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HomeMy WebLinkAbout220-074DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20492-01-00Well Name/No. CANNERY LOOP UNIT 06RDCompletion Status1-GASCompletion Date1/16/2021Permit to Drill2200740Operator Hilcorp Alaska, LLCMD6300TVD4477Current Status1-GAS8/6/2021UICNoWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:LWD/MWD logs, CBL 1-14-21, MudlogNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF1/26/20211732 6300 Electronic Data Set, Filename: CLU 06RD LWD Final.las34622EDDigital DataDF1/26/2021 Electronic File: CLU 06RD LWD Final MD.cgm34622EDDigital DataDF1/26/2021 Electronic File: CLU 06RD LWD Final TVD.cgm34622EDDigital DataDF1/26/2021 Electronic File: CLU-06RD - Definitive Survey Report.pdf34622EDDigital DataDF1/26/2021 Electronic File: CLU-06RD - DSR Plan View.pdf34622EDDigital DataDF1/26/2021 Electronic File: CLU-06RD - DSR VSec View.pdf34622EDDigital DataDF1/26/2021 Electronic File: CLU-06RD - Final Surveys.xlsx34622EDDigital DataDF1/26/2021 Electronic File: CLU-06RD_DSR.txt34622EDDigital DataDF1/26/2021 Electronic File: CLU-06RD_GIS.txt34622EDDigital DataDF1/26/2021 Electronic File: CLU 06RD LWD Final MD.emf34622EDDigital DataDF1/26/2021 Electronic File: CLU 06RD LWD Final TVD.emf34622EDDigital DataDF1/26/2021 Electronic File: CLU 06RD LWD Final MD.pdf34622EDDigital DataDF1/26/2021 Electronic File: CLU 06RD LWD Final TVD.pdf34622EDDigital DataDF1/26/2021 Electronic File: CLU 06RD LWD Final MD.tif34622EDDigital DataDF1/26/2021 Electronic File: CLU 06RD LWD Final TVD.tif34622EDDigital DataDF1/26/2021 Electronic File: EMFView3_1.zip34622EDDigital DataDF1/26/2021 Electronic File: Readme.txt34622EDDigital Data0 0 2200740 CANNERY LOOP UNIT 06RD LOG HEADERS34622LogLog Header ScansFriday, August 6, 2021AOGCCPage 1 of 6Supplied byOpSupplied byOpCLU 06RD LWDFinal.las
DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20492-01-00Well Name/No. CANNERY LOOP UNIT 06RDCompletion Status1-GASCompletion Date1/16/2021Permit to Drill2200740Operator Hilcorp Alaska, LLCMD6300TVD4477Current Status1-GAS8/6/2021UICNoDF1/29/20216246 1544 Electronic Data Set, Filename: CLU-06RD RCBL 14JAN2021.las34633EDDigital DataDF1/29/2021 Electronic File: CLU-06RD RCBL 14JAN2021.pdf34633EDDigital Data0 0 2200740 CANNERY LOOP UNIT 06RD LOG HEADERS34633LogLog Header ScansDF2/2/20211700 6350 Electronic Data Set, Filename: CLU-06RD.las34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD Daily Reports.pdf34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD Final Well Report.pdf34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD Drilling Dynamics Log MD 2in.pdf34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD Drilling Dynamics Log MD 5in.pdf34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD Drilling Dynamics Log TVD 2in.pdf34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD Drilling Dynamics Log TVD 5in.pdf34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD Formation Log MD 2in.pdf34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD Formation Log MD 5in.pdf34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD Formation Log TVD 2in.pdf34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD Formation Log TVD 5in.pdf34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD Gas Ratio Log MD 2in.pdf34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD Gas Ratio Log MD 5in.pdf34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD Gas Ratio Log TVD 2in.pdf34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD Gas Ratio Log TVD 5in.pdf34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD LWD Combo Log MD 2in.pdf34641EDDigital DataFriday, August 6, 2021AOGCCPage 2 of 6CLU-06RD.las
DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20492-01-00Well Name/No. CANNERY LOOP UNIT 06RDCompletion Status1-GASCompletion Date1/16/2021Permit to Drill2200740Operator Hilcorp Alaska, LLCMD6300TVD4477Current Status1-GAS8/6/2021UICNoDF2/2/2021 Electronic File: CLU-06RD LWD Combo Log MD 5in.pdf34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD LWD Combo Log TVD 2in.pdf34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD LWD Combo Log TVD 5in.pdf34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD Drilling Dynamics Log MD 2in.tif34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD Drilling Dynamics Log MD 5in.tif34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD Drilling Dynamics Log TVD 2in.tif34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD Drilling Dynamics Log TVD 5in.tif34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD Formation Log MD 2in.tif34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD Formation Log MD 5in.tif34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD Formation Log TVD 2in.tif34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD Formation Log TVD 5in.tif34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD Gas Ratio Log MD 2in.tif34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD Gas Ratio Log MD 5in.tif34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD Gas Ratio Log TVD 2in.tif34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD Gas Ratio Log TVD 5in.tif34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD LWD Combo Log MD 2in.tif34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD LWD Combo Log MD 5in.tif34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD LWD Combo Log TVD 2in.tif34641EDDigital DataFriday, August 6, 2021AOGCCPage 3 of 6
DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20492-01-00Well Name/No. CANNERY LOOP UNIT 06RDCompletion Status1-GASCompletion Date1/16/2021Permit to Drill2200740Operator Hilcorp Alaska, LLCMD6300TVD4477Current Status1-GAS8/6/2021UICNoDF2/2/2021 Electronic File: CLU-06RD LWD Combo Log TVD 5in.tif34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD.dbf34641EDDigital DataDF2/2/2021 Electronic File: clu-06rd.hdr34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD.mdx34641EDDigital DataDF2/2/2021 Electronic File: clu-06rdr.dbf34641EDDigital DataDF2/2/2021 Electronic File: clu-06rdr.mdx34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD_SCL.DBF34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD_SCL.MDX34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD_TVD.DBF34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD_TVD.mdx34641EDDigital DataDF2/2/2021 Electronic File: CLU-06RD Show Reports.pdf34641EDDigital Data0 0 2200740 CANNERY LOOP UNIT 06RD LOG HEADERS34641LogLog Header ScansDF3/8/20214140 6102 Electronic Data Set, Filename: CLU-06RD FL,PATCH SET,PERF RECORD 15-FEB-21.las34746EDDigital DataDF3/8/2021 Electronic File: CLU-06RD FLUID LEVEL, PATCH SET, PERF RECORD 15-FEB-21.pdf34746EDDigital Data0 0 2200740 CANNERY LOOP UNIT 06RD LOG HEADERS34746LogLog Header ScansDF3/30/20216080 5879 Electronic Data Set, Filename: CLU-06RD_PERF_19MAR21_PERF 6086-6094.las34837EDDigital DataDF3/30/20216074 5868 Electronic Data Set, Filename: CLU-06RD_PERF_19MAR21_PERF CORRELATION.las34837EDDigital DataDF3/30/20216116 5862 Electronic Data Set, Filename: CLU-06RD_PERF_19MAR21_PLUG CORRELATION.las34837EDDigital DataDF3/30/20216103 5867 Electronic Data Set, Filename: CLU-06RD_PERF_19MAR21_PLUG SETTING PASS.las34837EDDigital DataDF3/30/2021 Electronic File: CLU-06RD_PERF_19MAR21.pdf34837EDDigital DataDF3/30/2021 Electronic File: CLU-06RD_PERF_19MAR21_img.tiff34837EDDigital DataFriday, August 6, 2021AOGCCPage 4 of 6
DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20492-01-00Well Name/No. CANNERY LOOP UNIT 06RDCompletion Status1-GASCompletion Date1/16/2021Permit to Drill2200740Operator Hilcorp Alaska, LLCMD6300TVD4477Current Status1-GAS8/6/2021UICNo0 0 2200740 CANNERY LOOP UNIT 06RD LOG HEADERS34837LogLog Header ScansDF5/6/20215932 5768 Electronic Data Set, Filename: CLU_06RD_PERF_31MAR21_CORRELATION (2).las35100EDDigital DataDF5/6/20215924 5609 Electronic Data Set, Filename: CLU_06RD_PERF_31MAR21_CORRELATION.las35100EDDigital DataDF5/6/20215945 5758 Electronic Data Set, Filename: CLU_06RD_PERF_31MAR21_GPT_COR.las35100EDDigital DataDF5/6/20215905 5695 Electronic Data Set, Filename: CLU_06RD_PERF_31MAR21_PERF.las35100EDDigital DataDF5/6/20215936 5796 Electronic Data Set, Filename: CLU_06RD_PERF_31MAR21_SETTING.las35100EDDigital DataDF5/6/2021 Electronic File: CLU_06RD_PERF_31MAR21.pdf35100EDDigital DataDF5/6/2021 Electronic File: CLU_06RD_PERF_31MAR21_img.tiff35100EDDigital Data0 0 2200740 CANNERY LOOP UNIT 06RD LOG HEADERS35100LogLog Header ScansDF6/28/2021204 5997 Electronic Data Set, Filename: 012821 clu-06rd_GPT LOG.las35260EDDigital DataDF6/28/2021 Electronic File: 012821 CLU 06RD GPT FINAL.pdf35260EDDigital Data0 0 2200740 CANNERY LOOP UNIT 06RD LOG HEADERS35260LogLog Header Scans0 0 2200740 CANNERY LOOP UNIT 06RD LOG HEADERS35261LogLog Header ScansDF6/28/20216206 5870 Electronic Data Set, Filename: 012621 clu-06rd_CORRELATION GUN1.las35261EDDigital DataDF6/28/20216186 5866 Electronic Data Set, Filename: 012621 clu-06rd_CORRELATION GUN2.las35261EDDigital DataDF6/28/2021 Electronic File: 012621 CLU 06RD PERF FINAL.pdf35261EDDigital DataDF6/28/2021 Electronic File: CLU 06RD 1-26-21 CORRELATION GUN 1.pdf35261EDDigital DataDF6/28/2021 Electronic File: CLU 06RD 1-26-21 CORRELATION GUN 2.pdf35261EDDigital DataFriday, August 6, 2021AOGCCPage 5 of 6
DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20492-01-00Well Name/No. CANNERY LOOP UNIT 06RDCompletion Status1-GASCompletion Date1/16/2021Permit to Drill2200740Operator Hilcorp Alaska, LLCMD6300TVD4477Current Status1-GAS8/6/2021UICNoWell 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:1/16/2021Release Date:12/10/20202/8/20211740 630031772CuttingsFriday, August 6, 2021AOGCCPage 6 of 6M. Guhl8/6/2021
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 and return one copy of this transmittal or FAX to 907 564-4424
Received By: Date:
Hilcorp North Slope, LLC
Date: 06/22/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL
FTP Folder Contents: Log Print Files and LAS Data Files:
Well API # PTD # Date Log Type Logging Company
CLU 05RD 501332047401 215160 6/15/2021 SET PLUG Yellowjacket
CLU-06RD 501332049201 220074 1/26/2021 PERF Yellowjacket
CLU-06RD 501332049201 220074 1/28/2021 GPT Yellowjacket
CLU 14 501332068400 219078 7/23/2020 SET PLUG/PERF Yellowjacket
CLU-15 501332068700 220003 5/27/2020 PERF Yellowjacket
Please include current contact information if different from above.
06/28/2021
PTD: 2200740
E-Set: 35261
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 and return one copy of this transmittal or FAX to 907 564-4424
Received By: Date:
Hilcorp North Slope, LLC
Date: 06/22/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL
FTP Folder Contents: Log Print Files and LAS Data Files:
Well API # PTD # Date Log Type Logging Company
CLU 05RD 501332047401 215160 6/15/2021 SET PLUG Yellowjacket
CLU-06RD 501332049201 220074 1/26/2021 PERF Yellowjacket
CLU-06RD 501332049201 220074 1/28/2021 GPT Yellowjacket
CLU 14 501332068400 219078 7/23/2020 SET PLUG/PERF Yellowjacket
CLU-15 501332068700 220003 5/27/2020 PERF Yellowjacket
Please include current contact information if different from above.
06/28/2021
PTD: 2200740
E-Set: 35260
Samuel Gebert Hilcorp Alaska, LLC
GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: 907 777-8337
Fax: 907 777-8510
E-mail: sam.gebert@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510
Received By: Date:
DATE: 05/06/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
CLU 06RD (PTD 220-074)
PERF 03/31/2021
Please include current contact information if different from above.
PTD: 2200740
E-Set: 35100
Received by the AOGCC 05/06/2021
05/06/2021
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): Cannery Loop Unit
GL:20.7' BF:20.7'
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
4-1/2" L-80 4,477'
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
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,
TUBING RECORD
1,577'4-1/2" Tieback
SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation
Size and Number; Date Perfd):
6-1/8" L - 265 sx / T - 70 sx
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
1/16/2021
114' FSL, 463' FEL, Sec 7, T5N, R11W, SM, AK
1264' FSL, 1957' FEL, Sec 8, T5N, R11W, SM, AK
220-074 / 321-023
Sterling Undef Gas Pool
37.7'
5,932' MD / 4,196' TVD
Top Perf
HOLE SIZE AMOUNT
PULLED
50-133-20492-01-00
CLU-06RD
272506 2388566
1207' FSL, 2211' FEL, Sec 8, T5N, R11W, SM, AK
CEMENTING RECORD
2389584
SETTING DEPTH TVD
2389637
BOTTOM TOP
1,504'
CASING WT. PER
FT.GRADE
276066
276322
TOP
SETTING DEPTH MD
1,575'
Per 20 AAC 25.283 (i)(2) attach electronic information
DEPTH SET (MD)
LTP 1,575' MD / 1,504' TVD
PACKER SET (MD/TVD)
13.5# 6,300'
Gas-Oil Ratio:Choke Size:Water-Bbl:
PRODUCTION TEST
N/A
Date of Test:
N/A
N/A N/A
Flow Tubing
N/A
N/A
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/AN/A
N/A
**Please see attached schematic for perforation detail**
N/A
LWD/MWD logs, CBL 1-14-21, Mudlog
Sr Res EngSr Pet GeoSr Pet Eng
N/A
N/A
Oil-Bbl: Water-Bbl:
N/A N/AN/A
January 11, 2021
January 8, 2021
Fee ADL60569, Fee ADL60568, ADL391790
N/A
N/A
1,743' MD / 1,634' TVDN/A
206' MD / 206' TVD
6,300' MD / 4,477' TVD
WINJ
SPLUG Other Abandoned Suspended
Stratigraphic Test
No
No
(attached) No
Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment
By Meredith Guhl at 11:41 am, Apr 12, 2021
RBDMS HEW 4/12/2021
Completion Date
1/16/2021
HEW
G
DSR-4/12/21
SFD 4/19/2021
BJM 08/05/2021 DLB 04/14/2021
Conventional Core(s): Yes No Sidewall Cores:
30.
MD TVD
N/A N/A
Top of Productive Interval 5,900' ST A11A 4,173'
5549 3954
5658 4020
5768 4087
5853 4142
5890 4167
5955 4212
6000 4245
6096 4316
Sterling
31. List of Attachments:
32. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Contact Name: Cody Dinger
Contact Email:cdinger@hilcorp.com
Authorized Contact Phone: 777-8389
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:
FORMATION TESTS
Permafrost - Top
ST A8
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.
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
ST A11B
ST B1
Permafrost - Base
29. GEOLOGIC MARKERS (List all formations and markers encountered):
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
ST B2
ST A11A
ST A9
ST A10
Formation at total depth:
ST A11
Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Report.
Signature w/Date:
Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345),
and/or Easement (ADL 123456) number.
INSTRUCTIONS
Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each
segregated pool is a completion.
TPI (Top of Producing Interval).
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.
Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and
other tests as required including, but not limited to: core analysis, paleontological report, production or well test results.
Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29.
Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool.
If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the
producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced,
showing the data pertinent to such interval).
Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit
detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity,
permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology.
The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements
given in other spaces on this form and in any attachments.
The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00).
Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain).
No
NoSidewall Cores: Yes No
Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment
4.12.2021Digitally 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: 2021.04.12 10:31:14 -08'00'
Monty M
Myers
_____________________________________________________________________________________
Updated by CJD 4/12/21
SCHEMATIC Cook Inlet Basin, Alaska
Middle Ground Shoal
Last Completed: 02-28-1992
Oil Well ->Water injector -> Gas producer
for Platform
Kenai CLU
CLU-06RD
PTD: 220-074
API: 50-133-20492-01-00
TD = 6,300’ MD / 4,172’ TVD
2
RKB=18’ MSL
7”
Window
1
ST-A11A
3
4
5
9-5/8”
4-1/2”
PBTD = 5,932’ MD / 4,196’ TVD
ST-B1
ST-B2
ST-B2
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm
9-5/8" Conductor 53.5 / P-110 / Unknown 9.95” Surf 91'
7" Surface 23 & 26 / L-80 / Unknown 6.151” Surf 1,600'
4-1/2" Production 13.5# / L-80 / VAM HTTC 3.920” 1,575’ 6,300’
4-1/2” Tieback 12.6# / L-80 / IBT Mod 3.920” Surf 1,576’
JEWELRY DETAIL
No Depth ID Item
1 206’ 3.613” SSSV
2 1,575’ 4.176” Baker liner hanger/LTP system
3 5,942’ CIBP w/ 10’ of cmt on top (5,932’)
4 6,106’ CIBP w/8’ of cmt on top (6,098’)
5 6,121-
6,132’ Tubing Patch
OPEN HOLE / CEMENT DETAIL
7” (CLU-06) 280 sx 11.5 ppg litecrete
4-1/2” 110 bbls 12 ppg Type I, II Lead Cement
12 bbls 15.3 ppg Prem. G Tail Cement
Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Status
ST-A11A 5,900' 5,905' 4,173’ 4,177’ 5’ 3/31/21 Open
ST-B1 6,086' 6,094' 4,308’ 4,314’ 8' 3/19/21 Isolated
ST-B2 6,122' 6,130' 4,336’ 4,342’ 8’ 1/26/21 Isolated
w/ Patch
ST-B2 6,146’ 6,151’ 4,355’ 4,359’ 5’ 2/22/21 Isolated
bjm
TOW=1743' md
7" Window top is 1743' md
Activity Date Ops Summary
1/8/2021 No activity swap to drilling AFE @ noon.;Continue easing in hole orientating tool face t/ 63R / Dn pumps / Tag @ 1760' w/ 15k dn seen good indication of anchor
trip over pull 15k and verified same / set dn and sheared off w/ 25k / p/up w/ no over pull / Top of slide @ 1743'.;Dis place well t/ 6% KCL mud @ 9.1 ppg and
over board water to cutting box.;Establish Parameters / SPR / Mill window f/ 1743' t/ 1757' Time drilling 6 fph on ramp, 9k WOB 80 rpm Drill t/ 1777' in formation'
Top of window 1743' Bottom of window 1757' Work mills across window clean up ramp x3 smooth no issues, work through with no rotary pulled smooth.;Rack
back 2 stands perform FIT t/ 14.02 ppg EMW 422 psi, pumped 9.7 gal bled back 6.9 gal, Blow down all lines.;POOH on elevators, L/D BHA mills in
gauge.;Service rig, change oil in floor motor, grease crown, blocks and top drive, inspect breaks and drive shaft.;P/U stack washer and flush stack, set wear
ring.;P/U Drilling BHA as per DD/MWD, upload MWD, shallow test tools, Load sources RIH w/ BHA f/derrick t/ 1727'.;Slip and cut drilling line.;Hauled: 13 bbls
solids to KGF G&I
Cumulative: 67.5 bbls
Hauled: 157 bbls fluid to KGF G&I
Cumulative: 262.5 bbls
Hauled: 0 bbls cement to KGF G&I
Cumulative: 0 bbls
Daily downhole losses: 0 bbls
Cumulative: 0 bbls
Daily metals: 152lbs.
Cumulative: 186 lbs.
1/9/2021 Continue and finish slip and cut drilling line 10 wraps 48' @ 1727'.;Orient t/ window @ 63R and establish parameters / dn pump / ease through window w/ no
issues f/ 1727' t/ 1777'.;Drill f/ 1777' t/ 1825' WOB - 2/4k / RPM-30 / GPM-275 / SPP-1375 psi / P/up 47k / SO 42K / Rot 43k / off Btm TQ 3.3k / on btm 3.5k.;Circ
Btm/up pooh f/ 1825' t/ 1692' w/ no over pull through window.;M/up XO retrive wear ring / M/up test plug and hang off drill string @ 42k / M/up r/up test
equipment / flood stack and purge air / Acquire good shell test.;Test bopes as per drilling permit 250L / 3500H / on 4-1/2" and 2-7/8" test jts / Test CMV 1-15, Auto
and Man IBOP, TIW and Dart, Upper lower and blind rams, annular, HCR and Man choke and kill, Inside and outside mezz kill valves, w/ one F/P / R/D test
equipment, pull test plug set wear ring.;Trip in the hole f/ 1692' t/ 1825' no fill on bottom, didn't see anything through window.;Drill ahead f/ 1825' t/ 2349' 300 gpm
1650 psi 80 prm 4.1k tq on, 56k PUW 44k SOW 50k ROT.;Drill Ahead f/ 2349' t/ 2845' 300 gpm 1690 psi 80 rpm 5.5k on 4.6k off PUW 65k SOW 45k 51k ROT
9.1 ppg MW ECD 10.88 ppg.;Blow Down top drive, flow check well slight seepage, POOH f/ 2845' t/ 1853' no issues.;Hauled: 0 bbls solids to KGF G&I
Cumulative: 67.5 bbls
Hauled: 0 bbls fluid to KGF G&I
Cumulative: 262.5 bbls
Hauled: 0 bbls cement to KGF G&I
Cumulative: 0 bbls
Daily downhole losses: 0 bbls
Cumulative: 0 bbls
Daily metals: 12lbs.
Cumulative: 198 lbs.
1/10/2021 Service rig / grease traveling equipment and monitor well @ 1 bph loss rate.;Short trip on elevators RIH f/ 1789' t/ 2845' wash last stand to btm / w/ no issues or
fill / Calc. disp. @ 17 bbls / Actual @ 16.5 bbls.;Resume drilling 6-1/8" directional hole holding max rop to 200fph and pumpe d 20 bbl High vis sweep around
while drilling back on time w/ 20% excess f/ 2845' t/3375' and send other 20bbl high vis sweep around while drilling / Back 11.5 bbls late w/ 50% increase Back
reaming full stands.;With slides as necessary to maintain WP-08 and mad passing slide @ 300 fph / WOB 1-4k / RPM=80 / GPM=300 / SPP= 1690psi / on Btm
TQ = 5.5k / off btm TQ 4.6k / Pu/SO/Rot 65/45/ 51k w/ high gas 3 units / MW @ 9.1ppg w/ ECD @ 10.83PPG.;Continue Drilling f/ 3375' t/3769' @ 300 GPM /
1650psi SPP / Up/dn/rot 56/44/50k / 80 RPM w/ TQ 4.1k ECD 11.02 / WOB 1-4k / MW @ 9.1 ppg / Max gas 5 units / Offload rabbit and tally 4-1/2 csg / circ
clean / obtain survey / SPR.;Flow chk slight seepage / Pooh on elevators f/ 3836' t/ 2846' w/ no issue.;Service rig grease traveling equipment / clean suction and
discharge screens / cleaned rod wash tanks / chg out love joy coupler on MP #1 / while monitoring hole w/ 1.5 bph loss rate.;RIH f/ 2846' t/ 3775' Wash last stand
to bottom no fill or hole issues.;Drill Ahead f/ 3846' t/ 4455' 300 gpm 1930 psi 80 rpm 6.7k tq on 5.3k tq off, 83k PUW 54k SOW 62k ROT.;Drill Ahead f/ 4455' t/ t/
4824' 300 gpm 2010 psi 80 rpm 7.3k tq on PUW 83k SOW 54k ROT 62k Distance to Plan 7.46' Low 3.62' Right.;Circulate bottoms up, obtain surveys and SPR's,
Flow Check Well static.;Make Wiper trip f/ 4824' t/ 1729' No Hole Issues didnt't see anything pulling throught window.;Service rig and top drive, inspect brakes
and Draw works.;Hauled: 85 bbls solids to KGF G&I
Cumulative: 152.5 bbls
Hauled: 270 bbls fluid to KGF G&I
Cumulative: 532.5 bbls
Hauled: 0 bbls cement to KGF G&I
Cumulative: 0 bbls
Daily downhole losses: 24 bbls
Cumulative: 24 bbls
Daily metals: 0lbs.
Cumulative: 198 lbs.
Contractor
AFE #:
AFE $:
Job Name:201-04185D CLU-06RD Drilling
Spud Date:
Well Name:
Field:
County/State:
CLU 006RD
Cannery Loop
Hilcorp Energy Company Composite Report
, Alaska
18
n (LAT/LONG):
evation (RKB):
50-133-20492-01-00API #:
g
;Drill Ahead f/ 3846' t/ 4455'
;Continue Drilling f/ 3375' t/3769'
p
9.1 ppg MW
perform FIT t/ 14.02 ppg EMW
;Drill Ahead f/ 4455' t/ t/
4824'
pp p
/ Mill window f/ 1743' t/ 1757'
@ g
;Dis place well t/ 6% KCL mud @ 9.1 ppg and
pp
422 psi, pumped 9.7 gal bled back 6.9 gal,
;Drill Ahead f/ 2349' t/ 2845'
1/11/2021 Short trip RIH f/ 1729' t/ t/ 4824' seen 5k extra drag @ 4515' (formation change and small slide area) / Fill pipe and wash last stand to btm w/ no issues or fill /
sent 20 bbl sweep around while drilling / Back 17.3 bbls late w/ 10% increase;directional drill 6-1/8" hole f/ 4824' t/ 5688' Holding max ROP t/ 200fph WOB 2-5k /
RPM=80 / GPM=285 / SPP= 2025 psi / on Btm TQ = 8.6k / off btm TQ 9.2k / Pu/SO/Rot 102/45/ 69k w/ high gas 36 units (coal )/ MW @ 9.2ppg w/ ECD @
11.25PPG w/ slides as necessary to maintain WP-08.;Add couple drums of lube at 5450' do to torque and up weight creeping up / Circ clean / Survey /
SPR.;Pooh on elevators f/ 5688' t/ 4464' No hole issues.;Service rig Monitor loss rate 1.5 bph.;RIH f/ 4464' t/ 5629' Wash last stand to bottom, pump sweep 21
bbls late.;Drill Ahead f/ 5688' t/ 6123' 285 gpm 2155 psi 80 rpm 8.5k tq on 7.2k tq off 100k PUW 58k SOW 71k ROT.;Drill Ahead f/ 6123' t/ TD @ 6300' 285 gpm
2080 psi 80 rpm 10.2k tq 100k PUW 58k SOW 71k ROT Distance to plan 7.46' Low 3.62' Right.;Circulate bottoms up X 3 Shakers cleaned up, Obtain Surveys
and SPR's, Blow down top drive.;Make wiper trip t/ 5440' No Hole Issues RIH t/ 6300 with out issue.;Circulate Hi Vis Sweep around back 17.8 bbls late and no
increase in cuttings, Blow down top drive, flow check static slight loss.;POOH f/ 6300' t/ 5728' No Issues.;Hauled: 63 bbls solids to KGF G&I
Cumulative: 215.5 bbls
Hauled: 187 bbls fluid to KGF G&I
Cumulative: 719.5 bbls
Hauled: 0 bbls cement to KGF G&I
Cumulative: 0 bbls
Daily downhole losses: 36 bbls
Cumulative: 60 bbls
Daily metals: 0lbs.
Cumulative: 198 lbs.
1/12/2021 Con tinue POOH f/ 5727' t/1662' w/ no hole or window issues / Dropped hollow 2.38" OD drift on wire @ 1792' w/ flow chk at window w/ slight seepage
observed.;Resumed pooh from 1662' to BHA, racked back HWDP, LD jars, removed sources and downloaded MWD, LD all smart iron and motor, bit graded a 1-
1 and was in gauge.;CO grabber dies and hydraulic line o-ring on topdrive, staged centralizers and casing equipment on rig floor, racked 3 new joints of shoe
track, RU fill up line, hung casing tongs., held PJSM with rig crew and Weatherford reps.;PU and MU 4 1/2" VAM HTTC shoe track, filled same and checked
floats (OK), cont PU single in hole with 4 1/2" VAM HTTC 13.5# L-80 liner from 126' to 1630', top filling on the fly, topping off every ten joints.;MU circ swedge and
topdrive, CBU at 114 gpm-80 psi, up wt 28K, dwn wt 28K.;Cont PU single in hole from 1630' to 4727' No Hole Issues, M/U Hanger and crossover RIH w/ 1 stand
of DP.;Circulate bottoms up 114 gpm 250 psi.;Continue RIH w/ 4.5'' Casing on 4.5'' DP t/ 6300 ' No Hole issues tag bottom.;Circulate and condition mud f/ cement
job stage pumps t/ 5 bpm 630 psi, spot in cementers stag equipment on catwalk.;R/U baker rotating cement head and circulating lines, Hold PJSM with
Halliburton cementers.;Halliburton pumped 10 bbls water to flush lines. Shut in at Baker cement head and PT lines at 260 psi low 4908 psi high. Good tests. Lined
up Baker cement head to Halliburton, pumped 45 bbls 10.5 ppg Tuned Prime Spacer at 3 bpm- 440 psi, followed with 110 bbls (265 sx) 12ppg Type I II Lead
cement at;6 bpm, 449 to 220 psi, followed with 12 bbls (70 sx) 15.3 ppg Premium G Tail cement at 3 bpm, 264 to 251 psi.;Hauled: 37 bbls solids to KGF G&I
Cumulative: 252.5 bbls
Hauled: 148 bbls fluid to KGF G&I
Cumulative: 867.5 bbls
Hauled: 0 bbls cement to KGF G&I
Cumulative: 0 bbls
Daily downhole losses: 36 bbls
Cumulative: 96 bbls
Daily metals: 0lbs.
Cumulative: 198 lbs.
1/13/2021 Cementers flushed lines while Baker dropped wiper dart, Halliburton then displaced with 9.2 KCL mud at 3 bpm-57 to 1280 psi, saw dart latch wiper plug 20 bbls
into displacement, 77 bbls into displacement started overboard spacer returns, with 10 bbls to go slowed to 2 bpm-1200 psi and bumped wiper;plug/landing collar
at 89 bbls into displacement (calc at 90 bbls). FCP 1200 psi. Halliburton increased to and held 1800 psi (600 over fcp) for 3 minutes, bled off and floats held. Bled
back 1 bbl to truck. Were able to rotate and reciprocate string until starting displacement. Lost a total of 21.4;throughout the job. CIP at 06:30 on 1-13-
21.;Halliburton increased pressure as per Baker Rep to 2227 psi to set hanger, did not see indication hanger set, S/O on blocks from 85K to 15K indicating
hanger set. PU to 48K and applied pressure to 3800 psi to set packer, then up to 4500 psi to neutralize pusher tool and release running tool.;Bled off string, broke
off hardline to cement head and capped 1502 connection, lined up on topdrive, pressured up on string to 500 psi and PU, as pressure dropped, started circulating
with rig pump and CBU one time at 347 gpm-761 psi. Downed pump, PU and released dog sub, rotated at 20 rpm, S/O and;set down on liner top, did not see dog
sub shear (shallow hanger depth/light string weight). Broke off topdrive and cement head, LD same, racked back one stand DP, inserted wiper balls in drill string,
MU topdrive, CBU again at 402 gpm-347 psi. Had 4.8 bbls lead cement to surface on first CBU.;RD and released cementers, blew down topdrive and mudline,
POOH racking back DP in derrick from 1575' to surface. Upon inspection of run tool, dog sub was not sheared, hydraulic pusher tool had functioned as desired.
LD Baker run tool.;Cleaned and cleared rig floor. PU Baker cement head and broke off pup joints and XO's. LD same.;PU Baker 5.25" "TBR" dress and polish mill
assembly, MU XO, RIH on 4 1/2" DP from derrick to 1569'. MU topdrive, ease down and tagged top of liner at 1575', lower polish mill at 1584.5'. Up wt 39K, dwn
wt 38K.;Circ at 250 gpm-160 psi, 30 rpm-2200 ft/lbs, S/O and dressed liner top 5 times as per Baker Rep, down pump. Blew down topdrive and mudline.;POOH
from 1584' to surface, LD and inspect mill assembly, bottom mill had no markings of contact. Shipped out Sperry tools, dressed pump #2 with 4 1/2"
liners/swabs.;Shipped 14 jnts 2 7/8" over to KGF workover rig, shipped excess VAM liner pipe to Tuboscope. Haul off excess mud to G&I. Brought in two trailers 2
7/8" workstring, rack and tally same, cleaning pits, built brine, RU Weatherford, held PJSM.;BOP previously tested with 2 7/8" test joint on 1-9-21. MU 3.65" bit
and scraper assembly for 4 1/2" liner, PU and single in hole with 2 7/8" workstring to 4669', M/u 7'' Scraper and Crossover t/ 4.5'' DP, RIH on 4.5'' DP t/ 6217' set
down 4k x2.;Circulate bottoms up 156 gpm 1930 psi contaminated mud on bottoms up.;R/U and Test casing to 2500 psi f/ 30 min on chart pumped 43.7 gal in
42.5 gal bled back to tank, R/D test equipment Line back up to displace.;Displace well t/ 8.6 ppg Inhibited KCL brine 158 gpm 1715 psi, Blow Down lines, flow
check static.;POOH L/D DP, Dropping balls and vacuuming clean, cleaning and doping threads and installing thread protectors L/D 45 stands RIH w/ 3rd batch of
20 to L/D.;Hauled: 67 bbls solids to KGF G&I
Cumulative: 319.5 bbls
Hauled: 568 bbls fluid to KGF G&I
Cumulative: 1435.5 bbls
Hauled: 4.8 bbls cement to KGF G&I
Cumulative: 4.8 bbls
Daily downhole losses: 22 bbls
Cumulative: 118 bbls
Daily metals: 0lbs.
Cumulative: 198 lbs.
pp
;Drill Ahead f/ 6123' t/ TD @ 6300' ff
p
(calc at 90 bbls)
p
t 89 bbls into displacement
Upon inspection of run tool, dog sub was not sheared, h
g) p
Had 4.8 bbls lead cement to surface on first CBU.
MW @ 9.2ppg
g
RIH w/ 4.5'' Casing on 4.5'' DP t/ 6300
)pp
drill 6-1/8" hole f/ 4824' t/ 5688'
displaced with 9.2 KCL mud
p( p)
Lost a total of 21.4;throughout the job.
ggg g
single in hole with 4 1/2" VAM HTTC 13.5# L-80 liner
pumped 43.7 gal in
p p ppg p p
followed with 12 bbls (70 sx) 15.3 ppg Premium G Tail cement
ppp
applied pressure to 3800 psi to set packer,
p
;R/U and Test casing to 2500 psi f/ 30 min on chart p
;Displace well t/ 8.6 ppg Inhibited KCL brine
g
p pg
followed with 110 bbls (265 sx) 12ppg Type I II Leadp
cement
1/14/2021 Continue RIH w/ 4.5'' DP 20 stands and POOH L/D singles and vacuuming wiper balls through pipe and doping threads and installing thread protectors, left 22
stands in derrick.;R/U Weatherford tongs and L/D 2 7/8'' work string f/ 4670' t/ surface, L/D scraper and bit, R/D Weatherford, Notified AOGCC and Quadco of
upcoming BOP test.;Spot in Yellow Jacket E Line and R/U, M/U tool String, RIH w/ CBL tag @ 6217' Log out of the hole t/ 1575' POOH R/D E Line.;M/U Mule
Shoe RIH w/ 20 stands of DP f/ Derrick t/ 1128' M/U storm Packer as per Tri Point and RIH and Set 17k string weight.;R/U and Test storm packer t/ 1500 psi f/ 10
min, good test, R/D and blow down lines.;N/D BOP's Drop single gate off the bottom of the stack N/U new tubing spool and stack back up on wellhead, N/U
Choke and Kill Lines, Install Flow box and riser, hook up flow line, hook up koomey lines, tighten all connections, flood stack and lines w/ water.;change test plug
rubber, fill stack and lines and shell test check for leaks while waiting on state man to arrive to test BOP's. Work on EAM's and House keeping around the rig.
Switch to Completion AFE.;Hauled: 26 bbls solids to KGF G&I
Cumulative: 345.5 bbls
Hauled: 495 bbls fluid to KGF G&I
Cumulative: 1930.5 bbls
Hauled: 0 bbls cement to KGF G&I
Cumulative: 4.8 bbls
Daily downhole losses: 0 bbls
Cumulative: 118 bbls
Daily metals: 0lbs.
Cumulative: 198 lbs.
p
RIH w/ CBL tag @ 6217' Log out of the hole t/ 1575' POOH
Activity Date Ops Summary
1/15/2021 Blew down surface lines and equipment after shell test of BOPE. Strapped 4 1/2" IBT tubing for tie back run, pressure washed throughout rig, completed PM's on
rig equipment, welder working on valve storage brackets in connex. Flooded BOPE and shell tested again prior to official test.,AOGCC Rep Adam Earl and
Quadco Rep on location at 11:00 to witness BOP test. Tested audio and visual gas sensor alarms and released Quadco Rep. Tested all BOPE at 250 low, 3500
high for 5 min each. Had one fail/pass on inside kill (air). 3.5 hour test time, lower ram gate removed from stack, so did not test that.,Blew down surface lines and
equipment, drained stack and removed test plug, RD test equipment, welder repaired hinges on boiler door.,Continued pressure washing throughout rig, Hydraulic
Rep on location and installed manrider manifold to allow rig floor winches to also be used for manrider winches. Received XO for seal assembly 4 1/2" IBT x 5"
TXP.,M/U Pulling tool and crossover, RIH Retrieve storm packer, L/D storm packer and cross over.,POOH L/D 4.5'' DP 21 stands, cleaning threads and sucking
wiper balls through pipe, installing doped protectors.,M/U Running tool and crossover, Set Spacer ring in wellhead as per Well head rep.,Service rig and top
drive.,Clean floor, work on EAM's and House keeping, Mix Soap pill in pits.,Flush soap through both mud pumps and choke manifold, top drive and kill lines,
suction lines in the pits, drain and blow down lines, Suck remaining fluid out of stack.,Continue House keeping and organizing parts houses, work on EAM's and
maintenance, wait on equipment and personnel to run completion, load racks w/ tubing stage completion equipment on slide.
1/16/2021 Started 10,000 hr inspection of mud pump engine #2, pressure washed all three hopper rooms, replaced hydraulic hose on pit roof raise valve bank, received
SSSV, called out Baker Rep and Weatherford, staged tie back tubing and seal assembly.,RU Weatherford, held PJSM with them, Baker Rep and rig crew. Called
out Pollard for control line, notified Wellhead Rep for hanger and pup.,MU Baker 5.25” Bullet Seal-Seal Assembly, XO sub and pup joint. PU singled in hole to
1350’ with 4 1/2" IBT Mod 12.6# tubing, MU torque at 4200 ft/lbs. At 1350' MU Halliburton wireline retrievable SSSV assembly, RU Pollard and 1/4" control line.
Cont single in hole and installing a cannon clamp on next three jnts, cont single in and observed seals enter SBR, tagged.,No-Go putting liner top at 1576.58’. Up
wt 27K, dwn wt 26K. Marked pipe, PU and obtained measurement for space out, LD 3 jnts. PU 2 pups and drift joint (4.5" IBT Mod 13.5#/ID = 3.920"). RIH, MU
hanger and pup, terminated control line at hanger, tested same (OK). Added 1/2 bbl diesel down backside to freeze protect 7” x 4 1/2" annulus.,Pulled rotary
bushings, up wt 28K, dwn wt 28K, SO and MU landing jnt, opened annulus valve, cont SO and landed hanger. No-Go 2.20' off seat, bottom of mule shoe at
1585.32', ran total 3 cannon clamps and 3 SS bands, 13K set on hanger. RKB = 15.19'.,RILD's, LD landing joint, RD Pollard and W eatherford, RU test pump on
IA, pumped 16.1 gallons to achieve 2000 psi, held 30 min on chart, good test, bled back 13.8 gallons, RD test equipment, installed BPV.,ND flow riser and flow
line, broke off kill and choke lines, ND BOP stack.,N/U dry hole tree, terminate control line, fill void and test hanger seals as per well head rep, install twc and test
tree t/ 250/5000 psi, remove twc suck tubing down 20' fill tubing with diesel.,Break down BOB stack, pull rams out of preventers, separate preventers plug
hydraulic ports, clean and grease cavities, break apart mud cross and valves, break HCR's clean and grease components, strip pumps and prep f/ stack out,
clean suction lines and pump discharge screens, inspect and clean shaker motor covers, clean all BOP components install flange covers, grease and molly mist
components.
1/17/2021 Cleaned and prepped annular and double gate for storage, changed gear oil in all agitators, covered electric motors for storage, installed shipping blocks on
shakers, lubed cables on vac degasser, RD and cleaned equalizer lines in pits, RD Pason gas monitor in pits, RD poorboy degasser plumbing, replaced hydraulic
hoses from sub to catwalk,,obtained oil and coolant samples from mud pump motors floor motor and gen #2, pickled pumps, cleaned and lubed pony rod clamps
and rods on pumps, cleaned liner wash tubs, removed plugs from mud pump charge pumps, covered exhaust stacks from pump house roof tops, installed
hydraulic isolation valve for derrick lock pins,,RD mud lab, shipped DP bunks, checking valve lash on both mud pump motors, adding desiccant to electrical
enclosures.,Pressure washed and scrubbed topdrive, and blocks, cleaned rig tongs and removed from rig floor, cleaned all crossovers and removed from rig floor,
removed all ropes from derrick board, pressure wash iron roughneck, finished 10,000 hr PM on pump #1 motor, cleaned mud dock area, cleaned skate operator
cab on catwalk,,Cleaned hopper rooms, cleaned pit module exteriors, freeze protected test pump, removed Pason screen from pits, cleaned and capped jumper
hoses for pit mods, covered shaker motors and vac degasser motor, stage all subs in basket for inspection, load BOP components on trailer, cleared snow on
CLU pad 3, cont installing,desiccant in electrical enclosures, finished checking valve lash on mud pump motors, shipped Sperry tools and shack.,Continue
cleaning rig floor and top drive wash iron roughneck, pressure washing around rig, working on stack out list, pull rotary cover and pressure wash under floor, load
out trailers and prep to transport, clean and anti seize mud line connections and bag for storage.,Continue pressure washing under rig floor, and in pits, clean
boiler and outside of buildings, organize buildings and working on stack out list, prep to move complexes, continue disconnecti ng modules and prepping lines f/
storage, organize choke house, clean mez deck and cellar.
1/18/2021 Unpin link tilt cylinders on topdrive and removed bails, checked topdrive end play on quill shaft (good), cont pressure washing mezz deck area, pressure washed
poorboy degasser skid, removed saver sub clamp and removed saver sub, removed IBOP clamp and IBOP, LOTO topdrive HPU and bled system off, removed
torque bushing from,torque tube and topdrive LD same, staged topdrive cradle on rig floor and pinned to topdrive, cont cleaning and wrapping equipment for
storage.,Installed trolly beam in cellar, cleaned and covered open ends of kelly hose and service loop lines, shut in both boilers, removed steam trap discs and
blew down steam lines, LD topdrive, bridled up, installed shipping bar in iron roughneck, removed mudline “S” pipe, removed sho ck hose from choke line at rig
floor, loaded and manifested,8 trailer loads of equipment for shipping, installed shipping blocks in centrifuge, cont blowdown of steam lines, spool up cords and
hoses for tear out of main modules, lay over poorboy degasser, checked end play on pump engine turbo's, re-mounted contactors on topdrive HP unit, adjusted
breaker linkages on topdrive HP unit, cont placing desiccant packs in electrical panels.,Removed kill line shock hose from mezz area, prep to scope derrick,
remove T bar and turn buckles, disconnect top section power bring down pason cord f/ crown, pull upper dogs and scope derrick down, remove torque tube f/
upper section, prep derrick t/ Lay over, continue stage down boilers, blow down water system, hang blocks, disconnect upper tor que tube and chain in derrick,
remove equipment f/ rig floor.,Prep to unspool drilling line, secure climber assist to derrick, unspool drilling line cut 15 wraps of line, coil up and secure in the
derrick, secure kelly hose and service loop in the derrick, remove tarps f/ around pits prep f/ crane work, Rig down rig cameras and gas detectors, Rig down break
handle, drive shaft and break linkage.
Contractor
AFE #:
AFE $:
201-04185C
Job Name:201-04185C CLU-06RD Completion
Spud Date:
Well Name:
Field:
County/State:
CLU 006RD
Cannery Loop
Hilcorp Energy Company Composite Report
, Alaska
18
n (LAT/LONG):
evation (RKB):
50-133-20492-01-00API #:
pg
singled in hole to
1350’ with 4 1/2" IBT Mod 12.6# tubing,
RU test pump onpg
IA, pumped 16.1 gallons to achieve 2000 psi, held 30 min on chart, good test,
in
MUpp
hanger and pup, terminated control line at hanger, tested same (OK). A
1/19/2021 Change blue filter elements on gens 1-2-3, Quadco Rep RD and boxed up all gas alarm equipment for shipping, welder on location replacing hinges on boiler
house door, rebuilt wash pipe, RD electric cords and fuel lines on pump skids, lay over upright water tank and load for shipping, removed shaker slides, cover
electric motors on TD HP unit,,greased beaver slide hinges and lay over same, change oil and filter on change shack gen set, RD water and steam line jumpers
between pits, welder installed hatch door on centrifuge stand for camera view of dump line, tore out poorboy degasser skid and shipped same to CLU pad
3.,Secured koomey lines in cable tray, shipped upright water tank, spotted crane and removed clam shell windwall, re-located cr ane and removed windwalls from
pits-stored same in connex, shipped BOP components, tore out and loaded gen 3 and windwall connex, RD TajMahall meeting hooch, vac’d out water from boiler
skids and hotwells,Picked centrifuge with crane, RD released crane crew, blew down water and pickled water pumps, vac'd out rig water tank and cleaned tank
bottom, lowered roof tops of pit mods 2 and 3, secured bridge cranes in cellar, removed rig floor drain hoses, shipped: Tri-Point basket, thread protectors, oily
waste, metal cuttings drum, dunnage, upright tank, gen 3, windwall connex,,subs and test joints, hurricane vacs, test joint rack, stack of sils, diverter anchors and
knife valve rack, mudlog shack, flow box, mud lab, Baker tools, 2 7/8" PH-6 from KGF, Weatherford tools, jars, pup joints.,Laid over derrick, tied up lines, lowered
roof on pit module #1, vacuumed out both boilers/hot wells, R/D down fuel lines/plumbing on boilers. Removed Handy berm around rig foot print and put away in
storage conex, disconnected unnecessary power wires and capped/taped end. Removed handrails & folded down water tank landing. f olded in & secured TDS
HPU grasshopper.,Cont. R/D electrical, HYD, & fuel lines. R/D V-door support braces, secured pits for load out, prepped dog house to lower into rig water tank.
Cleaned up around pad & cont. loading out misc. equip/tools onto trailers.
1/20/2021 Cont to wrap up cords etc on sub, removed lights from mods, shut down gen set, lowered dog house, crane crew on loc at 09:30 with second crane. Held PJSM,
staged crane. Tore out aux fuel tank, both boilers, gen skid, HPU, both pump skids, catwalk. Shipped gen skid, pit 3, both pumps.,Tore out doghouse, pits 2-3.
Picked iron roughneck off floor, picked choke house off floor, LD “V” door windwall. Tore out pit 1, relocated crane and LD der rick windwalls, spotted second
crane and picked derrick off carrier, picked carrier off sub base. Shipped doghouse, #1 boiler, derrick and carrier. Picked sub off pony walls. Folded
stairs/landings on sub, shipped big crane.,Loaded pits 1-2, removed old tree, kill line, IR HPU from between pony walls, shipped pits 1-2 and sub base. Broke
tours with crews.,Pick and stacked rig mats, vac up water off liner, picked up and disposed of liner & felt on CLU pad #1. Sent crew over to CCI yard to scratch
pad, laid felt, liner, rig mats & pony subs.,Released CCI night rig support crew and rested rig crews for the night.
1/21/2021 Held PTSM w/ rig crews. Sent majority of rig crew to CCI yard. Met w/ rig moving crew @ 07:30 hrs. Cont. loading up & hauling of misc. items from CLU pad #1.
Scarfed & policed CLU pad #1 for trash. Spotted & R/U cranes at CCI yard, set sub, DWKS, & derrick. R/D cranes, Hooked up HYD & pinned same,,untied lines
in derrick and prepped to half mask derrick. Spotted & set pit modules 1-3.,Raised derrick to half-mast. Spotted & set MP’s 1&2 and run electrical lines from
pumps to plug board. Set rig water tank/dog house, raised & pinned dog house. Set TDS HPU/C-can, boiler house, raised pit roofs on all three pit modules. Run
electrical lines from mud pump 1 and doghouse skid to gen combo building inspect and plug in same,,install lights on pit roofs, mud pumps, dog house and gen
combo building, set liner and rig mats for catwalk to be set in the morning, ensure rig is properly grounded in preparation to run generator when needed. Install
spill kits in proper locations around rig,,Rested rig crews for the night. Final report for CLU-06RD
1/23/2021 Petrospec coiled tubing arrive and conduct JSA and approve PTW. MIRU. NU BOPE on xmas tree. Spot choke manifold and return tank.,Function test BOP's.
Close Blind rams and pressure test to 250/3500 psi. Insert 1.75" test rod and close pipe/slip rams, test to 250/3500 psi. Test accumulator system. AOGCC
witness waived by Jim Regg.,Rig up hardline to coil reel. Stage N2 equipment for next day.
1/24/2021 Petrospec coiled tubing and Fox Energy N2 conduct JSA and approve PTW. MU injector above BOP's.,Pressure test stripper and lubricator to 250/3500 psi.
Pressure test inner reel valve to 250/3500 psi.,RIH with 1.75" coil pumping N2, taking returns to diffuser tank. Tag at 6245' ctmd. Set on bottom pumping N2.
Recover 95 bbls of fluid. POOH with coil. Trap 300 psi on well.,RDMO.
1/26/2021 Yellow Jacket E-line conduct JSA and approve PTW. MIRU E-line and MU 2' gun with 2-3/4" x 7' weight bar and 2-3/4" GR. PT lubricator to 250/2000 psi.,RIH
with 2' x 2.875" gun, 6 spf, 60 deg phasing, razor charges. Tag PBTD at 6215' uncorrected. Send correlation data to town, correct to OH and Perforate 6122 -
6124'.
Initial pressure = 300 psi. 5 min = 310 psi, 10 min = 310 psi, 15 min = 310 psi.
Gun is wet.,Rig up jumper line from CLU-14 to CLU-06RD to increase tubing pressure.
MU 5' gun with 2-3/4" x 7' weight bar, 3-1/8" x 5' weight bar, and 2-3/4" GR.,Send correlation data to town. On depth.
CLU-06RD tubing pressure increased from 310 psi to 410 psi, then started to decline to 360 psi. Closed in block valve on CLU-06RD and verified pressure would
increase on SCADA.,Open block valve on CLU-06RD with jumper line still open from CLU-14. TP on CLU-06RD at 380 psi. TP on CLU-14 at 800 psi. Pressure
increased from 380 psi to 470 psi.,Perforate 6125 - 6130'.
Initial press = 480 psi. 5 min = 700 psi, 10 min = 740 psi, 15 min = 750 psi.
Bullnose on gun was full of sand, small amount of fluid.,RDMO. Hand well over to production.
1/28/2021 MIRU Yellow Jacket E-line and Fox Energy N2. MU 1-11/16" GPT and 5' x 2-7/8" gun. PT to 250/2000 psi.,RIH and tag at 5935' (corrected depth). E-line is
stuck. Discuss options with town. Work wire up to 3100# and toolstring pulled free. POOH.,Recover entire toolstring. No ind ication of sand around toolstring.
RDMO.
2/13/2021 Petrospec coiled tubing conduct JSA and approve PTW. Spot equipment and NU BOPE.,Function test BOP rams. Test blind/shear ram to 250/3500 psi. Insert
1.75" test bar and test pipe/slip ram to 250/3500 psi. Choke and kill lines tested to 250/3500 psi. Test accumulator system.
AOGCC waived witness of BOP test by Jim Regg.,Install night cap on BOP's. Drill downjet hole in 1.75" nozzle for upcoming cleanout. Stage N2 equipment.
2/14/2021 Petrospec coiled tubing and Fox Energy conduct JSA and approve PTW. MU dual checks and 1.75" cleanout nozzle. Spot equipment, stab injector on top of
BOP's. Test N2 lines.,Pressure test stripper and lubricator to 250/3500 psi.,RIH with coil pumping minimum N2 rate (~ 300 scf/m). At 1500', increase rate to 800
scf/m. Getting fluid returns to surface. Continue to pump N2 and tag at 6245' ctmd.
Pull up hole to above perfs and pinch back choke to 200 psi. RIH and tag again at 6245'. POOH pinching choke back slowly. Getting sand and water returns at
surface.,POOH. at 5200', fluid and sand returns stopped at surface; just getting N2. Close in choke and continue to pump N2 while POOH. WHP = 500 psi.
Total return of 132 bbls of water.,Coil at surface. Shut down N2. WHP = 1400 psi.,RDMO
2/15/2021 AK E-line conduct JSA and approve PTW. Spot equipment. MIRU. MU GPT w/ 3.75" gauge ring and junk basket.,Open well and RIH. WHP = 1400 psi. Find
fluid level at 4342'. Tag at 6086'.
Attempt to get through tag, no success. POOH.,Laydown toolstring at surface. No sand in junk basket.
RDMO
2/20/2021 Travel to location, Contact DSO, inspect location. PTW and PSJM,Spot equipment,MIRU. Make up Gamma/CCL, test wire. Good test. Make up 3.75" gauge ring.
Stab on well, PT WLV/LUB 250/1500,Open well, Swab 23, WHP 250. RIH,Tag at 1580', work wire finally broke through. CRIH, Tag at 6122' ELM. Worked wire,
not making any hole.,POOH,Tagged up, swab shut, bleed down, pop off well. Gauge ring looks fine, no marking on it. Junk basket had some very fine sand and
fluid in it.. Break off gauge ring, Stab back on well. open up, RIH,Tag at 6120' ELM. Work wire down with junk basket to see if we can make some hole. No luck.
POOH. Tagged up, swab shut, bleed down, pop off well.,RDMO Eline.
psi.,Perforate 6125 - 6130'.
p
Perforate 6122 -
6124'.
2/21/2021 Travel to location, Spot equipment.,PTW, PJSM, MIRU Coil unit and crane. Rig up hardline to coil and tanks, make up hydraulic lines to bop's. Put BOPs on well,
prep for Bop test.,Test BOPE as per Hilcorp & AOGCC requirements, witnessed waived by AOGCC Inspections Supervisor Jim Regg, 250/4000.
Emailed BOPE Test Report to AOGCC.,Make up 20' Lubricator, Make up BHA, Pull test connector 30k ( CTC 2.25" X .77') ( DFCV 2.13" X .98') ( STINGER 2.13"
X 5') ( HYD DISCO 2.13" X 1.58') ( CIRC SUB 2.13" X 1.08') ( XO 2.0" X .66') ( NOZZLE 3.45" X .70') TOL= 11.75',Stab on well, PT well low/high 250/4000, Open
well, Swab 24 turns, T/I/O= 200/200/0. RIH,Tag at 6148' CTMD. N2 Cooling down. PT N2 low/high 250/4500.,Come online with N2 down coil at 1,000 SCFM,
Having hard time busting through sand bridge, up rate to 1500 scfm, start making hole. take 50' bites making it down to 6245' ctmd, Chase up hole above perfs @
6120', RBIH down to 6245' CTMD,POOH,Tagged up, swab shut, bleed down, pop off well. Rig down coil tools, stack down lubricator and injector.,MIRU Eline unit
next to coil. Make up 2.75" GR/CCL, test wire. Good test, Make up 3.68" WT BAR, 2.75" GR/CCL, 2.75" junk basket with 3.75" gauge ring.TOL= 20' Stab on
well, PT WLV/Lub 250/2500.
CCL T/bottom of tools is 12'.,Open well, WHP 1200, IA 0, OA 0. RIH N2 online at 500 scfm, whp 1320.,Tag at 6162' ELM +12' to bottom of tools= 6174' ELM. Pull
log up to 5850'. Down load and send to town for evaluation. POOH,Tagged up, N2 off line, swab shut, bleed down, pop off well. Break down wt bar and junk
basket. Make up 11.5', 3.5" 2.992" ID patch. Stab on well.,Open well, Swab 23, WHP 1380, come online with N2 down tubing at 500 scfm, RIH with Eline,Tag @
6096', bring N2 rate up to 1500 scfm, wait 5 min, RIH made It past 6096' down to 6145'. log up getting on CCL depth @ 6101.8' CCL T/ top element 18.5 CCL
T/bottom element 30' Set patch at 6120.5'-6132'. pressure up with N2 to 2000 psi for a pt of the patch.,POOH, Tagged up, swab shut, bleed down, pop off well.
Setting tool looks good, Rig down Eline and Stack back for the night. Jo b in progress.
2/22/2021 Travel to location,Contact DSO, inspect location, PTW, PJSM,Make up BHA, ( CTC 2.25" X .77') ( DFCV 2.13" X .98') ( STINGER 2.13" X 5') ( HYD DISCO 2.13"
X 1.58') ( CIRC SUB 2.13" X 1.08') ( XO 2.0" X .66') ( NOZZLE 2.5" X .70') TOL= 11.75'. Stab on well,Open well, Swab 23 turns, T/I/O= 2000/200/0, RIH,@
6,000' Come online with N2 at 500 scfm down coil. RIH to TD @ 6250' CTMD. Sit here for 10 min, PU above patch @ 6120' RBIH to TD @ 6250'. Wait here for
15 min.,POOH, shut well in at choke, build WHP to 1400 psi,Tagged up, swab shut, bleed down, pop off well. Break down tools, set down lubricator,,MIRU Eline,
Make up GR/CCL, test wire. Good test. Make up 5', 5 spt, 60* phase 11gram low swell razor gun. Stab on well, Pt WLV/LUB 250/1500. Open well, swab 23, whp
1500.,RIH, Tag at 6113' bottom of tools. work wire made it past and tagged bottom at 6189', log up to 6070', Send log to town for correlation to shoot 6146'-
6151'.,Got approval to shoot 6146'-6151' ( Ben Siks) PU to CCL depth of 6137'. CCL t/top shot 9', CCL to bottom shot 14'. Shoot 6146'-6151'. ITP 1400, 5 min, no
change, 10 min no change, 15 min 1360 psi. POOH,Tagged up, Lost a total of 100 psi from one we first shot. Shut well in, Bleed down, pop off well. All shots fired.
Wet gun. RDMO. Turn over to production.
3/15/2021 Travel to location,Contact DSO, Fill out PTW, PJSM. Spot equipment. MIRU,Test BOPE as per Hilcorp & AOGCC requirements, 250/4000.
Emailed BOPE Test Report to AOGCC.,Stab Pipe into injector head, change packoffs, inspect chains. Finish making up all hydraulic lines, return line and
miscellaneous cables. Secure well and location for the night. Job in progress.
3/16/2021 Travel to location,Arrive on location, contact DSO, inspect location, PTW, PJSM completed. Fire up equipment let warm up.,PU injector head, 10' lubricator, Make
up (CTC 2.0" X .166') ( DFCV 2.0" X 1.160') ( STINGER 2.0" X 3.1') ( DJN 2.0" X .583') TOL= 5.1',Stab on well, pt lub 250/3500. Open well, swab 24, WHP 0, IA
no gauge, OA 0. RIH,Have issue with drain hose. POOH slowly while fixing drain hose. Drain hose fixed, CRIH. Tag at 6024' CTMD,Call operations for some neat
meth to pump ahead of the water in the coil. Neat meth on location, come online with meth ahead.. having some issues with Schlumberger pump not able to
pump. Trouble shoot issues.,Got fluid moving down the coil, RIH start cleaning out. Clean out down to 6155' CTMD, Chase out of hole at 80%. Leaving 1100 psi
on the well. Got two bottoms up, shut down pump, shut the choke in. Wait for 30 min, RBIH to dry tag. Tagged at 6054' CTMD. POOH,Tagged up, swab shut,
come online with N2 to blow down the reel. Stack back for the night. Secure well and location. Job in progress.
3/17/2021 Travel to location,Contact DSO, PTW, PJSM. Fire up equipment, Let it warm up,PU injector, 10' lubricator. Make up (CTC 2.0" X .166') ( DFCV 2.0" X 1.160') (
STINGER 2.0" X 3.1') ( DJN 2.0" X .583') TOL= 5.1',Stab on well, PT low/high 250/3500. Open well, swab and upper swab would only open 18 turns. Wrap tree
and put heat on it. Finally got tree valves open.,RIH, 2350' Drain hose froze, down comer to choke froze, PU slowly while crew fixes drain hose and hard line
issues. Drain hose fixed, CRIH,Come online with water down coil to fluid pack, Coil fluid packed, come offline with pump, RIH for dry tag, tag at 6027' CTMD,
Come online down coil start cleaning out. Clean out down to 6225'. Can't establish any injection. Once we got bottoms up we shut in the choke and pressured up
on the well to 2500 psi, whp broke over and established injection. Start cooling down N2. Continue pumping water down coil injecting.,well locked up again not
able to inject, work coil past 6100'-6225' multiple times to try and get injectivity, no joy. RIH to 6225' pump 2 bbls out the coil, chase ooh at 80%.,POOH, Tagged
up, trap 2600 psi on well, swab shut, bleed down, pop off well.,MIRU HES Eline, Make up 4.5" CIBP. 3.71" OD X 1.25' L. CCL T/middle element 12.5'. Stab on
well, pt low/high 250/3000. RIH, tag at 6097'+ 13.2'= 6110' ELM to bottom of tools. Log up to 4500' Send log to town for corr elation. On depth to set plug (Ben
Siks). RIH to tag, pu get wt back CCL depth 6093.2',CCL t/ME 12.5'. Set plug @ 6105.7'. Good set. POOH,Tagged up, swab shut, bleed down, pop off well. Stack
back Eline. Set down Coil 10' lubricator, set down injector head secure well and location for the night. Job in progress.
3/18/2021 Travel to locatoin.,Arrive on location, Contact DSO, Inspect location, PTW, PJSM. Fire up equipment, let it warm up.,PU Injector head, 10' lubricator, Make up
(CTC 2.0" X .166') ( DFCV 2.0" X 1.160') ( STINGER 2.0" X 3.1') ( DJN 2.0" X .583') TOL= 5.1',Stab on well, PT low/high 250/3500, Swab valve froze again, only
able to get 13.5 turns on it. Got swab open 23.5 turns.,RIH, N2 online down coil at 0930. @ 4500' pumping @ 1500 scfm, RIH tag plug at 6105.7', Park here for
20 min Chase out of hole. Recovered 89 bbls of 93bbls. Trap 1400 psi on well.,Tagged up, swab shut, bleed down, pop off well, Stack lubricator down, Break
down tools, Set Injector head down.,MIRU Eline, Make up 30' X 2.25" bailer, mix up 5 gallons, 16ppg cement. Stab on well PT low/high,Open Well , WHP 1300,
RIH, Tag plug @ 6105', dump bail 8' cement on top of plug. Cement top +/- 6097'. POOH,Tagged up, swab shut, bleed down, pop off well. Stack back Eline for
the night. Job in progress.
3/19/2021 Travel to location,Arrive at Office, Check in, fill out PTW, do PJSM,Fire up equipment, let warm up, inspect location, PU lub and WLV, Make up GR/CCL, test
wire, good communication. Make up 8', 2 7/8", 6 spf, 60* phase, 15 gram Geo Razor gun. Stab on well, PT WLV/LUB 250/3500.,Open well, swab 23.5, WHP
1300. Start in hole. @ 350' grease started not working. Stop rih, trouble shoot grease skid,Got grease Skid working, Start RIH again. Tag cement at 6097.5', Log
up to 5500', Send log to town for correlation. Adjust -1'. On depth (Anthony McConkey). Pull up to CCL depth 6072.4. CCL t/top shot 13.6', CCL t/bottom shot
21.6'. Shoot 6086'-6094'. ITP 1320psi, 5 min 1350 psi, 10 min 1350 psi, 15 min 1350 psi,POOH, Tagged up, swab shut, bleed down, pop off well, All shots fired,
Dry Gun. RDMO Eline. Turn well over to production
3/25/2021 PTW, JSA and SIMOPS with HES/Fox Energy. Spot equip, rig up lubricator and N2 hard Lines. PT hard lines and lubricator to 250 psi low and 4000psi high.,RIH
w/GPT and tied into OHL. Found fluid level at 930' with 280 psi on tubing. Pushed fluid to 1010' with 3500 psi. Called town and discussed. Run on down hole to
see if we tag high. Tagged at 5950' which is 136' above open perf. Sat down on obstruction 3 times and it was sticky (overpulled 200 lb). Decision made to leave
3500 psi on tubing and check it in the morning. Used 458 gals of N2.,Rig down lubricator off tree and secure well. Will come back in the morning and check it.
3/26/2021 PTW/JSA. Rig Halliburton lubricator back up. PT to 250 low and 4000 psi high. TP - 3300 psi (left 3500 psi on tubing all night),RIH w/GPT w/2.75" wt bars and tie
into OHL. Found Fluid level at 1028' and tagged fill at 5950' with 3300 psi on well. Run correlation log and send to town. Call ed town and decision was made to get
slickline out and see if we can bail obstruction. POOH. Wait on Halliburton slickline.,Add HES SL on HES EL PTW added SL JSA. R igged up equipment and PT
lubricator to 250 psi low and 4000 psi high,RIH w/2-1/2"x10' pump bailer to 5950'. Got call from town to set plug in the morning and POOH with bailer. Got 3
pumps on and POOH. Bailer had mud that smelled and looked like wet cement/mud. Got a sample at office.,Rig slickline down completely and send back to HES
yard. HES E-Line truck stays and we will set plug in the morning
g
Set plug @ 6105.7'.
g
Shoot 6086'-6094'.
jp
Tag plug @ 6105', dump bail 8' cement on top of plug. Cement top +/- 6097'.
p
t 30' Set patch at 6120.5'-6132'.
Tag cement at 6097.5',
Shoot 6146'-6151'
3/27/2021 PTW and JSA. Rig lubricator back up. PT to 250 psi low and 3500 psi high. TP - 2800 psi,RIH w/3.71" OD CIBP, tie into OHL and tag fill at 5943'. Run correlation
log and send to town. Get ok to set plug at 5942' with 2800 psi on tubing. Spot and set plug at 5942'. Lost 200 line tension when plug set. Pick up 30' and go back
down and tag plug at 5942'. POOH. Setting tool looks good. Good set.,Mix cement. MU 2-1/2"x30' cement dump bailer. Had a few issues with dump bailer bottom
feed. Troubleshoot and fix bottoom feed on bailer system . Load bailer with 17 ppg cement.,RIH w/2-1/2"x30' cement dump bailer filled with 17 ppg cement (6 gal)
and tag plug at 5942'. Pick up 15' and dump 10' of cement on top of plug. POOH. Good dump. CIP (Cement in place)at 1330 hrs. Est Top of cement (TOC)
5932'.,Rig down lubricaor off tree and lay down. Break down toolsand make room for Pollard slick line. WOC
3/28/2021 ON LOCATION - TGSM - JSA - PERMIT
RIG UP .160 WIRE - PT LUB - GOOD
BEGIN BLEEDING WELL TO 0 PSI
RIH W/ TANDEM SWAB MADREL AND 4 CUPS TO 950'KB - BEGIN SWABBING TO 5900'KB,CHANGE OUT CUPS - ADD ONE SWAB MANDREL AND 3'
STEM IN BETWEEN - FLUID AT 3200'KB
2500'KB CUP CONFIGURATION WOULD NOT GO DOWN HOLE - POOH - REMOVE SWAB MANDREL
RIH W/ TANDEM SWAB MANDREL AND 6 CUPS TO 2500'KB COULD NOT FALL - POOH
REMOVE 2 CUPS,RIH W/ SAME FLUID AT 3200'KB BEGIN SWABBING TO 5926'KB
PULLING WEIGHT IS INCREASING 1500' FROM BOTTOM (3800 LBS W/ 500' FLUID)
RIH W/ SAME - TAG TOP OF CEMENT W/ SWAB CUPS AT 5926'KB - POOH
RIG DOWN W/L - SECURE WELL- Return to shop
3/31/2021 PTW, JSA and SIMOPS with HES and Fox Energy(N2). Rig up lubricator and hard lines. PT hard lines and lubricator to 250 psi low and 3500 psi high. TP - 0
psi,RIH w/GPT tool and tie into OHL. Tag TOC at 5932'. Found fluid level at 5849'. Run correlation log and send to town. Was told were 1' deep. adjusted 1' and
POOH. TP -0 psi surface.,RIH w/2-7/8"x5'Razar HC, 6 spf, 60 degree phase, tie into GPT log and tag at 5932' . Run correlation log and send to town. Get OK to
perf from 5900' to 5905' with 1103 psi on well. Pressured up tubing to 1103 psi, spot and fired gun. After 5 min - 1156 psi, 10 min - 1170 psi and 15 min - 1175
psi. POOH. All shots fired/Gun was wet.,Rig down off well. Secure well and turn it over to field. Move equipment to KDU-10 for Perf Job in the morning.
FOX Energy pumped 695 gals of N2.
p
Spot and set plug at 5942'.
gy( )
Tag TOC at 5932'.
(
- TAG TOP OF CEMENT W/ SWAB CUPS AT 5926'KB
ppg
Est Top of cement (TOC)
5932'.,
g
spot and fired gun.
p
perf from 5900' to 5905'
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A@E A@
@
Benjamin Hand Digitally signed by Benjamin Hand
Date: 2021.01.13 15:52:25 -09'00'Chelsea Wright Digitally signed by Chelsea Wright
Date: 2021.01.14 08:08:04 -09'00'
TD Shoe Depth: PBTD:
Jts.
1
1
113
X Yes No X Yes No 5
Fluid Description:
Liner hanger Info (Make/Model):Liner top Packer?:X Yes No
Liner hanger test pressure:X Yes No
Centralizer Placement:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp: X Yes No
Casing Rotated?X Yes No Reciprocated?X Yes No % Returns during job
Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Casing (Or Liner) Detail
Float Shoe 5 1/2
Rotate Csg Recip Csg Ft. Min. PPG9.2
Shoe @ 6303 FC @ Top of Liner 1575.286,259.00
Floats Held
6% KCL Polymer
CASING RECORD
County State Alaska Supv.Hauck / Riley
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.CLU 006RD Date Run 12-Jan-21
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
VAM HTTC 2.14 6,303.00 6,300.86
Csg Wt. On Hook: Type Float Collar:Baker No. Hrs to Run:10
9.2 4
100
1200FIRST STAGE10.36Tune Primed Spacer 45
89/92
1800
4.8
Halliburton
15.3 12
Bump press
CBL
Bump Plug?
6:43 1/13/2021 1,975
6,303.006,304.00
CEMENTING REPORT
Csg Wt. On Slips:
6% KCL Polymer
12 110
Type of Shoe:Baker Round noce Casing Crew:Weatherford
Baker HRD-E ZXP w/ FLEX LOCK V DG Liner Hanger
www.wellez.net WellEz Information Management LLC ver_04818br
2
2 on first jt then 1 every jt t/ jt # 113 floating in between collars
4.5'' Liner Jt 4 1/2 13.5 L-80 VAM HTTC 40.29 6,300.86 6,260.57
Float Collar 5 1/2 VAM HTTC 1.51 6,260.57 6,259.06
4.5'' Liner Jt 4 1/2 13.5 L-80 VAM HTTC 40.26 6,259.06 6,218.80
Landing Collar 5 1/2 VAM HTTC Baker 1.09 6,218.80 6,217.71
4.5'' Line Jts 4 1/2 13.5 L-80 VAM HTTC 4,608.63 6,217.71 1,609.08
Liner Hanger Packer 5 1/2 Vam HTTC Baker 33.80 1,609.08 1,575.28
1 ll 265 2.4
Class G 70 1.24
5
Samuel Gebert Hilcorp Alaska, LLC
GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: 907 777-8337
Fax: 907 777-8510
E-mail: sam.gebert@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510
Received By: Date:
DATE: 03/29/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
CLU-06RD (PTD 220-074)
PERFORATING RECORD 03/19/2021
Please include current contact information if different from above.
PTD: 2200740
E-Set: 34837
Received by the AOGCC 03/30/2021
03/30/2021
Samuel Gebert Hilcorp Alaska, LLC
GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: 907 777-8337
Fax: 907 777-8510
E-mail: sam.gebert@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510
Received By: Date:
DATE: 03/08/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
CLU 06RD (PTD 220-074)
FLUID LEVEL, PATCH SETTING RECORD, PERF RECORD 02/15/2021
Please include current contact information if different from above.
PTD: 2200740
E-Set: 34746
Received by the AOGCC 03/08/2021
03/09/2021
Hilenrp A1a.ka, UA.
Date: 02/08/2021
David Douglas Hilcorp Alaska, LLC
GeoTechnician 3800 CenterPoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
To: Alaska Oil & Gas Conservation Commission
Petroleum Geology Assistant
333 W 7th Ave Ste 100
Anchorage, AK 99501
DATA TRANSMITTAL
CLU-06RD (PTD 220-074)
Washed and Dried Well Samples
B Set (3 Boxes):
WELL
BOX
SAMPLE INTERVAL (FEET / MD)
CLU-06RD
BOX 1 OF 3
1740' - 3450' MD
CLU-06RD
BOX 2 OF 3
3450' - 5010' MD
CLU-06RD
BOX 3 OF 3
5010' - 6300' MD (TD)
Please include current contact information if different from above.
1 7 q 2-
RECEIVED
FEB 0 8 2021
AOGCC
Please acknowledge receipt by signing and returning one copy of this transmittal via Email or FAX to:
(907) 777-8510
Received 8}�- �` / /� Date:
i
David Douglas Hilcorp Alaska, LLC
GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510
Received By: Date:
Date: 02/01/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resources Technician
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
DATA TRANSMITTAL
CLU-06RD (PTD 220-074)
GEOLOG: EOW DRILLING REPORTS and MUDLOGS (01/08/2021 to 01/12/2021)
1.DAILY DRILLING REPORTS
2.FINAL EOW REPORT
3.DIGITAL DATA
4.LWD LOG PRINTS
5.MUDLOG PRINTS
6.SHOW REPORTS
Folder Contents:
Please include current contact information if different from above.
Received by the AOGCC 02/02/2021
PTD: 2200740
E-Set: 34641
Abby Bell 02/02/2021
Samuel Gebert Hilcorp Alaska, LLC
GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: 907 777-8337
Fax: 907 777-8510
E-mail: sam.gebert@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510
Received By: Date:
DATE: 01/29/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
CLU-06RD (PTD 220-074)
RCBL Radial Cement Bond Log 01/14/2021
Please include current contact information if different from above.
PTD: 2200740
E-Set: 34633
Received by the AOGCC 01/29/2021
Abby Bell 02/01/2021
David Douglas Hilcorp Alaska, LLC
GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal or fax to 907 777-8510.
Received By: Date:
Date: 1/26/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
CLU 06RD (PTD 220-074)
FINAL LWD FORMATION EVALUATION LOGS (01/08/2021 to 01/12/2021)
•DGR, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs)
•Final Definitive Directional Survey
SFTP Transfer - Data Folders:
Please include current contact information if different from above.
PTD: 2200740
E-Set: 34622
Received by the AOGCC 01/26/2021
Abby Bell 01/26/2021
1
Guhl, Meredith D (CED)
From:Schwartz, Guy L (CED)
Sent:Monday, February 1, 2021 3:53 PM
To:Ted Kramer
Cc:Donna Ambruz
Subject:RE: CLU -6RD, PTD# 220-074, Initial Completion
Ted,
Per our phone call you have approval to rig up CTU on the wellbore as proposed below. If SLB CT you will not need to
notify us of the BOPE test as per the new agreement.
Update the MOC form and make sure this email is on location. The CT FCO can be reported on the 10‐407 form when it
is submitted for this new well.
Also make sure all Nitrogen safety protocols all followed.
Regards ,
Guy Schwartz
Sr. Petroleum Engineer
AOGCC
907‐301‐4533 cell
907‐793‐1226 office
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation
Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged
information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended
recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to
you, contact Guy Schwartz at (907-793-1226 ) or (Guy.schwartz@alaska.gov).
From: Ted Kramer <tkramer@hilcorp.com>
Sent: Monday, February 1, 2021 3:34 PM
To: Schwartz, Guy L (CED) <guy.schwartz@alaska.gov>
Cc: Donna Ambruz <dambruz@hilcorp.com>
Subject: CLU ‐6RD, PTD# 220‐074, Initial Completion
Guy,
During the initial completion of the above well, the ST_B2 Sand was perforated from 6,125‐6,130’. Flow was not
sustained from this interval and a SL tag was made, finding fill had entered the well bore up to 5,938’. Attempts to bail
were made thinking it may be a bridge but little progress was made ( to 5,944’).
Hilcorp requests permission to put coil back on this well to clean it out and set a patch across these perforations.
Please let me know if this is agreeable to the AOGCC. There is a contingency in the completion Sundry to install a patch
but not for putting Coil back on the well. The precautions for using nitrogen will be the same as stated in the completion
Sundry. Basically the procedure will be:
1.) MIRU CTU. Pressure test BOP’s to 3500 psi.
2.) RU N2 pump to coil unit and pressure test lines.
3.) RIH W/ 1.75” coil (mud motor and bit if necessary). Clean pout well to PBTD ( 6,270’).
4.) Keep pressure on well to hold back Fill.
2
5.) RU E‐line on top of the Coil BOP stack.
6.) Pressure test E‐line lubricator to 250 psi low/ 3,500 psi high.
7.) PU, RIH with permeant isolation patch and place same across the open perforations (6,125’ – 6,130’).
8.) Pressure up on well to push any fluid back into perforations, Set patch.
9.) POH with setting tools. PU GPT Tool. RIH W/same to find fluid level. POOH.
10.) If Necessary, use coil and N2 to blow well dry Trapping 1200 psi on well. RDMO Coil tubing.
11.) RU E‐line. Pressure test lubricator to 2,000 psi high/ 250 psi low.
12.) PU perf guns, RIH and perf next interval; in the Sundry.
Sincerely,
Ted Kramer
Senior Operations Engineer
Hilcorp Alaska LLC
907‐777‐8420 (Office)
985‐867‐0665 (cell)
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed
above, then promptly and permanently delete this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission,
opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and
the recipient should carry out such virus and other checks as it considers appropriate.
STATE OF ALASKA
Reviewed By:
OIL AND GAS CONSERVATION COMMISSION
P.1.Supry �o ZGZI
BOPE Test Report for: CANNERY LOOP UNIT 06RD Comm
Contractor/Rig No.: Hilcorp 169 PTD#: 2200740 - DATE: 1/15/2021 - Inspector Adam Earl Insp Source
Operator: Hilcorp Alaska, LLC Operator Rep: Pederson / Riley Rig Rep: Van Evera / Deshotel Inspector
Type Operation: DRILL Sundry No: Test Pressures: Inspection No: bopAGE210121073616
Rams: Annular: Valves: MASP:
Type Test: BIWKLY 250/3500 - 250/3500- 250/3500, 1489 " Related Insp No:
TEST DATA
MISC. INSPECTIONS:
MUD SYSTEM:
ACCUMULATOR SYSTEM:
P/F
Visual Alarm
Time/Pressure P/F
Location Gen.:
P
Trip Tank
P-
P_ _
System Pressure 3025_ _
P
Housekeeping:
—P
Pit Level Indicators
-P_ .
P
Pressure After Closure -1700
P
PTD On Location
P
Flow Indicator
P
P
200 PSI Attained 19 -
P
Standing Order Posted
P
Meth Gas Detector
P
P '
Full Pressure Attained 85
P
Well Sign
P
H2S Gas Detector
—P _
P
Blind Switch Covers: All Stations"
P "
Drl. Rig
P
MS Misc
0
NA
Nitgn. Bottles (avg): 4 (a, 2500
P "
Hazard Sec.
P
ACC Misc 0
NA
Misc
NA
FLOOR SAFTY VALVES:
Quantity
P/F
Upper Kelly
- I
P—
Lower Kelly
1
P___
Ball Type
- _ 1
P
Inside BOP
1
P
FSV Misc
0
NA
BOP STACK:
CHOKE MANIFOLD:
Quantity
Size
P/F
Quantity
P/F
Stripper
0
NA
No. Valves 15 -
P "
Annular Preventer
1- 11"
P-
Manual Chokes I
P "
#1 Rams
1 2 7/8 x 5" "
P -
Hydraulic Chokes 1
P "
#2 Rams
-1 blind -
P
CH Misc 0 -
NA
#3 Rams
0
NA
#4 Rams
0
NA
— _— —
INSIDE REEL VALVES:
#5 Rams
0
NA
#6 Rams
0
NA
(Valid for Coil Rigs Only)
Choke Ln. Valves
3 1/8" __
P
Quantity
P
HCR Valves
—1—"
2 2 1/16",_3 1/8
P
Inside Reel Valves 0
NA
Kill Line Valves
2 2 1/16"
FP
Check Valve
0
NA
BOP Misc
0
NA
Number of Failures: 1 w Test Results
Remarks: Manual kill had to be functioned,FP, no issues, good test
Test Time 4
1.Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Initial Completion
2.Operator Name:4.Current Well Class:5.Permit to Drill Number:
Exploratory Development
3.Address:Stratigraphic Service 6.API Number:
7.If perforating:8.Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Will planned perforations require a spacing exception?Yes No
9.Property Designation (Lease Number):10. Field/Pool(s):
11.
Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD):
6,300'N/A
Casing Collapse
Structural
Conductor 7,950psi
Surface 3,830psi
Intermediate
Production 8,540psi
Liner
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
12. Attachments:Proposal Summary Wellbore schematic 13.Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14.Estimated Date for 15.Well Status after proposed work:
Commencing Operations:OIL WINJ WDSPL Suspended
16.Verbal Approval:Date:GAS WAG GSTOR SPLUG
Commission Representative: GINJ Op Shutdown Abandoned
Taylor Wellman 777-8449 Contact Name: Ted Kramer
Operations Manager Contact Email:
Contact Phone: 777-8420
Date:
Conditions of approval: Notify Commission so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other:
Post Initial Injection MIT Req'd? Yes No
Spacing Exception Required? Yes No Subsequent Form Required:
APPROVED BY
Approved by: COMMISSIONER THE COMMISSION Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
tkramer@hilcorp.com
4,172'6,280'4,155'390 N/A
N/A; N/A 4-1/2" liner top Packer @ 1,400'.
Perforation Depth TVD (ft):Tubing Size:
COMMISSION USE ONLY
Authorized Name:
Tubing Grade:Tubing MD (ft):
See Attached Schematic
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
FEE ADL60568, FEE ADL60569, ADL391790
220-074
50-133-20492-01-00
CLU-06RD
Cannery Loop Unit / Sterling Undefined Gas Pool
Length Size
CO 231
Hilcorp Alaska, LLC
3800 Centerpoint Dr, Suite 1400
Anchorage Alaska 99503
PRESENT WELL CONDITION SUMMARY
N/A
TVD Burst
N/A
9,020psi
MD
10,900psi
6,340psi
91'
1,600'
91'
1,600'
4,172'4-1/2"
9-5/8"
7"
91'
1,600'
6,300'
Perforation Depth MD (ft):
See Attached Schematic
4,900'
Authorized Title:
17.I hereby certify that the foregoing is true and the procedure approved herein will not
be deviated from without prior written approval.
Authorized Signature:
January 16, 2021
N/A
m
n
P
66
t
Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval.
By Samantha Carlisle at 3:11 pm, Jan 13, 2021
321-023
Digitally signed by Taylor
Wellman
DN: cn=Taylor Wellman,
ou=Users
Date: 2021.01.13 15:01:58 -09'00'
Taylor
Wellman
Initial
169 / CTU
Completion
*
gls 1/14/21
X
* CBL required over 4.5" liner (forward to AOGCC prior to perforating).
1/14/21
10-407 (final well report)
DLB 01/13/2021
Perforate
Guy Schwartz (verbal to run tieback only-- not to perforate)
DSR-1/14/21
3500 psi BOPE test (both CT and Rig 169)
X
Nitrogen displace/CT
Comm
1/15/21
dts 1/14/2021
JLC 1/15/2021
RBDMS HEW 1/27/2021
Well Prognosis
Well: CLU #06RD
Date: 1-13-2021
Well Name: CLU #06RD API Number: 50-133-20492-01
Current Status: Side Track Leg: N/A
Estimated Start Date: January 16th 2021 Rig: 169
Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd:
Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 220-074
First Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (C)
Second Call Engineer: Todd Sidoti (907) 777-8443 (O) (907) 632-4113 (C)
AFE Number: 201-04185C
Maximum Expected BHP: ~ 821 psi @ 4,371’ TVD (Based on normal gradient of 0.43
psi/ft and the TVD of the lowest
perforation)
Max. Potential Surface Pressure: ~ 390 psi @ 4,371’ TVD (Based on expected BHP and gas
gradient to surface (0.10psi/ft)
Brief Well Summary
CLU #06RD is a side track well targeting gas sands in the Beluga and Sterling formation. This new well reached
TD on 1-11-2021.
The purpose of this work/sundry is to run a CBL, 4-1/2” tieback string W/SSSV, jet the well dry with CT, and
perforate. This work will be performed by the drilling rig which is currently on the well.
Notes Regarding Wellbore Condition
x Well will be filled with 6% KCL
x E-line will complete CBL prior to starting sundry work. Electronic copy of CBL to be sent to AOGCC when
completed.
Safety Concerns
x Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people
could enter prior to Coil operation.
x Consider tank placement based on wind direction and current weather forecast (venting Nitrogen
during this job)
x Ensure all crews are aware of stop work authority
Drill Rig RIH 4-1/2” Tieback and SSSV Procedure (start of Sundry work)
1. NU and test BOP. 250 psi low / 2,500 psi high. Submit test report to AOGCC within 5 days.
2. PU and pull storm packer. Lay down same.
3. PU PBR seals, 4-1/2” Tie-back string, and SSSV and RIH.
4. Set SSSV at (+/-) 500’ MD.
5. Sting into the liner hanger, space out and land the Tie-back string.
6. Perform MIT-IA (7” x 4-1/2”) 2,000 psig for 30 minutes (on Chart).
7. ND BOP, NU Wellhead and pressure test same.
8. RDMO Rig 169.
(removing bottom single gate BOP for clearance ) MASP <3000 psi
OK gls
1/14/21
3500 psi (same as PTD)
Well Prognosis
Well: CLU #06RD
Date: 1-13-2021
Coiled Tubing Procedure
1. MIRU Coiled Tubing, PT BOPE to 3,500 psi Hi 250 Low. Notify AOGCC 24 hrs. in advance of BOP test.
2. RU N2 pumping unit to Coil.
3. PU, RIH W/ Jet Nozzle.
4. Drop ball and come online with N2 and jet well dry.
x Estimated volume of displaced 6% KCl is 95 bbls. To 6270’
5. RIH w/ coiled tubing and jet nozzle BHA and tag PBTD.
6. Once well is dry, trap 300 psi on well.
7. POOH w/ coil. LD BHA.
8. RDMO Coiled Tubing Unit.
E-Line Procedure
9. MIRU e-line and pressure control equipment. PT lubricator to 2,000 psi Hi 250 Low. Note that the
well is pressurized with nitrogen.
x Bleed pressure down to 275 psi. for perforating (30% underbalance).
10. PU RIH W/perf guns.
11. Proposed Perforated Intervals
Zone Top (MD) Base (MD)
Top (TVD) Bot. (TVD) Total Feet
ST_A11A ±5,897' ±5,918' ±4,171' ±4,192' 21'
ST_B1 ±6,050' ±6,093' ±4,281' ±4,315' 43'
ST_B2 ±6,122' ±6,167' ±4,336' ±4,371' 45’
a. Proposed perfs. also shown on the proposed schematic in red font.
b. Final Perfs tie-in sheet will be provided in the field for exact perf intervals.
c. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass
to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation.
d. Use Gamma/CCL to correlate.
e. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing
pressures before and after each perforating run (5, 10, 15 min).
f. These sands are governed by Conservation Order 231.
g. Sand intervals may be grouped or shot one at a time and flow tested to the system. If a
sand makes water, then a plug or an isolated patch may be set prior to moving up to the
next sand interval.
12. POOH.
13. RD e-line.
14. Turn well over to production. (Test SSV with-in 5 days of stable production on well – notify AOGCC
24hrs before testing)
Attachments:
1. Current Well Schematic
2. Proposed Well Schematic
3. Rig BOP
4. Coil BOP
5. Wellhead Drawing
6. Standard Well Procedure – N2 Operations
.0149 bbl/ft x 6270 ft = 94 bbls
±4,171'±4,192'21'ST_A11A ±5,897'±5,918'
ST_B1 ±6,050'±6,093'±4,281'±4,315'43'
ST_B2 ±6,122'±6,167'±4,336'±4,371'45’
and ScSSV
Note: all zones are above the Sterling
C1 gas storage pool (CINGSA)
(displace to Nitrogen)
_____________________________________________________________________________________
Updated by DMA 01-13-21
SCHEMATIC Cook Inlet Basin, Alaska
Middle Ground Shoal
Last Completed: 02-28-1992
Oil Well ->Water injector -> Gas producer
for Platform
Kenai CLU
CLU-06RD
PTD: 220-074
API: 50-133-20492-01-00
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm
9-5/8" Conductor 53.5 / P-110 / Unknown 9.95” Surf 91'
7" Surface 23 & 26 / L-80 / Unknown 6.151” Surf 1,600'
4-1/2" Production 13.5# / L-80 / VAM HTTC 3.920” Surf 6,300’
JEWELRY DETAIL
No Depth ID Item
1 1,400’ 4.176” Baker liner hanger/LTP system
OPEN HOLE / CEMENT DETAIL
7” (CLU-06) 280 xs 11.5 ppg litecrete
4-1/2” 107 bbls 12 ppg Type III Lead Cement
F/B 12 bbls 15.3 ppg Prem. G Tail
_____________________________________________________________________________________
Updated by DMA 01-13-21
SCHEMATIC Cook Inlet Basin, Alaska
Middle Ground Shoal
Last Completed: 02-28-1992
Oil Well ->Water injector -> Gas producer
for Platform
Kenai CLU
CLU-06RD
PTD: 220-074
API: 50-133-20492-01-00
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm
9-5/8" Conductor 53.5 / P-110 / Unknown 9.95” Surf 91'
7" Surface 23 & 26 / L-80 / Unknown 6.151” Surf 1,600'
4-1/2" Production 13.5# / L-80 / VAM HTTC 3.920” 1,400’ 6,300’
JEWELRY DETAIL
No Depth ID Item
1 500 SSSV
2 1,400’ 4.176” Baker liner hanger/LTP system
OPEN HOLE / CEMENT DETAIL
7” (CLU-06) 280 xs 11.5 ppg litecrete
4-1/2” 107 bbls 12 ppg Type I, II Lead Cement
F/B 12 bbls 15.3 ppg Prem. G Tail
Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Status
ST-A11A ±5,897' ±5,918' ±4,171' ±4,192' 21' Proposed TBD
ST-B1 ±6,050' ±6,093' ±4,281' ±4,315' 43' Proposed TBD
ST-B2 ±6,122' ±6,167' ±4,336' ±4,371' 45’ Proposed TBD
Coiled Tubing Services
Pressure Category 1 BOP Configuration
(0-3,500 psi)
Client: Hilcorp
Date: April 3rd, 2017
Drawn: Chad Barrett
Revision: 0
Well Category: CAT I
4-1/16" 10K Combi BOP
Top Set: Blind/Shear
Second Set: Pipe/Slip
Wellhead
4-1/16" 10K Conventional Stripper
4-1/16" 10K x Wellhead Adapter Flange
5K CO62 x 4-1/16" 10K Flange
5K CO62 Lubricator
4-1/16" 10K Flow Cross
Manual 2x2 Valve 1: 2" 1502 x 2-1/16" 10K Flange
Manual 2x2 Valve 2: 2-1/16" 10K x 2-1/16" 10K Flange
Manual 2x2 Valve 3: 2-1/16" 10K x 2-1/16" 10K Flange
Manual 2x2 Valve 4: 2" 1502 x 2-1/16" 10K Flange
21 3 4
WH PSI
2" 1502 x 2-1/16 10K
Flanged Valve
(Manual)
2-1/16 10K x 2-1/16
10K Flanged Valve
(Manual)
Kill Port
Coiled Tubing HR580 Injector Head & Gooseneck
Weight = 12,850 lbs
Coil Tubing BOP
Cannery Loop Unit
CLU #6
10/08/2020
Valve, Master, VG-200,
4 1/16 5M FE, HWO,
EE trim
Valve, Upper master,
VG-200,
4 1/16 5M FE, HWO, EE trim
Valve, Swab, VG-200
4 1/16 5M FE, HWO,
EE trim
Valve, Wing, VG-200,
3 1/8 5M FE, HWO,
EE trim
BHTA, Otis, 4 1/16 5M FE x
6.5 Otis quick union top
Starting head, Vetco-Custom-
C22BP, 11 5M x 7'’ SOW, w/
2- 2 1/16 5M SSO
Cannery Loop Unit
CLU #6
9 5/8 x 7 x 4 ½
Tubing hanger, Vetco Gray-
custom, 11 x 4 ½ BTC box
btm x 4 ½ BTC box top, w/ 5
1/2 od neck, 4'’ type H BPV
profile, DD-NL material
Valve, Wing, SSV, VG-200,
3 1/8 5M FE, w/ 15'’ operator
7'’
4 ½’’
Only 2 lockpins on wellhead
Not enough for conventional
tubing hanger
18'’
Grade level
STANDARD WELL PROCEDURE
NITROGEN OPERATIONS
12/08/2015 FINAL v1 Page 1 of 1
1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport.
2.) Notify Pad Operator of upcoming Nitrogen operations.
3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and
appropriate Safety Data Sheets (formerly MSDS).
4.) Document hazards and mitigation measures and confirm flow paths. Include review on
asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate
routing of flowlines, adequate venting and atmospheric monitoring.
5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport.
6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip
checks.
7.) Place signs and placards warning of high pressure and nitrogen operations at areas where
Nitrogen may accumulate or be released.
8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing
and casing pressures.
9.) Place pressure gauges upstream and downstream of any check valves.
10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct.
11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to
detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as
well that measures O2 levels.
12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential
Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank)
to 1,500 psi. Perform visual inspection for any leaks.
13.) Bleed off test pressure and prepare for pumping nitrogen.
14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns
are to be routed to the returns tank.
15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and
bleed down lines between well and Nitrogen Pumping Unit.
16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has
accumulated begin rig down of lines from the Nitrogen Pumping Unit.
17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned
and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport.
18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport.
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Re: Cannery Loop Field, Sterling Undefined Gas Pool, CLU-06RD
Hilcorp Alaska, LLC
Permit to Drill Number: 220-074
Surface Location: 114' FSL, 463' FEL, Sec 7, T5N, R11W, SM, AK
Bottomhole Location: 1283' FSL, 1865' FEL, Sec 8, T5N, R11W, SM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to redrill the above referenced development
well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs
run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment
of this well.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Jeremy M. Price
Chair
DATED this ___ day of December, 2020.
y,
JMPi
10
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: 6,495' TVD: 4,642'
4a. Location of Well (Governmental Section): 7. Property Designation:
Surface:
Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date:
Total Depth: 9. Acres in Property: 14. Distance to Nearest Property:
4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 38.7' 15. Distance to Nearest Well Open
Surface: x-272506 y- 2388566 Zone-4 20.7' to Same Pool: N/A
16. Deviated wells: Kickoff depth: 1600 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 53.8 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
6-1/8" 4-1/2" 13.5# L-80 Vam HTTC 5,095' 1,400' 1,372' 6,495' 4,642'
19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations)
Junk (measured):
6,031' (fill)
TVD
91'
2,322'
5,148'
Hydraulic Fracture planned? Yes No
20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis
Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements
Contact Name:
Contact Email:
Contact Phone:
Date:
Permit to Drill API Number: Permit Approval
Number: 50- Date:
Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales:
Samples req'd: Yes No Mud log req'd: Yes No
H2S measures: Yes No Directional svy req'd: Yes No
Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No
Post initial injection MIT req'd: Yes No
APPROVED BY
Approved by: COMMISSIONER THE COMMISSION Date:
Sr Pet Eng Sr Pet Geo Sr Res Eng
2467' to nearest unit boundary
1/2/2021
Authorized Name: Monty Myers
Authorized Title: Drilling Manager
Frank Roach
frank.roach@hilcorp.com
777-8413
18. Casing Program: Top - Setting Depth - BottomSpecifications
CLU-06RD
Cannery Loop Unit
Sterling Undefined Gas Pool
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
Hilcorp Alaska, LLC
114' FSL, 463' FEL, Sec 7, T5N, R11W, SM, AK FEE ADL60569, ADL324602, ADL391790
022224484
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
1489
1222' FSL, 2141' FEL, Sec 8, T5N, R11W, SM, AK
1283' FSL, 1865' FEL, Sec 8, T5N, R11W, SM, AK
N/A
923
1920
Total Depth MD (ft): Total Depth TVD (ft):
Cement Quantity, c.f. or sacks
Cement Volume MDSize
Plugs (measured):
(including stage data)
L -539 ft3 / T - 64 ft3
4,947' 3,229'
Effect. Depth TVD (ft):
Conductor/Structural 9-5/8"91'
8,320'5,277'
Length
Driven 91'
2,964'7"
Production
Liner
Casing
Multiple top 4,947'
Intermediate
2,964'
4-1/2"
Commission Use Only
307 sx
Effect. Depth MD (ft):
Authorized Signature:
547 sx
See cover letter for other
requirements.
Perforation Depth MD (ft):
21. I hereby certify that the foregoing is true and the procedure approved herein will not be
deviated from without prior written approval.
Surface
Perforation Depth TVD (ft):
GL / BF Elevation above MSL (ft):
4752' - 4757' 3202' - 3204'
8,124'8,124'
Stratigraphic Test
No Mud log req'd: Yes No
No Directional svy req'd: Yes No
Seabed ReportDrilling Fluid Program 20 AAC 25.050 requirements
BOP SketchDrilling Program Time v. Depth Plot Shallow Hazard Analysis
Single Well
Gas Hydrates
No Inclination-only svy req'd: Yes No
Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal
No
No
Form 10-401 Revised 3/2020 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
12.7.2020
By Samantha Carlisle at 12:52 pm, Dec 07, 2020
Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp Alaska, LLC, ou=Technical
Services - AK Drilling,
email=mmyers@hilcorp.com
Reason: I am approving this document
Date: 2020.12.07 12:47:20 -09'00'
Monty M
Myers
X
DSR-12/7/2020
133-20492-01-00
DLB 12/09/2020
X
*3500 psi BOPE test
* CBL required over 4.1/2" liner
*Sundry required for completion / perforating operations.
* SSSV required under 20 AAC 25.265(d)
FEE ADL60568 DLB
X
X
X
220-074
gls 12/10/20
pDevelopment - Gas
X
X
0/200000
12/10/2020
12/10/2020
CLU-06RD
Drilling Program
Cannery Loop Unit
Rev 1
December 4th, 2020
CLU-06RD
Drilling Procedure
Contents
1.0 Well Summary ...................................................................................................................... 2
2.0 Management of Change Information .................................................................................... 3
3.0 Tubular Program:................................................................................................................ 4
4.0 Drill Pipe Information: ......................................................................................................... 4
5.0 Internal Reporting Requirements ......................................................................................... 5
6.0 Planned Wellbore Schematic ................................................................................................ 6
7.0 Drilling / Completion Summary ............................................................................................ 7
8.0 Mandatory Regulatory Compliance / Notifications............................................................... 8
9.0 R/U and Preparatory Work ................................................................................................ 10
10.0 BOP N/U and Test.............................................................................................................. 10
11.0 Whipstock Running Procedure ........................................................................................... 12
12.0 Whipstock Setting Procedure.............................................................................................. 13
13.0 Drill 6-1/8” Hole Section ..................................................................................................... 15
14.0 Run 4-1/2” Production Liner .............................................................................................. 17
15.0 Cement 4-1/2” Production Liner ......................................................................................... 20
16.0 Wellbore Clean Up & Displacement ................................................................................... 23
17.0 Install Storm Packer ........................................................................................................... 24
18.0 RDMO ................................................................................................................................ 24
19.0 Run Completion Assembly.................................................................................................. 24
19.0 BOP Schematic ................................................................................................................... 25
20.0 Wellhead Schematic............................................................................................................ 26
21.0 Days Vs Depth .................................................................................................................... 27
22.0 Geo-Prog............................................................................................................................. 28
23.0 Anticipated Drilling Hazards .............................................................................................. 29
24.0 Hilcorp Rig 169 Layout....................................................................................................... 30
25.0 FIT/LOT Procedure............................................................................................................ 31
26.0 Choke Manifold Schematic ................................................................................................. 32
27.0 Casing Design Information ................................................................................................. 33
28.0 6-1/8” Hole Section MASP .................................................................................................. 34
29.0 Spider Plot (NAD 27) (Governmental Sections) .................................................................. 35
30.0 Surface Plat (NAD 27) ........................................................................................................ 36
Page 2 Version 1 December, 2020
CLU-06RD
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1.0 Well Summary
Well CLU-06RD
Pad & Old Well Designation Sidetrack of existing well CLU-06 (PTD# 200-033)
Planned Completion Type 4-1/2” Production Liner
Target Reservoir(s) Sterling
Planned Well TD, MD / TVD 6,495’ MD / 4,642’ TVD
PBTD, MD / TVD 6,415’ MD / 4,573’ TVD
Surface Location (Governmental) 114' FSL, 463' FEL, Sec 7, T5N, R11W, SM, AK
Surface Location (NAD 27) X=272506.87, Y=2388566.25
Top of Productive Horizon
(Governmental) 1222' FSL, 2141' FEL, Sec 8, T5N, R11W, SM, AK
TPH Location (NAD 27) X=276137.30, Y=2389598.63
BHL (Governmental) 1283' FSL, 1865' FEL, Sec 8, T5N, R11W, SM, AK
BHL (NAD 27) X=276414.46, Y=2389654.79
AFE Number 2014185
AFE Drilling Days 3 MOB, 14 DRLG
AFE Completion Days 10
AFE Drilling Amount $2,623,000
AFE Completion Amount $1,032,000
Maximum Anticipated Pressure
(Surface) 1489 psi
Maximum Anticipated Pressure
(Downhole/Reservoir) 1920 psi
Work String 4-1/2” 16.6# S-135 CDS-40
RKB – GL 38.7’ (20.7 + 18)
Ground Elevation 20.7’
BOP Equipment 11” 5M Annular BOP
11” 5M Double Ram
11” 5M Single Ram
1489 psi
RIG 169
Page 3 Version 1 December, 2020
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Drilling Procedure
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2.0 Management of Change Information
Page 4 Version 1 December, 2020
CLU-06RD
Drilling Procedure
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3.0 Tubular Program:
Hole
Section
OD (in) ID (in) Drift
(in)
Conn
OD (in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
6-1/8” 4-1/2” 3.920” 3.795” 5.0” 13.5 L-80 VAM HTTC 9020 8540 307
4.0 Drill Pipe Information:
Hole
Section
OD (in) ID (in) TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
All 4-1/2” 3.826 2.6875” 5.25” 16.6 S-135 CDS40 17,693 16,769 468k
All casing/liner installed will be new
Capacity = .0149 bbl/ft
Capacity=.01422 bbl / ft
Page 5 Version 1 December, 2020
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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
tab.
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.
5.2 Afternoon Updates
x Submit a short operations update each work day to Frank.Roach@hilcorp.com,
mmyers@hilcorp.com and cdinger@hilcorp.com
5.3 Intranet Home Page Morning Update
x Submit a short operations update each morning by 7am on the company intranet homepage. On
weekend and holidays, ensure to have this update in before 5am. Each rig w ill be assigned a
username to login with.
5.4 EHS Incident Reporting
x Notify EHS field coordinator.
1. This could be one of (3) individuals as they rotate around. Know who your EHS field
coordinator is at all times, don’t wait until an emergency to have to call around and figure
it out!!!!
a. John Coston: O: (907) 777-6726 C: (907) 227-3189
b. Matt Hogge: O: (907) 777-8418 C: (907) 227-9829
2. Spills: Keegan Fleming: O:907-777-8477 C:907-350-9439
x Notify Drlg Manager
1. Monty M Myers: O: 907-777-8431 C: 907-538-1168
x Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
x Send final “As -Run” Casing tally to Frank.Roach@hilcorp.com and cdinger@hilcorp.com
5.6 Casing and Cmt report
x Send casing and cement report for each string of casing to Frank.Roach@hilcorp.com and
cdinger@hilcorp.com
Page 6 Version 1 December, 2020
CLU-06RD
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6.0 Planned Wellbore Schematic
CLU 6
plugged.
ScSSV required
in completion
13.5 ppg FIT min
CBL required over 4.5" liner
Note: Rig 401 to follow 169 and run 4.5" tieback/ complete well (gls 12-9-20)
TD is above CINGSA gas storage pool .
gls12/9/20
(4642 ft TVD)
Page 7 Version 1 December, 2020
CLU-06RD
Drilling Procedure
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7.0 Drilling / Completion Summary
CLU-06RD is an S-shaped directional grassroots development well to be re-drilled in an easterly direction
from the existing CLU-06 well, utilizing the existing casing program down to ~1,600’ MD / ~1,743’ TVD.
The base plan is a directional wellbore, sidetracking from the parent well at 1,600’ MD. Maximum hole
angle will be 60° and TD of the well will be 6,495’ MD/ 4,642’ TVD, ending with 30° inclination left in the
hole.
Drilling operations are expected to commence approximately January 2 nd, 2021. The Hilcorp Rig # 169 will
be used to drill the wellbore then run casing and cement.
A 4-1/2” production liner will be run with ~200’ of liner lap inside the existing surface casing. The well will
be completed, post-rig, with a 4-1/2” tieback.
All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field
G&I facility for disposal / beneficial reuse depending on test results.
A separate sundry notice will be submitted to cover pre-rig P&A and wellbore preparation for the
sidetrack and for post-rig running of the completion assembly
General sequence of operations:
1. MOB Hilcorp Rig # 169 to well site
2. N/D tree, N/U & test 11” x 5M BOP.
3. PU and RIH with whipstock/window milling assy. Orient and set at ~1,600’ MD
4. Mill 6-1/8” window and 20’ of new formation. Displace to drilling mud.
5. Perform FIT.
6. Drill 6-1/8 ” hole section to 6,495’ MD. Perform Wiper trip.
7. POOH laying down drill pipe.
8. Run and cmt 4-1/2” production liner.
9. Make cleanout run & Displace well to brine.
10. Run kill string. Set storm packer @ 100 ’.
11. N/D BOP, N/U dry-hole tree, RDMO.
Reservoir Evaluation Plan:
1. Production Hole: GR + Res + Den/Neu (LWD).
2. Mud loggers from window exit to TD.
The base plan is a directional wellbore , sidetracking from the parent well at 1,600’ MD. Maximum hole p,gp,
angle will be 60° and TD of the well will be 6,495’ MD/ 4,642’ TVD, ending with 30° inclinatio n left in the g
hole.
NOTE: TD of well is approx 250 ft TVD above the CINGSA Gas Storage Pool (Sterling C)
(4642 ft TVD)
NOTE: Plug back for redrill operations are under Sundry 320-512 and will be
done by rig 401 prior.
(Rig 401)
gls 12/9/20
Page 8 Version 1 December, 2020
CLU-06RD
Drilling Procedure
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8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that our drilling and completion operations comply with the below AOGCC regulations. 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 of CLU-06RD . Ensure to provide
AOGCC 24 hrs notice prior to testing BOPs.
x The initial test of BOP equipment will be to 250/3500 psi & subsequent tests of the BOP equipment
will be to 250/3500 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, 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 ”
x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
Regulation Variance Requests:
Page 9 Version 1 December, 2020
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Drilling Procedure
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Summary of BOP Equipment and Test Requirements
Hole Section Equipment Test Pressure (psi)
6-1/8”
x 11” x 5M Annular BOP
x 11” x 5M Double Ram
o Blind ram in btm cavity
x Mud cross
x 11” x 5M Single Ram
x 3-1/8” 5M Choke Line
x 2-1/16” x 5M Kill line
x 3-1/8” x 2-1/16” 5M Choke manifold
x Standpipe, floor valves, etc
Initial Test: 250/3500
(Annular 2500 psi)
Subsequent Tests:
250/3500
(Annular 2500 psi)
x Primary closing unit: accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles).
x Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency
pressure is provided by bottled nitrogen.
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.
Additional requirements may be stipulated on APD and Sundry.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Ema il: jim.regg@alaska.gov
Guy Schwartz / Petroleum Engineer / (O): 907-793-1226 / (C): 907-301-4533 / Ema il: guy.schwartz@alaska.gov
Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / Ema il: melvin.rixse@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Ema il: victoria.loepp@alaska.gov
Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov
Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitne ssNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
Page 10 Version 1 December, 2020
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Drilling Procedure
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9.0 R/U and Preparatory Work
9.1 Separate sundries will be submitted that will include the following:
x P&A lower perfs
x Cut and recover 4-1/2” production casing from inside 7” surface casing.
x Set CIBP at ~1,600’ MD (5’ above nearest collar using CCL) to use as base for whipstock.
9.2 Level pad and ensure enough room for layout of rig footprint and R/U.
9.3 Layout Herculite on pad to extend beyond footprint of rig.
9.4 R/U Hilcorp Rig # 169, spot service company shacks, spot & R/U company man & toolpusher
offices.
9.5 RU Mud loggers on surface hole section for gas detection only. No samples required
9.6 After rig equipment has been spotted, R/U handi-berm containment system around footprint of
rig.
9.7 Mix mud for 6-1/8” hole section.
9.8 Verify 5 ” liners installed in mud pumps.
x HHF-1000 mud pumps are rated at 3457 psi (80%) / 306 gpm (100%) at 120 strokes
with 5 ” liners . Will be able to drill 6-1/8” hole section with (1) mud pump.
10.0 BOP N/U and Test
10.1 N/U 11” x 5M BOP as follows:
x BOP configuration from Top down: 11” x 5M annular BOP/11” x 5M double ram /11” x 5M
mud cross/11” x 5M single ram
x Double ram should be dressed with 2-7/8 x 5” VBRs in top cavity, blind ram in btm cavity.
x Single ram should be dressed with 2-7/8 x 5” VBRs.
x N/U bell nipple, install flowline.
x Install (1) manual valves & (1) HCR valve on kill side of mud cross.
x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual
valve.
10.2 Run 4-1/2” BOP test assy, land out test plug (if not installed previously).
x Test BOP to 250/3500 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min.
x Utilize both 4-1/2” and 2-7/8” test joints to be set up for production casing cleanout run.
3500 psi BOPE test
Sundry 320-512 (plug for Redrill)
Page 11 Version 1 December, 2020
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x Ensure to leave side outlet valves open during BOP testing to monitor well below test plug
and so pressure does not build up beneath the test plug.
10.3 R/D BOP test assy.
10.4 Install wear bushing in wellhead. Ensure ID of wear bushing is greater than upcoming 6-1/8”
drilling BHA and subsequent liner hanger/tieback equipment.
10.5 Continue mixing mud for 6-1/8” hole section.
10.6 R/U mud loggers for production hole section.
10.7 Rack back as much 4-1/2” DP in derrick as possible to be used while drilling the hole section.
Page 12 Version 1 December, 2020
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11.0 Whipstock Running Procedure
11.1 M/U window milling assembly and TIH w/ 4-1/2” DP out of derrick.
x Use a 6-1/8” taper mill and a 6-1/8” string mill above to ensure whipstock assy will pass
freely.
x Ensure BHA components have been inspected previously.
x Caliper and drift all BHA components before running them in the hole.
x Drift DP prior to RIH.
x Lightly wash and ream any tight spots noted.
11.2 TIH to CIBP (~1600’ MD). Note that this was a wireline measurement so actual depth tagged
may vary slightly. Keep up with the # of joints picked up so we know where we are.
11.3 Pressure test casing to 3000 psi / 30 min. Chart record casing test & keep track of the amount of
fluid pumped. Stage up to 3000 psi in 200 psi increments.
11.4 CBU & circ at least (1) hi-vis sweep to remove any debris created by the clean out run.
Anything left in the wellbore could affect the setting of the Whipstock.
11.5 TOH.
11.6 Make up mills on a joint of HWDP.
11.7 RIH & set in slips.
11.8 Make up float sub, install float. Make up directional tools for whipstock orientation.
11.9 RIH 2 stands and shallow test MWD tools. POOH, leaving assembly hanging in the elevators,
and stand back on floor.
11.10 Bring Whipstock to rig floor on the pipe skate. Do not slam into bottom of Whipstock with pipe
skate.
11.11 Pick up Whipstock per Baker rep using the Baker Whipstock handling system using air hoist.
Allow assy to hang while Baker Rep inspects and removes shear screws as needed and any safety
screws.
Note: Confirm number of remaining shear screws with Baker rep before proceeding to make up mills to
whipstock.
Note: Confirm proper mill shear bolt with Baker rep before installing.
11.12 If needed, open BOP Blinds.
7" CIBP @ 1600 ft .
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11.13 Run the Whipstock in the hole, install safety clamp as per Baker Rep, and install hole cover
wrap.
11.14 Release pick up system at this point, Make up mills.
11.15 With the top drive, pick the assembly and position the starting mill to align with the hole in the
slide. The Baker Rep will instruct the driller when the slot is lined up, the shear bolt then can be
made up by the Baker Rep.
11.16 The assembly can now be picked up to ensure that the shear bolt is tight.
11.17 If not done yet, scribe tools to orient MWD equipment to whipstock tray.
11.18 Remove the handling system.
11.19 Slowly run in the hole as per Baker Rep. Run extremely slow through the BOP & wear bushing.
11.20 Run in hole at 1 ½ to 2 minutes per stand.
11.21 Fill every 30 stands or as needed, do not rotate or work the string unnecessarily.
11.22 Call for Baker Rep. 15 – 10 stands before getting to bottom.
11.23 Orient whipstock, ~60° right-of-high-side, at least 30-45’ above CIBP.
12.0 Whipstock Setting Procedure
12.1 With the bottom of the Whipstock 30 – 45’ above the CIBP, measure and record P/U and S/O
weights.
12.2 Orient Whipstock to desired direction by turning DP in ¼ round increments. P/U and S/O on DP
to work all torque out. Orient the whipstock 60°R of high side.
12.3 Once whipstock is in desired orientation, slack off and tag CIBP to set Bottom Trip Anchor.
12.4 Set down 12-15K on anchor to trip, P/U 5-7K maximum overpull to verify anchor is set. The
window mill can then be sheared off by slacking off weight on the Whipstock shear bolt.
12.5 P/U 5-10’ above top of Whipstock.
12.6 Displace to 9.0 ppg 6% KCl/PHPA drilling fluid.
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12.7 Record P/U, S/O weights, and free rotation. Slack off to top of whipstock and with light weight
and low torque. Mill window. Utilize 4 ditch magnets on the surface to catch metal cuttings.
12.8 Install catch trays in shaker underflow chute to help catch iron.
12.9 Keep iron in separate bbls. Record weight of iron recovered on ditch magnets.
12.10 Estimated metal cuttings volume from cutting window:
7”
26# L-80 Cuttings Weight
Window
Length Casing Weight Min (lbs) Avg (lbs) Max (lbs)
13 26# 72 99 126
12.11 Drill approx. 20’ rat hole to accommodate the drilling assembly. Ream window as needed to assure
there is little or no drag. After reaming, shut off pumps and rotary (if hole conditions allow) and
pass through window checking for drag.
12.12 CBU and condition mud for FIT
12.13 Conduct FIT to 13.5 ppg EMW.
Note: Offset field test data predicts frac gradients at the window to be between 12 ppg and 15 ppg.
A 13.5 ppg FIT results in a 4.5 ppg kick tolerance while drilling the interval with a 9.0 ppg fluid
density.
Kick tolerance (13.5 -9.0) * (1523/4642) = 1.47
12.14 POOH. Gauge Mills for wear.
12.15 Should a second run be required pick up the following BHA.
Back Up M ills Connection Length O.D.
WINDOW MILL 3 ½ REG-P X MILL 0.98 6.13
NEW LOWER WATERMELON MILL 3 ½ IF-B X 3 ½ REG-B 5.5 6.00
FLEX JOINT 3 ½ IF-B X 3 ½ IF-P 6.5 4.75
UPPER WATERMELON MILL 3 ½” IF-B X 3 ½” IF-P 5.83 6.13
FLOAT SUB 3 ½” IF-B X 3 ½” IF-P 3.00 4.75
XO sub and 30 jts-HWDP 4 ½” CDS40-B X 3 ½” IF-P 900’ 5.25
CONNECTIONS AND OD’s ON TUBULARS ARE SUBJECT TO CHANGE. BHA’S SHOW SPECIFIC CONNECTIONS AS AN EXAMPLE ONLY!
Start Sidetrack
Mill window
________________________________________________________________________________________________________________________________
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13.0 Drill 6-1/8 ” Hole Section
13.1 Ensure BHA components have been inspected previously.
13.2 Drift and caliper all components before M/U. Visually verify no debris inside components that
cannot be drifted.
13.3 TIH, conduct shallow hole test of MWD and confirm LWD tools functioning properly.
13.4 Ensure TF offset is measured accurately and entered correctly into the MWD software.
13.5 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
13.6 Workstring will be 4.5” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to drill
the entire open hole section without having to pick up pipe from the pipeshed.
13.7 6-1/8” BHA: Triple Combo GR/Res/Den/Neu + PWD
13.8 6-1/8” hole section mud program summary:
Weighting material to be used for the hole section will be salt and calcium carbonate. Additional
calcium carbonate will be on location to weight up the active system (1) ppg above highest
anticipated MW.
Pason PVT will be used thro ughout 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.
System Type: 9.0 ppg 6% KCL PHPA fresh water based drilling fluid.
Properties:
MD Mud
Weight Viscosity Plastic
Viscosity Yield Point pH HPHT
1,600’- 6,495’ 9.0 – 11.0 40-53 15-25 15-25 8.5-9.5 11.0
NOTE: See Page 34. Highest expected MWE pressures are 8.6 ppg based on original and nearby wells.
DLB
9.0 – 11.0–
g
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System Formulation: 6% KCL EZ Mud DP
Product Concentration
Water
KCl
Caustic
BARAZAN D+
EZ MUD DP
DEXTRID LT
PAC-L
BARACARB 5/25/50
BAROID 41
ALDACIDE G
BARACOR 700
BARASCAV D
0.905 bbl
22 ppb (29 K chlorides)
0.2 ppb (9 pH)
1.25 ppb (as required 18 YP)
0.75 ppb (initially 0.25 ppb)
1-2 ppb
1 ppb
15 - 20 ppb (5 ppb of each)
as required for a 9.0 – 10.0 ppg
0.1 ppb
1 ppb
0.5 ppb (maintain per dilution rate)
13.9 TIH w/ 6-1/8” directional assy to top of window. Shallow test MWD and LWD on trip in.
13.10 Drill 6-1/8 ” hole section to 6,495’ MD / 4,642’ TVD
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Pump at 225 - 300 gpm. Ensure shaker screens are set up to handle this flowrate.
x Keep swab and surge pressures low when tripping.
x Make wiper trips every 1000’ unless hole conditions dictate otherwise.
x On the second or third 1000’ interval (~4,000’ MD), perform wiper trip back to the window.
x Ensure shale shakers are functioning properly. Check for holes in screens on connections.
x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10.
x Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed
necessary.
13.11 At TD; pump sweeps, CBU, and pull a wiper trip back to the window.
13.12 Once back on bottom after wiper trip, CBU to condition hole for casing run.
13.13 POOH LDDP and BHA
13.14 2-7/8” x 5-1/2” VBRs previously installed in BOP stack and tested with 4-1/2” test joint.
VBR installed...
2-7/8” x 5-1/2 ” VBRs previously installed in BOP stack and tested with 4-1/2” test joint.
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14.0 Run 4-1/2 ” Production Liner
14.1. R/U Weatherford 4-1/2” casing running equipment.
x Ensure 4-1/2” VAM HTTC x CDS 40 crossover on rig floor and M/U to FOSV.
x R/U fill up line to fill casing while r unning.
x Ensure all casing has been drifted prior to running.
x Be sure to count the total # of joints before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
14.2. P/U shoe joint, visually verify no debris inside joint.
14.3. Continue M/U & thread locking shoe track assy consisting of:
x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked).
x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked).
x (1) Joint with landing collar bucked on pin end & threadlocked (coupling also thread locked).
x Centralizers will be pre-installed on shoe joint, FC joint, and LC joint.
x Leave centralizers free floating so that they can slide up and down the joint.
x Ensure proper operation of float shoe and float collar.
x Utilize a collar clamp until weight is sufficient to keep slips set properly
14.4. Continue running 4-1/2 ” production liner
x Fill casing while r unning using fill up line on rig floor.
x Use “API Modified” thread compound. Dope pin end only w/ paint brush.
x Install solid body centralizers on every joint to the first joint below the window. Leave the
centralizers free floating.
4-1/2”HTTC M/U torques
Casing OD Minimum Maximum Yield Torque
4-1/2” 6,910 ft-lbs 6,500 ft-lbs 8,400 ft-lbs
9350 ft lbs
14400 ft lbs
Optimum = 8130 ft-lbs
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14.6. Ensure to run enough liner to provide for approx 200’ overlap inside 7” casing. Ensure
hanger/pkr will not be set in a 7” connection.
14.7. Circulate one liner volume at 7” window prior to going into open hole. Stage pumps up slowly
and monitor for losses. Do not exceed 60% of the nominal liner hanger setting pressure.
14.8. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
20, & 30 rpm.
14.9. Before picking up Baker ZXHD liner hanger / packer assy, count the # of joints on the pipe deck
to make sure it coincides with the pipe tally. Confirm shear pins and shear values with Baker rep.
14.10. M/U Baker ZXHD line r top packer. Fill liner tieback sleeve with “Xanplex ”, ensure mixture is
thin enough to travel past the HRD-E tool and down to the packoff. Wait 30 min for mixture to
set up.
14.11. RIH one stand and circulate a minimum of 1-1/2 liner volumes. Note weight of liner and obtain
up and down weights of liner before continuing.
14.12. RIH w/ liner on DP no faster than 1 min / stand. Watch displacement carefully and avoid
surging the hole. Slow down running speed if necessary.
14.13. M/U top drive and fill pipe while lowering string every 10 stands.
14.14. Set slowly in and pull slowly out of slips.
14.15. Continue to fill the string every 10 joints while running liner in open hole. Do not stop to fill
casing.
14.16. P/U the cmt stand and tag bottom with the liner shoe. P/U 2’ off bottom. Note slack-off and
pick-up weights. Record rotating torque values at 10, 20, & 30 rpm.
14.17. Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting
pressure. Circ and condition mud with the liner on bottom. Reduce the low end rheology of the
drilling fluid by adding water and thinners.
14.18. Reciprocate & rotate string if hole conditions allow. Circ until hole and mud is in good
condition for cementing.
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15.0 Cement 4-1/2 ”Production Liner
15.1. Hold a pre-job safety meeting over the upcoming cmt 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 cmt unit at acceptable rates.
x Pump 20 bbls of freshwater through all of Cementers equipment, taking returns to
cuttings bin, prior to pumping any fluid downhole
x How to handle cement returns at surface.
x Which pump will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Positions and expectations of personnel involved with the cmt operation.
x Document efficiency of all possible displacement pumps prior to cement job.
15.2. Attempt to reciprocate the casing during cmt operations until hole gets sticky
15.3. Pump 5 bbls of 10.5 ppg Mud Push spacer.
15.4. Test surface cmt lines to 4750 psi.
15.5. Pump remaining 40 bbls 10.5 ppg Mud Push spacer.
15.6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed
weight. Job is designed to pump 20% OH excess.
Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designedpp p
weight. Job is designed to pump 20% OH excess.
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Production CEMENT CALCULATIONS
CSG BTM (ft) 6,495
CSG
Size 4 1/2
Section: Calculation: Vol
(BBLS)
Vol
(ft3)
LEAD:
200’ x .019 bpf = 3.72 20.9 7" x 4-1/2"
200’ DP x 7” csg:
LEAD:
200’ x .019 bpf = 3.72 20.9 7" x 4-1/2"
200’ Liner Lap:
LEAD: (5,995’ – 1,600’) x .0 17 bpf x
1.20 = 88.46 496.7 6-1/8" OH x 4-1/2"
Liner annulus:
Total LEAD: 95.90 538.5
TAIL: (6,495’-5,995’) x .017 bpf x 1.20
= 10.07 56.5 6-1/8" OH x 4-1/2"
Liner annulus:
TAIL: 80 x .015 bpf = 1.22 6.8 4-1/2” Shoe track:
Total TAIL: 11.29 63.3
Total Cement: 107.58 604.0
15.7. Drop drillpipe dart and displace with drilling mud.
15.8. Pump cement at max rate of 5 bbl/min. Reduce pump rate to 2-3 bpm prior to latching DP dart
into liner wiper plug. Note plug departure from liner hanger running tool and resume pumping at
full displacement rate. Displacement volume can be re-zeroed at this point
15.9. If elevated displacement pressures are encountered, position liner at setting depth and cease
reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman
immediately of any changes. Reduce pump rate as required to avoid packoff.
15.10. Bump the plug and pressure up to up as required by Baker procedure to set the liner hanger
(ensure pressure is above nominal setting pressure, but below pusher tool activation pressure).
Hold pressure for 3-5 minutes.
15.11. Slack off total liner weight plus 30k to confirm hanger is set.
1400 ft DP = .01422 x 1400 ft = 20 bbls
Displacement for 4.5" liner = 6400 - 1400 (.0149 bbl/ft)
above liner hanger
Approx ...
=74bbls
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15.12. Do not overdisplace by more than ½ shoe track (~1 bbls). Shoe track volume is 1.8 bbls.
15.13. Continue pressuring up to activate LTP pusher tool and set packer with running tool in
compression.
15.14. Pressure up to 4,500 psi to neutralize the pusher tool and release the running tool (HRD-E) from
the liner.
15.15. Bleed pressure to zero to check float equipment.
15.16. P/U past free-travel verify setting tool is released, confirmed by loss of liner weight.
15.17. Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS
nipple. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the
pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be
enough to overcome hydrostatic differential at liner top).
15.18. Immediately with the loss of pressure and before DP reaches zero, initiate circulation while
picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to
wellbore clean up rate until the sleeve area is thoroughly cleaned.
15.19. Pick up to the high-rate circulation point above the tieback extension, mark the pipe for
reciprocation, do not re-tag the liner top, and circulate the well clean.
15.20. Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from
DP.
15.21. POOH, LDDP. Verify the liner top packer received the required setting force by inspecting the
rotating dog sub.
Backup release from liner hanger:
15.22. If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise) torque will
have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure
and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear
screws.
15.23. NOTE: Some hole conditions may require movement of the drillpipe to “work” the torque down
to the setting tool.
15.24. After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then
proceed slacking off set-down weight to shear second set of shear screws. The top sub will drop
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1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up
with workstring to release collet from the profile.
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 Frank.Roach@hilcorp.com and
mmyers@hilcorp.com . This will be included with the EOW documentation that goes to the AOGCC.
16.0 Wellbore Clean Up & Displacement
16.1. M/U casing clean out assy complete with casing scraper assys for each size casing in the hole.
x 3-1/2” bit or mill
x Casing scraper & brush for 4-1/2 ” 13.5# tubulars
x +/- 5100’ 2-7/8” PH-6 workstring.
x Casing scraper & brush for 7” 2 6# casing
x 4-1/2” DP to surface.
16.2. TIH & clean out well to landing collar (+/- 6,730’ MD).
x Circulate as needed on trip in if string begins to take weight.
x Circulate hi-vis sweeps as necessary to carry debris out of wellbore.
x Ensure 3-1/2” bit is worked down to the landing collar.
x Space out the cleanout BHA so that the 3-1/2” bit reaches the 4-1/2” landing collar when
crossover/7” casing scraper is +/- 30’ above the 4-1/2” liner top.
16.3. After wellbore has been cleaned out satisfactorily using mud, test casing to 2500 psi / 30 min.
Ensure to chart record casing test.
16.4. Displace drilling fluid in wellbore with a hi-vis pill followed by 6% KCl completion fluid.
Page 24 Version 1 December, 2020
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16.5. TOH w/ clean out assy. LDDP, casing scraper, and crossover from drillpipe to 2-7/8” PH-6
workstring. 2-7/8” workstring will be left in hole for rig 401 to use.
17.0 Install Storm Packer
17.1 PU additional 2-7/8” workstring and RIH t/ ~120’ above tag depth (~6,730’ MD).
17.2 MU 7” storm packer to 2-7/8” workstring used in above cleanout and RIH 1 stand.
17.3 Set storm packer and pressure test from below to 2,500 psi / 5 min to confirm seal.
17.4 Release from storm packer and LD running tool.
18.0 RDMO
18.1 ND BOPE, NU adapter flange and dry-hole tree, test void.
18.2 RDMO
19.0 Run Completion Assembly
19.1 Run 4-1/2” tieback completion assembly and test as per separate Approved Completion Sundry.
(separate sundry )
______________________________________________________________________________________________________________________________________
Rig 401 to run tieback and complete well. SSSV required.
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19.0 BOP Schematic
VBR
BLINDS
VBR
Page 26 Version 1 December, 2020
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20.0 Wellhead Schematic
(with test plug) see 320-512 sundry
Current Wellhead.
NOTE: rig 401 to leave dry hole tree after pulling 4 1/2"
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21.0 Days Vs Depth
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22.0 Geo-Prog
_-------- 6494ft
SUPERCEDED
gls 12/9/20
See attached updated GEO prognosis with Storage sand depths
Page 29 Version 1 December, 2020
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23.0 Anticipated Drilling Hazards
6-1/8” Hole Section:
Lost Circulation:
Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix
LCM pills at moderate product concentrations.
Hole Cleaning:
Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary.
Optimize solids control equipment to maintain density and minimize sand content. Maintain YP
between 20 - 30 to optimize hole cleaning and control ECD.
Wellbore stability:
Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque
reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl
in system for shale inhibition.
Coal Drilling:
The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The
need for good planning and drilling practices is also emphasized as a key component for success.
x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections.
x Use asphalt-type additives to further stabilize coal seams.
x Increase fluid density as required to control running coals.
x Emphasize good hole cleaning through hydraulics, ROP and system rheology.
H2S:
H2S is not present in this hole section.
No abnormal temperatures are present in this hole section.
Page 30 Version 1 December, 2020
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24.0 Hilcorp Rig 169 Layout
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25.0 FIT/LOT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT/LOT:
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.
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26.0 Choke Manifold Schematic
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27.0 Casing Design Information
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28.0 6-1/8” Hole Section MASP
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29.0 Spider Plot (NAD 27) (Governmental Sections)
Note: TD of well CLU 6 RD
is 250 TVD above storage pool
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30.0 Surface Plat (NAD 27)
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!
" #$##
%
&'
%
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03757501125150018752250262530003375375041254500487552505625True Vertical Depth (750 usft/in)375 750 1125 1500 1875 2250 2625 3000 3375 3750 4125 4500 4875 5250 5625 6000 6375 6750 7125 7500Vertical Section at 73.00° (750 usft/in)CLU-06RD wp08 tgt1150020002500300035004000450050005500600065007000750080008320Cannery Loop Unit 064 1/2" x 6 1/8"15002000250030003500400045005000550060006495CLU 06RD wp08KOP: 12.3º/100' : 1600' MD, 1523.6'TVD : 60° RT TFEnd Dir : 1617' MD, 1537.24' TVDStart Dir 2º/100' : 1637' MD, 1553.17'TVDStart Dir 4º/100' : 1877' MD, 1738.07'TVDEnd Dir : 2379.83' MD, 2077.02' TVDStart Dir 3.5º/100' : 5695.99' MD, 4036.55'TVDEnd Dir : 6375.39' MD, 4538.7' TVDTotal Depth : 6494.67' MD, 4642' TVDCL_ST_X1_MARKERCL_ST_X2_MARKERCL_ST_A1-2_CCL_ST_A2_MKRCL_ST_A3_MKRCL_ST_A4_MKRCL_ST_A5_MKRCL_ST_A6_MKRCL_ST_A7_MKRCL_ST_A8_MKRCL_ST_A9_MKRCL_ST_A10_MKRCL_ST_A11ACL_ST_B1_MKRCL_ST_B2_MKRHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Cannery Loop Unit 06Ground Level: 20.70+N/-S+E/-WNorthingEastingLatittudeLongitude0.00 0.002388566.25 272506.8760° 31' 55.267 N 151° 15' 47.217 WSURVEY PROGRAMDate: 2020-10-07T00:00:00 Validated: Yes Version: Depth FromDepth ToSurvey/PlanTool191.70 1600.00CLU 06 (MWD) (Cannery Loop Unit 06)3_MWD1600.00 2000.00 CLU 06RD wp08 (Cannery Loop Unit 06RD) 3_MWD_Interp Azi+Sag2000.00 6494.67 CLU 06RD wp08 (Cannery Loop Unit 06RD) 3_MWD+IFR1+MS+SagFORMATION TOP DETAILSTVDPathTVDssPathMDPathFormation2628.76 2590.06 3313.55 CL_ST_X1_MARKER2782.53 2743.83 3573.78 CL_ST_X2_MARKER3012.70 2974.00 3963.30 CL_ST_A1-2_C3151.26 3112.56 4197.79 CL_ST_A2_MKR3418.06 3379.36 4649.30 CL_ST_A3_MKR3469.65 3430.95 4736.61 CL_ST_A4_MKR3668.72 3630.02 5073.50 CL_ST_A5_MKR3766.34 3727.64 5238.70 CL_ST_A6_MKR3881.09 3842.39 5432.90 CL_ST_A7_MKR3939.98 3901.28 5532.56 CL_ST_A8_MKR4005.41 3966.71 5643.29 CL_ST_A9_MKR4065.81 4027.11 5744.53 CL_ST_A10_MKR4151.47 4112.77 5877.16 CL_ST_A11A4229.81 4191.11 5988.92 CL_ST_B1_MKR4304.87 4266.17 6089.56 CL_ST_B2_MKRREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Cannery Loop Unit 06, True NorthVertical (TVD) Reference:CLU-06RD @ 38.70usft (HEC 169)Measured Depth Reference: CLU-06RD @ 38.70usft (HEC 169)Calculation Method:Minimum CurvatureProject:Kenai C.I.U.Site:Cannery Loop Unit #1 PadWell:Cannery Loop Unit 06Wellbore:Cannery Loop Unit 06RDDesign:CLU 06RD wp08Kenai C.I.U.Cannery Loop Unit #1 PaCannery Loop Unit 06Cannery Loop Unit 06RDCLU 06RD wp085.784CASING DETAILSTVD TVDSS MD Size Name4642.00 4603.30 6494.67 4-1/2 4 1/2" x 6 1/8"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 1600.00 36.11 52.79 1523.60 223.63 294.74 0.00 0.00 347.24 KOP: 12.3º/100' : 1600' MD, 1523.6'TVD : 60° RT TF2 1617.00 37.20 55.79 1537.24 229.54 302.98 12.30 60.00 356.85 End Dir : 1617' MD, 1537.24' TVD3 1637.00 37.20 55.79 1553.17 236.34 312.98 0.00 0.00 368.40 Start Dir 2º/100' : 1637' MD, 1553.17'TVD4 1877.00 41.98 55.16 1738.07 323.03 438.92 2.00 -5.00 514.19 Start Dir 4º/100' : 1877' MD, 1738.07'TVD5 2379.83 53.78 77.32 2077.02 465.07 778.33 4.00 62.24 880.29 End Dir : 2379.83' MD, 2077.02' TVD6 5695.99 53.78 77.32 4036.55 1052.16 3388.39 0.00 0.00 3547.96 Start Dir 3.5º/100' : 5695.99' MD, 4036.55'TVD7 6375.39 30.00 77.50 4538.70 1150.48 3827.91 3.50 179.78 3997.02 CLU-06RD wp08 tgt1 End Dir : 6375.39' MD, 4538.7' TVD8 6494.67 30.00 77.50 4642.00 1163.39 3886.14 0.00 0.00 4056.48 Total Depth : 6494.67' MD, 4642' TVD
-1000-667-333033366710001333166720002333South(-)/North(+) (500 usft/in)-333 0 333 667 1000 1333 1667 2000 2333 2667 3000 3333 3667 4000 4333West(-)/East(+) (500 usft/in)CLU-06RD wp08 tgt1Cannery Loop Unit 069 5/8"4 1/2" x 6 1/8"25050075010001250150017502 0 0 0
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4 2 5 045004642CLU 06RD wp08KOP: 12.3º/100' : 1600' MD, 1523.6'TVD : 60° RT TFEnd Dir : 1617' MD, 1537.24' TVDStart Dir 2º/100' : 1637' MD, 1553.17'TVDStart Dir 4º/100' : 1877' MD, 1738.07'TVDEnd Dir : 2379.83' MD, 2077.02' TVDStart Dir 3.5º/100' : 5695.99' MD, 4036.55'TVDEnd Dir : 6375.39' MD, 4538.7' TVDTotal Depth : 6494.67' MD, 4642' TVDProject: Kenai C.I.U.Site: Cannery Loop Unit #1 PadWell: Cannery Loop Unit 06Wellbore: Cannery Loop Unit 06RDPlan: CLU 06RD wp08WELL DETAILS: Cannery Loop Unit 06Ground Level: 20.70+N/-S +E/-W NorthingEastingLatittude Longitude0.000.002388566.25 272506.87 60° 31' 55.267 N 151° 15' 47.217 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Cannery Loop Unit 06, True NorthVertical (TVD) Reference:CLU-06RD @ 38.70usft (HEC 169)Measured Depth Reference:CLU-06RD @ 38.70usft (HEC 169)Calculation Method:Minimum CurvatureCASING DETAILSTVD TVDSS MD Size Name4642.00 4603.30 6494.67 4-1/2 4 1/2" x 6 1/8"
-1000-667-333033366710001333166720002333South(-)/North(+) (500 usft/in)-333 0 333 667 1000 1333 1667 2000 2333 2667 3000 3333 3667 4000 4333West(-)/East(+) (500 usft/in)CLU-06RD wp08 tgt1450 0 4 7 5 0
5 0 0 0
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CLU Storage 4250500750100012501500175020002250250027503000325035003750400042504500475050005 2 5 055005750600062506500675070007250750077507998 Cannery Loop Unit 1047505000CLU Storage 52 5 0500750100012501500175020002250250027503000Cannery Loop Unit 072505007 5 0100 012501500
1 7 5 0
2 0 0 0225025002750
3 0 0 0325035003750400042504500475050005250550057506000
6 2 506 5006750700072507500775080008250CLU #132 5 050075010001250
1 5 0 0
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2 0 0 0
2 2 5 0
2 5 0 0
2 7 5 0
3 0 0 0
3 2 5 0
3 5 0 0
3 7 50
4 0 0 0
4 2 5 0
4 5 0 047505000525055005750600062506500675070007250750077507937Cannery Loop Unit 08475050005059CLU Storage 32505007501000125015001750200022502500275030003250350037504000425045004750500052505500CANNERY LOOP UNIT 01RD2505007501000125015001750200022502500275030003250350037504000425045004750500052505500CANNERY LOOP UNIT 01RDPB1250500750100012501500175020002250250027503000325035003750400042504500475050005250550057506000Cannery Loop Unit 01250500750100012501500175020002250250027503000325035003750400042504500475050005250550057506000625065006750CLU05RD25050075010001250150017502000225025002750300032503500375040004250450047505000525055005750600062506500675070007250750077508000825085008 7 5 090009250950097501000010226CLU05
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5 2 5 0550057506000625065006750700072507500775080008038Cannery Loop Unit 09250500750100012501500175020002250250027503000325035003750Cannery Loop Unit 062505 0 0
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4 0 0 042504500475050005250550057506000625065006750700072507500775080008043CLU 149 5/8"4 1/2" x 6 1/8"25050075010001250150017502 0 0 0
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4 2 5 045004642CLU 06RD wp08Project: Kenai C.I.U.Site: Cannery Loop Unit #1 PadWell: Cannery Loop Unit 06Wellbore: Cannery Loop Unit 06RDPlan: CLU 06RD wp08
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0.001.503.004.50Separation Factor1800 2100 2400 2700 3000 3300 3600 3900 4200 4500 4800 5100 5400 5700 6000 6300 6600 6900 7200Measured DepthCLU Storage 4CLU #13Cannery Loop Unit 08CLU05RDCannery Loop Unit 06CLU 14No-Go Zone - Stop DrillingCollision Avoidance Req.Collision Risk Procedures Req.NOERRORSWELL DETAILS:Cannery Loop Unit 06 NAD 1927 (NADCON CONUS)Alaska Zone 04Ground Level: 20.70+N/-S +E/-W Northing EastingLatittudeLongitude0.000.00 2388566.25 272506.87 60° 31' 55.267 N 151° 15' 47.217 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Cannery Loop Unit 06, True NorthVertical (TVD) Reference:CLU-06RD @ 38.70usft (HEC 169)Measured Depth Reference:CLU-06RD @ 38.70usft (HEC 169)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2020-10-07T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool191.70 1600.00 CLU 06 (MWD) (Cannery Loop Unit 06) 3_MWD1600.00 2000.00 CLU 06RD wp08 (Cannery Loop Unit 06RD) 3_MWD_Interp Azi+Sag2000.00 6494.67 CLU 06RD wp08 (Cannery Loop Unit 06RD) 3_MWD+IFR1+MS+Sag0.0030.0060.0090.00120.00150.00Centre to Centre Separation (50.00 usft/in)1800 2100 2400 2700 3000 3300 3600 3900 4200 4500 4800 5100 5400 5700 6000 6300 6600 6900 7200Measured DepthCLU #13Cannery Loop Unit 08CANNERY LOOP UNIT 01RDCANNERY LOOP UNIT 01RDPB1Cannery Loop Unit 01CLU05RDCLU05Cannery Loop Unit 09GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference1600.00 To 6494.67Project: Kenai C.I.U.Site: Cannery Loop Unit #1 PadWell: Cannery Loop Unit 06Wellbore: Cannery Loop Unit 06RDPlan: CLU 06RD wp08Ladder / S.F. PlotsCASING DETAILSTVD TVDSS MD Size Name4642.00 4603.30 6494.67 4-1/2 4 1/2" x 6 1/8"
1
Carlisle, Samantha J (CED)
From:Frank Roach <Frank.Roach@hilcorp.com>
Sent:Wednesday, December 9, 2020 3:59 PM
To:Schwartz, Guy L (CED)
Cc:Monty Myers
Subject:CLU 06RD Updated GeoProg Table with CINGSA Storage Zone Added
Attachments:CLU-06RD Geoprog with CINGSA Top.pdf
Guy,
Perourphoneconversationearliertoday,pleaseseetheattachedGeoProgtable.ThisshowsthedepthoftheCINGSA
storagepoolinrelationtotheplannedCLU06RDwell.AttheplannedTDofwp08,thereis~250’verticalseparation
betweenTDandthetopofthestoragepool.
TheGeoProgtableinthedrillingprogramhasbeenupdatedwiththisversion.
Letmeknowifyouneedanythingadditional.
Regards,
FrankVRoach
DrillingEngineer
907.854.2321(c)
907.777.8413(o)
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Well Name:CLU-06RD Survey Type RKB
Field Name:Cannery Loop Surface Hole:38.7
Pool Name:Tyonek Bottom Hole:HEC 169
State:Alaska 18
Field Location:Onshore Coord Ref Sys:NAD27 ASP Z4 20.7
County/Parish:Kenai Penninsula Bourgh
Objective:
Reference Plan:
CL_ST_X1_MARKER Sandstone / Coals Water 3,314 2,628.8 -2590 2,389,196.70 274,020.10 1166 0.45
CL_ST_X2_MARKER Sandstone / Coals Water 3574 2,782.5 -2744 2,389,242.70 274,224.90 1235 0.45
CL_ST_A1-2_C Sandstone / Coals Water 3963 3,012.7 -2974 2,389,311.70 274,531.50 1338 0.45
CL_ST_A1-3_C Sandstone / Coals Water 4054 3,066.5 -3028 2,389,327.80 274,603.10 1362 0.45
CL_ST_A2_MKR Sandstone / Coals Water 4198 3,151.3 -3113 2,389,353.20 274,716.00 1401 0.45
CL_ST_A3_MKR Sandstone / Coals Water 4649 3,418.1 -3379 2,389,433.20 275,071.40 1521 0.45
CL_ST_A4_MKR Sandstone / Coals Water 4737 3,469.7 -3431 2,389,448.70 275,140.10 1544 0.45
CL_ST_A4A Sandstone / Coals Water 4824 3,521.0 -3482 2,389,464.10 275,208.50 1567 0.45
CL_ST_A4B Sandstone / Coals Water 4949 3,595.2 -3556 2,389,486.30 275,307.30 1600 0.45
CL_ST_A5_MKR Sandstone / Coals Water 5074 3,668.7 -3630 2,389,508.30 275,405.30 1634 0.45
CL_ST_A5A Sandstone / Coals Water 5111 3,690.8 -3652 2,389,514.90 275,434.70 1643 0.45
CL_ST_A6_MKR Sandstone / Coals Water 5239 3,766.3 -3728 2,389,537.60 275,535.30 1677 0.45
CL_ST_A6A Sandstone / Coals Water 5311 3,809.2 -3771 2,389,550.40 275,592.40 1697 0.45
CL_ST_A7_MKR Sandstone / Coals Water 5,433 3,881.1 -3842 2,389,572.00 275,688.20 1729 0.45
CL_ST_A8_MKR Sandstone / Coals Water 5,533 3,940.0 -3901 2,389,589.60 275,766.60 1756 0.45
CL_ST_A9_MKR Sandstone / Coals Water 5,643 4,005.4 -3967 2,389,609.20 275,853.70 1785 0.45
CL_ST_A10_MKR Sandstone / Coals Water 5,745 4,065.8 -4027 2,389,627.00 275,932.90 1812 0.45
CL_ST_A11_MKR Sandstone / Coals Water 5,841 4,127.2 -4088 2,389,643.30 276,005.20 1840 0.45
CL_ST_A11A Sandstone / Coals Gas 5,877 4,151.5 -4113 2,389,649.20 276,031.70 1851 0.45
CL_ST_A11B Sandstone / Coals Gas / Water 5,949 4,201.5 -4163 2,389,660.60 276,082.50 1873 0.45
CL_ST_B1_MKR Sandstone / Coals Gas 5,989 4,229.8 -4191 2,389,666.60 276,109.30 1886 0.45
CL_ST_B2_MKR Sandstone / Coals Gas 6,090 4,304.9 -4266 2,389,681.20 276,174.70 1920 0.45
CL_ST_B5_COAL_MK Coal Storage Gas 6,789 4,896.7 -4858 2,389,684.00 276,558.80
= Reservoir Objectives
= Possible Geo Hazards
TARGET RADIUS
Sidetrack CLU to target the Sterling A11A Amplitude, as well as the B1 and B2 sands. TD will be before entering the CLU Sterling C
sands, so no contact with CINGSA Storage Reservoirs will be made.
100 FT
CLU-06RD wp08ANTICIPATED FORMATION TOPS & GEOHAZARDS
Geo Summary/
Justification:
See above
TOP NAME LITHOLOGY EXPECTED
FLUID
MD
(FT)
TVD
(FT)
TVDSS
(FT)NORTHING Gradient
Storage Sand
Ground Elevation:
GEOLOGICAL PROGNOSIS
As-Built
x = 272,506.87 y = 2,388,566.25
TVD Ref Datum:
TVD Ref Elevation:
Planned Rig:
Rig Height:
x = 276,414.46 y = 2,389,654.79
6,495' MD 4,642' TVD
EASTING Est.
Pressure
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.
CLU-06RD
220-074
X
X
X
Cannery Loop Unit Sterling Undefined Gas
WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:CANNERY LOOP UNIT 06RDInitial Class/TypeDEV / 1-GASGeoArea820Unit10320On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2200740STERLING, STERLING UNDEF GAS - 768500NA1 Permit fee attachedYes2 Lease number appropriateYes3 Unique well name and numberNo Sterling Undefined Gas Pool4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For sNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)NA conductor set in Motherbore well CLU 618 Conductor string providedNA19 Surface casing protects all known USDWsNA20 CMT vol adequate to circulate on conductor & surf csgYes 4 1/2" liner will be cemented back to the liner hanger (in 7")21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes BTC calculations are provided. All within industry standards.23 Casing designs adequate for C, T, B & permafrostYes Rig 169 has steel pits. All waste to approved disposal .. KGF24 Adequate tankage or reserve pitYes 320-512 is plug for redrill sundry (CLU 6 PTD 200-033)25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedNA Wellhead in place. BOPE used27 If diverter required, does it meet regulationsYes Max formation press=1920 psi (8.6 ppg EMW) will drill with 9-11ppg mud28 Drilling fluid program schematic & equip list adequateYes Rig 169 has 11" BOPE 5000 psi WP29 BOPEs, do they meet regulationNo MASP = 1490 psi (will test BOPE tot 3500 psi)30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes Rig 401 will follow to run 4.5" tieback and complete well.32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S not anticipated based on offset wells.35 Permit can be issued w/o hydrogen sulfide measuresYes36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprDLBDate12/7/2020ApprGLSDate12/9/2020ApprDLBDate12/7/2020AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateCLU 6 requires a SSSV … Wellbore is landed 250 ft TVD above the CINGSA Gas Storage pool. gls 12/9/20JMP 12/10/2020dts 12/10/2020JLC 12/10/2020
