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DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-629-23456-60-00Well Name/No. NIKAITCHUQ SP23-N03L1Completion Status1-OILCompletion Date3/18/2021Permit to Drill2210090Operator Eni US Operating Company Inc.MD13592TVD3795Current Status1-OIL5/6/2021UICNoWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:E-Line: CCL, Caliper MWD/LWD: GR, RES, NEU, Den Mud Logging: GRL, FELNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF4/19/20214818 4523 Electronic Data Set, Filename: SP3-N3L1_MFC_25FEB21_casing.las35018EDDigital DataDF4/19/20216241 6114 Electronic Data Set, Filename: SP3-N3L1_MFC_25FEB21_liner.las35018EDDigital DataDF4/19/20216163 4500 Electronic Data Set, Filename: SP23-N3L1_RBT_25FEB21_MainPass.las35018EDDigital DataDF4/19/20210 3811 Electronic Data Set, Filename: SP23-N3L1_SBHP_28FEB21_stop-6066.las35018EDDigital DataDF4/19/20210 6460 Electronic Data Set, Filename: SP23-N3L1_SBHP_28FEB21_stop-6082.las35018EDDigital DataDF4/19/2021 Electronic File: SP3-N3L1_MFC_25FEB21.pdf35018EDDigital DataDF4/19/2021 Electronic File: SP23-N3L1_RBT_25FEB21.pdf35018EDDigital DataDF4/19/2021 Electronic File: SP23-N3L1_RBT_25FEB21_MainPass.dlis35018EDDigital DataDF4/19/2021 Electronic File: SP23-N3L1_SBHP_28FEB21.pdf35018EDDigital Data0 0 2210090 NIKAITCHUQ SP23-N03L1 LOG HEADERS35018LogLog Header Scans0 0 2210090 NIKAITCHUQ SP23-N03L1 LOG HEADERS35019LogLog Header ScansDF4/19/20216010 13592 Electronic Data Set, Filename: SP23-N3L1_Drilling_Mechanics_Depth_5MD_6010_13592ft.las35019EDDigital DataDF4/19/20216010 13592 Electronic Data Set, Filename: SP23-N3L1_ScopeServices_RM_LAS_6010_13592ft.las35019EDDigital DataThursday, May 6, 2021AOGCCPage 1 of 3Supplied byOpSP23-,N3L1_ScopeServices_RM_LAS_6010_13592ft.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-629-23456-60-00Well Name/No. NIKAITCHUQ SP23-N03L1Completion Status1-OILCompletion Date3/18/2021Permit to Drill2210090Operator Eni US Operating Company Inc.MD13592TVD3795Current Status1-OIL5/6/2021UICNoDF4/19/202144260 44266 Electronic Data Set, Filename: SP23-N3L1_Drilling_Mechanics_Time_LWD01.las35019EDDigital DataDF4/19/2021 Electronic File: SP23-N3L1_LWD_Scope_Service_RM_DLIS.dlis35019EDDigital DataDF4/19/2021 Electronic File: SP23-N3L1_LWD_Scope_Service_RM_DLIS.html35019EDDigital DataDF4/19/2021 Electronic File: SP23-N3L1_Drilling_Mechanics_Depth_5MD_6010_13592ft.Pdf35019EDDigital DataDF4/19/2021 Electronic File: SP23-N3L1_ScopeServices_RM_2MD_6010_13592ft.Pdf35019EDDigital DataDF4/19/2021 Electronic File: SP23-N3L1_ScopeServices_RM_2TVD_6010_13592ft.Pdf35019EDDigital DataDF4/19/2021 Electronic File: SP23-N3L1_ScopeServices_RM_5MD_6010_13592ft.Pdf35019EDDigital DataDF4/19/2021 Electronic File: SP23-N3L1_ScopeServices_RM_5TVD_6010_13592ft.Pdf35019EDDigital DataDF4/19/2021 Electronic File: SP23-N3L1_Drilling_Mechanics_Time_LWD01.Pdf35019EDDigital DataDF4/19/2021 Electronic File: SP23-N3L1 ASP Final HD Survey.pdf35019EDDigital DataDF4/19/2021 Electronic File: SP23-N3L1 ASP Final HD Survey.xlsx35019EDDigital DataDF4/19/20216052 13592 Electronic Data Set, Filename: SP23-N3 L1.las35020EDDigital DataDF4/19/2021 Electronic File: SP23-N3-L1 2MD DEL.pdf35020EDDigital DataDF4/19/2021 Electronic File: SP23-N3-L1 2MD FEL.pdf35020EDDigital DataDF4/19/2021 Electronic File: SP23-N3-L1 2MD GRL.pdf35020EDDigital DataDF4/19/2021 Electronic File: SP23-N3-L1 5MD DEL.pdf35020EDDigital DataDF4/19/2021 Electronic File: SP23-N3-L1 5MD FEL.pdf35020EDDigital DataDF4/19/2021 Electronic File: SP23-N3-L1 5MD GRL.pdf35020EDDigital Data0 0 2210090 NIKAITCHUQ SP23-N03L1 LOG HEADERS35020LogLog Header ScansThursday, May 6, 2021AOGCCPage 2 of 3SP23-N3 L1.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-629-23456-60-00Well Name/No. NIKAITCHUQ SP23-N03L1Completion Status1-OILCompletion Date3/18/2021Permit to Drill2210090Operator Eni US Operating Company Inc.MD13592TVD3795Current Status1-OIL5/6/2021UICNoWell Cores/Samples Information:ReceivedStart Stop CommentsTotalBoxesSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments:Compliance Reviewed By:Date:Mud 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:3/18/2021Release Date:1/27/2021Thursday, May 6, 2021AOGCCPage 3 of 3M. 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6313%6313%631/631/6/%B'8$/*0$*6$* 631/631/6/%B0:'*0$* 6313%6313%6/%B0:'*0$* 631/631//HJDO'HVFULSWLRQ 1RUWKLQJ < (DVWLQJ ; 6XUIDFH )6/)(/6 715 (80 6/%B0:',1&B21/<B),//(57RS2$ )6/)(/6 715 (80 7RS:LQGRZ )6/ )(/6 715 (80 %+/ )6/ )(/715(80 'ULOOLQJ2IILFH $03DJHRI1LNDLWFKXT?6S\,VODQG?631?631/?631/^ĐŚůƵŵďĞƌŐĞƌͲWƌŝǀĂƚĞ Eni US Operating Co, Inc WELL LOG/DATA TRANSMITTAL To: ůĂƐŬĂKŝůĂŶĚ' ĂƐŽŶƐĞƌǀĂƟŽŶŽŵŵŝƐƐŝŽ 333 W. 7th Ave, Anchorage, AK 99501 April 19, 2021 Well:SP23-N3 L1 LWD/MWD Logs PDF LAS DLIS Excel Drilling Mechanics Depth X X Drilling_Mechanics Time X X ScopeService RM X 2" & 5"ScopeServices RM MD X 2" & 5"ScopeServices RM TVD X ASP Final Survey X X Mudlogs 2" & 5" MD Formation Evaluation Log X X 2" & 5"MD Drilling Evaluation Log X X 2" & 5"MD Gas Ratio Log X X E-line logs 9-5/8" Multi-Finger Imaging Tool Casing X X 9-5/8"Multi-Finger Imaging Tool Liner X X 9-5/8"Radial Cement Bond Log X X 9-5/8"Bottom Hole Pressure Survey X X 9-5/8"Micro DLS Log X PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Joshua Zuber Mail: joshua.zuber@eni.com Received By: ___________________________________Date:____________ Eni US Operating Co, Inc. PTD: 2210090 E-Set: 35018 Received by the AOGCC 04/19/2021 04/20/2021 Eni US Operating Co, Inc WELL LOG/DATA TRANSMITTAL To: ůĂƐŬĂKŝůĂŶĚ' ĂƐŽŶƐĞƌǀĂƟŽŶŽŵŵŝƐƐŝŽ 333 W. 7th Ave, Anchorage, AK 99501 April 19, 2021 Well:SP23-N3 L1 LWD/MWD Logs PDF LAS DLIS Excel Drilling Mechanics Depth X X Drilling_Mechanics Time X X ScopeService RM X 2" & 5"ScopeServices RM MD X 2" & 5"ScopeServices RM TVD X ASP Final Survey X X Mudlogs 2" & 5" MD Formation Evaluation Log X X 2" & 5"MD Drilling Evaluation Log X X 2" & 5"MD Gas Ratio Log X X E-line logs 9-5/8" Multi-Finger Imaging Tool Casing X X 9-5/8"Multi-Finger Imaging Tool Liner X X 9-5/8"Radial Cement Bond Log X X 9-5/8"Bottom Hole Pressure Survey X X 9-5/8"Micro DLS Log X PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Joshua Zuber Mail: joshua.zuber@eni.com Received By: ___________________________________Date:____________ Eni US Operating Co, Inc. PTD: 2210090 E-Set: 35020 Received by the AOGCC 04/19/2021 04/19/2021 Eni US Operating Co, Inc WELL LOG/DATA TRANSMITTAL To: ůĂƐŬĂKŝůĂŶĚ' ĂƐŽŶƐĞƌǀĂƟŽŶŽŵŵŝƐƐŝŽ 333 W. 7th Ave, Anchorage, AK 99501 April 19, 2021 Well:SP23-N3 L1 LWD/MWD Logs PDF LAS DLIS Excel Drilling Mechanics Depth X X Drilling_Mechanics Time X X ScopeService RM X 2" & 5"ScopeServices RM MD X 2" & 5"ScopeServices RM TVD X ASP Final Survey X X Mudlogs 2" & 5" MD Formation Evaluation Log X X 2" & 5"MD Drilling Evaluation Log X X 2" & 5"MD Gas Ratio Log X X E-line logs 9-5/8" Multi-Finger Imaging Tool Casing X X 9-5/8"Multi-Finger Imaging Tool Liner X X 9-5/8"Radial Cement Bond Log X X 9-5/8"Bottom Hole Pressure Survey X X 9-5/8"Micro DLS Log X PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Joshua Zuber Mail: joshua.zuber@eni.com Received By: ___________________________________Date:____________ Eni US Operating Co, Inc. PTD: 2210090 E-Set: 35019 Received by the AOGCC 04/19/2021 04/20/2021 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Stefano Pierfelici Well Operations Project Manager Eni US Operating Co. Inc. 3700 Centerpoint Drive, Suite 500 Anchorage, AK 99503 Re: Nikaitchuq Field, Schrader Bluff Oil Pool, SP23-N3L1 Eni US Operating Co. Inc. Permit to Drill Number: 221-009 Surface Location: 4449.8’ FSL, 1374.2’ FEL, SEC. 19, T14N, R9E, UM Bottomhole Location: 3607’ FSL, 3913’ FEL, SEC. 13, T14N, R8E, UM Dear Mr. Pierfelici: 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 January, 2021. Jeremy M Pric 27 By Samantha Carlisle at 11:07 am, Jan 21, 2021 X 221-009 DLB 01/25/2021 X X 629-23456-60-00 VTL 1/27/21 X X X DSR-1/22/21 X BOPtestto3500psig Annular preventer test to 2500 psig X TL1/27/21 1/27/21 1/27/21 Application for Permit to Drill SP23-N3L1 Saved: 20-Jan-21 AOGCC PERMIT Document rev1 Page 1 of 7 Printed: 20-Jan-21 Application for Permit to Drill Document Producer Well SP23-N3L1 Table of Contents 1. Well Name ................................................................................................................3 Requirements of 20 AAC 25.005 (f)....................................................................................................3 2. Location Summary..................................................................................................3 Requirements of 20 AAC 25.005(c)(2)................................................................................................3 Please see Attachment 7: Surface Platt ..............................................................................................3 Requirements of 20 AAC 25.050(b)....................................................................................................3 3. Blowout Prevention Equipment Information ....................................................4 Requirements of 20 AAC 25.005(c)(3)................................................................................................4 4. Drilling Hazards Information ................................................................................4 Requirements of 20 AAC 25.005 (c)(4)...............................................................................................4 5. Procedure for Conducting Formation Integrity Tests ......................................4 Requirements of 20 AAC 25.005 (c)(5)...............................................................................................4 6. Casing and Cementing Program ..........................................................................5 Requirements of 20 AAC 25.005(c)(6)................................................................................................5 7. Diverter System Information ...............................................................................5 Requirements of 20 AAC 25.005(c)(7)................................................................................................5 8. Drilling Fluid Program ............................................................................................6 Requirements of 20 AAC 25.005(c)(8)................................................................................................6 9. Abnormally Pressured Formation Information .................................................6 Requirements of 20 AAC 25.005 (c)(9)...............................................................................................6 10. Seismic Analysis ...............................................................................................6 Requirements of 20 AAC 25.005 (c)(10).............................................................................................6 11. Seabed Condition Analysis .............................................................................6 Requirements of 20 AAC 25.005 (c)(11).............................................................................................6 Application for Permit to Drill SP23-N3L1 Saved: 20-Jan-21 AOGCC PERMIT Document rev1 Page 2 of 7 Printed: 20-Jan-21 12. Evidence of Bonding ........................................................................................6 Requirements of 20 AAC 25.005 (c)(12).............................................................................................6 13. Proposed Drilling Program .............................................................................7 Requirements of 20 AAC 25.005 (c)(13).............................................................................................7 14. Discussion of Mud and Cuttings Disposal and Annular Disposal .............7 Requirements of 20 AAC 25.005 (c)(14).............................................................................................7 15. Attachments ......................................................................................................7 Attachment 1 Drilling Procedure .........................................................................................................7 Attachment 2 Directional Plan ............................................................................................................7 Attachment 3 Drilling Hazards Summary ............................................................................................7 Attachment 4 BOP Configuration ........................................................................................................7 Attachment 5 Formation Integrity And Leak Off Test Procedure .........................................................7 Attachment 6 Surface Platt ................................................................................................................7 Application for Permit to Drill SP23-N3L1 Saved: 20-Jan-21 AOGCC PERMIT Document rev1 Page 3 of 7 Printed: 20-Jan-21 1. Well Name Requirements of 20 AAC 25.005 (f) Each well must be identified by a unique name designated by the operator and a unique API number assigned by the commission under 20 AAC 25.040(b). For a well with multiple well branches, each branch must similarly be identified by a unique name and API number by adding a suffix to the name designated for the well by the operator and to the number assigned to the well by the commission. Well Name: SP30-W1 L1 2. Location Summary Requirements of 20 AAC 25.005(c)(2) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (2) a plat identifying the property and the property's owners and showing (A)the coordinates of the proposed location of the well at the surface, at the top of each objective formation, and at total depth, referenced to governmental section lines. (B) the coordinates of the proposed location of the well at the surface, referenced to the state plane coordinate system for this state as maintained by the National Geodetic Survey in the National Oceanic and Atmospheric Administration; (C) the proposed depth of the well at the top of each objective formation and at total depth; Please see Attachment 7: Surface Platt and (D) other information required by 20 AAC 25.050(b); Requirements of 20 AAC 25.050(b) If a well is to be intentionally deviated, the application for a Permit to Drill (Form 10-401) must (1) include a plat, drawn to a suitable scale, showing the path of the proposed wellbore, including all adjacent wellbores within 200 feet of any portion of the proposed well; Please see Attachment 2: Directional Plan and (2) for all wells within 200 feet of the proposed wellbore (A) list the names of the operators of those wells, to the extent that those names are known or discoverable in public records, and show that each named operator has been furnished a copy of the application by certified mail; or (B) state that the applicant is the only affected owner. The Applicant is the only affected owner. 4449.8 FSL 1374.2 FEL S19 T14N R9E UM RKB Elevation 53.99’ AMSL Northing: 6053631.53 ft Easting: 511535.62 ft Pad Elevation 13.1’ AMSL Measured Depth, RKB:6380.00 ft Northing: 6052671.51 ft Easting: 509280.16 ft Total Vertical Depth, RKB:3881.59 ft Total Vertical Depth, SS:3827.60 ft Measured Depth, RKB:14032.17 ft Northing: 6058060.00 ft Easting: 503911.00 ft Total Vertical Depth, RKB:3789.99 ft Total Vertical Depth, SS:3736.00 ft ASP Zone 4 NAD 27 Coordinates 3494 FSL 3635 FEL 19 T14N R9EUM 3607 FSL 3913 FEL 13 T14N R8EUM Location at Surface Location at Top of Productive Interval Location at Total Depth ASP Zone 4 NAD 27 Coordinates ASP Zone 4 NAD 27 Coordinates Application for Permit to Drill SP23-N3L1 Saved: 20-Jan-21 AOGCC PERMIT Document rev1 Page 4 of 7 Printed: 20-Jan-21 3. Blowout Prevention Equipment Information Requirements of 20 AAC 25.005(c)(3) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (3) a diagram and description of the blowout prevention equipment (BOPE) as required by 20 AAC 25.035, 20 AAC 25.036, or 20 AAC 25.037, as applicable; Please see Attachment 4: BOP and Diverter Configuration 4. Drilling Hazards Information Requirements of 20 AAC 25.005 (c)(4) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (4) information on drilling hazards, including (A) the maximum downhole pressure that may be encountered, criteria used to determine it, and maximum potential surface pressure based on a methane gradient; The expected reservoir pressure in the Schrader Bluff sand is 0.45 psi/ft, or 8.6 ppg EMW (equivalent mud weight). The maximum potential surface pressure (MPSP) based on the above maximum pressure gradient, a methane gradient (0.11), and the planned vertical depth of the OA sand formation is: (B) data on potential gas zones; The well bore is not expected to penetrate any gas zones. and (C) data concerning potential causes of hole problems such as abnormally geo-pressured strata, lost circulation zones, and zones that have a propensity for differential sticking; Please see Attachment 2: Drilling Hazards Summary. 5. Procedure for Conducting Formation Integrity Tests Requirements of 20 AAC 25.005 (c)(5) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (5) a description of the procedure for conducting formation integrity tests, as required under 20 AAC 25.030(f); Please see Attachment 6: Formation Integrity and Leak off Test Procedure TVDss Pore Pressure Gas Gradient MPSP 3736.00 ft 0.45 psi/ft 0.11 psi/ft 1270.2 psi Application for Permit to Drill SP23-N3L1 Saved: 20-Jan-21 AOGCC PERMIT Document rev1 Page 5 of 7 Printed: 20-Jan-21 6. Casing and Cementing Program Requirements of 20 AAC 25.005(c)(6) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (6) a complete proposed casing and cementing program as required by 20 AAC 25.030, and a description of any slotted liner, pre- perforated liner, or screen to be installed; 7. Diverter System Information Requirements of 20 AAC 25.005(c)(7) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (7) a diagram and description of the diverter system as required by 20 AAC 25.035, unless this requirement is waived by the commission under 20 AAC 25.035(h)(2); Please see Attachment 4: BOP and Diverter Configuration. Cas - Tbg Hole Weight Grade Connection Length Cement Program OD Size MD TVD MD TVD (in) (in) (lb/ft) (ft) (ft) (ft) (ft) (ft) 20 Driven 178.89 X-65 Welded 123 37.04 37.04 160 160 Pre-Installed 13 3/8 16 68 L-80 BTC 2711 36.8 36.8 2748 2480 In place / Completed 9 5/8 12 1/4 40 L-80 Hydril 563 6334 35.5 35.5 6369 3895 In place / Completed 5 1/2 8 3/4 15.5 L-80 Hydril 521 7792 6175 3888 13967 3807 Liner in Open Hole - no Top Btm Casing and Cementing Program See also Attachment 4: Cement Summary Application for Permit to Drill SP23-N3L1 Saved: 20-Jan-21 AOGCC PERMIT Document rev1 Page 6 of 7 Printed: 20-Jan-21 8. Drilling Fluid Program Requirements of 20 AAC 25.005(c)(8) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (8) a drilling fluid program, including a diagram and description of the drilling fluid system, as required by 20 AAC 25.033; Drilling will be done with muds having the following properties over the listed intervals: Fluid description: MI FazePro Mineral Oil Bas Value Density (ppg) 9.0 –9.6 Plastic Viscostiy (CP) 15 - 25 Yield Point (lb/100 sf) 15 - 20 HTHP Fluid loss (ml/30 min @ 200psi & 100°F <5.0 Oil / Water Ratio 60 / 40 Electrical Stability >600 Drilling fluid practices will be in accordance with appropriate regulations stated in 20 AAC 25.033. 9. Abnormally Pressured Formation Information Requirements of 20 AAC 25.005 (c)(9) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (9) for an exploratory or stratigraphic test well, a tabulation setting out the depths of predicted abnormally geo-pressured strata as required by 20 AAC 25.033(f); Not applicable: Application is not for an exploratory or stratigraphic test well. 10. Seismic Analysis Requirements of 20 AAC 25.005 (c)(10) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (10) for an exploratory or stratigraphic test well, a seismic refraction or reflection analysis as required by 20 AAC 25.061(a); Not applicable: Application is not for an exploratory or stratigraphic test well. 11. Seabed Condition Analysis Requirements of 20 AAC 25.005 (c)(11) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (11) for a well drilled from an offshore platform, mobile bottom-founded structure, jack-up rig, or floating drilling vessel, an analysis of seabed conditions as required by 20 AAC 25.061(b); Not applicable: Application is not for an offshore well. 12. Evidence of Bonding Requirements of 20 AAC 25.005 (c)(12) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (12) evidence showing that the requirements of 20 AAC 25.025 {Bonding}have been met; Evidence of bonding for ENI is on file with the Commission. DLBNote: Minimum EMW needed at T.D.=3736' TVDss is 8.65 ppg. Note: Application for Permit to Drill SP23-N3L1 Saved: 20-Jan-21 AOGCC PERMIT Document rev1 Page 7 of 7 Printed: 20-Jan-21 13. Proposed Drilling Program Requirements of 20 AAC 25.005 (c)(13) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: Please refer also to Attachment 1 – Drilling Procedure 14. Discussion of Mud and Cuttings Disposal and Annular Disposal Requirements of 20 AAC 25.005 (c)(14) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (14) a general description of how the operator plans to dispose of drilling mud and cuttings and a statement of whether the operator intends to request authorization under 20 AAC 25.080 for an annular disposal operation in the well.; Waste fluids generated during the drilling process will be disposed of by injection down an Oliktok Point or Spy Island Class I disposal well. Alternative disposal method will include hauling the fluids to the Prudhoe Bay Grind and Inject Facility. 15. Attachments Attachment 1 Drilling Procedure Attachment 2 Directional Plan Attachment 3 Drilling Hazards Summary Attachment 4 BOP Configuration Attachment 5 Formation Integrity And Leak Off Test Procedure Attachment 6 Surface Platt WELL SP23-N3L1 SP23-N3L1 Drilling Wellplan Page 1 of 22 01/20/21 Drilling Procedure SP23-N3L1 Spy Island Conductor slot #23 Reservoir location #N3 L1 Producer (Schrader Bluff) Nikaitchuq Project WELL SP23-N3L1 SP23-N3L1 Drilling Wellplan Page 2 of 22 01/20/21 WELL SP23-N3L1 SP23-N3L1 Drilling Wellplan Page 3 of 22 01/20/21 Table of Contents WELL PLAN SUMMARY .......................................................................................................... 4 OBJECTIVES............................................................................................................................... 5 WELL HISTORY......................................................................................................................... 6 DE-COMPLETION SECTION................................................................................................... 7 RIH WHIPSTOCK AND 9 5/8” MILLING OPERATIONS ................................................... 8 Pick Up Production Drilling Assembly..................................................................................... 10 PRODUCTION SECTION........................................................................................................ 11 Production Drilling..................................................................................................................... 12 Production Liner......................................................................................................................... 13 RIH ESP Completion.................................................................................................................. 15 Well Shut In Procedure While Running Production Tubing.................................... 22 WELL SP23-N3L1 SP23-N3L1 Drilling Wellplan Page 4 of 22 01/20/21 WELL PLAN SUMMARY Rig:Doyon 15 Type of Well:Producer Well Design:13-3/8” Surface x 9-5/8” Intermediate x 5-1/2” Liner Close Approach and Offset Well Interception Risks It is important to stay as close as practical to the planned directional program. The directional program and a summary of close approaches can be found in the attachments. These close approaches will be in conformance with the minimum well separation criteria detailed by the Drilling Anti-Collision Analysis and Close Approach Guidelines. It is the responsibility of the Directional Driller and the Drilling Supervisor to ensure that the directional plan is executed as planned, that the position of the well as it is drilled is monitored on an anti-collision diagram and that no tolerance line for close approach wells is crossed. It is important that the well bore remains close to the planned well path as any major deviations from the profile may adversely affect the ability to drill future wells and still adhere to the current close crossing guidelines. Survey Program & Procedures Take MWD surveys as frequently as needed, but no less than every 100 ft. Carefully review the anticipated close crossings with existing wellbores and future well paths. Make sure that directional drillers are aware of all drilling close crossing issues, hard lines and no-go lines. If a no-go or hard line has been or will be crossed,stop drilling immediately and contact the Drilling Superintendent to discuss options. Mud Logging Program Mudlogging will be utilized from spud to production hole TD. Refer to the Geological Mud Logging Procedure document. WELL SP23-N3L1 SP23-N3L1 Drilling Wellplan Page 5 of 22 01/20/21 OBJECTIVES x Perform work in a safe and professional manner meeting all ENI Petroleum Health, Safety, and Environmental requirements. Drill the well at or under AFE cost and time. x Remove current TTESP completion assembly, Execute the setting and orientation of the whipstock per the wellplan. x Cut window in the 9 5/8” casing and drill 2nd lateral per the well plan. Maximum dogleg severity in the landing shall be no greater than 3.5°/100' DLS. x Target Greater than 90% within the OA sand Reservoir. x 8-3/4" hole LWD Failure Requirements: GR/Res/Dir/PWD– Require GR/Res/Dir to achieve TD. WELL SP23-N3L1 SP23-N3L1 Drilling Wellplan Page 6 of 22 01/20/21 WELL HISTORY Current Status Well SP23-N3 is currently shut in Scope of Work Scope of this workover is to pull the current TTC-ESP tubing completion, rih and set a retrievable whipstock , mill a window in the 9 5/8” casing , drill a new 8 3/4” lateral section, rih a second 5 ½” slotted liner and run in with a new ESP system to have a commingle production for both lateral. GeneralWellinfo Reservoir Pressure/TVD: This well is expected to have a static max bottom hole pressure of approximately 1681 psi during the drilling time. Wellhead type/pressure rating: Vetco Gray, MB-247/5000 psi ` BOP configuration: Annular 3-1/2” x 6” VBR Blind Ram 4-1/2” x7” VBR WELL SP23-N3L1 SP23-N3L1 Drilling Wellplan Page 7 of 22 01/20/21 DE-COMPLETION SECTION Procedure: 1. MIRU Doyon 15. 2. Circulate 9.1 ppg hot water with 3 % KCl kill fluid through tree. 3. Set BPV. ND tree and NU BOP and test to 3500 psi. 4. Pull tubing to lower GLM. Rig up wireline and pull tubing stop check valve. 5. Circulate out remaining production fluid. 6. Continue POOH and lay down ESP assembly. Current schematic of the well: Surf.Casing 13-3/8", 68 # BTC 2,748' MD, 2,481' TVD 49ºInc. Interm.Casing 9-5/8", 40# 6369' MD, 3895' TVD 89ºInc. 4-½”12.6 ppf H563 Production Tubing Slotted Liner, 5-½”15.5 ppf 13,967' MD, 3807' TVD, 91.5ºInc. Zonal Isolation Swell Packers 4-½”x-cplg cable clamps, for ESP Power Cable,(1)3/8" Chem Inj Line SP23-N3 Oil Producer with ESP Lift Nikaitchuq Field – Spy Island 5995' MD, 3874' TVD, 86º Inc – Bottom of Motor Centralizer Centrilift, TTC-ESP, 116-stage 380P18SXD pump, 513 GSB3 seals, 150 HP MSP1 motor 2,282' MD, 2150, 38º Inc - GLM, KBMG, 4-½” x 1", with 2,000 psi STS-1 SOV installed 6176' MD, 3,888 TVD - Baker SLXP Liner Hanger/Packer 5-½” Silver Bullet Ecc. Nose Guide Shoe Dec, 20205789' MD, 3857' TVD, 86º Inc - GLM, KBMG, 4-½” x 1", with 3,100 psi STS-1 SOV installed 5891' MD, 3865' TVD - Discharge Gauge Sub Swell Packer MD’s (ft): #1) 7,486 #2 8,535 #3) 9,417 #4) 11,426 6,015' MD 32 # Shroud Assembly with cable and chemical injection line feed-thrus WELL SP23-N3L1 SP23-N3L1 Drilling Wellplan Page 8 of 22 01/20/21 RIH WHIPSTOCK AND 9 5/8” MILLING OPERATIONS 1. RIH with a Drift/clean out BHA to the top of the previous 5 ½” liner 2. PU MLZXP LH assembly and sting in to the SLZXP. 3. Position hanger & packer at the desired depth. Use MWD to record orientation of MLZXP profile as this is critical for future use. Repeat multiple times until all parties are in agreement on MLZXP hanger orientation. 4. POOH and LD running tool. Mill a window in 9 5/8” 40# casing: Notes: x It is important that the whipstock assembly be spaced out to ensure that the entire window is milled between casing collars. x The approximate overall length of the casing window to be milled is 16’-17’ ft. x All measurement and procedures are to be double-checked and approved by Co.Man prior to running the whipstock/window milling assembly in the hole. x Ensure drill pipe pup joints are available for the correct space out x After the window is milled, the upper watermelon mill should be gauged. If the upper watermelon mill is more that 1/8” under gauge a cleanup trip is recommended to ensure window is fully open. A back up set of mills should be on location. x Ditch magnets should be placed in the flow line to recover all metal circulated out of the well Whipstock/Window Milling Guidelines: x Check with Geologist to confirm if there is a concretion at the window milling depth. x Never rotate a bit on the face of the whipstock x Orient the BHA (if motor is used) above the window before attempting to exit the window. Bit rotation may “catch” the edge of the whipstock and damage the face making recovery operations more difficult. x If at any time during operations a problem is encountered tripping through the window area, a watermelon or string mill should be run in the drilling assembly to clean up the window area x Always trip slowly and carefully ( +/- 90 seconds per stand) with all BHA’s through the milled window WELL SP23-N3L1 SP23-N3L1 Drilling Wellplan Page 9 of 22 01/20/21 Procedure: 1. Prior to mill the window, hold a Tech Planning meeting to discuss this phase of the well. Review the well plan and discuss any discrepancies or concerns with the drilling superintendent 2. RIH the whipstock assembly 3. At surface align the MWD with the whipstock face 4. Shallow test the MWD tools 5. RIH to setting depth 6. 45’ above setting depth establish circulation and work torque out of string. 7. Swab brine to Oil Based Reservoir Drill-In fluid. 8. Orient the whipstock as per well plan. Once the correct orientation is confirmed, Slack off slowly to land the Anchor and latch to MLZXP. 9. Initiate circulation and obtain a survey of the installed whipstock orientation 10. Start 9 5/8” casing milling operation. Establish rotation to begin milling the window. 11. After the window is complete and before POOH, shut pumps and work milling assembly through window several times watching for drag. POOH and L/D milling assembly. WELL SP23-N3L1 SP23-N3L1 Drilling Wellplan Page 10 of 22 01/20/21 Pick Up Production Drilling Assembly 1. PU the 8-3/4” bit and the BHA assembly as per the BHA diagram. a. 8-3/4” PDC b. Rotary Steerable 2. Drill 20’-50’ of new hole using the Oil Based Reservoir Drill-In fluid. 3. Perform Leak Off Test as per AOGCC requirements following the attached LOT Procedure. a. PU into casing and perform LOT. b. If the pressure continues to rise past 12.5 ppg EMW, shut down and call it a FIT per the FIT Guidelines (attached). c. If LOT is unacceptable to drill ahead (less than 12.0 ppg EMW), contact Drilling Superintendent to discuss options. d. Do not pump more than 1/2 bbl after early leak is determined. There is no need to pump more than 1/2 bbl into the leak off and extend the fracture. . WELL SP23-N3L1 SP23-N3L1 Drilling Wellplan Page 11 of 22 01/20/21 PRODUCTION SECTION Production Mud Program: FazePro Interval Density (ppg)YP HTHP FL (ml/30min)Oil:water Electrical Stability mlVolts Production 9.0-9.6 15-20 <5.0 60:40 >600 Production Logging/Formation Evaluation Program Production: MWD Directional / PWD (Pressure While Drilling) LWD GR / Res / Ecoscope/ PeriSCOPE Production Drill Pipe Pipe WT (ppf)Grade Conn. type Tool Joint OD (in) Tool Joint ID (in) Body ID (in) Make Up Torque (ft.lbs) Joint Torsion al Yield (ft lbs) Body Torsional Yield (ft.lbs) DP capacity w/ conn. (gal/ft) Tensile Capacity (kips) 4.5” DP 16.6 S-135 Delta 425 5.25 3.00 3.826 35,000 43,450 43,500 .560 471 5” DP 19.5 S-135 TT525 6.50 3.875 4.276 49,600 82,700 74,100 .731 712 Production Section Notes: x Monitor hole conditions carefully. Be alert for early signs of lost circulation and differential sticking. If any of these problems are observed immediately notify the Drilling Supervisor or Toolpusher (attempt to keep the pipe moving and circulation established). Ensure that all team members are communicating with each other on any observed drilling trends and that everyone understands the potential risks. x Shallow test MWD tools. x Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. x Keep shut down times to a minimum during connections. When surveying in this hole section reciprocate the pipe slowly while the survey is transmitted uphole. Keep the pipe rotating whenever possible. x Ensure the Top Drive Torque Limit is set below the lowest make up torque in the string. Do not run the risk of further make up to a connection while drilling. Openhole Sidetracking Practices: x Lowside in a fast drilling interval where the wellbore is heading up and where the ABI’s show a good build rate. WELL SP23-N3L1 SP23-N3L1 Drilling Wellplan Page 12 of 22 01/20/21 x Orient within 15 degrees either side of lowside and trough with high rotary RPM’s while reciprocating from the kickoff point back to the first stabilizer. Trough for approximately 30 minutes. x Time drill at 4 to 6 feet per hour with high flow rates and rotary RPM’s for the first 5 feet. Gradually increase the penetration rate as the openhole sidetrack is achieved. x If any openhole sidetracks are drilled, confer with Drilling Supt. and consider tripping without circulating or without rotating past the sidetrack point. Production Drilling 1. Directionally drill the 8-3/4” hole to TD. a. Geosteering will be required to remain in the target boundary 100% of the time b. Maintain sufficient flow ratewith maximumpiperotation as needed to bringmud/wellproperties inline. 2. Backream at TD: a. At TD circulate 50% of calculated TAD cleanup cycle pulling 1 stand per bottoms up. Once the first 50% cleanup cycle is completed circulate the remaining 50% of the calculated cleanup cycle pulling 2 stands per bottoms up. Decrease backreaming speed as torque and pump pressure dictate. 3. Backream to upper stabilizer +/- 100’ window’ below window. Take care when pulling into the window as a. Do NOT ream across whipstock. 4. Pull with pumps only into the window and above the whipstock. Perform clean up cycle as needed observing cuttings volume at the shakers. a. Decrease back reaming speed as torque and pump pressure dictate 5. Continue backreaming until depth at which it is possible to pull out on elevators at >9.1 swab EMW at 2.5 a. Determine depth at which swab can be kept >9.1 EMW as per K&M TAD Model. 6. Circulate until shakers are clean as per K&M. 7. Slug DP and trip out of hole on elevators. a. Utilize K&M’s swab model to control trip speed and avoid swabbing the open hole below ±9.1 ppg EMW. 8. Lay down BHA. 9. RIH with retrieving tool assemblyto retrieve the whipstock assembly WELL SP23-N3L1 SP23-N3L1 Drilling Wellplan Page 13 of 22 01/20/21 Production Liner Production Liner OD (in)WT (ppf) Grade Conn. Type Cplg OD (in)ID (in) Drift (in) Collapse (psi) Burst (psi) Tensile Yield (kips) 5-1/2 15.5 L-80 Hydril 521 5.713 4.950 4.825 4990 7000 242 Production Liner Connection Make Up Torque (ft-lbs) OD (in) WT (ppf)Grade Conn. Type Min. Make Up Torque, ft- lbs Target Make Up Torque Max. Make Up Torque Yield Torque 5-1/2 15.5 L-80 Hydril 521 4600 8100 N/A 24,000 Production Liner Centralization From To Quantity / Joint Fixed / Floating Type Shoe Liner top 1/joint -Mid-joint Fixed -Crimpedon 5-1/2” x 7” - Hydroform, Volant (Crimp on) Liner Running Procedure Notes: x Ensure proper crossover from DP to slotted liner is on the rig floor in case of a well control situation. x Liner top should be placed a minimum of 200 ft above the intermediate casing shoe. x Ensure accurate torque and drag data is gathered. Record pick up and slack off weights every stand and free rotating torque every five stands. Data gathered will assist in future liner running operations throughout the project. x Perform visual inspection, measure and caliper all components prior to running any assembly in the hole. Ensure accurate dimensional data is recorded for all equipment run in the well and recorded in WellView. x Ensure all equipment has been hydraulically and operationally tested. Also ensure all equipment to be run is dimensionally compatible with all other equipment. x Review all setting operations and shear pressures with Baker Oil Tools service hand. x Ensure that all workstring components have been rabbited as ball will be dropped to actuate downhole tools. Rabbit DP on last trip out of prior to running liner. x If any openhole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters the correct hole. x Torque ratings for string components: String Components Yield Torque (ft-lb) 5" 19.5# TT525 Drill Pipe 74,100 WELL SP23-N3L1 SP23-N3L1 Drilling Wellplan Page 14 of 22 01/20/21 HRD Running Tool 40,000 7" 29# Hydril 563 39,000 5-1/2” 15.5# Hydril 521 24,000 x Shear pressures for liner hanger assembly: Item Description Shear Value Shear Range HRD Running Tool, 7" Nominal -3192 psi 15% + 3671 psi 6795 mch rel, 3 pins 15% - 2713 psi Pusher Tool Activation Nominal -1986 psi 15% + 2284 psi 15% - 1688 psi Pusher Tool Neutrlz. Nominal -3588 psi 15%+ 4126 psi 15% - 3050 psi Ball Seat SOLID Procedure: 1. Hold Pre-job safety meeting to ensure all parties understand operation 2. PU the Liner Assembly and Running/Inner String as outlined above. 3. RIH with Liner Assembly. Record PU and SO weights as required. 4. Pick up liner hanger assemblyand make uptopropertorque. Fill Liner TiebackSleeve with “pal mix” and ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 minutes for mixture to set up. 5. Trip in hole one stand and circulate 5 bbls to ensure all flow paths are free. Record ROTATE, PU and SO of liner assembly. 6. RIH in hole to casing shoe with DP. RIH with Liner Assembly as hole conditions allow, but do not exceed running speed of one stand per minute. Break circulation and fill DP as necessary. 7. Monitor mud flow while running in open hole and slow running speed if necessary. Circulate minimum of one DP volume and record ROTATE, PU and SO weights. 8. Record PU, SO, and Rotating torque in open hole every 500’ to ensure friction factors are sufficient to run the liner to bottom successfully. If friction trend indicates liner will not go to bottom then call Drilling Supt. immediately. 9. Rotating liner 20-60 RPM will be necessary to run to bottom. 10. Continue RIH with Liner Assembly to proper setting depth. Liner should be spaced out to locate the liner top approximately 200 feet above 9-5/8” window. 11. Trip slightlydeeper than desired liner top location with liner top. Last motion of the liner should be up to ensure it is set in tension. 12. Ensure Liner Hanger assembly does not exit 9-5/8” Window. 13. Prior to setting the hanger & packer, double check all pipe tallies and record amount of drill pipe on location. 14. Rig up to pump down workstring with rig pumps. Pressure test lines. Bleed off test pressure. WELL SP23-N3L1 SP23-N3L1 Drilling Wellplan Page 17 of 22 01/20/21 ATTACHMENTS x Recommended Drilling Practices x Health, Safety, and Environment x Safety Meeting Topics x Well Shut In Procedure While Running Tubing WELL SP23-N3L1 SP23-N3L1 Drilling Wellplan Page 18 of 22 01/20/21 Recommended Drilling Practices Hole Cleaning With a deviated well path and potential for losses, hole cleaning will require special practices. Pipe rotation is critical for effective hole cleaning. The maximum string RPM, as determined by the BHA, is specified for each hole section in the detailed procedures. The shakers should be monitored as an indicator of adequate circulating time. If circulation is of long duration, then pipe movement to prevent casing wear is critical and a stand should be laid down occasionally to prevent excess hole erosion over the length of pipe reciprocation. In addition the following practices should be employed at all times: x Use all available solids control equipment to keep mud as clean as possible. x Emphasize proper hole cleaning after slides by rotating at maximum allowable RPM x As the hole angle increases, hole cleaning practices must be altered. Maximum pipe rotating speeds along with maximum achievable flow rates will increase hole cleaning efficiencies. Circulating times prior to trips should be increased accordingly to account for longer times required to remove cuttings from higher angle wells. x Use good connection practices while drilling. After reaching the bottom of a stand, allow a small amount of circulating time to allow cuttings to get above the BHA prior to picking up off bottom. Be sure to pick up slowly to prevent packing off the cuttings bed around the top of the drill collars. Slower Trip / Connection Speeds High POOH and RIH speeds can aggravate fragile shales/formations due to the pressure variations between surge/swab. PWD data shows that excessive tripping and reaming speeds can exert pressure spikes in excess of 2 ppg equivalent. Effective ROP Strive to find the maximum effective rate of penetration. That is, the maximum rate at which a clean hole can be produced. While on bottom ROPs in excess of 400 ftph may be possible, but such ROPs may load a high angle hole with cuttings that are not being removed fast enough. Using torque and drag trends, ECD and the shakers, establish a base line clean hole ROP, and then try to improve it by altering the hole cleaning practices. Slower Initial Pump Rates PWD data has shown that the most significant period for increased ECD occurs when the pumps are brought on at drilling rate while washing a connection to bottom. The study also concluded the least damaging procedure is if pump rates are held at 40% or less of drilling rate while reaming connections. WELL SP23-N3L1 SP23-N3L1 Drilling Wellplan Page 19 of 22 01/20/21 Health, Safety & Environment The following are part of the mitigation & contingency measures to be put in place in order to complete this project while helping to meet our HS&E goals. It is the Drilling Supervisor’s responsibility that these measures are implemented and communicated to the relevant parties on location. Good communication when drilling is essential for increasing the safety of personnel and equipment. H2S Contingency Measures Assume all locations have the potential for H2S. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. Manual detectors in accordance with 20 AAC 25.065 will also be maintained on location. 3. Self-contained Breathing Apparatus for all rig personnel will be maintained on location. 4. All personnel engaged in the drilling operation will be trained in H2S emergency procedures and the use of proper personal protective equipment. 5. A standard H2S contingency plan will be posted at the rig. All rig personnel should read and familiarize themselves with this document and copies should be posted in the rig floor doghouse and in the camp on location. 6. H2S treating material for the drilling mud system will be available on location in the event that any H2Sis encountered. It is expected that the rig and personnel will have the equipment and training to identify and contain a H2Semergency situation. If it becomes necessary to notify the AOGCC of an H2S encounter, drilling will be suspended and will resume only after the development of detailed remedial and contingency procedures, full compliance with 20 AAC 25.065 and the applicable referenced sections of API RP49 and approval of the AOGCC. Lessons Learned Documentation of lessons learned has been proven to reduce downtime and increase efficiency of rig operations. It is expected that planning meetings, daily operations meetings and pre-tour meetings will be held on a regular and consistent basis and that the records of those meetings will be placed on the N drive in the appropriate folder for this well. WELL SP23-N3L1 SP23-N3L1 Drilling Wellplan Page 20 of 22 01/20/21 Safety Meeting Topics Move In, Rig Up x Prior to spud, a safety meeting should be held with the rig crews to discuss open hole drilling procedures. a. Subsidence around wellheads - use of buddy system, b. Conductor broaching operations and contingencies, c. Shallow gas hydrate drilling practices, d. Proper tripping practices and hole fill calculations with various sizes of pipe and tubing, e. Well control procedures, f. Flow rates and hole cleaning, and g. Diverter operation and crew responsibilities. x A 'Diverting Shallow Gas' drill should be held with rig crews prior to spud, unless each crew on tour has completed this drill within the past 3 months. Document drill and record on morning report. x An 'Accumulator' drill should be held with rig crews prior to spud. Document drill and record on morning report. x Shut-in drills should be held on a regularly scheduled basis. A suggested minimum is once per day on alternating tours. Document and record on morning report. x Check trip tank for leaks and confirm gauges are calibrated. Complete trip sheets and submit to the Drilling Supervisor after each trip. x Perform and document all drills. x Designate crew member to control access at the pad entrance in case of diverter operation. Surface x A 'Stripping' drill should be held with rig crews prior to drill out, unless each crew on tour has completed this drill within the past 3 months. Document drill and record on morning report. x A 'Well Kill' drill should be held with rig crews prior to drill out, unless each crew on tour has completed this drill within the past 3 months. Document drill and record on morning report. x A well kill sheet shall be posted in the doghouse and updated each tour. Intermediate x Prior to picking up the BHA a safety meeting should be held with the rig crews to discuss hole risks and open hole drilling procedures. x Potential formation pressures and mud weight, Well control procedures. x Hole cleaning best practices, flow rates. WELL SP23-N3L1 SP23-N3L1 Drilling Wellplan Page 21 of 22 01/20/21 x Stuck pipe, Lost circulation. x Proper tripping practices and hole fill calculations with various sizes of pipe and tubing. Production x Prior to picking up the BHA a safety meeting should be held with the rig crews to discuss production hole risks and open hole drilling procedures. x Potential formation pressures and mud weight, Well control procedures. x Hole cleaning best practices, flow rates. x Stuck pipe, Lost circulation. x Proper tripping practices and hole fill calculations with various sizes of pipe and tubing. Completion x Operation of the control line spooler. x Pinch points associated with tongs and slips. x Proper tripping practices and hole fill calculations with tubing and control line. x Well control practices while running production tubing with control line. x Pressure testing and minimizing personnel exposure to pressurized lines. WELL SP23-N3L1 SP23-N3L1 Drilling Wellplan Page 22 of 22 01/20/21 Well Shut In Procedure While Running Production Tubing If well is suspected to be flowing: 1. Install TIW valve and pull back to the first banding point below the BOP stack. 2. Shut off air to control line spool and bleed off line pressure while checking well for flow. 3. If well is confirmed to be flowing, cut control line with bolt cutters directly above a banding point. 4. Slack off until full joint of pipe with no control line attached is spaced out across BOP stack. 5. Close annular and monitor pressure. If well is coming in rapidly and time is not permitted to complete above operations: 1. Install TIW and close annular around pipe and control line. 2. Shut off air to control line spool and bleed off line pressure while picking up a joint of drill pipe and making it up to TIW and top drive. 3. Close IBOP on top drive and open TIW valve. 4. Cut control line and strip the joint of drill pipe across stack for ram closure if needed. 5. If annular does not seal off around tubing and control line and the joint of drill pipe cannot be safely picked up, close blind/shear rams on production tubing. 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2OLNWRN3RLQW,3% 'HI 6XUYH\ 3DVV 23 'HI6XUYH\ 3DVV 23 'HI6XUYH\ 3DVV 7KHWLV,VODQG 'HI6XUYH\ 3DVV 6''63 'HI6XUYH\ 3DVV 2,/ 3 'HI3ODQ 3DVV 2333% 'HI6XUYH\ 3DVV 2OLNWRN3RLQW 'HI6XUYH\ 3DVV 23:: 'HI6XUYH\ 3DVV 1LNDLWFKXT3% 'HI6XUYH\ 3DVV 23/3% 'HI6XUYH\ 3DVV 1LNDLWFKXT 'HI6XUYH\ 3DVV 233% 'HI6XUYH\ 3DVV 23/ 'HI6XUYH\ 3DVV 1LNDLWFKXT3% 'HI6XUYH\ 3DVV 1LNDLWFKXT 'HI6XUYH\ 3DVV 233 'HI6XUYH\ 3DVV 23 6/3% 'HI6XUYH\ 3DVV 2, 'HI6XUYH\ 3DVV 2,3% 'HI6XUYH\ 3DVV 233% 'HI6XUYH\ 3DVV 233% 'HI6XUYH\ 3DVV 2,3% 'HI6XUYH\ 3DVV 2, 'HI6XUYH\ 3DVV 233% 'HI6XUYH\ 3DVV 'ULOOLQJ2IILFH 1LNDLWFKXT?6S\,VODQG?631?631/3ODQ?631/ 3E 3DJHRI ADL 0388571ADL 0388572ADL 0388574 ADL 0388575 ADL 0388577ADL 0388581 ADL 0388582 ADL 0388583 ADL 0390615ADL 0390616 ADL 0391283603500060400006045000605000060550006060000606500060700006075000480000 490000 500000 510000 520000 530000NorthingEastingGovernmental Section Coordinates CompiledBy:CCDate:10/01/10CheckedBY:DHSDate:10/03/10SPY ISLAND DRILL SITEConductor As-BuiltsAlaska State Plane NAD83 & NAD27Lounsbury&AssociatesEniͲNikaitchuqDoc.EͲ087Rev.0'Y' 'X' Latitude(N) Longitude(W) 'Y' 'X' Latitude(N) Longitude(W) F.N.L F.E.L(USft.) (USft.)1 6,053,423.20 1,651,769.82 70°33'27.209" 149°54'24.765" 6,053,671.08 511,739.02 70°33'28.246" 149°54'13.383" 797 1171 12.42 6,053,421.65 1,651,761.87 70°33'27.194" 149°54'25.000" 6,053,669.53 511,731.06 70°33'28.231" 149°54'13.618" 798 1179 12.43 6,053,420.07 1,651,754.10 70°33'27.179" 149°54'25.229" 6,053,667.95 511,723.30 70°33'28.216" 149°54'13.847" 800 1186 12.44 6,053,418.56 1,651,746.17 70°33'27.164" 149°54'25.463" 6,053,666.44 511,715.38 70°33'28.201" 149°54'14.081" 801 1194 12.45 6,053,417.03 1,651,738.44 70°33'27.149" 149°54'25.692" 6,053,664.91 511,707.64 70°33'28.186" 149°54'14.309" 803 1202 12.46 6,053,415.54 1,651,730.54 70°33'27.134" 149°54'25.925" 6,053,664.91 511,699.74 70°33'28.171" 149°54'14.543" 804 1210 12.47 6,053,412.44 1,651,714.77 70°33'27.104" 149°54'26.391" 6,053,660.34 511,683.97 70°33'28.141" 149°54'15.009" 807 1226 12.48 6,053,410.91 1,651,706.96 70°33'27.089" 149°54'26.622" 6,053,658.80 511,676.16 70°33'28.126" 149°54'15.239" 809 1234 12.49 6,053,409.39 1,651,699.11 70°33'27.074" 149°54'26.853" 6,053,657.28 511,668.32 70°33'28.111" 149°54'15.471" 810 1241 12.410 6,053,407.94 1,651,691.31 70°33'27.060" 149°54'27.084" 6,053,655.83 511,660.51 70°33'28.097" 149°54'15.702" 812 1249 12.411 6,053,406.32 1,651,683.39 70°33'27.044" 149°54'27.318" 6,053,654.21 511,652.60 70°33'28.082" 149°54'15.935" 813 1257 12.412 6,053,404.80 1,651,675.51 70°33'27.029" 149°54'27.551" 6,053,652.82 511,644.69 70°33'28.067" 149°54'16.168" 815 1265 12.413 6,053,400.38 1,651,652.80 70°33'26.986" 149°54'28.221" 6,053,648.26 511,622.00 70°33'28.023" 149°54'16.839" 819 1288 12.414 6,053,398.83 1,651,644.95 70°33'26.971" 149°54'28.453" 6,053,646.72 511,614.15 70°33'28.008" 149°54'17.071" 821 1296 12.415 6,053,397.31 1,651,637.12 70°33'26.956" 149°54'28.685" 6,053,645.20 511,606.32 70°33'27.993" 149°54'17.302" 822 1304 12.416 6,053,395.82 1,651,629.26 70°33'26.942" 149°54'28.917" 6,053,643.71 511,598.46 70°33'27.979" 149°54'17.534" 824 1311 12.417 6,053,394.32 1,651,621.47 70°33'26.927" 149°54'29.147" 6,053,642.21 511,590.68 70°33'27.964" 149°54'17.764" 825 1319 12.418 6,053,392.78 1,651,613.58 70°33'26.912" 149°54'29.380" 6,053,640.67 511,582.79 70°33'27.949" 149°54'17.997" 827 1327 12.419 6,053,389.63 1,651,597.90 70°33'26.881" 149°54'29.843" 6,053,637.52 511,567.11 70°33'27.919" 149°54'18.460" 830 1343 12.420 6,053,388.17 1,651,590.00 70°33'26.867" 149°54'30.076" 6,053,636.06 511,559.21 70°33'27.904" 149°54'18.694" 831 1351 12.421 6,053,386.60 1,651,582.24 70°33'26.852" 149°54'30.306" 6,053,634.49 511,551.44 70°33'27.889" 149°54'18.923" 833 1358 12.422 6,053,385.19 1,651,574.35 70°33'26.838" 149°54'30.538" 6,053,633.08 511,543.56 70°33'27.875" 149°54'19.156" 834 1366 12.423 6,053,383.64 1,651,566.41 70°33'26.823" 149°54'30.773" 6,053,631.53 511,535.62 70°33'27.860" 149°54'19.391" 836 1374 12.424 6,053,382.12 1,651,558.61 70°33'26.808" 149°54'31.003" 6,053,630.01 511,527.82 70°33'27.845" 149°54'19.621" 837 1382 12.425 6,053,377.65 1,651,535.94 70°33'26.764" 149°54'31.673" 6,053,625.54 511,505.15 70°33'27.802" 149°54'20.291" 842 1405 12.426 6,053,376.14 1,651,528.13 70°33'26.750" 149°54'31.904" 6,053,624.03 511,497.34 70°33'27.787" 149°54'20.521" 843 1413 12.427 6,053,374.53 1,651,520.23 70°33'26.734" 149°54'32.137" 6,053,622.43 511,489.44 70°33'27.771" 149°54'20.754" 845 1421 12.428 6,053,373.11 1,651,512.46 70°33'26.720" 149°54'32.366" 6,053,621.01 511,481.67 70°33'27.758" 149°54'20.984" 846 1428 12.4PadElev.AlaskaStatePlane,NAD83GRID NAD83GeographicWellNo.SectionLineOffsetAlaskaStatePlane,NAD27GRID NAD27GeographicDocEͲ087ConductorAsbuiltsNAD27_NAD83.xlsx 1of211/2/2010 CompiledBy:CCDate:10/01/10CheckedBY:DHSDate:10/03/10SPY ISLAND DRILL SITEConductor As-BuiltsAlaska State Plane NAD83 & NAD27Lounsbury&AssociatesEniͲNikaitchuqDoc.EͲ087Rev.0'Y' 'X' Latitude(N) Longitude(W) 'Y' 'X' Latitude(N) Longitude(W) F.N.L F.E.LPadElev.AlaskaStatePlane,NAD83GRID NAD83GeographicWellNo.SectionLineOffsetAlaskaStatePlane,NAD27GRID NAD27Geographic29 6,053,371.56 1,651,504.49 70°33'26.705" 149°54'32.602" 6,053,619.45 511,473.70 70°33'27.742" 149°54'21.219" 848 1436 12.430 6,053,370.06 1,651,496.66 70°33'26.690" 149°54'32.833" 6,053,617.96 511,465.87 70°33'27.728" 149°54'21.451" 849 1444 12.431 6,053,367.05 1,651,480.97 70°33'26.661" 149°54'33.296" 6,053,614.95 511,450.17 70°33'27.698" 149°54'21.914" 852 1460 12.432 6,053,365.47 1,651,473.16 70°33'26.646" 149°54'33.527" 6,053,613.37 511,442.37 70°33'27.683" 149°54'22.145" 854 1468 12.433 6,053,363.93 1,651,465.22 70°33'26.631" 149°54'33.762" 6,053,611.83 511,434.43 70°33'27.668" 149°54'22.379" 855 1476 12.434 6,053,362.44 1,651,457.37 70°33'26.616" 149°54'33.993" 6,053,610.33 511,426.58 70°33'27.653" 149°54'22.611" 857 1483 12.435 6,053,360.91 1,651,449.52 70°33'26.601" 149°54'34.225" 6,053,608.81 511,418.73 70°33'27.638" 149°54'22.843" 858 1491 12.436 6,053,359.33 1,651,441.62 70°33'26.586" 149°54'34.459" 6,053,607.23 511,410.83 70°33'27.623" 149°54'23.076" 860 1499 12.437 6,053,356.19 1,651,425.30 70°33'26.555" 149°54'34.941" 6,053,604.09 511,394.51 70°33'27.592" 149°54'23.558" 863 1516 12.438 6,053,354.74 1,651,417.32 70°33'26.541" 149°54'35.177" 6,053,602.64 511,386.54 70°33'27.578" 149°54'23.794" 864 1524 12.4DocEͲ087ConductorAsbuiltsNAD27_NAD83.xlsx 2of211/2/2010 Drilling Hazards Summary 16" Open Hole / 13-3/8” Casing Interval Hazard Risk Level Mitigation Strategy Broach of Conductor Low Monitor continuously during interval. Gas Hydrates Moderate Control drill, Reduced pump rates, Reduced drilling fluid temperatures, Additions of Lecithin. Running Sands and Gravels Low Maintain planned mud parameters, Increase mud weight, use weighted sweeps. Hole swabbing on trips Moderate Trip speeds, proper hole filling (use of trip sheets), pumping out 12-1/4" Open Hole / 9-5/8” Casing Interval Hazard Risk Level Mitigation Strategy Running Sands and Gravels Low Maintain planned mud parameters, Increase mud weight, use weighted sweeps. Gas Hydrates Low Control drill, reduced pump rates, reduced drilling fluid temperatures, additions of Lecithin. Stuck Pipe Low Good hole cleaning, pre-treatment with lost circulation material, stabilized BHA, decreased mud weight Abnormal Reservoir Pressure Low BOP training and drills, increased mud weight. Lost circulation Low Reduced pump rates, mud rheology, LCM Hole swabbing on trips Moderate Trip speeds, proper hole filling (use of trip sheets), pumping out 8-1/2" Open Hole / 5-1/2” Liner Interval Hazard Risk Level Mitigation Strategy Abnormal Reservoir Pressure Low Stripping drills, shut-in drills, increased mud weight. Stuck Pipe Low Good hole cleaning, PWD tools, hole opener runs, decreased mud weight Lost Circulation Low Reduced pump rates, mud rheology, LCM Hole Swabbing on Trips Moderate Trip speeds, proper hole filling (use of trip sheets),pumping out, backreaming S P E O ENI S.p.A. E&P Division IDENTIFICATION CODE PAG 206 OF 338 REVISION STAP-P-1-M-6140 0 1 15. LEAK OFF TEST PROCEDURE A Leak-Off Test (LOT) will be performed On Wild-Cat wells at each casing shoe after setting the surface casing. LOTs are also recommended to be carried out on both appraisal and development wells. Leak Off Test and Formation Integrity Test (FIT), also termed the Limit Test, are for formation strength pressure tests made just below the casing seat prior to drilling ahead. These tests are carried out to: x Investigate the cement seal around the casing shoe which should be at least as high as the predicted fracture pressure for the area. x Investigate the wellbore capability to withstand pressures below the casing shoe in order to allow proper well planning with regard to the setting depth of the next casing, mud weights and alternatives during well control operations. x Collect regional information on formation strengths and stress magnitude for different applications including optimisation of future well planning, hole stability analysis and modelling, reservoir application. Prior to a test, a decision should be made to either increase the pressure until leak off occurs (as in the LOT) or to stop at a predetermined pressure for a (FIT). It should be noted that: x FIT does not obtain information on stress magnitude. x A LOT is designed and should be performed to determine, in a better way, the desired data without breaking down the formation. When a Formation Integrity Test is required, the maximum pumping pressure is often expressed in terms of ‘Equivalent Mud Weight’ (EMW): Im .perialunitsEMW P xTVD MW 0 052 where: P = Pumping Pressure (psi) TVD = True Vertical Depth (ft) MW = Actual Mud Weight (PPG) MWTVD 10xPEMWunitsMetric where: P = Pumping Pressure (kg/cm2) TVD = True Vertical Depth (m) MW = Actual Mud Weight (kg/l). S P E O ENI S.p.A. E&P Division IDENTIFICATION CODE PAG 207 OF 338 REVISION STAP-P-1-M-6140 0 1 LOTts or FITs can be carried out in any open hole section and at any time while drilling the hole, even if it is customary to have it performed some metres (6-15 metres) below the casing. For instance, the casing seat can be in a shale and the first sand formation may be encountered several hundred feet deeper. This will certainly be more permeable than the shale, and a test can be performed to ascertain the maximum pressure this sand can hold. If it is lower than the shale just below the casing seat, this sand becomes the limiting factor. Note Information obtained from leak-off tests in straight holes is not applicable to deviated holes in the same field and vice versa. 15.1 TEST PROCEDURE Prior to performing a formation strength test, prepare a sheet of graph paper to record pressure, versus cumulative mud volume. 1) Drill out the float equipment, clean the rat hole and drill 5m of new hole. 2) Circulate a mud quantity equal to the internal string volume plus the new hole plus 50m internal casing volumes. This mud shall be cleaned and conditioned to the density and filtrate as indicated in the Mud Programme to be used for the next drilling phase. 3) Pull the bit back into the casing shoe. 4) Rig up the cementing unit to the drill pipe. The unit shall be equipped with high precision, low pressure gauges. The range of the pressure gauge shall be selected based on the actual mud weight and the estimated (LOT) or predetermined (FIT) pressure. A pressure recorder should be used during the test. The use of the rig pumps for making these tests is unsuitable. 5) Fill and test the lines with mud. 6) Break circulation with the cementing unit to make sure that the bit nozzles are clear. Stop pumping when circulation is established. 7) Close the top pipe rams or the annular. 8) In surface well head both flanged and multistage wellheads, open the annulus of the previous casings. In sub sea well head pay attention to not excide the burst pressure of the previous casing. 9) Pump slowly and in continuous way, until pressure builds up to approximately half the anticipated maximum surface pressure. 10) Once pressure is established, pump uniform volumes of mud and wait for the time required for the pressure to stabilise. The flow rate range is from 1/8 bbl/min (20 l/min) up to a maximum of 1 bbl/min (160 l/min), however values of 0.25 bbl (121/4” and smaller holes) or 0.50 bbl (171/2” hole) are commonly used. 11) Note the cumulative mud volume pumped, the final pumping and final static pressure. 12) Repeat steps (9) and (10) above and plot pressure versus cumulative mud volume for each increment of pumped volume. S P E O ENI S.p.A. E&P Division IDENTIFICATION CODE PAG 208 OF 338 REVISION STAP-P-1-M-6140 0 1 13) Continue this procedure until: x Two or three points on the plot are reached where the pressure deviates and falls below the approximate straight line (or if the pressure does not increase with the injected volume). The point on the plot where the curve begins to bend away from the straight line is called Leak Off Point (Refer to Figure 15-1) x Or the predetermined test pressure is reached. 14) Stop pumping, shut in the well, record and plot pressure versus time until stabilisation (usually it takes 15-20min). In the early stage (2-3min) one value every 15-30sec should be collected while for the remaining a value of pressure every 30- 60sec may be sufficient. The use of PACR or an equivalent device, if available, is preferred. 15) Bleed off the pressure and record the quantity of fluid returned into the cementing unit. Compare it to the volume used for the test to obtain the amount of fluid lost to the formation. 16) Open the BOP and calculate the formation strength in terms of ‘Equivalent Mud Weight’ using the lowest between leak off point pressure and stabilised pressure. 17) Collect the data recorded during the test in a data sheet together with the following information: borehole diameter, depth of test, depth and type of the last casing, mud density, plastic viscosity, filtrate and gels (refer to the example on the next page). Note: The LOT pressure doesn’t exceed the pressure which the casing was tested. Note: When a good zonal isolation behind the casing is imperative, the Leak- off test should be carried out with a retrievable packer to avoid pressurising the casing which may cause possible permanent damage to the cement bond by the creation of micro annuli in the cement. Note: The pumping rate should be kept within the limits described in step 9). If the rate is too low, filtration losses will mask any leakage loss, or, if the rate is too high the formation may suddenly break and the leak off pressure will not be determined. Also, the longer the open hole section, the higher should be the injection rate. If the initial pumping rate is not sufficient, the well should be depressurized and the test restarted with a higher rate. Note: If a float valve is used in the drilling string, the test can not be carried out by pumping down the drill pipe. In this case rig up the cementing unit to the choke or kill line, fill and test the lines against the fail-safe and establish circulation through the riser. Close the BOP and perform the formation strength test pumping down the annulus. S P E O ENI S.p.A. E&P Division IDENTIFICATION CODE PAG 209 OF 338 REVISION STAP-P-1-M-6140 0 1 Figure 15-1 - Leak-Off Test Report 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. SP23-N03L1 221-009 X Nikaitchuq Schrader Bluff X 211-127 629-23456-00-00 X X WELL PERMIT CHECKLISTCompanyEni US Operating Company Inc.Well Name:NIKAITCHUQ SP23-N03L1Initial Class/TypeDEV / PENDGeoArea973Unit11400On/Off ShoreOffProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2210090NIKAITCHUQ, SCHRADER BLUFF OIL - 561100NA1Permit fee attachedYes2Lease number appropriateYes3Unique well name and numberYes4Well located in a defined poolYes5Well located proper distance from drilling unit boundaryYes6Well located proper distance from other wellsYes7Sufficient acreage available in drilling unitYes8If deviated, is wellbore plat includedYes9Operator only affected partyYes10Operator has appropriate bond in forceYes11Permit can be issued without conservation orderYes12Permit can be issued without administrative approvalYes13Can permit be approved before 15-day waitNA14Well located within area and strata authorized by Injection Order # (put IO# in comments) (For NA15All wells within 1/4 mile area of review identified (For service well only)NA16Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)NA18Conductor string providedNA19Surface casing protects all known USDWsNA20CMT vol adequate to circulate on conductor & surf csgNA21CMT vol adequate to tie-in long string to surf csgNoProductive liner will be completed with uncemented liner22CMT will cover all known productive horizonsYes23Casing designs adequate for C, T, B & permafrostYesRig has steel tanks; all waste to approved disposal wells24Adequate tankage or reserve pitNA25If a re-drill, has a 10-403 for abandonment been approvedYesAnti-collision analysis; no major risk failures26Adequate wellbore separation proposedNA27If diverter required, does it meet regulationsYesMax reservoir pressure is 1681.2 psig(8.6 ppg EMW); will drill w/ 9.0-9.6 ppg EMW.28Drilling fluid program schematic & equip list adequateYes29BOPEs, do they meet regulationYesMPSP is 1270 psig; will test BOPs to 3500 psig30BOPE press rating appropriate; test to (put psig in comments)Yes31Choke manifold complies w/API RP-53 (May 84)Yes32Work will occur without operation shutdownNo33Is presence of H2S gas probableNA34Mechanical condition of wells within AOR verified (For service well only)YesH2S not expected. Rig has sensors and alarms, and H2S sequestering materials are onsite.35Permit can be issued w/o hydrogen sulfide measuresYes36Data presented on potential overpressure zonesNA37Seismic analysis of shallow gas zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprDLBDate1/22/2021ApprVTLDate1/26/2021ApprDLBDate1/22/2021AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJMP 1/27/21dts 1/27/2021JLC 1/27/2021
