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HomeMy WebLinkAbout220-0461
Guhl, Meredith D (OGC)
From:Guhl, Meredith D (OGC)
Sent:Wednesday, June 29, 2022 10:04 AM
To:'Abbie Barker'; 'Carrie Janowski'; 'Cody Dinger'; 'Darci Horner - (C)'; 'Donna Ambruz'; 'Jerimiah
Galloway'; 'Joseph Lastufka'; 'Josh Allely'; 'Juanita Lovett'; 'Tom Fouts'
Subject:Kenai Expired Permit: 220-046
Hello,
The following Permit to Drill, issued to Hilcorp Alaska, has expired under Regulation 20 AAC 25.005 (g). The PTD will be
marked expired in the AOGCC database.
Kenai KU 44‐01, PTD 220‐046, issued 22 May 2020.
If you have any questions, please contact me.
Thank you,
Meredith
Meredith Guhl (she/her)
Petroleum Geology Assistant
Alaska Oil and Gas Conservation Commission
333 W. 7th Ave, Anchorage, AK 99501
meredith.guhl@alaska.gov
Direct: (907) 793‐1235
CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation
Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.
The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail,
please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Meredith Guhl at
907‐793‐1235 or meredith.guhl@alaska.gov.
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Re: Kenai Gas Field, Beluga/Upper Tyonek Gas Pool, KU 44-01
Hilcorp Alaska, LLC
Permit to Drill Number: 220-046
Surface Location: 418' FSL, 1066' FWL, Sec. 6, T4N, R11W, SM, AK
Bottomhole Location: 990' FSL, 679' FEL, Sec. 1, T4N, R12W, SM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced development 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,
Daniel T. Seamount, Jr.
Commissioner
DATED this ___ day of May, 2020. 22
Daniel T.
Seamount, Jr.
Digitally signed by
Daniel T. Seamount, Jr.
Date: 2020.05.22
08:59:43 -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: 7,114' TVD: 6,844'
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): 83' 15. Distance to Nearest Well Open
Surface: x-271981 y- 2362473 Zone-4 65' to Same Pool: 2142' to KBU 11-07
16. Deviated wells:Kickoff depth: 350 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 23 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
Cond 16" 84# X-56 Weld 120' Surface Surface 120' 120'
9-7/8" 7-5/8" 29.7# L-80 DWC/C 1,750' Surface Surface 1,750' 1,680'
6-3/4" 5-1/2" 17# L-80 CDC HTQ 6,500' Surface Surface 7,114' 6,844'
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:
Contact Email:
Contact Phone:
Date:
Permit to Drill API Number: Permit Approval
Number:50- 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:
Sr Pet Eng Sr Pet Geo Sr Res Eng
6081' to nearest unit boundary
6/25/2020
Authorized Name: Monty Myers
Authorized Title: Drilling Manager
Monty Myers
mmyers@hilcorp.com
777-8431
18. Casing Program:Top - Setting Depth - BottomSpecifications
KU 44-01
Kenai Gas Field
Beluga / Upper Tyonek Gas Pool
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
Hilcorp Alaska, LLC
418' FSL, 1066' FWL, Sec 6, T4N, R11W, SM, AK FEEA028142, ADL392670
022224484
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
537 ft3
1252
889' FSL, 326' FEL, Sec 1, T4N, R12W, SM, AK
990' FSL, 679' FEL, Sec 1, T4N, R12W, SM, AK
N/A
2927
1609
Total Depth MD (ft):Total Depth TVD (ft):
Cement Quantity, c.f. or sacks
Cement Volume MDSize
Plugs (measured):
(including stage data)
Driven
L - 675 ft3 / T - 209 ft3
Effect. Depth TVD (ft):
Conductor/Structural
Length
Production
Liner
Casing
Intermediate
Commission Use Only
Effect. Depth MD (ft):
Authorized Signature:
See cover letter for other
requirements.
Perforation Depth MD (ft):
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):
5/14/2020
es N
ype of W
L
l R
L
1b
S
Class:
os N es No
s N o
D s
s
s
D
84
o
:
well is p
G
S
S
20
S S
S
es No s No
S
G
E
S
es No
s
Form 10-401 Revised 3/2020 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
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: 2020.05.14 13:36:15 -08'00'
Monty M
Myers
By Samantha Carlisle at 2:55 pm, May 14, 2020
*Diverter waiver to 20 AAC 25.035(h)(2) is approved
*24 hour notice to AOGCC for BOPE test to 3500 psi, 2500 psi annular
*CBL, MIT-IA to 2500 psi
*10-403 required to perforate
133-20690-00-00220-046
2943 psi
X
X
MGR21MAY20
X X
2285 psi
523 cu ft
X
490 cu ft
X
7,114
DSR-5/15/2020DLB 05/15/2020
X
05/22/2020
05/22/2020Daniel T. Seamount, Jr.Digitally signed by Daniel T. Seamount, Jr.
Date: 2020.05.22 09:18:26 -08'00'
KU 44-01
Drilling Program
Kenai Gas Field
Rev 0
May 14th, 2020
KU 44-01
Drilling Procedure
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 16” Conductor Riser ........................................................................................................ 11
11.0 Drill 9-7/8” Hole Section .......................................................................................................... 13
12.0 Run 7-5/8” Surface Casing ...................................................................................................... 16
13.0 Cement 7-5/8” Surface Casing ................................................................................................. 19
14.0 BOP N/U and Test.................................................................................................................... 22
15.0 Drill 6-3/4” Hole Section .......................................................................................................... 23
16.0 Run 5-1/2” Production Casing ................................................................................................. 26
17.0 Cement 5-1/2” Production Casing ........................................................................................... 29
18.0 RDMO ...................................................................................................................................... 31
19.0 BOP Schematic ........................................................................................................................ 32
20.0 Wellhead Schematic ................................................................................................................. 33
21.0 Days Vs Depth .......................................................................................................................... 34
22.0 Geo-Prog .................................................................................................................................. 35
23.0 Anticipated Drilling Hazards .................................................................................................. 36
24.0 Hilcorp Rig 169 Layout ........................................................................................................... 38
25.0 FIT Procedure .......................................................................................................................... 39
26.0 Choke Manifold Schematic ...................................................................................................... 40
27.0 Casing Design Information ...................................................................................................... 41
28.0 6-3/4” Hole Section MASP ....................................................................................................... 42
29.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 43
30.0 Surface Plat (NAD 27) ............................................................................................................. 44
31.0 Directional Plan (wp05) ........................................................................................................... 46
Page 2 Version 0 May, 2020
KU 44-01
Drilling Procedure
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1.0 Well Summary
Well KU 44-01
Pad & Old Well Designation KU 44-01 is a grass roots well on KGF Pad 14-06
Planned Completion Type 5-1/2” Production Longstring (monobore)
Target Reservoir(s) Beluga
Planned Well TD, MD / TVD 7,114 MD / 6,844’ TVD
PBTD, MD / TVD 7,000’ MD / 6,731’ TVD
Surface Location (Governmental) 418’ FSL, 1066’ FWL, Sec 6, T4N, R11W, SM, AK
Surface Location (NAD 27) X=271981.62 Y=2362473.32
Surface Location (NAD 83)
Top of Productive Horizon
(Governmental) 889’ FSL, 326’ FEL, Sec 1, T4N, R12W, SM, AK
TPH Location (NAD 27) X=270683.21, Y=2362870.85
TPH Location (NAD 83)
BHL (Governmental) 990’ FSL, 679’ FEL, Sec 1, T4N, R12W, SM, AK
BHL (NAD 27) X=270332.3, Y=2362978.79
BHL (NAD 83)
AFE Number 2011786 (D, C, F)
AFE Drilling Days 3 MOB, 20 DRLG
AFE Completion Days
AFE Drilling Amount $2,357,530
AFE Completion Amount
Maximum Anticipated Pressure
(Surface) 1252 psi
Maximum Anticipated Pressure
(Downhole/Reservoir) 1609 psi
Work String 4-1/2” 16.6# S-135 CDS-40
RKB – GL 83’(65 + 18)
Ground Elevation 65’
BOP Equipment 11” 5M Control Tech Type 90 Annular BOP
11” 5M Control Tech Type 82 Double Ram
11” 5M Control Tech Type 82 Single Ram
2943 psi
2285 psi
Page 3 Version 0 May, 2020
KU 44-01
Drilling Procedure
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2.0 Management of Change Information
Page 4 Version 0 May, 2020
KU 44-01
Drilling Procedure
Rev 0
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 16” 15.01” 14.822 17” 84 J-55 Weld 2980 1410 -
9-7/8” 7-5/8” 6.875” 6.75” 8.5” 29.7 L-80 BTC 6890 4790 683
6-3/4” 5-1/2” 4.892” 4.767” 6.05” 17 P110HC USS-CDC 10600 8730 568
4.0 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 4-1/2” 3.826 2.6875” 5.25” 16.6 S-135 CDS40 17,693 16,769 468k
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks).
L-80
Page 5 Version 0 May, 2020
KU 44-01
Drilling Procedure
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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
tab.
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.
5.2 Afternoon Updates
x Submit a short operations update each work day to pmazzolini@hilcorp.com,
mmyers@hilcorp.com and cdinger@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. Each rig will be assigned a
username to login with.
5.4 EHS Incident Reporting
x Notify EHS field coordinator.
1. This could be one of (3) individuals as they rotate around. Know who your EHS field
coordinator is at all times, don’t wait until an emergency to have to call around and figure
it out!!!!
a. John Coston: O: (907) 777-6726 C: (907) 227-3189
b. Matt Hogge: O: (907) 777-8418 C: (907) 227-9829
2. Spills: Keegan Fleming: O:907-777-8477 C:907-350-9439
x Notify Drlg Manager
1. Monty M Myers: O: 907-777-8431 C: 907-538-1368
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 and cdinger@hilcorp.com
5.6 Casing and Cmt report
x Send casing and cement report for each string of casing to mmyers@hilcorp.com and
cdinger@hilcorp.com
Page 6 Version 0 May, 2020
KU 44-01
Drilling Procedure
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6.0 Planned Wellbore Schematic
Page 7 Version 0 May, 2020
KU 44-01
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7.0 Drilling / Completion Summary
KU 44-01 is an S-shaped directional grassroots development well to be drilled off of the KGF 14-06 pad.
Reservoir analysis and subsurface mapping has identified an optimal location for infill development in the
Middle and Upper Beluga sands.
The base plan is a directional wellbore with a kick off point at 350’ MD. Maximum hole angle will be 23
deg. and TD of the well will be 7,114’ TMD/ 6,844’ TVD, ending with 10 deg inclination left in the hole.
Vertical section will be 4679 ft.
Drilling operations are expected to commence approximately June 25th 2020. The Hilcorp Rig # 169 will be
used to drill the wellbore then run casing and cement.
Surface casing will be run to 1,750 MD / 1,680’ TVD and cemented to surface to ensure protection of any
shallow freshwater resources. Cement returns to surface will confirm TOC at surface. If cmt returns to surface
are not observed, a Temp log will be run between 6 – 18 hrs after CIP to determine TOC. Necessary remedial
action will then be discussed with AOGCC authorities.
All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field
G&I facility for disposal / beneficial reuse depending on test results.
General sequence of operations:
1. MOB Hilcorp Rig # 169 to well site
2. N/U conductor riser. (No diverter, diverter waiver requested)
3. Drill 9-7/8” hole to 1,750’ MD. Run and cmt 7-5/8” surface casing.
4. ND conductor riser, N/U & test 11” x 5M BOP.
5. Drill 6-3/4” hole section to 7,114’ MD. Perform Wiper trip.
6. Make cleanout run
7. POOH laying down drill pipe.
8. Run and cmt 5-1/2” production casing.
9. N/D BOP, N/U temp abandonment cap, RDMO.
Reservoir Evaluation Plan:
1. Surface hole: GR + Res
2. Production Hole: GR + Res
3. Mud loggers from surface casing point to TD.
Diverter waiver approved.
24 hour notice to AOGCC to witness.
Casing test and FIT digital data to AOGCC.
Page 8 Version 0 May, 2020
KU 44-01
Drilling Procedure
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8.0 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 of KU 44-01. Ensure to provide
AOGCC 24 hrs notice prior to testing BOPs.
x The initial test of BOP equipment will be to 250/3500 psi & subsequent tests of the BOP equipment
will be to 250/3500 psi for 5/5 min (annular to 50% rated WP, 2500 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, 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”
x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
Regulation Variance Requests:
x Diverter waiver requested due to the recent drilling of KU 24-32 and KU 11-07X nearby. No issues
were experienced on either well drilling the surface hole. Surface casing will be set at the same
depth on KU 44-01. No shallow hydrocarbon zones will be penetrated.
Page 9 Version 0 May, 2020
KU 44-01
Drilling Procedure
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Summary of BOP Equipment and Test Requirements
Hole Section Equipment Test Pressure (psi)
9-7/8” x No diverter utilized n/a
6-3/4”
x 11” x 5M Annular BOP
x 11” x 5M Double Ram
o Blind ram in btm cavity
x Mud cross
x 11” x 5M Single Ram
x 3-1/8” 5M Choke Line
x 2-1/16” x 5M Kill line
x 3-1/8” x 2-1/16” 5M Choke manifold
x Standpipe, floor valves, etc
Initial Test: 250/3500
(Annular 2500 psi)
Subsequent Tests:
250/3500
(Annular 2500 psi)
x Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal
bottles).
x Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency
pressure is provided by bottled nitrogen.
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.
Additional requirements may be stipulated on APD and Sundry.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email: jim.regg@alaska.gov
Guy Schwartz / Petroleum Engineer / (O): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartz@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email: victoria.loepp@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 Version 0 May, 2020
KU 44-01
Drilling Procedure
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9.0 R/U and Preparatory Work
9.1 Set 16” conductor at +/-120’ below ground level.
9.2 Dig out and set impermeable cellar.
9.3 Install Seaboard slip-on 16-3/4” 3M “A” section. Ensure to orient wellhead so that tree will line
up with flowline later.
9.4 Level pad and ensure enough room for layout of rig footprint and R/U.
9.5 Layout Herculite on pad to extend beyond footprint of rig.
9.6 R/U Hilcorp Rig # 169, spot service company shacks, spot & R/U company man & toolpusher
offices.
9.7 RU Mud loggers on surface hole section for gas detection only. No samples required
9.8 After rig equipment has been spotted, R/U handi-berm containment system around footprint of
rig.
9.9 Mix mud for 9-7/8” hole section.
9.10 Install 5-1/2” liners in mud pumps.
x HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes
with 5-1/2” liners.
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10.0 N/U 16” Conductor Riser
10.1 N/U 16” Conductor Riser
x Ensure line does not direct flow from trip tank straight down the flowline. Fill up line and
flowline should be oriented 90 degrees to each other at approx. the same height.
x Ensure flowline outlet installed so that enough slope exists to carry cuttings to the shakers.
x Consider adding additional drainage points at the bottom of the conductor riser if deemed
necessary.
x R/U fill up line to conductor riser.
10.2 Set wearbushing in wellhead.
Diverter waiver approved per 20 AAC 25.035 (h)(2)
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KU 44-01
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10.3 Rig Orientation on KGF 14-06 pad:
Page 13 Version 0 May, 2020
KU 44-01
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11.0 Drill 9-7/8” Hole Section
11.1 P/U 9-7/8” directional drilling assy:
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 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
x Workstring will be 4.5” 16.6# S-135 CDS40
11.2 Primary Bit:
Page 14 Version 0 May, 2020
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11.3 4-1/2” Workstring & HWDP will come from Hilcorp. Jars will come from Weatherford.
11.4 Begin drilling out from 16” conductor at reduced flow rates to avoid broaching the conductor.
11.5 Drill 9-7/8” hole section to 1,750’ MD/ 1,680’ TVD. Confirm this setting depth with the
geologist and Drilling Engineer while drilling the well.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate.
x Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be
provided by Hilcorp Geo team.
x Keep swab and surge pressures low when tripping.
x Make wiper trips every 500’ or every couple days 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.
x TD the hole section in a good shale between 1700’ MD and 1800’ MD.
x Take MWD surveys every stand drilled (60’ intervals).
11.6 9-7/8” hole mud program summary:
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.
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, Toolpusher office, and mud
loggers office.
System Type: 8.8 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud
Properties:
Depths Density Viscosity Plastic Viscosity Yield Point API FL pH
120-1750’ 8.8 – 9.5 85-150 20 - 40 25 - 45 <10 8.5-9.0
8.8 – 9.5
Page 15 Version 0 May, 2020
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System Formulation: Aquagel + FW spud mud
Product Concentration
FRESH WATER
SODA ASH
AQUAGEL
CAUSTIC SODA
BARAZAN D+
BAROID 41
PAC-L /DEXTRID LT
ALDACIDE G
X-TEND II
0.905 bbl
0.5 ppb
12-15 ppb
0.1 ppb (9 pH)
as needed
as required for weight
if required for <12 FL
0.1 ppb
0.02 ppb
11.7 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16” conductor shoe.
11.8 TOH with the drilling assy, handle BHA as appropriate.
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12.0 Run 7-5/8” Surface Casing
12.1 R/U and pull wearbushing.
12.2 R/U Weatherford 7-5/8” casing running equipment.
x Ensure 7-5/8” BTC x CDS 40 XO on rig floor and M/U to FOSV.
x R/U fill-up line to fill casing while running.
x Ensure all casing has been drifted on the location prior to running.
x Be sure to count the total # of joints on the location before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
12.3 P/U shoe joint, visually verify no debris inside joint.
12.4 Continue M/U & thread locking shoe track assy consisting of:
x (1) Shoe joint w/ float shoe bucked on (thread locked).
x (1) Joint with coupling thread locked.
x (1) Joint with float collar bucked on pin end & thread locked.
x Install (2) centralizers on shoe joint over a stop collar. 10’ from each end.
x Install (1) centralizer, mid tube on thread locked joint and on FC joint.
x Ensure proper operation of float equipment.
12.5 Continue running 7-5/8” surface casing
x Fill casing while running using fill up line on rig floor.
x Use “API Modified” thread compound. Dope pin end only w/ paint brush.
x Install (1) centralizer every other joint to 300’. Do not run any centralizers above 300’ in the
event a top out job is needed.
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
7-5/8” DWC/C M/U Torque
Casing OD Min Torque Max Torque
7-5/8” 21,700 ft-lbs 25,100 ft-lbs
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12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.7 Slow in and out of slips.
12.8 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. Position the shoe as close to TD as possible. 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.
12.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly
landed out in the wellhead profile.
12.10 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.
12.11 After circulating, lower string and land hanger in wellhead again.
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13.0 Cement 7-5/8” Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cmt 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 cmt unit at acceptable rates.
x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to
cuttings bin, prior to pumping any fluid downhole
x How to handle cmt returns at surface.
x Which pump will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Positions and expectations of personnel involved with the cmt operation.
13.2 Document efficiency of all possible displacement pumps prior to cement job
13.3 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded
correctly.
13.4 Pump 5 bbls 10 ppg spacer. Test surface cmt lines.
13.5 Pump remaining 30 bbls of 10 ppg spacer.
13.6 Drop bottom plug. Mix and pump cmt per below recipe.
13.7 Cement volume based on annular volume + 75% open hole excess. Job will consist of lead &
tail, TOC brought to surface.
Estimated Total Cement Volume:
Section: Calculation: Vol (BBLS) Vol (ft3)
12.0 ppg LEAD:
16” Conductor x 7-5/8”
casing annulus:
120’ x .0932 bpf = 11.2 63
12.0 ppg LEAD:
9-7/8” OH x 7-5/8” Casing
annulus:
(1750’ – 120’) x .0382 bpf x
1.75 =
109 612
Total LEAD: 120.2 675 ft3
15.4 ppg TAIL:
9-7/8” OH x 7-5/8” Casing
annulus:
(1750’-1250’) x .0382 bpf x
1.75 =
33.4 188
15.4 ppg TAIL:
7-5/8” Shoe track:
80 x .04591 bpf = 3.7 21
Total TAIL: 37.1 bbl 209 ft3
2
86.7
427
170 sx
75.5
490 198 sx
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Cement Slurry Design:
13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger
elevated above the wellhead while working. If the hole gets “sticky”, land the hanger on seat
and continue with the cement job.
13.9 After pumping cement, drop top plug and displace cement with spud mud.
13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate.
13.11 Displacement calculation:
1750’- 80’ = 1670’ x .04591 bpf = 77 bbls
13.12 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes
become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to
pump out fluid from cellar. Have some sx of sugar available to retard setting of cement.
Lead Slurry (1000’ MD to surface) Tail Slurry (1250’ to 1750’ MD)
System Extended Conventional
Density 12 lb/gal 15.4 lb/gal
Yield 2.46 ft3/sk 1.22 ft3/sk
Mixed Water 14.349 gal/sk 5.507 gal/sk
Mixed Fluid 14.469 gal/sk 5.507 gal/sk
Additives
Code Description Concentration Code Description Concentration
G Cement 94#/sk A Cement 94#/sk
D110 Retarder 0.15 gal/sk BWOC D046 Anti Foam 0.2 % BWOC
D046 Anti Foam 0.2 % BWOC D065 Dispersant 0.4 % BWOC
D079 Extender 2.0 % BWOC S002 CaCl2 0.35 % BWOC
D020 Extender 3.0 % BWOC D177 CaCl2 0.1 % BWOC
1250'
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13.13 Do not overdisplace by more than ½ shoe track volume. Total volume in shoe track is 3.7 bbls.
x Be prepared for cement returns to surface. If cmt returns are not observed to surface, be
prepared to run a temp log between 12 – 18 hours after CIP.
x Be prepared with small OD top out tubing in the event a top out job is required. The
AOGCC will require us to run steel pipe through the hanger flutes. The ID of the flutes
is 1.5”.
13.14 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.
13.15 R/D cement equipment. Flush out wellhead with FW.
13.16 Back out and L/D landing joint. Flush out wellhead with FW.
13.17 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.
13.18 Lay down landing joint and pack-off running tool.
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 cdinger@hilcorp.com and
mmyers@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC.
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14.0 BOP N/U and Test
14.1 N/U multi-bowl wellhead assy. Install 7-5/8” packoff P-seals. Test to 3000 psi.
14.2 N/U 11” x 5M BOP as follows:
x BOP configuration from Top down: 11” x 5M annular BOP/11” x 5M double ram /11” x 5M
mud cross/11” x 5M single ram
x Double ram should be dressed with 2-7/8” X 5” variable bore rams in top cavity, blind ram
in btm cavity.
x Single ram should be dressed with 2-7/8” X 5” variable bore rams
x N/U bell nipple, install flowline.
x Install (2) manual valves & a check valve on kill side of mud cross.
x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual
valve.
14.3 Run 4-1/2” BOP test assy, land out test plug (if not installed previously).
x Test BOP to 250/3500 psi for 5/10 min. Test annular to 250/2500 psi for 5/10 min.
x Ensure to leave “B” section side outlet valves open during BOP testing so pressure does not
build up beneath the test plug.
14.4 R/D BOP test assy.
14.5 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.6 Mix 9.0 ppg 6% KCL PHPA mud system.
14.7 R/U mud loggers for production hole section.
14.8 Rack back as much 4-1/2” DP in derrick as possible to be used while drilling the hole section.
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15.0 Drill 6-3/4” Hole Section
15.1 Pull test plug, run and set wear bushing
15.2 Ensure BHA components have been inspected previously.
15.3 Drift and caliper all components before M/U. Visually verify no debris inside components that
cannot be drifted.
15.4 TIH, Conduct shallow hole test of MWD and confirm Gamma Ray and Resistivity LWD
functioning properly.
15.5 Ensure TF offset is measured accurately and entered correctly into the MWD software.
15.6 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
15.7 Workstring will be 4-1/2” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to
drill the entire open hole section without having to pick up pipe from the pipeshed.
15.8 6-3/4” hole section mud program summary:
Weighting material to be used for the hole section will be barite, salt and calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg above
highest anticipated MW.
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, Toolpusher office, and mud
loggers office.
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System Type: 9.0 ppg 6% KCL PHPA fresh water based drilling fluid.
Properties:
MD Mud
Weight Viscosity Plastic
Viscosity Yield Point pH HPHT
1,750’- 7,114’ 9.0 – 10.0 40-53 15-25 15-25 8.5-9.5 11.0
System Formulation: 6% KCL EZ Mud DP
Product Concentration
Water
KCl
Caustic
BARAZAN D+
EZ MUD DP
DEXTRID LT
PAC-L
BARACARB 5/25/50
BAROID 41
ALDACIDE G
BARACOR 700
BARASCAV D
0.905 bbl
22 ppb (29 K chlorides)
0.2 ppb (9 pH)
1.25 ppb (as required 18 YP)
0.75 ppb (initially 0.25 ppb)
1-2 ppb
1 ppb
15 - 20 ppb (5 ppb of each)
as required for a 9.0 – 10.0 ppg
0.1 ppb
1 ppb
0.5 ppb (maintain per dilution rate)
15.9 TIH w/ 6-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth
TOC tagged on AM report.
15.10 R/U and test casing to 3500 psi / 30 min. Ensure to record volume / pressure and plot on FIT
graph. AOGCC requirement is 50% of burst. 7-5/8” burst is 6890 psi / 2 = 3445 psi.
15.11 Drill out shoe track and 20’ of new formation.
15.12 CBU and condition mud for FIT.
15.13 Conduct FIT to 13.5 ppg EMW.
Note: Offset field test data predicts frac gradient at the 7-5/8” shoe to be between 11 - 13 ppg
EMW. A 13.5 ppg FIT results in a 4 ppg kick margin while drilling with the planned MW of 9.5
ppg.
Kick tolerance = (13.5-9.0)X(1680/6844) = 1.10
15.14 Drill 6-3/4” hole section to 7,114’ MD / 6,844’ TVD
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
9.0 – 10.0 –
g
FIT
MIT casing
Casing test and FIT digitatl data to AOGCC for review.
Conduct FIT to 13.5 ppg EMW.
R/U and test casing to 3500 psi / 30 min.
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x Pump at 225 - 300 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 500’ 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.
x Take (3) sets of formation samples every 20’.
15.15 At TD; pump sweeps, CBU, and pull a wiper trip back to the 7-5/8” shoe.
15.16 TOH with the drilling assy, standing back drill pipe.
15.17 LD BHA
15.18 RD loggers, PU 6-3/4”clean out BHA, and TIH to TD.
15.19 Pump sweep, CBU and condition mud for casing run.
15.20 POOH LDDP and BHA
15.21 Install 5-1/2” pipe rams in BOP stack and test.
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16.0 Run 5-1/2” Production Casing
16.1. R/U Weatherford 5-1/2” casing running equipment.
x Ensure 5-1/2” CDC HTQ x CDS 40 crossover on rig floor and M/U to FOSV.
x R/U fill up line to fill casing while running.
x Ensure all casing has been drifted 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.
16.2. P/U shoe joint, visually verify no debris inside joint.
16.3. Continue M/U & thread locking shoe track assy consisting of:
x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked).
x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked).
x Solid body centralizers will be pre-installed on shoe joint an FC joint.
x Leave centralizers free floating so that they can slide up and down the joint.
x Ensure proper operation of float shoe and float collar.
x Utilize a collar clamp until weight is sufficient to keep slips set properly
16.4. Continue running 5-1/2” production casing
x Fill casing while running using fill up line on rig floor.
x Use “API Modified” thread compound. Dope pin end only w/ paint brush.
x Install solid body centralizers on every joint across zones of interest, TBD after LWD.
x Install solid body centralizers on every other joint to 7-5/8” shoe. Leave the centralizers free
floating.
x Pick up swell packer and place in string at approximately 1400’.
16.5. Continue running 5-1/2” production casing
5-1/2” CDC HTQ M/U torques
Casing OD Minimum Maximum Yield Torque
5-1/2” 8,500 ft-lbs 11,500 ft-lbs 13,900 ft-lbs
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16.6. Run in hole w/ 5-1/2” casing to the 7-5/8” casing shoe.
16.7. Fill the casing with fill up line and break circulation every 1,000 feet to the shoe or as the hole
dictates.
16.8. Obtain slack off weight, PU weight, rotating weight and torque of the casing.
16.9. Circulate 2X bottoms up at shoe, ease casing thru shoe.
16.10. Continue to RIH w/ casing no faster than 1 jt./minute. Watch displacement carefully and avoid
surging the hole. Slow down running speed if necessary.
16.11. Set casing slowly in and out of slips.
16.12. PU 5-1/2” X 6-3/4” swell packer to be placed at approximately 1400’. Swell packer should have
10’ handling pups installed on both ends with bow spring centralizers on pups.
16.13. Swedge up and wash last 2 joints to bottom. P/U 5’ off bottom. Note slack-off and pick-up
weights.
16.14. Stage pump rates up slowly to circulating rate. Circ and condition mud with casing on bottom.
Circulate 2X bottoms up or until pressures stabilize and mud properties are correct and the
shakers are clean. Reduce the low end rheology of the drilling fluid by adding water and
thinners.
16.15. Reciprocate string if hole conditions allow. Circ until hole and mud is in good condition for
cementing.
PU 5-1/2” X 6-3/4” swell packer to be placed at approximately 1400’
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17.0 Cement 5-1/2” Production Casing
17.1. Hold a pre-job safety meeting over the upcoming cmt 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 cmt unit at acceptable rates.
x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to
cuttings bin, prior to pumping any fluid downhole
x How to handle cmt returns at surface, regardless of how unlikely it is that this should occur.
x Which pump will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Positions and expectations of personnel involved with the cmt operation.
x Document efficiency of all possible displacement pumps prior to cement job.
17.2. Attempt to reciprocate the casing during cmt operations until hole gets sticky
17.3. Pump 5 bbls of 12.5 ppg Mud Push spacer.
17.4. Test surface cmt lines to 4500 psi.
17.5. Pump remaining 30 bbls 12.5 ppg Mud Push spacer.
17.6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed
weight. Job is designed to pump 5% OH excess.
Section: Calculation: Vol
(BBLS) Vol (ft3)
7-5/8” x 5-1/2” Csg Overlap: 500’ x 0.01653 = 8 46
6-3/4” OH x 5-1/2” Casing: (7114 – 1750) x 0.01487 x 1.05 = 84 470
Shoe Track: 80’ x 0.04591 = 3.7 21
Total Volume : 96 537
52294
1.9 11
.0232
410 sx
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17.7. Drop wiper plug and displace with 6% KCl mud.
17.8. If hole conditions allow – continue reciprocating casing throughout displacement. This will
ensure a high quality cement job with 100% coverage around the pipe.
17.9. If elevated displacement pressures are encountered, position casing at setting depth and cease
reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman
immediately of any changes.
17.10. Bump the plug and pressure up to 500 psi over final lift pressure. Hold pressure for 3 minutes.
17.11. Do not overdisplace by more than ½ shoe track. Shoe track volume is 1.5 bbls.
17.12. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned
after bumping plug and releasing pressure.
17.13. RD cementers and flush equipment.
17.14. WOC minimum of 12 hours, test casing to 2500 psi and chart for 30 minutes.
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 mmyers@hilcorp.com. This will be
included with the EOW documentation that goes to the AOGCC.
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18.0 RDMO
18.1. Install BPV in wellhead
18.2. N/D BOPE
18.3. N/U temp abandonment cap
18.4. RDMO Hilcorp Rig #169
POST Rig CBL of 5-1/2" and MIT-IA to 2500 psi.
Separate 10-403 must be submitted to perforate.
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19.0 BOP Schematic
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20.0 Wellhead Schematic
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21.0 Days Vs Depth
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22.0 Geo-Prog
Well Name:KU 44-01 Survey Type RKB
Field Name:Kenai Gas Field Surface Hole:83
Pool Name: Bottom Hole:
169
State:Alaska 18
Field Location:Onshore Coord Ref Sys:NAD27 AK Zone 4 65
County/Parish:Kenai Penninsula Borough
Objective:
Reference Plan:
P3_A4 Sandstone Water 3489
3,219.0 -3201 2362590.25 270878.47 1440.45 0.45
P3_A8 Sandstone Gas/Water 3807
3,527.0 -3509 2362612.1 270802.5 947 0.27
P3_A9 Sandstone Gas/Water 3857
3,576.0 -3558 2362614.51 270794.1 1601.1 0.45
P3_A10 Sandstone Gas/Water 3876
3,594.0 -3576 2362615.39 270791.03 440 0.12
P3_A11 Sandstone Gas/Water 3949
3,666.0 -3648 2362618.89 270778.84 500 0.14
P4_B1 Sandstone Gas/Water 4030
3,746.0 -3728 2362622.77 270765.32 1623 0.44
P6_C1 Sandstone GAS 4723
4,429.0 -4411 2362655.94 270649.62 250 0.06
P6_C2 Sandstone GAS 4889
4,593.0 -4575 2362663.91 270621.84 250 0.05
U_BELUGA Sandstone Gas/Water 4985
4,687.0 -4669 2362668.48 270605.89 1526 0.33
UB_3 Sandstone Gas 5148
4,847.0 -4829 2362676.28 270578.68 1875 0.39
UB_4 Sandstone Gas 5220
4,919.0 -4901 2362679.75 270566.57 2008 0.41
UB_5B Sandstone Gas 5383
5,079.0 -5061 2362687.54 270539.43 1329 0.26
UB_7 Sandstone Gas 5460
5,154.0 -5136 2362691.21 270526.62 1008 0.20
UB_8 Sandstone Gas 5547
5,240.0 -5222 2362695.37 270512.11 2135 0.41
M_BELUGA Sandstone Gas/Water 5658
5,349.0 -5331 2362700.68 270493.6 2147 0.40
MB_3 Sandstone Gas/Water 5833
5,522.0 -5504 2362709.05 270464.39 2343 0.43
L_BELUGA Sandstone Gas/Water 6438
6,118.0 -6100 2362738.02 270363.37 2745 0.45
LB_1B Sandstone Gas 6515
6,194.0 -6176 2362741.74 270350.4 2269 0.37
LB_2A Sandstone Gas 6807
6,482.0 -6464 2362755.71 270301.68 2602 0.40
LB_2C Sandstone Gas/Water 6884
6,557.0 -6539 2362759.39 270288.85 2942.55 0.45
= Reservoir Objectives
= Possible Geo Hazards
TARGETRADIUS
Mud Logging:
LWD Data:
Other Log Data:
Coreing:
Frac Half-Length
SH Max Direction
Surf.
Inter.
Prod.
NOTES:
DATA COLLECTION REQUIREMENTS:
OTHER COMMENTS
LWD Triple Combo; GeoTap Pressure Stations
PROSED PIPE SET DEPTHS
Chance of Success & Anticipated Rate
ARTIFICIAL LIFT EQUIPMENT OD
TUBING SIZE
Target Sterling and Upper Beluga sands on the West side of structure.
COMPLETION TYPE Monobore
Fault Constraints
100 FT
Surface casing to total depth, 30 ft samples with 20' samples in zones of interest, two sets of dry cut cuttings,
KU 44-01 wp02ANTICIPATED FORMATION TOPS & GEOHAZARDS
Geo Summary/
Justification:
Sterling and upper beluga offtake in the local area has been minimal. Log shows, pressure data support remaining prospects
TOP NAME LITHOLOGY EXPECTED
FLUID
MD
(FT)
TVD
(FT)
TVDSS
(FT)NORTHING EASTING Est.
Pressure Gradient
Ground Elevation:
GEOLOGICAL PROGNOSIS
Proposed
x = 2,362,473.32 y = 271,981.62
TVD Ref Datum:
TVD Ref Elevation:
Planned Rig:
Rig Height:
x = 2,362,978.79 y = 270,332.30
7,114' MD 6,844' TVD
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23.0 Anticipated Drilling Hazards
9-7/8” Hole Section:
Lost Circulation:
Ensure 500 lbs of medium/coarse fibrous 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/ gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary.
Optimize solids control equipment to maintain density, sand content, and reduce the waste stream.
Maintain YP between 25 – 45 to optimize hole cleaning and control ECD.
Wellbore stability:
Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with
intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger
than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity.
Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP
of ~50 - ~60 lbs/100ft2 to combat this issue. Maintain low flow rates for the initial 200’ of drilling to
reduce the likelihood of washing out the conductor shoe.
To help insure good cement to surface after running the casing, condition the mud to a YP of 25 –30
prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be
found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be
achieved.
H2S:
H2S is not present in this hole section.
No abnormal pressures or temperatures are present in this hole section.
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6-3/4” Hole Section:
Lost Circulation:
Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix
LCM pills at moderate product concentrations.
Hole Cleaning:
Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary.
Optimize solids control equipment to maintain density and minimize sand content. Maintain YP
between 20 - 30 to optimize hole cleaning and control ECD.
Wellbore stability:
Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque
reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl
in system for shale inhibition.
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.
H2S:
H2S is not present in this hole section.
No abnormal temperatures are present in this hole section.
Page 38 Version 0 May, 2020
KU 44-01
Drilling Procedure
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24.0 Hilcorp Rig 169 Layout
Page 39 Version 0 May, 2020
KU 44-01
Drilling Procedure
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25.0 FIT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
Page 40 Version 0 May, 2020
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Drilling Procedure
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26.0 Choke Manifold Schematic
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KU 44-01
Drilling Procedure
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27.0 Casing Design Information
9-7/8"Mud Density:8.8 ppg
6-3/4"Mud Density:10 ppg
Mud Density:
1609 psi (see attached M ASP determination & calculation)
1252 psi (see attached M ASP determination & calculation)
Collapse Calculation:
Section Calculation
1 Normal gradient external stress (0.45 psi/ft) and the casing evacuated for the internal stress
1234
7-5/8" 5-1/2"
00
0 0
1,750 7,114
1,680 6,844
1,750 7,114
29.7 17
L-80 L-80
DWC CDC HTQ
51,975 120,938
51,975 120,938
683 428
13.14 3.54
731 3,080
4,790 6,290
6.55 2.04
475 1,609
6,890 7,740
14.51 4.81
Collapse Pressure at bottom (Psi)
Calculation & Casing Design Factors
Kenai Gas Field
Calculation/Specification
Casing OD
Bottom (MD)
Bottom (TVD)
Top (MD)
Tension at Top of Section (lbs)
Design Criteria:
Minimum Yield (psi)
Weight (ppf)
Grade
Connection
Weight w/o Bouyancy Factor (lbs)
Min strength Tension (1000 lbs)
Collapse Resistance w/o tension (Psi)
Worst Case Safety Factor (Collapse)
MASP (psi)
Worst Case Safety Factor (Tension)
Casing Section
MASP:
Drilling Mode
MASP:
Length
Top (TVD)
Worst case safety factor (Burst)
DATE: 05/14/2020
WELL: KU 44-01
FIELD: Kenai Gas Field
DESIGN BY: Monty M Myers
Hole Size
Hole Size
Hole Size
MASP:
Production Mode
MASP =2285 psi
3.38
1 609
81
Page 42 Version 0 May, 2020
KU 44-01
Drilling Procedure
Rev 0
28.0 6-3/4” Hole Section MASP
MD TVD
Planned Top: 0 0
Planned TD: 7114 6844
Anticipated Formations and Pressures:
Formation TVD Est Pressure Oil/Gas/Wet PPG Grad
P3_A4 3219 1440 Water 8.6 0.45
P3_A8 3527 947 Gas/Water 5.2 0.27
P3_A9 3576 1601 Gas/Water 8.6 0.45
P3_A10 3594 440 Gas/Water 2.4 0.12
P3_A11 3666 500 Gas/Water 2.6 0.14
P4_B1 3746 1623 Gas/Water 8.3 0.43
P6_C1 4429 250 GAS 1.1 0.06
P6_C2 4593 250 GAS 1.0 0.05
U_BELUGA 4687 1526 Gas/Water 6.3 0.33
UB_3 4847 1875 Gas 7.4 0.39
UB_4 4919 2008 Gas 7.9 0.41
UB_5B 5079 1329 Gas 5.0 0.26
UB_7 5154 1008 Gas 3.8 0.20
UB_8 5240 2135 Gas 7.8 0.41
M_BELUGA 5349 2147 Gas/Water 7.7 0.40
MB_3 5522 2343 Gas/Water 8.2 0.42
L_BELUGA 6118 2745 Gas/Water 8.6 0.45
LB_1B 6194 2269 Gas 7.0 0.37
LB_2A 6482 2602 Gas 7.7 0.40
LB_2C 6557 2943 Gas/Water 8.6 0.45
TD 6844 3000 Gas/Water 8.4 0.44
Offset Well Mud Densities
Well MW range Top (TVD) Bottom (TVD) Date
KBU 11-17X 9 - 9.2 1,587 5,464 2009
KBU 14-08 9 - 9.2 1,510 5,432 2008
KBU 41-18X 9 - 9.2 1,500 5,391 2008
KBU 24-7X 9 - 9.7 1,502 5,326 2006
KBU 32-08 9.3 - 9.8 1,446 5,401 2014
KBU 43-07Y 9.5 - 9.7 1,540 5,738 2014
Assumptions:
1. Fracture gradient at shoe (1680' TVD) is estimated at 17 ppg based on field test data.
2. Maximum planned mud density for the 6-3/4" hole section is 10.0 ppg.
3. Calculations assume "Unknown" reservoir contains 100% gas (worst case).
4. Calculations assume worst case event is 100% evacuation of wellbore to gas.
Fracture Pressure at 7-5/8" shoe considering a full column of gas from shoe to surface:
TVD Frac Grad
1680 ft X 0.884 psi/ft 1485 psi
1485(psi) - [0.1(psi/ft)*1680(ft)]= 1317 psi
MASP from pore pressure during production mode (Complete evacuation to gas)
3576 ft X 0.450 psi/ft 1609 psi Downhol e
1609(psi) - [0.1(psi/ft)* 3576 (ft)]= 1252 psi Surface
Summary:
1. MASP while drilling 6-3/4" production hole is governed by pore pressure from reservoir
with entire wellbore evacuated to gas
KU 44-01
Kenai Gas Field
6-3/4" Hole Section
Maximum Anticipated Surface Pressure Calculation
6657x .45= 2943 psi
Revised MASP 2285 psi from
Max downhole press of 2943 psi
(LB-2C)
2943 - .1(6657) =2285 psi
LB_2C 6557 2943 Gas/Water 8.6 0.45
formation. DLB
2943 psi
2285 psi
Pressure calculations by
Page 43 Version 0 May, 2020
KU 44-01
Drilling Procedure
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29.0 Spider Plot (NAD 27) (Governmental Sections)
KU 44-01
Page 44 Version 0 May, 2020
KU 44-01
Drilling Procedure
Rev 0
30.0 Surface Plat (NAD 27)
Page 45 Version 0 May, 2020
KU 44-01
Drilling Procedure
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Page 46 Version 0 May, 2020
KU 44-01
Drilling Procedure
Rev 0
31.0 Directional Plan (wp05)
!""#
$ %
$%&
-500
0
500
1000
1500
2000
2500
3000
3500
4000
4500
5000
5500
6000
6500
7000True Vertical Depth (1000 usft/in)-1000 -500 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500
Vertical Section at 285.94° (1000 usft/in)
Hogwarts Tgt1
20"
7 5/8" x 9-7/8"
5 1/2" X 6-3/4"
5 0 0
1 0 0 0
1 50 0
2 0 0 0
2 5 0 0
3 0 0 0
3 5 0 0
4 0 0 0
4 5 0 0
5 00 0
5 5 00
6 0 0 0
6 50 0
7 0 00
71 1 4 KU 44-01 wp05
Start Dir 3º/100' : 350' MD, 350'TVD
End Dir : 1091.33' MD, 1072.86' TVD
Start Dir 3º/100' : 1291.33' MD, 1257.98'TVD
End Dir : 1529.56' MD, 1477.95' TVD
Start Dir 3º/100' : 3364.63' MD, 3163.89'TVD
End Dir : 3808.23' MD, 3588' TVD
Total Depth : 7114.32' MD, 6843.87' TVD
P3_A4
P3_A8
P4_B1
P6_C1
P6_C2
U_BELUGA
M_BELUGA
L_BELUGA
Hilcorp Alaska, LLC
Calculation Method:Minimum Curvature
Error System:ISCWSA
Scan Method: Closest Approach 3D
Error Surface: Pedal Curve
Warning Method: Error Ratio
WELL DETAILS: Plan: KU 44-01
65.00
+N/-S +E/-W Northing Easting Latittude Longitude
0.00 0.00 2362473.32 271981.62 60° 27' 38.244 N 151° 15' 47.706 W
SURVEY PROGRAM
Date: 2020-04-28T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
18.00 1750.00 KU 44-01 wp05 (KU 44-01) 3_MWD+IFR1+MS+Sag
1750.00 7114.32 KU 44-01 wp05 (KU 44-01) 3_MWD+IFR1+MS+Sag
FORMATION TOP DETAILS
TVDPath TVDssPath MDPath Formation
3284.00 3201.00 3493.59 P3_A4
3592.00 3509.00 3812.29 P3_A8
3811.00 3728.00 4034.67 P4_B1
4494.00 4411.00 4728.20 P6_C1
4658.00 4575.00 4894.73 P6_C2
4752.00 4669.00 4990.18 U_BELUGA
5414.00 5331.00 5662.40 M_BELUGA
6183.00 6100.00 6443.26 L_BELUGA
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: KU 44-01, True North
Vertical (TVD) Reference:RKB As-%XLOW @ 83.00usft
Measured Depth Reference:RKB As-%XLOW @ 83.00usft
Calculation Method:Minimum Curvature
Project:Kenai Gas FieldSite:KGF 14-6 Pad
Well:Plan: KU 44-01
Wellbore:KU 44-01
Design:KU 44-01 wp05
Kenai Gas Field
KGF 14-6 Pad
Plan: KU 44-01
KU 44-01
KU 44-01 wp05
4.994
CASING DETAILS
TVD TVDSS MD Size Name
120.00 37.00 120.00 20 20"
1680.47 1597.47 1750.00 7-5/8 7 5/8" x 9-7/8"
6843.87 6760.87 7114.32 5-1/2 5 1/2" X 6-3/4"
SECTION DETAILS
Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation
1 18.00 0.00 0.00 18.00 0.00 0.00 0.00 0.00 0.00
2 350.00 0.00 0.00 350.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 350' MD, 350'TVD
3 1091.33 22.24 300.00 1072.86 71.04 -123.05 3.00 300.00 137.82 End Dir : 1091.33' MD, 1072.86' TVD
4 1291.33 22.24 300.00 1257.98 108.89 -188.60 0.00 0.00 211.25 Start Dir 3º/100' : 1291.33' MD, 1257.98'TVD
5 1529.56 23.26 281.64 1477.95 140.96 -273.82 3.00 -90.39 302.01 End Dir : 1529.56' MD, 1477.95' TVD
6 3364.63 23.26 281.64 3163.89 287.11 -983.56 0.00 0.00 1024.59 Start Dir 3º/100' : 3364.63' MD, 3163.89'TVD
7 3808.23 10.00 286.00 3588.00 315.52 -1106.92 3.00 176.71 1151.01 Hogwarts Tgt1 End Dir : 3808.23' MD, 3588' TVD
8 7114.32 10.00 286.00 6843.87 473.76 -1658.78 0.00 0.00 1725.11 Total Depth : 7114.32' MD, 6843.87' TVD
-400-267-1330133267400533667800South(-)/North(+) (200 usft/in)-1733 -1600 -1467 -1333 -1200 -1067 -933 -800 -667 -533 -400 -267 -133 0 133West(-)/East(+) (200 usft/in)Hogwarts Tgt120"7 5/8" x 9-7/8"5 1/2" X 6-3/4"2505007501000125015001750200022502500275030003250350037504000425045004750500052505500575060006250650067506844KU 44-01 wp05Start Dir 3º/100' : 350' MD, 350'TVDEnd Dir : 1091.33' MD, 1072.86' TVDStart Dir 3º/100' : 1291.33' MD, 1257.98'TVDEnd Dir : 1529.56' MD, 1477.95' TVDStart Dir 3º/100' : 3364.63' MD, 3163.89'TVDEnd Dir : 3808.23' MD, 3588' TVDTotal Depth : 7114.32' MD, 6843.87' TVDProject: Kenai Gas FieldSite: KGF 14-6 PadWell: Plan: KU 44-01Wellbore: KU 44-01Plan: KU 44-01 wp05WELL DETAILS: Plan: KU 44-0165.00+N/-S +E/-W NorthingEastingLatittude Longitude0.000.002362473.32 271981.62 60° 27' 38.244 N 151° 15' 47.706 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: KU 44-01, True NorthVertical (TVD) Reference:RKB As-%XLOW @ 83.00usftMeasured Depth Reference:RKB As-%XLOW @ 83.00usftCalculation Method:Minimum CurvatureCASING DETAILSTVD TVDSS MD Size Name120.00 37.00 120.00 20 20"1680.47 1597.47 1750.00 7-5/8 7 5/8" x 9-7/8"6843.87 6760.87 7114.32 5-1/2 5 1/2" X 6-3/4"
-600-400-2000200400600800100012001400South(-)/North(+) (300 usft/in)-2200 -2000 -1800 -1600 -1400 -1200 -1000 -800 -600 -400 -200 0 200 400 600West(-)/East(+) (300 usft/in)5001000150020002500KBU 31-07RD5001000150020002500KBU 31-07500100015002000KBU 32-065001000150020002 5 0 0
3 0 0 0
3 5 0 0
4000450050005500KU 11-07X50010001500200025003000KU 13-65001 0 0 015002000250030003500400 04500500055006000
6500
7000
750080008500900095009905KU 14X-65 0 010001500 20002500KBU 23-07500100015002000250030003500400045005000550060006500700075008000850090009500100001050011000115001200012500130001350014000145001500015042KU 14-65001000150020002500300035004000450050005341KU 14-06RD50010001500200025003000350040004364KU 21-750010001185KU 21-7PB0500100015002 0 0 0250030003500KBU 24-060500100015002 0 0 025003000350060006500700075007622KBU 24-06RD50010001500KU 42-12 wp06500100015002000KBU 22-065001000150020002500300035004000450050005 5 0 0
6 0 0 0650070007500KDU 15001000150020002500300035004000450050005 5 0 0
6 0 0 0650070007500KDU 1 PB15001000150020002500300035004000450050005500KBU 22-06Y5 0 0100 01500
2000
250030003500400045005000550060006500700075007569KBU 14-06Y5001000150020002500KBU 11-0750010001500200025003000350040004500KBU 23X-65001000150020002500300035004000450050005500600065006844KU 44-01 wp05Azimuths to True NorthMagnetic North: 14.71°Magnetic FieldStrength: 55306.8nTDip Angle: 73.38°Date: 6/28/2020Model: BGGM2019TMProject: Kenai Gas FieldSite: KGF 14-6 PadWell: Plan: KU 44-01Wellbore: KU 44-01Plan: KU 44-01 wp05-333 -167 0 167 333 500West(-)/East(+) (250 usft/in)-1670167South(-)/North(+) (250 usft/in)50015002000KBU 31-07RDKBU 31-075001000KBU 32-06500KU 11-07X1000KU 13-61500350055006000
65 00
70 00
KU 14X-610002000KBU 23-07KU 14-6KU 14-06RD20002 0 0 025003000KBU 24-06RDKU 42-12 wp061000KBU 22-065 5 0 0
6 0 0 0
6 5 0 0KDU 11500KBU 22-06Y1500300035002000KBU 23X-650010001500KU 44-01 wp05
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0.001.503.004.50Separation Factor0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000 6400 6800 7200Measured DepthKDU 1No-Go Zone - Stop DrillingCollision Avoidance Req.Collision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: KU 44-01 NAD 1927 (NADCON CONUS)Alaska Zone 0465.00+N/-S +E/-W Northing EastingLatittudeLongitude0.000.002362473.32 271981.62 60° 27' 38.244 N 151° 15' 47.706 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: KU 44-01, True NorthVertical (TVD) Reference:RKB As-%XLOW @ 83.00usftMeasured Depth Reference:RKB As-%XLOW @ 83.00usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2020-04-28T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool18.00 1750.00 KU 44-01 wp05 (KU 44-01) 3_MWD+IFR1+MS+Sag1750.00 7114.32 KU 44-01 wp05 (KU 44-01) 3_MWD+IFR1+MS+Sag0.0030.0060.0090.00120.00150.00Centre to Centre Separation (50.00 usft/in)0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000 6400 6800 7200Measured DepthKU 14X-6KBU 23-07KU 21-7KU 21-7PBKDU 1KDU 1 PB1KBU 22-06YKBU 14-06YKBU 11-07GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference18.00 To 7114.32Project: Kenai Gas FieldSite: KGF 14-6 PadWell: Plan: KU 44-01Wellbore: KU 44-01Plan: KU 44-01 wp05Ladder / S.F. PlotsCASING DETAILSTVD TVDSS MD Size Name120.00 37.00 120.00 20 20"1680.47 1597.47 1750.00 7-5/8 7 5/8" x 9-7/8"6843.87 6760.87 7114.32 5-1/2 5 1/2" X 6-3/4"
Revised 2/2015
TRANSMITTAL LETTER CHECKLIST
WELL NAME: ______________________________________
PTD: _____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD: ____________________________ POOL: ______________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
No. _____________, API No. 50-_______________________.
Production should continue to be reported as a function of the original
API number stated above.
Pilot Hole
In accordance with 20 AAC 25.005(f), all records, data and logs
acquired for the pilot hole must be clearly differentiated in both
well name (_______________________PH) and API number
(50-_____________________) from records, data and logs acquired for
well (name on permit).
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce/inject is contingent upon issuance of
a conservation order approving a spacing exception.
(_____________________________) as Operator assumes the liability
of any protest to the spacing exception that may occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in no greater
than 30' sample intervals from below the permafrost or from where
samples are first caught and 10' sample intervals through target zones.
Non-
Conventional
Well
Please note the following special condition of this permit:
Production or production testing of coal bed methane is not allowed for
well ( ) until after ( )
has designed and implemented a water well testing program to provide
baseline data on water quality and quantity.
(________________________) must contact the AOGCC to obtain
advance approval of such water well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by (_______________________________) in the attached application,
the following well logs are also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for well logs run must be submitted to the AOGCC
within 90 days after completion, suspension or abandonment of this
well.
KU 44-01
220-046
X
X
X
Kenai Gas Beluga/Upper Tyonek Gas
WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:KENAI UNIT 44-01Initial Class/TypeDEV / PENDGeoArea820Unit51120On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2200460KENAI, BELUGA/UP TYONEK GAS - 448571NA1 Permit fee attachedYes2 Lease number appropriateYes3 Unique well name and numberYes4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18 Conductor string providedYes 7 5/8" set at 1750 ft19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes 5 1/2" long string will have swell packer and cement in linerlap.21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes BTC calcs are suppled and with in industry standards.23 Casing designs adequate for C, T, B & permafrostYes Rig has steel pits. Waste will be hauled to KGF disposal wells.24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes No issues with collision26 Adequate wellbore separation proposedNA Diverter waived.27 If diverter required, does it meet regulationsYes Max form pressure at 2943 psi (8.6PPG EMW) Drilling with 9-10 ppg mud28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MASP = 2285 psi will test BOPE to 3500 psi30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes Nearby wells did not encounter H2S gas. Measures not required.35 Permit can be issued w/o hydrogen sulfide measuresYes36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprDLBDate5/15/2020ApprGLSDate5/21/2020ApprDLBDate5/15/2020AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateCement packer completion… MIT-IA and CBL are required post rig. GlsJLC 5/22/2020dts 5/22/2020
