Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAbout221-042 Hilcorp Alaska, LLC Post Office Box 244027
Anchorage, AK 99524-4027
3800 Centerpoint Drive
Suite 1400
Anchorage, AK 99503
Phone: 907/777-8547
September 29, 2023
Mr. Mel Rixse
Alaska Oil and Gas Conservation Commission
333 West 7th Avenue, Suite 100
Anchorage, Alaska 99501
Re: Milne Point Conductor Annulus Corrosion Inhibitor Treatments 6/9 to 9/27/2023
Dear Mr. Rixse,
Enclosed please a copy of a spreadsheet with a list of thirteen Milne Point wells that were treated
with corrosion inhibiting casing filler in the surface casing by conductor annulus. The heavier than
water “grease-like” filler displaces water to prevent external casing corrosion that could result in
a surface casing leak. The attached spreadsheets include the well names, field, API and PTD
numbers, treatment dates and volumes.
If you have any additional questions, please contact me at 907-777-8406 or
dhorner@hilcorp.com.
Sincerely,
Darci Horner
Regulatory Tech
Hilcorp Alaska, LLC
Digitally signed by Darci Horner
(c-100048)
DN: cn=Darci Horner (c-100048)
Date: 2023.09.29 09:45:20 -
08'00'
Darci Horner
(c-100048)
Well Field API PTD
Initial Top
of Cement
(ft.)
Volume of
Cement
Pumped
(bbls)
Final Top of
Cement (ft.)
Cement
Pump Date
Corrosion
Inhibitor
Fill Volume
(gal)
Final CI Top
(ft.)
Corrosion
Inhibitor
Treatment
Date
Comments
MPB-35 MPU 50029237240000 2220850 14' 0 14' N/A 50 surface 9/27/2023 Drilled Sept/Oct 2022.
MPB-39 MPU 50029237470000 2230120 1'6" 0 1'6" N/A 10 surface 6/10/2023 Drilled Mar 2023.
MPI-20 MPU 50029236790000 2200490 10' 1 1 7/2/2023 5 surface 9/27/2023 Completed Apr 8, 2021.
MPI-29 MPU 50029237080000 2220060 6' 0.5 3 7/2/2023 15 surfce 9/27/2023
Drilled in March 2022. Completeted
on 4/30/22.
MPL-60 MPU 50029236780000 2200480 1' 0 1' N/A 10 surface 6/26/2023 Drilled in 2020.
MPL-62 MPU 50029236850000 2200590 1' 0 1' N/A 10 surface 6/26/2023 Drilled in 2020.
MPM-13 MPU 50029236380000 2190870 20' 3.5 2' 8/2/2023 10 surface 9/27/2023 Drilled in 2019.
MPM-27 MPU 50029237160000 2220490 2' 0 2' N/A 20 surface 6/11/2023 Monobore. Drilled June 2022.
MPM-30 MPU 50029237300000 2221180 1' 0 1' N/A 10 surface 6/11/2023 Drilled in Oct 2022.
MPM-43 MPU 50029236710000 2200200 1' 0 1' N/A 10 surface 6/11/2023 Drilled in 2020.
MPM-62 MPU 50029237440000 2230060 1' 0 1' N/A 10 surface 6/11/2023 Completed May 2023.
MPS-45 MPU 50029236930000 2210420 1' 0 1' N/A 10 surface 6/12/2023 Drilled in June 2021.
MPS-47 MPU 50029236960000 2210470 4' 0 4' N/A 20 surface 6/12/2023 Drilled in August 2021.
Notes:
The 4" conductor outlets are any where from 1 to 3' down from the top of the conductor
Surface Casing by Conductor Annulus Cement Top Job and Fill Coat Corrosion Inhibitor (CI) Applications
Cement to surface means cement is up to the 4" outlets below the wellhead. From the 4" outlets up to the top of conductor was filled with Fill Coat #7
Initial top of cement footage measurement was taken from the 4" outlet down to the TOC
RBDMS JSB 100323
MPS-45 MPU 50029236930000 2210420 1'0 1'N/A 10 surface 6/12/2023 Drilled in June 2021.
DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23693-00-00Well Name/No. MILNE PT UNIT S-45Completion Status1-OILCompletion Date6/19/2021Permit to Drill2210420Operator Hilcorp Alaska, LLCMD14074TVD3986Current Status1-OIL8/6/2021UICNoWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:ROP, AGR, ABG, DGR, EWR, ADR MD & TVDNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF6/28/2021 Electronic File: MPU S-45 AOGCC FINAL EOW_GEOSTEERING LOGS 23JUNE2021 TRANSMITTAL.DOC35291EDDigital DataDF6/28/2021 Electronic File: MPU S-45 Geosteering End of Well Report.pdf35291EDDigital DataDF6/28/2021 Electronic File: MPU S-45 Geosteering EOW Plot 300dpi.tif35291EDDigital DataDF6/28/2021 Electronic File: MPU S-45 Geosteering EOW Plot.emf35291EDDigital DataDF6/28/2021 Electronic File: MPU S-45 Geosteering EOW Plot.pdf35291EDDigital DataDF6/28/2021 Electronic File: MPU S-45 Geosteering EOW Plot.tif35291EDDigital DataDF6/28/2021 Electronic File: MPU S-45 Post-Well Geosteering X-Section Summary.pdf35291EDDigital Data0 0 2210420 MILNE PT UNIT S-45 LOG HEADERS35291LogLog Header ScansDF6/28/2021105 14074 Electronic Data Set, Filename: MPU S-45 LWD FInal.las35292EDDigital DataDF6/28/20215920 14036 Electronic Data Set, Filename: MPU S-45 ADR Quadrants All Curves.las35292EDDigital DataDF6/28/2021 Electronic File: MPU S-45 AOGCC FINAL LWD LOGS 23JUNE2021 TRANSMITTAL.DOC35292EDDigital DataDF6/28/2021 Electronic File: MPU S-45 LWD Final MD.cgm35292EDDigital DataDF6/28/2021 Electronic File: MPU S-45 LWD Final TVD.cgm35292EDDigital DataDF6/28/2021 Electronic File: MPU S-45 - Definitive Survey Report.pdf35292EDDigital DataFriday, August 6, 2021AOGCCPage 1 of 3MPU S-45 LWD FInal.las
DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23693-00-00Well Name/No. MILNE PT UNIT S-45Completion Status1-OILCompletion Date6/19/2021Permit to Drill2210420Operator Hilcorp Alaska, LLCMD14074TVD3986Current Status1-OIL8/6/2021UICNoWell 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: 6/19/2021Release Date: 5/21/2021DF6/28/2021 Electronic File: MPU S-45 - DSR Plan Plot.pdf35292EDDigital DataDF6/28/2021 Electronic File: MPU S-45 - DSR Section Plot.pdf35292EDDigital DataDF6/28/2021 Electronic File: MPU S-45 - Final Surveys.xlsx35292EDDigital DataDF6/28/2021 Electronic File: MPU S-45 - GIS.txt35292EDDigital DataDF6/28/2021 Electronic File: MPU S-45 -DSR.txt35292EDDigital DataDF6/28/2021 Electronic File: MPU S-45 LWD Final MD.emf35292EDDigital DataDF6/28/2021 Electronic File: MPU S-45 LWD Final TVD.emf35292EDDigital DataDF6/28/2021 Electronic File: MPU_S-45_Geosteering.dlis35292EDDigital DataDF6/28/2021 Electronic File: MPU_S-45_Geosteering.ver35292EDDigital DataDF6/28/2021 Electronic File: MPU S-45 LWD Final MD.pdf35292EDDigital DataDF6/28/2021 Electronic File: MPU S-45 LWD Final TVD.pdf35292EDDigital DataDF6/28/2021 Electronic File: MPU S-45 LWD Final MD.tif35292EDDigital DataDF6/28/2021 Electronic File: MPU S-45 LWD Final TVD.tif35292EDDigital Data0 0 2210420 MILNE PT UNIT S-45 LOG HEADERS35292LogLog Header ScansFriday, August 6, 2021AOGCCPage 2 of 3
DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23693-00-00Well Name/No. MILNE PT UNIT S-45Completion Status1-OILCompletion Date6/19/2021Permit to Drill2210420Operator Hilcorp Alaska, LLCMD14074TVD3986Current Status1-OIL8/6/2021UICNoComments:Compliance Reviewed By:Date:Friday, August 6, 2021AOGCCPage 3 of 3M. Guhl8/6/2021
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: 36.9' BF:
Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation:
4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number:
Surface: x- y- Zone- 4
TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD:
Total Depth: x- y- Zone- 4
5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD:
Submit electronic information per 20 AAC 25.050 (ft MSL)
22.Logs Obtained:
23.
BOTTOM
20" X-52 117'
L-80 1,968'
L-80 4,052'
7" L-80 4,042'
4-1/2" L-80 3,986'
24. Open to production or injection? Yes No 25.
26.
Was hydraulic fracturing used during completion? Yes No
DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED
27.
Date First Production: Method of Operation (Flowing, gas lift, etc.):
Hours Tested: Production for Gas-MCF:
Test Period
Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr):
Press. 24-Hour Rate
9-5/8"12-1/4"
ACID, FRACTURE, CEMENT SQUEEZE, ETC.
CASING, LINER AND CEMENTING RECORD
List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion,
Uncemented TiebackTieback
TUBING RECORD
Uncemented Screen Liner
Liner Top Packer
5,628'4-1/2" 12.6# L-80
SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation
Size and Number; Date Perfd):
14,142'
Stg 2 L 5561 sx / T - 270 sx
4,030'
Surface
Driven
13.5#
Surface 2,532' Stg 1 L - 435 sx / T - 393 sx
8-1/2"
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
Hilcorp Alaska, LLC
WAG
Gas
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
6/19/2021
3194' FSL, 634' FEL, Sec. 12, T12N, R10E, UM, AK
289' FNL, 958' FWL, Sec. 01, T12N, R10E, UM, AK
221-042
Milne Point Field / Schrader Bluff Oil Pool
63.5'
14,072' / 3,986'
HOLE SIZE AMOUNT
PULLED
50-029-23693-00-00
MPU S-45
565378 5999858
2538' FSL, 1729' FEL, Sec. 12, T12N, R10E, UM, AK
CEMENTING RECORD
5999192
SETTING DEPTH TVD
6006902
BOTTOM TOP
Surface
Surface
CASING WT. PER
FT.GRADE
26#
564288
561628
TOP
SETTING DEPTH MD
Surface
Per 20 AAC 25.283 (i)(2) attach electronic information
40#
5,782'
1,968'
Surface
DEPTH SET (MD)
5,769' / 4,041'
PACKER SET (MD/TVD)
5,628'
129.5#
47#
117'
2,532' 5,929'
Gas-Oil Ratio:Choke Size:Water-Bbl:
PRODUCTION TEST
Not on Production
Date of Test:
Flow Tubing
Oil-Bbl:
suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray,
caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation
record. Acronyms may be used. Attach a separate page if necessary
N/A
***Please see Schematic for Details***
ROP, AGR, ABG, DGR, EWR, ADR MD & TVD
Sr Res EngSr Pet GeoSr Pet Eng
Oil-Bbl: Water-Bbl:
6/15/2021
6/3/2021
ADL 380109
01-001
2,349' / 1838'
N/AN/A
None
14,074' / 3,986'
Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment
By Samantha Carlisle at 12:53 pm, Jul 07, 2021
RBDMS HEW 7/9/2021
Completion Date
6/19/2021
HEW
GSFD 7/16/2021
MGR13JULY2021 DLB 07/12/2021
DSR-8/4/21
SFD 7/16/202114,074
Conventional Core(s): Yes No Sidewall Cores:
30.
MD TVD
40' 40'
2389' 1878'
Top of Productive Interval 5869' 4049'
1532' 1394'
2561' 1987'
4459' 3562'
5668' 4033'
5869' 4049'
SB NB 5869' 4049'
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:
FORMATION TESTS
Permafrost - Top
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.
LOT / FIT Data Sheet, Drilling and Completion Reports, Definitive Directional Survey, Wellbore Schematic
Signature w/Date:
If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form,
if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071.
Authorized Name: Monty Myers
Authorized Title: Drilling Manager
Schrader Bluff NB
Permafrost - Base
29. GEOLOGIC MARKERS (List all formations and markers encountered):
Formation at total depth:
Ugnu LA3
Yes No
Well tested? Yes No
28. CORE DATA
If yes, list intervals and formations tested, briefly summarizing test results.
Attach separate pages to this form, if needed, and submit detailed test
information, including reports, per 20 AAC 25.071.
NAME
Schrader Bluff NA
SV 5
SV 1
The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00).
Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345),
and/or Easement (ADL 123456) number.
INSTRUCTIONS
Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each
segregated pool is a completion.
TPI (Top of Producing Interval).
Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain).
Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical
laboratory information required by 20 AAC 25.071.
Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion,
suspension, or abandonment, whichever occurs first.
Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection,
Observation, or Other.
Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and
other tests as required including, but not limited to: core analysis, paleontological report, production or well test results.
Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29.
Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool.
If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the
producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced,
showing the data pertinent to such interval).
Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit
detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity,
permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology.
The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements
given in other spaces on this form and in any attachments.
Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment
7.7.2021Digitally 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: 2021.07.07 06:43:03 -08'00'
Monty M
Myers
_____________________________________________________________________________________
Revised By: JNL 6/29/2021
SCHEMATIC
Milne Point Unit
Well: MPU S-45
Last Completed: 6/19/2021
PTD: 221-042
TD =14,074’(MD) / TD =3,986’ (TVD)
5
20”
Orig. KB Elev.: 63.5’ / GL Elev.: 36.9’
7”
10
1
1
4
13
9-5/8”
1
2
3
See
Screen
Liner
Detail
PBTD =14,072’(MD) / PBTD = 3,986’ (TVD)
9-5/8” ‘ES’
Cementer @
2,532’
4-1/2”
Shoe @
14,072’
12
11
6
8 & 9
7
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20" Conductor 129.5 / X52 / Weld N/A Surface 119’ N/A
9-5/8" Surface 47/ L-80 / TXP 8.681 Surface 2,532’ 0.0732
9-5/8” Surface 40 / L-80 / TXP 8.835 2,532’ 5,929’ 0.0758
7” Tieback 26 / L-80 / Hyd 521 6.276 Surface 5,782’ 0.0383
4-1/2” Liner 13.5 / L-80 / Hyd 625 3.920 5,628’ 14,142’ .0149
TUBING DETAIL
4-1/2" Tubing 12.6# / L-80 / TXPM 3.958 Surface 5,628’ 0.0152
OPEN HOLE / CEMENT DETAIL
Driven Conductor
12-1/4"Stg 1 – Lead – 435 sx / Tail – 393 sx
Stg 2 – Lead – 561 sx / Tail – 270 sx
8-1/2” Cementless Screen Liner
WELL INCLINATION DETAIL
KOP @ 258’
90° Hole Angle = @ 5995’ MD
TREE & WELLHEAD
Tree Cameron 3 1/8" 5M w/ 4-1/16” 5M Cameron Wing
Wellhead FMC 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs
GENERAL WELL INFO
API: 50-029-23693-00-00
Completion Date: 6/19/2021
JEWELRY DETAIL
No. Top MD Item ID
1 4,951’ Gauge 3.958”
2 4,959’ Sliding Sleeve 3.958”
3 4,964’ Ported Sub 3.958”
4 5,028’ Baker Premier Packer 3.860”
5 5,099’ XN Nipple, 2.813”, Packing Bore, 3.725” Bottom No-Go 3.725”
6 5,764’ WLEG – Bottom @ 5,794’ 3.958”
7 5,769’ SLZXP Liner Top Packer 6.160”
8 5,771 Locator Sub, TC-II Box x Box 6.180”
9 5,772’ Bullet Seals (TBSA), Mule Shoe (4 – 1” Holes) 6.180”
10 5,790’ 7” H563 x 4.5”TSH 625 XO 3.800”
11 8,209’ Tandeka SwellRight Packer 3.920”
12 8,723’ Tandeka SwellRight Packer 3.920”
13 14,072’ Shoe
4-1/2” LINER 250ђ SCREEN DETAIL
Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD)
54 5,959’ 4,052’ 8,204’ 4,027’
32 8,737’ 4,017’ 10,081’ 4,025’
51 10,413’ 4,024’ 12,506’ 4,010’
25 12,997’ 4,002’ 14,032’ 3,984’
14,074 SFD
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:MPU S-45 Date:6/11/2021
Csg Size/Wt/Grade: 9.625 40#/47# L-80 Supervisor:Lott / Amend
Csg Setting Depth:5,929' 4,050 TVD
Mud Weight:8.95 ppg LOT / FIT Press =642 psi
LOT / FIT =12.00 ppg Hole Depth =5957 md
Fluid Pumped=1.1 Bbls Volume Back =0.8 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
->216 ->00
->487 ->211
->6154 ->697
->8232 ->12 294
->10 303 ->18 476
->12 390 ->20 522
->14 449 ->30 775
->16 517 ->50 1217
->18 585 ->70 1694
->20 652 ->90 2179
-> ->108 2630
-> ->
-> ->
-> ->
Enter Holding Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0652 ->02630
->1632 ->52611
->2625 ->10 2605
->3620 ->15 2598
->4615 ->20 2594
->5612 ->25 2588
->6607 ->30 2584
->7604 ->
->8598 ->
->9593 ->
->10 588 ->
-> ->
-> ->
-> ->
2
4
6
8
10
12
14
16
18
20
0 2
6
12
1820
30
50
70
90
108
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 102030405060708090100110120Pressure (psi)Strokes (# of)
LOT / FIT DATA CASING TEST DATA
652632625620615612607604598593588
2630 2611 2605 2598 2594 2588 2584
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
3100
3200
3300
3400
3500
3600
3700
3800
3900
4000
0 5 10 15 20 25 30Pressure (psi)Time (Minutes)
LOT / FIT DATA CASING TEST DATA
Activity Date Ops Summary
6/3/2021 Accept RIG @ 09:00 hrs PJSM, P/U 5" NC-50, 19.5# DP, make up stds in mouse hole and Rack Back in Derrick. Drift Size 3.125". Tq connections to 30K ft/lbs.
P/U Jars and 9 stds HWDP. Open Annular and L/D Mouse Hole. Re-connect Koomey lines to Knife Valve. Function test all Equip in Mud Pits & finish Rig
acceptance List. PJSM, Test Diverter System. Witness waived by Guy Cook. Knife open 5 sec, Bag close 9 sec. Draw Down initial 3000 psi, Final 1950 psi, 200 psi
build 15 sec, Full Recovery 57 sec. N2 6@ 2300 psi. Test Gas alarms, PVT, R/F, Trip Tanks, G/L. PJSM, Grease Crown and Perform Derrick inspection. Grease
Top Drive, Blocks, Wash Pipe, Drawworks, IBOP, Iron Roughneck, and all handling Equipment. Stage TM, DM, X/O's and lift sub on rig floor. Set BHA tools in order
in Shed. R/U tongs and prep floor for BHA. Hold Pre Spud meeting discussing broaching, Well control, Rig evacuation, gas hydrates and muster areas. Informed
pad ops of operations. P/U M/U 12.25" Kymera Bit 3 X 14, 3 X 13 jets (0.8399 TFA) 8" TerraForce 4/5 5.3 stage 1.5° Motor and 1 stand 5" HWDP PJSM Prime MP
W/ H2O and fill hole. Check for leaks, good. PT mud lines to 3,000 PSI, good Wash down with 130 GPM, tag up at 107’. Drill 12-1/4" hole from 107' to 220'. 375
GPM, 415 PSI, 40 RPM, 1-2k Tq. 3-5k WOB. Utilize fresh water for first 10' of drilling & swap to 8.7 ppg spud mud on the fly. CBU and pump out f/ 220' t/ 107'. flow
check- static. POOH t/ surface. Flush flow line and possum belly through bleeder. B/D TopDrive PJSM for BHA. P/U EWR-M5 Collar, and DM collar, to 73'. Perform
offset DM-Mtr = 214.65°, Cont P/U 8" TM to 83' Plug in, initialize and download MWD tools. P/U 8" NM FC and 1 stand 5" 49.3# S-135 NC50 HWDP washed
down to 220' W/ no fill encountered. Drill 12-1/4" surface hole f/ 220' t/ 639', (634’ TVD) 419' drilled, 76’/hr AROP. 400 GPM, 890 PSI, 50 RPM, 2-3k Tq, 5-10k
WOB. MW 8.9 in / 8.95 out, vis 300 in / 300 out, 9.8 ECD. 57k PU / 59k SO / 59k ROT. Kick off @ 220’, target 3.0° BUR Distance to WP 07: 10.22’, 10.16' High
1.11' Left Daily Disposal to G&I 114 bbls, total = 114 bbls. Daily Water from 6 mile lake 240 bbls, total = 240 bbls. Total Water from S-Pad Creek = 5560 bbls. Daily
Metal: 0 lb. Total Metal 0 lb. Daily Mud lost to formation 0 bbls, total = 0 bbls.
6/4/2021 Drill 12-1/4" surface hole f/ 639' t/ 1085', (1048’ TVD) 446' drilled, 74’/hr AROP. 500 GPM, 1300 PSI, 60 RPM, 3-4k Tq, 5-10k WOB. MW 8.9 in / 8.95 out, vis 300
in / 300 out, 9.9 ECD. Max Gas 31u. 73k PU / 66k SO / 70k ROT. Target 4° BUR. Backream full stands at connection. Drill 12-1/4" surface hole f/ 1085' t/ 1580',
(1245’ TVD) 495' drilled, 82’/hr AROP. 500 GPM, 1525 PSI, 60 RPM, 5-6k Tq, 7-18k WOB. MW 8.9 in / 8.95 out, vis 300 in / 300 out, 9.9 ECD. Max Gas 108u.
80k PU / 74k SO / 74k ROT. Continue target 4° BUR. Backream full stands at connection. Drill 12-1/4" surface hole f/ 1580' t/ 2190’, (1764’ TVD) 610' drilled,
101.6’/hr AROP. 500 GPM, 1490 PSI, 60 RPM, 6-8k Tq, 5-18k WOB. MW 9.05, Vis 200, 10.1 ECD. 130u max gas. 81k PU / 64k SO / 74k ROT1425. Target 4°
BUR. Tangent with maintenance slides f/ 1800' t/2190’. Backream full stands at conn. Drill 12-1/4" surface hole f/ 2190' t/ 2799’, (2161’ TVD) 609' drilled, 101.5’/hr
AROP. 500 GPM, 1425 PSI, 60 RPM, 6-8k Tq, 1-6k WOB. MW 9.2, Vis 180, 10.0 ECD. 355u max gas. 102k PU / 66k SO / 84k ROT. Target 4.25° DLS for drop
and turn. BOPF logged at 2389' MD, 1878' TVD Distance to Wp07: 7.3’, 6.55' Low & 3.22' Right Daily Disposal to G&I 1254 bbls, total = 1368 bbls. Daily Water
from 6 mile lake 400 bbls, total = 640 bbls. Daily Water from S-Pad Creek =480. Total Water from S-Pad Creek = 1040 bbls. Total Metal 0 lb. Mud lost to formation
= 0 bbls total.
6/5/2021 Drill 12-1/4" surface hole f/ 2799' t/3260 ’, (2525’ TVD) 461' drilled, 76.8’/hr AROP. 500 GPM, 1575 PSI, 80RPM, 7-8k Tq, 5-12k WOB. MW 9.2, Vis 90, 10.1 ECD.
922u max gas. 121k PU / 77k SO / 92k ROT. Target 4.25° DLS for drop and turn. Back Ream full stands. Drill 12-1/4" surface hole f/ 3260' t/3561 ’, (2577’ TVD)
301' drilled, 67’/hr AROP. 500 GPM, 1410 PSI, 80RPM, 7-8k Tq, 5-12k WOB. MW 9.2, Vis 90, 10.0 ECD. 244u max gas. 128k PU / 89k SO / 101k ROT. Target
4.25° DLS for drop and turn. Back Ream full stands. Top of Ugnu logged at 3308’ MD, 2588' TVD P/U off btm and circulate @ 3 bpm/240 psi while change out
leaking O-Ring on solenoid valve behind coffin lid on Top Drive. Finish change out leaking O-Ring on solenoid valve behind coffin lid on Top Drive and Service Rig
Drill 12-1/4" surface hole f/ 3561' t/ 4050’, (3250’ TVD) 489' drilled, 75.2’/hr AROP. 500 GPM, 1355 PSI, 80 RPM, 9-10k Tq, 2-14k WOB. MW 9.1 in / 9.1 out, vis
80 in / 101 out, 9.7 ECD. 282u max gas. 151k PU / 86k SO / 106k ROT. Target 4.25° DLS for build and turn. Back Ream full stands. Drill 12-1/4" surface hole f/
4050' t/ 4525’, (3607’ TVD) 475' drilled, 79.17’/hr AROP. 500 GPM, 1580 PSI, 80 RPM, 11-12k Tq, 3-12k WOB. MW 9.1 vis 95, 9.7 ECD. 164k PU / 88k SO /
111k ROT. Continue target 4.25° DLS for build and turn. Back Ream full stands. Distance to WP 07: 7.36’, 7.32' High 0.73' Right Daily Disposal to G&I 969 bbls,
total = 2374 bbls. Daily Water from 6 mile lake 0 bbls, total = 640 bbls. Daily Water from S-Pad Creek = 1120. Total Water from S-Pad Creek = 2160 bbls. Daily
Metal: 0 lb. Total Metal 0 lb. Daily Mud lost to formation 0 bbls, total = 0 bbls.
6/6/2021 Drill 12-1/4" surface hole f/ 4525' t/ 4943’, (3861’ TVD) 418' drilled, 69.66’/hr AROP. 550 GPM, 1750 PSI, 80 RPM, 12-14k Tq, 12k WOB. MW 9.1 vis 82, 9.7 ECD.
178k PU / 89k SO / 116k ROT. Continue target 4.25° DLS for build and turn. Back Ream full stands. Drill 12-1/4" surface hole f/ 4943' t/ 5023', (3890’ TVD) 80'
drilled, 80’/hr AROP. 550 GPM, 1750 PSI, 80 RPM, 12-14k Tq, 2-8k WOB. MW 9.05 vis 80, 9.7 ECD. 174k PU / 90k SO / 116k ROT. Continue target 4.25° DLS
for build and turn. Back Ream full stands. Change out wear plate and liner gasket on MP#1. Reciprocate string slowly, circulate at 3 BPM, 340 psi. Drill 12-1/4"
surface hole f/ 5023' t/ 5218’, (3967’ TVD) 195' drilled, 48.75’/hr AROP. 550 GPM, 1815 PSI, 80 RPM, 13-15k Tq, 6-16k WOB. MW 9.1 vis 80, 9.6 ECD. 179k PU /
89k SO / 118k ROT. Continue target 4.25° DLS for build and turn. Back Ream full stands. Screens blinding off with oil severely and loosing mud over shakers.
Screen down to 120’s & 80’s @ 5214’ MD Then 100's & 80's to keep mud on shakers. Drill 12-1/4" surface hole f/ 5023' t/ 5532’, (4021’ TVD) 509' drilled, 84.83’/hr
AROP. 500 GPM, 1740 PSI, 80 RPM, 14-16k Tq, 5-25k WOB. MW 9.2 vis 82, 9.6 ECD. 174k PU / 84k SO / 111k ROT. Continue target 4.25° DLS for build and
turn. Start pump tangent at 5514’. Back Ream full stands. Experience multiple motor stalls and pack-offs while backreaming stand @ 5311’ MD. Work through
several times until clean. Drill 12-1/4" surface hole f/ 5532' t/ 5903’, (4052’ TVD) 371' drilled, 61.83’/hr AROP. 500 GPM, 1790 PSI, 80 RPM, 14-15k Tq, 9-15k
WOB. MW 9.3 vis 74, 9.9 ECD. 178k PU / 79k SO / 109k ROT. Cont pump tangent to 5787’ w/100% rotation. Largest DL through pump tangent = 1.39°. Continue
build to 90° inc Top of the SB_NA logged at 5649’ MD, 4031’ TVD. Distance to WP 07: 5.43’, 1.82' Low, 5.12' Left Daily Disposal to G&I = 1606 bbls, total = 3943
bbls. Daily Water from 6 mile lake 0 bbls, total = 640 bbls. Daily Water from S-Pad Creek = 1200. Total Water from S-Pad Creek = 3360 bbls. Daily Metal: 0 lb.
Total Metal 0 lb. Daily Mud lost to formation 0 bbls, total = 0 bbls.
50-029-23693-00-00API #:
Well Name:
Field:
County/State:
MP S-45
Milne Point
Hilcorp Energy Company Composite Report
, Alaska
6/3/2021Spud Date:
6/7/2021 Drill 12-1/4" Surface Hole f/ 5903' t/ 5937' MD (4051' TVD) casing point (34' total= 34fph AROP) 80 RPM, 16k Tq. 550 GPM, 1920 PSI, WOB 9-15, ECD 10.1 ppg
w/ 9.0 ppg MW. P/U 178K, S/O 79K, ROT 109K. Max Gas 187U. SB_NB logged @ 5879’ MD, 4050’ TVD. Distance to WP 07: 4.71’, 3.65' Low, 2.98' Left
BROOH from 5937' to 5790'. Pump 48 bbl Hi-Vis sweep w/ nutplug. CBU 3x, 500 GPM, 1450 psi, 60 rpms, 14-16k Tq. Sweep back on time with no visible
increase in cuttings. Mud conditioned to a 65 FV. RIH to bottom with no fill encountered. Monitor well, static. 184k PU, 81k SO BROOH from 5937' to 5300' at 500
gpm, 1480 psi, 60 rpms, 14-16k Tq. Pulling speeds 30-35 fpm. Max gas 69u. PUW 185k, SOW 83k, BROOH f/ 5300' t/ 2417', 30-35 FPM, slowing as necessary,
500 GPM, 1200 PSI, 60 RPM, 9-10k Tq. Max gas 84u. Pull slow f/ 2547’ t/ 2484’ while circulating a BU. Pull through BAPF @ 15-25 FPM, no issues. Continue
BROOH f/ 2417' t/ 950' at 30-35 FPM, slowing as necessary, 500 GPM, 1015 PSI, 60 RPM, 1.5-3k Tq. Max gas 125u. Seeing hole unloading at 950’, cleaning up
by 760’. Monitor Well – Static. Attempt to pull HWDP on elevators with no success, seeing 15k overpull. Attempt to pump HWDP out with no rotary, also with no
success. Continue BROOH t/ 220’ where assembly was able to pull on elevators. Monitor Well at 220’ – Static. POOH on elevators to 146’. No losses recorded
while BROOH L/D (2) DC. Plug in and download MWD. Continue to L/D BHA. Bit grade 1-1-CT-G-E-I-SD-TD Clean and clear rig floor of BHA components. Jet
flow line & blow down TopDrive Rig up to RIH with 9-5/8" casing. Bring centralizers to rig floor. M/U Volant CRT tool, bail extensions, elevators, double stack power
tongs. PJSM, Baker Loc and M/U 9-5/8" shoe track: round nose float shoe, Baker lock joint & FC joint. Ensure proper float operation - good. Install top hat as per
HES rep after M/U FC joint. M/U baffle adapter & joint #4 to 164’ Torque all connections to 21,000 ft/lbs w/ Weatherford double stack tongs, Two 9-5/8" x 12-1/4"
centralizer & 4 stop rings on shoe joint, 1 free floating centralizer on Baker-Loc joint, 1 centrailizer w/ 2 stop rings on the float collar and baffle adapter joints. Run 9-
5/8" 40# L-80 TXP-BTC casing f/ 164' t/ 798'. 58k PU, 56k SO. Torque to 21,000 ft/lbs with Weatherford double stack tongs. Install 9-5/8" x 12-1/4" bow spring
centralizers on jts #5-20. Fill casing every 5 jts & top off every 10 joints. Daily Disposal to G&I = 798 bbls, total = 4741 bbls. Daily Water from 6 mile lake 0 bbls,
total = 640 bbls. Daily Water from S-Pad Creek = 880 bbls. Total Water from S-Pad Creek = 4240 bbls. Daily Metal: 0 lb. Total Metal 0 lb. Daily Mud lost to
formation 0 bbls, total = 0 bbls.
6/8/2021 Run 9 5/8" , 40#, L-80, TXP BTC Csg from 798' to 2807'MD. Use BEST-O-LIFE Pipe Dope_ TQ connections to 21,000ft/lbs_RIH 25-30 FPM_ Fill csg every 5 jts_
fill pipe and break circulation back to Pits for 15 bbls. At 1370' set down 30K. Work through tight spot and CBU slowly with next Jt. CBU below base of permafrost @
2600', stage pump to 5 bpm, 114 psi, PU 140K, SO 64K. Run 9 5/8" , 40#, L-80, TXP BTC Csg from 2600' to 3376''. PU/MU HES Stage Tool. Run casing to 3662'.
PU 165K, SO 88K CBU From 3662' staging pup to 6 bpm, 175 psi. No increase at shakers. Continue to RIH with 9 5/8" Casing from 3662' to 4901' MD Run 9-5/8"
40# L-80 TXP-BTC casing f/ 4901' t/ 5929'. 305k PU, 93k SO. Torque to 23,800 ft/lbs with Weatherford double stack tongs. Fill casing every 5 jts & top off every
10 joints. Wash last jt down @ 2 BPM. Verifiy pipe count and confirm 5929' depth. 71 bbls total lost while running casing. Stage pump rate to 7 BPM, 195 PSI and
circulate 2 x bottoms up, condition mud to 9.6 ppg, 54 Vis, 17 YP. Rotate and reciprocate pipe 13’ (Collar hanging up on conductor or Wellhead), 1-2 RPM @ 15k
Tq. Max Gas 136U. PUW 301k, SOW 101k. Blow down top drive. Circulate through bleeder to clean out flow line, clean both mud pump suction screens. Rig up
HES cementers. Blow air to cementers to ensure line clear. Rig up cement hoses to Volant CRT, and break circulation staging up to 6 bpm, 470 psi through the
cement line. Hold PJSM with rig crew, Halliburton, Baroid & ASRC on 1st stage cement job. HES pump 5 bbls fresh water, 2 BPM, 80 PSI. Pressure test lines to
1000 PSI low / 4000 PSI high. Mix & pump 60 bbls of 10.0 ppg Tuned Spacer w/ 4# red dye & 5# Pol-E-Flake in 1st 10 bbls, 4.2 BPM, 245 PSI. Drop by-pass plug
Mix & pump 182 bbls of 12.0 ppg lead cement (435 sks @ 2.347^3/sk yield), 4.8 BPM, 360 PSI. Mix & pump 82 bbls of 15.8 ppg tail cement (400 sks @
1.151^3/sk yield), 3.6 BPM, 463 PSI. Drop shut-off plug. Pump 20 bbls of fresh water, 5 BPM, 380 PSI. Displace 218.2 bbls, 9.6 ppg spud mud from the rig, 5 BPM,
220 PSI. HES pump 80 bbls 9.4 ppg tuned spacer, 4.6 BPM, 283 PSI. Continue displace from rig 5 bpm, 920 psi, last 10 bbls slow to 3 bpm, FCP 750 psi, plug
bumped @ 5764 stks, 374 stks late. CIP @ 03:31 376 bbls into displacement see trace poly flake at shakers. No spacer or cement to surface while displacing. Rot
and Recip string until started taking wt 50 bbls into displacing. Slack off to 5929’ and pull string into tension @ 250k. 3 bbl losses recorded while cementing and
displacing. Pressure to 1300 psi, hold for 5 min, Bleed down and check floats. Good. Pressure to 3870 psi shifting cementer tool open at 2535'. CBU thru ESC @
2535' staging pump to 5 bpm, 350 psi. Dump contaminated returns to cuttings box, clean returns back @ 5500 stks, dumped total 93 bbls. 83 bbls clabbored
interface & 10 bbls cement. Continue to circulate 6 bpm, 400 psi, for a total of CBU 3.5x Daily Disposal to G&I = 917 bbls, total = 5658 bbls. Daily Water from 6 mile
lake 0 bbls, total = 640 bbls. Daily Water from S-Pad Creek = 240 bbls. Total Water from S-Pad Creek = 4480 bbls. Daily Metal: 0 lb. Total Metal 0 lb. Daily Mud
lost to formation 71 bbls, total = 71 bbls.
6/9/2021 Finish CBU through Stage Tool @ 2535'. Disconnect knife valve, flush snd drsin stack with Black water pills while functioning the bag. CBU staging pumps to 6
bpm, 380 psi. @ 1900 strokes well began to packoff. Slow pumps to 1 bpm, 640 psi. Clabbered up mud seen at surface. Stage pump up slowly working pipe 1' from
250K to 35K. Keep stepping up pumps and obtain 5 bpm, 520 psi. After to STS circulations pressure dropped to 430 psi. Stage pump to 6 bpm, 510 psi. Prep for
2nd stage cement. Pump 2nd stage cement job as follows: 60 bbls 10# Tuned spacer w/ 4# red dye & .5 lb/bbl poly flake (1st 10 bbls) 2 BPM ICP 115PSI FCP 108
PSI. 288 bbls 10.7# ArticCem Lead cmt, 2.883 yld, 4 bpm, ICP 306 PSI FCP 461 PSI PSI. 57bbls 15.8# Premium G Tail cmt, 1.17 yld, 4 bpm, ICP 515 PSI FCP
400. Drop closing plug. Displace w/ 20 bbls H2O (HES) then turn over to rig. Rig disp w/ 169 bbls 9.4# spud mud, 6 bpm, 800 PSI slowing to 3 bpm 600 FCP at
last 15 bbls.. Bump plug with 189 bbls actual / 185.6 bbls calculated. Cont. Press up stage tool shifted at 1,690 PSI, held 1900 PSI for 3 minutes, stage tool, good.
CIP @ 15:30 hrs. Full returns throughout job. Saw contaminated spacer 60 bbls early at shakers. Good 10.7 ppg cement seen at shakers at 20 bbls into
displacement. Dumped 167 bbls of cement at surface. PJSM Disconnect cement lines and flush W/ back water. Disconnect knife valve and flush stack 3X W/ black
water. Break out Volant tool and L/D. Disconnect and rig down diverter line W/ crane. Install 9.625" elevators. B/D lines and clean cellar box. Install bridge cranes to
Stack and remove binders. P/U Stack and set emergency slips as per NOS re onsite. (115K in slips) Set down Stack and remove diverter Tee bolts. Clean out
9.625" jnt. P/U Stack and make finial cut on 9.625" csg (29.99') SIMOPS Flush lines and pumps in pits. Begin offloading surface mud. P/U M/U 5" working single&
Johnny Whack Stack W/ back water. L/D single and Johnny Whack. B/D Top Drive and mud lines. PJSM Remove riser & knife valve, P/U Stack and break off
speed head. Remove speed head, DSA and diverter tee. Set Stack on pedestal. Make final cut on 9.625" Csg 22" above E Slips and dress stump. Remove 4"
conductor valves and install 4" caps. SIMOPS Clear rig floor of Csg Equip. P/U Split bushings trip nipple and wear ring/ test plug. Remove bell nipple and clean out
stud holes. PJSM P/U RCD W/ top drive and hang below flow box. P/U Stack and move under RCD. Lower RCD onto Stack and bolt up. Move Stack back to
pedestal. PJSM Install lower wellhead and test plug as per NOS rep. Tighten lower slip lock bolts. Test metal seal to 500 PSI 5 min, 3,800 psi 10 min. SIMOPS Trq
RCD studs to stack as per Beyond rep onsite. PJSM Install tubing spool and BOP. Install 1502 flanges on IA & OA. Secure BOP W/ turnbuckles. Install drip pan,
choke & kill lines and beyond hard lines. SIMOPS M/U valve valve assembly on rig floor. Cont cleaning pits. Daily Disposal to G&I = 1401 bbls, total = 7059 bbls.
Daily Water from 6 mile lake 0 bbls, total = 640 bbls. Daily Water from S-Pad Creek = 1600 bbls. Total Water from S-Pad Creek = 6080 bbls. Daily Metal: 0 lb. Total
Metal 0 lb. Daily Mud lost to formation 3 bbls, total = 74 bbls.
6/10/2021 PJSM, Fill Stack and circ through BEYOND MPD Llines checking for leaks. PT MPD Surface Equip. to 250/1400 psi. Blow down lines R/D MPD Cap and install
flow riser. Install mouse hole. Simops: C/O Super choke. M/U 5" test jt and valve assembly to test plug, R/U Top Drive and Test Hoses. PJSM, Test BOPE on 5"
and 4.5" Test jts to 250/3000 psi. Test gas alarms and PVT System. Accumulator Draw Down: Start 3000 psi, Draw Down 1500 psi, 200 psi build 27 sec, Full
recovery 100 sec, N2 6 @ 2316 psi. R/D Test Equipment, Pull Test plug and L/D same. Blow down choke/Kill lines. Install 5" Hyd Elevators. Install 9" ID Wear
Bushing. RILDS (4) PJSM, P/U 8.5" Bit, M/U Motor, Float Sub, RIH with 9 stds HWDP/Jars out of Derrick to 535'. PJSM, Single in hole P/U 5" DP from 535' to
2470'. PUW 85K, SO, 59K. Drift with 3.125 Drift. PJSM Establish parameters at 2,470’ MD. 400 gpm, 705 psi, 40 rpm, 4-7k trq, P/U 92k SLK 65k ROT 78K. Wash
through cement stringers at 2,517’ MD W/ 3k wob to ES on depth at 2,532’ MD. Drill plug & ES W/ 6k wob. Ream ES 2X W/ pump & rot, 2X W/out. Wash down to
2,564’ MD. Cont single in hole W/ 5” D.P. F/ 2,564’ to 5,682’ MD. Drift 3.125”. P/U 200K SLK 60K. Fill pipe and wash down F/ 5,682’ to 5,800’ MD 320 gpm, 695
psi, 40 rpm, TRQ 15-16k, P/U 198k SLK 68k ROT 105k. CBU 400 gpm 980 psi 40 rpm TRQ 17-18k. No cement seen at surface. R/U Test Equip. Test 9.625” Csg
to 2,600 psi for 30 min on chart. Pumped 3.4 bbl bled back 3.4 bbls. Blow down choke and kill lines. PJSM Drill shoe track F/ 5,800' to 5,937' MD. 400 gpm 800 psi
40 rpm Trq on 15-17 Trq off 15k WOB 3-7k. BFA, FC & shoe on depth. Drill 20' new hole F/ 5,937 to 5,957' MD 400 gpm 1,040 psi P/U 210k SLK 76k ROT 108k.
Good cement seen at surface. PJSM Displace Spud Mud to 8.95 ppg Baradril N. 400 gpm 800 psi 40 rpm Trq 15k. PJSM R/U test Equip. Perform FIT to 12 EMW.
Press up to 642 psi pump 1.1 bbl bled back 0.8 bbl. Daily Disposal to G&I = 228 bbls, total = 7287 bbls. Daily Water from 6 mile lake 0 bbls, total = 640 bbls. Daily
Water from S-Pad Creek = 280 bbls. Total Water from S-Pad Creek = 6360 bbls. Daily Metal: 0 lb. Total Metal 0 lb. Daily Mud lost to formation 0 bbls, total = 74
bbls.
6/11/2021 Blow down choke and kill lines. Monitor well 10 min, static. Pump dry job & BD TD. PJSM POOH rack back 5" D.P. F/ 5,929' to 595' MD. P/U 210k SLK 76k. Calc
51 bbl, Act 60 bbl, lost 9 bbl. PJSM L/D 14 jnts 5" HWDP, rack back 2 stands 5" HWDP & Jars. Break bit and L/D motor. Bit Grade 1-2-WT-A-E-I-NO-BHA. PJSM
Pull wear ring, Johnny Whack stack. Reinstall wear ring. SIMOPS Clean and clear rig floor. Stage BHA components on fir floor. PJSM P/U M/U Rebuilt 8.5 SK616M-
J1D (6X14 TFA 0.9020) 8.5" Hyc NRP, Geo-Pilot 7600 XL 25KSI, 6.75" ADR, 8.375" ILS, 6.75" DGR, 6.75" PWD, 6.75" DM, 6.75" TM HOC, 8.375" Intergral
Blade, 2 ea 6.75" FS (non ported-plunger), 2 ea 6.75" NM FC, 2 ea 5" HWDP, 6.5" SLB Jars & 1 ea 5" HWDP 281.22' MD. Uploaded MWD tools. Install corrosion
ring on top of NM FC. Shallow pulse test tools as per MWD. PJSM Single in hole BHA 3 W/ 5" D.P. F/ 281' to 2,506' MD. Fill pipe and break in Geo-pilot seals. P/U
98k SLK 73k. Cont single in hole W/ 5" D.P. (102 Jnts) F/ 2,506' to 3,524' MD. Cont RIH 5" D.P. F/ derrick F/ 3,524' to 5,804' MD. P/U 155k SLK 72k. No losses.
PJSM Cut and slip drilling line. 10 wraps 63', Accum 14955 TM Left spool 2,512'. Circ at 247 gpm 385 psi F/O 40%. no losses. PJSM Service rig, add 100 gal
Hydraulic fluid to rig HPU. Perform monthly EAM on Crown and blocks. PJSM Remove riser and install RCD bearing as per Beyond rep onsite. Tighten grey clamp
and check for leaks, good. RIH F/ 5,804' to 5,957' MD. Establish parameters prior to exiting shoe (5,929' MD) 400 gpm 750 psi 60 rpm Trq 14k. Clean ECD 9.6
ppg. Drill 8.5" Production Hole F/ 5,957' to 6,475' MD (4,043' TVD) Total 518’ (AROP 94.2’) 500 GPM/ MPD 490, 1,180 PSI, 120 RPM, TRQ on 14K, TRQ off 13-
14K, WOB 5-14K. ECD 10. Max Gas 1,522u. P/U 162k, SLK 71k, ROT 101k. MPD full open. Back ream 60'. Distance to WP08: 2.94', 0.33' high, 2.92' right No
faults. 5 concretions for a total thickness of 17' (3.9% of the lateral). Total footage NB Sand 441' in zone Daily Disposal to G&I = 669 bbls, total = 7956 bbls. Daily
Water from 6 mile lake 0 bbls, total = 640 bbls. Daily Water from S-Pad Creek = 180 bbls. Total Water from S-Pad Creek = 6540 bbls. Daily Metal: 0 lb. Total Metal
0 lb. Daily Mud lost to formation 0 bbls, total = 74 bbls.
6/12/2021 Drill 8.5" Production Hole F/ 6,475' to 7,273' MD (4,028' TVD) Total 798’ (AROP 133’) 500 GPM/ MPD 488, 1,260 PSI, 120 RPM, TRQ on 11-12K, TRQ off 11K,
WOB 3-12K. ECD 10.16 Max Gas 1,526u. P/U 155k, SLK 74k, ROT 101k. MPD full open. Back ream 60'. Drill 8.5" Production Hole F/ 7,273' to 8,038' MD (4,028'
TVD) Total 765’ (AROP 127.85’) 500 GPM/ MPD 488, 1,370 PSI, 120 RPM, TRQ on 11K, TRQ off 12K, WOB 6-10K. ECD 10.24 Max Gas 1,501u. P/U 136k, SLK
76k, ROT 100k. MPD full open. Back ream 60'. At 7,950' MD CC S-28 76.56' Drill 8.5" Production Hole F/ 8,038' to 8,482' MD (4,019' TVD) Total 444’ (AROP
49.4’) 500 GPM/ MPD 483, 1,398 PSI, 120 RPM, TRQ on 9.7K, TRQ off 9.8K, WOB 7-10K. ECD 10.38 Max Gas 1,008u. P/U 134k, SLK 76k, ROT 99k. MPD full
open. Back ream 60'. At 8,466' encountered complete loss in returns. P/U off bottom to 8,414' MD 40 rpm, Trq 7.6k, Reduced pump rate to 2 bpm 28 psi W/ no
returns. Increased pump rate to 6 bpm 340 psi 80 rpm Trq 8.1k w/ no returns. Lined up hole full pump through MPD and established immediate returns. Shut down
hole fill pump and had 20% returns. Initial loss rate 320 bph. Rec 13-15' Reduced rate to 5 bpm 400 psi 90 rpm Trq 8.3k while building 60 bbls 45 ppb LCM Pill
(Baracarb 5 15 ppb, 25 10 ppb 50 20 ppb). Returns increasing to 50% returns. Pumped LCM pill washing back to 8,466' MD as LCM pill exited DS. Drill down F/
8,466' to 8,545' 250 gpm/ MPD 167, 555 PSI 57% returns 100 RPM Trq 8.3k WOB 7-8k. Increased rate to 300 pgm/ MPD 220 W/ 73% returns. ~100 bph
dynamic. Decision was made to Cont drilling at reduced rates. Max Gas 730u. At 8,466' MD S-28 CC 189' left Increased BGG Baracarb F/ 12 to 17 ppb. Fault
encountered at 8,463' MD 1-2' DTW. Lost 218 bbls. Control drill 150-200 ft/hr F/ 8,545' to 8,780' MD (4,017' TVD) Total 235’ (AROP 117.5’) 400 GPM/ MPD 316,
80% returns 975 PSI, 100 RPM, TRQ on 9-10k, TRQ off 9k, WOB 2-15K. ECD 10.04 Max Gas 1005u. P/U 140k, SLK 74k, ROT 100k. MPD full open. At 8,611'
MD Pumped 2 nd 60 bbls 45 ppb LCM Pill (Baracarb 5 15 ppb, 25 10 ppb 50 20 ppb) with no change. At 01:45 Pad operator asked if we were having losses.
Operator shut in S-28 and returns increased to 95%. Total lost 584 bbls. Drill 8.5" Production F/ 8,780' to 9,181' MD (4,015' TVD) Total 401’ (AROP 100.3’) 400-
525 GPM/ MPD 316-505, 95% returns 1,630 PSI, 120 RPM, TRQ on 14-17.5k, TRQ off 14K, WOB 4-15k. ECD 10.55 Max Gas 1004u. P/U 147k, SLK 68k, ROT
98k. MPD full open. Back ream 60' Distance to WP08: 14.25', 14.25' high, 0.08' right Fault #1 at 8,463' MD 1-2' DTW. 16 concretions for a total thickness of 86'
(2.7% of the lateral). Total footage NB Sand 3,131' in zone Daily Disposal to G&I = 570 bbls, total = 8,526 bbls. Daily Water from 6 mile lake 0 bbls, total = 640 bbls.
Daily Water from S-Pad Creek = 800 bbls. Total Water from S-Pad Creek = 7340 bbls. Daily Metal: 9 lb. Total Metal 9 lb. Daily Mud lost on Prod 218 bbl total 218
bbl.
6/13/2021 Drill 8.5" Production F/ 9,181' to 9,690' MD (4,021' TVD) Total 509’ (AROP 84.8’) 400-525 GPM/ MPD 316-505, 95% returns 1,875 PSI, 120-140 RPM, TRQ on
14k, TRQ off 11K, WOB 4-18k. ECD 10.8Max Gas 1025u. P/U 134k, SLK 74k, ROT 97k. MPD full open. Back ream 60' At 9380’ LRS Freeze Protect S-28. Slow
Pump Rate to 400 gpm, see 70 bbl loss opening up S-28 for FP. See 30 bbl gain when FP the Tbg on S-28. See full returns when S-28 Shut back in after FP. Drill
8.5" Production F/ 9,690' to 10'060' MD (4,026' TVD) Total 370’ (AROP 61.6’) 525 GPM/ MPD 502, 95% returns 1,860 PSI, 125 RPM, TRQ on 14k, TRQ off 16K,
WOB 5-18k. ECD 10.9Max Gas 1070u. P/U 144k, SLK 69k, ROT 97k. MPD full open. Back ream 60' Drill 8.5" Production F/ 10,060' to 10,279' MD (4,026' TVD)
Total 219’ (AROP 36.5’) 525 GPM/ MPD 502, 95% returns 1,950 PSI, 80-125 RPM, TRQ on 12k, TRQ off 11K, WOB 5-14k. ECD 11.02 Max Gas 1263u. P/U
139k, SLK 72k, ROT 97k. MPD full open. Back ream 60' At 10,198’ MD survey depth 10,128’ MD 22’ CC to S-28 encountering magnetic inference. Shot survey 2X.
Geo asked for F/ 90° to 91.5°, discussed with town to maintain 90° due to S-28 close approach till 10,300’ MD. Maintain 90° inc and 30° left for more separation F/
S-28. Control drill 150 ft/hr max F/ 10,198’ MD to 10,271’ MD At 10,271’ MD S-28 was 7’ CC 20%R of tool face. Encountered 5K bobble on WOB with no other
signs, started losing Circ. Flow out 500 gpm/ MPD 170 W/ 56% returns (185 BPH Dynamic). P/U off bottom reduce rate to 300 gpm/ MPD 249 902 psi 83%
returns. Stage pumps up to 475 gpm/ 423 89% returns. Wash down F/ 10,258’ to 10,279’ MD to Cont drilling ahead. Contacted S-Pad about S-28 pad operator saw
100 psi spikes but nothing to indicate press up the well.. Cont to see magnetic interference. Closest point to S-28 at 10,258' MD 6.01 CC. Drill 8.5" Production F/
10,279' to 11,02' MD (4,008' TVD) Total 74’ (AROP 124’) 525 GPM/ MPD 495, 95% returns 1,910 PSI, 80-125 RPM, TRQ on 15k, TRQ off 14K, WOB 4-12k. ECD
11.2 Max Gas 1673. P/U 144k, SLK 56k, ROT 97k. MPD full open. Back ream 60'. Dynamic loss 15-20 bph. 10,300' MD target 91.5°. Survey depth 10,382' MD
survey 91.6° inc 341° Az, 31' CC F/ S-28. 10,466.02' MD 91.54° inc 346.9° showing 8.23° DL no indication while drilling. Shot survey 2X may have been to
interference at 10,382'. Distance to WP08: 21.26', 13.70' high, 16.74' right Fault #1 at 8,463' MD 1-2' DTW. 24 concretions for a total thickness of 142' (2.9% of the
lateral). Total footage NB Sand 4,971' in zone Daily Disposal to G&I = 342 bbls, total = 8,868 bbls. Daily Water from 6 mile lake 0 bbls, total = 640 bbls. Daily Water
from S-Pad Creek = 720 bbls. Total Water from S-Pad Creek = 8060 bbls. Daily Metal: 5 lb. Total Metal 24 lb. Daily Mud lost on Prod 645 bbl total 863 bbl.
6/14/2021 Drill 8.5" Production F/ 11,002' to 11,723' MD (4,000' TVD) Total 721’ (AROP 120’) 500 GPM/ MPD 476, 95% returns 1,810 PSI, 130 RPM, TRQ on 13k, TRQ off
12-13K, WOB 4-18k. ECD 11.1 Max Gas 1360. P/U 146k, SLK 55k, ROT 96k. MPD full open. Back ream 60'. Dynamic loss 15-20 bph. Target 89.5 deg. Drill 8.5"
Production F/ 11,723 to 12,330' MD (4,004' TVD) Total 607’ (AROP 101’) 500 GPM/ MPD 476, 95% returns 1,937 PSI, 125 RPM, TRQ on 15k, TRQ off 16K,
WOB 13k. ECD 11.1 Max Gas 1302. P/U 146k, SLK 56k, ROT 98k. MPD full open. Back ream 60'. Dynamic loss 15-20 bph. Target 89.5 deg. Drill 8.5" Production
F/ 12,330' to 12,740' MD (4,015' TVD) Total 410’ (AROP 68.4’) 500 GPM/ MPD 479, 95% returns 1,980 PSI, 120 RPM, TRQ on 16k, TRQ off 17K, WOB 7-15k.
ECD 11.55 Max Gas 1267. P/U 150, SLK 52k, ROT 95k. MPD full open. Back ream 60' Out bottom of NB at 12,520' MD. Geo called for 93.5° target. At 12,612'
perform clean up cycle BU 2X due to ECD F/ 11.9 to 11.6. Dynamic loss 10-15 bph. MPS-28: 171.23' CC 0.761 SF @ 12,721' MD. MPU S-56PB1: 24.17' CC 0.34
SF @ 12317.8' MD. MPS-28: SF 0.627 173.95' CC @ 12,690' MD. MPU S-56PB1: 0.291 SF 28.99' CC @ 12,530' MD Drill 8.5" Production F/ 12,740' to 13,250'
MD (3,991' TVD) Total 510’ (AROP 85’) 475 GPM/ MPD 454, 97% returns 1,900 PSI, 120 RPM, TRQ on 14-15k, TRQ off 14k, WOB 5-16k. ECD 11.78 Max Gas
546. P/U 147, SLK 45k, ROT 93k. MPD full open. Back ream 60' Dynamic loss slow to 1-5 bph. At 12,926'pumped tandem 30 bbl 8.6 ppg 30 Vis & 30 bbl 9.1 ppg
160 Vis sweeps to control ECD's. Sweep back on time, 10% increase. Back in NB at 12,950' MD. Distance to WP08: 14.44', 13.33' high, 5.54' Left Fault #1 at
8,463' MD 1-2' DTW. 29 concretions for a total thickness of 160' (2.2% of the lateral). Total footage NB Sand 6,756' Out of zone 430', total 7,186' Daily Disposal to
G&I = 684 bbls, total = 9,552 bbls. Daily Water from 6 mile lake 0 bbls, total = 640 bbls. Daily Water from S-Pad Creek = 960 bbls. Total Water from S-Pad Creek =
9020 bbls. Daily Metal: 2 lb. Total Metal 26 lb. Daily Mud lost on Prod 291 bbl total 1154 bbl.
6/15/2021 Drill 8.5" Production F/ 13,250' to 13,805' MD (3,979' TVD) Total 555’ (AROP 92’) 500 GPM/ MPD 473, 97% returns 2,220 PSI, 120 RPM, TRQ on 16-19k, TRQ
off 14-17k, WOB 5-15k. ECD 11.78 Max Gas 913u. P/U 150, SLK 35k, ROT 92k. MPD full open. Back ream 60' Drill 8.5" Production F/ 13,805' to TD @ 14,074'
MD (3,986' TVD) Total 269’ (AROP 67’) 500 GPM/ MPD 473, 97% returns 2,220 PSI, 120 RPM, TRQ on 16-19k, TRQ off 14-17k, WOB 5-15k. ECD 11.78 Max
Gas 913u. P/U 150, SLK 35k, ROT 92k. MPD full open. Back ream 60'. Final survey. PJSM Pump 40 bbl 8.5 ppg 35 vis, 40 bbl 10.3 ppg 185 vis tandem sweeps.
500 gpm/ mpd 477 2,248 psi, 120 rpm, Trq 16k. Sweep back on time W/ 50% inc. Rack back 1 stand to 14,013' MD Rot Rec 3X BU. Seeing 20 bph dynamic
losses at end of 3 BU. SIMOPS Build Sapp pills and prep for Disp. Max Gas 172u PJSM RIH 1 stand to 14,074' MD Pump 3X 40 bbls SAPP Pills W/ 20 bbl 9.2 ppg
viscosified lubricated (1.5%) QuickDril spacers. Chase W/ 9.2 ppg QuickDril Vis Lub brine. Overboard all returns. Pills back on time. 414 gpm/ mpd 393 1,415 PSI
120 rpm, trq 16k prior Dis. After 455 gpm/ mpd 435 1,205 psi Before 414 gpm/ mpd 393 1,415 PSI 120 rpm, trq 16k prior Dis. After 455 gpm/ mpd 435 1,205 psi
120 rom trq 19k. Seeing ~20 bph dynamic loss. Rot Rec F/ 14,074' to 14,013' MD. 455 gpm/ mpd 435 1,205 psi, 120 rpm Trq 19k. Clean pits 3&4 and add 9.2 ppg
QuciDril. Prep pits for BROOH. CBU 3X for passing PST. Suction After Displacement 19.6 13.5 13.4 Average 16.1 sec Flowline after Displacement 14.8 13.8 14.1
Average 14.2 sec Monitor well 10 min initial flow 18 bph static after 5 min. Shut in MPD no press. BROOH F/ 14,074' to 10,964' MD 500 GPM/ MPD 462, 1,350
PSI, 120 RPM, TRQ 15k, ECD 10.56 Max Gas 812u. P/U 165, SLK 65k, ROT 100k. MPD full open. Distance to WP08: 13.5', 13.27' high, 2.48' right Fault #1 at
8,463' MD 1-2' DTW. 38 concretions for a total thickness of 220' (2.7% of the lateral). Total footage NB Sand 7,675', Out zone 470' Total 8,145' Daily Disposal to
G&I = 2332 bbls, total = 11884 bbls. Daily Water from 6 mile lake 0 bbls, total = 640 bbls. Daily Water from S-Pad Creek = 880 bbls. Total Water from S-Pad Creek
= 9900 bbls. Daily Metal: 5 lb. Total Metal 31 lb. Daily Mud lost on Prod 104 bbl total 1258 bbl.
6/16/2021 BROOH F/ 10,964' to 6,512' MD 500 GPM/ MPD 420, 1,040 PSI, 120 RPM, TRQ 6-8k, ECD 10.5 Max Gas 240u. P/U 103, SLK 128k, ROT 88k. MPD full open.
Dynamic loss 20 bph. BROOH F/ 6,512' to 5,877' MD 500 GPM/ MPD 422, 1,040 PSI, 120 RPM, TRQ 6-8k, ECD 10.5 Max Gas 18u. P/U 132, SLK 88k, ROT
103k. MPD full open. Dynamic loss 20 bph. CBU over 5 stands 6,131' to 5,877' MD. No issue at Shoe. (5,929') At 5,877' MD pump 32 bbl 9.2 ppg 160 vis sweep.
On time W/ 10% increase. 550 GPM/ MPD 532 1.259 psi 80 rpm Trq 6-8k PST pass suction 5.92, 6.04, 6.57 Avg 6.18. Flowline 4.97, 5.65, 6.12 Avg 5.58.
Dynamic loss 11 bph. PJSM Service TD & grease crown. Monitor well for 30 min, static. PJSM Remove RCD bearing as per Beyond rep onsite. Install trip nipple.
Monitor well through static. PJSM POOH L./D 5" D.P. F/ 5,877' to 281' MD P/U 102k SLK 77k. lost 18 bbls for trip. PJSM L/D BHA #3. Recover corrosion ring. Drift
landed at FC. Download MWD tool. L/D TM,, DM, ADR, GeoPilot and Bit. Severe wear on ILS. Bit Grade 2-1-CT-N-X-I-NO-TD. Static loss ~4 bph. Clean and clear
rig floor of BHA components. PJSM C/O 5" hydraulic elevators to 4.5" YC elevators. R/U Weatherford tongs and handling Equip. Stage 4.5" liner components in
pipe shed. Bring 36 centralizers and stop rings to rig floor. SIMOPS trouble shoot skate-tripped breaker. Static loss ~4 bph. PJSM RIH 4.5" Screen & 4.5" 13.5# L-
80 W625 as per tally to 5,911' MD P/U 101k SLK 76k. Trq 9.6k. Lost 10 bbls. Daily Disposal to G&I = 416 bbls, total = 12300 bbls. Daily Water from 6 mile lake 0
bbls, total = 640 bbls. Daily Water from S-Pad Creek = 480 bbls. Total Water from S-Pad Creek = 10380 bbls. Daily Metal: 0 lb. Total Metal 31 lb. Daily Mud lost on
Prod 104 bbl total 1492 bbl.
6/17/2021 PJSM Continue RIH 4.5" Lower Screen completion assy (13.5# L-80 W625) as per tally from 5811' to 8305' MD P/U 109k SLK 76k. Trq 9.6k. No issues exiting
shoe, clean trip in open hole. M/U SLZXP BOT packer assy. Obtain parameters 5/10 rpm w/ 7.9k tq. 2 bpm, 68 psi. 13 bbl loss for trip C/O handling equipment
to 5" dp. RIH w/ 4.5" lower completion assy conveyed on 5" NC50 drill pipe out of derrick F/ 8305' - T/ 14074' MD (final set depth). 11 bbl loss for trip. 163k up,
77k dn. Clean trip in lateral with no issues. Tag btm with 6k dn (on depth). Pick up to break over putting liner on depth ~14074' MD (TOL @ 5768' MD). Drop
1.25" phenolic setting ball and pump dn @ 3 bpm, 215 psi slowing to 2 bpm @ 1100 stks w/ 130 psi. Ball on seat @ 1331 stks (1577 stks calc). Psi up to 5100 psi
w/ 5 min hold @ 2700 psi. Saw set @ 2080 psi, Neutralize @ 3340 psi and psi dump @ 5100 psi shearing circ sub. P/U 1' over break over w/ clean 127k up wt
(confirm liner released). R/U and test R/U and flood surface lines. Test annulus against packer assy w/ 1500 psi 10 min hold (chart and record same). Test good.
Bleed down and R/D test equipment. Monitor well (3 bph static losses). Pump dry job (CI brine), B/D TDS. POOH laying down 5" drill pipe F/ 5785' - T/ 5467' MD.
Cont POOH L/D 5" D.P. F/ 5,467' to running tool. Burst disc sheared. Running tool looked good. L/D as per Baker rep onsite. Lost 16 bbl for trip. PJSM M/U Johnny
Wacker and YoYo 5" D.P. F/ derrick and L/D remainder 5" D.P. 45 stands. Lost 10 bbl. PJSM Drain stack. Pull wear ring and set test plug. L/D 5" D.P. Bleed down
Koomey. C/O upper VBR's to 7" solid body. Recharge Koomey. SIMOPS R/U Weatherford 7" handling Equip. PJSM P/U 7" test jnts & install head pin. R/U test
Equip. Test Annular 250/3000 psi 5/5 min, upper 7" rams 250/3000 psi 5/5 min on chart. R/D test Equip L/D test jnt. SIMOPS Cont R/U Weatherford Power Tongs.
PJSM P/U M/U 7" Seal Assy RIH W/ 7" 26# L-80 TXP BTC to 1,400' MD. TRQ 14,750 lb/ft Running speed 90 ft/min. Lost 3 bbls. Daily Disposal to G&I = 160 bbls,
total = 12460 bbls. Daily Water from 6 mile lake 0 bbls, total = 640 bbls. Daily Water from S-Pad Creek = 0 bbls. Total Water from S-Pad Creek = 10380 bbls. Daily
Metal: 0 lb. Total Metal 31 lb. Daily Mud lost on Prod 59 bbl total 1551 bbl.
Activity Date Ops Summary
6/18/2021 Continue RIH W/ 7" tieback assy 26# L-80 TXP BTC F/1400' T/ 5777 (9' deep from tieback tally)' MD. TRQ 14,750 lb/ft Running speed 90 ft/min. Lost 30 bbls for
total trip.,Set down at taq depth 5777' (no go depth) with 20k down. Space out, L/D jt 142 and 141. Install 9.86' pup jt below 141. M/U hanger and landing jt. S/O
landing out on hanger with 55k on hanger (90k dn, 147k up). 2.19' off NoGo, Seal depth 5784.41' MD. R/U to reverse circulate,Reduce annular psi to 550 psi and
close same. Pressure up on annulus to 250 psi, strip up until psi dump to locate 1" ports on seal assy. Reverse circulate 7"x9-5/8" with 160 bbls 9.2 CI brine, 65
bbls diesel (Freeze protect) @ 5 bpm, 330 psi. Strip down and land back out on depth.,B/O landing jt, Drain stack. Install packoff assy and test same 500/5000 psi
with 5/10 min hold (test good). R/D WOT 7" casing equipment. L/D packoff running tool.,R/U and test 7" x 9-5/8" annulus to 1000 psi with 30 min hold. Chart and
record same (test good). .5 bbl pumped in, .5 bbl bled back.,PJSM M/U X/O to FOSV. RIH 4.5" Completion as per Tally. P/U M/U 4.5" Mule Shoe, 664' Tubing 4.5"
12.6# L-80 W521, M/U XN Nipple (3.725" NoGO), 7" Baker Premier Packer, Ported Sub, Sliding Sleeve & Gauge as per tally. Install sensor and tech wire to Gauge
as per Centrilift rep onsite.,Cont RIH W/ 4.5" 12.6# L-80 W521 F/ 893' to 5795.73' MD. Tag W/ Jnt142 3K. Lost 22 bbls. Install 5 ea every jnt after Gauge and
every other one to surface. Test tech wire ecery 1,800'. TRQ 521 4,700 ft/lb.,PJSM L/D Jnts 142 & 141. Space out 4.79' pup and P/U Jnt 141. C/O Elevators to 5"
& P/U 5" D.P. M/U X/O and Hanger. Terminate Tech wire and test, good. Land Hanger W/ shoe at 5793.99' 1.74' off NoGo. P/U 94K SLK 63K Wt in hanger 28K.
RILDS. Ran 63 CC.,PJSM Set BPV as per NOS. Clear rig floor of Weatherford & Centrilift tools and Equip. Johnny Whack Stack. Flush choke, kill and choke
manifold. Blow down.,PJSM Bleed off Koomey. L/D mouse hole. Pull riser and remove drip pan. Remove choke and kill lines. Hook up bridge cranes and break
bolts on DSA. SIMOPS Dismantle fluid end MP #2 for inspection. Haul off fluid in pits and prep to clean.,Daily Disposal to G&I = 347 bbls, total = 12807 bbls. Daily
Water from 6 mile lake 0 bbls, total = 640 bbls. Daily Water from S-Pad Creek = 0 bbls. Total Water from S-Pad Creek = 10380 bbls. Daily Metal: 8 lb. Total Metal
39 lb. Daily Mud lost on Prod 72 bbl total 1623 bbl.
6/19/2021 N/D koomey lines. Rack back BOP and hot bolt same. Secure stack with 4pt chains. N/D DSA and stage in cellar. Set CTS in BPV.,Mob tree into cellar and N/U
same. BOT rep perform final check on tek wire (1748 gauge psi w/ 74°F temp). Test void 500/5000 with 5/10 min hold (test good). Flood and test tree 250/5000
psi with 5/15 min hold (test good). Remove CTS and BPV. Sym ops - Clean pits and prep for rig move. Process 5" dp in shed.,Bridle up and prep derrick to scope
down. Continue clean pits. Remove peripheral equipment from around rig. Clean rig floor and cellar area. Check tires for rig move.,R/U LRS to IA. P/T lines to
1000 psi. Freeze protect 7"x4.5" IA w/ 47.5 bbls diesel (2550' MD) @ ~1 bpm, 500 psi. SICP 290 psi. F/P 4.5" tbg with 36.5 bbls diesel (2550' MD) @ ~1 bpm,
500 psi. SITP 290 psi. Release LRS @ 14:00 hrs.,R/U lubricator riser loaded with 1-7/8" ball and rod (no roller stems). Drop ball and rod then rig down riser. R/U
on tbg and psi up to 3000 psi w/ 15 min hold. Test 4.5" tubing to 3500 psi with 30 min hold, chart and record same (test good). Bleed down tbg to 2000 psi. P/T
4.5" x 7" IA to 3500 psi with 30 min hold, chart and record same (test good). Bleed IA down to 0. Bleed down tbg to 350 psi. R/D test equip.,Went to gen power at
16:00.,Release rig @ 18:00. Blow down & disconnect H2O., steam & air. Scope down derrick. Disconnect inner connects. Swap to cold start. Flip roof hatches and
secure stairs. NES on location 21:00. Jack up and spot pipe shed,, Gen, Mud Mod & Cattwalk. Install steering are on sub. Hook up D9 to sub. Jack up sub and pull
off well (S-45). Start laying Matts to crab walk sub to S-44.,Daily Disposal to G&I = 575 bbls, total = 13035 bbls. Daily Water from 6 mile lake 0 bbls, total = 640
bbls. Daily Water from S-Pad Creek = 0 bbls. Total Water from S-Pad Creek = 10380 bbls. Daily Metal: 0 lb. Total Metal 39 lb. Daily Mud lost on Prod 0 bbl total
1623 bbl.
6/3/2021Spud Date:
Well Name:
Field:
County/State:
MP S-45
Milne Point
Hilcorp Energy Company Composite Report
, Alaska
50-029-23693-00-00API #:
TD Shoe Depth: PBTD:
No. Jts. Returned
RKB RKB to BHF RKB to THF
Jts.
1
2
1
1
1
81
1
1
1
61
Yes X No X Yes No 5.8
Fluid Description:
Liner hanger Info (Make/Model): Liner top Packer?: Yes No
Liner hanger test pressure:X Yes No
Centralizer Placement:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:Yes No
Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job
Cement returns to surface? Yes X No Spacer returns?Yes X No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:Yes No
Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job
Cement returns to surface? Yes X No Spacer returns?Yes X No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Post Job Calculations:
Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped:
Cmt returned to surface: Calculated cement left in wellbore:
OH volume Calculated: OH volume actual: Actual % Washout:
Casing (Or Liner) Detail
Shoe
RKB
10 K55
353.5 19324.8SECOND STAGEHAL
Rotate Csg Recip Csg Ft. Min. PPG9.6
Shoe @ 5929 FC @ Top of Liner5,803.91
Floats Held
30 609
175 434
H2O
CASING RECORD
County State Alaska Supv.J Lott / J Vanderpool
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.MP S-45 Date Run 9-Jun-21
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
TXP BTC Innovex 1.57 5,929.00 5,927.43
25.80 25.80
Csg Wt. On Hook:305,000 Type Float Collar:Conventional No. Hrs to Run:17
8.34 4
0
10
10.7 288 4.5
100
Bump Plug?FIRST STAGE10Pol-E-Flake red dye 60
15.8
215
3.6
8.34 4.5 20/20
20/20
0
Halliburton
15.8 82
Bump pressBump Plug?
ok
0
2532.41
5,929.005,937.00
CEMENTING REPORT
Csg Wt. On Slips:115,000
Spud Mud
Pol-E-Flake red dye
561 2.88
Stage Collar @
50
Bump press
0
ES Closure OK
57
12 182
26.60 RKB to CHF
Type of Shoe:Ported Casing Crew:Weatherford
No. Jts. Delivered 151 No. Jts. Run 145 6
Length Measurements W/O
Threads
Ftg. Delivered 6,191.00 Ftg. Run 5,929.00 Ftg. Returned 262.00
Ftg. Cut Jt.29.99 Ftg. Balance
www.wellez.net WellEz Information Management LLC ver_04818br
3.6
Artic Cem
Type
2 ea Jnt1, 1 ea Jnt 2, 1 ea F/ Jnts 4-26, every other Jnt F/ 27-50, 1 ea F/ Jnt 79 to ES, 1 ea F/ ES to Jnt 90, every
other F/ jnt 92-142. Total 80
Casing 9 5/8 40.0 L-80 TXP BTC Tenaris 82.14 5,927.43 5,845.29
Float Collar 10 K55 TXP BTC Innovex 1.29 5,845.29 5,844.00
Casing 9 5/8 40.0 L-80 TXP BTC Tenaris 40.09 5,844.00 5,803.91
Baffle Adapter 10 40.0 TXP BTC Halliburton 1.39 5,803.91 5,802.52
Casing 9 5/8 40.0 L-80 TXP BTC Tenaris 3,249.63 5,802.52 2,552.89
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Artic Cem 435 2.35
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@
Benjamin Hand Digitally signed by Benjamin Hand
Date: 2021.06.20 13:20:50 -08'00'Chelsea Wright Digitally signed by Chelsea
Wright
Date: 2021.06.21 07:24:06 -08'00'
David Douglas Hilcorp Alaska, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal or fax to 907 564-4422.
Received By: Date:
Date: 6/23/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
MPU S-45 (PTD 221-042)
FINAL LWD FORMATION EVALUATION LOGS (06/03/2021 to 06/15/2021)
•EWR-M5, AGR, ABG, DGR, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs)
•Final Definitive Directional Survey
SFTP Transfer - Data Folders:
Please include current contact information if different from above.
06/28/2021
PTD: 2210420
E-Set: 35292
David Douglas Hilcorp Alaska, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal or fax to 907 564-4422.
Received By: Date:
Date: 06/23/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
MPU S-45 (PTD 221-042)
FINAL EOW REPORT – GEOSTEERING LOGS (06/11/2021 to 06/15/2021)
SFTP Transfer - Data Folders:
Please include current contact information if different from above.
06/28/2021
PTD: 2210420
E-Set: 35291
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, Inc.
3800 Centerpoint Drive, Suite 400
Anchorage, AK 99503
Re: Milne Point Field, Kuparuk Oil Pool, MPU S-45
Hilcorp Alaska, LLC
Permit to Drill Number: 221-042
Surface Location: 2086' FNL, 634' FEL, Sec. 12, T12N, R10E, UM, AK
Bottomhole Location: 219' FNL, 936' FWL, Sec. 01, T12N, R10E, UM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs
run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment
of this well.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Jeremy M. Price
Chair
DATED this ___ day of May, 2021.
Jeremy
Price
Digitally signed
by Jeremy Price
Date: 2021.05.21
11:25:39 -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: 14,142' TVD: 3,969'
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:
2485'
4b. Location of Well (State Base Plane Coordinates - NAD 27):10.KB Elevation above MSL (ft): 63.4'15.Distance to Nearest Well Open
Surface: x-565378 y- 5999858 Zone- 4 36.9' to Same Pool: 50'
16.Deviated wells: Kickoff depth: 300 feet 17.Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 103 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
Driven 20" 129.5# X-52 80' Surface Surface 110' 110'
47# L-80 TXP 2,500' Surface Surface 2,500' 1,929'
40# L-80 TXP 3,128' 2,500' 1,929' 5,778' 4,040'
Tieback 7" 26# L-80 TXP 5,628' Surface Surface 5,628' 4,027'
8-1/2" 4-1/2" 13.5# L-80 Hyd625 8,764' 5,628' 4,027' 14,142' 3,969'
19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations)
Junk (measured):
TVD
Hydraulic Fracture planned? Yes No
20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis
Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements
Contact Name: Nathan Sperry
Monty Myers Contact Email:nathan.sperry@hilcorp.com
Drilling Manager Contact Phone:777-8450
Date:
Permit to Drill API Number: Permit Approval
Number:Date:
Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales:
Samples req'd: Yes No Mud log req'd: Yes No
H2S measures: Yes No Directional svy req'd: Yes No
Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No
Post initial injection MIT req'd: Yes No
APPROVED BY
Approved by: COMMISSIONER THE COMMISSION Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
12-1/4" 9-5/8"
June 3, 2021
21. I hereby certify that the foregoing is true and the procedure approved herein will not be
deviated from without prior written approval.
Surface
Perforation Depth TVD (ft):
GL / BF Elevation above MSL (ft):
Perforation Depth MD (ft):
Tieback
Uncemented Screen Liner
Effect. Depth MD (ft): Effect. Depth TVD (ft):
Authorized Title:
Authorized Signature:
Production
Liner
Intermediate
Authorized Name:
Conductor/Structural
LengthCasing Cement Volume MDSize
Plugs (measured):
(including stage data)
Stg 1 L - 927 ft3 / T - 458 ft3
2560
18.Casing Program: Top - Setting Depth - BottomSpecifications
1472
Total Depth MD (ft): Total Depth TVD (ft):
022224484
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
Stg 2 L - 1935 ft3 / T - 313 ft3
1068
2486' FSL, 1695' FEL, Sec. 12, T12N, R10E, UM, AK
219' FNL, 936' FWL, Sec. 01, T12N, R10E, UM, AK
01-001
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
Hilcorp Alaska, LLC
2086' FNL, 634' FEL, Sec. 12, T12N, R10E, UM, AK ADL 380109
MPU S-45
Milne Point Field
Schrader Bluff Oil Pool
Cement Quantity, c.f. or sacks
Commission Use Only
See cover letter for other
requirements.
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
5.17.2021
By Meredith Guhl at 2:26 pm, May 17, 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: 2021.05.17 14:10:57 -08'00'
Monty M
Myers
XXBOPE test to 3000 psi. Annular to 2500 psi.
221-042
MGR20MAY2021
X
X
DLB 05/20/2021
X
50-029-23693-00-00
SDR-5/17/21
X X
dts 5/20/2021
JLC 5/21/2021
5/21/21
Jeremy Price Digitally signed by Jeremy Price
Date: 2021.05.21 11:25:56 -08'00'
Milne Point Unit
(MPU) S-45
Drilling Program
Version 1
4/15/2021
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 4-1/2” Screened Liner ...................................................................................................... 33
17.0 Run 7” Tieback ........................................................................................................................ 37
18.0 Run Upper Completion – Jet Pump ........................................................................................ 40
19.0 Innovation Rig Diverter Schematic ......................................................................................... 42
20.0 Innovation Rig BOP Schematic ............................................................................................... 43
21.0 Wellhead Schematic ................................................................................................................. 44
22.0 Days Vs Depth .......................................................................................................................... 45
23.0 Formation Tops & Information............................................................................................... 46
24.0 Anticipated Drilling Hazards .................................................................................................. 48
25.0 Innovation Rig Layout ............................................................................................................. 52
26.0 FIT Procedure .......................................................................................................................... 53
27.0 Innovation Rig Choke Manifold Schematic ............................................................................ 54
28.0 Casing Design ........................................................................................................................... 55
29.0 8-1/2” Hole Section MASP ....................................................................................................... 56
30.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 57
31.0 Surface Plat (As Built) (NAD 27) ............................................................................................. 58
Page 2
Milne Point Unit
S-45 SB Producer
Drilling Procedure
1.0 Well Summary
Well MPU S-45
Pad Milne Point “S” Pad
Planned Completion Type Jet pump on 4-1/2 tubing
Target Reservoir(s) Schrader Bluff NB Sand
Planned Well TD, MD / TVD 14,142’ MD / 3,969’ TVD
PBTD, MD / TVD 14,142’ MD / 3,969’ TVD
Surface Location (Governmental) 2086' FNL, 634' FEL, Sec 12, T12N, R10E, UM, AK
Surface Location (NAD 27) X= 565378, Y=5999858
Top of Productive Horizon
(Governmental)2486' FSL, 1695' FEL, Sec 12, T12N, R10E, UM, AK
TPH Location (NAD 27) X= 564323, Y=5999140
BHL (Governmental) 219' FNL, 936' FWL, Sec 1, T12N, R10E, UM, AK
BHL (NAD 27) X= 561605, Y=6006971
AFE Drilling Days 17
AFE Completion Days 4
Maximum Anticipated Pressure
(Surface) 1068 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 1472 psig
Work String 5” 19.5# S-135 NC 50
Innovation KB Elevation above MSL: 26.5 ft + 36.9 ft = 63.4 ft
GL Elevation above MSL: 36.9 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
Page 3
Milne Point Unit
S-45 SB Producer
Drilling Procedure
2.0 Management of Change Information
Page 4
Milne Point Unit
S-45 SB Producer
Drilling Procedure
3.0 Tubular Program:
Hole
Section
OD (in)ID
(in)
Drift
(in)
Conn OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 20” 19.25”---X-52Weld
12-1/4”9-5/8” 8.835”8.679”10.625”40 L-80 TXP 5,750 3,090 916
9-5/8” 8.681”8.525”10.625”47 L-80 TXP 6,870 4,750 1,086
Tieback 7” 6.276 6.151 7.656 26 L-80 TXP 7,240 5,410 604
8-1/2”4-1/2”
Screens 3.920 3.795 4.714 13.5 L-80
Hydril 625 9,020 8,540 279
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).
Page 5
Milne Point Unit
S-45 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 nathan.sperry@hilcorp.com and
joseph.lastufka@hilcorp.com
5.6 Casing and Cement report
x Send casing and cement report for each string of casing to mmyers@hilcorp.com
nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com
5.7 Hilcorp Milne Point Contact List:
Title Name Work Phone Cell Phone Email
Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmyers@hilcorp.com
Drilling Engineer Joe Engel 907.777.8395 805.235.6265 jengel@hilcorp.com
Drilling Engineer Nate Sperry 907.777.8450 907.301.8996 nathan.sperry@hilcorp.com
Completion Engineer Ian Toomey 907.777.8434 907.903.3987 itoomey@hilcorp.com
Geologist John Salsbury 907.777.8481 907.350.1088 jsalsbury@hilcorp.com
Reservoir Engineer Reid Edwards 907.777.8421 907.250.5081 reedwards@hilcorp.com
Drilling Env. Coordinator Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com
EHS Manager Carl Jones 907.777.8327 907.382.4336 cajones@hilcorp.com
Drilling Tech Joe Lastufka 907.777.8400 907.227.8496 Joseph.Lastufka@hilcorp.com
Page 6
Milne Point Unit
S-45 SB Producer
Drilling Procedure
6.0 Planned Wellbore Schematic
Page 7
Milne Point Unit
S-45 SB Producer
Drilling Procedure
7.0 Drilling / Completion Summary
MPU S-45 is a grassroots producer planned to be drilled in the Schrader Bluff NB sand. S-45 is part of a
multi well program targeting the Schrader Bluff sand on S-pad
The directional plan is a catenary well path with 12-1/4” hole and 9-5/8” surface casing set into the top of the
Schrader Bluff NB sand. An 8-1/2” lateral section will be drilled. A 4-1/2” liner will be run in the open hole
section and the well will be produced with a jet pump.
The Innovation Rig will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately June 3, 2021, pending rig schedule.
Surface casing will be run to 5,778’ MD / 4,040’ TVD and cemented to surface via a 2 stage primary cement
job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed,
necessary remedial action will then be discussed with AOGCC authorities.
All cuttings & mud generated during drilling operations will be hauled to the Milne Point “B” pad G&I facility.
General sequence of operations:
1. MIRU Innovation Rig to well site
2. N/U & Test 13-5/8” Diverter and 16” diverter line
3. Drill 12-1/4” hole to TD of surface hole section. Run and cement 9-5/8” surface casing
4. N/D diverter, N/U wellhead, NU 13-5/8” 5M BOP & Test
5. Drill 8-1/2” lateral to well TD
6. Run 4-1/2” production liner
7. Run 7” tieback
8. Run Upper Completion
9. N/D BOP, N/U Tree, RDMO
Reservoir Evaluation Plan:
1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res
2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering)
Page 8
Milne Point Unit
S-45 SB Producer
Drilling Procedure
8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations,
specific regulations are listed below. If additional clarity or guidance is required on how to comply with
a specific regulation, do not hesitate to contact the Anchorage Drilling Team.
x BOPs shall be tested at (2) week intervals during the drilling and completion of MPU S-45. 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:
No variances are requested at this time.
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Summary of Innovation BOP Equipment & Test Requirements
Hole Section Equipment Test Pressure (psi)
12-1/4”x 13-5/8” 5M CTI Annular BOP w/ 16” diverter line Function Test Only
8-1/2”
x 13-5/8” x 5M Control Technology Inc Annular BOP
x 13-5/8” x 5M Control Technology Inc Double Gate
o Blind ram in btm cavity
x Mud cross w/ 3” x 5M side outlets
x 13-5/8” x 5M Control Technology Single ram
x 3-1/8” x 5M Choke Line
x 3-1/8” x 5M Kill line
x 3-1/8” x 5M Choke manifold
x Standpipe, floor valves, etc
Initial Test: 250/3,000
Subsequent Tests:
250/3,000
Primary closing unit: Control Technology Inc. (CTI), 6 station, 3,000 psi, 220 gallon accumulator unit.
Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an electric
triplex pump on a different electrical circuit and emergency pressure is provided by bottled nitrogen.
The remote closing operator panels are located in the doghouse and on accumulator unit.
Required AOGCC Notifications:
x Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
x 24 hours notice prior to spud.
x 24 hours notice prior to testing BOPs.
x 24 hours notice prior to casing running & cement operations.
x Any other notifications required in APD.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov
Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov
Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov
Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
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9.0 R/U and Preparatory Work
9.1 S-45 will utilize a newly set 20” conductor on S-pad. Ensure to review attached surface plat and
make sure rig is over appropriate conductor.
9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor.
9.3 Install landing ring.
9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each.
9.5 Level pad and ensure enough room for layout of rig footprint and R/U.
9.6 Rig mat footprint of rig.
9.7 MIRU Innovation. Ensure rig is centered over conductor to prevent any wear to BOPE or
wellhead.
9.8 Mud loggers WILL NOT be used on either hole section.
9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80qF).
9.10 Ensure 5” liners in mud pumps.
x White Star Quattro 1,300 HP mud pumps are rated at 4,097 psi, 381 gpm @ 140 spm @
96.5% volumetric efficiency.
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10.0 N/U 13-5/8” 5M Diverter System
10.1 N/U 13-5/8” CTI BOP stack in diverter configuration (Diverter Schematic attached to program).
x N/U 20” x 13-5/8” DSA
x N/U 13 5/8”, 5M diverter “T”.
x NU Knife gate & 16” diverter line.
x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
x Diverter line must be 75 ft from nearest ignition source
x Place drip berm at the end of diverter line.
x Utilized extensions if needed.
10.2 Notify AOGCC. Function test diverter.
x Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens
prior to annular closure.
x Ensure that the annular closes in less than 30 seconds (API Standard 64 3rd edition March 2018
section 12.6.2 for packing element ID less than or equal to 20”)
10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the
vent line tip. “Warning Zone” must include:
x A prohibition on vehicle parking
x A prohibition on ignition sources or running equipment
x A prohibition on staged equipment or materials
x Restriction of traffic to essential foot or vehicle traffic only.
24 hour notice for AOGCC to witness.
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10.4 Rig & Diverter Orientation:
x May change on location
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11.0 Drill 12-1/4” Hole Section
11.1 P/U 12-1/4” directional drilling assembly:
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Be sure to run a UBHO sub for wireline gyro
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 NB 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 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 9.2
minimum at TD (pending MW increase due to hydrates).
x Perform wireline gyros until clean MWD surveys are seen. Take MWD surveys every stand
drilled.
x Be prepared for gas hydrates. In MPU they have been encountered typically around 2,100-
2,400’ TVD (just below permafrost). Be prepared for hydrates:
x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD
x Monitor returns for hydrates, checking pressurized & non-pressurized scales
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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 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 9.2+ ppg.
Depth Interval MW (ppg)
Surface –Base Permafrost 8.9+
Base Permafrost - TD 9.2+ (For Hydrates if need based on offset wells)
MW can be cut once ~500’ below hydrate zone
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.
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).
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System Type:8.8 – 9.2 ppg Pre-Hydrated Aquagel/freshwater spud mud
Properties:
Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp
Surface 8.8 –9.8 75-175 20 - 40 25-45 <10 8.5 –9.0 70 F
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, 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.
Note: Minimum EMW needed is 8.46 ppg. DLB
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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” TXP x DS50 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” TXP, 2 Centralizers 10’ from each end w/ stop rings
1 joint –9-5/8” TXP, 1 Centralizer mid joint w/ stop ring
9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’
1 joint –9-5/8” TXP, 1 Centralizer mid joint with stop ring
9-5/8” HES Baffle Adaptor
x Ensure bypass baffle is correctly installed on top of float collar.
x Ensure proper operation of float equipment while picking up.
x Ensure to record S/N’s of all float equipment and stage tool components.
This end up.
Bypass Baffle
2500' of 47#
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12.5 Float equipment and Stage tool equipment drawings:
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12.6 Continue running 9-5/8” surface casing
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
x 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” 40# L-80 TXP Make-Up Torques:
Casing OD Minimum Optimum Maximum
9-5/8”18,860 ft-lbs 20,960 ft-lbs 23,060 ft-lbs
9-5/8” 47# L-80 TXP MUT:
Casing OD Minimum Optimum Maximum
9-5/8”21,440 ft-lbs 2,3820 ft-lbs 26,200 ft-lbs
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12.8 Continue running 9-5/8” surface casing
x Centralizers: 1 centralizer every 3rd joint to 200’ from surface
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
o 1 centralizer every 2 joints to base of conductor
12.9 The last 2,000’ of 9-5/8” will be 47#, from 2,000’ to Surface
x Ensure drifted to 8.525”
2,500'2,500'
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12.10 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.11 Slow in and out of slips.
12.12 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the
landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference
when getting the casing on depth.
12.13 Lower casing to setting depth. Confirm measurements.
12.14 Have slips staged in cellar, along with necessary equipment for the operation.
12.15 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement
job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible
reciprocate casing string while conditioning mud.
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13.0 Cement 9-5/8” Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
x Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks.
x Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
x Review test reports and ensure pump times are acceptable.
x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
13.2 Document efficiency of all possible displacement pumps prior to cement job.
13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
13.5 Fill surface cement lines with water and pressure test.
13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below
calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached.
13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead &
tail, TOC brought to stage tool.
Estimated 1st Stage Total Cement Volume:
395 sx
395 sx
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Cement Slurry Design (1st Stage Cement Job):
13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue
with the cement job.
13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of
mud pits, spotting water across the HEC stage cementer.
x Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
13.10 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very
accurate using 0.0625 bps (5” liners) for the Quattro pump output. To operate the stage tool
hydraulically, the plug must be bumped.
13.11 Displacement calculation:
5,658’ x .0758 bpf = 423.8 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
Mixed
Water 13.92 gal/sk 4.98 gal/sk
[(5778-120)-2500]* 0.0758 + (2500 * .0732) = 422.3 bbls
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13.16 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher pressure
may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns
to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation
for the 2nd stage of the cement job.
13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker
bypass line to the cuttings tank. Have black water available and vac trucks ready to assist.
Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact
with the cement.
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Second Stage Surface Cement Job:
13.18 Prepare for the 2
nd stage as necessary. Circulate until first stage reaches sufficient compressive
strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre-job safety
meeting.
x Past wells have seen pressure increase while circulating through stage tool after reduced
rate
13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing
head.
13.20 Fill surface lines with water and pressure test.
13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.22 Mix and pump cmt per below recipe for the 2
nd stage.
13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail).
Job will consist of lead & tail, TOC brought to surface. However cement will continue to be
pumped until clean spacer is observed at surface.
Estimated 2nd Stage Total Cement Volume:
Cement Slurry Design (2nd stage cement job):
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
439 sx
267 sx
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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 .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 nathan.sperry@hilcorp.com and
joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the
AOGCC.
.0732 183
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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.
24 hour notice to AOGCC to witness.
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15.0 Drill 8-1/2” Hole Section
15.1 MU 8-1/2” Cleanout BHA (Milltooth Bit & 1.22° PDM)
15.2 TIH 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 FIT.
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 DS50 & NC50.
x Run a ported float in the production hole section.
Schrader Bluff Bit Jetting Recommendation
Formation Jetting TFA
NB 6 x 14 0.902
OA 6 x 13 0.778
OB 6 x 13 0.778
FIT and casing test digital data to AOGCC.
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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
Minimum EMW needed for Schrader NB interval is 7.0 ppg. DLB
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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 Surveys can be taken more frequently if deemed necessary.
x Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible and avoid stopping with the
BHA across the sand for any extended period of time.
x Use ADR to stay in section. Reservoir plan is to stay in NB 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 NB Concretions: 4-6% Historically
x MPD will be utilized to monitor pressure build up on connections.
x 8-1/2” Lateral A/C:
x S-20 has a separation factor of 0.446. S-20 is an active Schrader O-Sands injector
that will be gyro’d. S-45 will be nudged around to ensure a SF>1.
x S-24/PB1/PB2 is a long term shut-in Schrader producer with a separation factor of
0.631. There is no HSE risk associated with a collision. The only risk is damage to
the bit.
x S-28/PB1/PB2 has a separation factor of 0.062. S-28 will be P&A’d prior to drilling
S-45. The only risk is damage to the bit.
x S-56PB1 has a separation factor of 0.033. This was a Schrader Bluff NE well drilled
in 2020 by Innovation. The lateral was abandoned with cement after a liner running
failure. The only risk is damage to the bit.
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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.
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.
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15.19 BROOH with the drilling assembly to the 9-5/8” casing shoe
x Circulate at full drill rate (less if losses are seen, 350 GPM minimum).
x Rotate at maximum RPM that can be sustained.
x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as
dictated by hole conditions
x If backreaming operations are commenced, continue backreaming to the shoe
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 the well is breathing, treat all flow as an influx until proven otherwise.
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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16.0 Run 4-1/2” Screened Liner
16.1 Well control preparedness: In the event of an influx of formation fluids while running the 4-
1/2” screened liner, the following well control response procedure will be followed:
x P/U & M/U the 5” safety joint (with 4-1/2” crossover installed on bottom, TIW valve in open
position on top, 4-1/2” handling joint above TIW). This joint shall be fully M/U and
available prior to running the first joint of 4-1/2” Predrilled liner.
x Slack off and with 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW.
x Proceed with well kill operations.
16.2 R/U 4-1/2” liner running equipment.
x Ensure 4-1/2” 13.5# Hydril 625 x DS-50 crossover is on rig floor and M/U to FOSV.
x Ensure all casing has been drifted on the deck prior to running.
x Be sure to count the total # of joints on the deck before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
16.3 Run 4-1/2” screened 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 round nose float shoe on bottom.
x 4-1/2” screened liner will auto –fill
x 4-1/2” Liner will be centralized with 1/joint free floating
x If needed, install swell packers as per the lower completion tally.
x Remove protective packaging on swell packers just prior to picking up
x Do not place tongs or slips on the packer element
4-1/2” 13.5# L-80 Hydril 625 Torque
OD Minimum Optimum Maximum
4-1/2 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs
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16.6. Ensure to run enough liner to provide for approx 150’ overlap inside 9-5/8” casing. Ensure
hanger/pkr will not be set in a 9-5/8” connection.
x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as
per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8” connection.
16.7. Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck
to make sure it coincides with the pipe tally.
16.8. M/U Baker SLZXP liner top packer to 4-1/2” liner.
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” HWDP has been drifted
x There is no inner string planned to be run, as opposed to previous wells. The DP should auto
fill. Monitor FL and if filling is required due to losses/surging.
16.11. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe
depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to
bottom.
16.12. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
& 20 RPM.
16.13. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
16.14. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
16.15. Rig up to pump down the work string with the rig pumps.
16.16. Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed
1,600 psi while circulating.Pusher tool is set at 2,100 psi with 5% shear screws but it should be
discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker
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.
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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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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 TXP tieback to position seal assembly two joints above tieback sleeve.
Record PU and SO weights.
7”, 26#, L-80, TXP
=Casing OD Torque (Min) Torque (Opt)Torque (Max)Torque (Operating)
7”13,280 ft-lbs 14,750 ft-lbs 16,230 ft-lbs 20,000 ft-lbs
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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.
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18.0 Run Upper Completion – Jet Pump
18.1 RU to run 4-1/2”, 12.6#, L-80 Hydril 521 tubing.
x Ensure wear bushing is pulled.
x Ensure 4-1/2”, L-80, 13.5#, Hydril 521 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” JP completion (confirm tally with Operations
Engineer):
x WLEG/Mule shoe
x XX joints, 4-1/2”, 12.6#, L-80, H521
x Crossover Pup, 4-1/2” TXPM Box x 4-1/2” H521 Pin
x Nipple, 3.813” XN profile (3.750” no-go), 4-1/2”, TXPM (RHC plug body installed)
x Crossover Pup, 4-1/2”, H521 Box x 4-1/2”, TXP Pin
x 1 joint, 4-1/2”, 12.6#, L-80, H521
x Crossover Pup, 4-1/2” TC-II Box x 4-1/2” H521 Pin
x Retrievable Packer, Baker, 4-1/2”, 12.6#, L-80, TC-II
x Crossover Pup, 4-1/2”, H521 Box x 4-1/2”, TC-II Pin
x 1 joint, 4-1/2”, 12.6#, L-80, H521
x Pup joint, 4-1/2”, 12.6#, L-80, H521
x Crossover, 4-1/2”, EUE 8rd Box x 4-1/2”, H521 Pin
x Ported Pressure Sub, 4-1/2”, 12.6#, L-80, EUE 8rd
x Crossover, 4-1/2”, H521 Box x 4-1/2”, EUE 8rd Pin
x Sliding Sleeve, 4-1/2”, 12.6#, L-80 Hydril 521
x Crossover, 4-1/2”, EUE 8rd Box x 4-1/2”, H521 Pin
x Gauge Carrier, 4-1/2”, 12.6#, L-80, EUE 8rd
x Crossover, 4-1/2”, H521 Box x 4-1/2”, EUE 8rd Pin
x Pup joint, 4-1/2”, 12.6#, L-80, H521
x XXX joints, 4-1/2”, 12.6#, L-80, H521
18.3 PU and MU the 4-1/2” tubing hanger. Make final splice of the TEC wire and ensure any unsued
control line ports are dummied off.
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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.
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
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19.0 Innovation Rig Diverter Schematic
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20.0 Innovation Rig BOP Schematic
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21.0 Wellhead Schematic
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22.0 Days Vs Depth
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23.0 Formation Tops & Information
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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
Gas hydrates are generally not seen on S-pad. They were reported between 1000’ and 2000’ MD on S-
15 (2002). 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.
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H2S:
Treat every hole section as though it has the potential for H2S. MPU S-pad is not known for H2S.
Three samples containing H2S have been captured. S-08 had 50 ppm measured in 2012. S-12 had 28.9
ppm measured in 2012. S-39 had 2 ppm measured in 2014.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
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8-1/2” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor
ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe
moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation
after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300
gpm
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
There are no planned fault crossings for S-45.
H2S:
Treat every hole section as though it has the potential for H2S. MPU S-pad is not known for H2S.
Three samples containing H2S have been captured. S-08 had 50 ppm measured in 2012. S-12 had 28.9
ppm measured in 2012. S-39 had 2 ppm measured in 2014.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Abnormal Pressures and Temperatures:
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:
8-1/2” Lateral A/C:
x S-20 has a separation factor of 0.446. S-20 is an active Schrader O-Sands injector
that will be gyro’d. S-45 will be nudged around to ensure a SF>1.
x S-24/PB1/PB2 is a long term shut-in Schrader producer with a separation factor of
0.631. There is no HSE risk associated with a collision. The only risk is damage to
the bit.
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x S-28/PB1/PB2 has a separation factor of 0.062. S-28 will be P&A’d prior to drilling
S-45. The only risk is damage to the bit.
x S-56PB1 has a separation factor of 0.033. This was a Schrader Bluff NE well drilled
in 2020 by Innovation. The lateral was abandoned with cement after a liner running
failure. The only risk is damage to the bit.
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25.0 Innovation Rig Layout
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26.0 FIT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5.On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6.Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7.Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental
volume pumped and returned during test.
Page 54
Milne Point Unit
S-45 SB Producer
Drilling Procedure
27.0 Innovation Rig Choke Manifold Schematic
Page 55
Milne Point Unit
S-45 SB Producer
Drilling Procedure
28.0 Casing Design
Page 56
Milne Point Unit
S-45 SB Producer
Drilling Procedure
29.0 8-1/2” Hole Section MASP
Page 57
Milne Point Unit
S-45 SB Producer
Drilling Procedure
30.0 Spider Plot (NAD 27) (Governmental Sections)
Page 58
Milne Point Unit
S-45 SB Producer
Drilling Procedure
31.0 Surface Plat (As Built) (NAD 27)
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06001200180024003000360042004800True Vertical Depth (1200 usft/in)-2400 -1800 -1200 -600 0 600 1200 1800 2400 3000 3600 4200 4800 5400 6000 6600 7200 7800 8400 9000Vertical Section at 331.94° (1200 usft/in)MPU S-Edmontonia wp03 mid2MPU S-Edmontonia wp04 heel9 5/8" x 12 1/4"4 1/2" x 8 1/2"500100015002 0 0 0
25003000350040004500500055006000
6500
7000
7500
8000
8500
9000
9500
10000
10500
11000
11500
12000
1250013000135001400014142MPU S-45 wp07Start Dir 3º/100' : 250' MD, 250'TVDStart Dir 4º/100' : 550' MD, 548.77'TVDEnd Dir : 1815.64' MD, 1560.47' TVDStart Dir 4.25º/100' : 2209.16' MD, 1759.46'TVDEnd Dir : 5527.67' MD, 4018.61' TVDStart Dir 4º/100' : 5777.67' MD, 4040.4'TVDEnd Dir : 5972.67' MD, 4044.14' TVDStart Dir 2º/100' : 6872.67' MD, 4000.18'TVDEnd Dir : 7273.88' MD, 3994.94' TVDStart Dir 2º/100' : 8907.43' MD, 4032.19'TVDEnd Dir : 9373.83' MD, 4036.4' TVDStart Dir 3º/100' : 13730' MD, 4015.63'TVDTotal Depth : 14142.06' MD, 3969.4' TVDLA3LA1UG MAUG MBUG MCUG MDUG MESB NASB_NBHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: MPU S-4536.90+N/-S +E/-WNorthingEastingLatittudeLongitude0.000.005999857.560565377.590 70° 24' 36.228 N 149° 28' 3.559 WSURVEY PROGRAMDate: 2021-02-04T00:00:00 Validated: Yes Version: Depth From Depth To Tool26.50 500.00 3_Gyro-GC_Csg500.00 5777.67 3_MWD+IFR2+MS+Sag5777.67 14142.06Survey/PlanMPU S-45 wp07 (MPU S-45)MPU S-45 wp07 (MPU S-45)MPU S-45 wp07 (MPU S-45)3_MWD+IFR2+MS+SagFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation3568.40 3505.00 4458.89 LA33630.40 3567.00 4548.62 LA13801.40 3738.00 4833.61 UG MA3826.40 3763.00 4882.52 UG MB3850.40 3787.00 4932.21 UG MC3884.40 3821.00 5008.42 UG MD3993.40 3930.00 5354.34 UG ME4028.40 3965.00 5639.99 SB NA4044.40 3981.00 5838.20 SB_NBREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU S-45, True NorthVertical (TVD) Reference:MPU S-45 As-built RKB @ 63.40usftMeasured Depth Reference:MPU S-45 As-built RKB @ 63.40usftCalculation Method:Minimum CurvatureProject:Milne PointSite:M Pt S PadWell:Plan: MPU S-45Wellbore:MPU S-45 Design:MPU S-45 wp07CASING DETAILSTVD TVDSS MD SizeName4040.40 3977.00 5777.67 9-5/8 9 5/8" x 12 1/4"3969.40 3906.00 14142.06 4-1/2 4 1/2" x 8 1/2"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 26.50 0.00 0.00 26.50 0.00 0.00 0.00 0.00 0.002 250.00 0.00 0.00 250.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 250' MD, 250'TVD3 550.00 9.00 167.00 548.77 -22.91 5.29 3.00 167.00 -22.71 Start Dir 4º/100' : 550' MD, 548.77'TVD4 1700.00 55.00 167.00 1498.04 -600.88 138.72 4.00 0.00 -595.505 1815.64 59.63 167.06 1560.47 -695.69 160.56 4.00 0.68 -689.44 End Dir : 1815.64' MD, 1560.47' TVD6 2209.16 59.63 167.06 1759.46 -1026.58 236.56 0.00 0.00 -1017.19 Start Dir 4.25º/100' : 2209.16' MD, 1759.46'TVD7 5527.67 85.00 330.00 4018.61 -943.15 -925.57 4.25 152.30 -396.90 End Dir : 5527.67' MD, 4018.61' TVD8 5777.67 85.00 330.00 4040.40 -727.47 -1050.10 0.00 0.00 -147.99 MPU S-Edmontonia wp04 heel Start Dir 4º/100' : 5777.67' MD, 4040.4'TVD9 5972.67 92.80 330.00 4044.14 -558.75 -1147.50 4.00 0.00 46.71 End Dir : 5972.67' MD, 4044.14' TVD10 6872.67 92.80 330.00 4000.18 219.74 -1596.97 0.00 0.00 945.12 Start Dir 2º/100' : 6872.67' MD, 4000.18'TVD11 7273.88 88.69 336.90 3994.94 578.31 -1776.14 2.00 120.69 1345.83 End Dir : 7273.88' MD, 3994.94' TVD12 8907.43 88.69 336.90 4032.19 2080.45 -2416.98 0.00 0.00 2972.85 Start Dir 2º/100' : 8907.43' MD, 4032.19'TVD13 9373.83 90.27 346.09 4036.40 2522.23 -2564.86 2.00 80.31 3432.25 MPU S-Edmontonia wp03 mid2 End Dir : 9373.83' MD, 4036.4' TVD14 13730.00 90.27 346.09 4015.63 6750.60 -3612.07 0.00 0.00 7656.21 Start Dir 3º/100' : 13730' MD, 4015.63'TVD15 14142.06 102.63 346.09 3969.40 7147.27 -3710.31 3.00 0.00 8052.46 Total Depth : 14142.06' MD, 3969.4' TVD
-2000
-1500
-1000
-500
0
500
1000
1500
2000
2500
3000
3500
4000
4500
5000
5500
6000
6500
7000
7500
South(-)/North(+) (1000 usft/in)-4500 -4000 -3500 -3000 -2500 -2000 -1500 -1000 -500 0 500 1000 1500 2000 2500
West(-)/East(+) (1000 usft/in)
MPU S-Edmontonia wp04 heel
MPU S-Edmontonia wp03 mid2
9 5/8" x 12 1/4"
4 1/2" x 8 1/2"
7 5 0
1 2 5 0
1 5 0 0
1 7 5 0
200 0
2250
2500
3000350037504 0 0 0
3 9 6 9
MPU S-45 wp07
Start Dir 3º/100' : 250' MD, 250'TVD
Start Dir 4º/100' : 550' MD, 548.77'TVD
End Dir : 1815.64' MD, 1560.47' TVD
Start Dir 4.25º/100' : 2209.16' MD, 1759.46'TVD
End Dir : 5527.67' MD, 4018.61' TVD
Start Dir 4º/100' : 5777.67' MD, 4040.4'TVD
End Dir : 5972.67' MD, 4044.14' TVD
Start Dir 2º/100' : 6872.67' MD, 4000.18'TVD
End Dir : 7273.88' MD, 3994.94' TVD
Start Dir 2º/100' : 8907.43' MD, 4032.19'TVD
End Dir : 9373.83' MD, 4036.4' TVD
Start Dir 3º/100' : 13730' MD, 4015.63'TVD
Total Depth : 14142.06' MD, 3969.4' TVD
CASING DETAILS
TVD TVDSS MD Size Name
4040.40 3977.00 5777.67 9-5/8 9 5/8" x 12 1/4"
3969.40 3906.00 14142.06 4-1/2 4 1/2" x 8 1/2"
Project: Milne Point
Site:M Pt S Pad
Well:Plan: MPU S-45
Wellbore:MPU S-45
Plan: MPU S-45 wp07
WELL DETAILS: Plan: MPU S-45
36.90
+N/-S +E/-W Northing Easting Latittude Longitude
0.00 0.00 5999857.560 565377.590 70° 24' 36.228 N 149° 28' 3.559 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: MPU S-45, True North
Vertical (TVD) Reference:MPU S-45 As-built RKB @ 63.40usft
Measured Depth Reference:MPU S-45 As-built RKB @ 63.40usft
Calculation Method:Minimum Curvature
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0.001.002.003.004.00Separation Factor0 300 600 900 1200 1500 1800 2100 2400 2700 3000 3300 3600 3900 4200 4500 4800 5100 5400 5700Measured Depth (600 usft/in)No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: MPU S-45 NAD 1927 (NADCON CONUS)Alaska Zone 0436.90+N/-S +E/-W Northing Easting Latittude Longitude0.000.005999857.560565377.59070° 24' 36.228 N149° 28' 3.559 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU S-45, True NorthVertical (TVD) Reference: MPU S-45 As-built RKB @ 63.40usftMeasured Depth Reference:MPU S-45 As-built RKB @ 63.40usftCalculation Method: Minimum CurvatureSURVEY PROGRAMDate: 2021-02-04T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool3_Gyro-GC_Csg3_MWD+IFR2+MS+Sag26.50500.00MPU S-45 wp07 (MPU S-45)500.005777.67MPU S-45 wp07 (MPU S-45 5777.6714142.06MPU S-45 wp07 (MPU S-45 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 300 600 900 1200 1500 1800 2100 2400 2700 3000 3300 3600 3900 4200 4500 4800 5100 5400 5700Measured Depth (600 usft/in)MPU S-44 wp05MPU S-202 wp10MPS-41MPS-39MPU S-201 wp07MPU S-48 wp03MPU S-56PB1MPU S-46 wp03MPU S-203PB2MPU S-203PB1MPU S-203MPU S-203MPU S-47 wp03MPS-43NO GLOBAL FILTER: Using user defined selection & filtering criteria26.50 To 14142.06Project: Milne PointSite:M Pt S PadWell:Plan: MPU S-45Wellbore:MPU S-45 Plan: MPU S-45 wp07Ladder / S.F. Plots1 of 2CASING DETAILSTVD TVDSS MD Size Name4040.40 3977.00 5777.67 9-5/8 9 5/8" x 12 1/4"3969.40 3906.00 14142.06 4-1/2 4 1/2" x 8 1/2"
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0.001.002.003.004.00Separation Factor5700 6175 6650 7125 7600 8075 8550 9025 9500 9975 10450 10925 11400 11875 12350 12825 13300 13775 14250Measured Depth (950 usft/in)No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: MPU S-45 NAD 1927 (NADCON CONUS)Alaska Zone 0436.90+N/-S +E/-W Northing Easting Latittude Longitude0.000.005999857.560565377.59070° 24' 36.228 N149° 28' 3.559 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU S-45, True NorthVertical (TVD) Reference: MPU S-45 As-built RKB @ 63.40usftMeasured Depth Reference:MPU S-45 As-built RKB @ 63.40usftCalculation Method: Minimum CurvatureSURVEY PROGRAMDate: 2021-02-04T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool3_Gyro-GC_Csg3_MWD+IFR2+MS+Sag26.50500.00MPU S-45 wp07 (MPU S-45)500.005777.67MPU S-45 wp07 (MPU S-45)5777.6714142.06MPU S-45 wp07 (MPU S-45)3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)5700 6175 6650 7125 7600 8075 8550 9025 9500 9975 10450 10925 11400 11875 12350 12825 13300 13775 14250Measured Depth (950 usft/in)MPS-28PB2MPS-28MPS-17L1MPS-17MPU S-56PB1MPS-23L1NO GLOBAL FILTER: Using user defined selection & filtering criteria26.50 To 14142.06Project: Milne PointSite:M Pt S PadWell:Plan: MPU S-45Wellbore:MPU S-45 Plan: MPU S-45 wp07CASING DETAILSTVD TVDSS MD Size Name4040.40 3977.00 5777.67 9-5/8 9 5/8" x 12 1/4"3969.40 3906.00 14142.06 4-1/2 4 1/2" x 8 1/2"Ladder / S.F. Plots2 of 2
Revised 2/2015
TRANSMITTAL LETTER CHECKLIST
WELL NAME: ______________________________________
PTD: _____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD: ____________________________ POOL: ______________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
No. _____________, API No. 50-_______________________.
Production should continue to be reported as a function of the original
API number stated above.
Pilot Hole
In accordance with 20 AAC 25.005(f), all records, data and logs
acquired for the pilot hole must be clearly differentiated in both
well name (_______________________PH) and API number
(50-_____________________) from records, data and logs acquired for
well (name on permit).
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce/inject is contingent upon issuance of
a conservation order approving a spacing exception.
(_____________________________) as Operator assumes the liability
of any protest to the spacing exception that may occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in no greater
than 30' sample intervals from below the permafrost or from where
samples are first caught and 10' sample intervals through target zones.
Non-
Conventional
Well
Please note the following special condition of this permit:
Production or production testing of coal bed methane is not allowed for
well ( ) until after ( )
has designed and implemented a water well testing program to provide
baseline data on water quality and quantity.
(________________________) must contact the AOGCC to obtain
advance approval of such water well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by (_______________________________) in the attached application,
the following well logs are also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for well logs run must be submitted to the AOGCC
within 90 days after completion, suspension or abandonment of this
well.
Schrader Bluff Oil
Milne Point Unit
X
X
221-042
X
MPU S-45
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