Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAbout221-095Post Office Box 244027
Anchorage, AK 99524-4027
3800 Centerpoint Drive
Suite 1400
Anchorage, AK 99503
Phone: (907) 564-4891
01/12/2023
Mr. Mel Rixse
Alaska Oil and Gas Conservation Commission
333 West 7th Avenue, Suite 100
Anchorage, Alaska 99501
Re: Prudhoe Bay Surface Casing by Conductor Annulus Top-offs of Cement, Corrosion Inhibitor
through 4Q 2022.
Dear Mr. Rixse,
Enclosed please find a copy of a spreadsheet with a list of Prudhoe Bay wells that were topped-off
with cement, corrosion inhibitor in the surface casing by conductor annulus through the end of 4Q
2022. Cement top-offs are executed as needed to mitigate the void space left at surface by minor
cement fallback during the primary surface casing by conductor cement job. The remaining void
space between the top of the cement and the top of the conductor is filled with a heavier than water
corrosion inhibitor to reduce the risk of external surface casing corrosion. The attached
spreadsheets include the well names, API and PTD numbers, treatment dates and volumes.
As per previous agreement with the AOGCC, this letter and spreadsheet serve as notification that
the treatments took place and meet the requirements of form 10-404 Report of Sundry Operations.
If you have any additional questions, please contact me at 564-4891 or
oliver.sternicki@hilcorp.com.
Sincerely,
Oliver Sternicki
Well Integrity Engineer
Hilcorp North Slope, LLC
By Samantha Carlisle at 3:53 pm, Jan 12, 2023
Digitally signed by Oliver Sternicki
(4525)
DN: cn=Oliver Sternicki (4525),
ou=Users
Date: 2023.01.12 14:52:49 -09'00'
Oliver Sternicki
(4525)
Kyle 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: 12/02/2022
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20221202
Well API #PTD #Log Date Log
Company Log Type AOGCC
Eset#
BRU 222-34 50283201860000 222039 11/22/2022 AK E-Line Perf
BRU 233-23 50283201360100 222050 11/3/2022 AK E-Line GPT
BRU 244-27 50283201850000 222038 11/23/2022 AK E-Line Perf GPT
CLU 05RD2 50133204740200 222092 11/17/2022 AK E-Line Perf
MPU K-34 50029227120000 196169 11/10/2022 AK E-Line Punch
CLU 13 50133206460000 214171 11/12/2022 Halliburton SBHP
END 3-25B 50029221250200 203021 11/24/2022 Halliburton PPROF
PBU S-15 50029211130000 184071 11/24/2022 Halliburton RBT
PBU Z-221 50029237040000 221095 11/17/2022 Halliburton IPROF
PBU Z-221 50029237040000 221095 11/19/2022 Halliburton IPROF
Please include current contact information if different from above.
T37345
T37346
T37347
T37348
T37349
T37350
T37351
T37352
T37353
T37353
By Meredith Guhl at 12:25 pm, Dec 02, 2022
PBU Z-221 50029237040000 221095 11/17/2022 Halliburton IPROF
PBU Z-221 50029237040000 221095 11/19/2022 Halliburton IPROF
Meredith Guhl Digitally signed by Meredith Guhl
Date: 2022.12.02 12:24:17 -09'00'
DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23704-00-00Well Name/No. PRUDHOE BAY UN ORIN Z-221Completion StatusWAGINCompletion Date1/8/2022Permit to Drill2210950Operator Hilcorp North Slope, LLCMD17186TVD4949Current StatusWAGIN5/16/2022UICYesWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:ROP, AGR, DGR, ABG, EWR, ADR MD & TVDNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF1/21/20226460 17148 Electronic Data Set, Filename: PBU Z-221 ADR Quadrants All Curves.las36286EDDigital DataDF1/21/2022 Electronic File: PBU Z-221 Geosteering EOW Plot.emf36286EDDigital DataDF1/21/2022 Electronic File: PBU_Z-221_Geosteering.dlis36286EDDigital DataDF1/21/2022 Electronic File: PBU_Z-221_Geosteering.ver36286EDDigital DataDF1/21/2022 Electronic File: PBU Z-221 Geosteering EOW Plot.pdf36286EDDigital DataDF1/21/2022 Electronic File: PBU Z-221 Geosteering End of Well Report.docx36286EDDigital DataDF1/21/2022 Electronic File: PBU Z-221 Geosteering End of Well Report.pdf36286EDDigital DataDF1/21/2022 Electronic File: PBU Z-221 Post-Well Geosteering X-Section Summary.pdf36286EDDigital DataDF1/21/2022 Electronic File: PBU Z-221 Post-Well Geosteering X-Section Summary.pptx36286EDDigital DataDF1/21/2022 Electronic File: PBU Z-221 Geosteering EOW Plot150dpi.tif36286EDDigital DataDF1/21/2022 Electronic File: PBU Z-221 Geosteering EOW Plot300dpi.tif36286EDDigital Data0 0 2210950 PRUDHOE BAY UN ORIN Z-221 LOG HEADERS36286LogLog Header ScansDF1/21/2022150 17186 Electronic Data Set, Filename: PBU Z-221 LWD Final.las36287EDDigital DataDF1/21/2022 Electronic File: PBU Z-221 LWD Final MD.cgm36287EDDigital DataMonday, May 16, 2022AOGCCPage 1 of 3PBU Z-221 LWD Final.las
DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23704-00-00Well Name/No. PRUDHOE BAY UN ORIN Z-221Completion StatusWAGINCompletion Date1/8/2022Permit to Drill2210950Operator Hilcorp North Slope, LLCMD17186TVD4949Current StatusWAGIN5/16/2022UICYesWell Cores/Samples Information:ReceivedStart Stop CommentsTotalBoxesSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYMud 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 HISTORYCompletion Date:1/8/2022Release Date:11/23/2021DF1/21/2022 Electronic File: PBU Z-221 LWD Final TVD.cgm36287EDDigital DataDF1/21/2022 Electronic File: Z-221_Definitive Survey Report.pdf36287EDDigital DataDF1/21/2022 Electronic File: Z-221_Definitive Survey Report.txt36287EDDigital DataDF1/21/2022 Electronic File: Z-221_Definitive Surveys.xlsx36287EDDigital DataDF1/21/2022 Electronic File: Z-221_GIS.txt36287EDDigital DataDF1/21/2022 Electronic File: Z-221_Plan.pdf36287EDDigital DataDF1/21/2022 Electronic File: Z-221_VSec.pdf36287EDDigital DataDF1/21/2022 Electronic File: PBU Z-221 LWD Final MD.emf36287EDDigital DataDF1/21/2022 Electronic File: PBU Z-221 LWD Final TVD.emf36287EDDigital DataDF1/21/2022 Electronic File: PBU Z-221 LWD Final MD.pdf36287EDDigital DataDF1/21/2022 Electronic File: PBU Z-221 LWD Final TVD.pdf36287EDDigital DataDF1/21/2022 Electronic File: PBU Z-221 LWD Final MD.tif36287EDDigital DataDF1/21/2022 Electronic File: PBU Z-221 LWD Final TVD.tif36287EDDigital Data0 0 2210950 PRUDHOE BAY UN ORIN Z-221 LOG HEADERS36287LogLog Header ScansMonday, May 16, 2022AOGCCPage 2 of 3
DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23704-00-00Well Name/No. PRUDHOE BAY UN ORIN Z-221Completion StatusWAGINCompletion Date1/8/2022Permit to Drill2210950Operator Hilcorp North Slope, LLCMD17186TVD4949Current StatusWAGIN5/16/2022UICYesComments:Compliance Reviewed By:Date:Date CommentsDescriptionMonday, May 16, 2022AOGCCPage 3 of 3M. Guhl5/16/2022
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: 56.4' 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-53 162'
L80 1,996'
L-80 4,765'
7" L-80 4,565'
7"x4-1/2" L-80 4,949'
24. Open to production or injection? Yes No 25.
26.
Was hydraulic fracturing used during completion? Yes No
DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED
27.
Date First Production: Method of Operation (Flowing, gas lift, etc.):
Hours Tested: Production for Gas-MCF:
Test Period
Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr):
Press. 24-Hour Rate
9-5/8"12-1/4"
ACID, FRACTURE, CEMENT SQUEEZE, ETC.
CASING, LINER AND CEMENTING RECORD
List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion,
Uncemented TiebackTieback
TUBING RECORD
Uncemented Sliding Sleeves
5,756'4-1/2" 12.6# L-80
SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation
Size and Number; Date Perfd):
5,457' 17,181'
Stg 2 L - 461 sx / T - 267 sx
4,560'
42"
26# / 12.6#
25' 2,264' Stg 1 L - 537 sx / T - 400 sx
8-1/2"
17 yds Concrete
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
Hilcorp Alaska, LLC
WAG
Gas
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
1/8/2022
4295' FSL, 2802' FEL, Sec. 19, T11N, R12E, UM, AK
2586' FNL, 700' FWL, Sec. 08. T11N, R12E, UM, AK
221-095
Schrader Bluff Oil Pooll, Orion Dev Area
82.96'
17,138' / 4,947'
Prudhoe Bay /
HOLE SIZE AMOUNT
PULLED
50-029-23704-00-00
PBU Z-221
599876 5959100
2109' FNL, 1742' FEL, Sec. 19, T11N, R12E, UM, AK
CEMENTING RECORD
5957991
SETTING DEPTH TVD
5968104
BOTTOM TOP
26'
25'
CASING WT. PER
FT.GRADE
26#
600955
603223
TOP
SETTING DEPTH MD
26'
23'
Per 20 AAC 25.283 (i)(2) attach electronic information
40#
5,468'
1,996'
23'
DEPTH SET (MD)
5,569' / 4,610'
PACKER SET (MD/TVD)
215.5#
47#
162'
2,264' 6,474'
Gas-Oil Ratio:Choke Size:Water-Bbl:
PRODUCTION TEST
Not on Injection
Date of Test:
Flow Tubing
Oil-Bbl:
suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray,
caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation
record. Acronyms may be used. Attach a separate page if necessary
N/A
***Please see Schematic for Detail***
ROP, AGR, DGR, ABG, EWR, ADR MD & TVD
Sr Res EngSr Pet GeoSr Pet Eng
Oil-Bbl: Water-Bbl:
12/30/2021
12/17/2021
ADL 028262 & 047450
85-009
2,095' / 1,851'
N/AN/A
None
17,186' / 4,949'
Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment
By Meredith Guhl at 2:56 pm, Feb 01, 2022
RBDMS HEW 2/2/2022
Completion Date
1/8/2022
HEW
GDSR-2/2/22MGR08MAR2022DLB 04-27-2022
Conventional Core(s): Yes No Sidewall Cores:
30.
MD TVD
60' 60'
2155' 1911'
Top of Productive Interval 6393' 4759'
1932' 1740'
3317' 2830'
4119' 3500'
5098' 4348'
5485' 4573'
6393' 4759'
SB OBd 6393' 4759'
31. List of Attachments:
32. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Contact Name: Joe Lastufka
Contact Email:joseph.lastufka@hilcorp.com
Authorized Contact Phone: 777-8400
General:
Item 1a:
Item 1b:
Item 4b:
Item 9:
Item 15:
Item 19:
Item 20:
Item 22:
Item 23:
Item 24:
Item 27:
Item 28:
Item 30:
Item 31:
If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form,
if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071.
Authorized Name: Monty Myers
Authorized Title: Drilling Manager
Schrader Bluff NB
Schrader Bluff OBd
Permafrost - Base
29. GEOLOGIC MARKERS (List all formations and markers encountered): FORMATION TESTS
Permafrost - Top
Ugnu MB
SV5
SV1
This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram
with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical
reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted.
Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis,
paleontological report, production or well test results, per 20 AAC 25.070.
Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each
segregated pool is a completion.
TPI (Top of Producing Interval).
Yes No
Well tested? Yes No
28. CORE DATA
If yes, list intervals and formations tested, briefly summarizing test results.
Attach separate pages to this form, if needed, and submit detailed test
information, including reports, per 20 AAC 25.071.
NAME
Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical
laboratory information required by 20 AAC 25.071.
Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion,
suspension, or abandonment, whichever occurs first.
Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection,
Observation, or Other.
Formation at total depth:
Ugnu 3
LOT / FIT Data Sheet, 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
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).
Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and
other tests as required including, but not limited to: core analysis, paleontological report, production or well test results.
Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29.
Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool.
If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the
producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced,
showing the data pertinent to such interval).
Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit
detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity,
permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology.
Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment
2.1.2022Digitally 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: 2022.02.01 14:41:46 -09'00'
Monty M
Myers
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:PBU Z-221 Date:12/25/2021
Csg Size/Wt/Grade: Supervisor:Lott
Csg Setting Depth:6474 TMD 4766 TVD
Mud Weight:9.5 ppg LOT / FIT Press =620 psi
LOT / FIT =12.00 ppg Hole Depth =6483 md
Fluid Pumped=4.7 Bbls Volume Back =4.5 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
->05 ->00
->235 ->218
->499 ->477
->6 180 ->6148
->8 260 ->8221
->10 330 ->10 294
->12 400 ->12 360
->14 485 ->14 423
->16 540 ->16 487
->18 620 ->18 550
->20 ->20 619
->22 ->50 1638
->24 ->60 2011
->26 ->77 2700
Enter Holding Enter Holding Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0 620 ->0 2685
->1 590 ->5 2676
->2 570 ->10 2669
->3 560 ->15 2663
->4 550 ->20 2659
->5 540 ->25 2654
->6 532 ->30 2654
->7 525 ->
->8 519 ->
->9 512 ->
->10 508 ->
-> ->
-> ->
-> ->
9 5/8" 47#/40# L-80
0
2
4
6
8
10
12
14
16
18
0 2
4
6
8
10
12
14
16
18
20
50
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
0 102030405060708090Pressure (psi)Strokes (# of)
LOT / FIT DATA CASING TEST DATA
620
590570560550540532525519512508
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
0 5 10 15 20 25 30Pressure (psi)Time (Minutes)
LOT / FIT DATA CASING TEST DATA
Activity Date Ops Summary
12/14/2021 Rig down U-tube hoses. De-energize and blow down water adn steam. Disonnect interconnects. Lift staiirs on modules. Swap to cold start at 13:30 hrs. Scope
mezzanine back to sub from pits. Lift and scope cattle chute. Remove cuttings tank. Jack up Gen mod and install Jeep. NES trucks on location at 13:30 Split rig
mods. Install hooches and tioga heaters on all rig tires. Mobilize Gen Mod and mud Mod to Z-pad while walking sub base of L-207. Turn sub base and install sub
tires. Cont. installing rear tires on sub base. Install front tow bar. Prep catwalk and pipe shed. Mobilize sub, catwalk and pipe shed to 'Z' pad. Lay herculite and set
rig mats. Install slip lock head. Stage sub base on mats. Remove steering bar and rear tires.
12/15/2021 Spot and shim sub base over well. Turn stompers and retract. Safe out stairway. Spot rig mats. Spot catwalk. Unload rig mats from truck. Spot, shim and set pipe
shed, mud mod and gen mod. Sim Ops: Install outriggers. Convoy office camp and rig shop from L-pad to Z pad. Finish setting up office camp and rig shop. ASRC
trucks released at 16:30. Spot MPD choke house. Spot and hook up break shack and eivirovac. Spot cuttings tank. Set down all stairs. Safe out all
walkways/stairways. Plug in and swap from cold start to gen power at 19:30. Hook up all interconnects. Energize steam and air systems. Begin working on rig
acceptance checklist. Scope up derrick. Remove bridle jump pins. Plug in upper derrick lights. Lower blocks and bridle down. Perform post rig move derrick
inspection. Grease crown sheaves. Hang rig tongs. Sim Ops: work on rig acceptance checklist. N/U diverter system: Assist wellhead rep C/O grub screw on slip
lock head. Install diverter 'T' and N/U stack, tighten flange bolts. Install bell nipple on top of annular. Install knife valve on diverter 'T'. Start installing vent line. Sim
Ops: Cont. working on rig acceptance checklist. Assemble fluid ends on both mud pumps. Add nitrogen to pulsation dampeners.
12/16/2021 Cont N/U diverter vent line. Cross chain BOP, hook up hole-fill line and drain hoses. Install mousehole. Hook up accumulator hoses to annular. Install 5" DP
elevators. Pick up and rack back 39 stands of 5" drill pipe in derrick. Cont. N/U diverter vent line outside of cellar, with crane and loader. Finish N/U diverter vent line
with crane and loader. Vent line total length 253.2', 100' away from closest ignition source. Sim Ops: continue assisting mechanic with drag chain. Install new Mezz
kill valve. Grease blocks, top drive, wash pipe and IBOP. Rig accepted at 16:30 Hrs. Cont. to P/U and rack back a total of 100 stands of 5" drill pipe (3.125" drift).
Pick up and rack back HWDP and Jars (2.75" drift). L/D mousehole, hook up knife valve. Pick up joint of 5" DP and perform diverter test, witness waived by
AOGCC Austin Mcleod. Annular close in 8 seconds, knife valve open in 6 seconds. Test gas alarms. checked level alarms in pits, PVT sensors, pit and trip G/L,
return flow paddle alarms. Cut and slip 88' of drilling line. Calibrate block height, check brake tolerances. Service rig: grease crown, iron roughneck, drawworks and
handling equipment. C/O bail sensor batter. Install battery for link tilt board saver. prep rig floor to pick up BHA. R/U and test new mezzanine valve to 5000 psi.
Pre-Spud meeting. M/U cleanout BHA, 12-1/4" Kymera bit, mud motor. M/U first stand of HWDP and tag ice plug at 35'. Fill lines and PT surface lines to 3000 psi -
good. Wash and ream down cleaning out conductor to 162' at 375 gpm, 375 psi, 30 rpms, 1-2Kft-lbs. Drill 12-1/4" hole from 162' to 220' at 375 gpm, 400 psi, 30
rpms, 1-3Kft-lbs, WOB 1-3K. Lost 150 bbls of mud while drilling. BROOH at drilling rates to 190' prior to drag chain packing off. POOH to 160' inside conductor.
Rig up hoses and supersucker to clear out drag chain. Wash down at 1 bpm, tag up at 190'. Wash and ream from 190' to 220' at 400 gpm, 425 psi, 30 rpms, 1-2K
ft-lbs. BROOH to 160' inside conductor. CBU x 2 to clear out conductor. Blow down top drive. Daily disposal to G&I= 0 bbls, total = 0 bbls. Daily water from Lake-2
= 580 bbls, total = 580 bbls. Daily Metal = 0 bbls, total = 0 bbls. Daily losses = 150 bbls, total = 150 bbls.
12/17/2021 PU GWD and DM Collars, make Scribe, PU EWR and TM Collars and upload MWD Tools. PU 2 flex collars, RIH with 1st stand HWD and tag 15’ ft of fill @ 205’,
wash/ream down to 220’. Drill 12-1/4" surface hole from 220' to 343' MD, GPM 400, PSI 815, WOB 2-5K, RPM 30, TQ on 2-5K, TQ off 1-2K, ECD 9.7, PU 58K, SO
55K, Rot 57K. Drill 12-1/4" surface hole from 343' to 893' (total 550', AROP=92fph) at 475 gpm, 1235psi, WOB 2-5K, 60rpms, 3-4Kft-lbs, ECD 10.2 ppg with
9.1ppg mud. PUW 67K, SOW 70K, ROTW 70K. GWD surveys. KOP 500', building 3°/100 to 600' then attempting 5°/100' build as per plan, output 2.5-3.5°/100'.
Drill 12-1/4" surface hole from 893' to 1289' (total 396', AROP=66fph) at 475 gpm, 1235psi, WOB 3-10K, 60rpms, 3-5Kft-lbs, ECD 9.8 ppg with 9.2ppg mud. PUW
78K, SOW 73K, ROTW 75K. Last GWD survey at 995'. sliding 80% attempting for 5°/100' build as per plan, output 2.5-3.5°/100'. Drill 12-1/4" surface hole from
1289' to 1988' (total 699', AROP=117fph) at 500 gpm, 1480psi, WOB 5-15K, 80rpms, 5-6Kft-lbs, ECD 10.3 ppg with 9.4 ppg mud. PUW 90K, SOW 75K, ROTW
81K. Backream full stands. Start Tangent at 1455'. Daily disposal to G&I= 741 bbls, total = 741 bbls. Daily water from Lake-2 = 840 bbls, total = 1420 bbls. Daily
Metal = 0 bbls, total = 0 bbls. Daily losses = 70 bbls, total = 120 bbls. Distance to WP05: 24.01', 23.4' Low, 5.37' Right.
12/18/2021 Drill 12-1/4" surface hole from 1,988' to 2751,' MD, (total 763', AROP=127fph) at 500 gpm, 1650 psi, WOB 4-12K, 80rpms, 6-8kftlbs, ECD 10.6 ppg , MW 9.5, Max
Gas 483u, PUW 105K, SOW 80K, ROTW 92K. Back Ream Full stds. GEO Picked Base Permafrost @ 2,155’ md / 1,911’ tvd. Mant. slides through tangent Drill 12-
1/4" surface hole from 2,751' MD to 3,403' MD, (total 652', AROP=109fph) at 500 gpm, 1690 psi, WOB 2-12K, 80rpms, 7-8kft-lbs, ECD 10.3 ppg , MW 9.55, Max
Gas 762u, PUW 123K, SOW 91K, ROTW 105K. Back Ream Full stds. Maintenance slides through tangent. Drill 12-1/4" surface hole from 3403' MD to 3832' MD,
(total 429', AROP=72fph) at 530 gpm, 1700 psi, WOB 2-16K, 80rpms, 7-8kft-lbs, ECD 10.2 ppg , MW 9.55, Max Gas 628u, PUW 130K, SOW 97K, ROTW 111K.
Back Ream Full stds. Start 5°/100' turn/drop at 3641'. Drill 12-1/4" surface hole from 3832' MD to 4149' MD, (total 317', AROP=53fph) at 550 gpm, 1840 psi, WOB
4-15K, 80rpms, 10-12kft-lbs, ECD 10.0 ppg , MW 9.55, Max Gas 337u, PUW 152K, SOW 92K, ROTW 114K. Back Ream Full stds. Slide 70% for 5°/100' turn.
Daily disposal to G&I= 1026 bbls, total = 1767 bbls. Daily water from Lake-2 = 1120 bbls, total = 2540 bbls. Daily Metal = 0 bbls, total = 0 bbls. Daily losses = 0
bbls, total = 220 bbls. Distance to WP05: 22.7', 13.53' High, 18.23' Left.
50-029-23704-00-00API #:
Well Name:
Field:
County/State:
PBW Z-221
Prudhoe Bay West
Hilcorp Energy Company Composite Report
, Alaska
12/17/2021Spud Date:
12/19/2021 Drill 12-1/4" surface hole from 4149' MD to 4540' MD, (total 391', AROP=65fph) at 550 gpm, 1860 psi, WOB 4-15K, 80rpms, 13-15kft-lbs, ECD 10.13 ppg , MW
9.55, Max Gas 405u, PUW 167K, SOW 99K, ROTW 125K. Back Ream Full stds. 70% slide for 5°/100' turn/drop. Drill 12-1/4" surface hole from 4540' MD to 4654'
MD, (total 114', AROP=57fph) at 550 gpm, 2085 psi, WOB 6-15K, 80rpms, 12-14kft-lbs, ECD 10.13 ppg , MW 9.4, Max Gas 215u, PUW 166K, SOW 100K,
ROTW 126K. Back Ream Full stds. 70% slide for 5°/100' turn/build. Change out swab and liner on mud pump 1, pod 4. Reciprocate pipe, at 3.5 bpm, 535 psi. Drill
12-1/4" surface hole from 4654' MD to 4828' MD, (total 174', AROP=50fph) at 550 gpm, 2015 psi, WOB 2-16K, 80rpms, 12-14kft-lbs, ECD 9.8 ppg , MW 9.4, Max
Gas 251u, PUW 174K, SOW 100K, ROTW 128K. Back Ream Full stds. 60-70% slide for 5°/100' turn/build. Drill 12-1/4" surface hole from 4828' MD to 5104' MD,
(total 276', AROP= 46fph) at 550 gpm, 2145 psi, WOB 2-16K, 80rpms, 13-16kft-lbs, ECD 9.9 ppg , MW 9.35, Max Gas 158u, PUW 178K, SOW 101K, ROTW
128K. Back Ream Full stds. 60-70% slide for 5°/100' turn/build. Drill 12-1/4" surface hole from 5104' MD to 5398' MD, (total 294', AROP= 49fph) at 550 gpm, 2175
psi, WOB 5-15K, 80rpms, 15-18kft-lbs, ECD 10.2 ppg , MW 9.4, Max Gas 306u, PUW 192K, SOW 98K, ROTW 133K. Back Ream Full stds. 60-70% slide for
5°/100' turn/build. Daily disposal to G&I= 1207 bbls, total = 2974 bbls. Daily water from Lake-2 = 840 bbls, total = 3380 bbls. Daily Metal = 0 bbls, total = 0 bbls.
Daily losses = 0 bbls, total = 220 bbls. Distance to WP05: 22.46', 15.17' High, 16.57' Right.
12/20/2021 Drill 12-1/4" surface hole from 5398' MD to 5804' MD, (total 406', AROP= 68fph) at 550 gpm, 2270 psi, WOB 5-15K, 80rpms, 15-16kft-lbs, ECD 10.4 ppg , MW
9.4, Max Gas 619u, PUW 188K, SOW 93K, ROTW 128K. Back Ream Full stds. 60-70% slide for 5°/100' turn/build. Drill 12-1/4" surface hole from 5804' MD to
6192' MD, (total 388', AROP= 65fph) at 550 gpm, 2360 psi, WOB 5-15K, 80rpms, 15-16kft-lbs, ECD 9.9 ppg , MW 9.5, Max Gas 695u, PUW 182K, SOW 91K,
ROTW 124K. Back Ream Full stds. Start tangent section at 5976' holding 85°. Drill 12-1/4" surface hole from 6192' MD to casing point at 6483' MD, (total 291',
AROP= 73fph) at 550 gpm, 2410 psi, WOB 6-22K, 80rpms, 15-16kft-lbs, ECD 10.0 ppg , MW 9.5, Max Gas 612u, PUW 182K, SOW 91K, ROTW 124K. Back
Ream Full stds. Obtain final survey. BROOH from 6483' to 6315'. Pump high viscosity/walnut sweep (on time, no increase) and circulate hole clean x2 bottoms up
at 550 gpm, 1920 psi, 80 rpms, 14-16Kft-lbs, ECD 9.8 ppg, reciprocating pipe. Max gas 565U. Downlink to MWD to turn GWD on. Monitor well, static. RIH on
elevators from 6252' to 6483, washing last stand down at 3 bpm, 450 psi. No fill. PUW 186K, SOW 94K BROOH from 6483' to 4058' at 550 gpm, 1950 psi, 80
rpms 11-16Kft-lbs, ECD 10.3 ppg with 9.5 ppg mud. Max gas 468U. Pulling 15-40 fpm as hole dictates. PUW 169K, SOW 96K, ROTW 120K Daily disposal to
G&I= 1145 bbls, total = 4119 bbls. Daily water from Lake-2 = 1400 bbls, total = 4780 bbls. Daily Metal = 0 bbls, total = 0 bbls. Daily losses = 0 bbls, total = 220
bbls. Distance to WP05: 6.71', 5.9' Low, 3.2' Left.
12/21/2021 Cont. to BROOH from 4058' to 3481' at 550 gpm, 1775 psi, 80 rpms, 9-12Kft-lbs, max gas 245U, ECD 10.8 ppg with 9.5 ppg mud. ROT 102K. Pull 15-30 fpm.
Circulate bottoms up (end of tangent) at 550 gpm, 1770 psi, 80 rpms, 9-11Kft-lbs, reciprocating pipe up to 3415'. Observe hole unload with clay. Cont. BROOH
from 3415' to 781' at 550 gpm, 1375 psi, 80 rpms, 3.6Kft-lbs. Max gas 596U. ECD 10.3 ppg, PUW 75K, SOW 70K, ROT 72K. Pull 25-60 fpm as hole dictates.
Slow pulling speed from 2308' to 2181' to circulated bottoms up prior to permafrost. Monitor well at HWDP, static. Cont BROOH from 781' to 408' at 550 gpm, 1295
psi, 80 rpms, 1-3Kft-lbs, no gas. ECD 10.1 ppg with 9.5 ppg mud. Blow down top drive.
POOH on elevators from 408' to 159'. PUW 52K, SOW 52K. L/D BHA. L/D XO and 2 flex collars. Plug in and download MWD. L/D TM, EWR, DM, GWD, motor
and bit. Bit grade 1-2-BT-G-X-2-CT-TD. Clean and clear rig floor of BHA components. R/U to RIH with casing, rig up power tongs. M/U Volant tool. Remove Hyd
elevators and install 9-5/8". Verify pipe and centralizer count. M/U shoe track, Baker Lok joints, check floats - good. HES install bypass baffle. RIH with 9-5/8", 40#,
L-80, TXP casing as per detail to 1160'. Set down at 1160'. Attempt to work though, establish rotary and circulations adjusting parameters as needed. Wash and
ream 9-5/8" casing from 1160' to 1349' with 3-5 bpm, 75-250 psi, 5-15 rpms, 7-12Kft-lbs. Observe significant amount of sand with wood and gravel returns. PUW
83K, SOW 60K, ROTW 71K. Cont. to wash and ream 9-5/8 casing from 1349' to 2238' at 3 bpm, 150 psi, 10 rpm, 7-12Kft-lbs. PUW 108K, SOW 76K, ROT 73K.
Circulate 2 x bottoms up staging pumps up to 7 bpm, 152 psi, 15 rpms, 8-9Kft-lbs. Observed significant amount of sand, clay with some wood at first bottoms up.
Cont. to RIH from 2238' to 3266' with 9-5/8", 40#, L-80, TXP casing at 25-35 fpm. PUW 146K, SOW 86K. Daily disposal to G&I= 922 bbls, total = 5041 bbls. Daily
water from Lake-2 = 560 bbls, total = 5340 bbls. Daily Metal = 0 bbls, total = 0 bbls. Daily losses = 42 bbls, total = 262 bbls.
12/22/2021 Continue to Run 9 5/8", 40#, L-80, TXP/BTC Casing from 3266' to 3513' MD. Use BEST-O LIFE Pipe Dope, TQ connections to 21K Ft/lbs, run Bow Spring Cents
as Tally. Running speed 25 fpm. CBU from 3513' (End Of Tangent)Staging pumps up to 6 BPM, 222 PSI. Reciprocate pipe from 3513 to 3475'. Continue to Run 9
5/8", 40#, L-80, TXP/BTC Casing from 3513'' to 4169' MD.. MU ESCMTR from 4169' to 4209'. Thread lock connections. M/U XO Joint. Run in hole with 9 5/8" 47#,
L-80, VAM-TOP Casing from 4209' to 5737'. PU 295K, SO 128K. Loss-37 bbls. Continue to run 9 5/8" 47#, L-80, VAM-TOP Casing from 5737'' to 6477'. (Ran 75
centralizers, 8 Stop Rings) Run Speed 25-35 fpm. PU 280K, SO 126K. Verify Pipe Count and/Tally. Lost 17 bbls. Circulate and condition Mud for Cement Job,
staging pumps to 7 bpm, 205 PSI, Rot/Recip from 6435' to 6478'. PU 280K, SO 126K ROT 305k SIMOPS: R/D Weatherford PWR Tongs,elvators and Bale
Extensions. Blow down Cement Line. Prep for Cement Job. Lost 15 bbls PJSM Shut down pumps. Blow down top drive. Break out Volant. Inspect dies and cup.
M/U Volant. R/U 1502 HP cement lines and valves. Close IBOP's. ROT Rec 6435' to 6478' MD. stage pumps up to 6 bpm 395 psi 1-3 RPM while moving. TRQ
limit set 18k. P/U 295k SLK 130k Lost 10 bbls PJSM, Wet lines w/ 5 bbls H2O (HES) and P/T low kick out 1,511 low/ 4,100 high. HES replaced PRV on air
compressor and Press gauge on silo. Rec F/ 6,478' to 6,435' MD. Pump 1st stage cement job as follows: 55.4 bbls 10 ppg Tuned spacer w/ 4# red dye & 5 lb/bbl
poly flake (1st 10 bbls) 3.5 bpm, 320 psi. Release F/ Volant, Drop bypass plug. 223 bbls (537 sx) 12 ppg EconoCem Type I II Lead cmt, 2.347 yld, 4.3 bpm, 450
PSI. 84.3 bbls (400 sx) 15.8 ppg HalCem Type I II Tail cmt, 1.156 yld, 3.8 bpm, ICP 846 psi FCP 451 PSI. Release F/ Volant, drop shutoff plug. Displace w/ 20 bbls
H2O (HES) 6.5 bpm 672 psi then turn over to rig. Rig disp w/ 278 bbls 9.55 ppg spud mud, 7 bpm, ICP 354 psi for 220 bbls away, reduced rate to 6 bpm ICP 338
psi, FCP 441 psi. Stop Rot & Rec string set at 6,477’ MD W/ 238K string WT. HES disp 80 bbls 9.4 ppg spacer, 5 bpm 504 psi. Rig disp 102.2 bbls 9.55 ppg spud
mud 6 bpm, ICP 736 psi FCP 1011 psi. Reduced rate last 21 bbls to 3 bpm, FCP 840 PSI. Bump plug, Press up to 1,415 PSI with 460.3 bbls actual / 455.6 bbls
calculated. Held pressure for 5 minutes, check floats - good. CIP 00:20 hrs. Full returns throughout job. Pump at 3 bpm Press up to 3,071 psi ES cementer opened.
Increase pumps to 6 bpm 470 PSI. At 1,600 STKS (99.2 bbls) away saw green cement, 50 bbls cement dumped at surface. 9.625" Shoe at 6,478' MD. Stage up to
7 bpm 440 psi. Shut down flush surface lines. W/ black H2O. At 15,000 stks shut down. Disconnect knife valve and flush stack W/ black H2O. Function Annular 2X.
Stage pumps up to 7 bpm 430 psi. SIMOPS haul excess cement and prep pits. Prep pits for 2nd stage. Load 5" D.P. in pipe shed. Daily disposal to G&I= 529 bbls,
total = 5570 bbls. Daily water from Lake-2 = 420 bbls, total = 5760 bbls. Daily Metal = 0 bbls, total = 0 bbls. Daily losses = 144 bbls, total = 406 bbls.
223 bbls (537 sx) 12 ppg EconoCem
84.3 bbls (400 sx) 15.8 ppg
Full returns throughout job.
Rot/Recip from 6435' to 6478'. P
Bump plug,
ppoint at 6483' MD,
12/23/2021 Continue to circulate through stage tool @ 7 bpm / 500 psi while prepping for 2nd stage Cement. PJSM, Pump 2nd stage cmt job. Lineup to cmtrs, wet lines w/ 5
bbls FW. Mix/Pump 55 bbls 10.5# Tuned Spacer III w/ 4# red dye first 10 bbls, 4.7 BPM, 290 psi. Mix and pump 461 sxs (254 bbls)( 2.883 yld)Perm "L" Lead
Cement at 10.7 ppg. Pump Lead until seen @ Surface. See Spacer @ 210 bbls into Lead. See Green Cmt 235 bbls into Lead. (Calculated STS volume =328 bbls).
Go into Tail CMT. Mix and pump 267 sxs (56 bbls)(1.169 yld) Premium "G" Tail Cement at 15.8 ppg. Drop closing plug. Displace cmt w/ 20 bbls FW f/ Cmt Unit.
Rig 147.3 bbls (147.3 calculated)(Total 167.3 bbls) (Calc 167.3) 9.4ppg mud, 6bpm/ 835psi, FCP 690 psi @ 3 bpm last 17 bbls. Bumped and psi up to 1880 psi
(ES shift @ 1450 psi)Held 5 min.CIP @ 10:30. Full Returns through out job Pump Cement @ 6 BPM avg. Circulated 221 bbls of Green Cement to surface. Blow
down cement lines and R/D. L/D Volant. R/D knife valve. Drain stack. Flush stack and cement lines W/ black H2O. Vac out 9.625" Csg for cut. R/D first section of
diverter line. R/U bridge cranes to BOP stack. R/D chain and binders. SIMOPS Haul off surface mud and clean pits. PJSM Loosen speed head and suspend stack.
Set 9.625" emergency slips W/ 40k as per Vault rep onsite. Cut 9.625" Csg (28.29') Johnny whack stack and jet flowline. Clean hatches on flow line. Blow down
TD. Disconnect knife valve., diverter tee and remove W/ crane. SIMOPS Cont crane diverter sections. Off load fluid and pit cleaning. Stop all operations due to
Phase 3 weather conditions. PJSM N/D speed head. M/U RCD to BOP. Daily disposal to G&I= 867 bbls, total = 6437 bbls. Daily water from Lake-2 = 700 bbls, total
= 6460 bbls. Daily Metal = 0 bbls, total = 0 bbls. Daily losses = 0 bbls, total = 369 bbls.
12/24/2021 Install MPD Head on top of Stack, install nuts, disconnect tuggers and rack back Stack. PU Slip Lock CSG Spool and install as per Wellhead Rep. Install test plug
and Make up TBG Spool and Test Tbg spool seals. Tq MPD Head connections. PJSM, Install DSA, Set Stack on Well, M/U 4" MPD Line, install Drip Pan, R/U Hole
Fill line, R/U turn buckles, Tq connections, M/U Choke and kill lines. SIMOPS: M/U Floor valve assembly for BOPE Test, R/U Pump in sub to Top Drive. C/O
Elevators to 5" Hyd Elevators, R/U Koomey lines to BOP's PJSM Finish torqueing choke, kill lines, & DSA. Install companion flange on IA. SIMOPS Clean Pits.
PJSM Open UPR & LWR dorrs. Clean and inspect ram seals and doors. C/O LPR upper ram seal DS. RKB ANN 12.64' UPR 14.87' Blind 16.52' LPR 19.94' ULDS
24.23' LLDS 24.23' GL 26.68'. PJSM Install RCD test cap. Flood MPD Equip & lines. PT MPD 250/ 1200 psi, good. BD MPD Equip. R/D test cap. Install trip nipple.
PJSM M/U 5" test jnt, test plug, side entry sub, 5" TIW & 5" Dart. Flood lines and purge air. Perform shell test 250/3000 psi, good. Flange leak on Super Choke
tightened, good. 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 3,000 PSI, Manifold
1,300 PSI, Annular 1,500 PSI, after System 1,500 PSI, Man 1,500 PSI, Annular 1,550 PSI. 200 PSI increase 24 Sec, full charge 98 sec. Nitrogen 6 bottle average
2,329 PSI. Witnessed Waived by AOGCC Bob Noble. PJSM R/D 4.5" test jnt and test Equip. Blow down choke, kill and manifold. Pull test plug. Drain BOP. Install
wear ring. (9" ID 10.75" OD 38" Lng) Clean and clear rig floor. Prep pipe shed for picking up D.P. Bring air slips to rig floor and prep to P/U D.P. SIMOPS bring on
9.5 ppg BaraDril N. PJSM P/U M/U RR 8.5" XR-CPS Tri Cone bit (0.9419 TFA) & 6.75" StrataForce 6:7- 6 stg 1.5° motor 32.1'. Check float Cont P/U 5" HWDP &
jar to 591' MD. PJSM Single in hole W/ 5" 19.5# S-135 NC50 D.P. F/ skate F/ 591' to 2,243' MD. Fill pipe & wash F/ 2,243' to tag cement 2,281' MD 350 gpm 470
psi 30 rpm trq 4.5k P/U 96k SLK 70k ROT 89k. (Drift OD 3.125") Drill cement and ES F/ 2,281' to 2,286 MD ES on depth at 2,282' MD. 350 gpm 610 psi 30 rpm
Trq 4.5k WOB 4k. Ream through ES 2X. & no pumps & rotation. No issue. Chased plug F/ 2,286' to 2,434' MD. Rubber overserved at shakers. Blow down top
drive. PJSM Cont single in hole W/ 5" 19.5# S-135 NC50 D.P. F/ skate F/ 2,434' to 5,040' MD. P/U 166k SLK 86k. (Drift OD 3.125") Daily disposal to G&I= 1098
bbls, total = 7535 bbls. Daily water from Lake-2 = 140 bbls, total = 6600 bbls. Daily Metal = 0 bbls, total = 0 bbls. Daily losses = 0 bbls, total = 369 bbls.
12/25/2021 Continue single n the hole picking up 5" DP from 5040' to 6280', wash down to 6309' (Baffle adapter @ 6349') PU 205K, SO 87K PJSM, CBU @ 350 GPM, 650
PSI, 20 RPM, 16-17 TQ, working pipe from 6309' to 6248' R/U and PT 9 5/8" Casing to 2500 psi on chart for 30 min. 4.5 bbls pumped, 4.5 bbls back. Blow down
Choke and Kill Lines, shut manual valves. Drill CMT/FE from 6309' to 6474' MD, 450 GPM, 1170 PSI, 5-12K WOB, 30 RPM, 15-17K TQ, PU 205K, SO 84K, Rot
125K. Drill baffle, Float collar and Shoe on Depth as per Casing Tally. Pass through Baffle and Float collar with/with out Pumps and Rotary, no issues. Drill Rat hole
and 20' New formation from 6483' to 6503' MD, 4767' TVD, Pump 44 bbls Visc Spacer and displace to 9.5 ppg BARADRIL-N, 450 GPM, 920 PSI, 5-12K WOB 30
RPM, 15-17K TQ, PU 195K, SO 87K, Rot 125K. Rack Back 2 Stands into Casing Shoe for FIT Test. Line up and Flood Choke /Kill Lines. Perform FIT Test @ 6430'
Bit Depth, 6503' TD, 4767' TVD, w/9.5 ppg MW, Apply 620 PSI surface pressure (12.0 EMW) Pumped 1.1 BBLS, bled back .50 BBLS. R/D and Blow Down Choke
and Kill Lines. TOH From 6430' to 592' MD, racking back 5" DP. No losses. PJSM L/D 10 jnts 5" HWDP. Rack back 4 stand 5" HWDP & Jar. L/D 1.5° Motor and
Tri cone Bit. Bit Grade 1-1-A-E-1/16-NO-BHA PJSM Stage on rig floor, 8.5" TK66 PDC (6X13 0.7777 TFA) 8.5" NPR, 2 ea Float Sub, 8.3/8" ILS. 8.375" IB, 6.75"
DM, 6.75 TM HOC. PJSM P/U M/U Geo-Pilot 7600 XL 25KSI, 8.5" HRP & 8.5" PDC TK66 Bit. PJSM Cont P/U M/U 6.75" ADR, 8.375" ILS, 6.75" DGR, 6.75"
PWD. Put TM HOC in mouse hole. While inspecting IBS TM collar slipped out of slips and dog collar and landed at bottom of mouse hole. Heavy frost was
observed on TM collar. Picked up TM and inspected, no visual signs of damage observed. Changed out TM W/ spare for potential internal damage. M/U 6.75" TM
HOC, 8.375" Integral Blade. Download MWD as per MWD rep onsite. Cont P/U 6.75" NM FS (non ported plunger) 6.75" NM FC, 6.75" NM FS (non ported plunger)
6.75" NM FC, encountered debris at 95' MD and worked through without issue. 4 ea 5" HWDP, 6.75" SLB Hydra Jar, 3 ea 5" HWDP. 405.66' MD. PJSM Single in
hole BHA 3 8.5" RSS W/ 5" 19.5# S-135 NC50 F/ pipe shed F/ 406' to 1,676' MD. Drift OD 3.135" P/U 69k SLK 60k. No losses. Daily disposal to G&I= 1137bbls,
total = 8672 bbls. Daily water from Lake-2 = 560 bbls, total = 7160 bbls. Daily Metal = 10 bbls, total = 10 bbls. Daily losses = 0 bbls, total = 0 bbls. Surface Loss:
369.
12/26/2021 Continue RIH Picking up 5" DP from 1676' to 6062'. RIH out of Derrick to 6442'. (Break in Geo Pilot/Shallow Hole Test @ 2597') PU 170, SO 86K PJSM, Drain
Stack and remove bell nipple. Install RCD Bearing. Circulate through and check for leaks. Hang Blocks and set slips, slip off drum and cut Drill Line, MU Dog Nut
and loosen Deadman, slip on Drill Line, TQ Deadman to 80 ft/lbs. Un Hang block. Check Brake Tolerances on Drawworks. Teach Drum position on 1st layer, teach
block position, check floor and crown saver. Cut 69', 11 wraps, l Grease Roughneck, Crown Sheaves and Top Drive. Perform Derrick inspection, inspect welds and
parts on Top Drive Cradle. Check Gear Oil Level on Top Drive and Rotary Table. Complete monthly Block Sheave Wobble Tolerance EAM. Wash Down from6443'
to 6503'MD. Drill 8 1/2" Lateral from 6,503' MD to 6,820' MD, 4,779 TVD (total 317', AROP= 79.3fph) at 450 gpm, 1120 psi, WOB 5-8K, 120 rpms, 14kft-lbs, ECD
10.38 ppg , MW 9.5, Max Gas 950u, PUW 185K, SOW 76K, ROTW 112K. MPD Chokes Full Open. Drill 8.5" Lateral Hole F/ 6,820' to 7,647' MD (4,809' TVD)
Total 827’ (AROP 137.9’) 500 GPM/ MPD 500, on 1,450 psi 80-120 RPM, TRQ on 15-16k, TRQ off 15k, WOB 5-8k. ECD 10.73. Max Gas 1,570u. P/U 187k, SLK
75k, ROT 110k. MPD 100% open Undulating in OBd sand as per Geo. Back ream 30' stands. Drill 8.5" Lateral Hole F/ 7,647' to 8,180' MD (4,826' TVD) Total 533’
(AROP 88.9’) 500 GPM/ MPD 500, on 1,480 psi 60-120 RPM, TRQ on 16-18k, TRQ off 15-17k, WOB 2-8k. ECD 10.51. Max Gas 1,250u. P/U 188k, SLK 77k,
ROT 112k. MPD 100% open Adjusting RPM and ROP due to surface wobble of drill string. Undulating in OBd sand as per Geo. Back ream 30' stands. Distance to
WP05 19.08', 19.08' Low, 0.28' Left. 12 concretions drilled, for total footage of 45’ (2.8% of the lateral section). OBd sand footage 1,619'. Total 1,619' in OBd sand
Daily disposal to G&I= 259 bbls, total = 8931 bbls. Daily water from Lake-2 = 240 bbls, total = 7400 bbls. Daily Metal = 10 bbls, total = 10 bbls. Daily losses = 0
bbls, total = 0 bbls. Surface loss 369 bbls.
Bumped and psi up to 1880 psi
Full Returns through out job Pump Cement
r 2nd stage Cement.
(254 bbls)( 2.883 yld)
Circulated 221 bbls of Green Cement to surface.
267 sxs (56 bbls)(1.169 yld) Premium "G" Tail Cement at 15.8 ppg.
Casing to 2500 psi on chart for 30 min. 4.5 bbls pumped, 4.5 bbls back.
12/27/2021 Drill 8.5" Lateral Hole F/ 8,180' to 8,792' MD (4,833' TVD) Total 612’ (AROP 102’) 500 GPM/ MPD 500, on 1,450 psi 80-100 RPM, TRQ on 16-17k, TRQ off 15-
16k, WOB 4-8k. ECD 10.51. Max Gas 1,138u. P/U 178k, SLK 74k, ROT 111k. MPD 100% open. Undulating in OBD as per Geo. Drill 8.5" Lateral Hole F/ 8,792' to
9,435' MD (4,833' TVD) Total 643' (AROP 107.2’) 500 GPM/ MPD 500, on 1,605 psi 80-100 RPM, TRQ on 16-17k, TRQ off 15-16k, WOB 4-8k. ECD 10.6. Max
Gas 757u. P/U 177k, SLK 75k, ROT 115k. MPD 100% open. Back ream 60'. Adjust RPM & ROP for surface wobble. Drill 8.5" Lateral Hole F/ 9,435' to 9,938' MD
(4,880' TVD) Total 503' (AROP 83.4’) 500 GPM/ MPD 500, on 1,750 psi 80-100 RPM, TRQ on 17k, TRQ off 16k, WOB 6-8k. ECD 10.78. Max Gas 968u. P/U
178k, SLK 76k, ROT 112k. MPD 100% open. Back ream 60'. Crossed Fault #1 9,547' MD back in OBd at 9,943' MD throw 60' DTN. Adjust RPM & ROP for surface
wobble. Drill 8.5" Lateral Hole F/ 9,938' to 10,606' MD (4,897' TVD) Total 668' (AROP 111.4’) 500 GPM/ MPD 500, on 1,815 psi 100-110 RPM, TRQ on 18-19k,
TRQ off 16-17k, WOB 4-8k. ECD 11.1. Max Gas 1179u. P/U 188k, SLK 43k, ROT 111k. MPD 100% open. Back ream 60'. No issue w/ wobble on surface. Distance
to WP05 21.77', 21.77' Low, 0.24' Left undulating in OBD as per Geo. Fault 1 @ 9,545' MD. 29 concretions drilled, for total footage of 91’ (2.3% of the lateral
section). OBd sand footage 3,643' Footage out OBd 398'. Total 3,643' in OBd sand. Daily disposal to G&I= 750 bbls, total = 9681 bbls. Daily water from Lake-2 =
700 bbls, total = 8100 bbls. Daily Metal = 3 bbls, total = 13 bbls. Daily losses = 0 bbls, total = 0 bbls. Surface loss 369 bbls.
12/28/2021 Drill 8.5" Lateral Hole F/ 10,660' to 11,081' MD (4,900' TVD) Total 421' (AROP 70.2’) 500 GPM/ MPD 500, on 1,895 psi 100-110 RPM, TRQ on 20-21k, TRQ off
18-19k, WOB 4-16k. ECD 11.2. Max Gas 1174u. P/U 188k, SLK 35k, ROT 107k. MPD 100% open. Back ream 60'. 1 MPD 100% open. Lost SLK @ 10,765' MD.
Drill 8.5" Lateral Hole F/ 11,081' to 11,725' MD (4,900' TVD) Total 644' (AROP 107.’) 500 GPM/ MPD 500, on 2,050 psi 100-105 RPM, TRQ on 20-21k, TRQ off
19k, WOB 3-9k. ECD 11.28. Max Gas 1344u. P/U 190k, SLK 35k, ROT 108k. MPD 100% open. Back ream 60'. 1 MPD 100% open. Drill 8.5" Lateral Hole F/
11,725' to 12,259' MD (4,880' TVD) Total 534' (AROP 89’) 500 GPM/ MPD 496, on 2,210 psi 100-120 RPM, TRQ on 19-21k, TRQ off 19k, WOB 3-8k. ECD
11.74. Max Gas 995u. P/U 195k, SLK 35k, ROT 103k. MPD 100% open. Back ream 60'. 1 MPD 100% open. Came out top of OBd sand at 11,641' crossed Fault 2
at 11,853' MD throw 60' DTS. Reenter OBd at 12,137' MD. Drill 8.5" Lateral Hole F/ 12,259' to 12,862' MD (4,886' TVD) Total 603x' (AROP 100.5’) 500 GPM/ MPD
492, on 2,295 psi 120 RPM, TRQ on 20-21k, TRQ off 18-19k, WOB 3-8k. ECD 11.74. Max Gas 1150u. P/U 178k, SLK 35k, ROT 105k. MPD 100% open. Back
ream 60'. 1 MPD 100% open. Came out top of OBd sand at 11,641' crossed Fault 2 at 11,853' MD throw 60' DTS. Reenter OBd at 12,137' MD. Perform clean cycle
F/ 12,545’ to 12,673’ MD. Dump & Dilute 100 bbls, increase H20 to 40 bph to control ECD’s. Distance to WP05 20.35', 19.14' High, 6.83' Left undulating in OBD as
per Geo. Fault 1 @ 9,545' MD Fault 2 @ 11,858'. 39 concretions drilled, for total footage of 175’ (2.8% of the lateral section). OBd sand footage 5,379' Footage out
OBd 894'. Total 5,379' in OBd sand. Daily disposal to G&I= 635 bbls, total = 10316 bbls. Daily water from Lake-2 = 700 bbls, total = 8800 bbls. Daily Metal = 2
bbls, total = 15 bbls. Daily losses = 0 bbls, total = 0 bbls. Surface loss 369 bbls.
12/29/2021 Drill 8.5" Lateral Hole F/ 12,862' to 13,434' MD (4,913' TVD) Total 572' (AROP 95.4’) 500 GPM/ MPD 492, on 2,290 psi 120 RPM, TRQ on 18-19k, TRQ off 17-
18k, WOB 3-9k. ECD 11.68. Max Gas 977u. P/U 178k, SLK 35k, ROT 105k. MPD 100% open. Back ream 60'. Drill 8.5" Lateral Hole F/ 13,434' to 13,910' MD
(4,886' TVD) Total 476' (AROP 79.4’) 500 GPM/ MPD 490, on 2,355 psi 120 RPM, TRQ on 18-19k, TRQ off 18k, WOB 3-8k. ECD 11.72. Max Gas 1158u. P/U
178k, SLK 35k, ROT 104k. MPD 100% open. Back ream 60'. Crossed Fault 3 at 13,477' MD throw 81' DTS. Reenter OBd at 14,053' MD. Encountered dynamic
losses at 13,480' MD Initial loss rate ~85 bph dynamic healing up to ~13 bph dynamic at 13,497' MD, Cont drilling W/ ~10 bph dynamic losses to 13,628' MD. Drill
8.5" Lateral Hole F/ 13,910' to 14,451' MD (4,872' TVD) Total 541' (AROP 90.2') 500 GPM/ MPD 492, 2,125 psi 120 RPM, TRQ on 20k, TRQ off 19k, WOB 3-8k.
ECD 11.37. Max Gas 1060u. P/U 179k, SLK 35k, ROT 104k. MPD 100% open. Back ream 60'. Dump & Dilute 580 bbls 14,175' to 14,330' MD W/ 9.3 ppg BaraDril
N 4% lubes due to MBT & ECD. ECD prior 11.84 after 11.37. Drill 8.5" Lateral Hole F/ 14,451' to 15,150' MD (4,892' TVD) Total 699' (AROP 116.5') 500 GPM/
MPD 492, 2,325 psi 120 RPM, TRQ on 20-21k, TRQ off 19-20k, WOB 4-8k. ECD 11.44. Max Gas 1413u. P/U 194k, SLK 35k, ROT 106k. MPD 100% open. Back
ream 60'. Seeing 5-10 bph dynamic losses. Lost 30 bbls. Distance to WP05 20.82', 15.13' High, 14.3' Left undulating in OBD as per Geo. Fault 1 @ 9,545' Fault 2
@ 11,858' Fault 3 @ 13,477' MD. 46 concretions drilled, for total footage of 217’ (2.5% of the lateral section). OBd sand footage 7,143' Footage out OBd 1,460'.
Total 8,603' lateral Daily disposal to G&I= 867 bbls, total = 11183 bbls. Daily water from Lake-2 = 800 bbls, total = 9600 bbls. Daily Metal = 3 bbls, total = 18 bbls.
Daily losses = 82 bbls, total = 82 bbls. Surface loss 369 bbls.
12/30/2021 Drill 8.5" Lateral Hole F/ 15,150' to 15,851' MD (4,918' TVD) Total 701' (AROP 116.8') 500 GPM/ MPD 492, 2,500 psi 120 RPM, TRQ on 20-23k, TRQ off 19-20k,
WOB 4-8k. ECD 11.78. Max Gas 1418u. P/U 197k, SLK 35k, ROT 106k. MPD 100% open. Back ream 60'. Seeing 5-10 bph dynamic losses. Lost 25 bbls. Drill
8.5" Lateral Hole F/ 15,851' to 16,160' MD (4,932' TVD) Total 309' (AROP 123.6') 500 GPM/ MPD 488, 2,475 psi 120 RPM, TRQ on 20-23k, TRQ off 19-20k,
WOB 4-8k. ECD 11.54. Max Gas 1312u. P/U 192k, SLK 35k, ROT 105k. MPD 100% open. Back ream 60'. Seeing intermittent 5-15 bph dynamic losses. PJSM MP
#2 Pod #1 Swab, liner and wear plate failure (expendable items). C/O swab, liner and wear plate. Rot Rec F/ 16,160' to 16,100' MD 260 GPM/ MPD 260, 1,010 psi
80 RPM, TRQ 19-20k, ECD 10.89. Max Gas 1151u. P/U 192k, SLK 35k, ROT 104k. Lost 15 bbls. Drill 8.5" Lateral Hole F/ 16,160' to 16,350' MD (4,932' TVD)
Total 190' (AROP 76') 500 GPM/ MPD 490, 2,475 psi 120 RPM, TRQ on 20-27k, TRQ off 19-20k, WOB 4-8k. ECD 11.6. Max Gas 1273u. P/U 192k, SLK 35k,
ROT 105k. MPD 100% open. Back ream 60'. Seeing intermittent 5-15 bph dynamic losses. Drill 8.5" Lateral Hole F/ 16,350' to 16,868' MD (4,934' TVD) Total 518'
(AROP 86.4') 485-500 GPM/ MPD 488/473, 2,445 psi 90-120 RPM, TRQ on 22-24k, TRQ off 20-21k, WOB 4-8k. ECD 11.63. Max Gas 1125u. P/U 202k, SLK
35k, ROT 106k. MPD 100% open. Back ream 60'. F/ 16,284' to 16,420' reduce RPM F/ 120 to 100 due to high Trq 24-27.5k able to bring RPM back up to 120
rpm.. Adjusting rotary 90-120 RPM to control high Trq. Seeing intermittent 10-15 bph dynamic losses. Lost 57 bbl for tour. Drill 8.5" Lateral Hole F/ 16,868' to TD
17,186' MD (4,949' TVD) Total 318' (AROP 53') 485 GPM/ MPD 465, 2,445 psi 90-100 RPM, TRQ on 23.5-27.5k, TRQ off 21-22k, WOB 5-8k. ECD 11.57. Max
Gas 957u. P/U 205k, SLK 35k, ROT 111k. MPD 100% open. Back ream 60'. Obtain final MWD survey at TD 17,186' MD 4948.68' TVD 87.77° inc 3.96° az.
Seeing intermittent 10-15 bph dynamic losses. Lost 65 bbl. Distance to WP05 39.13', 39.05' Low, 2.44' Left. Fault 1 @ 9,545' Fault 2 @ 11,858' Fault 3 @ 13,477'
MD. 63 concretions drilled, for total footage of 302’ (2.8% of the lateral section). OBd sand footage 9,252' Footage out OBd 1,460'. Total 10,712' lateral Daily
disposal to G&I= 577 bbls, total = 11760 bbls. Daily water from Lake-2 = 840 bbls, total = 10440 bbls. Daily Metal = 2 bbls, total = 20 bbls. Daily losses = 112 bbls,
total = 194 bbls. Surface loss 369 bbls.
final MWD survey at TD 17,186' MD 4948.68' TVD 87.77° inc 3.96° az.
12/31/2021 Pump tandem 35 bbl low vis (8.6 ppg 38 vis) / high vis (10.0 ppg 225 vis) sweeps. Observed sweeps back on calc strokes with no increase in cuttings. Continue to
circulate at 485 GPM, 2475 PSI, 100-120 RPM, 22K TQ, 11.55 ECD, 9.3 ppg MW in/out with a max of 40 BPH losses which slowed to 17 BPH. Reciprocate 60'
alternating stopping points. MPD chokes fully open. Max gas 910u with 200-300u background. Circulated a total of 6x bottoms up while waiting on trucks to arrive.
Delayed due to frozen brakes and fuel lines with -40° temps. Pump three 40 bbl SAPP pills spaced w/ 20 bbls 9.3 ppg QuickDril. Displace w/ new 9.3 ppg QuickDril
3% lube 250 GPM, 1090 PSI, 120 RPM, 22K TQ. Inc to 295 GPM, 900 PSI. SAPP back on calc strokes. Observe erratic torque 18-24.5K, lower rotary to 100 RPM,
18-21K TQ. 32 bbls lost / 10 BPH avg. 20 BPH final loss rate observed. Take clean fluid returns to pit #5. Obtain new slow pump rates. Flow check - static. Close
MPD choke, observe well for 5 min., pressure dropped from 16 PSI to 9 PSI (hydrostatic to sensor). Drop 2.39" O.D. drill pipe drift - no wire tail. PJSM BROOH F/
17,186' to 16,620' MD 500 GPM/ MPD 448 1,550 psi 110 RPM, TRQ 16-20k, ECD 10.6. Max Gas 41u. P/U 204k, SLK 35k, ROT 115k. MPD 100% open. Pull
speed 20-30 ft/min. Cont BROOH F/ 16,620' to 14,790' MD 500 GPM/ MPD 468 1,600 psi 120 RPM, TRQ 15-18k, ECD 10.58. Max Gas 215u. P/U 178k, SLK
35k, ROT 112k. MPD 100% open. Pull speed 10-25 ft/min as hole dictates. F/ 15,446' to 15,344' (2 Stands) perform clean up cycle 1 BU due to Trq & Press spikes.
Dynamic losses 10-15 bph. Lost 70 bbls BROOH. Cont BROOH F/ 14,790' to 13,510' MD cont to work high trq and minor packing off. 500/450 GPM/ MPD
468/435 1,480/1,400 psi 120 RPM, TRQ 10-18k, ECD 10.59. Max Gas 540u. P/U 175k, SLK 35k, ROT 120k. MPD 100% open. Pull speed 5-20 ft/min as hole
dictates. F/ 13,926’ to 13,779’ and 13,563' to 13,510' MD adjust pull speed and pump rate due to erratic trq & Press spikes W/ minor packing off. Wipe through &
clean up spots as needed. Out of OBd sand F/ 14,043' to Fault #3 at 13,477' MD. Dynamic losses 20-30 bph loss rate. Lost 92 bbls. Daily disposal to G&I= 2533
bbls, total = 14293 bbls. Daily water from Lake-2 = 420 bbls, total = 10860 bbls. Daily Metal = 0 bbls, total = 20 bbls. Daily losses = 215 bbls, total = 369 bbls.
Surface loss 369 bbls.
1/1/2022 Cont BROOH F/ 13,510' to 12,291' MD cont to work high trq and minor packing off. 500 GPM/ MPD 475 GPM, 1,480 psi, 120 RPM, TRQ 9-17k, ECD 10.35. Max
Gas 337u. P/U 168k, SLK 35k, ROT 110k. MPD 100% open. Pull speed 1-30 ft/min as hole dictates. F/ 13,510’ to 13,438’ MD adjust pull speed and pump rate due
to erratic trq & press spikes W/ minor packing off. Pack-off & stall at 13,438', lower flow to 245 GPM, 830 PSI, 100 RPM, 20K & re-establish full circulation and
rotation. Wipe through & clean up spots as needed. Out of OBd sand F/ 14,043' to Fault #3 at 13,477' MD. Dynamic losses 10 bph loss rate. Lost 69 bbls. Cont
BROOH F/ 12,291' to 11,475' MD. 500 GPM/ MPD 475 GPM, 1,475 psi, 120 RPM, TRQ 9-16k, ECD 10.37. Max Gas 585u. P/U 160k, SLK 80k, ROT 105k. MPD
100% open. Pull speed 1-30 ft/min as hole dictates. Pull slow f/ 12,267’ t/ 12,178' MD and circulate a bottoms up prior to crossing fault #2 at 2'/min. Working torque
and pressure spikes f/ 11903’ t/ 11,853' MD. Fault #2 at 11853’. Rod wash pump failed on #2 MP, pull F/ 11690' T/ 11646' w/ 310 GPM, 700 GPM, 120 RPM,
13.5k TQ @ 2'/min. 7 BPH dynamic losses. Hydraulic hose on elevators cracked due to cold, remove hydraulic and install manual elevators before hose failed for
replacement. Cont BROOH F/ 11,475' to 9,600' MD. 500 GPM/ MPD 472 GPM, 1,380 psi, 120 RPM, TRQ 9-12k, ECD 10.22. Max Gas 572u. P/U 160k, SLK 88k,
ROT 108k. MPD 100% open. Pull speed 1-30 ft/min as hole dictates. No dynamic losses seen. Went out of zone at 9,043' MD encountered minor packing off F/
9,741' to 9,600' MD reduced pulling speed 1-4 ft min, no Trq issues. Crossed Fault #1 at 9,545' without issue. Cont BROOH F/ 9,600' to 7,077' MD. 500 GPM/
MPD 475 GPM, 1,220 psi, 120 RPM, TRQ 9.3k, ECD 9.95. Max Gas 267u. P/U 153k, SLK 93k, ROT 120k. MPD 100% open. Pull speed 20-30 ft/min as hole
dictates. No dynamic losses seen. CBU at 8,900' MD. Daily disposal to G&I= 288 bbls, total = 14581 bbls. Daily water from Lake-2 = 420 bbls, total = 11280 bbls.
Daily Metal = 6 bbls, total = 26 bbls. Daily losses = 215 bbls, total = 624 bbls. Surface loss 369 bbls.
1/2/2022 Continue to BROOH f/ 7,077' t/ 6442' MD. 500 GPM / MPD 475 GPM, 1,200 PSI, 120 RPM, TRQ 8K, ECD 9.89. Max Gas 231u. P/U 155K, SLK 95K, ROT 118.
MPD 100% open. Pull speed 20-30'/min as hole conditions allow. Pull slow f/ 7000' t/ 6875' to obtain a B/U before entering the shoe. Lower rotary to 60 RPM for
stabilizers entering the shoe. No drag or overpull observed. Pump 35 bbl high vis sweep. 530 GPM, 1320 PSI, 100 RPM, 7k TQ. Reciprocate f/ 6442' t/ 6379'.
Cuttings unloaded and observed 280u gas at 2500 stks into sweep displacement. No cuttings increase observed when sweep came back with 20u background gas.
Perform flow check - static. Close MPD chokes, monitor for 10 minutes - no pressure observed. Open chokes. PJSM. Blow down top drive & Sperry Geo-Span.
Remove MPD RCD and install trip nipple. POOH laying down 5" drill pipe f/ 6,442' t/ 405'. No swabbing on 1st two stand pulled, pumped dry job & blow down top
drive. P/U 150K, SLK 100K. Inspect hard band &remove selected joints for Category 5 inspection. 68.7 bbls hole fill for 95 stands, 15.5 bbls losses over calculated
for 3.1 BPH avg. RIH f/ 405' t/ 1990', 24 stands from 1st three fingers on drillers side to provide room for running liner. 41 bbls displacement, 3.8 bbls under
calculated for 2.5 BPH avg. losses. P/U 70K, SLK 66K. POOH L/D 5" D.P. F/ 1,990' to 405' MD. Max gas 16u. P/U 59k SLK 61k. Seeing ~3 bph static losses.
PJSM L/D 7 jnt 5" HWDP, jar, 2 ea NM FC & 2 ea FS. Down load MWD as per Sperry. Cont L/D Integral Blade (Minor wear), TM, DM, PWD, DGR, ILS (minor wear)
ADR, GeoPilot and 8.5" PDC Bit. Bit Grade 2-2-BT-A-X-I-CT-TD. Static loss rate 3 bph. Clean and clear rig floor of BHA components. PJSM Service rig. Grease
Blocks, Crown, service TD & Iron Roughneck. PJSM R/U Weatherford tools and Equip. Bring up 4.5" slips, 7" 220T elevators and handling Equip. C/O 5" elevators
to 4.5" YT. Stage 204 7.5" straight vein centralizers. R/U 9.625" EMGA power tongs and Trq Turn Equip. PJSM about floating 4.5" liner, well control and plan for
collapse or float failure. Incase of collapse have mud pump lined up on kill line to fill hole. Monitor string weight closely incase casing leaks. Use dog collars until
enough string weight is achieved (15k). Do not rattle stump. M/U 4.5" Shoe and check float, good, P/U M/U float collar and Float 4.5" 12.5# L-80 EZGO HTGT liner
to 970' MD. Trq turn connections. Had to kick out Jnt 5 due to 8k max Trq Yield and flared nose after breaking out and making up Jnt 5 shouldered at 4.3k & yeild
at 7k found flared nose. Made up Jnt 6 to frac sleeve 4.3k shoulder and max trq 6k. Talk to town and reduced Trq to 7k. During making up Jnt 13 shouldered at
2.1k and yield 6.2k. Attempted again and damaged both box and pin. L/D 12 & 13. Discussed with town and decision was made 3k shoulder minimum and 6k max.
P/U 40k SLK 37k Run speed 30 ft/min. Calc 15.5 bbls, actual 6.5 bbls, lost 9 bbls. Daily disposal to G&I= 116 bbls, total = 14697 bbls. Daily water from Lake-2 =
280 bbls, total = 11560 bbls. Daily Metal = 0 bbls, total = 26 bbls. Daily losses = 16 bbls, total = 640 bbls. Surface loss 369 bbls.
1/3/2022 Cont floating 4.5" 12.5# L-80 EZGO HTGT liner f/ 970' t/ 2078' with Weatherford Torque Turn. M/U parameters of 3K ft/lbs minimum shoulder and 6K ft/lbs MU
torque. Multiple joints shouldered 1.8-2K, retorque 2-3 times then M/U good. Multiple joints shoulder at 2.8K w/ no debris or damage observed, acceptable to 3K
shoulder. Jt #44 & 45 low shoulder of 1.8-2K three times. Inspect connection, observe flare of pin, L/D & C/O joints. P/U 43K, S/O 42K. 1.5 BPH losses. Source
replacement collars for Northern Solutions. Their machine shop found collars on re-run pipe seated too deep. Had to back off to 1/2 of collar length then make
connection. Measure joints in pipe shed, I.D. & back-off 1/2 to 3/4 turn on rig floor before final M/U. Cont floating 4.5" 12.5# L-80 EZGO HTGT liner f/ 2078' t/ 4505'
with Weatherford Torque Turn. Joints #67 & 76 did not shoulder above 2.5K. C/O pin end joint & M/U fine. Multiple joints shouldered at 2.2K with no damage to
threads observed after backing out. Consult engineer and lower min shoulder TQ to 2K & 6K MU torque. Approximately 20% of joints shoulder less than 2K, back
out then re-torque good. 1 BPH losses. Float 4.5" 12.5# L-80 EZGO HTGT liner F/ 4,505' to 7,745' MD as per tally with Weatherford Torque Turn shoulder 2k & 6k
max. Checking all Frac sleeves to insure closed position. At 6,470' MD obtain P/U 60k SLK 51k prior to going into open hole. Run speed 50 ft/min. In open hole 30-
40 ft/min. Check to ensure Frac Sleeves are closed. P/U 64k SLK 51k. Calc disp 60 bbls, actual 55 bbls lost 5. Float 4.5" 12.5# L-80 EZGO HTGT liner F/ 7,745' to
10,690' MD as per tally with Weatherford Torque Turn shoulder 2k & 6k max. Checking all Frac sleeves to insure closed position. Run speed in open hole 35 ft/min.
At Fault #1 9,545' MD no change. Reenter OBd at 9,943'. Kicked out Jnt 266 no shoulder. M/U AirLock G W/ 3.5k shear disk. P/U 69k SLK 49k. Calc Disp 52 bbls,
actual 49.9 bbls lost 2.8 bbls. Daily disposal to G&I= 0 bbls, total = 14697 bbls. Daily water from Lake-2 = 80 bbls, total = 11640 bbls. Daily Metal = 0 bbls, total =
26 bbls. Daily losses = 13 bbls, total = 653 bbls. Surface loss 369 bbls.
1/4/2022 Fill 4.5" joint above AirLock sub and verify burst disk holding fluid - good. M/U 5" drill pipe safety joint with FOSV and large head lift sub for 7" elevators. C/O
elevators, slips & tong heads from 4.5" to 7". Run 7" 26# L-80 H-563 liner f/ 10,690' t/ 11,699'. Torque turn connections to 9,400 ft/lbs. Fill pipe on the fly & top over
every 5 joints w/ 9.3 ppg QuikDrill. 86k PU, 62k SO. 35'/min running speed. Out of zone from 11,641' to 12,137' with fault #2 at 11,853'. Losses 1.25 BPH avg.
Change elevators and P/U Baker 7"x9-5/8" SLZXP liner top hanger packer to 11,736'. RIH w/ liner on 5" drill pipe to 11,786' where the liner took all the weight, set
down 4 times. Establish rotation to obtain parameters: 5 RPM= 4.4k, 10 RPM=4.8k, 15 RPM=5k. 95k PU, 67K SO, 74K ROT. 1.25 BPH avg. Work liner past
11,786'. Attempt 5 to 15 RPM, set down the same spot 3 times. Attempt to work down with no rotation up to 30' per minute, set down at same spot. Establish rotation
and work liner past 11,786'. Continue to float 4-1/2" x 7" liner on 5" drill pipe from 11,786' to 17,186', tagging bottom on depth. Fill pipe on the fly and top off every 5
stands. No problems observed from fault #3 at 13477' to back in zone at 13805'. 170k PU, 93k SO. 1.75 BPH losses. Space out - Rack back stand to 17,141'. P/U
9.58' & 4.60' pup joints and 31.90' joint. M/U pump in sub, FOSV & top drive. Place on set depth 5' off bottom at 17,181' with string in tension. R/U hoses to
circulate / fill pipe. Pressure up to burst AirLock disk (3500 PSI) at 6532' MD / 4768' TVD with 9.3 ppg QuickDril (2306 PSI hydrostatic). Pump 0.5 BPM and
observe disk rupture at 1175 PSI. Pump 8 bbls at 5 BPM, 24 PSI as per NCS AirLock procedure. Wait 30 to allow fluid to swap. PJSM Line up TT for continuous
hole fill monitoring. R/U HP hose F/ mud manifold, Lo Trq, Tee W/ Lo Trq, Lo Trq HP hose to side entry sub on stump. M/U Head pin to FOSCV, swing, Lo Trq HP
hose, Lo Trq W/ Tee to beneath bleeder valve. Use charge pump on MP #1 W/ pump bleeder open to prevent dead heading charge pump while filling liner. Use Lo
Trq on rig floor to regulate rate. Fill liner at 3/4-1 bpm for 63 bbls and vent for 30 min, pump 50 bbls . Static loss rate 1-3 bph. PJSM Vent liner for 30 min. Cont
pumping at ~3/4 bpm for 30 bbls (total 145.1 bbls) caught fluid. Cont topping off additional 11 bbls catching venting to TT gain 8.65 bbls in TT. Able to get 2.27
more bbls in liner. Total to fill 147.4 bbls, Calc 162 bbls, short 14.6 bbls. Liner string topped off. PJMS R/D HP lines, Lo Trqs, FOSV, Side Entry Sub & Head Pin.
Cicr set packerPJSM Break Circ at 2 bpm 305 psi confirm liner fluid packed. Drop 1” Phenolic Ball pump down at 3 bpm 495 psi. Caught Press at 1,183 stks (73.4
bbl) Calc 1,548 stks (95.9 bbls). Press up 1 bpm to 3,000 psi. Did not definitively see packer set. Increased to 3,200 psi & hold. Set down 36k and check packer set.
P/U to neutral WT 113k. Cont to bring Press up to 3,800, 4,000, 4,200 psi W/ no indication of neutralizer engaging. ITTS sheared at 4,240 psi. Bled off Press.
Attempt to release form packer P/U to 170k. Worked F/ 1,500 ft/lb to 5,200 ft/lb trq down string in ½ left hand hand turns to mechanically release from packer. Broke
over 140k P/U.. TOL at 5,457’ MD. PJSM R/U test Equip. Fluid choke, kill and manifold purging air out. Perform SLZXP test to 1,500 psi for 10 min on chart.
Pumped 2.0 bbls, bled 1.9 bbls. R/D test Equip. P/U breaking Circ at 1 bpm 113 psi cleared seals and increased to 6 bpm 420 psi . POOH to 5,434’ MD. L/D
Working jnt, 5’ & 10’ Pup. Daily disposal to G&I= 57 bbls, total = 14754 bbls. Daily water from Lake-2 = 100 bbls, total = 11740 bbls. Daily Metal = 0 bbls, total = 26
bbls. Daily losses = 23 bbls, total = 676 bbls. Surface loss 369 bbls.
Perform SLZXP test to 1,500 psi for 10 min on chart.
Place on set depth 5' off bottom at 17,181' with string in tension.
Activity Date Ops Summary
1/5/2022 Pump 40 bbl high vis sweep to clean the 9-5/8" casing. 6 BPM, 430 PSI. No cuttings observed during circulation or with sweep back to surface - clean. Blow down
choke manifold.,Monitor well, static. POOH laying down drill pipe and SLZXP running tool. Cull pipe as per Cat 5 and hard band inspection. Liner running tool
showed no HRD activation,M/U Johnny whacker and RIH on elevators with excess drill pipe from derrick to 4851'. PUW 124K, SOW 99K. Actual displacement
35.8 bbls, Calc 41.4 bbls.,Cut and slip drilling line. Check brake tolerance, calibrate block height.,Service rig: grease crown, TD, spinners, check rotary oil level -
good. Grease IBOP, replace batteries in racking board saver.,Monitor well, 1.3 bph static loss rate. Pump dry job. POOH laying down drill pipe from 4,851' to
surface.,Drain stack, Pull wear bushing.,Close blind rams. Bleed down accumulator. C/O UPR's to 7" SB.,P/U 7" test joint. M/U and set test plug. M/U head pin
and test hose. Flood lines. Test UPR's on 7" test joint 250/3000 psi - good. R/D testing equipment. Pull test joint. Pull test plug.,Clear floor of 4.5" handling
equipment. Rig up 7" tools, install elevators.,M/U Baker Bullet seal. RIH with 7", 26#, L-80, DWC tie-back string to 2239'. PUW 69K, SOW 66K,Daily disposal to
G&I= 490 bbls, total = 15244 bbls. Daily water from Lake-2 = 60bbls, total = 11800bbls. Daily Metal = 0 bbls, total = 26 bbls. Daily losses = 40bbls, total = 716bbls.
Surface loss 369 bbls.
1/6/2022 Continue RIH with 7", 26#, L-80, DWC tie-back string from 2239' to 5430' MD. PUW 155K, SOW 110K. Remove air slips. M/U tag jts 135 and 136. Tag up @
5470' MD w/ 13k set down (2x). Saw 3-5k seal drag. Calculate spaceout (1.36'. off no/go) L/D tag jts 135 & 136. B/O jt 134 and M/U 3.83' pup below jt 134. M/U
hanger assy w/ landing jt. RIH and landout on depth (75k on hanger). Reduce annular psi to 500 psi. R/U to reverse circulate. Psi up 150 on annulus and strip up
to locate circ ports on seal assy +1 ft.,Reverse circulate well over to clean 9.1 corrosion inhibited brine down 9-5/8" x 7" annulus. 6 bpm, 195 psi (pumped 400 bbls
total). R/U LRS. Pump 57 bbls diesel down OA @ 1.6 bpm, 260 FCP. F/P @ 2280' MD. R/D circulating equipment.,Strip 7" tieback down and landout on depth
1.36' off No/Go (5469' MD). 75k on hanger. L/D landing jt. M/U running tool and packoff assy. Install packoff and test void 3k (test good).,Test 9-5/8" x 7" OA to
1500 psi w/ 30 min hold (test good). Chart and record same 1.6 bbl in / 1.7 bbl out,Clean and clear rig floor. C/O elevators to 4.5". rig up power tongs and TQ turn.
Verify pipe count/jewelry. Check OD's, ID's and mandrill elevators/slips.,RIH with 4-1/2", 12.6#, L-80, VAM top completion as per detail to 4560'. Bakerlok all
connections below packer. Verify 6 shear screws on packer. TQ turn connections to 4400 ft-lbs. PUW 76K, SOW 65K.,Cont. to RIH with 4-1/2", 12.6#, L-80, VAM
top completion as per detail from 4560' to 5734'. TQ turn connections to 4400 ft-lbs. PUW 93K, SOW 74K.,C/O elevators to 5". P/U landing joint, M/U XO to TCII.
M/U hanger. Land tubing at 5757'. RILDS. 39K on hanger. Pull mouse hole, R/U 1502 components to landing joint. Pump 10 bbls down tubing to verify clear at 2
bpm, 43 psi. Remove headpin and drop 1.875" ball and rod (top roller missing).,Allow ball and rod to fall while rigging up testing equipment, side entry sub, TIW,
high pressure hose to tubing, high pressure hose to IA with isolation valves. Pressure up tubing to 3600 psi, observe slight indication of packer set at 1600 psi.
Hold pressure and MIT-T to 3500 for 30 minutes (initial 3600 psi, 15 min 3550, 30 min 3525) - good. Bleed tubing down to 2000 psi.,MIT-IA to 3500 psi for 30
minutes (initial 3706 psi, 15 min 3636 psi, 30 min 3624 psi) - good. Witness waived by AOGCC rep Austin Mcleod. Bleed pressure on tubing. Observe GLM valve
shear at ~2500 psi differential pressure. Pumped total 3.2 bbls for testing, bled back 3.2 bbls. Reverse circulate through GLM to ensure communication.,Daily
disposal to G&I= 741 bbls, total = 15,985 bbls. Daily water from Lake-2 = 40bbls, total = 11,840bbls. Daily Metal = 0 bbls, total = 26 bbls. Daily losses = 8bbls, total
= 724bbls. Surface loss 369 bbls.
1/7/2022 R/D circ equipment from IA and tbg, B/D lines. L/D landing joint. R/D Weatherford casing equipment and demob from floor.,Install TWC, Flush surface equipment
and F/D same. N/D RCD head, choke and kill lines. N/D drip pan, riser and 4 pt. Sym Ops - B/D surface lines in pits. Clean pits and prep fluid end mud pumps for
inspection and upcoming rig move.,Bleed down koomey unit and isolate same. C/O upper pipe rams to 2-7/8" x 5-1/2" VBR's. Inspect cavities (good). Close doors
and tighten same. Hook up to RCD w/ test cap. N/D and remove from BOP's. N/D DSA and set BOP's on pedestal.,Install cross chains and M/U studs to secure
BOP to pedastal. Set RCD on ground. Remove DSA. Clean, lube and bag all rig grooves.,Assist wellhead with prep wellhead. N/U tree. Test tubing hanger void
500/5000 - good. Test tree 250/5000 - good. Sim Ops: Remove rig tongs, bridal up for scoping. Cont. cleaning pits. Finish processing drill pipe in shed. Install
shipping pin on iron roughneck. Prep rig floor.,Pull TWC. Spot vac truck and LRS. R/U and freeze protect well with Little Red Services: Pump 78 bbls diesel ICP
200 psi at 1bpm, final 1000 psi at 2 bpm. R/D LRS. Sim Ops: Cont. cleaning mud pits, cont with mud pump inspection. Prep stairs, landings and rooftops for rig
move.,Scope down derrick. Finish mud pump inspection, C/O total 4 valve/seats. Clean out flow line. Finish cleaning mud pits.Clean cellar box and secure cellar
for move. Disconnect interconnect lines at pits/mezzanine. Work on rig move checklist. Clean out vac unit. Daily disposal to G&I= 461 bbls, total = 16,446 bbls.
Daily water from Lake-2 = 130bbls, total = 11,970bbls. Daily Metal = 0 bbls, total = 26 bbls. Daily losses = 5 bbls, total = 729bbls. Surface loss 369 bbls.
1/8/2022 Assemble fluid ends on mud pumps. Turn stompers to prep to walk off well. Empty and clean out vac unit. B/D cutting box steam loop and disconnect hoses.
Prep break shack to move. Flip up roof caps. Dig out and start portable welding machine.,NES rig move trucks unavailable due to another rig move. Wait on
trucks. Unplug and move break shack. Assist welder with skate wing repair. Remove suction dampener on mud pump 1. Inspect and re-install. Clean suction
manifolds on mud pumps. Final Report for PBU Z-221. RDMO 06:00. Daily disposal to G&I= 461 bbls, total = 16,446 bbls. Daily water from Lake-2 = 130bbls, total
= 11,970bbls. Daily Metal = 0 bbls, total = 26 bbls. Daily losses = 5 bbls, total = 729bbls. Surface loss 369 bbls.
50-029-23704-00-00API #:
Well Name:
Field:
County/State:
PBW Z-221
Prudhoe Bay West
Hilcorp Energy Company Composite Report
, Alaska
,Test 9-5/8" x 7" OA to
1500 psi w/ 30 min hold (test good).
psi.,MIT-IA to 3500 psi for 30
minutes (initial 3706 psi, 15 min 3636 psi, 30 min 3624 psi) - good.
MIT-T to 3500 for 30 minutes (initial 3600 psi, 15 min 3550, 30 min 3525) - good.
TD Shoe Depth: PBTD:
No. Jts. Returned
RKB RKB to BHF RKB to THF
Jts.
1
2
99
54
X Yes No X Yes No 4.3
Fluid Description:
Liner hanger Info (Make/Model): Liner top Packer?: Yes No
Liner hanger test pressure:X Yes No
Centralizer Placement:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:Yes No
Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job
Cement returns to surface? Yes X No Spacer returns?Yes X No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:Yes No
Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job
Cement returns to surface? Yes X No Spacer returns?Yes X 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
Shoe
9.625" Csg
RKB
10
89162SECOND STAGEHES
10:30
Returns to Surface
Rotate Csg Recip Csg Ft. Min. PPG9.5
Shoe @ 6474 FC @ Top of Liner6,390.00
Floats Held
30 310
221 89
H2O
CASING RECORD
County State Alaska Supv.J Lott / C Montague
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.PBW Z-221 Date Run 21-Dec-21
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
TXP BTC Innovex 1.75 6,474.00 6,472.25
2,197.62 2,222.96
25.34
9 5/8 87.0 L-80 Vam21
Csg Wt. On Hook:280,000 Type Float Collar:Standard No. Hrs to Run:25.5
8.34 6.5
0
10.5
10.7 254 4.75
100
672
Bump Plug?FIRST STAGE10Tuned Spacer 55.4
15.8
495
4.7
8.34 6.5 20/20
20/20
50
HES
15.8 84.3
Bump press
Circulated Returns off top of Stage Tool
Bump Plug?
Y
0:20 12/22/2021 Stage Tool
2282.5
6,474.006,483.00
CEMENTING REPORT
Csg Wt. On Slips:40,000
Spud Mud
Tuned Spacer
461 2.88
Stage Collar @
60
Bump press
100
221
ES Closure OK
56
12 223
26.56 RKB to CHF
Type of Shoe:Standard Casing Crew:Weatherford
No. Jts. Delivered 170 No. Jts. Run 158 12
Length Measurements W/O
Threads
Ftg. Delivered 6,970.00 Ftg. Run 6,474.00 Ftg. Returned 496.00
Ftg. Cut Jt.28.29 Ftg. Balance
www.wellez.net WellEz Information Management LLC ver_04818br
3.8
Perm L
Type
1 ea Bow Spring centralizer 2 ea stop ring on shoe track (3) Bow Springs on Jnts 4-25, every other F/ 28-70. 6 below
6 above ES, every third jnt F/111-153. Total 74 BS 8 SR.
9.625" Csg 9 5/8 40.0 L-80 TXP BTC 80.69 6,472.25 6,391.56
FC 10 TXP BTC Halliburton 1.45 6,391.56 6,390.11
9.625" Csg 9 5/8 40.0 L-80 TXP BTC 39.52 6,390.11 6,350.59
Baffle Adapter 10 TXP BTC Halliburton 1.43 6,350.59 6,349.16
9.625" Csg 9 5/8 40.0 L-80 TXP BTC 4,044.54 6,349.16 2,304.62
Pup Jnt 9 5/8 40.0 L-80 TXP BTC 19.21 2,304.62 2,285.41
ES Cementer 10 TXP BTC Halliburton 2.82 2,285.41 2,282.59
Pup Jnt 9 5/8 40.0 L-80 TXP BTC 18.50 2,282.59 2,264.09
9.625" Csg X/O 9 5/8 47.0 L-80 Vam21 41.13 2,264.09 2,222.96
EconoCem Type I/ II 537 2.35
HelCem Type I/ II 400 1.16
4.3
Premium G 267 1.17
12/23/2021 Surface
H2O
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Chelsea Wright Digitally signed by Chelsea Wright
Date: 2022.01.04 09:02:22 -09'00'Benjamin Hand Digitally signed by Benjamin Hand
Date: 2022.01.04 09:36:11 -09'00'
David Douglas Hilcorp Alaska, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Hilcorp North Slope, LLC
Date: 01/14/2022
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
PBU Z-221 (PTD 221-095)
FINAL LWD FORMATION EVALUATION LOGS (12/17/2021 to 12/31/2021)
x ROP, AGR, DGR, ABG, EWR-M5, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
x Geosteering and EOW Report
SFTP Transfer – Main Folders:
LWD Subfolder:
Geosteering Subfolder: g
Please include current contact information if different from above.
Received By:
01/20/2022
37'
(6HW
By Abby Bell at 10:19 am, Jan 20, 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: 01/14/2022
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
PBU Z-221 (PTD 221-095)
FINAL LWD FORMATION EVALUATION LOGS (12/17/2021 to 12/31/2021)
x ROP, AGR, DGR, ABG, EWR-M5, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
x Geosteering and EOW Report
SFTP Transfer – Main Folders:
LWD Subfolder:
Geosteering Subfolder: g
Please include current contact information if different from above.
Received By:
01/20/2022
37'
(6HW
By Abby Bell at 10:19 am, Jan 20, 2022
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, Pt. McIntyre Oil Pool, PBU Z-221
Hilcorp North Slope, LLC
Permit to Drill Number: 221-095
Surface Location: 4295' FSL, 2802' FEL, Sec. 19, T11N, R12E, UM, AK
Bottomhole Location: 1641' FNL, 749' FWL, Sec. 08, T11N, R12E, 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 AOGCC within 90 days after completion, suspension or abandonment
of this well.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Jessie L. Chmielowski
Commissioner
DATED this ___ day of November, 2021. 23
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2021.11.23 14:33:38
-09'00'
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: 18,240' TVD: 4,513'
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): 82.9' 15. Distance to Nearest Well Open
Surface: x-599876 y- 5959100 Zone- 4 56.4' to Same Pool: 520'
16. Deviated wells: Kickoff depth: 500 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 128 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
42" 20"x34" 215.5# A-53 136' Surface Surface 136' 136'
47# L-80 Vam21 2,500' Surface Surface 2,500' 2,184'
40# L-80 BTC 3,777' 2,500' 2,184' 6,277' 4,748'
Tieback 7" 26# L-80 DWCC 5,550' Surface Surface 5,500' 4,612'
8-1/2" 4-1/2" 13.5# L-80 EzGoHTGT 11,424' 5,550' 4,612' 16,974' 4,913'
19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations)
Junk (measured):
TVD
Hydraulic Fracture planned? Yes No
20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis
Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements
Contact Name: Joe 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
December 10, 2021
8.394'
12-1/4" 9-5/8"
21. I hereby certify that the foregoing is true and the procedure approved herein will not be
deviated from without prior written approval.
Surface
Perforation Depth TVD (ft):
GL / BF Elevation above MSL (ft):
Perforation Depth MD (ft):
Tieback Liner
Uncemented Sliding Sleeves
Effect. Depth MD (ft): Effect. Depth TVD (ft):
Authorized Title:
Authorized Signature:
Production
Liner
Intermediate
Authorized Name:
Conductor/Structural
LengthCasing Cement Volume MDSize
Plugs (measured):
(including stage data)
17 yds Concrete
Stg 1 L - 1130 ft3 / T - 458 ft3
4949
18. Casing Program: Top - Setting Depth - BottomSpecifications
2087
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
Stg 2 L - 2527 ft3 / T - 313 ft3
1614
2255' FNL, 1872' FEL, Sec. 19, T11N, R12E, UM, AK
1641' FNL, 749' FWL, Sec. 08, T11N, R12E, UM, AK
85-009
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
Hilcorp North Slope, LLC
4295' FSL, 2802' FEL, Sec. 19, T11N, R12E, UM, AK ADL 028262 & 047450
PBU Z-221
Prudhoe Bay Field
Schrader Bluff Oil Pool,
Orion Development Area
Cement Quantity, c.f. or sacks
Commission Use Only
See cover letter for other
requirements.
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
11.12.2021
By Meredith Guhl at 4:14 pm, Nov 12, 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: 2021.11.12 15:41:54 -09'00'
Monty M
Myers
X
X
BOPE test to 3000 psi. Annular to 2500 psi.
Variance to 20AAC25.285(c)(2)(B)(i). Approved as production packer
will be 138' TVD deeper than the OBa reservoir, well below
the SB confining zones.
MGR21NOV21
221-095
DLB 11/16/2021 DSR-11/12/21
1614
X X
X
X
50-029-23704-00-00
dts 11/23/2021
11/23/21
11/23/21Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski
Date: 2021.11.23 14:34:55 -09'00'
87
171813
201924
CHEV181112
HIGHLANDST
K071112PB1
Z-01
Z-02
Z-03
Z-04
Z-05
Z-06
Z-07
Z-08
Z-09
Z-10
Z-100
Z-101
Z-102
Z-103
Z-108
Z-11
Z-112PB1
Z-113PB1
Z-114
Z-115
Z-116
Z-12
Z-13
Z-14
Z-15
Z-16
Z-17
Z-18
Z-19
Z-19A
Z-20
Z-21
Z-210
Z-210PB1
Z-22
Z-23
Z-24
Z-25 Z-26
Z-27
Z-28
Z-29
Z-30
Z-31
Z-32
Z-33
Z-34
Z-35
Z-35PB1
Z-38
Z-38PB1
Z-39
Z-40
Z-46
Z-46A
Z-50
Z-61
Z-65
Z-66
Z-67 Z-68
Z-69
Z-70
Z-71
Z-221_prop_wp02
HILCORP NORTH SLOPE
Greater Prudhoe Bay
AOR MAP
Z-221 Injector (Proposed)
FEET
0 1,000 2,000
POSTED WELL DATA
Well Label
WELL SYMBOLS
Location
Shut In Oil
INJ Well (Water Flood)
Abandoned Injector
P&A Oil/Gas
J&A
Temporarily Abandoned
Active Oil
Injector Location
REMARKS
Well symbols at top of Schrader Bluff OBd sand (target
sand of proposed Z-221 well). Black Dashed circle and
lines = 1320' radius from heel to toe of proposed Z-221
lateral.
August 12, 2021
PETRA 8/12/2021 4:26:16 PM
Well Name PTD API Status
Top of Oil Pool (SB
OBd, MD)
Top of Oil Pool
(SB OBd, TVD)
Top of class G Cmt
(MD)Top of Cmt (TVD)Zonal
Isolation Comments
Z-03 210-010 50-029-22787-00-00 Offline Producer 5014' 4695' 3090' 3067'Closed 2008 USIT found TOC @ 3090'
MD
Z-11 190-072 50-029-22053-00-00 P&A'd 4913'4694'3007'3006'P&A'd P&A'd
Z-11A 205-031 50-029-22053-01-00 Online Producer 4913' 4694'3007' 3006' Closed
2021 USIT found TOC @ 3007'
MD
Z-15 215-025 50-029-21849-00-00 Online Producer 5861' 4791' 2110' 2080'Closed
OA downsqueeze was
performed that left TOC in the
9-5/8" annulus at 2110'
The primary cement job
cemented the 9-5/8" casing
that had been landed at 8087'
with 2036 cu ft of Class G
cement in a 12-1/4" hole. This
puts calculated TOC @ 1586'
MD
Z-20 188-100 50-029-21859-00-00 Online Producer 5043' 4765' ~4550' ~4391' Closed
9-5/8" casing set in 12/1-4"
hole at 10,711' and cemented
with 2243 cu ft of Class G
cement, calculated TOC is at
~4500' MD
Z-34 212-061 50-029-23469-00-00 Offline Producer 4925' 4735' ~3613' ~3567' Closed
7" casing set in 8-3/4" hole at
10176' and cemented with 662
sx LiteCrete and 196 sx of Class
G, calculate4d TOC is at ~3613'
MD
Z-39 200-208 50-029-22995-00-00 P&A'd 5000'4736'~4152'~3973'N/A P&A'd
Z-39A 204-224 50-029-22995-01-00 Offline Producer 5000' 4736' ~4152' ~3973' Closed
7" casing set in 8-3/4" hole at
9273' and cemented with 351
sx LiteCrete and 100 sx of Class
G, calculated TOC is at ~4152'
MD
Z-40 211-173 50-029-23462-00-00 Online Producer 4960' 4709' 3968' 3471' Closed
2012 USIT found TOC @ 3968'
MD
Z-68 213-093 50-029-23493-00-00
Not Operable
(OA NFT failed)5047' 4762' 3970' 3815' Closed
2013 USIT found TOC @ 3970'
MD
Z-71 213-025 50-029-23484-00-00 Offline Producer 5800' 4791' ~1411' ~1393' Closed
7" casing set in 8-3/4" hole at
10902' and cemented with 703
sx LiteCrete and 102 sx Class G,
calculated TOC is at ~1411' MD
Z-103 204-229 50-029-23235-00-00
Online WAG
Injector 4942' 4715' ~4038' ~3864' Closed
7" casing set in 8-3/4" hole at
6998' and cemented with 406
sx Class G, calculated TOC is at
~4038' MD
Z-112 207-172 50-029-23380-00-00 Online Producer 5319' 4943' ~3326' ~3124' Closed
7" casing set in 8-3/4" hole at
7713' and cemented with 242
sx LiteCrete and 179 sx Class G,
calculated ToC is at ~3326' MD
Z-112PB1 207-172 50-029-23380-70-00 Plugback 5319' 4943' ~3326' ~3124' Closed
7" casing set in 8-3/4" hole at
7713' and cemented with 242
sx LiteCrete and 179 sx Class G,
calculated ToC is at ~3326' MD
Z-210 204-181 50-029-23226-00-00
Not Operable
Injector 7473' 4902' 4810' 3499' Closed
2004 USIT found TOC @ 4810'
MD
Z-210PB1 204-181 50-029-23226-70-00 Plugback 7473' 4902' 4810' 3499' Closed
2004 USIT found TOC @ 4810'
MD
Area of Review PBU Z-221
Prudhoe Bay West
(PBU) Z-221
Drilling Program
Version 1
11/3/2021
Table of Contents
1.0 Well Summary ........................................................................................................................... 2
2.0 Management of Change Information ........................................................................................ 3
3.0 Tubular Program:...................................................................................................................... 4
4.0 Drill Pipe Information: .............................................................................................................. 4
5.0 Internal Reporting Requirements ............................................................................................. 5
6.0 Planned Wellbore Schematic ..................................................................................................... 6
7.0 Drilling / Completion Summary ................................................................................................ 7
8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 8
9.0 R/U and Preparatory Work ..................................................................................................... 11
10.0 N/U 13-5/8” 5M Diverter System ............................................................................................. 12
11.0 Drill 12-1/4” Hole Section ........................................................................................................ 14
12.0 Run 9-5/8” Surface Casing ...................................................................................................... 17
13.0 Cement 9-5/8” Surface Casing ................................................................................................. 22
14.0 ND Diverter, NU BOPE, & Test .............................................................................................. 27
15.0 Drill 8-1/2” Hole Section .......................................................................................................... 28
16.0 Run 4-1/2” Injection Liner ...................................................................................................... 33
17.0 Run 7” Tieback - connections .................................................................................................. 37
18.0 Run Upper Completion/ Post Rig Work ................................................................................. 40
19.0 Innovation Rig Diverter Schematic ......................................................................................... 42
20.0 Innovation Rig BOP Schematic ............................................................................................... 43
21.0 Wellhead Schematic ................................................................................................................. 44
22.0 Days Vs Depth .......................................................................................................................... 45
23.0 Formation Tops & Information............................................................................................... 46
24.0 Anticipated Drilling Hazards .................................................................................................. 48
25.0 Innovation Rig Layout ............................................................................................................. 52
26.0 FIT Procedure .......................................................................................................................... 53
27.0 Innovation Rig Choke Manifold Schematic ............................................................................ 54
28.0 Casing Design ........................................................................................................................... 55
29.0 8-1/2” Hole Section MASP ....................................................................................................... 56
30.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 57
31.0 Surface Plat (As Built) (NAD 27) ............................................................................................. 58
32.0 Offset Wells TVD MW............................................................................................................. 59
Page 2
Prudhoe Bay West
Z-221 SB Injector
Drilling Procedure
1.0 Well Summary
Well PBU Z-221
Pad Prudhoe Bay Z Pad
Planned Completion Type 4-1/2” Injection
Target Reservoir(s) Schrader Bluff OBd Sand
Planned Well TD, MD / TVD 18,240’ MD / 4,512’ TVD
PBTD, MD / TVD 16,974 MD / 4,912’ TVD
Surface Location (Governmental) 4295' FSL, 2802' FEL, Sec 19, T11N, R12E, UM, AK
Surface Location (NAD 27) X= 599876, Y=5959100
Top of Productive Horizon
(Governmental)2255' FNL, 1872' FEL, Sec 19, T11N, R12E, UM, AK
TPH Location (NAD 27) X=600827, Y= 5957842
BHL (Governmental) 1641' FNL, 749' FWL, Sec 8, T11N, R12E, UM, AK
BHL (NAD 27) X= 603255, Y=5969049
AFE Number 211-00052
AFE Drilling Days 21
AFE Completion Days 4
Maximum Anticipated Pressure
(Surface) 1614 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 2087 psig
Work String 5” 19.5# S-135 NC 50
Innovation KB Elevation above MSL: 26.5 ft + 56.4 ft = 82.9 ft
GL Elevation above MSL: 56.4 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
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Drilling Procedure
2.0 Management of Change Information
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3.0 Tubular Program:
Hole
Section
OD (in)ID
(in)
Drift
(in)
Conn OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 20” 19.25”---X-52Weld
12-1/4”9-5/8” 8.835”8.679”10.625”40 L-80 BTC 5,750 3,090 916
9-5/8” 8.681”8.525”10.625”47 L-80 VAM 21 6,870 4,750 1,086
Tieback 7” 6.276 6.151 7.565 26 L-80 DWC SR 7,240 5,410 604
8-1/2” 4-1/2” 3.96 3.833 5 12.7 L-80
EZGO
HTGT 8,431 7,500 288
Tubing 4-1/2” 3.958 3.833 4.937 12.6 L-80 VAMTOP 8,430 7,500 288
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)
Surface &
Production
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
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
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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 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 Wyatt Rivard 907.777.8547 509.670.8001 wrivard@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 Laura Green 907.777.8314 907.342.7511 lagreen@hilcorp.com
Drilling Tech Joe Lastufka 907.777.8400 907.227.8496 Joseph.Lastufka@hilcorp.com
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Drilling Procedure
6.0 Planned Wellbore Schematic
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7.0 Drilling / Completion Summary
PBU Z-221 is a grassroots injector planned to be drilled in the Schrader Bluff OBd sands. Z-221 is part of a
multi-well program targeting the Schrader Bluff sand on PBU Z-pad
The directional plan is 12-1/4” surface hole and 9-5/8” surface casing set into the top of the Schrader Bluff
OBd sand. An 8-1/2” lateral section will be drilled. A 4-1/2” liner will be run in the open hole section,
followed by a 7” tieback and 4-1/2”injection tubing.
The Innovation Rig will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately Dec 10, 2021, pending rig schedule.
Surface casing will be run to 6,277’ MD / 4,748’ TVD and cemented to surface via a 2 stage primary cement
job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed,
necessary remedial action will then be discussed with AOGCC authorities.
All cuttings & mud generated during drilling operations will be hauled to 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” Diverter and 16” diverter line
3. Drill 12-1/4” hole to TD of surface hole section. Run and cement 9-5/8” surface casing
4. N/D diverter, N/U wellhead, NU 13-5/8” 5M BOP & Test
5. Drill 8-1/2” lateral to well TD
6. Run 4-1/2” production liner
7. Run 7” tieback
8. Run Upper Completion
9. N/D BOP, N/U Tree, RDMO
Reservoir Evaluation Plan:
1. Surface hole: No mud logging. Remote geologist. LWD: GR + Res
2. Production Hole: No mud logging. Remote geologist. LWD: GR + ADR (For geo-steering)
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8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations,
specific regulations are listed below. If additional clarity or guidance is required on how to comply with
a specific regulation, do not hesitate to contact the Anchorage Drilling Team.
x BOPs shall be tested at (2) week intervals during the drilling and completion of PBU Z-221. 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)”.
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AOGCC Regulation Variance Requests:
Hilcorp would like to request a variance from 20 AAC 25.412.(b) which states:
“A well used for injection must be equipped with tubing and a packer, or with other equipment that isolates
pressure to the injection interval, unless the commission approves the operator's use of alternate means to ensure
that injection of fluid is limited to the injection zone. The minimum burst pressure of the tubing must exceed the
maximum surface injection pressure by at least 25 percent. The packer must be placed within 200 feet measured
depth above the top of the perforations, unless the commission approves a different placement depth as the
commission considers appropriate given the thickness and depth of the confining zone.”
In order to effectively produce this fault block, the current wellplan has the surface casing shoe landing in the
OBd production interval at 85 degrees inclination. In order to make the ball and rod we land to set the production
packer slickline accessible, the X nipple in the tubing tail must be landed at less than 70 degrees inclination. The
MD we currently have planned for 70 degrees is at ~5600’ MD. The production packer will be ~60’ MD above
the X nipple which puts it at ~5540’ MD. The surface casing shoe is planned at 6277’ MD which means the
planned packer depth is 737’ MD away.
From a TVD standpoint, the production tubing packer is ~138’ TVD from the surface casing shoe and is deeper
than the top of the Oba reservoir located in the same Orion oil pool. With the surface casing set in the Schrader
Bluff sand, and the injection packer set inside the surface casing, injection fluids will be confined to the Schrader
bluff sands.
q
m 20 AAC 25.412.(b) w
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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)
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9.0 R/U and Preparatory Work
9.1 Z-221 will utilize a 20” conductor on Z-pad. Ensure to review attached surface plat and make
sure rig is over appropriate conductor.
9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor.
9.3 Install landing ring.
9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each.
9.5 Level pad and ensure enough room for layout of rig footprint and R/U.
9.6 Rig mat footprint of rig.
9.7 MIRU Innovation. Ensure rig is centered over conductor to prevent any wear to BOPE or
wellhead.
9.8 Mud loggers WILL NOT be used on either hole section.
9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80qF).
x Cold mud temps are necessary to mitigate hydrate breakout
9.10 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.
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10.0 N/U 13-5/8” 5M Diverter System
10.1 N/U 13-5/8” CTI BOP stack in diverter configuration (Diverter Schematic attached to program).
x N/U 20” x 13-5/8” DSA
x N/U 13 5/8”, 5M diverter “T”.
x NU Knife gate & 16” diverter line.
x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
x Diverter line must be 75 ft from nearest ignition source
x Place drip berm at the end of diverter line.
x Utilized extensions if needed.
10.2 Notify AOGCC with 24 hour notice to witness. Function test diverter.
x Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens
prior to annular closure.
x Ensure that the annular closes in less than 30 seconds (API Standard 64 3rd edition March 2018
section 12.6.2 for packing element ID less than or equal to 20”)
10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the
vent line tip. “Warning Zone” must include:
x A prohibition on vehicle parking
x A prohibition on ignition sources or running equipment
x A prohibition on staged equipment or materials
x Restriction of traffic to essential foot or vehicle traffic only.
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10.4 Rig & Diverter Orientation:
x May change on location
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11.0 Drill 12-1/4” Hole Section
11.1 P/U 12-1/4” 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.
11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor.
x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in
conductor.
11.3 Drill 12-1/4” hole section to section TD, in the Schrader OBd sand. Confirm this setting depth
with the Geologist and Drilling Engineer while drilling the well.
x Monitor the area around the conductor for any signs of broaching. If broaching is observed,
Stop drilling (or circulating) immediately notify Drilling Engineer.
x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100.
x Hold a safety meeting with rig crews to discuss:
x Conductor broaching ops and mitigation procedures.
x Well control procedures and rig evacuation
x Flow rates, hole cleaning, mud cooling, etc.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Keep mud as cool as possible to keep from washing out permafrost.
x Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can
handle the flow rate.
x There have been ‘directional dead zones’ noted in PBW. Directional plan has a build up in
DLS from 2 – 4, to allow gradual build. If possible get ahead of build rates while still
meeting tangent hold target.
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 at
base of perm and at TD (pending MW increase due to hydrates). 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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x Be prepared for gas hydrates. In PBW they have been encountered typically around 1660’
TVD (Base of Perm) to 2740’ TVD (Top Ugnu) and below. Be prepared for hydrates:
x Gas Hydrates have been seen on Z pad, Last SB Well Z-210
x Keep mud temperature as cool as possible, Target 60-70*F.
x Dump and dilute as necessary to maintain temp, utilize cold water on the rig as well as
cold pre-made mud on trucks ready.
x Drill through hydrate sands and quickly as possible, do not backream.
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 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
11.4 12-1/4” hole mud program summary:
x Density: Weighting material to be used for the hole section will be barite. Additional
barite or spike fluid will be on location to weight up the active system (1) ppg above
highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and
TD with 9.5+ ppg. MW for free gas and hydrates based upon offset wells
Depth Interval MW (ppg)
Surface –Base Permafrost 8.9+
Base Permafrost - 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.
DLB
DLB
TVD (Base of Perm) to 2740’ TVD (Top Ugnu) and below. Be prepared for hydrates:
Be prepared for gas hydrates. In PBW they have been encountered typically around 1660’pp g y yypy
EMW expected=8.46 ppg DLB
DLB
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Drilling Procedure
x Wellbore and mud stability:Additions of CON DET PRE-MIX/DRIL N SLIDE are
recommended to reduce the incidence of bit balling and shaker blinding when penetrating
the high-clay content sections of the Sagavanirktok and the heavy oil sections of the
UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of
ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action.
x Casing Running:Reduce system YP with DESCO as required for running casing as
allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and
swab pressures. Reduce the system rheology once the casing is landed to a YP < 20
(check with the cementers to see what YP value they have targeted).
System Type:8.8 – 9.8 ppg Pre-Hydrated Aquagel/freshwater spud mud
Properties:
Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp
Surface 8.8 –9.8 75-175 20 - 40 25-45 <10 8.5 –9.0 70 F
System Formulation: Gel + FW spud mud
Product Concentration
Fresh Water
soda Ash
AQUAGEL
caustic soda
BARAZAN D+
BAROID 41
PAC-L /DEXTRID LT
ALDACIDE G
0.905 bbl
0.5 ppb
15 - 20 ppb
0.1 ppb (8.5 – 9.0 pH)
as needed
as required for 8.8 – 9.2 ppg
if required for <10 FL
0.1 ppb
11.5 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem
sweeps and drop viscosity.
11.6 RIH to bottom, proceed to BROOH to HWDP
x Pump at full drill rate (400-600 gpm), and maximize rotation.
x Pull slowly, 5 – 10 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.
11.7 TOOH and LD BHA
11.8 No open hole logging program planned.
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12.0 Run 9-5/8” Surface Casing
12.1 R/U and pull wearbushing.
12.2 R/U Weatherford 9-5/8” casing running equipment (CRT & Tongs)
x Ensure 9-5/8” BTC x NC50, and VAM 21 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 8.75” on the location prior to running.
x Top 2,500’ of casing 47# drift 8.525”
x Actual depth to be dependant upon base of permafrost and stage tool
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:
9-5/8” Float Shoe
1 joint – 9-5/8” , 2 Centralizers 10’ from each end w/ stop rings
1 joint –9-5/8” , 1 Centralizer mid joint w/ stop ring
9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’
1 joint – 9-5/8” , 1 Centralizer mid joint with stop ring
9-5/8” HES Baffle Adaptor
x Ensure bypass baffle is correctly installed on top of float collar.
x Ensure proper operation of float equipment while picking up.
x Ensure to record S/N’s of all float equipment and stage tool components.
This end up.
Bypass Baffle
g 120’ shoe track
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12.5 Float equipment and Stage tool equipment drawings:
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12.6 Continue running 9-5/8” surface casing
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
x Bowspring Centralizers only
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 Verify depth of lowest Ugnu water sand for isolation with Geologist
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
x Any packing off while running casing should be treated as a major problem. It is preferable
to POH with casing and condition hole than to risk not getting cement returns to surface.
12.7 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below
the permafrost (~ 2,500’ MD, actual depth based upon base of permafrost)
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.
9-5/8” 47# L-80 VAM21 Make-Up Torques:
Casing OD Minimum Optimum Maximum
9-5/8”28,400 ft-lbs 31,550 ft-lbs 34,650 ft-lbs
9-5/8” 40# L-80 BTC MUT:
Casing OD Minimum Optimum Maximum
9-5/8”To mark on pipe. Keep track of averages and investigate anomalies.
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12.8 Continue running 9-5/8” surface casing
x Centralizers: 1 centralizer every 3rd joint to 200’ from surface
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
o 1 centralizer every 2 joints to base of conductor
12.9 The last 2,500’ of 9-5/8” will be 47#, from 2,500’ to Surface
x Actual length of 47# may change due to depth of permafrost as drilled
x Ensure drifted to 8.525”
12.10 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.11 Slow in and out of slips.
12.12 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.
12.13 Lower casing to setting depth. Confirm measurements.
12.14 Have slips staged in cellar, along with necessary equipment for the operation.
12.15 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.
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13.0 Cement 9-5/8” Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
x Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks.
x Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
x Review test reports and ensure pump times are acceptable.
x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
13.2 Document efficiency of all possible displacement pumps prior to cement job.
13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
13.5 Fill surface cement lines with water and pressure test.
13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below
calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached.
13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead &
tail, TOC brought to stage tool.
Estimated 1st Stage Total Cement Volume:
Section Calculation Vol (bbl) Vol (ft3) Vol (sks)
12-1/4" OH x 9-5/8" Casing (6,277'-1,000'-2,500') x 0.0558 bpf x 1.3 201.4 1129.9
Total Lead 201.4 1129.9 480.8
12-1/4" OH x 9-5/8" Casing 1000' x 0.0558 bpf x 1.3 = 72.5 406.7
9-5/8" Shoetrack 120' x 0.0758 bpf = 9.1 51.1
Total Tail 81.6 457.8 394.6LeadTail
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Drilling Procedure
Cement Slurry Design (1st Stage Cement Job):
13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue
with the cement job.
13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of
mud pits, spotting water across the HEC stage cementer.
x Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
13.10 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very
accurate using 0.0625 bps (5” liners) for the Quattro pump output. To operate the stage tool
hydraulically, the plug must be bumped.
13.11 Displacement calculation:
2500’ x 0.0732 bpf + (6,277’-120’-2500’) x .0758 bpf =
183 bbl + 277.2 bbl = 460.2 bbls
80 bbls of tuned spacer to be left behind stage tool for preventing of contamination of
cement in the annulus
13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any
point during the job. Be prepared to pump out fluid from cellar. Have black water available to
contaminate any cement seen at surface.
13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over
displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling
Engineer.
13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening
plug is available if needed. This is the back-up option to open the stage tool if the plugs are not
bumped.
13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened.
Lead Slurry Tail Slurry
System EconoCem HalCem
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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Z-221 SB Injector
Drilling Procedure
13.16 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher pressure
may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns
to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation
for the 2nd stage of the cement job.
13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker
bypass line to the cuttings tank. Have black water available and vac trucks ready to assist.
Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact
with the cement.
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Prudhoe Bay West
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Drilling Procedure
Second Stage Surface Cement Job:
13.18 Prepare for the 2
nd stage as necessary. Circulate until first stage reaches sufficient compressive
strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre-job safety
meeting.
x Past wells have seen pressure increase while circulating through stage tool after reduced
rate
13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing
head.
13.20 Fill surface lines with water and pressure test.
13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.22 Mix and pump cmt per below recipe for the 2
nd stage.
13.23 Cement volume based on annular volume + open hole excess (300% for lead and 100% for tail).
Job will consist of lead & tail, TOC brought to surface. PBU Z pad has a history of washout %
that exceeds the standard 200%, to mitigate the risk we will pump 300% excess for lead Cement
will continue to be pumped until clean spacer is observed at surface.
Estimated 2nd Stage Total Cement Volume:
Cement Slurry Design (2nd stage cement job):
Section Calculation Vol (bbl) Vol (ft3) Vol (sks)
20" Cond x 9-5/8" Casing 110' x 0.26 bpf 28.6 160.4
12-1/4" OH x 9-5/8" Casing (2000' - 110) x .0558 x 4 421.8 2366.3
Total Lead 450.4 2526.7 877.3
12-1/4" OH x 9-5/8" Casing (2500 - 2000' x .0558 bpf x 2 55.8 313.0
Total Tail 55.8 313.0 267.6LeadTail
Lead Slurry Tail Slurry
System Arctic Cem HalCem
Density 10.7 lb/gal 15.8 lb/gal
Yield 2.88 ft3/sk 1.17 ft3/sk
Mixed
Water 22.02 gal/sk 5.08 gal/sk
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Z-221 SB Injector
Drilling Procedure
13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail.
13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out
of mud pits.
13.26 Displacement calculation:
2500’ x 0.0732 bpf = 183 bbls mud
13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side
outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out
fluid from cellar. Have black water available to retard setting of cement.
13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should
circulate approximately 100 - 150 bbls of cement slurry to surface.
13.29 Land closing plug on stage collar and pressure up to 1,000 – 1,500 psi to ensure stage tool closes.
Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool
has closed. Slips will be set as per plan to allow full annulus for returns during surface cement
job. Set slips.
13.30 Make initial cut on 9-5/8” final joint. L/D cut joint. Make final cut on 9-5/8”. Dress off stump.
Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule.
Ensure to report the following on wellez:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
x Note calculated top of cement
x Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to jengel@hilcorp.com and
joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the
AOGCC.
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Drilling Procedure
14.0 ND Diverter, NU BOPE, & Test
14.1 Give AOGCC 24hr notice of BOPE test, for test witness.
14.2 ND the diverter T, knife gate, diverter line & NU 11” x 13-5/8” 5M casing spool.
14.3 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.
14.4 RU MPD RCD and related equipment
14.5 Run 5” BOP test plug
14.6 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
14.7 RD BOP test equipment
14.8 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.9 Mix 8.9 ppg Baradrill-N fluid for production hole.
14.10 Set wearbushing in wellhead.
14.11 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole
section.
14.12 Ensure 5” liners in mud pumps.
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Drilling Procedure
15.0 Drill 8-1/2” Hole Section
15.1 MU 8-1/2” Cleanout BHA (Milltooth Bit & 1.22° PDM)
15.2 TIH w/ 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out
stage tool.
15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report.
15.4 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and
plot on FIT graph. AOGCC reg is 50% of burst = 5,750 / 2 = ~2,875 psi, but max test pressure
on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent
pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry
Guidance Bulletin 17-001.
15.5 Drill out shoe track and 20’ of new formation.
15.6 CBU and condition mud for FIT.
15.7 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test.
Document incremental volume pumped (and subsequent pressure) and volume returned. Submit
casing test and FIT digital data to AOGCC.
15.8 POOH and LD cleanout BHA
15.9 PU 8-1/2” directional BHA.
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before MU. Visually verify no debris inside components that
cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Ensure MWD is RU and operational.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
x Drill string will be 5” 19.5# S-135 NC50.
x Run a ported float in the production hole section.
Schrader Bluff Bit Jetting Guidelines
Formation Jetting TFA
NB 6 x 14 0.902
OA 6 x 13 0.778
OB 6 x 13 0.778
FIT and casing test digital data to AOGCC.
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Drilling Procedure
15.10 8-1/2” hole section mud program summary:
x Density: Weighting material to be used for the hole section will be calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg
above highest anticipated MW.
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
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Drilling Procedure
15.11 TIH with 8-1/2” directional assembly to bottom
15.12 Install MPD RCD
15.13 Displace wellbore to 9.2 ppg Baradrill-N drilling fluid
x Density may change based upon TD of surface hole section
15.14 Begin drilling 8-1/2” hole section, on-bottom staging technique:
x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K.
x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations
x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU
off bottom and restart on bottom staging technique. If stick slip continues, consider adding
0.5% lubes
15.14 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer.
x Flow Rate: 350-550 GPM, target min. AV’s 200 ft/min, 385 GPM
x RPM: 120+
x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly
wet to maximize solids removal efficiency. Check for holes in screens on every connection.
x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
x Monitor Torque and Drag with pumps on every 5 stands
x Monitor ECD, pump pressure & hookload trends for hole cleaning indication
x 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 OBd 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 OBd Concretions: 4-6% Historically
x MPD will be utilized to monitor pressure build up on connections.
x 8-1/2” Lateral A/C:
x There are no wells with a clearance factor <1.0.
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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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 (385+ GPM) and rotation (120+ RPM). Pump
tandem sweeps if needed
x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent
stream, circulate more if necessary
x 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.
15.15 Monitor the returned fluids carefully while displacing to brine.
15.19 BROOH with the drilling assembly to the 9-5/8” casing shoe
x Circulate at full drill rate (less if losses are seen, 350 GPM 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
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Drilling Procedure
15.20 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while
BROOH.
15.21 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps.
15.22 Monitor well for flow/pressure build up with MPD. Increase fluid weight if necessary.
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.
x Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any
additional logging runs conducted.
15.25 Based upon what is seen at the toe of the well, an OH P&A kit may be ran to ~ 17000’ prior to
running liner, to ensure OBd isolation.
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Drilling Procedure
16.0 Run 4-1/2” Injection Liner
16.1 Well control preparedness: In the event of an influx of formation fluids while running the 4-
1/2” injection liner, the following well control response procedure will be followed:
x P/U & M/U the 5” safety joint (with 4-1/2” crossover installed on bottom, TIW valve in open
position on top, 4-1/2” handling joint above TIW). This joint shall be fully M/U and
available prior to running the first joint of 4-1/2” liner.
x Slack off and with 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW.
x Proceed with well kill operations.
16.2 R/U 4-1/2” liner running equipment.
x Ensure 4-1/2” 12.75# EZGO x NC50 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” injection liner
x Use API Modified or “Best O Life 2000 AG”thread compound. Dope pin end only w/ paint
brush. Wipe off excess. Thread compound can plug the screens
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Use lift nubbins and stabbing guides for the liner run.
x Install joints as per the Running Order (From Completion Engineer post TD).
o Do not place tongs or slips on sleeve joints
o 22 NCS Sleeves will be ran, spaced ~500’ MD apart
o The liner connection is 4-1/2” 12.75 # EZGO HTGT
x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint
outside of the surface shoe.
x Obtain up and down weights of the liner before entering open hole. Record rotating torque at
10 and 20 rpm
4-1/2” 12.75 # EZGO HT Torque
OD Minimum Maximum Yield Torque
4-1/2 4,322 6,627 12,445
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Drilling Procedure
16.6. Ensure to run enough liner to provide for setting the liner hanger at ~ 5500’ MD
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Drilling Procedure
x Confirm set depth with completion engineer.
x 3-5 joints of 7” will be ran under the liner hanger for the production packer. Confirm with
completion engineer.
16.7. Ensure hanger/pkr will not be set in a 9-5/8” connection.
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 9-5/8” connection.
16.8. Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck
to make sure it coincides with the pipe tally.
16.9. M/U Baker SLZXP liner top packer to 4-1/2” liner.
16.10. 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.
16.11. 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.
16.12. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe
depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to
bottom.
16.13. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
& 20 RPM.
16.14. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
16.15. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
16.16. Rig up to pump down the work string with the rig pumps.
16.17. Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed
1,600 psi while circulating.Pusher tool is set at 2,100 psi with 5% shear screws but it should be
discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker
16.18. 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.
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Drilling Procedure
16.19. 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.
16.20. 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.
16.21. 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.
16.22. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted.
16.23. 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.
16.24. PU pulling running tool free of the packer and displace with at max rate to wash the liner top.
Pump sweeps as needed.
16.25. 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.
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Drilling Procedure
17.0 Run 7” Tieback - connections
17.1 RU and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder
to be used for tie-back space out calculation. Install 7” solid body casing rams in the upper ram
cavity. RU testing equipment. PT to 250/3,000 psi with 7” test joint. RD testing equipment.
17.2 RU 7” casing handling equipment.
x Ensure XO to DP made up to FOSV and ready on rig floor.
x Rig up computer torque monitoring service.
x String should stay full while running, RU fill up line and check as appropriate.
17.3 PU 7” tieback seal assembly and set in rotary table. Ensure 7” seal assembly has (4) 1” holes
above the first seal. These holes will be used to spot diesel freeze protect in the 9-5/8” x 7”
annulus.
17.4 MU first joint of 7” to seal assy.
17.6 Run 7”, 26#, L-80 DWC-SR Gas tight tieback to position seal assembly two joints above tieback
sleeve. Record PU and SO weights.
7”, 26#, L-80, DWC-SR
=Casing OD Torque (Min) Torque (Opt)Torque (Max)
7”17,700 20,400 23,100
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Drilling Procedure
17.7 MU 7” to DP crossover.
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Drilling Procedure
17.8 MU stand of DP to string, and MU top drive.
17.9 Break circulation at 1 BPM and begin lowering string.
17.10 Note seal assembly entering tieback sleeve with a pressure increase, stop pumping and bleed off
pressure. Leave standpipe bleed off valve open.
17.11 Continue lowering string and land out on no-go. Set down 5 – 10K and mark the pipe as “NO-
GO DEPTH”.
17.12 PU string & remove unnecessary 7” joints.
17.13 Space out with pups as needed to leave the no-go 1 ft above fully no-go position when the casing
hanger is landed. Ensure one full joint is below the casing hanger.
17.14 PU and MU the 7” casing hanger.
17.15 Ensure circulation is possible through 7” string.
17.16 RU and circulation corrosion inhibited brine in the 9-5/8” x 7” annulus.
17.17 With seals stabbed into tieback sleeve, spot diesel freeze protection from 2,500’ TVD to surface
in 9-5/8” x 7” annulus by reverse circulating through the holes in the seal assembly. Ensure
annular pressure are limited to prevent collapse of the 7” casing (verify collapse pressure of 7”
tieback seal assembly).
17.18 SO and land hanger. Confirm hanger has seated properly in wellhead. Make note of actual
weight on hanger on morning report.
17.19 Back out the landing joint. MU packoff running tool and install packoff on bottom of landing
joint. Set casing hanger packoff and RILDS. PT void to 3,000 psi for 10 minutes.
17.20 RD casing running tools.
17.21 PT 9-5/8” x 7” annulus to 1,500 psi for 30 minutes charted.
Page 40
Prudhoe Bay West
Z-221 SB Injector
Drilling Procedure
18.0 Run Upper Completion/ Post Rig Work
18.1 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 NC50 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.
18.2 PU, MU and RH with the following 4-1/2” injection completion jewelry (tally to be provided by
Operations Engineer):
x Tubing Jewelry to include:
x 1x XN Nipple
x 1x GLM
x 3x X Nipple
x 1x Production Packer
x XXX joints, 4-1/2”, 12.6#, L-80, VAMTOP
x X1 WLEG, set as close to 7” x 4-1/2” liner xo as possible
RIH
Page 41
Prudhoe Bay West
Z-221 SB Injector
Drilling Procedure
18.3 PU and MU the 4-1/2” tubing hanger.
18.4 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with
band/clamp summary.
18.5 Land the tubing hanger and RILDS. Lay down the landing joint.
18.6 Install 4” HP BPV. ND BOP. Install the plug off tool.
18.7 NU the tubing head adapter and NU the tree.
18.8 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi.
18.9 Pull the plug off tool and BPV.
18.10 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.
18.11 Drop the ball & rod and complete loading tubing and hydraulically set the packer as per
Halliburton’s setting procedure
18.12 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.
i. Note this test must be witnessed by the AOGCC representative.
18.13 Bleed both the IA and tubing to 0 psi.
18.14 Rig up jumper from IA to tubing to allow freeze protect to swap.
18.15 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over
with valve alignment as per operations personnel.
18.16 RDMO Innovation
i. POST RIG WELL WORK
1. Slickline
a. Change out GLV per GL ENGR
b. Pull ball and rod and RHC
2. Fullbore
a. Shear hydraulic toe port
3. Coil
a. Shift injection sleeves open
4. Well Tie in
5. Put well on injection
a. AOGCC witnessed MIT-IA once injection is stable
Page 42
Prudhoe Bay West
Z-221 SB Injector
Drilling Procedure
19.0 Innovation Rig Diverter Schematic
Page 43
Prudhoe Bay West
Z-221 SB Injector
Drilling Procedure
20.0 Innovation Rig BOP Schematic
Page 44
Prudhoe Bay West
Z-221 SB Injector
Drilling Procedure
21.0 Wellhead Schematic
Page 45
Prudhoe Bay West
Z-221 SB Injector
Drilling Procedure
22.0 Days Vs Depth
Page 46
Prudhoe Bay West
Z-221 SB Injector
Drilling Procedure
23.0 Formation Tops & Information
Page 47
Prudhoe Bay West
Z-221 SB Injector
Drilling Procedure
Page 48
Prudhoe Bay West
Z-221 SB Injector
Drilling Procedure
24.0 Anticipated Drilling Hazards
12-1/4” Hole Section:
Lost Circulation
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Gas Hydrates/Free Gas
Gas hydrates have been seen on PBU Z Pad. They were reported between 1800’ and 3140’ TVD. MW
has been chosen based upon successful trouble free penetrations of offset wells.
x Be prepared for gas hydrates
o Keep mud temperature as cool as possible, Target 60-70*F
o Dump and dilute as necessary to maintain temp, utilize cold water on the rig as well as
cold premade mud on trucks ready
o Drill through hydrate sands and quickly as possible, do not backream.
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.
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
Page 49
Prudhoe Bay West
Z-221 SB Injector
Drilling Procedure
swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching.
Maintain mud parameters and increase MW to combat running sands and gravel formations.
H2S:
Treat every hole section as though it has the potential for H2S. PBU Z-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.
Page 50
Prudhoe Bay West
Z-221 SB Injector
Drilling Procedure
8-1/2” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor
ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe
moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation
after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300
gpm
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
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 Z-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.
Page 51
Prudhoe Bay West
Z-221 SB Injector
Drilling Procedure
Abnormal Pressures and Temperatures:
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 There are no wells with a clearance factor <1.0.
Page 52
Prudhoe Bay West
Z-221 SB Injector
Drilling Procedure
25.0 Innovation Rig Layout
Page 53
Prudhoe Bay West
Z-221 SB Injector
Drilling Procedure
26.0 FIT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental
volume pumped and returned during test.
Page 54
Prudhoe Bay West
Z-221 SB Injector
Drilling Procedure
27.0 Innovation Rig Choke Manifold Schematic
Page 55
Prudhoe Bay West
Z-221 SB Injector
Drilling Procedure
28.0 Casing Design
Page 56
Prudhoe Bay West
Z-221 SB Injector
Drilling Procedure
29.0 8-1/2” Hole Section MASP
Page 57
Prudhoe Bay West
Z-221 SB Injector
Drilling Procedure
30.0 Spider Plot (NAD 27) (Governmental Sections)
Page 58
Prudhoe Bay West
Z-221 SB Injector
Drilling Procedure
31.0 Surface Plat (As Built) (NAD 27)
Page 59
Prudhoe Bay West
Z-221 SB Injector
Drilling Procedure
32.0 Offset Wells TVD MW
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0750150022503000375045005250True Vertical Depth (1500 usft/in)-3000 -2250 -1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250Vertical Section at 15.00° (1500 usft/in)Z-221 wp01 CP3Z-221 wp01 HeelZ-221 wp01 CP1Z-221 wp01 CP2Z-221 wp03 Toe9 5/8" x 12 1/4"4 1/2" x 8 1/2"500100015002000250030003500400045005000550060006500
7000
7500
8000
8500
9000
9500
10000
10500
11000
11500
12000
12500
13000
13500
14000
14500
15000
15500
160001650017000175001800018240Z-221 wp05Start Dir 3º/100' : 400' MD, 400'TVDStart Dir 5º/100' : 550' MD, 549.85'TVDEnd Dir : 1205.68' MD, 1154.12' TVDStart Dir 5º/100' : 3658.69' MD, 3105.97'TVDFault #1 (210' Throw)End Dir : 5976.63' MD, 4721.75' TVDStart Dir 3º/100' : 6276.63' MD, 4747.9'TVDEnd Dir : 6411.81' MD, 4755.64' TVDStart Dir 3º/100' : 8415.43' MD, 4810.45'TVDLateral Fault #1 (70' DTN)End Dir : 9578.97' MD, 4845.27' TVDStart Dir 3º/100' : 10742.92' MD, 4887.9'TVDEnd Dir : 10960.14' MD, 4892.26' TVDLateral Fault #2 (50' DTS)Lateral Fault #3 (40' DTS)Start Dir 3º/100' : 16974.9' MD, 4912.9'TVDTotal Depth : 18240.21' MD, 4512.9' TVDBPRFSV1UG4Ugnu LAUgnu MBOBAOBDHilcorp North Slope, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: Z-22156.40+N/-S +E/-WNorthingEastingLatitudeLongitude0.000.005959100.11599875.9270° 17' 51.6296 N 149° 11' 28.2825 WSURVEY PROGRAMDate: 2021-09-30T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool26.50 1000.00 Z-221 wp05 (Z-221) 3_Gyro-MWD90+Sag1000.00 6277.00 Z-221 wp05 (Z-221) 3_MWD+IFR2+MS+Sag6277.00 18240.21 Z-221 wp05 (Z-221) 3_MWD+IFR2+MS+SagFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation1848.90 1766.00 2078.86 BPRF2825.90 2743.00 3306.71 SV13142.90 3060.00 3704.55 UG44134.90 4052.00 4813.15 Ugnu LA4305.90 4223.00 5029.77 Ugnu MB4581.90 4499.00 5480.60 OBA4742.90 4660.00 6219.26 OBDREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: Z-221, True NorthVertical (TVD) Reference:Z-221 IRIG Planned RKB @ 82.90usftMeasured Depth Reference:Z-221 IRIG Planned RKB @ 82.90usftCalculation Method:Minimum CurvatureProject:Prudhoe BaySite:ZWell:Plan: Z-221Wellbore:Z-221Design:Z-221 wp05CASING DETAILSTVD TVDSS MD SizeName4747.93 4665.03 6277.00 9-5/8 9 5/8" x 12 1/4"4512.90 4430.00 18240.21 4-1/2 4 1/2" x 8 1/2"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 26.50 0.00 0.00 26.50 0.00 0.00 0.00 0.00 0.002 400.00 0.00 0.00 400.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 400' MD, 400'TVD3 550.00 4.50 186.00 549.85 -5.86 -0.62 3.00 186.00 -5.81 Start Dir 5º/100' : 550' MD, 549.85'TVD4 1205.68 37.28 188.68 1154.12 -233.99 -34.19 5.00 3.00 -234.87 End Dir : 1205.68' MD, 1154.12' TVD5 3658.69 37.28 188.68 3105.97 -1702.75 -258.41 0.00 0.00 -1711.61 Start Dir 5º/100' : 3658.69' MD, 3105.97'TVD6 5976.63 85.00 41.67 4721.75 -1436.66 786.44 5.00 -142.92 -1184.16 End Dir : 5976.63' MD, 4721.75' TVD7 6276.63 85.00 41.67 4747.90 -1213.42 985.13 0.00 0.00 -917.10 Z-221 wp01 Heel Start Dir 3º/100' : 6276.63' MD, 4747.9'TVD8 6411.81 88.43 43.83 4755.64 -1114.34 1076.73 3.00 32.25 -797.69 End Dir : 6411.81' MD, 4755.64' TVD9 8415.43 88.43 43.83 4810.45 330.44 2463.85 0.00 0.00 956.87 Start Dir 3º/100' : 8415.43' MD, 4810.45'TVD10 9042.98 88.41 25.00 4827.90 845.61 2816.82 3.00 -90.33 1545.84 Z-221 wp01 CP111 9578.97 87.90 8.92 4845.27 1356.34 2972.58 3.00 -92.06 2079.48 End Dir : 9578.97' MD, 4845.27' TVD12 10742.92 87.90 8.92 4887.90 2505.43 3152.93 0.00 0.00 3236.10 Z-221 wp01 CP2 Start Dir 3º/100' : 10742.92' MD, 4887.9'TVD13 10960.14 89.80 2.69 4892.26 2721.38 3174.87 3.00 -73.11 3450.37 End Dir : 10960.14' MD, 4892.26' TVD14 16974.90 89.80 2.69 4912.90 8729.50 3456.70 0.00 0.00 9326.71 Z-221 wp01 CP3 Start Dir 3º/100' : 16974.9' MD, 4912.9'TVD15 18240.21 127.76 2.69 4512.90 9904.34 3511.80 3.00 0.00 10475.78 Z-221 wp03 Toe Total Depth : 18240.21' MD, 4512.9' TVD
-2250
-1500
-750
0
750
1500
2250
3000
3750
4500
5250
6000
6750
7500
8250
9000
9750
10500
South(-)/North(+) (1500 usft/in)-3750 -3000 -2250 -1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750
West(-)/East(+) (1500 usft/in)
Z-221 wp03 Toe
Z-221 wp01 CP2
Z-221 wp01 CP1
Z-221 wp01 Heel
Z-221 wp01 CP3
9 5/8" x 12 1/4"
4 1/2" x 8 1/2"
250
1000
1500
2000
2500
375042504500
4
7
5
0
Z-221 wp05
Start Dir 3º/100' : 400' MD, 400'TVD
Start Dir 5º/100' : 550' MD, 549.85'TVD
End Dir : 1205.68' MD, 1154.12' TVD
Start Dir 5º/100' : 3658.69' MD, 3105.97'TVD
Fault #1 (210' Throw)
End Dir : 5976.63' MD, 4721.75' TVD
Start Dir 3º/100' : 6276.63' MD, 4747.9'TVD
End Dir : 6411.81' MD, 4755.64' TVD
Start Dir 3º/100' : 8415.43' MD, 4810.45'TVD
Lateral Fault #1 (70' DTN)
End Dir : 9578.97' MD, 4845.27' TVD
Start Dir 3º/100' : 10742.92' MD, 4887.9'TVD
End Dir : 10960.14' MD, 4892.26' TVD
Lateral Fault #2 (50' DTS)
Lateral Fault #3 (40' DTS)
Start Dir 3º/100' : 16974.9' MD, 4912.9'TVD
Total Depth : 18240.21' MD, 4512.9' TVD
CASING DETAILS
TVD TVDSS MD Size Name
4747.93 4665.03 6277.00 9-5/8 9 5/8" x 12 1/4"
4512.90 4430.00 18240.21 4-1/2 4 1/2" x 8 1/2"
Project: Prudhoe Bay
Site: Z
Well: Plan: Z-221
Wellbore: Z-221
Plan: Z-221 wp05
WELL DETAILS: Plan: Z-221
56.40
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 5959100.11 599875.92 70° 17' 51.6296 N 149° 11' 28.2825 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: Z-221, True North
Vertical (TVD) Reference: Z-221 IRIG Planned RKB @ 82.90usft
Measured Depth Reference:Z-221 IRIG Planned RKB @ 82.90usft
Calculation Method:Minimum Curvature
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0.001.002.003.004.00Separation Factor6750 7500 8250 9000 9750 10500 11250 12000 12750 13500 14250 15000 15750 16500 17250 18000 18750 19500 20250Measured Depth (1500 usft/in)Z-210Z-210PB1Z-220 wp07No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: Z-221 NAD 1927 (NADCON CONUS)Alaska Zone 0456.40+N/-S +E/-W NorthingEastingLatitudeLongitude0.000.005959100.11 599875.9270° 17' 51.6296 N 149° 11' 28.2825 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: Z-221, True NorthVertical (TVD) Reference:Z-221 IRIG Planned RKB @ 82.90usftMeasured Depth Reference:Z-221 IRIG Planned RKB @ 82.90usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2021-09-30T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.50 1000.00 Z-221 wp05 (Z-221) 3_Gyro-MWD90+Sag1000.00 6277.00 Z-221 wp05 (Z-221) 3_MWD+IFR2+MS+Sag6277.00 18240.21 Z-221 wp05 (Z-221) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)6750 7500 8250 9000 9750 10500 11250 12000 12750 13500 14250 15000 15750 16500 17250 18000 18750 19500 20250Measured Depth (1500 usft/in)GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference26.50 To 18240.21Project: Prudhoe BaySite: ZWell: Plan: Z-221Wellbore: Z-221Plan: Z-221 wp05Ladder / S.F. Plots2 of 2CASING DETAILSTVD TVDSS MD Size Name4747.93 4665.03 6277.00 9-5/8 9 5/8" x 12 1/4"4512.90 4430.00 18240.21 4-1/2 4 1/2" x 8 1/2"
Revised 2/2015
TRANSMITTAL LETTER CHECKLIST
WELL NAME: ______________________________________
PTD: _____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD: ____________________________ POOL: ______________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
No. _____________, API No. 50-_______________________.
Production should continue to be reported as a function of the original
API number stated above.
Pilot Hole
In accordance with 20 AAC 25.005(f), all records, data and logs
acquired for the pilot hole must be clearly differentiated in both
well name (_______________________PH) and API number
(50-_____________________) from records, data and logs acquired for
well (name on permit).
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce/inject is contingent upon issuance of
a conservation order approving a spacing exception.
(_____________________________) as Operator assumes the liability
of any protest to the spacing exception that may occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in no greater
than 30' sample intervals from below the permafrost or from where
samples are first caught and 10' sample intervals through target zones.
Non-
Conventional
Well
Please note the following special condition of this permit:
Production or production testing of coal bed methane is not allowed for
well ( ) until after ( )
has designed and implemented a water well testing program to provide
baseline data on water quality and quantity.
(________________________) must contact the AOGCC to obtain
advance approval of such water well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by (_______________________________) in the attached application,
the following well logs are also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for well logs run must be submitted to the AOGCC
within 90 days after completion, suspension or abandonment of this
well.
X
221-095
PBU Z-221
X
Prudhoe Bay Unit
Schrader Bluff Oil, Orion Development
X
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