Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAbout225-039Alaska 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
Sean McLaughlin
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK, 99503
Re: Granite Point Field, Undefined Gas Pool, Granite Pt St 17586 010,
Hilcorp Alaska, LLC
Permit to Drill Number: 225-039
Surface Location: 1981' FSL, 2056' FWL, Sec 31, T11N, R11W, SM, AK
Bottomhole Location: 181' FSL, 1951' FEL, Sec 36, T11N, R12W, SM, AK
Dear Mr. McLaughlin:
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 all well
logs run must be submitted to the AOGCC within 90 days after completion, suspension, or
abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first.
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 AOGCCreserves
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 AOGCCspecifically 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 AOGCCorder, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Jessie L. Chmielowski
Commissioner
DATED this 2th day of June 2025.
Jessie L.
Chmielowski
Digitally signed by
Jessie L. Chmielowski
Date: 2025.06.25
12:04:38 -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: 7,055' TVD: 4,783'
4a. Location of Well (Governmental Section):7. Property Designation:
Surface:
Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date:
Total Depth: 9. Acres in Property: 14. Distance to Nearest Property:
4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 115' 15. Distance to Nearest Well Open
Surface: x-269666 y-2559347 Zone-4 N/A to Same Pool:3893' GP St 17586 09
16. Deviated wells:Kickoff depth: 600 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 64 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
17-1/2" 13-3/8" 68# L-80 BTC 600' Surface Surface 600' 600'
12-1/4" 9-5/8" 47# L-80 DWC/C 5,000' Surface Surface 5,000' 3,215'
8-1/2" 4-1/2" 12.6# L-80 GBCD 2,255' 4,800' 3,128' 7,055' 4,783'
Tieback 4-1/2" 12.6# L-80 IBT 4,800' Surface Surface 4,800' 3,128'
19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations)
Junk (measured):
TVD
228'
Hydraulic Fracture planned?Yes No
20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis
Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements
Contact Name:
Contact Email:
Contact Phone:
Date:
Permit to Drill API Number: Permit Approval
Number: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
022224484
Specifications
2296
L - 1151 ft3
L - 1911 ft3 / T - 251 ft3
GL / BF Elevation above MSL (ft):
Tieback Assy.
7/1/2025
3328' to nearest unit boundary
Granite Pt St 17586 010
Granite Point Field
Undefined Gas Pool
Cement Quantity, c.f. or sacks
Commission Use Only
See cover letter for other
requirements.
Plugs (measured):
(including stage data)
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
L - 675 ft3 / T - 206 ft3
1818
983' FSL, 31' FWL, Sec 31, T11N, R11W, SM, AK
181' FSL, 1951' FEL, Sec 36, T11N, R12W, SM, AK
N/A
3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503
Hilcorp Alaska, LLC
1981' FSL, 2056' FWL, Sec 31, T11N, R11W, SM, AK ADL 18742 / ADL 17586
8130
18. Casing Program:Top - Setting Depth - Bottom
Effect. Depth MD (ft):Effect. Depth TVD (ft):
Casing Cement VolumeSizeLength
Total Depth MD (ft):Total Depth TVD (ft):
MD
Conductor/Structural 30"228'
Authorized Title:
Authorized Signature:
Authorized Name:
Perforation Depth MD (ft):
Production
Liner
Intermediate
N/A 228'
Drilling Manager
Sean Mclaughlin
21. I hereby certify that the foregoing is true and the procedure approved herein will not be
Surface
Perforation Depth TVD (ft):
Sean Mclaughlin
sean.mclaughlin@hilcorp.com
907-223-6784
No
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Class:
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Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
By Grace Christianson at 8:22 am, Apr 22, 2025
Digitally signed by Sean
McLaughlin (4311)
DN: cn=Sean McLaughlin (4311)
Date: 2025.04.21 09:40:16 -
08'00'
Sean
McLaughlin
(4311)
225-039
DSR-4/24/25
50-733-20736-00-00
SFD 6/23/2025
* BOPE test to 3000 psi. Annular to 2500 psi.
* Email casing test and FIT digital data to AOGCC immediately upon
completion of FIT.
269 - mgr
MGR05MAY2025*&:
Jessie L. Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2025.06.25 12:04:51 -08'00'
06/25/25
06/25/25
RBDMS JSB 062725
86-10 Drilling Program
Bruce Platform
Sean McLaughlin
PTD
April, 11 2025
BR 86-10
PTD
APD xxxxxxx
Contents
1. Well Summary.....................................................................................................................................2
2. Management of Change Information................................................................................................3
3. Tubular Program................................................................................................................................4
4. Drill Pipe Information........................................................................................................................4
5. Internal Reporting Requirements.....................................................................................................5
6. Planned Wellbore Schematic.............................................................................................................6
7. Drilling Summary...............................................................................................................................7
8. Mandatory Regulatory Compliance / Notifications.........................................................................8
9. R/U and Preparatory Work.............................................................................................................10
10. Drill 17-1/2” hole, Run 13-3/8” conductor, Cement to surface.....................................................10
11. N/U 21-1/4” 2M Diverter..................................................................................................................12
12. Drill 12-1/4” Surface Hole Section...................................................................................................13
13. Run 9-5/8” Surface Casing...............................................................................................................14
14. Cement 9-5/8” Surface Casing.........................................................................................................17
15. 8-1/2” Production hole Preparatory Work.....................................................................................20
16. Drill 8-1/2” Production Hole Section...............................................................................................21
17. Run 4-1/2” Production Liner...........................................................................................................22
18. Cement 4-1/2” Production Liner.....................................................................................................24
19. Wellbore Clean Up & Displacement...............................................................................................27
20. Run Completion Assembly...............................................................................................................28
21. BOP Schematic..................................................................................................................................29
22. Wellhead Schematic..........................................................................................................................30
23. Anticipated Drilling Hazards...........................................................................................................31
24. FIT Procedure...................................................................................................................................32
25. Choke Manifold Schematic..............................................................................................................33
26. Casing Design Information ..............................................................................................................35
27. 8-1/2” Hole Section MASP...............................................................................................................36
28. Plot (NAD 27) (Governmental Sections).........................................................................................37
29. Slot Diagram......................................................................................................................................38
30. Directional Program (wp05) - Attached separately......................................................................39
Page 2 April 11, 2025
BR 86-10
PTD
APD xxxxxxxx
1. Well Summary
Well BR 86-10
Drilling Rig Rig 151
Leg & Slot Leg 2 / Slot 5
Directional plan wp05
Pad & Old Well Designation Bruce Platform
Planned Completion Type 4-1/2” 12.6# Liner, 4-1/2” Tubing GL Comp
Target Reservoir(s)TM 0-15
Kick off point NA
Planned Well TD, MD / TVD 7055’ MD / 4783’ TVD
PBTD, MD 6955’
AFE Number
AFE Days
AFE Drilling Amount
Work String 5” DP NC-50
RKB – AMSL 115’
MSL to ML 75’
Page 3 April 11, 2025
BR 86-10
PTD
APD xxxxxxxx
2. Management of Change Information
Date: August 13, 2024
Subject: Changes to Approved Permit to Drill
File #: BR 86-10 Drilling Program
Significant modifications to Drilling Program for PTD will be documented and approved below. Changes to an
approved PTD will be communicated and approved by the AOGCC prior to continuing forward with work.
Sec Page Date Procedure Change
Approval:
Drilling Manager Date
Prepared:
Engineer Date
Page 4 April 11, 2025
BR 86-10
PTD
APD xxxxxxxx
3. Tubular Program
Hole Section OD (in)ID (in)Drift
(in)
Conn
OD (in)
Wt
(#/ft)Grade Conn Burst
(psi)
Collap
se
(psi)
Tension
(k-lbs)
Structural(in place)30”28”Welded
17-1/2” Conductor 13.375 12.415 12.259 13.375 68 L-80 BTC 5020 2260 932
12-1/4” Surface 9.625”8.681”8.525”10.625”47/40 L-80 DWC/C 6870 4750 1086
8-1/2” Production 4-1/2”3.958”3.833”5.0”12.6#L-80 GBCD 8430 7500 288
** Minimum of 100’ overlap required between casing strings
4. Drill Pipe Information
Hole
Section
OD (in)ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
All 5”4.276 3.25 6.625 19.5 S-135 NC50 15,638 10,029 560k
Page 5 April 11, 2025
BR 86-10
PTD
APD xxxxxxxx
5. Internal Reporting Requirements
1. Fill out daily drilling report and cost report.
x Report covers operations from 6am to 6am
x Ensure time entry adds up to 24 hours total.
x Try to capture any out-of-scope work as NPT. This helps later when aggregating end of well
reports.
2. Afternoon Updates
x Submit a short operations update every day to kenaiciodrilling@hilcorp.com
3. EHS Incident Reporting
o Notify EHS field coordinator.
Garrett St. Clair: C: (907) 252-7780
o Spills:
Adrian Kersten: C: 907-564-4820
Sean Mclaughlin
o Report ALL spills to the water within 15 minutes.
o Submit Hilcorp Incident report to contacts above within 24 hrs
4. Casing Tally
x Send final “As-Run” Casing tally to sean.mclaughlin@hilcorp.com and cdinger@hilcorp.com
5. Casing and Cmt report
x Send casing and cement report for each string of casing to sean.mclaughlin@hilcorp.com and
cdinger@hilcorp.com
Page 6 April 11, 2025
BR 86-10
PTD
APD xxxxxxxx
6. Planned Wellbore Schematic
Page 7 April 11, 2025
BR 86-10
PTD
APD xxxxxxxx
7. Drilling Summary
BR 86-10 is a 7055’ MD / 4783’ TVD development gas well drilled from leg 2 slot #5 off the Bruce
platform. The base plan is an infill gas well to the Tyonek TM15.
The well will be completed with a 4-1/2” gas lift tie-back completion.
Drilling operations are expected to commence approximately July 2025.
General sequence of operations pertaining to this drilling operation:
Rig
1. Rig 151 will MIRU over leg 2, slot 5
2. Drill 17-1/2” Conductor hole to 600’
3. Run 13-3/8” conductor. Perform stab in surface to surface cement job
4. ND riser, Rig up 21-1/4” x 2M Diverter
5. Drill 12-1/4” Surface hole to 5000’ MD.
x GR/Res LWD for Surface hole
6. Run 9-5/8” casing to surface. Cement in single stage
7. ND Diverter, NU 13-5/8” BOPE. Test to 3500psi
8. Test casing to 3500 psi.
9. Mill shoe track with 20’ of new formation.
10. Perform FIT to 14.0 ppg EMW
11. Drill 8-1/2” production hole to 7055’ MD, performing short trips as needed
x Triple Combo LWD
x Open Hole eline logs as needed
12. RIH w/ 4-1/2” liner. Set liner and cement. Circ wellbore clean.
13. Perform Clean out run to polish bore
14. Perform liner lap test to 2000 psi.
15. Run 4-1/2” gas lift completion.
16. Land hanger and test.MIT-T to 2000 psi, MIT-IA to 2000 psi
17. ND BOPE, NU tree and test void
Page 8 April 11, 2025
BR 86-10
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APD xxxxxxxx
8. Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that our drilling and completion operations comply with the below AOGCC regulations. If
additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to
contact the Anchorage Drilling Team.
x BOPs shall be tested at (2) week intervals during the drilling. Ensure to provide AOGCC 48 hrs
notice prior to testing BOPs.
x The test of BOP equipment will be to 250/3500 psi for 5/5 min (annular to 2500).Confirm that
these test pressures match those specified on the APD.
o The upper casing flange is rated to 5000 psi.
o The highest reservoir pressure expected is 2296 psi in the TM11 (4783' TVD). MASP is 1818 psi
with 0.1psi/ft gas in the wellbore.
x If the BOP is used to shut in on the well in a well control situation,ALL BOP components utilized
for well control must be tested prior to the next trip into the wellbore. This pressure test will be
charted same as the 14 day BOP test.
x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid
program and drilling fluid system”
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”
x Review all conditions of approval of the PTD on the 10-401 form. Ensure that the conditions of
approval are captured in shift handover notes until they are executed and complied with.
x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
Page 9 April 11, 2025
BR 86-10
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Summary of BOP Equipment and Test Requirements
Hole Section Equipment Test Pressure (psi)
8.5”
x 13-5/8” Shaffer 5M annular
x 13-5/8” 5M Shaffer SL Double gate
x Blind ram in bottom cavity
x Mud cross
x 13-5/8” 5M Shaffer SL single gate
x 3-1/16” 5M Choke Manifold
x Standpipe, floor valves, etc
Initial Test: 250/3000
(Annular 2500 psi)
Subsequent Tests:
250/3000
(Annular 2500 psi)
x Primary closing unit: Masco 7 station, 15 bottle, 3000 psi closing unit with two air pumps, a triplex
electric driven pump
Required AOGCC Notifications:
x Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
x 48 hours notice prior to full BOPE test.
x Any other notifications required in APD conditions of approval.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov
Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / (C): 907-250-9193 / Email:bryan.mclellan@alaska.gov
Melvin Rixse / Petroleum Engineer / (O): 907-793-1231 / Email:melvin.rixse@alaska.gov
Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov
Test/Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
Page 10 April 11, 2025
BR 86-10
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9. R/U and Preparatory Work
1. N/U 24” riser assembly to 30” landing ring
2. Mix Spud mud for 17-1/2” hole section.
3. Install 7” liners in mud pumps. Plan to pump at 1000 gpm to clean the 30” conductor. 7” liners will
deliver 575 gpm @ 98% eff @ 3623 psi.
10. Drill 17-1/2” hole, Run 13-3/8” conductor, Cement to surface
1. P/U 17-1/2” drilling assy:
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U.
x Recommended BHA: 17-1/2” mill tooth bit with 9” directional motor, 8” UBHO sub, 5” DP
x Pump at 1000 gpm to clean the hole effectively.
2. 17-1/2” hole mud program summary:
x Weighting material to be used for the hole section will be barite. Additional barite 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.
x Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations
will be available at the driller’s console, Co Man office, and Toolpusher office.
System Type:8.8 – 9.6 ppg Pre-Hydrated Aquagel/freshwater spud mud
Page 11 April 11, 2025
BR 86-10
PTD
APD xxxxxxxx
Properties:
Depths Density Viscosity Plastic Viscosity Yield Point API FL pH
194-600 8.8 – 9.6 80-120 20 - 40 35 - 55 <10 8.5 – 9.5
System Formulation:Aquagel / FW spud mud
Product Concentration
Fresh Water
soda Ash
AQUAGEL
BARAZAN D+
PAC-L /DEXTRID LT
BARACARB 5/25/50
STEELSEAL 50/100/400
BAROFIBRE
BAROID 41
caustic soda
ALDACIDE G
0.905 bbl
0.5 ppb
15 - 25 ppb
as needed
if required for <10 API FL
5 ppb total
5 ppb total
4.0 ppb
as required for weight 8.8 – 9.2 ppg
0.1 ppb (8.5 –9.5pH)
0.1 ppb
AQUAGEL and BARAZAN D+ should be used to maintain rheology. Begin system with a 55 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. DEXTRID and/or PAC L should be used
for filtrate control. Background LCM (10 - 20 ppb total) BARACARBs/BAROFIBRE/STEELSEALs
should be used in the system while drilling the surface interval to prevent losses and strengthen the
wellbore. While drilling, monitor the torque and drag to determine if liquid lubricant is required. If so,
approval from town will be required prior to additions of lubricants. Additions of CON DET PRE-
MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when
penetrating high-clay content sections. Maintain the pH in the 8.5 – 9.5 range with caustic soda. Daily
additions of ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action.
Mix a ~50 bbl LCM pill prior to drilling out of the conductor, to be available for immediate use if losses
are seen drilling the Surface hole. The pill formulation will be the 50 ppb pill from the LCM tree. Mix
the recommended LCM material in thinned back base mud.
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).
Sweep Formulations: 20 barrels mud, add 1.0 ppb BARAZAN D.
Additions of CON DET PREMIX are recommended when penetrating high-clay content sections to
reduce the incidence of bit balling and shaker blinding.
At TD, a Walnut “flag” (20 bbl pill with 15 ppb of Wallnut M) could be pumped to gauge hole washout
- to help calculate the required cement volume. The cement will then be pumped and drilling mud will
be used to bump the plug. Pretreat this chase mud with 1 ppb Bicarb and 0.5 ppb citric acid.
Page 12 April 11, 2025
BR 86-10
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3. TIH in the 30” drive pipe. Records indicate the 30” drive pipe had 79’ of penetration. A magnet was
run in the 30’ and tagged at 194’ below the drill deck. Bottom of drivepipe is expected at 228’
4. Drill vertical hole to 600’.
x Close approach: 87-04 (Suspended with deep cement plug)
x Use eline gyro to verify directional control
5. Run 13-3/8” 68# L-80 BTC conductor.
x Include stab in double valve float shoe for inner string cement job (PESI)
6. Land mandrel hanger. After landing all fluid returns with be through two 4” outlets on the 30” casing.
7. Rig up false table and bowl.
8. Run 5” drill pipe with stab in stinger to the float equipment. (verify stinger tool joint connection)
9. Pump 15.3# cement until cement is observed at surface (monitor overboard line). Unstab from float
and lay in ~50’ of cement in the 13-3/8” conductor (~8bbls). Displace cement in drillpipe and
conductor to mud. Be prepared to overboard cement returns.
x Drive pipe (28”) x Conductor - 134 bbls (228’)
x OH x Conductor – 65 bbls (40% excess)
x Shoe Volume (40’) – 6 bbls
x Drill Pipe volume (560’) – 10 bbls
x Conductor cement volume required on location – 275 bbls
x Annular cement to surface is required.
11. N/U 21-1/4” 2M Diverter
1. N/D riser
2. N/U 21-1/4” Hydril MSP 2M diverter System.
x N/U 21-1/4” x 2 M riser on 28” landing ring.
x N/U 21-1/4” 2M diverter w/16” outlet.
x Knife gate, 16” diverter line.
x 75’ between ignition source and diverter outlet required.
Page 13 April 11, 2025
BR 86-10
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3. Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that
knife gate opens prior to annular closure.Annular element must close in less than 45 seconds.
4. Set wear bushing in wellhead.
5. Diverter Line Orientation:
12. Drill 12-1/4” Surface Hole Section
1. 12-1/4” hole mud program summary:
x Weighting material to be used for the hole section will be barite. Additional barite 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 9.0ppg.
x Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations
will be available at the driller’s console, Co Man office, and Toolpusher office.
System Type:9.0 – 9.6 ppg Pre-Hydrated Aquagel/freshwater spud mud
Properties:
Page 14 April 11, 2025
BR 86-10
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Depths Density Viscosity Plastic Viscosity Yield Point API FL pH
600 – 5000 9.0 – 9.6 80-120 20 - 40 35 - 55 <10 8.5 – 9.5
2. PU Drilling BHA
x 12-1/4” Kymera Bit
x 8” motor w/ 1.5 deg bend
x GR/Res
x UBHO for Gyro operations
3. TIH w/ 12-1/4” directional drilling assy drill 12-1/4” hole section .
x Eline gyro required until clean tool face and MWD surveys are obtained.
x Close approach:
o 87-04- Deep set cement plug, Suspended well
x Pump at 700 gpm. Short trips and sweep will be required. Ensure shaker screens are set up to
handle this flowrate.
x Circulate hole clean and pump sweep before dropping rate to prevent fall back and sticking.
Maximize drill string RPMs, Pump sweeps and 6rpm rheology (target 10) to ensure effective hole
cleaning.
x Keep swab and surge pressures low when tripping.
x Do not allow MW to drop below a 9.0 ppg.
x Pull wiper trips as often as necessary.
x Ensure shale shakers are functioning properly. Check for holes in screens on connections.
x Take MWD surveys every stand drilled.
x Rationale for casing shoe depth is to top set the reservoir (TM0). Planned shoe depth is 3215’ TVD
and the top of reservoir is expected at 3525’ TVD.
o BR 87-06 17-1/2” OH to 3471’ TVD on diverter
o BR 86-08 17-1/2” OH to 3468’ TVD on diverter
o BR 42-12 17-1/2” OH to 3108’ TVD on diverter
o BR 42-16 17-1/2” OH to 3030’ TVD on diverter
13. Run 9-5/8” Surface Casing
1. R/U and pull wear bushing.
2. R/U Parker (Volant) 9-5/8” casing running equipment
x Ensure 9-5/8” DWC/C x NC50 XO on rig floor and M/U to FOSV.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Plan to rig up Volant CRT if available
Page 15 April 11, 2025
BR 86-10
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APD xxxxxxxx
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 8-1/2” on the location prior to running.
x Note that 47# drift is 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.
3. P/U shoe joint, visually verify no debris inside joint.
4. Continue M/U & thread locking 120’ shoe track assembly consisting of:
9-5/8” Float Shoe
1 joint – 9-5/8” BTC, 1 Centralizer 10’ from bottom w/ stop ring
1 joint – 9-5/8” BTC, NO Centralizer
1 joint – 9-5/8” BTC, 1 Free floating centralizer
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.
5. Continue running 9-5/8” surface casing
x Fill casing while running using fill up line on rig floor.
x Centralization:
x 1 centralizer every joint to the conductor shoe
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
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.
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6. Continue running 9-5/8” surface casing
x Fill casing while running using the Volant tool.
x Centralization: No centralizers in the conductor.
7. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary.
8. Slow in and out of slips.
9. P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the
landing joint already M/U. Strap the landing joint while it is on the deck and mark the joint at (1) ft
intervals to use as a reference when landing the hanger.
10. Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed
out in the wellhead profile. Conventional circulation is not permissible once casing hanger is landed.
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11. P/U and R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume.
Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor losses
closely while circulating.
14. Cement 9-5/8” Surface Casing
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 Discuss how to handle cement returns at surface. Ensure overboard lines are in place and
observable.
x Decide which pumps will be utilized for displacement, and how fluid will be fed to
displacement pump.
x Ensure adequate amount of water for mix fluid is heated and available in the water tanks.
x Confirm 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.
2. Document efficiency of all possible displacement pumps prior to cement job.
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.
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.
5. Fill surface cement lines with water and pressure test.
6. Pump remaining 60 bbls 10.5 ppg tuned spacer.
7. Drop bottom plug– FOX rep to witness. Mix and pump cement per below calculations, confirm actual
cement volumes with cementer after TD is reached.
8. Cement volume based on annular volume + 40% open hole excess. Job will consist of lead & tail, TOC
brought to surface.
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Estimated Total Cement Volume:
Cement Slurry Design:
9. Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation
PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation, land hanger, and continue with
the cement job.
10. After pumping cement, drop top plug and displace cement with spud mud out of mud pits.
x Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, FOX Cementers during the entire job.
Lead Slurry Tail Slurry
Density 12.0 lb/gal 15.3 lb/gal
Yield 2.35 ft3/sk 1.16 ft3/sk
Mix Water 13.92 gal/sk 4.98 gal/sk
500' @ 40% excess
388.2 bbls - mgr
0.07320 bpf
47.8 bbls 15.8 ppg tail
Displacement = ( 5000' - 120' ) * ( (8.681 ^2) / 1029.4) = 357.3 bbls - Surface to float collar at 4880' MD
8.681" nominal ID for 47# 9.625"
8.78 bbls for 120' 47# shoe track
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11. Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the plug must be
bumped.
12. Lower string and land hanger in wellhead again. Cement returns will be out the 2 x 4” side outlets.
Ensure hose is in place to take returns and dump into the inlet over the side of the platform.
13. Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point
during the job.
14. If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by
no more than 1 shoe track volume, ±6 bbls before consulting with Drilling Engineer.
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.
16. Be prepared for cement returns to surface. Cement return to be taken overboard. Ensure to flush out
any rig components, hard lines and BOP stack that may have come in contact with the cement.
17. Close 4” valves on wellhead side outlet and monitor pressure build up.
18. R/D cement equipment. Flush out wellhead with FW.
19. Back out and L/D landing joint. Flush out wellhead with FW.
20. M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in
lock downs and inject plastic packing element.
21. Lay down landing joint and pack-off running tool.
Ensure to report the following on WellView:
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
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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 sean.mclaughlin@hilcorp.com and
cody.dinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC.
15. 8-1/2” Production hole Preparatory Work
1. N/D the Diverter
2. N/U 13-3/8” 5M multi-bowl wellhead assy. Install 9-5/8” packoff P-seals. Test to 3000 psi.
3. 6” liners to be installed in mud pump #1 and pump #2.
x Pump range for drilling will be ~420 gpm. This can be achieved with one or both pumps.
4. 8-1/2” Production hole mud program summary:
x Primary weighting material to be used for the hole section will be barite to minimize solids. Ensure
enough barite is on location to weight up the active system 1ppg above highest anticipated MW in
the event of a well control situation.
x Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations
will be available at the driller’s console, Co Man office, and Toolpusher office.
System Type:LNSD WBM
Properties:
MD Mud
Weight Viscosity Plastic
Viscosity Yield Point pH HPHT
5000- TD 9.2-10.0 40-53 6-15 13-24 8.5-9.5 11.0
System Formulation: 2% KCL/BDF-976/GEM GP
Product Concentration
Water
KCl
Caustic
BARAZAN D+
DEXTRID LT
PAC L
BDF-976
GEM GP
BARACARB 5/25/50
STEELSEAL 50/100/400
BAROFIBRE
BAROTROL PLUS
SOLTEX
BAROID 41
ALDACIDE-G
0.905 bbl
7 ppb
0.2 ppb (9 pH)
1.0 ppb (as required 18 YP)
1-2 ppb
1 ppb
4 ppb
1.0% by volume
5 ppb (1.7 ppb of each)
5 ppb (1.7 ppb of each)
1.7 ppb
4.0 ppb
2 – 4 ppb
as needed
0.1 ppb
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5. Program mud weights are generated by reviewing data from producing & shut in offset wells, estimated
BHP’s from formations capable of producing fluids or gas and formations which could require mud
weights for hole stabilization.
6. A guiding philosophy will be that it is less risky to weight up a lower weight mud than be overbalanced
and have the challenge to mitigate lost circulation while drilling ahead.
7. NU 13-5/8” BOPE as follows (top down):
x 13-5/8” x 5M Shaffer annular BOP.
x 13-5/8” 5M Shaffer SL Double ram. (2-7/8” X 5” VBR in top cavity, blind ram in btm cavity)
x 13-5/8” mud cross
x 13-5/8” 5M Shaffer SL single ram. (2-7/8” X 5” VBR)
x N/U pitcher nipple, install flowline.
x Install (2) manual valves on kill side of mud cross. Manual valve used as inside or “master
valve”.
x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual
valve.
8. Run BOPE test plug.
9. Test BOPE.
x Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min.
x Ensure to leave “A” section side outlet valves open during BOP testing so pressure does not build up
beneath the test plug. Confirm the correct valves are opened.
x Test VBRs on a 5” and 4-1/2” test joints (3000 psi)
x Test Annular on a 4-1/2” test joint (2500 psi)
x Ensure gas monitors are calibrated and tested in conjunction w/ BOPE.
10. Pull test plug, set wear bushing
16. Drill 8-1/2” Production Hole Section
1. Ensure BHA components have been inspected previously.
2. Drift and caliper all components before M/U. Visually verify no debris inside components that cannot
be drifted.
3. PU 6-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged
on AM report.
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x Triple Combo LWD tools required (DEN, POR, RES)
4. Ensure TF offset is measured accurately and entered correctly into the MWD software.
5. Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
6. Ensure to have enough 5” DP in derrick to drill the entire open hole section without having to pick up
pipe from the pipeshed.
7.R/U and test casing to 3500 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph.
8. Drill out shoe track and 20’ of new formation.
9. CBU and condition mud for FIT.
10. Conduct FIT to 14.0 ppg EMW. With 9.2 BHP and 9.6 ppg MW there will be unlimited KTV.
11. Drill 8-1/2” hole section to 7055’ MD / 4783’ TVD
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Pump at 400 - 500 gpm. Ensure shaker screens are set up to handle this flowrate.
x Keep swab and surge pressures low when tripping.
x Make wiper trips every 1000’ unless hole conditions dictate otherwise.
x Ensure shale shakers are functioning properly. Check for holes in screens on connections.
x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10.
x Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed
necessary.
12. At TD; pump sweeps, CBU, and pull a wiper trip back to the 9-5/8” shoe.
13. POOH LDDP and BHA
14. 2-7/8” x 5” VBRs previously installed in BOP stack and tested with 4-1/2” test joint.
17. Run 4-1/2” Production Liner
1. R/U Baker 4-1/2” liner running equipment.
x Ensure 5” NC50 crossover on rig floor and M/U to FOSV.
x R/U fill up line to fill liner while running.
x Ensure all liner has been drifted and tally verified prior to running.
x Be sure to count the total # of joints before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
* Casing test and FIT digital data to AOGCC immediately upon completion of FIT. - mgr
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2. P/U shoe joint, visually verify no debris inside joint.
3. Continue M/U & thread locking shoe track assy consisting of:
x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). Centralizer
10’ from the bottom with stop ring
x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked).
x Landing collar pup bucked up. No centralizer
x Centralizers will be run on 4-1/2” liner every joint to 5000’.
4. Continue running 4-1/2” production liner to TD
x Short joint run every 1000’, RA Tag 1000’ from bottom.
x Fill liner while running using fill up line on rig floor.
x Use “API Modified” thread compound. Dope pin end only w/ paint brush.
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
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5.Ensure to run enough liner to provide at least 100’ overlap inside casing. Ensure setting sleeve will
not be set in a connection.
6. Before picking up Baker ZXP liner hanger / packer assy, count the # of joints on the pipe deck to make
sure it coincides with the pipe tally.
7. M/U Baker ZXP liner top packer. Fill liner tieback sleeve with “XANPLEX”, ensure mixture is thin
enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up.
8. RIH one stand and circulate a minimum of one liner volume. Note weight of liner.
9. RIH w/ liner on DP no faster than 1 min / stand. Watch displacement carefully and avoid surging the
hole. Slow down running speed if necessary.
10. M/U top drive and fill pipe while lowering string every 10 stands.
11. Set slowly in and pull slowly out of slips.
12. Circulate 1-1/2 drill pipe and liner volume at 9-5/8” shoe prior to going into open hole. Stage pumps up
slowly and monitor for losses. Do not exceed 60% of the nominal liner hanger setting pressure.
13. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, &
30 rpm.
14. Continue to fill the string every 10 joints while running liner in open hole. Do not stop to fill casing.
15. P/U the cmt stand and tag bottom with the liner shoe. P/U 2’ off bottom. Note slack-off and pick-up
weights. Record rotating torque values at 10, 20, & 30 rpm.
16. Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting
pressure. Circ and condition mud with the liner on bottom. Reduce the low end rheology of the drilling
fluid by adding water and thinners.
17. Reciprocate & rotate string if hole conditions allow. Circ until hole and mud is in good condition for
cementing.
18. Cement 4-1/2” Production Liner
1. Hold a pre-job safety meeting over the upcoming cmt operations.
2. Attempt to reciprocate the casing during cmt operations until hole gets sticky.
3. Pump 15 bbls 12.5 ppg spacer.
4. Test surface cmt lines to 4500 psi.
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5. Pump remaining 10 bbls 12.5 ppg spacer.
6. Mix and pump cement per below recipe and volume below with xx lbs/bbl of loss circulation fiber.
Please independently verify cement volume with actual inputs. Ensure cmt is pumped at designed
weight. Job is designed to pump 40% OH excess but if wellbore conditions dictate otherwise decrease
or increase excess volumes. Cement volume is designed to bring cement to 5000’ MD (TOL).
7. Displacement fluid will be CLEAN drilling mud. Please independently verify with actual inputs.
Displacement = 119.6 bbls = (((7055-4800)*((3.958^2)/1029.4)))+((4800*((4.276^2)/1029.4))) - mgr
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Slurry Information:
8. Drop DP dart and displace with 9.6 ppg WBM.
9. Pump cement at max rate of 5 bbl/min. Reduce pump rate to 3 bpm prior to latching DP dart into liner
wiper plug. Note plug departure from liner hanger running tool and resume pumping at full
displacement rate. Displacement volume can be re-zeroed at this point
10. If elevated displacement pressures are encountered, position liner at setting depth and cease
reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman
immediately of any changes. Reduce pump rate as required to avoid packoff.
11. Bump the plug. Do not overdisplace by more than 2 bbls.
12. Pressure up to 4200 psi to release the running tool (HRD-E) from the liner
13. Bleed pressure to zero to check float equipment.
14. P/U, verify setting tool is released.
15. Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS nipple.
Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the pressure drops
rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be enough to overcome
hydrostatic differential at liner top).
16. Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up
to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up
rate until the sleeve area is thoroughly cleaned.
17. Pick up to the high-rate circulation point above the tieback extension, mark the pipe for reciprocation,
do not re-tag the liner top, and circulate the well clean.
18. Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP.
19. POOH, LDDP.
Backup release from liner running tool:
Lead Slurry Tail Slurry
Density 12.0 lb/gal 15.3 lb/gal
Yield 2.35 ft3/sk 1.16 ft3/sk
Mix Water 13.92 gal/sk 4.98 gal/sk
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20. If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise) torque will have to
be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that
the tool is in the neutral position. Apply left-hand torque as required to shear screws.
21. NOTE: Some hole conditions may require movement of the drillpipe to “work” the torque down to the
setting tool.
22. After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed
slacking off set-down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At
this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to
release collet from the profile.
Ensure to report the following on WellView:
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 liner 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
Note: Send Csg & cmt report + “As-Run” liner tally to sean.mclaughlin@hilcorp.com
19. Wellbore Clean Up & Displacement
1. No cleanout planned. Service coil will cleanout, displace mud, and blow down well with N2 prior to
perforating.
2. Test liner lap to 2000 psi after cement has reached 500 psi compressive strength. 10 min operational
assurance test.
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20. Run Completion Assembly
1. Run 4-1/2” tubing completion assembly to above the liner top
x Tubing will be 4-1/2” L-80 12.6# IBT
x SSSV to be placed at 500’
x CIM to be placed at 2000’
x GLM’s will be run.
2. Swap the well over to FIW
x Circulate a hi-vis pill followed by a soap train per Baroid
x Circulate FIW until clean-up is satisfactory.
x Leave FIW in the annulus.
3. Space out and land seal bore in tie back sleeve. RILDs.
4.Test IA to 2000 psi and tubing to 2000 psi. Charted 30 min.
5. Install BPV in wellhead.
6. ND BOPE, NU tree, test void
7. Rig Down
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21. BOP Schematic
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22. Wellhead Schematic
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23. Anticipated Drilling Hazards
Lost Circulation:
Little indication of LC in offset wells.
x Maintain sufficient volumes while drill.
x Maintain ability to take on FIW during drilling phase
x If a LC event occurs pumping cement will be the likely remedy
Ensure 500 lbs of medium/coarse fibrous material, 500 lbs SteelSeal (Angular, dual-composition
carbon-based material), & 500 lbs different sizes of Calcium Carbonate are available on location to mix
LCM pills at moderate product concentrations.
Hole Cleaning:
Maintain rheology w/ viscofier as necessary. Sweep hole w/ 20 bbls flowzan as necessary. Optimize
solids control equipment to maintain density and minimize sand content. Maintain programmed mud
specs.
Coal Drilling:
The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The
need for good planning and drilling practices is also emphasized as a key component for success.
x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections.
x Use asphalt-type additives to further stabilize coal seams.
x Increase fluid density as required to control running coals.
x Emphasize good hole cleaning through hydraulics, ROP and system rheology.
x Minimize swab and surge pressures
x Minimize back reaming through coals when possible
H2S:
H2S gas is not present is planned hole sections
Anti Collision:
o 87-04- Suspended with deep set cement plug
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24. 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 plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface
pressure is achieved for FIT at shoe. Add casing pressure test data to graph if recent and available.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
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25. Choke Manifold Schematic
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26. Casing Design Information
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27. 8-1/2” Hole Section MASP
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28. Plot (NAD 27) (Governmental Sections)
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29. Slot Diagram
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30. Directional Program (wp05) - Attached separately.
!
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-1275-850-42504258501275170021252550297534003825425046755100True Vertical Depth (850 usft/in)-425 0 425 850 1275 1700 2125 2550 2975 3400 3825 4250 4675 5100 5525 5950 6375 6800 7225 7650 8075Vertical Section at 245.80° (850 usft/in)13 3/8" x 17 1/2"9 5/8" x 12 1/4"4 1/2" x 8 1/2"050010001500200025003000350040004500500055006000650070007055BR 86-10 wp05Start Dir 2º/100' : 600' MD, 600'TVDStart Dir 3º/100' : 700' MD, 699.98'TVDStart Dir 4º/100' : 800' MD, 799.78'TVDEnd Dir : 2406.26' MD, 2078.48' TVDStart Dir 3º/100' : 5056.26' MD, 3240.16'TVDEnd Dir : 6356.26' MD, 4149.59' TVDTotal Depth : 7055' MD, 4782.87' TVDLower Beluga - SC ShoeTop TM1Top TM4Top TM8Top TM11Hilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: BR 86-10Water Depth: 62.00+N/-S +E/-WNorthing Easting LatitudeLongitude0.00 0.002559347.60269666.9060° 59' 56.2382 N 151° 17' 51.4219 WSURVEY PROGRAMDate: 2022-10-17T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool0.00 1000.00 BR 86-10 wp05 (BR 86-10) 3_Gyro-GC_Csg1000.00 5000.00 BR 86-10 wp05 (BR 86-10) 3_MWD+AX+Sag5000.00 7055.00 BR 86-10 wp05 (BR 86-10) 3_MWD+AX+SagFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation3215.00 3100.00 4998.86 Lower Beluga - SC Shoe3525.00 3410.00 5570.91 Top TM13843.00 3728.00 6000.51 Top TM44271.00 4156.00 6490.22 Top TM84630.00 4515.00 6886.33 Top TM11REFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: BR 86-10, True NorthVertical (TVD) Reference:kb @ 115.00usftMeasured Depth Reference:kb @ 115.00usftCalculation Method: Minimum CurvatureProject:Granite PointSite:Bruce PlatformWell:Plan: BR 86-10Wellbore:BR 86-10Design:BR 86-10 wp05CASING DETAILSTVD TVDSS MD Size Name600.00 485.00 600.00 13-3/8 13 3/8" x 17 1/2"3215.50 3100.50 5000.00 9-5/8 9 5/8" x 12 1/4"4782.87 4667.87 7055.00 4-1/2 4 1/2" x 8 1/2"SECTION DETAILSSecMD Inc Azi TVD +N/-S +E/-W Dleg TFace VSectTargetAnnotation1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002 600.00 0.00 0.00 600.00 0.00 0.00 0.00 0.00 0.00 Start Dir 2º/100' : 600' MD, 600'TVD3 700.00 2.00 180.00 699.98 -1.75 0.00 2.00 180.00 0.72 Start Dir 3º/100' : 700' MD, 699.98'TVD4 800.00 5.00 180.00 799.78 -7.85 0.00 3.00 0.00 3.22 Start Dir 4º/100' : 800' MD, 799.78'TVD5 1050.00 14.38 203.64 1046.01 -47.29 -12.48 4.00 35.00 30.7762406.26 64.00 248.00 2078.48 -461.31 -697.07 4.00 50.74 824.91 End Dir : 2406.26' MD, 2078.48' TVD75056.26 64.00 248.00 3240.16 -1353.55 -2905.44 0.00 0.00 3204.96 Start Dir 3º/100' : 5056.26' MD, 3240.16'TVD86356.26 25.00 248.00 4149.59 -1688.33 -3734.06 3.00 180.00 4097.99 End Dir : 6356.26' MD, 4149.59' TVD9 7055.00 25.00 248.00 4782.87 -1798.95 -4007.85 0.00 0.00 4393.08 Total Depth : 7055' MD, 4782.87' TVD
-2475-2250-2025-1800-1575-1350-1125-900-675-450-2250225450675South(-)/North(+) (450 usft/in)-4050 -3825 -3600 -3375 -3150 -2925 -2700 -2475 -2250 -2025 -1800 -1575 -1350 -1125 -900 -675 -450 -225 0West(-)/East(+) (450 usft/in)13 3/8" x 17 1/2"9 5/8" x 12 1/4"4 1/2" x 8 1/2"0250500750100012501 5 0 0
1 7 5 0
2 0 0 0
2 2 5 0
2 5 0 0
2 7 5 0
3 0 0 0
3 2 5 0
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4 2 5 0
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4 7 8 3 B R 8 6 -1 0 w p 0 5Start Dir 2º/100' : 600' MD, 600'TVDStart Dir 3º/100' : 700' MD, 699.98'TVDStart Dir 4º/100' : 800' MD, 799.78'TVDEnd Dir : 2406.26' MD, 2078.48' TVDStart Dir 3º/100' : 5056.26' MD, 3240.16'TVDEnd Dir : 6356.26' MD, 4149.59' TVDTotal Depth : 7055' MD, 4782.87' TVDCASING DETAILSTVDTVDSS MDSize Name600.00 485.00 600.00 13-3/8 13 3/8" x 17 1/2"3215.50 3100.50 5000.00 9-5/8 9 5/8" x 12 1/4"4782.87 4667.87 7055.00 4-1/2 4 1/2" x 8 1/2"Project: Granite PointSite: Bruce PlatformWell: Plan: BR 86-10Wellbore: BR 86-10Plan: BR 86-10 wp05WELL DETAILS: Plan: BR 86-10Water Depth: 62.00+N/-S +E/-WNorthingEastingLatitudeLongitude0.00 0.002559347.60 269666.90 60° 59' 56.2382 N 151° 17' 51.4219 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: BR 86-10, True NorthVertical (TVD) Reference: kb @ 115.00usftMeasured Depth Reference:kb @ 115.00usftCalculation Method:Minimum Curvature
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0.001.002.003.004.00Separation Factor0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000 6400 6800 7200 7600Measured Depth (800 usft/in)BR 42-18BR 42-31TYST86-01BR 87-04BR 42-12PB2BR 42-12BR 42-12RDBR 42-10BR Azalea L2-8 slotBR Fireweed 3 L2-3 slotBR Gernaium 2 L2-5 SlotNo-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: BR 86-10 NAD 1927 (NADCON CONUS)Alaska Zone 04Water Depth: 62.00+N/-S+E/-W Northing EastingLatitudeLongitude0.000.002559347.60 269666.90 60° 59' 56.2382 N 151° 17' 51.4219 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: BR 86-10, True NorthVertical (TVD) Reference: kb @ 115.00usftMeasured Depth Reference:kb @ 115.00usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2022-10-17T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool0.00 1000.00 BR 86-10 wp05 (BR 86-10) 3_Gyro-GC_Csg1000.00 5000.00 BR 86-10 wp05 (BR 86-10) 3_MWD+AX+Sag5000.00 7055.00 BR 86-10 wp05 (BR 86-10) 3_MWD+AX+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000 6400 6800 7200 7600Measured Depth (800 usft/in)BR 42-14BR 42-30BR 42-06BR-86-03L2BR 86-03RDBR 86 - 03BR 87-06BR 87-06PB1 - ShallowBR 42-20BR 42-20RDBR 42-18BR 42-31BR 42-31PB1BR 87-03TYST86-01TYST86-01BR 42-08BR 87-04BR 86-04BR 42-34BR 86-08BR 42-12BR 42-12RDBR 42-12RDBR 42-16BR 42-42LT1BR 42-42BR 86-09BR 87-05BR 86-05RDBR 86-05BR 86-08RD wp01BR Azalea L2-8 slotBR Fireweed 3 L2-3 slotBR Gernaium 2 L2-5 SlotGLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference0.00 To 7055.00Project: Granite PointSite: Bruce PlatformWell: Plan: BR 86-10Wellbore: BR 86-10Plan: BR 86-10 wp05CASING DETAILSTVD TVDSS MD Size Name600.00 485.00 600.00 13-3/8 13 3/8" x 17 1/2"3215.50 3100.50 5000.00 9-5/8 9 5/8" x 12 1/4"4782.87 4667.87 7055.00 4-1/2 4 1/2" x 8 1/2"
Revised 7/2022
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
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The 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-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot 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 this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a 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 the Operator 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 all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
UNDEFINED GAS
225-039
GRANITE POINT
GRANITE PT ST 17586-010
WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:GRANITE PT ST 17586 010Initial Class/TypeDEV / PENDGeoArea820Unit11954On/Off ShoreOnProgramDEVWell bore segAnnular DisposalPTD#:2250390Field & Pool:GRANITE PT, GRANITE PT GAS - 280500NA1Permit fee attachedYesSurf Loc & Top Prod Int lie in ADL0018742; TD lies within ADL0017586.2Lease number appropriateYes3Unique well name and numberNoGRANITE PT, UNDEFINED GAS - 280500 - governed by Statewide Regs4Well located in a defined poolYes5Well located proper distance from drilling unit boundaryNA6Well located proper distance from other wellsYes7Sufficient acreage available in drilling unitYes8If deviated, is wellbore plat includedYes9Operator only affected partyYes10Operator has appropriate bond in forceYes11Permit can be issued without conservation orderYes12Permit can be issued without administrative approvalYes13Can permit be approved before 15-day waitNA14Well located within area and strata authorized by Injection Order # (put IO# in comments) (For NA15All wells within 1/4 mile area of review identified (For service well only)NA16Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes17-1/2" conductor hole to 600'. 13-3/8" 68# conductor18Conductor string providedYes19Surface casing protects all known USDWsYesBoth conductor and 9-5/8" suface casing fully cemented.20CMT vol adequate to circulate on conductor & surf csgYes4-1/2" production liner fully cemented21CMT vol adequate to tie-in long string to surf csgYes22CMT will cover all known productive horizonsYes23Casing designs adequate for C, T, B & permafrostYesSpartan 151 has adequate tankage24Adequate tankage or reserve pitNAGrassroots well.25If a re-drill, has a 10-403 for abandonment been approvedYesHalliburton collision scan shows no existing wells with HSE risk. Close approach well will have downhole plug26Adequate wellbore separation proposedYes21-1/4" diverter w/16" outlet27If diverter required, does it meet regulationsYesAll fluids should be overbalanced to pore pressure28Drilling fluid program schematic & equip list adequateYes1 annular, 3 ram, 1 flow cross stack 13-5/8" 5M stack29BOPEs, do they meet regulationYesPressure tested to 3000 psi.30BOPE press rating appropriate; test to (put psig in comments)Yes31Choke manifold complies w/API RP-53 (May 84)Yes32Work will occur without operation shutdownNo33Is presence of H2S gas probableNA34Mechanical condition of wells within AOR verified (For service well only)YesNone anticipated based on offset wells.35Permit can be issued w/o hydrogen sulfide measuresYesExpected pressure range is 0.451 to 0.477 psi/ft (8.7 to 9.2 ppg EMW). Operator's planned mud program36Data presented on potential overpressure zonesNAappears sufficient to control anticipated pressures and maintain wellbore stability.37Seismic analysis of shallow gas zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate6/23/2025ApprMGRDate5/5/2025ApprSFDDate6/23/2025AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 6/25/2025
