Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAbout221-0711. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing
2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address:Stratigraphic Service
6. API Number:
7. If perforating: 8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number): 10. Field:
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
7,960 N/A
Casing Collapse
Structural
Conductor
Surface 670psi
Intermediate 2,090psi
Production 3,270psi
Liner 7,500psi
Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft):
12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations: OIL WINJ WDSPL Suspended
16. Verbal Approval: Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name: Eric Dickerman
Contact Email:Eric.Dickerman@hilcorp.com
Contact Phone:(907) 564-4061
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
North Cook Inlet Tertiary System Gas Same
5,615 7,240 5,005 120psi 7,250 & 7,645
Subsequent Form Required:
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi): Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
Tubing Size:
PRESENT WELL CONDITION SUMMARY
AOGCC USE ONLY
8,430psi
Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft):
Operations Manager
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0017589 / ADL0037831
221-071
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20016-01-00
Hilcorp Alaska, LLC
N Cook Inlet Unit A-01A
Length Size
Proposed Pools:
L-80
TVD Burst
2,935
4,360psi
MD
3,580psi
1,640psi
388'
614'
2,395'
388'
614'
2,863'7"
30"
16"
388'
10-3/4"2,544'
614'
Perforation Depth MD (ft):
2,544'
6,633 - 7,112
3,135'
4-1/2"
4,622 - 4,915
Other: CTCO, N2 Operations
N/A
1/23/2026
7,960'5,039'
4-1/2"
5,615'
Baker ZXP & Halliburton XXO SSSVLN 2,921 (MD) 2,684 (TVD) & 442 (MD) 442 (TVD)
3,135'
No
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
Digitally signed by Dan
Marlowe (1267)
DN: cn=Dan Marlowe (1267)
Date: 2026.01.08 14:42:33 -
09'00'
Dan Marlowe
(1267)
326-009
By Grace Christianson at 8:12 am, Jan 09, 2026
DSR-1/16/26TS 1/12/26MGR09JAN2025
*BOPE test to 3000 psi. 48 hour notice to AOGCC for opportunity to witness.
* Safety valve system performance test within 5 days of production . 48 hour notice to
AOGCC.
10-404
01/20/26
Fill Clean Out
Well: North Cook Inlet Unit A-01A
Well Name:NCIU A-01A API Number:50-883-20016-01
Current Status:Online, Gas Well Leg:Leg #3 (SE corner)
Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:221-071
First Call Engineer:Eric Dickerman (907) 564-4061
Second Call Engineer:Dan Marlowe (907) 283-1329
Maximum Expected BHP:610 psi at 4,906 TVD 0.13 psi/ft 11/10/2021 SBHP survey
Max. Potential Surface Pressure: 120 psi MPSP -0.1 psi/ft gas grad. to surface
Field/Pool: North Cook Inlet Unit, Tertiary System Gas Pool
Brief Well Summary:
NCIU A-01A was completed in November 2021 in the Beluga Formation. A pressure and temperature survey
from February 2022 indicated a fluid level at 7,040 (above the bottom two sets of perforations) and tagged fill
at 7,090 (above the bottom set of perforations). Infill Beluga perforations were added in March 2022.
Another pressure and temperature survey was performed in July 2023 with a tag depth of 7,072 and notes of
the toolstring returning to surface packed with fine sand. Based on current production rates and the history of
fill, a cleanout is proposed.
Objective:
Coiled tubing fill cleanout.
Wellbore information:
Well is completed with a wireline retrievable subsurface safety valve.
North Cook Inlet Unit, Tertiary System Gas Pool top = Top of Sterling sands, at 3,719 md / 3,253 tvd.
North Cook Inlet Unit, Tertiary System Gas Pool Bottom = Base of Beluga sands (below TD).
Fill Clean Out
Well: North Cook Inlet Unit A-01A
Slickline:
1. MIRU Slickline. PT PCE 250 psi low / 2,500 psi high.
2. Pull SSSV from 442.
3. Drift and tag TD.
4. RDMO.
Coiled Tubing Cleanout:
5. MIRU Fox Offshore Coiled Tubing Unit #9 and pressure control equipment.
6. Pressure test BOP and PCE to 250 psi low / 3,000 psi high.
a. Provide AOGCC with 48hr witness notification for BOP test.
7. MU cleanout BHA. Dry tag top of fill, then clean out to top of fish ± 7,177.
b. Working fluid will be 6% KCl (8.6 ppg).
c. Take returns to surface from the coiled tubing backside.
d. Add foam and nitrogen as necessary to carry solids to surface.
8. RDMO CTU.
Slickline:
9. MIRU Slickline. PT PCE 250 psi low / 2,500 psi high.
10. Drift and tag TD.
11. Perform Pressure/Temperature survey.
12. Set SSSV at 442.
13. RDMO.
Operations:
14. Test SSSV within 5 days of production.
a. Provide AOGCC with 48hr witness notification.
Attachments:
1. Current Wellbore Schematic (no change proposed)
2. CT BOP Drawing
3. Nitrogen procedure
Updated By JLL 01/29/24
SCHEMATIC
Tyonek Platform
Well: NCI A-01A
PTD: 221-071
API: 50-883-20016-01-00
Completed: 10/08/21
Jewelry Detail
Item Depth
MD
Depth
TVD ID OD Description
1 442 442 3.813 5.000
Halliburton XXO SSSVLN 3.813 X profile (Isolation
sleeve pulled.WL-SSSV set 10/02/22)
2 2,8812,662 3.813 5.450 Tripoint X Nipple 3.813 X Profile
3 2,924 2,686 3.960 5.760 No Go locator / Seal Assembly 9.5 seal
4 2,921 2,684 4.170 6.050 Baker 4-1/2 x 7 ZXP Liner top packer
5 2,944 2,704 5.250 7.000 Liner Setting Sleeve
6 7,250 5,013 - 4.50
CIBP (10 of cement dumped on top 7,240 MD)
(11/10/21)
7 7,645 5,334 - 4.50 CIBP (11/07/21)
PBTD: 7,240' MD TD: 7,960 MD
30
RKB: MSL = 126.6
1
6
10-3/4
4-1/2
7
7
16
Beluga A
2
Top of
Window @
3,135
Beluga B
Beluga D-E
Beluga C
Beluga G
3X
4
5
Casing Detail
SIZE WT GRADE CONN MIN ID TOP BTM (MD)
30 29.0 Surf 388
16 65 H-40 15.25 Surf 614
10-3/4 45.5 & 51 J-55 BTC 9.85 Surf 2,544
7 23 J-55 BTC 6.366 Surf
3,135
(TOW)
4-1/2 12.6 L-80 VamTop 3.958 2,921 7,960
Tubing Detail
4-1/2 12.6 L-80 IBTM 3.958 Surf 2,935
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Size Status
Bel A 6,633 6,653 4,622 4,632 40 3/3/22
2-1/2 6 SPF Open
Bel B 6,682 6,693 4,648 4,654 11 11/12/21
2-1/2 6 SPF Open
Bel B 6,722 6,742 4,670 4,681 20 11/12/21
2-1/2 6 SPF Open
Bel B 6,744 6,753 4,682 4,687 ± 3/3/22
2-1/2 6 SPF Open
Bel B 6,772 6,785 4,697 4,705 13 11/12/21
2-1/2 6 SPF Open
Bel B 6,801 6,815 4,714 4,722 14 11/12/21
2-1/2 6 SPF Open
Bel B 6,801 6,815 4,714 4,722 ±4 3/3/22
2-1/2 6 SPF Open
Bel B 6,858 6,864 4,748 4,751 ± 3/3/22
2-1/2 6 SPF Open
Bel B 6,876 6,892 4,758 4,768 16 11/12/21
2-1/2 6 SPF Open
Bel B 6,899 6,905 4,773 4,777 ± 3/2/22
2-1/2 6 SPF Open
Bel C 7,030 7,039 4,858 4,865 9 11/12/21
2-1/2 6 SPF Open
Bel C 7,054 7,074 4,875 4,888 20 11/10/21
2-1/2 6 SPF Open
Bel C 7,100 7,112 4,906 4,915 12 11/10/21 2-1/2 6 SPF Open
GAS LIFT MANDRELS
STA MD TVD ID Type Port Valve Psc Date
1 1,542 1,529 3.833 BK-2 (SMOR-1A Slim hole)20 DUMMY 10/8/2021
2 2,8312,623 3.833 BK-2 (SMOR-1A Slim hole)20 ORIFICE 10/16/2021
FISH DETAILS
7,177' 24' OAL Braided line brush BHA plus ~5' of wire left at top fish 1/14/2021
Updated By JLL 01/29/2024
SCHEMATIC
Tyonek Platform
Well: NCI A-01A
PTD: 221-071
API: 50-883-20016-01-00
Completed: 10/08/21
OPEN HOLE / CEMENT DETAIL
16"22 Hole: Pumped 825sxs of 11.0ppg class G lead followed by 125sxs class G tail cement. Lost returns.
performed 1 top job down to 120. Pumped 200sxs class G to bring ToC to surface.
10-3/4"15 hole: Pumped 740sxs (300bbls) 11.0ppg lead followed by 125sxs (24bbls) 15.5ppg class G tail. Good
returns throughout.Volumetric ToC assuming 30% washout = 250
7
9-5/8 hole in A-01 parentbore: Casing sat at 7449. Primary job pumped 546sxs (131bbls) 13.2ppg class G
cement. Cement seen back to surface when circulating through DV collar before 2nd stage pumped.
2nd stage through DV collar at 5,094. Pumped 552sxs (122bbls) 15.4ppg class G. Full circulation throughout.
Volumetric ToC calculated assuming 30% washout = 2880. 9/22/92 USIT shows great cement up to 4,120, and
patchy cement above to 2,552. Free pipe starts at 2552
4-1/26-1/8 hole: Pumped 123bbls 15.3ppg cement. Saw 1bbl cement circulated off the liner top.10/26/21 CBL
shows great cement up to 4450, and okay cement up to Liner Top packer at 2950.
ISOLATED PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Size Status
Bel D 7,267 7,277 5,027 5,034 10 11/8/21
2-1/2 6 SPF Isolated
Bel E 7,288 7,295 5,042 5,048 7 11/8/21
2-1/2 6 SPF Isolated
Bel E 7,301 7,316 5,052 5,064 15 11/8/21
2-1/2 6 SPF Isolated
Bel E 7,327 7,347 5,072 5,087 20 11/7/21
2-1/2 6 SPF Isolated
Bel E 7,357 7,366 5,095 5,102 9 11/7/21
2-1/2 6 SPF Isolated
Bel E 7,393 7,405 5,123 5,132 12 11/7/21
2-1/2 6 SPF Isolated
Bel G 7,665 7,675 5,349 5,358 10 11/7/21
2-1/2 6 SPF Isolated
STANDARD WELL PROCEDURE
NITROGEN OPERATIONS
09/23/2016 FINAL v-offshore Page 1 of 1
1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport.
2.) Notify Facility Operator of upcoming Nitrogen operations.
3.) Perform Pre-Job Safety Meeting. Review operating procedures and appropriate Safety Data
Sheets (formerly MSDS).
4.) Document hazards and mitigation measures and confirm flow paths. Include review on
asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate
routing of flowlines, adequate venting and atmospheric monitoring.
5.) Spot Pumping Unit and Nitrogen Tank. Confirm liquid N2 volumes in transport.
6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip
checks.
7.) Place signs and placards warning of high pressure and nitrogen operations at areas where
Nitrogen may accumulate or be released.
8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing
and casing pressures.
9.) Place pressure gauges upstream and downstream of any check valves.
10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct.
11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to
detect LEL/H2S/CO2/O2 levels. Ensure supplier has a working and calibrated detector as well
that measures O2 levels.
12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential
Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank)
to 1,500 psi. Perform visual inspection for any leaks.
13.) Bleed off test pressure and prepare for pumping nitrogen.
14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns
are to be routed to the returns tank.
15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and
bleed down lines between well and Nitrogen Pumping Unit.
16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has
accumulated begin rig down of lines from the Nitrogen Pumping Unit.
17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned
and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport.
18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Tank.
DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-883-20016-01-00Well Name/No. N COOK INLET UNIT A-01ACompletion Status1-GASCompletion Date11/7/2021Permit to Drill2210710Operator Hilcorp Alaska, LLCMD7960TVD5616Current Status1-GAS8/31/2022UICNoWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:LWD/MWD Logs, CBLNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF10/6/20213130 7960 Electronic Data Set, Filename: NCIU A-01A LWD Final.las35758EDDigital DataDF10/6/2021 Electronic File: NCIU A-01A LWD Final MD.cgm35758EDDigital DataDF10/6/2021 Electronic File: NCIU A-01A LWD Final TVD.cgm35758EDDigital DataDF10/6/2021 Electronic File: NCI A-01A - Definitive Survey Report.pdf35758EDDigital DataDF10/6/2021 Electronic File: NCI A-01A - DSR.txt35758EDDigital DataDF10/6/2021 Electronic File: NCI A-01A - GIS.txt35758EDDigital DataDF10/6/2021 Electronic File: NCI A-01A DSR Actual - Plan.pdf35758EDDigital DataDF10/6/2021 Electronic File: NCI A-01A DSR Actual - VSec.pdf35758EDDigital DataDF10/6/2021 Electronic File: NCI A-01A Final Surveys.xlsx35758EDDigital DataDF10/6/2021 Electronic File: NCIU A-01A LWD Final MD.emf35758EDDigital DataDF10/6/2021 Electronic File: NCIU A-01A LWD Final TVD.emf35758EDDigital DataDF10/6/2021 Electronic File: NCIU A-01A LWD Final MD.pdf35758EDDigital DataDF10/6/2021 Electronic File: NCIU A-01A LWD Final TVD.pdf35758EDDigital DataDF10/6/2021 Electronic File: NCIU A-01A LWD Final MD.tif35758EDDigital DataDF10/6/2021 Electronic File: NCIU A-01A LWD Final TVD.tif35758EDDigital Data0 0 2210710 N COOK INLET UNIT A-01A LOG HEADERS35758LogLog Header ScansDF11/22/20212067 1844 Electronic Data Set, Filename: NCI_A-01A_CBL_26-Oct-2021_(3550).las35964EDDigital DataDF11/22/2021 Electronic File: NCI_A-01A_CBL_26-Oct-2021_(3550).pdf35964EDDigital DataWednesday, August 31, 2022AOGCCPage 1 of 3NCIU A-01A LWDFinal.las
DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-883-20016-01-00Well Name/No. N COOK INLET UNIT A-01ACompletion Status1-GASCompletion Date11/7/2021Permit to Drill2210710Operator Hilcorp Alaska, LLCMD7960TVD5616Current Status1-GAS8/31/2022UICNoWell Cores/Samples Information:ReceivedStart Stop CommentsTotalBoxesSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYMud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date: 11/7/2021Release Date: 9/10/20210 0 2210710 N COOK INLET UNIT A-01A LOG HEADERS35964LogLog Header ScansDF12/29/20216 7698 Electronic Data Set, Filename: NCI_A-01A_Perf_07-Nov-2021_(3558).las36132EDDigital DataDF12/29/2021 Electronic File: NCI_A-01A_Perf_07-Nov-2021_(3558).pdf36132EDDigital Data0 0 2210710 N COOK INLET UNIT A-01A LOG HEADERS36132LogLog Header ScansDF1/24/20226 7698 Electronic Data Set, Filename: NCI_A-01A_PressureTemp_07-Nov-2021_(3558).las36288EDDigital DataDF1/24/2022 Electronic File: NCI_A-01A_PressureTemp_07-Nov-2021_(3558).pdf36288EDDigital Data0 0 2210710 N COOK INLET UNIT A-01A LOG HEADERS36288LogLog Header ScansDF3/15/20226994 6585 Electronic Data Set, Filename: NCI_A-01A_Perf_03-Mar-2022_(3676).las36416EDDigital DataDF3/15/2022 Electronic File: NCI_A-01A_Perf_03-Mar-2022_(3676).pdf36416EDDigital DataWednesday, August 31, 2022AOGCCPage 2 of 3
DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-883-20016-01-00Well Name/No. N COOK INLET UNIT A-01ACompletion Status1-GASCompletion Date11/7/2021Permit to Drill2210710Operator Hilcorp Alaska, LLCMD7960TVD5616Current Status1-GAS8/31/2022UICNoComments:Compliance Reviewed By:Date:Wednesday, August 31, 2022AOGCCPage 3 of 3M.Guhl8/31/2022
1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown
Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program
Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: ______________________
Development Exploratory
Stratigraphic Service 6. API Number:
7. Property Designation (Lease Number):8. Well Name and Number:
9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s):
11. Present Well Condition Summary:
Total Depth measured 7,960 feet 7250 & 7645 feet
true vertical 5,615 feet N/A feet
Effective Depth measured 7,240 feet 2,921 feet
true vertical 5,005 feet 2,684 feet
Perforation depth Measured depth See Schematic feet
True Vertical depth See Schematic feet
Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6# / L-80 2,935' MD 2,705' TVD
XXO SSSSVLN; 442' MD 442' TVD
Packers and SSSV (type, measured and true vertical depth)Baker ZXP Liner Top Pkr 2,921' MD 2,684' TVD
12. Stimulation or cement squeeze summary:
Intervals treated (measured):
Treatment descriptions including volumes used and final pressure:N/A
13.
Prior to well operation:
Subsequent to operation:
15. Well Class after work:
Daily Report of Well Operations Exploratory Development Service Stratigraphic
Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL
Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG
Sundry Number or N/A if C.O. Exempt:
Contact Name:
Contact Email:
Authorized Title:Contact Phone:
322-076
Sr Pet Eng:
7,500psi
Sr Pet Geo:Sr Res Eng:
Authorized Name and Digital
Signature with Date:
WINJ WAG
1,907
Water-BblOil-Bbl
17. I hereby certify that the foregoing is true and correct to the best of my knowledge.
0
59
8,430psi
Chad Helgeson, Operations Engineer
chelgeson@hilcorp.com
907-777-8405Dan Marlowe, Operations Manager, 907-283-1329
measured
true vertical
Packer
Representative Daily Average Production or Injection Data
Casing Pressure Tubing Pressure
0 112,600
0 56
14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283)
0
Gas-Mcf
MD
388'
614'
11
Structural
TVD
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
221-071
50-883-20016--01-00
N/A
5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work:
ADL0017589|ADL0037831
North Cook Inlet Unit / Tertiary System Gas Pool
Hilcorp Alaska LLC
3800 Centerpoint Dr, Suite 1400
Anchorage, AK 99503
3. Address:
N COOK INLET UNIT A-01A
measuredPlugs
Junk measured
N/A
Length
388'
614'
Size
Conductor
Surface
Intermediate
30"
16"
10-3/4"
Production
Liner
2,544'
3,135'
5,039'
Casing
388'
614'
2,395'
2,863'
4-1/2"
2,544'
3,135'
7,960'5,615'
7"
2,090psi
3,270psi
1,640psi
3,580psi
4,360psi
Burst Collapse
670psi
t
Fra
O
O
6. A
PG
,
R
Form 10-404 Revised 10/2021 Submit Within 30 days of Operations
By Meredith Guhl at 2:36 pm, Mar 29, 2022
Digitally signed by Dan Marlowe
(1267)
DN: cn=Dan Marlowe (1267),
ou=Users
Date: 2022.03.29 12:14:19 -08'00'
Dan Marlowe
(1267)
Rig Start Date End Date
3/2/22 3/12/22
03/12/2022 - Saturday
AOGCC witnessed SSSV test after perforating. Passed.
03/06/2022 - Sunday
Slickline set SSSV. Tested closure on valve. RD unit and move to A-2. SVS performance test is scheduled for 3/11.
Hilcorp Alaska, LLC
Well Operations Summary
API Number Well Permit NumberWell Name
NCIU A-01A 50-833-20016-01-00 221-071
Daily Operations:
03/02/2022 - Wednesday
03/03/2022 - Thursday
AKEL crew assembles and attends morning safety meeting. Obtain permits and hold PJSM. Fire up eline equipment
and rig up. Perforating with 2.5" HC Razor guns loaded at 6 SPF with 11.5g charges. Arm and RIH with 6' gun
assembly. Correlate to open hole log and send to town for correction. On depth. Perforate Beluga B Lower 1 from
6858-6864'. Initial: 1735 mcf @ 58 psi. 5 min: 1725 mcf @ 58 psi. 10 min: 1720 mcf @ 58 psi. 15 min: 1725 mcf @ 58
psi. POOH. Lay down tools, all shots fired and gun was dry and covered with greasy sand. Arm and RIH with 14' gun
assembly. Correlate to open hole log and send to town for correction. On depth. Perforate Beluga B Mid 2 from 6801-
6815'. Initial: 1735 mcf @ 58 psi. 5 min: 1760 mcf @ 58 psi. 10 min: 1760 mcf @ 58 psi. 15 min: 1775 mcf @ 58 psi.
POOH. Lay down tools, all shots fired and gun was dry, covered with viscous sand. Arm and RIH with 9' gun assembly.
Correlate to open hole log and send to town for correction. On depth. Platform ESDs and well is shut in. Unable to
make it down to spot guns. Platform comes back online and well begins to flow again. Still unable to make it past
6100', work tools at various speeds. POOH. Lay down tools and add additional 5' weight bar. RIH and correlate to
open hole log, send to town for correction. On depth. Perforate Beluga B Upper 3 from 6744-6753'. Initial: 1890 mcf
@ 61 psi. 5 min: 1820 mcf @ 61 psi. 10 min: 1890 mcf @ 61 psi. 15 min: 1885 mcf @ 61 psi. POOH. Lay down tools,
all shots fired and gun was dry, covered with viscous sand. Arm and RIH with 20' gun assembly. Correlate to open
hole log and send to town for correction. On depth. Perforated Beluga A Lower from 6633-6653'. Initial: 1835 mcf @
59 psi. 5 min: 3045 mcf @ 63 psi. 10 min: 3215 mcf @ 65 psi. 15 min: 3220 mcf @ 65 psi. POOH. Lay down tools, all
shots fired and gun was dry, covered with viscous sand. Arm and RIH with 20' gun assembly. Unable to work tools
past 4000', POOH Lay down and inspect tools, covered in viscous sand. Rig down from and secure A-01A. Spot
equipment on leg 2 for well A-11. SDFN.
AKEL crew arrives at facility and obtains permit, PJSM. Replace battery on eline unit and build new rope socket. Spot
eline equipment on leg 3 side and rig up. Pressure test lubricator to 250 psi low and 2500 psi high. Perforating with
2.5" Razor guns loaded at 6 SPF with 11.5g charges. Arm and RIH with 6' gun. Tag high at 6690' and pick up clean. Pull
up hole and attempt to re-tag. Tag at 5400' and pick up clean. Keep working tools at higher speeds and eventually
make it down to 6540' but unable to progress further. POOH and lay down tools, gun is wet with greasy sand at tool
connections. Add two weight bars to increase string weight from 200# to 320#. RIH and punch through obstruction at
6540'. Correlate to open hole log and send to town for correction. Add one foot per reservoir engineer. Perforated
Beluga B Lower 3 from 6899-6905'. Initial :1730 mcf @ 59 psi. 5 min: 1770 mcf @ 59 psi. 10 min: 1770 mcf @ 59 psi.
15 min: 1755 mcf @ 59 psi. POOH and lay down gun. All shots fired and gun was wet with greasy sand. Secure well
and SDFN.
Updated By DMA 03-28-22
SCHEMATIC
Tyonek Platform
Well: NCI A-01A
PTD: 221-071
API: 50-883-20016-01-00
Completed: 10/08/21
Jewelry Detail
Item Depth
MD
Depth
TVD ID OD Description
1 442’442’3.813 5.000 Halliburton XXO SSSVLN 3.813 X profile
2 1,542’1,529’3.833 6.030 GLM #1 BK-2 Latch Profile (SMOR-1A slim hole ) 1'' Valve
3 2,831’2,623’3.833 6.030 GLM #2 BK-2 Latch Profile (SMOR-1A slim hole ) 1'' Valve
4 2,881’2,662’ 3.813 5.450 Tripoint X Nipple 3.813 X Profile
5 2,924’ 2,686’ 3.960 5.760 No Go locator / Seal Assembly 9.5’ seal
6 2,921’2,684’4.170 6.050 Baker 4-1/2” x 7” ZXP Liner top packer
7 2,944’2,704’5.250 7.000 Liner Setting Sleeve
8 7,250’5,013’-4.50 CIBP (10’ of cement dumped on top – 7,240’ MD)
9 7,645’ 5,334’ - 4.50 CIBP
Casing Detail
SIZE WT GRADE CONN MIN ID TOP BTM (MD)
30”29.0 Surf 388’
16”65 H-40 15.25 Surf 614’
10-3/4” 45.5 & 51 J-55 BTC 9.85 Surf 2,544’
7” 23 J-55 BTC 6.366 Surf
3,135’
(TOW)
4-1/2” 12.6 L-80 VamTop 3.958 2,921’ 7,960’
Tubing Detail
4-1/2”12.6 L-80 IBTM 3.958 Surf 2,935’
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Size Status
Bel A 6,633’6,653’4,622’4,632’40’3/3/22 2-1/2” 6 SPF Opem
Bel B 6,682’6,693’4,648’4,654’11’11/12/21 2-1/2” 6 SPF Open
Bel B 6,722’6,742’4,670’4,681’20’11/12/21 2-1/2” 6 SPF Open
Bel B 6,744’6,753’4,682’4,687’±’3/3/22 2-1/2” 6 SPF Open
Bel B 6,772’6,785’4,697’4,705’13’11/12/21 2-1/2” 6 SPF Open
Bel B 6,801’6,815’4,714’4,722’14’11/12/21 2-1/2” 6 SPF Open
Bel B 6,801’6,815’4,714’4,722’±4’3/3/22 2-1/2” 6 SPF Open
Bel B 6,858’6,864’4,748’4,751’±’3/3/22 2-1/2” 6 SPF Open
Bel B 6,876’6,892’4,758’4,768’16’11/12/21 2-1/2” 6 SPF Open
Bel B 6,899’6,905’4,773’4,777’±’3/2/22 2-1/2” 6 SPF Open
Bel C 7,030’7,039’4,858’4,865’9’11/12/21 2-1/2” 6 SPF Open
Bel C 7,054’7,074’4,875’4,888’20’11/10/21 2-1/2” 6 SPF Open
Bel C 7,100’7,112’4,906’4,915’12’11/10/21 2-1/2” 6 SPF Open
Bel D 7,267’7,277’5,027’5,034’10’11/8/21 2-1/2” 6 SPF Isolated
Bel E 7,288’7,295’5,042’5,048’7’11/8/21 2-1/2” 6 SPF Isolated
Bel E 7,301’7,316’5,052’5,064’15’11/8/21 2-1/2” 6 SPF Isolated
Bel E 7,327’7,347’5,072’5,087’20’11/7/21 2-1/2” 6 SPF Isolated
Bel E 7,357’7,366’5,095’5,102’9’11/7/21 2-1/2” 6 SPF Isolated
Bel E 7,393’7,405’5,123’5,132’12’11/7/21 2-1/2” 6 SPF Isolated
Bel G 7,665’7,675’5,349’5,358’10’11/7/21 2-1/2” 6 SPF Isolated
Kaitlyn Barcelona Hilcorp North Slope, LLC
GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: 907 564-4389
E-mail: kaitlyn.barcelona@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal
Received By: Date:
DATE: 03/15/2022
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
NCI A-01A (PTD 221-071)
Perf 03/03/2022
Please include current contact information if different from above.
221-071
T36416
Meredith Guhl Digitally signed by Meredith Guhl
Date: 2022.03.15 14:26:05 -08'00'
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Digitally signed by
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Date: 2022.02.24
12:59:29 -09'00'
RBDMS SJC 022822
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Current Bottom Hole Pressure: 901 psi @ 4,769’ TVD Based on original SITP of A-01A on 10/2021
Maximum Expected BHP: 901 psi @ 4,769’ TVD Based on original SITP of A-01A on 10/2021
Maximum Potential Surface Pressure: ~424 psi @ 4,769’ TVD Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4)
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Kaitlyn Barcelona Hilcorp North Slope, LLC
GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: 907 777-8337
E-mail: kaitlyn.barcelona@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal
Received By: Date:
DATE: 12/28/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
NCI A-01A (PTD 221-071)
Pressure Temperature 11/07/2021
Please include current contact information if different from above.
Received By:
01/20/2022
37'
(6HW
By Abby Bell at 10:27 am, Jan 20, 2022
Kaitlyn Barcelona Hilcorp North Slope, LLC
GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: 907 777-8337
E-mail: kaitlyn.barcelona@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal
Received By: Date:
DATE: 12/28/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
NCI A-01A (PTD 221-071)
Perf 11/07/2021
Please include current contact information if different from above.
37'
(6HW
Received By:
12/29/2021
By Abby Bell at 8:58 am, Dec 29, 2021
CAUTION: This email originated from outside the State of Alaska mail system. Do not
click links or open attachments unless you recognize the sender and know the content
is safe.
From:Cody Dinger
To:Guhl, Meredith D (OGC)
Subject:RE: [EXTERNAL] NCIU A-01A, PTD 221-071, formation at TD
Date:Thursday, December 9, 2021 1:36:42 PM
Hi Meredith,
NCIU was TD’d in the Beluga H.
Thank you!
Cody Dinger
Hilcorp Alaska, LLC
Drilling Tech
907-777-8389
From: Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>
Sent: Wednesday, December 8, 2021 2:39 PM
To: Cody Dinger <cdinger@hilcorp.com>
Subject: [EXTERNAL] NCIU A-01A, PTD 221-071, formation at TD
Hi Cody,
Just a quick check to see if NCIU A-01A ended in a lettered Beluga bed, or just general Beluga
formation.
Thanks!
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.
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the
individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby
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While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the
onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility
is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
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Completion Date
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1 bbl cement interface at surface, possible no cmt -bjm
Kaitlyn Barcelona Hilcorp North Slope, LLC
GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: 907 777-8337
E-mail: kaitlyn.barcelona@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal
Received By: Date:
DATE: 11/19/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
NCI A-01A (PTD 221-071)
CBL 10/26/2021
Please include current contact information if different from above.
37'
(6HW
Received By:
11/22/2021
By Abby Bell at 1:06 pm, Nov 22, 2021
From:McLellan, Bryan J (CED)
To:Todd Sidoti - (C)
Subject:RE: NCIU A-01A (PTD 221-071) Plugback
Date:Monday, November 8, 2021 9:52:00 AM
Todd,
As discussed, the proposed change to Sundry 321-471 in your email below is approved. You do not
need to submit another sundry for this change. I will attach this note to the wellfile for the record.
Regards
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
333 W 7th Ave
Anchorage, AK 99501
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Todd Sidoti - (C) <Todd.Sidoti@hilcorp.com>
Sent: Sunday, November 7, 2021 7:08 PM
To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov>
Subject: NCIU A-01A (PTD 221-071) Plugback
Hi Bryan,
We shot water in A-01A in the Beluga G from 7665-7675’. In the Sundry we stated that unproductive
zones may be isolated with a CIBP and cement before continuing uphole. In this case since we are
not crossing into a different pool we would like to simply set a CIBP without cement for isolation. Per
our phone conversation we are moving in that direction.
Thanks
Todd
Todd Sidoti | ASC Field Engineer | Hilcorp Alaska | 907-632-4113
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the
individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please
immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the
onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility
is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
From:McLellan, Bryan J (CED)
To:Karson Kozub - (C)
Subject:RE: NCIU A-01A (PTD 221-071) Sundry 321-471 CBL Log
Date:Wednesday, October 27, 2021 1:37:00 PM
Cement looks good Karson. You have approval to proceed with the perfs pursuant to Sundry 321-
471.
Regards
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
333 W 7th Ave
Anchorage, AK 99501
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Karson Kozub - (C) <kkozub@hilcorp.com>
Sent: Wednesday, October 27, 2021 12:50 PM
To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov>
Cc: Juanita Lovett <jlovett@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com>; Todd Sidoti - (C)
<Todd.Sidoti@hilcorp.com>
Subject: NCIU A-01A (PTD 221-071) Sundry 321-471 CBL Log
Hello Bryan,
Attached is the CBL and liner cement report for NCIU A-01A. Top of cement is at 4450’, the top of
the liner is at 2920’. Our top shot for perforating is 6,633’.
Cement is sufficient above our zones we will be perforating the next couple of days.
We do have a liner top packer in A-01A. We have a Baker ZXP Liner Top Packer.
We got a passing MITIA on 9/17. IA was tested to 3,050psi and charted for 30 min. Witness was
waived for the MITIA on 10/6, attached is the email waiving witness.
Also attached is the approved sundry and an updated schematic.
Regards,
Karson KozubMobile: +1 (907) 570-1801kkozub@hilcorp.com
STATE OF ALASKA
Reviewed By: ^-
OIL AND GAS CONSERVATION COMMISSION P,I. Supry 11151z47-1
BOPE Test Report for: N COOK INLET UNIT A-01 A Comm
Contractor/Rig No.: Spartan 151 PTD#: 2210710' DATE: 10/6/2021 - Inspector Austin McLeod Insp Source
Operator: Hilcorp Alaska, LLC Operator Rep: Hauck/Demoski Rig Rep: Lafleur/Boyd Inspector
Type Operation: DRILL Sundry No: Test Pressures: Inspection No: bopSAM211012075852
Rams: Annular: Valves: MASP:
Type Test: BIWKLY 250/3000 250/2500 � 250/3000 2814 - Related Insp No:
TEST DATA
MISC. INSPECTIONS:
MUD SYSTEM:
ACCUMULATOR SYSTEM:
CHOKE MANIFOLD:
P/F
P/F
Visual
Alarm
Time/Pressure P/F
Location Gen.:
P
Trip Tank
P :
P
System Pressure 3000 -
P
Housekeeping:
P
Pit Level Indicators
P
P
Pressure After Closure 2050
P "
PTD On Location
P
Flow Indicator
P
P
200 PSI Attained 28
P
Standing Order Posted
P--
Meth Gas Detector
P
P
Full Pressure Attained 120
P "
Well Sign
P-
H2S Gas Detector
P
P
Blind Switch Covers: All stations'
P
Drl. Rig
- P
MS Mise
NA
_NA
Nitgn. Bottles (avg): 16(a-),2200 -
P "
Hazard Sec.
P J
P
ACC Misc 0
NA
Misc
NA
0
NA_
FLOOR SAFTY VALVES:
BOP STACK:
CHOKE MANIFOLD:
Quantity
P/F
Quantity
Size
P/F
Quantity
P/F
Upper Kelly
1
P "
Stripper
0
NA
No. Valves 13
P -
Lower Kelly
-- 1
P -
Annular Preventer
1
13-5/8
P
Manual Chokes 1
P -
Ball Type
_ 2
P _
#1 Rams
1
-4-1/2
P
Hydraulic Chokes 2
P "
Inside BOP
--1-
P
#2 Rams
1
Blinds
P
CH Misc 0
NA
FSV Misc
0
NA
#3 Rams
1
2-7/8x5-1/2
P
#4 Rams
0
NA_
#5 Rams
0
_ _
NA
INSIDE REEL VALVES:
#6 Rams
0
NA
(Valid for Coil Rigs Only)
Choke Ln. Valves
1_
3-1/16
P
Quantity
P/F
HCR Valves
_ 2 "
3-1/16
P -
Inside Reel Valves 0 -
NA
Kill Line Valves
3"
3-1/16
P
Check Valve
0
NA
BOP Misc
0
NA
Number of Failures: 0 Test Results
Remarks: 4-1/2 joint. Extension was given until liner was run.
Test Time 5.5
David Douglas Hilcorp Alaska, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal or fax to 907 564-4422.
Received By: Date:
Date: 10/06/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
NCIU A-01A (PTD 221-071)
FINAL LWD FORMATION EVALUATION LOGS (09/23/2021 to 10/04/2021)
x ROP, PCG, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
SFTP Transfer - Data Folders:
Please include current contact information if different from above.
37'
(6HW
eceived By:
10/07/2021
By Abby Bell at 5:05 pm, Oct 06, 2021
1
Guhl, Meredith D (CED)
From:McLellan, Bryan J (CED)
Sent:Wednesday, September 29, 2021 8:38 AM
To:Karson Kozub - (C)
Subject:RE: NCIU A-01A Completion Sundry (321-471) PTD 221-071
Karson,
Yes, you are correct, my mistake.
A 10‐407 should be filed for the work completed under Sundry 321‐471.
Thanks
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
333 W 7th Ave
Anchorage, AK 99501
Bryan.mclellan@alaska.gov
+1 (907) 250‐9193
From: Karson Kozub ‐ (C) <kkozub@hilcorp.com>
Sent: Wednesday, September 29, 2021 8:13 AM
To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov>
Subject: NCIU A‐01A Completion Sundry (321‐471) PTD 221‐071
Good Morning Bryan,
Thank you for approving the A‐01A completion sundry quickly.
I noticed a few things and wanted to make sure our notes aligned.
In the comments it states Rig 169, we will be using the Spartan 151.
Subsequent form required: it says 10‐404, we usually submit a 10‐407 on the re‐drills.
Attached is a copy of the approved sundry.
Regards,
Karson Kozub
2
Mobile: +1 (907) 570-1801
kkozub@hilcorp.com
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed
above, then promptly and permanently delete this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission,
opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and
the recipient should carry out such virus and other checks as it considers appropriate.
1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing
2.Operator Name:4.Current Well Class:5.Permit to Drill Number:
Exploratory Development
3.Address: 3800 Centerpoint Drive, Suite 1400 Stratigraphic Service 6.API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Will planned perforations require a spacing exception?Yes No
9. Property Designation (Lease Number):10. Field/Pool(s):
North Cook Inlet Unit / Tertiary System Gas Pool
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD):
±9,208 (proposed)N/A
Casing Collapse
Structural
Conductor
Surface 670 psi
Intermediate 2,090 psi
Production 3,270 psi
Liner 7,500 psi
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14.Estimated Date for 15. Well Status after proposed work:
Commencing Operations:OIL WINJ WDSPL Suspended
16.Verbal Approval:Date:GAS WAG GSTOR SPLUG
Commission Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:kkozub@hilcorp.com
Contact Phone: (907) 570-1801
Date:
Conditions of approval: Notify Commission so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other:
Post Initial Injection MIT Req'd? Yes No
Spacing Exception Required? Yes No Subsequent Form Required:
APPROVED BY
Approved by: COMMISSIONER THE COMMISSION Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
±2,875 (proposed)7"
±9,208 (proposed) ±6,827 (proposed)
Authorized Title:
17. I hereby certify that the foregoing is true and the procedure approved herein will not
be deviated from without prior written approval.
10/1/2021
N/A
Daniel E. Marlowe
N/A
N/A
±3,150 (proposed)
N/A
Tubing Grade:Tubing MD (ft):
N/A
Perforation Depth TVD (ft):
8,430 psi
Tubing Size:
±6,208 (proposed)
10-3/4"2,544'
614'
±3,150 (proposed)
Perforation Depth MD (ft):
2,544'
4-1/2"
388'
614'
2,395'
388'
614'
30"
16"
388'
N/A
TVD Burst
N/A
4,360 psi
MD
1,640 psi
221-071
50-883-20016-01-00Anchorage, AK 99503
Hilcorp Alaska, LLC
N Cook Inlet Unit A-01A
N/A±6,827 (proposed) ±9,088 (proposed)±6,711 (proposed)2,814 psi
COMMISSION USE ONLY
Authorized Name:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0017589 / ADL0037831
Other: G/L Completion /
N2 Operations
Authorized Signature:
Operations Manager
Karson Kozub
CO 68A
PRESENT WELL CONDITION SUMMARY
Length Size
3,580 psi
Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval.
By Meredith Guhl at 3:01 pm, Sep 13, 2021
321-471
Digitally signed by Dan Marlowe
(1267)
DN: cn=Dan Marlowe (1267),
ou=Users
Date: 2021.09.13 14:23:27 -08'00'
Dan Marlowe
(1267)
CT BOP test to 3500 psi.
DLB 09/13/2021
X
BJM 9/22/21
Approval to perforate is contingent on success of 4-1/2" liner job and cement bond log. Liner cement report and CBL to AOGCC for review prior
to perforating.
X
DSR-9/13/21
Rig 169 BOP test to 3000 psi. Annular test to 2500 psi.
10-404
Allow 48 hrs notice for AOGCC to witness MIT-T and MIT-IA.
X
dts 9/23/2021 JLC 9/23/2021
Jeremy Price Digitally signed by Jeremy Price
Date: 2021.09.23 15:13:06 -08'00'
RBDMS HEW 9/24/2021
Well Work Prognosis
Well Name:NCIU A-01A API Number:50-883-20016-01-00
Current Status:Producer Leg:Leg #3 SE Corner
Estimated Start Date:10/01/2021 Rig:Spartan 151/Coil/EL
Reg. Approval Req’d?403 Date Reg. Approval Rec’vd:
Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:221-071
First Call Engineer:Karson Kozub (907) 570-1801 (M)
Second Call Engineer:Katherine O’Connor (907) 777-8376 (O) (214) 684-7400 (M)
Current Bottom Hole Pressure: 3,484 psi @ 6,700’ TVD 0.520psi/ft (10.0 ppg) Beluga U sands expected
Maximum Expected BHP:3,484 psi @ 6,700’ TVD 0.520psi/ft (10.0 ppg) Beluga U sands expected
Maximum Potential Surface Pressure: 2,814 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4)
Brief Well Summary
NCIU A-01A is a Beluga producer that will be completed with gas lift. This new well was redrilled from
the current NCIU A-01, a shut-in plugged producer. This work will run completion, clean out, N2 blow
dry and perforate. Timing will be based on timeliness of getting the well drilled.
Waiver Request:
Hilcorp requests a waiver to 20AAC25.265(c)(1). We request to locate the SSV on the tree wing allowing the SSV to
remain in the production stream while providing concurrent wellbore access.
Procedure:
1. ***Take over operations from the Drilling Sidetrack Program PTD 221-071***
2. Test BOP’s every 14 days continued from last test date from PTD 221-071
a. Test to 250psi low/3,000psi high / 2,500 psi annular. (Note: Notify AOGCC 48 hours in advance of
test to allow them to witness test).
3. Completion fluid will be KCL. BOP’s will be closed as needed to circulate the well.
4. After liner cement has reached compressive strength of 500psi+
a. Test liner lap to 2,180psi (50% of burst of 7”) for 30 min charted
5. RIH with 4-1/2” tubing, SSSV nipple, X-nipple, and Gas Lift completion (see schematic for specific depths)
a. When completion is just above the sealbore circulate out drilling mud with KCL (note below
sealbore will still be drilling mud)
b. Space out and land completion per proposed schematic
c. Pressure test tubing, liner, and sealbore to 2,900psi for 30 min charted
i. (Note: Notify AOGCC 48 hours in advance of test to allow them to witness test)
d. Pressure test inner annulus to 2,900 psi for 30 min charted (GLM’s Dummied off)
i. (Note: Notify AOGCC 48 hours in advance of test to allow them to witness test)
6. Set BPV, ND BOPE, NU tree and test same
7. RDMO Spartan 151
8. RU SL pressure test 250psi low/3,000psi high
a. Pull SSSV
b. Change out GLV’s to live valves
c. Perform drift run to TD
9. RU E-line pressure test 250psi low/3,000psi high
a. run gamma/ccl/cbl.
10. R/U Coil tubing unit
11. Perform BOPE pressure test 250psi low/3,500psi high (Note: Notify AOGCC 48hrs in advance to allow
them to witness)
12. RIH and clean out to PBTD ±9,088’
13. Blow well dry with Nitrogen to production header or non-enclosed open top tank.
a. POOH, R/D Coil tubing.
14. RU E-line pressure test 250psi low/3,500psi high
a. perforate per program. Note: Deepest zone will be perforated first. This zone will be tested.
Variance approved. bjm
Review CBL log data and 4-1/2" liner cement report with AOGCC before perforating. bjm
Monitor returns for 1:1 while displacing to underbalanced fluid. bjm
Completion fluid will be KCL.
Well Work Prognosis
b.Contingency: If zone is unproductive, a CIBP w/cement will be placed above the open zone. E-line
will perforate the next shallowest zone. This will be repeated until a productive zone is achieved.
15. Turn over to production.
16. Schedule SVS testing with AOGCC as per regulations
Attachments:
1. Well Schematic Current
2. Well Schematic Proposed
3. Wellhead Schematic
4. BOP Drawing – Spartan 151
5. BOP Drawing – Coil Tubing
6. Fluid Flow Diagram –Spartan 151
7. Choke Diagram – Spartan 151
8. Fluid Flow Diagram –Coil Tubing
9. Standard Well Procedure – Nitrogen operations
10. Sundry Revision Change Form
_____________________________________________________________________________________
Updated By: JLL 09-02-21
PROPOSED
North Cook Inlet Unit
Well: NCI A-01
PTD: 168-072
API: 50-883-20016-00
PBTD: 7,156’ TD: 8,279’
30”
RKB: 116’
7”
CI-A
CI-B
3
4
5
6
7
8
9
10
11
12
13
16”
10-3/4”1
2
Fill 4,348’ on
7/13/11
14
15
16
17
Temperature
tool stuck in
fill @ 4,351’
CI-8.0
CI -9.0
CI -10.0
CI -11.0
C-5
D-1
D-3
D-4
E-8
E-9
G-1
G-2
H-4
M-3
I-7
J-2.1
J-3
CI-3.0 -6.0
CI -6.2
CI-1.0
CI-2.0
M-2
18
19
Tight spot
@ 4,002’
Sterl StrayCIBP @ 4,290’
w/ 5’ Cement
Tbg Cut
+/-3,980’
Cement Retainer
+/- 3,950’
TOC 2,570’
CBL 1992
X
XN
CASING DETAIL
Size Wt Grade Conn ID Top Btm
30” 29.000 Surf 388’
16” 65 H-40 15.250 Surf 614’
10-3/4” 51 J-55 9.850 Surf 2,544’
7” 23 J-55 Butt 6.366 Surf ±3,150’ (KOP)
TUBING DETAIL
PERFORATION DETAIL
Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
CI - Stray 3 4,057’ 4,067’ 3,607’ 3,616’ 10’ 02/12/20 Isolated
CI-A 4,085' 4,095' 3,630' 3,639' 10' 2/1/1969 Isolated
CI-B 4,116' 4,140' 3,656' 3,676' 24' 2/1/1969 Isolated
CI-1.0 4,351' 4,391' 3,854' 3,887' 40' 2/1/1969 Isolated
CI-2.0 4,402' 4,482' 3,896' 3,963' 80' 2/1/1969 Isolated
CI-3.0 4,516' 4,525' 3,991' 3,999' 9' 2/1/1969 Isolated
CI-4.0 4,552' 4,588' 4,021' 4,051' 36' 2/1/1969 Isolated
CI-5.0 4,624' 4,674' 4,081' 4,122' 50' 2/1/1969 Isolated
CI-6.0 4,708' 4,738' 4,150' 4,174' 30' 2/1/1969 Isolated
CI-6.2 4,760' 4,784' 4,192' 4,212' 24' 2/1/1969 Isolated
CI-8.0 4,874' 4,886' 4,284' 4,294' 12' 2/1/1969 Isolated
CI-9.0 4,960' 4,972' 4,354' 4,363' 12' 2/1/1969 Isolated
CI-10.0 5,000' 5,012' 4,386' 4,395' 12' 2/1/1969 Isolated
CI-11.0 5,044' 5,080' 4,421' 4,449' 36' 2/1/1969 Isolated
C-5 5,590' 5,598' 4,852' 4,858' 8' 2/1/1969 Isolated
D-1 5,604' 5,616' 4,863' 4,872' 12' 2/1/1969 Isolated
D-3 5,663' 5,692' 4,909' 4,932' 29' 2/1/1969 Isolated
D-4 5,708' 5,715' 4,945' 4,950' 10' 2/1/1969 Isolated
E-8 5,874' 5,888' 5,076' 5,088' 14' 2/1/1969 Isolated
E-9 5,892' 5,904' 5,162' 5,100' 12' 2/1/1969 Isolated
G-1 6,076' 6,084' 5,237' 5,243' 8' 2/1/1969 Isolated
G-2 6,098' 6,116' 5,254' 5,268' 18' 2/1/1969 Isolated
H-4 6,271' 6,278' 5,391' 5,397' 7' 2/1/1969 Isolated
M-3 6,508' 6,814' 5,578' 5,820' 306' 2/1/1969 Isolated
I-7 6,509' 6,514' 5,579' 5,583' 5' 2/1/1969 Isolated
J-2.1 6,578' 6,584' 5,634' 5,638' 6' 2/1/1969 Isolated
J-3 6,589' 6,602' 5,642' 5,653' 13' 2/1/1969 Isolated
M-2 6,790' 6,798' 5,801' 5,808' 8' 2/1/1969 Isolated
JEWELRY DETAIL
No Depth
(MD)
Depth
(TVD)ID OD Item
1 ±3,150’ ±2,873’ Whipstock
2 ±3,950’ ±3,520’ Cement Retainer
±3,980’ ±3,544’ Tubing Cut
3 4,000’ 3,561’ 3.880 Otis VCR Retrievable Packer
4,290’ 3,802’ CIBP w/ 5’ cement (TOC 4,283’)
4 4,299’ 3,810’ 4.000 Otis TWR Permanent Packer
5 4,494’ 3,973’ 3.810 Otis XA Sliding Sleeve (Opens up) – Opened 10/1996
6 4,502’ 3,980’ 4.000 Otis TWR Permanent Packer
7 4,704’ 4,147’ 3.810 Otis XD Sliding Sleeve (Opens down) Closed
4,753’ 4,187’ 3.500 XO 4.5 x 3.5, 9.3# J-55 EUE8rd
8 4,764’ 4,196’ 4.000 Otis BWH Permanent Packer
9 4,882’ 4,291’ 4.000 Otis BWH Permanent Packer
10 4,924’ 4,325’ 2.750 Otis XA Sliding Sleeve (Opens up) – Opened 7/1996
11 5,023’ 4,404’ 4.000 Otis BWH Permanent Packer
12 5,056’
4,430’ 2.750 Otis Sliding Sleeve XO (Opens down) Closed – Set Isolated
Sleeve
13 5,076’ 4,446’ 4.000 Otis BWH Permanent Packer
14 5,088’ 4,456’ 2.313 Otis Sliding Sleeve XO (Opens down) Closed
15 6,895’ 5,884’ 2.205 Otis X Nipple
16 6,960’ 5,936’ 2.205 HES XN Nipple
17 6,971’ 5,945’ 2.441 Wireline Re-Entry Guide
18 7,156’ 6,091’ Baker Retrievable Bridge Plug
19 7,405’ 6,289’ SLB Bobcat Retrievable Bridge Plug
Updated By: JLL 09/10/21
PROPOSED
North Cook Inlet Unit
Tyonek Platform
Well: NCI A-01A
PTD: 221-071
API: 50-883-20016-01-00
Completed: Future
Jewelry Detail
Item Depth
MD
Depth
TVD ID OD Description
1 ±370’ ±370’ SSSV
2 ±1,505’ ±1,500’ GLM
3 ±2,940’ ±2,709 GLM
4 ±2,970’ ±2,732’ X Nipple
5 ±3,000’ ±2,756’ Baker Liner Hanger / Seal Bore
PBTD:±9,088’ TD:±9,208’
30”
RKB: MSL = 126.6’
2
1
10-3/4”
4-1/2”
7”
16”
Beluga
A-U
4
3
5
X
Casing Detail
SIZE WT GRADE CONN MIN ID TOP BTM (MD)
30” 29.0 Surf 388’
16” 65 H-40 15.25 Surf 614’
10-3/4” 45.5 & 51 J-55 BTC 9.85 Surf 2,544’
7” 23 J-55 BTC 6.366 Surf ±3,150’
4-1/2” 12.6 L-80 VamTop 3.833 ±3,000’ ±9,208’
Tubing Detail
4-1/2” Surf ±3,000’
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
Beluga A-U ±6,300’ ±9,208’ ±4,459’ ±6,827’ ±2,908’ Future Proposed
Proposed Wellhead 09/10/2021
NCIU A-01A
Unihead, OCT type 3, 16 3/4 5M
BX-161 hub top X 16'’ LTC casing
bottom, w/ 2- 2 LPO on lower
section, 2- 2 1/16 5M SSO on middle
section, 2- 2 1/16 5M SSO on upper
section , IP internal lockpin assy
28'’
Starting head, OCT,
30 ½ 1M X 28'’ BW,
w/ 2- 4'’ 1M EFO
Tubing hanger, Cactus-EN-
CCL, 11 x 4 ½ EUE 8rd lift and
susp, w/ 4'’ type H BPV, 2- ¼
cont control line ports
Tyonek Platform
A-01A
28 X 16 X 10 3/4 X 7 x 4 1/2
16'’
10 ¾’’
7'’
4 ½’’
Tubing head attachment,
Cactus,
11 5M FE X 16 3/4 5M BX-161 hub
bottom
Valve, Master, CIW-FLS,
4 1/16 5M FE, HWO,
EE trim
BHTA, Otis, 4 1/16 5M FE x
7.5 Otis quick union top
Adapter, Cactus-EN-CCL,
11 5M stdd x 4 1/16 5M, w/
2- 1'’ npt control line exits
Valve, Master, CIW-FLS,
4 1/16 5M FE, HWO,
EE trim
Valve, Swab, CIW-FLS,
4 1/16 5M FE, HWO,
EE trim
1. BOP Schematic
2. Choke Manifold Schematic
Coiled Tubing BOP
SWAB VALVE
MASTER VALVE
HilcorpMonopod Rig 56Flow Diagram Fluids Pumped Fluids ReturnedValve Open Valve ClosedGate Valve Ball ValveButterfly Valve Lo Torq ValveAutomatic Choke Manual ChokePressure Gauge Knife ValveChoke LineP PIT SYSTEM SucƟon SHAKER
SHAKER CHOKE MANIFOLDGAS BUSTER Panic LineC12 C13 C15 C14 C16 A B C4 C5 C6 C7 C2 C10 C9 C11 C8 C3 P C1 C
STANDARD WELL PROCEDURE
NITROGEN OPERATIONS
09/23/2016 FINAL v-offshore Page 1 of 1
1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport.
2.) Notify Facility Operator of upcoming Nitrogen operations.
3.) Perform Pre-Job Safety Meeting. Review operating procedures and appropriate Safety Data
Sheets (formerly MSDS).
4.) Document hazards and mitigation measures and confirm flow paths. Include review on
asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate
routing of flowlines, adequate venting and atmospheric monitoring.
5.) Spot Pumping Unit and Nitrogen Tank. Confirm liquid N2 volumes in transport.
6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip
checks.
7.) Place signs and placards warning of high pressure and nitrogen operations at areas where
Nitrogen may accumulate or be released.
8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing
and casing pressures.
9.) Place pressure gauges upstream and downstream of any check valves.
10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct.
11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to
detect LEL/H2S/CO2/O2 levels. Ensure supplier has a working and calibrated detector as well
that measures O2 levels.
12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential
Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank)
to 1,500 psi. Perform visual inspection for any leaks.
13.) Bleed off test pressure and prepare for pumping nitrogen.
14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns
are to be routed to the returns tank.
15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and
bleed down lines between well and Nitrogen Pumping Unit.
16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has
accumulated begin rig down of lines from the Nitrogen Pumping Unit.
17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned
and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport.
18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Tank.
Hilcorp Alaska, LLCHilcorp Alaska, LLCChanges to Approved Rig Work Over Sundry ProcedureSubject: Changes to Approved Sundry Procedure for Well: N Cook Inlet Unit A-01A (PTD 221-071)Sundry #: XXX-XXXAny modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC by the rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change.Sec Page Date Procedure Change New 403Required?Y / NHAKPreparedBy(Initials)HAKApprovedBy(Initials)AOGCC WrittenApproval Received(Person and Date)Approval:Asset Team Operations Manager DatePrepared:First Call Operations Engineer Date
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: North Cook Inlet Field, Tertiary System Gas Pool, NCIU A-01A
Hilcorp Alaska, LLC
Permit to Drill Number: 221-071
Surface Location: 1252' FNL, 1083' FWL, Sec 6, T11N, R9W, SM, AK
Bottomhole Location: 1968' FNL, 1172' FEL, Sec 36, T12N, R10W, SM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Jeremy M. Price
Chair
DATED this ___ day of September, 2021.
Jeremy
Price
Digitally signed by
Jeremy Price
Date: 2021.09.10
14:55:54 -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: 9,208' TVD: 6,827'
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): 126.6' 15. Distance to Nearest Well Open
Surface: x-332102 y- 2586726 Zone-4 N/A to Same Pool: 1700' to A-16
16. Deviated wells:Kickoff depth: 3,150 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 62 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
6-1/8" 4-1/2" 12.6# L-80 Vamtop 6,208' 3,000' 2,633' 9,208' 6,827'
19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations)
Junk (measured):
4,351'
TVD
614'
2,393'
6,324'
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
NCIU A-01A
North Cook Inlet Unit
Tertiary System Gas Pool
Cement Quantity, c.f. or sacks
Commission Use Only
See cover letter for other
requirements.
3,067' - 5,808'
7,449'7"
Total Depth MD (ft):Total Depth TVD (ft):
022224484
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
2814
2190' FSL, 661' FEL, Sec 36, T12N, R10W, SM, AK
1968' FNL, 1172' FEL, Sec 36, T12N, R10W, SM, AK
N/A
3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503
Hilcorp Alaska, LLC
1252' FNL, 1083' FWL, Sec 6, T11N, R9W, SM, AK ADL 17589 / ADL 37831
18. Casing Program:Top - Setting Depth - BottomSpecifications
3484
GL / BF Elevation above MSL (ft):
Cement Volume MDSize
Plugs (measured):
(including stage data)
882 ft3
4,283'3,796'
Effect. Depth MD (ft):Effect. Depth TVD (ft):
8,279'7,012'
LengthCasing
See Schematic
4,057' - 6,798'
Conductor/Structural 16"614'
Authorized Title:
Authorized Signature:
Authorized Name:
Production
Liner
7,449'
Intermediate
1150 sx 614'
2,544'10-3/4"865 sx
Drilling Manager
Monty Myers
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):Perforation Depth MD (ft):
2,544'
1098 sx
9/16/2021
2455' to nearest unit boundary
Sean Mclaughlin
sean.mclaughlin@hilcorp.com
907-223-6784
8328
s N
ype of W
L
l R
L
1b
S
Class:
os N s No
s N o
D s
s
sD
84
o
well is p
G
S
S
20
S S
S
s No s No
S
G
y E
S
s No
s
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
9.2.2021
By Samantha Carlisle at 2:11 pm, Sep 02, 2021
Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp Alaska, LLC, ou=Technical
Services - AK Drilling,
email=mmyers@hilcorp.com
Reason: I am approving this document
Date: 2021.09.02 12:29:32 -08'00'
Monty M
Myers
Send FIT data to AOGCC for review before drilling sidetrack.
SFD 9/2/2021BJM 9/9/21
DSR-9/2/21
50-883-20016-01-00221-071
BOP test to 3000 psi, Annular test to 2500 psi.
dts 9/9/2021 JLC 9/10/2021
9/10/21
Jeremy Price Digitally signed by Jeremy Price
Date: 2021.09.10 14:56:13 -08'00'
A-01A PTD information
Tyonek
Sean McLaughlin
Revision 0
September 01, 2021
NCI A-01A
PTD
Rev 0
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. Current Wellbore Schematic ......................................................................................................... 6
7. Pre-Sidetrack Schematic ............................................................................................................... 7
8. Planned Wellbore Schematic ......................................................................................................... 8
9. Drilling Summary .......................................................................................................................... 9
10. Mandatory Regulatory Compliance / Notifications .................................................................... 10
11. R/U and Preparatory Work......................................................................................................... 12
12. Tubing Cut and Circ out well ...................................................................................................... 13
13. BOP N/U and Test ....................................................................................................................... 13
14. Mud Program and Density Selection Criteria ............................................................................ 14
15. Plug Perforations /Set Whipstock / Mill Window ....................................................................... 15
16. Drill 6-1/8” Hole Section .............................................................................................................. 16
17. Run 4-1/2” Production Liner ....................................................................................................... 18
18. Cement 4-1/2” Production Liner ................................................................................................. 20
19. Wellbore Clean Up & Displacement ........................................................................................... 23
20. Run Completion Assembly .......................................................................................................... 23
21. RD ................................................................................................................................................ 23
22. BOP Schematic ............................................................................................................................ 24
23. Wellhead Schematic (current) ..................................................................................................... 25
24. Anticipated Drilling Hazards ...................................................................................................... 26
25. Jack up position ........................................................................................................................... 27
26. FIT Procedure.............................................................................................................................. 28
27. Choke Manifold Schematic ......................................................................................................... 29
28. Casing Design Information .......................................................................................................... 31
29. 6-1/8” Hole Section MASP ........................................................................................................... 32
30. Plot (NAD 27) (Governmental Sections) ..................................................................................... 33
31. Slot Diagram ................................................................................................................................ 34
32. Directional Program (wp03) - Attached separately ................................................................... 35
Page 2 Revision 0 September 01, 2021
NCI A-01A
PTD
Rev 0
1. Well Summary
Well NCI A-01A
Directional plan wp03
Pad & Old Well Designation Sidetrack of existing well A-01 (PTD#168-072)
Planned Completion Type 4-1/2” 12.6# Liner, 4-1/2” Tubing GL Comp
Target Reservoir(s) Beluga B-U
Kick off point 3,150’ MD / 2,749’ TVD
Planned Well TD, MD / TVD 9,208’ MD / 6,827’ TVD
PBTD, MD 9088’ MD
Surface Location (Governmental) 1252' FNL, 1083' FWL, Sec 6, T11N, R9W, SM, AK
Surface Location (NAD 27) X=332102.26, Y=2586726.40
Surface Location (NAD 83)
Top of Productive Horizon
(Governmental) 2190' FSL, 661' FEL, Sec 36, T12N, R10W, SM, AK
TPH Location (NAD 27) X=330409.00, Y=2590194.00
TPH Location (NAD 83)
BHL (Governmental) 1968' FNL, 1172' FEL, Sec 36, T12N, R10W, SM, AK
BHL (NAD 27) X=329914.00, Y=2591322.47
BHL (NAD 83)
AFE Number
AFE Days
AFE Drilling Amount
Work String 4.5” 16.6# S-135 CDS40
RKB – AMSL 126.63’
MSL to ML 101’
Page 3 Revision 0 September 01, 2021
NCI A-01A
PTD
Rev 0
2. Management of Change Information
Date: September 01, 2021
Subject: Changes to Approved Permit to Drill for NCI A-01A
File #: NCI A-01A Drilling Program
Any modifications to NCI A-01A Drilling Program 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 Approved By
Approval:
Drilling Manager Date
Prepared:
Engineer Date
Page 4 Revision 0 September 01, 2021
NCI A-01A
PTD
Rev 0
3. Tubular Program
Hole
Section
OD (in) Wt (#/ft) Coupl
OD
ID
(in)
Drift
(in)
Grade Conn Top Bottom
6-1/8” 4-1/2” 12.6 4.937” 3.913” 3.833 L-80 VAMTOP 3,050’ 9,208
** 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)
6-1/8” 4-1/2” 3.826 2.6875” 5.25” 16.6 S-135 CDS40 16,176 10,959 468k
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5. Internal Reporting Requirements
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 when aggregating end of well
reports.
2. Afternoon Updates
x Submit a short operations update each work day to mmyers@hilcorp.com,
cdinger@hilcorp.com, sean.mclaughlin@hilcorp.com
3. EHS Incident Reporting
x Notify EHS field coordinator.
i. Tyler Pruitt: C: (907) 513-9903
x Spills:
i. Keegan Fleming: C:907-350-9439
ii. Monty Myers: O: 907-777-8431 C: 907-538-1168
iii. Sean Mclaughlin
x 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
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6. Current Wellbore Schematic
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7. Pre-Sidetrack Schematic
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8. Planned Wellbore Schematic
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9. Drilling Summary
The parent well perforations will be plugged as part of the decomplete (Sundry to be submitted separately).
The 4-1/2” tubing will be cut and pulled prior to running a 7” retainer to plug perforations and isolate the
casing. At 3150’ MD the parent wellbore will be sidetracked and new wellbore drilled to 9208’. A 4-1/2”
12.6# L-80 VamTop prod liner will be run, cemented, and perforated based on data obtained while drilling the
interval.
The well will be completed with a 4-1/2” gas lift tie-back completion.
Operations are expected to commence approximately September 16th, 2021.
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.
A separate sundry notice will be submitted for the decomplete, perforation plugging, and running the
completion assembly.
General sequence of operations pertaining to this drilling operation:
Sundry Operations:
1. Spartan 151 will MIRU over A-01
2. S/L: Pull SSSV, Tag fill
3. Eline: Cut 4-1/2” tubing at 3990’
4. Swap well to 9.5 ppg fluid
5. Set BPV, ND tree, NU BOPE, and test to 3000 psi. (MASP 2814 psi)
a. Leaking tubing hanger body seals, rolling test of adapter may be required.
6. Pull BPV, Pull 4-1/2” tubing
7. Set 7” cement retainer at 3950’
8. Squeeze 15 bbl of cement into perforations, lay in 75’ of cement above retainer
9. WOC. Make bit and scraper run. Tag cement with 10 klbs.
10. Test casing to 3000 psi.
Drilling Operations
1. Set 7” whipstock at 3150’ and 0R.
2. Mill window with 20’ of new formation.
3. Perform FIT to 14.7 ppg EMW
4. PU 6-1/8” motor drilling assembly and TIH to window.
5. Drill 6-1/8” production hole to 9208 MD, performing short trips as needed
6. POOH w/ directional tools.
7. RIH w/ 4-1/2” liner. Set liner and cement. Circ wellbore clean.
8. Perform casing test to 2180 psi.
9. Run 4-1/2” completion. (Covered under separate sundry)
10. Land hanger and test.
11. ND BOPE, NU tree and test void
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10. 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 initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment
will be to 250/3000 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.
o The highest reservoir pressure expected is 3484 psi in the Beluga U sand (6700' TVD). MASP is
2814 psi with 0.1psi/ft gas in the wellbore.
o A casing test to 3000 psi is planned as part of the decomplete
x Minimum required Rated Working Pressure (RWP) the BOPE and wellhead must meet or exceed:
3000 psi. The wellhead is rated to 5000 psi.
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 Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
x Ensure to provide AOGCC 48 hrs notice prior to testing.
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Summary of BOP Equipment and Test Requirements
Hole Section Equipment Test Pressure (psi)
6-1/8”
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 spud.
x 48 hours notice prior to testing BOPs.
x 48 hours notice prior to casing running & cement operations (N/A for sidetrack)
x Any other notifications required in APD.
Additional requirements may be stipulated on APD.
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
Mel 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)
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11. R/U and Preparatory Work
1. Separate sundries will be submitted that will include the following:
x Pull tubing, Plugging perforations
x Running Completion
2. Mix WBM mud for 6-1/8” hole section.
3. 6” liners installed in mud pump #1 and pump #2. (PZ-10’s)
x Gardner Denver PZ-10’s Pumps are rated at 4932 psi (98%) with 6” liners and can deliver 422
gpm at 115 spm.
x Pump range for drilling will be 150-300 gpm. This can be achieved with one or both pumps.
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12. Tubing Cut and Circ out well
1. RU Slickline pressure test lubricator to 250psi low/1,500psi high
x Pull SSSV
x RIH and tag fill ±4,044’
2. RU E-line pressure test lubricator to 250psi low/1,500psi high
x Cut tubing at ±3,990’
3. Circulate well with 9.5 ppg mud
x Monitor well to ensure static
4. Install BPV
13. BOP N/U and Test
1. N/D Tree
2. N/U 16-3/4” 5M Unihead adapter x 13-5/8” 5M
3. N/U 13-5/8” x 5M BOP as follows (top down):
x 13-5/8” x 5M Shaffer annular BOP.
x 13-5/8” Shaffer Type “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” Shaffer Type “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.
4. Perform a rolling test 3000 psi test of lower adapter flange.
x Ensure visual confirmation of no leaks.
5. Set test plug.
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 TWC. Confirm the correct valves are opened!!!
x Test VBRs on 4.5” test joint.
Sections 12.0 - 15.5 are part of a separate Plug for
redrill sundry #321-444 - bjm
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x Ensure gas monitors are calibrated and tested in conjunction w/ BOPE.
6. Pull Test plug.
7. Pull BPV
x Monitor well to ensure static
14. Mud Program and Density Selection Criteria
1. 6-1/8” 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
3,150’-
Beluga H
9.5-9.7 40-53 6-15 13-24 8.5-9.5 11.0
Beluga H –
TD
10.3-10.5 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 for 9.5 – 10.0 ppg
0.1 ppb
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2. 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.
3. 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.
15. Plug Perforations /Set Whipstock / Mill Window
x BOP Test interval for this section is 14 days - To comply with state regulations, record mud weights in and out
and ensure BOPE function test are recorded in WellEZ before the 7 day deadline.
Operation Steps:
1. Pull hanger and LD 4-1/2” tubing.
x 4-1/2” EUE 8rd lift thread
x 4-1/2” EUE 8rd tubing
2. Set wear bushing in wellhead. Ensure ID of wear bushing > 6-1/8”.
3. Set 7” cement retainer at 3950’
4. Squeeze 15 bbl of cement into perforations, lay in 75’ of cement above retainer
5. WOC. Make 6-1/8” bit and scraper run. Tag cement with 10 klbs.
6. Test casing to 3000 psi., 30 minutes charted
7. Make up the WIS 7” Hydraulic set Whipstock.
8. TIH with DP to the whipstock setting depth. Exercise caution when RIH / setting slips with whipstock
assembly
¾ Fill the drill pipe a minimum of every 20 stands on the trip in the hole with the whipstock assembly.
¾ Avoid sudden starts and stops while running the whipstock.
¾ Recommend running in the hole at a maximum of 90-120 seconds per stand taking care not to spud or catch
the slips. Ensure running string is stationary prior to insertion of the slips and that slips are removed slowly
when releasing the work string to RIH. These precautions are required to avoid any weakening of the
whipstock shear mechanisms and / or to avoid part / preset on the packer.
9. Orient whipstock as directed by the directional driller. The directional plan specifies 0 deg ROHS.
10. Set the top of the whipstock at ~3,150’ MD
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x Ref log: 9/22/1992 SLB Cement Evaluation Log
11. Mill window plus 20’-50’ of new hole (DO NOT EXCEED 50’ OF NEW HOLE BEFORE RUNNING
THE PLANNED FIT/LOT).
¾ Use ditch magnets to collect the metal shavings. Clean regularly.
¾ Ensure any personnel working around metal shavings wear proper PPE, including goggles, face shield and
Kevlar gloves.
¾ Work the upper mill through the window to confirm the window milling is complete and circulate well clean
(circulate a minimum of 1-1/2 bottoms up). Pump a high-vis super sweep to remove metal shavings and
make every effort to remove all of the super sweep pill from the mud system as it is circulated to surface.
12. Pull starter mill into casing above top of whipstock, flow check the well for 10 minutes and conduct a
FIT to 14.7 ppg.
¾ **Assuming the kick zone is at TD, a FIT of 14.7 ppg EMW gives a Kick Tolerance volume of 24.8 bbls
with 10.3 ppg mud weight. Send FIT chart to Drilling Engineer immediately upon test conclusion.
13. POOH and LD milling assembly
¾ Once out of the hole, inspect mill gauge and record.
¾ Flow check well for 10 minutes to confirm no flow:
¾Before pulling off bottom.
¾ Before pulling the BHA through the BOPE.
14. Flush the stack/lines to remove metal debris that may have settled out in these areas. Ensure BOP
equipment is operable.
16. Drill 6-1/8” Hole Section
1. PU 9200’ of 4-1/2” CDS40 Drill pipe for drilling 6-1/8” hole section
2. P/U 4-3/4” Sperry Sun motor drilling assy w/ triple combo (DEN, POR, RES).
3. Ensure BHA Components have been inspected previously.
4. Drift & caliper all components before M/U. Visually verify no debris inside components that
cannot be drifted.
5. Ensure TF offset is measured accurately and entered correctly into the MWD software.
14.7 ppg EMW minimum FIT required. bjm
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6. Have DD run hydraulics models to ensure optimum TFA. Plan to pump at 150 - 300 gpm.
7. Production section will be drilled with a motor. Must keep up with 4 deg/100 DLS in the drop
section of the wellbore.
8. Primary bit will be the Baker Hughes Kymera 6-1/8” KM323. Ensure to have a backup PDC bit
available on location.
9. TIH to window. Shallow test MWD on trip in.
10. TIH through window ensure Baker Hughes MWD service rep on rig floor during this operation.
11. Circulate well with 9.5 ppg LNSD to warm up mud until good 9.5 ppg in and out.
12. Drill approx. 20’ rat hole to accommodate the drilling assembly. Ream shoe as needed to assure
there is little or no drag. After reaming, shut off pumps and rotary (if hole conditions allow) and
pass through shoe checking for drag.
13. Circulate Bottoms Up until MW in = MW out.
14. Drill 6-1/8” hole to Beluga H using motor assembly. Approximate depth of the Beluga H is 5525’
TVD. Weight up to 10.3 ppg mud prior to drilling out of the Beluga H. Maintain 10.3 ppg
EMD to TD (Beluga U).
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be
provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal
seams once drilled.
x Keep swab and surge pressures low when tripping.
x See attached mud program for hole cleaning and LCM strategies.
x Ensure solids control equipment functioning properly and utilized to keep LGS to a
minimum without excessive dilution.
x Adjust MW as necessary to maintain hole stability.
x Ensure mud engineer set up to perform HTHP fluid loss.
x Maintain API fluid loss < 6.
x Take MWD surveys every stand drilled.
x Minimize backreaming when working tight hole
15. At TD pump a sweep and a marker to be used as a fluid caliper to determine annulus volume for
cement calculations. CBU, and pull a wiper trip back to the window.
16. TOH with drilling assembly, handle BHA as appropriate.
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17. Run 4-1/2” Production Liner
1. R/U Baker 4-1/2” liner running equipment.
x Ensure 4-1/2” CDS-40 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.
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).
x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked).
x Landing collar pup bucked up.
x Centralizers will be run on 4-1/2” liner
x Ensure proper operation of float shoe & FC.
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4. Continue running 4-1/2” production liner to TD
x Short joint run every 1000’
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.
5. Ensure to run enough liner to provide at least 100’ overlap inside 7” casing. Ensure hanger/pkr will not
be set in a 7” 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 7” window 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. Continue to fill the string every 10 joints while running liner in open hole. Do not stop to fill casing.
14. 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.
15. 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.
16. Reciprocate & rotate string if hole conditions allow. Circ until hole and mud is in good condition for
cementing.
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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.
5. Pump remaining 10 bbls 12.5 ppg spacer.
6. Mix and pump 157 bbls of 15.3 ppg EasyBLOK per below recipe with xx lbs/bbl of loss circulation
fiber. Ensure cmt is pumped at designed weight. Job is designed to pump 50% OH excess but if
wellbore conditions dictates otherwise we may increase excess volumes. Cement volume is designed to
bring cement to 3050’ TMD (TOL).
7. Displacement fluid will be drilling mud. (4-1/2 DP (.0142*3050 =43 bbls), (4-1/2” Liner (.0152 * 6158
= 94 bbls)), Total 137 bbls
Cement Calculations
6-1/8” OH x 4.5” Liner: (9208’ – 3050’) x 0.01677 x 1.5 = 155 bbls
Shoe Track: 90’ x 0.0152 = 1.4 bbls
Total Volume (bbls): 155 + 1.4 = 157 bbls
Total Volume (ft3): 157 bbls x 5.615 ft3/bbl = 882 ft3
Total Volume (sx): 882 ft3 / 1.34 ft3/sk = 1182 sx
Verified cement and displacement calcs - bjm
658 sx - bjm
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Slurry Information:
System EasyBLOK
Density 15.3 lb/gal
Yield 1.34 ft3/sk
Mixed Water 5.879 gal/sk
Mixed Fluid 5.879 gal/sk
Expected Thickening 70 Bc at 05:00 hr:mn
API Fluid Loss <25 mL in 30.0 min at 155degF / 1000 psi
Additives
Code Description Concentration
G
D046
D202
D400
D154
Cement
Anti Foam
Dispersant
Gas Control Agent
Extender
94 lb/sk
0.2% BWOC
1.5% BWOC
0.8% BWOC
8.0% BWOC
8. Drop DP dart and displace with 10.3 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 and pressure up to up as required by Baker procedure to set the liner hanger (15% above
nominal setting pressure. Hold pressure for 3-5 minutes.
12. Slack off total liner weight plus 30k to confirm hanger is set.
13. Do not overdisplace by more than 1 bbls. Shoe track volume is 1.4 bbls.
14. Pressure up to 4200 psi to release the running tool (HRD-E) from the liner
15. Bleed pressure to zero to check float equipment.
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16. P/U, verify setting tool is released, and expose setting dogs on top of tieback sleeve
17. Rotate slowly and slack off 50k downhole to set ZXPN.
18. 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).
19. 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.
20. 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.
21. Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP.
22. POOH, LDDP. Verify the liner top packer received the required setting force by inspecting the rotating
dog sub.
Backup release from liner hanger:
23. 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.
24. NOTE: Some hole conditions may require movement of the drillpipe to “work” the torque down to the
setting tool.
25. 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 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
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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
x No cleanout planned. Service coil will cleanout, displace mud, and blow down well with N2 prior to
perforating.
x Test liner lap to 2180 psi (50% burst of 7”) after cement has reached 500 psi compressive strength.
20. Run Completion Assembly
1. Run 4-1/2” tubing completion assembly as per separate Approved Completion Sundry
21. RD
x Install BPV in wellhead. RILDs.
x ND BOPE, NU tree, test void
x Rig Down
pg
Test liner lap to 2180 psi (50% burst of 7”) after cement has reached 500 psi compressive strength.
Step 20 is not permitted under this PTD. Separate Sundry required. bjm
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22. BOP Schematic
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23. Wellhead Schematic (current)
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24. Anticipated Drilling Hazards
Lost Circulation:
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 is not present in this hole section.
No abnormal temperatures or pressures are present in this hole section.
Abnormal pressure (10 ppg EMW) expected in Beluga H
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25. Jack up position
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26. 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.
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27. Choke Manifold Schematic
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28. Casing Design Information
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29. 6-1/8” Hole Section MASP
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30. Plot (NAD 27) (Governmental Sections)
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31. Slot Diagram
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32. Directional Program (wp03) - Attached separately
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2800
3150
3500
3850
4200
4550
4900
5250
5600
5950
6300
6650
7000True Vertical Depth (700 usft/in)350 700 1050 1400 1750 2100 2450 2800 3150 3500 3850 4200 4550 4900 5250 5600
Vertical Section at 333.71° (700 usft/in)
NCI A-01A wp01 tgt300035004000450050005500
60006500700075008000
8279A-01
7" TOW
4 1/2" x 6 1/8"3500400045005000550060006500700075 008 000
850 0
900 0
92 07
NCI A-01A wp03
KOP : Start Dir 12º/100' : 3150' MD, 2875.23'TVD : 0° RT TF
End Dir : 3167' MD, 2888.46' TVD
Start Dir 4º/100' : 3187' MD, 2903.79'TVD
End Dir : 3772.76' MD, 3271.06' TVD
Start Dir 3º/100' : 6540.66' MD, 4571.63'TVD
End Dir : 8106.45' MD, 5763.22' TVD
Total Depth : 9207.38' MD, 6826.63' TVD
Top CI 1
Top Beluga B
Hilcorp Alaska, LLC
Calculation Method:Minimum Curvature
Error System:ISCWSA
Scan Method: Closest Approach 3D
Error Surface: Ellipsoid Separation
Warning Method: Error Ratio
WELL DETAILS: NCIU A-01
Water Depth: 101.00
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 2586726.400 332102.260 61° 4' 36.3581 N 150° 56' 53.4414 W
SURVEY PROGRAM
Date: 2021-09-01T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
710.63 3150.00 N COOK INLET UNIT A-01 (NCI A-01) 3_CB-Film-GSS
3150.00 3350.00 NCI A-01A wp03 (Plan: NCI A-01A) 3_MWD_Interp Azi+Sag
3350.00 9207.38 NCI A-01A wp03 (Plan: NCI A-01A) 3_MWD+AX+Sag
FORMATION TOP DETAILS
TVDPath TVDssPath MDPath Formation
3801.63 3675.00 4901.93 Top CI 1
4571.63 4445.00 6540.66 Top Beluga B
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well NCIU A-01, True North
Vertical (TVD) Reference:NCI A-01A Planned RKB @ 126.63usft
Measured Depth Reference:NCI A-01A Planned RKB @ 126.63usft
Calculation Method:Minimum Curvature
Project:North Cook Inlet
Site:North Cook Inlet Unit
Well:NCIU A-01
Wellbore:Plan: NCI A-01A
Design:NCI A-01A wp03
CASING DETAILS
TVD TVDSS MD Size Name
2876.02 2749.39 3151.00 7 7" TOW
6826.63 6700.00 9207.38 4-1/2 4 1/2" x 6 1/8"
SECTION DETAILS
Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation
1 3150.00 37.91 325.00 2875.23 805.45 -498.72 0.00 0.00 943.02 KOP : Start Dir 12º/100' : 3150' MD, 2875.23'TVD : 0° RT TF
2 3167.00 39.95 325.00 2888.46 814.21 -504.85 12.00 0.00 953.58 End Dir : 3167' MD, 2888.46' TVD
3 3187.00 39.95 325.00 2903.79 824.73 -512.21 0.00 0.00 966.28 Start Dir 4º/100' : 3187' MD, 2903.79'TVD
4 3772.76 61.97 335.50 3271.06 1219.56 -730.33 4.00 23.87 1416.88 End Dir : 3772.76' MD, 3271.06' TVD
5 6540.66 61.97 335.50 4571.63 3442.94 -1743.43 0.00 0.00 3859.01 NCI A-01A wp01 tgt Start Dir 3º/100' : 6540.66' MD, 4571.63'TVD
6 8106.45 15.00 335.50 5763.22 4305.05 -2136.25 3.00 180.00 4805.93 End Dir : 8106.45' MD, 5763.22' TVD
7 9207.38 15.00 335.50 6826.63 4564.34 -2254.40 0.00 0.00 5090.73 Total Depth : 9207.38' MD, 6826.63' TVD
667
1000
1333
1667
2000
2333
2667
3000
3333
3667
4000
4333
4667
5000
South(-)/North(+) (500 usft/in)-2667 -2333 -2000 -1667 -1333 -1000 -667 -333 0 333 667
West(-)/East(+) (500 usft/in)
NCI A-01A wp01 tgt
2 2 5 0
2 5 0 0
2 7 5 0
3 0 0 0
3 2 5 0
3 5 0 0
3 7 5 0
4 0 0 0
4 2 5 0
4 5 0 0
4 7 5 0
5 0 0 0
5 2 5 0
5 5 0 0
5 7 5 0
6 0 0 0
6 2 5 0
6 5 0 0
6 7 5 0
7 0 0 07022
A -0 1
7" TOW
4 1/2" x 6 1/8"
3 0 00
3 2 5 0
3 5 0 0
3 7 5 0
4 0 0 0
4 2 5 0
4 5 0 0
4 7 5 0
5 0 0 0
5 2 5 0
5 5 0 0
5 7 5 0600062506500
6 8 2 7NCI A -0 1 A w p 0 3
KOP : Start Dir 12º/100' : 3150' MD, 2875.23'TVD : 0° RT TF
End Dir : 3167' MD, 2888.46' TVD
Start Dir 4º/100' : 3187' MD, 2903.79'TVD
End Dir : 3772.76' MD, 3271.06' TVD
Start Dir 3º/100' : 6540.66' MD, 4571.63'TVD
End Dir : 8106.45' MD, 5763.22' TVD
Total Depth : 9207.38' MD, 6826.63' TVD
Project: North Cook Inlet
Site: North Cook Inlet Unit
Well: NCIU A-01
Wellbore: Plan: NCI A-01A
Plan: NCI A-01A wp03
WELL DETAILS: NCIU A-01
Water Depth: 101.00
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 2586726.400 332102.260 61° 4' 36.3581 N 150° 56' 53.4414 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well NCIU A-01, True North
Vertical (TVD) Reference:NCI A-01A Planned RKB @ 126.63usft
Measured Depth Reference:NCI A-01A Planned RKB @ 126.63usft
Calculation Method:Minimum Curvature
CASING DETAILS
TVD TVDSS MD Size Name
2876.02 2749.39 3151.00 7 7" TOW
6826.63 6700.00 9207.38 4-1/2 4 1/2" x 6 1/8"
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Clearance SummaryAnticollision Report01 September, 2021Hilcorp Alaska, LLCNorth Cook InletNorth Cook Inlet UnitNCIU A-01Plan: NCI A-01A5088320016NCI A-01A wp03Reference Design: North Cook Inlet Unit - NCIU A-01 - Plan: NCI A-01A - NCI A-01A wp03Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Well Coordinates: 2,586,726.40 N, 332,102.26 E (61° 04' 36.36" N, 150° 56' 53.44" W)Datum Height: NCI A-01A Planned RKB @ 126.63usftScan Range: 3,150.00 to 9,207.38 usft. Measured Depth.Geodetic Scale Factor AppliedVersion: 5000.15 Build: 91EScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usftGLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of referenceScan Type:Scan Type:25.00
North Cook InletHilcorp Alaska, LLCAnticollision Report for NCIU A-01 - NCI A-01A wp03Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usftSite NameScan Range: 3,150.00 to 9,207.38 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: North Cook Inlet Unit - NCIU A-01 - Plan: NCI A-01A - NCI A-01A wp03MeasuredDepth(usft)Summary Based on MinimumSeparation WarningNorth Cook Inlet UnitNCIU A-01 - NCI A-01 - A-01 32.29 3,450.00 28.50 3,436.41 8.5313,450.00Clearance Factor Pass - NCIU A-05 - NCI A-05 - A-05 738.61 3,150.00 652.38 2,948.10 8.5653,150.00Clearance Factor Pass - NCIU A-08 - NCI A-08 - A-08 620.23 3,150.00 533.00 2,963.72 7.1103,150.00Clearance Factor Pass - NCIU A-10 - NCI A-10 - A-10 977.78 3,150.00 907.21 2,678.86 13.8553,150.00Clearance Factor Pass - NCIU A-10 - NCI A-10A - A-10A 1,052.89 3,150.00 1,006.17 2,490.94 22.5383,150.00Clearance Factor Pass - NCIU A-12 - NCI A-12 - A-12 913.50 3,150.00 866.60 2,865.06 19.4793,150.00Clearance Factor Pass - NCIU A-13 - NCIU A-13 - NCIU A-13 760.32 3,150.00 675.42 2,910.16 8.9563,150.00Clearance Factor Pass - NCIU A-13 - NCIU A-13PB1 - NCIU A-13PB1 761.64 3,150.00 676.76 2,909.23 8.9733,150.00Clearance Factor Pass - NCIU A-13 - NCIU A-13PB2 - NCIU A-13PB2 761.64 3,150.00 677.03 2,909.23 9.0033,150.00Clearance Factor Pass - NCIU A-13 - NCIU A-13PB3 - NCIU A-13PB3 761.64 3,150.00 677.03 2,909.23 9.0033,150.00Clearance Factor Pass - NCIU A-13 - NCIU A-13PB4 - NCIU A-13PB4 761.64 3,150.00 676.76 2,909.23 8.9733,150.00Clearance Factor Pass - NCIU A-13 - NCIU A-13PB5 - NCIU A-13PB5 761.64 3,150.00 676.76 2,909.23 8.9733,150.00Clearance Factor Pass - NCIU A-13 - NCIU A-13PB6 - NCIU A-13PB6 761.64 3,150.00 676.76 2,909.23 8.9733,150.00Clearance Factor Pass - NCIU A-13 - NCIU A-13PB7 - NCIU A-13PB7 761.64 3,150.00 676.76 2,909.23 8.9733,150.00Clearance Factor Pass - NCIU A-14 - NCIU A-14 - NCIU A-14 957.66 3,150.00 912.18 2,687.30 21.0573,150.00Clearance Factor Pass - NCIU A-16 - NCIU A-16 - NCIU A-16 700.30 3,150.00 637.74 2,977.97 11.1943,150.00Ellipse Separation Pass - NCIU A-16 - NCIU A-16 - NCIU A-16 1,114.46 4,750.00 996.89 4,494.56 9.4794,750.00Clearance Factor Pass - NCIU B-02 - NCIU B-02 - B-02 334.24 3,150.00 289.96 3,111.28 7.5473,150.00Clearance Factor Pass - NCIU B-02 - SUNFISH 3 - SUNFISH 3 334.24 3,150.00 289.89 3,111.28 7.5373,150.00Clearance Factor Pass - Plan: NCIU A-11 - NCI A-11 - A-11 479.37 3,150.00 391.48 2,973.01 5.4543,150.00Ellipse Separation Pass - Plan: NCIU A-11 - NCI A-11 - A-11 791.86 4,300.00 641.19 4,039.49 5.2564,300.00Clearance Factor Pass - Plan: NCIU A-11 - NCI A-11A - NCI A-11A wp03 479.37 3,150.00 391.48 3,015.71 5.4543,150.00Clearance Factor Pass - Prelim: NCIU B-04 - NCIU B-04 - NCIU B-04 wp01 1,022.00 3,150.00 978.32 2,731.73 23.3983,150.00Clearance Factor Pass - Prelim: NCIU B-05 - NCIU B-05 - NCIU B-05 wp01 1,111.67 3,150.00 1,079.83 2,637.31 34.9163,150.00Clearance Factor Pass - 01 September, 2021 - 17:57COMPASSPage 2 of 5
North Cook InletHilcorp Alaska, LLCAnticollision Report for NCIU A-01 - NCI A-01A wp03Survey tool programFrom(usft)To(usft)Survey/Plan Survey Tool710.63 3,150.003_CB-Film-GSS3,150.00 3,350.00 NCI A-01A wp03 3_MWD_Interp Azi+Sag3,350.00 9,207.38 NCI A-01A wp03 3_MWD+AX+SagEllipse error terms are correlated across survey tool tie-on points.Separation is the actual distance between ellipsoids.Calculated ellipses incorporate surface errors.Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation).Distance Between centres is the straight line distance between wellbore centres.All station coordinates were calculated using the Minimum Curvature method.01 September, 2021 - 17:57COMPASSPage 3 of 5
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.
North Cook Inlet Unit A-01A
221-071
North Cook Inlet Unit Tertiary Systems Gas
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