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Home My WebLink About198-161Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 10/02/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20251002 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 11A 50133205210100 224123 9/23/2025 YELLOWJACKET PERF T40937 BCU 13 50133205250000 203138 8/18/2025 YELLOWJACKET GPT-PERF T40938 BCU 13 50133205250000 203138 8/26/2025 YELLOWJACKET GPT-PERF T49038 BCU 13 50133205250000 203138 8/21/2025 YELLOWJACKET GPT-PLUG T40938 BCU 23 50133206350000 214093 9/10/2025 YELLOWJACKET PERF T40939 BCU 24 50133206390000 214112 9/16/2025 YELLOWJACKET PLUG-PERF T40940 BRU 212-35T 50283200970000 198161 9/18/2025 AK E-LINE Perf T40941 BRU 224-34T 50283202050000 225044 7/29/2025 AK E-LINE CBP/Punch T40942 BRU 224-34T 50133207170000 225044 9/19/2025 AK E-LINE GPT/Perf T40942 END 1-05 50029216050000 186106 9/25/2025 YELLOWJACKET IPROF T40943 END 2-08 50029217710000 188004 8/11/2025 YELLOWJACKET PERF T40944 END 4-50 50029219400000 189044 9/8/2025 YELLOWJACKET P-PROF T40945 KBU 11-08Z 50133206290000 214044 9/15/2025 AK E-LINE Perf T40946 KU 33-08 50133207180000 224008 7/1/2025 YELLOWJACKET PERF T40947 KU 41-08 50133207170000 224005 8/28/2025 YELLOWJACKET PERF T40948 KU 41-08 50883201990100 224005 9/16/2025 AK E-LINE Perf T40948 MPU R-108 50029238210000 225062 8/14/2025 YELLOWJACKET SCBL T40949 MRU K-06RD2 50733200880200 216131 9/12/2025 AK E-LINE CBL T40950 MRU M-01 50733203880000 187046 9/20/2025 AK E-LINE Perf T40951 MRU M-25 50733203910000 187086 9/21/2025 AK E-LINE Perf T40952 NCIU A-21A 50883201990100 225075 8/21/2025 AK E-LINE CBL T40953 NFU 14-25 50231200350000 210111 9/3/2025 YELLOWJACKET PERF T40954 PBU PTM P1-08A 50029223840100 202199 9/13/2025 YELLOWJACKET SCBL T40955 PBU W-35A 50029217990200 225076 9/17/2025 YELLOWJACKET SCBL T40956 SRU 241-33 50133206630000 217047 9/17/2025 AK E-LINE Perf T40957 SRU 32A-33 50133101640100 191014 9/23/2025 AK E-LINE Perf T40958 SRU 32A-33 50133101640100 191014 9/21/2025 AK E-LINE Perf T40958 Please include current contact information if different from above. BRU 212-35T 50283200970000 198161 9/18/2025 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.10.03 09:00:56 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 09/19/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250919 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BRU 212-35T 50283200970000 198161 8/10/2025 AK E-LINE PPROF T40899 BRU 223-34T 50283202060000 225059 8/17/2025 AK E-LINE CBL T40900 BRU 234-27 50283202070000 225065 9/12/2025 AK E-LINE CBL T40901 BRU 242-04 50283201640000 212041 6/9/2025 AK E-LINE Perf T40902 KBU 11-08Z 50133206290000 214044 9/8/2025 AK E-LINE Perf T40903 MPU H-03 50029220630000 190088 9/9/2025 AK E-LINE SetPacker T40904 MPU H-11 50029228020000 197163 2/9/2025 AK E-LINE Caliper T40905 MPU M-62 50029237440000 223006 8/31/2025 AK E-LINE LDL T40906 NCIU A-06 50883200260000 169050 8/25/2025 AK E-LINE TubingCut T40907 NCIU A-21A 50883201990100 225075 8/26/2025 AK E-LINE Perf T40908 ODSK-33 50703205620000 207183 9/10/2025 READ Caliper Survey T40909 ODSN-01a 50703206480100 216008 9/8/2025 READ Caliper Survey T40910 ODSN-06 50703207150000 215098 9/9/2025 READ Jewelry Log T40911 PBU C-34C 50029217850300 225068 8/25/2025 BAKER MRPM T40912 PBU Q-06A 50029203460100 198090 8/21/2025 BAKER SPN T40913 TBU M-25 50733203910000 187086 8/31/2025 AK E-LINE Drift T40914 Please include current contact information if different from above. BRU 212-35T 50283200970000 198161 8/10/2025 AK E-LINE PPROF Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.09.22 13:22:50 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 08/26/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250826 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 24 50133206390000 214112 7/15/2025 AK E-LINE PPROF T40803 BR 11-86 50733207370000 225057 7/30/2025 AK E-LINE Hoist T40804 BR 11-86 50733207370000 225057 8/4/2025 AK E-LINE Perf T40804 BR 11-86 50733207370000 225057 8/9/2025 AK E-LINE Perf T40804 BRU 212-35T 50283200970000 198161 8/4/2025 AK E-LINE Perf T40805 BRU 212-35T 50283200970000 198161 6/28/2025 AK E-LINE Perf T40805 BRU 224-34T 50283202050000 225044 8/2/2025 AK E-LINE CBL T40806 BRU 224-34T 50283202050000 225044 8/5/2025 AK E-LINE CBL T40806 BRU 224-34T 50283202050000 225044 7/27/2025 AK E-LINE CBL T40806 BRU 224-34T 50283202050000 225044 8/2/2025 AK E-LINE Punch T40806 KTU 43-6XRD2 50133203280200 205117 7/26/2025 AK E-LINE Perf T40807 MPL-13A 50029223350100 223017 8/10/2025 READ CaliperSurvey T40808 NCIU A-21 50883201990000 224086 1/14/2025 AK E-LINE Plug/Perf T40809 ODSN-16 50703206200000 210053 8/10/2025 READ CaliperSurvey T40810 PBU 01-30A 50029216060100 225050 8/7/2025 HALLIBURTON RBT-COILFLAG T40811 PBU 06-11A 50029204280100 225042 7/13/2025 HALLIBURTON RBT-COILFLAG T40812 PBU 11-37A 50029227160100 219062 7/27/2025 HALLIBURTON RBT T40813 PBU 14-43A 50029222960100 225041 7/31/2025 HALLIBURTON RBT-COILFLAG T40814 PBU F-06B 50029200970200 225054 8/5/2025 HALLIBURTON RBT-COILFLAG T40815 PBU L1-10A 50029213400100 225032 8/1/2025 HALLIBURTON RBT-COILFLAG T40816 PCU 02A 50283200220100 224110 7/27/2025 AK E-LINE Perf T40817 SRU 241-33 50133206630000 217047 7/28/2025 AK E-LINE Perf T40818 WhiskeyGulch 1 50231200790000 221046 6/18/2025 AK E-LINE Packer T40819 Please include current contact information if different from above. T40805BRU 212-35T 50283200970000 198161 8/4/2025 AK E-LINE Perf T40805BRU 212-35T 50283200970000 198161 6/28/2025 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.08.27 08:12:23 -08'00' CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Regg, James B (OGC) To:Chad Helgeson Subject:RE: [EXTERNAL] RE: BRU 212-35T (PTD# 198-161) SSSV reinstall Date:Thursday, August 7, 2025 10:42:00 AM Hilcorp is approved to leave SSSV out of BRU 212-35T to run the production log. If SSSV installation is delayed past 8/12, please contact me with an updated schedule. Performance test due 5 days after installation. Just a heads up – we are a month past due for witnessing a BOPE test on Rig 147 and I am projecting the next test could happen about the same time the SSSV performance test is due. If possible, we would like to do both Rig 147 BOPE test and this SSSV test with a single trip (I would grant an extension to complete the SSSV test, if needed). Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Thursday, August 7, 2025 10:28 AM To: Regg, James B (OGC) <jim.regg@alaska.gov> Subject: RE: [EXTERNAL] RE: BRU 212-35T (PTD# 198-161) SSSV reinstall Jim, As discussed on the phone, our schedule of work has updated over the last couple days and we are currently scheduled to run the production log on Monday, August 11th and will take 1 day to run, and our SL is scheduled to reinstall the SSSV on Tuesday, August 12th. Thanks Chad Helgeson From: Regg, James B (OGC) <jim.regg@alaska.gov> Sent: Thursday, August 7, 2025 9:35 AM To: Chad Helgeson <chelgeson@hilcorp.com> Subject: RE: [EXTERNAL] RE: BRU 212-35T (PTD# 198-161) SSSV reinstall Approval is conditioned on equipment needed to kill the well that is rigged up and ready for use. RE: [EXTERNAL] RE: BRU 212-35T (PTD# 198-161) SSSV reinstall Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Wednesday, August 6, 2025 9:32 AM To: Regg, James B (OGC) <jim.regg@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Brandon Bauer <bbauer@hilcorp.com>; Brian Woolley <bwoolley@hilcorp.com>; Joe Nightingale <jnightingale@hilcorp.com>; Noel Nocas <Noel.Nocas@hilcorp.com>; Daniel Taylor <dtaylor@hilcorp.com> Subject: RE: [EXTERNAL] RE: BRU 212-35T (PTD# 198-161) SSSV reinstall Sorry if I missed an S, but the surface safety valve is intact and working. I was just asking about the subsurface safety valve needing to be out more than 14 days. This is a request to avoid installing the valve and then removing it again 4-5 days later to run the production log and then reinstalling it again. If there was an issue with the well, the surface safety valve would trip and shut in the well. If there was an issue between the master valve and the surface safety valve, we would safety to try kill the well with a fluid pump through the flowline. Let me know if I need to call and discuss it with you any additional details. Thanks Chad From: Regg, James B (OGC) <jim.regg@alaska.gov> Sent: Wednesday, August 6, 2025 8:41 AM To: Chad Helgeson <chelgeson@hilcorp.com>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Brandon Bauer <bbauer@hilcorp.com>; Brian Woolley <bwoolley@hilcorp.com>; Joe Nightingale <jnightingale@hilcorp.com>; Noel Nocas <Noel.Nocas@hilcorp.com>; Daniel Taylor <dtaylor@hilcorp.com> Subject: [EXTERNAL] RE: BRU 212-35T (PTD# 198-161) SSSV reinstall CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. How would you respond to the surface safety valve system being compromised during the time of no SSSV available? Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Tuesday, August 5, 2025 10:00 AM To: Regg, James B (OGC) <jim.regg@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Brandon Bauer <bbauer@hilcorp.com>; Brian Woolley <bwoolley@hilcorp.com>; Joe Nightingale <jnightingale@hilcorp.com>; Noel Nocas <Noel.Nocas@hilcorp.com>; Daniel Taylor <dtaylor@hilcorp.com> Subject: BRU 212-35T (PTD# 198-161) SSSV reinstall Jim, We pulled the SSSV on BRU 212-35T (PTD# 198-161) on 7/25 for some perf adds on Eline. It is due to be installed on 8/7 (14 days), however we just finished the perf add work yesterday and our reservoir engineer would like us to run a production log after a week of production with the new perforations open. The well has been on production the entire time the SSSV has been removed, except while we were actively perforating. Hilcorp is requesting approval to leave the SSSV out of this well until after we complete the PLT log on Eline that will be scheduled next week? We will install the valve as soon as crews are available after the production log and then provide 48hr notice for testing after it is installed. I think a safe timeline for us to complete all our work and get the SSSV reinstalled would be around August 19th. This would mean the SSSV would be out of service for a total of approximately 26days Please let us know if this extended SSSV removal is approved. Thanks Chad Helgeson Operations Engineer Kenai Asset Team 907-777-8405 - O 907-229-4824 - C The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 4,801'N/A Casing Collapse Structural Conductor Surface 1,950psi Intermediate Production 7,100psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng See Schematic See Schematic 4,678'4,716'4,594' Beluga River Sterling-Beluga Gas 20" 13-3/8" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beluga River Unit (BRU) 212-35TCO 802A Same 4,677'9-5/8" ~1717psi 4,800' N/A Length July 29, 2025 5-1/2" & 3-1/2" 4,800' Perforation Depth MD (ft): See Attached Schematic 3,450psi 98'98' 2,677' Size 98' 2,677' MD Hilcorp Alaska, LLC Proposed Pools: 15.5# / L-80 & 9.2 / L-80 TVD Burst 3,811 & 4,713 8,150psi 2,605' Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA029657 198-161 50-283-20097-00-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade: chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: m n P s 66 t _ N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 11:51 am, Jul 14, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.07.14 11:28:35 - 08'00' Noel Nocas (4361) 325-417 SFD 7/21/2025 DSR-7/16/25 10-404 BJM 7/22/25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.07.22 13:36:53 -08'00'07/22/25 RBDMS JSB 072225 Well Prognosis Well Name: BRU 212-35T API Number: 50-283-20097-00-00 Current Status: Gas Producer Permit to Drill Number: 198-161 First Call Engineer: Chad Helgeson (907) 777-8504 (O) (907) 229-4824 (C) Second Call Engineer: Scott Warner (907) 564-4506 (O) (907) 830-8663 (C) Maximum Expected BHP: 1943 psi @ 4519’ TVD (Based on 0.43 psi/ft gradient)) Max. Potential Surface Pressure: 1717 psi (Based on 0.05 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.832 psi/ft using 16.0 ppg EMW LOT at the Surface shoe (2645’ TVD) Shallowest Allowable Perf TVD: MPSP/(0.832-0.05) = 1717 psi / 0.782 = 2,195‘ TVD Top of SBGP (CO 802A): ~2,971’ MD/ ~2,882’ TVD Brief Well Summary Drilled & completed in 1998 through the Beluga F sands, but was completed as a Sterling producer with a 5- 1/2" gravel pack to 3,811’, leaving the well cased through the Beluga sands below. An ESP was installed thru tbg on dual coil in 2015 to help unload water. The well was making 3-4 MMCFD until a hole in tbg compromised the completion in late 2017. In the summer of 2019, the dual coil ESP was pulled from the well and the well would not flow. In the summer of 2020, a tubing conveyed ESP was placed back in the well, however the well could not sustain flow long term and was shut-in. A 2022 RWO pulled the ESP and cemented 3-1/2” tubing across the gravel pack which isolated the open Sterling perfs and the well was returned to production through reperforating the E - F sands. Objective: The purpose of this work/sundry is to increase production by adding additional perforations in the Beluga D sands. All sands lie in the BRU SBGP. Wellbore Conditions: x Flowing at ~500mcf @ 57 psi with 5 bwpd x 3-1/2” TOC @ ~3411’ from CBL 5-7-22 Procedure 1. RU E-line, PT lubricator to 250/2000 psi 2. Perforate Beluga sands within the below intervals with the well shut-in: 3. Return well to production Attachments: 1. Current Well Schematic 2. Proposed Well Schematic Formation MD TOP MD BASE TVD TOP TVD BASE H Top Pool ~2,971’ ~2,882' Beluga D1 ±3,783' ±3,788' ±3,674' ±3,679' ±5' Beluga D1 ±3,793' ±3,798' ±3,684' ±3,689' ±5' Beluga D2 ±3,809' ±3,818' ±3,700' ±3,709' ±9' Beluga D3 ±3,828' ±3,856' ±3,718' ±3,746' ±28' Beluga D4 ±3,870' ±3,879' ±3,760' ±3,769' ±9' Beluga D5 ±3,904' ±3,915' ±3,793' ±3,804' ±11' Beluga D5 ±3,920' ±3,925' ±3,809' ±3,814' ±5' Beluga D6 ±3,939' ±3,945' ±3,828' ±3,833' ±5' p Max. Potential Surface Pressure: p 1717 psi (pg)) (Based on 0.05 psi/ft gas gradient to surface) _____________________________________________________________________________________ Updated by DMA 03-01-23 SCHEMATIC Beluga River Unit Well: BRU 212-35T Last Completed: 10/10/1998 PTD: 198-161 API: 50-283-20097-00-00 20” 13-3/8” 9-5/8” RKB to MSL = 92.5’ RKB to GL = 22.5’ TD = 4,801’ MD / 4,678’ TVD PBTD = 4,716’MD / 4,594’ TVD Sterling A Max Angle = 22 deg @ 1,970’ 3 4 5/6 7 8 9 10 11 12 13 14 15 16 17 18 19 Sterling B Sterling C 09/98 P1 2 P2 1 BEL E1 TOC in 3-1/2 @ 3,411’ CBL dated: 5/7/22 BEL E3 BEL E5 BEL E6 BEL F1 BEL F4 BEL F6 BEL F7 JEWELRY DETAIL Production String ID. Depth MD Depth TVD ID (in.) Description 25 25 5.5 10"x5.5" DCB Hanger w/ 5.5" API LTC csg top/btm 1 172’ 172’ 2.813 Giant 2.813 GXSV Nipple 2 2,010 1,983 4.653 Teledyne-Merla GLM 5.5"x1.5", 15.5# set 10/08/1998 3 2,765 2,687 4.653 Teledyne-Merla GLM 5.5"x1.5", 15.5# set 10/08/1998 4 3,079 2,986 4.562 Otis 'X' Sliding Sleeve, closed 5 3,128 3,033 4.875 Baker GBH-22 Locator Seal Assy, 190-60, 8' stroke 6 3,135 3,040 6 Baker SC-1 Gravel Pack Packer 96A4-60 7 3,149 3,054 4.75 Baker S Mini-Beta Gravel Pack 190-47 w/ss (18 ft.) 8 3,261 3,163 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (91 ft.) 9 3,354 3,254 6 Baker SC-1L Isolation Pkr. 96A4-60 10 3,359 3,259 4.75 Baker S Mini-Beta Gravel Pack 190-47 w/ss (18 ft.) 11 3,401 3,300 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (30 ft.) 12 3,441 3,339 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (121 ft.) 13 3,564 3,459 6 Baker SC-1L Isolation Pkr. 96A4-60 14 3,570 3,465 4.75 Baker S Mini-Beta Gravel Pack 190-47 w/ss (18 ft.) 15 3,611 3,506 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (30 ft.) 16 3,655 3,549 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (121 ft.) 17 3,776 3,667 4.75 Baker S-22B Snaplatch Seal Assembly 18 3,777 3,668 6 Baker FB-1 Retainer Prod. Pkr. 192-60 19 3,811 3,702 4.767 Wireline Entry Guide PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) Amt SPF Phase Date Status Sterling A 3,264' 3,346' 3,166' 3,246' 59'* 14 12 05/06/2022 Isolated 3,388' 3,416' 3,287' 3,315' 28' 14 12 05/06/2022 Isolated Sterling B 3,450' 3,492' 3,348' 3,389' 42' 14 12 05/06/2022 Isolated 3,523' 3,556' 3,419' 3,452' 14'* 14 12 05/06/2022 Isolated Sterling C 3,598' 3,636' 3,493' 3,530' 18'* 14 11 05/06/2022 Isolated 3,692' 3,712' 3,585' 3,605' 20' 14 11 05/06/2022 Isolated Beluga E1 4,004' 4,012' 3,890' 3,898' 8' 6 05/12/2022 Open 4,020’ 4,025’ 3,907’ 3,912’ 5’ 02/19/2023 Open 4,046' 4,059' 3,932' 3,945' 13' 6 05/12/2022 Open Beluga E3 4,114' 4,117' 3,999' 4,002' 3' 6 05/12/2022 Open 4,138’ 4,145’ 4,023’ 4,030’ 7’ 02/19/2023 Open Beluga E5 4,182’ 4,191’ 4,067’ 4,076’ 9’ 6 05/12/2022 Open 4,198’ 4,200’ 4,082’ 4,084’ 2’ 6 05/12/2022 Open 4,211’ 4,221’ 4,095’ 4,105’ 10’ 02/19/2023 Open 4,248' 4,261' 4,134' 4,147' 13' 6 05/12/2022 Open Beluga E6 4,272' 4,276' 4,157' 4,161' 4' 6 05/12/2022 Open 4,291’ 4,298’ 4,174’ 4,181’ 7’ 02/19/2023 Open 4,305’ 4,311’ 4,188’ 4,194’ 6’ 02/19/2023 Open 4,321' 4,333' 4,203' 4,215' 12' 6 05/12/2022 Open Beluga F1 4,377' 4,385' 4,259' 4,267' 8' 6 05/11/2022 Open Beluga F4 4,413' 4,426' 4,295' 4,308' 13' 6 05/11/2022 Open 4,460' 4,468' 4,341' 4,349' 8' 6 05/11/2022 Open Beluga F6 4,547' 4,556' 4,427' 4,436' 9' 6 05/11/2022 Open 4,577' 4,581' 4,455' 4,459' 4' 6 05/11/2022 Open Beluga F7 4,639' 4,643' 4,519' 4,523' 4' 6 05/11/2022 Open Plugs/Fish/Other ID. Depth MD (ft.) ID (in.) Description P1 3,745 - 9-5/8" Marker Joint P2 4,718 - Float Collar CASING DETAIL Size Type WT Grade Conn ID Btm 20'' Conductor 166# X-56 Weld 19.124'' 98' 13-3/8" Surface 68# K-55 Butt 12.415'' 2,677' 9-5/8" Prod Casing 47# S-95 Butt Mod. 8.681'' 4,800' TUBING DETAILS 5-1/2” Prod String 15.5# L-80 LTC 4.95'' 3,811' 3-1/2 Prod. Tubing 9.2# L-80 IBT 2.992” 4,713’ _____________________________________________________________________________________ Updated by CAH 07-08-25 PROPOSED Beluga River Unit Well: BRU 212-35T Last Completed: 5/7/22 PTD: 198-161 API: 50-283-20097-00-00 20” 13-3/8” 9-5/8” RKB to MSL = 92.5’ RKB to GL = 22.5’ TD = 4,801’ MD / 4,678’ TVD PBTD = 4,716’MD / 4,594’ TVD Sterling A Max Angle = 22 deg @ 1,970’ 3 4 5/6 7 8 9 10 11 12 13 14 15 16 17 18 19 Sterling B Sterling C 09/98 P1 2 1 BEL E1 TOC in 3-1/2 @ 3,411’ CBL dated: 5/7/22 BEL E3 BEL E5 BEL E6 BEL F1 BEL F4 BEL F6 BEL F7 BEL D1-2 BEL D3 &4 BEL D5 & 6 3-1/2” JEWELRY DETAIL ID. Depth MD Depth TVD ID (in.) Description 18’ 18’ 2.992” Cactus-EN-CL 7” x 3-1/2” hanger w/ 3” Type H BPV 1 172’ 172’ 2.813 Giant 2.813 GXSV Nipple P1 3,745’ 3,637’ NA 9-5/8” Marker joint 5-1/2” Details on Page 2 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) Amt SPF Phase Date Status Top of SBGP Pool: 2971’ MD, 2,882’ TVD Sterling A 3,264' 3,346' 3,166' 3,246' 59'* 14 12 05/06/2022 Isolated 3,388' 3,416' 3,287' 3,315' 28' 14 12 05/06/2022 Isolated Sterling B 3,450' 3,492' 3,348' 3,389' 42' 14 12 05/06/2022 Isolated 3,523' 3,556' 3,419' 3,452' 14'* 14 12 05/06/2022 Isolated Sterling C 3,598' 3,636' 3,493' 3,530' 18'* 14 11 05/06/2022 Isolated 3,692' 3,712' 3,585' 3,605' 20' 14 11 05/06/2022 Isolated Beluga D1 ±3,783' ±3,788' ±3,674' ±3,679' ±5' 6 60 TBD Proposed Beluga D1 ±3,793' ±3,798' ±3,684' ±3,689' ±5' 6 60 TBD Proposed Beluga D2 ±3,809' ±3,818' ±3,700' ±3,709' ±9' 6 60 TBD Proposed Beluga D3 ±3,828' ±3,856' ±3,718' ±3,746' ±28' 6 60 TBD Proposed Beluga D4 ±3,870' ±3,879' ±3,760' ±3,769' ±9' 6 60 TBD Proposed Beluga D5 ±3,904' ±3,915' ±3,793' ±3,804' ±11' 6 60 TBD Proposed Beluga D5 ±3,920' ±3,925' ±3,809' ±3,814' ±5' 6 60 TBD Proposed Beluga D6 ±3,939' ±3,945' ±3,828' ±3,833' ±5' 6 60 TBD Proposed Beluga E1 4,004' 4,012' 3,890' 3,898' 8' 6 05/12/2022 Open 4,020’ 4,025’ 3,907’ 3,912’ 5’ 02/19/2023 Open 4,046' 4,059' 3,932' 3,945' 13' 6 05/12/2022 Open Beluga E3 4,114' 4,117' 3,999' 4,002' 3' 6 05/12/2022 Open 4,138’ 4,145’ 4,023’ 4,030’ 7’ 02/19/2023 Open Beluga E5 4,182’ 4,191’ 4,067’ 4,076’ 9’ 6 05/12/2022 Open 4,198’ 4,200’ 4,082’ 4,084’ 2’ 6 05/12/2022 Open 4,211’ 4,221’ 4,095’ 4,105’ 10’ 02/19/2023 Open 4,248' 4,261' 4,134' 4,147' 13' 6 05/12/2022 Open Beluga E6 4,272' 4,276' 4,157' 4,161' 4' 6 05/12/2022 Open 4,291’ 4,298’ 4,174’ 4,181’ 7’ 02/19/2023 Open 4,305’ 4,311’ 4,188’ 4,194’ 6’ 02/19/2023 Open 4,321' 4,333' 4,203' 4,215' 12' 6 05/12/2022 Open Beluga F1 4,377' 4,385' 4,259' 4,267' 8' 6 05/11/2022 Open Beluga F4 4,413' 4,426' 4,295' 4,308' 13' 6 05/11/2022 Open 4,460' 4,468' 4,341' 4,349' 8' 6 05/11/2022 Open Beluga F6 4,547' 4,556' 4,427' 4,436' 9' 6 05/11/2022 Open 4,577' 4,581' 4,455' 4,459' 4' 6 05/11/2022 Open Beluga F7 4,639' 4,643' 4,519' 4,523' 4' 6 05/11/2022 Open CASING DETAIL Size Type WT Grade Conn ID Btm 20'' Conductor 166# X-56 Weld 19.124'' 98' 13-3/8" Surface 68# K-55 Butt 12.415'' 2,677' 9-5/8" Prod Casing 47# S-95 Butt Mod. 8.681'' 4,800' TUBING DETAILS 5-1/2” Prod String 15.5# L-80 LTC 4.95'' 3,811' 3-1/2 Prod. Tubing 9.2# L-80 IBT SC 2.992” 4,718’ _____________________________________________________________________________________ Updated by CAH 07-08-25 PROPOSED Beluga River Unit Well: BRU 211-03 Last Completed: 5/7/22 PTD: 186-010 API: 50-283-20079-00 Cemented 5-1/2” Gravel Pack Sterling Completion Detail ID. Depth MD Depth TVD ID (in.) Description 25 25 5.5 10"x5.5" DCB Hanger w/ 5.5" API LTC csg top/btm 2 2,010 1,983 4.653 Teledyne-Merla GLM 5.5"x1.5", 15.5# set 10/08/1998 3 2,765 2,687 4.653 Teledyne-Merla GLM 5.5"x1.5", 15.5# set 10/08/1998 4 3,079 2,986 4.562 Otis 'X' Sliding Sleeve, closed 5 3,128 3,033 4.875 Baker GBH-22 Locator Seal Assy, 190-60, 8' stroke 6 3,135 3,040 6 Baker SC-1 Gravel Pack Packer 96A4-60 7 3,149 3,054 4.75 Baker S Mini-Beta Gravel Pack 190-47 w/ss (18 ft.) 8 3,261 3,163 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (91 ft.) 9 3,354 3,254 6 Baker SC-1L Isolation Pkr. 96A4-60 10 3,359 3,259 4.75 Baker S Mini-Beta Gravel Pack 190-47 w/ss (18 ft.) 11 3,401 3,300 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (30 ft.) 12 3,441 3,339 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (121 ft.) 13 3,564 3,459 6 Baker SC-1L Isolation Pkr. 96A4-60 14 3,570 3,465 4.75 Baker S Mini-Beta Gravel Pack 190-47 w/ss (18 ft.) 15 3,611 3,506 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (30 ft.) 16 3,655 3,549 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (121 ft.) 17 3,776 3,667 4.75 Baker S-22B Snaplatch Seal Assembly 18 3,777 3,668 6 Baker FB-1 Retainer Prod. Pkr. 192-60 19 3,811 3,702 4.767 Wireline Entry Guide 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: ______________________ Development Exploratory 3. Address: Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 4,801 feet 4,801 feet true vertical 4,678 feet 4,678 feet Effective Depth measured 4,716 feet 4,716 feet true vertical 4,594 feet 4,594 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet 5-1/2" 15.5# / L-80 3,811 MD 3,702 TVD Tubing (size, grade, measured and true vertical depth)3-1/2" 9.2# / L-80 4,713 MD 4,591 TVD Packers and SSSV (type, measured and true vertical depth) See Schematic 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Contact Phone: 7,100psi 2,460psi 8,150psi 2,677' 2,605' Burst Collapse 1,950psi Production Liner 4,800' Casing Structural 4,677'4,800' 98'Conductor Surface Intermediate 20" 13-3/8" 98' 2,677' measured TVD 9-5/8" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 198-161 50-283-20097-00-00 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Hilcorp Alaska, LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: FEDA019657 Beluga River / Undefined Gas Pool Beluga River Unit (BRU) 212-35T Plugs Junk measured Length measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 54 Size 98' 8 582239 0 888 212 Jake Flora, Operations Engineer 323-012 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 588 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 jake.flora@hilcorp.com 907-777-8442 N/A p k ft t Fra O s O 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Samantha Carlisle at 12:27 pm, Mar 07, 2023 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361), ou=Users Date: 2023.03.07 12:00:21 -09'00' Noel Nocas (4361) Rig Start Date End Date 2/18/23 3/2/23 03/01/2023 - Wednesday Install WRSSSV, closure test passed, submit for witnessed test. 03/02/2023 - Thursday Conduct SSSV closure test, passed. Unable to re-open valve after test. State witnessed passed. Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BRU 212-35T 50-283-20097-00-00 198-161 02/18/2023 - Saturday AK E-line crew attend production operations meeting, Obtain PTW and hold PJSM. Travel to E pad location. RU PCE, crane and tool string: R.S., 1.69"GR/CCL, 5'x1.69" wt.bar, shock sub and 15' x 2.375" perf gun (loaded 9'). CCL to top shot = 19' / CCL to btm = 31'. PU tools and lubricator and MU to well head. PT 250/2500 psi. Pass. Well flowing at 106 psi / 574 mcfd. Open swab and RIH. Tools set down at 172'. Tag several times and review WBD with production and engineers. Determine obstruction is safety valve in place. POOH. Rig back e-line and arrange for slickline crew and flights. W/O slickline crew. Slickline crew arrives, check-in and mobe equipment to location. RU Wt bars, SJ, HJ and GS pulling tool. Stab on and SI well. RIH to 172' KB, W/T and latch SV. Unlock and dump SV surface pressure at accumulator. Hand spang with jars until valve releases from profile. POOH. OOH. Remove safety valve and GS and MU 2.72" Gauge ring. RIH and set down at 4330', work tool to 4332' sticky. POOH. Mud in GR. RD SL. RU E-line to continue perforating operations for next day. 02/19/2023 - Sunday AK E-line obtain PTW and hold PJSM. Travel to location and complete RU. FTP = 148 psi/ 507mscfd. MU perforating tool string (Wt. bar, GR/CCL, shock sub and 6' x 2-3/8" (6spf/60D). 12.9' CCL to top shot. Move tools and lubricator to well and PT 250/2500 psi. Pass. Open swab and RIH. Possible fluid level at 1950'. Tag PBTD at 4362' and logged correlation to 3800'. Send to Geo, confirm on depth. Position gun #1 and shoot E6 sand at 4305'-4311'. 153.8 psi / 487.6 mscfd. POOH. OOH. Gun wet. Cycle choke to clear. MU Gun run #2 E6 (7'). RIH, correlate and shoot gun at (4291'- 4298'). POOH. Continue perforating: Gun Run #3 - E5 - (4211'-4221') (10') Gun Run #4 - E3 - (4138'-4145') (7') Gun Run #5 - E1 - (4020'-4025') (5'). All guns fired and wet. Choke plugged every run POOH. Pressure / rates unsteady. OOH. Close swab. FTP = 171.8 psi / 481.6 MSCFD After 1 hr. - 169.5 psi / 485.8 MSCFD (Choke setting 6) Secure well RDMO. Turn well over to production. Note: WLR SSSV removed from well on 18-FEB-2023. Daily Operations _____________________________________________________________________________________ Updated by DMA 03-01-23 SCHEMATIC Beluga River Unit Well: BRU 212-35T Last Completed: 10/10/1998 PTD: 198-161 API: 50-283-20097-00-00 20 13-3/8 9-5/8 RKB to MSL = 92.5 RKB to GL = 22.5 TD = 4,801 MD / 4,678 TVD PBTD = 4,716MD / 4,594 TVD Sterling A Max Angle = 22 deg @ 1,970 3 4 5/6 7 8 9 10 11 12 13 14 15 16 17 18 19 Sterling B Sterling C 09/98 P1 2 P2 1 BEL E1 TOC in 3-1/2 @ 3,411 CBL dated: 5/7/22 BEL E3 BEL E5 BEL E6 BEL F1 BEL F4 BEL F6 BEL F7 JEWELRY DETAIL Production String ID. Depth MD Depth TVD ID (in.) Description 25 25 5.5 10"x5.5" DCB Hanger w/ 5.5" API LTC csg top/btm 1 172 172 2.813 Giant 2.813 GXSV Nipple 2 2,010 1,983 4.653 Teledyne-Merla GLM 5.5"x1.5", 15.5# set 10/08/1998 3 2,765 2,687 4.653 Teledyne-Merla GLM 5.5"x1.5", 15.5# set 10/08/1998 4 3,079 2,986 4.562 Otis 'X' Sliding Sleeve, closed 5 3,128 3,033 4.875 Baker GBH-22 Locator Seal Assy, 190-60, 8' stroke 6 3,135 3,040 6 Baker SC-1 Gravel Pack Packer 96A4-60 7 3,149 3,054 4.75 Baker S Mini-Beta Gravel Pack 190-47 w/ss (18 ft.) 8 3,261 3,163 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (91 ft.) 9 3,354 3,254 6 Baker SC-1L Isolation Pkr. 96A4-60 10 3,359 3,259 4.75 Baker S Mini-Beta Gravel Pack 190-47 w/ss (18 ft.) 11 3,401 3,300 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (30 ft.) 12 3,441 3,339 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (121 ft.) 13 3,564 3,459 6 Baker SC-1L Isolation Pkr. 96A4-60 14 3,570 3,465 4.75 Baker S Mini-Beta Gravel Pack 190-47 w/ss (18 ft.) 15 3,611 3,506 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (30 ft.) 16 3,655 3,549 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (121 ft.) 17 3,776 3,667 4.75 Baker S-22B Snaplatch Seal Assembly 18 3,777 3,668 6 Baker FB-1 Retainer Prod. Pkr. 192-60 19 3,811 3,702 4.767 Wireline Entry Guide PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) Amt SPF Phase Date Status Sterling A 3,264' 3,346' 3,166' 3,246' 59'* 14 12 05/06/2022 Isolated 3,388' 3,416' 3,287' 3,315' 28' 14 12 05/06/2022 Isolated Sterling B 3,450' 3,492' 3,348' 3,389' 42' 14 12 05/06/2022 Isolated 3,523' 3,556' 3,419' 3,452' 14'* 14 12 05/06/2022 Isolated Sterling C 3,598' 3,636' 3,493' 3,530' 18'* 14 11 05/06/2022 Isolated 3,692' 3,712' 3,585' 3,605' 20' 14 11 05/06/2022 Isolated Beluga E1 4,004' 4,012' 3,890' 3,898' 8' 6 05/12/2022 Open 4,020 4,025 3,907 3,912 5 02/19/2023 Open 4,046' 4,059' 3,932' 3,945' 13' 6 05/12/2022 Open Beluga E3 4,114' 4,117' 3,999' 4,002' 3' 6 05/12/2022 Open 4,138 4,145 4,023 4,030 7 02/19/2023 Open Beluga E5 4,182 4,191 4,067 4,076 9 6 05/12/2022 Open 4,198 4,200 4,082 4,084 2 6 05/12/2022 Open 4,211 4,221 4,095 4,105 10 02/19/2023 Open 4,248' 4,261' 4,134' 4,147' 13' 6 05/12/2022 Open Beluga E6 4,272' 4,276' 4,157' 4,161' 4' 6 05/12/2022 Open 4,291 4,298 4,174 4,181 7 02/19/2023 Open 4,305 4,311 4,188 4,194 6 02/19/2023 Open 4,321' 4,333' 4,203' 4,215' 12' 6 05/12/2022 Open Beluga F1 4,377' 4,385' 4,259' 4,267' 8' 6 05/11/2022 Open Beluga F4 4,413' 4,426' 4,295' 4,308' 13' 6 05/11/2022 Open 4,460' 4,468' 4,341' 4,349' 8' 6 05/11/2022 Open Beluga F6 4,547' 4,556' 4,427' 4,436' 9' 6 05/11/2022 Open 4,577' 4,581' 4,455' 4,459' 4' 6 05/11/2022 Open Beluga F7 4,639' 4,643' 4,519' 4,523' 4' 6 05/11/2022 Open Plugs/Fish/Other ID. Depth MD (ft.) ID (in.) Description P1 3,745 - 9-5/8" Marker Joint P2 4,718 - Float Collar CASING DETAIL Size Type WT Grade Conn ID Btm 20'' Conductor 166# X-56 Weld 19.124'' 98' 13-3/8" Surface 68# K-55 Butt 12.415'' 2,677' 9-5/8" Prod Casing 47# S-95 Butt Mod. 8.681'' 4,800' TUBING DETAILS 5-1/2 Prod String 15.5# L-80 LTC 4.95'' 3,811' 3-1/2 Prod. Tubing 9.2# L-80 IBT 2.992 4,713 Kyle Wiseman Hilcorp Alaska, LLC Geo Tech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: Kyle.Wiseman@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 03/03/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230303 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BRU 212-35T 50283200970000 198161 2/19/2023 AK E-LINE Perf BRU 232-26 50283200770000 184138 2/14/2023 AK E-LINE Perf END 1-29 50029216690000 186181 2/16/2023 AK E-LINE Perf MPU H-16 50029232270000 204190 2/28/2023 AK E-LINE Perf Please include current contact information if different from above. BRU 212-35T 50283200970000 198161 2/19/2023 AK E-LINE Perf 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. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6.API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number):10. Field: Current Pools: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 4,801'N/A Casing Collapse Structural Conductor Surface 1,950psi Intermediate Production 7,100psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 8,150psi4,677'4,800' 98' 2,677' Perforation Depth MD (ft): 4,800'9-5/8" 20" 13-3/8" 98' 2,677'3,450psi 98' 2,605' Length Size Proposed Pools: TVD Burst PRESENT WELL CONDITION SUMMARY 4,678'4,716'4,594'~1,534psi N/A MD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA029657 198-161 50-298-20097-00-00 Beluga River Sterling-Beluga Gas Same CO 802 Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beluga River Unit (BRU) 212-35T Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft):Tubing Size: 15.5# / L-80 & 4.6# / L-80 3,811 & 3,891 January 25, 2023 See Schematic See Schematic See Schematic See Schematic 5-1/2" & 2-3/8" 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: AOGCC USE ONLY Jake Flora, Operations Engineer jake.flora@hilcorp.com 907-777-8442 Noel Nocas, Operations Manager 907-564-5278 m n P s t _ 66 Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Meredith Guhl at 2:06 pm, Jan 11, 2023 323-012 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361), ou=Users Date: 2023.01.11 10:48:05 -09'00' Noel Nocas (4361) 50-283-20097-00-00 BJM 1/17/23 SFD 1/11/2023 DSR-1/12/23 10-404 SFD Brett W. Huber, Sr. GCW 01/17/23 JLC 1/17/2023 1/17/23 RBDMS JSB 011923 Well Prognosis Well Name: BRU 212-35T API Number: 50-283-20097-00 Permit to Drill Number: 184-138 Rig: E-line First Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (M) Second Call Engineer: Chad Helgeson (907) 777-8420 (O) (907) 229-4824 (M) Maximum Expected BHP: ~1985psi @ 4513’ TVD (0.44 psi/ft gradient to bottom perf) Max. Potential Surface Pressure: ~1534 psi (Max expected BHP - gas to surface) Well Status: Online Producer making 625 mcfd at 111 psi FTP Brief Well Summary Drilled & completed in 1998 as a Sterling producer with 5-1/2" gravel pack to 3,811’, while leaving the well cased through the Beluga sands below. An ESP was installed thru tbg on dual coil in 2015 to help unload water. The well was making 3-4 MMCFD until a hole in tbg compromised the completion in late 2017. In the summer of 2019, the dual coil ESP was pulled from the well. The well would not flow. In summer 2020, a tubing conveyed ESP was placed back in the well, however the well could not sustain flow long term and was shut-in. A 2022 RWO cemented 3-1/2” tubing across the gravel pack which isolated the open perfs and the well was returned to production through reperforating the E - F sands. The objective of this sundry is to increase productivity by perforating additional Beluga sands. Notes Regarding Wellbore Condition: 05/12/22 Perforated E - F-sands within 4004 – 4643’, brought online: 2.9MM @ 320 psi FTP 11/10/22 Bail fill from 4580’ with 2.5” DDB Procedure 1. RU E-line, PT lubricator to 2500 psi 2. Perforate below Beluga sands from the bottom up: Top Beluga D 3793’ MD 3684’ TVD Bottom Beluga F 4634’ MD 4513’ TVD a) If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations. Attachments: 1. As-built Well Schematic 2. Proposed Well Schematic _____________________________________________________________________________________ Updated by JLL 06/06/22 SCHEMATIC Beluga River Unit Well: BRU 212-35T Last Completed: 10/10/1998 PTD: 198-161 API: 50-283-20097-00 20” 13-3/8” 9-5/8” RKB to MSL = 92.5’ RKB to GL = 22.5’ TD = 4,801’ MD / 4,678’ TVD PBTD = 4,716’MD / 4,594’ TVD Sterling A Max Angle = 22 deg @ 1,970’ 3 4 5/6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Sterling B Sterling C 09/98 P1 2 P2 1 BEL E1 TOC in 3-1/2 @ 3,411’ CBL dated: 5/7/22 BEL E3 BEL E5 BEL E6 BEL F1 BEL F4 BEL F6 BEL F7 JEWELRY DETAIL Production String ID.Depth MD Depth TVD ID (in.) Description 25 25 5.5 10"x5.5" DCB Hanger w/ 5.5" API LTC csg top/btm 1 172’ 172’ 2.813 Giant 2.813 GXSV Nipple 2 2,010 1,983 4.653 Teledyne-Merla GLM 5.5"x1.5", 15.5# set 10/08/1998 3 2,765 2,687 4.653 Teledyne-Merla GLM 5.5"x1.5", 15.5# set 10/08/1998 4 3,079 2,986 4.562 Otis 'X' Sliding Sleeve, closed 5 3,128 3,033 4.875 Baker GBH-22 Locator Seal Assy, 190-60, 8' stroke 6 3,135 3,040 6 Baker SC-1 Gravel Pack Packer 96A4-60 7 3,149 3,054 4.75 Baker S Mini-Beta Gravel Pack 190-47 w/ss (18 ft.) 8 3,261 3,163 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (91 ft.) 9 3,354 3,254 6 Baker SC-1L Isolation Pkr. 96A4-60 10 3,359 3,259 4.75 Baker S Mini-Beta Gravel Pack 190-47 w/ss (18 ft.) 11 3,401 3,300 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (30 ft.) 12 3,441 3,339 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (121 ft.) 13 3,564 3,459 6 Baker SC-1L Isolation Pkr. 96A4-60 14 3,570 3,465 4.75 Baker S Mini-Beta Gravel Pack 190-47 w/ss (18 ft.) 15 3,611 3,506 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (30 ft.) 16 3,655 3,549 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (121 ft.) 17 3,776 3,667 4.75 Baker S-22B Snaplatch Seal Assembly 18 3,777 3,668 6 Baker FB-1 Retainer Prod. Pkr. 192-60 19 3,811 3,702 4.767 Wireline Entry Guide PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) Amt SPF Phase Date Status Sterling A 3,264' 3,346' 3,166' 3,246' 59'* 14 12 05/06/2022 Isolated Sterling A 3,388' 3,416' 3,287' 3,315' 28' 14 12 05/06/2022 Isolated Sterling B 3,450' 3,492' 3,348' 3,389' 42' 14 12 05/06/2022 Isolated Sterling B 3,523' 3,556' 3,419' 3,452' 14'* 14 12 05/06/2022 Isolated Sterling C 3,598' 3,636' 3,493' 3,530' 18'* 14 11 05/06/2022 Isolated Sterling C 3,692' 3,712' 3,585' 3,605' 20' 14 11 05/06/2022 Isolated Beluga E1 4,004' 4,012' 3,890' 3,898' 8' 6 05/12/2022 Open Beluga E1 4,046' 4,059' 3,932' 3,945' 13' 6 05/12/2022 Open Beluga E3 4,114' 4,117' 3,999' 4,002' 3' 6 05/12/2022 Open Beluga E5 4,182' 4,191' 4,067' 4,076' 9' 6 05/12/2022 Open Beluga E5 4,198' 4,200' 4,082' 4,084' 2' 6 05/12/2022 Open Beluga E5 4,248' 4,261' 4,134' 4,147' 13' 6 05/12/2022 Open Beluga E6 4,272' 4,276' 4,157' 4,161' 4' 6 05/12/2022 Open Beluga E6 4,321' 4,333' 4,203' 4,215' 12' 6 05/12/2022 Open Beluga F1 4,377' 4,385' 4,259' 4,267' 8' 6 05/11/2022 Open Beluga F4 4,413' 4,426' 4,295' 4,308' 13' 6 05/11/2022 Open Beluga F4 4,460' 4,468' 4,341' 4,349' 8' 6 05/11/2022 Open Beluga F6 4,547' 4,556' 4,427' 4,436' 9' 6 05/11/2022 Open Beluga F6 4,577' 4,581' 4,455' 4,459' 4' 6 05/11/2022 Open Beluga F7 4,639' 4,643' 4,519' 4,523' 4' 6 05/11/2022 Open CASING DETAIL Size Type WT Grade Conn ID Btm 20'' Conductor 166# X-56 Weld 19.124'' 98' 13-3/8" Surface 68# K-55 Butt 12.415'' 2,677' 9-5/8" Prod Casing 47# S-95 Butt Mod. 8.681'' 4,800' TUBING DETAILS 5-1/2” Prod String 15.5# L-80 LTC 4.95'' 3,811' 3-1/2 Prod. Tubing 9.2# L-80 IBT 2.992” 4,713’ Plugs/Fish/Other ID.Depth MD (ft.)ID (in.) Description P1 3,745 - 9-5/8" Marker Joint P2 4,718 - Float Collar _____________________________________________________________________________________ Updated by JMF 01/10/23 PROPOSED Beluga River Unit Well: BRU 212-35T Last Completed: 10/10/1998 PTD: 198-161 API: 50-283-20097-00 20” 13-3/8” 9-5/8” RKB to MSL = 92.5’ RKB to GL = 22.5’ TD = 4,801’ MD / 4,678’ TVD PBTD = 4,716’MD / 4,594’ TVD Sterling A Max Angle = 22 deg @ 1,970’ 3 4 5/6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Sterling B Sterling C 09/98 P1 2 P2 1 BEL E1 TOC in 3-1/2 @ 3,411’ CBL dated: 5/7/22 BEL E5 BEL E6 BEL F1 BEL F4 BEL F6 BEL F7 BEL D-F Planned JEWELRY DETAIL Production String ID. Depth MD Depth TVD ID (in.) Description 25 25 5.5 10"x5.5" DCB Hanger w/ 5.5" API LTC csg top/btm 1 172’ 172’ 2.813 Giant 2.813 GXSV Nipple 2 2,010 1,983 4.653 Teledyne-Merla GLM 5.5"x1.5", 15.5# set 10/08/1998 3 2,765 2,687 4.653 Teledyne-Merla GLM 5.5"x1.5", 15.5# set 10/08/1998 4 3,079 2,986 4.562 Otis 'X' Sliding Sleeve, closed 5 3,128 3,033 4.875 Baker GBH-22 Locator Seal Assy, 190-60, 8' stroke 6 3,135 3,040 6 Baker SC-1 Gravel Pack Packer 96A4-60 7 3,149 3,054 4.75 Baker S Mini-Beta Gravel Pack 190-47 w/ss (18 ft.) 8 3,261 3,163 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (91 ft.) 9 3,354 3,254 6 Baker SC-1L Isolation Pkr. 96A4-60 10 3,359 3,259 4.75 Baker S Mini-Beta Gravel Pack 190-47 w/ss (18 ft.) 11 3,401 3,300 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (30 ft.) 12 3,441 3,339 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (121 ft.) 13 3,564 3,459 6 Baker SC-1L Isolation Pkr. 96A4-60 14 3,570 3,465 4.75 Baker S Mini-Beta Gravel Pack 190-47 w/ss (18 ft.) 15 3,611 3,506 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (30 ft.) 16 3,655 3,549 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (121 ft.) 17 3,776 3,667 4.75 Baker S-22B Snaplatch Seal Assembly 18 3,777 3,668 6 Baker FB-1 Retainer Prod. Pkr. 192-60 19 3,811 3,702 4.767 Wireline Entry Guide PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) Amt SPF Phase Date Status Sterling A 3,264' 3,346' 3,166' 3,246' 59'* 14 12 05/06/2022 Isolated Sterling A 3,388' 3,416' 3,287' 3,315' 28' 14 12 05/06/2022 Isolated Sterling B 3,450' 3,492' 3,348' 3,389' 42' 14 12 05/06/2022 Isolated Sterling B 3,523' 3,556' 3,419' 3,452' 14'* 14 12 05/06/2022 Isolated Sterling C 3,598' 3,636' 3,493' 3,530' 18'* 14 11 05/06/2022 Isolated Sterling C 3,692' 3,712' 3,585' 3,605' 20' 14 11 05/06/2022 Isolated Beluga D-F ~3793’ 4634’ Planned Beluga E1 4,004' 4,012' 3,890' 3,898' 8' 6 05/12/2022 Open Beluga E1 4,046' 4,059' 3,932' 3,945' 13' 6 05/12/2022 Open Beluga E3 4,114' 4,117' 3,999' 4,002' 3' 6 05/12/2022 Open Beluga E5 4,182' 4,191' 4,067' 4,076' 9' 6 05/12/2022 Open Beluga E5 4,198' 4,200' 4,082' 4,084' 2' 6 05/12/2022 Open Beluga E5 4,248' 4,261' 4,134' 4,147' 13' 6 05/12/2022 Open Beluga E6 4,272' 4,276' 4,157' 4,161' 4' 6 05/12/2022 Open Beluga E6 4,321' 4,333' 4,203' 4,215' 12' 6 05/12/2022 Open Beluga F1 4,377' 4,385' 4,259' 4,267' 8' 6 05/11/2022 Open Beluga F4 4,413' 4,426' 4,295' 4,308' 13' 6 05/11/2022 Open Beluga F4 4,460' 4,468' 4,341' 4,349' 8' 6 05/11/2022 Open Beluga F6 4,547' 4,556' 4,427' 4,436' 9' 6 05/11/2022 Open Beluga F6 4,577' 4,581' 4,455' 4,459' 4' 6 05/11/2022 Open Beluga F7 4,639' 4,643' 4,519' 4,523' 4' 6 05/11/2022 Open CASING DETAIL Size Type WT Grade Conn ID Btm 20'' Conductor 166# X-56 Weld 19.124'' 98' 13-3/8" Surface 68# K-55 Butt 12.415'' 2,677' 9-5/8" Prod Casing 47# S-95 Butt Mod. 8.681'' 4,800' TUBING DETAILS 5-1/2” Prod String 15.5# L-80 LTC 4.95'' 3,811' 3-1/2 Prod. Tubing 9.2# L-80 IBT 2.992” 4,713’ Plugs/Fish/Other ID. Depth MD (ft.) ID (in.) Description P1 3,745 - 9-5/8" Marker Joint P2 4,718 - Float Collar Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 05/24/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL BRU 212-35T (PTD 198-161) PERF 05/12/2022 Please include current contact information if different from above. PTD:198-161 T36658 Kayla Junke Digitally signed by Kayla Junke Date: 2022.05.25 11:54:22 -08'00' Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 5/16/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL BRU 212-35T (PTD 198-161) CBL 5/07/2022 Please include current contact information if different from above. PTD:198-161 T36608 Kayla Junke Digitally signed by Kayla Junke Date: 2022.05.16 14:51:56 -08'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Jacob Flora Cc:Todd Sidoti - (C) Subject:RE: BRU 212-35T PTD 198-161 Sundry_322-123_Approved 040822 (3.5 CBL) Date:Tuesday, May 10, 2022 9:07:00 AM Jake, You have approval to proceed with the perfs. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Jacob Flora <Jake.Flora@hilcorp.com> Sent: Monday, May 9, 2022 3:03 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Todd Sidoti - (C) <Todd.Sidoti@hilcorp.com> Subject: BRU 212-35T PTD 198-161 Sundry_322-123_Approved 040822 (3.5 CBL) Hello Bryan, Please see attached CBL of the 3.5 tubing we cemented in place. I was surprised at how little the gravel pack screened interval drank as the TOC is above the planned top of 3500’. Let me know if you see any concerns, we plan on perforating it Wednesday, Thanks Jake Jake Flora | Kenai Ops Engineer | Hilcorp Alaska | 720-988-5375 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. From:Regg, James B (OGC) To:AOGCC Reporting (CED sponsored) Subject:FW: [EXTERNAL] RE: BRU 212-35T (PTD 198-161) - BOP test extension request Date:Friday, May 6, 2022 5:08:41 PM Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Regg, James B (OGC) Sent: Friday, May 6, 2022 5:06 PM To: Jacob Flora <Jake.Flora@hilcorp.com> Subject: RE: [EXTERNAL] RE: BRU 212-35T (PTD 198-161) - BOP test extension request Either way its approved. FYI, an extension would mean you are delaying the test. In this case it appears to me you do not plan to tests the Rig 401 BOPE on well BRU 212-35T so that would be a waiver. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Jacob Flora <Jake.Flora@hilcorp.com> Sent: Friday, May 6, 2022 2:54 PM To: Regg, James B (OGC) <jim.regg@alaska.gov> Subject: Re: [EXTERNAL] RE: BRU 212-35T (PTD 198-161) - BOP test extension request A one day extension to allow us to put the tree on and RDMO, which will occur tomorrow. Thank you On May 6, 2022, at 1:25 PM, Regg, James B (OGC) <jim.regg@alaska.gov> wrote: Are you asking for an extension or waiver? Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Jacob Flora <Jake.Flora@hilcorp.com> Sent: Friday, May 6, 2022 1:16 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Howard Hooter - (C) <Howard.Hooter@hilcorp.com> Subject: BRU 212-35T (PTD 198-161) - BOP test extension request Hello Jim, We have rig 401 on this well now and just cemented in 3.5 tubing per the approved sundry. Currently we have 1500 psi trapped on it and are waiting on the cement to harden before bleeding back and nippling down. Per the 7 day clock we would need to have the tree back on by midnight tonight. With permission we would like to request a one day extension that would allow us to leave the pressure on it overnight, and ND/NU the tree tomorrow am. Thanks for looking at this, Jake Flora Kenai Operations Engineer Hilcorp On Apr 6, 2022, at 4:23 PM, McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> wrote: Jake, Could you send me the aerial photo showing the SSSV 660’ radius? Why will the well require an SSSV in the planned completion, but it doesn’t right now? We might have already discussed this, but can you not run a production packer above the screens? You could run the completion, set the packer, then pump the cement as you planned, except with returns going into the screens instead of back up to surface. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Let me know if you have any of the MIT results yet. I’m assuming that since this well hasn’t been on the weekly priority list, you are not in a big hurry to get this sundry approved? Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Jacob Flora <Jake.Flora@hilcorp.com> Sent: Wednesday, March 30, 2022 10:01 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] BRU 212-35T (PTD 198-161) Cement Bryan, The reason for leaving the TOC below the gravel pack packer is to preserve maximum depth for a future sidetrack. For cutting/pulling the tubing strings in the future we would be limited to where the 3-1/2 x 5-1/2 TOC came to. Due to depleted zones in the gravel pack, it would be difficult to estimate the cement volume to bring the TOC right to this upper packer depth. We would be fine planning the TOC right to this upper packer depth with the provision it would not have to pass a MITIA. The MITIA is a big driver here as remediating a failed MITIA would be done with a down squeeze, and again complicate a future de-complete attempt. We have no intention of producing from the annulus, and the well will not be set up to produce from the annulus, and will not have a SSV on the side outlet. Let me know if you need more data, we are working on our 5-1/2 x 9-5/8 MITIAs now (for both 212-35T & 232-26). Thanks, Jake From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, March 29, 2022 4:20 PM To: Jacob Flora <Jake.Flora@hilcorp.com> Subject: [EXTERNAL] BRU 212-35T (PTD 198-161) Cement Jake, A couple questions about the proposed sundry. Why not bring cement up above the Sterling gravel pack so that you can pressure test the 3.5” x 5.5” annulus? Do you have any intention of producing from the sterling gravel pack in the future? Is the well currently set up to produce from this annulus? Does it have a SSV on the side outlet? Thanks Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibilityof the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received thismessage in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Howard Hooter - (C) To:DOA AOGCC Prudhoe Bay;Brooks, Phoebe L (OGC) Subject:Test Report Hilcorp 401 BRU 212-35T Date:Tuesday, May 3, 2022 10:00:41 AM Attachments:Hilcorp Rig 401 4-29-22.xlsx Please test rpt for Hilcorp 401 4-29-22 BRU 212-35T Thank you ED Hooter The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. %HOXJD5LYHU8QLW7 37' STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* SSu b m i tt t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Owner/Contractor: Rig No.:401 DATE: 4/29/22 Rig Rep.: Rig Phone: 907-283-2580 Operator: Op. Phone:318-452-8947 Rep.: E-Mail Well Name: PTD #11981610 Sundry #322-123 Operation: Drilling: Workover: X Explor.: Test: Initial: X Weekly: Bi-Weekly: Other: Rams:250 / 2500 Annular:250 / 2500 Valves:250 / 2500 MASP:1642 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen.P Well Sign P Upper Kelly 0NA Housekeeping P Rig P Lower Kelly 0NA PTD On Location P Hazard Sec.NA Ball Type 1P Standing Order Posted P Misc.NA Inside BOP 1P FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0NATrip Tank NA NA Annular Preventer 1 13-5/8 5M P Pit Level Indicators PP #1 Rams 1 2-3/8 X 3-1/2 VBR P Flow Indicator NA NA #2 Rams 1 Blind rams P Meth Gas Detector PP #3 Rams 0NAH2S Gas Detector PP #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NA Quantity Test Result Choke Ln. Valves 1 3-1/8 5m P Inside Reel valves 0NA HCR Valves 1 3-1/8 5m P Kill Line Valves 3 3-1/8 5m P Check Valve 0NAACCUMULATOR SYSTEM: BOP Misc 0NA Time/Pressure Test Result System Pressure (psi)3000 P CHOKE MANIFOLD:Pressure After Closure (psi)1850 P Quantity Test Result 200 psi Attained (sec)36 P No. Valves 8P Full Pressure Attained (sec)142 P Manual Chokes 2P Blind Switch Covers: All stations Yes Hydraulic Chokes 0NA Nitgn. Bottles # & psi (Avg.): 6 @ 2175 P CH Misc 0NA ACC Misc 0NA Test Results Number of Failures:0 Test Time:4.0 Hours Repair or replacement of equipment will be made within days. Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 4/27/22 9:46 Waived By Test Start Date/Time:4/29/2022 13:30 (date) (time)Witness Test Finish Date/Time:4/29/2022 17:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Hilcorp Tested with 2-3/8", 2-7/8", & 3-1/2" test joints, PVT,Gas detector alarms tested by Quadc, Annular closing time 27 seconds Kevin Reed Hilcorp Ed Hooter BRU 212-35T Test Pressure (psi): howard.hooter@hilcorp Form 10-424 (Revised 02/2022) 2022-0429_BOP_Hilcorp401_BRU_212-35T 9 9 9 9 9 9 9 9 99 9 9 -5HJJ Annular closing time 27 seconds 7\SHRI5HTXHVW $EDQGRQ 3OXJ3HUIRUDWLRQV )UDFWXUH6WLPXODWH 5HSDLU:HOO 2SHUDWLRQVVKXWGRZQ 6XVSHQG 3HUIRUDWH 2WKHU6WLPXODWH 3XOO7XELQJ &KDQJH$SSURYHG3URJUDP 3OXJIRU5HGULOO 3HUIRUDWH1HZ3RRO 5HHQWHU6XVS:HOO $OWHU&DVLQJ 2SHUDWRU1DPH &XUUHQW:HOO&ODVV 3HUPLWWR'ULOO1XPEHU ([SORUDWRU\ 'HYHORSPHQW $GGUHVV6WUDWLJUDSKLF 6HUYLFH $3,1XPEHU ,ISHUIRUDWLQJ:HOO1DPHDQG1XPEHU :KDW5HJXODWLRQRU&RQVHUYDWLRQ2UGHUJRYHUQVZHOOVSDFLQJLQWKLVSRRO" :LOOSODQQHGSHUIRUDWLRQVUHTXLUHDVSDFLQJH[FHSWLRQ" <HV 1R 3URSHUW\'HVLJQDWLRQ/HDVH1XPEHU )LHOG3RROV 7RWDO'HSWK0'IW 7RWDO'HSWK79'IW (IIHFWLYH'HSWK0' (IIHFWLYH'HSWK79' 0363SVL 3OXJV0' -XQN0' 1$ &DVLQJ &ROODSVH 6WUXFWXUDO &RQGXFWRU 6XUIDFH SVL ,QWHUPHGLDWH 3URGXFWLRQ SVL /LQHU 3DFNHUVDQG66697\SH 3DFNHUVDQG66690'IWDQG79'IW $WWDFKPHQWV 3URSRVDO6XPPDU\ :HOOERUHVFKHPDWLF :HOO&ODVVDIWHUSURSRVHGZRUN 'HWDLOHG2SHUDWLRQV3URJUDP %236NHWFK ([SORUDWRU\ 6WUDWLJUDSKLF 'HYHORSPHQW 6HUYLFH (VWLPDWHG'DWHIRU :HOO6WDWXVDIWHUSURSRVHGZRUN &RPPHQFLQJ2SHUDWLRQV 2,/ :,1- :'63/6XVSHQGHG 9HUEDO$SSURYDO 'DWH *$6 :$* *6725 63/8* $2*&&5HSUHVHQWDWLYH*,1-2S6KXWGRZQ $EDQGRQHG &RQWDFW1DPH -DNH)ORUD &RQWDFW(PDLO &RQWDFW3KRQH $XWKRUL]HG7LWOH &RQGLWLRQVRIDSSURYDO1RWLI\$2*&&VRWKDWDUHSUHVHQWDWLYHPD\ZLWQHVV 6XQGU\1XPEHU 3OXJ,QWHJULW\ %237HVW 0HFKDQLFDO,QWHJULW\7HVW /RFDWLRQ&OHDUDQFH 2WKHU 3RVW,QLWLDO,QMHFWLRQ0,75HT G"<HV 1R 6SDFLQJ([FHSWLRQ5HTXLUHG"<HV 1R 6XEVHTXHQW)RUP5HTXLUHG $33529('%< $SSURYHGE\ &200,66,21(5 7+($2*&& 'DWH &RPP &RPP 6U3HW(QJ 6U3HW*HR 6U5HV(QJ 1$ ,KHUHE\FHUWLI\WKDWWKHIRUHJRLQJLVWUXHDQGWKHSURFHGXUHDSSURYHGKHUHLQZLOOQRWEHGHYLDWHGIURPZLWKRXWSULRUZULWWHQDSSURYDO $XWKRUL]HG1DPHDQG 'LJLWDO6LJQDWXUHZLWK'DWH $2*&&86(21/< 'DQ0DUORZH2SHUDWLRQV0DQDJHU -DNH)ORUD#KLOFRUSFRP 7XELQJ*UDGH 7XELQJ0'IW3HUIRUDWLRQ'HSWK79'IW 7XELQJ6L]H 6HHVFKHPDWLF 6HHVFKHPDWLF 35(6(17:(//&21',7,216800$5< 67$7(2)$/$6.$ $/$6.$2,/$1'*$6&216(59$7,21&200,66,21 $33/,&$7,21)25681'5<$33529$/6 $$& )('$ %HOXJD5LYHU8QLW7 %HOXJD5LYHU)LHOG8QGHILQHG*DV3RRO &2 &HQWHUSRLQW'ULYH6XLWH $QFKRUDJH$. +LOFRUS$ODVND//& 2WKHU1&HPHQWLQJ2SHUDWLRQV ,QVWDOO7EJ6WULQJ /HQJWK 6L]H / / 79' %XUVW SVL 0' SVL 3HUIRUDWLRQ'HSWK0'IW U\ 6WDWX )RUP5HYLVHG$SSURYHGDSSOLFDWLRQLVYDOLGIRUPRQWKVIURPWKHGDWHRIDSSURYDO By Samantha Carlisle at 9:47 am, Mar 11, 2022 'LJLWDOO\VLJQHGE\'DQ0DUORZH '1FQ 'DQ0DUORZH RX 8VHUV 'DWH 'DQ0DUORZH BJM 4/8/22 X DSR-3/14/22SFD 3/11/2022 10-404 Production from the 3-1/2" x 5-1/2" annulus is not allowed. Place a tag on the annulus valve indicating that production is not permitted without AOGCC approval and a Surface Safety Valve system installed on the flowing side outlet of the annulus. BOP test to 2500 psi. dts 4/8/2022 Jeremy Price Digitally signed by Jeremy Price Date: 2022.04.08 11:34:59 -08'00' RBDMS SJC 041222 tĞůůWƌŽŐŶŽƐŝƐ tĞůůEĂŵĞ͗ZhϮϭϮͲϯϱd W/EƵŵďĞƌ͗ϱϬͲϮϴϯͲϮϬϬϵϳͲϬϬͲϬϬ ƵƌƌĞŶƚ^ƚĂƚƵƐ͗^/'ĂƐWƌŽĚƵĐĞƌ ZŝŐ͗ϰϬϭ ZĞŐƵůĂƚŽƌǇŽŶƚĂĐƚ͗:ƵĂŶŝƚĂ>ŽǀĞƚƚϳϳϳͲϴϯϯϮ WĞƌŵŝƚƚŽƌŝůůEƵŵďĞƌ͗ϭϵϴͲϭϲϭ &ŝƌƐƚĂůůŶŐŝŶĞĞƌ͗:ĂŬĞ&ůŽƌĂ ;ϵϬϳͿϳϳϳͲϴϰϰϮ ;KͿ ;ϳϮϬͿϵϴϴͲϱϯϳϱ;DͿ ^ĞĐŽŶĚĂůůŶŐŝŶĞĞƌ͗ŚĂĚ,ĞůŐĞƐŽŶ ;ϵϬϳͿϳϳϳͲϴϰϮϬ;KͿ ;ϵϬϳͿϮϮϵͲϰϴϮϰ ;DͿ 0D[3RWHQWLDO%+3 SVL %DVHGRQSVLIWJUDGLHQWDWIW79' 0D[3RWHQWLDO6XUIDFH3UHVVXUH SVL %DVHGRQ%+3PLQXVSVLIWJDVJUDGLHQW &XUUHQW6,73 SVL tĞůů^ƚĂƚƵƐ͗ ^/ŐĂƐƉƌŽĚƵĐĞƌƐŝŶĐĞϮϬϮϬ ƌŝĞĨtĞůů^ƵŵŵĂƌǇ ƌŝůůĞĚΘĐŽŵƉůĞƚĞĚŝŶϭϵϵϴĂƐĂ^ƚĞƌůŝŶŐƉƌŽĚƵĐĞƌǁŝƚŚϱͲϭͬϮΗŐƌĂǀĞůƉĂĐŬƚŽϯ͕ϴϭϭ͕͛ǁŚŝůĞůĞĂǀŝŶŐƚŚĞǁĞůůĐĂƐĞĚ ƚŚƌŽƵŐŚƚŚĞĞůƵŐĂƐĂŶĚƐďĞůŽǁ͘Ŷ^WǁĂƐŝŶƐƚĂůůĞĚƚŚƌƵƚďŐŽŶĚƵĂůĐŽŝůŝŶϮϬϭϱƚŽŚĞůƉƵŶůŽĂĚǁĂƚĞƌ͘dŚĞ ǁĞůůǁĂƐŵĂŬŝŶŐϯͲϰDD&ƵŶƚŝůĂŚŽůĞŝŶƚďŐĐŽŵƉƌŽŵŝƐĞĚƚŚĞĐŽŵƉůĞƚŝŽŶŝŶůĂƚĞϮϬϭϳ͘/ŶƚŚĞƐƵŵŵĞƌŽĨ ϮϬϭϵ͕ƚŚĞĚƵĂůĐŽŝů^WǁĂƐƉƵůůĞĚĨƌŽŵƚŚĞǁĞůů͘dŚĞǁĞůůǁŽƵů ĚŶŽƚĨůŽǁ͘/ŶƐƵŵŵĞƌϮϬϮϬ͕ĂƚƵďŝŶŐĐŽŶǀĞǇĞĚ ^WǁĂƐƉůĂĐĞĚďĂĐŬŝŶƚŚĞǁĞůů͕ŚŽǁĞǀĞƌƚŚĞǁĞůůĐŽƵůĚŶŽƚƐƵƐƚĂŝŶĨůŽǁůŽŶŐƚĞƌŵĂŶĚǁĂƐƐŚƵƚͲŝŶ͘dŚŝƐǁĞůů ŚĂƐŶŽƌĞŵĂŝŶŝŶŐǀĂůƵĞŝŶŝƚƐĐƵƌƌĞŶƚĐŽŶĨŝŐƵƌĂƚŝŽŶ͘ dŚĞŽďũĞĐƚŝǀĞŽĨƚŚŝƐƐƵŶĚƌǇŝƐƚŽƉƵůůƚŚĞĞǆŝƐƚŝŶŐ^W͕ĂŶĚŝ ƐŽůĂƚĞƚŚĞǁĞƚ^ƚĞƌůŝŶŐŐƌĂǀĞůƉĂĐŬĐŽŵƉůĞƚŝŽŶďĞŚŝŶĚ ĂĐĞŵĞŶƚĞĚϯͲϭͬϮ͟ƚƵďŝŶŐƐƚƌŝŶŐƌĂŶƚŽd͘dŚĞĞůƵŐĂͲ&ƐĂŶĚƐǁŝůůƚŚĞŶďĞƉĞƌĨŽƌĂƚĞĚĂŶĚƚĞƐƚĞĚ͘ůůƐĂŶĚƐ ůŝĞŝŶƚŚĞĞůƵŐĂ^ƚĞƌůŝŶŐhŶĚĞĨŝŶĞĚ'ĂƐWŽŽů͘ EŽƚĞƐZĞŐĂƌĚŝŶŐtĞůůďŽƌĞŽŶĚŝƚŝŽŶ͗ ϲͬϵͬϮϬϮϬ ΘdǁŝƚŚϭϭ͛ϰ͘ϱ͟ĚƵŵŵǇŐƵŶƚŽϰϳϮϴ͛ WƌŽĐĞĚƵƌĞ͗ ϭ͘ ZĞǀŝĞǁKƐŝŶƉƉƌŽǀĞĚ^ƵŶĚƌǇϭϬͲϰϬϯ&Žƌŵ Ϯ͘ D/d/ϱͲϭͬϮ͟ǆϵͲϱͬϴ͟ĂŶŶƵůƵƐƚŽϮϬϬϬƉƐŝ ϯ͘ D/ZhϰϬϭǁŽƌŬŽǀĞƌƌŝŐ ϰ͘ WƌŽǀŝĚĞK'ϰϴŚƌƐŝŶĂĚǀĂŶĐĞŽĨKWƚĞƐƚ ϱ͘ ƵůůŚĞĂĚƚŚĞϮͲϯͬϴ͟ǆϱͲϭͬϮ͟ĂŶŶƵůƵƐƚŽƉůĂĐĞǁĞůůŽŶĂǀĂĐƵƵŵ ϲ͘ /ŶƐƚĂůůdt ϳ͘ EdƌĞĞ ϴ͘ EhKWĂŶĚƚĞƐƚƚŽϮϱϬϬƉƐŝ ϵ͘ WƵůůdt ϭϬ͘ WƵůůĂŶĚůĂǇĚŽǁŶϮͲϯͬϴ͟^WĐŽŵƉůĞƚŝŽŶ ϭϭ͘ ZƵŶϯͲϭͬϮ͟ƐƉĞĐŝĂůĐůĞĂƌĂŶĐĞƚƵďŝŶŐƚŽΕϰϳϬϬ͛;ĐŽƵƉůŝŶŐKϯ͘ϴϲϱ͟Ϳ͕ůĂŶĚƚƵďŝŶŐŚĂŶŐĞƌ͕ƚĞƐƚƐĞĂůƐ Ă͘ ^ƵƌĨĂĐĞĐŽŶƚƌŽůůĞĚ^^^sŶŝƉƉůĞƐĞƚΕϭϭϬ͛;ŵŝŶŝŵƵŵϭϬϬ͛ĞůŽǁ'ƌŽƵŶĚ>ĞǀĞůͿ ϭϮ͘ ZhĐĞŵĞŶƚŚĞĂĚƚŽůĂŶĚŝŶŐũŽŝŶƚ͕ƉƵŵƉϵϰďďůƐϭϱ͘ϯƉƉŐĐĞŵĞŶƚ͕ĚƌŽƉǁŝƉĞƌďĂůů͕ĚŝƐƉůĂĐĞǁŝƚŚϰϭďďůƐ ǁĂƚĞƌ Ă͘ WůĂŶŶĞĚdKŝŶϯͲϭͬϮǆϱͲϭͬϮĂŶŶƵůƵƐсϯϱϬϬ͛ ď͘ WƵŵƉƚŚƌƵ^^^sĐŽŶƚƌŽůůŝŶĞĚƵƌŝŶŐĐĞŵĞŶƚũŽď ϭϯ͘ /ƐŽůĂƚĞƚƵďŝŶŐ͕tKŽǀĞƌŶŝŐŚƚ ϭϰ͘ D/dƚƵďŝŶŐƚŽϮϬϬϬƉƐŝ ĞůƵŐĂͲ&ƐĂŶĚƐǁŝůůƚŚĞŶďĞƉĞƌĨŽƌĂƚĞĚĂŶĚƚĞƐƚĞĚ͘ Bullhead tubing as well. - bjm No Float shoe? Use Kill Weight Fluid. Done. 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Ϯϭ͘dƵƌŶŽǀĞƌƚŽƉƌŽĚƵĐƚŝŽŶ ϮϮ͘/ŶƐƚĂůůtZͲ^^^sĂŶĚƚĞƐƚ ΎΎůůƚĂƌŐĞƚƐĂŶĚƐĂƌĞďĞůŽǁƚŚĞĞǆŝƐƚŝŶŐϱͲϭͬϮǆϵͲϱͬϴĂŶŶƵůƵƐ ŽŝůdƵďŝŶŐΘEŝƚƌŽŐĞŶWƌŽĐĞĚƵƌĞ;ŽŶƚŝŶŐĞŶĐǇŝĨĨŝůůŝƐĞŶĐŽƵŶƚĞƌĞĚĂĨƚĞƌƉĞƌĨŽƌĂƚŝŶŐ͕ŽƌĐĞŵĞŶƚƐƚƌŝŶŐĞƌƐ ĂĨƚĞƌĐĞŵĞŶƚŝŶŐͿ͗ ϭ͘D/ZhŽŝůĞĚdƵďŝŶŐ͕ŶŽƚŝĨǇK'ϰϴŚŽƵƌƐŝŶĂĚǀĂŶĐĞŽĨKWƚĞƐƚ͕WdKWƚŽϮϱϬϬƉƐŝ Ϯ͘ůĞĂŶŽƵƚƚŽd ϯ͘ůŽǁĚŽǁŶǁĞůůǁŝƚŚŶŝƚƌŽŐĞŶ͕ƚƌĂƉƉƌĞƐƐƵƌĞĨŽƌƉĞƌĨŽƌĂƚŝŶŐ͕ZDKdh ͲůŝŶĞWƌŽĐĞĚƵƌĞ;ŽŶƚŝŶŐĞŶĐǇŝĨǁĂƚĞƌŝƐĞŶĐŽƵŶƚĞƌĞĚĂĨƚĞƌƉĞƌĨŽƌĂƚŝŶŐͿ͗ ϭ͘D/ZhͲ>ŝŶĞ͕WdůƵďƌŝĐĂƚŽƌƚŽϮϱϬϬƉƐŝ Ϯ͘Z/,ĂŶĚƐĞƚƉůƵŐĂďŽǀĞƚŚĞƉĞƌĨŽƌĂƚŝŽŶƐKZƐĞƚƉĂƚĐŚŽǀĞƌƚŚĞǁĞƚƉĞƌĨŽƌĂƚŝŽŶƐ͘ tĞůůWƌŽŐŶŽƐŝƐ ƚƚĂĐŚŵĞŶƚƐ͗ ϭ͘ĐƚƵĂů^ĐŚĞŵĂƚŝĐ Ϯ͘WƌŽƉŽƐĞĚ^ĐŚĞŵĂƚŝĐ ϯ͘ƵƌƌĞŶƚtĞůůŚĞĂĚŝĂŐƌĂŵ ϰ͘WƌŽƉŽƐĞĚtĞůůŚĞĂĚŝĂŐƌĂŵ ϱ͘ZŝŐϰϬϭKWŝĂŐƌĂŵ ϲ͘EŝƚƌŽŐĞŶ^KW ϳ͘ZtKŚĂŶŐĞ&Žƌŵ BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB hƉĚĂƚĞĚďǇ:D&ϭϮͲϭϱͲϮϬ ^,Dd/ ĞůƵŐĂZŝǀĞƌhŶŝƚ tĞůů͗ZhϮϭϮͲϯϱd >ĂƐƚŽŵƉůĞƚĞĚ͗ϭϬͬϭϬͬϭϵϵϴ Wd͗ϭϵϴͲϭϲϭ W/͗ϱϬͲϮϴϯͲϮϬϬϵϳͲϬϬ ϮϬ͟ ϭϯͲϯͬϴ͟ ϵͲϱͬϴ͟ Z<ƚŽD^>сϵϮ͘ϱ͛Z<ƚŽ'>сϮϮ͘ϱ͛ dсϰ͕ϴϬϭ͛Dͬϰ͕ϲϳϴ͛ds Wdсϰ͕ϳϭϲ͛Dͬϰ͕ϱϵϰ͛ds ^ƚĞƌůŝŶŐ DĂǆŶŐůĞсϮϮĚĞŐΛϭ͕ϵϳϬ͛ dƵďŝŶŐDŝŶ /сϰ͘ϱϲϮ͟ ϯ ϰ ϱͬϲ ϳ ϴ ϵ ϭϬ ϭϭ ϭϮ ϭϯ ϭϰ ϭϱ ϭϲ ϭϳ ϭϴ ϭϵ ϮϬ ^ƚĞƌůŝŶŐ ^ƚĞƌůŝŶŐ Ϭϵͬϵϴ Wϭ Ϯ WϮ ϭ ^/E'd/> ^ŝǌĞ dǇƉĞ td 'ƌĂĚĞ ŽŶŶ / ƚŵ ϮϬΖΖŽŶĚƵĐƚŽƌϭϲϲηyͲϱϲtĞůĚϭϵ͘ϭϮϰΖΖϵϴΖ ϭϯͲϯͬϴΗ^ƵƌĨĂĐĞϲϴη<ͲϱϱƵƚƚϭϮ͘ϰϭϱΖΖϮ͕ϲϳϳΖ ϵͲϱͬϴΗWƌŽĚĂƐŝŶŐϰϳη^ͲϵϱƵƚƚDŽĚ͘ϴ͘ϲϴϭΖΖϰ͕ϴϬϬΖ dh/E'd/>^ ϱͲϭͬϮ͟WƌŽĚ^ƚƌŝŶŐϭϱ͘ϱη>ͲϴϬ>dϰ͘ϵϱΖΖϯ͕ϴϭϭΖ ϮͲϯͬϴ͟WƌŽĚ͘dƵďŝŶŐϰ͘ϲη>ͲϴϬϴZhϭ͘ϵϳϱ͟ϯ͕ϴϵϭ͛ WXELQJ (63UDQ :t>Zzd/> WƌŽĚƵĐƚŝŽŶ^ƚƌŝŶŐ /͘ ĞƉƚŚD;Ĩƚ͘Ϳ /;ŝŶ͘Ϳ ĞƐĐƌŝƉƚŝŽŶ ϭϮϱϱ͘ϱϭϬΗǆϱ͘ϱΗ,ĂŶŐĞƌǁͬϱ͘ϱΗW/>dĐƐŐƚŽƉͬďƚŵ ϮϮ͕ϬϭϬϰ͘ϲϱϯdĞůĞĚǇŶĞͲDĞƌůĂ'>Dϱ͘ϱΗǆϭ͘ϱΗ͕ϭϱ͘ϱηƐĞƚϭϬͬϬϴͬϭϵϵϴ ϯϮ͕ϳϲϱϰ͘ϲϱϯdĞůĞĚǇŶĞͲDĞƌůĂ'>Dϱ͘ϱΗǆϭ͘ϱΗ͕ϭϱ͘ϱηƐĞƚϭϬͬϬϴͬϭϵϵϴ ϰ ϯ͕Ϭϳϵ ϰ͘ϱϲϮ KƚŝƐΖyΖ^ůŝĚŝŶŐ^ůĞĞǀĞ͕ĐůŽƐĞĚ ϱϯ͕ϭϮϴϰ͘ϴϳϱĂŬĞƌ',ͲϮϮ>ŽĐĂƚŽƌ^ĞĂůƐƐǇ͕ϭϵϬͲϲϬ͕ϴΖƐƚƌŽŬĞ ϲϯ͕ϭϯϱϲĂŬĞƌ^Ͳϭ'ƌĂǀĞůWĂĐŬWĂĐŬĞƌϵϲϰͲϲϬ ϳϯ͕ϭϰϵϰ͘ϳϱĂŬĞƌ^DŝŶŝͲĞƚĂ'ƌĂǀĞůWĂĐŬϭϵϬͲϰϳǁͬƐƐ;ϭϴĨƚ͘Ϳ ϴϯ͕Ϯϲϭϰ͘ϵϱĂŬĞƌǁĞůĚ^ĐƌĞĞŶϭϰϬ͕ϯϭϲ>͕͘ϬϭϮΗ'Ă͕͘>ͲϴϬ;ϵϭĨƚ͘Ϳ ϵϯ͕ϯϱϰϲĂŬĞƌ^Ͳϭ>/ƐŽůĂƚŝŽŶWŬƌ͘ϵϲϰͲϲϬ ϭϬϯ͕ϯϱϵϰ͘ϳϱĂŬĞƌ^DŝŶŝͲĞƚĂ'ƌĂǀĞůWĂĐŬϭϵϬͲϰϳǁͬƐƐ;ϭϴĨƚ͘Ϳ ϭϭϯ͕ϰϬϭϰ͘ϵϱĂŬĞƌǁĞůĚ^ĐƌĞĞŶϭϰϬ͕ϯϭϲ>͕͘ϬϭϮΗ'Ă͕͘>ͲϴϬ;ϯϬĨƚ͘Ϳ ϭϮϯ͕ϰϰϭϰ͘ϵϱĂŬĞƌǁĞůĚ^ĐƌĞĞŶϭϰϬ͕ϯϭϲ>͕͘ϬϭϮΗ'Ă͕͘>ͲϴϬ;ϭϮϭĨƚ͘Ϳ ϭϯϯ͕ϱϲϰϲĂŬĞƌ^Ͳϭ>/ƐŽůĂƚŝŽŶWŬƌ͘ϵϲϰͲϲϬ ϭϰϯ͕ϱϳϬϰ͘ϳϱĂŬĞƌ^DŝŶŝͲĞƚĂ'ƌĂǀĞůWĂĐŬϭϵϬͲϰϳǁͬƐƐ;ϭϴĨƚ͘Ϳ ϭϱϯ͕ϲϭϭϰ͘ϵϱĂŬĞƌǁĞůĚ^ĐƌĞĞŶϭϰϬ͕ϯϭϲ>͕͘ϬϭϮΗ'Ă͕͘>ͲϴϬ;ϯϬĨƚ͘Ϳ ϭϲϯ͕ϲϱϱϰ͘ϵϱĂŬĞƌǁĞůĚ^ĐƌĞĞŶϭϰϬ͕ϯϭϲ>͕͘ϬϭϮΗ'Ă͕͘>ͲϴϬ;ϭϮϭĨƚ͘Ϳ ϭϳϯ͕ϳϳϲϰ͘ϳϱĂŬĞƌ^ͲϮϮ^ŶĂƉůĂƚĐŚ^ĞĂůƐƐĞŵďůǇ ϭϴϯ͕ϳϳϳϲĂŬĞƌ&ͲϭZĞƚĂŝŶĞƌWƌŽĚ͘WŬƌ͘ϭϵϮͲϲϬ ϭϵϯ͕ϴϭϭϰ͘ϳϲϳtŝƌĞůŝŶĞŶƚƌǇ'ƵŝĚĞ ϮϬϯ͕ϴϴϵ͛^Wʹ ^Ƶŵŵŝƚ^ϱϱϬϬϲͬϮϮͬϮϬ WůƵŐƐͬ&ŝƐŚͬKƚŚĞƌ /͘ ĞƉƚŚD;Ĩƚ͘Ϳ /;ŝŶ͘Ϳ ĞƐĐƌŝƉƚŝŽŶ Wϭ ϯ͕ϳϰϱͲ ϵͲϱͬϴΗDĂƌŬĞƌ:ŽŝŶƚ WϮ ϰ͕ϳϭϴͲ &ůŽĂƚŽůůĂƌ WZ&KZd/KEd/> ^ĂŶĚƐ dŽƉ;DͿ ƚŵ;DͿ dŽƉ;dsͿ ƚŵ;dsͿ ŵƚ ^W& WŚĂƐĞ ĂƚĞ^ƚĂƚƵƐ ^ƚĞƌůŝŶŐϯ͕ϮϲϰΖϯ͕ϯϰϲΖϯ͕ϭϲϲΖϯ͕ϮϰϲΖϱϵΖΎϭϰϭϮϭϬͬϭͬϭϵϵϴKƉĞŶ ^ƚĞƌůŝŶŐ ϯ͕ϯϴϴΖϯ͕ϰϭϲΖϯ͕ϮϴϳΖϯ͕ϯϭϱΖϮϴΖϭϰϭϮϭϬͬϭͬϭϵϵϴKƉĞŶ ^ƚĞƌůŝŶŐϯ͕ϰϱϬΖϯ͕ϰϵϮΖϯ͕ϯϰϴΖϯ͕ϯϴϵΖϰϮΖϭϰϭϮϭϬͬϭͬϭϵϵϴKƉĞŶ ^ƚĞƌůŝŶŐϯ͕ϱϮϯΖϯ͕ϱϱϲΖϯ͕ϰϭϵΖϯ͕ϰϱϮΖϭϰΖΎϭϰϭϮϭϬͬϭͬϭϵϵϴKƉĞŶ ^ƚĞƌůŝŶŐϯ͕ϱϵϴΖϯ͕ϲϯϲΖϯ͕ϰϵϯΖϯ͕ϱϯϬΖϭϴΖΎϭϰϭϭϭϬͬϭͬϭϵϵϴKƉĞŶ ^ƚĞƌůŝŶŐϯ͕ϲϵϮΖϯ͕ϳϭϮΖϯ͕ϱϴϱΖϯ͕ϲϬϱΖϮϬΖϭϰϭϭϭϬͬϭͬϭϵϵϴKƉĞŶ ΎWĂƌƚŝĂůůǇWĞƌĨŽƌĂƚĞĚ/ŶƚĞƌǀĂů BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB hƉĚĂƚĞĚďǇ:D&ϬϯͬϬϭͬϮϮ WZKWK^ ĞůƵŐĂZŝǀĞƌhŶŝƚ tĞůů͗ZhϮϭϮͲϯϱd >ĂƐƚŽŵƉůĞƚĞĚ͗ϭϬͬϭϬͬϭϵϵϴ Wd͗ϭϵϴͲϭϲϭ W/͗ϱϬͲϮϴϯͲϮϬϬϵϳͲϬϬ ϮϬ͟ ϭϯͲϯͬϴ͟ ϵͲϱͬϴ͟ Z<ƚŽD^>сϵϮ͘ϱ͛Z<ƚŽ'>сϮϮ͘ϱ͛ dсϰ͕ϴϬϭ͛ Dͬ ϰ͕ϲϳϴ͛ds Wdсϰ͕ϳϭϲ͛Dͬϰ͕ϱϵϰ͛ds ^ƚĞƌůŝŶŐ DĂǆŶŐůĞсϮϮĚĞŐΛϭ͕ϵϳϬ͛ ϯ ϰ ϱͬϲ ϳ ϴ ϵ ϭϬ ϭϭ ϭϮ ϭϯ ϭϰ ϭϱ ϭϲ ϭϳ ϭϴ ϭϵ ϮϬ ^ƚĞƌůŝŶŐ ^ƚĞƌůŝŶŐ Ϭϵͬϵϴ Wϭ Ϯ WϮ ϭ ĞůƵŐĂ Ϯ ƚŚƌƵ &ϳ WůĂŶŶĞĚϯͲϭͬϮ dKΛϯϱϬϬ͛ ^/E'd/> ^ŝǌĞ dǇƉĞ td 'ƌĂĚĞ ŽŶŶ / ƚŵ ϮϬΖΖ ŽŶĚƵĐƚŽƌ ϭϲϲη yͲϱϲ tĞůĚ ϭϵ͘ϭϮϰΖΖ ϵϴΖ ϭϯͲϯͬϴΗ ^ƵƌĨĂĐĞ ϲϴη <Ͳϱϱ Ƶƚƚ ϭϮ͘ϰϭϱΖΖ Ϯ͕ϲϳϳΖ ϵͲϱͬϴΗ WƌŽĚĂƐŝŶŐ ϰϳη ^Ͳϵϱ ƵƚƚDŽĚ͘ ϴ͘ϲϴϭΖΖ ϰ͕ϴϬϬΖ dh/E'd/>^ ϱͲϭͬϮ͟ WƌŽĚ^ƚƌŝŶŐ ϭϱ͘ϱη >ͲϴϬ >d ϰ͘ϵϱΖΖ ϯ͕ϴϭϭΖ ϯͲϭͬϮ WƌŽĚ͘dƵďŝŶŐ ϰ͘ϲη >ͲϴϬ /d^ Ϯ͘ϵϵϮ͟ ΕϰϳϬϬ͛ :t>Zzd/> WƌŽĚƵĐƚŝŽŶ^ƚƌŝŶŐ /͘ĞƉƚŚ D ĞƉƚŚ ds/;ŝŶ͘Ϳ ĞƐĐƌŝƉƚŝŽŶ Ϯϱ Ϯϱ ϱ͘ϱ ϭϬΗǆϱ͘ϱΗ,ĂŶŐĞƌǁͬϱ͘ϱΗW/>dĐƐŐƚŽƉͬďƚŵ ϭ ΕϭϭϬ ΕϭϭϬ ^ƵƌĨĂĐĞŽŶƚƌŽůůĞĚ^^^s Ϯ Ϯ͕ϬϭϬ ϭ͕ϵϴϯ ϰ͘ϲϱϯ dĞůĞĚǇŶĞͲDĞƌůĂ'>Dϱ͘ϱΗǆϭ͘ϱΗ͕ϭϱ͘ϱηƐĞƚϭϬͬϬϴͬϭϵϵϴ ϯ Ϯ͕ϳϲϱ Ϯ͕ϲϴϳ ϰ͘ϲϱϯ dĞůĞĚǇŶĞͲDĞƌůĂ'>Dϱ͘ϱΗǆϭ͘ϱΗ͕ϭϱ͘ϱηƐĞƚϭϬͬϬϴͬϭϵϵϴ ϰ ϯ͕Ϭϳϵ Ϯ͕ϵϴϲ ϰ͘ϱϲϮ KƚŝƐΖyΖ^ůŝĚŝŶŐ^ůĞĞǀĞ͕ĐůŽƐĞĚ ϱ ϯ͕ϭϮϴ ϯ͕Ϭϯϯ ϰ͘ϴϳϱ ĂŬĞƌ',ͲϮϮ>ŽĐĂƚŽƌ^ĞĂůƐƐǇ͕ϭϵϬͲϲϬ͕ϴΖƐƚƌŽŬĞ ϲ ϯ͕ϭϯϱ ϯ͕ϬϰϬ ϲ ĂŬĞƌ^Ͳϭ'ƌĂǀĞůWĂĐŬWĂĐŬĞƌϵϲϰͲϲϬ ϳ ϯ͕ϭϰϵ ϯ͕Ϭϱϰ ϰ͘ϳϱ ĂŬĞƌ^DŝŶŝͲĞƚĂ'ƌĂǀĞůWĂĐŬϭϵϬͲϰϳǁͬƐƐ;ϭϴĨƚ͘Ϳ ϴ ϯ͕Ϯϲϭ ϯ͕ϭϲϯ ϰ͘ϵϱ ĂŬĞƌǁĞůĚ^ĐƌĞĞŶϭϰϬ͕ϯϭϲ>͕͘ϬϭϮΗ'Ă͕͘>ͲϴϬ;ϵϭĨƚ͘Ϳ ϵ ϯ͕ϯϱϰ ϯ͕Ϯϱϰ ϲ ĂŬĞƌ^Ͳϭ>/ƐŽůĂƚŝŽŶWŬƌ͘ϵϲϰͲϲϬ ϭϬ ϯ͕ϯϱϵ ϯ͕Ϯϱϵ ϰ͘ϳϱ ĂŬĞƌ^DŝŶŝͲĞƚĂ'ƌĂǀĞůWĂĐŬϭϵϬͲϰϳǁͬƐƐ;ϭϴĨƚ͘Ϳ ϭϭ ϯ͕ϰϬϭ ϯ͕ϯϬϬ ϰ͘ϵϱ ĂŬĞƌǁĞůĚ^ĐƌĞĞŶϭϰϬ͕ϯϭϲ>͕͘ϬϭϮΗ'Ă͕͘>ͲϴϬ;ϯϬĨƚ͘Ϳ ϭϮ ϯ͕ϰϰϭ ϯ͕ϯϯϵ ϰ͘ϵϱ ĂŬĞƌǁĞůĚ^ĐƌĞĞŶϭϰϬ͕ϯϭϲ>͕͘ϬϭϮΗ'Ă͕͘>ͲϴϬ;ϭϮϭĨƚ͘Ϳ ϭϯ ϯ͕ϱϲϰ ϯ͕ϰϱϵ ϲ ĂŬĞƌ^Ͳϭ>/ƐŽůĂƚŝŽŶWŬƌ͘ϵϲϰͲϲϬ ϭϰ ϯ͕ϱϳϬ ϯ͕ϰϲϱ ϰ͘ϳϱ ĂŬĞƌ^DŝŶŝͲĞƚĂ'ƌĂǀĞůWĂĐŬϭϵϬͲϰϳǁͬƐƐ;ϭϴĨƚ͘Ϳ ϭϱ ϯ͕ϲϭϭ ϯ͕ϱϬϲ ϰ͘ϵϱ ĂŬĞƌǁĞůĚ^ĐƌĞĞŶϭϰϬ͕ϯϭϲ>͕͘ϬϭϮΗ'Ă͕͘>ͲϴϬ;ϯϬĨƚ͘Ϳ ϭϲ ϯ͕ϲϱϱ ϯ͕ϱϰϵ ϰ͘ϵϱ ĂŬĞƌǁĞůĚ^ĐƌĞĞŶϭϰϬ͕ϯϭϲ>͕͘ϬϭϮΗ'Ă͕͘>ͲϴϬ;ϭϮϭĨƚ͘Ϳ ϭϳ ϯ͕ϳϳϲ ϯ͕ϲϲϳ ϰ͘ϳϱ ĂŬĞƌ^ͲϮϮ^ŶĂƉůĂƚĐŚ^ĞĂůƐƐĞŵďůǇ ϭϴ ϯ͕ϳϳϳ ϯ͕ϲϲϴ ϲ ĂŬĞƌ&ͲϭZĞƚĂŝŶĞƌWƌŽĚ͘WŬƌ͘ϭϵϮͲϲϬ ϭϵ ϯ͕ϴϭϭ ϯ͕ϳϬϮ ϰ͘ϳϲϳ tŝƌĞůŝŶĞŶƚƌǇ'ƵŝĚĞ WůƵŐƐͬ&ŝƐŚͬKƚŚĞƌ /͘ ĞƉƚŚD;Ĩƚ͘Ϳ /;ŝŶ͘Ϳ ĞƐĐƌŝƉƚŝŽŶ Wϭ ϯ͕ϳϰϱ Ͳ ϵͲϱͬϴΗDĂƌŬĞƌ:ŽŝŶƚ WϮ ϰ͕ϳϭϴ Ͳ &ůŽĂƚŽůůĂƌ WZ&KZd/KEd/> ^ĂŶĚƐ dŽƉ ;DͿ ƚŵ ;DͿ dŽƉ ;dsͿ ƚŵ;dsͿ ŵƚ ^W& WŚĂƐĞ ĂƚĞ ^ƚĂƚƵƐ ^ƚĞƌůŝŶŐ ϯ͕ϮϲϰΖ ϯ͕ϯϰϲΖ ϯ͕ϭϲϲΖ ϯ͕ϮϰϲΖ ϱϵΖΎ ϭϰ ϭϮ ϭϬͬϭͬϭϵϵϴ /ƐŽůĂƚĞ ^ƚĞƌůŝŶŐ ϯ͕ϯϴϴΖ ϯ͕ϰϭϲΖ ϯ͕ϮϴϳΖ ϯ͕ϯϭϱΖ ϮϴΖ ϭϰ ϭϮ ϭϬͬϭͬϭϵϵϴ /ƐŽůĂƚĞ ^ƚĞƌůŝŶŐ ϯ͕ϰϱϬΖ ϯ͕ϰϵϮΖ ϯ͕ϯϰϴΖ ϯ͕ϯϴϵΖ ϰϮΖ ϭϰ ϭϮ ϭϬͬϭͬϭϵϵϴ /ƐŽůĂƚĞ ^ƚĞƌůŝŶŐ ϯ͕ϱϮϯΖ ϯ͕ϱϱϲΖ ϯ͕ϰϭϵΖ ϯ͕ϰϱϮΖ ϭϰΖΎ ϭϰ ϭϮ ϭϬͬϭͬϭϵϵϴ /ƐŽůĂƚĞ ^ƚĞƌůŝŶŐ ϯ͕ϱϵϴΖ ϯ͕ϲϯϲΖ ϯ͕ϰϵϯΖ ϯ͕ϱϯϬΖ ϭϴΖΎ ϭϰ ϭϭ ϭϬͬϭͬϭϵϵϴ /ƐŽůĂƚĞ ^ƚĞƌůŝŶŐ ϯ͕ϲϵϮΖ ϯ͕ϳϭϮΖ ϯ͕ϱϴϱΖ ϯ͕ϲϬϱΖ ϮϬΖ ϭϰ ϭϭ ϭϬͬϭͬϭϵϵϴ /ƐŽůĂƚĞ ĞůƵŐĂϮͲ ĞůƵŐĂ&ϳ цϯ͕ϴϬϵ͛ цϰ͕ϲϰϯ͛ цϯ͕ϳϬϬ͛ цϰ͕ϱϮϯ͛ &ƵƚƵƌĞ WƌŽƉŽƐĞĚ %HOXJD5LYHU YƚǇϮ ЬĐŚĞŵŝĐĂůůŝŶĞ ĂƐŝŶŐŚĞĂĚ͕/t͕ ϭϯϱͬϴϯD&ƚŽƉǆϭϯϯͬϴ ^Ktďƚŵ͕ǁͬϮͲϮϭͬϭϲϱD ^^K dƵďŝŶŐŚĂŶŐĞƌ͕/tͲͲ &͕ϭϭΖ͛ǆϱϭͬϮ>důŝĨƚĂŶĚ ƐƵƐƉ͕ǁͬϱΖ͛ƚǇƉĞ,Ws ƉƌŽĨŝůĞ dƵďŝŶŐŚĞĂĚ͕/tͲ͕ ϭϯϱͬϴϯDǆϭϭϱD͕ǁͬϮͲ ϮϭͬϭϲϱD^^K͕yďŽƚƚŽŵ ƉƌĞƉ ϭϯϯͬϴΖ͛ ϱ͘ϱΖ͛ ϵϱͬϴΖ͛ sĂůǀĞ͕^ǁĂď͕t<DͲD ϮϭͬϭϲϱD&͕,tK͕ ƚƌŝŵ ,d͕KƚŝƐ͕ϮϭͬϭϲϱD& ǆϲϭͬϮKƚŝƐƋƵŝĐŬƵŶŝŽŶ ƚŽƉ sĂůǀĞ͕tŝŶŐ͕^^s͕ t<DͲD͕ϮϭͬϭϲϱD&͕ ,tK͕ǁͬϭϱΖ͛ŽƉĞƌĂƚŽƌ͕ ƚƌŝŵ sĂůǀĞ͕tŝŶŐ͕t<DͲD͕ ϮϭͬϭϲϱD&͕,tK͕ ƚƌŝŵ ^ƉĂĐĞƌƐƉŽŽů͕ϳϭͬϭϲϱDǆ ϱϭͬϴϱDďŽƚƚŽŵ͕ŶĞĞĚĞĚĨŽƌ ƐƉĂĐĞŽŶ^W ƚƚĂĐŚŵĞŶƚƐƉŽŽů͕&DͲ dD͕ϳϭͬϭϲϱD&ƚŽƉǆ ϳϭͬϭϲϱD^ƚƵĚĚĞĚďŽƚƚŽŵ͕ ǁͬϮͲϮϭͬϭϲϱD^^K͕ŶŽ ďŽƚƚŽŵƉƌĞƉ sĂůǀĞ͕DĂƐƚĞƌƐ͕t<DͲD ϮϭͬϭϲϱD&͕,tK͕ ƚƌŝŵ ĞůƵŐĂZŝǀĞƌhŶŝƚ ZhϮϭϮͲϯϱd 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'DWH 3URFHGXUH&KDQJH 1HZ5HTXLUHG"<1+$.3UHSDUHG%\,QLWLDOV+$.$SSURYHG%\,QLWLDOV$2*&&:ULWWHQ$SSURYDO5HFHLYHG3HUVRQDQG'DWH$SSURYDO$VVHW7HDP2SHUDWLRQV0DQDJHU 'DWH3UHSDUHG)LUVW&DOO2SHUDWLRQV(QJLQHHU 'DWH ! ! !(W !(W SEC. 26 SEC. 35 SEC. 34 13N10WBELUGA HWYBRU 212-35 BRU 212-35T BELUGA RIVER UNIT KURTZ HELEN M CHUGACH ELECTRIC ASSN INC COOK INLET REGION INC TYONEK NATIVE CORPORATION S & E FOSTER PROPERTIES LLC TYONEK NATIVE CORPORATION E PAD 151°1'30"W151°1'40"W151°1'50"W151°2'0"W 61°10'50"N61°10'50"N61°10'45"N61°10'45"N61°10'40"N61°10'40"N61°10'35"N61°10'35"N61°10'30"N61°10'30"N61°10'25"N61°10'25"N± 0 100 200 300 400 Feet 1 inch = 200 feet @ 11x17 Page Size Map Date: 3/3/2022 Document Path: O:\Alaska\GIS\cook_inlet\fields\All_Fields\SSSV_TWellman\mxds\All_Fields_Pad_SHL_660ftBuffer_11x17_BRU_E-PAD_v01.mxdBRU E PAD Well BRU212-35T 660 ft Buffer from Well Surface Hole Location Legend !(W Water Well Location !Surface Hole Well Location 660 Foot Buffer from POI MHW Line (NOAA) KPB Parcels Cook Inlet Oil and Gas Units CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Jacob Flora To:McLellan, Bryan J (OGC) Subject:RE: [EXTERNAL] BRU 212-35T (PTD 198-161) Cement Date:Wednesday, March 30, 2022 10:00:48 AM Bryan, The reason for leaving the TOC below the gravel pack packer is to preserve maximum depth for a future sidetrack. For cutting/pulling the tubing strings in the future we would be limited to where the 3-1/2 x 5-1/2 TOC came to. Due to depleted zones in the gravel pack, it would be difficult to estimate the cement volume to bring the TOC right to this upper packer depth. We would be fine planning the TOC right to this upper packer depth with the provision it would not have to pass a MITIA. The MITIA is a big driver here as remediating a failed MITIA would be done with a down squeeze, and again complicate a future de-complete attempt. We have no intention of producing from the annulus, and the well will not be set up to produce from the annulus, and will not have a SSV on the side outlet. Let me know if you need more data, we are working on our 5-1/2 x 9-5/8 MITIAs now (for both 212-35T & 232-26). Thanks, Jake From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, March 29, 2022 4:20 PM To: Jacob Flora <Jake.Flora@hilcorp.com> Subject: [EXTERNAL] BRU 212-35T (PTD 198-161) Cement Jake, A couple questions about the proposed sundry. Why not bring cement up above the Sterling gravel pack so that you can pressure test the 3.5” x 5.5” annulus? Do you have any intention of producing from the sterling gravel pack in the future? Is the well currently set up to produce from this annulus? Does it have a SSV on the side outlet? Thanks Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Install ESP Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 4,801 feet N/A feet true vertical 4,678 feet N/A feet 3135, 3354, Effective Depth measured 4,716 feet 3564, 3777 feet true vertical 4,594 feet 3040, 3254, feet 3459, 3668 Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic 5-1/2" 15.5# / L-80 3,811' MD 3,702' TVD Tubing (size, grade, measured and true vertical depth)2-3/8" 4.6# / L-80 3,891' MD 3,780' TVD Baker SC-1, SC-1L X 2, 3135, 3354, 3040, 3254, Packers and SSSV (type, measured and true vertical depth)FB-1 Pkrs; N/A 3564, 3777 MD 3459, 3668 TVD NA/ N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Taylor Wellman 777-8449 Contact Name:Ted Kramer Authorized Title:Operations Manager Contact Email: Contact Phone:777-8420 tkramer@hilcorp.com Senior Engineer:Senior Res. Engineer: Burst 8,150psi 98' 2,605'3,450psi Collapse 1,950psi 7,100psi Casing Structural 20" 13-3/8" Length 98' 2,677' 4,800' Conductor Surface Intermediate Production Authorized Signature with date: Authorized Name: 5 Casing Pressure Liner 0 0 Representative Daily Average Production or Injection Data 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 320-174 229 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 5 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 198-161 50-283-20097-00-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 2600 Beluga River Unit (BRU) 212-35T N/A FEDA029657 Plugs Junk measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Beluga River / Undefined GasN/A measured TVD Tubing PressureOil-Bbl measured true vertical Packer 9-5/8'4,800'4,677' WINJ WAG 0 Water-Bbl MD 98' 2,677' 0 t Fra O 6. A G L PG , R Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Jody Colombie at 3:31 pm, Jul 23, 2020 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.07.23 14:53:10 -08'00' Taylor Wellman RBDMS HEW 7/23/2020 gls 9/3/20 water unloading Install ESP DSR-7/23/2020 SFD 7/28/2020 Rig Start Date End Date E-Line 6/20/20 6/23/20 Daily Operations Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BRU 212-35T 50-283-20097-00-00 198-161 06/20/2020 - Saturday Held PTSM, crew change. Cont. w/ continuous hole fill and metering fluid to keep well static, current rate of 7.7 bph. Held PJSM w/ rig crew, Weatherford, Summit, Pollard, Toolpusher, & DSM on P/U & running ESP. P/U ESP BHA as per Summit Reps, P/U shroud & RIH, P/U & M/U gauge & motor, filled motor w/ synthetic oil. P/U incorrect tandem, L/D tandem & swapped for correct tandem. M/U motor leads to motor & tested (ok), lubricated seals w/ synthetic oil, RIH M/U shroud hanger to shroud, cont. RIH installing 2 clamps on 1st pump and 3 clamps on second pump. P/U 1st jt on 2- 3/8" tubing and M/U discharge head to tubing and second pump, installed 1 clamp below discharge head, RIH to splice, installed splice clamp but OD was to large, removed splice clamp and installed separate clamps on both sides of splice, taped up top of splice prior to installing top clamp. currently M/U check valve to chem control line. 9-5/8" x 5.5" Annulus = 0 psi. Continue monitor well pressures, Chase leaks on Mud line and changed out two rubber gaskets (ok), M/U test jt. flooded BOP stack w/ water, attempted to shell test BOP's, chased leak (top hyd valve on TDS IBOP failure) Isolate TDS. R/U line to tubing spool valve for continuous hole fill, started filling hole and metering fluid to keep well static, current rate of 8 bph. Isolated TD from tests, proceeded w/ testing while we prepped to change out HYD IBOP & trip tank motor. Cont. test BOP Annular 250 Low & 2500 High 5/5 min, BOP's and all other components 250 Low & 3000 high 5/5 min. Witness by AOGCC Rep Mr. Adam Earl (ok). Re-tested HYD IBOP (ok), tested stand pipe & mud lines to 3000 psi (ok), R/D testing equip. blew down TD, Kelley hose, MP's, & choke manifold, greased choke manifold. Cont. w/ continuous hole fill and metering fluid to keep well static, current rate of 8 bph. Cleared & cleaned rig floor, R/U Weatherford handling equip, staged Summits ESP tools on catwalk, spotted & set ESP cable spool, hung sheave in derrick, spotted & set Pollard chemical control spool, run ESP cable & chem control lines through sheave in derrick. Last report on Rig Mob AFE, changing to BRU 212-35T AFE at midnight. , BOP's and all other components 250 Low & 3000 high 5/5 min. Witness by AOGCC Rep Mr. Adam Earl (ok). Re t Reps, P/U shroud & RIH, P/U & M/U gauge & motor, filled motor w/ synthetic oil. 401 Rig Start Date End Date E-Line 6/20/20 6/23/20 Daily Operations Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BRU 212-35T 50-283-20097-00-00 198-161 06/22/2020 - Monday Cont. working on penetration splice and dress hanger w/ continuous chem control line. Landed hanger & RILD's, tested ESP cable (ok), pulled landing jt. set BPV, Ran a total of 117 jt. of 2-3/8" 4.7 ppf 8RD EUE tubing, installing 124 cable clamps & 3 super bands R/D flow line, bell nipple & flow box, installed trolley beams, Bled & pumped to remove gas off annulus, N/D 7-1/16" BOP stack completely for return to vendor. Tested void 500 Low/5,000 High 5/10 min (ok), N/U 2- 3/8" tree, pulled BPV & installed TWC, shell tested tree 500 Low/ 5,000 High 5/10 min (ok). Removed TWC and secured well. Held PTSM, crew change. R/D blow down tank, blow down TD, R/D TD & rig floor, installed shipping beams in sub, disconnected interconnects from MP's to pits, removed TQ bushing from TQ tube & TD and L/D. Brought TD cradle to floor, pinned TD in cradle removed TD from blocks, L/D TD using new L/D procedure. disconnected all equalizers between pit modules, disconnected electrical lines & Pason cords in derrick. Removed T-bar from TQ tube, laid over pit module #2 roof, R/D & L/D poor boy gas buster, removed wind wall hood from behind I-roughneck, R/D I-roughneck, scoped derrick & L/D lower section of TQ tube, Un-spooled drill line off DWKS drum, prepped derrick for laying over, laid down derrick, folded back beaver slide onto catwalk Held PTSM, crew change, Cont. R/D misc. rig equip. lowered roof on shaker pit, changed out climb assist cables on mast, drained water tank & cleaned tank bottoms, tied up HYD & Elec. lines in mast for removal. organized choke house, roughneck room/dog house, tool room, shake house and worked on misc. house keeping around rig. Lower doghouse into water tank, prepped all modules for trucking & crane work. 9-5/8: x 5.5" Annulus=0 psi. 2-3/8" tubing=62 psi. 06/21/2020 - Sunday Cont. running ESP assy on 2-3/8” tbg installing cable clamps every collar and with one control line and testing cable every +- 1,000’ T/2,017'. Cont. filling well w/ water @ 8-9 bph. P/U-34K S/O-30K Held PTSM, crew change. Performed rig service, greased /inspected- crown, blocks, TD, swivel, TQ bushing, floor motor, DWKS, drive line, dog nut, crown-o- matic, & brake linkage Held PJSM w/ rig crew, Weatherford, Pollard, & Summit. Cont. RIH w/ ESP assembly on 2-3/8" tubing F/2,017', installing cable clamps on every jt. & testing ESP cable every 1,000', set down @ 2,044', attempted to work through w/ no luck, L/D jt. 62 due scarring from elevator, discussed options w/ town, decision was made to POOH looking for any signs of scaring. Held PJSM w/ rig crew, Weatherford, Pollard, & Summit on POOH. POOH F/2,044' -T/65'. POOH F/65'-T/0' inspecting ESP BHA for marring, found some scarring on top end on shroud where there was a weld w/ an OD of 4.625". L/D shroud on cat walk and proceeded to grind down excess weld to OD of 4.5" P/U shroud & re-built ESP BHA F/0'-T/65', re-tested ESP (ok). RIH F/65'-2,017', testing cable every 1000' & cont. to pump water in the well @ 8- 9 bph, hole took 97.4 bbls over last 12 hrs. & 262.9 bbls over last 24 hrs. Held PTSM, crew change, cont. RIH w/ ESP assembly on 2-3/8" tubing F/2,017'-2,989', didn't see a bobble @ 2,044'. Stopped & checked ESP cable and check valve on chem control line@ 2,989' Cont. RIH w/ ESP assembly on 2-3/8" tubing F/2,989'-3,867' w/ no issues, P/U hanger & pup, M/U to spare jt. for landing hanger, M/U hanger to string, currently working on ESP splice through hanger. currently Summit hand are working on ESP splice through hanger, while cont. to pump water in the well @ 8-9 bph. 9-5/8" x 5.5" Annular = 0 psi. Cont. running ESP assy on 2-3/8” tbg installing cable clamps every collar a N/U 2- 3/8" tree, pulled BPV & installed TWC, shell tested tree 500 Low/ 5,000 Hig Rig Start Date End Date E-Line 6/20/20 6/23/20 Daily Operations Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BRU 212-35T 50-283-20097-00-00 198-161 06/23/2020 - Tuesday Continue Prep and move rig modules and accessible rig mats and stage on "K" Pad / work on rig maintenance issues and weld list / assist coil w/ 2nd crane / weld starting head on conductor of "K" pad / and assist E-line operations on 212-24T / work on dust control Continue and finish moving rig modules and accessible rig mats and stage on "K" Pad ( waiting on 2nd crane to remove derrick carrier & sub ) / work on rig maintenance issues / finish assisting coil w/ 2nd crane and haul back to rig / weld starting head on conductor of "H" pad and start "F" pad / and assist E-line operations on 212-24T / work on dust control Spot in cranes, pick derrick off sub base load on trailer, pick draworks skid off sub, pick sub off pony walls, pull pony walls and mats off well load on trucks send t/ 212-24T, Clean up liner and felt around well, blade and level next location, Swap AFE t/ 212-24Tat 0000hrs. _____________________________________________________________________________________ Updated by DMA 07-15-20 SCHEMATIC Beluga River Unit Well: BRU 212-35T Last Completed: 10/10/1998 PTD: 198-161 API: 50-283-20097-00 20” 13-3/8” 9-5/8” RKB to MSL = 92.5’ RKB to GL = 22.5’ TD = 4,801’ MD / 4,678’ TVD PBTD = 4,716’MD / 4,594’ TVD Sterling A Max Angle = 22 deg @ 1,970’ Tubing Min ID = 4.562” 3 4 5/6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Sterling B Sterling C 09/98 P1 2 P2 1 CASING DETAIL Size Type WT Grade Conn ID Btm 20'' Conductor 166# X-56 Weld 19.124'' 98' 13-3/8" Surface 68# K-55 Butt 12.415'' 2,677' 9-5/8" Prod Casing 47# S-95 Butt Mod. 8.681'' 4,800' TUBING DETAILS 5-1/2” Prod String 15.5# L-80 LTC 4.95'' 3,811' 2-3/8” Prod. Tubing 4.6# L-80 8RD EUE 1.975” 3,891’ JEWELRY DETAIL Production String ID. Depth MD (ft.) ID (in.) Description 1 25 5.5 10"x5.5" DCB Hanger w/ 5.5" API LTC csg top/btm 2 2,010 4.653 Teledyne-Merla GLM 5.5"x1.5", 15.5# set 10/08/1998 3 2,765 4.653 Teledyne-Merla GLM 5.5"x1.5", 15.5# set 10/08/1998 4 3,079 4.562 Otis 'X' Sliding Sleeve, closed 5 3,128 4.875 Baker GBH-22 Locator Seal Assy, 190-60, 8' stroke 6 3,135 6 Baker SC-1 Gravel Pack Packer 96A4-60 7 3,149 4.75 Baker S Mini-Beta Gravel Pack 190-47 w/ss (18 ft.) 8 3,261 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (91 ft.) 9 3,354 6 Baker SC-1L Isolation Pkr. 96A4-60 10 3,359 4.75 Baker S Mini-Beta Gravel Pack 190-47 w/ss (18 ft.) 11 3,401 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (30 ft.) 12 3,441 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (121 ft.) 13 3,564 6 Baker SC-1L Isolation Pkr. 96A4-60 14 3,570 4.75 Baker S Mini-Beta Gravel Pack 190-47 w/ss (18 ft.) 15 3,611 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (30 ft.) 16 3,655 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (121 ft.) 17 3,776 4.75 Baker S-22B Snaplatch Seal Assembly 18 3,777 6 Baker FB-1 Retainer Prod. Pkr. 192-60 19 3,811 4.767 Wireline Entry Guide 20 3,889’ ESP – Summit SD 550 06/22/20 Plugs/Fish/Other ID. Depth MD (ft.) ID (in.) Description P1 3,745 - 9-5/8" Marker Joint P2 4,718 - Float Collar PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) Amt SPF Phase Date Status Sterling A 3,264' 3,346' 3,166' 3,246' 59'* 14 12 10/1/1998 Open Sterling A 3,388' 3,416' 3,287' 3,315' 28' 14 12 10/1/1998 Open Sterling B 3,450' 3,492' 3,348' 3,389' 42' 14 12 10/1/1998 Open Sterling B 3,523' 3,556' 3,419' 3,452' 14'* 14 12 10/1/1998 Open Sterling C 3,598' 3,636' 3,493' 3,530' 18'* 14 11 10/1/1998 Open Sterling C 3,692' 3,712' 3,585' 3,605' 20' 14 11 10/1/1998 Open *Partially Perforated Interval 20 3,889’ ESP – Summit SD 550 06/22/20 2 3/8" ESP tubing inside 5.5" ESP pump (ESP tubing 2 3/8") NOTE: Water production is up 2 3/8" tubing via ESP pump. Gas production up 2 3/8" x 5" annulus gls 2-3/8” Prod. Tubing 4.6#L-80 8RD EUE 1.975”3,891’ STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Reviewed By:� P.I. Supryj"/720710 BOPE Test Report for: BELUGA RIV UNIT 212-35T ' Comm Contractor/Rig No.: Hilcorp 169 PTD#: 1981610. DATE: 6/20/2020 ' Inspector Adam Earl Iosp Source Operator: Hilcorp Alaska, LLC Operator Rep: Hauck/Ricbardson Rig Rep: Van Evers/ Trick Inspector Type Operation: WRKOV Type Test. DUT Pressures: Sundry No: Rams: Annular: Valves: 320-174 -- -- 250/3000 ' 250/2500 ' 250/3000 ' MASP: Inspection No: bopAGE200701070409 17j-;- Related Insp No: TEST DATA MISC. INSPECTIONS: MUD SYSTEM: ACCUMULATOR SYSTEM: P/F Visual Alarm Time/Pressure P/F Location Gen.: — P, Trip Tank P _ P - System Pressure 3075 - P ' Housekeeping: _ _P Pit Level Indicators P -. P " _ Pressure After Closure 1475 - P PTD On Location P - Flow Indicator P_ " P " _ 200 PSI Attained 12 P Standing Order Posted P. Meth Gas Detector P P Full Pressure Attained _ 36 " P Well Sign _P= 112S Gas Detector P - _ P - _ _ Blind Switch Covers: All Stations" P Drl. Rig P MS Misc 0- NA Nitgn. Bottles (avg): 4 @ 2500 - P - Hazard Sec. _P ACC Misc 0 NA Misc NA _ FLOOR SAFTY VALVES: BOP STACK: CHOKE MANIFOLD: Quantity P/F Quantity Size P/F Quantity P/F Upper Kelly ____I FP ✓ Stripper 0 --NA No. Valves 15 p, Lower Kell 1 P Annular Preventer 1, 91/16 - P - Manual Chokes I P " Ball Type 1 P #1 Rams 1 _ 23/8 _ ' P Hydraulic Chokes 1 P Inside BOP 1.__ ' P ' #2 Rams 1 'blind - P = CH Misc 0 NA FSV Mise 0 NA #3 Rams _0 _ _NA #4 Rams 0 NA #5 Rams 0 NA INSIDE REEL VALVES: #6 Rams 0 NA (Valid for Coil Rigs Only) Choke Lu. Valves 1 - 2 1/16 P "_ Quantity P/F _ HCR Valves 1 "2 1/16 P Inside Reel Valves 0 NA Kill Line Valves _ 2 -21/16 _ _' P Check Valve 0 NA BOP Misc 0 NA Number of Failures: I ✓ Test Results Remarks: IBOP failed, needed changed out. Passed re test Test Time 8 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.04.21 13:23:34 -08'00' Taylor Wellman By Samantha Carlisle at 4:36 pm, Apr 21, 2020 320-174Rig 401 SFD 4/23/2020gls 4/27/20 DSR-4/21/2020 +2500 psi annular test 10-404 X + 3000 psi BOPE test 4/28/2020 dts 4/28/2020 JLC 4/28/2020 xxx Also nipple up new tubing hanger for 2.3/8" before NU BOPE stack 2 3/8" test joint (gauge run for ESP OD?) ESP string w/ power cable. (not shown) New tubing and spacer spools. (all gas production thru IA ... water thru 2 3/8" ) Water production SSV STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon U Plug Perforations LJ Fracture 'St—im—uta—te-0 Pull Tubing LJ Operations shutdown Li Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ erforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: Pull ESP ❑✓ 2. Operator Hilcorp Alaska, LLC 4. Well Class Before Work: 5. Permit to Drill Number: p,, 4. Name: Development ❑� Exploratory ❑ Stratigraphic❑ Service ❑ 198-161 CT - Y3. 3.Address: 3800 Centerpoint Dr, Suite 1400 Anchorage, 6. API Number: AK 99503 50-283-20097-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: FEDA029657 Beluga River Unit (BRU) 212-35T 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Beluga River/ Undefined Gas 11. Present Well Condition Summary: Total Depth measured 4,801 feet Plugs measured N/A feet true vertical 4,678 feet Junk measured N/A feet 3135, 3354, Effective Depth measured 4,716 feet Packer measured 3564, 3777 feet true vertical 4,594 feet true vertical 3040, 3254, feet 3459, 3668 Casing Length Size MD TVD Burst Collapse Structural Conductor 98' 20" 98' 98' Surface 2,677' 13-3/8" 2,677' 2,605' 3,450psi 1,950psi Intermediate Production 4,800' 9-5/8" 4,800' 4,677' 8,150psi 7,100psi Liner Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth) 5-1/2" 15.5# / L-80 3,811' MD 3,702' TVD Baker SCA, SC -1 L X 2, 3135, 3354, 3040, 3254, Packers and SSSV (type, measured and true vertical depth) FBA Pkrs; N/A 3564, 3777 MD 3459, 3668 TVD NA/ N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mct Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 10 247 Subsequent to operation: 0 0 0 10 0 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 15. Well Class after work: Daily Report of Well Operations ❑� Exploratory❑ Development 0 Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil Gas J WDSPL ❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.G. Exempt: 319-374 Authorized Name: Bo York 777-8345 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramer(rDhilcom.com ,f Authorized Signature(/ i �%\ ''� Date: C Contact Phone: 777-8420 Form 10-404 Revised 4/2017 WI/ �o . y! f Submit Original Only niD nAAQ �-t7.G✓nnt � .. ��.� Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date BRU 212-35T CTU 50-283-20097-00-00 198-161 9/18/19 9/22/19 Daily Operations 09/18/2019 - Wednesday PTW, JSA. Rig up Petrospec CTU unit. Install Dual string reel. Prep for BODE test. Bleed off 175 psi from IA. Rig up hot oil truck to coil completion string. Pump 7 bbls to fluid pack. 09/19/2019 - Thursday JSA, PTW. Function test BODE stack. Fill BOPE stack with produced water. Standby for state Rep witnessed BOPE test. 24 hr BOPE test witness notification sent 9/17/19 @ 0747 AM. State Rep Austin Mcloud on location. Test all rams and valves to 250/3,500 psi. Choke skid listed as FP. Replace choke skid and passed. Perform Accumulator draw down test. Pump 35 bbls down CT annulus x 5.5" production casing. 09/20/2019 - Friday PTW, ISA. Remove Wellhead ESP cable cradle and flanges to expose coil. Make up 2x spools. Install BOPE stack. Tight fit in well house. Pump 80 bbls down CT x 5.5" casing annulus. Pick injector head. make up 70' of lubricator, Make up work window. RIH with coil to dress end of CT. Crews noticed weight stacking after 12.5' of travel. Found Armor pack clamps and sliding and bunching up between pack offs and stripper. Stack down work window, lubricator and injector head. Found 2 broken clamps in stripper head. Remove clamps and inspect stripper. Possibly wrong stripper installed. Set injector head on back of CTU unit. SDFN. 09/21/2019 -Saturday PTW, JSA 45 psi IA, 0 PSI CT. Pick injector head. Make up stripper assembly. Make up 70' of 5" lubricator. Make up hydraulic work window. move to well. RIH with coil 5' out the bottom of lubricator. Make up injector head side of dual string coil to wellhead completion. Combination of cold roll's and dimple connections. Drop chain traction. Attempt to slip chains OOH and line down with crane to close window and screw onto BOPE top. While slipping chains there was a loud pop. Above at the gooseneck one string was slacked and had a bow in it. Petrospec indicated it was just slack or coil stretch. Continue to scope down and make up lubricator. Pump 80 bbls of produced water down CT x 5.5" tubing IA. Well went from 45 psi to Vac. Back out Hanger bolts. Pick up on coil to 21K then weight fell off to 8k. Pick up 4'. Hanger measurement to work window. Ensure 0 psi. Open work window. Only one string of coil. Coil hand jiggle the one string. Both string were separated from hanger. This is believed to happen at two different occasions. Not at the same time. 1st was when stripping down over exposed coil. 2nd pulling hanger. Secure hanger bolts. Pop injector lubricator and work window off well. Stack down. Set injector on back deck. Cut coil until coil bow is removed. Coil is back to even lengths. SDFN. Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date BRU 212-35T CTU 50-283-20097-00-00 198-161 9/18/19 1 9/22/19 Daily Operations 09/22/2019 -Sunday PTW, JSA. Pick injector head and make up Lubricator and work window. Stab on well and double cold roll both CT strings to whip end. Slip chains. Walk down and connect lubricator to BOPE bowen. Back out hanger bolts. Pump 25 bbls down CT x 5.5" casing annulus. Well is on a vac. Back out hanger bolts. Pull up on hanger. 38k broke free. 28K moving pipe to work window. Open work window and remove dual string hanger. Start spooling OOH with 3,961' of dual 1.5" CT with coil clamps every 6-10'. Noticed production string coil was parted at 2,197'. Cut out bad spots in part. Looks like pipe was washed out due to erosion and thin wall thickness. Pictures captured for reference. At surface with ESP pump. PU OOH and close master vale. Run ESP into ESP rat hole outside of well house. Break down lubricator and work window. Set injector head on deck. Break down center lift ESP pump and lay down. Motor spun freely as well as pumps. ESP looks to be in decent shape. Shut down for night. Location secure. Ifl TD=4,801' MD/4,678'TVD PBTD = 4,716'M D / 4,594' ND Max Angle = 22 deg @ 1,970' SCHEMATIC CASING DETAIL Beluga River Unit Well: BRU 212-35T Last Completed: 10/10/1998 PTD: 198-161 API: 50-283-20097-00 Size Type WT Grade Conn ID Btm 20" Conductor 166# x-56 Weld 19.124" 98' 13-3/8" Surface68# 1 K-55 I But 12.415" 2,677' I Prod Casing 47# 1 S-95 I ButtMod. 8.681" 4,800' TUBING DETAILS Prod String 15.5# L-80 LTC 4.95" 3,811' JEWELRY DETAIL Production Strine ID. Depth MD (ft.)KB Btm (MD) v Description 1 25 SPF "x5.5" DCB Hanger w/ 5.5" API LTC csg top/btm 2 2,010ledyne-Marla SterlingA GLM 5.5"x1.5", 15.5# set 10/08/1998 3 2,765edyne-Marla 3,246' GLM 5.5"x1.5", 15.5# set 10/08/1998 4 3,079 10/1/1998 s'X'Sliding Sleeve, closed 5 3,128 3,416' ker GBH -22 Lo cator Seal Assy, 190-60, 8'stroke 6 3,135 14 ker SC -1 Gravel Pack Packer96A4-60 7 3,149 Sterling B kers Mini -Beta Gravel Pack 190 -47w/ ss (18 ft.) 8 3,261 3;389' erweld Screen 140, 316L, .012" Ga., L-80 (91 ft.) 9 3,354 10/1/1998 er SC -1L Isolation Pkr. 96A4-60 10 3,359 4.75 Bakers Ni Gravel Pack 190-47W/SS (18 ft.) 11 3,401 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (30 ft.) 12 3,441 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (121 ft.) 13 3,564 6 Baker SC -IL Isolation Pkr. 96A4-60 14 3,570 4.75 Baker SMini-seta Gravel Pack 190-47 w/ss (18 ft.) 15 3,611 4.95 Bakerweld Screen 140,316L,.012" Ga., L-80 (30 ft.) 16 3,655 4.95 Bakerweld Screen 140,316L,.012" Ga., L-80 (121 ft.) 17 3,776 4.75 BakerS-22B Snaplatch Seal Assembly 18 3,777 6 Baker FB -1 Retainer Prod. Pkr. 192-60 19 1 3,811 4.767 Wireline Entry Guide Plugs/Fish/Other ID. I Depth MD (ft.) ID (in.) Description I Pl 3,745 - 9-5/8" Marker Joint P2 1 4,718 - Float Collar PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) Amt SPF Phase Date Status SterlingA 3,264' 3,346' 3,166' 3,246' 59'* 14 12 10/1/1998 Open SterlingA 3,388' 3,416' 3,287' 3,315' 28' 14 12 10/1/1998 Open Sterling B 3,450' 3,492' 3,348' 3;389' 42' 14 12 10/1/1998 Open Sterling B 3,523' 3,556' 3,419' 3,452' 14" 14 12 10/1/1998 Open Sterling C 3,598' 3,636' 3,493' 3,530' 18'* 14 11 10/1/1998 Open SterlingC 3,692' 3,712' 3,585' 3,605' 20' 14 11 10/1/1998 Open *Partially Perforated Interval Updated by DMA 10-03-19 THE STATE OfALASKA GOVERNOR MIKE DUNLEAVY Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Beluga River Field, Undefined Gas Pool, BRU 212-35T Permit to Drill Number: 198-161 Sundry Number: 319-374 Dear Mr. York: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 v✓wvs. aogc c. olaska.gov Enclosed is the approved application for the 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 7day of August, 2019. RBDMS. T/t✓46 2 12019 A �m v_0 -. So STATE OF ALASKA AUG ' �� ALASKA OIL AND GAS CONSERVATION COMMISSION 2019 APPLICATION FOR SUNDRY APPROVALS Vit, 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 ElRe-enterSusp Well ❑ Alter Casing 1:1 Pull ESP C")• Other: ❑Q 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory 11 Development 21- 198-161 - 3. Address: 3800 Centerpoint Dr, Suite 1400 Stratigraphic ❑ Service ❑ 6. API Number: Anchorage Alaska 99503 50-283-20097-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? N/A Will planned perforations require a spacing exception? Yes ❑ No ❑Q Beluga River Unit (BRU) 212-35T ' 9. Property Designation (Lease Number): 10. Field/Pool(s): FEDA029657 Beluga River / Undefined Gas 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ftl; Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 4800 i '1 4,678' 4,715' 4,593' 173 N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 98' 20" 98• Surface 2,677' 13-3/8" 2,677' 2,605' 3,450psi 1,950psi Intermediate Production 4,800' 9-5/8" 4,800' 4,677' 8,150psi 7,100psi Liner j Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: D (ft): See Attached Schematic See Attached Schematic 5-1/2" 15.5# / 1-80 3,811' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): ,135'MD/3,040'TVD, Baker SCA, SCAL X 2, FB -1 Pkrs; N/A 33,354'MD/3,254'TVD, 3,564'MD3,459'TVD, 3,777'MD/3,668'TVD; N/A, N/A 12. Attachments: Proposal Summary w Wellbore schematic U 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development Q Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: August 28,2019 OIL ❑ WINJ ❑ WDSPL ❑ ❑ Suspended 16. Verbal Approval: Date: GAS ❑O WAG ❑ GSTOR ❑ SPLUG El Representative: GINJ E] 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. Authorized Name: Be York 777-8345 Contact Name: Ted Kramer Authorized Title: Oper tions Manager Contact Email: t1kramer0hilcom.com n Contact Phone: 777-8420 t� Authorized Signature: Date: ✓Y-� �) COMMISSIOWUSE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: c-1' I I)la-3�U Plug Integrity ❑ BOP Test 2( Mechanical Integrity Test ❑ Location Clearance ❑ Other: 3 500 11:440- RBDMS4NAUG 2 Post Initial Injection MIT Req'd? Yes ❑ No ❑ 12019 Spacing Exception Required? Yes No Subsequent Form Required: / 0 — Li (DI APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: �gyvl11 �1 o f y-7 orm 10-403 Revised 4/2017 A roved a licatiQ1 vvlli j tGr 2l1Nh�.f�(happroval y� Submit Form and PP PP a date of approval`+t"�Attachments in Duplicate ,��y/ p•y77��' K Hamm Alwka, u, Well Prognosis Well: BRU 212-35T Date: 8/13/2019 Well Name: BRU 212-35T API Number: 50-283-20097-00 Current Status: SI Gas Producer Leg: N/A Estimated Start Date: August 28, 2019 Rig: Coil Unit / Moncla 401 Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 198-161 First Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (C) Second Call Engineer: Bo York (907) 777-8345 (0) (907) 727-9247 (C) AFE Number: Maximum Expected BHP: — 561 psi @ 3,887' TVD (From ESP pressure Gauge 2-12-18) Max. Potential Surface Pressure: 173 psi From ESP Gauge subtracting 0.1 psi/ft gas gradient to 3,887' TVD). Brief Well Summary BRU 212-35T is a ESP gas producer that developed a tubing leak in Summer of 2017. While the ESP is still operable, a suspected hole in the tubing prevents the well from lifting produced water to surface. Once this lift capacity was lost, the well loaded up with water and died. The purpose of this work/sundry is to pull the coil tubing conveyed ESP in order to determine why the well failed. Note: BRU 212-35T is currently SI and is dead on both the IA and the tubing. Well will not flow. Notes Regarding Wellbore Condition • ESP sits below gravel packed screens. • ESP was Ran on dual String Coil tubing which requires a special BOP Stack. • Well has a suspected Hole in the tubing and may have a hole in a screen. Safety Concerns • This coil design is atypical for this area. Pre -job safety meetings and tailgate safety meetings will be conducted at each appropriate phase of the procedure. • Ensure all crews are aware of their stop work authority. • Follow LOTO procedures to disable power to ESP. Pre -rig Work 1. Disconnect Power to ESP. 2. Remove Well house. 3. RU Lubricator. Petrosoec Coil Tubing Unit 1. Install below injector, ArmorPAK KR3 Strippers, Orientation Guides, enough 5" lubricator to swallow the ESP BHA and 5-1/8" ArmorPak dressed BOPE. 2. MIRU Coiled Tubing, PT BOPE to 3,500 psi Hi 250 Low (Notify AOGCC 24 hrs. in advance of BOP test). J -0- 5iu^'^P -Ti,s` (Sly -fa 3s16z,->� Well Prognosis Well: BRU 212-35T Hllcaro Alaeta, LL Date: 8/13/2019 Note: Due to the stripper head being limited to 500 psi, we will not be able to pressure test the BOPE to the 3,500 psi with it in the lineup. Therefore, the BOP stack will be tested on a stump and then bolted onto the well with a tested companion flange. NA,+S P < Sibfa5` 3. Kill well by pumping 3% KCL down backside. 4. Bleed off any residual trapped pressure from both coil strings. 5. Connect to Coil tubing and spool dual 1.50" coil tubing and ESP unit out of well. Note: Pay close attention to evidence of fluid jetting on Coil tubing and record depths of any found holes or jetting. 6. Lay down ESP. 7. Install dry hole tree with flange. 8. RDMO Coil Tubing Unit. Attachments: 1. Actual and Proposed Well Schematics 2. Coil BOPE Schematic on Wellhead 3. CT Flow Diagrams 4. Blank RWO Change Form 0440 tlr11111�� rL� Pe "3r � ' . TD 4,801' TVD =4,678' PBTD = 41801' ED 4,715' END=4,593' Max Angle= 22 deg @ 1,970' SCHEMATIC CASING DETAII Beluga River Unit Well: BRU 212-35T Last Completed: 10/10/1998 PTD: 198-161 API: 50-283-20097-00 Size Type WT Grade I Conn ID Btm 20" 1 Conductor 1 166# X-56 I Weld 19.124" 1 98' 13-3/8" Surface 68# K-55 Butt 12.415" 2,677' 9-5/8" Prod Casing 47# 5-95 Butt Mad. 8.6814,800- Baker SC -1 Gravel Pack Packer 96A4-60 TUBING DETAILS 5.5" Prod String 15.5# L-80 LTC 4.95" 3,811' 1.5" Coil Tubing 1.43# CT80 Armorpak 1.31" 3,961" .95 Coil Tubing 1.43# CT80 Armorpak 1.31" 3,961" JEWELRY DETAIL Production String ID. Depth MD (ft.) ID (in.) Description 1 25 5.5 10"x5.5" DCB Hanger w/ 5.5" API LTC csg top/btm 2 2,010 Teledyne -Meda GLM 5.5"x1.5", 15.5# set 10/08/1998 3 2,765 3,246' Teledyne -Meda GLM 5.5"x1.5", 15.5# set 10/08/1998 4 3,079 4.562 Otis'X' Sliding Sleeve, closed 5 3,128 4.875 Baker GBH -22 Locator Seal Assy, 190-60, 8'stroke 6 3,135 6 Baker SC -1 Gravel Pack Packer 96A4-60 7 3,149 4.75 Baker S Mini -Beta Gravel Pack 190-47 w/ss (18 ft.) 8 3,261 4.95 Bakerweld Screen 140,316L,.012" Ga., L-80 (91 ft.) 9 3,354 6 Baker SC -1L Isolation Pkr. 96A4-60 30 3,359 4.75 Baker S Mini -Beta Gravel Pack 190-47 w/ss (18 ft.) 11 3,4014 .95 Bakerweld Screen 140, 316L,.012" Ga., L-80 (30 ft.) 12 3,441 4.95 Bakerweld Screen 140, 316L,.012" Ga., L-80 (121 ft.) 13 3,564 6 Baker SC -11- Isolation Pkr. 96A4-60 14 3,570 4.75 Baker S Mini -Beta Gravel Pack 190-47 w/ss (18 ft.) 15 3,611 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (30 ft.) 16 3,655 4.95 Bakerweld Screen 140,316L,.012" Ga., L-80 (121 ft.) 17 3,776 4.75 Baker 5-22B Snaplatch Seal Assembly 18 3,777 6 Baker FB -1 Retainer Prod. Pkr. 192-60 19 3,811 4.767 Wireline Entry Guide 20 2,999 .88 D Nipple 21 3,901 CT ESP 60' X 4.45" w/Armorpak Connector Assembly Plugs/Fish/Other ID. Depth MD (ft.) ID (in.) Description P1 3,745 9-5/8" Marker Joint P2 4,718 - Float Collar PERFORATION DETAII `Partially Perforated Interval Updated By: TRH 5-29-18 Top (MD) Btm (MD) Top (TVD) Btm (TVD) Amt SPF Phase Date Status 3,264' 3,346' 3,166' 3,246' 59'* 14 12 10/1/1998 Open 3,388' 3,416' 3,287' 3,315' 28' 14 12 10/1/1998 Open 15terling 3,450' 3,492' 3,348' 3,389' 42' 14 12 10/1/1998 Open 3,523' 3,556' 3,419' 3,452' 14" 14 12 10/1/1998 Open 3,598' 3,636' 3,493' 3,530' 181" 14 11 10/1/1998 Open 3,692' 3,712' 3,585' 3,605' 20' 14 11 10/1/1998 Open `Partially Perforated Interval Updated By: TRH 5-29-18 fBilmro Alaska. LLC To 4,801' TVD =4,678' PBTD = 4,801' ED 4,715' ETD =4,593' Max Angle = 22 deg @ 1,970' Beluga River Unit : BRU 212-35T Last tlCompleted: 10/10/1998 PROPOSED PTD: 198-161 API: 50-283-20097-00 CASING DETAII Size Type WT GradeConn 1 ID Btm 20" Conductor 166# X-56 Weld 19.124" 98' 13-3/8" Surface 68# K-55 Butt 12.415" 2,677' 9-5/8" Prod Casing 1 47# 1 S-95 Butt Mod. 8.681" 4,800' TUBING DETAILS 5.5" 1 Prod String 1 15.5# 1 L-80 I LTC 4.95" 3,811' JEWELRY DETAIL Production String ID. Depth MD (ft.) ID (in.) Description 1 25 5.5 10"x5.5" DCB Hanger w/5.5"API LTC csg top/btm 2 2,010 SterlingA Teledyne -Marla GLM 5.5"x1.5", 15.5# set 10/08/1998 3 2,765 3,246' Teledyne-Merla GLM 5.5"x1.5", 15.5# set 10/08/1998 4 3,079 4.562 Otis'X' Sliding Sleeve, closed 53,128 3,388' 4.875 Baker GBH -22 Locator Seal Assy,19D-60, 8'stroke 6 3,135 6 Baker SC -1 Gravel Pack Packer 96A4-60 7 3,149 4.75 Baker Mini -Beta Gravel Pack 190-47 w/ss (18 ft.) 8 3,261 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (91 ft.) 9 3,354 6 Baker SC -11. Isolation Pkr. 96A4-60 10 3,359 4.75 Baker Mini -Beta Gravel Pack 190-47 w/ss (18 ft.) 11 3,401 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (30 ft.) 12 3,441 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (121 ft.) 13 3,564 6 Baker SC -11- Isolation Pkr. 96A4-60 14 3,570 4.75 Baker Mini -Beta Gravel Pack 190-47 w/ss (18 ft.) 2'1' 3,692' 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (30 ft.) 16 3,655 4.95 Bakerweld Screen 140, 316L, .012" Ga., L-80 (121 ft.) 17 3,776 4.75 Baker S-2 Snaplatch Seal Assembly 18 3,777 6 Baker FB -1 Retainer Prod. Pkr. 192-60 19 1 3,811 4.767 Wireline Entry Guide Plugs/Fish/Other ID. Depth MD (ft.) ID (in.) Description P1 3,745 - 9-5/8" Marker Joint P2 1 4,718 - Float Collar PERFORATION DETAII Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) Amt SPF Phase Date Status SterlingA 3,264' 3,346' 3,166' 3,246' 59'* 14 12 10/1/1998 Open Sterling 3,388' 3,416' 3,287' 3,315 ' 28 14 12 10/1/1998 Open Sterling B 3,450' 3,492' 3,348' 3,389' 42' 14 12 10/1/1998 Open Sterling B 3,523' 3,556' 3,419' 3,452' 14'* 14 12 10/1/1998 Open Sterling 3,598' 3,636' 3,493' 3,530' 181* 14 11 10/1/1998 Open Sterling 3,692' 3,712' 3,585' 3,605' 20' 14 11 10/1/1998 Open `Partially Perforated Interval Updated ByJLL 8/13/2019 L Ir Coiled Tubing HydraCo 60K Injedor Head&Gooseneck Weight = 350 lbs 9"SOOPsi ArmorPak Stri er Y 5� S� �Et' N J11 —4dsvenType SK 5.5"Lubricator SK CIS ArmorPak Guide Bavren Type SK x 5-1/8" 30K flange 5.1/8" SOK quad SOP 1. ArmorPak 1.5" x 1.5" Pipe Ram 2. ArmorPak 1.5" x 15" Pipe Ram 3. Shear Ram a. Bllndi m 5-1/8 OR Spool with 2-1/I6" IOK Outlets- Kill Port Manual Valve 1: 2-1/16" IOK Manual Valve 2: 21/16" 30K Manual Valve 3: 2" Weca 1502 Ad ter Spool s-1/8" 10K x 7-1/16" SK Adapter Spool 7-1/16" SK x 5 1/fl" SK Wellhead R 4 i 9 O N !J O 9 3 O � v c y c s R E g it o i Q � i 0 v 0 z 0 v TI O O 1 D_ Z N 8 L f9� rt 3 u _ � � a7 ti o z m Cn c� o E� Q" D g � SQ E F\ A in: L N L � 'D d ? m - Y do 0-0i C U m Um C 0 0 N O 0.4, Q CLd N m = a m '_ 5 a a dN Y m aA = d m Y c CL CO � � 2 d tr Z d C m t U a 3 a N O a m m m m CL U y 0 a a w m Lo 'O d m CL 2 IL r m O E L PETROSPEC WORK INSTRUCTION FOR PULLING ARMORPAK WWII ENGINEERUNG Hilcorp Alaska LLC — BRU 212-35T Notes: CODE: PEI-WI19-03274-001 DATE: August 7, 2019 REVISION N°: 0 PAGE: 1 of 26 WORK INSTRUCTION FOR PULLING ARMORPAK ESP SYSTEM WRITTEN BY: REVIEWED BY: APPROVED BY: Name: Clint Jones, P. Eng Name: Mark Padberg, P.L.(Eng.) Name: Mark Padberg, P.L.(Eng.) Title: Power -Tube- Product Line Specialist Title: Senior Project Technologist Title: Senior Project Technologist Company: Petrospec Engineering Inc. Company: Petrospec Engineering Inc. Company: Petrospec Engineering Inc. This document is the property of PETROSPEC ENGINEERING and for the exclusive use of its Personnel. It is prohibited to reproduce, transmit, orcopy to Third Parties without the express written authorization from Petrospec. CODE: PEI -W I19-03274-001 WORK INSTRUCTION FOR PULLING ARMORPAK DATE: August 7, 2019 to PETROSPEC ENGINEEPING Hilcorp Alaska LLC — BRU 212-35T REVISION N^: 0 PAGE: 2 of 26 TABLE OF CONTENTS 1. DOCUMENT REVISION HISTORY............................................................................................................3 2. OBJECTIVE..............................................................................................................................................3 3. SCOPE AND BACKGROUND....................................................................................................................4 4. ASSOCIATED CORPORATE DOCUMENTS................................................................................................4 S. REFERENCE DOCUMENTS......................................................................................................................4 6. TERMINOLOGY AND DEFINITIONS.........................................................................................................5 7. ENVIRONMENT, HEALTH, AND SAFETY.................................................................................................8 8. EQUIPMENT SPECIFICATIONS..............................................................................................................14 9. CREW ROLES AND RESPONSIBILITIES..................................................................................................16 10. LIST OF EQUIPMENT............................................................................................................................19 11. ARMORPAK PULL WORK INSTRUCTION...............................................................................................2C Page 2 of 26 PETROSPEC WORK INSTRUCTION FOR PULLING ARMORPAK ENGINEERING I Hilcorp Alaska LLC — BRU 212-35T 1. DOCUMENT REVISION HISTORY CODE: PEI-WI19-03274-001 DATE: August 7, 2019 REVISION N": 0 PAGE: 3 of 26 Record changes in the DOCUMENT REVISION HISTORY table. The description of the modifications must be done in descending order starting at the current version. Only the last five revisions of the document should be recorded in this table. The descriptions should briefly describe the circumstances that led to the revision. REV. N° DATE DESCRIPTION OF CHANGE 0 07/19 Document creation and review. 2. OBJECTIVE The objective of this document is to provide a detailed operational work instruction including documents, activities, instructions, and references necessary to complete pulling the existing ArmorPak'M completion from well BRU 212-35T. Page 3 of 26 tPETROEiPEC WORK INSTRUCTION FOR PULLING ARMORPAK o ENGINEERING Hiloorp Alaska LLC — BRU 212-35T 3. SCOPE AND BACKGROUND CODE: PEI -W119-03274-001 DATE: August 7, 2019 REVISION N°: 0 PAGE: 4 of 26 BRU 212-35T is an ESP gas producer that developed a tubing leak in the Summer of 2017. While the ESP is currently still operable, a suspected hole in the tubing prevents the well from lifting produced water to surface. Once this lift capacity was lost, the well loaded up with water and died. The purpose of this work is to pull the coiled tubing conveyed ESP in order to determine why the well failed. The coiled tubing deployed ESP completion is an ArmorPak'm completion originally run by CJS and Petrospec back in 2015. 4. ASSOCIATED CORPORATE DOCUMENTS CODE DOCUMENT TITLE DOCUMENT TYPE n/a Petrospec Engineering EHS Manual 2019 EHS IRP #21 Coiled Tubing Operations— Industry Recommend Practice (IRP) for the Canadian Oil and Gas Industry Enform 5. REFERENCE DOCUMENTS 5.1. — Page 4 of 26 CODE: PEI-WI19-03274-001 WORK INSTRUCTION FOR PULLING ARMORPAK DATE: August 7, 2019 ENGINEERING PETHilcorp Alaska — U 212-35T Eaiti� AlLLC BRREVISION N°: 0 PAGE: 5 of 26 6. TERMINOLOGY AND DEFINITIONS 6.1. Accumulator. A pressure storage reservoir in which a non-compressible hydraulic fluid is held under pressure by an external source. 6.2. Annular Preventer. An annular blowout preventer uses the principle of a wedge to shut in the wellbore by forming a seal in the annular space between the pipe and the wellbore. It has a donut -like rubber seal, known as an elastomeric packing unit, reinforced with steel ribs. Annular preventers have only two moving parts, piston and packing unit, making them simple and easy to maintain relative to ram preventers. 6.3. Bottom Hole Assembly (BHA). Any assembly of parts or fittings that is connected to the downhole end of the coiled tubing string. 6.4. Blow Out Preventer (BOP). A large, specialized valve or similar mechanical device, usually installed redundantly in stacks, used to seal, control and monitor oil and gas wells. 6.5. CF. Casing Flange. 6.6. Class I Well. A well in which the reservoir pressure of the zone is less than 800psi (5500 kPa), and there is no hydrogen sulphide present in a representative sample of the gas and the well. i. Is a gas well, or ii. Produces heavy oil with a density greater than 940 kg/m3, a gas -oil ratio of less than 70m3/m3, the well produces by primary recovery, or is included in a water -flood scheme. 6.7. Class 11 Well. A well where the pressure rating of the production casing flange is less than or equal to 3000psi (21,000 kPa), and the hydrogen sulphide content in a representative sample of gas is less than 10 moles per kilomole (10000ppm or 1% 1-12S). 6.8. Class IIA Well. A well where the expected bottomhole pressure is less than 3000psi (21,000 kPa) and the expected H2S release rate will be less than 0.001m3/s. 6.9. Class III Well. A well where the pressure rating of the production casing flange is: i. Greater than 3000psi (21,000 kPa), or ii. Less than or equal to 3000psi (21,000 kPa) and the hydrogen sulphide content in a representative sample of gas is 10 moles per kilomole or greater (1% H2S or greater) 6.10. Coiled Tubing (CT). Any continuously -milled tubular product manufactured in lengths that require spooling onto a take-up reel, during the primary milling or manufacturing process. The tube is nominally straightened prior to being inserted into the wellbore and is recoiled for spooling back onto the reel. Tubing diameter normally ranges from 0.75 in. to 4 in., and single reel tubing lengths in excess of 30,000 ft. have been commercially manufactured. Common CT steels have yield strengths ranging from 55,000 PSI to 120,000 PSI. Page 5 of 26 PETROSPEC WORK INSTRUCTION FOR PULLING ARMORPAK ENGINEERING Hilcorp Alaska LLC — BRU 212-35T CODE: PEI -W I19-03274-001 DATE: August 7, 2019 REVISION N": 0 PAGE: 6 of 26 6.11. Coiled Tubing Unit (CTU). A complete assembly of equipment (normally mobile) necessary to perform standard continuous -length tubing operations in the field. A CTU consists of five basic elements: • Tubing Spool. For storage and transport of the CT. • Spooler. A motorized mechanism capable of storing and rotating a tubing Spool. • Injector Head. To provide the surface drive force to run and retrieve the CT. • Control Cabin. From which the equipment operator monitors and controls the CT. • Power Pack. An engine used to generate hydraulic and pneumatic power required to operate the CT unit. 6.12. Cooling Loop. A flanged closed fluid circulation system designed to remove heat between a wellhead and BOP. 6.13. CSA. Canadian Standards Association. 6.14. IRP. Industry Recommended Practice. 6.15. JHA. Job Hazard Analysis. 6.16. KB. Kelly Bushing. 6.17. Master Valve. Manually controlled gate type valve, located just over the casing head. 6.18. MD. Measured Depth. 6.19. MIRU. Move -In and Rig -Up. 6.20. Nipple Down. The process of disassembling well -control or pressure -control equipment on the wellhead. 6.21. Nipple Up. To put together, connect parts and plumbing, or otherwise make ready for use. The process of assembling well -control or pressure -control equipment on the wellhead. 6.22. PBTD. Plug Back Total Depth. 6.23. Plug Valve. In the open position, the plug -passage is in one line with the inlet and outlet ports of the Valve body. If the plug 900 is rotated from the open position, the solid part of the plug blocks the port and stops flow. 6.24. POOH. Pull -Out of Hole 6.25. RDMO. Rig -Down and Move -Out. 6.26. RIH. Run -In Hole. 6.27. SICP. Shut In Casing Pressure. 6.28. SITP. Shut In Tubing Pressure. 6.29. SOW. Scope of Work. Page 6 of 26 CODE: PEI-WI19-03274-001 WORK INSTRUCTION FOR PULLING ARMORPAK DATE: August 7, 2019 - ENGINEEERING RING PETPHilcorp Alaska LLC — BRU 212-35T REVISION N°: 0 PAGE: 7 of 26 6.30. Stripper. The primary operational seal between pressurized wellbore fluids and the surface environment. It is physically located between the BOP and the injector head. The stripper provides a dynamic seal around the CT during tripping and a static seal around the CT when there is no movement. 6.31. Swab Valve. This is the topmost manual control gate type valve. This valve also called wire line valve or crown valve. It affords access to the well for remedial actions. 6.32. TVD. True Vertical Depth. 6.33. VD. Vertical Depth. 6.34. Wellhead. A component at the surface of an oil orgas well that provides the structural and pressure -containing interface for the drilling and production equipment. The primary purpose of the wellhead is to provide the suspension point and pressure seals for tubulars that run from the bottom of the well to the surface pressure control equipment. 6.35. Wing Valve. Manual control gate type valve used to shut in the well. The wing valve is used to open or close the well from line pipe flow. This is the first valve to be closed during routine well shut in. Page 7 of 26 CODE: PEI-WI19-03274-001 WORK INSTRUCTION FOR PULLING ARMORPAK DATE: August 7, 2019 PETELRING C Hilcor Alaska LLC — BRU 212-35T EN�i^�ROS p REVISION N°: 0 PAGE: 8 of 26 7. ENVIRONMENT, HEALTH, AND SAFETY 7.1. Personal Protective Equipment (PPE). The minimum personal protective equipment required to perform the operations described within this work instruction are as follows: • Steel toe boots (to CSA Standard Z195-09) • Safety glasses (to CSA Standard Z94.3-07 (R2014)) • Coveralls • Hearing protection (to CSA Standard Z94.2.02) • Hardhat (to CSA Standard Z94.1-05 (R2013)) • Gloves 7.2. PRE -RIG -UP RECOMMENDATIONS (per IRP 21) Before rigging up any coiled tubing equipment on the location, Hilcorp Alaska LLC and Petrospec Engineering shall review the equipment service log and ensure the following: 1. The coiled tubing pipe to be used shall have sufficient serviceability to safely complete the job with a reasonable contingency factor; 2. The coiled tubing string used shall be able to complete the job within operating limits (such as tensile strength, burst, collapse, torsional yield, etc.); 3. The three-year BOP equipment certification must have been completed (this includes all riser, lubricator, flow spools, cross -overs, strippers, etc., from the wellhead to the upper stripper); 4. The accumulator specifications must be available and accumulator sizing calculations must have been performed; 5. All equipment, including the coiled tubing pipe and BOP system, shall have been checked for compatibility with the formation fluids and treating fluids; 6. If the shear ram is installed, it shall be capable of severing the coiled tubing pipe and any internal/external hardware such as instrumentation/wireline installed coiled tubing being used; For critical sour operations inspection/testing requirements for the coiled tubing pipe, refer to IRP 21 Section 3.6.2: Full -Length NDE of CT Strings. Page 8 of 26 CODE: PEI -W I19-03274-001 WORK INSTRUCTION FOR PULLING ARMORPAK DATE: August 7, 2019 ENGINEEERINGRING LLC BRU 2 PETFHilcorp Alaska — 12-35T REVISION N': 0 PAGE: 9 of 26 The Hilcorp Alaska LLC representative shall provide a documented site specific orientation to the Petrospec Engineering representatives before starting operations. Items to be reviewed shall include the following: • General safety issues, • Identification of any hazards on location (such as rat holes, high pressure piping, etc.), • Muster stations, and • Egress routes. Hilcorp Alaska LLC and Petrospec Engineering shall review the well parameters including, but not limited to the following: • Depth, • Formation or treatment fluids, • Gas composition (especially air, H2S, and CO2 concentrations), • Emergency response plan (ERP) if required, • Iron sulphide, • Naturally occurring radioactive material (NORM), • Other scales, • Pressures, • Relevant well equipment and detail (trajectory, ID restrictions, etc.), • Salinity of produced water, • Sulphur scales, • Temperature and, • Wind direction. Hilcorp Alaska LLC and Petrospec Engineering shall review proposed equipment layout and spacing requirements recognizing all regulatory requirements. 7.3. RIG -UP RECOMMENDATIONS (per IRP 21) A safety/operations meeting shall be held with all on -location personnel to discuss the following: • Pressure testing, • The detailed operations to be performed, • Delegation of responsibilities, • Review BOP Drill requirements, • Emergency response plans, and • Other appropriate considerations. All hydraulic lines, testing lines, and kill lines shall be organized and kept tidy so they prevent interference with an emergency evacuation of the area. Page 9 of 26 CODE: PEI-W119-03274-001 WORK INSTRUCTION FOR PULLING ARMORPAK DATE: August 7, 2019 PETROSPEC eN�INEEPING Hilcorp Alaska LLC — BRU 212-35T REVISION N°: 0 PAGE: 10 of 26 All equipment attached to the wellhead shall be adequately supported to limit transverse movement. Refer to Section 1: Recommendations on Coiled Tubing Operations Planning of IRP 21 for detailed matters to be addressed during the safety/operations meeting. • Injector height, equipment weight, and wind conditions should be considered. • Guy lines should be installed to rig anchors or a secure anchor point as deemed necessary. • If liquid CO2 is to be pumped, contingency plans shall be in place to deal with ice plugs in the surface piping (treating iron, coiled tubing, etc.). 7.4. PRESSURE TESTS (PT) (per IRP 21) With the coiled tubing BOP components and auxiliary equipment installed on the wellhead, the BOP system shall be pressure tested as follows: • A low-pressure test of 200psi (1,400 kPa) must be conducted on each ram preventer for ten minutes. This test is to be conducted first. • A high-pressure test must be conducted on each ram preventer for ten minutes. The pressure required shall be the wellhead pressure rating or 1.1 times the estimated maximum potential SITP (for critical sour wells 1.3 times the estimated maximum potential SITP)—whichever is the lesser. • The annular preventer must be pressure tested for ten minutes to the wellhead pressure rating or 1.1 times the estimated maximum potential SITP (for critical sour wells 1.3 times the estimated maximum potential SITP)— whichever is the lesser. • The stuffing box assembly must be pressure tested for ten minutes to the wellhead pressure rating or 1.1 times the estimated maximum potential SITP (for critical sour wells 1.3 times the estimated maximum potential SITP)— whichever is the lesser. An on -location stump test is acceptable if a pressure test of the connecting flange is completed after installation on the well. A produced hydrocarbon is not an acceptable pressure testing medium. Page 10 of 26 CODE: PEI-WI19-03274-001 WORK INSTRUCTION FOR PULLING ARMORPAK DATE: August 7, 2019 ENGINEEERINGERING LLC BRU 212 PETC Hilcorp Alaska — -35T REVISION N°: 0 PAGE: 11 of 26 The following components of the BOP system shall be pressure tested for ten minutes to the wellhead pressure rating or 1.1 times the estimated maximum potential SITP (for critical sour wells 1.3 times the estimated maximum potential SITP)—whichever is the lesser: • The connection between the BOP stack and the wellhead, • Auxiliary equipment including lubricators and pressure windows, • Bleed -off and kill lines, • All valves in the bleed -off manifold (if applicable), • Reel isolation valve, • Coiled tubing pipe (pressure tested to the criteria above or maximum anticipated wellhead treatment pressure—whichever is greater), and • Downhole equipment composing a part of the coiled tubing pipe above the isolation device (check valves). Adjustable chokes do not require testing. A differential pressure across the check valve shall be established to confirm check valve integrity before running in the hole. For a satisfactory pressure test using a liquid, all tests shall maintain a stabilized pressure of at least 90% of the test pressure over a 10 minute interval. For a satisfactory pressure test using an inert gas or air, not more than 5% of the value of the test pressure is to be recorded to have leaked off during the test period. If more than 5% has leaked off, then the length of the test shall be increased to determine the nature of the pressure decline. Where well classification or the greater of reservoir pressure and SITP is not clear through past operations, pressure tests should be conducted to the wellhead pressure rating. For Class I operations, a daily pressure test is acceptable. If air is to be used as a test medium, all regulatory requirements must be met and the appropriate hazard assessments carried out. Page 11 of 26 CODE: PEI -W I19-03274-001 WORK INSTRUCTION FOR PULLING ARMORPAK DATE: August 7, 2019 t PETEERING C Hilcorp Alaska LLC — BRU 212-35T ��/// PETR aiN� REVISION N°: 0 PAGE: 12 of 26 7.5. EQUIPMENT RECORDS (per IRP 21) Equipment Records are files detailing information about the history of the equipment used during CT operations. A coiled tubing contractor shall have a pipe management system ensuring that a program is in place using a records log to predict when a coiled tubing pipe shall be removed from service. Records should be kept of the following: • all operations conducted with the coiled tubing pipe being used, • fluid types and/or gases pumped, and • metres run and cycled. See IRP 21 Sections 3.9.4: CT String Post -Production Records and 3.11: Implementing a CT String - Life Management System for further details. 7.6. OPERATING PRACTICES (per IRP 21) The coiled tubing unit shall not be left unattended while the lubricator or injector head assembly is connected to the wellhead. For coiled tubing strings with a BHA, a pull test shall be performed on the coiled tubing pipe to BHA connection before running into the well, and the intensity of the pull shall be based on the expected operational requirements. While in the hole, coiled tubing pipe shall not exceed operating limits. Factors such as differential pressure across coiled tubing pipe and axial load should be taken into consideration. These accumulative factors affect total stress level on the coiled tubing pipe. In the event of a serious wellhead leak between the coiled tubing BOP stack and the master valve, consideration should be given to the following procedure in order to bring the well under control: 1. Ensure everyone on location is safe. 2. Evaluate if the coiled tubing can be pulled from the hole so the master valve can be closed to bring the well under control. 3. Evaluate if the well can be safely killed and brought under control. Page 12 of 26 CODE: PEI-WI19-03274-001 WORK INSTRUCTION FOR PULLING ARMORPAK DATE: August 7, 2019 ENGINEERINGEERING PETHilcorp Alaska — BRU 212-35T ENGINEERING AlLLC REVISION N°: 0 PAGE: 13 of 26 For Class II and III wells, if the procedures listed above cannot be performed, consideration should be given to the following procedure: 1. Identify the depth of the bottom portion of the coiled tubing pipe. 2. Pull the bottom of the coiled tubing pipe high enough in the vertical portion of the hole to ensure that when the coiled tubing pipe is cut, the top of the coil will fall below the lowest master valve. 3. Activate the slip rams. 4. Ensure tension is pulled into the coiled tubing pipe above the slip rams then activate the shear rams and shear the pipe. 5. Open the slip rams and allow the coiled tubing pipe to fall below the lower master valve. 6. Shut in Master Valve and secure the well. When performing a BOP Drill the slip rams should not be closed on the coiled tubing as this will add stress risers that could lead to premature failure of the coiled tubing in the hole. Stress risers will make the coiled string significantly more susceptible to failure in sour gas environments. This applies to the BOP Drill only. In emergency situations the slip rams should be closed if the situation merits it. Page 13 of 26 E PETROSP to G WORK INSTRUCTION FOR PULLING ARMORPAK ENG NEER N� Hilcorp Alaska LLC — BRU 212-35T 8. EQUIPMENT SPECIFICATIONS 8.1. Existing ArmorPakTM System • Material: o Tenaris AN 5ST Certified HS70T" (CT70) CinMn Corina Cnarc Chemical Requirements (mass percent) CODE: PEI -W I19-03274-001 DATE: August 7, 2019 REVISION N°: 0 PAGE: 14 of 26 Grade Carbon Manganese Phosphorus Sulfur Silicon - max max max max max H57V 0.16 1.20 0.020 0.005 0.50 o Tensile Requirements Grade Yield Strength MIN Vield Strength MAX Tensile Strength MIN Hardness Maximum BODY & WELD - psi MPa psi MPa psi MPa HRC HS70'" 70,000 483 80,000 552 80,000 552 22 Sectional Strength Strength Outside Wall Inside Weight Cross Yield Tensile Internal Torsional Diameter Thickness Diameter Sectional Strength Strength Yield Yield Area Pressure Strength (in) (in) (in) (Lb/ft) (in A2) (Lbs) (Lbs) (psi) (ft -lbs) 1.5 .109 1.264 1.621 0.476 33,860 38,100 9,050 1,040 0.75 .095 0.560 0.665 0.195 13,680 15,640 16,800 190 Armnr Park Weight Yield Strength Tensile Strength (Ib/ft) (Lbs) (lbs) 3.242 67,720 76,200 Page 14 of 26 ♦PETROSPEO WORK INSTRUCTION FOR PULLING ARMORPAK ENGINEERING Hilcorp Alaska LLC — BRU 212-35T CODE: PEI-WI19-03274-001 DATE: August 7, 2019 REVISION N°: 0 PAGE: 15 of 26 • Dimensions: 0 0.75" OD x 0.095" specified wall thickness, continuously milled. 0 112" diameter x 70" width x 95" core wooden shipping spool. 0 4,137 ft (1261m) total length. • Max. Pull to Yield (calculated; with no safety factor): 13,929 Ibf (6,196 daN) • String Weight (w/o CT Spool): 3,690 lbs (1,674 kg) • Total Spool Weight (Loaded): 4,690 lbs (2,127 kg) Page 15 of 26 PETROSPEC WORK INSTRUCTION FOR PULLING ARMORPAK ENGINEERING Hilcorp Alaska LLC — BRU 212-35T 9. CREW ROLES AND RESPONSIBILITIES CODE: PEI -W HM3274-001 DATE: August 7, 2019 REVISION N°: 0 PAGE: 16 of 26 Crew -Member Role Responsibility Company Man / Well -site Supervisor Described by Hilcorp Alaska LLC • Defined by Hilcorp Cole Bartlewski 907.690.2854 • Lead the CTU crew in providing downhole completion installation services and/or associated services regarding instrumentation applications. Ensure proper tools and equipment are loaded out for specific jobs. • To be an industry leader in the quality of products & services delivered to clients. Coiled Tubing Supervisor is • Conduct safety and equipment inspections in a thorough and responsible for the coordination timely manner. of various instrumentation . Provide oversight and monitor high-risk activities at job site. operations in the field. . Ensure that necessary equipment and personnel are assigned Supervisors are also responsible to & ready for the job. CT Supervisor for the supervision and safety of . Operate CT unit and a ui ment used in CT operations. P Y equipment an personnel and equipment at all . Monitor work of the crew to ensure it is carried out in a safe Colin McAmmond times, whether on a customer's and effective manner at all times. location or between locations. . Supervise crew completion of Job Safety Analysis forms, Job 403.363.8412 Safety Checklist forms. Reports to Company -Man on location and office Project • Complete Field Reports, Incident Reports, and associated job Engineer. Performs duties as documentation and submits them to the Operations Centre directed. Manager, CT Manager, and Project Engineer in a thorough and timely manner. • Provide instructions to the assigned crew members, as well as directing and assigning work accordingly. Direct rigging in and other functions at the job site as required. • Communicate with Petrospec internal departments (Project Engineer & Operations Center Manager) and client. • Comply with all Hilcorp Alaska LLC and Petrospec Engineering policies and procedures. • Responsible for the coordination, compliance, and sign -off of all client Safe Work Permits The ArmorPak`" Engineer is ArmorPakw responsible for, but not limited • Follow direction from the CT Supervisor. Engineer to assembly and disassembly of • Consult manuals, read and interpret circuit diagrams, blueprints Sheldon Minish bottom hole assemblies and and schematics. 780.871.3076 coiled tubing connectors. • Inspect and test the operation of instruments and systems to diagnose faults using testing devices. Page 16 of 26 ®PETwOspEC WORK INSTRUCTION FOR PULLING ARMORPAK ENGINEERING Hilcorp Alaska LLC — BRU 212-35T CODE: PEI-WI19-03274-001 DATE: August 7, 2019 REVISION N°: 0 PAGE: 17 of 26 Page 17 of 26 Reports to Coil Tubing • Write job reports. Supervisor on location and • Repair and adjust system components or remove and replace perform duties as directed. defective parts. • Calibrate components and instruments. • Perform scheduled preventative maintenance work. • Install control and measurement instruments on existing or new equipment. • Installation, troubleshooting, and commissioning of fiber optic systems. • Practice loss management principles. • Consult with and advise process operators. • Work with office engineers on basic design. • Interpret and use appropriate CSA, ISA, API, and ABSA installation standards and practices. • Observe safety in accordance with government and company standards. • Comply with all Hilcorp Alaska LLC and Petrospec Engineering policies and procedures. • Assist the CTU crew in providing downhole completion installation services and/or associated services regarding The Coiled Tubing Operator is instrumentation applications responsible for the safe • Help ensure proper tools and equipment are loaded out for operation of equipment at all specific job. times. • To be an industry leader in the quality of products & services CT Operator delivered to clients Reports to Coil Tubing • Operate and drive tandem -tandem or tandem -tri -axle coil Supervisor on location and tubing units and picker trucks perform duties as directed. • Operate CT unit and any equipment used in CT operations. • Communicate with internal departments • Training and mentoring crewmembers • Comply with all Hilcorp Alaska LLC and Petrospec Engineering policies and procedures Be involved in coiled tubing operations as pertains to well completion services. • Communicate with engineering and operation departments of Field Technician Petrospec Engineering Clint Jones Reports to Coil Tubing • Complete and submit all required paperwork (i.e. expense 780.233.2930 Supervisor on location and account, bonus and fuel sheets, logbooks, pre/post trip perform duties as directed. inspections, loading tickets) • Complete a journey management plan Page 17 of 26 ®PETROSPEC WORK INSTRUCTION FOR PULLING ARMORPAK ENGINEERING Hilcorp Alaska LLC — BRU 212-35T CODE: PEW119-03274-001 DATE: August 7, 2019 REVISION N°: 0 PAGE: 18 of 26 Page 18 of 26 • Complete a proper pre -trip inspection prior to leaving on any journey • Drive well servicing equipment to and from well sites Assist in rigging in and other functions at the job site as required • Ensure units are clean and properly functioning Maintain Coiled Tubing equipment, including the Coiled Tubing Unit, Boom Truck, Power Reel Trailer and Crew Truck with support trailer Ensure all hand tools are clean and put away • Clean well site • Comply with all Hilcorp Alaska LLC and Petrospec Engineering policies and procedures Crane Operator Defined by 3`d party crane 0 Defined by 3'd party crane provider provider Pump Operator Defined by pump provider 0 Defined by pump provider Reports to CT Supervisor ESP Technician Defined by Summit ESP Defined by Summit ESP Page 18 of 26 CODE: PEI -W119-03274-001 WORK INSTRUCTION FOR PULLING ARMORPAK DATE: August 7, 2019 ENGINEERINGEaini� PETEERING Hilcorp Alaska LLC — BRU 212-35T REVISION N°: 0 PAGE: 19 of 26 10. LIST OF EQUIPMENT 10.1. Supplied by Petrospec • Coiled tubing unit # 181 loaded with 1.5" X 1.5" Coil Tubing Tail on 120" wood spool • 1.5" x 1.5" Armorpak running gear for the Injector and Arch. • 5 1/8" BOPS Dressed with 1.5" X 1.5" ArmorPak Rams • Manual Orientation Guide • 5 1/8" Lubricator • KR3 Stripper dressed with 1.5" X 1.5" Armorpak Elements • 1.5" X 1.5" Armorpak Dimple Blocks • Hilcorp Technician or Summit ESP Technician to disassemble cable splice. 10.2. Supplied by Hilcorp • 10 k Anchor Blocks • 2 rain for rent tanks • Fluid disposal tank -100 barrel tank • Vac truck • Pump truck • Filter Pod equipment • 80 Ton Crane • Zoom Boom man basket • Radios for crane operator and CTU operator • 2 3/8" hammer wrenches • 5 1/8" x 5K Flange with %2" NPT port, %" needle valve, and gauge. (Sold by Petrospec) Page 19 of 26 PETROBPEC WORK INSTRUCTION FOR PULLING ARMORPAK ENGINEERiNG Hilcorp Alaska LLC — BRU 212-35T 11. ARMORPAK PULL WORK INSTRUCTION CODE: PEI-WI19-03274-001 DATE: August 7, 2019 REVISION N°: 0 PAGE: 20 of 26 Page 20 of 26 1. Hold safety and procedure meeting. 2. Ensure all equipment is powered down and locked out. Verify there is no power in the electrical cable. 3. Kill well as per Company policy and field requirements. 4. Perform stump test on BOP to 200psi low and 3000psi high for 10 minutes each. 5. Remove water production line tee. t� w sit Gaa N.d.o.a, — ovsany new 55 "BRU Lan,em 31/16' 5000 pai na 212-35T Tree Configuration Page 20 of 26 PETROSPECI WORK INSTRUCTION FOR PULLING ARMORPAK ENGINEERING Hilcorp Alaska LLC — EIRU 212-35T 6. Install surface isolation plug into 1.5" CT. SIP Installation Procedure CODE: PEI-WI19-03274-001 DATE: August 7, 2019 REVISION N': 0 PAGE: 21 of 26 I. Close D -Flange gate valve above coil tubing and bleed off well pressure above gate valve. ii. Remove Flow Tee and D flange adapter from wellhead. iii. Install D -Flange X 2 3/8 EUE Adapter and Flow Tee with thread half hammer union sticking up. iv. Make up Y. NPT extension to SIP Ram. Note: Ensure extension will space out SIP to within 1" of the gate of the D -Flange gate valve. V. Make up Surface Isolation Plug to bottom of extension hand tight. This is an orb fitting and the oring will provide the seal. Vi. Make up SIP ram and plug to the hammer union on the wellhead. Vii. Make hydraulic hand pump to the SIP ram. viii. Pump ram down into the coiled tubing watching hydraulic pressure to determine if you make contact with the top of the coiled tubing. Use the full stroke of the ram. ix. Once the SIP is in place remove one of the hydraulic lines and put it to the top of the of the ram. Pump hydraulic fluid into the SIP ram and pressure up to 6000 psi and bleed off pressure above SIP to check that the SIP is holding pressure. X. Quickly release hydraulic pressure from SIP back into pump and check well pressure again. xi. Remove the hydraulic hose from the top of the ram and Install it back on the cylinder. xii. Rotating to the left, back off the orb fitting on the top of the SIP by turning the rod at the top of the ram. xiii. By reversing the flow on the valve of the pump stroke the rod all the way out and close the D -flange gate valve. Page 21 of 26 PETROBPEC WORK INSTRUCTION FOR PULLING ARMORPAK ENGINEERING Hilcorp Alaska LLC — BRU 212-35T CODE: PEI -W I19-03274-001 DATE: August 7, 2019 REVISION N°: 0 PAGE: 22 of 26 7. Spot equipment in accordance with Company and country regulations. �1 8. Check pressure on production and cable side of coiled tubing. Bleed off any residual pressure. 9. Disconnect cable splice at the LB at the wellhead. Page 22 of 26 PETROSPEC WORK INSTRUCTION FOR PULLING ARMORPAK W ENGINEERING I Hilcorp Alaska LLC — BRU 212-35T CODE: PEI-WI19-03274-001 DATE: August 7, 2019 REVISION N°: 0 PAGE: 23 of 26 10. Disassemble wellhead down to ArmorPak tubing head. li �t-14 t I New 55V. Cameron 2-1/16' 5000 -psi Hyd t aul is WBRU 212-35T Tree Configuration 11. Bend Armorpak stickup so that both sides are straight and parallel. Cut Armorpak down to equal lengths. Keep them as short as possible but leave enough room to get the Dimple Block inserted into the stickup. 12. Dress coil with a 45 degree bevel on the inside and remove the seam at least 4" inside the coil. Page 23 of 26 PETROSPEC WORK INSTRUCTION FOR PULLING ARMORPAK LPAING Hilcorp, Alaska LLC — BRU 212-35T CODE: PEI -W119-03274-001 DATE: August 7, 2019 REVISION N': 0 PAGE: 24 of 26 Page 24 of 26 13. Repeat steps 11 and 12 with the Armorpak whip (tail) in the injector. 14. Dimple on 10 feet (3m) straightened section of coil using dimple block and 1.5" CJS Sealing Cold Roll and 1.5" Cable Cold Roll (Torque each bolt to 1300 in Ib) This 10 foot section is to get through the BOP and guide. 15. Attach guy wires to the injector at ground level. 6. Install, below the injector, Armorpak�ppers, stripper orientation guides, enough 5" lubricator to swallow the Bottom Hole Assembly (BHA), window and 5 1/8" ArmorPak dressed BOP's. 17. Install 51/8" Armorpak dressed BOPS and 5 1/8" Manual Orientation Guide over the 10 foot (3m) coil tubing extension and make up to tubing head. 18. Mark, with a paint marker, where the cold roll grooves would line up in the coiled tubing and insert 1.5" sealing cold rolls into Armorpak extension 19. Bring Injector, lubricator and Armorpak whip over Manual Guide and insert coil onto cold roll and dimple pipe into connector using dimple block. (Torque each bolt to 1300 in Ib) 20. Walk injector down pipe and make up lubricator stack to Manual Guide using man lift basket. 21. Chain Injector to Anchor Blocks. Page 24 of 26 PETROSPEC WORK INSTRUCTION FOR PULLING ARMORPAK ENGINEERING Hilcorp Alaska LLC — BRU 212-35T CODE: PEI-WI19-03274-001 DATE: August 7, 2019 REVISION N': 0 PAGE: 25 of 26 Page 25 of 26 22. Pressure test lubricator against tubing hanger and KR3 strippers by pumping through BOPS. Test to 500psi for 10 minutes. 23. Measure the distance from the tubing head to the center of the window, Unseat tubing hanger and pull up into window. Close BOPS, bleed of pressure and open windowCRemove tubing hanger. 24. Close window, open BOPs and continue pulling Armorpak from well. Pull out at no more than 100 feet/min. Confirm needle valve and tee is installed on production side of the Armorpak at core of the CTU spool and monitor pressure as we are pulling out of hole. 25. Slow down POOH rate to 25 feet minute from 3250 feet and below. Observe the pipe condition carefully to observe any damage. 26. Pull at 10 feet per minute for the last 20 feet. 27. Once out of the well, pull pump up into lubricator, close master valve and bleed off any gas build up. 28. Disconnect guy wires from the rig anchor blocks. 29. Break connection between lubricator and manual guide. 30. Position injector and lubricator stack over the rathole and lower the ESP assembly into the rathole. 31. Walk injector up the pipe to expose the Armorpak CT above the BHA. Page 25 of 26 6 PETROSPEC WORK INSTRUCTION FOR PULLING ARMORPAK ENGINEERING Hilcorp Alaska LLC — BRU 212-35T CODE: PEI -W I19-03274-001 DATE: August 7, 2019 REVISION N°: 0 PAGE: 26 of 26 Page 26 of 26 32. Using hot tap tool, tap into production of Armorpak CT and bleed off any trapped pressure. We will need the man lift on this step. 33. Cut MLE 6" below the QCI splice boots. Disconnect the ESP flange. 34. Move injector and lubricator away from rathole. Inject ArmorPak to expose coil connector. Cut connector from Armorpak. Cut both sides of the Armorpak 6" above the dual coil connector. 35. Remove lubricator sections one at a time and rack injector onto the cradle at the rear of the unit. 36. Remove BOPS 37. Install 5 1/8" x 5K top cap flange on CT Head. Top cap flange has %2" NPT port, needle valve, and pressure gauge. 38. RDMO all equipment to staging area. Page 26 of 26 Y.I . O • Y .F� �� w'1 P f p A' AlIATE OF ALASKA • AKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon i,-- Plug Perforations l— Fracture Stimulate r... Pull Tubing T Operations Shutdown fv Performed: Suspend 1--- Perforate E Other Stimulate fl Alter Casing P Change Appjo-vrgd Program P Plug for Redrill I ' Perforate New Pool I Repair Well F Re-enter Susp Well r Other: ESP Swap C" P r---,,,,4-14-- 2.Operator Name: 4.Well Class Before Work: 5. Permit to Drill Number ConocoPhillips Alaska, Inc. Development [ ., Exploratory 198-161 3.Address: — 6.API Number: Stratigraphic fl Service r P. 0. Box 100360,Anchorage,Alaska 99510 50-283-20097-00 7.Property Designation(Lease Number): 8.Well Name and Number A029657 BRU 212 35T 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): none Beluga River Unit Undefined Gas 11. Present Well Condition Summary: Total Depth measured 4801 feet Plugs(measured) None true vertical 4678 feet Junk(measured) None Effective Depth measured 4721 feet Packer(measured) 0 true vertical 4214 feet (true vertical) 0 Casing Length Size MD TVD Burst Collapse CONDUCTOR 68 20 98 98 0 0 SURFACE 2647 13.375 2677 2605 0 0 PRODUCTION 4770 9.625 4800 4677 0 ,i s 0 r7 (----c ''~��,� • ' ECEIVE . Perforation depth: Measured depth: 3264-3346,3388-3416,3450-3492,3523-3556,3598-3636,3692-3712 DEC 2 8 2015 True Vertical Depth: 3166-3246,3287-3314,3348-3389,3419-3452,3493-3530,3585-3604 AOGCC Tubing(size,grade, MD,and TVD) 5.5,L-80,3811=MD, 3702=TVD Packer-Baker SC-1 3135=MD, 3040=TVD, Isolation Packer SC-1L 3354=MD,3254=TVD, Packers&SSSV(type,MD,and TVD) Isolation Packer SC-1L 3564=MD,3459=TVD, Baker FB-1 Retainer Packer 3777=MD, 3668=TVD SSSV: none 12.Stimulation or cement squeeze summary: Intervals treated(measured): none Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation 0 0 0 90 260 Subsequent to operation 0 1.5M 700 BWPD 90 116 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: r.n„ Daily Report of Well Operations 1.. Exploratory t Development Iv. Service I,.,., Stratigraphic Copies of Logs and Surveys Run f, 16.Well Status after work: Oil P Gas R WDSPL P Printed and Electronic Fracture Stimulation Data '-- GSTOR I.... WINJ P WAG 1— GINJ P SUSP P SPLUG P 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 315-699 Contact Michael Hazen@265-1032 Email hazenmc(a�conocophillips.com Printed Name Michael Haz-n Title Wells Engineer Signature -- �_� Phone:265-1032 Date (OC7EG(s RBDMSLLDLC 3 0 2015 .7 / -2._-3c' -/S' Form 10 404 Revised 5/2015 Z�� bmit Original Only 3 • DAILY REPORT OF WELL OPERATIONS BRU 212-35T 24hr Summaries 12/2/2015 RIG DOWN CTU PACKAGE & MOB EQUIPMENT TO BARGE LANDING; BLEED CT WATER PRODUCTION LINE PRESSURE =0; RETURN WELL TO O&M PRODUCTION OPERATORS;JOB COMPLETE 12/1/2015 LAND ESP/CT COMPLETION @ 4021' KB DEPTH;PULL Q-PLUG FROM WATER PRODUCTION STRING @ 3972' KB DEPTH 11/30/2015 RIG UP CTU +ESP TO WHA; NIGHT CRANE OPERATOR WATCHES INJECTOR/ESP STACK ON WH OVERNIGHT 1129/2015 ASSEMB LED ESP IN MOUSE HOLE;WAITING ON PETROSP EC TECH TO ARR NE FOR REMOVAL OF ARMORPAK COATING 11/28/2015 PUMP TO CLEAN & PURGE CT WATER PRODUCTION STRING;SLU TAG @ 4720' KB W/BAILER; BLACK SLUDGE SAMPLE RETURNED IN BAILER; PREP POWER CABLE 1127/2015 PULLED ESP/CT COMPLETION 1/26/2015 CT CREW REPAIRS PACKOFF ASSEMBLY 1/25/2015 RIGGED UP CTU TO PULL ESP/CT COMPLETION;POOH 27'WHEN OBJECT DROPS FROM INJECTOR&PACKOFF-TO-INJECTORX-OVER BENDS;RIH27'& LAND CT @ HANGER HEAD; RIG DOWN INJECTOR; DELAYJOB FOR PACKOFF REPAIR 1124/2015 KILL WELL;STRIP OFF WATER & POWER CABLE TREE EQUIPMENT; INSTALL 5- 18",SK MASTER VALVE,5-18", OK QUAD BOP/FLOWCROSS&CTUTUBI NG GUIDE 1123/2015 MIX 780 BBL 6% KCL WATER;HEATED KCL WATER TO 80F; SPOTIED TRIPLEX TEST PUMP&BLEED TRAILER ONSITE;STUMPTESTED BOP-PASS 1/22/2015 CONTINUE W/CTU RIG UP;SPOT 3 FLUID TANKS& LOAD 1TANK W/6% KCL WATER; USE INDIRECT HEATERS 2 THAW2ND&3RD TANK MANIFOLDS FROZEN W/SEAWATER FROM BARGE RIDE;THAW WELL FLOW LINE 1/21/2015 FLY CJS,SCHLUMBERGER, PEAK&POLLARD CREWSTO BELUGA;PRE-SPUD SAFETY/HSE MEETING; Spotted up in containment the CTU,80-Ton crane, SBL downhole pump, batch mixer, N2 pump/tank. Offloaded lubricator stand and pressure equipment, light plants, remaining containment equipment. - SAK i&OD ipU 212-35T ConocC Phi lips & Well Attribuillir Max Angle&MD TD r AIBvkc)Inc. : Wellbore APVUWI Field Name Wellbore Status ncl(9 MD(ftKB) Act Btm(ftKB) Carw�.rRldgips 502832009700 BELUGA RIVER UNIT PROD 22.07 1,985.01 4,801.0 ... Comment H2S(ppm) Date Annotation End Date KB-Grd(ft) Rig Release Date BRU 212-35T,12128/201510'.42'.11 AM SSSV:NONE Last WO: 22.50 10/10/1998 :...Vertical schemabc(actual) Annotation Depth(ftKB) End Date Annotation Last Mod By End Date Last Tag WLM 4,720.0 11/28/2015 Rev Reason:CHANGE OUT ESP(12/2/2015) pproven 12/16/2015 i.i.. - .Casing Strings HANGER;25.471Z t` Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)...Wt/Len(I...Grade Top Thread CONDUCTOR 20 19.124 30.0 98.0 98.0 166.00 X-56 WELDED Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)...Wt/Len(I...Grade Top Thread I I SURFACE 13 3/8 12.415 30.0 2,677.0 2,604.9 68.00 K-55 BUTT Casing Description OD(in) ID(in) Top IRKS) Set Depth(MKS) Set Depth(TVD)...Wt/Len(I...Grade Top Thread Mr CONDUCTOR.3058.0 .0 ^ PRODUCTION 9 5/8 8.681 30.0 4,800.0 4,677.2 47.00 S-95 BUTT-MOD COILED TUBING,-60.0 Tubing Strings GAS LIFT;2,009.8 Tubing Description String Ma...ID(in) Top(ftKB) Set Depth(ft..Set Depth(TVD)(...WI(Ib/ft) Grade Top Connection COILED TUBING(2 1 1/2 1.310 -60.0 3,961.0 3,849.2 1.43 CT80 EA 1 5"x 0 95"CT) SURFACE;30.0.2,677.0-0 Completion Details Nominal ID GAS LIFT;2,7648Top(MB) Top(TVD)(ftKB) Top Incl(9 Item Des Corn (in) '•, 3,901.0 3,790.2 10.72 ESP 60.0'OAL X 4.45"BAKER CENTRALIFT ESP(INCL. 1.310 ARMORPAK CONNECTOR ASSEMBLY) Tubing DescriptionMa...ID(in) Top(ftKB) Set Depth(ft..Set Depth(TVD)(...Wt(Ib/it) Grade Top Connection SLEEVE-C;3,078.8 i TUBING 1 String 51/21 4.9501 254 3,811.41 3 ,702.21 15.50 L-80 I LTC - Ii Completion Details _ Nominal ID SEAL ASSY,3,127.8 Top(ftKB) Top(TVD)(ftKB) Top Incl(3 Item Des Com (in) 25.4 25.4 0.05 HANGER DCB TUBING HANGER 5.500 3,078.8 2,985.3 14.55 SLEEVE-C OTIS X PROFILE SLIDING SLEEVE-CLOSED 4.562 PACKER;3,134.8 - , 3,127.8 3,032.8 13.45 SEAL ASSY BAKER GBH-22 LOCATOR SEAL ASSEMBLY 4.875 3,134.8 3,039.7 13.33 PACKER BAKER SC-1 GRAVEL PACK PACKER 6.000 -' 3,148.8 3,053.3 13.09 Gravel Pack BAKERS MINI-BETA GRAVEL PACK 4.750 Grovel Pack;3,148.8 M M 3,260.8 3,162.7 12.07 SCREEN BAKERWELD SCREEN 140 4.950 3,353.8 3,253.7 11.84 PACKER BAKER SC-1L ISOLATION PACKER 6.000 3,358.8 3,258.6 11.83 Gravel Pack BAKER S MINI-BETA GRAVEL PACK 4.750 SLOTS;3,264.0-3,346 0-, SCREEN;3,260.81 ( a I 3,400.8 3,299.7 11.76 SCREEN BAKERWELD SCREEN 140 4.950 pf 0 3,440.8 3,338.8 11.72 SCREEN BAKERWELD SCREEN 140 4.950 3,563.8 3,4593 11.47 PACKER BAKER SC-1L ISOLATION PACKER 6.000 3,569.8 3,465.2 11.46 Gravel Pack BAKER S MINI-BETA GRAVEL PACK 4.750 PACKER;3,353.8 3,610.8 3,505.4 11.35 SCREEN BAKERWELD SCREEN 140 4.950 3,654.8 3,548.5 11.23 SCREEN BAKERWELD SCREEN 140 4.950 3,775.8 3,667.3 10.93 SEAL ASSY BAKER S-22B SNAP LATCH SEAL ASSEMBLY 4.750 Graces Pack 3,358 a 3,777.0 3,668.4 10.93 PACKER BAKER FB-1 RETAINER PRODUCTION PACKER 6.000 Lt 3,811.0 3,701.8 10.90 WLEG WIRELINE ENTRY GUIDE 4.767 Perforations&Slots SLOTS;3,388.0-3,416.0-. ru Shot 1 1 I Dens SCREEN;3,400.8 1 1 Top(TVD) Btm(TVD) (shots/ 11 Top(ftKB) Btm(ftKB) (ftKB) (ftKB) Zone Date ft) Type Com 3,264.0 3,346.0 3,165.8 3,246.0 A,BRU 212- 10/1/1998 14.0 SLOTS '7"HSD Deep Pen.TCP i 35T I:. 3,388.0 3,416.0 3,287.1 3,314.5 A,BRU 212- 10/1/1998 14.0 SLOTS 7"HSD Deep Pen.TCP 35T SLOTS,3.4500-3.452.0- lfy1l ( I 3,450 0 3,492.0 3,347.8 3,389.0 B,BRU 212- 10/1/1998 14.0 SLOTS 7"HSD Deep Pen.TCP SCREEN,3,440.8 M 9+ 35T i II 3.523.0 3,556.0 3,419.3 3,451.6 B,BRU 212- 10/1/1998 14.0 SLOTS 7"HSD Deep Pen.TCP SLOTS;3,523.0-3,556.0---. 351 3,598.0 3,636.0 3,492.8 3,530.1 C,BRU 212- 10/1/1998 14.0 SLOTS 7"HSD Deep Pen.TCP 35T 3,692.0 3,712.0 3,585.0 3,604.6 C,BRU 212- 10/1/1998 14.0 SLOTS 7"HSD Deep Pen.TCP PACKER;3,5638 "III lir 35T Mandrel Inserts St Gravel Pack.3.5838 '!1111 ati ';_. N Top(TVD) Valve Latch Port Size TRO Run Top IftKB) (ftKB) Make Model OD(in) Sew Type Type (in) (psi) Run Date Corn 1 2,009.8 1,983.0 MERLA 1 1/2 GAS LIFT DMY 0.000 0.0 10/8/1998 2 2,764 8 2,686.8 MERLA 1 1/2 GAS LIFT DMY 0.000 0.0 10/8/1998 SLOTS;3,598.03,636.0 -, ` Notes:General&Safety SCREEN;3,810.8d End Date Annotation 11 0 10/8/1998 NOTE:NO MANDREL OD/ID,MODEL DATA AVAILABLE 1/21/2011 NOTE View Schematic w/Alaska Schematic9.0 SLOTS,3,692.03,712.0 '1. u SCREEN;3,854.8 - 'I 0 'I O SEAL ASSY;3,775.8 PACKER;3,777.0 WLEG;3,811.0 I! ESP;3,901.0 l:;lfi PRODUCTION,30.0-4,800.0 - •tioF 7I . • w��%sem THE STATE Alaska Oil and Gas 4i1 of T Conservati®n Commission :fz AsKA 333 West Seventh Avenue Anchorage, Alaska 99501-3572 GOVERNOR BILL WALKER g Main: 907.279.1433 Fax: 907.276.7542 NON rL�Oq www.aogcc.alaska.gov 0EDNON ' 6 Michael Hazen Wells Engineer p ( b j ConocoPhillips Alaska, Inc. Z� P.O. Box 100360 Anchorage, AK 99510-0360 Re: Beluga River Field, Undefined Gas Pool, BRU 212-35T Sundry Number: 315-699 Dear Mr. Hazen: 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, Cathy P. Foerster Chair DATED this 13 day of November, 2015 Encl. RBDMS` OV 161015 0 • RECEIVED STATE OF ALASKA NOV 12 2015 ALASKA OIL AND GAS CONSERVATION COMMISSION f /� APPLICATION FOR SUNDRY APPROVALS A0Uu 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: ESP Swap n^ 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: DUAL- Sr X I Al"1 ConocoPhillips Alaska, Inc. ` Exploratory ❑ Development Q. 198-161 3.Address: Stratigraphic ❑ Service ❑ 6.API Number: P.O. Box 100360,Anchorage,Alaska 99510 50-283-20097-00 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? BRU 212-35T. Will planned perforations require a spacing exception? Yes ❑ No ❑., / 9.Property Designation(Lease Number): 10.Field/Pool(s): r�� J�L t4 A029657 ' Beluga River Unit/Beluga River Vs1 i GU-S 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): 4801 ' 4678 • 4721 ' 4214 - 0 none none Casing Length Size MD TVD Burst Collapse Structural Conductor 68' 20" 98' 98' 3060 1500 Surface 2647 13.375" 2677' 2605' 3450 1950 Intermediate Production 4770 9.625" 4800' 4677' 6870 4750 Liner Perforation Depth MD(ft) 3264-3346,3388-3416 Perforation Depth TVD(ft; 3166-3246,3287-3315 Tubing Size: Tubing Grade: Tubing MD(ft): 3450-3492,3450-3492,3598-3636,3692-3712 , 3348-3389,3419-3452,3493-3530,3585-3605 5.5 L-80 3811 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): Packer-Baker FB-1 Retainer Production Packer / No SSSV MD=3777 TVD=3668 12.Attachments: Proposal Summary Q Wellbore schematic ❑✓ 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic❑ Development❑., - Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 11/18/2015 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS El- WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Michael Hazen @ 265-1032 Email hazenmc(c�conocophillips.com Printed Name L Michael Hazen Title Wells Engineer Signature ` Phone Date COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3 �� 15— Cc? Plug Integrity ❑ BOP Test [27- Mechanical Integrity Test ❑ Location Clearance ❑ ` Other: w 3 t7CYJ f6° egr)e . �..+25 If— ( Ise .7-- 2 G C7 ,e, J\ Post Initial Injection MIT Req'd? Yes ❑ No ❑ .1 RBDMS OV 1611115 Spacing Exception Required? Yes ❑ LiJ No Subsequent Form Required: /O "'y O 1 APPROVED BY Approved by:G7� /12"9(1,14...7(74,,,—___ 2" COMMISSIONER THE COMMISSION Date:/(— /3 -- /S" Gifil,G4NA yi l� i. /A Submit Form and Form 10-40 Revised 11/2015 lid for 12 months fro adateof approval. „{ '-' Attachments in Duplicate ,'f./3•ar- ,.0`-'1r�1�5----- • • BRU 212-35T Coiled Tubing Workover: Pull and Reinstall Dual-String Coiled Tubing Completion with Replaced Electric Submersible Pump (PTD# 198-161) Current Status: The well is shut in,dead,with a failed ESP unable to surface fluid.Prior to the ESP failure the well produced approximately 3.9-MMSCFD and 600,_BWPD. There is a plug set in the bottom of the water production string at the CT/ESP connector and the string has been logged and pressure tested to 2000-psi to confirm CT integrity. Scope of Work: Pull the dual-string 1.5"CT completion and re-run after replacing the 35-HP Baker Hughes 375 Series ESP with a Flex 6 DC 550 AR. / General Well info: MASP: 260 psi(using 0.1 psi/ft gas gradient and Beluga C @ 3,692'MD) Max.Reservoir pressures/TVD: From 11/10/2015 Downhole ESP Gauge: Beluga C @ 3,500'MD/3,397'TVD=370 psi/2.1 ppg Wellhead type/pressure rating: VetcoGray 3,000 psig CJS Production Technologies BOP Configuration: Blind-Shear/Blind-Shear/Pipe/Slip Rams Well Type: Gas Producer Estimated Start Date: November 18,2015 Wells Engineer: Mike Hazen(265-1032,hazenmc@conocophillips.com) Production Engineer: Tyler Hall(263-4012,Tyler.A.Hall @conocophillips.com)Cook Inlet Production Engineer Procedure: Equipment List ' a. Coiled tubing unit loaded with 1.5"X 1.5"Coil Tubing(ArmorPak)Workstring Tail b. 5"X 1.5"ArmorPak running gear for the Injector and Arch. c. 65-80 Ton Crane(100'Boom Height) d. Pressure Truck for pressure testing lubricator connection and well kill e. Tanks f. 5-1/8"BOPs Dressed with 1.5"X 1.5"ArmorPak Rams g. Manual Orientation Guide h. 5-1/8"Lubricator i. Rolling BOP dressed with 1.5"X 1.5"ArmorPak Elements j. 1.5"X 1.5"ArmorPak Dimple Block k. Qualified Technician to disassemble cable splice. 1. Anchor Blocks m. Slickline Unit for pulling downhole Plug Pull ESP Pump \ 2. Hold HSE and procedure meeting. K w F t p P / 3. Kill well as per Company policy and field requirements. C 4. Spot equipment in accordance with regulations. 5. Install,below the injector,ArmorPak KR3 Strippers,orientation guides,enough 5"lubricator to swallow the Bottom Hole Assembly(BHA),window and 5 1/8"ArmorPak dressed BOPE. 6. Test BOPE. .-+ 5 cue, psi 7. Check pressure on production and cable side of coiled tubing.Bleed off any residual pressure. 8. Ensure all equipment is powered down and locked out. Verify there is now power in the electrical cable. . 9. Have a qualified technician disconnect cable splice. • 10. Disassemble the water production and electrical-penetrator wellhead down to tubing head. 11. Bend ArmorPak so that both sides are straight and parallel.Cut ArmorPak down to equal lengths. Keep them as short as possible but leave enough room to attach Dimple Block connector. • • 12. Dress coil looking up from hanger with a 45 degree bevel on the inside and remove the seam at least 4"inside the coil.Repeat steps 9 and 10 with the ArmorPak in the injector. 13. Dimple on straightened section of coil using dimple block and 1.5"CJS Sealing Cold Roll and 1.5"Cable Cold Roll(Torque each bolt to 1300 in lb). 14. Set down 5-1/8"ArmorPak dressed BOPE and 5-1/8"Manual Orientation Guide over coil tubing extension and make up to tubing head. 15. Mark,with a paint marker,where the cold roll grooves would line up in the coiled tubing and insert 1.5"sealing cold rolls into ArmorPak extension 16. Bring Injector and ArmorPak over Manual Guide and insert coil onto cold roll and dimple pipe into connector using dimple block.(Torque each bolt to 1300 in ib) 17. Walk injector down pipe and make up Manual Guide to BOPE. 18. Chain Injector to Anchor Blocks 19. Pressure test lubricator against tubing hanger pumping through BOP's 20. Measure the distance from the tubing head to the centre of the window.Back out hanger torque bolts appropriate distance and unseat tubing hanger pulling it up into window. Close BOPs,bleed of pressure and open window. Remove tubing hanger. Flag pipe with paint. 21. Close window,open BOPs and continue pulling ArmorPak from well, Pull out at no more than 30 m/min. 22. Once out of the well,pull pump up into lubricator,close master valve and bleed off any gas build up. 23. Break off lubricator remove ESP from connector.Cut connector from ArmorPak. 24. Note:If you are removing the coil to replace the pump and motors and there are no problems with the cable,the down hole splice a the connector can be disassembled and the top portion of the wires can be reused. The connector does not have to be cut off and stripped back to expose more electrical cable. 25. Cap well and disassemble stack. 26. Cap Hydraulic Lines. 27. Analyze ESP pump for root cause failure and make decision to stop here RDMO or re-run replacement pump. Replace ESP Pump 28. Pick up ESP assembly with new replacement pump. 29. Perform electrical continuity checks phase x phase x ground.Function test the ESP gauge. 30. Suck entire ESP up into the lubricator assembly. 31. Move assembly over to the well. 32. Attach chains from the corners of the injector head to the 10,000-lb cement anchors located at 45°angles from the corners.Tighten chains to support stack. 33. Pressure test lubricator stack. 34. Open BOPE and tree valves. 35. Ensure well is dead;if necessary,pump additional HEC/KC1 quantities. 36. RIH until pump and pump connector is past the guide and ArmorPak is sitting across the guide. Close the guide. 37. RIH to near landing depth;observe pipe for flag. 38. Stop pipe at appropriate space out relative to pipe flag and depth counter.Account for difference in new completion depth as compared to previous depth due to losing some CT length to ensure spoolable connector stays out of the new system. 39. Close pipe rams on BOP's.Bleed window to tank. 40. Open work window to install CT tubing hanger. 41. Install 2 halves of hanger around the ArmorPak. 42. Tighten 0.375"screws into the hanger to fasten the two halves together. Tighten screws to 45 ft-lbs of torque. Install screws such that slots on either side are even-0.2"gap. Start in the middle of the hanger and work toward the top and bottom of the hanger. 43. Apply TFE15 sealant to hanger seals. 44. Measure the distance between the top of the hanger and leg bolts to ensure hanger gets landed properly. 45. Close window.Equalize window.Open the guide. Open BOP's. 46. RIH and stab hanger into hanger seat.Stack 10,000 lbs over string weight to ensure proper set. 47. Screw in lock down bolts to 80 ft-lb.Relax weight to neutral. 48. Hook up test pump to ports on wellhead and pressure test seals individually to 1000 ps for 15 minutes. Two barriers in direction of flow. 49. Cut coil at the work window. • • 50. Lift stack off of tubing hanger spool;lift injector slowly and monitor cable.Pull power cable free of ArmorPak at the wellhead. 51. Rig down CTU injector. 52. Remove BOP Stack. 53. Reinstall wellhead assemblies on both the water production and cable sides. 54. Quick Connectors Incorporated(QCI)technician to reconnect surface power from VFD skid. 55. Rig up slickline and pull Q-Plug from water production string 56. Rig up slickline on top of flow tee. 57. Run slickline and retrieve 0.875"Q-Plug in pump connector profile. 58. Rig out slickline. 59. Turn well over to Operations to restart ESP and restore gas production. �. / SAK PROD 0 BRU 212-35T CCmO OPhf li is �? Well Attributes Max Angle&MD TD Alaska Inc. Wellbore API/UWI Field Name Wellbore Status Inc!7) MD(ftKB) Act Btm(ftKB) r_mw,,,,,, 502832009700 BELUGA RIVER UNIT PROD 22.07 1,985.01 4,801.0 N ..- Comment H2S(ppm) Date Annotation End Date KB-Grd(ft) Rig Release Date BRU 212-35T,918/20152:40'22 PM SSSV NONE Last WO 22.50 10/10/1998 Vertical schematic(actual) Annotation Depth(ftKB) End Date Annotation Last Mod By End Date Last Tag-WLM 4,711.0 10/18/1998 Rev Reason.ADD ESP TUBING STRING smsmith 9/8/2015 g HANGER;25.4 Irl Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)...WE/Len ...Grade Top Thread ��{.J J CONDUCTOR (I 20 19.124 30.0 98.0 98.0 166.00 X-56 WELDED Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)...Wt/Len(I...Grade Top Thread SURFACE 133/8 12.415 30.0 2,677.0 2,604.9 68.00 K-55 BUTT Casing Deseriplion OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)... Wt/Len(I...Grade Top Thread �AnCONDUCTOR 30.0-98D 'e PRODUCTION 95/8 8.681 30.0 4,800.0 4,677.2 47.00 S-95 BUTT-MOD ` Tubing Strings GAS LIFT;2,009.81 Tubing Description Strang Ma...ID(in) Top(ftKB) Set Depth(ft..Set Depth(TVD)(...Wt(Ib/ft) Grade Top Connection COILED TUBING;0.0 COILED TUBING(2 11/2 1.310 0.0 4,086.9 3,973.1 1.43 CT80 }". I EA 1 5"x 0.95"CT) SURFACE;30.0-2,677.0 a Completion Details Nominal ID Top(ftKB) Top(TVD)(ftKB) Top Incl 13 Item Des Com (in) GAS LIFT;2,764.8 4,033.0 3,920.0 10.17 ESP 53.93'OAL x 4.4"BAKER CENTRILIFT ESP(INC.16.5' 1.310 ARMORPAK CONNECTOR ASSEMBLY) Tubing Description Stnng Ma...ID(in) Top(ftKB) Set Depth(ft..Set Depth(TVD)(...Wt(lb//t) Grade Top Connection SLEEVE C;3,078.8 I I TUBING 51/2 4.950 25.4 3,811.4 3,702.2 15.50 L-80 LTC Completion Details Nominal ID SEAL ASSY;3,127 8 Top(ftKB) Top(TVD)(ftKB) Top Incl(.) Item Des Com (in) 25.4 25.4 0.05 HANGER DCB TUBING HANGER 5.500 3,078.8 2,985.3 14.55 SLEEVE-C OTIS X PROFILE SLIDING SLEEVE-CLOSED 4.562 PACKER;3,134.8 3,127.8 3,032.8 13.45 SEAL ASSY BAKER GBH-22 LOCATOR SEAL ASSEMBLY 4.875 3,134.8 3,039.7 13.33 PACKER BAKER SC-1 GRAVEL PACK PACKER 6.000 3,148.8 3,053.3 13.09 Gravel Pack BAKERS MINI-BETA GRAVEL PACK 4.750 Gravel Pack',3,1488 3 3,260.8 3,162.7 12.07 SCREEN BAKERWELD SCREEN 140 4.950 3,353.8 3,253.7 11.84 PACKER BAKER SC-1L ISOLATION PACKER 6.000 3,358.8 3,258.6 11.83 Gravel Pack BAKERS MINI-BETA GRAVEL PACK 4.750 SLOTS;3,264.0-3,346.0 I ;i 3,400.8 3,299.7 11.76 SCREEN BAKERWELD SCREEN 140 4.950 SCREEN;3,260.8, I.- -( 1`1 I 3,440.8 3,338.8 11.72 SCREEN BAKERWELD SCREEN 140 4.950 3,563.8 3,459.3 11.47 PACKER BAKER SC-1L ISOLATION PACKER 6.000 3,569.8 3,465.2 11.46 Gravel Pack BAKERS MINI-BETA GRAVEL PACK 4.750 PACKER;3.353.8 3,610.8 3,505.4 11.35 SCREEN BAKERWELD SCREEN 140 4.950 3,654.8 3,548.5 11.23 SCREEN BAKERWELD SCREEN 140 4.950 _ 3,775.8 3,667.3 10.93 SEAL ASSY BAKER S-228 SNAP LATCH SEAL ASSEMBLY 4.750 Gravel Pack;3,358.8 3,777.0 3,668.4 10.93 PACKER BAKER FB-1 RETAINER PRODUCTION PACKER 6.000 3,811.0 3,701.8 10.90 WLEG WIRELINE ENTRY GUIDE 4.767 Perforations&Slots SLOTS;3,388.0-3,418.0- _ � Shot Dens SCREEN;3,400.8 f' 1': Top(TVD) Btm(TVD) (shots/f 1 t Top(ftKB) Btm(ftKB) (ftKB) (ftKB) Zone Date t) Type Com v 3,264.0 3,346.0 3,165.8 3,246.0 A,BRU 212- 10/1/1998 14.0 SLOTS 7"HSD Deep Pen.TCP • 35T 3,388.0 3,416.0 3,287.1 3,314.5 A,BRU 212- 10/1/1998 14.0 SLOTS 7"HSD Deep Pen.TCP 35T SLOTS;3,450.0-,492.0- I,r I 3,450.0 3,492.0 3,347.8 3,389.0 B,BRU 212- 10/1/1998 14.0 SLOTS 7"HSD Deep Pen.TCP .-- 35T SCREEN;3,440 8 B" 1' 3,523.0 3,556.0 3,419.3 3,451.6 B,BRU 212- 10/1/1998 14.0 SLOTS 7"HSD Deep Pen.TCP SLOTS;3,523.0-3,558.0- f t 35T .... 3,598.0 3,636.0 3,492.8 3,530.1 C,BRU 212- 10/1/1998 14.0 SLOTS 7"HSD Deep Pen.TCP 35T ' , 3,692.0 3,712.0 3,585.0 3,604.6 C,BRU 212- 10/1/1998 14.0 SLOTS 7"HSD Deep Pen.TCP 4: 35T PACKER',2563 8 Mandrel Inserts at Gravel Pack;3,569.8 on Top(TVD) Valve Latch Poll Size TRO Run N Tap(ftKB) (ftKB) Make Model OD(in) Sent Type Type (in) (psi) Run Date Com 'f' 2,009.8 1,983.0 MERLA 1 1/2 GAS LIFT DMY 0.000 0.0 10/8/1998 2 2,764.8 2,686.8 MERLA 1 1/2 GAS LIFT DMY 0.000 0.0 10/8/1998 SLOTS;3,696.0-3,636.0, Notes:General&Safety SCREEN;3,610.8 -I End Date Annotation .4 10/8/1998 NOTE NO MANDREL OD/ID,MODEL DATA AVAILABLE 1/21/2011 NOTE:View Schematic w/Alaska Schematic9.0 SLOTS;3,692.0-3,712.0-- I k/ O SCREEN;3,854.8 JJtt 0� SEAL ASSY;3,775.8 PACKER;3,777.0 c,r- WLEG 3,811.0 i 11/4) 41 `l ESP;4,033.0 //•{� /�V -S l ate( 6l�y-.51 PRODUCTION;30.04,800.0 P • STATE OF ALASKA ALQA OIL AND GAS CONSERVATION COMISSION REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon r Rug Perforations r Fracture Stimulate r Pull Tubing r Operations Shutdown r Performed: Suspend fl Perforate r Other Stimulate r Alter Casing r Change Approved Program[- Rug for Redrill r Perforate New Pool r Repair Well F Re-enter Susp Well r Other:ESP&CT completion installatiR 2.Operator Name: 4.Well Class Before Work: 5.Permit to Drill Number: ConocoPhillips Alaska, Inc. Development 17 Exploratoryr _ 198-161 3.Address: 6.API Number: P.O. Box 100360,Anchorage,Alaska 99510 Stratigraphic Service 50-283-20097-00 7.Property Designation(Lease Number): 8.Well Name and Number: A029657 BRU 212-35T 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): caliper Beluga River Unit/Beluga River Pool 11.Present Well Condition Summary: Total Depth measured 4801 feet Plugs(measured) None true vertical 4678 feet Junk(measured) None Effective Depth measured 4721 feet Packer(measured) 3135, 3354,3777 true vertical 4214 feet (true vertical) 3040,3254,3668 Casing Length Size MD TVD -- Burst Collapse Conductor 68' 20" 98' 98' Surface 2647' 13.375" 2677' 2605' Production 4770' 9.625" 4800' 4677' RECEWED %AINEP DELI 5 2015, AUG 2 4 2015 Perforation depth: Measured depth: 3264-3346,3388-3416,3450-3492, 3523-3556,3598-3636,3692-3712 � �� True Vertical Depth: 3166-3246, 3287-3315,3348-3389, 3419-3452,3493-3530,3585-3605 Tubing(size,grade,MD,and TVD) 5.5, L-80, 3811 MD, 3702 TVD Packers&SSSV(type,MD,and TVD) PACKER-BAKER SC-1 GRAVEL PACK PACKER @ 3135 MD/3040 TVD PACKER-2 BAKER SC-1L ISOLATION PACKERS @ 3354 MD/3254 TVD and 3564 MD/3459 TVD PACKER-BAKER FB-1 RETAINER PRODUCTION PACKER @ 3777 MD/3668 TVD no SSSV 12.Stimulation or cement squeeze summary: Intervals treated(measured): no stimulation or cement squeeze during this operation Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation is-VA 0 Z 0 '3" 0 Subsequent to operation Xibi 2-. 6, 1-1 f o 4, It 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations p Exploratory r Development Service fl Stratigraphic Copies of Logs and Surveys Run r 16.Well Status after work: Oil r Gas V WDSPL Printed and Electronic Fracture Stimulation Data r GSTOR r WINJ ifl WAG r GINJ r SUSP r SPLUG 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 314-601 Contact Michael Hazen 265-1032 Email Hazenmc(a�conocophillips.com Printed Name Michael Hazen Title Wells Engineer Signature ..IA '"Phone:265-1032 Date AL,it S �' I S-I RBDM ' 2 4 2015 Form 10-404 Revised 5/2015 Submit Original Only • • BRU 212-35T(PTD#198-161)ESP and Dual String CT Completion Install Summary 7/19/15 Offloaded second barge this morning.CJS coiled tubing unit,CT spools,and crane arrived;crews offloaded CT and equipment from floats and installed CT on unit. Mounted injector and stabbed pipe. Welded connector. Schlumberger crew arrived in Beluga. Inspected pumping and mixing equipment;inventoried all product and chemicals.Walked location. Initial programing/setup-up of the VSD performed, incoming voltage verified good and VSD stated and run with no load applied,all appears good. Attempted to establish remote SCADA communication link with the VSD, however BH monitoring service in Tulsa off line. Issue was reported to BH service desk, they confirm problems on their side and stated system would be up Monday AM. Visually confirmed all BH DHE, Field Service Tools and drill collar clamp have arrived in BRU. QC!, BH and Petrospec are assisting COP electricians with labor on cable prep and termination of VSD skid to Wellhead Vent box and Vent Box to Wellhead penetrator. 7/20/15 Spotted CJS CTU in containment and made up BOPE on stump.Connected accumulator and function tested BOPs. Erected work platform over mouse hole.Spotted/staged anchor blocks for work platform. Spotted SLB pump and batch mixer in containment;staged N2 unit on location.Staged iron racks. Spotted KCI filter pod. Laid out containment for four tanks and spotted three.Offloaded other equipment and tools. Baker Hughes web based monitoring system (Ambit) up and running this morning. We are able to attach, login,and view operation of the ESP, and edit parameters and settings. Designated COP staff will have read-only(view) rights to well; read/write rights will be limited to E&I. User rights are under the control of the BRU supervisors working with the BH representative in Anchorage. ESP power feed from the VSD skid is now terminated at the Wellhead vent box. Power feed at the VSD output transformer will be terminated tomorrow. All BH (ESP)downhole equipment has been physically checked, unboxed and moved near the rat hole and is ready to be made-up and serviced in the morning. BH field service engineers will rotate tomorrow, but no delay in operations is anticipated. 7/21/15 Performed BOP test;AOGCC waived witness 7-20-15. Spotted up fourth supply tank and began mixing 6% KCI. Rigged up pump and batch mixer. ESP system assembled,serviced, MLE (Motor Lead Extension)tied-in and left in the mouse hole. Received final instructions from E&I on termination of power feed from VSD output transformer to wellhead vent box. Small quantity of specialty electrical supplies needed and shipped from Houston for an expected arrival in Kenai Wednesday afternoon. No impact to system start-up even if the materials were late. • • System is ready to mate with lower coil connector and MLE termination to coil power cable. 7/22/15 Installed and pressure tested dual stripper assembly on injector. Picked up lubricator stack and work- window; pressure tested against test sub. Cut and dressed Apak and installed pump connector onto Apak.Welded production-side coil to connector and pressure tested production CT against tubing end plug. Mixed remaining 6%KCI for operation.Staged HEC-10 dry polymer,caustic soda,citric,defoamer,and breaker at batch mixer for gel mixing. ESP system mated to lower coil connector. The electrical power cable feed through assembly is complete, pressure tested and mated to the ESP MLE(Motor Lead Extension). All electrical checks of the system performed and the ESP gauge was function tested. Ready to pull up into the lubricator and RIH. 7/23/15 Moved to well and pressure tested lubricator stack and tree connection. Mixed and filtered gel at batch mixer; encountered delays preparing gel and maintaining constant KCI water supply from tanks to downhole pump. Fixed water manifolding issues and introduced breaker to gel. Pumped 6%KCI well kill fluid then circulated first pill. Wellhead pressure returned during circulation. Circulated second pill and again encountered WHP. Eventually able to maintain well on a vacuum. Built additional gel pill for RIH in the morning. 7/24/15 Pumped well kill procedure. Ran in hole and stopped at 82'to closed Armorpak guide. Ran in hole 3872ft and stopped for Baker to test cable. Ran in to 3977' and secured drum and injector to release clamp Armorpak and spool off of drum to obtain max hang depth of ESP. Ran pump into 4015ft and secured Armorpak tubing hanger clamp. Landed clamp in tubing hanger tightened in bolts. Pressure tested seals between upper and middle tubing hanger seals. Pressure tested seals between middle and lower. Cut cable side coil with pipe cutter and pulled out hole to expose cable in coil. Marked cable to ensure no movement in cable as pulling up on Apak. Rigged down lubricator stack with work window. Rigged of BOP stack and installed new wellhead tree. ESP electrical integrity checks as well as function test of the ESP downhole gauge system were performed just prior to the coil coming off of the reel. Electrical checks were all acceptable and gauge is functioning properly. The same checks were repeated just after the tubing hanger was landed and pressure tested. Again all readings were acceptable. All power cable runs for the surface equipment (VSD)are completed. The VSD setup/programing has been double checked and the VSD has been energized and run up with no load. • • Final cable whip/jumper from the wellhead electrical penetrator will be built up and installed once the ESP tubing head is made up. At that point the ESP will be ready to bring on line. 7/25/15 Completed connection of the final cable whip/jumper to the wellhead electrical penetrator.Completed the water production wellhead including surface safety valve. Pressure tested existing and new tree components against dart plug run in BHA. Rigged up slickline with 1-in tools, RIH CT production string to 4000-ft,and pulled dart plug in BHA. Installation complete;well online. II 4 it 1st? o ipr 1. t.. • •AK PROD BRU 212-35T ConocoPhillips t Well Attributes Max Angle&MD TD AlAtik<a,It),.; Wellbore API/UWI Field Name Wellbore Status Incl(°) MD(ftKB) Act Btm(ftKB) Crrnot;ayllip; 502832009700 BELUGA RIVER UNIT PROD 22.07 1,985.01 4,801.0 I ... Comment H2S(ppm) Date Annotation End Date KB-Grd(ft) Rig Release Date BRU 212-35T,9/8/2015 2:40:22 PM SSSV:NONE Last WO: 22.50 10/10/1998 Vertical schematic(actual) Annotation Depth(ftKB) End Date Annotation Last Mod By End Date Last Tag:WLM 4,711.0 10/18/1998 Rev Reason:ADD ESP TUBING STRING smsmith 9/8/2015 , , '„e'"'...m.are',Casing Strings HANGER:25.4 j WI , Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)... Wt/Len(I...Grade Top Thread CONDUCTOR 20 19.124 30.0 98.0 98.0 166.00 X-56 WELDED Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)... Wt/Len(I...Grade Top Thread SURFACE 13 3/8 12.415 30.0 2,677.0 2,604.9 68.00 K-55 BUTT ICasing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) 'Set Depth(TVD)... Wt/Len(I...Grade Top Thread -AA-A-CONDUCTOR;30.0-98.0 ► ^^ PRODUCTION 9 5/8 8.681 30.0 4,800.0 4,677.2 47.00 S-95 BUTT-MOD E ' Tubing Strings GAS LIFT;2,009.8 - Tubing Description String Ma...ID(in) Top(ftKB) Set Depth(ft...Set Depth(TVD)(...Wt(Ib/ft) Grade Top Connection COILED TUBING;0.0 COILED TUBING(2 1 1/2 1.310 0.0 4,086.9 3,973.1 1.43 CT80 I EA 1.5"x 0.95"CT) SURFACE;30.0-2,677.0 • Completion Details Nominal ID GAS LIFT;2,764.8 I Top(ftKB) Top(TVD)(ftKB) Top Incl(°) Item Des Com 53.93'OAL x 4.4"BAKER (in) 4,033.0 3,920.0 10.17 ESP CENTRILIFT ESP(INC.16.5' 1.310 ARMORPAK CONNECTOR ASSEMBLY) Tubing Description String Ma...ID(in) Top(ftKB) Set Depth(ft.. Set Depth(TVD)(...Wt(Ib/ft) Grade Top Connection SLEEVE-C;3,078.8 TUBING 51/2 4.950 25.4 3,811.4 3,702.2 15.50 L-80 LTC Completion Details Nominal ID SEAL ASSY;3,127.8 Top(ftKB) Top(ND)(ftKB) Top Incl(°) Item Des Com (in) 25.4+ 25.4 0.05 HANGER DCB TUBING HANGER 5.500 3,078.8 2,985.3 14.55 SLEEVE-C OTIS X PROFILE SLIDING SLEEVE-CLOSED 4.562 PACKER;3,134.8 3,127.8 3,032.8 13.45 SEAL ASSY BAKER GBH-22 LOCATOR SEAL ASSEMBLY 4.875 3,134.8 3,039.7 13.33 PACKER BAKER SC-1 GRAVEL PACK PACKER 6.000 3,148.8 3,053.3 13.09 Gravel Pack BAKERS MINI-BETA GRAVEL PACK 4.750 Gravel Pack;3,148.8 l® 3,260.8 3,162.7 12.07 SCREEN BAKERWELD SCREEN 140 4.950 3,353.8 3,253.7 11.84 PACKER BAKER SC-1L ISOLATION PACKER 6.000 3,358.8 3,258.6 11.83 Gravel Pack BAKER S MINI-BETA GRAVEL PACK 4.750 SLOTS;3,264,0-3,346.0 I I 3,400.8 3,440.8 3,299.7 3,338.8 11.76 SCREEN 11.72 SCREEN BAKERWELD SCREEN 140 4.950 SCREEN;3,260.81 I BAKERWELD SCREEN 140 4.950 3,563.8 3,459.3 11.47 PACKER BAKER SC-1L ISOLATION PACKER 6.000 3,569.8 3,465.2 11.46 Gravel Pack BAKER S MINI-BETA GRAVEL PACK 4.750 1•7'' 3,610.8 3,505.4 11.35 SCREEN BAKERWELD SCREEN 140 4.950 PACKER;3,353.8 3,654.8 3,548.5 11.23 SCREEN BAKERWELD SCREEN 140 4.950 3,775.8 3,667.3 10.93 SEAL ASSY BAKER S-22B SNAP LATCH SEAL ASSEMBLY 4.750 Gravel Pack;3,358.8 7 Ki 3,777.0 3,668.4 10.93 PACKER BAKER FB-1 RETAINER PRODUCTION PACKER 6.000 3,811.0 3,701.8 10.90 WLEG WIRELINE ENTRY GUIDE 4.767 I III Perforations&Slots SLOTS;3,388.0-3,416.0 I I 1I Shot 0 0 1 Dens SCREEN;3,400.8 I 0 Top(ND) Btm(TVD) (shots/f 0 0 Top(ftKB) Btm(ftKB) (ftKB) (ftKB) Zone Date t) Type Com ;; 3,264.0 3,346.0 3,165.8 3,246.0 A,BRU 212- 10/1/1998 14.0 SLOTS 7"HSD Deep Pen.TCP 35T 3,388.0 3,416.0 3,287.1 3,314.5 A,BRU 212- 10/1/1998 14.0 SLOTS 7"HSD Deep Pen.TCP • 35T SLOTS;3,450,0-3,492.0 1 I I I 3,450.0 3,492.0 3,347.8 3,389.0 B,BRU 212- 10/1/1998 14.0 SLOTS 7"HSD Deep Pen.TCP SCREEN;3,440.8 I I I I 35T 3,523.0 3,556.0 3,419.3 3,451.6 B,BRU 212- 10/1/1998 14.0 SLOTS 7"HSD Deep Pen.TCP SLOTS;3,523.0-3,556.0 I O . 35T 3,598.0 3,636.0 3,492.8 3,530.1 C,BRU 212- 10/1/1998 14.0 SLOTS 7"HSD Deep Pen.TCP 35T 3,692.0 3,712.0 3,585.0 3,604.6 C,BRU 212- 10/1/1998 ' 14.0 SLOTS 7"HSD Deep Pen.TCP 35T PACKER;3,563.8 Mandrel Inserts St ati Gravel Pack;3,569.8 -- f on Top(ND) Valve Latch Port Size TRO Run N Top(ftKB) (ftKB) Make Model OD(in) Sery Type Type (in) (psi) Run Date Com 1 2,009.8 1,983.0 MERLA 1 1/2 GAS LIFT DMY 0.000 0.0 10/8/1998 2' 2,764.8 2,686.8 MERLA 1 1/2 GAS LIFT DMY 0.000 0.0 10/8/1998 SLOTS;3,598.0-3,636.0 I I Notes: General&Safety SCREEN;3,610.8 I 'I 0 I End Date Annotation 0 0 10/8/1998 NOTE:NO MANDREL OD/ID,MODEL DATA AVAILABLE 1/21/2011 NOTE:View Schematic w/Alaska Schematic9.0 SLOTS;3,692.0-3,712.0 1 SCREEN;3,654.8 I SEAL ASSY;3,775.8 PACKER;3,777.0 WLEG;3,811.0 ESP;4,033.001 PRODUCTION;30.0-4,800,0 • T� Alaska Oil and Gas r:OF Oji sA THE STATE 71 OfALA c 1(A Conservation Commission • hitt= 333 West Seventh Avenue I GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 *M1 Main: 907.279.1433 OFALA6l‘� Fax: 907 276 7542 www.aogcc.alaska.gov Michael Hazen w i, 'I- ;1 �� Wells Engineer 1 b 1 ConocoPhillips Alaska, Inc. U P.O. Box 100360 ` Anchorage, AK 99510 Re: Beluga River Field, Beluga River Pool, BRU 212-35T Sundry Number: 314-601 Dear Mr. Hazen: 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, 'e21/ ' Daniel T. Seamount, Jr. Commissioner DATED this T day of April, 2015 Encl. v ! STATE OF ALASKA SKA OIL AND GAS CONSERVATION COMi ,ION N0\; 1 0 ZD 4 APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 rl,Ot t`;G C 1.Type of Request. Abandon r Rug for Redrill r Perforate New Pool r Repair w ell r Change Approved Program r Suspend r Rug Perforations r Perforate r Pull Tubing r Time Extension r Operational Shutdown r Re-enter Susp Well r StimulateAftecasino in r v,/&CT c L/Fi 61 r g Other.ESP 3 CT completion installatim W 2.Operator Name 4.Current Well Class. 5 Permit to Drill Number ConocoPhillips Alaska, Inc. Exploratory r Development F. . 198-161 3 AddressStratigraphic r Service r-" 6.API Number P.O. Box 100360,Anchorage,Alaska 99510 50-283-20097-00 7.If perforating, What 8 Well Name and Number. Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require spacing exception? Yes r No r BRU 212-35T ' 9 Property Designation(Lease Number): 10 Field/Pool(s): A029657 Beluga River Unit/Beluga River 11. PRESENT WELL CONDITION SUMMARY Total depth MD(ft): Total Depth TVD(ft) Effective Depth MD(ft)• Effective Depth TVD(ft) Plugs(measured) Junk(measured) 4801 4678 4721' 4214' none none _ _ _ Casing Length Size MD TVD Burst Collapse Conductor 68' 20" 98' 98' Surface 2647' 13.375" 2677' 2605' Production 4770' 9.625" 4800' 4677' Perforation Depth MD(+3264-3346,3388-3416, Perforation Depth TVD(ft). 3166-3246, Tubing Size Tubing Grade: Tubing MD(ft) 3450-3492,3523-3556,3598-3636,3692-3712 . 3287-3315,3348-3389,3419-3452,3493-3530,3585-3605 5.5 L-803811 _ Packers and SSSV Type Packers and SSSV MD(ft)and TVD(ft) PACKER-BAKER SC-1 GRAVEL PACK PACKER MD=3135 TVD=3040 PACKER-2 BAKER SC-1L ISOLATION PACKERS , MD=3354 TVD=3254 and MD=3564 TVD=3459 - PACKER-BAKER FB-1 RETAINER PRODUCTION PACKER MD=3777 TVD=3668 NO SSSV 12.Attachments: Description Sunmary of Proposal 17• 13. Well Class after proposed work: Detailed Operations Program r BOP Sketch r- Exploratory r Stratigraphic r Development r' Service r 14 Estimated Date for Commencing Operations 15 Well Status after proposed work: . 4/1/2015 Oil r Gas I✓ . WDSPL r Suspended r 16 Verbal Approval Date VVINJ r GINJ r WAG r Abandoned r Commission Representative GSTOR r SPLUG r 17. I hereby certify that the foregoing is true and correct to the best of my knowledge Contact Michael Hazen @ 265-1032 Email Hazenmc@conocophillips corn Printed Name Michael Hazen Title Wells Engineer Signature ' / - Phone:265-1032 Date If A/V 2_0 01- _:. f 0 Commission Use Only Sundry Number Conditions of approval Notify Commission so that a representative may witness �k — to G\i, C. Plug Integrity r BOP Test Fr Mechanical Integrity Test r Location Clearance r P 0 i s 1--- L /1411.5e= 3 7' ,a Other .t 3 Q.k r' (' Spacing Exception Required? Yes D No [r Subsequent Form Required to t/U Ll All APPROVED BY . I C Approved by: `u" COMMISSIONER THE COMMISSION Date. ` 1S , y.b 15 Apprii-cRilikInNfa) y�,� f[12 onths fom thedaaterova04 * .1SForm 10-403ised10/2012) -1\ 4/4 lllid I/ "lei/ _Submit Form and A ac nts in Duplicate //Y RBD MC APR - 9 2015 vi:D ConocoPhillips I Alaska N O V 10 2 914 P.O. BOX 100360 AOGCC ANCHORAGE,ALASKA 99510-0360 November 3,2014 Commissioner Dan Seamount State of Alaska Alaska Oil&Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage,Alaska 99501 Dear Commissioner: ConocoPhillips Alaska, Inc. hereby submits an Application for Sundry Approval to workover Beluga River Unit Producer 212-35T(PTD# 198-161). Beluga River Unit(BRU)212-35T was originally drilled and completed in late 1998 as a producer in the Beluga A-, B-,and C-sands. It is constructed with 9-5/8"production casing to 4800' and 5-1/2"tubing to 3811'. \// The purpose of this coiled-tubing (CT) workover is to install an electric submersible pump (ESP) on a dual-string fi CT completion for the purpose of water removal. One CT string will hang-off the ESP and at the same time serve as the water production string,while the other CT string will house and protect the ESP power cable. If you have any questions or require any further information, please contact me at 265-1032 or hazenmc@conocophillips.com. Sincerely, Michael C. Hazen Wells Engineer CPAI Drilling and Wells Sundry Application Supplement March 31, 2015 BRU 212-35T Coiled Tubing Workover: Install Dual-String Coiled Tubing Completion with Electric Submersible Pump for Water Removal (PTD# 198-161) Current Status: The well is currently shut in. When last online,the well produced approximately 7.5-MMSCFD and 400-B WPD. Scope of Work: Install dual-string 1.5"CT completion with 35-HP Baker Hughes 375 Series ESP. General Well info: MASP: 374 psi(using 0.1 psi/ft gas gradient and Beluga C @ 3,692'MD) Max.Reservoir pressures/TVD: From 5/9/2007 FBHPS: Beluga C @ 3,692'MD/3,585' TVD=732 psi/3.9 ppg Wellhead type/pressure rating: VetcoGray 3,000 psig CJS Production Technologies BOP Configuration: Blind-Shear/Blind-Shear/Pipe/Slip Rams Well Type: Gas Producer Estimated Start Date: April 15,2015 Wells Engineer: Mike Hazen(265-1032,hazenmc@conocophillips.com) Production Engineer: Tyler Hall(263-4012),Tyler.A.Hall@,conocophillips.com)Cook Inlet Production Engineer Brian Buck(265-6826,Brian.R.Buck@conocophillips.com)Cook Inlet Development Supervisor Proposed Completion and Tree Configuration: At the time of the planned workover to recomplete BRU 212-35T with the proposed dual-string coiled tubing(CT) electric submersible pump(ESP)completion,the existing tree(photo attached)will be reconfigured as in figure 1.The upper master will replace the SSV position,and a new 2-1/16"5M SSV will be installed in the horizontal run just outside the wing valve.Prior to this tree work,the well will be killed using corrosion inhibited 6%KCl and isolated Water Production Line ESP Power t Cable From VFD Skid seas Gas ^b Production Gas / S Line to "'rod uction Facility 11111.1 Line to Facility SSV: --- Cameron 5- - 1/8"5004- ) New SSV: psi yllao4« Cameron 2- ► Pneumatic 1/16" - ( ) 5000-psi -" Hydraulic BRU 212-35T BRU 212-35T Current Tree Pr,gse_dTree l Configuration using a 5.5"WRP bridge plug.A back pressure valve will be set in the tubing hanger and lower master closed (remaining in place as is). With the reconfiguration of the tree complete,the proposed ESP completion and SSV will be installed and production restored with water removal taking place from the ESP through its coil tubing string.The ESP power supply via a designated variable frequency drive(VFD)unit to be installed with the new completion will be connected to the emergency shut-down(ESD)system for the pad and for the well itself.Accordingly,at any time that the well or pad is turned off using the ESD or well safety system,then the ESP is automatically shut down as well and surfacing of water via ESP and CT stopped.It is shown that the well will not produce gas on its own without the removal of water from the well due to insufficient bottomhole pressure,essentially killing itself with a sustained production water level above and overcoming the gas production zone.A well kill plan and other contingencies are included with the sundry application detailing other considerations in the operation of the well. The well will be fitted with a web-based monitoring system of ESP downhole data via a cell modem to selected parties to remotely monitor and control the Variable Frequency Drive from a computer or phone application.This will serve as a enhancement to the existing SCADA system highlight important parameters and troubleshoot potential problems as we adopt this technology to the field. : i _ / i t , „/ �' `LA-f(447f L,A.y� ;,,be.., re i ha 4, Plb 1, i ' . , Ilt ' ; r' 11111 II, Ill r Una:„ f y k. _..+n.-,_....--. . a r 4 t Water Production Line ESP Power Cable From VFD Skid pr'r ' Gas Production Line to Facility don.. 1m V c `/ a New SSV: ` Cameron 2-1/16" 5000-psi Hydraulic BRU 212-35T Proposed Tree Configuration BRU 212-35T Coiled Tubing Workover: Install Dual-String Coiled Tubing Completion with Electric Submersible Pump for Water Removal (PTD# 198-161) Current Status: The well is on line and currently produces approximately 10-MMSCFD and 400-BWPD. Scope of Work: Install dual-string 1.5"CT completion with 35-HP Baker Hughes 375 Series ESP. General Well info: MASP: 3 psi(using 0.1 psi/ft gas gradient and Beluga C @ 3,692'MD) Max.Reservoir pressures/TVD: From 5/9/2007 FBHPS: Beluga C @ 3,692' MD/3,585' TVD=732 psi/3.9 ppg Wellhead type/pressure rating: VetcoGray 3,000 psig CJS Production Technologies BOP Configuration: Blind-Shear/Blind-Shear/Pipe/Slip Rams Well Type: Gas Producer Estimated Start Date: April 1,2015 Wells Engineer: Mike Hazen(265-1032,hazenmc@conocophillips.com) Production Engineer: Brian Buck(265-6826,Brian.R.Buck@conocophillips.com)Cook Inlet Development Supervisor Proposed Procedure: ESP Installation 1. Rig up steel work drum with dual 1.5"ArmorPak(one production string,one ESP cable housing)on CJS coiled tubing unit(CJS Production Technologies,Inc.,Calgary, Canada)and stab into Injector head and 2 strippers. Function test strippers. 2. Pick up Baker Hughes ESP to work floor then lower into rathole. Set retaining clamp on C-Plate in elevator on the work floor and lower stripper to top of lubricator. Connect joints of lubricator to strippers. 3. Install work window below lubricator and cut Production coil to expose ESP cable.Run Armorpak out from injector enough length so Petrospec soldering can be done with end of coil pointing up in vertical position. Install Re-entry Guide onto Armorpak. 4. Suck armorpak back into lubricator and strip connector up to ArmorPak.Dimple/seal electrical side of ArmorPak. Weld pump connector to production side of ArmorPak. Hook up ESP cable and Petrospec to check electrical continuity. 5. Pressure test cable side of coil down to seal in pump connector with nitrogen to 1,000 psi for 15 minutes. Coil with cable will have lens lock with 1' of piping,valve and 1"NPT fitting to pressure test against. Bleed off nitrogen pressure. 6. Connect pressure pump to high pressure swivel on working drum and pressure test production side of ArmorPak using water(3000 psi).Pressure test for 15 min at 500 psi,and 30 min at 3000 psi. Production coil will have a lens lock with ball valve and 1"NPT fitting. 7. Slide re-entry guide down to the top of the pump connector. 8. Suck pump connector into lubricator. Move lubricator assembly over to working floor.Attach lubricator to the top of the working floor. 9. Screw bottom sub into the top of the ESP and raise ESP with elevator up to the offset sub on the pump connector. Function Test—ESP. Suck entire ESP up into the lubricator assembly. 10.Stump test pipe rams by installing Armor Pak on plate. P/T to 5.000 psi for 30 minutes. 11.Install Wellhead hanger on top of the Flo-Tee on the well. Install the BOP's above the wellhead hanger. Install the coil guide on top of the BOP's. 12.Test BOPE. 13.Disconnect work window from the top of the floor. Move assembly over to the well. Connect the work window to the guide on top of the well. 14.Open master valve. 15.RIH until pump and pump connector is past the guide and ArmorPak is sitting across the guide. Close the guide. Close the pipe rams on the BOP's. Bleed window to tank. 16.Open work window and check to ensure armorpak is orientated correctly. 17.Close window and equalize. Open BOPs. RIH to landing depth accounting for K.B. elevations. Test continuity. Close pipe rams on BOP's. Bleed window to tank. Open work window. Install Hanger Assembly 18.Lower ArmorPak until clamp is not in work window. Install and torque 2 halves of hanger around the ArmorPak. I9.Measure the distance between the top of the hanger and legbolts to ensure hanger gets landed properly. Close window. Equalize window. Open the guide. Open BOP's. 20.RIH and stab hanger into hanger seat. Stack 10,000 lbs. over string weight to ensure proper set. 21.Measure distance the hanger was lowered and compare to above measurement to ensure the hanger is seated properly. 22.Screw in lock down bolts.Relax weight to neutral. 23.Hook up small CTU fluid pump to ports on wellhead and pressure test seals individually to 5,000 psi for 30 minutes. Two barriers tested in direction of flow. 24.Bleed off window. Hang Off Coil 25.Measure distance between the hanger and the work window. Confirm with QCI and Baker Hughes that distance is sufficient for their requirements. Unfasten wires from the coil drum. 26.Cut production coil with reciprocating saw at the work window. Install manual 2"cutters, and slowly cut coil with wires 1"above the cut on the production coil. 27.Lift injector slowly with picker;monitor cables and pull armorpak out of the way. 28.Rig down CTU injector. 29.Remove BOP Stack and install Wellhead Assembly on the Production Side. Lower crossover spool over the coil string and onto the Tubing Head. Tighten bolts. 30.Straighten production coil. Cut production coil 4' above hanger with 2"pipe cutter. Install the 5M D-Flange Seal Sub over the production coil. Bolt to the crossover spool. 31.Measure distance between flange face and gate on valve in segmented gate valve. 32.Measure and make final cut with 2"pipe cutter on production coil. Production coil to terminate just below gate valve. Install re-entry guide to the end of the production coil. 33.Lower segmented valve over the production coil and onto the 5M D-Flange Seal Sub. Bolt to the Seal Sub. 34.Close the segmented valve to secure production side. 35.Install Wellhead Assembly on the Wire Side. Cut coil with wire using 2"manual pipe cutter 4' above the hanger. 36.Strip on 5M D-Flange Seal Sub over wires and coil and land on crossover spool. Tighten bolts. 37.Cut coil 2"above the seal sub with 2"pipe cutter. 38.Install Petro spec Anchor. Install Quick Connector Seal Adapter over the wires and onto the Seal Sub. Install 2.0625"segmented X 2.0625"flanged crossover onto segmented valve. Tighten bolts. Install 2.0625" studded flow tee onto crossover. Tighten bolts.Install 2.0625"flanged ball valve onto studded tee. Tighten Bolts. 'Pressure Testing 39.Pressure Test to 1,500 psi for 30 minutes through port in production coil seal sub with nitrogen. This will test: 1.)the seals on production string;2.)the flanges between seal subs and crossover spool;and,3.)the flanges between crossover spool and tubing head. 40.Hook up to flow-tee and pressure test with water to 1,500 for 30 minutes. This will test the seal sub against the coil and all flanged connections above the seal sub. 41.Hook up nitrogen to the port in quick connector seal sub and pressure test to 1,500 psi for 30 minutes. Bleed off pressure. Pull CT Production String BHA Plug 42.Rig to slickline on top of flow tee. 43.Run slickline and retrieve 0.875"Q-Plug in pump connector profile. 44.Rig down slickline. 45.Rig down remaining equipment and turn over to production.Move to 232-26. Beluga River Unit (BRU)Well 212-35T CT/ESP Completion Kill Plan Purpose The purpose of this kill plan is to outline in detail the required equipment and process necessary to kill BRU 212-35T in the event of: A leak case,where production tree barrier is compromised and leaking occurs in the tree or surface flow equipment upstream of the wing valve. Mitigations to some of the risks associated with a major well control event were identified in the formal risk assessment of this completion and are included. Major catastrophic failure of the wellhead equipment,tree, or flowline is not covered here, however. Such cases are addressed as other live wells with respect to emergency preparedness under the CPAI D&W Emergency Preparedness& Blowout Contingency Plan. \\conoco.net\AK shared\ANC\Longterm\Drilling&Wells\Web\Wells Management System\7.1 - Emergency Preparedness\7.1.1 CPA Drilling and Wells Blowout Cont. Plan.pdf Well 212-35T Background Well 2:L2-35T is an onshore gas production well in BRU Alaska. Originally constructed in October 1998, the well was completed with a 20" X-56 Conductor(98'), 13-3/8" K-55 surface casing(2677'), 9-5/8"S-95 production casing(4800'), and 5-1/2" L-80 production tubing(3811'). The well will be completed with a thru-tubing ESP; utilizing dual 1-1/2" OS ArmorPak coiled tubing through the existing 5-1/2" production tubing. The dual ArmorPak coiled tubing configuration has one string of 1-1/2" conduit coil tubing containing the 1" ESP cable, and one string of 1-1/2" production coil tubing with the ESP on bottom. Once installed, water will be pumped to surface through the 1-1/2" production coil tubing;the gas will continue to be produced through the existing 5-1/2" production tubing, (now 5-1/2"tubing by CT annulus). The ESP installation will utilize 3900' dual 1-1/2"ArmorPak with#6 ESP bundle pre-loaded on one side and both coils pressure testable. During rig up and ESP installation,the following equipment will be rigged up to complete the work:40T crane,ArmorPak capable CTU C/W minimum 60k injector head,7" x 5M BOP's and accumulator, 5-1/2" annular BOP, 5-1/2" Bowen union x 5M 5-1/8" flange,5-1/2" hydraulic work window, 40' lubricator, 15-bbl pressure testing fluid, 2000-psi pressure testing pump, and an inventory of nitrogen for purging. This well is considered a category 3 well. The maximum expected flow rate from the well is 10MMSCFD natural gas and 500-BWPD produced water. No sand production. SITP is approximately 150-200 psig. Gas is 99%CH4 with negligible amounts of H2S and CO2. Water production from the 1-1/2" CT line is tied back to the well's production flowline through manifolding just outside the well house. Roles and Responsibilities CPAI Beluga Operators of 212-35T are expected to be familiar with this plan, and the implicit tasks that may be required herein such as pump rig up and operation,the limited heavy lift operations in its vicinity,etc. Operations Personnel are additionally expected to be familiar with the proper notifications necessary in the event of Level I, II, and III well control incidents should any incident escalate beyond the general well kill operation outlined in this plan. Equipment • Pumps o Field triplex stored at nearby pad (proximity of less than a mile to 212-35T) o Little Red Services downhole pump staged in Beluga • Piping or high-pressure hose; pump to flow line o Stored on pump unit:%2"JIC on field triplex(5000-psi); 1" and 2" lines with hammer unions (x/o to Weco1502 on LRS pump). • Water Availability o Peak water hauling trucks on contract to BRU in field • Flowline valves and tie-in for pump unit o To be installed on flow line manifolding where water production line ties into main well flowline:tee is required with double block valve, as well as valves in either flowline direction, and capped with crossover to field triplex high pressure hose. This tie-in point enables quick rig-up of field triplex to isolate flowline up-and downstream,then pump down the CT string in well for well kill pumping. o Existing swab valve on well to be moved opposite of wing in tree in order to allow additional downhole pump tie-in.This tie-in point enables rig-up of downhole pump to pump down production tubing by CT annulus for well kill pumping operations. Procedure )1(In the event of a leak at surface,where wellbore gas/liquid is being released at surface through a leak point in the wellhead or tree upstream of the wing valve or SSV,the following procedure can be followed to ESD the well to stop water production, isolate the well from flowline,and begin to kill the well down its existing CT production string, as well as begin the process to kill the well down the gas production flowpath if necessary,and if conditions allow. • Coiled tubing Volume (3900' x 1-1/2"CT) 5-bbl • Production tubing by CT annulus(5.5" by 2 each 1.5"CT) 75.4-bbl 1. Upon discovery of a leak in the production tree,shut down the operation of 212-35T by closing in wing valve on tree and/or SSV if possible. If necessary, shut in well using the well or pad ESD. 2. Power down the ESP and shut down power supply on pad. Lock out ESP pump breaker. 3. Dispatch LRS pump operator to Beluga for well kill operation. 4. Assess possible gas accumulation in and around well house by taking LEL meter readings in and around well and well house, staying cognizant of areas up and down wind. 5. Record initial pressures. 6. Conduct PJSM with involved personnel. 7. Dispatch tanks and field water hauling truck to site.Strap tank at compressor building to determine if water supply exists at pad to kill well. 8. Evaluate leak profile to determine pump rig up option. 9. Rig up LRS downhole pump unit into companion valve to pump down production tubing by CT annulus. Maximum pump pressure for this operation is 2300-psi. 10. Rig up field triplex to pump down the CT by tying in to the water production line tee at the flowline outside the well house. 11. Line up the manifolding to pump down the CT water production line only by isolating the flowline in directions toward wing and toward facility(such valves need to be installed at the time of water line tie-in). 12. Using LRS downhole pump, pump produced water at 3-bpm down 5.5" production tubing. Maximum pump pressure for this operation is 2300-psi. 13. Pump max rate of field triplex(%-bpm @ 200-psi)down 1.5" CT water production line. Maximum pump pressure for this operation is 3300-psi. 14. Dispatch loader to bring additional open top tank to location if necessary in order to fill with produced water for additional fluid.Consider mobilizing gel mixing equipment for HEC gel. 15. Continue pumping until well is dead and leak in production tree subsides.Total volume of tubing and CT to 3900' is 80-bbl. 16. Shut down pumps and isolate well. 17. Shut in ball valve at base of water production line,top of tree. 18. Record pressures and monitor well. 19. Assess production tree leak for plan forward. Well Design Envelope: Pumping Down CT String Max Pump Pressure: 3300 psi Max Pump Rate: 2.2 BPM Fluid: CT: 8.46# P.W. PT: natural gas IA: 8.4# F.W. OA: 8.4# F.W. Max BHP: CT: 9984 PT: 5032 IA: 4072 OA: N/A Pipe Press. Ratings: CT: 1.5" 1.62#CT90 PT: 5.5" 15.5# L-80 Casing: 9 5/8"47#S-95 OA: N/A (Burst/Collapse) (psi) 12480 10670 7740 1 6290 8,150 5090 Min I.D. 1.282" CT ID Max Dev: 22 deg @ 1985' Reservoir Pressure 2012 average Sterling 450-psi Latest Drift/Tag: SL 3860'8/30/09 Estimate: Pumping Down Production Tubing Max Pump Pressure: 2300 psi Max Pump Rate: 3.4 BPM Fluid: CT: 8.46#P.W. PT: 8.46# P.W. IA: 8.4# F.W. OA: 8.4#F.W. Max BHP: CT: 9984 PT: 5032 IA: 4072 OA: N/A Pipe Press. Ratings: CT: 1.5" 1.62#CT90 PT: 5.5" 15.5#L-80 Casing: 9 5/8"47#S-95 OA: N/A (Burst/Collapse) (psi) 12480 10670 7740 1 6290 8,150 5090 Min I.D. 1.282" CT ID Max Dev: 22 deg @ 1985' Reservoir Pressure 2012 average Sterling <450-psi Latest Drift/Tag: SL 4711', 1998 Estimate: Mitigations to Events Causing Loss of Well Control Piping/flowline protection outside well house • Pipe bollards to be constructed around piping outside of well house structure in order to prevent unintended contact from vehicles and equipment. • Jersey barriers to be installed around sides of well structure subject to paths of vehicle and equipment movement. Limited Overhead Lift Authorization in the 212-35T Vicinity Note:Any overhead lifting operation outside the matrix below planned to occur on E-Pad must be reviewed/approve by the Wells Superintendent. Possible Overhead Lift Scenario Mitigation Coiled tubing stack lift (i.e.:CT completion install; Well killed during CT completion installation decompletion) Thorough PJSM during lifting operations Multiple spotters at all time during lifting ops One designated signal man to crane operator Slickline stack lift(i.e.:rig up on CT water production string Well killed during CT completion installation side for BHA plug removal) Thorough PJSM during lifting operations Multiple spotters at all time during lifting ops One designated signal man to crane operator Rig up slickline from approach angle with least exposure Scaffold rig-down/removal post installation operations Well killed during CT completion installation Plan to disassemble as much as possible without using boom trucks Thorough PJSM during lifting operations Multiple spotters at all time during lifting ops One designated signal man to crane operator Rig up boom truck from approach angle with least exposure Well house structure removal/replacement Current plan does not anticipate necessity to remove well house. If discovery work shows we need to,assess ability to remove and replace rooftop only,and not the steel I-beam construction. t SAK BRU 212-35T ConocoPhillips /g Well Attributes Max Angle&MD TD Wellbore APIIUWI Field Name Wellbore Status Incl(') MD(RKB) Act Btm(RKB) 502832009700 BELUGA RIVER UNIT PROD 22.07 1,985.01 4,801.0 _.. "" Comment H2S(ppm) Date Annotation 'End Date KB-Ord(R) Rig Release Date Well Cnnfig:-SRU 212-35T 1111201210:44:29 AM SSSV:NONE Last WO: 22.50 10/10/1998 - Schematic-Actual Annotation Depth(RKB) End Date Annotation Last Mod By End Date Last Tag:WLM 4,711.0 10/18/1998 Rev Reason:WELL REVIEW osborl 11/1/2012 Casing Strings HANGER,25 " Casing Description String 0... String ID...Top(RKB) Set Depth(1...Set Depth(ND)...String Wt...String...String Top Thrd CONDUCTOR 20 19.124 30.0 98.0 98.0 166.00 X-56 WELDED Casing Description String 0... String ID...Top(RKB) Set Depth(f...Set Depth(ND)...String Wt...String...String Top Thrd SURFACE 133/8 12.415 30.0 2,677.0 2,604.9 68.00 K-55 BUTT CONDUCTOR ' Casing Description String 0... String ID...Top(MB) Set Depth(f...Set Depth(TVD)...String Wt...String...String Top Thrd PRODUCTION 9 5/8 8.681 30.0 4,800.0 4,677.2 47.00 5-95 BUTT-MOD Tubing Strings GAS LIFT. 11:.[L : Tubing Description String 0... String ID...Top(MB) Set Depth(1...Set Depth(ND)...String Wt...String...String Top Thrd 2,010 TUBING 51/2 4.950 25.4 3,811.4 3,702.2 15.50 L-80 LTC SURFACE, ` Completion Details 362 fi77 A Top Depth (TVD) Top Incl Nonni... Top(RKB) (RKB) (') Item Description Comment tO(in) GAS DFT 25.4 25.4 0.08 HANGER DCB TUBING HANGER 5.500 2,765 3,078.8 2,985.3 14.27 SLEEVE-C OTIS X PROFILE SLIDING SLEEVE-CLOSED 4.562 7,411, 3,127.8 3,032.8 12.51 SEAL ASSY BAKER GBH-22 LOCATOR SEAL ASSEMBLY 4.875 SLEEVE-C, 3.079 3,134.8 3,039.6 12.48 PACKER BAKER SC-1 GRAVEL PACK PACKER 6.000 .' 0)1 3,148.8 3,053.2 12.44 Gravel Pack BAKERS MINI-BETA GRAVEL PACK 4.750 SEAL ASSY, 3,260.8 3,162.7 12.07 SCREEN BAKERWELD SCREEN 140 4.950 3't2e '�'°" 3,353.8 3,253.7 11.80 PACKER BAKER SC-1L ISOLATION PACKER 6.000 . 3,358.8 3,258.6 11.79 Gravel Pack BAKERS MINI-BETA GRAVEL PACK 4.750 PACKER 3,135 - 3,400.8 3,299.7 11.76 SCREEN BAKERWELD SCREEN 140 4.950 ' 3,440.8 3,338.8 11.72 SCREEN BAKERWELD SCREEN 140 4.950 3563.8 3,459.3 11.47 PACKER BAKER SC-IL ISOLATION PACKER 6.000 Gravel Pad 3,569.8 3,465.2 11.46 Gravel Pack BAKERS MINI-BETA GRAVEL PACK 4.750 3,610.8 3,505.4 11.35 SCREEN BAKERWELD SCREEN 140 4.950 _ 3,654.8 3,548.5 11.23 SCREEN BAKERWELD SCREEN 140 4.950 SLOTS, 0 0 U 3,775.8 3,667.3 10.93 SEAL ASSY 'BAKER S-22B SNAP LATCH SEAL ASSEMBLY 4.750 3.264-3,346 NU II U 3,777.0 3,668.4 10.93 PACKER BAKER FB-1 RETAINER PRODUCTION PACKER 6.000 SCREEN,3,2611 3,811.01 3,701.81 10.90 WLEG WIRELINE ENTRY GUIDE 4.767 oco -Perforations&Slots Shot _ y Top(ND) Btm(TVD) Dere PACKER.3.354 Top(ftKS)She(MB) (MB) (RKB) Zone _ Date (eh-- Type Comment 3,264.0 3,346.0 3,165.8 3,246.0 A,BRU 212-35T 10/1/1998 14.0 SLOTS 7"HSD Deep Pen.TCP IN 3,388.0 3,416.0 3,287.1 3,314.5 A,BRU 212-35T 10%1/1998 14.0 SLOTS T HSD Deep Pen.TCP Gravel Paas liteiA`i 3,450.0 3,492.0 3,347.8 3,389.0 B,BRU 212-35T 10/1/1998 14.0 SLOTS T HSD DeepPen.TCP 3,359 - ►iii- 3,523.0 3,556.0 3,419.3 3,451.7 B,BRU 212-35T 10/1/1998 14.0 SLOTS T HSD Deep Pen.TCP 3,598.0 3,636.0 3,492.8 3,530.1 C,BRU 212-35T'10/1/1998 14.0 SLOTS T HSD Deep Pen.TCP .::tEk 3,692.0 3,712.0 3,585.0 3,604.6 C,BRU 212-35T 10/1/1998 14.0 SLOTS 7"HSD Deep Pen.TCP SLOT$ E: 3,36&3.416 0 D p...:: Notes:General&Safety SCREEN,3,401 `-'- a 0 0 U:' End Date Annotation 0 n Q; 10/8/1998 NOTE:NO MANDREL OD/ID,MODEL DATA AVAILABLE 1/21/2011 NOTE:View Schematic w/Alaska Schematic9.0 SLOTS, 3.4563.492 SCREEN,3.441 u E F SLOTS. E° III 3,5233.566 ,' '('''� PACKER,3,554 -- -- L•• Gravel Pack. 4►� 3,570 A�� 030 I SLOTS, 699-3,636 ri.,k' 0 0 0 SCREEN .2611 ;_. 0 0 3 000 SLOTS, 3,692-3,712 SCREEN,3,655 SEAL ASSY, C 3,776 PACKER,3,777 HI Mandrel Details Top Depth Top I Port (ND) Incl OD Valve Latch Size TRO Run WLEG,3,811 Stn Top(RKB) (RKB) (') Make Model (in) Sant Type Type (in) (psi) Run Date Com... PRODUCTION, 1 2,009.8 1,983.0 21.85 MERLA 1 12 GAS LIFT DMY 0.000 0.0 10/8/1998 • � 2 2,764.8. 2,687.0.20.88 MERLA 1 12 GAS LIFT DMY 0.000 0.0 10/8/1998 TD,4,801 likit OD c Eel • C ri, 3 N O J ° 'a L. MI= 3 in ._C 01 Mi: tx MIL IMMO ••M • ii=l d Q IH:. .•C "I'mu � a W 4� V I- -t 0o 03 C Q I- ( o N N N N OC GC CO m W ' wyn» fa, I. 1ss , aIll ji , _ z i" 0y <.. t diIt s - .mac. ti' - ' , '''i r 6i r _ 1 ' • 0 1/4) /III CU ILtJ l.0 m LII CN1 C• \1 Q.) -1 mL II > CN1 CN1 < D D CL > C . .C = +.1 0 as CO C[ 0 111 1 r, a LD 0 OA — o N C u c Li N d) 1- _C co -0 Q 0 w N tab O• s }' Q se I _ co . 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'�� k« 111111 1111 f >l 1-1 1 Q -C �_ R tt //1 b .. it I I 11 47 ± CN1 "y r:. a r .., j • 1 ..;.z \,._,__ x r 1 M • 40 `` �, rw {,1 ';� Jam,, t ,. ,�,'1 - .,, i c , /, '.,k \\ a (\ . • Z a) a) C_ —O C C6 L- -I--i Cro - > a) ni O co U O Q - 0 C6 C ' .N t/'1 C6 Co CD k . co — cu c " szu co (1.-5 C > 4 0, c/' 'to C co Q cn E.u. +-' 0 .O 1- �� cn U p O O •— v 0 c 0_ 00 -0 O c6 �O CD N 0 0 L " 0) — ca dQ' 0 d. a_ .J Q- - U O_ O cam/) ' V) 0- N Q .CO � W QN 1 i II ii Avg- 161 25511 WELL LOG TRANSMITTAL DATA LOGGED r2„5zo15 M K BENDER To: Alaska Oil and Gas Conservation Comm. March 4, 2015 Attn.: Makana Bender 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 RECEIVED MAR 2 4 2015 AOGCC RE: Multi-Finger Caliper: BRU 212-35T Run Date: 2/17/2015 The technical data listed below is being submitted herewith. Please address any problems or concerns to the attention of: Chris Gullett, Halliburton Wireline&Perforating, 6900 Arctic Blvd., Anchorage, AK 99518 BRU 212-35T Digital Log Image file, LAS file, Interpretation Report, 3D Viewers 1 CD Rom 50-283-20097-00 SCANNED :J. + 6 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Halliburton Wireline &Perforating Attn: Chris Gullett 6900 Arctic Blvd. Anchorage, Alaska 99518 Office: 907-273-3527 Fax: 907-273-3535 FRS_ANC@halliburton.com Date: Signe 16-eiceeet • +~~-~t~'t~~p TRANSMITTAL Be/uga River Unit deve%pment we//data FROM: Sandra D. Lemke, AT01808 TO: Christine Shartzer ConocoPhillips Alaska, Inc. State of Alaska P.O. Box 100360 AOGCC Anchorage AK 99510-0360 333 W. 7"' Ave, Suite 100 Anchorage, Alaska 99501-3539 RE: Beluga River Unit production logging DATE: 08/16/2010 Cook Inlet, Alaska BRU224-13 (permit 173-037-0) ~~ t ~ Proactive Diagnostic Services, Multi-finger caliper report and 3D data and viewer; 8/28/2007 ~~roactive Diagnostic Services, Production profile; 7/18/2008 BRU 211-03 (permit 186-010-0) apUt'~ ~ Proactive Diagnostic Services, Multi-finger caliper report and 3D data and viewer; 6!4/2008 ~roactive Diagnostic Services, Gas Entry Survey; 6/5/2008 BRU 212-35T (permit 198-161-0) ~~j(j (~. ' / Proactive Diagnostic Services, Production profile; 7/17 BRU 212-24 (permit 172-015-0) ~dU6t=P Proactive Diagnostic Services, Multi-finger caliper report and 3D data and viewer; 9122/2005 BRU 243-34 (permit 208-079-0) ~C~o chi- Proactive Diagnostic Services, Production profile; 9/2/2008 s ~ CIS /•a~:~nl~al L3ala Man en ~ g . e, Alaska ~ ~h,° ~l}7,~~.~ ~'.~~ Sandra.D.LsmkeCv~Conorn~hil/ips com ~~~~~~~ Schlumberger -DCS 2525 Gambell Street, Suite 400 Anchorage, AK 99503-2838 ATTN: Beth Weli Job # ~, ,~ ~;. -~ ~, a ~r~ ~t~ c~a'~ya,q, 5. ~~3r s ~6~41- Log Description NO. 5266 Company: Alaska Oil & Gas Cons Comm Attn: Christine Mahnken 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Fleld: Beluga River Unit Date BL Color CD BRU 212-35T 8000-00009 PRODUCTION LOG 05/14/09 1 1 Please sign and return one copy of this transmittal to Beth at the above address or fax to (907) 561-8317. Thank you. 06/04/09 r we i Compliance Report File on Left side of folder 198-161-0 BELUGA RI¥ UNIT 212-35T 50- 283-20097-00 PHILLIPS ALASKAINC Roll #1: Start: Stop Roll #2: Start Stop MD 04801 TVD 04678 Completion Date: 10/10/98 Completed Status: 2-GAS Current: Name Interval Sent Received T/C/D · L CMR/GR FINAL 2980-4700 OH 5 12/15/98 12/23/98 L CMR/GR-TVD FINAL 2980-4700 OH 12/15/98 12/23/98 L DSI-TVD FINAL 2690-4768 OH 12/15/98 12/23/98 L DSI/GR FINAL 2690-4768 OH 12/15/98 12/23/98 L GR/CDR-MD FINAL 121-2702 OH 12/15/98 12/23/98 L GR/CDR-TVD FINAL 121-4798 OH 12/15/98 12/23/98 L PEX-AZT-TVD FINAL 2690-4753 OH 12/15/98 12/23/98 L PEX-AZT/GR FlNAL 2690-4753 OH 12/15/98 12/23/98 L PEX-NDT-TVD FINAL 2690-4753 OH 12/15/98 12/23/98 L PEX-NDT/CALI?ER FINAL 2690-4753 OH 12/15/98 12/23/98 Daily Well Ops _ Was the well cored? yes no Comments: Are Dry Ditch Samples Required? yes no And Received? yes no Analysis Description Received? yes no Sample Set # Wednesday, November 08, 2000 Page 1 of 1 ARCO Alaska, Inc. Post Office Box~ i~0360 Anchorage Alaska 99510-0360 Telephone 907 276 1215 December 15, 1998 Mr. David W. Johnston Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501-3192 Subject: BRU 212-.35T Well Logs Enclosed are final prints of the open hole logs run on BRU 212-35T. A sepia paper copy of the following logs are included: MWD GR/CDR in md and tvd PEX Azimuthal resistivity in md and tvd PEX-Density/Neutron in md and tvd CMR in md and tvd Dipole Sonic in md and tvd If you have any questions or require additional information, please contact me at (907)265-6961. Sincerely, Brian Seitz BRU Operations Engineer Cc: Scott Reynolds ARCO Alaska, Inc. ARCO Alaska, Inc. is a Subsidiary of Atlantic Richfield Company AR3B-6003-C ARCO Alaska, In,~ / Post Officb~Box 100360 Anchorage, Alaska 99510-0360 December 10, 1998 1Vh'. David J. Johnson Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Subject: BRU 212-35T (Permit No 98-161) Well Completion Report Dear Mr. Commissioner Enclosed is the revised Form 10-407, and the As Built for the surface location for BRU 212-35T. If there are any questions, please call 263-4603 Sincerely, P. Mazzolini Drilling Team Leader AAI Drilling PM/skad ARCO Alaska, Inc. is a Subsidiary of AtlanticRichfieldCompany STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1 Status of Well Classification of Service Well OIL [] GAS [~ SUSPENDED E~] ABANDONED E~ SERVICE [~] 2 Name of Operator 7 Permit Number ARCO Alaska, Inc 98-161 3 Address 8 APl Number P.O. Box 100360, Anchorage, AK 99510-0360 50-283-20097 4 Location of well at sudace ~ ¢'r'~i"~;i '~.: :;~"',~[' :*'% 9 Unit or Lease Name ;~ i~ ~?~ ....... ~? 10 WellBeluga River UnitNumber 1485' FNL, 683' ~b, NW 1/4, Sec. 35, T13N, R10W, SM '~;-~: / ¢-~ At Top Producing Inte~al ~ .~~'7 J, ~~ ~[ 1898'FNL, 263'~L, NW1/4, Soo. 35, TlaN, R10W, SM~ ~ ' ~' !:~"- 'i BRU212-g5T At Total Depth ........... ~ 11 Field and Pool 2172' FNL, 165' ~L, NW 1/4, Sec. 35, T13N, R10W, SM · ,- BELUGA RIVER 5 Elevation in feet (indicate KB, DF, etc.) ~ 6 Lease Designation and Sedal No. NA RKB 21', Pad 70'J A-029657 12 Date Spudded 13 Date T.D. Reached 14 Date Comp., Susp. or ~and. 15 Water Depth, if offshore 16 No. of Completions 09-Sep-98 21-Sep-98 1~Oct-98 NA feet MSL 1 17 Total Depth (MD+~D) 18 Plug Back Depth (MD+~D) 19 Dir~tional Su~ey 20 Depth where SSSV set 21 ~ickn~s of permafr~t 4801' MD & 4678' TVD 4721' MD & 4214' ~D YES ~ NO ~ NA feet MD NA APPROX 22 Type Electric or Other Logs Run G~Res, CNURes/DensitF, CMR/Sonic, RFT, CBT 23 CASING, LINER AND CEMENTING RECORD SE~ING DEPTH MD CASING SIZE ~ GRADE TOP BTM HOLE SIZE CEMENT RECORD 20' 166~ X-56 SURF. 98' ~A DRIVEN 13-3/8" 68~ K-55 SURF. 2677' 17.5" LEAD: 1048 sx Class G, TAIL 677 sx Class G 9-5/8" 47~ L-80 SURF. 4800' 12-1/4" 1050 sx Class G 24 Pedorations open to Production (MD+~D of Top and BoSom and 25 TUBING RECORD inte~al, size ~d number) SIZE DEPTH SET (MD) PACKER S~ (MD) 7" HSD Deep Penofroting TCP, ]4 SPF 5-1/2" 3127.62' 3] 35' 3264'-3266' MD 3165'-3168' ~D 3450'-3492' MD 3348'-3389' ~D 3266'-3284' MD 3168'-3185' ~D 3523'-3528' MD 3419'-3424' ~D 26 ACID, FRACTURE, CEMENT SQUE~E, ~C 3290'-3302' MD 3191'-3203' TVD 3~7'-3556' MD 3~3'-3452' ~D DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED 3308'-3313' MD 3209'-3214' TVD 3598'-3603' MD 3493'-3498'~D 3264'-3~6' MD upper 4000¢ 20-40 sand 3324'-3~6' MD 3225'-3246'~D 3623'-3636' MD 3517'-3530' ~D 3388'-3556' MD middle 5800¢ 20-40 sand 3388'-3416' MD 3287'-3314' ~D 3692'-3712' MD 3585'-3605'~D 3598'-3712' MD lower 7700¢ 20-40 sand 27 PRODUCTION TEST! I k l Date First Production Method of Operation (Flowing, gas lift, etc.)U.~i~ll~mL 10/20/1998 f owing ~ate o~l~st Hours l~tod PBOB~GIIO~ FOB OIk-BBk GAS-MCF WAIEB-BBt GHOK[ SlZfi GAS-OI~ 10/20/1998 24 TEST PERIOD: 5M 0 25/65 Flow Tubing Casing Pressure CALCU~TED OIL-BBL GAS-MCF WATER-BB[ OIL GRAVIS-APl (corr) Pres 1000 ~ 0 24-HOUR RATE: 28 CORE DATA Brief description of lithology, porosity, fracture, apparent dips and presence of oil, gas or water. Submit core chips. N/A Form 10-407 Submit in duplicate I~ev. 7-1-80 CONTINUED ON REVERSE SIDE 29. 30. GEOLOGIC MARKERS FORMATION TESTS NAME Include interval tested, pressure data, all fluids recovered and gravity, MEAS DEPTH TRUE VERT. DEPTH GOR, and time of each phase. Top of Sterling A 3198' 3101' Top of Sterling B 3417' 3316' Top of Sterling C 3569' 3464' Top of Beluga D 3724' 3616' Top of Beluga E 3976' 3864' 9-5/8" x 5-1/2" annulus freeze protected with 2 bbls diesel Top of Beluga F 4384' 4226' See Attached RFT Data 31. LiST OF ATTACHMENTS Summary of Daily Drilling Reports, Directional Survey, Completion Detail 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed Title Drilling Team Leader DATE Prepared by Name/Number Scoff D. Reynolds/265-6253 INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1: Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-sku combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21: Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). Item 23: Attached supplemental records for this well should show the details of any multiple stage cement- ing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water In- jection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". Form10-407 Water Well AP~OX~JA'/~ EDGE 0~' G~AVEL PAD 1 ~ BRU-21,~-35-T~MN L~T et-1o-38,ot'N . GRAPHIC SCALE ~--..-~ ; T T T Beluga River Unit BRU 212-35 Drill Pad R.C. DAVIS & ASSOC. LAND, CONSTRUCTION AND MINERAL SURVEYORS ] ~OB NAME: IDRAWN 3Y:Mo [CHECKED BY: KD LOCATION: BELUGA RIVER UNIT ~ _~. ~ 20' IDATE: 2/7/98 [.CONTRACTOR: ARCO ALASKA IHC. I JOB NUMBER SHEE-r 7/9/98 REVISEB WELL LOCAllON IDESCRIPTION: m 98_06 I O: 2 Sheet1 BRU 212-35T MW 10.3 RFT KB= 92.5 Temperature Grad. 0.0065841:72.06918 IHydrostatic Depth TVD SSTVD Before ~ 2995 2904.49 2811.99 1605.1 3017 2925.53 2833.03 1616.7 3042 2949.67 2857,17 1631.1 ~ 13103,'!~:!3~8i57!i:~29.16 3146 3050.44 2957.94 3166 3069.93 2977.43 Formation . After Press tpsig) Temp. Mobilit~ Comments 1605 1199.5. 89.4 . 26.1 Goodset 1616.6 1208.8 89.5 1051.4 Real Good Set 1631.2 1219,3 89.8 429,7 GOod Set 1687.2 1687.2 1228.2 91.3 240.7 Good Set 1698.2 1698.1 1236.7 91.4 173.6 Fair Set 3228 3130.43 3037.93 1732 1731.8 91.7 Tite 3265 3166.61 3074.11 1751.9 1751.6 1142 92 69.6 Gas Zone 3200.83 3108.33 1770.2 1770.3 1145.6 92.7 225.9 Good set 3231.17 3138.67 1787.3 1787 1138 93.1 38.2 slow build ?set 3260.53 3168.03 1803.5 1803.2 1138.4 93.5 103.7 good set 3296.74 3204.24 1823.5 1823.3 1193.7 )3.7 624.6 ~ood set 34'2015.5 3328.05 1892.3 1892.2 1137.4 94.7 63.1 Fair Test 3446.67 3354.17 1907.7 1907.5 1190.6 94.9 23.9 Fair Test 3300 3331 3361 3398 3525 3552 3600 3493.77 3401.27 1933.8 1933.6 1165.8 95.1 188.9 Good Test 3627 3520.58 3428.08 1948.5 1948.7 1178.8 95.3 40.2 Fair Test 3696 3588.83 3496.33 1987 1986.5 1179.3 95.8 107.9 Good Test 3707 3599.65 3507.15 1992.4 1992.2 1178.8 95.9 205.3 Good Test 3752 3643.91 3551.41 2017.3 2017.1 1334.4 96.1 24.7 :Fair Test 3815 3705.66 3613.16 2052.5 2052.3 1368.9 95.9 7.3 Fair Test 4053 3939.44 3846.94 2184.2 2184 1369.2 96.8 20.1 good test 4189 4073.50 3981.00 2260 2259.5 1363.8 97.3 55.3 good test 4380 4261.88 4169.38 2365.6 2365.2 1541.5 98.5 21.6 Fair Test 4417 4298.44 4205.94 2386.1 2386.1 1250.7 99.5 35.9 Fair Test 4464 4344.87 4252.37 2412.2 2411.9 1599 100 23.3 Fair Test 4554 4433.79 4341.29 2462.2 2461.9 1385.9 101 22.5 Fair Test Page 1 ARCO Alaska, Inc. Structure : BRU Pad 212-,35 Well : 212-35Tn Field : Beluga River Unit Location : Cook Inlet, Alaska 250 5OO 750 1000 1250 1500 it,,, ,,, ~ 1750 Q~ 2000 ('h 2250 0 2500 13 .3/8 2750 I--Vi 32503°°° _ ~Well#1 T/ Sterling Rvsd 11-Feb-98 3500 ~, Well#1 T/ Beluga l 1-Feb-98 3750 4000 4250 4500 ,~ Well#1 TD l 1-Feb-98 4750 50aa I i I ii I i I iO 0 250 500 750 1000 Vertical Section (feet) -> Azlmuth 225.49 with reference 0.00 N, 0.00 E from slot #212-35Twin 560 480 400 I I I I I I <- West (feet) 320 240 160 80 I I I I I I I I I 0 80 I 8O 160 Well#1 T/ Sterling Rvsd l 1-Feb-98 Well#1 T/ Beluga 11-Feb-98 24O 320 4OO 480 56O Well#1 TD l 1-Feb-g8 640 720 Creoted hy linch Date plotted : 26-0ct--98 Plot Reference is 212-55 Twin Ver~.jlS. Coord[nat~; ore ;n [eel reference ~crt INT~Q SURVEY CALCULATION AND FIELD WORKSHEET Job No. 0451-00397 Sidetrack No.Page1 of 3 Company ARCO ALASKA, INC. Rig Contractor & No. AFC #594107 - SAD Field BELUGA RIVER Well Name & No. BELUGA RIVER UNIT/BRU 212-35T Survey Section Name Definitive Survey BHI Rep. T DUNN WELL DATA , . _ Target TVD (FI') Target Coord. N/S Slot Coord. N/S 1485.00 Grid Correction 0.000 Depths Measured From: RKB Target Description Target Coord. E/W Slot Coord. E/W -686.00 Magn. Declination 21.960 Calculation Method MINIMUM CURVATURE Target Direction (DD) Build\Walk\DL per: 10Oft~ 30m0 10mo Vert. Sec. Azim. 225.49 Magn. to Map Corr. 21.960 Map North to: OTHER L llmll IJ III ! I ! I ~ ! I III · SURVEY DATA Survey Survey Incl, Hole Course Vertical Total Coordinate Build Rate Walk Rate Date Tool Depth Angle Direction Length TVD Section I~(+) / S(-) Ei'~) / W(-'i' DL Build (+) Right (+) Comment Type (F'r) (DD) ,. . (DD) (F'D (FT) (FT) .... (FT) (Per lO0 FT) D.ro.p, (-) Left (-) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 TIE IN POINT .~: 09-SEP-98 MWD 111,00 0.24 125.70 111,00 111.00 -0,04 -0.14 0.19 0.22 0.22 10'SE P-98 MWD 196.00 0.40 121.30 85,00 196.00 -0.14 -0.39 0.59 0,19 0.19 ......... 10-SEP-98 MWD 294,00 0.57 134.60 98,00 293.99 -0,23 -0,91 1.23 0.21 0,17 ...... 10-SEP-98 MWD 412,00 0,71 135.70 118,00 411.99 -0.24 -1.85 2.15 0,12 0,12 .... 10-SEP-98 MWD 504,00 0.86 136,40 92,00 503.98 -0,23 -2.76 3.03 0,16 0.16 ............ 10-S EP-98 MWD 562,00 0.99 141,10 58.00 561,97 -0,17 -3,46 3,64 0,26 0.22 ...... , .......... 10-S EP-98 MWD 643,00 0,93 140.00 81.00 642,96 -0,05 -4.51 4.51 0.08 -0.07 10-SEP-98 MWD 743,00 1,08 148.80 100,00 742,94 0.23 -5,94 5.52 0,21 0,15 10-SEP-98 MWD 861.00 0,68 152.00 118,00 860.93 0.68 -7,51 6,42 0.34 -0.34 10-SEP-98 MWD 953,00 0.80 i'" 217.80 92,00 952.92 1.48 -8,50 6,28 0.88 0.13 ,,~ 10-SEP-98 MWD 1045.00 1.38 244,20 92,00 1044,91 3.16 -9,49 4.89 0,82 0.63 ............ , 10-SEP-98 MWD .............. 1106.00 2.68 260.90 61.00 1105.87 5.02 -10.03 2.82 2.32 2.13 10-S EP-98 MWD 1201.00 3.57 252.20 95.00 1200.73 9.47 -11.29 -2.19 1.06 0.94 11 -SEP-98 MWD 1327.00 6.92 240.60 126.00 1326.18 20.31 -16.21 -12.54 2.78 2.66 -9.21 .................... , 11 -SEP-98 MWD 1419.00 9.07 244.60 92.00 1417.29 32.51 -22.05 -23.92 2.41 2.34 4.35 11 -S EP-98 MWD 1513.00 11.30 250.00 94.00 1509.80 47.90 -28.38 -39.27 2.58 2.37 5.74 ....... 11-SEP-98 MWD 1607.00 14.51 256.80 94.00 1601.42 66.34 -34.22 -59.39 3.77 3.41 7.23 12-S EP-98 MWD 1701.00 16.36 261.50 94.00 1692.03 87.11 -38.86 -83.95 2.37 1.97 5.00 12-SEP-98 MWD 1797.00 18.26 259.70 96.00 1783.68 110.49 -43.55 -112.13 2.06 1.98 -1.88 12-S E P-98 MWD 1892.00 20.63 247.70 95.00 1873.29 138.31 -52.57 -142.27 4.88 2.49 -12.63 . 12-SEP-98 MWD 1985.00 22.07 234.50 93.00 1959.95 170.75 -68.94 -171.67 5.38 1.55 -14.19 12-SE P-98 MWD 2079.00 21.22 223.00 94.00 2047.37 205.21 -91.65 -197.66 4.60 -0.90 -12.23 12-SEP-98 MWD 2173.00 21.22 218.60 94.00 2135.00 239.09 -117.39 -219.88 1,69 0,00 -4.68 I IIIIIIIIIII I II~alllll I II I IIIII II II IIIIII I I I II SURVEY CALCULATION AND FIELD WORKSHEET Job No. '0451-00397 Sidetrack No. Page 2 of 3 ~=J.l~[~ =-] ::~--~ Company ARCO ALASKA. INC. Rig Contractor & No. AFC #594107 - SAD Field BELUGA RIVER ...... ilr Well Name & No. BELUGA RIVER UNIT/BRU 212-35T Survey Section Name Definitive Survey BHI Rep. T DUNN ...... I II III I I I I II I I I I I I · I I I I II WELL DATA Target TVD (F-r) Target Coord. N/S Slot Coord. N/S 1485.00 Grid Correction 0.000 Depths Measured From: RKB l~ MSL~ SS~j Target Description Target Coord. E/W Slot Coord. ENV .686.00 Magn. Declination 21.960 Calculation Method M_IN!M.U.M. CURVATURE Target Direction (DD) Build\Walk\DL per: 100ft[~ 30m0 10m[~ Vert. Sec. Azim. 225.49 Magn. to Map Corr. 21.960 Map North to: OTHER .. ......· ., .c=URVE'~ DATA ' = ' Survey Survey Incl. Hole Course Vertical Total Coordinate Build Rate Walk Rate Date Tool Depth Angle Direction Length TVD Section N(+) / s(-) E(+) / W(-) DL Build (+) Right (+) Comment 'ype (F-r). (DD) (DD) (F-T~ (FT) (F'T) .... (F'T). (Per ~00 F-r) Drop (-) Left (-) 12-SE P-98 MWD 2265.00 21.27 214.80 92.00 2220.75 272.02 -144.10 -239.79 1.50 0.05 -4.13 12-S EP-98 MWD 2328.00 21.46 212.00 63.00 2279.42 294.46 -163.26 -252.42 1.65 0.30 -4.44 ...... 12'S EP-98 MWD 2390.00 21.53 211.90 62.00 2337.11 316.54 -182.54 -264.44 0.13 0.11 -0.16 12-SEP-98 MWD 2483.00 21.10 210.90 93.00 2423.75 349.33 -211.39 -282.06 0.61 -0.46 -1.08 12-S EP-98 MWD 2576.00 21.01 210.90 93.00 2510.54 381.67 -240.06 -299.21 0.10 -0.10 0.00 ..... 12-SEP-98 MWD 2636.00 20.88 210.50 60.00 2566.57 402.40 -258.50 -310.16 0.32 -0.22 -0.67 ...... 20-S EP-98 VIWD 2732.00 21.27 209.80 96.00 2656.15 435.69 -288.35 -327.50 0.48 0.41 -0.73 ,, , 20-S EP-98 MWD 2825.00 19.84 211.20 93.00 2743.23 467.23 -316.49 -344.06 1.63 -1.54 1.51 ~0-SEP-98 MWD 2904.00 18.51 212.70 79.00 2817.85 492.45 -338.51 -357.78 1.80 -1.68 1.90 20-SEP-98 MWD 3011.00 16.43 211.00 107.00 2919.91 523.67 -365.78 -374.75 2.00 -1.94 -1.59 20-S EP-98 MWD 3104.00 13.83 210.90 93.00 3009.67 547.16 -386.59 -387.24 2.80 -2.80 -0.11 ,, ......... 20-SEP-98 MWD 3197.00 12.28 210.40 93.00 3100.27 567.47 -404.66 -397.95 1.67 -1.67 -0.54 ;~0-S EP-98 MWD 3291.00 11.97 210.70 94.00 3192.17 586.55 -421.66 -407.99 0.34 -0.33 0.32 ........................ 20-SEP-98 MWD 3385.00 11.77 211.70 94.00 3284.16 605.28 -438.20 -418.00 0.31 -0.21 1.06 20-SEP-98 MWD 3480.00 11.69 213.10 95.00 3377.18 624.09 -454.51 -428.35 0.31 -0.~08 1.47 ........ 20-SEP-98 MWD 3572.00 11.45 212.80 92.00 3467.31 642.10 -469.99 -438.38 0.27 -0.26 -0.33 ....... 20-SEP-98 MWD 3668.00 11.20 213.60 96.00 3561.44 660.52 -485.77 -448.70 0.31 -0.26 0.83 20-S EP-98 MWD 3762.00 10.94 213.50 94.00 3653.69 678.18 -500.81 -458.68 0.28 -0.28 -0.11 21 -sE~-98 MWD 3849.00 10.86 213.00 87.00 3739.12 694.26 -514.57 -467.70 0.14 -0.09 -0.57 21 -SEP-98 MWD 3951.00 10.58 213.80 102.00 3839.34 712.81 -530.41 -478.14 0.31 -0.27 0.78 21 -SEP-98 MWD 4039.00 10.14 213.50 88.00 3925.90 728.30 -543.58 -486.91 0.50 -0.50 -0.34 21-SEP-98 MWD 4137.00 9.94 214.40 98.00 4022.40 745.04 -557.75 -496.45 0.26 -0.20 0.92 21-SEP-98 MWD ' 4231.00 9.62 213.80 94.00 4115.04 760.69 -570.97 -505.40 0.36 -0.34 -0.64 21 -SEP-98 MWD 4328.00 9.26 215.10 97.00 4210.72 776.30 -584.09 -514.40 0.~,a -0.37 1.34 · i ill--, iiiii i i i i iii ii1~ r SURVEY CALCULATION AND FIELD WORKSHEET Job No. 0451-00397 Sidetrack No.Page3 of 3 I IIII · Iffi; [114, I ::(--11 Company ARCO ALASKA, lNG. Rig Contractor & No. AFC #594107 - SAD Field BELUGA RIVER - Well Name & No. BELUGA RIVER UNIT/BRU 212-35T Survey Section Name Definitive Survey BHI Rep. T DUNN .,.,., ~ i ~ ~1 i i i ! ~'~~ ............. WELl_ Target WD (~ Target Coord. N/S Slot Coord. N/S 1485.00 Grid Correction 0.0~ Depths Measured From' RKB ~ MSL~ SS~ Target Description Target Coord. E~ Slot Coord. E~ -686.00 Magn. Declination 21.960 Calculation Method MINIMUM CURVATURE Target Direction (DP) Build~Walk~DL per: 1~ 30m~ 10m~ Ve~. Sec. Azim. 225.49 Magn. to Map Corr. 21.960 Map No~h to: OTHER SURVEY DATA ,,. Suwey Suwey i Incl. Hole i Total Coordinate Build Rate Walk Rate Date Tool Course Ve~ical Build (+) Right (+) Comment Depth Angle Direction Length ~D Section N(+) / S(-) E(+) / W(-) DL Type (~ (DP) (DD) (~ (~ (~ (~ (Per ~00 ~ Drop (-) Left (-) 21 -S EP-98 MWD 4422.00 9.00 216.20 94.00 4303.53 791.00 -596.21 -523.09 0.33 -0.28 1.1 7 .. 21 -SEP-98 MWD 4516.00 8.85 216.90 94.00 4396.39 805.40 -607.93 -531.78 0.20 -0.16 0.74 21 -SEP-98 MWD 4610.00 8.70 216.50 94,00 4489.29 819.58 -619.43 -540.35 0.17 -0.16 -0.43 ,~ ,. , 21 -S EP-98 MWD 4703.00 8.53 216.60 93.00 4581.24 833.34 -630.62 -548,64 0.18 -0.18 0.11 ,.. 21 -SEP-98 MWD 4722.00 8.62 216.80 19.00 4600,03 836.14 -632.89 -550.34 0,50 0.47 1.05 .... , 21-SEP-98 MWD 4801.00 8.60 216.90 79.00 4678.14 847.83 -642.35 -557.43 0.03 -0.03 0.13 Projected Data - NO SURVEY ......... ........................... ........... ................... ..... . /, ~ ..... ,,, , ,, ~,, ........ ....... ,, , ................................................................................................. .... ...................................... ........... ...... ............... iii iii iii . ii ii i iiii ARCO Alaska, Inc. Subsidiary of Atlantic Richfield Company # ITEMS Casing Detail 5 7/2"COM. PLET!ON COMPLETE DESCRIPTION OF EQUIP~ENT RUN SADI #1 RKB to GL = 21.0' SADI # I RKB TO/TOP OF TBG HANGER 10" x 5-1/2" DCB Hanger w/5-1/2" API LTC csg top x btm 5-1/2" 15.5#, L-80 LTC Pup (attached to hanger) pups 5-1/2" its 26-71 5-1/2" 5-1/2" [ jts 9-25 i its 2:-8 jt 1 5-1/2" 15.5#, L-80 LTC Pups (10',8.68',2.68') 15.5#,L-80 LTC csg 15.5#, L-80 LTC Pup 5-1/2" 5-1/2" 5-1/2" 5-1/2" 5-1/2" x 1-1/2", 15.5# Telidyne-Mefla GL.M #2 15.5#, L-80 LTC Pup 15.5#,L-80 LTC csg 15.5#, L-80 LTC Pup x 1-1/2", 15.5# Telidyne-Mefla GLM #1 15.5#, L-80 LTC Pup 5-1/2" 15.5#,L-80 LTC csg Baker CMU sliding sleeve w/5-1/2" LTC Box & Pin w/4.562" Otis X profile 5-1/2" 15.5#, L-80,LTC CSG 5-1/2" 15.5#, L-80 LTC PUP w/Baker Model %-22" Locator Tubing Sea1 Assembly w/5-1/2", 15.5# Box, bonded seal units, half mule shoe, 8' seal stroke. (9.02' seal pup) Top of Baker Model SC-1 Gravel Pack Packer WELL: BRU 212-35T DATE: 10/9/98 I OF I PAGES LENGTH 22.7O .85 2.30 21.36 1954.26 ,, 10.04 9.20 10.04 725.25 10.05 9.05 10.01 295.43 5.01 43.39 6.40 DEPTH TOPS 22.70 23.55 25.85 47.21 2001.47 2011.51 2020.71 2030.75 2756.00 2766.05 2775.10 2785.11 3080.54 3085.55 3128.94 3135.34 Remarks: String Weights with Blocks: 62K¢ Up,60K¢ Dn,201¢ Blocks. Ran 71 joints of casing. Drifted casing. Used Arctic Grade AP! Modified No Lead thread compound on all connections. Casing is non-coated. STERLING #1 Drilling Supervisor:R. [4/. SPRINGER 27 26 25- 24 23 19 ~ A~ 'o 263 ~3'3 ~ 1100 ~aO de ...... ' ..... __~__. ' .... , ~ deg. I ~ '~ ..... ~j BELUGA RIVER 212-35T ~~-- 5-1/~' 140 3~ --- /&w~ BELUGA ~IVE~ I 20/40 J 5% KCL ~;IKKISKi Sterling Alaska #1 BRIAN L. DUW/E BEPTH LENGTH 3,807.25 0.39 30.78 3,776~ 3,773.00 3.10, 3,773.00 1.18 3,771 3,771.82 3,771.82 120.80 3,651.02 3,651.02 3,651.02 13.78 3,637.24: 30_20 3,607.04 20.22 #1 3,607. O4 3,436.71 9.78! 30.20! 3,436.71 3,426.93 ~;428~93' 3,396.73 20.22 3;396.73 3,396 73, 3,370.51, 3.08 3,373._43i 18.07 3,355.36 3,355.36 3.11 3,352.25 3,~2,.25t 3,349.81 } 2.33i 3.347 28 3,347.28 263-3921 561 - I OD ID 6.050 7.625 8.438 7.000 6.110 6.050i .'4.767 e ~ i Ol ~ 5 J 3,250.68 ---~ 3,256.68 4 24J 3,256.68 ~ 3,166.28i 2 1 ...~---~. :: .~_ .~ ?: :. ,;=;; , . ~-. ~ 767 6.750 6.000 4.750 4.950 SEE BELOW ii CAS,Ne t J 47.00 LINER I . 7-5/8" Wire tine Re-Entry CZ~uide Mill-Out Ex-'tensian w/7-518" LT&O Pin _x Pin. E~aker Model FB-1 Retainer Productio~ Packer Size I g2-60, f/9-518" 40-58.4~ Csg, w/7-5!B¢ LT&C Box Dwn. ~ Baker Model S-22B Snap Latch S¢-~¢ Ashy. Size !wi2 Molding Seal Unit~, w/~l~: Flush ~ x 20' F'r~¢uc~ion Tube, w/5-1/2"' LT&C Box x Ratcheting Muleshoe. Bakerweid Screen, 140, 316L, Size .5-1/2" x _0!2" Ga. L-80, Base Pipe, w/5-1/2" LT&C Box x Pin: w/'CVetd~On Bta0e Type Guides, ¢/9-5/8" 47# Csl~. Pup Jr. w/5-1/2" 17# LT&C Box x Pin. Bakerweid Screen, 140, 316L, Size 5-1/2" x .012" Ga. L-80, B~se Pipe, w/5-i/2" LT&C Box x Pin, 81-~d,e Type ,~.~uide-~, ff9-$/8' 47¢~ csg. size 5-1/'2" ~×clurJer. L-80, w/{5-1/2" LT&C Bo× × Pin [.~/Indicaling. Chamfer On Both Ends, w/8-5/8" LT&C Ix 5-t/2" 17# LT&C Pin. 8.0O0[8aker Model SC-1L Is~ation P~ker, Size ~A4-60, f/ [9-5/8" 47¢ Csg w/6-5/8" LT&C Box, w/B.50 LHST Box Lip Bakerweld Screen, 140, 316L Size 5-112" x .012" ~. L-80, 6.1 10~ 4.~50 I B~s~.__~e P_ipe, w/5-112" LT&C Bo)< x Pin, w/VVeld-On Cent. 8.62:5_~ 4.750 ~Baker S~t Bore R~ep~e, Size 4.750" x 5-I~' x w/$ It~di~tion Chamfer on Both Ends. w15-I~:' LT&C Pin x 6-518" LT&O Box. ~.~0 6.000 Baker Model SC-1L isolation Packer, 8i~e 96A~0, 9-~8" 47¢ Csg., ~5/8" LT&C ~x Dh. w/8. ~8 L_~ST Box 6.~,25 4.750 ~k~r Sea~ ~re R~ep~le, S~e 4.750" x 5-3~' ~- 6-5/8" ~w/5-1/2" LT&C Bo~ Up, x ~1/2" LHST Pin 6.110 4.950 ~ke~etd ~reen, 140, 316L, S~e 5-1~".~ .012" C~. ~as~Pipe, w/5-1t2" LT&C ~x x Pin, ~B!ade Type Gu(d~ f/~/8" 47¢ Cs~: . . __ 6.050 4.767 Blank Pipe w15-1~' 17~ LT&C Box x ~n ~. 110 4.950i Bake~eld ~reen, ~40, 316L, S~e 5-1/2" A .0~2" Ga. L~0, ~. Base Pipe, w/~1/2" LT&C Box x Pin, w~e~n Blade Type Guides f/9-5/8" 47¢ 5.11dj 4.950 8be 5-1t2" Bcluder. L-80, Note: 2-18.5' ¢.390[ 4.750 Baker Seal Bore R~ep~le, Size 4.750" x ~5/8" ~ 0~ w/Inditing. Chamfer On Both E~s, w/O~5/8" LT&C 7. . 4.750 Baker M~el "S" Mini-B~a Gavel P~k Size 1g0~7 w/Sliding Sleeve, w/6-5!8"' LT&C Pin X Pin. 7.390: 4.750~'~a~ Seal Bore R~ept~le, Size 4,75~' x 6-5/8" x 5-I~" 4.950 90:-41 6_o5ol] [ Base Pice, w/5-1/2" 17# LT&O Box × Pin, Blade Type ~uides ft9-5/8" 47# Csg. 4.950 Blank Pipe, Sjz. e. 5-1/2", L-80, w15-1/2" LT&C Box x pin, wfVVeld-On Blacte Type (~uides f/9-518" 47# Csg. 21 BELUGA RIVER 212-35T ALASKA BELUGA RIVER l.- 2.0140 [ 5% KCL Jo~ ~,~ ~x~ ~ T~-~ ....... ~erling AtasEa ~1 283-3921 CASING ! ~ 47.00 S-95 BRI~ L. DUWE 561-1939 LINER } } 2~8ep-98 ..... [ ~1/2 17_00 , L-80 BU~RESS ~1 Gas VVRKSTR. } ~1/2 13.30 ~I ;No.~ D~PTH '} L~NGTH O0 I I ['I'Ib ' r DESCRIPTION 2S~ - 3,~.2~j: 3.~0' - . 7~90~-- '4.75° ~akerS~lB;reR~Pmcle' SIz;4.~50"X 6~/¢'x5-I~' m---~, 1~3; i~J ....... [ .... w/i~di~ting' Cham~r 10~'B~h' En~s, ..... 3~i'63.~8~ ...... ~" X 5-1/2" LT&C Pin DWn. ' ' 2~i. . ~.~s3.,e '" ~.07 7.000 4.750~B~ M~.~ "S" ~n~-e~ ~ ~k , 1 3,145.11 .... [Size ~9~7, w/Stiding~i~ve,.w/8~/8" LT&C Pin X Pin. 27.~ 3,145.1i ~. 73 7.390 4_7~ ~ker ~1 Bore R~e~le, S~e 4.75~' x 7-5/8'~ _ -~ 3,141.'3'8 ' . , ~ - ' .... '~/tnd~in~ C~m~er ~n ~th Ends, w/6~/8~LT&C ~x 3,141.38 ~x 7~/8" LT&C Box, 28 3,141.~ 5.51 ..... 7.~5 ' G'.~75 [~ke~ millet e~ens~n, S~e 1~0, L-80 _..~ '3,135.87 t ........ 2~7~ LY~ ~'in ~ Pin 29 S, 135.87 4.53 - 8.~6 '~.'000 ;BaKer Ne~ U<e} S~L1 dmvei Pack P~ker, Size ....... 30 3, aa;.a4 i.~ ' ~ .... ' ...... . ...... 6.~2 4.875 GBH-~ I~o~ '8~i Assy.' 8b~' 19M0, -_ . 3,1~0.34 .. ' ..... Bu~. B°X x Bond~,S~l un~s x HaE ~ule s~e~ ..... t8' of ~al Stroke .... :. ...... - .... I '- ........ -:- - -' ~ --=' ~ ' ...... , ........ ........ Item ~3 F~I Packer s~ ~ 3T73' ' " = ..... Item ~12-8eat ~re above S~IL set at ~59.84' ......... " .... Item ~1 s~i Bore above SC-!L set at 3349.~1' ... ,, ~ ......... ............... ~ ~;p~hs ~ o~ n ~he~e it~ need a Tolerance + or . _. ~: . .... ; · = . ~ .... _ .... ........... - ~ ~e~or~i0~S: ........ ....... L~eE 359~03[ ~23-3~8, ~g2~712 .... ~die'~. ~3a8-~6, 345~.3492, 3523~3~2~.~547-~558 ..... Upper: 32~2~, 3290-3302, 3309-3313, 3324-3~6 , , ~.. ~- ~- : . . ~ .. ~ ,, = ......~ j- -., j - ~ ; ~ _ :. ......... '~"i/] .... ;- t ;. - ....... , ......... .._,. _'--, '.' '.;~.. ',;. ' I ....... . ....... . . ............. :_] ..... , ~ ..... ~ ,,, ~ ....... ~ ......... 28 27 2~ lo , STUCTURAL/CONDUCTOR INSTALLATION REPORT FORM ARCO Alaska, Inc. Beluga River Field Date Installed: 22 August 1998 Well Name & No. BRU212-35T Surface Location: 1,485' FNL, 683' FWL Sec. 35T13N R10W SM Casing Size: 20" Weight: 166.4 Lbs./ft Grade: X56 Number of Joints: 4 +_20' joints (bottom joint 19' long, top 3 joints 20' long) Contractor: Kraxberger Drilling, Soldotna, AK (907) 2624720 Type of Connection: Welded joints Method of Installation: Drill pipe with 15-3/4" bit was inserted into 20" conductor, hole was drilled out 34 feet below drive shoe of conductor, then pipe was driven down with hammer. Blow Count @ Refusal or end of Job: 960 BPF Depth Conductor Set below Grade Line: 76' Comments: Fine sand and gravel to depth, clay layer at refusal. Final blow count was 80 blows per inch (960 BPF). Diagram: Attached Prepared By: Ben Landry 28 August 1998 Figure Drive Pipe Procedu re Rig Floor (KB) 4.3' Grade Line Weld-On Diverter Flange Center Line 36" to 48' 21' ~Figure 1. Drive Sho( ~ 20" .0° 1.00' Drive shoe made by welding quarter sections to the exterior and end of the 20" casing CUt quarter seCtions from a 1.00' long piece of casing that has been cut from the bottom of a "casi int. 1.00' 20" Date: 10/16/98 ARCO ALASKA INC. WELL SUPKW_ARY REPORT Page: 1 ~ELL:BRU 212-35T RIG:STERLING 1 WELL_ID: 594107 TYPE: AFC: 594107 AFC EST/UL:$ 2300M/ 2500M STATE:ALASKA AREA/CNTY: BELUGA RIVER SOUTHERN ALASKA FIELD: BELUGA RIVER UNIT BLOCK: SPUD:09/09/98 START COMP: FINAL: WI: 0% SECURITY:0 API NUMBER: 50-283-20097-00 09/08/98 (D1) MW: 9.5 VISC: 69 PV/YP: 20/27 APIWL: 13.3 TD: 77' ( 77) RIGGING UP SUPV:R. SPRINGER/S. REYNOLDS Function test diverter. Continue to RU. DAILY:$ 189,463 CUM:$ 189,464 ETD:$ 0 EFC:$ 2,489,464 09/09/98 (D2) MW: 9.6 VISC: 63 PV/YP: 15/23 APIWL: 12.6 TD: 218'(141) SUPV:R. SPRINGER/S. REYNOLDS Accept rig @ 1500 hrs. 9/9/98. Drilling 12.25" hole from 90' to 218' DAILY:$ 25,749 CUN:~ 215,213 ETD:$ 0 EFC:$ 2,515,213 09/10/98 (D3) MW: 9.5 VISC: 66 PV/YP: 18/32 APIWL: 11.5 TD: 1202'( 984) DIRECTIONAL DRILLING @ 1300' SUPV:R. SPRINGER/S. REYNOLDS Drilled from 218 to 1202' Unable to build angle. CBU. POH to change motor. DAILY:$ 31,270 CUM:$ 246,483 ETD:$ 0 EFC:$ 2,546,483 09/11/98 (D4) MW: 9.5 VISC: 62 PV/YP: 19/29 APIWL: 11.5 TD: 1672'(470) DIRECTIONAL DRLG @1954' SUPV:R. SPRINGER/S. REYNOLDS Slide from 1202' to 1420'. MWD tool failure. Wash and ream from 1286' to 1420' Slide from 1420' to 1672' DAILY:$ 39,788 CUM:$ 286,271 ETD:$ 0 EFC:$ 2,586,271 09/12/98 (D5) MW: 9.5 VISC: 60 PV/YP: 19/23 APIWL: 12.4 TD: 2700'(1028) POH, LAYING DOWN BHA SUPV:R. SPRINGER/S. REYNOLDS Slide and rotary drill from 1672' to 2700' DAILY:$ 27,847 CUM:$ 314,118 ETD:$ 0 EFC:$ 2,614,118 09/13/98 (D6) MW: 9.6 VISC: 89 PV/YP: 27/60 APIWL: 11.4 TD: 2700'( 0) OPEN HOLE T/17.5" SUPV:R. SPRINGER/S. REYNOLDS RIH with hole opener. Open hole to 1436' Very little cuttings back, hole appears to be washed out. Open hole t/1519' DAILY:$ 264,494 CUM:$ 578,611 ETD:$ 0 EFC:$ 2,878,611 09/14/98 (D7) MW: 9.7 VISC: 106 PV/YP: 31/44 APIWL: 10.4 TD: 2700' ( 0) OPEN HOLE SUPV:R. SPRINGER/S. REYNOLDS Open hole from 1519' to 2675', possible bit balling from claystone formation. DAILY:$ 28,100 CUM:$ 606,711 ETD:$ 0 EFC:$ 2,906,711 Date: 10/16/98 ARCO ALASKA INC. WELL SUMMARY REPORT Page: 2 99/15/98 (D8) MW: 9.7 VISC: 133 PV/YP: 29/72 APIWL: 10.0 '~D: 2700' ( 0) CONDITION MUD FOR CEMENTING SUPV:R. SPRINGER/S. REYNOLDS Circ and work to btm from 2659 to 2669' Open hole from 2669' to 2683' Run 13-3/8" casing. DAILY:$ 35,510 CUM:$ 642,221 ETD:$ 0 EFC:$ 2,942,221 09/16/98 (D9) MW: 9.6 VISC: 53 PV/YP: 27/15 APIWL: 8.6 TD: 2700'( 0) WELDING ON 13 3/8" WELL HEAD SUPV:DOUG NIENHAUS/S. REYNOLDS Pump cement. DAILY:$ 120,282 CUM:$ 762,503 ETD:$ 0 EFC:$ 3,062,503 09/17/98 (D10) MW: 8.3 VISC: 28 PV/YP: 0/ 0 APIWL: 0.0 TD: 2700' ( 0) FINISH NIPPLE UP BOPS AND FUNCTION TEST. MIXING 5 % KCL MUD. SUPV:DOUG NIENHAUS/S. REYNOLDS NU BOPs. DAILY:$ 79,822 CUM:$ 842,325 ETD:$ 0 EFC:$ 3,142,325 09/18/98 (Dll) MW: 9.7 VISC: 51 PV/YP: 22/22 APIWL: 5.2 TD: 2700' ( 0) DRILLING CMT TO SHOE SUPV:DOUG NIENHAUS/S. REYNOLDS Test BOPs to 250/3000 psi. RIH with BHA #4. DAILY:$ 270,075 CUM:$ 1,112,400 ETD:$ 0 EFC:$ 3,412,400 09/19/98 (D12) MW: 9.6 VISC: 46 PV/YP: 18/15 APIWL: 5.8 TD: 2745' ( 45) DRILLING WITH ROTARY SUPV:DOUG NIENHAUS/S. REYNOLDS Clean out cement from 2544' to 2598' float collar, drill cement and shoe to 2677' Drill new 12.25" hole from 2700' to 2720' Perform LOT. Rotary drill from 2720' to 2745' DAILY:$ 61,325 CUM:$ 1,173,725 ETD:$ 0 EFC:$ 3,473,725 09/20/98 (D13) MW: 9.9 VISC: 46 PV/YP: 19/ 0 APIWL: 3.4 TD: 3915' (1170) ROTARY DRILLING AT 4175' SUPV:DOUG NIENHAUS/S. REYNOLDS Rotary drill from 2745' to 3915' DAILY:$ 55,766 CUM:$ 1,229,491 ETD:$ 0 EFC:$ 3,529,491 09/21/98 (D14) MW: 10.1 VISC: 50 PV/YP: 26/22 APIWL: 3.8 TD: 4801' ( 886) CIRCULATE AND CONDITION SUPV:DOUG NIENHAUS/S. REYNOLDS Drilling w/rotary from 3915' to 4801' DAILY:$ 56,993 CUM:$ 1,286,484 ETD:$ 0 EFC:$ 3,586,484 09/22/98 (D15) MW: 10.3 VISC: 49 PV/YP: 21/17 APIWL: 3.8 TD: 4801' ( 0) RUNNING CMI W/ SCHLUMBERGER RUN # 2 SUPV:DOUG NIENHAUS/S. REYNOLDS Circulate and pump 100 vis sweep. Had a lot of cuttings and thick mud to surface. Well flowing. Shut in well. Pump dry job. Run in hole with open hole logging tools. DAILY:$ 60,609 CUM:$ 1,347,093 ETD:$ 0 EFC:$ 3,647,093 09/23/98 (D16) MW: 10.3 VISC: 48 PV/YP: 22/17 APIWL: 3.8 TD: 4801'( 0) RIH FOR WIPER TRIP SUPV:DOUG NIENHAUS/S. REYNOLDS Open hole logging. Run RFT log. Held safety time out meeting. DAILY:$ 19,602 CUM:$ 1,366,695 ETD:$ 0 EFC:$ 3,666,695 Date: 10/16/98 ARCO ALASKA INC. WELL SUMPLARY REPORT Page: 3 99/24/98 (D17) MW: 9.9 VISC: 45 PV/YP: 20/15 APIWL: 'PD: 4801'( 0) RUN 9 5/8" CASING SUPV:DOUG NIENHAUS/S. REYNOLDS Run in hole. Hole losing fluid not getting back displacement on some stands. Had tight spots to work through. DAILY:$ 225,921 CUM:$ 1,592,617 ETD:$ 0 EFC:$ 3,892,617 4.0 09/25/98 (D18) MW: 9.9 VISC: 45 PV/YP: 21/13 APIWL: 4.0 TD: 4801' ( 0) MAKE ROUGH CUT ON 9 5/8" CASING SUPV:DOUG NIENHAUS/S. REYNOLDS Run 9-5/8" casing. Pump cement. DAILY:$ 101,710 CUM:$ 1,694,327 ETD:$ 0 EFC:$ 3,994,327 09/26/98 (D19) MW: 9.9 VISC: 45 PV/YP: 21/13 APIWL: 4.0 TD: 4801'( 0) SUPV:OUG NIENHAUS/S. REYNOLDS Displace cement with 9.9 ppg drilling mud. ND BOPs. NU BOPs and test to 250/3000 psi. DAILY:$ 107,792 CUM:$ 1,802,120 ETD:$ 0 EFC:$ 4,102,120 09/27/98 (D20) MW: 8.3 VISC: 28 PV/YP: 0/ 0 APIWL: 0.0 TD: 4801'( 0) CLEANING MUD TANKS SUPV:DOUG NIENHAUS/S. REYNOLDS Clean out cement to top of float equipment at 4716' Run in hole 8 4723' · DAILY:$ 40,838 CUM:$ 1,842,959 ETD:$ 0 EFC:$ 4,142,959 $9/28/98 (D21) MW: 8.6 VISC: 28 PV/YP: 0/ 0 TD: 4801' ( 0) REV CIR 2 TBG VOLUMES SUPV:DOUG NIENHAUS/S. REYNOLDS DAILY:$ APIWL: 0.0 Cleaning solids from pits with guzzler, wash pits with power washer, centrifuge drilling fluid. Rig up GBR and held safety meeting on picking up tubing. Had to change out GBR power unit for tongs. Hands inadvertantly filled hydraulic tank with diesel. RIH w/3.5" tubing. 31,090 CUM:$ 1,874,049 ETD:$ 0 EFC:$ 4,174,049 09/29/98 (D22) TD: 4801' ( 0) SUPV:RAY SPRINGER DAILY:$ MW: 8.6 VISC: 28 PV/YP: MIXING & FILTERING KCL BRINE Pump caustic sweep. 31,065 CUM:$ 1,905,114 ETD:$ 0/ 0 APIWL: 0.0 0 EFC:$ 4,205,114 09/30/98 (D23) TD: 4801' ( 0) SUPV:RAY SPRINGER DAILY:$ MW: 8.6 VISC: 0 PV/YP: 0/ 0 RIH W/TCP PERFORATING ASSY. APIWL: 0.0 Pump acid pickle. Rig up mouse hole elevator and line up perf guns. 36,016 CUM:$ 1,941,130 ETD:$ 0 EFC:$ 4,241,130 10/01/98 (D24) ~FD: 4801' ( 0) SUPV: RAY SPRINGER DAILY:$ MW: 8.6 VISC: 0 PV/YP: 0/ 0 POH, LAYING DOWN PERF GUNS APIWL: 0.0 RIH w/7" perf guns. Set packer. Shoot perf guns. Pump bridge sal LCM pill. Set packer and squeeze perfs. 41,833 CUM:$ 1,982,963 ETD:$ 0 EFC:$ 4,282,963 Date: 10/16/98 ARCO ALASKA INC. WELL SUMMARY REPORT Page: 4 10/02/98 (D25) TD: 4801'( 0) SUPV:RAY SPRINGER DAILY:$ MW: 8.6 VISC: Set sump packer 0 PV/YP: 0/ 0 APIWL: 0.0 Observe well, U-tubing. Well taking fluid, nIH with scraper/mill BHA. 172,595 CUM:$ 2,155,558 ETD:$ 0 EFC:$ 4,455,558 10/03/98 (D26) TD: 4801'( 0) SUPV:RAY SPRINGER DAILY:$ MW: 8.6 VISC: 0 PV/YP: 0/ 0 APIWL: 0.0 Run Baker sump packer. 10' discrepancy on CCL. POOH and re-run sump packer. Still have 10' discrepancy. Run slimhole CCL to confirm perf depths. Run sump packer. Test BOPEs to 3000 psi. 72,493 CUM:$ 2,228,051 ETD:$ 0 EFC:$ 4,528,051 10/04/98 (D27) TD: 4801'( 0) SUPV:RAY SPRINGER DAILY:$ MW: 8.6 VISC: SETTING PACKERS 0 PV/YP: 0/ 0 APIWL: 0.0 Run gravel pack and screen assembly. Run 4" & 2-7/8" inside assembly. 27,874 CUM:$ 2,255,925 ETD:$ 0 EFC:$ 4,555,925 10/05/98 (D28) TD: 4801' ( 0) SUPV:RAY SPRINGER DAILY:$ MW: 8.6 VISC: PREPARING TO POH 0 PV/YP: 0/ 0 APIWL: 0.0 nIH w/gravel pack assembly on 3.5" tubing. Set packer @ 3135', set lower isolation G 3564' Set middle isolation packer @ 3144' Frac and pack bottom zone. Pack middle zone. 29,707 CUM:$ 2,285,632 ETD:$ 0 EFC:$ 4,585,632 10/06/98 (D29) TD: 4801'( 0) SUPV:RAY SPRINGER DAILY:$ MW: 8.6 VISC: 0 PV/YP: 0/ 0 APIWL: 0.0 LAYING DOWN OVERSHOT ASSEMBLY WITH PARTIAL FISH. Frac & pack top zone. Lay down gravel pack assembly, assembly backed off in seals above isolation packer, nIH with grapple, overshot, drill collars, jars and drill pipe. Tag fish @ 2968'. work free. 32,892 CUM:$ 2,318,524 ETD:$ 0 EFC:$ 4,618,524 10/07/98 (D30) TD: 4801'( 0) SUPV:RAY SPRINGER DAILY:$ MW: 8.6 VISC: 0 PV/YP: 0/ 0 LOGGING SCREENS W/SCHLUMBERGER APIWL: 0.0 nIH w/overshot. Tag fish & latch @ 2937', jar loose. POH w/fish, recovered 1.05' section of seal sub assy. nIH w/grapple, latch onto fish and jar free. Losing fluid thru overshot. Shut in. Mix bridge sal pill and spot. 46,528 CUM:$ 2,365,052 ETD:$ 0 EFC:$ 4,665,052 10/08/98 (D31) TD: 4801' ( 0) SUPV:RAY SPRINGER DAILY:$ MW: 8.6 VISC: LAY DOWN 3-1/2" DP 0 PV/YP: 0/ 0 APIWL: 0.0 Continue to nIH w/PH-6 to 3821' tagged w/locator sub, POOH to 3131'. Monitor well. Losing ~ bbl/hr. Re-run logs due to tool failure. Losing 6 bbl/hr, nIH w/3.5" tubing. 37,194 CUM:$ 2,402,246 ETD:$ 0 EFC:$ 4,702,246 Date: 10/16/98 ARCO ALASKA INC. WELL SUMMARY REPORT Page: 5 !0/09/98 (D32) · rD: 4801' ( 0) SUPV:RAY SPRINGER DAILY:$ MW: 8.6 VISC: NIPPLING DOWN BOP 0 PV/YP: 0/ 0 APIWL: 0.0 Run 5.5" tubing. 227,025 CUM:$ 2,629,271 ETD:$ 0 EFC:$ 4,929,271 10/10/98 (D33) TD: 4801' ( 0) SUPV:RAY SPRINGER DAILY:$ MW: 8.6 VISC: RIGGING DOWN TO MOVE 0 PV/YP: 0/ 0 APIWL: 0.0 Test tubing to 3000 psi. N/D BOPs, set BPV. Install tree and test to 5000 psi. Release rig ~ 1800 hrs. 10/10/98. RDMO. 55,478 CUM:$ 2,684,749 ETD:$ 0 EFC:$ 4,984,749 End of WellSummary for We11:594107 Prepared by: S. ALLSUP-DRAKE CASING TEST and FORMATION INTEGR~TY TEST Well Name: BRU 212-35T Supe~'isor: DOUG NIENHAUS/SCOTr REYNOLDS Date: 9/19/98 Casing Size and Description: Casing Setting Depth: Mud Weight: _ 9.7 ppg Hole Depth: 2,646' TVD 13 3/8", _~8 ppf, K-55, BTC 2,683' TMD 2,611' TVD EMW = Leak-off Press. + MW 0.052 x TVD 860 psL + 9.7 ppg EMW LOT = (0.052 x 2,645') = t6,0 Fluid Pumped = 153 bH8 Pump output = N/A 3.14 NOTE: BARRELS TURN TO MINUTES DURING "SHUT IN T ' IME :see ti *ne I ne above LEAK-OFF DATA CASING TEST DATA MINUTES MINUTES FOR FOR LOT BARRELS PRESSURE CSGTEST BARRELS PRESSURE 0,00 bbls 46 ps i i ! 0.00 bbs 30,7 Rs 0.50 bbls 267 ~s 0.50 bbs 211 0 0.75 bbls 417 Bsi ! O 73 bbs 380 0 1,~ bbls 565 Bs ~ i 0.96 bbs 543.0 psi 1,50 bbs 842 ~si i 1 40 bbs 882 0 Bs ............... i 2.30 bbls 1 ~80~s ....................................................... .~ ¢ .................. ~ 2.~ bbls 1,507.0~si ................................... ~ ................ ~ SHUT IN PRESSURE SHUT IN TIME i SHUT IN PRESSURE ............................. O0 3,0 ....... ~:9 mir ........ 60 mn I 502 Es 1 502 ps [ 20 O mk~ 30~Ornin ~ i 1 497 psi NOTE: TO CLEAR DATA. NIGHLIGHT AND PRESS THE DELETE KEY CASING TEST and FORMATION ~NTEGR~TY TEST Well Name: BRU 212-35T Supervisor: DOUG NtENHAUS/SCOTT REYNOLDS Date: 9/~f~/98 Casing Size and Description: Casing Setting Depth: Mud Weight: Hole Depth: 9 5/8" 47# L,,80 4,800' TMD 2,678' TVD #N/A + 9.9 ppg LOT = (0.052 x 2,678') Fluid Pumped =68~ bbls 4,678' TYD EMW = Leak~off Press. + MW 0.052 x TVD E~W Pump output = N/A 3.14 MINU~ES NOTE: BARRELS TURN TO MINUTES DURING "SHUT IN TIME":see time line above LEAK~OFF DATA MINUTES FOR LOT BARRELS PRESSURE CASING TEST DATA MINUTES FOR CSG TEST BARRELS PRESSURE iNote; P oeeure te~ was eondi,a~ted withj ?9 ?ureps ard efarge pump, The d~ ipump r;~mps imm¢~:~iae/y (/p to ~7-41 lstr~kes eF ~nn t~.,. ~Ir~ti/ a astern bsck~ ?re~s re of 800 Cs ~s reac}e<~ Becausoi ',of h~ mc~sha~{cai ntu~s of t5~, ~The well required 6 bbis of mud pumped~ to reach test pressure and 6 bbls of mud returned when pressure was b ed o f of leasing. SHUT N T MEt SHUT IN PRESSURE 2,0 3,500 psi i NOTE: TO CLEAR DATA, HIGHLIGHT AND PRESS THE DELETE KEY MEMORANDUM TO: State of Alaska Alaska Oil and Gas Conservation Commission . David Johnst ,,9~''''~ DATE: September 18, 1998 Chairman---~~ THRU: Blair Wondzeli, c ~ FILE NO: .DOC P. I. Supervisor ~ ~ ~ FROM: Larry Wade, SUBJECT: Petroleum Inspector BOP Test SAD #1 BRU 212-35T PTD 98-161 September 17,1998: I traveled to Beluga on Spernak Airways at 6:00 PM. ! went thru ARCO safety orientation and went to camp. We started testing BOP's next day at 11:00 AM. Other than a flange leak on the starting head, flange leak on the choke manifold, flange leak on the BOP stack and a malfunctioning test pump the test went ok. They are to change out the test pump before the next Bop test. SUMMARY: I witnessed a BOP test on Sterling Alaska Drilling Rig #1, 0 failures, 5 h~burs. Attachments: am9girfe.xts cc; NON-CONFIDENTIAL STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report OPERATION: Drlg: X Workover: Drlg Contractor: Sterling Alaska Drilling Operator: ARCO Well Name: BRU 212-35T Casing Size: 13 3/8" Set @ Test: Initial X Weekly Rig No. f PTD # Rep.: Rig Rep.: 2,656 Location: Sec. Other TEST DATA: · 98-161 DATE: 9/18/98 Rig Ph.# 263-3921 Don .Hoaglurn Mike Leslie 35 T. 13N Test Pressures R. lOW Meddian 250~3000 Seward MISC. INSPECTIONS: Location Gen.: ok Housekeeping: ok PTD On Location X Standing Order Posted BOP STACK: Annular Preventer Pipe Rams Lower Pipe Rams Blind Rams Choke Ln. Valves HCR Valves Kill Line Valves Check Valve (Gen) X Well Sign X Drl. Rig ok Hazard Sec. X Quan. Test Press. P/F P 250/2500 f 250/3000 P f 250,/3000 P f 250/3000 P f 250/3000 P f 250/3000 P 1 250/3000 P 250/3000 MUD SYSTEM: Visual Alarm Trip Tank X X Pit Level Indicators X X Flow Indicator X X Meth Gas Detector X X H2S Gas Detector X X FLOOR SAFETY VALVES: Upper Kelly / IBOP Lower Kelly / IBOP Ball Type Inside BOP Quan. Test Pressure 250/3000 250/3000 250/3000 250/3000 P/F CHOKE MANIFOLD: No. Valves 14 No. Flanges 34 Manual Chokes 1 , Hydraulic Chokes 1 Test Pressure P/F 250/3000 I P 250/3000 P., Functioned P Funch'oned ! P ACCUMULATOR SYSTEM: System Pressure Pressure After Closure 200 psi Attained After Closure System Pressure Attained Blind Switch Covers: Master: Nitgn. Btl's: 2f00-2450 2000-2250 3,000 1,500 minutes 25 minutes 15 X Remote: Psig. TEST: RESULTS sec. sec. X Number of Failures: ,Test Time: 5.0 Hours. Number of valves tested 18 Repair or Replacement of Failed Equipment will be made within days. Notify the Inspector and follow with Written or Faxed verification to the AOGCC Commission Office at: Fax No. 276-7542 Inspector North Slope Pager No. 659-3607 or 3687 If your call is not returned by the inspector within 12 hours please contact the P. !. Supervisor at 279-1433 REMARKS: Distribution: odg-Well File c - Oper.tRig c- Database c - Tdp Rpt File c -Inspector F1-021L (Rev.12/94) STATE WITNESS REQUIRED? YES X NO 24 HOUR NOTICE GIVEN YES X NO Waived By: W*~nessed By: Am9girfe Larry Wade TONY KNOWLE$, GOVERNOR ALASKA OIL AND GAS CONSERVATION COMMISSION September 2, 1998 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 FAX: (907) 276-7542 Paul Mazzolini, Drlg Team Leader ARCO Alaska, Inc. P O Box 100360 Anchorage, AK 99510-0360 Beluga River Unit 212-35T ARCO Alaska, Inc. Permit No: 98-161 Sur Loc: 1485'FNL, 683'FWL. NW %, Sec. 35. TI3N, RIOW. SM Btmholc Loc. 2171'FNL. 165'FWL, NW ~A. Sec. 35, TI3N, R10W, SM Dear Mr. Mazzolini: Enclosed is the approved application for permit to drill the above referenced well. The permit to drill docs not exempt you from obtaining additional permits required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permitting determinations are made. Blowout prevention equipment (BOPE) must bc tested in accordance with 20 AAC 25 035. Sufficient notice (approximately 24 hours) must be given to allow a representative of the Commission to witness a test of BOPE installed prior to drilling new hole. Notice may be given by contacting thc Commission at 279-1433. Chairman ~ ~- BY ORDER OF THE COMMISSION dlffEnclOsurcs CC~ Department of Fish & Game, Habitat Section xv/o cncl. Department of Environmental Conservation w/o cncl. STATE OF ALASKA ALA,~I',,A OIL AND GAS CONSERVATION COMM';~$1ON PERMIT TO DRILL 20 AAC 25.005 la. Type of Work Ddll X Redrill 1 b Type of Well Exploratory Stratigraphic Test Development Oil Re-Entry Deepen Service Development Gas X Single Zone Multiple Zone X 2. Name of Operator 5. Datum Elevation (DF or KB) 10. Field and Pool ARCO Alaska, Inc. RJg- 21' REB, PAD- ?0' feet Beluga River Field 3. Address 6. Property Designation P. O. Box 100360, Anchorage, AK 99510-0360 A-029657 4. Location of well at surface 7. Unit or property Name 11. Type Bond (see 20 AAC 25.025) 1,485' FNL, 683' FWL, NW ~A, SEC 35, T13N, R10W Beluga River Unit Statewide At top of productive interval (@ TARGET ) 8. Well number Number 1,898' FNL, 263' FWL, NW ~A, SEC 35, T13N, R10W 212-35T #U-630610 At total depth 9. Approximate spud date Amount 2,172 FNL, 165' FWL, NW ~A, SEC 35, T13N, R10W 9/1/98 $200,000 12. Distance to nearest 13. Distance to nearest well 14. Number of acres in property 15. Proposed depth (MD and TVD) property line BRU 212-35 4,910' MD 165 @ TD feet 46' @ 1491' feet 8231 4,791' TVD feet 16. To be completed for deviated wells 17. Anticipated pressure (see 2O AAC 25.035(e)(2)) Kickoff depth 825' feet Maximum hole angle 22.56° Maximum surface 1,750 psig At total depth (TVD) 2,600 psig 18. Casing program Setting Depth size Specifications Top Bottom Quantify of cement Hole Casing Weight Grade Coupling Length MD TVD MD TVD (include stage data) 20" 166 # X56 Weld 100' 21' 21' 121' 121' Driven 17-1/2 13-3/8 68 # K55 BTC 2597' 21' 21' 2,700' 2,618' 540, Class 'G' 600, Class 'G' 12-1/4 9-5/8 47 # L80 BTC-Mod 4889' 21' 21' 4910' 4491' 871 Class 'G' 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Total depth: measured feet Plugs (measured) true vertical feet Effective depth: measured feet Junk (measured) true vertical feet Size Cemented Measured depth [.~l'u~. V~rt,~ Casing Length Structural ~ % '~ '~' L ~ ¥ Conductor Surface ~ ,,.~, Intermediate /-~ ( -'-' 'O - Production Liner0R ,r,,AL Perforation depth: measured I L.. ~ I ~ "Alaska 0il & Gas true vertical ~ Anchorace 20. Attachments Filing fee X Property plat X BOP Sketch X Diverter Sketch X Drilling program X Drilling fluid program X Time vs depth plot Refraction analysis Seabed report 20 AAC 25.050 requirements X 21. I hereby certify that the foregoing is true and correct to the best of my knowledge Signed ~"~¢~,~0.//,,¢~~ Title Drillin~lTeamLeader Date ~/~/~ ~ (/ 0 Commission Use Only Permit Number APl number, IAppr°va' date ¢~-~, ~-~{~ otherSee cover letter fOrrequirements ??-/~' / 5o- .Z ? ~ .2. oo ? 2' Conditions of approval Samples required Yes ~ Mud log required Yes sulfide measures Yes ~) Directional survey required ~ No Hydrogen Required working pressure for BOPE 2M '/~ 5M 10M 15M Other: Original Signed By David W. Johnston by order of ¢,~. -..- Approved by Commissioner the commission Date n~ssi0n Form 10-401 Rev. 7-24-89 Submit in triplicate Beluga River Unit BRU 212-35 Drill Pad R.C. DAVIS & ASSOC. LU?N~CONStlIUCilON MiD MIN~.i~tL SUlll~YOI~ LOCATION: ~L~A RI~ UNIT ~$~[: I' ~ 20 I ~T[: 2/7/9a [CONT~TOR: ARCO ALA~A i~. I ~e NUM~ 7~/98 RE~D ~ ~A~ IDESCR~N: CHECKED 0¥: KD I$H£~--I' I 0= 2 ALASKA VICINITY MAP COOK INLET VICINITY BELUGA RIVER UNIT Jm 2' cOO .. ..- TI3H, RIOW 32 BELUC.,A' RIVER WELL SITES AND FAClLmES $~-NT BY: 8-27-58 : 8:51ga'*l : ARCO AI_4$KA'-' 907 276 7542: # 8/ 3 GENERAL DRILLING PROCEDURE BELUGA RIVER VIEI,D BRU 212-35T l. Drive 20" conductor to 4-100' or refusal. 2. Move in and rig up Sterling Alaska #l. 3. Install & lest diwrter system with single 10" vent line that will bifurcate, itl directions that ensure safe downwind venting. Vent line will extend to at least 100' from any pogsible ignition sottrce. (Notify AOGCC and BLM 24 hou~ in advance of testing diverter) 4. Drill 12-1/4" stu-fa~ hole tv 13-318" easing point (4-9700' MD) according to the directional plan. 5. PU hole opener and open 12-1/4" hole to 17-1/2" down to the 13-3/8" casing point. 6. Run and cement 13-3/8" casing with approximately 1140 sk Class 'G' cement with additives. If there am no cement returns at surface contact AOGCC for consultation. 7. Inslall & test wellhead. Install and test BOPE to 3000 psi. Test Casing to 1500 Os[. for 30 minutes, (Notify AOGCC and BLM 24 hours in advance of testing BOPE) 8. Drill out ccmcnt and 20' or' new hole. Perform I,OT to 12.5 ppg EMW. 9. Drill 12-1/4" hole to 9.5/8 ca.,ting point (:1:4910' MD) according to the directional plan. 10. Run open holt: logs and RFT's. [ I. Condition hole, mn and cement 9-5/8 casing with approximately 630 sk ofCla,5s 'G' cement with additive.,;. 12. Install tubinl~ head and test. NU BOP and test. (Notify AOGCC and BI.,M 24 hours in advance of testing BOPE) 13. RIH to PBTD with bit and scraper. If rat hole is sufficient, drii{ing out c~mtmt will not be required. 14. Test casing to 1500 psi. tbr 30 minutes. 15. Change hole over to filtered brine, 16. Perforate well with 7" TCP guns. 1.7. RIH with bit and scraper to PBTD. 18. Run Baker Frac& Pack completion equipment and pump Fmc & Pack., circulate hole clean. 19. RIH with 5-1/2" tubing & completion equipment. 20. ND BOP & NU production tree, Test tree. 21. Rig down and move to 22,1-34 workovor. Turn well over to facilities. 212-35T GE-NERAI, DRII ,l .lNG PROCEDU RE SDR/Rev. 4/08/27/98 Drilling Fluids Program BRU 212-35T Mud Properties 17-1/2" 12-1/4" Surface Hole Production Hole Density 9.2-9.5 10-10.5 PV (CPS) 15-25 10-20 YP (#/100 ft2) 20-30 8-15 Viscosity (sec) 50-70 38-48 Initial Gel (#/100 ft2) 10 3 10 Minute Gel (#/100 ft2) 20 8 API Filtrate (cc) 15-20 < 10 HTHP MBT 25-30 <20 pH 9-10 8.5-9.0 % Solids ....... <13 Chlorides (mg/l) 500 15000 Basic Mud Formulation ADDITIVE SURFACE PRODUCTION HOLE APPLICATION HOLE Bentonite Clays & 20-30 ppb 10-12 ppb Viscosifier Extenders 0.1 ppb trace Barite As required As required weighting agent Polyanionic Cellulose None .25-.75 ppb Filtrate control Polymer Polyacrylate/terpolymer Trace .10-1.0 ppb deflocculant Soda Ash As required As required Calcium removal/pH control KC1 None 14.4 ppb Clay inhibition NaOH .2-.4 ppb None pH control Baranex None 4-6 ppb HTHP filtrate control Caustic Soda As required As required pH control Sulfonated asphalt None 2-4 ppb Shales/coals protection Drilling Fluids System: ,/' Tri-Flow tandem mud shakers. ,/' Harrisburg Hydracyclone desander with 2-10" cones. · / Tri-Flow desilter with 16-4" cones. v" Shaker pit (370 bbls), volume pit (450 bbls), suction pit (250 bbls) & trip tank (65 bbls) w/remote gauge for driller. · ," Fluid agitators. ,/' Pit Level Indicator. Existing mud system listed above will be upgraded with an adjustable linear shale shaker and rented centrifuge. Drilling fluid practices will be in accordance with the appropriate regulations stated in 20 ACC 25.033. See Attached diagram for layout of mud systems. 212-35T Drilling Fluids Program SDR/Rev. 4 / 07/27/98 1. Spud to 13-3/8" Casing Point (17-1/2" hole to 2265' TMD) Drill this interval with basic bentonite spud mud. Adjust the funnel viscosity and yield point of the mud on an as needed basis for satisfactory hole cleaning capabilities. Surface gravel's will dictate initial funnel viscosities in the 70 sec/qt range and yield point values in the 30g/ft2 range. Maximize pump rates to provide annular velocity rates in the 110-130 feet per minute range for improved hole cleaning. The increase in annular velocity is a much more effective mechanism for improved hole cleaning in large diameter drilling than a corresponding increase in drilling mud viscosity. The mud weight will not be allowed to increase naturally through the accumulation of drilled solids to a 9.2-9.5 ppg density. Control % of drill solids in mud to improve mud rheology properties and minimize washout concerns. 2. 13-3/8" Casing Shoe to TD (12-1/4" hole to 4910' TMD) Drill this interval with a standard LSND system built with 3% KC1. PAC Polymer will be utilized to provide an API filtration rate of 6.0 cc at the time of drilling out the surface casing. Once out of the shoe, treat the mud with sulfonated asphalt and a HTHP filtration control product to provide protection for the problem coal sections that will be encountered in the drilling of this interval. Treat the mud as necessary to maintain the properties as listed in the above table. High-vis sweeps will be executed as hole conditions warrant. The mud weight will be maintained in the 9.2-9.6 ppg range while drilling the Sterling Sands. The mud will be weighted up to 9.6-10.0 ppg range for drilling into the Beluga Sands. The maximum anticipated mud weight at well TD is 10.5 ppg. LCM will be used to control any loss of circulation into the Sterling Sands. 212-35T Drilling Fluids Program SDR / Rev. 4 / 07/27/98 SENT BY' 8-27-.~8 ' 8'-~0t~1 ' .~CO )J_~$KA~ 907 276 7-~42'# 2/ 3 Casing & Cementing Program BRU 212-35T Surface Casin~, 13-3/8", 68 #, N-8(I, BT.C.. I. Run surface casing to TD as follows: a) Use float shoe with the float collar placed 2 joints up. Centralizz the sh(~c hy placing a [3-3/8" buwspring centralizer in the rniddle of first joint, the fa'st collar, middle of second joint, and the float collar. b) Run one 13-3/8" bowspring centralizer per joint of casing for a minimum of 500' above the casing shoe float collar. Past this point nm one centralizer per three joints uf casing to surface. c) Control casing running spccd to minimize surge pressures. d) Break circulation and check flow through float equipment at ±l,00O'. e) At TD, t;irculate and condition while reciprocating casing, if possible. Cement casing as follows: a) Pump preflush & spacer and drop bm~om plug. Mix and pump lead and mil slurries. Reciprocate casing as long a~,~ possible. (Note that once the top plug is dropped it is very rare to bt: able to move the pipe again) b) Drop top plug after the tail slurry. Verify ~ha! indicalor shows plug has left cement head. Pump _10 bbls cement on top of plug befi~rc beginning dis~placement. Displace until the plug bumps and presstu'e up to 500 psi al-n~vc thc circulating pressure to insure the plug has landed. If' float~ do not hold, maintain 1,500 psi on the casing for a minimum of four hours before rechecking. ti) If there are no cement returns at surface contact AOGCC lbr consultation. e) ND Diverter, cut 13-318" casing, slip on and weld 13-5/8", 5,000 psi casing head. NU 13-5/8, 5,000 psi BOPE. Test to 3,000 psi. Prodaction Casing, 9-W8", 47 #, L-80~ BTC-MOD 1. Run Production Casing to TD as fl~llows: a) ll.~e float shoe with the float collar placed 2 joints up. Centralize the shoe by placing a 9-5/8" bowspfing centralizer in the middle of first joint, thc first collar, middle of second joint, and the float cc)Ilar. h) Run one 9-5/8" bOwslyring centralizer every 2 joints of ca.~ing through thc productive intervals to 200' below the 13-3/8 casing point. From there, run 1 per joint to 500' above 13-3/8" casing shoe. c) Control cusing running speed to minimize .s~lrge pressures. d) Break circulation and check tlow through float equipment at +_1,000'. e) At TD, circulate and condition mud wlfilt: reciprocating casing, if possible. 212-35T Drilling Fluids Program SDR / Rev. 4 / 08/27/98 2. Cement casing as follows: Pump preflush & spacer and drop bottom plug. Mix and pump tail slurry. Reciprocate casing as long as possible. (Note that once the top plug is dropped it is very rare to be able to move the pipe again) b) Land 9-5/8" casing in 13-3/8" casing head. c) d) Drop top plug after the tail slurry. Verify that indicator shows plug has left cement head. Pump + 10 bbls cement on top of plug before beginning displacement. Displace until the plug bumps and pressure up to 500 psi above the circulating pressure to insure the plug has landed. If floats do not hold, maintain 1,500 psi on the casing for a minimum of four hours before rechecking. e) Install tubing head and test secondary packoff to 3,000 psi. NU BOPE and test. CEMENT ADDITIVES Additive Extender Celloflake Dispersant Retarder Anti-foam liquid Barite Purpose Reduce slurry density & increase yield Lost circulation material Friction reducer Delays the time for cement to set Defoamer Weighting agent 212-35T Drilling Fluids Program SDR/Rev. 4 / 07/27/98 NOTES Maximum anticipated surface pressure is calculated using a surface casing leak-off of 13.5 ppg EMW and a Beluga gas gradient of 0.04 psi/ft. This shows that a formation breakdown would occur before a surface pressure of 1,720 psi could be reached. Therefore, ARCO Alaska, Inc. will test the BOP equipment to 3,000 psi. The nearest existing well to BRU 212-35T is the existing BRU 212-35 discovery well. As designed the closest crossing between the two wells will be 46' ft at 1,491' MD. Drilling Area Risks: Risks in the BRU 212-35T drilling area include uncertainty of the Sterling formation top and the reservoir pressures of the Sterling Sands. The surface casing will be set deep enough (2,600' TVD) to ensure competent formation for the 13-3/8" casing point. Any deeper than 2,500' TVD runs the risk of encountering substantial coal beds which lie between the chosen casing point and the top of the Sterling sands. Because channel deposits make up the reservoir sands, there is a risk of drilling into a channel sand that contains virgin reservoir pressure. However, it is believed the Sterling sands will be depleted due to the interconnectivity of the channels. Lost circulation into the Sterling will be countered with lost circulation material (LCM). Analysis of pressure data from offset wells indicates that a 9.7 ppg mud will provide sufficient overpressure to safely drill, trip pipe, and cement. The 13-3/8" casing shoe will be tested to an equivalent mud weight of 12.5 ppg upon drilling 20' out of the surface casing. Lo~ing: Open hole logging will consist of a MWD with directional/GR tools and E-line with GR, Neutron, Density, Combinable Magnetic Resonance, and Sonic tools. A repeat formation tester will be utilized for pressure determination of the individual sands to assess sand continuity, and new reserves potential. In the event of a poor cement job, a cement bond log will be run. Expected Formation Tops: Sterling A All Depths are TVD STA- 1 STA-2 STA-3 STA-4 Expected Tops 3,017 3,065 3,152 3,190 Expected Pay 16 40.5 23.5 0 Sterling B All Depths are TVD STB-1 STB-2 STB-3 Expected Tops 3,261 3,312 3,334 Expected Pay 29.5 9.5 7 212-35T Drilling Fluids Program SDR / Rev. 4 / 07/27/98 Sterling C All Depths are TVD STC- 1 STC-2 STC-3 STC-4 Expected Tops 3,362 3,403 3,450 3,491 Expected Pay 17 23 16.5 4.5 Beluga All Depths are TVD Beluga D Beluga E Beluga F Expected Tops 3,510 3,740 4,660 Expected Pay 130 120 100 Potential Fresh Water Zones: The fresh water zone is from 60' to 400' TVD. The fresh/brackish water zone is from 400' to 3,000' TVD. Bonding: As required under AOGCC Regulation 20 ACC 25.025, ARCO Alaska, Inc. has obtained a Statewide Blanket Bond (#U-630610) for the amount of $200,000. 212-35T Drilling Fluids Program SDR / Rev. 4 / 07/27/98 Basic Layout of Mud System Sterling Alaska #1 Used Drilling Fluid Rig Floor Motor Shed Pump Room Shaker/Mud cleaner pits Centrifuges Volume Pit Water Tank Boiler #2 Boiler #1 Motor Mans House Generator House IMud Lab I Dual Tandem Shale Shaker Desilter Desander SDR 5/19/97 ARCO Alaska, Inc. Structure : BRU Pacl 212-35 Well : 212-55Tn Field : Beluga River Unit Location : Cook Inlet, Alaska 25O 25O 500 750 lOOO 125o 15oo 1750 2aaa 2250 250O 2750 3OO0 3250 35OO 375O 4OO0 425O 45O0 ¢750 50OO 250 ~ RKB Elevation: 91' KOP 2,50 5.00 7.50 OLS: 2,50 dog per 100 ft 10.00 560 480 I I I I <- West (feet) 400 320 24O 160 80 t I I I I I I I I Estimated I Surface Lacotlon: 1485' FNL, 686' F'WL Sec. 55, T15N, RIOW, SM Begin Turn & Drop J Target ~1 Location: I 1898' FNL, 265' F'WL Sec. 35, T13N, ElOW, SM Begin Turn to TorgE 12.50 Begin Turn to Target 13.49 14.66 1~ 16.1.3 17,82 19.68 21.67 £0C 22.06 Begin Turn & Drop 20.61 19.16 ~ 17.75 BLS: 1.50 dog 100 ft PO~4T ~ 14.go ii 13,51 ~ 12,15 TAEGL-f - T/ Sterling _ TARGET - T/ Beluga TO - 9 5/8 Casing TARGET - T/ Sterling TARGET - T/ Beluga TD - 9 5/8 Casing Pt JTO Location: J 2172' FNL, 164.' F'Wt. Sec. 55, T13N, RIOW, SM 0 0 80 160 0 320 400 i 560 64O 72O i I i i i !i i i[ i 0 250 500 750 1000 Vertical Section (feet) -> AzJmuJh 22[.4§ wJlh relerence 0.~ )~, 0.00 [ from slot WELL PROFILE DATA 9.74 Paint ..... MD Inc O~r TVD North East V. SectDog/leO T~e on 0.00 0.00 0.00 0.00 O.OO 0.00 0.00 0.0~ J KO~ ~25.00 O.OO 260.00 825.00 O.OO o.ao 0.00 0.0~3 Begin Turn 1545.00 13.00 260.00 ~ 54o.55 -10.20 -57.85 48.40 2.50 l end of Build/Turn 1943.41 22.58 220.20 1911.64 -110.14 -199.04 219.15 2.50 f end of Ha~d 2265.25 22.56 220.20 2208.84- -204.46 -278.76 342.12 0.0{3 Target 3184.96 9.74 200.27 3091.00 -413.17 -~,20.27 589.56 1.50 I Target 3692.27 g.74 200.2? 3591100 -493.67 -4.50.01 666.99 0.00 T.O. ar End of Ho~d 4.909.83 9.74 200.27 4791.00 -686.92 -521.38 853,37 0.00 I c,~t,,~ by $o.,, For: S Reynolds Date p~otted: 21-Jut-gA Plot Refecence is 212-3~ Twin Vets. f4. C~'d~nat~a are ~ f~*t refers'me ~a~ J212-35'T',~n True vertical ne4:Rh~ E.~rnated RKB. IOe.=~ed ~, jo,,e. For: S Reynolds Oote plotted : 21-Jul-98 Plot Reference ;~ 212-35 Twin Vets. ~4. ARCO Alaska, Inc. Structure : BRU Pad 212-35 Well : 212-55Tn Field : Beluga River Unit Location : Cook Inlet, Alaska 6o 5o Q) 20 ~- 5o 0 I 50 60 70 80 go lOO 11o 120 130 <- West (feet) 130 120 110 100 90 80 70 60 50 4.0 .30 20 10 o lO I I I I I I I I I I I I I I I I I I I I I I I I I I I I I <- West (feet) 20 20 0 c- 3o 40 I 50 80 100 110 120 130 BRU PAd 212-35,212-357n Beluga River Unit,Cook Inlet, AlAskA Heasured Xnclin. Azimuths True Vert R · C T & N G U ~ A R Depth Degrees Degrees Depth C O 0 R D ! N A T E S 0.00 0.00 0.00 0.00 1484.71 S 685.69 100.00 0.00 260.00 100.00 1484.71 S 685.69 200.00 0.00 260.00 200.00 1484.71 S 685.69 300.00 0.00 260.00 300.00 1484.71 S 685.69 400.00 0.00 260.00 400.00 1484.71 S 685.69 500.00 0.00 260.00 500.00 1484.71 S 685.69 600.00 0.00 260.00 600.00 1484.71 S 685.69 700.00 0.00 260.00 700.00 1484.71 S 685.69 800.00 0.00 260.00 800.00 1484.71 S 685.69 825.00 0.00 260.00 825.00 1484.71 S 685.69 925.00 2.50 260,00 924.97 1485.09 S 683.54 1025,00 5.00 260.00 1024.75 1486.23 S 677.10 1125.00 ?.S0 260.00 1124.14 1488.12 S 666.38 1225.00 10.00 260.00 1222.97 1490.76 S 651,40 1325.00 12.50 260.00 1321.04 1494.15 S 632.19 1345.00 13.00 260.00 1340.5S 1494.92 S 627.84 1400.00 13.49 254.38 1394.09 1497.72 S 615.57 1500.00 14.66 245.28 1491.10 1506.15 S 592.85 1600.00 16.13 237.65 1587.52 1518.87 S 569.62 1700.00 17.82 231.34 1683.17 1535.87 S 545.94 1800.00 19.68 226.15 1777.86 1900.00 21.67 221.84 1871.43 1943.41 22.56 220.20 1911.64 2000.00 22.56 220.20 1963.90 2265.25 22.56 220.20 2208.84 PROPOSA~ LISTIH~ PAge 1 Your res : 212-35 Twin Vets. 94 Last revised : 21-J~1-98 3300.00 22.06 219.87 2240.99 2400.00 20.61 218.82 2334.14 2500.00 19.16 217.61 2428.17 2600.00 17.73 216.22 2523.03 2700.00 16.31 214.59 2618.65 2800.00 14.90 212.67 2714.96 2900.00 13.51 210.35 2811.90 3000.00 12.15 207.52 2900.40 3100.00 10.82 204.00 3007.40 3184.95 9.74 200.27 3090.99 3184.96 9.74 200.27 3091.00 3201.04 9.74 200.27 3106.84 3301.04 9.74 200.27 3205.40 3401.04 9.74 200.27 3303.96 3501.04 9.74 200.27 3402.52 Dogleg Deg/100ft 0.00 0.00 0.00 0.00 0.00 Vert Sect 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 EOP 2.50 1.80 2.50 7.19 2.50 16.16 2.50 28.69 2.50 44.76 2.50 48.40 BegLn Tu~ to T~et 2.50 59.11 2.50 81.23 2.50 106.72 2.50 135.52 1557.1o s 522.84 E 2.50 167.59 1582.52 S 497.37 E 2.50 202.86 1594.8S s 486.65 E 2.s0 219.15 1611.44 S 472.63 · 0.00 240.78 1689.17 S 406/93 Z 0.00 342.12 Begin Turn & Drop 1699.27 S 398.45 E 1.50 355.25 1727.4o s 375.38 B 2.50 392.42 1754.12 S 354.33 E 1.50 425.16 1779.40 S 335.31 E 1.50 456.48 1803.25 S 318.34 E 1.50 488.27 l~/% 1828.63 S 303.43 Z 1.50 511.59 1846.54 S 290.59 E 1.50 535.41 1865.95 S 2?9.82 E 1.50 556.69 1883.86 S 271.14 E 1.50 575.44 1897.89 S 265.41 B 1.50 589.36 ?AROL'T 1897.8~ S 265.41 E 2.50 589.36 2900.i( S 284.~? U 0.00 592.82 1916.30 S 258.61 E 0.00 607.12 1932.17 ~ 252.75 g 0,00 622.~2 19~8.01 ~ 246.89 a 0.00 3601.04 9.74 200.27 3501.08 1963.90 S 241.03 E 0.00 653.03 3692.36 9.74 200.27 3590,99 1978.38 S 235.68 E 0.00 666.99 TARGL~ - T/ Belug& 3692.27 9,74 200.27 3591,00 1978.38 S 235.68 E 0.00 666.99 4000.00 9.74 200.27 3894.29 2027.23 S 217.64 g 0.00 714.10 4500.00 9.74 200.27 4387.08 2106.59 S 188.33 B 0.00 790.64 4909.83 9.74 200.27 4791.00 2171.64 S 164.31 0.00 853.37 ~ - 9 5/8' All data is ~n feet unless otherwise stated. Coordinates from NW Corner of See. 35, T13N, R10W SM and TVD from Estimated RKB 491.00 Ft above mean sea level). Bottom hole d/stance is 862.38 on azimuth 217.20 degrees fronw~llhead. Total D~leg for wellp&th is 41.76 degrees. VerticAl section is from wellhead on azimuth 225.49 degrees. CAlculAtion uses the minAmnu~ cu~-vature method. Presented by Baker Hughes INTEQ ARCO Alaska, Inc. BIU Pad 212-35,212-35Tn PROPOSAr~ LZS?3:]~G Page 2 L&st revised : 21-Ju~-98 C~ents in wellpath ND TVD Rectangular Coords. Connent 825.00 825.00 1484.71 1345.00 1340.55 1494.92 1943.41 1911.64 1994.86 22SS.25 2208.84 1689.17 3184.95 3090.99 1897.89 3602.26 3590.99 1978.38 4909.83 4791.00 2171.64 685.69 Z KOP 627.84 E Begin ~urn to Target 486.65 B BOG 406.93 B Begin Tuz-n & Drop 265.41 · TARGET - T/ Sterling 235.68 B TARGET - T/ Beluga 164.31 B TD - 9 5/8N Casing Pt Casingpositions in string 'Ae Top MD TOP TVD Rec~ungul&r Coo~Ls. Bot MD Bot TVD Rectangular Cooz~s. Casing ..o... .................. .00...0...0..0 ............................... . ........... .......................... 0.00 0.00 1484.718 685.69· 22SS.2· 2208.84 1589.179 406.93· 13 3/8s C~sJ.n~ 0.00 0.00 148&.719 685.69· 4909.83 4791.00 2171.649 164.3LE 9 5/8w ~m.S~ Targets associated with this wellpath mmmm m mmmmm mm m mmmmmz Target name Geogr&ph/c Location T.V.D. Reef&uglier Coo~Ltuates RevXsed ........... 0... ...... ....-..o0.....0... .................. . ....................... .......................... well#l TO 11-Feb-98 318069.000,2623000.000,999.00 4791.00 2152.48S 167.42· 17-De~-97 #e~1#1 T/ S=erlingR 318167.000,2623253.000,999.00 3091.00 1897.89S 265.42· 16-Deco97 #e~1#1 T/ Beluga 11- 318136.000,2623173.000,999.00 3591.00 1978.379 235.68· 17-Dec-97 21-1/4", 2,000 PS' DIVERTER SCHEMAS'lC Beluga River Unit 6 5 DO NOT SHUT IN DIVERTER AND VALVE AT THE SAME TIME UNDER ANY CIRCUMSTANCES 4 3 Master Diverter Valve MAINTENANCE & OPERATION 1. UPON INITIAL INSTALLATION.' - CLOSE VALVE AND FILL PREVENTER WITH WATER TO ENSURE THAT THERE ARE NO LEAKS. - CLOSE PREVENTER TO VERIFY OPERATION AND THAT THE VALVE OPENS IMMEDIATELY. 2. CLOSE ANNULAR PREVENTER IN THE THE EVENT THAT AN INFLUX OF WELLBORE FLUIDS OR GAS IS DETECTED. OPEN VALVE TO ACHIEVE DIVERSION. 1. 20" CONDUCTOR. 2. WELD ON STARTING HEAD FLANGE. 3. RISER SPOOL 4. 13-5/8", 2,000 PS~. DRILLING SPOOL WITH ONE 10" OUTLET. 5. ONE 10" MASTER DIVERTER VALVE WITH 10" DIVERTER LINE. THE VALVE OPENS AUTOMATICALLY UPON CLOSURE OF ANNULAR PREVENTER. DIVERTER LINE WILL BE PLACED FOR OPTIMUM DIVERSION IN PREVAILING WIND CONDITIONS. 6. 21-1/4", 2000 PS~. ANNULAR PREVENTER. SDR 5/14/98 HCR ! ! Manual Normally Closed ~ ~ Normally Open 4-1/16" Bartor~ '~ 4-1/16 Cameron Manual ! ! HCR Normally Oped~ ~J Normally Closed I 13-5/8" 5 00" PSI. BOP STACK BELUGA RIVER UNIT ACCUMULATOR CAPACITY TEST 1. CHECK AND FILL ACCUMULATOR RESERVOIR TOPROPER LEVEL WITH HYDRAULIC FLUID. 2. ASSURE THAT ACCUMULATOR PRESSURE IS 3000 PSI. WITH 1500 PSI. DOWNSTREAM OF THE REGULATOR. 3. WHILE OBSERVING THE TIME, CLOSE ALL UNITS SIMULTANEOUSLY . RECORD THE TIME AND RECORD THE PRESSURE REMAINING AFTER ALL UNITS ARE CLOSED WITH CHARGING PUMP OFF. 4. RECORD ON THE IADC REPORT. THE ACCEPTABLE LOWER LIMIT IS 45 SECONDS CLOSING TIME AND 1200 PS~. OF REMAINING PRESSURE. DOPE STACK TEST 1. FILL BOP STACK AND MANIFOLD WITH WATER. 2. CHECK THAT ALL HOLD-DOWN SCREWS ARE FULLY RETRACTED. 3. CLOSE ANNULAR PREVENTER AND CHOKES AND BYPASS VALVES ON THE MANIFOLD. ALL OTHERS ARE LEFT OPEN. 4. TEST ALL COMPONENTS TO 250 PSI. AND HOLD FOR 3 MINUTES. INCREASE PRESSURE TO 3,000 PSI. AND HOLD FOR 3 MINUTES. BLEED TO 0 FSI. 5. OPEN ANNULAR PREVENTER, MAUNUAL, AND CHOKE LINE VALVES. 6. CLOSE TOP PIPE RAMS AND HCR VALVES ON KILL AND CHOKE LINES. 7. TEST TO 250 PSI o AND 3000 PSI AS IN STEP 4. CONTINUE TESTING ALL VALVES, LINES, AND CHOKES WITH A 250 PSI LOW AND 3000 PSI HIGH. TEST AS IN STEP 4. DO NOT PRESSURE TEST ANY CHOKE THAT IS NOT A FULL CLOSING POSITIVE SEAL CHOKE. OPEN TOP PIPE RAMS AND CLOSE BoTroM PIPE RAMS. TEST Bo'frOM PIPE RAMS AT 250 PSI & 3000 PSI FOR 3 MINUTES. OPEN PIPE RAMS, BACKOFF RUNNING JOINT AND PULL OUT OF HOLE. CLOSE BUND RAMS AND TEST TO 3000 PSI FOR 3 MINUTES. BLEED PRESSURE TO O PSI. 10. OPEN BLIND RAMS AND RECOVER TEST PLUG. MAKE SURE ALL VALVES ARE SET IN THE DRILLING POSITION. 11. TEST STANDPIPE VALVES TO 3000 PSI FOR 3 MINUTES. 12. TEST KELLY COCKS AND INSIDE BOP TO 3000 PSI FOR 3 MINUTES. 13. RECORD TEST INFORMATION ON BLOWOUT PREVENTER TEST FORM. SIGN AND SEND TO DRILLING SUPERVISOR. 14. PERFORM COMPLETE DOPE TEST ONCE A WEEK AND FUNCTIONALLY OPERATE DOPE DAILY. 8. 1. LANDING RING 2. 13-5/8", 5,000 PSI CASING HEAD. 3. 13-5/8", 5,000 PSI SPACER SPOOL.(As NEEDED) 4. 13-5/8", 5,000 PSI SINGLE PIPE RAM. 5. 13-5/8", 5,000 PSI DRILLING SPOOL WITH CHOKE AND KILL LINES. 6. 13-5/8', 5,000 PSI DOUBLE RAM WITH PIPE RAMS ON TOP AND BLIND RAMS ON BO]-I'OM. 7. 13-5/8", 5,000 PSI ANNULAR PREVENTER. SDR 5/14/98 Sterling Alaska Drilling, Rig #1 5,000 psi Choke Manifold To Gas Buster 3" OCT Normally Open Pressure 2-1/16' WKM Sensors Hydraulic Choke 2" Cameron Normally Closed Normally Open 2-1/16" WKM Normally Open P ressu re Gauge 2" Cameron Normally Closed OCT Manual Choke __Normally Open Dischcarge Line 3" OCT Normally Closed SENT BY: 8-27-.58 · 8'50AM · ARCO ALASKA~- ~07 276 7542'# 1/ 3 ARCO Alaska, Inc. Il ~1 I FACSIMILE TR.ANSMISSION J .11 - '11 mil III II I · Kuparuk Development P. O. BOX 10036o ANCHORAGE, AK 99510-0360 FAX # 907 265-6224 ATe-1279 ocation: _ A_0,,G(j~_ . Phone #: Subject: (~uz~-zctl~,y_.~ ,,. Apo. ('tht.4 F,z.. ~-r~. ....... -- Comments; ~'/J,~ r Wl~r~l~[~'1 , GRAPHIC SCALE "T T T Beluga River Unit BRU 212-35 Drill Pad R.C. DAVIS & ASSOC. LANi~CONSTRUCTION AND MINERAL SURVi~'~ORS l SCALE: I" - 20' LOCATION: BCLU(]A RI*vT:R UNIT I DAI'E: 2/7/98 ICON¥~,CTOR: ARCO ALASKA INC. I JOB NUMBER 7/9/98 R£'vlSED WELL LOCA'IiON I DESCRIPTION: 98-06 ICHECKEDBY: KD I 0= 2 ALASKA VICINITY MAP COOK INLET VICINITY 11 13 BELUGA RIVER UNIT 28 27 2" ,..- cO0 .. ,.- TI .I&L RIOW TI2N. BELUOA. RIVER- WELL SITES AND FACILmES CHE~ AB-13g,,-2 ' ;; SENT BY: 8-27-.58 ; 8 :-51Al~I : ARCO ALASKA-+- 907 276 7542; # 3/ ,3 GENERAL DRILLING PROCEDURE BELUGA RIVER I~"I'EI.,D BRU 212-35T 1. Drive 20" conductor to __100' or refusal. 2. Move in and rig up Sterling Alaska #'1. 3, Install & test diverter system with single 10" vent line flint will biftn't;ate in directions that ensure safe downwind venting. Vent line will exlend to at. least 100' from any possible ignition source. (Notify AOGCC and BLM 24 hours in advance of testing diverter) 4. Drill 12-1/4" surfa~ hole to 13-3/8" casing point (+2700' MD) according to the directional plan. 5. PU hole opener and open 12- t/4" hole to 17-1/2" down to thc 13-3/8" casing point, 6. Run and cement 13-3/8" casing with approxhnately 1140 sk Class 'G' cement with additives. If there are no cement returns at surf acc contact AOGCC for consultation. 7. Inslall & test. wellhead. Install and test BOPE to 3000 psi. Test Casing to 1500 psi. for 30 minutes. (Notify AOGCC and BLM 24 hours in advance of testing BOPE) 8. Drill out cement and 20' of new hole. Pert'oma LOT to 12.5 ppg EMW. 9. Drill 12-l/,~" hole m 9-5/8 casing point (:!:4910' MI)) according to the directional plan. 10. Run open hole logs and RFT's. I I. Condition hole, nm and cemen! 9-5/8 casing with approximately 630 sk ofCla,ss 'G' cement with additives. 12. Install tubing head and test. NU BOP and test. (Notify AOGCC and BLM 24 hours in advance of testing BOPE) 13. RIH to PBTD with bit and scraper. If rat hole is sufficient, drilling out cement will not be required. 14. Test casing to 'i 500 psi, 1br 30 minutes. 15, Change hole over to filtered brine. 16. Perforate well with 7" TCP guns. 17. R_IH with bit and scraper to PBTD. 18. Run Baker Frac& Pack completion equipment and pump Frac& Pack., circulate hole clean. 19. RIH with 5-1/2" tubing & completion equipment. 20. ND BOP & NI,! pr~.~luction tree. Test tree. 2'1. Rig down and move to :224-34 workover. Turn well over to facilities. 212-35T GENERAl, DRI! ,l ,lNG PRO(.T..,DU RE SDR/Rev, 4/08/27/98 Drilling Fluids Program BRU 212-35T Mud Properties 17-1/2" 12-1/4" Surface Hole Production Hole Density 9.2-9.5 10-10.5 PV (CPS) 15-25 10-20 YP (#/100 ft2) 20-30 8-15 Viscosity (sec) 50-70 38-48 Initial Gel (#/100 ft2) 10 3 10 Minute Gel (#/100 ft2) 20 8 AP1 Filtrate (cc) 15-20 <10 HTHP MBT 25-30 <20 pH 9-10 8.5-9.0 % Solids ....... <13 Chlorides (mg/1) 500 15000 Basic Mud Formulation ADDITIVE SURFACE PRODUCTION HOLE APPLICATION HOLE Bentonite Clays & 20-30 ppb 10-12 ppb Viscosifier Extenders 0.1 ppb trace Barite As required As required weighting agent Polyanionic Cellulose None .25-.75 ppb Filtrate control Polymer Polyacrylate/terpolymer Trace .10-1.0 ppb deflocculant Soda Ash As required As required Calcium removal/pH control KC1 None 14.4 ppb Clay inhibition NaOH .2-.4 ppb None pH control Baranex None 4-6 ppb HTHP filtrate control Caustic Soda As required As required pH control Sulfonated asphalt None 2-4 ppb Shales/coals protection Drilling Fluids System: ,/ Tri-Flow tandem mud shakers. ,/ Harrisburg Hydracyclone desander with 2-10" cones. ,/' Tri-Flow desilter with 16-4" cones. ,/' Shaker pit (370 bbls), volume pit (450 bbls), suction pit (250 bbls) & trip tank (65 bbls) w/remote gauge for driller. ,,/ Fluid agitators. ,/' Pit Level Indicator. Existing mud system listed above will be upgraded with an adjustable linear shale shaker and rented centrifuge. Drilling fluid practices will be in accordance with the appropriate regulations stated in 20 ACC 25.033. See Attached diagram for layout of mud systems. 212-35T Drilling Fluids Program SDR / Rev. 4 / 07/27/98 1. Spud to 13-3/8" Casing Point (17-1/2" hole to 2265' TMD) Drill this interval with basic bentonite spud mud. Adjust the funnel viscosity and yield point of the mud on an as needed basis for satisfactory hole cleaning capabilities. Surface gravel's will dictate initial funnel viscosities in the 70 sec/qt range and yield point values in the 30~/ft2 range. Maximize pump rates to provide annular velocity rates in the 110-130 feet per minute range for improved hole cleaning. The increase in annular velocity is a much more effective mechanism for improved hole cleaning in large diameter drilling than a corresponding increase in drilling mud viscosity. The mud weight will not be allowed to increase naturally through the accumulation of drilled solids to a 9.2-9.5 ppg density. Control % of drill solids in mud to improve mud rheology properties and minimize washout concerns. 2. 13-3/8" Casing Shoe to TD (12-1/4" hole to 4910' TMD) Drill this interval with a standard LSND system built with 3% KC1. PAC Polymer will be utilized to provide an API filtration rate of 6.0 cc at the time of drilling out the surface casing. Once out of the shoe, treat the mud with sulfonated asphalt and a HTHP filtration control product to provide protection for the problem coal sections that will be encountered in the drilling of this interval. Treat the mud as necessary to maintain the properties as listed in the above table. High-vis sweeps will be executed as hole conditions warrant. The mud weight will be maintained in the 9.2-9.6 ppg range while drilling the Sterling Sands. The mud will be weighted up to 9.6-10.0 ppg range for drilling into the Beluga Sands. The maximum anticipated mud weight at well TD is 10.5 ppg. LCM will be used to control any loss of circulation into the Sterling Sands. 212-35T Drilling Fluids Program SDR ! Rev. 4 / 07/27/98 SENT BY: 8-27-58 ; 8:50AI~ ; ARCO Casing & Cementing Ptogra~n BRU 212-35T Surface Casin~. 13-3/8", 68 #, N-80, BT.C. I. Run surface casing to TD as follows: a) Use float shoe with the float collar placed 2 joints up. Centralizx: the shoe by placing a [3-3/8" bowspring ccntraliz~er in the middle of first joint, the fa'st collar, middlt~ o1' second joint, and the float collar. b) Run one 13-3/8" bowspring centralizer pet' joint of casing fur a minimum of 500' above the casing shoe float, collar. Past this point run one centralizer per fl~rce joints tff casing to surface, c) Control casing running spccd to minimize surge pressures. d) Break circulation and check flow through float equipment at +1,000'. e) At 'I'D, ~ircuhtt¢ and condition while recipmcaling casing, if possible. Cement casing as follows: a) Pump preflush & spacer and drop bottom plug. Mix and pump Icad and mil slurries. Reciprocate casing as long as possible. (Note that once the top plug is dropped it is very rare to be able move the pipe again) b) Drop top plug after the tail slurry. Verify lhat indicator shows plug has loft comont head. Pump 4-10 bbls cement on top of plug before beginning dis'placement. Displace until the plug bumps and pressure up to 500 psi above thc circulating pressure to insure the plug has landed. If floats, do not hold, maintain 1,500 p~i on tho casing I'or a minimum of four hours before rechecking. d) If there are no cement returns at surface contact AOGCC lbr consultation. e) ND Diverter, cut 13-3/8" casing, slip on and weld 13-5/8", 5,000 psi casing head, NU 13-5/8, 5,000 psi BOPE. Tes~ to 3,000 psi. Production Casing, 9-~/8", 47 q~_L-80~ BTC-MOD 1. Run Production Casing to TD as ~ollows: n) l!.~e flnat .~hne wi~h the float collar placed 2 joints up. Centralize the .qhoe by placing a 9-5/8" bowspring centralizer in the middle of first joint, thc first collar, middle of second joint, and the float collar. b) Run one 9-5/8" bowspring centralizer every 2 joints of ea.qing through the productive intervals to 200' below the 13-3/8 casing point. From there, tun 1 per joint to 500' above 13-3/8" casing shoe. c) Control casing running speed to minimize surge pressures, d) Break circulation and check tlow through float equipment at +_1,000', e) At TD, circulate and condition mttd wlfile rccipr{mating casing, if possible. 212-35'1' Drilling Fluids Program SDR / Rev. 4 / 08/27/98 2. Cement casing as follows: Pump preflush & spacer and drop bottom plug. Mix and pump tail slurry. Reciprocate casing as long as possible. (Note that once the top plug is dropped it is very rare to be able to move the pipe again) b) Land 9-5/8" casing in 13-3/8" casing head. c) Drop top plug after the tail slurry. Verify that indicator shows plug has left cement head. Pump +10 bbls cement on top of plug before beginning displacement. d) Displace until the plug bumps and pressure up to 500 psi above the circulating pressure to insure the plug has landed. If floats do not hold, maintain 1,500 psi on the casing for a minimum of four hours before rechecking. e) Install tubing head and test secondary packoff to 3,000 psi. NU BOPE and test. CEMENT ADDITIVES Additive Extender Celloflake Dispersant Retarder Anti-foam liquid Barite Purpose Reduce slurry density & increase yield Lost circulation material Friction reducer Delays the time for cement to set Defoamer Weighting agent 212-35T Drilling Fluids Program SDR / Rev. 4 / 07/27/98 NOTES Maximum anticipated surface pressure is calculated using a surface casing leak-off of 13.5 ppg EMW and a Beluga gas gradient of 0.04 psi/ft. This shows that a formation breakdown would occur before a surface pressure of 1,720 psi could be reached. Therefore, ARCO Alaska, Inc. will test the BOP equipment to 3,000psi. ~{~ ~qt' 7'0'0, ~}i~ '~Goo -- t.;;y'O ,~ ~.1,~'0 The nearest existing well to BRU 212-35T is the existing BRU 212-35 discovery well. As designed the closest crossing between the two wells will be 46' ft at 1,491' MD. Drilling Area Risks: Risks in the BRU 212-35T drilling area include uncertainty of the Sterling formation top and the reservoir pressures of the Sterling Sands. The surface casing will be set deep enough (2,600' TVD) to ensure competent formation for the 13-3/8" casing point. Any deeper than 2,500' TVD runs the risk of encountering substantial coal beds which lie between the chosen casing point and the top of the Sterling sands. Because channel deposits make up the reservoir sands, there is a risk of drilling into a channel sand that contains virgin reservoir pressure. However, it is believed the Sterling sands will be depleted due to the interconnectivity of the channels. Lost circulation into the Sterling will be countered with lost circulation material (LCM). Analysis of pressure data from offset wells indicates that a 9.7 ppg mud will provide sufficient overpressure to safely drill, trip pipe, and cement. The 13-3/8" casing shoe will be tested to an equivalent mud weight of 12.5 ppg upon drilling 20' out of the surface casing. Lo~ein~: Open hole logging will consist of a MWD with directional/GR tools and E-line with GR, Neutron, Density, Combinable Magnetic Resonance, and Sonic tools. A repeat formation tester will be utilized for pressure determination of the individual sands to assess sand continuity, and new reserves potential. In the event of a poor cement job, a cement bond log will be run. Expected Formation Tops: Sterling A All Depths are TVD STA- 1 STA-2 STA-3 STA-4 Expected Tops 3,017 3,065 3,152 3,190 Expected Pay 16 40.5 23.5 0 Sterling B All Depths are TVD STB-1 STB-2 STB-3 Expected Tops 3,261 3,312 3,334 Expected Pay 29.5 9.5 7 212-35T Drilling Fluids Program SDR / Rev. 4 / 07/27/98 Sterling C AH Depths are TVD STC- 1 STC-2 STC-3 STC-4 Expected Tops 3,362 3,403 3,450 3,491 Expected Pay 17 23 16.5 4.5 Beluga All Depths are TVD Beluga D Beluga E Beluga F Expected Tops 3,510 3,740 4,660 Expected Pay 130 120 100 Potential Fresh Water Zones: The fresh water zone is from 60' to 400' TVD. The fresh/brackish water zone is from 400' to 3,000' TVD. Bonding: As required under AOGCC Regulation 20 ACC 25.025, ARCO Alaska, Inc. has obtained a Statewide Blanket Bond (#U-630610) for the amount of $200,000. 212-35T Drilling Fluids Program SDR / Rev. 4 / 07/27/98 Basic Layout of Mud System Sterling Alaska Cf1 Used Drilling Fluid Rig Floor Motor Shed Pump Room Water Tank Boiler #2 Boiler #1 Motor Mans House Generator House Dual Tandem Shale Shaker ShakedMud cleaner pits Centrifuges Desilter Desander Volume Pit IMud Lab I SDR 5/19/97 21-1/4", 2,000 PS' DIVERTER SCHEM -TIC Beluga River Unit $ Diverter Valve DO NOT SHUT IN DIVERTER AND VALVE AT THE SAME TIME UNDER ANY CIRCUMSTANCES MAINTENANCE & OPERATION 1. UPON INITIAL INSTALLATION: - CLOSE VALVE AND FILL PREVENTER WITH WATER TO ENSURE THAT THERE ARE NO LEAKS. - CLOSE PREVENTER TO VERIFY OPERATION AND THAT THE VALVE OPENS IMMEDIATELY. 2. CLOSE ANNULAR PREVENTER IN THE THE EVENT THAT AN INFLUX OF WELLBORE FLUIDS OR GAS IS DETECTED. OPEN VALVE TO ACHIEVE DIVERSION. 1. 20" CONDUCTOR. 2. WELD ON STARTING HEAD FLANGE. 3. RISER SPOOL 4. 13-5/8", 2,000 PS~. DRILLING SPOOL WITH ONE 10" OUTLET. 5. ONE 10" MASTER DIVERTER VALVE WITH 10" DIVERTER LINE. THE VALVE OPENS AUTOMATICALLY UPON CLOSURE OF ANNULAR PREVENTER. DIVERTER LINE WILL BE PLACED FOR OPTIMUM DIVERSION IN PREVAILING WIND CONDITIONS. 6. 21-1/4", 2000 PS~. ANNULAR PREVENTER. SDR 5/14/98 / 4-1/16" Barton ~-~ HCR Normally Closed 4-1/16 Barton,' Manual Normally Ope~ 6 4-1/16" Barton Manual Normally Open 4-1/16" Cameron HCR Normally Closed 13-5/8" 5 00n PSI. BOP STACK BELL'-GA RIVER UNIT ACCUMULATOR CAPACITY TEST 1. CHECK AND FILL ACCUMULATOR RESERVOIR TOPROPER LEVEL WITH HYDRAULIC FLUID. 2. ASSURE THAT ACCUMULATOR PRESSURE IS 3000 PSI. WITH 1500 PSI. DOWNSTREAM OF THE REGULATOR. 3. WHILE OBSERVING THE TIME, CLOSE ALL UNITS SIMULTANEOUSLY · RECORD THE TIME AND RECORD THE PRESSURE REMAINING AFTER ALL UNITS ARE CLOSED WITH CHARGING PUMP OFF. 4. RECORD ON THE IADC REPORT. THE ACCEPTABLE LOWER LIMIT IS 45 SECONDS CLOSING TIME AND 1200 PSI. OF REMAINING PRESSURE. BOPE STACK TEST 1. FILL BOP STACK AND MANIFOLD WITH WATER. 2. CHECK THAT ALL HOLD-DOWN SCREWS ARE FULLY RETRACTED. 3. CLOSE ANNULAR PREVENTER AND CHOKES AND BYPASS VALVES ON THE MANIFOLD. ALL OTHERS ARE LEFT OPEN. 4. TEST ALL COMPONENTS TO 250 PSI. AND HOLD FOR 3 MINUTES. INCREASE PRESSURE TO 3,000 PSI. AND HOLD FOR 3 MINUTES. BLEED TO 0 PSI. 5. OPEN ANNULAR PREVENTER, MAUNUAL, AND CHOKE LINE VALVES. 6. CLOSE TOP PIPE RAMS AND HCR VALVES ON KILL AND CHOKE LINES. 7. TEST TO 250 PSI. AND 3000 PSI AS IN STEP 4. CONTINUE TESTING ALL VALVES, LINES, AND CHOKES WITH A 250 PSI LOW AND 3000 PSI HIGH. TEST AS IN STEP 4. DO NOT PRESSURE TEST ANY CHOKE THAT IS NOT A FULL CLOSING POSITIVE SEAL CHOKE. 8. OPEN TOP PIPE RAMS AND CLOSE BO'FrOM PIPE RAMS. TEST BO'I-rOM PIPE RAMS AT 250 PSI & 3000 PSI FOR 3 MINUTES. 9. OPEN PIPE RAMS, BACKOFF RUNNING JOINT AND PULL OUT OF HOLE. CLOSE BLIND RAMS AND TEST TO 3000 PSI FOR 3 MINUTES. BLEED PRESSURE TO O PSI. 10. OPEN BLIND RAMS AND RECOVER TEST PLUG. MAKE SURE ALL VALVES ARE SET IN THE DRILLING POSITION. 11. TEST STANDPIPE VALVES TO 3000 PSI FOR 3 MINUTES. 12. TEST KELLY COCKS AND INSIDE BOP TO 3000 PS~ FOR 3 MINUTES. 13. RECORD TEST INFORMATION ON BLOWOUT PREVENTER TEST FORM. SIGN AND SEND TO DRILLING SUPERVISOR. 14. PERFORM COMPLETE BOPE TEST ONCE A WEEK AND FUNCTIONALLY OPERATE BOPE DAILY. 1. LANDING RING 2. 13-5/8", 5,000 PSI CASING HEAD. 3. 13-5/8", 5,000 PSI SPACER SPOOL(As NEEDED) 4. 13-5/8", 5,000 PSI SINGLE PIPE RAM. 5. 13-5/8", 5,000 PSi DRILLING SPOOL WITH CHOKE AND KILL LINES. 6. 13-5/8", 5,000 PSI DOUBLE RAM WITH PIPE RAMS ON TOP AND BLIND RAMS ON BOTTOM. 7. 13-5/8", 5,000 PSI ANNULAR PREVENTER. SDR 5/14/98 Sterling Alaska Drilling, Rig #1 5,000 psi Choke Manifold To Gas Buster 3" OCT Normally Open Pressure 2-1/16. WKM Sensors Hydraulic Choke 2" Cameron Normally Closed Normally Open Normally Open °~ 2-1/16" WKM Normally Open P ressu re Gauge i 2" Cameron Normally Closed OCT Manual Choke Normally Open 2" Cameron Normally Closed 0_>, Dischcarge Line 3" OCT Normally Closed ARCO Alaska, Inc. Structure : BRU Pad 212-35 Well : 212-55Tn Field : Beluga River Unit Location : Cook Inlet, Alaska I V 25O 25O 500 75O lOOO 1250 1500 1750 2000 2250 2500 2750 3O00 3250 3500 3750 4000 4250 4500 4750 ~ RrB Elevation: 91' KOP 2.50 5.00 7.50 DLS: 2.50 deg per 100 ft 10.00 12.50 Begin Turn to Target 13.49 14.66 16.1,3 17,82 19.68 21.67 £0C 560 480 i I i i <- Wesf (feet) 400 320 240 160 t I I I I I I EsUmoted Surface Locetion: 1485' FNL, 686' FWL Sec. 35, T13N, RIOW, SM Begin Turn to Begin Turn & Drop TARGET - T/ Sterling_ Target #1 Location: 1898' FNL, 265' FWL Sec. 35, T13N, RIOW, SM TARGET - T/ Steding TARGET - T/ Beluga itl3 - 9 5/8 Casing Pt TARGET - T/ Beluga 22.06 Begin Turn & Drop 20.61 19.16 17.75 16.31 14.90 15.51 12.15 10.82 9.74 TO - 9 5/8 Casing Pt _,~[_~ 5000 s r i, ~ ~ I m m~ 25o o 250 soo 750 lOOO Vertical Section (feet) -> DLS: 1.50 de9 per 100 ft Paint 'fie on KOP Begin Turn I~d of Build/Turn End of Hold Target Target T.O. ~t Fnd of Hold TO Location: 2172' FNL, 164' FWL Sec. 35. T13N, RIOW, SMJ WELL MD Inc 0.00 0.00 825.00 0.00 154-5.00 13.00 1943.41 22.56 2265.25 22.56 3184.96 9.74 3692.27 9.74 4909.83 9.74 PROFILE DATA 0 o 80 160 24-0 O --m- 320 400 480 V 560 64o 720 Dir WD North East V. Sect Oe9/1 O0 0.00 0.00 0.00 0.00 0.00 0.00 260.00 825.00 O.O0 O.O0 O.O0 0.00 260.00 1340.55 -- 10.20 -57.85 48.40 2.50 220.20 1911.64 --110.14 -199.04 219.15 2.50 220.20 2208.84 -204_4-6 -278.76 342.12 0.00 200.27 3091.00 -413.17 -4-20.27 589.36 1.50 200.27 3591 i00 -493.67 -450.01 666.99 0.00 200.27 4791.00 -656.92 -521.38 853.57 0.00 ~lmulh ~)5.4§ with relerence 0.00 ~, 0.00 ff frem slot ~t~t~-3e, Twln tCreoted by jones For: S Re3molds Oote plot~ed : ~l-J~--g~ Plot Refer~ce is 212-~ T~in Vers. ~4. C~rd[n~ ere in fe~ ~efe~nce sl~ ~212-3~n. T~e Vc~l O~ths~ ~mated ~. Oot~ plotted : 2~--Jul-98 Plot Reference is 212-35 Twin Vers. ~4. ARCO Alaska, Inc. Structure : BRU Pad 212-35 Well : 2~2-.~5Tn Field : Beluga River Unit Location : Cook Inlet, Alosko 60 50 Q~ 20 (- 30 -i.- 0 I Y 50 6O 70 8O 90 100 110 120 150 <- West (feet) 130 120 110 100 90 80 70 60 50 4-0 ..30 20 10 0 10 i i Ii ii Ii ii ii ii ii ii ii ii ii ii I i ~ 1800 21001. ~ 1600 -u --~-800 i i i i i i i i i i [ i i [ i i ~o ,~o ,,o ,~o ~'o ~'o /o ~'o ~'o'.'o ~'o ~'o ;o o ;o <- West (feet) 5O ,tO 30 20 20 0 (- ,-i- so ~. --4.- y lO0 110 120 1.30 ARCO Alaska, Inc. BRU Pad 212-35,212-35Tn Beluga River Vnit,Cook Inlet, Alaska Measured Inclin. Azimuth True Vert R B C T A N G U L A R Depth Degrees Degrees Depth C O O R D I N A T E S PROPOSAL LISTING Page 1 Your ref : 212-35 Twin Vets. 94 Last revised ~ 21-Jul-98 Dogleg Vert Deg/100ft Sect 0.00 0.00 0.00 0.00 1484.71 S 685.69 R 0.00 0.00 100.00 0.00 260.00 100.00 1484.71 S 685.69 E 0.00 0.00 200.00 0.00 260.00 200.00 1484.71 S 685.69 E 0.00 0.00 300.00 0.00 260.00 300.00 1484.71 S 685.69 E 0.00 0.00 400.00 0.00 260.00 400.00 1484.71 S 685.69 E 0.00 0.00 500.00 0.00 260.00 SO0.O0 1484.71 S 685.69 E 0.00 0.00 600.00 0.00 260.00 600.00 1484.71 S 685.69 g 0.00 0.00 700.00 0.00 260.00 700.00 1484.71 S 685.69 E 0.00 0.00 800.00 0.00 260.00 800.00 1484.71 S 685.69 E 0.00 0.00 825.00 0.00 260.00 825.00 1484.71 S 685.69 E 0.00 0.00 925.00 2.50 260.00 924.97 1485.09 S 683.54 E 2.50 1.80 1025.00 5.00 260.00 1024.75 1486.23 S 677.10 g 2.50 7.19 1125.00 ?.50 260.00 1124.14 1488.12 S 666.38 g 2.50 16.16 1225.00 10.00 260.00 1222.97 1490.76 S 651.40 ~ 2.50 28.69 1325.00 12.50 260.00 1321.04 1494.15 S 632.19 E 2.50 44.76 1345.00 13.00 260.00 1340.55 1494.92 S 627.84 E 2.50 48.40 1400.00 13.49 254.38 1394.09 1497.72 S 615.57 E 2.50 59.11 1500.00 14.66 245.28 1491.10 1506.15 S 592.85 E 2.50 81.23 1600.00 16.13 237.65 1587.52 1518.87 S 569.62 g 2.50 106.72 1700.00 17.82 231.34 1683.17 1535.87 S 545.94 E 2.50 135.52 KOP Begin Turn to Target 1800.00 19.68 226.15 1777.86 1557.10 S 521.84 E 2.50 167.59 1900.00 21.67 221.84 1871.42 1582.52 S 497.37 E 2.50 202.86 1943.41 22.56 220.20 1911.64 1594.86 S 486.65 E 2.50 219.15 E0C 2000.00 22.56 220.20 1963.90 1611.44 S 472.63 E 0.00 240.78 2265.25 22.56 220.20 2208.84 1689.17 S 406.93 E 0.00 342.12 Begin Turn & Drop 2300.00 22.06 219.87 2240.99 1699.27 S 398.45 E 1.50 355.25 2400.00 20.61 218.82 2334.14 1727.40 S 375.38 E 1.50 391.42 2500.00 19.16 217.61 2428.17 1754.12 S 354.33 E 1.50 425.16 2600.00 17.73 216.22 2523.03 1779.40 S 335.31 E 1.50 456.45 2700.00 16.31 214.59 2618.65 1803.25 S 318.34 g 1.50 485.27 2800.00 14.90 212.67 2714.96 1825.63 S 303.43 R 1.50 511.59 2900.00 13.51 210.35 2811.90 1846.54 S 290.59 E 1.50 535.41 3000.00 12.15 207.52 2909.40 1865.95 S 279.82 g 1.50 556.69 3100.00 10.82 204.00 3007.40 1883.86 S 271.14 E 1.50 575.44 3184.95 9.74 200.2? 3090.99 1897.89 S 265.41 E 1.50 589.36 3184.96 9.74 200.27 3091.00 1897.89 S 265.41 E 1.50 589.36 3201.04 9.74 200.27 3106.84 1900.44 S 264.47 E 0.00 591.82 3301.04 9.74 200.27 3205.40 1916.30 S 258.61 E 0.00 607.12 3401.04 9.74 200.27 3303.96 1932.17 S 252.75 g 0.00 622.42 3501.04 9.74 200.27 3402.52 1948.04 S 246.89 E 0.00 637.72 3601.04 9.74 200.27 3501.08 1963.90 S 241.03 E 0.00 653.03 3692.26 9.74 200.27 3590.99 1978.38 S 235.68 g 0.00 666.99 3692.27 9.74 200.27 3591.00 1978.38 S 235.68 E 0.00 666.99 4000.00 9.74 200.27 3894.29 2027.23 S 217.64 E 0.00 714.10 4500.00 9.74 200.27 4387.08 2106.59 S 188.33 E 0.00 790.64 TARGET - T/ Sterllng TARGET - T/ Beluga 4909.83 9.74 200.27 4791.00 2171.64 S 164.31 E 0.00 853.37 TI) - 9 5/8' Casing Pt All data is in feet unless otherwise stated. Coordinates from NW Corner of Sec. 35, T13N, R10W SM and TVD from Estimated RKB (91.00 Ft above mean sea level). Bottom hole distance is 862.38 on azimuth 217.20 degrees from wellhead. Total Dogleg for wellpath is 41.76 degrees. Vertical section is from wellhead on azimuth 225.49 deG~-ees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ ARCO Alaska; Inc. BRU Pad 212-35,212-35Tn Beluga River Unit,Cook Inlet, Alaska PROPOSAL LISTING Page 2 Your reS ; 212-35 Twin Vets. 94 Last revised ; 21-Jul-98 Comments in we11path MD TFD Rectangular Coords. Comment 825.00 825.00 1484.71 1345.00 1340.55 1494.92 1943.41 1911.64 1594.86 2265.25 2208.84 1689.17 3184.95 3090.99 1897.89 3692.26 3590.99 1978.38 4909.83 4791.00 2171.64 685.69 E KOP 627.84 E Begin Turn to Target 486.65 EEOC 406.93 Z Begin Turn & Drop 265.41 E TARGET - T/ Sterling 235.68 E TARGET - T/ Beluga 164.31 E TD - 9 5/8' Casing Pt Casing positions in string Top MD Top TVD Rectangular Coords. Bot MD Bot TVD Rectangular Coorc~s. Casing 0.00 0.00 1484.71S 685.69E 2265.25 2208.84 1689.17S 406.93E 13 3/8N Casing 0.00 0.00 1484.71S 685.69E 4909.83 4791.00 2171.64S 164.31E 9 Targets associated with th/s we11path =_- ==5 5------==-- Target name Geographic Location T.V.D. Rectangular Coordinates Revised We11#1 TD 11-Feb-98 318065.000,2623000.000,999.00 4791.00 2152.48S 167.42E 1?-Dec-9? Ne11#1 T/ Sterlincj R 318167.000,2623253.000,999.00 3091.00 1897.89S 265.42E 16-Dec-97 Well#1 T/ Belug& 11- 318136.000,2623173.000,999.00 3591.00 1978.37S 235.68E 17-De=-97 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage Alaska 99501-3192 ac: THE APPLICATION OF ARCO ) ALASKA, INC. for an order granting ) an exception to spacing requirements of ) 20 AAC 25.055 to provide for the drilling ) of thc Beluga Rivcr Unit 212-35 gas ) production well in the Beluga River Unit. ) Conservation Order No. 424 ARCO Alaska. Inc. Beluga River Unit Mav 15. 1998 IT APPEARING THAT: . ARCO Alaska. Inc. submitted an application dated March 5. 1998 requesting exception to the well spacing provisions of 20 AAC 25.055(a)(4) to allow drilling the ARCO Beluga River Unit 212-35 gas production well to a location within 1500 feet ora section line. Thc Commission published notice of opportunity for public hearing in the Anchorage Dailv Ncws on April 15. 1998 pursuant to 20 AAC 25.540. 3. No protcsts to the application were received. FINDINGS: Thc Beluga Rivcr Unit 212-35 gas production well will be drilled as a deviated hole with a surface location 1404' from thc north line and 4557' from thc cast line of Section 35, T13N, R I()W. Seward Meridian (SM) and a proposed bottomholc location 2153' from thc north line and 165' from thc west line of Section 35. T13N, R10W. SM. Offset owncrs ARCO Beluga. Inc.. Chevron USA Inc., Municipal Light and Power and the Statc of Alaska havc bccn duly notified. An cxccption to thc wcll spacing provisions of 20 AAC 25.055(a)(4) is necessary to allow the drilling of this well. CONCLUSION: Granting a spacing cxccption to allow drilling of the ARCO Beluga River Unit 212-35 gas production xvcll will not rcsult in waste nor jcopardizc correlative rights. Conservation Order No.-._4 Mav 15, 1998 Page 2 NOW, THEREFORE, IT IS ORDERED: ARCO Alaska. Inc.'s application for cxception to thc well spacing provisions of 20 AAC 25.055(a)(4) for the purpose of drilling thc ARCO Bcluga Rivcr Unit 212-35 gas production wcll is approved. DONE at Anchorage, Alaska and dated May 15. 1998. . Robert N. Christcnson. P.E.. Commissioncr Cammy Oech~j, ~ommissioncr :kS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person aflbcled bv it may file with the Commission an application for rehea~ing. A request lbr rehearing must be received by 4:30 PM on the 23~a dav t:ollowing the date of the order, or next working day ifa holiday or weekend, to be timely filed. The Conuni~qion shall grant or retiree the application in whole or m part within 10 days. The Conmfission can refuse an application by not acting on it within the 10-day period. An affected person has 30 days from the dale the Commission rethses the application or mails (or otherxvise distributes) an order upon rehearing. both being the final order of the Commissiom to appeal the decision to Superior Court. \Vhere a request for rehearing is denied by nonaction of the Commission. the 30-day period lbr appeal to Superior Court runs fi-om the date on which thc request is deemed denied (i.e.. 10th Stix,' after the application for rehearm~ w,'c~ filed). . WELL PERMIT CHECKLIST FIELD & POOL ----Y~ðð ADMINISTRATION ~ ~}1B -- GEOLOGY IWf)R 4'9A T1 -/ 6fL-é{~ ANNULAR DISPOSAL APPR DATE ----- -- (\1 COMPANY INIT CLASS 2- 70-<' WELL NAME GEOLAREA PROGRAM: exp 0 dev redrll 0 serv 0 wellbore seg II ann. disposal para req II ;? ...2 (') UNIT# SO 2...2 -C') ON/OFF SHORE (3 Yt.J 1. Permit fee attached. . . . . . . . . . . . . . . . . . . . . . . 2. Lease number appropriate. . . . . . . . . . . . . . . . . . . 3. Unique well name and number. .. . . . . . . . . . . . . . . . 4. Well located in a defined pool.. . . . . . . . . . . . . . . . . 5. Well located proper distance from drilling unit boundary. . . . 6. Well located proper distance from other wells.. . . . . . . . . 7. Sufficient acreage available in drilling unit.. . . . . . . . . . . 8. If deviated, is wellbore plat included.. . . . . . . . . . . . . . 9. Operator only affected party.. . . . . . . . . . . . . . . . . . 10. Operator has appropriate bond in force. . . . . . . . . . . . . 11. Permit can be issued without conservation order. . . . . . . . 12. Permit can be issued without administrative approval.. . . . . 13. Can permit be approved before 15-day wait.. . . . . . . . . . 14. Conductor string provided. . . . . . . . . . . . . . . 15. Surface casing protects all known USDWs. . . . . . . 16. CMT vol adequate to circulate on conductor & surf csg. . . . . 17. CMT vol adequate to tie-in long string to surf csg. . . 18. CMT will cover all known productive horizons. . . . . . 19. Casing designs adequate for C, T, B & permafrost. . . . . . . 20. Adequate tankage or reserve pit.. . . . . . . . . . . . . . . . 21. If a re-drill, has a 10-403 for abandonment been approved. . . 22. Adequate wellbore separation proposed.. . . . . . . . . . . . 23. If diverter required, does it meet regulations. . . . . . . . . . 24. Drilling fluid program schematic & equip list adequate. . . . . 25. BOPEs, do they meet regulation. . . . . . . " . . . . . . . . 26. BOPE press rating appropriate; test to ~ 000 psig. 27. Choke manifold complies w/API RP-53 (May 84). . . . . . . . 28. Work will occur without operation shutdown. . . . . . . . . . . 29. Is presence of H2S gas probable.. . . . . . . . . . . . . . . . Y N ;~. ~ermit can bt ~ssued ~/o/rdrogen sulfide measures. . . A" ~ CfN ~ 32: s:::~~e:~~I;Si~~lsoh:170~ ;::~~~:~~r~ ~~n~~ : : : : : ". '. N M fl- ~ 33. Seabed condition survey (if off-shore). . . . . . . . . . . . . Y N 34. Contact name/phone for weekly progress reports. . . ... Y N [exploratory only] 35. With proper cementing records, this plan (A) will contain waste in a suitable receiving zone; . . . . . . . (B) will not contaminate freshwater; or cause drilling waste. .. to surface; (C) will not impair mechanical integrity of the well used for disposal; Y N (D) will not damage producing formation or impair recovery from a Y N pool; and (E) will not circumvent 20 AAC 25.252 or 20 AAC 25.412. G&: EN~~ UIC/An~ COMMI~ RP ~gH" WMW~ õ\ q 'ð ~~¿ f3k/o CO !/~, ú;)" ~ .;Ó~ M.cheklist revaS/29/98 rtl r: c. \rnsorrice\wor dinn\dim1tl\d1(~ch Ii!, I ------~-_._._--_._-_._._-------- Qð N . Ç]N J - ~ ) ~~~t2:~~:~~ &~ ~lC~;~~:~Z:;;7- ~j ~,~~~ Y~ C, 0, ~ c¡ ~#c>doe/- ÆÆ- .1/'2j?9 ~~ Y N ~~ ~ ¡Vfl c..\Cecl ~ Mc..-c..-z:..o f,8O\~ 26r 1-/60 ~ 'GJ('O... /Oc) (j.^~wQr P..ô bJ.aWt, d41(~ Po.u...t 9j'e..t'8 ~Q" t7" nt,.,.. p 1ðT::~.st.. I:r 6 ~~ é.. J C6.¥r"3 Ce~i"~ ~"~ 2 J) ~ Tit Jòl>? . ' L?iV4J~ S c::heM..--+~ t.t:: S- O (Ie,... ( \C. (I~ t- {,~ 1'l e1 r o..dø- (J.dw '"\ú1 / ( -_--..:...-.-_------_\ ~---~----'-"'-"--'------- Y N Y N J\J I A . \IO"? J?-t:: n "'~~ ~k "p.d.vcL JIJ ~'" Sç~ þQ;J$e ¿ L~~ Ccy , I~;~,.,. , ; Y N Com mentsll nstructions: -----