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Home My WebLink About219-180Originated: Delivered to:19-Feb-25Halliburton Alaska Oil and Gas Conservation Comm.Wireline & Perforating Attn.: Natural Resource TechnicianAttn: Fanny Haroun 333 West 7th Avenue, Suite 1006900 Arctic Blvd. Anchorage, Alaska 99501Anchorage, Alaska 99518Office: 907-275-2605FRS_ANC@halliburton.comThe technical data listed below is being submitted herewith. Please address any problems orconcerns to the attention of the sender aboveWELL NAME API # SERVICE ORDER # FIELD NAME JOB TYPE DATA TYPE LOGGING DATE PRINTS # DIGITAL # E SET#1 3Q-10 50-029-21675-00 909817087 Kuparuk River Plug Setting Record Field- Final 30-Jan-25 0 12 3R-107 50-029-23660-00 909821694 Kuparuk River Multi Finger Caliper Field & Processed 25-Jan-25 0 1345678910PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF:Fanny Haroun, Halliburton Wireline & Perforating, 6900 Arctic Blvd., Anchorage, AK 99518FRS_ANC@halliburton.comDate:Signed:Transmittal Date:T40124T40125186-187219-1802/20/2025Gavin GluyasDigitally signed by Gavin Gluyas Date: 2025.02.20 11:47:07 -09'00'3R-10750-029-23660-00 909821694Kuparuk RiverMulti Finger CaliperField & Processed25-Jan-2501219-180 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.govNovember 13, 2024 Mr. Doug McMullen Production Engineer Specialist ConocoPhillips Alaska, Inc. PO Box 100360 Anchorage, AK 99510-0360 RE: No-Flow Verification Kuparuk River Unit 3R-107 PTD 2191800 Dear Mr. McMullen: On September 26, 2024 an Alaska Oil and Gas Conservation Commission (AOGCC) Petroleum Inspector witnessed a no-flow test of Kuparuk River Unit 3R-107. The AOGCC Inspector confirmed that the proper test equipment was rigged up prior to the test as outlined in AOGCC Industry Guidance Bulletin 21-001. The test procedure employed was a 1 hour shut in period to monitor pressure build up followed by a short flow period through the test equipment to an open top tank – repeated two additional times. There was no oil flow to surface. Observed gas rates when opened to flow dropped from an initial rate exceeding 1500 scf/hr to less than 900 scf/hr within 15 minutes. Kuparuk River Unit 3R-107 may be produced without a subsurface safety valve as confirmed by the AOGCC Inspector at the conclusion the test. A fail-safe automatic surface safety valve system capable of preventing uncontrolled flow must be maintained in proper working condition in this well as required in 20 AAC 25.265. The subsurface safety valve must be returned to service if Kuparuk River Unit 3R-107 demonstrates an ability to flow unassisted to surface. Any cleanout, perforating or other stimulation work in this well will necessitate a subsequent no-flow test. Please retain a copy of this letter in the Kuparuk River Unit field office. Sincerely, James B. Regg Petroleum Inspection Supervisor ecc: P. Brooks AOGCC Inspectors doug.mcmullen@conocophillips.com James B. Regg Digitally signed by James B. Regg Date: 2024.11.14 09:42:29 -09'00' 2024-0926_No-Flow_KRU_3R-107_ksj Page 1 of 4 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: 09/26/2024 P. I. Supervisor FROM: Kam StJohn SUBJECT: No Flow Test Petroleum Inspector KRU 3R-107 ConocoPhillips Alaska Inc. PTD 2191800 09/26/2024: I traveled to KRU 3R-107 and met with Joey Foshaug (CPAI representative) for the no-flow test. We discussed the options for testing and confirmed CPAI will use the flow meter method described in Guidance Bulletin 21-001. We inspected the rig up: 1-inch hose and piping for good flow through the meter and for pressure bleed-off; appropriate digital gauge and low-flow meter. I verified the equipment calibration dates were current. KRU 3R-107 had been shut in prior to commencing bleed-down of pressure from 18:00 09/25/2024 until the 09:00 09/26/2024. The following table shows test details: Time Pressures1 Flow Rate2 Remarks (psi) Gas – scf/hr Liquid – gal/hr 09:00 0 / 0 / 260 - - Initial pressure before shut in 09:15 2.8 / 1.5 / 260 - - 09:30 5.2 / 2.9 / 260 - - 09:45 7.4 / 4.9 / 260 - - 10:00 9.3 / 6.9 / 260 300 0 Open to bleed 10:05 3.3 / 1.9 / 260 600 0 10:10 2.1 / 0 / 260 900 0 10:15 1.7 / 0 / 260 200 0 10:20 2.1 / 0 / 260 175 0 Shut in for pressure build-up 10:35 4 / 1.7 / 260 - - 10:50 6.5 / 3.3 / 260 - - 11:05 8.1 / 5.6 / 260 - - 11:20 9.9 / 7.4 / 260 1500+ 0 Open to bleed 11:25 3.6 / 2.0 /260 1500+ 0 11:30 2.0 / 0/ 260 1000 0 11:35 1.7 / 0 / 260 400 0 11:40 2.3 / 0 / 260 -` - Shut In 11:55 4.2 / 1.4 / 260 - - 12:10 6.3 / 3.1 / 260 - - 12:25 8.3 / 5.1 / 260 - - 9 9 9 9 9 9 9 James B. Regg Digitally signed by James B. Regg Date: 2024.11.13 11:06:56 -09'00' 2024-0926_No-Flow_KRU_3R-107_ksj Page 2 of 4 Time Pressures1 Flow Rate2 Remarks (psi) Gas – scf/hr Liquid – gal/hr 12:40 9.7 / 6.6 / 260 1500+ 0 Open to bleed 12:45 3.3 / 1.5 / 260 1500+ 0 12:50 2.3 / 0 / 260 800 0 13:55 2.2 / 0 / 260 300 0 13:00 2.0 / 0 / 260 150 0 Shut in; end test 1 Pressures are T/IA/OA 2 Gas flow not to exceed 900 scf/hr; Liquid flow not to exceed 6.3 gal/hr This test shows that KRU 3R-107 will not sustain flow to surface without assistance. Attachments: Photos 9 9 2024-0926_No-Flow_KRU_3R-107_ksj Page 3 of 4 No-Flow Test – KRU 3R-107 (PTD 2191800) Photos by AOGCC Inspector K. StJohn 9/26/2024 2024-0926_No-Flow_KRU_3R-107_ksj Page 4 of 4 Some people who received this message don't often get email from n1223@conocophillips.com. Learn why this isimportant From:Regg, James B (OGC) To:AOGCC Records (CED sponsored) Subject:FW: Removed K-valve on well 3R-107 (PTD# 219-180-0) Date:Monday, August 29, 2022 9:11:18 AM Attachments:image001.png Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: CPF3 Prod Engrs <n1223@conocophillips.com> Sent: Friday, August 26, 2022 6:04 PM To: Regg, James B (OGC) <jim.regg@alaska.gov>; Lewis, Brian M <Brian.M.Lewis@conocophillips.com> Cc: NSK Prod Engr Specialist <n1139@conocophillips.com>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; CPF3 DS Lead Techs <n1105@conocophillips.com>; Braun, Michael <Michael.Braun@conocophillips.com> Subject: Removed K-valve on well 3R-107 (PTD# 219-180-0) Mr. Regg, The K-valve on production well 3R-107 (PTD# 219-180-0) was pulled on 08/25/2022 in preparation for the No-Flow Test mentioned below. The K-valve status has been recorded in the “Drill Site Defeated Safety Device Log.” The well was brought online the same day (08/25/2022) and will be produced for ~7-10 days to allow the well to stabilize prior to the No-Flow Test. We will request a date to perform the test and we will notify the AOGCC at least 48 hours in advance of any changes to the plan The well is currently online taking ~1,600 MCFD of lift gas and producing ~850 BLPD at a flowing tubing pressure of 195 psi. Please let me know if you have any questions, Brian Lewis Senior Production Engineer – CPF3 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. Some people who received this message don't often get email from brian.m.lewis@conocophillips.com. Learn whythis is important Phone: (907) 263-4535 | Cell: (918) 521-8990 From: Regg, James B (OGC) <jim.regg@alaska.gov> Sent: Monday, August 1, 2022 9:55 AM To: Lewis, Brian M <Brian.M.Lewis@conocophillips.com> Cc: NSK Prod Engr Specialist <n1139@conocophillips.com>; CPF3 Prod Engrs <n1223@conocophillips.com>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Subject: [EXTERNAL]RE: 3R-107 No Flow Test Procedure CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. No-Flow Test procedure is consistent with Guidance Bulletin 21-001 and approved. Thank you for including the supporting info. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Lewis, Brian M <Brian.M.Lewis@conocophillips.com> Sent: Thursday, July 28, 2022 11:46 AM To: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; NSK Prod Engr Specialist <n1139@conocophillips.com>; CPF3 Prod Engrs <n1223@conocophillips.com> Subject: 3R-107 No Flow Test Procedure Victoria, Please see the attached procedure for the KRU 3R-107 (PTD 219-180-0) no flow test for approval. Upon procedure approval, we will request a date to perform the test and we will notify the AOGCC at least 48 hours in advance of any changes to the plan. The only offset injector to 3R-107 is 3R-106. Injection history for 3R-106 can be found in the included attachment. Please let me know if there is any additional information required to receive procedural approval. 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Measured liquid production is not greater than 6.3 gallons per hour (GPH) and the measured gas production is not greater than 900 standard cubic feet per hour (SCFH). The following procedure outlines how this will be accomplished. Pre-Work x 72+ hours prior to no flow test o Slickline to pull K-valve from well and BOL to allow well to stabilize x 72 hours prior to no flow test o Verify operability of low-pressure gauge and flow meter ERDCO Armor-Flo flowmeter is in the SVS Tech office at Kuparuk Meter is ¾” female NPT on both ends and can be threaded on after the well is bled off, as this is piece of equipment is only rated to 400 PSI Meter was calibrated 10/2021 by the manufacturer Meter reads a range of 0-1500 SCFH x 48 hours prior to no flow test o Notify AOGCC of no flow test (NSK Production Technician) o Stage tanks for no flow test at 3R pad o Relocate meter to 3R and connect wireless gauge into SCADA Verify tags are appropriately reading into IP.21 Meter should be kept warm and protected x 24-48 hours prior to no flow test o Shut in well (CPF3 Operations) o Rig up the following piping Hardline from IA to tank and 1” hose to meter 1” hose from treecap to hardline and NFT meter 1” hose from IA to meter Hardline from meter to tank o Bleed tubing and IA pressures to open top tank (CPF3 Operations) Leave flow path open to atmosphere 9 9 9 9 9 9 9 3R-107 No Flow Test Procedure Revision 1 Page 2 of 5 Day of the Test: 1. Verify install test equipment downstream of IA and Tubing (NSK SVS Technicians) a. Orifice flowmeter b. ERDCO Armor-flo Flowmeter c. Low pressure local gauge off tree cap d. ¼ turn full open ball valve e. Hose to atmospheric tank 2. Conduct pre job discussion in control room at DS3R a. Personnel onsite: i. AOGCC Representative ii. SVS Technicians iii. Operations Representative 3. Record initial tubing (T), inner annulus (IA), and outer annulus (OA) pressures. Record duration of pre-test bleed period. 4. Begin test by shutting in all bleeds on well a. Monitor pressure buildup by recording T, IA, and OA pressures every 15 minutes 5. After one hour, open well to flow through ERDCO meter a. Document flow rates & well pressures (T, IA, OA) at 5-minute increments until the rate has declined to below the acceptance criteria, not to exceed 30 minutes 6. Repeat the shut-in/flow monitoring steps (steps 5 & 6) at least two times 7. Test acceptance: a. Flow rates not exceeding 6.3 gallons per hour liquid and 900 standard cubic feet per hour gas demonstrated by at least 2 consecutive flow monitoring periods 8. AOGCC inspector to evaluate test data & inform on pass/fail decision 9. If test passes: a. BOL following normal 3R-107 startup procedure b. Normal up SVS system 10. If test fails: a. Leave well SI pending wellwork b. Normal up SVS system 9 9 9 9 3R-107 No Flow Test Procedure Revision 1 Page 3 of 5 Images of No Flow Testing Equipment 3R-107 No Flow Test Procedure Revision 1 Page 4 of 5 3R-107 No Flow Test Procedure Revision 1 Page 5 of 5 Appendix A No Flow Test Setup in AOGCC Guidance Bulletin 10-004 Note: AOGCC Guidance Bulletin 21-001 supersedes 10-004, but does not include diagram shown below ϬϱϬϬϭϬϬϬϭϱϬϬϮϬϬϬϮϱϬϬϯϬϬϬϯϱϬϬϵͬϭϰͬϮϬϭϵϭϬͬϭϰͬϮϬϭϵϭϭͬϭϰͬϮϬϭϵϭϮͬϭϰͬϮϬϭϵϭͬϭϰͬϮϬϮϬϮͬϭϰͬϮϬϮϬϯͬϭϰͬϮϬϮϬϰͬϭϰͬϮϬϮϬϱͬϭϰͬϮϬϮϬϲͬϭϰͬϮϬϮϬϳͬϭϰͬϮϬϮϬϴͬϭϰͬϮϬϮϬϵͬϭϰͬϮϬϮϬϭϬͬϭϰͬϮϬϮϬϭϭͬϭϰͬϮϬϮϬϭϮͬϭϰͬϮϬϮϬϭͬϭϰͬϮϬϮϭϮͬϭϰͬϮϬϮϭϯͬϭϰͬϮϬϮϭϰͬϭϰͬϮϬϮϭϱͬϭϰͬϮϬϮϭϲͬϭϰͬϮϬϮϭϳͬϭϰͬϮϬϮϭϴͬϭϰͬϮϬϮϭϵͬϭϰͬϮϬϮϭϭϬͬϭϰͬϮϬϮϭϭϭͬϭϰͬϮϬϮϭϭϮͬϭϰͬϮϬϮϭϭͬϭϰͬϮϬϮϮϮͬϭϰͬϮϬϮϮϯͬϭϰͬϮϬϮϮϰͬϭϰͬϮϬϮϮϱͬϭϰͬϮϬϮϮϲͬϭϰͬϮϬϮϮϳͬϭϰͬϮϬϮϮϯZͲϭϬϲtĂƚĞƌ/ŶũĞĐƚŝŽŶsŽůƵŵĞ Originated: Delivered to:20-Jun-22Halliburton Alaska Oil and Gas Conservation Comm.Wireline & Perforating Attn.: Natural Resource TechnicianAttn: Fanny Haroun 333 West 7th Avenue, Suite 1006900 Arctic Blvd. Anchorage, Alaska 99501Anchorage, Alaska 99518Office: 907-275-2605FRS_ANC@halliburton.comThe technical data listed below is being submitted herewith. Please address any problems orconcerns to the attention of the sender aboveWELL NAME API # SERVICE ORDER # FIELD NAME JOB TYPE DATA TYPE LOGGING DATE PRINTS #DIGITAL #1 1D-135 50-029-22816-00 n/a Kuparuk River Packer Setting Record Field- Final 9-Jun-22 0 12 1F-03A 50-029-20853-60 907799903 Kuparuk River Multi Finger Caliper Field & Processed 9-Apr-22 0 13 1H-103 50-029-23593-00 n/a Kuparuk River Leak Detect Log Field- Final 3-Jun-22 0 14 1H-103 50-029-23593-00 n/a Kuparuk River Leak Detect Log Field- Final 4-Jun-22 0 15 1H-103 50-029-23593-00 n/a Kuparuk River Multi Finger Caliper Field & Processed 3-Jun-22 0 16 1H-104 50-029-23610-00 n/a Kuparuk River Leak Detect Log Field- Final 6-Jun-22 0 17 1H-104 50-029-23610-00 n/a Kuparuk River Multi Finger Caliper Field & Processed 7-Jun-22 0 18 2M-33 50-029-22816-00 n/a Kuparuk River Packer Setting Record Field- Final 15-May-22 0 19 3R-107 50-029-23660-00 n/a Kuparuk River Packer Setting Record Field- Final 20-May-22 0 110PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF:Fanny Haroun, Halliburton Wireline & Perforating, 6900 Arctic Blvd., Anchorage, AK 99518FRS_ANC@halliburton.comDate:Signed:Transmittal Date: 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:CPF3 Prod Engrs To:Regg, James B (OGC) Cc:Well Integrity Specialist CPF1 & CPF3;NSK Prod Engr Specialist;NSK Optimization Engr;CPF3 Ops Supv;CPF3 DS Lead Techs;Braun, Michael (Alaska) Subject:RE: Removed K-valve on well 3R-107 (PTD# 219-180-0) Date:Friday, May 20, 2022 10:58:15 PM Attachments:image001.png Mr. Regg, The K-valve on production well 3R-107 (PTD# 219-180-0) was re-installed today (05/20/2022). The K-valve status has been recorded in the “Drill Site Defeated Safety Device Log.” We are in the process of bringing the well back online and it is currently taking ~1,300 MCFD of lift gas at a flowing tubing pressure of 625psi and dropping. Thank you, Brian Lewis Senior Production Engineer – CPF3 Phone: (907) 263-4535 | Cell: (918) 521-8990 From: CPF3 Prod Engrs Sent: Monday, May 9, 2022 8:42 AM To: Regg, James B (CED) <jim.regg@alaska.gov> Cc: Well Integrity Specialist CPF1 & CPF3 <n1617@conocophillips.com>; NSK Prod Engr Specialist <n1139@conocophillips.com>; NSK Optimization Engr <n2046@conocophillips.com>; CPF3 Ops Supv <n2070@conocophillips.com>; CPF3 DS Lead Techs <n1105@conocophillips.com>; Braun, Michael (Alaska) <Michael.Braun@conocophillips.com> Subject: Removed K-valve on well 3R-107 (PTD# 219-180-0) Mr. Regg, The K-valve on production well 3R-107 (PTD# 219-180-0) was pulled on 05/06/2022 as part of a Coil Tubing job to mill through a hydrate plug and cleanout the mainbore. The K-valve status has been recorded in the “Drill Site Defeated Safety Device Log.” Due to the potential for fill flowback after the cleanout, the well was brought online on 05/07/2022 without the K-valve for a short duration cleanup period. We currently have the K-valve re-installation scheduled for 05/12/2022, and I will notify all those included in this notice when the work is 9 9 -5HJJ 3R-107 (PTD# 219-180-0) completed. The well is currently online taking ~1,600 MCFD of lift gas and producing ~1,300 BLPD at a flowing tubing pressure of 300 psi. Please let me know if you have any questions, Brian Lewis Senior Production Engineer – CPF3 Phone: (907) 263-4535 | Cell: (918) 521-8990 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:Regg, James B (OGC) To:AOGCC Records (CED sponsored) Subject:FW: Removed K-valve on well 3R-107 (PTD# 219-180-0) Date:Monday, May 9, 2022 11:16:13 AM Attachments:image001.png Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: CPF3 Prod Engrs <n1223@conocophillips.com> Sent: Monday, May 9, 2022 8:42 AM To: Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Well Integrity Specialist CPF1 & CPF3 <n1617@conocophillips.com>; NSK Prod Engr Specialist <n1139@conocophillips.com>; NSK Optimization Engr <n2046@conocophillips.com>; CPF3 Ops Supv <n2070@conocophillips.com>; CPF3 DS Lead Techs <n1105@conocophillips.com>; Braun, Michael (Alaska) <Michael.Braun@conocophillips.com> Subject: Removed K-valve on well 3R-107 (PTD# 219-180-0) Mr. Regg, The K-valve on production well 3R-107 (PTD# 219-180-0) was pulled on 05/06/2022 as part of a Coil Tubing job to mill through a hydrate plug and cleanout the mainbore. The K-valve status has been recorded in the “Drill Site Defeated Safety Device Log.” Due to the potential for fill flowback after the cleanout, the well was brought online on 05/07/2022 without the K-valve for a short duration cleanup period. We currently have the K-valve re-installation scheduled for 05/12/2022, and I will notify all those included in this notice when the work is completed. The well is currently online taking ~1,600 MCFD of lift gas and producing ~1,300 BLPD at a flowing tubing pressure of 300 psi. Please let me know if you have any questions, Brian Lewis ! " # " $#%& ' () * +&! , *' -. !/ 0"!! 1. -. 23243,/3 5- / " * ' ( ' 6 % - 788 / 9 %- *8 / 2 :7 * & - / ; : 4" 9 ' * " () * ' . * +" 9 < "'. ( ' < <&!= > .>< *!!5 () ! ( @)33;+3 8$1143 #@ " #@ 98& (.$ .$&.!'<!( %&!66&&! 4 ' !2 ! ! A" @"9 A -: 23243,38243,8B2420;/ < #6 =9 ! ,&* * *9 . 9 ; !"#$%"&'()%')*+),-$&'*..* & /$,'01 ' * &C ' )01-2 '3) 4"%,- /.**$#,) /!5678 59!$*() 56 *.--)+'0)%: *.--)+'0)%: ( ( 7 "&!="< 3#A3A ;52323 " ;3* 7!' $79 Devin Kozak 7 ( 979? -13,/2+;#A2 By Samantha Carlisle at 8:48 pm, Mar 31, 2021 Devin Kozak Digitally signed by Devin Kozak Date: 2021.03.31 16:54:08 -08'00' VTL 5/5/21 SFD 4/1/2021DSR-4/1/21 RBDMS HEW 4/2/2021 !""#$ %&'(%!)* "#( '"#$ )+,- ) +./0",12+..344+5671 Last Rev Reason Annotation End Date Wellbore Last Mod By Rev Reason: Set 3.75" P2P W/ K-Valve 3/6/2021 3R-107 zembaej Casing Strings Casing Description CONDUCTOR OD (in) 20 ID (in) 18.50 Top (ftKB) 40.0 Set Depth (ftKB) 169.0 Set Depth (TVD)… 169.0 Wt/Len (l… 154.34 Grade 65 Top Thread NA Casing Description SURFACE OD (in) 10 3/4 ID (in) 9.95 Top (ftKB) 39.9 Set Depth (ftKB) 2,253.3 Set Depth (TVD)… 2,169.3 Wt/Len (l… 45.50 Grade L-80 Top Thread Hydril 563 Casing Description INTERMEDIATE OD (in) 7 5/8 ID (in) 6.88 Top (ftKB) 0.0 Set Depth (ftKB) 7,069.7 Set Depth (TVD)… 3,680.5 Wt/Len (l… 29.70 Grade L80 Top Thread H563 Casing Description LOWER LATERAL SLOTTED LINER OD (in) 4 1/2 ID (in) 3.99 Top (ftKB) 5,336.6 Set Depth (ftKB) 13,614.0 Set Depth (TVD)… 3,788.7 Wt/Len (l… 12.60 Grade L-80 Top Thread Hyd 563 Liner Details Top (ftKB)Top (TVD) (ftKB)Top Incl (°)Item Des Com Nominal ID (in) 5,356.33,654.4 87.51 NIPPLE- RS Baker 5.5" RS Nipple, 17# , L-80, Hyd 563 box x box 4.890 5,369.03,654.987.49SBE (Seal Bore Extension) Baker 190-47 Sealbore Extension, 20' 5-1/2" L-80 Hyd 563 box X pin 4.750 8,286.23,723.286.71SWELL PACKER PACKER,SWELL, 4 1/2 X 6.125", BAKER, HYD 563, PN (H301-87-0488) #24 3.980 8,306.3 3,724.4 86.60 SWELL PACKER PACKER,SWELL, 4 1/2 X 6.125", BAKER, HYD 563, PN (H301-87-0488) #23 3.980 8,987.83,675.093.13 SWELL PACKER PACKER,SWELL, 4 1/2 X 6.125", BAKER, HYD 563, PN (H301-87-0488) #22 3.980 9,007.83,674.092.29 SWELL PACKER PACKER,SWELL, 4 1/2 X 6.125", BAKER, HYD 563, PN (H301-87-0488) #21 3.980 Tubing Strings Tubing Description ESP TUBING COMPLETION String Ma… 4 1/2 ID (in) 3.96 Top (ftKB) 34.6 Set Depth (ft… 5,206.7 Set Depth (TVD) (… 3,647.9 Wt (lb/ft) 12.60 Grade L-80 Top Connection Hyd 563 Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Item Des Com Nominal ID (in) 34.6 34.6 0.00 HANGER VETCO/GE MB 242 13-3/8" x 4-1/2" tubing hanger (4.909 MCA Box Up) 3.900 4,807.3 3,630.3 87.45 GAUGE/PUMP SENSOR HES ROC-150 Annulus DHG ser # ROC-005608-10 + Mandrel 3.919 4,818.4 3,630.8 87.51 GAUGE/PUMP SENSOR HES ROC-150 Discharge DHG ser # ROC-005612 + Mandrel 3.919 4,963.8 3,637.3 87.44 Sliding Sleeve 5-1/2" GVSSD, 4 1/2" Vamtop Box x 5 1/2", 23#, Vam FJL Box (Closed 1/10/21) 3.913 4,967.8 3,637.5 87.44 Motor Shroud Motor Shroud, 5 1/2" 23# Vam FJL Pin x Pin 3.893 4,972.2 3,637.7 87.44 Motor Centralizer Motor Cenralizer, 5 1/2" 23# Vam FJL Box x Box 3.893 4,973.7 3,637.7 87.44 Motor Shroud Motor Shroud, 5 1/2" 23# Vam FJL Pin x Pin 3.893 4,978.2 3,637.9 87.44 Motor Centralizer Motor Cenralizer, 5 1/2" 23# Vam FJL Box x Box 3.893 4,979.7 3,638.087.44 Motor Shroud Motor Shroud, 5 1/2" 23# Vam FJL Pin x Pin 3.893 4,984.4 3,638.287.44 Motor Centralizer Motor Cenralizer, 5 1/2" 23# Vam FJL Box x Box 3.893 4,985.9 3,638.3 87.44 Motor Shroud Motor Shroud, 5 1/2" 23# Vam FJL Pin x Pin 3.893 4,990.4 3,638.5 87.45 Motor Centralizer Motor Cenralizer, 5 1/2" 23# Vam FJL Box x Box 3.893 4,991.93,638.687.45 Motor Shroud Motor Shroud, 5 1/2" 23# Vam FJL Pin x Pin 3.893 4,996.33,638.7 87.45 Motor Centralizer Motor Cenralizer, 5 1/2" 23# Vam FJL Box x Box 3.893 4,997.83,638.887.45 Motor Shroud Motor Shroud, 5 1/2" 23# Vam FJL Pin x Pin 3.893 5,002.3 3,639.0 87.45 Motor Centralizer Motor Cenralizer, 5 1/2" 23# Vam FJL Box x Box 3.893 5,003.8 3,639.1 87.45 Motor Shroud Motor Shroud, 5 1/2" 23# Vam FJL Pin x Pin 3.893 5,008.2 3,639.3 87.46 Motor Centralizer Motor Cenralizer, 5 1/2" 23# Vam FJL Box x Box 3.893 5,009.7 3,639.3 87.46 Motor Shroud Motor Shroud, 5 1/2" 23# Vam FJL Pin x Pin 4.548 5,016.1 3,639.6 87.47 Annular Connection Port Ann Connection Port 5", 18# Vam FJL Box x 4 1/2" 12.6# Vamtop Box SN#ACPTX18M0021 3.835 5,039.7 3,640.7 87.51 Profile Sub B-Profile, 4 1/2", 12.6#, L-80 Vamtop Box x Box 3.956 5,053.23,641.287.53 No-go nipple No-Go, 4 1/2" 12.6# Vamtop Box x 4 1/2" Hyd 563 Box 3.813 5,068.23,641.987.55 Sliding Sleeve Camco Sliding Sleeve CMU w/ 3.813 X-nipple, 4 1/2" Hyd 563 SN#2B (Closed 1/9/2021) 3.813 5,116.93,643.987.57 SSSV SSSV NE TRSV-HAL, 6.62" x 3.813 X-nipple TSH-Blue Box x Pin 3.813 5,179.7 3,646.7 87.45 LOCATOR Mechanical locator (Collar 5.5" OD ( NOGO spaced out 3' Seal assembly) 3.870 5,180.13,646.7 87.45 Seal Assembly Baker 192-47 Seal assembly, 4 1/2" Hyd 563 Box 3.870 Tubing Description LEM String Ma… 4 1/2 ID (in) 3.88 Top (ftKB) 5,171.0 Set Depth (ft… 5,384.0 Set Depth (TVD) (… 3,655.6 Wt (lb/ft) 12.60 Grade L-80 Top Connection HYD 563 Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Item Des Com Nominal ID (in) 5,171.03,646.387.46 PACKER HR ZXP LTP w/HD L-80 & 10’ ext, 5-1/2” 14# Hyd 563 Pin Down 4.890 5,190.7 3,647.287.43SBE (Seal Bore Extension) 190-47 SBE, 5-1/2” Hyd 563 Box x Pin 4.750 5,226.4 3,648.887.47 NIPPLE DB Camco 4.5 x 3.75” DB-6 Nipple to isolate both laterals (SN# 6918- 3) 3.750 5,249.23,649.887.51 DIVERTER T1 LEM, Pos #4, 4-1/2” BTC Box x Pin, above hook 3.710 5,252.33,649.987.51 DIVERTER T1 LEM, Pos #4, 4-1/2” BTC Box x Pin, below hook 3.688 MULTIPLE LATERALS, 3R-107, 3/24/2021 2:13:08 PM Vertical schematic (actual) LOWER LATERAL SLOTTED LINER; 5,336.6-13,614.0 Annular Fluid - Flo-Pro Drilling Mud; 5,192.0-13,614.5 INTERMEDIATE; 0.0-7,069.7 SEAL ASSY; 5,380.7 NIPPLE; 5,329.3 DIVERTER T1; 5,252.3 DIVERTER T1; 5,249.1 Tubing - Pup; 5,245.1 Tubing - Pup; 5,238.3 Tubing - Pup; 5,228.4 NIPPLE DB; 5,226.4 SBE (Seal Bore Extension); 5,190.7 Seal Assembly; 5,180.1 PACKER; 5,171.0 LOCATOR; 5,179.7 SSSV; 5,116.9 INJECTION; 5,092.9 Sliding Sleeve; 5,068.2 No-go nipple; 5,053.2 Profile Sub; 5,039.7 ACCESS ESP ISO-SLEEVE; 5,015.0 Annular Connection Port; 5,016.1 Motor Shroud; 5,009.7 Motor Centralizer; 5,008.2 Motor Shroud; 5,003.8 Motor Centralizer; 5,002.3 Motor Shroud; 4,997.8 Motor Centralizer; 4,996.3 Motor Shroud; 4,991.9 Motor Centralizer; 4,990.4 Motor Shroud; 4,985.9 Motor Centralizer; 4,984.4 Motor Shroud; 4,979.7 Motor Centralizer; 4,978.2 Motor Shroud; 4,973.7 Motor Centralizer; 4,972.2 Motor Shroud; 4,967.8 Sliding Sleeve; 4,963.8 GAUGE/PUMP SENSOR; 4,818.4 GAUGE/PUMP SENSOR; 4,807.3 GAS LIFT; 4,046.1 Annular Fluid - Diesel; 2,633.2- 5,337.2 GAS LIFT; 2,633.3 SURFACE; 39.9-2,253.3 3.75" P2P W/ K-Valve (418 Dome PSI); 1,868.0 Annular Fluid - Saltwater/Brine; 34.6-2,633.2 CONDUCTOR; 40.0-169.0 HANGER; 34.6 KUP PROD KB-Grd (ft) 39.45 Rig Release Date 2/19/2020 3R-107 ... TD Act Btm (ftKB) 13,614.0 Well Attributes Field Name Wellbore API/UWI 500292366000 Wellbore Status PROD Max Angle & MD Incl (°) 98.35 MD (ftKB) 8,717.71 WELLNAME WELLBORE Annotation End DateH2S (ppm) 2 Date 8/4/2020 Comment SSSV NE TRSV, HES SAP,6.6… Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Item Des Com Nominal ID (in) 5,329.33,653.287.53 NIPPLE Camco 4.5" x 3.562" DB-6 for parent isolation (SN # 6199-1) 3.563 5,380.7 3,655.4 87.48 SEAL ASSY 190-47 GBH-22 Non Locating Seal Assembly, 4 1/2" STL Box 3.860 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Des Com Run Date ID (in)SN 1,868.01,827.623.77 3.75" P2P W/ K- Valve (418 Dome PSI) 3.75" P2P W/ K-Valve (418 closing pressure @ 60°F / 86" OAL) 2/18/2021 0.000 5,015.0 3,639.6 87.47 ACCESS ESP ISO-SLEEVE AccessESP Iso-sleeve 1/10/2021 3.000 Mandrel Inserts St ati on N o/Top (ftKB) Top (TVD) (ftKB)Make Model OD (in)Serv Valve Type Latch Ty pe Port Size (in) TRO Run (psi)Run Date Com 1 2,633.32,501.8Camco 1 GAS LIFT GLV BK 0.188 1,526.01/11/2021 2 4,046.13,482.0Camco 1 GAS LIFT OVBK 0.313 0.01/11/2021 3 5,092.9 3,642.9 HES Halliburt on 5.6CHEM DCIV- 8000 800.08/8/2020 Max rate 3GPM , 700- 800 cracki ng press MULTIPLE LATERALS, 3R-107, 3/24/2021 2:13:10 PM Vertical schematic (actual) LOWER LATERAL SLOTTED LINER; 5,336.6-13,614.0 Annular Fluid - Flo-Pro Drilling Mud; 5,192.0-13,614.5 INTERMEDIATE; 0.0-7,069.7 SEAL ASSY; 5,380.7 NIPPLE; 5,329.3 DIVERTER T1; 5,252.3 DIVERTER T1; 5,249.1 Tubing - Pup; 5,245.1 Tubing - Pup; 5,238.3 Tubing - Pup; 5,228.4 NIPPLE DB; 5,226.4 SBE (Seal Bore Extension); 5,190.7 Seal Assembly; 5,180.1 PACKER; 5,171.0 LOCATOR; 5,179.7 SSSV; 5,116.9 INJECTION; 5,092.9 Sliding Sleeve; 5,068.2 No-go nipple; 5,053.2 Profile Sub; 5,039.7 ACCESS ESP ISO-SLEEVE; 5,015.0 Annular Connection Port; 5,016.1 Motor Shroud; 5,009.7 Motor Centralizer; 5,008.2 Motor Shroud; 5,003.8 Motor Centralizer; 5,002.3 Motor Shroud; 4,997.8 Motor Centralizer; 4,996.3 Motor Shroud; 4,991.9 Motor Centralizer; 4,990.4 Motor Shroud; 4,985.9 Motor Centralizer; 4,984.4 Motor Shroud; 4,979.7 Motor Centralizer; 4,978.2 Motor Shroud; 4,973.7 Motor Centralizer; 4,972.2 Motor Shroud; 4,967.8 Sliding Sleeve; 4,963.8 GAUGE/PUMP SENSOR; 4,818.4 GAUGE/PUMP SENSOR; 4,807.3 GAS LIFT; 4,046.1 Annular Fluid - Diesel; 2,633.2- 5,337.2 GAS LIFT; 2,633.3 SURFACE; 39.9-2,253.3 3.75" P2P W/ K-Valve (418 Dome PSI); 1,868.0 Annular Fluid - Saltwater/Brine; 34.6-2,633.2 CONDUCTOR; 40.0-169.0 HANGER; 34.6 KUP PROD 3R-107 ... 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(8"(*(18 " =>'(4%18%8 ! # $ %#$&'()&) $ & #* By Samantha Carlisle at 11:22 am, Feb 22, 2021 321-092 Rachel Kautz Digitally signed by Rachel Kautz Date: 2021.02.22 10:53:10 -09'00' 13,638' DLB DLB 02/22/2021 -23660-00-00 DLB X DSR-2/22/21VTL 3/2/21 20 AAC 25.265(o), Approval is granted for a variance to use a non-surface controlled subsurface safety valve (SSSV) as the primary SSSV in Kuparuk River Unit producer 3R-107. 10-404 Per 20 AAC 25.265 (h) (2) witnessed performance test by AOGCC. 24 hour notice. X " 3/3/21 dts 3/03/2021 JLC 3/3/2021 RBDMS HEW 3/3/2021 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 February 22, 2021 AOGCC Commissioner State of Alaska, Oil & Gas Conservation Commission 333 W. 7th Ave., Suite 100 Anchorage, AK 99501 Dear Commissioner, In accordance with 20 AAC 25.265(o), ConocoPhillips requests approval for a variance to use a non-surface controlled subsurface safety valve (SSSV) as the primary SSSV in Kuparuk River Unit producer 3R-107. KRU 3R-107 was completed as a producer in February 2020 with a tubing conveyed, surface-controlled SSSV. A passing state-witnessed test of the surface-controlled SSSV was last performed in November 2020. However, following a failed test witnessed by Adam Earl on February 20, 2020, ConocoPhillips has decided to install a Halliburton K-valve between 1700’-2000’ rather than mobilize coil to investigate the deep SSSV. Enclosed please find the 10-403 forms for 3R-107 & 3R-107L1 (PTD 219-180 & 219-181), schematic, proposed operating plan, and the ConocoPhillips SOP for testing non-surface controlled SSSV. Sincerely, Rachel Kautz Production Engineer ConocoPhillips Alaska, Inc. 907-659-7871 Rachel Kautz Digitally signed by Rachel Kautz Date: 2021.02.22 10:53:43 -09'00' Proposed Operating Plan 1. When necessary, perform flowing pressure and temperature survey with gauges at the estimated Halliburton K-valve set depth. Gather data at depth during full-open stable flow, as well as various other producing conditions, to identify smoothest flowing scenario for good K-valve operation. 2. Use data to appropriately design and charge K-valve. 3. Install K-valve. 4. Restart and stabilize production at designed conditions for the K-valve installed. 5. Perform and schedule test per ConocoPhillips Standard Operating Procedure (SOP). 6. Incorporate the K-valve test frequency into the current SVS testing cycle at Kuparuk 3R pad. 7. Upon a passing closure test, continue operating the well in normal production service. TEST PROCEDURE (DS-1B or DS-3R only) – test of non-surface controlled SSSV (aka “k-valve” or “storm valve”) These steps will take place after normal testing of the Surface Safety Valve and Low Pressure Sensing device 1. Close the Wing Valve 2. Build 200-300 psi of tubing pressure above initial FTP reading. 3. Block-in the lift gas at the tree. 4. Open the Wing Valve completely. 5. If the well does not stop flowing within 4 minutes, indicate that the SSSV failed the test, along with the failure code for “Failed to close” on the ConocoPhillips Kuparuk Safety Valve Test Report. 6. After the well has stopped flowing, close the Wing Valve. 7. Record the tree cap pressure (IP for the SSSV test). 8. Open the lift gas at the tree. 9. Monitor the wellhead pressure for 3-5 minutes. 10. If the well builds pressure above the shut-in well pressure (IP), indicate that the SSSV failed the test, along with the fa ilure code for “Failed to hold DP” on the ConocoPhillips Kuparuk Safety Valve Test Report. 11. Testing is complete; proceed to Rig-Down steps. Last Rev Reason Annotation End Date Wellbore Last Mod By Rev Reason: Pulled Gauges 2/18/2021 3R-107 fergusp Casing Strings Casing Description CONDUCTOR OD (in) 20 ID (in) 18.50 Top (ftKB) 40.0 Set Depth (ftKB) 169.0 Set Depth (TVD)… 169.0 Wt/Len (l… 154.34 Grade 65 Top Thread NA Casing Description SURFACE OD (in) 10 3/4 ID (in) 9.95 Top (ftKB) 39.9 Set Depth (ftKB) 2,253.3 Set Depth (TVD)… 2,169.3 Wt/Len (l… 45.50 Grade L-80 Top Thread Hydril 563 Casing Description INTERMEDIATE OD (in) 7 5/8 ID (in) 6.88 Top (ftKB) 0.0 Set Depth (ftKB) 7,069.7 Set Depth (TVD)… 3,680.5 Wt/Len (l… 29.70 Grade L80 Top Thread H563 Casing Description LOWER LATERAL SLOTTED LINER OD (in) 4 1/2 ID (in) 3.99 Top (ftKB) 5,336.6 Set Depth (ftKB) 13,614.0 Set Depth (TVD)… 3,788.7 Wt/Len (l… 12.60 Grade L-80 Top Thread Hyd 563 Liner Details Top (ftKB)Top (TVD) (ftKB)Top Incl (°)Item Des Com Nominal ID (in) 5,356.33,654.4 87.51 NIPPLE- RS Baker 5.5" RS Nipple, 17# , L-80, Hyd 563 box x box 4.890 5,369.03,654.987.49SBE (Seal Bore Extension) Baker 190-47 Sealbore Extension, 20' 5-1/2" L-80 Hyd 563 box X pin 4.750 8,286.23,723.286.71SWELL PACKER PACKER,SWELL, 4 1/2 X 6.125", BAKER, HYD 563, PN (H301-87-0488) #24 3.980 8,306.3 3,724.4 86.60 SWELL PACKER PACKER,SWELL, 4 1/2 X 6.125", BAKER, HYD 563, PN (H301-87-0488) #23 3.980 8,987.83,675.093.13 SWELL PACKER PACKER,SWELL, 4 1/2 X 6.125", BAKER, HYD 563, PN (H301-87-0488) #22 3.980 9,007.83,674.092.29 SWELL PACKER PACKER,SWELL, 4 1/2 X 6.125", BAKER, HYD 563, PN (H301-87-0488) #21 3.980 Tubing Strings Tubing Description ESP TUBING COMPLETION String Ma… 4 1/2 ID (in) 3.96 Top (ftKB) 34.6 Set Depth (ft… 5,206.7 Set Depth (TVD) (… 3,647.9 Wt (lb/ft) 12.60 Grade L-80 Top Connection Hyd 563 Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Item Des Com Nominal ID (in) 34.6 34.6 0.00 HANGER VETCO/GE MB 242 13-3/8" x 4-1/2" tubing hanger (4.909 MCA Box Up) 3.900 4,807.3 3,630.3 87.45 GAUGE/PUMP SENSOR HES ROC-150 Annulus DHG ser # ROC-005608-10 + Mandrel 3.919 4,818.4 3,630.8 87.51 GAUGE/PUMP SENSOR HES ROC-150 Discharge DHG ser # ROC-005612 + Mandrel 3.919 4,963.8 3,637.3 87.44 Sliding Sleeve 5-1/2" GVSSD, 4 1/2" Vamtop Box x 5 1/2", 23#, Vam FJL Box (Closed 1/10/21) 3.913 4,967.8 3,637.5 87.44 Motor Shroud Motor Shroud, 5 1/2" 23# Vam FJL Pin x Pin 3.893 4,972.2 3,637.7 87.44 Motor Centralizer Motor Cenralizer, 5 1/2" 23# Vam FJL Box x Box 3.893 4,973.7 3,637.7 87.44 Motor Shroud Motor Shroud, 5 1/2" 23# Vam FJL Pin x Pin 3.893 4,978.2 3,637.9 87.44 Motor Centralizer Motor Cenralizer, 5 1/2" 23# Vam FJL Box x Box 3.893 4,979.7 3,638.087.44 Motor Shroud Motor Shroud, 5 1/2" 23# Vam FJL Pin x Pin 3.893 4,984.4 3,638.287.44 Motor Centralizer Motor Cenralizer, 5 1/2" 23# Vam FJL Box x Box 3.893 4,985.9 3,638.3 87.44 Motor Shroud Motor Shroud, 5 1/2" 23# Vam FJL Pin x Pin 3.893 4,990.4 3,638.5 87.45 Motor Centralizer Motor Cenralizer, 5 1/2" 23# Vam FJL Box x Box 3.893 4,991.93,638.687.45 Motor Shroud Motor Shroud, 5 1/2" 23# Vam FJL Pin x Pin 3.893 4,996.33,638.7 87.45 Motor Centralizer Motor Cenralizer, 5 1/2" 23# Vam FJL Box x Box 3.893 4,997.83,638.887.45 Motor Shroud Motor Shroud, 5 1/2" 23# Vam FJL Pin x Pin 3.893 5,002.3 3,639.0 87.45 Motor Centralizer Motor Cenralizer, 5 1/2" 23# Vam FJL Box x Box 3.893 5,003.8 3,639.1 87.45 Motor Shroud Motor Shroud, 5 1/2" 23# Vam FJL Pin x Pin 3.893 5,008.2 3,639.3 87.46 Motor Centralizer Motor Cenralizer, 5 1/2" 23# Vam FJL Box x Box 3.893 5,009.7 3,639.3 87.46 Motor Shroud Motor Shroud, 5 1/2" 23# Vam FJL Pin x Pin 4.548 5,016.1 3,639.6 87.47 Annular Connection Port Ann Connection Port 5", 18# Vam FJL Box x 4 1/2" 12.6# Vamtop Box SN#ACPTX18M0021 3.835 5,039.7 3,640.7 87.51 Profile Sub B-Profile, 4 1/2", 12.6#, L-80 Vamtop Box x Box 3.956 5,053.23,641.287.53 No-go nipple No-Go, 4 1/2" 12.6# Vamtop Box x 4 1/2" Hyd 563 Box 3.813 5,068.23,641.987.55 Sliding Sleeve Camco Sliding Sleeve CMU w/ 3.813 X-nipple, 4 1/2" Hyd 563 SN#2B (Closed 1/9/2021) 3.813 5,116.93,643.987.57 SSSV SSSV NE TRSV-HAL, 6.62" x 3.813 X-nipple TSH-Blue Box x Pin 3.813 5,179.7 3,646.7 87.45 LOCATOR Mechanical locator (Collar 5.5" OD ( NOGO spaced out 3' Seal assembly) 3.870 5,180.13,646.7 87.45 Seal Assembly Baker 192-47 Seal assembly, 4 1/2" Hyd 563 Box 3.870 Tubing Description LEM String Ma… 4 1/2 ID (in) 3.88 Top (ftKB) 5,171.0 Set Depth (ft… 5,384.0 Set Depth (TVD) (… 3,655.6 Wt (lb/ft) 12.60 Grade L-80 Top Connection HYD 563 Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Item Des Com Nominal ID (in) 5,171.03,646.387.46 PACKER HR ZXP LTP w/HD L-80 & 10’ ext, 5-1/2” 14# Hyd 563 Pin Down 4.890 5,190.7 3,647.287.43SBE (Seal Bore Extension) 190-47 SBE, 5-1/2” Hyd 563 Box x Pin 4.750 5,226.4 3,648.887.47 NIPPLE DB Camco 4.5 x 3.75” DB-6 Nipple to isolate both laterals (SN# 6918- 3) 3.750 5,249.2 3,649.8 87.51 DIVERTER T1 LEM, Pos #4, 4-1/2” BTC Box x Pin, above hook 3.710 5,252.33,649.987.51 DIVERTER T1 LEM, Pos #4, 4-1/2” BTC Box x Pin, below hook 3.688 MULTIPLE LATERALS, 3R-107, 2/19/2021 7:09:23 AM Vertical schematic (actual) LOWER LATERAL SLOTTED LINER; 5,336.6-13,614.0 Annular Fluid - Flo-Pro Drilling Mud; 5,192.0-13,614.5 INTERMEDIATE; 0.0-7,069.7 SEAL ASSY; 5,380.7 NIPPLE; 5,329.3 DIVERTER T1; 5,252.3 DIVERTER T1; 5,249.1 Tubing - Pup; 5,245.1 Tubing - Pup; 5,238.3 Tubing - Pup; 5,228.4 NIPPLE DB; 5,226.4 SBE (Seal Bore Extension); 5,190.7 Seal Assembly; 5,180.1 PACKER; 5,171.0 LOCATOR; 5,179.7 SSSV; 5,116.9 INJECTION; 5,092.9 Sliding Sleeve; 5,068.2 No-go nipple; 5,053.2 Profile Sub; 5,039.7 ACCESS ESP ISO-SLEEVE; 5,015.0 Annular Connection Port; 5,016.1 Motor Shroud; 5,009.7 Motor Centralizer; 5,008.2 Motor Shroud; 5,003.8 Motor Centralizer; 5,002.3 Motor Shroud; 4,997.8 Motor Centralizer; 4,996.3 Motor Shroud; 4,991.9 Motor Centralizer; 4,990.4 Motor Shroud; 4,985.9 Motor Centralizer; 4,984.4 Motor Shroud; 4,979.7 Motor Centralizer; 4,978.2 Motor Shroud; 4,973.7 Motor Centralizer; 4,972.2 Motor Shroud; 4,967.8 Sliding Sleeve; 4,963.8 GAUGE/PUMP SENSOR; 4,818.4 GAUGE/PUMP SENSOR; 4,807.3 GAS LIFT; 4,046.1 Annular Fluid - Diesel; 2,633.2- 5,337.2 GAS LIFT; 2,633.3 SURFACE; 39.9-2,253.3 Annular Fluid - Saltwater/Brine; 34.6-2,633.2 CONDUCTOR; 40.0-169.0 HANGER; 34.6 KUP PROD KB-Grd (ft) 39.45 Rig Release Date 2/19/2020 3R-107 ... TD Act Btm (ftKB) 13,614.0 Well Attributes Field Name Wellbore API/UWI 500292366000 Wellbore Status PROD Max Angle & MD Incl (°) 98.35 MD (ftKB) 8,717.71 WELLNAME WELLBORE Annotation End DateH2S (ppm) 2 Date 8/4/2020 Comment SSSV NE TRSV, HES SAP,6.6… Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Item Des Com Nominal ID (in) 5,329.33,653.287.53 NIPPLE Camco 4.5" x 3.562" DB-6 for parent isolation (SN # 6199-1) 3.563 5,380.7 3,655.4 87.48 SEAL ASSY 190-47 GBH-22 Non Locating Seal Assembly, 4 1/2" STL Box 3.860 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Des Com Run Date ID (in)SN 5,015.03,639.687.47 ACCESS ESP ISO-SLEEVE AccessESP Iso-sleeve1/10/2021 3.000 Mandrel Inserts St ati on N o/Top (ftKB) Top (TVD) (ftKB)Make Model OD (in)Serv Valve Type Latch Ty pe Port Size (in) TRO Run (psi)Run Date Com 1 2,633.32,501.8Camco 1 GAS LIFT GLV BK 0.188 1,526.01/11/2021 2 4,046.13,482.0Camco 1 GAS LIFT OVBK 0.313 0.01/11/2021 3 5,092.93,642.9 HES Halliburt on 5.6CHEM DCIV- 8000 800.08/8/2020 Max rate 3GPM , 700- 800 cracki ng press MULTIPLE LATERALS, 3R-107, 2/19/2021 7:09:25 AM Vertical schematic (actual) LOWER LATERAL SLOTTED LINER; 5,336.6-13,614.0 Annular Fluid - Flo-Pro Drilling Mud; 5,192.0-13,614.5 INTERMEDIATE; 0.0-7,069.7 SEAL ASSY; 5,380.7 NIPPLE; 5,329.3 DIVERTER T1; 5,252.3 DIVERTER T1; 5,249.1 Tubing - Pup; 5,245.1 Tubing - Pup; 5,238.3 Tubing - Pup; 5,228.4 NIPPLE DB; 5,226.4 SBE (Seal Bore Extension); 5,190.7 Seal Assembly; 5,180.1 PACKER; 5,171.0 LOCATOR; 5,179.7 SSSV; 5,116.9 INJECTION; 5,092.9 Sliding Sleeve; 5,068.2 No-go nipple; 5,053.2 Profile Sub; 5,039.7 ACCESS ESP ISO-SLEEVE; 5,015.0 Annular Connection Port; 5,016.1 Motor Shroud; 5,009.7 Motor Centralizer; 5,008.2 Motor Shroud; 5,003.8 Motor Centralizer; 5,002.3 Motor Shroud; 4,997.8 Motor Centralizer; 4,996.3 Motor Shroud; 4,991.9 Motor Centralizer; 4,990.4 Motor Shroud; 4,985.9 Motor Centralizer; 4,984.4 Motor Shroud; 4,979.7 Motor Centralizer; 4,978.2 Motor Shroud; 4,973.7 Motor Centralizer; 4,972.2 Motor Shroud; 4,967.8 Sliding Sleeve; 4,963.8 GAUGE/PUMP SENSOR; 4,818.4 GAUGE/PUMP SENSOR; 4,807.3 GAS LIFT; 4,046.1 Annular Fluid - Diesel; 2,633.2- 5,337.2 GAS LIFT; 2,633.3 SURFACE; 39.9-2,253.3 Annular Fluid - Saltwater/Brine; 34.6-2,633.2 CONDUCTOR; 40.0-169.0 HANGER; 34.6 KUP PROD 3R-107 ... WELLNAME WELLBORE ! " # " $ % & ' $( ) *+! , )' -& !. /& -& 01021,. 1 3- . " ) ' 45*6 ! 45,77 ! $ ' 45*6 45,77 - 855 .6299 &#71 2501,9:'45*679;' < ;- )5 . =$ > ?>&25,9:' 45*6*9;' ; !$ ;#>&25,9:' 45*669;' 0 @8 ) + - . 4 @ 2" < ' ) " $( ) ' & ) *" < % "'& % %+!A B&B% )!!3 $( = 8 ! = 83= $ 8 $ $ -/1,.*2/#,7, 4 C(114*155 < //21 21#10/#04**1#11#11 7"!!= B4 #1,'&1422104 $&= &=+&!'%!$ ;+!::++! 0 ! <5+6" C"< 2 ' ! 0/#71#1 < !3=< 3" < A< !!" !'B ,7 01D */9:' */9;' &$'&+!$ 750,7 63099 45*69:' 4,77,9;' +!$ :$'+$ ,51*/ ,23799 ,51,19:' 4*7129;' B $ 0504 143699 050249:' 0*/49;' !3 ' ) +E ' : ; & 244,#4*69:' & 4*24#4,7/9;' ! ! ! ! ! 6 -@ 01021,15021,5F02074. #C % #: " #C ! ! ! ! ! 8! 8 $ $ $ ' "+!A"% ,+) ) )< #$%&'## !" By Samantha Carlisle at 9:42 am, Feb 02, 2021 Rachel Kautz Digitally signed by Rachel Kautz Date: 2021.02.02 09:12:54 -09'00' DSR-2/2/21VTL 2/17/21 13,638 SFD 2/3/2021 SFD 2/3/2021 RBDMS HEW 2/2/2021 ! "!# $%%& ' $()(* !"""+,-+."*/#//+/ +*&+*&0 ,"+/+! *00(* (* 1 2-3'4 %* 5 %* 5 6 " ("!$7 -+",# "-!/ 8" Rachel Kautz Digitally signed by Rachel Kautz Date: 2021.02.02 09:13:18 -09'00' !"# $$%& & '() #) *+ $ '() *+ $ ,- !" .,, !" ' /0/ !" 1.2.3,245# + $$%//6!"786!" -,,6!" " # Last Rev Reason Annotation End Date Wellbore Last Mod By Rev Reason: CORRECTED GLM's Service Types to Gas Lift and CHEM 1/26/2021 3R-107 pproven Casing Strings Casing Description CONDUCTOR OD (in) 20 ID (in) 18.50 Top (ftKB) 40.0 Set Depth (ftKB) 169.0 Set Depth (TVD)… 169.0 Wt/Len (l… 154.34 Grade 65 Top Thread NA Casing Description SURFACE OD (in) 10 3/4 ID (in) 9.95 Top (ftKB) 39.9 Set Depth (ftKB) 2,253.3 Set Depth (TVD)… 2,169.3 Wt/Len (l… 45.50 Grade L-80 Top Thread Hydril 563 Casing Description INTERMEDIATE OD (in) 7 5/8 ID (in) 6.88 Top (ftKB) 0.0 Set Depth (ftKB) 7,069.7 Set Depth (TVD)… 3,680.5 Wt/Len (l… 29.70 Grade L80 Top Thread H563 Casing Description LOWER LATERAL SLOTTED LINER OD (in) 4 1/2 ID (in) 3.99 Top (ftKB) 5,336.6 Set Depth (ftKB) 13,614.0 Set Depth (TVD)… 3,788.7 Wt/Len (l… 12.60 Grade L-80 Top Thread Hyd 563 Liner Details Top (ftKB)Top (TVD) (ftKB)Top Incl (°)Item Des Com Nominal ID (in) 5,356.33,654.4 87.51 NIPPLE- RS Baker 5.5" RS Nipple, 17# , L-80, Hyd 563 box x box 4.890 5,369.0 3,654.9 87.49 SBE (Seal Bore Extension) Baker 190-47 Sealbore Extension, 20' 5-1/2" L-80 Hyd 563 box X pin 4.750 8,286.23,723.286.71SWELL PACKER PACKER,SWELL, 4 1/2 X 6.125", BAKER, HYD 563, PN (H301-87-0488) #24 3.980 8,306.3 3,724.4 86.60 SWELL PACKER PACKER,SWELL, 4 1/2 X 6.125", BAKER, HYD 563, PN (H301-87-0488) #23 3.980 8,987.83,675.093.13 SWELL PACKER PACKER,SWELL, 4 1/2 X 6.125", BAKER, HYD 563, PN (H301-87-0488) #22 3.980 9,007.8 3,674.0 92.29 SWELL PACKER PACKER,SWELL, 4 1/2 X 6.125", BAKER, HYD 563, PN (H301-87-0488) #21 3.980 Tubing Strings Tubing Description ESP TUBING COMPLETION String Ma… 4 1/2 ID (in) 3.96 Top (ftKB) 34.6 Set Depth (ft… 5,206.7 Set Depth (TVD) (… 3,647.9 Wt (lb/ft) 12.60 Grade L-80 Top Connection Hyd 563 Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Item Des Com Nominal ID (in) 34.6 34.6 0.00 HANGER VETCO/GE MB 242 13-3/8" x 4-1/2" tubing hanger (4.909 MCA Box Up) 3.900 4,807.3 3,630.3 87.45 GAUGE/PUMP SENSOR HES ROC-150 Annulus DHG ser # ROC-005608-10 + Mandrel 3.919 4,818.4 3,630.8 87.51 GAUGE/PUMP SENSOR HES ROC-150 Discharge DHG ser # ROC-005612 + Mandrel 3.919 4,963.8 3,637.3 87.44 Sliding Sleeve 5-1/2" GVSSD, 4 1/2" Vamtop Box x 5 1/2", 23#, Vam FJL Box (Closed 1/10/21) 3.913 4,967.8 3,637.5 87.44 Motor Shroud Motor Shroud, 5 1/2" 23# Vam FJL Pin x Pin 3.893 4,972.2 3,637.7 87.44 Motor Centralizer Motor Cenralizer, 5 1/2" 23# Vam FJL Box x Box 3.893 4,973.7 3,637.7 87.44 Motor Shroud Motor Shroud, 5 1/2" 23# Vam FJL Pin x Pin 3.893 4,978.2 3,637.9 87.44 Motor Centralizer Motor Cenralizer, 5 1/2" 23# Vam FJL Box x Box 3.893 4,979.7 3,638.087.44 Motor Shroud Motor Shroud, 5 1/2" 23# Vam FJL Pin x Pin 3.893 4,984.4 3,638.2 87.44 Motor Centralizer Motor Cenralizer, 5 1/2" 23# Vam FJL Box x Box 3.893 4,985.93,638.387.44 Motor Shroud Motor Shroud, 5 1/2" 23# Vam FJL Pin x Pin 3.893 4,990.4 3,638.5 87.45 Motor Centralizer Motor Cenralizer, 5 1/2" 23# Vam FJL Box x Box 3.893 4,991.93,638.687.45 Motor Shroud Motor Shroud, 5 1/2" 23# Vam FJL Pin x Pin 3.893 4,996.3 3,638.7 87.45 Motor Centralizer Motor Cenralizer, 5 1/2" 23# Vam FJL Box x Box 3.893 4,997.83,638.887.45 Motor Shroud Motor Shroud, 5 1/2" 23# Vam FJL Pin x Pin 3.893 5,002.3 3,639.0 87.45 Motor Centralizer Motor Cenralizer, 5 1/2" 23# Vam FJL Box x Box 3.893 5,003.8 3,639.1 87.45 Motor Shroud Motor Shroud, 5 1/2" 23# Vam FJL Pin x Pin 3.893 5,008.2 3,639.3 87.46 Motor Centralizer Motor Cenralizer, 5 1/2" 23# Vam FJL Box x Box 3.893 5,009.7 3,639.3 87.46 Motor Shroud Motor Shroud, 5 1/2" 23# Vam FJL Pin x Pin 4.548 5,016.1 3,639.6 87.47 Annular Connection Port Ann Connection Port 5", 18# Vam FJL Box x 4 1/2" 12.6# Vamtop Box SN#ACPTX18M0021 3.835 5,039.7 3,640.7 87.51 Profile Sub B-Profile, 4 1/2", 12.6#, L-80 Vamtop Box x Box 3.956 5,053.23,641.287.53 No-go nipple No-Go, 4 1/2" 12.6# Vamtop Box x 4 1/2" Hyd 563 Box 3.813 5,068.2 3,641.9 87.55 Sliding Sleeve Camco Sliding Sleeve CMU w/ 3.813 X-nipple, 4 1/2" Hyd 563 SN#2B (Closed 1/9/2021) 3.813 5,116.9 3,643.9 87.57 SSSV SSSV NE TRSV-HAL, 6.62" x 3.813 X-nipple TSH-Blue Box x Pin 3.813 5,179.7 3,646.7 87.45 LOCATOR Mechanical locator (Collar 5.5" OD ( NOGO spaced out 3' Seal assembly) 3.870 5,180.1 3,646.7 87.45 Seal Assembly Baker 192-47 Seal assembly, 4 1/2" Hyd 563 Box 3.870 Tubing Description LEM String Ma… 4 1/2 ID (in) 3.88 Top (ftKB) 5,171.0 Set Depth (ft… 5,384.0 Set Depth (TVD) (… 3,655.6 Wt (lb/ft) 12.60 Grade L-80 Top Connection HYD 563 Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Item Des Com Nominal ID (in) 5,171.0 3,646.3 87.46 PACKER HR ZXP LTP w/HD L-80 & 10’ ext, 5-1/2” 14# Hyd 563 Pin Down 4.890 5,190.7 3,647.287.43SBE (Seal Bore Extension) 190-47 SBE, 5-1/2” Hyd 563 Box x Pin 4.750 5,226.4 3,648.8 87.47 NIPPLE DB Camco 4.5 x 3.75” DB-6 Nipple to isolate both laterals (SN# 6918- 3) 3.750 5,249.2 3,649.8 87.51 DIVERTER T1 LEM, Pos #4, 4-1/2” BTC Box x Pin, above hook 3.710 5,252.3 3,649.9 87.51 DIVERTER T1 LEM, Pos #4, 4-1/2” BTC Box x Pin, below hook 3.688 MULTIPLE LATERALS, 3R-107, 2/1/2021 5:27:09 PM Vertical schematic (actual) LOWER LATERAL SLOTTED LINER; 5,336.6-13,614.0 Annular Fluid - Flo-Pro Drilling Mud; 5,192.0-13,614.5 INTERMEDIATE; 0.0-7,069.7 SEAL ASSY; 5,380.7 NIPPLE; 5,329.3 DIVERTER T1; 5,252.3 DIVERTER T1; 5,249.1 Tubing - Pup; 5,245.1 Tubing - Pup; 5,238.3 Tubing - Pup; 5,228.4 NIPPLE DB; 5,226.4 SBE (Seal Bore Extension); 5,190.7 Seal Assembly; 5,180.1 PACKER; 5,171.0 LOCATOR; 5,179.7 SSSV; 5,116.9 INJECTION; 5,092.9 Sliding Sleeve; 5,068.2 No-go nipple; 5,053.2 Profile Sub; 5,039.7 ACCESS ESP ISO-SLEEVE; 5,015.0 Annular Connection Port; 5,016.1 Motor Shroud; 5,009.7 Motor Centralizer; 5,008.2 Motor Shroud; 5,003.8 Motor Centralizer; 5,002.3 Motor Shroud; 4,997.8 Motor Centralizer; 4,996.3 Motor Shroud; 4,991.9 Motor Centralizer; 4,990.4 Motor Shroud; 4,985.9 Motor Centralizer; 4,984.4 Motor Shroud; 4,979.7 Motor Centralizer; 4,978.2 Motor Shroud; 4,973.7 Motor Centralizer; 4,972.2 Motor Shroud; 4,967.8 Sliding Sleeve; 4,963.8 GAUGE/PUMP SENSOR; 4,818.4 GAUGE/PUMP SENSOR; 4,807.3 GAS LIFT; 4,046.1 Annular Fluid - Diesel; 2,633.2- 5,337.2 GAS LIFT; 2,633.3 SURFACE; 39.9-2,253.3 4 1/2" SLIP STOP, FLOW THRU SUB, & SPARTEK GAUGES; 1,855.0 Annular Fluid - Saltwater/Brine; 34.6-2,633.2 CONDUCTOR; 40.0-169.0 HANGER; 34.6 KUP PROD KB-Grd (ft) 39.45 Rig Release Date 2/19/2020 3R-107 ... TD Act Btm (ftKB) 13,614.0 Well Attributes Field Name Wellbore API/UWI 500292366000 Wellbore Status PROD Max Angle & MD Incl (°) 98.35 MD (ftKB) 8,717.71 WELLNAME WELLBORE Annotation End DateH2S (ppm) 2 Date 8/4/2020 Comment SSSV NE TRSV, HES SAP,6.6… Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Item Des Com Nominal ID (in) 5,329.3 3,653.2 87.53 NIPPLE Camco 4.5" x 3.562" DB-6 for parent isolation (SN # 6199-1) 3.563 5,380.7 3,655.4 87.48 SEAL ASSY 190-47 GBH-22 Non Locating Seal Assembly, 4 1/2" STL Box 3.860 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Des Com Run Date ID (in)SN 1,855.01,815.7 23.40 4 1/2" SLIP STOP, FLOW THRU SUB, & SPARTEK GAUGES 4 1/2" SLIP STOP, FLOW THRU SUB, SHOCK ABSORBER, AND SPARTEK GAUGES (86" OAL) 1/14/2021 0.000 5,015.0 3,639.6 87.47 ACCESS ESP ISO-SLEEVE AccessESP Iso-sleeve 1/10/2021 3.000 Mandrel Inserts St ati on N o/Top (ftKB) Top (TVD) (ftKB)Make Model OD (in)Serv Valve Type Latch Ty pe Port Size (in) TRO Run (psi)Run Date Com 1 2,633.3 2,501.8 Camco 1 GAS LIFT GLV BK 0.188 1,526.0 1/11/2021 2 4,046.13,482.0Camco 1 GAS LIFT OVBK 0.313 0.01/11/2021 3 5,092.9 3,642.9 HES Halliburt on 5.6CHEM DCIV- 8000 800.08/8/2020 Max rate 3GPM , 700- 800 cracki ng press MULTIPLE LATERALS, 3R-107, 2/1/2021 5:27:12 PM Vertical schematic (actual) LOWER LATERAL SLOTTED LINER; 5,336.6-13,614.0 Annular Fluid - Flo-Pro Drilling Mud; 5,192.0-13,614.5 INTERMEDIATE; 0.0-7,069.7 SEAL ASSY; 5,380.7 NIPPLE; 5,329.3 DIVERTER T1; 5,252.3 DIVERTER T1; 5,249.1 Tubing - Pup; 5,245.1 Tubing - Pup; 5,238.3 Tubing - Pup; 5,228.4 NIPPLE DB; 5,226.4 SBE (Seal Bore Extension); 5,190.7 Seal Assembly; 5,180.1 PACKER; 5,171.0 LOCATOR; 5,179.7 SSSV; 5,116.9 INJECTION; 5,092.9 Sliding Sleeve; 5,068.2 No-go nipple; 5,053.2 Profile Sub; 5,039.7 ACCESS ESP ISO-SLEEVE; 5,015.0 Annular Connection Port; 5,016.1 Motor Shroud; 5,009.7 Motor Centralizer; 5,008.2 Motor Shroud; 5,003.8 Motor Centralizer; 5,002.3 Motor Shroud; 4,997.8 Motor Centralizer; 4,996.3 Motor Shroud; 4,991.9 Motor Centralizer; 4,990.4 Motor Shroud; 4,985.9 Motor Centralizer; 4,984.4 Motor Shroud; 4,979.7 Motor Centralizer; 4,978.2 Motor Shroud; 4,973.7 Motor Centralizer; 4,972.2 Motor Shroud; 4,967.8 Sliding Sleeve; 4,963.8 GAUGE/PUMP SENSOR; 4,818.4 GAUGE/PUMP SENSOR; 4,807.3 GAS LIFT; 4,046.1 Annular Fluid - Diesel; 2,633.2- 5,337.2 GAS LIFT; 2,633.3 SURFACE; 39.9-2,253.3 4 1/2" SLIP STOP, FLOW THRU SUB, & SPARTEK GAUGES; 1,855.0 Annular Fluid - Saltwater/Brine; 34.6-2,633.2 CONDUCTOR; 40.0-169.0 HANGER; 34.6 KUP PROD 3R-107 ... 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0RWRU6KURXG 0RWRU&HQWUDOL]HU 5(75,(9$%/((6302725 $66(0%/< 0RWRU6KURXG 0RWRU&HQWUDOL]HU 0RWRU6KURXG 0RWRU&HQWUDOL]HU 0RWRU6KURXG 0RWRU&HQWUDOL]HU 0RWRU6KURXG 0RWRU&HQWUDOL]HU 0RWRU6KURXG 0RWRU&HQWUDOL]HU 0RWRU6KURXG 6OLGLQJ6OHHYH 5(75,(9$%/((633803 $66(0%/< 3$&.2))$66(0%/< 6/,36723 *$8*(38036(1625 *$8*(38036(1625 *$6/,)7 $QQXODU)OXLG'LHVHO *$6/,)7 685)$&( $QQXODU)OXLG6DOWZDWHU%ULQH &21'8&725 +$1*(5 .83352' 5 :(//1$0( :(//%25( James B From: Sent: Regg, James B (CED) Friday, October 23, 2020 10:27 AM To: AOGCCf, Subject: FW: [EXTERNAL]RE: COP 3R-107 NFT r / I guess another SSSV after they do some well intervention. See below. Jim Regg Supervisor, Inspections AOGCC 333 W. 7^ Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Trower, Alex J <Alex.J.Trower@conocophillips.com> Sent: Friday, October 23, 2020 9:25 AM To: Regg, James B (CED) <jim.regg@alaska.gov> Cc: Loepp, Victoria T (CED) <victoria.loepp@alaska.gov> Subject: RE: [EXTERNAL]RE: COP 311-107 NFT Current plan is to rig up coiled tubing to pull ESP, brush SSSV Thanks, Alex From: Regg, James B (CED) <jim.regg Dalaska gov> Sent: Friday, October 23, 2020 9:19 AM To: Trower, Alex J <AIex.J.Trower(a)conoconhillios com> Cc: Loepp, Victoria T (CED) <victoria loepot7a_ alaska eov> Subject: [EXTERNAL)RE: COP 3R-107 NFT KC" 302-107 P"t 7-l'i 1 Roo 1Q1z31Zezo verify function, then reinstall ESP in kind. Well work? Jim Regg Supervisor, Inspections AOGCC 333 W. 7° Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Trower, Alex J <Alex.J.Trower(a�conocoohillios com> Sent: Friday, October 23, 2020 8:45 AM To: Regg, James B (CED) <jim.re¢z@alaska.aov> Subject: COP 3R-107 NFT Hello Jim, ,✓ As you may have heard, 3R-107 won't bleed off to support our no -flow test. For this reason, we're canceling the test and proceeding to intervention. The FBHP & productivity index looked encouraging, but now that the wel is s u -m i Just won't bleed down. We'll plan to revert to testing the SSSV with the previously approved procedure once wellwork is complete. Sorry for the runaround — really appreciate you working with us on this. Thanks, Alex Trower Drillsite Petroleum Engineer Kuparuk I 3ABCFJK/R ConocoPhillips Alaska 0:(907)263-3733 C:(785)691-6746 Kees - �-(o-? PM 21-1recto Regg, James B (CED) From: Trower, Alex J <Alex.J.Trower@conocophillips.com> Sent: Friday, October 16, 2020 1:01 PM � jolt&(Zo To: Regg, James B (CED) Subject: RE: [EXTERNAL]RE: 311-107 SSSV Test Procedure Attachments: 3R-107 NFT Procedure v4.docx Thanks, here's that update. The changes are all on page 2: Step 3 now includes documenting the duration of the pre-test bleed alongside the baseline pressures, and step 4 is to isolate the SSSV control line & monitor throughout test. Hope this is sufficient! Let me know if you have any other recommendations. Thanks, Alex Trower Drillsite Petroleum Engineer Kuparuk 13ABCFJK/R ConocoPhillips Alaska 0:(907)263-3733 C:(785)691-6746 From: Regg, James B (CED) <jim.regg@alaska.gov> Sent: Friday, October 16, 2020 10:44 AM To: Trower, Alex J <Alex.J.Trower@conocophillips.com> Subject: RE: [EXTERNAL]RE: 311-107 SSSV Test Procedure Just asking for the time and duration resulting from existing step 3 to be documented. Jim Regg Supervisor, Inspections AOGCC 333 W. 71" Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Trower, Alex J <Alex J Trower@conocophillips.com> Sent: Friday, October 16, 2020 9:02 AM To: Regg, James B (CED) <[im.regg@alaska.goy> Subject: RE: [EXTERNAL]RE: 311-107 SSSV Test Procedure Jim, Absolutely, I can add an item to confirm the SSSV is open & pressurized if needed. The current pressure will also be available to the inspector at the time of the test. For your second point regarding time & duration of bleed —Are you asking us to specify both of those? Or are you just requesting we include a step to document them? Thanks, Alex Trower Drillsite Petroleum Engineer Kuparuk 13ABCFIK/R ConocoPhillips Alaska 0:(907)263-3733 C:(785)691-6746 From: Regg, James B (CED) <iim.regg@alaska.gov> Sent: Friday, October 16, 2020 7:25 AM To: Trower, Alex J <Alex.J.Trower@conocophillips.com> Subject: RE: [EXTERNAL]RE: 311-107 SSSV Test Procedure Two more clarifications: - when the well is shut-in, ensure the SSSV stays pressured up and OPEN; - document the time and duration for the bleed down (Step 3) prior to shutting in for the initial pressure build Jim Regg Supervisor, Inspections AOGCC 333 W. 7" Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Trower, Alex <Alex.J.Trower@conocophillips.com> Sent: Thursday, October 15, 2020 7:16 PM To: Regg, James B (CED) <iim.regg@alaska.gov> Cc: Loepp, Victoria T (CED) <victoria.loepp@alasl<a.gov>; AOGCC <'AOGCC.Inspectors@alaska.gov'> Subject: RE: [EXTERNAL]RE: 311-107 SSSV Test Procedure Hi Jim, Thanks for this! You were correct that we were testing on the flow rate option, but it was a little vague. I've incorporated your recommendations & attached the updated procedure for your review. Let me know what you think. Thanks, Alex Trower Drillsite Petroleum Engineer Kuparuk 13ABCFIK/R ConocoPhillips Alaska 0:(907)263-3733 C:(785)691-6746 From: Regg, James B (CED) <iim.regg@alaska.gov> Sent: Thursday, October 15, 2020 9:53 AM To: Trower, Alex J <Alex.!.Trower@conocophillips.com> Cc: Loepp, Victoria T (CED) <victoria.loepp@alaska.gov>; AOGCC <'AOGCC.Inspectors@alaska.gov'> Subject: RE: [EXTERNAL]RE: 311-107 SSSV Test Procedure There are 2 options for a no -flow test; pressure discharge or flow rate. The attached procedure is not clear which option you intend to use and how it will be implemented. Since you intend to use a low flow meter (ERDCO), i ppears the test will be attempting to demonstrate the well will not flow in excess of 900 scfm or 6.3 gpm. That test ould be performed as follows: Option A — Fluid Flow Rate ➢ Record tubing (T), inner annulus (IA), and outer annZOA ures before the well is shut in to start No -Flow Test ➢ Shut in well to monitor pressure buildup —record T,ures at least every 15 minutes ➢ At 1 -hour, open to flow through the meter and dotes and well pressures (T, IA, OA) at 5 -minute increments until the rate exceed 30 minutes ➢ Repeat the shut-in/flow monitoring steps4 to less than the acceptance criteria, not to least 2 times ➢ Test acceptance: flow rates not ex5cqi6ding 6.3 gallons per hour liquid and 900 standard cubic feet per hour gas demonstrated b at least 2 consecutive flow monitoring periods Make sure all offset injectors remain online inject g at their normal rate, and have information available for Inspector's review at the time of no -flow test. Jim Regg Supervisor, Inspections AOGCC 333 W. 71' Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Trower, Alex <Alex!.Trower@conocoPhil Iips.com> Sent: Wednesday, October 14, 20205:08 PM To: Regg, James B (CED) <iim.regg@alaska.gov> Cc: Loepp, Victoria T (CED) <victoria.loepp@alaska.gov>; AOGCC <' CC.Inspectors@alaska.gov'> Subject: RE: [EXTERNAL]RE: 313-107 SSSV Test Procedure Hello Jim, See attached for our updated 311-107 NFT proced9w. We started with the procedure from the initial attempt back in March and made two minor changes as follows Updated the metering specificati s (pg 1, item 1a). We're now using the ERDCO Armor-flo that was recommended during the firs,t4ttempt. The photos and calibration details were updated as well Made a note on the skid-unted orifice flowmeter (pg 2, item 1a). We're not going to use that particular meter so we'll remove the orifi a plate based on feedback from the inspector on the last round. The ERDCO meter will be used instead for is purpose Please let me know if you have any questions or concerns with the procedure as written. We will wait for your guidance on how to proceed. Thanks, 4 311-107 No Flow Test Procedure Versiorq.3� Summary: 311-107 is attempting to pass on the following NFT criteria: 1. Measured liquid production is not greater than 6.3 gallons per hour (GPH) and the measured gas production is not greater than 900 standard cubic feet per hour (SCFH). The following procedure outlines how this will be accomplished. Pre -Work: 1. 72 hours prior to no flow test a) Verify operability of low-pressure gauge, temperature transmitter and flow meter i. ERDCO Armor -Flo flowmeter is in the SVS Tech office at Kuparuk ii. Meter is %" female NPT on both ends and can be threaded on after the well is bled off, as this is piece of equipment is only rated to 400 PSI iii. Meter was calibrated 06/20 by the manufacturer iv. Meter reads a range of 0-1500 SCFH 2. 48 hours prior to no flow test a) Notify AOGCC of no flow test (NSK Production Technician) b) Stage tanks for no flow test at 311 pad c) Relocate meter to 3R and connect wireless gauge into SCADA i. Verify tags are appropriately reading into IP.21 ii. Meter should be kept warm and protected 3. 24-48 hours prior to no flow test a) Shut in well (CPF3 Operations) b) Isolate well from flowlines with blinds or dropping pipe (CPF3 Operations) c) Rig up the following piping i. Hardline from IA to tank and 1" hose to meter ii. 1" hose from treecap to hardline and NFT meter iii. 1" hose from IA to meter iv. Hardline from meter to tank d) Bleed tubing and IA pressures to open top tank (CPF3 Operations) i. Leave flow path open to atmosphere Page 1 of 6 311-107 No Flow Test Procedure Version 3 Day of the Test: 1. Verify install test equipment downstream of IA and Tubing (NSK SVS Technicians) a. Orifice flowmeter (not used for this test — orifice plate removed) b. ERDCO Armor-flo Flowmeter C. Temperature transmitter d. Low pressure local gauge off tree cap e. X turn full open ball valve f. Hose to atmospheric tank 2. Conduct pre job discussion in control room at DS311 a. Personnel onsite: i. Production Engineer ii. AOGCC Representative iii. SVSTechnicians iv. Operations Representative 3. Record initial tubing (T), inner annulus (IA), and outer annulus (OA) pressures 4. Begin test by shutting in well a. Monitor pressure buildup by recording T, IA, and OA pressures every 15 minutes S. After one hour, open well to flow through ERDCO meter a. Document flow rates & well pressures (T, IA, OA) at 5 -minute increments until the rate has declined to below the acceptance criteria, not to exceed 30 minutes 6. Repeat the shut-in/flow monitoring steps (steps 4 & 5) at least two times 7. Test acceptance: a. Flow rates not exceeding 6.3 gallons per hour liquid and 900 standard cubic feet per hour gas demonstrated by at least 2 consecutive flow monitoring periods 8. AOGCC inspector to evaluate test data & inform on pass/fail decision 9. If test passes: a. BOL following normal 311-107 startup procedure b. Normal up SVS system 10. If test fails: a. Leave well SI pending wellwork b. Normal up SVS system -}yy u`Pi�4 kyr Z Page 2 of 6 1<4W 5P-- 107 P'Th zief(CODo Regg, James B (CED) From: Regg, James B (CED) Sent: Thursday, October 15, 2020 9:53 AM To: Trower, Alex J Cc: Loepp, Victoria T (CED); AOGCC Subject: RE: [EXTERNAL]RE: 311-107 SSSV Test Procedure ✓ There are 2 options for a no -flow test; pressure discharge or flow rate. The attached procedure is not clear which option you intend to use and how it will be implemented. Since you intend to use a low flow meter (ERDCO), it appears the test will be attempting to demonstrate the well will not flow in excess of 900 scfm or 6.3 gpm. That test should be performed as follows: - Option A— Fluid Flow Rate ➢ Record tubing (T), inner annulus (IA), and outer annulus (OA) pressures before the well is shut in to start No -Flow Test ➢ Shut in well to monitor pressure build up—record T, IA and OA pressures at least every 15 minutes ➢ At 1 -hour, open to flow through the meter and document flow rates and well pressures IT, IA, OA) at 5 -minute increments until the rate declines to less than the acceptance criteria, not to exceed 30 minutes ➢ Repeat the shut-in/flow monitoring steps at least 2 times ➢ Test acceptance: flow rates not exceeding 6.3 gallons per hour liquid and 900 standard cubic feet per hour gas demonstrated by at least 2 consecutive flow monitoring periods Make sure all offset injectors remain online injecting at their normal rate, and have information available for Inspector's review at the time of no -flow test. Jim Regg Supervisor, Inspections AOGCC 333 W. 7'h Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Trower, Alex 1 <Alex.J.Trower@conocophillips.com> Sent: Wednesday, October 14, 2020 5:08 PM To: Regg, James B (CED) <jim.regg@alaska.gov> Cc: Loepp, Victoria T (CED) <victoria.loepp@alaska.gov>; AOGCC <'AOGCC.Inspectors@alaska.gov'> Subject: RE: [EXTERNAL]RE: 311-107 SSSV Test Procedure Hello Jim, _�_ (J` 5J 1 eyv 2 -- See attached for our updated 311-107 NFT procedure. We started with the procedure from the initial attempt back in March and made two minor changes as follows: - Updated the metering specifications (pg 1, item la). We're now using the ERDCO Armor-flo that was recommended during the first attempt. The photos and calibration details were updated as well - Made a note on the skid -mounted orifice flowmeter (pg 2, item la). We're not going to use that particular meter so we'll remove the orifice plate based on feedback from the inspector on the last round. The ERDCO meter will be used instead for this purpose 3R-107 No Flow Test Procedure Version 2 Summary: 311-107 is attempting to pass on the following NFT criteria: 1. Measured liquid production is not greater than 6.3 gallons per hour (GPH) and the measured gas production is not greater than 900 standard cubic feet per hour (SCFH). The following procedure outlines how this will be accomplished. Pre -Work: 1. 72 hours prior to no flow test a) Verify operability of low-pressure gauge, temperature transmitter and flow meter i. ERDCO Armor -Flo flowmeter is in the SVS Tech office at Kuparuk ii. Meter is %" female NPT on both ends and can be threaded on after the well is bled off, as this is piece of equipment is only rated to 400 PSI iii. Meter was calibrated 06/20 by the manufacturer iv. Meter reads a range of 0-1500 SCFH 2. 48 hours prior to no flow test a) Notify AOGCC of no flow test (NSK Production Technician) b) Stage tanks for no flow test at 311 pad c) Relocate meter to 311 and connect wireless gauge into SCADA i. Verify tags are appropriately reading into I13.21 ii. Meter should be kept warm and protected 3. 24-48 hours prior to no flow test a) Shut in well (CPF3 Operations) b) Isolate well from flowlines with blinds or dropping pipe (CPF3 Operations) c) Rig up the following piping L Hardline from IA to tank and 1" hose to meter ii. 1" hose from treecap to hardline and NFT meter iii. 1" hose from IA to meter iv. Hardline from meter to tank d) Bleed tubing and IA pressures to open top tank (CPF3 Operations) L Leave flow path open to atmosphere Page 1 of 6 3R-107 No Flow Test Procedure Version 2 Day of the Test: 1. Verify install test equipment downstream of IA and Tubing (NSK SVS Technicians) a. Orifice flowmeter (not used for this test — orifice plate removed) b. ERDCO Armor-flo Flowmeter c. Temperature transmitter d. Low pressure local gauge off tree cap e. Y4 turn full open ball valve f. Hose to atmospheric tank 2. Conduct pre job discussion in control room at DS3R a. Personnel onsite: i. Production Engineer ii. AOGCC Representative iii. SVSTechnicians iv. Operations Representative 3. Confer with AOGCC representative prior to beginning test 4. Operations representative to close bypass bleed to the open tank a. Only path to the tank is through calibrated meter for tubing and IA 5. Monitor well and confirm whether test passes or fails 6. Wait on AOGCC decision whether test passes or fails 7. If test passes: a. BOL following normal 311-107 startup procedure b. Normal up SVS system 8. If test fails: a. Leave well SI pending wellwork b. Normal up SVS system Page 2 of 6 3R-107 No Flow Test Procedure Version 2 Images of No Flow Testing Equipment Page 3 of 6 311-107 No Flow Test Procedure Version 2 Page 4 of 6 3R-107 No Flow Test Procedure Version 2 Page 5 of 6 3R-107 No Flow Test Procedure Appendix B No Flow Test Setup in AOGCC Guidance Bulletin 10-004 Appendix A - No Flow Test Equipment Low pressure gauge: 1 -psi divisions '/.-turn Full } opening / Valve Flow Meter Swage connection to Tree Cap I lose or flexible line to atmospheric tank (e.g., bucket with water) Version 2 Page 6 of 6 Regg, James B (CED) From: Sent: To: Cc: Subject: Attachments: Version 4 procedure is approved. PNS z 1 � ►e:c Regg, James B (CED) / Monday, September 21, 2020 2:49 PM Trower, Alex J AOGCC; Loepp, Victoria T (CED) RE: [EXTERNAL]RE: 3R-107 SSSV Test Procedure 3R-107 SSSV Performance Test Procedure v4.docx From: Trower, Alex J <Alex.J.Trower@conocophillips.com> Sent: Friday, September 18, 2020 9:52 AM To: Regg, James B (CED) <jim.regg@alaska.gov> Cc: AOGCC <'AOGCC.Inspectors@alaska.gov'>; Loepp, Victoria T (CED) <victoria.loepp@alaska.gov> Subject: RE: [EXTERNAL]RE: 3R-107 SSSV Test Procedure Good Morning Jim, Thanks for these comments. This morning we've made the following changes: - Increased the open bleed duration to 2 hours, as you proposed in bullet #1 - Removed the iteration step (21a) - Added back language to step 21 around test acceptance, to alleviate your concerns in bullet #3 The updated version is attached with changes highlighted in yellow. Please let us know if you approve and we'll get testing scheduled as soon as possible. As always, please feel free to call with any further questions or concerns. Thanks, Alex Trower Drillsite Petroleum Engineer Kuparuk 13ABCFJK/R ConocoPhillips Alaska 0: (907) 263-3733 C: (785) 691-6746 From: Regg, James B (CED) <jim.reg @alaska.gov> Sent: Thursday, September 17, 2020 5:03 PM To: Trower, Alex J <Alex.J.Trower@conocophillips.com> Cc: AOGCC <'AOGCC.Inspectors@alaska.gov'>; Loepp, Victoria T (CED) <victori e alaska. ov> Subject: RE: [EXTERNAL]RE: 3R-107 SSSV Test Procedure Comments on test procedure version 3: - The initial bleed of the IA pressure after closing the SS (step 20b) seems to be ok (no different than creating a differential across a valve for a performance test). onger bleed time 1-2 hrs (?) would be ok. - The test is verifying the performance of the SSSV (close and hold differential pressure) not the function (close only). - Previous procedure (version 2) included test acceptance — "No buildup of IA pressure indicates closed SSSV & passing test". The new procedure drops the test acceptance. STANDARD OPERATING PROCEDURES Updated 9/1 20 Summary: qj,�,(��,� This procedure provides general guidelines for state -required Safety Valve System (SVS) testing on 3R J'7� ESP -lifted oil production wells (with SSSV below ESP). Objective: Performance test 311-107 surface safety valves & subsurface safety valve by demonstrating a pressure differential across the SSSV and no pressure buildup in annulus. Procedure: Notify AOGCC 24 hours before 3R-107 SSSV performance test 1. Close hydraulic accumulator supply on both SVS panel and SSSV panel 2. Install calibrated gauge to tree cap, open swab 3. Install calibrated gauge on IA surface piping 4. Install calibrated digital test gauge with bleed manifold to LPP test fitting, record FTP 5. Radio Summit representative to shut down ESP 6. Close wing after confirmation of ESP stop 7. Close needle valve on wellhead to SSSV hydraulic control line Testing LPP, Tubing & IA SSVs: 8. Close root valve below LPP (pressure switch), slowly bleed pressure off until SSV starts to close signaling a "trip". Record trip pressure. 9. Once tubing SSV is fully closed and both hydraulic panels read Opsi open tree cap and bleed off the pressure between SSV and wing a. If FTP is 200 psi or more over header pressure the wing can be opened to release pressure down flowline then shut back in 10. Mark down results of passing or failing tubing SSV 11. Install digital calibrated test gauge with hydraulic fitting onto bleed ring between IA casing valve & IA SSV 12. Close casing valve on IA 13. Using truck hydraulic pump, build differential pressure to 200-300 psi (over starting IA pressure) between closed IA casing valve & IA SSV a. Monitor for 3-5 minutes to confirm stabilized pressure & confirm IA SSV holding 14. Mark down results of passing or failing IA SSV 15. Re -pressure SSV panel, opening both tubing SSV and IA SSV 16. Close IA to FL (downstream) plug valve (in wellhouse) 17. Open IA casing valve to prepare for SSSV test Location KUPARUK FIELD Facility FLD ConocoPhillips Section PRODUCTION SYSTEMS Document # FLD-0000-XXXXXX Alaska, Inc. Equipment OIL PRODUCTION — ESP's Document Name STATE TESTING 311 ESP LIFTED OIL WELLS (SSSV Below ESP) Document Owner Updated 9/1 20 Summary: qj,�,(��,� This procedure provides general guidelines for state -required Safety Valve System (SVS) testing on 3R J'7� ESP -lifted oil production wells (with SSSV below ESP). Objective: Performance test 311-107 surface safety valves & subsurface safety valve by demonstrating a pressure differential across the SSSV and no pressure buildup in annulus. Procedure: Notify AOGCC 24 hours before 3R-107 SSSV performance test 1. Close hydraulic accumulator supply on both SVS panel and SSSV panel 2. Install calibrated gauge to tree cap, open swab 3. Install calibrated gauge on IA surface piping 4. Install calibrated digital test gauge with bleed manifold to LPP test fitting, record FTP 5. Radio Summit representative to shut down ESP 6. Close wing after confirmation of ESP stop 7. Close needle valve on wellhead to SSSV hydraulic control line Testing LPP, Tubing & IA SSVs: 8. Close root valve below LPP (pressure switch), slowly bleed pressure off until SSV starts to close signaling a "trip". Record trip pressure. 9. Once tubing SSV is fully closed and both hydraulic panels read Opsi open tree cap and bleed off the pressure between SSV and wing a. If FTP is 200 psi or more over header pressure the wing can be opened to release pressure down flowline then shut back in 10. Mark down results of passing or failing tubing SSV 11. Install digital calibrated test gauge with hydraulic fitting onto bleed ring between IA casing valve & IA SSV 12. Close casing valve on IA 13. Using truck hydraulic pump, build differential pressure to 200-300 psi (over starting IA pressure) between closed IA casing valve & IA SSV a. Monitor for 3-5 minutes to confirm stabilized pressure & confirm IA SSV holding 14. Mark down results of passing or failing IA SSV 15. Re -pressure SSV panel, opening both tubing SSV and IA SSV 16. Close IA to FL (downstream) plug valve (in wellhouse) 17. Open IA casing valve to prepare for SSSV test STANDARD OPERATING PROCEDURES Testing SSSV: Updated 9/120 cl/l�� 18. Observe pressure on IA to ensure a measurable differential above flowline pressure a. Set up bleed trailer if inspector determines a greater differential is needed 19. Open needle valve on wellhead to SSSV, effectively closing SSSV 20. Slowly open plug valve on IA to flowline jumper (or to bleed trailer, if applicable) a. Bleed down pressure at a rate no higher than 50psi/min to prevent damage to ESP cable b. Leave IA and tubing open to flowline (or bleed trailer, if applicable) for 2 hours to allow sufficient gas breakout in IA 21. Close block valve and monitor IA gauge for pressure build up for 30 minutes or until inspector deems sufficient to establish SSSV is effectively isolating formation pressure buildup a. Passing test will entail no detectable leakage as evidenced by a stabilized, flat -line pressure response on the IA 22. Mark down results of passing or failing SSSV 23. Normal well back up & hand back to Operations for startup (addressed in a separate document) Location KUPARUK FIELD Facility FLD ConocoPhillips Section PRODUCTION SYSTEMS Document # FLD-0000-XXXXXX Alaska, Inc. Equipment OIL PRODUCTION — ESP's Document Name STATE TESTING 3111 ESP LIFTED OIL WELLS (SSSV Below ESP) Document Owner Testing SSSV: Updated 9/120 cl/l�� 18. Observe pressure on IA to ensure a measurable differential above flowline pressure a. Set up bleed trailer if inspector determines a greater differential is needed 19. Open needle valve on wellhead to SSSV, effectively closing SSSV 20. Slowly open plug valve on IA to flowline jumper (or to bleed trailer, if applicable) a. Bleed down pressure at a rate no higher than 50psi/min to prevent damage to ESP cable b. Leave IA and tubing open to flowline (or bleed trailer, if applicable) for 2 hours to allow sufficient gas breakout in IA 21. Close block valve and monitor IA gauge for pressure build up for 30 minutes or until inspector deems sufficient to establish SSSV is effectively isolating formation pressure buildup a. Passing test will entail no detectable leakage as evidenced by a stabilized, flat -line pressure response on the IA 22. Mark down results of passing or failing SSSV 23. Normal well back up & hand back to Operations for startup (addressed in a separate document) STANDARD OPERATING PROCEDURES Appendix A — 3R-107 SSSV Panel Pressures Location KUPARUK FIELD Facility FLD ConocoPhillips Section PRODUCTION SYSTEMS Document # FLD-0000-XXXXXX Alaska, Inc. Equipment OIL PRODUCTION — ESP's Document Name STATE TESTING 3R ESP LIFTED OIL WELLS (SSSV Below ESP) Document Owner Appendix A — 3R-107 SSSV Panel Pressures Updated 9/10/2 J TSS 3R-107 Start to Open 4,200 Fully Open 4,800 Start to Close 2,900 Fully Close 2,500 TVD Valve 3,644 Tbg Pressure 1,400 Rec Hold Open 3,390 Hyd Fluid 0.387 psi/ft Updated 9/10/2 J TSS STANDARD OPERATING PROCEDURES Appendix B — Schematic Summary of 311-107 Location KUPARUK FIELD Facility FILD ConocoPhillips Section PRODUCTION SYSTEMS Document # FLD-0000-XXXXXX Alaska, Inc. Equipment OIL PRODUCTION — ESP's Document Name STATE TESTING 311 ESP LIFTED OIL WELLS (SSSV Below ESP) Document Owner Appendix B — Schematic Summary of 311-107 Updated 9J-1 �2020 qb 61 �z-o 3.00'T%D f-^ legless EaP-vireiSoe ... bl. p -p --4963'-MD 637'T'l*D 1Wl1he.d!T.bigH-d1T 3R-107 Dual Literal Slatted Liner :Q's r .-,", 5.0cOp.: Producer :3cnndnnoFinal Schematic 0 e) :64 M) 1 :69' TIM Of 14 5,171 19 3.645- W. 3 7S0' DS Und.;.:Pple P-511 L111-1 E111 11L 13-1 OH, IM 4'% 45,5-, L-80, H,diu-6z MD '-16Q'TVD -61 1!D d 3.64VTVD Sys B-3 H..k 4-1:2-.1:6 LZO, 7XP. SL—d L.. •OH I.—] Z..y •r 13.473MD ),-7:'^ 7 TD z 13 610'NM 3.-7-','= 0. LiftMlud.:. 4.1 1, -,1' KaNICT. 2,63 3rjJD L -M H�Af6, ------ ........ Updated 9J-1 �2020 qb 61 �z-o JU- 3.00'T%D f-^ legless EaP-vireiSoe ... bl. p -p --4963'-MD 637'T'l*D 43" 3 913' CNIV Sliding Sl- a, X-L'adi- 11PPIt It 5.063- 3,547'TV D 14 5,171 19 3.645- W. 3 7S0' DS Und.;.:Pple P-511 L111-1 E111 11L -61 1!D d 3.64VTVD Sys B-3 H..k 4-1:2-.1:6 LZO, 7XP. SL—d L.. •OH I.—] Z..y •r 13.473MD ),-7:'^ 7 TD z 13 610'NM 3.-7-','= ------------ ........ .................................... ------ ........ 80 TXR 9 ttadL..1 -D -OH TD.,13.633-D3-91n= I'D .'S- T% ............... 7,049MD 3M1 7,-D 4-1," 6 OD WIL JU- Regg, James B (CED) From: Regg, James B (CED) Sent: Thursday, September 17, 2020 5:03 PM To: Trower, Alex J Cc: AOGCC; Loepp, Victoria T (CED) Subject: RE: [EXTERNAL]RE: 3R-107 SSSV Test Procedure Comments on test procedure version 3: - The initial bleed of the IA pressure after closing the SSSV (step 20b) seems to be ok (no different than creating a differential across a valve for a performance test). Longer bleed time 1-2 hrs (?) would be ok. - The test is verifying the performance of the SSSV (close and hold differential pressure) not the function (close only). - Previous procedure (version 2) included test acceptance — "No buildup of IA pressure indicates closed SSSV & passing test". The new procedure drops the test acceptance. - AOGCC disagrees with the iteration proposed in Step 21a ("Repeat steps 20 & 21 if unable to verify SSSV function due to further gas breakout in IA"). What is proposed is effectively a retest following a failure which is still a failure in our vernacular, not a passing test, and requires corrective action. From: Trower, Alex J <Alex.J.Trower@conocophillips.com> Sent: Wednesday, September 16, 2020 8:13 AM To: Regg, James B (CED) <jim.regg@alaska.gov> Subject: RE: [EXTERNAL]RE: 3R-107 SSSV Test Procedure Good Morning Jim, Just wanted to check in on this procedure and see if you had any questions we could address, or if there might be line of sight to a resolution. I hadn't seen any comments from AOGCC yet; just making sure I haven't missed anything. Feel free to call anytime if you'd like to discuss... Thanks, Alex Trower Drillsite Petroleum Engineer Kuparuk 13ABCFJK/R ConocoPhillips Alaska 0: (907) 263-3733 C: (785) 691-6746 From: Trower, Alex J Sent: Monday, September 14, 2020 8:28 AM To: Regg, James B (CED) <jim.reg@alaska.gov> Subject: RE: [EXTERNAL]RE: 3R-107 SSSV Test Procedure Thanks —The well was shut-in this weekend. As always, please don't hesitate to contact us with any concerns you have about the procedure. Looking forward to a resolution on this! Best, Alex Trower Drillsite Petroleum Engineer Kuparuk 13ABCFJK/R ConocoPhillips Alaska 0: (907) 263-3733 C: (785) 691-6746 From: Regg, James B (CED) <jim.re 9 aIaska.gov> Sent: Friday, September 11, 2020 7:34 PM To: Trower, Alex J <Alex J Trower@conocophillips.com> Subject: RE: [EXTERNAL)RE: 3R-107 SSSV Test Procedure No test this weekend; we are reviewing the procedure and will have comments maybe on Monday. ConocoPhillips is free to test but AOGCC will not be witnessing — instructions sent to that end in response to test notice received this afternoon. Well can remain online not more than 14 days from date of failure per regulation: 20 AAC 25.265(i)(3) for a well equipped with both a surface safety valve and a commission -required subsurface safety valve... (B) if either the surface safety valve or commission -required subsurface safety valve leaks, the leaking valve must, not later than 14 days after the leak is found, be both repaired or replaced and performance -tested, or the well must be shut-in; Jim Regg Supervisor, Inspections AOGCC 333 W.7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim.regg alaska.gov. From: Trower, Alex J <Alex J Trowillips.c er@conocophom> Sent: Friday, September 11, 2020 5:42 PM To: Regg, James B (CED) <jim.reg alaska.gov> Subject: RE: [EXTERNAL]RE: 311-107 SSSV Test Procedure Hi Jim — Wanted to touch base on this since we're not sure where things stand. Certainly not trying to rush your approval, and I do apologize for how quickly we had to turn this around — we were still troubleshooting this SSSV as of this Wednesday! Our Ops folks were hoping to do this test this weekend but if there's still a need for additional review & discussion we certainly understand. However, if additional time is needed, would AOGCC consider allowing the well to continue producing until we can get alignment on this procedure? Please let me know what you think. Thanks for your time, Alex Trower Drillsite Petroleum Engineer Kuparuk 13ABCFJK/R ConocoPhillips Alaska 0:(907)263-3733 C: (785) 691-6746 From: Trower, Alex J Sent: Thursday, September 10, 2020 11:10 AM To: Regg, James B (CED) <jim.regg2alaska.gov> Cc: AOGCC <'AOGCC.Inspectors@alaska.gov'> Subject: RE: [EXTERNAL]RE: 311-107 SSSV Test Procedure Hello Jim, We've been working the last two weeks to come up with an improved process for testing 3R -107's SSSV. After several days of troubleshooting, it is our belief that the SSSV is functioning correctly, but due to gas breakout from produced fluids in the IA, we weren't able to demonstrate this using the previously approved procedure. Thanks in part to some great feedback from your inspectors, we've come up with an updated version which you'll find attached. The changes versus the prior procedure are all in the SSSV testing section, steps 18-23. The primary updates to this version are: - We will bleed the IA for one hour (step 20b) after shutting the SSSV in order to allow the fluid in the IA to equalize - Then, we'll isolate the IA and monitor for pressure buildup for 30 minutes - Additionally, we've included a step (21a) to repeat the bleed if we're still seeing gas interference on the IA pressure trend We hope to schedule a re -test on this well as soon as possible, so please don't hesitate to contact me with any questions you might have. Thanks, Alex Trower Drillsite Petroleum Engineer Kuparuk 13ABCFJK/R ConocoPhillips Alaska O: (907) 263-3733 C: (785) 691-6746 From: Regg, James B (CED) <jim.regg@alaska.gov> Sent: Friday, August 28, 2020 5:01 PM To: Trower, Alex J <Alex.J.Trower@conocophillips.com> Cc: AOGCC <'AOGCC.lnspectors@alaska.gov'> Subject: FW: [EXTERNAL]RE: 3R-107 SSSV Test Procedy Thank you. ok to proceed with testing. Please ntact AOGCC Inspector using the web notice form. MEMORANDUM TO: Jim Regg Q'I P. I. Supervisor FROM: Brian Bixby Petroleum Inspector State of Alaska Alaska Oil and Gas Conservation Commission q'/51z'u-' DATE: September 3, 2020 SUBJECT: SVS Test KRU 3R-107 " ConocoPhillips Alaska PTD 2191800 - 8/29/2020: 1 traveled to KRU 3R-107 to witness a safety valve system (SVS) test. The well is an ESP completion producing from the West Sak with a deep-set SSSV below the ESP and an open sliding sleeve. There are also an actuated SSV and manual block valve on the tubing -casing annulus outlet that would be tested. The test procedure was reviewed and approved by AOGCC prior to the test. CPAI Pad Operator Joey Foshaug performed the test as follows: Pre-test Tubing/IA/OA Pressures = 176/176/320 psi Separator Pressure = 82 psi LPP and Tubing SSV Test v The low-pressure pilot (LPP) set pressure was 70 psi and tripped at 70 psi. The tubing built up to 340 psi and they bled down above the SSV via the tree cap to 50 psi. The SSV held GOOD. IA SSV Test With the IA SSV fully closed, the IA valve manual valve was closed and the void between the valves pressured up to 580psi:'The IA SSV held GOOD. SSSV Test The control line needle valve to the SSSV was opened to close the SSSV. The manual IA and the IA SSV were opened to the flowline showing 341 psi. The flowline valve was opened, and IA pressure bled it until it stopped at 180 psi. They then opened up a bleed via a '/2" bleed hose to a trailer for 15 to 20 minutes and it stopped going down at 150 psi. The well was shut in for 30 minutes and get the readings. After 30 minutes the IA pressure built back up to 300 psi. (end initial test) A second hose was rigged up to the bleed trailer and the IA was again bled from 180 psi after taking the initial bleed down the flowline from 300 psi to 180 psi. After 30 minutes of bleeding to the trailer, the pressure would not drop below 130psi. The tubing was bled from 700 psi to 180 psi through the flowline then shut in for 30 minutes. The IA pressure increased to 221 psi and tubing to 280 psi in 30 minutes. (end retest) I put on my RBDMS test report that the SSSV failed to hold differential pressure. -- 2020-0829 SVS_KRU_3R-107_bb.docx Page 1 of 1 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg12�� y�,��, DATE: September 3, 2020 P. I. Supervisor FROM: Brian Bixby Petroleum Inspector SUBJECT: SVS Test - Retest KRU 3R-107 - ConocoPhillips Alaska PTD 2191800 11 9/3/2020: 1 traveled to KRU 3R-107 to witness a retest of the KRU 3R-107 safety valve ' system (SVS). The well's SSSV failed to hold a pressure differential on its initial attempts done 8/29/2020. CPAI Pad Operator Brian Martin performed the test. Pre-test conditions: Tubing/IA/OA Pressures = 163/163/320 psi; Separator Pressure = 83 psi. 10:22am — Summit shutdown the ESP 10:42am — Tubing/IA/OA Pressures = 255/290/320 psi 10:45am — LPP/SSV Test. The Low -Pressure Pilot set pressure was 70 psi; tripped at 69 psi (LPP - pass). With the SSV and Wing Valve closed pressure between the valves was bled to 0 psi. Pressure above the SSV was monitored for 5 minutes with 0 psi build up (SSV - pass). 10:51 am — The manual IA block valve and the hydraulic IA SSV were closed. The void between the valves was pressured up to 630 psi and held for 5 minutes with a 5 -psi pressure drop. Test gauge located downstream of the IA SSV and upstream of the closed flowline valve indicated 0 psi increase (IA SSV - pass). 11:10am — The control line needle valve to the SSSV was opened to close the SSSV. 11:13am — Bled IA from 365 psi to 155 psi in 6 minutes. 11:19am — Closed bleed and monitored for 30 minutes. 11:49am — IA increased 100 psi, from 155 psi to 255 psi, in 30 minutes (SSSV — fail to hold differential pressure). 11:53am — Bled IA again from 255 psi to 140 psi in 3 minutes for 2nd attempt. 11:56am — Closed bleed and monitored for 30 minutes. 12:26pm — IA increased 100 psi, from 140 psi to 240 psi, in 30 minutes (SSSV — fail to hold differential pressure). I put on my RBDMS test report that the SSSV failed to hold differential pressure. 2020-0903—SVS—Retest KRU 3R-107 bb.docx Page 1 of 1 Int 3R -(07 Regg, James B (CED) From: Regg, James B (CED) Sent: Friday, August 28, 2020 5:01 PM To: Trower, Alex J ] Cc: AOGCC Subject: FW: [EXTERNAL]RE: 3R-107 SSSV Test Procedure Attachments: 3R-107 SSSV Performance Test Procedure Final v2.docx Thank you. ok to proceed with testing. Please contact AOGCC Inspector using the web notice form. Jim Regg Supervisor, Inspections AOGCC 333 W.7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 orjim.regg@alaska.gov. From: Trower, Alex J <Alex.J.Trower@conocophillips.com> Sent: Friday, August 28, 2020 1:07 PM To: Regg, James B (CED) <jim.regg@alaska.gov> Subject: RE: [EXTERNAL]RE: 3R-107 SSSV Test Procedure Jim, Thanks for the call this morning. To address your question regarding testing of the IA SSV (and the other questions addressed below) we added several steps to the testing procedure, which you'll find attached. To confirm from our discussion — yes the IA SSV would be closing during the test, but there were no explicit steps to test it. This version adds steps 11-16 (with all changes highlighted in yellow) to isolate the IA SSV and confirm that it's holding pressure. We also tried to differentiate a little better between steps for testing the tubing SSV versus testing the IA SSV so hopefully that's a little more clear in this version. Additionally, I went ahead and increased the IA monitor period from 10 min to 30 minutes (from our email exchange the other day) — I forgot to confirm with you this morning whether this was the appropriate amount of monitor time, but please let me know if not. I hope this will be sufficient. Please don't hesitate to give me a call if you have any questions or would like me to walk through these updates with you. Thanks, Alex Trower Drillsite Petroleum Engineer STANDARD OPERATING PROCEDURES 1�2�t 312-107 s Location KUPARUK FIELD Facility FLD COnOCOPiIillips Alaska,lnc. Section PRODUCTION SYSTEMS Document # FLD-0000-XXXXXX Equipment OIL PRODUCTION — ESP's Document Name STATE TESTING 311 ESP LIFTED OIL WELLS (SSSV Below ESP) Document Owner Summary: Updated 8/18/2020 � This procedure provides general guidelines for state -required Safety Valve System (SVS) testing on 3R ESP -lifted oil production wells (with SSSV below ESP). Objective: Performance test 311-107 surface safety valves & subsurface safety valve by demonstrating a pressure differential across the SSSV and no pressure buildup in annulus. Procedure: Notify AOGCC 24 hours before 3R-107 SSSV performance test 1. Close hydraulic accumulator supply on both SVS panel and SSSV panel 2. Install calibrated gauge to tree cap, open swab 3. Install calibrated gauge on IA surface piping 4. Install calibrated digital test gauge with bleed manifold to LPP test fitting, record FTP 5. Radio Summit representative to shut down ESP 6. Close wing after confirmation of ESP stop 7. Close needle valve on wellhead to SSSV hydraulic control line Testing LPP, Tubing & IA SSVs: 8. Close root valve below LPP (pressure switch), slowly bleed pressure off until SSV starts to close signaling a "trip". Record trip pressure. 9. Once tubing SSV is fully closed and both hydraulic panels read Opsi open tree cap and bleed off the pressure between SSV and wing a. If FTP is 200 psi or more over header pressure the wing can be opened to release pressure down flowline then shut back in 10. Mark down results of passing or failing tubing SSV 11. Install digital calibrated test gauge with hydraulic fitting onto bleed ring between IA casing valve & IA SSV 12. Close casing valve on IA 13. Using truck hydraulic pump, build differential pressure to 200-300 psi (over starting IA pressure) between closed IA casing valve & IA SSV a. Monitor for 3-5 minutes to confirm stabilized pressure & confirm IA SSV holding 14. Mark down results of passing or failing IA SSV 15. Re -pressure SSV panel, opening both tubing SSV and IA SSV 16. Close IA to FL (downstream) plug valve (in wellhouse) 17. Open IA casing valve to prepare for SSSV test STANDARD OPERATING PROCEDURES Updated 8/18/2020 Testing SSSV: 18. Observe pressure on IA to ensure at least 200psi differential above flowline pressure 19. Open needle valve on wellhead to SSSV effectively closing SSSV 20. Slowly open plug valve on IA to flowline jumper a. Bleed down pressure at a rate no higher than 50psi/min to prevent damage to ESP cable 21. Once IA is equalized with flowline pressure, close block valve and monitor IA gauge for pressure build up for 30 minutes or until inspector deems sufficient a. No buildup of IA pressure indicates closed SSSV & passing test 22. Mark down results of passing or failing SSSV 23. Normal well back up & hand back to Operations for startup (addressed in a separate document) Location KUPARUK FIELD Facility FLD ConocoPhillips Section PRODUCTION SYSTEMS Document # FLD 0000-XXXXXX Alaska, Inc. Equipment OIL PRODUCTION —ESP's Document Name STATE TESTING 311 ESP LIFTED OIL WELLS (SSSV Below ESP) Document Owner Updated 8/18/2020 Testing SSSV: 18. Observe pressure on IA to ensure at least 200psi differential above flowline pressure 19. Open needle valve on wellhead to SSSV effectively closing SSSV 20. Slowly open plug valve on IA to flowline jumper a. Bleed down pressure at a rate no higher than 50psi/min to prevent damage to ESP cable 21. Once IA is equalized with flowline pressure, close block valve and monitor IA gauge for pressure build up for 30 minutes or until inspector deems sufficient a. No buildup of IA pressure indicates closed SSSV & passing test 22. Mark down results of passing or failing SSSV 23. Normal well back up & hand back to Operations for startup (addressed in a separate document) STANDARD OPERATING PROCEDURES Appendix A — 311-107 SSSV Panel Pressures Location KUPARUK FIELD Facility FLD ConocoPhillips Section PRODUCTION SYSTEMS Document # FLD-0000 XXXXXX Alaska, Inc. Equipment OIL PRODUCTION — ESP's Document Name STATE TESTING 3R ESP LIFTED OIL WELLS (SSSV Below ESP) Document Owner Appendix A — 311-107 SSSV Panel Pressures Updated 8/18/2020 J�L 3R-107 Start to Open 4,200 Fully Open 4,800 Start to Close 2,900 Fully Close 2,500 TVD Valve 3,644 Tbg Pressure 1,400 Rec Hold Open 3,390 Hyd Fluid 0.387 psi/ft Updated 8/18/2020 J�L STANDARD OPERATING PROCEDURES Location KUPARUK FIELD Facility FLD Document # FLD-0000-XXXXXX ConocoPhillips Section PRODUCTION SYSTEMS Alaska, Inc. 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Couple items: - Previous test procedure refers to using downhole gauges for determining if the SSSV is able to maintain a differential pressure across the valve; where will pressures be monitored for this procedure and if changed, why? Describe test gauges - Procedure mentions monitoring for 10 minutes to ensure the SSSV is holds pressure; 5000ft of 4.5" x 7" annular space warrants monitoring for much longer (CPAI used annular space and time to build pressure as justification for not performance testing packer vent valves) - What is the target starting differential pressure across the SSSV for the performance test? - Tubing and IA pressure must be monitored; both should have at least a 50 psi differential between tubing and IA - What are current orientations of the gas lift mandrel (2633 ft MD) and sliding sleeve (5068 ft MD)? Same during testing? - Will tubing and IA be bled to production or to a tiger tank? - How does CPAI plan to service the SSSV in the event of a failure? Jim Regg Supervisor, Inspections AOGCC 333 W.711 Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim.regg@alaska.gov. From: Trower, Alex J <Alex.J.Trower@conocophillips.com> Sent: Tuesday, August 18, 2020 11:49 AM To: Regg, James B (CED) <jim.regg@alaska.gov>; Loepp, Victoria T (CED) <victoria.loepp@alaska.gov> Subject: 3R-107 SSSV Test Procedure Jim, Victoria: Attached you'll find our SSSV testing procedure for 313-107. The team added quite a bit more detail to the procedure and I wanted to share it with you two so that I can address any questions you might have prior to testing. As you'll recall, the well has a deep-set SSSV so the testing procedure looks somewhat different from a more typical well. (For reference, there's a schematic included in the document as well.) Here are the bullet points: - We will shut down the ESP completely in order to provide a static annulus for monitoring - We'll then equalize the inner annulus to flowline pressure o Annular pressure drawdown rate is limited by our ESP provider's recommendation, so drawdown may take several minutes Then, close the SSSV and monitor annular pressure o A passing test will entail a flat -line pressure on the inner annulus after closing the SSSV, demonstrating no pressure buildup from formation All in all, It's very similar to the procedure performed in April, with added detail & additional steps for shutting down the ESP (April's test was performed while the well was already shut-in). Please let me know if you have any questions or concerns with the procedure as written. If there are none, we'll distribute this version to Operations & plan to use it in the upcoming pad test. Thanks, Alex Trower Drillsite Petroleum Engineer Kuparuk 13ABCFJK/R ConocoPhillips Alaska 0: (907) 263-3733 C: (785) 691-6746 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23660-00-00Well Name/No. KUPARUK RIV UNIT 3R-107Completion Status1-OILCompletion Date2/19/2020Permit to Drill2191800Operator ConocoPhillips Alaska, Inc.MD13638TVD3789Current Status1-OIL5/18/2020UICNoWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:GR/Res/AZM ResNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleC3/24/2020 Electronic File: 3R-107 EOW - NAD27.pdf32251EDDigital DataC3/24/2020 Electronic File: 3R-107 EOW - NAD27.txt32251EDDigital DataC3/24/2020 Electronic File: 3R-107 EOW - NAD83.pdf32251EDDigital DataC3/24/2020 Electronic File: 3R-107 EOW - NAD83.txt32251EDDigital Data0 0 2191800 KUPARUK RIV UNIT 3R-107 LOG HEADERS32251LogLog Header ScansC5/8/2020276 13638 Electronic Data Set, Filename: 3R-107 Drilling Mechanics Depth Data.las33007EDDigital DataC5/8/2020270 2258 Electronic Data Set, Filename: 3R-107 OTK Memory 13.5inch Section Drilling Data.las33007EDDigital DataC5/8/20207075 13638 Electronic Data Set, Filename: 3R-107 OTK Memory 6.75inch Section Drilling Data.las33007EDDigital DataC5/8/20202258 7075 Electronic Data Set, Filename: 3R-107 OTK Memory 9.875inch Section Drilling Data.las33007EDDigital DataC5/8/2020270 13638 Electronic Data Set, Filename: 3R-107 OTK Memory Composite Drilling Data.las33007EDDigital DataC5/8/2020269 2258 Electronic Data Set, Filename: 3R-107 OTK Realtime 13.5 Inch Section Drilling FE Data.las33007EDDigital DataC5/8/20207075 13638 Electronic Data Set, Filename: 3R-107 OTK Realtime 6.75 Inch Section Drilling FE Data.las33007EDDigital DataC5/8/20202258 7075 Electronic Data Set, Filename: 3R-107 OTK Realtime 9.875 Inch Section Drilling FE Data.las33007EDDigital DataC5/8/2020274 13638 Electronic Data Set, Filename: 3R-107 OTK Realtime Composite Drilling Dynamics.las33007EDDigital DataMonday, May 18, 2020AOGCCPage 1 of 4: 3R-107 OTK ,Memory Composite Drilling Data.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23660-00-00Well Name/No. KUPARUK RIV UNIT 3R-107Completion Status1-OILCompletion Date2/19/2020Permit to Drill2191800Operator ConocoPhillips Alaska, Inc.MD13638TVD3789Current Status1-OIL5/18/2020UICNoC5/8/2020269 13638 Electronic Data Set, Filename: 3R-107 OTK Realtime Composite Drilling FE Data.las33007EDDigital DataC5/8/2020 Electronic File: 3R-107 Drilling Mechanics Depth Log.cgm33007EDDigital DataC5/8/2020 Electronic File: 3R-107 OTK 2MD Memory Log.cgm33007EDDigital DataC5/8/2020 Electronic File: 3R-107 OTK 2TVD Memory Log.cgm33007EDDigital DataC5/8/2020 Electronic File: 3R-107 OTK 5MD Memory Log.cgm33007EDDigital DataC5/8/2020 Electronic File: 3R-107 OTK 5TVD Memory Log.cgm33007EDDigital DataC5/8/2020 Electronic File: 3R-107 2MDRLT_4MPR.cgm33007EDDigital DataC5/8/2020 Electronic File: 3R-107 2TVDRLT_4MPR.cgm33007EDDigital DataC5/8/2020 Electronic File: 3R-107 5MDRLT_4MPR.cgm33007EDDigital DataC5/8/2020 Electronic File: 3R-107 5TVDRLT_4MPR.cgm33007EDDigital DataC5/8/2020 Electronic File: 3R-107 Drilling Mechanics Time Log Run 01.cgm33007EDDigital DataC5/8/2020 Electronic File: 3R-107 Drilling Mechanics Time Log Run 02.cgm33007EDDigital DataC5/8/2020 Electronic File: 3R-107 Drilling Mechanics Time Log Run 03.cgm33007EDDigital DataC5/8/2020 Electronic File: 3R-107 13.5 Inch Section OTK Memory Drilling Data.dls33007EDDigital DataC5/8/2020 Electronic File: 3R-107 6.75 Inch Section OTK Memory Drilling Data.dls33007EDDigital DataC5/8/2020 Electronic File: 3R-107 9.875 Inch Section OTK Memory Drilling Data.dls33007EDDigital DataC5/8/2020 Electronic File: 3R-107 OTK Memory Drilling Data.dls33007EDDigital DataC5/8/2020 Electronic File: 3R-107 OTK Realtime 13.5 Inch Section Drilling FE Data.dls33007EDDigital DataC5/8/2020 Electronic File: 3R-107 OTK Realtime 6.75 Inch Section Drilling FE Data.dls33007EDDigital DataMonday, May 18, 2020AOGCCPage 2 of 4 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23660-00-00Well Name/No. KUPARUK RIV UNIT 3R-107Completion Status1-OILCompletion Date2/19/2020Permit to Drill2191800Operator ConocoPhillips Alaska, Inc.MD13638TVD3789Current Status1-OIL5/18/2020UICNoWell Cores/Samples Information:ReceivedStart Stop CommentsSentSample SetNumberNameIntervalC5/8/2020 Electronic File: 3R-107 OTK Realtime 9.875 Inch Section Drilling FE Data.dls33007EDDigital DataC5/8/2020 Electronic File: 3R-107 OTK Realtime Composite Drilling Dynamics.dls33007EDDigital DataC5/8/2020 Electronic File: 3R-107_BH_EOW Letter.docx33007EDDigital DataC5/8/2020 Electronic File: 3R-107 Drilling Mechanics Depth Log.pdf33007EDDigital DataC5/8/2020 Electronic File: 3R-107 OTK 2MD Memory Log.pdf33007EDDigital DataC5/8/2020 Electronic File: 3R-107 OTK 2TVD Memory Log.pdf33007EDDigital DataC5/8/2020 Electronic File: 3R-107 OTK 5MD Memory Log.pdf33007EDDigital DataC5/8/2020 Electronic File: 3R-107 OTK 5TVD Memory Log.pdf33007EDDigital DataC5/8/2020 Electronic File: 3R-107 2MDRLT_4MPR.pdf33007EDDigital DataC5/8/2020 Electronic File: 3R-107 2TVDRLT_4MPR.pdf33007EDDigital DataC5/8/2020 Electronic File: 3R-107 5MDRLT_4MPR.PDF33007EDDigital DataC5/8/2020 Electronic File: 3R-107 5TVDRLT_4MPR.pdf33007EDDigital DataC5/8/2020 Electronic File: 3R-107_Drilling Mechanics Time Log_Run1.pdf33007EDDigital DataC5/8/2020 Electronic File: 3R-107_Drilling Mechanics Time Log_Run2.pdf33007EDDigital DataC5/8/2020 Electronic File: 3R-107_Drilling Mechanics Time Log_Run3.pdf33007EDDigital DataC5/8/2020 Electronic File: 3R-107_Final Surveys.pdf33007EDDigital DataC5/8/2020 Electronic File: 3R-107_Final Surveys.txt33007EDDigital DataC5/8/2020 Electronic File: 3R-107_Final Surveys.xlsx33007EDDigital DataC5/8/2020 Electronic File: 3R-107_Final Survey_DDO.xls33007EDDigital Data0 0 2191800 KUPARUK RIV UNIT 3R-107 LOG HEADERS33007LogLog Header ScansMonday, May 18, 2020AOGCCPage 3 of 4 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23660-00-00Well Name/No. KUPARUK RIV UNIT 3R-107Completion Status1-OILCompletion Date2/19/2020Permit to Drill2191800Operator ConocoPhillips Alaska, Inc.MD13638TVD3789Current Status1-OIL5/18/2020UICNoINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments:Compliance Reviewed By:Date:Mud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date:2/19/2020Release Date:12/11/2019Monday, May 18, 2020AOGCCPage 4 of 4M. Guhl5/18/2020 Transmittal #1273 Detail Date: 5/8/2020 To (External Party):From (CPAI Contact): Email*: abby.bell@alaska.gov Email*: richard.e.elgarico@conocophillips.com First Name*:Abby First Name*: Ricky Last Name*: Bell Last Name*: Elgarico Phone Number:(907) 79 Phone Number: (907) 265-6580 Company: AOGCC Company: ConocoPhillips Address: 333 West 7th Ave.Address: 700 G Street City: Anchorage City: Anchorage State: AK State: AK Zip Code: 99501 Zip Code: 99501 Transmittal Info Sent Via: FTP Tracking #: Justification: Data Detail Quantity*:Description*:Type*: 1 CD4-215l1 LWD Data - CGM, LAS, PDF, TAPESCAN, TIF Digital 1 CD5-23L1 LWD Data - CGM, LAS, PDF, TAPESCAN, TIF Digital 1 CD5-23L1-01 LWD Data - CGM, LAS, PDF, TAPESCAN, TIF Digital 1 3R-105 LWD Data - CGM, LAS, PDF, TAPESCAN, TIF Digital 1 3R-105L1 LWD Data - CGM, LAS, PDF, TAPESCAN, TIF Digital 1 3R-107 LWD Data - CGM, LAS, PDF, TAPESCAN, TIF Digital 1 3R-107L1 LWD Data - CGM, LAS, PDF, TAPESCAN, TIF Digital 1 CD4-214L1 LWD Data - CGM, LAS, PDF, TAPESCAN, TIF Digital 1 3O-04L1 LWD Data - CGM, LAS, PDF, TAPESCAN, TIF Digital 1 3O-04L1-01 LWD Data - CGM, LAS, PDF, TAPESCAN, TIF Digital Received by the AOGCC 05/08/2020 PTD: 2191800 E-Set: 33007 1 3O-04L1PB1 LWD Data - CGM, LAS, PDF, TAPESCAN, TIF Digital Attachments: Received By: ___________________________ Signature: ___________________________ Date: _________________ Approver: ___________________________ Signature: ___________________________ Date: _________________ Abby Bell Abby Bell 05/08/2020 Z 17 160o, Regg, James B (CED) From: Regg, James B (CED) Sent: Tuesday, April 28, 2020 12:06 PM l�/f l 4-( JZ u; To: Valentine, Doug K Cc: NSK Fieldwide Operations Supt; Loepp, Victoria T (CED); AOGCC Subject: RE: [EXTERNAL]RE: 3R-107 (PTD #219-180) Performance Test Procedure Thank you for the information. Please use our web -based test notification form for opportunity to witness the SSSV test. Jim Regg Supervisor, Inspections AOGCC 333 W.7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim.regg@alaska.gov. From: Valentine, Doug K <Doug.K.Valentine@conocophillips.com> Sent: Monday, April 27, 2020 3:43 PM To: Regg, James B (CED) <jim.regg@alaska.gov> Cc: NSK Fieldwide Operations Supt <n2072@conocophillips.com>; Loepp, Victoria T (CED) <victoria.loepp@alaska.gov>; AOGCC <'AOGCC.Inspectors@alaska.gov'> Subject: RE: [EXTERNAL]RE: 3R-107 (PTD #219-180) Performance Test Procedure Jim, First, in regards to your questions:��t� - Do you plan to test the LPS/SSV again? o No, we tested 3/24/2020 with Bx-ian Bixby. - Is there a programmed time delay in initiating close of the SSSV (HAL NE TRSV)?; step 2.d o There is no programmed delay in initiating close of the SSSV - what is the target "measurable amount of differential pressure" when bleeding off IA pressure?; step 2.e o Minimum of 100 psi differential across the SSSV - CPAI's acceptance criteria for the IA pressure monitoring after attaining the differential pressure? o There is no internal CPAI's for IA pressure monitoring. The proposed procedure is to utilize the tubing located ESP suction gauge, PI -3115303-107, @ 5011' RKB for both the SSSV differential and to monitor pressure buildup. The acceptance criteria specifies a 10 minute monitoring period for pressure buildup. The gas lift mandrel at 2633' MD contains a shear out valve for freeze protecting the well. The SSSV is functionally equivalent to both a tubing and IA SSSV due to the linear top packer and SSSV in combination. When the SSSV is shut in, the reservoir is completed isolated from both the tubing and IA. As for the requirements, please see the responses below and attached. Provide the control process flow or MID for the SVS system. Specifically for the closing of the actuated valve on the IA prior to the recombination of the gas with produced fluids ✓ a. Please see the attached P&ID'20-03-10_Revised MID 3R Well 107.pdf.' This is the as -built drawing that has been red -lined; CPA] hasn't received the CAD drawing. I've also included the wellbore diagram including the SSSV, '3R-107.pdf.' Demonstrate the equivalence of the proposed deep-set operable valve to a SSSV a. A Halliburton NE Tubing -Retrievable Safety Valve was installed in 311-107. I've attached the technical information available publicly on Halliburton's website, 'NE-TRSV-H012542.pdf' to this email. 3. The deep set operable valve would require a performance test every 6 months like a typical SSSV. a. CPAI is ready and able to do the performance testing every 6 months. i 4. The SSSV would be required during ESP operation as well as gas lift operation a. The SSSV is currently in service on the well and will remain in service. If equivalence between the deep set operable valve and a SSSV cannot be demonstrated prior to running the completion or in a subsequent performance test(every 6 months), then an SSSV meeting regulations would be required for the well to remain on production Best Regards, Doug Valentine From: Regg, James B (CED) <iim regg@alaska.gov> Sent: Friday, April 24, 2020 1:05 PM To: Valentine, Doug K <Doug. CValentine@conocophillips.com> Cc: NSK Fieldwide Operations Supt <n2072@conocophillips.com>; Loepp, Victoria T (CED) <victor]a.loepp@alaska.gov>; AOGCC <'AOGCC.Inspectors@alaska.gov'> Subject: [EXTERNAL]RE: 3R-107 (PTD #219-180) Performance Test Procedure Thank you for providing the test procedure. Here are the approval conditions attached to 3R-107 Permit to Drill that address actions in response to a failed no -flow test: it the well dries not pass a no -flow test, and CpAI proposes to use the deep-set operable valve as a SSSV, the following apply;. 1, Provide the control process flow or MID for the SVS system, Specifitally for the of theactuated valve on the tA prior to the recombination of the gas with prOdUced requiredfluids 2Demonstrate the equivalence of the proposed deep-set operable valve to a SSSV, 3, The deep set operable valve would require a performance t�est every 6 months like a typical SSSV, 4. The SSSV or deep set operable valve would be during ESP operation gas lift operation, S. If equivalence between the deep set operable valve and a SSSv cannot be demonstrated prior to running th compleflonorma subsequent performance test(everV6 months), then a SSSV meeting regulations would be required for the well to remain on A couple questions regarding the proposed SSSV test procedure (LPS/SSV performance test was completed 3/24/2020; not witnessed): - Do you plan to test the LPS/SSV again? - Is there a programmed time delay in initiating close of the SSSV (HAL NE TRSV)?; step 2.d - what is the target "measurable amount of differential pressure" when bleeding off IA pressure?; step 2.e - CPAI's acceptance criteria for the IA pressure monitoring after attaining the differential pressure? Regarding the well schematic, is the gas lift mandrel at 2633 ft MD (2499 ft TVD) for recombining gas into the produced fluids stream? Is there an actuated SSV on the IA or is the SSSV (below the pump) functionally equivalent? Please provide the control process flow or MID for the SVS system as required in condition approval #1. Jim Regg Supervisor, Inspections AOGCC 333 W.7t' Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or jim.regg@alaska.gov. From: Valentine, Doug K <Doug.l<.Valentine@conocophillips.com> Sent: Thursday, April 23, 2020 2:52 PM To: Regg, James B (CED) <'il m.re@alasl<a..Rov> Cc: NSK Fieldwide Operations Supt <n20725)conocophillips.com> Subject: 3R-107 (PTD #219-180) Performance Test Procedure Jim, I was told by Larry Baker that you requested to see our performance testing procedure for 3R-107. The procedure is attached to this email. The overview of the test is to close the SSSV, bleed the IA, shut the IA, then monitor the pressure buildup. The SVS techs attach their normal gauge to the wellhead, as well as utilizing the downhole suction gauge (tubing), and a downhole IA gauge that has been installed in the well. I have annotated them on the 311-107 schematic below. Victoria has been involved in discussions this summer with our completions group about the SSSV design. Please contact me if you have any questions. 11% tIAW44 t t 11'r* D I text. MJ21DIALLALU t . - 4.,1%v**jP"* 1't1t.d,t1 Final Sh -8l'MI)Ir'I WIN -1) : tl''4tO/22A N'9I DSI Discharge both IA and tu preSSUre gau pig--*� I Sp - Wurtux,rVMrqVajo4v Via .'#€ V %itt t ; n v�* IN D Sliding Sleeve is open to I 1 a1xvt , r �,j,! %ill +,f�WTt% ?. O* DO LWw1mg.crag Ai Doug Valentine DS Petroleum Engineer I ConocoPhillips *4 C at tea °ems vah � .,4 5,0 I' S%I'l I I, t IN Ll t.s et .t Idn 9w IWIM, Nil )W�'twn °i �,•�` �,r""' L 1 fit k`i"a$ tna '� ��ddY '�B f� t �.Cs.i^i %lr`%.p e.,... ........... . yy. .ye,a,.......t ........ . C TA PV ... ._ ........ ..... .......... ................. -' 4-1. o r i a' �'.CO ' Lo 4 5-2;n mr. sss�at -------- ------------- ----- -- -- -------------- I ' SET O :A0 PSIG I NOTES: 5Ckh SGL .r --o-¢ o � SS TUBING - - - - - - - - - - - - - - - - - - - - - �rmu65 LOCArMt XLlAF �a i - -J AL4M raz cssa maw ,V, DoGIT NISI EJi t. ElRM-.OUT FLANGES FOR REMOVAL OF LATERAL SPOM I ------------- PSL SET 0 70 PSIG ' UNIT. 03 PIECE BETNTEN WELLHEAD SHELTER 1?.T] EDGE OF PIT. I F'---- ---T'------- sn A 794595 "a«a 0869 2- NOT USED 3. NOT USED. rur. 001 a - I ; SV7 -gym 6 7/1 ISSIiD PER 224978577CP c1 JJC 111!1 EJS CW acca cures ' `"a°' '�10"`C. 1 4. SSV HADD SWITCH LOCATED OUTSIDE �cc'i I NFAD SHELTER FOR j PY I VIE L SHUT -RL i 5. SPECTACLE BUND 70 BE CLOSED DURING ESP OPERATION. 6. MCP HAS FUSIBLE PLUG. NOTE 6 I 7. SHEAR RELIEF VAL1E PROVIDED FCR DOTVNHOLE RVEF. SET AT 2018 PSID. E. SFECTACEE BUND TO K CLOSED DURING LIFT GAS OPERATION. I I I S HIGH POINT VENT uT I I - ' - - - -' - - - - - ..• - - - - - - I 1 10. CONNECTION FROVIDES LOW POINT DRAIN/PUW' TN POINT FCR I I NOTE 4 I A FD I ; FREEZE PRDTECTION. A'OTE 71 NOTE /`�C�` 6 11. W ADDITION TO VSD SIG.VIS, P--i86-107/187-M A%D, SSV PoLL k_• r j I I � SHUT DM CTI THE FOLLOWING: - PSW/PSU.-389352-107 NIGH OR LOW PRES51�. { ° '��7-� FY I I I I 3R I { z= I 107- 07 o I 4,A I I 1 1 I I 4'PC-3i3i-FKC VGCNi3 z to I � I � j 4 , 'n L IAN ,eT I �� F3 to 3 -in ls�1rXM1A 150-3805-4 j X4' API FKC7 1�a� 2� ji ►�C4.9 SP -ESP ESP FREEM04CY SEVOINi 502df XA-E9'LCC PUMP PERMISSIVE I I -- � ~ t NOTE XA-ESF� OOKN STAA15 BAD I � I Y,p T�I�NB SC -ESP E'S' FREQUENCY ( IL �L - NOTE 10 El -ESP VSO OUTPUT VOLTAGE ( I i T II -ESP VSD Af CUIPLIT CLFUWJ4T I X#,-ESFGND GRCUND FAULT I ( L X,% -ES eCK BACKSFIN fU.-ES*ll PUMP SYSTEM FAULT I `•' :2 - NOTE 9 NOTE 5 ,.!5ai u» 1. 3/�m NOTE I I I INS NOTE 13 tipA FKC7 53 HACF 1 I I I 4'PC-3831-FKC7 I, I I r,GL-3886-FKC7 I NANO -- -- ----- -- -- � ---- - -----� I _ I }4' LEGEND: ® INDICATES AVAILABLE 1R OCS 5Ckh SGL .r NOTE 7t - - - - - DETAIL 1 ESP PRODUCTION 15fl1. 107 uPD-D3RY-2816%sl � SS TUBING - - - - - - - - - - - - - - - - - - - - - �rmu65 LOCArMt XLlAF �a i - -J AL4M raz cssa maw 0A 33/16 RET/!gD PER 224978571CP DoGIT NISI EJi pa 724978S71CP ` 1KPx41.P081.EXO2ENICP8dD � CLJ 084 OHOFENSL y� ConocoPhillips 'L DMOFEWELL L CAMP AREA -3R UOOLRE 3RR11 DS3R WELL 107 WELL HOUSE DETAILS NOTE 9 NOTE 5 ,.!5ai u» 1. 3/�m NOTE I I I INS NOTE 13 tipA FKC7 53 HACF 1 I I I 4'PC-3831-FKC7 I, I I r,GL-3886-FKC7 I NANO -- -- ----- -- -- � ---- - -----� I _ I }4' LEGEND: ® INDICATES AVAILABLE 1R OCS 5Ckh SGL To SSSV L� I-- NOTE 7 IP -3896-107 lP-3806-In-w 1 NOTE 7t - - - - - DETAIL 1 ESP PRODUCTION 15fl1. 107 uPD-D3RY-2816%sl � SS TUBING - - - - - - - - - - - - - - - - - - - - - �rmu65 LOCArMt XLlAF �a i - -J AL4M raz cssa maw 0A 33/16 RET/!gD PER 224978571CP DoGIT NISI EJi pa 724978S71CP ` 1KPx41.P081.EXO2ENICP8dD � CLJ 084 OHOFENSL y� ConocoPhillips 'L DMOFEWELL L CAMP AREA -3R UOOLRE 3RR11 DS3R WELL 107 WELL HOUSE DETAILS UNIT. 03 A 794595 "a«a 0869 �� A{PO-D3RW-2004 rur. 001 a - aye 0A 6 7/1 ISSIiD PER 224978577CP c1 JJC 111!1 EJS CW acca cures ' `"a°' '�10"`C. my ua &.L n ox NONE 04/19 JOFMSON BIC n N t N t-_ t7 O i 0 N m a a w O U_ a U CD n n C4 N N DO a 0 0 cc CL0 0 3 M n n KUP PROD WELLNAME 3R-107 YELLBORE 3R-107 ConocoPhillips Alaska, Inc. E: MULTIPLE LATERALS. 3R-107, 4/21/20207.47: 09 AM Completion Details Vertical schematic(&deal) ToTop Incl Top Il(RKB) (') Rem Des Com Noml-1 ID pn) 5,380.7 3,655.4 1 87.48 1 SEAL ASSY 19DA7 GBH -22 Non Locating Seal Assembly, 4 1/2" STL Box 3.860 HANGER 34.6 ..... ........... Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (TVD) Top Incl Top (RKB) (RKB) (') Das Com Run Data ID (In) . . . .............. __........ _....... 4,818.3 3,630.8 87.51 MANDREL HES ROC -150 Discharge DHG ser # ROC -005612 + 2/16/2020 3.919 Mandrel CELLAR BOX; 39.4-43.4 4,928.0 3,635.7 87.43 SLIP STOP Tubing Slip Stop OAL = 1.68' 3/6/2020 0.000 4,929.7 3,635.8 87.43 PACKOFF Tubing PackoH Assembly includes: Tubing Packofl, 3/6/2020 0.000 ASSEMBLY Standing valve, and Stinger Seal DAL = 4.2 4,933.9 3,636.0 87.43 RETRIEVABLE AccessESP Retrievable Pump Assembly includes: 3/6/2020 0.000 ESP PUMP Polished Bore Receptacle, X -Over, Pump Discharge CONDUCTOR; 40.13-169.0 Mnuler Fluid - Sa¢water/Brme; ASSEMBLY Head, Summit Upper Pump, Summit Lower Pump, and Upper Mating Unit DAL = 41.32' 34,6-2 633,2 4,963.8 3,637.3 87.44 GVSSD / CMD 5-1/2' GVSSD, 4 1/2" Vamtop Box x 5 1/2", 23#, Vam 2/17/2020 3.913 SURFACE; 38 P2,253.3 (OPENED 311/2020) FJL Box GAS LIFT; 2,633.3 4,975.2 3,637.8 87.44 RETRIEVABLE AccessESP Retrievable ESP motor assembly includes: 3/6/2020 0.000 ESP MOTOR Lower Mating Unit, Upper Summit 338 Series Seal, ASSEMBLY Lower Summit 338 Series Seal, Access 375 250 HP Motor, Downhole Gauge, Plug Arm Assembly, and Motor Annuls, Fluid - Diesel; 2,633.2- Guide. DAL = 50.75' 5.337.2 5,068.1 3,641.9 87.55 Siding sleeve SSSV NE TRSV-HAL, 6.62' x 3.813 X -nipple w/ RHC 2/16/2020 3.813 GAS LIFT; 1,046.1 GAUGEIPUMP SENSOR; CMU (OPENED plug Installed.TSH-Blue Box x Pin 4,807.3 MANDREL', 4,818.3 3/112020) GAUGEIPUMP SENSOR; 1 4,818.4 Mandrel Inserts St SLIP STOP, 4,928.0 PACKOFFASSEMBLY 4,929.7 a6 RETRIEVABLE ESPPUMP ASSEMBLY; 4,933.9 GVSSD/CMD (OPENED 3!1/2020); 4,963.6 onTop(TVD) N Top IRKS) IRKS) Make Model OD (in) S., Valve Type Latch Type Port Sim (in) TRO Run (psi) Run Date Com 1 2,633.3 2,501.8 Camco ser# 67/16 ESP SOV BK 0.000 0.0 42012020 #2000 sliding sl«ve; 4.983.8 057AKO TBG Motor Shroud; 4,967.8 2 shear Moloy for Sh keer,oud; 4,9722 Motor shroud; 4,973.7 Motor cernreuzer; 4,9]83 2 4,046.1 3,482.0 Camco ser # 071 AKO 67/16 ESP DMY BK 1.1300 0.0 2/172020 Motto Shroud; 4,979.7 2 Motor Centrahzer, 4,984.6 Motor Shroud; 4,985.9 Motor Centralizer, 4,990.4 Motor Shroud; 4,991.9 Mdor Centralizer, 4,996.3 Motor Shroud; 4.997.8 RETRIEVABLE ESP MOTOR ASSEMBLY; 4,975.2 Motor Cemrahver, 5,002.3 Mdor Shroud, 5,003.8 Motor Centrslmer 5.008.2 Motor Shroud; 5,009.7 Amular Cwn« Pon, 5,016.1 Profile Sub: 5,039.7 No-go nipple; 5,0532 Sliding alseva CMU toPENED 3)112020):5.068 1 Slidrp Sleeve: 5,068.2 Mandrel: 5,092.9 SSSV; 5.116.9 LOCATOR; 5,179.7 PACKER; 5,171.0 Seal Assembly; 5,180.1 SBE Extension); Bore Extension); 5,190.7 NIPPLE DB; 5.2264 Tubing -Pup, 5.228 4 Tubing - Pup; 5,238.3 TOng - Pup; 5,245.1 DIVERTER T1; 5,249.1 DIVERTER T1: 5.252.3 NIPPLE; 5,3293 SEAL ASSY; 5,380.7 INTERMEDIATE, 0.0-].069.] Mnuler Fluid - Flo -Pro Dr Ihw Mud, 5,192. Q13614.6 LOWER LATERAL SLOTTED_�� LINER, 5,336.813,611.0 N ETM Tubing -Retrievable Safety Valve OVERVIEW The Halliburton NETM tubing -retrievable safety valve (TRSV) is a single rod -piston non -elastomer flapper valve designed for general production with enhanced reliability and long life. The valve includes the non -elastomer hydraulic actuator design from the highly reliable SPTM line of safety valves. Along with the metal -to -metal (MTM) body joints and closure mechanism, the actuator places this valve in the premium category while keeping costs economical. The simple, compact design enhances the valve's overall reliability and provides for trouble-free operation. APPLICATIONS » General production completions » Hostile well environments incompatible with elastomers FEATURES » Non -elastomer dynamic piston seals » Simple compact design » 100% metal -to -metal well containment in closed position » Positive debris barrier at both ends of flow tube » No construction seals used in the lockout and communication system » Unique flow tube construction prevents debris from settling on top of flow tube BENEFITS » Most field -proven and reliable hydraulic actuator in the industry » Dynamic and static seals independently verified gas tight » Verified MTM flapper sealing (no resilient seal required) » Critical components isolated from well debris during production » Minimized potential leak paths » Optimal reliability HALLIBURTON I Completion Tools NET' Tubing -Retrievable Safety Valves Tubing Size Maximum OD Internal Packing Bore Lock Pro- file Pressure Rating Length in. in. mm in. mm psi bar in. mm 23/8 3.63* 92 1.875 48 X"' 5,000 344.74 47.9 1216 3.70 94 5,000 344.74 3.97 101 10,000 689.48 27/8 4.65 118 2.125 - 2.313 54-59 R", X 5,000 344.74 51.4 1305 4.91 125 10,000 689.48 4.51 114 10,000 689.48 3 1/2 5.03* 128 2.562 - 2.813 70-71 X, R, RQ, RPT-" 5,000 344.74 56.1 1425 5.20 132 5,000 344.74 5.38 137 10,000 689.48 5.62 143 10,000 689.48 41/2 5.965* 151 3.750 - 3.813 95-97 X, R, RQ, RPT 8,500 586.19 57.5 1460 6.62 168 5,000 344.74 6.73 171 5,000 344.74 6.97 177 7,500 516.75 *Slimline options For more information, contact your local Halliburton representative or visit us on the web at www.halliburton.com HALLIBURTON THE STATE "'ALASKA GovERNOR MIKE DUNLEAVY April 22, 2020 Mr. Doug Valentine Senior DS Petroleum Engineer, GKA — CPF3 ConocoPhillips Alaska, Inc. PO Box 100360 Anchorage, AK 99510-0360 RE: No -Flow Verification Kuparuk River Unit 3R-107 PTD 2191800 Dear Mr. Valentine: Alaska Oil and Gas Conservation Commission 333 west Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaska.gov On April 19, 2020 an Alaska Oil and Gas Conservation Commission (AOGCC) Petroleum Inspector witnessed a no -flow test of Kuparuk River Unit (KRU) 3R-107. The AOGCC Inspector confirmed that the proper test equipment — as outlined in AOGCC Industry Guidance Bulletin 10- 004 — was rigged up on KRU 3R-107 prior to the test including calibrated pressure gauges and flow meter with suitable range and accuracy. The no -flow test procedure called for monitoring well performance up to 4.5 hours consisting of 30 -minute fluid flow rate checks preceded by I - hour pressure build up periods. Criteria used for determining a successful test were as stated in 20 AAC 25.265(1)(1)(A): "The measured liquid production is not greater than 6.3 gallons per hour, and the measured gas production is not greater than 900 standard cubic feet per hour". Observed gas flow rates were as follows (there was no liquid produced to surface): Flow Interval Gas Flow Rate scf/hr Initial 30 min 60 min 90 min 1 2902 1322 - - 2 3107 1598 1309 1071 The results witnessed by AOGCC on April 19, 2020 indicate a failed no -flow test. Kuparuk River Unit 3R-107 must be equipped with a fail-safe automatic safety valve system capable of preventing uncontrolled flow — including a surface controlled subsurface safety valve or AOGCC-approved alternate — as required in 20 AAC 25.265. Sincerely, James B. Regg / Petroleum Inspection Supervisor No -Flow Test — KRU 3R-107 April 22, 2020 Page 2 of 2 ecc: P. Brooks AOGCC Inspectors TION AND As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or 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 of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. MEMORANDUM TO: FROM: State of Alaska Alaska Oil and Gas Conservation Commission Jim ReggDATE: 4/19/2020 P. I. Supervisor Guy Cook Petroleum Inspector SUBJECT: No Flow Test KRU 3R-107 CPAI PTD 2191800 4/19/2020: Arrived on site at 10:15 am and met with Phil Tuttle, KRU SVS Tech, and several other workers along with the pad operator. After confirming the planned procedure with Victoria Loepp (Sr. Petroleum Engineer, AOGCC), they started the job. The well was shut in for an hour and then opened to bleed for a total of 36 minutes. The gas flowrate did not decline below 900 scf/hr before 30 minutes had elapsed. The well was shut in again for 1 hour followed by a second bleed. The well produced a higher gas rate than the first flow period and at the 30 -minute mark it failed to fall below 900 scf/hr. After 1.5 hours of continuous bleeding the gas rate still did not fall below the 900 scf/hr test limit. No liquids were produced to surface during the test. - The followina table shows test details: Time Pressures' psi Flow Rate Gas - scf/hr Liquid - al/hr Remarks 11:12 0/4/164 Shut well in for 1 -hr buildup - 11:27 3/46/165 11:42 5/67/164 11:57 7/76/164 12:12 9/90/163 2902 0 Oen well to bleed " 12:48 7/19/165 1322 - Well shut in for 1 -hr buildup 13:03 9/74/166 13:18 11/92/164 13:33 13/102/165 13:48 ' 13/117/164 3107 - 0 Oen well to bleed 14:04 16/17/164 1839 0 14:20 1598 - 0 14:24 1552 0 14:35 1678 0 14;48 7/8/164 1309 0 15:20 5/6/163 1071 0 Shut in well. ' Pressures are T/IA/OA 2 Gas flow not to exceed 900 scf/hr; Liquid flow not to exceed 6.3 gal/hr This well has failed the criteria for being able to be produced without an SSSV. - Attachments: None 2020-0419 No -Flow KRU 3R-107 gc.doc Page 1 of 1 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: ____________________ Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval:9. Ref Elevations: KB:49.2 17. Field / Pool(s): GL: 9.8 BF: Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 N/A (ft MSL) 22. Logs Obtained: 23. BOTTOM 20 H-40 169 10 3/4 L-80 2169 7 5/8 L-80 3680 4 1/2 L-80 3789 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press:Calculated Gas-MCF:Oil Gravity - API (corr): Press. 24-Hour Rate STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Gas WAG ConocoPhillips Alaska, Inc 2/19/2020 219-180 P.O. Box 100360 Anchorage, AK 99510-0360 1/9/2020 50-029-23660-00-00 1730' FNL, 2926' FEL, Sec 9, T13N, R9E, UM 1/24/2020 KRU 3R-107 623' FNL, 1342' FEL, Sec 9, T13N, R9E, UM Kuparuk River Field/West Sak Oil Pool 2013' FNL, 3179' FEL, Sec 11, T13N, R9E, UM 13614/3789 ADL 355023 520660 6031633 13638/3789 931933000 522238 6032744 530967 6031386 5117/3644 1765/1732 N/A List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary CASING, LINER AND CEMENTING RECORD GR/Res/AZM Res CASING WT. PER FT.GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT PULLEDTOP BOTTOM TOP 154.3 40 169 40 42 Existing cement to surface 45.5 40 2253 40 13 1/2 875sx 11.0ppg Class G 295 15 8 Cl G SLOTTED LINER 29.7 40 7070 40 9 7/8 1057sx 15.8ppg Class G 12.6 5337 13614 3654 6 3/4 TUBING RECORD If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 4 1/2 5207 n/a SLOTTED LINER@ 7013-13614 MD and 3685-3789 TVD….1/26/2020 ACID, FRACTURE, CEMENT SQUEEZE, ETC. Per 20 AAC 25.283 (i)(2) attach electronic information PRODUCTION TEST 3/21/2020 ESP Date of Test: Oil-Bbl: Water-Bbl: Choke Size: Gas-Oil Ratio: 402 1 169 3/28/2020 10hrs 1140 140 0 96 beans (Full Open) Sr Pet Eng Sr Pet Geo Sr Res Eng 152 Flow Tubing Oil-Bbl:Water-Bbl: 228 228 2648 WINJ SPLUGOther Abandoned Suspended Stratigraphic Test No No (attached) No Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment By Samantha Carlisle at 10:06 am, Apr 08, 2020 169 GDSR-4/8/2020 Completion Date 2/19/2020 HEW DLB 04/13/2020 16.9 HEW RBDMS HEW 4/13/2020 295sx 15.8 cls G VTL 5/5/20 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD Surface Surface Top of Productive Interval 1706 1677 2019 1964 3066 2871 3445 3154 UG-A 3624 3269 N 3929 3431 4504 3608 TD 13610 3773 West Sak D 31. List of Attachments:Daily Operations Summary, Definitive Survey, Cement Report, Schematic 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Mark Vanderhorst Contact Name:Matt Nagel Kuparuk Drilling Manager Contact Email:Matt.B.Nagel@cop.com Authorized Contact Phone:263-4747 General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: 28. CORE DATA Yes No If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): FORMATION TESTS NAME Well tested? Yes No Permafrost - Top If yes, list intervals and formations tested, briefly summarizing test results. Attach separate pages to this form, if needed, and submit detailed test information, including reports, per 20 AAC 25.071. Permafrost - Base Formation @TPI -West Sak D T-3 K-15 UG-C UG-B WS Formation at total depth: Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. Authorized Name: Authorized Title: Signature w/Date: INSTRUCTIONS This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. TPI (Top of Producing Interval). The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment, whichever occurs first. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). No No Sidewall Cores: Yes NoNoSidewall Cores: Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment Ugnu - N Sands HEW Baker Hughes $ Date: March 24, 2020 To: Abby Bell AOGCC 333 West 7`" Ave, Suite 100 Anchorage, Alaska 99501 219150 3225 Letter of Transmittal Michael Soper Baker Hughes 795 East 94`h Avenue Anchorage, Alaska 99515 Please find enclosed the directional survey data for the following well(s): 3R-107 3R-1071-1 RECEIVED MAR 2 4 2020 AOGCC (2) Total prints Enclosed for each well(s): 1 hardcopy print of directional survey reports (NAD27) 1 compact disk containing electronic survey files Michael Soper Baker Hughes Applications Engineer Michael.Sooer@bakerhuahes.com vvo cn w 0 CD o o n �1 � CD N i0 p y N O foolL 7r-0 O O \• O Q - C 0 O =r ♦//�� V) '� c CD (n CD Z << --j D M— CD J M o s� rook 0 C N 01 CA N) LO N Ln m N J N _ C N K) O C T A o (D W (D N O K N A N a o o = 3 T A (A 10 3 G G D p 3 C v * 3 C) 3 fl p:E :E N v 0 T N w w w N p N in (D CO W J V V V O o p O0 7 O �. d 1 Z Z Z Zw 3 O O .G .ni. .Z7 = rr N Q Z V N N (D 0 0 _ z x N O N L7 O > O m n ao 3 CD o A cc co �j Co CD d C N O O J O O< O CD w p o G 7 n 7 6 C 0 A O� W V O N O C 4 N O A O U N V U W w N w d -n T w w w w N p N in (D CO W J V V V K o } m G) G) G) �. 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W W m m (0 O j m (T N A W W A N N m N O f0 J J O J m J J m fp O Ut W W m O t0 m A N j O W A A N (n m Ul (Jt O M 0 J m O m m N m J m` �a W 9) J m m � - m � O � � � � N m m O m m N m m V tD j O Ut A m J J j A Ut (Jt m W m N m C V W A O N m N W m N m (T A W N J m N m J A t0 m m t0 (h N -4 D 3 D D o c c p y v O O 0 0 W N O N O O O O OD W A O A m J J A 0 O v m �I J A O N O w W O A m W OD t0 m V (O -p G t0 m Om CL (D + W + W ? A O O O O O O t0 (D (D t0 t0 t0 t0 t0 A W tD t0 tD m m m m m pD 00 OD m A pG OD V .�.. O N O W V W A (Old N m V w N j N W A A T m tN0 O N A N V (m0 t" Cl //N�� V @ V W W V N A m V A W N O m U� W W tp O A N P m m N m m V 7 L1 A A W N N N V O W N A N V A W N W V m W m N N A O m O m O NN Ov M O � 3 $3$ d $$3 g3g d d 55� d � $3$ d � 535 v d 3 � 3 3 � $$ d � 3 3 3 3 3 3 3 3 3$ � cn d o 2 cn cn m rn + + + + + + + + + + + + + + + + + + + + + + + + + + + K 0 0 Ci C1 Tl T �7 T T T T �l T 7 f1 T T T x T T T T T T T T T T T M 1 M m N A . N N . . N N . N . . N N . . N N . . N N A . A N N N . N A A N N . N . . N N A A N N N A A 1 N N N O p p + + + + + + + + + + + + + + + + + + + + + + + + + + + p j 7 0 o D D D D D D D D D D D D D D D D D D D D D D D D D D D Z CO m In W In In m W V) W V) V1 m Ul m m m m Vl N 2 T N m fn [n V) .lz A .-. - A A I� A A �-. A - 1. A A 1. �-. A A �-. A A .... A A A A ,... A A t, A ..-. A A b .3 A A A .... .... .... A A A D w j o A O N ca 0 ID S c m m P7-10 2/3—/t50 Loepp, Victoria T (CED) From: Loepp, Victoria T (CED) Sent: Tuesday, March 17, 2020 11:41 AM To: Valentine, Doug K Cc: Regg, James B (CED) Subject: KRU 3R-107 NFT Extension Doug, Flowing 90 days before performing a no -flow test is unprecedented and will be allowed if CPAI makes the existing deep set operable valve (supposedly a SSSV equivalent) functional. If KRU 311-107 passes a no -flow test after the requested 90 day flow, the DSOV can be isolated. Thanx, Victoria Victoria Loepp Senior Petroleum Engineer State of Alaska Oil & Gas Conservation Commission 333 W. 7th Ave Anchorage, AK 99501 Work: (907)793-1247 Victoria. Loepp@alaska.gov CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Victoria Loepp at (907)793-1247 or Vic loloep�_r c Disk adv From: Valentine, Doug K <Doug.K.Valentine@conocophillips.com> Sent: Tuesday, March 17, 2020 10:01 AM To: Loepp, Victoria T (CED) <victoria.loepp@alaska.gov> Cc: Regg, James B (CED) <jim.regg@alaska.gov> Subject: RE: [EXTERNAL]KRU 3R-107 NFT Extension Victoria, 1. What day of the flow period is 311-107 on? a. The well has not flowed yet. We anticipate the well will be brought online this week to start its flow period. 2. What is the tentative schedule for NFTs for future planned DS -3R West Sak wells? a. There are 2 more producers planned, after 311-107. The plan would be to test the wells within the AOGCC required flow period. The most recent 3R production data shows a more representative test for the life of the well would be closer to 90 days. 3. Will the future DS 1C West Salk wells require NFTs? ,_� . ,! i ;rc• eta ' . 4. In KRU 311-107, is the existing deepset operable valve functional? This was planned as a SSSV equivalent. It is functional. The plan is to only qualify and test the valve if needed. All our data indicates that these wells will not flow to surface over the lifetime of the well. The valve was included in the completion to minimize the risk of having an inoperable well, with no ability to draw it down to steady state conditions. 5. Please see the attached email chain between Scott Pessetto and myself concerning WSak NFT in August 2017. a. Thanks for including. The correspondence remains true, that we don't believe these wells will flow to surface. Rather, the most recent production data since Aug 2017 clarifies how quickly we are able to drawdown the wells, with 30 days being an aggressive target. Within 90 days, the wells will pass no flow tests with no ambiguity. Thanks, Doug Valentine Senior DS Petroleum Engineer I ConocoPhillips GKA — CPF3 13F,3A,3B,3J,3C,3K, 311 Westsak 0: 907-263-4146 1 C: 208-932-5280 From: Loepp, Victoria T (CED) <victoria.loepp@alaska.gov> Sent: Tuesday, March 17, 2020 8:11 AM To: Valentine, Doug K <Doug.K.Valentine@conocophillips.com> Cc: Regg, James B (CED) <jim.regg@alaska.gov> Subject: [EXTERNAL]KRU 3R-107 NFT Extension Doug, Please provide the following information: 1. What day of the flow period is 311-107 on? 2. What is the tentative schedule for NFTs for future planned DS -311 West Salk wells? 3. Will the future DS 1C West Salk wells require NFTs? 4. In KRU 3R-107, is the existing deepset operable valve functional? This was planned as a SSSV equivalent. 5. Please see the attached email chain between Scott Pessetto and myself concerning WSak NFT in August 2017. Thanx, Victoria Victoria Loepp Senior Petroleum Engineer State of Alaska Oil & Gas Conservation Commission 333 W. 7th Ave Anchorage, AK 99501 Work: (907)793-1247 Victoria. Loepp(a�alaska.gov CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Victoria Loepp at (907)793-1247 or Victoria_Loepp � ala,,ka.c -) From: Valentine, Doug K <Doug.K.Valentine@conocophillips.com> Sent: Tuesday, March 17, 2020 6:48 AM To: Loepp, Victoria T (CED) <victoria.loepp@alaska.gov>; Regg, James B (CED) <iim.regg@alaska.gov> Cc: Pessetto, Scott T <Scott.T.Pessetto@conocophillips.com>; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Subject: RE: KRU 313-107 NFT Extension Victoria/Jim, I wanted to follow-up with you on my recent request for 90 day flow period for 311-107 NFT. Do you know when we can expect an answer? Thanks, Doug Valentine 907-263-4146 From: Valentine, Doug K Sent: Monday, March 2, 2020 9:33 AM To: Loepp, Victoria T (CED) <victoria.loepp@alaska.gov>; Regg, James B (CED) <iim.re��@alaska.�ov> Cc: Pessetto, Scott T<Scott.T.Pessetto@conocophillips.com>; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Subject: KRU 311-107 NFT Extension Victoria/Jim, ConocoPhillips Alaska is requesting a 90 day flow window to perform the no flow test at KRU 313-107 (PTD #219-180) in light of recent data from two analogous wells, 311-101 and 311-111. According to productivity indexes for both the 311- 101 and 3R-111, both wells didn't reach the steady state inflow within 30 days. By 90 days 311-101 had reached its PI that it is still operating today. A 90 day window allows us to test the well in its most common state. Granting this extension will result in a more accurate test and reduce the risks, production impacts, and AOGCC inspector schedule burdens associated with multiple NFTs in attempts capture changing reservoir conditions. Please see the chart attached to this email. Best Regards, Doug Valentine Senior DS Petroleum Engineer I ConocoPhillips GKA—CPF3 ( 3F,3A,3B,3J,3C,3K, 311 Westsak 0: 907-263-4146 1 C: 208-932-5280 Loepp, Victoria T (CED) From: Valentine, Doug K <Doug.K.Valentine@conocophiIIips.com> Sent: Tuesday, March 17, 2020 10:01 AM To: Loepp, Victoria T (CED) Cc: Regg, James B (CED) Subject: RE: [EXTERNAL]KRU 3R-107 NFT Extension Follow Up Flag: Follow up Flag Status: Flagged Victoria, 1. What day of the flow period is 311-107 on? a. The well has not flowed yet. We anticipate the well will be brought online this week to start its flow period. 2. What is the tentative schedule for NFTs for future planned DS -311 West Sak wells? a. There are 2 more producers planned, after 3R-107. The plan would be to test the wells within the AOGCC required flow period. The most recent 3R production data shows a more representative test for the life of the well Would be closer to 90 days. 3. Will the future DS 1C West Sak wells require NFTs? a. No, 1C does not require a NFT or SSSV 4. In KRU 3R-107, is the existing deepset operable valve functional? This was planned as a SSSV equivalent. a. It is functional. The plan is to only qualify and test the valve if needed. All our data indicates that these wells will not flow to surface over the lifetime of the well. The valve was included in the completion to minimize the risk of having an inoperable well, with no ability to draw it down to steady state conditions. Please see the attached email chain between Scott Pessetto and myself concerning WSak NFT in August 2017. a. Thanks for including. The correspondence remains true, that we don't believe these wells will flow to surface. Rather, the most recent production data since Aug 2017 clarifies how quickly we are able to drawdown the wells, with 30 days being an aggressive target. Within 90 days, the wells will pass no flow tests with no ambiguity. Thanks, Doug Valentine Senior DS Petroleum Engineer I ConocoPhillips GKA — CPF3 13F,3A,3B,3J,3C,3K, 3R Westsak 0: 907-263-4146 1 C: 208-932-5280 From: Loepp, Victoria T (CED) <victoria.loepp@alaska.gov> Sent: Tuesday, March 17, 2020 8:11 AM To: Valentine, Doug K <Doug.K.Valentine@conocophillips.com> Cc: Regg, James B (CED) <jim.regg@alaska.gov> Subject: [EXTERNAL]KRU 311-107 NFT Extension Doug, Please provide the following information: 1. What day of the flow period is 3R-107 on? 2. What is the tentative schedule for NFTs for future planned DS -3R West Sak wells? 3. Will the future DS 1C West Sak wells require NFTs? 4. In KRU 311-107, is the existing deepset operable valve functional? This was planned as a SSSV equivalent. 5. Please see the attached email chain between Scott Pessetto and myself concerning WSak NFT in August 2017. Thanx, Victoria Victoria Loepp Senior Petroleum Engineer State of Alaska Oil & Gas Conservation Commission 333 W. 7th Ave Anchorage, AK 99501 Work: (907)793-1247 Victoria. Loepp(a)alaska.gov CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Victoria Loepp at (907)793-1247 or Victoria Laer�a alaska.gov From: Valentine, Doug K <Doug.K.Valentine@conocophillips.com> Sent: Tuesday, March 17, 2020 6:48 AM To: Loepp, Victoria T (CED) <victoria.loepp@alaska.gov>; Regg, James B (CED) <iim.regg@alaska.gov> Cc: Pessetto, Scott T <Scost.T.Pessetto@conocophillips.com>; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Subject: RE: KRU 311-107 NFT Extension Victoria/Jim, I wanted to follow-up with you on my recent request for 90 day flow period for 311-107 NFT. Do you know when we can expect an answer? Thanks, Doug Valentine 907-263-4146 From: Valentine, Doug K Sent: Monday, March 2, 2020 9:33 AM To: Loepp, Victoria T (CED) <victoria.loepp@alaska.gov>; Regg, James B (CED) <iim.regg@alaska.gov> Cc: Pessetto, Scott T <Scott.T.Pessetto conocophillips.com>; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Subject: KRU 311-107 NFT Extension Victoria/Jim, ConocoPhillips Alaska is requesting a 90 day flow window to perform the no flow test at KRU 311-107 (PTD #219-180) in light of recent data from two analogous wells, 311-101 and 311-111. According to productivity indexes for both the 311- 101 and 311-111, both wells didn't reach the steady state inflow within 30 days. By 90 days 311-101 had reached its PI that it is still operating today. A 90 day window allows us to test the well in its most common state. Granting this extension will result in a more accurate test and reduce the risks, production impacts, and AOGCC inspector schedule burdens associated with multiple NFTs in attempts capture changing reservoir conditions. Please see the chart attached to this email. Best Regards, Doug Valentine Senior DS Petroleum Engineer I ConocoPhillips GKA— CPF3 13F,3A,3B,31,3C,3K, 311 Westsak 0: 907-263-4146 1 C: 208-932-5280 Loepp, Victoria T (CED) From: Valentine, Doug K <Doug.K.Valentine@conocophillips.com> Sent: Tuesday, March 17, 2020 6:48 AM To: Loepp, Victoria T (CED); Regg, James B (CED) Cc: Pessetto, Scott T; Hobbs, Greg S Subject: RE: KRU 3R-107 NFT Extension Attachments: 3R_PROD_Pl.png Follow Up Flag: Follow up Flag Status: Flagged Victoria/Jim, I wanted to follow-up with you on my recent request for 90 day flow period for 311-107 NFT. Do you know when we can expect an answer? Thanks, Doug Valentine 907-263-4146 From: Valentine, Doug K Sent: Monday, March 2, 2020 9:33 AM To: Loepp, Victoria T (CED) <victoria.loepp@alaska.gov>; Regg, James B (CED) <jim.regg@alaska.gov> Cc: Pessetto, Scott T <Scott.T.Pessetto@conocophillips.com>; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Subject: KRU 3R-107 NFT Extension Victoria/Jim, ConocoPhillips Alaska is requesting a 90 day flow window to perform the no flow test at KRU 311-107 (PTD #219-180) in light of recent data from two analogous wells, 3R-101 and 3R-111. According to productivity indexes for both the 3R- 101 and 3R-111, both wells didn't reach the steady state inflow within 30 days. By 90 days 311-101 had reached its PI that it is still operating today. A 90 day window allows us to test the well in its most common state. Granting this extension will result in a more accurate test and reduce the risks, production impacts, and AOGCC inspector schedule burdens associated with multiple NFTs in attempts capture changing reservoir conditions. Please see the chart attached to this email. Best Regards, Doug Valentine Senior DS Petroleum Engineer I ConocoPhillips GKA—CPF3 I 3F,3A,3B,3J,3C,3K, 311 Westsak 0: 907-263-4146 1 C: 208-932-5280 THE STATE ''ALASKA GOVERNOR MIKE DUNLEAVY Chip Alvord Alaska Drilling Manager ConocoPhillips Alaska, Inc. PO Box 100360 Anchorage, AK 99510-0360 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Kuparuk River Field, West Sak Oil Pool, KRU 3R-107 ConocoPhillips Alaska, Inc. Permit to Drill Number: 219-180 Surface Location: 1730' FNL, 2926' FEL, SEC. 9, T13N, R9E, UM Bottomhole Location: 2015' FNL, 3178' FEL, SEC. 11, T13N, R9E, UM Dear Mr. Alvord: Enclosed is the approved application for the permit to drill the above referenced development well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, "'6V-, e . Price Chair DATED this � I day of December, 2019. RECEIVED NOV 21 2019 A0rp r.r - STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 1 a. Type of Work: 1 b. roposed Well Class: Exploratory - Gas ❑ Service - WAG ❑ Service - Disp ❑ Drill 0 Lateral ❑ Stratigraphic Test ❑ Development - Oil 0 Service - Winj ❑ Single Zone ❑� Redrill ❑ Reentry ❑ Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ 1 c. Specify if well is proposed for: Coalbed Gas ❑ Gas Hydrates ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: ConocoPhillips Alaska, Inc. 5. Bond: Blanket ❑� Single Well ❑ Bond No. 59-52-180 11. Well Name and Number: KRU 3R-107 3. Address: P.O. Box 100360 Anchorage, AK 99510-0360 6. Proposed Depth: MD: 13684' TVD: 3801' 12. Field/Pool(s): Kuparak River Field West Sak Oil Pool 4a. Location of Well (Governmental Section): Surface: 1730' FNL & 2926' FEL, Sec 9, T13N, R9E, UM Top of Productive Horizon: 587' FNL & 1273' FEL, Sec 9, T13N, R9E, UM Total Depth: 2015' FNL & 3178' FEL, Sec 11, T13N, R9E, UMiri 7. Property Designation: ADL355023 8. DNR Approval Number: 931933000 13. Approximate Spud Date: 12/25/2019 9. Acres in Property: 3255 14. Distance to Nearest Property: 538' to ADL388235 4b. Location of Well (State Base Plane Coordinates - NAD 27): Surface: x- 520660.18 y- 6,031,633.15 Zone- 4 10. KB Elevation above MSL (ft): 48.9' GL / BF Elevation above MSL (ft): 9.8' 15. Distance to Nearest Well Open to Same Pool: 1124' to 3R-106 16. Deviated wells: Kickoff depth: 600 feet Maximum Hole Angle: 97 degrees 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Downhole: 1,720 Surface: 1,340 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling I Length MD TVD MD TVD (including stage data) 42" 20" 94# H-40 Welded 129' Surf Surf 168' 168' Existing, cement to surface 13-1/2" 10-3/4" 45.5# L-80 HYD563 2253' Surf Surf 2253' 2171' 861 sx 11.0 ppg, 283 sx 15.8 ppg 9-7/8" 7-5/8" 29.7# L-80 HYD563 5836 Surf Surf 5836' 3700' 763 sx Class G 15.8 ppg 6-3/4" 4-1/2" 12.6# L-80 TXP 7998' 5686' 3690' 13684' 3801' N/A 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Perforation Depth MD (ft): Perforation Depth TVD (ft): Hydraulic Fracture planned? Yes El No ❑.r 20. Attachments: Property Plat ❑ BOP Sketch Diverter Sketch e Drilling Program Time v. Depth Plot Seabed Report B Drilling Fluid Program Shallow Hazard Analysis 20 AAC 25.050 requirements 8 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: Madeline Woodard Authorized Name: Chip Alvord Contact Email: madeline.e.vvoodard co .Com Authorized Title: Alaska Drilling Manager Contact Phone: 907-265-6086 Authorized Signature: �`\. Date: 012 0 (2-, ! Commission Use Only Permit to Drill Number: - 8 API Number: 50- QZ - 6 Q- Q 0_ flo Permit Approval Date: 2 I I See cover letter for other requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Other:B�P tri Samples req'd: Yes ❑ NoR" Mud log req'd: Yes❑ No&r H2S measures: Yes S" No❑ Directional svy req'd: Yes q' No ❑ 1, Spacmg exgeption req'd: Yes ❑ NoX Inclination -only svy req'd: Yes[:] No N/ Post initial injection MIT req'd: Yes ❑ No f%�rova/ is sc.e artnCt-7 41P/19f-ova/ 1-e/a,fih�i✓ /a fht Well C'o. a C�ov�cji¢/'ons of APPROVED BY 1,111) 11 Approved by: COMMISSIONER THE COMMISSION Date:Submit Form and ,,-,Y 7`'J --t' KRU 3R-107(PTD 219-180) Conditions of Approval Based on the location of 311-107, that is, a surface location that is 660 feet or less of a coast line (20 AAC 25.265(d)(2)(f)) a SSSV is required if this well is capable of unassisted flow of hydrocarbons to surface (20 AAC 25.265(d)(1)). If a no -flow test to demonstrate the well is not capable of unassisted flow of hydrocarbons to surface is conducted and the well passes the test, a SSSV will not be required (20 AAC 25.265(k)). The following guidelines apply. 1. Reference AOGCC Guidance Bulletin 10-004 2. Up to a 30 day production period is acceptable prior to the no -flow test for this well 3. The no -flow test must be conducted within 30 days 4. A procedure must be submitted for AOGCC approval at least two weeks in advance. 5. CPAI must demonstrate that offset injectors have not been shut in prior to the no -flow test by providing a list of offset injectors with status and injection history for the past 6 months. Should conditions change, such as increased reservoir pressure due to water injection, an updated no - flow test may be required If the well does not pass a no -flow test, and CPAI proposes to use the deep-set operable valve as a SSSV, the following apply: 1. Provide the control process flow or MID for the SVS system. Specifically for the closing of the actuated valve on the IA prior to the recombination of the gas with produced fluids 2. Demonstrate the equivalence of the proposed deep-set operable valve to a SSSV. 3. The deep set operable valve would require a performance test every 6 months like a typical SSSV. 4. The SSSV or deep set operable valve would be required during ESP operation as well as gas lift operation. S. If equivalence between the deep set operable valve and a SSSV cannot be demonstrated prior to running the completion or in a subsequent performance test(every 6 months), then a SSSV meeting regulations would be required for the well to remain on production. Application for Permit to Drill, Well 3R-107 Saved: 20 -Nov -19 November 20, 2019 Alaska Oil and Gas Conservation Commission 333 West 711 Avenue, Suite 100 Anchorage, Alaska 99501 Re: Application for Permit to Drill Well 311-107, a West Sak D Sand Producer Dear Commissioner: ConocoPhillips Alaska, Inc. hereby applies for a permit to drill an onshore grassroots dual -lateral producer well from the 3R pad. The expected spud date for this well is December 25, 2019. It is planned to use rig Doyon 142. 0 3R-107 is planned to be a horizontal dual -lateral producer in the West Sak D sand upper and lower lobes. The surface section will be drilled with a 13-1/2" bit and cased with 10-3/4" casing to +2,253' MD / 2,171' TVD. The remaining intervals will utilize Doyon 142's 13-5/8" x 5,000 psi BOP stack with required ram installations and tested on a 14 -day cycle in accordance with COP and AOGCC policy. The intermediate section will be drilled with a 9-7/8" bit and cased with 7-5/8" casing to +5,836'MD / 3,700' TVD. The first production section will be drilled with a 6-3/4" bit in the West Sak D sandiower lobe to +/- 13,684' MD / 3,801' TVD and lined with a 4-1/2" slotted liner. The subsequent production lateral will be drilled with a 6-3/4" bit in the West Sak D sand °upper lobe and lined with 4-1/2" slotted liner. A separate PTD application will be submitted for each lateral: 3R-107 and 3R -107L1. The upper completion will be run with 4-1/2" tubing. Please find attached the information required by 20 ACC 25.005 (a) and (c) for your review. Pertine�t information attached to this application includes the following: 1. Form 10-401 Application for Permit to Drill per 20 ACC 25.005 (a). 2. Pressure information as required by 20 ACC 25.035 (d) (2). 3. Casing and cementing program. 4. A drilling fluids program summary. 5. A proposed drilling program. 6. Directional drilling/collision avoidance information as required by 20 ACC 25.050 (b). 7. A proposed completion diagram. Information pertinent to the application that is presently on file at the AOGCC: 1. Diagrams of the BOP equipment, diverter equipment and choke manifold lay out as required by 20 ACC 25.035 (a) and (b). 2. A description of the drilling fluids handling system. 3. Diagram of riser set up. If you have any questions or require further information, please contact Madeline Woodard at 265-6086 (madeline.e.woodard@cop.com) or Chip Alvord at 265-6120. Sincerely, 4� a,,k Chip Alvord Drilling Manager • s Application for Permit to Drill Document Kuparuk Well 3R-107 Well Name Requirements of 20 AAC 25.005 (f) The well for which this application is submitted will be designated as KRU 3R-107 Location Summary Requirements of 20 AAC 25.005(c)(2) An application for a Permit to Drill must be accompanied by each ofthe following items, exceptfor an item already on file with the commission and identified in the application: (3) a plat identifying the property and the proper i,'s owners and showing (1) the coordinates of the proposed location of the well at the sur face, at the top of each objective formation, mud at total depth, referenced to governmental section lines. (B) the coordinates of the proposed location of the well at the snrface, referenced to the state plane coordinate system for this state as maintained by the National Geodetic Survey in the National Oceanic and Atmospheric Administration; (C) the proposed depth of the well at the top of each objective formation and at total depth; Location at Surface 1730' FNL & 2926' FEL, Sec 09, TON, R9E, UM NGS Coordinates Northings: 6,031,633.15' Eastings: 520,660.18' 1Pad IRKB Elevation 48.9' AMSL Elevation 9.8' AMSL Location at Top of Productive Interval est Sak D Sand 587' FNL & 1273' FEL, Sec 09, T13N, R9E, UM NGS Coordinates Northings: 6,032,779.94' Eastings: 522,306.25' Measured Depth, RKB: 4,607' Total Vertical Depth, RKB: 3,612' Total Vertical Depth, SS: 3,563' Location at Total Depth 2015' FNL & 3178' FEL, Sec 11, T13N, R9E, UM NGS Coordinates Northings: 6,031,383.64' Eastings: 530,967.97' Measured Depth, RKB: 13,684' Total Vertical Depth, RKB: 3,80P Total Vertical Depth, SS: 3,752' and (D) other information required by 10 ,4 4 C 15.050(h), Requirements of 20 AAC 25.050(b) If cu well is to be into "lied, the application j"or a Permit to Drill (Form 10-401) must (1) include a plat, draMrn 1" a suitable scale, showing the path of the proposed wellbore, including all adjacent wellbore.s within 200 feet of any portion of the proposed well; Please see Attachment: Directional Plan And (2) for all wells within 200 feet of the proposed wellbore (4) list the names of the operators of those wells, to the extent that those names are known or discoverable in public records, and show that each named operator has been furnished a copy of'the application by certifted mail; or ('B) .state that the applicant is the only affected owner. The Applicant is the only affected owner. Blowout Prevention Equipment Information Requirements of 20 AAC 25.005(c)(3) 4n application for a Permit to Drill must be accompanied by each of the following items, except for an items alrecuiy os file with the commission and identified in the application. (31 a diagram and description of the blowout prevention equipment (BOPS) us required by 20 4 1 25.035, 2014C 25.036, or 20 AAC 25.037, as applicable, Please reference BOP schematics on file for Doyon 142 and attachment. Drilling Hazards Information Requirements of 20 AAC 25.005 (c)(4) An application for a Permit to Drill must be accounpartied by each of the following items, ercepl for an itern alreadv ori file with the commission and identified in the application.- (4) pplication:(4) it formation on drilling hazards, including, ("A) the maximum downhole pressure that may be encountered, criteria used to determine it, and maximum potential surface pressure based on a methane gradient; The maximum potential surface pressure (MPSP) while drilling 3R-107 is calculated using an estimated maximum reservoir pressure of 1,720 psi (based on 3R-102 downhole gauge data and reservoir modeling), a gas gradient of 0.10 psi/ft, and the estimated depth of the West Sak D sand at 3,801' TVD: D Sand Estimated. BHP = 1,720 psi ✓ r— f , �C D Sand estimated depth = 3,801' TVD ,J ✓ Gas Gradient = 0.10 psi/ft as per 20 AAC 25.005 (c)(4)(A) Hydrostatic of full gas column = 380 psi (3,801 TVD * 0.10 psi/ft) ,�j MPSP = BHP — gas column = 1,340 psi (1,720 psi — 380 psi) V/ (B) data on potential gas =ores, The well bore is not expected to penetrate any shallow gas zones. i120 o 0 And (C) data concerning potential causes of hole problems such as abnormalhr veo pressured strata, 1fis/circulation _-ones, and -ones that have a piopensitvjbr di ferential sticking; See attached 3R-107 Drilling Hazards Summary Requirements of 20 AAC 25.005 (c)(5) An application for a Permit to Drill must be at by each of the following items, except for an item already on file with the commission and identified in the application: (5) a description of the procedure for conducting formation integrity tests, as required tinder 20.4, W 25.030( ) A procedure is on file with the commission for performing LOT'S. Casing and Cementing Program Requirements of 20 AAC 25.005(c)(6) An application for a Permit to Drill must be accompanied by each of the following items, except for on item ah•eady on file ,7 ith the connnission and identified in the application: (6) a complete proposed casing and cementing program as required by 20 AAC 25.030, and a description of airy slotted liner. pre -perforated liner, or screen to he installed Casing and Cement Program Casin and Cementing Pro ram Csg/Tbg OD Hole Sine Weight Grade Conn. Length Top MD/TVD Btm MD/TVD Cement Program (in) (lb/ft) (ft) (ft) (ft) 20 42 94 H-40 Welded 129 Surf 168/168 Existing Cement to Surface with 10-3/4 13-1/2 45.5 L-80 HYD563 2,253 Surf 2,253 / 2,171 861 sx 11.0 ppg lead, 283 sx 15.8 ppg tail 7-5/8 9-7/8 29.7 L-80 HYD563 5,836 Surf 5,836 / 3,700 763 sx Class G at 15.8 ppg w/ TOC at 2,890' MD 4-1/2 6-3/4 12.6 L-80 TxP 7,998' 5,686 / 3,690 13,684 / 3,801 N/A 10-3/4" Surface casing run to 2,253' MD / 2,171' TVD Cement from 2,253' MD to 1,753'(500' of tail) with 15.8 ppg and from 1,753' to surface with 11.0 ppg lead. Assume 250% excess annular volume for lead and tail in the permafrost, 50% annular excess below the permafrost for tail, and 0% excess in 20" conductor. 10-3/4" Surface Casing Design: 11.0 ppg lead slurry from 1753' to surface and 500' of 15.8 ppg tail slurry Lead Cement yield= 1 2.61 ft3/sk I Tail Cement yield= 1.16 ft3/sk 11.0 ppg LiteCRETE Lead Slurry Conductor 168' x 0.24302 bbl/ft x 1.0 (0% excess) 40.8 bbls Btm of lead to conductor (1753'- 168) x 0.06478 bbl/ft x 3.5 (250% excess) 359.4 bbls Total Lead Cement 400.2 bbls 2247.0 ft3 861 sx 15.8 ppg Class G Tail Slurry Shoe to Base of Permafrost (2253'- 1763) x 0.06478 bbl/ft x 1.5 (50% excess) 48.6 bbls Base of Permafrost to top of tail (1763'- 1753) x 0.06478 bbl/ft x 3.5 (250% excess) 2.3 bbls Shoetrack 80'x 0.096175 bbl/ft x 1 (0% excess) 7.7 bbls Total Tail Cement 58.5 bbls 328.7 ft3 283 sx 7-5/8" Intermediate casing run to 5,836' MD / 3,700' TVD Single stage slurry is designed to be placed from TD to 2,890' MD, which is 500' MD above top of the Ugnu B (predicted top of hydrocarbon) with 35% excess annular volume. 7-5/8" Intermediate Casing Design: Single stage 15.8 ppg Class G slurry with 35% excess in OH Cement yield 1.16 ft3/sk 15.8 ppg Class G Slurry Shoe to TOC (5836'- 2890')'x 0.03825 bbl/ft x 1.35 (35% excess) 152.1 bbls Shoetrack 120'x 0.0.04592 bbl/ft x 1 (0% excess) 5.5 bbls Total Tail Cement 157.6 bbls 885.1 ft3 763 sx Diverter System Information _Requirements of 20 AAC 25.005(c)(7) III application Jur a f'rrmu to 1)rill nn,st he accompanied by each of theJollowing items, except for an item ab-ead3. on,file with the commission and identified in the application. (7) a diagram and description of the divener system as required b.v 20.4AC 25.035, unless this requirement is waived bti, the commission under 20 AAC 25.035(h)(2)r It is requested that a variance of the diverter requirement under 20 AAC 25.035 (h)(2) is granted. At 3R, there has not been an indication of shallow gas or gas hydrates through the surface hole interval. The previously drilled West Sak wells 3R-102, 3R-101, 3R-106, and 3R-111 are within 500' from the proposed 3R-107 base of permafrost location and did not encounter any shallow gas. DZ J3 Drilling Fluid Program Requirements of 20 AAC 25.005(c)(8) 4n applicunon for a Permit to Drill Heusi be accompanied by each or the following items, excepi for an item already on file with the commission and identified in the application: (8) a drilling fluid program, including a diagram and description of the drilling fluzd system, as required by 2014C ?5.033, Mud Program Summary Diagram of Doyon 142 Mud System is on file with AOGCC. Drilling fluid practices will be in accordance with appropriate regulations stated in 20 AAC 25.033. Abnormally Pressured Formation Information Requirements of 20 AAC 25.005 (c)(9) N/A - Application is not for an exploratory or stratigraphic test well. Seismic Analysis Requirements of 20 AAC 25.005 (c)(10) N/A - Application is not for an exploratory or stratigraphic test well. Seabed Condition Analysis Requirements of 20 AAC 25.005 (c)(11) N/A - Application is not for an offshore well. Evidence of Bonding Requirements of 20 AAC 25.005 (c)(12) Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission. Proposed Drilling Program _Requirements of 20 AAC 25.005 (c)(13) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: Surface 13-1/2" Hole 10-3/4" Casing Intermediate 9-7/8" Hole 7-5/8" Casing Production 6-3/4" Hole 4-1/2" Liner Mud System Spud WBM) LSND (WBM) F1oPro NT (WBM Density 8.8-9.5 9.0-9.5 9.0 — 9.5 ppg PV ALAP ALAP ALAP YP 30-80 20-30 15-20 Funnel Viscosity 250-300 Permafrost Base 100-150 to TD N/A N/A Initial Gel 30-50 9 - 11 7-10 10 -minute Gel 30-50 <20 8-16 API Filtrate NC <6 <6 HTHP Fluid Loss at 160° F N/A < 10 <10 H 10.8-11.2 9.5-10.0 9.5-10.0 Diagram of Doyon 142 Mud System is on file with AOGCC. Drilling fluid practices will be in accordance with appropriate regulations stated in 20 AAC 25.033. Abnormally Pressured Formation Information Requirements of 20 AAC 25.005 (c)(9) N/A - Application is not for an exploratory or stratigraphic test well. Seismic Analysis Requirements of 20 AAC 25.005 (c)(10) N/A - Application is not for an exploratory or stratigraphic test well. Seabed Condition Analysis Requirements of 20 AAC 25.005 (c)(11) N/A - Application is not for an offshore well. Evidence of Bonding Requirements of 20 AAC 25.005 (c)(12) Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission. Proposed Drilling Program _Requirements of 20 AAC 25.005 (c)(13) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: The proposed drilling program is included below. Please refer to Attachment 3 for proposed well schematic. 1. Move in / rig up Doyon Rig 142. 2. Spud and directionally drill 13-1/2" hole to surface TD as per directional plan. Run GWD/MWD/LWD tools [gamma ray & resistivity] required for directional monitoring. 3. Run and cement 10-3/4", 45.5#, L80, HYD563 casing to surface. Displace cement with mud and check floats upon bumping plug. Notify AOGCC if top job is required. 4. Remove diverter system and install wellhead. Install and test 13-5/8" x 5,000 psi BOP'S to 250 psi low and 3,500 psi high (annular preventer to 3,500 psi). Notify AOGCC 24 hrs before test. 5. PU 9-7/8" bit and 6-3/4" drilling assembly, with MWD/LWD [gamma ray & resistivity]. RIH, clean out cement to top of float equipment and test casing to 3,000 psi for 30 min. 6. Drill out shoe track and 20' of new hole. Perform shoe test to a minimum of 1 1.5ppg EMW LOT and maximum 13.0 ppg EMW FIT, recording results. 7. Displace to 9.2 ppg LSND water-based drilling fluid. 8. Directionally drill to intermediate TD. 9. Circulate hole clean. BROOH. 10. Run and cement 7-5/8", 29.7#, L80, HYD563 casing to surface. (Top of cement to be 250' TVD or 500' MD, whichever is greater, above the Ugnu B sand). 11. Install 7-5/8" packoff and test to 5,000 psi. 12. Flush 10.75" x 7.625" annulus with water and freeze protect. 13. PU 6-3/4" bit and 4-3/4" drilling assembly, with MWD/LWD [gamma ray & resistivity]. Clean out cement to shoe track and test casing to 3,500 psi for 30 min. 14. Drill out shoe track and 20' of new hole. Perform shoe test to a minimum of 11.5 ppg EMW LOT and maximum 13.0 ppg EMW FIT, recording results. 15. Directionally drill to production TD. 16. Circulate hole clean. BROOH. 17. P/U and run 4-1/2", 12.6# slotted liner. 18. Set liner hanger and top packer. Pressure test for 10 min, chart results. 19. POOH and lay down running tools. 20. PU whipstock (anchor, whipstock, mills, MWD). TIH with whipstock assembly. Once on depth, orient and set whipstock anchor. Shear whipstock bolt and mill window. 21. Perform formation integrity test to 11.5 ppg min, 13.0 ppg maximum. 22. POOH with whipstock assembly and LD. 23. PU motor assembly with MWD and roller cone bit. RIH to window. 24. See separate PTD for 3R -107L1 lateral. Discussion of Mud and Cuttings Disposal and Annular Disposal Requirements of 20 AAC 25.005 (c)(14) An application, for a Permit to Drill Maui be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (14) a general description of how the operator plans to dispose of drilling mad and catlings and a statement of whether the operator intends to request authorization under 20 AAC 25.080 for an annular disposal operation in the well.: Waste fluids generated during the drilling process will be disposed of by hauling the fluids to a KRU Class II disposal well (DS 1B CRI), Milne Point, Prudhoe DS -4. All cuttings generated will be hauled to the DS 1B CRI, Milne Point, Prudhoe Bay Grind and Inject Facility (for temporary storage and eventual processing for injection down an approved disposal well), or stored, tested for hazardous substances, and (if free of hazardous substances) used on pads and roads in the Kuparuk area in accordance with a permit from the State of Alaska. Attachments: Attachment 1 Directional Plan Attachment 2 Drilling Hazards Summary Attachment 3 Well Schematic Attachment 4 BOP Configuration 0 rl O V O c LM m CL I v m O CL Q to to .� E •- aL O o o N L V O M > 0 V YYaca Z O a N z 3: v N N N J 3 3 00 0 d W O O co rn .CL Y O (6 d CL Y� c s m Y N _ O C 3 n > a ^0 0 O O O L � V V A O M I� ( O O 3.i. 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(o M o O t0 O M M o Cl) N o o m O O O o o o0 M O o N M Q i O O m t0 t!l O D O O v o o O o O o O O OD M m M C `F 0 > (00 On � r r- Q coo � m O O O N N lV M M N' ❑ v too tN r n V ❑ �"' t N N b N N N N N r N t:N N N N Oi .a j (y H N LL a O .. d `O C d p C d .. .O LA C N V o Q Y N m m m N Y y m m 1n h O N c0 N V O V O O V m N n N O 10 O O M N 10 (O n h m OD m OR n n M O V n m m n n N MM M M V) N N n m V n N W) 10 00 O (O n to m N (0 N N V n n (O N Y 2 d V OR m V V V M r n N V N 1n O N m m m n r O (0 t17 m O (O M n M m 1A m V V `"' (0 m M M (O r V tO l0 OR Z cc M Cl) Cl) Cl) Cl) N o 0) tb t` N Cl) Cl) M O) (- m (V N O n V 7 Y V V V V Cl) Cl) co Cl) M co M N N N N N N N 3 U' C ca) Q o) o) o) 0) o) o) m o) o) o) m o) ZD m o) o) o) m m Y N O O co m O W co (9 n W m N w m M N m u') V m M _ n M M V _ N 1O m t0 M m N O V M N O V n L' 'C 0= J m m m m m m m m m CA CA CA m m m m m m m m m m m N a a n n r r r r r r r r r r r r r r r r r r r r r r o ) = a` m 0 0 z z z z Z Z z z z z z z z z z z z z z z Z Z Z H O O M N N CO) m n (O O V O) O m 11D N n m N m n N 07 N n M O tO O (0 LO M V O m Cl) (O 10 O O) 10 Cl •- cl m O O r l0 m M M t0 O Cl) (O n O CO. M (O m N N V O m N N 01 o 1O n N n tO n LO n LO n6 0 0 6 m C6 N of 10 of 10 of N of 10 o O o 0 0 r r r r r S^ y, O O O O O O O O m m O O m O M O M O M O M O M O M O M O Cl) O M O Cl) li O O O O >. d N N N N N N N N N N N N N O O O O O n o O m o o m N m O O O O O O O N OD Goo .dJ Q �^. 0 0 0 0 0 0 0 0 0 0 0 o n n n O n O n O n O n O n O r. - O 2 0 G V p c I d m d _ V Eo a� OD M m N r O N V O N N O n V m n O N O W O 0 O N N r r m V O N m 10 V O M M9 O N M (0 9 O n M M Oi 7 Cl) Cl) U Q. M N V V N 1n m O t0 10 N (O N O Cl) N O c0 O N n N M O) O) m O V 00 N m LLD V M O Cl) M r C t 0 0 m m m 0 0 m O O O r r N N N M M V V 1O (O ( n W a 0 o) o N 0 N 0 N N N N N N N N N N N N N N N N N N N N C N N 7 Y N 1n h tO 1O 1(D m to N LO 1O 1O 1O (0 (O t0 t0 10 N N 1O 10 t0 N Q a a 2 O W 1O N m N 0 O O O N N t0 OD O n n m V N O m t0 n Cl? n N 1O (O N m N 1O m M V n N n V (O N m O M V (D (D Mm n V O 1O n O M m [O N M m m M M (U C .Q 0) m r NN M Cl! n N O M V M 1O M w M N V 1O V W V m V N O t0 10 1O 1O M V c0 V cc V O O cD m O n y O L y 0 C � j N Cl) O N M O N co O N co O N M O N co O N M O N M O N M O N M O N Cl) O N co O N Cl) O N M O N Cl) O N M O N M O N co O N co O N Cl) O N co O N Cl) O N Cl) O W O — M co o co O c0 c0 O c0 c0 c0 (O m c0 o m c0 m c0 c0 O co t0 C 2 d O 'a' V d 7 c d C U m V co n m m M O M n (O O " N n N LO V co m m m N m Cl) M O n M o0 M 1O 10 (O m V N O N V (O W V m (O O d w tO m N N M N n m M v (O N N V O O N N N M N V O r d U N () d >, W M N M N N N m N N M N M O M O V V V m V tO LO O m r co co co V n t0 n N M O m c0 Cl) m m n O O N N d U 0 J F 2 cn o O N 0- O Q) o o o O O o v LO v (n v (n v 1n v 1n v 1n v 1n V 1n v 1? v 0 v 1n v 1n v (n v (n v 1n v (n v 1n v 1n v UD v o _ CK 0 0 o co M co M co M co M M M M M M M co M M Cl) M M T E c U V O � = m V N O O co O O 10 O O 1O O O o O m O (O CO m m m m N N O N W N O O r OD O N O c0 O9 0 N O (0 V n m co to O 1t) a0 M m M M m N n N V n V n V N m tO m O m n n n V cc N m O O (0 O n O M r m r O N N N M O M O CO O V V V OD V N cn � N N N N N N N N N N N co Cl) Cl) Cl) Cl) M Cl) co M co co co M O O m m V 1O O O m m O LO m O m O O (0 O co O m f� CO n N V V m n m O O m O n m m 10 m m O O M N M (o (O h 7 01 M o n o M N N n CO tO 01 n V N N N to LO N V cc MN n M m m cc n m V O _ N N V NN 10 O M (O M V V 1O V m V N N Q (V N N N N N N N N N M M Cl) Cl) M C'1 M O') c`') c7 co M Cl) N Y y m m 1n h O N c0 N V O V O O V m N n N O 10 O O M N 10 (O n h m OD m OR n n M O V n m m n n N L 3 M M M V M O V 10 V m V m V M 1O O N m 10 N co N co V m t0 O to m w m O n N n N n V n 1O n n n Y 2 _E cc M N 7 Y U' C Q Y N O O co m O W co (9 n W m N w m M N m u') V m M _ n M M V _ N 1O m t0 M m N O V M N O V n 'C 0= co co N N m N n N 0) N N Cl) V co to M no Cl) V M V m V m V m V N N N W) 1t) 1f) m N N (O N t0 LO co m to (� N a a n n b H o ) = a` ao M n O H n F •- c n ca wr v Wi U Y Y n_ M(n O M M M O O O O co O O O r O O O O O O O O O O S^ O r y N O O O O n O O O O O o O O O O M O O O li >. d O (D O to O (c J n m (c O O n O O Cc o O m O O O N C o O_ O O N O o M m M O O V O O N t0 co O O O m O O n o O m o o m N m O O O O O O O N Li Q �^. N N .9 N N N N M M tt'' T M M M M m M M Cl) Q M M M M M V r V V 2 0 G V p c I d m d _ V Eo a� 0 Y y n M N O N n Cl) co O M N n O O co O m o O N co N m O w N N V N U0 t0 M N M N M M r O O O O n O n m W N O n m u) O V r o O M o co N O V N M a ':3 .� 0)0 r .r N r m m co d) M d) M d) M m M m CO Q) CO b) O a) n V tO U0 m V OD V CO V M V V O V O V n M n M m 'IT 3 V v v v v v a v v e0 aD ao m ao ao eD co m m m ao = c v W m m m W m v v v v V v v V v v v v o L J m m m W d) m p a ri) m o o z z z z z z z z z z z z z z z z z z z z z z SK OO O n n M r 0 n N n N n O w UO w U') OD co o OD N m V M CO n N 0) �_ Cl) O n7 r LO Cl) In O tO O Q r N V U0 u7 (n U0 Un UO (O OD m o r r N V UO N (O O O a N N N N N N N N N N N N Cl) M M Cl) Cl) Cl) M co Cl) Cl) 77 `�„ O M O M O M O M O M O M O M O M O M O M O M O M O M O M O M O M O M O M O M O M O M O M O O m 0) m J O O O O O O O o O O O O O O O o O O O O O O co OD N n n n n n n n n n n n n n n n n n n n n n n n Ud ) o o m Cl) CO m (3) V m M (O N UO m Cl) V O o V m N n V � Z M Cl) Cl) O U a n V 0 N O O Co I� m m L6N m o o V 0 V N 0 O m 0 M M (n V m M M m r N m O rn m n OO M m 00 n OO 00 U0 n6 co N (o n N n Cl) O co O O N (n Em W SE m O r r N M M Cl M M M V V m n n oc 0 O o C 202 r r d m m Q C N N N N N N N N N N N N N N N N N Cl) M M M Cl) E y 2 g 2 c Y y N _ (N a 110 UN M M M h u M M N N M N M M u UN N N N N O w a a F m O W CO N Cl) O N O N O N u0 o UO m O 0) V m V m UO M _N N N O O O O M m Cl? o N N N n UO [O (� m (3) co V V V N Vo O co Cl) (O (O (3)N V O n d a m M n tO n (0 n 0 n o n 00 n OO n OD n m n m n oN (o co M m V cc V cc tO w n m OD m M m o oc m Oo m OD L M M N 04 04 C14 M M C14 C-4 04 N cq M M M M `1 0) d L' + C O Cl) O M O Cl) O Cl) O O O Cl) O Cl) O M O M O M O O o O Cl) O M O Cl) O Cl) O M o O N O M O O c0 O O o co c0 c0 O co co (O (D (O O O co c0 co O K z C N O CU d C 'O C U N u V d A t0 n n N M M N N O O CO OO N M V _ (O N V (O N N N Un tO o V n n N (O o o U0 UO co M V V M o Cl! 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M N 14' M O U) M (O O O O) O O N N O O V UO O O O N (fl O cc r 0) O W OO O N M M O M N W 7 NN N N M M M M V UO N O (O O r n r n W d + R C O O U O O N W O N V N N w O O O M UO O W UO .- O N n O M O N O) jp O O N (P CO V O) V (O O N O (O O) N (P n' N r r N O r V r M V N N [O (� O O w V o o M N (O r- — V r UO N N O r M � O O O (O N V N r V OO O O V (O w V m V (O (O W O O) (O M m CA J to N N V V N (ON N N N M N N N O O W O (O V r e - O O O O O N O O n O m N n n O N CD O (O M O O O V w O N O r- n O O 0) O O (- N OD O O Ou O) n O O N CO V OR M M Cl OR 7 7 O M OR OR M CO O3 rO O O Qu CO )n O .- N UO V O) V O OO N V to N O N O) M N UO a0 O O V C$ Cl) O V O M N (D O) (A (A CO CO O 0 O O ( cc (CL (C (C N Un O N (O f� ao N N V (O O O O O O (O O (( O (O ( (O h n r O O O O r- r d Q N N N N M M M M M M M M M M M M M M co co M M co M M co M O O O M M M N M 0 M 0 M MV M V M O M UA N N M r- h O O CM a O UO r O O M r N OD O V r-: N M OR O OR O) O O UO V CD M (O O O) CO v O O O) co UO UO UO (o O M co Cl) co O) UO M W N Un N V N M r N CO V V M J .L+ Cr M O V N V O N h O h CO O N O Un OD (O () n CO O U) N UO O N m n co N CL N CO n OD CO M N O (O N M Un O O O N (C r (O O O) O OO OO r (O M Un O r- ) .- N N CV N V V N Un N N CO CO (O CO n r n CO Ou O of M O O O cD a m 7 O O O O 0 C/) IX g O U Q Ch 12 N O Vi t z CL E LO E O U) C 6, 0 IW CL Y 7 m Q 7 Y OI C c ci c u ° c m a m yd V d M S O o � N O> Oco O Q O co O M O M Q 0N OJ O FO 2 M O O g , O L (6 v 2 ri coo O O D N y6 N YO YO (6 u) u) u) d M W M V I In N O O) (D lf] M M C O O M O) O M M O W O O I- 7 N M O) CO N CO (0O N Ou O] N M N N N N V M r M m I-- N V O Il- N 0 m O r t` I- t` co M M M M M M N W 0 O 10 W N O M N r— M V O m N L) U N L U cD co a m _V O O O U N O r ConocoPs philli ConocoPhillips Alaska Inc—Kuparuk Kuparuk River Unit _2 Kuparuk 3R Pad Plan: 3R-107 50029xxxxx00 3R-107 3R-107 wp07 Anticollision Report 20 November, 2019 BakerWughes 2�; ConocoPhillips ConocoPhillips Anticollision Report BakerHughes Company: ConocoPhillips Alaska Inc_Kuparuk Project: Kuparuk River Unit -2 Reference Site: Kuparuk 3R Pad Site Error: 0.00 usft Reference Well: Plan: 3R-107 Well Error: 0.00 usft Reference Wellbore 3R-107 Reference Design: 3R-107 wp07 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well Plan: 3R-107 Plan: 9.8+39.10 @ 48.90usft (Doyon 142) Plan: 9.8+39.10 @ 48.90usft (Doyon 142) True Minimum Curvature 2.00 sigma OAKEDMP1 Offset Datum Reference 3R-107 wp07 GYD-GC-SS Gyrodata gyro single shots Filter type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference OWSG MWD - Standard Interpolation Method: MD Interval 25.00usft Error Model: ISCWSA Depth Range: Unlimited Scan Method: Tray. Cylinder North Results Limited by: Maximum ellipse separation of 3,000.00 usft Error Surface: Combined Pedal Curve Warning Levels Evaluated at: 2.79 Sigma Casing Method: Added to Error Values Survey Tool Program Date 11/2012019 From To (usft) (usft) Survey (Wellbore) Tool Name Description 39.10 1,000.00 3R-107 wp07 (3R-107) GYD-GC-SS Gyrodata gyro single shots 1,000.00 2,345.08 3R-107 wp07 (3R-107) MWD OWSG OWSG MWD - Standard 1,000.00 2,345.08 3R-107 wp07 (3R-107) MWD+IFR2+SAG+MS OWSG MWD + IFR2 + Sag + Multi -Station Correction 2,345.08 5,573.00 3R-107 wp07 (3R-107) MWD OWSG OWSG MWD - Standard 2,345.08 5,573.00 3R-107 wp07 (3R-107) MWD+IFR2+SAG+MS OWSG MWD + IFR2 + Sag + Multi -Station Correction 5,573.00 13,684.40 3R-107 wp07 (3R-107) MWD OWSG OWSG MWD - Standard 5,573.00 13,684.40 3R-107 wp07 (3R-107) MWD+IFR2+SAG+MS OWSG MWD + IFR2 + Sag + Multi -Station Correction Summary Reference Offset Distance Measured Measured Between Between Separation Warning Site Name Depth Depth Centres Ellipses Factor Offset Well - Wellbore - Design (usft) (usft) (usft) (usft) Kuparuk 3R Pad 3R-10 - 3R-10 - 3R-10 196.90 200.00 14.58 11.92 5.485 CC 3R-10 - 3R-10 - 3R-10 346.88 350.00 15.17 10.54 3.281 ES 3R-10 - 3R-10 - 3R-10 4,241.62 4,025.00 142.72 56.43 1.654 Caution Monitor Closely, SF 3R-10 - 3R -10A - 3R -10A 196.90 200.00 14.58 11.92 5.485 CC 3R-10 - 3R -10A- 3R -10A 346.88 350.00 15.17 10.54 3.281 ES 3R -10 -3R -10A -3R -10A 4,241.62 4,025.00 142.72 56.43 1.654 Caution Monitor Closely, SF 3R-101 - 3R-101 - 3R-101 39.10 39.10 104.76 103.64 93.521 CC 3R-101 - 3R-101 - 3R-101 174.89 175.00 105.17 103.49 62.859 ES 3R-101 - 3R-101 - 3R-101 2,228.98 2,225.00 331.57 310.76 15.936 SF 3R-101 - 3R-101 L1 - 3R-101 L1 39.10 39.10 104.76 103.64 93.521 CC 3R-101 - 3R-101 L1 - 3R-101 L1 174.89 175.00 105.17 103.49 62.859 ES 3R-101 - 3R-101 L1 - 3R-101 L1 2,228.98 2,225.00 331.57 310.76 15.936 SF 3R-101 - 3R-101 L1 PB1 - 3R-101 L1 PB1 39.10 39.10 104.76 103.64 93.521 CC 3R-101 - 3R-101 L1 P61 - 3R-101 L1 PB1 174.89 175.00 105.17 103.49 62.859 ES 3R-101 - 3R-101 L1 PB1 - 3R-101 L1 PB1 2,228.98 2,225.00 331.57 310.76 15.936 SF 3R-102 - 3R-102 - 3R-102 299.90 300.00 74.13 71.79 31.730 CC 3R-102 - 3R-102 - 3R-102 349.89 350.00 74.23 71.67 29.006 ES 3R-102 - 3R-102 - 3R-102 725.31 725.00 90.79 86.38 20.579 SF 3R-106 - 3R-106 - 3R-106 39.10 39.49 34.79 33.78 34.417 CC 3R-106 - 3R-106 - 3R-106 1,129.36 1,125.00 34.93 28.17 5.164 ES 3R-106 - 3R-106 - 3R-106 13,590.00 14,125.00 1,356.50 694.77 2.050 Caution Monitor Closely, SF 3R-111 - 3R-111 - 3R-111 324.74 325.00 19.20 16.73 7.755 CC 3R-111 - 3R-111 - 3R-111 374.70 375.00 19.34 16.58 7.018 ES 3R-111 - 3R-111 - 3R-111 474.43 475.00 21.56 18.23 6.488 SF 3R-111 - 3R-111 L1 - 3R-111 L1 324.74 325.00 19.20 16.73 7.755 CC 3R-111 - 3R-111 L1 - 3R-111 L1 374.70 375.00 19.34 16.58 7.018 ES 3R-111 - 3R-111 L1 - 3R-111 L1 474.43 475.00 21.56 18.23 6.488 SF 3R-111 - 3R-111 L1 PB1 - 3R-111 L1 PB1 324.74 325.00 19.20 16.73 7.755 CC 3R-111 - 3R-111 L1 PB1 - 3R-111 L1 PB1 374.70 375.00 19.34 16.58 7.018 ES 3R-111 - 3R-111 L1 PB1 - 3R-111 L1 PB1 474.43 475.00 21.56 18.23 6.488 SF CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 11/20/2019 9:32:15AM Page 2 COMPASS 5000.14 Build 85G BakerHughes Well Plan: 3R-107 Plan: 9.8+39.10 @ 48.90usft (Doyon 142) Plan: 9.8+39.10 @ 48.90usft (Doyon 142) True Minimum Curvature 2.00 sigma OAKEDMP1 Offset Datum Summary ConocoPhillips ConocoPhillips Anticollision Report Company: ConocoPhillips Alaska Inc_Kuparuk Local Co-ordinate Reference Project: Kuparuk River Unit -2 TVD Reference: Reference Site: Kuparuk 3R Pad MD Reference: Site Error: 0.00 usft North Reference: Reference Well: Plan: 3R-107 Survey Calculation Method: Well Error: 0.00 usft Output errors are at Reference Wellbore 3R-107 Database: Reference Design: 3R-107 wp07 Offset TVD Reference: BakerHughes Well Plan: 3R-107 Plan: 9.8+39.10 @ 48.90usft (Doyon 142) Plan: 9.8+39.10 @ 48.90usft (Doyon 142) True Minimum Curvature 2.00 sigma OAKEDMP1 Offset Datum Summary Reference Offset Distance Measured Measured Between Between Separation Warning Site Name Depth Depth Centres Ellipses Factor Offset Well - Wellbore - Design (usft) (usft) (usft) (usft) Kuparuk 3R Pad 3R-112 - 3R-112 - 3R-112 149.65 150.00 54.47 53.06 38.418 CC, ES 3R-112 - 3R-112 - 3R-112 4,531.97 4,800.00 370.89 300.83 5.294 SF 3R-11 D - 3R-11 D - 3R-11 D 646.76 650.00 8.73 4.12 1.892 Caution Monitor Closely, CC 3R-11 D - 3R-11 D - 3R-11 D 671.70 675.00 8.88 4.10 1.859 Caution Monitor Closely, ES 3R -12D - 3R -12A- 3R -12A 621.72 625.00 32.46 24.23 3.942 CC 3R -12D - 3R -12A - 3R -12A 671.31 675.00 32.83 23.94 3.694 ES 3R -12D - 3R -12A - 3R -12A 770.37 775.00 35.55 25.37 3.492 SF 3R -12D - 3R -12D - 3R -12D 621.72 625.00 32.46 24.23 3.942 CC 3R -12D - 3R -12D - 3R -12D 671.31 675.00 32.83 23.94 3.694 ES 3R -12D - 3R -12D - 3R -12D 770.37 775.00 35.55 25.37 3.492 SF 3R-14 - 3R-14 - 3R-14 1,574.65 1,625.00 128.47 108.17 6.329 CC 3R-14 - 3R-14 - 3R-14 1,600.00 1,650.00 128.65 108.03 6.238 ES 3R-14 - 3R-14 - 3R-14 2,000.00 2,075.00 152.35 126.20 5.827 SF 3R-15 - 3R-15 - 3R-15 246.90 250.00 175.25 171.94 52.846 CC 3R-15 - 3R-15 - 3R-15 644.94 650.00 176.13 167.57 20.575 ES 3R-15 - 3R-15 - 3R-15 1,234.23 1,275.00 229.22 213.05 14.175 SF 3R-17 - 3R-17 - 3R-17 46.90 50.00 225.26 223.97 175.075 CC 3R-17 - 3R-17 - 3R-17 644.35 650.00 226.86 218.32 26.565 ES 3R-17 - 3R-17 - 3R-17 1,247.10 1,300.00 292.15 275.60 17.654 SF 3R-18 - 3R-18 - 3R-18 39.10 41.40 250.27 249.04 203.545 CC 3R-18 - 3R-18 - 3R-18 620.57 625.00 253.14 244.90 30.751 ES 3R-18 - 3R-18 - 3R-18 1,308.98 1,375.00 334.64 317.21 19.198 SF 3R-25 - 3R-25 - 3R-25 46.90 50.00 200.31 199.05 159.382 CC 3R-25 - 3R-25 - 3R-25 96.90 100.00 200.36 198.95 141.367 ES 3R -25 -3R -25-3R-25 1,114.39 1,150.00 245.90 239.08 36.056 SF 3R-26 - 3R-26 - 3R-26 346.58 350.00 123.47 120.84 46.939 CC 3R-26 - 3R-26 - 3R-26 371.40 375.00 123.54 120.73 43.956 ES 3R-26 - 3R-26 - 3R-26 661.23 675.00 154.59 149.19 28.630 SF 3R-26 - 3R-26PB1 - 3R-26PB1 346.58 350.00 123.47 120.74 45.324 CC 3R-26 - 3R-26PB1 - 3R-26PB1 371.40 375.00 123.54 120.63 42.537 ES 3R-26 - 3R-26PB1 - 3R-26PB1 638.37 650.00 149.02 143.72 28.132 SF Plan: 3R-103 - 3R-103 - 3R-103 wp06 299.00 300.00 164.09 161.76 70.631 CC Plan: 3R-103 - 3R-103 - 3R-103 wp06 324.00 325.00 164.16 161.70 66.703 ES Plan: 3R-103 - 3R-103 - 3R-103 wp06 902.98 900.00 212.75 207.04 37.265 SF Plan: 3R-103 - 3R-1031-1 - 3R-1031-1 wp02 299.80 300.00 164.09 161.76 70.492 CC Plan: 3R-103 - 3R-1031-1 - 3R-1031-1 wp02 324.80 325.00 164.17 161.70 66.586 ES Plan: 3R-103 - 3R-1031-1 - 3R-1031-1 wp02 903.78 900.00 212.89 207.18 37.264 SF Plan: 3R-104 - 3R-104 - 3R-104 wp05 299.80 300.00 177.36 175.03 76.232 CC Plan: 3R-104 - 3R-104 - 3R-104 wp05 324.80 325.00 177.44 174.98 72.097 ES Plan: 3R-104 - 3R-104 - 3R-104 wp05 973.34 975.00 243.79 237.69 39.966 SF Plan: 3R-104 - 3R-104PB1 - 3R-104PB1 wp01 299.80 300.00 177.36 175.03 76.232 CC Plan: 3R-104 - 3R-104PB1 - 3R-104PB1 wp01 324.80 325.00 177.44 174.98 72.097 ES Plan: 3R-104 - 3R-104PB1 - 3R-104PB1 wp01 973.34 975.00 243.79 237.69 39.966 SF Plan: 3R-105 - 3R-105 - 3R-105_wp10 300.00 300.00 54.85 52.52 23.570 CC Plan: 3R-105 - 3R-105 - 3R-105_wp10 325.00 325.00 54.93 52.46 22.246 ES Plan: 3R-105 - 3R-105 - 3R-105_wp10 599.63 600.00 67.49 63.45 16.694 SF Plan: 3R-105 - 3R-1051-1 - 3R-105L1-wp02 300.00 300.00 54.85 52.52 23.570 CC Plan: 3R-105 - 3R-1051-1 - 3R-105L1_wp02 325.00 325.00 54.93 52.46 22.246 ES Plan: 3R-105 - 3R-1051-1 - 3R-105L1-wp02 599.63 600.00 67.49 63.45 16.694 SF Plan: 3R-107 - 3R-1071-1 - 3R -107L1 wp05 5,396.42 5,400.00 42.03 20.55 1.957 Caution Monitor Closely, CC Plan: 3R-107 - 3R-1071-1 - 31R-1071-1 wp05 13,583.55 13,600.00 102.23 -411.28 0.199 STOP Drilling, ES, SF Plan: 3R-108 - 3R-108 - 3R-108_wPO4 1,403.26 1,375.00 138.38 131.15 19.141 CC, ES Plan: 3R-108 - 3R-108 - 3R-108 w 04 13,586.80 12,975.00 1,275.53 621.89 1.951 Caution Monitor Closely, SF CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 11/20/2019 9:32:15AM Page 3 COMPASS 5000.14 Build 85G `, ConocoPhillips ConocoPhillips Anticollision Report BakerHughes ";;z Company: ConocoPhillips Alaska Inc-Kuparuk Project: Kuparuk River Unit -2 Reference Site: Kuparuk 3R Pad Site Error: 0.00 usft Reference Well: Plan: 3R-107 Well Error: 0.00 usft Reference Wellbore 3R-107 Reference Design: 3R-107 wp07 Summary Site Name Offset Well - Wellbore - Design Kuparuk 3R Pad Plan: 3R-109 - 3R-109 - 3R-109_wp05 (Draft B) Plan: 3R-109 - 3R-109 - 3R-109_wp05 (Draft B) Plan: 3R-109 - 3R-109 - 3R-109_wp05 (Draft B) Plan: 3R-109 - 3R-10911 - 3R-10911 wp02 Plan: 3R-109 - 3R-10911 - 3R-10911 wp02 Plan: 3R-109 - 3R-1091-1 - 313-1091-1 wp02 Kuparuk Oliktok Oliktok Point State 1 - Oliktok Point State 1 - Oliktok Poin Oliktok Point State 1 - Oliktok Point State 1 - Oliktok Poin Oliktok Point State 1 - Oliktok Point State 1 - Oliktok Poin Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well Plan: 3R-107 Plain 9.8+39.10 @ 48.90usft (Doyon 142) Plan: 9.8+39.10 @ 48.90usft (Doyon 142) True Minimum Curvature 2.00 sigma OAKEDMPI Offset Datum Reference Offset Distance Measured Measured Between Between Separation Warning Depth Depth Centres Ellipses Factor (usft) (usft) (usftl (usft) 4,011.04 3,850.00 113.34 70.88 2.669 Normal Operations, CC 4,136.94 3,975.00 122.76 62.45 2.036 Caution Monitor Closely, ES 4,211.37 4,050.00 137.08 67.71 1.976 Caution Monitor Closely, SF 3,981.19 3,850.00 84.91 46.41 2.205 Caution Monitor Closely, CC 4,080.44 3,950.00 91.26 35.05 1.623 Caution Monitor Closely, ES 4,129.59 4,000.00 99.79 36.27 1.571 Caution Monitor Closely, SF 60.10 50.00 39.73 38.43 30.583 CC 260.10 250.00 40.13 38.15 20.251 ES 534.34 525.00 50.80 46.99 13.349 SF CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 1112012019 9:32 15AM Page 4 COMPASS 5000.14 Build 85G ConocoPhillips ConocoPhillips Anticollision Report BakerHughes Company: ConocoPhillips Alaska Inc-Kuparuk Project: Kuparuk River Unit -2 Reference Site: Kuparuk 3R Pad Site Error: 0.00 usft Reference Well: Plan: 3R-107 Well Error: 0.00 usft Reference Wellbore 3R-107 Reference Design: 3R-107 wp07 Local Co-ordinate Reference: ND Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset ND Reference: Well Plan: 3R-107 Plan: 9.8+39.10 @ 48.90usft (Doyon 142) Plan: 9.8+39.10 @ 48.90usft (Doyon 142) True Minimum Curvature 2.00 sigma OAKEDMP1 Offset Datum Reference Depths are relative to Plan: 9.8+39.10 @ 48.90usft (Doyon 1 Coordinates are relative to: Plan: 3R-107 Dffset Depths are relative to Offset Datum Coordinate System is US State Plane 1927, Alaska Zone 4 ventral Meridian is 150° 0'0.000 W Grid Convergence at Surface is: 0.160 Separation Factor Plot II I I I I - I I I I I 1 - --i- LL�� C o Q-- -----' -- - — - - - -- - - -`- -------------- U) Normal Operations 3. Caution MonilorOosely I I I I Take Immediate Action --- I STOP Drilling I I I I I I I I I i I 0.00- 0 2500I5 7500 100D0 12500 Measured Depth LEGEND 3310.3R10,3R10Y2 �1103R1103R11GN :3R103.3R103L1.3RttYtv¢rzw 3R10.3Rt0A3R1Mw 3R12p3R1]A3R1}AVt 3Rt0a 3Rt0a,3Rt0opf5w Ot.3itt01w 3Rtzp3R1203R1zCM :3RtOC,3Rt04LB�,3Rf0aFBi�rpOtw 3i10t.3Rt01L1,3a10tLtw 1a,3Rtu.3R19N :3R1p53R10M-05 V10w 3R10t,3Rt01L1FB1,—ULtFBtw 3R15,3416.3415w Fbn:3R.1053Rt041,3RV31- mw 1023Rt02w]Ltv�2w 3a1M.3R1 W,3R1Cfiw 10,3R10.3R10 V1R1w,3R1-1003 NNW 3RzsaRzS.aRzSw m �wo3to�w xza �ze.3Rzsw Rt®.3R1n�L� 3RmLl�ozw sx111,x1nL�i�aR1n�1�w 3R z51at.3Rzr>re�w owkro��el.oswkw°csau l,oxczw.,t�mtw 3R1u.aR1lzsanzw w°°.3R1msa1m,3R1aaw�w CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 11/20/2019 9:32:15AM Page 5 COMPASS 5000.14 Build 85G 3R-107 & 3R -107L1 Drilling Hazards Summary 13-1/2" Open Hole / 10-3/4" Casing Interval Hazard Risk Level Mitigation Strategy Washouts / Hole Sloughing Moderate Cool mud temperatures, minimize circulating times Concretions when possible. Broach of Conductor Low Monitor cellar continuously during interval. Gas Hydrates Low Control drill, reduced pump rates, reduced drilling fluid temperatures, additions of ScreenKleen. Running Sands and Gravels Low Maintain planned mud parameters, increase mud weight, Whipstock Retrieval Moderate use weighted sweeps. Hole swabbing on trips Low Trip speeds, proper hole filling (use of trip sheets), Hole Swabbing on Trips Moderate pumping out. Anti -Collision Low Follow real time surveys very closely, shut in nearby Tight Hole Low wells that have collision concerns, utilize gyro survey to ensure survey accuracy through zone with magnetic interference. 9-7/8" Open Hole / 7-5/8" CasinI4 Interval Hazard Risk Level Mitigation Strategy Hole swabbing on trips Moderate Trip speeds, proper hole filling (use of trip sheets), Concretions pumping out. Anti -Collision Moderate Follow real time surveys very closely, shut in nearby Getting Liner to Bottom Moderate wells that have collision concerns, and perform real time survey corrections. Stuck Pipe Low Good hole cleaning, monitor real time T&D, stabilized Whipstock Retrieval Moderate BHA, decreased mud weight. Abnormal Reservoir Pressure Low Normally pressured, ensure adequate mud weight prior Hole Swabbing on Trips Moderate to drilling into reservoir. BOP training and drills. Lost circulation Low Monitor ECD, mud rheology, LCM. Tight Hole Low Control with proper drilling practices. Perform wiper trip if hole conditions dictate. 6-3/4" Open Hole / 4-1/2" Liner Interval Hazard Risk Level Mitigation Strategy Fault Crossings and Moderate Use developed best practices for concretion drilling. Ensure Concretions good communication between Wellsite Geologist and DD prior to crossin faults. Getting Liner to Bottom Moderate Properly clean hole on trip out with BHA, add lubes to mud system prior to tripping out to aid in torque and drag, and keep DLS to a minimum. Utilize Su erSliders if necessary. Whipstock Retrieval Moderate A dedicated clean out run prior to attempting to pull whipstock can be used to reduce the risk of fishing operations. Hole Swabbing on Trips Moderate Trip speeds, proper hole filling (use of trip sheets), pumping out or backreamin . 3R-107 Drilling Hazards Summarydoc 11120120198:57:36 AM Lost Circulation Moderate Monitor ECD, mud rheology, LCM program, and have additional fluid stored on location. Differential Sticking Moderate Follow mud program, keep pipe moving when able. Anti -Collision Moderate Follow real time surveys very closely, shut in nearby wells that are of concern for collision. Utilize AziTrak tool to maintain geological certainty to stay in zone. Casing Wear Moderate Maintain low doglegs in the surface interval and use SuperSliders if necessary for drilling, milling, and liner running o erations. Abnormal Reservoir Low Stripping drills, shut-in drills, increased mud weight if higher Pressure pressure encountered. Stuck Pipe Low Good hole cleaning, PWD tools monitoring and analysis, decreased mud weight. 3R-107 Drilling Hazards Summarydoc 11/2020198:57:36 AM x .,. . x O nl ; pl r m ozo • III m , pl • ' � r ' III • ' • III ' 00 111 111 , r z III • � ; III • r 111 • ri • III ; ; 111 ; �, • III r ' III • , r III r III r v � III r r III r = III r • III • p • III ; y ; III ; G� , 111 • � • III • , III r ,� • III r III r a 4L ryl • , ao� r III � r Ip ' .-7 • III ' r ' III • r • III ; `� • � III r III ; y.• (`V ' III r ; ., r 111 , V � ^ � ; III r • 111 ; • � ; III r 111 ; � � � � ; 111 • III ; ' III � • ; 111 . 111 r 111 • "i r ' III • r III r nJ y,. Y� , III r , III r • • III , III • y ' r (Q L � r III ' ; 111 i • � r III SC 1 1 • � Q , III • �j f1. � FN4 M °>' •p V Qz � m ; r , ' � • c ' III r � 111 • q q y p�� ; I11 • Y 1 III • ^ � b0 � O � • III ; � ; III ; .x C C a � •� o pl • (� • dl W 3 III ; N � � y i� t x � m b i III • • Ill ' r 1 r ' T .moi G. t> Ni - oo x W !�S 9 ' III • % r a M CJ 0000 y ted C ^✓ ' 00 a/-� E' c v (� I U "oFo I v p a Cq o U v ni.45 q22 c 0— "yy� 12 T Q U R x M x o A N Vl d m c a 8 R. 0 z s � A �______-- --- N .a a •� as A O n m iV � M ConocoPhillips 311-107 Dual Lateral Slotted Liner Producer 3R-107wp07 Wmdrd 11/70119 Alaska 1 0 � nI o F I lil I b M 1 III M 1 III P 1 1 III ' ALL ' III 1 III ' III 1 � 1 i III ' O ' III 1 III O 1 111 � 1 III 1 7 � 111 1 � III � j III 1 1 G 1 III 1 1 a 1 j � 111 1 III 1 III � III 'b j III 1 1 Y ' 1 III 1 111 1 1 III O � III j � j ' C � III j III 1 III U vi � III 1 ,j 1 III J M 1p 1 1 III G LV\ N i 111 U4 CC U - (Q Q1 III 1 .. U y ' 111 1 '51 1 III 1 III 1 j III 1 U III 1 1 III 1 M' IV)CU F�-1 'Q 11I i a� i 4i Pte. 1 1 7 III 1 D 'pt�.G ♦... 4:r R G C E I 1 Q 111 I Q x C�C - � (b F Q a 1 III 1 x 1 111 ' .G. C 7 1 III 1 X 1 111 ' > X11 ' N to. F v o o x 1 111 1 3 Q= 0�0 U C M E N a ♦� o H '4:!tb X N a \ bq a T x .N -.LL. G :o �I I. 0 N \ N�"4 a W . ♦ 4l U ^ N � � y a 2 L ^CD 7 b c G N 7 G G Vt N C Q h L � M M 3 O T E OOO N� �F ow d N n G O p, a a v CL -------:'' ,n � on G 'd b G F e a N O � � M M :IIS 3R-105 Dual Lateral Slotted Liner Producer 3R-107 Dmf, Schemm,cvsd Sylte 8/10/1018 Attachment 4 SOP Conftyuration The following ram configuration will be utilized for the West Sak wells. Further details regarding the BOPE specifications can be found with the Doyon 142 documentation on file with the State. Name: KRU 3R-107 1 —Data Input Mud Welaht point or LOT - Measured depth (tt) point or LOT True vertical depth (ft) point or LOT - Hole angle (deg) point or LOT - Hole size (in) point pressure or LOT - EMW (ppg) — Data Input 70 1 — Data — Data Input — Data Input — Data Input — Data Input — Data Input !one of interest - Measured depth (ft) 5,836' — Data Input !one of interest - True vertical depth (ft) 3,700' — Data Input !-one of interest - Hole angle (deg) 91.50 — Data Input '--one of interest - Hole size (in) 7.625" — Data Input !one of interest - Pore pressure EMW (ppg) 9.20 — Data Input — Data Bottom hole assembly OD (in) 1 8.0..1 — Data Input Bottom hole assembly length (ft) 1 200' — Data Input Drill pipe OD (in) 5.500" — Data Input BHA annular vol. @ zone of interest (bbl/ft)-0.0057 DP annular vol. @ zone of interest (bbl/ft) 0.0271 DP annular vol. weak point bbl/ft0.0829 Additional safety margin (psi) 0.00 <_= Data Input Weak point pressure (psi): Plo 1,338 psi Weak point pressure - Safety margin: Pmax Pmax EMW 1,338 psi 11.50 ppg Max anticipated formation pressure (psi): Pf 1,770 psi Weak Pt to Zone of Interest distance (TVD ft): OH {TVD) 1,462' Weak Pt to Zone of Interest distance (MD ft): OH {MD) 3,583' Maximum influx height at the bit (TVD ft): H (TVD) 652' Maximum influx height at the bit (MD ft): H {MD) -24,895' Calc. volume of (H) around BHA: Calc. volume of (H) around drill pipe: Calc. volume that H equals @ initial shut in: Vlbha Vldp V1 141.7 bbl 0.0 bbl 141.7 bbl Calc. vol. that H equals @ weak point (MD ft): VWP 63.0 bbl Calc. volume of Vwp @ initial shut in: V2 47.6 bbl Kick Tolerance: V2 Loepp, Victoria T (CED) From: Woodard, Madeline E <Madeline.E.Woodard@conocophillips.com> Sent: Tuesday, December 10, 2019 8:58 AM To: Loepp, Victoria T (CED) Subject: 3R-107 Correct Wellbore Schematic Attachments: 3R-107 wp07.pdf Victoria, See the correct schematic attached. I am really sorry about that, as I mentioned 311-1071-1 PTD application has the correct schematic (same as attached). Thanks, Madeline Woodard Drilling Engineer ConocoPhillips Alaska, Inc Office: 907-265-6086 Mobile: 907-764-8095 If �I o� III O ' III 1 7 . III III 1 III i III , ,+i i N ; III r r III , �^ III 1 1 III lu 1 1 nl Iu ' IL ; iii i oco� R r III ; y III Y � , ' •� 'm 1 G vNi I11 .. 3 U 1 IIvm- I � X Q, °❑❑",y „� . III ' X ' ,� (Yj C cd III � V 00 L bi r T 10 bit x N k NA �t; y In vi N N C p W v1 d R U ^ pq �{ N `� ,p� td •C y H �Q bDO 90 =- M D Q N l n> 00 U x , M 10 [� M N y d .-. C C Oo N Vi Y 'FO O !: C R Z 5 c px o Ni 10 r; ConocoPhillips 3R-107 Dual Lateral Slotted Liner Producer 3R-107wpp7 W dtrd 77120119 Alaska IA Q �a 0 0 0 u I �T F --T T - -i -F— --7 Ob'- V c (ui/)jsn 009) (+)uljoN/(-)glnos 0 y z a s 4 3X i6 h y0 p D/b K ib 0. 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Then click on the appropriate arrow button to transform the points to the desired coordinate system. t r Fush < Back Cancel l l64Pelp TRANSMITTAL LETTER CHECKLIST WELL NAME: KR U, ,5R --(0 PTD: 2S11- 1190 `I Development —Service Exploratory Stratigraphic Test _ Non -Conventional FIELD:I t,t p V� I �� (BOOL:S l " Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. ) API No. 50- - - - (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69 In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - - from records, data and logs acquired for well name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (CompM Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company) in the attached application, the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool KUPARUK RIVER, WEST SAK OIL - 490150 PTD#: 2191800 Company ConocoPhillips Alaska, Inc. Initial Class/Type Well Name: KUPARUK RIV UNIT 3R-107 Program DEV Well bore seg ❑ DEV / PEND GeoArea 890 Unit 11160 On/Off Shore On Annular Disposal ❑ Administration 1 Permit_feeattached------------------------------------------- NA --- ------- ---------------------- 2 Lease number appropriate- - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 3 Unique well -name and number - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - 4 Well Io c at e d i n a _ d efi n e d pool - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Y es - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - ------------------------- 5 Well located proper distance from drilling unit _boundary _ _ _ _ _ _ _ __ _ _ _ _ _ _ _ _ _ _ _ _ Yes ------------------------------ 6 Well located proper distance from other wells_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes - _ _ _ _ . _ ----------------------------------------------- 7 Sufficient acreage available in drilling unit - - - - - _ - _ _ - _ _ _ _ _ - - Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 8 If deviated, is -wellbore plat_included - - - - - - - - - - - - - - - - - - -- - - - - - - - - - - - - - - Yes _ - - _ _ _ . Directional -plat and wellbore profile were provided. - - - - - - - - - - 9 Operator only affected party - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - _ - _ _ _ _ 10 Operator has_appropriate_bondinforce---- ----------------------- - - - - -- Yes ___________-__________________._________ 11 Permit can be issued without conservation order- - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - - - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . - Appr Date 12 Permit can be issued without administrativ_e_approval _ . - _ _ Yes _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 13 Can permit be approved before 15 -day wait- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes _ - - - - - - - - _ _ . _ _ _ - - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ - _ - - _ - - - - - DLB 11/26/2019 14 Well located within area and strata authorized by- Injection Order # (put 10# in_comments)_(For_ NA- - - - - - - - - - - - - - - - - - - - - - --------------------------------------------------- 15 All wells -within 1/4_mile area of review identified(For service ice -well y l onl NA- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 16 Pre -produced injector: duration of pre production Less than 3 months_ (For service well only) - NA_ 17 Nonconven. gas conforms toAS31.05.030(y1.A),(j.2.A-D) - - - - - - - - - - - - - - - - - - - - - NA-- - - -- - - - - - - - - - .. _ - - - - - - - - - - _ - 18 Conductor string -provided - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - 12.9' conductor set and_ cemented _ _ _ _ Engineering 19 Surface casing_ protects all -known USDWs - - - - - - - - - - - - - - - - - - - Yes - - - - - - - Set to 2253' MD - - - - 20 CUT -vol _adequate _to circulate on conductor & surf_csg _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ _ _ _ _ _ _ _ Yes - - - - - - - 2115516 excess _ 21 CMT_vol_adequate _to tie -in -long string to surf csg_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ No_ - - - - - - - - - - - - - - - - _ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 22 CMT will cover all known productive horizons- - - - - - - - - - - - - - - - - - - - - - - - - - - - - No_ - - - - - - - Productiv_e_interval will be completed with uncemented slotted_ liner 23 Casing designs adequate for C,_T, B &_permafrost- - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - - - - - _ _ _ _ _ _ _ _ _ - _ - - - _ _ _ _ _ _ - _ _ .. _ - - - . - _ _ .. _ _ - . 24 Adequate -tankage or reserve pit - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - _ _ _ Rig has steel tanks, all _waste _to approved disposal wells_ 25 If a -re -drill, has_a 10-403 for abandonment been approved _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA_ - - - - - _ _ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 26 Adequate wellbore separation proposed - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes Anti -collision analysis complete; no major risk failures 27 If diverter required, does it meet regulations- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - Diverter variance granted per -20 AAC 25.035(h)(2) - - - - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ Appr Date 28 Drilling fluid_program schematic & equip list -adequate - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - Max formation_ pressure is_ 1720 psig(8.7 ppg EMW ); will drill w/_8.8-9.5 ppg EMW _ _ _ _ VTL 12/6/2019 29 BOPEs,_do they meet regulation - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 30 BOPE_press rating appropriate; test to (put psig in comments)_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes - - - - - _ - MPSP is -1 34Q psig, will test BOPs_to 3500-psig - - - - - - - - - - - _ _ _ _ _ - 31 Choke_manifold complies w/API_RP-53 (May 84)- - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 32 Work will occur without operation shutdown ------------------------------ Yes ____________-________________-_____________________________ 33 Is presence ofH2Sgas probable ------------------------------------ Yes ------- H2Smeasures required __-_________________________-_---_____ 34 Mechanical condition of wells within AOR verified (For service well only_) _ _ _ _ _ _ _ _ _ _ _ _ _ NA_ - - _ - - - - - - - - - - - - - - - _ - - _ - - _ _ _ _ _ _ - _ _ _ - - - - 35 Permit -can be issued w/o hydrogen_ sulfide measures _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ No_ - - - - - - - The -highest H2S recorded in the West Sak open in 3R-101 was 20 ppm on 10107/19._ Geology 36 Data -presented on potential overpressure zones - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - 1-12S measures are now required as aprecaution for West Sak development on 3R Pad. - Appr Date 37 Seismic analysis_ of shallow gas -zones - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - NA_ - - - - - - - - - _ _ - _ _ - _ - _ _ - - - _ _ _ _ _ _ - - - - _ _ .. _ _ .... _ _ _ _ - _ _ _ - - - - - - D L B 11/26/2019 38 Seabed condition survey -(if off_ -shore) - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - N A _ - - - - - - - - - - - - - - - _ - - - - - - - - - - - - - - - - - - - - - - - - - - - - _ - - - _ _ _ - . _ 39 Contact-name/phone for weekly -progress reports [exploratory only_] - - _ _ _ _ _ - NA_ Geologic Engineering Public Commissioner: Date: Commissioner: Date Comis ner Date p,