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Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAbout221-077Kyle Wiseman Hilcorp Alaska, LLC
Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: Kyle.Wiseman@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 11/28/2022
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20221128-2
Well API #PTD #Log Date Log
Company Log Type AOGCC
Eset#
PBU 01-14A 50029202810100 209129 11/2/2022 Halliburton PPROF
PBU 01-20 50029208210000 182146 10/31/2022 Halliburton PPROF
PBU 01-33 50029216170000 186122 11/1/2022 Halliburton PPROF
PBU A-04 50029201150000 172006 11/9/2022 Halliburton PPROF
PBU C-01B 50029201210200 212053 11/6/2022 Halliburton PPROF
PBU L-200A 50029231910200 221077 10/27/2022 Halliburton PPROF
PAXTON 9 50133206470000 214173 11/4/2022 Halliburton PPROF
Please include current contact information if different from above.
By Meredith Guhl at 11:18 am, Nov 29, 2022
T37324
T37325
T37326
T37327
T37328
T37329
T37330PBU L-200A 50029231910200 221077 10/27/2022 Halliburton PPROF
Meredith Guhl Digitally signed by Meredith Guhl
Date: 2022.11.29 11:30:55 -09'00'
DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-029-23191-02-00Well Name/No.PRUDHOE BAY UN ORIN L-200ACompletion Status1-OILCompletion Date10/31/2021Permit to Drill2210770OperatorHilcorp North Slope, LLCMD14060TVD4155Current Status1-OIL2/25/2022UICNoWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:ROP, ADR, DGR, ABG, GM MD & TVDNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF1/26/20226897 14017 Electronic Data Set, Filename: PBU L-200A ADR Quadrants All Curves.las36292EDDigital DataDF1/26/20223352 14060 Electronic Data Set, Filename: PBU L-200A LWD Final.las36292EDDigital DataDF1/26/2022 Electronic File: PBU L-200A EOW log.emf36292EDDigital DataDF1/26/2022 Electronic File: PBU_L-200A_Geosteering.dlis36292EDDigital DataDF1/26/2022 Electronic File: PBU_L-200A_Geosteering.ver36292EDDigital DataDF1/26/2022 Electronic File: PBU L-200A EOW log.pdf36292EDDigital DataDF1/26/2022 Electronic File: PBU L-200A End of Well Report.pdf36292EDDigital DataDF1/26/2022 Electronic File: PBU L-200A Post-Well Geosteering X-Section Summary.pdf36292EDDigital DataDF1/26/2022 Electronic File: PBU L-200A EOW log.tif36292EDDigital DataDF1/26/2022 Electronic File: PBU L-200A LWD Final MD.cgm36292EDDigital DataDF1/26/2022 Electronic File: PBU L-200A LWD Final TVD.cgm36292EDDigital DataDF1/26/2022 Electronic File: L-200A - Defintive Survey Report.pdf36292EDDigital DataDF1/26/2022 Electronic File: L-200A - Defintive Survey Report.txt36292EDDigital DataDF1/26/2022 Electronic File: L-200A - final surveys.xlsx36292EDDigital DataDF1/26/2022 Electronic File: L-200A - GIS.txt36292EDDigital DataDF1/26/2022 Electronic File: L-200A_Plan.pdf36292EDDigital DataDF1/26/2022 Electronic File: L-200A_VSec.pdf36292EDDigital DataFriday, February 25, 2022AOGCC Page 1 of 3PBU L-200ALWD Final.las
DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-029-23191-02-00Well Name/No.PRUDHOE BAY UN ORIN L-200ACompletion Status1-OILCompletion Date10/31/2021Permit to Drill2210770OperatorHilcorp North Slope, LLCMD14060TVD4155Current Status1-OIL2/25/2022UICNoWell Cores/Samples Information:ReceivedStart Stop CommentsTotalBoxesSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments:Mud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date:10/31/2021Release Date:10/8/2021DF1/26/2022 Electronic File: PBU L-200A LWD Final MD.emf36292EDDigital DataDF1/26/2022 Electronic File: PBU L-200A LWD Final TVD.emf36292EDDigital DataDF1/26/2022 Electronic File: PBU L-200A LWD Final MD.pdf36292EDDigital DataDF1/26/2022 Electronic File: PBU L-200A LWD Final TVD.pdf36292EDDigital DataDF1/26/2022 Electronic File: PBU L-200A LWD Final MD.tif36292EDDigital DataDF1/26/2022 Electronic File: PBU L-200A LWD Final TVD.tif36292EDDigital Data0 0 2210770 PRUDHOE BAY UN ORIN L-200A LOG HEADERS36292LogLog Header ScansFriday, February 25, 2022AOGCC Page 2 of 3
DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-029-23191-02-00Well Name/No.PRUDHOE BAY UN ORIN L-200ACompletion Status1-OILCompletion Date10/31/2021Permit to Drill2210770OperatorHilcorp North Slope, LLCMD14060TVD4155Current Status1-OIL2/25/2022UICNoCompliance Reviewed By:Date:Friday, February 25, 2022AOGCC Page 3 of 3M. Guhl2/25/2022
David Douglas Hilcorp Alaska, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Hilcorp North Slope, LLC
Date: 01/26/2022
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
PBU L-200A (PTD 221-077)
FINAL LWD FORMATION EVALUATION LOGS (10/14/2021 to 10/26/2021)
x ADR, DGR, ABG, GM, Horizontal Presentation (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
x EOW Report and Geosteering
SFTP Transfer – Main Folders:
LWD Subfolder:
Geosteering Subfolder: g
Please include current contact information if different from above.
Received By:
01/26/2021
37'
(6HW
By Abby Bell at 10:38 am, Jan 26, 2022
1a. Well Status:Oil SPLUG Other Abandoned Suspended
1b. Well Class:
20AAC 25.105 20AAC 25.110 Development Exploratory
GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test
2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry:
Aband.:
3. Address: 7. Date Spudded: 15. API Number:
4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number:
Surface:
Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s):
GL: 49.1' BF:
Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation:
4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number:
Surface: x- y- Zone- 4
TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD:
Total Depth: x- y- Zone- 4
5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD:
Submit electronic information per 20 AAC 25.050 (ft MSL)
22.Logs Obtained:
23.
BOTTOM
20"x34" A-53 108'
10-3/4" L-80 2,404'
7-5/8" L-80 4,237'
4-1/2" L-80 4,155'
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 Rate300
10/26/2021
10/1/2021
ADL 028239 & 047447
00-001
1900' (Approx.)
3,354' / 2,404'N/A
None
14,060' / 4,155'
ROP, ADR, DGR, ABG, GM MD & TVD
Sr Res EngSr Pet GeoSr Pet Eng
45
N/A
Oil-Bbl: Water-Bbl:
2,584 782,677
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
1,152892
Flowing
6,955' - 14,016' 4,237' - 4,155' 10/28/2021
861
Water-Bbl:
PRODUCTION TEST
November 7, 2021
Date of Test:
1300
11/7/2021 8
Flow Tubing
26
215.5#
45.5#
108'
26' 6,907'
Gas-Oil Ratio:Choke Size:
Per 20 AAC 25.283 (i)(2) attach electronic information
29.6# 26'
DEPTH SET (MD)
6,363' / 4,101'
PACKER SET (MD/TVD)
29'
CASING WT. PER
FT.GRADE
582790
577692
TOP
SETTING DEPTH MD
29'
SETTING DEPTH TVD
5987609
BOTTOM TOP
9-1/2"
29'
13-1/2"
HOLE SIZE AMOUNT
PULLED
50-029-23191-02-00
PBU L-200A
583209 5978290
1517' FSL, 1211' FWL, Sec. 27, T12N, R11E, UM, AK
CEMENTING RECORD
5982514
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
10/31/2021
2568' FSL, 3704' FEL, Sec. 34, T12N, R11E, UM, AK
1386' FSL, 1458' FWL, Sec. 21, T12N, R11E, UM, AK
221-077
Schrader Bluff Oil Pool, Orion Dev Area
75.65'
14,056' / 4,155'
Prudhoe Bay Field /
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
Hilcorp North Slope, LLC
WAG
Gas
48"
13.5#
29' 3,354'723 sx AS Lite, 338 sx Class 'G'
6-3/4"
260 sx Arctic Set (Approx.)
6,759' 14,058'
Stg 1 L - 287 sx / T - 277 sx
4,223'
6,661'4-1/2" 12.6# L-80
SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation
Size and Number; Date Perfd):
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,
Stg 2 L - 215 sx / T - 105 sx
TUBING RECORD
Uncemented Screen Liner
Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment
By Samantha Carlisle at 12:03 pm, Nov 18, 2021
RBDMS HEW 11/19/2021
Completion Date
10/31/2021
HEW
G
MGR21FEB2022 SFD 11/19/2021 DSR-12/16/21
Conventional Core(s): Yes No Sidewall Cores:
30.
MD TVD
Top of Productive Interval 6813' 4232'
3646' 2573'
4696' 3216'
5998' 3919'
6382' 4109'
6813' 4232'
SB OA 6813' 4232'
31. List of Attachments:
32. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Contact Name: Joe Lastufka
Contact Email:joseph.lastufka@hilcorp.com
Authorized Contact Phone: 777-8400
General:
Item 1a:
Item 1b:
Item 4b:
Item 9:
Item 15:
Item 19:
Item 20:
Item 22:
Item 23:
Item 24:
Item 27:
Item 28:
Item 30:
Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and
other tests as required including, but not limited to: core analysis, paleontological report, production or well test results.
Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29.
Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool.
If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the
producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced,
showing the data pertinent to such interval).
Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit
detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity,
permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology.
The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements
given in other spaces on this form and in any attachments.
The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00).
Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain).
Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical
laboratory information required by 20 AAC 25.071.
Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion,
suspension, or abandonment, whichever occurs first.
Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection,
Observation, or Other.
Formation at total depth:
Ugnu MB
LOT / FIT Data Sheets, Drilling and Completion Reports, Casing and Cement Report, Definitive Directional Survey, Wellbore
Schematic
Signature w/Date:
Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345),
and/or Easement (ADL 123456) number.
INSTRUCTIONS
Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each
segregated pool is a completion.
TPI (Top of Producing Interval).
Yes No
Well tested? Yes No
28. CORE DATA
If yes, list intervals and formations tested, briefly summarizing test results.
Attach separate pages to this form, if needed, and submit detailed test
information, including reports, per 20 AAC 25.071.
NAME
Schrader Bluff NB
SV1
Ugnu LA3
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
Schrader Bluff OA
Permafrost - Base
29. GEOLOGIC MARKERS (List all formations and markers encountered): FORMATION TESTS
Permafrost - Top
Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment
11.18.2021Digitally 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: 2021.11.18 11:55:25 -09'00'
Monty M
Myers
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:PBW L-206 Date:10/15/2021
Csg Size/Wt/Grade: 10.75" 45.5# L-80 Supervisor:S. Barber
Csg Setting Depth:3,354 2,404 TVD
Mud Weight:9.5 ppg LOT / FIT Press =312 psi
LOT / FIT =12.00 ppg Hole Depth =7761 md
Fluid Pumped=0.8 Bbls Volume Back =0.6 bbls
Estimated Pump Output:0.062 Barrels/Stroke
LOT / FIT DATA CASING TEST DATA
Enter Strokes Enter Pressure Enter Strokes Enter Pressure
Here Here Here Here
->120 ->028
->250 ->4240
->390 ->8505
->4130 ->12 750
->5160 ->16 1000
->6190 ->20 1245
->7210 ->24 1500
->8225 ->28 1755
->9245 ->32 2050
->10 265 ->36
->11 280 ->40
->12 295 ->44
->13 315 ->48
->14 ->52
Enter Holding Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0315 ->02050
->1312 ->52030
->2306 ->10 2015
->3301 ->15 2010
->4298 ->20 2005
->5293 ->25 2000
->6288 ->30 1995
->7285 ->
->8282 ->
->9280 ->
->10 277 ->
-> ->
-> ->
-> ->
1 2 3 4 5 6 7 8 9 10111213
0
4
8
12
16
20
24
28
32
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
3100
3200
3300
3400
3500
3600
3700
3800
3900
4000
0 102030405060Pressure (psi)Strokes (# of)
LOT / FIT DATA CASING TEST DATA
315312306301298293288285282280277
2050 2030 2015 2010 2005 2000 1995
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
3100
3200
3300
3400
3500
3600
3700
3800
3900
4000
0 5 10 15 20 25 30Pressure (psi)Time (Minutes)
LOT / FIT DATA CASING TEST DATA
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:PBW L-206A Date:10/23/2021
Csg Size/Wt/Grade:7.625", 29.6, L-80 Supervisor:Lott / Montague
Csg Setting Depth:6,906 4,236 TVD
Mud Weight:9.5 ppg LOT / FIT Press =571 psi
LOT / FIT =12.09 ppg Hole Depth =6920 md
Fluid Pumped=0.7 Bbls Volume Back =0.5 bbls
Estimated Pump Output:0.062 Barrels/Stroke
LOT / FIT DATA CASING TEST DATA
Enter Strokes Enter Pressure Enter Strokes Enter Pressure
Here Here Here Here
->00 ->00
->159 ->4220
->2127 ->8409
->3181 ->12 606
->4247 ->20 1040
->5306 ->24 1260
->6362 ->28 1511
->7410 ->32 1768
->8462 ->36 2013
->9518 ->40 2260
->10 571 ->44 2510
-> ->48 2760
-> ->52 3010
-> ->55 3197
Enter Holding Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0571 ->03197
->0.25 556 ->53166
->0.5 553 ->10 3155
->1548 ->15 3146
->1.5 542 ->20 3139
->2537 ->25 3133
->3527 ->30 3128
->4518 ->
->5510 ->
->6502 ->
->7494 ->
->8487 ->
->9478 ->
->10 472 ->
0
1
2 3
4
5
6 7 8
9 10
0
4
8
12
20
24
28
32
36
40
44
48
52
55
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
3100
3200
3300
3400
3500
3600
3700
3800
3900
4000
0 102030405060Pressure (psi)Strokes (# of)
LOT / FIT DATA CASING TEST DATA
571556553548542537527518510502494487478472
3197 3166 3155 3146 3139 3133 3128
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
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2200
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2400
2500
2600
2700
2800
2900
3000
3100
3200
3300
3400
3500
3600
3700
3800
3900
4000
0 5 10 15 20 25 30Pressure (psi)Time (Minutes)
LOT / FIT DATA CASING TEST DATA
Activity Date Ops Summary
10/11/2021 PJSM NES on location at 06:00 for rig move. Move and stage Gen & Mus Mods. Remove matt boards. Jack up pipe shed and Catwalk stage on pad. Jack up Sub
and walk sub down well row to L-200A. SIMOPS C/O suction valve and seat on MP #2 Pod #1. PJSM Cont walk sub down well row and center over L-200A. Spot
Catwalk, Pipe Shed & Mud Mod. Install inner connects. ODS arm stabilizers on sub. Cover stompers W/ Herculite. Work on test pump, clean steam traps. PJSM
Cont spotting Gen Mod. Set matt boards Release NES trucks at 00:30. PJSM R/u inner connects. Pres up Air, steam and H2O though out rig. Assist Electrician
going to Gen power through mods. Gen power at 02:00. Set down stompers and prep to scope up derrick. Safe out stairs and landings throughout rig.. Spot break
shack and enviro vac. PJSM Scope up derrick and bridle down. Grease crown sheaves and perform full derrick inspection. Hang rig tomgs and unpin weight
buckets. Function rig floor Equip as per rig acceptance check list. Lay Herculite and spot cutting box. Cont rig acceptance check list.
10/12/2021 Work rig acceptance checklist. Function test all equipment in mud pits and pump room. Repair and install guards on skate. Rig accepted @ 07:30 hrs. Pull TWC.
Spot and rig up flowback tank. Purge line from cellar to tank with air and check for leaks (good). Flood lines with H2O and PT same 1000 psi (no leaks). Circulate
down 4.5" tubing taking returns IA to flowback tank. Pump 40 bbls heated Baraklean pill, chase with 330 bbls 9.5 quikdril milling fluid @ 6 bpm, 260 psi. ~160 bbls
diesel returned to tank, ~210 bbls 9.2 brine. Set BPV, N/D tree. Install CTS and test (TWC) same 5k (test good). Install 18" 11"x13-5/8" spacer spool. N/U 13-5/8"
stack - LPR 2-7/8x5-1/2" VBRs, Blinds, UPR 2-7/8x5-1/2". RKB Ann 11.77', UPR 14.66', BLND 16.10', LPR 19.77', ULDS 23.03' LLDS 25.32', Ground 26.56'.
Flood stack W/ H2O purge air. Shell test to 2,000 psi, good. Remove RCD cap and install trip nipple. M/U 5" test jnt, X/O 4.5" IF X 4.5 TCII to test sub on hanger.
R/U side entry, 2 ea 5" TIW and 5" Dart valve. SIMOPS R/D hard lines and flow back tank. PJSM Perform BOPE test W/ 4.5" & 5" to 250 PSI low and 3,000 PSI
high for 5 Min. Tested Choke Manifold 1-15, 5" Dart, 2 ea 5" TIW, Upper and lower IBOP, Mez Kill, HCR and manual Choke and Kill, Super Choke and manual to
1,600 PSI, Upper and lower VRB Rams (2.875" X 5.5") Blind Rams & Annular. Test H2S 10-20 ppm, LEL 20-40%, PVT high/ low level alarms. Checked PVT
sensors and return flow. Koomey draw drown Initial System 2,925 PSI, Manifold 1,425 PSI, Annular 1,375 PSI, after System 1,500 PSI, Man 1,500 PSI, Annular
1,500 PSI. 200 PSI increase 18 Sec, full charge 86 sec. Nitrogen 6 bottle average 2,291 PSI. Witnessed Waived by AOGCC Jeff Jones via phone call. PJSM R/D
4.5" test, break down head pin L/D. P/U 5" test jnt break down TIW, side entry and dart. L/D. Blow down choke manifold and lines. Grease choke manifold. PJSM
R/U Weatherboard 4.5" tools & Equip. C/O elevators to YC 75T. R/U power tongs. M/U X/O for TIW. SIMOPS C/O Saver Sub. P/U Tee Bar and remove CTS and
BPV as per Vault rep onsite. PJSM M/U 4.5" landing jnt to Hanger, BOLDS as per Vault rep onsite. Unseat Hanger W/ string weight 60K. no issue. POOH L/D 4.5"
126# 13cr-85 VamTop to 2,900' MD.. P/U 58k SLK 56k Extra X/O pup under hanger pup. Hanger pup 2.57' & X/O pup 2.40'. Daily Disposal to G&I = 0 bbls, total =
0 bbls. Daily H2O F/ Lake 2 = 560 bbls total= 560 bbls. Daily Metal: 0 lb. Total Metal 0 lb.
10/13/2021 Continue POOH w/ 4.5" Vam Top kill string from 2900' to surface. L/D mule shoe jt. R/D WOT handling equipment. Calculated displacement from trip. 45k Up/Dn
@ 2900' MD. R/U test equipment. Close blinds and test 10-3/4" 45.5# L-80 casing to 2000 psi w/ 30 min hold. Chart and record same. 2 bbls pumped / 1.8 bbls
bled back. (Test good). B/D test equipment. R/D same. Install wear bushing. Pick up drift (3.125") and single in the hole with 5" drill pipe to 1468'. POOH racking
back drill pipe. Clean and clear rig floor. Mobilize BHA components to rig floor. M/U Baker milling assembly: 9-3/4" starter mill, 9-1/2" lower mill, flex joint, 9.80
upper mill, 15' HWDP pup join, XO, Float sub. (6) jts HWDP, 6 jnts DC to 453'. Tight at 252' with 6K drag work through x 2. Set down with 15K at 284', unable to
work through. Establish circulation at 6 bpm, 55 psi. 20 rpms, 1500 ft-lbs worked through x 3. RIH with milling BHA picking up, drifting (3.125") and single in the
hole with 5" DP from 453' to 996'. Set down 20K at 559'. Worked through x3 with 6 bpm, 65 psi, 20 rpms 1500ft-lbs. Set down 25K at 980' (Tam Port), with 25K
overpull. Work down to 996', setting down 30K with 30K overpull. Discuss options with Engineer. POOH from 996' to surface. L/D upper mill. RIH with dual mill
assembly (same BHA without the upper window mill), picking up drill pipe to 1300'. Observe drag at 980', work through x 2 with 25-30K down and 25K overpull.
Cont. to RIH with dual mill assembly, picking up 5"DP to 3294', RIH one stand out of derrick and tag whipstock at 3354' (P272 RKB 3375'), on depth. Rack back
one stand and pick up single, M/U stand of drill pipe. Establish parameters, 10 bpm, 272 psi, 70 rpms, 4500ft-lbs. PUW 91K, SOW 78K, ROTW 88K Mill window
from 3354' to 3360', WOB 1-2K, 460 gpm, 305 psi, 70-80rpms, 6-9Kft-lbs Daily Disposal to G&I = 0 bbls, total = 0 bbls. Daily H2O F/ Lake 2 = 140 bbls total= 700
bbls. Daily Metal: 0 lb. Total Metal 0 lb.
10/14/2021 Cont milling window from 3360' to 3381' at 460 gpm, 310 psi, 80 rpms, 4Kft-lbs off 5.5Kft-lbs on bottom, WOB 2-6K. PUW 95K, SOW 81K, ROTW 88K. TOW
3354'. BOW 3374' Ream up through window without issues. Pump high vis sweep and circulate surface to surface. No increase in cuttings. monitor well, observe
slight flow. Rack back stand to 3363'. Circ bottoms up at 450 gpm, 305 psi, 40 rpm 4-5K ft-lbs. Monitor well, static. Pump 10 bbls dry job, B/D top drive. POOH
racking back drill pipe from 3363' to 438'. Observe 20K over pull from 1005' to 980'. Calc hole fill. Monitor well - static. Rack back 3 stands of HWDP and 3 stands
spiral drill collars. Mills ~1/8 under gauge. L/D milling assembly. M/U milling BHA #3, window mill, bit sub, HW pup, 9.88" OD Upper mill, flex joint, HW pup, XO
sub, (1) HWDP. float sub. Pull 9-7/8" wear bushing. RIH with milling assembly with (6) DC, (6) HWDP to 453' working through tight spots at 250' and 400'. RIH
with milling assembly on drill pipe from 453' to 1015'. Set down at 985' with 30K. Work pipe down to 1015', rotating pipe 1/8 turn and circulating at 6 bpm, 105 psi
with 15-35K down and overpull. Unable to make past 1015'. Monitor well, slight flow. CBU 455 gpm, 195 psi. Monitor well, static POOH from 955' to 80'.
Calculated hole fill observed. Cont. to POOH from 80'. L/D 9.88" OD upper mill. M/U 9.80" Upper mill. Set 9-15/16" wear bushing. RIH with milling assembly to
TOW at 3354'. Work through tight spots at 547', 616' with 10-15K down. Work through tight spot from 992' to 1015' with 6 bpm, 132 psi setting down 25-35K.
Establish rotary at 80 rpms, 6Kft-lbs, circulation at 11 bpm, 330 psi. Dress off window, milling from 3354' to 3384' PUW 98K, SOW 80K, ROTW 88K. Daily
Disposal to G&I = 57 bbls, total = 57 bbls. Daily H2O F/ Lake 2 = 140 bbls total= 700 bbls. Daily Metal: 100 lb. Total Metal 100 lb.
50-029-23191-02-00API #:
Well Name:
Field:
County/State:
PBW L-200A
Prudhoe Bay West
Hilcorp Energy Company Composite Report
, Alaska
10/14/2021Spud Date:
10/15/2021 Continue Milling 9.800" window in 10-3/4" 45.5#, L-80 casing F/ 3384' to 3404' MD. TOW @ 3354', BOW @ 3374' MD. Drilled 30' new formation to allow lower
mill to work btm of window and drill 6' of gauge hole outside window. 11 bpm, 330 psi, 80 rpm, 6k tq. P/U 97k, S/O 79k, ROT 89k. Pump 35 bbls spacer pill then
displace wellbore over to 9.5 PPG spud mud while Rot/Recip @ 3404' to 3347' MD. 450 gpm, 775 psi, 46% R/F, 40 rpm, 6k tq, P/U 92k, S/O 74k, ROT 85k. Flush
choke and kill lines post milling operations. PJSM, B/D TDS. R/U and perform 12 ppg EMW FIT @ 3354' MD (2404' TVD) using upper pipe rams. 1/4 bpm pump
rate. .8 bbls in, .6 bbls out. Psi up to 315. Good FIT. Chart and record same. B/D test equipment and R/D same. Monitor well (static). L/D working single. POOH
racking back 5" NC50, 19.5#, S-135 drill pipe F/ 3354' - T/ 2402' MD. P/U 89k, S/O 72k. Cont POOH rack back 5" NC50, 19.5#, S-135 DP F/ 2402' - T/ BHA.
Rack back 3x stds 5" HWDP, L/D DC"s and mill assy. Gauge mills. Starter mill 1/4" under, upper mill in gauge / 9.800" OD. Hole took proper disp. Slow pulled
mills thru @ 1015' w/ 35k drag (3'). Saw 7k bobble @ 550' MD then clean. Clean and clear rig floor. Pull wear bushing and johnny whack the stack to flush metal
cuttings from surface. Re-install 9-15/16" ID wear bushing. RILDS (4x). Service traveling equipment and pipe handling equipment. M/U BHA: 9.5" PDC bit, motor
with 1.86° bend, GWD, DM, Measure RFO: MWD-MTR=133.13°, MWD-GWD=255.08°. Cont M/U GHA DGR, ADR, PWD, TM, float sub. Plug in and upload
MWD. P/U and RIH with (2) DC, 17 jnts HWDP, jars to730'. Pick up, drift (3.125") and RIH with 5" drill pipe from 730' to 1986'. Calculated displacement observed.
5K drag at 985'. PUW 77K, SOW 64K Cont. Pick up, drift (3.125") and RIH with 5" drill pipe from 1986' to 2995'. RIH from derrick from 2995' to 3338'. Calculated
displacement observed. PUW 98K, SOW 60K Service rig. Grease and inspect crown sheaves, service iron roughneck, grease an dinspect top drive. Check gear
oil level. Pull trip nipple, install MPD. Fill pipe. Pulse test. Orient motor to 42°LOHS. RIH to 3404', no issues through window. Wash down from 3385', no issues.
Drill 9.5" hole from 3404' to 3464' (total=64', AROP=43fph) at 450 gpm, 1400 psi, WOB 4-6K, 60 rpms, 8Kft-lbsMax gas 30U, ECD 10.8 ppg EMW with 9.5ppg
mud. PUW 110K, SOW 77K. Daily Disposal to G&I = 568 bbls, total = 625 bbls. Daily H2O F/ Lake 2 = 70 bbls total= 770 bbls. Daily Metal: 25 lb. Total Metal 125
lb.
10/16/2021 Drill 9.5" hole from 3484' to 3581' (total=97', AROP=65fph) at 450 gpm, 1400 psi, WOB 4-6K, 60 rpms, 8Kft-lbsMax gas 30U, ECD 10.8 ppg EMW with 9.5ppg
mud. PUW 110K, SOW 77K. Moderate amount of noise detected from MWD. Troubleshoot mud pumps while servicing rig. Grease traveling equipment and
inspect same. POOH F/ 3581' - T/ 3326' MD. Pulled BHA thru window with 5k drag. Continue troubleshoot mud pump #1. Found mud pump #1, Pod #4 was
washed. B/D TDS and monitor well via TT while repairing mud pump (Replace pod). Well static. Cut and slip drilling line. Load and process 7-5/8" csg. Finish
installing pod on MP#1, torque bolts and studs to spec. Install valve, seat, liner and swab. Prime pump and function test - good. Sime Ops: process 7-5/8" casing.
Orient toolface to 45°LOHS. Shut down pumps and trip through window, 5K drag observed. Wash down from 3374' to 3581' and tag bottom, no fill. PUW 116K,
SOW 73K, ROTW 87K. Cont. to drill 9.5" hole from 3581' to 3779' (total=198', AROP=66fph) at 550 gpm, 2055 psi, WOB 2K, 60 rpms, 9.5Kft-lbs. Max gas 547U,
ECD 11.1 ppg EMW with 9.5ppg mud. PUW 116K, SOW 73K, ROTW87K. Backream full stands. Last GWD survey at 3609'. Cont. to drill 9.5" hole from 3779' to
4224' (total=445', AROP=74fph) at 530 gpm, 2350 psi, WOB 2-17K, 60 rpms, 9-10Kft-lbs. Max gas 774U, ECD 11.4 ppg EMW with 9.5ppg mud. PUW 120K,
SOW 76K, ROTW88K. Backream full stands. Cont. to drill 9.5" hole from 4224' to 4695' (total=471', AROP=118fph) at 530 gpm, 2100 psi, WOB 1-3K, 80 rpms,
11Kft-lbs. Max gas 700U, ECD 11.1 ppg EMW with 9.5ppg mud. PUW 125K, SOW 75K, ROTW93K. Backream full stands. Rack back stand. Change out swab
on mud pump #2 Pod#2. Rotate and reciprocate 30 rpms, 12.5Kft-lbs, 290 gpm, 950 psi. Cont. to drill 9.5" hole from 4695' to 4863' (total=168', AROP=112fph) at
530 gpm, 2150 psi, WOB 2-4K, 80 rpms, 12.5Kft-lbs. Max gas 344U, ECD 10.98 ppg EMW with 9.5ppg mud. PUW 132K, SOW 74K, ROTW93K. Backream full
stands. Daily Disposal to G&I = 461 bbls, total = 1086 bbls. Daily H2O F/ Lake 2 = 560 bbls total= 1330 bbls. Daily Metal: 40 lb. Total Metal 165 lb. Distance to
WP#3: 13.07', 11.91' Low, 5.37' Left.
10/17/2021 Cont. to drill 9.5" hole from 4863' to 5165' (total=302', AROP=76fph) at 530 gpm, 2250 psi, WOB 7K, 80 rpms, 13-15Kft-lbs. Max gas 381U, ECD 11.07 ppg EMW
with 9.5ppg mud. PUW 145K, SOW 75K, ROTW 100K. Backream full stands. Slide as necessary for 4°/100 turn to 5060', start of tangent. Rack back stand.
Change out swab, liner and wear plate on MP2, pod 2. Change out swab and liner on MP 2 pod 3. Rotate and reciprocate pipe, 290 gpm, 310 psi, 20 rpms, 15Kft-
lbs. Wash down to 5165'. Cont. to drill 9.5" hole from 5165' to 5244' (total=79', AROP=79fph) at 530 gpm, 2250 psi, WOB 7K, 80 rpms, 14Kft-lbs. Max gas 381U,
ECD 11.07 ppg EMW with 9.5ppg mud. PUW 145K, SOW 75K, ROTW 100K. Backream full stands. Slide as necessary to maintain WP03, through tangent.
Cont. to drill 9.5" hole from 5244' to 5855' (total=611', AROP=102fph) at 530 gpm, 2415 psi, WOB 2-17K, 80 rpms, 13Kft-lbs. Max gas 631U, ECD 11.3 ppg EMW
with 9.5ppg mud. PUW 154K, SOW 77K, ROTW 101K. Backream full stands. Slide as necessary to maintain WP03, through tangent. Cont. to drill 9.5" hole from
5855' to 6259' (total=404', AROP=67fph) at 530 gpm, 2485 psi, WOB 4-20K, 80 rpms, 14-15Kft-lbs. Max gas 1199U, ECD 11.1 ppg EMW with 9.5ppg mud.
PUW 175K, SOW 81K, ROTW 107K. Backream full stands. Slide as necessary to maintain WP03. Start 4°/100 build at 6132'. Cont. to drill 9.5" hole from 6259'
to 6498' (total=239', AROP=40fph) at 530 gpm, 2485 psi, WOB 6-20K, 80 rpms, 18-22Kft-lbs. Max gas 514U, ECD 10.3 ppg EMW, 9.5ppg mud. PUW 195K,
SOW 81K, ROTW 107K. Backream full stands. Slide as necessary for 4°/100 build. Adjust parameters for hard spot at 6492'. Daily Disposal to G&I = 860 bbls, total
= 1946 bbls. Daily H2O F/ Lake 2 = 980 bbls total= 2310 bbls. Daily Metal: 10 lb. Total Metal 175 lb. Distance to WP#3: 4.62', 3.44' Low, 3.09' Right.
10/18/2021 Cont. to drill 9.5" hole from 6498' to 6706' MD / 4210' TVD. (Total=208', AROP=35fph) 530 gpm, 2240 psi, WOB 16-18K, 80 rpm, 18-22K Tq. Max gas 507u, ECD
10.49 ppg w/ 9.5 MW. P/U 185K, S/O 75K, ROT 113K. B/R full stands. Slide as necessary for 4°/100 build. Cont drilg 9.5" hole from 6706' to (TD) 6920' MD /
4236' TVD. (Total=214', AROP=54fph) 530 gpm, 2240 psi, WOB 16-18K, 80 rpm, 18-22K Tq. Max gas 507u, ECD 10.5 ppg w/ 9.5 MW. P/U 185K, S/O 75K,
ROT 113K. B/R full stands. BROOH from 6920' to 6897'. Pump 40 bbls high vis sweep (on time, no increase in cuttings) and circulation hole clean 3xBU, racking
stand back each bottoms up. 530 gpm, 2010 psi, 60 rpms, 18-19Kft-lbs. max gas 482U. RIH on elevators from 6770' to 6920', no fill. PUW 190K, SOW 82K.
Close MPD choke and monitor well for 10 minutes, observe 40 psi build. Bleed off and close choke in observe 28psi build in 10 minutes. Downlink to activate GWD
to collect surveys, start dusting mud up to 9.7 ppg. BROOH from 6920' to 4927', 15-30 fpm as hole dictates. 530 gpm, 2025 psi, 60 rpms 15Kft-lbs. ECD 10.7
ppg with 9.7 ppg mud. Max gas 562U. PUW 171K, SOW 67K, ROT 98K. Cont. BROOH from 4927' to 3530', 15-30 fpm as hole dictates. 530 gpm, 1900 psi, 80
rpms 11-13Kft-lbs. ECD 11.13ppg with 9.7 ppg mud. Max gas 196U. PUW 135K, SOW 74K, ROT 95K. Slow pulling speed from 3719 to 3591' pump sweep
(20% increase, on time) and circulate 2 x BU. Pull BHA through window from 3530' to 3334' with no rotary and pumps. Observe 5-10K drag building to 30K (wipe x
1, without issue) - open hole drag. 5K bobble as bit comes across window. Monitor well with MPD for 10 minutes, no pressure build. Daily Disposal to G&I = 917
bbls, total = 2863 bbls. Daily H2O F/ Lake 2 = 560 bbls total= 2870 bbls. Daily Metal: 4 lb. Total Metal 181 lb. Distance to WP#3: 24.71', 23.89' Low, 6.31' Left.
R/U and perform 12 ppg EMW FIT @ 3354' MD (2404' TVD) using upper pipe rams. 1/4 bpm pumpr
rate. .8 bbls in, .6 bbls out. Psi up to 315. Good FIT.
See FIT data page 4. Break over at 200 psi, ~ 11.1 FIT not 12.0.
10/19/2021 PJSM, Drain stack. Remove RCD and install trip nipple. Strip off bearing from 5" stand and laydown same. Remove gravel from cellar and install mousehole.
POOH F/ 3338' - T/ 730' MD racking back 5" drill pipe. Saw 5-8k bobble @ 1015' MD (Tamport). Monitor well @ BHA (static). POOH F/ 730' - T/ surface.. L/D 5"
HWDP, 6-1/2" Jars (#89760D), DC's and FS. Download recorded data from MWD. B/O and L/D MWD, drain mtr, B/O bit and L/D same. Bit graded
2,6,BT,S,X,I,TD Pull wear bushing. Close blind rams. C/O upper pipe rams to fixed body 7-5/8". Test upper rams with 7-5/8" test jt 250/3000 psi w/ 5 min hold on
each (chart and record same). Test good. R/D test equipment. R/U Weatherford "Volant" CRT, 75T side doors, bail extensions and double stack power tongs with
"Tq Turn". RIH w/ Shoe jt and check floats (good). QC tq turn on 2nd jt (failed gear). Replaced pwr tongs with backups and QC'd tq turn on new tongs (good).
Flashlight float equipment (good). Bakerlok connections. Pump through float - good. Install bypass baffle. Torque connections to 14,500ft-lbs. Cont. to RIH with 7-
5/8" VAM top, 29.6#, L-80 casing from 160' to 2590'. 60-80 fpm as hole dictates. Fill casing every 5 joints, top off every 10. PUW 81K, SOW 66K. Calculated
displacement 21.5 bbls, Actual 16.5 bbls. Torque connections to 14,500ft-lbs. Cont. to RIH with 7-5/8" VAM top, 29.6#, L-80 casing from 2590' to 3308'. 60-80 fpm
as hole dictates. Fill casing every 5 joints, top off every 10. PUW 115K, SOW 76K. Torque connections to 14,500ft-lbs. Circulate surface to surface, staging pumps
up to 7 bpm 160 psi. Max gas 494U, no losses. Cont. to RIH with 7-5/8" VAM top, 29.6#, L-80 casing from 3308' to 4818'. 30-50 fpm as hole dictates. Fill casing
every 5 joints, top off every 10. PUW 155K, SOW 70K. Torque connections to 14,500ft-lbs. 5K drag through window, ~10K drag in open hole. Calc disp for trip
51.6 bbls, Act. 34.6 bbls. Daily Disposal to G&I = 404 bbls, total = 3267 bbls. Daily H2O F/ Lake 2 = 630 bbls total= 3500 bbls. Daily Metal: 5 lb. Total Metal 186 lb.
Daily fluid lost down hole = 13 bbls total = 13 bbls.
10/20/2021 Cont. to RIH with 7-5/8", L-80, 29.6#, VamTop casing from 4814' to 6907', TQ connections to 14,500ft-lbs using torque turn. RIH at 30-50 fpm as hole dictates. Fill
every 5 joints top off every 10. Observe 10-20K drag in open hole. PUW 225K, SOW 80K. Calc displacement 22.7, Act. 13.7. Circulate surface to surface,
lowering YP to 11. Stage pumps up to 7 bpm, 510 psi, set Tq limiter to 10Kft-lbs and rotate 1-2 rpms. max gas 188U. PUW 245K, SOW 82K . No losses. Rig
down casing and handling equipment. Shut down pumps and change out cup on Volant tool. R/U cement lines. Cement as per Detail: Fluid pack lines with water.
PT hard line to 1260/4408 psi - good. HES pump: 61 bbls 10.0 ppg tuned spacer with 4 ppg red dye and Pol-E-Flake at 4 bpm, 340 psi. Drop bypass bottom plug.
120 bbls 12.0 ppg type I/II lead cement at 4.4 bpm, 400 psi 57 bbls 15.8 ppg type I/II cement at 3.2 bpm, 530 psi. Drop shut off plug. Displace cement with: 20 bbls
water from HES at 7 bpm, 667psi. 144.5 bbls 9.7 ppg spud mud from rig at 7 bpm 335psi. 80 bbls 9.4 ppg tuned spacer from HES at 4 bpm, 570psi. 65.6 bbls 9.7
ppg spud mud from rig at 6 bpm, 890psi slow rate to 3 bpm, 850 psi. Bump plug 1.2 bbls early. Pressure up to 1350 psi and hold for 3 minutes. Check floats -
good. CIP at 17:30. No losses during cement job. Rotate and Reciprocate until pumping tail cement. Pressure up and open ES cementer and observe shift open
at 3412 psi. Establish circ and stage pumps up to 6 bpm, 440 psi. Observe 68 bbls of green cement at bottoms up. Circulate 4 x BU. Shut down pumps and flush
out stack with black water, function annular. Cont. to circ hole while prepping for 2nd stage cement job, allowing cement to gain 50 psi comp. strength. PJSM. Blow
air to ensure lines are clear. Batch up tuned spacer. Perform 2nd stage cement job as per detail. HES pumped: 5 bbls water at 4 bpm, 255 psi. 56 bbls 10.0 ppg
Tuned spacer at 4.5 bpm, 350 psi. 110 bbls 10.7 ppg ArcticCem lead cement at 4.5 bpm, 350 psi 22 bbls 15.8 ppg type I/II tail cement at 3 bpm, 340 psi. drop
closing plug. Displace cement with: 20 bbls water at 5 bpm, 330 psi (HES). Swap to rig pumps and pump 113.9 bbls 9.7 ppg spud mud at 7 bpm, 687 psi. Slow to
2 bpm with 10 bbls to go, FCP 344 psi. Bump plug 2.9 bbls early. Pressure up to 1800 psi and hold for 5 minutes. Bleed back 1.4 bbls and confirm tool closed.
CIP at 03:05. No losses during cement job. 13 bbls of cement returned to surface. Flush surface lines with black water. fill stack with black water ane cycle annular
x 2. Spray off top of annular. R/D Volant tool. Install casing elevators. Offload mud from pits. Prep cellar. Rig up and suck out joint of casing. Pull mousehole.
Remove MPD hardline and drip pan. Remove holefill line. Deflate 20" airboot. Hook up bridge cranes and remove chains from BOPE. Break bolts between spools
Daily Disposal to G&I = 566 bbls, total = 3833 bbls. Daily H2O F/ Lake 2 = 440 bbls total= 3940 bbls. Daily Metal: 3 lb. Total Metal 189 lb. Daily fluid lost down hole
= 19 bbls total = 32 bbls.
10/21/2021 P/U BOPE, Remove Studs from bottom of spool. Center pipe in Wellhead, set Emer. Slips w/ 100K in slips. Assist NES Welder w/7 5/8" Casing cut. L/D 26.61' cut
jt. Install Hydraulic Elevators. Break RCD Clamp and pull riser. Set stack aside. Perform finish cut on csg Stub. Land stack and tighten Flg Bolts. M/U Running tool
and land Packoff. RILDS. Test Packoff to 3800 psi. Test Good. LD Run tool. Welder patch hole in TT #2 gun line. Flush and clean surface equipment in Mud Pits.
Continue to N/U BOPE. install Drip Pan and flow riser, Air Boot and tighten clamp. Install Drain Hoses. Install Beyond 4" Choke Line. M/U Flushing and jet stack
with Black Water. Flush through Flow Line. L/D Flushing tool. Blow down TD PJSM. Change out UPR from 7 5/8" to 2 7/8" x 5 1/2" VBR's. Sim Ops: grease choke
manifold. Mobilize 4" XT 39 XO's, subs and well control equipment to rig floor. M/U dart, TIW, pump in sub and XO to 4-1/2" test joint. Set test plug. Perform BOP
body test - good. Sim Ops: Clean mud pits, take apart MP#1 for inspection. Test BOPE 250/3000 psi on 4" and 4-1/2" test joints. AOGCC Bob noble witness. No
failures. Test gas alarms, flow paddle, and pit sensors. Accumulator drawdown: starting pressure 3000 psi, final 1500 psi. First 200 psi recharge 27 seconds, final
91 seconds. (6)N2 at 2441 psi average. Sim Ops: Change out pods 1, 2, and 3 on MP 1. Break out and L/D XO' pump in sub, TIW and test joint. Blow down
choke/kill lines. Install wear bushing. Dig out cellar to install mousehole, prep rig floor to L/D drill pipe. Cont to clean out cellar and install mousehole. L/D 85 stands
of 5" drill pipe from derrick via mousehole. Cull out joints for Cat V inspection. SimOps: Cont. cleaning pits. Cont. working on mud pump #1. Daily Disposal to G&I =
850 bbls, total = 4683 bbls. Daily H2O F/ Lake 2 = 355 bbls total= 4295 bbls. Daily Metal: 3 lb. Total Metal 189 lb. Daily fluid lost down hole = 19 bbls total = 32
bbls.
10/22/2021 L/D remaining 5" drill pipe from derrick. Sim Ops: continue working on putting MP#1 back together. Clean and clear rig floor. Rig down 5" hydraulic elevators, R/U
4" manual elevators. Change out saver sub to 4" XT-39. Rig up rig tongs, position ST-80 in tripping position. Bring XO's, flot subs and bit to rig floor. Service rig:
grease crown, blocks, top drive, wash pipe, iron roughneck adn drawworks. Check oil in top drive. Check welds on top drive cradle. Perform derrick inspection.
M/U drill out assembly BHA: 6-3/4" bit, 2 flex collars, 2 float subs, 3 joints HWDP, jars, XO to 229'. PUW 41K, SOW 41K. RIH with drill out assembly from 299' to
2953'. Picking up, drifting (2.347") and single in with drill pipe. PUW 72K, SOW 57K, Calculated displacement observed. Set down 5K at 2953'. Fill pipe every
2500'. Wash and ream from 2953' to 2987'. Tag and drill up ES cementer at 2982' (4' low) at 250 gpm, 880 psi, 40 rpms, 2-3Kft-lbs, WOB 6-12K. PUW 72K,
SOW 57K, ROTW 63K. Cont. to wash and ream as necessary chasing debris from ES cementer down to 3132'. Cont to RIH with drill out assembly from 3132' to
6678'. Picking up, drifting (2.347") and single in with drill pipe. PUW 150K, SOW 58K, Calculated displacement observed. Fill pipe every 2500'. Wash down from
6678' to 6770', and circulate bottoms up at 250gpm, 1215 psi, 20 rpm, 10.5Kft-lbs. PUW 150K, SOW 58K, ROTW 70K. Observe cement stringers with 5-10K
WOB drilling off quickly. Blow down top drive. M/U XO and headpin to string. Flush theough choke and kill. Flood lines. Shut UPR's PT 7-5/8" casing to 3000 psi
for 30 minutes. Pumped 3.5 bbls, bled back 3.5 bbls. Good test. Rig down testing equipment. Drill cement, shoe track and 20' of new hole to 6940'. 250 gpm,
1200 psi, WOB 3-5K staging up to 12K once in open hole, 40 rpm, 8-9Kft-lbs. Tag shoe track equipment 4' deep. Displace to Baradril-N on the fly once in open
hole. Blow down top drive and rig up XO's and pump in sub. Flush and purge system. Perform FIT to 12.0 ppg EMW, pump 0.7 bbls, bled back 0.5 bbls. Pressure
up to 571 psi, TVD at shoe 4236', MW 9.5 ppg. Blow down choke and kill. Rig down. Daily Disposal to G&I = 171 bbls, total = 4854 bbls. Daily H2O F/ Lake 2 = 0
bbls total= 4295 bbls. Daily Metal: 0 lb. Total Metal 189 lb. Daily fluid lost down hole = 0 bbls total = 32 bbls.
10/23/2021 After FIT, Monitor Well, Static, pump dry job, R/D Test Equipment. PJSM, POOH with 6-3/4" drill-out assembly from 6898' to 225'. PUW 158K, SOW 63K @ 6898'.
Calculated displacement PJSM, Single in the hole from 225' picking up 4" DP to 1230'. PU 48K SO 48K PJSM, POOH from 1230' to 225' standing back 4" DP
Work BHA: Rack back 2 stands 4" HWDP, Rack back 1 stand Collars. L/D motor and bit. Bit grade 11-WT-A-E-I-NO-BHA. Clean and clear rig floor. M/U stack
washing tool 'Johnny Whacker'. Flush out stack. Blow down top drive. M/U 6-3/4" drilling BHA: PDC bit, Geo-Pilot, GM collar, ADR collar, PWD, DM and TM. Plug
in and upload MWD. M/U (2) NM flex collars, (2) float subs, Jars and HWDP to 288'. Pick up, drift (2.347") and single in hole with 4" XT-39 drill pipe from 288' to
6783'. Fill pipe, break in Geo-Pilot, and shallow pulse test at 2177'. PUW 139K, SOW 58K. Calc displacement observed. Service rig: grease crown, blocks, top
drive, wash pipe, iron roughneck, drawworks, cobra head, spinners. Check oil in top drive. Pull trip nipple, set MPD bearing. Flood lines and test to 250/1250 -
good. Fill pipe, obtain parameters and wash down from 6783' to 6940' at 250 gpm, 1260 psi, 80 rpms, 8Kft-lbs, ECD 9.67ppg EMW with 9.5 ppg md. PUW 123K,
SOW 65K, ROT 81K. Pass through shoe with no rotary/pumps - clean. Drill 6-3/4" production from 6940' to 7385' (Total=445', AROP=74fph) at 250 gpm, 1260
psi, 120 rpm, 8500 ft-lbs, WOB 3-7K, ECD 10.62 ppg EMW with 9.5 ppg mud. Max gas 781U. PUW 142K, SOW 54K, ROT 83K. Backream full stands. MPD
chokes wide open. In SB OA sands. Drilled 3 concretions for a total thickness of 15' (0.2% of the lateral). Distance to WP3 8.61', 8.04' Low, 3.07' Left Daily
Disposal to G&I = 404 bbls, total = 5258 bbls. Daily H2O F/ Lake 2 = 250 bbls total= 4545 bbls. Daily Metal: 0 lb. Total Metal 189 lb. Daily fluid lost down hole = 0
bbls total =0 bbls. Total fluid lost Surface hole=32 bbls.
10/24/2021 Cont. to Drill 6-3/4" production from 7385' to 8117' (Total=732', AROP=122fph) at 250 gpm, 1305 psi, 120 rpm, 9000 ft-lbs, WOB 2-7K, ECD 10.62 ppg EMW with
9.5 ppg mud. Max gas 1661U. PUW 148K, SOW 50K, ROT 78K. Backream full stands. MPD chokes wide open. In SB OA sands. Cont. to Drill 6-3/4"
production from 8117' to 8766' (Total=649', AROP=108fph) at 250 gpm, 1305 psi, WOB 2-8K, 120 rpm, 9500 ft-lbs, ECD 10.64 ppg EMW with 9.5 ppg mud. Max
gas 1635U. PUW 144K, SOW 50K, ROT 80K. Backream full stands. MPD chokes wide open. In SB OA sands. Cont. to Drill 6-3/4" production from 8766' to
9363' (Total=597', AROP=99fph) at 250 gpm, 1385 psi, WOB 2-9K, 120 rpm, 9500 ft-lbs, ECD 10.94 ppg EMW with 9.5 ppg mud. Max gas 1564U. PUW 134K,
SOW 51K, ROT 79K. Backream full stands. MPD chokes wide open. In SB OA sands. Cont. to Drill 6-3/4" production from 9363' to 9865' (Total=502',
AROP=84fph) at 250 gpm, 1445 psi, WOB 2-16K, 120 rpm, 10-11Kft-lbs, ECD 10.9 ppg EMW with 9.5 ppg mud. Max gas 1620U. PUW 139K, SOW 45K, ROT
77K. Backream full stands. MPD chokes wide open. In SB OA sands. Drilled 17 concretions for a total thickness of 53' (1.9% of the lateral). Distance to WP#3:
34.58', 21.15' Low, 27.35' Right Daily Disposal to G&I = 456 bbls, total = 5714 bbls. Daily H2O F/ Lake 2 = 280 bbls total= 4825 bbls. Daily Metal: 0 lb. Total Metal
189 lb. Daily fluid lost down hole = 0 bbls total =0 bbls. Total fluid lost Surface hole=32 bbls.
10/25/2021 Cont. to Drill 6-3/4" production from 9865' to 10,430' (Total=565', AROP=94fph) at 250 gpm, 1490 psi, WOB 4-16K, 120 rpm, 9-10Kft-lbs, ECD 11.08 ppg EMW
with 9.5 ppg mud. Max gas 1710U. PUW 125K, SOW 45K, ROT 80K. Backream full stands. MPD chokes wide open. In SB OA sands. Pump tandem high vis,
low vis weep at 10,119', 10% increase in cuttings back on time. Cont. to Drill 6-3/4" production from 10,430' to 11,059' (Total=629', AROP=105fph) at 250 gpm,
1545 psi, WOB 2-14K, 120 rpm, 10.5Kft-lbs, ECD 11.16 ppg EMW with 9.5 ppg mud. Max gas 1442U. PUW 121K, SOW 51K, ROT 78K. Backream full stands.
MPD chokes wide open. In SB OA sands. Cont. to Drill 6-3/4" production from 11,059' to 11,751' (Total=692', AROP=115fph) at 250 gpm, 1640 psi, WOB 2-10K,
120 rpm, 11.5Kft-lbs, ECD 11.36 ppg EMW with 9.5 ppg mud. Max gas 1508U. PUW 126K, ROT 77K. Lost SOW at 11,690'. Backream full stands. MPD chokes
wide open. In SB OA sands. Cont. to Drill 6-3/4" production from 11,751' to 12,445' (Total=694', AROP=116fph) at 250 gpm, 1705 psi, WOB 4-16K, 120 rpm,
11.5Kft-lbs, ECD 11.5 ppg EMW with 9.5 ppg mud. Max gas 1627U. PUW 131K, ROT 75K. Backream full stands. MPD chokes wide open. In SB OA sands.
Drilled 28 concretions for a total thickness of 112' (2.1% of the lateral). Distance to WP#3: 25.15', 24.32' Low, 6.44' Right Daily Disposal to G&I = 342 bbls, total =
6056 bbls. Daily H2O F/ Lake 2 = 300 bbls total= 5125 bbls. Daily Metal: 0 lb. Total Metal 189 lb. Daily fluid lost down hole = 0 bbls total =0 bbls. Total fluid lost
Surface hole=32 bbls.
10/26/2021 Cont. to Drill 6-3/4" production from 12.445' to 13,204' (Total=759', AROP=126.5fph) at 250 gpm, 1755 psi, WOB 4-16K, 120 rpm, 10-12kft-lbs, ECD 11.5 ppg
EMW with 9.5 ppg mud. Max gas 1627U. PUW 131K, ROT 75K. Backream full stands. MPD chokes wide open. In SB OA sands. Cont. to Drill 6-3/4" production
from 13.204' to 13,866' (Total=662', AROP=110fph) at 250 gpm, 1840 psi, WOB 6-12K, 120 rpm, 11-12kft-lbs, ECD 11.69 ppg EMW with 9.5 ppg mud. Max gas
1655U. PUW 133K, ROT 77K. Backream full stands. MPD chokes wide open. In SB OA sands. Cont. to Drill 6-3/4" production from 13.866' to 14,060'
(Total=194', AROP=97fph) at 250 gpm, 1840 psi, WOB 6-12K, 120 rpm, 12-13kft-lbs, ECD 11.82 ppg EMW with 9.5 ppg mud. Max gas 1669U. PUW 133K, ROT
77K. Backream full stands. MPD chokes wide open. In SB OA sands. Obtain final survey. Circulate hole clean, pump tandem low vis/wt sweep followed by high
vis/wt (on time 25% increase) and circulate hole clean. Circulate total 4 x bottoms up, racking stand back every BU at 250 gpm, 1780 psi, 120 rpm, 11-12Kft-lbs,
ECD 11.3 ppg with 9.5 ppg mud, Max gas 1636U. PUW 133K, ROT 75K. Wash and ream from 13,890' to 14,060' at 250 gpm, 1800 psi, 120 rpms 10Kft-lbs. Tag
bottom, no fill. Pump SAPP train (3x 40bbls SAPP pill followed by 20 bbls Quickdril) displace to 9.5ppg QuickDril 250gpm, ICP 1800psi, FCP 1330psi, 120rpms,
10-12Kft-lbs, max gas 17.5U, ECD 10.87ppg, reciprocating pipe. Perform passing PST test in/out. Obtain SPR's. Monitor well through MPD, static. PUW 139K
SOW 43K BROOH from 14,060 to 13,267' at 250 gpm, 1290 psi, 120 rpms, 10-11Kft-lbs. Max gas 25U. ECD's 10.8 ppg with 9.5 ppg QuickDril. PUW 141K,
SOW N/A, ROTW 85K. MPD chokes full open. Drilled 31 concretions for a total thickness of 124' (1.7% of the lateral). Distance to WP03: 2.24', 0.58' High,
2.16'Left Daily Disposal to G&I = 694 bbls, total = 6750 bbls. Daily H2O F/ Lake 2 = 540 bbls total= 5665 bbls. Daily Metal: 0 lb. Total Metal 189 lb. Daily fluid lost
down hole = 0 bbls total =0 bbls. Total fluid lost Surface hole=32 bbls.
10/27/2021 BROOH from 13,267 to 9,491' at 280 gpm, 1300 psi, 120 rpms, 10-11Kft-lbs. Max gas 134U. ECD's 10.6 ppg with 9.5 ppg QuickDril. PUW 155K, SOW 55K,
ROTW 78K. MPD chokes full open. Pulling Speed 40-60 fph. (Regain SOW @ 11,700') Lost 34 bbls on BROOH BROOH from 9,194' to 7,171' MD 280 gpm,
1215 psi, 120 rpms, 8.5Kft-lbs. Max gas 96U. ECD's 10.3 ppg with 9.5 ppg QuickDril. PUW 135K, SOW 61K, ROTW 80K. MPD chokes full open. Pulling Speed
40-70 fph CBU 2X While pulling F/ 7,171' to 7,103' MD. 280/ mpd 281 gpm 1,215 psi 120 rpm Trq 8.5k ECD 10.3 Max Gas 30u. MPD 100% open. Cont BROOH
F/ 7,103' to 6,851' MD 280/ mpd 281 gpm 1,215 psi120 rpm Trq 8.5k ECD 10.3 Max Gas 20u. MPD 100% open. P/U 133k SLK 61k ROT 80k. Pull speed 15-25
ft/min. MPD 100% open. Pull through shoe W/ no issues. Pump 30 bbl 9.6 ppg 180 vis sweep on time no increase. CBU 2X. Rot Rec F/ 6,851' to 6,788' MD. 280/
mpd 281 gpm 1,220 psi 70 rpm Trq 8k ECD 10.27 Max Gas 19u. MPD 100% open. Perform passing PST W/ 100 micron screen. Monitor well 10 min, static. Blow
down TD & GEO Span. Lost 41 bbl trip. PJSM Drain stack. Pull L/D RCD Bearing as per Beyond rep onsite. Remove bowl saver and install trip nipple. Pump 20 bbl
corrosion inhibited dry job. B/D TD. C/O leaking air boot on riser. PJSM POOH L/D 4" 14# S-135 XT39 F/ 6,851' to 3,756' MD. P/U 95k SLK 63k Lost 4.6 bbls.
PJSM POOH L/D 4" 14# S-135 XT39 F/ 3,756' to 297' MD. P/U 44k SLK 44k Lost 5.4 bbls. PJSM L/D 3 jnts 4" HWDP, Hyd Jars, 2 ea NM FC, X/O & FS. 1.95"
OD Rabbit on top of FS. Down load MWD. SIMOPS L/D X/O's & FS. Cont L/D TM, DM, PWD, ILS missing tile inserts F/ back reaming, ADR, ILS & GM collars. L/D
GeoPilot. Break 6..75" Bit grade 8-8-BC-S-X-1-BT-TD. Severe damage. Bit had two broken pieces off two blades about 2.5" on one and 4" off the other. PJSM
Clean and clear rig floor. L/D Remaining BHA components F/ rig floor. Daily Disposal to G&I = 1333 bbls, total = 8083 bbls. Daily H2O F/ Lake 2 = 290 bbls total=
5955 bbls. Daily Metal: 0 lb. Total Metal 189 lb. Daily fluid lost down hole = 80 bbls total =80 bbls. Total fluid lost Surface hole=32 bbls.
14,060'
10/28/2021 PJSM C/O Elevators to 4.5" 75T YC. Move ST80 to storage position. R/U Weatherford Power Tongs. P/U M/U Solid Guide Shoe & 4.5" 13.5# L-80 W625 jnt to 4.5"
13.5# L-80 W625 100 micron screens W/ centralizer RIH to 7,311' MD. Trq 9.6 ft/lb. P/U 141k SLK 70k. Parameters at 6,901' MD 10 rpm trq 8.2k 20 rpm trq 8.7k
ROT 93k. No losses. P/U M/U 5.5" X 7.63" SLZXP as per Baker Rep onsite. (11.48' tie PJSM M/U X/O 3.5" IF P X XT39 B. Pump through SLZXP 2 bpm 50 psi no
issue. Convey 4.5" Liner W/ 4" 14# S-135 XT39 D.P. F/ derrick F/ 7,311' to 9,322' MD. Run speed 60 ft/min. P/U 159k SLK 59k. Cont to convey 4.5" Liner W/ 4"
29.7# S-135 XT39 HWDP F/ pipe shed (80 Jnts) F/ 9,322' to 11,768' MD. Drift 2.375" OD. Run speed 80 ft/min. P/U 225k SLK 45k. Convey 4.5" Liner W/ 4" 14# S-
135 XT39 D.P. F/ derrick F/ 11,768' to 12,500' MD. Run speed 15 ft/min. Lost SLK WT at 12,459' MD. M/U TD and us 5k block weight to Cont in hole. At 12,522’
MD working string W/ 1-2 RPM Trq stall set at 10k. SLK to 20k and pull to 225k. Working 1-5’. Increase Trq stall to 11.5k working trq down string W/ 30-35k string
WT. Able to Cont TIH W/ 1-2 RPM SLK 35-45k at 1-7 ft/min TRQ 8.7-11.5k to 13,,778’ MD. Lost 29 bbls. PJSM Cont convey 4.5" Liner W/ 4" 14# S-135 XT39 D.P.
F/ derrick F/ 13,778' to 14,058' MD 1-2 RPM SLK 35-60k at 1-7 ft/min TRQ 8.7-11.5k PJSM P/U 10' stretch 225k String WT. Break Circ 5 bpm 815 psi string
volume. Drop 1.25"OD Phenolic ball. Pump down at 5 bpm 815 psi slow to 3 bpm 390 psi last 15 bbls. Ball seated press up to 1,200 psi, press up to 2,000 psi hold
SLK down 60k string WT. Press up to 3,500 psi W/ rig. Use test pump Press up to 3,600 psi sheared out. Hanger set. Drop 1.5" OD Phenolic ball 5 bpm 810 psi
slow to 3 bpm 389 psilast 15 bbls. Ball seated press up to 3,000 psi hold 2 min, cont to press up to 3,624 psi W/ rig. Use test pump to 4,290 psi release F/ HRD.
Break Circ 3 bpm 320 psi shut down. P/U Broke over at 167k running tool released. SLK to 76k string WT, P/U 160k slack to 72k free. P/U to 105k 20 rpm trq 9.6k
ROT 88k slack down and set SLZXP W/ 60k as per Baker rep onsite. TOL at 6,758' MD. Test SLZXP to 1,500 psi 10 min, good. Pump 1.5 bbl, bled 1.5 bbls. R/D
B/D PJSM POOH L/D 4" D.P. & 4" HWDP to pipe shed F/ 6,758' to 4,014' MD. P/U 100k SLK 75k. Lost 2.5 bbls. Daily Disposal to G&I = 0 bbls, total = 8083 bbls.
Daily H2O F/ Lake 2 = 0 bbls total= 5955 bbls. Daily Metal: 0 lb. Total Metal 189 lb. Daily fluid lost down hole = 34 bbls total =114 bbls. Total fluid lost Surface
hole=32 bbls.
Activity Date Ops Summary
10/29/2021 Continue to L/D Drill Pipe from 4041' to surface. L/d liner Hgr Running tool. Disp. Cal 48 bbls, Actual 58 bbls, Losst 10 bbls. Clean and Clear Rig Floor.,PJSM, M/U
XO and Mule Shoe on 4" DP. TIH out of Derrick with remaining 4" DP to 3475'.,PJSM, M/U TIW and space out, hang Blocks, unspooldrum and remove Dog Nut,
cut 17 wraps from drum, remove brass from Dead Man , run line through drum and reinstall Dog nut, slip line back onto Drum, Tq Dead Man, Cut 107', 1445' Left
on Drum, Accu TM=27993. Check Brake Tolerance on Drum. Calibrate Drum position Encoder#1 1st layer, calibrate Block Position f/Crown/Floor saver,Rig
Service, Grease Top Drive, Iron Roughneck. C/O Lower/Upper Block Dies, Grease Crown, complete monthly crown sheave woble EAM. Complete monthly Block
Sheave Wobble EAM.,PJSM Pump corrosion inhibited dry job. POOH L/D all 4" DP from 3475' to surface.,PJSM R/U Weatherford 4.5" handling Equip. Stage
jewelry in pipe shed. R/U Weatherford Trq Turn Equip.,PJSM P/U M/U 4.5" 12.6# L-80 Vam Tubing, Baler Loc all components below TNT Packer. RIH 4.5" Gas Lift
Completion to 3,090' MD as per tally. P/U 58k SLK 51k. Trq Turn Vam Top 4,440 ft/lb. Run speed 30 ft/min as per TNT Packer recommendation. Lost 5 bbls.,PJSM
Cont RIH 4.5" 12.6# L-80 Vam Gas Lift Completion F/ 3,090' to 6,661' MD as per tally. P/U M/U Hanger and land as per Vault rep onsite. Set TWC. Trq Turn Vam
Top 4,440 ft/lb. Run speed 30 ft/min as per TNT Packer recommendation. Lost 4 bbls. P/U 95k SLK 61k. (WT in Hngr 26k). R/D Weatherford Equip.,PJSM P/U Jnt
and Johnny Wacker. Flush stack, choke & kill lines. B/D choke and kill lines. Drain stack.,Daily Disposal to G&I = 275 bbls, total = 8358 bbls. Daily H2O F/ Lake 2 =
0 bbls total= 5955 bbls. Daily Metal: 0 lb. Total Metal 189 lb. Daily fluid lost down hole = 28 bbls total =142 bbls. Total fluid lost Surface hole=32 bbls.
10/30/2021 Blow Down Top Drive both ways. Rig up Head Pin and hose to bleeder. Blow down hole fill line and kill line to verify clear. Rig down Jt and L/D same. Clean and
clear Rig Floor of XT-39 XO's, TIW and Dart valves.,PJSM, Pull Bell Nipple and install test cap on MPD, R/D Choke, Kill and hole fil lines, Remove 4" line from
ORBITS Valve, pull Drip Pan, remove turn buckles from stack, break and 4 bolt stack and MPD Head while removing Kill Line for 5 year Inspection. Prep MP #1 for
6 month cross head Inspection. Replace pump on Degasser.,PJSM, Continue to R/D Choke and Kill Lines in Cellar. Install flange and 1502 cap on kill line. R/D 18"
DSA Spacer Spool, R/D Starting Head, Rack Back BOP and secure same. SIMOPS: Work on Mud Pump #1 6 month EAM, off loading fluid from pits and clean
same, Install 8" Otis Flg Adapt on bottom of Ball and Rod Launcher.,PJSM N/U Tubing Hanger and Tree. Test void 500/5000 psi. PT Tree, Tightened flange bolts.
Cont test 500/5000 psi good.,PJSM R/U 2" HP hoses and low trqs to reverse Circ. R/U LRS. SIMOPS Clean pits. Inspect MP #2.,PJSM Reverse Circ 240 bbl 8.5
ppg 2% corrosion inhibited brine W/ rig pumps. Stage up pumps .5 to 3 bpm ICP 150 psi FCP 305 psi. Shut in IA and swap to LRS. LRS pump 136 Diesel FP at
1.6 bpm ICP 282 psi FCP 298 psi.,PJSM R/D HP lines & Otis on top of tree. R/U ball and rod launcher to tree. Drop 1.875” OD ball and roller rod. Let fall while R/D
Launcher. R/U HP lines to tree.,PJSM LRS PT lines to 4,000 psi for 5 min, good. Line up LRS to 4.5" tubing. Press up to 500 psi for 5 min. Cont Press up packer
set at 2,350 psi cont to 3,675 psi IA 424 psi OA 77 psi. Hold for 30 min MIT-T passed. Pump 1.08 bbs. Bleed 4.5" tubing to 2,000 psi 0.6 bbls back. Line up on IA
Press up to 3,672 psi Tub 2,606 psi OA 79 psi. Lost 101 psi in 5 min, 54 psi after 12 min.,Bumped Press up to 3,674 psi Tub 2,617 psi Tub 2,592 psi OA 81 psi for
30 min, 15 min 52 psi loss 26 psi last 15 min, pass. Bleed down 4.5" tubing to 950 psi shear valve did not shear. Unable to bleed any more to LRS due to brine in
tubing. Switch to IA and Press up to 3,670 psi, valve sheared. Bleed down IA to 346 psi. Bled back 3.4 bbls. R/D LRS. SIMOPS R/D floor Equip. Bridle up. Prep MP
#2 for cross head insp.,PJSM Scope down derrick, Cont cleaning pits. Daily Disposal to G&I = 520 bbls, total = 8878 bbls. Daily H2O F/ Lake 2 = 0 bbls total= 5955
bbls. Daily Metal: 0 lb. Total Metal 189 lb. Daily fluid lost down hole = 0 bbls total =142 bbls. Total fluid lost Surface hole=32 bbls.
10/31/2021 Disconnect inner connects. SIMOPS U-Tube 4.5" Tubing and IA. Release rig at 06:00.
50-029-23191-02-00API #:
Well Name:
Field:
PBW L-200A
Prudhoe Bay West
Hilcorp Energy Company Composite Report
10/14/2021Spud Date:
pass.
TD Shoe Depth: PBTD:
No. Jts. Returned
RKB RKB to BHF RKB to THF
Jts.
2
1
95
74
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:X Yes No
Casing Rotated?X Yes No Reciprocated?X Yes No % Returns during job
Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:X Yes No
Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job
Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Post Job Calculations:
Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped:
Cmt returned to surface: Calculated cement left in wellbore:
OH volume Calculated: OH volume actual: Actual % Washout:
Casing (Or Liner) Detail
Casing 7 5/8 29.6 L-80
88 0.8110SECOND STAGERig
3:05
Returns to surface
Shoe @ 6906.61 FC @ Top of Liner #N/A6,819.23
250 309
81 228
Spud Mud/Spacer
CASING RECORD
County State Alaska Supv.
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.PBW L-200A Date Run
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
VAMTOP VAM 79.43 #N/A 6,825.17
9.7 6
1800
10
10.7 110 4.5
100
850
Bump Plug?FIRST STAGE10Tuned 61
15.8
344
3
9.7 7 113.9/116.8
290.1/291.3
1350
68
Rig/HES
15.8 57
Bump press
Returns after opening stage tool
Bump Plug?
Yes
17:30 10/20/2021 2,978
2978.46
CEMENTING REPORT
Tuned
215 2.88
Stage Collar @
56
Bump press
100
13
ES Cementer Closure OK
2058.4
22
ArcticCem
Type
Type I/II 105
12 120
Water
RKB to CHF
No. Jts. Delivered No. Jts. Run
Length Measurements W/O
Threads
Ftg. Delivered Ftg. Run Ftg. Returned
Ftg. Cut Jt. Ftg. Balance
www.wellez.net WellEz Information Management LLC ver_04818br
7208.4Water
3.2
Float Collar 8 3/4 L-80 VAMTOP DHP 85.37 #N/A 6,819.23
Casing 7 5/8 29.6 L-80 VAMTOP VAM 118.84 #N/A 6,785.76
Baffle Adapter 8 3/4 29.6 L-80 VAMTOP HES 124.78 #N/A 6,799.99
Casing 7 5/8 29.6 L-80 VAMTOP VAM 3,905.67 #N/A 2,999.10
Pup Joint 7 5/8 29.6 L-80 VAMTOP VAM 3,923.26 #N/A
ES Cementer 8 3/4 29.6 L-80 VAMTOP HES 3,926.31 #N/A 2,978.46
Pup Joint 7 5/8 29.6 L-80 VAMTOP VAM 3,943.52 #N/A 2,961.25
Casing1 7 5/8 29.6 L-80 VAMTOP VAM 6,869.98 #N/A 34.79
Cut Joint 7 5/8 29.6 L-80 VAMTOP VAM 6,881.16 #N/A 23.61
Type I/II 287 2.35
Type I/II 277 1.16
4.4
1.17
10/21/2021 surface
Spud Mud
Returns to surface
2,978
100
13
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Chelsea Wright Digitally signed by Chelsea
Wright
Date: 2021.11.03 09:13:29 -08'00'
Benjamin Hand Digitally signed by Benjamin Hand
Date: 2021.11.03 09:39:29 -08'00'
STATE OF ALASKA
13
OIL AND GAS CONSERVATION COMMISSION Reviewed By:
P.1. Supry
BOPE Test Report for: PRUDHOE BAY UN ORIN L -200A Comm
Contractor/Rig No.: Hilcorp Innovation ' PTD#: 2210770 - DATE: 10/21/2021, Inspector Bob Noble Insp Source
Operator: Hilcorp North Slope, LLC Operator Rep: James Lott Rig Rep: Matt Vanhose Inspector
Type Operation: DRILL Sundry No: Test Pressures: Inspection No: bopRCN211022133903
Rams: Annular: Valves: MASP:
Type Test: BIWKLY 250/3000' 250/3000' 250/3000 1437 ' Related Insp No:
TEST DATA
MISC. INSPECTIONS:
MUD SYSTEM:
ACCUMULATOR SYSTEM:
Upper Kelly
I
P/F
Lower Kelly
Visual
Alarm
Time/Pressure P/F
Location Gen.:
P_
Trip Tank
-P- -
P
System Pressure 3000_ -
P
Housekeeping:
P '
Pit Level Indicators
- P
P "
Pressure After Closure 1500 -
P
PTD On Location
P -
Flow Indicator
P -
P
200 PSI Attained 27
P
Standing Order Posted
-P -_
Meth Gas Detector
- P
P
Full Pressure Attained 91
P "
Well Sign
P -
H2S Gas Detector
P `
P
Blind Switch Covers: All Stations-
P '
Drl. Rig
P -
MS Misc
NA
NA
Nitgn. Bottles (avg): 6 �&' 2241 "
P -
Hazard Sec.
P _
P -
Inside Reel Valves 0
NA
ACC Misc 0
NA_
Misc
NA
Check Valve
0
NA
FLOOR SAFTY VALVES:
BOP STACK:
Quantity
P/F
Upper Kelly
I
P
Lower Kelly
1
P "
Ball Type
_ _ 2 ----
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 13 5/8" -
P
Manual Chokes 1
P
#1 Rams
1 2 7/8" x 5 1/2
Hydraulic Chokes 1
P
#2 Rams
1 Blinds -
P -
CH Misc 0
NA
#3 Rams
1 2 7/8" x 5 1/2
P
#4 Rams
0
NA
#5 Rams
0
NA
INSIDE REEL VALVES:
#6 Rams
_ _0
NA
(Valid for Coil Rigs Only)
Choke Ln. Valves
1 _ 3 1/8"
P -
Quantity
P/F
HCR Valves
2 " 3 1/8"
P -
Inside Reel Valves 0
NA
Kill Line Valves
2 -31/8"
P "
Check Valve
0
NA
BOP Misc
0
NA
Number of Failures: 0 I/ Test Results
Remarks: Very good test.
Test Time 5
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 North Slope, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Re: Prudhoe Bay Field, Schrader Bluff Oil Pool, PBU L-200A
Hilcorp North Slope, LLC
Permit to Drill Number: 221-077
Surface Location: 2568' FSL, 3704' FEL, Sec. 34, T12N, R11E, UM, AK
Bottomhole Location: 1395' FSL, 1451' FWL, Sec. 21, T12N, R11E, UM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced 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 AOGCCwithin 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 October, 2021.
Jeremy Price
Digitally signed by
Jeremy Price
Date: 2021.10.08
14:04:45 -08'00'
1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for:
Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates
Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas
2. Operator Name: 5. Bond: Blanket Single Well 11. Well Name and Number:
Bond No.
3. Address:6. Proposed Depth:12. Field/Pool(s):
MD: 14,059' TVD: 4,155'
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): 75.49' 15.Distance to Nearest Well Open
Surface: x-583209 y- 5978290 Zone- 4 49.1' to Same Pool: 855'
16.Deviated wells: Kickoff depth: 3375 feet 17.Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 92 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
9-7/8" 7-5/8" 29.7# L-80 Vamtop 7,055' Surface Surface 7,055' 4,226'
6-3/4" 4-1/2" 13.5# L-80 Ezgo HT 7,638' 6,421' 4,119' 14,059' 4,155'
19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations)
Junk (measured):
None
TVD
110'
2,671
2,505' - 4,499'
4,316' - 4,427'
4,423' - 4,370'
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: Joseph Engel
Monty Myers Contact Email:jengel@hilcorp.com
Drilling Manager Contact Phone:777-8395
Date:
Permit to Drill API Number: Permit Approval
Number:Date:
Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales:
Samples req'd: Yes No Mud log req'd: Yes No
H2S measures: Yes No Directional svy req'd: Yes No
Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No
Post initial injection MIT req'd: Yes No
APPROVED BY
Approved by: COMMISSIONER THE COMMISSION Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
PBU L-200A
Prudhoe Bay Field
Schrader Bluff Oil Pool,
Orion Development Area
Cement Quantity, c.f. or sacks
Commission Use Only
See cover letter for other
50-029-23191-02-00 requirements.
515 sx Class 'G'
7,282' - 7,548'4-1/2"
7-5/8"
Total Depth MD (ft): Total Depth TVD (ft):
107205344
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
Uncemented Screen Liner
1437
1701' FSL, 1048' FWL, Sec. 27, T12N, R11E, UM, AK
1395' FSL, 1451' FWL, Sec. 21, T12N, R11E, UM, AK
00-001
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
Hilcorp North Slope, LLC
2568' FSL, 3704' FEL, Sec. 34, T12N, R11E, UM, AK ADL 028239 & 047447
5120
18.Casing Program: Top - Setting Depth - BottomSpecifications
1824
Cement Volume MDSize
Plugs (measured):
(including stage data)
Stg 1 L - 365 sx / T - 267 sx
Stg 2 L - 139 sx / T - 105 sx
3,375' 2,416'13,067'4,370'
LengthCasing
3375 , 3400, 5050 ,7122
None
Conductor/Structural 20" x 34"78'
Effect. Depth MD (ft): Effect. Depth TVD (ft):
Authorized Title:
Authorized Signature:
4-1/2"
3,555' - 7,872'
Uncemented Tieback Liner
Uncemented Slotted Liner
Liner
Liner
4,317'
266'
5,515'
Intermediate
Authorized Name:
9,168'
October 12, 2021
7,537' - 13,052'
21. I hereby certify that the foregoing is true and the procedure approved herein will not be
deviated from without prior written approval.
Surface
Perforation Depth TVD (ft):
GL / BF Elevation above MSL (ft):
Perforation Depth MD (ft):
3,840'
260 sx Arctic Set (Approx.) 110'
3,871'10-3/4" 723 AS Lite, 338 sx Class 'G'
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
10.6.2021
By Samantha Carlisle at 8:54 am, Oct 07, 2021
Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp Alaska, LLC, ou=Technical
Services - AK Drilling,
email=mmyers@hilcorp.com
Reason: I am approving this document
Date: 2021.10.06 17:10:35 -08'00'
Monty M
Myers
X
X
221-077
BOPE test to 3000 psi. Annular to 2500 psi.
X
X
DLB
MGR08OCT2021 DLB 10/07/2021
X
DSR-10/7/21
X
X
dts 10/8/2021
10/8/21
Jeremy Price Digitally signed by Jeremy Price
Date: 2021.10.08 14:06:28 -08'00'
Prudhoe Bay West
(PBU) L-200A
Drilling Program
Version 2
10/6/2021
Table of Contents
1.0 Well Summary ........................................................................................................................... 2
2.0 Management of Change Information ........................................................................................ 3
3.0 Tubular Program ....................................................................................................................... 4
4.0 Drill Pipe Information ............................................................................................................... 4
5.0 Internal Reporting Requirements ............................................................................................. 5
6.0 Current & Planned Wellbore Schematic .................................................................................. 6
7.0 Drilling / Completion Summary ................................................................................................ 8
8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 9
9.0 MIRU & Test BOPE ................................................................................................................ 11
10.0 Pull 4-1/2” Kill String & PT 10-3/4” Casing & Drift .............................................................. 13
11.0 Mill 9-7/8” Window and Kick Off ........................................................................................... 14
12.0 Drill 9-7/8” Hole Section .......................................................................................................... 16
13.0 Run 7-5/8” Casing .................................................................................................................... 19
14.0 Cement 7-5/8” Intermediate Casing ........................................................................................ 24
15.0 Drill 6-3/4” Hole Section .......................................................................................................... 29
16.0 Run 4-1/2” Screen Liner .......................................................................................................... 34
17.0 Run Gas Lift Completion & Post Rig Work ........................................................................... 38
18.0 Innovation Rig Diverter Schematic ......................................................................................... 41
19.0 Innovation Rig BOP Schematic ............................................................................................... 42
20.0 Wellhead Schematic ................................................................................................................. 43
21.0 Days Vs Depth .......................................................................................................................... 44
22.0 Formation Tops & Information............................................................................................... 45
23.0 Anticipated Drilling Hazards .................................................................................................. 47
24.0 Innovation Rig Layout ............................................................................................................. 51
25.0 FIT Procedure .......................................................................................................................... 52
26.0 Innovation Rig Choke Manifold Schematic ............................................................................ 53
27.0 Casing Design ........................................................................................................................... 54
28.0 MASP ....................................................................................................................................... 55
29.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 57
30.0 Surface Plat (As Built) (NAD 27) ............................................................................................. 58
31.0 Offset Wells TVD MW............................................................................................................. 59
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Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
1.0 Well Summary
Well PBU L-200A
Pad Prudhoe Bay L Pad
Planned Completion Type Gas Lift on 4-1/2” Tubing
Target Reservoir(s) Schrader Bluff OA Sand
Planned Well TD, MD / TVD 14,059’ MD / 4,155’ TVD
PBTD, MD / TVD 14,049’ MD / 4,155’ TVD
Surface Location (Governmental) 2568' FSL, 3704' FEL, Sec 34, T12N, R11E, UM, AK
Surface Location (NAD 27) X=583,209.27 , Y= 5,978,289.74
Top of Productive Horizon
(Governmental)1701' FSL, 1048' FWL, Sec 27, T12N, R11E, UM, AK
TPH Location (NAD 27) X= 582624.94, Y=5982695.83
BHL (Governmental) 1395' FSL, 1451' FWL, Sec 21, T12N, R11E, UM, AK
BHL (NAD 27) X= 577683.99, Y=5987616.99
AFE Number 211-00049
AFE Drilling Days 20
AFE Completion Days 4
Maximum Anticipated Pressure
(Intermediate) 1410 psig
Maximum Anticipated Pressure
(Production) 1437 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 1824 psig
Work String 5” 19.5# S-135 NC 50
Innovation KB Elevation above MSL: 26.5 ft + 49.1 ft = 75.6 ft
GL Elevation above MSL: 49.10 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
Page 3
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
2.0 Management of Change Information
Page 4
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
3.0 Tubular Program
Hole
Section
OD (in)ID
(in)
Drift
(in)
Conn OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 20” 19.25”---X-52Weld---
13-1/2” 10-3/4” 9.95 9.794 11.75 45.5 L-80 BTC 5210 2470 1040
9-7/8” 7-5/8” 6.875 6.75 8.23 29.7 L-80 VAMTOP 7080 4790 683
6-3/4” 4-1/2” 4.0 3.833 5 11.6 L-80 EZGO HT 7780 6350 267
Comp 4-1/2” 3.958 3.833 4.937 12.6 L-80 VAMTOP 8430 7500 288
4.0 Drill Pipe Information
Hole
Section
OD
(in)
ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn M/U
(Min)
M/U
(Max)
Tension
(k-lbs)
Intermediate 5”4.276”3.25” 6.625”19.5 S-135 DS50 36,100 43,100 560klb
5”4.276”3.25” 6.625”19.5 S-135 NC50 30,730 34,136 560klb
Production 4”3.34 2.688 4.875 14 S-135 XT-39 17,700 21,200 553klb
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
Page 5
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on WellEz.
x Report covers operations from 6am to 6am
x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left
of the data entry area – this will not save the data entered, and will navigate to another data entry.
x Ensure time entry adds up to 24 hours total.
x Try to capture any out of scope work as NPT. This helps later on when we pull end of well
reports.
x Enter the MD and TVD depths EVERY DAY whether you are making hole or not.
5.2 Afternoon Updates
x Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers@hilcorp,
nathan.sperry@hilcorp.com, jengel@hilcorp.com and joseph.lastufka@hilcorp.com
5.3 Intranet Home Page Morning Update
x Submit a short operations update each morning by 7am on the company intranet homepage. On
weekend and holidays, ensure to have this update in before 5am.
5.4 EHS Incident Reporting
x Health and Safety: Notify EHS field coordinator.
x Environmental: Drilling Environmental Coordinator
x Notify Drilling Manager & Drilling Engineer on all incidents
x Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
x Send final “As-Run” Casing tally to mmyers@hilcorp,com jengel@hilcorp.com and
joseph.lastufka@hilcorp.com
5.6 Casing and Cement report
x Send casing and cement report for each string of casing to mmyers@hilcorp.com
jengel@hilcorp.com and joseph.lastufka@hilcorp.com
5.7 Hilcorp Milne Point Contact List:
Title Name Work Phone Cell Phone Email
Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmyers@hilcorp.com
Drilling Engineer Joe Engel 907.777.8395 805.235.6265 jengel@hilcorp.com
Drilling Engineer Nate Sperry 907.777.8450 907.301.8996 nathan.sperry@hilcorp.com
Completion Engineer Brodie Wages 907.564.5006 713.380.9836 david.wages@hilcorp.com
Geologist Kevin Eastham 907.777.8316 907.360.5087 keastham@hilcorp.com
Reservoir Engineer Michael Mayfield 907.564.5097 713.205.0533 mmayfield@hilcorp.com
Drilling Env. Coordinator Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com
EHS Manager Carl Jones 907.777.8327 907.382.4336 cajones@hilcorp.com
Drilling Tech Joe Lastufka 907.777.8400 907.227.8496 Joseph.Lastufka@hilcorp.com
Page 6
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
6.0 Current & Planned Wellbore Schematic
Page 7
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
7-5/8" 29.7# ID = 6.875"
Page 8
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
7.0 Drilling / Completion Summary
PBU L-200A is a sidetrack producer planned to be drilled in the Schrader Bluff OA sand. L-200A is part of
a multi well program targeting the Schrader Bluff sand on PBU L-pad.
The parent bore, L-200, is an abandoned multilateral well targeting multiple lobes of Schrader bluff sand.
The previous operator has already set a whipstock in the 10-3/4” casing at 3,356’ MD, which will be used to
sidetrack the well. L-200 has documented subsidence damage to the surface casing and prior 10-3/4”
integrity issues with a tam port collar sleeve shifting open. A RWO was completed in 2019 to lock the tam
port collar closed, and the surface casing PT to 2000 psi for 30 minutes.
The directional plan is a 9-7/8” intermediate hole and 7-5/8” casing set into the top of the Schrader Bluff OA
sand. A 6-3/4” lateral section will be drilled. A 4-1/2” screen liner will be run in the open hole section and
the well will be produced with a gas lift completion
The Innovation Rig will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately October 14, 2021, pending rig schedule.
Intermediate casing will be run to 7,055’ MD / 4,225’ TVD and cemented to surface via a 2 stage primary
cement job, this will done for subsidence mitigation. Cement returns to surface will confirm TOC at surface.
If cement returns to surface are not observed, necessary remedial action will then be discussed with AOGCC
authorities.
All cuttings & mud generated during drilling operations will be hauled to one of two locations:
Primary: Prudhoe G&I on Pad 4
Secondary: the Milne Point “B” pad G&I facility
General sequence of operations:
1. MIRU Innovation Rig to well site
2. N/U & Test 13-5/8” BOPE
3. Pull 3-1/2” Killstring, test 10-3/4” casing to 2000 psi
4. Mill 10-3/4” Window, Drill 9-7/8” Hole to TD
5. Run and Cement 7-5/8” to surface
6. Drill 6-3/4” lateral to well TD
7. Run 4-1/2” screen liner
8. Run 4-1/2” gas lift completion
9. N/D BOPE, NU Tree, RDMO
Reservoir Evaluation Plan:
1. Intermediate hole: No mud logging. On Site geologist. LWD: GR + Res
2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering)
Page 9
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations,
specific regulations are listed below. If additional clarity or guidance is required on how to comply with
a specific regulation, do not hesitate to contact the Anchorage Drilling Team.
x BOPs shall be tested at 1 week intervals prior to initiating window milling and at (2) week intervals
during the drilling and completion of PBU L-200A. Ensure to provide AOGCC 24 hrs notice prior
to testing BOPs.
x The initial test of BOP equipment will be to 250/3,000 psi & subsequent tests of the BOP equipment
will be to 250/3,000 psi for 5/5 min (annular to 50% rated WP, 2,500 psi on the high test for initial
and subsequent tests).Confirm that these test pressures match those specified on the APD.
x If the BOP is used to shut in on the well in a well control situation or control fluid flow from the
well bore, AOGCC is to be notified and we must test all BOP components utilized for well control
prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP
test.
x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program
and drilling fluid system”.
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”.
o Ensure the diverter vent line is at least 75’ away from potential ignition sources
x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
x Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test
must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a
minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test
pressure must show stabilizing pressure and may not decline more than 10 percent within 30
minutes. The results of this test and any subsequent tests of the casing must be recorded as required
by 20 AAC 25.070(1)”.
AOGCC Regulation Variance Requests:
x No variance requests at this time.
Page 10
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
Summary of Innovation BOP Equipment & Test Requirements
Hole Section Equipment Test Pressure (psi)
12-1/4”x 13-5/8” 5M CTI Annular BOP w/ 16” diverter line Function Test Only
8-1/2”
x 13-5/8” x 5M Control Technology Inc Annular BOP
x 13-5/8” x 5M Control Technology Inc Double Gate
o Blind ram in btm cavity
x Mud cross w/ 3” x 5M side outlets
x 13-5/8” x 5M Control Technology Single ram
x 3-1/8” x 5M Choke Line
x 3-1/8” x 5M Kill line
x 3-1/8” x 5M Choke manifold
x Standpipe, floor valves, etc
Initial Test: 250/3,000
Subsequent Tests:
250/3,000
Primary closing unit: Control Technology Inc. (CTI), 6 station, 3,000 psi, 220 gallon accumulator unit.
Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an electric
triplex pump on a different electrical circuit and emergency pressure is provided by bottled nitrogen.
The remote closing operator panels are located in the doghouse and on accumulator unit.
Required AOGCC Notifications:
x Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
x 24 hours notice prior to spud.
x 24 hours notice prior to testing BOPs.
x 24 hours notice prior to casing running & cement operations.
x Any other notifications required in APD.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov
Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov
Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov
Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
Page 11
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
9.0 MIRU & Test BOPE
9.1 Reservoir abandonment was completed pre-rig via a separate sundry.
9.2 Ensure to review attached surface plat and well tags to make sure rig is over appropriate
conductor.
9.3 Ensure PTD and drilling program are posted in the rig office and on the rig floor.
9.4 Level pad and ensure enough room for layout of rig footprint and R/U.
9.5 Rig mat footprint of rig.
9.6 MIRU Innovation. Ensure rig is centered over wellhead to prevent any wear to BOPE or
wellhead.
9.7 Mud loggers WILL NOT be used on either hole section.
9.8 Ensure 5” liners in mud pumps.
x White Star Quattro 1,300 HP mud pumps are rated at 4,097 psi, 381 gpm @ 140 spm @
96.5% volumetric efficiency.
9.9 RU to pull BPV
9.10 RU to pump down tubing and take returns from IA to a take. Pump atelast 1 truck of seawater w/
soap followed by spacer and 9.5ppg brine.
9.11 Flow check well to ensure fluids are balanced.
9.12 Install BPV, N/D the tree. Install test dart in the BPV. Verify lifting threads are good and check
XO for landing joint. Count turns in to hanger. Well head hand should do a void test and if
needed pack the hanger with graphite for the bop test.
9.13 NU 13-5/8” x 5M BOP as follows:
x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13-
5/8” x 5M mud cross / 13-5/8” x 5M single gate
x Double gate ram should be dressed with 2-7/8” x 5-1/2” VBRs in top cavity,blind ram in
bottom cavity.
x Single ram can be dressed with 2-7/8” x 5-1/2” VBRs or 5” solid body rams
x NU bell nipple, install flowline.
x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to
mud cross).
x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual
valve
at least
Page 12
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
9.14 RU MPD RCD and related equipment
9.15 Run 5” BOP test plug
9.16 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min.
x Test with 5” test joint and test VBR’s with 3-1/2” test joint
x Confirm test pressures with PTD
x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure
is trapped underneath test plug
x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech
9.17 RD BOP test equipment
9.18 Mix 9.5 ppg milling fluid.
9.19 Set wearbushing in wellhead.
9.20 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole
section.
24 hour notice to AOGCC to witness.
Page 13
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
10.0 Pull 4-1/2” Kill String & PT 10-3/4” Casing & Drift
10.1 RU tubing handling equipment
x Kill string is 4-1/2” 12.6# 13cr-85 VAMTOP
x Kill string length: 3362’ MD
10.2 PU landing joint or spear and engage tubing hanger
10.3 Backout lock down screws
10.4 Pull tubing hanger with landing joint/xo to the rig floor, have appropriate protectors ready.
10.5 POOH, laying down 4-1/2” killstring
10.6 RD casing equipment. RU casing test equipment.
10.7 Pressure test 10-3/4” casing to 2,000psi for 30 min, chart test. Ensure rams are used to test casing
as per AOGCC Industry Guidance Bulletin 17-001.
x L-200 10-3/4” casing was last tested to 2,000 psi on Sept 7, 2019
Page 14
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
11.0 Mill 9-7/8” Window and Kick Off
11.1 Whipstock Set Depth Information:
x 10-3/4” Whipstock was set at 3400’ MD, 44q Left of High side on 2/2/2017
x Casing obstructions encountered at the following depths while RIH:
1. 260-300’
2. 390-400’
3. 1620’
x The whipstock and milling assembly had to be modified and ran in multiple trips to get to
bottom.
x During trips with the milling BHA, the sliding sleeve of the TAM port collar (985’ MD)
in the 10-3/4” casing would shift, creating a loss in casing integrity. In Sept 2019 the
TAM port collar was locked closed.
x Ensure back up whipstock is available.
11.2 MU 9-7/8” milling assembly as per fishing rep
x Make up HWDP, magnets, and float sub
x Ensure magnets are in trough, under shaker and floar area to capture metal shavings
circulated out
x No MWD is needed, as whipstock is already set
Page 15
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
11.3 RIH as per fishing rep to ~3375’ MD, run slowly through BOP and wear bushing
x Watch running in hole at following casing depths:
1. 260-300’
2. 390-400’
3. 1620’
11.4 If the full tri mill assembly is unable to get past the casing obstructions, POOH and LD the
uppermost mill. The back up option will be to mill the window in two runs:
x Run #1: Window Mill and Lower Mill
x Run #2: Window Mil and Upper Full gauge 9-7/8” Mill
x If unable to get the full gauge mill through the obstructions, and smaller bit will be used
for the intermediate hole section
11.5 Displace to 9.5ppg milling fluid
x Visc: 40-60, YP: 18-20
11.6 Record P/U, S/O weights, and free rotation. Slack off to top of whipstock and with light weight
and low torque. Mill window as per fishing rep. Utilize 4 ditch magnets on the surface to catch
metal cuttings. Pump high visc sweeps as necessary.
11.7 IF possible, install catch trays in shakers underflow to help catch metal cuttings
11.8 Clean ditch magnets and catch trays frequently while milling window
11.9 Mill window as per fishing rep, until the uppermost mill has passed across the entire tray. Dress
and polish /window as needed
x Watch for gas hydrates after milling window on bottoms up, as window depth is in the
hydrate zone
11.10 With upper mill at the end of the tray, drill 20’ of new hole
11.11 Pull back in to 10-3/4” casing and observe well for flow
11.12 Ru and perform FIT to 12.0ppg EMW. Chart test.
11.13 POOH, LD milling BHA
x Gauge mills for wear
11.14 PU stack washer and wash BOPE stack, ensure to function all rams to clear any potential debris
FIT digital data to AOGCC. (Pressure vs volume)
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Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
12.0 Drill 9-7/8” Hole Section
12.1 P/U 9-7/8” directional drilling assembly:
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Consider running a UBHO sub for wireline gyro.GWD will be the primary gyro tool.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
x Drill string will be 5” 19.5# S-135.
x Run a solid float in the surface hole section.
12.2 RIH with 9-7/8” BHA to top of whipstock, Shallow test MWD
x RIH slow at the following casing depths due to past obstructions:
x 260-300’
x 390-400’
x 1620’
12.3 Orient directional motor 44* left of high side and slide through window with no pumps or
rotary
12.4 Drill 9-7/8” hole section to section TD, in the Schrader OA sand. Confirm this setting depth with
the Geologist and Drilling Engineer while drilling the well.
x Hold a safety meeting with rig crews to discuss:
x Well control procedures and rig evacuation
x Flow rates, hole cleaning, mud cooling, etc.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Keep mud as cool as possible to keep from washing out permafrost.
x Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can
handle the flow rate.
x There have been ‘directional dead zones’ noted in PBW. Keep an eye on directional bha
output
x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoffs, increase in pump pressure or changes in hookload are seen
x Slow in/out of slips and while tripping to keep swab and surge pressures low
x Ensure shakers are functioning properly. Check for holes in screens on connections.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea
gravel, clay balling or packing off.
x Adjust MW and viscosity as necessary to maintain hole stability,ensure MW is at a 9.5 for
entire hole section. This is to combat hydrates and free gas risk, based upon offset wells.
x Perform gyro surveys until clean MWD surveys are seen. Take MWD surveys every stand
drilled.
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Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
x Be prepared for gas hydrates. In PBW they have been encountered typically to 2740’ TVD
(Top Ugnu). And Free Gas Until 3000’ TVD Be prepared for hydrates from 3350 – 4750’
MD:
x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD
x Monitor returns for hydrates, checking pressurized & non-pressurized scales
x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by
washing out additional permafrost. Attempt to control drill (150 fph MAX) through the
zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be
reduced to prevent mud from belching over the bell nipple.
x Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well.
MW will not control gas hydrates, but will affect how gas breaks out at surface.
x Be prepared for heavy ugnu oil at ~ 4250’ – 6100’ MD
x Take MWD and GWD surveys every stand until magnetic interference cleans up. After
MWD surveys show clean magnetics, only take MWD surveys.
x Surface Hole AC:
x There are no wells with a clearance factor of <1.0
12.5 9-7/8” hole mud program summary:
x Density: Weighting material to be used for the hole section will be barite. Additional
barite or spike fluid will be on location to weight up the active system (1) ppg above
highest anticipated MW. We will start with a LSND at 9.5 ppg and TD with 9.5+ ppg.
MW for free gas and hydrates based upon offset wells
Depth Interval MW (ppg)
Window - TD 9.5+ (For Hydrates/Free Gas based on offset
wells)
x PVT System: PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, Toolpusher
office, and mud loggers office.
x Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system
with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at
all times while drilling. Be prepared to increase the YP if hole cleaning becomes an
issue.
x Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background
LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the
system while drilling the surface interval to prevent losses and strengthen the wellbore.
x Wellbore and mud stability:Additions of CON DET PRE-MIX/DRIL N SLIDE are
recommended to reduce the incidence of bit balling and shaker blinding when penetrating
the high-clay content sections of the Sagavanirktok and the heavy oil sections of the
UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of
ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action.
DLB
Be prepared for gas hydrates. In PBW they have been encountered typically to 2740’ TVDpp g y y yp y
(Top Ugnu). And Free Gas Until 3000’ TVD Be prepared for hydrates from 3350 – 4750’(p
MD:
x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD
Page 18
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
x Casing Running:Reduce system YP with DESCO as required for running casing as
allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and
swab pressures. Reduce the system rheology once the casing is landed to a YP < 20
(check with the cementers to see what YP value they have targeted).
System Type:9.0 – 9.5 ppg LSND
Properties:
Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp
Surface 8.8 –9.8 75-175 20 - 40 25-45 <10 8.5 –9.0 70 F
System Formulation: Gel + FW spud mud
Product Concentration
Fresh Water
soda Ash
AQUAGEL
caustic soda
BARAZAN D+
BAROID 41
PAC-L /DEXTRID LT
ALDACIDE G
0.905 bbl
0.5 ppb
15 - 20 ppb
0.1 ppb (8.5 – 9.0 pH)
as needed
as required for 8.8 – 9.2 ppg
if required for <10 FL
0.1 ppb
12.6 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem
sweeps and drop viscosity.
12.7 RIH to bottom, proceed to BROOH to 2 stands below window.
x Pump at full drill rate (400-600 gpm), and maximize rotation.
x Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions
x Monitor well for any signs of packing off or losses.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay
balling.
x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until
parameters are restored.
12.8 CBU and OWFF. Pull through window with no pumps or rotary
12.9 Once inside 10-3/4” casing, POOH on elevators, LDDP.
12.10 No open hole logging program planned.
Minimum EMW needed = 8.46 ppg DLB
NOTE:
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Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
13.0 Run 7-5/8” Casing
12.1 R/U and pull wearbushing.
12.2 R/U Weatherford 7-5/8” casing running equipment (CRT & Tongs)
x Ensure 7-5/8” VAMTOP x NC50 XO on rig floor and M/U to FOSV.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x R/U of CRT if hole conditions require.
x R/U a fill up tool to fill casing while running if the CRT is not used.
x Ensure all casing has been drifted to 6.75” on the location prior to running.
x Be sure to count the total # of joints on the location before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
12.3 P/U shoe joint, visually verify no debris inside joint.
12.4 Continue M/U & thread locking 120’ shoe track assembly consisting of:
7-5/8” Float Shoe
1 joint – 7-5/8” , 2 Centralizers 10’ from each end w/ stop rings
1 joint –7-5/8” , 1 Centralizer mid joint w/ stop ring
7-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’
1 joint –7-5/8” , 1 Centralizer mid joint with stop ring
7-5/8” HES Baffle Adaptor
x Ensure bypass baffle is correctly installed on top of float collar.
x Ensure proper operation of float equipment while picking up.
x Ensure to record S/N’s of all float equipment and stage tool components.
12.5 Float equipment and Stage tool equipment drawings:
This end up.
Bypass Baffle
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Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
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Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
12.6 Continue running 7-5/8” intermediate casing
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
x 1 centralizer every joint to ~ 1000’ MD from shoe
x 1 centralizer every 2 joints to ~2,000’ above shoe (Top of Lowest Ugnu)
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
x Any packing off while running casing should be treated as a major problem. It is preferable
to POH with casing and condition hole than to risk not getting cement returns to surface.
12.7 Install the Halliburton Type H ES-II Stage tool so that it is positioned ~3000’ MD
x The stage tool will be threaded BTC, so ensure proper XO’s to VAMTOP are available.
Bakerlock XO connections.
x Install centralizers over couplings on 5 joints below and 5 joints above stage tool.
x Do not place tongs on ES cementer, this can cause damaged to the tool.
x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi.
7-5/8” 29.7# L-80 VAMTOP Make-Up Torques:
Casing OD Minimum Optimum Maximum
7-5/8”13,050 ft-lbs 14,050 ft-lbs 15,850 ft-lbs
Page 22
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
Page 23
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
12.8 Continue running 7-5/8” surface casing
x Centralizers: 1 centralizer every 4rd joint to 200’ from surface
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
o 1 centralizer every 4 joints to base of conductor
12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.10 Slow in and out of slips.
12.11 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the
landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference
when getting the casing on depth.
12.12 Lower casing to setting depth. Confirm measurements.
12.13 Have slips staged in cellar, along with necessary equipment for the operation.
12.14 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement
job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible
reciprocate casing string while conditioning mud.
intermediate
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Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
14.0 Cement 7-5/8” Intermediate Casing
14.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
x Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks.
x Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
x Review test reports and ensure pump times are acceptable.
x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
14.2 Document efficiency of all possible displacement pumps prior to cement job.
14.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
14.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
14.5 Fill surface cement lines with water and pressure test.
14.6 Pump remaining 60 bbls 10.5 ppg tuned spacer.
14.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below
calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached.
14.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead &
tail, TOC brought to stage tool.
Estimated 1st Stage Total Cement Volume:
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Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
Cement Slurry Design (1st Stage Cement Job):
14.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation, land hanger,
and continue with the cement job.
14.10 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of
mud pits, spotting water across the HEC stage cementer.
x Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
14.11 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very
accurate using 0.0625 bps (5” liners) for the Quattro pump output. To operate the stage tool
hydraulically, the plug must be bumped.
14.12 Displacement calculation:
(7055’ – 120’) x 0.0459 bpf = 318.6 bbls
80 bbls of tuned spacer to be inside casing at the stage tool so that when the ES is
functioned, spacer is the first fluid to enter the annulus
14.13 Land hanger prior to completion of displacement.
14.14 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any
point during the job. Be prepared to pump out fluid from cellar. Have black water available to
contaminate any cement seen at surface.
14.15 If plug is not bumped at calculated strokes, double check volumes and calculations. Over
displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling
Engineer.
14.16 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening
plug is available if needed. This is the back-up option to open the stage tool if the plugs are not
bumped.
Lead Slurry Tail Slurry
Density 12.0 lb/gal 15.8 lb/gal
Yield 2.35 ft3/sk 1.16 ft3/sk
Mix Water 13.92 gal/sk 4.98 gal/sk
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Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
14.17 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened.
14.18 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher pressure
may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns
to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation
for the 2nd stage of the cement job.
14.19 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker
bypass line to the cuttings tank. Have black water available and vac trucks ready to assist.
Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact
with the cement.
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Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
Second Stage Surface Cement Job:
14.20 Prepare for the 2
nd stage as necessary. Circulate until first stage reaches sufficient compressive
strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre-job safety
meeting.
x Past wells have seen pressure increase while circulating through stage tool after reduced
rate
14.21 HEC representative to witness the loading of the ES cementer closing plug in the cementing
head.
14.22 Fill surface lines with water and pressure test.
14.23 Pump remaining 60 bbls 10.5 ppg tuned spacer.
14.24 Mix and pump cmt per below recipe for the 2
nd stage.
14.25 Cement volume based on annular volume + excess (10% for volumes in cased hole). Job will
consist of lead & tail, TOC brought to surface.
Estimated 2nd Stage Total Cement Volume:
Cement Slurry Design (2nd stage cement job):
Lead Slurry Tail Slurry
System Permafrost L G
Density 10.7 lb/gal 15.8 lb/gal
Yield 4.41 ft3/sk 1.17 ft3/sk
Mixed
Water 22.02 gal/sk 5.08 gal/sk
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Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
14.26 Consider adjust lead cement volume if there is concern getting cement to surface
14.27 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out
of mud pits.
14.28 Displacement calculation:
3000’ x 0.0459 bpf = 137.7 bbls mud
14.29 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side
outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out
fluid from cellar. Have black water available to retard setting of cement.
14.30 Decide ahead of time what will be done with cement returns once they are at surface. We should
circulate approximately 10-20bbls of cement slurry to surface.
14.31 Land closing plug on stage collar and pressure up to 1,000 – 1,500 psi to ensure stage tool closes.
Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool
has closed. Slips will be set as per plan to allow full annulus for returns during surface cement
job. Set slips.
14.32 RILDS
Ensure to report the following on wellez:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
x Note calculated top of cement
x Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to jengel@hilcorp.com and
joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the
AOGCC.
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Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
15.0 Drill 6-3/4” Hole Section
15.1 Lay down all 5” DP, Pick up 4” DP for 6-3/4” hole section
x Ensure BOPE have been tested with 4” test joints
15.2 MU 6-3/4” Cleanout BHA (Milltooth Bit & 1.22° PDM)
15.3 TIH w/ 6-3/4” cleanout BHA to stage tool, ~ 3000’. Note depth TOC tagged on AM report. Drill
out stage tool.
15.4 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report.
15.5 RU and test casing to 3,000 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and
plot on FIT graph. 50% of burst= 7080 / 2 = 3540. Max test pressure with BOPE is 3000.
Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure
rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001.
15.6 Drill out shoe track and 20’ of new formation.
15.7 CBU and condition mud for FIT.
15.8 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test.
Document incremental volume pumped (and subsequent pressure) and volume returned.
15.9 POOH and LD cleanout BHA
15.10 PU 6-3/4” directional BHA.
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before MU. Visually verify no debris inside components that
cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Ensure MWD is RU and operational.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.Planned jetting
is x5-12s
x Drill string will be 4” 14# S-135 XT39.
x Run a solid in the production hole section for managed pressure drilling.
Page 30
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
15.11 8-1/2” hole section mud program summary:
x Density: Weighting material to be used for the hole section will be calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg
above highest anticipated MW.
x Solids Concentration: It is imperative that the solids concentration be kept low while
drilling the production hole section. Keep the shaker screen size optimized and fluid
running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure
we are running the finest screens possible.
x Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests
excessive viscosifier concentrations can decrease return permeability. Do not pump high
vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for
sufficient hole cleaning
x Run the centrifuge continuously while drilling the production hole, this will help with
solids removal.
x Dump and dilute as necessary to keep drilled solids to an absolute minimum.
x MD Totco PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, &
Toolpusher office.
System Type:8.9 – 9.5 ppg Baradrill-N drilling fluid
Properties:
Interval Density PV YP
LSYP Total Solids MBT HPH
T
Hardness
Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100
System Formulation:
Product Concentration
Water
KCL
KOH
N-VIS
DEXTRID LT
BARACARB 5
BARACARB 25
BARACARB 50
BARACOR 700
BARASCAV D
X-CIDE 207
0.955 bbl
11 ppb
0.1 ppb
1.0 – 1.5 ppb
5 ppb
4 ppb
4 ppb
2 ppb
1.0 ppb
0.5 ppb
0.015 ppb
NOTE: Minimum EMW needed = 8.46 ppg DLB
Page 31
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
15.12 TIH with 6-3/4” directional assembly to bottom
15.13 Install MPD RCD
15.14 Displace wellbore to 9.5 ppg Baradrill-N drilling fluid
15.15 Begin drilling 6-3/4” hole section, on-bottom staging technique:
x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K.
x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations
x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU
off bottom and restart on bottom staging technique. If stick slip continues, consider adding
0.5% lubes
15.14 Drill 6-3/4” hole section to section TD per Geologist and Drilling Engineer.
x Flow Rate: 200-300 GPM, target min. AV’s 200 ft/min, 250 GPM
x RPM: 120+
x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly
wet to maximize solids removal efficiency. Check for holes in screens on every connection.
x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
x Monitor Torque and Drag with pumps on every 5 stands
x Monitor ECD, pump pressure & hookload trends for hole cleaning indication
x Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible and avoid stopping with the
BHA across the sand for any extended period of time.
x Use ADR to stay in section. Reservoir plan is to stay in OA sand.
x Limit maximum instantaneous ROP to < 250 FPH. The sands will drill faster than this, but
when concretions are hit when drilling this fast, cutter damage can occur.
x Target ROP is as fast as we can clean the hole without having to backream connections
x Schrader Bluff OA Concretions: 4-6% Historically
x MPD will be utilized to monitor pressure build up on connections. Adjust MW as needed.
x 6-3/4” Lateral A/C:
x L-207wp05 CF < 1.0: L-207 is a future planned well and does not exist. There is
no risk with collision. When L-207 is drilled it will be in the Oba sand, and there will be
geologic separation between L-200A and L-207 at all times.
15.15 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons
learned and best practices. Ensure the DD is referencing their procedure.
x Patience is key! Getting kicked off too quickly might have been the cause of failed liner
runs on past wells.
x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so
we have a nice place to low side.
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Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
x Attempt to lowside in a fast drilling interval where the wellbore is headed up.
x Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working
string back and forth. Trough for approximately 30 minutes.
x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the
openhole sidetrack is achieved.
15.16 At TD, CBU at least 4 times at 200 ft/min AV (250+ GPM) and rotation (120+ RPM). Pump
tandem sweeps if needed
x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent
stream, circulate more if necessary
x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum
15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP
pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter
cake and calcium carbonate. Circulate the well clean.
Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being
removed, including an increase in the loss rate.
15.18 Displace 1.5 OH + liner volume with viscosified brine.
x Proposed brine blend (same as used on M-16, aiming for an 8 on the 6 RPM reading) -
KCl: 7.1ppb for 2%
NaCl: 60.9ppg for 9.4ppg
Lotorq: 1.5%
Lube 776: 1.5%
Soda Ash: as needed for 9.5pH
Busan 1060: 0.42ppb
Flo-Vis Plus: 1.25ppb
x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further
discussion needed prior to BROOH.
15.16 Monitor the returned fluids carefully while displacing to brine. After 1 (or more if needed) BU,
Perform production screen test (PST). The brine has been properly conditioned when it will pass
the production screen test (x3 350 ml samples passing through the screen in the same amount
of time which will indicate no plugging of the screen). Reference PST Test Procedure
Page 33
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
15.19 BROOH with the drilling assembly to the 7-5/8” casing shoe
x Circulate at full drill rate (less if losses are seen, 250 GPM minimum).
x Rotate at maximum RPM that can be sustained.
x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as
dictated by hole conditions
x If backreaming operations are commenced, continue backreaming to the shoe
15.20 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while
BROOH.
15.21 CBU minimum two times at 7-5/8” shoe and clean casing with high vis sweeps.
15.22 Monitor well for flow/pressure build up with MPD. Increase fluid weight if necessary.
x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to
determine if well is breathing, treat all flow as an influx until proven otherwise
x If necessary, increase MW at shoe for any higher than expected pressure seen
x Ensure fluid coming out of hole has passed a PST at the possum belly
15.23 POOH and LD BHA.
15.24 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit
diameter is sufficient for future ball drops.
Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any
additional logging runs conducted.
Page 34
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
16.0 Run 4-1/2” Screen Liner
16.1 Well control preparedness: In the event of an influx of formation fluids while running the 4-
41/2” EZGO screen liner, the following well control response procedure will be followed:
x P/U & M/U the 4” safety joint (with 4-1/2” crossover installed on bottom, TIW valve in open
position on top, 4-1/2” handling joint above TIW). This joint shall be fully M/U and
available prior to running the first joint of 4-1/2” slotted liner.
x Slack off and with 4” DP across the BOP, shut in ram or annular on 4” DP. Close TIW.
x Proceed with well kill operations.
16.2 R/U 4-1/2” liner running equipment.
x Ensure 4-1/2” 12.6# Hydril 563 x DS-50 crossover is on rig floor and M/U to FOSV.
x Ensure all casing has been drifted on the deck prior to running.
x Be sure to count the total # of joints on the deck before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
16.3 Run 4-1/2” slotted production liner
x Use API Modified or “Best O Life 2000 AG”thread compound. Dope pin end only w/ paint
brush. Wipe off excess.
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Run float shoe on bottom
x 4-1/2” screen Liner will auto fill
x 4-1/2” Liner will be centralized, 1/jt free floating
x Install liner as per the Running Order (From Completion Engineer post TD).
x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint
outside of the surface shoe. This is to mitigate difference sticking risk while running inner
string.
x Obtain up and down weights of the liner before entering open hole. Record rotating torque at
10 and 20 rpm
4-1/2” 11.6 # EZGO Torque
OD Minimum Maximum Yield Torque
4-1/2” 4007 ft-lbs 6114 ft-lbs 11537 ft-lbs
Page 35
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
Page 36
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
16.6. Ensure to run enough liner to provide for sufficient overlap inside 7-5/8” casing for gas lift
completion. Ensure hanger/pkr will not be set in a 7-5/8” connection.
x L-200A ~ liner top packer depth 6905’ MD. Confirm with Completion Engineer
x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as
per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 7-5/8” connection.
16.7. Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck
to make sure it coincides with the pipe tally.
16.8. M/U Baker SLZXP liner top packer to 4-1/2” liner.
x Confirm with OE any 7” joints between liner top packer and 4-1/2” liner for GLM
and packer setting depth
16.9. Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner
hanger to ensure a clear flow path exists.
16.10. RIH with liner no faster than 30 ft/min – this is to prevent buckling the liner and drill string and
weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and
avoid surging the hole or buckling the liner. Slow down running speed if necessary.
x Ensure 5” DP/HWDP has been drifted
x There is no inner string planned to be run, as opposed to previous wells. The DP should auto
fill. Monitor FL and if filling is required due to losses/surging.
16.11. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe
depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to
bottom.
16.12. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
& 20 RPM.
16.13. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
16.14. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
16.15. Rig up to pump down the work string with the rig pumps.
16.16. Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed
1,600 psi while circulating.Pusher tool is set at 2,100 psi with 5% shear screws but it should be
discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker
Page 37
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
16.17. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill
pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger.
16.18. Shut down pumps. Drop setting ball (ball seat now located in HRDE setting tool and not at the
WIV) down the workstring and pump slowly (1-2 BPM). Slow pump before the ball seats. Do
not allow ball to slam into ball seat.
16.19. Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes.
Slack off 20K lbs on the SZXP liner hanger/packer to ensure the HRDE setting tool is in
compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi
to release the HRDE running tool.
16.20. Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without
pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20
RPM and set down 50K again.
16.21. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted.
16.22. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If
packer did not test, rotating dog sub can be used to set packer. If running tool cannot be
hydraulically released, apply LH torque to mechanically release the setting tool.
16.23. PU pulling running tool free of the packer and displace with at max rate to wash the liner top.
Pump sweeps as needed.
16.24. POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned,
LD DP on the TOOH.
Note: Once running tool is LD, swap to the completion AFE.
Page 38
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
17.0 Run Gas Lift Completion & Post Rig Work
17.1 RU to run 4-1/2”, 12.6#, L-80 VAMTOP tubing.
x Ensure wear bushing is pulled.
x Ensure 4-1/2”, L-80, 13.5#, VAMTOP x XT-39 crossover is on rig floor and M/U to FOSV.
x Ensure all tubing has been drifted in the pipe shed prior to running.
x Be sure to count the total # of joints in the pipe shed before running.
x Keep hole covered while RU casing tools.
x Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info.
x Monitor displacement from wellbore while RIH.
Page 39
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
17.2 PU, MU and RH with the following 4-1/2” GL completion jewelry (tally to be provided by
Operations Engineer):
Nom. Size Thread ~Length Item Lb/ft Material ~ Depth (MD) Comments
4.5" VamTop 10 WLEG 12.6 L80 6425
4.5" VamTop 13.5 Pup Joint 12.6 L80
4.5" VamTop X-nip with RHC L80 6400
land at 68 deg INC or ~6400' MD per L-200A
wp03
4.5" VamTop 13.5 Pup Joint 12.6 L80
4.5" VamTop 1 joint 12.6 L80
4.5" VamTop 13.5 Pup Joint 12.6 L80
4.5" VamTop Production Packer L80 6266
~134' above lower X, ~6266' MD, Production
liner set above this depth
4.5" VamTop 13.5 Pup Joint 12.6 L80
4.5" VamTop 1 joint 12.6 L80
4.5" VamTop 13.5 Pup Joint 12.6 L80
4.5" VamTop X-nip L80 6200 ~201' above lower X, (4024' TVD)
4.5" VamTop 13.5 Pup Joint 12.6 L80
4.5" VamTop 1 joint 12.6 L80
4.5" VamTop 13.5 Pup Joint 12.6 L80
4.5" VamTop GLM#1 w/ DMY Valve L80 5600
(3685' TVD) set as deep as possible, consider
removing joint above packer
4.5" VamTop 13.5 Pup Joint 12.6 L80
4.5" VamTop Tubing 12.6 L80
4.5" VamTop 13.5 Pup Joint 12.6 L80
4.5" VamTop GLM#2 w/ DMY Valve L80 4900 (3325' TVD)
4.5" VamTop 13.5 Pup Joint 12.6 L80
4.5" VamTop Tubing 12.6 L80
4.5" VamTop 13.5 Pup Joint 12.6 L80
4.5" VamTop GLM#3 w/ DMY Valve L80 4300 (2955' TVD)
4.5" VamTop 13.5 Pup Joint 12.6 L80
4.5" VamTop Tubing 12.6 L80
4.5" VamTop 13.5 Pup Joint 12.6 L80
4.5" VamTop GLM#4 w/ DMY Valve 12.6 L80 3297 (2375' TVD)
4.5" VamTop 13.5 Pup Joint 12.6 L80
4.5" VamTop Tubing 12.6 L80
4.5" VamTop 13.5 Pup Joint 12.6 L80
4.5" VamTop X-nip L80 2200 set @ ~2200' MD
4.5" VamTop 13.5 Pup Joint 12.6 L80
4.5" VamTop Tubing 12.6 L80
4.5" VamTop Spaceout Pups 12.6 L80
4.5" VamTop x TCII 1 Joint 12.6 L80 VamTop Pin x TCII PIN
Tubing Hanger
Page 40
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
17.3 PU and MU the 4-1/2” tubing hanger. Make final splice of any TEC wire used and ensure any
unsued control line ports are dummied off.
17.4 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with
band/clamp summary.
17.5 Land the tubing hanger and RILDS. Lay down the landing joint.
17.6 Install 4” HP BPV. ND BOP. Install the plug off tool.
17.7 NU the tubing head adapter and NU the tree.
17.8 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi.
17.9 Pull the plug off tool and BPV.
17.10 Reverse circulate the well over to corrosion inhibited source water follow by 85 bbls of diesel
freeze protect for both tubing and IA to 2,500’ MD.
17.11 Drop the ball & rod and complete loading tubing and hydraulically set the packer as per
Halliburton’s setting procedure
17.12 Pressure up and test the tubing to 3500 psi for MIT-T with 1000 psi on the IA. Bleed off the
tubing to 2000psi. Test the IA to 3500 psi for MIT-IA. Bleed off the tubing and observe DCK
shear. Confirm circulation in both directions thru the sheared valve. Record and notate all
pressure tests (30 minutes) on chart.
17.13 Bleed both the IA and tubing to 0 psi.
17.14 Rig up jumper from IA to tubing to allow freeze protect to swap.
17.15 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over
with valve alignment as per operations personnel.
17.16 RDMO Innovation
i. POST RIG WELL WORK
1. SL
a. Change out GLV per GL ENGR
b. Pull ball and rod and RHC
Page 41
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
18.0 Innovation Rig Diverter Schematic
No diverter planned
Page 42
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
19.0 Innovation Rig BOP Schematic
Page 43
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
20.0 Wellhead Schematic
Page 44
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
21.0 Days Vs Depth
Page 45
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
22.0 Formation Tops & Information
Reference Plan:
SV1 Gas Hydrates 3,663 2,496.0 -2496 1098 8.46 GAS HYDRATES: 3350' ~ 4050' MD
Ugnu 4A Gas/Heavy Oil 4,215 2,830.0 -2830 1245 8.46 FREE GAS/HEAVY OIL: ~4250' - 4750' MD
FAULT 50' throw n/a 5,215 3,422.0 -3422
Ugnu LA Heavy Oil 5,605 3,628.0 -3628 1596 8.46 HEAVY OIL: ~5550' - 6100' MD
NA Top Schrader Bluff Oil 6,309 4,000.0 -4000 1760 8.46
OA (Heel) Schrader Bluff Oil 6,983 4,145.0 -4145 1824 8.46
Est.
Pressure ppg EM W
ANTICIPATED FORMATION TOPS & GEOHAZARDS PBU L-200A wp03
TOP NAME LITHOLOGY EXPECTED
FLUID
MD
(FT)
TVD
(FT)
TVDSS
(FT)
NORTHIN
G EASTING
Page 46
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
Page 47
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
23.0 Anticipated Drilling Hazards
9-7/8” Hole Section:
Lost Circulation
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Gas Hydrates/Free Gas
Gas hydrates have been seen on PBU L Pad. They were reported between 1660’ and 2740’ TVD. MW
has been chosen based upon successful trouble free penetrations of offset wells. Remember that hydrate
gas behaves differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates,
but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come
out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching.
Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate
formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud
circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized
mud scale. The non-pressurized scale will reflect the actual mud cut weight. Isolate/dump
contaminated fluid to remove hydrates from the system.Watch for heavy oil and gas at window
depth
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize
solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor
ECD’s to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPM’s when CBU, and keep pipe
moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after
slide intervals. Do not out drill our ability to clean the hole.
Anti-Collison:
There are no known wells with a clearance factory <1.0. Take directional surveys every stand, take
additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any
close approaches on AM report.
Well Specific A/C:
x There are no wells with a clearance factor of <1.0
Wellbore stability (Permafrost, running sands and gravel, conductor broaching):
Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of
time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH
speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and
swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching.
Maintain mud parameters and increase MW to combat running sands and gravel formations.
Page 48
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
H2S:
Treat every hole section as though it has the potential for H2S. PBU L-pad has a history of H2S on
wells in all reservoirs. Below are the most recent H2S values of monitored wells in the Shrader / Orion
Pool.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
H2S:
Treat every hole section as though it has the potential for H2S. PBU L-pad has a history of H2S onygp py
wells in all reservoirs. Below are the most recent H2S values of monitored wells in the Shrader / Orion
Pool.
1.
DLB 10/07/2021
Page 49
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
6-3/4” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor
ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe
moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation
after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300
gpm
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
Crossing faults, known or unknown, can result in drilling into unstable formations that may impact
future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared
for accordingly.
H2S:
Treat every hole section as though it has the potential for H2S. PBU L-pad has a history of H2S on
wells in all reservoirs. Below are the most recent H2S values of monitored wells in the Shrader / Orion
Pool.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Abnormal Pressures and Temperatures:
H2S:
Treat every hole section as though it has the potential for H2S. PBU L-pad has a history of H2S onygp py
wells in all reservoirs. Below are the most recent H2S values of monitored wells in the Shrader / Orion
Pool.
1.
DLB
Page 50
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen.
Anti-Collision
Take directional surveys every stand, take additional surveys if necessary. Continuously monitor
drilling parameters for signs of magnetic interference with another well. Reference A/C report in
directional plan.
Well Specific AC:
x L-207wp05 CF < 1.0: L-207 is a future planned well and does not exist. There is no risk
with collision. When L-207 is drilled it will be in the Oba sand, and there will be geologic
separation between L-200A and L-207 at all times.
Page 51
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
24.0 Innovation Rig Layout
Page 52
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
25.0 FIT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5.On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6.Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7.Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental
volume pumped and returned during test.
Page 53
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
26.0 Innovation Rig Choke Manifold Schematic
Page 54
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
27.0 Casing Design
Page 55
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
28.0 MASP
DLB
Page 56
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
Page 57
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
29.0 Spider Plot (NAD 27) (Governmental Sections)
Page 58
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
30.0 Surface Plat (As Built) (NAD 27)
Page 59
Prudhoe Bay West
L-200A SB Producer
Drilling Procedure
31.0 Offset Wells TVD MW
_____________________________________________________________________________________
Revised By: JNL 10/5/2021
PROPOSED SCHEMATIC
Prudhoe Bay Unit
Well: PBU L-200A
Last Completed: TBD
PTD: TBD
TREE & WELLHEAD
Tree 4-1/16” CIW
Wellhead FMC 11” 5K w/ Mandrel hanger, x2 2-1/16” outs
Sidetrack Information
A Sidetrack: 3375’ MD / 2414’ TVD
Whipstock @3375’ Set Pre-Rig in 2017
GENERAL WELL INFO
API: 50-029-23191-02-00
Completion Date: TBD
TD =14,059’ (MD) / TD =4,155’ (TVD)
5
20”
Whipstock
@ 3375’ Set
Pre-Rig in
2017
Orig. KB Elev.: 75.49’ / GL Elev.: 49.1’
7-5/8”
4
1
2
3
See
Screen
Liner
Detail
10-3/4”
PBTD =14,059’ (MD) / PBTD =4,155’ (TVD)
7-5/8” ‘ES’
Cementer @
±3,000’
4-1/2”
Shoe @
14,059’
10
9
8
11
6
7
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20" Conductor 129.5 / X52 / Weld N/A Surface 110’ N/A
10-3/4" Surface 45.5/ L-80 / BTC 8.681 Surface 3,375’ 0.0962
7-5/8” Interm. 29.7 / L-80 / Vamtop 6.750 Surface 7,055’ 0.0459
4-1/2” Liner 11.6 / L-80 / ezgo HT 4.000 6,421’ 14,059’ 0.0149
TUBING DETAIL
4-1/2" Tubing 12.6# / L-80 / Vamtop 3.958 Surface 6,425’ 0.0152
OPEN HOLE / CEMENT DETAIL
48” 260 sx Arctic Set (Approx.)
13-1/2" 723 AS Lite, 338 sx Class G
9-7/8”Stg 1 Lead – 365 sx / Tail – 267 sx
Stg 2 Lead – 139 sx / Tail – 105 sx
6-3/4” Cementless Screen Liner
WELL INCLINATION DETAIL
KOP @ 3375’
90° Hole Angle = @ 7200’ MD
JEWELRY DETAIL
No. Top MD* Item ID
1 2,200’ X Nipple 3.813”
2 3,297’ GLM 3.833”
3 4,300’ GLM 3.833”
4 4,900’ GLM 3.833”
5 5,600’ GLM 3.833”
6 6,200’ X Nipple 3.813”
7 6,266’ 4-1/2” Production Packer 3.865”
8 6,400’ X Nipple 3.813”
9 6,425’ WLEG 3.958”
10 6,421’ 7-5/8” x 5-1/2” Liner Hanger (XO to 4-1/2” Liner) 3.875”
11 14,059’ Shoe
*All depths are approximate and will depend on actual drilled depths.
4-1/2” 100ђ SCREEN LINER DETAIL
Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD)
6WDQGDUG3URSRVDO5HSRUW
6HSWHPEHU
3ODQ /$ZS
+LOFRUS$ODVND//&
3UXGKRH%D\
/
3ODQ /
3ODQ /$
1200180024003000360042004800True Vertical Depth (1200 usft/in)0 600 1200 1800 2400 3000 3600 4200 4800 5400 6000 6600 7200 7800 8400 9000 9600 10200 10800 11400 12000Vertical Section at 310.00° (1200 usft/in)L-200 wp01 HeelL-200 wp01 CP1L-200 wp01 CP2L-200 wp01 CP3L-200 wp01 Toe13115L-200L2750080008500
9 0 0 0950010000
10 50 0
11 5 0 0
120 00
12 50 0
1 30 0013045 L-200L110001500200025003000350040004500500055006000650070007500800085009000
9 5 0 0100001050011000
11 5 0 01200012500
1 300013067 L-20010 3/4" TOW7 5/8" 9 7/8"4 1/2" x 6 3/4"350040004500500055006000650070007 500
8000
8500
9000
9500
1 0000
1 050 0
11 0 0 0
11 5 0 0
120001250013000135001400014059L-200A wp03KOP : Start Dir 9.46º/100' : 3355' MD, 2404.67'TVD : 60° LT TFEnd Dir : 3375' MD, 2414.4' TVDStart Dir 4º/100' : 3395' MD, 2423.98'TVDEnd Dir : 3579.33' MD, 2522.45' TVDStart Dir 4º/100' : 3779.33' MD, 2640'TVDEnd Dir : 4996.82' MD, 3373.03' TVDFault #1 (50' Throw)Start Dir 4º/100' : 6122.3' MD, 3984.15'TVDEnd Dir : 6846.83' MD, 4210.98' TVDStart Dir 3º/100' : 7054.83' MD, 4225.49'TVDEnd Dir : 7246.72' MD, 4229.28' TVDStart Dir 2º/100' : 8032.88' MD, 4205.49'TVDEnd Dir : 8111.05' MD, 4204.12' TVDStart Dir 2º/100' : 9887.13' MD, 4195.49'TVDEnd Dir : 10140.99' MD, 4191.9' TVDStart Dir 2º/100' : 11483.68' MD, 4160.42'TVDEnd Dir : 12202.57' MD, 4150.25' TVDTotal Depth : 14059.12' MD, 4155.49' TVDSV1Ugnu 4AUgnu LANAOA (Heel)Hilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: L-200Ground Level: 49.10+N/-S +E/-WNorthingEastingLatitudeLongitude0.000.005978289.74583209.27 70° 21' 2.3606 N 149° 19' 27.9135 WSURVEY PROGRAMDate: 2021-09-02T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool97.89 3349.89 Survey #4 (L-200) 3_Gyro-CT_Drill pipe3372.89 3355.00 Gyrodata Gyro (L-200) 3_Gyro-CT_Drill pipe3355.00 3650.00 L-200A wp03 (Plan: L-200A) 3_MWD_Interp Azi+Sag3650.00 7055.00 L-200A wp03 (Plan: L-200A) 3_MWD+IFR2+MS+Sag7055.00 14059.12 L-200A wp03 (Plan: L-200A) 3_MWD+IFR2+MS+SagFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation2571.49 2496.00 3662.77 SV12905.49 2830.00 4214.63 Ugnu 4A3703.49 3628.00 5605.42 Ugnu LA4075.49 4000.00 6309.97 NA4220.49 4145.00 6983.14 OA (Heel)REFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: L-200, True NorthVertical (TVD) Reference:L-200A Planned RKB @ 75.49usftMeasured Depth Reference:L-200A Planned RKB @ 75.49usftCalculation Method: Minimum CurvatureProject:Prudhoe BaySite:LWell:Plan: L-200Wellbore:Plan: L-200ADesign:L-200A wp03CASING DETAILSTVD TVDSS MD SizeName2405.16 2329.67 3356.00 10-3/4 10 3/4" TOW4225.50 4150.01 7055.00 7-5/8 7 5/8" 9 7/8"4155.49 4080.00 14059.12 4-1/2 4 1/2" x 6 3/4"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target1 3355.00 60.43 21.43 2404.67 1790.87 727.83 0.00 0.00 593.602 3375.00 61.37 19.56 2414.40 1807.24 733.95 9.46 -60.00 599.433 3395.00 61.37 19.56 2423.98 1823.78 739.83 0.00 0.00 605.564 3579.33 54.00 19.56 2522.45 1970.48 791.94 4.00 179.99 659.935 3779.33 54.00 19.56 2640.00 2122.94 846.12 0.00 0.00 716.446 4996.82 57.11 319.67 3373.03 3032.13 669.42 4.00 -104.78 1436.217 6122.30 57.11 319.67 3984.15 3752.65 57.79 0.00 0.00 2367.898 6846.83 86.00 317.18 4210.98 4260.52 -394.38 4.00 -5.14 3040.729 7054.83 86.00 317.18 4225.49 4412.71 -535.42 0.00 0.00 3246.59 L-200 wp01 Heel10 7246.72 91.73 316.67 4229.28 4552.79 -666.38 3.00 -5.05 3436.9611 8032.88 91.73 316.67 4205.49 5124.43 -1205.56 0.00 0.00 4217.43 L-200 wp01 CP112 8111.05 90.28 317.24 4204.12 5181.55 -1258.90 2.00 158.63 4295.0113 9887.13 90.28 317.24 4195.49 6485.62 -2464.64 0.00 0.00 6056.90 L-200 wp01 CP214 10140.99 91.34322.21 4191.90 6679.22 -2628.67 2.00 77.86 6307.0015 11483.68 91.34322.21 4160.42 7739.98 -3451.23 0.00 0.00 7618.9616 11694.04 91.34 318.00 4155.49 7901.29 -3586.09 2.00-90.007825.96 L-200 wp01 CP317 12202.57 89.84 307.94 4150.25 8247.44 -3957.69 2.00-98.428333.1218 14059.12 89.84 307.94 4155.49 9388.91 -5421.85 0.00 0.00 10188.45 L-200 wp01 ToeAnnotationKOP : Start Dir 9.46º/100' : 3355' MD, 2404.67'TVD : 60° LT7) End Dir : 3375' MD, 2414.4' TVDStart Dir 4º/100' : 3395' MD, 2423.98'TVDEnd Dir : 3579.33' MD, 2522.45' TVDStart Dir 4º/100' : 3779.33' MD, 2640'TVDEnd Dir : 4996.82' MD, 3373.03' TVDStart Dir 4º/100' : 6122.3' MD, 3984.15'TVDEnd Dir : 6846.83' MD, 4210.98' TVDStart Dir 3º/100' : 7054.83' MD, 4225.49'TVDEnd Dir : 7246.72' MD, 4229.28' TVDStart Dir 2º/100' : 8032.88' MD, 4205.49'TVDEnd Dir : 8111.05' MD, 4204.12' TVDStart Dir 2º/100' : 9887.13' MD, 4195.49'TVDEnd Dir : 10140.99' MD, 4191.9' TVDStart Dir 2º/100' : 11483.68' MD, 4160.42'TVDEnd Dir : 12202.57' MD, 4150.25' TVDTotal Depth : 14059.12' MD, 4155.49' TVD
750
1500
2250
3000
3750
4500
5250
6000
6750
7500
8250
9000
9750
10500
11250
12000
12750
13500
South(-)/North(+) (1500 usft/in)-6000 -5250 -4500 -3750 -3000 -2250 -1500 -750 0 750 1500 2250 3000 3750 4500
West(-)/East(+) (1500 usft/in)
L-200 wp01 Toe
L-200 wp01 CP3
L-200 wp01 CP2
L-200 wp01 CP1
L-200 wp01 Heel4246L-200L24276L-200L12000
2250
2500
2750
3000
3250
3 5 0 0
3 7 5 04000425045004368L-20010 3/4" TOW
7 5/8" 9 7/8"
4 1/2" x 6 3/4"
3 2 5 03500375040004155L-200A wp03KOP : Start Dir 9.46º/100' : 3355' MD, 2404.67'TVD : 60° LT TF
End Dir : 3375' MD, 2414.4' TVD
Start Dir 4º/100' : 3395' MD, 2423.98'TVD
End Dir : 3579.33' MD, 2522.45' TVD
Start Dir 4º/100' : 3779.33' MD, 2640'TVD
End Dir : 4996.82' MD, 3373.03' TVD
Fault #1 (50' Throw)
Start Dir 4º/100' : 6122.3' MD, 3984.15'TVD
End Dir : 6846.83' MD, 4210.98' TVD
Start Dir 3º/100' : 7054.83' MD, 4225.49'TVD
End Dir : 7246.72' MD, 4229.28' TVD
Start Dir 2º/100' : 8032.88' MD, 4205.49'TVD
End Dir : 8111.05' MD, 4204.12' TVD
Start Dir 2º/100' : 9887.13' MD, 4195.49'TVD
End Dir : 10140.99' MD, 4191.9' TVD
Start Dir 2º/100' : 11483.68' MD, 4160.42'TVD
End Dir : 12202.57' MD, 4150.25' TVD
Total Depth : 14059.12' MD, 4155.49' TVD
CASING DETAILS
TVD TVDSS MD Size Name
2405.16 2329.67 3356.00 10-3/4 10 3/4" TOW
4225.50 4150.01 7055.00 7-5/8 7 5/8" 9 7/8"
4155.49 4080.00 14059.12 4-1/2 4 1/2" x 6 3/4"
Project: Prudhoe Bay
Site: L
Well: Plan: L-200
Wellbore: Plan: L-200A
Plan: L-200A wp03
WELL DETAILS: Plan: L-200
Ground Level: 49.10
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 5978289.74 583209.27 70° 21' 2.3606 N 149° 19' 27.9135 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: L-200, True North
Vertical (TVD) Reference: L-200A Planned RKB @ 75.49usft
Measured Depth Reference:L-200A Planned RKB @ 75.49usft
Calculation Method:Minimum Curvature
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0.001.002.003.004.00Separation Factor3400 3600 3800 4000 4200 4400 4600 4800 5000 5200 5400 5600 5800 6000 6200 6400 6600 6800 7000 7200Measured Depth (400 usft/in)L-117L-217L-202L-250L1L-216L-200L2L-200L1L-200L-206 wp06No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: L-200 NAD 1927 (NADCON CONUS)Alaska Zone 04Ground Level: 49.10+N/-S+E/-W NorthingEastingLatitude Longitude0.000.005978289.74583209.2770° 21' 2.3606 N149° 19' 27.9135 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: L-200, True NorthVertical (TVD) Reference:L-200A Planned RKB @ 75.49usftMeasured Depth Reference:L-200A Planned RKB @ 75.49usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2021-09-02T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool97.89 3349.89 Survey #4 (L-200) 3_Gyro-CT_Drill pipe3372.89 3355.00 Gyrodata Gyro (L-200) 3_Gyro-CT_Drill pipe3355.00 3650.00 L-200A wp03 (Plan: L-200A) 3_MWD_Interp Azi+Sag3650.00 7055.00 L-200A wp03 (Plan: L-200A) 3_MWD+IFR2+MS+Sag7055.00 14059.12 L-200A wp03 (Plan: L-200A) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)3400 3600 3800 4000 4200 4400 4600 4800 5000 5200 5400 5600 5800 6000 6200 6400 6600 6800 7000 7200Measured Depth (400 usft/in)L-206 wp06GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference3355.00 To 14059.12Project: Prudhoe BaySite: LWell: Plan: L-200Wellbore: Plan: L-200APlan: L-200A wp03Ladder / S.F. Plots1 of 2CASING DETAILSTVD TVDSS MD Size Name2405.16 2329.67 3356.00 10-3/4 10 3/4" TOW4225.50 4150.01 7055.00 7-5/8 7 5/8" 9 7/8"4155.49 4080.00 14059.12 4-1/2 4 1/2" x 6 3/4"
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0.001.002.003.004.00Separation Factor7125 7500 7875 8250 8625 9000 9375 9750 10125 10500 10875 11250 11625 12000 12375 12750 13125 13500 13875Measured Depth (750 usft/in)L-240 wp03L-218L-211L-200L2L-200L1L-200L-206 wp06L-207 wp05No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: L-200 NAD 1927 (NADCON CONUS)Alaska Zone 04Ground Level: 49.10+N/-S +E/-W NorthingEastingLatitudeLongitude0.000.005978289.74583209.2770° 21' 2.3606 N149° 19' 27.9135 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: L-200, True NorthVertical (TVD) Reference:L-200A Planned RKB @ 75.49usftMeasured Depth Reference:L-200A Planned RKB @ 75.49usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2021-09-02T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool97.89 3349.89 Survey #4 (L-200) 3_Gyro-CT_Drill pipe3372.89 3355.00 Gyrodata Gyro (L-200) 3_Gyro-CT_Drill pipe3355.00 3650.00 L-200A wp03 (Plan: L-200A) 3_MWD_Interp Azi+Sag3650.00 7055.00 L-200A wp03 (Plan: L-200A) 3_MWD+IFR2+MS+Sag7055.00 14059.12 L-200A wp03 (Plan: L-200A) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)7125 7500 7875 8250 8625 9000 9375 9750 10125 10500 10875 11250 11625 12000 12375 12750 13125 13500 13875Measured Depth (750 usft/in)L-207 wp05GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference3355.00 To 14059.12Project: Prudhoe BaySite: LWell: Plan: L-200Wellbore: Plan: L-200APlan: L-200A wp03Ladder / S.F. Plots2 of 2CASING DETAILSTVD TVDSS MD Size Name2405.16 2329.67 3356.00 10-3/4 10 3/4" TOW4225.50 4150.01 7055.00 7-5/8 7 5/8" 9 7/8"4155.49 4080.00 14059.12 4-1/2 4 1/2" x 6 3/4"
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.
X
X
Prudhoe Bay Unit
X
PBU L-200A
Schrader Bluff Oil, Orion Development Area
221-077
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