 psi, 120 rpm, 14k tq. 20-40
fpm pulling speed . No tight spots or other issues encountered. 165-180° ROHS Toolface and begin time drilling @ 10 fpm from 11798' - T/ 11816'. time drill rop
f/ 10 to 25 fpm f/ 11,816' - T/ 11,831' MD (4027' tvd) pb1 inc @ 11,831' 88.2° inc ABI @ same depth 84.8° inc. 500 gpm, 1940 psi, 120 rpm, 18.5k tq, WOB 3-6k ,
max gas 254u. P/U 145k, S/O 46k, Rot 96k. Cont Drill 8.5" Hole F/ 11,831' to 12,230' MD (4,052' TVD) Total 399’ (AROP 79.8’) 500 GPM / MPD 499, 2,040 psi,
120 RPM, TRQ on 14-15k, TRQ off 14k, WOB 6-12k. ECD 11.6. Max Gas 1249u. P/U 146k, SLK 47k ROT 95k. MPD 100% open. B/R full stand. Control drill 175
ft/hr for ECD's. Back in NB sand at 12,033’ MD 4,043’ TVD Cont Drill 8.5" Hole F/ 12,230' to 12,738' MD (4,032' TVD) Total 508’ (AROP 84.7’) 490 GPM / MPD
485, 1,960 psi, 120 RPM, TRQ on 13-15k, TRQ off 12.5-14k, WOB 6-13k. ECD 11.57. Max Gas 1383u. P/U 140k, SLK 60k ROT 96k. MPD 100% open. B/R full
stand. Control drill 150 ft/hr for ECD's. At 12,340' MD saw slight dynamic loss ~20 bph, lost 5 bbls, reduce rate to 490 gpm ROP 150 ft/hr due to ECD's 11.72, no
losses. Dump 200 bls & diluted W/ 240 bbls 9.0 ppg BaraDril due to MBT, went F/ 8 to 6.2 ppb. Distance to WP08a: 25.05', 9.10' Low, 23.34' Right Fault #1 at
7,499' MD'. Fault #2 is at 11,689’ MD, Fault #3 11,735' 48' DTW. 22 concretions for a total thickness of 101' (1.7% of the lateral). PB1 11,800' to 12,512' MD Total
732'. Footage NB Sand 4,845', Out of zone 1,226'. Total 6,071' Daily disposal to G&I: 889 bbl. Total disposal to G&I: 11444 bbl. Daily H2O f/ S-Pad: 0 bbl. Total
H2O S-Pad: 700 bbl. Daily H2O f/ A-Pad: 760bbl. Total H2O A-Pad: 9750 bbl. Daily Metal: 5 lbs. Total Metal: 38 lbs. Daily Fluid Loss: 5 bbl. Surface Loss: 89 bbl.
9/13/2021 Cont Drill 8.5" Hole F/ 12738' to 13247' MD (4,015' TVD) Total 509’ (AROP 85’) 470 GPM / MPD 468, 1905 psi, 120 RPM, TRQ on 15.5k, TRQ off 15k, WOB 5-
8k. ECD 11.7 Max Gas 1191u. P/U 157k, SLK 50k ROT 95k. MPD 100% open. B/R full stand. Control drill 150 ft/hr for ECD's. Continue managing ECD's with 30
bph H2O, 200's on both shakers and reducing flow rate as needed to not exceed 11.7 ECD's. Cont Drill 8.5" Hole F/ 13247' to 13748' MD (4,044' TVD) Total 501’
(AROP 71.6’) 470 GPM / MPD 471, 2100 psi, 120 RPM, TRQ on 17.5k, TRQ off 17k, WOB 7-14k. ECD 11.92, Max Gas 1378u. P/U 160k, SLK N/A(13624'), ROT
95k. MPD 100% open. B/R full stand. Control drill 120-150 ft/hr for ECD's. Fault #4 at 13,306' MD 25' DTW, renter NB Sand at 13,622' MD. At 13,748’ MD
encountered Trq stall 22k, initial dynamic losses ~178 bph (lost ~41 bbl). Reduced rate F/ 475 to 350 gpm 86% return flow 71 bph loss rate. Stage up pumps to
400 gpm 95% returns W/ 30 bph loss rate. Rot Rec F/ 13,748’ to 13,685’ MD 400 gpm/ mpd 379 1,260 psi 120 rpm Trq 16.5-20k ROT 97k. Build 54 bbl 44 ppb
LCM Pill (BaraCarb 20 ppb 50, 8 ppb 25, 16 ppb 5) Drill stand down W/ 93% returns F/ 13,748’ to 13,753’ MD ROP 1-5 ft/hr 400 gpm/ mpd 375 93% 1,440 psi
120 rpm Trq on17.5-20.8k Trq off 15.2k WOB 4-15k ECD 11.05 Max Gas 637u. P/U 153k SLK 35k ROT 97k. MPD 100% open. Appeared to be a concretion. At
kelly down Pump 27 bbl 44 ppb LCM Pill and spot outside of bit. Seeing ballooning at connections. Lost 114 bbls during this time (Avg loss 38 bph). Control Drill
8.5" Hole F/ 13,753' to 13,851' MD (4,046' TVD) Total 98’ (AROP 49’) 400 GPM / MPD 378, 1,470 psi, 120 RPM, TRQ on 13-14k, TRQ off 13k, WOB 3-5k. ECD
11.14, Max Gas 575u. P/U 150k, SLK 54, ROT 97k. MPD 100% open. B/R full stand. Control drill 100 ft/hr due to reduced pump rates. Take surveys prior to
connection. Staging up pumps at connection F/ 325-400 gpm W/ ~90% return flow. Cont ballooning at connections. Increase lube 0.5% to 3%. Increase
background Calcium Carbonate F/ 12 ppb to 15 ppb. Control Drill 8.5" Hole F/ 13,851' to 14,168' MD (4,047' TVD) Total 371’ (AROP 53’) 420 GPM / MPD 408,
1,610 psi, 120 RPM, TRQ on 15-16.5k, TRQ off 12-15k, WOB 4-11k. ECD 11.26, Max Gas 833u. P/U 155k, SLK 46k ROT 98k. MPD 100% open. B/R full stand.
Control ROP 120 ft/hr due to reduced pump rates. Cont seeing ballooning at connections. Staging up pumps at connection F/ 325-420 gpm W/ ~90% return flow.
Dynamic losses 2-15 bph. Lost 50 bbls. Distance to WP08a: 7.94', 7.75' High, 1.71' Left Fault #1 at 7,499' MD'. Fault #2 is at 11,689’ MD, Fault #3 11,735' 48'
DTW Fault #4 13,306'. 37 concretions for a total thickness of 140' (1.9% of the lateral). PB1 11,800' to 12,512' MD Total 732'. Footage NB Sand 5,971', Out of zone
1,542'. Total 7,513' Daily disposal to G&I: 627 bbl. Total disposal to G&I: 12071 bbl. Daily H2O f/ S-Pad: 0 bbl. Total H2O S-Pad: 700 bbl. Daily H2O f/ A-Pad:
1060bbl. Total H2O A-Pad: 10810 bbl. Daily Metal: 2 lbs. Total Metal: 40 lbs. Daily Fluid Loss: 171 bbl. Prod total: 176 bbl.
9/14/2021 Control Drill 8.5" Hole F/ 14168' - T/ 14391' MD (4,048' TVD) Total 223’ (AROP 37’) 430 GPM / MPD 408, 1630 psi, 80-120 RPM, TRQ on 16.5k, TRQ off 15k,
WOB 4-11k. ECD 11.25, Max Gas 833u. P/U 161k, SLK 44k ROT 99k. MPD 100% open. B/R full stand. Control ROP 120 ft/hr manage loss rate. 5-34 bph
dynamic loss rate. Minimize loss rates by keeping ECD's under 11.3 EMW. Breathing back on connections and trending down (flowback 18-24 bbl during
connections). Drilled Fault #5 @ 14248’ w/ 8’ DTW throw, Drilled fault #6 @ 14378’ MD w/ 8’ DTW throw. Control Drill 8.5" Hole F/ 14391' - T/ 14818' MD (4,061'
TVD) Total 427’ (AROP 61’) 430 GPM / MPD 408, 1630 psi, 80-120 RPM, TRQ on 16.5k, TRQ off 15k, WOB 10-16k. ECD 11.42, Max Gas 613u. P/U 169k, SLK
N/A ROT 97k. MPD 100% open. B/R full stand. Control ROP 120 ft/hr manage loss rate. At 14,818’ MD encountered minor spike Trq 21k, initial dynamic losses
~103 bph (lost ~70 bbl). Reduced rate F/ 430 to 300 gpm 84% return flow, 80 bph loss rate. Stage up pumps to 350 gpm 89% returns W/ 56 bph loss rate. Drill
stand down W/ 93% returns F/ 14,818’ to 14,832’ MD ROP 1-5 ft/hr due to concretion & Trq 350 gpm/ mpd 326 93% 1,203 psi 80-100 rpm Trq on18.5-20.8k Trq
off 18.5k WOB 1-6k ECD 10.76 Max Gas 316u BGG 33u. P/U 169k SLK 35k ROT 97k. MPD 100% open. At kelly down Pump 25 bbl 44 ppb LCM Pill 44 ppb
LCM Pill (BaraCarb 20 ppb 50, 8 ppb 25, 16 ppb 5) and spot outside of bit. Rot Rec F/ 14,837’ to 14,772’ MD 350 gpm/ mpd 316 90% 1,265 psi 100 rpm Trq 18.5-
19.1k ROT 97k. Seeing ballooning at connections. Lost 123 bbls during this time (Avg loss 38 bph). Control drill 8.5" Hole F/ 14,837' to TD 14,899' MD (4,066'
TVD) Total 62’ (AROP 41.4’) 360 GPM / MPD 330 91%, 1,270 psi, 90-110 RPM, TRQ on 18-20.5k, TRQ off 19k, WOB 6-10k. ECD 10.85, Max Gas 223u. P/U
170k, SLK 35, ROT 98k. MPD 100% open. Control drill 100 ft/hr for trq & AV's. Cont to see dynamic losses ~30 bph. Saw ballooning at connections. Appears
sweep did not slow dynamic losses down. Perform final survey 14,899’ MD 4065.76’ TVD 88.08° inc 345.81° Azi Perform clean up cycle. Rot Rec F/ 14,899’ to
14,837’ MD 350-370 GPM/ MPD 337-347 1,540 psi 110 rpm Trq 18.8-19.7k ECD 10.93 Mac Gas 387u. Dynamic losses 25-35 bph. Pump 40 bbl 8.8 ppg 35 Vis &
50 bbl 9.8 ppg 300+ Vis tandem sweeps. Sweeps back 700 stks (43 bbls) late and 15% increase of cuttings. After sweeps came out return flow came up to 97%
and ECD fell F/ 10.95 to 10.81. Shut down and line up on charge pumps to clean pit 5. Came back on at 370 GPM/ MPD 350 94% returns. Max Gas 411u. CBU 3
of 4. P/U 168k SLK 44k ROT 99k. Lost 144 bbls during circ. Distance to WP08a: 21.31', 2.42' High, 21.17' Left Fault #1 at 7,499' MD'. Fault #2 is at 11,689’ MD,
Fault #3 11,735' 48' DTW, Fault #5 14248’ 8’ DTW, Fault #6 14378’ MD 8’ DTW. 47 concretions for a total thickness of 221' (2.7% of the lateral). PB1 11,800' to
12,512' MD Total 732'. Footage NB Sand 6,600', Out of zone 1,702'. Total 8,302' Daily disposal to G&I: 513 bbl. Total disposal to G&I: 12584 bbl. Daily H2O f/ S-
Pad: 0 bbl. Total H2O S-Pad: 700 bbl. Daily H2O f/ A-Pad: 960bbl. Total H2O A-Pad: 11770 bbl. Daily Metal: 3 lbs. Total Metal: 43 lbs. Daily Fluid Loss: 453 bbl.
Surface Loss: 629 bbl.
9/15/2021 Continue circulating hole clean @ TD 14899' MD. Rot/Recip 115 rpm, 19k tq, 370 gpm, 1330 psi, 10.9 ECD's, 168k up, 35k dn, 99k rot. 13-16 bph dynamic loss
rate. PJSM, Displace 9.3 Baradril to 9.1 ppg lubricated brine (Quikdril) w/ 2.25% lubes. Pump 3x 40 bbls Sapp Pills with 20 bbl quikdril spacers between. Sapp
pills came back on time. Rot/Recip 370 gpm, 1080 psi, 110 rpm, 20k tq, 10.65 ECD's with max gas 66u. Monitor well (15 min to go static). Drop 2.38" steel drift.
BROOH F/ 14899' - T/ 14391' MD. Stage up to 430 gpm, 1190 psi, 80 rpm, 17.5k tq, 10.4 ECD's. 180k up, S/O N/A, ROT110k. Maximize pump rate keeping
returns at or above 90% (~40 BPH dynamic loss rate). 15-25 fpm pulling speed as hole allows. Cont. to BROOH from 14,391' to 12,547', 475 gpm, 1335 psi, 100
rpms, 15Kft-lbs, ECD 10.51 ppg EMW with 9.1 ppg MW. PUW 161K, SOW 49K, ROT 104K pulling 5-20 fpm as hole dictates. Dynamic loss rate ~40 BPH,
breathing back on connections. Cont. to BROOH from 12,547' to 10,850', 475 gpm, 1345 psi, 120 rpms, 11-13Kft-lbs, ECD 10.52 ppg EMW with 9.1 ppg MW.
max gas 261U. Pulling 15-20 fpm, slowing to 5-10 fpm at 11,400' due to TQ spikes and slight packoffs (out of zone 11420'-10,807') PUW 151K, SOW 58K, ROT
102K Dynamic loss rate ~40-50 BPH, breathing back on connections. Cont. to BROOH from 10,850' to 9040', 475 gpm, 1275 psi, 120 rpms, 10.5Kft-lbs, ECD
10.32 ppg EMW with 9.1 ppg MW. max gas 439U. Pulling 5-20 fpm as hole dictates. PUW 133K, SOW 71K, ROT 105K, dynamic loss rate 30-50 fpm breathing
back on connections. Daily disposal to G&I: 2091 bbl, Total disposal to G&I: 14675 bbl. Daily H2O f/ S-Pad: 0 bbl, Total H2O S-Pad: 700 bbl. Daily H2O f/ A-Pad:
390 bbl, Total H2O A-Pad: 12160 bbl. Daily Metal: 0 lbs, Total Metal: 43 lbs. Daily Fluid Loss: 257 bbl, Fluid Loss production zone: 886 bbl.
9/16/2021 Cont BROOH from 9040' to 7506' MD. , 475 gpm, 1275 psi, 120 rpms, 10.5Kft-lbs, ECD 10.32 ppg EMW with 9.1 ppg MW. max gas 439U. Pulling 5-20 fpm as
hole dictates. PUW 127K, SOW 81K, ROT 103K, dynamic loss rate 30-50 BPH breathing back on connections. 3k tq spikes, 100-150 psi psi spikes. Consistently
saw sand back at shakers while backreaming out. Periodically slowed pulling rate to 5 fpm over 3x stands to allow hole to clean up before continuing at normal pull
rate of ~25 fpm. Saw significant losses when seeing psi spikes (50% losses) 40 bbl loss for tour. Cont BROOH from 7506' to 6553' MD. , 475 gpm, 1140 psi, 120
rpms, 7.4Kft-lbs, ECD 9.9 ppg EMW with 9.1 ppg MW. max gas 320u. Pulling 5-15 fpm as hole dictates. PUW 125K, SOW 90K, ROT 105K, dynamic loss rate
15-20 BPH breathing back on connections. Worked tight hole F/ 6771' up to 6686' before hole cleaned up. Saw 3k tq spikes, 100-150 psi psi spikes with max
overpull 20k. Reduced rpm's to 40 when pulling jars and BHA thru shoe with no further issue. Circulate and Condition hole while rotating and reciprocating pipe @
6553' up to 6495' MD. 475 gpm, 1110 psi, 40 rpm, 7k tq, 9.89 ECD's, 92u Max Gas, P/U 130k, S/O 90k, ROT 105k. Pumped 42 bbl Hi Vis sweep (back on time
w/ 10% increase in cuttings). Lost 193 bbls for entire backreaming operation Perform passing "PST" w/ 250 coupons @ suction pit. Service traveling equipment.
Perform derrick inspection. Grease FH80 "Iron Roughneck". Monitor well (static). PJSM, Drain Stack. Pull RCD bearing and install trip nipple. Pump (corrosion
inhibited) dry job and B/D TDS. POOH laying down 5" drill pipe from 6,553' to 260'. PUW 46K, SOW 48K. Lost 13 bbls during trip from shoe. L/D BHA, retrieve
drift on top of float. Download MWD. Break Bit. Bit grade 2-2-BT-A-X-I-CT-TD. Clean and clear rig floor. Static loss rate 5 bph. R/U to RIH with 6-5/8", 20#, L-80
slotted liner. Rig up Weatherford handling equipment. Remove hydraulic elevators and install casing elevators. Service rig: grease blocks, inspect top drive and
floor equipment. Monitor well on trip tank, 3 bph loss rate. Daily disposal to G&I: 399 bbl, Total disposal to G&I: 15364 bbl. Daily H2O f/ S-Pad: 0 bbl, Total H2O S-
Pad: 700 bbl. Daily H2O f/ A-Pad: 700 bbl, Total H2O A-Pad: 12860 bbl. Daily Metal: 0 lbs, Total Metal: 43 lbs. Daily Fluid Loss: 124 bbl, Fluid Loss production
zone: 1010 bbl.
9/17/2021 M/U 6-5/8" eccentric blank AL slick shoe assy. RIH w/ 6-5/8" 563, 20#, L-80 Blank/Slotted liner assy to 6955' MD. 7.1k tq on connections. P/U 121k, S/O 73k.
12.2 bbl loss for tour. Continue RIH w/ 6-5/8" 563, 20#, L-80 Blank/Slotted liner assy F/ 6955' - T/ 8423' MD. M/U SLZXP T/ 8464'and pump thru 5 bpm, 225 psi.
7.1k tq on connections. P/U 137k, S/O 68k. 6.5 bbl loss for tour. Attempt rotation (no go) w/ max tq 6k. Clean exiting shoe and running in open hole. Continue
running 6-5/8" liner on 5" DP F/ 9464' - T/ 13768. Clean dn wt to 13520' MD. Clean up wt, work down with moderate effort with 16k set down to 13768' MD. RIH
with liner on 5" HWDP F/ 13768'-14899' MD. Tag on depth with 3K. P/U 223k, S/O 63k. Calc displacement 62.5 bbls, Act. 47.6 bbls, Set SLZXP as per Baker.
Drop 1.25" Phenolic ball, pick up to up wt. to put string in tension. Chase ball down at 3 bpm, 210 psi, slow to 1 bpm, 100 psi at 1300 strokes. Ball on seat at 1472
strokes. Pressure up to 2400 psi and hold for 15 minutes, observe indication of set at 2099 psi. Slack off to 35K. Cont. to pressure up, observe ball seat shear at
3550 psi. Pick up 1' and ensure released from SLZXP, PUW 155K. TOL at 6447' Shut UPR's, flood and purge choke and kill lines. PT SLZXP packer to 1500 psi
for 10 minutes, good. Pumped 2.1 bbls, bled back 2.1 bbls. Pick up 9' to expose packoff. L/D joint of HWDP. Break circulation at 3 bpm, 200 psi. Slowly pull out
of liner top to 6440'. Stage pumps up and circulate bottoms up at 10 bpm, 1200 psi. Monitor well, static. Pump 15 bbls corrosion inhibited dry job. Blow down top
drive, kill and choke lines. POOH laying down 5" HWDP from 6440' to 5430'. PUW 132K. Calc displacement 11.6 bbls, actual 13.1 bbls. Cont. POOH laying down
HWDP/DP from 5430' to surface, L/D running tool. Calculated displ 65, actual 177.7. 12.7 bbls lost. Service rig: grease/inspect crown sheaves. Service top drive
and check gear oil. Service iron roughneck. RIH with excess drill pipe from derrick to 3627'. PUW 96K, SOW 76K. Lost 3 bbls on trip. Swap to completions. Daily
disposal to G&I: 0 bbl, Total disposal to G&I: 15364 bbl. Daily H2O f/ S-Pad: 0 bbl, Total H2O S-Pad: 700 bbl. Daily H2O f/ A-Pad: 0 bbl, Total H2O A-Pad: 12860
bbl. Daily Metal: 0 lbs, Total Metal: 43 lbs. Daily Fluid Loss: 43 bbl, Fluid Loss production zone: 1053 bbl.
Activity Date Ops Summary
9/18/2021 Park @ 3605' MD. PJSM, Hang blocks. Cut and slip 69' drilling line. Re-install deadman and tq same. Inspect brakes. Calibrate drawworks. 2.5 BPH static loss
rate.,Pump corrosion inhibited dry job and B/D TDS. POOH F/ 3605' laying down 5" NC50 drill pipe. P/U 55k, S/O 56k. 7.6 bbl loss for trip. Remove wear
bushing.,206 jts 3-1/2" jts in shed. Mob 100 Cannon clamps to floor. R/U BOT tek wire spool. R/U WOT 3.5" power tongs and handling equipment. M/U XO
FOSV.,M/U Bullet seal assembly and RIH with 3-1/2" 8rd tubing as per tally to 675', M/U XN nipple, 1 joint and Baker G6 gauge carrier. Cont. to RIH with 3-1/2"
completion as per tally installing 1 cannon clamp every joint for 10 joints then every other joint. Test tech wire every 2000'.,Observed seals enter TOL with 3-4K
drag. No-Go on TOL at 6448.5' x2 with 10K down. Ran a total of 96 cannon clamps. PUW 72K, SOW53K. Calc displ 22.3 bbls, actual 5.4 bbls.,Space out 1.9' off
No-Go. L/D 3 joints, install 8.14' pup below last joint. M/U hanger and terminate gauge wire. Land hanger and verify landed. Close annular and pressure up to
250 psi, good. Strip OOH to located ports on bullet seal assembly, until pressure drops.,PJSM, Reverse circulate 290 bbls Corrosion inhibited 9.2 ppg brine @ 4
bpm, 190 ICP, FCP. Chase with 155 bbls diesel for freeze protect down IA @ 4 bpm, ICP, FCP. Strip in and land tubing. RILDS.,Rig up to test IA. Pull
mousehole and lower high pressure hose to cellar, r/u testing equipment.,Flood lines. PT IA to 2500 psi for 30 minutes - good, 4 bbls pumped 3.9 bbls
returned.,Install modified BPV. M/U stack washing tool. Flush BOP with hot soapy water. Flush choke manifold. Blow down surface lines and mud pumps.,Daily
disposal to G&I: 444 bbl, Total disposal to G&I: 15808 bbl. Daily H2O f/ S-Pad: 0 bbl, Total H2O S-Pad: 700 bbl. Daily H2O f/ A-Pad: 0 bbl, Total H2O A-Pad:
12860 bbl. Daily Metal: 0 lbs, Total Metal: 43 lbs. Daily Fluid Loss: 47 bbl, Fluid Loss production zone: 1100 bbl.
9/19/2021 PJSM, Bleed off accumulator and L/O - T/O for rig move. Demob split bushing from floor. Disconnect "Koomey" lines, N/D RCD clamp adn pull riser. Install RCD
test cap and tighten same. R/U and N/D RCD head from BOP stack. N/D choke and kill lines. Sym Ops - Inspect and prep both MP's for rig move. Offload pits and
clean same.,R/D MPD 3" hardlines. N/D spacer spool and DSA. N/D drip pan, lift and rack back BOP's on pedestal, 4 pt same to secure for move. Clean and prep
DSA.,Clean hanger neck and prep for tree adapter. Set adapter and 4 bolt tree flange. Test gauge tek wire (fail). Remove 4 bolt and hoist tree. Found "Tek wire"
had been pinched during tree install. Splice "Tek" wire and test (good). Re-install tree and 4 bolt. Test "Tek" wire (test good). Tighten flange on tree and perform
final check. Tested as follows: 1684.55 PSI. 1535.10 PSI. 71.4° F. 71.2° F,Sim Ops - Prep derrick. PJSM, Scope down derrick. Disconnect svc lines between
modules. Secure 5" pipe in shed.,Test tubing hanger void 500/5000 psi - good. Test tree 250/5000 psi - good. Pull CTS and modified BPV. Sim Ops: Clean mud
pits, vac unit and poor boy. Secure cellar.,Rig up LRS and pump 19 bbls diesel down tubing for freeze protect ICR 2 bpm, 40 ps, FCR 1.6 bpm, 500 psi. Rig down
LRS. Sim Ops: Clean mud pits, Start rigging down mezzanine interconnect.,Blow down steam and water systems. Rig down interconnects. Rig down and move
break shack and envirovac. Unplug and swap from Gen to cold start power at 21:00. Pick up stairs on outside of rig. Move cuttings box. Jack up and install jeep
on Gen mod.,Jack up and split rig modules apart and stage on pad for convoy. Rig released. Final Report for S-48.,Daily disposal to G&I: 1175 bbl, Total disposal
to G&I: 16983 bbl. Daily H2O f/ S-Pad: 0 bbl, Total H2O S-Pad: 700 bbl. Daily H2O f/ A-Pad: 170 bbl, Total H2O A-Pad: 13030 bbl. Daily Metal: 0 lbs, Total Metal:
43 lbs. Daily Fluid Loss: 0 bbl, Fluid Loss production zone: 1100 bbl.
Well Name:
Field:
County/State:
MP S-48
Milne Point
Hilcorp Energy Company Composite Report
, Alaska
50-029-23697-00-00API #:
TD Shoe Depth: PBTD:
No. Jts. Returned
RKB RKB to BHF RKB to THF
Jts.
2
3
99
62
X Yes No X Yes No 7.85
Fluid Description:
Liner hanger Info (Make/Model): Liner top Packer?: Yes No
Liner hanger test pressure:X Yes No
Centralizer Placement:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:Yes X No
Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job
Cement returns to surface? Yes X No Spacer returns?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:Yes No
Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job
Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Post Job Calculations:
Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped:
Cmt returned to surface: Calculated cement left in wellbore:
OH volume Calculated: OH volume actual: Actual % Washout:
Casing (Or Liner) Detail
Float Shoe
RKB
10 3/4
479.7 20386.7SECOND STAGEHES
Rotate Csg Recip Csg Ft. Min. PPG9.4
Shoe @ 6597 FC @ Top of Liner6,515.00
Floats Held
30 830.7
342 488.7
H20
CASING RECORD
County State Alaska Supv.J Lott / O Amend
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.MP S-48 Date Run 4-Sep-21
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
TCP BTC Antelope 1.60 6,597.00 6,595.40
26.50
Csg Wt. On Hook:270,000 Type Float Collar:Conventional No. Hrs to Run:14
8.34 6
0
10
10.7 446 4.6
100
355
Bump Plug?FIRST STAGE104# Red Dye & 5# Pol-E-Flak 70
15.8
306
3
8.34 5.3 20/20
20/0
20
2
15.8 82
Bump press
Circ cement off ES
Bump Plug?
Y
2,493
2493
6,597.006,607.00
CEMENTING REPORT
Csg Wt. On Slips:115,000
Spud Mud
4# Red Dye & 5# Pol-E-Flak
870 2.88
Stage Collar @
60
Bump press
100
322
ES Closure OK
57.7
12 245
26.72 RKB to CHF
Type of Shoe:Conventional Casing Crew:Weatherford
No. Jts. Delivered 187 No. Jts. Run 173 14
Length Measurements W/O Threads
Ftg. Delivered 7,480.00 Ftg. Run 6,597.00 Ftg. Returned 883.00
Ftg. Cut Jt.29.90 Ftg. Balance
www.wellez.net WellEz Information Management LLC ver_04818br
3.5
Arctic Cem
Type
Shoe Jnt 2 ea 10' F/ end, 1 ea 2 nd & 3rd jnt, 1 ea F/ jnt 4 to 27, every other jnt F/ 28 to 50, Every 3rd jnt F/ 53 to 95, 6
ffS / C // /
9.625 CSG 9 5/8 40.0 L-80 TCP BTC Tenaris 78.63 6,595.40 6,516.77
Float Collar 10 3/4 TCP BTC Antelope 1.32 6,516.77 6,515.45
9.625 CSG 9 5/8 40.0 L-80 TCP BTC Tenaris 38.36 6,515.45 6,477.09
Baffle Adapter 10 3/4 TCP BTC Halliburton 1.44 6,477.09 6,475.65
9.625 CSG 9 5/8 40.0 L-80 TCP BTC Tenaris 3,962.02 6,475.65 2,513.63
Pup 9 5/8 40.0 L-80 TCP BTC Tenaris 17.56 2,513.63 2,496.07
ES Cementer 11 3/4 TCP BTC Halliburton 2.82 2,496.07 2,493.25
Pup 9 5/8 40.0 L-80 TCP BTC Tenaris 17.83 2,493.25 2,475.42
9.625 CSG 9 5/8 47.0 L-80 TCP BTC Tenaris 2,449.52 2,475.42
ExtendCem 587 2.35
HalCem 400 1.15
5.4
SwiftCem 270 1.17
0
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Chelsea Wright Digitally signed by Chelsea
Wright
Date: 2021.09.15 10:36:08 -08'00'
Benjamin Hand Digitally signed by Benjamin Hand
Date: 2021.09.15 11:36:52 -08'00'
David Douglas Hilcorp Alaska, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal or fax to 907 564-4422.
Received By: Date:
Date: 10/01/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
MPU S-48 + MPU S-48PB1 (PTD 221-049)
FINAL EOW REPORT – GEOSTEERING LOGS (09/01/2021 to 09/15/2021)
SFTP Transfer - Data Folders:
Please include current contact information if different from above.
Received By:
10/04/2021
37'
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By Abby Bell at 10:37 am, Oct 04, 2021
David Douglas Hilcorp Alaska, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal or fax to 907 564-4422.
Received By: Date:
Date: 10/01/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
MPU S-48 + MPU S-48PB1 (PTD 221-049)
FINAL EOW REPORT – GEOSTEERING LOGS (09/01/2021 to 09/15/2021)
SFTP Transfer - Data Folders:
Please include current contact information if different from above.
Received By:
10/04/2021
37'
(6HW
By Abby Bell at 10:37 am, Oct 04, 2021
David Douglas Hilcorp Alaska, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal or fax to 907 564-4422.
Received By: Date:
Date: 10/01/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
MPU S-48 + MPU S-48PB1 (PTD 221-049)
FINAL LWD FORMATION EVALUATION LOGS (09/01/2021 to 09/15/2021)
x EWR-M5, AGR, ABG, DGR, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
SFTP Transfer – Main Folders:
Subfolders:
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Received By:
10/04/2021
37'
(6HW
By Abby Bell at 10:37 am, Oct 04, 2021
David Douglas Hilcorp Alaska, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal or fax to 907 564-4422.
Received By: Date:
Date: 10/01/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
MPU S-48 + MPU S-48PB1 (PTD 221-049)
FINAL LWD FORMATION EVALUATION LOGS (09/01/2021 to 09/15/2021)
x EWR-M5, AGR, ABG, DGR, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
SFTP Transfer – Main Folders:
Subfolders:
Please include current contact information if different from above.
Received By:
10/04/2021
37'
(6HW
By Abby Bell at 10:37 am, Oct 04, 2021
MEMORANDUM
TO: Jim Regg C e-(ZI
P.I. Supervisor �11�
FROM: Matt Herrera
Petroleum Inspector
Well Name MILNE PT UNIT S-48
Insp Num: mitMFH210925141357
Rel Insp Num:
NON -CONFIDENTIAL
State of Alaska
Alaska Oil and Gas Conservation Commission
DATE: Wednesday, September 29, 2021
SUBJECT: Mechanical Integrity Tests
Hilcorp Alaska, LLC
S-48
MILNE PT UNIT S48
Src: Inspector
Reviewed By:
P.I. Supry J�" 47
Comm
API Well Number 50-029-23697-00-00 Inspector Name: Matt Herrera
Permit Number: 221-049-0 Inspection Date: 9/25/2021
Notes: Initial MIT -IA performed to 2800 PSI per Operations (2500 PSI required per PTD). Monobore Completion No OA
Wednesday, September 29, 2021 Page 1 of 1
Packer
Depth
Pretest
Initial 15 Min 30 Min 45 Min 60 Min
Wel S-48
e n �'
-TypeJ
3879
Tubin g
637
638
r
637 - 637
PTD 2210490
T e Testi SPT ;Test S1
p
2500
IA
1 0
�
2822
2717 _ 2678
_
BBL Pumped:
5.3 - BBL Retrurned. '
5.2
OA
-
-
--
Interval
--- _
IIIITAL lP/F i
P
✓J
Notes: Initial MIT -IA performed to 2800 PSI per Operations (2500 PSI required per PTD). Monobore Completion No OA
Wednesday, September 29, 2021 Page 1 of 1
1
Guhl, Meredith D (CED)
From:Davies, Stephen F (CED)
Sent:Monday, September 13, 2021 12:35 PM
To:AOGCC Records (CED sponsored)
Subject:FW: PTD 221-049 Hilcorp Well MPU S-48: Plugback and sidetrack
Please file. Thanks.
From: Rixse, Melvin G (CED)
Sent: Monday, September 13, 2021 10:46 AM
To: Davies, Stephen F (CED) <steve.davies@alaska.gov>; Boyer, David L (CED) <david.boyer2@alaska.gov>
Subject: Fwd: PTD 221‐049 Hilcorp Well MPU S‐48: Plugback and sidetrack
Mel Rixse
Begin forwarded message:
From: Nathan Sperry <Nathan.Sperry@hilcorp.com>
Date: September 13, 2021 at 7:21:18 AM AKDT
To: "Rixse, Melvin G (CED)" <melvin.rixse@alaska.gov>
Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Subject: PTD 221‐049 Hilcorp Well MPU S‐48: Plugback and sidetrack
Good morning Mel,
Yesterday we crossed a fault and ended up high to the NB, in the NA. We climbed thinking the NB was
above us but quickly determined it was below us. We backed up and performed an open hole sidetrack
to drop to the NB.
PBTD 12,512’ MD
Sidetrack point 11,800’ MD.
Regards,
Nate Sperry
Drilling Engineer
Hilcorp Alaska, LLC
O: 907‐777‐8450
C: 907‐301‐8996
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
STATE OF ALASKA Reviewed By: L...1yT'
OIL AND GAS CONSERVATION COMMISSION P.I. Suprv.1 lcj
BOPE Test Report for: MILNE PT UNIT S-48 Comm
Contractor/Rig No.: Hilcorp Innovation
Operator: Hilcorp Alaska, LLC
Type Operation: DRILL Sundry No:
Type Test: INIT
PTD#: 2210490 - DATE: 9/8/2021
Operator Rep: Lott/Amend
Test Pressures:
Rams: Annular: Valves: MASP:
250/3000 - 250/3000 250/3000 - 1325
TEST DATA
Inspector Matt Herrera
Rig Rep: Evans/Sture
Insp Source
Inspector
Inspection No: bopMFH210908130632
Related Insp No:
MISC. INSPECTIONS:
MUD SYSTEM:
ACCUMULATOR SYSTEM:
CHOKE MANIFOLD:
P/F
P/F
Visual
Alarm
Time/Pressure
P/F
P/F
Location Gen.:
P
Trip Tank
_P
--P--
System Pressure
3000 _
_P
Housekeeping:
P
Pit Level Indicators
P
P
Pressure After Closure
1600
P
PTD On Location
P
Flow Indicator
P
P
200 PSI Attained
24
P
Standing Order Posted
P
Meth Gas Detector
P
-P -
Full Pressure Attained
-_ -84
_ P -
Well Sign
P -
H2S Gas Detector
P
---P__
Blind Switch Covers:
Yes
-P -
Drl. Rig
P -_
MS Misc
NA
_ -NA-
Nitgn. Bottles (avg):
6(&,2308
P_
Hazard Sec.
P -
NA-
ACC Misc
0
NA
Misc
NA
- _ --
-
NA _
INSIDE REEL VALVES:
FLOOR SAFTY VALVES:
BOP STACK:
CHOKE MANIFOLD:
Quantity
P/F
Quantity Size
P/F
Quantity
P/F
Upper Kelly
1 -
-P
Stripper
--0
-_
NA-
No. Valves 15
P
Lower Kelly
1 -_
P
Annular Preventer
1-=-13
5/8" _
-P
Manual Chokes 1
P
Ball Type
2 __
P
#1 Rams
_ 1
2 7/8 x 5 1/2
- P __-
Hydraulic Chokes 1
FP_
Inside BOP
1
P
#2 Rams
1
Blinds
P
CH Misc 0
NA
FSV Misc
0
NA
#3 Rams
1
2 7/8 x 51/2
FP
#4 Rams
NA-
#5 Rams
--0----
0
- _ --
-
NA _
INSIDE REEL VALVES:
#6 Rams
0
NA
(Valid for Coil Rigs Only)
Choke Ln. Valves
1
31/81
P
Quantity
P/F
HCR Valves
2
3 1/8"
P
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 4.5
Remarks: Two Test Joints utilized 3 1/2" and 5". LPR's Failed initially, functioned passed retest on 5" test joint. Hyd Choke initially failed
was functioned and passed retest. All Gas Alarms and PVT System es—
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 Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Re: Milne Point Field, Schrader Bluff Oil Pool, MPU S-48
Hilcorp Alaska
Permit to Drill Number: 221-049
Surface Location: 3171’FSL, 721 FEL, Sec. 12, T12N, R10E, UM, AK
Bottomhole Location: 2511’FNL, 2278’FWL, Sec. 2, T12N, R10E, UM, AK
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 July 2021.
Jeremy
Price
Digitally signed by
Jeremy Price
Date: 2021.07.21
14:50:31 -08'00'
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: 14,743' TVD: 4,069'
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:
1236'
4b. Location of Well (State Base Plane Coordinates - NAD 27): 10.KB Elevation above MSL (ft): 64.4'15.Distance to Nearest Well Open
Surface: x-565291 y- 5999834 Zone- 4 37.9' to Same Pool: 10'
16.Deviated wells: Kickoff depth: 300 feet 17.Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 92 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
Driven 20" 129.5# X-52 80' Surface Surface 110' 110'
47# L-80 TXP 2,500' Surface Surface 2,500' 1,924'
40# L-80 TXP 4,700' 2,500' 1,924' 7,200' 3,898'
8-1/2" 4-1/2" 13.5# L-80 Hyd 625 7,693' 7,050' 3,896' 14,743' 4,069'
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: Nathan Sperry
Monty Myers Contact Email:nathan.sperry@hilcorp.com
Drilling Manager Contact Phone:777-8450
Date:
Permit to Drill API Number: Permit Approval
Number: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:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
August 15, 2021
12-1/4" 9-5/8"
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):
Perforation Depth MD (ft):
Uncemented Screen Liner
Effect. Depth MD (ft): Effect. Depth TVD (ft):
Authorized Title:
Authorized Signature:
Production
Liner
Intermediate
Authorized Name:
Conductor/Structural
LengthCasing Cement Volume MDSize
Plugs (measured):
(including stage data)
Stg 1 L - 1505 ft3 / T - 458 ft3
2560
18. Casing Program: Top - Setting Depth - BottomSpecifications
1715
Total Depth MD (ft): Total Depth TVD (ft):
022224484
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
Stg 2 L - 1935 ft3 / T - 313 ft3
1325
1236' FSL, 82' FWL, Sec. 12, T12N, R10E, UM, AK
2511' FNL, 2278' FWL, Sec. 2, T12N, R10E, UM, AK
01-001
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
Hilcorp Alaska, LLC
3171' FSL, 721' FEL, Sec. 12, T12N, R10E, UM, AK ADL 380109
MPU S-48
Milne Point Field
Schrader Bluff Oil Pool
Cement Quantity, c.f. or sacks
Commission Use Only
See cover letter for other
requirements.
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
6.28.2021
By Meredith Guhl at 1:35 pm, Jun 28, 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: 2021.06.28 13:18:08 -08'00'
Monty M
Myers
MGR21JUL2021 DLB 06/29/2021
X
X
X
X
X
X
DSR-6/28/21
50-029-23697-00-00221-049
*BOPE test to 3000 psi. Annular to 2500 psi.
* Approved to remove 20' section of diverter while circulating
overbalance fluid at surface hole TD to move in cementing
equipment. Line to be replaced before cementing or tripping.
* 24 hour notice for AOGCC to witness MIT-IA to 2500 psi.
X
dts 7/21/2021 JLC 7/21/2021
7/21/2021
Jeremy Price Digitally signed by Jeremy Price
Date: 2021.07.21 14:50:46 -08'00'
Area of Review MPS-48PTDAPIWELL STATUSTop of SBNB (MD)Top of SBNB (TVD)Top ofCement(MD)Top ofCement(TVD)Schrader NBstatusZonal Isolation195-198 50-029-22597-00-00 MPU H-07 P&A'd 8,200' 4,069' Surface Surface ClosedP&A'd202-024 50-029-22597-01-00 MPU H-07A OB Producer 8,209' 4,071' Surface Surface ClosedCement to Surface202-024 50-029-22597-70-00 MPU H-07APB1 Plugback 8,209' 4,071' Surface Surface ClosedPlugback - Cemented202-028 50-029-22597-60-00 MPU H-07AL1 OA Producer 8,209' 4,071' Surface Surface ClosedCement to Surface202-028 50-029-22597-71-00 MPU H-07AL1PB1 Plugback 8,209' 4,071' Surface Surface ClosedPlugback - Cemented202-028 50-029-22597-72-00 MPU H-07AL1PB2 Plugback 8,209' 4,071' Surface Surface ClosedPlugback - Cemented203-143 50-029-23175-00-00 MPU S-35 NB Producer 10,699' 4,082 N/A N/A OpenOpen to Injection Support203-143 50-029-23175-70-00 MPU S-35PB1 Plugback 10,699' 4,082' N/A N/A ClosedPlugback - Cemented203-143 50-029-23175-71-00 MPU S-35PB2 Plugback 10,699' 4,082' N/A N/A ClosedPlugback - Cemented202-014 50-029-23066-00-00 MPU S-31 NB / OA / OB Injector 7,673' 3,912' Surface Surface OpenOpen to Injection Support203-130 50-029-23171-00-00 MPU S-34 Not Producing 9,939' 4,063' 7,461' 3,414' ClosedNot Open to Producing - 7-5/8"casing ran to 11,159' MD andcement top calculated at 7,461'203-132 50-029-23171-60-00 MPU S-34L1 OA Producer 9,939' 4,063' 7,461' 3,414' Closed7-5/8" casing ran to 11,159' MD andcement top calculated at 7,461203-144 50-029-23171-61-00 MPU S-34L2 NE Producer 9,939' 4,063' 7,461' 3,414' Closed7-5/8" casing ran to 11,159' MD andcement top calculated at 7,461TBD TBD MPU S-47 NB Producer (not drilled) ~6,200' ~3,918' N/A N/A TBD - OpenOpen to Injection Support onceDrilled
Milne Point Unit
(MPU) S-48
Drilling Program
Version 1
6/24/2021
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 ................................................................................................ 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 ...................................................................................................... 16
13.0 Cement 9-5/8” Surface Casing ................................................................................................. 22
14.0 NU BOP and Test..................................................................................................................... 27
15.0 Drill 8-1/2” Hole Section .......................................................................................................... 28
16.0 Run 4-1/2” Injection Liner (Lower Completion) .................................................................... 33
17.0 Run 3-1/2” Tubing (Upper Completion) ................................................................................. 37
18.0 Innovation Rig Diverter Schematic ......................................................................................... 39
19.0 Innovation Rig BOP Schematic ............................................................................................... 40
20.0 Wellhead Schematic ................................................................................................................. 41
21.0 Days Vs Depth .......................................................................................................................... 42
22.0 Formation Tops & Information............................................................................................... 43
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
Page 2
Milne Point Unit
S-48 SB Injector
Drilling Procedure
1.0 Well Summary
Well MPU S-48
Pad Milne Point “S” Pad
Planned Completion Type 3-1/2” Injection Tubing
Target Reservoir(s) Schrader Bluff Nb Sand
Planned Well TD, MD / TVD 14,743’ MD / 4,069’ TVD
PBTD, MD / TVD 14,743’ MD / 4,069’ TVD
Surface Location (Governmental) 2108' FNL, 721' FEL, Sec 12, T12N, R10E, UM, AK
Surface Location (NAD 27) X= 565,291 Y=5,999,834
Top of Productive Horizon
(Governmental)1236' FSL, 82' FWL, Sec 12, T12N, R10E, UM, AK
TPH Location (NAD 27) X= 560,831 Y=5,997,861
BHL (Governmental) 2511' FNL, 2278' FWL, Sec 2, T12N, R10E, UM, AK
BHL (NAD 27) X= 557,688 Y=6,004,649
AFE Number
AFE Drilling Days 17 days
AFE Completion Days 3 days
AFE Drilling Amount
AFE Completion Amount
AFE Facility Amount
Maximum Anticipated Pressure
(Surface) 1,325 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 1,715 psig
Work String 5”, 19.5#, S-135, DS-50 & NC 50
KB Elevation above MSL: 26.5 ft + 37.9 ft = 64.4 ft
GL Elevation above MSL: 37.9 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
Page 3
Milne Point Unit
S-48 SB Injector
Drilling Procedure
2.0 Management of Change Information
Page 4
Milne Point Unit
S-48 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”40.0 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”2.867”4.500”9.3 L-80
EUE 8 RD 10,160 10,535 207
4.0 Drill Pipe Information:
Hole
Section
OD
(in)
ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn M/U
(Min)
M/U
(Max)
Tension
(k-lbs)
Surface &
Production
5”4.276” 3.25” 6.625” 19.5 S-135 GPDS50 36,100 43,100 560klb
5”4.276”3.25” 6.625”19.5 S-135 NC50 31,032 34,136 560klb
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
Page 5
Milne Point Unit
S-48 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 David Gorm 907.777.8333 505.215.2819 dgorm@hilcorp.com
Geologist John Salsbury 907.777.8481 907.350.1088 jsalsbury@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
Milne Point Unit
S-48 SB Injector
Drilling Procedure
6.0 Planned Wellbore Schematic
Page 7
Milne Point Unit
S-48 SB Injector
Drilling Procedure
7.0 Drilling / Completion Summary
MPU S-48 is a grassroots injector planned to be drilled in the Schrader Bluff Nb sand. S-48 is part of a multi
well program targeting the Schrader Bluff sand on S-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 Nb 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 August 15th, 2021, pending rig schedule.
Surface casing will be run to 7,200’ MD / 3,898’ 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)
Page 8
Milne Point Unit
S-48 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 S-48. 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
Abhijeet.tambe@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 requests a variance to remove a 20’ section of vent line after drilling and running 9-5/8” casing
to surface TD. The section would be removed after circulating a minimum of 1.5X BU in order to move
cement equipment to the west side of the pad. The section will be re-installed prior to cementing.
While the section is removed, we will continue to pump at minimum rate. At no time will underbalanced
fluids be pumped into the well while the section is removed.
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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
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 S-48 will utilize a newly set 20” conductor on S-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.
24 hour notice to AOGCC.
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10.4 Rig & Diverter Orientation:
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11.0 Drill 12-1/4” Hole Section
11.1 PU 12-1/4” directional drilling assembly:
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 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, 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.
x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in
conductor.
11.3 Drill 12-1/4” hole section to TD
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 GWD surveys until MWD surveys are clean. Take MWD surveys every stand
drilled as well.
x Gas hydrates may be present on S-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
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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 no wells with a clearance factor < 1.0
11.4 12-1/4” hole mud program summary:
x Density: Weighting material to be used for the hole section will be barite. Additional
barite or spike fluid will be on location to weight up the active system (1) ppg above
highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and
TD with 9.2+ ppg.
Depth Interval MW (ppg)
Surface – Base Permafrost 8.9+
Base Permafrost - TD 9.2+
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 – 9.2 ppg Pre-Hydrated Aquagel/freshwater spud mud
Properties:
Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp
Surface 8.8 –9.8 75-175 20 - 40 25-45 <10 8.5 –9.0 70 F
Note: 8.46 ppg minimum EMW needed. DLB
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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
11.5 At TD, CBU and condition the mud until the hole is clean while BROOH. Rack back stands but
do not trip to bottom until the hole is clean.
11.6 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, as dictated by hole conditions
x Monitor well for any signs of packing off or losses.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay
balling.
x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until
parameters are restored.
11.7 TOOH and LD BHA
11.8 No open hole logging program planned.
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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
2500'
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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 (roughly ~ 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/joint
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.
2500'
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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.
Estimated 1st Stage Total Cement Volume:
640.3 sx
394 sx
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Cement Slurry Design (1st Stage Cement Job):
13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue
with the cement job.
13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of
mud pits, spotting water across the HEC stage cementer.
x Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
13.10 Ensure rig pump is used to displace cement. 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:
2,500’ x 0.0732 BPF + (7,200’ – 120’ - 2,500’) x 0.0758 BPF = 493.7 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.
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.
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
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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 2
nd stage as necessary. Circulate until first stage reaches sufficient compressive
strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre-job safety
meeting.
x Past wells have seen pressure increase while circulating through stage tool after reduced rate
13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing
head.
13.20 Fill surface lines with water and pressure test.
13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.22 Mix and pump cmt per below recipe for the 2
nd stage.
13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail).
Job will consist of lead & tail, TOC brought to surface. However cement will continue to be
pumped until clean spacer is observed at surface.
Estimated 2nd Stage Total Cement Volume:
Cement Slurry Design (2nd stage cement job):
13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail.
13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out
of mud pits.
13.26 Displacement calculation:
2,500’ x 0.0732 bpf = 183.0 bbls mud
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
268 sx
439 sx
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13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side
outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out
fluid from cellar. Have black water available to retard setting of cement.
13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should
circulate approximately 100 - 200 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.
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14.0 NU BOP 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.
24 hour notice to AOGCC
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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. Pump at least one high vis sweep at maximum rate to surface to
clean up debris.
15.7 Conduct FIT to 12.0 ppg EMW. Chart test. Ensure test is recorded on same chart as FIT.
Document incremental volume pumped (and subsequent pressure) and volume returned.
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.
Casing test and FIT digital data to AOGCC for review.
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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
15.12 Displace wellbore to 8.9 ppg Baradrill-N drilling fluid
Note: 8.46 ppg EMW needed. DLB
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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 Schrader Bluff Nb Concretions: 4-6% of lateral
x A/C, wells with < 1.0 clearance factor:
x S-32 has a clearance factor of 0.092. S-32 is a Schrader water injector that is P&A’d.
x S-35 has a clearance factor of 0.041. S-35 is a Schrader producer that is scheduled to be
P&A’d.
15.15 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons
learned and best practices. Ensure the DD is referencing their procedure.
x Patience is key! Getting kicked off too quickly might have been the cause of failed liner
runs on past wells.
x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so
we have a nice place to low side.
x Attempt to 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.
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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 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.
Assure continued overbalance to reservoir pressure.
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15.22 Monitor well for flow / pressure build up with MPD. Increase fluid 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
15.23 POOH laying down DP. Only rack back the length needed to run the liner.
15.24 Continue to POOH and LD BHA. 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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16.0 Run 4-1/2” Injection Liner (Lower Completion)
16.1. Confirm VBR’s have been tested on 3-1/2” and 5” test joints to 250/3,000 psi.
16.2.Well control preparedness: In the event of an influx of formation fluids while running the 4-
1/2” production screens, the following well control response procedure will be followed:
x 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” screen.
x Slack off and position the 5” DP across the BOP, shut in ram or annular on 5” DP. Close
TIW valve.
x Proceed with well kill operations.
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” screen injection liner – Reference screen handling and running procedure.
x Use Best O Life 2000 AG thread compound. Dope pin end only with paint brush. Wipe off
excess. Thread compound will plug the screens.
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Run packoff and float shoe on bottom.
x 4-1/2” Screens should auto–fill, top off with completion brine if needed
x Swell packers will not be required on this completion unless the well is drilled out of zone
x If needed, install swell packers as per the lower completion tally.
x Remove protective packaging on swell packers just prior to picking up
x Do not place tongs or slips on the packer element
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.
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.
16.9. Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner
hanger to ensure a clear flow path exists.
16.10. RIH with liner no faster than 30 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. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe
depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to
bottom.
16.12. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
& 20 RPM.
16.13. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
16.14. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
16.15. Rig up to pump down the work string with the rig pumps.
16.16. Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed
1,600 psi while circulating.Pusher tool is set at 2,100 psi with 5% shear screws but it should be
discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker.
16.17. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill
pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger.
16.18. Shut down pumps. Drop setting ball (ball seat now located in HRDE setting tool and not at the
WIV) down the workstring and pump slowly (1-2 BPM). Slow pump before the ball seats. Do
not allow ball to slam into ball seat.
16.19. Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes.
Slack off 20K lbs on the ZXP to ensure the HRDE setting tool is in compression for release from
the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi to neutralize and release
running tools.
16.20. 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.
16.21. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted.
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16.22. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If
packer did not test, rotating dog sub can be used to set packer. If running tool cannot be
hydraulically released, apply LH torque to mechanically release the setting tool.
16.23. POOH laying down DP/HWDP. LD and inspect the liner running tools.
Once running tools are LD, swap to the Completion AFE.
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17.0 Run 3-1/2” Tubing (Upper Completion)
17.1 Notify the AOGCC at least 24 hours in advance of the IA pressure test after running the
completion as per 20 AAC 25.412 (e). Record pressure test on 10-426 form and email to
abhijeet.tambe@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.
Monitor and assure well
is overbalanced to res-
ervoir pressure.
24 hour notice.
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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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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 S-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:
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.
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Drilling Procedure
H2S:
Treat every hole section as though it has the potential for H2S. MPU S-pad is not known for H2S.
Three samples containing H2S have been captured. S-08 had 50 ppm measured in 2012. S-12 had 28.9
ppm measured in 2012. S-39 had 2 ppm measured in 2014.
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 one mapped fault crossing. If an unmapped fault is crossed, we’ll need to either drill up or
down to get a look at the LWD log and determine the throw and then replan the wellbore.
H2S:
Treat every hole section as though it has the potential for H2S. MPU S-pad is not known for H2S.
Three samples containing H2S have been captured. S-08 had 50 ppm measured in 2012. S-12 had 28.9
ppm measured in 2012. S-39 had 2 ppm measured in 2014.
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 can be seen on S-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 S-32 has a clearance factor of 0.092. S-32 is a Schrader water injector that is P&A’d.
x S-35 has a clearance factor of 0.041. S-35 is a Schrader producer that is scheduled to be
P&A’d.
Abnormal Pressures and Temperatures:NOTE DLB
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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.
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26.0 Innovation Rig Choke Manifold Schematic
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27.0 Casing Design
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28.0 8-1/2” Hole Section MASP
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29.0 Spider Plot (NAD 27) (Governmental Sections)
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30.0 Surface Plat (As Built) (NAD 27)
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10500
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11500
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12500
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14743MPU S-48i wp05Start Dir 3º/100' : 250' MD, 250'TVDStart Dir 4º/100' : 550' MD, 548.77'TVDEnd Dir : 1817.37' MD, 1570.54' TVDStart Dir 4º/100' : 5106.83' MD, 3275.01'TVDEnd Dir : 6852.85' MD, 3880.33' TVDStart Dir 4º/100' : 7002.85' MD, 3893.4'TVDEnd Dir : 7136.56' MD, 3898.82' TVDStart Dir 2º/100' : 7732.83' MD, 3895.2'TVDEnd Dir : 9742.03' MD, 3881.07' TVDStart Dir 2º/100' : 9858.97' MD, 3877.4'TVDEnd Dir : 10030.91' MD, 3877.02' TVDStart Dir 2º/100' : 11070.4' MD, 3905.03'TVDEnd Dir : 11467.36' MD, 3943.11' TVDStart Dir 2º/100' : 11567.28' MD, 3959.55'TVDEnd Dir : 11967.8' MD, 3997.73' TVDTotal Depth : 14742.8' MD, 4069.4' TVDBPRFUG3 CoalUG2 CoalLA3LA1UG MAUG MBUG MCUG MDUG MESB NASB_NB (target)Hilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: MPU S-48i37.90+N/-S+E/-WNorthingEastingLatitudeLongitude0.000.005999834.28565290.67 70° 24' 36.006 N 149° 28' 6.112 WSURVEY PROGRAMDate: 2021-02-04T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool26.50 650.00 MPU S-48i wp05 (MPU S-48i) 3_Gyro-MWD90+Sag650.00 7200.00 MPU S-48i wp05 (MPU S-48i) 3_MWD+IFR2+MS+Sag7200.00 14742.80 MPU S-48i wp05 (MPU S-48i) 3_MWD+IFR2+MS+SagFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation1866.69 1802.29 2388.91 BPRF2858.78 2794.38 4303.55 UG3 Coal3093.11 3028.71 4755.78 UG2 Coal3409.03 3344.63 5371.57 LA33493.98 3429.58 5549.16 LA13658.06 3593.66 5935.30 UG MA3721.47 3657.07 6112.88 UG MB3728.29 3663.89 6133.56 UG MC3747.07 3682.67 6192.61 UG MD3814.72 3750.32 6442.61 UG ME3887.05 3822.65 6929.99 SB NA3893.03 3828.63 6998.60 SB_NB (target)REFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU S-48i, True NorthVertical (TVD) Reference:MPU S-48 AS-built @ 64.40usftMeasured Depth Reference:MPU S-48 AS-built @ 64.40usftCalculation Method: Minimum CurvatureProject:Milne PointSite:M Pt S PadWell:Plan: MPU S-48iWellbore:MPU S-48iDesign:MPU S-48i wp05CASING DETAILSTVD TVDSS MD SizeName3898.44 3834.04 7200.00 9-5/8 9 5/8" x 12 1/4"4069.40 4005.00 14742.80 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 0.002 250.00 0.00 0.00 250.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 250' MD, 250'TVD3 550.00 9.00 210.00 548.77 -20.36 -11.76 3.00 210.00 -11.76 Start Dir 4º/100' : 550' MD, 548.77'TVD4 1817.37 58.79 234.58 1570.54 -448.65 -537.75 4.00 27.37 -119.67 End Dir : 1817.37' MD, 1570.54' TVD5 5106.83 58.79 234.58 3275.01 -2079.31 -2830.42 0.00 0.00 -385.52 Start Dir 4º/100' : 5106.83' MD, 3275.01'TVD6 6852.85 85.00 304.00 3880.33 -2017.96 -4353.29 4.00 83.46 429.04 End Dir : 6852.85' MD, 3880.33' TVD7 7002.85 85.00 304.00 3893.40 -1934.40 -4477.18 0.00 0.00 563.35 MPU S-48 wp05 heel Start Dir 4º/100' : 7002.85' MD, 3893.4'TVD8 7136.56 90.35 304.02 3898.82 -1859.70 -4587.88 4.00 0.21 683.39 End Dir : 7136.56' MD, 3898.82' TVD9 7732.83 90.35 304.02 3895.20 -1526.11 -5082.10 0.00 0.00 1219.40 Start Dir 2º/100' : 7732.83' MD, 3895.2'TVD10 8037.32 89.20 310.00 3896.40 -1342.91 -5325.12 2.00 100.87 1499.56 MPU S-48 wp04 cp111 9742.03 91.80 344.00 3881.07 65.66 -6239.99 2.00 85.60 3176.86 End Dir : 9742.03' MD, 3881.07' TVD12 9858.97 91.80 344.00 3877.40 178.02 -6272.21 0.00 0.00 3290.27 MPU S-48 wp04 cp2 Start Dir 2º/100' : 9858.97' MD, 3877.4'TVD13 10030.91 88.46 344.80 3877.02 343.60 -6318.44 2.00166.53 3456.79 End Dir : 10030.91' MD, 3877.02' TVD14 11070.40 88.46 344.80 3905.03 1346.36 -6590.88 0.00 0.00 4461.42 Start Dir 2º/100' : 11070.4' MD, 3905.03'TVD15 11243.19 85.00 344.80 3914.89 1512.81 -6636.10 2.00-179.994628.18 MPU S-48 wp04 cp316 11467.36 80.53 345.17 3943.11 1727.54 -6693.71 2.00175.354842.95 End Dir : 11467.36' MD, 3943.11' TVD17 11567.28 80.53 345.17 3959.55 1822.81 -6718.94 0.00 0.00 4938.07 Start Dir 2º/100' : 11567.28' MD, 3959.55'TVD18 11967.80 88.52 344.57 3997.73 2207.38 -6822.94 2.00 -4.29 5323.11 End Dir : 11967.8' MD, 3997.73' TVD19 14742.80 88.52 344.57 4069.40 4881.46 -7561.01 0.00 0.00 8007.97 MPU S-48 wp04 toe Total Depth : 14742.8' MD, 4069.4' TVD
-2200-1650-1100-550055011001650220027503300385044004950South(-)/North(+) (1100 usft/in)-8800 -8250 -7700 -7150 -6600 -6050 -5500 -4950 -4400 -3850 -3300 -2750 -2200 -1650 -1100 -550 0 550 1100West(-)/East(+) (1100 usft/in)MPU S-48 wp04 toeMPU S-48 wp04 cp3MPU S-48 wp04 cp2MPU S-48 wp04 cp1MPU S-48 wp05 heel9 5/8" x 12 1/4"4 1/2" x 8 1/2"75012501500
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375040004069MPU S-48i wp05Start Dir 3º/100' : 250' MD, 250'TVDStart Dir 4º/100' : 550' MD, 548.77'TVDEnd Dir : 1817.37' MD, 1570.54' TVDStart Dir 4º/100' : 5106.83' MD, 3275.01'TVDEnd Dir : 6852.85' MD, 3880.33' TVDStart Dir 4º/100' : 7002.85' MD, 3893.4'TVDEnd Dir : 7136.56' MD, 3898.82' TVDStart Dir 2º/100' : 7732.83' MD, 3895.2'TVDEnd Dir : 9742.03' MD, 3881.07' TVDStart Dir 2º/100' : 9858.97' MD, 3877.4'TVDEnd Dir : 10030.91' MD, 3877.02' TVDStart Dir 2º/100' : 11070.4' MD, 3905.03'TVDEnd Dir : 11467.36' MD, 3943.11' TVDStart Dir 2º/100' : 11567.28' MD, 3959.55'TVDEnd Dir : 11967.8' MD, 3997.73' TVDTotal Depth : 14742.8' MD, 4069.4' TVDCASING DETAILSTVDTVDSS MDSize Name3898.44 3834.04 7200.00 9-5/8 9 5/8" x 12 1/4"4069.40 4005.00 14742.80 4-1/2 4 1/2" x 8 1/2"Project: Milne PointSite: M Pt S PadWell: Plan: MPU S-48iWellbore: MPU S-48iPlan: MPU S-48i wp05WELL DETAILS: Plan: MPU S-48i37.90+N/-S+E/-WNorthingEastingLatitude Longitude0.000.005999834.28 565290.6770° 24' 36.006 N149° 28' 6.112 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU S-48i, True NorthVertical (TVD) Reference: MPU S-48 AS-built @ 64.40usftMeasured Depth Reference:MPU S-48 AS-built @ 64.40usftCalculation Method:Minimum Curvature
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0.001.002.003.004.00Separation Factor0 375 750 1125 1500 1875 2250 2625 3000 3375 3750 4125 4500 4875 5250 5625 6000 6375 6750 7125Measured Depth (750 usft/in)No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: MPU S-48i NAD 1927 (NADCON CONUS)Alaska Zone 0437.90+N/-S +E/-W Northing EastingLatitudeLongitude0.000.005999834.28565290.6770° 24' 36.006 N149° 28' 6.112 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU S-48i, True NorthVertical (TVD) Reference:MPU S-48 AS-built @ 64.40usftMeasured Depth Reference:MPU S-48 AS-built @ 64.40usftCalculation Method: Minimum CurvatureSURVEY PROGRAMDate: 2021-02-04T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.50 650.00 MPU S-48i wp05 (MPU S-48i) 3_Gyro-MWD90+Sag650.00 7200.00 MPU S-48i wp05 (MPU S-48i) 3_MWD+IFR2+MS+Sag7200.00 14742.80 MPU S-48i wp05 (MPU S-48i) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0375 750 1125 1500 1875 2250 2625 3000 3375 3750 4125 4500 4875 5250 5625 6000 6375 6750 7125Measured Depth (750 usft/in)MPS-43MPU S-45MPU S-201 wp07MPU S-46i wp08MPU S-47 wp07MPU S-44iMPU S-44i wp06GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference26.50 To 14742.80Project: Milne PointSite: M Pt S PadWell: Plan: MPU S-48iWellbore: MPU S-48iPlan: MPU S-48i wp05Ladder / S.F. Plots1 of 2CASING DETAILSTVD TVDSS MD Size Name3898.44 3834.04 7200.00 9-5/8 9 5/8" x 12 1/4"4069.40 4005.00 14742.80 4-1/2 4 1/2" x 8 1/2"
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0LOQH3RLQW+LOFRUS$ODVND//&$QWLFROOLVLRQ5HSRUWIRU3ODQ 0386L0386LZS&OHDUDQFH)DFWRU3ORW 0HDVXUHG'HSWKYHUVXV6HSDUDWLRQ &OHDUDQFH )DFWRU0.001.252.503.755.006.257.508.7510.00Separation Factor (2.50 /in)0 1250 2500 3750 5000 6250 7500 8750 10000 1125012500 13750 15000Measured Depth (2500 usft/in)No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSMPH-07, MPH-07APB1, MPH-07APB1 V25MPH-09, MPH-09, MPH-09 V3MPH-11, MPH-11, MPH-11 V6MPH-17, MPH-17, MPH-17 V6MPS-21, MPS-21, MPS-21 V19MPS-22, MPS-22, MPS-22 V8MPS-24, MPS-24, MPS-24 V3MPS-25, MPS-25, MPS-25 V3MPS-25, MPS-25L1, MPS-25L1 V10MPS-27, MPS-27, MPS-27 V9MPS-27, MPS-27L1, MPS-27L1 V7MPS-31, MPS-31, MPS-31 V8MPS-32, MPS-32, MPS-32 V5MPS-34, MPS-34, MPS-34 V9MPS-34, MPS-34L1, MPS-34L1 V1MPS-34, MPS-34L2, MPS-34L2 V9MPS-35, MPS-35, MPS-35 V17MPS-35, MPS-35PB1, MPS-35PB1 V16MPS-35, MPS-35PB2, MPS-35PB2 V16MPS-41, MPS-41, MPS-41 V7MPS-41, MPS-41A, MPS-41A V5MPS-41, MPS-41APB1, MPS-41APB1 V11MPS-41, MPS-41APB2, MPS-41APB2 V2MPS-43, MPS-43, MPS-43 V3MPU S-203, MPU S-203, MPU S-203 V0MPU S-203, MPU S-203PB1, MPU S-203PB1 V0MPU S-203, MPU S-203PB2, MPU S-203PB2 V0MPU S-45, MPU S-45, MPU S-45 V0MPUS 56i MPUS 56PB1 MPUS 56PB1V0-XQH &203$663DJHRI
0LOQH3RLQW+LOFRUS$ODVND//&$QWLFROOLVLRQ5HSRUWIRU3ODQ 0386L0386LZS&RRUGLQDWH6\VWHPLV866WDWH3ODQH ([DFWVROXWLRQ $ODVND=RQH&HQWUDO0HULGLDQLV*ULG&RQYHUJHQFHDW6XUIDFHLV 9HUWLFDO'HSWKVDUHUHODWLYHWR0386$6EXLOW#XVIW1RUWKLQJDQG(DVWLQJDUHUHODWLYHWR3ODQ 0386L050010001500Centre to Centre Separation (500 usft/in)0 1500 3000 4500 6000 7500Measured Depth (1500 usft/in)Ladder Plot,,MPH-07, MPH-07APB1, MPH-07APB1 V25MPH-09, MPH-09, MPH-09 V3MPH-11, MPH-11, MPH-11 V6MPH-17, MPH-17, MPH-17 V6MPS-21, MPS-21, MPS-21 V19MPS-22, MPS-22, MPS-22 V8MPS-24, MPS-24, MPS-24 V3MPS-25, MPS-25, MPS-25 V3MPS-25, MPS-25L1, MPS-25L1 V10MPS-27, MPS-27, MPS-27 V9MPS-27, MPS-27L1, MPS-27L1 V7MPS-31, MPS-31, MPS-31 V8MPS-32, MPS-32, MPS-32 V5MPS-34, MPS-34, MPS-34 V9MPS-34, MPS-34L1, MPS-34L1 V1MPS-34, MPS-34L2, MPS-34L2 V9MPS-35, MPS-35, MPS-35 V17MPS-35, MPS-35PB1, MPS-35PB1 V16MPS-35, MPS-35PB2, MPS-35PB2 V16MPS-41, MPS-41, MPS-41 V7MPS-41, MPS-41A, MPS-41A V5MPS-41, MPS-41APB1, MPS-41APB1 V11MPS-41, MPS-41APB2, MPS-41APB2 V2MPS-43, MPS-43, MPS-43 V3MPU S-203, MPU S-203, MPU S-203 V0MPU S-203, MPU S-203PB1, MPU S-203PB1 V0MPU S-203, MPU S-203PB2, MPU S-203PB2 V0MPU S-45, MPU S-45, MPU S-45 V0MPU S 56i MPUS 56PB1 MPUS 56PB1V0'LUHFWLRQDQG&RRUGLQDWHVDUHUHODWLYHWR7UXH1RUWK5HIHUHQFH-XQH &203$663DJHRI
0LOQH3RLQW+LOFRUS$ODVND//&$QWLFROOLVLRQ5HSRUWIRU3ODQ 0386L0386LZS&OHDUDQFH)DFWRU3ORW 0HDVXUHG'HSWKYHUVXV6HSDUDWLRQ &OHDUDQFH )DFWRU0.001.252.503.755.006.257.508.7510.00Separation Factor (2.50 /in)0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000Measured Depth (1500 usft/in)No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSMPH-07, MPH-07APB1, MPH-07APB1 V25MPH-09, MPH-09, MPH-09 V3MPH-11, MPH-11, MPH-11 V6MPH-17, MPH-17, MPH-17 V6MPS-21, MPS-21, MPS-21 V19MPS-22, MPS-22, MPS-22 V8MPS-24, MPS-24, MPS-24 V3MPS-25, MPS-25, MPS-25 V3MPS-25, MPS-25L1, MPS-25L1 V10MPS-27, MPS-27, MPS-27 V9MPS-27, MPS-27L1, MPS-27L1 V7MPS-31, MPS-31, MPS-31 V8MPS-32, MPS-32, MPS-32 V5MPS-34, MPS-34, MPS-34 V9MPS-34, MPS-34L1, MPS-34L1 V1MPS-34, MPS-34L2, MPS-34L2 V9MPS-35, MPS-35, MPS-35 V17MPS-35, MPS-35PB1, MPS-35PB1 V16MPS-35, MPS-35PB2, MPS-35PB2 V16MPS-41, MPS-41, MPS-41 V7MPS-41, MPS-41A, MPS-41A V5MPS-41, MPS-41APB1, MPS-41APB1 V11MPS-41, MPS-41APB2, MPS-41APB2 V2MPS-43, MPS-43, MPS-43 V3MPU S-203, MPU S-203, MPU S-203 V0MPU S-203, MPU S-203PB1, MPU S-203PB1 V0MPU S-203, MPU S-203PB2, MPU S-203PB2 V0MPU S-45, MPU S-45, MPU S-45 V0MPUS 56i MPUS 56PB1 MPUS 56PB1V0-XQH &203$663DJHRI
0.001.002.003.004.00Separation Factor7200 7600 8000 8400 8800 9200 9600 10000 10400 10800 11200 11600 12000 12400 12800 13200 13600 14000 14400 14800Measured Depth (800 usft/in)No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: MPU S-48i NAD 1927 (NADCON CONUS)Alaska Zone 0437.90+N/-S +E/-W Northing EastingLatitudeLongitude0.000.005999834.28565290.6770° 24' 36.006 N149° 28' 6.112 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU S-48i, True NorthVertical (TVD) Reference:MPU S-48 AS-built @ 64.40usftMeasured Depth Reference:MPU S-48 AS-built @ 64.40usftCalculation Method: Minimum CurvatureSURVEY PROGRAMDate: 2021-02-04T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.50 650.00 MPU S-48i wp05 (MPU S-48i) 3_Gyro-MWD90+Sag650.00 7200.00 MPU S-48i wp05 (MPU S-48i) 3_MWD+IFR2+MS+Sag7200.00 14742.80 MPU S-48i wp05 (MPU S-48i) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)7200 7600 8000 8400 8800 9200 9600 10000 10400 10800 11200 11600 12000 12400 12800 13200 13600 14000 14400 14800Measured Depth (800 usft/in)MPS-35MPS-35PB1MPS-35PB2GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference26.50 To 14742.80Project: Milne PointSite: M Pt S PadWell: Plan: MPU S-48iWellbore: MPU S-48iPlan: MPU S-48i wp05CASING DETAILSTVD TVDSS MD Size Name3898.44 3834.04 7200.00 9-5/8 9 5/8" x 12 1/4"4069.40 4005.00 14742.80 4-1/2 4 1/2" x 8 1/2"Ladder / S.F. Plots2 of 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.
Schrader Bluff Oil
X
X
X
MPU S-48
Milne Point Unit
221-049
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