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Home My WebLink About192-109Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 3/20/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240320 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 19RD 50133205790100 219188 2/2/2024 AK E-LINE Perf CLU 14 50133206840000 219078 12/11/2023 AK E-LINE Perf IRU 41-01 50283200880000 192109 11/15/2023 AK E-LINE PERF KBU 22-06Y 50133206500000 215044 12/29/2023 AK E-LINE PERF MPU C-14 50029213440000 185088 3/4/2024 AK E-LINE Whipstock MPU L-62 50029236850000 220059 3/3/2024 AK E-LINE TubingPunch NCIU A-17 50883201880000 223031 12/13/2024 AK E-LINE GPT /Plug /Perf Paxton 6 50133207070000 222054 2/27/2024 AK E-LINE Plug/Perf PBU BORE V-109 50029231200000 202202 2/13/2024 AK E-LINE TubingPunch Please include current contact information if different from above. T38657 T38658 T38659 T38660 T38661 T38662 T38663 T38664 T38665 IRU 41-01 50283200880000 192109 11/15/2023 AK E-LINE PERF Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.03.21 13:14:02 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 3/14/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240314 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 13 50133205250000 203138 1/20/2024 AK E-LINE GPT/PL BCU 13 50133205250000 203138 1/4/2023 AK E-LINE JetCut/CBL BRU 221-35 50283201930000 223077 11/18/2023 AK E-LINE Perf HV B-13 50231200320000 207151 12/22/2023 AK E-LINE CBL IRU 41-01 50283200880000 192109 11/16/2023 AK E-LINE Perf KBU 22-06Y 50133206500000 215044 1/16/2024 AK E-LINE GPT/Perf KTU 32-07H 50133205110000 202043 10/27/2023 AK E-LINE PPROF KU 3-06A 50133207160000 223112 1/12/2024 AK E-LINE CBL KU 21X-32 50133202040000 169100 12/8/2023 AK E-LINE JetCut MPU CFP-02 50029212580000 184242 3/9/2024 READ CaliperSurvey NCI A-18 50883201890000 223033 12/8/2023 AK E-LINE Perf/GPT NIA NK-18 50029224210000 193177 12/13/2023 AK E-LINE IPROF PTM P1-13 50029223720000 193074 12/9/2023 AK E-LINE Cement TBU M-11 50733205900000 210145 1/8/2024 AK E-LINE Perf TBU M-15 50733204220000 190109 2/7/2024 AK E-LINE GPT/Perf Please include current contact information if different from above. T38615 T38615 T38616 T38617 T38618 T38619 T38620 T38621 T38622 T38623 T38624 T38625 T38626 T38627 T38628 IRU 41-01 50283200880000 192109 11/16/2023 AK E-LINE Perf Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.03.15 11:38:35 -08'00' 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: CTCO, Cmt Sqz, N2 2.Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 9,170'8,530' Casing Collapse Structural Conductor Surface 1,950psi Intermediate 4,750psi Production 7,020psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Baker Premier Pkr & N/A 5,374 (MD) 4,902 (TVD) & N/A 8,283'5,534'5,045' Ivan River Undefined Gas Pool 20" 13-3/8" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Ivan River Unit (IRU) 41-01CO 301 Same 8,266'7" ~2449psi 9,152' 5,534; 8,597 Length November 14, 2023 2-7/8" & 1-1/2" 9,152' Perforation Depth MD (ft): 3,498' See Attached Schematic 6,870psi 3,450psi 165' 3,335' 165' 895' Size 165' 9-5/8"3,498' 895' MD Hilcorp Alaska, LLC Proposed Pools: 6.4# / L-80 & 2.75# / J-55 TVD Burst 5,955 & 2,994 8,160psi 894' Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0032930 192-109 50-283-20088-00-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Jake Flora, Operations Engineer AOGCC USE ONLY Tubing Grade: jake.flora@hilcorp.com 907-777-8442 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: m n P s 66 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 3:39 pm, Nov 01, 2023 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2023.11.01 12:46:32 - 08'00' Noel Nocas (4361) 323-596 MGR02NOV23 10-404 DSR-11/2/23 ~2449psi SFD 11/2/2023 BOPE test to 3000 psi. 48 hour notice to AOGCC. *&: Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.11.03 10:39:03 -08'00'11/03/23 RBDMS JSB 110723 Well Prognosis Well Name: IRU 41-01 API Number: 50-283-20088-00 Regulatory Contact: Donna Ambruz Permit to Drill Number: 192-109 First Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (M) Second Call Engineer: Chad Helgeson (907) 777-8420 (O) (907) 229-4824 (M) Maximum Expected BHP: ~ 3169 psi @ 7204’ TVD (0.44 psi/ft gradient to bottom new perf) Max. Potential Surface Pressure: ~ 2449 psi (Max expected BHP minus gas to surface) Well Status: SI Gas Producer Last well test: 1000 mcfd @ 765 psi, 20 bwpd (10/24/23) Brief Well Summary IRU 41-01 is a Sterling & Beluga gas producer that sanded off and was brought back online by perforating the Sterling B1 in 2021, and then again by adding the A3 sands in 2022. The well was recently cleanout out to below the open sterling perforations, but was unable to unload or be brought back online. A subsequent cleanout was then performed, followed by a plug and cement retainer squeeze to isolate uphole Sterling targets. The Sterling A2 was shot and found wet. The Sterling X2 was then shot and kicked the well off again. It flowed approximately one month and loaded up and died, with the water entry from the Sterling A1 suspected as the culprit. The objective of this sundry is to clean the well out , squeeze off both sets of perfs and reperf the Sterling X2. History: 4/06/22 Drift and tag at 5656’ w 1.75” bailer, recover sand 7/18/23 Well plugged off and died 7/22/23 Bailed hard packed clay (4) days from 5053’ – 5111’ (top open perfs: 5544-5551’) 8/05/23 Performed coil cleanout to 5800’, lifted w N2, could not get well online or unloaded 9/03/23 RU E-line, could not pass 5404’ (not deep enough to add perfs) 9/16/23 Set CIBP at 5728’ 9/17/23 Set cmt retainer at 5534’, pump coil squeeze below retainer 9/22/23 Perf Sterling A1 9/23/23 Perf Sterling X2, POP well 10/27/23 2” DDB, tag muddy fill at 5015’ Procedure: 1. Review approved COAs 2. Provide AOGCC 48hrs notice 3. MIRU coil tubing, BOP test to 3000 psi 4. Clean out to 5534’ with water 5. Log with memory tools, flag pipe 6. Set 2-7/8 cement retainer just over A1 perfs at ~5584’ 7. Establish injection into open perfs, determine cement job volume based on injection results 8. Mix and pump cement below retainer, into the A1 perfs taking returns from annulus via the X2 perfs 9. Unsting, circulate clean from retainer depth 10. TOOH, WOC 11. RIH with motor/mill, clean out to cmt retainer, blow dry with N2, trap pressure 12. RDMO coil Well Prognosis 13. MIRU E-line, PT lubricator to 3000 psi 14. Reperforate Sterling X2 Attachments: 1. Actual Schematic 2. Proposed Schematic 3. CT BOP Diagram 4. Standard Nitrogen Procedure 5. AOGCC Rig Workover Change Form _______________ __________________________________________________ Updated by DMA 10-18-23 SCHEMATIC Ivan River Unit IRU 41-01 Completion Ran 8/10/11 PTD: 192-109 API: 50-283-20088-00-00 TD =9,170’ PBTD = 8,597’ Sterling / Beluga RT-THF:24’ KB 7” @ 9,152’ ST B1U 13 17 18 20 16 19 11 3 4 6 RKB: 51’ AMSL 13-3/8” @ 895’ 9-5/8” @ 3,498’ 20” @ 165’ 1 12 8 9 10 2 Tyonek ST A3 7 5 ST X2-A1 Tagged fill @ 8,851’(7/22/09) CBL Top:5,000’ R RA Fill cleanout to 5800’(8-4-23) CASING DETAIL Size Type Wt/ Grade Top Btm CONN / ID Cement / Other 20”Conductor 94#Surface 165’Driven 13-3/8”Surface 68#, K-55 Surface 895’Butt / 12.415”212 bbl / Cmt to Surface 9-5/8”Intermediate 47#, N-80 Surface 144’Butt / 8.681”281 bbl / Cmt to Surface47#, S-95 144’3,498’Butt / 8.681” 7”Production 29#, N-80 Surface 9,152’Butt / 6.184”171 bbl / Cmt to 5,000’ Tubing Detail 2-7/8”Production 6.4#, L-80 Surface 5,955’IBT-Mod/2.441” 1-1/2”Heater 2.75#, J-55 Surface 2,994’10RD Fluid: Propelyne Glycol JEWELRY DETAIL No.Depth Length ID OD Item 1 24.20’ 0.55’2.441”12.00”Dual Tubing Hanger, 2-7/8” x 2-3/8” 12” 5M National (2-7/8” & 2-3/8” 8RD lift threads) 2 5,327’4.03’2.310”3.920”Sliding Sleeve, Halliburton XD 3 5,374’8.38’2.870”5.980”Premier Packer 4 5,428’1.30’2.313”3.220”Baker X Profile (2.313” Min ID) 5 5,534’Cement Retainer (9/17/23) 6 5,595’1.41’2.257”2.880”Mechanical-release 7 5,728’CIBP (9/16/23) 8 5,916’0.70’2.441”3.958”Ported Sub 9 5,955’0.94’3.670”4.950”WLEG 10 +/-8,530’32.77’--Dropped TCP Assembly 11 8,597’2.00’--Cement Retainer capped w/ 269’ cement (Est) 12 8,613’-2.441”3.500”Cut tubing stub 13 8,629’ 4.78’3.250”5.968”Baker 3H Packer w/ mill out extension (Min ID thru Anchor Latch Seal Assembly) 16 8,643’0.67’2.441”3.500”Baker “RA” Sub 17 8,650’1.24’2.250”3.500"Baker R Profile w/ No-go 18 8,659’0.63’2.441”3.687”Baker Ported Sub w/ glass disc 19 8,693’0.82’2.441”3.687”Tubing Tail 20 8,895’ (est)183’3.687”FISH: Baker TCP Drop Off Guns PERFORATION DETAIL ZONE TOP (MD) BTM (MD)TOP (TVD)BTM (TVD)Ft Condition Sterling X2 5,446’5,454’4,669’4,975’8’Perfed 9/23/23 - Open Sterling A1 5,494’5,501’5,010’5,017’7’Perfed 9/22/23 - Open ST-A3 5,544’5,551’5,054’5,060’7 Perfed 9/9/22 – Isolated ST-B1U 5,671'5,678'5,165'5,172'7 Perfed 2/4/21 – Isolated Sterling/ Beluga 5,977’5,987’5,434'5,443'5 spf 4-5/8” TCP (11/2/11) 73-4 Sd 7,768'7,796'7,019'7,044'6 spf 2” HC, 60 deg phase (6/29/12) Iso 7,954’7,974’7,186'7,204'6 spf 2” HC, 60 deg phase (6/28/12) Iso Tyonek 8,710’8,725’7,868'7,882'12 spf Perfed 1/26/93 Isolated 8,745’8,768’7,900'7,920'12 spf Perfed 1/26/93 Isolated 8,783’8,803’7,934'7,952'12 spf Perfed 1/26/93 Isolated 8,815’8,875’7,963'8,017'12 spf Perfed 1/26/93 Isolated _______________ __________________________________________________ Updated by JMF 10-30 -23 PROPOSED Ivan River Unit IRU 41-01 Completion Ran 8/10/11 PTD: 192-109 API: 50-283-20088-00-00 TD =9,170’ PBTD = 8,597’ Sterling / Beluga RT-THF:24’ KB 7” @ 9,152’ ST B1U 13 17 18 20 16 19 11 3 4 6 RKB: 51’ AMSL 13-3/8” @ 895’ 9-5/8” @ 3,498’ 20” @ 165’ 1 12 8 9 10 2 Tyonek ST A3 7 5 ST X2 re-perf ST A1 squeeze with retainer Tagged fill @ 8,851’(7/22/09) CBL Top:5,000’ R RA Fill cleanout to 5800’(8-4-23) CASING DETAIL Size Type Wt/ Grade Top Btm CONN / ID Cement / Other 20”Conductor 94#Surface 165’Driven 13-3/8”Surface 68#, K-55 Surface 895’Butt / 12.415”212 bbl / Cmt to Surface 9-5/8”Intermediate 47#, N-80 Surface 144’Butt / 8.681”281 bbl / Cmt to Surface47#, S-95 144’3,498’Butt / 8.681” 7”Production 29#, N-80 Surface 9,152’Butt / 6.184”171 bbl / Cmt to 5,000’ Tubing Detail 2-7/8”Production 6.4#, L-80 Surface 5,955’IBT-Mod/2.441” 1-1/2”Heater 2.75#, J-55 Surface 2,994’10RD Fluid: Propelyne Glycol JEWELRY DETAIL No.Depth Length ID OD Item 1 24.20’ 0.55’2.441”12.00”Dual Tubing Hanger, 2-7/8” x 2-3/8” 12” 5M National (2-7/8” & 2-3/8” 8RD lift threads) 2 5,327’4.03’2.310”3.920”Sliding Sleeve, Halliburton XD 3 5,374’8.38’2.870”5.980”Premier Packer 4 5,428’1.30’2.313”3.220”Baker X Profile (2.313” Min ID) 5484’Cement retainer 5 5,534’Cement Retainer (9/17/23) 6 5,595’1.41’2.257”2.880”Mechanical-release 7 5,728’CIBP (9/16/23) 8 5,916’0.70’2.441”3.958”Ported Sub 9 5,955’0.94’3.670”4.950”WLEG 10 +/-8,530’32.77’--Dropped TCP Assembly 11 8,597’2.00’--Cement Retainer capped w/ 269’ cement (Est) 12 8,613’-2.441”3.500”Cut tubing stub 13 8,629’ 4.78’3.250”5.968”Baker 3H Packer w/ mill out extension (Min ID thru Anchor Latch Seal Assembly) 16 8,643’0.67’2.441”3.500”Baker “RA” Sub 17 8,650’1.24’2.250”3.500"Baker R Profile w/ No-go 18 8,659’0.63’2.441”3.687”Baker Ported Sub w/ glass disc 19 8,693’0.82’2.441”3.687”Tubing Tail 20 8,895’ (est)183’3.687”FISH: Baker TCP Drop Off Guns PERFORATION DETAIL ZONE TOP (MD) BTM (MD)TOP (TVD)BTM (TVD)Ft Condition Sterling X2 5,446’5,454’4,669’4,975’8’Perfed 9/23/23 - Open Sterling A1 5,494’5,501’5,010’5,017’7’Perfed 9/22/23 -squeezed ST-A3 5,544’5,551’5,054’5,060’7 Perfed 9/9/22 – Isolated ST-B1U 5,671'5,678'5,165'5,172'7 Perfed 2/4/21 – Isolated Sterling/ Beluga 5,977’5,987’5,434'5,443'5 spf 4-5/8” TCP (11/2/11) 73-4 Sd 7,768'7,796'7,019'7,044'6 spf 2” HC, 60 deg phase (6/29/12) Iso 7,954’7,974’7,186'7,204'6 spf 2” HC, 60 deg phase (6/28/12) Iso Tyonek 8,710’8,725’7,868'7,882'12 spf Perfed 1/26/93 Isolated 8,745’8,768’7,900'7,920'12 spf Perfed 1/26/93 Isolated 8,783’8,803’7,934'7,952'12 spf Perfed 1/26/93 Isolated 8,815’8,875’7,963'8,017'12 spf Perfed 1/26/93 Isolated STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. H i l c o r p A l a s k a , L L C Hi l c o r p A l a s k a , L L C Ch a n g e s t o A p p r o v e d R i g W o r k O v e r S u n d r y P r o c e d u r e Su b j e c t : C h a n g e s t o A p p r o v e d S u n d r y P r o c e d u r e f o r W e l l I R U 4 1 - 0 1 ( P T D 1 9 2 - 1 0 9 ) Su n d r y # : X X X - X X X An y m o d i f i c a t i o n s t o a n a p p r o v e d s u n d r y w i l l b e d o c u m e n t e d a n d a p p r o v e d b e l o w . C h a n g e s t o a n a p p r o v e d s u n d r y w i l l b e c o m m u n i c a te d t o t h e AO G C C by t h e r i g w o r k o v e r ( R W O ) “ f i r s t c a l l ” e n g i n e e r . A O G C C w r i t t e n a p p r o v a l o f t h e c h a n g e i s r e q u i r e d b e f o r e i m p l e m e n t i n g t h e c h a n g e . Se c Pa g e Da t e Pr o c e d u r e C h a n g e Ne w 4 0 3 Re q u i r e d ? Y / N HA K Pr e p a r e d By (I n i t i a l s ) HA K Ap p r o v e d By (I n i t i a l s ) AO G C C W r i t t e n Ap p r o v a l R e c e i v e d (P e r s o n a n d D a t e ) Ap p r o v a l : A s s e t T e a m O p e r a t i o n s M a n a g e r D a t e Pr e p a r e d : F i r s t C a l l O p e r a t i o n s E n g i n e e r D a t e Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 10/25/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20231025 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BRU 241-23 50283201910000 223061 9/27/2023 AK E-LINE CBL BRU 241-23 50283201910000 223061 10/4/2023 AK E-LINE GPT/Plug/Perf GP ST 18742 37 50733203940000 187109 9/30/2023 AK E-LINE Plug IRU 41-01 50283200880000 192109 9/22/2023 AK E-LINE Perf/GPT LRU C-02 50283201900000 223057 9/28/2023 AK E-LINE Perf LRU C-02 50283201900000 223057 9/25/2023 AK E-LINE Perf/GPT MPU K-13 50029226550000 196040 10/1/2023 AK E-LINE GPT/Plug/Perf NCI A-05 50883200250000 169032 9/27/2023 AK E-LINE Perf Please include current contact information if different from above. T38097 T38097 T38098 T38099 T38100 T38100 T38101 T38102 10/25/2023 IRU 41-01 50283200880000 192109 9/22/2023 AK E-LINE Perf/GPT Kayla Junke Digitally signed by Kayla Junke Date: 2023.10.25 11:33:48 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 10/04/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20231004 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# IRU 41-01 50283200880000 192109 9/17/2023 HALLIBURTON Coilflag KBU 32-06 50133206580000 216137 9/8/2023 HALLIBURTON PPROF LRU C-02 50283201900000 223057 9/13/2023 HALLIBURTON RBT MPU E-37 50029236160000 218158 9/24/2023 READ Caliper Survey MPU F-53A 50029225780100 213136 9/27/2023 READ Caliper Survey MPU F-79 50029228130000 197180 9/26/2023 READ Caliper Survey MPU L-57 50029236090000 218072 9/26/2023 READ Caliper Survey MPU S-06 50029231630000 203109 9/29/2023 READ Caliper Survey MPU B-32 50029235700000 216151 9/12/2023 HALLIBURTON Perf TBU K-09 50733201100000 1068038 10/1/2023 READ Caliper Survey Please include current contact information if different from above. T38028 T38029 T38030 T38031 T38032 T38033 T38034 T38035 T38036 T38037 10/4/2023 IRU 41-01 50283200880000 192109 9/17/2023 HALLIBURTON Coilflag Kayla Junke Digitally signed by Kayla Junke Date: 2023.10.04 13:03:04 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 09/12/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230912 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 18RD 50133205840100 222033 9/6/2023 YELLOW JACKET GPT-PERF BCU 18RD 50133205840100 222033 8/24/2023 YELLOW JACKET PLUG BCU 18RD 50133205840100 222033 8/28/2023 YELLOW JACKET PLUG-PERF BCU 18RD 50133205840100 222033 9/9/2023 YELLOW JACKET PLU-GPT-PERF BCU 18RD 50133205840100 222033 9/4/2023 YELLOW JACKET SCBL BRU 211-35 50283201890000 223050 7/31/2023 AK E-LINE CBL BRU 211-35 50283201890000 223050 8/19/2023 AK E-LINE GPT/Plug/Perf BRU 211-35 50283201890000 223050 8/10/2023 AK E-LINE Perf BRU 212-26 50283201820000 220058 8/20/2023 AK E-LINE GPT IRU 11-06 50283201300000 208184 8/1/2023 AK E-LINE Perf IRU 41-01 50283200880000 192109 9/3/2023 AK E-LINE GPT/Perf KTU 43-6XRD2 50133203280200 205117 9/4/2023 YELLOW JACKET CALIPER KU 42-12 50133206890000 220045 8/31/2023 YELLOW JACKET GPT-PERF KU 42-12 50133206890000 220045 8/20/2023 YELLOW JACKET SCBL MPU E-23 50029225700000 195094 8/18/2023 YELLOW JACKET CBL-PLUG MPU E-23 50029225700000 195094 8/20/2023 YELLOW JACKET PERF Paxton 12 50133207100000 223014 8/20/2023 AK E-LINE GPT/Perf Paxton 12 50133207100000 223014 8/14/2023 AK E-LINE Patch/Perf PBU L-240 50029237030000 221086 8/30/2023 READ IPROF Please include current contact information if different from above. T37983 T37983 T37983 T37983 T37983 T37984 T37984 T37984 T37985 T37986 T37987 T37988 T37989 T37989 T37990 T37990 T37991 T37991 T37992 9/13/2023 IRU 41-01 50283200880000 192109 9/3/2023 AK E-LINE GPT/Perf Kayla Junke Digitally signed by Kayla Junke Date: 2023.09.13 10:28:30 -08'00' 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: CTCO, Cmt Sqz, N2 2.Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6.API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 9,170'8,530' Casing Collapse Structural Conductor Surface 1,950psi Intermediate 4,750psi Production 7,020psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng jake.flora@hilcorp.com 907-777-8442 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Jake Flora, Operations Engineer AOGCC USE ONLY Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0032930 192-109 50-283-20088-00-00 Hilcorp Alaska, LLC Proposed Pools: 6.4# / L-80 & 2.75# / J-55 TVD Burst 5,955 & 2,994 8,160psi 894' Size 165' 9-5/8"3,498' 895' MD See Attached Schematic 6,870psi 3,450psi 165' 3,335' 165' 895' September 8, 2023 2-7/8" & 1-1/2" 9,152' Perforation Depth MD (ft): 3,498' 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Ivan River Unit (IRU) 41-01CO 301 Same 8,266'7" ~2449psi 9,152' 8,597' Length Baker Premier Pkr & N/A 5,374 (MD) 4,902 (TVD) & N/A 8,283'8,328'7,523' Ivan River Undefined Gas Pool 20" 13-3/8" See Attached Schematic m n P s 66 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 9:48 am, Sep 07, 2023 323-506 Digitally signed by Aras Worthington (4643) DN: cn=Aras Worthington (4643) Date: 2023.09.07 09:33:36 -08'00' Aras Worthington (4643) 10-404 CT BOP test to 3000 psi BJM 9/11/23 X DSR-9/11/23MDG 9/7/2023 *&:JLC 9/12/2023 09/12/23 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.09.12 16:04:37 -05'00' RBDMS JBS 091223 Well Prognosis Well Name: IRU 41-01 API Number: 50-283-20088-00 Regulatory Contact: Donna Ambruz Permit to Drill Number: 192-109 First Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (M) Second Call Engineer: Chad Helgeson (907) 777-8420 (O) (907) 229-4824 (M) Maximum Expected BHP: ~ 3169 psi @ 7204’ TVD (0.44 psi/ft gradient to bottom new perf) Max. Potential Surface Pressure: ~ 2449 psi (Max expected BHP minus gas to surface) Well Status: SI Gas Producer Last well test: 2000 mcfd @ 820 psi, 45 bwpd (7/11/23) Brief Well Summary IRU 41-01 is a Sterling & Beluga gas producer that sanded off and was brought back online by perforating the Sterling B1 in 2021, and then again by adding the A3 sands in 2022. The well was recently cleanout out to below the open sterling perforations, but was unable to unload or be brought back online. The objective of this sundry is to clean the well out , squeeze off the open perfs, and recomplete uphole in the A1 and X2 sands per Sundry 323-451. History: 04/06/22 Drift and tag at 5656’ w 1.75” bailer, recover sand 07/18/23 Well plugged off and died 07/22/23 Bailed hard packed clay (4) days from 5053’ – 5111’ (top open perfs: 5544-5551’) 08/05/23 Performed coil cleanout to 5800’, lifted w N2, could not get well online or unloaded 09/03/23 RU E-line, could not pass 5404’ (not deep enough to add perfs) Procedure: 1. Review approved COAs 2. Provide AOGCC 48hrs notice 3. MIRU coil tubing, BOP test to 3000 psi 4. Clean out to 5900’ with water 5. Log with memory tools, flag pipe 6. Set 2-7/8 cement retainer just over open perfs (top perf at 5544’, set retainer at ~5534’) 7. Establish injection into open perfs, determine cement job volume based on injection results 8. Mix and pump cement below retainer 9. Unsting, circulate clean from retainer depth 10. TOOH, WOC 11. Log CBL 12. RIH with nozzle, blow dry with N2, trap pressure 13. RDMO coil 14. Proceed with perforations per approved sundry 323-451 Attachments: 1. Actual Schematic 2. Proposed Schematic 3. CT BOP Diagram 4. Standard Nitrogen Procedure 5. AOGCC Rig Workover Change Form CBL is meant to look for cement possibly squeezed behind the tailpipe. _______________ __________________________________________________ Updated by JMF 09/06/23 SCHEMATIC Ivan River Unit IRU 41-01 Completion Ran 8/10/11 PTD: 192-109 API: 50-283-20088-00-00 TD =9,170’ PBTD = 8,597’ Sterling / Beluga RT-THF: 24’ KB 7” @ 9,152’55 ST B1U 13 17 18 20 16 19 11 3 4 5 RKB: 51’ AMSL 13-3/8” @ 895’ 9-5/8” @ 3,498’ 20” @ 165’ 1 12 6 7 10 2 Tyonek ST A3 Tagged fill @ 8,851’ (7/22/09) CBL Top: 5,000’ R RA Fill cleanout to 5800’ (8-4-23) Fill @ 5404’ (9-3-23) CASING DETAIL Size Type Wt/ Grade Top Btm CONN / ID Cement / Other 20” Conductor 94# Surface 165’ Driven 13-3/8” Surface 68#, K-55 Surface 895’ Butt / 12.415” 212 bbl / Cmt to Surface 9-5/8” Intermediate 47#, N-80 Surface 144’ Butt / 8.681”281 bbl / Cmt to Surface47#, S-95 144’ 3,498’ Butt / 8.681” 7” Production 29#, N-80 Surface 9,152’ Butt / 6.184” 171 bbl / Cmt to 5,000’ Tubing Detail 2-7/8” Production 6.4#, L-80 Surface 5,955’ IBT-Mod/2.441” 1-1/2” Heater 2.75#, J-55 Surface 2,994’ 10RD Fluid: Propelyne Glycol JEWELRY DETAIL No. Depth Length ID OD Item 1 24.20’ 0.55’ 2.441” 12.00”Dual Tubing Hanger, 2-7/8” x 2-3/8” 12” 5M National (2-7/8” & 2-3/8” 8RD lift threads) 2 5,327’ 4.03’ 2.310” 3.920” Sliding Sleeve, Halliburton XD 3 5,374’ 8.38’ 2.870” 5.980” Premier Packer 4 5,428’ 1.30’ 2.313” 3.220” Baker X Profile (2.313” Min ID) 5 5,595’ 1.41’ 2.257” 2.880” Mechanical-release 6 5,916’ 0.70’ 2.441” 3.958” Ported Sub 7 5,955’ 0.94’ 3.670” 4.950” WLEG 10 +/-8,530’ 32.77’ - - Dropped TCP Assembly 11 8,597’ 2.00’ - - Cement Retainer capped w/ 269’ cement (Est) 12 8,613’ - 2.441” 3.500” Cut tubing stub 13 8,629’ 4.78’ 3.250” 5.968” Baker 3H Packer w/ mill out extension (Min ID thru Anchor Latch Seal Assembly) 16 8,643’ 0.67’ 2.441” 3.500” Baker “RA” Sub 17 8,650’ 1.24’ 2.250” 3.500" Baker R Profile w/ No-go 18 8,659’ 0.63’ 2.441” 3.687” Baker Ported Sub w/ glass disc 19 8,693’ 0.82’ 2.441” 3.687” Tubing Tail 20 8,895’ (est) 183’ 3.687” FISH: Baker TCP Drop Off Guns PERFORATION DETAIL ZONE TOP (MD) BTM (MD) TOP (TVD) BTM (TVD) Shot Condition ST-A3 5,544’5,551’5,054’5,060’7 Perfed 9/9/22 -Open ST-B1U 5,671'5,678'5,165'5,172'7 Perfed 2/4/21 –Open Sterling/ Beluga 5,977’5,987’5,434'5,443'5 spf 4-5/8” TCP (11/2/11) 73-4 Sd 7,768'7,796'7,019'7,044'6 spf 2” HC, 60 deg phase (6/29/12) 7,954’7,974’7,186'7,204'6 spf 2” HC, 60 deg phase (6/28/12) Tyonek 8,710’8,725’7,868'7,882'12 spf Perfed 1/26/93 Isolated 8,745’8,768’7,900'7,920'12 spf Perfed 1/26/93 Isolated 8,783’8,803’7,934'7,952'12 spf Perfed 1/26/93 Isolated 8,815’8,875’7,963'8,017'12 spf Perfed 1/26/93 Isolated _______________ __________________________________________________ Updated by JMF 09/06/23 PROPOSED Ivan River Unit IRU 41-01 Completion Ran 8/10/11 PTD: 192-109 API: 50-283-20088-00-00 TD =9,170’ PBTD = 8,597’ Sterling / Beluga RT-THF: 24’ KB 7” @ 9,152’55 ST B1U 13 17 18 20 16 19 11 3 4 5 RKB: 51’ AMSL 13-3/8” @ 895’ 9-5/8” @ 3,498’ 20” @ 165’ 1 12 6 7 10 2 Tyonek ST A3 Cmt retainer @ ~5534’ Tagged fill @ 8,851’ (7/22/09) CBL Top: 5,000’ R RA Fill cleanout to 5800’ (8-4-23) CASING DETAIL Size Type Wt/ Grade Top Btm CONN / ID Cement / Other 20” Conductor 94# Surface 165’ Driven 13-3/8” Surface 68#, K-55 Surface 895’ Butt / 12.415” 212 bbl / Cmt to Surface 9-5/8” Intermediate 47#, N-80 Surface 144’ Butt / 8.681”281 bbl / Cmt to Surface47#, S-95 144’ 3,498’ Butt / 8.681” 7” Production 29#, N-80 Surface 9,152’ Butt / 6.184” 171 bbl / Cmt to 5,000’ Tubing Detail 2-7/8” Production 6.4#, L-80 Surface 5,955’ IBT-Mod/2.441” 1-1/2” Heater 2.75#, J-55 Surface 2,994’ 10RD Fluid: Propelyne Glycol JEWELRY DETAIL No. Depth Length ID OD Item 1 24.20’ 0.55’ 2.441” 12.00”Dual Tubing Hanger, 2-7/8” x 2-3/8” 12” 5M National (2-7/8” & 2-3/8” 8RD lift threads) 2 5,327’ 4.03’ 2.310” 3.920” Sliding Sleeve, Halliburton XD 3 5,374’ 8.38’ 2.870” 5.980” Premier Packer 4 5,428’ 1.30’ 2.313” 3.220” Baker X Profile (2.313” Min ID) 5 5,595’ 1.41’ 2.257” 2.880” Mechanical-release 6 5,916’ 0.70’ 2.441” 3.958” Ported Sub 7 5,955’ 0.94’ 3.670” 4.950” WLEG 10 +/-8,530’ 32.77’ - - Dropped TCP Assembly 11 8,597’ 2.00’ - - Cement Retainer capped w/ 269’ cement (Est) 12 8,613’ - 2.441” 3.500” Cut tubing stub 13 8,629’ 4.78’ 3.250” 5.968” Baker 3H Packer w/ mill out extension (Min ID thru Anchor Latch Seal Assembly) 16 8,643’ 0.67’ 2.441” 3.500” Baker “RA” Sub 17 8,650’ 1.24’ 2.250” 3.500" Baker R Profile w/ No-go 18 8,659’ 0.63’ 2.441” 3.687” Baker Ported Sub w/ glass disc 19 8,693’ 0.82’ 2.441” 3.687” Tubing Tail 20 8,895’ (est) 183’ 3.687” FISH: Baker TCP Drop Off Guns PERFORATION DETAIL ZONE TOP (MD) BTM (MD) TOP (TVD) BTM (TVD) Ft Condition Sterling X2 5,446’5,454 4,669’4,975’8’Planned Sterling A1 5,494’5,501’5,010’5,017’7’Planned ST-A3 5,544’5,551’5,054’5,060’7 Perfed 9/9/22 -Open ST-B1U 5,671'5,678'5,165'5,172'7 Perfed 2/4/21 –Open Sterling/ Beluga 5,977’5,987’5,434'5,443'5 spf 4-5/8” TCP (11/2/11) 73-4 Sd 7,768'7,796'7,019'7,044'6 spf 2” HC, 60 deg phase (6/29/12) 7,954’7,974’7,186'7,204'6 spf 2” HC, 60 deg phase (6/28/12) Tyonek 8,710’8,725’7,868'7,882'12 spf Perfed 1/26/93 Isolated 8,745’8,768’7,900'7,920'12 spf Perfed 1/26/93 Isolated 8,783’8,803’7,934'7,952'12 spf Perfed 1/26/93 Isolated 8,815’8,875’7,963'8,017'12 spf Perfed 1/26/93 Isolated STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. Hilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Subject: Changes to Approved Sundry Procedure for Well IRU 41-01 (PTD 192-109) Sundry #: XXX-XXX Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change. Sec Page Date Procedure Change New 403 Required? Y / N HAK Prepared By (Initials) HAK Approved By (Initials) AOGCC Written Approval Received (Person and Date) Approval: Asset Team Operations Manager Date Prepared: First Call Operations Engineer Date 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: N2 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 9,170'8,530' Casing Collapse Structural Conductor Surface 1,950psi Intermediate 4,750psi Production 7,020psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Baker Premier Pkr & N/A 5,374 (MD) 4,902 (TVD) & N/A 8,283'8,328'7,523' Ivan River Undefined Gas Pool 20" 13-3/8" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Ivan River Unit (IRU) 41-01CO 301 Same 8,266'7" ~2449psi 9,152' 8,597' Length August 22, 2023 2-7/8" & 1-1/2" 9,152' Perforation Depth MD (ft): 3,498' See Attached Schematic 6,870psi 3,450psi 165' 3,335' 165' 895' Size 165' 9-5/8"3,498' 895' MD Hilcorp Alaska, LLC Proposed Pools: 6.4# / L-80 & 2.75# / J-55 TVD Burst 5,955 & 2,994 8,160psi 894' Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0032930 192-109 50-283-20088-00-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Jake Flora, Operations Engineer AOGCC USE ONLY Tubing Grade: jake.flora@hilcorp.com 907-777-8442 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: m n P s 66 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 10:55 am, Aug 10, 2023 323-451 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2023.08.08 16:52:58 - 08'00' Noel Nocas (4361) 10-404 BJM 8/14/23 DSR-8/14/23SFD 8/14/2023GCW 08/09/2023JLC 8/15/2023 08/15/23 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.08.15 10:36:37 -08'00' RBDMS JSB 081723 Well Prognosis Well Name: IRU 41-01 API Number: 50-283-20088-00 Regulatory Contact: Donna Ambruz Permit to Drill Number: 192-109 First Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (M) Second Call Engineer: Chad Helgeson (907) 777-8420 (O) (907) 229-4824 (M) Maximum Expected BHP: ~ 3169 psi @ 7204’ TVD (0.44 psi/ft gradient to bottom open perf) Max. Potential Surface Pressure: ~ 2449 psi (Max expected BHP minus gas to surface) Well Status: SI Gas Producer Last well test: 2000 mcfd @ 820 psi, 45 bwpd (7/11/23) Brief Well Summary IRU 41-01 is a Sterling & Beluga gas producer that sanded off and was brought back online by perforating the Sterling B1 in 2021, and then again by adding the A3 sands in 2022. The well went offline in July of 2023. A recent effort was made to clean out the well with coil tubing and nitrogen which was unsuccessful in bringing the well back online. The objective of this sundry is to perforate the two remaining sands below the packer in effort to return the well to production. The sands are above the existing open perfs. History: 4/06/22 Drift and tag at 5656’ w 1.75” bailer, recover sand 7/18/23 Well plugged off and died 7/22/23 Bailed hard packed clay (4) days from 5053’ – 5111’ (top open perfs: 5544-5551’) 8/04/23 Coil cleaned out the well with water and nitrogen to 5800’, would not flow Procedure: 1. Review approved COAs 2. MIRU Eline, PT lubricator to 2750 psi. 3. Perforate the below sands from the bottom up: Sterling X2 5446 to 5454’ MD ( 4669’ – 4975’ TVD) Sterling A1 5494 to 5501’ MD ( 5010’ – 5017’ TVD) a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations. b. If necessary use nitrogen to pressure up well during perforating 4. Return to production Attachments: 1. Actual Schematic 2. Proposed Schematic 3. Nitrogen SOP _______________ __________________________________________________ Updated by JMF 08/07/23 SCHEMATIC Ivan River Unit IRU 41-01 Completion Ran 8/10/11 PTD: 192-109 API: 50-283-20088-00-00 TD =9,170’ PBTD = 8,597’ Sterling / Beluga RT-THF: 24’ KB 7” @ 9,152’55 ST B1U 13 17 18 20 16 19 11 3 4 5 RKB: 51’ AMSL 13-3/8” @ 895’ 9-5/8” @ 3,498’ 20” @ 165’ 1 12 6 7 10 2 Tyonek ST A3 Tagged fill @ 8,851’ (7/22/09) CBL Top: 5,000’ R RA Fill cleanout to 5800’ (8-4-23) CASING DETAIL Size Type Wt/ Grade Top Btm CONN / ID Cement / Other 20” Conductor 94# Surface 165’ Driven 13-3/8” Surface 68#, K-55 Surface 895’ Butt / 12.415” 212 bbl / Cmt to Surface 9-5/8” Intermediate 47#, N-80 Surface 144’ Butt / 8.681”281 bbl / Cmt to Surface47#, S-95 144’ 3,498’ Butt / 8.681” 7” Production 29#, N-80 Surface 9,152’ Butt / 6.184” 171 bbl / Cmt to 5,000’ Tubing Detail 2-7/8” Production 6.4#, L-80 Surface 5,955’ IBT-Mod/2.441” 1-1/2” Heater 2.75#, J-55 Surface 2,994’ 10RD Fluid: Propelyne Glycol JEWELRY DETAIL No. Depth Length ID OD Item 1 24.20’ 0.55’ 2.441” 12.00”Dual Tubing Hanger, 2-7/8” x 2-3/8” 12” 5M National (2-7/8” & 2-3/8” 8RD lift threads) 2 5,327’ 4.03’ 2.310” 3.920” Sliding Sleeve, Halliburton XD 3 5,374’ 8.38’ 2.870” 5.980” Premier Packer 4 5,428’ 1.30’ 2.313” 3.220” Baker X Profile (2.313” Min ID) 5 5,595’ 1.41’ 2.257” 2.880” Mechanical-release 6 5,916’ 0.70’ 2.441” 3.958” Ported Sub 7 5,955’ 0.94’ 3.670” 4.950” WLEG 10 +/-8,530’ 32.77’ - - Dropped TCP Assembly 11 8,597’ 2.00’ - - Cement Retainer capped w/ 269’ cement (Est) 12 8,613’ - 2.441” 3.500” Cut tubing stub 13 8,629’ 4.78’ 3.250” 5.968” Baker 3H Packer w/ mill out extension (Min ID thru Anchor Latch Seal Assembly) 16 8,643’ 0.67’ 2.441” 3.500” Baker “RA” Sub 17 8,650’ 1.24’ 2.250” 3.500" Baker R Profile w/ No-go 18 8,659’ 0.63’ 2.441” 3.687” Baker Ported Sub w/ glass disc 19 8,693’ 0.82’ 2.441” 3.687” Tubing Tail 20 8,895’ (est) 183’ 3.687” FISH: Baker TCP Drop Off Guns PERFORATION DETAIL ZONE TOP (MD) BTM (MD) TOP (TVD) BTM (TVD) Shot Condition ST-A3 5,544’5,551’5,054’5,060’7 Perfed 9/9/22 -Open ST-B1U 5,671'5,678'5,165'5,172'7 Perfed 2/4/21 –Open Sterling/ Beluga 5,977’5,987’5,434'5,443'5 spf 4-5/8” TCP (11/2/11) 73-4 Sd 7,768'7,796'7,019'7,044'6 spf 2” HC, 60 deg phase (6/29/12) 7,954’7,974’7,186'7,204'6 spf 2” HC, 60 deg phase (6/28/12) Tyonek 8,710’8,725’7,868'7,882'12 spf Perfed 1/26/93 Isolated 8,745’8,768’7,900'7,920'12 spf Perfed 1/26/93 Isolated 8,783’8,803’7,934'7,952'12 spf Perfed 1/26/93 Isolated 8,815’8,875’7,963'8,017'12 spf Perfed 1/26/93 Isolated _______________ __________________________________________________ Updated by JMF 08/07/23 PROPOSED Ivan River Unit IRU 41-01 Completion Ran 8/10/11 PTD: 192-109 API: 50-283-20088-00-00 TD =9,170’ PBTD = 8,597’ Sterling / Beluga RT-THF: 24’ KB 7” @ 9,152’ ST B1U 13 17 18 20 16 19 11 3 4 5 RKB: 51’ AMSL 13-3/8” @ 895’ 9-5/8” @ 3,498’ 20” @ 165’ 1 12 6 7 10 2 Tyonek ST A3 Tagged fill @ 8,851’(7/22/09) CBL Top:5,000’ R RA Fill cleanout to 5800’(8-4-23) CASING DETAIL Size Type Wt/ Grade Top Btm CONN / ID Cement / Other 20”Conductor 94#Surface 165’Driven 13-3/8”Surface 68#, K-55 Surface 895’Butt / 12.415”212 bbl / Cmt to Surface 9-5/8”Intermediate 47#, N-80 Surface 144’Butt / 8.681”281 bbl / Cmt to Surface47#, S-95 144’3,498’Butt / 8.681” 7”Production 29#, N-80 Surface 9,152’Butt / 6.184”171 bbl / Cmt to 5,000’ Tubing Detail 2-7/8”Production 6.4#, L-80 Surface 5,955’IBT-Mod/2.441” 1-1/2”Heater 2.75#, J-55 Surface 2,994’10RD Fluid: Propelyne Glycol JEWELRY DETAIL No.Depth Length ID OD Item 1 24.20’ 0.55’2.441”12.00”Dual Tubing Hanger, 2-7/8” x 2-3/8” 12” 5M National (2-7/8” & 2-3/8” 8RD lift threads) 2 5,327’4.03’2.310”3.920”Sliding Sleeve, Halliburton XD 3 5,374’8.38’2.870”5.980”Premier Packer 4 5,428’1.30’2.313”3.220”Baker X Profile (2.313” Min ID) 5 5,595’1.41’2.257”2.880”Mechanical-release 6 5,916’0.70’2.441”3.958”Ported Sub 7 5,955’0.94’3.670”4.950”WLEG 10 +/-8,530’32.77’--Dropped TCP Assembly 11 8,597’2.00’--Cement Retainer capped w/ 269’ cement (Est) 12 8,613’-2.441”3.500”Cut tubing stub 13 8,629’ 4.78’3.250”5.968”Baker 3H Packer w/ mill out extension (Min ID thru Anchor Latch Seal Assembly) 16 8,643’0.67’2.441”3.500”Baker “RA” Sub 17 8,650’1.24’2.250”3.500"Baker R Profile w/ No-go 18 8,659’0.63’2.441”3.687”Baker Ported Sub w/ glass disc 19 8,693’0.82’2.441”3.687”Tubing Tail 20 8,895’ (est)183’3.687”FISH: Baker TCP Drop Off Guns PERFORATION DETAIL ZONE TOP (MD) BTM (MD)TOP (TVD)BTM (TVD)Ft Condition Sterling X2 5,446’5,454 4,669’4,975’8’Planned Sterling A1 5,494’5,501’5,010’5,017’7’Planned ST-A3 5,544’5,551’5,054’5,060’7 Perfed 9/9/22 - Open ST-B1U 5,671'5,678'5,165'5,172'7 Perfed 2/4/21 – Open Sterling/ Beluga 5,977’5,987’5,434'5,443'5 spf 4-5/8” TCP (11/2/11) 73-4 Sd 7,768'7,796'7,019'7,044'6 spf 2” HC, 60 deg phase (6/29/12) 7,954’7,974’7,186'7,204'6 spf 2” HC, 60 deg phase (6/28/12) Tyonek 8,710’8,725’7,868'7,882'12 spf Perfed 1/26/93 Isolated 8,745’8,768’7,900'7,920'12 spf Perfed 1/26/93 Isolated 8,783’8,803’7,934'7,952'12 spf Perfed 1/26/93 Isolated 8,815’8,875’7,963'8,017'12 spf Perfed 1/26/93 Isolated STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: CTCO, N2 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 9,170'8,530' Casing Collapse Structural Conductor Surface 1,950psi Intermediate 4,750psi Production 7,020psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Baker Premier Pkr & N/A 5,374 (MD) 4,902 (TVD) & N/A 8,283'8,328'7,523' Ivan River Undefined Gas Pool 20" 13-3/8" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Ivan River Unit (IRU) 41-01CO 301 Same 8,266'7" ~2449psi 9,152' 8,597' Length August 9, 2023 2-7/8" & 1-1/2" 9,152' Perforation Depth MD (ft): 3,498' See Attached Schematic 6,870psi 3,450psi 165' 3,335' 165' 895' Size 165' 9-5/8"3,498' 895' MD Hilcorp Alaska, LLC Proposed Pools: 6.4# / L-80 & 2.75# / J-55 TVD Burst 5,955 & 2,994 8,160psi 894' Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0032930 192-109 50-283-20088-00-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Jake Flora, Operations Engineer AOGCC USE ONLY Tubing Grade: jake.flora@hilcorp.com 907-777-8442 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: m n P s 66 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 12:50 pm, Jul 31, 2023 323-433 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2023.07.31 11:45:59 - 08'00' Noel Nocas (4361) 10-404 MGR02AUG23 BOPE test to 3000 psi. MDG 7/31/2023 DSR-7/31/23 ~2449psi GCW 08/02/2023 JLC 8/2/2023 08/02/23 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.08.02 16:03:10 -08'00' RBDMS 080323 JSB Well Prognosis Well Name: IRU 41-01 API Number: 50-283-20088-00 Regulatory Contact: Donna Ambruz Permit to Drill Number: 192-109 First Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (M) Second Call Engineer: Chad Helgeson (907) 777-8420 (O) (907) 229-4824 (M) Maximum Expected BHP: ~ 3169 psi @ 7204’ TVD (0.44 psi/ft gradient to bottom new perf) Max. Potential Surface Pressure: ~ 2449 psi (Max expected BHP minus gas to surface) Well Status: SI Gas Producer Last well test: 2000 mcfd @ 820 psi, 45 bwpd (7/11/23) Brief Well Summary IRU 41-01 is a Sterling & Beluga gas producer that sanded off and was brought back online by perforating the Sterling B1 in 2021, and then again by adding the A3 sands in 2022. The well is currently unable to flow due to 400’ of mud fill covering the uppermost perforations. The objective of this sundry is to clean the well out and bring it back online. Historically there have been bridges in the wellbore and it will be a wellsite decision as to the max depth of the cleanout effort with the main goal of clearing the Sterling A3 & B1 perforations for production. History: 4/06/22 Drift and tag at 5656’ w 1.75” bailer, recover sand 7/18/23 Well plugged off and died 7/22/23 Bailed hard packed clay (4) days from 5053’ – 5111’ (top open perfs: 5544-5551’) Procedure: 1. Review approved COAs 2. Provide 48hrs notice to AOGCC of BOP test 3. MIRU Coiled Tubing, PT BOPE to 3000 psi Hi 250 Low 4. Route returns to open top diffuser tank 5. RIH w/ 1.75” coil w/ jet nozzle BHA, using water clean out wellbore to a minimum of 5700’ (below Sterling B1) 6. Open circ port, pump nitrogen to unload wellbore 7. Return to production Attachments: 1. Actual Schematic 2. Proposed Schematic 3. CT BOP Diagram 4. Standard Nitrogen Procedure 5. AOGCC Rig Workover Change Form _______________ __________________________________________________ Updated by JMF 12/05/22 SCHEMATIC Ivan River Unit IRU 41-01 Completion Ran 8/10/11 PTD: 192-109 API: 50-283-20088-00-00 TD =9,170’ PBTD = 8,597’ Sterling / Beluga RT-THF: 24’ KB 7” @ 9,152’55 ST B1U 13 17 18 20 16 19 11 3 4 5 RKB: 51’ AMSL 13-3/8” @ 895’ 9-5/8” @ 3,498’ 20” @ 165’ 1 12 6 7 10 2 Tyonek ST A3 Tagged fill @ 8,851’ (7/22/09) CBL Top: 5,000’ R RA Tagged fill @ 8,129’ (6/27/12) Tagged fill w/ 1.75” Bailer @ 7,796’ (6/06/14) Fill Top 5053’ 7/22/23 CASING DETAIL Size Type Wt/ Grade Top Btm CONN / ID Cement / Other 20” Conductor 94# Surface 165’ Driven 13-3/8” Surface 68#, K-55 Surface 895’ Butt / 12.415” 212 bbl / Cmt to Surface 9-5/8” Intermediate 47#, N-80 Surface 144’ Butt / 8.681”281 bbl / Cmt to Surface47#, S-95 144’ 3,498’ Butt / 8.681” 7” Production 29#, N-80 Surface 9,152’ Butt / 6.184” 171 bbl / Cmt to 5,000’ Tubing Detail 2-7/8” Production 6.4#, L-80 Surface 5,955’ IBT-Mod/2.441” 1-1/2” Heater 2.75#, J-55 Surface 2,994’ 10RD Fluid: Propelyne Glycol JEWELRY DETAIL No. Depth Length ID OD Item 1 24.20’ 0.55’ 2.441” 12.00”Dual Tubing Hanger, 2-7/8” x 2-3/8” 12” 5M National (2-7/8” & 2-3/8” 8RD lift threads) 2 5,327’ 4.03’ 2.310” 3.920” Sliding Sleeve, Halliburton XD 3 5,374’ 8.38’ 2.870” 5.980” Premier Packer 4 5,428’ 1.30’ 2.313” 3.220” Baker X Profile (2.313” Min ID) 5 5,595’ 1.41’ 2.257” 2.880” Mechanical-release 6 5,916’ 0.70’ 2.441” 3.958” Ported Sub 7 5,955’ 0.94’ 3.670” 4.950” WLEG 10 +/-8,530’ 32.77’ - - Dropped TCP Assembly 11 8,597’ 2.00’ - - Cement Retainer capped w/ 269’ cement (Est) 12 8,613’ - 2.441” 3.500” Cut tubing stub 13 8,629’ 4.78’ 3.250” 5.968” Baker 3H Packer w/ mill out extension (Min ID thru Anchor Latch Seal Assembly) 16 8,643’ 0.67’ 2.441” 3.500” Baker “RA” Sub 17 8,650’ 1.24’ 2.250” 3.500" Baker R Profile w/ No-go 18 8,659’ 0.63’ 2.441” 3.687” Baker Ported Sub w/ glass disc 19 8,693’ 0.82’ 2.441” 3.687” Tubing Tail 20 8,895’ (est) 183’ 3.687” FISH: Baker TCP Drop Off Guns PERFORATION DETAIL ZONE TOP (MD) BTM (MD) TOP (TVD) BTM (TVD) Shot Condition ST-A3 5,544’5,551’5,054’5,060’7 Perfed 9/9/22 -Open ST-B1U 5,671'5,678'5,165'5,172'7 Perfed 2/4/21 –Open Sterling/ Beluga 5,977’5,987’5,434'5,443'5 spf 4-5/8” TCP (11/2/11) 73-4 Sd 7,768'7,796'7,019'7,044'6 spf 2” HC, 60 deg phase (6/29/12) 7,954’7,974’7,186'7,204'6 spf 2” HC, 60 deg phase (6/28/12) Tyonek 8,710’8,725’7,868'7,882'12 spf Perfed 1/26/93 Isolated 8,745’8,768’7,900'7,920'12 spf Perfed 1/26/93 Isolated 8,783’8,803’7,934'7,952'12 spf Perfed 1/26/93 Isolated 8,815’8,875’7,963'8,017'12 spf Perfed 1/26/93 Isolated _______________ __________________________________________________ Updated by JMF 12/05/22 PROPOSED Ivan River Unit IRU 41-01 Completion Ran 8/10/11 PTD: 192-109 API: 50-283-20088-00-00 TD =9,170’ PBTD = 8,597’ Sterling / Beluga RT-THF: 24’ KB 7” @ 9,152’55 ST B1U 13 17 18 20 16 19 11 3 4 5 RKB: 51’ AMSL 13-3/8” @ 895’ 9-5/8” @ 3,498’ 20” @ 165’ 1 12 6 7 10 2 Tyonek ST A3 Tagged fill @ 8,851’ (7/22/09) CBL Top: 5,000’ R RA Tagged fill @ 8,129’ (6/27/12) Tagged fill w/ 1.75” Bailer @ 7,796’ (6/06/14) CASING DETAIL Size Type Wt/ Grade Top Btm CONN / ID Cement / Other 20” Conductor 94# Surface 165’ Driven 13-3/8” Surface 68#, K-55 Surface 895’ Butt / 12.415” 212 bbl / Cmt to Surface 9-5/8” Intermediate 47#, N-80 Surface 144’ Butt / 8.681”281 bbl / Cmt to Surface47#, S-95 144’ 3,498’ Butt / 8.681” 7” Production 29#, N-80 Surface 9,152’ Butt / 6.184” 171 bbl / Cmt to 5,000’ Tubing Detail 2-7/8” Production 6.4#, L-80 Surface 5,955’ IBT-Mod/2.441” 1-1/2” Heater 2.75#, J-55 Surface 2,994’ 10RD Fluid: Propelyne Glycol JEWELRY DETAIL No. Depth Length ID OD Item 1 24.20’ 0.55’ 2.441” 12.00”Dual Tubing Hanger, 2-7/8” x 2-3/8” 12” 5M National (2-7/8” & 2-3/8” 8RD lift threads) 2 5,327’ 4.03’ 2.310” 3.920” Sliding Sleeve, Halliburton XD 3 5,374’ 8.38’ 2.870” 5.980” Premier Packer 4 5,428’ 1.30’ 2.313” 3.220” Baker X Profile (2.313” Min ID) 5 5,595’ 1.41’ 2.257” 2.880” Mechanical-release 6 5,916’ 0.70’ 2.441” 3.958” Ported Sub 7 5,955’ 0.94’ 3.670” 4.950” WLEG 10 +/-8,530’ 32.77’ - - Dropped TCP Assembly 11 8,597’ 2.00’ - - Cement Retainer capped w/ 269’ cement (Est) 12 8,613’ - 2.441” 3.500” Cut tubing stub 13 8,629’ 4.78’ 3.250” 5.968” Baker 3H Packer w/ mill out extension (Min ID thru Anchor Latch Seal Assembly) 16 8,643’ 0.67’ 2.441” 3.500” Baker “RA” Sub 17 8,650’ 1.24’ 2.250” 3.500" Baker R Profile w/ No-go 18 8,659’ 0.63’ 2.441” 3.687” Baker Ported Sub w/ glass disc 19 8,693’ 0.82’ 2.441” 3.687” Tubing Tail 20 8,895’ (est) 183’ 3.687” FISH: Baker TCP Drop Off Guns PERFORATION DETAIL ZONE TOP (MD) BTM (MD) TOP (TVD) BTM (TVD) Shot Condition ST-A3 5,544’5,551’5,054’5,060’7 Perfed 9/9/22 -Open ST-B1U 5,671'5,678'5,165'5,172'7 Perfed 2/4/21 –Open Sterling/ Beluga 5,977’5,987’5,434'5,443'5 spf 4-5/8” TCP (11/2/11) 73-4 Sd 7,768'7,796'7,019'7,044'6 spf 2” HC, 60 deg phase (6/29/12) 7,954’7,974’7,186'7,204'6 spf 2” HC, 60 deg phase (6/28/12) Tyonek 8,710’8,725’7,868'7,882'12 spf Perfed 1/26/93 Isolated 8,745’8,768’7,900'7,920'12 spf Perfed 1/26/93 Isolated 8,783’8,803’7,934'7,952'12 spf Perfed 1/26/93 Isolated 8,815’8,875’7,963'8,017'12 spf Perfed 1/26/93 Isolated STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. Hilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Subject: Changes to Approved Sundry Procedure for Well IRU 41-01 (PTD 192-109) Sundry #: XXX-XXX Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change. Sec Page Date Procedure Change New 403 Required? Y / N HAK Prepared By (Initials) HAK Approved By (Initials) AOGCC Written Approval Received (Person and Date) Approval: Asset Team Operations Manager Date Prepared: First Call Operations Engineer Date Kyle Wiseman Hilcorp Alaska, LLC Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: Kyle.Wiseman@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 11/8/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20221108 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# IRU 241-01 502832018400 221076 8/14/2022 AK E-Line GPT/Plug/Perf IRU 241-01 502832018400 221076 8/31/2022 AK E-Line GPT/Plug/Perf IRU 41-01 502832008800 192109 9/9/2022 AK E-Line GR/Perf IRU 241-01 502832018400 221076 8/25/2022 AK E-Line Perf IRU 241-01 502832018400 221076 8/22/2022 AK E-Line Plug/GR MPU S-34 500292317100 203130 9/4/2022 AK E-Line Cut Tubing NCI A-09A 508832002901 222024 8/20/2022 AK E-Line Perf NCI A-10B 508832003002 222025 8/23/2022 AK E-Line Perf Please include current contact information if different from above. 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^dͲϭ>цϱ͕ϲϴϴ͛ цϱ͕ϲϵϰ͛ цϱ͕ϭϴϭ͛ цϱ͕ϭϴϲ͛ ϲ͛ ^dͲϮƵ цϱ͕ϳϬϴ͛ цϱ͕ϳϭϳ͛ цϱ͕ϭϵϴ͛ цϱ͕ϮϬϲ͛ ϵ͛ ^dͲϮ>цϱ͕ϳϮϱ͛ цϱ͕ϳϯϮ͛ цϱ͕Ϯϭϯ͛ цϱ͕Ϯϭϵ͛ ϳ͛ ΎZĞĚĚĞŶŽƚĞƐƚŚĞƐĞƉĞƌĨŽƌĂƚŝŽŶŝŶƚĞƌǀĂůƐĂƌĞĐƵƌƌĞŶƚůǇĐŽǀĞƌĞĚďǇĨŝůů Ă͘ /ĨŶĞĐĞƐƐĂƌǇƉƌĞƐƐƵƌĞƵƉǁĞůůǁŝƚŚEŝƚƌŽŐĞŶƉƌŝŽƌƚŽƉĞƌĨŽƌĂƚŝŶŐ ď͘ ůůƐĂŶĚƐůŝĞŝŶƚŚĞ/sEZ/sZhE&/E'^WKK> ϰ͘ ZĞƚƵƌŶƚŽƉƌŽĚƵĐƚŝŽŶ ůůƐĂŶĚƐůŝĞŝŶƚŚĞ/sEZ/sZhE&/E'^WKK> tĞůůWƌŽŐŶŽƐŝƐ ŽŝůůĞĂŶŽƵƚŽŶƚŝŶŐĞŶĐǇ;/ĨĨŝůůŝƐĨŽƵŶĚĂďŽǀĞƉĞƌĨŝŶƚĞƌǀĂůͿ ϭ͘ D/ZhŽŝůĞĚdƵďŝŶŐ͕WdKWƚŽϯ͕ϱϬϬƉƐŝ,ŝϮϱϬ>Žǁ͘EŽƚŝĨǇK'ϰϴŚƌƐ͘ŝŶĂĚǀĂŶĐĞŽĨKWƚĞƐƚ͘ Ϯ͘ Z/,͕ĐůĞĂŶŽƵƚƚƵďŝŶŐ ϯ͘ ƚWdĐŽŵĞŽŶůŝŶĞǁŝƚŚEϮĂŶĚũĞƚǁĞůůĚƌǇ͘ ϰ͘ KŶĐĞǁĞůůŝƐĚƌǇ͕ůĞĂǀĞΕϮϬϬϬƉƐŝ͘ŽŶƚŚĞǁĞůůĨŽƌĨŝƌƐƚƉĞƌĨŽƌĂƚŝŽŶŝŶƚĞƌǀĂů͘ ϱ͘ WKK,ǁͬĐŽŝů͘>,͘ ϲ͘ ZDKŽŝůĞĚdƵďŝŶŐ͘ ƚƚĂĐŚŵĞŶƚƐ͗ ϭ͘ ĐƚƵĂů^ĐŚĞŵĂƚŝĐ Ϯ͘ WƌŽƉŽƐĞĚ^ĐŚĞŵĂƚŝĐ ϯ͘ dKWŝĂŐƌĂŵ ϰ͘ ^ƚĂŶĚĂƌĚEŝƚƌŽŐĞŶWƌŽĐĞĚƵƌĞ ϱ͘ K'ZŝŐtŽƌŬŽǀĞƌŚĂŶŐĞ&Žƌŵ BBBBBBBBBBBBBBB BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB hƉĚĂƚĞĚďǇ:D&ϬϴͲϭϵͲϮϮ ^,Dd/ /ǀĂŶZŝǀĞƌhŶŝƚ /ZhϰϭͲϬϭ ŽŵƉůĞƚŝŽŶZĂŶϴͬϭϬͬϭϭ Wd͗ϭϵϮͲϭϬϵ W/͗ ϱϬͲϮϴϯͲϮϬϬϴϴͲϬϬͲϬϬ 7' ¶3%7' ¶ 577+)¶.% ´#¶ 5.%¶ $06/ ´ #¶ ´# ¶ ´# ¶ 7\RQHN 7DJJHGILOO# ¶ &%/7RS¶ 5 5$ 7DJJHGILOO# ¶ 7DJJHGILOOZ´ %DLOHU #¶ 7DJJHG)LOO #¶ ^/E'd/> ^ŝǌĞ dǇƉĞ tƚͬ'ƌĂĚĞ dŽƉ ƚŵ KEEͬ/ ĞŵĞŶƚͬKƚŚĞƌ ϮϬ͟ ŽŶĚƵĐƚŽƌ ϵϰη ^ƵƌĨĂĐĞ ϭϲϱ͛ ƌŝǀĞŶ ϭϯͲϯͬϴ͟ ^ƵƌĨĂĐĞ ϲϴη͕<Ͳϱϱ ^ƵƌĨĂĐĞ ϴϵϱ͛ ƵƚƚͬϭϮ͘ϰϭϱ͟ ϮϭϮďďůͬŵƚƚŽ^ƵƌĨĂĐĞ ϵͲϱͬϴ͟ /ŶƚĞƌŵĞĚŝĂƚĞ ϰϳη͕EͲϴϬ ^ƵƌĨĂĐĞ ϭϰϰ͛ Ƶƚƚͬϴ͘ϲϴϭ͟ϮϴϭďďůͬŵƚƚŽ^ƵƌĨĂĐĞ ϰϳη͕^Ͳϵϱ ϭϰϰ͛ ϯ͕ϰϵϴ͛ Ƶƚƚͬϴ͘ϲϴϭ͟ ϳ͟ WƌŽĚƵĐƚŝŽŶ Ϯϵη͕EͲϴϬ ^ƵƌĨĂĐĞ ϵ͕ϭϱϮ͛ Ƶƚƚͬϲ͘ϭϴϰ͟ ϭϳϭďďůͬŵƚƚŽϱ͕ϬϬϬ͛ dƵďŝŶŐĞƚĂŝů ϮͲϳͬϴ͟ WƌŽĚƵĐƚŝŽŶ ϲ͘ϰη͕>ͲϴϬ ^ƵƌĨĂĐĞ ϱ͕ϵϱϱ͛ /dͲDŽĚͬϮ͘ϰϰϭ͟ ϭͲϭͬϮ͟ ,ĞĂƚĞƌ Ϯ͘ϳϱη͕:Ͳϱϱ ^ƵƌĨĂĐĞ Ϯ͕ϵϵϰ͛ ϭϬZ &ůƵŝĚ͗WƌŽƉĞůǇŶĞ'ůǇĐŽů :t>Zzd/> EŽ͘ ĞƉƚŚ >ĞŶŐƚŚ / K /ƚĞŵ ϭ Ϯϰ͘ϮϬ͛ Ϭ͘ϱϱ͛ Ϯ͘ϰϰϭ͟ ϭϮ͘ϬϬ͟ ƵĂůdƵďŝŶŐ,ĂŶŐĞƌ͕ϮͲϳͬϴ͟ǆϮͲϯͬϴ͟ϭϮ͟ϱDEĂƚŝŽŶĂů ;ϮͲϳͬϴ͟ΘϮͲϯͬϴ͟ϴZůŝĨƚƚŚƌĞĂĚƐͿ Ϯ ϱ͕ϯϮϳ͛ ϰ͘Ϭϯ͛ Ϯ͘ϯϭϬ͟ ϯ͘ϵϮϬ͟ ^ůŝĚŝŶŐ^ůĞĞǀĞ͕,ĂůůŝďƵƌƚŽŶy ϯ ϱ͕ϯϳϰ͛ ϴ͘ϯϴ͛ Ϯ͘ϴϳϬ͟ ϱ͘ϵϴϬ͟ WƌĞŵŝĞƌWĂĐŬĞƌ ϰ ϱ͕ϰϮϴ͛ ϭ͘ϯϬ͛ Ϯ͘ϯϭϯ͟ ϯ͘ϮϮϬ͟ ĂŬĞƌyWƌŽĨŝůĞ;Ϯ͘ϯϭϯ͟DŝŶ/Ϳ ϱ ϱ͕ϱϵϱ͛ ϭ͘ϰϭ͛ Ϯ͘Ϯϱϳ͟ Ϯ͘ϴϴϬ͟ DĞĐŚĂŶŝĐĂůͲƌĞůĞĂƐĞ ϲ ϱ͕ϵϭϲ͛ Ϭ͘ϳϬ͛ Ϯ͘ϰϰϭ͟ ϯ͘ϵϱϴ͟ WŽƌƚĞĚ^Ƶď ϳ ϱ͕ϵϱϱ͛ Ϭ͘ϵϰ͛ ϯ͘ϲϳϬ͟ ϰ͘ϵϱϬ͟ t>' ϭϬ нͬͲϴ͕ϱϯϬ͛ ϯϮ͘ϳϳ͛ Ͳ Ͳ ƌŽƉƉĞĚdWƐƐĞŵďůǇ ϭϭ ϴ͕ϱϵϳ͛ Ϯ͘ϬϬ͛ Ͳ Ͳ ĞŵĞŶƚZĞƚĂŝŶĞƌĐĂƉƉĞĚǁͬϮϲϵ͛ĐĞŵĞŶƚ;ƐƚͿ ϭϮ ϴ͕ϲϭϯ͛ Ͳ Ϯ͘ϰϰϭ͟ ϯ͘ϱϬϬ͟ ƵƚƚƵďŝŶŐƐƚƵď ϭϯ ϴ͕ϲϮϵ͛ ϰ͘ϳϴ͛ ϯ͘ϮϱϬ͟ ϱ͘ϵϲϴ͟ ĂŬĞƌϯ,WĂĐŬĞƌǁͬŵŝůůŽƵƚĞǆƚĞŶƐŝŽŶ;DŝŶ/ƚŚƌƵ ŶĐŚŽƌ>ĂƚĐŚ^ĞĂůƐƐĞŵďůǇͿ ϭϲ ϴ͕ϲϰϯ͛ Ϭ͘ϲϳ͛ Ϯ͘ϰϰϭ͟ ϯ͘ϱϬϬ͟ ĂŬĞƌ͞Z͟^Ƶď ϭϳ ϴ͕ϲϱϬ͛ ϭ͘Ϯϰ͛ Ϯ͘ϮϱϬ͟ ϯ͘ϱϬϬΗ ĂŬĞƌZWƌŽĨŝůĞǁͬEŽͲŐŽ ϭϴ ϴ͕ϲϱϵ͛ Ϭ͘ϲϯ͛ Ϯ͘ϰϰϭ͟ ϯ͘ϲϴϳ͟ ĂŬĞƌWŽƌƚĞĚ^ƵďǁͬŐůĂƐƐĚŝƐĐ ϭϵ ϴ͕ϲϵϯ͛ Ϭ͘ϴϮ͛ Ϯ͘ϰϰϭ͟ ϯ͘ϲϴϳ͟ dƵďŝŶŐdĂŝů ϮϬ ϴ͕ϴϵϱ͛;ĞƐƚͿ ϭϴϯ͛ ϯ͘ϲϴϳ͟ &/^,͗ĂŬĞƌdWƌŽƉKĨĨ'ƵŶƐ WZ&KZd/KEd/> KE dKW;DͿ dD;DͿ dKW;dsͿ dD;dsͿ ^ŚŽƚ ŽŶĚŝƚŝŽŶ ^ƚĞƌůŝŶŐϭh ϱ͕ϲϳϭΖ ϱ͕ϲϳϴΖ ϱ͕ϭϲϱΖ ϱ͕ϭϳϮΖ ϳ WĞƌĨĞĚϮͬϰͬϮϭʹKƉĞŶ ^ƚĞƌůŝŶŐͬ ĞůƵŐĂ ϱ͕ϵϳϳ͛ ϱ͕ϵϴϳ͛ ϱ͕ϰϯϰΖ ϱ͕ϰϰϯΖ ϱƐƉĨ ϰͲϱͬϴ͟dW;ϭϭͬϮͬϭϭͿϳϯͲϰ^Ě ϳ͕ϳϲϴΖ ϳ͕ϳϵϲΖ ϳ͕ϬϭϵΖ ϳ͕ϬϰϰΖ ϲƐƉĨ Ϯ͟,͕ϲϬĚĞŐƉŚĂƐĞ;ϲͬϮϵͬϭϮͿ ϳ͕ϵϱϰ͛ ϳ͕ϵϳϰ͛ ϳ͕ϭϴϲΖ ϳ͕ϮϬϰΖ ϲƐƉĨ Ϯ͟,͕ϲϬĚĞŐƉŚĂƐĞ;ϲͬϮϴͬϭϮͿ dǇŽŶĞŬ ϴ͕ϳϭϬ͛ ϴ͕ϳϮϱ͛ ϳ͕ϴϲϴΖ ϳ͕ϴϴϮΖ ϭϮƐƉĨ WĞƌĨĞĚϭͬϮϲͬϵϯ/ƐŽůĂƚĞĚ ϴ͕ϳϰϱ͛ ϴ͕ϳϲϴ͛ ϳ͕ϵϬϬΖ ϳ͕ϵϮϬΖ ϭϮƐƉĨ WĞƌĨĞĚϭͬϮϲͬϵϯ/ƐŽůĂƚĞĚ ϴ͕ϳϴϯ͛ ϴ͕ϴϬϯ͛ ϳ͕ϵϯϰΖ ϳ͕ϵϱϮΖ ϭϮƐƉĨ WĞƌĨĞĚϭͬϮϲͬϵϯ/ƐŽůĂƚĞĚ ϴ͕ϴϭϱ͛ ϴ͕ϴϳϱ͛ ϳ͕ϵϲϯΖ ϴ͕ϬϭϳΖ ϭϮƐƉĨ WĞƌĨĞĚϭͬϮϲͬϵϯ/ƐŽůĂƚĞĚ BBBBBBBBBBBBBBB BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB hƉĚĂƚĞĚďǇ:>>ϴͬϮϮͬϮϮ WZKWK^ /ǀĂŶZŝǀĞƌhŶŝƚ /ZhϰϭͲϬϭ ŽŵƉůĞƚŝŽŶZĂŶϴͬϭϬͬϭϭ Wd͗ϭϵϮͲϭϬϵ W/͗ ϱϬͲϮϴϯͲϮϬϬϴϴͲϬϬͲϬϬ 7' ¶3%7' ¶ 6WHUOLQJ %HOXJD 577+)¶.% ´#¶ 67%8 5.%¶$06/ ´ #¶ ´# ¶ ´# ¶ 7\RQHN 67$±$ 67$ 67%/ 67%8 67%/ 7DJJHGILOO# ¶ &%/7RS¶ 5 5$ 7DJJHGILOO# ¶ 7DJJHGILOOZ´ %DLOHU #¶ 7DJJHG)LOO #¶ ^/E'd/> ^ŝǌĞ dǇƉĞ tƚͬ'ƌĂĚĞ dŽƉ ƚŵ KEEͬ/ ĞŵĞŶƚͬKƚŚĞƌ ϮϬ͟ ŽŶĚƵĐƚŽƌ ϵϰη ^ƵƌĨĂĐĞ ϭϲϱ͛ ƌŝǀĞŶ ϭϯͲϯͬϴ͟ ^ƵƌĨĂĐĞ ϲϴη͕<Ͳϱϱ ^ƵƌĨĂĐĞ ϴϵϱ͛ ƵƚƚͬϭϮ͘ϰϭϱ͟ ϮϭϮďďůͬŵƚƚŽ^ƵƌĨĂĐĞ ϵͲϱͬϴ͟ /ŶƚĞƌŵĞĚŝĂƚĞ ϰϳη͕EͲϴϬ ^ƵƌĨĂĐĞ ϭϰϰ͛ Ƶƚƚͬϴ͘ϲϴϭ͟ϮϴϭďďůͬŵƚƚŽ^ƵƌĨĂĐĞ ϰϳη͕^Ͳϵϱ ϭϰϰ͛ ϯ͕ϰϵϴ͛ Ƶƚƚͬϴ͘ϲϴϭ͟ ϳ͟ WƌŽĚƵĐƚŝŽŶ Ϯϵη͕EͲϴϬ ^ƵƌĨĂĐĞ ϵ͕ϭϱϮ͛ Ƶƚƚͬϲ͘ϭϴϰ͟ ϭϳϭďďůͬŵƚƚŽϱ͕ϬϬϬ͛ dƵďŝŶŐĞƚĂŝů ϮͲϳͬϴ͟ WƌŽĚƵĐƚŝŽŶ ϲ͘ϰη͕>ͲϴϬ ^ƵƌĨĂĐĞ ϱ͕ϵϱϱ͛ /dͲDŽĚͬϮ͘ϰϰϭ͟ ϭͲϭͬϮ͟ ,ĞĂƚĞƌ Ϯ͘ϳϱη͕:Ͳϱϱ ^ƵƌĨĂĐĞ Ϯ͕ϵϵϰ͛ ϭϬZ &ůƵŝĚ͗WƌŽƉĞůǇŶĞ'ůǇĐŽů :t>Zzd/> EŽ͘ ĞƉƚŚ >ĞŶŐƚŚ / K /ƚĞŵ ϭ Ϯϰ͘ϮϬ͛ Ϭ͘ϱϱ͛ Ϯ͘ϰϰϭ͟ ϭϮ͘ϬϬ͟ ƵĂůdƵďŝŶŐ,ĂŶŐĞƌ͕ϮͲϳͬϴ͟ǆϮͲϯͬϴ͟ϭϮ͟ϱDEĂƚŝŽŶĂů ;ϮͲϳͬϴ͟ΘϮͲϯͬϴ͟ϴZůŝĨƚƚŚƌĞĂĚƐͿ Ϯ ϱ͕ϯϮϳ͛ ϰ͘Ϭϯ͛ Ϯ͘ϯϭϬ͟ ϯ͘ϵϮϬ͟ ^ůŝĚŝŶŐ^ůĞĞǀĞ͕,ĂůůŝďƵƌƚŽŶy ϯ ϱ͕ϯϳϰ͛ ϴ͘ϯϴ͛ Ϯ͘ϴϳϬ͟ ϱ͘ϵϴϬ͟ WƌĞŵŝĞƌWĂĐŬĞƌ ϰ ϱ͕ϰϮϴ͛ ϭ͘ϯϬ͛ Ϯ͘ϯϭϯ͟ ϯ͘ϮϮϬ͟ ĂŬĞƌyWƌŽĨŝůĞ;Ϯ͘ϯϭϯ͟DŝŶ/Ϳ ϱ ϱ͕ϱϵϱ͛ ϭ͘ϰϭ͛ Ϯ͘Ϯϱϳ͟ Ϯ͘ϴϴϬ͟ DĞĐŚĂŶŝĐĂůͲƌĞůĞĂƐĞ ϲ ϱ͕ϵϭϲ͛ Ϭ͘ϳϬ͛ Ϯ͘ϰϰϭ͟ ϯ͘ϵϱϴ͟ WŽƌƚĞĚ^Ƶď ϳ ϱ͕ϵϱϱ͛ Ϭ͘ϵϰ͛ ϯ͘ϲϳϬ͟ ϰ͘ϵϱϬ͟ t>' ϭϬ нͬͲϴ͕ϱϯϬ͛ ϯϮ͘ϳϳ͛ Ͳ Ͳ ƌŽƉƉĞĚdWƐƐĞŵďůǇ ϭϭ ϴ͕ϱϵϳ͛ Ϯ͘ϬϬ͛ Ͳ Ͳ ĞŵĞŶƚZĞƚĂŝŶĞƌĐĂƉƉĞĚǁͬϮϲϵ͛ĐĞŵĞŶƚ;ƐƚͿ ϭϮ ϴ͕ϲϭϯ͛ Ͳ Ϯ͘ϰϰϭ͟ ϯ͘ϱϬϬ͟ ƵƚƚƵďŝŶŐƐƚƵď ϭϯ ϴ͕ϲϮϵ͛ ϰ͘ϳϴ͛ ϯ͘ϮϱϬ͟ ϱ͘ϵϲϴ͟ ĂŬĞƌϯ,WĂĐŬĞƌǁͬŵŝůůŽƵƚĞǆƚĞŶƐŝŽŶ;DŝŶ/ƚŚƌƵ ŶĐŚŽƌ>ĂƚĐŚ^ĞĂůƐƐĞŵďůǇͿ ϭϲ ϴ͕ϲϰϯ͛ Ϭ͘ϲϳ͛ Ϯ͘ϰϰϭ͟ ϯ͘ϱϬϬ͟ ĂŬĞƌ͞Z͟^Ƶď ϭϳ ϴ͕ϲϱϬ͛ ϭ͘Ϯϰ͛ Ϯ͘ϮϱϬ͟ ϯ͘ϱϬϬΗ ĂŬĞƌZWƌŽĨŝůĞǁͬEŽͲŐŽ ϭϴ ϴ͕ϲϱϵ͛ Ϭ͘ϲϯ͛ Ϯ͘ϰϰϭ͟ ϯ͘ϲϴϳ͟ ĂŬĞƌWŽƌƚĞĚ^ƵďǁͬŐůĂƐƐĚŝƐĐ ϭϵ ϴ͕ϲϵϯ͛ Ϭ͘ϴϮ͛ Ϯ͘ϰϰϭ͟ ϯ͘ϲϴϳ͟ dƵďŝŶŐdĂŝů ϮϬ ϴ͕ϴϵϱ͛;ĞƐƚͿ ϭϴϯ͛ ϯ͘ϲϴϳ͟ &/^,͗ĂŬĞƌdWƌŽƉKĨĨ'ƵŶƐ WZ&KZd/KEd/> KE dKW;DͿ dD;DͿ dKW;dsͿ dD;dsͿ ^ŚŽƚ ŽŶĚŝƚŝŽŶ ^dͲϭ цϱ͕ϰϰϳ͛ цϱ͕ϰϱϰ͛ цϰ͕ϵϲϵ͛ цϰ͕ϵϳϱ͛ &ƵƚƵƌĞͬWƌŽƉŽƐĞĚ ^dͲϮ цϱ͕ϰϵϰ͛ цϱ͕ϱϬϮ͛ цϱ͕ϬϭϬ͛ цϱ͕Ϭϭϳ͛ &ƵƚƵƌĞͬWƌŽƉŽƐĞĚ ^dͲϯ цϱ͕ϱϰϰ͛ цϱ͕ϱϱϭ͛ цϱ͕Ϭϱϰ͛ цϱ͕ϬϲϬ͛ &ƵƚƵƌĞͬWƌŽƉŽƐĞĚ ^dͲϱ цϱ͕ϲϰϬ͛ цϱ͕ϲϰϱ͛ цϱ͕ϭϯϴ͛ цϱ͕ϭϰϮ͛ &ƵƚƵƌĞͬWƌŽƉŽƐĞĚ ^dͲϭh ϱ͕ϲϳϭΖ ϱ͕ϲϳϴΖ ϱ͕ϭϲϱΖ ϱ͕ϭϳϮΖ ϳ WĞƌĨĞĚϮͬϰͬϮϭʹKƉĞŶ 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___________________ 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6.API Number: 7.If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 9,170'8530 (TCP Guns) Casing Collapse Structural Conductor Surface 1,950 psi Intermediate 4,750 psi Production 7,020 psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Ted Kramer Operations Manager Contact Email: Contact Phone: 777-8420 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Perforation Depth MD (ft): Baker Premier Packer; N/A 5,374' MD/4,902' TVD; N/A Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: January 26, 2021 tkramer@hilcorp.com See Attached Schematic 9,152'8,266'7" 2-7/8" - Prod., 1-1/2" Heater 9,152' 20" 13-3/8" 165' 9-5/8"3,498' 895'3,450 psi 164' 894' 3,335' 165' 895' 3,498' L-80, 6.5# / J-55, 2.75# TVD Burst 5,955' / 2,994' 8,160 psi MD 6,870 psi Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY 8,282'8,597'7,762' 50-283-20088-00-00 Ivan River Unit (IRU) 41-01 Ivan River Field / Undefined Gas Length Size State Wide Spacing Tubing Grade:Tubing MD (ft): See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL032930 (Ivan River Unit) 192-109 1,761 8,597' Perforation Depth TVD (ft):Tubing Size: COMMISSION USE ONLY Authorized Name: m n P 66 t _ Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 1:13 pm, Jan 15, 2021 321-030 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2021.01.15 12:31:07 -09'00' Taylor Wellman Perforate 10-404 CO 301 approves a spacing exception for the IRU 41-01 development gas well DSR-1/19/21SFD 1/21/2021 SFD 1/21/2021 gls 1/21/21Comm 1/22/21 dts 1/22/2021 JLC 1/22/2021 RBDMS HEW 1/27/2020 Well Prognosis Well: IRU 41-01 Date: 1/11/2021 Well Name: IRU 41-01 API Number: 50-283-20088-00 Current Status: SI Gas Producer Leg: N/A Estimated Start Date: January 26, 2021 Rig: E-line Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 192-109 First Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (C) Second Call Engineer: Todd Sidoti (907) 777-8443 (O) (907) 632-4113 (C) AFE Number: Maximum Expected BHP: ~ 2,283 psi @ 5,221’ TVD (Using 0.437 PSI/ft Gradient) Max. Potential Surface Pressure: 1,761 psi Using Max BHP minus .1 psi/ft. gas gradient to 5,221’ TVD). Brief Well Summary IRU 41-01 was last perforated in the H-13 and I Sands in June of 2012. IP of the well after this work was 1.5 MMscfd. The well flowed until July of 2020 when it sanded up and died. A recent slick line tag on January 10, 2021 found fill @ 5,933’ (Just inside of the tubing tail). SI Tubing pressure is 1,100 psi. This purpose of this Sundry is to add perforations in the Sterling Sands (B2, B1 and A5). Notes Regarding Wellbore Condition x SL Tagged fill @ 5,933’ on 1/10/21 x SITP 1,100 PSI E-Line Procedure: 1. MIRU e-line and pressure control equipment. PT lubricator to 250 psi low / 2500 psi high. 2. RIH with GPT to 5,933’ and locate fluid level (if there is one). 3. Perforate the below sands : Sand Top, MD ft Bottom, MD ft TVD Top TVD Bottom Total ftg, MD Sterling A5 ±5,640' ±5,651' ±5,138' ±5,148' 11' Sterling B1U ±5,671' ±5,678' ±5,165' ±5,172' 7' Sterling B1L ±5,688' ±5,694' ±5,180' ±5,186' 6' Sterling B2 ±5,707' ±5,717 ±5,197' ±5,206' 10' Sterling B2 ±5,724' ±5,734’ ±5,212' ±5,221' 10' a. Proposed perfs also shown on the proposed schematic in red font. b. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. c. Use Gamma/CCL to correlate. d. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run for 5, 10, and 15 minute intervals. e. Ivan River Unit falls under the Beluga River undefined Gas Pool. State wide Rules govern this Unit which historically allowed the comingling of the Beluga and Sterling pools. Hilcorp has committed to submit for Pool Rules for the future for the Ivan River Unit. NOTE: perforating through the tubing tail add perforations in the Sterling Sands (B2, B1 and A5). Well Prognosis Well: IRU 41-01 Date: 1/11/2021 4. POOH. RD E-line. 5. Turn Well over to Production. E-line Procedure (Contingency): 1. If any zone produces sand and/or water or needs isolated 2. MIRU E-line, PT lubricator to 2,000 psi Hi 250 Low. 3. RIH and set a through tubing plug at depth above zone. Attachments: 1. Actual Schematic 2. Proposed Schematic _______________ __________________________________________________ Updated by DMA 01-14-21 SCHEMATIC Ivan River Unit IRU 41-01 Completion Ran 8/10/11 PTD: 192-109 API: 50-283-20088-00-00 Casing Detail Size Type Wt/ Grade Top Btm CONN / ID Cement / Other 20” Conductor 94# Surface 165’ Driven 13-3/8” Surface 68#, K-55 Surface 895’ Butt / 12.415” 212 bbl / Cmt to Surface 9-5/8” Intermediate 47#, N-80 Surface 144’ Butt / 8.681” 281 bbl / Cmt to Surface 47#, S-95 144’ 3,498’ Butt / 8.681” 7” Production 29#, N-80 Surface 9,152’ Butt / 6.184” 171 bbl / Cmt to 5,000’ Tubing Detail 2-7/8” Production 6.4#, L-80 Surface 5,955’ IBT-Mod/2.441” 1-1/2” Heater 2.75#, J-55 Surface 2,994’ 10RD Fluid: Propelyne Glycol Jewelry Detail No. Depth Length ID OD Item 1 24.20’ 0.55’ 2.441” 12.00” Dual Tubing Hanger, 2-7/8” x 2-3/8” 12” 5M National (2-7/8” & 2-3/8” 8RD lift threads) 2 5,327’ 4.03’ 2.310” 3.920” Sliding Sleeve, Halliburton XD 3 5,373’ 1.45’ 2.441” 3.510” XO, 2-7/8” IBT-MOD Box x 3-1/2” TC-II Pin 4 5,374’ 8.38’ 2.870” 5.980” Premier Packer 5 5,383’ 1.42’ 2.441” 3.900” XO, 3-1/2” TC-II Box x 2-7/8” IBT-MOD Pin 6 5,428’ 1.30’ 2.313” 3.220” Baker X Profile (2.313” Min ID) 7 5,595’ 1.41’ 2.257” 2.880” Mechanical-release 8 5,916’ 0.70’ 2.441” 3.958” Ported Sub 9 5,955’ 0.94’ 3.670” 4.950” WLEG 10 +/-8,530’ 32.77’ - - Dropped TCP Assembly 11 8,597’ 2.00’ - - Cement Retainer capped w/ 269’ cement (Est) 12 8,613’ - 2.441” 3.500” Cut tubing stub 13 8,628’ 0.66’ 2.441” 3.750” XO, 2-7/8” IBT Box x 3-1/2” EUE 8RD Pin 14 8,629’ 4.78’ 3.250” 5.968” Baker 3H Packer w/ mill out extension (Min ID thru Anchor Latch Seal Assembly) 15 8,640’ 0.84’ 2.441” 5.000” XO, 4-1/2” 8RD Box x 2-7/8” IBT Pin 16 8,643’ 0.67’ 2.441” 3.500” Baker “RA” Sub 17 8,650’ 1.24’ 2.250” 3.500" Baker R Profile w/ No-go 18 8,659’ 0.63’ 2.441” 3.687” Baker Ported Sub w/ glass disc 19 8,693’ 0.82’ 2.441” 3.687” Tubing Tail 20 8,895’ (est) 183’ 3.687” FISH: Baker TCP Drop Off Guns Perforation Data ZONE TOP(MD) BTM(MD) TOP(TVD) BTM(TVD) Shot Condition Sterling/ Beluga 5,977’ 5,987’ 5,434' 5,443' 5 spf 4-5/8” TCP (11/2/11) 73-4 Sd 7,768' 7,796' 7,019' 7,044' 6 spf 2” HC, 60 deg phase (6/29/12) 7,954’ 7,974’ 7,186' 7,204' 6 spf 2” HC, 60 deg phase (6/28/12) Tyonek 8,710’ 8,725’ 7,868' 7,882' 12 spf Perfed 1/26/93 Isolated 8,745’ 8,768’ 7,900' 7,920' 12 spf Perfed 1/26/93 Isolated 8,783’ 8,803’ 7,934' 7,952' 12 spf Perfed 1/26/93 Isolated 8,815’ 8,875’ 7,963' 8,017' 12 spf Perfed 1/26/93 Isolated _______________ __________________________________________________ Updated by DMA 01-14-21 PROPOSED SCHEMATIC Ivan River Unit IRU 41-01 Completion Ran 8/10/11 PTD: 192-109 API: 50-283-20088-00-00 CASING DETAIL Size Type Wt/ Grade Top Btm CONN / ID Cement / Other 20” Conductor 94# Surface 165’ Driven 13-3/8” Surface 68#, K-55 Surface 895’ Butt / 12.415” 212 bbl / Cmt to Surface 9-5/8” Intermediate 47#, N-80 Surface 144’ Butt / 8.681” 281 bbl / Cmt to Surface 47#, S-95 144’ 3,498’ Butt / 8.681” 7” Production 29#, N-80 Surface 9,152’ Butt / 6.184” 171 bbl / Cmt to 5,000’ Tubing Detail 2-7/8” Production 6.4#, L-80 Surface 5,955’ IBT-Mod/2.441” 1-1/2” Heater 2.75#, J-55 Surface 2,994’ 10RD Fluid: Propelyne Glycol JEWELRY DETAIL No. Depth Length ID OD Item 1 24.20’ 0.55’ 2.441” 12.00” Dual Tubing Hanger, 2-7/8” x 2-3/8” 12” 5M National (2-7/8” & 2-3/8” 8RD lift threads) 2 5,327’ 4.03’ 2.310” 3.920” Sliding Sleeve, Halliburton XD 3 5,373’ 1.45’ 2.441” 3.510” XO, 2-7/8” IBT-MOD Box x 3-1/2” TC-II Pin 4 5,374’ 8.38’ 2.870” 5.980” Premier Packer 5 5,383’ 1.42’ 2.441” 3.900” XO, 3-1/2” TC-II Box x 2-7/8” IBT-MOD Pin 6 5,428’ 1.30’ 2.313” 3.220” Baker X Profile (2.313” Min ID) 7 5,595’ 1.41’ 2.257” 2.880” Mechanical-release 8 5,916’ 0.70’ 2.441” 3.958” Ported Sub 9 5,955’ 0.94’ 3.670” 4.950” WLEG 10 +/-8,530’ 32.77’ - - Dropped TCP Assembly 11 8,597’ 2.00’ - - Cement Retainer capped w/ 269’ cement (Est) 12 8,613’ - 2.441” 3.500” Cut tubing stub 13 8,628’ 0.66’ 2.441” 3.750” XO, 2-7/8” IBT Box x 3-1/2” EUE 8RD Pin 14 8,629’ 4.78’ 3.250” 5.968” Baker 3H Packer w/ mill out extension (Min ID thru Anchor Latch Seal Assembly) 15 8,640’ 0.84’ 2.441” 5.000” XO, 4-1/2” 8RD Box x 2-7/8” IBT Pin 16 8,643’ 0.67’ 2.441” 3.500” Baker “RA” Sub 17 8,650’ 1.24’ 2.250” 3.500" Baker R Profile w/ No-go 18 8,659’ 0.63’ 2.441” 3.687” Baker Ported Sub w/ glass disc 19 8,693’ 0.82’ 2.441” 3.687” Tubing Tail 20 8,895’ (est) 183’ 3.687” FISH: Baker TCP Drop Off Guns PERFORATION DETAIL ZONE TOP (MD) BTM (MD) TOP (TVD) BTM (TVD) Shot Condition Sterling A5 ±5,640' ±5,651' ±5,138' ±5,148' Proposed - TBD Sterling B1U ±5,671' ±5,678' ±5,165' ±5,172' Proposed - TBD Sterling B1L ±5,688' ±5,694' ±5,180' ±5,186' Proposed - TBD Sterling B2 ±5,707' ±5,717 ±5,197' ±5,206' Proposed - TBD Sterling B2 ±5,724' ±5,734’ ±5,212' ±5,221' Proposed - TBD Sterling/ Beluga 5,977’ 5,987’ 5,434' 5,443' 5 spf 4-5/8” TCP (11/2/11) 73-4 Sd 7,768' 7,796' 7,019' 7,044' 6 spf 2” HC, 60 deg phase (6/29/12) 7,954’ 7,974’ 7,186' 7,204' 6 spf 2” HC, 60 deg phase (6/28/12) Tyonek 8,710’ 8,725’ 7,868' 7,882' 12 spf Perfed 1/26/93 Isolated 8,745’ 8,768’ 7,900' 7,920' 12 spf Perfed 1/26/93 Isolated 8,783’ 8,803’ 7,934' 7,952' 12 spf Perfed 1/26/93 Isolated 8,815’ 8,875’ 7,963' 8,017' 12 spf Perfed 1/26/93 Isolated Sterling A5 ±5,640'±5,651'±5,138'±5,148'Proposed - TBD Sterling B1U ±5,671'±5,678'±5,165'±5,172'Proposed - TBD Sterling B1L ±5,688'±5,694'±5,180'±5,186'Proposed - TBD Sterling B2 ±5,707'±5,717 ±5,197'±5,206'Proposed - TBD Sterling B2 ±5,724'±5,734’±5,212'±5,221'Proposed - TBD Pages NOT Scanned in this Well History File XHVZE This page identifies those items that were not scanned during the initial scanning project. They are available in the original file and viewable by direct inspection. File Number of Well History File PAGES TO DELETE Complete RESCAN Color items - Pages: GrayScale, halftones, pictures, graphs, charts- Pages: Poor Quality Original - Pages: [] Other- Pages: DIGITAL DATA [] Diskettes, No. [] Other, No/Type OVERSIZED · [] Logs 'of vadous kinds n Other COMMENTS: Scanned by: IDianna Vincent Nathan Lowell TO RE-SCAN Notes: Re-Scanned by: Beverly Dianna Vincent Nathan Lowell Date: /si , OF ALOKA OIL AND G S COMNffSSION RECEIVED REPORT OF SUNDRY WELL OPERATIONS JUL 2 7 2012 1. Operations Abandon U Repair Well [J Plug Perforations LJ Perforate pi b Other AOGCC Performed: Alter Casing Pull Tubing Stimulate - Frac 0 Waiver E Time Extension Change Approved Program ❑ Operat. Shutdown ❑ Stimulate - Other ❑ Re -enter Suspended WeN❑ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska, LLC Development El . Exploratory ❑ 192 -109 ' 3. Address: 3800 Centerpoint Drive, Suite 100, Anchorage, Stratigraphic 0 Service ❑ 6. API Number: Alaska 99503 ' 50- 283 - 20088 -00 " 00 7. Property Designation (Lease Number): - 8. Well Name and Number: Ivan River Unit (ADL032930) - Ivan River Unit (IRU) 41 -01 ' 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field /Pool(s): Ivan River Field / Undefined Gas 11. Present Well Condition Summary: Total Depth measured 9,170 ' feet Plugs measured 8,597 feet true vertical 8,283 , feet Junk measured 8,129 (fill) feet Effective Depth measured 8,597 feet Packer measured 5,374 feet true vertical 7,766 feet true vertical 4,905 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 165' 20" 165' 165' Surface 895' 13 -3/8" 895' 895' 3,450 psi 1,950 psi Intermediate 3,498' 9 -5/8" 3,498' 3,335' 6,870 psi 4,750 psi Production 9,152' 7" 9,152' 8,267' 8,160 psi 7,020 psi Liner Perforation depth Measured depth see attached schematic True Vertical depth see attached schematic 2 -7/8" 6.4# / L -80 5,955' 5,414' TVD Tubing (size, grade, measured and true vertical depth) 1 -1/2" (heater) 2.75# / J -55 2,994' 2,901' TVD 5,374' MD Packers and SSSV (type, measured and true vertical depth) Premier Packer 4,905' TVD N/A N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): N/A AUG � Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 0 650 Subsequent to operation: 0 1,100 0 0 350 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run N/A Exploratory ❑ Development El Service [] Stratigraphic ❑ Daily Report of Well Operations X 16. Well Status after work: OiI ❑ -.Gas In . WDSPL ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: Contact Chad Helgeson Phone: 777 -8405 Printed Name Chad Helgeson Title Operations Engineer Signature Phone 777 -8405 Date 7/ c /j Z R&DMS JUL 2 7 rl 7 2 7 -12 r ;i✓ Form 10 -404 Revised 11/2011 7�y Submit Original Only r N '.' • • Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date IRU 41 -01 Add Perfs 50- 283 - 20088 -00 192 -109 6/27/12 6/29/12 Daily Operations: 06/27/2012 - Wednesday RU and pressure test to 600 psi. RIH CCIJGR and 2 "x10' spent dummy gun (OD 2 -1/8 ") and tie into SLB RST Log dated 17 -July- 2009. Tagged fill at 8,129'. POOH. RD lubricator and secure well. 06/28/2012 - Thursday RU lubricator and pressure test to 2500 psi. RIH w /CCL -GR, 2 "x20' HC, 6 spf, 60 degree phase down to 6,200'. POOH. RIH with pert gun and tie into RST Log dated 17 -Jul -2009. Tag fill at 8,129'. Log up a number of times to 7,700', engineer adjusted printer and logged up to 7,500' and tied into log. Spotted guns from 7,954' to 7,974'. Tubing pressure was 549 psi. i Fired guns. POOH. Tubing pressure was 530 psi. SDFN. 06/29/2012 - Friday RU lubricator back up. Pressure test to 2500 psi. RIH w /CCL -GR, 2 "x28' HC, 6 spf, 60 deg phase and tie into Expro log from yesterday that was tied into SLB RST log dated 17 -July -2009. Spot perf gun from 7,768' to 7,796'. Tubing pressure was 560 , psi. Fired guns within minutes tubing pressure started building approx 20 psi every 5 min. POOH. Tubing pressure was 840 psi when we shut well in. RD lubricator and turn well over to production. Tubing pressure got up to 1450 psi and still building. 06/30/2012 - Saturday Started flowing well to production. 07/01/2012 - Sunday Nothing to report. 07/02/2012 - Monday Nothing to report. 07/03/2012 - Tuesday Nothing to report. - • • Ivan River Unit IRU 41 -01 Hilcorp Alaska, LLC SCHEMATIC - Completed 8/10/11 50- 283 - 20088 -00 Casing Detail RI0a 51' KBANSL ` Izrnf: 24' KB Size Type Grade Top Btm CONN / ID Cement / Other w 6 20" Conductor 94# Surface 165' Driven 4 ati . a 1 3 3/8" Surface 68 #, K -55 Surface 895' Butt / 12.415" 212 bbl / Cmt to Surface 20 @ r 165' ♦ 47 #, N -80 Surface 144' Butt / 8.681" 9 5/8" Intermediate 281 bbl / Cmt to Surface 47 #, 5 -95 144' 3,498' Butt / 8.681" 1 v a 7" Production 29 #, N -80 Surface 9,152' Butt / 6.184" 171 bbl / Cmt to 5,000' a Tubing Detail "i — 1, 2 -7/8" Production 6.4 #, L -80 Surface 5,955' IBT- Mod /2.441" I # 1 -1/2" Heater 2.75 #,1 -55 Surface 2,994' 1ORD Fluid: Propelyne Glycol _` Jewelry Detail . 1 :` No. Depth Length ID OD Item !:!► 1 24.20' 0.55' 2.441" 12.00" Dual Tubing Hanger, 2 -7/8" x 2 -3/8" 12" 5M National 9y8"@ a (2 -7/8" & 2 -3/8" 8RD lift threads) Ii 2 2 5,327' 4.03' 2.310" 3.920" Sliding Sleeve, Halliburton XD =` 3 3 5,373' 1.45' 2.441" 3.510" XO, 2 -7/8" IBT -MOD Box x 3 -1/2" TC -II Pin CEIL Tops 5,000' i' _; 4 4 5,374' 8.38' 2.870" 5.980" Premier Packer ' i ' i . 5 5,383' 1.42' 2.441" 3.900" XO, 3 -1/2" TC -II Box x 2 -7/8" IBT -MOD Pin US 5 6 5,428' 1.30' 2.313" 3.220" Baker X Profile (2.313" Min ID) a 6 7 5,595' 1.41' 2.257" 2.880" Mechanical - release ums K. m 8 5,916' 0.70' 2.441" 3.958" Ported Sub I 1 7 9 5,955' 0.94' 3.670" 4.950" WLEG R 8 10 +/- 8,530' 32.77' - - Dropped TCP Assembly ,* 9 11 8,597' 2.00' - - Cement Retainer capped w/ 269' cement (Est) 12 8,613' - 2.441" 3.500" Cut tubing stub 13 8,628' 0.66' 2.441" 3.750" XO, 2 -7/8" IBT Box x 3 -1/2" EUE 8RD Pin 14 8,629' 4.78' 3.250" 5.968" Baker 3H Packer w/ mill out extension (Min ID thru Anchor Latch Seal Assembly) 15 8,640' 0.84' 2.441" 5.000" XO, 4 -1/2" 8RD Box x 2 -7/8" IBT Pin . 16 8,643' 0.67' 2.441" 3.500" Baker "RA" Sub Tagged fill @ r 8,129' (6 , : , Il . .,'" a. + 17 8,650' 1.24' 2.250" 3.500" Baker R Profile w/ No -go ' 17 t 10 18 8,659' 0.63' 2.441" 3.687" Baker Ported Sub w/ glass disc `F #.:`, 11 19 8,693' 0.82' 2.441" 3.687" Tubing Tail ( . m . r ° 20 8,895' (est) 183' 3.687" FISH: Baker TCP Drop Off Guns ' I JI ` ' 14 Perforation Data ZONE TOP(MD) BTM(MD) TOP(TVD) BTM(TVD) Shot Condition 1 - 4 5 5,987' 5,434' 5,443' 5 spf 4 -5/8" TCP (11/2/11) 73 -4 Sd + IM .� - Sterling/ 7,768' 7( 7,796' 7,019' 7,044' 6 spf 2" HC, 60 deg phase (6/29/12) ' t Beluga 7,954' ✓ 7,974' 7,186' 7,204' 6 spf 2" HC, 60 deg phase (6/28/12) ' ' ' • l 8,710' 8,725' 7,868' 7,882' 12 spf Perfed 1/26/93 Isolated t• 1 IV} 8,745' 8,768' 7,900' 7,920' 12 spf Perfed 1/26/93 Isolated A, pi Tyonek � , 8,783' 8,803' 7,934' 7,952' 12 spf Perfed 1/26/93 Isolated Y { ±I ' ° '. 8,815' 8,875' 7,963' 8,017' 12 spf Perfed 1/26/93 Isolated ht. " o „}t t ki Tagged fill @ r e 8,851' (7/12109) 1 r k., • f t � V' • .. 20 . tt i", T' @9,157 I 1'• b TD 4,17V PBTD= 9,078' Updated by TDF 7 -20 -12 . ALASKA OIL ANS CONSERVATION AVTE OF ALASKA ON COMMISSION • 1 'C 01 2011 REPORT OF SUNDRY WELL OPERATIONS Alska iil R, (gas Cnttt rarttmpssim 1. Operations Abandon U Repair Well U Plug Perforations U Stimulate U Other Ll Anont'!$& Performed: Alter Casing ❑ Pull Tubing Q • Perf orate New Pool ❑ Waiver ❑ Time Extension ❑ Change Approved Program ❑ Operat. Shutdown ❑ Perforate El . Re -enter Suspended Well ❑ 2. Operator Union Oil Company of California 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development 0 Exploratory ❑ 192 -109 -° 3. Address: PO Box 196247, Anchorage, AK 99519 Stratigraphic❑ Service ❑ 6. API Number: 50- 283 - 20088 -00 — 00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL032930 [Ivan River Unit] • Ivan River Unit 41 -01 e 9. Field /Pool(s): r Ivan River Field/ Undefined Gas Pool • 10. Present Well Condition Summary: Total Depth measured 9,170 • feet Plugs measured N/A feet true vertical 8,282 • feet Junk measured ±8,530 feet Effective Depth measured ±8,530 feet Packer measured 5,374 feet true vertical ±7,705 feet true vertical 4,905 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 165' 20" 165' 164' Surface 895' 13 -3/8" 895' 894' 3,450psi 1,950psi Intermediate 3,498' 9 -5/8" 3,498' 3,335' 6,870psi 4,750psi Production 9,152' 7" 9,152' 8,266' 8,160psi 7,020psi Liner Perforation depth Measured depth 5,977.5,987 feet 4: 04 y 1 t ' q;. 'i 70i True Vertical depth 5,434 -5,443 feet 2 -7/8" 6.4#, L -80 5,955'(MD) 5,414'(TVD) Tubing (size, grade, measured and true vertical depth) 1 -1/2" 2.75 #, J -55 2,994'(MD) 2,901'(TVD) 5,374'(MD) Packers and SSSV (type, measured and true vertical depth) Premier Packer 4,905'(TVD) N/A N/A 11. Stimulation or cement squeeze summary: Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 12. Representative Daily Average Production or Injection Data Oil-Bbl Gas -Mcf Water -Bbl Casing Pressure - Tubing Pressure Prior to well operation: 0 0 0 Opsi 100psi Subsequent to operation: 0 0 0 Opsi 350psi 13. Attachments: 14. Well Class after work: Copies of Logs and Surveys Run N/A Exploratory❑ Development ig - Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 15. Well Status after work: Oil ❑ '. Gas U . WDSPL U GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 16. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 311 -227 Contact Chris Kanyer Phone: 263 -7831 Printed Name Timothy C. Brandenbu . Title Drilling Manager - r 7—,, Signature �t Phone 276 -7600 Date j i /3 c' /-2 o 1 1 RBDMS DEC 01 f 0- 0. Form 10 -404 Revised 10/2010 Submit Original Only ,�, evro • Ivan river Unit IRU 41 -01 Well IRU 41 -01 "11%%...� Actual Well Schematic Completed 1 17 11 RIM: 51' KBMASI- RT -T : Casing and Tubing Detail ji 1 r Size Type Wt/ Grade Top Btm CONN / ID Cement / Other 20,@ 20" Conductor 94# Surface 165' Driven 156 13 -3/8" Surface 68 #, K -55 Surface 895' Butt / 12.415" 212 bbl / Cmt to Surface 9 -5/8" Intermediate 47 #, N -80 Surface 144' Butt / 8.681" 281 bbl / Cmt to Surface 47 #, S -95 144' 3,498' Butt / 8.681" 133/8" 7" Production 29 #, N -80 Surface 9,152' Butt / 6.184" 171 bbl / Cmt to 5,000' 896 Tubing 2 -7/8" Production 6.4 #, L -80 Surface 5,955' IBT- Mod/2.441" — 1 -1/2" Heater 2.75 #, J -55 Surface 2,994' 1ORD Fluid: Propelyne Glycol Production String Jewelry Detail G # Depth (RKB) Length ID OD Item 1 24.20' 0.55' 2.441" 12.00" Dual Tubing Hanger, 2 -7/8" x 2 -3/8" 12" 5M 95B°' @ 2 National (2 -7/8" & 2 -3/8" 8RD lift threads) 3 2 5,327' 4.03' 2.310" 3.920" Sliding Sleeve, Halliburton XD i 3 3 5,373' 1.45' 2.441" 3.510" XO, 2 -7/8" IBT -MOD Box x 3 -1/2" TC -II Pin 4 5,374' 8.38' 2.870" 5.980" Premier Packer CBLTop: 5000' 4 5 5,383' 1.42' 2.441" 3.900" XO, 3 -1/2" TC -II Box x 2 -7/8" IBT -MOD Pin 6 5,428' 1.30' 2.313" 3.220" Baker X Profile (2.313" Min ID) 5 7 5,595' 1.41' 2.257" 2.880" Mechanical - release • 6 8 5,916' 0.70' 2.441" 3.958" Ported Sub 9 5,955' 0.94' 3.670" 4.950" WLEG +/- 8,530' Dropped TCP Assembly 11 8,597' 2.00' 0.66' Cement Retainer capped w/ 269' cement (Est) 7 12 8,613' 2.441" 3.500" Cut tubing stub 13 8,628' 2.441" 3.750" XO, 2 -7/8" IBT Box x 3 1/2" EUE 8RD Pin 14 8,629' 4.78' 3.250" 5.968" Baker 3H Packer w/ mill out extension (Min ID 8 thru Anchor Latch Seal Assembly) 15 8,640' 0.84' 2.441" 5.000" X0, 4 -1/2" 8RD Box x 2 -7/8" IBT Pin 9 16 8,643' 0.67' 2.441" 3.500" Baker "RA" Sub 17 8,650' 1.24' 2.250" 3.500" Baker R Profile w/ No -go 18 8,659' 0.63' 2.441" 3.687" Baker Ported Sub w/ glass disc i j 19 8,693' 0.82' 2.441" 3.687" Tubing Tail 10 20 8,895' (est) 183' 3.687" FISH: Baker TCP Drop Off Guns � 11 Perforation Data 13 ZONE TOP BTM Shot Condition it 73 -4 5,977' 5,987' 5 spf 4 -5/8" TCP (11/2/11) I 0 14 8,710' ' 8,725' 12 spf Perfed 1/26/93 Isolated _7 Tyonek 8,745' - 8,768' 12 spf Perfed 1/26/93 Isolated 1M 15 8,783' 8,803' 12 spf Perfed 1/26/93 Isolated I. 8,815' 8,875' 12 spf Perfed 1/26/93 Isolated 161 17 R 18- 19 Tagged ill@ — 8,851' (7/72'09) — 0 0 20 0 7 " @9,15Z t A TD x,170' FEUD = 9,078 IRU 41 -01 Actual Well Schematic 11- 17- 11.doc Updated by CVK 11 -17 -11 Chevron • Chevron - Alaska Daily Operations Summary Well Name Legal Well Name [Lease Surface UWI ;ChevNo Original RKB (ft) 'Water Depth (ft) IRU 41 -01 IVAN RIVER UNIT 41 -01 jADL0032930 5028320088 QU1525 51.00 Primary Job Type Job Category Objective Actual Start Date Actual End Date - Completion - Reconfigure Major Rig 7/29/2011 8/18/2011 Work Over (MRWO) Primary Wellbore Affected Wellbore UWI Well Permit Number IRU 41 -01 502832008800 1921090 Daily "Qsiroi u 7/31/2011 00:00 - 811/2011 00:00 Operations Summary RU Key Pulling Unit. Test annulus to 1,500 psi for 30 min. N/D Tree. N/U BOPE. AOGCC witness waived by Jim Regg. 8/112011 00:00 - 8/212011 00:00 Operations Summary Continue NU BOPE. Perform initial BOPE test. Test annular to 250 psi low/ 2,500 psi high. Test BOPE to 250 psi low/ 3,000 psi high. RU and pull 1 -1/2" heater string. 8/2/2011 00:00 - 8/3/2011 00:00 Operations Summary Continue to pull 1 -1/2" heater string. RU slickline. RU lubricator and test to 2,500 psi. RIH and engage WRP plug at 303' WLM. POOH and recover WRP plug. Bullhead lease water down tubing, well on vacuum. RIH w/ 2.30" GR to 8,630' WLM. POOH. RU wireline. RU lubricator and test to 3,000 psi. RIH w/ 6' 1- 9/16" tubing punch and punch tubing from 8,614' to 8,620' WLM. POOH w/ tubing punch and tools stuck at 5,584' WLM. Bullhead lease water down tubing. Tools came free. Continue POOH. Tools stuck at 2,444' WLM. Work tools up to 2,405' WLM. Bullhead 25 bbl lease water. MU Kinley cutter on wireline and drop in hole. 8/3/2011 00:00.8/4/2011 00:00 Operations Summary Kinley cutter fired and cut wireline. Pull remaining line. RU slickline. RU and test lubricator to 250psi low/ 3,000psi high. RIH w/ baited wire grab. Set down at 1,977' SLM. Unable to jar fish free. Shear release POOH. Bullhead 57 bbl lease water down tubing. RD slickline. RU wireline. Test lubricator to 250psi low/ 3,000psi high. RIH w/ 6' tubing punch. Punch tubing from 1,939' - 1,945' WLM. POOH. RIH w/ 1- 11/16" radial torch. Cut tubing at 1,930' WLM. POOH. RD wireline. MU landing joint and pull tubing hanger. POOH. UD cut tubing. 8/4/2011 00:00 - 8/8/2011 00:00 Operations Summary PU 6" OD cutter BHA. RIH on 3 -1/2" workstring. Tag cut tubing at 1,933' DPM. Work over tubing to 2,371' DPM. Make OD cut at 2,385' DPM. POOH. L/D cut tubing and OD cutter BHA. 8/5/2011 00:00 - 8/6/2011 00:00 Operations Summary Make overshot BHA. RIH on 3 -1/2" workstring. Latch tubing at 2,378' DPM. Work overpull to release FH packer. RU wireline. RU lubricator and test to 250psi low/ 3,000psi high. RIH w/ radial torch and cut pipe at 8,609' WLM. POOH. RD wireline. POOH. L/D tubing. 8/6/2011 00 :00 - 8/7/2011 00:00 Operations Summary Continue to L/D cut tubing. PU casing scraper BHA. RIH on 3 -1/2" workstring. Tag top of cut joint at 8,601' DPM w/ 10K down. Mix and circulated a 155 bbl casing wash train. POOH. 8/7/2011 00:00 - 8/8/2011 00:00 Operations Summary L/D casing scraper BHA. PU 7" cement retainer. RIH on 3 -1/2" workstring. Tag cut tubing at 8,601' DPM (8,613' Orig RKB). PU and set cement retainer at 8,585' DPM (8,597' Orig RKB). Stab into cement retainer and set down w/ 15K. Perform injectivity test into perfs at 3 bpm at 3,000 psi. Test annulus to 1,500 psi for 15 min. Mix and pump 20 bbl (83.2 sx) 15.3 ppg EasyBLOK cement. Pump 10 bbl cement below retainer. Calculated TOC at 8,316' DPM (8,328' Orig RKB). Unsting from cement retainer and lay 10 bbl cement above retainer and PU 400' above retainer. Reverse circulate and get 1/2 bbl cement returns at bottoms up. Displace well over to 8.8 ppg 9% KCI. POOH. 8/8/2011 00:00 - 8/9/2011 00:00 Operations Summary POOH. L/D 3 -1/2" workstring. UD cement retainer running tool. PU 4 -5/8" TCP, 7" packer and 2 -7/8" 6.4 #/ L -80 tubing. RIH w/ completion. Place TCP guns on depth. RU wireline. RU lubricator and test to 250psi low /3,000psi high. RIH w/ GR /CCL to 5,900' WLM. Correlate TCP on depth. POOH. R/D wireline. 8/9/2011 00:00 - 8/10/2011 00:00 Operations Summary Space out and land completion. Test tubing hanger to 250psi low/ 2,800psi high. RU wireline. RU and test lubricator to 250psi low/ 3,000psi high. RIH w/ GR/CCL to 5,900' WLM. Correlate TCP on depth to re- confirm. POOH. R/D wireline. RU slickline. RU and test lubricator to 250psi low/ 4,000psi high. RIH and set PX plug in X profile at 5,428' Orig RKB. Pressure up to 4,000 psi to set packer at 5,374' Orig RKB. Pressure leaking off, no flow from annulus. No surface leaks noted, possible PX plug leaking. Test annulus to 1,500 psi. RIH w/ slickline and recover PX plug. RIH and set new PX plug in X- profile at 5,428' Orig RKB. Test tubing to 4,000 psi - failed (Bled to 2,400 psi in 30 min, no response on annulus, possible leak below packer). RIH and open sliding sleeve at 5,327' Orig RKB. Displace annulus with glycol. Ran 20 bbl short, leaving 20 bbl 9% KCI in annulus. Plan to displace out 9% KCI using heater string when new glycol gets on location. RIH and close sliding sleeve. POOH. R/D slickline. • Chevron Chevron - Alaska Daily Operations Summary Well Name Legal Well Name Lease 'Surface UWI 'ChevNo Original RKB (ft) Water Depth (ft) IRU 41 -01 IVAN RIVER UNIT 41 -01 ADL0032930 ; 5028320088 1QU1525 51.00 Dai r Operation 8110/2011 00:00 - 8/11 /2011 00:00 Operations Summary Run and land 1 -1/2" J -55 heater string at 2,994'. Set BPV in long string and heater string. ND BOPE. NU Tree. Pull BPVs. Set TWC in long string and heater string. Test tree to 250psi low /5,000psi high. RU slickline. RU lubricator and test to 250psi low /3,000psi high. RIH and pull PX plug. RD slickline. Pressure up and test tubing to 2,500 psi for 30 min. Test casing annulus to 2,200 psi for 30 min. RU slickline. RU lubricator and test to 250psi low /3,000psi high. RIH w/ 2 -7/8" swab cups, Swab well to 600' SLM. 8/11/2011 00:00 - 8112/2011 00:00 Operations Summary Continue to swab fluid down to 5,296' SLM. RD slickline. RD Key Energy Pulling Unit for demobilization. 8/12/2011 00:00 - 8/1312011 00:00 . Operations Summary Continue rig down and demobe. 8/13/2011 00:00 - 8/1412011 00:00 Operations Summary Continue rig down and demobe. 8/14/2011 00:00 - 8/18/2011 00:00 Operations Summary Continue rig down and demobe. 8/15/2011 00:00 - 8/16/2011 00:00 Operations Summary No operations 8/16/2011 00:00 - 8/17/2011 00:00 Operations Summary No operations 8/17/2011 00:00 - 8/18/2011.00:00 Operations Summary COSTS ONLY 11/2/2011 00:00 -.11/3/2011 00:00 Operations Summary RU lubricator, drop bar, perforated 73 -4 sand from 5,977' to 5,987' w/ 5spf 4 -5/8" ZTCP guns, RD. Turn well over to production. • • • )1 (1[F ic\Lici,\EA SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMl�IISSION ANCHORAGE, ALASKA 99501 -3539 L PHONE (907) 279 -1433 FAX (907) 276 -7542 Timothy C. Brandenburg � Drilling Manager q 9-4 tI Union Oil Company of California P.O. Box 196247 Anchorage, AK 99519 Re: Ivan River Field, Undefined Gas Pool, Ivan River Unit 41 -01 Sundry Number: 311 -227 Dear Mr. Brandenburg: . randenburg: ` t ` ` ? i 1 Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, L 4, I Daniel T. Seamount, Jr. St Chair DATED this 2 - 1 day of July, 2011. Encl. • • Chevron Timothy C Brandenburg Union Oil Company of California %011 Drilling Manager P.O. Box 196427 Anchorage, AK 99519 -6247 Tel 907 263 7657 %. Fax 907 263 78888 4 Email brandenburgt @chevron.com July 13, 2011 F E C E*\itt b a Commissioner Alaska Oil & Gas Conservation Commission ,_ : .; #' i vi _ WK . , s? 6114. &.iiiiliiiSSion 333 W. 7`" Avenue, Suite 100 r;r °'.j? 06 Anchorage, Alaska 99501 -3572 Re: Ivan River Unit 41 -01 PTD: 192 -109 Plugback and Recompletion, Application for Sundry Approval Dear Commissioner 1 I I Enclosed is an Application for Sundry Approval (Form 10 -403) for the above referenced well. The outlined / workover is for the plugback of a shut -in gas well and completing the well uphole at a new sand in the same pool, scheduled to start August 2nd We would like to request a variance from requirements of 20 AAC 25.035(e)(1)(A), requiring BOPs for each size of tubing to be run in the well. We are planning - rG n`a` preventer stackup. From top to bottom, we will run an annular preventer, blind rams, a 2- 7/8 "x5' iariable pipe rams. The long string will be 2 -7/8" and the heater string will be 1 -1/2 ". Curren a are no variable rams available to close n 1 -1/2" tubing. Lease water will be pumped down the heater string annulus to displace the glycol currently above the FH packer at 3,034' and the annulus tested to 1,500 psi prior to mobilizing the pulling unit. The 1 -1/2" heater string will be pulled before removing the FH packer at 3,034'. In the event of a need to shut -in during removal of the heater string, the rig crew will have a joint of 2 -7/8" tubing with a 1 - 1/2" crossover ready to place across the 2- 7/8 "x5" variable rams or the annular preventer to be able to close in on the well if necessary. Therefore, pulling of the heater string separately without a 1 -1/2" pipe ram should not present a risk to well control. Due to the proximity of the Key Energy pulling unit to the well IRU 14 -31 (PTD 175 -008), we will keep this _ well in a shut -in status for the duration of our workover program at Ivan River which is expected to last into mid - August. This well is historically used for produced water disposal. During the workover program, we will be utilizing IRU 13 -31 (PTD 192 -088) for disposal injection purposes. This well is currently being used in the place of IRU 14 -31 for produced water disposal during our workover program. If you have any questions pertaining to this variance, please contact Stan Porhola 907 - 263 -7640. Z____ c Timothy C. Brandenburg / Drilling Manager Enclosure Cc: Well File Union Oil Company of California / A Chevron Company • 1,21-i � < - it t i 1 111 STATE OF ALASKA t ,1,� ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALSAi z "" ' & C Ci . = rrtmission 20 AAC 25.280 1rir tIr?n;j 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Change Approved Program ❑ Suspend ❑ Plug Perforations 0 . Perforate 0 - Pull Tubing Ei • Time Extension ❑ Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other: ❑ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Union Oil Company of California Development 0 . Exploratory ❑ 192 -109 • 3. Address: Stratigraphic ❑ Service ❑ 6. API Number: PO Box 196247, Anchorage, AK 99519 50- 283 - 20088 -00 . 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes ❑ No El Ivan River Unit 41 -01 9. Property Designation (Lease Number): 10. Field / Pool(s): ADL032930 River Unit) Ivan River Field/ Undefined Gas • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): / Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 9,170 • 8,282 . 8,851 7,995 N/A 8,851 (Fill) Casing Length Size MD % TVD Burst Collapse Conductor 165' 20" 165' 164' Surface 895' 13 -3/8" 895' 894' 3,450psi 1,950psi Intermediate 3,498' 9 -5/8" 3,498' 3,335' 6,870psi 4,750psi Production 9,152' 7" 9,152' 8,266' 8,160psi 7,020psi Perforation Depth MD (ft): J Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 8,710- 8,725, 8,785- 8,768, 8,783- 7,868- 7,881, 7,899- 7,920, 7,933- 2 - 7/8" & 1 6.4 #, N - & 2.75 #, J - 8,693 & 2,994 8,803, 8,815 -8,875 7,952, 7,962 -8,016 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): / Baker FH Retrievable and 3H Packers & N/A 3,034/ 8,630 MD (2,936/ 7,795 TVD) & N/A 12. Attachments: Description Summary of Proposal 151 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch In Exploratory ❑ Development Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 8/21,2011 Oil ❑ Gas 0° WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: WI NJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: N/A GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Stan Porhola 263 -7640 Printed Name Timothy C. Brandenburg Title Drilling Manager - "" Signature L -''--. Phone 276 -7600 Date 7/13/2011 / COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 311-a-97 Plug Integrity ❑ BOP Test [1 f Mechanical Integrity Test ❑ Location Clearance ❑ Other: ?Kr 5u aw'E to 20 Alf L IT. 2 $S C& , aL vi.t& 'e 730 Pt h AffJrOvcd Test tad P E to 3000 COL... i et( o +€o "� .14 sf to H. i orw,_ fo 'forage r.1e4 DrAe►r ado. otI.oco . Subsequent Form Required: 10 _ 4 - 1 APPROVED BY Approved by: j COMMISSIONER THE COMMISSION Date: 7) Z/ 1 JUL 1 ' 7 Form 10 -403 Revised 1/2010 n R 1 G 11 Aill2MS Submit in Duplicate 5� 1 • • Chevron Ivan River Unit MN. IRU 41 -01 IIIII0 7 -06 -2011 Objective: • Pull current completion and abandon existing zones; Re- complete uphole. Current BHP: 1,023 psi c@ 7,891' TVD 2.5ppg EMW • Maximum 7' psi @ 5,443' TVD 8.6ppg EMW (Based on non - depleted Beluga 73-4 sand) • MASP: 2462 p ased on actual reservoir conditions of the Beluga 73 -4 sand and dry gas (0.56 sp gr) gradient (0 0 si /ft) to surface) Procedure Summary: 1. MIRU Key Energy Rig #3. 2. Kill well with 8.4 ppg lease water. Install BPV, ND tree. ■ 3. NU BOPE & test same 250psi low/ 3,000psi high, Test annular to 250psi low/ 2,500psi high. Contingency: If unable to thread test joint into hanger, anchor test joint to bottom rams to test. / 4. Pull BPV. Pull 1 -1/2" heater string. (Displace glycol above FH packer with water prior to rig). 5. Pull on 2 -7/8" production string to unset FH packer at 3,034'. 6. Pump 8.4ppg lease water down tubing and annulus. 7. RU E -line. RIH and cut tubing at 8,607' ( + / -) 8. Pull 2 -7/8" production tubing from cut depth of 8,607' ( + / -). 9. PU 7" casing scraper and tag cut tubing above 3H packer at 8,607' ( + / -). 10. PU Cement Retainer. Set Cement Retainer above tubing cut above 3H packer at 8,600' ( + / -). 11. Tag Cement Retainer w/ 10k to confirm set. 12. Mix and pump 10 to(1�b1 +/- 15.3ppg cement below retainer. Spo4 bbl on top of Retainer. Wait on cement. 13. RIH with 10' of 4 -5/8" TCP guns and 7" Premier packer and 2 -7/8" completion tubing. 14. Correlate on depth and set packer at 5,370' ( + / -). Note: TCP guns will be correlated to perforate the following intervals: Beluga 73 -4 from 5,982'( + / -) to 5,992'( + / -) . v 15. RU slickline. RIH and set PX plug in profile below Premier Packer at 5,405' ( + / -). 16. Pressure up tubing and set packer. Test tubing to psi for 30 min. Pull PX plug. 17. Test annulus to Premier Packer at 5,370' ( + / -) to 1;500 psi for 30 min. 18. Set BPV. ND BOPE. Pull BPV. Set TWC. NU and test tree. 250psi Low/ 5,000psi High. Pull TWC. 19. Release Key Energy Rig #3. Post -rig: Drop bar to fire TCP guns. Turn well over to production. 07/06/2011 SP evro 7 1R T 41_01 Ivan River Unit lJ Well IRU 41 -01 �� Actual Wellb Schematic St Completed 1/26/93 pdated 7/22109 RKB: 51' KB AMSL RT- THF:24'KB Casing and Tubing Detail i _ N.--/ / k 1 Size Type Wt/ Grade Top Btm CONN / ID Cement / Other 25'@ 20" Conductor 94# Surface 165' Driven 165 13 -3/8" Surface 68 #, K -55 Surface 895' Butt / 12.415" 212 bbl / Cmt to Surface Q 9 -5/8" Intermediate 47 #, N -80 Surface 144' 47 #, S-95 144' 3,498' Butt / 8.681" Butt / 8.681" 281 bbl / Cmt to Surface 133/5" 7" Production 29 #, N -80 Surface 9,152' Butt / 6.184" 171 bbl / Cmt to 5,000' @895 Tubing 2 -7/8" Production 6.4 #, N -80 Surface 8,693' IBT- Mod/2.441" 7 % 1 -1/2" Heater 2.75 #, J -55 _ Surface 2,994' 10RD Fluid: Propelyne Glycol 2 r W / _ 6t Production String Jewelry Detail # Depth (RKB) Length ID OD Item a 3 a 1 24.20' Dual Tubing Hanger, 2 -7/8" x 2 -3/8" 12" 5M 95/8" @ National (2 -7/8" & 2 -3/8" 8RD lift threads) 3,488 2 2,988' 4.00' 2.313" 3.750" Baker CMU Sliding Sleeve 3 3,034' 5.71' 2.441" 5.968" Baker FH Retrievable Packer (40K shear) 4 8,628' 0.66' 2.441" 3.750" XO, 2 -7/8" IBT Box x 3-1/2" EUE 8RD Pin 5 8,629' 0.78' 3.250" 5.000" Anchor Latch Seal Assembly C8LTop: Baker 3H Packer w/ mill out extension (Min ID 6 8,630' 4.78' 3.250" 5.968" thru Anchor Latch Seal Assembly) 7 8,640' 0.84' 2.441" 5.000" XO, 4 -1/2" 8RD Box x 2 -7/8" IBT Pin 8 8,643' 0.67' 2.441" 3.500" Baker "RA" Sub 9 8,650' 1.24' 2.250" 3.500" Baker R Profile w/ No -go 10 8,659' 0.63' 2.441" 3.687" Baker Ported Sub w/ glass disc 11 8,693' 0.82' 2.441" 3.687" Tubing Tail 12 8,895' (est) 183' 3.687" FISH: Baker TCP Drop Off Guns Perforation Data ZONE TOP BTM Shot Condition 8,710' 8,725' 12 spf Perfed 1/26/93 Tyonek 8,745' 8,768' 12 spf Perfed 1/26/93 8,783' 8,803' 12 spf Perfed 1/26/93 8,815' 8,875' 12 spf Perfed 1/26/93 4 • Ran Expro Camera 7/15/09 to investigate tubing tail obstruction. Tool stopped in 6' pup 1 5 joint between Baker RA Sub & R Profile. '0' 6 • Ran RST log above production packer from 8,634' - 5,000' on 7/15/09. • Tagged fill at 8,851' RKB w/ 1.25" GR on 1" knuckled tool string on 7/22/09. 7 • Packer fluid between packers consists of 10% KCL Brine (8.9ppg). 8 IRA • Heater string fluid consists of glycol for freeze protect. 9 R 10=, 11 Tagged fill @ 8,851' (7/72/09) , 0 12 0 7" @9,152 / - TD x,170' PB1D = 9,078' IRU 41 -01 Actual Well Schematic 7- 22- 09.doc Updated by STP 7 -08 -11 evro r. n River Unit IRU 41-01 ell IRU 41 -01 44'4'4./11°. PR OPOSED SCHEMATIC op osed 7/08/11 RIB: BY KBftM L RT : Casing and Tubing Detail . k ii - - 1 Size Type Wt/ Grade Top Btm CONN / ID Cement / Other 20" Conductor 94# Surface 165' Driven 166 13 -3/8" Surface 68 #, K -55 Surface 895' Butt / 12.415" 212 bbl / Cmt to Surface 9-5/8" Intermediate 47 #, N -80 Surface 144' Butt / 8.681" 281 bbl / Cmt to Surface 47 #, S -95 144' 3,498' Butt / 8.681" 1330 7" Production 29 #, N -80 Surface _ 9,152' Butt / 6.184" 171 bbl / Cmt to 5,000' @896 Tubing 2 -7/8" Production 6.4 #, L -80 Surface +/- 5,950' IBT- Mod /2.441" 1 -1/2" Heater 2.75 #, J -55 Surface 2,994' 1ORD Fluid: Propelyne Glycol E 9 @ Production String Jewelry Detail 3 I # Depth (RKB) Length ID OD Item is 2 Dual Tubing Hanger, 2 -7/8" x 2 -3/8" 12" 5M Mar 1 24.20' 1.00' 2.441" 12.00" National (2 -7/8" & 2 -3/8" 8RD lift threads) CBL Top: 600O3 ' ■ _ 3 2 +/- 5,364' 6.00' 2.441" 5.000" XO, 2 -7/8" IBT Box x 4 -1/2" EUE 8RD Pin j` 1 3 +/- 5,370' 6.00' 2.441" 5.968" Premier Packer VW ),,1 di 4 4 +/- 5,376' 4.00' 2.441" 5.000" XO, 4 -1/2" EUE 8RD Box x 2 -7/8" IBT Pin f 5 +/- 5,405' 1.50' 2.313" 3.500" Baker X Profile (2.313" Min ID) `s' 5 6 +/- 5,600' 1.50' 2.350" 3.500" Auto - release 0 7 +/- 5,9 0.75' 2.441" 3.500" Ported Sub ,x 8 +/- 95 0.50' 2.441" 3.687" WLEG 6 9 +/- , 30' 20.00' - - Dropped TCP Assembly 'i 10 +/- 8,600' 2.00' - - Cement Retainer capped w/ 50' cement 11 +/- 8,607' 2.441" 3.500" Cut tubing stub if HE 7 12 8,628' 0.66' 2.441" 3.750" XO, 2 -7/8" IBT Box x 3-1/2" EUE 8RD Pin 13 8,629' 4.78' 3.250" 5.968" Baker 3H Packer w/ mill out extension (Min ID 4 r 8 thru Anchor Latch Seal Assembly) i:1 = lqi, 14 8,640' 0.84' 2.441" 5.000" X0, 4-1/2" 8RD Box x 2 -7/8" IBT Pin VI r 15 8,643' 0.67' 2.441" 3.500" Baker "RA" Sub 16 8,650' 1.24' 2.250" 3.500" Baker R Profile w/ No -go f or 9 17 8,659' 0.63' 2.441" 3.687" Baker Ported Sub w/ glass disc P 18 8,693' 0.82' 2.441" 3.687" Tubing Tail *' 1 3 19 8,895' (est) 183' 3.687" FISH: Baker TCP Drop Off Guns 10 ,' Perforation Data .'t ZONE TOP BTM Shot Condition fit, 73-4 +/- 5,982' +/- 5,992' 12 spf 4 -5 /8" TCP (Proposed) 13 8,710' 8,725' 12 spf Perfed 1/26/93 Isolated Tyonek 8,745' 8,768' 12 spf Perfed 1/26/93 Isolated 14 8,783' 8,803' 12 spf Perfed 1/26/93 Isolated 8,815' 8,875' 12 spf Perfed 1/26/93 Isolated 15 RA 161 R 17 18 1 Tegged 10 @ 8,891' (712209) - 4 19 /2/- O 7" @9,152 . - , 1D x,170' PBTD = 9,078 IRU 41 -01 Proposed Well Schematic 7- 08- 11.doc Updated by STP 7 -08 -11 Chevron • • %110 Summary of Key Energy Riq #3 Specifics IRU 41 -01 Plugback and Recompletion The IRU 41 -01 workover will involve pulling the existing completion, abandoning the lower zones and running a completion to the Beluga 73 -4 zone for a gas completion. The rig specifics are for the planned rig up on this well and are likely to change from well to well. Proposed Configuration Rig Model The rig model is a Hopper Hydra- hoist, Back -model GXXTA. Drawworks The drawworks are GXXTA -MD 10x42; w/ Sand Drum 15,000 ft — 9/16" sand line. Derrick The derrick is a 102' tall telescoping double, with 260,000 lb capacity, 30" crown sheaves and McKissick 30" 150 ton 73A traveling block. Pipe Handling The pipe handling system is a Pipe Wrangler, 45' long, 8.5' wide, 9' high. The base beam is internally guided and load bearing. The beam is load rated with 102' derrick and 10,000 of 2 -7/8" tubing to 58 mph winds. BOP SpecificatiOns Annular, 5M 13/8" Hydril GK Single gate, 5M, 13 -5/8" Shaffer SL w/ blind ram Mud Cross, 5M, "13r5/8" w/ 2 each 3 -1/8" 5M x 2- 1/16" 5M Double Studded Adapters Single gate, 5M, 7-5/8" Shaffer SL w/ pipe ram (2 -7/8 ", 3 -1/2 ", or 2- 7/8 "x5" VBR rams) BOP Diagram See attached. Accumulator 240 gallon KOOMEY Accumulator System on an enclosed skid unit. Includes 7 functions with manual bypass and remote panel. Sixteen 15 gallon accumulator bottles. 462 gallon hydraulic tank with air operated hydraulic pump. Pits The pit consists of a 200 bbl tank partitioned into three isolatable compartments. An optional shale shaker is also available that is a 3'x4' Jr. Standard - hydraulic driven. Pumps The primary pump is a National JWS -400 7 "x4.5" Triplex rated to 5,000 psi on an independent skid. A secondary pump is a Gardner Denver PAH 8 "x4.5" Triplex rated to 4,000 psi on an independent skid. The primary pump will pull fluid directly from the pit. The discharge will be plumbed to kill line and an independent stand pipe line. The secondary pump will be used in conjunction with the primary pump as needed for increased flow rates and used for fluid disposal in well IRU 13 -31 (PTD 192 -088). Key Energy Rig #3 Specs (IRU 41 -01) rev0.doc 6/16/11 • Chevron I OW Kill Line The Kill Line /Circulating Line consists of 2 ", 5,000 psi hose with Unibolt/Hub- flanged connectors. Kill Line Valves The kill line valves consist of 2 ea. manually operated, 2- 1/16 ", 5M valves attached to the mud cross with co -flex hose with a Unibolt/Hub- flanged connectors. Choke Line The choke line consists of 2 ", 5,000 psi hose with Unibolt /Hub - flanged connectors. Choke Line Valves The choke line valves consist of 1 ea. manually operated, 2- 1/16" 5M valve and 1 ea. automatically operated HCR valve that is attached to the mud cross with co -flex hose with a Unibolt/Hub- flanged connectors. Choke Manifold See attached. Choke Return Line /Diffuser Line The diffuser line will consist of 2 ", 5,000 psi hose with Unibolt connections. The line will run from the choke manifold to the diffuser tank. Diffuser Tank A diffuser tank will be placed adjacent to the mud pits with the capability of fluid transfer to the circulating system. Trip Tank A trip tank will be placed adjacent to the rig with the capability of fluid transfer to the circulating system. Gas Detection There will be a gas LEL monitor and a H2S monitor placed at the work platform (rig floor), shale shaker, upper cellar area, and lower cellar area. d r ! . PVT There is no PVT system for the circulation system on this workover rig, as is standard practice in this type of well service work. Key Energy Rig #3 Specs (IRU 41 -01) rev0.doc 6/16/11 Chevron • West Side Ivan River 41 -01 07/06/2011 Key Stripper Head Assy 1.17' iil 1i•1 iii iii di .38' 4.54' • Hydril • GK 13 5/8 -5000 lit ill lii Shaffer SL 13 5/8 5M 13.21' Iwo= 1.44' - a _ �, 1g1 1o1 1 1 -��, �. 1 ki ll 'i • �� • ■ ■ �� ``!■ Vi' 14 4 i i - i ' ■ i Z i i _� lit ■Iti ■1lldil.lil • _ 2 1/16 54choke and kill lines "unibolt ends - - Shaffer SL 13 5/8 5M 4 1.44' TMETTlEnnPrtar Spool, 13 5/8 5M API hub 1.00' r \ X135 /8 "5M FE Adapter, NSCO, 13 5/8 5M API Hub X 7 1/16 5M top c oO X 2 1/16 X 2 9/16 5M, w/ O 1.50' GT pockets top and bottom Ground Level 0 • Chevron Ivan River 2011 Choke Manifold IWO 06/07/2011 Blooey Line To Gas Buster aria iiiiill l.l III 1SI U III zy.... WWI UMW .t. ooF i 00, _, / 0 / 0 I /,.,,, 1711-1 "1111110 i _ _ : iUI: ` I iiiP•mmillillE III III IP p _ o $ I . 00 0 0 ` Ill t., 0 G 0 � 0 p 0 . 0 - 0 - ^`. l O / 0 0 ` -__ _ " te 0 00/ �. mill. in fill r _ .0 / J 0 IV II • . , ,,t oo , i;,� c o ® 00 0 0 # c o o , ,,` o , IP O , 0 .. f c yl. Ali i�'. . a=': . II 11 IV Super Choke Q ..... ..., All valves 2 1/16 5M on ,,, r is . manifold stio ^`� Unibolt Connection 0 0 r ,00 Aubert, Winton G (DOA) From: PORHOLA, STAN T [stan.porhola @chevron.com] Sent: Thursday, June 30, 2011 9:22 AM To: Aubert, Winton G (DOA) Cc: Fouts, Tom [EMC Engineering] Subject: Gas Detection for Key Energy Rig #3 Winton, Per the sundry submitted for Ivan River Unit 44-36 (PTD 193 -022), I would like to update the Gas Detection systems used on the rig. The Key Energy Rig #3 will have a set of H and LEL monitors at the 4 following locations: Rig Floor, Shale Shaker, Upper Cellar Area, and Lower Cellar Area. (Futureundry submittals involving the Key Energy Rig #3 will reflect these specifications. Stan Porhola* Drilling Engineer MidContinent/Alaska Business Unit Chevron North America Exploration and Production 3800 Centerpoint Dr. Suite 100 Anchorage, AK 99503 Tel 907 263 7640 Fax 907 263 7884 CeII 907 229 1769 is 1 ON OR BEFO I a. TEST' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION ~,o,¢IMISSION COMM GAS WELL OPEN FLOW POTENTIAL TEST REPORTs ENG lb. TYPE TEST MULTIPOINT OTHER. STABILIZED ~] NC c( INITIAL ANNUAL SPECIAL ~t. MM COMM 2. Name of Operator 7. Permit No. Union Oil Company of California (Unocal) f/92-109~ 3. Address 8. APl Numb~L.__.~ P.O. Box 196247, Anchorage, AK 99519-6247 50-283-20088-00 4. Location of Well 1, T13N, R9W, SM 712' FSL, 737' FEL, SEC. 6. Lease Designation and Serial No. ADL 32930 STAT 9. Unit or Lease Name STAT TEC~ Ivan River Uni 10. Well Number 41-1 11. Field and Pool 5. Elevation in feet (indicate KB, DF etc.) RKB' 51' 12. Completion Date 113. Total Depth 114. Plugback T.D. 1-25-93 I 9,170' I 9,078' 16. Csg. Size Weight per foot, lb. I.D. in inches Set at ft. 7" 29 6. 184 9,152 Ivan River/Tyonek 17. Tbg. Size Weight per foot, lb. I.D. in inches Set at ft. 2 7/8" 6.4 2.441 8,693 18. Packer set at ft. 119. GOR cf/bbl. I 20. APl Liquid Hydrocarbons I I 3,034 8,629 22. Producing thru: Reservoir Temp. o F. Tbg. [] Csg. [] I1 5. Type Completion (Describe) Single String/Gas Perforations: From8,710 To 8,725 8,745 8,768 8,783 8,803 8,815 8,875 21. Specific Gravity Flowing fluid (G) f~-6 Mean Annual Temp. o F. Barometric Pressure (Pa), psia 23. Length of flow channel (L) I Vertical Depth (H) ! Go. ! %CO? ! "" N2 % H2S Prover Meter run Taps 8,693'! 7,855' I I I I I 24. Flow Data Tubing Data Casing Data Duration of Prover Choke Pressure Diff. Temp. Pressure Temp. Pressure Temp. I Line X Orifice Flow No. Size (in.) Size (in.) psig hw '° F. psig ° F. psig o F. Hr. 1. ~.n?R ?_n 1065 7,5 80 3222 60 0 - 2 2. 6.025 ~]6 1065 25.4 65 3152 60 0 - 2 3. 6.025 2,5 1065 i 26.0 60 3091 60 0 - 211 4. 6.025 2.5 1065I 56 2 I 52 2841 60 0 - 2 ' ! [ Basic Coefficient -- f Flow Temp. Gravity Super Comp. Pressure Factor Factor Factor Rate of Flow (24-Hour)--~ hwPm Pm Q, Mcfd No. Fb or Fp Ft Fg Fpv 1. 28 89.37 1065 - - - 2502 2. I 28.5 164.4 1065 - - - 4685 3. 45.3 166.4 1065 _ i _ i _ 7538 4. 45.6 244.6 1065 - i - - 11153 5. I I for Separator for Flowing pr Temperaturei T Tr Z Gas Fluid No. Gg G 1. I 9. 3. ~Z C~'~ ~,~ CriticalPressure Critical Temperature 5. ,- ,.~ ~- ,~#~ __ __ Form 10-421 Rev. 7-1-80 .Alaska~il & $~tS U0iiS, (~,Ol?tfi~'~T~ED ON REVERSE SIDE Submit in duplicate Pc No. , , Pt 3222 3152 3091 9836 Pc2 10,640,644 Pt2 [0381284 9935104 pc2 . pt2 259,36C 705,54C 1,086,363 2,597~74e Pw 3887 Pw2 15108769 pc2 - pw2 -4468125 3887 15108769 -4468125 3887 15108769 3aa7 lglNa7~q -4468125 -4468125 Pf Ps 3862 25. 9554281 8042896 3262 AOF (Mcfd).400, 100 Remarks: I hereby certify that the foregoing is true and correct to the best of my knowledge Signed ~ ~ .Title 3838 3819 3797 384O ,Ips2 ! 14915044 14730244 !14584761 14417209 Date /-~ ~/" ? ~' . pi214,745,6~ Pi2 _ ps2 -169,494 1.5,356 160~839 1328,391 n 1. 1716 AOF Fb Fp Fg Fpv Ft G Gg GOR .hw H L n Pa Pc Pf Pm Pr Ps Pt Pw Q Tr T Z DEFINITIONS OF SYMBOLS Absolute Open Flow Potential. Rate of Flow that would be obtained if the bottom hole pressure opposite the producing face were reduced to zero psia. Basic orifice factor Mcfd/~..J hwPm Basic critical flow prover or positive choke factor Mcfd/psia Specific gravity factor, dimensionless Super compressibility- factor=-x./1/z dimensionless Flowing temperature factor, dimensionless Specific gravity of flowing fluid (air=l .000), dimensionless Specific Gravity of separator gas (air=l .00), dimensionless Gas-oil ratio, cu. ft. of gas (14.65 psia and 60 degrees F.) per barrel oil (60 degrees F.) Meter differential pressure, inches of water Vertical depth corresponding to L, feet (TVD) Length of flow channel, feet (MD) Exponent (slope) of back-pressure equation, dimensionless Field barometric pressure, psia Shut-in wellhead pressure, psia Shut-in pressure at vertical depth H, psia Static pressure at point of gas measurement, psia Reduced pressure, dimensionless Flowing pressure at vertical depth H, psia Flowing wellhead pressure, psia Static column wellhead pressure corresponding to Pt, psia Rate of flow, Mcfd (14.65 psia and 60 degrees F.) Reduced temperature, dimensionless Absolute temperature, degrees Rankin Compressibility factor, dimensionless Recommended procedures for tests and calculations may be found in the Manual Of Back-Pressure Testing Of Gas Wells, Interstate Oil Compact Commission, Oklahoma City, Oklahoma. Form 10-421 Unocal North American Oil & Gas Division Unocal Corporation P.O. Box 190247 Anchorage, Alaska 99519-0247 Telephone (907) 276-7600 UNOCAL ) Alaska Region DOCUMENT TRANSMITTAL Feburary 11, 1993 TO: Larry Grant LOCATION: 3001 PORCUPINE DRIVE ANCHORAGE, AK 99501 ALASKA OIL & GAS CONSERVATION COMM. FROM: Eric Graven LOCATION: P.O.BOX 196247 ANCHORAGE AK 99519 UNOCAL TRANSMITTING AS FOLLOWS IVAN RIVER 41-1 1 blueline and 1 sepia VI)ual Induction Focused Log W'BHC Acoustilog \ Gamma Ray \ Caliper ~,'4-Arm Caliper Log \ Gamma Ray W'Densilog \ Neutron \ Gamma Ray ~ffFormation Log - Mudlog V~BT \ Cement Map 17 JAN 93 ~,~BT \ Cement Map 21 JAN 93 Tape Survey--~xgOb RECEIVED MAR 1 9 1993 Alaska Oil & Gas Cons, Conlmlss/o~ PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COPY OF THIS DOCUMENT TRANSMIT~~. YO~~ RECEIVED BY: DATED: !;' .~ ..... STATE OF ALASKA . ~ ALASKA ~ ~ND GAS CONSERVATION COMMISS' WELL COMPLETION OR RECOMPLETION REF.. RT AND Classification of Service I ~ i 17'PermitNumbe, I_ . ~--__,/V~! I 92-109 l~ 18. AP~ Number 1. Status of Well OIL U GAS ~ SUSPENDED[~ 2. Name of Operator UNION OIL COMPANY OF CALIFORNIA (UNOCAL) 3. Address P.O. BOX 196247 ANCHORAGE, AK 99519 4. Location of well at surface 712' FSL, 737' FEL OF SEC. 1, T13N, RDW, ~,i.~~--' AtTop Producing Interval (8710') 3262'N, 768' FEL OF SEC. 1, T13N, i~W !'" ' ". At Total Depth (9170') 4174' FSL, EL OF SEC. 1, T13N, RDW, SM 9. Unit or Lease Name IVAN RIVER 10. Well Number 41-1 11. Field and Pool IVAN RIVER/UNNAMED 5. Elevation51,KB in feet (indicate KB, DF, etc.) 6. Lease DesignatiOnIvAN RIVERand Serial No. 12. Date Spudded 13. Date T.D. Reached 114. Date Comp., Susp. or Aband. 12/20/92 01/15/93 I 01/26/93 17. Total Depth (MD+TVD) 18. Plug Back Depth (MD+TVD) 119. Directional Survey 120. Depth where SSSV set 9170'-8283' 9078'-8209' lYES [~ NO E]I N/A feet MD 22. Type Electric or Other Logs Run CNL/C- DENSITY/DIL/BHC-ACOUSTIC/GR/SP SBT/GR/CCL 15. Water Depth, if offshore 116. No. of Completions N/A Feet MSLI 1 21. Thickness of Permafrost N/A 23. CASING, LINER AND CEMENTING RECORD I I I SETTING DEPTH MD CASING SIZE WT. PER FT. GRADE TOP BOTTOM HOLESIZE I CEMENTING RECORD 20" 94# WELDED 26' 165' DRIVEN 13-3/8" 68# K-55 26' 895' 17.5" 130 BBLS 9-5/8" 47# S-95, N-80 25' 3498' 12.25" 281 BBLS ?' 29# N-80 25' 10,350' 8.5" 171 BBLS I AMOUNT PULLED 24. Perforations open to Production (MD+TVD of Top and Bottom and interval, size and number) MD TVD 8710'-8725' 7867'-7882' 12 SPF, 0.5" 8745'-8768' 7899'-7921' 12 SPF, 0.5" 8783'-8803' 7934'-7952' 12 SPF, 0.5" 8815'-8875' 7963'-8017' 12 SPF, 0.5" 25. TUBING RECORD SIZE I DEPTH SET (MD) } PACKER SET (MD) 2-7/8" 8693' 8629'-3034' 1 - 1/2" 2994' N/A 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) [ AMOUNT & KIND OF MATERIAL USED N/A 27 PRODUCTION TEST Date First Production 2/22/93 Date of Test 2/22/93 Hours Tested Flow Tubing Casing Pressure Press. 2300 0 28. I Method of Operation (Flowing, gas lift, etc.) FLOWING IPRODUCTION FOF~ TEST PERIOD CALCULATED 24-HOUR RATE OIL-BBL OIL-BBL GAS-MCF GAS- M CF 6580 CORE DATA WATER- BBL WATER- BBL CHOKE SIZE GAS-OIL RATIO OIL GRAVITY-APl (corr) Bdef description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. NONE Form 10-407 rev. 7-1 - 80 CONTINUED ON REVERSE SIDE Submit in duplicate MAR 0 'j 199;¢ 0il & Gas Cons. Anchorage 29. ¢. - 30. : '% --.~GEOLOGIC MARKERS FORMATION TESTS · ; -, .~,;: .~,N,~E..' . ~ ' Include interval tested, pressure dat~, all fluids recovered and grlav~ty, ': '" .~ MEAS. DEPTH TRUE VERT. DEPTH GOR, and time of each phase. '~¢EEUG~ FM. " 5757 5217 NONE -TYONEK FM. : 8677 7787 -, 31. LIST OF ATTACHMENTS 32. I hereby(,~rtify~ect to the best of my knowledge Signed G. RUSSELL SCHMIDT Title DRILLING MANAGER Date 02/22/93 INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and Icg on all types of lands and leases in Alaska. Item 1' Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion Item 5' Indicatewhich elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments, Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21' Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). Item 23: Attach ed supplemental records for thiswell should show the details of any multiple stage cement- ing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water In- jection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". IVAN RIVER FIELD WELL 41-1 PRESENT 20' at 165' 13-3/8' at 895' HEATER STRING FLUID PROPELYNE GLYCOL SHORT STRING: 1-1/2' J-55, 10RD, TUBING @ 2x:J94' BAKER 'CMU' SLIDING SLEEVE AT 2988' BAKER 'FH' PACKER AT 3034' 9-5/8' at 3498' LONG STRING 2-7/8' N-80, ABC MODIFIED TUBING BAKER '3H' PACKER AT 8629' BAKER 'R' PROFILE AT 8650' TUBING TAIL AT 8893' TOF ESTIMATED AT 88,96' (DROP OFF GUNS) ETD AT 9O78' 7' CASING AT 9152' TD AT 9170' TYONEK GAS SANDS 871 O' - 8725' 8745' - 8768' 8783' - 8803' 8815' - 8875' Oil & Gas Cons. Corr, m~ss~ Anchors§e GRB 2-19-92 IVAN RIVER 41-1 IRU 41-1 9020 ' DaY 1 (12/20/92) 20" DRIVEN TO 165' 504 PSI CONT'D MOVING RIG. ACCEPT RIG @ 0600 HRS. FUNCTION TST. DIVERTER SPUDDED WELL AT 2030 HRS 12/20/92. DRILLED/OUT FM 55' TO 183'-17-1/2" HOLE. IRU 41-1 907 '/724 ' DAY 2 (12/21/92) 20" DRIVEN TO 165' 520 PSI DRILLED 17-1/2" DIRECTIONAL HOLE F/183' TO 907'. SHORT TRIP TO 20" SHOE. RIH TO 907'-NO FILL. POOH. RUN 13-3/8" CSG. IRU 41-1 907' DaY 3 (12/22/92) 20" DRIVEN TO 165' 13-3/8" @ 895' 488 PSI RAN 13-3/8" CSG TO 895'. STAB IN & CMT SAME W/108 BBLS LEAD AT 12.9 PPG PLUS 32 BBLS TAIL AT 15.8 PPG. CMT TO SURFACE. NIPPLE/DOWN 20" DIVERTER. MAR 0 1 Alaska Oil & Gar_, Cons. cornmissi~,n AnchoraOe IRU 41-1 907' DaY 4-8 (12/23-28/92) 20" DRIVEN TO 165' 13-3/8" @ 895' 484 PSI FINISH REMOVING 20" DIVERTER. INSTALLED BOPE. TEST BOPE, RIH DRILL FC, TST CSG NO TEST. DRILL SHOE & OPEN HOLE TO 917' CIRC. POOH. RIH WITH A 13-3/8" RTTS & SET @ 790', TAIL @ 883'. TEST ANNULUS TO 1500 PSI-OK. PERFORMED L.O.T. POOH. RIH TO 917'. DRILL 12-1/4" DIR HOLE FROM 917' TO 1396'. POOH F/MWD. RIH & DRILL 12-1/4" DIR HOLE FRM 1396' TO 2228'. CBU. POOH F/BIT & BHA. RIH & DRILL 12-1/4" DIR HOLE FRM/2228' TO 2903'. CBU. SHORT TRIP TO 1880. DRILL 12-1/4" DIR HOLE FRM/2903' TO 3147'. CBU. POOH F/BIT. IRU 41-1 3512' DaY 9 (12/29/92) 20" DRIVEN TO 165' 13-3/8" @ 895' 484 PSI RIH. REAMED 3013'-3147'. DRILLED 12-1/4" HOLE F/3147'-3512'. SHORT TRIP TO 857'. REAMED 3451'-3512'. CIRC. POOH. IRU 41-1 3512' DaY 10 (12/30/92) 20" DRIVEN TO 165' 13-3/8" @ 895' 9-5/8" @ 3498' 484 PSI CONT'D POOH. CHANGED FROM 5" TO 9-5/8" RAMS AND TESTED TO 2500 PSI, OK. RAN AND CEMENTED 9-5/8" CASING @ 3498'. CEMENT TO SURFACE CLEANED STACK AND WELL HEAD. IRU 41-1 5689/2177 ' DaY 11-15 (12/31/92-1/3/93) 20" DRIVEN TO 165' 13-3/8" @ 895' 9-5/8" @ 3498' 489 PSI WAIT ON CEMENT. P/U STACK AND SET EMERGENCY SLIPS. CUT 9- 5/8" CSG. INSTALLED PACKOFF AND TESTED, OK. INSTALLED BOPE. TESTED BOPE TO 5000 PSI, OK. CLEANED OUT CEMENT FROM 3425'- 3449'. TESTED 9-5/8" CSG TO 1500 PSI, OK. DRILLED OUT FLOAT TRACK AND NEW HOLE TO 3522'. PERFORMED L.O.T., OK. DRILLED 8-1/2" HOLE FROM 3522'-4050'. SHORT TRIP TO 3450'. DRILLED FROM 4050'-4355'. TRIP FOR BIT. DRILLED 8-1/2" HOLE WITH PDC BIT FROM 4355'-4981'. SHORT TRIP TO 3450'. DRILLED FROM 4981'-5195'. TRIP FOR MWD TOOL. DRILLED FROM 5195'-5689'. IRU 41-1 6140'/451' DaY 16 (1/4/93) 20" DRIVEN TO 165' 13-3/8" @ 895' 9-5/8" @ 3498' 510 PSI SHORT TRIP TO 3450'. DRILLED 8-1/2" HOLE FROM 5689'-5751'. HIGH CONNECTION GAS. WEIGHTED UP TO 9.8 PPG. DRILLED FROM 5751'-6043'. SHORT TRIP TO 3450'. DRILLED FROM 6043'-6140'. IRU 41-1 6369'/390' DaY 17 (1/5/93) 20" DRIVEN TO 165' 13-3/8" @ 895' 9-5/8" @ 3498' 515 PSI DRILLED 8-1/2" HOLE FROM 6140'-6369'. DRILLED FROM 6369'-6530'. SHORT TRIP TO 5216'. IRU 41-1 6725 '/195 ' DaY 18 (1/6/93) 20" DRIVEN TO 165' 13-3/8" @ 895' 9-5/8" @ 3498' 515 PSI DRILLED 8-1/2" HOLE FROM 6530'-6585'. TRIP FOR BIT. DRILLED FROM 6585'-6725'. IRU 41-1 7100'/375' DaY 19 (1/7/93) 20" DRIVEN TO 165' 13-3/8" @ 895' 9-5/8" @ 3498' 515 PSI DRILLED 8-1/2" HOLE FROM 6725'-6823'. FROM 6725'-7100'. SHORT TRIP. DRILLED IRU 41-1 7745'/645' DaY 20-22 (1/8-10/93) 20" DRIVEN TO 165' 13-3/8" @ 895' 9-5/8" @ 3498' 525 PSI DRILLED 8-1/2" HOLE FROM 7100'-7138'. POOH FOR BIT. TEST BOPE TO 5000 PSI, OK. RIH. DRILLED FROM 7138'-7177' WITH PDC BIT. TRIP FOR BIT. DRILLED FROM 7177'-7515'. CIRCULATED AND MADE SHORT TRIP-OK. DRILLED 8-1/2" HOLE FROM 7515'-7745'. IRU 41-1 8392'/275' DaY 24 (1/12/93) 20" DRIVEN TO 165' 13-3/8" @ 895' 9-5/8" @ 3498' 536 PSI DRILLED 8-1/2" HOLE FROM 8117'-8268'. CIRCULATED AND TRIPPED FOR BIT. DRILLED 8-1/2" HOLE FROM 8268'-8392'. IRU 41-1 8617 '/225 ' DaY 25 (1/13/93) 20" DRIVEN TO 165' 13-3/8" @ 895' 9-5/8" @ 3498' 536 PSI DRILLED 8-1/2" HOLE FROM 8392'-8594'. DRILLED 8-1/2" HOLE FROM 8594'-8617'. TRIP FOR WASHOUT. IRU 41-1 8977'/585' DaY 26 (1/14/93) 20" DRIVEN TO 165' 13-3/8" @ 895' 9-5/8" @ 3498' DRILLED 8-1/2" HOLE FROM 8617'-8965'. CIRCULATED AND MADE SHORT TRIP W/GOOD HOLE CONDITIONS. DRILLED 8-1/2" HOLE FROM 8965'-8977'. IRU 41-1 9170'/193' DaY 27-29 (1/15-17/93) 20" DRIVEN TO 165' 13-3/8" @ 895' 9-5/8" @ 3498' DRILLED 8-1/2" HOLE FROM 8977'-9170'. CIRC. SHORT TRIP TO 7350'. CIRC. POOH. RIGGED UP WIRELINE. LOGGED FROM 9168'- 3500' WITH CNL/C-DENSITY/DIL/BHC-ACOUSTIC/GR/SP. LOGGED FROM 9168'-3500' WITH 4-ARM CALIPER. RAN SBT LOG FROM 3495'- SURFACE, OK. RAN 64-ARM CASING CALIPER FROM 3495'-SURFACE; CASING CHECKED OK. RIH WITH 9-5/8" RTTS TO 3477' PRESSURE TESTED 9-5/8" CASING TO 4100' PSI, OK. POOH. RETRIEVED WEAR BUSHING. TESTED BOPE-OK. STAND BACK 7" LANDING JOINT AND PREP FOR WIPER TRIP. IRU 41-1 9170' DaY 30 (1/18/93) 20" DRIVEN TO 165' 13-3/8" @ 895' 9-5/8" @ 3498' SET WEAR-BUSHING. RUN IN TO T.D. AT 9170' (DPM) WITH TIGHT SPOTS AT 8407' AND 8432' AND 10 FT. FILL ON BOTTOM. CONDITION HOLE. MADE 20 STAND SHORT TRIP-OK. POOH TO RUN 7" CASING. IRU 41-1 9170 ' DaY 31 (1/19/93) 20" DRIVEN TO 165' 13-3/8" @ 895' 9-5/8" @ 3498' 7" @ 9152 ' 546 PSI PULL WEAR-BUSHING. INSTALL 7" CASING RAMS IN BOPE AND TEST. RAN 7" CASING TO 9152'. RECIPROCATE AND CIRCULATE CASING. ATTEMPTED TOLANDHANGER TO CHECK SPACE-OUT. 7" CASING STUCK- UNABLE TO RECIPROCATE. PUMPED CEMENT JOB: 171 BBLS TRINITY- LIGHT @ 12 PPG. IRU 41-1 9170' DaY 32 (1/20/93) 20" DRIVEN TO 165' 13-3/8" @ 895' 9-5/8" @ 3498' 7" @ 9152' 546 PSI BUMPED PLUG @ 0200 HRS. CHECKED FLOATS, OK. ATTEMPTED TO SET WELLHEAD PACKOFF SEAL WITHOUT SUCCESS. HANGER NOT SEATED. INJECTED 494 BBLS MUD, MUD DOWN 7" X 9-5/8" ANNULUS. LIFTED BOP STACK. FOUND BOW SPRING CENTRALIZER PARTS UNDER THE CASING HANGER PREVENTING IT FROM SEATING. IRU 41-1 9170' DaY 33 (1/21/93) 20" DRIVEN TO 165' 13-3/8" @ 895' 9-5/8" @ 3498' 7" @ 9152' 546 PSI SPEARED 7" CASING AT 35' RKB. REMOVED CENTRALIZER JUNK FROM WELLHEAD. LANDED CASING HANGER. INSTALLED AND TESTED BOPE TO 2200 PSI, OK. INSTALLED BOPE. CHANGED TO 2-7/8" RAMS. TESTED BOPE TO 5000 PSI, OK. RAN WEAR SLEEVE. BEGAN RUNNING SBT. IRU 41-1 9170 ' DaY 34-36 (1/22-24/93) 20" DRIVEN TO 165' 13-3/8" @ 895' 9-5/8" @ 3498' 7" @ 9152 ' COMPLETED RUNNING SBT/GR/CCL UNDER 1500 PSI FROM 9048'-4200'. RIH WITH 6" BIT AND A 7" CASING SCRAPER ON 2-7/8" TBG. WASHED FROM 9061'-9078'. CHANGED WELL OVER TO 10% KCL BRINE, BOTTOM 500' FILTERED. POOH AND STOOD BACK TBG. PRESSURE TESTED 7" CASING TO 1500 PSI, OK. RIH WITH TCP DROP OFF GUNS. RAN GR/CCL LOG AND PLACED GUNS ON DEPTH. HUNG OFF TUBING AND TESTED HGR TO 2500 PSI, OK. DISPLACED TUBING WITH FILTERED 10% KCL. SET CHECK VALVE IN THE "R" NIPPLE AT 8651'. SET BOTTOM PACKER AT 8629'. PRESSURE TESTED ANNULUS TO 750 PSI, OK. SET TOP PACKER AT 3034'. INSTALLED BPV. RAN 1-1/2" HEATER STRING TO 2994'. INSTALLED BPV. LAID DOWN 1/3 OF THE 5" DRILL PIPE. BEGAN REMOVING BOPE. IRU 41-1 9170' DaY 37 (1/25/93) 20" DRIVEN TO 165' 13-3/8" @ 895' 9-5/8" @ 3498' 7" @ 9152' CONT'D TO REMOVE BOPE. INSTALLED TREE AND TESTED TO 5000 PSI, OK. PULLED "RB2" CHECK VALVE AT 6581'. OPENED THE "CMU" SLEEVE AT 2987'. DISPLACED TUBING WITH FIELD GAS. IRU 41-1 9170' DaY 38 (1/26/93) 20" DRIVEN TO 165' 13-3/8" @ 895' 9-5/8" @ 3498' 7" @ 9152' FINAL TUBING DISPLACEMENT PRESSURE 1150 PSI. CLOSED SLIDING SLEEVE. REDUCED TUBING PRESSURE TO 650 PSI. DROPPED BAR. GUNS FIRED. UNLOADED WELL. PUT WELL IN TEST, 2.8 MMSCFPD @ 3145' PSI TP, O FLUID. L/D 5" DRILL PIPE. DISPLACED HEATER STRING AND ANNULUS WITH GLYCOL. INSTALLED BPV'S. CLEANED PITS. IRU 41-1 9170' DaY 39 (1/27/93) 20" DRIVEN TO 165' 13-3/8" @ 895' 9-5/8" @ 3498' 7" @ 9152 ' CONT'D CLEANING PITS. INSTALLED CELLAR FOR WELL #44-36. RELEASED RIG AT 0600 HRS FOR TURNKEY RIG MOVE. IRU 41-1 9170' DaY 40 (1/28/93) 20" DRIVEN TO 165' 13-3/8" @ 895' 9-5/8" @ 3498' 7" @ 9152' CONT'D WITH TURNKEY RIG MOVE TO WELL #14-31. UNOCAL Ivan River ,41-1 Ivan River Field,Cook Inlet, Alaska SURVEY LISTING Page 1 Your ref : PMSS <0-9170'> Last revised : 16-Jan-93 Measured Inctin. Azimuth True Vert. R E C T A N G U L A R Dogleg Vert Depth Degrees Degrees Depth C 0 0 R D I N A T E S Deg/lOOFt Sect 0.00 0.00 0.00 0.00 0.00 N 0.00 E 0.00 0.00 89.00 0.70 243.60 89.00 0.24 S 0.49 W 0.79 -0.25 187.00 2.10 243.60 186.97 1.31 S 2.63 W 1.43 -1.35 274.00 1.40 238.70 273.92 2.57 S 4.97 W 0.82 -2.64 374.00 1.20 246.00 373.90 3.63 S 6.97 W 0.26 -3.73 464.00 1.30 244.30 463.8,B 4.45 S 8.75 W 0.12 -4.58 554.00 1.10 229.20 553.86 5.46 S 10.32 W 0.41 -5.62 643.00 1.10 232.70 642.84 6.54 S 11.65 W 0.08 -6.71 732.00 1.00 220.00 731.83 7.65 S 12.83 W 0.28 -7.84 831.00 0.90 222.10 830.81 8.89 S 13.90 W 0.11 -9.10 886.00 0.90 220.70 885.81 9.54 S 14.48 W 0.04 -9.75 972.00 0.40 297.00 971.80 9.91 S 15.18 W 1.04 -10.14 1061.00 0.60 243.10 1060.80 9.98 S 15.88 W 0.55 -10.22 1151.00 0.90 201.40 1150.79 10.85 $ 16.55 W 0.67 -11.10 1242.00 1.50 192.60 1241.77 12.68 S 17.07 W 0.69 -12.94 1341.00 1.50 218.60 1340.74 14.96 S 18.16 W 0.68 -15.23 1432.00 0.40 316.40 1431.73 15.66 S 19.13 W 1.76 -15.95 1524.00 2.40 16.80 1523.70 13.58 S 18.79 W 2.42 -13.86 1615.00 5.20 11.20 1614.49 7.71 S 17.44 W 3.10 -7.97 1706.00 7.60 8.00 1704.92 2.29 N 15.80 W 2.66 2.05 1798.00 9.70 7.00 1795.86 16.01 N 14.01 g 2.29 15.80 1890.00 10.50 1.70 1886.44 32.08 N 12.82 W 1.33 31.89 1980.00 12.70 1.70 1974.60 50.17 N 12.28 W 2.44 49.98 2072.00 15.30 357.80 2063.86 72.42 N 12.45 W 3.00 72.22 2165.00 18.00 357.50 2152.95 99.04 N 13.54 W 2.90 98.82 2257.00 20.50 0.30 2239.80 129.35 N 14.08 W 2.90 129.12 2348.00 22.00 4.50 2324.62 162.28 N 12.66 W 2.35 162.07 2442.00 23.40 3.50 2411.33 198.47 N 10.14 W 1.54 198.29 2533.00 24.90 4.90 2494.37 235.59 N 7.40 W 1.76 235.46 2627.00 26.40 5.60 2579.10 276.11 N 3.67 W 1.63 276.02 2719.00 27.30 3.50 2661.18 317.53 N 0.38 W 1.42 317.48 2812.00 28.40 2.80 2743.41 360.91 N 2.00 E 1.23 360.90 2900.00 29.80 1.70 2820.30 403.67 N 3.67 E 1.70 403.68 2992.00 30.80 2.40 2899.73 450.05 N 5.33 E 1.15 450.08 3084.00 30.00 0.60 2979.09 496.59 N 6.56 E 1.32 496.63 3179.00 30.10 4.90 3061.33 544.08 N 8.84 E 2.27 544.15 3272.00 31.20 3.50 3141.33 591.36 N 12.31 E 1.41 591.48 3369.00 30.50 3.80 3224.61 641.00 N 15.47 E 0.74 641.16 3459.00 31.80 3.10 3301.63 687.47 N 18.27 E 1.50 687.66 3552.00 28.90 2.80 3381.88 734.39 N 20.69 E 3.12 734.62 3642.00 32.40 1.70 3459.29 780.23 N 22.47 E 3.94 780.48 3733.00 33.00 1.40 3535.87 829.37 N 23.80 E 0.68 829.64 3825.00 33.00 1.70 3613.03 879.46 N 25.15 E 0.18 879.74 3916.00 33.30 1.40 3689.22 929.20 N 26.50 E 0.38 929.50 4010.00 33.90 1.70 3767.51 981.20 N 27.91 E 0.66 981.51 4101.00 34.50 1.40 3842.78 1032.33 N 29.29 E 0.68 1032.66 4193.00 35.10 1.40 3918.32 1084.82 N 30.57 E 0.65 1085.16 4284.00 35.50 1.00 3992.59 1137.40 N 31.67 E 0.51 1137.74 4376.00 35.70 1.40 4067.39 1190.94 N 32.80 E 0.33 1191.30 4468.00 36.00 1.00 4141.96 1244.81 N 33.92 E 0.41 1245.18 All data is in feet unless otherwise stated Coordinates from slot #41-1 and TVD from wellhead (51.00 Ft above mean sea level Vertical section is from wet[head on azimuth 0.87 degrees. Declination ~s 23.68 degrees~ Convergence is -0.69 degrees. Calculation uses the minimum curvature method. Presented by Eastman Teleco MAR 0 1 Alaska Oil & Gas Cons. Commissio~ Anchorage UNOCAL Ivan River ,41-1 Ivan River Field,Cook InLet, Alaska SURVEY LISTING Page 2 Your ref : PMSS <0-9170'> Last revised : 16-Jan-93 Measured Inclin. Azimuth True Vert. R E C T A N G U L A R Dogleg Vert Depth Degrees Degrees Depth C 0 0 R D I N A T E $ Deg/lOOFt Sect 4560.00 35.40 0.60 4216.68 1298.49 N 34.67 E 0.70 1298.86 4652.00 35.10 0.30 4291.81 1351.58 N 35.09 E 0.38 1351.96 4743.00 34.20 0.60 4366.67 1403.32 N 35.50 E 1.01 1403.70 4835.00 33.40 359.90 4443.12 1454.50 N 35.72 E 0.97 1454.87 4925.00 32.40 359.90 4518.68 1503.38 N 35.64 E 1.11 1503.75 5017.00 31.60 0.20 4596.70 1552.13 N 35.68 E 0.89 1552.50 5107.00 30.10 359.60 4673.97 1598.28 N 35.60 E 1.70 1598.64 5201.00 29.90 359.60 4755.37 1645.28 N 35.28 E 0.21 1645.63 5294.00 30.60 359.20 4835.71 1692.13 N 34.78 E 0.78 1692.46 5386.00 29.60 358.50 4915.30 1738.26 N 33.86 E 1.15 1738.57 5479.00 28.20 358.50 4996.72 1783.19 N 32.68 E 1.50 1783.48 5571.00 28.50 358.50 5077.68 1826.86 N 31.54 E 0.33 1827.13 5664.00 28.70 358.20 5159.34 1871.36 N 30.26 E 0.26 1871.60 5756.00 28.80 358.50 5240.00 1915.59 N 28.98 E 0.19 1915.81 5849.00 29.10 358.20 5321.37 1960.59 N 27.69 E 0.36 1960.78 5941.00 28.10 359.90 5402.15 2004.62 N 26.95 E 1.40 2004.80 6034.00 28.20 359.90 5484.15 2048.49 N 26.87 E 0.11 2048.67 6129.00 28.40 359.60 5567.79 2093.53 N 26.67 E 0.26 2093.70 6222.00 28.60 359.90 5649.52 2137.91 N 26.48 E 0.26 2138.06 6313.00 28.50 359.60 5729.46 2181.40 N 26.29 E 0.19 2181.54 6407.00 28.40 359.60 5812.11 2226.18 N 25.98 E 0.11 2226.32 6500.00 28.40 1.00 5893.91 2270.41 N 26.21 E 0.72 2270.54 6597.00 28.60 1.00 5979.16 2316.68 N 27.02 E 0.21 2316.83 6691.00 27.90 0.60 6061.96 2361.17 N 27.64 E 0.77 2361.32 6783.00 27.90 1.40 6143.27 2404.21 N 28.39 E 0.41 2404.37 6875.00 27.70 1.00 6224.65 2447.11 N 29.29 E 0.30 2447.27 6967.00 27.50 0.60 6306.18 2489.73 N 29.89 E 0.30 2489.90 7060.00 27.60 0.30 6388.64 2532.74 N 30.22 E 0.18 2532.91 7146.00 27.30 0.30 6464.95 2572.39 N 30.43 E 0.35 2572.55 7239.00 27.50 0.30 6547.52 2615.18 N 30.66 E 0.22 2615.35 7332.00 27.20 359.90 6630.12 2657.91 N 30.73 E 0.38 2658.07 7425.00 27.00 0.60 6712.92 2700.28 N 30.92 E 0.40 2700.43 7518.00 26.90 1.00 6795.82 2742.42 N 31.50 E 0.22 2742.58 7612.00 26.80 ' 1.00 6879.68 2784.87 N 32.24 E 0.11 2785.04 7705.00 26.70 0.60 6962.73 2826.72 N 32.83 E 0.22 2826.90 7798.00 26.20 0.60 7045.99 2868.14 N 33.26 E 0.54 2868.32 7890.00 26.10 1.00 7128.58 2908.69 N 33.83 E 0.22 2908.87 7983.00 26.20 1.00 7212.06 2949.67 N 34.54 E 0.11 2949.85 8077.00 25.80 0.60 7296.54 2990.87 N 35.12 E 0.46 2991.06 8168.00 25.50 359.90 7378.58 3030.26 N 35.29 E 0.47 3030.45 8259.00 25.50 359.20 7460.71 3069.44 N 34.99 E 0.33 3069.61 8352.00 25.60 358.90 7544.62 3109.54 N 34.32 E 0.18 3109.70 8445.00 25.70 358.50 7628.45 3149.79 N 33.41 E 0.22 3149.93 8538.00 25.30 358.90 7712.39 3189.81 N 32.50 E 0.47 3189.94 8632.00 25.20 358.50 7797.41 3229.90 N 31.59 E 0.21 3230.01 8726.00 25.10 358.50 7882.50 3269.84 N 30.54 E 0.11 3269.92 8819.00 25.40 357.80 7966.62 3309.49 N 29.26 E 0.46 3309.55 8910.00 25.80 357.10 8048.68 3348.77 N 27.51 E 0.55 3348.80 9005.00 25.70 357.10 8134.25 3389.99 N 25.42 E 0.10 3389.98 9098.00 25.80 357.50 8218.01 3430.34 N 23.52 E 0,22 3430.31 All data is in feet unless otherwise stated Coordinates from slot #41-1 and TVD from wellhead (51.00 Ft above mean sea level Vertical section is from wellhead on azimuth 0.87 degrees. Declination is 23.68 degrees, Convergence is -0.69 degrees. Calculation uses the minimum curvature method. Presented by Eastman Teleco k AR 0 1 t-99 .,~laska Oil & (;as Cons. 6omr¢is~ion Anchorage UNOCAL Ivan River ,41-1 Ivan River Field,Cook Inlet, Alaska SURVEY LISTING Page 3 Your ref : PMSS <0-9170'> Last revised : 16-Jan-93 Measured Inclin. Azimuth True Vert. R E C T A N G U L A R Dogleg Vert Depth Degrees Degrees Depth C 0 0 R D I N A T E S Deg/lOOFt Sect 9138.00 25.80 357.80 8254.03 3447.74 N 22.80 E 9170.00 25.80 357.80 8282.84 3461.66 N 22.27 E 0.33 3447.69 0.00 3461.60 Projected Data - NO SURVEY All data is in feet unless otherwise stated Coordinates from slot fl41-1 and TVD from wellhead (51.00 Ft above mean sea level Vertical section is from we[thead on azimuth 0.87 degrees. Declination is 23.68 degrees, Convergence is -0.69 degrees. Calculation uses the minimum curvature method. Presented by Eastman Te[eco COMPLETION DATE . ~ ! 2.~ ,/c/~ CO. CONTACT ' Check Offo~iiSt data .as it i's re~eived.,list recei~ved date for 407. if not ~:equi~e~ list as NR .40~' ! *~ 11 I q.'~, drillin9 histO~' / ' ~U~e~!' [ ~"~ell tests ~ I' ~°re ~es~[iptio~n cored intew~ls cole ~nal~s ~., d~ ditch info.pis digital data ............. ...... " LOG TYPE ' RUN INTERYALS ' SCALE NO. [to thc nearest footI linch/! 00'! iii i i ~ i ,--, .i i iiii i i ~ J , , ,,, , J,, ,, , - · i51 ' 171 Il I Il I I I IIll I l[ Il I I I I III I I I Il Unocal North Americap Oil & Gas Division Unocal Corporation ' ~' r P.O. Box 190247 Anchorage, Alaska 99519-0247 Telephone (907) 276-7600 UNOCAL Alaska Region DOCUMENT TRANSMITTAL Feburary 23, 1993 TO: Larry Grant LOCATION' 3001 PORCUPINE DRIVE ANCHORAGE, AK 99501 ALASKA OIL & GAS CONSERVATION COMM. FROM' Eric Graven LOCATION-P.O.BOX 196247 ANCHORAGE AK 99519 UNOCAL IVAN RIVER 41-1 4 boxes dry samples box 1 3500 - 4790 box 2 4790 - 6440 box 3 6440- 8030 box 4 8030 - 9170 TRANSMITTING AS FOLLOWS PLEASE ACKNOWLEDGE RECEIPT BY SIGNING ~G ONE COPY OF THIS ,ocm N DATED. // ~ Oil & · -' ~,horaCe · MEMORANDUM STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION to: Leigh Griffin~~'L£'~[ '~'~ Commissioner date: file: December 28, 1992 LOU12123. DOC thru: Blair E Wondzell'~~ subject: Sr Petr Engineer from:i~LLou Grimaldi Petr Inspector Diveder Inspection Grace Rig #154 UNOCAL Well 41-1 Ivan River Unit PTD 92-109 Saturday, December 12, 1992: I traveled to Grace Drilling Company Rig #154 which was preparing to spud UNOCAL's Well #41-13 in the Ivan River Unit. Upon arrival I found the rig crew dismantling the vent line so they could place some cementing equipment on the oppostie side. The stack was still too cold to function test so the test was postponed until the following day. Sunday, December 20, 1992: The function test of the diverter went well with a 40 second closure of the annular preventer and proper sequence of the vent line valve. Grace uses two hydraulically operated 10 inch ball type valves at the tee in their vent line. These are far superior to the knife valves found on some other diverter assembly's I have inspected. There was a production separator with a burner near the end of the vent line; at my request, the burner was extinguished and will remain off until the rig is off of the diverter system. The rig had also changed its blowdown line configuration so that it pointed straight up in the direction of the side of the rig. After conferring with George Buck (UNOCAL Representative) this will be changed to point away from the rig before they drill out the surface casing. SUMMARY: I witnessed the function test of Grace Drilling's Rig #154. The diverter system was properly installed. OPERATIOfl~ Drlg h.~ ,,Comp1 Wkvr. UIC L~o~ton (gen'l) /- , ., -~11 sign ~.~; · ~: "::'~' IN C~L ~NC~ ~ " ': · yel . no nte A. DIV[RTER 2,'~ ( ) ( ) l~ne corm & anchored 3, ~ ( ) ( ) b~furca~ed & dwn w~nd ~.~) ( ) ( ) ~0e t~rge~ed turns " . 5. ~ ( ) ( ) vlvs~ auto 6.~ ( ) ( ) annular psck-off . ~. ~ 7, ( ) ( ) B. BOP STA~ · u 8 ( ) ( ) ~) ~11head flg wkg pre~ ~ 9. ( ) ( ) ~ stack wkg press 10. ( ) ( ) ~ annular · ~ :'12, ( ) ( ) ~) b11nd r~m~ ~ 1~. ( ) ( ) Itack tk.e( ) ( ) ~) chke/kt11 lt~ t5, ( ) ( ) ~ 90~ ~u~n~ ~arge~ed (chke t ktll ln) ~6, ( ) ( ) . ~ HCRv~v~ (c~e ~k~l) 17, () ( ) ~ manual vlvs (chke & kt11) :' 18. ( )' ( ) ~) conn~onl (flgd, ~d~ clmpd) ,: ~"-. ~, ( ) ( ) ~) dr1 ~poo~ ' .~ 20. ( ) ( ) (~) ~ n~pple 21, ( ) ( ) ~ fl~ mon~o,' 22, ( ,~ ( ) [~)"cont,ol l~nes 23. ~) ( ) ( ) wkg · .2~. ~" ( ) ( ) fluid level '; : I · ' 26. (~) ( ) ( ) p,esl gauges 27. ~ ( ) ( ) tufftcten~ vlvl 28. ~) ( ) ( ) regulator bypass 30. ~ ( ) ( ) bltnd handle cover , 31, ( ) ( ) drtlle~ COhEre1 panel STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMM Rtg/BOPE Inspection Report DATE: IN COMPL I ANC[~, 33, 35. ( ) 36, 37 ~J, ( ) 38:v-/ () 39. 6'4) ( ) ,o. (~) ( ) ~1.~) () ~.~ () ~s, ( ) ~6,~ qT, ~/J () nitrogen power source condition (leaks, hoses, D, HUD SYSTEM pit love) floats installed flow ra~e sensors mud g~s separator dega~sor chke In corm kelly cock~ (upper,lo~er,l~OP) floor vlvm (dart vlv, ball kelly ~ floor vlv ~enches dr()'er's console (fl o~ flon' rate (ndicato~, indicators, gauges) ~8. ( ) ( ) ~ kill #~. ~ ( ) ( ) gas ~,j~tecl:ton monitors (H-$ & n~ethane) so. si. S:. ( ) s~.() () ss,~ () ( ) hydr chke pane) chke n'.~ntfold ~, ~llSC EOUIPHE~T flare/vent line gO~ turns targeted {dr~~ strm choke )ns) Peserve pit tankag~ persornel protective e~uip ava all dr.! tire suprv: trainer for procedures H2S probes : ~.', s7, ( ) ( ) (. :~ 32. ( ) ( ) remote control penal 58, (~ ( ) ( ) rig nousekeeping ~ECORDS). .,. - Date of last ~P Inspections, m ~ Da~e of le~ BOP ~est: . :' Non-c~pltmnce~ no~ corrected & ~y~ _ -~; .......... . ~' '~,' Date correcl;lons wilt be completed: BOP tess & resul~e properly entered on daily record/. ~'. Kill ~hoet current? ~_._~ WALTER J. HICKEL, GOVERNOR ALASKA OIL AND GAS CONSERVATION COMMISSION November 13, 1992 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 2767542 Gary S. Bush Regional Drilling Manager Union Oil Company of California (UNOCAL) P O Box 196247 Anchorage, AK 99519 Ivan River 41-1 UNOCAL Permit No: 92-109 Sur. Loc. 712'FSL, 737'FEL, Sec. 1, T13N, R9W, SM Btmhole Loc. 4193'FSL, 684'FEL, Sec. 1, T13N, R9W, SM Dear Mr. Bush: Enclosed is the approved application for permit to drill the above referenced well. The permit to drill does not exempt you from obtaining additional permits required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permitting determinations are made. Blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25.035. Sufficient notice (approximately 24 hours) of the BOPE test performed before drilling below the surface casing shoe must be given so that a representative of the Commission may witness the test. Notice may be given by contacting the Commission at 279-1433. Chairman BY ORDER OF THE COMMISSION dlf/Enclosures cc: Department of Fish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. .... --.. STATE OF ALASKA --_ ALASKA' 'AND GAS CONSERVATION COl~ SSION PERMIT TO DRILL 20 AAC 25.005 la. Type of work Drill ~:~ Redrill ~ 1 lb. Type of well. Exploratory J-] Stratigraphic Test ~ Development Oil Re-Entry [] Deepen ~]I Service ~ Development Gas ~ Single Zone~ Multiple Zone 2. Name of Operator 5. Datum Elevation (DF or KB) 10. Field and Pool Union Oil Company of California (UNOCAL) 51' KB feet IVAN RIVER/UNNAMED 3. Address 6. Property Designation P.O. Box 196247, Anchorage, AK 99519 ADL-,CJS-7'8~ ,.W,%'?,3' O 4. Location of well at surface 712' FSL, 737' FEL of 7. Unit or property name 11. Type Bond (SEE 20 ACC 25.025) Sec. 1, T13N, R9W, SM Ivan River United Pacific Ins. Co. At top of productive interval 8660' MD, 4012' FSI_, 687' FEL 8. Well number Number of Sec. 1, T13N, R9W, SM 41-1 U62-9269 At total depth 9020' MD-4193' FSL, 684' FEL, 9. Approximate spud date Amount of Sec. 1, T13N, R9W, SM November 15 $200,000 12. Distance to nearest 13. Distance to nearest well 14. N umber of acres in property 15. Proposed depth (MO ,,,d'rW) property line Greater than 1500 feet 25' @ surface feet 2295.34 9020'MD/811 1' TVD feet 16. To be completed for deviated wells 17. Anticipated Pressure(see 20 Mc 25.035 (e)(2)) Kickoff depth 1500 feet Maximum hole angle 31 deg M~ximumsu~ce 2141 psig At total depth (TVD) 811 1' psig 18. Casing program Setting Depth size Specifications Top Bottom Quantity of cement Hole Casing Weight Grade Coupling Length MD TVD MD '1'VD (include stage data) 20" 94# VVELDEE 0 0 140' 140' DRIVEN 17-1/2" 13-3/8" 61# K55 BUTT 875 0 0 875' 875' 750 SXS (To surface) 12-1/4" 9-5/8" 47# N80 BUTT 3000 0 0 3000' 2905' 800 SXS (To surface) 8-1/2" 7" 29# N80 BUTT 9020 0 0 9020' 8111' 600 SXS (To 5000') 19. To be completed for Redrill, Re-entry, and Deepen Operations Present well condition summary Total depth: measured feet Plugs (measured) true vertical feet Effective depth: measured feet Junk (measured) true vertical feet Casing Length Size Cemented Measured depth True vertical depth Structural sC~r~adcU;t°r ~ E C E IV E D Intermediate Production 00T 1 4 1992 Liner A{aska. 0il & 6as Cons. Perforation depth: measured true vertical 20. Attachments Filing fee ~ Property plat ~ BOP Sketch~: Diverter Sketch [~ Drilling program ~ Drilling fluid program ~ Time vs depth plot ~ Refraction analysis ~ Seabed report j-] 20 AAC 25.050 requirements 21. I hereby certify that the foregoing is true and correct to the best of my knowledge Signed GARYS. BUSFI,~.,.~ %. ~"),..,..~Title REGIONAL DRILLINGMANAGER .,.-.¢,~ ~ .... Commission Use Only Permit Number ~ A~l~ber I Approval date 92.-/(:::) c~, r~o- ~ ~'a~ ;7_ O0 ~'~ [ //-'/~ '"~ [Seecoverletter I for other requirements Condiiions of approval Samples required ~ Yes,,..~ No Mud log rec~uir.ed - ~ Ye~ No Hydrogen sulfide measures ~ Yes,~ No Directional survey required ~ Yes [~ No Required working pressure forBOPE '~ 2M; ~-] 3M; J~' 5M; ~ 1OM; '~ 15M Other: Original ~y /1. by the order of __. Approved by David W, Johnston Commissioner the commission Date , Form 10-401 Rev. 12-1-85 Submit in triplicate IVAN RIVER 41-1 PROCEDURE: 1. DRIVE 20" CASING TO 140'. 2. INSTALL DIVERTER. 3. DRILL 17.5" HOLE TO 875' (420' /day) . 4. RUN AND CEMENT 13-3/8" CASING. 5. INSTALL 13-5/8" 5000 PSI BOPE AND TEST TO 2000 PSI. 6. DRILL 12-1/4" HOLE TO 3000' (440' /day). 7. RUN AND CEMENT 9-5/8" CASING. 8. TEST THE 13-5/8" BOPE TO 5000 PSI. 9. DRILL 8-1/2" HOLE TO 9020' MD (450' /day to 8000'). (160' /day to 9020') 10. RUN AND CEMENT 7" CASING. 11. CHANGE THE WELL OVER TO SODIUM BROMIDE BRINE. 12. PERFORATE AND GRAVEL PACK THE TYONEK GAS SANDS. 13. RUN A 2-7/8" COMPLETION TO 8900' , SET A HYDRAULIC PACKER AT 3050'. 14. RUN A 2-1/16" X 1-1/2" HEATER STRING TO 3000'. 15. CHANGE THE TOP 3000' OVER TO GLYCOL/WATER HEATER STRING FLUID. 16. REMOVE BOPE, INSTALL TREE. 17. MOVE THE RIG TO THE IVAN RIVER 14-31 LOCATION. Time: 51 Days IVAN RIVER UNIT WELL NO. 41-1 MUD PROGRAM MUD TYPE: Low Solids/Non Dispersed/Fresh Water Gel DEPTH: 24' - 875' MUD PROPERTIES: Weight (Lbs/Cu ft) = 68-72 PCF ~? Funnel Viscosity (Sec/Qt) -- 80 - 250 Plastic Viscosity (cps) = 10 - 20 Yield Point (#/100 Cu ft) = 15 - 30 API Fluid Loss (cc) = 5 - 8 pH = 9.0 - 10.0 API Fluid Loss < 75 cc MUD PROGRAM MUD TYPE: Low Solids/Non Dispersed/Fresh Water Gel DEPTH: 875'- 3000' MUD PROPERTIES: Weight (Lbs/Cu ft) = 70-74 PCF Funnel Viscosity (Sec/Qt) = 42 - 80 Plastic Viscosity (cps) = 10 - 20 Yield Point (#/100 Cu ft) = 10 - 30 API Fluid Loss (cc) = 10 - 12 pH = 9.0 - 10.0 Drilled Solids (Lbs/bbl) < 75 MUD TYPE: Fresh Water Gel / Polymer Mud DEPTH: 3000'- 9,020' MUD PROPERTIES: Weight (Lbs/Cu ft) = 72-90 PCF Funnel Viscosity (sec/Qt) = 42 - 80 Plastic Viscosity (cps) = 10 - 20 Yield Point (#/100 Cu ft) = 10 - 30 API Fluid Loss (cc) = 9 - 10 HPHT Fluid Loss (cc) = 12 - 15 (500 psi @ 200 Degrees F) pH = 9.0 - 10.0 MBT (Lbs/bbl) < 25 Drill Solids (Lbs/bbl) < 50 . ,ECEIVED Alaska. Oil & Gas Cons. {$om~-~!9~ STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage Alaska 99501-3192 Re: THE APPLICATION OF UNION OIL ) COMPANY of CALIFORNIA ) (UNOCAL) for an exception to ) spacing requirements of ) Title 20 AAC 25.055 to provide ) for the drilling of the Ivan River ) Unit 41-1development gas well. ) Conservation Order No. 301 Ivan River Unit 41-1 Development Gas Well November 10, 1992 IT APPEARING THAT: · UNOCAL submitted an application dated October 14, 1992 requesting an exception to 20 AAC 25.055(a)(4) to allow drilling the Ivan River Unit 41-1 development gas well as the second well in a section, closer than 1500 feet to a section line and closer than 3000 feet to a well capable of producing from the same pool. Notice of hearing was published in the Anchorage Daily News on October 17, 1992 and the Alaska Administrative Journal on October 26, 1992 pursuant to 20 AAC 25.540. 3. No protests to the application were received. FINDINGS: · The Ivan River Unit 41-1 well is proposed to be directionally drilled from a surface location 712 feet from the south line (FSL), 737 feet from the east line (FEL) of Section 1, T13N, R9W, Seward Meridian, to a proposed bottomhole location 4193 feet FSL, 684 feet FEL, Section 1, T13N, R9W, Seward Meridian. 2. All offset operators/owners have been duly notified. · An exception to 20 AAC 25.055(a)(4) is necessary to allow drilling of the well. Conservation Orde~ .01 November 10, 1992 Page 2 , The Unit Agreement for the development and operation of the Ivan River Unit validly integrates the interests in this well and the surrounding acreage. CONCLUSIONS: Granting a spacing exception to allow drilling of the Ivan River Unit 41-1 development gas well as proposed will not result in waste nor jeopardize correlative rights. NOW, THEREFORE, IT IS ORDERED: UNOCAL's application for an exception to 20 AAC 25.055 for the purpose of drilling the Ivan River Unit 41-1 development gas well is approved as proposed. DONE at Anchorage, Alaska and dated November 10, 1992. David W. ~ohnston,hChairman Alaska Oil~onservation Commission. Russell A. Douglass, Cog~nisSioner Alaska Oil and Gas Conservation Commission ~;~h ~riffi~ ~Co~{~sioner Alaska Oil and Ga~'~'Conservation Commission IVAN RIVER FIELD WELL 41-1 PROPOSED 13-3/8" at 875' 1-1/2' x 2-1/16" to 3000' 9-5/8' at (~oo' PACKER AT 3050' 2-7/8" COMPLETION 20-40 GRAVEL PACK Gravel Packed TYONEK GAS SANDS 7" CASING AT 9,020' GRB 10-2-92 + + 35 ++ I I 36 i + + 3-3t R 14-31 41-1 i 44-1 REC. R 23-12 -t- ~t3 .o, UNOCALO Unocal North American Oil & Gas Division ALASKA REGION UPPER COOK INLET IVAN RIVER UNIT STRUCTURE CONTOUR-.c TOP UPPER TYONEK TESTED GAS SAND AFE #321058 Interpretation b.~: KILOH I Date: 6/92 EXHIBIT F 10 ' ~ENT LINE · 7 k 10" t0 ' VENT LINE WEE. I' NAME: Ivan River RIG CONTRACTOR: F[IG: DJIIERTER SIZE: 20" DJVERTER LINE SIZE: 10" DEPT. APPROVAL · ANGLED FILL UP LINE~, 10 - HYDRAULI~ VALVE.~..~ LINE NOTES: VENT LINES ARE 180° .y APART. FLEX HOSE (~J IS TO BE USED' IF ! NECESSARY WITH DDS APPROVAL 3. BALL VALVES TIED TOGETH SO THAT ONE IS OPEN AND ONE CLOSED. 4. DIVERTER LINE MIN. 10' O.D. NOTE: ALL CHANGES Must HAVE WRITTEN APPROVAL BY THE DISTRICT DRILLING SUPERINTENDENT. , REV. ) 0ATE 20" OR 30" DIVERTER CONTRACTOR RIG UNION OIL COMPANY OF CALIFORNIA ANCHORAGF, , ALASKA SC^LZ _L~O N E DATE 10/I0185 FILL-UP KILL LINE ii '~ FLOW I ANNULAR ~ BOP 13s/~"3000 ps PI?E RAMS 13%"5000 psi BLIND RAMS 13s/d'5000 psi ~ l DRIVING ~ __ ~ _ ~[~~ SPOOL ~[ ~ ~3s/&'5000 p~ 4" 5000 psi }[ [~ 4" 5000 [ PIPE RAMS1 13%"5000 psi CHOKE LINE~ psi RISER ~3%" 5000 psi IV AN RIVER BOPE STACK 13 %" 5000 psi ITEM A -o Remote Activated Choke ITEM B - Remo[-e Act. .!ed Choke All other components are rated to 10,000 psi T T Structure : Ivan River Well: 41-1 Z~EATED BY : .ONES For: G BUCK DATE PLOTTED : 1-OCT-92 ~LOT REFERENCE IS 4-1-1 VERSION ~1. COORDINATES ARE !N FEET REFERENCE SLOT #41--1 ., TRUE VERTICAL DEPTHS ARE REFERENCE WELLHEAD. FA TMAN T£LECO Field : Ivan River Field 3481' ( TO TD ) I I V - 2404:1. - 28OO.. 32O41. 36OO. S60{L, - - 760O._ B000- RKB ELEVATION: 25' 20" CSG PT TVD=100 13 3/SI'CSG PT TVD:875 KOP -FVO=1500 TMD=IEO0 DEP:0 5.00 10.00 1 5.00 BUILD 2.5 0EG/ 100' 20.00 25.00 30.00 EOC TVD=2651 TM0--2706 DEP--310 9 5/8"CSG PT TV0=2905 TMD=3000 DEP=458 TARGET #2 TVD=8025 TM0=8920 DEP=343t NORTH 3431 EAST 52 AVERAGE ANGLE 30.15 DEG i i i i i i i i i ~ [ i i t i i o 400 BOO 11200 1600 2000 124. o0 2800 SCALE I : 2oo.oo Vedicol Section on 0.87 azimuth with reference 0.00 N, 0.00 £ from slot ~41-1 Location : Cook Inlet, Alaska TD TVD=8111 TMD=9020 DEP=34B1 NORTH 3481 EAST 53 ~,.~ <-- ,,~oo 200 200 400 I 1 I TARGET #1 'I-VD=7800 TMD=8660 DEP=3300 NORTH 3300 EAST 50 SURFACE LOCATION: 712' FSL, 737' FEL SEC. 1, T13N, Rgw TARGET #1 - T/ TYONEK TVD=T800 TMD=8660 DEP=3300 TARGET i~2 - B/ TYONEK TVI)=8025 TMD=8920 DEP=3431 TI) TVD=8111 TI~I)=g020 DEP=3481 3200 3600 o00 - .~BO0 - -2600 - :'400 - -2200 - ':'ooo - - r- .2o0 I-q .. o ':'oo $CALF 1 : 100.00 400 300 200 West lO0 2600 24- 220( 1600 1400 1200 1000 UNOCAL Structure: Ivan RNer Well : 41-1 PLOT INCLUDES PORPOSED: 13-31 field : Ivan River field Lacaflon : C~ok Inlef, Ala.ka 3400 2400 3200 2200 3000 2000 2800 1800 2600 2000 East --> 100 I 200 I 300 I BO0 ,00 1800 O0 ,C~ 600 000 200 4-00 600 400 I 900 _BO0 -- _700 _600 -- _500 -- _400 0 _300 -- _200 -- _100 _ 0 _100 _200 /% I I 7 0 UNOCAL Ivan River 41-1 slot #41-1 Ivan River Field Cook Inlet, Alaska PROPOSAL LISTING Your ref : 41-1 Version #1 Our ref : prop613 Other ref : Date printed : 1-Oct-92 Date created : 14-Sep-92 Last revised : 1-0ct-92 Field is centred on 360387.836,2645652.913,999.00000,N Structure is centred on 360387.836,2645652.913,999.00000,N UNOCAL Ivan River ,41-1 Ivan River Field,Cook Inlet, Alaska PROPOSAL LISTING Page 1 Your ref : 41-1 Version Last revised : 1-Oct-92 Measured Inclin. Azimuth True Vert. R E C T A N G U L A R Dogleg Vert Depth Degrees Degrees Depth C O O R D I N A T E S Deg/100Ft Sect 0.00 0.00 0.00 0.00 0.00 N 0.00 E 0.00 0.00 100.00 0.00 0.87 100.00 0.00 N 0.00 E 0.00 0.00 200.00 0.00 0.87 200.00 0.00 N 0.00 E 0.00 0.00 300.00 0.00 0.87 300.00 0.00 N 0.00 E 0.00 0.00 400.00 0.00 0.87 400.00 0.00 N 0.00 E 0.00 0.00 500.00 0.00 0.87 500.00 0.00 N 0.00 E 0.00 0.00 600.00 0.00 0.87 600.00 0.00 N 0.00 E 0.00 0.00 700.00 0.00 0.87 700.00 0.00 N 0.00 E 0.00 0.00 800.00 0.00 0.87 800.00 0.00 N 0.00 E 0.00 0.00 875.00 0.00 0.87 875.00 0.00 N 0.00 E 0.00 0.00 13 3/8" 900.00 0.00 0.87 900.00 0.00 N 0.00 E 0.00 0.00 1000.00 0.00 0.87 1000.00 0.00 N 0.00 E 0.00 0.00 1100.00 0.00 0.87 1100.00 0.00 N 0.00 E 0.00 0.00 1200.00 0.00 0.87 1200.00 0.00 N 0.00 E 0.00 0.00 1300.00 0.00 0.87 1300.00 0.00 N 0.00 E 0.00 0.00 1400.00 0.00 0.87 1400.00 0.00 N 0.00 E 0.00 0.00 1500.00 0.00 0.87 1500.00 0.00 N 0.00 E 0.00 0.00 KOP 1600.00 2.50 0.87 1599.97 2.18 N 0.03 E 2.50 2.18 1700.00 5.00 0.87 1699.75 8.72 N 0.13 E 2.50 8.72 1800.00 7.50 0.87 1799.14 19.60 N 0.30 E 2.50 19.61 1900.00 10.00 0.87 1897.97 34.81 N 0.53 E 2.50 34.82 2000.00 12.50 0.87 1996.04 54.32 N 0.82 E 2.50 54.32 2100.00 15.00 0.87 2093.17 78.08 N 1.18 E 2.50 78.09 2200.00 17.50 0.87 2189.17 106.06 N 1.61 E 2.50 106.07 2300.00 20.00 0.87 2283.85 138.20 N 2.09 E 2.50 138.21 Ail data is in feet unless otherwise stated Coordinates are from slot #41-1 and TVDs are from wellhead. Vertical section is from wellhead on azimuth 0.87 degrees. Calculation uses the minimum curvature method. CSG PT UNOCAL Ivan River ,41-1 Ivan River Field,Cook Inlet, Alaska PROPOSAL LISTING Page 2 Your ref : 41-1 Version #1 Last revised : 1-Oct-92 Measured Inclin. Azimuth True Vert. R E C T A N G U L A R Dogleg Vert Depth Degrees Degrees Depth C O O R D I N A T E S Deg/100Ft Sect 2400.00 22.50 0.87 2377.04 174.44 N 2.64 E 2.50 174.46 2500.00 25.00 0.87 2468.57 214.70 N 3.25 E 2.50 214.73 2600.00 27.50 0.87 2558.25 258.92 N 3.92 E 2.50 258.95 2700.00 30.00 0.87 2645.92 307.01 N 4.65 E 2.50 307.05 2705.87 30.15 0.87 2651.00 309.95 N 4.70 E 2.50 309.99 EOC 3000.00 30.15 0.87 2905.34 457.65 N 6.93 E 0.00 457.70 9 5/8" 3500.00 30.15 0.87 3337.71 708.73 N 10.74 E 0.00 708.81 4000.00 30.15 0.87 3770.08 959.81 N 14.54 E 0.00 959.92 4500.00 30.15 0.87 4202.45 1210.89 N 18.35 E 0.00 1211.03 5000.00 30.15 0.87 4634.82 1461.97 N 22.15 E 0.00 1462.14 5500.00 30.15 0.87 5067.20 1713.05 N 25.96 E 0.00 1713.25 6000.00 30.15 0.87 5499.57 1964.13 N 29.76 E 0.00 1964.36 6500.00 30.15 0.87 5931.94 2215.21 N 33.56 E 0.00 2215.46 7000.00 30.15 0.87 6364.31 2466.29 N 37.37 E 0.00 2466.57 7500.00 30.15 0.87 6796.68 2717.37 N 41.17 E 0.00 2717.68 8000.00 30.15 0.87 7229.05 2968.45 N 44.98 E 0.00 8500.00 30.15 0.87 7661.42 3219.53 N 48.78 E 0.00 8660.25 30.15 0.87 7800.00 3300.00 N 50.00 E 0.00 8920.45 30.15 0.87 8025.00 3430.66 N 51.98 E 0.00 9000.00 30.15 0.87 8093.79 3470.61 N 52.58 E 0.00 CSG PT 2968.79 3219.90 3300.38 TARGET #1 - T/ TYONEK 3431.05 TARGET #2 - B/ TYONEK 3471.00 9020.45 30.15 0.87 8111.48 3480.88 N 52.74 E 0.00 3481.28 TD Ail data is in feet unless otherwise stated Coordinates are from slot #41-1 and TVDs are from wellhead. Vertical section is from wellhead on azimuth 0.87 degrees. Calculation uses the minimum curvature method. UNOCAL Ivan River ,41-1 Ivan River Field,Cook Inlet, Alaska MD TVD Rectangular Coords. PROPOSAL LISTING Page 3 Your ref : 41-1 Version #1 Last revised : 1-Oct-92 Comments in wellpath Comment 875.00 875.00 0.00 N 1500.00 1500.00 0.00 N 2705.87 2651.00 309.95 N 3000.00 2905.34 457.65 N 8660.25 7800.00 3300.00 N 8920.45 8025.00 3430.66 N 9020.45 8111.48 3480.88 N 0.00 E 0.00 E 4.70 E 6.93 E 50.00 E 51.98 E 52.74 E 13 3/8" CSG PT KOP EOC 9 5/8" CSG PT TARGET #1 - T/ TYONEK TARGET #2 - B/ TYONEK TD Casing positions in string 'A' Top MD Top TVD Rectangular Coords. Bot MD Bot TVD 0.00 0.00 0.00N 0.00 0.00 0.00N 0.00 0.00 0.00N 0.00 0.00 0.00N 0.00E 100.00 100.00 0.00E 875.00 875.00 0.00E 3000.00 2905.34 0.00E 9020.45 8111.48 Rectangular Coords. Casing 0.00N 0.00N 457.65N 3480.88N 0.00E 20" CSG 0.00E 13 3/8" CSG 6.93E 9 5/8" CSG 52.74E 7" LINER Targets associated with this wellpath Target name Position T.V.D. Local rectangular coords. Date revised IV 41-1 T/ Tyonek IV41-1 B/ Tyonek not specified not specified 7800.00 3300.00N 8025.00 3430.66N 50.00E 1-Oct-92 51.98E 1-Oct-92 Ail data is in feet unless otherwise stated Coordinates are from slot #41-1 and TVDs are from wellhead. Slot coordinates are 712.00 N 737.00 W. Bottom hole distance is 3481.28 on azimuth 0.87 degrees from wellhead. Total Dogleg for wellpath is 30.15 degrees. Vertical section is from wellhead on azimuth 0.87 degrees. Calculation uses the minimum curvature method. UNOCAL Ivan River 41-1 slot #41-1 Ivan River Field Cook Inlet, Alaska CLEARANCE REPORT Your ref : 41-1 Version #1 Our ref : prop613 Other ref : Date printed : Date created : Last revised : 1-Oct-92 14-Sep-92 1-Oct-92 Field is centred on 360387.836,2645652.913,999.00000,N Structure is centred on 360387.836,2645652.913,999.00000,N Main calculation performed with 3-D minimum distance method Object wellpath PGMS <0-5000'>,,44-1,Ivan River MSS <0-10958'>,,14-31,Ivan River MSS <0-112188'>,,23-12,Ivan River 13-31 Version #2,,13-31,Ivan River PMSS <0-???>,,13-31,Ivan River Closest approach with 3-D minimum distance method Last revised Distance M.D. Diverging from 10-Sep-92 86.7 1400.0 1400.0 ll-Sep-92 25.0 400.0 400.0 ll-Sep-92 68.6 0.0 4900.0 ll-Sep-92 40.8 1400.0 1400.0 1-Oct-92 50.9 1100.0 1100.0 M.D. 0.0 100.0 200.0 300.0 400.0 500.0 600.0 700.0 800.0 875.0 900.0 1000.0 1100.0 1200.0 1300.0 1400.0 1500.0 1600.0 1600.0 1700.0 1700.2 1800.0 1800.9 1900.0 1902.0 UNOCAL Ivan River ,41-1 Ivan River Field,Cook Inlet, Reference wellpath Alaska CLEARANCE LISTING Page 1 Your ref : 41-1 Version #1 Last revised : 1-Oct-92 Object wellpath T.V.D. Rect Coordinates M.D. T.V.D. 0.0 0.0N 0.0E 0.0 0.0 100.0 0.0N 0.0E 99.9 99.9 200.0 0.0N 0.0E 199.9 199.9 300.0 0.0N 0.0E 300.1 300.0 400.0 0.0N 0.0E 400.1 400.1 500.0 0.0N 0.0E 500.1 500.1 600.0 0.0N 0.0E 600.2 600.2 700.0 0.0N 0.0E 700.2 700.2 800.0 0.0N 0.0E 800.2 800.2 875.0 0.0N 0.0E 875.3 875.3 900.0 0.0N 0.0E 900.3 900.3 1000.0 0.0N 0.0E 1000.4 1000.4 1100.0 0.0N 0.0E 1100.1 1100.1 1200.0 0.0N 0.0E 1200.1 1200.1 1300.0 0.0N 0.0E 1300.2 1300.2 1400.0 0.0N 0.0E 1400.1 1400.1 1500.0 0.0N 0.0E 1499.9 1499.9 1600.0 2.2N 0.0E 1599.9 1599.9 1600.0 2.2N 0.0E 1599.9 1599.9 1699.7 8.7N 0.1E 1699.8 1699.8 1700.0 8.7N 0.1E 1700.0 1700.0 1799.1 19.6N 0.3E 1799.1 1799.1 1800.0 19.7N 0.3E 1800.0 1800.0 1898.0 34.8N 0.5E 1898.0 1897.9 1900.0 35.2N 0.5E 1900.0 1900.0 : PGMS <0-5000'>,,44-1,Ivan River Angle fm Min'm Rect Coordinates HighSide Dist 51.0S 73.0E +124.9 89.0 51.1S 73.0E +124.1 89.1 51.4S 72.9E +124.3 89.2 51.6S 72.7E +124.5 89.1 51.7S 72.4E +124.6 89.0 51.8S 72.2E +124.8 88.8 51.7S 71.9E +124.8 88.6 51.6S 71.7E +124.9 88.3 51.6S 71.4E +125.0 88.1 51.6S 71.1E +125.1 87.9 51.6S 71.0E +125.2 87.8 51.5S 70.6E +125.2 87.4 51.2S 70.5E +125.1 87.1 50.8S 70.6E +124.8 87.0 50.4S 70.7E +124.6 86.8 50.1S 70.7E +124.4 86.7 50.1S 70.8E +124.4 86.7 50.1S 70.9E +125.5 88.1 50.1S 70.9E +125.5 88.1 50.0S 71.0E +128.6 92.0 50.0S 71.0E +128.6 92.0 50.0S 71.0E +133.2 99.2 50.0S 71.0E +133.3 99.3 50.0S 71.0E +138.4 110.3 50.0S 71.0E +138.5 110.6 TCyl Dist 89.0 89.1 89.2 89.1 89.0 88.8 88.6 88.3 88.1 87.9 87.8 87.4 87.1 87.0 86.8 86.7 86.7 88.1 88.1 92.2 92.2 99.6 99.7 111.3 111.6 Ail data is in feet unless otherwise stated Coordinates are from slot #41-1 and TVDs are from wellhead. Vertical section is from wellhead on azimuth 0.87 degrees. Calculation uses the minimum curvature method. M.D. 2000.0 2004.0 2100.0 2107.1 2200.0 2211.4 UNOCAL Ivan River ,41-1 Ivan River Field,Cook Inlet, Reference wellpath Alaska CLEARANCE LISTING Page 2 Your ref : 41-1 Version Last revised : 1-Oct-92 #1 Object wellpath : PGMS <0-5000'>,,44-1,Ivan River T.V.D. Rect Coordinates M.D. T.V.D. Angle fm Min'm Rect Coordinates HighSide Dist 1996.0 54.3N 0.8E 1996.2 1996.1 49.9S 71.0E +143.3 125.7 2000.0 55.2N 0.8E 2000.1 2000.1 49.9S 71.0E +143.4 126.4 2093.2 78.1N 1.2E 2093.2 2093.2 49.9S 71.0E +147.2 145.7 2100.0 79.9N 1.2E 2100.0 2100.0 49.9S 71.0E +147.5 147.4 2189.2 106.1N 1.6E 2189.0 2189.0 50.0S 70.9E +149.9 170.7 2200.0 109.5N 1.6E 2199.9 2199.9 50.0S 70.8E +150.2 173.9 TCyl Dist 127.7 128.5 149.7 151.4 177.~ 181.2 Ail data is in feet unless otherwise stated Coordinates are from slot #41-1 and TVDs are from wellhead. Vertical section is from wellhead on azimuth 0.87 degrees. Calculation uses the minimum curvature method. UNOCAL Ivan River ,41-1 Ivan River Field,Cook Inlet, Alaska CLEARANCE LISTING Page 3 Your ref : 41-1 Version Last revised : 1-Oct-92 #1 Reference wellpath Object wellpath : MSS <0-10958'>,,14-31,Ivan River MoD. T.V.D. Rect Coordinates M.D. T.V.D. Angle fm Min'm TCyl Rect Coordinates HighSide Dist Dist 0.0 100.0 200.0 300.0 400.0 500.0 600.0 700.0 8O0.0 875.0 0.0 0.0N 0.0E 100.0 0.0N 0.0E 200.0 0.0N 0.0E 300.0 0.0N 0.0E 400.0 0.0N 0.0E 500.0 0.0N 0.0E 600.0 0.0N 0.0E 700.0 0.0N 0.0E 800.0 0.0N 0.0E 875.0 0.0N 0.0E 20 120 220 320 420 520 620 719 817 890 .9 0.0 15.0N 20.0W -53.1 25.0 25.0 .9 100.0 15.0N 20.0W -54.0 25.0 25.0 .9 200.0 15.0N 20.0W -54.0 25.0 25.0 .9 300.0 15.0N 20.0W -54.0 25.0 25.0 .9 400.0 15.0N 20.0W -54.0 25.0 25.0 .3 499.4 16.0N 19.9W -52.2 25.5 25.5 .0 598.9 21.6N 19.1W -42.3 28.9 28.9 .7 698.4 27.6N 18.0W -34.0 33.0 33.0 .9 796.3 35.5N 17.3W -27.3 39.6 39.8 .2 868.0 45..1N 16.6W -22.6 48.6 49.0 900.0 1000.0 1100.0 1200.0 1300.0 900.0 0.0N 0.0E 1000.0 0.0N 0.0E 1100.0 0.0N 0.0E 1200.0 0.0N 0.0E 1300.0 0.0N 0.0E 914 1011 1106 1197 1291 .9 892.4 48.9N 16.5W -21.1 52.2 52.8 .5 987.5 65.8N 16.0W -17.8 68.9 70.0 .8 1080.8 84.8N 15.6W -16.8 88.3 90.5 .9 1169.2 107.1N 14.8W -18.1 112.4 117.1 .3 1258.5 134.1N 13.3W -18.3 141.0 147.7 1400.0 1400.0 0.0N 1384 1346.8 162.3N 11.0W -18.7 171.2 180.4 Ail data is in feet unless otherwise stated Coordinates are from slot #41-1 and TVDs are from wellhead. Vertical section is from wellhead on azimuth 0.87 degrees. Calculation uses the minimum curvature method. M.D. 0.0 100.0 200.0 300.0 400.0 500.0 600.0 700.0 800.0 875.0 900.0 1000.0 1100.0 1200.0 1300.0 UNOCAL Ivan River ,41-1 Ivan River Field,Cook Inlet, Reference wellpath Alaska CLEARANCE LISTING Page 4 Your ref : 41-1 Version #1 Last revised : 1-Oct-92 Object wellpath : MSS <0-112188'>,,23-12,Ivan River T.V.D. Rect Coordinates M.D. T.V.D. Angle fm Min'm Rect Coordinates HighSide Dist 0.0 0.0N 0.0E 20.4 0.0 41.0S 55.0E +126.7 68.6 100.0 0.0N 0.0E 120.3 99.8 40.9S 55.3E +125.6 68.8 200.0 0.0N 0.0E 220.2 199.7 40.5S 56.0E +125.0 69.2 300.0 0.0N 0.0E 320.0 299.5 40.0S 57.1E +124.1 69.7 400.0 0.0N 0.0E 420.2 399.7 39.2S 58.4E +123.0 70.3 500.0 0.0N 0.0E 520.1 499.6 37.4S 59.8E +121.1 70.6 600.0 0.0N 0.0E 619.3 598.4 30.8S 64.6E +114.6 71.6 700.0 0.0N 0.0E 716.9 695.2 21.1S 72.8E +105.2 75.9 800.0 0.0N 0.0E 814.4 791.2 8.7S 83.4E +95.0 84.3 875.0 0.0N 0.0E 886.7 862.2 1.8N 92.5E +88.0 93.4 900.0 0.0N 0.0E 910.4 885.4 5.4N 95.8E +86.0 97.0 1000.0 0.0N 0.0E 1007.8 980.7 19.9N 109.9E +79.0 113.3 1100.0 0.0N 0.0E 1102.9 1073.5 34.8N 124.5E +73.8 132.0 1200.0 0.0N 0.0E 1195.6 1163.2 51.2N 140.9E +69.8 154.3 1300.0 0.0N 0.0E 1287.1 1251.0 69.7N 158.6E +66.4 180.0 TCyl Dist 68.6 68.8 69.2 69.7 70.2 70.6 71.6 76.1 84.7 94.4 98.2 115.0 135.0 159.3 187.5 Ail data is in feet unless otherwise stated Coordinates are from slot #41-1 and TVDs are from wellhead. Vertical section is from wellhead on azimuth 0.87 degrees. Calculation uses the minimum curvature method. M.D. 0.0 100.0 200.0 300.0 400.0 500.0 600.0 700.0 800.0 875.0 900.0 1000.0 1100.0 1200.0 1300.0 1400.0 1500.0 1600.0 1600.0 1700.0 1700.2 1800.0 1800.9 1900.0 1902.0 UNOCAL Ivan River ,41-1 Ivan River Field,Cook Inlet, Reference wellpath Alaska CLEARANCE LISTING Page 5 Your ref : 41-1 Version #1 Last revised : 1-Oct-92 Object wellpath T.V.D. Rect Coordinates M.D. T.V.D. 0.0 0.0N 0.0E 0.0 0.5 100.0 0.0N 0.0E 99.5 100.0 200.0 0.0N 0.0E 199.5 200.0 300.0 0.0N 0.0E 299.5 300.0 400.0 0.0N 0.0E 399.5 400.0 500.0 0.0N 0.0E 499.5 500.0 600.0 0.0N 0.0E 599.5 600.0 700.0 0.0N 0.0E 699.5 700.0 800.0 0.0N 0.0E 799.5 800.0 875.0 0.0N 0.0E 874.5 875.0 900.0 0.0N 0.0E 899.5 900.0 1000.0 0.0N 0.0E 999.5 1000.0 1100.0 0.0N 0.0E 1101.1 1101.5 1200.0 0.0N 0.0E 1202.7 1202.8 1300.0 0.0N 0.0E 1302.8 1302.0 1400.0 0.0N 0.0E 1401.2 1398.8 1500.0 0.0N 0.0E 1497.7 1492.6 1600.0 2.2N 0.0E 1592.1 1583.2 1600.0 2.2N 0.0E 1592.1 1583.2 1699.7 8.7N 0.1E 1684.9 1670.8 1700.0 8.7N 0.1E 1685.1 1671.0 1799.1 19.6N 0.3E 1776.0 1755.3 1800.0 19.7N 0.3E 1776.8 1756.1 1898.0 34.8N 0.5E 1867.2 1838.2 1900.0 35.2N 0.5E 1869.2 1840.0 : 13-31 Version #2,,13-31,Ivan River Angle fm Min'm Rect Coordinates HighSide Dist 30.0S 45.0E +123.7 54.1 30.0S 45.0E +122.8 54.1 30.0S 45.0E +122.8 54.1 30.0S 45.0E +122.8 54.1 30.0S 45.0E +122.8 54.1 30.0S 45.0E +122.8 54.1 30.0S 45.0E +122.8 54.1 30.0S 45.0E +122.8 54.1 30.0S 45.0E +122.8 54.1 30.0S 45.0E +122.8 54.1 30.0S 45.0E +122.8 54.1 30.0S 45.0E +122.8 54.1 27.4S 44.6E +120.6 52.4 19.4S 43.5E +113.1 47.7 6.3S 41.7E +97.7 42.2 ll.6N 39.2E +72.7 40.8 33.8N 36.0E +46.5 50.0 60.2N 32.3E +30.2 68.5 60.2N 32.3E +30.2 68.5 90.3N 28.1E +22.2 91.0 TCyl Dist 54.1 54.1 54.1 54.1 54.1 54.1 54.1 54.1 54.1 54.1 54.1 54.1 52.4 47.8 42.2 40.9 50.6 70.1 70.1 93.8 90.4N 28.1E +22.2 91.0 93.9 124.0N 23.4E +18.5 115.5 119.7 124.3N 23.3E +18.5 115.7 119.9 161.6N 18.1E +16.4 141.3 146.9 162.5N 17.9E +16.3 141.8 147.4 Ail data is in feet unless otherwise stated Coordinates are from slot #41-1 and TVDs are from wellhead. Vertical section is from wellhead on azimuth 0.87 degrees. Calculation uses the minimum curvature method. M.D. 2000.0 2004.0 UNOCAL Ivan River ,41-1 Ivan River Field,Cook Inlet, Alaska CLEARANCE LISTING Page 6 Your ref : 41-1 Version Last revised : 1-Oct-92 Reference wellpath Object wellpath : 13-31 Version #2,,13-31,Ivan River Angle fm Min'm T.V.D. Rect Coordinates M.D. T.V.D. Rect Coordinates HighSide Dist 1996.0 54.3N 0.8E 1955.3 1916.4 201.7N 12.4E +16.2 167.9 2000.0 55.2N 0.8E 1959.2 1919.9 203.5N 12.2E +16.0 169.0 TCyl Dist 175.0 176.2 Ail data is in feet unless otherwise stated Coordinates are from slot ~41-1 and TVDs are from wellhead. Vertical section is from wellhead on azimuth 0.87 degrees. Calculation uses the minimum curvature method. M.D. 0.0 100.0 200.0 300.0 400.0 500.0 600.0 700.0 800.0 875.0 900.0 1000.0 1100.0 UNOCAL Ivan River ,41-1 Ivan River Field,Cook Inlet, Reference wellpath Alaska CLEARANCE LISTING Page 7 Your ref : 41-1 Version #1 Last revised : 1-Oct-92 Object wellpath T.V.D. Rect Coordinates M.D. T.V.D. 0.0 0.0N 0.0E 0.0 0.5 100.0 0.0N 0.0E 99.5 100.0 200.0 0.0N 0.0E 199.5 200.0 300.0 0.0N 0.0E 299.5 300.0 400.0 0.0N 0.0E 399.5 400.0 500.0 0.0N 0.0E 499.5 500.0 600.0 0.0N 0.0E 599.5 600.0 700.0 0.0N 0.0E 699.5 700.0 800.0 0.0N 0.0E 799.5 800.0 875.0 0.0N 0.0E 874.5 875.0 900.0 0.0N 0.0E 899.5 900.0 1000.0 0.0N 0.0E 1000.3 1000.8 1100.0 0.0N 0.0E 1101.1 1101.5 : PMSS <0-???>,,13-31,Ivan River Angle fm Min'm Rect Coordinates HighSide Dist 30.0S 45.0E +123.7 54.1 30.0S 45.0E +122.8 54.1 30.0S 45.0E +122.8 54.1 30.0S 45.0E +122.8 54.1 30.0S 45.0E +122.8 54.1 30.0S 45.0E +122.8 54.1 30.0S 45.0E +122.8 54.1 30.0S 45.0E +122.8 54.1 30.0S 45.0E +122.8 54.1 30.0S 45.0E +122.8 54.1 30.0S 45.0E +122.9 54.1 29.8S 44.4E +123.0 53.5 26.9S 43.1E +121.1 50.9 TCyl Dist 54.1 54.1 54.1 54.1 54.1 54.1 54.1 54.1 54.1 54.1 54.1 53.5 50.9 Ail data is in feet unless otherwise stated Coordinates are from slot #41-1 and TVDs are from wellhead. Vertical section is from wellhead on azimuth 0.87 degrees. Calculation uses the minimum curvature method. CASING AND TU~ING DESIGN WELL CASING STRING FIELD BOROUGtt DATE DESIGN BY ~'~ t" Of-ce '~. . HUD WT. I 9. g #/q. tlYD GR. I 9°? /o. / O.-[ pst/fL. O. MUD WI. II #/q. NYD. GR. II psi/ft. M.S.P. psit CASING SIZE 1./3 J/~" INTERVAL Bottom Top LENGTH ( ~7.F 7'/-'~)) __ Wt. WEIGHT WI BF DESCRIPTION W/O BFx Grade lhread lbs 1ENSION MINIMUM -top of SIRENGTIt section TENSION lbs 1000 lbs IDF /3%919 COLLAPSE PRESS. 0 bottom psi COLLAPSE RESIST. tension psi CDF 3.-~ BURST PRESSURE psi INTERNAL MINIMUM YIELD psi BDF 7./ ~02 0 IVAN RIVER UNIT WELL NO. 41-1 Anticipated Pressures for the 17-1/2" hole: Mud Weight = 70 PCF = 0.486 psi/ft Total Depth of 17-1/2" hole is 875' MD , 875' TVD Pore Pressure Gradient = 0.450 psi/ft Maximum Surface Pressure cannot exceed maximum bottom hole pressure; 875' * 0.450 psi/ft = 425 psi Anticipated Pressures for the 12-1/4" hole: Mud Weight = 74 PCF = 0.514 psi/ft 13-3/8" shoe is proposed to be at 875' MD, 875' TVD Total Depth of 12-1/4" hole is 3000' MD , 2905' TVD Estimated fracture gradient (13-3/8" shoe) = 0.90 psi/ft Pore Pressure Gradient = 0.450 psi/ft Gas gradient (assume worst case) = 0.0 psi/ft Assume 1/2 of the wellbore volume is gas and 1/2 is mud during a kick situation. Maximum Surface pressure = (2905 ft * 0.450 psi/ft) -0.5 (2905 ft * 0.514 psi/ft) - 0.5 (2905 ft * 0 psi/ft) = 560 psi Anticipated Pressures for the 8-1/2" hole: Mud Weight = 76 PCF = 0.528 psi/ft 9-5/8" shoe is proposed to be at 3000' MD, 2905' TVD Total Depth of 8-1/2" hole is 9,020' MD , 8111' TVD Estimated fracture gradient (9-5/8" shoe) = 0.90 psi/ft Pore Pressure Gradient = 0.494 psi/ft Gas gradient (assume worst case) = 0.0 psi/ft Assume 1/2 of the wellbore volume is gas and 1/2 is mud during a kick situation. Maximum Surface pressure = (8111 ft * 0.494 psi/ft) - 0.5 (8111 ft * 0.528 psi/ft) - 0.5 (8133 ft * 0 psi/ft) = 2141 psi GRACE ~154 Active Mud System PILL PIT ~~ SUCTION 72 BBL ~ 200 BBL .SBBL/INCH .~ 2.3BBL/INCH /~///Z~///~./////////~////////////////./////////////////////////// 442'- VOLUME PIT 437 BBL 5.0BBL/INCH . . 136' TOTAL USABLE VOLUME - 1001 BBL - 11.7 BBL/INCH IVR_41-1.XLS Stale: Alaska Borough: Welh 41-1 Reid: ivan River St. Perm; 92-109 Date 11/9/92 Engr: M. Minder Casing Interval Interval Size Bottom Descriptionescriptionescription Tension Top Length lA I 3.375 875 0 875 2A 9.625 2905 0 3000 3A 7 8111 0 9020 4A 0 0 0 0 5A 0 0 0 0 6A 0 0 0 0 7A 0 0 0 0 8A 0 0 0 0 9A 0 0 0 0 10A 0 0 0 0 Lbs Grade Thread Lbs 61 K~55 BTC 0 47 N-80 BTC 0 29 N-80 BTC 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Mud Hydraulic Wieght Gradient ppg psi/ff 1B 9.6 0.499 2B 9.9 0.515 3B 12,0 0.624 4B 0.0 0,000 5B 0.0 0.000 6B 0,0 0.000 7B 0.0 0.000 8B 0.0 0.000 9B 0.0 0.000 10B 0.0 0,000 Maximum Minimum Pressure Yield psi psi BDF 1:307 3090 2.4 3432 6870 2.0 3432 8160 Z.4 0 0 lID[VIOl 0 0 IIDIV/O! o 0 lIDNlO! 0 0 lIDIVi0! 0 0 0 0 #DIV/O! 0 0 #DIV/O! 1C 20 3C 4C 50 6C 7C 8C 90 Tension Strength K/Lbs K/Lbs TDF 53.375 962 18.02 141 1086 7.70 261.58 676 2.58 0 0 #DIV/O! 0 0 #DIV/O! 0 0 #DIV/O! 0 0 #DIV/O! 0 0 #DIV/O! 0 0 IIDIV/O! Collapse Collapse Pr-Bot-Psi Resist. C:OF 437 1540 3.526 1495 4750 3.176 5061 7020 1.387 0 0 liD[V/0! 0 0 #DIV/0! 0 0 lIOiV/0! 0 0 #DNiO! 0 0 #DN/O! 0 0 #DIVIO! Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: The application of Union Oil Company of California (UNOCAL) for exception to 20 AAC 25.055 to allow drilling the UNOCAL Ivan River 41-1 gas development well. UNOCAL by correspondence dated October 14, 1992, has requested an exception to the provisions of 20 AAC 25.055(a)(4) for the drilling of a gas development well in the Ivan River Unit. The exception would allow drilling the UNOCAL Ivan River Unit 41-1 gas development well, as the second well in a section, to a location closer than 1,500 feet to a section line and within 3,000 feet from a well capable of producing from the same pool. The proposed surface location of the well is 712 feet from the south line (FSL), 737 feet from the east line (FEL) of Section 1 T13N R9W Seward Meridian, and the proposed bottom- hole location is 4193 feet from the south line (FSL), 684 feet from the east line (FEL) of Section 1 T13N R9W Seward Meridian. A person who may be harmed if the requested order is issued may file a written protest prior to 4:00 PM November 3, 1992, with the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501, and request a hearing on the matter. If the protest is timely filed, and raises a substantial and material issue crucial to the Commission's determination, a hearing on the matter will be held at the above address at 1:00PM November 17, 1992 in conformance with 20 AAC 25.540. If a hearing is to be held, interested parties may confirm this by calling the Commission's office, (907) 279-1433, after November3, 1992. If no proper protest is filed, the Commission will consider the issuance of the order without a hearing. Russell A. Douglass Commissioner Alaska Oil and Gas Conservation Commission Published October 17, 1992 . -. Unocal North Americ' Oil & Gas Division Unocal Corporation P.O. Box 190247 Anchorage, Alaska 99519-0247 Telephone (907) 276-7600 UNOCAL Alaska Region October 14, 1992 Mr. Bob Crandell Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501-3192 Ivan River Unit State of Alaska Permit to Drill Ivan River #41 - 1 Dear Mr. Crandell: Pursuant to the provisions of 20 ACC 25.005, I have enclosed check number 11209 dated October 14, 1992 in the amount of $100.00 to cover the application fee for Permit to Drill Ivan River #41-1. In as much as field rules do not exist and Statewide spacing applies, we hereby ask for a spacing exception to 20 AAC 25.055 to allow this well to be opened to the well bore closer than 1,500 feet to the governmental section line, and produce closer than 3,000 feet to other wells capable of producing from the same pool. We understand that this application will have to go to public notice and would appreciate your expedited handling of same. ~,ery truly yours, Kevin A. Tabler Land Manager KAT:nk Enclosure cc: George Buck Cig. ITEM (1) Fee (2) Loc ** CHECK LIST FOR NEW WELL PERMITS [2 thru (3) Admi [8~ ' ! [9' thru 13] [10 S 13] (5) BOPE J~' ",. .... /2- 7-¢m · ;,,'~"~',~ , ~ ~_.. [23 thru 28] (6) Other [~29_~ru 3~1] (:7) (8) Addl ~,"'.'~::'~'~'~'"' //-.~-~ .geology' engineering' LAGj_. ,' . 2. 3. 4. , 6. 7 8 . 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. 21. 22. 23. 24. 25. 26. 27 28. rev 08/18/92 jo/6.011 Company Lease & Well NO YES Is permit fee attached ............................................... _~_ f.s well to be located in a defined pool .............................. Is well located proper distance from property line ................... ~ Is well located proper distance from other wells ..................... ~ Is sufficient undedicated acreage available in this pool ............. /~_ Is well to be deviated & is wellbore plat included ................... _~_ Is operator the only affected party .................................. Can permit be approved before 15-day wait ............................ Does operator have a bond in force ................................... //~ Is a conservation order needed ....................................... ~_~ Is administrative approval needed .................................... Is lease nLrnber appropriate .......................................... Does well have a unique name & nLrnber ................................ Is conductor string provided ......................................... Will surface casing protect all zones reasonably expected to serve as an underground source of drinking water .................. /¢¢¢ Is enough cement used to circulate on conductor & surface ............ /¢'~ 1 cement tie in surface & intermediate or production strings ...... ~ 1 cement cover all known productive horizons ..................... .~4 1 all casing give adequate safety in collapse, tension, and burst. .,~( well to be kicked off from an existing wellbore ................... old wellbore abandonment procedure included on 10-403 ............. Wil Wil Wil Is Is Is Is adequate wellbore separation proposed .......... a diverter system required ..................... Is drilling fluid program schematic & list of equi Are necessary diagrams & descriptions of diverter Does BOPE have sufficient pressure rating -- test Does choke manifold comply w/API RP-53 (May 84)... Is presence of H2S gas probable ................... Illlllllellllleelll pment adequate ..... & BOPE attached .... to~psig ..... REMARKS 29. 30. 31. 32. FOR EXPLORATORY & STRATIGRAPHIC WELLS: Are data presented on potential overpressure zones ................... Are seismic analysis data presented on shallow gas zones ............. If offshore loc, are survey results of seabed conditions D~sented... Name and phone ntrnber of contact to supply weekly progress data ...... 33. Additional requ i rements ............................................. INITIAL GEOL UNIT ON/OFF POOL CLASS STATUS AREA ~ SHORE Add i t ional remarks' / 0 --I 'T Z ~0 U'~ --I