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Home My WebLink About216-133P?1&-133 2$2,5g Guhl, Meredith D (CED) From: Gayle Kleinschmidt <gayle@armstrongoilandgas.com> Sent: Monday, February 24, 2020 12:17 PM To: Guhl, Meredith D (CED) Cc: Doran Adams; Gayle Kleinschmidt Subject: Armstrong Horseshoe 1 Additional Core data Attachments: Horseshoe 1 core Conv description.pdf; Horseshoe 1 SWCore Description.pdf; Armstrong -Horseshoe No. 1 CO -94175 Spectral Profile.xlsx Good afternoon. This request kinda got lost amongst all the fires that needed to be put out the last few months. Hoping it is OK to send you these via email. Let us know if we are missing anything else. Gayle K. Gayle Kleinschmidt, Geotechnical Manager Armstrong Oil and Gas, Inc. 1421 Blake St. Denver, CO 802.02 gayle@armstrongoilandgas.com Direct: 303.551.9987 Cella 303.538.4624 From: Doran Adams <doran@armstrongoilandgas.com> Sent: Monday, February 24, 2020 10:30 AM To: Gayle Kleinschmidt <gayle@armstrongoilandgas.com> Subject: FW: HD Copy Complete From: Guhl, Meredith D (CED) <meredith.guhl@alaska.aov> Sent: Friday, November 15, 2019 10:16 AM To: Doran Adams <doran@armstrongoilandaas.com> Subject: RE: HD Copy Complete I'm after a gamma log measured in the laboratory on core samples. Spectral gamma is the most common nomenclature used in the archive, but I'm not sure if there's a difference between spectral gamma or core gamma? I did a full review of all wells cored by all operators for wells permitted since 2000. As you know, exploration wells have a huge collection of data with them, and apparently there are pieces missing here and there from just about every well. made a list of the "basics" and also what is required by regulations and reviewed each file. If the data doesn't exist, that's fine, but I did need to ask. Thanks, Meredith Meredith Guhl 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 GuhI at 907-793-1235 or meredith.euhlWalaska.gov. From: Doran Adams <doran@armstrongoilandaas.com> Sent: Friday, November 15, 2019 8:07 AM To: Guhl, Meredith D (CED) <meredith.euhl@alaska.aov> Subject: RE: HD Copy Complete Great, thanks! I'm also going to look a little deeper into your request you sent Gayle regarding Horseshoe 1 data. Our intend was to send you everything we had, if we missed some pieces, my apologies. You were requesting core descriptions for both conventional and sidewall core, and a "spectral gamma log". Were you wanting that "spectral gamma log" or a core gamma log? I'm not sure if we have either, but wanted to double check on what you were looking for. I'll do some more digging! Thanks again for the data dump! Doran Adams Data Systems Manager Armstrong Oil and Gas, Inc. 1421 Blake St. Denver, CO 80202 303-623-1821 Disclaimer The information contained in this communication from the sender is confidential. It is intended solely for use by the recipient and others authorized to receive it. If you are not the recipient, you are hereby notified that any disclosure, copying, distribution or taking action in relation of the contents of this information is strictly prohibited and may be unlawful. This email has been scanned for viruses and malware, and may have been automatically archived by Mimecast Ltd, an innovator in Software as a Service (SaaS) for business. Providing a safer and more useful place for your human generated data. Specializing in; Security, archiving and compliance. To find out more Click Here. Release of Confidential Data Coversheet Well Name: HORSESHOE 1 1 PTD: 216-133 E-Set: T28025, T28026, T28027, T28029, T28030, T28031, T28033, T28080, T28083, T28137, T28258, T28852 ✓ Physical data labeled with PTD, E-Set # Conf. entry: various ✓ Import CD data to RBDMS ✓ Confidential (incomplete) entry in Well Data List notes Import to DigLogs via E-Set tab Scan labeled data Apply OCR text recognition Save to Well Log Header Scans New "complete" entry in Well Data List notes Logged by: Meredith Guhl Fully logged: 5/9/2019 DATA SUBMITTAL COMPLIANCE REPORT 12/8/2017 Permit to Drill 2161330 Well Name/No. HORSESHOE 1 MD 6000 TVD 5819 Completion Date 2/18/2017 REQUIRED INFORMATION Mud Log Yes Operator ARMSTRONG ENERGY, LLC Completion Status P&A Samples Yes API No. 50-103-20751-00-00 Current Status P&A UIC No Directional Survey Yes ,/ DATA INFORMATION Types Electric or Other Logs Run: PEX, RT Scanner, NGI Imager, Sonic Scanner, HNGS, CMR, ECS, M (data taken from Logs Portion of Master Well Data Maint) Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Interval OH I Type MedlFrmt Number Name Scale Media No Start Stop CH Received Comments ED C 27936 Digital Data 10/24/2016 Electronic File: Armstrong Horseshoe Summary - AOGCC.pdf ED C 27936 Digital Data ED C 27936 Digital Data ED C 27936 Digital Data ED C 27936 Digital Data ED C 27936 Digital Data ED C 27936 Digital Data ED C 27936 Digital Data Log C 28025 Log Header Scans ED C 28025 Digital Data ED C 28025 Digital Data ED C 28025 Digital Data ED C 28025 Digital Data ED C 28025 Digital Data AOG(C Electronic File: Horseshoe_Sha I I ow_H aza rds_Study. pdf Electronic File: HS3D_PSDM_Seismic_Lines.pdf Electronic File: Altamurat_TD.xlsx Electronic File: Horseshoet_Prognosed_TD.xlsx Electronic File: ItkillikRiverUnitl_TD.xlsx Electronic File: Pioneerl_TD.xlsx Electronic File: Rendezvous2_TD.xlsx Confidential (incomplete) entry for HORSESHOE 1 Electronic Data Set, Filename: Armstrong Horseshoel IBC-MSIP-Main Pass 4 -FEB -17 Dlis- REV-A.las Electronic Data Set, Filename: Armstrong Horseshoel IBC-MSIP-Repeat Pass 4 -FEB -17 Dlis-REV-A.las Electronic File: Armstrong Horseshoel IBC- MSIP-Main Pass 4 -FEB -17 Dlis-REV-A.dlis Electronic File: Armstrong Horseshoel IBC- MSIP-Repeat Pass 4 -FEB -17 Dlis-REV-A.dlis Electronic File: Arm strong_Horseshoel-IBC- MSIP-IBC-IBC with VDL Print-4-FEB-17-REV-� A.Pdf I iiday, December 8, 2017 10/24/2016 10/24/2016 10/24/2016 10/24/2016 10/24/2016 10/24/2016 10/24/2016 0 0 2081 104 3/2/2017 2106 1752 3/2/2017 3/2/2017 3/2/2017 3/2/2017 Page 1 o1'33 Electronic File: Horseshoe_Sha I I ow_H aza rds_Study. pdf Electronic File: HS3D_PSDM_Seismic_Lines.pdf Electronic File: Altamurat_TD.xlsx Electronic File: Horseshoet_Prognosed_TD.xlsx Electronic File: ItkillikRiverUnitl_TD.xlsx Electronic File: Pioneerl_TD.xlsx Electronic File: Rendezvous2_TD.xlsx Confidential (incomplete) entry for HORSESHOE 1 Electronic Data Set, Filename: Armstrong Horseshoel IBC-MSIP-Main Pass 4 -FEB -17 Dlis- REV-A.las Electronic Data Set, Filename: Armstrong Horseshoel IBC-MSIP-Repeat Pass 4 -FEB -17 Dlis-REV-A.las Electronic File: Armstrong Horseshoel IBC- MSIP-Main Pass 4 -FEB -17 Dlis-REV-A.dlis Electronic File: Armstrong Horseshoel IBC- MSIP-Repeat Pass 4 -FEB -17 Dlis-REV-A.dlis Electronic File: Arm strong_Horseshoel-IBC- MSIP-IBC-IBC with VDL Print-4-FEB-17-REV-� A.Pdf I iiday, December 8, 2017 DATA SUBMITTAL COMPLIANCE REPORT 12/8/2017 Permit to Drill 2161330 Well Name/No. HORSESHOE 1 MD 6000 TVD 5819 Completion Date 2/18/2017 ED C 28025 Digital Data ED C 28025 Digital Data ED C 28026 Digital Data ED C 28026 Digital Data ED C 28026 Digital Data ED C 28026 Digital Data ED C 28026 Digital Data ED C 28026 Digital Data ED C 28026 Digital Data ED C 28026 Digital Data Log C 28026 Log Header Scans ED C 28027 Digital Data ED C 28027 Digital Data ED C 28027 Digital Data AOGCC Operator ARMSTRONG ENERGY, LLC API No. 50-103-20751-00-00 Completion Status P&A Current Status P&A UIC No 3/2/2017 Electronic File: Armstrong_Horseshoel-IBC- 0 P MSIP-Isolation Scanner Print-4-FEB-I7-REV- A.Pdf 3/2/2017 Electronic File: Armstrong_Horseshoel-IBC- P MSIP-MSIP CBL Print-4-FEB-17-REV-A.Pdf 6020 2039 3/2/2017 Electronic Data Set, Filename: Armstrong_HorseShoe 1_PEX-ZAIT_Main pass 6000-2213ft_basic.las 4967 4542 3/2/2017 Electronic Data Set, Filename: Armstrong_HorseShoe 1_PEX-ZAIT_Repeat pass 4690-4890ft_basic.las 3/2/2017 Electronic File: Armstrong_HorseShoe 1_PEX- ZAIT_Mam pass 6000-2213ft.dlis 3/2/2017 Electronic File: Armstrong_HorseShoe 1_PEX- ZAIT_Repeat pass 4690-4890ft.dlis 3/2/2017 Electronic File: p Armstrong_HomeShoe_1_R201_TD-PEX- e 1 GR_2in.Pdf 3/2/2017 Electronic File: P Armstrong_HorseShoe_1_R2D1_TD-PEX-.o GR 5in.Pdf 3/2/2017 Electronic File: Armstrong_HomeShoe_l_R2D1_ZAIT- GR_2in.Pdf ' 3/2/2017 Electronic File: Armstrong_HorseShoe_1_R2D7_ZAIT-e P GR_5in.Pdf 0 0 Confidential (incomplete) entry for HORSESHOE 1 2102 6000 3/2/2017 Electronic Data Set, Filename: Armstrong_HorseShoe 1_NGI Main Pass 6000- 2213.1as 4963 4660 3/2/2017 Electronic Data Set, Filename: Armstrong_HorseShoe 1_NGI Repeat Pass 4690-4890.las 3/2/2017 Electronic File: Armstrong_HorseShoe 1_NGI Main Pass 6000-2213.dlis Page 2 of 33 Friday, December 8, 2017 DATA SUBMITTAL COMPLIANCE REPORT 12/8/2017 Permit to Drill 2161330 Well Name/No. HORSESHOE 1 Operator ARMSTRONG ENERGY, LLC API No. 50.103-20751-00-00 MD 6000 TVD 5819 Completion Date 2/18/2017 Completion Status P&A Current Status P&A UIC No ED C 28027 Digital Data 3/2/2017 Electronic File: Armstrong_HorseShoe 1_NGI Repeat Pass 4690-4890.diis ED C 28027 Digital Data 3/2/2017 Electronic File: Armstrong_HorseShoe _1_R2D2_NGI- ° GR_5in.Pdf ED C 28027 Digital Data 3/2/2017 Electronic File: Armstrong_HorseShoe_i_R2D2_NGI- O GR_60in.Pdf Log C 28027 Log Header Scans 0 0 Confidential (incomplete) entry for HORSESHOE 1 Log C 28028 Log Header Scans 0 0 Confidential (incomplete) entry for HORSESHOE 1 ED C 28028 Digital Data 6012 2196 3/2/2017 Electronic Data Set, Filename: Armstrong_HorseShoe 1_MSIP-PPC Main Pass 6000-2213.1as ED C 28028 Digital Data 4973 4582 3/2/2017 Electronic Data Set, Filename: Armstrong_HorseShoe 1_MSIP-PPC Repeat Pass 4690-4890.1as ED C 28028 Digital Data 3/2/2017 Electronic File: Armstrong_HorseShoe 1_MSIP- PPC Main Pass 6000-2213.diis ED C 28028 Digital Data 3/2/2017 Electronic File: Armstrong_HorseShoe 1_MSIP- PPC Repeat Pass 4690-4890.dlis ED C 28028 Digital Data 3/2/2017 Electronic File: Armstrong_HorseShoe_7_R2D2_ ' P 4 Arm Caliper_2in.Pdf ED C 28028 Digital Data 3/2/2017 Electronic File: Armstrong_ HorseShoe_1_R2D2_ 1P 4 Arte Caliper_5in.Pdf ED C 28028 Digital Data 3/2/2017 Electronic File: Armstrong_HorseShoe_1_R2D2_MSIP- ° ,e PPC_2in.Pdf ED C 28028 Digital Data 3/2/2017 Electronic File: Armstrong_HorseShoe_i_R202_MSIP- PPC_5in.Pdf Log C 28029 Log Header Scans 0 0 Confidential (incomplete) entry for HORSESHOE 1 ED C 28029 Digital Data 6006 2209 3/2/2017 Electronic Data Set, Filename: Armstrong_HorseShoe 1_CMR-HNGS-ECS- Main Pass 6000-2213.1as AOGCC Page 3 of 33 Friday, December 8, 2017 DATA SUBMITTAL COMPLIANCE REPORT 12/8/2017 Permit to Drill 2161330 Well Name/No. HORSESHOE 1 MD 6000 TVD 5819 Completion Date 2/18/2017 ED C 28029 Digital Data ED C ED C ED C ED C ED C Log C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C 28029 Digital Data 28029 Digital Data 28029 Digital Data 28029 Digital Data 28029 Digital Data 28030 Log Header Scans 28030 Digital Data 28030 Digital Data 28030 Digital Data 28030 Digital Data 28030 Digital Data 28030 Digital Data 28030 Digital Data 28030 Digital Data 28030 Digital Data 28030 Digital Data 28030 Digital Data Operator ARMSTRONG ENERGY, LLC API No. 50-103-20751-00-00 Completion Status P&A Current Status P&A UIC No 5000 4608 3/2/2017 Electronic Data Set, Filename: Armstrong_HorseShoe 1_CMR-HNGS-ECS- Repeat Pass 4690-4890.1as 3/2/2017 Electronic File: Armstrong_HorseShoe 1_CMR- HNGS-ECS-Main Pass 6000-2213.diis 3/2/2017 Electronic File: Amistrong_HorseShoe 1_CMR- HNGS-ECS-Repeat Pass 4690-4890.diis 3/2/2017 Electronic File: Armstrong_HorseShoe , 1_R2D3_ECS-GR_5in.Pdf 3/2/2017 Electronic File: Armstrong_HorseShoe . 1_R2D3_HNGS_5in.Pdf Electronic File: Armstrong_HorseShoe , P3/2/2017 1 _R2 D3_CMR-GR_5in. Pdf 0 0 Confidential (incomplete) entry for HORSESHOE 1 3/2/2017 Electronic File: ConPr R05_Sta001 MDT_EDTA.dlis 3/2/2017 Electronic File: ConPr_R05 Sta002_MOT_EDTA.dlis 3/2/2017 Electronic File: ConPr_R05 Sta003_MDT_EDTA.dlis 3/2/2017 Electronic File: ConPr_R05_Sta004_MDT_EDTA.dlis 3/2/2017 Electronic File: ConPr_R05 Sta005_MDT_EDTA.dlis 3/2/2017 Electronic File: ConPr_R05_Sta006_MDT_E DTA. dlis 3/2/2017 Electronic File: Con Pr_R05_Sta007_MDT_EDTA.d lis 3/2/2017 Electronic File: ConPr_R05 Sta008_MDT_EDTA.dlis 3/2/2017 Electronic File: ConPr R05 Sta009 MDT EDTA.dlis 3/2/2017 Electronic File: ConPr_R05 Sta010_MDT_EDTA.dlis 3/2/2017 Electronic File: ConPr R05 Sta011 MDT EDTA.dlis AOGCC Page 4 of 33 Friday, December 8, 2017 DATA SUBMITTAL COMPLIANCE REPORT 12/812017 Permit to Drill 2161330 Well Name/No. HORSESHOE 1 MD 6000 TVD 5819 Completion Date 2/18/2017 ED C 28030 Digital Data ED C 28030 Digital Data ED C 28030 Digital Data ED C 28030 Digital Data ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C 28030 Digital Data 28030 Digital Data 28030 Digital Data 28030 Digital Data 28030 Digital Data 28030 Digital Data 28030 Digital Data 28030 Digital Data 28030 Digital Data 28030 Digital Data 28030 Digital Data 28030 Digital Data 28030 Digital Data 28030 Digital Data Operator ARMSTRONG ENERGY, LLC API No. 50.103-20751-00-00 Completion Status P&A Current Status P&A UIC No 3/2/2017 Electronic File: Con Pr_R05_Sta012_MDT_EDTA.d lis 3/2/2017 Electronic File: Con Pr_R05_Sta013_MDT_E DTA.dl is 3/2/2017 Electronic File: ConPr_R05 Sta014_MDT_EDTA.dlis 3/2/2017 Electronic File: ConPr_R05 Sta015_MDT_EDTA.dlis 3/2/2017 Electronic File: ConPr_R05 Sta016_MDT_EDTA.dlis 3/2/2017 Electronic File: ConPr_R05 Sta017_MDT_EDTA.dlis 3/2/2017 Electronic File: ConPr_R05_Sta018_MDT_EDTA.dlis 3/2/2017 Electronic File: ConPr_R05 Sta019_MDT_EDTA.dlis 3/2/2017 Electronic File: ConPr_R05 Sta020_MDT_EDTA.dlis 3/2/2017 Electronic File: ConPr_R05 Sta021_MDT_EDTA.dlis 3/2/2017 Electronic File: ConPr_R05 S1a022_MDT_EDTA.dlis 3/2/2017 Electronic File: ConPr_R05 Sta023_MDT_EDTA.dlis 3/2/2017 Electronic File: ConPr_R05 Sta024_MDT_EDTA.dlis 3/2/2017 Electronic File: ConPr_R05 Sta025_MDT_EDTA.dlis 3/2/2017 Electronic File: ConPr_R05 Sta026_MDT_EDTA.dlis 3/2/2017 Electronic File: ConPr_R05 Sta027_MDT_EDTA.dlis 3/2/2017 Electronic File: D 11 Armstrong_Horseshoe_1_R2D4_MDT.Pdf , 3/2/2017 Electronic File: Armstrong_Horseshoe_l _RSA_Sam pling_Report .pdf AOGCC Page 5 of 33 Friday, December 8, 2017 DATA SUBMITTAL COMPLIANCE REPORT 1218/2017 Permit to Drill 2161330 Well Name/No. HORSESHOE 1 Operator ARMSTRONG ENERGY, LLC API No. 50-103-20751.00.00 MD 6000 TVD 5819 Completion Date 2/18/2017 Completion Status P&A Current Status P&A UIC No ED C 28031 Digital Data 4773 3148 3/2/2017 Electronic Data Set, Filename: Armstrong_HorseShoe 1_R2D5_5in XLRock Correlation Pass.las ED C 28031 Digital Data 42781 42782 3/2/2017 Electronic Data Set, Filename: Armstrong_HorseShoe1 R2D5_5inXL Rock Customer XLRock Station Log.las ED C 28031 Digital Data 3/2/2017 Electronic File: Armstrong_HorseShoe -- 1_R2D5 5in XLRock Correlation Pass.dlis ED C 28031 Digital Data 3/2/2017 Electronic File: Armstrong_HorseShoe 1 R2D5 5inXL Rock Customer XLRock Station Log.dlis ED C 28031 Digital Data 3/2/2017 Electronic File: Armstrong -Horseshoe P , 1_R2D5_XL Rock Summary.pdf Log C 28031 Log Header Scans 0 0 Confidential (incomplete) entry for HORSESHOE 1 Log C 28031 Log Header Scans 0 0 Confidential (incomplete) entry for HORSESHOE 1 ED C 28033 Digital Data 3/7/2017 Electronic File: P Armstrong_Horseshoe_1 8.5in_MDT— Downhole— Fluid—Analysis_revl .pdf Log C 28033 Log Header Scans 0 0 Confidential (incomplete) entry for HORSESHOE 1 Log C 28080 Log Header Scans 0 0 Confidential (incomplete) entry for HORSESHOE 1 ED C 28080 Digital Data 95 6000 3/21/2017 Electronic Data Set, Filename: �}l� Armstrong_Horseshoe#1_MEM_110-6000.1as 1.A ED C 28080 Digital Data 3/21/2017 Electronic File: Armstrong_Horseshoe#1 _AP_MEM_2017-02- 12.cgm ED C 28080 Digital Data 3/21/2017 Electronic File: Armstrong_Horseshoe#1 _M D2ME M_110- 6000_2017-02-12.cgm ED C 28080 Digital Data 3/21/2017 Electronic File: Armstrong_Horseshoe#1 _M D5ME M_110- 6000_2017-02-12.cgm ED C 28080 Digital Data 3/21/2017 Electronic File: Armstrong_Horseshoe#1_TVD2MEM_110- 6000_2017-02-12.cgm AOGCC Page 6 of 33 Friday, December 8, 2017 AOGCC Page 7 of 33 Friday, December 8, 2017 DATA SUBMITTAL COMPLIANCE REPORT 12/812017 Permit to Drill 2161330 Well Name/No. HORSESHOE 1 Operator ARMSTRONG ENERGY, LLC API No. 50.103-20751-00-00 MD 6000 TVD 5819 Completion Date 2/18/2017 Completion Status P&A Current Status P&A UIC No ED C 28080 Digital Data 3/21/2017 Electronic File: Armstrong_Horseshoe#1 _T V D5ME M_110- 6000_2017-02-12.cgm ED C 28080 Digital Data 3/21/2017 Electronic File: Armstrong_Horseshoe#1_AP_MEM_2017-02- 12.PDF ED C 28080 Digital Data 3/21/2017 Electronic File: D Armstrong_Horseshoe#1_MD2ME1V1_110-' 6000_2017-02-12.PDF ED C 28080 Digital Data 3/21/2017 Electronic File: Armstrong_Homeshoe#1 M_110 - P _MD5ME 6000_2017-02-12.PDF ED C 28080 Digital Data 3/21/2017 Electronic File: Armstrong_Horseshoe#1 _T V D2MEM_110- 6000 2017-02-12.PDF ED C 28080 Digital Data 3/21/2017 Electronic File: Armstrong_Horseshoe#1_TVD5MEM_110- . 6000_2017-0 2-12. P D F ED C 28080 Digital Data 3/21/2017 Electronic File: Horseshoe#1 Definitive Surveys.pdf ED C 28080 Digital Data 3/21/2017 Electronic File: Horseshoe#1 Definitive Surveys.xlsx ED C 28080 Digital Data 3/21/2017 Electronic File: Horseshoe#1 FinalSurvey.pdf ED C 28080 Digital Data 3/21/2017 Electronic File: Horseshoe#1 FinalS� ED C 28083 Digital Data 10 6050 3/31/2017 11 -- Electronic Data Set, Filenamee: Horses ,d,tv, ED C 28083 Digital Data 3/31/2017 Electronic File: HORSESHOEt_tvd.dbf ED C 28083 Digital Data 3/31/2017 Electronic File: HORSESHOE1_tvd.mdx ED C 28083 Digital Data 3/31/2017 Electronic File: Horseshoet.dbf ED C 28083 Digital Data 3/31/2017 Electronic File: Horseshoel.mdx ED C 28083 Digital Data 3/31/2017 Electronic File: Horseshoel_SCL.DBF ED C 28083 Digital Data 3/31/2017 Electronic File: Horseshoel_SCL.MDX ED C 28083 Digital Data 3/31/2017 Electronic File: horseshoet.hdr ED C 28083 Digital Data 3/31/2017 Electronic File: horseshoelr.dbf ED C 28083 Digital Data 3/31/2017 Electronic File: horseshoelr.mdx AOGCC Page 7 of 33 Friday, December 8, 2017 DATA SUBMITTAL COMPLIANCE REPORT 12/8/2017 Permit to Drill MD 6000 2161330 Well Name/No. HORSESHOE 1 TVD 5819 Completion Date 2/18/2017 Operator ARMSTRONG ENERGY, LLC API No. 50-103-20751-00-00 Completion Status P&A Current Status P&A UIC No ED C 28083 Digital Data 3/31/2017 Electronic File: Armstrong Midnight REPORT 1- 27-17-W 10.pdf ED C 28083 Digital Data 3/31/2017 Electronic File: Armstrong Midnight REPORT 1- 28-17-W 10.pdf ED C 28083 Digital Data 3/31/2017 Electronic File: Armstrong Midnight REPORT 1- 29-17-W 10.pdf ED C 28083 Digital Data 3/31/2017 Electronic File: Armstrong Midnight REPORT 1- 30-17-W t O.pdf ED C 28083 Digital Data 3/31/2017 Electronic File: Armstrong Midnight REPORT 1- 31-17-W IO.pdf ED C 28083 Digital Data 3/31/2017 Electronic File: Armstrong Midnight REPORT 2- 01-17-W 1 O.pdf ED C 28083 Digital Data 3/31/2017 Electronic File: Armstrong Midnight REPORT 2- 02-17-W10.pdf ED C 28083 Digital Data 3/31/2017 Electronic File: Armstrong Midnight REPORT 2- 03-17-W10.pdf ED C 28083 Digital Data 3/31/2017 Electronic File: Armstrong Midnight REPORT 2- 04-17-W10.pdf ED C 28083 Digital Data 3/31/2017 Electronic File: Armstrong Midnight REPORT 2- 05-17-W 10.pdf ED C 28083 Digital Data 3/31/2017 Electronic File: Armstrong Midnight REPORT 2- 06-17-W 10.pdf ED C 28083 Digital Data 3/31/2017 Electronic File: Armstrong Midnight REPORT 2- 07-17-W 10.pdf ED C 28083 Digital Data 3/31/2017 Electronic File: Armstrong Midnight REPORT 2- 08-17-W 10.pdf ED C 28083 Digital Data 3/31/2017 Electronic File: Armstrong Midnight REPORT 2- 09-17-W10.pdf ED C 28083 Digital Data 3/31/2017 Electronic File: Armstrong Midnight REPORT 2- 10-17-W10.pdf ED C 28083 Digital Data 3/31/2017 Electronic File: Armstrong Midnight REPORT 2- 11-17-W10.pdf ED C 28083 Digital Data 3/31/2017 Electronic File: Armstrong Midnight REPORT 2- 12-17-W t 0.pdf ED C 28083 Digital Data 3/31/2017 Electronic File: Armstrong Midnight REPORT 2- AOGCC Page 8 of 33 Friday, December 8, 2017 DATA SUBMITTAL COMPLIANCE REPORT 12/8/2017 Permit to Drill 2161330 Well Name/No. HORSESHOE 1 Operator ARMSTRONG ENERGY, LLC API No. 50-103-20751-00-00 MD 6000 TVD 5819 Completion Date 2/18/2017 Completion Status P&A ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data AOGCC Page 9 of 33 Current Status P&A UIC No 3/31/2017 Electronic File: Armstrong Midnight REPORT 2- 14-17-W 10.pdf 3/31/2017 Electronic File: Armstrong Midnight REPORT 2- 15-17-W10.pdf 3/31/2017 Electronic File: Armstrong Midnight REPORT 2- 16-17-W 10.pdf 3/31/2017 Electronic File: Armstrong Horseshoe 1 Final Well Report TD.doc 3/31/2017 Electronic File: Armstrong Horseshoe 1 Final. I? Well Report.pdf 3/31/2017 Electronic File: HORSESHOE 1 - Drilling. P Dynamics Log MD.pdf 3/31/2017 Electronic File: HORSESHOE 1 - Drilling. tp Dynamics Log TVD.pdf 3/31/2017 Electronic File: HORSESHOE 1 - Formation Log rJ MD.pdf 3/31/2017 Electronic File: HORSESHOE 1 - Formation Log , P TVD.pdf 3/31/2017 Electronic File: HORSESHOE 1 - Gas Ratio Log , (1 1'3/31/2017 MD.pdf Electronic File: HORSESHOE 1 - Gas Ratio Log ' O TVD.pdf 3/31/2017 Electronic File: HORSESHOE 1 - LWD Combo . n Log MD.pdf 3/31/2017 Electronic File: HORSESHOE 1 - LWO Combo P Log TVD.pdf 3/31/2017 Electronic File: HORSESHOE 1 - DRILLING. DYNAMICS LOG MD.tif 3/31/2017 Electronic File: HORSESHOE 1 - DRILLING DYNAMICS LOG TVD.tif 3/31/2017 Electronic File: HORSESHOE 1 - FORMATION , LOG MO.tif 3/31/2017 Electronic File: HORSESHOE 1 - FORMATION LOG TVD.tif 3/31/2017 Electronic File: HORSESHOE 1 - GAS RATIO LOG MD.tif Friday, December 8, 2017 DATA SUBMITTAL COMPLIANCE REPORT 12/8/2017 Permit to Drill 2161330 Well Name/No. HORSESHOE 1 MD 6000 TVD 5819 Completion Date 2/18/2017 ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data Operator ARMSTRONG ENERGY, LLC API No. 50-103-20751-00-00 Completion Status P&A Current Status P&A UIC No 3/31/2017 Electronic File: HORSESHOE 1 - GAS RATIO LOG TVD.tif 3/31/2017 Electronic File: HORSESHOE 1 - LW D COMBO LOG MD.tif 3/31/2017 Electronic File: HORSESHOE 1 - LWD COMBO LOG TVD.tif 3/31/2017 Electronic File: Horseshoe #1 120.jpg 3/31/2017 Electronic File: Horseshoe #1 1200.jpg 3/31/2017 Electronic File: Horseshoe #1 1300.jpg 3/31/2017 Electronic File: Horseshoe #1 1400.jpg 3/31/2017 Electronic File: Horseshoe #1 1530.jpg 3/31/2017 Electronic File: Horseshoe #1 1531.jpg 3/31/2017 Electronic File: Horseshoe #1 1695.jpg 3/31/2017 Electronic File: Horseshoe #1 1725.jpg 3/31/2017 Electronic File: Horseshoe #1 1750.jpg 3/31/2017 Electronic File: Horseshoe #1 1751.jpg 3/31/2017 Electronic File: Horseshoe #1 1753.jpg 3/31/2017 Electronic File: Horseshoe #1 1780.jpg 3/31/2017 Electronic File: 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Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data Completion Date 2/18/2017 Operator ARMSTRONG ENERGY, LLC API No. 50-103-20751-00-00 Completion Status P&A AOGCC Page 11 of 33 Current Status P&A UIC No 3/31/2017 Electronic File: Horseshoe #1 2230.jpg 3/31/2017 Electronic File: Horseshoe #1 240.jpg 3/31/2017 Electronic File: Horseshoe #1 241.jpg 3/31/2017 Electronic File: Horseshoe #1 2650.jpg 3/31/2017 Electronic File: Horseshoe #1 270.jpg 3/31/2017 Electronic File: Horseshoe #1 2820.jpg 3/31/2017 Electronic File: Horseshoe #1 2910.jpg 3/31/2017 Electronic File: Horseshoe #1 3000.jpg 3/31/2017 Electronic File: Horseshoe #1 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December 8, 2017 DATA SUBMITTAL COMPLIANCE REPORT 12/8/2017 Permit to Drill 2161330 Well Name/No. HORSESHOE 1 MD 6000 TVD 5819 ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C _ 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data ED C 28083 Digital Data Operator ARMSTRONG ENERGY, LLC API No. 50-103-20751.00-00 Completion Date 2/18/2017 Completion Status P&A Current Status P&A UIC No 3/31/2017 Electronic File: Horseshoe #1 4425.jpg 3/31/2017 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Electronic File: Horseshoe #1 4753a.jpg 3/31/2017 Electronic File: Horseshoe #1 4755.jpg 3/31/2017 Electronic File: Horseshoe #1 4760.jpg 3/31/2017 Electronic File: Horseshoe #1 510.jpg 3/31/2017 Electronic File: Horseshoe #1 540.jpg 3/31/2017 Electronic File: Horseshoe #1 690.jpg 3/31/2017 Electronic File: SHOW REPORT#1 Horseshoe #1.pdf AOGCC Page 12 of 33 Friday, December 8. 2017 DATA SUBMITTAL COMPLIANCE REPORT 12/8/2017 Permit to Drill 2161330 Well NamelNo. HORSESHOE 1 MD 6000 TVD 5819 Completion Date 2/18/2017 ED C 28083 Digital Data ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C 28083 Digital Data 28083 Digital Data 28083 Digital Data 28083 Digital Data 28083 Digital Data 28083 Digital Data 28083 Digital Data 28083 Digital Data 28083 Digital Data 28083 Digital Data 28083 Digital Data 28083 Digital Data 28083 Digital Data 28083 Digital Data 28083 Digital Data 28083 Digital Data 28083 Digital Data Operator ARMSTRONG ENERGY, LLC API No. 50-103-20751-00-00 Completion Status P&A Current Status P&A UIC No 3/31/2017 Electronic File: SHOW REPORT #2 Horseshoe #1.pdf 3/31/2017 Electronic File: SHOW REPORT #3 Horseshoe #1.pdf 3/31/2017 Electronic File: SHOW REPORT #4 Horseshoe #1.pdf 3/31/2017 Electronic File: SHOW REPORT #5 Horseshoe #1.pdf 3/31/2017 Electronic File: SHOW REPORT #1 Horseshoe #1 Pixler.pdf - 3/31/2017 Electronic File: SHOW REPORT #1 Horseshoe #1.pdf 3/31/2017 Electronic File: SHOW REPORT #1 Horseshoe #1.xls 3/31/2017 Electronic File: SHOW REPORT #2 Horseshoe #1 Pixler.pdf 3/31/2017 Electronic File: SHOW REPORT #2 Horseshoe #1.pdf 3/31/2017 Electronic File: SHOW REPORT #2 Horseshoe #1.xls 3/31/2017 Electronic File: SHOW REPORT #3 Horseshoe #1 Pixler.pdf 3/31/2017 Electronic File: SHOW REPORT #3 Horseshoe #1.pdf 3/31/2017 Electronic File: SHOW REPORT #3 Horseshoe #1.xls 3/31/2017 Electronic File: SHOW REPORT #4 Horseshoe #1 Pixler.pdf 3/31/2017 Electronic File: SHOW REPORT #4 Horseshoe #1.pdf 3/31/2017 Electronic File: SHOW REPORT #4 Horseshoe #1.xls 3/31/2017 Electronic File: SHOW REPORT #5 Horseshoe #1 Pixler.pdf 3/31/2017 Electronic File: SHOW REPORT #5 Horseshoe #1.pdf AOGCC Page 13 of 33 Friday, December 8, 2017 DATA SUBMITTAL COMPLIANCE REPORT 12/8/2017 Permit to Drill 2161330 Well Name/No. HORSESHOE 1 MD 6000 TVD 5819 Completion Date 2/18/2017 ED C 28083 Digital Data Log C ED C ED C ED C ED C ED C ED C ED C Log C ED C ED C ED C ED C ED C ED C 28083 Log Header Scans 089 Digital Data 28089 Digital Data 28089 Digital Data 28089 Digital Data 28089 Digital Data 28089�Data 89 Digital Data 28089 Log Header Scans 28137 Digital Data 28137 Digital Data 28137 Digital Data 28137 Digital Data 28137 Digital Data 28137 Digital Data Operator ARMSTRONG ENERGY, LLC API No. 50-103-20751-00-00 Completion Status P&A Current Status P&A UIC No 3/31/2017 Electronic File: SHOW REPORT #5 Horseshoe #1.xls 0 0 Confidential (incomplete) entry for HORSESHOE 1 2081 104 3/28/2017 Electronic Data Set, Filena 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Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data EO C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data AOGCC Operator ARMSTRONG ENERGY, LLC Completion Status P&A Page 15 of 33 API No. 50-103-20751-00-00 Current Status P&A UIC No 4/18/2017 Electronic File: Armstrong_Horseshoel _Bed_Boundary_All_Hist ogmm_2244-5983.jpg 4/18/2017 Electronic File: Armstrong_Horseshoel Bed_ Boundary_AII_Ros e_Azimuth_2244-5983.jpg 4/18/2017 Electronic File: Armstrong_Homeshoet_Bed_Boundary_AII_Ros e_Strike_2244-5983.jpg 4/18/2017 Electronic File: Armstrong_Homeshoel _Bed_Boundary_All_Ster eonet_2244-5983.jpg 4/18/2017 Electronic File: Armstrong_Homeshoel Bed_Boundary_AII_Vect or_Plot_2244-5983.jpg 4/18/2017 Electronic File: Armstrong_Homeshoel_Bed_Boundary_Mcu_His togram_2108-2492.jpg 4/18/2017 Electronic File: Armstrong _Homeshoel 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C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data AOGCC Operator ARMSTRONG ENERGY, LLC API No. 50-103-20751-00-00 Completion Status P&A Page 16 of 33 Current Status P&A UIC No 4/18/2017 Electronic File: Armstrong_Horseshoel_Bed_Boundary_Nanush uk 1_Stereonet_5582-5983.jpg 4/18/2017 Electronic File: Armstrong_HorseshoelBed_Boundary_Nanush uk 1_Vector_Plot _5582-5983.jpg 4/18/2017 Electronic File: Armstrong_ Homeshoel_Bed_Boundary_Nanush uk 2_Histogram_4881-5582.jpg 4/18/2017 Electronic File: Armstrong_Horseshoel_Bed _Boundary_Nanush uk 2_Rose_Azimuth _4881-5582.jpg 4/18/2017 Electronic File: Armstrong_Horseshoel Bed Boundary_Nanush uk 2_Rose_Strike_4881-5582.jpg 4/18/2017 Electronic File: Armstrong_Horseshoel _Bed_Boundary_Nanush uk 2_Stereonet_4881-5582.jpg 4/18/2017 Electronic File: Armstrong_HorseshoelBed_Boundary_Nanush uk 2_Vector_Plot_4881-5582.jpg 4/18/2017 Electronic File: Armstrong_Horseshoel Bed_Boundary_Nanush uk 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Friday, December 8, 2017 DATA SUBMITTAL COMPLIANCE REPORT 12/812017 Permit to Drill 2161330 Well Name/No. HORSESHOE 1 Operator ARMSTRONG ENERGY, LLC API No. 50-103-20751-00-00 MD 6000 TVD 5819 Completion Date 2/18/2017 Completion Status P&A Current Status P&A UIC No ED C 28137 Digital Data 4/18/2017 Electronic File: Armstrong_Horseshoel_BH_Stress_Nanushuk 7_Histogram_4257-4390.jpg ED C 28137 Digital Data 4/18/2017 Electronic File: Armstrong_Homeshoel _BH_Stress_Nan ushuk 7_Rose_Azimuth_42574390.jpg ED C 28137 Digital Data 4/18/2017 Electronic File: Armstmng_Horseshoel BH Stress_Nanushuk 7_Rose_Azimuth_Mirror_4257-4390.jpg ED C 28137 Digital Data 4/18/2017 Electronic File: Armstrong_Homeshoel BH_Stress_Nanushuk 7_Stereonet_4257-4390.jpg ED C 28137 Digital Data 4/18/2017 Electronic File: Armstrong_Horseshoel _B H_ Stress_Nanushuk 7_Vector_Plot _4257-4390.jpg ED C 28137 Digital Data 4/18/2017 Electronic File: Armstrong_Horseshoel _BH_Stress_Nanushuk_ H istogram_4214-4257.jpg ED C 28137 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LLC API No. 50-103-20751-00-00 MD 6000 TVD 5819 Completion Date 2/18/2017 Completion Status P&A ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data Current Status P&A UIC No 4/18/2017 Electronic File: Armstrong _Horseshoe1 _B H_ Stress_Tuluvak_Ste reon et_2492-4214.j pg 4/18/2017 Electronic File: Amrstrong_Horseshoel BH_ Stress_Tuluvak_Ve ctor_Plot_2492-4214.jpg 4/18/2017 Electronic File: Armstrong_Homeshoel Deformed_Beddmg_AII_ Histogram_2244-5983.jpg 4/18/2017 Electronic File: Armstrong_Horseshoel Deformed Bedding_?kll_ Rose—Azimuth 2244-5983.jpg 4/18/2017 Electronic File: Armstrong_Horseshoe l _Deformed_Bedding_AII_ Rose_Strike_2244-5983.jpg 4/18/2017 Electronic File: Armstrong_Homeshoel Deformed_Bedding_AII_ 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Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data AOGCC Operator ARMSTRONG ENERGY, LLC API No. 50-103-20751-00-00 Completion Status P&A Page 23 of 33 Current Status P&A UIC No 4/18/2017 Electronic File: Armstrong_Homeshoel_Deformed_Bedding_Nan ushuk 1_Rose_Azimuth_5582-5983.jpg 4/18/2017 Electronic File: Armstrong_Horseshoel Deformed Bedding Nan ushuk 1 Rose_ Strike_ 5582-5983.jpg 4/18/2017 Electronic File: Armstrong_Horseshoel Deformed Bedding Nan ushuk 1_Stereonet_5582-5983.jpg 4/18/2017 Electronic File: Armstrong_Horseshoel _Deformed_Bedding_Nan ushuk 1—Vector _ Plot_ 5582-5983.jpg 4/1812017 Electronic File: Armstrong_Horseshoe l_Deformed_Bedding_Nan ushuk 2_Histogram_4881-5582.jpg 4/18/2017 Electronic File: Armstrong_ Horseshoet_Deformed Bedding_Nan ushuk 2_Rose_Azimuth_4881-5582.jpg 4/18/2017 Electronic File: Armstrong_Horseshoel _Deform ed_Bedding_Nan ushuk 2_ Rose_ Strike_4881-5582.j- 4/18/2017 Electronic File: Armstrong_Horseshoel _Deformed _Bedding_Na n ushuk 2_Stereonet_4881-5582.jpg 4/18/2017 Electronic File: Armstrong_Horseshoel _Deformed _Bedding_Na n ushuk 2_Vector_Plot_4881-5582.jpg 4/18/2017 Electronic File: Armstrong_Horseshoel Deformed Bedding_Nan ushuk 3_Histogram_47124881.jpg 4/18/2017 Electronic File: Armstrong_Horseshoel_Deformed Bedding_Nan ushuk 3_Rose_Azimuth_4712-4881.jpg 4/18/2017 Electronic File: Arm strong_Horseshoel _Deformed_Bedding_Na n ushuk 3_ Rose_ Strike47_ 12-4881.jpg 4/18/2017 Electronic File: Armstrong_Horseshoel Deformed_Bedding_Nan ushuk 3_Stereonet_4712-4881.jpg Friday, December 8, 2017 DATA SUBMITTAL COMPLIANCE REPORT 121&/2017 Permit to Drill 2161330 Well Name/No. HORSESHOE 1 Operator ARMSTRONG ENERGY, LLC API No. 50-103-20751-00-00 MD 6000 TVD 5819 Completion Date 2/18/2017 Completion Status P&A Current Status P&A UIC No ED C 28137 Digital Data 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December 8, 2017 DATA SUBMITTAL COMPLIANCE REPORT 12/812017 Permit to Drill 2161330 Well Name/No. HORSESHOE 1 Operator ARMSTRONG ENERGY, LLC API No. 50-103-20751-00-00 MD 6000 TVD 5819 Completion Date 2/18/2017 Completion Status P&A Current Status P&A UIC No ED C 28137 Digital Data 4/18/2017 Electronic File: Armstrong_Horseshoel_Deformed_Bedding_Nan'. ushuk 6—Rose _Strike_4390-4511.jpg ED C 28137 Digital Data 4/18/2017 Electronic File: Armstrong_Horseshoel Deformed_Bedding_Nan ushuk 6_Stereonet_4390-4511.jpg ED C 28137 Digital Data 4/18/2017 Electronic File: Armstrong_Horseshoe 1 _Deformed _Bedding_Na n ushuk 6—Vector _ Plot_ 4390-4511.jpg ED C 28137 Digital Data 4/18/2017 Electronic File: Armstrong_Horseshoel Deformed_Bedding_Nan ushuk 7_Histogram_4257-4390.jpg ED C 28137 Digital Data 4/18/2017 Electronic File: Armstrong_Horseshoet_Deformed_Bedding_Nan ushuk 7_Rose_Azimuth_4257-4390.jpg ED C 28137 Digital Data 4/18/2017 Electronic File: Armstrong_Horseshoe 1 _Deformed_Bedding_Nan 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12/8/2017 Permit to Drill 2161330 Well Name/No. HORSESHOE 1 Operator ARMSTRONG ENERGY, LLC API No. 50-103-20751-00-00 MD 6000 TVD 5819 Completion Date 2/18/2017 Completion Status P&A Current Status P&A UIC No ED C 28137 Digital Data 4/18/2017 Electronic File: Armstrong_Horseshoel _Fa ult_AII_H istogram_22 44-5983.jpg ED C 28137 Digital Data 4/18/2017 Electronic File: Armstrong_Homeshoel _Fault_AI I_Rose_Azim uth _2244-5983.jpg ED C 28137 Digital Data 4/18/2017 Electronic File: Arm strong_Horseshoel _Fault_AII_Rose_Strike_2 244-5983.jpg ED C 28137 Digital Data 4/18/2017 Electronic File: Armstrong_Homeshoel_Fault_All_Stereonet_224 4-5983.jpg ED C 28137 Digital Data 4/18/2017 Electronic File: Annstrong_Horseshoel _Fault _All—Vector—Plot-2 244-5983.jpg ED C 28137 Digital Data 4/18/2017 Electronic File: Armstrong_Horseshoe 1 _Fault_Nanushuk 1 _Histogram_5582-5983.] pg ED C 28137 Digital Data 4/18/2017 Electronic File: Armstrong_Homeshoel _Fault_Nanushu k 1 _Rose—Azimuth _5582-5983.j pg ED C 28137 Digital Data 4/18/2017 Electronic File: Armstrong_Horseshoel Fault_Nanushuk 1_Rose_Strike_5582-5983.jpg ED C 28137 Digital Data 4/18/2017 Electronic File: Arm strong_Horseshoel _Fault _Nan ushuk 1 _Stereonet_5582-5983.jpg ED C 28137 Digital Data 4/18/2017 Electronic File: Armstrong _Horseshoet _Fault_Nanushuk 1 _Vector_Plot_5582-5983.jpg ED C 28137 Digital Data 4/18/2017 Electronic File: Armstrong_Homeshoel Fault_Nanushuk 2_ Histogram_4881-5582.jpg ED C 28137 Digital Data 4/18/2017 Electronic File: Armstrong_Horseshoe 1 _Fault_Nanushuk 2_Rose_Azimuth_4881-5582.jpg ED C 28137 Digital Data 4/18/2017 Electronic File: Armstrong _Horseshoel _Fault_Nanushu k 2_Rose_Strike_4881-5582.jpg AOGCC Page 26 of 33 Friday, December 8, 2017 DATA SUBMITTAL COMPLIANCE REPORT 12/8/2017 Permit to Drill 2161330 Well Name/No. HORSESHOE 1 MD 6000 TVD 5819 Completion Date 2/18/2017 ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data ED C 28137 Digital Data Operator ARMSTRONG ENERGY, LLC Completion Status P&A API No. 50-103-20751-00-00 Current Status P&A UIC No 4/18/2017 Electronic File: Armstrong _Horseshoel Fault_Nanushuk 2_Stereonet_4881-5582.jpg 4/18/2017 Electronic File: Armstrong_Homeshoel _Fault_Nanushuk 2_Vector_Plot_4881-5582.jpg 4/18/2017 Electronic File: Annstrong_Horseshoel Fault_Nanushuk 3_ Histogram_ 4712-4881.jpg 4/18/2017 Electronic File: Armstrong_Horseshoet_Fault_Nanushuk 3_Rose_Azimuth 4712-4881.jpg 4/18/2017 Electronic File: Armstrong_ Horseshoel_Fault_Nanushuk 3_Rose_SVike_4712-4881.jpg 4/18/2017 Electronic File: Armstrong_Homeshoe1 Fault_Nanushuk 3_Stereonet_4712-4881.jpg 4/18/2017 Electronic File: Armslrong_Horseshoel Fault_Nanushuk 3_Vector_Plot _4712-4881.jpg 4/18/2017 Electronic File: Armstrong_Horseshoel Fault_Nanushuk 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ED C 28137 Digital Data 4/18/2017 Electronic File: Armstrong _Horseshoel Fracture_Nanushuk 2_Stereonet_4881-5582.jpg ED C 28137 Digital Data 4/18/2017 Electronic File: Armstrong_Homeshoel _Fracture_Nanushu k 2_Vector_Plot_4881-5582.jpg ED C 28137 Digital Data 4/18/2017 Electronic File: Armstrong_Horseshoe t_Fmcture_Nanushuk 6_ Histogram_ 4390-4511.j pg ED C 28137 Digital Data 4/18/2017 Electronic File: Armstrong_Horseshoel Fmcture_Nanushuk 6_Rose_Azimuth _4390-4511.jpg ED C 28137 Digital Data 4/18/2017 Electronic File: Armstrong_Horseshoel _Fmcture_Nanushuk 6_Rose_Strike_4390-4511.jpg ED C 28137 Digital Data 4/18/2017 Electronic File: Armstrong_Horseshoel _Fracture_Nanushuk 6_Stereonet_4390-4511.jpg ED C 28137 Digital Data 4/18/2017 Electronic File: Arm strong_Horseshoel _Fractu re_Nanushuk 6_Vector_Plot_4390-4511.jpg ED C 28137 Digital Data 4/18/2017 Electronic File: Armstrong_Homeshoel _Fracture_Tuluvak_Histo gram_2492-4214.jp9 ED C 28137 Digital Data 4/18/2017 Electronic File: Arm 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File: 4822.00-4840.00-wl.jpg ED C 28258 Digital Data 5/30/2017 Electronic File: 4840.004841.30-uv.jpg ED C 28258 ' Digital Data 5/30/2017 Electronic File: 4840.00-4841.30-wl.jpg ED C 28258 Digital Data 5/30/2017 Electronic File: 4842.00-4860.00-uv.jpg ED C 28258 Digital Data 5/30/2017 Electronic File: 4842.00-4860.00-wl.jpg ED C - 28258 Digital Data 5/30/2017 Electronic File: 4860.00-4878.00-uv.jpg ED - C 28258 Digital Data 5/30/2017 Electronic File: 4860.00-4878.00-wl.jpg ED C 28258 Digital Data 5/30/2017 Electronic File: 4878.00-4896.00-uv.jpg ED C 28258 Digital Data 5/30/2017 Electronic File: 4878.00-4896.00-wl.jpg ED C 28258 Digital Data 5/30/2017 Electronic File: 4896.00-4914.00-uv.jpg ED C 28258 Digital Data 5/30/2017 Electronic File: 4896.004914.00-wl.jpg ED C 28258 Digital Data 5/30/2017 Electronic File: 4914.00-0932.00-uv.jpg ED C 28258 Digital Data _ 5/30/2017 Electronic File: 4914.00-4932.00-wl.jpg ED C 28258 Digital Data 5/30/2017 Electronic File: 4932.00-4933.65-uv.jpg ED C 28258 Digital Data 5/30/2017 Electronic File: 4932.00-4933.65-wl.jpg ED C 28258 Digital Data 5/30/2017 Electronic File: Horseshoe #1—SW Routine Core Analysis_05.01.17.xlsx ED C 28258 Digital Data 5/30/2017 Electronic File: 14_UV.jpg ED C 28258 Digital Data 5/30/2017 Electronic File: 14_WL.jpg ED C 28258 Digital Data 5/30/2017 Electronic File: 13-16_UV.jpg ED C 28258 Digital Data 5/30/2017 Electronic File: 13-16_WL.jpg AOOCC Page 31 of 33 Friday, December 8, 2017 DATA SUBMITTAL COMPLIANCE REPORT 12/8/2017 Permit to Drill 2161330 Well Name/No. HORSESHOE 1 Operator ARMSTRONG ENERGY, LLC API No. 50-103-20751-00-00 MD 6000 TVD 5819 Completion Date 2/18/2017 Completion Status P&A Current Status P&A UIC No ED C 28258 Digital Data 5/30/2017 Electronic File: 17-20_UV.jpg ED C 28258 Digital Data 5/30/2017 Electronic File: 17-20_WL.jpg ED C 28258 Digital Data 5/30/2017 Electronic File: 21-24_UV.jpg ED C 28258 Digital Data 5/30/2017 Electronic File: 21-24_WL.jpg ED C 28258 Digital Data 5/30/2017 Electronic File: 25-28_UV.jpg ED C 28258 Digital Data 5/30/2017 Electronic File: 25-28_WL.jpg ED C 28258 Digital Data 5/30/2017 Electronic File: 29-32_UV.jpg ED C 28258 Digital Data 5/30/2017 Electronic File: 29-32_W L.jpg ED C 28258 Digital Data 5/30/2017 Electronic File: 33-36_UV.jpg ED C 28258 Digital Data 5/30/2017 Electronic File: 33-36_WL.jpg ED C 28258 Digital Data 5/30/2017 Electronic File: 37-40_UV.jpg ED C 28258 Digital Data 5/30/2017 Electronic File: 37-40_WL.jpg ED C 28258 Digital Data 5/30/2017 Electronic File: 41-42_UV.jpg ED C 28258 Digital Data 5/30/2017 Electronic File: 41-42_WL.jpg ED C 28258 Digital Data 5/30/2017 Electronic File: 5-8_UV.jpg ED C 28258 Digital Data - 5/30/2017 Electronic File: 5-8_WL.jpg ED C 28258 Digital Data 5/30/2017 Electronic File: 9-12_UV.jpg ED C 28258 Digital Data 5/30/2017 Electronic File: 9-12_WL.jpg Log C 28258 Log Header Scans 0 0 Confidential (incomplete) entry for HORSESHOE 1 Well Cores/Samples Information: Sample Interval Set Name Start Stop Sent Received Number Comments Cuttings 120 6000 2/23/2017 1598 Purple boxes INFORMATION RECEIVED �>wwvhu�l� colt c(�t'ps ✓�wilr�cl. c�a c� X2-1 Y ,(tiGr�dt( PQM AOOCC Page 32 of 33 friday, Dmember 8, 2017 DATA SUBMITTAL COMPLIANCE REPORT 1218/2017 Permit to Drill 2161330 Well Name/No. HORSESHOE 1 Operator ARMSTRONG ENERGY, LLC API No. 50-103.20751-00-00 MD 6000 TVD 5819 Completion Date 2/18/2017 Completion Status P&A Current Status P&A UIC No Completion Report b Directional / Inclination Data Mud Logs, Image Files, Digital Data (D NA Core Chips Y / NA Production Test Information Y Mechanical Integrity Test Information Y / INC) Composite Logs, Image, Data Files® Core Photographs 6! / NA Geologic Markers/Tops (Y Daily Operations Summary YO Cuttings Samples (' NA Laboratory Analyses�iY '' NA COMPLIANCE HISTORY Completion Date: Release Date: Description Comments: 2/18/2017 4/10/2019 Date Comments --- Compliance Reviewed By: =-7- Date: AOG(V Page 33 of 33 Friday, December 8, 2017 C;�Ic�-133 eI�a25 l RECEIVED ARMSTRONG DEC 29Z017 EneM,, LLC AOGCC December 21, 2017 Alaska Oil and Gas Conservation Commission 333 W 7' Ave., Suite 100 Anchorage, AK 99501 Attn: Meredith Guhl RE: Horseshoe #1 Core Chips API 50103207510000, permit to drill 216-133 North Slope, Alaska Dear Meredith: Please find enclosed the conventional core chips from each foot of recovered conventional core for the above referenced well. Please indicate your receipt of the aforementioned data by signing in the space provided below and returning a scanned copy of this letter to me at patti(cbarmstroneoilandsas.com. Should you have any questions please call this office at 303-623-1821. Yours truly, Patti Reed Geo Tech —H111 QW� wq-`i 2 - 1-1 e q t Received this I day of CQgi , 20 ii' l ALASKA OIL AND GAS CONSERVATION COMMISSION LL 60101— By: °10'— By: 1� � KAj)/,eUVA CTL.-" 1421 Blake Street Denver, CO 80202 p 303.623.1821 /'303.623.3019 Guhl, Meredith D (DOA) From: Colby VanDenburg <colby@armstrongoilandgas.com> Sent: Monday, December 18, 2017 1:41 PM To: Guhl, Meredith D (DOA) Cc: Patti Reed Subject: Horseshoe RT Scanner Meredith, The Horseshoe 1 RT Scanner log was run in conjunction with the standard array induction tool. I confirmed with Schlumberger that the data is presented at the bottom of the ZAIT logs listed below and that a separate 'RT Scanner' log was never generated. The ZAIT print contains standard resistivity curves plus the RV, RH and dip curves from the RT Scanner tool. The data has also been integrated into the LSA interpretation. According to our records, AOGCC should have all the wireline data that exists for the well. Please let me know if you have any issues locating the data. Thanks. Armstrong_HorseShoe_1_R2 D1_ZAIT-G R_5 i n. Pdf Armstrong_HorseShoe_3_R2 Dl_ZAIT-G R_2in. Pdf Colby VanDenburg Geologic Manager Armstrong Oil and Gas 1421 Blake Street Denver, CO 80102 303-623-1821 (office) 303-908-0564 (cell) Guhl, Meredith D (DOA) From: Patti Reed <patti@armstrongoilandgas.com> Sent: Friday, December 15, 2017 8:37 AM To: Guhl, Meredith D (DOA) Subject: RE: Horseshoe 1, PTD 216-133, Conventional Core Chip delivery ETA? Sorry for the delay on this. We are making arrangements to get the core chips next week; with the upcoming holidays you may not receive them in your office until early January. Patti Reed From: Guhl, Meredith D (DOA)[mailto:meredith.guhl@alaska.gov] Sent: Friday, December 08, 2017 11:34 AM To: Patti Reed <patti@armstrongoilandgas.com> Cc: Bettis, Patricia K (DOA) <patricia.bettis@alaska.gov> Subject: Horseshoe 1, PTD 216-133, Conventional Core Chip delivery ETA? Hi Patti, When can the AOGCC expect to receive the conventional core chips from Horseshoe 1? Per Regulation 20 AAC 25.071(b)(4) chips from each foot of recovered conventional core are required to be submitted, within 30 days after the conventional core is analyzed. We did receive the conventional core photos and analyses in May 2017. Please advise. Thank you, Meredith Meredith Guhl Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 me red it h. gu h I @a la ska.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 GuhI at 907-793-1235 or meredith.euhl@alaska.eov. Gi Meredith D (DOA) From: Guhl, Meredith D (DOA) Sent: Tuesday, December 12, 2017 1:33 PM To: 'Patti Reed' Cc: Bettis, Patricia K (DOA) Subject: RE: Horseshoe 1, PTD 216-133, RT Scanner Log Attachments: CPAI_Moraine_1_RTScanner_Dip_3600ft_5560ft_PDF.PDF; Repsol_Qugruk_9_Run1 _RTScanner_Processed_I nversion.pdf Patti, I received an oversized paper Laminated Sand Analysis log and the digital data associated with the Laminated Sand Analysis log today, thank you. What arrived today was not the RT Scanner log I was expecting, however. In the two RT scanner logs received for previous wells, Repsol/Armstrong's Qugruk 9 (eset T25926 and T25928) and ConocoPhillips' Moraine 1 (eset T25705), the AOGCC received a paper log specific to the RT scanner, along with associated digital LAS and PDF data. Based on the header on the Laminated Sand Analysis log, which states "Hydrocarbon Identification from RT scanner" and the previous RT Scanner logs received it seems like there a RT scanner log still needs to be supplied. Please advise. Thank you, Meredith Meredith Guhl Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 mered ith.gu h l @a laska.eov 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 a -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.¢uhl@alaska.eov. From: Patti Reed[mailto:patti@armstrongoilandgas.comj Sent: Friday, December 8, 2017 11:50 AM To: Guhl, Meredith D (DOA) <meredith.guhl@alaska.gov> Cc: Bettis, Patricia K (DOA) <patricia.bettis@alaska.gov> Subject: RE: Horseshoe 1, PTD 216-133, RT Scanner Log Meredith- The RT Scanner log was completed; I thought that data would have come to you directly from the vendor, Schlumberger. Since you don't have it I will make a copy of those files and send it to you on a CD next week. Thanks, Patti From: Guhl, Meredith D (DOA)[mailto:meredith.guhl@alaska.gov] Sent: Friday, December 08, 2017 12:17 PM To: Patti Reed <paatti@armstronaoilandeas.com> Cc: Bettis, Patricia K (DOA) <patricia.bettis@alaska.eov> Subject: Horseshoe 1, PTD 216-133, RT Scanner Log Hi Patti, I just reviewed the logs received to date for Horseshoe 1. On the form 10-407, a RT Scanner log was noted as being completed, but 1 did not come across that log in the Horseshoe 1 logs on hand. All other logs noted on the form were received. In addition, the following logs were not noted on the form but were received: GR/RES/NEU/DEN, PPC, AIT -GR. Can you please review your records to see if the RT Scanner log was completed, and if it perhaps got missed in the submittal? Thank you, Meredith Meredith Guhl Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.euhl@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.euhlibDalaska.eov. F.1 ARMSTRONG Zg(,S2 RECEIVE® EaeiV,LLC DEC 12 2017 AOGCC December 11, 2017 Alaska Oil and Gas Conservation Commission 333 W 7°i Ave., Suite 100 Anchorage, AK 99501 Attn: Meredith Guhl RE: CD — Horseshoe #1 API 50103207510000, permit to drill 216-133 North Slope, Alaska Dear Meredith: Please find enclosed one CD containing digital data: Horseshoe 1 RT Scanner Also enclosed is one paper copy of the Laminated Sand Analysis from the RT Scanner. Please indicate your receipt of the aforementioned data by signing in the space provided below and returning a scanned copy of this letter to me at pattigarmstrongoilandgas.com. Should you have any questions please call this office at 303-623-1821. Yours truly, : 2 \ Patti Reed Geo Tech Received this day of 2017. ALASKA OIL AND GAS CONSERVATION COMMISSION By: 1421 Blake Street Denver, CO 80202 p 303.623.1821 f'303.623.3019 A 21 61 33 RECEIVED 2 8 25 8 ARMSTRONG MAY 3 0 2017 Enertpa LLC AOGCC May 26, 2017 DATA LOGGED Go /'% /201-1 ;.I K BENDER Alaska Oil and Gas Conservation Commission 333 W lin Ave., Suite 100 Anchorage, AK 99501 Attn: Meredith Guhl RE: CD — Horseshoe #I API 50103207510000, permit to drill 216-133 North Slope, Alaska Dear Meredith: Please find enclosed one CD containing the following confidential digital data: Horseshoe 1 Conventional Core Photos and Analyses Horseshoe 1 RSWC Photos and Analysis Please indicate your receipt of the aforementioned data by signing in the space provided below and returning a scanned copy of this letter to me at pattigarmstroneoiland ag s.com. Should you have any questions please call this office at 303-623-1821. Yours truly, Patti Reed Geo Tech Received this Z) day of A 2017. ALASKA OIL AND GAS CONSERVATION COMMISSION 1421 Blake Street Denver, CO 80202 p 303.623.1821 1'303.623.3019 Oar VISt�'D I STATE OF ALASKA ALyoKA OIL AND GAS CONSERVATION COMImISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1a. Well Status: Oil ❑ Gas E] SPLUG ❑ Other ❑ Abandoned Q Suspended❑ 1b. Well Class: 2DAAC 25.105 20AAC 25.110 Development ❑ Exploratory Q GINJ ❑ WINJ ❑ WAG❑ WDSPL ❑ No. of Completions: Service ❑ Stratigraphic Test ❑ 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number/ Sundry: Armstrong Energy, LLC Aband. 2/1$/2017 216-133 / (317-074) 3. Address: 7. Date Spudded: L- 15. API Number: 510 L Street, Suite 310 Anchorage, Alaska 99501 1/2$/2017 50-103-20751-00-00 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: 1413' FWL & 2226' FSL UM Sec 015 T8n R4e 2/12/2017 Horseshoe # i Top of Productive Horizon: 9. Ref Elevations: KB: 42.1 17. Field / Pool(s): Estimated 2035' FWL & 2407' FNL UM Sec 015 T8n R4e GL 18,6' BF: 22.3' Wildcat Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 2033' FWL & 2405' FNL UM Sec 015 T8n R4e 2030'/ 2007' ADL 392048 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. Land Use Permit: Surface: x- 360,290 y- 5,867,909 Zone- 4 6000'/ 5819' LAS 28269 & Others TPI: t x- 360,878 y- 5,868,527 Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- 360,918 y- 5,868,536 Zone- 4 5957.9'/ 5776.9' 860'MD / 859'TVD 5. Directional or Inclination Survey: Yes E(attached) No 13. Water Depth, N Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic and printed information per 20 AAC 25.050 1 na (ft MSL) na 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary PEX 2213'-6000' MD . HNGS 2213'-6000' MD IBC-MSIP-USIT-CBL 210'-2100' MD RT Scanner 2213'-6000' MD-*Psv+ a/ ��i (T • CMR 2213'-6000' MD R EC E I V NGI Imager 2213'-6000' MD lecJ • ECS 2213'-6000' MD Dg 118' - 6000" MD Sonic Scanner 2213'-6000'MD c �1 L 2654'-4815'MD APR 25 2017 Gf-)QES/NEI.JJDEN , p tT-GRrwecld t tz 23. CASING, LINER AND CEMENTING REC WT. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING FT TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 16 84 X56 0 118 0 118 24 85 bbls 15.6 ppg Permafrost 36' 0 0.00 0 0 0 0 0 0 0 See PTD 217x15 95/8 53.50 L80 0 2,216 0 2,188 121/4 216 bbls 10.5 ppg PF -L Lead, 48.5 *6, bbls 15.8 Swiftcem Tail OH 0.00 0 0 6,000 0 5,819 81/2 na See PTD 217-015 0 1 0.00 0 0 0 10 0 0 ina 24. Open to production or injection? Yes ❑ No Q 25. TUBING RECORD If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation SIZE DEPTH SET (MD) PACKER SET (MD/TVD) Size and Number): na COMPLETION 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DATE 811-q-_ Was hydraulic fracturing used during completion? Yes No Z __Z/f VERIFIED LL Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production: Method of Operation (Flowing, gas lift, etc.): na Date of Test: Hours Tested: Production for Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: Test Period Flow Tubing Casing Press: Calculated Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity -API (torr): Press. 24 -Hour Rate VIIII IV-YV/ RCVI.IGV 11/LV IJVVIYIIIVVVrI1VGC� A74�� RBDMS LL- MAY - 2V 20i7vrcnauYlr.L Vnly 28. CORE DATA Conventional G s): Yes ❑� No ❑ Sidewall Corey 'es ❑] No ❑ If Yes, list formations and intervals cored (MD/TVD, From/ro), and summarize lithology and presence of ou, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. Conventional Core 4750'MD/4569'TVD 4934'MD/4753'TVD Nanushuk Fm Oil -saturated sandstone 4332'MD/4153'TVD 4760'MD/4579'TVD Nanushuk Fm Oil -saturated sandstone Sidewall Cores 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No ❑� 0 If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top 0 Permafrost - Base 860 859 Attach separate pages to this form, if needed, and submit detailed test Upper Schrader Bluff 900 899 information, including reports, per 20 AAC 25.071. Middle Schrader Bluff 1859 1845 Lower Schrader Bluff 2023 2003 MCU 2108 2084 Tuluvak 2492 2454 Nanushuk 4214 4037 Nanushuk Target 4712 4531 Top of Productive Interval 4712 4531 Torok 4881 4700 Formation at total depth: Torok 6000 5819 31. List of Attachments: Directional surveys, wellbore schematic, CIT/LOT chart, Post Well Cmtg Csg Record Surface Feb 02 17, operations summary, copy of letter "Horseshoe 1 core notification", as-bult pad Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Stephen Hannigan 337 849-5345 Email: steve@peiinc.com Printed Name: Stephen F. H`an—n_igan Title: Project Engineer/Mgr for Armstrong Energy, LLC AZ ry` �'�" Signature: "'Phone: 3378495345 Date: 4/14/2017 INSTRUCTIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Item 1 a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1b: Well Class - Service wells: Gas Injection, Water Injection, Water -Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Forth 10-407 Revised 11/2015 Submit ORIGINAL Only STATE OF ALASKA Al : .A Oil ANn rAR CONSERVATION COM. 3SION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1a. Well Status: Oil ❑ Gas F] SPLUG ❑ Other ❑ Abandoned ❑� Suspended F] 20AAC 25.105 20AAC 26.110 tb. Well Class: Development ❑ Exploratory 0 GINJ ❑ WINJ ❑ WAG❑ WDSPL ❑ No. of Completions: Service ❑ Stratigraphic Test ❑ 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number/ Sundry: Armstrong Energy, LLC Aband.: 2/1$/2017 216-133 / (317-074) . 3. Address: 7. Date Spudded: 15. API Number: 510 L Street, Suite 310 Anchorage, Alaska 99501 1/27/2017 50-103.20751-00-00 , 4a. Location of Well (Governmental Section): 8. Date TO Reached: 16. Well Name and Number: Surface: 1413' FWL & 2226' FSL UM Sec 015 T8n R4e 2/12/2017 Horseshoe # 1 ' 9. Ref Elevations: KB: v.0 11 17. Field / Pool(s): Top of Productive Horizon: t 2033' FWL & 2405' FNL UM Sec 015 T8n R4e GL 19,6' BF: 23.3' Wildcat Total Depth: 10. Plug Back Depth MD/TVD: 18. Prop y Designation: t 2033' FWL & 2405' FNL UM Sec 015 T8n R4e 2030' / 2007' , ADL 392048 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD:and 19 Use Permit: Surface: x- 360,290 y- 5,867,909 Zone- 4 6000'/ 5819' LAS 28269 & Others TPI: t x- 360,878 y- 5,868,527 Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- 360,918 y- 5,868,536 Zone- 4 5956.9'/ 5775.9' 860'MD / 859'TVD 5. Directional or Inclination Survey: Yes (attached) No ❑ 13. Water Depth, if Off ore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic and printed information per 20 AAC 25.050 na (ft)fSL) - na 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submi I electronV aata and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Types of logs to be listed i ude, b t ere not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formatio tester, to eratur crlent evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necess j�i✓ PEX 2213'-6000' MD HNGS 213'- MD IBC-MSIP-USIT-CBL 210'-2100' MD RT Scanner 2213'-6000' MD CMR 2 '-6 0' MD R ECE I V NGI Imager 2213'-6000' MD ECS 1 000' MD MD Sonic Scanner 2213'-6000'MD MDT 2 '-4815'MD,1_)PF-R-SEDEDr MAR 2 8 2017 23, CAST L ER AND CEMENT NGFRECORDY-- -- --.,.sem CASING WT. PER FT GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE AMOUNT CEMENTING RECORD PULLED TOP BOTTO TOP BOTTOM 16 84 X56 0 118 0 118 24 85 bible 15.6 ppg Permalrost t6' 0 0.00 0 0 D 0 D 0 0 See PTD 217015 95/8 53.50 L80 0 2 16 0 2,188 121/4 216 bbls 10.5 ppg PF -L Lead, 48.5 t6' We 15.8 SyAftcem Tail OH 0.00 0 0 6,000 0 5,819 81/2 na See PTD 217015 0 0.00 0 0 0 0 0 0 na 0 (To be cora 0 0 0 0 0 19. 10 24. Open to production or injection? Ws ❑ No Q 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/TVD) If Yes, list each interval open (MD/TV of Top and Bottom; Perforation na #REFI #REF! #REF! Size and Number): AijAN AoN2'(1 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. D4-rF --°L11&It 7 Was hydraulic fracturing used during completion? Yes No Per 20 AAC 25.283 (i)(2) attach electronic and printed information /f'pn_ �i"r` DEPTH INTERVAL (MD) JAMOUNT AND KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production: Method of Operation (Flowing, gas lift, etc.): na Date of Test: Hours Tested: Production for Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: Test Period Flow Tubing Casing Press: Calculated Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity - API (corr): Press. 24 -Hour Rate Form m-wvr newsea 1172015 /( �+��_� 11uiZ--..... RBDMS I.I MAR 3 112017 28. CORE DATA Conventic 'ore(s): Yes ❑' No ❑ Sidewall Cores: i ❑� No ❑ If Yes, list formations and intervals cored (MD/TVD, Fr)m/TO), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071, Conventional Core 4750'MD/4569'TVD 4934'MD/4753'TVD Nanushuk Fm Oil -saturated sandstone Sidewall Cores 4332'MD/4153'TVD 4760'MD/4579'TVD Nanushuk Fm Oil -saturated sandstone 29. GEOLOGIC MARKERS (List all formations and markers encountered) 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No❑� If yes, list intervals and formations tested, briefly summarizing test Permafrost - Top 0 0 Permafrost - Base 860 859 results. Attach separate pages to this form, if needed, and submit Upper Schrader Bluff 900 899 detailed test information, including reports, per 20 AAC 25.071. Middle Schrader Bluff 1859 1845 Lower Schrader Bluff 2023 2003 MCU 2108 2084 Tuluvak 2492 2454 Nanushuk 4214 4037 Nanushuk Target 4712 4531 Top of Productive Interval 4712 4531 ¢y ice` r� P• SUPERSEDE[_-, Torok 4881 4700 Formation at total depth: Tor 6000 5819 31. List of Attachments: Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Stephen Hannigan 337849-5345 Email: steve@peunc.com rinted Name: Ste lheF. Hannigan Title: Project Engineer/Mgr for Armstrong Energy, LLC Signature.. Phone: 3378495345 Date: 3/23/2017 INSTRUCTIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses Item 1 a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1b: Well Class - Service wells: Gas Injection, Water Injection, Water -Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070, attach to this torn: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Farm 10-407 Revised 11/2015 Submit ORIGINAL Only A R C T I C O C E A N as eenc+av�ua o aa�r. �aNaacr ngEq mm z tairbonka O Il x VICINITY MAP N.T.S N 1� NOTES: 1.DATES OF SURVEY 3-7-17 to 3-8-17. & ,Ey5N0 HORSESHOE ICE ROAD AS BUILT Pi- �+ SECEN)N,5, 16N, ME, U.M. ARMSTRONG a`TI' 3114/17 ° NOTTOSCALE °A"�""' K3 "KWA FIG wre vawmox cxim aaui wwn.�1• ar�rx '. etc ox4wwe xmria, 4ewx�cww URE 1 OF1 Nx O 61 5x % sr % % gg x+ m u % % ggn�uu s, 1aH 3 Y TW 1 9 2 1 8 5 1 3 x ` 8 6 1 6 2 1 8 6 — 16 y�e 16 a� e GOA 11 Iz t e e � 11 Iz > a e ,o 11 ,x ) 6 HS-1 PAD ,e 16 ,. ,s 9 CONOCO 18 tt 18 ,6 L H id 18 17 16 14 ,8 15 15 DS 2P CAMP PAD 27 II ?3 1B A xt m 16 A t14 yil&!TiN1 x x4q 6 2 � 8 5 A R C T I C O C E A N as eenc+av�ua o aa�r. �aNaacr ngEq mm z tairbonka O Il x VICINITY MAP N.T.S N 1� NOTES: 1.DATES OF SURVEY 3-7-17 to 3-8-17. & ,Ey5N0 HORSESHOE ICE ROAD AS BUILT Pi- �+ SECEN)N,5, 16N, ME, U.M. ARMSTRONG a`TI' 3114/17 ° NOTTOSCALE °A"�""' K3 "KWA FIG wre vawmox cxim aaui wwn.�1• ar�rx '. etc ox4wwe xmria, 4ewx�cww URE 1 OF1 Nx O 61 5x % sr % % gg x+ m u % % ggn�uu s, 1aH 3 Y TW 1 9 2 1 8 5 1 3 x ` 8 6 1 6 2 1 8 6 — 16 y�e 16 a� e GOA 11 Iz t e e � 11 Iz > a e ,o 11 ,x ) 6 HS-1 PAD ,e 16 ,. ,s 9 CONOCO 18 tt 18 ,6 L H id 18 17 16 14 ,8 15 15 DS 2P CAMP PAD 27 II ?3 1B A xt m 16 A t14 0 a � ZWp qqq O NN.PY1b 1NNOmmn€bJJ 2 ga?gguC x I.1 oia ZRPig �oI 4s m 1N�^ I�"� IVn� H,x 13 >x 59p gBw$m S YX J kgs m�mi;g zmTia m."v ji�3N x p'Ammm 8m8 My��pV$nq nr�jj qq L 6RMy {O� b O�F 1414 ` n eTi FiOn � pt>viJ Y�y mn ��n� �� 11 ^,4 lit'�' `Y pp yzr< pp r pY¢{{X{U Yx O](1r �x 25 Tx 3 YX 6J1%i nt t't d� R WE Horseshoe 1 FIT -CIT PRESSURE INTEGRITY TEST Instructions: Fill in shaded areas COMPLETELY! OPERATOR Armstrong Energy WELL NAME Horseshoe #1 DATE: 2/5/17 Co. Rep. Bob Lenhart / Tom Boyd RIG TYPE Land STATE: Alaska RIG Arctic Fox CASING SIZE 95/8" MUD WT 10.4 ELEVATION ABOVE MSL 42' DESCR. GRADE/WT L80/53.5 INFORM. PV 32 (RKB) ABOVE G.S. 21.65' DEPTHS SHOE (TVD) 2185' YP 20 PUMP TYPE Triplex OH (TVD) 2201' FL 6 BPS 0.0026 SHOE (MD) 2213' GELS 10 EFFICIENCY 0.96 OH (MD) 2230' CASING TEST (CIT) FORM INTEG. TEST (Fro Monitor RATE 0.25 BPM FLOWBACK 2.0 bbls APPR RATE: 0.25 BPM FLOWBACK 2.5 bbls Time: Plotted Rate: 0.25 BPM TIME 2.0 min Plotted Rate: 0.25 BPM TIME 5.0 min CUM. VOL. PRESSURE POINTS Calc Time CUM. VOL. PRESSURE EMW 0.00 0 1 0 0.00 0 1 10.40 0.25 100 2 1 0.25 31 2 10.67 0.50_ 192 3 2 0.50 39 3 10.74 0.75 700 4 3 0.75 47 4 10.81 1.00 899 5 4 1.00 53 5 10.86 1.25 1341 6 5 1.25 56 6 10.89 1.50 1828 7 6 1.50 60 7 10.92 1.75 2327 8 7 1.75 60 8 10.92 2.00 2816 9 8 2.00 62 9 10.94 2.25 3543 10 9 2.25 64 10 10.96 2.50 3760 11 10 2.50 63 11 10.95 2.75 4200 12 11 2.75 63 12 10.95 3.00 13 12 3.00 101 13 11.28 3.25 14 13 3.25 189 14 12.05 3.50 15 14 3.50 320 15 13.20 3.75 16 15 3.75 404 16 13.93 4.00 0 0.00 - ' - 10.40 4.25 0 0.00 10.40 4.50 0 0.00 10.40 4.75 0 0.00 10.40 5.00 0 0.00 10.40 5.25 0 0.00 10.40 5.50 0 0.00 10.40 5.75 0 0.00 10.40 6.00 0 0.00 10.40 6.25 0 0.00 10.40 6.50 0 0.00 10.40 6.75 0 0.00 10.40 7.00 0 0.00 10.40 7.25 0 0.00 10.40 7.50 0 0.00 10.40 7.75 0 0.00 10.40 8.00 0 0.00 10.40 8.25 0 0.00 10.40 8.50 0 0.00 10.40 8.75 0 0.00 10.40 9.00 0 0.00 10.40 9.25 0 0.00 10.40 9.50 0 0.00 10.40 9.75 0 0.00 10.40 4245 /SIP 0.00 10.40 4240 AFTER 30 MIN INCA. TIME» 4.8 380 13.72 Olnmenis SPR # PSI GPS :NCR. TIME>> 6.8 366 13.60 #1 - ' INCR. TIME» 8.8 355 13.50 #2 INCR. TIME>> 10.8 344 13.41 INCR. TIME>> 12.8 334 13.32 PRESSURE VS. VOLUME 500IX 1 1 1 I 1 1 1 8 of EMW 4 * 36E 35,E f 1 X --�- Mazimum Volume Line / N / -CIT a +-O-CASING Test .30 MIN / SLOT incremental Time 1 / I I -EMW 1 / 1 • Bind 0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 1 8 19 20 21 Stephen F. (Steve) Hennigan 3/25/2017 of EMW 4 f 1 Stephen F. (Steve) Hennigan 3/25/2017 Armstrong Energy, LLC Horseshoe Well # 1 Permit # 216-133 Spud Date: 1/27/2017 Daily Summary Rot Start Date: 01/16/17 North Slope, AK PLAN Actual Rot Act COMMENTS Data Day Depth Depth His MW 0 _ _ _ ___ Continue ice road construction Refer to construction antl camp daily reports for details Costs to 01/1612017 are accumulated from invoices processed for payment and daily field reports Discussed rig prep and breakdown schedule for rig mod. Start load out of mats & misc equipment Tue, Jan 17. Start rig breakdown Wed, Jan 18. Can loadout and move large loads Thur, Jan 19 after 72 hr notice. Ship small loads and spot light towers, mats, heaters misc on drill pad as required. Discussed rig prep and breakdown schedule for rig mod. Start mob smaller loads Tuesday, 1/16/2017 1 and spot on drill pad. Mob large rig loads after 72 hr notice is given. Spot light towers, work shop, heaters, mats as required for rig -up. Spot large loads as required when arrive. Should take 3 days to move, 7 days to rig up. Rig needs housing for rig -up crew. Discussed schedule and coordinating mob of other misc equipment. .----------------------------------------------------------------- - — -- — - - ------ —------------ -- — ----------- -- Continue ice road construction Refer to construction and camp daily reports for details Discussed rig prep and breakdown schedule for rig mobe. Start load out of mats & misc equipment Tue, Jan 17. Start rig breakdown Wed, Jan 18. Can loadout and move large loads Thur, Jan 19 after 72 hr notice. Ship small loads and spot light towers, mats, heaters misc on drill pad as required. Discussed rig prep and breakdown schedule for rig mod. Start mob smaller loads Tuesday, and spot on drill pad. Mob large rig loads after 72 hr notice is given. Spot light towers, 1/17/2017 2 work shop, heaters, mats as required for rig -up. Spot large loads as required when arrive. Should take 3 days to move, 7 days to rig up. Rig needs housing for rig -up crew. Discussed schedule and coordinating mob of other misc equipment. Drilling pad finished ready for mob drilling equipment. All camp modules on camp pad location. .----------- —--------------- _------------------------------ ------------------_--_ _--------------------- Continue ice road construction Refer to construction and camp daily reports for details Continuing to break down rig for rig move. Prep to load trailers with misc rig equipment, mats, etc. Load trailers with misc equipment tomorrow and haul same. Thursday load first group of large loads and haul same Thrusday night. Continue load out and hauling until rig is moved. Load and move shop with first group of large equipment loads. Hauled misc equipment to location, heaters, light poles, matting 1/18/2017 3 board cover, etc. Office skid hauled to location. Baker DD skid and CanRig skid in route to Deadhome for mobe to location. Should be in DH by the weekend. Contacted Baker, CanRig and Baroid with heads up for moving skids to location Jan 24. Have hands ready for dg up. Trash containers being sent out. ....................... ........................................ -------------------------------- -------''-- Refer to construction and camp daily reports for details Continue to prep rig for rig move Generator for the Drilling office, switch gear and GCI Comm building mobed to drill site, DSM witnessed setting of cellar ring and conductor HES grouted same, in place at 03:30 Rig up crane arrived on location Caring skid and jars are in Deadhorse Discussed landing 1/192017 4 joints with New Baker shop Supervisor and made sure that GE Vetco communicated correct Info to Baker Set up with GBR to provide a base plate for the conductor that will be installed at the same time as the 4" top job ports after the rig is on location Page 1 4/24/2017 10'54 AM Refer to construction antl camp daily reports for at it Sent 6 loads of mist. rig equipment including matting boards, rig loader and gas buster to location Rig move on hold due to low temperature Rig Manager and 1/2012017 5 Crew members travel to location. Cut cellar ring off @GL. Set cellar cover. .__________________________------ ______---------------------- — _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ —- _ _ _ _ _ _ _ — _ _ _ _ _ _ _ _ — _ _ _ _ Continue ice road maintenance and RIU of drilling camp, dressed pad around teller ring moved rig components and staged on pad, laid out liner and matting boards for rig pony subs, set subs heavylwide loads arriving at guard shack starting at 03:00 Plan Forward: R/U rig over the 1/21/2017 6 conductor, R/U Drilling office/generator/ envirovac unit on location move remaining 7-9 dg loads to location NOTE: Some cost adjustments _--_—__—-------------------------- __--______ Continue Ice road maintenance and RIU of drilling camp, set shop building, set rig sub with cranes, pinned derrick set rig water tank and dog house, scoped up dog house. Built containment for office generator and 1/22/2017 7 envirovac spotted equipment in containment, set in office buildings, raise mast, set in pits, pumps, boilers & generators, set in rig shop, set in 3 portable heaters to start warming rig .__---------------------- _------------------------ ---- __— _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ — _ _ _ _ Continue ice road maintenance and R/U of drilling camp & offices, power up rig lights, warm up boiler with heater, install centrifuge and rock washer, install auger, string up blocks and scope derrick, received pipe 1/23/2017 8 shed, set small shop pick up top drive and set on dg floor, hook up plumbing and steam lines, hang top drive, set in pipe shed modules, take on hot water to boilers, berm the rig, empty out the rig shop 1/24/2017 Continue ice road maintenance and R/U of drilling camp & offices, Cont to rig up electrical and plumbing system, Hang service loop. Hook up top drive house to VFD, install chains on rig water tank and fill with 200 bbls take water Cont R/U pits, install new retaining rings in mud pumps Hang torque tube, Install torque brace, offload wellhead equipment & put parts in shop, set in doorway landings, Received liquid mud warm storage conexes, matting boards and jersey barriers for mud dock, pipe racks and bull rails Received wellhead equipment ._...m-- ----------------------------------------------------- _ _ _ — _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _. _ _ _ _ _ _ Continue ice road maintenance and R/U of drilling camp. Hooked up electrical connections on top drive Installed link tilt bales on top drive test functions and rotation Installed baseplate with gussets on conductor installed two 4" ports for top job access measured conductor for cut off Cut conductor 55.5' below GL, dress cut Install landing ring for 9.625 casing Spotted GCI Comms unit and hooked up to electric power Installed insulation between office modules Install slip on starter head 1/25/2017 10 a 0.0 0.0 and flange & tested to 500psi for 10 minutes, OK Install valves w/ plugs on 4" ports, NIU diverter stack Received DP ,HWDP 3 pup joints, handling tools, safety valves and 24'x11" spool Baroid mud lab, Caring mud logging skid, Baker skid and rig envirovacTwo 12.25' and one 8.5" milltooth bits and 80 pallets mud material Page 2 4/2412017 10:54 AM 1/28/2017 1/27/2017 1/2812017 1/29/2017 fH 12 13 14 Continue ice road maintenance and R/U of drilling camp. Set last 2 sections of diverter line with cmne,instali Katch Kan under rig floor, service shakers and solids control equip R/U vac system in rock washer, take on water to rig tank, check nitrogen precharge on accumulator bottles, 5 of 6 backup bottles low, ordered more nitrogen from deadhorse, install gas alarms hook up comm system,load pipe shed with 4" DP, strap and tally 70 jnts, set 600 bbi upright water tank, set mud lab and Baker DD units, tie down diverter, finish R/U derrick board lights and SRL, Ran operational ESD test on boilers OK, test ESD on mud pumps OK, hooked 0.0 0.0 up ESD hoses on Top Drive generator and both rig generators, tested OK, Installed containment at the end of the diverter line, spotted 400 bbl upright for base oil in containment behind rig pits spot & berm rig evirovac, organize mud products, set connexs for liquid mud products, take on water to pits and test valves & connections for leaks, inspect derrick, service TO GCI cont R/U comms Received load of mud material, 36 jnts 4" OF, directional and MWD tools, landing joints jars, and ACS spill containment conex .---------------------------------------------------- — ----- — - - — -- — -- — -- — -- — -- — -- — -- — -- — -- — -- — -- — -- — -- — - Continue ice road maintenance and R/U of drilling camp. Test mud lines w/ 120 psi air Fill line with water, pump through rig floor bleederw/ all 3 mud pumps, verify pump operation and stroke counters, blow down lines, GCI comms working, inspect drawworks and transmission Hook up Totco instrumentation and rig sense, calibrate gas alarms, refill N2 back up system for accumulator, check precharge, service derrick lights, PIU 35 stds DP and rack back, fix heater on centrifuge, reinstall 2 derrick lights, test gas alarms operating correctly Cont rig up of Mudlogging and MWD 0' 0.0 0.0 equipment, load BHA components in pipe shed Transfer water between mud pits and test PVT alarms. Trouble shoot level indicator on trip tank Continue calibration of Totco - Rig Sense, Pump Pressure, % Flow, and audible alarms Spot cutting box under cutting auger and Berm area around, berm and spot tanks for trac hoe cuttings freeze tanks Received Baker DO tools, cement silo,conex of office chairs and tables, trac hoe matting boards and bins for cuttings storage in adverse weather, ----------------- -------------------------- -------------------------------------------- AOGCC Petroleum Inspector, Lou Grimaldi, Witnessed Diverter test and provided rig acceptance to commence operations Continued rigging up Arctic Fox drilling rig, Cleaned and organized rig. Moved Baker Hughes Surface BHA equipment into pipe shed. Loaded 290 bbls of 10.1 ppg Spud Mud into pits. Moved surface casing landing joint into pipe shed to warm up Pre -spud meeting (PJSM) with rig crew and service hands RIH w/ 12- 1W' bit and 4", 28.38 ppf (adj wt) HWDP tag up at 103'. Spud Horseshoe 6.0 0.0 #1 at 11:50pm on 1-27-2017. Drill with fresh water @ 300 gpm, 110 psi, 30 RPM, 1 - 5 k Torque, Drill ahead to make connection at 132'. Hole had some fill and could not get back to bottom. Switch to Spud Mud at Continue to drill from 110'to 192'w/ 10.1 ppg, 180 vis spud mud 300 gpm, 30-40 rpm, 5 -10 k WOB,1 - 2 k torque. No gravel or sand in returns, only clay and wood POOH, back ream tat stand (132'), pump out 2nd stand (7(') and pull last stand with elevators. Blow down top drive and clean clay off bit. ._--------------------------- _------------------- ------------ — -- — -- — -- — -- — -- — -- — -- — -- — -- — -- — -- — -- — -- — -- — - Clean rig floor prep for BHA P/U BHA 2 P/U BCPM (bidirectional communications power module),program tool,M/U filter PJSM source handling install sources C/O elevators for DP PJSM on directional drilling surface, discussed diverter operations and crew responsibilities, held diverter drill with crew 2 min response time P/U STD OF 5" HWDP Drilled F/ 192' Tl 545', @ 514 GPM, 1200 PSI, 60 RPM, 20 - 25k WOB, 1.3 TORO, 55k PU, 54k SO, 54k ROT Wf, 10.1 PPG Mud, 538'MD=TVD, 3.67deg INC, 1,038' 12.0 10.1 9.22 DEG AZI, 18'N, 1.69'E, 0.25 DLS Drilled from FI 545' T/ 1,038', @ 514 GPM, 1300 PSI, 80 RPM, 25 - 30k WOB, 1-6 TORO, 65k PU, 62k SO, 63k ROT WT, 10.2 PPG Mud, 850' MD, 849' TVD, 4.46 deg INC, 10.97 DEG AZI, 38' N, 5'E, 0.7 DLS Transfer 9-5/8" casing, to pipe barn, drift and tally same Page 3 4/24/2017 10:54 AM Drilled from F/ 1,038' Tl 1,102', @ 554 GPM, 1950 PSI on bottom, 1800 PSI off RPM 60-80, WOB 20.30k, TORO on 3-6k, TOROofft-2k, PU 64k, SO 64k, ROT 63k Trouble shoot Top Drive Drilled from FI 1,102' T/ 1,227', @ 540 GPM, 2055 PSI on bottom, 1800 PSI off RPM 60 -80, WOB 20 - 30 k, TORO on 3 - Sk, TORO off 1 - 2k, PU 64k, SO 64k, ROT 63k Max Gas 50 Units Continue drilling 12-1/4" Surface Hole FI 1,227' T/ 1,685', @ 525 GPM, 2100 PSI on bottom, 1930 PSI off RPM 60 - 80, WOB 20 - 30 k, TORO on 3 - 5k, TORO off 1 - 2k, PU 75k, SO 72k, ROT 72k Max Gas 166 Units Started Back -Reaming full stands at 1,475' Drill 12-114" Surface Hole F/ 1,685' TI 1,947', @570 GPM, 2430 PSI on bottom, 2170 PSI off RPM 60 - 80, WOB 1/30/2017 15 2,160' 21.0 103 30 - 35 k, TORO on 3 - 6k, TORO off 1 -3k, PU 78k, SO 73k, ROT 75k Max Gas 168 Units Torq up to 13k while back -reaming F/ 1,710' T/ 1,770'. Worked area until clearNo Gains / No Losses Drill 12-114" Surface Hole F/ 1,947' T/ 2,032', @ 570 GPM, 2430 PSI on bottom, WOB 35k Pump No. 1 lost power. Trouble shoot and return to drilling. Drilled from F/ 2,032' T/ 2160', @ 565 GPM, 2227 PSI on bottom, 2070 PSI off RPM 60 -80, WOB 25 - 30 k, TORO on 3 - 6k, TORO off 1 - 3k, PU 82k, SO 75k, ROT 75k Some costs adjustments included --------------------------------------------------------------- Drilled from F/ 2160'T1 2230' ( 2201.23 TVD), @ 640 GPM, 2350 PSI on --- bottom, 2120 PSI off RPM 60 - 80, WOB 30 - 35 k, TORO on 3 - 5k, TORO off 1 - 3k, PU 83k, SO 78k, ROT 76k Circ and Cond pump 35 bbl 300 vis sweep, 550 GPM, 1890 PP, work pipe 40 RPM, 1-2K TO, sweep back 45 bbis early TOH, 20-25K overpull, pump out to top of stands, 2230 to 1935, 550 GPM, 1890 PP, work pipe through tight spots 2140 and 1950, PIU 80K S10 75K max gas 80 units Pump out 1935 to 1630, 560 GPM 2150 PP, PIU 75K SIO 65K TIH 1630 to 2230 MD, PIU 80K S/O 75K Circ and Cond pump 35 bbl 300 vis sweep, 560 GPM, 2150 PP, work pipe 40 RPM, 1-2K TO, sweep back 41 bbls early TOH 2230 to 1590 PIU 75 -BOK work tight spot at 1630 to 1640 TOH, pump out 1590 to 1280, $10 and PIU with pump off to make sure each STD is clean, 540 GPM 2000 PP P/U 70K S/O 60 K 1131/2017 16 2,230' 5.5 10.2 Condition mud, circulate at 1,280' MD to remove clay cuttings from holeContinue to pump out of hole F/ 1,280' T/ 1040'. PU 67k, SO 65k, 550 GPM, 1800 PSI Remove clay ball from Riser Nipple and Flow Line Continue to pump out of hole F/ 1,040' Tl 731'. Flow Check well at 4" HWDP. No Overpull Continue to pump out of hole F/ 731' T/ 233'. at 5" HWDP. No Overpull Pump out of hole F1233' T/ 140' PJSM - Handling RA Source. Clear floor and Baker MWD remove source from GR tool and load into Source Box Continue laying down BHA F/ 140'108' Download MWD data Finish laying down BHA, Drain motor and break off bit ------------------------------------- _--------------- - _ _ _ _ _ _ _ _ - _ _ - _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ - _ _ - _ _ _ - Ciean and clear rig for upcoming Casing operation R/U to run 9518" Casing. Remove Short Bails, Change Saver Sub to 4-1/2" IF, Install 15' Bails Move equipment up to rig floor PIU and RIH w/ 9.5/8", 53.50#, BTC, MOD L-80 Casing. Use BOL 2000NM pipe dope Attach Bow Spring centralizers as per tally sheet. Torque pipe to 8k ffdb Joint #3 cross - thread, lay -out same. Pipe appears to be floating, Circulate Bottoms up every 5 joints to clean wellbore, Break circulation every other joint to prevent Top Drive freezing TIH F/ Surface T/ 1,500' Continue TIH. Land 2/1/2017 17 2,230' 0.0 10.4 out GE-Vetco Hanger on Load Shoulder in Conductor. Stick Up above RKB 4.93' Float Shoe at 2,213.56', Rat Hole 16.44' PIU 124k, S/O I I Sk. Circulate hole clean at 130 SPM (250 GPM), 220 PSI Losses per Tour 0 bbls RID casing equipment and continue to circulate hole to achieve desired mud properties. Current mud properties: MW 10.2, YP 18, VIS 55, Ph 8.2, GELS 6,8,11 Page 4 4/24/2017 10:54 AM I 2/2/2017 2/3/2017 2/4P20f7 2/5/2017 18 19 20 Rig down Elevators, Long Bails, False Table, Tongs, and clean rig floor, change out Saver Sub pick up Drilling Sails and DP elevators Move HWDP to drillees side on pipe rack M/U Cement stinger assembly and RIH T/ 1180'. PIU 42k, SIO 42k TIH w/ Stab -In tool F/ 1180' T/ 1886' Bring Cement Head up to rig Floor and assemble TIH FI 1886' T/ 2116' PIU Cement head and stab into Float Collar. PIU 55k, S/O 54k. Set 20k lbs down on Float Collar with Stab -In tool. Chain down Cement head. CBU at 5 bpm to confirm seals holding in stinger/float. All OK. Continue circulating PJSM for Cementing operations Pressure test cement lines 300 psi Low, 3000 psi High, hold for 5 min. Pump cement as per program: 40 bbl Spacer @ 10.5 ppg, (add 1 gal Red dye @ 20 bbl) 216 We Lead 2,230' 0.0 10.2 cement, Permafrost L @ 10.5 ppg, 4.74 cu -(tisk, 32.51 gal/sk at 4 bpm.48.4 bbls Tail cement, SwiftCem @ 15.8 ppg,1.173 cu.ft/sk, 5.13 gal/sk at 2 bpm. Shut down and drop 4" latching wiper plug. Displace with 23.5 We of fresh water. 87 We cmt to surface Bump plug wl 1500 psi at 22:00 hm, hold for 3 min and bleed back 1/4 bbl. Float holding. Pull out of float with stinger and circulate water out of drill pipe Remove Cement head and rack back 1 stand of OP. Flush stack, wash and function Annulur Pull 9-518" landing joint. Inspect Annular and verity clear of cement Continue to clean up rig Floor and start to break down Annular --------------------------- --------- ---------------- ---- -- — -- -- - — -- — -- — -- — -- — -- — -- — -- — -- — -- — -- — -- — - Remove knife valve, Remove Diverter Line and Diverter with crane SIMOPS - Cleaning Pits, Rockwasher, Change out rubber goods in suctions with Oil Based Compatible items, change out Centrifugal pump on mix pit No. 2, cleaned all cement manifold valves Picked up GE-Vetco Starting Head and Well Head. Measure and cut conductor pipe. Install 11" 5M bottom flange, P/U and install Upper and Lower MB -230 wellhead. 2,230' 00 10.0 Test VG seals on bottom flange to 1,500 psi for 15 minutes. Good Test Nipple up 11" 5000 psi Schaffer Annular and 11" 5000 psi Schaffer double and single BOPs Attach Koomey lines and Choke / Kill hard lines 2-7/8" x 5" VBR Top and Bottom, Blind in middle .---_---_------------------------------------------------ --------------------------------------_--_. Complete installation of Koomy lines, Choke/Kill lines, winterize piping, install Riser, Catch -can. Load and strap 4" XT -39 OP into shed, total 179 joints Finish NIU BOP Set test plug and PIU test joint. R/U to test BOPE. Shell test BOP, Choke manifold, and Choke & Kill lines to 4000psi. Good test Rig down test equiment, Pull test plug, set wear bushing (9-1/4" in ID) PIU and rack back 88 joints (44 stands) of DP. Transfer HWDP & Jam 2,230' 0.0 10.0 from DS T/ Off DS of derrick PJSM, M/U BHA N3 as per plan (see details below), torque all connections to spec. Plug into MWD and establish communication w/ surface computers. Complete download prepare rig for AOGCC inspection ..... — —------------------------------------------------ ----"--------------------------------------- Complete prep of BOPE for AOGCC inspection AOGCC Inspector Matt Hererm arrived and commenced testing of ROPE. 250psi low, 4,000 psi high Hold each test for a minimum of 5 minutes. Test Choke and Kill lines to 2,000 psi. Good tests. RID test egipment, Pull test plug, and install wear bushing (ID=9-114", OD=10.3/4", L=2.81') PJSM for wireline, R/U Schlumberger E -Line RIH wl CBL equipment, log F/ 2,100' T/ Surface RID Schlumberger E -Line PJSM for handling BHA. M/U 8-112" BHA, torque connections as directed. Complete shallow test on Baker MWD. Send downlink 426 GPM, 810 psi Continue RIH F/ 186' T/ 679' MD. PU=52k, SO=52k Continue RIH F/ 679' T/ 1,928' MD. Torq every DP connection to 2,230' 0.0 10.0 21.Sk ft -lbs Conduct Well Control Drill - Trip Drill. Crew response tmin 45sec Continue RIH F/1,928' T/ 2,052' MD. Torq every DP connection to 21.5k ft -lbs, PU=70k, SO -67k RIH to 2,116'tag up. Hold PJSM for Casing pressure integrity testRU surface lines and test to 300 psi, inspect, no leaks. Pressure up casing to 250psi and hold for 5 min, pressure up to 4,245psi w/ 2.8 bbls WBM and hold for 30 min. Pressure bled to 4,237psi. Good Test Bleed back +/. 2 bible RD pressure test lines. Commence drilling out casing shoe track. Page 5 4/24/2017 10'.54 AM 2/6/2017 2/7/2017 22 23 2/8/2017 24 Continue drilling ahead. Tag up @ 2124' MD, 7-10K WOB 3-6K TORQUE Drill T/ 2143' MD, PU=70K, 5O=65K, ROT= 65K @ 80 RPM, 1.SK TO. Increase in % Flow. Flow Check. Monitor well. Mud returns contaminated / Clabbored. Condition mud. PJSM on OBM displacement Clean all pits / surface equipment and prep for OBM Displace WBM w/ 10.4 ppg, OBM @ 3 BPM, 220 PSI Continue cleaning Mud Pits and Rockwasher Resume drilling, Break Circ- Ramp Pump T/ 550 GPM=1700 PSI; send MWD downlink Drill cement F/ 2139' T/ 2230', Drill new formation F12230' TI 2250' (2185' = 2221' TVD) RPM= 6050 TO ON=24K TO OFF=1 K ; GPM=450 PUMP ON= 1421 PSI PUMP OFF=1407PSI WOB= 5-10K; PUW= 70K; SOW= 69K; RTW-- 70K; MW=10.4ppg. Take SPR CBU until 2,670' 18.0 104 Shakers clean. 10.4 ppg in/out, Pull 2 studs bring bit Into casing Commence FIT, Pump 1/2bpm and record pressures, pump total 3.75 bbls, to 404PSI (13.9 EMW) Hold for 10 Min. Pressure fell to 334 psi, bleed back 2.5 bbls. Report results to office Continue circulating Approved to continue drilling. Good Test. Pit Drill, 2.0 min response timeDrill ahead F/ 2250' TI 2296'. RPM= 110 TO ON=2-4K; TO OFF= 1-2K , GPM=528 @ 1675 PSI WOB= 5-110K; PU=72K; SO=70K; ROT=72K; Drill ahead F/ 2296' T/ 2670 RPM= 118 TO ON=24K; TO OFF= 1-21K, GPM=509 @ 2480 PSI ---------- _---- _----------------------------- ------ _ ---- ------------------------_ - _ _ -- _------------- Drill ahead F/ 2670'T/ 3030' RPM 120, TO on 2Sk, TO off 1.2k, GPM 542, Pump On 2870 psi Pump off 2810 psi, WOB 5-10k, PU 80k, SO 75k, ROT 76k SPR @ 2670', MP #1 @ 3BPM = 230, 4BPM = 350, MP #2 @ 3BPM = 230, 4BPM = 330, MP #3 @ 3BPM = 260, 4BPM = 350, Drill ahead F13030' T/ 3483' (3367' TVD) RPM 100, TO on 3-6k, TO off 1-3k, GPM 552, Pump On 3069 psi Pump off 3034 psi, WOB 8-10k, PU 90k, SO 87k, ROT 88k, MW 10.4 ppg Pump 46 bbls of hi -vis sweep. Increased cuttings on BU. SPR @ 3483', 3367' TVD SPR @ 3367', MP #1 @ 3BPM = 250, 4BPM = 400, MP #2 @3BPM=250,4BPM=400, MP#3@3BPM=250,4BPM=400, 10Stand 4,125' 16.1 10.4 Short Trip, Flow check -well static. POOH F/ 3483' T/ 3213' No Pump, No Rotate Pulled 25k over at 3240', Wiped clean RIH , No problems, Go back t bottom, No 811 Drill ahead F13483' T/ 3772' (3623' TVD) RPM 110, TQ on 3- 7k, TO off 1-2k, GPM 560, Pump On 3123 psi Pump off 3109 psi, WOB 8- 10k, PU 98k, S0 920k, ROT 94k. ECD 11.14Drill ahead F13772' T14125' (3950' TVD) RPM 65-110, TO on 3-7k, TQ off 1-2k, GPM 560, Pump On 3162 psi Pump off 3109 psi, WOB 8-10k, PU 98k, SO 920k, ROT 94k. ECD 11.14 Add LVT @ 2 bbl/hr .--------------------------'---- ---------------- -------------- ------------------ _ -- _ _ - _. ---------------- - - Drill ahead F/41126' T/ 4474' MD (4295' TVD) RPM 65-100, TO on 3Sk, TO off 1-2k, GPM 528, Pump On 3260 psi Pump off 3200 psi, WOB 8-12k, PU 105k, SO 90k, ROT 90k. ECD 11.05 Add LVT @ 2 bbllhr SPR @ 4350' MD, MP#13BPM=300PSI,4BPM=420, MP#23BPM=300PSI, 4BPM=445 MP#3 38PM=310PSI, 4BPM=450 Drill ahead F14474' T/ 4599' MD RPM 65-100, Tq on 3-9k, TO off 1-2k, GPM 432, Pump On=2434 psi Pump off 2335 psi, WOB 8-12K PU 107k, SO 94k, ROT 96k. ECD 11.13 Add LVT @ 2 bbllhr CBU Looking for core point. GPM=435 @ 2380PSI Drill @ 50 FT/HR Fl 4599' T/ 4750' MD (4569' TVD) Designated Core Point, As Per GEO RPM 60-70, TO on 2Sk, TO off 2.3k, GPM 497, Pump On=3029 psi, Pump off 3004 psi, ECD 11.02 WOB 8-12k, PU 106k, SO 97k, ROT 100k, Add LVT @ 4,750' 16.1 10.4 2 bbl/hr, MAX GAS =145 Units Mix and Pumb 25 bbl, 200 vis, Sweep @ BU noted 20% increase in cuttings SPR @ 4569' MD, MP#1 38PM=450PS1, 4BPM=420, MP#2 3BPM=300PS1, 48PM=450 MP#3 3BPM=300PSI, 4BPM=490. Flow Check - No Flow POOH F/ 4750'T/ 4102' 10 Stand SIT W/O Pumps or Rotation. Flow Check w/ 5 stride pulledPU 18k, SO 90k RIH F/ 4102' T/ 4750'. Tag bottom -No Fill CBU GPM=510 @ 3170PSI, No increase in cuttings on BU. Flow check - No Flow Slug Pipe (21 bbl, 12.2ppg) POOH F14750' T/ Surface W/O Pumps or Rotation. No Problems. Handle BHA. Down load MWD. Rack back MWD / AutoTrak in derrick. Page 6 4/24/2017 10.54 AM Continue to Down load MWD. Rack back MWD I AutoTrek in derrick. Remove bit Clean rig Boor after trip due to OEM. Ready pipe shed to pick up core barrels PJSM M/U Coring assembly, Handle NMFlex Drill Collars, RIH w/ Coring easy to 1224' PU=50k, SO=50k RIH F/ 1224'T/ 4706'. PU=100k, SO=90k, Fill pipe every 1000', Break circ @ 3 BPM, 380 PSI MU to stand 66 &bwash down to 4750, Stage pumps up to 364 GPM, 1630 PSI Rot Wt 95K, 20 RPM, Off TO 1.9k, Add Weatherford tracer to mud and circulate volume 4X Drop diverter ball and seat @ 200 GPM, 580 PSI. Core 2/9/2017 25 4,840' 16.1 10.5 F/ 4750'T/ 4840' GPM=230, Pump 1070 PSI, RPM+40.60, TO On=2-10k, TO Off=1.5.2k, PU=100k, SO=95k WOB=2.5k Attempt to snap core. P/U to 25k over, saw 20k weight loss then pipe hung. Attemp to reset grapple and PIU again, jars fired. Unable to pull core easy. Work pipe and back ream to 4795' Continue backream TO 4750'@160 SPM, 1600 PSI, ROT 15 RMP, TQ 1-6k Circulate and condition mud while reciprocating pipe. Pump slug and POOH Continue POOH .____—------------------------------------------------- ----------------------------------- - _ — _ _ _ _ _ _ _ _ — _ Continue POOH V 226' per Weatherford Trip Schedule, Had to work stab into shoe, Continue POOH U 98' Lay down Core barrels, POOH & inspect bit - No chipped teeth & In gauge Make up core barrels, RIH w/ HWOP RIH V 4765' Ream V 4840' CBU @ 350gpm Drop Bali & seat, Core 114840' - V 2/10/2017 26 4,930' 16.1 10.5 4930', 250gpm, 60rpm, WOB 5k, TO on 3-7k, off 14k, PU 100k, SO 95k, Rot 97k Break off core w/ 25k over -pull, Back ream V 4830 .__— ----------------- -------------------------- _------------ _ _ _ _ _ _ _ _ _ — _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Continue Back reaming V 3530' POOH V 100' per core trip schedule, Trip drill LID core#2 & core barrel assembly, Retrieved 91' of core Monitor well for losses while clearing floor of coring tools - 0 losses M/U BHA #6, 2/11/2017 27 4,930' 0.0 10.7 LID Near Bit Gama, Plug into smart tools, M/U Bit, Circ & test tools RIH w/ HWDP RIH , PIU 20 jts DP, RIH Slip & cut Drlg line, Calibrate block height Continue RIH Cim & cond mud @ 4604' Mad pass 0 4604' _ V 4930', 480 Bpm @ 3000 psi, 2/12/2017 28 6,000' 19.5 10.4 PU 105k, SO 95k, Rot 100k, Tq 1.Sk DrIg f14930' - V 6000' Circulate up samples & HI -Vis sweep .__W__-_____-____------------------------------------- ----------------------------------------------- POOH _—__—__—___-_______—_______________________—_POOH V 4667', No tight hole, RIH V 6000' Circ. Hi -Vis sweep POOH V 675', No tight hole Rack back BHA, Down load smart tools, break bit Pull Wear 013/2017 29 6,000' 0.0 10.4 ring R/U & test BOPs -Annular V 250/2500psi, All other BOP Equipment 260/4000 psi, RID Test equipment Install wear ring R/U Schlumberger .____________— --------- _____________________________------ m W _Sonar_., Resistivif V.J jvu JiabL47L2A2W _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Run #2 PPC-MSIP.PPC-NGI 0losses Run #3 ECS-HNGS-CMR 014/2017 30 6,000' 0.0 10.4 0losses Run #4 MDT 0losses .v______________________________________-______— -------- _____________—_____—__—__—__—_______ Cont. Run #4 MDT, Move to set point #2 @ 1530 hm, #3 @ 0200 hm, #4 @ 015/2017 31 6,000' 0.0 10.5 0500 hm, 0losses .______________________________________________—-------------- —_____—__—__—__—__ - _____________—__—_______ Cont Run #4 MDT, Move to set point #4 0500 hm, LID Tools Run #5 XL Rock cores, Shot 42.100% recovery on core samples, Rig down e -line. 0 mud losses during WL work Prep to run tbg for P&A of open hole Move HWDP to left-hand side of derrick Service Top Drive & Draw - 2/16/2017 32 6,000' 0.0 10.5 works R/U Weatherford tbg tools Sundry 317-074 Approved for P&A and Plugback for Sidetrack A Includes logging cost and some full drilling season contract costs .______________________________________________---------------- — _ _ _ _ _ _ _ _ _ _ _ — _ _ _ _ _ _ _ _ _ _ _ —_ _ — _ _ _ _ _ _ _ _ _ _ _ — _ _ — _ PIU 3-1/2 Tbg for P&A of open hole, break circ periodically M/U Tbg release sub & test, RIH w/ DP V 5898' Wash f/ 6898'. V 6000' CBU - Max 3380 gas Space out DP, R/U to cement PJSM, Batch mix 35 bbis of Clean Spacer III, Test lines V 4500 psi, Pump 29.5 bbis spacer, 244.5 bbis of 14.5 ppg cement, Launch release dart, Pump 1 bbl cement, 5.5 bbis spacer, Rig displaced w/ 20.8 bbis MOBM, pressure up to 2800 psi to release tbg, Top 017/2017 33 6,000' 0.5 10.5 of TBG 2604' Pick up 40', Circ out spacers & excess cmt (112 bbis). Est top of the abandonment plug 2564' Mix & pump 29.5 bbis spacer, 43 bbis 17 ppg KO Cement, 5.5 bbis spacer, rig displaced wt 13.4 bbis MOBM, CIP 0200 hm, Estimated top of cement 2037' Pump wiper ball down DP, Circ out spacer, Circ & condition POOH Page 7 4/24/2017 10,54 AM 2/18/2017 34 2,030' 1.0 Change out washpipe on Top Drive Wash Inside of BOPs, Blow down MN BHA #7 RIH t/ 1825' Wash to top of cement @ 2030', Set t Ok on bit for 10.5 AOGCC Rep Lou Gramaldi Start new report for Horseshoe #1A side track _.___ __—___ IA Page 8 4/24/2017 10:54 AM Armstrong Energy, LLC Horseshoe Well # 1 Permit# 216-133 Daily Summary North Slope, AK Spud Date: 1127/2017 Rot Start Date: 01/16/17 PLAN Actual Rot Act COMMENTS Date Day Depth Depth Hrs MW 0 1/16/2017 1 - Finishingice road ______-____-__--_""_""_"-_""_- 1/172017 2 _ Flnsihingiee road/mapping-f oreamp/rig_move 1/18/2017 3--------------------------------------------------------------- _""_ Finish conductor snit cellar installation "____________"____" 1/192D17 4--------------------------------------------------------------- ____ Cut offcond/cellar of prop-ar heights, stage some rlgegprnt__ ---_- 1/20/2017 5 .______�_ __ Hig_move on hold due to cold weather ""__________""____- """""""-_---""""""""""""""""""----------------------� Continue ice road maintenance aaril RAf of drfiling cemp, dressed Ped 112112017 6 _________........__.________- _ _ _ around caller ring, install mats etc. Slarl_rgmobs ______________________"""_"___"""""_ _ _ _ Conue i tince road mairdenceanand WU of drilfi, g cemp, set shop 1/22/2017 7 "_ buildinSL-setrB sub with trans,+ pinned derrick__-_--_-"_" Continue ice road maintenance and RfU of drilling camp & offices, power 1/23/2017 8 up rig lights, warm Up boiler with heater, install centrifuge 1/24/2017 9.___________________________________________________________.__._""_ _Continue riWcomP mobs_ ""- _ _ _ _ _ _ _ _ _ _ _ =.. - _ _ _ _ _ _ ._______________...............___________ _ . _ . - - _ -1 _ _ _ _ _ linished F/U top Erive and function test, prep eonduMor, Install starting 1252017 10 -------------------- - __"_____0.0 __ head WU diverter stack_ _____"_ _"___"____-___ _-_________________"-..______ Finis Eiverter line,callbrate rig equip,set upriglll tanks, chock 1262017 11 0' 0.0 0.0 aceumulator,&IJ service Co ups___"_"-_--_-"_"-_-__- 7272017 72 ................ 00.0 """"___-_ 0.0 _ _ Calibrate ri equip 4 DP comms u rnildl ce co units rigged up . ______________________________ or t AtSGCC� r Brim nsped7`oi,lou Onmafdi�IVatressedl)werTei asr anti" provided rig acceptance to commence operations. Perform diverter test, spot cmt unit, receive first load spud mud, P/U BHA 1 spud at 11:50pm 1128/2017 13 ------ - 00 drM1P_182___________________.________ P/U tlireetionel BHA, PJ$M on diverter ops, tlrilg from 792' l0 1038 per 1292017 14 1+038' 12.0_________10.1 _ "_ direstigUIJAan--- __-_""_-"_--_-"_""_-"_-______ ______________ --------- - - - ----------- 1/302017 15 2+160' 21.0 10.3 _ Continue drilling ahead from 1,038'to 2160as per directional plan .......................__""............_________......._� _ _ _ _ . _ _ _ _ _ _ _. _ _. _ _ _ _ _. Reach cesing point of 2230', Clean & Condition hole, Make short trip, 7/312017 16 ,.. 2+230'_ 5.5 ....__ 70_2 _ _ POOH to run casigq_ - ________________________________________-_ "R/UCatingequipmenf, ATR 47 e-6IS'"31186W,, 9YLC5srg."Laridhangei ori load ring, circulate hole clean, RID Casing Equip, Condition mud for 2/12017 17 _.2,230'_ 0.0 10.4 ___4funeid lglr-_"-_-___ Condition mud for cement job. R/D Casing equip, RIH w/ stinger on DP, 222017 18 2230' 0.0 10.2 WU Cementers, Pump cement job, bump plug, begin to RID Cementer, ___________________________________________________________WD-6,;________.__________________________ erter, Clean pita and cement manifold, P/U starting head and WU 2/32017 19 2+230'. 0.0 ""_"""""" 10.0 BOPS _ _ Complete tl4-t doTa, P7Cf aT' AY39-6p (Tjofnta), SaI plug ana sTi6lr%et BOPS, P/U 8-1/2" BHA and download MWD.Install test plug, WU TIW and 2/42017 20 ,._2'230'_ 0.0 .... IB�t914st_ Tp_______.________.. _..-_____ "'"""" Complete AOG C ROPE teat, Run CBL, TIH W/ 8-1/2" BHA tag up at $124', 2/52017 21 2230' 0.0---______70.0 Perform ClT. Begin to drill out Shoe track_"_" ... U92 _____________..._.______________ Drilled shoe track, mutl became contaminated w/ cement, displace with 2/62017 22 --- 2,670' ------- 180 --------- 1.0.4 gqp. conduct FlT-Goodtest. Drill ahead Drill ahead F/ 2670'. T/ 3483'. Made /0 stand short trip at 3483'. Continue 2/72077 23 4125'_ 16.1""""__"_ 10.4 __ drilling F/3483' _T/L?S'__.__ Drill F/ 4125' T/ 4750' MD (4569' TVD) Core Potnt. CBU, ShortTrip, CBU, 2/82017 24 __ POOH__--_--_-"_""_--_""_""_""_-_________ 2/92017 25.__4�8_40'16.110b------------------- ______M/U Coring Eg_uipRGm A1H_end core F/4750_1/41I40'iPOOH POOH w/ core 121, UD core, M/U new inner barrel, RIH, Wash 114765'- V 2/102017 26 4 930' 16.1 10.5 4840', Cut core M2 It 4840 - V 4930, Back ream V 4830', POOH __________________"-.-___________________-_________________ _. _'0(56 _ _ _ _ _ _ _ _ 76 _ _ m_ _ _ _ _ _ _ . _ - _ . _ _ _ _ _ _ _ _ _ _ _ H w/ core e2, UD core &core barrel assembly, M/U Drig assembly, 2/112017 27 ....... 0.0 .......... 0.7 ................ _............ __"_ 911L P/U 20 Its DP, CW drly line FIlH,_____._.__""_""__"_" Circ 8 eonaition mud, Mad pass 4604 - 4930, Ong 4930 - 60001, circulate up 2/122017 28 +000' ............................. _saMRle9LcircVA1 eHl-Vistyeee_-_"-_--_--_--__"_"__" Wrper Trip t/ 4886, circulate Hf -Vis sweep, POOH, test BOPa, R/U 2/132017 29 6000' .......... SchlumbergarRun If I Soni c_ resistivity Logging- Run M2PPC-MSIP-PPCNGR_f3 __S"H_GS-_C_MR_, Run 124 2/142017 30 _ 6,000 0.0 70.4 MDT "_""_"-_--_--_-"_--_-______ _ _ ____________________ _______________________________.. _. _ _ _ _ _ _ _ _ _ 2/152017 310.0._______ 10.5 _ _ g login- ri n #4 MDT ________________________________ Log9�ng-FinRlliunkklDTrFFuri k57rClioek core, 1009; sample recovery, RID Schlumberger, Prep to RIH w/ tubing for P&A of open hole, 2/162017 32 __ 6000. 0.0 ""--__-_70_5 WU Weaihert9)_d_tegjy, P TT __- .____-__ ____ _____________________________________________ ash 5898-6000', ump IGTtig or cementing, p7rf Re ease too, spacers & cmt, release tgb, circ, Pump KO Cement, POOH V 19001, circ out 2/172017 33 6000'_ ............... 4P.F9Cs..P991i______""_."_______."_""-______- Change out Washpipe on TD, Wash Inside of BOP,, M/U Kick off BHA, RIH, 2/18/2017 34 2,03D' 1.0 10.5 Wash f/1825' -tau cmt at 2030' 5�. Page 1 31252017 7:57 AM Survey Approval Report Horseshoe#1 Page 1 of 6 riRG BAKER HUGHES REFERENCE Operator WELLPATH IDENTIFICATION Armstrong Energy,LLC Slot lHorseshoe #1 rea North Slope, Alaska Well jHorseshoe#1 Field Armstrong Energy, LLC North Slope Wellbore 1-lorseshoe#1_awp Facility Exploration Projection System NAD27 / TM Alaska SP, Zone 4 (5004), US feet Software System WellArchitect® 5.0 North Reference True User 11.11ricard Scale 0.999922 Report Generated 03/10/17 at 14:42 Convergence at slot 1.060 West Database/Source file IWA ANC Defn/Horseshoe#1.xml ELLPATH LOCATION Local coordinates Grid coordinates North[ft] East[ft] Easting[US ft] Northing[US ft] Geographic coordinates Latitude Longitude Slot Location 0.00 0.00 360290.00 5867909.00 70002'48.595"N 151007'03.989"W Facility Reference Pt 360290.00 5867909.00 70002'48.595"N 151007'03.989"W Field Reference Pt 360315.00 5867922.00 70002'48.728"N 151007'03.276"W IWELLPATH DATUM Calculation method IMinimum curvature lArctic Fox (RT) to Facility Vertical Datum 2.00ft Horizontal Reference Pt slot Arctic Fox (RT) to Mean Sea Level 42.00ft Vertical Reference Pt Arctic Fox (RT) Arctic Fox (RT) to Ground Level at Slot (Horseshoe #1) 42.00ft MD Reference Pt Arctic Fox (RT) Field Vertical Reference Mean Sea Level Survey Approval Report Horseshoe#1 Page 2 of 6 ri.9 LLPATH DATA (97 stations) t = lnterpolatedlextrapolated station MD R Inclination Azimuth D ft East Grid East S ft Grid North S R Latitude LongitudeDL Comments MOM 0. 0.00 355.03 -4 .0 9 . 4 . 1 1 07 03.989 w 18.50 O.D0 355.03 18.50 -23.5000 360290.00 5867909.00 70°02'48.595"N 151°07'03.989"W 0.00 212.97 0.77 355.03 212.96 170.9611 M7.29O.22 360289.91 5867910.30 70°02'48.608"N 151°07'03.992"W 0.40 293.96 3.05 3.76 293.90 251.9002 360290.05 5867912.99 70°02'48.634"N 151"07'03.989"W 2.83 355.96 3.07 4.64 355. 2 313.8222 360290.36 5867916.29 70°02'48.66T'N 151°OT03.982"W 0.08 422.92 3.39 6.14 422.67 380.6758 360290.78 5867920.04 70°02'48.704"N 151°07'03.972"W 0.49 476.96 3.52 8.47 476.61 434.61 ..00 360291.26 5867923.26 70°02'48.736"N 151°07'03.960"W 0.35 538.88 1 3.6701 9.2201 536.41 496.411 18.12 1.591 360291.92 5867927.08 70°02'48.773"N 151°OT03.943"W 0.25 600.93 3.4801 9.58 600.34 558.34 21.93 2.22 360292.63 5867930.89 70°02'48.811"N 151°07'03.925"W 0.31 663.20 3.57 12.0 662.49 620.49 25.69 2.84 380293.41 5867934.63 70°02'48.848"N 151°OT03.904"W 0.28 725.37 3.57 11.13 724.54 682.54 29.49 3.72 360294.26 5867938.41 70°02'48.885"N 151°OT03.882"W 0.09 788.70 4.03 10.98 787.73 745.73 33.60 4.53 360295.14 5867942.51 70°02'48.926"N 151°07'03.859"W 0.73 850.49 4.46 10.97 849.35 807.35 38.09 5.40 360296.09 5867946.99 70°02'48.970"N 151,or03.834"W 0.70 912.10 4.39 9.92 910.78 868.78 42.77 6.26 360297.04 5867951.64 70°02'49.016"N 151°07'03.809"W 0.17 9 4. @7 .75 9 1.75 4 . 3 6.98 380297.65 586 956.69 70602'49.066"N 15 T03. 88"W 0.921 1038.00 6.19 359.25 1036.18 994.18 53.88 7.23 360298.22 5867962.73 70°02'49.125"N 151°07'03.781"W 2.33 1099.04 6.76 357.14 1096.83 1054.83 60.75 7.01 360298.12 5867969.61 70"02'49.193"N 151°07'03.787"W 1.01 1161.96 7.30 357.22 1159.27 1117.27 68.45 6.63 360297.89 5867977.31 70°02'49.268"N 151°07'03.798"W 0.86 1225.20 7.74 357.44 1221.97 1179.97 76.71 6.25 360297.65 5867985.58 70°02'49.350"N 151°07'03.809"W 0.70 7. 57.34 1 1 4 . 6 5. .86 0297.42 5 67 .1 -77-0162747.4-377 51 OT 3. 0.5 1350.34 8.57 357.21 1345.85 1303.85 94.38 5.42 360297.15 5868003.26 70°02'49.523"N 151°07'03.833"W 0.76 1413.08 8.73 357.31 1407.88 1365.88 103.80 4.97 360296.88 5868012.69 70°02'49.616"N 151°07'03.846"W 0.26 1470.59 9.62 356.30 1464.65 1422.65 112.96 4.46 360296.53 5868021.85 70°02'49.706"N 151°07'03.861"W 1.57 1534.79 10.30 355.35 1527.88 1485.88 124.03 3.65 360295.92 5868032.94 70°02'49.815"N 151°07'03.884"W 1.09 1 10.9 .39 8 1546. 13 . 7 2.80 295.29 5868 8 70 0 '49.931" 151°OTO . 8' .03 1659.77 12.36 357.41 1650.51 1608.51 148.08 2.14 360294.86 5868057.01 70°02'50.052' 151°07'03.927"W 2.36 1721.74 13.12 357.64 1710.95 1668.95 161.74 1.55 360294.52 5868070.67 70°02'50.186"N 151°OT03.W'W 1.23 1784.90 13.03 357.71 1772.48 1730.48 176.01 0.97 360294.20 5868084.95 70°02'50.326"N 151°OT03.961"W 0.14 1845.96 13.48 357.08 1831.91 1789.91 190.00 0.34 360293.82 5868098.95 70°02'50.464"N 151°OT03.979"W 0.77 1 .96 15. 356.4801 1890.001 1848.00 2W.99 -0.511 360 93.25 5868113.95 70°02'50.6110N 151°OT04.004 W 3.38 Survey Approval Report Horseshoe#1 Page 3 of 6 MCA .2 BAKER HUGHES ELLPATH DATA (97 IDENTIFICATION Operator Armstrong Energy,LLC Slot Horseshoe #1 Area North Slope, Alaska IWO lWorseshoe#1 Field Armstrong Energy, LLC North Slope Wellbore jHorseshoe#1_awp j Facility Exploration I I ELLPATH DATA (97 stations) MD ft Inclination M Azimuth M TVD ft m"170=53 IVDSS ft North East ft Grid East US ft Grid North US ft Latitude Longitude DLS Comments I1DOft 1968.91 16.40 357.98 1950.53 77272 -1.34 6029 .73 5868131.23 70°0250.781 151'5777197 1.57 2027.12 16.14 357.62 2006.40 1964.40 238.56 -1.97 360292.41 5868147.54 7002'50.941"N 151"07'04.046"W 0.48 2089.21 16.26 357.67 2066.03 2024.03 255.87 -2.68 360292.01 5868164.85 70°02'51.112"N 151'07'04,066"W 0.19 2152.79 16.25 358.06 2127.07 2085.07 273.65 -3.34 360291.68 5868182.65 70°02'51.287"N 151°07'04.085"W 0.17 2164.33 16.1 358.32 2138.15 2096.15 276.87 -3.45 360291.63 5868185.87 70`02'51.318"N 151"07'04.088"W 1.07 2263.77 15.85 358,74C 2233.74 2191.74 304.27 -4.15 360291.43 5868213.27 70"02'51.588"N 151'07'04.108"W 0.32 2326.24 15,490,1.00CI 2293.89 2251.89 321.14 -4.19 360291.70 5868230.14 70`02'51.754"N 151'07'04.110"W 1.13 2369.13 14.63 4.72 2354.52 2312.62 337.45 -3.39 360292.80 5868246.43 70°02'51.914"N 151°07'04.087"W 2.06 2450.45 14.74 6.62 2413.93 2371.93 352.92 -1.85 360294.62 5868261.87 70°02'52.066"N 151°07'04.042"W 0.81 2513.26 15.15 8.51 2474.62 2432.62 368.97 0.28 360297.05 5868277.88 70`02'52.224"N 151"07'03.981"W 1.01 2575.77 15.60 15.53 2534.90 2492.90 385.15 3.74 360300.80 5868293.99 70"02'52.383"N 151°07'03.881"W 3.06 2638.81 15.99 26.28 2595.57 2553.57 401.11 9.86 360307.21 5868309.83 70°02'52.540"N 151°07'03.705"W 4.68 2700.29 17.2101 36.18 2654.50 2612.50 416.05 18.98 360316.60 5868324.60 70"02'52.687"N 151°07'03.442"W 5.00 2761.81 18.0701 45.18 2713.14 2671.14 430.12 31.12 360329.00 5868338.44 70"02'52.825"N 151`07'03.093"W 4.64 2824.50 18.58 51.64 2772.65 2730.65 443.17 45.85 360343.96 5868351.22 70°02'52.954"N 151°OT02.668"W 3.34 2887.14 19.570QI 57.83 2831.86 2789.861 454.95 62.56 360360.88 5868362.69 70°02'53.070"N 151"07'02.187"W 3.59 2949.01 20.92011 62.63 2889.91 2847.91 465.55 81.14 360379.66 5868372.95 70"02'53.174"N 151"07'01.652"W 3.46 3011.26 22.4801 65.61 2947.75 2905.75 475.58 101.85 360400.54 5868382.59 7002'53.273"N 151'07'01,056"W 3.07 3073.84 23.9001 68.24 3005.27 2963.27 485.22 124.52 360423.39 5868391.81 70°02'53.367"N 151'07'00.403"W 2.81 3136.62 254201 70.37 3062.33 3020. 494.46 149.03 360448.05 5868400.60 70°02'53.458" 151°0659.697"W 2.80 3199.44 27.6101 72.21 3118.54 3076.54 503.44 175.59 360474.78 5868409.09 70°02'53.547"N 151`06'58.932"W 3.72 3261.54 28.850QI 72.40 3173.25 3131.25 512.36 203.57 360502.92 5868417.50 70°02'53.634"N 151"06'58.126"W 2.00 3323.60 29.0801 73.36 3227.55 3185.55 521.21 232.29 360531.79 5868425.82 70°02'53.721"N 151"0657.299"W 0.84 3386.34 29.060qj 72.76 3282.38 3240.38 530.09 261.46 360561.11 5868434.17 70°02'53.809"N 151`06'56.459"W 0.47 3448.23 29.1301 73.03CI 3336.46 3204A6-[- 38.94 290.22 360590.03 5868442.49 70'02'53.896'N 151°06'55.631"W 0.24 3510.46 28.97 72.70101 3390.86 3348.86 547.85 319.10 360619.06 5868450.86 70°02'53.983"N 15106'54.799"W 0.36 3572.39 29.13 72.75 3445.00 3403.00 556.78 347.81 360647.93 5868459.26 70°02'54.071"N 151°06'53.972"W 0.26 3634.43 28.67 72.27 3499.32 3457.32 565.79 376.41 360676.69 5868467.74 7002'54.160"N 151"06'53.148"W 0.83 3695.92 27.464 71.964 3553.58 3511.58 574.67 403.94 360704.37 5868476.12 70°02'54.247"N 151°06'52.355'W 1.98 3757.77 26.47 72.1 3608.7® 3566.70 583.30 430.82 360731.21 5868484.26 70'02'54.332"N 151"06'51.58T'W 1.61 Survey Approval Report FEARS VVIELLPATH DATA (97 stations) Horseshoe#1 Page 4 of 6 BAKER HUGH ng Energy,LLC Slot Horseshoe #1 MD ft MA ope, Alaska Well Horseshoe#1 NDSS ft ng Energy, LLC North Slope Wellbore Horseshoe#1 awp Grid East us ft Grid North us ion Longitude DLS Comments 1100ft VVIELLPATH DATA (97 stations) MD ft Inclination Azimuth ND ft NDSS ft North ft East ft Grid East us ft Grid North us Latitude Longitude DLS Comments 1100ft 3820.72 25.40 72.20 665.3 3 1 .7 456.83 6 7.57 5 0 54.415' 51°06'5 . 32"W 1.70 3883.19 23.70 72.95 3722.13 3680.13 599.50 481.60 360782.47 5868499.52 70°02'54.491"N 151°06'50.119"W 2.77 3944.73 21.53 73.11 3778.94 3736.94 606.40 504.23 360805.22 5868506.01 70°02'54.559"N 151'06'49.467"W 3.53 4007.35 19.36 73.24 3837.61 3795.61 612.74 525.16 360826.27 5868511.96 70°02'54.621"N 151°06'48.664"W 3.47 4068.56 16.84 73.07 3895.78 3853.78 618.24 543.36 360844.56 5868517.13 70°02'54.676"N 151 °06'48.340"W 4.12 4130.52 14.30 73.01 3955.47 3913.47 623.10 559.27 360660.56 5868521.69 70°02'54.723"N 151°06'47.882"W 4.10 4193.43 12.23 72.5 4016.69 3974.69 1 627.361 573.06 360874.42 5868525.70 70°02'54.765"N 151'06'47.485"W 3.29 4255.80 10.8801 72.4901 4077.80 4035.80 631.12 584.97 360886.40 5868529.23 70"02'54.802"N 151°06'47.141"W 2.16 4317.31 9.7301 712701 4138.32 4096.32 634.36 595.49 360696.97 5868532.28 70`02'54.834"N 151'06'46.839"W 1.88 4379.06 8.4001 74.5701 4199.29 4157.29 637.06 604.83 360906.36 5868534.81 70°02'54.861"N 151°06'46.569"W 2.18 4441.90 6.27 76.5101 4261.61 4219.61 639.08 612.60 360914.16 5868536.69 70°02'54.880"N 151'06'46.346"W 3.41 4501.99 3.41 79.4501 4321.48 4279.48 640.18 617.54 360919.13 5868537.69 70°02'54.891"N 151'06'46.203"W 4.78 4563.99 0.58 87.9201 4383.44 4341.44 640.53 619.67 360921.26 5868538.00 70'02'54.895"N 151'06'46.142"W 4.58 4627.06 0.13 209.58CI 4446.51 4404.51 640.47 619.95 360921.54 5868537.95 70°02'54.894"N 151"06'46.134"W 1.04 4688.66 0.04 88.9901 4508.11 4466.11 640.39 619.92 360921.51 5868537.87 70°02'54.893"N 151°06'46.135"W 0.15 4760.16 0.03 226.0801 4579.61 4537,611 640351 619.90 360921.49 5868537.83 70'02'54.893"N 151'06'46.135"W 0.03 4820.91 0.07 243,3801 4640.36 4598.36 640.33M619.40 360921.44 5868537.80 70'02'54.893"N 151'06'46.137"W 0.07 4884.23 0.07 191.68 4703.68 4661.68 640.27 360921.40 5868537.75 70'02'54.892"N 151'06'46.138"W 0.10 4945.24 0.04 259.94 4764.69 4722.69 640.23 360921.37 5868537.71 70"02'54.892"N 151'06'46.139"W 0.11 5007.53 0.11 243.45 4826.98 4784.98 640.20 360921.29 5868537.68 70°02'54.891"N 151'06'46.141"W 0.12 506823 0.09 245.45 4887.68 4845.68 640.16 360921.20 5868537.64 70'02'54.891"N 151'06'46.144"W 0.03 5129.88 0.31 273.33 4949.33 4907.33 640.14 360920.99 5868537.63 70'02'54.891"N 151'06'46.150"W 0.38 5191.73 0.34 271.78 5011.16 496918 640.16 360920.64 5868537.65 70'02'54.891"N 151'06'46.160"W 0.05 5254.98 0.28 260.86 5074.43 5032.43 640.14 360920.30 5868537.64 70'02'54.891"N 151'06'46.170"W 0.13 5316.78 1 0.220640.08 618.45 360920.04 5868537.58 70'02'54.890"N 151'06'46.177"W 0.13 5378.41 0.30i 236.5501 5197.861 5155.86 639.94 618.21 360919.79 5868537.45 70'02'54.889"N 151'06'46.184"W 0.16 5441.13 0.38 200.02 5260.57 5218.57 639.66 618.00 360919.57 5868537.17 70'02'54.886"N 151'06'46.190"W 0.36 5503.66 0.39 209.31 5323.10 5281.10 639.28 617.82 360919.39 5868536.79 70'02'54.882"N 151'06'46.195"W 0.10 5566.26 0.26 223.264 5385.701 5343.70 638.99 617.62 360919.19 5868536.51 70'02'54.880"N 151'06'46.201"W 0.24 5627.48 0.26 205.71 q 5446.921 5404.92 638.78 617.47 360919.03 5868536.28 70'02'54.877"N 151'06'46.206"W 0.13 Survey Approval Report Horseshoe#1 Page 5 of 6 Alaska riusa LLPATH DATA (97 stations) Ret Welipath: lforseshoe#i TVD ft North ft East ft String/Diameter Start MD I ft End MD I ft Interval Start TVD ft k] End TVD Start NIS rftl rftlMi nclination Azimuth TVD ft TVDSS ft North ft East ft Grid East US ft Grid North us ft Latitude Longitude DLS omments It00ft -0.03 0.21 212.26 55 8.13 546 .13 638.54 617.5 36 918.90 5868536.06 70°02'54.875"N 151°06'46.209' 0.09 6000.001 0.11 214.70 5571.22 5529.22 638.39 617.25 360918.80 5868535.92 70°02'54.874"N 151°06'46.212"W 0.16 I 0.10 227.71 5634.68 5592.68 638.31 617.18 360918.73 5868535.83 70°02'54.873"N 151°06'46.214"W 0.04 0.10 251.93 5695.32 5653.32 638.25 617.09 360918.64 5668535.78 70"02'54.872"N 151°06'46.217"W 0.07 0.18 262.16 5759.81 571781 63822 616.93 918.48 586853575 70'02'54.872"N 151°06'46.221-W 0.13 0.26 259.35 5791.33 5749.33 638.20 616.81 360918.36 5868535.74 70°072"N151°O6'46.224"W 0.26 0.26 259.35 5819.44 5777.44 638.18 616.69 360918.24 5668535.71 70°02'54.872"N 151°06'46.228"W 0.001Pro'edionto TD HOLE & CASING SECTIONS -Ref Wellbore: Horseshoe#1_avvp Ret Welipath: lforseshoe#i TVD ft North ft East ft String/Diameter Start MD I ft End MD I ft Interval Start TVD ft k] End TVD Start NIS rftl rftlMi Start E/W End N/S rftlk End E/W 16in Conductor 18.5 118.00 99.50 18.50 118.00 0.00 0. 0.34 -0.03 9.625in Casing 18.50 2213.00 2194.50 18.50 2184.92 0.00 0.0 290.34 3.82 8.5in Open Hole 2213.001 6000.001 3787.001 2184.921 5819.441 290.34 -3.821 638.181 616.65 TARGETS Name TVD ft North ft East ft Grid East US ft Grid North Latitude US ft Longitude Shape Nanushuk 3 Core Point (Rev -1) 4442.001 644.521 623.961 360925.621 5868541.92 70°02'54.934"N 151"06'46.019" point Survey Approval Report Horseshoe#1 Page 6 of 6 ri.a BAKER REFERENCE Operator WELLPATH IDENTIFICATION ►mstrong Energy,LLC Islot Horseshoe #1 Area INorth Slope, Alaska Well Horseshoe#1 Field jAnnstrong Energy, LLC North Slope lWellbore Horseshoe#1_awp Facility lExploration ELLPATH COMPOSITION - Ref wellbore: Horseshoe#1_awp Ref Wllpath: Horseshoe#1 Start MD End MD Positional Uncertainty Model k k Log Name/Comment Wellbore OnTrak (Standa Horseshoe#1 < > an an orses aw 2164.33 6000.00 BHI OnTrak Standard Horseshoe#1 MWD <2263.6000 Feb 5-12 2017 1 Horseshoe#1 aw 7APPROVAL Baker Hughes Representatives Prepared by far/ elle4A Reviewed by I Aeju ;2A�3 Signature Signature Position ;r , f Position UI!Qp�, Date Date d3 (0(201'4 , Armstrong Energy,LLC Representative Approved by Position Signature Date ARMSTRONG Enegp;. LLC March 23, 2017 Alaska Oil and Gas Conservation Commission 333 W 7t" Ave., Suite 100 Anchorage, AK 99501 Attn: Meredith Guhl RE: offilawmW API 50103207510000, permit to drill North Slope, Alaska Dear Meredith: This letter is sent to advise you that a core gamma ray and routine analysis for the conventional core and the routine analysis for the sidewall cores for above referenced well will be delivered to your office by June 1, 2017. We did not collect any core data for the Horseshoe 1 A well (ptd 217-015). Should you have any questions please call me at 303-623-1821. Yours truly, Patti Reed Geological Technician 1421 Blahs Strcet Denver, CO 80202 p 303.623.1821 1 303.623.3019 Armstrong Energy, LLC CASING & CEMENTING REPORT Permit to Drill (PTD) 216-133 Lease & Well No. ADL 392048 Horseshoe 1i 1 County North Slope State Alaska CASING RECORD TD MD 2230 TVD 2201.23 Shoe Depth: Date 1 -Feb -17 Cc Supv. Lenhart/Boyd/OryalVWallingford Surface MD 2213.54 TVD 2185.42 PBTD: MD na TVD na Wt. On Hook: Wt. On Slips: Description: hanger Info (Make/Model): caner cop racKer r. Yes A NO hanger test pressure: na Lnr Hgr Tech ralizer Placement: 3 on shoe track; then every 3rd joint 120k Type Float Collar: Check Valve 120k Type of Shoe: Check Valve Water Base Mud Csg Supv. No. Hrs to Run: Casing Crew: 13 Weatherford Casing (Or Liner) Detail (should match casing tally) Setting Depths No. of Jts. Size Wt. Grade THD Eqpmnt Mfg Length Bottom Top Shoe/jt 95/8 53.50 L80 Mod BTC 2.25 2,213.54 2,211.29 2 95/8 53.5 L80 Mod BTC 79.38 2,211.29 2,131.91 Float collar Density (ppg) U: L80 Mod BTC 2.40 2,131.91 2,129.51 54 95/8 53.5 L80 Mod BTC 2,101.47 2,129.51 28.04 Hanger L80 Mod BTC 1.21 Totals I I 1 1 2,186.71 Wt. On Hook: Wt. On Slips: Description: hanger Info (Make/Model): caner cop racKer r. Yes A NO hanger test pressure: na Lnr Hgr Tech ralizer Placement: 3 on shoe track; then every 3rd joint 120k Type Float Collar: Check Valve 120k Type of Shoe: Check Valve Water Base Mud Csg Supv. No. Hrs to Run: Casing Crew: 13 Weatherford 10.5 Volume pumped (BBLs) Yield (Ft3/sack): 4.74 216/ Mixing / Pumping Rate (bpm): Yield (Ft3/sack): 1.173 48/ Mixing / Pumping Rate (bpm): Rate (bpm): Volume: 40 bbls water Density (ppg) 8.34 Rate (bpm): 2 Volume (actual / calculated): 23.5 (psi): Pump used for disp: Howco cement pump Plug Bumped? x Yes No Bump press _ ig Rotated? _Yes x No Reciprocated? _Yes x No % Returns during job 100 ant returns to surface? x Yes —No Spacer returns? x Yes —No Vol to Surf: 87 ant In Place At: 22:00 Date: 2/1/2017 Estimated TOC: surface od Used To Determine TOC: Cement sample taken & weiahed ® surface Preflush (Spacer) Type: Preflush (Spacer) Type: Type: Howco Pump Clean III Density (ppg) Lead Slurry Type: Type: Permafrrost L Density (ppg) m Density (ppg) 10.7 Volume (BBLs/sack Type: Tail Slurry Displacement: Type: Class G Density (ppg) 15.8 Volume (BBLs/sack. N Post Flush (Spacer) y Type: Density (ppg) U: Displacement: 10.5 Volume pumped (BBLs) Yield (Ft3/sack): 4.74 216/ Mixing / Pumping Rate (bpm): Yield (Ft3/sack): 1.173 48/ Mixing / Pumping Rate (bpm): Rate (bpm): Volume: 40 bbls water Density (ppg) 8.34 Rate (bpm): 2 Volume (actual / calculated): 23.5 (psi): Pump used for disp: Howco cement pump Plug Bumped? x Yes No Bump press _ ig Rotated? _Yes x No Reciprocated? _Yes x No % Returns during job 100 ant returns to surface? x Yes —No Spacer returns? x Yes —No Vol to Surf: 87 ant In Place At: 22:00 Date: 2/1/2017 Estimated TOC: surface od Used To Determine TOC: Cement sample taken & weiahed ® surface Preflush (Spacer) Type: Density (ppg) Volume (BBLs/sacks): Volume (BBLs/sacks): Density (ppg) Yield (Ft3/sack): Yield (Ft3/sack): Jeff Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Mixing / Pumping Rate (bpm): Rate (bpm): Volume: Density (ppg) Rate (bpm): Volume (actual / calculated): _ (psi): Pump used for disp: Plug Bumped? _Yes No Bump press ig Rotated? _Yes _No Reciprocated? —Yes —No % Returns during job ant returns to surface? —Yes —No Spacer returns? —Yes —No Vol to Surf: ant In Place At: Date: Estimated TOC: od Used To Determine TOC: Remarks: 4 4 Lead Slurry Type: Density (ppg) Tail Slurry Type: w Density (ppg) m _ Post Flush (Spacer) 0 p Type: w y Displacement: Density (ppg) Volume (BBLs/sacks): Volume (BBLs/sacks): Density (ppg) Yield (Ft3/sack): Yield (Ft3/sack): Jeff Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Mixing / Pumping Rate (bpm): Rate (bpm): Volume: Density (ppg) Rate (bpm): Volume (actual / calculated): _ (psi): Pump used for disp: Plug Bumped? _Yes No Bump press ig Rotated? _Yes _No Reciprocated? —Yes —No % Returns during job ant returns to surface? —Yes —No Spacer returns? —Yes —No Vol to Surf: ant In Place At: Date: Estimated TOC: od Used To Determine TOC: Remarks: 4 4 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report Submitto: _nn.regg(aalaska-gov AOGCC.lnspectors(o)alaska qov phoebe -brooks(o)a laska. qov Contractor: Doyon Rig No.. 1 DATE: 2/4117 Rig Rep.. John Huschle/Kelly Haug Rig Phone: 1-907-771-1046 Operator: Armstrong Energy LLC Op. Phone: 1-907-771-1055 Rep.: Bob Lenhart/Tom Boyd E -Mail a�vononliii -com Well Name: Horseshoe #1 PTD # 216-133 Sundry # Operation: Drilling: Workover: Test: Initial: X Weekly: sure (psi): Rams: 250/4000 osi Annular: Explor.: X Bi -Weekly: BOP STACK: Test Result Size/Type, Test Result Quantity Test Result Location Gen. P Well Sign P Upper Kelly 1 P Housekeeping P Rig P Lower Kelly I P PTD On Location P Hazard Sec. P Ball Type I P ling Order Posted P Misc. NA Inside BOP I P NA #6 Rams 0 FSV Misc 0 NA BOP STACK: Quantity Size/Type, Test Result Stripper 0 Meth Gas Detector NA Annular Preventer I 11"/ 5000 P #1 Rams I 2 718X5 vbr P #2 Rams I BLINDS P #3 Rams 1 2 7/8X5 vbr P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3 1/8"x5000 P HCR Valves 2 3 1/8"x5000 P Kill Line Valves 2 3 1/8"x5000 P Check Valve 0 NA BOP Misc I P MUD SYSTEM: Visual Trip Tank P Pit Level Indicators P Flow Indicator P Meth Gas Detector P H2S Gas Detector P MS Misc 0 Quantity Inside Reel valves 0 ACCUMULATOR SYSTEM: Time/Pressure System Pressure (psi) CHOKE MANIFOLD: Pressure After Closure (psi) Quantity Test Result 200 psi Attained (sec) No. Valves 15 P Full Pressure Attained (sec) Manual Chokes 1 P Blind Switch Covers: Hydraulic Chokes I FP Nitgn. Bottles Avg. (# and psi): CH Misc 0 NA ACC Misc Test Results Number of Failures: 1 FP Test Time: 5_5 Hours Repair or replacement of equipment will be made within days. es[ annular i rzouizouu psi, i est rams and valves T/250/4000 psi, with choke retest good. BOP mist, valve 18 midline kill valve hr Notice Yes Date/Time Waived By _ Start Date/Time: 2/48017 7:00 (date) (time) Witness Matt DateFrime: 33 Alarm P Test Result Test Result P Form 10424 (Revised 06/2014) bope test 242017 �t�.'Yc s•�o.� 1 SG�(i dI+'lu�aq/ C�p�t �C .1 J '� G1 M-zl S V i �t�.'Yc s•�o.� 1 SG�(i dI+'lu�aq/ C�p�t / �� t .� 1,n a ,; � Q ,( a\ �� , � '� `� ff �,�� }� i � � y�� \'� �I % � � � � � � 6J9 � �! � i � �� a __� ,�-y-i> __-- - - T�_._.___"�_ yy(( +J _ ... 1 ; i r ;row �\ /� I r• s' � l � �- -� �'` � _ �,� - p� Imo. y ' '. 1 �. V L ti . ' � STATE OF OIL AND GAS CONSERVATION COMMISSION BOPE Test Report Submit to: jim.regq(a)alaska.goy AOGCC.Insoectors(da laska.clov ghoebe.brooks(glalaska clov Contractor: Doyon Rig No.: 1 DATE: 2/12/17 Rig Rep.: John Huschle/Duane Sim:Rig Phone: 1-907-771-1048 Operator: Armstrong Energy LLC Op. Phone: 1-907-771-1055 Rep.: Bob Lenhart/Joe Steiner E -Mail arctcfox(g)doyondrilling.com Well Name: Horseshoe #1 PTD # 216.133 Sundry # Operation: Drilling: Size/Type Workover: Explor.: X Pit Level Indicators Test: Initial: t Weekly X Bi -Weekly: #1 Rams 1 rat Pressure (psi): Rams: 250/4000 psi Annular: 250/2500 psi Valves: 250/4000 p! MASP: 2959 psi MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: #4 Rams 0 Test Result NA Test Result 0 Quantity Test Result Location Gen. P Well Sign P Upper Kelly 1 P Housekeeping P Rig P Lower Kelly 1 P PTD On Location P Hazard Sec. P Ball Type I P ling Order Posted P Misc. NA Inside BOP 1 P FSV Misc 0 NA BOP STACK: Quantity Size/Type Test Result Stopper 0 Pit Level Indicators NA Annular Preventer t 11" 15000 P #1 Rams 1 2 7/8X5 vbr P #2 Rams 1 BLINDS P #3 Rams 1 2 7/6X5 vbr P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3 1/8"x5000 P HCR Valves 2 31/8"x5000 P Kill Line Valves 2 3 1/8"x5000 P Check Valve 0 NA BOP Misc I P CHOKE MANIFOLD: Quantity Test Result No, Valves is P Manual Chokes 1 P Hydraulic Chokes 1 P CH Misc 0 NA MUD SYSTEM: Visual Alarm Trip Tank P P Pit Level Indicators P P Flow Indicator P P Meth Gas Detector P P H2S Gas Detector P p MS Misc 0 NA Quantity Test Result Inside Reel valves ACCUMULATOR SYSTEM: Time/Pressure Test Result System Pressure (psi) 3000 Pressure After Closure (psi) 1750 200 psi Attained (sec) 20 Full Pressure Attained (sec) 92 Blind Switch Covers: All statior Nitgn. Bottles Avg. (# and psi): 6 @ 2225 ACC Misc 0 Test Results Number of Failures: 0 Test Time. 5_5 Hours Repair or replacement of equipment will be made within Notify the AOGCC of repairs with written confirmatio emarks. Test annular T/250/2500 psi, test rams and valves T/250/41 hr Notice Yes Date/Time 2/10/2017 Start Date/Time: days. By (date) (time)Witness 211212017 10:30 Form 10-424 (Revised 06/2014) bope test 2-12-2017 m il NO /CHART MO. MC MP-5000-4HR cIIAR7 .: . A:[. N ii}-( ( Air - CA A 30 i P ON E A 0s --009-- IX 005IX 04 Ci W Meredith Guhl Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.guhl@alaska.gov Direct: (907) 793-1235 RECEIVE® APR 2 5 2017 AOGCC a e�a-�e Nom ✓tn�� / "A, ARMSTRONG Enetgw. LLC April 17, 2017 Alaska Oil and Gas Conservation Commission 333 W 71' Ave., Suite 100 Anchorage, AK 99501 Attn: Meredith Guhl RE: DVD — Horseshoe #1 API 50103207510000, permit to drill 216-133 North Slope, Alaska Dear Meredith: Please find enclosed one DVDD containing digital data: Horseshoe 1 QGeo Digital Data 21 6133 28 13 7 RECEIVED APR 18 2017 AOGCC NO LONGER CONFIDENTIAL APR 11 2019 Please indicate your receipt of the aforementioned data by signing in the space provided below and returning a scanned copy of this letter tome at patti@armstrongoilandgas.com. Should you have any questions please call this office at 303-623-1821. Yours truly, Patti Reed Geo Tech TN Received this 1~`T day of 2017. ALASKA OIL AND GAS CONSERVATION COMMISSION By: NO LONGER CONFIDENTIAL APR 1 1 2019 1421 Blake Street Denver, CO 80202 p 303.623.1821 f 303.623.3019 Nanushuk Project TRANSMITTAL FORM DATE ISSUED: 3/29/2017 To: Alaska Oil and Gas Conservation Commission Meredith Guhl TRANSMISSION TYPE: ®External Request Dlnternal Request REASON FOR TRANSMITTAL: DApproved DApproved with Comments D ForApproval OToBe Returned COMMENTS: ®I nformat ❑For Your ❑ For Your ❑With Ou 1 Horseshoe #1 - Final Well Report & Log Prints, De 2 Horseshoe #1A - Final Well Report & Log Prints, 3 4 5 RECEIVED BY: Name (First/Last) / UJpt--1 p., 1L, Signature Date ( Please Print) Nanushuk Project TRANSMITTAL FORM DATEISSUED: 3/29/2017 To: Alaska Oil and Gas Conservation Commission • Meredith Guhl TRANSMISSION TYPE: ®External Request Olnternal Request REASON FOR TRANSMITTAL: OApproved MInformat-- - _ OApproved with Comments ❑For Your OForApproval ❑For Your OToBe Returned ❑With Ou - - - -- _ COMMENTS: 1 Horseshoe #1 - Final Well Report & Log Prints, D -- 2 Horseshoe #1A - Final Well Report & Log Prints, - 3 4 5 RECEIVED BY: ,k20� ,'A Name (First/Last) t,AktG-pAi b. V, `t6 FaA®F 2 X13 Signature Date (Please Print) 2 7015 L 6133 Nanushuk Project RECEIVE® , 0 8 2 A 2 8 0 8 3 TRANSMITTAL FORM MAR 31 2017 AOGCC ARMSTRONG Enerkn', LLC DATE ISSUED: 3/29/2017 TRANSMITTAL #: 038 To: Alaska Oil and Gas Conservation Commission From: Armstrong Energy, LLC • Meredith Guhl Kristie Pepperworth TRANSMISSION TYPE: TRANSMISSION METHOD: ®External Request ®CD ❑ Thumb Drive ❑Internal Request ❑Email ❑SharePoint ®Hardcopy ❑Other REASON FOR TRANSMITTAL: ❑Approved Z Information Only ❑Approved with Comments El For Your Review ❑ For Approval ❑ For Your Use ❑To Be Returned ❑With Our Comments COMMENTS: Itern No. Description I Horseshoe #1- Final Well Report & Log Prints, Digital Well Data CD 3 Z> 2 Horseshoe #1A - Final Well Report & Log Prints, Digital Well Data CD - Z I 3 4 5 RECEIVED BY: Name (First/Last) / Signature Date (Please Print) SENT FROM: '' ZI wits STATE OF ALASKA At KA OIL AND GAS CONSERVATION COMP SION REPuRT OF SUNDRY WELL OPERA (IONS 1. Operations Abandon Repair Well Plug Perforations LJ Perforate L Other LJ Plug Back Performed: Alter Casing ❑ Pull Tubing❑ Stimulate -Frac ❑ Waiver ❑ Time Extension[] Change Approved Program ❑ Operat. Shutdown ❑ Stimulate - Other ❑ Re-enter Suspended Well ❑ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Armstrong Energy, LLC Development ❑ Stratigraphic❑ Exploratory '❑ Service ❑ 216-133 3. Address: 510 L Street, Suite 310 Anchorage, Alaska 6. API Number: 99501 50-103-20751-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL 392048 Horseshoe M 1 R E C E I V E 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): Wildcat 11. Present Well Condition Summary: q p MAR 2 8 2017, Open Hole Plug Total Depth measured 6.000 feet Plugs measured 6000-2030 feet AOGCC true vertical 5819 feet Junk measured feet vv Effective Depth measured 6,000 feet Packer measured feet true vertical 5819 feet true vertical 0 feet Casing Length Size MD TVD Burst Collapse Structural 118' 16 118• 118' na na Conductor 0 0' 0' 0 0 Surface 2216' 95/8" 2216' 2188' 7930 6620 Intermediate OH 6000' 5 0 0 Production 0' 0 0' /0' 0 0 Liner 0' 0 0' •` 0' 0 0 Perforation depth Measured depth na feet True Vertical depth na feet �r, -� Tubing (size, grade, measured and true vertical depth) VVV Packers and SSSV (type, measured and true vertical depth) na na 12. Stimulation or cement squeeze summary: Intervals treated (measured): 6000-2030 Treatment descriptions including volumes used and fi/reeSpacers followedls of 14.5 ppg cement, spacers,43 bible 17 ppg KO Cement - 0 13. Representative Daily Average Production or Injection Data -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: Subsequent to operation: 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run Exploratory0 Development❑ Service ❑ Stratigraphic ❑ Daily Report of Well Operations y 16. Well Status after work: Oil LJ Gas —WDSPLLJ GSTOR ❑ WINJ ❑ WAG ❑ GINJ❑ SUSP❑ SPLUG❑ 17. 1 hereby certify that the foregoin is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 317-074 Contact Stephen Hannigan ph 337849-5345 Email St2Va@DBlinc.conl Printed Name Stephen F. Hannigan Title Project Engineer/Mgr for Armstrong Energy, LLC ��" ,�i 3-23-2 k-( Signature Phone Date Form 10-404 Revised 10/2012 Submit Original Only D I Armstrong Energy, LLC Horseshoe # 1 Block/Sec 015 T8n Rate Wildcat North Slope Alaska PTD #: 216-133, Sundry for Plug OH 317-074 Eat RNb 43' ................... KOP'. IREF 1' .................... 8.3 8.4 11 99'pen 118' ROP/Gas lag Cord/Dawe to TD. Osx Lead Is Oppg+(ex Tad 15 6ppg Wash to top of cement 9) 2030', 5010k on bit, AOGCC Rep Grimaldi witness 02 /17/2017 8.6 10 13.8 ce Re:, oan'Nrx' 2216' onics 2188' H51 ON Abandonment: PISM, Batch mix 35 bblsof Clean Spacer III, Tart Imest/ 4500 psi, Pump 29.5 this Water, 244.5 bblsof 14.5 ppg cement, Launch release dart, Pump 1 bbl cement, 5.5 bbls spacer, Rig displaced w/ 20.8 bbis M08M, pressure up to Z800 psi to release tbg, Top of TBG 2604' Pick up 40', Cim out spacers& excesscmt 1212 bbhl. Est top of the abandonment plug 2564' Mix&pump29.5bbls spacer,43 bbls 37 ppg KO Cement, 5.5 bbisspacer, rig displaced w/ 13.4 ball; MOBM, CIP 0200 hr; Estimated top of cement 2037' Pump wiper ball down DP, Circ out spacer, Circ & condition Cement inside and outside Mud Logging: Manned: 2v/50' 0-32200', 25K/10', 22200' -TD 10.4 ppg MOBM 3 1/2" 9.2N L-80 TC - 9 10.4 16 GR. Re, sorcA w,s 6000' GR, RT, Den, Neut, Sonic fC+SI, MOT w/ fluid 5819' sample, Oil Bawd FMI, NMR, ECS or Lithoscanner, VSP Rotary SW Core, CONVENTIONAL core of upper 4300' of Nanumuk 3 844xS6 Weld as Gap Auger/drwass 16 2V Pibl Male no (yam Y� 10.4 ppg MOBM 53.54280 Mod BTC 121/4" Area for MCNin{ off to tltlll 1-10rseaM1oe 1, Si F Plmnred R6st TOC = x2564' RKB Planned Tap of 3 1/2" =:2604' RKB llnlatching plug for Halm disconnect tool. 81/2" OH A Armstrong Energy, LLC A It M S T R O N G North Slope 2016-2017 Rpt # DAILY JOB REPORT 32 AFE If 6212016-2 Date: W16Y2017 GAYS mw _ TOTAL'. 31 SPUD: 20 PHONE Rig: 907771-1048, Office 907-771-1055 Pem'ilk_ 21¢121 State AK Lease Horseshoe Well # 1 Legal: _7413711,11 2236' FSL Sec/Blk 015 -8n -4e Area North Slope X = 360290, Y = 5867909' POB- 94 HSE' 1 Qt fuel spill, Vehicle off ice roac Depth 6000' MD to 6000' MD ftg 0' HIS 0 Cum $/h Fmn Nanushuk Depth 5619' TVDto 5619' TVD ftg 0' FVhr he Day$/ft Max gas 23 BGG 16.2 CG 2 TG 11 Opns B 6AM RIH w/ 34/2" Tbc TAOOrr BTM Tao De BTM MAX TRO ROT Vi _ PU NR Dmm WT _MAX DRAG Contractor Doyan Rig ArChC oX Toolpusher(s) Bobby In ram/ Duane Sims BOP Size i t WP S,00p BOP Test DUE 2/19/17 Hy4rr 5000 Per Rams 5000 psi SINS 5000 psi Body 5000 psi Elevation 23.50' Total 0.00' RK&CNF 18.60' iK&MWUG 42.00' WD 1.00' RAM SIZES Too 2.7m,xs. Mid Blind Lw 2.7W.T Casing PIT PIT PIT 16 Dnve 118' na COnd has nm PIT 95/8 " Surface 2213' 13.9 code ProtecWe Liner, It to Prod Tubing Packer Perfs to PBTD TD Tubin Pump Into Pump #1 GO PZ 8 ("few ja EQ 0.046 BPS 88 SPM 4.048 BPM 170 GPM 95 es E6. 3000 psi Pump 02 GPZ8 Lnr/stk 21 x4 0046 BPS SPM 28 3.1 BPM 131 GPM 95 %, Elf. psi Pump k3 GDO PZB Lnr/slk .&B 0.048 BPS N 98 SPM 6.508 BPM 189 GPM 95 %Efl. _psi 491 T9 GPM 3200 i Slow Rate k1 SPM® PSI k2 SPMQ psi k3 SPM@ psi Rt Dnll- Morning Secs: _ Day Secs: Evening N/8 Secs: 2 Capacues Pipe lnfonration DISPLACEMENT CAPACITY ANNULAR VOLUME Ann Vel O.D. Grace Wt Throe ID Feet BMs/ft BMs BUs41 Bbls O.D. Wt. Q Bus/ft Feat BUS fpm DP 4" S-035 14 XT -39 3.34^ 2213' 0.0047 10.41 0.0108 23ef) Surface 9-5n8" 53.5 8.535" 0.0552 2213' 122.21 211 DP 4" &135 14 XT -39 334" 3112' 0.0047 1665 0.0108 33.72 0 0" 0 8.5" 0.0546 3112' 170.05 214 DP 0" 0 0 0 0" 0' G(Xxx, 0.00 0.0000 0.00 0 0" 0 0" 0.0000 0' 0.00 0DIV/Oi HWDP 6" HWDP 28.4 XT39 2.5625" 556' 0.0092 5.10 0.0(64 3.55 0 0" 0 8.5" 00546 556' 60.38 214 DC 6.75" NM 160 6 5/8, T2 2.8" 119' 0.0366 4.36 0.0076 0.91 0 0" 0 8.5" 0.0259 119' 3.09 451 DC 0" 0 0 0 0' 0' GWIX) 0.00 0.0000 0.00 BHA OH 0" 0 0" 00000 0' 0.00 #DIW0! Totals 0 6000' 34.52 62.16 6000' 326 Number of Strokes 01 PUMP) To Fig Hole 750 To Bit 1351 Bottoms up: 7081 Slks Sown DIRECTIOIWUSURVEYS I KOP: 200' ISURVEYS1 MD I TVD I ANGLE 1 DIRECTIOWAZIM I COORDINATES VT. SEC DOG LEGCLOSUR COMMENTS ar u es MWD CO Baker Hughes 5940' 0.2 1.9° .1 MUD MTR. Autotrek ] 57 1 0.3° .3 382 615.8. 3 Projected to TD 6000 5819' 0.3° 259.35 1 1 638 1 616.7° 1 1 887' 1 0.0" Proj to 2400 hrs depth Fluid omp I API HTHP solids I LXluid % Santl Tim. WT Va PV YP Gels WL 300°r % Of WAS, % EB EXC LME PM PF MF H IN 2359 10.45 110 34 17 9/14/20 3.6 12.7 77.6 22.4 .1 814 5.7 OUT wLORiDBs CA LGS% FLUID VOLUME SHAKER SCREENS HRS Other MuN nwic INFO CHEMICALS USED 8 REMARKS IN 285920 2 5.9 ROLE 422.4 #1 200#. ""'S0 0 0 0 0hEM AMT REM AMT REM AMT OUT Pp- 500 #z M77.7 0 ECD 0Slroe HWe Volume 422.4 LVT 294 EZ MUL Dundone Engineer FLUID TYPE #3 sma, IMM 0 1 Pit Volume 748 Bat Invermul Siltex Joe PeAean Emironul es 65x4 0 Losses DH 0 Bar Tons I I Gem. Bamblok DAILY COST CUM COST 1 I CuttritsDi3 Sus en net I Uma M.1,01$3460 5277,001 OTHERCOMMENTS N0. SIZE MANUF. TYPE SERIALS NOZ GPM FTG HRS WT %Or -NI Pon W013TWPar m mo m T B G Reason 3 RR1 8.5 HAL FC3555 12614632 5 X 17 230 90 2.5 4930 3600 % 6 4U60 hatCore 4 8.5 HVC KH519M-C A191313 ]x12 490 170 15 fi000' 7133% 10l 195 2 Na TD LOG OF OPERATIONS ACCIDENTS: None Po. 6:00 9:30 3.5 1 602 Cont. Run #4 MDT Move to set point #4 0 0500 hrs 9:30 11:30 2.0 602 LID TOOIS 11:30 22:00 10.5 602 IRur_... 22:00 2:00 4.0 2250 2:00 3:00 1.0 22 3:00 3:30 0.5 3:30 6:00 2.5 h �o a W 4 y Armstrong Energy, LLC A RMS 1 e O u c North Slope 2016-2017 Rpt If ,•.... ,r DAILY JOB REPORT 33 AFEY 62120162 Date 21117120117 DAIS Rd PHONE Rig: 907 ]]1-1Dae, Oliice 907-Ti1-1055 TOTIL: 32 218-133 SWD: SUte 21Pennit4 K Lease Horseshoe well # 1 Legal: 1413' FWL 2236' FSL Sec/Blk 015 -8n -4e Area North Slope X= 360290' Y=5867909' POB' 93 HSE" None Depth 2037' MD to 6000' MD ftg Hrs 0 Cum $/h Fmn Cement Depth 2016' TVD to 5819' TVDftg Ft/hr na Day $M Max gas 3380 BGG CG TG Opn44D 6AM POOH TRD0FF6TM TRooHeTM MAXTRO _ ROT WT. _ PU WT p WT -MAX DRAG Contractor Doyon Rig Arctic ox Toolpusher(s) Bobby Ingram / Duane ims BOP Size 1t WP SAW BOP Test DUE 2/19/17 Hydd 5000 psi Rens 5000 psi onds 5000 psi Body 5000 Dsi Elevation 23.50' Total 0.00' RKBCHF 18.60' IKB-MWL/G 42.00' WD 1.00' RAM SIZES T '- Mid BlindLwr Casing PIT PIT PIT 16 Drwe 118' na Cond na 83 PIT 9518 " Surface 2213' 13 9ypgg Pmtective Liner, l/ to Prod Tubing Packer Paris to PBTD TD Tubin Pump Info Puna Mt GO PZ 8 tni/slk ri, I-8 gQ 0.046 BPS 88 SPM 4.048 BPM 170 GPM 95 % Elf. 3000 psi Pump 42 GD PZB Lnr/sIX $yQ U 0.046 BPS 68 SPM 3.128 BPM 131 GPM 95 %EH Puro#3 GO PZ8 Lnr/slk 55a ---Q0.046 BPS 98 SPM 4.508 BPM _psi 189 GPM 95 %Efl _psi Slow Rale 41 SPM® PSI 42 SPMO psi e3 491 Tit GPM SPM@ 3200 psi Pit DMI - Moming Secs: _ Day Secs', Evening INA Secs: Q _psi Capacities Pipe Information DISPLACEMENT CAPACITY ANNULAR VOLUME Ann Vel O.D. Gusto Wt ThMs ID Feet Own able Bbls/fl Bbls O.D. Wt. ID Bbls/a Feat able fen DP 4" 8135 14 X7-39 3.34" 2213' 0.0047 10.41 0.0108 2398 Surface 9.5/8' 53.5 8.535" 0.0552 2213' 122.21 211 DP 1" 8135 14 XT -39 3.34• 3112' 0.0047 14.65 0.0108 33.72 0 0" 0 BF, 0.0546 3112 170.05 214 DP V. 0 0 0 0" 0' 0.0000 Dw 0.0000 0.00 0 0" 0 0" 0.0000 0' 0.00 IDIV/oI HWDP 4" HWDP 28.4 XT -39 2.5625" 556 0.0092 5.10 0.0064 3.55 0 0" 0 8.5" 0.0546 556' 30.38 214 DC 6.75' NM 180 65'8, T2 2.8" 119' 0.03% 6.36 0.0076 0.91 0 0" 0 8.5" 0.0259 119' 3.09 451 DC 01' 0 0 0 0" 0' 0.0000 0.00 0.0000 0.00 BHA ON 0" 0 0" DOM 0' 0.00 001WK). Totals 0 6000' 34.52 62.16 6000' 326 Number of $Yokes X1 PUMP To Fill Hole 750 To Bit 1351 BOHM$ Uig: 7081 Siks 80 Min DIRECTIONAUSURVEYS KOP: 200' SURVEYS MD TVD ANGLE DIRECTION/AZIM OOOflDINATES VT. $EC DOG LEG CLOSUR COMMENTS ar ug es MWDCO Baker Hughes 5760' 0.2° .1 fi38. 2 616.9 BBB' MUD MTR. Aolobak .i Pro"TD ectetl to 8000' 5819' 0.3° 259.35 638 616.7° 88T 0.0" 1 1 Pro' to 2400 hrs depth Fluid Comp BAROID API HTHP Sonde uM / Time WT Va PV Yp Gels WL 3007 i Oi Wafer E%CLIME PM PF IN 2359 10.5 122 29 15 9/14/20 4 12.7 77.6 22.4 5.57CREENS HRS Omer Mud'H rauic INFO ALS USED 8 REMARKSIN5.9 HOLE 422 xt 20p p,1 0 00 0AMT RLVT ITEM AM! M OUT PIT- Slp x2 sppa.+>o xx 0 ECD®Slave Hole Volume EZ MUL E ineer FLUID TYPE x3 zaoa. noa 0 Pit Volume Imennul Joe Patlfean Emimrwl xa d5 x4 0 Losses DHs Gellone DAILY COST CUM COST Cenlrl Cltin Din Uma $2,04.5 32]9046 OTHER CCke4ENT5 NO. I SIZE MANUF. TYPE SERV Lx NOZ GPM FTG HRS OUT %D,ot Pon WOO T2'7 Mfr m T B G Raison 3 RRt 8.5 HAL FC3555 12614632 5 X 17 230 90 2.5 4830 3800% 6 4060 na Core 4 BS HYC KH519M-C A181313 7x12 490 n0 15 8000' ]133% tOk 95 2 n/a TD LOG OF OPERATIONS W ffix ACCIDENTS: None 6:00 13:30 7.5 225e P/U 3-1/2 Tbq for P&A of open hole, break circ periodically 13:30 18:30 5.0 225e M/U Tbg release sub & test, RIH W/ DP U 5898' A Armstrong Energy, LLC ARMSTRONG North Slope 2016-2017 Rpt# DAILY JOB REPORT 34 AFE # 6212016.2 Date: 2/18/2017 TOTw.. 33 FROM stat: 22 PHONE Rig: 907 771-1048, Office 907-771-1055 Permit# 1 -1 State AK Lease Horseshoe Well # 1 Legal: 1413' FWL 2236' FSL Sec/Blk 015.8n•4e Area North SID e X= 360290' Y=5867909' POB* a9 HSE* None Depth 2030' MD to 2030' MD ftg 0' Hiss, 0 Cum $/ft Fm Cernint Depth 2011' TVD to 2011' ND ftg 0' Ft/hr na Day SM Max gas 3380 BGG CG TG Gone 0 6A POOH ma OFFk1V TRQI BTA MAXTRO _ ROT WT. _ PU WT Down WT _MAX DRAG Contractor Doyon Rig Arctic FOX Toolpusher(s) Bobby In ram/Duane Sims BOP Sze n WP 5,000 BOP Test DUE 2/19/17 Hydra 5000 psi Rama 5000 psi emnds 5000 psi Baily 5000 ps1 Elevation 23.50' Total 0.00' RKB-CHF 18.60' ;KB-MWUG 42.00' WD 1.00' RAM SIZES Too Mid In Lr Casing RT PIT PIT 16 Drive 118' nil CMd na Dg PIT 95/8" Surface 2213' 13.9 woe Protective Uner, f/ to Prod Tubing Packer Peds to PBTD TD Tubing Pump Info Pump #1 GDPZ8 Lnusk 2a x9 0.1146 BPS 88 SPM 4.048 BPM 170 GPM 95 %E6. 3000 psi Pun GDPZ8 Lndstk >Lxa g9 0.046 BPS 68 SPM 3.128 BPM 131 GPM 95 %Eft. psi Pump#3 GDPZ8 Lndstk 5-8 X -Q 0.046 BPS 90 SPM 4.508 BPM 189 GPM 95 %Elf, _psi 491 Ttl GPM 3200 psi Sbw Rale #1 SPM(➢ PSI #2 Some psi #3 SPMW _psi RI Drill- Morning Secs Day Secs: Evening IAC Secs: 9 Capecl9es Pipe Infornalion DISPLACEMENT CAPACITY ANNULAR VOLUME Ann Vel O.D. Grade Wt Thick; ID Feet Bbls/ft BMs BMs/ft able O.D. WL ID Bbls/t Feet Bbls to. DP 4" S-135 14 XT -39 3.34' 2213' 0.0047 10.41 0.0108 23.98 Surface 9.5/8' 53.5 8.535" 0.0552 2213' 122.21 211 DP 4" S-135 14 XT -39 3.34" 3112' 0.0047 14.65 0.0108 33.72 0 0" 0 8.5" 0.0546 3112' 170.05 214 DP 0" 0 0 0 0" 0' 0.0000 Coo 0.0000 0.00 0 0" 0 0" 0.0000 0' 0.00 #DIV/01 HWDP 4" HWDP 28.4 XT -39 2.5625" 556' 0.0092 5.10 0.0064 3.55 0 0" 0 8.5" 0.0546 sm. 30.38 214 DC 6.75" NM 180 6SE, T2 2.8" 119' 0.0350 4.36 00076 0.91 0 0" 0 8.5" 0.0259 119' 3.09 451 DC 0" D 0 0 T 0' 0.0000 0.00 00000 0.00 BHA OH 0" 0 0" 0.0000 0' 0.00 #DIV/01 Totals 0 60W 34.52 62,16 6000' 326 Number of Strokes fell PUMP To Fill Hole 750 To 30 1351 Bottoms up: 7081 Stks 80 Min DIRECTIONAL/SURVEYS I KOP: 200' ISURVEYSI MD I TVD I ANGLE 1 DIRECTION/AZIM COORDINATES I VT. SEC DOG LEG CLOSUR COMMENTS e er 111.911115 MWD CO Baker Hughes63 5]60 .1 8.22 616.8° 888' .1 MUD MTR. Autotrak 5 1' .3° 2 B. 61 888' ProLE2 tO TO 6000 5819' 0.3° 259.35 638 616.7° 887' 1 0.0" 1 Pro' to 2400 hire depth Fluid Conno BAROID API HTHP Solids% L' aid Sand Time WT I vt I PV I YP Gets I WL 3004 % 0 WMer % ES MLME PM PF MF H IN 2359 10.5 105 30 15 9/15/20 3.8 12.7 77.6 1 22.4 .1 845 5.57 O CHLMIDES CA I LGS% IRUID VOLUME SHAKER SCREENS HRS Other MudH, draullc INFO CHEMICALS USED 6 REMARKS IN 265920 2 5.9 HOLE 422.4 #1 so iTl,2 12 o 0 0 0 r EM AMT ITEM AMT REM AMT OUT PIT- 500 n 2w n.1 o 12 ECD ® Shoe Hole Volume 422.4 LW 840 EZ MUL Durabne 2 Enin4#r FLUID TYPE a3 200,2.+70,0 12 Rt Volume 748 Bar IrrvemMl 2 Statex 2 Joe Pefi'ean Enviromul 44 45x4 12 Losses DH 0 Bar TMs Geltone 4 Bemblok 2 DAILY COST CUM COST Cenbf, DUtAO sDis Sus ntM 4 lime 35 Barotrol 2 $14331 1 $293377 OTHER COMMENTb NO I SIZE MANUR TYPE 1 SERM 1 1 NOZ 1 GPM 1 FTG HRS WT %D,-bA PDD I WOB I TDPS,W 1 Mt, rina 1 T 1 e G Reason 3 RRI 85 HAL FC3555 1126146321 5X17 1 230 1 90 1 2.5 1 4930 ji 1 3600, 1 6 1 40-60 1 nil I I if Core 4 8.5I HYC KH519WC A191313 7x12 490 170 15 6000' 7133 % 10k 95 2 Ne I TD 5 8.5I HCG VM.3 5265141 1&181x16l LOG OF OPERATIONS ACCIDENTS: None to &DO 7:30 1 1.5 1 225f lChange out wash i e on Top Drive 7:30 9:30 1 2.0 1 0 Wash inside of BOPS, Blow down 9:30 14:00 1 4.5 1 225c JIWIJ BHA #7 Witnessed By IBab Lenhan G 21 61 33 28089 Cement Evaluation Log J SLG Map with MSIP VDL J e Scale: 5" = 100' 9.625" Casing d LL m W Surface: 2236 FSL AND 1413 FWL Elev.: K.B. 43.00 k M m G.L. 23.50 It v y D.F. 42.10 k 0 0 z 3 x¢ c Permanent Datum: Mean Sea Level Elev.: 0.00 k v, .0 Log Measured From: Drill Floor 42.10 k above Penr r c c Drilling Measured From: Drill Floor w o m 'o API Serial No. Section: Township: Rang 0 m 50103207510000 15 8N 4E M LL J U Logging Date 04 -Feb -2017 Run Number R1 131 Depth Driller 2230.00 it Schlumberger Depth 2230.00 It Bottom Log Interval 2100.00 ft Top Log Interval 210.0011 Casing Fluid Type Fresh Water Salinity Density 10 Ibm'gal Fluid Level 8.00 it BITICASING/TUBING STRING Bit Size 12.25 in From 118.00 It To 2230.00 It Casing/cubing Size 9.625 in Weight 53.5 lbm'ft Grade L80 From 0.00 ft TO 2214.00 It Max Recorded Temperatures 68 degF 68 68 Logger on Bottom Time 04 -Feb -2017 15.55:00 Unit Number Location: 2290 USPS Recorded By M.Reiter Witnessed By IBab Lenhan G 21 61 33 28089 A ARMSTRONG EnetXv. U.0 March 23, 2017 Alaska Oil and Gas Conservation Commission 333 W 7" Ave., Suite 100 Anchorage, AK 99501 Attn: Meredith Guhl RE: Horseshoe #1 API 50103207510000, permit to drill 216-133 North Slope, Alaska Dear Meredith: 21(0- 13-2:1 RECEIVE® MAR 2 3 2017 AOGCC This letter is sent to advise you that a core gamma ray and routine analysis for the conventional core and the routine analysis for the sidewall cores for above referenced well will be delivered to your office bMIIIIIIIIIIIIF We did not collect any core data for the Horseshoe I well (ptd 217-015). Should you have any questions please call me at 303-623-1821. Yours truly, rklzo Patti Reed Geological Technician 1421 Blake Street Denver, CO 80202 p 303.623.1821 1'303.623.3019 RECEIVFD /Fag MAR 2 1 2017 BAKER PRINT DISTRIBUTION LIST IiUGNES AOGCC COMPANY Armstrong Energy, LLC WELL NAME Horseshoe #1 CD/DVD FIELD Colville River PRELIM COUNTY North Slope Borough SURVEY I BHI DISTRICT Alaska AUTHORIZED BY Paul Canizares EMAIL Paul.Canizaresgnbakerhughes.com STATUS Final Replacement: COMPANY ADDRESS (FEDEX WILL NOT DELIVER TO P.O. 90* PERSON ATTENTION 4 1 Armstrong Energy, LLC Krisite Pepperworth 510 L Street, Suit 310 Anchorage, AK. 99501 11 61 33 2800 sign and return one copy of this transmittal form to: strong Energy, LLC iy VanDenburg/Krisite Pepperworth L Street, Suit 310 forage, AK. 99501 LOG TYPE GR-RES-DEN-NEU SDTK:Acoustic Log LOG DATE February 12, 2017 TODAYS DATE March 20, 2017 Revision No Details: Rev. Requested by: -- FIELD I FINAL CD/DVD FINAL PRELIM LOGS (las, dlis, PDF, META, SURVEY I REPORT LOGS CGM, Final Surveys) (Compass) # OF PRINTS9 Ur MIN # OF COPIES 1# OF COPIES # OF COPIES 2 Armstrong Energy, LLC 0 Atte: Colby VanDerbug 1421 Blake St Den Ver,CO 80202 3 GMT Exploration Company LLC 0 i 'I i 0 Attn: Philip Wood 1560 Broadway Suite 2000 Den Ver,CO 80202 4 State of Alaska -AOGCC 0 i 0 Attn: Meredith Guhl 333 W. 7th Ave, Suite 100 Anchorage, Alaska 99501 5DNR -Division of Oil & Gas *** 1 0 1 0 1 1 0 0 Attn: Resource Evaluation Section 550 West 7th Avenue, Suite 1100 Anchorage, Alaska 99501-3510 I— Stamp "confidential' on all material deliver to DNR 6 Repsol Services Company 0 0 1 2 1 0 0 Attn: Tom Buerkert 2455 Technology Forest Boulevard The Woodnlands, TX 77381 TOTALS FOR THIS PAGE: 0 4 7 4 0 TOTALS FOR ALL PAGES: 0 4 7 4 0 21 6133 2 8 0 A ri.l ADVANTAGE Final Survey Listing Num Es 2%RMS TRONG INTEQ Operator Armstrong Energy, LLC Fields Colville River API No 501032075101 Well Horseshoe#1A Wellbore Horseshoe#IA Rig Arctic Fox Job 8327027 Latitude 70.05 deg Longitude -151.12 deg North Reference True Drill Depth Zero Rig Floor Vertical Datum is Mean Sea Level Vertical Datum to DDZ 42.00 ft Vertical Section North 0.00 rt Vertical Section East 0.00 IT Vertical Section Azimuth 283.36 deg Vertical Section Depth 0.00 ft Grid Convergence 0.00 deg Magnetic Declination 17.26 deg Total Correction 17.26 deg TVD Calculation Method Minimum Curvature D -Raw Calculation None Local Magnetic Field 57504 nT Local Magnetic Dip Angle 80.65 deg Local Gravity Field 9.826 m/s^2 Tie MD Incl Azim North I East TVD VS Temperature CRS LEN DLS Build Turn In ft deg deg ft ft ft ft degF ft deg/100ft deg/10aft deg/100ft U 18.50 0.00 0.00 0.00 0.00 18.50 0.00 212.97 0.77 355.03 1.30 -0.11 212.96 0.41 66.2 194.47 0.40 0.40 -2.55 293.96 3.05 3.76 3.99 -0.02 293.90 0.94 66.2 80.99 2.83 2.81 10.77 355.96 3.07 4.64 7.29 0.22 355.82 1.47 66.2 62.00 0.08 0.03 1.42 422.92 3.39 6.14 11.04 0.58 422.67 1.99 66.2 66.96 0.50 0.48 2.24 476.96 3.52 8.47 14.28 1.00 476.61 2.33 63.5 54.04 0.36 0.24 4.33 538.86 3.67 9.22 18.12 1.59 538.41 2.64 66.2 61.92 0.26 0.25 1.20 600.93 3.48 9.58 21.94 2.23 600.34 2.90 68.9 62.05 0.32 -0.31 0.59 663.20 3.57 12.05 25.70 2.95 662.49 3.07 71.6 62.27 0.29 0.15 3.97 725.37 3.57 11.13 29.49 3.72 724.54 3.19 71.6 62.17 0.09 0.00 -1.48 788.70 4.03 10.90 33.62 4.53 787.73 3.36 77.0 63.33 0.72 0.72 -0.36 850.49 4.46 10.97 38.11 5.39 849.35 3.56 77.0 61.79 0.69 0.69 0.11 912.10 4.39 9.92 42.78 6.26 910.78 3.80 363.6 61.61 0.17 -0.11 -1.71 975.28 4.90 6.44 47.85 6.98 973.75 4.27 77.0 63.18 0.92 0.81 -5.50 1038.00 6.19 359.25 53.90 7.23 1036.18 5.42 79.7 62.72 2.33 2.06 -11.46 1099.04 6.76 357.14 60.78 7.01 1096.82 7.22 79.7 61.04 1.01 0.93 -3.46 11.61.96 7.30 357.22 68.47 6.63 1159.27 9.37 85.1 62.92 0.85 0.85 .0.13 1225.20 7.74 357.44 76.73 6.25 1221.97 11.65 85.1 63.24 0.71 0.70 0.35 1267.08 8.09 357.34 85.24 5.86 1283.26 14.00 87.8 61.88 0.56 0.56 -0.16 1350.34 8.57 357.21 94.40 5.42 1345.85 16.54 85.1 63.26 0.76 0.76 -0.21 1413.08 8.73 357.31 103.82 4.97 1407.88 19.15 87.8 62.74 0.25 0.25 0.16 1470.59 9.62 356.30 112.97 4.46 1464.65 21.77 90.5 57.51 1.57 1.55 -1.76 1534.79 10.30 355.35 124.05 3.64 1527.89 25.12 93.2 64.20 1.10 1.07 -1.48 1598.68 10.93 356.39 135.79 2.80 1590.68 28.65 63.89 1.03 0.98 1.63 1659.77 12.36 357.41 148.10 2.14 1650.51 32.14 61.09 2.36 2.34 1.67 1721.74 13.12 357.64 161.75 1.55 1710.95 35.87 61.97 1.23 1.23 0.37 1784.90 13.03 357.71 176.03 0.97 1772.48 39.73 63.16 0.14 -0.14 0.11 1845.96 13.48 357.08 190.01 0.33 1831.91 43.58 61.06 0.77 0.74 -1.03 1905.96 15.50 356.48 205.00 -0.52 1890.00 47.87 60.00 3.38 3.37 -1.00 1968.91 16.40 357.98 222.28 -1.35 1950.52 52.67 62.95 1.57 1.43 2.38 2027.12 16.14 357.62 238.58 -1.97 2006.40 57.05 58.21 0.48 -0.45 -0.62 2089.21 16.26 357.67 255.88 -2.68 2066.03 61.74 62.09 0.19 0.19 0.08 2152.79 16.25 358.06 273.67 -3.35 2127.07 66.49 63.58 0.17 -0.02 0.61 2164.33 16.15 358.32 276.89 -3.45 2138.15 67.34 11.54 1.07 -0.87 2.25 U 2213.00 16.00 358.52 290.36 -3.82 2184.92 70.81 48.67 0.32 -0.30 0.41 2328.04 19.92 337.60 324.38 -11.71 2294.44 86.35 114.9 115.04 6.51 3.41 -18.19 2391.30 21.62 328.79 344.32 -21.86 2353.60 100.83 117.6 63.26 5.61 2.68 -13.93 2453.82 22.22 318.76 363.06 -35.63 2411.62 118.55 120.3 62.52 6.06 0.96 -16.04 2517.15 22.23 315.60 380.62 -51.90 2470.25 138.45 123.0 63.33 1.89 0.02 -4.99 2576.95 23.24 312.99 396.75 -68.45 2525.41 158.27 125.7 59.80 2.38 1.68 -4.35 2639.25 25.95 306.00 413.15 -88.47 2582.06 181.55 128.4 62.30 6.39 4.36 -11.23 2701.75 27.62 302.81 429.04 -111.72 2637.85 207.83 131.1 62.50 3.51 2.66 -5.09 2764.11 28.98 300.39 444.51 -136.90 2692.76 235.91 131.1 62.36 2.87 2.19 -3.90 2790.16 29.59 299.25 450.85 -147.96 2715.48 248.13 90.5 26.05 3.16 2.33 -4.35 2851.76 30.72 296.95 465.41 -175.25 2768.75 278.05 98.7 61.60 2.62 1.83 -3.73 2916.76 33.51 294.50 480.38 -206.39 2823.80 311.80 104.1 65.00 4.75 4.30 -3.78 2978.86 36.08 292.27 494.42 -238.92 2874.79 346.70 109.5 62.10 4.61 4.13 -3.59 3041.08 38.71 290.62 508.22 -274.09 2924.22 384.11 114.9 62.22 4.52 4.23 -2.65 3101.52 41.38 289.47 521.53 -310.62 2970.48 422.72 117.6 60.44 4.57 4.40 -1.90 3164.07 44.63 288.64 1 535.45 -350.94 3016.22 465.17 120.3 1 62.55 5.28 5.20 -1.33 Page 1 .ER A BAKER ADVANTAGE Final Survey Listing ARMS IR090 INTGQ Operator Armstrong Energy, LLC Fields Colville River API No 501032075101 Well Horseshoe#1A Wellbore Horseshoe#1A Rig Arctic Fox Job 8327027 Tie MD Incl Azim North East TVD VS Temperature CRS LEN DLS Build Turn In ft deg deg ft I ft ft ft degF ft deg/100ft deg/SOOft deg/100ft 3227.45 47.61 287.94 549.78 -394.31 3060.15 510.68 125.7 63.38 4.78 4.71 -1.09 3290.19 50.92 286.92 564.01 -439.67 3101.09 558.09 128.4 62.74 5.41 5.26 -1.63 3353.79 54.29 285.78 578.22 -488.15 3139.71 608.54 131.1 63.60 5.50 5.31 -1.79 3416.68 57.38 284.85 591.95 -538.33 3175.02 660.54 133.8 62.89 5.06 4.91 -1.49 3478.45 59.08 283.46 604.78 -589.25 3207.55 713.05 131.1 61.77 3.35 2.75 -2.25 3541.79 60.49 281.09 616.41 -642.72 3239.42 767.76 133.8 63.34 3.92 2.23 -3.73 3604.35 63.38 279.36 626.20 -697.05 3268.85 822.88 136.5 62.56 5.22 4.62 -2.76 3667.09 66.93 278.24 634.90 -753.30 3295.21 879.62 139.2 62.74 5.89 5.66 -1.79 3728.96 70.27 279.65 643.87 -810.19 3317.78 937.04 141.9 61.87 5.79 5.39 2.28 3792.87 70.46 278.63 653.43 -869.62 3339.26 997.07 141.9 63.91 1.53 0.30 -1.59 3856.04 70.49 279.00 662.56 -928.45 3360.37 1056.42 128.4 63.17 0.56 0.06 0.59 3918.76 70.49 278.95 671.78 -986.85 3381.31 1115.37 133.8 62.72 0.09 0.00 -0.09 3980.08 70.49 278.65 680.62 -1043.97 3401.79 1172.99 133.8 61.32 0.46 -0.01 -0.49 4044.64 70.29 278.70 689.79 -1104.09 3423.46 1233.60 133.8 64.56 0.31 -0.30 0.08 4106.67 70.23 278.64 698.59 -1161.81 3444.41 1291.79 136.5 62.03 0.13 -0.10 -0.09 4170.05 70.33 277.99 707.22 -1220.84 3465.79 1351.22 136.5 63.38 0.98 0.16 -1.02 4231.78 70.27 277.85 715.23 -1278.41 3486.60 1409.08 139.2 61.73 0.24 -0.10 -0.23 4293.35 70.36 277.94 723.20 -1335.83 3507.34 1466.79 136.5 61.57 0.21 0.15 0.15 4355.15 70.29 277.17 730.85 -1393.52 3528.14 1524.68 136.5 61.80 1.19 -0.12 -1.26 4418.09 70.33 276.90 738.11 -1452.33 3549.35 1583.58 139.2 62.94 0.40 0.06 -0.42 4479.05 70.23 276.01 744.56 -1509.35 3569.92 1640.55 139.2 60.96 1.38 -0.16 -1.46 4541.63 70.37 276.41 750.94 -1567.92 3591.02 1699.01 141.9 62.58 0.63 0.22 0.63 4604.30 70.23 276.01 757.32 -1626.58 3612.14 1757.55 141.9 62.67 0.63 -0.22 -0.63 4666.51 70.33 276.04 763.47 -1684.81 3633.13 1815.63 141.9 62.21 0.17 0.16 0.03 4729.04 70.26 276.24 769.76 -1743.35 3654.21 1874.03 141.9 62.53 0.32 -0.11 0.32 4791.81 70.30 277.53 776.84 -1802.01 3675.39 1932.75 141.9 62.77 1.94 0.05 2.06 4853.76 70.30 277.91 784.68 -1859.80 3696.28 1990.78 139.2 61.95 0.57 0.00 0.60 4915.66 70.36 278.46 792.98 -1917.50 3717.11 2048.84 136.5 61.90 0.85 0.11 0.90 4977.96 70.30 277.74 801.24 -1975.58 3738.08 2107.25 139.2 62.30 1.10 -0.11 -1.16 5038.96 70.26 278.20 809.21 -2032.44 3758.67 2164.42 139.2 61.00 0.71 -0.06 0.75 5101.10 70.37 279.11 818.01 -2090.28 3779.60 2222.73 141.9 62.14 1.40 0.18 1.47 5164.75 70.30 279.12 827.51 -2149.46 3801.03 2282.50 139.2 63.65 0.11 -0.11 0.01 5226.96 70.30 279.20 836.83 -2207.28 3822.00 2340.91 141.9 62.21 0.13 -0.00 0.13 5289.96 70.13 279.65 846.54 -2265.76 3843.33 2400.05 139.2 63.00 0.72 -0.26 0.72 5352.26 70.17 279.33 856.21 -2323.56 3864.48 2458.52 128.4 62.30 0.49 0.06 -0.52 5414.40 70.18 278.46 865.25 -2381.31 3885.56 2516.80 133.8 62.14 1.32 0.01 -1.41 5477.17 70.23 279.69 874.56 -2439.63 3906.82 2575.69 133.8 62.77 1.84 0.09 1.95 5539.91 70.24 279.60 884.45 -2497.84 3928.03 2634.61 136.5 62.74 0.12 0.00 -0.13 5601.34 70.27 279.94 894.27 -2554.82 3948.79 2692.32 136.5 61.43 0.52 0.05 0.55 5661.09 70.24 280.08 904.04 -2610.20 3968.98 2748.46 136.5 59.75 0.23 -0.05 0.23 5723.98 70.24 279.90 914.31 -2668.49 3990.24 2807.54 136.5 62.89 0.27 -0.00 -0.29 5787.40 70.29 278.78 924.01 -2727.39 4011.66 2867.09 136.5 63.42 1.66 0.09 -1.76 5849.10 70.27 278.61 932.79 -2784.80 4032.48 2924.98 136.5 61.70 0.27 -0.05 -0.29 5911.23 70.23 278.83 941.65 -2842.60 4053.47 2983.26 136.5 62.13 0.34 -0.05 0.35 5973.96 70.20 278.17 950.37 -2900.98 4074.71 3042.07 139.2 62.73 0.99 -0.OQ, . -1.05 6036.54 70.30 278.26 958.79 -2959.27 4095.86 3100.73 139.2 62.58 0.21 0.17 0.14 6099.10 70.33 278.30 967.27 -3017.56 4116.93 3159.41 139.2 62.56 0.09 0.05 0.07 6161.62 70.43 278.56 975.91 -3075.82 4137.92 3218.08 139.2 62.52 0.42 0.15 0.41 6224.35 70.46 278.19 984.52 -3134.30 4158.92 3276.97 139.2 62.73 0.56 0.05 -0.59 6288.36 70.49 277.56 992.79 -3194.06 4180.31 3337.02 139.2 64.01 0.94 0.05 -0.99 6347.31 70.46 276.37 999.52 -3249.21 4200.01 3392.23 139.2 58.95 1.90 -0.06 -2.01 6410.03 70.42 276.69 1006.25 -3307.92 4221.01 3450.91 139.2 62.72 0.48 -0.05 0.51 6471.07 70.42 275.92 1012.56 -3365.09 4241.46 3507.99 139.2 61.04 1.19 -0.00 -1.26 6532.64 70.43 276.48 1018.83 -3422.76 4262.09 3565.55 141.9 61.57 0.86 0.01 0.91 6595.73 70.46 277.25 1025.94 -3481.78 4283.21 3624.62 141.9 63.09 1.15 0.05 1.22 6657.69 70.43 277.58 1033.48 -3539.68 4303.95 3682.69 141.9 61.96 0.50 -0.05 0.53 6720.55 70.43 277.95 1041.48 -3598.36 4325.01 3741.64 144.6 62.86 0.55 0.00 0.58 6789.62 70.23 278.14 1050.59 -3662.76 4348.26 3806.40 120.3 69.07 0.39 -0.28 0.28 6850.96 70.44 278.34 1058.87 -3719.93 4368.90 3863.93 125.7 61.34 0.45 0.33 0.33 6912.96 70.50 278.71 1 1067.53 -3777.71 4389.63 3922.15 131.1 1 62.00 0.57 0.10 0.60 Page 2 .M A ADVANTAGE Final Survey Listing HUGHES A RM S T RONII INTCQ Operator Armstrong Energy, LLC Fields Colville River API No 501032075101 Well Horseshoe#IA Wellbore Horseshoe#IA Rig Arctic Fox Job 8327027 Tie MD Incl Azim North East TVD VS Temperature CRS LEN DLS Build Turn In ft deg deg ft I ft ft ft degF ft deg/100ft deg/100ft deg/SGoff 6974,08 70.43 278.39 1076.10 -3834.67 4410.07 3979.55 131.1 61.12 0.51 -0.12 -0.53 7035.27 70.50 278.72 1084.68 -3891.70 4430.53 4037.01 131.1 61.19 0.52 0.12 0.54 7097.87 70.42 279.04 1093.79 -3949.99 4451.47 4095.83 133.8 62.60 0.50 -0.12 0.52 7160.31 70.23 279.06 1103.04 -4008.05 4472.49 4154.46 136.5 62.44 0.31 -0.31 0.03 7222.80 70.27 278.70 1112.12 -4066.16 4493.61 4213.09 136.5 62.49 0.55 0.05 -0.59 7285.53 70.27 278.92 1121.16 -4124.51 4514.79 4271.95 139.2 62.73 0.33 0.00 0.35 7348.05 70.27 277.67 1129.65 -4182.74 4535.89 4330.57 139.2 62.52 1.87 -0.00 -1.99 7410.11 70.34 277.49 1137.36 -4240.66 4556.81 4388.70 141.9 62.06 0.30 0.11 -0.29 7472.36 70.30 277.08 1144.79 -4298.80 4577.78 4446.99 139.2 62.25 0.62 -0.05 -0.66 7534.36 70.30 277.14 1152.02 -4356.72 4598.67 4505.01 141.9 62.00 0.09 -0.00 0.10 7595.96 70.30 277.78 1159.55 -4414.23 4619.44 4562.70 144,6 61.60 0.98 -0.01 1.04 7658.45 70.27 277.02 1167.12 -4472.56 4640.52 4621.21 141.9 62.49 1.15 -0.04 -1.22 7719.96 70.26 277.38 1174.37 -4530.00 4661.29 4678.77 141.9 61.51 0.55 -0.01 0.59 7782.17 70.30 277.43 1181.92 -4588.08 4682.27 4737.02 144.6 62.21 0.10 0.06 0.08 7842.96 70.26 277.42 1189.31 -4644.83 4702.78 4793.94 141.9 60.79 0.06 -0.06 -0,01 7906.43 70.26 277.85 1197.24 -4704,03 4724.21 4853.38 144.6 63.47 0.64 -0.00 0.68 7966.23 70.33 277.58 1204.80 -4759.83 4744.38 4909.41 125.7 59.80 0.44 0.10 -0.45 8029.86 70.23 278.54 1213.20 -4819.13 4765.85 4969.05 131.1 63.63 1.44 -0.15 1.52 8091.63 70.27 278.84 1221.99 -4876.60 4786.72 5026,99 133.8 61.77 0.46 0.06 0.48 8153.76 70.33 279.21 1231.16 -4934.37 4807.67 5085.31 136.5 62.13 0.57 0.10 0.60 8184.73 70.27 278.64 1 1235.69 -4963.17 4818.11 5114.38 139.2 1 30.97 1.75 -0.20 -1.85 Projection to TD 8215.00 70.27 278.64 1239.97-4991.34 4828.33 5142.78 1 30.27 0.00 0.00 0.00 Tie Column Legend: I - interpolated tie -point, S - survey station, U - user -defined, T - Surface Page 3 Carlisle, Samantha J (DOA) al 1,H 33 From: Carlisle, Samantha J (DOA) Sent: Friday, March 10, 2017 12:13 PM To: Stephen Hennigan; Schwartz, Guy L (DOA) Subject: RE: Sundry 317-044 Steve —the AOGCC will withdraw Sundry 317-044 per your request Thank you, Samantha Carlisle Executive Secretary D:1 Alaska Oil and Gas Conservation Commission 333 West Th Avenue Anchorage, AK 99501 (907) 793-1223 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains intoe oration from the Alaska Cil and Gas Conservation Commission (AOGCC), State of Alaskaand is for the sole use of the intended mcipient(s). It may contain confidential and/or privileged information. The uruiuthorized 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 Samantha Carlisle at (907) :93-1223 or Smnantha.Carhsle@)alaska.gov. From: Stephen Hennigan [mailto:shennigan@peiinc.com] Sent: Friday, March 10, 2017 11:46 AM To: Schwartz, Guy L (DOA) <guy.schwa rtz@alaska.gov> Cc: Carlisle, Samantha J (DOA) <samantha.carlisle@alaska.gov> Subject: Sundry 317-044 Armstrong Energy would like to "cancel" or withdraw this Sundry. If I need to do anything else, please let me know. 7341 you ad dam a 6laed dayl 94446W 7(//,LIL'ILCQ22 l NIS Emgt O A Project Manager/Engineer'"l-T!" 2: 337-984-2603 2: 337-849-5345 (mobile) Petroleum ,= rr SIERRA ':•' R�% rtgl(l 01.1-20 HAMILTON RnNe!p Hfv.✓+u` vwniNlNnn¢NN Wyblh p!!>Nq.�x ryuxMG vvvLume] .ry eineslMzrotl mYw p!nkg+lnAvwpnnmaMwl Pp�nuw, uveomwm Munrewnnwrw M vnYuw!in!5ene yvnve<Mneu!pN /+usavw vM1a.Arvn RenwnMm. Wn! o ptlucef I!Y�!mrvMMs�numr.{bnnw'.w�!1awMneMEekm!Mmmml v,mnnywmWb iS �U b,A RBDW r;a c J 2 ./ "l Schlumberger 21 61 33 2&033 RECEIVE® MAR 0 7 2017 DATA SERVICES AOGCC NOTE! Once you have verified content(s) of packaged delivery, please sign this form acknowledging receipt of item(s) and e-mail to JEl-khouryQslb.com. Description of Data: Letter of Transmittal DATA LOGGED Alaska Oil and Gas Conservation Commission Address: March I, 2017 3 i1 /201'7 id K BENDER Job Number: DS -2017-04959 Attention: Job Processed by: Jules EI -Khoury UPS: 2"' Day Air Courier: Other: Plcesc acknowledge receipt of above item(s) by signing and faxing one (1) copy of this transmittal to Page 1 of 1 Operator Name: Armstrong Energy, LLC Signature o en�ta}[y�Je Received B : Well/Lease ID: Horseshoe Field Name: Wildcat Logging Run(s): R2134 API Number: 50-103-20751-00-00 Log Date(s): 14 -Feb -2017 County: North Slope State/Country: Alaska, USA Description of Data: MDT Final Report and Digital Data: l report, I DVD Company Name: Alaska Oil and Gas Conservation Commission Address: 333 W 7' Ave., Suite 100 Anchorage, AK 99501 Attention: Meredith Guhl Sent Via UPS: 2"' Day Air Courier: Other: Plcesc acknowledge receipt of above item(s) by signing and faxing one (1) copy of this transmittal to JE1-k"houry(@,sIb.com. Signature o en�ta}[y�Je Received B : ✓JtiV Date: 61 33 REG ?IVED MAR 0 2 2017 AOGCC Customer: ARMSTRONG ENERGY Well No: Job#: Horseshoe 1 CHJJ-00266 WIRELINE SERVICES Product Delivery Dispatched To: 21 61 33 Transmittal #: 01MAR17-SP02 DATA LOGGED 3/3/201? M K. BENDER AOGCC: Meredith Guhl Date Dispatched: 1 -Mar -17 Dispatched By: Stephanie Pacillo Well / Product Hardcopy Digital Copy Date Color Log Prints 10 Contents on CD R2D1 R201 2' PEX 5' PEX 2' ?AIT X x X X X X X X X X X 13 -Feb -17 13 -Feb -17 R201 -- R2D1 R2D2 R2D2_ R2D2 R2D2 R2D2 R2D2 5'ZAIT 5' NGI 60' NGI 2' CALIPER 5' CALIPER 2' MSIP-PPC -- 5- MSIP-PPC x _ X X X X X X X X Digital Data N/A Contents on CD OLIS+LAS X CD 3 Contents on CD CD: R2D1 CD: R2D2 Field Data + Graphics d U _ Field Data + Graphics M04-7 1 CD _ 2 co s Please sign and email a copy to: Please sign and email/fax a copy to: JNemec2 anslb.com AlaskaF`TSPrintCenter(a)slb.com Attn: Jeremiah Nemec Attn: Stephanie Pacillo Received By: ✓"'pkv REChFVED 02 2017 AOGCC Customer: ARMSTRONG ENERGY Well No: Horseshoe 1 WIRELINE SERVICES Product Delivery Dispatched To: Date Dispatched: 21 61 33 Transmittal #: 01 MAR17-SP03 DATA LOGGED 3 /3/201-7 M K BENDER AOGCC: Meredith Guhl 1 -Mar -17 Job#: CHJJ-00266 Dispatched By: Stephanie Pacillo Well/ Product Hardeopy Digital Copy Date Color Log Prints 5 Contents on CD R2D3 5' CMR x x 13 -Feb -17 R2133 5" ECS x x R2D3 5 HNGS x x R2D4 MDT x x 14 -Feb -17 R2D5 XL ROCK x x 15 -Feb -17 Digital Data N/A Contents on CD DLIS + LAS x CD 3 Contents on CD C0: R2D3 Field Data + GraP hics 8 0 2 9 1 CD CD: R2D4 Field Data + Graphics 8 0 3 0 ICD CD: R2D5 Field Data + Graphics 28 0 3 1 ICD Please sign and email a copy to: Please sign and email/fax a copy to: JNemec2(a)slb.com AlaskaF`TSPrintCenter(a),slb.com Attn: Jeremiah Nemec Attn: Stephanie Pacillo Received By: III A jAORS Sample Manifest 301 East 92nd Avenue,#2 Operator: Armstrong Energy LLC Anchorage, AK 99515 Well Name: HorseShoe#1 (907) 561-2465 Location: North Slope 6000 Date: 2/15/2017 Sample Type Start Depth End Depth Total # # Boxes Date Shipped Remarks Repsol Dry Samples 120 6000 211 5 2/15/2017 Purple Boxes Repsol Wet Sample 120 6000 211 4 2/15/2017 Classic Brown Boxes Ship to: Attn Shipped by: Expeditor: Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 Meredith Guhl Petroleum Geology Assistant meredith.guhl@alaska.gov Direct: (907) 793-1235 Date: Date: o?►lv- 1�33 \5glb RECEIVED FEB 2 3 2017 AOGCC Ec' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg Kn�� Z-�L-711 DATE: February 19, 2017 P. I. Supervisor FROM: Lou Grimaldi SUBJECT: Wellbore plug Verification Petroleum Inspector Horseshoe #1 PTD 216-133 Sundry 317-074 Armstrong Energy Inc. Exploratory, Wildcat Friday, February 17, 2017: 1 witnessed the verification by drill pipe tag of the wellbore plug in Armstrong Energy Inc's Wildcat well, Horseshoe #1. I arrived in time to witness the make-up of bottom hole assembly and trip in on drill pipe to top of cement (TOC). The tag was made with an 8 '/4 -inch mill tooth roller cone bit. The last full stand of drill pipe (#21) was kelly'd up and washed down through some heavier fluid (contaminated cement?). Stand #22 was made up and washed down 18 ft where it took weight with approximately 1 OK down. This depth was calculated at 2030 ft RKB. The 9 5/8 -inch shoe was reported at 2213 ft RKB. ATTACHMENTS: none NON -CONFIDENTIAL 2017-0217_Plug_Verification_Horseshoe-1_Ig.doc x Page 1 of 1 THE STATE °fALASKA GOVERNOR BILL WALKER Stephen Hennigan Consulting Project Engineer Armstrong Energy, LLC 510 L Street, Suite 310 Anchorage, AK 99501 Re: Exploratory Field, Exploratory Pool, Horseshoe 1 Permit to Drill Number: 216-133 Sundry Number: 317-074 Dear Mr. Hennigan: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1 433 Fax 907.276.7542 www.00gcc.cilaska.gov Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sine Hollis S. French Commissioner .6l DATED this 1S day of February, 2017. RBDMS LL- FD 1 6 2017 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ��gIVED FEB 14,ZbCJ AC - ac 1. Type of Request: Abandon L Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend RA00 Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: ❑ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Armstrong Energy, LLC Exploratory ❑ Development ❑ Stratigraphic ❑ Service ❑ 216-133 3. Address: 6. API Number: 510 L Street, Suite 310 Anchorage, Alaska 99501 50-103-20751-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? na Horseshoe 1 Will planned perforations require a spacing exception? Yes 1:1No Q 9. Property Designation (Lease Number): 10. Field/Pool(s): Wildcat ADL 392048 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): �m o #4 `!- 0 0 na na Casing Length Size MD TVD Burst Collapse Structural 118 16 118 118 ne na Conductor 0 0 0 0 0 Surface 2216 9.625 2216 2188 7930 6620 Interm Prod Liner 6000 OH 6000 5819 0 0 Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: I Tubing MD (ft): na na na na ne Packers and SSSV Type: Packers and SSSV MO (ft) and TVD (ft): na na 12. Attachments: Proposal Summary Wellbore schematic ✓ 13. Well Class ter proposed work: Detailed Operations Program E] SOP Sketch ❑ Exploratory [r Stratigraphic ❑ Development ❑ Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: �,j �L1% 17 rf OIL ❑ WINJ ❑ WDSPL ❑ Suspended L±1 GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: ate: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Stephen Hannigan ph 337 849-5345 Email steve(caoeiinc.COm Printed Name Title Stephen F. Hannigan Consulting Project Engineer for Armstrong Energy, LLC Signature , P one (337) 849-5345 Date 2/1412017 9:03 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. 3V7-07 Plug Integrity RI/ BOP Test Mechanical Integrity Test ❑ Location Clearance ❑ Other. � U p fiZ S f '� � G U C7 ��) J -P TD zit, -1 3 12 . Post Initial Injection MIT Req'd? Yes ❑ No Spacing Exception Required? Yes E)No 2r Subsequent Form Required: /0 —107- RBDMS L- FEB 1 6 201 APPROVED BY j,S Ity — COMMISSIONER THE COMMISSION Date: I 'C Approved by: j Submit Form and Yom 10-003 �Sse� 1112015 p r frr1t1A id for 12 mon a I0 h¢ d¢� f approve!. Attachments m Duplicate A ARMSTRONG Eno - gr. LLC February 13, 2017 Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7'" Avenue, Suite 100 Anchorage, AK 99501 RE: Application for Sundry Approval Armstrong Energy, LLC Horseshoe #1 (PTD 216-133) Sec 15 8n 4e UM Wildcat North Slope, Alaska Subject: P&A Open Hole and Plugback for Sidetrack 1A (PTD 217-015) Dear Ms. Foerster, RECEIVE® FEB 14 2017 0GCC Armstrong Energy, LLC hereby applies for an Application for Sundry Approval to P&A and plugback the Horseshoe #1 in anticipation of drilling Horseshoe #1 ST 1A (PTD 217-015))/an exploratory oil test on the North Slope. The well will be located on State of Alaska lands. The Horseshoe #1 well is drilled to TD of 6000'MD. Upon completion of evaluation it is requested that the well be plugged back to :100' below the surface casing shoe in anticipation of sidetracking. All hydrocarbon bearing zones below that point in the Horseshoe # 1 will be cemented. If there are any questions and/or any additional information desired, please contact me at (337) 849-5345 or Pete Berge at (573) 201-3861. Respectfully ARMSTRONG ENERCzY, LLC Stephen F. Hennigan Armstrong Project Drilling Engineer Enclosures Cc: Edward Teng — Armstrong VP and Project Manager Pete Berge - All American — Armstrong Drilling Superintendent Cindy Bailey — Armstrong Public Affairs Manager Robert Britch — Senior Advisor Pete Dickinson — All American — Armstrong Drilling Manager Stephen Hennigan — Sierra Hamilton Petroleum Engineers for Armstrong Energy 510 L Street, Suite 310 -Anchorage, AK 99501 p907.375.6900 Armstrong Energy, LLC Horseshoe # 1 ST Block/Sec 015 T8n Roe Wildcat North Slope Alaska PTD 1f: 216-133 A ARMSTRONG !.110,'1. Lel Current Status: TO: TBD AR,tAIRONG OPE2117ONS GROUP FROM: STEPHEN HENNIGAN ARMSTRONG PROIECC MGR/ENG DATE: FEBRUARY 6, 2017 SUBJECT: HS #I PLUGBACK FOR SIDETRACK TO I A (PTD 217-015) Well is being evaluated. P&A w/ plugback anticipated to begin 2/15-16/2017. WELL DATA: Well: Horseshoe #1 Location: Block/Sec 15 8n 4e Wildcat - ADL 392048 North Slope, Alaska PTD: 216-133 ICEMD: 1.0' AG 18.6' FKB (perm datum) MSL: 43.1' Elew (GL to MSL) 23.5' Well Depth: 6000'MD/ ±5819'TVD (surveys attached) PBTD: Open Hole Well Construction: See wellbore schematic Correlation Log: (Delivered to AOGCC G&G) 1 OBJECTIVE: Secure wellbore for sidetracking to the proposed geologic bottom hole location of the Horseshoe #1 ST 1- A. COMMENTS: The well is presently in the process of being evaluated. It is proposed that the entire open hole to within x100' of the surface casing shoe will be cemented with cement remaining in the inside of the tubing. The drill pipe will be disconnected from the tubing by pumping down a plug. The cemented tubing with approximately x2-500' of cement on top will function as a complete open hole abandonment plug as well as serve as a kick off plug. Well History: The Horseshoe #1 is the one exploration well for the 2017 North Slope drilling season. The drilling prognosis calls for multiple zones of interest to be penetrated and evaluated in this well. Drilling began on January 27, 2017. After setting surrface pipe, drilling and 2 coring runs,TD was reached February 11, 2017. Evaluation is in process. Assumptions : Un The estimated BHP of the formations penetrated is assumed to be <.45 psi/ft. Casing design safety factors are: lnteraal Start Deoth Seat Depth Using M= Design Factors for... MD MD Size / Wt Grade Burst • Tension- Brst Des. ..e ..,In flhiftl 1.1—.. roll— De< Bunt Collapse Tension D'W./ 0 118 %56 N/A N/A N/A N/A N/A 16"-89 pPf Structural24" ._ ____----- ----- -_-_- --------------- _._-_ _-_-_0 118 Weld ._ ---__-_----------------N/A N/A N/A N/A N/A 0 23189.625" - 53.5 L80 7930 1299 1993 5.50 8.50 11.84 Surface 12.25" 0 ---- _ — 2242 PPf --'----- Mod BTC 6620 -- 728 C Horseshoe 1 Plugback for Sidetrack Procedure Following open hole logging: Refer to: Target mud properties Cement Program Halco Disconnect Procedure Final Wellbore Schematic 1. PU 3 1/2" 9.2# L-80 TC -2 (ID 2.992, drift 2.867) tubing and trip in hole. Install Halliburton Bottom Hole Kickoff Assembly (BHKA) Disconnect. a. Space out so top of tubing will be ±300' below the shoe and cement above it to ±100' below shoe after cementing and disconnecting. b. PU drillpipe to lower the tubing to TD. c. Circulate as necessary utilizing MAXIMUM flow rate and MAXIMUM rpm. 2. At td pump a low vis followed by weighted sweep while continuing to circulate and rotate as above. a. Hole will require more than just circulating bottoms up. Circulate till clean. b. Condition mud to lower YP and gels. c. Monitor pill lag and mud log lag times to aid in adjusting cement volumes for hole washout and compare to elog value. 3. RU cementing company. Test lines. (Cement volume is PLANNED to be ±2-500' above the tubing.) Cement. 4. Pump releasing dart and pressure up disconnecting from the tubing. 5. Pump top balanced cement plug above disconnect tool. 6. POOH into the surface casing and circulate CLEAN. 7. POOH and prepare for Horseshoe 1A sidetrack (PTD 217-015). 8. TAG plug w/ 5k. /V6 t° );� 4—C 61, C C f -O wi S,5 3 Target mud properties with mud weight in use: Pre -cement target fluid properties Prior to cementing a fluid sample will be Section YP Additions 8.5' Evaluation 18-22 Whole LVT provided to cement lab to ensure compatibility 4 Armstrong Horseshoe #1 Plug Back Procedure 14.5 Ib/gal plug cement from TD to — 2516 ft MD using BHKA Disconnect Tool *Prior to pumping cement plug through BHKA Disconnect, Halliburton Service Supervisor will ensure that all components are in operating condition and are made up properly per the BHKA Disconnect Operator's Manual. All job calculations will also be completed prior to the job utilizing actual casing tally and verified by the company man. Well Data L TD — 6000 ft MD L Desired TOC —100 ft below surface casing shoe o 2216ftMD+100ftMD=2316ftMDTOC L Plug Length — 6000 It TD — 2316 ft TOC = 3684 ft cement plug Li Anticipated Open Hole Excess —10%q L Mud Density /Type — 10.4 Ib/gal MOBM Capacity Factors L 3-1/2", 9.24 Tubing Capacity — 0.00870 bbl/ft L 3-1/2" Tubing x 8-1/2" Open Hole — 0.0583 bbl/ft Calculations a. Volume of Spacer to Pump Ahead i. 29 bbl b. Volume of Cement to Pump i. (3484 ft * (0.0583+.00870 bbl/ft) * 1.10) + (200 ft * 0.06544 bbl/ft * 1.10) = 256.76 bbl + 14.39 bbl = 272 bbl cement c. Volume of Spacer to Pump Behind i. 6 bbl d. Volume of Mud Displacement i. 6 bbl spacer behind / 0.01084 bbl/ft = 522.14 ft 2316 ft — 522.14 ft = 1793.8 ft mud displacement 1793.8 ft * 0.01084 bbl/ft = 19.44 bbl mud displacement Job Procedure 1. PU 3528' of 3-1/2", 9.2# sacrificial tubing and RIH. When tubing reaches desired TOC, begin pumping mud to clean wellbore 2. Install workstring adapter onto workstring, utilizing any necessary crossovers to ensure thread compatibility 3. Install BHKA Disconnect hand tight into tailpipe, utilizing any necessary crossovers to ensure thread compatibility 4. Torque BHKA Disconnect on the lower adapter 5. Install workstring adapter into BHKA Disconnect 6. Continue pumping as tool is lowered into wellbore 7. Pump 29 bbl spacer ahead of cement 8. Pump 272 bbl cement through workstring 9. Pump releasing dart through workstring to releasing mechanism, followed by 6 bbl spacer behind and 19.44 bbl 10.4 lb/gal MOBM. Pump entire displacement at 1-2 bpm. Note circulation pressure before landing releasing dart. 10. When plug bumps, apply required surface pressure as specified in manual to shift releasing sleeve and disconnect workstring from tailpipe 11. When release mechanism is activated, stop pumping, pull 300' above TOC, and circulate clean. Continue to POOH H-le4%v idisconrech rechar sm Dm.rler suh Figure 1.1—Major features o/ the BHKA disconnect tool. Figure 1.2—BHKA disconnect used for side-tracking. P40e 1 of 2 J Actual Wellpath Geographic Report - including Position Uncertainty I Z/Fe6/2017 at 06: 47 NAD ) M Alaska SP, Zone 4(ENO, US feet Armstrong Energy,LLG rve Wright Seat. A16ake 0.989922 Armstrong Brma , LLC North Blo#a Slot Ex lars40n - Arotle FOX( HoitAeMe #1 - ZD2 FOX RD Hg9e~l Won SM Lintel Horadhoe#1 .0051 HowesXoe#1 awp .00X Oti9/201] 42,OON (none) E 0.00 X LevejetsN 0.OW MinX Minimum curvature d T MagmbO Nor1X is 1].26"0" seat M True NMI1 induktl 200 on, Dev 4200 X 0.99 099380280.Po 58%909.00 ]0"0248.595'N 151"%03.989"W 2 W 1 03 NEZ,.Po 566]909.00 360316.00 588]92200 ]0'0248.595"N )0'02'46728"N 151"%'99.989"W 151"0703.96-W 2099 3.99 18.50 2184.33 3636 5971 It 21.61.33 59]11)9 600.00 BHI O-Tmk(StarMertl) BHI OnTrek (SlaiWartl) 51519 Ohit (stEl _ X121/1"BHI DBurvays <18.5'-2164.33' ;8177 BHI MWD Surv818,2gG-xxxx_>_ LL>ro' onbblt Horseshoe et un-1oe Horsesho¢xl _ 3636_ 3611 3636 -� _ _ string I Dinarder 982 in Casi Butlace Start MD 18.50 End MD 227300 laM.1 2254.5018.50 Stan TVD EhdTVD 2242.62 Saimms Saint E"A' End " 0.00 000 3,16 79 End M 4.20 Horsasnce$I glifliber. I- Tar,tNnnna, Nenushuk3Cw. POInt(Bat-11 TOO 444200 North 644.52 Seat 62398 Grid Saint 360925.62 Grid N.rIh 586854192 Latitude Longitude 70°02'54.934'2151°2'66019'99 she,. pini Continent NID 000 inclination ON �rhadh 35503 TVD O00 TVGSS 4200 N-th QW-1 E-I 0.00 Grid E-I 360299.00 Grid North 58%90900 -clunda Larlit.al ]Og2'48.5N'N 151°070358899 OILS 000 T..lfaci, Build 1 1 R.I. Turn 0.00 R,it. OW Will Sarl OW Sarri OW sagn, 000 vtIl s1rhi 0.00j2VW �1,, Corning". 185D OW 35503 18.50 -2350 OW 0.00 990290.99 585]999.00 ]0'0246595'2 151°OTO3969"9tl 000 4.9> OW OW OW 080 000 0.002129) 0D 35503 21286 17ON 1.30 -0.11 36026991 580)910.80 )0°02'66603"N 151WO3, N'W 0,40 11.65 0.40 _ -256 ON 40.20 40M 6,73 293.96 305 376 293.80 251.90 3.98 -0.02 360280.05 5867912.99 70.02'48.834'N 151ro7'03N9W 283 6].38 282 10.]8 2.68 4021 4020 6.74 9355.96 307 464 355.82 313.82 7.29 0.22 360290.36 5997916.28 7Oro348AE7"N 151°0T 03.NEV 0.08 15.54 0.03 1.92 540 40.22 4021 674 422.92 3.39 6.14 AN 67 380.6] 1105 0.58 380290.]8 599)921.04 )0°02'48.799"2 151gT03.97E V 0.49 48.3] 0. 8 224 834 60.23 40.21 6,74 84]688 536.88 3.528A7 387 36 922 4]6.61 SNAt 434.61 496.41 1028 18.12 1.0 1.68 360291.26 360281.92 5869955.28 580792!.2 70.248. �N 151oWD9 70°0248.43"N 151gI'W.993^N-0.25 035 1)78 1]3.94 0.24 024 431 1.21 1095 1612 4023 40.24 40.22_ 40.23 675 6.)5 136 8NO 93 348 956 600.34 55834 21%1 222 380282.63 586793389 70°0248.811"N IsoOl"03.1i 0.31 6058 -0.31 058 1].31 40.25 40.24 6,76 6663.20 357 1205 662.49 620.49 25.69 294 36029341 5861934.63 )0°0748.6482 151 ro>'03W4'V7 0.28 -00.46 0.14 3.9) 2051 40.26 40,25 677 27253] 3 7 11]3 72454 682.54 29A9 319 360294.28 586)93641 70°0748.880"N 151ro703.862M' 0.09 .181 000 -1.48 23.77 40.2) 40.26 6.78 59788.70 499 10.98 7%.)3 745.73 MN 4.53 38Od5.W 5861942.51 70.0248.92899 151TOWSS8"W 0.73 -0.10 0.73 -0124 27.28 40.28 40.28 679 585049 4.48 109] 84935 80735 3808 540 380298.09 5867946.99 70g748.97WN 151.07'08.834'W 070 -131.35 0.70 -0Ce 31.12 4030 4028 6.80 95912.10 4.39 992 _ 910.78 %8]8 42.7] 8.26 30028].04 SM7951 W ]0°029016'2 1WOro 03.13W`N 0.17 -33.6] -0,11 dJ0 40,31 40.31 6997528 AN 646 919.75 21)5 4783 698 38028>.85 688]958.89- 70.OZ48.080"N 151ro''03.780"W 0.92 -3182 _ 0.61 -5.51 _35.08 39.22 4033 4033 _6.81 6.82 8 1038.00 6.19 35825 1038.18 994.18 SON ).2 360288.22 586796213 70°OZ49.125"N 151°070378199 233 -23]1 2.06 41.46 43.74 40.35 4026 6.83 344]5 1099.04 6.76 357.14 1096.83 1054.83 60.75 7.01 380288.12 $867869.61 ]0°02'49.193"N 151°0703.]8'7'99 1.01 108 0.93 -3A6 Ali 40.37 40.'.17 6.84 4.98 116196 7,30 357.22 1159.27 11179 SEAS 663 360297.89 586]94.31 70.OZ49.268'N 151•%'2.77NZ 0.99 365 0.N 0.13 5319 40.40 40.39 686 .3.65 1225.20 7.74 35744 1221.97 1179.% 76.71 6.25 360287.65 5867985.58 ]0°OZ493N'N 151°OTO3.809W 070 2.30 0.70 0.35 59.46 4043 4041 687 2.15 12VO8 8.09 35734 1283.26 124126 65.23 5.86 380297.42 5887894.10 70gZ484W'N 151"OT03.BW W 0.57 -2.31 0.57 -0.16 65.31 AU.40 40.43 8.69 1.24 1350.34 14132 8.57 ._ 8.63 35721 -. _ _ 35731 1345.85 - _ 140760 132.85 1365.._ 1415!AS 9438 _ 103.80 SA2_ 4.% NOND.15 ..-3636- 360296.88 5868003.26 _-12.61 5668012.99 170.0241LM-N 151°OT03833W ]0gQ49.616'N 151"OTO3.866W 076 1.28 542 - - -t07fi 076 - _ 0.26 021 - 0.16 71.58 4049 40,53 40.48 _ 40,49 690 682 _ 0.62 _ - 7.18 147059 1464.65 1422.65 11296 4.46 380996.53 5@3312195 TO.O2'4972'N 751gTO3, iV 1.57 -16.05 1.55 4.76 SAN 84.28 40.5] 40.51 694 Ni 1538.]8 1Q.620.3 10.311 ON�156.30 355.35 1527.88 1685.88 1242 3.65 990295.92 5808032.99 )0.02'49AW-N 151.OTOS%gnW 1.09 1.06 -1.68 91.65 40.54 696 359.54 1598.68 10.83 356.39 159O.SI 1548.68 135.4 2.80 38022.28 5868344.08 70°02WOWN 151°0T0392"W 1.03 8.89 8.0 0.99 1.63 OSSO07.8 AIDE 40.66 40.57 698 359.15 1859.]) 1236 Si 165051 1608.61 166.00 2.14 36028188 580835],07 ]0°0250052'2 151°%0399W 2.36 3.83 2.34 1.87 11728 40]1 40.60 799 358]2 172194 13.M 35'.64 168695 18176 1.55 360204.52 588807067 70°02'W.180'N 151°0T039UW 123 170.06 123 0.37 11728 40.4 40.61 702 1 13.03 357.11 im,,95 142.98 1780.48 176.01 0.97 800294.20 5806088.95 70°02'S0.328'N 151•%0396199 0.14 -ASA 0..14 126.14 40.04 40.61 7,06 OMAI 358.29 WN 996 19OSA6 13.48 183191 1788.91 190.00 0.34 360283.82 5806388.95 70-02 W464-14 151°0703919^99 0.77 4.54 0174 -1.0 -1.03 136.74 40.71 7.07 356.20 1905.98 15.50 WAS 356.98 199000 1848.99 20498 -0.51 360283.25 593811393 7M-50.611"N 151-0704,00499 3.38 25.33 3.% 4,00 14682 4ON 4190 4095 7.10 358.11 1968.81 1610 357.98 1906,53 1808.53 222.26 -1.94 380292.]3 5858131.23 ]0°02'99.781"N 151.0704028^99 157 - 143 230 15096 4108 40.19 712 35807 202].12 1614 357.62 2066.40 1984.40 238.56 -1.0 380292.41 5868147.54 151°%04,06i OAS ON 686 -0AS -082 17003 41.15 4083 715 35788 209921 16.28 357.% 2066.03 2024.03 255.87 39020201 5808164.85 7TMI.11VN 7TW51.112'N 151-0]04.08899 0.19 0.19 008 181.97 4124 ADS, 7.19 357.88 2152.)9 16.25 358.08 212707 2085.% 2)3.85 -384 434 36029188 $808182.85 ]0°0251.33!"N 151-0714.08599 0.17 Writ 148.1) -0.02 0.81 194.29 4135 40.91 7.22 35].85 2164.33 16.15 350.32 2138.15 2096.15 96.87 -345 360281.63 5858103.8! 70°02'51.316"N 151.0J04.INV 1.07 159.10 0.87 225 196,53 41.38 4092 723 357.84 2225.)7 15.85 35874 2293.70 2181]4 304.27 4.15 360201JO 5808213.2] 19roZ51354N 151ro7W 11:0V 0.32 121.82 -0.30 0.42 215.]2 41.50 40.96 729 357.85 2328.20 1519 1.99 2203.88 2251.88 321.14 4.19 360281.]0 5868230.14 70°251151"2 151•%01,110"99 1.13 13345 0.58 3.62 22].82 41.58 40.96 7.28 Ni 2389.13 1463 4.72 2354.62 231262 337.45 339 380282.80 5868246.63 7TW51 DIAN 151-0704.0%"W 206 7806 -1,37 592 240.09 41.63 40% 732 358.42 2450A5 14.74 6.82 2413.93 237183 352.92 -1.85 360299.62 SOWN1t 7 70.252.080"N 151•%'0404199 081 50.85 OAS 3.10 252.27 41.69 40.97 7.35 358.84 251328 15.15 8.51 24]4.62 243262 308.% 026 3602%.05 586824.80 7%0252.224"N 151°07'03901"W 101 ]8.81 0.65 301 265.28 41.4 40.98 7.38 358.24 2575.77 1599 15.53 2534.90 2492W 385.15 3.74 380300.80 5868293.99 70°252.32"2 151.07'03.881"W 3.06 87.60 072 1123 2'9.32 41.65 AO.N 742 359.79 2838.81 1599 26.28 2595.57 255357 401.11 8.80 3603%.21 5888300.83 70cOZ52,54l 151°%'03105W 488 71.46 0.62 1705 NEDA 41.94 41.00 745 0.76 270121) 11.21 36.18 1954.50 261250 416.05 18.0 300316.60 5888324.99 7%252.687'N 151°%'03.442"99 5.99 )6.82 1.N 16.10 312.12 42.04 41.01 7.49 2.19 96181 1607 45.18 91314 2%1.14 430.12 31.12 360329.00 5688338.44 >0°OZ52.25'N 151°%'03.02"W 4.99 19.2 140 14.63 330.2 42.14 41.02 752 3.90 P40e 1 of 2 J 2824,50 1859 51.84 1285 2]3085 443.17 45.85 360313.98 5868351.22 )0°0252.951"N 151 °0702668"04 3.34 66.8) 0.81 10.3) 350.30 42.23 41.04 268].14 19.57 5]83 2831.88 189 fib 454.85 62.58 360:30.88 5868362.69 70°0Z53.10 -N 151 °07M.187M1 359 53.17 1.59 9.88 3]0.38 42.32 41.06 ).60 7.94 2919.01 2192 62.63 2889.91 284)91 485.55 81.14 3603]9,66 56683]2.95 7WO253.1)4'N 151°DT01.8-'W SAO 36.63 2.18 7.76 390.92 42A2 41.08 ].64 10.11 3011.26 22.48 6561 294]]5 2805]5 475.58 101,85 380400,54 5868382.59 70°02'532)3-N 151°OTO1.O%6 3.07 WU 2.51 4.79 412.53 4252 41.10 7.68 12.39 3873.80 23.90 08.24 300$2] 28832) 48522 124.52 380423.39 5888391.81 700253387"N 151°OT00.403-W 281 3128 21 420 435.23 4263 41.13 7.73 14.77 3136.82 25.42 70.3) 3082.33 302033 49448 14903 360448.05 5888400.80 7VOZS3AW'N 151°06'5969]"W 2.80 2189 2.42 3.30 458.91 42.75 41.16 778 17.28 3198.44 2].61 M.21 3116.54 3048.54 503.44 175.59 36BQ4 ]8 5869909.09 )D°0253.51]'N 151°05'58.4#'04 302 4.23 3.49 193 4H1.84 42.68 4120 7.83 19.93 3281.54 2685 72AO 3173.25 3131.25 512.36 2035] 3-502.92 5868417.50 7WOY53.634-N 151°O6'S8.128 2.00 64.10 2.00 0.31 508]2 43.04 41.24 7.88 22.82 3323.80 29.06 73.04 322]55 3185.55 52121 232.29 380531.79 5888425.82 7WM$3.721'N 151°D6'S72B9'W 0.84 94.19 0.1 1.55 538.05 43.20 41.28 7.95 25.35 33%.34 2806 72.76 328238 3240.38 530.09 281.48 380581.11 5868434.1] 7WW53809'N 151°06'S6.459"W 047 62.05 .0.- -0.96 562.]1 43.38 41.33 8.01 28.04 3048.23 29.13 73.03 3336.6 3294.48 538.94 290.22 3-590.03 5868442A9 70°OZ53.696"N 151°6655631'04 024 -1.45.10 0.11 0.44 569.06 43,58 41.38 8.08 3054 3510.46 28.87 72.]0 MON 334886 547.85 319.10 360619.06 5868950.88 70°025.=N 151°06'54199'04 -DM 885 -0.26 -0.53 815.56 43.78 41.3 8.15 32.92 35T2.39 2913 72.]5 3445.00 3403.00 556.]8 347.81 3-64).93 5888459.28 70°0254.07VN 151°O6'53.8]2"W 028 .1-A5 0.26 0.08 641.95 44.02 41.8 8.23 35.12 3634.43 26.6) 72.27 3499.32 30.5732 585.79 378.41 360676.69 586646]]4 70°0254.160'N 151°06'53.118'04 0.83 -173.26 -0.74 -0.P 688.31 44.27 41.53 831 W16 3895.92 2746 71% 355358 351158 57467 403.94 360]04.37 5688478.12 70.02'54.247-N 15l°O6'52.355'W 1.98 174.08 1 -1.97 1 -0.50 693.80 44.52 41.59 839 38.96 375777 26A7 72.18 3609.]0 3588.]0 58383 43062 3-731.21 5869984.26 7WO2'S0.SUN 1151°OB'S1.68TW 1.61 179.P 1 4.60 0.37 718.61 44.79 4161 8.48 40.55 382172 MAO 72.20 3665.31 3623.31 591]2 45663 1 350)575] 1 596&19220 70°02'M415 -N 151°O6'50.832W 1.70 10.95 -110 0.02 742.88 4506 4169 8.57 42.- 38-.19 2370 72.95 3]22.13 38-.13 559.50 48160 360762.4] 5868499.52 70°0254.491'44 151°08'50.119'04 2P 178.45 -2.72 1.20 76570 45.32 41.74 888 9327 3944.73 2153 7311 3P894 3]36.94 606.40 504.23 3--5.22 5638505.01 70°02'54.559'N 151°0649.46704 3.53 178.86 -353 0.26 786.40 45.W 41.79 8.75 44.34 4007,35 1938 7324 363781 3795.61 61274 52518 %0828.2] 568511.96 70°0254621'44 t5t°064886a'W 3.4] -178.66 3.47 0.21 905.51 4581 41.85 684 45.24 4068.56 1684 7307 3895.78 3853]8 618.24 543.36 3-804.56 5858511.13 ]0702'54.6]6'N 151 48.34PW 412 4)9.6] 4.12 41.28 822.13 46.02 41.80 802 45% 413)52 1430 73.01 3955.47 -13.47 MAO 55827 380650.56 _ M8521.59 7TOZE4.723'N 151°06'0788204 4.10 4P.31 4.10 4.10 838.88 48.22 41.95 9.01 46.53 410343 1223 12.55 4016.89 3974.- 627.36 573.06 360874.42 5898525.70 70°02'54.]65"N 151tl8'47.4 V 3.29 SU -0.73 84034 48.38 4201 908 46.98 4255.80 1088 12.49 40P- 4035.80 -1.12 584.9] 3-896,40 5%9529.23 70"02'54.802"N 151°0647.141^04 2.15 IM47 3.16 -0.10 8-.32 46.55 42.06 9.16 47,36 4317.31 9]3 731 413882 4086.32 634.38 595.49 MOM 9] 5868532.28 )0°02'54.834"N 151°OB46.6395Y 1.88 171.89 -1,87 1.27 062.96 46.69 42.10 923 47.70 4379.06 940 )4.5] 4199.29 4157,28 637.06 604.63 36090686 5888534.81 )0°0254.861"N 151 O 46.588"04 2.18 17483 -215 2.11 878.41 46.82 42,15 9.30 4TW 4441.90 8.1 76.51 426161 421881 639.08 61260 380914.18 5868536.- 7TOZ54.8-'N 151 -M -46.3465Y 341 176.51 3.39 3,00 865.26 4893 4220 9.37 48.24 4-1.49 341 79A5 4821 A8 427908 640.18 617.54 360919.13 580853!.69 7TOZ54.891"N 151°06'46.20344! 478 1]82] 4.76 4.89 889.49 47.01 42.24 9.44 48.37 4563.99 0.58 87.92 4383.44 434141 640.53 619.67 3-921.26 586853800 70°OZ50.895"N 1516646.142'04 4.58 170.31 4.56 1386 -1.22 47.06 02.29 9.50 48.38 462].06 0,13 209.58 4498.51 I 4404.51 840-47 619.95 36092154 588853).95 7WOZ2 .894N 151.0446A34M 1.04 -171. -0.71 19290 -1.36 47.10 42.34 9.56 22834 4688.66 0.04 188.99 4508.11 4466.11 640.39 619.92 3-921.51 5808537.81 7VOZ54.883N 151°0696.13544! 0.15 1 -815 33.43 -1.29 47.14 42.37 9.63 228.33 4]-.16 003 226.08 45]981 453].61 WAS 619.0 3-821A8 5886537.83 7VOZS4.M'N 151Wd46.1W5 0.03 ] -001 51.87 041.25 47.18 4242 900 22832 462091 0.07 243.38 4640.36 459835 84033 619.86 3-921.04 5888537.-17W�U.Wl OZ54.893N 151°0646.13744! 0.07 85 0.0] 28.48 BB120 4722 4246 9.76 228.32 4884.23 4945.24 0.1 _ 0.04 18168 259.94 4]-88 4]64.69 4881.88 4722.- 6102] 690.23 619.81 819.78 360821.40 3609218]- 58-537]5OY54.892'N 5868537.]1 151°W'a6.1MV 0454 -2'44 151 °OB'<8139NJ 0.10 _-0.11-0 5 0.- -005 -81.65 11188 881.13 89109 4726 47.30 4250 02.59 9.83 9.90 220.31 228.31 500].53 0.11 243.65 4828.98 4784.98 840.20 819.71 .29 586853).680250.891'44 151°0848141 NJ 0.12 10 0.11 @8.4I BB1.01 4].34 42.58 897 228.31 5088.23 ON 245.45 488].68 4845.66 640.16 619.61 20 588653764OZ54.891"N 151°O6Y6144'W 0.03 3 -0- 3.28 800.91 4].38 42.62 10.04 228.31 5129.88 031 -034 2]333 4949.33 490733 640.14 619AO .89 5886537.-02'54.-1"N 151°W46.1 -W 038 J171.100.11 1 036 4522 M.76 47.43 42.68 10.11 228.32 5191 3 2]1.]8 -1118 4969.18 WAS 819.05 .84 i 586853].6502'54.-t"N 151°0696.1-W 0.05 81 0.05 -2.51 8-.52 47.47 42.71 10.18 22832 5254.98 028 280.86 -]443 5-2A3 610.14 618.)1 .30 586853].64OZ54691'N 151°06'06.1]0"W 0.13 .99 -009 -1].26 8-.17 47.52 42.)8 10.28 228.32 5316.78 _22 030 248.9) 238.55 5136.23 519).88 509023 515504 600.08 -8.94 018.45 __ 61821 .04 .]9 586851.580450.-0"N 586853).450254.889'44 151°O6'48.1P'W - 6 151"O6'<6AWW 0.13 0.185 8 0.10 0.13@015 -19.2a 8-.04 889.78 47.58 4761 42.81 42.65 10.33 10.41 228.32 228.32 5441.13 038 200.02 52-.5] 5218.57 -986 618.- 380919.57 588851.17OZ59.B88'N 151°06'46190"W 0.38 6 0.13 58.24 BE9.43 4766 42.90 10.49 228.32 5-3.68 038 209.31 5323.10 5291.10 -926 61).82 3-819.39 5868536.]9OZ54.882"N 151°0646.195"W 0.10 52 0.02 14.86 8-.03 47.70 42.95 10.57 22832 5508.28 028 22326 5385.70 5343.0 83899 617.62 3-919,19 5866536.51 OY54680"N 151.00'46.201"W 0.24 -98.]8 -021 22.28 808.89 47.7556148 026 205.)1 5446.92 5404.92 63876 61].4] 360919.03 586953628DY54.3P'N 151°0698206"W 0.13 155.- 0.- -28.1 888.42 47- 4308 10.73 228.31 5888.- 0.21 212.26 5508.13 5466.13 -8.51 61735 36091890 5868538.080459.875'44 151.06'46.20904 0.00 11].32 -0.08 10.70 888A 4785 43.11 10.82 228- 5]51.]8 581524 0.11 0.10 214)0 227]1 55]1.22 5830.88 552922 5592.66 -838 63831 61725 61).18 360818.- 360918.7) 5888535.92°0254.874'N 5868535.80°0254.873'N 151°06'46.212"W 151°06'46214'44 016 0.04 119.17 102.11 -0.16 -0.02 3,1 28.50 MOO 8189 47- 47.98 43.17 4322 10.0 10,94 228.29 228.29 5-78535.)8°02'54.12'44 151°06'4621]4) 0.07 22.51 0.00 39.99 8WAS 48.07 4328 1108 22829 59403] 0.18 262.16 159.81 5]17.81 63922 61693 3-916.a8 58885M.74 70ro2 151°06'46221 Y4 0.13 8.08 0.12 15.86 81.66 46.1 4339 11.P 228.29 59)189 0.28 2-.'35 5791.33 5]4933 836.20 61881 300916.38 5868535.74 .M -N 70°M'S4.872'N 151°0696.224^04 0.26 0.- 025 8.91 81.56 48.10 43.1 1121 228.29 6000.00 0.28I 259.35 I 5818.44 I S7P.44 I -8.18 I 618- I %091824 1 5%8535.71 70°0254812'44 151°06'4622804 0.00 0.- 000 0.00 81.05 46.13 <3A0 71.39 228.28 Pro'acBonb TO P9g42 of 2 Sundry Application Plug for Re -drill Wells Work Flow This process is used to identify wells that are suspended for a very short time prior to being re - drilled. Those wells that are not re -drilled immediately are identified every 6 months and assigned a current status of "Suspended." Ste Task Responsible I The initial reviewer will check to ensure that the "Plug for Redrill" box Geologist in the upper left corner of Form 10-403 is checked. If the "Abandon" or "Suspend" boxes are also checked, cross out that erroneous entry and initial it on both copies of the Form 10-403 (AOGCC's and operator's copies). 2 If the "Abandon" box is checked in Box 15 (Well Status after proposed Geologist work) the initial reviewer will cross out that erroneous entry and initial f then it on both copies of the Form 10-403 (AOGCC's and operator's copies). Instead, check the "Suspended" box and initial that change. Drilling Engineer The drilling engineers will serve as quality control for steps 1 and 2. (QC) 3 When the Stat Tech receives a Form 10-403 with a check in the "Plug Stat Tech for Redrill" box, they will enter the Typ_Work code "IPBRD" into the History tab for the well in RBDMS. This code automatically generates a comment in the well history that states "Intent: Plug for Redrill." 4 When the Stat Tech receives any Form 10-407, they Aill check the Stat Tech History tab in RBDMS for the "Intent: Plug for Redrill" code (IPBRD). If present and there is no evidence that a subsequent re -drill has been COMPLETED, the Stat Tech will assign a status of SUSPENDED to the well bore in RBDMS no matter what status is listed on the 10-407. The Stat Tech will also change the status on the 10-407 form to SUSPENDED, and date and initial this change. If the Stat Tech does not see the "Intent: Plug for Redrill" comment or code, they will enter the status listed on the Form 10-407 into RBDMS. 5 When the Form 10-407 for the redrill is received, the Stat Tech will Stat Tech change the original well's status from SUSPENDED to ABANDONED. 6 The first week of every January and July, the Stat Tech and one of the Stat Tech Geologists will check the "Well by Type Work Outstanding" user query Geologist in RBDMS to ensure that all of the Plug for Redrill wells have been handled properly. At this same time, they will also review the list of suspended wells for accuracy. Pepe 1 of 2 Actual Wellpath Geographic Report - includin Position Uncertaint 1gFeb2017M04A) 4rmso-engE ,LLC Z7/TM uke 1. NOM Sbpq P1 Erom tuitional E ,LLC North Slope , M 0'888822 1 ne Horsesarslwrse 41 Nc6c Fox Hrsesel 4mtic Fw HT) HarseslXOe 4fI - Mean See Lwd Hcrseslge 41 -x600 '� X 42.00 X its. (ronel infrogs 2.00k Levafeh E 0.00 n MiNmum curvenxe N 0.00 k agreUO NOM is 1].26 degree¢ Ectal of True NOM .00sla Dec OJ° iMudea ao n Start MD End 000 000 0235.00 586]908.00 380280.00 588]909.00 380315.00 588]8]3.00 70°ar48.%5'N 70°ar48.%SN Jparb.]28N 151 ] .BBB'M19 151ro]03.9BBW 151°0)03.27860 2.00 1.00 20.60 3,00 18,50 218633 59]1..88 MD 216433 59]1.89 6000.00 Positions Uncertainty BHIDOTme Slentlerd) BHI OnTrek 9erldaN) &IM Ddlli S_. .- Model 121/4• I Sury e<19.5'218133a 81e8HIMWDSury s<2263auxx> P c9on t9 Nt IbrpeOOaN IbigpslpeM Homesnoc pl St11[harnmear 9625in Cazi urlate Studoho I6S0 EndMD 22]3.60 Interval 2250.50 Start TVD 1Ift] End TAD 2202.62 Start NIS start EM [it] 000 GrmNIS jff) End EIW -0. HOrsplpe Yt Waltham Tar,st No.. NenuaM1uk 3_COre Point( w-1 TVD if'] 44x2.[0 North [it] 64x.52 East III 386 Grid East [US IN 360925.62 Grid North Us it) 58%541.92 Lafitudis Longitude ]0°0254.93a'N 151"O6'd6.018^N Shape 1 Common, MO hishholion Azimuth TVD TVDSS North Eh't Grid Major Nine, Minor [f,j [h) East [US ft) Grid North h] Latitude L.n,,Ifde DLS T..1ar, Sofa Rate Turn Role Varl Seet Sari Sam Vail Semi Azim Comment, 000 12.9 212.9] 283.98 3%.98 422.92 4)6.86 536.88 800.93 883.20 725.3] ]%.70 950,40 912.10 605.28 1099.00 iWB.96 1181.96 1225.20 129]08 1350.36 103.08 1470.59 1534]9 1598.68 1659.]) 1 ]21.76 1]84.90 1846,46 1905.86 1988.91 202).1 2088.21 2152.)9 2184.33 228924 2326.20 2388.13 2450.45 2513.28. 2575.)) 2838.21 2-00.28 2761.81 000 000 O.n 3.05 3,07 3.38 352 3.8) 3.x8 3.57 3.57 4.03 4.46 1_39 4090 8.19 8.78 7.30 ].]4 8.09 8.57 B.Yd - 8.62 10.30 10.83 12.36 13.12 13.03 1548 15.6 16.6 18.14 18.28 18.25 16.45 1885 15.48 1463 14.]4 15.15 15.60 1828 17.21 180) 3%.0:1 3%.03 355.03 3.78 4.84 Bf4 8.6] 9.22 9.% 1205 11.13 toga 109) _ _092 __ 1106[ 3%.25 35).16 35].22 357.31 35).34 35)21 397.31 3%.30 3%.35 358.39 351.41 36!.84 357.]1 35708 3%.68 357.98 357.62 35/.67 359.08 3%.32 3%.]4 100 4.72 6.82 851 I5.% 2628 36.18 45.18 000 18.50 21235 283.90 3%.82 422.8] 4]681 538.41 600130 882.48 ]20.50 760.Yd 848.35 810)8 9Yd.)5 1096.18 109833 115B.Y1 1221.8] 1283.26 130685 1x07.35 1464.85 152).88 1500.88 1650.51 1]10.95 1772.49 1931.81 1890.00 1950.58 2006.6 2086.ar 212).07 2138.15 2233.)4 2293,88 2354.62 2413.93 2Q6.62 2534.80 2595.57 2654.% 2)13.14 62.00 -23.50 170.96 251.90 31382 380.6) 494.61 498.41 558.30 820,411 662.54 76513 80)35 888.]8 83115 960.18 1054.83 111>.Z! 1179.07 124126 1603.85 1385.011 1422% 1485.88 1508.88 1808.51 1%8.95 1730.48 1]88.91 1818.00 1908.% 1984.40 202403 20850] 2006.15 2191)6 2251.89 2312.82 2371.83 262.62 248290 2%55] 2612.50 28)1.14 Oc0 000 1.33 399 702,4 11.03 14.28 18.12 21.83 25_68 28.46 33.80 38.08 62.T/ 0).83 53.x8 60.)5 611.45 78.>t 85.23 94.38 103.60 112.06 120.03 135.77 14,Lw 161.]4 176.01 180.00 200.99 222.28 239.56 255.81 2]3.% 2]887 334.2] 321.14 337.45 352.92 388.60 385.15 61.11 416.05 430.12 0.00 360280,00 0.00 360280.00 -0.11 350288.91 -O.ar 360280.05 0.22 36026.38 0.58 380280.]8 1.00 360291.26 1.58 390281.92 222 360202.63 2.94 380283.41 3.T2 360284.28 4.53 360295.14 S.b 380299.08 6.28 38028].06 B.Po X029].85 7.23 380208.22 7.01 380288,12 8.83 36028].88 8.25 360207.fi5 5.98 3602B7A2 5A2 _38020].15 <.W 35028886 4,46 36028653 3.% 360288.92 2.8]1 36029529 2.14 360294,8fi 1.55 36028x52 0.97 350284,20 0.34 360283.82 -0.51 38029325 -1.30 360282.]3 -1.97 360282A1 2.88 36020201 5,34 35029188 3.45 36028163 6.15 360291,43 4010 36028110 5.39 360292.60 -1,85 360294112 0.28 Smal 05 3.76 360300.80 8.66 35035].21 18.98 350318.60 31.12 380329.w [US SB6R09.00 ]11102'68.5%'N 151°OT03.W8'WONE 0.00 586]909.00 ]0°ar011.595'N 151°OY05B89W 0.00 5%]910.6 ]0°0248.6011'N 151°0703.99260 p6 5%]91299 70°0248.636'N 151°07ri3.960'W 2.33 586]916.28 ]Og2'48.607'N 151gT03.Po2W O.OB 588)820.00 >0°02'6B.700'N 151.0>03.972W O.b 588]923.28 M°02'08.736'N 151roT0596060 _ 0.35 5807827.08 10°02487/3'N 151°OY03.943W -025 535M358B )0°are88tt'N 151°OT03.925W 588)930.63 )0°ar48.848'N 151°07'60.90660 0.28 5357938,41 ]Og2'a8.8%'N 151 ro]'03.882W 0.09 5807902.51 711°02'0892fi'N 151 g703.B5BW O.Td 586846.89-0g2A89>0'N 151°OT056W60 070 586]85160 ]0.OT49.016'N 151°OT03.90BW _q.]0 50956.89 70°ar49.0%'N 151-U ----- 0.82 5%]962]3 ]0°OY49.125"N 151°%'WJ81NJ 2.33 586]969.61 7pg2'49.183"N 151ro7R3,-8]19 101 58678]].31 8g2'49.26a"N i51ro]03.]PoW 0.86 5867985.% ]0°ar'49.350'N 151"0)U3.8J9N/ W70 SM7986.10 70°02'49.433'N 151°OT03.82059 0.07 5888003.26 70°0248.523-N 151°,039MV 076 -NXIS012.88 ]0°024961fi•N 151°OT03.B46YV- 0.26 58fiBJ21.85 ]p0Y48.706N 151°OT03.B61W 1S] SBfi6032,94 )M02'48815'N isiT 3.9a1W 1.09 5886044.68 >0°OT49.931N 151°MW.9PoW 1.03 5888057.01 ]0°02'SD.OWN 151gY03.927V 2.36 58890)007 70°ar'S0.186'N 151°OT03.91860 Y.23 58880&.0.5 ]0'ar50.326'N 151°orar.alW 0.11 SBfi8DPo.86 )O°p2'SOA64Y4 151°0703.9860 07) 535811595 )0°02'50.811T1151°0T04.004W 3.38 5880131.23 70ro2'S0.)91•14 151 q>04.028W 1,57 586814].50 70°M'S0A61•N 151'OT04.048W OA8 5888184.95 -0°0251.112'N 151°0700.08660 0.18 5898182.% -0°oZ51.28)'N 151°070408560 0.17 5858195.87 70"WS1.318•N 151°0704.08860 1,07 5868213.2) )0°0251.588"N 151q]'01.10aW 0.32 5868230.14 70g2'51154N 15187' 110M 1.13 5888246.43 8ro251, WN 151°0)466.011]60 208 586g261.07 8°02'S2.OB8"N 151ro704iNiff 0111 5SES271.as-0°0252224•N 151°0T039B1W 1001 58682113.99 70°0252.383'N 151°OT03.B81W 506 5858108.83 JO°0252540'N 151°OT03.705W 4,68 5%8324.60 riY0252.B8TN 151°07'03.44260 5.00 5358338.44 7002'52.825"N 151 °OT03.OB360 464 000 49) 11.85 07.38 1556 48,3) 1].]8 1T3A4 -90,46 -1.31 -0.10 131.35 -31.82 .23J1 1.08 3.85 230 .2.31 5.42 ---10)8 � �t405 1)43 Bar 3,93 1)0.08 48.10 6.50 25.33 4%.117 8.% 95.42 140.1) 1%.10 121,82 133.45 8.08 %.% ]8.81 11].60 71.46 )882 78.88 000 0.00 0.40 2,82 0.03 0.411 002,4 0.2a -0.31 0.14 000 0.)3 0.70 0021 2.06 0.93 O.% 0.>0 0.5- 0.70 O.fi6 1.% 1.08 0.98 2.34 1.23 -0.14 070 3.37 1.43 -0.45 0.19 -0.02 -0.07 -0.30 4% -1.31 0.18 0.85 012 062 1.35 tA0 0.00 0.00 3.% 10.]8 1.42 2.24 4.31 1.21 058 597 -1.18 -0.26 A.ar -551 SAb 3.48 0.13 0.35 -0.18 -0.21 0.16 A.78 -1.68 1.83 1.60 0.3- 0.11 .1.03 .1.00 2.311 -0.82 0.08 0.81 225 0.42 3.82 S.B2 3.10 3.01 11.23 1].05 16.10 14.83 0.00 0.00 0.88 2.88 SAO am 10,45 16.12 17.31 20.51 237) 27.28 31.12 35.08 3922 43.74 48.53 %.79 58,46 8831 ]1,58_ 7a.0n 24,28 91.85 98.50 107.88 11).28 12].14 138.)4 148.82 1%.76 1]0.03 181.97 180.28 186.53 215.T! 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Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate Q Repair Well ❑ Operati s shutdown Li Suspend El Perforate ❑✓ Other Stimulate E] Pull Tubing E-]Changeroved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: ❑ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill umber: Armstrong Energy, LLC Exploratory Development ❑ Stratigraphic ❑ Service ❑ 216-133 , 3. Address: 6. API Nu er: 510 L Street, Suite 310, Anchorage, Alaska 99501 50-10 0751-00-00 . 7. If perforating: and Number: What Regulation or Conservation Order governs well spacing in this pool? NA JvHorE Will planned perforations require a spacing exception? Yes ❑ No ❑✓ @Shoe #1 + 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL 392048 1 Wildcat 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP ( sl . Plugs (MD): Junk (MD): Casing Length Size MDN Burst Collapse Structural Conductor 1181 161 11 118 2980 1410 Surface 2214 95/81 221 2185 7930 6620 Intermediate Production Liner 36001 7 5 8 5539 7240 5410 Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Siz Tubing Grade: Tubing MD (ft): 4800-4830' 4667'- 4697' 3 1/2" L80 4793' Packers and SSSV Type: SLB -3 1/2" TRSV safety valv Paoky rs and SV MD (ft) and TVD (ft): Packer 4785' MD (4652' TVD) HAL 3 1/2" PHIL retreivable SSSV 2400 -MD (2324 -TVD) 12. Attachments: Proposal Summary ✓ Wellbore s1 . W II Class after proposed work: Detailed Operations Program ❑� BOP Sketch oratory ❑� Stratigraphic ❑ Development ❑ Service ❑ 14. Estimated Date for 1/ 17 15. ell Status after proposed work: Commencing Operations: OIL ❑✓ WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GiNJ ❑ Op Shutdown ❑ Abandoned Q 17. 1 hereby certify that the foregoing is true and th procedure approved Craig Rang 907-252-6799 herein will not be deviated from without prior writ[ n approval. Contact Email crana@allamericanoilfield.com Printed Name Craig Rang Title Consulting Completions and Testing Engineer for Armstrong Energy, LLC Signature 907-252- 2/2/2017 6799 COMMISSION USE ONLY ission that a representative may witness Sundry Number: `� Conditions of app/Req'd? 31 -- W, Plug Integrity ❑ Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Post Initial Injectis ❑ Nol.�Spacing Exceptios ❑ No ❑ Subsequent Form Required: / 0 — y U 1 RMOS L,�- FF9 1 5 2017 APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Submit Form and Form 10-403 Revised 11/2015 0 Mr G d appli¢atjpn 1: lid for 12 months from the date of approval. Attachments in Duplicate RECEIVE® FEB 0 3 2011 A AOGCC ARMSTRONG Fnergm LLC February 2, 2017 Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 71h Avenue, Suite 100 Anchorage, AK 99501 RE: Application for Sundry Approvals Armstrong Energy, LLC Horseshoe #1 (PTD 216-133) Sec 15 8n 4e UM Wildcat North Slope, Alaska Dear Ms. Foerster, Armstrong Energy, LLC (AE)) hereby applies for a Sundry permit to complete and test the well permitted by PTD 216-133. Armstrong at this time has set the conductor pipe at 118' MD, drilled out for the surface pipe, set 9 5/8" surface pipe at 2214" MD, nippled up BOP's and following the BOP test should be ready to drill out for the production section this weekend. Please find attached information as required by 20 AAC 25.283 for your review. Pertinent information attached to this application includes the following: • Form 10-403 Application for Sundry Permit • Completions Procedure Summary • AS Built Surface Location Plat for PTD 216-133 • Stakeholder Notification Affidavit • Intersecting well bore identification • Offset water wells plat • Proposed Wellbore Diagram • Casing Dimensions and Strengths • Cementing Program Summary • Pressure Testing Calculations and Summary • Wellhead diagram and Test Tree • Target Fracture and Confining Zone Information Proposed Fracture Stimulation Program with dimensions • Proposed Chemical Additives for Fracture Stimulation Program • Anticipated Fracture Stimulation Pressures 510 L Street, Suite 310 - Anchorage, AK 99501 p907.375.6900 • Pressure Relief Valves o Treating Line o Tubing Annulus • Post Treatment Clean up and Reporting If there are any questions and/or any additional information desired, please contact me at (337) 849-5345 or Pete Berga at (573) 201-3861. Respectfully Armstrong Energy, LLC Craig L. Rang Armstrong Completions and Testing Engineer Enclosures Cc: Edward Teng — Armstrong VP and Project Manager Colby VanDenburg— Armstrong Project G&G Nate C. Lowe — Armstrong Land Manager Cindy Bailey — Armstrong Public Affairs Manager Robert Britch — Senior Advisor Pete Dickinson — All American — Armstrong Drilling Manager Pete Berge - All American — Armstrong Drilling Superintendent Stephen Hannigan — Sierra Hamilton Petroleum Engineers for Armstrong Energy 510 L Street, Suite 310 - Anchorage, AK 99501 p907.375.6900 ARMSTRONG Energy, LLC 10-403 Application for Sundry Approvals Armstrong Energy, LLC — Horseshoe #1 510 L Street p.907-375-6900 February 1, 2017 Suite 310 E 907-375-6930 Edward Teng Anchorage, Alaska 99501 <edteng@armstrongoilandgas.com> Table of Contents 1. Completion Overview 2. Completion Procedure 3. Well Information a. Basic Well Data 4. Stakeholder Notification Affidavit a. Offset Land owner within '/2 mile b. Offset Operators within '/2 mile 5. Offset Water Well and Fresh Water Aquifer Identification G. Casing and Cementing Information 7. Pressure Test Information 8. Wellbore, Wellhead and Test Tree Information 9. Target Fracture and Confining Zone Information 10. Geologic Fault Information 11. Proposed Hydraulic Fracturing Program 12. Pressure Relief Valves 13. Post Treatment Clean-up and Reporting Completions Overview The drilling plan is to drill one wellbore with the potential for sidetracking after test. The Horseshoe #1 is essentially vertical from surface to total depth. The plan is to drill down to the core point just above the Nanushuk formation at roughly 4400 foot MD. The coring plan is to cut 5 or 6 — 60 foot cores, pick up LWD and drill out to TD, run Schlumberger logs, run 7 inch liner, cement liner, evaluate cement, perforate using 3 '/2" tubing work string, evaluate the fluid inflow and pressure, fracture stimulate the perforated interval if needed clean out tubing using N2 lift to clean out the well if needed and then flow well back to tanks. Following the test, kill the well and pull the 3 '/a" tubing test string. Run in the hole, set a cement retainer and abandon the well. Pull out of hole and move up to whipstock located above liner hanger. r 10-403 APPLICATION FOR SUNDRY APPROVALS - FEBRUARY 2017 Completions Procedure r ` ♦ r ♦ ♦ r �.. r 1 1 1 1 I 91 ar \ / � 1 ! 1 1 Sroo 1 \ 1 A� ICEROADENT&.1-NCE —1 WOOL- I 1. While coring completion interval, prepare 40'x 60' containment on East side of rig adjacent to lake. See ice pad and placement schematic above. The current frac design calls for 966 BBL of frac fluid which will require 3 frac tanks. Containment - Containment for 400 BBI, tank = 110% x 400 BBL. = 440 BBL, = 440 BBL x 5.61458333 cubic ft / BBL= 2,470 cubic feet 40 feet x 60 feet x I ft = 2400 cubic feet 12 inches plus 6 inches = 18 inch berms 2. Following completion of the full cores, pick up LWD tools and bottom hole assembly to drill to TD 3. Clean out hole and rig up Schlumberger for open hole logging program. Estimated logging time is several days with five different logging runs into the hole 4. While running open hole logs prepare containment for tank farm as depicted below. Setting containment and tanks is estimated to take 10 days. Containment will be split into two sections each containing half of the 32 tanks. The split will occur from West to East as depicted below. 10-403 APPLICATION FOR SUNDRY APPROVALS - FEBRUARY 2017 10 L 0000 0000 X100 0000 '00 0 0 F--- 0000�-� 83 feet plus 2 feet to make berm 87 feet plus 2 feet to make berm Containment for 400 88L tank = 110% x 400 BBL = 440 BBL = 440 BBL x 5.61458333 cubic ft / BBL= 2,470 cubic feet 83 feet x 87 feet x .34 fi24555 cubic feet .34 ft x 12 inches / fT = 4 inches plus 6 inches = 12 inch berms This scenario would take two containments 90 feet x 85 feet. B_grming timbers would need to be 12 inch thickness. 5. While running open hole logs prepare containment for Halliburton fracture stimulation equipment - 100'x 140'. 6. Simultaneously prepare containment for PTS well test equipment 96' x 77' directly south of the flare stack placement - 40'x 40' 7. Prep 7" production liner , shoe track and Baker liner hanger 8. Prep hole to run 7" production liner. 9. Rig down Schlumberger wireline crew 10. Rig up Weatherford casing crews 11. Rig up Halliburton cementing crew 12. Run 7 " production liner with Baker liner hanger and packer. 13. Rig down Weatherford 14. Cement production finer. Displace cement with 3% KCL above top plug. Volume of 3 % KCL is equal to volume of 7 inch liner followed by drilling mud. The drilling mud will be used to displace cement on top of liner hanger once the liner hanger has been set and the pipe is released from the liner setting tools. 15. Wait on cement- rig down cementers -f 16. Rig up frac crew starting with frac tanks and begin filling with frac fluid. Rig up time for Halliburton frac crew is 1 day. Little Red Services will heat frac fluid which is estimated to take one day to rig up and heat. Current frac design will use 966 BBL of salt water which will require 4 truck loads of water — estimated one day depending on weather. 17. Trip in hole to clean out to top of shoe track and dress finer hanger. May take several pipe trips. 18. Displace fluid in hole with 3% filtered KCL water. Percentage of KCL used may change based upon lab testing of effect of completion fluids on clays in formation 10-403 APPLICATION FOR SUNDRY APPROVALS - FEBRUARY 2017 19. Trip out of hole while rigging up Wireline unit to run Cement Bond Log with Gamma Ray correlation to open hole logs 20. Rig up Cod and N2 units on Southwest end of rig. 'fool shed may have to be removed to place coil unit. StlO 881 FIOWBACK TANK 50 88t If protect tank 400 681. Sea waterfoamers Choke Manifold .-01 ctk'ck z*.* :16 95K Injector L] check so VMW 21. Rig up PTS well test equipment on containment south of flare 96'x 77' 22. Run CBL / GR log. Management to review cement evaluation log. If cement is good, continue to next step. If concerns, apply 500# pressure and relog cement bond log I SF,-Aj P r -/j` 4% 4-,(,e-(- 23. ¢',LIGE23. Rig down cggs�ed-hole wireline truck. Keep truck in position to position test packer U 17 , 24. Norif Ey P.4of intent to fracture stimulate well. 48 hours advance notice required prior to fracture stimulation. L1 HES representative on site can help with notification. ��T h5-r—Q,.- raj 25. Prep well to run 3 1/2" tubing string, l--lalliburton TCP perforating guns, Halliburton retriedable test packer with "XN" profile below packer, Halliburton ROC surface pressure readout mandrel with gauges, "X" profile above ROC gauges, Subsurface Safety Valve and Gas Lift Mandrel with dummy valve installed. Note: control lines and data lines willbe attached to external side of tubing back to surface. 10-403 APPLICATION FOR SUNDRY APPROVALS - FEBRUARY 2017 HAL, _ ATC]N PaEwaEn con; Am Uow EEG PROJECT WELL naFiek,oe Pn +zm'aa r py }a? 9.1 Lm EUE3W { 1I` u .i•R ^Epp„ ... n f'. �1 •i' CvhW Vv .-N' yi Sry . M1.Y. i -•.Viy tL':..: .{ .i:Na.i �. nrM1 Nbige j_ LSP. S SPF, IBIX. WIk1101�I11 i' ✓,, pemT [kx,i +qn Mtin.) I 0.13.6m) to tplK) MIM.) 1 Y ,yy' a i.s t�^a!G 2997 4500 TW 29 1 ai t CCS; + 3-T Y 3 9WlB Y6TT Ik61ev6p5SSi4 e'Uf Caned tae * 2 m2 :lF'.'?T.�'Y 3 9Ui }i7261Te 2613 F _01 X952 4.5&0 GCG 6.500 T&: P.p.9t :.Y32 1500 EL) �: � i 8EB }TTGM1Yk14nle'31WfYi1R _ 1.15 1'yr9 12 d.5C0 F :]t 2592 6.500 to) GU) T 2932 6.500 GO) r r-7 y6nts 7.•2' T]:ara 2'9?2 4" TPJ 2432 6,SE0 Ge. a ink 31 P6cYl ' , w 6.0; ,e 6onts }t'2'1'4tlrc ?592 " 4.;L0 o tEJ u JOct}t:Z 2952 4 K GOC a T. 275- WGo LWOK Nwe r<' NbGYPkM I 2T50 bat3f:Z ?.93? 1 6.5(4 GD.' f' .ee153-t' 2. 4 5C rW Pup.grt3yt'r 243%22 a.500 GO] .qR 3 1 1 2.X+2 1 4.S 6.03 : "a }1:7 Tuts'e 2.992 1 a 500 I 30.03 'BW OD+-+:6't0r stdWYn 26. Rig up Little Red Services to heat frac fluid. Begin heating 27. Run test string. Fill tubing while going in hole. ��/ truck c ' - 28. Rig up cased -hole wireline tck to position test packer � Jt N��.'Il !j . ;W` 29 3XHalliburton retrievable test packer. (attach packer setting procedure here) kJ, I /oa 30. Rig down wireline truck. Keep truck in position for slickline work '5 k 31. Lfang off tubing with TC2 thread in MB 230 wellhead. Note: tubing must be hung off using the 4 ''/2" tubing p hanger with crossover back to 3 1/2" 9.3# 1,80 TC II tubing string. The 4 1/2 " tubing hanger makes the >�432. wellhead capable of handling 10,000# pressures for conducting a fracture stimulation job. Any questions or issues, contact GE —Vetco. V r st tubing to 4400 psi and hold for 15 minutes, '� c tS;D AAC Install GE — Vetco well test tree onto wellhead and pre sure test same to 6600 psi 33. Drop bar to perforate 30 foot interval (4600 — 4630' MD estimated) and drop guns I" 34. Rig up wireline truck onto test tree with gauge ring and full lubricator C'�4,^� -� 35. pressure test lubricator to 1500 psi 36. Run gauge ring ran down through tubing tail and verify that guns have gone off and dropped. Note: I-lallibmton will supply the TCP system and gun drop. The gun drop sub should be 3'/z" which will give us the same ID's as the tubing. Verify that the gun drop is 3 '/2" or if it is not available, then the 2 7/8" gun drop ID. Tubing ID for 3'/2" 9.2# L-80 tubing is 2.992" with a drift Ill of 2.867". The "XN" profile below the packer has an internal ID of 2.75" 10-403 APPLICATION FOR SUNDRY APPROVALS - FEBRUARY 2017 6 37. Run pressure bomb through tubing down to perforations noting fluid level and monitoring wellhead pressure initially at time of perforations and throughout logging run. 38. POOH, verify data and rig down. Note: Compare data collected on pressure and temperatures to Halliburton ROC system surface pressure read out. If data does not duplicate Halliburton data, determine discrepancy. Note: if sufficient wellhead pressure and fluid level is at surface, fracture stimulation, cod cleanout and jetting may. not be necessary. If such, go to step 61. Keep truck in position for additional work 39. Rig up ProTechnics for Radioactive tracer in Frac - Contact Alex Darnley -832-444-8711 40.- Rig up frac equipment to wellhead; �( 41. Rig up PTS flowback equipment to wellhead flowline P J 42. Pressure test flowlines to 1 '/P times anticipated wellhead pressure from wellhead to inlet of test vessel. 43. Apply 2000# to annulus of 3 1/2" tubing x 7" production casing. Note: the pressure applied to production 44. casing may change based upon tubing movement calculations and fracture design pressures. Frac interval using RA tracer to mark breakdown, pad and proppant e 1/ 45. Prepare well for the well test while rigging down Halliburton frac crew rte" 46. Rig up Cased-hole slickline truck 47. Make gauge ring run through tubing down thru tubing tail and across fracture stimulated area noting fluid level while monitoring wellhead pressures. 48. Remove dummy valve from GLM 49. Prep N2 unit to pump N2 50. Install orifice valve in GLM - largest valve available for this mandrel 51. Run RA tracer log - Spectrascan memory log noting fluid level and wellhead pressure. Note: if sufficient wellhead pressure and fluid level is at surface, coil cleanout and jetting may not be necessary. If such, go to step 61. 52. Rig down slickline truck - keep truck in position 53. Pump N2 down annulus of tubing displacing fluid through GLM back to surface inside tubing. Displace enough fluid to get N2 to GLTNI 54. Rig up coil unit onto test tree 55. Perforin coil unit BOP TEST 56. clean out tubing down through test packer tail pipe and lift using N2 flowing back through PTS well test unit 57. Pull Coil unit out of hole. Rack back injector head. 58. Rig up slickline truck, memory gauges and full lubricator. Note: this step will be evaluated based upon data being transmitted from Halbburton ROC system for surface pressure readout and pressure measurements collected in step 38. If pressures are identical, this step can be eliminated. Go to step 61 59. Pressure test lubricator 60. Set memory gauges in tubing above test packer 61. Begin flowback test - approx. 8 hours clean up, 8 hours shut-in, 4 point step rate test. Note: once well has cleaned up and oil begins flowing to tanks, the tanks must only be filled from the top and must have continuous surveillance from the top of tank for levels. No more than 80% of the tank volume may be used per tank. Protocols must be followed for filling one tank at a time and switching from one tank to the next tank. 62. Monitor test volumes/ pressures / rates every 15 minutes recording data 63. Begin fluid sample collection. Collect fluid samples every 24 hours of test beginning when wells appears to have cleaned up. Clean oil samples and collection protocols must be followed for the oil samples. Water production is expected to be minuml, however daily water samples from the bottom of the separator vessel is requested with documented times and dates recorded. 64. Immediately begin fluid disposal after tanks have been measured and recorded when full 65. Upon completion of successful test, shut well in and prepare for 100 hour pressure build up test a. Shut in will be accomplished by using shckhne Downhole Shut In Tool. Memory gauges will be hung below shut in tool for redundancy if ROC gauges fail. b. Shut in Tool must be placed above Halliburton Roc surface pressure read out tool in "X" profile. "X" profile should have 2.813" ID c. Shut in period will be 100 hours. Set clock for 100 hour shut in period before differential pressures are equalized. d. Clock will equalize pressures after 100 hours. If clock fails, make sure we have an equalizing prong above downhole shut-in tool to manually equalize pressure above tool. 10-403 APPLICATION FOR SUNDRY APPROVALS - FEBRUARY 2017 66. Rig up slickline unit and install downhole shut in tool into "R"profile above Halliburton ROC surface pressure read out mandrel with gauges. 67. rig down well tester, coil and N2 68. At end of 100 hour shut in pressure build up period, rig up slickline unit and pull downhole shut in tool with memory gauges suspended below. Once back to the surface, verify data and compare to ROC surface pressure read out. 69. Rig down slickline unit but keep unit in place for L -line work 70. Kill well by bullheading kill fluid down tubing test string. 71. Install BPV in tubing string 72. Remove test tree. 73. Nipple up BOP'S and test same 74. Pull BPC 75. Release packer and pull tubing test string 76. Rig up Halliburton cementing unit 77. Using rig work string run into hole with cement retainer 78. Set cement retainer 79. Rig up cementing equipment 80. Pump cement down tubing, bullhead cement into perforations and spot cement below retainer in 7 inch liner. 81. Pull out of retainer and spot cement plug on top of retainer. POOH 82. Lay down cementing work string 83. Proceed with directional wellbore. 10-403 APPLICATION FOR SUNDRY APPROVALS - FEBRUARY 2017 Well Information "tC♦: t�lY V4r STATE Ot AL&<KA ALARA OI AhC)GA5 COb4EN'/A• JM1 G]NGI$]UV APFUCAT10N FUR SUNUNY AYYNUVAtS .fn V.vnrr lW.xr. V.9eMvnvr"I lain Aenw 1. •r W. M.f 4nrwr. V•Aln�/ P.91:. 4r).. .� >Mvel � Mwn ryl`NY AWf •r Qla��ryyyy la Y.•wA� NM WM :lYr'a O-.F� 4mWR JENI��C CyrN'h JnrMrar L :lbl)• vu lwnrr vrRVe. � Sw:e l.P nnb• : Nrw 5Nr h4.rcroaY.y'W� a •Afv>SIY p)Jt 1 . AYRp Mllan.Mlurb- Wla'MTrmaCnm�vb Cw`l Fnn rl aafY�nrV#r M IIRitlIYV Y'. Wl WrrwlplAlM rwt.n.paAn3alN� 1M bi• _ I N4n"1 ilpw.n �l.rn YiCrrl 14iM4rNn wwo Galnl l�A .. frr r m (lar m+M Wlc...� ctrl aV: 2N! 9Nf mam wRr m, afD A. .pV tw .wr: una ww N.---• N _—_ P.rw...i as4rw _. — .m�sar h. Iro o•.r •t Pa...r... c.rR�:...m .1 «.I..I R.a.a. _ +a .. wr... Ti Prwspam••^vT• � lY 3cr. _" csa:n Y. =l^l:ww: � h.rwnn i_ o `7 �—Vt a��YQaRYn _ I NCR(. i1 Lyrpn i 1 'M v'. IL 4tfM fI Ws4 _� ✓YMVUw Gu. 14.i J garnn• r T Tian Jr nY CS M.Mrnm rKn pr:. ran Wvw fM/w�.m+MTtl�MitY> �inM ry1P(fN+I Narcrgaa ..r9mrtEpaF r;. «.a•RIEroq ,IE 'Nir: i.. �:=fi„_�aa-- mnwmn �w .rt•.,nar C9rrbW M U4f a'r'ts _..__ 4Muu n A 1 • .m. r r•1•r1yV.•' 4I �•lMY � MnIK� va»rsa r.yGnliw -� :attlm OwRw >ti ` ISTJ nM'Ortw.y]4gC. .� CG:...i 4/Jl R•�•:} iPr4 E.xpR +ru.-,• ..J wr sn.o...l«..r na+.c. 14-Vu7 � 7 lmY.la �/ / oawx+:wn 'K LPw'g9Gn 4w �/ r.... rorl nr.a .rr. •. � Mvuassn� V�+l_I�+l `��rTPa+. �rR.�..c.l�r. 10-403 APPLICATION FOR SUNDRY APPROVALS - FEBRUARY 2017 9 Stakeholder Notification Affidavit There are no offset land owners within one half mile of the wellbore that is being proposed to be fracture stimulated. The affidavit required by state regulation 20 AAC 25.283 Iydraulic Fracturing part a 1 is attached. AFFIDAVIT OF NOTIFICATION Edward Y. Teng as Vice President of Engineering and Operations for Armstrong Energy, LLC ("Arms(rong"), being of lawful age and duly sworn, upon his oath deposes and states that Armstrong has made noticS ,mgFireh-Kjrsuant to 20 AAC 25.283. Further aunt sayeth not. Edward Y. Teng UNITED STATES OF AMERICA )SS. STATE OF _. ) THIS CERTIFIES that on the 5 day of February, 2017, before me appeared Edward Y. 7'eng known to me to be the person who executed this affidavit and acknowledged vol.rntarily signing it. Not y Publi 7 My CoEmitsionexpi•es: 10-403 APPLICATION FOR SUNDRY APPROVALS - FEBRUARY 2017 I P Mi SEO ICE P/U f WtE 61 �U jP ( a`11,07 �.-�.' a LMYEYORt CNNbR Mi SEO ICE P/U WE 61 jP 10-403 APPLICATION FOR SUNDRY APPROVALS - FEBRUARY 2017 /RCT I: �^IRN 1I CGRCMq.VBi/MfULOGl�01! rMiW.mE• . .Ai . . xzrynRax(rtro HORSESHOE 1 1 1 I rlrversxn-En ; I Native allotment 9114 is in the adjacent section 16; more than'/4 mile to the west and is owned by the State of Alaska and managed by DNR. Armstrong Oil and Gas is lessee of record for that parcel. �here are no well penetrations in this township and range T8n, Roe AA093r?'), 2011-N-( AE 67,5 REPSOL 25, GMT 7.5 $35.17, 212812022 411-0614 100 11-0613 $20.1 _ 11/3i/ 2 06 -SA NSAF1-06156 39205 ADL392055 6.25 0.E 56.25 NS 11-06 A NSA11-06166 REPSOL25 RFP5DL25 AE 1 0 AF F00 �AtT i8 75 GA7i 18.75 $25.E $27.6 ;2877.;1/30! 2877,IU30p. 11/30/2022 11/30/2022) %DL392052 ADL392053 A L392 S6 AD13920,7 JSA21.0515C NSA 11.0615D N 11-0 16C NSA11-0615() 100 AE 100 AF. AE i00 130.1$37.6 530.1` f 537 6 113412�4�? ..11133 202 1113017n22 1113012W? There are no well penetrations within the '/z mile radius of the proposed wellbore that may be fracture stimulated; nor any within the same township and range as seen on the screenshot above. 10-403 APPLICATION FOR SUNDRY APPROVALS - FEBRUARY 2017 12 Offset Water Wells There are no water wells located in this area due to the permafrost. The DNR maintains on their website a mapping program called Wellsite Logging T ool (Welts) where water well drilling contractor are required to register their water wells drilled. The attached search below is copied from that website. According to 20 AAC 25.283. Hydraulic Fracturing regulations section a part 4; a plan for baseline water sampling of water wells before hydraulic fracturing must be started. Since there are no water wells, this section is not applicable at this time for this area. 10-403 APPLICAIION FOR SUNDRY APPROVALS - FEBRUARY 2017 13 Casing and Cementing Information The Well Bore Diagram below gives the proposed bit sizes and casing sizes for the Horseshoe #I Arm &r j RDNG..1.. < IID..•.',... rrr w, u..:nlnw ,J 6I N311wun.n ....ev ••••<Dt ,RRf nn.n y. L.b.xQ 4,.Nt4. L'A G+lyn LLC Nl ffr W.Y • 19' ;� •u wr YYf ur»r.. uu 10-403 APPLICATION fOR Si1NDI:1Y APPROVALS - F_h;tUIVRY 2017 c .dsr Lahr, w, u..:nlnw ,J 6I N311wun.n ....ev ••••<Dt ,RRf nn.n y. L.b.xQ 4,.Nt4. L'A G+lyn LLC Nl ffr W.Y • 19' ;� •u wr YYf ur»r.. uu 10-403 APPLICATION fOR Si1NDI:1Y APPROVALS - F_h;tUIVRY 2017 c The proposed tubulars are as follows: Casing Length Size MD ND Burst Collapse Coractor 118 16 118 118 2980 1410 Surface 2318 95,8 2318 2242 7930 6620 Lsler 3400 7 5718 5539 8600 5870 Tubng 5718 312 5718 5539 14160 10,530 The proposed cementing summary in the Drilling Permit are as follows: 4.18 aeou•memons of i)AAC 25 005iP(6) An aypfi[mlen fere Permh ra Ddu must na.'ro-s orwivew ofor"lmw(ng Irvm; eneptforan from olmevvn fle w:ro one tlenttfl.0 in me vPP&vovn: (61ocompereprppmetl r.rlgen: cemendnppcogrom es eepo'rtr'Z0AAC25.030, mtivtle¢np•,;on ofar,i oraf tree, pe brvtetl lmrq...reel roee,ntrruro' Xe Sec 4.9 for c"" ProVern. Cement bebw Cementing Summary Sr_e 16 Seung Depth 116 fl Annular Volum (?to Washout. 1:419 w ft Leat Slum Densly 0 ppg YlaH 0 a sI. No 9a SDeuf"Ws 2 Desred Top of Cement 0 Tild Shim Densey. 15,6 Dog Yell 096 cu. alsx No. Sxs: J10 Specircabons: G prom 6 Hour Compressive Strength of Tet Sbry 500- psi 10181 Volume 24].6 cu N DiNred Top v l Cement 0 P. 310 Surface Sze 9625 strong Depth 2342 0 Annular Volum (No Washtub 944,9 Cu R Lead Shury Density it Dog y,ed 4.is C. ft isx Np. sxs = speclrcatons P_renu ostl S,cewpps Desaed Tap a1 Cepen1 0 ft Ta851urtir Dorsey Ise pp9 Yil 1.16 Cu III" 7s—., t0J0 SCecif"Jurs prem'G' nfi Speoatons: Droll 8Hour Coripressne Strength of Tail Slurry. 1000- par Total Volt. 49]1.3 Cu. fl. Vobme. Delred T000f Cement 1042 0 S HDulomp�uength of Tail Sony 1000- psi 1940 n. Prop. Casing I Sm. 7 Senng Depth8219 If Annular Vol (No Washout) 108142 Cu If Lead Slurry Densty: 12 Dog YeW 148 Cu a isx No. 9n'. 260 S,cewpps Tyge_r Desred Top of Cement 0 ft Tail W, Densty 14 DID Yen 1526 No. S. 500 Cu.a /Sx�r� nfi Speoatons: Droll ment w Deafer ry of Ce4000 a Total Vobme. � � orqal.' ✓� it/rr, S HDulomp�uength of Tail Sony 1000- psi The sixteen inch conductor pipe was set in the cellar using normal procedures and techniques. Cement was placed inside the conductor to a depth of 4 feet and around the conductor and up into the cellar to a depth of 4 feet from the bottom of the cellar. The 9 5/8" Surface casing string has been run to a depth of 2214' MD and the cementing operations went smoothly. The daily job report dated 2-2-2017 reported that 40 BBL of 10.5 ppg spacer was pumped, followed by 216 BBL of 10.5 ppg lead cement (Permafrost L) and tailed in with 48.4 BBL of 15.8 ppg Swiftcem tail slurry. The top wiping plug latched, was bumped and the float held. The current rig status is to wait on cement, nipple down the diverter, nipple up the BOP stack, change out the spud mud to the mineral oil based mud, BOP test and get ready to drill out early next week. 10-403 APPLICATION FOR SUNDRY APPROVALS - FEBRUARY 2017 15 Pressure Test Information + The maximum anticipated surface treating pressure (MASP) of theormatio is 6000#. Prior to the fracture stimulation treatment, 2000# will be applied at the surface to the annulus of the tubing string. The differential pressure between the two is 4000#. Regulation 20 AAC 25.283 Hydraulic Fracturing - requires in section "a" part 7; pressure test plans. In addition, part "c" section 2 of the same regulation requires that when hydraulic fracturing is done through a fracturing string, the fracturing string must be tested to not less than 110 % of the maximum anticipated pressure differential to which the fracturing string may be subjected. Therefore, the 3 1/2" 9.3# L80 tubing string will be tested to 4400# surface pressure for a 15 minute time span. J Zone I DFIT Treatment Plot 1.; '10 1 ,:-10 1? <o 14:(N) 14:10 R. 700 200 100 10-403 APPLICATION FOR SUNDRY APPROVALS - FEBRUARY 2017 16 rrent)ng Pressure (p,ig) A " .\111111111~ Pre„111'c (psi) A MuM Rate (bpm) B llurr% Proppunt Conc (Ilugal) C 1 BFI Proppanl Cow: (ilvgal) C Actual Bottonthole Pr (psi) A A 11 1 Actual Bottomhole "remp (on E c 1.; '10 1 ,:-10 1? <o 14:(N) 14:10 R. 700 200 100 10-403 APPLICATION FOR SUNDRY APPROVALS - FEBRUARY 2017 16 Wellbore, Wellhead and Test Tree Information The wellbore and tubulars have been documented above. The wellhead and Test Tree are as follows: ® GE an ISM 3PI, pWf . 10-403 APPLICATION FOR SUNDRY APPROVALS — FFBRUARY 2017 17 '+'.S+S'i.'+�t; t'S111 ft?N'J C:u C�Q.aIYi Al+itY /.:e�gy,'GIMVW))Wcv lmaa, r: t4i`)I>]r•p'aia .� NN !FJ ...�, SIN RM 'Ma.VtrtC.v,: �nn:+.M Wt?;C. 10-403 APPLICATION FOR SUNDRY APPROVALS — FFBRUARY 2017 17 aGE Oil & Gas r..,...., », .,. .:::1'."..K, .......... ......_> ':�.... ARMSTRONG HORSESHOE #1 4-V 16" 10M Rental Frac Tree Assemhiy. With 1 1 41!16' tOM D Win`' Serilon caev.N CR 26JAN 17 hP°"•'` KN 26JAN17 f.Y. Rt*iR'�C'R+i+ 0wnmc,m. 10012316 The test tree as seen above is rated to 10K psi. The wellhead seen in the schematic above is the MB230 rated at 5K psi. However, when using the 4'/2' tubing hanger and then crossing over to the 31h inch tubing below the wellhead, the rating is increased to 1 O due to the 4'/2" tubing hanger pressure rating of 10K psi. The lowest rating of all the components in the test string is 10K psi. The test tree with be pressure tested to 6600 # upon installation. 10-403 APPLICATION FOR SUNDRY APPROVALS - FEBRUARY 2017 18 Target Fracture and Confining Zone Information Lithologic description: The target reservoir and overlying confining zone are within the Nanushak Formation. The Nanushuk consists of a series of shallow marine deltaic deposits comprised of fine-grained sandstones, siltstones, and shale. Confining zone: Stratigraphic equivalent of interval seen in Qugruk 8 well from 4040' MD to 4135' NO. Drill cuttings were described as light to medium grey claystone, soft, slightly friable with abundant silt and sand grains. XRD analysis of a core plug within this interval contained 53% clay with a vertical Klinkenberg permeability of 0.009 md. The confining zone is overlain by approximately 200' of silts and shales of the upper Nanushuk Formation, and approximately 1000' of basinal shale -prone Seabee Formation. Reservoir: Stratigraphic equivalent of interval seen in Qugruk 8 well from 4145' MD tao 4400' MD. Whole core from the Qugruk 8 well shows massive to thinly -bedded, very fine-grained sandstones and siltstones. Bioturbation is prevalent in the upper shallow -water facies and decreases with depth. Soft -sediment deformation, including sand injections, deformed bedding and small-scale faulting, are present in the lower portion of the reservoir. Core analysis of the interval indicates the sands contain 15-40% clay and are predominantly lithic arkoses and feldspathic litharenites. Porosity within the sandstones ranges from 16% to 28% and permeability ranges from 1 to 500 md. Depth & Thickness: The expected depth of the reservoir and confining zone has been determined through interpretation of a pre -stack depth migrated 3D seismic survey. We estimate the top of the upper confining zone to be at approximately 4460' MD (4280' TVD) with a true vertical thickness of approximately 100'. The top of the reservoir is estimated to be at 4560' MD (4380' TVD) with a true vertical thickness of 260'. The well is planned to be vertical through the entire reservoir interval. Frac Pressure: Actual hydraulic fracturing downhole treating pressure was measured at 2500 psi in the Q-301 well. This.,57 frac gradient is expected to be consistent in the Nanushuk reservoir in the Horseshoe 1 well. The expected frac pressure of the overlying confining zone is approximately 2900 psi. Faults & Fractures: The Horseshoe well is located within a relatively unfaulted region of the north slope. No faults or fractures are evident on the high -effort 3D seismic survey in the vicinity of the well location. The nearest fault that intersects the reservoir and overlying confining zone is located approximately 7 miles west of the well location. The faults west and southwest of the well location tend strike north northeast, have vertical displacements of less than 70', and have strike lengths ranging from 1 to 5 miles. 10-403 APPLICATION FOR SUNDRY APPROVALS - FEBRUARY 2017 19 Proposed Hydraulic Fracturing Program CUSTOMER Armstrongaland Gas AN 8FD(Ib/golf 3.54 LEASE Horseshoe 91 SALES ORDER BHST(°F) 110 a R. nasiDrecc„ro incil Flwd Type Desi n Total ( al) FR -66 Water SC -140 259 WaterFracG 1,500 Prop Slurry Clean Clean Slurry Treatment Stage Fluid Stage Proppant Conic Rate Volume Volume Volume Interval Number Description Description Description (pg) (bpr.. (gal) (bbl (bbl) 1.00 1 259 De1taFrac 140 Pre -Pad 25.00 25 10,000 238 238 2 Shut -In Shut -In as bo 3 25N DeltaFrac 140 Pad 0:05:43 25 6,000 243 143 = a 4 25p DeltaFrac 140 Proppant Laden Fluid Carbollond 16/20 1.00 25 4,000 95 IOp 2 z . 5 259 DeltaFrac 140 Pro ant Laden Fluid Carbollond 16120 3.00 25 51000 119 135 co 6 259 Del laFnc 340 Pro ant Laden Fluid CarboBond 16/20 4.00 25 6,000 143 169 i �) 7 259 Deltalw 140 Prop ant Latlen Fluid CarboBond 16/20 5.00 25 6,000A41 020:40 1.00 1.00 8 259 DeltaFrac 140 Pro ant Laden Fluid CarboBPnd 16/20 6.00 25 4.500 0.15 30,000 9 25RWaterFracG Flush 1.00 2.25 25 1,500 2.00 25.00 1.00 1.00 0.15 2]000 0:05:2] 0:06:53 43,000 1.00 2.25 Flwd Type Desi n Total ( al) FR -66 Water SC -140 259 WaterFracG 1,500 259 DelteTrac 140 41,500 GBW-30 OpUFlo-11 Dry additives SP NALLIBURTON PloPPaMType Total fibs) / CarboSond 16/20 100,000 t/ Initial Design Material Max Additive Rao Min Additive Rao Ela -Web Losurf-3000 SC -140 MO -6] BA -20 Uquid Additives WG -36 GBW-30 OpUFlo-11 Dry additives SP m Prop Total (Ibs) Stage Time hh:mm:ss Interval Time (hh:mm:ss) Cla-Web cleTtaoa (9pl) Wsurf-300D Suda<Rnt (pt) BC -140 Cradnter ( t) MO -67 nater ( t) BA -20 Bunn (PQ CarboSond LTCA P.,.nt A[prator (op() WG -36 Dd (PPt) GBW-30 Bnehe (Pt) OptlFlo-R Dresser Will BE -6 %PPwa Ppt) SP answer (PPI 0.3 0:09:31 0:45:18 1.00 1.00 2.25 0.50 0.25 25.00 1.00 1.00 0.15 0:35:46 0:05:43 0:35:46 1.00 1.00 2.25 0.50 0.25 25.00 1.00 1.00 0.15 4,000 0:03:59 0:30.03 1.00 1.00 2.25 0.50 0.25 2.00 25.00 1.00 1.00 0.15 15000 0:05:25 0:26:04 1.00 1.00 2.25 0.50 0.25 2.00 25.00 1.00 1.00 0.15 24,000 0:06:45 020:40 1.00 1.00 2.25 0.50 0.25 2.00 25.00 1.00 1.00 0.15 30,000 0:07:01 0:13:54 1.00 1.00 2.25 0.50 0.25 2.00 25.00 1.00 1.00 0.15 2]000 0:05:2] 0:06:53 1.00 1.00 2.25 0.50 0.25 2.00 25.00 1.00 1.00 0.15 0.25 0.01:26 0:0]:26 1.00 1.00 25.00 1.00 1.00 0.15 0.50 100,000 0:45:18 Initial Design Material Max Additive Rao Min Additive Rao Ela -Web Losurf-3000 SC -140 MO -6] BA -20 Carbo BDrd TCA WG -36 GBW-30 OpUFlo-11 BE -6 SP m m(op.?m m m) m m m ppro IA 1.1 2.4 0.5 0.3 2.1 26.3 1.1 1.1 0.2 0.5 10-403 APPLICATION F012 SUNDRY APPROVALS - FEBRUARY 201 / Horseshoe #1 Stages Job Size Top TVD Btm TVD Propped Fracture Avg (lb) (ft) (ft) Half- Height (ft) Fracture UaaY Mrliv length (ft) Width (in) 1 100,000 4318 4418 440 ! 100 0.42 • Disclaimer Notice: • This model was generated using commercially available modeling software and is based on engineering estimates of reservoir properties. Armstrong Energy LLC is providing these model results as an informed prediction of actual results. Because of the inherent limitations in assumptions required to generate this model, and for other reasons, actual results may differ from the model results. The chemical additives are: NyJaWlc Fr%lunt flU ft bt Cdnp MNQIr Ibn Disclosure nwan aWa UaaY Mrliv gvwNes v.•�wabE�� vaWaNrpFbn ao nobawa1m .svoriFNvq rW vaMvwr' nNa•cnxvrprwcmN��ps CarmaM Wrnxvn W+bw Mnrnun FOM�rrr Fyµ[nl iraNNane SypYx Npoee FpeaenN Exvin Corynbalnnm M]Yna CennnbNanin FTe yMnlWss Ceemn�n fe�a•ab Firtl Wme lasl flee Equi Plwrt MuFax�CAa (liay nusF•• Ni FNk�Mq N F ssl'• _ esa stM.v uuh+n _+A w ena. xa Anticipated hydraulic fracture stimulation pressures are expected to be consistent with the pressures recorded in the Q-301 well. A B Zone I DFIT Treaunent Pkn Treating Ptrssure (Psig) .1 ,knnalus Pre%sure (Pd) A Slurr,Rate (bpm) B slum Proplutut ('onc BUT Proppant ('onc OlVgal) (' Actual Bullomhole Pk -(psi) A Actual Bottomhole Temn (01F) E MENEM Anticipated hydraulic fracture stimulation pressures are expected to be consistent with the pressures recorded in the Q-301 well. A B Zone I DFIT Treaunent Pkn Treating Ptrssure (Psig) .1 ,knnalus Pre%sure (Pd) A Slurr,Rate (bpm) B slum Proplutut ('onc BUT Proppant ('onc OlVgal) (' Actual Bullomhole Pk -(psi) A Actual Bottomhole Temn (01F) E C E r 1000 13:30 13:40 13:;0 1-10) 14:10 s e:or: s �a joss Tme 700 10-403 APPLICATION FOR SUNDRY APPROVALS - FEBRUARY 2017 22 Pressure Relief Valves yA Regulations 20 AAC 25.283. Hydraulic Fracturing section "d" requires a pressure relief valve to be S installed on the treating fine. Maximum Anticipated Surface Pressure on the treating line is expected �. to be 6000# so the PRV is being set at 6500 psi. The tubing frac and test string contains a Sub Surface Safety Valve controlled by a control line back to the surface. Section 'T' requires the surface casing annulus to be monitored with a gauge and pressure relief valve device while hydraulic fracturing operations are in progress. Prior to the treatment, 2000 psi will be applied to the annulus. A PRV will be installed and preset at 2450 psi during the fracturing operations. F -- Post Treatment Clean Up and Reporting ProdlyFtion Testing Services has been selected as the well test flowback company. Produced fluids will be flowed back through their facilities to separate the proppant, gelling fluids with chemicals, oil, gas and water. All fluids will be disposed of through approved facilities at the Hilcorp grind and inject facility,/ Any oil or produced water that has not been disposed of through their facility may be re -injected into the producing interval at the Horseshoe #1.J Following the frac job, a tracer log will be run to determine the frac height achieved during the treatment. Armstrong has applied for membership and been accepted into the FracFocus Chemical Disclosure Registry. The hydraulic fracture information required by the regulations will be posted on the registry site and then printed for attachment to the Report of Sundry Operations following the treatment to the Horseshoe #1 //&% x tL-fx Xe- y 10-403 APPLICATION FOR SUNDRY APPROVALS - FEBRUARY 2017 23 Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Tuesday, February 14, 2017 2:33 PM To: Stephen Hennigan; Bettis, Patricia K (DOA) Cc: samantha.carlisle@alaska.gov Subject: RE: AE Sundry Application for Well Test Horseshoe #1 PTD 216-133 Stephen, The AOGCC will retract sundry no. 317-064 to fracture stimulate Horseshoe #1 as requested. Sundry was still being processed and not approved yet. We will keep one copy and send you the duplicate back. We also have some comments and suggestions for your benefit for future stimulation sundries. These will come by email later next week. Regards, Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 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 Guy Schwartz at (907-793-1226 ) or (Guy.schwartz@olaska.aov(. From: Stephen Hennigan [mailto:shennigan@peiinc.comj Sent: Tuesday, February 14, 2017 2:13 PM To: Schwartz, Guy L (DOA) <guy.schwa rtz@alaska.gov>; Bettis, Patricia K (DOA) <patricia.bettis@alaska.gov> Subject: AE Sundry Application for Well Test Horseshoe #1 PTD 216-133 This is to formally notify the AOGCC that at this time, Armstrong Energy would like to retract the Sundry application to test the subject well. Your review of this application is appreciated. 7, w,e pa adkm a 6Beeed dad/ rT OT,uGt[8an, MS Emgt A Project Manager/Engineer"." S: 337-984-2603 S: 337-849-5345 (mobile) •_� #%Mo Petroleum Alto SIERRA 'it:% Engineers •;pis« HAMILTON Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Tuesday, February 14, 2017 2:26 PM �� To: Bettis, Patricia K (DOA) Subject: Horseshoe frac comments... 2—t4 _ 1,5 3 Here are my questions and comments for frac sundry, 1. What is test pressure for the 7 casing? 2. IN step 22 after CBL is run forward to AOGCC for review. 3. More detail on setting packer needed ...( hyd set. Packer.) What are you pressure testing against to set packer? No mention of testing IA after packer set. 4. Tubing test to 4400 psi looks like it is based 6000 psi — 2000 psi = 4000 psi X 1.1 => 4400 psi 5. Would be good to have a table showing all test pressures and PRV listed. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 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 Guy Schwartz at (907-793-1226 ) or (Guv.schwartz@alaska.aov). The sundry application received February 3, 2017 for the Horseshoe -1 well lacks information required by the Hydraulic Fracturing Regulations 20 AAC 25.283 amended effective January 7, 2015. A copy of the amended regulation may be obtained by contacting the AOGCC at (907) 279-1433 or fax (907) 276-7542. The amended regulations may also be found at the following address: http://doa.alaska.gov/ogc/Regulations/`20AAC25-005cl3.pdf. The application to hydraulically fracture Horseshoe -1 lacks the following information or document(s): 1. A notarized affidavit stating that all owners, landowners, surface owners, and operators within a one-half mile radius of the proposed wellbore trajectory have been provided a notice of operations. Please see AS 31.05.170. Definitions, for the definitions of owners and landowners. Owners would include Repsol E&P USA, Inc. and any other working interest owners. Surface owners would include the Department of Natural Resources, Division of Oil and Gas. Therefore, a new notarized affidavit must be submitted to AOGCC to accurately reflect that a notice of operations has been provide to all owners, landowners, surface owners, and operators within a one-half mile radius. The Affidavit submitted to AOGCC needs to be the original. 2. Submit a copy of the Notice of Operations that is sent to all owners, landowners, surface owners, and operators within a one-half mile radius of the proposed wellbore trajectory to the AOGCC. 3. Provide a list of all owners, landowners, surface owners, and operators within a one-half mile radius of the proposed Horseshoe -1 well. 4. Provide the legal description of the well, (surface, target and bottomhole locations). 5. Provide a discussion on the presence of freshwater aquifers within a one-half mile radius of the Horseshoe -1. Provide measured and true vertical depths for those aquifers. 6. Provide Total Dissolved Solids calculation for determining base of fresh water aquifer in the Horseshoe -1 well. Provide measured and true vertical depths for those aquifers. 20 AAC 25.990(27) defines fresh water as, "has a total dissolved solids concentration of less than 10,000 mg/l, and occurs in a stratum not exempted under 20 AAC 25.440". Please provide the calculation(s) and values used for this determination, so that the information can be verified. 7. Provide a plat showing the wellbore trajectory for the Horseshoe -1 well. 8. 20 AAC 25.283(a)(5 and 6) casing and cementing information requires for Horseshoe -1, an evaluation of the cementing program and its confinement performance. A CBL log is to be run and the log should be provided with the evaluation detail. 9. Provide a final wellbore schematic for Horseshoe -1 once total depth is reached. The schematic should show actual packer depths, casing information, and tops of cement. 10. Discuss any lost circulation zones encountered while drilling Horseshoe -1. 11. Provide the depth of the lower confining zone (basal shale -prone Seabee Formation) and the expected frac gradient for this zone. 12. Provide a discussion on the principal stress directions within the Nanushuk reservoir. Will fractures run parallel or perpendicular to the well path. 13. Provide mitigation measures if there are indications that a fracture has intersected an unknown fault during fracturing operations. 14. Provide a copy of the digital or a pdf copy of well log data (specifically gamma ray, caliper, resistivity, porosity and mud log) recorded in Horseshoe -1. These may be the OH logs recorded. Craig, if you are interested, I can provide an example application from another operator that may assist Armstrong with providing this omitted information. If you would like to stop by AOGCC, I can make you a paper copy. This would be an example for a development well on the North Slope. Z• v 0 m a x% N 2 y w Z A rn 1 y V co O N O N v m m CA cn C x m 0 m m m N S 0 CD m s 0-6 PSI N N CD W A A rA v m m CA cn C x m 0 m m m N S 0 CD m s 0-6 rA r •p — ro Vol X mg n m 3 n 'm 3 m � m O z � o �i X. o — J v m m CA cn C x m 0 m m m N S 0 CD m s 0-6 Armstrong Energy, LLC CASING & CEMENTING REPORT Permit to Drill (PTD) 216-133 Lease & Well No. ADL 392048 Horseshoe # 1 Date 1 -Feb -17 County North Slope State Alaska Cc Supv. Lenhart/Boyd/Oryall/Wallingford CASING RECORD Surface TO MD 2230 TVD 2201.23 Shoe Depth: MD 2213.54 TVD 2185.42 PBTD: MD na TVD na Ash (Spacer) Howco Pump Clean III Density (ppg) Slurry Permafrrost L city (ppg) 10.7 Volume (BBLs/sacks): Slurry .. Class G >ity(ppg) 15.8 Volume (BBLs/sacks): Flush (Spacer) 10.5 Volume pumped (BBLs) Yield (Ft3/sack): 4.74 Yield (Ft3/sack): 48 bbis 40 4.74 Mixing /Pumping Rate (bpm): 1.173 Mixing / Pumping Rate (bpm): 4 Type: Density(ppg) Rate (bpm): Volume: Displacement: Type: water Density (ppg) 8.34 Rate (bpm): 2 Volume (actual / calculated): 23.5 FCP (psi): Pump used for disp: Howco cement pump Plug Bumped? x Yes —No Bump press 15 Casing Rotated? _Yes x No Reciprocated? _Yes x No % Returns during job 100 Cement returns to surface? x Yes _No Spacer returns? x Yes —No Val to Surf: 87 Cement In Place At: 22:00 Date: 2/1/2017 Estimated TOC: surface Method Used To Determine TOC: Cement sample taken & weiched Cod surface Preflush (Spacer) Type: _ Lead Slurry T Density (ppg) Tail Slurry Tvne Density (ppg) Volume (BBLs/sacks): Yield (Ft3/sack): Yield (Ft3/sack): Volume pumped (BBLs) Mixing / Pumping Rate (bpm): ity (ppg) Volume (BBLs/sacks): Mixing / Pumping Rate (bpm): Flush (Spacer) Density (ppg) Rate (bpm): Volume: lacement: Density (ppg) Rate (bpm): Volume (actual / calculated): _ (psi): Pump used for disp: Plug Bumped? _Yes _ No Bump press ig Rotated? _Yes _No Reciprocated? _Yes _No % Returns during job ant returns to surface? _Yes —No Spacer returns? _Yes _ No Vol to Surf: :nt In Place At: Date: Estimated TOC: A Used To Determine TOC: Remarks: Casing (Or Liner) Detail (should match casing tally) Csg Wt. On Hook: 120k Type Float Collar: Check Valve Setting Depths No. of Jts. Size Wt. Grade THD Eqpmnt Mfg Length Bottom Top Shoe/jt 95/8 53.50 L80 Mod BTC 2.25 2,213.54 2,211.29 2 95/8 53.5 L80 Mod BTC 79.38 2,211.29 2,131.91 Float collar L80 Mod BTC 2.40 2,131.91 2,129.51 54 95/8 53.5 L80 Mod BTC 2,101.47 2,129.51 28.04 Hanger L80 Mod BTC 1.21 Totals 2,186.71 Ash (Spacer) Howco Pump Clean III Density (ppg) Slurry Permafrrost L city (ppg) 10.7 Volume (BBLs/sacks): Slurry .. Class G >ity(ppg) 15.8 Volume (BBLs/sacks): Flush (Spacer) 10.5 Volume pumped (BBLs) Yield (Ft3/sack): 4.74 Yield (Ft3/sack): 48 bbis 40 4.74 Mixing /Pumping Rate (bpm): 1.173 Mixing / Pumping Rate (bpm): 4 Type: Density(ppg) Rate (bpm): Volume: Displacement: Type: water Density (ppg) 8.34 Rate (bpm): 2 Volume (actual / calculated): 23.5 FCP (psi): Pump used for disp: Howco cement pump Plug Bumped? x Yes —No Bump press 15 Casing Rotated? _Yes x No Reciprocated? _Yes x No % Returns during job 100 Cement returns to surface? x Yes _No Spacer returns? x Yes —No Val to Surf: 87 Cement In Place At: 22:00 Date: 2/1/2017 Estimated TOC: surface Method Used To Determine TOC: Cement sample taken & weiched Cod surface Preflush (Spacer) Type: _ Lead Slurry T Density (ppg) Tail Slurry Tvne Density (ppg) Volume (BBLs/sacks): Yield (Ft3/sack): Yield (Ft3/sack): Volume pumped (BBLs) Mixing / Pumping Rate (bpm): ity (ppg) Volume (BBLs/sacks): Mixing / Pumping Rate (bpm): Flush (Spacer) Density (ppg) Rate (bpm): Volume: lacement: Density (ppg) Rate (bpm): Volume (actual / calculated): _ (psi): Pump used for disp: Plug Bumped? _Yes _ No Bump press ig Rotated? _Yes _No Reciprocated? _Yes _No % Returns during job ant returns to surface? _Yes —No Spacer returns? _Yes _ No Vol to Surf: :nt In Place At: Date: Estimated TOC: A Used To Determine TOC: Remarks: Csg Supv. Csg Wt. On Hook: 120k Type Float Collar: Check Valve No. Hrs to Run: 13 Csg Wt. On Slips: 120k Type of Shoe: Check Valve Casing Crew: Weatherford Fluid Description: Water Base Mud Liner hanger Info (Make/Model): na Liner top Packer?: X No Liner hanger test pressure: na _Yes Lnr Hgr Tech Centralizer Placement: 3 on shoe track; then every 3rd joint Ash (Spacer) Howco Pump Clean III Density (ppg) Slurry Permafrrost L city (ppg) 10.7 Volume (BBLs/sacks): Slurry .. Class G >ity(ppg) 15.8 Volume (BBLs/sacks): Flush (Spacer) 10.5 Volume pumped (BBLs) Yield (Ft3/sack): 4.74 Yield (Ft3/sack): 48 bbis 40 4.74 Mixing /Pumping Rate (bpm): 1.173 Mixing / Pumping Rate (bpm): 4 Type: Density(ppg) Rate (bpm): Volume: Displacement: Type: water Density (ppg) 8.34 Rate (bpm): 2 Volume (actual / calculated): 23.5 FCP (psi): Pump used for disp: Howco cement pump Plug Bumped? x Yes —No Bump press 15 Casing Rotated? _Yes x No Reciprocated? _Yes x No % Returns during job 100 Cement returns to surface? x Yes _No Spacer returns? x Yes —No Val to Surf: 87 Cement In Place At: 22:00 Date: 2/1/2017 Estimated TOC: surface Method Used To Determine TOC: Cement sample taken & weiched Cod surface Preflush (Spacer) Type: _ Lead Slurry T Density (ppg) Tail Slurry Tvne Density (ppg) Volume (BBLs/sacks): Yield (Ft3/sack): Yield (Ft3/sack): Volume pumped (BBLs) Mixing / Pumping Rate (bpm): ity (ppg) Volume (BBLs/sacks): Mixing / Pumping Rate (bpm): Flush (Spacer) Density (ppg) Rate (bpm): Volume: lacement: Density (ppg) Rate (bpm): Volume (actual / calculated): _ (psi): Pump used for disp: Plug Bumped? _Yes _ No Bump press ig Rotated? _Yes _No Reciprocated? _Yes _No % Returns during job ant returns to surface? _Yes —No Spacer returns? _Yes _ No Vol to Surf: :nt In Place At: Date: Estimated TOC: A Used To Determine TOC: Remarks: THE STATE °fALASKA GOVERNOR BILL WALKER Stephen F. Hennigan Consulting Project Engineer Armstrong Energy, LLC 510 L St., Ste. 310 Anchorage, AK 99501 Re: Exploratory Field, Wildcat Oil Pool, Horseshoe 1 Permit to Drill Number: 216-133 Sundry Number: 317-044 Dear Mr. Hennigan: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.claska.gov Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Daniel T. Seamount, Jr. Commissioner DATED this 33 o day of January, 2017. RBDT41S (,c- FE3 - 3 2017 RECEIVED STATE OF ALASKA JAN 2 5 2017 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 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 ❑✓ Other: ❑ 2. Operator Name: 4. Current Well Class: 5. Pennit to Drill Number. Armstrong Energy, LLC , Exploratory ❑✓ . Development ❑ Stratigraphic ❑ Service ❑ 216-133 3. Address: 6. API Number: 510 L Street, Suite 310 Anchorage, Alaska 99501 50-103-20751-00-00 , 7. If perforating: 8. Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? na Horseshoe #11 - Will planned perforations require a spacing exception? Yes ❑ No ❑✓ 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL 392048 • Wildcat it. PRESENT WELL CONDITION SUMMARY Total Depth MO (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 0 0 0 0 na Casing Length Size MD TVD Burst Collapse Structural 118 16 118 118 ne na Conductor 0 0 0 0 0 Surface 2318 9.625 2318 2242 7930 6620 Interm Prod Liner 3600 7 5718 5539 7240 5410 Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): na na na na ne Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): na na 12. Attachments: Proposal Summary ✓ Wellbore schematic ✓ 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory WrStratigraphic ❑ Development ❑ Service ❑ 14. Estimated Date for 15. Well after proposed work: Commencing Operations: �Status OIL W1 WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. ContactStephen Hannigan ph 337 849-5345 Email steve�oeiinc.com Printed Name Title Stephen F. Hennigan Consulting Project Engineer for Armstrong Energy, LLC Signature (337) 849-5345 Date 1/20/2017 16:51 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 31,-7- 0K`{ Plug Integrity ❑ BOP Test 9/ Mechanical Integrity Test ❑ Location Clearance ❑ Other:/T , ' .1F l.onc�G�i-;c•.s by s.-� �{asri.. ..._ to —1t) zIL-l33 Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No VJ Subsequent Form Required: f (� - 4 (� l d i n ✓� KJ RBDPIIS k(- FF^ - 3 2017 APPROVED BY Approved by COMMISSIONER THkCPMMISSION Date: 1/3w[17 V 1 � � r� Submit Formand Form 10-403 Revised Ji/20y5� Approved application is I 101 t S r�jlh� Of approval yA.ttachments in Duplicate " 1 /7 /l � t-2-7- I I 1't` A ARMSTRONG F.nerkn% LLC January 19, 2017 Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission E C E I V E D 333 West 7`h Avenue, Suite 100 Anchorage, AK 99501 IAS 2 5 2017 RE: Application for Sundry Permit to Change Casing A OGCC Armstrong Energy, LLC Horseshoe #1 (PTD 216-133) Sec 15 Bn 4e LIM Wildcat North Slope, Alaska Dear Ms. Foerster, Armstrong Energy, LLC (AE)) hereby applies for a Sundry permit to run a 7" liner instead of long string should it be desired to test the well permitted by PTD 216-133'. Armstrong at this time is mobilizing the Doyon Arctic Fox to drill the Horseshoe #1 (PTD 216- 133). Following evaluation of the PTD 216-133, Armstrong Energy is anticipating to abandon the lower open hole, setting casing short (Sundry requested for running a finer) and possibly testing (Sundry being prepared) with P&A of the zone IF tested (Sundry submitted but waiting exact data from the test). Please find attached information as required by 20 AAC 25.015 (b) (2) for your review. Pertinent information attached to this application includes the following if it is different than PTD 216-133: • Form 10-403 Application for Sundry Permit • AS Built Surface Location Plat for PTD 216-133 • Proposed Wellbore Diagram • Casing Burst Calculations • Operations Summary with Back up (Intm Prod section changed Step 12 on) • Cementing Program Summary • UPDATED Proposed Directional Plan for PTD 216-133 • Wellhead diagram (same as PTD 216-133) but without the 7" Casing Hanger • Miscellaneous 510 L Street, Suite 310 - Anchorage, AK 99501 p907.375.6900 if there are any questions and/or any additional information desired, please contact me at (337) 849-5345 or Pete Berga at (573) 201-3861. Respectfully ARMSTRONG ENERGY, LLC Stephen F. Hennigan Armstrong Project Engineer Enclosures Cc: Edward Teng — Armstrong VP and Project Manager Colby VanDenburg— Armstrong Project G&G Nate C. Lowe — Armstrong Land Manager Cindy Bailey — Armstrong Public Affairs Manager Robert Britch — Senior Advisor Pete Dickinson — All American — Armstrong Drilling Manager Pete Berga - All American — Armstrong Drilling Superintendent Stephen Hennigan — Sierra Hamilton Petroleum Engineers for Armstrong Energy 510 L Street, Suite 310 - Anchorage, AK 99501 p907.375.6900 5 i NO 0 W, 0 Oa Ow aU 0 O i 8 « i i � � 9 a: s➢ Y =_ 's § Y B� Y Y➢ k➢➢ A B➢ A§ k A➢ �� e�3s�nee"ss9gx§egas959H359 i i Igloo[] 1111111 Momm 'Aay � 3 w� Y p 9 i 8 « i i � � 9 a: s➢ Y =_ 's § Y B� Y Y➢ k➢➢ A B➢ A§ k A➢ �� e�3s�nee"ss9gx§egas959H359 i i Igloo[] 1111111 Momm Armstrong Energy, LLC Horseshoe # 1 Block/Sec 015 TBn Rife Wildcat North Slope Alaska PTD #: 216-133 Est Rkb 43' .................. ROP: ±300• 1' .................. 8.3 8.4 11 99 -pen 118' ROP/Gas log Co'wo've to T0. Osx Lead @ OpM a 430m Tail @ 15.6ppg d.6 10 13.8 GR, lies, neu, denot, 7318' 2142' 785sx Lead @ 11.1ppg+220 sx Tail @ IS.BpPS Tie On Casing 1 ROP Base Permafrost V MIOXMatler BluNarea 9' SEpdtangenp MCU Oaung2 i6' EnEMTangent Build&Turn TTulwak/Seabee EOOHOLD Mud Logging: Manned: 2 5x/50' 0. 32200',25x/10', ±2200' -TO W EOH, Drop TOO, Vemral, N.—Iiiik 3 Core Point d43a0' SSTVD NanusEuk1_5200' SSWU 9 10.4 16 GR, Res. svgs 5718' 's PonNIe TD COL 5539' "I opine Os- Lead @Oppg+420. Tail @14ppg TO Top 0HR2 TD O 8222' IN 8043' Gr, U, Den, Neun, + w/ flul sample, Oil-bazetl FMI, NMR, ECS or LiMoscanner Plugged with ±1675 sc of ctnt below Flsud 1: Rh<olopcally Enhanced Sluices CLEANSPACER III 36.5' gal bbI FRESH It :ATEA Fluid _2 Low fluid Loss PLUGCEM (TM) SYSTEM 0.20 `e SCR -100 4 93 Gal'sk FRESH WATER 8W x56 Weld Raox Est TOC =0'RAR SMS#Lg0 Mod OTC Ell Lar mP 2118' 2092' Air Gap Wtr. o Auger/arae sz 16 IiMHoe n.. #REFI #REFI 95/8" 1111—M Ell TOC' 11 RRB d 4- Z. til m> 2 So3A I -S3 C 1 71 -Tot- e zioo` Pill,j> L80 DWC #REFI AxNeipxleE AI PIA A VL0,orn U1,11 AFTER Evaluation Fluid Density: 10.5 IbiWlial Volume: 35 bbl Fluid Weight: 15.816ovgal Slum Yield: 1.153 R3/sack Total Mixing Fluid: 4.93 Gat sack 81/2" 7 .. 4.9 Casing Design and Calculations Note: In this program, MASP for each hole section is defined as the pore pressure (In psi) at the nextcasing point (or TDI less a gas column in surface. Gas gradient is assumed to be0.1 psi/R. MADP is defined as the maximum hydrostatic in the hale section. ATTIMES MASP CALCULATIONS WILL BE ADJUSTED FOR AIR GAP AND WATER DEPTH when applicable. And maybe modif ed for documented reasons discussed below or Ina requested variance. Casing Design Summary Chan (Cakulatiom below) Interval Start Depth Seat D pth CaJne Dip Mdm Faeanfor_ El" MD MD She / wt Grade Burst • Tendon• Brat Des. Ilb7ht Conn"n..Cama Tead Drive/ 0 118 X56 phothole N/A N/A N/A N/A N/A Structural 24" -_-_ 16"-80 PPf _._. _ mud wt of 10 ppg ......... .......... .......... ....... ....... 0 118 Weld 2242' ND x((8.6 ppge•.OS2)- 0.1 psi/ft) 779 psl MADP = ((PP ppge) x .052 x ND) -_._._._ _ _._._._ _ _ _.___ - - - - - - - - - - _._._._ N/A _._._. N/A N/A N/A _ 1443 psi Burst stress = N/._.___-_._ A 1443 psi, shoe would break down Design Factor guts[stre,dv Bonn Stress = 7930/1442.9532 0 2318_ 9.625"-53.5 L80 7930 1244 1443 5.50 850 11.84 Surface 12.25'------ -- _ -. ._ mud wt of 10A ppg _ -_-Mod from above _. - _ ---_ _._._._._ _ _-_._ _-_-_ 0 2242 Ppf BTC 6620 118 MADP= LINER Test US 2138 5718 7240 604 2039 3.55 2.65 4_83 .2092--- _ - 7".26ppf _L80 --- - - -- -----2038 ----- --- - -- - - 8.5" 5539 DWC 5430 • = minimum of body and Connection strengths RECOMMENCED Casing Design factors BURST(from internal pressure) 1.1 COLLAPSE (from external pressure) 1 TENSILE(joint hotly and connection)strength 1.6 BURST REQUIREMENTS No conductor 95/8" Surface 12.25" phothole no 121/4" Hole Sect ion-astmatwl nore nreseanp of 3.6 FPS a— Thisholesection willbeorllled toi 2242- WD with SOP'sinstalled/tested with a max anticipated mud wt of 10 ppg from a bove MASP(pp) =((PP ppge) x .052 x TVD) - (a x ND) MASP= 2242' ND x((8.6 ppge•.OS2)- 0.1 psi/ft) 779 psl MADP = ((PP ppge) x .052 x ND) MADP= 2242'ND x(1D ppg' 0.052) 1166 psi MASP(IS) = ((FG ♦ SF ppb) x .052 x ND) -(a x ND) MASP 0, Design= 2242'NDx((13.Spp8eF.5 ppge)-0.1 psi/ft) 1443 psi Burst stress = MASP US Design Is used since In me of a kik In excess of 1443 psi, shoe would break down Design Factor guts[stre,dv Bonn Stress = 7930/1442.9532 5.505f 7 " UNERTest Csg8.5" 81/2" HDIe SECU n-e"9mat.d pore nrxsureof 9 ppg emw This hol auction wi l i be dri l l ei to E 5539' WD with SOP'sinstalled/tested with a max anticipated mud wt of 10A ppg from above MASP(pp) = ((PP ppge) x.052 x ND) - (a x Ml) MASP = 5539' ND x((9 ppge•A52)-0.1 psl/ftl 2038 psi MADP = ((PP PpBe) x.052 x WD) MADP= 5539' ND x(10.4 ppg• 0.052) 2995 psi Burst Stress= MASP US Design = % TD MASP is used since Mr will be a phadou. test string 2036 from below F Design Fahr Burst streigtM Burst Strass= 7240/2038.352 3.55SF CODAPSE REQUIREMENTS Use an external pressure thatthe casing could possibly he put under. One design methodology uses pore pressure at the rasing shoewith a gas gradient internally. DRILLING OPERATIONS SUMMARY Armstrong Energy, LLC Horseshoe # 1 Block/Sec 015 8n 4e Wildcat North Slope Alaska PTD: 216-133 Start Depth Seat Death Casino Interval Hole Size MD TVD MD TVD Size Ib t Grade Conn Burst* Collapse Tension* Drive/ 24„ 070' 118'/118' 16 84 X56 Weld N/A Structural Conductor INA) Surface 121/4" 0'/0' 2318'/2242' 95/8" 53.5 L80 Mod BTC 7930 6620 1244 LINER 81/2" 2118'/2092' 5718'/5539' 7 26 L80 DWC 7240 5410 604 Test Csg * = minimum of body and connection strengths Buck on float equipment @ yard MU casing to optimum torque Notes: • SAFETY, HEALTH, AND THE ENVIRONMENT, COME FIRST throughout the operation. • AOGCC MUST be notified 48 hrs prior to each diverter function and BOPe test. • All test pressures in procedure should be checked on the rig by Supervisor / Consultant, any discrepancies should be discussed with Office Supervisor. Hold diverter drills until crews are familiar with diverting procedures. • While drilling w/diverter, if a positive indication of influx is observed, mud will be pumped at the fastest rate possible. The pumps will be switched to water if all the mud is pumped away without a kill. Monitor the ice (ground) around the rig for possible broaching to the surface. • Drilling to each casing string depth (after the drive pipe) will require an additional ±20' to allow hanging off the casing in the wellhead. • A compliance matrix will be constructed and the operation will be in compliance of all regulatory bodies. Structural (Drive/Conductor) 1. Drill/Drive 16" conductor to +/- 118ft. RKB. RD conductor rig. Install cellar. NOTE: Should be installed prior to rig arrival by construction. 2. Notify ALL appropriate parties and agencies, LAND OWNERS, etc, of pending rig move. 3. MIRU rig. Post drilling permit(s) and prognosis in Company man's office and rig floor. Place MSDS sheets at required locations. PERFORM Wellsite ore -spud meeting. Perform detailed HSE meeting. Establish Severe Weather responsibilities and POST same. AND other as approgriate. NOTE the following for the Doyon Attic Fox i. The RKB is 18.6" ABGL with the Rig sitting on ice and mats GL is defined as Bottom OF MATS. (TOP OF ICE) ii. Well headBOP Connection to be above Ground level with the rig's BOP. 4. Install starting head 16" SLC x 21 Y4", 2M flange. 5. Nipple up 21 t/4", 2M diverter, 12" diverter valve and 12" diverter line. Make sure control lines are installed at an angle to diverter line. NO lines should be above the diverter or diverter line INSIDE the diverter valve. 6. Function test diverter and diverter valve. (AOGCC 48hr notice). AOGCC at this time will NOT waive witness. 7. Build / take on spud mud. 8. Inspect BHA equipment. 9. Install mud loggers per logging program. Instruct same regarding dry ditch samples for AOGCC. 10. ORDER CONVENTIONAL CORING EQUIPMENT. 7 DAYS NOTICE IS REQUIRED. Notify core handling company as well. Identify area for Laydown Cradles and handling. NOTE: New cementing regulation 20 AAC 25.030 is being amended and net sections added to read: 20 AAC.25.030 Casing and cementing. (d) (i) intermediate and production casing must be cemented %Kith sufficient cement to fill the annular space from the casing shoe to it minimum of 500 vertical fcct above all significant hydrocarbon zones and abnormally geo-pressured strata or. if tonal emerage is not required under (a) of this section. from the casing shoe to a minimum of 500 vertical feet above the casing shoe. it' indications or improper cementing exist. such as lost returns. or if the formation integrity test shows an inadequate cement job. fREMEDIAL ACTION %11 ISI til; TAKEN: (A) the operator shall notify the commission and obtain approsal before drilline ahead; and (B) provide: (i) a cement quality Ioe or other approved method to evaluate the adequacy of the cement to contain potential wellbore pressures and fluids; and (ii) a plan setting forth the remedial actions proposed to brine the well into compliance with the requirements of (a) of this section; Surface: 1. Conductor is to be preinstalled. • Mud Program • Bit Program • Directional Program w/ BHA's • Cement Program • Wellhead Program 2. PU 4" drill pipe, bit and DIRECTIONAL BHA w/ GR/RES per bit/directional proposal. Set up WEEKLY STATUS Report for the Commission. 3. Drill w/ low rpm, gpm until stabilizers have exited drive pipe. Run max gpm, rotary, etc as allowed. Set up logging (if any) as per evaluation section. 4. Drill 12 Y4" hole to KOP of ±200'-400' TVD/MD. 5. Continue to drill a directional 12 1/4"hole to ±2318' MD/ 2242' TVD short tripping and pumping sweeps as considered necessary. At hole section TD, pump a HIGH VIS sweep and circulate the hole clean. Repeat until hole is slick. Strap out of hole. Note: No elog evaluation is anticipated for this hole interval at this time. NOTE: Prep for stab -in cementing job. PREP for displacing spud mud with MOBM after cementing. NOTE: Make sure that "for all casings" that landing jts and csg ram test jts and cross overs for them ARE ON SITE. Make sure that a top out string is on location. 6. TIH. Short trip. Circulate hole clean at max rpm and gpm. Pump a high vis sweep. Repeat until slick. 7. Condition mud to lower YP and gels (make sure gels are flat). Monitor pill lag and mud log lag times to aid in adjusting cement volumes for hole washout. Circulate hole clean at max rpm and gpm. Pump a high vis sweep. Repeat until slick. 8. Prep for excess mud, cement, rinse water, etc disposal. 9. Calculate landing equipment to make sure we have proper space out with top of landing jt ±4-6' above rotary. Run 9 5/8" surface casing as follows Baker -Locking the shoe track: a) Shoe b) 2 its casing c) Sting -in collar d) Casing With centralizers placed as follows: e) 2 bow -springs with stop collars in center of bottom 2 jts f) Centralizers across the bottom 2 couplings g) 1 centralizer across the coupling of every third jt (Except none from 200' from shoe to 300'. Assumes 200' liner lap) h) NO CENTRALIZER INSIDE CONDUCTOR AS CASING NEEDS TO BE CENTERED IN ROTARY i) ESTIMATED TOTAL centralizers = t23 w/ 2 stop collars 10. Perform a running tag. Reciprocate casing. Circulate and condition mud at a rate not to exceed the AV around the collars while drilling. Again condition mud for flat gels. 11. RU stab -in equipment. RIH w/ DP and stab in sub w/ centralizer, stab in float collar and break circulation. RU cementing head and lines. Test to 500/5000psi. Cement 9 5/8" casing PER cementing proposal with the inner string, cut off cementing when cement `r reaches surface, dump 2-5 bbls on top of sting -in collar. Circulate clean. Cement volumes are presently designed with 500% excess. Adjust as necessary to allow for cement returns to surface. Report amount of returns to surface on daily report. (See note following #16 below.) 12. Pump spacers and displace with MOBM. 13. NO Diverter. Cut casings. 14. Install 9 5/8" slip lock connection X 11" 5M' flanged multibowl wellhead. Test to 50% of casing collapse or 1500 psi whichever is greater. 15. NU adapter spool. NU 11" 5M BOPs. Test BOPs and choke manifold to 250/4000 psi, annular to 250/2500 psi. (AOGCC 48 hr notice). Pipe rams are to be 2 7/8" x 5" VBR's, blind rams, 4" pipe rams (may have variable as well). NOTE: (BOPe MUST be tested every, 7 da s during the remainder of the well. AOGCC must be notified at least 48 houl'§'before) NOTE: Maintain good communications with regulatory. Communicate with the inspector every couple of days just to let regulatory know current opns. 16. Set wear bushing. Run CBL. NOTE: If there is no cement to surface, below are instructions to follow: AOGCC Industry Guidance Bulletin 13-001 Remedial Cementing (aka "Top .lob") for Surface Casing Alaska Oil and Gas Conservation Commission (AOGCC) regulations governing cementing are found at 20 AAC 25.030. Paragraph (d)(4) requires the annular space of surface casing (conductor -surface casing annulus) to be filled with cement from the casing shoe to the surface. An inadequate primary cement job is evidenced by cement not circulated to surface, an excessive quantity of cement circulated to surface, or results of a formation integrity test that indicate insufficient integrity of the casing shoe. Regulation 20 AAC 25.030(d)(4) continues with required actions if an inadequate surface casing cement job occurs. The operator shall: • notify AOGCC before drilling ahead. AND • evaluate adequacy as described (cement quality log or other AOGCC approved method), AND • take remedial action as necessary to meet the design requirements of a well casing and cementing program as outlined in 20 .AAC 25.030(a). The following clarification is provided to address actions that are to he taken in response to inadequate surface casing cementing: • Contact AOGCC as soon as become aware of inadequate cementing using notification procedures outlined in AOGCC Industry Guidance Bulletin 10-OIA: • Prepare a plan for remedial cementing and submit to AOGCC for review and approval (email submittal is acceptable); an Application for Sundry Approvals (Form 10-403) is required; o Include details about primary cement job — volume pumped; any diagnostics prior to cement job to confirm hole size/voltune cement needed (e.g., tracer); problems during cement job; is gas bubblingiflowing?; etc. • Notify AOGCC Inspectors for an opportunity to witness the procedure that will be used to determine top of primary cement in the conductor -surface casing annulus: • Run small diameter pipe or other conduit to top of cement and pump "top job" per approved procedure; • If cannot definitively identify the primary cement top, notify AOGCC before pumping cement and discuss options; g,s `o0 Intermediate/Prod: 1. PU 8 t/2° PDC bit and BHA w/ LWD per directional evaluation program. Clean out casing tooaf i equipment. Test casing to 3500 psi recording on a chart. NOTE: Updated casing test regulations below (e) A casing pressure test must be performed it' 11011F is to he installed on a casing. The casing must be tested to hold a minimum surface pressure equal io 50 percent of the casing internal yield pressure.) REQUIRED WORKING PRESSURE: OF TIIF lil)PI? AS SPECII IED IN "1.111 P1 RMI'I '10 DRILL UNDER 24) AAC 25.035t E) 1:1 OR 20 AAC 25.0-,6(l 1(3).1 :PhE casint pressure test must be field a minimum of 30 minutes and not shoe a decline greater than 10 percent. The results of this test and any subsequent tests of the casing must he i'CCL,rded as required by 20 AAC 25.070(1 ). On a CHART 2. Drill out float equipment and at least 20' of new formation. Circulate hole clean. • Mud Program • Bit Program • Directional Program w/ BHA's • Coring Program • Evaluation Program / 3. Perform FIT on a chart. Email results. Estimated Leak Off EMW is 14.2 ppg emw. If test is less, discuss with office. A minimum of 13.8 ppge is acceptable. Data must be forwarded to AOGCC and approval given before drilling ahead. 4. Condition existing mud to DESIRED properties prior to drilling ahead. NOTE: Drilling ECD's should be monitored at each change of any drilling parameter. Engineered hole cleaning sweeps may be circulated as deemed necessary. 5. Drill ahead per plan. Monitor hole conditions, torque and drag, etc. Trip in and out of hole at a consistent low rate to minimize surge and swab, sit down on slips slowly to minimize surges, turn pumps on/off very slowly to minimize hammer effect, etc. 6. Near ±4300' TVD, make sure mud logs are correlated with Iwd data and OFFSET information to assist in picking the Nanushuk 3 Core Point anticipated at ±4385' TVD. From offset information there are formation markers that will be drilled to assist. Drilling 5' and circulating samples may be used to help pick the core point, but verify with superintendent. 7. POOH. Pick up conventional coring equipment (Coring BHA). TIH and perform coring runs as per the coring procedure and G&G. Handle cores carefully. 8. UPON COMPLETION OF CORING RUNS, OR, as necessary between one or more runs, TIH with core footage length area clean out assembly. (It is anticipated that the clean out assembly will be the same as the drilling assembly.) 9. Continue to drill to ±8222'MD / ±8043'TVD as per program, short tripping and pumping HIGH VIS sweeps as required. MINIMUM flow rate should be 500gpm. Higher if possible. 10. At hole section TD, pump a HIGH VIS sweep and circulate the hole clean. Make wiper trip. Again pump a sweep and circulate hole clean. Make sure pump is at MAX rate. Hole will require more than just circulating bottoms up. Repeat until hole is slick. Strap out of hole. 11. Evaluate hole as per program. NOTE. If the well is potentially productive it is planned to run and cement casing for a well test. If it is determined to NOT test, then a SUNDRY permit (10-403) will be submitted for the OPEN HOLE and WELL abandonment. • Mud Program • Cementing Program • Liner running and setting procedure if a liner. 12. TIH with stinger on drill pipe. Condition hole as before making sure hole is slick. Condition mud to lower YP and gels (make sure gels are flat). Monitor pill lag and mud log lag times to aid in adjusting cement volumes for hole washout and compare to elog value. NO . A decision may be made to set casing short. If so, this Sundry permit / application is made to the AOGCC to abandon the open hole from total depth to approximately 5,718'MD / 5,539'TVD. The preliminary plan is to set an open hole balanced plug will be set with the top at t5,718'MD. 13. Assuming 8 1/2" hole, mix and pump spacer and cement below approximately assuming TD of 8222', 40% excess, with the top of the plug at 5718' (.1375 bbl/ft). Yields ±(8222'- 5718') *±.1375 = t340 bbls cmt. This is ±1930 cult requiring ±1675 sx cement. Fluid 1: Rhcologically Fiilwued spacer CLEANSPAC'ER III 38.52 galbbl FRESH WATER Fluid_': Low fluid Loss PLUGCEM (TM) SYSTEM 0.20 ° e SCR -100 493 Gal'sk FRESH (PATER Fluid Density 10.5 lbin/gal Volume: 35 bbl Fluid Weight: 15.9 Ibud¢al Slum Yield: 1.153 ftYssack Total Miciue Fluid: 4.93 Gal/sack 14. Set the balanced plug pulling out of hole carefully. 15. At top of plug, circulate out at high rate to clean hole and condition mud. 16. Drop slug and TOOK Remove stinger if used and PU plug dress off assembly and TIH. Tag cement and dress off plug to desired casing depth. (NOTE: If plug is not tagged by that depth, continue dressing off until tag. This is the new liner casing setting depth.) 17. Circulate and condition hole as in Step 12. 18. TOOK Pull wear bushing. 19. Change out pipe ram with 7" casing rams in upper ram. Run test joint and test casing ram „r to 3 p�b6 s —Vake sure the appropriate x -over with FOSV is on the rig floor for casing run. 20. Calculate space out and prep as per previous. Run casing as follows Baker -Locking the shoe track: a) Shoe b) 2 jts casing c) Collar d) Casing e) Liner hanger f) Liner top packer g) Liner running tool h) etc With centralizers placed as follows: i) 3 bow -spring TURBOLIZERS with stop collars in center of bottom 3 jts j) 3 TURBOLIZERS across the bottom 3 couplings k) 1 TURBOLIZER across the coupling of every third jt for the next *800' casing (*40) but will be adjusted based on productive zones (*7) I) 1 TURBOLIZER across every coupling next x500' (*12) m) 1 TURBOLIZERS across the coupling of every third jt to surface shoe (±16) n) ESTIMATED TOTAL TURBOLIZER centralizers = *40 w/ 3 stop collars 21. Run 7" casing. Perform a running tag. Rotate and reciprocate casing if possible. Circulate and condition mud at a rate not to exceed the AV around the collars while drilling. Condition mud to have flat gels. 22. Cement 7" casing per cementing and liner running procedures (attached) (cement design is to address low fluid loss, formation compatibility of filtrate, RIGHT HAND SET) while rotating casing. Cement volumes are presently designed for cement to surface with 40% excess. Adjust volumes as necessary to insure top of cement is at liner top. 23. Once liner is set, release running tool, circulate cement off LT, set ZXP liner top packer, test backside to 3650 psi. 24. TIH w/ mill and scrapers spaced out for casing lengths. Work same. Circulate casing clean. 25. Run CBL. Forward same to AOGCC. 26. Displace with completion fluid. Well Test/ Completion (For information ONLY): 27. Completion Procedure will follow with a Sundry application. N.RN BAKER NUGNES Baker Oil Tools Baker Hughes Cemented Liner [Type text] Generic Running Procedure Running Procedure: • MU shoe track. Baker -Lok all connections below landing collar and check floats (Float Check Procedure: Fill shoe track with mud/brine. PU shoe track and drain fluid level through the floats into well. Run shoe track back into well and visually confirm no back-flow into the shoe track.). • Keep liner full while running in hole. Fill every 5-10 joints while running. • Monitor pick-up and slack -off weights while running. Record PU and SO weights. • Verify lift sub has been made up if needed. • MU Baker Liner Hanger and Liner Top Packer. o Elevators need to be slacked off while making up liner hanger to prevent liner running tool from secondary releasing. o Slack off to place top of tie back extension at rig floor. Fill tieback extension with Xan Plex-D. Xan Plex-D will gel while rigging down casing tools and preparing to run drill pipe. The liner can be reciprocated until ready to run drill pipe. • RIH with liner on drill pipe no faster than 1 minute per stand (90 ft/min). Watch displacement carefully and adjust running speed accordingly. o Slowly run in and out of slips. o Make up top drive and fill pipe every 10 stands. • Circulate 1-/z drill pipe and liner volumes at 7" shoe prior to going into open hole. Stage pumps up slowly watching for fluid losses. Do not exceed 1,800 psi while circulating. Obtain up and down weights of liner before entering the open hole. • If rotation is anticipated during the job, rotating parameters should be established in casing test @ 10, 15, and 20 RPM and every 2,000' while running to open hole. Torque and Drag analysis should be used as a reference. • Stage pump rates up slowly to circulating rate without exceeding 1,800 psi. Circulate a minimum of one bottoms up at the desired cementing rate while limiting rate/pressure to avoid setting liner hanger or initiating losses. Reciprocate string during all circulating and cementing operations if hole conditions permit. Pump Cement Job per CoP plans. • Drop DP dart and displace cement with rig pumps utilizing mud. o Ensure to completely function Plug Dropping Head as per Baker Field Specialist's Surface Cementing Equipment Spec Sheet. Flag sub will provide a positive confirmation when plug has been dropped. o Rotate and reciprocate as needed p.RG BAKER NYGNES Baker Oil Tools Baker Hughes Cemented Liner [Type text] • Position liner at setting depth and reduce pump rate to 3 BPM 7bbl prior to latching DP dart into Liner Wiper Plug. Observe LWP shearing off and resume pumping at desired displacement rate. Make first movement downward if pipe is to be moved again. If elevated displacement pressures are observed during displacement, position liner at setting depth and cease reciprocation. • Displace the cement with the rig pump, slowing rate as directed by Baker Field Specialist — 2-3 BPM and bump the plug. • Pressure up to 2000 psi as per Baker Field Specialist to set the liner hanger (typically 15% above nominal setting pressure). Need to consider possible hydrostatic imbalance due to lifting heavy spacer and cement above liner top as this will increase pressure required to set the liner hanger. • Slack off total liner weight plus 50k down hole to fully set liner hanger. • Continue to pressure up to 3000 psi to release HRDE running tool. • Apply 500 — 1,000 psi to the 4" drillpipe and pick up slowly to pull pack off. Once the standpipe pressure drops, engage pump to wash residual cement from liner top. • Pick up until packer dogs are above liner top per Baker Field Specialist. • Set down 50 klbs minimum at the tool. Rotate as necessary to get weight down to tool. • Pressure test wellbore as required. o Note that packoff has now been pulled from liner equipment and any pressure applied at this point will be to the entire wellbore. ri.� �eeR Nuc�Es Completions F�wER gEu �BttPe papEECRIPrpX CpClb. REV No. Run Lprerta tlesiretl tlapN. Pum{r cement pD. Gasecemem wiN Dnll Ripe Pump Oovm Plug 6 Pi-kuptoexpose Me Padrer Seairg Dog Sub. bib I 66 I Stark off regwratl amours ofwegN to set Liner Top Packer, I I test baIXsige as I I requretl. I I I I I I an.ww Na.mw I g@@xanNvow ®o6 I I ° sa— I I I I I I I I I I I I �_xao-eunerx.mNv FUMer increase I prereure to release zxr umc Top wger ° HRD-E Liner Runnng tool. SIOMy Dleetl off preEsure ro LYraIX Hosts soil LWP. Spaceout of RS PeIX Will be Slick encu Will be long dog s Rev.eon..a jm�ntry so ose sub sing seal ® ® gngaealon ess ei aNIX 4 joint.sia vs�nlial After LWP lands, p teet soil rpoxar setuner coranua to pressure neeoetl. Huger ~ up on DY t0W Uner Hanger. SlaIX off to wndrm Hanger ieW wro...e.xaeaa-� ww NaaemeN cN.urue� .—saes w.wrt°.; 2 WMn Pump Down Plug Iantlsin finer Wiper Plug, pressure up to sneer release LIAR COMinue PunPicg LWP to IaMing celWr. IaMNYCq..-1 RotateaM redpracero lirroras neatletl. roncm� -a M.%. Quote Drawing Title CUSTOMER: Armstrong Energy, LLC FIELD: Cdville River DATE: 1114/2016 WELL NO: Horseshoe 1 REFERENCE: Rev.2 DRAWN BY: D.Callis APPROVED BY: ri.a BAKER HUGHES OD ID LENGTH WELL SCHEMATIC DESCRIPTION 1. ZXP-N with HRD Profile MATERIAL 8.350 IN 6.790 IN ID 12ft OD LONG DESCRIPTION: ZXPN LINER PACKER W/HRD-E PROFILE HRD-E & RS PROFILE 7.625 IN 29.70 1 LB/FT VAM TOP HT BOX DOWN 09.625 IN 47.0-53.5 LB/FT CSG 8.250 IN EXT OD 7.625 IN EXT ID 10.00 FT EXT LG 125 KSI MYS (API SCT) EXT 8.350 IN OD 6.790 IN ID (MUST DRIFT 6.750) 6.875 IN PKOFF DIA 50,000 LBS 21 SETTING FORCE 7.265 OD COLLET (H078479700) 125 KSI MYS (API 5CT) 7.66 6.28 lft _ 2. XO, 7.625' 29.7 LB/FT VAM TOP HT Pin up x T' 26 LB/FT Box dwn, P110 3 8.33 6.18 Soft 3. Flex -Lock IV Hydraulic Rotating LONG DESCRIPTION: LINER HANGER FLEX -LOCK IV HYDRAULIC ASSEMBLY = ROT W/NLHR 7.000 IN 26.00 LB/FT VAM TOP HT PIN UP 7.000 IN 26.00 LB/FT VAM TOP HT PIN DOWN 09.625 IN 40.0-53.5 LB/FT CSG 8.334 IN OD 4 6.184 IN ID (MUST DRIFT 6.151) NITRILE SEAL 1,208-1,633 PSI SHEAR 15% SHEAR SCREWS 10.00 Fr LG KIT MOUNTED ON TOP BMS -P128 L80 GEN PURPOSE TBLR 80 MYS 22RC, 80 KSI --= 5 MYS (API SCT) BOY 22RC, 80 KSI MYS (API SCT) KIT WORLDWIDE STANDARD 6,202 PSI COLLAPSE RATING 9,269 PSI BURST RATING 6 4. Liner as needed 7 6.141 IN 2.890 IN ID S. Insert Type 1 OD & LONG DESCRIPTION: LANDING COLLAR INSERT TYPE 107.000 IN 9 23.0-26.0 LB/FT CSG F/6.151 IN MIN CSG ID F/6.466 IN MAX CSG ID 6.141 IN OD 2.890 IN ID 6. Shoe Track Joint 7. Single Valve Float Collar 8. Shoe Track Joint 9. Float Shoe Copyright p 2010 Baker Hughes Inc. All rights reserved. Armstrong Energy Horseshoe 1 Well Plug Back using BHKA Disconnect: 1. Prior to cementing: • Check cement lab test for sufficient pumping time including shutdowns, free water and fluid loss. • Discuss job with cementer and customer, double checking calculations for water, displacement, etc. • Verify all hoses and lines are in good shape and on site. Have extra hoses and high pressure pump iron available. • Ensure that circulating swage appropriate for Drill Pipe is on location. • Ensure that appropriate circulation rates are achievable within pressure limitations of iron and equipment. • Ensure that well is static. • Total Water Required for the job: 300 bbl heated to 70-80 F, this number assumes that any displacement not explicitly described below as using spacer will be drilling mud or some other fluid from the rig. Cement the casing as follows: Tie into drill pipe and pump cement through that and sacrificial tubing down to TD and back to tool. Sting out of tool and wash drill pipe. Spacer: 5 BBL Use Fresh Water to pressure test cementing iron Spacer: 40 BBL CleanSpacer 111 10.5 ppg Lead Slurry: 1200 SK Class G Cement + Additives 15.8 ppg 14113131- 41BBLExcess Excess40% Displacement Spacer: 5 BBL Use fresh water to clean truck and lines Displacement Fluid: 57 BBL Displacement Fluid -62 BBL Total Displacement Estimated Top Cement Slurry 5718 ft PROPERTIES Lead Slurry Weight 15.8 Yield 1.155 Water 4.92 Note: The final slurry design will be provided after testing cement, additive and mix water samples prior to performing the job. Volumes assume TD is 8222 ft and BHKA disconnect is set at 5718 ft. 2. After Cementing each stage, record the following: • Time cement in place • Pressure used to displace. • Amount of barrels pumped behind cement. Armstrong Energy Horseshoe 1 Well Cementing 16" Conductor Casing: 1. Prior to cementing casing: • Check cement lab test for sufficient pumping time, free water and fluid loss. • Discuss job with cementer and customer, double checking calculations for water, displacement, etc. • Verify all hoses and lines are in good shape and on site. Have extra hoses and high pressure pump iron available. • Ensure that appropriate circulating swage/tie-in is on location prior to running casing. • Total Water Required for the job: 150 bbl heated to 70-80 F Cement the casing as follows: Pump 5-10 bbl of Cement into the inside of the conductor casing and allow to set. Tie into provided iron to pump cement into annulus between conductor and OH. Spacer: 5 BBL Use Fresh Water to pressure test cementing iron Lead Slurry Cement 410 SK Class G Cement + Additives 15.6 ppg, 71 BBL This also includes 1.5 ft of fill in the cellar Open Hole Excess 50% Displacement Spacer: 5 BBL Use fresh water to clean lines Estimated Top Cement Slurry Surface PROPERTIES Lead Slurry Weight 15.6 Yield 0.96 Water 3.81 Note: The final slurry design will be provided after testing cement, additive and mix water samples prior to performing the job. 2. After Cementing, record the following: • Time cement in place • Pressure used to place. • Amount of barrels pumped behind cement. • If and when cement was seen at surface. Cementing 9-5/8" Surface Casing: Prior to cementing casing: • Check cement lab test for sufficient pumping time, free water and fluid loss. • Discuss job with cementer and customer, double checking calculations for water, displacement, etc. • Verify all hoses and lines are in good shape and on site. Have extra hoses and high pressure pump iron available. • Verify that wiper plugs are loaded in cementing plug assembly. • Drift casing prior to running. • Ensure that 9-5/8" circulating swage is on location prior to running casing. • Total Water Required for the job: 550 bbl heated to 70-80 F Cement the casing as follows: Bump the plug with 500 psi over circulating pressure. Immediately prior to shutting the pumps down record and report the pump pressure ON A RATE/TIME/PRESSURE basis ±5-10 minutes. Hold pressure for 5 minutes. Release the pressure and confirm the floats are holding. Do not over displace by more than half of the shoe volume. Spacer: 5 BBL Use Fresh Water to pressure test cementing iron Spacer: 40 BBL CleanSpacer III 10.5 ppg Lead Slurry: 800 SK Class G Cement + Additives 11.1 ppg Permafrost L 592 BBL Excess 500% Tail Slurry: 235 SK Class G Cement + Additives 15.8 ppg 49 BBL Excess 40% 500 ft of fill Displacement Spacer: 5 BBL Use fresh water to drop Top Rubber Plug Displacement Fluid: 19 BBL Displacement Fluid —24 BBL Total Displacement Estimated Top Cement Slurry Surface PROPERTIES Lead Slurry Weight 11.1 Yield 4.15 Water 21.41 PROPERTIES Tail Slurry Weight 15.8 Yield 1.16 Water 5.03 Note: The final slurry design will be provided after testing cement, additive and mix water samples prior to performing the job. Displacement design assumes 4" 14 ppf drill pipe inner -string and 126'shoe joint. 2. After Cementing, record the following: • Time cement in place • Pressure used to displace. • RATE/TIME/PRESSURE after slowing down in anticipation of bumping plug. • Amount of barrels pumped behind cement. • Amount of barrels bled back to check floats. • When and if returns were lost while cementing. Cementing 7" Production Liner: 1. Prior to cementing casing: • Check cement lab test for sufficient pumping time including shutdowns, free water and fluid loss. • Discuss job with cementer and customer, double checking calculations for water, displacement, etc. • Verify all hoses and lines are in good shape and on site. Have extra hoses and high pressure pump iron available. • Verify tool operations and plug dropping order and procedures. • Drift casing prior to running. • Ensure that circulating swage appropriate for Drill Pipe is on location prior to running casing. • Total Water Required for the job: 300 bbl heated to 70.80 F, This number assumes that any displacement not explicitly described below as using spacer will be drilling mud or some other fluid from the rig. Cement the casing as follows: Bump the plug with S00 psi over circulating pressure. Immediately prior to shutting the pumps down record and report the pump pressure ON A RATE/TIME/PRESSURE basis + 5-10 minutes. Hold pressure for 5 minutes. Release the pressure and confirm the floats are holding. Do not over displace by more than half of the shoe volume. Note: The final slurry design will be provided after testing cement, additive and mix water samples prior to performing the job. Calculations assume a 90 ft shoe joint. 2. After Cementing each stage, record the following: • Time cement in place • Pressure used to displace. • Pressures to open/close the tool • RATE/TIME/PRESSURE after slowing down in anticipation of bumping plug. • Amount of barrels pumped behind cement. • Amount of barrels bled back to check floats. • When and if returns were lost while cementing. Liner Top at 2118 ft Spacer: 5 BBL Use Fresh Water to pressure test cementing iron Spacer: 40 BBL CleanSpacer 111 11.0 ppg Lead Slurry: 115 SK Type I Cement + Additives 12 ppg 51 BBL Excess 40% Tail Slurry: 250 SK Class G Cement + Additives 14 ppg 68 BBL Excess 40% 2000 ft of fill Displacement Spacer: 5 BBL Use fresh waterto drop Drill pipe Wiper Dart Displacement Fluid: 125 BBL Displacement Fluid: 10 BBL Spacerto cover the liner lap Displacement Fluid: 17 BBL Displacement Fluid —157 BBL Total Displacement Estimated Top Cement Slurry 2118 ft PROPERTIES Lead Slurry Weight 12 Yield 2.48 Water 14.68 PROPERTIES Tail Slurry Weight 14 Yield 1.53 Water 7.76 Note: The final slurry design will be provided after testing cement, additive and mix water samples prior to performing the job. Calculations assume a 90 ft shoe joint. 2. After Cementing each stage, record the following: • Time cement in place • Pressure used to displace. • Pressures to open/close the tool • RATE/TIME/PRESSURE after slowing down in anticipation of bumping plug. • Amount of barrels pumped behind cement. • Amount of barrels bled back to check floats. • When and if returns were lost while cementing. NjjExA,,V Planned Wellpath Geographic Report - includin Position Uncertainty 1]191)af18:15 iiiii.W. 7/ TM Alaska SP, Zom 4 V100in. rmemng Emrgy,LLC hue OM Slope, mat 0.999922 :r ding contain. LLC Norld Slope Sbt - ArcBc Fox (HT) Orse5lroe Nt AmBFk (RT) orse'norl Mn Sea Level o uichnslrsesroeserl Rea G-01! )t mbkere N 0.0011 Midmain Pol i.e qq p> Magr48c NOM s 17,26 degrees Eaet of True NOM 00etl .00 SW Ow aG43 0011 US feet -0.lt 031 388288.0 566]909.00 70°02'48595'4 15l°0703.WVV 200 En 100 380290.31 5867909.10 ]0°0248.596'4 15l°OT03.980"W 2000 300 3609111 8867922.00 I ]0°0248.]28°N 151°0703.278'88 Sort MD fit 4300 22]330 End NO Jill 22]330 OnTrek SAG, 822191 OnTrek (SAG P-ilicont Unssroard, el No- I Comment el Hor9eed Noreae0oaM1 -' S11,111[alloNer 1 25in nHde S�Itei 000 Enil 2273.33 It 22]3.30 Sdi�: TVD 0.00 End TVD 2242.00 Star NIS Start E'S Eno .W 0.00 NIS 29 Eno E. 0,00 Hor5as8ae81 Itslanor, 9625in Gari 1150 22]330 225580 1].50 air iii 00 i 000 207.29 000 Horaeetae8l _' B.BnO an Hole1 22]3.33 1 8221.91 I 594881 I 2242.00 I 8843.00 I 29]29 I 0.00 I care i I 823.96 liddemenearead _ Ta,,e, Narl am6M1Ok3 Core Point Rw-1) MD 462181 TV(D 444300 Nero 614.52 East 623AE7 Cril 360925.62 Grid North 5888641.92 Latitude Lnohose ]0°02'54.994.4 151°06'4601988 Sl,,,;, point Comment I'D 000 cl,ralion rimmuth 000 0.00 TvD OOD T\GSS 43M North 000 East 0.00 Grid Earl 300290.00 Grid North 586790900 Latitude Longitude 70°0248.595'4 151°OT03989W DLS 000 Toolder 000 Solid Rate Turn 0.00 Rate 000 Vert Sect 0.00 Me tir Searri Minor Semi Vert Semi O.DO Jill Arion 000 17.50 000 000 17.50 -25.50 000 0.00 360290.00 586]909.00 70°02'48585'4 151°0703.98988 0.00 0.00 000 0.000Oo _0.00 _0.00 O.OD 000 000 Tie On 11]50 21150 0.00 of GOD 0.00 117.50 21].50 74.50 174.50 000 0.00 OW 000 380290.00 38028000 58679M 00 586]90906 70°02'48 S95'N 151°0703.98088 70°02'48.595°N 151°0703.98988 0.00 000 000 000 000 0.00 _000 000 000 0.00 000 40.20 40.20 40.20 60.20 6.73 STS 0.00 0.00 317.50 0.00 000 317.50 274.50 0.00 0.00 388290.00 6867908.00 -- 7WU48.Still 151°0703.98888 0.00 am 000 0.00 000 40.21 40.21 6.74 000 400.00 41150 0.00 0.00 0.16 000 400.00 61].50 357.00 3)4.50 0.00 0.03 OW 0.00 360250.00 350260.00 5867909.00 5867906.03 70°0248885'4 151°0703.98988 MM'48.595'N 15110T03.9891Y 0.00 1.00 0.00 000 0.00 1.88 0.00 000 0.00 0.02 0.22 4022 40.22 40.22 8.]4 6.74 0.0_0 21378 EM of TaMer4 51150 1.18 OW 517.0 474.49 120 0.00 380290.02 70°02'A&l 15110703.98888 1.00 Goo 1.00 Goo OB] 40.21 60.24 6.75 2)042 61150 2.18 0.00 61]45 Si 4.13 0.00 380290.08 _586]910.20 586]913.13 70°02'48688'4 151.OT03.98BW 100 000 100 0.00 288 40.28 40.25 8.76 270.37 ]1].50 3.18 000 71134 874.34 8.]9 0.00 380280.16 586791].78 70°0248882'4 151°0703.88888 1.00 000 100 0.00 8.32 40.28 60.27 6.78 270.53 817.50 4.18 000 81).13 714.13 15.20 000 360280.28 586]920.20 70°0248.74$'N 151°0703.98988 100 000 1.00 0.00 10.92 40.31 40.30 8.79 270.75 81150 5.18 0.00 91683 873.83 23.35 0.00 380200.43 586]032.35 70°0208825'4 151°0703.98088 100 000 1.00 0.00 16.78 40.34 60.32 6.81 2]1.08 1017.50 6.18 OOD 1016.31 9]3.31 3324 0.00 350290.61 Wits 2.23 ]0°0248.922'4 151°OT03.989W 1.00 0.00 0.00 23.88 40.3) 60.38 8.82 2]1.60 1117.50 ].18 0.00 1115.83 1%2.63 44.87 000 380280.82 588]953.86 ]0°02'49.038'4 151°0703.969'88 100 000 _=.W. I'M 0.00 32.24 40,41 4038 8.84 2]2.52 121150 8.18 000 1214.73 1171]3 5822 0.00 350281,07 5887957.21 70°O2'ASAWN 1St°0703.90988 1.00 6.W 100 0.00 41.83 40.45 4DA_4 8.87 2]4.]3 131).50 9.18 0.00 1313.58 1006M 73.30 000 380281.34 5867862.29 70°0249.316'4 151.OTO3.889'Vd 1.00 Ow 1.00 0.00 52.6] 40.49 60.40 669 28!.18 141)50 10.18 000 1412.18 1369.111 80.11 000 380291.65 5867999.09 MNIZ49A81'N 151°0703.889'88 100 000 1.00 0.00 BATA 0.55 40.54 Sol 349.10 151]50 11,18 000 1510.0 146].43 108.83 0.00 36020199 Willi 70°0249664.4 151°D703989W 1.00 000 1.00 0.00 ]805 0.62 10.58 8.95 355.31 1617.50 12.18 000 1808.38 1585.88 128.8) 000 360282.36 5668337.84 70°0249.883'4 151°OT03.988'YJ 1.00 0.00 1.00 0.00 W59 0.70 All 8.98 356.94 _1717.50 _ 13.18 0.00 1705.92 155292 lWAl 000 388282.71 5868359.7] 70°0250.078'4151°0703989'88 IN 000 1m 0.00 10835 0.79 0,69_ 7.02 357.88 18450 W.tB 0.00 Vol 1780.08 9445 0.00 350283.20 5868383.41 _ _ - 7010250311'4 154°070398888 1.00 0.00 1.00 000 125.34 0.89 60]5 ].O6 - 358-12 1917.50 15.18 0.00 1899.62 1856$2 199.79 000 350293.86 5868108.74 70°02'50.588°N 151.0703.969'88 100 O.00 100 000 143.54 4101 0.81 7.10 MAO 2000.00 16.00 000 19]9.28 1036.29 22195 000 360284.0] 5886130.60 70°0250.778'4 151°070389888 1.00 000 1.00 000 158,47 41.12 40.86 ].14 350.58 liof Bulb W1).50 18-00 OW 1906.11 1953.11 228.)8 0.00 380201.16 5888135.72 7010250826'N 151°070391i 0.00 000 OW 0.00 162.93 41.15 408] 7.14 358.81 2117.50 ISM 0.00 2092.23 2048.83 254.31 000 36029486 586818328 70°0251.097°N 151.0703.96988 0.00 000 000 0.00 -1 V-7-4 4130 41 7.20 358.]] 221150 1600 000 2188.36 2145.38 281.91 000 360285.17 5889190.64 70°0251388'4 151°0703.989'88 0.00 000 000 0.00 202.54 41.47 6100 ].25 3_W 227330 16M 000 220.00 2199.00 29729 000 350285.45 5888211821 70°0251.519-N 151°0TO3.989W 0.00 000 000 0,00 21359 4154 4102 7.28 358.95 Tangent anm4 Eno gairet, 231150 16.00 000 2281.0 2241 A9 MAT 000 38020567 5888218.39 70°02'51 p8°N 151°0TOSMIN 0.00 000 000 000 222.35 41.58 41.02 128 358.03 2323.30 1600 0.00 2290.08 2247.08 3110] 0.00 360211 588821999 ]0°0251.655'4 151°oT03.986^N 000 102.72 000 low MAO 4159 4102 ].28 388.04 EM ofT nt 2417.50 15.62 10.20 2380.]2 233172 336.53 2.27 380298.44 5888245.41 70°02'51905'4 151.OT03WIM 3.00 92.82 .0A1 low 243.36 41.70 41.03 7,33 359.71 Ell 1515 216A0 247/.02 2434.02 1 36242 962 380308.27 nilie .)5 70°0252.18874 151°OTO3.712VJ 300 82.12 0.13 11.10 2157.08 41.84 41.04 7.38 1.55 281].50 18.0 3108 25]3.12 2530.12 38705 22.05 360319.15 Edell 70°02'S240214 151°0703.35488 300 71.0 0.88 1 lo.58 20.43 42.00 41,05 7.43 303 2)1].50 1258 41.44 2568.7 2625]] 410.88 39.51 38033].00 5058318.55 7WW52831'N 151°01`02,851 3.00 1.16 948 322.35 42.16 4107 7.49 6.0 2817.50 19.13 41 2763.69 2720.88 43231 62.02 380358.03 585&3400] M -02'52&]'N 151°0702.20317 3.00 115 817 3075 42.34 41.09 7.54 9.20 291150 2098 55.51 285).84 2814.64 452.81 8944 36038)72 5885360.06 ]0°02'53.00'4 151°OTO'A13W SOD 185 689 387.% 42.53 41.11 ).61 1223 301],50 23.0] 6228 2850.35 2907.35 471.62 121.72 38042034 68883784] ]0°02'53.236'4 15l -0T00_.4 W 300 2.88 5.76 423,65 42.]4 41.14 ).88 15AB 311],50 25.X1 67.08 3041.58 2888.56 All 158.7] 36045]70 5868395.24 7P02'5307N 151.OB'S9AIBW 3.00 2.26 982 461.96 42.9] 41.1) 7.76 18.943217.50 072 ]1.13 313103 308803 505.13 200.49 36008.]0 nni 70°0253553'4 151108'S8215V 300 RW,144 2.39 405 502.38 43.23 41.22 TOO 22.64 3235.36 28.18 71.]9 310.81 310381 881]0 208.0 38050]69 5863/1284 70°02'53. Sit 151.OF57.9WW 300 2 6 3.67 509.81 0.27 4123 TN 23.31 F41tlof 3D Arc XS3317.50 26.16 ]1.79 3210,23 317823 51991 24525 360544.)2 56646/26 lil 53T09'N 151°OBSBfltBW 0.00 Om 000 54113 43.49 6128].93 El qp3417.50 28.16 71.79 330].88 3264.38 534.86 29008 388588.82 586&38.21 70°0253854'4 I51•U5'55634W 0.00 000 000 585,91 43.79 41.34 8.02 33.05351).50 28.16 7119 Stil 5 3352.55 59941 334.82 380634.91 Still.14 70°0253909'4 151.08'64.3088 0.00 000 000 82).69 44.12 61.41 8.12 33.38381].50 2816 71]9 3488.]1 340.71 564.18 3]975 360680.00 505846606 ]0102'54.144'4 151°08'S3.052W 0.00 000 0.00 559.47 46.50 41,47 822 38.43 Page 1 of 2 II• 388316 28.16. 71.M 35/160 349860 573.85 409.18 38070881 5%647521 70°9254.239'N 151°08'52.2"'W 0.00 -180.00 0.00 0.00 696.91 ".n 4152 8.29 38.28 Erq ofT M X67 3]1)50 2].13 71.79 35]2.02 3529.02 578.3] 424.32 3WM4.83 5888479.91 10°02542"'N 151°O6'51.768'W $.00 -180.0 -3.W 0.00 711.01 04.91 41.5/ 8.33 39.17 3811.50 24.13 71.72 3682.17 3619.17 59235 485.41 360768.16 5666492.67 70°0250."1"N 151°O6'W.5NM 300 1W.00 -300 0.00 149.31 45.33 41.62 8." 41.38 3917.50 21.13 ]1.19 3)54.0.5 3711.45 fiC9.39 50198 36083292 588850/.02 70°02".539'N 15YOWY ZW3 3.00 183.00 3.00 0.00 )83.37 45.]3 41,70 8.61 4296 4017,50 18.1$ it70 384863 3W563 614.88 533.8) 36083501 566651394 7WO254.642'N 151°06'.813'W 3.00 180.00 300 0.00 313.fl 06.10 4118 375 44.20 411].50 15.13 11.79 3"4." 3901.44 62382 561.06 360862.% 5668522.38 70°02S0.J30'N 151°06'47.833"W 3.00 183.00 -300 0.00 838.44 46.3 4186 8.89 45.13 421).50 12.13 71.72 4041.61 3986.81 831.19 583." 360884.81 5868529.33 70°02'54803°N 151°O6'47.186'W 3.00 183.00 -3W 0.00 859.31 ".71 418» 9.01 45.82 431]50 913 71.79 4339.89 409386 896.95 600.97 380802.50 5888534.78 7P 54.8W"N 151°0646.681"W 3.00 163.00 -300 0.00 i 875.60 49.95 42.8 9.13 46.28 "17.50 6.13 71.]9 423698 4195.93 6/1.10 613.56 380915.18 566953810 7TO7M.900'N 151°OB'45.317 W 3.00 183.00 3.00 0.00 987.40 4).13 42.15 9.25 46.55 4517,50 3.13 )119 4338.84 4295." 80363 62125 390922.90 5868541.08 70°0250.WFN 151°W'46.W]"W 3.00 183.00 300 0.00 68450 47.27 /2.25 8.38 48.65 461750 0.13 11.]8 "3350 4395.59 6".52 62398 360925.52 5688541.92 7VOZ54934"N 151°W'".019'W 3.00 163.00 -3.W 0.00 88).0] 47.38 42.34 91" "W 4621.91 O.0 71.19 44".00 "00.0 6".52 823.85 36092582 5668541.92 )0°0250.934"N lsrw'"8Ol'W 3.00 0.0 -300 -1828.82 887.0] 47.36 42.35 9.47 ".58 Dr X6 4)11.50 0.00 71.72 "38.59 "95.58 8".52 623.96 39082562 5888"1.92 7VW549W'N 151°O6'".Ot9'W 0.00 060 0.0 0.00 897.0] 47.41 02.41 9.56 ".61 4alTW 0.00 )119 "38.59 4595.59 6".52 62396 390925.62 5888541.82 70'0254934"N 151°O6'".019'W 0.00 0.00 0.0 0.00 69).07 47.47 42.48 9.67 "62 491].50 0.00 ]1.72 4728.58 4695.59 611.52 623.96 3W925.62 5880541.82 70°0254.934"N 151.06'".019"W 0,00 0.00 000 0.00 W1.07 47.53 42.55 9.78 ".63 5017.50 0.00 71,78 483359 4795.59 "4.52 823.98 380825.62 5666541.92 )0°02'54.934"N 151"0603019'W 0.00 0.00 000 0,00 891.0] 47,59 42.62 9.89 5117.50 060 7119 4938.W 4W5.59 649.52 823.86 360925.62 5814541.92 70°0254.9t4'N 151.08'".019W 0.00 0.00 0.00 0.00 891.0) 4768 42.10 10.01 "." $217.50 0.00 71.72 5038.59 "95.58 8".52 623.90 380925.62 5888541.92 70°0254.934"N 151°O6'".019"W 0.00 0.00 0,00 0.00 887.0] 47,M 42.78 10.13 ".67 531].50 0.0 7119 513359 NOS.% W0.52 823.88 360925.62 5668541.92 7202'54.9""N 151b6'".019'W 0.00 0.00 060 0,00 891.0] 47.80 42.8) 10.25 ".68 "17.50 0.00 ]t.79 5236.59 5185.58 6".52 623.96 380920.62 5888541.82 70°0254.93a'N 151°06'".019"W 0.00 060 0.00 0.00 88).0] 47.87 4295 10.36 ".69 551].50 0.00 71]9 5338.% 5285.59 644.52 823.96 360925.62 5668541.92 70°02549""N 151°08'".019"W 000 0.00 060 0.00 897.0] 4795 "." 10.51 ".71 581]50 0,00 71.79 5038.58 5385.58 644.52 MN 360825.62 5988541.92 70°0254, W'N 151°OB'".019"W 0.00 O.W 0.0 0.00 897.0] ".03 43.13 10." ".M 571750 0.0 7119 55M 59 55,% W4.52 623.98 380925.82 568854192 70°02'".9"'N 151.06'".D19'W 0.00 0.00 0.00 0,00 89!.07 ".il 43,23 10.78 ".73 5817.50 0.00 ]1,]9 5638.59 5585.% 64452 623.96 380925.62 SB88"1.92 IVM9 .9W°N 151°06'".019'W 0.00 0.00 0.0 0.00 897.07 48.20 43.33 10.92 46.74 5917.50 0.0 71.72 5738.59 569559 6".52 823.98 360825.82 5868541.92 10 54.9W"N 151°06'".019'W 0,00 0.0 O.W 0.00 887.07 ".28 "A3 11.08 06.78 &31].50 ON ]119 5636.59 5195.59 604.52 623.96 360825.62 5"8541.92 70°02'".9W'N 151°"'".019"W 0.00 0.00 0.00 0.00 897.07 ".37 4353 11.21 48." 611).50 060 71.79 59M 5895.59 W4.52 MIN 360925.62 5668"1.92 70°0 4,WN 151°"'48.019W 0.00 0.0 0.0 0.00 897.0] "." 43.W 11.38 4.78 6217.50 060 71.79 60:]8.59 5985.59 a".52 623.96 380925.62 M" 1.92 70'92W.WN 151°OBY6.019W 000 000 000 0.0 881.0) ".58 0.3.74 11.51 4680 8317.50 0.0 71.79 6136.59 6085.511 6".52 623.98 3W925.62 5868541.92 ]0°02'54.9"'N 151°OB'".919W 0.00 0.00 0.00 0.00 697.0] ".65 "." 11.67 "81 "17.50 0.0 7119 6238.% 619559 "4.52 M,N 36082562 5868W192 70°02'W.9W'N 151°O6'".019'W 000 0.0 0.0 0.00 887.0] ".15 ".97 11.83 46.82 651750 0.00 7118 6338.58 628559 W u 823.98 380925.82 5868"192 711°0264.9W'N 151°08'".019Y0 0.00 000 0.0 0.00 887.0) ".85 ".O9 1199 ".83 681).50 000 ]118 "38.58 8395.59 6W.52 823.96 360925.82 586854192 70°0250.9"'N 151°08'".019"W 0.00 O.W 0.00 0.00 897.0) ".98 1420 12.16 ".85 6717.50 881].50 681].50 0.0 0.00 0.00 71.72 ]l.]9 71.79 6538.59 8838.59 6728.59 "85.58 6%59 6695.58 8".52 6".52 8".52 623.86 _623.98 62398 360925.62 380925.62 360925.62 5868541.82 5868541.82 SB685C1.92 ]0°0254.RW'N 151°06'".01M 70°0254.% N 151°O6'".019'W 70°02'54.934'N 151°W'4 olm 000 0.00 0.00 0.0 0.00 ON 0.0 ON 000 0.00 0.00 0.00 89).07 891.0] 8%.0) 49.6 49.17 4928 4433 44.45 ".58 1233 12.51 1266 ".86 ".81 "89 ]01].50 0.0 ]1 19 6838.59 6]9559 "4.52 823.98 360825.82 586854192 70°OZ'U4. -N 151°OB'".019W 0.00 000 0.0 0.00 887.07 49.0 4471 12.87 "90 )11].50 0.0 71.79 6636.59 6885.59 6".52 623.96 360925.62 586854192 70°02'S4,IX N 151°"'".019W 0.00 0.00 0.0 0.00 89).0] 09.51 44" 13.05 "9t 7217.W 0.0 ]t.79 70M% 8895.59 a".52 623.86 3W925.62 5868541.92 M0° .9"'N 151°O6'".019'W 0.00 0.0 0.0 0.00 69).07 49.63 ".97 - 13.24 ".92 7217.50 0.00 ]I.>9 7138.58 ]09559 6".52 623.98 380925.62 5868641.92 70°02549WN 151°O6'46.019W 0.00 0.0 000 0.00 897.01 4915 4511 13" ]41].50 OW 71.79 7238.59 7195.59 6".52 623.96 360925.62 5068"192 10°02'54.9W"N 151°OB'".019W 0.00 0.00 0.00 0.00 997.07 0987 /525 13.0 ".95 ]511.50 ]61].50 0.0 0.00 71.]9 11-79 7338.58 193358 _7285.58 ]395.59 8".52 60/.52 623.98 823.98 360925.62 360825.82 5898541.82 5088"t 92 M0 54934'N 151°O6'46019'W ]0°02'S0.934'N 151"OB'".019W _0.00 0:00 O00 O.M 000 0.0 0.0 0.00 887.0] 897.07 50.00 %13 4539 45.53 1383 14,W ".98 498 _ )]1].50 0.00 ]1.79 7536.59 ]495.58 W4.52 623.96 360925.62 5%8"1.92 ]0°02'54.934"N 151"OB'46019V 0.00 O.W 0.0 000 89].0] W.25 05.68 1 14.24 "99 7817.50 O.W 71.79 7838.58 7585.59 8".52 623.96 3W925.62 5"8541.2 ]0°0254.934"N t5t°O6'a60t9'W 0.00 O.W 000 000 BB].07 50.38 45.33 14." 4].00 ]Bt].W 0.00 ]1.]9 7]38.59 7685.59 6".52 823.96 380825.62 5088"t 92 ]0°02'S0.9W'N 151"06'460t9W 0.00 000 0,00 000 W7.07 SD.52 45.98 14.65 9].02 801].W 0.09 71.79 7836.58 ]]95.58 W4.52 623.86 380925.62 586854192 ]0°02'S4.934'N 151"0546019W 0.00 000 0.00 000 997.0) W.W ".13 14.86 07.03 811].W OW 71.79 7938.W )895.59 6".52 823.96 3W92362 5868541.92 ]0°02'54.934"N 151°O6'08.019W 0.00 0.00 000 0.00 W7.07 W.79 46.28 15.10 I7.W 821].50 0.00 71.72 6036.59 7895.59 a"62 82396 3W 925.62 5%6541.92 ]0'02'S4.9W"N 151°08'46.019W 0.00_ O.OD O.W 0.00 897.07 W.93 "." 15,32 47.05 8?2191 0.00 7119 8043.00 8000.00 6".52 623.96 380925.82 5898"1.92 ]0°02254.B34'N 151°0646.19'W 0.00 _ O.OU 0.00 0.00 89).0] SO.W 48." 15.33 4706 _ FAH 011 nt XS P"202 Armstrong Energy,LLC Location: North Slope, Alaska Slot: Horseshoe #1 Field: Armstrong Energy, LLC North Slope Well: Horseshoe#1 _ Facility: Exploration Wellbore Horseshoe#1 FPS RI BAKER HUGHES PIM reference wdpath is Homeshoe#1_Rev _G-0 1.00100fl 1500 Grid System: NAD27I TM Alaska SP, Zone 4 (5304), US feet End of Buiid True venicel de hs are referenced to Arctic Fox (RT) 2250 End of Taigent -= Wellpath was transformed Rom a different geodetic datum 3.00°1100a 3000 Measured depths are iefemnced to Arctic Fox R End of 3D Arc (XS) North Reference: Tme north 3750 Etl of Tangent (XS) Arctic Fox (RT) to Mean Sea Level: 43 feet 3.00°11000 Scale: True distance j 4500 Mean Sea Level to Ground level (At SIM: Horseshoe 91): 0 feet Dmp (XS) Depths are in feet 2 CoMdinetes ..,it feet referenced to SIM Created by: uldoard on 2017-01-19 Database: WA ANC Defn Well Profile Data Design Comment MD ft Inc Az ° TVD ft Local N ft Local E ft DLS (°7100ft) VS (ft) Tie On 17.50 0.000 0.000 17.50 0.00 0.00 0.00 0.00 End of Tangent 400.00 0.000 0.000 400.00 0.00 0.00 0.00 0.00 End of Build 2000.00 16.000 0.000 1979.29 221.95 0.00 1.00 159.47 Tangent (planned csq polrT 2273,30 16.000 0.000 2242.00 297.29 0.00 0.00 213.59 End of Tangent 2323.30 16.000 0.000 2290.06 311.07 0.00 0.00 223.49 End of 3D Aro XS 3235.36 28.162 1 71.787 3746.81 607.79 208.43 3.00 509.81 End of Tangent XS 3683.16 28.162 71.787 3541.60 573.85 409.19 0.00 696.91 Dro XS 4621.91 0.000 71.787 4443.00 644.52 623.96 3.00 897.07 End of Tan ant XS 8221.91 0.000 77.787 8043.00 644.52 623.96 0.00 897.07 750 0 Tie On } End of Tangent TO ' Entl of Tangent (XS) 15 Facfinn !6t 1.00100fl 1500 End of Buiid d 9.625in CastW 2250 End of Taigent 3.00°1100a 3000 End of 3D Arc (XS) 3750 Etl of Tangent (XS) 0 3.00°11000 j 4500 Nanushuk 3_Core Point (Rev -i) Dmp (XS) dl 2 F ' Entl of Tangent (XS) 15 Facfinn !6t 0 G Oil & Gas 7" will NOT be run as a long string It will be run as a liner. ARE /.- This Cawing is the property of GE Oil& Gas Pressure Control LP and is considered oonfidandal. Unless otherwise approved in wddng, neither it nor its contents may be used, copied, transmitted or reproduced except for the sole purpose of GE Oil & Gas Pressure Control LP. ARMSTRONG 16" x 9-5/8" x 7" x 3-1/2" 5M MB -230 Conventional Wellhead Assembly, With MB -230 Upper Head, MB -230 Tubing Hanger and K Tubing Bonnet DRAWN CR 09AUG16 APPRV KN 09AUG16 FOR REFERENCE ONLY DRAWING NO. 10011822 Schwartz, Guy L (DOA) From: Stephen Hennigan <shennigan@peiinc.com> Sent: Wednesday, January 18, 2017 1:20 PM To: Schwartz, Guy L (DOA) Subject: RE: What did you think about the liner Thank you Will do 5ami yaa aad Aaaa a 6eeeecd dayl c7l� r7. �.L2Ii MS Emgt A Project Manager/Engineer`_"2_"` 9: 337-984-2603 S: 337-849-5345 (mobile) te SIERRA eum Petrolz '"°"a' •� .,. . .br %, Engineers •i9 HAMILTON �.M,.,,.m�o,�a tea.. a,.m® ,��,m��.,�am.��_ �e ,a —. From: Schwartz, Guy L (DOA)(mailto:guy.schwartz@alaska.gov] Sent: Wednesday, January 18, 2017 11:27 AM To: Stephen Hennigan Subject: RE: What did you think about the liner Steve, I looked at your proposal... No issues with this change. Please submit a " change approved program" with the same documentation for formal approval to modify the PTD for Horseshoe No. 1 Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 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 Guy Schwartz at (907-793-1226 ) or (Guv.schwartz@aloska aov(. From: Stephen Hennigan jmailto:shennigan@peiinc.com] Sent: Wednesday, January 18, 2017 10:57 AM To: Schwartz, Guy L (DOA) <guy.schwa rtz@alaska.eov> Subject: What did you think about the liner 7�u,eyou adkm a Xlmeed day./ cJ.fP7Q./ ffr7. �-e&,tq &, MS Emgt A Project Manager/Engineer""" "` 9: 337-984-2603 Q: 337-849-5345 (mobile) .s41a Petroleum ,.+',► SIERRA ' 0 Engineers HAMILTON HAMILTON v SerMY^Mm Canhbnama 1ppt¢ IMaWmapnlrzwnMaln nu.Al ayb W ivaWaanM'mafarpv Wnaf.Irmrymxammi64�abbpry`gm]utlwmnnnamererei Nry rtm, reumemesm, ns[mwvn a Wnrzeol.o- bvgolaMa=as^rebae Ye+MrtnMmnmb[*auuammveXzr Man nuvaMelre3a'ri vpgrtiref Ilyeu ma.W M¢mam. pcewnMhsMraMhWehnablM nrymryNw From: Stephen Hennigan fmailto:shennigan(alpeiinc.com] Sent: Saturday, January 14, 2017 12:46 PM To: Guy Schwartz (guy.schwartz(aalaska.00v) Cc: Pete Berga(pberga(callamericanoilfield.com); Craig Rang(crano(oballamericanoilfield.com) Subject: Info for approval to submit Sundry for Liner instead of long string Guy Attached are documents that we would include in our plans to run the 7" as a liner for production testing. As an introduction we included the 10-403 form for review. A WBS is included to show that we would abandon the open hole below the anticipated casing seat. The casing burst talcs are included to show that the 9 5/8" has a higher burst than the 7" To show how we would install the liner attached the Drlg Opns which includes everything already approved down to Step 12 under the Intermediate/Prod: header. Below that point, we address liner running and cementing. In addition we have attached the Baker Liner running procedure. We would like to finalize and submit this Sundry THIS WEEK as initial plans are to MOBE THE RIG NEXT WEEKEND . Let us know. %Eani yaa a ra 4aae a Xl"ad day/ 0542 0_4& r7. MS Emgt A Project Manager/Engineer"" """ 9: 337-984-2603 W: 337-849-5345 (mobile) 11/10/2016 Connection Type: Technical Specifications Technical Specifications Size(O.D.): DWC/C Casing 7 in 2012 API SPEC 5CT COUPLING O.D. Joint Strength (lbs.) Material L-80 Grade 80,000 Minimum Yield Strength (psi.) 95,000 Minimum Ultimate Strength (psi.) API Collapse Pressure Rating (psi.) Pipe Dimensions 7.000 Nominal Pipe Body O.D. (in.) 6.276 Nominal Pipe Body I.D. (in.) 0.362 Nominal Wall Thickness (in.) 26.00 Nominal Weight (lbs./ft.) 25.69 Plain End Weight (lbs./ft.) 7.549 Nominal Pipe Body Area (sq. in.) Pipe Body Performance Properties 604,000 Minimum Pipe Body Yield Strength (lbs.) 5,410 Minimum Collapse Pressure (psi.) 7,240 Minimum Internal Yield Pressure (psi.) 6,600 Hydrostatic Test Pressure (psi.) Connection Dimensions 7.875 Connection O.D. (in.) 6.276 Connection I.D. (in.) 6.151 Connection Drift Diameter (in.) 4.50 Make-up Loss (in.) 7.549 Critical Area (sq. in.) 100.0 Joint Efficiency (%) Weight (Wall): Grade: 26.00 Ib/ft (0.362 in) L-80 "MM USA VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Houston TX 77041 Phone: Y13-479-3200 Fax: 713-479-3234 E-mail: VAMUSAsales(&vam-usa.com Fordetailed information on performance properties, refer to DWC Connection Data Notes on following page(s). Connection specifications within the control of VAM USA were correct as of the date printed. Specifications are subject to change without notice. Certain connection specifications are dependent on the mechanical properties of the pipe. Mechanical properties of mill proprietary pipe grades were obtained from mill publications and are subject to change. Properties of mill proprietary grades should be confirmed with them If. Users are advised to obtain current connection specifications and verify pipe mechanical properties for each application. All information is provided by VAM USA or its affiliates at user's sole risk, without liabiliiv for loss, damage or injury resulting from the use thereof, and on an "AS IS" basis without warranty or representation of any kind, whether express or implied, inGuding wit, out limitation any warranty of merchantability, fitness for purpose or comPlateness. This document and its contents are subject to change without notice. In no event shall VAM USA or its affiliates be responsible for any indirect, special, incidental, punitive, exemplary or consequential loss or damage (including without limitation, loss of use, loss of bargain, loss of revenue, profit or anticipated profit) however caused or arising, and whether such losses or damages were foreseeable or VAM USA or its affiliates was advised of the possibility of such damages. 11/10/2016 8:04 PM hltps:/Avww.valloureconline.com/Spec Direct/rechnicalSpecifications.aspx?DESIGN_ID=1896&GRADE ID=112&Unit=Standard 1/2 Connection Performance Properties 604,000 Joint Strength (lbs.) 16,590 Reference String Length (ft) 1.4 Design Factor 641,000 API Joint Strength (lbs.) 302,000 Compression Rating (lbs.) 5,410 API Collapse Pressure Rating (psi.) ✓ 7,240 API Internal Pressure Resistance (psi.) 26.2 Maximum Uniaxial Bend Rating [degrees/100 ft] Approximated Field End Torque -Values V/1 8,300 Minimum Final Torque (ft. -lbs.) 21,100 Maximum Final Torque (ft. -lbs.) 23,800 Connection Yield Torque (ft. -lbs.) "MM USA VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Houston TX 77041 Phone: Y13-479-3200 Fax: 713-479-3234 E-mail: VAMUSAsales(&vam-usa.com Fordetailed information on performance properties, refer to DWC Connection Data Notes on following page(s). Connection specifications within the control of VAM USA were correct as of the date printed. Specifications are subject to change without notice. Certain connection specifications are dependent on the mechanical properties of the pipe. Mechanical properties of mill proprietary pipe grades were obtained from mill publications and are subject to change. Properties of mill proprietary grades should be confirmed with them If. Users are advised to obtain current connection specifications and verify pipe mechanical properties for each application. All information is provided by VAM USA or its affiliates at user's sole risk, without liabiliiv for loss, damage or injury resulting from the use thereof, and on an "AS IS" basis without warranty or representation of any kind, whether express or implied, inGuding wit, out limitation any warranty of merchantability, fitness for purpose or comPlateness. This document and its contents are subject to change without notice. In no event shall VAM USA or its affiliates be responsible for any indirect, special, incidental, punitive, exemplary or consequential loss or damage (including without limitation, loss of use, loss of bargain, loss of revenue, profit or anticipated profit) however caused or arising, and whether such losses or damages were foreseeable or VAM USA or its affiliates was advised of the possibility of such damages. 11/10/2016 8:04 PM hltps:/Avww.valloureconline.com/Spec Direct/rechnicalSpecifications.aspx?DESIGN_ID=1896&GRADE ID=112&Unit=Standard 1/2 6 x� e 2 V Jim O pcn $ �9;mcnx o0 m T C m n o n; /fro - Z _� lFq� O m N�Nr XKppprppp �y X(Ipppppp'r{{ X(��''ff F n Muni IIA��Q BII ��.Q II Nay "'''.....iiiii 31+ Lsq nyc �fyv umaR� OpJ'1 Ni,9 o&J'6 8 rri Nd p�y opupd u3wwpdw mPsJ�'�O In Zo G w w c0 E2� {2 Z � l7iS o Q SV a 2 Schwartz, Guy L (DOA) From: Stephen Hennigan <shennigan@peiinc.com> Sent: Saturday, January 14, 2017 12:46 PM To: Schwartz, Guy L (DOA) Cc: Pete Berga; Craig Rang Subject: Info for approval to submit Sundry for Liner instead of long string Attachments: Baker Cemented Liner Running Procedure edited.docx; 8 Horseshoe #1 Drlg Opns draft updated for liner 216 133.docx; Casing Burst Calcs for liner design.docx; AE HS #1 WBS for plugging OH and running liner PTD 216-133.xlsx; AE HS #110-403 for plugging OH and running liner PTD 216-133.xlsx Follow Up Flag: Follow up Flag Status: Flagged Guy Attached are documents that we would include in our plans to run the 7" as a liner for production testing. As an introduction we included the 10-403 form for review. A WBS is included to show that we would abandon the open hole below the anticipated casing seat. The casing burst calcs are included to show that the 9 5/8" has a higher burst than the 7". To show how we would install the liner attached the Drlg Opns which includes everything already approved down to Step 12 under the Intermediate/Prod: header. Below that point, we address liner running and cementing. In addition we have attached the Baker Liner running procedure. We would like to finalize and submit this Sundry THIS WEEK as initial plans are to MOBE THE RIG NEXT WEEKEND. Let us know. T orlpa ad Am a Aemd dV1 �Jl�O.IL!? r7. O�.G�uu8a.7, MS Emgt A Project Manager/Engineer"''„°” ei°: 337-984-2603 S: 337-849-5345 (mobile) .:•, fes;44 Petroleum ,%Mo SIERRA a:. Engineers '.: HAMILTON ��,,,a�n��,M.�,��,,�.,,�aM�„�„" �,�,�om�,e,s,�,��„�e.�,�".��.,�„�>.,.„�,,,�,<>,�,m.=��.,�„oe��,•a�a,.�,�,.•...�„�.�.�,a,�am�,�,�„ti.,.��.,,.� .,,„�„ „�.,,��m.,a �,�,�•.,.�,b�,�.,"��,��„ter'^ Has BAKER HUGHES Baker Oil Tools Baker Hughes Cemented Liner [Type text] Generic Running Procedure Running Procedure: • MU shoe track. Baker -Lok all connections below landing collar and check floats (Float Check Procedure: Fill shoe track with mud/brine. PU shoe track and drain fluid level through the floats into well. Run shoe track back into well and visually confirm no back-flow into the shoe track.). • Keep liner full while running in hole. Fill every 5-10 joints while running. • Monitor pick-up and slack -off weights while running. Record PU and SO weights. • Verify lift sub has been made up if needed. • MU Baker Liner Hanger and Liner Top Packer. o Elevators need to be slacked off while making up liner hanger to prevent liner running tool from secondary releasing. o Slack off to place top of tie back extension at rig floor. Fill tieback extension with Xan Plex-D. Xan Plex-D will gel while rigging down casing tools and preparing to run drill pipe. The liner can be reciprocated until ready to run drill pipe. • RIH with liner on drill pipe no faster than 1 minute per stand (90 fUmin). Watch displacement carefully and adjust running speed accordingly. o Slowly run in and out of slips. o Make up top drive and fill pipe every 10 stands. Circulate 1 '/2 drill pipe and liner volumes at 7" shoe prior to going into open hole. Stage pumps up slowly watching for fluid losses. Do not exceed 1,800 psi while circulating. Obtain up and down weights of liner before entering the open hole. • Rotation is anticipated during the job SO rotating parameters should be established in casing test @ 10, 15, and 20 RPM and every 2,000' while running to open hole. Torque and Drag analysis should be used as a reference. • Stage pump rates up slowly to circulating rate without exceeding 1,800 psi. Circulate a minimum of one bottoms up at the desired cementing rate while limiting rate/pressure to avoid setting liner hanger or initiating losses. Reciprocate string during all circulating and cementing operations if hole conditions permit. • Pump Cement Job per Armstrong Energy cementing procedure. • Drop DP dart and displace cement with rig pumps utilizing mud. o Ensure to completely function Plug Dropping Head as per Baker Tool Specialist's Surface Cementing Equipment Spec Sheet. Flag sub will provide a positive confirmation when plug has been dropped. I/.iI BAKER HUGHES Baker Oil Tools Baker Hughes Cemented Liner [Type text] • Position liner at setting depth and reduce pump rate to 3 BPM 7bbl prior to latching DP dart into Liner Wiper Plug. Observe LWP shearing off and resume pumping at desired displacement rate. Make first movement downward if pipe is to be moved again. If elevated displacement pressures are observed during displacement, position liner at setting depth and cease reciprocation. • Displace the cement with the rig pump, slowing rate as directed by BHI Service Supervisor — 2-3 BPM and bump the plug. • Pressure up to 2600 psi as per Baker Field Specialist to set the liner hanger (typically 15% above nominal setting pressure). Need to consider possible hydrostatic imbalance due to lifting heavy spacer and cement above liner top as this will increase pressure required to set the liner hanger. • Slack off total liner weight plus 50k down hole to fully set liner hanger. • Bleed pressure to Zero and check floats for flow back. If the floats leak, shut in and wait on cement. • Slack off 10 Klb on hanger and rotate 12 turns to the right at the tool to mechanical release Liner Running Tool. • Apply 500 — 1,000 psi to the 4" drillpipe and pick up slowly to pull pack off. Once the standpipe pressure drops, engage pump to wash residual cement from liner top. • Pick up until packer dogs are above liner top per Baker Oil Tools onsite engineer. • Set down 50 klbs minimum at the tool. Rotate as necessary to get weight down to tool. • After Liner Top Packer is set, pressure test back side to required amount, then circulate out until clean. Armstrong Energy, LLC Horseshoe # 1 Block/Sec 015 T6n R4e Wildcat North Slope Alaska PTD #: 216-133 THE STATE Alaska Oil and Gas °fALASKA Conservation Commission GOVERNOR BILL WALKER Stephen Hennigan Project Engineer Armstrong Energy, LLC. 510 L Street, Suite 310 Anchorage, AK 99501 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Exploratory Field, Exploratory Pool, Horseshoe 1 Armstrong Energy, LLC. Permit to Drill Number: 216-133 (revised) Surface Location: 1438' FWL, 2249 FSL, T8N, Sec. 15, R4E, UM Bottomhole Location: 2037' FWL, 2880' FSL, T8N, Sec. 15, R4E, UM Dear Mr. Hennigan: Enclosed is the approved application for permit to drill the above referenced exploration well. All dry ditch sample sets submitted to the Alaska Oil and Gas Conservation Commission (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. 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 Armstrong Energy, LLC in the attached application, the following well logs are also required for this well: Neutron and density logs will be recorded in the 12 '/4" hole interval and the 8 '/z" hole interval. 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. Please review the geologic and log requirements of 20 AAC 25.071. A rig inspection by AOGCC staff is required before spudding well. This permit to drill does not exempt you from obtaining additional permits or approvals 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. A weekly status report is required from the time the well is spudded until it is suspended or plugged and abandoned. The report should be a generalized synopsis of the week's activities and is exclusively for the AOGCC's internal use. PTD: 216-133 Page 2 of 2 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, Cathy P Foerster Chair, Commissioner DATED this 10 day of January, 2017. THE STATE °fALASKA GOVERNOR BILL WALKER Stephen Hennigan Project Engineer Armstrong Energy, LLC. 510 L Street, Suite 310 Anchorage, AK 99501 Alaska Oil and Gas Conservation Commission Re: Wildcat Field, Wildcat Pool, Horseshoe #1 Armstrong Energy, LLC. Permit to Drill Number: 216-133 Surface Location: 1438' FWL, 2249 FSL, T8N, Sec. 15, R4E, UM Bottomhole Location: 2037' FWL, 2880' FSL, T8N, Sec. 15, R4E, UM Dear Mr. Hennigan: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Enclosed is the approved application for permit to drill the above referenced development well. 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. 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 Armstrong Energy, LLC. in the attached application, the following well logs are also required for this well: 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 Armstrong Energy, LLC. 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. Please review the geologic and log requirements of 20 AAC 25.071. A rig inspection by AOGCC staff is required before spudding 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, Cathy IYFoerster Chair, Commissioner DATED this y of December, 2016. STATE OF ALASKA AL A OIL AND GAS CONSERVATION COWi )N PERMIT TO DRILL 20 AAC 25.005 RECEIVED OCT 19 2016 1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp E]tc. Specify if well is proposed for: Drill 21 Lateral ❑ Stratigraphic Test ❑ Development - Oil ❑ Service- Winj ❑ Single Zone ❑ Coalbed Gas ❑ Gas Hydrates ❑ Redrill ❑ Reentry ❑ Exploratory - Oil 0 Development -Gas ❑ Service - Supply ❑ Multiple Zone FZI Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket ❑' 1 Single Well ❑ 11. Well Name and Number: Armstrong Energy, LLC Bond No. 3563146, Horseshoe 1t 1 3. Address: (local) 6. Proposed Depth: 12. Field/Pool(s): 510 L Street, Suite 310 Anchorage, Alaska 99501 MD: 8175' , TVD: 6042' Wildcat 4a. Location of Well (Governmental Section): "re j11 &N E 46 7. Property Designation (Lease Number): Surface: 1438' FWL & 2249' FSL Sec 015 8n 4e 0 M. 4 Abk 392048 Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 2037' FWL & 2880' FSL Sec 015 8n 4e j)AI, 4 LAS 28269 & Others 1 -Jan -17 9. Acres in Property: 14. Distance to Nearest Property: Total Depth: 2037' FWL & 2880' FSL Sec 015 8n 4e 11.4 4 4916.44 1438 2249 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 43.0' - 15. Distance to Nearest Well Open Surface: x- 360,315 y- 5,867,922 Zone- 4 GL Elevation above MSL (ft): ,)�' 24.5' - to Same Pool: NA 16. Deviated wells: Kickoff depth:/ feel 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 420 degrees • Downhole: ,394.3 Surface: 2959 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade I Coupling Length MD TVD MD TVD (including stage data) 2l LJ16 84.00 X56 Weld R3 0 0 118 1180sx Lead ®Oppg+310sx Tail ®15.6ppg 0 0 0.00 0 0 R3 0 0 0 0 53- 0 0 2,318 2,242 900sx Lead 0 11.1pp9 + 1030sx Tail 0 121/4 95/8 47 -OT LBO BTC R3 15.eppg 81/2 7 26.00 L80 BTC R3 0 0 8,175 8,042 260sx Lead 0 12ppg +49osx Tail @ 14ppg 0 0 0.00 0 0 R3 0 0 0 0 na 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 20. Attachments: Property Plat Q BOP Sketch Drilling Program Q Time v. Depth Plot Q Shallow Hazard Analysis0 Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program ❑✓ 20 AAC 25.050 requirements❑✓ 21. Verbal Approval: Commission Representative: Date 10/10/2016 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not Stephen Hannigan 337849-5345 be deviated from without prior written approval. Contact Email steve@peiinc.com Printed Name Stephen F. Hannigan Title Consulting Project Engineer for Armstrong Energy, LLC Signature e,- Phone (337) 849-5345 Date 10/10/2016 Commission Use Only Permit to Drill API Number: Permit Approval See cover letter for other Number: - AA 50- - (� - v� -� ) Date: ��- 2.-, - k12. requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed ethane, gas hydrates, or gas contained in shales: Other: 05 �. & b � /fie- ✓ - Samples req'd: Yes No❑ Mud log req'd: Yes [� No❑ rZIOoj ��- / /- � '2 1" HzS measures: Yes No E] Directional svy req'd: Yes [� No❑ d�,y /�7�� .6 L..H,e�^c- T / 5 ✓ Spacing exception req'd: Yes ❑ No Inclination -only svy req'd: Yes No / �✓'a (C /at 5 w�m.��% �' Post initial injection MIT req'd: Yes ❑ No ❑ i(• �d. al `1 flnf7f " •cpprr9�-e.Ci �e�. F �G,4.4C ZSO3$�L1Cl�CA) �Z l�iver(ec APPROVED BY COMMISSION - Date: Z Approved by6&1 COMMISSIONER THE Form 7ao01 (wised 11 1 f. '1 4 r r� iy rsv�li rA�nths from the date of approval (j0 AAC 25.005(8)) Submit Fonn and Attachments in Duplicate A ARMSTRONG October 11, 2016 Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Application for Permit to Drill Armstrong Energy, LLC Horseshoe #1 Sec 15 8n 4e UM Wildcat North Slope, Alaska Dear Ms. Foerster, RECEIVED OCT 19 2016 AOGCC Armstrong Energy, LLC hereby applies for a Permit to Drill an exploratory oil test on the North Slope. The well will be located on Alaska State lands. Depending on rig availability and ice road construction, the approximate spud date is anticipated to be early January 2017. Armstrong at this time anticipates using the All Am T^ 11yto., drill this well. Well testing is anticipated. tf h Please find attached information as required by 20 AAC 25.005 (a) and (c) for your review. Pertinent information attached to this application includes the following: • Form 10-401 Application for Permit to Drill • Plats showing the surface location of the well • Proposed Wellbore Diagram • Plan Plot • Drilling Time vs. Depth Plot • Program Details • Cementing Program Summary • Proposed Directional Plan • Wellhead diagram • Diagrams and Descriptions of the BOP • Solids handling diagrams • Miscellaneous Equipment to be used 510 L Street, Suite 310 • Anchorage, AK 99501 p907.375.6900 "`y, /9 —!6 4 In addition, in compliance with 20 AAC 25.061 Well site surveys, Armstrong is submitting with this permit application a Shallow Hazard Study which exhibits no indication of a shallow gas situation. If there are any questions and/or any additional information desired, please contact me at (337) 849-5345 or Pete Berga at (573) 201-3861. Respectfully ARMSTRONG ENFRGY, LLC Stephen F. Hennigan Armstrong Project Engineer Enclosures Cc: Edward Teng — Armstrong VP and Project Manager Colby VanDenburg— Armstrong Project G&G Nate C. Lowe — Armstrong Land Manager Cindy Bailey — Armstrong Public Affairs Manager Robert Britch — Senior Advisor Pete Dickinson — All American — Armstrong Drilling Manager Pete Berge - All American — Armstrong Drilling Superintendent Stephen Hennigan — Sierra Hamilton Petroleum Engineers for Armstrong Energy 510 L Street, Suite 310 - Anchorage, AK 99501 p907.375,6900 v -x-o. 19- IONS rllll tu....\\ ...�� SURVEYORS CERTFlGTE p IIITEBYOgITIFY RNTIAMPROPERLY RE061EREp ANO LXFRBEOroPRACfICE LAND SURVEYN{FNTE / bTAIEGFALA8INANDTTNTITYC9RfIGT10Na W!•F®roT1ENBLCOIEN.'FOf( I.aGnaN OIA.r. ALL DTNERNFOfOIAlgN6FY1WNEAPPRO)OIWLIE na•4M4Y� i ¢ I _ __ N n40 n01 IrMO r�� u q[t A HORS-ESSSTA= I AS LOCAYEG TWIFRI BECIION 16, TBN,RE, WA ArNsrroRs £Rergy, LGC B/1BN9 4rac 1'u 100' MINI OO nW° _, WiArl ATiklRApq FIGRM 1 CIF 1 ARC T 1 OC EA N NOTES. I. ELEVATIONS SNOWN ME NAVD W PER MOD 2012A e.•w aA✓wr x DERIVED FROM CPS ORSERVARGN. —�� ` LAKE 2. THE EDGE OF THE LANE ISA POORLY DEflHED SHORELINE, VERY MARSHY 0711 SCATTERED �rRA4atr CRASS. FREDF THE WAFER AS FAR AS 20' EFT THE FROM THE EDGE AS SHOWN IS GENERALLY LESS THAN ONE FOOT. J. CONTOUR INTERVAL ONE FOOT. LAKE O u VKTOTY IMP N.T.S � \ C.ONDUCTORASSTAKED LOGLTON \ �\ O LU061ASFLEE� J LAT -70D' N / LONG+1 3D' W '0714. 67,669 1 �) O 5 X - ,500,353 � I PROPOSED NAO27E4 ICE PAD \ LAT=70002'1802'4872* N LONG=15VD7'D3.27' W Y - 5.867,922 La Zw �O LAKE X = 360.315 NAD27U1MIDFE6MEIB16 LAT- 70'02'4872* N LONG -151'07'03.27- W Y 7,776,221 = O X = 343.277 PRIMARY LOCATION rFrh �_' LaLOCATED T IHN PRUIIRACTED SEC 15.7iA 1,438' F.W,L. 2.249F.S.L. a SUIIFACE EIPVAROR TOP OF TUNDRA ELEVA aM = ;35'3 -x-o. 19- IONS rllll tu....\\ ...�� SURVEYORS CERTFlGTE p IIITEBYOgITIFY RNTIAMPROPERLY RE061EREp ANO LXFRBEOroPRACfICE LAND SURVEYN{FNTE / bTAIEGFALA8INANDTTNTITYC9RfIGT10Na W!•F®roT1ENBLCOIEN.'FOf( I.aGnaN OIA.r. ALL DTNERNFOfOIAlgN6FY1WNEAPPRO)OIWLIE na•4M4Y� i ¢ I _ __ N n40 n01 IrMO r�� u q[t A HORS-ESSSTA= I AS LOCAYEG TWIFRI BECIION 16, TBN,RE, WA ArNsrroRs £Rergy, LGC B/1BN9 4rac 1'u 100' MINI OO nW° _, WiArl ATiklRApq FIGRM 1 CIF 1 01 4O mZ �� ~ I J� Q • A as ✓7� o 30 of MW aX I'�„"a. pZ as < a > J O ®o W 3m jm ny WqF ZQpp 4K K QK a Ow aQ<gm O& JN Q j2 J S p > a w n, Z 2 ,4 oon W 2 ro �A{y s � i m z z z m u • 0 _ m � O o s Q <O N O 62 W O x R_ y �` J 4 � d �, 2 � 'o 2 'V '� KK � •d ,a 6 � N y �Y• � U ZO < p OS g itm rc o G < K W a Q m J m y li Jm Sm No az ME < ;m °a a owotusrour oNox oN- < osaxoKtaa zoozeeleciav --------------y 1 a 1 XC 1 ' a ° d 1 ry 1 5 1 -----k ---- i...i t w ZO O tY. z T c w 5Id>>F LL n i 0 s u a - u u u u a 550> t�wd z` 01.130 I v z Armstrong Energy, LLC Armstrong Energy, LLC "A " Location - Nanushuk 3, 1 Horseshoe # 1 Ocean Pt Block/Sec 015 8n 4e Wildcat North Slope Alaska USDW: <1300" Prepared By: Armstrong Energy, LLC and 1.11E„,,Sierra Hamilton Petroleum Engineers =aS SIERRA ,; Petroleum (337) 984-2603 HAMILTON Engineers and All American Oilfield Associates LLC Tie On O Casing 1 KOP Base Pemla 1000 EOB,HOLD PP Cesina 2 T Tuluvsk5eabee EON, Drop 3000 Holder EOD Ivenveli 4000 ro Na;&1 k3Core POIMA �v 5000 Nanushuk7_5200'SMi I PossIbM TD 16000 7000 Alpine Wildcat Armstrong Energy, LLC "A" Location - Nanushuk 3.1 Horseshoe # 1, North Slope, Alaska. 0 2000 4000 10000 r 12000 Directional CASING 9 10 11 12 13 14 15 16 1 �,� ' ■■■■■■■■■■ FIJ I01 I::■okI■■■■■ 2111■■11■■■OV■■■■ �!\��S■■■■■■■ �!■!��■■■■■■■■■ ��W■■� I■■■®iFrac rel■■ ■■f 1wdi■■■■■■■ ■wi l■■1 I■■m■■m■■ ■■I 1■■■■■■■■■■ ■■� 1■■� I■■■■■�■■ s■l lo■■■■■■■■■� ,�■, 1■■■■■■�■ 111UII0 IIII1M■■ ■■C ___ ,■■■■■MINI i■usio■■■■■■■ on ■■MEMMMMM■ 0 2000 4000 10000 r 12000 Armstrong Energy, LLC Horseshoe # 1 BlocWSec 015 8n 4e Wildcat North Slope Alaska 4e Est Rkb 42' ................. KOP: 5300' 1 8.3 8.4 11 101' pen 118' KUV/bas log r. ,l MA—t.. Tn Osx Lead @ Oppg+430sx Tail @ 15.6ppg 8.6 10 13.8 GR, Res, svgs 2318' 2242' 785sx Lead @ 11.1ppg+220 sx Tail @ 15.8ppg Te On Casing 1 KOP Base Permafrost Holler 3- EOD(Vertical) 4' Nanushuk3Care, Point 4340 SSND i Namu6uk t_5200' SSMC 9 10.4 16 GR, Res, sws 8175 PossibleM Gr, RT, Ilan, Neut, Sonic +5, MOTw ui sample, Oil-based FMI, NMR, ECS or LiMoscanner, 8042 Alpine Stage 1: 85 sit Lead @ 12ppg+255 sx Tail @ 14ppg -5- i= /70 sx crz�� Air Gap wff. D 848%56 Weld auger/drive se 16 na Ph, --I PJ Inr -uNA= 478LM BTC 121/4" 95/8" ov tool @ 2868' Manned E.f/TOC=B'RKB F. h L80 BTC Andilparedm PAA ANY Open Hole 8 1/2" T,. 3' EOB,HOLD� �j MCO r Casip2 Nati S TTuluvaK/Seabee Mud Lagging: P EOH, Drop Manned: 25x/50' 0-x2200', 25x/10', x2200' -TO Holler 3- EOD(Vertical) 4' Nanushuk3Care, Point 4340 SSND i Namu6uk t_5200' SSMC 9 10.4 16 GR, Res, sws 8175 PossibleM Gr, RT, Ilan, Neut, Sonic +5, MOTw ui sample, Oil-based FMI, NMR, ECS or LiMoscanner, 8042 Alpine Stage 1: 85 sit Lead @ 12ppg+255 sx Tail @ 14ppg -5- i= /70 sx crz�� Air Gap wff. D 848%56 Weld auger/drive se 16 na Ph, --I PJ Inr -uNA= 478LM BTC 121/4" 95/8" ov tool @ 2868' Manned E.f/TOC=B'RKB F. h L80 BTC Andilparedm PAA ANY Open Hole 8 1/2" T,. Armstrong Energy, LLC Horseshoe # 1 Block/Sec 015 8n 4e Wildcat North Slope Alaska M1N tOK/ q0. pVg Vpgei FVALVRIIDY,�_.—�/3='D 151 Rkb43' ..................... 3.3 8.4 11 101'pen 118' ROP/Gas log COnd/Drive to M. Tie On CasingI K0V Base Permafrost 3' EOB,HOLO .Cu Wtlng2 TTuluwVXabee Holder On, Lead @ Opp9+330sx Tail @ 15.6pn B.6 9.8 13.8 ca, aes,sm 2318' 2242' 900sx Lead @ 11.lppg+ 1030ax Tail @ 15.8ppg Mud Logging: 2 SX/50. 0-x sx/10', d13 EODiVMtrali A' NanRduk3C:ae Point A34P55ND NanusHvk>_52W' SSTVD 9 10.4 16 GR, Re%sv 8175' Possible To 8041' Melee 2Wsx Lead @ 12ppg+490ax Tail @ 14ppg TDTop of HRZ TO 8OX56 Weld Air Gap wo.I Drive sz» 16 './ 47X188 BTC 121/4" 95/8-' rs O'Est tO[ III Nm BTC A111111.d m 1'AA ANY Oyen 11u4 8 1/2" 7 " Armstrong Energy, LLC Horseshoe e 1 Block/Sec 015 8n 4e Wildcat North Slope Alaska 1438' FWL & 2249' FSL Sec 015 8n 4e Directional Program: Lithology Samples: Directional Survey: Per program 2 sx/50' 0-:2200', 2 sx/10', x2200' -TD Per regulatory and directional requirements. Prepared by Stephen F. Hennigan Directional 2037'l-WL&2880'F5L 5ec0158n4e VS 0 n s Send Tops/Significant Markers Objectives Type TVD EMW COMMENTS Ti, OnI].5 Casing 1 8.3 C.'s,I Drive/Structural In 8.4 KOP Base Permafrost 400 8.4 Base Pernseaoet EOB,HOLD 77J 8.4 EOB,HOLD Casing 2 1380.53 8.4 MCU Surface 1983 8.6 Cesing2 EOH, Drop 2242 8.9 TTWu.WJSeahee Holder 2403 8.9 ______- Eon, Drop2819A7 ----- _---- 8.9 Holder Nanushuk 3 Core Point 4340'SSTVD 3386 8.9 EOD (Veranll Nanushuk 1_5200' SSTVD 380D 8.9 N.rsshek 3 Core Possible TO 7442 Poitt 4340.8 Alpine 41MS4 8.9 "IPz5,7sJr.;8T3D ri2U'0" --- ------- &9TVD 5243 8.9 Possible TD SSOJ g AI isw .__________ ]442 9 TDTop of HRZ 8042 9 Directional Program: Lithology Samples: Directional Survey: Per program 2 sx/50' 0-:2200', 2 sx/10', x2200' -TD Per regulatory and directional requirements. Prepared by Stephen F. Hennigan Directional TVD VS 0 n s 17.5 0 Tie On 120 0 Casing 1 400 0 KOP 773 24.821691 Base Permafrost 1380.53 173.03 EOB,HOLD 2242 486.8 Casing 2 2403 545.48222 T Tulwak/Seab as 2819.47 697.19 EOH, Drop 3386 840.15 Holder 3800 870.22 EOD (Vertical) 4384.54 870.22 Nanushuk 3 Core Point 4340'SSTVD 5243 870.22 Nanushuk 1_5200' SSTVD 5543 870.22 Possible TO 7442 870.22 Alpine 4 Armstrong Energy, LLC Mud Logging Unmanned: ROP/Gas log Cond/Drive to TD. Manned: 2 sx/50' 0-±2200', 2 sx/10', x2200' -TD Mud Program: Interval (TVD) Mud Weght (ppg) From To From To Mud Type 0 8.8 Spud 2242 g.8' 10.0 WB Spud 2242 8042 9.8 10.4 MOBM �J`' Yll.)5 ft- Prepared 6 Prepared by Stephen F. Hennigan 5 Horseshoe R 1 Block/Sec 015 an 4e Wildcat Logging Program: Lwd OH OH Possible Cased Hole Mudlooelna Surface J GR, Res, svys CBL Full Svc GR, RT, Den, Neut, Sonic (C+S), MDT w/ fluid CONVENTIONAL core Prod/Test GR, Res, svys sample, Oil Based FMI, of upper x300' of Full Svc NMR, ECS or Nanushuk 3 (±4416'- Lithoscanner, Rotary SW 4716' TVD) Core, VSP Mud Logging Unmanned: ROP/Gas log Cond/Drive to TD. Manned: 2 sx/50' 0-±2200', 2 sx/10', x2200' -TD Mud Program: Interval (TVD) Mud Weght (ppg) From To From To Mud Type 0 8.8 Spud 2242 g.8' 10.0 WB Spud 2242 8042 9.8 10.4 MOBM �J`' Yll.)5 ft- Prepared 6 Prepared by Stephen F. Hennigan 5 Casing Program: General Drilling Prognosis Armstrong Energy, LLC Horseshoe # 1 BlockfSec 015 8n 4e Wildcat Hole Size Drive/ Structural 22 Conductor (NA) CMTD Surface 12.25 ProdfTest 8.5 General Drilling Prognosis Armstrong Energy, LLC Horseshoe # 1 BlockfSec 015 8n 4e Wildcat 1 Prep location. Auger/Drive structural, etc. Watch for water flows. 2 Mobilization -MIRU 3 Conform to ALL regulations. NU diverier. Perform rig spud mtg. 4 PU a 12 1/4° Dir LVID BHA easy. Clean out drive/conductor. Drill slowly until stabilizers have exited. 5 Incr RPM and flow rate. Be prepared for losses. Add LCM to mud. 6 Directionally drill to casing point. Condition hole. 7 Condition hole. Run csg and cmt w/ stab -in. Insure crit to surface. May need top job 8 Displ w/ SBM. 9 Install wellhead. NU BOPe. Test. 10 PU Dir LWD BHA and TIH. 11 Drill shoe track. Drill out 20' new hole & pert LOT. 12 Drill ahead. Monitor surge & swabs. Set down slowly on slips. Kick pumps on slowly. 13 Minimize ECD. (Pump wtd & LCM sweeps prior to each trip. Stage in hole Carefully after each trip.) 14 Monitor for markers. Pick coding point. POOH. 15 Perform approximately 5-60' core runs 16 PU Dir LWD BHA and TIH. 17 Clean out core hole. Drill. 18 Drill to TD. Conation Hole. Evaluate. 19 Following evaluation, a determination will be made to P&A, or run casing and test then P&A. A SUNDRY permit 20 is required for testing and for the P&A. Submit logs to AOGCC prior to abandonment. Prepared by Stephen F. Hennigan 6 Measured Depth Connection CMTD Est No. Casing Size From To Wt (lo//t) Grade Type with TOC Centralizers 16 0 118 84 X56 Weld NA none 310 9.625 0 2318 47 L80 BTC 1930 0 16 7 0 8175 26 L80 BTC 750 0 53 1 Prep location. Auger/Drive structural, etc. Watch for water flows. 2 Mobilization -MIRU 3 Conform to ALL regulations. NU diverier. Perform rig spud mtg. 4 PU a 12 1/4° Dir LVID BHA easy. Clean out drive/conductor. Drill slowly until stabilizers have exited. 5 Incr RPM and flow rate. Be prepared for losses. Add LCM to mud. 6 Directionally drill to casing point. Condition hole. 7 Condition hole. Run csg and cmt w/ stab -in. Insure crit to surface. May need top job 8 Displ w/ SBM. 9 Install wellhead. NU BOPe. Test. 10 PU Dir LWD BHA and TIH. 11 Drill shoe track. Drill out 20' new hole & pert LOT. 12 Drill ahead. Monitor surge & swabs. Set down slowly on slips. Kick pumps on slowly. 13 Minimize ECD. (Pump wtd & LCM sweeps prior to each trip. Stage in hole Carefully after each trip.) 14 Monitor for markers. Pick coding point. POOH. 15 Perform approximately 5-60' core runs 16 PU Dir LWD BHA and TIH. 17 Clean out core hole. Drill. 18 Drill to TD. Conation Hole. Evaluate. 19 Following evaluation, a determination will be made to P&A, or run casing and test then P&A. A SUNDRY permit 20 is required for testing and for the P&A. Submit logs to AOGCC prior to abandonment. Prepared by Stephen F. Hennigan 6 Armstrong Energy, LLC Horseshoe # 1 BlocWSec 015 8n 4e Wildcat North Slope Alaska Time vs Depth Casing Size & Depth —Days vs MD —TVD vs Days —Protl Csg/Inr 1,000 2,000 3,000 I 4,000 5,000 6,000 7,000 5,000 9,000 0 5 10 15 20 25 30 35 7@ ee Emergency response Information 1.1 Directions to Location Directions Driving direction to Horseshoe #1 Drill Site from Deadhorse 1. From Deadhorse (DH). Drive along Lake Colleen, either on the west side (Airport Way) or Spine Road (North side) to the BP West Gate Check Point (Mile O) 2. Continue along the Spine Road for 26.1 miles to the west 3. At Mile 26.1 the Spine Rd comes to Kuparuk River Unit Security Check Point. (unmanned) 4. The Spine Rd turns into the Kuparuk Rd at Mile 26.1 5. At Mile 31.8 entering the area of KOC✓CPF3 6. At Mile 33.8 is a three-way intersection, proceed to the left (west) 7. At Mile 35 is a three-way intersection, proceed to the left (Southwest) 8. At Mile 40 entering CPF2 9. At Mile 40.2 at the west -end of CPF2 take a hard left (south). This is the start of Meltwater Rd 10. Drive 26 miles on the Meltwater Rd to start of ice road (at Mile 66.2) on the right side (west, 0.6 miles before getting to Drill Site 2P. which is the end of the Meltwater Road) 1.2 Rig Contact Numbers (Tentative depending on rig and communications available at time of MIRU) Phone numbers will be (907) 685 — 3250 thm 3299 Rig Phone List Cell #'s Co.Man: TBD Tool Pusher: TBD Mud Engr. TBD Directional TBD Expediter: TBD Rig Fax: TBD CM Backup: TBD TP Backup: TBD Wireless Access Point#1 Company Man Office Wireless Access Point#3 Comm Room Wireless Access Point#2 Tool Pusher/OIM Office Wireless Access Point#4 Medical Facility Others will be addressed as necessary Prepared by Stephen F. Hennigan Page 8 1.3 Emergency Response Contact Numbers Company Contact Numbers Name TBD TBD Pete Berga Pete Dickinson Stephen Hennigan Brian Brigandi Response Service Aerial Ambulance/Medevac Fire Clinics- Hospital/Medical Police (Local) Alaska State Troopers Spill & Contamination Spill & Contamination Mgmnt Operations * Other clinics are located at Hilcorp Milne Pt., BP Base Opns., BP Main Construction, ENI Nkaitchu( pasuma Ca Man Clerk Superintendent/Opus Mgr Drilling Project Mgr Proj Mgr/Engr Logistics Location I` ow. Cell (573)201-3861 (907)230-6541 (337)849-5345 (907)748-7089 Contact Phone Genera 911 Anchorage Anchorage Fairbanks LIFE MED Alaska Regional Life Flight Guardian (800) 478-5433 (800) 478-9111 888 997-3822 Ka aruk Field SEE BELOW 907 659-7300 Deadhorse McC Medical Clinic 907 659-5300 Ku aruk Medical EMS 907 659-7230 Deadhorse Fairweather 907 685-1800 Fairbanks Fairbanks Memorial Nearest 907 458-5100 Anchors a Providence Medical Center Major 907 562-2211 Barrow Barrow Hospital 907 852-9209 Fairbanks Alaska State Troopers 907 451-5100 Main Number Alaska State main number 907 269-5511 Alaska Alaska State Spill Reporting National Response Center Coast Guard Alaska Clean Seas BM) 478-8300 907 269-3063 800 424-8802 (800)479-5555 Alaska AOGCC (907) 793-1236 907 279-1433 Slidell, LA Witt/O'Brien's Resource Management 24-hour emergency 985 781-0804 Houston TX Wild Well 281 784-4700 Prepared by Stephen F. Hennigan Page 9 Other NECESSARY Contact Numbers BP Security - Notify for security escorts of oversize loads traversing on the BP Road System Conoco Simultaneous Operations (Sim Ops) - Notification for rig moves, oversize loads, traversing over Conoco Road System Conoco Security - Notify Kuparuk Security for escorts over Conoco Road System (907) 659-5631 (907)943-1299 (907)659-7939 (907)659-7997 Konoruk Emergency Services.... KRU Security (907) 659-7997 KRU Emergency Services (907) 659-7300 KRU Fire Chief (907) 659-7494 1.4 Company Emergency Response Name Position office Mobile Pete Dickinson Drilling Project Mgr (907) 230-6541 Pete Berge Superintendent/Opns Mgr (573)201-3861 Steve Hannigan Project Mgr/Engr (337)849-5345 Brian Walden Field HSE Manager (907) 202-3274 Brian Brigandi Logistics (907)748-7089 Ed Tang VP Engineering (303)981-9957 2 Regulatory Agency Contacts by phone or email Well Class Agency Office M -F (UM -SPM) Contact 48 hr Notice AOGCC (907) 793-1236 Inspection Supervisor (Jim Regg) See Industry Guidance 10-01 usow http://doa.alaska.¢ov/ogc/formsNstWitnessNotif.html doa.aoe¢.prudhoe.bav0alas1ka.eov Rig Name See drilling prog for additional information 3 4 Regulatory Compliance Regulation 20 AAC 25 BOP testing awry7 days 48 hr notice required Drilling Program Summary 4.1 General Well data Name Horseshoe a 1 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(6). For a well with multiple well branches, each branch must similarly be identified by o 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. Surface Len 1438'FWL&2249'FSL Seco158n4e lease/u, 391048 Sit/Pad Tundra Field Wildcat Spud Datebot) 01/01/17 KB labove MSL) 43.0' County/Prov North Slope API No. GMT Expl Co. GL (above MSL) 24.5 Slate AS Permit No. Penn Datum MSL Total MO 8,175 Well Class Wildcat WD na Total ND 81042 OHg Contractor AAO usow <1300' Rig Name Rig 111 4.2 Working interest Owners Working Company Interest Operator Armstrong Energy, 3825% LLC Repsol 49.00% GMT Expl Co. 12.75% Address 510 L Street, Suite 310 Anchorage, Alaska 99501 Prepared by Stephen F. Hennigan Primary Phone Fax Page 10 4.3 Geologic Program Summary T.V.D. (ft) X Co-ord. Requirements of 20 AAC 25.005fc)(2) (Ppg) est 0 An application fora Permit to Drill must be accompanied by each of the following items, except for an item already on file elM thecommission and identifiedlo the a,urention: 360315 (2) o plot identifying the property And thepmpeny's owners ondshowing CONVENTIONAL core of upper 18 (A) the mand .ytne P.^Posed l«ntron f(M1e.enat the swfxe, at the W afeach ugedawfo•morrory mdm whodepdh •Harercee(ogovemmentul re[r hoes. 360315 (a) Metermattes at the proposedhrorim n)Me weYat rhetafare, M,..ret to thesrme plane •oardi-tesY,hertanhs stare os manatnedo nnehetlpwl Lendetk s,aM In Me Abaonal nreome analmme hem Atlmivstmrian; 120 360315 (c) the proposed depth afthe with of the top ofeach oblectiveformatme and at total depth, 84 400 Attachment I Perm/t Mats 360315 5867922 NAD 27 NAD 83 773 SHL SHL 8.4 NAD27 ASP ZONE NAD83 ASP ZONE 360436 LAT -70'/;2'48.72" N LAT=7rrf.2'47. 5�" N 2042 L0V3=15"J7'C3.27" '6' LUN;;=I-'-W'14.3O" :' 5868202 Y - 5,8.67,922 Y - 5,8c7,af9 2242 % - .So D.31r.; 5868269 9.9 NA027 UTM ZONE 6 METERS 2403 360698 LAT -7C,'02'48 72" N 8.9 2932 LONG=15 'J/'C3.27" 'w 360804 5868419 Y - 7,77G,221 3518 3386 X - 34.1.2// 5868521 8.9 NAO 27; Alaska Zone 4 3800 360926 5868542 X Co -and. TCo-ord. 4518 Surface Location Coordinates 360,315 5,867,922 1438' FW L & 2249' FSL 5ec 015 8n 4e Targetfrurning Point 360,925 5,868,542 2037'FWL&2880'FSL Sec0158n4e Bottom Hole Location co-ordinates 360.925 5.868.542 2037' FWL & 2880' FSL Sec OIS Sn 4e Targets Tie On Casing 1 KOP Base Permafrost EOB,HOLO MCU Casing 2 T Tuluvak/Seabee EOH, Drop Holder EOD (Vertical) Nanushuk 3 Core Point 4340' SSTVD Nanushuk 1_5200' SSTVD Possible TD Alpine TO Top of HH TO Top of HRZ 4.4 Formation Evaluation Summary Pilot Hole Final Hole Size MD/TVD na 118'/118' Conductor (NA) 0 Pare Pressure M.D. (ft) T.V.D. (ft) X Co-ord. V Cc ord. (Ppg) est 0 0 360315 5867922 CONVENTIONAL core of upper 18 18 360315 5867922 8.3 120 120 360315 5867922 84 400 400 360315 5867922 8.4 774 773 360332 5867940 8.4 1401 1381 360436 5868045 9.4 2042 1983 3605W 5868202 8.6 2318 2242 360657 5868269 9.9 2489 2403 360698 5868311 8.9 2932 2819 360804 5868419 8.9 3518 3386 360905 5868521 8.9 3933 3800 360926 5868542 8.9 4518 4385 360926 5868542 8.9 5376 5243 360926 5868542 8.9 5676 5543 360926 5868542 9.0 7575 7442 360926 5868542 9.0 8175 8042 360926 5868542 9.0 OH-WL(Possible) Other OH-WL(TBO) LWD Mud Logging Cased Hole 0 0 0 0 Surface 121/4" 231s'/2242' a 0 GR, Re, 1W, Fu IISvc ✓ Cat GR, RT, Den, Neut, Sonic(US), MDT w/ fluid sample, Oil Based FMI, NMR, CONVENTIONAL core of upper Prod/Test el/2" 83R'/8002' ECS or Lithoscanner, Rotary SW Care, ±300 of Nanushuk 3(14416'- GR, Res, sure VSP 4716' TVD) Full Svc y 0 0 0 0 0 0 0 0 0 0 0 Prepared by Stephen F. Hennigan Page 11 4.5 Summary of Potential Drilling Hazards Information Requirements of 20 AAC 25.005 (c)(4) Anapplimdonlora permitm Drill must he accompanied hyeach of thefollowingiteras, exceptforan item aindut onfile with thespmmiclon ordidentRodin the application: (9) in formation on drilling hazards, including A) the maximum downhole pressure that may be encountered, criteria used M determine it, and maximum Paten hotsudare pressure based on a pressure gradient to surface of.i psi perfacit See 4.8 Calculation of Maximum Anticipate Pressures (MASP and MADP) IB) data on potential gas zones, Based upon general experiences of other operators, there is a poten0al as zone below 13300' TVD. Sortare aMae is planned to be set above it. and (C) data comarning potential causes of hole problems such as abnormally gum pressured strata, lost arcudtion zones, andzones that have a propensity for df renrml sticking; There is no local data indicating any potential causes of hole problems. Some Items for Review Hazard Event Wildcat Well Gravel Balling Permafrost Gas Hydrates in PF or slightly below Stuck casing Boulders/rocks/sand Possible depleted zones High drill gas Depth /interval Discussion ALL Surface Gravel can pack off the drilling assy, take mud, etc Surface Balling can reduce penetration rate and can cause packing off. Too much time and too hot a mud will increase washout and Surface possible instability The sands right below include the Upper Schrader Bluff which The Surface be partially frozen. ALL Casing points Surface Control penetration, add Icm, high vis sweeps Prod Offset wells indicated few issues Preoupons Meritor all parameters for exploratoryweh. Maintain a viscuous mud and high gpm/rpm to circ out of hole. Perform additional circulating times as needed. Pump sweeps. Maintain high gpm/rpm to keep bit/BHA dean Perform additional circulating times Be optimal on directional and penetration rates. KEEP mud cool. KEEP mud cool. Maintain surface mW weight as planned. control drill w/ reduced pump rate. Perform multiple conditioning taps drooled, at max to and rpm with stiff BHA PRIOR to running casing. Monitor for Inas of runs Monitor ECD's as a MOSM mud is being used Monitor for ass of nm. Offset wells indicated no issues. However, the Tuluvak sand Prod (below surface pipe) has a high gas contact and has caused Moniiorforronnechonsinhole. rollowinganydriilbreak, circulate hole clean to clear gas before proceeding. problems when surface pipe was not set. Potential Hazards Statement To comply with state reputations the Potential Hazards section and the well shut-in Procedures must be posted in the drillersdoe house. The man on the brake, driller at relief driller is responsible for shutting the well in BOPf or diverter as applicable as soon as warning signs of a kick are detected and an influx is suspected or confirmed. A copy of the approved permit to drill must be kept on location and be readily available to the AOGCC inspector. This well's primary objective is all hydrocarbon bearing zones. No H2S is anticipated. Gas is NOTanticipatedin the shallower intervals. Oil sands are expected. These sands will run from slightly below "normal" to normal pressure. The drilling mud system will be property weighted to control the pressure of all sands and lost circulation materials will be available on location if required. Requirements of 20 AAC 25.005 (c)(9) An appliroaon fora permit M Drill most be accompanied by each of the following, items, except/or an item already on file each the commission and dernped in the application: (9)for an exploratory or strocgmphio test well, a tabulation setting out the depths ofpredlcted abnormally sea pressured strata as required by 20 AAC15.033ft There are no predicted abnormally geo- pressured strata Prepared by Stephen F. Hennigan Page 12 4.6 Drilling Program Summary 4.6 General Summary Well Name Permit to Drill No. Location Planned TD Directional Plan Well Summary Horseshoe g 1 0 Surface: 1438'FWL&2249'FSL Sec0358n4e Topof Productive Horizon: 2037'FWL&2880'FSL Sec0158n4e Bottom Hole: 203?' FWL & 2880' FSL Sec 015 Sn 4e MD: 8175' TVD: 8042' As per program Following ice road and location construction a 16" conductor will be drilled and/ordrlll/d4vento k 118' and a cellar will be installed. Using visced water-based mud, approximately 2318' 1 MD of 12.25' hole will be drilled to 2242't ND where 9.625" surface rasing will be set and cemented to surface. Then an 8.5" hole will be directionally drilled w/ SBM to the approximate raring point of 2 4385' TVD. Following coring, the well will be drilled to 8042't ND and evaluated. Following evaluation, the well will be P&A'd, or casing run, the well tested, and P&A'd. KEY CASING DEPTHS Interval Pilot Hole Hole Size Drive/ Structural 22 Conductor (NA) na Surface 121/4" Pmd/Test 81/2" Pare Pressure/ Mud Program Start Depth Seat Depth Size MD TVD MD ND 16 0 0 118 118 9 5/8" 0 0 2318 2242 7 0 0 8125 8D42 The well will be drilled to TD using WBM on surface and SBM below with a weight of ±10.4 ppg in the production hole section and adjusted as necessary while drilling to TD. Mud Logging i Gas monitoring will be provided in the conductor/surface holes. Basic mud logging services will be provided from SPUD to TD. Services will consist of cuttings description and construction of a Iithology log. The mud loggers will tie their well monitoring system into a PVT system to help monitor fluid levels and system gains/ losses. Logging Program Electric logging (either LWD or/and open hole) will be performed at each casing depth below drive pipe. BOP Testing BOP testing will be conducted at least every seven days and every rasing run. AOGCC Field Inspectors will be notified 48 hours in advance of spud and all diverter/ BOP Tests. It will be noted on drilling report and on IADC sheet whether the test was witnessed by the AOGCC inspector or waived. Waste Disposal i hi All solid waste, including drill cuttings, will be disposed of per regulatory. Excess mud and fluids will be disposed of as permitted. � Completion/Well Testing There is a possibility that this well will be cased and tested (Permit required for testing). A completion/test string and packer will be run. Each potential zone will be perfect, tested, and then isolated. Following the tests, the well will be P&A'd (Permit required). i' Prepared by Stephen F. Hennigan Page 13 4.7 Casing program Summary Buck on float equipment@ yard MU casing to optimum torque = minimum of body and connection strengths 4.8 Calculation of Maximum Anticipate Pressures (MASP and MADP) "-inP Note: In this program, MASP for each hole section is defined as the pore pressure (in psi) at the next casing point (or TD) less a gas column to surface. The MADP is defined as the pressure exerted by the MW at TD of the section. Gas gradient is assumed to be 0.1 psi/ft thru the shallower depths. In the offset wells, most tested oil and/or water which yields a higher gradient. 121/4" Hole Section- estimated pore pressure of 8.6 ppg emw This hole section will be drilled to casing point with BOP's and related equipment installed and tested and with a±9,8 ppg mud weight. Based on available offset information the most likely maximum pore pressure is anticipated to be <S.Sppg EMW. Calculations: MASP(pp) _ ((PP ppge) x.052 x TVD) - (gg x TVD) MASP= 2242'TVD x((8.6 ppge`.052)-0.1 psi/ft) 778 psi MADP = ((PP ppg) x.052 x TVD) MADP= 2242'TVD x(9.8 ppg-0.052) 1143 psi 81/2" Hole Section- estimated MAXI MUM pore Pressure of 9 ppg emw This hole section will be drilled to TD with BOP's and related equipment installed and tested and with a±10.4 ppg mud weight. Based on available offset information the most likely maximum pore pressure is anticipated to be <9.0 Poe EMW. / Calculations: MASP(pp)=((PP ppge) x.052 x TVD) -(gg x TVD) ,^ MASP = 8042' TVD x ((9 ppge•.052) - 0.1 psi/ft) 2959 psi P MADP = ((PP ppge) x.052 x TVD) MADP = 8042' TVD x (10.4 ppg* 0.052) 4349 psi 1 os� Prepared by Stephen F. Hannigan Page 14 Start Depth Seat Depth Casing Interval Hole Size MD1IVQ MDIFVD Sire Wt Ib Grade Conn Burst" Coles Tension' Drive/Structural 22" 01/0' 118'/118' 16 84 x56 Weld N/A Conductor (NAI Surface 121/4" 01/0' 2318'/2242' 95/8" 47 Lao BTC 6870 4760 1086 Prod/Test IT W., 01/0' 8175'18042' 7 " 26 L80 BTC 7240 5410 604 Buck on float equipment@ yard MU casing to optimum torque = minimum of body and connection strengths 4.8 Calculation of Maximum Anticipate Pressures (MASP and MADP) "-inP Note: In this program, MASP for each hole section is defined as the pore pressure (in psi) at the next casing point (or TD) less a gas column to surface. The MADP is defined as the pressure exerted by the MW at TD of the section. Gas gradient is assumed to be 0.1 psi/ft thru the shallower depths. In the offset wells, most tested oil and/or water which yields a higher gradient. 121/4" Hole Section- estimated pore pressure of 8.6 ppg emw This hole section will be drilled to casing point with BOP's and related equipment installed and tested and with a±9,8 ppg mud weight. Based on available offset information the most likely maximum pore pressure is anticipated to be <S.Sppg EMW. Calculations: MASP(pp) _ ((PP ppge) x.052 x TVD) - (gg x TVD) MASP= 2242'TVD x((8.6 ppge`.052)-0.1 psi/ft) 778 psi MADP = ((PP ppg) x.052 x TVD) MADP= 2242'TVD x(9.8 ppg-0.052) 1143 psi 81/2" Hole Section- estimated MAXI MUM pore Pressure of 9 ppg emw This hole section will be drilled to TD with BOP's and related equipment installed and tested and with a±10.4 ppg mud weight. Based on available offset information the most likely maximum pore pressure is anticipated to be <9.0 Poe EMW. / Calculations: MASP(pp)=((PP ppge) x.052 x TVD) -(gg x TVD) ,^ MASP = 8042' TVD x ((9 ppge•.052) - 0.1 psi/ft) 2959 psi P MADP = ((PP ppge) x.052 x TVD) MADP = 8042' TVD x (10.4 ppg* 0.052) 4349 psi 1 os� Prepared by Stephen F. Hannigan Page 14 ( 'f�' 4.9 Casing Design and Calculations Note: In this program, MASP for each hole section is defined as the pore pressure (in psi) at the next casing point (or TD) less a gas column to surface. Gas gradient is assumed to be 0.1 psi/ft. MADP is defined as the maximum hydrostatic in the hole section. AT TIMES MASP CALCULATIONS WILL BE ADJUSTED FOR AIR GAP AND WATER DEPTH when applicable. And may be modified for documented reasons discussed below or in a requested variance. Casing Design Summary Chart (Calculations below) Interval Start Depth Seat Depth Casing Masp Design Factors for.. Final MO MD Size / Wt (lb/ft) Grade BurstTension- Brst Des. Hole Size ND TVD Conn [ellanse Colne Dec Buret Cnllance Tencinn Drive/ 0 118 x56 N/A N/A N/A N/A N/A Hole Section -estimated pore pressure of 8.6 ppg emw 16"-84 ppf 2242' TVD with BOP's installed/tested with a max anticipated mud wt of ± 9.8 ppg from above Structural 22" -_ ___ _ _ _ __ _.................._ 2242'TVD x((8.6 ppge-.052)-0.1 psi/ft) 778 psi _____ ........... MADP = ((PP ppge) x.052 x TVD) 0 118 2242' TVD x (9.8 ppg* 0.052) Weld MASP(fg) _ ((FG + SF ppg) x.052 x TVD) - (gg x TVD) MASP Csg Design = _______ ___._ ______ ______ _.____ N/A _____ N/A N/A ______ N/A 1443 shoe would break down. /psi, Design Factor N________ /A Bunt Strength/ Burst Stress - 6870/ 1442.9512 4.76 SF ___ Prod/Test 8.5" 0 2318 LSO 6870 1086 1443 4.76 6.13 11.72 Surface 12.25" -_-_____ ___-_-_ 9.625"-47 pPf _-_____ ___-__ ___-_-_ ___ _ 8042' TVD x ((9 ppge-.052) -0.1 psi/ft) 0 2242 BT[ 4760 778 MADP = 8042' TVD x (10.4 ppg- 0.052) 4349 psi Prod/Test 8.5" 0 -_______ _ 8175 - 7.26 pPf L80 7240 _-_____ 604 _-_____ 2959 _-_-___ 2.45 _____-_ 1.83 3.38 __ 0 8042 BTC 5410 2.45 SF 2959 Prepared by Stephen F. Hennigan Page 15 0 = minimum of body and connection strengths RECOMMENDED Casing Design Factors BURST (from internal pressure) 1.1 COLLAPSE (from external pressure) 1 TENSILE (joint body and connection) strength 1.6 BURST REQUIREMENTS NOConductor 95/8" Surface 12.25" Pilot Hole no 121/4" Hole Section -estimated pore pressure of 8.6 ppg emw This hole section will be drilled to± 2242' TVD with BOP's installed/tested with a max anticipated mud wt of ± 9.8 ppg from above MASP(pp) _ ((PP ppge) x.052 x TVD) - (gg x TVD) MASP= 2242'TVD x((8.6 ppge-.052)-0.1 psi/ft) 778 psi MADP = ((PP ppge) x.052 x TVD) MADP = 2242' TVD x (9.8 ppg* 0.052) 1143 psi MASP(fg) _ ((FG + SF ppg) x.052 x TVD) - (gg x TVD) MASP Csg Design = 2242' TVD x ((13.8ppge+.5 ppge) -0.1 psi/ft) 1443 psi Burst Stress = MASP Csg Design is used since in case of a kick in excess of 1443 shoe would break down. /psi, Design Factor Bunt Strength/ Burst Stress - 6870/ 1442.9512 4.76 SF 7 " Prod/Test 8.5" 81/2" Hole Section - estimated Pore Pressure of 9 ppg emw This hole section will be drilled to ± 8042' TVD with BOP's installed/tested with a max anticipated mud wt of ± 10.4 ppg from above MASP(pp) _ ((PP ppge) x.052 x TVD) - (gg x TVD) MASP = 8042' TVD x ((9 ppge-.052) -0.1 psi/ft) 2959 psi MADP = ((PP ppge) x .052 x TVD) MADP = 8042' TVD x (10.4 ppg- 0.052) 4349 psi Burst Stress = MASP Csg Design = TD MASP is used since this will be a production string 2959 from below P/ Design Factor Burst Strength/ Burst Stress = 7240 / 2959.456 2.45 SF Prepared by Stephen F. Hennigan Page 15 Use an external pressure that the casing could possibly be put under. One design methodology uses pore pressure at the casing shoe with a gas gradient internally. No Conductor 9 5/8" Surface 12.25" External Pore Pressure less gas gradient MASP(pp) _ ((PP ppge) x.052 x TVD) - (gig x TVD) MASP = 2242' TVD x ((8.6 ppge`.052) -0.1 psi/ft) 778 psi Design Factor Collapse Rating/Collapse stress= 4760/778.4224 6.11 SF 911, 7 " Prod/Test 8.5" External Pore Pressure less gas gradient MASP(pp) _ ((PP ppge) x.052 x TVD) - (gg x TVD) MASP = 8042' TVD x ((9 ppge•.052) - 0.1 psi/ft) 2959 psi Design Factor Collapse Rating /collapse stress= 5410/2959.456 1.83SF t/ Tension is usually defined as the body or connection tensile strength (whichever is least) compared to the buoyed weight of casing in mud when run. Buoyed weight is defined as weight in air minus the weight of displaced fluid that it is run in. Buoyed weight formula=MD -Csg Wt(lb/ft)'(1-mw/ 65.45) where 65.5 is the avg wt per cu ft of iron in air. No Conductor 95/8" Surface 12.25" Buoyed weight= 2338' MD x 47 ppf'(1-9.8ppg/65.45) 92634 pounds Design Factor= tensile strength/ buoyed wt= 1086000/92634 11.725F 7 " Prod/Test 8.5" Buoyed weight 8175'MD x 26 ppf'(1-10.4ppg/65.45) 178776 pounds Design Factor= tensile strength/buoyed wt= 604000/178776 3.38 SF / (L-[5-/6 Prepared by Stephen F. Hennigan Page 16 4.10 Casing Test Pressure Calculations In this well, formation pressure is assumed to be the backup. See Casing design and MASP calculations. See discussion below BOP PROGRAM, Test Pressures and Casino Test Pressures MASP = Maximum Anliciapted Surface Pressure (psi) MADP = Maximum Anticipated Downhole Pressure (psi) 0 TD Casing Size Casing Equipment Test Pressure Low/ Hlgh 16 " Structural Casing 0 118, 21-1/4" 1000 Divener Function Test 70% of Burst WA Test Pressure Function Test " NO Conductor (1) I. Production 250/❑ 700/6 of Burst of weakest csg 5068 Min. (2) Pq 70% of Burst (2) 250/ Test Pressure (1) 250/ MASP NA MADP NA MASP Casing Design N/A 50% of minimum imerrwl yield NA 9.625" Surface Casing 0 2318 (1) 11" 5000 Annular 250/2500 70% of Burst 4809 (2) 11" 5000 Pipe Rams 250/ 4000 Test Pressure 3500 (1) 11" 5000 Blind Rams 25011 4000 MASP 2959 MADP 4349 MASP Casing Design 1443 50% of minimum internal yield 3435 7 " Production 0 8175' (1) Will not drill out 250/ 70% of Burst 5068 Min. (2) Will not drill out Pipe Rams 250/ Recommended Test Pressure 4500 (1) Will not drill out Blind Rams 260,F] Test Pressure 3650 MASP N/A MADP N/A MASP Casing Design 0 50% q% minimum internal yield 3620 70% of Burst Min. (2) 1�q Recommended Testt Pressure (1) Test Pressure MASP N/A MADP N/A MASP Casing Design 0 .50% of minimum internal yield 0 BOP Test Pressuresfor Welltest/Comoletion I. Production (1) 700/6 of Burst of weakest csg 5068 Min. (2) Pq Test Pressure O (1) Prepared by Stephen F. Hennigan Page 17 4.11 Blowout Prevention Equipment Information Fe quiremenG of 20AAC25.005(c)(3) An application fora permit[, Drill must be accompanied by each of the following items, except forun item already onple with the commission andidenthM m the oppliration: f3) a diagram and description after blowout prevention equipment (SOPE) as required by 20MC25.035, 20MC25.036, or20AAC25,D 7,, as applicable, Please see below for summary and Attachment 2 BOP Attachment 3 Choke Diagram Testing: Onsite supervisor will verify all pressure tests. All tests are to be recorded on the IADC and DDR reports. ALL are to be charted. AOGCC to verify BOP tests 148 hr notice) 50% of Casing Casing Casing Size (in) Burst MADP(psi) MASP(psi) Casing Test BOPS Test Fluid Density Pressure (Ib/gal) Ipso** No Conductor NA Surface 12.25' 9 5/8" Prod/Test 8.5' 7 " NA NA 3435 4,349 2,959 3620 N/A N/A 0 MINIMUM Size & Rating Rams are to be variable bore to accept 5" & 4" DP 3500 9.8 (1) 11" 5M annular (1)11" 5M pipe ram (1)11" SM blind ram (1)11" SM drilling spool w/ 3 —1/8" 5M outlets (1)11" 5M pipe ram 3650 10.4 (1)11" SM annular (1)11" SM pipe ram (1)11" SM blind ram (1)11" 5M drilling spool w/ 3 —1/8" SM outlets (I) 11" 5M pipe ram CASING TEST PRESSURE DEFINITION **Casing test pressures are based on 70% of the rated burst pressure of the casing adjusted for the mud weight used during the casing test less a 9.0 ppg backup unless otherwise noted and on the lesser value between 70% of the burst and MASP for EACH hole section. CTP =(0.7 x Internal yield) -(0.052 x(Mud Weight -Backup Mud Weight) x TVD). Liner Casing test pressure is the greater of the Expected Leak -off Test or 500 psi over the previous casing shoe test, adjusted for subsequent liner tests with heavier mud. Liner Top Test =(Previous Frac Gradient- Current Mud Weight) x(0.052) x TVD,. �)). Liner Test=((Frac Grad -Current Mud Weight) x(.052) xTVDIin,r). 4.11a The choke manifold will be rated 31/8" x 5000 psi. It will include a remote hydraulic actuated choke and a hand adjustable choke. Also on the location is a gas buster and a degasser. Flow sensors will be installed in the flowline and the mud pits will have a Fiver system. All data will be available to the driller, company men and key individuals. 4.11b Function Testing: Function on each tour. Report test on daily drilling report (DDR) and IADC. Test Pressure 250 psi Low/high (pd) 0 0 2500 4000 0 0 Prepared by Stephen F. Hennigan Page 18 4.11c Diverter System Information Requirements of 20 AAC 25A05(c)(7) An application fora Permit to Drill mustbe occamppniedby a.& afthe following items, exrept for as item alreadyon file with Die commission and identified In the application: (7) a adlorom and description ofdre divertersystem -remained by 20MC25.035, unless this requirement is waived by the cartar,o m ander20AAC25.035(17)(2), Attachment 4 Dimmer C'onftgumtion 4.12 Wellhead Equipment Summary Com ponent/Description Wellhead See drawing M5LT-EC.L HEAD. ME-330Lv+ER113hCV M DFLO BTM VvilX v595.115WC PI Ea FLSTi-0TJ:' 3-1115 50(X, M STUDDED D'.1 U7t w/ 2 PCO SH v Is,10421 2 V15 MULTa::4c: -_._ I_-_.] SSSV. UPPER. 11-5000 11-5000]A'-- - FLSPCG.v - GEaS. CIw' w/190.9 71 -DM_ TC'D 'C 'P. L-- wr: PACFDFP.M=--i3.':.. El 7DM FEAL- - TL'EING HRN`u .., 4'S), ME -230. 10 Vr 4312. 3 V- 2,0 L -9:0L Fr BTM K, BTM e3725 MU LIFT.3 Hen Tree No permanent completion. Completion for well testing is possible. USE SPACER SPOOL(s) AS NECESSARY Attachment 5 Wellhead Diagmm Prepared by Stephen F. Hennigan Page 19 4.13 Directional Surveying Summary Downhole realtime surveying tool. Interval Iftl Mulft) MWD/LWD Magnetic MUM Gyro Multi El, other Remarks 0 0 118 none 0 [US ft] P/iollft] 0 118 2318 x 0 2318 8175 x 0.00 0 360315.00 4.14 Directional Program Summary Well is to be drilled as programmed. Surveys will be taken per ACGCC regulations. Requirements of 20 AAC 25.050(6) Ifo wellls to be intentionallydeviateo,, the applkationJoro Permit to oral (Farm 10401) most (1) include a pbb drawn to a suit rblesmle, showing Mepath of theprapased weilbang irdeding aaadjacrnt wellbore, within 300 feet ofanyportion of Mie proposed well,, Please see below (2) forall wells whbb 200 feet of the proposed wellbore (A) let the names of the operators of those wells, to the extent that thosenomes ore known or dlsmvembkin publiarecords, andshow thateoch nomedoperatorhes been furnothoo copyof the opplkutlon by certified mail,, or (8)state that the opplimnt is the anty affected owner. NA Comments MD Inclination Azimuth TVD TVDSS Grid East Grid North OLS Build Rate Vert Sect Prepared by Stephen F. Hennigan Page 20 Iftl C] 11 [ft] Iftl [Usftl [US ft] P/iollft] 1/100111 [11] 0.00 0.00 43.52 0.00 -43.00 360315.00 5867922.00 0.00 0.00 0.00 Tie On 17.50 0.00 43.52 17.50 -25.50 360315.00 5867921.00 0.00 0.00 0.00 Casing[ 120.00 0.00 43.52 120.00 77.00 360315.00 5867922.00 0.00 0.00 0.00 NOP 400.00 0.00 43.52 400.00 357.00 360315.00 5867922.00 0.00 0.00 0.00 Base �- Permafrost 774.12 7.48 43.52 773.00 730.00 360332.41 5867939.68 2.00 2.00 24.82 EOB,HOLD 1400.76 20.02 43.52 1380.53 1337.53 360436.41 5868045.26 2.00 2.00 173.03 MCU 2041.96 20.02 43.52 1983.00 1940.00 360590.40 5868201.60 0.00 0.00 392.49 Casing 2 2317.50 20.02 43.52 2142.00 1198.90 360656.58 5868268.78 0.00 0.00 486.80 T Tuluwk/Seabe e 2488.96 20.02 43.52 2403.00 2360.00 360697.76 5868310.59 0.00 0.00 545.48 EOH, Drop 2932.20 20.02 43.52 2819.47 2776.47 360804.21 5868418.66 0.00 0.00 69719 Holder 3517.50 8.31 43.52 3386.00 3343.00 360904.52 5868520.50 1.00 -2.00 840.15 EOD (Vertical[ 3932.96 0.00 43.52 3800.00 3757.00 360925.62 5868541.92 1.00 -2.00 870.22 Nanushuk3 Core Point 4340'SSTVD 4517.50 0.00 43.52 4384.54 4341.54 360925.62 5868541.92 0.00 0.00 870.22 Nanushuk 1_5200'SSTVD 5375.96 0.00 43.52 5243.00 5200.00 360925.62 5868541.92 0.00 0.00 870.22 Possible TO 5675.96 0.00 43.52 5543.00 5500.00 360925.62 5868541.92 0.00 0.00 870.22 Alpine 7574.96 0.00 43.52 7441.00 7400.00 360925.62 5868541.92 0.00 0.00 870.22 TDTopof HU 8174.96 0.00 43.52 8042.00 8000.00 360925.62 5868541.92 0.00 0.00 870.22 Prepared by Stephen F. Hennigan Page 20 Armstrong Energy,LLC ocv rqE Igy SO. HOR46bM Al -`11urg Energy ;_ _ %:,rttl Toe VINI: FIOREY10Nf1 ^ r ri.s ew Ns J+i Eai MN. sc.:w MJ1 Prepared by Stephen F. Hennigan Page 21 FMf�E �3 wpe Pte„ +'n_.M Aww YM F .w i. fir• _ .:� ..ry ]pYm Y-• - YnY d - ffmvv-.v. - �T Y J+i Eai MN. sc.:w MJ1 Prepared by Stephen F. Hennigan Page 21 r +'n_.M Aww YM F .w i. fir• _ .:� ..ry d . ..vY PJM iHw.i l i0 .. _ _ •. ,_,WAS\ �.. J+i Eai MN. sc.:w MJ1 Prepared by Stephen F. Hennigan Page 21 4.15-4.16 Drilling Fluids Program Summary and Speciacatiou_ Regolrements of20 AAc 25.005(,)(8) An appllmtier fora Permit to Orlli must be accompanied by each of the fallowing items, except for an item already an file with the commission and identified in the application: (8) a drillingjimaprogrom, mil dingo diagram and description ofthe drillingfuldsystem, as required by 20MC25.033,' Drilling will be done with muds having the following properties over the listed intervals: Mud Program Overview Depth (MDI MOW Funnel PV Yield Point Gels pH API FL ppp V. ,P 1,11100101D.10mn m HTHP FL Chloride SLDS 2WF -00VMetseeks6VtwN rayl 0'.2,318- 9.8 85-275 10-30 25-65 20/35 >9.0 <14 N/A N/A X10 1 Build initial volume for cleaning out conductor and drilling surface interval. Begin system with a 45 YP and reduce once clays are encountered. Be prepared to increase the YP if hole cleaning becomes an issue. 2 AQUAGEL and BARAZAN D+ should be used to maintain rheology. 3 DEXTRID and PAC Lshould be used to keep the API Fluid loss below 14. 4 Background LCM (10 ppb total) BARACARBs/BAROPIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. 5 Additions of CON DET PRE-MDUDRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating high -clay content sections. 6 Maximize the use of solids control equipment while drilling to reduce low gravity solids (<10%). 7 Maintain the pH above 9.0 range with caustic soda. 8 Daily additions of ALDACIDE G / X -CEDE 207 MU T be made to control bacterial action. 9 At TD, a Wallaut "Dag" (20 bbl pill with 15 ppb of Wallnut M) could be pumped to gauge hole washout -to help calculate the requited cement volume. 10 IF casing is to be con, Reduce system YP with BARATHIN PLUS/DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). Depth Mud WL Funnel PV Yldd Point Gets WA API FL HTHP FL WPS ES (MDI PPr Va wtoom 10a 10rin m MF Ppm v setlq Iw1m le 2,3100,115 10.4 W 80 M37 15-25 15-25 859.5 WA 6 250-270K x600 I Build new/recondition used EN VIROMUL MOBM for drilling the 8 1/2" hole section. Preveat with EZ MUL NT and INVERMUL NT for interface with waterbased mud (WBM). Clean mud pits of WBM residue. 2 Drill out the 9 5/8" easing shoe with spud mud from an isolated pit Displace well with MOBM and perform FIT. 3 While dNling GELTONE and SUSPENTONE should be used to maintain rheological parameters. 4 BARACARB 5/25/50 should be maintained at 5 ppb 5 BARABLOK and DURATONE (confine DURATONE approved prior to use) to control shale and HPHT fluid loss. 6 Maintain the mud as clean as possible with solids control equipment while drilling. 7 Should LCM be required, do not exceed 35 ppb without consulting MWD personnel. 8 The system rheology may be relaxed as hole conditions allow. This will also lower the ECD for any possible loss zones which might be found and reduce swab tendencies. However, be prepared to increase the YP if hole cleaning becomes an issue. 9 Reduce system YP as required for muning casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP <20 (check with the cementers to see what YP value they have targeted). 10 Maintain a NAP/water ratio between 75/25 and 85115 Core point for this interval will be 4,400' SSTVD. While coring add l0sx1hr of BARACARB 25 and/or BARACARB 50 for brideina aoDlications. Prepared by Stephen F. Hennigan Page 22 4.17 Solids Control Equipment Interval Shaker Desander Desilter Mud Cleaner Centrifuge Cuttings Dryer Cuttings Injection Zero Discharge Comments -Total Depth 1 2 1 1 1 N/A Cuttings Injection N/A yes Run shakers with finest screens possible. Item Equipment Specifications (typical but may not be exact depending on rig) (quantity, design type, brand, model, flow capacity, etc.) Shaker 2 Brandt King Cobras Degasser 1 Brandt DG -10/12 Vacuum Degasser Desander See Mud Cleaner Desilter See Mud Cleaner Mud Cleaner 1 Brandt Mud Cleaner w/ King Cobra Hybrid Shaker, a SRS -2 cone Desander & SE -16 cone Desilter(This can also be used as a 3rd shaker) Centrifuge NA Cuttings Dryer N/A Cuttings Injection N/A Zero Discharge jUsing cuttings bin and super sucker. Hauling to G&I facility. 4.17b Requirements of20 AAC 25,005(c)(14) An application fora Permit to Drill must be accompanied by each of the fallowing Items, exceptforan item already on file with the aamension andident(ed in the appllcation: (t AJ a general description ofhow the oCemtor plans to dispose of drilling mud and ivUinia and a shater ent of whether the apemta inhMs to requestauthonzatiao under20 AAC25.De0 furan annular disposal operation in the well, All solid waste, including drill cuttings, will be disposed of per regulatory. Excess mud and fluids will be disposed of as permitted. See attached for rig - site handling procedure. Attachment 6 Typical Cuttings Handling Diagram Prepared by Stephen F. Hennigan Page 23 4.19 Bit Summary -ESTIMATED �.. Proposal prepared for: BAKER ARMSTRONG ENERGY, LLC HUGHES n�a- ve+Da 23x3 1 85. Max 5919 2 2.183 15 150 15 Sail 120M Ureraerei Molar Rcn 9125 Cmva'.a 23D4 3,616 w 119.99 15 520 30 220 Wls M<dor • Center let • Metal Face Seat & Bearing System Recommended Bit prep'.. 093 041 t1pHM v vrrnua load Bn WDG 13r, 1a:9aIY u.n1�Rr91 �aw.m•urro.xrd mnn9 tK1em 230 29 151 1.91 DirOaaonal MCObOb. 19M Hes. nomaes m +.w«mu wn.msc-, tard su1�.r+oro • 9ART Apff vs • Gereol purtnae'aler Profits 6 • OPcmaed Hymawr ElficwMy • Otlw� non rtar,dard or prosotype <ulten • SiaySfiarp"pe9thN Cwew Techn91a • 'dcn^ OPdmaad Blade Pr k • Undenut Gauge Prepared by Stephen F. Hennigan Page 2S 4.20 Procedure for Conducting Formation Integrity Tests Requirements of 20 AA 25,005 (c)(5) An application fora Permit to Drift mustbe anu mponied by each of the following items, exrept far on item alrevdy on file with themmmissma and ideati)iedin the a,alkwi.n: (5)a description of theptocedure formaductingformation integrity tests, as required under 10AAC25.030(0, Perform Casing Test (CIT) the pressure to which the casing should be tested should be 300-400 psi above the expected surface pressure needed for the leak off test. It is NOT necessary to retest to the APD casing test pressure. 1. GIH and clean out to the top of the float collar for casing test. 2. Circulate and condition mud until shaker is free of cuttings and mud weight in is within +/- 0.1 ppg of weight out for several consecutive measurements. 3. Rig up, pressure test and check for leaks. Make sure air is purged from the system. 4. Pumping down the drillpipe, break circulation with cementing unit (or low vol/high press pump). S. Close annular BOP or pipe rams. 6. Pump down drilloiae at 1/2 bpm. Do not exceed this rate and maintain constant rate as well as possible. Record pressure at each 1/2 bbl increment pumped. NOTE. Larger than 313/4"use J5-1 bpm,113/4-95/8 use JS -.S bpm -plotshouldbetgramerthan AS - 7. Continue until the test pressure (as described above) is reached. Do not exceed test pressure. Stop pump and shut in valve. B. Monitor and record shut in pressure; hold for at least 5 minutes, or as specified. Troubleshoot problems if desired test pressure cannot be obtained. 9. Release pressure and record volume of fluid recovered during flow back. 10. Input recorded pressures and corresponding volumes on the Casing Test section of the "CSG -FIT" worksheet (in the yellow shaded area). This is the minimum volume line for the subsequent leak off test. Enter flow back when pressure is released. Prepared by Stephen F. Hennigan Page 26 Perform Formation Test (LOT, FIT, etc) -enter oil the header information for the well, rig, casing size, shoe depth, mud weight date and your name at the top of theform on the "CSG -FIT" worksheet. 1. Drill shoe track and +20' of new formation. POOH into the using shoe. Circulate and condition mud until shaker is free of cuttings and mud weight in is within +/- 0.1 ppg of weight out for several consecutive measurements. 2. Rig up lines, pressure test and check for leaks. Make sure air is purged from the system. 3. Pumping down the drillpipe, break circulation with cementing unit (or low vol/high press pump). 4. Close annular BOP or pipe rams. 5. SLOWLY pump down drillpipe and maintain constant rate as well as possible. Required rate may vary, but first attempt should be at 1/2 bpm (OR same rate as casing test). Record pressure at each 1/2 bbl increment pumped and plot on the FORM INTEG.TEST (FIT) section of the "CSG -FIT" worksheet (in the blue shaded area). This will require teamwork among at least two, but better with three individuals. If the FORM INTEG. TEST (FIT) plot curves BELOW the Maximum Volume Line, stop and bleed off pressure then re -run the test at a higher pump rate (suggest 1/4 bpm higher). Note - also have someone record using pressure from the choke manifold at the same -- bbl increments. H these pressures differ from the drillpipe recorded pressures by more than 10%, notify the office. 6. Continue until leak off (fracture initiation) is detected as indicated by a change in the rate of pressure increase. This is determined by the leak off test chart and observation of the pressure behavior. Once leak off indications are noted continue to pump at constant rate to confirm. If the pressure resumes a constant rate of increase, continue pumping and watch for subsequent leak off indications. If the rate of pressure increase continues to decline, continue pumping for 3 more _ bbl increments to insure fracture has occurred (a noticable pressure drop should be evident). If a sudden pressure drop occurs, stop pumping immediately. Prepared by Stephen F. Hennigan Page 27 7. Record instantaneous shut in pressure (ISIP). Also see #11 below. Monitor and record shut in pressure every minute for at least 10 minutes. 8. Release pressure and record volume oflfuid recovered during flow back. 9. If the measured leak off pressure is less than the predicted leak off, then a cement channel may exist. Whenever a cement channel is suspected, the LOT should be repeated for confirmation. If a channel exists there should be little or no improvement seen. LOT or FIT or PIT It. EMWI = Pressure firsil /.052 casing shoe depth LTVD+ current mud we ht 10. If the Leak Off plot falls between the Minimum and Maximum Volume Lines, this is a good leak off plot. Pick the point on the curve where the line begins to break over (the rate of pressure increase has changed from a straight line). This is the leak off value. On a "jug" test, there is no bend. PPG equivalents are calculated on the right. 11. Input recorded pressures and corresponding volumes on the FORM INTEG.TEST (FIT( section of the "CSG -FIT" worksheet. Values should initially fall between the Maximum volume line and the Csg Test line. 12. Input recorded shut in pressures and corresponding times on the Shut In Pressure (ISIP) section of the "CSG -FIT' worksheet (in the yellow shaded area). This is indicated by ISIP and incremental time @ the bottomof FORM INTEG. TEST(FIT) section. 4.21 Seismic Analysis Requirements of 20 AAC 25.005 (c)(10) An application to: a Permit to Dral must be o amnaoniedby each of the following items, except for an item already onfde with the cammusron and dentiledin the apprlmtion: flAfora expromtoryarstraDgmphie test well,aseumkrefmohns amflecthmmmhais, as required by 20AAC25.061(f)1 See shallow hazard 4.22 Seabed Condition Analysis Requirements of 20 AAC 25.005 (c)(11) An opplicalroa fora Permit to Drill must bearcomponied by each of the joAowing items, exreptfor an item alreadyon fish` with the commission and identified in the pppliwtio s: (11) fora well diilledfrom an offshore platform, mobile bottom-foundMstrucWm jo&-up rig, orpootrngdrillrng vessel, an analysts ofseabedroMrtlons as required by 20AAC15.061(b); Not applicable: Application is not for an offshore well. ✓ 4.23 Evidence of Banding Requirements of 20 AAC 25.005 (c)(12) An opplicadonfor a Permit to Drill most be accompanied by each of thefollowing items, exreptforan item already onfile with themmmisston andidentPed in theopplimbon: (12) evidence showing that the requirements of20AAC25.015 have been met Evidence of bonding is on file with the Commission. t/ 4.24 Proposed Drilling Program Requirements of 20 AAC 25.005 (c)(13) An application fora Permit to Drill must be accompanied by each of the following items, exreptfor on item already on file with the commission and identified in the application: (13)o copy ofthe appased' drilling program Attachment 8 Drilling Procedure Summary t/ 4.25 Shallow Hazard Analysis Requirements of 20 AAC 25.061 well sitesurveys (a) Far. exph mtoryorstralymphic test well, nearsurfacestmta to a depth of 2,000 feetln the vicinity of the well must be evoluatedseumkallybycommon depth pointrefraction armfkc0on pmfrlandury t, urbyanothermethodoPmovedby the commission, to identify onomalous velocity variations indicative ofpotentralshaldw gas sources. Analysivesults most be included with the opplication forthe Permitto Drill (Form 10401). AttachmentA Shallow Hazard Report Prepared by Stephen F. Hennigan Page 28 4.26 ALL Attachments Attachment 1 Included Permit Plats, lease plats, etc Attachment2 BOP Attachment3 Choke Diagram Attachment4 Diverter Configuration. Attachment 5 Wellhead Diagram Attachment 6 Typical Cuttings Handling Diagram Attachment Cementing Program Summary Attachmentil Drilling Procedure Summary Attachment Pad Layout Attachment 10 General Arrangement Attachment 11 Post Well Cosing/Cementing Summary AttachmentA Shallow Hazard Report Prepared by Stephen F. Hennigan Page 29 0 G Oil & Gas This drawing Is the property of GE Oil & Gas Pressure Conbol LP and Is considered confidential. Unless otherwise approved in wnPog, ARMSTRONG neither It nor Its contents may be used copletl, hsnsmltled or reproduced except for the sale purpose of GE Oil & Gas Pressure Control LP. 16" x 9-5/8" x 7" x 3-1/2" 5M MB -230 Conventional Wellhead DRAWN CR 09AUG16 APPRV KN 09AUG16 Assembly, With MB -230 Upper Head, FOR REFERENCE ONLY MB -230 Tubing Hanger and K Tubing Bonnet DRAWING NO. 10011822 Armstrong Energy Horseshoe 1 Well Cementing 16" Conductor Casing: 1. Prior to cementing casing: • Check cement lab test for sufficient pumping time, free water and fluid loss. • Discuss job with cementer and customer, double checking calculations for water, displacement, etc. • Verify all hoses and lines are in good shape and on site. Have extra hoses and high pressure pump iron available. • Ensure that appropriate circulating swage/tie-in is on location prior to running casing. • Total Water Required for the job: 150 bbl heated to 7080 F Cement the casing as follows: Pump 5-10 bbl of Cement Into the inside of the conductor casing and allow to set. Tie into provided iron to pump cement Into annulus between conductor and OH. Spacer: 5 BBL Use Fresh Water to pressure test cementing iron Lead Slurry Cement 410 SK Class G Cement + Additives 15.6 ppg, 71 BBL This also includes 1.5 It of fill in the cellar Open Hole Excess 50% -7 " p Displacement Spacer: 5 BBL Use fresh water to clean lines Estimated Top Cement Slurry Surface PROPERTIES Lead Slurry Weight 15.6 Yield 0.96 Water 3.81 Note: The final slurry design will be provided after testing cement, additive and mix water samples prior to performing the job. 2. After Cementing, record the following: • Time cement in place • Pressure used to place. • Amount of barrels pumped behind cement. • If and when cement was seen at surface. Cementing 9-5/8" Surface Casing: 1. Prior to cementing casing: • Check cement lab test for sufficient pumping time, free water and fluid loss. • Discuss job with cementer and customer, double checking calculations for water, displacement, etc. • Verify all hoses and lines are in good shape and on site. Have extra hoses and high pressure pump iron available. • Verify that wiper plugs are loaded in cementing plug assembly. • Drift casing prior to running. • Ensure that 9-5/8" circulating swage is on location prior to running casing. • Total Water Required for the job: 550 bbl heated to 70.80 F Cement the casing as follows: Bump the plug with 500 psi over circulating pressure. Immediately prior to shutting the pumps down record and report the pump pressure ON A RATE/TIME/PRESSURE basis ±5-10 minutes. Hold pressure for 5 minutes. Release the pressure and confirm the floats are holding. Do not over displace by more than half of the shoe volume. Spacer: 5 BBL Use Fresh Water to pressure test cementing iron Spacer: 40 BBL CleanSpacer 111 10.5 ppg Lead Slurry: 785 SK Class G Cement +Additives 11.1 ppg Permafrost L 580 BBL Excess 500% Tail Slurry: 220 SK Class G Cement + Additives 15.8 ppg 45 BBL Excess 40% 500 ft of fill Displacement Spacer: 5 BBL Use fresh water to drop Top Rubber Plug 5T; Displacement Fluid: 20 BBL Displacement Fluid —25 BBL Total Displacement Estimated Top Cement Slurry Surface PROPERTIES Lead Slurry Weight 11.1 Yield 4.15 Water 21.41 PROPERTIES Tail Slurry Weight 15.8 Yield 1.16 Water 5.03 Note: The final slurry design will be provided after testing cement, additive and mix water samples prior to performing the job. Displacement design assumes 4" 14 ppf drill pipe inner -string. 2. After Cementing, record the following: • Time cement in place • Pressure used to displace. • RATE/TIME/PRESSURE after slowing down in anticipation of bumping plug. • Amount of barrels pumped behind cement. • Amount of barrels bled back to check floats. • When and if returns were lost while cementing. /' IN C�A2 J Cementing 7^ Production Casing Two Stage: 1. Prior to cementing casing: • Check cement lab test for sufficient pumping time including shutdowns, free water and fluid loss. • Discuss job with cementer and customer, double checking calculations for water, displacement, etc. • Verify all hoses and lines are in good shape and on site. Have extra hoses and high pressure pump iron available. • Verify tool operations and plug dropping order and procedures. • Drift casing prior to running. • Ensure that circulating swage appropriate for 7" is on location prior to running casing. • Total Water Required for the job: 400 bbl heated to 7080 F, This number assumes that any displacement not explicitly described below as using spacer will be drilling mud or some other fluid from the rig. Cement the casing as follows: Bump the plug with S00 psi over circulating pressure. Immediately prior to shutting the pumps down record and report the pump pressure ON A RATE/TIME/PRESSURE basis ±5-30 minutes. Hold pressure for 5 minutes. Release the pressure and confirm the floats are holding. Do not over displace by more than half of the shoe volume. Stage 1 ES Cementer placed at 2800 ft Spacer: 5 BBL Use Fresh Water to pressure test cementing iron Spacer: 40 BBL CleanSpacer 111 11.0 ppg Lead Slurry: 85 SK Type I Cement + Additives 12 ppg 38 BBL Excess 40% Tail Slurry: 255 SK Class G Cement + Additives 14 ppg 69 BBL Excess 40% 2000 ft of fill Displacement Spacer: 5 BBL Use fresh water to drop First Stage Shutoff Plug Displacement Fluid: 101 BBL Displacement Fluid: 20 BBL Spacer to cover the tool ports Displacement Fluid: 97 BBL Displacement Fluid -223 BBL Total Displacement Estimated Top Cement Slurry 2800 ft PROPERTIES Lead Slurry This is the same slurry for Stage 2 Weight 12 Yield 2.48 Sscs,�� Water 14.68 G S'7ov M PROPERTIES Tail Slurry Weight 14 Yield 1.526 Water 7.73 Stage 2 Spacer: 5 BBL Use Fresh Water to pressure test cementing iron Spacer: 40 BBL CleanSpacer 111 11.0 ppg Lead Slurry: 170 SK Type I Cement + Additives 12 ppg 75 BBL Excess 40% Displacement Spacer: 5 BBL Use fresh water to drop Closing Plug Displacement Fluid: 102 BBL Displacement Fluid —107 BBL Total Displacement Estimated Top Cement Slurry Surface Note: The final slurry design will be provided after testing cement, additive and mix water samples prior to performing the job. Please reference Armstrong Horseshoe #1 Two -Stage Production Casing Procedure for more detailed tool operations. After Cementing each stage, record the following: • Time cement in place • Pressure used to displace. • Pressures to open/close the tool • RATE/TIME/PRESSURE after slowing down in anticipation of bumping plug. • Amount of barrels pumped behind cement. • Amount of barrels bled back to check floats. • When and if returns were lost while cementing. Armstrong Energy Horseshoe 1 Well Cementing r Production Casing PM75' MD Two Stage: 1. Prior to cementing casing: • Check cement lab test for sufficient pumping time including shutdowns, free water and fluid loss. • Discuss job with cementer and customer, double checking calculations for water, displacement, etc. • Verify all hoses and lines are in good shape and on site. Have extra hoses and high pressure pump iron available. • Verify tool operations and plug dropping order and procedures. • Drift casing prior to running. • Ensure that circulating swage appropriate for 7" is on location prior to running casing. • Total Water Required for the job: 500 bbl heated to 70-80 F, This number assumes that any displacement not explicitly described below as using spacer will be drilling mud or some other fluid from the rig. Cement the casing as follows: Bump the plug with 500 psi over circulating pressure. Immediately prior to shutting the pumps down record and report the pump pressure ON A RATE/TIME/PRESSURE basis ± 5-30 minutes. Hold pressure for 5 minutes. Release the pressure and confirm the floats are holding. Do not over displace by more than half of the shoe volume. Stage 1 ES Cementer placed at 2800 It Spacer: 5 BBL Use Fresh Water to pressure test cementing iron Spacer: 40 BBL CleanSpacer 11111.0 ppg Lead Slurry: 90 SK Type 1 Cement + Additives 12 ppg 40 BBL Excess 40% Tail Slurry: 505 SK Class G Cement + Additives 14 ppg 137 BBL Excess 40% Top of Tail 4000 ft Displacement Spacer: 5 BBL Use fresh water to drop First Stage Shutoff Plug Displacement Fluid: 185 BBL Displacement Fluid: 20 BBL Spacer to cover the tool ports Displacement Fluid: 98 BBL Displacement Fluid -308 BBL Total Displacement Estimated Top Cement Slurry 2800 ft PROPERTIES Lead Slurry This is the same slurry for Stage 2 Weight 12 Yield 2.48 Water 14.68 PROPERTIES Tail Slurry Weight 14 Yield 1.526 Water 7.73 Stage 2 Spacer: 5 BBL Use Fresh Water to pressure test cementing iron Spacer: 40 BBL CleanSpacer 111 11.0 ppg Lead Slurry: 170 SK Type I Cement + Additives 12 ppg 75 BBL Excess 40% Displacement Spacer: 5 BBL Use fresh water to drop Closing Plug Displacement Fluid: 102 BBL Displacement Fluid —107 BBL Total Displacement Estimated Top Cement Slurry Surface Note: The final slurry design will be provided after testing cement, additive and mix water samples prior to performing the job. Please reference Armstrong Horseshoe #1 Two -Stage Production Casing Procedure for more detailed tool operations. 2. After Cementing each stage, record the following: • Time cement in place • Pressure used to displace. • Pressures to open/close the tool • RATE/TIME/PRESSURE after slowing down in anticipation of bumping plug. • Amount of barrels pumped behind cement. • Amount of barrels bled back to check floats. • When and if returns were lost while cementing. DRILLING OPERATIONS SUMMARY Armstrong Energy, LLC Horseshoe # 1 Block/Sec 015 8n 4e Wildcat North Slope Alaska Start Depth Seat Depth Casino Interval Hole Size MD D MD TVD Size lb tt Grade Conn Burst* Collapse Tension* Drive/ Structural 22 0 0 118 118 16 84 X56 Weld Conductor (NA) Surface 12.25 0 0 2318 2242 9.625 47 L80 BTC 6870 Prodfrest 8.5 0 0 8175 8042 7 26 LBO BTC 7240 * = minimum of body and connection strengths Buck on float equipment @ yard MU casing to optimum torque Notes: • SAFETY, HEALTH, AND THE ENVIRONMENT, COME FIRST throughout the operation. • AOGCC MUST be notified 48 hrs prior to each diverter function and BOPe test. • All test pressures in procedure should be checked on the rig by Supervisor / Consultant, any discrepancies should be discussed with Office Supervisor. • Hold diverter drills until crews are familiar with diverting procedures. • While drilling w/diverter, if a positive indication of influx is observed, mud will be pumped at the fastest rate possible. The pumps will be switched to water if all the mud is pumped away without a kill. • Monitor the ice (ground) around the rig for possible broaching to the surface. • Drilling to each casing string depth (after the drive pipe) will require an additional ±20' to allow hanging off the casing in the wellhead. • A compliance matrix will be constructed and the operation will be in compliance of all regulatory bodies. Structural (Drive/Conductor): 1. Drill/Drive 16" conductor to +/- 118ft. RKB. RD conductor rig. Install cellar. NOTE: Should be installed prior to rig arrival by construction. 2. Notify ALL appropriate parties and agencies, LAND OWNERS, etc. of pending rig move. 3. MIRU rig. Post drilling permit(s) and prognosis in Company man's office and rig floor. Place MSDS sheets at required locations PERFORM Wellsite pre -scud meeting. Perform detailed HSE meeting Establish Severe Weather responsibilities and POST same. AND other as appropriate. NOTE the following fa"ha AAf1 Rig 111 i. sittin on ice and mats GL is defined as TOP OF MATS.. ii. eve wn engs 4. Install starting head 16" SLC x 21 Y4", 2M flange. tv� 5. Nipple up 21 /4", 2M diverter, 16" diverter valve andiverterli e. Make sure control lines are installed at an angle to diverter line. NO lines should be above the diverter or diverter line INSIDE the diverter valve. G(, 6. Function test diverter and diverter valve. (AOGCC 48hr notice) A D f.1 &)V 7. Build/ take on spud mud. Lop. tslu 8. Inspect BHA equipment. 9. Install mud loggers per logging program. Instruct same regarding dry ditch samples for AOGCC. 10. ORDER CONVENTIONAL CORING EQUIPMENT. 7 DAYS NOTICE IS REQUIRED. Notify core handling company as well. Identify area for Laydown Cradles and handling. NOTE: New cementing regulation 20 AAC 25.030 is being amended and nm sections added to read: 20 AAC.25.030 Casing and cementing. (d) (i) intermediate and production casing must be cemented �Nith .ullicieut cement to fill the annular space from the casing shoe to ;t minimum of 500 vertical iect abo%e all significant hydrocarbon zones and abnormally -co-pressured strata or. if zonal co%eragc is not required under (a) of this section. from the casing shoe to a minimum of'Iif) vertical feet ahme the casing shoe: if indications of improper cementing exist. such as lost returns. or it' the formation integrity test shoes an inadequate cement job. (REIIFINAL :V TION MI!SI BF FAKIN; (A) the operator shall notify the commission and obtain approral before drilling ahead; and (B) provide: (i) a cement quality Iug or other srpproaed method to evaluate the adequacy of the cement to contain potential wellbore pressures and fluids• and (ii) a Plan setting forth the remedial actions proposed to briny the well into compliance with the requirements of (a) of this section; Surface: 1. Conductor is to be preinstalled. • Mud Program • Bit Program • Directional Program w/ BHA's • Cement Program • Wellhead Program 2. PU 4" drill pipe, bit and DIRECTIONAL BHA w/ GR/RES per bit/directional proposal. Set up WEEKLY STATUS Report for the Commission. 3. Drill w/ low rpm, gpm until stabilizers have exited drive pipe. Run max gpm, rotary, etc as allowed. Set up logging (if any) as per evaluation section. 4. Drill 121/4" hole to KOP of ±200'-400' TVD/MD. 5. Continue to drill a directional 12 /4"hole to ±2318' MD/ 2242' TVD short tripping and pumping sweeps as considered necessary. At hole section TD, pump a HIGH VIS sweep and circulate the hole clean. Repeat until hole is slick. Strap out of hole. Note: No elog evaluation is anticipated for this hole interval at this time. NOTE: Prep for stab -in cementing lob. _PREP for displacing spud mud with MOBM after cementing. NOTE: Make sure that "for all casings" that landing jts and csg ram test its and cross overs for them ARE ON SITE. Make sure that a top out string is on location. 6. TIH. Short trip. Circulate hole clean at max rpm and gpm. Pump a high vis sweep. Repeat until slick. 7. Condition mud to lower YP and gels (make sure gels are flat). Monitor pill lag and mud log lag times to aid in adjusting cement volumes for hole washout. Circulate hole clean at max rpm and gpm. Pump a high vis sweep. Repeat until slick. 8. Prep for excess mud, cement, rinse water, etc disposal. 9. Calculate landing equipment to make sure we have proper space out with top of landing jt ±4-6' above rotary. Run 9 5/8" surface casing as follows Baker -Locking the shoe track: a) Shoe b) 2 its casing c) Stmg-m col ars asmg With centralizers placed as follows: e) 2 bow -springs with stop collars in center of bottom 2 jts f) Centralizers across the bottom 2 couplings g) 1 centralizer across the coupling of every third it h) NO CENTRALIZER INSIDE CONDUCTOR AS CASING NEEDS TO BE CENTERED IN ROTARY i) ESTIMATED TOTAL centralizers =±23 w/ 2 stop collars 10. Perform a running tag. Reciprocate casing. Circulate and condition mud at a rate not to exceed the AV around the collars while drilling. Again condition mud for flat gels. 11. RU stab -in eauioment..RIH w/ DP and stab in sub w/ centralizer, stab in float collar and break circulation. RU cementing head and lines. Test to 500/5000psi. Cement 9 5/8" casing PER cementing proposal with the inner string, cut off cementing when cement reaches surface, dump 2-5 bbls on top of sting -in collar. Circulate clean. Cement volumes are presently designed with 500% excess. Adjust as necessary to allow for cement returns to surface. Report amount of returns to surface on daily report. (See note following #16 below.) 12. Pump spacers and displace with MOBM. 13. ND Diverter. Cut casings. 14. Install 9 5/8" slip lock connection X 11" 5M' flanged multibowl wellhead. Test to 50% of casing collapse or 1500 psi whichever is greater. 15. NU adapter spool. NU 11" 5M BOPs. Test BOPs and choke manifold to 250/4000 psi, annular to 250 000 (AOGCC 48 hr notice). Pipe rams are to be 2 7/8" x 5" VBR's, blind rams, ipe rams (may have variable as well). ,IV P5� NOTE: (BOPe MUST be tested every 7 days during the remainder of the well. AOGCC must be notified at least 48 hours before) NOTE: Maintain good communications with regulatory. Communicate with the inspector every couple of days just to let regulatory know current opns. 16. Set wear bushing. Run C : A +- ��`feG, NOTE: If there is no cement to surface, below are instructions'to follow: as� , AOGCC Industry Guidance Bulletin 13-001 Remedial Cementing (aka "Top,lob") for Surface Casing Alaska Oil and Gas Conservation Commission (AOGCC) regulations governing cementing are found at 20 AAC 25.030. Paragraph (d)(4) requires the annular space of surface casing (conductor -surface casing annulus) to be tilled with cement from the casing shoe to the surface. An inadequate primary cement job is evidenced by cement not circulated to surface, an excessive quantity of cement circulated to surface, or results of a formation integrity test that indicate insufficient integrity of the casing shoe. Regulation 20 AAC 25.030(d)(4) continues with required actions if an inadequate surface casing cement job occurs. The operator shall: • notify AOGCC before drilling ahead, AND • evaluate adequacy as described (cement quality log or other AOGCC approved method), AND • take remedial action as necessary- to meet the design requirements of a well casing and cementing program as outlined in 20 AAC 25.030(a). The following clarification is provided to address actions that are to be taken in response to inadequate surface casing cementing: • Contact AOGCC as soon as become aware of inadequate cementing using notification procedures outlined in AOGCC Industry Guidance Bulletin 10-01 A; • Prepare a plan for remedial cementing and submit to AOGCC for review and approval (email submittal is acceptable); an .Application for Sundry Approvals (Foul 10403) is required; o Include details about primary cement job - volume pumped; any diagnostics prior to cement job to confirm hole sizeivolume cement needed (e.g.. tracer); problems during cement job; is gas bubblingiflowing7; etc. • Notify AOGCC Inspectors for an opportunity to witness the procedure that will be used to determine top of primary cement in the conductor -surface casing annulus; • Run small diameter pipe or other conduit to top of cement and pump "top job" per approved procedure; • If cannot definitively identity the primary cement top. notify AOGCC before pumping cement and discuss options; Intermediate/Prod: 1. PU 8 %2" PDC bit and BHA w/ LWD per directional evaluation program. Clean out casing to float equipment. Test casing to 3500 psi recording on a chart. NOTE: Updated casing test regulations below (e) A casing pressure test must be pertonned if 13UPF is to be installed on a casinL. I he casing must be tested to bold it minimum surface pressure equal to 50 percent of the casing internal )field pressure.] REQUIRED A%(7KING PRESSURE OF -1111. R0111' AS SI1I-.C11 II'.I) I\ 1111- Pl It\91'1' 10 DRILL UNDER _'0 AAC 25.034;4 E) (3) UR 20 :QAC 25.036(()(3).1 The casing pressure test must he held a minimum or30 minutes and not shot+ a decline ereater than 10 percent. 7'hc results of this tell and any subsequent tc�t< of the casing rnust be recopied as required by 20 AAC 25.070( 1 ). On a CHART 2. Drill out float equipment and at least 20' of new formation. Circulate hole clean. • Mud Program • Bit Program • Directional Program w/ BHA's • Coring Program • Evaluation Program 3. Perform FIT on a chart. Email results. Estimated Leak Off EMW is 14.2 ppg emw. If test ;Y is less, discuss with office. A minimuLn offs acceptable. IL• ta. 4. Condition existing mud to DESIRED properties prior to drilling ahead. NOTE: Drilling (� ECD's should be monitored at each change of any drilling parameter. Engineered hole cleaning sweeps may be circulated as deemed necessary. 5. Drill ahead per plan. Monitor hole conditions, torque and drag, etc. Trip in and out of hole at a consistent low rate to minimize surge and swab, sit down on slips slowly to minimize surges, turn pumps on/off very slowly to minimize hammer effect, etc. 6. Near x4300' TVD, make sure mud logs are correlated with Iwd data and OFFSET information to assist in picking the Nanushuk 3 Core Point anticipated at x4385' TVD. Goi,G . From offset information there are formation markers that will be drilled to assist. Drilling 5' �et / and circulating samples may be used to help pick the core point, but verify with ✓ superintendent. 7. POOH. Pick up conventional coring equipment (Coring BHA). TIH and perform coring runs as per the coring procedure and G&G. Handle cores carefully. 8. UPON COMPLETION OF CORING RUNS, OR, as necessary between one or more runs, TIH with core footage length area clean out assembly. (It is anticipated that the clean out assembly will be the same as the drilling assembly.) 9. Continue to drill to x8175'MD / x8042'TVD as per program, short tripping and pumping HIGH VIS sweeps as required. MINIMUM flow rate should be 500gpm. Higher if possible. 10. At hole section TD, pump a HIGH VIS sweep and circulate the hole clean. Make wiper trip. Again pump a sweep and circulate hole clean. Make sure pump is at MAX rate. Hole will require more than just circulating bottoms up. Repeat until hole is slick. Strap out of hole. 11. Evaluate hole as per program. NOTE. If the well is potentially productive it is planned to run and cement casing for a well test. If His determined to NOT test, then a SUNDRY permit (10-403) will be submitted for the abandonment. With centralizers placed as follows: g) 3 bow -spring TURBOLIZERS with stop collars in center of bottom 3 jts h) 3 TURBOLIZERS across the bottom 3 couplings i) 1 TURBOLIZER across the coupling of every third it for the next .*3200' casing (:tQ) but will be adjusted based on productive zones (+26) j) 1 TURBOLIZER across every coupling next.*500' (±12) k) 1 TURBOLIZERS across the coupling of every third it to surface (.*36) I) ESTIMATED TOTAL TURBOLIZER centralizers = +-80 w/ 3 stop collars 16. Run 7" casing. Perform a running tag. Reciprocate casing. Circulate and condition mud at a rate not to exceed the AV around the collars while drilling. Condition mud to have flat gels. 17. Cement 7" casing per cementing and stage tool procedures (cement design is to address low fluid loss, formation compatibility of filtrate, RIGHT HAND SET) while reciprocating casing. Land hanger. Cement volumes are presently designed for cement to sum with 40% excess. Adjust volumes as necessary to insure top of cement is at surface. 18. Back out landing joint. Install packoff and test to 5000 psi. • Mud Program • Cementing Program • DV (stage tool) Procedure 12. TIH. Condition hole as before making sure hole is slick. Condition mud to lower YP and gels (make sure gels are flat). Monitor pill lag and mud log lag times to aid in adjusting cement volumes for hole washout and compare to elog value. NOTE: A decision may be made to set casing short. If so, a Sundry permit application will be made to tl C: the AOGCC to abandon the open hole from total depth to approximately 5676'M D/5543'TVD. The nI D t7v preliminary plan is to set an open hole balanced plug will be set with the top at .." 'MD. U 13. TOOH. Pull wear bushing. 14. Change out pipe ram with 7" casing rams in upper ram. Run test joint and test casing ram 0� to 300 psi. Make sure the appropriate x -over with FOSV is on the rig floor for casing run. 15. Calculate space out and prep as per previous. Run casing as follows Baker -Locking the shoe track: a) Shoe b) 2 its casing c) Collar d) Casing 2 goo Ik- e) DV (stage) tool P -P f) Casing With centralizers placed as follows: g) 3 bow -spring TURBOLIZERS with stop collars in center of bottom 3 jts h) 3 TURBOLIZERS across the bottom 3 couplings i) 1 TURBOLIZER across the coupling of every third it for the next .*3200' casing (:tQ) but will be adjusted based on productive zones (+26) j) 1 TURBOLIZER across every coupling next.*500' (±12) k) 1 TURBOLIZERS across the coupling of every third it to surface (.*36) I) ESTIMATED TOTAL TURBOLIZER centralizers = +-80 w/ 3 stop collars 16. Run 7" casing. Perform a running tag. Reciprocate casing. Circulate and condition mud at a rate not to exceed the AV around the collars while drilling. Condition mud to have flat gels. 17. Cement 7" casing per cementing and stage tool procedures (cement design is to address low fluid loss, formation compatibility of filtrate, RIGHT HAND SET) while reciprocating casing. Land hanger. Cement volumes are presently designed for cement to sum with 40% excess. Adjust volumes as necessary to insure top of cement is at surface. 18. Back out landing joint. Install packoff and test to 5000 psi. Well Test/ Completion (For information ONLY): 1. TIH w/ mill and scrapers spaced out for casing lengths. Work same. 2. Test 7' casing to 3650 psi adjusting for mud weight. —" ' 5 3. Run CBL. z6e ?cti 1_J 4. Displace with completion fluid. 5. Completion Procedure will follow with a Sundry application. "o►� P=A N 6 `J A�- SURVEYORS CERTIFICATE 2 g III ean,rra a` tamma IFIEOI"ISLI STATE OFALPEI(A AND THgT THIB CERTIFIGTION IS LIMITED TO TtE WELL CONWCTOR LOCATION ONLY. qLL MLY.T LL GRAPHIC SCALE OTHER INFORMATION SHOWN W APPRO%IMATE. UN0 I ineU =100 fI. ' HORSSELOCATIE�SSHOE 1 LNFTAI1 1F.r - A Li NYSIp'E 1R u auzlae II � F b eei+FrtE u erreeE F _- _.. , O 612&i6 T._1 :m.wu: occas 00' CC KWA oluxn� b smrstE LL' b $+p1]E r O . W �. nowus+AsaTe�a\c FIGURE 1 OF 1 3 u avo•aeE n• u eoa ears tr O O L+a e�ravFW n• U, tImFSTV +r br NN91' W t01 \ \\\\\\Ittf U3 hlS v F �It, t lM NpilpOrN R TH Ltt i+tgn F. 01 Xr1iTM F % i`:FiUnCLn8:ls J Coil+� :4 xantax r sir".i, t3-10886 L NOTES: I. ELEVATIONS SHOWN ARE NAVD 88 PER GEOID 2012A DERIVED FROM GPS OBSERVATION. 2 -THE EDGE OF THE LAKE IS A POORLY DEFINED LAKE SHORELINE, VERY MARSHY WITH SCATTERED GRASS. THE DEPTH OF THE WATER AS FAR AS 20OUT FROM THE EDGE AS SHOWN IS GENERALLY LESS THAN ONE FOOT, 3.CONTOUR INTERVAL ONE FOOT. 4. RIG FOOTPRINT RE -DRAWN PER PDF RECEIVED FROM O CLIENT, TITLED " AAOA RIG I11 LAYOUT", SHEET 2 �., OF 3. DATED 9/22/14. RIM PROPOSED ICE PAD Lt6 � Lb � LN L1] CONDUCTOR AS -STAKED LOCATION N0083ASPZOW4 LAT=70.02'47.50" N LONG=151'07'10.30" W Y = 5,867,669 X = 1,500.353 NADVASPZONE4 LAT=70'02'48.72" N LONG= 151'07'03.27" W Y = 5,867,922 X = 360.315 NADVUTA20NE6MEITR6 LAT=70'02'48.72" N LONG=151`07'03.27" W Y = J 776,221 X - 343.277 PRIMARY LOCATION LOCATED 'A1T1IN PROTRACTED SEC 15, TEN, R4E. U.M. 1.438' F.W.L. 2.249' F.S.L. SURFACE ELEVATION TOP OF TUNDRA ELEVATION - 23.52 rr, p... v/ ✓v ..'.1 6 `J SURVEYORS CERTIFICATE 2 g III I HEREBYCERTIFYTDTIAMPROCE ANOLIOENSED IYl PRACi10E LANDSURV a` IFIEOI"ISLI STATE OFALPEI(A AND THgT THIB CERTIFIGTION IS LIMITED TO TtE WELL CONWCTOR LOCATION ONLY. qLL MLY.T LL OTHER INFORMATION SHOWN W APPRO%IMATE. i ' HORSSELOCATIE�SSHOE 1 �Aev&—�- ,..,,.., ,, A HIN II �u,�•.•. SECTION 15, TBN, R4E, UM I�o.+Te _- _.. Arms1ron Pne • LL S +>ti'1. 612&i6 T._1 :m.wu: occas 00' CC KWA oluxn� �. nowus+AsaTe�a\c FIGURE 1 OF 1 3 OBJECTIVE: Drill Surface Hole Section to TO North Slope RIG:TBD BOTTOM HOLE ASSEMBLY #1 12.26" Hole Based on WP Rev C-01 MIN EAKM lawme EPTH IN0' DEPTH OUT TOTAL 2,361' 2,361' ITEM NO. DESCRIPTION EQUIP. GAUGE BODY BODY PROVIDER OD OD I ID DOWN CONN 1 UP CONN UNIT LENGTH ACCUM. LENGTH ppf 1 12.25" Bit 12.25 6 5/8 Reg P 1.20 1.20 2 8" X-treme t.xx ako w/ 12 1/8" UBHS w/Float Installed BHI 12.125 8.00 6 518 Reg 8 6 518 Rea B 28.90 30.10 138.00 3 8" NM String Stab w/ 12 1/8" Straight Blades BHI 12.125 8.00 2.88 6 5/8 Reg P 6 518 Reg B 5.00 35.10 175.54 4 8"NMCSDP BHI 8.00 2.75 6 W Rea P 6 51&'RK 8 10.00 45.10 101.00 5 Stop Sub BHI 1 8.25 2.81 65/8 Reg P 81W T2 2.00 47.10 200.00 6 10ntmk Ganl/Res/Pres/VSS/Surve BHI 8.39 2.76 81/4"T2P 8IWT26 18.96 66.06 179.00 7 121/8" Modular Stabalizer BHI 12.125 8.27 3.03 e v r, T2 P 81/4" T2 B 5.74 71.80 163.00 8 BCPM Pulser BHI 8.40 2.76 8114"T2P 81/4"T28 11.75 83.55 186.46 9 Stop Sub BHI 8.25 2BI 81/4"T2P 6 518 RB 2.00 85.55 200.00 10 NM Downhole Filter Sub BHI 8.25 3.00 8 5/6 Reg P 6 51W Rea 8 5.45 91.00 157.66 11 2 Joints 8" NMCSDP BHI 8.00 2.75 6 518 Rea P 6 5/8 Reg B 62.00 153.00 101.00 12 XO RIG 8.00 1 2.75 6 5/8 Reg P NC50 B 3.00 156.00 65.00 13 12 Joints 5" HWDP 5W1 Adjusted weight) RIG 6.625 TJ 5.00 3.00 NOW P NC50 B 360.00 516.00 49.77 14 Drilling Jar WFD 6.25 33.00 549.00 15 6 Joints 5" HWDP 50#/11 Adjusted weight) RIG 6.625 TJ 5.00 3.00 NC50 P NC50 8 180.00 729.00 49.77 16 XO RIG 5.00 3.00 NG50 P XT -39 B 3.00 732.00 49.77 17 4" 5-135 Drill Pie 15.62#/11 Adjusted weight) RIG 4.00 3.34 XT -39 P XT -39 B 1629.00 2361.00 15.62 otes and Comments Max required Dogleg for INS section is 2 deg/100 Motor RPM 0.22 rev/ al/ Max notation with ix AKO is xxrpm /Theoirdcal Do le is abo"L de 1100f1 ec mca an ec amoal Spec ficstiars FLOW RATES: s" X4reme Motor 396.900 gP0*--8.26" BCPM Low Flow Pulser (4001476.670) Flow Contig needs to be finalized MUD TYPE Max DL Rot / Slide as 110's RPM: per AKO setting WOB: 45 Bibs NBI: ala Survey: ECD: 49.2' VSS: Gamma Ray: 48.4' Non Mag Below Sensor: Resistivity: 53.8' Non Mag above Sensor: Sensor 60.6 808' 30.5' 92.4' Distance Information North Slope Horseshoe#1 10119 1LAKM 1111111114IIIIIIIIIIIIE6 RIG:TBD BOTTOM HOLE ASSEMBLY #2 8.5" Hole Based on WP Rev CA DEPTH IN DEPTH OUT TOTAL OBJECTIVE: Drill 8 112" Hole Section to Core Point then to TO after Coring is Complete ITEM EQUIP. GAUGE BODY BODY[ DOWN UP UNIT ACCUM. ppf NO. DESCRIPTION PROVIDER OD DO ID CONN CONN LENGTH LENGTH .......... ........ ........ ........ .................. ........ 1 81/2" Bit ROD (HCC T605X) 8,500 0.90 0.90 2 6 314" AutoTrak SHI 7.74 1.54 -4MRegPin 412 Reg B 63/4"T28 7.12 8,02 125.70 3 6 3/4" ZoneTrak-G BHI 6.75 2.81 16 314" T2 P 6 314"T2 8 4,07 12.09 90.00 4 Modular Flex Stab BHI 8.375 615 2.81 16 3/4'T2 P 6 3/4" T2 8 8.20 20.29 130.23 6 Ontrak (Garn/Res1PresfVSS/Survey) BHI 6r75 2.81 6 3141L T2 P 631#1 T2 B 16.92 37.21 130.00 6 IMod.la, Stbalizer BHI 8.375 615 2.81 6 3/4" T2 P 6 3/4"T2 B 4,29 41.50 78.00 7 BCPM (Pulser) SHI 6.75 2.81 8 3/4"T2 P 6 314" T2 B 1057 52.07 98,00 8 Stop Sub BHI 015 2.81 6 3X'T2 P NC50 8 1.67 53.74 7800 9 NM Dmnhoie Filter Sub BHI_ 6.75 2.88 NC60 P NC50 S 5,27 59.01 70.00 10 NM Float Sub BHI 6,75 281 NC50 P NC50 B 3o0 62.01 65.00 11 2 Joints 6.314" NMCSDP SHI 6.75 2.81 NC50 P NC50 8 62.00 A:124.0 49.77 12 9 Joints 5" HWDP (60#/ft Adjusted weight) RIG 6.625 TJ 5ro 300 NC50 P NC50 B 270.00 394.01 50.00 13 Drilling Jar WFD 6,25 33.00 427.01 14 6 Joints S' HWDP (50WII Adjusted weight) RIG 6.625 TJ 5.00 3.00 180.00 607.01 50.00 15 X0 RIG 5" 300 3.00 610.01 15.62 16 4" S-135 Dril Pipe (I 5.62#/ft Adjusted weight) RIG 400 3.34 5365.95 5975.96 15.62 17 --wo-w , ""t, Max required Dogleg for this section is 2degt100 drop tover fical Technical and Mechanical Specifications FLOWRATES: BCPMN*r=IFlow Pul"ri38Q/45O.66O)FfowConfignmdstab fimlized MUD TYPE: MaxDLR.t/Slld. 6.5 /13 RPM: 400maxpublisheii;200max recommended WOO: 22.51,11s; Sensor Distance Information NSI: 4.0' survey: 31,3' ZoneTrak NB Gamma 98 SOD: 21.6' VSS(vIhratIorJSS): 31.3' Giimnut Ray: 22.5' Nonillair Below: 23.3' R..isti.ity-, 26,5' MmMcg Above: 30.T Arctic Fox Doyon Drilling, Inc. 3201 C Street, St. 700 Anchorage, Alaska � 2 ! (� o � . . ! - /§ / § n n |§ §\ § ( , / 7[(/ c \ k\\\ . [ '�2} §k2§` ° w■:,w 2 /Wwxo |/2.2 \ /!))f :=2;� ƒ [[:2& _ [` �®w* §§!) (fizz §!§! ®. / _ §§ zm wk 2] wom wo k§ & Zza ozz m \� 00 ` < _m: . � 2 ! (� o � . . ! 11' 5000 PSI SHAFFER ANNUI STUDDED TOP/FLANGED I1. 5000 PSI SNAFTER DOUBLE CATS PIPE 3 1/8' 5000 PSI 3 1/8' 5000 PSI GATE 11' 5000 PSI SH SINGLE GATE v.w m Ile moo rs, r� rima. mr/�Axlm sTmom Ta/Rurm eonw ACCUMULATOR: TRIPLEX PUMP: AIR PUMP: FLUID RESERVOIR: CONTROL TECHNOLOGY INC 6 STATION 1/208 VAC, 20 HP 2/40:1, 8GPM, 3,000 PSI 165 GALLON ACCUMULATOR MANIFOLD 10 BOTTLES, 11 GALLONS EACH NITROGEN BACKUP BOTTLES 4 BOTTIFS VALVE LEGEND 1 BYPASS 2 KILL 3 CHOKE 4 BOTTOM RAMS 5 BLIND RAMS 6 TOP PIPE RAMS 7 ANNULAR f:1. r _ •rr r a 1EPYR7 AKITA JV TG FPIF- PITS T,0 FAIRS LIST Item Description A I2MATERIAL 3-1116" 10M Remote Operated Hydraulic Choke 8 3.118" SM Adjustable Choke 1 2-1116" 5M Manual Gate Valve -14 3-118" SM Manual Gate Valve LEDGEND White Handle Valves Normally Open Red Handle Valves Normally Closed '1e) FROM gGF STACK A y _' 05GASSER Z � frSoFio_ F -a p on 25x` re �fo 7E 'o 0 N �.i Q O T �W/�// r) ~ z d z Z !L ~ m 0 z Co w;nZ It N H � Z CO) w >w F- w om az v� AMER1C P ® 1% 3 1/8" - 5000# Cameron variable choke manually Valve #5 y All blocks and DSA'sare API \,I certified with 3 1/8" - 5000# Valve #8 y Outlet to mudtank Valve?R \4 Valve #9 RIG 111 Choke Manifold Inlet - 3 1/8'- 5000# Valve #2 If 1 Valve #3 Valye 44 y �V 1 ., L Valve #6 L "- Valve #13 Gauge Port on top of 2 1/16" - 5000 # flanged gate valve Valve #11 y #12 P-, \i ti e . Valve #10 Outlet - Panic or Blooey Outlets - 3 1/8" - 5000# Outlet 3 1/8" - 5000# Swaco Super Choke Hydraulically Valve # 7 3 1/8"-5000# flanged gate valves quantity or Poorboy Degasser ALL AMERICAN OILFIELD, LLC. RIG 111 21-1/4" 2M DIVERTER 21-1/4" 2M AXON TYPE 55`CNNULAR 1/2" TALL 4" 2M DIVERTER SPOOL W/16" KNIFE GATE VALVE (18" Diverter Line) 48" TALL 21-1/4" 2M CONDUCTOR HEAD -100-1/2" TOTAL STACK HEIGHT STYLE BOP FLUID SPECS: - 31.10 gaii6n close chamber volume - 18.90 gallon open chamber olume KNIFE GATE VALVE FLUID SPECS: - —1.00 gallon close chamber volume - —1.00 gallon open chamber volume i ANNULAR 48" TALL 11" 5M HYDRIL GK DOUBLE GATE 33" 7 11" 5M SHAFFER L STD TOP / BTM DRLG SP 24" TALL 4-1/16" SM OTOS DSA 4" 5M X 2" 5M 2 EA. 2" 5M MGV SINGLE GATE 19.5 11" 5M SHAFFER L' STD TOP / BTM ALL AMERICAN OILFIELD, LLC. RIG 111 5M BOP I" ED W/PIPE RAMS 1 . 1 D W/BLIND RAMS 3 ; I / 1 EACH 3" 5M HCR; -------------- i ED W/PIPE RAMS y- 124.5^ i ED W/PIPE RAMS 1 . 1 D W/BLIND RAMS 3 ; I / 1 EACH 3" 5M HCR; -------------- i ED W/PIPE RAMS y- 124.5^ Armstrong Energy L.L.C. Horseshoe #1 Shallow Hazard Study August 2016 For any questions contact Kevin Dorrington Phone: (303) 623-1821 email: kevin(@armstrongoilandgas.com Executive Summary Armstrong Energy L.L.C. intends to drill the Horseshoe #1 well during the 2016-2017 winter season. Subsurface investigation of shallow hazard risks was completed using existing well control and amplitude analysis of the Horseshoe 3D seismic survey. This study indicates low risk of shallow drilling hazards (<2,000 ft SSTVD) at the Horseshoe #1 location. Horzeshce 3D 1 zowe NarsezFoe rv(W) Figure 1. Map showing Horseshoe #1 location, offset well control, and Horseshoe 2D and 3D seismic surveys. Existing Well Control Review of offset well control indicates no significant shallow hazards at the Horseshoe #1 location. The presence of gas hydrates within and in the transition zone below the base of permafrost is possible and should be planned for using standard drilling practices. The base of permafrost at Horseshoe #1 is prognosed to be approximately -730 ft SSTVD (Figure 2). —.I Horseshoe 30 e 0 92 00° \ o 315 XonesXoe p1 ISHII Xn�xxsipexe lervp j Ia Figure 2. Depth to base of permafrost from well control (SSTVD, contour interval = 2J5/ft) Gas bearing sands in the Tuluvak formation are a potential drilling risk below surface casing. The Tuluvak formation is prognosed to be approximately -2,500 ft SSTVD at the Horseshoe #1 location. Nearby well control and seismic data indicate the Tuluvak sands are not well developed at the Horseshoe #1 location (Figures 3 and 8). Standard drilling practices including setting surface casing above the Tuluvak should be used to mitigate potential drilling hazards associated with gas bearing sands in the Tuluvak. Albmura pl -' -- Figure 3. Well log cross-section of existing wells near the Horseshoe #1 location Horseshoe 3D Seismic Survey FE. ma(rost -I v The Horseshoe 3D seismic survey includes the Horseshoe #1 surface hole location (SHL) and multiple offset wells in the study area (Figure 1). A detailed study of shallow amplitudes was completed between near the base of permafrost (approximately -700 ft SSTVD) to below prognosed surface casing point (approximately -2,200 ft SSTVD). Lack of fold in the shallow section combined with the high density of rivers in lakes in the area creates several shallow seismic imaging problems including: numerous skips along the lakes and rivers, shallow amplitude anomalies present near the skips generally correlate with the edge of the lake or river that created the skip, and the base permafrost event is not seismically mappable. The seismic profiles in Figures 4 and 5 illustrate these imaging limitations clearly. Given these limitations, analysis of shallow seismic amplitude data should be integrated with offset well control in order to assess the presence of shallow drilling hazards. Rdtk Rrvar ry UnlNl qr!+nw . 4 1. i I Q! I Figure 3. Well log cross-section of existing wells near the Horseshoe #1 location Horseshoe 3D Seismic Survey FE. ma(rost -I v The Horseshoe 3D seismic survey includes the Horseshoe #1 surface hole location (SHL) and multiple offset wells in the study area (Figure 1). A detailed study of shallow amplitudes was completed between near the base of permafrost (approximately -700 ft SSTVD) to below prognosed surface casing point (approximately -2,200 ft SSTVD). Lack of fold in the shallow section combined with the high density of rivers in lakes in the area creates several shallow seismic imaging problems including: numerous skips along the lakes and rivers, shallow amplitude anomalies present near the skips generally correlate with the edge of the lake or river that created the skip, and the base permafrost event is not seismically mappable. The seismic profiles in Figures 4 and 5 illustrate these imaging limitations clearly. Given these limitations, analysis of shallow seismic amplitude data should be integrated with offset well control in order to assess the presence of shallow drilling hazards. Typical gas bearing sands in the shallow section will exhibit anomalously low acoustic impedance relative to background lithology. The expected seismic response in this case is a strong trough over peak seismic anomaly. In order to identify potential shallow gas bearing sands, the methodology used in this study consisted of extracting 100ms constant time RMS amplitude windows from near the base of permafrost (200ms) to below the top of the Tuluvak formation (700ms). Because the shallow horizons are dipping to the east, the constant time extractions cross -cut horizons and were used as a reconnaissance tool in order to identify potential shallow gas horizons for more detailed study. Based on these results, three horizons were identified for further study. The shallowest zone identified, termed Shallow Zone 1, correlates to the lower Schrader Bluff based on offset well control (Figures 4 and 5). A windowed 50ms RMS amplitude extraction centered on this horizon was extracted and examined for potential shallow gas signature. No amplitude anomaly was noted at the Horeshoe #1 location. However, approximately one mile west of the Horesehoe #1 location an area of discontinuous amplitude was noted as a potential gas bearing zone (Figure 6). K REDACTED M. Guhl 5/9/20109 Poneh. 01 Itkillik River Unit #1 B' REDACTED M. Guhl 5/9/20109 The second zone identified is termed Shallow Zone 2 (Figures 4 and 5). This zone is approximately 100ms below the Shallow Zone 1 horizon. A windowed 50ms RMS amplitude extraction centered on this horizon was extracted and examined for potential shallow gas signature (Figure 7). Several weak anomalies relative to the background amplitude trend were noted on this horizon. The Horseshoe #1 location is approximately 1,500ft north of the edge of the nearest potential anomaly. d Shallow Zone 2 correlates to a lower Schrader Bluff sand in Pioneer #1 at approximately 1,100 ft MD. No drilling complications were noted at Pioneer #1 in this sand. This zone was also encountered at the Itkillik River Unit #1 well at approximately 1,850ft MD. Logs were not run across this interval; however, the mudlog describes minor sand in the interval with slightly elevated total gas readings. Background gas was approximately 50 units above this zone with readings averaging 75-100 units in the upper 200ft of this zone. Mudlog gas peaked to 190 units at 2,150ft MD. No drilling complications were noted during the drilling of the zone. The third zone of interest is the Tuluvak formation. A windowed 100ms RMS amplitude extraction centered on the Top Tuluvak horizon shows that the Horseshoe #1 location is not located within an amplitude anomaly (Figure 8). A large continuous amplitude anomaly is present approximately eight miles west of the Horseshoe #1 location. This anomaly may indicate the presence of gas charged Tuluvak sand south of the Pioneer #1 well. In addition, evidence of localized channels are apparent near the Rendezvous #2 and Pioneer #1 wells (Figure 8). Amplitude mapping shows no evidence of potential channels at the Horseshoe #1 location./In addition, offset well control shows that the Tulvak sands are not well developed in the area. REDACTED M. Guhl 5/9/20109 Figure 6. -25 to +25ms RMS amplitude extraction on Shallow Zone 1 horizon Conclusions Analysis of shallow seismic amplitudes in the Horseshoe 3D show no significant shallow amplitude anomalies at the Horseshoe #1 location. The nearest shallow amplitude anomaly is approximately 1,500ft south of the Horseshoe #1 location. This anomaly appears to correlate with a lower Schrader Bluff sand�encountered in the Itkillik River Unit #1 that had slightly elvated mudlog gas readings. However, no drilling complications were noted in this zone. No shallow drilling issues were noted in the nearest offset well control to the Horseshoe #1 location. Based on offset well control, the Tuluvak sands are not well developed at the Horseshoe #1 location. In addition, no anomalous seismic amplitudes were noted at the Horseshoe #1 location within the Tuluvak formation. In conclusion, detailed review of offset well control and 31) seismic data indicate low risk of encountering shallow drilling hazards at the Horseshoe #1 location. REDACTED M. Guhl 5/9/20109 Figure 7. -25 to +25ms RMS amplitude extraction on Shallow Zone 2 horizon REDACTED M. Guhl 5/9/20109 Figure 8. -SO to +50ms RMS amplitude extraction on Top Tuluvok horizon Bettis, Patricia K (DOA) From: Sent: To: Subject: Attachments: 101 Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office Schwartz, Guy L (DOA) Monday, January 09, 2017 8:55 AM Bettis, Patricia K (DOA) FW: Revised Directional for PTD 216-133 Armstrong Energy Horshoe#1_Rev-F-0Small Plot.pdf,, Horshoe#1_Rev-F-0_Wellpath Geo Rpt..xlsx 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). If 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 Guy Schwartz at (907-793-1226) or (Guv schwartz@alaska aovl. From: Stephen Hennigan [mailto:shennigan@peiinc.com] Sent: Sunday, January 08, 2017 4:34 PM To: Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov> Cc: Pete Berga <pberga@allamericanoilfield.com> Subject: Revised Directional for PTD 216-133 Armstrong Energy Guy For your records attached is the info for the revised directional. (And please note that Horseshoe iS misspelled in the attachments' names) 73ave p,t ad ,para a Xlmad aat1 9.>t &4ff OTe&oV PW,/, MS Emgt A Project Manager/Engineer"":: "" 2: 337-984-2603 W: 337-849-5345 (mobile) .fto Petroleum .Berra SIERRA `_ X40, Engineers ';cam:: HAMILTON v� SmeWmmrCmlmuWrylbua.IMmkmarm innmery¢mrw4Emryb Mgnmlgwwniyw Mu'Aoe WaN IlmrymnuncmXMnW awpgxlep¢1,rlwmermvmaatl M,rem,reeanm¢sm.OuemrvxyrmmMrued w WirydaryaVwnm.alere,gn tlmmbmermgq.mnuanXta mn eenrM nve.^Mr¢genr ¢pNMN rlyaurxa«M Nenmw.,avemimuYaMrmg6Ye¢rMmereW Xwn erryarnryM Armstrong Energy,LLC BAKER Location: North Slope, Alaska Slot: Horseshoe #1 IIU"ES Field: Armstrong Energy, LLC North Slope Well: Horseshoe#1 Facildw Explotnition Wellbore Horsesh 1 PIM reference wellpath is Ho seshoW t_Rev_F-0 Grid System: NAD271 TO Alaska SP, Zone 4 (5W4), US feel This verlicel depths are referenced t0 Arclic Fox (RT) '= Wellpath was transfained from a ditmnl geodetic it Measured depths are referenced to Arctic Fox (RT) North Reference: Tme north Arctic Fox (RT) ro Mean Sea Level: 43 feet Scale: True di4snce Mean Sea Level to Ground level(At Slot: Horseshoe #1:0 fest Depths are in feet Coordinates are In feel sferenoed to SIM Created by: ulricard on 2017-01-02 Database: WA ANC Def i Well Profile Data Design Comment MD ft Inc (°) Az (°) TVD ft Local N (ft) Local E (ft) DLS °/100ft VS (ft) Tie On 17.50 0.000 0.000 17.50 0.00 0.00 0.00 0.00 End of Tangent 400.00 0.000 0.000 400.00 0.00 0.00 0.00 0.00 End of Build 2000.00 16.000 0.000 1979.29 221.95 0.00 1.00 159.49 Tangent (planned csg point) 2273.30 16.000 0.000 2242.00 297.29 0.00 0.00 213.63 End of Tangent 2323.30 16.000 0.000 2290.06 311.07 0.00 0.00 223.53 End of 3D Are XS 3234.47 28.133 71.776 3146.05 507.56 208.00 3.00 509.38 End of Tangent (XS) 3683.98 28.133 71.776 3542.46 573.85 409.33 0.00 697.02 Drop XS 4621.75 0.000 71.776 4443.00 644.41 623.65 3.00 896.78 End of Tangent XS 8221.75 0.000 71.776 8043.00 644.41 623.65 0.00 896.78 -760 o T on End of Tangent 750 1.00°1100# 1500 °�, zoo Easling (ft) DD 0 10D 2D0 a50 450 S50 600 700 End MBOd p anuahuk3 1 9625in Casing t Tangent call point) 2250 Coe Pofnf 700 /Reny/ 3.00'/1008 Norsaaho°#1 3000 boo r End of 3D Am (XS) n O Entl of Tangent (XS) 3750 S00 ry 3.00°/1006 N 2 4500 Nanushuk 3 Core Point (Rev- Cop (XS) #OD Z 6250 5 re.625in Casing soo S 6000 200 6750 100 7500 i �0 Horseshoe #1 End of Tangent (XS) 8?50 -750 0 750 1500 - 1110 Vertical Section (ft)a=.•,.E°-,aa Azimuth 44.06° with reverence OAO N, O. E 000 000 17 50 __ -255-._ 0 _ 000 - 000- 36029031 5867959 10 586]909.10 20°02'48.596"N-151' 100 50 000 0.00 1150 7450 0.00 000 360290.31 586]909.10 70°02'48.596"N 151' _ 50 0.00 0.00 21].50 174.50 0.00 0.00 360290.31 5867909 10 70°02'40.596"N 151' 50 - 0.00 000 31750 274 50 - OVU 000 - 36029031 5867909 10 ]0"02'48.596"N .551 100 _ DO 000 100 40000 35]00 000 000 36029031 586]909.10 ]#826'N 158 50 0.18 _0.00 000 41750 3]450 003 000 36029031 586]90913 7 151' 50 1.18 000 51]49 _ 474 49 120 GOO 36029033 586]91030 7N 151' 50 2._18 000 61]45 57445 413 - 000 36029039 506]91323 ]N 151' 50 318 000 71.34 6]4-34 -• P]9 0.00 36029047 586]38 B9 ]N 151' 50 4.18 000 PP 13 ]]613 1520 0.00 36029059 586]92430 ]N 151' _ 50 5.18 000 91680 8_380 23395 0.00 36029074 586/932 a5 7N 151' 50- 618 000 1016.31 97331 3324 0.00 36029092 5867042 33 70024892TN 151' 50 7.18 000 1115.63 1072.63 44 87 _ 000 96029113 586795396 000 151 50 8.18 000 1214]3 11]1]3 5822 0.00 340291.30 5867967.31 _70'024903]"N 70 02 49 149"N 151 50 918 000 1313.58 1270.58 7330 _ 0.00 360291.65 5867982 39 70"'0249.31]"N 151' 50 1018 000 141246 _ 1369 16 9011 - 0.00 36029190 5067999 19 X70'0249482"N 151 50 11.18 _ 0.00 151043 146743 108.63 0.00 36029230 86801].]1 70'0249665"N 151 50 18 13 - 0.00 1608.36 1565.36 128 87 - D .00 36 0292 6] - 506803794 5 ]0'0249064"N 151" 50 13.16 V0592�_166292 15081 000 36029308 586805987 ]0'02 60.0]9"N 151 50 14.18 GGoooa 000 180308 1760.08 174 45 000 36029351 586808351 ]0`02'50312"N 151' _50 1518 000 1899.82 105682 19979 000 36029397 586810884 700250561"N 151 00 1600 0.00 1934.29 221.95 0.00 36029438 5868131.00 70°0250779"N 151 50 16.00 000 _1979.29 1996.11 195311 22678 600 - 360294 397 5868135.82 ]p°02'50.82]"N 151' 50 46.06 - 000 209223 204923 254.3a 000 36029497 586816338 70°OT51.MEN 151' 50 1600 000 218836 214536 281.91 0.00 36029548 586819094 70°0251369'N 151' 30 16.00 0.00 224200 2199.00 29729 0.00 360295.]6 5868206.31 70°02'51520-N 151' 50 16.00 000 228449 - 224149 - 30947 0.00 360295.98 586821849 70W51 W14 151' 30 1600 000 2290.06 2247.06 311 07 000 36029601 5868220.09 70W51 656N 151' 50 15.62 1029 - 2380.]2 - 233772 33653 2.27 36029875 5868245.50 70°02'51.906N 151' 50 15.75 2140 2477.02 2434.02 36241 9.62 36030657 5 2712 70VZ52.161N 151' .50 1642 31.96 25]3.12 2530.42 38]04 2206 360319.46 5868295.64 70'W52403N 151' .50 1 17.58 4145 - 2668]] 262577 41036 3954 36033]36 586831863 ID°02'52.632N 151' 50 1912 2]63.]0 3020 ]0 43229 6202 36036024 586834014 700252848"N 151 .50 20.90 _4963 5652 2857.65 2814.65 452 77 8843 360388.03 586836012 700253.NTN 151' 90 2306 6228 2950.36 290]36 mt 76 12111 J 36042064 586837851 700253236N 151 50 2532_ 671G 3041.58 2998.50 48920 15875 36045].99 586839527 700253408"N' 151 .50 2772 7115 313106 301806 200.47 360499.99 586841034 700253.OWN 151 47 1 2813 7178 --50504 314605 310305 50756 208.00 36050].5] 586841272 7p0253588 -N 151 50 28.13 71.78 3219.28 317628 51984 245.19 360544.97 586842428 MOD 53709-N 151 50 28.13 7178 _ 330746 3264.46 53455 289.96 36059002 5868438.21 7W02'53.854"N .151 Norsesnos6l rtorsatlnoeal 0.00 0.00 1 0.00 goo 0.00 0.00 000 0.00 _ 0.00 100 000 - 1 D 100 000 1 00 1.00 000 1 00 100 000 -- 100 1.00 000 - 100 1 00 000 1 00 100 0.00 -1 Go 1.00 0.00 100 1.0o 000 - 190 1.00 Gua 1.00 100 _ 000 100 -0.00 000- 0.00 0.00 000 000 000 000 000 000 0.00 102.75 3.00 9284 300 82]5 300 71 99 300 _ 62.92 300 5515 300 000 000 000 0.00 0.00 P 9e1 oft 000 0.00 4020 673 4020 673 4021 624 4022 6 7 -- 4022 624 40.22 6 ]5 4025 676 40.30 6 ]8 2030 679 40.32 681 40.36 682 4039 68d 4044 687 re Oo EM of TeMlent _ J 0 000 - 16296 4115 1 4087 1 7.14 1 358.61 1.00 0.00 1827] 41.30 40.83 720 35817 IN 0.00 Goold 414] 41.00 7.25 35888' -._ 100 0.00 213.63 41.54 41.02 726 356.94 Ta, 300 000 22238 41.58 41.02 728 35902 3.00 0.00 223.53 4159 4102 728 35903 Eo8 041 - 10.92 24340 41 70 4103 733 35971 ].13 - 11.11 267 12 4104 - 4104 738 - 155 - 167 10.57 29346 4210 41.0 743 383 115 949 322.3] 4216 _ 4107 749 640 1 55 8.18 35376 42 34 4109 754 921 1 85 6.89 38755 42 53 41.11 7 61 1223 209 5]6 42364 42]4 41.14 768 1548 _ 226 482 46194 4297 41.17 776 1894 - 2 39 4 062 33 _ - 43.23 4122 7 85 - 2264 _ 246 366 1 09.38 4327 - 4123 ]86 2328 Eno 000 0.00 544.04 4349 1 41.28 ]93 2644 361750 2813 7170 3483.83 3440.83 56405 379.55 360680.11 586846605 ]0'02'54.144"N 151.06'553.049-W 0.00 0.00 000 0.00 66927 4450 4147 0.22 `36.42 3683.58 28.13 7178 354246 3499.46 93.85 409.33 36071006 586847580 ]0'02'54280"N 151°06'52191"W 000 18000 0 0.00 69].02 44.77 _ 41.52 829 38.29 End Of Targent(%5) 3]1].50 2].13 ]t]8 35]215 3529.15 5]8]1 424.09 36076622 58684]9.89 ]0°0254288"N 151°0651]66W 300 -180.00 -3 -3.00 0.00 ]10]6 4431 4154 833 39.16 3817.50 24.13 7178 366231 3619.31 502.24 465 17 360]06.22 586850266 70°0254422"N 151°0650531 W 3.00 18000 -3.00 0.00 ]490] I 4533 4162 846 41.35 301].50 21.13 ]t]8 3]5460 371160 60427 501 36083290 5868504.02 70°0254539"N 151.0648612W 300 18000 -3.00 0.00 78313 45 73 4170 8.61 4295 4017.50 18.13 7178 304878 3005.]8 61472 53361 36086240 5868513.93 70"02'54.682"N 151`0648622"W 300 18000 -3.00 000 81286 46.09 4179 875 45.19 411750 1513 7178 3941.58 390150 63108 56079 36086240 5868522.38 ]0"0254730"N 151°0647.829"W 300 100.00 -3.00 _00.0 838.19 4642 41.08 8.89 45.12 421750 7178 404176 399703 63608 583.17 36088490 5868529.34 ]0°02'54.803"N 151°06'47.185"W 300 180.00 3.00 0.00 859.05 4671 41 97 901 4580 431.50 913 9.13 7178 4140.03 409]03 63685 60368 36090252 586853478 70°02'54860"N 151"06'46.317-W 300 180.00 -3.00 OW 8]53] 46.94 42.06 9.13 4627 4417.50 6.13 7178 423918 419614 641.00 61329 36091520 5868530.70 70°02'54.925-N 151.06'46.31YW 3.00 180.00 3.00 000 88]12 47.13 42.15 925 46.58 4617.50 3.13 7178 4338.80 429580 64353 62065 360922.91 586854108 ]0.02'54.925'N 151.06'46.096'W 3.00 -180.00 -300 000 09426 4]2] 42.25 9.36 4664 462].50 013 71.78 443875 439575 64441 623.65 360925.62 586854192 70.0254.934-N 151.0646.019'W 3.00 180.00 300 0.00 89678 4].35 42.34 946 46.58 _ 4621 76 0.00 7178 4543.00 4400.00 64441 62365 360925.62 5868541.92 ]0°02'54.934'N 151.06'46019'W 3.00 0.00 -1000 896]8 47.35 4234 9.1 46.58 Drop (XS) 4]17.50 0.00 7178 4538.75 459575 64441 623.65 360925.62 586854192 70"02'549-0"N 151'0846019"W 0.00 0.00 000 000 0.00 89678 4741 4241 9.56 46.59 481.50 000 7178 463875 459575 64442 623.65 360925.62 506054192 70°0254934"N 151°0846.019"W 0.00 000 000 0.00 89678 47A7 4258 9.67 46.61 501.50 0.00 178 4]30.75 469575 64441 62365 36092562 5868541.92 70°0254.934"N 15106'46019"W 000 0.00 0.00 0.00 89678 4]53 4255 978 4662 5017.50 000 7178 7 4838.75 47955 64441 62365 36092562 5868541.92 70°02'54.938"N 151"-0646019'W 0.00 0.00 0.00 0.00 89678 47.59 42.62 9.89 46.63 521750 0.00 ]178 4930.]5 4895775 64441 623.65 360925.62 5868541.92 70-02'54.934"N 151°0646.019"W 0.00 000 000 0.00 896.78 47.66 42.70 10.01 46.64 _ 521].50 0.00 7178 503875 509575 64441 623.65 36092562 5868541.92 ]0°02'54.934"N 151°0646 -151`06'46019"W 919"W 000 000 000 0 .00 896]8 ] 473 4]8 2 10.13 4666 $31]50 0.00 71 78 523875 509575 64441 62365 360925.62 5868541.92 70°0254.934"N 0.00 000 000 0.00 89678 4].80 4287 1025 46.67 5517.50 000 71 78 5238.75 5195.]5 64441 62365 3609252 5868541.92 ]0"02'54.934"N 151"066 4019"W 0.00 0.00 0.00 000 89678 47 .87 2 495 1038 . 46.68 551].50 000 7178 533875 529575 644.41 623 65 360925.62 6 586854192 70°02'54.934"N 151°06'46.019"W 0.00 000 000 000 89678 4805 4308 1051 46.69 5617.50 0.00 7178 543875 539575 644.41 360925.62 5868541.92 70.02'54.934-N 151°06'46.019"W 0.00 000 0.00 0.00 896.78 48.03 43.13 1065 4671 5717.50 0.00 7178 553875 559575 64441 62365 62365 360925.62 5868541.92 70.02'54934-N 151"06'46.019"W 0.00 0.00 0.00 000 896.78 48.11 43.23 1078 46.72 5817.50 000 71.78 563875 559575 644.41 623.65 360925.62 5868541.92 7W02'54.934'N 151'06'46.019-W 0.00 _ 0.00 0.00 000 89678 48.19 43.33 10.92 46]3 501750 0.00 7178 573875 569575 64441 623.65 586854192 70°0254.934'N 151"06'46.019-W 0.00 000 0.00 0.00 896.78 4828 4343 11.06 4674 601750 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653875 5 975 64441 62365 360925.62 5868541.92 700254 .934'N 151`06'4019"W 6 000 000 000 000 89678 4906 4483 12.33 46.85 681].50 0 .00 7178 663875 659535 65 64441 62365 360925.62 586854192 70".02'.54.934"N 251°06'46.019"W 0.00 0.00 0.00 000 89678 49.1 4445 1251 4686 601850 0.00 7178 6]38]5 6695.75 64441 62365 36092562 5868541.92 70°0254.934"N 151°06'46.019"W 000 0.00 0.00 0.00 89678 49.28 44.58 1268 46.87 701850 0.00 7178 683875 679575 64441 623.65 360925.62 5868541.92 70°02'54.934'N 15106'46.019'11 000 0.00 0.00 000 89678 49.39 4470 12.87 46.98 7217.50 0.00 7178 693875 6895]5 64441 62365 360925.62 5868541.92 ]002'54934'N 151. W O6'46.019' 0.00 0.00 0.00 0.00 89670 4961 45.84 13.05 46.90 ]21].50 000 7178 703875 699575 64441 623.65 360925.62 586854192 0.0254934"N 15106'46.019W 0.00 0.00 0.00 000 09670 49.63 45.11 13.24 46.91 731750 0.00 7178 723875 70955 4441 623.65 360925.62 58685419 2 7 54N 70°-02 934" 151".0846019"-W 000 000 0.00 0.00 89678 49]5 45.11 1343 46.92 751]50 000 7178 723875 729577 5 64441 6 623.65 36092562 586854192 70°0254935"N 151°0846019"W 000 0.00 0.00 0.00 0967 4907 4525 13.63 4694 751750 0.00 7170 7338.75 729575 64441 623.65 360925.62 5868541.92 70"0254931"N 151 " 0646019"W 0.00 000 000 - 0.00 896785 5999 45.39 13.83 46.95 761750 0.00 7178 7538.]5 739575 64441 623.65 36092562 5868541.92 70-02'54,93,1-N 151°0646019"W 000 000 000 0.00 89678 5022 4553 14.03 4696 771750 0.00 7178 753875 7495.75 64441 62365 36092562 5868541.92 70°02'54.934"N 1510646019"W 000 000 000 000 89678 5025 4560 1425 46.98 ]81].50 000 7178 ]638.75 - ]595]5 64441 623.65 36092562 5868541.92 70°0254.934"N 151-06 -151°06'46.019"W 46'019"W 0.00 0.00 0.00 000 896.78 50.38 45.03 1445 46.99 791750 0.00 7178 ]]3875 7695.75 64441 623.65 36092562 5868541.92 70°0254.934'N 000 000 000 0.00 89678 - 50.52 45.98 1466 47.00 8017.50 000 7178 ]838]5 779575 644.41 62365 360925.62 586854192 7002'54.934'N 151°06'46.019"W 0.00 0.00 0.00 000 89678 50.65 46.13 15.88 4701 811.50 0.00 7170 79385 789575 64441 62365 360925.62 5868541.92 ]0.02'54.934'N 151°06'46019'W 0.00 0.00 0.00 Q00 89678 5079 4628 1510 4703 8227.50 000 71 78 803875 7995 75 64441 623.65 360925.62 586854192 ]0".0254934-N 151°0646.019W 0.00 0.00 0.00 000 896.78 50.93 4644 15.32 4700 -822175 0.00 71 78 0043.00 8000.00 65441 623.65 360925.62 586854192 70°0254.934'N 151°0646.019'-11 0.00 0.00 0.00 0.00 89678 50.94 4645 15.33 5704 End of Tangent XS Page 2 of 2 Schwartz, Guy L (DOA) From: Stephen Hennigan <shennigan@peiinc.com> %x# Sent: Monday, December 12, 2016 3:55 PM E n9 Engineers To: Schwartz, Guy L (DOA); Regg, James B (DOA) o Cc: Subject: Pete Berga; Ed Teng Horseshoe #1 PTD (PTD 216-133) Update Smsa9inMnCmMniWYrp'Yx IMmbmTm nmmmw¢mrohl w/Mvu {crvryelanrMlomnYru¢ey¢ret ¢pMMaf yaurmrMersnmw,gwemrmrMSmb Wae'e&IMmaWNM1em aMm^Md nmrymnnnrmlhmyaWw P��k4mlrvmmmwmeraY AM^"�. r¢wmnmm. ti¢enmrmboNr wM cr Mvg Marr, ylmn Mavpn Xo brmmumry,aaa¢a me�aµnem.pealep]raµni Follow Up Flag: Follow up Flag Status: Flagged Guy Armstrong Energy has opted (for this project) to have an option for sidetracking the above well. Although continuing with the Rig 111 certifications for other potential, AE is negotiating with Doyon for the possibility of using the Artic Fox tQdrill the Horseshoe #1.. With that rig's capability and history, should a sidetrack be desired by AE management, operations would have the equipment to do it. With the change in the rig we are also opting to go with 53.5 mod BTC 9 5/8" casing in the surface hole and changing the connection on the 7" to DWC (BTC). Specs on both are equal to or greater than permitted. What data would you like AE to provide for this change in the drilling permit 77 oe,o a a d Gam a Mmsd dryr/ C54404P./r 0' .L,e2tf.¢7, MS Emgt A Project Manager/Engineer""" "' 9: 337-984-2603 S: 337-849-5345 (mobile) Petroleum %x# SIERRA , ' '%% E n9 Engineers ��: � HAMILTON o :. Smsa9inMnCmMniWYrp'Yx IMmbmTm nmmmw¢mrohl w/Mvu {crvryelanrMlomnYru¢ey¢ret ¢pMMaf yaurmrMersnmw,gwemrmrMSmb Wae'e&IMmaWNM1em aMm^Md nmrymnnnrmlhmyaWw P��k4mlrvmmmwmeraY AM^"�. r¢wmnmm. ti¢enmrmboNr wM cr Mvg Marr, ylmn Mavpn Xo brmmumry,aaa¢a me�aµnem.pealep]raµni Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Monday, December 05, 2016 10:54 AM To: Stephen Hennigan Cc: Bettis, Patricia K (DOA); 'Pete Berga' Subject: RE: Horseshoe #1 (PTD 216-133) Questions LOT/FIT Stephen, FIT/Lot of 13.8 ppg minimum would be fine. I can change the procedure step to reflect that. Not a bad idea to have a brain dump on kick Tolerance either.... As far as the cementing corrections just update the individual sheets and email them to me. I can replace the old ones. Same with the WBS.. just email the new one. No issues with the conductor hole size... just update the conductor cementing sheet and send to me. I can update the 10-407 also by hand. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NO110E: 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 Guy Schwartz at (907-793-1226) or (Guv.schwartz@alaska.g.Q). From: Stephen Hennigan [mailto:shennigan@peiinc.com] Sent: Sunday, December 04, 2016 11:25 AM To: Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov> Cc: Bettis, Patricia K (DOA)<patricia.bettis@alaska.gov>;'Pete Berga'<pberga@allamericanoilfield.com> Subject: RE: Horseshoe #1 (PTD 216-133) Questions LOT/FIT We have no problem changing the FIT to a higher number for a minimum. How about 13.8ppg? Will explain later. And that would be the minimum in the Opns summary. Related to this why don't we (NEXT YEAR) coordinate a little forum so each company can present their ideas on kick tolerance so the AOGCC can have a number of ideas to look at. We (Sierra Hamilton and/or Armstrong) will pick up the sandwich lunch tab and we can probably get the cont room at JL Towers. In the meantime, I will contact my friends at BE, Wild Well, Boots & Coots, etc for their ideas and forward onto you. With regard to comments 4,5, 1 understand your question. My mistake. I do have Halliburton double-checking my calcs for #5. How do you want us to state that we are planning for up to 500% excess but we are going to stop when cement gets to surface? I have redone the WBS (comment 6) i One last thing — the conductor setting company chosen want to drill a 24" hole in>,ead of 22" so I am going to have Halliburton recalculate that too. What do you want us to redo and submit or are you going to write notes? We are in town and can meet with you anytime Monday afternoon or Tuesday if you would like. %ia 1pa exd Aw a XAe^d dap1 r�.tl�"Zff c7.�.ZOVE97.29, MS Emgt A Project Manager/Engineer' " 2: 337-984-2603 W: 337-849-5345 (mobile) �: .�'-N• Petroleum .xrS� SIERRA Engineers `fi:. HAMILTON L^✓'M" .naxsH��[mvfalvn NnmMileabm»f nmry mnN�rnFInW M'bpm&pf nMnmwivimYW FMrerw,iWarsmsm, samwlwggM.c¢N,v Wupdmy mnmi0vaxipm Xn mbmaenry,avmvnA4aMAw VamMyrapanl avm[� �w xivw i..�[.w�_wr..�.s...i aaxx4 mam rymwAx From: Schwartz, Guy L (DOA)[mailto:guv.schwartz(obalaska.gov] Sent: Friday, December 02, 2016 1:24 PM To: Stephen Hennigan Cc: Bettis, Patricia K (DOA); Pete Berga Subject: RE: Horseshoe #1 (PTD 216-133) Questions LOT/FIT Steve, As far as the Kick Tolerance methods ...I use a spreadsheet that calculates the volume of gas influx ( in downhole bbls) that can be tolerated assuming a .5 ppg kick intensity without breaking down the casing shoe as the gas passes by on way uphole. I used to use a simpler "Kick Factor".. (LOT - MW) X (TVD difference). This is simple to use but not totally accurate and I generally use this for development drilling ( KF of .75 is marginal) . In your case Kick Factor = (12.5 —10.4) x (2240/8040)=.58 If I run my spreadsheet I only get 2 bbls of kick Tolerance.... Assuming you are drilling with 10.4 ppg mud, a 12.5 ppg LOT and take a .5 ppg kick. (A LOT of 14.2 ppg gets me closer to 12 bbls influx allowed). Not sure where you were getting 38 bbls but there are many spreadsheets and formulas out there and as far as I know none are API standard. 1 think you will be able to get to the proposed LOT of 13.9 or so... I just wanted to make sure you were aware that 12.5 ppg LOT would not be acceptable without consulting the AOGCC first to drill ahead. After issues with some recent wells the AOGCC is really looking at Kick Tolerance closely and we required all exploration wells to provide us the LOT/FIT data as soon as acquired. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 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 if, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-12261 or (Guv.schwartz@alaska.aov). From: Stephen Hennigan [mailto:shennilgan@peiinc.com] Sent: Friday, December 02, 2016 4:47 AM To: Schwartz, Guy L (DOA) <guy.schwartz@alaska.eov> Cc: Bettis, Patricia K (DOA) <patricia.bettis@alaska.eov>; Pete Berga <pberea@allamericanoilfield.com> Subject: RE: Horseshoe #1 (PTD 216-133) Questions Guy Responded to your concerns in blue below. I will look at the cementing issue shortly. Let me know on the kick tolerance please. T61 pa axd ,Fane a Adnd dad 1 Sod& t7. OTeW4,97a.R, MS Emgt A Project Manager/Engineer""""" W: 337-984-2603 S: 337-849-5345 (mobile) From: Schwartz, Guy L (DOA)[mailto:quy.schwartz(&alaska.gov] Sent: Thursday, December 01, 2016 2:09 PM To: Stephen Hennigan Cc: Bettis, Patricia K (DOA) Subject: Horseshoe #1 (PTD 216-133) Questions Steve, I have gone through the permit and have a couple of preliminary questions and comments: 1) Where are the cuttings and drilling mud going to be disposed? Not stated in permit ..They are going to 1 or more of the G&I facilities ie Hilcorp, BP, and another is still being worked. 2) Initial BOPE test will be full working pressure (5000 psi) thereafter 4000 psi. Nota problem 3) Suggest ending MW for surface hole section go to 10 ppg (vs 9.8 ppg ) That is ok as a lot of the offsets used 10.0 ppg BUT for no apparent pressure reasons in the drilling reports. 4) The cementing data summary on page 24 doesn't jive with the cementing sheets provided later in the application. The 9 5/8" surface casing volumes do not agree (one has 900% vs 500% excess) and the 7" casing volumes do not make sense either (ie proposed TOC for 1" stage cement volume is not enough?) .... Suggest deleting page 24 and just go with the one cementing sheet per casing string. Will do 5) Also re -check displacement volumes for both 7" and 9 5/8" casing on the cement sheets. Will do Petroleum Aly SIERRA - 'v. Engineers Iii.'r";* HAMILTON 9 „w�.��,�,�..�>,.�.,�,Po.�.�,�.,�,�� .��,m�..�o1 .,de-I,.e..—a1. ,M.,, From: Schwartz, Guy L (DOA)[mailto:quy.schwartz(&alaska.gov] Sent: Thursday, December 01, 2016 2:09 PM To: Stephen Hennigan Cc: Bettis, Patricia K (DOA) Subject: Horseshoe #1 (PTD 216-133) Questions Steve, I have gone through the permit and have a couple of preliminary questions and comments: 1) Where are the cuttings and drilling mud going to be disposed? Not stated in permit ..They are going to 1 or more of the G&I facilities ie Hilcorp, BP, and another is still being worked. 2) Initial BOPE test will be full working pressure (5000 psi) thereafter 4000 psi. Nota problem 3) Suggest ending MW for surface hole section go to 10 ppg (vs 9.8 ppg ) That is ok as a lot of the offsets used 10.0 ppg BUT for no apparent pressure reasons in the drilling reports. 4) The cementing data summary on page 24 doesn't jive with the cementing sheets provided later in the application. The 9 5/8" surface casing volumes do not agree (one has 900% vs 500% excess) and the 7" casing volumes do not make sense either (ie proposed TOC for 1" stage cement volume is not enough?) .... Suggest deleting page 24 and just go with the one cementing sheet per casing string. Will do 5) Also re -check displacement volumes for both 7" and 9 5/8" casing on the cement sheets. Will do 6) The well schematic should reiiect a ES cementer and cement to surface. , will do that but the WBS states "0' TOC" 7) CBL is not required on the surface casing by regulation unless requested by AOGCC for specific reason. You may run one but may be hard to interpret due to Arctic set cement. We are aware of the difficulties in "interpreting" the CBL because of the Artic set cement but Armstrong wants its "own baseline" and my plans are to have some "expert" friends review and evaluate. 8) Please provide calculations to back up your minimum FIT value of 12.5 ppg EMW. My independent calculations show this is too low. (this is stated in the detail procedure step 3 in the Intermediate /Prod: area. During drilling you will be required to forward the FIT/LOT data to AOGCC for review before drilling ahead. Is this lost statement a new rule? Glad you are doing that as Repsol and a few others have drilled ahead with dubious tests (according to the drilling reports) some of which are in the table here. ANYWAY 1. ECD's in the offset wells in an 8'/:" hole were generally 10.7 ppge or less. Occasionally in smaller hole at p- rates approaching 100' per hour, ECD's approached 11.77ppge. Historically. loss of fluid with a MOBM, DOBM, etc, losses near the shoe because of the oil hydraulic effects occur when mud weight or ECD is within +-.7 ppg of the "Leak off". So we should be very safe on that. NOTICE that the shoe test minimum for that "problem" has absolutely nothing to do with a "kick tolerance" where the shoe would break down. For kick tolerance, we can take an influx of approximately 38 bbls which will give an influx height (assuming gauge hole) of approximately 738'. Note the QS above had a 12.2 going to 7100" TVD. We are targeting 13.8 - 14.2ppge FIT as indicated in the drilling prog. The 12.5 was MINIMUM. What kick tolerance calculations or guides do you use? Will redo the other things indicated above by "will do" Regards, Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 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 Well Name Qugruk 301 Tofkat Oberon 1 Qugruk 8 Qugruk 7 Qugruk 5 Qugruk 3,3A Surface depth 2107' 2938' 1895' 2102' 1950' 2345' 2120' Rptd shoe test ??? 15.3ppge 13.7ppge 14.2ppge 14.1ppge 12.2ppge 13.9ppge Intm depth 4186' 6127' Rptd shoe Ti2 test Oppge 13.5ppge ANYWAY 1. ECD's in the offset wells in an 8'/:" hole were generally 10.7 ppge or less. Occasionally in smaller hole at p- rates approaching 100' per hour, ECD's approached 11.77ppge. Historically. loss of fluid with a MOBM, DOBM, etc, losses near the shoe because of the oil hydraulic effects occur when mud weight or ECD is within +-.7 ppg of the "Leak off". So we should be very safe on that. NOTICE that the shoe test minimum for that "problem" has absolutely nothing to do with a "kick tolerance" where the shoe would break down. For kick tolerance, we can take an influx of approximately 38 bbls which will give an influx height (assuming gauge hole) of approximately 738'. Note the QS above had a 12.2 going to 7100" TVD. We are targeting 13.8 - 14.2ppge FIT as indicated in the drilling prog. The 12.5 was MINIMUM. What kick tolerance calculations or guides do you use? Will redo the other things indicated above by "will do" Regards, Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 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 Bettis, Patricia K (DOA) From: Bettis, Patricia K (DOA) Sent: Wednesday, October 26, 2016 10:16 AM To: 'Steve@pelinc.com' Subject: Horseshoe -1: Permit to Drill Application Good morning Steve: On the proposed wellbore schematic, anticipated target (formation depth list), proposed wellbore survey, and anticipated wellbore plats, Armstrong shows the Alpine Formation overlying the HRZ shale. If Armstrong is not anticipating a reverse thrust in the area, please correct this error as the Alpine Formation was not deposited after the HRZ shale. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 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 Patricia Bettis at (907) 793-1238 or patricia.bettis@alaska.eov. na, ARMSTRONG Energn•, LLC October 21, 2016 State of Alaska Oil & Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 Attn: Patricia Bettis RE: North Slope Project DVD, Armstrong Energy, LLC Dear Ms. Bettis, 2-l(0-133 Zia 3G RECEIVED OCT 24 2016 AQCCC Please find enclosed the above referenced DVD containing North Slope Project Materials. Please note that this DVD is to be held confidential. &L° (4ov-110u c _ #6aQ 511,ohq Should you have any questions please don't hesitate to call Colby VanDenburg at 303-623-1821. Yo truly, vva w X6tA a>J sic Lease Analyst 1421 Blake Street Denver, CO 80202 p 303.623.1821 f 303.623.3019 TRANSMITTAL LETTER CHECKLIST WELL NAME: �j/1u 1 — I PTD: 121b —/33 Development _ Service Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: C O�OJ POOL: Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL The permit is for a new wellbore segment of existing well Permit (If last two digits No. , API No. 50- _ _. Production in API number are should continue to be reported as a function of the original API number stated between 60-69) above. In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the Pilot Hole pilot hole must be clearly differentiated in both well name ( PH) and API number (50- _ _ ) from records, data and logs acquired for well. 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 Spacing Exception a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the Commission must be in no greater than Dry Ditch Sample 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for name of Non- well until after (Company Name) has designed and implemented a water well Conventional Well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the Commission to obtain advance approval of such water well testing program. 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 '4AMS�ltvt� in the attached application, the following well logs are also required for this wen: NEkfton �! dEnsiN� s Wi'/1 4(. me rAJ M 4k Idy�l� haIL ;AMJV4 144 4E s� Y;," AoM 1n144rvwa, Well Logging Requirements 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. I/ ?4&%& rt-VIN6WU l ,z Revised 5/2013 0%� A -A -L o25 �`` R;Ksf � ofn� �iJ `r �0C b e CLA4 (' Jw`�rEmFn�S dor•- 5P" ` WELL PERMIT CHECKLIST Field & Pool Well Name: NORSESHOE.1Program EXP._ Well bore seg Li I PTD#:2161330 Company ARMSTRONG—ENERGY, LLC Initial Class/Type EXP / PEND GeoArea 890 Unit On/Off Shore On Annular Disposal n Administration 17 Nonconven, gas conforms to AS31.05.030(j.1.A),Q.2.A-D) _ NA 8 1 Permit. fee attached.. _ _. NA ... �. .............. 2 Lease number appropriate_ _ _ _ _ _ _ _ _ _ Yes ADL392048,. entire wellbore. . .... . .......... 3 Unique well. name and number ... .. _ _ Yes Horseshoe -1 4 Well located in, a. defined pool. _ _ No Exploratory 5 Well located proper distance from drilling unit. boundary _ _ Yes _ .. . 6 Well located proper distance, from other wells _ _ _ Yes First well drilled within Section 15, TBN,. R4E, U.M. 7 Sufficient acreage. available in drilling unit. ..... Yes 8 If deviated, is wellbore plat included _ _ _ Yes .. _ . 9 Operator only affected party.. _ _ .... .... _ Yes _ .. 10 Operator has. appropriate bond in force _ Yes _ Appr Date 11 Permit. can be issued without conservation order. _ Yes _ PKB 12/16/2016 12 Permit can be issued without administrative. approval Yes 13 Can permit be approved before 15 day wait. Yes 14 Well located within area and strata authorized by Injection Order # (put. 1O# in comments) (For NA 15 All wells within 1/4. mile area.of review identified (For service well only) .. NA...... 16 Pre -produced injector; duration of pre production less than 3 months (For service well only) _ NA Geologic 18 Conductor string. provided _ Yes _ _ _ _ _ 16" conductor set at 118 ft. (cemented in place) Engineering 19 Surface casing. protects all.known USDWs _ NA No Aquifers..._arctic slope area. 20 CMT vol adequate to circulate on conductor & surf csg _ Yes _ 9 5/8" surface casing will be cemented to surface, 500% excess. planned.... . 21 CMT vol adequate to tie-in long string to surf csg. _ _ _ Yes . _ ... 7" -production casing will be cemented to surface. _ 2 stage cmt 22 CMT will cover. all known.prodpctive horizons _ Yes 23 Casing designs adequate for C, T. B & permafrost _ _ _ _ _ Yes _ ... BTC talc provided_ meet industry standards .. ............... 24 Adequate tankage. or reserve pit _ .. _ _ _ Yes _ _ Rig has steel pits. Drilling waste will be transported to approved G &.I facility, _ ...... . 25 If.a re -drill, has. a 10403 for abandonment been approved ...NA 26 Adequate wellbore separation proposed _ _ _ _ _ _ _ _ NA _ .... Near vertical well. No other wells in area, . ................... 27 If diverter required, does it meet regulations _ Yes .... _ Arctic Fox has 12" knife valve and. 12" diverter lines._ Appr Date 28 Drilling fluid program schematic & equip list. adequate Yes _ _ _ _ Max formation pressure= 3763 psi (9 ppg EMW) Will.drill with 10:4. ppg mud_ GLS 12/20/2016 29 BOPEs,_do they meet regulation _ _ .. _ _ Yes ..... . Arctic. Fox will use 11" 5000 psi BOPE - 3 Ram and 1 annular ... . 30 f3OPE.press rating appropriate; test to (put psig in comments)... Yes _ _ _ MASP= 2959 psi ( Will test. BOPE to 4000. psi). annular = 2500 psi '.31 Choke manifold complies w/API RP -53 (May 84)...... _ No _ _ _ . 3 1/8" 5000 psi manifold 32 Work will occur without operation shutdown _ _ _ _ _ _ Yes _ _ _ Sundry required to P 8 A or complete well for testing, 33 Is presence of 1-12S gas probable _ _ _ _ _ .. Yes .. . Exploration well.. H2S sensors and alarms are required.. 134 Mechanical condition of wells within AOR verified (For service well only) NA 35 Permit can be tssued w/o hydrogen sulfide measures ........ _ _ No... _ _ _ _ Exploratorywell. 112S.measures. required.. _ .... Geology 36 Data presented on potential overpressure zones _ _ _ _ _ _ _ _ _ _ Yes ..... _ . Expected reservoir pressure is 9.0_ppg EMW; will be drilled using 8.8 to 10,4. ppg mud.. . Appr Date 37 Seismic analysis of shallow gas zones .... . . . . . . . ........ . _ _ _ _ _ _ Yes _ _ _ _ _ _ _ Low potential for shallow gas; drill surf mtervrvw/ 8.8710 OPP9 mud _ Surf csg to beset above Tuluvak. Some PKB 12/16/2016 38 Seabed condition survey (if off -shore) _ _ _ _ _ _ _ _ _ .. _ _ _ _ _ _ NA _ _ potential for gas hydrates b4 permafrost. Onshore expJ well, I39 Contact name/phone for weekly progress reports [exploratory only] _ _ _ _ _ _ _ _ _ _ Yes .. _ _ Stephen Hannigan (337) 849-5345 Geologic Engineering Public Arctic Fox Rig will need full rig inspection before spudding well. GIs. Commi sic er: Date: 0 issioner Date Commissioner Date A -i -g E -Sy, LLC Horseshoe #1 50-103-20751-00-00 Exploration (Wildcat) North Slope Borough, Alaska January 27, 2017 — February 12, 2017 Approved by: Colby VanDenburg Distribution: 03/23/2017 Provided by: 4111l NABORS NABORSALASKA 1 DRILLING, INC. Compiled by: Albert Neubert Britten Adams T.D. Date: 2/12/2017 A—I—g Energy, LLC Horseshoe #1 TABLE OF CONTENTS 1 Mudlogging Equipment & Crew ........................................................ 1.1 Equipment Summary................................................................ 1.2 Crew.......................................................................................... 2 Well Details...................................................................................... 2.1 Well Summary .......................................................................... 2.2 Hole Data.................................................................................. 2.3 Daily Activity Summary............................................................. 3 Geological Data................................................................................ 3.1 Lithostratigraphy....................................................................... 3.2 Coring Program........................................................................ 3.3 Formation Summary................................................................. 3.3.1 Permafrost......................................................................... 3.3.2 Undifferentiated Paleogene............................................... 3.3.3 Middle Schrader Bluff ........................................................ 3.3.4 Lower Schrader Bluff......................................................... 3.3.5 MCU.................................................................................. 3.3.6 Tuluvak/Seabee................................................................. 3.3.7 Nanushuk Top................................................................... 3.3.8 Nanushuk 6....................................................................... 3.3.9 Nanushuk 5....................................................................... 3.3.10 Nanushuk 4....................................................................... 3.3.11 Nanushuk 3....................................................................... 3.3.12 Nanushuk 2....................................................................... 3.3.13 Nanushuk 1....................................................................... 3.4 Connection Gases.................................................................... 3.5 Trip (Wiper) Gases................................................................... 3.6 Sampling Program / Sample Dispatch ...................................... 4 Drilling Data...................................................................................... 4.1 Survey Data.............................................................................. 4.2 Bit Record................................................................................. 4.3 Mud Record.............................................................................. 4.4 Days vs. Depth Plot.................................................................. 5 Show Reports................................................................................... 6 Daily Reports.................................................................................... Enclosures: 2'/100' Formation Log (MD/TVD) 2'/100' Drilling Dynamics Log (MD/TVD) 2'/100' LWD / Lithology Log (MD/TVD) 2"/100' Gas Ratio Log (MD/TVD) Final Data CD NABORSALASKA DRILLING, INC. .. 3 .. 3 .. 3 ..4 ..4 ..4 .. 5 .. 7 .. 7 .. 7 .. 8 .. 8 11 14 16 17 19 24 26 27 28 29 32 34 36 36 37 38 38 42 43 44 45 51 E A-ao- g En -Sy, LLC Horseshoe #1 Mudlogging Equipment & Crew 1.1 Equipment Summary Parameter Equipment Type / Position Total Downtime Comments Unit Type Unit Number Steel Arctic ML 056 0 Functional Formation Gas Equipment QGM Agitator Gas Extractor (Trap) Baseline 9000 FID THA Baseline 9100 FID Chromatograph. 1 Hour 0 0 Repair Trap Functional Functional Fluid/Mud Density pp Halliburton / Baroid 0 10.2-10.75 Hook Load / Weight on bit Totco WITS Feed 0 Functional Mud Flow In Calculated value derived from Strokes/Minute and Pump Output 0 Functional Mud Flow Out Totco WITS Feed 0 Unreliable Mudlogging unit computer system Intel(R)Core(TM)2 Duo CPU 0 Functional Mudlogging unit DAC box In -unit data collection/distribution 0 Functional Pit Volumes, Pit Gain/Loss Totco WITS Feed 0 Functional Pump Pressure Totco WITS Feed 0 Functional Pump stroke counters Totco WITS Feed 0 Functional Totco Well Monitoring Components Totco computer networked in Mudlogging Unit 0 Functional Rate of penetration Totco WITS Feed 0 Functional RPM Totco WITS Feed 0 Functional Torque Totco WITS Feed 0 Functional 1.2 Crew .' Years' experience as Logging Geologist `2 Days at wellsite between spud and total depth of well NABORS ALASKA 3 DRILLING, INC. Years Das Sample Mudlo ers gg Catchers Years Das y Technician Days y Albert Neubert 43 16 Kyle Wiseman 2 16 Travis 5 Smith Britten Adams 5 16 Russell 13 16 Wardner .' Years' experience as Logging Geologist `2 Days at wellsite between spud and total depth of well NABORS ALASKA 3 DRILLING, INC. A—i—g Energy, LLC Horseshoe #1 Well Details 2.1 Well Summary Operator: Armstrong Energy, LLC Well Name: Horseshoe #1 Field: Exploratory (Wildcat) County: North Slope Borough State: Alaska Company Representatives: David Oryall, Bob Lenhart, Tom Boyd, Joe Steiner Location: Surface Coordinates: 1438' FWL & 2249' FSL, Section 015, T8N, R4E, UM Ground ( Pad ) Elevation: 23.5 MSL + Ice Rotary Table Elevation: 42.1 AML Classification: Exploration API #: 50-103-20751-00-00 Permit #: 216-1330 Rig Name/Type: Doyon Drilling, Arctic Fox, Land Double Spud Date: January 28, 2017 Completion Date: February 12, 2017 Total Depth: 6000' MD / 5819.44' TVD Drilling Days: 16 Primary Target: Nanushuk 3 Secondary Target: Nanushuk 5 Total Depth Formation: Nanushuk 1 Completion Status: Plug back pilot hole for sidetracks LWD-MWD Services: Baker Hughes / Inteq Directional Drilling: Baker Hughes / Inteq Drilling Fluids Service: Halliburton / Baroid Core Handling Weatherford Wireline Logging Service Schlumberger 2.2 Hole Data VNABORSALASKA III DRILLING, INC. Maximum Depth Mud Shoe Depth Hole TD Weight Dev. Coring Casing LOT MD TVD MD TVD Section Formation (Inc.) Liner (ppg) (ft) (ft) (ppg) (ft) (ft) 20" 118' 118' Permafrost 10.0 0 16" 118' 118' No 121/4" 2231' 2202,2' Schrader 10.2- 16.2 9.625" 2213' 2184.9' 13.8 Bluff 10.4 8.50" 4750' 4569.4' Nanushuk 3 10.4- 0.04 Yes NA 10.75 8.50" 6000' 5819.4' Nanushuk 1 10.4 0.26 NA VNABORSALASKA III DRILLING, INC. A-ao- g En -Sy, LLC Horseshoe #1 2.3 Daily Activity Summary 1/27/2017: 118' Rigging up Doyon Arctic Fox for Armstrong Energy, LLC. Continue calibration of Totco-Rig Sense; Pump pressure, flow out%, audible alarm. Spot cutting box under rockwasher auger -berm around, continue cleaning and servicing fig. Calibrate PVT sensors on pits, pressure test -good, and blow down line, spot 4 cuttings bins and berm, service rig loader. Prep pipe shed for BHA, warming up surface BHA. Loaded 290 barrels of 10.0 ppg spud mud to pits. Pre -spud meeting with rig crew and well support hands. Make up BHA and run in hole, tag up cement and start drilling on cement from 103' to 115' measured depth. 1/28/17: 118'-560' Pre -tour meeting with crew for spud. After meeting, prepare/test pumps and valves for drilling. Pick up tools and HWDP for short run until 192' MD. Get the confirmation to drill from team. Drill from 118'-192' MD. Pull out of hole and lay pipe down to prepare for second BHA per Baker Hughes. Rig -up new BHA and run in hole. Drilled from 192'-560' MD with sliding interval of (194'-236') (236'-276') (421'-436') MD. Continue to drill ahead. 1/29/17: 560'-1932' Drilled from 560'-1932' MD. While drilling per Baker Hughes representative use directional tools to build angle. Correctly we are still drilling ahead. 1/30/17: 1932'-2231' Drilled from 1932'-2030' MD. Repair rig mud pump then continue to drill ahead. TD drilling for casing at 2231' MD. Pump out of hole from 2231'-1935' MD and work tight spots. Pull out to 1630' MD. Trip back in hole to 2231' MD. Condition mud and circulate sweep. Prepare to pull out of entire hole. Pull out to 1590' MD. Condition mud and circulate. Continue to pull out to 1280' MD and remove excessive clay in cutting box. Pump out to 1040' MD. Remove clay balls from riser nipple and flow line. Continue to pull out 731' MD and flow check the well for 10 minutes. Well flow test is good. Pull out to 233' MD. 1/31/17: 2231' Continue to pull out the hole to 140' MD. Remove source from rig floor and lay down BHA. Clean rig floor and prepare for casing crew. Rig up casing equipment and have meeting on running casing. Run casing from surface to 1630' MD. 2/01/17: 2231' Continue to run in hole with casing to 2231.56' MD. Clean rig floor and prepare to rig up cement equipment. Pre -job safety meeting for cementjob. TIH with cement equipment and begin process. Completed cementjob and disassemble cement head. 2/02/17: 2231' Rig down cement equipment. Pull out of hole from 2053'MD to surface. Clean/clear rig floor to prepare for changing BOP stack. Begin to nipple down and service rig. Pick up and start on well head. 2/03/17: 2231' Continue to nipple up BOP stack. Rig up test plug to test shell, choke manifold, and kill lines to 4000psi. Testing completed and pick up 88 joints of 4" pipe. Pre -job meeting and pick up BHA per Baker Hughes. 2/04/17: 2231' Downloading of MWD tools, and clean rig. Continue to move up BHA and rack back in derrick. Prepare for test plug and test BOP stack. Test BOP to 4000psi and choke to 2000psi. Test is good and rig down test equipment. PJSM with E -line team. Run in hole with E -line equipment to 2100' MD and begin logging. Log bond finish and lay down Schlumberger E -line assembly. PJSM with all rig hand for running in hole with BHA. Run in hole with 4" drill pipe. 1�NABORS ALASKA 5 DRILLING, INC. A-ao- g En -Sy, LLC Horseshoe #1 2/05/17: 2231'-2296' Continue run in hole from 2052'-2124' MD. Rack back stand in derrick and blow down top drive. Rig up to test casing to 4000psi for 30 minutes. Test good and completed. Rig down test equipment, and prepare for displacement of new mud. Displace well with 10.4ppg OBM. Flow check the borehole (Good). Start FIT test. Pressure up to 404psi-334psi and bleed back 2.5bbls. Test completed and began to drill ahead. 2/06/17: 2296'-3772' Continue to drill ahead from 2296'-3483' MD. Pump 46bbls high viscosity sweep to clean hole and circulated sweep. Monitor well for 10mins. Pull out of hole from 3483'-2861'MD and wipe borehole. Run back in to 3483' MD and drill ahead 3772'MD. 2/07/17: 3772'-4750' Continue to drill ahead to 4599' MD. Circulate and clean hole. Control drill 50ft per hour until 4750' MD. Mix and pump 25bbls sweep. Monitor the well for 15 minutes. Pull out from 4750'-4102' MD to clean the borehole. 2/08/17: 4750'-4840' Continue to pull hole the hole from 3733'-680' MD. Monitor the well for 15 minutes. Pull up BHA and rack back. Clean rig floors and prepare for new coring BHA. Pre -job safety meeting and assemble coring BHA. Run in hole with coring tool and fill pipe continuously. Core from 4750' to 4840' MD. 2/09/17: 4840'-4931' Pull out of hole with core #1 and slowly back ream the borehole to 4750' MD. Begin to circulate bottoms up and work the pipe. Cut off pumps and pull out to 47' MD. Lay down cores as per Halliburton representative and remove core. RIH back in the hole with coring tool to 4840' MD, and core #2 from 4840' to 4931' MD. 2/10/17: 4931' Back ream and pump out of hole from 4931'-3530' MD. Start pulling with elevator from 3530'-300' MD. Lay down core barrels. Clean rig floors and monitor well. Build new BHA and begin to run in hole. 2/11/17: 4931'-5680' Trip in hole from 1301' MD to 4931' MD. Drill ahead to 5680' MD and continue to drill ahead. 2/12/17: 5680'-6000' Continue drill to 6000' MD, total depth at 4:25 am. Circulate bottom up and pump a sweep. Pull out of hole from 6000'-4667' MD and monitor the hole. Condition mud and circulate sweep around until hole is clean. Pump dryjob and continue to pull out to 675' MD. Lay down BHA and HWDP. Rig up to test BOP stack. Test the BOP stack and test is completed. Prepare for Schlumberger wireline tools. 2/13/17: 6000' Move up wireline tools and run in the hole to log borehole. Complete #143 logs and start on #4 log. 2/14/17: 6000' Continue to wireline the borehole and maintenance the rig. 2/15/17: 6000' Continue logging with wireline tools. Finish tool #4 wireline, and start on #5 core side-wall run. Begin loading pipe shed with 3.50" tubing. Completed #5 run and lay down core from run #5. Start to strap 3.50" for tally sheet. 2/16/17: 6000' Starting running 3.50" tubing running in 3.50" tubing. Prepare for Halliburton cementers. PJSM and start the cement job on borehole. 1�NABORS ALASKA 6 DRILLING, INC. A—i—g Energy, LLC Horseshoe #1 3 Geological Data 3.1 Lithostratigraphy LW D tops refer to provisional picks by the Geoloqist. FORMATION PROGNOSED MD SSTVD (ft) (ft) LWD MD (ft) PICK SSTVD (ft) Permafrost 118 - 118 - Undifferentiated Paleogene 900, -858 900 -858 Middle Schrader Bluff 1776 -1720 1848 -1792 Lower Schrader Bluff 1921 -1860 2016 -1953 MCU 2004 -1940 2103 -2038 Tuluvak/Seabee 2441 -2360 2454 -2376 Nanushuk 4188 -3970 4207 -3988 Nanushuk 6 4290 -4070 4384 -4162 Nanushuk 5 4351 -4130 4504 -4281 Nanushuk 4 4411 -4190 4560 -4337 Nanushuk 3 4562 -4340 4704 -4481 Nanushuk 2 5172 -4950 5252 -5030 Nanushuk1 5422 -5200 5775 -5553 TD 5722 -5500 6000 -5778 3.2 Coring Program Field Core Data Core Bit #1, Halliburton FC3555, 12614632, 8.5"- 6 Blade PDC, 90' Barrel, 4" Core Core # Formation Depth Interval (ft) Core Cut (ft) Recovery (ft) 1 Nanushuk 3 4750' - 4840' 90' in 1.3 hrs. 90.0' 2 Nanushuk 3 4840' - 4931' 91' in 1.1 hrs. 90.0' Total 181' 180' Rate of Penetration Total Gas Units Top Drive RPM Weight On Bit Top Drive Torque Total Pump GPM Pump Pressure Max — 60 Min — 10 Ave — 42 Max — 47 Min — 10 Ave — 40 Max - 60 Min - 40 Ave — 50 Max — 6.0 Min — 4.0 Ave — 5.0 Max -7467 Min - 2548 Ave - 4658 Max - 250 Min - 250 Ave - 250 Max - 1420 Min - 1370 Ave - 1400 VNABORSALASKA 7 III DRILLING, INC. A-ao- g En -Sy, LLC Horseshoe #1 3.3 Formation Summary 3.3.1 Permafrost 118' to 900' MD (-118' to -858' TVDSS) Encounter Permafrost gravel, sand, and mudstone drilling 121/2" hole out of 16" conductor set at 118', then continued through Permafrost base at 900'. Coarse clastic members share a similar depositional history and mineralogical components with some variation due to changes in depositional environment, system energy, and clastic provenance. Coarse clastics consist of black to multicolored gravels and granules with black to white interstitial sands; lithic rich framework clasts of black to multicolored cherts with subsidiary mineral grains and lithics consisting of clear to white quartz and translucent to opaque white, gray, and yellow feldspar plus scattered clasts of ironstone, jasper chalcedony, and trace polycrystalline yellow metaseds. Slight trace unusual accessory mineral of green glass shards and proto-round green glass (Si02) spheres. Gravels and sands are commonly clay mineral encrusted with occasional pyrite inclusion and subhedral crystal surface growth. Diverse non marine clast/grain surface features ranging from grind abrasion, transportation polish, impact chatter/frost on lithics and feldspars to mild aqueous solution frost on quartz. Clast/grain encrustation increase in grain packed channels then presents as freshly polished surfaces in clay held over -bank deposits. Lithic rich gravel and sand members diminish with depth in Permafrost coinciding with sharp increase in gray to light brownish gray siltstone and mudstone beginning at 170'. More massive bedded cohesive mudstone holds local sand packages, and a diversity of large lightly altered to partially carbonized tree wood fragments retaining their plant structures, brown black lignites, pyritized herbaceous NABORSALASKA 8 1 DRILLING, INC. Drilling Parameters Rate of Penetration ft/hr Wei ht On Bit klbs) Pump Pressure(psi) Max Min Average Min Max Average Min Max Average 302 9.5 147.9 34 0 18.2 2255 152 1257 Gas Summar Total Gas units Chromato rah (ppm) Max Min Average Methane Ethane Propane Butane Pentane 13 0 1.9 Max 2722 0 0 0 0 Min 68 0 Average 468 0 0 0 0 0 0 0 Encounter Permafrost gravel, sand, and mudstone drilling 121/2" hole out of 16" conductor set at 118', then continued through Permafrost base at 900'. Coarse clastic members share a similar depositional history and mineralogical components with some variation due to changes in depositional environment, system energy, and clastic provenance. Coarse clastics consist of black to multicolored gravels and granules with black to white interstitial sands; lithic rich framework clasts of black to multicolored cherts with subsidiary mineral grains and lithics consisting of clear to white quartz and translucent to opaque white, gray, and yellow feldspar plus scattered clasts of ironstone, jasper chalcedony, and trace polycrystalline yellow metaseds. Slight trace unusual accessory mineral of green glass shards and proto-round green glass (Si02) spheres. Gravels and sands are commonly clay mineral encrusted with occasional pyrite inclusion and subhedral crystal surface growth. Diverse non marine clast/grain surface features ranging from grind abrasion, transportation polish, impact chatter/frost on lithics and feldspars to mild aqueous solution frost on quartz. Clast/grain encrustation increase in grain packed channels then presents as freshly polished surfaces in clay held over -bank deposits. Lithic rich gravel and sand members diminish with depth in Permafrost coinciding with sharp increase in gray to light brownish gray siltstone and mudstone beginning at 170'. More massive bedded cohesive mudstone holds local sand packages, and a diversity of large lightly altered to partially carbonized tree wood fragments retaining their plant structures, brown black lignites, pyritized herbaceous NABORSALASKA 8 1 DRILLING, INC. A-ao- g En -Sy, LLC Horseshoe #1 plant remains, thin to thick walled shell fragments, and local volcanic ash fall beds. Volcanic ash falls are as local well defined beds and disseminated into mudstone host to create a very reactive and expansive clay. There is no well-defined contact or marker between the Permafrost and underlying undifferentiated Paleogene sediments at 900'. Sand (118'-195') = clear to translucent with milky -cloudy hues, dark gray to medium gray with greenish gray hues, and traces of reddish -pink and brownish gray/black colors; quartz dominant with lithics, chert, and traces of orthoclase framework; very fine to pebble grain sizes; very poorly sorting; rounded to angular angularity; very low to high sphericity; dominantly unconsolidated sand with trace of moderate hard sandstones; thick to thin bedding structures; moderate HCL reaction in bulk sample; greenish yellow fluorescence tuffaceous claystone 10%-3% in bulk samples; no hydrocarbon indictors. Claystone: (215'-290') = medium gray to dark gray with light brownish gray hues, slight brownish olive hues colors; adhesive clay properties; mushy to clotted consistency; malleable to pulverulent tenacity; irregular fracture; massive nodular cutting habits; earthy to waxy when wet and dull to earthy when dry luster; colloidal to clayey and silty with slight gritty texture; thick to massive bedding structures; traces of pyrite, sand, tuffaceous sandstone, tuff, are interbedded with the claystone; weak to moderate HCL reaction; 1% greenish yellow tuff and tuffaceous sandstone fluorescence in bulk samples; no hydrocarbon indictors. Claystone (305'-360') = medium gray to dark brownish gray with brownish olive hues colors; cohesive to expansive clay properties; pasty to stiff consistency; malleable to stiff tenacity; earthy to irregular fracture; massive to nodular and rounded wedgelike cutting habits; earthy to dull and slight frosted luster; silty to clayey with slight matte texture; massive to thick bedding structures; weak HCL reaction in bulk samples; no oil indictors. Sand (375'-460') = clear to translucent with slight gray cloudy hues, greenish gray hues, dark gray to black lithics, brownish to golden yellow hues, blue to turquoise hues, and brownish green hues colors; quartz dominant with feldspars, lithics, trace tuff, trace pyrite, trace thermal tuff; very fine to coarse grain sizes; poor sorting; angular to subrounded angularity; low to moderated sphericity; unconsolidated sands; trace of petrified wood material; thin bedding structures; 1%-3% fluorescence of greenish yellow and brownish red from tuff and tuff clay/sandstone; weak to moderate HCL reaction in bulk sample; no oil indictors. Tuff (470-525') = creamy brown to cloudy white colors; tough to stiff with traces of malleable to pulverulent tenacity; splintery to hackly fractures; flaky to bladed wedgelike cutting habits; polish luster; smooth to abrasive texture; thin laminae banded bedding structure; moderate HCL reaction with fissile separation during reaction and tuffaceous calcareous properties; no hydrocarbon indictors in bulk samples. Claystone (550'-620') = medium light brownish gray to dark gray with slight brownish hues colors; stiff to clumpy consistency; plastic to cohesive clay properties; malleable to flexible tenacity; irregular to earthy fractures; massive to nodular with few elongated cutting habits; dull to waxy when wet; silty to clayey to colloidal texture; thick to massive bedding structures; weak to very weak HCL reaction in bulk sample; 1% white to slight yellow fluorescence in bulk samples; no hydrocarbon indictors. Sand (625'-690') = dark gray to black dominant with clear to smoke translucent, blue to greenish blue hues, cloudy clear yellowish hues, brownish red hues, reddish pink hues colors; lithic dominant with quartz, feldspar, tuff, chert and trace pyrite framework; fine to coarse grain size; poorto well sorting; subrounded to subangular angularity; very low to low sphericity; unconsolidated sands; thin bedding structures; very weak 1�NABORS ALASKA 9 DRILLING, INC. A -a -g En -Sy, LLC Horseshoe #1 HCL reaction; traces of yellowish green fluorescence in bulk samples; no hydrocarbon indictors. Claystone (700'-755') = dark gray to medium gray, light medium gray, and slight brownish gray hues colors; colloidal to pliable clay properties; clotted to pasty and clumpy consistency; elastic to malleable tenacity; irregular fracture; nodular to massive cutting habits; dull when dry and waxy when wet luster; silty to clayey texture; massive to thick bedding structure; very weak HCL reaction in bulk sample; no hydrocarbon oil indictors. Tuffaceous Claystone (765'-810') = light brown to cream tan color; reactive clay properties; mushy consistency; pulverulent to malleable tenacity; irregular fracture; nodular cutting habits; dull luster; matte to clayey texture; thin to soft sediment deformation bedding structure; moderate to slight strong HCL reaction; yellowish green fluorescence in Ultra Violet light; no hydrocarbon indictors. Claystone (820'-900') = light medium gray to medium gray with a slight change to light greenish gray color; adhesive clay properties; clotted to clumpy consistency; malleable to pulverulent tenacity; earthyto irregular fracture; massive to nodular cutting habits; waxy when wet and dull when dry; silty to clayey with gritty texture; massive to thick bedding structure; very weak HCL reaction; trace of yellowish white in bulk sample; no oil smell; no cut; visual cut; no hydrocarbon indictors. NABORS ALASKA 10 DRILLING, INC. A-ao- g En -Sy, LLC Horseshoe #1 3.3.2 Undifferentiated Paleogene 900' to 1848' MD (-858' to -1848' TVDSS) ti . f 0.5 mm k -A This Undifferentiated Paleogene rock shares a similar depositional history and mineralogical components with some variation due to changes in depositional environment, system energy. The first noticeable change from hydro -reactive light brownish gray claystone/mudstone of the Permafrost to the underlying Paleogene rock was seen as more indurated non-reactive pale to moderate brown marine clay shale starting at 1160'. This well-defined shale member continues to 1250' then graded back to non -brackish marine coarser clastics held in brownish to greenish gray clay and siltstone. Only subtle variations within these sediments occur past the clay shale at 1200' and clay held sand at 1300'. Sand from 1270' through 1350' is medium grained, angular, and far more felsic than the lithic rich sand found in the Permafrost. Common clay mineral cementation, to sands floating in a mudstone matrix. Sand member at 1300' is also laden with fine brownish black carbonaceous material and stippled with red jasper. Underlying light brownish gray mudstone slowly changes to a lighter gray siltstone conformable with fine grained sandstone beginning at 1675'. Non -marine sand framework below 1675' is now more evenly mixed between coarse grained, rounded, black to multicolored lithics and angular, medium to fine grained, felsic grains. Clearly non -marine sand is bracketed by brownish black woody durian lignite to waxy brown clarain (liptinite) coal macerals; coal macerals from 1750' to 1800' are responsible for gas and iridescent oil shows within this sand member. Coals and sands are now intercalated with increasing volcanic ash content and discrete beds. Once again there is an appearance of thin walled thin walled shell fragments and green glass shards in framework. There is no well-defined contact, marker, or consistent pick between the Undifferentiated Paleogene and underlying Upper Cretaceous Middle Schrader Bluff sediments at 1848'. NABORSALASKA 11 1 DRILLING, INC. Drilling Parameters Rate of Penetration ft/hr Wei ht On Bit klbs Pump Pressure(psi) Max Min Average Min Max Average Min Max Average 488 7.7 150 42 1 26.8 2297 J 1229 1975 Gas Summary Total Gas units Chromato rah (ppm) Max Min Average Methane Ethane Propane Butane Pentane 84 0 30.5 Max 19776 0 0 0 0 Min Average 125 0 6847 0 0 0 0 0 0 0 ti . f 0.5 mm k -A This Undifferentiated Paleogene rock shares a similar depositional history and mineralogical components with some variation due to changes in depositional environment, system energy. The first noticeable change from hydro -reactive light brownish gray claystone/mudstone of the Permafrost to the underlying Paleogene rock was seen as more indurated non-reactive pale to moderate brown marine clay shale starting at 1160'. This well-defined shale member continues to 1250' then graded back to non -brackish marine coarser clastics held in brownish to greenish gray clay and siltstone. Only subtle variations within these sediments occur past the clay shale at 1200' and clay held sand at 1300'. Sand from 1270' through 1350' is medium grained, angular, and far more felsic than the lithic rich sand found in the Permafrost. Common clay mineral cementation, to sands floating in a mudstone matrix. Sand member at 1300' is also laden with fine brownish black carbonaceous material and stippled with red jasper. Underlying light brownish gray mudstone slowly changes to a lighter gray siltstone conformable with fine grained sandstone beginning at 1675'. Non -marine sand framework below 1675' is now more evenly mixed between coarse grained, rounded, black to multicolored lithics and angular, medium to fine grained, felsic grains. Clearly non -marine sand is bracketed by brownish black woody durian lignite to waxy brown clarain (liptinite) coal macerals; coal macerals from 1750' to 1800' are responsible for gas and iridescent oil shows within this sand member. Coals and sands are now intercalated with increasing volcanic ash content and discrete beds. Once again there is an appearance of thin walled thin walled shell fragments and green glass shards in framework. There is no well-defined contact, marker, or consistent pick between the Undifferentiated Paleogene and underlying Upper Cretaceous Middle Schrader Bluff sediments at 1848'. NABORSALASKA 11 1 DRILLING, INC. A-ao- g En -Sy, LLC Horseshoe #1 Siltstone/Claystone (900'-960') =medium gray to light medium gray with slight grayish green hues color; stiff to clot consistency; dense to stiff tenacity; earthy fracture; massive to block cutting habits; dull when dry and waxy when wet luster; clayey to silty with matte colloidal texture; massive to thick bedding structure; 5-10% claystone are changing slowly in siltstone; 1% traces of yellowish white and green in fluorescence bulk samples; weak HCL reaction on clay/siltstones; no hydrocarbon indictors. Clay/Claystone (960'-1020') = medium dark gray overall, even consistency and texture but studded with sand grains resembling armored mud balls; local yellowish brown wood debris also shows minor compaction with sand grains indented into some bark surfaces; clays are stiff and moderately cohesive; slightly adhesive and slightly expansive in water; sectile; malleable; earthy break; lumpy nodular cuttings habit; dull earthy luster to waxy when wet; thick bedding structure; smooth texture; trace floating silts; non calcareous; no visible oil indicators. Clay/Claystone (1020'-1100') = subtle change to brownish gray with pale yellowish brown hues; very stiff, sectile, but expansive in water; very cohesive to moderate adhesive; abundant floating fine debris and silts held in the reactive clay matrix; malleable with break; nodular to lumpy cuttings habit; dull luster with sparkles from reflective mica; smooth to silty texture; thick bedding; trace fine light amber organic debris; non fluorescent; no visible oil indicators. Claystone (1100'-1170') = brownish gray grading to an even medium light gray with pale brown hues; massive appearance and bedding; sectile with resistance to very stiff; increased density; very cohesive; moderately adhesive; malleable with rupture; earthy break; large nodular cuttings habit; dull to waxy luster with sparkles from cryptomicas and silts; smooth to finely silty texture with now common crypto -floating light amber brown carbonaceous material; no oil indicators. Clay Shale (1170'-1220') = consistent to color variegated with appearance of moderate brown organic layers within brownish gray clay shale; low density; when carbonaceous to moderate density as stiff to friable shale; firm sectile to crumbly; earthy to blocky break; nod to blocky cutting habit with blunted edges; dull to organic luster; smooth texture; thick to hydro -fissile; non calcareous and non -expansive; loss of most crypto mica; no visible oil indicators. Sandy Clay/Claystone (1220'-1330') = light gray overall with areas of brownish gray and greenish gray; change in sand composition to dominant felsic non marine sands over previous non marine lithic dominated coarser framework; moderately cohesive gray clay matrix holding dominant quartz, feldspars, and scattered lithic rich framework; sand have a salt and pepper appearance; grains are fine to very coarse with dominant medium to coarse; fair sorting; angular to subround with dominant subangular; low to moderate sphericity; moderate grind polish surface features with local fine pitted frost; soft with break around a floating fabric; first trace silver mica in sample; no visible bedding; non calcareous; no visible oil indicators. Clay/Claystone (1330'-1420') = medium light gray grading to brownish gray overall with local splotches of moderate brown surrounding fine floating black lignites; massive appearance and bedding plus subtle color variations; stiff to firm friable; sectile to resistant to break; large blocky/lumpy cuttings habit with earthy break; dull to waxy luster with sparkles from disseminated crypto mica flecks and patchy sulfides; smooth texture; hint of aligned detritus; predominant non calcareous until appearance of silts near 1420'; slowly reactive to water; no visible oil indicators. Siltstone (1420'-1480') = medium light gray overall; generally massive but with some floatingfine to medium 1�NABORS ALASKA 12 DRILLING, INC. A -a -g E -Sy, LLC Horseshoe #1 felsic sand beds; medium to occasionally coarse silt floating in a thick clay matrix; stiff cohesive clays; more reactive than clay shale; moderately adhesive; slightly calcareous; nodular cuttings with earthy break and blunt edges; dull luster with sparkles from cryptomica; no visible bedding; smooth texture; slightly reactive in water; no visible oil. Silty Sandy Claystone (1480'-1550') = light to medium gray; generally massive bedding and appearance with silts and fine to med sand floating in a thick but firm claystone matrix; low density; moderate cohesive and adhesive; reactive with water; stiff but sectile; irregular nodular cuttings with earthy break; dull luster; smooth to gritty texture; no visible beddings; sample stippled with very pale yellow thin walled shell fragments; only calcareous reaction is on shell fragments showing weak yellow fluorescence. Siltstone (1550'-1610') = medium light gray overall with subtle linear variations with more and less silts, fine sand, and claystone; all coarser clastics are predominant floating in clay matrix; low density; stiff to crumbly; sectile to malleable with rupture; irregular nodular cuttings habit with earthy break; dull luster; silty to smooth texture; slight lineation of clastics delineates bedding; slight calcareous reaction to HCL; no visible oil. Claystone (1615'-1675') = dark gray to medium gray with brownish gray hues colors; pliable to cohesive clay properties; stiff to pasty consistency; flexible to malleable tenacity; earthy to irregular fracture; massive to elongated nodular cutting habits; dull when dry and waxy when wet luster; clayey to silty with few colloidal textures; thick to massive bedding structures; weak to moderate HCL reaction in bulk sample; traces of yellowish green in fluorescence bulk sample; no hydrocarbon indictors. Sandstone (1685'-1745') = light gray to medium gray with translucent to white hue, translucent to light green hues, cream to white clastic hues colors; quartz dominant with calcareous fragments and traces of black minerals framework; very fine to fine grain size; well to fair sorting; subangular to subrounded; low sphericity; firm friable to moderate hard hardness; dolomite and quartz matrix grain support; thin bedding structure; trace pyrite in bulk sample; no oil indictors. Sand (1755'-1848') = clear to translucent with light greenish brown hues, yellowish green hues, olive brown hues, light greenish gray hues, cloudy white hues colors; unconsolidated sands; dominantly quartz with trace calcite and dolomite framework; medium to coarse grain sizes; well to moderate sorting; angular to subangular; low to very low sphericity; thin bedding structure; very weak HCL reaction in bulk sample; slight to weak odor; no visual oil stains; 70% yellowish white bright patchy fluorescence; fluorescence cut slow dull to slight bright translucent white color; no streamer in fluorescence cut; faint brown yellow residue in flour cut; no visual cut residue or color. NABORS ALASKA 13 DRILLING, INC. A-ao- g En -Sy, LLC Horseshoe #1 3.3.3 Middle Schrader Bluff 1848' to 2016' MD (-1792' to -1953' TVDSS) The Upper Cretaceous, Middle Schrader Bluff sand package and volcanic claystone starts with a non -marine, coarse grained, poorly sorted, rounded, bit disaggregated sand showing a reappearance of black chert lithics from 1848' to 1900', followed a shallow water fine grained, well sorted, felsic sandstone. Transition begins from non -marine sand shallow water sand starting at 1900' showing multicolored rounded non -marine lithics and thick walled shell fragment in framework to an angular, medium/fine grained, well sorted, white, felsic sandstone showing remnant grain surface crust from indurated authigenic clay mineral including kaolin, smectite, and very minor zeolite on both felsic minerals and lithic grain free/fixed margins. This area is also the start of abundant disseminated to intercalated volcanic ash beds, white Kaolin Tonstein layers. Reactive volcanic ash layers and non-reactive Tonstein layers have evenly disseminated cryptomica. Larger hex -biotite micromica is seen specifically in volcanic ash at 1920'. Tuff/Tuffaceous Sandstone (1848'-1910') = white to milky white with occasional very light gray hues color; micro crystalline quartz and tuff framework with tuff cement grain support; veryfine grain size; well sorted; angular angularity; very low sphericity; 90% firm friable with 10% easily friable hardness; thin bedding structure; no HCL reaction on tuff; no visual fluorescence on any tuffaceous sandstone; no oil or gas indictors. Tuff (1935'-1990') = white to cream milk with occasional light greenish blue hues colors; micro crystalline volcanic ash framework; dense to crumbly tenacity; hackly to drusy fracture; tabular to bladed edge cutting 1�NABORS ALASKA 14 DRILLING, INC. Drilling Parameters Rate of Penetration ft/hr Wei ht On Bit klbs Pum Pressure si Max Min Average Min I Max I Average Min Max Average 236 10 72 41 1 14 1 30 2443 2058 2346 Gas Summary Total Gas units Chromato rah (ppm) Max Min Average Methane Ethane Propane Butane Pentane 48 19 34 Max 10960 0 0 0 0 Min Average 3093 0 7508 0 0 0 0 0 0 0 The Upper Cretaceous, Middle Schrader Bluff sand package and volcanic claystone starts with a non -marine, coarse grained, poorly sorted, rounded, bit disaggregated sand showing a reappearance of black chert lithics from 1848' to 1900', followed a shallow water fine grained, well sorted, felsic sandstone. Transition begins from non -marine sand shallow water sand starting at 1900' showing multicolored rounded non -marine lithics and thick walled shell fragment in framework to an angular, medium/fine grained, well sorted, white, felsic sandstone showing remnant grain surface crust from indurated authigenic clay mineral including kaolin, smectite, and very minor zeolite on both felsic minerals and lithic grain free/fixed margins. This area is also the start of abundant disseminated to intercalated volcanic ash beds, white Kaolin Tonstein layers. Reactive volcanic ash layers and non-reactive Tonstein layers have evenly disseminated cryptomica. Larger hex -biotite micromica is seen specifically in volcanic ash at 1920'. Tuff/Tuffaceous Sandstone (1848'-1910') = white to milky white with occasional very light gray hues color; micro crystalline quartz and tuff framework with tuff cement grain support; veryfine grain size; well sorted; angular angularity; very low sphericity; 90% firm friable with 10% easily friable hardness; thin bedding structure; no HCL reaction on tuff; no visual fluorescence on any tuffaceous sandstone; no oil or gas indictors. Tuff (1935'-1990') = white to cream milk with occasional light greenish blue hues colors; micro crystalline volcanic ash framework; dense to crumbly tenacity; hackly to drusy fracture; tabular to bladed edge cutting 1�NABORS ALASKA 14 DRILLING, INC. A -a -g E -Sy, LLC Horseshoe #1 habits; dull to slight waxy luster; clayey to sucrosic texture; thick bedding with occasional slight dark black banded layers; no fluorescence on tuff; no HCL reaction on tuff; no hydrocarbon indictors in bulk sample. Siltstone (1990'-2016') = dark brown to black grayish brown colors; very fine grain size; well sorted; firm friable to hard hardness; overgrowth of quartz cement; thin interbedded siltstone with claystone; no HCL reaction on siltstone; matte texture; frosted to earthy luster; splintery fracture; no HCL reaction on siltstone; trace fluorescence yellowish green in bulk sample; no hydrocarbon indictors in sample. NABORS ALASKA 15 DRILLING, INC. A-ao- g En -Sy, LLC Horseshoe #1 3.3.4 Lower Schrader Bluff 2016' to 2103' MD (-1953' to -2038' TVDSS) Reactive volcanic ash layers and non-reactive Tonstein layers have evenly disseminated cryptomica continue within the Lower Schrader Bluff. Also seen is a persistence of disseminated and framboidal pyrite replacement of marine microfossils that continue through sample at 2040'. Formation is unique with its abundance of opaque to translucent white Kaolin Tonstein beds (altered from volcanic ash) both colloidal in appearance and texture from coalescing remnant glass shards and sub-porcelaneous as flint clay. Claystone (2016'-2103') = medium gray to light gray with light grayish brown hue colors; adhesive clay properties; clotted to pasty consistency; pulverulent to malleable tenacity; irregular fracture; nodular to massive rounded balls of cutting habits; silty to clayey texture; thick to massive bedding structure; very weak HCL reaction in bulk sample; trace yellowish green fluorescence in bulk sample; not hydrocarbon indictors in full sample tray. NABORS ALASKA 16 DRILLING, INC. Drilling Parameters Rate of Penetration ft/hr Wei ht On Bit klbs Pum Pressure si Max Min Average Min Max Avera eMin Max Average 176 28 93 30 13 26 2346 1954 2281 Gas Summary Total Gas units Chromatography (ppm) Max Min Average Methane Ethane Propane Butane Pentane 38 7 19 Max 8187 0 0 0 0 Min Average 1597 0 3952 0 0 0 0 0 0 0 Reactive volcanic ash layers and non-reactive Tonstein layers have evenly disseminated cryptomica continue within the Lower Schrader Bluff. Also seen is a persistence of disseminated and framboidal pyrite replacement of marine microfossils that continue through sample at 2040'. Formation is unique with its abundance of opaque to translucent white Kaolin Tonstein beds (altered from volcanic ash) both colloidal in appearance and texture from coalescing remnant glass shards and sub-porcelaneous as flint clay. Claystone (2016'-2103') = medium gray to light gray with light grayish brown hue colors; adhesive clay properties; clotted to pasty consistency; pulverulent to malleable tenacity; irregular fracture; nodular to massive rounded balls of cutting habits; silty to clayey texture; thick to massive bedding structure; very weak HCL reaction in bulk sample; trace yellowish green fluorescence in bulk sample; not hydrocarbon indictors in full sample tray. NABORS ALASKA 16 DRILLING, INC. A -a -g E -Sy, LLC Horseshoe #1 3.3.5 MCU 2103' to 2454' MD (-2038' to -2376' TVDSS) A change at the MCU is characterized by its ever increasing volcanic ash content as concise layers and disseminated into all lithology types. Volcanic ash is present but no sign of white Kaolin Tonstein beds. Massive quantities of volcanic ash persist as layer and expansive tuffaceous claystone until the contact with Tuluvak/Seabee Formation @ 2454'. Lithology (2103'-2200') = generally massive grayto pastel brownish gray clay as hydrated claystone with local gradational beds to interbeds of light gray white volcanic ash; all lithology types lack bedding structure except for slight lineation of cryptomicas disseminated in ash; non calcareous, no mineral fluorescence; no oil indicators. Volcanic Ash/Tuff (2170'-2200') = pastel gray, light brownish gray, and white when pure; hydrophilic, expansive on rehydration; low density; amorphous microcrystalline appearance with evenly disseminated silver gold cryptomicas; interbedded and gradational with med brownish gray claystone; no mineral fluorescence; no visible bedding; no oil. Tuff (2265'-2290') = creamy white to white with yellowish brown hue, and light gray layers colors; stiff to crumbly tenacity; earthy fracture; tabular cutting habits; dull to earthy when dry luster; colloidal to clayey texture; thick with gray banded bedding structures, weak to slight moderate HCL reaction, no oil indictors. NABORS ALASKA 17 DRILLING, INC. Drilling Parameters Rate of Penetration ft/hr Wei ht On Bit klbs Pum Pressure si Max Min Average Min Max Avera aMin Max Average 162 8.5 83 30 0 14 2365 1372 1885 Gas Summary Total Gas units Chromatography (ppm) Max Min Average Methane Ethane Propane Butane Pentane 65 2 18 Max 15750 0 0 0 0 Min Average 159 0 4009 0 0 0 0 0 0 0 A change at the MCU is characterized by its ever increasing volcanic ash content as concise layers and disseminated into all lithology types. Volcanic ash is present but no sign of white Kaolin Tonstein beds. Massive quantities of volcanic ash persist as layer and expansive tuffaceous claystone until the contact with Tuluvak/Seabee Formation @ 2454'. Lithology (2103'-2200') = generally massive grayto pastel brownish gray clay as hydrated claystone with local gradational beds to interbeds of light gray white volcanic ash; all lithology types lack bedding structure except for slight lineation of cryptomicas disseminated in ash; non calcareous, no mineral fluorescence; no oil indicators. Volcanic Ash/Tuff (2170'-2200') = pastel gray, light brownish gray, and white when pure; hydrophilic, expansive on rehydration; low density; amorphous microcrystalline appearance with evenly disseminated silver gold cryptomicas; interbedded and gradational with med brownish gray claystone; no mineral fluorescence; no visible bedding; no oil. Tuff (2265'-2290') = creamy white to white with yellowish brown hue, and light gray layers colors; stiff to crumbly tenacity; earthy fracture; tabular cutting habits; dull to earthy when dry luster; colloidal to clayey texture; thick with gray banded bedding structures, weak to slight moderate HCL reaction, no oil indictors. NABORS ALASKA 17 DRILLING, INC. A -a -g En -Sy, LLC Horseshoe #1 Claystone (2315'-2345') = dark brown to brownish black gray color; clumpy to stiff consistency; sectile tenacity; earthy to irregular cutting habits; dull to slight waxy luster; smooth to clayey texture; thick to massive bedding structure; no HCL reaction; no oil indictors. Shale (2355'-2385') = gray brown to dark brownish gray color; tough to dense tenacity; hackly to splintery fracture; platy to wedgelike with bladed edge cutting habits; frosted luster; matte to abrasive texture thin bedding structure; no HCL reaction on shale; no hydrocarbon indictors. Tuff (2400'-2415') = creamy white to slight grayish white with occasional light brownish colors; clay like clotted consistency; sectile tenacity; earthy to irregular fracture; massive to rounded wedgelike bedding structure; weak HCL reaction on tuff; no hydrocarbon indictors. NABORS ALASKA 18 DRILLING, INC. A-ao- g En -Sy, LLC Horseshoe #1 3.3.6 Tuluvak/Seabee 2454' to 4207' MD (-2376' to -3988' TVDSS) 2m 12 mml i kiti •i: fir: ±_ ,.��. • qtr 1 L A io- h-,11 1.1 1- IMI Tuluvak/Seabee formation begins with a classic LWD separation from gamma and resistivity which symbolizes sands/sandstone. This sandstone share deposits with volcanic ash and lignites throughout this member. Sandstone background gas stays consist to 10-68u. As the sandstone decrease in depth silty -shale was the dominant lithology with black carbonaceous material disseminated in shale/siltstone. Gas units increased in tuffaceous shale just prior to drilling into the Nanushuk Top at 4207'. At 2650' MD sandstone reappeared with marine shell fragments and calcite cement grain support. No hydrocarbon indictors were 1�NABORS ALASKA 19 DRILLING, INC. Drilling Parameters Rate of Penetration ft/hr Weight On Bit klbs Pump Pressure(psi) Max Min Average Min Max Average Min Max Average 221 12 109 11 0 7 3255 1525 2878 Gas Summary Total Gas units Chromatography (ppm) Max Min Average Methane Ethane Propane Butane Pentane 66 1 15 Max 15558 171 37 0 0 Min Average 78 43 3067 9 25 2 0 0 0 0 2m 12 mml i kiti •i: fir: ±_ ,.��. • qtr 1 L A io- h-,11 1.1 1- IMI Tuluvak/Seabee formation begins with a classic LWD separation from gamma and resistivity which symbolizes sands/sandstone. This sandstone share deposits with volcanic ash and lignites throughout this member. Sandstone background gas stays consist to 10-68u. As the sandstone decrease in depth silty -shale was the dominant lithology with black carbonaceous material disseminated in shale/siltstone. Gas units increased in tuffaceous shale just prior to drilling into the Nanushuk Top at 4207'. At 2650' MD sandstone reappeared with marine shell fragments and calcite cement grain support. No hydrocarbon indictors were 1�NABORS ALASKA 19 DRILLING, INC. A-ao- g En -Sy, LLC Horseshoe #1 found. The rest of this formation is dominated by siltstone and shale. Around 2950' MD tuffaceous materials are deposited in patches from 10-30ft in depth throughout the rest of formation. The tuffaceous materials were interbedded and gradational within sandstones, siltstone, and consolidated sands. To end this section, 90-100% tuffaceous shale was drilled, shale induration continues until we reached Nanushuk top. Siltstone (2465'-2505') = gray brown to dark grayish brown color; brittle to crumbly tenacity; earthyfracture; tabular to massive wedgelike cutting habits; waxy to dull luster; silty texture; thick bedding with tiny black banding in bedding structure; moderate HCL reaction in bulk sample; no hydrocarbon indictors in bulk sample. Sandstone (2515'-2565') = light brownish gray to clear with occasional light greenish translucent hue colors; quartz dominant with black sparkling lithics and dolomite; very fine grain size; very well sorting; subangular to angular angularity; low sphericity; soft to easily friable hardness; soft claylike cement grain support; thin bedding structure; weak to slight moderate HCL reaction; no hydrocarbon indictors. Claystone (2580'-2625') = gray brown to dark brownish gray color; mushy consistency; sectile to malleable tenacity; irregular to earthy fracture; nodular to small ball cutting habits; waxy luster when wet; clayey to colloidal texture; thin bedding structure; no HCL reaction on claystone; no hydrocarbon indictors in sample. Sandstone (2620'-2720') = light gray when grain packed to medium light gray then gray with depth and increased silt to shale matrix; dominant felsic framework stippled with color from common to abundant interstitial black carb material laced into framework, orange mineral resembling palagonite, pale yellowish orange slowly reactive carbonate occasional deformed between grains, and scattered gray lithics as grains; sand are very fine to medium with dominant medium then grades to fine with depth; fair sort; angular to subangular with dominant angular; moderate to low sphericity; PDC bit disaggregate sand grains appearance vitreous to mild solution frost over relic grind abrasion; friable with weak clay mineral cement to spottyfirm calcite cement associated with possible very pale orange shell fragment; sample breaks around a point to long contact fabric; trace crypto mica and disseminated pyrite only accessory mineral; good visible bedding increasing as fine grained sandstone interbedded with siltstone and light yellowish gray tuff; also increased lineation of detritus; very spotty calcareous reaction to HCL; no visible oil indicators. Lithology = discretely interbedded medium gray, fine sandstone, medium dark gray siltstone to mudstone, and dark gray claystone to clay shale; local beds of pastel yellow grayvolcanic ash that also disseminates into host rock; trace very pale orange slowly reactive carbonate to dolomite; thin fine to medium grained sandstone beds becoming very dirty with abundant interstitial claystone to sands floating in clay shale matrix; common aligned crypto -micro detritus including micro mica sheets and very fine black carb flecks; no visible oil indicators. Sandstone (2815'-2850') = dirty, matrix supported to minor grain packed; medium light gray with slight brownish gray hues; brown hues are surface stain from lignite tannins; individual grains of water clear relic euhedral bi-pyramidal volcanic quartz with white clouded quartz and pyritized opaque gray feldspar; common gray to green rounded lithic clasts as grains and squashed yellow associated clasts; very fine to medium with dominant fine; angular to subround with dominant angular to subangular; moderate to low sphericity with local high on volcanic quartz and lithics; fair to well sorted; remnant grind polish abrasion with a mild solution frost overprint; also common clay mineral surface crust/cement; easily to firm friable; breaks around a point contact -floating fabric; common small mica books plus black volcanic hex biotite; also 1�NABORS ALASKA 20 DRILLING, INC. A-ao- g En -Sy, LLC Horseshoe #1 common pyritized grains and framboidal pyrite; good bedding features seen as aligned detritus including black carb material plus trace aligned grains; no visible oil indicators. Clay Shale (2850'-2980') = medium dark gray to brownish gray shale member terminating into a pale gray indurated tuffaceous siltstone at 2980', non -fluorescence but very expansive; composition of shale below ash changes; moderate density; crumbly tenacity; friable; PDC shaved and stacked platelets as dominant cuttings habit; dull luster with matte texture; very slight trace disseminated aligned carb material; non calcareous; no visible oil indicators. Tuffaceous Siltstone/Ash (2980'-3000') = siltstone shows even color and comp but with minor black carbonaceous material somewhat aligned to contorted bedding; non fluorescence; expansive; no visible oil. Tuffaceous Shale (3000'-3110') = pastel medium to light gray with minor dark gray as argillaceous shale and light gray as siltstone laced with aligned crypto carb material; tuffaceous shale grades back into a dark gray clay shale a well-defined yellow orange ash bed at 3060'; moderate density; easily to firm friable; crunchy; blocky break and cuttings habit seen over PDC generated texture; chalky dull luster with micro sparkles on silts; matte to silty texture; good trace lineation of detritus; very expansive to pinpoint calcareous; trace crypto pyrite; no visible oil indicators. Shale (3110'-3170') = medium to dark gray with minor variations to medium light gray as silts, pastel gray with ash, and very faint brownish gray from organic stain by lignite tannins around disseminated carb material; very homogeneous appearance and bedding; moderate density; crunchy tenacity; firm friable to moderate hard; blocky cuttings habit and break seen over PDC bit generated textures; dull luster with some sparkle from silts; matte to coarse matte texture; slight lineation of detritus only bedding indicator; one distinct thick translucent olive yellow calcareous volcanic ash layer at 3170' with moderate mineral fluorescence; no visible oil. Volcanic Ash (3170'-3210') = translucent pastel light yellowish gray to very pale orange; in planar contact with medium dark gray shale; low density; waxy when scored to very crumbly; very expansive on hydration; large PDC bit shaved wafers; blocky break; waxy luster with a hint of sparkles from minor disseminated sulfides; smooth texture; no associated shards; dull yellow mineral fluorescence; no oil indicators. Mudstone/Shale (3210'-3300') = medium to medium light gray overall with only color change due to local very pale orange volcanic ash layers; massive homogeneous appear and bedding with only slight lineation of crypto -carbonaceous debris in mudstone; moderate density; crunchy tenacity; firm friable; mix between wedgelike PDC platelets and blocky cuttings habit; also blocky break; dull luster with trace crypto sulfides in mudstone; silts in mudstone range from fine to medium in a shale matrix; massive bedding but with shale/ash contacts; slight overall calcareous reaction to HCL with non -calcareous areas being expansive; no visible oil. Volcanic Ash (3300'-3350') = different color on different ash layers with dominant translucent light yellowish gray/v pale orange then opaque pale orange, and translucent olive green; low density but indurated; trace disseminated crypto pyrite then crypto mica; blocky to PDC shaved cuttings habit; smooth texture; low dull yellow mineral fluorescence; no oil. NABORS ALASKA 21 DRILLING, INC. A -a -g E -Sy, LLC Horseshoe #1 Shale (3350'-3450') = medium to dark gray with slight brownish hues; gen massive appearance and bedding with only hint of lineation on contacts with volcanic ash; moderate density; crunchy tenacity; firm friable to moderate hard; blocky cuttings habit seen over dominant PDC bit shaved and stacked platelets; blocky break; dull luster; very matte texture lacking any grit from silts; increasing calcareous content with slow even reaction to HCL; local calcareous tuff/ash beds plus one very reactive pale orange marl; poor bedding indicators; trace mineral fluorescence only on ash; only a hint of carb material around 3390'; no visible oil indicators. Lithology (3350'-3480') = massive medium to dark gray shale with brownish gray hues with local pale orange and rare olive green very expansive ash beds; one non expansive pale orange very calcareous marl at 3425'; slight calcareous reaction to HCL in sand and some ash. Shale (3490'-3530') = dark brown to black brownish gray color; tough to dense tenacity; hackly to splintery fracture; platy to wedgelike with slight bladed edges cutting habits; dull to earthy luster when dry; granular to silty texture; thick bedding structure; no HCL reaction on shale; no hydrocarbon indictors. Shale (3540'-3585') = dark grayish brown to black brown with occasional black bands layers colors; tough to dense tenacity; hackly to splintery fracture; massive to tabular with occasional elongated and bladed edges cutting habits; silty to slight matte texture; massive to verythick bedding structure; no HCL reaction on shale; no hydrocarbon indictors. Tuffaceous Siltstone/Shale (3595'-3640') = light milky brown to creamy white gray with brownish hues colors; trace to 10% only; dense to crumbly tenacity; hackly fracture; small wedgelike cutting habits; silty to matte texture; very thin bedding structure with black and golden brown banded layers; very weak HCL reaction on tuff; no hydrocarbon indictors in bulk sample. Shale (3650'-3690') = black brown to dark brownish gray colors; tough to dense tenacity; blocky to hackly fracture; wedgelike with occasional massive elongated cutting habits; dull to earthy luster when dry; silty texture; massive bedding structure; no HCL reaction in bulk sample; no hydrocarbon indictors in entire sample. Shale (3720'-3760') = black brown to dark brownish gray with black banded layers colors; dense to tough tenacity; hackly to splintery fracture; wedgelike to occasional elongated cutting habits; dull to earthy when dry luster; matte to silty texture; massive bedding structure; no HCL reaction on shale; no hydrocarbon indictors. Siltstone (3770'-3830') = dark grayish black to brownish dark gray color; microcrystalline dark brown to dark gray with occasional clear to translucent minerals; very fine grain size; very well to well sorting; subangular angularity; very low to low sphericity; friable to firm friable hardness; overgrowth mineral matrix grain support; black carbonaceous materials in black layer interbedded; no HCL reaction in bulk sample; no hydrocarbon indictors. Shale (3840'-3890') = black brown to dark brownish gray colors; tough to dense tenacity; hackly to splintery fracture; tabular to wedgelike with occasional large elongated cutting habits; dull to earthy when dry and sparkling when wet luster; matte to silty texture; massive bedding structure with blackto dark banded layer; no HCL reaction in bulk sample; no oil indictors in bulk sample. 1�NABORS ALASKA 22 DRILLING, INC. A -a -g E -Sy, LLC Horseshoe #1 Tuffaceous Siltstone (3900'-3950') = grayish white to creamy white with yellowish white with brownish hue colors; brittle to tough tenacity; hackly to crunchy fracture; microcrystalline mineral framework with calcareous mineral with slightly moderated HCL reaction; veryfine grain size; very well sorted; overgrowth of calcareous cement; thin bedding structure; no hydrocarbon indictors. Tuffaceous Sandstone (3960'-4015') = milky white to creamy brownish white with pastel grayish layer, translucent to clear minerals colors; quartz with calcareous minerals with moderate HCL reaction, and black lithics in framework; very fine to fine grain size; well sorting; firm friable to moderate hard hardness; calcareous cement grain support; no cut oil visual; oil smell due to OBM mud in system; no oil indictor in sandstone. Shale (4025'-4080') = dark brown to dark brownish gray colors; tough to very hard tenacity; blocky splintery fracture; tabular to wedgelike with occasional platy cutting habits; dull to earthy luster when dry; matte to silty texture; massive bedding structure with traces of black banded layer interbedded; no HCL reaction on shale but moderate reaction on tuffaceous sandstone; no oil indicators. Lithology (4080'-4150') = discretely bedded brownish gray shale with olive gray hues; shale is in contact and interbedded with common medium pastel gray volcanic ash laced with silver marcasite encrusting sulfides plus disseminated pyrite crystals; gray ash has a sharp but gradational contact into shale also sparkling with sulfides near contact; shale at this point is laced with discrete discontinuous crypto carbonaceous flecks that delineate bedding; occasional sulfide seams in shale; gen loss of discrete bedding and carb material below 4150'; no visible oil indicators. Shale (4150'-4207') = more massive brownish gray shale but has discrete medium light bluish gray volcanic ash laced and disseminated into bedding; some associated with blue gray ash and minor flecks of carb material that delineates bedding; shale has moderate density; crunchy tenacity; moderate hard; blocky cuttings habit and break seen over PDC bit gen platelets; dull luster; matte texture; non calcareous; no oil indicators. NABORS ALASKA 23 DRILLING, INC. A-ao- g En -Sy, LLC Horseshoe #1 3.3.7 Nanushuk Top 4207' to 4384' MD (-3988' tn -4162' TVDSS) Top of Nanushuk was picked due to 195api gamma spike and 1.46ohmn resistivity dip (Per Wellsite Geologist) on the LWD logs. We correlated the gamma spike with a tuff/volcanic ash. The main features of the volcanic ash are micas disseminated throughout bedding. This marker is only 15'-20' long in measure depth. As the depth increases contacts and traces of siltstone appeared in samples with ash. Around 4220'MD a major change in lithology presented itself. Colors change from yellowish -bluish gray to a consistent medium gray. This medium gray sediment was identified as siltstone. Siltstone features traces of black carbonaceous materials and sparkling traces of sulfides. Also included in the Nanushuk top, are disseminated tuffaceous siltstone layers and silty shale. At the end of this formation, siltstone is dominant with 30% shale content. Tuff/Volcanic Ash (4207'-4220') = specular reflection of amber brown cryptomicas in a translucent light yellowish and bluish gray ash matrix; color shades vary on discrete bedding; micas are evenly disseminated but shows lineation over PDC bit smear; good trace yellow fracture material in sample with ash and shale; crumbly; friable; blocky; waxy luster; smooth texture; both gradational and with clear contact to shale; moderate dull yellow mineral fluorescence; note, trace calcareous fracture fill, good bright translucent yellow white cut fluorescence with faint visible cut; no visible stain or other indicators. Mudstone/Siltstone (4220'-4310') = medium to medium light gray with increased ash content; sample occasional stippled to laced with black carbonaceous material; slowly expansive on hydration; moderate to 1�NABORS ALASKA 24 DRILLING, INC. Drilling Parameters Rate of Penetration ft/hr Weight On Bit klbs Pump Pressurepsi) Max Min Average Min Max Average Min Max Average 148 35 84 11 4 10 3260 2730 64 Gas Summary Total Gas units Chromatography (ppm) Max Min Average Methane Ethane Propane Butane Pentane 58 18 35 Max 13042 489 190 24 0 Min Average 3623 44 7454 125 25 59 18 20 0 0 Top of Nanushuk was picked due to 195api gamma spike and 1.46ohmn resistivity dip (Per Wellsite Geologist) on the LWD logs. We correlated the gamma spike with a tuff/volcanic ash. The main features of the volcanic ash are micas disseminated throughout bedding. This marker is only 15'-20' long in measure depth. As the depth increases contacts and traces of siltstone appeared in samples with ash. Around 4220'MD a major change in lithology presented itself. Colors change from yellowish -bluish gray to a consistent medium gray. This medium gray sediment was identified as siltstone. Siltstone features traces of black carbonaceous materials and sparkling traces of sulfides. Also included in the Nanushuk top, are disseminated tuffaceous siltstone layers and silty shale. At the end of this formation, siltstone is dominant with 30% shale content. Tuff/Volcanic Ash (4207'-4220') = specular reflection of amber brown cryptomicas in a translucent light yellowish and bluish gray ash matrix; color shades vary on discrete bedding; micas are evenly disseminated but shows lineation over PDC bit smear; good trace yellow fracture material in sample with ash and shale; crumbly; friable; blocky; waxy luster; smooth texture; both gradational and with clear contact to shale; moderate dull yellow mineral fluorescence; note, trace calcareous fracture fill, good bright translucent yellow white cut fluorescence with faint visible cut; no visible stain or other indicators. Mudstone/Siltstone (4220'-4310') = medium to medium light gray with increased ash content; sample occasional stippled to laced with black carbonaceous material; slowly expansive on hydration; moderate to 1�NABORS ALASKA 24 DRILLING, INC. A -a -g E -Sy, LLC Horseshoe #1 low density; crumbly; persist blocky cuttings habit and break; dull luster with hint of sparkles from reflective detritus; matte to medium silty texture; vague lineation to contorted detritus; non calcareous; trace mineral fluorescence; no visible oil. Siltstone (4310'-4384') = medium light gray with random fine specks of black carb material and flecks of cryptomica; sample sparkles from disseminated sulfides; low density; crumbly; easily friable; blocky blunted cuttings and break; dull overall luster; silty texture; medium to occasional coarse silts with minor mudstone until 4370' with appearance of thick mudstone; detritus delineates vague planar bedding; non calcareous; no visible oil indicators. NABORS ALASKA 25 DRILLING, INC. A-ao- g En -Sy, LLC Horseshoe #1 3.3.8 Nanushuk 6 4384' to 4504' MD (-4162' to -4281' TVDSS) 2 mm k A., At At the start of Nanushuk #6, the formation change from siltstone dominant to 30% siltstone, 20% claystone, and 50% shale. A drastic change in lithology is one characteristic of Nanushuk #6. At the beginning depth, a small 10% sandstone enter formation with a spike in total gas to 28unit max. Throughout this formation shale and siltstone are dominant with detritus and interbedded contacts structures. Claystone is consistent with 20%-30% throughout formation. This formation section ends with a solid shale conformation on the LWD log. Also shale material increase to 80% in sample. Mudstone/Shale (4384'-4410') = medium gray with slight brownish to olive gray hues; very homogeneous appearance except for minor silt beds; moderate density; crunchy; friable; very blocky break and cuttings habit; dull luster; smooth matte texture; rare visible bedding; non calcareous but slowly expansive, more on silt; no visible oil indicators. Siltstone (4410'-4460') = medium light gray with light gray on rare very fine sandstone stringers; gen massive appearance but with faint alignment of detritus including some black carb material; mod -low density; crumbly; easily friable; blocky cuttings habit; dull luster; slow calcareous reaction to HCL to strong reaction on sandstone; no visible oil indicators. Shale/Mudstone = (4460'-4504') = medium dark gray with olive gray hues; mudstone with medium to rarely coarse silts content; shale is non calcareous but expansive; moderate density; firm friable; blocky; discrete lineation of detritus; non fluorescence sample; no visible oil. 1�NABORS ALASKA 26 DRILLING, INC. Drilling Parameters Rate of Penetration ft/hr Wei ht On Bit klbs Pum Pressure si Max Min Average Min I Max I Average Min Max Average 124 27 88 11 1 2 1 10 3269 2316 3024 Gas Summary Total Gas units Chromato rah ppm) Max Min Average Methane Ethane Propane Butane Pentane 28 4 15 Max 5985 444 190 22 3 Min Average 125 39 2754 72 6 30 3 2 1 1 2 mm k A., At At the start of Nanushuk #6, the formation change from siltstone dominant to 30% siltstone, 20% claystone, and 50% shale. A drastic change in lithology is one characteristic of Nanushuk #6. At the beginning depth, a small 10% sandstone enter formation with a spike in total gas to 28unit max. Throughout this formation shale and siltstone are dominant with detritus and interbedded contacts structures. Claystone is consistent with 20%-30% throughout formation. This formation section ends with a solid shale conformation on the LWD log. Also shale material increase to 80% in sample. Mudstone/Shale (4384'-4410') = medium gray with slight brownish to olive gray hues; very homogeneous appearance except for minor silt beds; moderate density; crunchy; friable; very blocky break and cuttings habit; dull luster; smooth matte texture; rare visible bedding; non calcareous but slowly expansive, more on silt; no visible oil indicators. Siltstone (4410'-4460') = medium light gray with light gray on rare very fine sandstone stringers; gen massive appearance but with faint alignment of detritus including some black carb material; mod -low density; crumbly; easily friable; blocky cuttings habit; dull luster; slow calcareous reaction to HCL to strong reaction on sandstone; no visible oil indicators. Shale/Mudstone = (4460'-4504') = medium dark gray with olive gray hues; mudstone with medium to rarely coarse silts content; shale is non calcareous but expansive; moderate density; firm friable; blocky; discrete lineation of detritus; non fluorescence sample; no visible oil. 1�NABORS ALASKA 26 DRILLING, INC. A -a -g E -Sy, LLC Horseshoe #1 3.3.9 Nanushuk 5 4504' to 4560' MD (-4281' to -4337' TVDSS) Nanushuk #5 is a small member in depth. It contains a pockets of sand and altered change from Nanushuk #6. This pocket of sand revealed hydrocarbon indictors. Related to the oil indictors were 70 units of total gas with C1-05 gases. Due to visible oil stain, this sandstone has porosity and permeability. Nanushuk #5 ends with an increase to shale at 90% and shale like LWD (106api gamma & 3.6ohmn resistivity). Oil Sandstone (4504'-4560') = medium light gray to light brownish gray from visible oil stain; silt sized clastics through very fine sand grains; very well sorted; angular to subangular; moderate sphericity; no visible grain surface features; dominant felsic framework but stippled with dark gray and green undefined detritus of accessory lithics; trace cryptomica, trace carb material; breaks around a point to long contact fabric; slight lineation of detritus; no calcareous reaction to HCL; interstices filled with clay minerals and fluid oil; good oil indicators with moderate iridescence sheen, dark brown interstitial stain; moderate yellow white sample fluorescence, streaming yellow white cut fluorescence, dark straw visible cut, straw residual ring cut, strong yellow orange residual fluorescence. NABORSALASKA 27 1 DRILLING, INC. Drilling Parameters Rate of Penetration ft/hr Wei ht On Bit klbs Pump Pressure(psi) Max Min Average Min Max Average Min Max Average 105 40 93 9 0 9 2431 2342 2426 Gas Summary Total Gas units Chromato rah (ppm) Max Min Average Methane Ethane Propane Butane Pentane 70 12 36 Max 14087 452 70 43 14 Min 2332 46 Average 7418 220 0 38 0 19 0 7 Nanushuk #5 is a small member in depth. It contains a pockets of sand and altered change from Nanushuk #6. This pocket of sand revealed hydrocarbon indictors. Related to the oil indictors were 70 units of total gas with C1-05 gases. Due to visible oil stain, this sandstone has porosity and permeability. Nanushuk #5 ends with an increase to shale at 90% and shale like LWD (106api gamma & 3.6ohmn resistivity). Oil Sandstone (4504'-4560') = medium light gray to light brownish gray from visible oil stain; silt sized clastics through very fine sand grains; very well sorted; angular to subangular; moderate sphericity; no visible grain surface features; dominant felsic framework but stippled with dark gray and green undefined detritus of accessory lithics; trace cryptomica, trace carb material; breaks around a point to long contact fabric; slight lineation of detritus; no calcareous reaction to HCL; interstices filled with clay minerals and fluid oil; good oil indicators with moderate iridescence sheen, dark brown interstitial stain; moderate yellow white sample fluorescence, streaming yellow white cut fluorescence, dark straw visible cut, straw residual ring cut, strong yellow orange residual fluorescence. NABORSALASKA 27 1 DRILLING, INC. A -a -g E -Sy, LLC Horseshoe #1 3.3.10 Nanushuk 4 4560' to 4704' MD (-4337' to -4481' TVDSS) Nanushuk #4 is dominantly shale to silty shale. The formation background gases are staying a constant 11-13 units of gas. As depth increases, the shales become harder to fracture. This section is a general massive bed of shale and cap for the oil sands in the next formation. Silty Shale (4560'-4650') = medium gray with slight brownish hues; darker as true shale; massive to more bedded appearance with trace very discrete lineations; moderate density; crunchy tenacity; friable to hard; blocky cuttings habit; dull luster; matte texture to silty; non calcareous but slightly expansive; only visible bedding seen in siltstone; no visible oil indicators. Shale (4650'-4704') = medium dark brownish gray; gen massive appearance; moderate density; crunchy; blocky break and cuttings habit seen over PDC platelets; dull luster; smooth to matte texture with disseminated medium silts in matrix; firm friable to moderate hard; no visible bedding seen over PDC bit smear; non calcareous; slightly expansive; no visible oil indicators. NABORSALASKA 28 1 DRILLING, INC. Drilling Parameters Rate of Penetration ft/hr Wei ht On Bit klbs Pum Pressure si Max Min Average Min I Max I Average Min Max Average 102 26 69 9 1 1 1 7 3079 2029 2801 Gas Summary Total Gas units Chromato rah ppm) Max Min Average Methane Ethane Propane Butane Pentane 30 1 13 Max 6430 138 40 18 2 Min 391 5 Average 2727 60 0 14 0 6 0 1 Nanushuk #4 is dominantly shale to silty shale. The formation background gases are staying a constant 11-13 units of gas. As depth increases, the shales become harder to fracture. This section is a general massive bed of shale and cap for the oil sands in the next formation. Silty Shale (4560'-4650') = medium gray with slight brownish hues; darker as true shale; massive to more bedded appearance with trace very discrete lineations; moderate density; crunchy tenacity; friable to hard; blocky cuttings habit; dull luster; matte texture to silty; non calcareous but slightly expansive; only visible bedding seen in siltstone; no visible oil indicators. Shale (4650'-4704') = medium dark brownish gray; gen massive appearance; moderate density; crunchy; blocky break and cuttings habit seen over PDC platelets; dull luster; smooth to matte texture with disseminated medium silts in matrix; firm friable to moderate hard; no visible bedding seen over PDC bit smear; non calcareous; slightly expansive; no visible oil indicators. NABORSALASKA 28 1 DRILLING, INC. A -a -g E -Sy, LLC Horseshoe #1 3.3.11 Nanushuk 3 4704' to 5252' MD (-4481' to -5030' TVDSS) Nanushuk 3 distal deltaic sandstone package and its interbedded to underlying siltstone, mudstone, and shale members lie directly below a thick, brownish gray, dense terminus shale of the Nanushuk 4. The Nanushuk 3 sandstone is topped by an undefined yellow carbonate at 4705' then changes rapidly to oil stained sandstone by 4710'. This sandstone is rich in lightly pyritized carbonaceous debris laced and laminated into a dominant very fine to fine grained felsic (quartz/feldspar) framework. Brittle amber, black, and rare pliable red carbonaceous material continues in sandstone body until shale is the dominant rock NABORSALASKA 29 i� 1 DRILLING, INC. Drilling Parameters Rate of Penetration ft/hr Wei ht On Bit klbs Pump Pressure(psi) Max Min Average Min Max Average Min Max Average 156 8.4 74 13 2 8 3312 j 556 2528 Gas Summary Total Gas units Chromato rah (ppm) Max Min Average Methane Ethane Propane Butane Pentane 73 2 20 Max 27606 1633 1117 1966 1996 Min Average 236 19 4233 125 6 48 0 25 0 15 Nanushuk 3 distal deltaic sandstone package and its interbedded to underlying siltstone, mudstone, and shale members lie directly below a thick, brownish gray, dense terminus shale of the Nanushuk 4. The Nanushuk 3 sandstone is topped by an undefined yellow carbonate at 4705' then changes rapidly to oil stained sandstone by 4710'. This sandstone is rich in lightly pyritized carbonaceous debris laced and laminated into a dominant very fine to fine grained felsic (quartz/feldspar) framework. Brittle amber, black, and rare pliable red carbonaceous material continues in sandstone body until shale is the dominant rock NABORSALASKA 29 i� 1 DRILLING, INC. A-ao- g En -Sy, LLC Horseshoe #1 type by 4810'. Oil indicators and saturation throughout the sandstone body are very good but decrease with depth primarily due to increased mudstone content. Sandstone layers are discretely interbedded and gradational with finer clastics to where sand floating in siltstone and mudstone are common then become dominant near the base of sandstone unit. Partial mudstone/shale clasts in sandstone to soft sedimentary deformation structures seen in larger cuttings. Changes in sandstone gain fabric, cement, matrix, authigenic pore filling, dissolution of proto cement, and pore enlargement determine oil saturation. The heaviest oil saturation was seen in grain packed layers showing a point to long contact fabric, weaker clay mineral to siliceous cement, minor clay mineral occluded pores, and dissolution of proto cement leaving both a diagenetic frost on grain free margins and abundant subhedral quartz overgrowths on quartz grains seen reflecting back light from sandstone interstices/pores. Strongest oil indicators and saturation appear to be within the first 50' to 100' where a heavy amber brown stain and mobile viscous oil fills interstices and coats all sand grains. Fresh breaks on the best quality sandstone cuttings with highest visible porosity appear to show dry oil stain but left to sit for hours become coated with fluid translucent to opaque amber brown oil. Decrease in oil saturation comes with a tightly packed fabric, increased authigenic clay mineral pore filling, stronger siliceous cement and eventual change to mudstone matrix. Intercalated to gradational mudstone with sands show some weak oil indicators with greatly reduces sample fluorescence, staining, and solvent cut. No oil indicators or saturation is seen on local tightly packed light gray siltstone/tuffaceous mudstone layers (possible indurated ash beds) in contact with heavily stained porous sandstone due to decreased grain size to silt or less, strong non calcareous cement and expansive smectitic clay mineral filled siltstone interstices. Oil Sandstone (4704'-4750') = begins with light gray calcareous cement sandy siltstone and local pale yellowish orange carbonate, changes rapidly to medium dark gray to brownish gray from both moderate to heavy oil stain and brown argillaceous content; sample stippled by and laced with black to amber and rare red carbonaceous material; dominant framework is felsic (quartz/feldspar) with scattered multicolored clasts of gray, green, and red; very fine to fine with dominant fine; very well to well sorted; angular to subround with dominant angular to subangular; moderate to low sphericity; only visible grain surface feature is solution to diagenetic dissolution frost plus subhedral quartz overgrowth on quartz grain free margins; clay mineral cement to argillaceous matrix; breaks around a point to long fabric plus sands floating in siltstone and shale; common scattered interstitial pale yellow lime clasts and possible abundant translucent light yellow volcanic ash at 4750' start of coring; rare visible accessory minerals; very minor interstitial calcareous; good visible planar -contorted bedding seen by aligned detritus; increased argillaceous matrix and interbedded shale with depth; strong initial oil shows with gray purple iridescence sheen, amber/brown oil stain yielding 60% yellow orange sample fluorescence; fast yellow white cut fluorescence with streamers; amber to straw visible cut with translucent light straw residual cut and bright yellow orange residual cut fluorescence; oil indicators decrease with increasing shale. Sandstone (4845'-4930') = medium gray to light brownish gray with light bluish gray hues, and trace creamy white colors; translucent to clear quartz and feldspar dominant with black lithics and traces of white tuffaceous claystone; fine to very fine grain size; well sort; grains; subangular to angular; low sphericity; friable to firm friable; argillaceous matrix and cement; dominant grain support; sandstone decrease in sample as depth increases; yellowish green visible fluorescence; no staining; no visible cut color; pale bluish white fluorescent cut color; no streamer; faint yellowish white fluorescent residual color; no residual color. 1�NABORS ALASKA 30 DRILLING, INC. A -a -g E -Sy, LLC Horseshoe #1 Silty Shale (4931'-5000') = medium dark gray with slight brownish hues; sample is lightly stippled with black from disseminated carb material plus bronze disseminated to framboidal pyrite; sample occasional lightens to light gray on medium to coarse siltstone layers in contact with shale; moderate to high density; crunchy tenacity; blocky overall cuttings habit and break seen over PDC bit gen platelets; dull luster with sparkles from disseminated pyrite; slight to good bedding indicators seen as aligned detritus showing hint of planarto contorted bedding; predominant non calcareous to pinpoint but with one carbonate layer at 4965'; disseminated pyrite also seen as either coating a bedding surface or as a seem in shale; moderate expansive; no visible oil indicators. Siltstone/Mudstone (5000'-5100') = medium gray to medium light gray with increased silt content dominant medium to coarse silts occasional as mudstone in a heavy clay/shale matrix; moderate density; very crunchy to occasional crumbly tenacity; friable to moderate hard based on composition with mudstone/shale being hard and siltstone being friable; blocky break and cuttings habit seen over PDC bit gen textures; very dull luster except for local reflection off of disseminated sulfides; smooth matte to siltytexture; predominant non calcareous except for scattered light yellowish gray to very pale orange carbonate layers to possible fracture fill; sample is slightly reactive to expansive; trace discrete bedding seen as aligned fine. Lithology (5000'-5200') = variation of gray between medium dark gray with slightly brown hues on shale to medium gray with mudstone, and medium light to light gray on siltstone; mudstone and siltstone with trace to common black crypto -micro flecks of carbonaceous material increasing with grain size and scattered disseminated sulfides; increasing common light yellowish gray calcareous fracture fill; all lithologytypes are gradational, generally stratified, to just massive in appearance; non calcareous but slight expansive; lime as discrete layers with gradational contacts to apparent fracture fill; no visible oil. Shale (5195'-5255') = dark brown to slight dark grayish brown color with black and white thin layer colors; tough to dense tenacity; splintery to hackly fracture; tabular to wedgelike cutting habits; dull to earthy with slight waxy luster; matte to abrasive texture; black carbonaceous and white clay material interbedded in structure; no fluorescence cut in bulk sample; no hydrocarbon cut colors; no hydrocarbon indictors in bulk sample. NABORS ALASKA 31 DRILLING, INC. A -a -g E -Sy, LLC Horseshoe #1 3.3.12 Nanushuk 2 5252' to 5775' MD (-5030' to -5553' TVDSS) Nanushuk #2 formation began as shale increased in grain size to siltstone and sandstone but both are matrix rich. With this sandstone, there was not high gases, LWD major change, and no oil staining. The LWD readings stay consistent to siltstone/silty shale values. The formation became harder and more argillaceous with depth. Around 5575'MD, tuff/tuffaceous material entered as thin layer. 30% black carbonaceous material was seen in shale as contacts and interbedding. The rest of Nanushuk #2, became harder as 90% to 100% shale dominated the samples. Sandstone (5275'-5340) = light grayish to light grayish brown with clear and translucent minerals, trace black and black grayish colors; quartz & feldspar with black lithics framework; very fine to fine grain size; well sorted; subangular angularity; low sphericity; consolidated sands with friable to firm friable hardness; argillaceous cement with slight creamy white colors; traces of siltstone contact with sandstone; thin bedding structure; traces of pyrite in bulk sample; no cut colors; patchy bright yellowish white fluorescence color; no streamers; faint white fluorescence cut color; no other oil indictors. Shale (5350'-5410') = dark brown to black brown colors; dense to tough tenacity; blockyto splintery fracture; tabular to wedgelike with occasional bladed edges cutting habits; dull to earthy when dry luster; matte to abrasive texture; very thin interbedded black carbonaceous minerals and traces of white tuff bedded in structure; occasional wavy to curved lamination structure; PDC bit carving on some shale surfaces; no HCL reaction on shale; no hydrocarbon indictors. NABORSALASKA 32 DRILLING, INC. Drilling Parameters Rate of Penetration ft/hr Wei ht On Bit klbs Pum Pressure si Max Min Average Min Max Average Min Max Average 167 27 97 11 4 10 3531 3127 3339 Gas Summary Total Gas units Chromato rah ppm) Max Min Average Methane Ethane Propane Butane Pentane 23 8 17 Max 4982 67 49 19 14 Min Average 1211 20 3445 49 10 23 0 1 0 .5 Nanushuk #2 formation began as shale increased in grain size to siltstone and sandstone but both are matrix rich. With this sandstone, there was not high gases, LWD major change, and no oil staining. The LWD readings stay consistent to siltstone/silty shale values. The formation became harder and more argillaceous with depth. Around 5575'MD, tuff/tuffaceous material entered as thin layer. 30% black carbonaceous material was seen in shale as contacts and interbedding. The rest of Nanushuk #2, became harder as 90% to 100% shale dominated the samples. Sandstone (5275'-5340) = light grayish to light grayish brown with clear and translucent minerals, trace black and black grayish colors; quartz & feldspar with black lithics framework; very fine to fine grain size; well sorted; subangular angularity; low sphericity; consolidated sands with friable to firm friable hardness; argillaceous cement with slight creamy white colors; traces of siltstone contact with sandstone; thin bedding structure; traces of pyrite in bulk sample; no cut colors; patchy bright yellowish white fluorescence color; no streamers; faint white fluorescence cut color; no other oil indictors. Shale (5350'-5410') = dark brown to black brown colors; dense to tough tenacity; blockyto splintery fracture; tabular to wedgelike with occasional bladed edges cutting habits; dull to earthy when dry luster; matte to abrasive texture; very thin interbedded black carbonaceous minerals and traces of white tuff bedded in structure; occasional wavy to curved lamination structure; PDC bit carving on some shale surfaces; no HCL reaction on shale; no hydrocarbon indictors. NABORSALASKA 32 DRILLING, INC. A -a -g E -Sy, LLC Horseshoe #1 Shale (5420'-5485') = dark brown to black brown colors; dense to tough tenacity; hackly to splintery with blocky fracture; tabular to wedgelike cutting habits; dull to earthy when dry and slight frosted micro crystalline texture; massive bedding structure with very thin interbedded layer; no HCL reaction on shale; oil odor discredited due to OBM in mud system; no hydrocarbon indictors. Shale (5485'-5530') = tough to dense tenacity; moderate hard to very hard induration; tabular to wedgelike with bladed features cutting habits; blocky to splintery fracture; dull to earthy and slight sparkling when wet luster; silty to matte and granular texture; massive structure bedding; no HCL reaction in bulk sample; no oil staining; no fluorescence cut in bulk sample; no hydrocarbon indictors. Tuffaceous Siltstone (5540'-5605') = tan to light grayish brown with slight white hue colors; stiff to crumbly tenacity; slight hackly to earthy fracture; elongated with occasional nodular; dull to slight waxy when dry luster; silty to smooth texture; thin bedding with lamination on firm tuffaceous siltstone; traces of reddish orange tuff, pyrite, and carbonaceous material are in the bulk sample; no oil staining; no fluorescence cut on sandstone; no cut color on sandstone; no hydrocarbon indictor in bulk sample. Shale (5615'-5675') = dark brown to slight dark grayish brown colors; tough to dense tenacity; hackly to splintery with blocky fracture; wedgelike to tabular cutting habits, and also can see PDC bit indentation on some shale fragments; dull to slight waxy luster; matte to silty and abrasive texture; massive bedding structure with black carbonaceous layers; trace pyrite mineral and tuff; no HCL reaction in bulk sample; no hydrocarbon indictors in bulk sample. Sandstone (5705'-5775') = brownish gray to light medium gray with slight bluish gray hues, white and brown banded layers color; quartz and feldspar with black lithics framework; very fine to lowerfine grain sizes; well sorted; subangular to subrounded minerals; low to slight moderate sphericity; consolidated sands with firm friable to friable hardness; argillaceous and dolomitic cement with weak to slight moderate HCL reaction in sandstone; several contact fabric with silty shale; thin contact bedding structure; very fainted white fluorescence cut color; no streamers; no visual cut color; no hydrocarbon indictors in sample. NABORS ALASKA 33 DRILLING, INC. A -a -g E -Sy, LLC Horseshoe #1 3.3.13 Nanushuk 1 5775' to 6000' MD (-5553' to -5778' TVDSS) Nanushuk #1 continue with above formation shale ended. All samples, LWD logs data, and gas unit were consistent with shale/siltstone properties. The best feature of Nanushuk #1 is the toughness and extreme dense shale fragments. Silty Shale (5775'-5870') = dark brown to dark grayish brown with black thin layers colors; dense to tough tenacity; blocky to splintery fracture; wedgelike to tabular cutting habits; dull to slight frosted due to diagenesis of siltstone to shale; abrasive to matte and granular texture; massive structure with carbonaceous and clayey interbedded moderate HCL reaction with crushed shale; oil odor discredited due to OBM mud; slight bright white fluorescence cut; no streamers; no visual cut colors; no other hydrocarbon indictor in bulk sample. Shale (5880'-5940') = grayish brown to dark brown colors; very tough to dense tenacity; splintery to blocky fracture; tabular to wedgelike with occasional bladed edges cutting habits; dull to earthy when dry and slight waxy when wet luster; abrasive to matte with slight silty texture; massive structure with clayey and carbonaceous interbedded; no HCL reaction on shale until crushed or fractured, reaction is weak; no hydrocarbon reaction in bulk sample. Shale (5941'-6000') = dark brownish gray to dark brown colors; very tough to dense tenacity; splintery to blocky fracture; tabular to wedgelike with occasional bladed edges cutting habits; dull to earthy when dry 1�NABORS ALASKA 34 DRILLING, INC. Drilling Parameters Rate of Penetration ft/hr Wei ht On Bit klbs Pum Pressure si Max Min Average Min I Max I Average Min Max Average 163 23 103 11 1 2 1 10 3583 1705 3460 Gas Summary Total Gas units Chromato rah ppm) Max Min Average Methane Ethane Propane Butane Pentane 23 10 16 Max 4924 69 50 11 2 Min Average 1005 26 3126 46 8 25 0 2 0 .5 Nanushuk #1 continue with above formation shale ended. All samples, LWD logs data, and gas unit were consistent with shale/siltstone properties. The best feature of Nanushuk #1 is the toughness and extreme dense shale fragments. Silty Shale (5775'-5870') = dark brown to dark grayish brown with black thin layers colors; dense to tough tenacity; blocky to splintery fracture; wedgelike to tabular cutting habits; dull to slight frosted due to diagenesis of siltstone to shale; abrasive to matte and granular texture; massive structure with carbonaceous and clayey interbedded moderate HCL reaction with crushed shale; oil odor discredited due to OBM mud; slight bright white fluorescence cut; no streamers; no visual cut colors; no other hydrocarbon indictor in bulk sample. Shale (5880'-5940') = grayish brown to dark brown colors; very tough to dense tenacity; splintery to blocky fracture; tabular to wedgelike with occasional bladed edges cutting habits; dull to earthy when dry and slight waxy when wet luster; abrasive to matte with slight silty texture; massive structure with clayey and carbonaceous interbedded; no HCL reaction on shale until crushed or fractured, reaction is weak; no hydrocarbon reaction in bulk sample. Shale (5941'-6000') = dark brownish gray to dark brown colors; very tough to dense tenacity; splintery to blocky fracture; tabular to wedgelike with occasional bladed edges cutting habits; dull to earthy when dry 1�NABORS ALASKA 34 DRILLING, INC. A -a -g E -Sy, LLC Horseshoe #1 and slight waxy when wet luster; abrasive to matte with slight silty texture; massive bedding slight lamination; no to slow calcareous reaction is weak; no hydrocarbon reaction in bulk sample. NABORS ALASKA 35 DRILLING, INC. A -i -.g E.-gy, LLC Horseshoe #1 3.4 Connection Gases 1 % Methane Equivalent = 50 Units Depth Gas over BGG Depth Gas over BGG 1226 12 2260 5 1290 18 2420 0 1353 24 2550 2 1415 33 5038 2 1478 15 5100 4 1540 10 5162 6 1846 1 5222 7 1972 1 5223 0 2260 5 5410 1 3.5 Trip (Wiper) Gases 1% Methane Equivalent = 50 Units Depth Trip to Gas Downtime feet feet units hours 6000' 4663' 13 3 NABORSALASKA 36 1 DRILLING, INC. A -a -g E -Sy, LLC Horseshoe #1 3.6 Sampling Program / Sample Dispatch Set Type / Purpose Frequency Interval Dispatched to 1 Washed, screened & dried 30' 15' 120'— 4710'Armstrong 4710'— 4740' Oil and Gas, Inc. (A) Reference Samples 10' 4740'— 4930'1421 Blake Street 30' 4930'— 6000' Denver, CO 80202 30' 120'— 4710' REPSOL 2 Washed, screened & dried 15' 4710'— 4740' 2455 Technology Forest Boulevard (B) Reference Samples 10' 4740'— 4930' Building 5 30' 4930'— 6000' The Woodlands, TX 77381 30' 120'— 4710' AOGCC 3 Washed, screened & dried 15' 4710'— 4740' Attn: Howard Okland (C) Reference Samples 10' 4740'— 4930' 333 W. 7th Ave., Suite 100 30' 4930'— 6000' Anchorage, Alaska 99501-3539 4 LVT washed, Paleo 30' 30' 120'— 1740' 1740' — 3210' Armstrong Oil and Gas, Inc. (Box) Samples 30' 3210'— 4750' 1421 Blake Street 10'-15'-30' 4750'— 6000' Denver, CO 80202 5 LVT washed, Paleo 30' 30' 120'— 1740' 1740' — 3210' Armstrong Oil and Gas, Inc. (Box) Samples 30' 3210'— 4750' 1421 Blake Street 10'-15'-30' 4750'— 6000' Denver, CO 80202 Sample frequency was locally altered according to drill rate constraints and zones of interest. NABORS ALASKA 37 DRILLING, INC. A -L -g Energy, LLC Horseshoe #1 Drilling Data 4.1 Survey Data Measured Depth (ft) Incl. o () Azim. o () True Vertical Depth (ft) (ft) N(+), S(-) (ft) E(+), W(-) Vertical Section (ft) Dogleg Rate (.1100ft) 0 0 0 0 0 0 I 0 0 212.97 0.77 355.03 212.96 1.3 -0.11 0.86 0.4000 293.96 3.05 3.76 293.9 3.99 -0.02 2.85 2.8300 355.96 3.07 4.64 355.82 7.29 0.22 I 5.39 0.0800 422.92 3.39 6.14 422.67 11.04 0.58 I 8.34 0.5000 476.96 3.52 8.47 476.61 14.28 1 I 10.95 0.3600 538.88 3.67 9.22 538.41 18.12 1.59 I 14.13 0.2600 600.93 3.48 9.58 600.34 21.94 2.23 I 17.31 0.3200 663.2 3.57 12.05 662.49 25.7 2.95 20.51 0.2900 725.37 3.57 11.13 724.54 29.49 3.72 23.78 0.0900 788.7 4.03 10.9 787.73 33.62 4.53 27.3 0.7200 850.49 4.46 10.97 849.35 38.11 5.39 31.13 0.6900 912.1 4.39 9.92 910.78 42.78 6.26 35.09 0.1700 975.28 4.9 6.44 973.75 47.85 6.98 39.23 0.9200 1038 6.19 359.25 1036.18 53.9 7.23 43.75 2.3300 1099.04 6.76 357.14 1096.82 60.78 7.01 48.54 1.0100 1161.96 7.3 357.22 1159.27 68.47 6.63 53.81 0.8500 1225.2 7.74 357.44 1221.97 76.73 6.25 59.48 0.7100 1287.08 8.09 357.34 1283.26 85.24 5.86 65.32 0.5600 1350.34 8.57 357.21 1345.85 94.4 5.42 71.6 0.7600 1413.08 8.73 357.31 1407.88 103.82 4.97 78.05 0.2500 1470.59 9.62 356.3 1464.65 112.97 4.46 84.27 1.5700 1534.79 10.3 355.35 1527.89 124.05 3.64 91.66 1.1000 1598.68 10.93 356.39 1590.68 135.79 2.8 99.51 1.0200 1659.77 12.36 357.41 1650.51 148.1 2.14 107.9 2.3700 `� NABORS ALASKA 38 DRILLING, INC. A -L -g Energy, LLC Horseshoe #1 Measured Depth (ft) Incl. Azim. (o) (o) True (ft) (ft) Vertical Dogleg Vertical N(+) S(-) E(+) W(_) Section -Rate Depth (ft) (ft) (/100ft) 1721.74 13.12 357.64 1710.95 161.76 1.55 117.3 1.2300 1784.9 13.03 357.71 1772.48 176.03 0.97 127.15 0.1600 1845.96 13.48 357.08 1831.91 190.02 0.33 136.76 0.7800 1905.96 15.5 356.48 1890 205.01 -0.52 146.94 3.3800 1968.91 16.4 357.98 1950.52 222.29 -1.35 158.78 1.5700 2027.12 16.14 357.62 2006.4 238.59 -1.97 170.05 0.4800 2089.21 16.26 357.67 2066.02 255.9 -2.68 181.99 0.1900 2152.79 16.25 358.06 2127.06 273.68 -3.35 194.31 0.1700 2164.33 16.15 358.32 2138.15 276.9 -3.45 196.55 1.0400 2263.77 15.85 358.74 2233.73 304.3 -4.15 215.75 0.3300 2326.24 15.49 1 2293.88 321.17 -4.2 227.84 1.1300 2389.13 14.63 4.72 2354.61 337.48 -3.4 240.11 2.0600 2450.45 14.74 6.62 2413.93 352.94 -1.86 252.29 0.8100 2513.26 15.15 8.51 2474.62 368.99 0.28 265.31 1.0100 2575.77 15.6 15.53 2534.9 385.17 3.74 279.34 3.0600 2638.81 15.99 26.28 2595.57 401.13 9.85 295.06 4.6800 2700.29 17.21 36.18 2654.5 416.07 18.97 312.14 5.0000 2761.81 18.07 45.18 2713.13 430.14 31.11 330.69 4.6400 2824.5 18.58 51.64 2772.65 443.2 45.84 350.32 3.3400 2887.14 19.57 57.83 2831.86 454.98 62.55 370.4 3.6000 2949.01 20.92 62.63 2889.91 465.58 81.13 390.94 3.4600 3011.26 22.48 65.61 2947.74 475.6 101.85 412.55 3.0700 3073.84 23.9 68.24 3005.27 485.24 124.52 435.25 2.8100 3136.62 25.42 70.37 3062.32 494.49 149.03 458.94 2.8100 3199.44 27.61 72.21 3118.53 503.46 175.59 483.86 3.7100 3261.54 28.85 72.4 3173.24 512.39 203.57 509.74 2.0000 3323.6 29.08 73.36 3227.54 521.23 232.29 536.07 0.8400 3386.34 29.06 72.76 3282.38 530.11 261.45 562.73 0.4700 3448.23 29.13 73.03 3336.46 538.96 290.22 589.09 0.2500 `� NABOR5 ALASKA 39 DRILLING, INC. A -L -g Energy, LLC Horseshoe #1 Measured Depth (ft) Incl. Azim. (o) (o) True (ft) (ft) Vertical Dogleg Vertical N(+) S(-) E(+) W(_) Section -Rate Depth (ft) (ft) (/100ft) 3510.46 28.97 72.7 3390.86 547.86 319.09 615.57 0.3700 3572.39 29.13 72.75 3445 556.79 347.8 641.96 0.2600 3634.43 28.67 72.27 3499.32 565.8 376.39 668.32 0.8300 3695.92 27.46 71.96 3553.58 574.69 403.93 693.85 1.9800 3757.77 26.47 72.19 3608.7 583.32 430.61 718.61 1.6200 3820.72 25.4 72.2 3665.32 591.74 456.82 742.89 1.7000 3883.19 23.7 72.95 3722.14 599.51 481.58 765.7 2.7600 3944.73 21.53 73.11 3778.94 606.42 504.21 786.4 3.5300 4007.35 19.36 73.24 3837.61 612.75 525.14 805.51 3.4600 4068.56 16.84 73.07 3895.79 618.26 543.35 822.13 4.1200 4130.52 14.3 73.01 3955.47 623.11 559.26 836.68 4.1000 4193.43 12.23 72.55 4016.7 627.38 573.05 849.35 3.3000 4255.8 10.88 72.49 4077.8 631.13 584.97 860.33 2.1800 4317.31 9.73 73.27 4138.32 634.38 595.48 869.97 1.8900 4379.06 8.4 74.57 4199.3 637.08 604.82 878.41 2.1700 4441.9 6.27 76.51 4261.62 639.1 612.58 885.26 3.4100 4501.99 3.41 79.45 4321.49 640.19 617.54 889.49 4.7800 4563.99 0.58 87.92 4383.44 640.54 619.66 891.22 4.5700 4627.06 0.13 209.58 4446.51 640.49 619.95 891.39 1.0500 4688.66 0.04 188.99 4508.11 640.41 619.91 891.3 0.1500 4760.16 0.03 226.08 4579.61 640.37 619.89 891.26 0.0400 4820.91 0.07 243.38 4640.36 640.34 619.85 891.21 0.0700 4884.23 0.07 191.31 4703.68 640.29 619.81 891.14 0.1000 4945.24 0.04 259.94 4764.69 640.25 619.78 891.09 0.1100 5007.53 0.11 243.45 4826.98 640.22 619.7 891.01 0.1100 5068.23 0.09 245.45 4887.68 640.17 619.6 890.91 0.0300 5129.88 0.31 273.33 4949.33 640.16 619.39 890.76 0.3700 5191.73 0.34 271.78 5011.18 640.17 619.04 890.53 0.0500 5254.98 0.28 260.86 5074.43 640.16 618.71 890.28 0.1400 `� NABOR5 ALASKA 40 DRILLING, INC. A -L -g Energy, LLC Horseshoe #1 Measured Depth (ft) Incl. Azim. (p) (p) True (ft) (ft) Vertical Dogleg Vertical N(+), S(-) E(+), W(-) Section oRate Depth (ft) (ft) (/100ft) 5316.78 0.22 248.97 5136.23 640.09 618.45 890.05 0.1200 5378.41 0.3 236.55 5197.86 639.96 618.2 889.79 0.1600 5441.13 0.38 200.02 5260.58 639.67 617.99 889.43 0.3600 5503.66 0.39 209.31 5323.11 639.29 617.82 889.04 0.1000 5566.26 0.26 223.26 5385.7 639 617.61 888.69 0.2500 5627.48 0.26 205.71 5446.92 638.77 617.46 888.41 0.1300 5688.69 0.21 212.26 5508.13 638.55 617.34 888.17 0.1000 5751.78 0.11 214.7 5571.22 638.4 617.24 888 0.1500 5815.24 0.1 227.71 5634.68 638.32 617.17 887.89 0.0400 5875.88 0.1 251.93 5695.32 638.27 617.08 887.79 0.0700 5940.37 0.18 262.16 5759.81 638.24 616.93 887.66 0.1300 5971.89 0.26 259.35 5791.33 638.22 616.81 887.56 0.2700 6000.00 0.26 259.35 5819.44 638.19 616.68 887.46 0.0000 `� NABORSALASKA 41 DRILLING, INC. A -t -g E -Sy, LLC Horseshoe #1 4.2 Bit Record 1�NABORS ALASKA 42 DRILLING, INC. Depth In Total Bit Avg. WOB PP Bit Size Make Type / S# Jets / TFA ROP RPM Wear BHA MD/ Footage Hrs. (Klbs) (psi) (ft/hr) VMD- 1x16, 3x8 1 12.25" HCC 3HCC 0.942 118' 2231' 23.3 135.7 23.7 57.4 1759 1,1,NO,A,3,1,NO,TD 1 5259382 2 8.5 Reed Hycalog 191314 7x12 2230' 2520' 11.6 101.0 7.3 86.3 2786 2,1,CT,M,X,I,BT,TD 2 SKH519M-C1 0.7731 C131 8.50 " Halliburton 12614632 - 4750' 181' 5.2 49.2 5.4 50.3 1208 - 2 3 FC3555 4 8.50 " Reed Hycalog A191313 7x12 4931' 1069' 11.6 95.4 10.1 99.2 3319 2,1,CT,M,X,I,BT,TD 4 SKH519M-C1 0.7731 1�NABORS ALASKA 42 DRILLING, INC. A -t -g En -Sy, LLC Horseshoe #1 4.3 Mud Record Contractor: Halliburton / Baroid Mud Type: Spud Mud to 2231' Date Flow Depth Temp MW (ppg) VIS (S/qtr.) PV YP Gels FL (cc) FC Sols N O/W Ratio SD (%) pH CI (ml/1) Ca (ml/1) 1/28/17 541' - 10.1 194 51 53 24/38/49 4.9 2 7.6 0.2/92 0 10 300 40 1/29/17 1900' - 10.3 135 30 54 22/42/55 4.6 2 8.8 0.5/90.5 1 9.9 300 40 1/30/17 2231' - 10.2 94 36 37 22/35/44 4.9 2 8.8 0.5/90.5 0.25 9.8 400 40 1/31/17 2231' - 10.4 230 38 45 21/39/51 5.3 2 9.3 0.5/90 0.25 9.5 400 40 2/1/17 2231' - 10.2 55 28 17 6/8/9 5.8 2 8.8 0.5/90.5 0.15 8.1 300 40 2/2/17 2231' - 10.0 61 32 21 7/10/12 6.0 2 7.5 0.5/91.8 0.25 9.3 300 360 2/3/17 2231' - 10.0 62 32 20 7/10/12 6.0 2 7.5 0.5/91.8 0.25 9.3 300 360 2/4/17 2231' - 10.0 61 32 20 7/10/12 6.0 2 7.5 0.5/91.8 0.15 8.2 300 360 Mud Type: Oil Base Mud to 6000' Date Depth Flow Temp MW (ppg) VIS (S/qtr.) PV YP Gels FL (cc) FC Sols % O/W Ratio SD (%) ASG CaCl2 b Estab v 2/5/17 2251' 83 10.4 93 33 17 9/13/25 4.6 0/3 11.2 75.9/24.6 0.1 3.84 26.07 597 2/6/17 3627' 105 10.4 67 31 17 8/14/23 4.1 0/3 11.1 77.0/23.0 0.1 3.80 11.12 613 2/7/17 4750' 115 10.4 77 40 15 9/15/21 3.6 0/3 11.6 76.2/23.8 0.1 3.58 24.71 637 2/8/17 4750' 87 10.5 106 40 15 9/14/21 3.8 0/3 11.5 76.2/23.8 0.1 3.63 24.71 659 2/9/17 4931' 88 10.55 145 44 22 9/17/26 3.8 0/2 1 13.3 75.7/24.3 2.0 3.32 25.68 560 2/10/17 4933' 80 10.75 128 42 18 10/18/24 3.8 0/2 13.3 75.7/24.3 0.1 3.50 24.71 548 2/11/17 5680' 104 10.4 71 31 15 8/13/19 4.0 0/2 10.9 77.6/22.4 0.1 3.35 19.37 1025 2/12/17 6000' 104 10.4 73 31 15 8/12/17 3.8 0/1 12.7 77.6/22.4 0.1 3.40 18.88 968 Abbreviations MW = Mud Weight WL = Water or Filtrate Loss Ca = Hardness Calcium YP = Yield Point Gels = Gel Strength Cl = Chlorides PV = Plastic Viscosity ASG = Ave Specific Gravity SD = Sand content VIS = Funnel Viscosity Sols = Solids CaC12 = Calcium Chloride ECD = Effective Circulating Density FC = Filter Cake O/W = Oil to Water ratio Estab - Electrical Stability 1�NABORS ALASKA 43 DRILLING, INC. A -t -g E -Sy, LLC Horseshoe #1 4.4 Days vs. Depth Plot Dailv Proaress 1�NABORS ALASKA 44 DRILLING, INC. Days vs. Depth 0 1000 2000 • . 12.25" Hole 9 5/8" Casing 3000 = • 8 1/2" Hole „ • 8 1/2" Coring 4000 • 8 112 "Hole — —E -Logs 5000 ' —<>--- Plug Back 6000 o- 7000 ry0 �O �O ry0 IV IV v �O �O ry0 ry0 ,O 1�NABORS ALASKA 44 DRILLING, INC. Show Reports NABORS ALASKA DRILLING, INC. 45 1� CANRIG DRILLING TECHNOLOGY LTD. Armstrong Energy, LLC Hydrocarbon Show Report # Operator: Armstrong Energy, LLC Well: Field: Rig: Horseshoe #1 API Number 50-103-20751-00-00 Ex loritor Wildcat Date: January 29, 2017 Doyon Rig #1 Arctic Fox Time: 9:17:42 PM County: North Sloe Borough Depth Start End State: Country: Alaska USA 1755' MD 1800' MD 1750' TVD 1795' TVD Averages Before During After Maximum Pixler Plot 10000 1000 DR GAS E 100 CONDE SATE a a 10 OIL WIP DOW 1 ON PRODU TIVE 1 2 3 4 C1/C2 C1/C3 C1/C4 C1/C5 ROP (f h) 86 130 140 224 Torque 2,863 3,076 2,984 4,619 WOB 34 32 32 34 RPM 76 76 71 79 Pump Press 2,136 2,276 2,279 2,297 Mud Weight 10.3 10.3 10.3 10.3 Chloride 400 400 300 400 Total Gas 23 35 45 49 C1 (Ppm) 5,450 7,878 9,251 11,034 C2 (ppm) - - - - C3 (ppm) - _ _ - C4 (ppm) - - - - C5 (ppm) I- - - - Lithology SAND: CLEAR TO TRANSLUCENT WITH LIGHT GREENISH BROWN HUES, YELLOWISH GREEN HUES, OLIVE BROWN HUES, LIGHT GREENISH GRAY HUES, CLOUDY WHITE HUES COLORS; UNCONSOLIDATED SANDS; DOMINATLY QUARTZ WITH TRACE CALCITE AND DOLOMITE FRAMEWORK; MEDIUM TO COARSE GRAIN SIZES; WELL TO MODERATE SORTING; ANGULAR TO SUBANGULAR; LOW TO VERY LOW SPHERICITY; THIN BEDDING STRUCTURE; VERY WEAK HCL REACTION IN BULK SAMPLE; SLIGHT TO WEAK ODOR; NO VISUAL OIL STAINS; 70% YELLOWISH WHITE BRIGHT PACHY FLOURSCENCE; FLOURSCENCE CUT SLOW DULL TO SLIGHT BRIGHT TRANSLUCENT WHITE COLOR; NO STREAMER IN FLOURSCENCE CUT; FAINTED BROWN YELLOW RESIDUE IN FLOURSCENCE CUT; NO VISUAL CUT RESIDUE OR COLOR. Oil Indicators Petroleum Odor Type Slight Free Oil, in Mud Type Pnpnt Visible Cut Intensity Very weak Residual Cut (Ring) AmountL0% Color None -Gray Oil Stain - Amount Color Sample Fluorescence Amount 70% Distribution Patchy Intensity Mod-strng Color White Color Pale straw 10% Cut Fluorescence Speed Slow Intensity Moderate Color blue-wht Residual Fluorescence Intensity Moderate Color org-brn None -Gray il Show roRating 1.8 Outgassing No Show Mudlogger/Sample-Catcher smelled hydrocarbon from the sample. There was a slight silver to purple sheen on the water surface during cleaning of the sample. Report by: AL Neubert 1� CANRIG DRILLING TECHNOLOGY LTD. Armstrong Energy, LLC Hydrocarbon Show Report # Operator: Armstrong Energy, LLC Well: Field: Horseshoe #1 Ex loritor Wildcat API Number 50-103-20751-00-00 Date: February 7, 2017 Rig: Doyon Rig #1 Arctic Fox Time: 1:25:21 PM County: North Sloe Borough Depth Start End State: Country: Alaska USA 4510' MD 4540' MD 4329' TVD 4359' TVD Averages Before During After Maximum Pixler Plot 10000 1000 t12RGAS 8 100 CONTotal 100ll_ 110 ON PRODU TIVE 1 2 3 4 Cl/C2 Cl/C3 C, C4 C,/C5 ROP (f h) 85 94 89 105 Torque 4,141 3,944 4,386 4,914 WOB 10 9 g 9 RPM 73 87 72 88 Pump Press 2,777 2,462 2,422 2,431 Mud Weight 10.4 10.4 10.4 10.4 Chloride 231,176 309,735 309,735 309,735 Gas 18 48 17 70 C1 (Ppm) 3,181 10,074 3,717 13,713 C2 (ppm) 79 177 46 257 C3 (ppm) 28 42 1 61 C4 (Ppm) 1 18 1 24 C5 (ppm) 1 11 0 15 Lithology Oil sandstone (4510'-4540') = medium light gray to light brownish gray from visible oil stain; silt sized clastics thru very fine sand gr's; very well sorted; angular to subangular; moderate sphericity; no visible grain surf features; dominant felsic framework but stippled with dark gray and green undefined detritus of accessory lithics; trace cryptomica, trace carb material; breaks around a point to long contact fabric; slight lineation of detritus; no calcareous reaction to HCL; interstices filled with clay minerals and fluid oil. Oil Indicators Petroleum Odor Type V Slight Free Oil, in Mud Type Com Visible Cut Intensityl Moderate Residual Cut (Ring) Amount 20% Oil Stain Amount 60% Color Pale straw Sample Fluorescence Amount 60% Distribution Patchy Intensity Mod-strng Color yel-wht Colorl Straw Color Pale straw Cut Fluorescence Speed Quick Intensity Mod-strng Color yel-wht Residual Fluorescence '- Intensity Moderate Color yel-wht Oil Show Rating 2.2 Outgassing No Show Good oil indicators with moderate iridescence sheen, dark brown interstitial stain; moderate yellow white sample fluorescence, streaming yellow white cut fluorescence, dark straw visible cut, straw resinous ring cut, no odor over oil based mud. Report by: AL Neubert CANRIG ,Armstrong Energy, LLC Hydrocarbon Show Report # 3 Operator: Armstrong Energy, LLC Well: Horseshoe #1 API Number 50-103-20751-00-00 Field: Ex loritor Wildcat Date: February 7, 2017 Rig: Doyon Rig #1 Arctic Fox Time: 6:56:05 PM County: North Sloe Borough Depth Start End State: Country: Alaska USA 4710' MD 4740' MD 4527' TVD 4557' TVD Averages Before During After Maximum Pixler Plot 10000 1000 DR GAS £ 100 CONDU SATE CL CL 10 OIL WIP DOW 11 ON PRODU TIVE 1 2 3 4 C,/C2 C„C3 C,/C4 C,/C5 ROP (f h) 84 78 84 91 Torque 4,350 4,122 4,827 4,802 WOB 9 10 12 11 RPM 70 63 60 70 Pump Press 3,207 3,113 3,302 3,048 Mud Weight 10.4 10.4 10.4 10.4 Chloride 231,176 309,735 1 309,735 309,735 Total Gas 6 54 9 73 C1 (PPM) 1,455 11,041 1,250 16,290 C2 (ppm) 23 333 123 487 C3 (ppm) - 137 90 220 C4 (ppm) - 16 - 34 C5 (ppm) -1 71 26 Lithology Oil sandstone (4690'-4750') = begins with light gray calcareous cement sandy siltstone and local pale yellowish orange carbonate, changes rapidly to medium dark gray to brownish gray f/both moderate to heavy oil stain and brown argillaceous content; sample stippled by and laced with black to amber and rare red carbonaceous material; dominant framework is felsic (quartz/feldspar) with scat multicolored clasts of gray, green, and red; very fine to fine with dominant fine; very well to well sorted; angular to subround with dominant angular to subangular; moderate to low sphericity; only visible gr surf features are diagenetic frost and subhedral overgrowth on quartz gr free margins; clay mineral cement to argillaceous matrix; breaks around a point to long fabric plus sands floating in siltstone and shale; com scat interstitial pale yellow lime clasts and possible abundant translucent light yellow volcanic ash at 4750' start of coring; rare visible accessory minerals; very minor interstitial calcareous; good visible planar -contorted bedding seen by aligned detritus; increased argillaceous matrix and interbedded shale with depth. Oil Indicators Petroleum Odor Type Strong Free Oil, in Mud Type Com Visible Cut IntensityModerate Color Pale straw Residual Cut (Ring) Amount 70% Color Amber Oil Stain Amount 60% Color Amb-brn Sample Fluorescence Amount 80% Distribution Even Intensity Mod-strng Color bri yel-org Cut Fluorescence Speed Quick Intensity Mod-strng Color White Residual Fluorescence Intensity Mod -string Color yel-org il Show rcRating 2.8 Outgassing No Show Strong initial oil shows with gray purple iridescence sheen, amber/brown oil stain yielding 60% yellow orange sample fluorescence; fast yellow white cut fluorescence with streamers; amber -straw visible cut with translucent light straw resinous cut and bright yellow orange resinous cut fluorescence; oil indicators decrease with increasing shale. Report b AL Neubert 1� CANRIG DRILLING TECHNOLOGY LTD. Armstrong anergy, LLC Hydrocarbon Show Report # Operator: Armstrong Energy, LLC After Maximum Well: Horseshoe #1 API Number 50-103-20751-00-00 Field: Ex loritor Wildcat Date: February 8, 2017 Rig: Doyon Rig #1 Arctic Fox Time: 11:22:53 PM County: North Sloe Borough Depth Start End State: Alaska 1,493 1 4750' MD 4841' MD Country: USA 10.4 1 4569' TVD 4660' TVD ROP (fph) Torque WOB RPM Pump Press Mud Weight Chloride Total Gas C1 (ppm) C2 (ppm) C3 (ppm) C4 (ppm) C5 (ppm) Litholoav Oil Indicators Show rt Before During After Maximum 81 47 55 88 4,634 4,671 9,986 6,592 12 6 9 13 58 46 98 59 3,153 1,039 1,493 1 3,010 10.4 10.4 10.4 1 10.4 231,176 309,735 309,735 309,735 35 40 82 47 9,605 9,275 17,480 27,606 399 314 561 1,633 145 123 181 1,117 49 97 52 1,966 17 1 78 1 20 1 1,996 10000 1000 £ 100 a a 10 1 Pixler Plot 1 2 3 4 CI/C2 CI/C3 CI/C4 CI/C5 Sandstone (4750'-4841'MD) = Dark gray to grayish brown with translucent to clear minerals, and black carbonaceous layer bands colors; quartz dominant with lithic framework; very fine to fine grain sorting; subangular with low sphericity; friable to easily friable hardness; mineral matrix grain support; no HCI reaction in bulk sample; amber to light amber visible oil stains on sandstone. 'etroleum Odor Type Strong Free Oil, in Mud _ Type Scat )il Stain Intensity Sample Fluorescence Amount 40% Amount 70% Color Amb-brn Distribution Even Intensity Mod-strng Oil Show 2.5 Ratinq', Quick Color bri yel-org i_ble Cut Residual Cut (Ring) Intensity Moderate Amount 50% Color Pale straw Color Straw Fluorescence Residual Fluorescence Speed Quick Intensity Moderate Intensity Mod-strng Color yel-org Color White Outgassinq No Visible amber to light -amber stains under white light. Oil odor discredited due to OBM in borehole. Britten Adams 1� CANRIG DRILLING TECHNOLOGY LTD. Armstrong Energy, LLC Hydrocarbon Show Report # Operator: Armstrong Energy, LLC Well: Field: Horseshoe #1 Ex loritor Wildcat API Number Date: 50-103-20751-00-00 February 9, 2017 Rig: Doyon Rig #1 Arctic Fox Time: 11:56:12 PM County: North Sloe Borough Depth Start End State: Country: Alaska USA 4840' MD 4931' MD 4659' TVD 4750' TVD Averages Before During After Maximum Pixler Plot 10000 1000 GAS £ 100 ATE Q Q 10 OIL WIP DOW PRODU TIVE 1 1 2 3 4 c1/c2 Cl/C3 cuc4 cvc5 ROP (f h) 47 52 51 85 Torque 5,350 4,447 5,344 6,540 WOB 6 5 6 6 RPM 50 54 59 59 Pump Press 1,050 1,372 1,447 1,414 Mud Weight 10.5 10.5 1 10.5 10.55 Chloride 304,944 277,004 277,004 277,004 Total Gas 41 23 28 43 C1 (Ppm) 8,626 4,838 5,608 9,149 C2 (ppm) 273 140 149 293ON C3 ( m) 88 51 48 96 C4 (ppm) 29 20 18 29 C5 (ppm) 11 8 2 32 Lithology Sandstone: Medium gray to light brownish gray with light bluish gray hues, and trace creamy white color; Translucent to clear quartz and feldspar dominant with black lithics and white traces of tuffaceous claystone; fine to very fine grain size; well sorted grains; subangular to angular angularity; low sphericity; friable to firm friable hardness; argillaceous cement; grain support; sandstone decrease in sample as depth increases; Oil Indicators Petroleum Odor Type Strong Free Oil, in Mud Type None Visible Cut Intensity None -v wk Residual Cut (Ring) AmountL0% Color None -Gray Oil Stain Amount 10% Color Amber Sample Fluorescence Amount 50% Distribution Patchy Intensity Mod-strng Color yel-org Color None -Gray Cut Fluorescence Speed Slow Intensity Very weak Color blue-wht Residual Fluorescence Intensity None -v wk Color yel-wht il Show �Rating 1.4 Outgassing No Show Yellowish green visual fluorescence; no staining; no visible cut; pale bluish white fluorescent cut color; no streamers; faint yellowish white fluorescent residual cut color; no residual cut color. Report by: Britten Adams Daily Reports NABORS ALASKA DRILLING, INC. 51 DAILY WELLSITE REPORT Armstrong Energy, LLC CA,.NR143 Horseshoe #1 Wildcat, North Slope Borough DRILLING TECHNOLOGY LTD_ Date: 1/27/2017 Time: 24:00:00 Depth:192' Operation: Drilling Ahead Report for: Wellsite Leader: David Oryall Yesterday: 118' Contractor: Doyon Drilling AK Geologist: Colby Vandenburg Footage: 74' Spud Date: 1/28/2017 CASING INFO 18" @ 118' BIT INFORMATION INTERVAL TOTAL FOOTAGE On Bottom HOURS CONDITION CS / B / G REASON PULLED NO SIZE MAKE/TYPE S/N JETS IN OUT 1 12.25" VMD-3/HCC 5259382 16,3x8 118' 192' 74' 2.5 INC BHA DIRECTIONAL TOOLS BH Motor -steerable, OnTrak-MWD, BCPM, ORD, CCN SURVEY DATA DEPTH INCL AZI TVD TVDSS +N -S +E -W DLS DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG PENETRATION 47.2 @ 155' 12.1 @ 146' 19 26 ft/hr SURFACE TORQUE 77 @ 142' 0 @ 178' 3 0 ft/lbs WEIGHT ON BIT 12 @ 178' 1 @ 133' 6 7 Klbs TOP DRIVE RPM 43 @ 158' 23 @ 143' 25 36 rpm PUMP PRESSURE 169 @ 160' 152 @ 179' 116 160 psi DRILLING MUD REPORT DEPTH: 191' TYPE: OBM MI-Swaco BASE: Water FLOWLINE TEMP: 100°F MW VIS PV YP Gels FL Cake Sol Oil/1-120 MBT pH Cl- ppm Ca++ 10.5 194 14 4 4/4/5 4.6 13.37 76/24 0.9 41500 191923 1.17 180 LAG DATA Hole Cap String Cap String Disp Total Disp Ann Cap Strokes Surf to Surface Strokes to bit Strokes Bottoms Up DEPTH (bbls) (bbls) (bbls) (bbls) (bbls) Pump 1+2 Pump 3 Pump 1+2 Pump 3 Pump 1+2 Pump 3 191' 36 1 2 3 33.3 748 748 26 26 723 723 GAS SUMMARY HIGH LOW AVERAGE UNITS DITCH GAS 0 @ 0 0 @ 0 0 CURRENT GAS = 0 CHROMATOGRAPHY(ppm) TRIP GAS = 0 WIPER GAS = 0 HIGH LOW AVERAGE SURVEY GAS = 0 METHANE(C-1) 79 @ 169' 79 @ 169' 1 CONNECTION GAS MAX = 0 ETHANE(C-2) 0 @ 191' 0 @ 191' 0 AVG = 0 PROPANE(C-3) 0 @ 191' 0 @ 191' 0 CURRENT= 0 BUTANE(C-4) 0 @ 191' 0 @ 191' 0 BACKGROUND GAS MAX = 0 PENTANE(C-5) 0 @ 191' 0 @ 191' 0 AVG = 0 CURRENT= 0 HYDROCARBON SHOWS NA INTERVAL LITHOLOGY/REMARKS GAS UNITS DESCRIPTION TO TO LITHOLOGY (%) Claystone Tuffaceous Shale Volcanic Ash Sand FORMATION: 80% 0% 0% 20% Permafrost 100% PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Pretour meeting with crew for spud meeting. After meeting, prepare/test, pumps and valves for drilling. Pick up tools and HW DP for short run until 192'MD. Get the confirmation to drill from team. Drill from 118'-191' MD. Pull out of hole and lay pipe down to prepare for second BHA per Baker Hughes. Canrig Personnel On Board: Neubert, Adams, Wardner, Wiseman Daily Cost: $3,125 Report Completed by: Britten Adams DAILY WELLSITE REPORT Armstrong Energy, LLC CA,.NR143 Horseshoe #1 Wildcat, North Slope Borough DRILLING TECHNOLOGY LTD_ Date: 1/28/2017 Time: 24:00:00 Depth:ZOperation: Drilling Ahead Report for: Wellsite Leader: David Oryall Yesterday:Contractor: Doyon Drilling AK Geologist: Colby Vandenburg Footage:Spud Date: 1/28/2017 CASING INFO 18" @ 118' BIT INFORMATION INTERVAL TOTAL FOOTAGE On Bottom HOURS CONDITION CS / B / G REASON PULLED NO SIZE MAKE/TYPE S/N JETS IN OUT 1 12.25" VMD-3/HCC 5259382 16,3x8 118' 192' 74' 2.5 INC BHA DIRECTIONAL TOOLS BH Motor -steerable, OnTrak-MWD, BCPM, ORD, CCN SURVEY DATA DEPTH INCL AZI TVD TVDSS +N -S +E -W DLS 213' .8' 355.03 212.96 1.43 -0.12 1.43 0.36 294' 3.1' 3.76 293.90 4.12 -0.03 4.12 2.83 356' 3.1' 4.64 355.82 7.42 0.21 7.42 0.08 423' 3.4' 6.14 422.67 11.17 0.57 11.17 0.49 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENTAVG PENETRATION 953.2 @ 236' 8.8 @ 546' 150 160 ft/hr SURFACE TORQUE 3045 @ 283' 0 @ 424' 1050 1214 ft/lbs WEIGHT ON BIT 25 @ 343' 0 @ 236' 16 20 Klbs TOP DRIVE RPM 62 @ 282' 1 @ 435' 39 61 rpm PUMP PRESSURE 1303 @ 554' 152 @ 179' 909 1249 psi DRILLING MUD REPORT DEPTH: 191' TYPE: OBM MI-Swaco BASE: Water FLOWLINE TEMP: 100°F MW VIS PV YP Gels FL Cake Sol Oil/H20 MBT pH Cl- ppm Ca++ 10.1 194 51 53 24/38/49 4.9 2.00 7.6 0.2/92 22.5 10 300 40 LAG DATA Hole Cap String Cap String Disp Total Disp Ann Cap Strokes Surf to Surface Strokes to bit Strokes Bottoms Up DEPTH (bbls) (bbls) (bbls) (bbls) (bbls) Pump 1+2 Pump 3 Pump 1+2 Pump 3 Pump 1+2 Pump 3 560' 90 2 11 14 76.6 1709 1709 48 48 1660 1660 GAS SUMMARY HIGH LOW AVERAGE UNITS DITCH GAS 0 @ 0 0 @ 0 0 CURRENT GAS = 1.8 CHROMATOGRAPHY(ppm) TRIP GAS = 0 WIPER GAS = 0 HIGH LOW AVERAGE SURVEY GAS = 0 METHANE(C-1) 481 @ 541' 68 @ 318' 87 CONNECTION GAS MAX = 0 ETHANE(C-2) 0 @ 560' 0 @ 560' 0 AVG = 0 PROPANE(C-3) 0 @ 560' 0 @ 560' 0 CURRENT= 0 BUTANE(C-4) 0 @ 560' 0 @ 560' 0 BACKGROUND GAS MAX = 1.8 PENTANE(C-5) 0 @ 560' 0 @ 560' 0 AVG = 1.1 CURRENT= 1 HYDROCARBON SHOWS NA INTERVAL LITHOLOGY/REMARKS GAS UNITS DESCRIPTION TO TO LITHOLOGY (%) Claystone Tuffaceous Shale Volcanic Ash Sand FORMATION: 70% 0% 0% 30% Permafrost 100% PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Pretour meeting with crew for spud. After meeting, prepare/test, pumps and valves for drilling. Pick up tools and HW DP for short run until 192'MD. Get the confirmation to drill from team. Drill from 118'-192' MD. Pull out of hole and lay pipe down to prepare for second BHA per Baker Hughes. Rig -up new BHA and run in hole. Drilled from 192'-560'MD with sliding interval of (194'-236') (236'-276') (421'-436')MD. Continue to drill ahead. Canrig Personnel On Board: Neubert, Adams, Wardner, Wiseman Daily Cost: $3,125 Report Completed by: Britten Adams DAILY WELLSITE REPORT Armstrong Energy, LLC Horseshoe #1 Wildcat, North Slope Borough DRILLING TECHNOLOGY LTD_ Date: 1/29/2017 Time: 24:00:00 Operation: Drilling Ahead Depth:1932']Spud Report for: Wellsite Leader: David Oryall Yesterday: 560'Contractor: Doyon Drilling AK Geologist: Colby Vandenburg Footage: 1372' Date: 1/28/2017 CASING INFO 18" @ 118' BIT INFORMATION INTERVAL TOTAL FOOTAGE On Bottom HOURS CONDITION CS / B / G REASON PULLED NO SIZE MAKE/TYPE S/N JETS IN OUT 1 12.25" VMD-3/HCC 5259382 16,3x8 118' 192' 74' 2.5 INC DIRECTIONAL TOOLS BH Motor-steerable, OnTrak-MWD, BCPM, ORD, CCN SURVEY DATA DEPTH INCL AZI TVD TVDSS +N-S +E-W DLS 1660' 12.4' 357.41 1650.51 148.21 2.07 148.21 2.36 1722' 13.1' 357.64 1710.95 161.86 1.48 161.86 1.23 1785' 13.0' 357.71 1772.48 176.14 0.90 176.14 0.14 1846' 13.5' 357.08 1831.91 190.12 0.27 190.12 0.77 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENTAVG PENETRATION 488.5 @ 1280' 7.7 @ 1676' 145 86 ft/hr SURFACE TORQUE 5424 @ 1306' 0 @ 1419' 1941 2425 ft/lbs WEIGHT ON BIT 42 @ 1677' 1 @ 1007' 26 32 Klbs TOP DRIVE RPM 83 @ 959' 1 @ 1875' 60 73 rpm PUMP PRESSURE 2443 @ 1893' 1149 @ 608' 1930 2430 psi DRILLING MUD REPORT DEPTH: 1900' TYPE: Halliburton BASE: Water FLOWLINE TEMP: MW VIS PV YP Gels FL Cake Sol Oil/H20 MBT pH Cl- ppm Ca++ 10.3 135 30 54 19/39/51 4.6 2.00 8.8 0.5/91.2 22.5 10 300 40 LAG DATA Hole Cap String Cap String Disp Total Disp Ann Cap Strokes Surf to Surface Strokes to bit Strokes Bottoms Up DEPTH (bbls) (bbls) (bbls) (bbls) (bbls) Pump 1+2 Pump 3 Pump 1+2 Pump 3 Pump 1+2 Pump 3 1932' 290 16 21 36 253.8 5845 5845 345 345 5500 5500 GAS SUMMARY HIGH LOW AVERAGE UNITS DITCH GAS 84 @ 1558 0 @ 1230 24.4 CURRENT GAS = 20 CHROMATOGRAPHY(ppm) TRIP GAS = 0 WIPER GAS = 0 HIGH LOW AVERAGE SURVEY GAS = 0 METHANE(C-1) 19776 @ 1558' 72 @ 643' 5493 CONNECTION GAS MAX = 33 ETHANE(C-2) 0 @ 1932' 0 @ 1932' 0 AVG = 15 PROPANE(C-3) 0 @ 1932' 0 @ 1932' 0 CURRENT= 0 BUTANE(C-4) 0 @ 1932' 0 @ 1932' 0 BACKGROUND GAS MAX = 45 PENTANE(C-5) 0 @ 1932' 0 @ 1932' 0 AVG = 24 CURRENT= 20 HYDROCARBON SHOWS 1 INTERVAL LITHOLOGY/REMARKS GAS UNITS DESCRIPTION 1755' TO 1800' Sand/1.4 show rating 49 Sands with oil odor and sheen on sample surface. TO LITHOLOGY (%) Claystone Tuffaceous Claystone Siltstone Tuffaceous Sandstone FORMATION: 30% 10% 30% 30% Schrader Bluff FM 100% PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Drilled from 560'-1932'MD. While drilling per Baker Hughes representive use directional tools to build angle. Correctly we are still drilling ahead. Canrig Personnel On Board: Neubert, Adams, Wardner, Wiseman Daily Cost: $3,125 Report Completed by: Britten Adams DAILY WELLSITE REPORT Armstrong Energy, LLC Horseshoe #1 CA,.NR143 Wildcat, North Slope Borough DRILLING TECHNOLOGY LTD_ Date: 1/30/2017 Time: 24:00:00 Depth:Operation: POOH for Casing Report for: Wellsite Leader: David Oryall Contractor: Doyon Drilling AK Yesterday:15] Geologist: Colby Vandenburg Footage: Spud Date: 1/28/2017 CASING INFO 18" @ 118' BIT INFORMATION INTERVAL TOTAL On Bottom CONDITION REASON NO SIZE MAKE/TYPE S/N JETS IN OUT FOOTAGE HOURS CS / B / G PULLED 1 12.25" VMD-3/HCC 5259382 16,3x8 118' 2230' 2112' Casing DIRECTIONAL TOOLS BH Motor -steerable, OnTrak-MWD, BCPM, ORD, CCN SURVEY DATA DEPTH INCL AZI TVD +N -S +E -W VS DLS 2027.12' 16.14 357.62 2006.40' 238.68' -2.04' 238.68' 0.48 2089.21' 16.26 357.67 2066.03' 255.99' -2.75' 255.99' 0.19 2152.79' 16.25 358.06 2127.07' 273.78' -3.41' 273.78' 0.17 2164.33' 16.15 358.32 2138.15' 276.99' -3.51' 276.99' 1.07 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG PENETRATION 176.2 @ 2043' 8.5 @ 2218' 74 69 ft/hr SURFACE TORQUE 3925 @ 1942' 26 @ 2210' 1572 962 ft/lbs WEIGHT ON BIT 32 @ 1952' 13 @ 2095' 26 28 Klbs TOP DRIVE RPM 82 @ 2107' 54 @ 1936' 75 76 rpm PUMP PRESSURE 2438 @ 1951' 1488 @ 2210' 2236 2125 psi DRILLING MUD REPORT DEPTH: 2230' TYPE: Halliburton BASE: Water FLOWLINE TEMP: MW VIS PV YP Gels FL Cake Sol Oil/H20 MBT pH Cl- ppm Ca++ 10.2 94 32 37 17/30/39 4.9 2.00 8.8 0.5/90.5 22.5 10 400 40 LAG DATA Hole Cap String Cap String Disp Total Disp Ann Cap Strokes Surf to Surface Strokes to bit Strokes Bottoms Up DEPTH (bbls) (bbls) (bbls) (bbls) (bbls) Pump 1+2 Pump 3 Pump 1+2 Pump 3 Pump 1+2 Pump 3 2230' 334 19 22 41 292.6 6756 6756 415 415 6341 6341 GAS SUMMARY HIGH LOW AVERAGE UNITS DITCH GAS 39 @ 2007 7 @ 2031 22.3 CURRENT GAS = 20 CHROMATOGRAPHY(ppm) TRIP GAS = 64 WIPER GAS = 0 HIGH LOW AVERAGE SURVEY GAS = 0 CONNECTION GAS MAX = 33 METHANE(C-1) 8476 @ 2147' 1597 @ 2031' 4879 ETHANE(C-2) 0 @ 2230' 0 @ 2230' 0 AVG = 15 PROPANE(C-3) 0 @ 2230' 0 @ 2230' 0 CURRENT= 0 BUTANE(C-4) 0 @ 2230' 0 @ 2230' 0 BACKGROUND GAS MAX = 45 PENTANE(C-5) 0 @ 2230' 0 @ 2230' 0 AVG = 24 CURRENT= 20 HYDROCARBON SHOWS Show Report #1 INTERVAL LITHOLOGY/REMARKS GAS UNITS DESCRIPTION 1755' TO 1800' Sand/1.4 show rating 49 Sands with oil odor and sheen on sample surface. TO LITHOLOGY (%) Claystone Volcanic Ash Siltstone Tuffaceous Sandstone FORMATION: 10% 90% 0% 0% Schrader Bluff FM 100% PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Drilled from 1932'-2030'MD. Repair rig mud pump then continue to drill ahead. TD drilling for casing at 2231'MD. Pump out of hole from 2231'- 1935'MD and work tight spots. Pull out to 1630'MD. Trip back in hole to 2231'MD. Condition mud and circulate sweep. Prepare to pull out of entire hole. Pull out to 1590'MD. Condition mud and circulate. Continue to pull out to 1280'MD and remove excessive clay in cutting box. Pump out to 1040'MD. Remove clay balls from riser nipple and flow line. Continue to pull out 731'MD and flow check the well for 10 minutes. Well flow test is good. Pull out to 233'MD. Canrig Personnel On Board: Neubert, Adams, Wardner, Wiseman Daily Cost: $2,825 Report Completed by: Britten Adams DAILY WELLSITE REPORT Armstrong Energy, LLC Horseshoe #1 CA,.NR143 Wildcat, North Slope Borough DRILLING TECHNOLOGY LTD_ Date: 1/31/2017 Time: 24:00:00 Depth:Operation: POOH for Casing Report for: Wellsite Leader: David Oryall Yesterday:15] Contractor: Doyon Drilling AK Geologist: Colby Vandenburg Footage: Spud Date: 1/28/2017 CASING INFO 18" @ 118' BIT INFORMATION INTERVAL TOTAL On Bottom CONDITION REASON NO SIZE MAKE/TYPE S/N JETS IN OUT FOOTAGE HOURS CS / B / G PULLED 1 12.25" VMD-3/HCC 5259382 16,3x8 118' 2230' 2112' Casing DIRECTIONAL TOOLS BH Motor -steerable, OnTrak-MWD, BCPM, ORD, CCN SURVEY DATA DEPTH INCL AZI TVD +N -S +E -W VS DLS 2027.12' 16.14 357.62 2006.40' 238.68' -2.04' 238.68' 0.48 2089.21' 16.26 357.67 2066.03' 255.99' -2.75' 255.99' 0.19 2152.79' 16.25 358.06 2127.07' 273.78' -3.41' 273.78' 0.17 2164.33' 16.15 358.32 2138.15' 276.99' -3.51' 276.99' 1.07 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG PENETRATION 0 @ 0 @ 0 0 ft/hr SURFACE TORQUE 0 @ 0 @ 0 0 ft/lbs WEIGHT ON BIT 0 @ 0 @ 0 0 Klbs TOP DRIVE RPM 0 @ 0 @ 0 0 rpm PUMP PRESSURE 0 @ 0 @ 0 0 psi DRILLING MUD REPORT DEPTH: 2230' TYPE: Halliburton BASE: Water FLOWLINE TEMP: MW VIS PV YP Gels FL Cake Sol Oil/H20 MBT pH Cl- ppm Ca++ 10.4 230 38 45 20/38/48 5.3 2.00 9.3 0.5/90 27 1 o 400 40 LAG DATA Hole Cap String Cap String Disp Total Disp Ann Cap Strokes Surf to Surface Strokes to bit Strokes Bottoms Up DEPTH (bbls) (bbls) (bbls) (bbls) (bbls) Pump 1+2 Pump 3 Pump 1+2 Pump 3 Pump 1+2 Pump 3 GAS SUMMARY HIGH LOW AVERAGE UNITS DITCH GAS 0 @ 0 0 @ 0 0 CURRENT GAS = 0 CHROMATOGRAPHY(ppm) TRIP GAS = 0 WIPER GAS = 0 HIGH LOW AVERAGE SURVEY GAS = 0 METHANE(C-1) 0 @ 0 @ 0 CONNECTION GAS MAX = 0 ETHANE(C-2) 0 @ 0 @ 0 AVG = 0 PROPANE(C-3) 0 @ 0 @ 0 CURRENT= 0 BUTANE(C-4) 0 @ 0 @ 0 CIRCULATING GAS MAX = 38 PENTANE(C-5) 0 @ 0 @ 0 AVG = 8 CURRENT= 0 HYDROCARBON SHOWS Show Report #1 INTERVAL LITHOLOGY/REMARKS GAS UNITS DESCRIPTION 1755' TO 1800' Sand/1.4 show rating 49 Sands with oil odor and sheen on sample surface. TO LITHOLOGY (%) Claystone Volcanic Ash Siltstone Tuffaceous Sandstone FORMATION: 10% 90% 0% 0% Schrader Bluff FM 100% PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Continue to pull out the hole to 140'MD. Remove source from rig floor and lay down BHA. Clean rig floor and prepare for casing crew. Rig up casing equipment and have meeting on running casing. Run casing from surface to 1630'MD. Canrig Personnel On Board: Neubert, Adams, Wardner, Wiseman Daily Cost: $2,825 Report Completed by: Britten Adams DAILY WELLSITE REPORT Armstrong Energy, LLC Horseshoe #1 CA,.NR143 Wildcat, North Slope Borough DRILLING TECHNOLOGY LTD_ Date: 2/1/2017 Time: 24:00:00 Depth:Operation: POOH for Casing Report for: Wellsite Leader: David Oryall Yesterday:15] Contractor: Doyon Drilling AK Armstrong Geologist: Colby Vandenburg Footage: Spud Date: 1/28/2017 CASING INFO 16" @ 118' 9 5/8" @ 2231' BIT INFORMATION INTERVAL TOTAL On Bottom CONDITION REASON NO SIZE MAKE/TYPE S/N JETS IN OUT FOOTAGE HOURS CS / B / G PULLED 1 12.25" VMD-3/HCC 5259382 16,3x8 118' 2230' 2112' 23.3 1,1,NO,A,3,1,NO,TD Casing 2 8.50 " DIRECTIONAL TOOLS BH Motor -steerable, OnTrak-MWD, BCPM, ORD, CCN SURVEY DATA DEPTH INCL AZI TVD +N -S +E -W VS DLS 2027.12' 16.14 357.62 2006.40' 238.68' -2.04' 238.68' 0.48 2089.21' 16.26 357.67 2066.03' 255.99' -2.75' 255.99' 0.19 2152.79' 16.25 358.06 2127.07' 273.78' -3.41' 273.78' 0.17 2164.33' 16.15 358.32 2138.15' 276.99' -3.51' 276.99' 1.07 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG PENETRATION 0 @ 0 @ 0 0 ft/hr SURFACE TORQUE 0 @ 0 @ 0 0 ft/lbs WEIGHT ON BIT 0 @ 0 @ 0 0 Klbs TOP DRIVE RPM 0 @ 0 @ 0 0 rpm PUMP PRESSURE 0 @ 0 @ 0 0 psi DRILLING MUD REPORT DEPTH: 2230' TYPE: Halliburton BASE: Water FLOWLINE TEMP: MW VIS PV YP Gels FL Cake Sol Oil/1-120 MBT pH Cl- ppm Ca++ 10.2 55 28 17 6/8/9 5.8 2.00 8.8 0.5/90.5 25 8 300 40 LAG DATA Hole Cap String Cap String Disp Total Disp Ann Cap Strokes Surf to Surface Strokes to bit Strokes Bottoms Up DEPTH (bbls) (bbls) (bbls) (bbls) (bbls) Pump 1+2 Pump 3 Pump 1+2 Pump 3 Pump 1+2 Pump 3 GAS SUMMARY HIGH LOW AVERAGE UNITS DITCH GAS 0 @ 0 0 @ 0 0 CURRENT GAS = 0 CHROMATOGRAPHY(ppm) TRIP GAS = 0 WIPER GAS = 0 HIGH LOW AVERAGE SURVEY GAS = 0 METHANE(C-1) 0 @ 0 @ 0 CONNECTION GAS MAX = 0 ETHANE(C-2) 0 @ 0 @ 0 AVG = 0 PROPANE(C-3) 0 @ 0 @ 0 CURRENT= 0 BUTANE(C-4) 0 @ 0 @ 0 CIRCULATING GAS MAX = 32 PENTANE(C-5) 0 @ 0 @ 0 AVG = 3 CURRENT= 0 HYDROCARBON SHOWS Show Report #1 INTERVAL LITHOLOGY/REMARKS GAS UNITS DESCRIPTION 1755' TO 1800' Sand/1.4 show rating 49 Sands with oil odor and sheen on sample surface. TO LITHOLOGY (%) Claystone Volcanic Ash Siltstone Tuffaceous Sandstone FORMATION: 10% 90% 0% 0% Lwr Schrader Bluff 100% PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Continue to run in hole with casing to 2231.56'MD. Clean rig floor and prepare to rig up cement equipment. Pre -job safety meeting for cement job. TIH with cement eqiupment and begin process. Completed cement job and disassemble cement head. Canrig Personnel On Board: Neubert, Adams, Wardner, Wiseman Daily Cost: $2,825 Report Completed by: Britten Adams DAILY WELLSITE REPORT Armstrong Energy, LLC Horseshoe #1 CA,.NR143 Wildcat, North Slope Borough DRILLING TECHNOLOGY LTD_ Date: 2/2/2017 Time: 24:00:00 Depth:Operation: POOH for Casing Report for: Wellsite Leader: David Oryall Yesterday:15] Contractor: Doyon Drilling AK Armstrong Geologist: Colby Vandenburg Footage: Spud Date: 1/28/2017 CASING INFO 16" @ 118' 9 5/8" @ 2231' BIT INFORMATION INTERVAL TOTAL On Bottom CONDITION REASON NO SIZE MAKE/TYPE S/N JETS IN OUT FOOTAGE HOURS CS / B / G PULLED 1 12.25" VMD-3/HCC 5259382 16,3x8 118' 2230' 2112' 23.3 1,1,NO,A,3,1,NO,TD Casing 2 8.50 " DIRECTIONAL TOOLS BH Motor -steerable, OnTrak-MWD, BCPM, ORD, CCN SURVEY DATA DEPTH INCL AZI TVD +N -S +E -W VS DLS 2027.12' 16.14 357.62 2006.40' 238.68' -2.04' 238.68' 0.48 2089.21' 16.26 357.67 2066.03' 255.99' -2.75' 255.99' 0.19 2152.79' 16.25 358.06 2127.07' 273.78' -3.41' 273.78' 0.17 2164.33' 16.15 358.32 2138.15' 276.99' -3.51' 276.99' 1.07 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG PENETRATION 0 @ 0 @ 0 0 ft/hr SURFACE TORQUE 0 @ 0 @ 0 0 ft/lbs WEIGHT ON BIT 0 @ 0 @ 0 0 Klbs TOP DRIVE RPM 0 @ 0 @ 0 0 rpm PUMP PRESSURE 0 @ 0 @ 0 0 psi DRILLING MUD REPORT DEPTH: 2230' TYPE: Halliburton BASE: Water FLOWLINE TEMP: MW VIS PV YP Gels FL Cake Sol Oil/H20 MBT pH Cl- ppm Ca++ 10 61 32 21 7/10/12 6 2.00 7.5 0.5/91.8 20 9 300 360 LAG DATA Hole Cap String Cap String Disp Total Disp Ann Cap Strokes Surf to Surface Strokes to bit Strokes Bottoms Up DEPTH (bbls) (bbls) (bbls) (bbls) (bbls) Pump 1+2 Pump 3 Pump 1+2 Pump 3 Pump 1+2 Pump 3 GAS SUMMARY HIGH LOW AVERAGE UNITS DITCH GAS 0 @ 0 0 @ 0 0 CURRENT GAS = 0 CHROMATOGRAPHY(ppm) TRIP GAS = 0 WIPER GAS = 0 HIGH LOW AVERAGE SURVEY GAS = 0 METHANE(C-1) 0 @ 0 @ 0 CONNECTION GAS MAX = 0 ETHANE(C-2) 0 @ 0 @ 0 AVG = 0 PROPANE(C-3) 0 @ 0 @ 0 CURRENT= 0 CIRCULATING GAS MAX = 0 BUTANE(C-4) 0 @ 0 @ 0 PENTANE(C-5) 0 @ 0 @ 0 AVG = 0 CURRENT= 0 HYDROCARBON SHOWS Show Report #1 INTERVAL LITHOLOGY/REMARKS GAS UNITS DESCRIPTION 1755' TO 1800' Sand/1.4 show rating 49 Sands with oil odor and sheen on sample surface. TO LITHOLOGY (%) Claystone Volcanic Ash Siltstone Tuffaceous Sandstone FORMATION: 10% 90% 0% 0% Lwr Schrader Bluff 100% PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Rig down cement equipment. Pull out of hole from 2053'MD to surface. Clean/clear rig floor to prepare for changing BOP stack. Begin to nipple down and service rig. Pick up and start on well head. Canrig Personnel On Board: Neubert, Adams, Wardner, Wiseman Daily Cost: $2,825 Report Completed by: Britten Adams DAILY WELLSITE REPORT Armstrong Energy, LLC Horseshoe #1 CA,.NR143 Wildcat, North Slope Borough DRILLING TECHNOLOGY LTD_ Date: 2/3/2017 Time: 24:00:00 Depth:Operation: POOH for Casing Report for: Wellsite Leader: David Oryall Yesterday:15] Contractor: Doyon Drilling AK Armstrong Geologist: Colby Vandenburg Footage: Spud Date: 1/28/2017 CASING INFO 16" @ 118' 9 5/8" @ 2231' BIT INFORMATION INTERVAL TOTAL On Bottom CONDITION REASON NO SIZE MAKE/TYPE S/N JETS IN OUT FOOTAGE HOURS CS / B / G PULLED 1 12.25" VMD-3/HCC 5259382 16,3x8 118' 2230' 2112' 23.3 1,1,NO,A,3,1,NO,TD Casing 2 8.50 " DIRECTIONAL TOOLS BH Motor -steerable, OnTrak-MWD, BCPM, ORD, CCN SURVEY DATA DEPTH INCL AZI TVD +N -S +E -W VS DLS 2027.12' 16.14 357.62 2006.40' 238.68' -2.04' 238.68' 0.48 2089.21' 16.26 357.67 2066.03' 255.99' -2.75' 255.99' 0.19 2152.79' 16.25 358.06 2127.07' 273.78' -3.41' 273.78' 0.17 2164.33' 16.15 358.32 2138.15' 276.99' -3.51' 276.99' 1.07 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG PENETRATION 0 @ 0 @ 0 0 ft/hr SURFACE TORQUE 0 @ 0 @ 0 0 ft/lbs WEIGHT ON BIT 0 @ 0 @ 0 0 Klbs TOP DRIVE RPM 0 @ 0 @ 0 0 rpm PUMP PRESSURE 0 @ 0 @ 0 0 psi DRILLING MUD REPORT DEPTH: 2230' TYPE: Halliburton BASE: Water FLOWLINE TEMP: MW VIS PV YP Gels FL Cake Sol Oil/H20 MBT pH Cl- ppm Ca++ 1 o 62 32 20 7/10/12 6 2.00 7.5 0.5/91.8 20 9 300 360 LAG DATA Hole Cap String Cap String Disp Total Disp Ann Cap Strokes Surf to Surface Strokes to bit Strokes Bottoms Up DEPTH (bbls) (bbls) (bbls) (bbls) (bbls) Pump 1+2 Pump 3 Pump 1+2 Pump 3 Pump 1+2 Pump 3 GAS SUMMARY HIGH LOW AVERAGE UNITS DITCH GAS 0 @ 0 0 @ 0 0 CURRENT GAS = 0 CHROMATOGRAPHY(ppm) TRIP GAS = 0 WIPER GAS = 0 HIGH LOW AVERAGE SURVEY GAS = 0 METHANE(C-1) 0 @ 0 @ 0 CONNECTION GAS MAX = 0 ETHANE(C-2) 0 @ 0 @ 0 AVG = 0 PROPANE(C-3) 0 @ 0 @ 0 CURRENT= 0 CIRCULATING GAS MAX = 0 BUTANE(C-4) 0 @ 0 @ 0 PENTANE(C-5) 0 @ 0 @ 0 AVG = 0 CURRENT= 0 HYDROCARBON SHOWS Show Report #1 INTERVAL LITHOLOGY/REMARKS GAS UNITS DESCRIPTION 1755' TO 1800' Sand/1.4 show rating 49 Sands with oil odor and sheen on sample surface. TO LITHOLOGY (%) Claystone Volcanic Ash Siltstone Tuffaceous Sandstone FORMATION: 10% 90% 0% 0% Lwr Schrader Bluff 100% PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Continue to nipple up BOP stack. Rig up test plug to test shell, choke manifold, and kill lines to 4000psi. Testing completed and pick up 88 joints of 4" pipe. Pre -job meeting and pick up BHA per Baker Hughes. Canrig Personnel On Board: Neubert, Adams, Wardner, Wiseman Daily Cost: $2,825 Report Completed by: Britten Adams DAILY WELLSITE REPORT Armstrong Energy, LLC Hoo Horseshoe #1 Wildcat, North Slope Borough DRILLING TEL HNLiLC�GY LTD_ Date: 2/4/2017 Time: 24:00:00 Depth:Operation: RIH w/ 4" Drill Pipe Contractor: Doyon Drilling AK Report for: Wellsite Leader: Bob Lenhart Yesterday:15] Armstrong Geologist: Colby Vandenburg Footage: Spud Date: 1/27/2017 CASING INFO 16" @ 118' 9 5/8" @ 2213' BIT INFORMATION INTERVAL TOTAL FOOTAGE On Bottom HOURS CONDITION CS / B / G REASON PULLED NO SIZE MAKE/TYPE S/N JETS IN OUT 1 12.25" VMD-3/HCC 5259382 16,3x8 118' 2230' 2112' 23.3 1,1,NO,A,3,1,NO,TD Casing 2 8.50 " Hycalog SKH519M-Ci 7x12 2230' DIRECTIONAL TOOLS Baker Hughes AutoTrak, MWD/LWD tool, OnTrak-MWD, BCPM SURVEY DATA DEPTH INCL AZI TVD +N -S +E -W VS DLS 2164.33' 16.15 358.32 2138.15' 276.99' -3.51' 276.99' 1.07 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG PENETRATION 0 @ 0 @ 0 0 ft/hr SURFACE TORQUE 0 @ 0 @ 0 0 ft/lbs WEIGHT ON BIT 0 @ 0 @ 0 0 Klbs TOP DRIVE RPM 0 @ 0 @ 0 0 rpm PUMP PRESSURE 0 @ 0 @ 0 0 psi DRILLING MUD REPORT DEPTH: 2230' TYPE: Halliburton I Baroid BASE: Oil FLOWLINE TEMP: MW VIS PV YP Gels HT FL Corr Sol Oil/1-120 Alk POM Cl- mg/L WPS Lime Stability 10.4 93 37 16 10/0/24 4.6 12.50 64.5/21 0.15 LAG DATA Hole Cap String Cap String Disp Total Disp Ann Cap Strokes Surf to Surface Strokes to bit Strokes Bottoms Up DEPTH (bbls) (bbls) (bbls) (bbls) (bbls) Pump 1+2 Pump 3 Pump 1+2 Pump 3 Pump 1+2 Pump 3 2230' 158 21 16 38 120.1 3067 3067 464 464 2603 2603 GAS SUMMARY HIGH LOW AVERAGE UNITS DITCH GAS 0 @ 0 @ 0 0 CURRENT GAS = 0 CHROMATOGRAPHY(ppm) TRIP GAS = 0 WIPER GAS = 0 HIGH LOW AVERAGE SURVEY GAS = 0 METHANE(C-1) 0 @ 0 @ 0 CONNECTION GAS MAX = 0 ETHANE(C-2) 0 @ 0 @ 0 AVG = 0 PROPANE(C-3) 0 @ 0 @ 0 CURRENT= 0 CIRCULATING GAS MAX = 0 BUTANE(C-4) 0 @ 0 @ 0 PENTANE(C-5) 0 @ 0 @ 0 AVG = 0 CURRENT= 0 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS UNITS DESCRIPTION TO TO LITHOLOGY (%) Claystone Volcanic Ash Siltstone Tuffaceous Sandstone 7 FORMATION: 10% 90% 0% 0% Lwr Schrader Bluff 100% PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Downloading of MWD tools, and clean rig. Continue to move up BHA and rack back in derrick. Prepare for test plug and test BOP stack. Test BOP to 4000psi and choke to 2000psi. Test is good and rig down test equipment. PJSM with E -line team. Run in hole with E -line eqiupment to 2100'MD and begin logging. Log bond finish and lay down Sclumberger's E -line assembley. PJSM with all rig hand for running in hole with BHA. Run in hole with 4" drill pipe. Canrig Personnel On Board: Neubert, Adams, Wardner, Wiseman Daily Cost: $2,905 Report Completed by: Britten Adams DAILY WELLSITE REPORT Armstrong Energy, LLC Horseshoe #1 CA,.NR143 Wildcat, North Slope Borough DRILLING TECHNOLOGY LTD_ Date: 2/5/2017 Time: 24:00:00 Operation: Drilling Depth:2310']Spud Report for: Wellsite Leader: Bob Lenhart Yesterday: 1950'Contractor: Doyon Drilling AK Armstrong Geologist: Colby Vandenburg Footage: 360' Date: 1/27/2017 CASING INFO 16" @ 118' 9 5/8" @ 2213' BIT INFORMATION INTERVAL TOTAL FOOTAGE On Bottom HOURS CONDITION CS / B / G REASON PULLED NO SIZE MAKE/TYPE S/N JETS IN OUT 1 12.25" VMD-3/HCC 5259382 16,3x8 118' 2230' 2112' 23.3 1,1,NO,A,3,1,NO,TD Casing 2 8.50 " Hycalog SKH519M-Ci 191314 7x12 2230' DIRECTIONAL TOOLS Baker Hughes AutoTrak, MWD/LWD tool, OnTrak-MWD, BCPM SURVEY DATA DEPTH INCL AZI TVD +N -S +E -W VS DLS 2164.33' 16.15 358.32 2138.15' 276.99' -3.51' 276.99' 1.07 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENTAVG PENETRATION 176.2 @ 2043' 8.5 @ 2218' 76 116 ft/hr SURFACE TORQUE 3382 @ 2309' 20 @ 2231' 1574 2650 ft/lbs WEIGHT ON BIT 32 @ 1952' 0 @ 2239' 22 8 Klbs TOP DRIVE RPM 109 @ 2290' 6 @ 2231' 77 106 rpm PUMP PRESSURE 2438 @ 1951' 12 @ 2231' 2084 1752 psi DRILLING MUD REPORT DEPTH: 2230' TYPE: Halliburton Baroid BASE: SBM FLOWLINE TEMP: 83°F MW VIS PV YP Gels HT FL Corr Sol Oil/H20 Alk POM CI- mg/L WPS Lime Stability 10.4 93 33 17 9/13/25 4.6 11.20 66/21 0 3.84 201509 6.6 597 LAG DATA Hole Cap String Cap String Disp Total Disp Ann Cap Strokes Surf to Surface Strokes to bit Strokes Bottoms Up DEPTH (bbls) (bbls) (bbls) (bbls) (bbls) Pump 1+2 Pump 3 Pump 1+2 Pump 3 Pump 1+2 Pump 3 2310' 163 22 17 39 124.5 3175 3175 477 477 2698 2698 GAS SUMMARY HIGH LOW AVERAGE UNITS DITCH GAS 65 @ 2231 2 @ 2251 19.3 CURRENT GAS = 9.97 CHROMATOGRAPHY(ppm) TRIP GAS = 0 WIPER GAS = 0 HIGH LOW AVERAGE SURVEY GAS = 0 CONNECTION GAS MAX = 0 METHANE(C-1) 15750 @ 2231' 159 @ 2235' 4194 ETHANE(C-2) 980 @ 2232' 980 @ 2232' 3 AVG = 0 PROPANE(C-3) 969 @ 2232' 969 @ 2232' 3 CURRENT= 0 BUTANE(C-4) 0 @ 2310' 0 @ 2310' 0 BACKGROUND GAS MAX = 16 PENTANE(C-5) 0 @ 2310' 0 @ 2310' 0 AVG = 10 CURRENT= 9.97 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS UNITS DESCRIPTION TO TO LITHOLOGY (%) Claystone Volcanic Ash Siltstone Tuffaceous Sandstone FORMATION: 80% 0% 20% 0% MCU 100% PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Continue washing the hole from 2052'-2124'MD. Rack back stand in derrick and blow down top drive. Rig up to test casing to 4000psi for 30 minutes. Test good and completed. Rig down test equipment, and prepare for displacement of new mud. Displace well with 10.4ppg OBM. Flow check the borehole (Good). Start FIT test. Pressure up to 404psi- 334psi and bleed back 2.5bbls. Test completed and began to drill ahead. Canrig Personnel On Board: Neubert, Adams, Wardner, Wiseman Daily Cost: $2,905 Report Completed by: Britten Adams DAILY WELLSITE REPORT Armstrong Energy, LLC Horseshoe #1 CA,.NR143 Wildcat, North Slope Borough DRILLING TECHNOLOGY LTD_ Date: 2/6/2017 Time: 24:00:00 Depth:S Operation: Drilling Report for: Wellsite Leader: Bob Lenhart Yesterday:Contractor: Doyon Drilling AK Armstrong Geologist: Colby Vandenburg Footage:Spud Date: 1/27/2017 CASING INFO 16" @ 118' 9 5/8" @ 2213' BIT INFORMATION INTERVAL TOTAL FOOTAGE On Bottom HOURS CONDITION CS / B / G REASON PULLED NO SIZE MAKE/TYPE S/N JETS IN OUT 1 12.25" VMD-3/HCC 5259382 16,3x8 118' 2230' 2112' 23.3 1,1,NO,A,3,1,NO,TD Casing 2 8.50 " Hycalog SKH519M-Ci 191314 7x12 2230' DIRECTIONAL TOOLS Baker Hughes AutoTrak, MWD/LWD tool, OnTrak-MWD, BCPM SURVEY DATA DEPTH INCL AZI TVD +N -S +E -W VS DLS 3386.34' 29.06 72.76 3282.38' 530.21' 261.39' 530.21' 0.47 3448.23' 29.13 73.03 3336.46' 539.07' 290.15' 539.07' 0.24 3510.46' 28.97 72.70 3390.86' 547.97' 319.03' 547.97' 0.36 3572.39' 29.13 72.75 3445.00' 556.90' 347.74' 556.90' 0.26 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG PENETRATION 220.6 @ 2891' 17.8 @ 2644' 112 95 ft/hr SURFACE TORQUE 4938 @ 2329' 22 @ 2924' 2197 3303 ft/lbs WEIGHT ON BIT 27 @ 2329' 0 @ 2637' 7 9 Klbs TOP DRIVE RPM 122 @ 2831' 50 @ 3673' 93 76 rpm PUMP PRESSURE 3196 @ 3739' 1463 @ 2404' 2693 3189 psi DRILLING MUD REPORT DEPTH: 2230' TYPE: Halliburton Baroid BASE: SBM FLOWLINE TEMP: 105°F MW VIS PV YP Gels HT FL Corr Sol Oil/H20 Alk POM CI- mg/L WPS Lime Stability 10.4 67 31 17 8/14/23 4.1 11.10 67/20 0 11.12 231176 10.23 613 LAG DATA Hole Cap String Cap String Disp Total Disp Ann Cap Strokes Surf to Surface Strokes to bit Strokes Bottoms Up DEPTH (bbls) (bbls) (bbls) (bbls) (bbls) Pump 1+2 Pump 3 Pump 1+2 Pump 3 Pump 1+2 Pump 3 3743' 264 38 24 61 202.8 5208 5208 813 813 4395 4395 GAS SUMMARY HIGH LOW AVERAGE UNITS DITCH GAS 36 @ 3521 4 @ 3327 13.9 CURRENT GAS = 2 CHROMATOGRAPHY(ppm) TRIP GAS = 0 WIPER GAS = 0 HIGH LOW AVERAGE SURVEY GAS = 0 METHANE(C-1) 8625 @ 3522' 321 @ 2883' 2754 CONNECTION GAS MAX = 1 ETHANE(C-2) 0 @ 3743' 0 @ 3743' 0 AVG = 0 PROPANE(C-3) 0 @ 3743' 0 @ 3743' 0 CURRENT= 0 BACKGROUND GAS MAX = 36 BUTANE(C-4) 0 @ 3743' 0 @ 3743' 0 PENTANE(C-5) 0 @ 3743' 0 @ 3743' 0 AVG = 10 CURRENT= 2 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS UNITS DESCRIPTION TO TO LITHOLOGY (%) Shale Volcanic Ash Siltstone Tuffaceous Sandstone FORMATION: 80% 10% 10% 0% Tuluvak FM 100% PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Continue to drill ahead from 2296'-3483'MD. Pump 46bbls high viscosity sweep to clean hole. Monitor well for 10mins. Pull out of hole from 3483'- 2861'MD and wipe borehole. Run back in to 3483'MD and drill ahead. Canrig Personnel On Board: Neubert, Adams, Wardner, Wiseman Daily Cost: $2,905 Report Completed by: Britten Adams DAILY WELLSITE REPORT Armstrong Energy, LLC Horseshoe #1 CA,.NR143 Wildcat, North Slope Borough DRILLING TECHNOLOGY LTD_ Date: 2/7/2017 Time: 24:00:00 Depth:SOperation: Drilling Report for: Wellsite Leader: Bob Lenhart Yesterday:Contractor: Doyon Drilling AK Armstrong Geologist: Colby Vandenburg Footage:Spud Date: 1/27/2017 CASING INFO 16" @ 118' 9 5/8" @ 2213' BIT INFORMATION INTERVAL TOTAL FOOTAGE On Bottom HOURS CONDITION CS / B / G REASON PULLED NO SIZE MAKE/TYPE S/N JETS IN OUT 1 12.25" VMD-3/HCC 5259382 16,3x8 118' 2230' 2112' 23.3 1,1,NO,A,3,1,NO,TD Casing 2 8.50 " Hycalog SKH519M-Ci 191314 7x12 2230' DIRECTIONAL TOOLS Baker Hughes AutoTrak, MWD/LWD tool, OnTrak-MWD, BCPM SURVEY DATA DEPTH INCL AZI TVD +N -S +E -W VS DLS 4501.99' 3.41 79.45 4321.48' 640.30' 617.48' 640.30' 4.78 4563.99' 0.58 87.92 4383.44' 640.65' 619.60' 640.65' 4.58 4627.06' 0.13 209.58 4446.51' 640.60' 619.89' 640.60' 1.04 4688.66' 0.04 188.99 4508.11' 640.51' 619.85' 640.51' 0.15 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG PENETRATION 154.6 @ 4056' 12.4 @ 3975' 87 78 ft/hr SURFACE TORQUE 5234 @ 4381' 517 @ 4104' 3375 4286 ft/lbs WEIGHT ON BIT 13 @ 4750' 0 @ 4539' 9 14 Klbs TOP DRIVE RPM 111 @ 3781' 49 @ 4636' 76 53 rpm PUMP PRESSURE 3269 @ 4446' 2029 @ 4581' 3004 3010 psi DRILLING MUD REPORT DEPTH: 2230' TYPE: Halliburton Baroid BASE: SBM FLOWLINE TEMP: 115°F MW VIS PV YP Gels HT FL Corr Sol Oil/H20 Alk POM CI- mg/L WPS Lime Stability 10.4 77 40 15 9/15/21 3.6 11.60 65.5/20.5 0 24.71 287726 5.57 637 LAG DATA Hole Cap String Cap String Disp Total Disp Ann Cap Strokes Surf to Surface Strokes to bit Strokes Bottoms Up DEPTH (bbls) (bbls) (bbls) (bbls) (bbls) Pump 1+2 Pump 3 Pump 1+2 Pump 3 Pump 1+2 Pump 3 4750' 335 48 28 77 257.8 6638 6638 1050 1050 5588 5588 GAS SUMMARY HIGH LOW AVERAGE UNITS DITCH GAS 73 @ 4724 1 @ 4017 23.3 CURRENT GAS = 5.61 CHROMATOGRAPHY(ppm) TRIP GAS = 9.9 WIPER GAS = 19 HIGH LOW AVERAGE SURVEY GAS = 0 METHANE(C-1) 16290 @ 4724' 78 @ 4018' 4882 CONNECTION GAS MAX = 1 ETHANE(C-2) 489 @ 4381' 7 @ 4586' 68 AVG = 0 PROPANE(C-3) 229 @ 4741' 1 @ 4547' 23 CURRENT= 0 BUTANE(C-4) 34 @ 4724' 0 @ 4500' 2 BACKGROUND GAS MAX = 73 PENTANE(C-5) 26 @ 4724' 0 @ 4547' 1 AVG = 14 CURRENT= 5.61 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS UNITS DESCRIPTION 4505' TO 4540' 70% Sandstone with show. 70.4 Oil stain and sheen visible in sandstone. 4710' TO 4750' 80% Sandstone with show 73.8 Oil stain visible in sandstone. LITHOLOGY (%) Sandstone Volcanic Ash Siltstone Tuffaceous Sandstone FORMATION: 80% 0% 20% 0% Lwr Nanushuk FM 100% PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Continue to drill ahead to 4599'MD. Circulate and clean hole. Control drill 50ft per hour until 4750'MD. Mix and pump 25bbls sweep. Montior the well for 15 minutes. Pull out from 4750'-4102'MD to clean the borehole. Canrig Personnel On Board: Neubert, Adams, Wardner, Wiseman Daily Cost: $2,905 Report Completed by: Britten Adams DAILY WELLSITE REPORT Armstrong Energy, LLC Horseshoe #1 CA,.NRIO Wildcat, North Slope Borough DRILLING TECHNOLOGY LTD_ Date: 2/8/2017 Time: 24:00:00 Operation: Drilling Depth:4841']Spud Report for: Wellsite Leader: Bob Lenhart Yesterday: 4750'Contractor: Doyon Drilling AK Armstrong Geologist: Colby Vandenburg Footage: 91' Date: 1/27/2017 CASING INFO 16" @ 118' 9 5/8" @ 2213' BIT INFORMATION INTERVAL TOTAL FOOTAGE On Bottom HOURS CONDITION CS / B / G REASON PULLED NO SIZE MAKE/TYPE S/N JETS IN OUT 1 12.25" VMD-3/HCC 5259382 16,3x8 118' 2230' 2112' 23.3 1,1,NO,A,3,1,NO,TD Casing 2 8.50 " Hycalog SKH519M-Ci 191314 7x12 2230' DIRECTIONAL TOOLS Baker Hughes AutoTrak, MWD/LWD tool, OnTrak-MWD, BCPM SURVEY DATA DEPTH INCL AZI TVD +N -S +E -W VS DLS 4501.99' 3.41 79.45 4321.48' 640.30' 617.48' 640.30' 4.78 4563.99' 0.58 87.92 4383.44' 640.65' 619.60' 640.65' 4.58 4627.06' 0.13 209.58 4446.51' 640.60' 619.89' 640.60' 1.04 4688.66' 0.04 188.99 4508.11' 640.51' 619.85' 640.51' 0.15 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG PENETRATION 88.2 @ 4801' 9.5 @ 4841' 47 10 ft/hr SURFACE TORQUE 6592 @ 4839' 516 @ 4751' 4671 3446 ft/lbs WEIGHT ON BIT 13 @ 4750' 1 @ 4751' 6 4 Klbs TOP DRIVE RPM 59 @ 4831' 34 @ 4751' 46 40 rpm PUMP PRESSURE 3010 @ 4750' 556 @ 4841' 1039 556 psi DRILLING MUD REPORT DEPTH: 2230' TYPE: Halliburton Baroid BASE: SBM FLOWLINE TEMP: 87°F MW VIS PV YP Gels HT FL Corr Sol Oil/H20 Alk POM CI- mg/L WPS Lime Stability 10.5 106 40 15 9/14/21 3.8 11.50 65.5/20.5 0 24.71 297781 5.57 659 LAG DATA Hole Cap String Cap String Disp Total Disp Ann Cap Strokes Surf to Surface Strokes to bit Strokes Bottoms Up DEPTH (bbls) (bbls) (bbls) (bbls) (bbls) Pump 1+2 Pump 3 Pump 1+2 Pump 3 Pump 1+2 Pump 3 4841' 341 53 30 83 258.0 6736 6736 1144 1144 5592 5592 GAS SUMMARY HIGH LOW AVERAGE UNITS DITCH GAS 47 @ 4793 3 @ 4750 39.8 CURRENT GAS = 25.11 CHROMATOGRAPHY(ppm) TRIP GAS = 0 WIPER GAS = 0 HIGH LOW AVERAGE SURVEY GAS = 0 METHANE(C-1) 27606 @ 4751' 3122 @ 4750' 9275 CONNECTION GAS MAX = 0 ETHANE(C-2) 1633 @ 4751' 128 @ 4750' 314 AVG = 0 PROPANE(C-3) 1117 @ 4751' 44 @ 4750' 123 CURRENT= 0 BUTANE(C-4) 1966 @ 4752' 14 @ 4750' 97 BACKGROUND GAS MAX = 47.6 PENTANE(C-5) 1996 @ 4752' 0 @ 4759' 78 AVG = 39.8 CURRENT= 25.1 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS UNITS DESCRIPTION 4750' TO 4841' Samples dominant with sandstone. 47u Silty sandstone with 50%-40% oil stains. TO LITHOLOGY (%) Sandstone Volcanic Ash Siltstone Tuffaceous Sandstone 7 FORMATION: 80% 0% 20% 0% Lwr Nanushuk FM 100% PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Continue to pull hole the hole from 3733'-680'MD. Monitor the well for 15 minutes. Pull up BHA and rack back. Clean rig floors and prepare for new coring BHA. Pre -job safety meeting and assemble coring BHA. Run in hole with coring tool and fill pipe continously. Drill to 4841'MD. Canrig Personnel On Board: Neubert, Adams, Wardner, Wiseman Daily Cost: $2,905 Report Completed by: Britten Adams DAILY WELLSITE REPORT Armstrong Energy, LLC Horseshoe #1 CA,.NR143 Wildcat, North Slope Borough DRILLING TECHNOLOGY LTD_ Date: 2/9/2017 Time: 24:00:00 Operation: Coring #2 Depth:4931']Spud Report for: Wellsite Leader: Bob Lenhart Yesterday: 4840'Contractor: Doyon Drilling AK Armstrong Geologist: Colby Vandenburg Footage: 91' Date: 1/27/2017 CASING INFO 16" @ 118' 9 5/8" @ 2213' BIT INFORMATION INTERVAL TOTAL On Bottom CONDITION REASON NO SIZE MAKE/TYPE S/N JETS IN OUT FOOTAGE HOURS CS / B / G PULLED 1 12.25" VMD-3/HCC 5259382 16,3x8 118' 2230' 2112' 23.3 1,1,NO,A,3,1,NO,TD Casing 2 8.50" HycalogSKH519M-Ci 191314 7x12 2230' 4750' 2520' 2,2,CT,M,X,I,BT,CP Core 3 8.50 " Haliburton FC3555 12614632 4750' 4840' 90' DIRECTIONAL TOOLS Baker Hughes AutoTrak, MWD/LWD tool, OnTrak-MWD, BCPM SURVEY DATA DEPTH INCL AZI TVD +N -S +E -W VS DLS 4501.99' 3.41 79.45 4321.48' 640.30' 617.48' 640.30' 4.78 4563.99' 0.58 87.92 4383.44' 640.65' 619.60' 640.65' 4.58 4627.06' 0.13 209.58 4446.51' 640.60' 619.89' 640.60' 1.04 4688.66' 0.04 188.99 4508.11' 640.51' 619.85' 640.51' 0.15 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENTAVG PENETRATION 84.6 @ 4843' 8.4 @ 4890' 51 53 ft/hr SURFACE TORQUE 7467 @ 4926' 180 @ 4843' 4703 5021 ft/lbs WEIGHT ON BIT 6 @ 4843' 2 @ 4844' 5 5 Klbs TOP DRIVE RPM 61 @ 4910' 1 @ 4843' 55 57 rpm PUMP PRESSURE 1436 @ 4906' 556 @ 4841' 1382 1387 psi DRILLING MUD REPORT DEPTH: 2230' TYPE: Halliburton Baroid BASE: SBM FLOWLINE TEMP: 87°F MW VIS PV YP Gels HT FL Corr Sol Oil/H20 Alk POM CI- mg/L WPS Lime Stability 10.55 145 44 22 9/17/26 3.8 13.30 64/20.5 0 25.68 277004 5.76 560 LAG DATA Hole Cap String Cap String Disp Total Disp Ann Cap Strokes Surf to Surface Strokes to bit Strokes Bottoms Up DEPTH (bbls) (bbls) (bbls) (bbls) (bbls) Pump 1+2 Pump 3 Pump 1+2 Pump 3 Pump 1+2 Pump 3 4931' 347 54 31 84 262.9 6864 6864 1165 1165 5699 5699 GAS SUMMARY HIGH LOW AVERAGE UNITS DITCH GAS 43 @ 4840 11 @ 4852 24.2 CURRENT GAS = 25.55 CHROMATOGRAPHY(ppm) TRIP GAS = 0 WIPER GAS = 0 HIGH LOW AVERAGE SURVEY GAS = 0 CONNECTION GAS MAX = 0 METHANE(C-1) 9149 @ 4840' 3111 @ 4847' 5044 ETHANE(C-2) 293 @ 4840' 102 @ 4844' 141 AVG = 0 PROPANE(C-3) 96 @ 4840' 36 @ 4844' 49 CURRENT= 0 BUTANE(C-4) 39 @ 4931' 12 @ 4914' 19 BACKGROUND GAS MAX = 43 PENTANE(C-5) 32 @ 4870' 0 @ 4926' 6 AVG = 24.2 CURRENT= 25.55 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS UNITS DESCRIPTION 4750' TO 4841' Samples dominant with sandstone. 47u Silty sandstone with 50%-40% oil stains. 4841' TO 4933' Decrease in sandstone. 43u Siltstone to shale dominant the lithology. LITHOLOGY (%) Sandstone Shale Siltstone Tuffaceous Sandstone FORMATION: 20% 20% 60% 0% LwrNanushuk FM 100% PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Pull out of hole and slowly back ream the borehole to 4750'MD. Begin to circulate bottoms up and work the pipe. Cut off pumps and pull out to 47'MD. Lay down cores as per haliburton rep and remove core. RIH back in the hole with coring tool to 4840'MD, and drill to 4931'MD. Canrig Personnel On Board: Neubert, Adams, Wardner, Wiseman Daily Cost: $2,905 Report Completed by: Britten Adams DAILY WELLSITE REPORT Armstrong Energy, LLC CA,.NR143 Horseshoe #1 Wildcat, North Slope Borough DRILLING TECHNOLOGY LTD_ Date: 2/10/2017 Operation: Coring #2 Time: 24:00:00 Depth:4931']Spud Report for: Wellsite Leader: Joe Steiner Yesterday: 4931'Contractor: Doyon Drilling AK Armstrong Geologist: Colby Vandenburg Footage: 0' Date: 1/27/2017 CASING INFO 16" @ 118' 9 5/8" @ 2213' BIT INFORMATION INTERVAL TOTAL On Bottom CONDITION REASON NO SIZE MAKE/TYPE S/N JETS IN OUT FOOTAGE HOURS CS / B / G PULLED 1 12.25" VMD-3/HCC 5259382 16,3x8 118' 2230' 2112' 23.3 1,1,NO,A,3,1,NO,TD Casing 2 8.50" HycalogSKH519M-Ci 191314 7x12 2230' 4750' 2520' 27.6 2,2,CT,M,X,I,BT,CP Core 3 8.50 " Haliburton FC3555 12614632 4750' 4840' 90' DIRECTIONAL TOOLS Baker Hughes AutoTrak, MWD/LWD tool, OnTrak-MWD, BCPM SURVEY DATA DEPTH INCL AZI TVD +N -S +E -W VS DLS DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG PENETRATION 0 @ 0 @ 0 0 ft/hr SURFACE TORQUE 0 @ 0 @ 0 0 ft/lbs WEIGHT ON BIT 0 @ 0 @ 0 0 Klbs TOP DRIVE RPM 0 @ 0 @ 0 0 rpm PUMP PRESSURE 0 @ 0 @ 0 0 psi DRILLING MUD REPORT DEPTH: 2230' TYPE: Halliburton Baroid BASE: SBM FLOWLINE TEMP: 0°F MW VIS PV YP Gels HT FL Corr Sol Oil/H20 Alk POM CI- mg/L WPS Lime Stability 10.75 128 42 18 10/18/24 3.8 13.30 64/20.5 0 24.71 277378 5.7 548 LAG DATA Hole Cap String Cap String Disp Total Disp Ann Cap Strokes Surf to Surface Strokes to bit Strokes Bottoms Up DEPTH (bbls) (bbls) (bbls) (bbls) (bbls) Pump 1+2 Pump 3 Pump 1+2 Pump 3 Pump 1+2 Pump 3 4931' 347 54 31 84 262.9 6864 6864 1165 1165 5699 5699 GAS SUMMARY HIGH LOW AVERAGE UNITS DITCH GAS 0 @ 0 0 @ 0 0 CURRENT GAS = 0 CHROMATOGRAPHY(ppm) TRIP GAS = 0 WIPER GAS = 0 HIGH LOW AVERAGE SURVEY GAS = 0 METHANE(C-1) 0 @ 0 @ 0 CONNECTION GAS MAX = 0 ETHANE(C-2) 0 @ 0 @ 0 AVG = 0 PROPANE(C-3) 0 @ 0 @ 0 CURRENT= 0 CIRCULATING GAS MAX = 0 BUTANE(C-4) 0 @ 0 @ 0 PENTANE(C-5) 0 @ 0 @ 0 AVG = 0 CURRENT= 0 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS UNITS DESCRIPTION 4750' TO 4841' Samples dominant with sandstone. 47u Silty sandstone with 50%-40% oil stains. 4841' TO 4933' Decrease in sandstone. 43u Siltstone to shale dominant the lithology. LITHOLOGY (%) Sandstone ShaleSiltstone Tuffaceous Sandstone FORMATION: 10% 40% 50% 0% Lwr Nanushuk FM 100% PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Back ream and pump out of hole from 4931'-3530'MD. Start pulling with elevator from 3530'-300'MD. Lay down core barrels. Clean rig floors and monitor well. Build new BHA and begin to run in hole. Canrig Personnel On Board: Neubert, Adams, Wardner, Wiseman Daily Cost: $2,905 Report Completed by: Britten Adams DAILY WELLSITE REPORT Armstrong Energy, LLC Horseshoe #1 Wildcat, North Slope Borough Date: 2/11/2017 Time: 24:00:00 Depth:5720']Spud Operation: Drilling Ahead Report for: Wellsite Leader: Joe Steiner Yesterday: 4931'Contractor: Doyon Drilling AK Armstrong Geologist: Colby Vandenburg Footage: 789' Date: 1/27/2017 CASING INFO 16" @ 118' 9 5/8" @ 2213' BIT INFORMATION INTERVAL TOTAL FOOTAGE On Bottom HOURS CONDITION CS/B/G REASON PULLED NO SIZE MAKE/TYPE S/N JETS IN OUT 1 12.25" VMD-3/HCC 5259382 16,3x8 118' 2230' 2112' 23.3 1,1,NO,A,3,1,NO,TD Casing 2 8.50 " Hycalog SKH519M-C1 191314 7x12 2230' 4750' 2520' 27.6 2,2,CT,M,X,I,BT,CP Core 3-CB1 8.50 " Haliburton FC3555 12614632 4750' 4931' 181' 5.2 4 8.50" Reed Hycalog A191313 7x12 4931' DIRECTIONAL TOOLS Baker Hughes AutoTrak, MWD/LWD tool, OnTrak-MWD, BCPM SURVEY DATA DEPTH INCL AZI TVD +N -S +E -W VS DLS 5503.66' 0.39 209.31 5323.10' 639.40' 617.76' 639.40' 0.10 5566.26' 0.26 223.26 5385.70' 639.11' 617.55' 639.11' 0.24 5627.48' 0.26 205.71 5446.92' 638.88' 617.40' 638.88' 0.13 5688.69' 0.21 212.26 5508.13' 638.66' 617.28' 638.66' 0.09 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG PENETRATION 166.8 @ 5659' 15.9 @ 4934' 93 96 ft/hr SURFACE TORQUE 6560 @ 5710' 0 @ 4933' 4444 5352 ft/lbs WEIGHT ON BIT 11 @ 5720' 2 @ 5410' 10 12 Klbs TOP DRIVE RPM 103 @ 5123' 17 @ 4933' 96 99 rpm PUMP PRESSURE 3453 @ 5537' 14 @ 4933' 3270 3358 psi DRILLING MUD REPORT DEPTH: 2230' TYPE: Halliburton Baroid BASE: SBM FLOWLINE TEMP: 104°F MW VIS PV YIP Gels HT FL Corr Sol Oil/H20 Alk POM CI- mg/L WPS Lime Stability 10.4 71 31 15 8/13/19 4 12.60 66/19 0 19.37 290436 5.37 1025 LAG DATA Hole Cap String Cap String Disp Total Disp Ann Cap Strokes Surf to Surface Strokes to bit Strokes Bottoms Up DEPTH (bbls) (bbls) (bbls) (bbls) (bbls) Pump 1+2 Pump 3 Pump 1+2 Pump 3 Pump 1+2 Pump 3 5720' 403 59 33 92 311.0 8021 8021 1282 1282 6740 6740 GAS SUMMARY HIGH LOW AVERAGE UNITS DITCH GAS 27 @ 4931 3 @ 4933 14.3 CURRENT GAS = 20 CHROMATOGRAPHY(ppm) TRIP GAS = 23 WIPER GAS = 0 HIGH LOW AVERAGE SURVEY GAS = 0 METHANE(C-1) 5666 @ 4931' 236 @ 4933' 2858 CONNECTION GAS MAX = 7 ETHANE(C-2) 152 @ 4931' 18 @ 4976' 45 AVG = 1 PROPANE(C-3) 52 @ 4931' 10 @ 5341' 22 CURRENT= 0 BUTANE(C-4) 39 @ 4931' 39 @ 4931' 0 BACKGROUND GAS MAX = 27 PENTANE(C-5) 7 @ 4931' 7 @ 4931' 0 AVG = 14 CURRENT= 20 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS UNITS DESCRIPTION TO TO LITHOLOGY (%) Shale Sandstone Siltstone Tuffaceous Sandstone 7 FORMATION: 70% 10% 20% 0% Lwr Nanushuk FM 100% PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Trip in hole from 1301'MD to 4930'MD. Drill ahead to 5720'MD and continue to drill ahead. Canrig Personnel On Board: Neubert, Adams, Wardner, Wiseman Daily Cost: $2,905 Report Completed by: Britten Adams DAILY WELLSITE REPORT Armstrong Energy, LLC Horseshoe #1 Wildcat, North Slope Borough Date: 2/12/2017 Time: 24:00:00 Depth:Operation: Drilling Ahead Report for: Wellsite Leader: Joe Steiner Yesterday:15] Contractor: Doyon Drilling AK Armstrong Geologist: Colby Vandenburg Footage: Spud Date: 1/27/2017 CASING INFO 16" @ 118' 9 5/8" @ 2213' BIT INFORMATION INTERVAL TOTAL FOOTAGE On Bottom HOURS CONDITION CS/B/G REASON PULLED NO SIZE MAKE/TYPE S/N JETS IN OUT 1 12.25" VMD-3/HCC 5259382 16,3x8 118' 2230' 2112' 23.3 1,1,NO,A,3,1,NO,TD Casing 2 8.50 " Hycalog SKH519M-C1 191314 7x12 2230' 4750' 2520' 27.6 2,2,CT,M,X,I,BT,CP Core 3-CB1 8.50 " Haliburton FC3555 12614632 4750' 4931' 181' 5.2 TD 4 8.50" Reed Hycalog A191313 7x12 1 4931' 1 6000' 1 1069' 11.6 2,1,CT,M,X,I,BT,TD TD DIRECTIONAL TOOLS Baker Hughes AutoTrak, MWD/LWD tool, OnTrak-MWD, BCPM SURVEY DATA DEPTH INCL AZI TVD +N -S +E -W VS DLS 5875.88' 0.10 251.93 5695.32' 638.27' 617.08' 887.79' 0.07 5940.37' 0.18 262.16 5759.81' 638.24' 616.93' 887.66' 0.13 5971.89' 0.26 259.35 5791.33' 638.22' 616.81' 887.56' 0.27 6000.00' 0.26 259.35 5819.44' 638.19' 616.68' 887.46' 0.00 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG PENETRATION 162.9 @ 5849' 23 @ 5972' 104 56 ft/hr SURFACE TORQUE 8120 @ 5928' 2204 @ 5972' 5422 4023 ft/lbs WEIGHT ON BIT 11 @ 5720' 2 @ 5909' 10 8 Klbs TOP DRIVE RPM 122 @ 5774' 91 @ 5961' 108 99 rpm PUMP PRESSURE 3583 @ 5930' 1705 @ 5842' 3450 3413 psi DRILLING MUD REPORT DEPTH: 2230' TYPE: Halliburton Baroid BASE: SBM FLOWLINE TEMP: 104°F MW VIS PV YIP Gels HT FL Corr Sol Oil/1120 Alk POM CI- mg/L WPS Lime Stability 10.45 74 31 16 8/13/18 3.8 12.70 66/19 0 18.88 288891 5.18 968 LAG DATA Hole Cap String Cap String Disp Total Disp Ann Cap Strokes Surf to Surface Strokes to bit Strokes Bottoms Up DEPTH (bbls) (bbls) (bbls) (bbls) (bbls) Pump 1+2 Pump 3 Pump 1+2 Pump 3 Pump 1+2 Pump 3 6000' 422 62 34 96 326.3 8419 8419 1347 1347 7071 7071 GAS SUMMARY HIGH LOW AVERAGE UNITS DITCH GAS 23 @ 5825 10 @ 5972 16.2 CURRENT GAS = 0 CHROMATOGRAPHY(ppm) TRIP GAS = 11 WIPER GAS = 0 HIGH LOW AVERAGE SURVEY GAS = 0 METHANE(C-1) 4924 @ 5825' 1005 @ 5860' 3156 CONNECTION GAS MAX = 2 ETHANE(C-2) 69 @ 5825' 26 @ 5861' 46 AVG = 0 PROPANE(C-3) 50 @ 5880' 8 @ 5999' 26 CURRENT= 0 BUTANE(C-4) 0 @ 6000' 0 @ 6000' 0 BACKGROUND GAS MAX = 23 PENTANE(C-5) 0 @ 6000' 0 @ 6000' 0 AVG = 16.2 CURRENT= 0 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS UNITS DESCRIPTION TO TO LITHOLOGY (%) Shale Sandstone Siltstone Tuffaceous Sandstone 7 FORMATION: 90% 10% 0% 0% Lwr Nanushuk FM 100% PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Continue drill to 6000'MD. Circulate bottom up and pump a sweep. Pull out of hole from 6000'-4667'MD and monitor the hole. Condition mud and cirulate sweep around until hole is clean. Pump dry job and continue to pull out to 675'MD. Lay down BHA and HWDP. Rig up to test BOP stack. Test the BOP stack and test is completed. Prepare for Schlumberger wireline tools. Canrig Personnel On Board: Neubert, Adams, Wardner, Wiseman Daily Cost: $2,905 Report Completed by: Britten Adams Armstrong Energy, LLC DAILY WELLSITE REPORT Horseshoe #1 cj" Io Wildcat, North Slope Borough DRILLING TECHNOLOGY L,Tn_ Date: 2/13/2017 Time: 24:00:00 Depth:6000']Spud Operation: Drilling Ahead Report for: Wellsite Leader: Joe Steiner Yesterday: 6000'Contractor: Doyon Drilling AK Armstrong Geologist: Colby Vandenburg Footage: 0' Date: 1/27/2017 CASING INFO 16" @ 118' 9 5/8" @ 2213' BIT INFORMATION INTERVAL TOTAL FOOTAGE On Bottom HOURS CONDITION CS / B / G REASON PULLED NO SIZE MAKE/TYPE S/N JETS IN OUT 1 12.25" VMD-3/HCC 5259382 16,3x8 118' 2230' 2112' 23.3 1,1,NO,A,3,1,NO,TD Casing 2 8.50 " Hycalog SKH519M-C1 191314 7x12 2230' 4750' 2520' 27.6 2,2,CT,M,X,I,BT,CP Core 3-CB1 8.50 " Haliburton FC3555 12614632 4750' 4931' 181' 5.2 TD 4 8.50" Reed Hycalog A191313 7x12 4931' 6000' 1069' 11.6 2,1,CT,M,X,I,BT,TD TD DIRECTIONAL TOOLS Baker Hughes AutoTrak, MWD/LWD tool, OnTrak-MWD, BCPM SURVEY DATA DEPTH INCL AZI TVD +N -S +E -W VS DLS DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG PENETRATION 0 @ 0 @ 0 0 ft/hr SURFACE TORQUE 0 @ 0 @ 0 0 ft/lbs WEIGHT ON BIT 0 @ 0 @ 0 0 Klbs TOP DRIVE RPM 0 @ 0 @ 0 0 rpm PUMP PRESSURE 0 @ 0 @ 0 0 psi DRILLING MUD REPORT DEPTH: 2230' TYPE: Halliburton I Baroid BASE: SBM FLOWLINE TEMP: 104°F MW VIS PV YP Gels HT FL Corr Sol Oil/H20 Alk POM CI- mg/L WPS Lime Stability 10.4 100 31 17 9/15/22 3.8 12.70 66/19 0 17.91 285920 5.18 9.7 LAG DATA Hole Cap String Cap String Disp Total Disp Ann Cap Strokes Surf to Surface Strokes to bit Strokes Bottoms Up DEPTH (bbls) (bbls) (bbls) (bbls) (bbls) Pump 1+2 Pump 3 Pump 1+2 Pump 3 Pump 1+2 Pump 3 6000' 422 62 34 96 326.3 8419 8419 1347 1347 7071 7071 GAS SUMMARY HIGH LOW AVERAGE UNITS DITCH GAS 0 @ 0 0 @ J 0 CURRENT GAS = 0 CHROMATOGRAPHY(ppm) TRIP GAS = 0 WIPER GAS = 0 HIGH LOW AVERAGE SURVEY GAS = 0 METHANE(C-1) 0 @ 0 @ 0 CONNECTION GAS MAX= 0 ETHANE(C-2) 0 @ 0 @ 0 AVG = 0 PROPANE(C-3) 0 @ 0 @ 0 CURRENT— 0 BUTANE(C-4) 0 @ 0 @ 0 CIRCULATING GAS MAX = 0 PENTANE(C-5) 0 @ 0 @ 0 AVG = 0 CURRENT= 0 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS UNITS DESCRIPTION TO TO LITHOLOGY (%) Shale Sandstone 770% Siltstone Tuffaceous Sandstone FORMATION: 0% 0% Lwr Nanushuk FM 0% PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Move up wireline tools and run in the hole to log borehole. Complete #143 logs and start on #4 log. Canrig Personnel On Board: Neubert, Adams, Wardner, Wiseman Daily Cost: $2,905 Report Completed by: Britten Adams Armstrong Energy, LLC DAILY WELLSITE REPORT Horseshoe #1 cj" Io Wildcat, North Slope Borough DRILLING TECHNOLOGY L,Tn_ Date: 2/14/2017 Time: 24:00:00 Depth:6000']Spud Operation: Drilling Ahead Report for: Wellsite Leader: Joe Steiner Yesterday: 6000'Contractor: Doyon Drilling AK Armstrong Geologist: Colby Vandenburg Footage: 0' Date: 1/27/2017 CASING INFO 16" @ 118' 9 5/8" @ 2213' BIT INFORMATION INTERVAL TOTAL FOOTAGE On Bottom HOURS CONDITION CS / B / G REASON PULLED NO SIZE MAKE/TYPE S/N JETS IN OUT 1 12.25" VMD-3/HCC 5259382 16,3x8 118' 2230' 2112' 23.3 1,1,NO,A,3,1,NO,TD Casing 2 8.50 " Hycalog SKH519M-C1 191314 7x12 2230' 4750' 2520' 27.6 2,2,CT,M,X,I,BT,CP Core 3-CB1 8.50 " Haliburton FC3555 12614632 4750' 4931' 181' 5.2 TD 4 8.50" Reed Hycalog A191313 7x12 4931' 6000' 1069' 11.6 2,1,CT,M,X,I,BT,TD TD DIRECTIONAL TOOLS Baker Hughes AutoTrak, MWD/LWD tool, OnTrak-MWD, BCPM SURVEY DATA DEPTH INCL AZI TVD +N -S +E -W VS DLS DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG PENETRATION 0 @ 0 @ 0 0 ft/hr SURFACE TORQUE 0 @ 0 @ 0 0 ft/lbs WEIGHT ON BIT 0 @ 0 @ 0 0 Klbs TOP DRIVE RPM 0 @ 0 @ 0 0 rpm PUMP PRESSURE 0 @ 0 @ 0 0 psi DRILLING MUD REPORT DEPTH: 2230' TYPE: Halliburton I Baroid BASE: SBM FLOWLINE TEMP: 104°F MW VIS PV YP Gels HT FL Corr Sol Oil/H20 Alk POM CI- mg/L WPS Lime Stability 10.45 102 30 17 9/15/22 4 12.70 66/19 0 17.91 285920 5.31 901 LAG DATA Hole Cap String Cap String Disp Total Disp Ann Cap Strokes Surf to Surface Strokes to bit Strokes Bottoms Up DEPTH (bbls) (bbls) (bbls) (bbls) (bbls) Pump 1+2 Pump 3 Pump 1+2 Pump 3 Pump 1+2 Pump 3 6000' 422 62 34 96 326.3 8419 8419 1347 1347 7071 7071 GAS SUMMARY HIGH LOW AVERAGE UNITS DITCH GAS 0 @ 0 0 @ J 0 CURRENT GAS = 0 CHROMATOGRAPHY(ppm) TRIP GAS = 0 WIPER GAS = 0 HIGH LOW AVERAGE SURVEY GAS = 0 METHANE(C-1) 0 @ 0 @ 0 CONNECTION GAS MAX= 0 ETHANE(C-2) 0 @ 0 @ 0 AVG = 0 PROPANE(C-3) 0 @ 0 @ 0 CURRENT— 0 BUTANE(C-4) 0 @ 0 @ 0 CIRCULATING GAS MAX = 0 PENTANE(C-5) 0 @ 0 @ 0 AVG = 0 CURRENT= 0 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS UNITS DESCRIPTION TO TO LITHOLOGY (%) Shale Sandstone 770% Siltstone Tuffaceous Sandstone FORMATION: 0% 0% Lwr Nanushuk FM 0% PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Continue to wireline the borehole and maintenance the rig. Canrig Personnel On Board: Neubert, Adams, Wardner, Wiseman Daily Cost: $2,905 Report Completed by: Britten Adams Armstrong Energy, LLC DAILY WELLSITE REPORT Horseshoe #1 cj" Io Wildcat, North Slope Borough DRILLING TECHNOLOGY L,Tn- Date: 2/15/2017 Time: 24:00:00 Depth:6000']Spud Operation: Drilling Ahead Report for: Wellsite Leader: Joe Steiner Yesterday: 6000'Contractor: Doyon Drilling AK Armstrong Geologist: Colby Vandenburg Footage: 0' Date: 1/27/2017 CASING INFO 16" @ 118' 9 5/8" @ 2213' BIT INFORMATION INTERVAL TOTAL FOOTAGE On Bottom HOURS CONDITION CS / B / G REASON PULLED NO SIZE MAKE/TYPE S/N JETS IN OUT 1 12.25" VMD-3/HCC 5259382 16,3x8 118' 2230' 2112' 23.3 1,1,NO,A,3,1,NO,TD Casing 2 8.50 " Hycalog SKH519M-C1 191314 7x12 2230' 4750' 2520' 27.6 2,2,CT,M,X,I,BT,CP Core 3-CB1 8.50 " Haliburton FC3555 12614632 4750' 4931' 181' 5.2 TD 4 8.50" Reed Hycalog A191313 7x12 4931' 6000' 1069' 11.6 2,1,CT,M,X,I,BT,TD TD DIRECTIONAL TOOLS Baker Hughes AutoTrak, MWD/LWD tool, OnTrak-MWD, BCPM SURVEY DATA DEPTH INCL AZI TVD +N -S +E -W VS DLS DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG PENETRATION 0 @ 0 @ 0 0 ft/hr SURFACE TORQUE 0 @ 0 @ 0 0 ft/lbs WEIGHT ON BIT 0 @ 0 @ 0 0 Klbs TOP DRIVE RPM 0 @ 0 @ 0 0 rpm PUMP PRESSURE 0 @ 0 @ 0 0 psi DRILLING MUD REPORT DEPTH: 2230' TYPE: Halliburton I Baroid BASE: SBM FLOWLINE TEMP: 104°F MW VIS PV YP Gels HT FL Corr Sol Oil/H20 Alk POM CI- mg/L WPS Lime Stability 10.45 110 34 17 9/14/20 3.6 12.70 66/19 0 17.91 285920 5.7 814 LAG DATA Hole Cap String Cap String Disp Total Disp Ann Cap Strokes Surf to Surface Strokes to bit Strokes Bottoms Up DEPTH (bbls) (bbls) (bbls) (bbls) (bbls) Pump 1+2 Pump 3 Pump 1+2 Pump 3 Pump 1+2 Pump 3 6000' 422 62 34 96 326.3 8419 8419 1347 1347 7071 7071 GAS SUMMARY HIGH LOW AVERAGE UNITS DITCH GAS 0 @ 0 0 @ J 0 CURRENT GAS = 0 CHROMATOGRAPHY(ppm) TRIP GAS = 0 WIPER GAS = 0 HIGH LOW AVERAGE SURVEY GAS = 0 METHANE(C-1) 0 @ 0 @ 0 CONNECTION GAS MAX= 0 ETHANE(C-2) 0 @ 0 @ 0 AVG = 0 PROPANE(C-3) 0 @ 0 @ 0 CURRENT— 0 BUTANE(C-4) 0 @ 0 @ 0 CIRCULATING GAS MAX = 0 PENTANE(C-5) 0 @ 0 @ 0 AVG = 0 CURRENT= 0 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS UNITS DESCRIPTION TO TO LITHOLOGY (%) Shale Sandstone 770% Siltstone Tuffaceous Sandstone FORMATION: 0% 0% Lwr Nanushuk FM 0% PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Continue logging with wireline tools. Finish tool #4 wireline, and start on #5 core side-wall run. Begin loading pipe shed with 3.50" tubing. Completed #5 run and lay down core from run #5. Start to strap 3.50" for tally sheet. Canrig Personnel On Board: Neubert, Adams, Wardner, Wiseman Daily Cost: $2,905 Report Completed by: Britten Adams Armstrong Energy, LLC DAILY WELLSITE REPORT Horseshoe #1 cj" Io Wildcat, North Slope Borough DRILLING TECHNOLOGY L,Tn_ Date: 2/16/2017 Time: 24:00:00 Depth:6000']Spud Operation: Drilling Ahead Report for: Wellsite Leader: Joe Steiner Yesterday: 6000'Contractor: Doyon Drilling AK Armstrong Geologist: Colby Vandenburg Footage: 0' Date: 1/27/2017 CASING INFO 16" @ 118' 9 5/8" @ 2213' BIT INFORMATION INTERVAL TOTAL FOOTAGE On Bottom HOURS CONDITION CS / B / G REASON PULLED NO SIZE MAKE/TYPE S/N JETS IN OUT 1 12.25" VMD-3/HCC 5259382 16,3x8 118' 2230' 2112' 23.3 1,1,NO,A,3,1,NO,TD Casing 2 8.50 " Hycalog SKH519M-C1 191314 7x12 2230' 4750' 2520' 27.6 2,2,CT,M,X,I,BT,CP Core 3-CB1 8.50 " Haliburton FC3555 12614632 4750' 4931' 181' 5.2 TD 4 8.50" Reed Hycalog A191313 7x12 4931' 6000' 1069' 11.6 2,1,CT,M,X,I,BT,TD TD DIRECTIONAL TOOLS Baker Hughes AutoTrak, MWD/LWD tool, OnTrak-MWD, BCPM SURVEY DATA DEPTH INCL AZI TVD +N -S +E -W VS DLS DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG PENETRATION 0 @ 0 @ 0 0 ft/hr SURFACE TORQUE 0 @ 0 @ 0 0 ft/lbs WEIGHT ON BIT 0 @ 0 @ 0 0 Klbs TOP DRIVE RPM 0 @ 0 @ 0 0 rpm PUMP PRESSURE 0 @ 0 @ 0 0 psi DRILLING MUD REPORT DEPTH: 2230' TYPE: Halliburton I Baroid BASE: SBM FLOWLINE TEMP: 104°F MW VIS PV YP Gels HT FL Corr Sol Oil/H20 Alk POM CI- mg/L WPS Lime Stability 10.5 122 29 15 9/14/20 4 12.70 66/19 0 17.91 285920 5.57 845 LAG DATA Hole Cap String Cap String Disp Total Disp Ann Cap Strokes Surf to Surface Strokes to bit Strokes Bottoms Up DEPTH (bbls) (bbls) (bbls) (bbls) (bbls) Pump 1+2 Pump 3 Pump 1+2 Pump 3 Pump 1+2 Pump 3 6000' 422 62 34 96 326.3 8419 8419 1347 1347 7071 7071 GAS SUMMARY HIGH LOW AVERAGE UNITS DITCH GAS 0 @ 0 0 @ J 0 CURRENT GAS = 0 CHROMATOGRAPHY(ppm) TRIP GAS = 0 WIPER GAS = 0 HIGH LOW AVERAGE SURVEY GAS = 0 METHANE(C-1) 0 @ 0 @ 0 CONNECTION GAS MAX= 0 ETHANE(C-2) 0 @ 0 @ 0 AVG = 0 PROPANE(C-3) 0 @ 0 @ 0 CURRENT— 0 BUTANE(C-4) 0 @ 0 @ 0 CIRCULATING GAS MAX = 1691 PENTANE(C-5) 0 @ 0 @ 0 AVG = 0 CURRENT= 0 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS UNITS DESCRIPTION TO TO LITHOLOGY (%) Shale Sandstone 770% Siltstone Tuffaceous Sandstone FORMATION: 0% 0% Lwr Nanushuk FM 0% PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Finish running in 3.50" tubing. Prepare for Halliburton cementers. PJSM and start the cement job on borehole. Canrig Personnel On Board: Neubert, Adams, Wardner, Wiseman Daily Cost: $2,905 Report Completed by: Britten Adams Company Armstrong Energy, LLC Well Horseshoe 1 Section: 8.5in Field Wildcat Rig / Drillship Arctic Fox State Alaska Country USA Report by W/L: M. Reiter/C. Elowe SIS: J. EI-Khoury/V. Lopes Reviewed By Ken Moelhoff Logging Date 14 -Feb -2017 Report Date 17 -Feb -2017 Run Number R2D4 Job Number DS -2017-04959 This page left intentionally blank Horseshoe 1 Schlumberger Schlumberger DISCLAIMER ANY INTERPRETATION, RESEARCH, ANALYSIS, DATA, RESULTS, ESTIMATES, OR RECOMMENDATION FURNISHED WITH THE SERVICES OR OTHERWISE COMMUNICATED BY SCHLUMBERGER TO CUSTOMER AT ANY TIME IN CONNECTION WITH THE SERVICES ARE OPINIONS BASED ON INFERENCES FROM MEASUREMENTS, EMPIRICAL RELATIONSHIPS AND/OR ASSUMPTIONS, WHICH INFERENCES, EMPIRICAL RELATIONSHIPS AND/OR ASSUMPTIONS ARE NOT INFALLIBLE, AND WITH RESPECT TO WHICH PROFESSIONALS IN THE INDUSTRY MAY DIFFER. ACCORDINGLY, SCHLUMBERGER CANNOT AND DOES NOT WARRANT THE ACCURACY, CORRECTNESS OR COMPLETENESS OF ANY SUCH INTERPRETATION, RESEARCH, ANALYSIS, DATA, RESULTS, ESTIMATES OR RECOMMENDATION. CUSTOMER ACKNOWLEDGES THAT IT IS ACCEPTING THE SERVICES "AS IS", THAT SCHLUMBERGER MAKES NO REPRESENTATION OR WARRANTY, EXPRESS OR IMPLIED, OF ANY KIND OR DESCRIPTION IN RESPECT THERETO. SPECIFICALLY, CUSTOMER ACKNOWLEDGES THAT SCHLUMBERGER DOES NOT WARRANT THAT ANY INTERPRETATION, RESEARCH, ANALYSIS, DATA, RESULTS, ESTIMATES, OR RECOMMENDATION IS FIT FOR A PARTICULAR PURPOSE, INCLUDING BUT NOT LIMITED TO COMPLIANCE WITH ANY GOVERNMENT REQUEST OR REGULATORY REQUIREMENT. CUSTOMER FURTHER ACKNOWLEDGES THAT SUCH SERVICES ARE DELIVERED WITH THE EXPLICIT UNDERSTANDING AND AGREEMENT THAT ANY ACTION TAKEN BASED ON THE SERVICES RECEIVED SHALL BE AT ITS OWN RISK AND RESPONSIBILITY AND NO CLAIM SHALL BE MADE AGAINST SCHLUMBERGER AS A CONSEQUENCE THEREOF. Horseshoe 1 3 Schlumberger 1 EXECUTIVE SUMMARY.............................................................................................................................................................5 2 INTERPRETATION SUMMARY...................................................................................................................................................7 2.1 INTRODUCTION.................................................................................................................................................................................. 7 2.2 FIELD REMARKS: R2D4.......................................................................................................................................................................7 2.2.1 Depth Control Remarks...........................................................................................................................................................7 2.3 INTERPRETATION BY ZONE....................................................................................................................................................................7 2.3.1 Zone 1.....................................................................................................................................................................................7 2.3.2 Zone 2..................................................................................................................................................................................... 7 2.3.3 Zone 3..................................................................................................................................................................................... 7 2.3.4 Zone 4..................................................................................................................................................................................... 7 2.3.5 Zone 5..................................................................................................................................................................................... 7 2.4 RECOMMENDATIONS..........................................................................................................................................................................8 2.5 FORMATION ZONE TABLE....................................................................................................................................................................8 2.6 CONTACT INFORMATION......................................................................................................................................................................8 3 FLUID AND SAMPLING SUMMARY............................................................................................................................................9 3.1 SAMPLING AND FLUIDS PROFILING SUMMARY TABLE................................................................................................................................9 3.2 FLUID ANALYSIS RESULTS TABLE............................................................................................................................................................9 4 FLUID GRADIENT....................................................................................................................................................................10 5 PRESSURE RESULTS................................................................................................................................................................11 5.1 PRETEST SUMMARY TABLE.................................................................................................................................................................11 5.1.1 Formation Pressure Quality Grading Description.................................................................................................................11 5.2 TEST POINT TABLE............................................................................................................................................................................12 6 PRESSURE VS. DEPTH VIEWS..................................................................................................................................................14 6.1 DEPTH OVERVIEW BY QUALITY........................................................................................................................................................... 14 6.2 ZONE 1..........................................................................................................................................................................................15 6.3 ZONE 2..........................................................................................................................................................................................16 6.4 ZONE 3 AND ZONE 4......................................................................................................................................................................... 17 6.5 ZONE 5..........................................................................................................................................................................................18 7 DOWNHOLE FLUID ANALYSIS AND SAMPLING........................................................................................................................19 7.1 CONPR_R02_STA021_MDT_EDTA4770.96FTMD.........................................................................................................................19 7.1.1 Standard Cross Plot (0 min - 414.21 min)............................................................................................................................. 20 7.1.2 LFA Cross Plot (0 min - 414.21 min)...................................................................................................................................... 21 7.2 CONPR_R02_STA024_MDT-EDTA 4760.69FTMD.........................................................................................................................22 7.2.1 Standard Cross Plot (0 min - 579.23 min).............................................................................................................................23 7.2.2 LFA Cross Plot (0 min - 579.23 min)...................................................................................................................................... 24 7.3 CONPR_R02_STA025_MDT-EDTA 4571.02FTMD.........................................................................................................................25 7.3.1 Standard Cross Plot (0 min - 203.69 min)............................................................................................................................. 26 7.3.2 LFA Cross Plot (0 min - 203.69 min)...................................................................................................................................... 27 7.4 CONPR_R02_STA026_MDT-EDTA 4514.79FTMID .........................................................................................................................28 7.4.1 Standard Cross Plot (0 min - 198.83 min)............................................................................................................................. 29 7.4.2 LFA Cross Plot (0 min - 198.83 min)...................................................................................................................................... 30 8 PRESSURE TRANSIENT ANALYSIS............................................................................................................................................31 9 RESERVOIR FLUID GEODYNAMICS (RFG) CONNECTIVITY EVALUATION...................................................................................32 10 WELL AND JOB DATA..............................................................................................................................................................34 10.1 WELL HEADER..............................................................................................................................................................................34 10.1.1 Well Header Table............................................................................................................................................................. 35 10.2 TOOL STRING...............................................................................................................................................................................37 10.3 WELL SURVEY TABLE.....................................................................................................................................................................38 11 LITERATURE............................................................................................................................................................................42 11.1.1 Excess Pressure Example....................................................................................................................................................43 Horseshoe 1 4 Schlumberger Executive Summary This report presents the evaluation and interpretation of the MDT pretest and sampling data from the 8.5in section of the Horseshoe 1 well. MDT R2D4 toolstring was configured with an extra -large diameter (XLD) probe mainly for pressure acquisition fitted with a crystal quartz gauge (CQG). A dual packer fitted with a CQG was installed in the toolstring. The dual packer was mainly used for sampling in low permeability formations. A Live Fluid Analyzer (LFA) was the downhole fluid analyzer (DFA) used during the run. The toolstring included two pump out modules, which consisted of a standard pump and an extra -high pressure pump. a total of eight (8) 420cc non -compensated bottles (MPSR) and four (4) 235cc compensated bottles (SPMC) were installed in two multi -sample carriers. A total of twenty one (21) pretests were acquired (including post pumping pretests). That resulted in seven (7) high quality, four (4) medium quality and two (2) low quality formation pressures as well as three (3) tight tests, three (3) dry tests, one (1) pumping only station and two (2) unstabilized tests. One pressure gradient of 0.401 psi/ft (0.926 g/cm3) was interpreted using five (5) high quality and two (2) medium quality formation pressures in zone 5 - refer to section 2.5, Formation Zone Table. Two (2) unsuccessful pump out stations were attempted with the XLD probe. The station was aborted due to the high- pressure differential that was generated. Consequently, the dual packer was used to move fluid from the formation and capture samples for analysis. A total of seven (7) samples were captured during the acquisition and were transported to the lab for further analysis. * Computed GOR was used as a cleanup tool and is not listed in the table above. The oil GOR is out of the sensor's specification range. Below is the 2-D spectrum of the fluids identified during the acquisition 0 O 5.0 4.5 4.0 35 3.6 tar 2.6 1S 1.4 0.5 -0.5 Multiple Stations 2D Spectrum Plot 0 Horseshoe 1_R2D4_21 LFA_Ma4776.95R • Horseshoe 1 R2D4 24 LFA F.'❑47K.3?R 0 Horseshoe 1_R2D4_25_LFA _F,'C4571.-•2ft Horseshoe 1 R2D4 28 LF.4 MD4514.79R Wave Length (nm) Horseshoe 1 5 Run File Flowline Flowline Contamination Water Oil No. Zone MD (ft) TVD (ft) TVDss (ft) Press. Temp. Comments No. No. o (�o) Frac. Frac. (psia) (degF) 1 Zone 5 R2D4 21 4770.95 4590.40 -4548.30 1028.237 119.61 -25 0.00 1.00 Heavy Oil. 2 1 Zone 51 R2D4 24 14760.69 4580.14 -4538.04 11534.928 120.19 -20 0.00 11.00 Heavy Oil. 3 Zone 4 R2D4 25 4571.02 4390.48 -4348.38 1136.829 117.31 na 0.91 0.09 Water. Mainly water with traces of 4 Zone 3 R2D4 26 4514.79 4334.26 -4292.16 829.663 115.49 na 0.58 0.42 mud filtrate and potential oil. * Computed GOR was used as a cleanup tool and is not listed in the table above. The oil GOR is out of the sensor's specification range. Below is the 2-D spectrum of the fluids identified during the acquisition 0 O 5.0 4.5 4.0 35 3.6 tar 2.6 1S 1.4 0.5 -0.5 Multiple Stations 2D Spectrum Plot 0 Horseshoe 1_R2D4_21 LFA_Ma4776.95R • Horseshoe 1 R2D4 24 LFA F.'❑47K.3?R 0 Horseshoe 1_R2D4_25_LFA _F,'C4571.-•2ft Horseshoe 1 R2D4 28 LF.4 MD4514.79R Wave Length (nm) Horseshoe 1 5 Schlumberger Below is a depth overview of the MDT acquisition. Forrnation Pressure Depth 7HoL, Mobi I ty and Res stivity DO MOB 02 mD/cP 20M Open Hole Log Fractior SKIIIIIISTSINFINRANM Well Pressure Array Inchicion Two Foot RestAvity A10 CAT10) Dkm)2Lr 1 -7PPIC2 FORM PRES Vda 33W. 0.6 IDU 01 Array Induction Two Foot Resiswity WD MID --------------------- 3000 30W 300 36M 3111 9,0 10 gAPI 1501 0.2 ohm.m 2goo . Water Green ShaOI0300 jil Hill Horseshoe 1 Schlumberger 2 Interpretation Summary 2.1 Introduction A total of twenty one (21) pretests were acquired (including post pumping pretests). That resulted in seven (7) high quality, four (4) medium quality and two (2) low quality formation pressures. Two (2) pumping stations were attempted with the XLD probe but were then aborted due to the high differential pressure that was created. Subsequently, the dual packer was used on four (4) stations to move formation fluid through the tool. Seven (7) samples were acquired in a mix of 420cc non -compensated MPSR and 235cc compensated SPMC bottles that were shipped to the laboratory for further analysis. 2.2 Field Remarks: R2D4 Tool configured with 2 pumps for redundancy. Two MRMS sample carriers were used. Each MRMS contained 2 SPMC's and 4 MRMS's. Sampling performed at: 4771.5, 4761, 4571, 4515 feet. In total: 1 SPMC was captured, 6 MPSR's captured. 2.2.1 Depth Control Remarks All Schlumberger depth control procedures were followed. IDW used as primary depth control device. Z chart used as secondary depth control device. Logs correlated to PEX-GR log over 4500-4900 ft. 2.3 Interpretation by Zone Zones were created for discussion purposes only and are presented on wireline petrophysical data that is analyzed further with pressure versus depth views. 2.3.1 Zone 1 One (1) pretest was attempted in this zone resulting in a low quality formation pressure that did not completely stabilize. Mobility is estimated to be 0.24 mD/cP. 2.3.2 Zone 2 One (1) pretest was attempted in this zone resulting in a tight test. 2.3.3 Zone 3 Three (3) pretests were attempted in this zone resulting in one (1) high quality and two (2) medium quality formation pressures. Pressure ranged from 1954 psi to 1959 psi and mobility ranged between 0.95 mD/cP and 4.14 mD/cP. One (1) DFA station was conducted identifying the presence of water, OBM filtrate and potentially traces of oil. R2D4 File 26 — 4514.79 ft MD: Two (2) 420cc MPSR bottles were filled using low shock sampling technique. The LFA indicated water as the main phase fluid with mud filtrate and traces of oil. 2.3.4 Zone 4 Two (2) pretests were attempted in this zone resulting in one (1) high quality formation pressure and one tight test. Pressure is 1975 psi and mobility is 2.93 mD/cP. One (1) DFA station was conducted identifying the presence of water R2D4 File 25 - 4571.02 ft MD. Two (2) 420cc MPSR bottles were filled using low shock sampling technique. The LFA indicated water as the main phase fluid. 2.3.5 Zone 5 Twelve (12) pretests were attempted in this zone resulting in 5 high quality and 2 medium quality formation pressures. Pressure ranged from 2051 psi to 2079 psi and mobility ranged between 0.96 mD/cP and 4.19 mD/cP. One pressure gradient of 0.401 psi/ft (0.926 g/cc) was computed using five (5) high pressure and two (2) medium pressure points. Horseshoe 1 7 Schlumberger Two (2) DFA stations were conducted identifying the presence of oil. R2D4 File 24 — 4760.69 ft MD: One (1) 420cc MPSR and one (1) 235cc SPMC were filled using low shock sampling technique. The LFA indicated heavy oil. Contamination is estimated to be --20%. R2D4 File 21 — 4770.95 ft MD: One (1) 420cc MPSR was filled using low shock sampling technique. The LFA indicated heavy oil. Contamination is estimated to be --25%. 2.4 Recommendations In the case of Horseshoe 1, the use of InSitu Fluid Analyzer (IFA) would provide additional information to confirm the presence of oil in File 26. Currently, there is not sufficient information to confirm the presence of oil and the samples should be analyzed in the laboratory for traces of oil. Saturn 3-D radial probe would be beneficial in order to reduce the sump volume and time on station compared to the dual packer. This would result in quick fluid identification and a radial cleanup. 2.5 Formation Zone Table Zone Color Top MD Top TVD Bottom MD Bottom TVD Station Count ft ft ft ft Zone 1 2621.02 2578.46 2789.41 2739.36 1 Zone 2 4326.73 4147.61 4369.31 4189.65 0 Zone 3 4510.52 4330 4565.67 4385.12 3 Zone 4 4565.67 4385.12 4713.15 4532.6 2 Zone 5 4713.15 4532.6 4830 4649.45 7 2.6 Contact Information Please contact Jules EI -Khoury for any further information or queries relating to this report E-mail: jel-khoury(a�slb.com Phone: +1 281 285 8379 For more details, refer to: Section 3 — Fluid and Sampling Summary Section 4 — Fluid Gradients Section 5 — Pressure Results Section 6 — Pressure vs. Depth Views Section 7 — Downhole Fluid Analysis and Sampling Section 8 — Interval Pressure Transient Testing IPTT Section 9 — DFA — Reservoir Fluid Geodynamics (RFG) Connectivity Evaluation Section 10 — Well and Job Data Section 11 — Literature Pressure versus time plots are presented in a separate appendix. Horseshoe 1 8 Schlumberger 3 Fluid and Sampling Summary 3.1 Sampling and Fluids Profiling Summary Table File No. Zone Run No. Date Time MD (ft) TVD (ft) Type Bottle Module Bottle Serial No. Bottle Type Bottle Volume (cm3) Closing Pres (psia) Formation Pres (psis) Flowline Temp (degF) Mobility (mD/cP) Maximum DD Pres (psia) Pump Time (min) Pump Volume (cm3) Remarks 21 Zone 5 R21D4 2/14/2017 4770.95 4590.40 Sampling MS_1 B6 5013 MPSR 420.00 9090.57 2070.37 119.63 3.14 879.38 369.75 109470.04 Heavy Oil 8:10:19 AM 420 cc 1 Zone 5 R21D4 21 4770.95 24 Zone 5 R21D4 2/14/2017 3:49:18 PM 4760.69 4580.14 Sampling MS_1 B5 3207 MPSR 420 cc 420.00 7004.27 2064.47 120.18 4.19 990.02 459.64 165353.17 Heavy Oil Sampling MS_1 B3 421 SPMC 235 C 250.00 6703.14 2064.47 120.18 4.19 990.02 496.72 171944.55 Heavy Oil 0.09 Water. Sampling MS_1 B4 4040 MPSR 420.00 7273.57 1897.871 117.28 0.31 771.65 130.10 45372.89 Water 25 Zone 4 R21D4 2/15/2017 1:42:15 AM 4571.03 4390.48 0.58 0.42 420 cc Sampling MS_1 B1 1681 MPSR 420 R 420.00 6563.65 1897.871 117.10 0.31 786.11 155.27 54852.33 Water 26 Zone 3 R2D4 2/15/2017 4514.79 4334.26 Sampling MS_2 B6 3211 MPSR 420 cc 420.00 5379.88 1953.64 115.47 4.14 809.55 178.40 35493.53 Mainly water with traces of mud filtrate and potential oil 5:13:31 AM Sampling MS_2 B5 3226 MPSR 420.00 6854.67 1953.64 115.47 4.14 809.55 185.58 36267.84 Mainly water with traces of mud filtrate 420 cc and potential oil * Formation pressure, and mobility acquired using XLD probe before setting the dual packer for sampling. 3.2 Fluid Analysis Results Table * Computed GOR was used as a cleanup tool and is not listed in the table above. The oil GOR is out of the sensor's specification range. Horseshoe 1 9 File Flowline Flowline Water Oil No. Zone Run No. MD (ft) TVD (ft) TVDss (ft) Te (%) Comments No Press. (psia) 9F) Frac. Frac. Contamination Td 1 Zone 5 R21D4 21 4770.95 4590.40 -4548.30 1028.237 119.61 -25 0.00 1.00 Heavy Oil. 2 1 Zone 5 R21D4 1 24 4760.69 4580.14 -4538.04 1534.928 120.19 -20 0.00 1.00 Heavy Oil. 3 Zone 4 R21D4 25 4571.02 4390.48 -4348.38 1136.829 117.31 na 0.91 0.09 Water. Mainly water with traces of mud 4 Zone 3 R21D4 26 4514.79 4334.26 -4292.16 829.663 115.49 na 0.58 0.42 filtrate and potential oil. * Computed GOR was used as a cleanup tool and is not listed in the table above. The oil GOR is out of the sensor's specification range. Horseshoe 1 9 Schlumberger Fluid Gradient Formation Gradient Summary Zone Gradient Top TVD Bottom TVD Top TVDSS Bottom TVDSS Density Color Gradient Comments Density Statistical Error Density Theoretical R2 Error lity Probability STD psi/ft ft ft ft ft g/cm3 g/cm3 I g/cm3 psia Zone 5 0.401 4537.464618.16-4495.36-4576.06 0.926 Interpreted using five (5) high quality and two (2) medium quality formation pressures 0.026 0.021 0.99686 0.15 0.64 Fluids Type Definition Density From (g/cm3) Density To (g/cm3) Gradient From (psi/ft) Gradient To (psi/ft) Color Probable Fluid Type Less 0.0000 Less 0.0000 Negative Gradient 0.0000 0.5769 0.0000 0.2500 Gas 0.5769 0.9577 0.2500 0.4150 I Oil 0.9577 1.1723 0.4150 0.5080 I Water 1.1723 1.8642 0.5080 0.8078 I Mud 1.8642 Higher 0.8078 Higher Invalid Horseshoe 1 10 Schlumberger 5 Pressure Results 5.1 Pretest Summary Table Horseshoe 1 Color Total Zone 1 Zone 2 Zone 3 Zone 4 Zone 5 Zone Top MD (ft) No Formation Pressure No Seal or Lost Seal 2621.02 4326.73 4510.52 4565.67 4713.15 Zone Bottom MD (ft) Stable Pressure (< 0.1 psi/min). Clear DP derivative reached. Medium 2789.41 4369.31 4565.67 4713.15 4830 Average Mobility (mD/cP) Low 0.24 0 2.08 1.62 2.39 Pretest Type Volumetric Drawdown Pretest 18 1 1 3 2 11 Normal Pretest 5 0 0 1 1 3 Pretest Status Valid Test 13 1 0 3 2 7 Tight Test 4 0 1 0 1 2 Dry Test 3 0 0 0 0 3 Unstabilized 1 0 0 0 0 1 Unrecognizable 2 0 0 1 0 1 Gauge IBQP1 19 1 1 3 2 12 IPAQP 4 1 0 I 0 1 1 2 Runs Color I I R2D4 (14 -Feb -2017) 23 I 1 I 1 4 3 14 Formation Pressure Quality Color I I NA 8 0 1 0 1 6 High 7 0 0 1 1 5 Medium 4 0 0 2 0 2 Low 2 1 0 0 1 0 Ungraded 2 0 0 1 0 1 Drawdown Mobility Quality Color NA 8 0 1 0 1 6 High 7 0 0 1 1 5 Medium 4 0 0 2 0 2 Low 2 1 0 0 1 0 Ungraded 2 0 0 1 0 1 5.1.1 Formation Pressure Quality Grading Description Quality Color Description Examples NA No Formation Pressure No Seal or Lost Seal High Good Formation Pressure Stable Pressure (< 0.1 psi/min). Clear DP derivative reached. Medium Fair Data, Near Formation Pressure Stable Pressure (- 0.1 psi/min). No clear DP derivative reached. Low Questionable Formation Pressure Building - Not close to being Stabilized Horseshoe 1 11 Schlumberger 5.2 Test Point Table File Test Probe Probe TVD Pretest Formation Last BU Eq' DD Spherical Radial No. No. Probe MD TVD Subsea Pretest Status Type Comments Pressure Pres. Formation Mobility Mobility Mob x H Density ft ft ft psia psia Ibm/gal mD/cP mD/cP mD.ft/cP 3 2 2654.47 2610.61 -2568.51 Valid Test Volumetric Pretest still building up. 1188.58 1188.58 8.66 0.24 Drawdown 4 4 4352.97 4173.50 -4131.40 Tight Test Volumetric Tight test. 1914.11 Drawdown 5 6 4514.56 4334.03 -4291.93 Valid Test Volumetric Pretest built-up and stabilized. 1953.64 1953.64 8.61 4.14 Drawdown 6 8 4516.96 4336.43 4294.33 Valid Test Volumetric Pretest built-up and close to 1955.74 1955.74 8.62 1.16 Drawdown stabilization. 7 10 4519.97 4339.44 4297.34 Valid Test Volumetric Pretest built-up and close to 1959.24 1959.24 8.63 0.95 Drawdown stabilization. 8 11 4569.96 4389.41 -4347.31 Tight Test Volumetric Tight test. 1080.83 Drawdown 9 13 4570.98 4390.43 -4348.33 Valid Test Volumetric Pretest built-up and stabilized. 1974.69 1974.69 8.59 2.93 Drawdown 10 14 4721.45 4540.90 -4498.80 Tight Test Volumetric Tight test. 2028.13 Drawdown Volumetric Pressure built-up and stabilized. 114 4722.47 4541.92 -4499.82 Valid Test Drawdown Spherical and Radial flow 2051.00 2051.00 8.63 1.72 1.10 1.15 identified 12 18 4729.49 4548.94 4506.84 Valid Test Volumetric Pressure built-up and stabilized. 2053.17 2053.17 8.63 1.95 2.67 Drawdown Radial flow identified 1320 4740.43 4559.88 -4517.78 Valid Test Volumetric Pressure built-up and stabilized. 2057.35 2057.35 8.62 0.96 0.25 Drawdown Radial flow identified. Volumetric Pressure built-up and stabilized. 14 4760.42 4579.87 -4537.77 Valid Test Drawdown Radial flow identified. Tried 2064.47 2064.47 8.62 4.19 1.62 pumping 15 24 4771.49 4590.94 -4548.84 Valid Test Volumetric Pressure built-up and stabilized. 2070.37 2070.37 8.62 3.14 0.84 Drawdown Radial flow identified. 16 26 4791.33 4610.78 -4568.68 Dry Test Volumetric Dry test. 410.37 Drawdown 17 28 4792.18 4611.63 -4569.53 Valid Test Volumetric Pressure built-up and close to 2078.82 2078.82 8.62 2.11 Drawdown stabilization. 18 29 4813.46 4632.91 -4590.81 Tight Test Volumetric Tight test. 1027.98 Drawdown 19 30 4814.53 4633.97 -4591.88 Dry Test Volumetric Dry test. 500.17 Drawdown 20 31 4811.92 4631.37 -4589.27 Dry Test Volumetric Dry test. 624.49 Drawdown Pretest before pumping to confirm 21 4770.95 4590.40 -4548.30 Unrecognizable Normal seal only. Pressure did not stabilize. 224729.36 4548.81 -4506.71 Valid Test Normal Pressure built-up and close to 2053.16 2053.16 8.63 2.68 stabilization. 24 1 4760.69 4580.14 -4538.04 Unstabilized Normal Pressure build up did not stabilize 1901.37 after pump out. Pretest post pumping built-up but 25 2 4571.02 4390.47 -4348.37 Valid Test Normal not close to stabilization. Used for 1897.87 1897.87 8.26 0.31 2.03 indication. 26 4514.79 4334.26 -4292.16 Unrecognizable Normal Pump out only. Horseshoe 1 12 Schlumberger File Test Mud Mud Eq. Pretest Pretest Pretest 60 Sec Pres. Temp. Temp. Formation Packer/Probe Gauge Well No. No. Pressure Pressure Mud Date Time Volume Duration Flowrate Slope Variance Before After Zone Type Type Deviation Before After Density psia psia Ibm/galcm3 min cm3/s psi/min psia degF degF 3 2 1495.7 1480.0 10.92 02-14-2017 1.66 0.07 0.39 1.89 0.05 64.0 67.1 Zone 1 XLarge- BQP1 16.26 01:51:05 Diameter 4 4 2378.4 2361.7 10.90 02-14-2017 1.80 0.08 0.35 15.35 0.04 75.6 86.3 Zone 2 XLarge- BQP1 8.96 02:28:30 Diameter 5 6 2468.7 2458.6 10.90 02-14-2017 9.82 0.32 0.50 0.06 0.01 87.2 92.2 Zone 3 XLarge- BQP1 2.84 03:00:22 Diameter 6 8 2458.7 2452.1 10.85 02-14-2017 9.63 0.32 0.51 0.16 0.00 93.2 97.6 Zone 3 XLarge- BQP1 2.73 03:21:10 Diameter 7 10 2455.4 2454.9 10.83 02-14-2017 9.52 0.30 0.52 0.18 0.00 98.4 102.1 Zone 3 XLarge- BQP1 2.59 03:46:51 Diameter 8 11 2494.6 2492.1 10.88 02-14-2017 5.26 0.19 0.46 516.28 0.38 102.6 103.1 Zone 4 XLarge- BQP1 0.52 04:17:13 Diameter 9 13 2491.7 2484.5 10.86 02-14-2017 9.46 0.31 0.52 0.03 0.00 103.4 105.3 Zone 4 XLarge- BQP1 0.51 04:23:52 Diameter 10 14 2584.9 2579.2 10.90 02-14-2017 5.20 0.19 0.46 15.42 0.20 105.9 106.9 Zone 5 XLarge- BQP1 0.03 04:47:23 Diameter 111412578.7 2571.0 10.87 02-14-2017 9.54 0.31 0.52 0.06 0.00 107.1 108.8 Zone 5 XLarge- BQP1 0.03 04:58:51 Diameter 12 18 2576.0 2571.5 10.84 02-14-2017 9.54 0.31 0.51 0.05 0.00 109.0 110.1 Zane 5 XLarge- BQP1 0.03 05:20:27 Diameter 13 20 2580.4 2577.3 10.83 02-14-214 9.55 0.30 0.52 0.05 0.00 110.2 111.8 Zone 5 XLarge- BQP1 0.03 05:36:14 Diameter 14 22 2594.6 2591.4 10.84 02-14-2017 9.59 0.31 0.52 0.01 0.00 111.9 113.6 Zone 5 XLarge- BQP1 0.03 06:07:02 Diameter 15 24 2599.1 2594.6 10.84 02-14-2017 9.61 0.31 0.52 0.07 0.02 113.8 114.4 Zone 5 XLarge- BQP1 0.04 06:49:11 Diameter 16 26 2611.5 2608.0 10.84 02-14-2017 9.80 0.32 0.50 12.78 0.14 114.5 114.9 Zone 5 XLarge- BQP1 0.05 07:08:59 Diameter 17 28 2608.0 2605.5 10.83 02-14-2017 9.52 0.31 0.52 0.12 0.01 114.8 115.2 Zone 5 XLarge- BQP1 0.05 07:20:29 Diameter 18 29 2624.0 2622.6 10.84 02-14-2017 9.61 0.33 0.48 650.19 7.35 115.2 115.4 Zone 5 XLarge- BQP1 0.06 07:41:20 Diameter 19 30 2622.9 2621.1 10.83 02-14-2017 9.45 0.33 0.48 36.20 0.55 115.4 115.6 Zone 5 XLarge- BQP1 0.07 07:46:32 Diameter 20 31 2617.1 2616.5 10.82 02-14-2017 9.49 0.33 0.48 96.58 0.13 115.6 115.8 Zone 5 XLarge- BQP1 0.06 07:57:51 Diameter 21 2610.3 2594.3 10.88 02-14-2017 116.8 119.8 Zone 5 Standard PAQP 0.05 08:10:19 packer 22 32 2567.9 2570.6 10.80 02-14-2017 9.76 0.32 0.51 0.12 0.01 117.3 117.5 Zone 5 XLarge- BQP1 0.03 15:10:41 Diameter 24 1 2593.9 2585.4 10.84 02-14-2017 1793.97 11.55 2.59 1.39 0.00 119.2 120.3 Zone 5 Standard PAQP 0.05 15:49:18 packer 25 2 2480.2 2498.6 10.81 02-15-2017 3193.97 8.03 6.63 1.14 0.02 120.2 117.1 Zone 4 Standard PAQP 0.24 01:42:15 packer 26 2446.8 10.80 02-15-2017 117.0 Zone 3 Standard PAQP 1.61 05:13:31 packer Horseshoe 1 13 Schlumberger 6 Pressure Vs. Depth Views 6.1 Depth Overview by Quality -T--T,9 30001W 34Fi8 3748 4473 4500 4681 -ice ------ ------ ------ -------------------- -- ----- Excess pressure computed using the 0.401 psi/ft gradient and pressure point 2051 psi. Horseshoe 1 14 F: nation Pressure Depth Mobility and Resistivity Open Hole Log Fraction 1^le11 Pressure Dual Packer XLD rHoL, ❑ DO MOB 02 mDkP 20W 16 Array InduxionTvro FcdResisl* A10 (AT10] 1 FORMPRES_ 0 ❑----------0.2 ohm.m 2000 1011� Psis 30[10 fi n 16 Array Induclion Twa Foo[ Resisiviy A30(AT30) Excess Pressure (EXC_PRES) PPC1 Hoe Diameter 1 0 (HD1_PPC1] — — — — -- — — — Standard Resolubn Formation Densly (RHOZ) MUD AFTER -100 psis 0 — — — — — — 0.2 ohm.m 20IX1 1.65 2.fi5�Gr—Sh�o 1300 6 n 16 glpn3 Array Induction Two Foot Resisl4y — A90 (AT90) Thema) Neutron Porosly (RaiD Metrwd) in 5elecled 1 060gy (FNPH)—�,W�iir 0.2 chm.m 2000 ❑fi '� 0300 � MUD-BEFORE p 13318, Gamma Ray (GR_EDTC) Depth (ft) ND MD 9API 150 a.,.._ ZmeI_. ......... ...................... ._._._._._._._.. _. ._._._._._._._._._._._._._._._._._._._._._._._._._._. ... ._. _ ._.. _._ .. .......... .............. _.._._._._._._ ._. ._._._._._._ ------------ ._.--------- ._._._._._._._.--------- .--------- ._.._._ ._._ ----- ..... ...... ..... ..... 2700 2748 -T--T,9 30001W 34Fi8 3748 4473 4500 4681 -ice ------ ------ ------ -------------------- -- ----- Excess pressure computed using the 0.401 psi/ft gradient and pressure point 2051 psi. Horseshoe 1 14 Schlumberger 6.2 Zone 1 Formation Pressure Depth Mobility and Resistivity Open Hale Log Fraction Well Pressure Dual PackerMEOW--",OB aiSae [SS} ❑ — X L D 6 15 0.2 mDkP 2000 Array lnduciion Two Foo[Reuslinly PPC2 Hoe Dtan>eter 1 A10 [AT10) [HD1_PPC2] -- —— — ---0.2 ohm.m 2000 6 In 16 LFA Fluids Fraction Array Induclion Two Foci — — — P30 [A�] — — — ohm.m 2000 PPC1 Hoe Dtan>eter 1 jHD1_PPC1] 6 In 16 FORM_PRES ❑ ❑---------•0.2 1000 psia 3000 Standard Resokim Forrimte i Densly [RHOZ] ❑ 13W Q 300 MUD MUD—BEFORE AFTER � 139a 33❑❑ 33❑(1 165 _ Trim" 0.6 Neutron gAm3 Porosity [Rafo Metrtod] Vu in Selec&d LlFwlogy (TNPH)— 265 ❑ Array Induction Two Foo[ ResislWy Ago (AT90) Gamma Ray [GR_EDTC] Depth (k) ND M❑ ❑ gAPI 150 0.2 ohm.m 200❑ n Water Green Shay) 2575 2617 -------------------------- - - - -- ------------------ --- --- ----- ------ -------------- ----- ------------------ -- -- -- ....-- -- -- -- -- -- Z-1 --------- ---------------- -------- -------- -------- - - ------- 2600 2643 — 3 — 2625 2669 F � 2656 26% f 2675 2722 27DD 2748 a � 2725) 2774 f a 4 -------- -- 7�� r 2750 2801 R r — 2775 2827 Horseshoe 1 15 Schlumberger 6.3 Zone 2 Formation Pressure Depth Mobility and Resistivity Open Hale Log Fraction Well Pressure Dual Packer MEOW --",OB XLD _ _A�s¢e [es} _ _ fi 16 0.2 mDkP 2OW Array Induxion Two Foot Reusli* A10 [AT10} PPC2 Hoe Dtan>eter 1 [HO1_PPC2] FDRM_PRES ohm.m 2000 0 ❑----------0.2 1000 psis 30[10 6 In 16 Array Ir6duclion Tym Foct Resis" P30 [A�] Excess Pressure (EXC_PRES) PPC1 Hoe DLmEter 1 Standard ResoFIDon Fommtem Deni* [RHOZ] MUD AFTER [HO1_PPC1] — — — — — — 1.65 2.65 100 psa 0 — — — n — — — —16 0 .2 ohm.m 2000 i Array Induction Twa Foot Resi;dvty Agp [A�-gp] 6 Themtal — Neutron Parody [Rafo gkW Me1Fwd] in 1t3JGi 5elecied Wtdogy (fNPH) — ❑ LFA Flu Fraction 13W p 3W MUO_6EFDRE psa ma 33❑❑ 3300 Gamma Ray (DR_EDTC) Depth (k) No MIDp2 ❑ gAPI 150 ohm.m 200010.6 n Water Green Shao 4120II 4299 I� 4130II 4309 s 414011 4319 } } s ................ ........ ....... _......... ..................... ______________ ________________ _______ _____ _____I'____________________ .. ._. _ ._.. _._ .. ._.._._._._._. _._._._._._.._._._._._.._._._._._._ = _., ._._._._._.._._._._._._ _.......... ._._._._._. ._._._._._._._.......... .......... ._.._._ ._._ _._. _._. _._. _._. _._. _._ ._._ _. 4150 4329 .............. 41501 4339 s� r_ } V r 41701 4349 e —4 Tent —t N 4180+ 4360 r _._._._._._._._._ ................ ........ ........ _.......... ...................... ._._._._._._._.......... _._._._.._._. _._._._._._._._.._._._._._._._. -4190 --_._._._._._._._._._._._.497Q._.... . -. _ ._.. _._ .. ._.._._._._._. ------------- ._._._._._.._._._._._._ _._._. — ._._.------- ._._._._._._ _ 4200111 4380 ` 11 4210Ij 4390 LI —tet 4220 4406 RYRYRY r 4236 4416 ~ r J� Horseshoe 1 16 Schlumberger 6.4 Zone 3 and Zone 4 Formation Pressure Depth Mobility and Resistivity Open Hale Log Fraction Well Pressure Dual Packer MEOW --",OB 6 in 16 02 mt]IcP 2000 Array Induxion Two Foot Reusli* A10 [AT10) PPC2 Hoe oian>eter 1 [HO1_PPC2] FDRM_PRES ohm.m 2000 p ❑----------0.2 1000 psis 3000 6 In 16 Array lr6d uclim Tym Find Resi" P30 [A�] Excess Pressure (EXC_PRES) PPC1 Hoe DLmEter 1 Standard ResoFIDon Fonrimte ri oeri* [RHOZ] MUD AFTER jHO1_PPC1] — — — — — — 1.65 2.65 -100 psia 0 — — — n — — — —1. 0.2 ohm.a 20[10 Induction Twa Ago �AT90) Foo[ Resi;dvty 6 gAm3 Themlal Neutron Parody [P.a<io AAelYrod] in Selec&d LAFtdogy (fNPH) — — Im 0 ' LFA Flu Fraction 10300 psa 3300 MUD -BEFORE Q 300 psis 3300 Gamma Ray [DR_EDTC} ❑epth {k) ND MID 432[}If 4501 gAPI 150 0Array2 ohm.m 200006 n Water Green Shao ---------- ---------------- ._._._._. _._._._._ -------- _I ----- ------ ._Y.--._._ ._._. ------ 1 t 5-2.812 4340 4521 I sr 435011 4541 } II 1 Y ~ti ? 4380I 4561 zmea-------------------- a TIt Mea 0-15.24 m 44001 4581 —� � Y J 4420 4641 44401 4621 L — Excess pressure computed using the 0.401 psi/ft gradient and pressure point 2051 psi. Horseshoe 1 17 Schlumberger 6.5 Zone 5 Formation Pressure Depth Mobility and Resistivity Open Hale Log Fraction Well Pressure Dual Packer DD MOB XLD e (BS) _ 7PPIC2 ° 16 0.2 mDkP 20W Array Induxion Tyro Foo[Re�nly Dtan>eter 1 A10 [AT10) FORMPRES_PPC2] ohm.m 2000 ° 0----------0.2 205 psis 21W 6 In 16 Array Induclion Two Foot RAY P30 [A�] Excess Pressure (EXC_PRES) PPC1 Hoe Diameter 1 Standard Resoluim Fom>adon Deni* [RHOZ] MUD AFTER [HD1_PPC1] — — — — — — 1.65 2.65 { psa 0 — — — n — — — —1fi 0.2 ohm.m 2W0 13W Array Induction Two Foot ResislWy Ago [AT90] 6 Trim" Neutron Porosity (134D gAm3 Metrtod) in SekKtd 1-Ndogy (TNPH)—MUO_BEFORE LFA Fluids Fraction psa 33W C.anma Ray [GR_EDTC] Depth (k) gAPI 150 ND M❑ — 0'fi Cffi Q 3W 135101 3300 0.2 ohm.m 2OW n Water Green Shay) I 4525 4706 ZmeS_._ ---------------- __._._.------- _--------- .__ ________ _______ .__ __._._._._.__ __._._._.__ _........ _--------------------- .--- ._._._._.__ _ _ _ __ _ __._.__ __._._.__ __._.__ __._._.__ ......... _.............. ............ ... __ _--------- __._._._._._.--------- .--------- ------- ____ __ __ __ __ __..... _... ¢ Tg ren u oou i s e 4550 4731 s P r 45'. 4755 psm tun) I IV } 4500 4781 S 4 16 Dry est .160 . 4625 4806 r k ---------------- ---------------- -------- ------- - --- --- ----- -------- ------- ---------------- ---------------- .-4650 -------------- 42M - ... ........... ............ ........... ........... ......... . r, ........ ----------- ------------ --- -- -------- -------------- --------- --------- -- ---- ---- --- ---- ---- ----- ----- - - ---- i i 4E'5i_ 4856` Excess pressure computed using the 0.401 psi/ft gradient and pressure point 2051 psi. Horseshoe 1 18 Schlumberger 7 Downhole Fluid Analysis and Sampling 7.1 Con Pr_R02_Sta021_MDT—EDTA 4770.96 ft MD Downhole Fluid Analysis File Sta021 - R2D4 4770.95 ft (MD) - 4590.40 ft (TVD) Fluid identification and sampling with Dual Packer LFA indicated Oil Sampled 1 MPSR (420 cc) bottle from MRMS1 Contamination -25% Horseshoe 1 19 7.1.1 Standard Cross Plot (0 min - 414.21 min) All Probe Quartz Gauge Pressure and Pump Volume 14 -Feb -2017 Armstrong Energy, LLC ConPr R05 Sta021 MDT EDTA MD: 4770.95 ft TVD: 4590.4 ft PAQT(degF), MRPA Quartz Gauge Temperature � POUDCV2(cm3), MRPOUD 2 Continuous Volume Computed_POUDFR(cm3/s), Computed Flow rate � Computed_POUDFR2(cm3/s), Computed Flow rate 3500 50 100K 120 45 90K 119 3000 40 80K 118 35 70K 117 2500-- 30-- 60K 116 n 2000E 25 v M 50K --a6 LL 115 � 20 40K 114 1500 15 30K 113 10 20K 112 1000-- 5-- 10K 111 500 0 0 110 ETIM (min) Schlumberger n 4 Wildcat Horseshoe 1 No Horseshoe 1 20 Schlumberger 7.1.2 LFA Cross Plot (0 min - 414.21 min) LFA 14 -Feb -2017 Armstrong Energy, LLC Wildcat ConPr_R05_Sta021_MDT_EDTA MD: 4770.95 ft TVD: 4590.4 ft Horseshoe 1 GOR_LFA(fl3/bbl), Gas Oil Ratio Computed_GOR_LFA(fl3/bbl), LFA Computed GOR Q Low Quality High Quality -260- -280- -300- -320- -340- -360 260-280-300-320 -340-360 -380 -400 -420 it TAW 440 lip lIfit-ir, I, 4.0 FAOD_LFA[4], Optical Density Data FAOD_LFA[7], Optcal Density Data FAOD_LFA[8], Optical Density Data 3.5 3.0 2.5 2.0 1.5 1.0 0.5 0-7 1.0 OILF_LFA, Oil Fraction WATF_LFA, Water Fraction HAFF_LFA, Highly Absorbing Fluid Flag 0.9 0.8 0.7 0.6 0.5 0.4 0.3 0.2 0.1 0 ETIM (min) Horseshoe 1 21 Schlumberger 7.2 Con Pr_R02_Sta024_MDT_EDTA 4760.69 ft MD Downhole Fluid Analysis File Sta024 - R2D4 4760.69 ft (MD) - 4580.14 ft (TVD) Fluid identification and sampling with Dual Packer LFA indicated Oil Sampled 1 SPMC (235 cc) and 1 MPSR (420 cc) bottles from MRMS1 Contamination —20% Horseshoe 1 22 7.2.1 Standard Cross Plot (0 min - 14 -Feb -2017 Con Pr_R05_Sta024_M DT—EDTA 50 125 160K 45 124 3000-- 40-- 140K 123 2500 35 120K--122 30 121 100K 2000 -�2 M LL n E 25 U 120 � 80 K 20 119 1500 60K-- 15-- 118 40K 10 117 1000 20K 5 116 500 0 0 115 Horseshoe 1 579.23 min) All Probe Quartz Gauge Pressure and Pump Volume Armstrong Energy, LLC MD: 4760.69 ft TVD: 4580.14 ft PAQT(degF), MRPA Quartz Gauge Temperature POUDCV2(cm3), MRPOUD 2 Continuous Volume Computed_POUDFR(cm3/s), Computed Flow rate Computed_POUDFR2(cm3/s), Computed Flow rate PAQP(psi), MRPA Quartz Gauge Pressure � BQP1(psi), MRPS 1 Quartz Gauge Pressure Schlumberger Wildcat Horseshoe 1 ETIM (min) 23 I Lik 200 250 300 350 400 450 500 0 50 100 150 550 600 ETIM (min) 23 Schlumberger 7.3 Con Pr_R02_StaO25_MDT_EDTA 4571.02 ft MD Downhole Fluid Analysis File Sta025 - R2D4 4571.03 ft (MD) - 4390.48 ft (TVD) Fluid identification and sampling with Dual Packer LFA indicated Water Sampled 2 MPSR (420 cc) bottles from MRMS1 Horseshoe 1 25 Schlumberger 7.3.1 Standard Cross Plot (0 min - 203.69 min) All Probe Quartz Gauge Pressure and Pump Volume 15 -Feb -2017 Armstrong Energy, LLC Wildcat ConPr R05 Sta025 MDT EDTA MD: 4571.03 ft TVD: 4390.48 ft Horseshoe 1 o PAQT(degF), MRPA Quartz Gauge Temperature POUDCV2(cm3), MRPOUD 2 Continuous Volume ri Computed_POUDFR(cm3/s), Computed Flow rate ti Computed_POUDFR2(cm3/s), Computed Flow rate 0 20 40 60 80 100 120 140 160 180 200 ETIM (min) Horseshoe 1 26 50 122 50000 45 121 3000 45000-- 40-- 120 40000 35 119 2500 35000-- 30-- 118 30000 N 2000 M 25 M E u - - 117 CL cE, L' 25000--- 20 116 20000 1500 15 15000 115 10 10000--114 1000-- 5-- 5000 113 0 0 112 0 20 40 60 80 100 120 140 160 180 200 ETIM (min) Horseshoe 1 26 7.3.2 LFA Cross Plot (0 min - 203.69 min) 15 -Feb -2017 ConPr_R05_Sta025_MDT—EDTA 4.0 3.5 3.0 2.5 v 2.0 1.5 1.0 0.5 1.0 0.9 0.8 0.7 0.6 0.5 0.4 0.3 0.2 0.1 0 LFA Armstrong Energy, LLC MD: 4571.03 ft TVD: 4390.48 ft Schlumberger Wildcat Horseshoe 1 ETIM (min) Horseshoe 1 27 Schlumberger 7.4 Con Pr_R02_Sta026_MDT_EDTA 4514.79 ft MD Downhole Fluid Analysis File Sta026 - R2D4 4514.79 ft (md) - 4334.26 ft (tvd) Fluid identification and sampling with Dual Packer LFA indicated Formation Water, OBM filtrate and traces of Oil Sampled 2 MPSR (420 cc) bottles from MRMS2 Horseshoe 1 28 7.4.1 Standard Cross Plot I 15 -Feb -2017 Con Pr_R05_Sta 026_M DT—EDT/ 30 35000- 3000-- 25-- 5000-300025 30000- 2500-- - 0000-2500 25000- 20-- 2000-- 5000- 202000 20000 � M Q 15 U U 15000- 1500-- 10-- 10000- 1000-- 5-- 5000- 500-- 0— 5000- 15001010000-100055000-5000 0— "0 min - 198.83 min) All Probe Quartz Gauge Pressure and Pump Volume Armstrong Energy, LLC MD: 4514.79 ft TVD: 4334.26 ft o PAQT(degF), MRPA Quartz Gauge Temperature POUDCV2(cm3), MRPOUD 2 Continuous Volume � Computed—POUDFR(cm3/s), Computed Flow rate Computed—POUDFR2(cm3/s), Computed Flow rate 122 PAQP(psi), MRPA Quartz Gauge Pressure BQP1(psi), MRPS 1 Quartz Gauge Pressure 121- 120- 119 21120119 118 LL 117 _ 116 115 112-f 0 Schlumberger Wildcat Horseshoe 1 20 40 60 80 100 120 140 160 180 20C ETIM (min) Horseshoe 1 29 7.4.2 LFA Cross Plot (0 min - 198.83 min) LFA 15 -Feb -2017 Armstrong Energy, LLC ConF`r_R05_Sta026_MDT_EDTA MD: 4514.79 ft TVD: 4334.26 ft X00 GOR_LFA(ft.Tb61), Gas Oil Ratio Computed_ GOR_LFA(Ubhl), LFAComputed GOR 0 Low Quality M High Quality -500 + +++ -1600 -MUL . . ,r . , 1 ll Ii� ll t ul i' I it 11, -7DD -8fl0 -900 1000 3.0 FAOD_LFA[4], Optical Density Data � FAOD_LFA[q, Optical Density Data FAOD_LFArej, Optical Density Data o F. OD_LFA[8], Optical Density Data 2.5 I 2.0- 1.5 E 1.fl -- I fl 1.0 M OILF_LFA Oil Fraction WATF_LFA dater Fraction M HAFF_LFA Highly Absorbing Fluid Flag 0.8 _� 5 0.4 Schlumberger 11iIdcat Horseshoe 1 120 140 160 180 200 ETI1"1 Mir Horseshoe 1 30 8 Pressure Transient Analysis Pump out stations were revised for the pressure transient completeness. The build up after pumping out was not long enough to be analyzed. For each of these files, the generic sequence of events consisted of a pumpout drawdown period followed by a short buildup period. The pressure response observed in each of these cases may be analyzed to determine reservoir properties as listed in the table below. Since the flow was conducted through a probe, the analysis of the data should be performed using a Single Probe Model (No second probe available fora VIT or Vertical Interference Test analysis). For a Single Probe Model flow occurs thru a circular probe where there is a mechanical skin at the probe, and wellbore storage caused by the storage volume of the flow lines within the tool but it is much smaller than the classical well testing storage. Since the flow converges thru the probe, the model contains a horizontal and vertical permeability component. The typical log -log response is as shown to the right with a unit slope during storage, a -1/2 spherical flow slope, and a flat Infinite Acting Radial Flow plateau. In many cases, the spherical flow pattern is masked by storage which results in a non -unique vertical permeability result. Schlumberger k I' Z Probe->Botm ......................... ....... -.... --.... -..... Schematic diagram afa sir�+leproEe (formation tester). Log -fog plot of the iypfcat drawdown r panne of a afngde probe [forma - bon tester). File fluid t5'PE: Typenf Analysis Input parameters Output paramders DepthThickness MD Furosilty Viscosity TVD Skin 110FIZOUtal Perm VertiCaI perm ft cP ft MD m D C I - Horseshoe 1 31 Schlumberger 9 Reservoir Fluid Geodynamics (RFG) Connectivity Evaluation "Reservoir fluid geodynamics" (RFG) refers to study of the process after reservoir filling and before present day (or production) that have an impact on reservoir connectivity assessment and production performance. The generic process is presented in the following graph: RFG reservoirN., Pressures FHZ & PredictiveIlk IML Audit I DFA* k6, EoS Perspective/ Model QC AAOF, GCXGC Analysis PS Mode - .- - •d- Pretest variations of fluids ' New well •Quality Control M" �.. prediction vs of available Analysis f: - attributes? RT data- Excess °°, ' Complexities Multiwell RFG • Data pressures �^°•�� ' ori Flow barrier organization DFA (OD,Disequilibrium and GOR, DENS, ° (biodegradation, classification VISCO, FLO, water wash...) according to AOP) °° m, -Multi i current their type and VIT' charge relevance to GCxGC'° -Other input the project. °° ° DFA Ma " available (FLAIR, oil AVfWlene Cp%en! fingerprints and biomarkers) DFA-RFG data can be used to investigate lateral and vertical hydraulic communication between wells and the corresponding units. DFA-RFG allows to evaluate: • Understanding of fluid distributions and its controlling factor in the reservoir • Vertical and lateral reservoir connectivity • Fluid gradients • Fluid equilibrium • Fluid contacts • AOP (Asphaltene onset pressure) • CO2 / H2S geodynamics • Analyze asphaltenes deposits distribution • Organic deposits drilling hazards Also, with real time DFA log analysis, a common feature in today's logging environment, model discrepancies uncovered by a mismatch with DFA measurements can be investigated during the wireline formation evaluation program. This workflow can be implemented during exploration, appraisal and development. Both the geology and the fluids in the model are compared to the real reservoir and fluid properties, and if needed, both models could be updated. This is a new way to bring value by taking advantage of DFA to guide not only sample acquisition but fluid data acquisition in general to help unravel reservoir architecture. DFA fluid mapping could be complementary to lab geochemistry studies and analyses of field pressure gradients, or as in the case study, it may tap into more advantageous and previously unnoticed reservoir features [1, 2, 3]. Horseshoe 1 32 3 2.5 0.5 M21 B 2S 2d Schlumberger 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 '15 2.7 r j5 'b 2 5h 2 5 2.45 2.4 wavelength, nm depth, R .810 MDT DFA Optical Density Spectrum for different stations (left) and Optical Density Gradient graph (right) to support Compartment / Fluid Equilibrium Studies [2] DFA Supporting Compartment / Fluid Equilibrium Studies [2] 1 2 GFA Color 4 Msotn [1] O.C. Mullins S.S. Betancourt, M.E. Cribbs, J.L. Creek, B.A. Andrews, F. Dubost, L. Venkataramanan, The colloidal structure of crude oil and the structure of reservoirs, Energy & Fuels, 21, 2785-2794, (2007) [2] S.S. Betancourt, F.X. Dubost, O.C. Mullins, M.E. Cribbs, J.L. Creek, S.G. Mathews, Predicting Downhole Fluid Analysis Logs to Investigate Reservoir Connectivity, SPE IPTC 11488, Dubai, UAE, (2007) [3] Vinay K. Mishra, Jesus A. Canas, Soraya S. Betancourt, Hadrien Dumont, Li Chen, Nivash Hingoo, Julian Y. Zuo, Oliver C. Mullins et al, DFA Connectivity Advisor: A New Workflow to Use Measured and Modeled Fluid Gradients for Analysis of Reservoir Connectivity, OTC, Houston, TX, 5-8 May 2014 Horseshoe 1 33 ► B TVD a rttadel • A Feet _ Ankei d` • ANDO • ANcrhModel o ASMM Gnv+trTerm air+3•ovcm � ''�^ri'. 1 2 GFA Color 4 Msotn [1] O.C. Mullins S.S. Betancourt, M.E. Cribbs, J.L. Creek, B.A. Andrews, F. Dubost, L. Venkataramanan, The colloidal structure of crude oil and the structure of reservoirs, Energy & Fuels, 21, 2785-2794, (2007) [2] S.S. Betancourt, F.X. Dubost, O.C. Mullins, M.E. Cribbs, J.L. Creek, S.G. Mathews, Predicting Downhole Fluid Analysis Logs to Investigate Reservoir Connectivity, SPE IPTC 11488, Dubai, UAE, (2007) [3] Vinay K. Mishra, Jesus A. Canas, Soraya S. Betancourt, Hadrien Dumont, Li Chen, Nivash Hingoo, Julian Y. Zuo, Oliver C. Mullins et al, DFA Connectivity Advisor: A New Workflow to Use Measured and Modeled Fluid Gradients for Analysis of Reservoir Connectivity, OTC, Houston, TX, 5-8 May 2014 Horseshoe 1 33 Schlumberger 10 Welland Job Data 10.1 Well Header Horseshoe 1 34 Schlumhepgep Company: Armstrong Energy, LILC Well: Horseshoe Wildcat Borough: Alaska MDT L) LV Modular Dynamic Tester J J v z Pressures and Samples Log FIELD PRINT 4 0LL U Surface: 2236 FSL AND 1413 FWL Elev.: K. B. 42.10 ft -9 L G. L. 23.50 ft' D. F. 42.10 ft po` Z 3: z d � Permanent Datum: Mean Sea Level Elev.: 0.00 ft ,n Log Measured From: Kelly Bushing 42.10 ft above Perm.Datum o 5 —01 Drilling Measured From: Kelly Bushing __ E 2 2c API Serial No. Section: Township: Range: � l.L J C_J m ° 50103207510000 15 8N 4E Logging date 14 -Feb -2017 Run Number R2D4 Depth Driller 6000.00 ft Schlumberger Depth 6000.00 ft Bottom Log Interval 4814.50 ft Top Lag Interval 2654.50 ft Casing Driller Size @ Depth 9.625 in @ 2213.00 ft Casing Schlumberger 2213 ft Bit Size 8.5 in Type Fluid In Hale Mineral Oil Density Viscosity 10 lbmlgal 129s ❑ Fluid Loss IPH 3.4 cm3 ❑ Source ofSample NIA RM @ Meas Temp NIA RMF @ Meas Temp NIA RMC @ Meas Temp NIA Source RMF IRMC NIA NIA RM @ BHT IRMF @ BHT NIA NIA Max Recorded Temperatures 131 degF 131 131 Circulation Stopped Time 13 -Feb -2017 02:45.00 Logger on Bottom Time 14 -Feb -2017 08:15:00 Unit Number Location: 2290 JUSPB Recorded By MReiter]CElowe Witnessed By Bob Len hart Horseshoe 1 34 Schlumberger 10.1.1 Well Header Table Horseshoe 1 35 Bit Bit Size in 8.5 Bottom Driller ft 6000 Bottom Logger ft 6000 Casing Size in 9.625 Weight Ibm/ft 53.5 Inner Diameter in 8.535 Grade L80 Top Driller Top Logger ft 0 Bottom Driller ft 2213 Bottom Logger ft 2213 Comments •• • ' Parameter Unit R21D4 Date Log Started 14 -Feb -2017 Time Log Started 00:28:48 Date Log Finished 14 -Feb -2017 Time Log Finished 00:29:21 Top Log Interval ft Bottom Log Interval ft Total Depth ft 6000 Max Hole Deviation de Azimuth of Max Deviation de Bit Size in 8.5 Logging Unit Number 2290 Logging Unit Location USPB Recorded By MReiter/CElow e Witnessed By Bob Lenhart Service Order Number CHJJ-00266 Comments :• •N a We Parameter (Unit) R2D4 Type Fluid Mineral Oil Max Recorded Temperature de F 131 I Source of Sample Active Tank Salinity m 0 Density Ibm/gal) 10 Viscosity s 0.48 Fluid Loss cm3 3.4 pH Date/Time Circulation Stopped 13 -Feb -2017 02:45:00 Date Logger on Bottom 14 -Feb -2017 Time Logger on Bottom 00:29:21 Source Rmf Horseshoe 1 35 Schlumberger Source Rmc Pressed Rm@Meas Temp ohm.m de F 500@68 Rmf@Meas Temp ohm.m de F 375@68 Rmc@Meas Temp ohm.m de F @68 Rm @ BHT Rmf @ BHT Rmc @ BHT Comments Depth Control Parameters R2D4 Ri T e Land Double Depth Measured Device R2D4 Type IDW-B Serial Number Wheel Correction 1 0 Wheel Correction 2 0 Tension Device R2D4 Type CMTD-B/A Serial Number Logging Cable R2D4 Type 7 -46A -XS Serial Number Logging Cable Length ft 17500 Comments Run Name R2D4 Remark Line 1 Remark Line 2 Remark Line 3 Remark Line 4 Remark Line 5 Remark Line 6 Remark Line 7 Remark Line 8 Remark Line 9 Remark Line 10 Remark Line 11 Remark Line 12 Remark Line 13 Remark Line 14 Remark Line 15 Remark Line 16 Remark Line 17 Comments Horseshoe 1 36 Schlumberger 10.2 Tool String Horseshoe 1 37 10.3 Well Survey Table Survey Top View View Azimuth: 90 W <- E (ft) Survey Side View View Azimuth: 90 500 1000-- 1500- 2000 00015002000 2500 3000 3500 4000 4500 5000 5500 6000 -3000 -2500 -2000 -1500 -1000 -500 0 500 1000 1500 2000 2500 3000 Schlumberger Horseshoe 1 38 Schlumberger # MD (ft) Incl (deg) Azim (deg) TVD (ft) North (ft) East (ft) Dep.Azim. (deg) Dog Leg Sev. (deg/100ft) 1 0 0 355.03 0 0 0 0 0 2 0 0 355.03 0 0 0 0 0 3 18.5 0 355.03 18.5 0 0 0 0 4 1 212.97 0.77 355.03 212.96 1.3 -0.11 355.03 0.4 5 293.96 3.05 3.76 293.9 3.99 -0.02 359.73 2.83 6 355.96 3.07 4.64 355.82 7.29 0.22 1.75 0.08 7 422.92 3.39 6.14 422.67 11.05 0.58 3.01 0.49 8 476.96 3.52 8.47 476.61 14.28 1 3.99 0.35 9 538.88 3.67 9.22 538.41 18.12 1.59 5.03 0.25 10 1 600.93 3.48 9.58 600.34 21.93 2.22 5.79 0.31 11 663.2 3.57 12.05 662.49 25.69 2.94 6.54 0.28 12 725.37 3.57 11.13 724.54 29.49 3.72 7.19 0.09 13 788.7 4.03 10.98 787.73 33.6 4.53 7.67 0.73 14 850.49 4.46 10.97 849.35 38.09 5.4 8.06 0.7 15 1 912.1 4.39 9.92 910.78 42.77 6.26 8.33 0.17 16 975.28 4.9 6.44 973.75 47.83 6.98 8.3 0.92 17 1038 6.19 359.25 1036.18 53.88 7.23 7.65 2.33 18 1099.04 6.76 357.14 1096.83 60.75 7.01 6.58 1.01 19 1161.96 7.3 357.22 1159.27 68.45 6.63 5.54 0.86 20 1 1225.2 7.74 357.44 1221.97 76.71 6.25 4.66 0.7 21 1287.08 8.09 357.34 1283.26 85.23 5.86 3.93 0.57 22 1350.34 8.57 357.21 1345.85 94.38 5.42 3.29 0.76 23 1413.08 8.73 357.31 1407.88 103.8 4.97 2.74 0.26 24 1470.59 9.62 356.3 1464.65 112.96 4.46 2.26 1.57 25 1 1534.79 10.3 355.35 1527.88 124.03 3.65 1.68 1.09 26 1598.68 10.93 356.39 1590.68 135.77 2.8 1.18 1.03 27 1659.77 12.36 357.41 1650.51 148.08 2.14 0.83 2.36 28 1721.74 13.12 1 357.64 1710.95 161.74 1.55 0.55 1.23 29 1784.9 13.03 357.71 1772.48 176.01 0.97 0.32 0.14 30 1845.96 13.48 357.08 1831.91 190 0.34 0.1 0.77 31 1905.96 15.5 356.48 1890 204.99 -0.51 359.86 3.38 32 1968.91 16.4 357.98 1950.53 222.26 -1.34 359.65 1.57 33 2027.12 16.14 357.62 2006.4 238.56 -1.97 359.53 0.48 34 2089.21 16.26 357.67 2066.03 255.87 -2.68 359.4 0.19 35 2152.79 16.25 358.06 2127.07 273.65 -3.34 359.3 0.17 36 2164.33 16.15 358.32 2138.15 276.87 -3.45 359.29 1.07 37 2263.77 15.85 358.74 2233.74 304.27 -4.15 359.22 0.32 38 2326.24 15.49 1 2293.89 321.14 -4.19 359.25 1.13 39 2389.13 14.63 4.72 2354.62 337.45 -3.39 359.42 2.06 40 2450.45 14.74 6.62 2413.93 352.92 -1.85 359.7 0.81 41 2513.26 15.15 8.51 2474.62 368.97 0.28 0.04 1.01 42 2575.77 15.6 15.53 2534.9 385.15 3.74 0.56 3.06 43 2638.81 15.99 26.28 2595.57 401.11 9.86 1.41 4.68 44 2700.29 17.21 1 36.18 2654.5 416.05 18.98 2.61 5 45 2761.81 18.07 45.18 2713.14 430.12 31.12 4.14 4.64 46 2824.5 18.58 51.64 2772.65 443.17 45.85 5.91 3.34 47 2887.14 19.57 57.83 2831.86 454.95 62.56 7.83 3.59 Horseshoe 1 39 Schlumberger # MD (ft) Incl (deg) Azim (deg) TVD (ft) North (ft) East (ft) Dep.Azim. (deg) Dog Leg Sev. (deg/100ft) 48 2949.01 20.92 62.63 2889.91 465.55 81.14 9.89 3.46 49 3011.26 22.48 65.61 2947.75 475.58 101.85 12.09 3.07 50 3073.84 23.9 68.24 3005.27 485.22 124.52 14.39 2.81 51 3136.62 25.42 70.37 3062.33 494.46 149.03 16.77 2.8 52 3199.44 27.61 72.21 3118.54 503.44 175.59 19.23 3.72 53 3261.54 28.85 72.4 3173.25 512.36 203.57 21.67 2 54 3323.6 29.08 73.36 3227.55 521.21 232.29 24.02 0.84 55 3386.34 29.06 72.76 3282.38 530.09 261.46 26.25 0.47 56 3448.23 29.13 73.03 3336.46 538.94 290.22 28.3 0.24 57 3510.46 28.97 72.7 3390.86 547.85 319.1 30.22 0.36 58 1 3572.39 29.13 1 72.75 3445 556.78 347.81 31.99 0.26 59 3634.43 28.67 72.27 3499.32 565.79 376.41 33.64 0.83 60 3695.92 27.46 71.96 3553.58 574.67 403.94 35.1 1.98 61 3757.77 26.47 72.19 3608.7 583.3 430.62 36.44 1.61 62 3820.72 25.4 72.2 3665.31 591.72 456.83 37.67 1.7 63 3883.19 23.7 72.95 3722.13 599.5 481.6 38.78 2.77 64 3944.73 21.53 73.11 3778.94 606.4 504.23 39.74 3.53 65 4007.35 19.36 73.24 3837.61 612.74 525.16 40.6 3.47 66 1 4068.56 16.84 73.07 3895.78 618.24 543.36 41.31 4.12 67 4130.52 14.3 73.01 3955.47 623.1 559.27 41.91 4.1 68 4193.43 12.23 72.55 4016.69 627.36 573.06 42.41 3.29 69 4255.8 10.88 72.49 4077.8 631.12 584.97 42.83 2.16 70 4317.31 9.73 1 73.27 4138.32 634.36 595.49 43.19 1.88 71 1 4379.06 8.4 74.57 4199.29 637.06 604.83 43.51 2.18 72 4441.9 6.27 76.51 4261.61 639.08 612.6 43.79 3.41 73 4501.99 3.41 79.45 4321.48 640.18 617.54 43.97 4.78 74 4563.99 0.58 87.92 4383.44 640.53 619.67 44.05 4.58 75 4627.06 0.13 209.58 4446.51 640.47 619.95 44.07 1.04 76 4688.66 0.04 188.99 4508.11 640.39 619.92 44.07 0.15 77 4760.16 0.03 226.08 4579.61 640.35 619.9 44.07 0.03 78 4820.91 0.07 243.38 4640.36 640.33 619.86 44.07 0.07 79 4884.23 0.07 191.68 4703.68 640.27 619.81 44.07 0.1 80 4945.24 0.04 259.94 4764.69 640.23 619.78 44.07 0.11 81 5007.53 0.11 243.45 4826.98 640.2 619.71 44.07 0.12 82 5068.23 0.09 245.45 4887.68 640.16 619.61 44.07 0.03 83 5129.88 0.31 273.33 4949.33 640.14 619.4 44.06 0.38 84 5191.73 0.34 271.78 5011.18 640.16 619.05 44.04 0.05 85 5254.98 0.28 260.86 5074.43 640.14 618.71 44.02 0.13 86 5316.78 0.22 248.97 5136.23 640.08 618.45 44.02 0.13 87 5378.41 0.3 236.55 5197.86 639.94 618.21 44.01 0.16 88 5441.13 0.38 200.02 5260.57 639.66 618 44.01 0.36 89 5503.66 0.39 209.31 5323.1 639.28 617.82 44.02 0.1 90 5566.26 0.26 223.26 5385.7 638.99 617.62 44.03 0.24 91 5627.48 0.26 205.71 5446.92 638.76 617.47 44.03 0.13 92 5688.69 0.21 212.26 5508.13 638.54 617.35 44.03 0.09 93 5751.78 0.11 214.7 5571.22 638.39 617.25 44.04 0.16 94 5815.24 0.1 227.71 5634.68 1 638.31 1 617.18 1 44.04 0.04 95 5875.88 0.1 251.93 5695.32 1 638.25 1 617.09 1 44.03 0.07 Horseshoe 1 40 Schlumberger # MD (ft) Incl (deg) Azim (deg) ND (ft) North (ft) East (ft) Dep.Azim. (deg) Dog Leg Sev. (deg/100ft) 96 5940.37 0.18 262.16 5759.81 638.22 616.93 44.03 0.13 97 5971.89 0.26 259.35 5791.33 638.2 616.81 44.02 0.26 98 6000 0.26 259.35 5819.44 638.18 616.69 44.02 0 Horseshoe 1 41 Schlumberger 11 Literature 11.1 Excess Pressure Excess Pressure is used in this report to show small changes in the pressure regime and to indicate a density or fluid change. The Excess pressure is generated by subtracting the expected pressure from the fluid weight from the total measured pressure and the remaining pressure is the difference. If the pressures are of high quality and the fluid in the pore space has not changed then the Excess Pressures should fall along a vertical line i.e. have the same excess pressure value. If the Excess Pressures deviates from the vertical line or from a consistent value this could indicate a pressure regime change, fluid density change, unstable pressures or supercharging. To get the Excess Pressure a high quality pressure is picked as the total pressure and the gradient is used to get a fluid density for computing the Excess Pressure. At the pressure datum the Excess Pressure will be 0. So when the Excess pressure is plotted any good pressures that don't have the same fluid density will be shifted off the zero line. The following low resistivity example demonstrates the use of Excess Pressure. Here test 2 was used as the pressure datum and the Gas gradient of 0.174 psi/ft was used as the fluid density to compute Excess Pressure. Tests 2 through 11 line up well on zero and tests 13 through 19 make a new diagonal line off the zero line. In this case this shows the pressures are good values and there is a fluid change around 11694 ft. The LFA analysis and the standard pressure gradient also support the fluid change, or Gas Oil contact. If the pressures were not stable or supercharged they would not of fit on a line and would of indicated poor quality pressures. A change in pressure regime due to a barrier would be indicated by a discrete excess pressure shift. Reference: Alton Brown: "Improved interpretation of wireline pressure data" , AAPG Bulletin v. 87 no.2 (February 2003) Horseshoe 1 42 11.1.1 Excess Pressure Example Pressure Depth Plat SchludepUep Schlumberger FORMATION (BQP1 psia) GR (gapi) LFA FLUID DRAWDOWN NPOR (cfcf) 0 FRAC MOSILITY(BQP1 and/cp) 7550 7610 30 130 a 0.1 10000 0.6 0 EXCESS PRESSURE (psia) 0 1 RHOZ (g/c3) 1:331 tvd (ft) AT90 (ohmm) 1.65 2.65 -5 45 0.1 10000 Crossover. AT20 (ohmml,.. 0.1 10000 XXX00 Zone 2 2 6 B - XXX50 0.174 psi/ft (Gas) 10 10 10 11 11 Gas it co tact 1169- .54 11 �13 ---- 13 ----- ---- ----- ---- --- ----- XXX00 13 17 17 1 s p 23 33 25 25 25 27 27 7 X29 29 2 XXX50 31 31 31 36 36 3 39 39 39 41 XXX00 45 45 Vii~ 747 47 49 4 M19 0.278 psi/ft (Oil) MDT Example Well 1 Horseshoe 1 43 Schiumhepgep 11.2 InSitu Fluid Analyzer Quantitative fluid measurements at reservoir conditions, in real time InSitu Fluid AnaMr Quantitative fluid meaents at reservoir conditions, in real time Horseshoe 1 44 Schlumhepgep Applications Quantified fluid measurements that were previously unachievable from wireline logs or laboratory analysis are now possible downhole and in real time. By investigating fluids at their source, you gain a deeper insight to fluid composition and distribution, to improve your understanding of the reservoir. Applications: • Reservoir fluid characterization • Identification of compartments and lateral sealing boundaries. Quantification of compositional grading • Strategy development for corrosion and scale • Sample assurance: single phase and purity Reservoir simulation (EOS modeling) • Improved -accuracy • Determination of pretest gradients and fluid contacts. Asphaltene gradient determination • Differentiation of biogenic and thermogenic dry gas • Identification of volatile oil and gas condensate • Determination of gas/oil ratio (GOR) and condensate/gas ratio (CGR) Horseshoe 1 45 Schlumhepgep Module InSitu Fluid Analyzer service integrates multiple InSitu Family reservoir fluid measurements and sensors. Fluid Profiling analysis of InSitu Family DFA measurements gives further insight to reservoir fluid distribution and variation. Characterization of the fluid system is extended from a single well to multiple -well (field-based) applications, such as quantifying compositional gradients and identifying zonal connectivity. Dual Spectrometers for Enhanced Accuracy The foundation of DFA is optical absorption spectroscopy. The InSitu Composition hydrocarbon fluid composition measurement introduces the first downhole deployment of a laboratory -grade "grating spectrometer" in addition to the conventional filter array spectrometer. This technical innovation expands the accuracy and detail of the compositional information, resulting in quantifiable fluid data. The filter array spectrometer measures wavelengths in the visible to near - infrared (Vis -NIR) range from 400 to 2,100 nm across 20 channels that indicate the color and molecular vibration absorptions of the reservoir fluid and also show the main absorption peaks of water and CO2. The grating spectrometer has 16 channels focused on the 1,600- to 1,800 - nm range, where reservoir fluid has characteristic absorptions that reflect molecular structure. The dual -spectrometer measurements together with real-time calibration (performed downhole every 1 second) and improved compositional algorithms significantly improve the accuracy and repeatability of quantitative reservoir fluid analysis. It is this improved accuracy that enables Fluid Profiling comparison of fluid properties between wells, making field -wide DFA characterization a new critical tool for reservoir studies. Horseshoe 1 46 Schlumberger 4 Water — Medium -weight oil 3 _ CO2 $_ 2 06 0 1 M 0 400 600 800 1,000 1,200 1,400 1,600 1,800 2'000 Filter Wavelength, nm mm�w Grating array The wavelength ranges of the filter array and grating optical spectrometers are optimized for the detection and analysis of hydrocarbon and CO2 components in crude oil and natural gas, as well as for the determination of water content and pH. The measurement of optical density (OD) is simply the base -10 logarithm of the ratio of incident light to the transmitted light through a cross-section of reservoir fluid in the flowline. OD is presented as a dimensionless unit, whereby one OD absorbance unit implies a 10 -fold reduction in light intensity. For example, OD = 0 means 100% of light is transmitted, OD = 1 indicates 10% light is transmitted, and OD = 2 means 1 % light is transmitted. The measurements are conducted across the entire frequency spectrum of light in the Vis -NIR range. 2. InSitu Composition Measurement The Vis -NIR spectrum measured by the two InSitu Composition spectrometers is used for the analysis of fluid hydrocarbon composition, GOR, CO2, water content, and mud filtrate contamination. In addition to the improved measurement capabilities of the dual spectrometers, the compositional analysis is refined with an algorithm developed from Beer-Lambert's law, which indicates that the optical absorption of a component is proportional to its concentration. Thus the spectrum of a live oil is a weighted sum of the absorptions of its individual components. The significant variation of the C6+ group in live oil is also accounted for in the algorithm. The C6+ group is the main component of stock -tank oil, and the detailed spectrum of the grating spectrometer in the 1,600- to 1,800 -nm range was used to characterize stock -tank oil on the basis of wax and branched -alkane content. From this data, the fluid composition analysis corrects for spectrum variation. An independent determination of ethane (C2) is now possible for the first time owing to the increased resolution of the grating spectrometer together with advanced deconvolution. This extra detail in analyzing light -end hydrocarbon components is critical for productivity analysis and economic assessment. The ratio of C1/C2 can also help determine whether the hydrocarbon source is biogenic or thermogenic. From the composition, the gas/oil ratio (GOR) and condensate/gas ratio (CGR) are determined from the vaporizations of the hydrocarbon and CO2 components at standard conditions for flashing a live fluid. Horseshoe 1 47 Schlumhepgep 3. InSitu GOR From the enhanced composition measurement, the gas/oil ratio (GOR) and condensate/gas ratio (CGR) are determined from the vaporizations of the hydrocarbon and CO2 components at standard conditions for flashing a live fluid. This new implementation provides greater range and increased accuracy over the measurement offered in previous generation tools (LFA live fluid analyzer and CFA compositional fluid analyzer). Results can now be entered into reservoir simulation models with confidence. 4. InSitu CO2 Measurement Carbon dioxide is present in the fluids of many reservoirs and must be accurately accounted for when developing hydrocarbon reserves. However, reliable quantification of CO2 from reservoir fluid samples can be difficult, especially if there is water in the collected samples, because CO2 easily reacts with water, whether from mud filtrate contamination or formation water. The measurement of CO2 content by the InSitu Fluid Analyzer system is performed with the filter array spectrometer. A dedicated channel to the CO2 absorption peak is complemented with dual baseline channels above and below that subtract out the overlapping spectrum of hydro -carbon and small amounts of water. The new channels and enhanced algorithm make it possible to plot the CO2 content in real time, together with upper and lower accuracy tolerances on the measurement. This gives increased confidence in the measurement accuracy under different environments. Horseshoe 1 48 Schlumhepgep 5. InSitu Color Measurement With optical filters improved for high-temperature performance, the InSitu Color reservoir fluid color measurement uses the extended measurement range of the 20 -channel filter array spectrometer to determine fluid color. The reliability of the measurement is supported by continuous real-time auto- calibration, application of a contamination algorithm that uses all the spectrometer channels, and a coated- window detection flag for enhanced QC. The color measurement supports fluid identification, determination of asphaltene gradients, and pH measurement. 6. InSitu Density Measurement Measuring density downhole at reservoir conditions provides numero surface measurements, especially for determining pressure gradients nate transition zones. This real-time measurement directly yields the slope of the pressure gradient for the identification of fluid contacts. The InSitu Density reservoir fluid density measurement is based on the resonance characteristics of a vibrating sensor that oscillates in two perpendicular modes within the fluid. Simple physical models describe the resonance frequency and quality factor of the sensor in relation to the fluid density. Dual -mode oscillation is superior to other resonant techniques because it minimizes the effects of pressure and temperature on the sensor through common mode rejection, which further improves the accuracy of the measurement. The InSitu Density measurement is made under flowing conditions, and the resonator is resistive to corrosive fluids. 7. InSitu fluorescence Measurement The InSitu Fluorescence reservoir fluid fluorescence measurement detects free gas bubbles and retrograde condensate liquid dropout for single-phase assurance while conducting DFA and sampling. Fluid type is also identified. The resulting fluid phase information is especially useful for defining the difference between retrograde condensates and volatile oils, which can have similar GORs and live -oil densities. Because the fluorescence measurement is also sensitive to liquid precipitation in a condensate gas when the flowing pressure falls below the dewpoint, it can be used to monitor phase separation in real time to ensure the collection of representative single-phase samples. Horseshoe 1 49 Schlumberger Dual fluorescence detector t 1 Gas detector %� r Light source Sapphire prism < Downhole reflection and dual fluorescence measurements provide assurance that the reservoir fluid is in single phase before DFA and sampling. 8. InSitu pH Measurement The formation water pH is a key parameter in water chemistry, used for calculating the corrosion and scaling potential of the water, under -standing reservoir connectivity and transition zones, determining the compatibility of injection water and formation water, and designating optimal salinity and pH windows for polymer and gel injections. Obtaining high-quality DFA and samples of formation water relies on tracking mud filtrate contamination by distinguishing between formation water and mud filtrate in real time. Water pH is measured with the InSitu pH reservoir fluid pH measurement by injecting dye into the formation fluid being pumped through the InSitu Fluid Analyzer flowline. The pH is calculated with 0.1- unit accuracy from the relevant visible wavelengths of the dye signal measured by an optical fluid analyzer. Making the measurement at reservoir conditions avoids the irreversible pH changes that occur when samples are brought to the surface, as acid gases and salts come out of solution with reduced temperature and pressure and routine laboratory flashing of the sample. InSitu pH sensor measures fluids across the entire flowline cross section, which makes it more robust than potentiometric methods of measurement, which are compromised when oil and mud foul electrode surfaces. Direct pH measurements with dye also avoid the limitations of resistivity measurement in monitoring contamination, which requires a sufficient resistivity contrast between the filtrate and formation water. Horseshoe 1 50 0 —2 Se al sample chamber i_itmutsdye injected ]Pen sample chamber Optical Density Channel I Optical Density Channel 2 Optical Density Channel 3 5,922 5,913 5,904 ' 5.895 5,886 5 877 — 5,859 U50 41 5.832 5,814579E R111 5,787 ; 11 1 5.769 5,760 ' 5.751 5,742 5.724 5;715 k t 5,893 5,688 5.679 ':I Pumpoutklodule PH OD Oabo Solenoid 3 StaL s 0.02 0 5 � 5 up -do -nn Pumpout Module 31 SdenoiV aetus Muhisample Module lower 1 '4"l Potion 4 11700 Medium duality Flags Schlumhepgep PH=3 i from Dye Indicator 0 10 InSitu pH measurement of pH = 3 indicated high CO2 that was missed in laboratory analysis conducted after the sample was flashed. With knowledge of the actual CO2 content, the operator could minimize subsequent corrosion and scaling problems. Horseshoe 1 51 Schlumberger 9. Flowline Resistivity Measurement The flowline resistivity sensor uses the same proven technology employed in Schlumberger formation testing tools. With the resistivity sensor included in the DFA assembly, it is possible to monitor resistivity during dual -packer sampling operations in WBM. 10. Flowline Pressure and Temperature Measurements The high-resolution pressure and temperature sensors used in Schlumberger formation testing tools are also incorporated in the InSitu Fluid Analyzer service. Direct measurement of pressure and temperature is essential to identify the position in the PVT envelope where the other fluid properties, such as density, are measured, especially when the sensors are placed downstream of the flowline pump. The DFA measurements within the flowline can then be accurately translated back to virginal reservoir conditions by employing well-known equation -of -state (EOS) algorithms. 11. Sampling Quality Control With InSitu Family measurements, the reservoir fluid is analyzed before samples are collected, which substantially improves the quality of the fluid samples. The sampling process is optimized in terms of where and when to sample and how many samples to collect. In addition, the pressure sensor provides an accurate record of over pressuring the sample contents before the sampling chamber is closed. The comprehensive InSitu Pro real-time quality control and interpretation software Horseshoe 1 52 �.. 11111111 ; tt MEN MEN (null •' r Rim Irml �i•1 ' a 11111111Y ill!■70711 1iiiliii� ��:�:�:�5�!! •,,", moi■ �I! I lllr .,■ice ■■� """IIF'. -- i■Mil■■ anonii �:m ■lil �iiiiiii The comprehensive InSitu Pro real-time quality control and interpretation software Horseshoe 1 52 Schlumberger depth view combines the results of pressure and fluids analysis from multiple data sources. 12. Chain of Custody DFA also provides a convenient technique for establishing a chain of custody for fluid samples. Differences between analytical data acquired downhole and that from corresponding samples in the laboratory are a strong indication that the laboratory sample may have been compromised. 13. Fluid Profiling Fluid Profiling characterization provides the distribution of fluid properties across the reservoir, beyond what a traditional sampling program can achieve. The quantified accuracy of the InSitu Family measurements expands DFA application from a single well to multiple -well analysis, defining reservoir architecture across the entire field. Quantification of the variation of fluid properties at higher resolution than conventional sampling and analysis is key to identifying and differentiating compositional grading, fluid contacts, and reservoir compartments. 14. InSitu Fluid Analyzer Mechanical Specifications Temperature rating, degF 350 [1751 Pressure rating, psi [MPaI 25,000 [1701 Diameter, in [cml 5 [12.71 Length, ft [ml 10.43 [3.181 Weiaht. Ibm fkal 368 [1671 Horseshoe 1 53 Schlumberger Thank you for cal ing Schlumberger Horseshoe 1 54