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HomeMy WebLinkAbout221-068DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23699-00-00Well Name/No. PRUDHOE BAY UN ORIN L-206Completion Status1-OILCompletion Date10/11/2021Permit to Drill2210680Operator Hilcorp North Slope, LLCMD14700TVD4358Current Status1-OIL10/29/2021UICNoWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:ROP, AGR, DGR, ABG, EWR-M5, ADR MD & TVDNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF10/19/20217720 14662 Electronic Data Set, Filename: PBU L-206 ADR Quadrants All Curves.las35839EDDigital DataDF10/19/2021 Electronic File: PBU L-206 Geosteering EOW Plot.emf35839EDDigital DataDF10/19/2021 Electronic File: PBU_L-206_Geosteering.dlis35839EDDigital DataDF10/19/2021 Electronic File: PBU_L-206_Geosteering.ver35839EDDigital DataDF10/19/2021 Electronic File: PBU L-206 Geosteering EOW Plot.pdf35839EDDigital DataDF10/19/2021 Electronic File: PBU L-206 Geosteering End of Well Report.pdf35839EDDigital DataDF10/19/2021 Electronic File: PBU L-206 Post-Well Geosteering X-Section Summary.pptx35839EDDigital DataDF10/19/2021 Electronic File: PBU L-206 Geosteering EOW Plot.tif35839EDDigital DataDF10/19/2021 Electronic File: PBU L-206 Geosteering EOW Plot300.tif35839EDDigital Data0 0 2210680 PRUDHOE BAY UN ORIN L-206 LOG HEADERS35839LogLog Header ScansDF10/19/2021145 14700 Electronic Data Set, Filename: PBU L-206 LWD Final.las35840EDDigital DataDF10/19/2021 Electronic File: PBU L-206 LWD Final MD.cgm35840EDDigital DataDF10/19/2021 Electronic File: PBU L-206 LWD Final TVD.cgm35840EDDigital DataDF10/19/2021 Electronic File: L-206 Definitive Survey report.pdf35840EDDigital DataDF10/19/2021 Electronic File: L-206 Final Surveys.xlsx35840EDDigital DataFriday, October 29, 2021AOGCCPage 1 of 3PBU L-206 LWDFinal.las
DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23699-00-00Well Name/No. PRUDHOE BAY UN ORIN L-206Completion Status1-OILCompletion Date10/11/2021Permit to Drill2210680Operator Hilcorp North Slope, LLCMD14700TVD4358Current Status1-OIL10/29/2021UICNoWell 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 HISTORYDate CommentsDescriptionCompletion Date:10/11/2021Release Date:9/2/2021DF10/19/2021 Electronic File: L-206_DSR.txt35840EDDigital DataDF10/19/2021 Electronic File: L-206_GIS.txt35840EDDigital DataDF10/19/2021 Electronic File: L-206_Plan.pdf35840EDDigital DataDF10/19/2021 Electronic File: L-206_VSec.pdf35840EDDigital DataDF10/19/2021 Electronic File: PBU L-206 LWD Final MD.emf35840EDDigital DataDF10/19/2021 Electronic File: PBU L-206 LWD Final TVD.emf35840EDDigital DataDF10/19/2021 Electronic File: PBU L-206 LWD Final MD.pdf35840EDDigital DataDF10/19/2021 Electronic File: PBU L-206 LWD Final TVD.pdf35840EDDigital DataDF10/19/2021 Electronic File: PBU L-206 LWD Final MD.tif35840EDDigital DataDF10/19/2021 Electronic File: PBU L-206 LWD Final TVD.tif35840EDDigital Data0 0 2210680 PRUDHOE BAY UN ORIN L-206 LOG HEADERS35840LogLog Header ScansFriday, October 29, 2021AOGCCPage 2 of 3
DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23699-00-00Well Name/No. PRUDHOE BAY UN ORIN L-206Completion Status1-OILCompletion Date10/11/2021Permit to Drill2210680Operator Hilcorp North Slope, LLCMD14700TVD4358Current Status1-OIL10/29/2021UICNoComments:Compliance Reviewed By:Date:Friday, October 29, 2021AOGCCPage 3 of 3M. Guhl10/29/2021
1a. Well Status:Oil SPLUG Other Abandoned Suspended
1b. Well Class:
20AAC 25.105 20AAC 25.110 Development Exploratory
GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test
2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry:
Aband.:
3. Address: 7. Date Spudded: 15. API Number:
4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number:
Surface:
Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s):
GL: 45.9' BF: 46.47'
Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation:
4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number:
Surface: x- y- Zone- 4
TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD:
Total Depth: x- y- Zone- 4
5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD:
Submit electronic information per 20 AAC 25.050 (ft MSL)
22.Logs Obtained:
23.
BOTTOM
20" X-52 155'
2,119'
4,486'
7" L-80 4,079'
7"x6-5/8" L-80 4,358'
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" L-80 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 Solid / Slotted Liner
6,416'4-1/2" 12.6# L-80
SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation
Size and Number; Date Perfd):
6,231' 14,700'
Stg 2 L - 779 sx / T - 270 sx
4,073'
Driven
26#/20#
27' 2,495' Stg 1 L - 728 sx / T - 400 sx
8-1/2"
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
Hilcorp North Slope, LLC
WAG
Gas
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
10/11/2021
2509' FSL, 3933' FEL, Sec. 34, T12N, R11E, UM, AK
1387' FSL, 1553' FWL, Sec. 21, T12N, R11E, UM, AK
221-068
Schrader Bluff Oil Pool, Orion Dev Area
72.85'
14,698' / 4,358'
Prudhoe Bay Field /
HOLE SIZE AMOUNT
PULLED
50-029-23699-00-00
PBU L-206
582983 5978229
2209' FSL, 1829' FWL, Sec. 27, T12N, R11E, UM, AK
CEMENTING RECORD
5983213
SETTING DEPTH TVD
5987610
BOTTOM TOP
27'
27'
CASING WT. PER
FT.GRADE
26#
583399
577786
TOP
SETTING DEPTH MD
27'
24'
Per 20 AAC 25.283 (i)(2) attach electronic information
40#
6,244'
2,119'
24'
DEPTH SET (MD)
6,273' / 4,093'
PACKER SET (MD/TVD)
129.5#
47#
155'
2,495' 7,728'
Gas-Oil Ratio:Choke Size:Water-Bbl:
PRODUCTION TEST
October 16, 2021
Date of Test:
1000
10/23/2021 6
Flow Tubing
61
2,108
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
610527
Gas Lift
6-5/8" Slotted Liner 10/8/2021
7,862' - 14,569' 4,485' - 4,361'
863
ROP, AGR, DGR, ABG, EWR-M5, ADR MD & TVD
Sr Res EngSr Pet GeoSr Pet Eng
84
N/A
Oil-Bbl: Water-Bbl:
3,453 244340
10/5/2021
9/22/2021
ADL 028239 & 047447
00-001
1,850' / 1,727'
N/AN/A
None
14,700' / 4,358'
Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment
By Samantha Carlisle at 10:07 am, Oct 27, 2021
RBDMS HEW 10/28/2021
Completion Date
10/11/2021
HEW
G
DSR-10/28/21 DLB 10/28/2021MGR28OCT2021
Conventional Core(s): Yes No Sidewall Cores:
30.
MD TVD
50' 50'
1900' 1777'
Top of Productive Interval 7558' 4473'
1707' 1630'
3287' 2533'
4599' 3228'
6163' 4040'
6712' 4269'
7558' 4473'
SB OBd 7558' 4473'
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 OA
Schrader Bluff OBd
Permafrost - Base
29. GEOLOGIC MARKERS (List all formations and markers encountered): FORMATION TESTS
Permafrost - Top
Ugnu MB
SV1
SV5
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, Csg and Cmt 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
10.27.2021Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp Alaska, LLC, ou=Technical
Services - AK Drilling,
email=mmyers@hilcorp.com
Reason: I am approving this document
Date: 2021.10.27 06:49:34 -08'00'
Monty M
Myers
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:PBW L-206 Date:10/2/2021
Csg Size/Wt/Grade: 9.625 40#/47# L-80 Supervisor:Lott / Amend
Csg Setting Depth:7,728 4,485 TVD
Mud Weight:9.5 ppg LOT / FIT Press =583 psi
LOT / FIT =12.00 ppg Hole Depth =7761 md
Fluid Pumped=1.5 Bbls Volume Back =1.3 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
->24 ->028
->49 ->8292
->651 ->16 476
->8121 ->24 686
->10 168 ->32 903
->12 297 ->40 1138
->14 342 ->48 1383
->16 406 ->56 1645
->18 462 ->64 1923
->20 525 ->72 2186
->22 591 ->76 2317
->24 606 ->80 2449
->26 ->84 2722
->28 ->
Enter Holding Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0606 ->02722
->1567 ->52707
->2554 ->10 2705
->3544 ->15 2703
->4536 ->20 2702
->5529 ->25 2701
->6523 ->30 2700
->7517 ->
->8512 ->
->9507 ->
->10 502 ->
-> ->
-> ->
-> ->
2 4 6
8 10
1214
16
18
20
2224
0
8
16
24
32
40
48
56
64
72
76
80
84
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
3100
3200
3300
3400
3500
3600
3700
3800
3900
4000
0 102030405060708090Pressure (psi)Strokes (# of)
LOT / FIT DATA
606567554544536529523517512507502
2722 2707 2705 2703 2702 2701 2700
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
3100
3200
3300
3400
3500
3600
3700
3800
3900
4000
0 5 10 15 20 25 30Pressure (psi)Time (Minutes)
LOT / FIT DATA
Activity Date Ops Summary
9/20/2021 Stage modules. Set down catwalk and pipe shed. Release two trucks. Lay herculite and set rig mats. Unload pipe shed. Stage well components behind conductor.
Stage sub base, and unhook sow. Remove front steering arm and connect rear steering arm. Remove rear tires from sub base. Spot sub base over PBW L-206.
Shim sub base. Spot remaining modules. Sim Ops: Install diverter 'T'. Set outriggers and stompers down. Connect interconnect lines in pits and utilidors.
Energize steam and air systems. Load shop and camp at MP S pad and begin to convoy to PBW L pad. Work on rig acceptance checklist. Safe out walkways,
rooftops and stairwells. Cont working on rig acceptance checklist. Lay herculite and spot cuttings box. Build containment. Hang rig tongs and unpin weight
buckets. Install 5" hydraulic elevators. Inspect handling equipment. Scope up derrick. Bridle down. Install cellar grating. Cont working on rig acceptance
checklist. Spot break shack and envirovac. Function test top drive.
9/21/2021 N/U diverter. Inspect slip lock system and install same. N/U diverter "T", BOP stack. Orient stack and tighten slip lock. M/U diverter line. Center and 4pt stack.
Energize "Koomey". Install 4" conductor valves and function same. Obtain RKB's: Annular - 11.78'. Grd - 26.29' Perform derrick inspection, svc surface equipment
in pits and ready shakers for surface hole section. Cleaned pipeshed. C/O spinners on "Iron Roughneck". Crane in final section of diverter line and flange up same.
Spot MPD shack. Install short mousehole. Load MWD tools in shed. Rig accepted @ 14:00 hrs 9/21/2021 P/U, drift (3.125") 5" NC50 19.5#, S-135 drill pipe and
rack back same (80 jts). Perform diverter test. Annular closed - 8 secs, Knife valve open - 5 secs. 6 bottle avg NO2 2358 psi. Test gas alarms H2S 10/20, LEL
20/40% (test good). Witness waived by AOGCC rep - Brian Bixby. Drawdown Test. Initial - 3000 psi. Drawdown - 1950 psi. 200 psi - 20 secs. Final - 52 secs
Continue P/U, drift (3.125") 5" NC50 19.5#, S-135 drill pipe and rack back same (250 jnts total). P/U, drift (2.75" drift) 5" HWDP (17 jnts, Jars). Service rig: Grease
and inspect crown sheaves, top drive and blocks. Check gear oil. R/U tongs and prep to P/U BHA. M/U 12.25" Kymera Hybrid bit to 8" Terra force motor, XO. RIH
and tag ice plug at 48'. PT surface lines to 3000 psi - good. Wash and ream down to 98' with 2-3K, 350 gpm, 300 psi, 30 rpms, 850 ft-lbs. Observe ice then sand
at shaker, displace to 8.8 ppg spud mud. Significant gravel back with mud. Clear out flow line pumping through bleeder and jetting. Cont. washing and reaming out
conductor at 350 gpm, 300 psi, 30 rpms, 1Kft-lbs to 155', with significant gravel. Continuous jet flowline, pick up and pump through bleeder as necessary to clear
out flow line. Drill 12.25" hole from 155' to 220' at 320-350gpm, 400psi, 30rpms, 1-3K ft-lbs, WOB 2-4K, ROP 60-100fph. Continuously jetting flowline/pumping
through bleeder as needed. Observe significant gravel at shakers. Losses observed, continuously checking for broaching, ~150bbb ls lost, no broaching.
9/22/2021 Circulate bottoms up while BROOH from 220' to 159'. POOH on elevators with no issues. Inspect bit and motor. Cont. M/U BHA: GWD, DM collar, EWR-M5, TM
collar. Measure RFO = 245.48°. Upload MWD. P/U flex collars, RIH with HWDP down to 198', tag up. Wash down to 220'. Drill 12.25" hole from 220' to 409'
(189' total, AROP =63fph) at 400 gpm, 780 psi, 40 rpms, 1-3.5Kft-lbs, WOB 1-3K. Continuously jetting flowline and pump through bleeder as needed. PUW 56K,
SOW 59K, ROTW 58K. Collecting GWD surveys. Drill 12.25" hole from 409' to 958' (549' total, AROP =92fph) at 450 gpm, 1110 psi, 60 rpms, 2-3Kft-lbs, WOB 4-
7K. ECD 9.8 ppg with 9.1 ppg mud. PUW 75K, SOW 78K, ROTW 76K. Collecting GWD surveys. Jet flowline as needed. KOP 594', slide as needed for 2-
3°/100 dog leg as per WP6. Drill 12.25" hole from 958' to 1418' (460' total, AROP =77fph) at 500 gpm, 1375 psi, 60 rpms, 2-4Kft-lbs, WOB 5-15K. ECD 9.9 ppg
with 9.25 ppg mud, weighing up for 9.5ppg by base of permafrost. PUW 81K, SOW 81K, ROTW 81K. Collecting GWD surveys. Slide as needed for 4°/100 dog leg
as per WP6. Drill 12.25" hole from '1418 to 1928' (510' total, AROP =85fph) at 525 gpm, 1530 psi, 60 rpms, 4Kft-lbs, WOB 2-4K. ECD 10.26 ppg with 9.5 ppg
mud. PUW 90K, SOW 78K, ROTW 83K. Collecting GWD surveys. Slide as needed for 4°/100 dog leg as per WP6. Slide as needed for 4°/100 dog leg as per
WP6. Observe gas hydrates at 1,909' max gas 867U. Daily Disposal to G&I 684 bbls, Total = 684 bbls. Daily water from Lake 2 820 bbls, Total = 820 bbls. Daily
losses downhole 220 bbls, Total = 220 bbls. Distance to WP6: 6.11', 4.64' hight, 3.97' Left.
9/23/2021 Drill 12.25" hole from 1928' to 2499' (571' total, AROP =95fph) at 550 gpm, 1780 psi, 80 rpms, 5Kft-lbs, WOB 5-8K. ECD 10.36 ppg with 9.55 ppg mud. PUW
86K, SOW 76K, ROTW 86K. Last Gyro survey at 1760' Backream full stands . Slide as needed for 4°/100 dog leg to 2200' (tangent) as per WP6. Continue
seeing gas hydrates Reduce flow when necessary, control drill at 100-150 fph. Max gas 720U. Drill 12.25" hole from 2499' to 3105' (606' total, AROP =101fph) at
500 gpm, 1635 psi, 80 rpms, 6-7Kft-lbs, WOB 2-13K. ECD 10.3 ppg with 9.6 ppg mud. PUW 103K, SOW 82K, ROTW 88K. Backream full stands. Slide as
needed to maintain WP6. Continue seeing gas hydrates at formation tops (SV-3, SV-2). reduce flow to 400-525 gpm, control drill at 180 fph, and cease
backreaming when needed. max gas 1998U. Drill 12.25" hole from 3105' to 3739' (634' total, AROP =106fph) at 450 gpm, 1445 psi, 80 rpms, 7Kft-lbs, WOB 5-
12K. ECD 10.4 ppg with 9.6 ppg mud. PUW 112K, SOW 85K, ROTW 95K. Max gas 2099U. Cont. to manage gas with reduced flow/ROP when necessary.
Backream full stands . Slide as needed to maintain tangent as per WP6. Drill 12.25" hole from 3739' to 4089' (350' total, AROP =59fph) at 450 gpm, 1380 psi, 80
rpms, 7.9Kft-lbs, WOB 5-12K. ECD 10.14 ppg with 9.6 ppg mud. PUW 118K, SOW 86K, ROTW 101K. Max gas 2363U. Cont. to manage gas with reduced
flow/ROP when necessary. Backream full stands. At 3896' observe 8.9 non-pressurized gas cut mud coming out with consistent 2000+U of gas. Double backream
stand to allow time to circulate (80% BU strokes) out gas cut mud. Observe gas fall to 1300U at bottoms up and trend down to 700U, prior to increasing to 1600U at
bottoms up from drilling ahead Observe oil at 4020', Top Ugnu 4A @3901'. Daily Disposal to G&I 1430 bbls, Total = 2114 bbls. Daily water from Lake 2: 1140 bbls,
Total = 2540 bbls. Daily losses downhole 220 bbls, Total = 220 bbls. Distance to WP6: 9.64', 4.29' Low, 8.63' Right.
9/24/2021 Drill 12.25" hole from 4089' to 4597' (508' total, AROP =85fph) at 500 gpm, 1700 psi on, 80 rpms, 9Kft-lbs, WOB 4-8K. ECD 10.35 ppg with 9.6 ppg mud. PUW
125K, SOW 85K, ROTW 104K. Max gas 2119U. Backream full stands. Drill 12.25" hole from 4597' to 5104' (507' total, AROP =85fph) at 535 gpm, 2140 psi on,
80 rpms, 11-14Kft-lbs, WOB 5-17K. ECD 10.4 ppg with 9.6 ppg mud. PUW 145K, SOW 87K, ROTW 107K. Max gas 1592U. Backream full stands. Drill 12.25"
hole from 5104' to 5679' (575' total, AROP =96fph) at 550 gpm, 2210 psi on, 80 rpms, 12-15Kft-lbs, WOB 5-17K. ECD 10.6 ppg with 9.6 ppg mud. PUW 158K,
SOW 85K, ROTW 111K. Max gas 2506U. Backream full stands. Drill 12.25" hole from 5679' to 6060' (381' total, AROP =64fph) at 500 gpm, 1950 psi on, 80
rpms, 13-15Kft-lbs, WOB 6-12K. ECD 10.4 ppg with 9.6 ppg mud. PUW 159K, SOW 87K, ROTW 115K. Max gas 1340U. Backream full stands. Start 4°/100
turn/build at 5816'. Daily Disposal to G&I 1202 bbls, Total = 3316 bbls. Daily water from Lake 2: 1410 bbls, Total = 3950 bbls. Daily losses downhole 0 bbls, Total =
220 bbls. Distance to WP6: 5.3', 2.34' Low, 4.76' Right.
9/25/2021 Drill 12.25" hole from 6060' to 6377' (317' total, AROP =53fph) at 500 gpm, 1810 psi on, 80 rpms, 13-17Kft-lbs, WOB 6-16K. ECD 10.2 ppg with 9.6 ppg mud.
PUW 164K, SOW 88K, ROTW 120K. Max gas 1431U. Backream full stands. Sliding to maintain 4°/100 turn/build, Drill 12.25" hole from 6377' to 6734' (357'
total, AROP =60fph) at 500 gpm, 2400psi on, 2175 psi off btm, 80 rpms, 15-17Kft-lbs, WOB 5-18K. ECD 10.4 ppg with 9.6 ppg mud. PUW 166K, SOW 90K,
ROTW 119K. Max gas 1026U. Backream full stands. Sliding to maintain 4°/100 turn/build, Drill 12.25" hole from 6734' to 7079' (345' total, AROP =58fph) at 550
gpm, 2330 psi on, 80 rpms, 15-17Kft-lbs, WOB 5-20K. ECD 10.4 ppg with 9.6 ppg mud. PUW 171K, SOW 91K, ROTW 121K. Max gas 1496U. Backream full
stands. Sliding to maintain 4°/100 turn/build, Drill 12.25" hole from 7079' to 7395' (316' total, AROP =53fph) at 550 gpm, 2215 psi on, 80 rpms, 15-17Kft-lbs, WOB
7-14K. ECD 10.4 ppg with 9.6 ppg mud. PUW 176K, SOW 85K, ROTW 120K. Max gas 1417U. Backream full stands. Sliding to maintain 3.5-4°/100 turn/build,
Daily Disposal to G&I 1140 bbls, Total = 4456 bbls. Daily water from Lake 2: 1130 bbls, Total = 5080 bbls. Daily losses downhole 0 bbls, Total = 220 bbls. Distance
to WP6: 2.85', 0.62' High, 2.78' Left.
Well Name:
Field:
County/State:
PBW L-206
Prudhoe Bay West
Hilcorp Energy Company Composite Report
, Alaska
9/22/2021Spud Date:
9/26/2021 Drill 12.25" hole from 7395' to 7700' (305' total, AROP =51fph) at 550 gpm, 2380 psi on, 80 rpms, 16-17Kft-lbs, WOB 6-20K. ECD 10.4 ppg with 9.6 ppg mud.
PUW 178K, SOW 81K, ROTW 118K. Max gas 2068U. Backream full stands. Sliding to maintain 3.5-4°/100 turn/build, Drill 12.25" hole from 7700' to 7741' (41'
total, AROP =82fph) at 550 gpm, 2380 psi on, 80 rpms, 16-17Kft-lbs, WOB 7K. ECD 10.4 ppg with 9.6 ppg mud. PUW 178K, SOW 81K, ROTW 118K. Max gas
1791U. Backream full stands. Obtain final survey on bottom. BROOH from 7741' to 7587'. Pump 50bbls high vis sweep, on time with 100% increase in cuttings,
and circulate 1.5x bottoms up. 550gpm, 2095psi, 80rpms, 15-17Kft-lbs, ECD 10.2ppg. Max gas 2187U. Monitor well, initial slight flow increasing to 18 bph. Non
pressurized MW 8.3ppg, MW 9.6 ppg. Weigh mud system up to 9.7 ppg, lower mud volume and add water at 50bph to cool down mud. Circulate at 550 gpm, 2055
psi, 55 rpms, 16-17Kft-lbs. Perform 2x flow checks with gas breaking out. Rack back stand. Circulate bottoms up, adding water from truck truck (37°F compared to
47°F from water tank) at 50 bph. Flow check, slight flow with gas breaking out slightly better than previous. Cont to cool down mud system, and weight up to 9.8
ppg adding water at 75 bph from truck. Initial gas 550U (480U prior to flow check). Slow rate to 450 gpm, 1300 psi, 30 rpms, 15-17Kft-lbs. Observe gas increase to
836U then beginning to decrease at ~4300 strokes (correlates to 1,940' in annulus). Initial mud temp 85°F, final 75°F. Flow check, initially static then slight flow
with gas breaking out. Rack one stand back. Circulate at lower rate preventing motor from heating up mud, weigh up to 9.9 and adding water at 75 bph. 400 gpm,
1250 psi, 30 rpms 15-17Kft-lbs. Flow check, intermittent gas breaking out fluid level falling. BROOH from 7460' to 5991' at 450 gpm, 1590 psi, 80 rpms, 15-18Kft-
lbs, ECD 11.0 ppg. Max gas 920U. PUW 175K, SOW 91K. At 20-30 fpm as hole dictates. Daily Disposal to G&I 1259 bbls, Total = 5715 bbls. Daily water from
Lake 2: 1140 bbls, Total = 6220 bbls. Daily losses downhole 0 bbls, Total = 220 bbls. Distance to WP6: 3.88', 3.19' Low, 2.21' Right.
9/27/2021 BROOH from 5991' to 5800' at 450 gpm, 1575 psi, 80 rpms, 15-17Kft-lbs, ECD 11.0 ppg, max gas 520U. Pulling 20-30 fpm as hole dictates. PUW 178K, SOW
92K, ROTW 113K. CBU at 450 gpm, 1510 psi, 40 rpm, 14-16Kft-lbs, ECD 10.8 ppg, max gas 653U, reciprocating pipe. Flow check well for 30 minutes, observe
intermittent gas breaking out at surface. Cont. BROOH from 5800' to 4169' at 450 gpm, 1350 psi, 80 rpm, 10-13Kft-lbs. ECD 10.7 ppg. Max gas 920U. Pull 20-30
fpm as hole dictates. PUW 140K, SOW 80K, ROTW 102K. Cont BROOH from 4169' to 2360' at 450 gpm, 1180 psi, 80 rpms, 15-19Kft-lbs, ECD 11.1 ppg. PUW
105K, SOW 74K, ROTW 84K. Observe erratic TQ and slight packoffs from 3822' to 3630' and from 3066' to 2360'. Pull 2-25 fpm as hole dictates. Max gas 2097'
Cont. BROOH from 2360' to 480', 450 gpm, 1000 psi, 80 rpms 3-4Kft-lbs. Max gas 1319U. PUW 67K, SOW 69K, ROT67K. CBU over two stands from 1960' to
1801'. CBU at 720' (HWDP) and monitor well, minimal gas at surface. Attempt to POOH on elevators without success. Cont BROOH at 40 rpms, 400 gpm. Cont.
BROOH from 480' to 1500' at 400 gpm, 650 psi, 40 rpms, 1000ft-lbs. Max gas 17U. L/D BHA. L/D 2 flex collars. Plug in and download, L/D TM, EWR-M5, DM,
GWD. Break bit. Bit grade: PDC 3-2-CT-A-X-I-WT-TD, Roller grade 1-1-WT-A-F-I-NO-TD. SIM Ops: Bring centralizers, casing elevators, slips to rig floor. Clean
and clear rig floor. Rig down tongs and move ST-80 to storage position. R/D hydraulic elevators. Service rig, grease crown, blocks and wash pipe. Check fluid
levels in top drive. Rig up to RIH with casing: rig up Weatherford Volant tool, bail extensions and elevators, power tongs. M/U 9-5/8" shoe track. Shoe, blank, Float
collar. Daily Disposal to G&I 456 bbls, Total = 6171 bbls. Daily water from Lake 2: 570 bbls, Total = 6790 bbls. Daily losses downhole 40 bbls, Total = 260 bbls.
Distance to WP6: 3.88', 3.19' Low, 2.21' Right.
9/28/2021 Cont M/U 9-5/8" shoe track and check floats - good. Drop top hat. Cont. to RIH with 9-5/8", 40#, L-80, DWC casing as per tally to 1366', fill every 5 joints, top off
every 10 jnts. RIH at 30 fpm watching displacement. At 1366', tong operator brought up the centralizer on jnt 28 did not slide down and land on collar. POOH from
1366' to 1120' to inspect jnt 28 and found that it had been egged. L/D and kick out joint. Cont to RIH with 9-5/8", 40#, DWC casing from 1366'. At 1787' set down.
Attempt to work though w/o pumps/rotary, unable to. Establish circ at 3.5 bpm, 105 psi and 5-20 rpms, 6K-20Kft-lbs. Wash and ream casing down from 1787' to
2500', working though numerous tight spots. PUW 132K, SOW 85K, ROT 94K Cont. to wash and ream casing from 2500' to 3308' at 3.5 bpm, 160 psi, 5-15 rpms,
8-20Kft-lbs. Work through several tight spots. PUW 145K, SOW 76K, ROTW 95K. Circulate bottoms up, staging pumps up to 7 bpm, 165 psi, 10 rpms, 10-18Kft-
lbs, reciprocating pipe. max gas 1815U. Cont to RIH with 9-5/8", L-80, 40#, DWC casing on elevators from 3308' to 3922', filling every 5 joints, breaking circ every
10 jnts. RIH at 15-30 fpm as hole dictates. PUW 166K, SOW 91K. Cont to RIH with 9-5/8", L-80, 40#, DWC casing on elevators from 3922' to 5195', M/U ES
Cementer and XO joint. Cont to RIH with 9-5/8", L-80, 47# VAM21 casing to 5847'. Filling every 5 joints, breaking circ every 10 jnts. PUW 250K, SOW 95K. Run
25-35 fpm. Establish circulation and stage pumps up to 166 gpm, ICP 280 psi. Observe losses initial up to 60 bph slowing to no losses. Continue staging pumps
up to 247gpm FCP 190 psi. Mud weight coming out initially 10.25 ppg down to 10.1. MW in 9.9 ppg. PUW 225K, SOW 115K. Max gas 556U. Cont to RIH with 9-
5/8", L-80, 47# VAM21 casing from 5847' to 6054'. Fill every 5 joints, break circulation every 10. Running speed 25 fpm. PUW 260K SOW 110K. Daily Disposal to
G&I 228 bbls, Total = 6399 bbls. Daily water from Lake 2: 560 bbls, Total = 7350 bbls. Daily losses downhole 20 bbls, Total = 280 bbls.
9/29/2021 Cont to RIH with 9-5/8", L-80, 47# VAM21 casing from 6054' to 6957'. Fill every 5 joints, break circulation every 10. Running speed 25 fpm. PUW 260K SOW
110K. @ 6957' pushed 7 bbls away in 5 jts. CBU and displace heavy/thick mud from annulus staging pump up .5 bbl increments to 5 bpm/180 psi working pipe.
Max gas @ 572u Cont to RIH with 9-5/8", L-80, 47# VAM21 casing from 6957' to 7731' washing last 2 jts to bottom @ 2 bpm/260 psi. Fill every 5 joints, break
circulation every 10. Running speed 20 fpm. Ran 43 solid Hydro form centralizers and 27 bow spring for total of 70 centralizers. Circulate and condition mud for
cement job staging pumps up in .5 bpm increments to 6 bpm/165 psi. CBU x2 Lowering Yeild point in mud to 16. Shut down and Blow down Top Drive. R/U
Cement line to Volant, cont to circulate through cement line @ 6 bpm. Max Gas 691u, PUW 282K, SOW 122K HES pump 5 bbls fresh water, 2 BPM, 80 PSI. PT
lines to 1000 PSI low / 4000 PSI high. Mix & pump 55 bbls of 10.0 ppg Tuned Spacer w/ 4# red dye & 5# Pol-E-Flake in 1st 10 bbls, 3.8 BPM, 270 PSI. Drop by-
pass plug. Mix & pump 310 bbls of 12.0 ppg lead cmt (728 sks @ 2.347^3/sk yield), 4.5 BPM, 450 PSi Mix & pump 80 bbls of 15.8 ppg tail cmt (400 sks @
1.15^3/sk yield), 3.5 BPM, 400 PSI. Drop shut-off plug. Pump 20 bbls fresh water, 5.4 BPM, 452 PSI. Displace cmt with 356 bbls, 9.8 ppg spud mud with rig pumps
7 BPM, 460 PSI (Chase CMT)" HES pump 80 bbls 9.4 ppg tuned spacer, 5 BPM, 670 PSI. Cont displace from rig 126 bbls, 6 bpm, 775 psi. (Calc 114.6 bbl).
Reduce rate to 3 bpm, 550 psi. Reciprocated throughout job, was unable to get to tally depth. Shoe is at 7,728’ MD 3.28’ off original tally. Bumped plug at 18:54
CIP. With 9.25 bbl shoe track and 12.95 bbls over Calc. (Total 22.2 bbls over) Press up 550 psi over FCP to 1,050 psi, shut down pumps and press was bleeding
off. Cycled pumps 3X to 1,200 psi attempting to seat plug, still bleeding off. (Pumped total 10.04 bbls) Check floats, good. Attempt to open ES @ 1 bpm to 1,250 psi
stage up to 2 bpm 1,520 psi with no success. (Pumped 8.4 bbls) Seeing returns from down hole. Discuss with town dropping Free Falling Open plug. ES at 2,520’
MD 59° inc. Decision was made to drop plug. Seeing Gas Hydrates breaking out at surface and fluid falling in well. Waited 25 min. Break Circ at 1 bpm to 260 psi, 3
bpm 902 psi shut down Press bled to 122 psi. Cycled pumps 2 more times with out success. (Pumped 10.2 bbls) Cont to see Hydrates at surface, Max 356u.
Discuss options with town. Attempt to Press up to 3,000 psi and open ES. Pumps on at 6 bpm and 31 stks (1.9 bbls) ES opened at 900 PSI at 20:56. Total over
displaced including shoe track 52.74 bbls. Cont circ through ES staging pumps up to 5 bpm 230 psi R/F 41% Max Gas 1,581u. Circ 6X BU. About 50 bbls of
spacer seen at surface, no cement. No losses. Shut down and flush stack W/ Black Water. Stage up to 6 bpm 290 psi 3X BU. No losses. PJSM, Wet lines w/ 5 bbls
H2O (HES) Pump 2nd stage cement job as follows: 50 bbls 10 ppg Tuned spacer w/ 4# red dye & 5 lb/bbl poly flake (1st 10 bbls). Lead ArticCem 400 bbls 10.7
ppg Lead cmt, 2.883 yld, (779 sx) 5.5 bpm, ICP 503/ FCP 530 psi. 295 bbls into cement saw poly flak at shaker (Calc 304 bbl). At 385 bbls into cement saw 10.55
ppg cement at shakers. Swapped to tail at 400 bbls away. Pump Tail Type I / II cement 57 bbls 15.8 ppg Tail cmt, 1.17 yld, (270 sx) 3.2 bpm, 541 psi. Drop closing
plug. Displace w/ 20 bbls H2O (HES) 5 bpm 230 psi then turn over to rig. Rig disp Calc 164.5 bbls 9.8 ppg spud mud, 7.5 bpm ICP 384 psi FCP 396 psi, reduce
rate 6 bpm 50 bbls away 277 psi. Reduced rate last 10 bbls to 3 bpm, ICP 513 psi FCP 517 PSI. ES Cementer shifted shut at 1,620 PSI. Held 2,247 psi for 3
minutes, check plug - good. CIP 05:10 hrs. No losses. Dumped 311.5 bbls of green cement. Max Gas 794u. PJSM Flush surface lines and stack W/ Black Water.
R/D Volant tool. Daily Disposal to G&I 666 bbls, Total = 7065 bbls. Daily water from Lake 2: 690 bbls, Total = 8040 bbls. Daily losses downhole 30 bbls, Total = 310
bbls.
9/30/2021 PJSM Remove Diverter lines F/ knife valve. Wash out flow box. R/D hole fill ine. R/U BOP Cranes. Pull mouse hole. Remove chain binders F/ stack. Back out speed
head bolts and P/U stack. Set emergency slips W/ 30K in slips. Set back stack and separate speed head and Diverter Tee. Assist welder W/ 9.625" Csg cut.
(33.50') Remove diverter pedestals. PJSM Finish dressing 9.625" Csg stump as per NOS rep onsite. Set stack and Johnny Whack stack. SIMOPS unload spud
mud F/ pits. PJSM Remove riser and set stack back on pedestal. Remove Diverter Tee and speed head. P/U MPD head W/ top drive and hang below flow box.
Bring stack over and set MPD on stack. Rack back to pedastal. PJSM Install Sliplock well head and trq to engage seals. PT seals 500 psi 5 min, 3,800 psi 10 min.
Orient and install tubing spool as per NOS rep onsite. Install test plug. SIMOPS Clean pits. PJSM Install DSA and set down stack. Install turn buckles, drip pan and
Beyond 4" hard lines. R/U choke and kill lines. R/U drain hose and fill up line. Install Koomey lines and charge Koomey. SIMOPS Cont cleaning pits. Perform EAM
top drive 7 J Box. C/O Ext sensor battery. RKB LLDS 24.23', ULD 21.98', LPR 19.84', BLNDS 15.98', UPR 14.47', Ann 11.93'. PJSM Pump through Beyond MPD
lines. Attempt to PT MPD lines found leak on 4" line. Disconnect and C/O O Ring. Reflood and test to 300 psi 5 min 1,300 psi 5 min, good. Pull test cap. Center
stack and install trip nipple. Install mouse hole. PJSM M/U 5" test jnt , 5" TIW, 5" Dart and side entry sub. Flood lines and purge air. 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, 5" TIW, Upper and lower IBOP, Mez Kill, HCR and manual Choke and
Kill, manual and Super Choke, Upper and lower VRB Rams (2,875" X 5.5") Blind Rams, Annular W/ 4.5" test Jnt. Koomey draw drown Initial System 3,000 PSI,
Manifold 1,350 PSI, Annular 1,475 PSI, after System 1,500 PSI, Man 1,500 PSI, Annular 1,500 PSI. 200 PSI increase 24 Sec, full charge 90 sec. Nitrogen 6 bottle
average 2,290 PSI. Test H2S 10-20 ppm, LEL 20-40%, PVT high/ low level alarms. Witnessed waived AOGCC Rep Bob Noble. F/P LPR’s W/ 5" jnt refunction and
passed. PJSM Pull test plug and install wear ring. (9 1/16" ID 10 3/4" OD 38" Lngt) Break doen test jnt L/D. Blow down choke and kill lines. Daily Disposal to G&I
2079 bbls, Total = 9144 bbls. Daily water from Lake 2: 660 bbls, Total = 8700 bbls. Daily losses downhole bbls, Total = 0 bbls. Total Surface loss: 310 bbls.
10/1/2021 PJSM P/U M/U Clean Out BHA. RR 8.5" XR-CPS Tricone Bit (0.9419 TFA) 6.75" StrataForce Lobe 6.7 - 6 stg 1.5° Motor, 10 ea 5" HWDP, 6.75" Hydra Jar and 7
ea 5" HWDP 592'. Cont single in hole W/ 5" 19.5# S-135 NC50 D.P. F/ 590' to 2,488' MD. Wash down 350 gpm 605 psi F/ 2,488' to ES plug at 2,515' set down
15k. Drill ES plug F/ 2,515' to 2,531' MD. 400 gpm 725 psi 30 rpm Trq 4-9k WOB 2-9k. P/U 99k SLK 74k ROT 81k. Rubber seen at shakers. Pass through ES
with and with out pumps. Clean. CBU @ 450 GPM, 930 psi, 40 RPM, 3-5K Tq. Shut upper Pipe Rams. Pump through DP and Kill line and pressure up to 2100 psi
confirm plug will hold for Casing test. Continue single in with 5" NC50, S-135 drill pipe F/ 2531' - T/ 7590' and set down 5K Tag. (BFL @ 7606') Circulate STS @
7540' MD. 550 gpm, 1475 psi, p/u 205k slk 65k MW 12.4 ppg at 7,000 stks. Gas 17u. PJSM Install head pin and HP hose to drill string. Flood lines and purge air
out of choke manifold and lines. Shut in UPR’s. Attempt to PT to 2,500 psi for 30 min. 15 min into test male to male MPT failed off the sensater on choke manifold.
Replaced MPT and purge air out of line. Attempted to test test again and had to purge air of the system again. Started second test and had sensater fail. Replaced
sensater. Test 9.625” Csg to 2,500 psi for 30 min on chart, good. Pumped 5.8 bbls, bled back 5.5 bbls. R/D test Equip. Blow down choke manifold and lines. Drill
out shoe track F/ 7,597' and 20' of new hole to 7,761' MD (4,485' TVD) 400 gpm 1,005 psi 40 rpm Trq 17-19k F/O 51% WOB 2-7k Max Gas 153u. On Depth BFA
7,606', FC 7,640' & Shoe 7,728' MD. Work through 3X no issue. Encountered heavy clabbered mud at 7,708' dumped over board and condition. F/ BFA to FC
partially cured cement seen at shakers. F/ FC to shoe cement was mostly cured W/ slight contamination. Rot & Rec F/ 7,761' to 7,714' MD. 400 gpm 900 psi 30 rpm
Trq 18k. Max Gas 1,341u. Prep pits and trucks for displacement. PJSM Pump 38 bbl Hi Vis sweep and displace F/ 9.3 ppg Spud Mud to 9.5 ppg BaraDril N. taking
returns overboard. 400 gpm 915 psi 30 rpm Trq 18k. SPR. Monitor well 10 min, static. Rack back 1 stand to 7,714' MD. PJSM R/U test Equip. Close UPR's.
Perform FIT 12 EMW MW 9.5 ppg 583 psi Pump 1.5 bbls, bled back 1.3 bbls. PJSM POOH F/ 7,714' to 2,500' MD P/U 105k SLK 75k. Daily Disposal to G&I 519
bbls, Total = 9663 bbls. Daily water from Lake 2: 659 bbls, Total = 9359 bbls. Daily Metal: 0 Total: 0. Daily losses downhole bbls, Total = 0 bbls. Total Surface
loss: 310 bbls.
10/2/2021 Continue to POOH from 2500' to 592' MD, PU 60K, SO 60K Rack back 1 stand HWDP, L/D BHA from 350' to Surface. M/U Flushing tool and jet Stack. Clean and
Clear Rig Floor. Bit Grade 1-1-WT-A-E-I-NO-BHA PJSM P/U M/U 8.5" SK616M-J1D (6X14)(0.9020 TFA) 8.5" Hycalog NRP, 7.625" Geo-Pilot 7600 XL 25KSI,
6.75" ADR, 8.375" ILS, 6.75" DGR & 6.75" PWD total 64.01' MD. Download. M/U 2x flex DCs w/ 2 solid plunger float sub between. 3x 5" NC50 HWDP w/ SLB 6.5"
jars T/ 302' MD. Shallow pulse test @ 400 gpm, 480 psi (test good). TIH with 5" NC50, S-135, 19.5# singles (72 jts) F/ 302' - T/ 2597' MD. Drift 3.125". Fill pipe
and Break in Geo Pilot . No losses. Continue TIH out of derrick with 5" dp F/ 2597' - T/ 7611' MD. 125k up, 75k dn. No losses. PJSM P/U stand & install RCD
bearing. Drain stack and pull flow nipple. Install RCD bearing as per Beyond rep onsite. Install clamp, bowl saver and curtain around bearing. PJSM Cut and slip
drilling line 14 wraps, 88'. ACCUM TM 1115. 1,653' left on spool. SIMOPS Circ at 4 bpm 385 psi. PJSM Service rig. Grease top drive, spinners, iron roughneck.
Monthly wobble on block sheaves. Check gear oil in top drive. Check brake gap, good. Wash down F/ 7,611' to 7,778' MD. 450 gpm/ mpd 457, 1,383 psi 80 rpm
Trq on 14-15k off 13k WOB 5k Max Gas 16u. ECD 10.49. P/U 174k SLK 82k ROT 112k. Drill 8.5" Production Hole F/ 7,778' to 8,353' MD (4,,482' TVD) Total 575’
(AROP 95.8’) 450 GPM/ MPD 450, 1,400 psi, 80-120 RPM, TRQ on 14-15k, TRQ off 13-14k, WOB 2-5k. ECD 10.66. Max Gas 2129u. P/U 170k, SLK 73k, ROT
111k. MPD 100% open. Adjusting flow rates to control shakers running over. Shut in at connections as needed to check for well press. Drilling with one choke open
to control gas flooding shakers. Distance to WP06: 12.08' 9.55 High 7.40' Low 1 concretion for a total thickness of 17' (3.3% of the lateral). Footage OBd Sand 512'
Daily Disposal to G&I 869 bbls, Total = 10532 bbls. Daily water from Lake 2: 140 bbls, Total = 9499 bbls. Daily Metal: 3 Total: 3. Daily losses downhole bbls, Total
= 0 bbls. Total Surface loss: 310 bbls.
10/3/2021 Drill 8.5" Production Hole F/ 8,353' to 8,890' MD (4,,484' TVD) Total 537’ (AROP 89.5’) 400-500 GPM/ MPD 400-500, 1,400 psi, 80-90 RPM, TRQ on 13-15k,
TRQ off 13-14k, WOB 5-12k. MW 9.5, ECD 11.00. Max Gas 2300u. P/U 147k, SLK 77k, ROT 108k. MPD hold 130 psi back pressure to mitigate gas at shakers.
Drill 8.5" Production Hole F/ 8,890' to 9,528' MD (4,,485' TVD) Total 638’ (AROP 106.3’) 500 GPM/ MPD 500, 1,985 psi, 80-90 RPM, TRQ on 12-15k, TRQ off 12-
14k, WOB 5-12k. MW 9.4, ECD 11..2. Max Gas 1698u. P/U 150k, SLK 78k, ROT 109k. MPD hold 125 psi back pressure to mitigate gas at shakers. Back ream full
stands. Adjusting RPM & WOB to try and mitigate excessive surface wobble, Drill 8.5" Production Hole F/ 9,528' to 10,037' MD (4,471' TVD) Total 509’ (AROP
84.9’) 525 GPM/ MPD 525, 2,010 psi, 80-90 RPM, TRQ on 11-14k, TRQ off 11-14k, WOB 5-12k. ECD 11.22. Max Gas 1696u. P/U 149k, SLK 80k, ROT 108k.
MPD 125 PSI dynamic, static 80 PSI 10.05 ppg EMW W/ 9.5.ppg MW. Use MPD to mitigate gas over running shakers. Adjusting RPM & W OB to try and mitigate
excessive surface wobble, Back ream full stands. Start out with 5k WOB and 60 rpm for ~5 increasing rpm slowly up to 120 rpm without surface wobble. Drill 8.5"
Production Hole F/ 10,037' to 10,734' MD ( 4,444' TVD) Total 706’ (AROP 117.7’) 450-525 GPM/ MPD 449-526, 1650 psi, 120 RPM, TRQ on 10-12k, TRQ off 9-
10k, WOB 2-8k. ECD 11.19. Max Gas 1827u. P/U 144k, SLK 79k, ROT 108k. MPD 150 PSI dynamic, static 100 PSI 10.1 ppg EMW W/ 9.45.ppg MW. Cont stage
up rpm to 120 rpm without surface wobble. Use MPD to mitigate gas over running shakers. Adjust flow rate to control over running shakers.. Back ream full stands.
Distance to WP06: 22.58 22.55' Low 1.12' Left 23 concretions for a total thickness of 97' (3.3% of the lateral). Footage OBd-2 Sand 1,456' OBd-3 1,183' Total
2,639'. Interlobe Clay 273' Daily Disposal to G&I 577 bbls, Total = 11109 bbls. Daily water from Lake 2: 700 bbls, Total = 10199 bbls. Daily Metal: 10 Total: 13.
Daily losses downhole bbls, Total = 0 bbls. Total Surface loss: 310 bbls.
10/4/2021 Drill 8.5" Production Hole F/ 10,734' to 11,340' MD ( 4,404' TVD) Total 606’ (AROP 101’) 400 GPM/ MPD 433, 1520 psi, 120 RPM, TRQ on 11-12k, TRQ off 10-
11k, WOB 5-14k. ECD 11.4. Max Gas 1648u. P/U 140k, SLK 77k, ROT 105k. MPD 170 PSI dynamic, static 100 PSI 10.1 ppg EMW W/ 9.45.ppg MW. started
seeing magnetic interference at 11109.21' MD survey point, but it was correctable. Drill ahead from 11,109' to 11,340'(231' w/o clean surveys), steering to the right
side of the plan to gain separation from the L-200, L-200L1 wellbores. Drill 8.5" Production Hole F/ 11,340' to 11,878' MD ( 4,411' TVD) Total 538’ (AROP 89’) 550
GPM/ MPD 560, 2430 psi, 120 RPM, TRQ on 13-14k, TRQ off 12k, WOB 5-12k. ECD 11.8. Max Gas 1674u. P/U 141k, SLK 77k, ROT 105k. MPD 100 PSI
dynamic, static 100 PSI 10.1 ppg EMW W/ 9.5.ppg MW. Continue Drill ahead from 11,,340' to 11,427'(87' )(318' total w/o clean surveys), steering to the right side
of the plan to gain separation from the L-200, L-200L1 wellbores. Obtain clean survey @ 11,427'. Drilled f/ 11,427' - 11,808' (381') before obtaing good survey @
11,808'. Bad @ 11872' We did exit the top of OBd-2 sand at 11220’. Continued dropping the inclination down to 89.0° and reentered OBd-2 sand at 11417' MD'
Drill 8.5" Production Hole F/ 11,878' to 12,278' MD (4,402' TVD) Total 400’ (AROP 66.7’) 525 GPM/ MPD 516, 2,305 psi, 120 RPM, TRQ on 12-13k, TRQ off 10-
12k, WOB 6-12k. ECD 11.82. Max Gas 1255u. P/U 140k, SLK 76k, ROT 102k. MPD 150 PSI dynamic, static 100 PSI 10.1 ppg EMW W/ 9.45.ppg MW. Drilling
ahead, building angle F/ 89° to 92° as per Geo. At 11,942' MD, survey after connection @11,872' had bad magnetics. Discuss with town and gaining further
distance to the right while drilling blind. Was told to try to keep in 100' Right or less, all depending on when we achieve clean surveys. At 12,070' MD, survey
@11,999' showed bad magnetics. Drill to 12,261' MD W/ bad surveys/magnetics, steering 30-50% right to get separation from offset well. Downlink 2 x survey
@12,191', magnetics was slightly out of spec. Discuss with town. Drill to 12,278' MD, downlink survey @12,208', Good Survey - 400' between clean surveys.
Continue drilling, building to 94.5° as per Geo, clean surveys. Start steering slight left to get back to plan azimuth and parallel plan. Start dropping to 93.5°
@12,371' per Geo. Drill 8.5" Production Hole F/ 12,278' to 12,961' MD (4,373' TVD) Total 683’ (AROP 113.8’) 450 GPM/ MPD 450, 1,940 psi, 120 RPM, TRQ on
11-12k, TRQ off 10-11k, WOB 2-6k. ECD 11.8. Max Gas 1678u. P/U 142k, SLK 67k, ROT 101k. MPD 150 PSI dynamic, static 100 PSI 10.1 ppg EMW W/
9.45.ppg MW. At 12,491' MD reduced rate to 500 gpm and dynamic mpd press F/ 150 to 125 psi due to ECD 12 EMW dropped it to 11.8 EMW. At 12,741' MD
reduced rate to 450 gpm due to ECD 11.96 EMW to 11.79 EMW. MPD dynamic F/ 125 to 150 psi to mitigate gas at shakers. Distance to WP06: 82.89' 12.84' Low
81.89' Right 32 concretions for a total thickness of 1' (2.2% of the lateral). Footage OBd-2 Sand 2,484' OBd-3 1,799' Total 4,283'. Interlobe Clay 839'. Total lateral:
5,122' Daily Disposal to G&I 635 bbls, Total = 11744 bbls. Daily water from Lake 2: 700 bbls, Total = 10899 bbls. Daily Metal: 12 Total: 25. Daily losses downhole
bbls, Total = 0 bbls. Total Surface loss: 310 bbls.
10/5/2021 Drill 8.5" Production Hole F/ 12,961' to 13,630' MD (4,370' TVD) Total 669’ (AROP 111.5’) 450 GPM/ MPD 475, 2,190 psi, 120 RPM, TRQ on 13-14k, TRQ off 12-
14k, WOB 5-14k. ECD 11.94. Max Gas 1725u. P/U 144k, SLK 63k, ROT 100k. MPD 150 PSI dynamic, static 100 PSI 10.1 ppg EMW W/ 9.45.ppg MW. Back ream
60' at connections. Drill 8.5" Production Hole F/ 13,630' to 14,220' MD (4,375' TVD) Total 590’ (AROP 98.4’) 475 GPM/ MPD 474, 2,290 psi, 120 RPM, TRQ on 14-
16k, TRQ off 14-15k, WOB 8-12k. ECD 12.2. Max Gas 1622u. P/U 154k, SLK 52k, ROT 100k. MPD 150 PSI dynamic, static 100 PSI 10.1 ppg EMW W/ 9.45.ppg
MW. Use MPD to mitigate gas at surface. Back ream 60' at connections. Drill 8.5" Production Hole F/ TD 14,220' to 14,700' MD (4,359' TVD) Total 480’ (AROP
73.9’) 450 GPM/ MPD 4450, 2,220 psi, 120 RPM, TRQ on 15-16k, TRQ off 14-16k, WOB 8-14k. ECD 12.33. Max Gas 1546u. P/U 145k, SLK 41k, ROT 95k. MPD
150 PSI dynamic, static 100 PSI 9.95 ppg EMW W/ 9.5.ppg MW. Finial surveys on bottom and set to home.
14,700' MD 4,358.37' TVD 90.74° in 308.98° Azi ROT & REC F/ 14,700' to 14,644' MD Pump tandem 35 bbl 9.0 ppg 38 Vis & 35 bbl 9.9 ppg 102 Vis sweeps.
Back on time W/ 10% inc. Open MPD choke 100% during circ. Max Gas 497u, BGG 210u. Stage up to 500 gpm/ mpd 497 2,480 psi 120 rpm Trq 14-15k ECD
11.85 ROT 99k. PJSM Perform displacement F/ 9.5 BaraDril N to 9.5 ppg QuickDril lubricated brine. Cont Rot & rec. Pump 40 bbl SAPP and 20 bbl 9.5 ppg
QuickDrill 3X spacers, chase with 9.5 ppg QuickDril lubricated brine at 336 gpm 1,290 psi. Distance to WP06: 12.45' 11.72' High 4.2' Right 36 concretions for a
total thickness of 125' (1.8% of the lateral). Footage OBd-2 Sand 3,188' OBd-3 2,683' Total 5,871'. Interlobe Clay 1,101'. Total lateral: 6,972' Daily Disposal to G&I
1099 bbls, Total = 12843 bbls. Daily water from Lake 2: 700 bbls, Total = 11599 bbls. Daily Metal: 4 Total: 29. Daily losses downhole bbls, Total = 0 bbls. Total
Surface loss: 310 bbls.
10/6/2021 Cont displacing to 9.5 ppg QuickDril lubricated brine. 336 gpm 915 psi 120 rpm trq 15-18k ECD 10.17 emw. ROT REC 14,700' to 14,644' md. Rot Rec F/ 14,700'
to 14,644' md 550 gpm 2,210 psi 120 rpm trq 11-13k ECD 10.6 emw. Clean surface pits and prep for BROOH. SPR's. p/u 148k slk 61k. Check well 10 min, static.
Close MPD and no press gain. PJSM BROOH F/ 14,700' to 14,089' MD 550 gpm/ mpd 485 2,250 psi 120 rpm Trq 11-14k ECD 11.1 Max Gas 22u P/U 160k SLK
41k ROT 102k MPD 100% open. Pull speed 20-30 ft/min. PJSM BROOH F/ 14,089' to 11,910' MD 550 gpm/ mpd 540 2,150 psi 120 rpm Trq 11-14k ECD 11.04
Max Gas 28u P/U 157k SLK 64k ROT 100k MPD 100% open. Pull speed 20-40 ft/min. F/ 12,310’ to 12,350’ MD Encountered high Trq, over pull and press spikes,
Worked 2X, good. PJSM BROOH F/ 11,910' to 10,786' MD 525 gpm/ mpd 520 1,760 psi 120 rpm Trq 11-14k ECD 10.58 Max Gas 1,162u BGG 100u P/U 158k
SLK 84k ROT 105k MPD 100% open. Pull speed 1-20 ft/min. F/ 11,761’ to 11,504’ MD & 11,015' to 11,000' MD. Encountered high trq & slight packing off.
Adjusting speed as hole dictates. Lost 66 bbls for tour. PJSM BROOH F/ 10,786' to 8,956' MD 525 gpm/ mpd 490 1,550 psi 120 rpm Trq 9-10k ECD 10.32 Max
Gas 1,088u BGG 75u P/U 150k SLK 84k ROT 108k MPD 100% open. Pull speed 1-20 ft/min. F/ 10,040' to 9,940' MD encountered high trq swings, packing off and
8-12k over pull. Reduced flow rate to 500 gpm, adjusting rpm 50-100 and pulling speed 1-4 ft min. Lost 8 bbls. Distance to WP06 : 12.45' 11.72' High 4.2' Right 36
concretions for a total thickness of 125' (1.8% of the lateral). Footage OBd-2 Sand 3,188' OBd-3 2,683' Total 5,871'. Interlobe Clay 1,101'. Total lateral: 6,972' Daily
Disposal to G&I 2124 bbls, Total = 14967 bbls. Daily water from Lake 2: 280 bbls, Total = 11879 bbls. Daily Metal: Total: 29. Daily losses downhole 70 bbls, Total
= 70 bbls. Total Surface loss: 310 bbls.
10/7/2021 Continue BROOH F/ 8956' - T/ 8257' MD. 525 gpm, 1500 psi, 120 rpm, 9k tq, 10.19 ECD's. 485 gpm out, 12-30 BGG. P/U 145k, S/O 95k, ROT 108k. Adjust
pulling speed 15-30 FPM. Pulled clean. Pull slow from 8257' to 8067' while circulating 2x BU @ max rates. 525 gpm, 1500 psi, 120 rpm, 8k tq. Sand back at
shakers. Cleaned up @ 1.5x BU. Obtained a passing PST (250u micron coupons). Backreamed into shoe F/ 8067' to 7621' MD at reduced rpms (80 rpm). Pulled
clean into shoe without issue. Circulated 2x BU inside shoe @ 7621' MD. Pumped 40 bbl hi/vis sweep. Back on time with no increase in cuttings. 525 gpm, 1500
psi. Shut down and monitor well (static). Pump CI dry job. PJSM, Drain stack. Pull RCD and install trip nipple as per Beyond MPD rep. Tq clamp. Install stripping
rubber, air slips and lineup on trip tank (CI fluid). Rack back from 7651' to 6676' MD. Continue POOH laying down remaining 5" S-135 NC50 drill pipe to 1,185'
md. Separate pipe for Cat V inspection and hard band. 9.5 MW. Continue POOH laying down remaining 5" S-135 NC50 drill pipe F/ 1,185' to 309' MD. Lost 15.9
bbls for trip. PJSM L/D 3 jnts 5" HWDP, 6.5" Jar, 3ea 6.75" NM FC, 2 ea 6.75" FS. Down load MWD. Cont L/D Integral Blade, TM, DM, PWD, DGR, ILS, ADR,
GeoPilot, NRP & 8.5" Bit as per DD & MWD. Bit Grade 1-1-WT-A-X-I-NO-TD. PJSM Clean and clear rig floor. Send down BHA components. PJSM Make up safety
jnt. 5" D.P. FOV & lift sub L/D in shed. C/O elevators 6.625" MYC 125T. Bring Weatherford 6.625" handling Equip to rig floor. R/U Weatherford power tongs.. PJSM
P/U 6.625" shoe W/ 2 centralizers and RIH W/ 6.625" 20# L-80 HYD 563 slotted liner to 484' MD. Trq 563 7100 ft/lb. PJSM Cont RIH W/ 6.625" 20# L-80 HYD 563
slotted liner F/ 484' to 7,855' MD. Pass through shoe at 7,728' without issue. Trq 563 7100 ft/lb. P/U 124k SLK 86k. Daily Disposal to G&I 172 bbls, Total = 15140
bbls. Daily water from Lake 2: 280 bbls, Total = 12079 bbls. Daily Metal: Total: 29. Daily losses downhole 41 bbls, Total = 111 bbls. Total Surface loss: 310 bbls.
10/8/2021 PJSM Cont RIH W/ 6.625" 20# L-80 HYD 563 slotted liner F/ 7855' to 8350' MD. M/U XO, 2ea 7"VamTop joints. Trq 563 7100 ft/lb. P/U 125k SLK 85k. C/O to 5"
handling equipment. M/U BOT SLZXP 9-5/8" x 7 liner hanger to 8482' MD. Obtain parameters 5,10,15 rpm with 6.5-6.9k tq on each. Pump thru @ 3 bpm, 95 psi.
P/U 125k, S/O 85k. Continue run 6.625" slotted liner conveyed on 5" NC50, S-135 drill pipe out of derrick F/ 8482' to 14,700' MD. Tag up on depth with liner @
14700' MD (15k tag). Verify pipe count (good). Drop 1.5" phenolic setting ball. Put liner on depth in tension (~ TOL @ 6232') parked @ 180k up. Pump ball dn @
2 bpm, 130 psi . Bumped @ 1075 stks (1698 stks calc). Pressure up to 3500 psi @ 1/2 BPM. Saw set @ 1878 psi, release shear @ 2440 psi then walk up to 3500
psi and hold 5 min. Bleed off psi. S/O to 55k and P/U (did not release liner). Wrk pipe from 181k up to blk wt 35k 2x times with no release from liner indicated.
R/U and test Annulus 1500 psi with 10 min hold (test good). 2.3 bbl in, 1.7 bbl bled back. Work pipe 8x 185k up to blk wt (35k) with no success releasing from
liner. Left hand off liner with 2.5 left hand turns (6k tq) and work pipe 3x before observing tq dump and free pipe with new up P/U wt @ 127k, S/O 105k. Rack back
1 stand to 6195' MD. Monitor well @ 6195' MD (Static). Service traveling equipment. Grease crown and inspect same. Svc "IR" and spinners. PJSM POOH L/D 5"
D.P. F/ 6,195' to 3,655' MD. P/U 115k SLK 102k Culling pipe for CAT 5 inspection. Lost 3.8 bbls. TIH 5" D.P. F/ Derrick F/ 3.655' to 5,820' MD. P/U 120k SLK
105k. No loss. PJSM Hang blocks. Cut 9 wraps (57') drilling line. ACCUM TM 26099. 1,596' left on spool. Set floor saver elevation position. Check crown and floor
saver. PJSM POOH L/D 5" D.P. F/ 5,820' to 3,537' MD. P/U 120k SLK 105k Culling pipe for CAT 5 inspection. Lost 3.8 bbls. Lost 8.2 bbls. Last drilling report.
Change to completion AFE at 00:00. Daily Disposal to G&I 57 bbls, Total = 15197 bbls. Daily water from Lake 2: 0 bbls, Total = 12079 bbls. Daily Metal: Total: 29.
Daily losses downhole 19 bbls, Total = 130 bbls. Total Surface loss: 310 bbls.
Activity Date Ops Summary
10/8/2021 PJSM POOH L/D 5" D.P. F/ 3,537' to running tool. L/D BOT running tool. Rupture disk sheared. Culling CAT 5 D.P. Lost 8 bbls.,PJSM Break down safety joint. Pull
wear ring and install test plug.,PJSM Drain stack. Bleed down Koomey. Remove UPR (VBR's) and install 7" Solid Body rams. SIMOPS R/U Weatherford 7"
handling Equip. C/O elevators to 7" 250T. R/U Power Tongs.,PJSM Install 7" test jnt. Flood lines. Test Annular 250/250 psi 5 min on chart.,Daily Disposal to G&I
57 bbls, Total = 15197 bbls. Daily water from Lake 2: 0 bbls, Total = 12079 bbls. Daily Metal: Total: 29. Daily losses downhole 19 bbls, Total = 130 bbls. Total
Surface loss: 310 bbls.
10/9/2021 Test upper pipe rams (fixed 7") 250/3000 psi w/ 5 min hold on each (test good). Chart and record same. Pull test plug. Had trouble removing test plug. Pulled free
and inspected at surface. Found small amount of aluminum debris around upper profile of plug. Assumed to be from surface shoe track. No other issues.,R/U
WOT 7" casing equipment equipped with tq turn . Verify pipe count (168 jts in shed). PJSM, M/U 7" tieback seal assy w/ 1" ports. Verify tq turn (good). RIH w/ 7",
26#, L-80 VAM Top to tag depth 6244.44' (~ TOL @ 6234'). Tagged No/Go 2x with 20k. Saw 3-4k seal drag after entering TOL. P/U 137k, S/O 105k,Psi up to 300
psi on annulus while landed out (confirm seals engaged). Calculate Spaceout. L/D tag jts #155, 154. M/U 7.86' pup under jt #153 . M/U hanger assy w/ landing
joint. Landout on depth .43' off no w/ 70k string wt on hanger. Ran a total of 151 jts w/ 1x pup. Shoe @ 6244.01' MD.,PJSM R/U Displace reverse Circ 170 bbls
9.5 ppg 2% KCL Corrosion Inhibited Brine F/ Vac Truck @ 5 bpm ICP 335 psi FCP 220 psi. Swap over to LRS. PT lines 3,000 psi. Pump 52 bbls Diesel Freeze
Protect @ 2 bpm ICP 450 psi FCP 289 psi. SIMOPS Clear rig floor 7" handling Equip.,Strip down through Annular and land fluted 7" Hanger. Bleed down system.
RILDS as per Vault rep onsite. L/D Landing Jnt. C/O elevators to 5". M/U running tool and pack off. Set pack off as per rep RILDS.PT void 5,000 psi 10 min.,PJSM
R/U to 9.625" X 7", Test to 1,500 psi for 30 min on chart, good. Pump 1.8 bbls, bled 1.8 bbls. R/D test Equip.,PJSM Break down 7" X/O and TIW. C/O elevators to
4.5" YC 75T. R/U Power Tongs.,PJSM P/U M/U Baker Loc WLEG, X Nipple (RHC-M-X-Lock) Single 4.5" 12.6# L-80 Vam, X Nipple, Single jnt and Halliburton
TNT Packer 143' MD. Cont RIH W/ 4.5" 12.6# L-80 Vam Top with remaining jewelry as per tally to 4,230' MD. Torque Turn 4400 ft/lb. P/U 63k SLK 59k,Daily
Disposal to G&I 164 bbls, Total = 15361 bbls. Daily water from Lake 2: 0 bbls, Total = 12079 bbls. Daily Metal: Total: 29. Daily losses downhole 13.5 bbls, Total =
143.5 bbls. Total Surface loss: 310 bbls.
10/10/2021 Continue RIH w/ 4.5" VAM Top, 12.6#, L-80 F/ 4230' - T/ 6390' MD. M/U hanger assy w/ landing joint. Landout with final set depth of 6416'.28' MD. P/U 85k, S/O
68k. 33k string wt on hanger. RILDS. Install modified BPV. 6 bbl loss for trip.,Clean and clear rig floor. Flush surface equipment with heated soap water. B/D all
lines. C/O upper rams to 2-7/8"x5-1/2" VBR's. Inspect lower VBR's (C/O top seal on ODS).,N/D 13-5/8" 5M BOP's. N/D 4 pt, drip pan, and install test cap on RCD.
L/D mousehole. Hook up cellar bridge cranes to stack. N/D choke and kill lines. N/D koomey lines and unflange from wellhead. Rack back and secure stack on
stump in cellar. Sym Ops - Clean pits. R/D MP's and inspect same.,Install tbg adapter dry hole tree. Test void 250/5000 w/ 10 min hold (test good). Install CTS
and test tree 250/5000 with 10 min hold (test good). Sym Ops - Cont clean pits. Inspect MP's. Unhang bridle lines and prep rig floor to scope down. Inspect TDS
coffin.,PJSM Pull CTS. R/U hardline manifold. Freeze Protect. Reverse Circ down IA 7" X 4.5" up through 4.5" tubing W/ LRS. Pump 70 bbls Diesel 2 bpm ICP 112
psi FCP 446 psi. Shut down and U Tube for 1 hr. SIMOPS Cont cleaning pits and inspecting MP's.,PJSM R/D hard lines and take off Otis. M/U ball and rod
launcher. Drop 1 7/8" Ball rod W/ 5 1 1/2" rollers, missing 1 roller. Length 9'. Wait for ball & rod to fall. R/D L/D ball & rod launcher. R/U hard lines and Otis.
SIMOPS C/O Wash Pipe.,PJSM LRS PT lines 4,500 psi. Press up 4.5" tubing (caught Press right away) .25 bpm up to 3,616 psi packer set. Hold for 30 min initial
15 min lost 89 psi, after 30 min fell below 3,500 psi. bleed down lines. Pumped 1.2 bbls bled 1.2 bbls. Press up to 3,688 psi 15 min 3,634 psi 30 min 3,611 psi
passed. Pumped 0.6 bbls.,Bled 4.5" tubing to 1,997 psi. Press IA 7"X 4.5" to 3,662 psi Tub 2,583 psi, pumped 1.94 bbl15 min 3,609 psi, Tub 2,598 psi, 30 min
3,594 psi Tub 2,599 psi passed. Bleed down IA to 2,000 psi open up tubing and bleed down both. Bled back 2.9 bbls. R/D LRS. Daily Disposal to G&I 126 bbls,
Total = 15487 bbls. Daily water from Lake 2: 0 bbls, Total = 12079 bbls. Daily Metal: Total: 29. Daily losses downhole 6 bbls, Total = 150 bbls. Total Surface loss:
310 bbls.
10/11/2021 SIMOPS Install new Wash Pipe. Release rig at 02:00,SIMOPS R/D Inner conects, Secure Iron Roughneck. Remove wings F/ pipe skate. Safe out stairs. PJSM
Load 5" D.P. in pipe shed. Remove Beyond Equip and choke house. Move diverter tee in cellar and secure. Bridle up and scope down derrick. Open coffin on top
drive, change gear oil and filter. Blow down H2O and steam. Remove cutting box. Stage break shack & enviro vac. Swap to cold start. Install jeep on Gen Mod.
50-029-23699-00-00API #:
Well Name:
Field:
County/State:
PBW L-206
Prudhoe Bay West
Hilcorp Energy Company Composite Report
, Alaska
9/22/2021Spud Date:
TD Shoe Depth: PBTD:
No. Jts. Returned
RKB RKB to BHF RKB to THF
Jts.
2
3
123
61
Yes X No X Yes No 5.4
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:X Yes No
Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job
Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Post Job Calculations:
Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped:
Cmt returned to surface: Calculated cement left in wellbore:
OH volume Calculated: OH volume actual: Actual % Washout:
Casing (Or Liner) Detail
Float Shoe
RKB
10 3/4
526 22461.4SECOND STAGE1
5:10
Surface
Rotate Csg Recip Csg Ft. Min. PPG9.8
Shoe @ 7728 FC @ Top of Liner7,605.00
Floats Held
462 847
311.5 535.5
Spud Mud
CASING RECORD
County State Alaska Supv.J Lott / C Montague
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.PBW L-206 Date Run 28-Sep-21
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
TCP BTC Innovex 1.88 7,727.72 7,725.84
26.95
Csg Wt. On Hook:282,000 Type Float Collar:Conventional No. Hrs to Run:24
9.8 7
1620
10
10.7 400 5.5
100
460
Bump Plug?FIRST STAGE10Tuned Spacer Red Dye/ 5# Poly Flake 55
15.8
517
3.2
9.8 6 164.4/264.5
356/356
0
1
15.8 80
Bump pressBump Plug?
0
2512
7,728.007,741.00
CEMENTING REPORT
Csg Wt. On Slips:30,000
Spud Mud
Tuned Spacer Red Dye/ 5# Poly Flake
779 2.88
Stage Collar @
50
Bump press
100
311.5
ES Cementer Closure OK
57
12 310
26.95 RKB to CHF
Type of Shoe:Conventional Casing Crew:Weatherford
No. Jts. Delivered 195 No. Jts. Run 186 9
Length Measurements W/O Threads
Ftg. Delivered 7,995.00 Ftg. Run 7,728.00 Ftg. Returned 267.00
Ftg. Cut Jt.33.50 Ftg. Balance
www.wellez.net WellEz Information Management LLC ver_04818br
3.5
ArcticCem
Type
Shoe Jnt 2 ea 10' F/ end, 1 ea 2 nd & 3rd jnt, 1 ea F/ jnt 4 to 26, every other jnt F/ 29 to 49, Every 3rd jnt F/ 52 to 61, 6
ffS / C // /
9.625 CSG 9 5/8 40.0 L-80 TCP BTC Tenaris 79.93 7,725.84 7,645.91
Float Collar 10 3/4 TCP BTC Innovex 6.20 7,645.91 7,639.71
9.625 CSG 9 5/8 40.0 L-80 TCP BTC Tenaris 32.89 7,639.71 7,606.82
Baffle Adapter 10 3/4 TCP BTC Halliburton 1.42 7,606.82 7,605.40
9.625 CSG 9 5/8 40.0 L-80 TCP BTC Tenaris 5,073.14 7,605.40 2,532.26
Pup 9 5/8 40.0 L-80 TCP BTC Tenaris 17.06 2,532.26 2,515.20
ES Cementer 11 3/4 TCP BTC Halliburton 2.82 2,515.20 2,512.38
Pup 9 5/8 40.0 L-80 TCP BTC Tenaris 17.18 2,512.38 2,495.20
9.625 CSG 9 5/8 47.0 L-80 VAM Tenaris 2,468.25 2,495.20
ArcticCem 728 2.35
Tyoe I / II 400 1.15
4.5
Type I / II 270 1.17
9/30/2021 0
Spud Mud
18:54 9/29/2021
550 psi
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Chelsea Wright Digitally signed by Chelsea Wright
Date: 2021.10.06 11:38:31 -08'00'Benjamin Hand Digitally signed by Benjamin Hand
Date: 2021.10.11 10:37:39 -08'00'
David Douglas Hilcorp Alaska, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 10/19/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
PBU L-206 (PTD 221-068)
FINAL LWD FORMATION EVALUATION LOGS (09/22/2021 to 10/06/2021)
x ROP, AGR, DGR, ABG, EWR-M5, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
x EOW Report and Geosteering
SFTP Transfer – Main Folders:
LWD Subfolder:
Geosteering Subfolder: g
Please include current contact information if different from above.
Received By:
10/19/2021
37'
(6HW
By Abby Bell at 4:31 pm, Oct 19, 2021
David Douglas Hilcorp Alaska, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 10/19/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
PBU L-206 (PTD 221-068)
FINAL LWD FORMATION EVALUATION LOGS (09/22/2021 to 10/06/2021)
x ROP, AGR, DGR, ABG, EWR-M5, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
x EOW Report and Geosteering
SFTP Transfer – Main Folders:
LWD Subfolder:
Geosteering Subfolder: g
Please include current contact information if different from above.
Received By:
10/19/2021
37'
(6HW
By Abby Bell at 4:31 pm, Oct 19, 2021
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M. Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Re: Prudhoe Bay Field, Schrader Bluff Oil Pool, Orion Development Area, PBU L-206
Hilcorp Alaska, LLC
Permit to Drill Number: 221-068
Surface Location: 2509' FSL, 3933' FEL, Sec. 34, T12N, R11E, UM, AK
Bottomhole Location: 1395' FSL, 1536' FWL, Sec. 21, T12N, R11E, UM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Jeremy M. Price
Chair
DATED this ___ day of 6HSWHPEHU, 2021.
Jeremy
Price
Digitally signed by
Jeremy Price
Date: 2021.09.02
09:53:19 -08'00'
1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for:
Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates
Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas
2. Operator Name: 5. Bond: Blanket Single Well 11. Well Name and Number:
Bond No.
3. Address:6. Proposed Depth:12. Field/Pool(s):
MD: 14,705' TVD: 4,371'
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): 70.7'15.Distance to Nearest Well Open
Surface: x-582982 y-5978229 Zone- 4 44.2' to Same Pool: 1,200'
16.Deviated wells: Kickoff depth: 700 feet 17.Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 92 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
Driven 20" 129.5# X-52 80' Surface Surface 110' 110'
47# L-80 DWC 2,500' Surface Surface 2,500' 2,113'
40# L-80 Vam 21 5,188' 2,500' 2,113' 7,688' 4,480'
Tieback 7" 26# L-80 Vamtop 7,538' Surface Surface 7,538' 4,465'
8-1/2" 6-5/8" 20# L-80 Hyd 563 7,167' 7,538' 4,465' 14,705 4,371'
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
PBU L-206
Prudhoe Bay Field
Orion Oil Pool
Cement Quantity, c.f. or sacks
Commission Use Only
See cover letter for other
requirements.
Total Depth MD (ft): Total Depth TVD (ft):
22224484
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
Stg 2 L - 1935 ft3 / T - 313 ft3
1521
2288' FSL, 1717' FWL, Sec. 27, T12N, R11E, UM, AK
1395' FSL, 1536' FWL, Sec. 21, T12N, R11E, UM, AK
00-001
3800 Cenerpoint Drive, Suite 1400, Anchorage, AK, 99503
Hilcorp North Slope, LLC
2509' FSL, 3933' FEL, Sec. 34, T12N, R11E, UM, AK ADL 028239 & 47447
5120
18.Casing Program: Top - Setting Depth - BottomSpecifications
1969
(including stage data)
Stg 1 L - 1704 ft3 / T - 458 ft3
Authorized Title:
Authorized Signature:
Production
Liner
Intermediate
Authorized Name:
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):
Effect. Depth MD (ft):
Conductor/Structural
Length
September 18, 2021
9,167'
12-1/4" 9-5/8"
Uncemented Tieback
Uncemented Slotted Liner
Effect. Depth TVD (ft):
Casing Cement Volume MDSize
Plugs (measured):
o
o
o
o
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
8.24.2021
By Samantha Carlisle at 7:54 am, Aug 25, 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: 2021.08.24 16:04:32 -08'00'
Monty M
Myers
SFD 8/25/2021
BOPE test to 3000 psi. Annular to 2500 psi.
SFD 8/25/2021 DSR-8/25/21
Schrader Bluff Oil Pool, Orion Development Area
221-068
MGR30AUG2021
SFD 8/25/2021107205344
50-029-23699-00-00
dts 8/31/2021
9/2/21
Jeremy Price Digitally signed by Jeremy Price
Date: 2021.09.02 09:55:16 -08'00'
Prudhoe Bay West
(PBU) L-206
Drilling Program
Version 1
8/24/2021
Table of Contents
1.0 Well Summary ................................................................................................................................. 2
2.0 Management of Change Information ............................................................................................ 3
3.0 Tubular Program: ........................................................................................................................... 4
4.0 Drill Pipe Information: ................................................................................................................... 4
5.0 Internal Reporting Requirements ................................................................................................. 5
6.0 Planned Wellbore Schematic ......................................................................................................... 6
7.0 Drilling / Completion Summary .................................................................................................... 7
8.0 Mandatory Regulatory Compliance / Notifications ..................................................................... 8
9.0 R/U and Preparatory Work ......................................................................................................... 10
10.0 N/U 13-5/8” 5M Diverter System ................................................................................................. 11
11.0 Drill 12-1/4” Hole Section ............................................................................................................. 13
12.0 Run 9-5/8” Surface Casing ........................................................................................................... 16
13.0 Cement 9-5/8” Surface Casing ..................................................................................................... 22
14.0 ND Diverter, NU BOPE, & Test .................................................................................................. 27
15.0 Drill 8-1/2” Hole Section ............................................................................................................... 28
16.0 Run 6-5/8” Slotted Liner .............................................................................................................. 33
17.0 Run 7” Tieback ............................................................................................................................. 37
18.0 Run Upper Completion – Gas Lift .............................................................................................. 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 .................................................................................................................. 51
26.0 FIT Procedure ............................................................................................................................... 52
27.0 Innovation Rig Choke Manifold Schematic ................................................................................ 53
28.0 Casing Design ................................................................................................................................ 54
29.0 8-1/2” Hole Section MASP ........................................................................................................... 55
30.0 Spider Plot (NAD 27) (Governmental Sections) ......................................................................... 56
31.0 Surface Plat (As Built) (NAD 27) ................................................................................................. 57
32.0 Offset Wells TVD MW ................................................................................................................. 58
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L-206 SB Producer
Drilling Procedure
1.0 Well Summary
Well PBU L-206
Pad Prudhoe Bay L Pad
Planned Completion Type Gas Lift on 4-1/2” Tubing
Target Reservoir(s) Schrader Bluff OBd Sand
Planned Well TD, MD / TVD 14,704’ MD / 4,370’ TVD
PBTD, MD / TVD 14,694’ MD / 4,370’ TVD
Surface Location (Governmental) 2509' FSL, 3933' FEL, Sec 34, T12N, R11E, UM, AK
Surface Location (NAD 27) X= 582982.15, Y= 5978228.79
Top of Productive Horizon
(Governmental) 2288' FSL, 1717' FWL, Sec 27, T12N, R11E, UM, AK
TPH Location (NAD 27) X= 583286.57, Y= 5983290.42
BHL (Governmental) 1395' FSL, 1536' FWL, Sec 21, T12N, R11E, UM, AK
BHL (NAD 27) X= 577769, Y= 5987618
AFE Number 211-00050
AFE Drilling Days 20
AFE Completion Days 4
Maximum Anticipated Pressure
(Surface) 1521 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 1969 psig
Work String 5” 19.5# S-135 NC 50
Innovation KB Elevation above MSL: 26.5 ft + 44.2 ft = 70.7 ft
GL Elevation above MSL: 44.2 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
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L-206 SB Producer
Drilling Procedure
2.0 Management of Change Information
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L-206 SB Producer
Drilling Procedure
3.0 Tubular Program:
Hole
Section
OD (in) ID
(in)
Drift
(in)
Conn OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 20” 19.25” - - - X-52 Weld
12-1/4” 9-5/8” 8.835” 8.679” 10.625” 40 L-80 DWC 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 VAMTOP 7,240 5,410 604
8-1/2” 6-5/8” 6.049 5.924 7.390 20 L-80 Hydril 563 6090 3470 459
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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L-206 SB Producer
Drilling Procedure
5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on WellEz.
x Report covers operations from 6am to 6am
x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left
of the data entry area – this will not save the data entered, and will navigate to another data entry.
x Ensure time entry adds up to 24 hours total.
x Try to capture any out of scope work as NPT. This helps later on when we pull end of well
reports.
x Enter the MD and TVD depths EVERY DAY whether you are making hole or not.
5.2 Afternoon Updates
x Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers@hilcorp,
nathan.sperry@hilcorp.com, jengel@hilcorp.com and joseph.lastufka@hilcorp.com
5.3 Intranet Home Page Morning Update
x Submit a short operations update each morning by 7am on the company intranet homepage. On
weekend and holidays, ensure to have this update in before 5am.
5.4 EHS Incident Reporting
x Health and Safety: Notify EHS field coordinator.
x Environmental: Drilling Environmental Coordinator
x Notify Drilling Manager & Drilling Engineer on all incidents
x Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
x Send final “As-Run” Casing tally to mmyers@hilcorp,com jengel@hilcorp.com and
joseph.lastufka@hilcorp.com
5.6 Casing and Cement report
x Send casing and cement report for each string of casing to mmyers@hilcorp.com
jengel@hilcorp.com and joseph.lastufka@hilcorp.com
5.7 Hilcorp Milne Point Contact List:
Title Name Work Phone Cell Phone Email
Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmyers@hilcorp.com
Drilling Engineer Joe Engel 907.777.8395 805.235.6265 jengel@hilcorp.com
Drilling Engineer Nate Sperry 907.777.8450 907.301.8996 nathan.sperry@hilcorp.com
Completion Engineer Brodie Wages 907.564.5006 713.380.9836 david.wages@hilcorp.com
Geologist Kevin Eastham 907.777.8316 907.360.5087 keastham@hilcorp.com
Reservoir Engineer Michael Mayfield 907.564.5097 713.205.0533 mmayfield@hilcorp.com
Drilling Env. Coordinator Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com
EHS Manager Carl Jones 907.777.8327 907.382.4336 cajones@hilcorp.com
Drilling Tech Joe Lastufka 907.777.8400 907.227.8496 Joseph.Lastufka@hilcorp.com
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L-206 SB Producer
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6.0 Planned Wellbore Schematic
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L-206 SB Producer
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7.0 Drilling / Completion Summary
PBU L-206 is a grassroots producer planned to be drilled in the Schrader Bluff OBd sand. L-206 is part of a
multi well program targeting the Schrader Bluff sand on PBU L-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 6-5/8” liner will be run in the open hole section and
the well will be produced with a gas lift completion
The Innovation Rig will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately Sept 18, 2021, pending rig schedule.
Surface casing will be run to 7,687’ MD / 4,480’ 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 6-5/8” 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. On Site geologist. LWD: GR + Res
2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering)
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8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations,
specific regulations are listed below. If additional clarity or guidance is required on how to comply with
a specific regulation, do not hesitate to contact the Anchorage Drilling Team.
x BOPs shall be tested at (2) week intervals during the drilling and completion of PBU L-206. Ensure
to provide AOGCC 24 hrs notice prior to testing BOPs.
x The initial test of BOP equipment will be to 250/3,000 psi & subsequent tests of the BOP equipment
will be to 250/3,000 psi for 5/5 min (annular to 50% rated WP, 2,500 psi on the high test for initial
and subsequent tests). Confirm that these test pressures match those specified on the APD.
x If the BOP is used to shut in on the well in a well control situation or control fluid flow from the
well bore, AOGCC is to be notified and we must test all BOP components utilized for well control
prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP
test.
x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program
and drilling fluid system”.
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”.
o Ensure the diverter vent line is at least 75’ away from potential ignition sources
x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
x Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing, “A casing pressure test
must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a
minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test
pressure must show stabilizing pressure and may not decline more than 10 percent within 30
minutes. The results of this test and any subsequent tests of the casing must be recorded as required
by 20 AAC 25.070(1)”.
AOGCC Regulation Variance Requests:
x No variance requests at this time.
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Drilling Procedure
Summary of Innovation BOP Equipment & Test Requirements
Hole Section Equipment Test Pressure (psi)
12-1/4” x 13-5/8” 5M CTI Annular BOP w/ 16” diverter line Function Test Only
8-1/2”
x 13-5/8” x 5M Control Technology Inc Annular BOP
x 13-5/8” x 5M Control Technology Inc Double Gate
o Blind ram in btm cavity
x Mud cross w/ 3” x 5M side outlets
x 13-5/8” x 5M Control Technology Single ram
x 3-1/8” x 5M Choke Line
x 3-1/8” x 5M Kill line
x 3-1/8” x 5M Choke manifold
x Standpipe, floor valves, etc
Initial Test: 250/3,000
Subsequent Tests:
250/3,000
Primary closing unit: Control Technology Inc. (CTI), 6 station, 3,000 psi, 220 gallon accumulator unit.
Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an electric
triplex pump on a different electrical circuit and emergency pressure is provided by bottled nitrogen.
The remote closing operator panels are located in the doghouse and on accumulator unit.
Required AOGCC Notifications:
x Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
x 24 hours notice prior to spud.
x 24 hours notice prior to testing BOPs.
x 24 hours notice prior to casing running & cement operations.
x Any other notifications required in APD.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email: jim.regg@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email: Victoria.loepp@alaska.gov
Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email: melvin.rixse@alaska.gov
Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov
Test Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
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Drilling Procedure
9.0 R/U and Preparatory Work
9.1 L-206 will utilize a newly set 20” conductor on L-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 (<80 qF).
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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L-206 SB Producer
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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. 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 3 rd 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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L-206 SB Producer
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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. Directoinal 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). Be prepared for hydrates:
x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD
x Monitor returns for hydrates, checking pressurized & non-pressurized scales
x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by
washing out additional permafrost. Attempt to control drill (150 fph MAX) through the
zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be
reduced to prevent mud from belching over the bell nipple.
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.
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.
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Drilling Procedure
x Casing Running: Reduce system YP with DESCO as required for running casing as
allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and
swab pressures. Reduce the system rheology once the casing is landed to a YP < 20
(check with the cementers to see what YP value they have targeted).
System Type: 8.8 – 9.5 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 2,000’ of casing 47# drift 8.525”
x Be sure to count the total # of joints on the location before running.
x Keep hole covered while 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
2500'
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Drilling Procedure
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 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).
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 DWC MUT:
Casing OD Minimum Optimum Maximum
9-5/8” 29,800 ft-lbs - 34,800 ft-lbs
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Drilling Procedure
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12.8 Continue running 9-5/8” surface casing
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Drilling Procedure
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 2,000’ of 9-5/8” will be 47#, from 2,000’ to Surface
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.
2500'
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L-206 SB Producer
Drilling Procedure
13.0 Cement 9-5/8” Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
x Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks.
x Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
x Review test reports and ensure pump times are acceptable.
x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
13.2 Document efficiency of all possible displacement pumps prior to cement job.
13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
13.5 Fill surface cement lines with water and pressure test.
13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below
calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached.
13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead &
tail, TOC brought to stage tool.
Estimated 1st Stage Total Cement Volume:
Section Calculation Vol (bbl)Vol (ft3)
12-1/4" OH x 9-5/8" Casing (7,689' - 1,000' - 2,500') x 0.0558 bpf X 1.3 = 303.8 1704.2
Total Lead 303.8 1704.2
12-1/4" OH x 9-5/8" Casing 1000' x 0.0558 bpf x 1.3 = 72.5 406.8
9-5/8" Shoetrack 120' x 0.0758 bpf = 9.1 51.0
Total Tail 81.6 457.8Tail Lead
726 sx
395 sx
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Prudhoe Bay West
L-206 SB Producer
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:
7,569’ x .0758 bpf = 573.7 bbls
80 bbls of tuned spacer to be left behind stage tool
13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any
point during the job. Be prepared to pump out fluid from cellar. Have black water available to
contaminate any cement seen at surface.
13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over
displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling
Engineer.
13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening
plug is available if needed. This is the back-up option to open the stage tool if the plugs are not
bumped.
13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened.
Lead Slurry Tail Slurry
Density 12.0 lb/gal 15.8 lb/gal
Yield 2.35 ft3/sk 1.16 ft3/sk
Mix Water 13.92 gal/sk 4.98 gal/sk
(2500 * .0732) + ((7688 -120-2500) * .0758)= 567.2 bbl
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Prudhoe Bay West
L-206 SB Producer
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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Drilling Procedure
Second Stage Surface Cement Job:
13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive
strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre-job safety
meeting.
x Past wells have seen pressure increase while circulating through stage tool after reduced
rate
13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing
head.
13.20 Fill surface lines with water and pressure test.
13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.22 Mix and pump cmt per below recipe for the 2 nd stage.
13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail).
Job will consist of lead & tail, TOC brought to surface. However cement will continue to be
pumped until clean spacer is observed at surface.
Estimated 2nd Stage Total Cement Volume:
Cement Slurry Design (2nd stage cement job):
Lead Slurry Tail Slurry
System Permafrost L G
Density 10.7 lb/gal 15.8 lb/gal
Yield 4.41 ft3/sk 1.17 ft3/sk
Mixed
Water
22.02 gal/sk 5.08 gal/sk
270 sx
437 sx
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Prudhoe Bay West
L-206 SB Producer
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 0.0758 bpf = 190 bbls mud
13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side
outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out
fluid from cellar. Have black water available to retard setting of cement.
13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should
circulate approximately 100 - 150 bbls of cement slurry to surface.
13.29 Land closing plug on stage collar and pressure up to 1,000 – 1,500 psi to ensure stage tool closes.
Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool
has closed. Slips will be set as per plan to allow full annulus for returns during surface cement
job. Set slips.
13.30 Make initial cut on 9-5/8” final joint. L/D cut joint. Make final cut on 9-5/8”. Dress off stump.
Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule.
Ensure to report the following on wellez:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
x Note calculated top of cement
x Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to jengel@hilcorp.com and
joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the
AOGCC.
2500 * .0732 = 183 bbls
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Prudhoe Bay West
L-206 SB Producer
Drilling Procedure
14.0 ND Diverter, NU BOPE, & Test
14.1 ND the diverter T, knife gate, diverter line & NU 11” x 13-5/8” 5M casing spool.
14.2 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
14.3 RU MPD RCD and related equipment
14.4 Run 5” BOP test plug
14.5 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
14.6 RD BOP test equipment
14.7 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.8 Mix 8.9 ppg Baradrill-N fluid for production hole.
14.9 Set wearbushing in wellhead.
14.10 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole
section.
14.11 Ensure 5” liners in mud pumps.
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L-206 SB Producer
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.
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
Casing test and FIT digital data to AOGCC.
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L-206 SB Producer
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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Prudhoe Bay West
L-206 SB Producer
Drilling Procedure
15.11 TIH with 8-1/2” directional assembly to bottom
15.12 Install MPD RCD
15.13 Displace wellbore to 8.9 ppg Baradrill-N drilling fluid
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 OB Concretions: 4-6% Historically
x MPD will be utilized to monitor pressure build up on connections.
x 8-1/2” Lateral A/C:
x L-200 & L-200L1 CF < 1.0: These laterals have been abandoned. The purpose of L-206
well is to replace the lateral of L-200 in the OBd sand. There is no HSE risk with this well.
15.15 Reference: Halliburton has a procedure for Schrader OH sidetracks based on lessons
learned and best practices. Ensure the DD is referencing their procedure.
x Patience is key! Getting kicked off too quickly might have been the cause of failed liner
runs on past wells.
x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so
we have a nice place to low side.
x Attempt to lowside in a fast drilling interval where the wellbore is headed up.
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.
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Drilling Procedure
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. After 1 (or more if needed) BU,
Perform production screen test (PST). The brine has been properly conditioned when it will pass
the production screen test (x3 350 ml samples passing through the screen in the same amount
of time which will indicate no plugging of the screen). Reference PST Test Procedure
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.
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Drilling Procedure
x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as
dictated by hole conditions
x If backreaming operations are commenced, continue backreaming to the shoe
15.20 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while
BROOH.
15.21 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps.
15.22 Monitor well for flow/pressure build up with MPD. Increase fluid weight if necessary.
x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to
determine if well is breathing, treat all flow as an influx until proven otherwise
x If necessary, increase MW at shoe for any higher than expected pressure seen
x Ensure fluid coming out of hole has passed a PST at the possum belly
15.23 POOH and LD BHA.
15.24 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit
diameter is sufficient for future ball drops.
Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any
additional logging runs conducted.
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Prudhoe Bay West
L-206 SB Producer
Drilling Procedure
16.0 Run 6-5/8” Slotted Liner
16.1 Well control preparedness: In the event of an influx of formation fluids while running the 6-
5/8” slotted liner, the following well control response procedure will be followed:
x P/U & M/U the 5” safety joint (with 6-5/8” crossover installed on bottom, TIW valve in open
position on top, 6-5/8” handling joint above TIW). This joint shall be fully M/U and
available prior to running the first joint of 6-5/8” slotted 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 6-5/8” liner running equipment.
x Ensure 6-5/8” 20# Hydril 563 x DS-50 crossover is on rig floor and M/U to FOSV.
x Ensure all casing has been drifted on the deck prior to running.
x Be sure to count the total # of joints on the deck before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
16.3 Run 6-5/8” slotted production liner
x Use API Modified or “Best O Life 2000 AG” thread compound. Dope pin end only w/ paint
brush. Wipe off excess.
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Run float shoe on bottom
x 6-5/8” Liner will auto fill
x 6-5/8” Liner will be centralized, 1/jt free floating
x Install liner as per the Running Order (From Completion Engineer post TD).
x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint
outside of the surface shoe. This is to mitigate difference sticking risk while running inner
string.
x Obtain up and down weights of the liner before entering open hole. Record rotating torque at
10 and 20 rpm
6-5/8” 20 # Hydril 563 Torque
OD Minimum Optimum Maximum Yield Torque
6-5/8 5,900 ft-lbs 7,100 ft-lbs 10,300 ft-lbs 36,000 ft-lbs
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L-206 SB Producer
Drilling Procedure
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Drilling Procedure
16.6. Ensure to run enough liner to provide for sufficient overlap inside 9-5/8” casing for gas lift
completion. Ensure hanger/pkr will not be set in a 9-5/8” connection.
x L-206 ~ liner top packer depth 6700’ MD. Confirm with Completion Engineer
x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as
per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8” connection.
16.7. Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck
to make sure it coincides with the pipe tally.
16.8. M/U Baker SLZXP liner top packer to 6-5/8” liner.
x Confirm with OE any 7” joints between liner top packer and 6-5/8” liner for GLM
and packer setting depth
16.9. Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner
hanger to ensure a clear flow path exists.
16.10. RIH with liner no faster than 30 ft/min – this is to prevent buckling the liner and drill string and
weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and
avoid surging the hole or buckling the liner. Slow down running speed if necessary.
x Ensure 5” DP/HWDP has been drifted
x There is no inner string planned to be run, as opposed to previous wells. The DP should auto
fill. Monitor FL and if filling is required due to losses/surging.
16.11. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe
depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to
bottom.
16.12. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
& 20 RPM.
16.13. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
16.14. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
16.15. Rig up to pump down the work string with the rig pumps.
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Drilling Procedure
16.16. Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed
1,600 psi while circulating. Pusher tool is set at 2,100 psi with 5% shear screws but it should be
discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker
16.17. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill
pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger.
16.18. Shut down pumps. Drop setting ball (ball seat now located in HRDE setting tool and not at the
WIV) down the workstring and pump slowly (1-2 BPM). Slow pump before the ball seats. Do
not allow ball to slam into ball seat.
16.19. Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes.
Slack off 20K lbs on the SZXP liner hanger/packer to ensure the HRDE setting tool is in
compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi
to release the HRDE running tool.
16.20. Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without
pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20
RPM and set down 50K again.
16.21. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted.
16.22. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If
packer did not test, rotating dog sub can be used to set packer. If running tool cannot be
hydraulically released, apply LH torque to mechanically release the setting tool.
16.23. PU pulling running tool free of the packer and displace with at max rate to wash the liner top.
Pump sweeps as needed.
16.24. POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned,
LD DP on the TOOH.
Note: Once running tool is LD, swap to the completion AFE.
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L-206 SB Producer
Drilling Procedure
17.0 Run 7” Tieback
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 VAMTOP Gas tight tieback to position seal assembly two joints above
tieback sleeve. Record PU and SO weights.
7”, 26#, L-80, VAMTOP
=
Casing OD Torque (Min) Torque (Opt) Torque (Max)
7” 10,850 ft-lbs 11,950 ft-lbs 13,050 ft-lbs
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L-206 SB Producer
Drilling Procedure
Page 39
Prudhoe Bay West
L-206 SB Producer
Drilling Procedure
17.7 MU 7” to DP crossover.
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 1,000 psi for 30 minutes charted.
1500 psi per AOGCC
Page 40
Prudhoe Bay West
L-206 SB Producer
Drilling Procedure
18.0 Run Upper Completion – Gas Lift
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 XT-39 crossover is on rig floor and M/U to FOSV.
x Ensure all tubing has been drifted in the pipe shed prior to running.
x Be sure to count the total # of joints in the pipe shed before running.
x Keep hole covered while RU casing tools.
x Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info.
x Monitor displacement from wellbore while RIH.
18.2 PU, MU and RH with the following 4-1/2” GL completion jewlery (tally to be provided by
Operations Engineer):
x Tubing Jewelry to include:
x 4x ‘X’ Nipple
x 4x GLM
x 1x WLEG
x 1x Packer
x XXX joints, 4-1/2”, 12.6#, L-80, VAMTOP
18.3 PU and MU the 4-1/2” tubing hanger. Make final splice of any TEC wire used and ensure any
unsued control line ports are dummied off.
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 diesel freeze protect
to 2,500’ MD.
18.11 Drop the ball & rod.
18.12 Pressure up on the tubing to 3,500 psi to set the packer. PT the tubing to 3,500 psi for 30
minutes (charted).
18.13 Bleed the tubing pressure to 2,000 psi and PT the IA to 3,500 psi for 30 minutes (charted). Bleed
both the IA and tubing to 0 psi.
Page 41
Prudhoe Bay West
L-206 SB Producer
Drilling Procedure
18.14 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over
with valve alignment as per operations personnel.
18.15 RDMO Innovation
Page 42
Prudhoe Bay West
L-206 SB Producer
Drilling Procedure
19.0 Innovation Rig Diverter Schematic
Page 43
Prudhoe Bay West
L-206 SB Producer
Drilling Procedure
20.0 Innovation Rig BOP Schematic
Page 44
Prudhoe Bay West
L-206 SB Producer
Drilling Procedure
21.0 Wellhead Schematic
Page 45
Prudhoe Bay West
L-206 SB Producer
Drilling Procedure
22.0 Days Vs Depth
Page 46
Prudhoe Bay West
L-206 SB Producer
Drilling Procedure
23.0 Formation Tops & Information
PB L-206 Formations MD (FT)
TVDSS
(FT)
TVD
(FT)
FM PRESS
(PSI)
FM Press
(EMW)
Base Permafrost 1894 -1693 1769 778 8.46
Gas Hydrates ~2350' - 2900' MD
SV1 3350 -2487 2563 1128 8.46
UPPR UGNU HEAVY OIL ~3340' - 4050' MD
UG3 4652 -3175 3251 1430 8.46
LWR UGNU HEAVY OIL ~5775' - 6250' MD
NA 6337 -4046 4122 1814 8.46
OA 6692 -4191 4267 1877 8.46
OBD 7650 -4400 4476 1969 8.46
Page 47
Prudhoe Bay West
L-206 SB Producer
Drilling Procedure
Page 48
Prudhoe Bay West
L-206 SB Producer
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 L Pad. They were reported between 1660’ and 2740’ TVD. MW
has been chosen based upon successful trouble free penetrations of offset wells. Remember that hydrate
gas behaves differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates,
but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come
out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching.
Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate
formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud
circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized
mud scale. The non-pressurized scale will reflect the actual mud cut weight. Isolate/dump
contaminated fluid to remove hydrates from the system.
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize
solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor
ECD’s to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPM’s when CBU, and keep pipe
moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after
slide intervals. Do not out drill our ability to clean the hole.
Anti-Collison:
There are no known wells with a clearance factory <1.0. Take directional surveys every stand, take
additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any
close approaches on AM report.
Well Specific A/C:
x There are no wells with a clearance factor of <1.0
Wellbore stability (Permafrost, running sands and gravel, conductor broaching):
Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of
time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH
speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and
swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching.
Maintain mud parameters and increase MW to combat running sands and gravel formations.
Page 49
Prudhoe Bay West
L-206 SB Producer
Drilling Procedure
H2S:
Treat every hole section as though it has the potential for H2S. PBU L-pad is not known for H2S.
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.
SFD 8/25/2021
H2S measures required.
Page 50
Prudhoe Bay West
L-206 SB Producer
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 L-pad is not known for H2S.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Abnormal Pressures and Temperatures:
Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen.
Anti-Collision
Take directional surveys every stand, take additional surveys if necessary. Continuously monitor
drilling parameters for signs of magnetic interference with another well. Reference A/C report in
directional plan.
Well Specific AC:
x L-200 & L-200L1 CF < 1.0: These laterals have been abandoned. The purpose of L-206
well is to replace the lateral of L-200 in the OBd sand. There is no HSE risk due to a
collision.
SFD 8/25/2021
H2S measures required.
Page 51
Prudhoe Bay West
L-206 SB Producer
Drilling Procedure
25.0 Innovation Rig Layout
Page 52
Prudhoe Bay West
L-206 SB Producer
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 53
Prudhoe Bay West
L-206 SB Producer
Drilling Procedure
27.0 Innovation Rig Choke Manifold Schematic
Page 54
Prudhoe Bay West
L-206 SB Producer
Drilling Procedure
28.0 Casing Design
Page 55
Prudhoe Bay West
L-206 SB Producer
Drilling Procedure
29.0 8-1/2” Hole Section MASP
Page 56
Prudhoe Bay West
L-206 SB Producer
Drilling Procedure
30.0 Spider Plot (NAD 27) (Governmental Sections)
Page 57
Prudhoe Bay West
L-206 SB Producer
Drilling Procedure
31.0 Surface Plat (As Built) (NAD 27)
Page 58
Prudhoe Bay West
L-206 SB Producer
Drilling Procedure
32.0 Offset Wells TVD MW
MD TVD MW MD TVD MW MD TVD MW MD TVD MW
800 791.5 8.9 108 108.0 8.8 1000 998.47 9 1560 1514.07 9.3
1600 1498.3 9.2 2631 2187.4 9.4 3130 2616.42 9.7 3310 2630.56 9.7
3000 2228.4 9.7 4005 2762.5 9.2 4836 3567.24 9.6 4776 3494.73 9.2
3900 2686.6 9.5 6647 3879.0 9.1 6195 4417.2 9.6 6175 4366.7 9.2
5000 3253.8 9.2 8793 4843.0 9.2 7458 5419.14 9.6 7686 5500.14 9.2
6500 4028.8 9.2
7800 4488.0 9.3
Source IADC reports Drilling reports Drilling Reports Drilling reports
Comments No daily reports 3130' TD 3310 surf td
No MW issues noted on drilling summary report
L-117 L-118
Hydrates from 1950' to TD 4005
Hydrates breaking out at bell nipple at
4005 td
at 4005, reduced MW from 9.5 to
9.2ppg
L-200 L-217
Planned this well
SFD 8/25/2021
! "#
-1500-1000-500050010001500200025003000350040004500500055006000True Vertical Depth (1000 usft/in)0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000 9500Vertical Section at 307.00° (1000 usft/in)L-206 wp04 cp1L-206 wp04 cp2L-206 wp04 cp3L-206 wp05 tangent landing9 5/8" x 12 1/4"4 1/2" x 8 1/2"500100015002000250030003500400045005000550060006500700075008 000
8500
9000
9 500
10 00 0
1 05 00
110 00
115 00
1200 0
1 250 01300013500140001450014705L-206 wp05Start Dir 2º/100' : 600' MD, 600'TVDStart Dir 3º/100' : 750' MD, 749.93'TVDStart Dir 4º/100' : 950' MD, 948.75'TVDEnd Dir : 2182.17' MD, 1945.3' TVDStart Dir 4º/100' : 5709.1' MD, 3810.25'TVDEnd Dir : 7488.67' MD, 4459.49' TVDBegin Pump TangentEnd Pump TangentStart Dir 3º/100' : 7688.67' MD, 4480.4'TVDEnd Dir : 7960.8' MD, 4491.4' TVDStart Dir 2º/100' : 10929.92' MD, 4420.7'TVDEnd Dir : 11017.6' MD, 4418.26' TVDStart Dir 2º/100' : 13296.39' MD, 4345.7'TVDEnd Dir : 13454.36' MD, 4344.82' TVDTotal Depth : 14704.94' MD, 4370.7' TVDHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: L-20644.20+N/-S+E/-WNorthingEastingLatitudeLongitude0.00 0.00 5978228.790 582982.150 70.350496 -149.326270SURVEY PROGRAMDate: 2020-09-14T00:00:00 Validated: Yes Version: Depth FromDepth ToSurvey/PlanTool26.50 2000.00 L-206 wp05 (L-206) 3_Gyro-GC_Csg2000.00 7688.00 L-206 wp05 (L-206) 3_MWD+HRGM+MS+Sag7688.00 14704.94 L-206 wp05 (L-206) 3_MWD+HRGM+MS+SagFORMATION TOP DETAILSNo formation data is availableREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: L-206, True NorthVertical (TVD) Reference:L-206 As-staked @ 70.70usftMeasured Depth Reference:L-206 As-staked @ 70.70usftCalculation Method:Minimum CurvatureProject:Prudhoe BaySite:LWell:Plan: L-206Wellbore:L-206Design:L-206 wp05Prudhoe BayLPlan: L-206L-206L-206 wp056.907CASING DETAILSTVD TVDSS MD Size Name4480.40 4409.70 7688.67 9-5/8 9 5/8" x 12 1/4"4370.70 4300.00 14704.94 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 0.002 600.00 0.00 0.00 600.00 0.00 0.00 0.00 0.00 0.00 Start Dir 2º/100' : 600' MD, 600'TVD3 750.00 3.00 0.00 749.93 3.93 0.00 2.00 0.00 2.36 Start Dir 3º/100' : 750' MD, 749.93'TVD4 950.00 8.97 6.69 948.75 24.66 1.82 3.00 10.00 13.39 Start Dir 4º/100' : 950' MD, 948.75'TVD5 2182.17 58.08 17.54 1945.30 658.22 181.83 4.00 12.17 250.91 End Dir : 2182.17' MD, 1945.3' TVD6 5709.10 58.08 17.54 3810.25 3512.56 1084.01 0.00 0.00 1248.18 Start Dir 4º/100' : 5709.1' MD, 3810.25'TVD7 7488.67 84.00 306.00 4459.49 4941.50 521.40 4.00 -85.29 2557.46 End Dir : 7488.67' MD, 4459.49' TVD8 7688.67 84.00 306.00 4480.40 5058.41 360.49 0.00 0.00 2756.33 L-206 wp05 tangent landing End Pump Tangent9 7960.80 91.36 309.53 4491.40 5224.82 145.72 3.00 25.68 3027.99 End Dir : 7960.8' MD, 4491.4' TVD1010929.92 91.36 309.53 4420.70 7114.04 -2143.70 0.00 0.00 5993.37 L-206 wp04 cp1 Start Dir 2º/100' : 10929.92' MD, 4420.7'TVD11 11017.60 91.82 307.84 4418.26 7168.82 -2212.12 2.00 -74.76 6080.98 End Dir : 11017.6' MD, 4418.26' TVD1213296.39 91.82 307.84 4345.70 8565.94 -4010.91 0.00 0.00 8358.37 L-206 wp04 cp2 Start Dir 2º/100' : 13296.39' MD, 4345.7'TVD1313454.36 88.81 308.80 4344.82 8663.87 -4134.84 2.00 162.33 8516.28 End Dir : 13454.36' MD, 4344.82' TVD1414704.94 88.81 308.80 4370.70 9447.24 -5109.32 0.00 0.00 9765.98 L-206 wp04 cp3 Total Depth : 14704.94' MD, 4370.7' TVD
-2000
-1000
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
10000
11000
South(-)/North(+) (1500 usft/in)-7000 -6000 -5000 -4000 -3000 -2000 -1000 0 1000 2000 3000
West(-)/East(+) (1500 usft/in)
L-206 wp05 tangent landing
L-206 wp04 cp3
L-206 wp04 cp2
L-206 wp04 cp1
9 5/8" x 12 1/4"
4 1/2" x 8 1/2"
2505007501000
1250
1500
1750
2000
2250
2500
2750
3000
3250
3500
3750
4000
4 2 5 04371L-206 wp05
Start Dir 2º/100' : 600' MD, 600'TVD
Start Dir 3º/100' : 750' MD, 749.93'TVD
Start Dir 4º/100' : 950' MD, 948.75'TVD
End Dir : 2182.17' MD, 1945.3' TVD
Start Dir 4º/100' : 5709.1' MD, 3810.25'TVD
End Dir : 7488.67' MD, 4459.49' TVD
Begin Pump Tangent
End Pump Tangent
Start Dir 3º/100' : 7688.67' MD, 4480.4'TVD
End Dir : 7960.8' MD, 4491.4' TVD
Start Dir 2º/100' : 10929.92' MD, 4420.7'TVD
End Dir : 11017.6' MD, 4418.26' TVD
Start Dir 2º/100' : 13296.39' MD, 4345.7'TVD
End Dir : 13454.36' MD, 4344.82' TVD
Total Depth : 14704.94' MD, 4370.7' TVD
Project: Prudhoe Bay
Site: L
Well: Plan: L-206
Wellbore: L-206
Plan: L-206 wp05
WELL DETAILS: Plan: L-206
44.20
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 5978228.790 582982.150 70.350496 -149.326270
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: L-206, True North
Vertical (TVD) Reference:L-206 As-staked @ 70.70usft
Measured Depth Reference:L-206 As-staked @ 70.70usft
Calculation Method:Minimum Curvature
CASING DETAILS
TVD TVDSS MD Size Name
4480.40 4409.70 7688.67 9-5/8 9 5/8" x 12 1/4"
4370.70 4300.00 14704.94 4-1/2 4 1/2" x 8 1/2"
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From:Davies, Stephen F (CED)
To:AOGCC Records (CED sponsored)
Subject:FW: [EXTERNAL] PBU L-206 (PTD 221-068) - Question
Date:Wednesday, August 25, 2021 1:44:45 PM
Attachments:image003.png
Sam, Meredith:
Please file.
Thanks
From: Joseph Engel <jengel@hilcorp.com>
Sent: Wednesday, August 25, 2021 1:28 PM
To: Davies, Stephen F (CED) <steve.davies@alaska.gov>
Cc: Boyer, David L (CED) <david.boyer2@alaska.gov>; Rixse, Melvin G (CED) <melvin.rixse@alaska.gov>; Joseph Lastufka
<Joseph.Lastufka@hilcorp.com>
Subject: RE: [EXTERNAL] PBU L-206 (PTD 221-068) - Question
Steve –
Please find the most recent H2S values for monitored Orion / Schrader wells in the table below.
Let me know if you have any other questions. Thank you for your time.
-Joe
Joe Engel | Drilling Engineer | Hilcorp Alaska, LLC
3800 Centerpoint Dr., Ste. 1400 | Anchorage | AK | 99503
Office: 907.777.8395 | Cell: 805.235.6265
From: Joseph Engel
Sent: Wednesday, August 25, 2021 12:55 PM
To: Davies, Stephen F (CED) <steve.davies@alaska.gov>
Cc: Boyer, David L (CED) <david.boyer2@alaska.gov>; Rixse, Melvin G (CED) <melvin.rixse@alaska.gov>; Joseph Lastufka
<Joseph.Lastufka@hilcorp.com>
Subject: RE: [EXTERNAL] PBU L-206 (PTD 221-068) - Question
Thanks for the question, Steve.
That is an oversight on my part. When reviewing the L pad data sheet I saw the reference for H2S with Kuparuk wells and incorrectly assumed that
did not apply to Schrader wells. I am also not used to the naming nomenclature describing the target reservoirs, so thank you for that and the note
about formal pool name.
Below is a list of SB/Orion wells that I found (noted that these are outside of your requested date range). I will get a current list of the H2S
monitored SB/Orion wells for L pad and values and send it over.
Please let me know if you have any other questions.
Thank you for your time.
Joe Engel | Drilling Engineer | Hilcorp Alaska, LLC
3800 Centerpoint Dr., Ste. 1400 | Anchorage | AK | 99503
Office: 907.777.8395 | Cell: 805.235.6265
From: Davies, Stephen F (CED) <steve.davies@alaska.gov>
Sent: Wednesday, August 25, 2021 10:34 AM
To: Joseph Engel <jengel@hilcorp.com>
Cc: Boyer, David L (CED) <david.boyer2@alaska.gov>; Rixse, Melvin G (CED) <melvin.rixse@alaska.gov>
Subject: [EXTERNAL] PBU L-206 (PTD 221-068) - Question
Hi Joe,
I’m reviewing Hilcorp’s Permit to Drill (PTD) application for PBU L-206. On pages 49 and 50 of the application, Hilcorp indicates that L-pad wells are
not known for H2S, as follows:
Below is a screen capture of a portion of the PTD application for PBU L-205A (PTD 217-118) submitted in 2017 by BP. Note that several Orion wells
(well numbers in the L-200 series) have recorded H2S values, the most recent measured in 2015.
Which is correct? Could Hilcorp please provide H2S values for Orion wells at PBU measured between 2016 and 2021?
Also: Please note that the formal name for this pool is “Schrader Bluff Oil Pool, Orion Development Area” as defined in Conservation Order No.
505.
Thanks and stay safe,
Steve Davies
Alaska Oil and Gas Conservation Commission (AOGCC)
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the
sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you
are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-
1224 or steve.davies@alaska.gov.
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipientor if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please
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appropriate.
Revised 2/2015
TRANSMITTAL LETTER CHECKLIST
WELL NAME: ______________________________________
PTD: _____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD: ____________________________ POOL: ______________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
No. _____________, API No. 50-_______________________.
Production should continue to be reported as a function of the original
API number stated above.
Pilot Hole
In accordance with 20 AAC 25.005(f), all records, data and logs
acquired for the pilot hole must be clearly differentiated in both
well name (_______________________PH) and API number
(50-_____________________) from records, data and logs acquired for
well (name on permit).
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce/inject is contingent upon issuance of
a conservation order approving a spacing exception.
(_____________________________) as Operator assumes the liability
of any protest to the spacing exception that may occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in no greater
than 30' sample intervals from below the permafrost or from where
samples are first caught and 10' sample intervals through target zones.
Non-
Conventional
Well
Please note the following special condition of this permit:
Production or production testing of coal bed methane is not allowed for
well ( ) until after ( )
has designed and implemented a water well testing program to provide
baseline data on water quality and quantity.
(________________________) must contact the AOGCC to obtain
advance approval of such water well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by (_______________________________) in the attached application,
the following well logs are also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for well logs run must be submitted to the AOGCC
within 90 days after completion, suspension or abandonment of this
well.
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