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174-010
By Anne Prysunka at 11:35 am, Aug 04, 2022 5HJJ-DPHV% 2*& )URP +DUROG6RXOH & KVRXOH#KLOFRUSFRP! 6HQW 6XQGD\-XO\ $0 7R 5HJJ-DPHV% 2*& '2$$2*&&3UXGKRH%D\ %URRNV3KRHEH/ 2*& 6XEMHFW +$. $WWDFKPHQWV +$.[OV[ dŚĂŶŬƐ Harold Soule Office 907-776-6754 Cell 907-227-9400 7KHLQIRUPDWLRQFRQWDLQHGLQWKLVHPDLOPHVVDJHLVFRQILGHQWLDODQGPD\EHOHJDOO\SULYLOHJHGDQGLVLQWHQGHGRQO\IRUWKHXVHRIWKHLQGLYLGXDORUHQWLW\QDPHG DERYH,I\RXDUHQRWDQLQWHQGHGUHFLSLHQWRULI\RXKDYHUHFHLYHGWKLVPHVVDJHLQHUURU\RXDUHKHUHE\QRWLILHGWKDWDQ\GLVVHPLQDWLRQGLVWULEXWLRQRUFRS\RIWKLV HPDLOLVVWULFWO\SURKLELWHG,I\RXKDYHUHFHLYHGWKLVHPDLOLQHUURUSOHDVHLPPHGLDWHO\QRWLI\XVE\UHWXUQHPDLORUWHOHSKRQHLIWKHVHQGHU VSKRQHQXPEHULVOLVWHG DERYHWKHQSURPSWO\DQGSHUPDQHQWO\GHOHWHWKLVPHVVDJH :KLOHDOOUHDVRQDEOHFDUHKDVEHHQWDNHQWRDYRLGWKHWUDQVPLVVLRQRIYLUXVHVLWLVWKHUHVSRQVLELOLW\RIWKHUHFLSLHQWWRHQVXUHWKDWWKHRQZDUGWUDQVPLVVLRQ RSHQLQJRUXVHRIWKLVPHVVDJHDQGDQ\DWWDFKPHQWVZLOOQRWDGYHUVHO\DIIHFWLWVV\VWHPVRUGDWD1RUHVSRQVLELOLW\LVDFFHSWHGE\WKHFRPSDQ\LQWKLVUHJDUGDQG WKHUHFLSLHQWVKRXOGFDUU\RXWVXFKYLUXVDQGRWKHUFKHFNVDVLWFRQVLGHUVDSSURSULDWH &$87,21 7KLVHPDLORULJLQDWHGIURPRXWVLGHWKH6WDWHRI$ODVNDPDLOV\VWHP'RQRWFOLFNOLQNVRURSHQ DWWDFKPHQWVXQOHVV\RXUHFRJQL]HWKHVHQGHUDQGNQRZWKHFRQWHQWLVVDIH 7%8* 37' STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* SSu b m i tt t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Contractor: Rig No.:404 DATE: 7/8/22 Rig Rep.: Rig Phone: 907-776-6754 Operator: Op. Phone: 907-776-6754 Rep.: E-Mail Well Name: PTD #11740100 Sundry #321-391 Operation: Drilling: Workover: x Explor.: Test: Initial: X Weekly: Bi-Weekly: Rams:250-2500 Annular:250-2500 Valves:250-2500 MASP:2020 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen.P Well Sign P Upper Kelly 0NA Housekeeping P Rig P Lower Kelly 1P PTD On Location P Hazard Sec.P Ball Type 1P Standing Order Posted P Misc.NA Inside BOP 1P FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0NATrip Tank NA NA Annular Preventer 1 13-5/8 5k P Pit Level Indicators PP #1 Rams 1 2-7/8x5-1/2 5k P Flow Indicator NA NA #2 Rams 1 Blinds 5k P Meth Gas Detector PP #3 Rams 0NAH2S Gas Detector PP #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NA Quantity Test Result Choke Ln. Valves 1 2-1/16" 5k P Inside Reel valves 0NA HCR Valves 2 2-1/16" 5k P Kill Line Valves 2 2-1/16" 5k P Check Valve 0NAACCUMULATOR SYSTEM: BOP Misc 0NA Time/Pressure Test Result System Pressure (psi)3000 P CHOKE MANIFOLD:Pressure After Closure (psi)1850 P Quantity Test Result 200 psi Attained (sec)17 P No. Valves 11 P Full Pressure Attained (sec)87 P Manual Chokes 1P Blind Switch Covers: All stations Yes Hydraulic Chokes 1P Nitgn. Bottles # & psi (Avg.): 4 x 2200psi P CH Misc 0NA ACC Misc 0NA Test Results Number of Failures:0 Test Time:11.5 Hours Repair or replacement of equipment will be made within days. Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 7-5-22/06:49Pm Waived By Test Start Date/Time:7/8/2022 3:30 (date) (time)Witness Test Finish Date/Time:7/8/2022 15:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Hilcorp Tested w/ 3 1/2 & 4 1/2" TJ. Test time includes troubleshoot & repairing Hanger leak, re-started testing after repairing leak, test time after restart 5 hrs.(Note while shell testing repaired L/D pin leak, & stem leaks on CMV's 11,10, 8, after getting good shell test first test was good, had isssues with second test troubleshoot & isolate to hanger leak, worked on getting leak stopped then restarted testing from start) Annular closing time w/3 1/2" TJ 17 sec Joe Steiner/Chad Johnson Hilcorp Alaska Harold Soule/Ed Hooter TBU G-20 Test Pressure (psi): hsoule@hilcorp.com Form 10-424 (Revised 05/2021) 2022-0708_BOP_Hilcorp404_TBU_G-20 9 9 9 9 9 9 9 9 99 9 9 MEU -5HJJ Annular closing time w/3 1/2" TJ 17 sec 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 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address: 3800 Centerpoint Drive, Suite 1400 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): McArthur River Field / Hemlock Oil & Middle Kenai G Oil Pools 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 10,642'N/A Casing Collapse Structural Conductor Surface 520 psi Intermediate 1,540 psi Production 4,760 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 Contact Name: Contact Email:kkozub@hilcorp.com Contact Phone: (907) 570-1801 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 Other: ESP/GL Completion 9,725'10,162'9,298'2,020 psi 9,711'9-5/8" 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. 8/25/2021 4-1/2" Daniel E. Marlowe N/A & N/A 10,626' Perforation Depth MD (ft): 5,099' 9,421 - 10,502 10,626' N/A & N/A Tubing Grade:Tubing MD (ft): 8,635 - 9,601 Perforation Depth TVD (ft): 26" 20" 356' 13-3/8"5,099' 798' 356' 798' 4,783' 356' 798' 12.6# / L-80 TVD Burst 9,259' 6,870 psi Tubing Size: MD 1,540 psi 174-010 50-733-20261-00-00Anchorage, AK 99503 Hilcorp Alaska, LLC N/A Trading Bay Unit G-20 COMMISSION USE ONLY Authorized Name: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0018730 Authorized Signature: Operations Manager Karson Kozub PRESENT WELL CONDITION SUMMARY Length Size 3,090 psi N/A Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 12:57 pm, Aug 09, 2021 321-391 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.08.06 12:46:56 -08'00' Dan Marlowe (1267) BJM 8/16/21 DSR-8/9/21DLB 08/09/2021 BOP test to 2500 psi. X X 10-404 dts 8/17/2021 JLC 8/17/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.08.17 09:50:14 -08'00' RBDMS HEW 8/19/2021 Well Work Prognosis Well Name:G-20 API Number:50-733-20261-00-00 Current Status:ESP Producer Leg:Leg #3 (SE corner) Estimated Start Date:August 25, 2021 Rig:HAK 404 Reg. Approval Req’d?403 Date Reg. Approval Rec’vd: Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:174-010 First Call Engineer:Karson Kozub (907) 570-1801 (M) Second Call Engineer:Katherine O’Connor (214) 684-7400 (M) Current Bottom Hole Pressure:2,878 psi @ 8,631’ TVD 0.334 psi/ft based on ESP Gauge 4/13/2018 Maximum Expected BHP:2,878 psi @ 8,631’ TVD 0.334 psi/ft based on ESP Gauge 4/13/2018 Maximum Potential Surface Pressure:2,020 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) *** This is a no flow well as of 12/04/2014 Brief Well Summary G-20 is a comingled G-Zone and Hemlock Producer that was converted to an ESP from a dual string gas-lift completion in November 2014. The current ESP is electrically grounded but still operating. We plan to pull the current ESP completion when it fails an d replace with a combination ESP / Gas lift completion. Last Casing Pressure Test: 10/29/2014 at 9,857’ at 1,500 psi, charted for 30 minutes. Procedure: 1. MIRU HAK 404 2. Circulate the well to production. a. Work over fluid will be filtered inlet water. 3. Set BPV, ND tree, NU BOP and test to 250psi Low/2,500psi High/2,500psi Annular a. Note: Notify AOGCC 48 hours in advance to allow them to witness test 4. Monitor well to ensure it is static. 5. Unseat hanger and POOH with ESP completion. 6. RU SL RIH and tag fill 7. * Contingent clean out if fill is tagged high a. RIH with clean out assembly, circulate bottoms up, POOH b. *BOP’s will be closed as needed to circulate the well 8. PU, RIH with ESP/Gas-lift Combo completion. 9. Land ESP with the bottom of the assembly at ±9,400’. 10. Set BPV, ND BOP, NU tree and test. 11. Turn well over to production. 12. Conduct SVS testing per AOGCC regulations. 13. If cleanout is conducted in step #7 - Conduct a no-flow per AOGCC regulations. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Current / Proposed Wellhead Diagram (Same) 4. BOP Drawing 5. Fluid/Flow Diagrams 6. Rolling BOP Test Procedures 7. RWO Sundry Change Form - Conduct a no-flow per AOGCC regulations. _____________________________________________________________________________________ Updated By: JLL 04/30/18 SCHEMATIC McArthur River Field Well: G-20 Last Completed: 04/13/18 PTD: 174-010 API: 50-733-20261-00 PBTD: 10,538‘ TD:10,642’ 2-9 10 RKB to TBG Hngr = 38.20’ 1 13 3/8” Top of Float Collar 10,538ft TVD: 9,632ft INC: 28° G-Zone 1-5 Hemlock 1-6 Tag 10,162ft MD WO, 11/10/14 w/ 6inX5-1/8in Shoe Top HB-4 9-5/8” 20” 26” TOC 4,618’ - Calculated CASING DETAIL Size Wt Grade Conn ID Top Btm 26” Surf 356’ 20” 94 H-40 BTC 19.124 Surf 798’ 13-3/8” 61 & 68 K-55 BTC 12.415 Surf 5,099’ 9-5/8”47 N-80 BTC 8.681 Surf 1,621’ 47 S-95 BTC 8.681 1,621’ 4,407’ 47 USS-95 BTC 8.535 4,407’ 10,626’ TUBING DETAIL 4-1/2” 12.6 L-80 Supermax 3.958 Surf 9,259’ Perforation Detail Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)Date SPF Total (ft)Condition GZN-1 9,421' 9,447' 8,635' 8,658' 11/11/2014 5 26 Open GZN-2 9,483' 9,495' 8,691' 8,702' 11/11/2014 5 12 Open GZN-4 9,616' 9,656' 8,810' 8,846' 11/11/2014 5 40 Open GZN-5 9,726' 9,735' 8,909' 8,917' 11/11/2014 5 9 Open HB-1 9,933' 9,967' 9,094' 9,124' 01/01/1991 4 34 Open HB-1 9,933' 9,967' 9,094' 9,124' 10/24/1994 634 Open HB-1 9,941' 9,948' 9,101' 9,108' 11/11/2014 5 7 Open HB-1 9,957' 9,963' 9,116' 9,121' 11/11/2014 5 6 Open HB-2 9,990' 10,074' 9,145' 9,220' 11/11/2014 5 84 Open HB-3,4 10,100' 10,268' 9,243' 9,393' 01/01/1991 4 168 Open HB-3 10,100' 10,136' 9,243' 9,275' 11/11/2014 5 36 Open HB-3 10,100' 10,140' 9,243' 9,279' 10/24/1994 640 Open HB-4 10,154' 10,268' 9,291' 9,393' 10/24/1994 6 114 Open HB-5 10,289' 10,305' 9,411' 9,426' 01/01/1991 4 16 Covered HB-5 10,289' 10,305' 9,411' 9,426' 10/24/1994 6 16 Covered HB-5 10,315' 10,360' 9,435' 9,475' 05/01/1974 4 45 Covered HB-5 10,315' 10,420' 9,435' 9,528' 03/01/1978 UK 105 Covered HB-5 10,315' 10,444' 9,435' 9,549' 01/01/1991 4 129 Covered HB-5 10,315' 10,444' 9,435' 9,549' 10/24/1994 6 129 Covered HB-5 10,395' 10,420' 9,506' 9,528' 05/01/1974 4 25 Covered HB-5 10,434' 10,444' 9,540' 9,549' 05/01/1974 4 10 Covered HB-5 10,434' 10,450' 9,540' 9,555' 03/01/1978 UK 16 Covered HB-6 10,470' 10,490' 9,572' 9,590' 03/01/1978 UK 20 Covered HB-6 10,472' 10,502' 9,574' 9,601' 05/01/1974 4 30 Covered JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 1 38.50 38.50 3.958 4.50 CIW-DCB-ESP, 11” x 4-1/2” IBT lift & susp, w/4” Type H BPV Profile 2 2,233’ 2,231’ 3.833 7.063 GLM #1 – SFO-2 w/dummy valve 3 3,699’ 3,556’ 3.833 7.063 GLM #2 – SFO-2 w/ dummy valve 4 4,641’ 4,378’ 3.833 7.063 GLM #3 – SFO-2 w/ dummy valve 5 5,183’ 4,858’ 3.833 7.063 GLM #4 – SFO-2 w/ dummy valve 6 5,729’ 5,342’ 3.833 7.063 GLM #5 – SFO-2 w/ dummy valve 7 6,275’ 5,825’ 3.833 7.063 GLM #6 – SFO-2 w/ dummy valve 8 6,888’ 6,369’ 3.833 7.063 GLM #7 – SFO-2 w/ dummy valve 9 7,432’ 6,849’ 3.833 7.063 GLM #8 – SFO-2 w/ dummy valve 10 9,259’ 8,489’ N/A 5.13 Bolt -On Discharge 9,259’ 8,489’ N/A 5.38 Pumps (x3) – 66 Stg SJ10000 9,330’ 8,553’ N/A 5.13 Gas Separator / Intake 9,332’ 8,555’ N/A 5.13 Tandem Seals (Upper & Lower) 513 Series, BPBSL 9,350’ 8,571’ N/A 5.62 Tandem Motors (x2) 562 Series, KMSLT 500 HP/1800V/165.5A 9,416’ 8,631’ N/A 5.62 Gauge / Centralizer / Anode _____________________________________________________________________________________ Updated By: JLL 08/02/21 PROPOSED McArthur River Field Well: G-20 Last Completed: FUTURE PTD: 174-010 API: 50-733-20261-00 PBTD: 10,538‘TD: 10,642’ 2-9 10 RKB to TBG Hngr = 38.20’ 1 13 3/8” Top of Float Collar 10,538ft TVD: 9,632ft INC: 28° G-Zone 1-5 Hemlock 1-6 TOC 4,618’ - Calculated 9-5/8” 20” 26” Tag 10,162ft MD WO, 11/10/14 w/ 6inX5-1/8in Shoe Top HB-4 CASING DETAIL Size Wt Grade Conn ID Top Btm 26” Surf 356’ 20” 94 H-40 BTC 19.124 Surf 798’ 13-3/8” 61 & 68 K-55 BTC 12.415 Surf 5,099’ 9-5/8”47 N-80 BTC 8.681 Surf 1,621’ 47 S-95 BTC 8.681 1,621’ 4,407’ 47 USS-95 BTC 8.535 4,407’ 10,626’ TUBING DETAIL 4-1/2” Surf ±9,245’ Perforation Detail Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)Date SPF Total (ft)Condition GZN-1 9,421' 9,447' 8,635' 8,658' 11/11/2014 5 26 Open GZN-2 9,483' 9,495' 8,691' 8,702' 11/11/2014 5 12 Open GZN-4 9,616' 9,656' 8,810' 8,846' 11/11/2014 5 40 Open GZN-5 9,726' 9,735' 8,909' 8,917' 11/11/2014 5 9 Open HB-1 9,933' 9,967' 9,094' 9,124' 01/01/1991 4 34 Open HB-1 9,933' 9,967' 9,094' 9,124' 10/24/1994 634 Open HB-1 9,941' 9,948' 9,101' 9,108' 11/11/2014 5 7 Open HB-1 9,957' 9,963' 9,116' 9,121' 11/11/2014 5 6 Open HB-2 9,990' 10,074' 9,145' 9,220' 11/11/2014 5 84 Open HB-3,4 10,100' 10,268' 9,243' 9,393' 01/01/1991 4 168 Open HB-3 10,100' 10,136' 9,243' 9,275' 11/11/2014 5 36 Open HB-3 10,100' 10,140' 9,243' 9,279' 10/24/1994 640 Open HB-4 10,154' 10,268' 9,291' 9,393' 10/24/1994 6 114 Open HB-5 10,289' 10,305' 9,411' 9,426' 01/01/1991 4 16 Covered HB-5 10,289' 10,305' 9,411' 9,426' 10/24/1994 6 16 Covered HB-5 10,315' 10,360' 9,435' 9,475' 05/01/1974 4 45 Covered HB-5 10,315' 10,420' 9,435' 9,528' 03/01/1978 UK 105 Covered HB-5 10,315' 10,444' 9,435' 9,549' 01/01/1991 4 129 Covered HB-5 10,315' 10,444' 9,435' 9,549' 10/24/1994 6 129 Covered HB-5 10,395' 10,420' 9,506' 9,528' 05/01/1974 4 25 Covered HB-5 10,434' 10,444' 9,540' 9,549' 05/01/1974 4 10 Covered HB-5 10,434' 10,450' 9,540' 9,555' 03/01/1978 UK 16 Covered HB-6 10,470' 10,490' 9,572' 9,590' 03/01/1978 UK 20 Covered HB-6 10,472' 10,502' 9,574' 9,601' 05/01/1974 4 30 Covered JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 1 38.50 38.50 3.958 4.50 CIW-DCB-ESP, 11” x 4-1/2” IBT lift & susp, w/4” Type H BPV Profile 2 ±2,233’ ±2,231’ 3.833 7.063 GLM #1 3 ±3,699’ ±3,556’ 3.833 7.063 GLM #2 4 ±4,641’ ±4,378’ 3.833 7.063 GLM #3 5 ±5,183’ ±4,858’ 3.833 7.063 GLM #4 6 ±5,729’ ±5,342’ 3.833 7.063 GLM #5 7 ±6,275’ ±5,825’ 3.833 7.063 GLM #6 8 ±6,888’ ±6,369’ 3.833 7.063 GLM #7 9 ±7,432’ ±6,849’ 3.833 7.063 GLM #8 10 ±9,245’ ±8,477’ -- -- Bolt -On Discharge Pumps (x3) – 66 Stg SJ10000 Gas Separator / Intake Tandem Seals (Upper & Lower) 513 Series, BPBSL Tandem Motors (x2) 562 Series, KMSLT 500 HP/1800V/165.5A ±9,400’ ±8,616’ -- -- Gauge / Centralizer / Anode Grayling Platform G-20 Current 11/05/2014 Grayling Platform BOP Stack HAK 404 20.00' 1.00' HILCORP ALASKA, LLC SwacoSuperchokeBlooey LineTo Gas BusterInlet Rig 404 BOP Test Procedure Attachment #1 Attachment #1 Hilcorp Alaska, LLC - BOP Test Procedure: Rig 404, WO Program – Oil Producers, Gas Producers, Water Injectors Pre Rig Move 1) Blow down well, bleed gas to Well Clean Tank that is vented thru flare to atmosphere 2) Load well with kill weight fluid. x Note: Fluid level will fall to a depth that balances with reservoir pressure. x Shoot fluid levels as needed. 3) Confirm that well is static. Initial Test (i.e. Tubing Hanger is in the Wellhead) If BPV profile is good 1) Set BPV. ND Tree. NU BOP. 2) MU landing joint. Pull BPV. Set 2-way check in hanger. 3) Space out test joint so end of tubing (EOT) is just above the blind rams. 4) Set slips, mark same. Test BOPE per standard test procedure. If the tubing hanger won’t pressure test due to either a penetrator leak or the BPV profile is eroded and/or corroded and BPV cannot be set with tree on. Profile and/or landing threads must be prepped while tree is off. Worst Case: BPV profile and landing threads are bad. 1) Attempt to set BPV through tree. If unsuccessful, shoot fluid level. 2) If fluid level is static from previous fluid level shots, notify Hilcorp Anchorage office that the well is static and the tree must be removed with no BPV. As approved in the sundry, proceed as follows: a) Fill well with KWF if the fluid is not to surface b) ND tree with no BPV Inspect and prepare BPV profile to accept a 2-way valve, or prepare lift-threads to accept landing joint to hold pressure. If well is a producer and the culprit is scale, attempt to clean profile with Muriatic acid and a wire brush or wheel. c) Set 2-way check valve by hand, or MU landing (test) joint to lift-threads d) For ESP wells - Ensure that cap is on cable penetrator e) NU BOP. Test BOPE per standard procedure. 3) If both set of threads appear to be bad and unable to hold a pressure test and / or a penetrator leaks, notify Operations Engineer (Hilcorp), Mr. Bryan McLellan (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness. As outlined and approved in the sundry, proceed as follows: a) Nipple Up BOPE b) With stack out of the test path, test choke manifold per standard procedure c) Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down-hole and not leaking anywhere at surface.) d) Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e) Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) Rig 404 BOP Test Procedure Attachment #1 f) Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn’t hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 4) Pull hanger to surface. (Requires tubing cuts as necessary to free tubing). CBU to displace annulus and tubing with kill weight fluid. 5) If a rolling test was conducted, remove the old hanger, MU new hanger or test plug to the completion tubing. Re-land hanger (or test plug) in tubing head. Test BOPE per standard procedure. Subsequent Tests (i.e. Test Plug can be set in the Tubing-head) 1) Remove wear bushing. a) Use inverted test plug to pull wear busing. MU to joint of tubing. b) Thread into wear bushing c) Back out hold down pins d) Pull and retrieve wear bushing. 2) Break off test plug and invert same- RIH with test plug on joint of tubing. Install a pump-in sub w/ test line plus an open TIW or lower Kelly valve in top of test joint w/ open IBOP. 3) Test BOPE per standard procedure. STANDARD BOPE TEST PROCEDURE (after 2-way check or test plug is set) 1) Fill stack and all lines with rig pump- install chart recorder on test line connected to pump-in sub below safety valve and IBOP in test joint assembly. 2) Note: When testing, pressure up with pump to desired pressure, close valve on pump manifold to trap pressure and read same with chart recorder (test pressures will be indicated in Sundry). 3) Referencing the attached schematics test rams and valves as follows. a) Close 1 st valve on standpipe manifold (PM1), close valves 8,10 &11 on choke manifold and close the annular preventer, open safety valve on top of test jt and close IBOP. Pressure test to 250 psi for 5 minutes and xxx psi (see sundry) high for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank and open annular. b) Close pipe rams and open annular preventer, close safety valve and open IBOP on test joint, close outside valve on kill side of mud cross (K2), open PM1, close valves 5,7 & 9 on choke manifold, open valve 10 on choke manifold. Test to 250 psi for 5 minutes and xxx psi (see sundry) high for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. c) Test Dual Rams. If the well has dual tubing, and dual rams are installed in the stack, test the dual rams by picking up two test joints with dual elevators and lowering them into stack and position them properly in the dual rams. Close rams. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. d) Close manual and super choke / open valves 7 & 9 on choke manifold. Bleed pressure from step b or c recording change and stabilization. If passes after 5 minutes, bleed off pressure back to tank. e) Close inside valve (K1) / open outside valve on kill side of mud cross (K2), close valves 2,4 & 6 / open valves 5,7 & 9 on choke manifold. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. f) Close valves 1 & 3 / open valves 4 & 6 on choke manifold. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. Rig 404 BOP Test Procedure Attachment #1 g) Close HCR (CL2) open valves 2,4 & 6 on choke manifold. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. h) Close inside valve (CL1) / open outside valve (HCR) on choke side of mud cross. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. i) Ensure all pressure is bled off- open pipe rams and pull test joint leaving test plug / 2-way check in place. Close blind rams and attach test line to valve 11 on choke manifold, close valve 1,2 & 3 / open valve 11 on choke manifold. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. j) Test additional floor valves (TIW or Lower Kelly Valve) and IBOPs as necessary. STANDARD TEST PROCEDURE OF CLOSING UNIT (ACCUMULATOR) 1) This is a test of stored energy. Shut off all power to electric and pneumatic pumps. 2) Record “Accumulator Pressure”. It should be +/- 3,000 psi. 3) Close Annular Preventer, the Pipe Rams, and HCR. Close 2 nd set of pipe rams if installed (e.g. dual pipe rams). Open the lower pipe rams to simulate the closing volume on the blinds. 4) Allow pressures to stabilize. 5) While stabilizing: Record pressure values of each Nitrogen bottle and average over the number of bottles. (i.e. Report might read “10 bottles at 2,150 psi”). 6) After accumulator has stabilized, record accumulator pressure again. This represents the pressure and volume remaining after all preventers are closed. (The stabilized pressure must be at least 200 psi above the pre- charge pressure of 1,000 psi). 7) Turn on the electric pump and record the amount of time it takes to build an additional 200 psi on the accumulator gauge. This is usually +/- 30 seconds. 8) Once 200 psi pressure build is reached, turn on the pneumatic pumps and record the time it takes for the pumps to automatically shut-off after the pressure to builds back to original pressure (+/- 3,000 psi). Note: Make sure the electric pump is turned to “Auto”, not “Manual” so the pumps will kick-off automatically. 9) Open all rams and annular and close HCR to place BOPE back into operating position for well work. 10) Fill out AOGCC report. FINAL STEP, FINAL CHECK 1) Test Gas Alarms 2) Double check all rams and valves, for correct operating position 3) Fill out the AOGCC BOPE Test Form (10-424) in Excel Format. Document both the rolling test and the follow up tests. Hilcorp Alaska, LLCHilcorp Alaska, LLCChanges to Approved Rig Work Over Sundry ProcedureSubject: Changes to Approved Sundry Procedure for Well G-20 (PTD 174-010)Sundry #: XXX-XXXAny modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC 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 403Required?Y / NHAKPreparedBy(Initials)HAKApprovedBy(Initials)AOGCC WrittenApproval Received(Person and Date)Approval:Asset Team Operations Manager DatePrepared:First Call Operations Engineer Date ' STATE OF ALASRECEIVED AlIkKA OIL AND GAS CONSERVATION COASION REPORT OF SUNDRY WELL OPERATIONS APR 302018 1.Operations Abandon ❑ Plug Perforations 0 Fracture Stimulate ❑ Pull Tubing D Operations shutdown ❑ Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing❑ ChAn,. 4 iggram ❑ Plug for Redrill 0 Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Well 0 Other. L • e •n ❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development El Exploratory❑ 174-010 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic El Service ❑ 6.API Number: Anchorage,AK 99503 50-733-20261-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0018730 Trading Bay Unit G-20 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A McArthur River Field/Hemlock Oil&Middle Kenai G Oil Pools 11.Present Well Condition Summary: Total Depth measured 10,642 feet Plugs measured N/A feet true vertical 9,719 feet Junk measured N/A feet Effective Depth measured 10,162 feet Packer measured N/A feet true vertical 9,298 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Structural Conductor 356' 26" 356' 356' Surface 798' 20" 798' 798' 1,540 psi 520 psi Intermediate 5,099' 13-3/8" 5,099' 4,783' 3,090 psi 1,540 psi Production 10,626' 9-5/8" 10,626' 9,711' 6,870 psi 4,760 psi Liner Perforation depth Measured depth 9,421 -10,502 feet True Vertical depth 8,635-9,601 feet Tubing(size,grade,measured and true vertical depth) 4-1/2" 12.6#/L-80 9,259(MD) 8,489(TVD) Packers and SSSV(type,measured and true vertical depth) N/A&N/A 12.Stimulation or cement squeeze summary: Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 50 55 Subsequent to operation: 260 94 7530 69 90 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations CI Exploratory 0 Develo ment p ❑ Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil ID Gas 0 WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ❑ 3USP❑ 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: 318-061 Authorized Name: Stan W.Golis Contact Name: Dan Marlowe Authorized Title: Operations Manager Contact Email: dmarlowe•hilco •.com Authorized Signature: Ska.• 1L:" Date: 0/4 /*Se.1 I v Contact Phone: (907)283-1329 Form 10-404 Revised 42 017 5`t-/ b RBDMS MAY .3 1 2018 Submit Original Only H . • McArthur River Field WeG-20 SCHEMATIC Last Completed:04/13/18 PTD: 174-010 Ililcorp Alaska,LLC API: 50-733-20261-00 CASING DETAIL RKB to TBG Hngr=38.20' J 1 I Size Wt Grade Conn ID Top Btm IL 26" Surf 356' 26" 20" 94 H-40 BTC 19.124 Surf 798' 13-3/8" 61&68 K-55 BTC 12.415 Surf 5,099' 47 N-80 BTC 8.681 Surf 1,621' 2a 9-5/8" 47 5-95 BTC 8.681 1,621' 4,407 47 USS 95 BTC 8.535 4,407' 10,626' TUBING DETAIL 4-1/2" 12.6 L-80 Supermax 3.958 Surf 9,259' ,h1, JEWELRY DETAIL a No Depth Depth ID OD Item (MD) (ND) 1 38.50 38.50 3.958 4.50 CIW-DCB-ESP,11"x 4-1/2"I8T lift&susp,w/4"Type H 1l BPV Profile 2 2,233' 2,231' 3.833 7.063 GLM#1-SFO-2 w/dummy valve 3 3,699' 3,556' 3.833 7.063 GLM#2-SFO-2 w/dummy valve 2-9 4 4,641' 4,378' 3.833 7.063 GLM#3-SFO-2 w/dummy valve 4. \ 5 5,183' 4,858' 3.833 7.063 GLM#4-SFO-2 w/dummy valve 133/8" 6 5,729' 5,342' 3.833 7.063 GLM#5-SFO-2 w/dummy valve ISI 7 6,275' 5,825' 3.833 7.063 GLM#6-SFO-2 w/dummy valve 8 6,888' 6,369' 3.833 7.063 GLM#7-SFO-2 w/dummy valve 9 7,432' 6,849' 3.833 7.063 GLM#8-SFO-2 w/dummy valve P9,259' 8,489' N/A 5.13 Bolt-On Discharge 9,259' 8,489' N/A 5.38 Pumps(x3)-66 Stg SJ10000 9,330' 8,553' N/A 5.13 Gas Separator/Intake ill 10 9,332' 8,555' N/A 5.13 Tandem Seals(Upper&Lower)513 Series,BPBSL 9,350 8,571' N/A 5.62 Tandem Motors(x2)562 Series,KMSLT 500 I HP/1800V/165.5A 9,416' 8,631' N/A 5.62 Gauge/Centralizer/Anode Perforation Detail Zone Top Btm Top Btm Date SPF Total Condition (MD) (MD) (ND) (TVD) (ft) iG 10 GZN-1 9,421' 9,447' 8,635' 8,658' 11/11/2014 5 26 Open GZN-2 9,483' 9,495' 8,691' 8,702' 11/11/2014 5 12 Open GZN-4 9,616' 9,656' 8,810' 8,846' 11/11/2014 5 40 Open GZN-5 9,726' 9,735' 8,909' 8,917' 11/11/2014 5 9 Open is HB-1 9,933' 9,967' 9,094' 9,124' 01/01/1991 4 34 Open HB-1 9,933' 9,967' 9,094' 9,124' 10/24/1994 6 34 Open HB-1 9,941' 9,948' 9,101' 9,108' 11/11/2014 5 7 Open HB-1 9,957' 9,963' 9,116' 9,121' 11/11/2014 5 6 Open HB-2 9,990' 10,074' 9,145' 9,220' 11/11/2014 5 84 Open HB-3,4 10,100' 10,268' 9,243' 9,393' 01/01/1991 4 168 Open HB-3 10,100' 10,136' 9,243' 9,275' 11/11/2014 5 36 Open Tag 10,162ft MD SOLI` HB-3 10,100' 10,140' 9,243' 9,279' 10/24/1994 6 40 Open veo,11/10/14 t- Ai8nXSUeinShoe HB-4 10,154' 10,268' 9,291' 9,393' 10/24/1994 6 114 Open Tap F&4 HB-5 10,289' 10,305' 9,411' 9,426' 01/01/1991 4 16 Covered HB-5 10,289' 10,305' 9,411' 9,426' 10/24/1994 6 16 Covered HB-5 10,315' 10,360' 9,435' 9,475' 05/01/1974 4 45 Covered Top of Float Collar HB-5 10,315' 10,420' 9,435' 9,528' 03/01/1978 UK 105 Covered 10,538ft HB-5 10,315' 10,444' 9,435' 9,549' 01/01/1991 4 129 Covered TVD:9,632k IIIIIIIIIIIIIIIIIIIIIII INC:28° HB-5 10,315' 10,444' 9,435' 9,549' 10/24/1994 6 129 Covered HB-5 10,395' 10,420' 9,506' 9,528' 05/01/1974 4 25 Covered ZismilL 9-5/8"" HB-5 10,434' 10,444' 9,540' 9,549' 05/01/1974 4 10 Covered HB-5 10,434' 10,450' 9,540' 9,555' 03/01/1978 UK 16 Covered PBTD:10,538' TD:10,642' HB-6 10,470' 10,490' 9,572' 9,590' 03/01/1978 UK 20 Covered HB-6 10,472' 10,502' 9,574' 9,601' 05/01/1974 4 30 Covered Updated By:JLL 04/30/18 • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date G-20 Moncla 404 50-733-20261-00 174-010 4/9/18 4/13/18 Daily Operations: 04/09/18 Monday Organized accumulator lines on deck.Offloaded (from M/V Titan) and positioned rig carrier w/walkways on strongback beams. Mounted drawworks,A-frame and derrick.Spotted choke house and driller's shack. Released M/V Titan (w/ accumulator house onboard)to pickup Summit pulling equipment,taking advantage of an ongoing callout(seas also expected to increase).Spotted Moncla electrical hub-production electrician energized hub. Quadco set up PVT and pulling unit monitoring systems. Checked tb&casing for pressure. NOS rep set BPV then N/D tree with assistance from prod and rig crew.Spotted accumulator unit and connected lines. M/U blanked RHR hanger test sub in hanger(hanger threads look good). N/U 13 5/8"5M BOPE-torqued all flange bolts and choke and kill lines on BOP stack. Hooked up all accumulator unit lines to stack. Redirected 1502 hoses f/rig to choke manifold. Installed lights in derrick, hooked up choke house lines and ran FIW line to mud tank. Installed carriage support cables, raised and scoped out derrick, rigged up all guide lines and installed drilling line cable to drawworks. Installed rig floor w/supports and wall. Loaded floor with handling equip and tongs-set stairs to rig floor-setup racking mat rails.Attempts to flush oil from well (LW)while demobing from G-01RD resulted in partial returns of 350 bbls with a total of 1868 bbls FIW pumped.Once well loaded up with FIW formation pressure was overcome resulting in complete loss of returns. Attempted to regain circ SW with no success. 04/10/18-Tuesday Positioned super choke on rig carrier. M/U 4 1/2"test jt with RHR xover on btm.Screwed onto RHR sub in hanger then M/U pup w/ pumpin,SV& IBOP on top. Secured BOP stack with chains to strong back beams. Tarped test pump area- closed annular and filled system w/FIW.Shell tested to 2500 psi repairing leaks on 4 hold down pins at tb head.Tested all BOPE to 250 psi low 2500 psi high as per Sundry in accordance with Hilcorp&AOGCC requirements. Performed successful koomey drawdown test.Tested w/4 1/2"and 3 1/2" tb. Checked PVT system on rig tank-Total Safety setup and tested gas alarm systems.Witness waived by Jim Regg/AOGCC 1340 hrs 9Apr18 (by email). R/D test equipment and M/U 4 1/2" IBT landing joint.Screwed into hanger w/NOS rep-backed out lock down pins (leveled rig and centered BOP stack w/chains prior to pulling hanger). Pulled hanfer off seat_@125k- PUW 140k.Worked hanger removing penetrator, ESP cables and control lines-laid down same. Pumped 75 bbls FIW w/no returns or fillup. Began pulling production tubing (standing back in derrick). R/U Summit sheaves in derrick(f/ESP and flat pack cables). POOH w/4 1/2" 12.60#L- 80 SuperMax production string pumping 10 bbls FIW every 20 stds.With 69 stands OOH (EOT @ 4,822') ESP cable was cut by Summit to change reels.Summit changed out ESP cable reel on spooling unit. Continued POOH w/production string pumping twice displacement every 20 stands.76 stands OOH at report(EOT @ 4,367'). Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date G-20 Moncla 404 50-733-20261-00 174-010 4/9/18 4/13/18 Daily Operations: ' � ' . , 04/11/18-Wednesday Finished POOH from 4,367'w/4 1/2" 12.6#L-80 SuperMax production string to ESP assy(pumping 10 bbls FIW every 20 stands). B/D Summit ESP assy checking for failure. No external damaged found during breakdown other than some plastic melting on flatpack at pumps-all sections with rotating internals turned,some were gritty,some showed wear. Main cause of failure appears to be electrical damage due to water invasion in motors.Tb,cable and flatpack in good condition-all clamps accounted for. Cleared and cleaned rig floor-prepped rig floor and Summit spoolers to M/U R/I new ESP/SPM assy. M/U centralizer/anode,gauge slb xt-150, 2-motors 562 series kmslt 500 hp, 2-lower tandem seals 513 series,gas separator/intake,3-pumps 66 stg sj 10000,discharge, bolt on ported pressure sub,xo to SuperMax, tubing handling joint.Serviced components and wired as needed.Started RIH (pumping 10 bbls every 20 stands in)w/ ESP/SPM assy on 4 1/2" 12.60#L-80 Supermax tubing(MUT 3200 FP) adding SPMs as directed. 16 of 137 stands+ESP assy in hole at report time= 1,244'. 04/12/18-Thursday Continued RIH from 1,244' (pumping 10 bbls every 20 stands)w/ESP/SPM assy on 4 1/2" 12.60#L-80 Supermax tubing (MUT 3200 FP)adding SPMs as directed-checking electrical cable every 1000'. Positioned mandrels 1-(7,432'), 2- (6,888'),3-(6,275'),4-(5,729'), 5-(5,182'), 6-(4,640'), 7-(3,699'). At 94 stands in hole(6,512')Summit changed ESP cable reels. Performed electrical cable splice at 6,714' and tested cable. Continued RIH f/6,714'to 9,370' (pumping 10 bbls every 20 stands)w/ESP/SPM assy on 4 1/2" 12.60#L-80 Supermax tubing(MUT 3200 FP) adding SPMs as directed- checking cable every 1000' (SPM 8-2,233'). M/U hanger w/4 1/2"Supermax pin x IBT box pup and 4 1/2" IBT landing joint. Plumbed electrical cable and flat pack thru hanger and tested same. Landed hanger on seat-SOW was 98K- EOT= 9,416.38'-NOS rep ran in lock down pins while landing jt was B/O L/D. 04/13/18-Friday Set BPV. Laid down 4-stands of 4 1/2"SuperMax prod tb-cleared rig floor of tongs and handling tools-removed both sets of stairs,slid driller's shack back and dismounted rig floor. Scoped down derrick-removed drill line and laid over derrick. N/D 13 5/8" 5M BOPE disconnecting koomey lines from both sides along with choke house. B/D mud pump and active tank. Unbolted draw works.Assisted production and NOS in N/U tree.Continued prepping loads to be moved to Steelhead M-31B.Tested hanger neck seals 500 psi 5 mins, 5000 psi 5 mins-tested void to 500 psi 5 mins,5000 psi f/15 mins. Loaded derrick,A-frame and draw works on M/V Titan. Loaded rig carrier and support beams on M/V. NOS shell tested tree to 4500 psi 10 mins-turned well over to production at 2200 hrs. THE STATE °fALASKA GOVERNOR BILL WALKER Stan Golis Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: McArthur River Field, Hemlock Oil & Middle Kenai G Oil Pools, TBU G-20 Permit to Drill Number: 174-010 Sundry Number: 318-061 Dear Mr. Golis: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Hollis S. French J, Chair s_ DATED this 2( day of February, 2018. RBDMS U 'FSE 2 6 2018 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 RECEIVED FEB 13 2018 I Z(L2 (F' AOGCC 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑J Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other. Install ESP/GL Completion P1 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number. Hilcorp Alaska, LLC Exploratory ❑ Development ❑+ Slratigraphic ❑ Service ❑ 174-010 , 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number. Anchorage, AK 99503 50-733-20261-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? N/A ' Will planned perforations require a spacing exception? Yes ❑ No 0 ✓ Trading Bay Unit / G-20 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL0018730 McArthur River Field / Hemlock Oil & Middle Kenai G Oil Pools 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 10,642 9,719 10,162 9,298 2,375 psi N/A 10,203 Casing Length Size MD TVD Burst Collapse Structural Conductor 356' 26" 356' 356' Surface 798' 20" 798' 798' 1,540 psi 520 psi Intermediate 5,099' 13-3/8" 5,099' 4,783' 3,090 psi 1,540 psi Production 10,626' 9-5/8" 10,626' 9,711' 6,870 psi 4,760 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 9,421 - 10,502 8,635 - 9,601 4-1/2" 12.6# / N-80 9,451 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): N/A & N/A N/A & N/A 12. Attachments: Proposal Summary E) Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch 0 Exploratory ❑ Stratigraphic ❑ Development 0 ' Service ❑ 14. Estimated Date for 15. Well Status after proposed work. Commencing Operations: 3/20/2018 OIL ❑+ WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Stan Golis Contact Name: Dan Marlowe Authorized Title: Operations Manager Contact Email: dmarlowe a h11Co .Com G,� ` Contact Phone: (907)283-1329 �J Authorized Signature: .y{'�„` w Date: Z I 1 �1 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. a I Plug Integrity [I BOP Test Mechanical Integrity Test TE]Elest Location Clearance Other: -1- 9904 6otlch /-s;, /C,Sf Post Initial Injection MIT Req'd? Yes ❑ No ❑�.,/ u J Spacing Exception Required? Yes ❑ No Id Subsequent Form Required:- 1 1 RBDMS L - F'3 2 6 2118 APPROVED BYZ 'Z r II �3 Approved by: COMMISSIONER THE COMMISSION Date: (1 �� Form 10403 Revised 412017 x;-14' ORIGINAL ya Submit Form and Approved application is valid for 12 months from the date of approval. Attachments in Duplicate B Hikorp Alaska, LLC Well Work Prognosis Well Name: G-20 API Number: 50-733-20261-00 Current Status: ESP Producer Leg: Leg #3 (SE corner) Estimated Start Date: March 20, 2018 Rig: Moncla 404 Reg. Approval Req'd? 403 Date Reg. Approval Rec'vd: Regulatory Contact: Juanita Lovett (8332) Permit to Drill Number: 174-010 First Call Engineer: Dan Marlowe (907) 283-1329 (0) (907) 398-9904 (M) Second Call Engineer: Mike Quick (907) 777-8442 (0) (907) 317-2969 (M) Current Bottom Hole Pressure: 3,240 psi @ 8,645' TVD 0.375 lbs/ft (7.21 ppg) based on ESP Gauge Maximum Expected BHP: 3,240 psi @ 8,645' TVD 0.375 lbs/ft (7.21 ppg) based on ESP Gauge Maximum Potential Surface Pressure: 2,375 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) *** This is a no flow well as of 12/04/2014 Brief Well Summary G-20 is a comingled G -Zone and Hemlock Producer that was converted to and ESP from a dual string gas -lift completion in November 2014. The current ESP failed February 7th. We plan to pull the current ESP completion and replace with a combination ESP / Gas lift completion. Last Casing Pressure Test: 10/29/2014 at 9857' at 1,500 psig and charted for 30 minutes. Procedure: 1. MIRU Moncla 404 2. Attempt to pump through ESP to circulate hydrocarbon off the well to production. General note - Work over fluid will be FIW and BOP's will be closed as needed to circulate the well. 3. ND Wellhead, NU BOP and test to 250psi low/2,500osi high. (Note: Notify AOGCC 48 hours in advance of test to allow them to witness test). 4. Monitor well to ensure it is static. 5. Unseat hanger and POOH with ESP completion. 6. If needed - RIH with cleanout assembly, Circulate bottoms up, POOH. 7. PU, RIH with ESP/Gas-lift Combo completion. 8. Land ESP with the bottom of the assembly at ±9,400'. 9. ND BOP, NU wellhead and test. 10. Turn well over to production. 11. Conduct SVS testing per AOGCC regulations. 12. If cleanout is conducted in step #6 - Conduct a no -flow per AOGCC regulations. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Current/ Proposed Wellhead Diagram (Same) 4. BOP Drawing 5. Fluid/Flow Diagrams 6. Rolling BOP Test Procedures 7. RWO Sundry Change Form RKBtoTBG Hngr=3&20 1 2G 201 13 3/8" TN 10,1CMw M. 11110'14 46N 10 9p Rp Ha4 10,539rt Tv 9,63Ht INC: 28' PBTD: 10,538' Hatl 14 TD: 10,647 McArthur River Field Well: G-20 Last Com SCHEMATIC PTD: 74-010 eted: 11/17/14 API: 50-733-20261-00 CASING DETAIL Size Wt Grade Conn ID TopBtm (MD) 26" ID Item 1 38.5 Surf 356' 20" 94 H-40 BTC 19.124 Surf 798' 13-3/8" 61 & 68 K-55 BTC 12.415 Surf 5,099' 9-5/8" 47 N-80 BTC 8.681 Surf 1,621' 9-5/8" 47 S-95 BTC 8.681 1,621' 4,407' 9-5/8" 47 USS -95 8TC 8.535 4,407' 10,626' TUBING DETAIL 4-1/2" 12.6 N-80 Supermax 1 3.958 Surf 9,451' JEWELRY DETAIL Perforation Detail Zone Depth Depth Top (TVD) Btm (TVD) No (MD) (TVD) ID Item 1 38.5 38.5 3.958 Hanger 5 9,322 8,545 - XO 4.5in EUE Box X 4.51n EUE pin 9,495' 8,691' 8,702' 11/11/2014 675 Series, 49STG, SH10000, 1-3/16in shaft, 12 9,324 8,548 9,616' #15Hsg, 1:3 AR, P/N 391249, S/N 6P14H P3197 8,810' 8,846' 11/11/2014 5 676 Series, 49STG, 51-110000, 1-3/16in shaft, Open 9,346 8,567 - #15Hsg, 1:3 AR, P/N 391249, S/N 2 11/11/2014 5 9 6P14HP31977 HB -1 9,368 8,587 - Gas Separator/ Intake, 675P 1/1/1991 9,447 8,658 Open Mtr Gauge, Zenith REV B, 5/N 13460049402 9,933' 9,451 8,661 - ESP Btm Perforation Detail Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) Date SPF Total (ft) Condition GZN-1 9,421' 9,447' 8,635' 8,658' 11/11/2014 5 26 Open GZN-2 9,483' 9,495' 8,691' 8,702' 11/11/2014 5 12 Open GZN-4 9,616' 9,656' 8,810' 8,846' 11/11/2014 5 40 Open GZN-5 9,726' 9,735' 8,909' 8,917' 11/11/2014 5 9 Open HB -1 9,933' 9,967' 9,094' 9,124' 1/1/1991 4 34 Open HB -1 9,933' 9,967' 9,094' 9,124' 10/24/1994 6 34 Open HB -1 9,941' 9,948' 9,101' 9,108' 11/11/2014 5 7 Open HB -1 9,957' 9,963' 9,116' 9,121' 11/11/2014 5 6 Open HB -2 9,990' 10,074' 9,145' 9,220' 11/11/2014 5 84 Open HB -3,4 10,100' 10,268' 9,243' 9,393' 1/1/1991 4 168 Open HB -3 10,100' 10,136' 9,243' 9,275' 11/11/2014 5 36 Open HB -3 10,100' 10,140' 9,243' 9,279' 10/24/1994 6 40 Open HB -4 10,154' 10,268' 9,291' 9,393' 10/24/1994 6 114 Open HB -5 10,289' 10,305' 9,411' 9,426' 1/1/1991 4 16 Covered HB -5 10,289' 10,305' 9,411' 9,426' 10/24/1994 6 16 Covered HB -5 10,315' 10,360' 9,435' 9,475' 5/1/1974 4 45 Covered HB -5 10,315' 10,420' 9,435' 9,528' 3/1/1978 UK 105 Covered HB -5 10,315' 10,444' 9,435' 9,549' 1/1/1991 4 129 Covered. HB -5 10,315' 10,444' 9,435 9,549' 10/24/1994 6 129 Covered HB -5 10,395' 10,420' 9,506' 9,528' 5/1/1974 4 25 Covered HB -5 10,434' 10,444' 9,540' 9,549' 5/1/1974 4 10 Covered HB -5 10,434' 10,450' 9,540' 9,555' 3/1/1978 UK 16 Covered HB -6 10,470' 10,490' 9,572' 9,590' 3/1/1978 UK 20 Covered HB -6 10,472' 10,502' 9,574' 9,601' 5/1/1974 4 30 Covered Updated By: JUL 02/08/18 0 Mleoro Alaska, UC Top 1W,538n TVP. 9,6uft W: 2r RKBto TBG 26" 20" 133/8" F ------------- T}14 PBTD: 10,538' TD: 10,647 PROPOSED CASING DETAIL McArthur River Field Well: G-20 Last Completed: FUTURE PTD: 174-010 API: 50-733-20261-00 Size Wt Grade Conn ID Top Btm 26" Condition Hanger 2 ±2,252' Surf 356' 20" 94 H-40 BTC 19.124 Surf 798' 13-3/8" 61 & 68 K-55 BTC 12.415 Surf 5,099' 9,616' 47 N-80 BTC 8.681 Surf 1,621' 9 5/8 47 5-95 BTC 8.681 1,621' 4,407' ±6,350 47 USS -95 BTC 8.535 4,407' 10,626' TUBING DETAIL 4-1/2" 12.6 L-80 Supermax 1 3.958 Surf ±9,275' JEWELRY DETAIL No Depth (MD) Depth (TVD) ID OD Item 1 SPF Total (ft) Condition Hanger 2 ±2,252' ±2,254 8,658' GLM#1 3 ±3,692' ±3,550' GZN-2 GLM #2 4 ±4,609' ±4,350' 11/11/2014 GLM #3 5 ±5,174' ±4,850' 9,616' GLM #4 6 ±5,738' ±5,350' 5 GUM #5 7 ±6,304' ±5,850' 9,735' GLM#6 8 ±6,867' ±6,350 9 GLM #7 9 7,433' ±6,850' 9,094' GLM #8 01/01/1991 ±9,275' ±8,504' N/A Bolt -On Discharge 9,933' 9,967' 9,094' N/A Pumps 6 34 Open N/A Gas Separator/ Intake 10 9,101' 9,108' N/A Tandem Seals 7 Open HB -1 N/A Tandem Motors 9,116' ±9,400' ±8,616' N/A Gauge / Centralizer / Anode Perforation Detail Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) Date SPF Total (ft) Condition GZN-1 9,421' 9,447' 8,635' 8,658' 11/11/2014 5 26 Open GZN-2 9,483' 9,495' 8,691' 8,702' 11/11/2014 5 12 Open GZN-4 9,616' 9,656' 8,810' 8,846' 11/11/2014 5 40 Open GZN-5 9,726' 9,735' 8,909' 8,917' 11/11/2014 5 9 Open HB -1 9,933' 9,967' 9,094' 9,124' 01/01/1991 4 34 Open HB -1 9,933' 9,967' 9,094' 9,124' 10/24/1994 6 34 Open HB -1 9,941' 9,948' 9,101' 9,108' 11/11/2014 5 7 Open HB -1 9,957' 9,963' 9,116' 9,121' 11/11/2014 5 6 Open HB -2 9,990' 10,074' 9,145' 9,220' 11/11/2014 5 84 Open HB -3,4 10,100' 10,268' 9,243' 9,393' 01/01/1991 4 168 Open HB -3 10,100' 10,136' 9,243' 9,275' 11/11/2014 5 36 Open HB -3 10,100' 10,140' 9,243' 9,279' 10/24/1994 6 40 Open HB -4 10,154' 10,268' 9,291' 9,393' 10/24/1994 6 114 Open HB -5 10,289' 10,305' 9,411' 9,426' 01/01/1991 4 16 Covered HB -5 10,289' 10,305' 9,411' 9,426' 10/24/1994 6 16 Covered HB -5 10,315' 10,360' 9,435' 9,475' 05/01/1974 4 45 Covered HB -5 10,315' 10,420' 9,435' 9,528' 03/01/1978 UK 105 Covered HB -5 10,315' 10,444' 9,435' 9,549' 01/01/1991 4 129 Covered HB -5 10,315' 10,444' 9,435' 9,549' 10/24/1994 6 129 Covered HB -5 10,395' 10,420' 9,506' 9,528' 05/01/1974 4 25 Covered HB -5 10,434' 10,444' 9,540' 9,549' 05/01/1974 4 10 Covered HB -5 10,434' 10,450' 9,540' 9,555' 03/01/1978 UK 16 Covered HB -6 10,470' 10,490' 9,572' 9,590' 03/01/1978 UK 20 Covered HB -6 10,472' 10,502' 9,574' 9,601' 05/01/1974 4 30 Covered Updated By: JLL 02/12/18 H Hilmrp Alanku, LII Grayling Platform G-20 13 3/8 X 9 5/8 X 4 1/2 BHTA, Bowen, 41/165M FE X 41/2" Bowen Quick Union Valve, swab, WKM-M, 41/165M FE, HWO, T-24 Valve, wing, WKM-M, 21/165M FE, HWO, T-24 Valve, lower master, WKM-M, 41/165M FE, H W 0, T-24 Grayling Platform G-20 Current 11/05/2014 Tubing hanger, CIW-DCB-ESP, 11 X 4 A IBT lift and susp, w/ 4" type H BPV profile, 5 Y. EN, 2-3/8 continuous control line ports, prepped for BIW penetrator Valve, WKM-M, 31/85M FE, w/ _�-\ MA -16 operator Casing head, CIW-WF, 135/83MX 133/8 casing Valve, ClW-F, 2 1/16 5M FE, O(Y thread bottom, w/ 2- 2 1/16 HWO, AA trim 5M EFO Q_ Adapter, CIW-Toadstool, 11 5M Stdd X 4 1116 5M FE, prepped for 5 % ESP neck, 2- % npt continuous control line ports Tubing head, CIW-DCB, 13 5/8 3M X 11 5M, w/ 2- 2 1/16 5M 550, Valve, WKM-M, 2 1/16 5M FE, X bottom ® ® HWO, DD Qty 2 Casing head, CIW-WF, 135/83MX 133/8 casing Valve, ClW-F, 2 1/16 5M FE, O(Y thread bottom, w/ 2- 2 1/16 HWO, AA trim 5M EFO Q_ n nilwrp Almk., LIT. Grayling Platform 2016 BOP Stack Moncla 05/13/2016 I valves M MONCLA RIG #404 FLUID FLOW DIAGRAM NORMAL OPERATIONS CIRCULATING DOWN CASING, UP TUBING 'REVERSE CIRCULATING' STANDPIPE PANIC LINE RIG FLOOR #2 tt SUPER #9 CHOKE vy3 STRIPPER #3 #5 #7 �1D 11 HEAD it #4 #2 PUMP BOP STACK #4 #6 #8 #5 #� MANUALJ CHOKE LIP q HCR � SUCTION VALVE #1 GAS LINE CUSTERR\ FLUID TANK/PIT Valve Position (O/C) StIN andpipe Pump Manifold l(PMl) 0 Manifold Pump Manifoltl2(PM2) O Pump Manifold 3 (PM3) C Pump Manifold4 (PM4) O Pump Manifold6(PMS) C Mud Kill Line 1 D Cross Kill Line 2 O HCR valve (Choke Line l) C Choke Line2 D Choke Choke Manifold l(CMl) O Manifold Choke Manlfold2(CM2) C Choke Manifold3(CM3) 0 Choke Manifold 41CM9) C Choke Manifold 51CM6) 0 Choke Manifold 61CM6) C Choke Manifold]ICM]) O Choke Manifold 81CM8) C Choke Manifold 91CM9) C Choke Manifold l0 (CM3f/) 0 Super Choke C Manual Choke C Rig 0 Floor Safety Valve MONCLA RIG #404 FLUID FLOW DIAGRAM NORMAL OPERATIONS CIRCULATING DOWN CASING, UP TUBING 'REVERSE CIRCULATING' STANDPIPE PANIC LINE RIG FLOOR #2 tt SUPER #9 CHOKE vy3 STRIPPER #3 #5 #7 �1D 11 HEAD it #4 #2 PUMP BOP STACK #4 #6 #8 #5 #� MANUALJ CHOKE LIP q HCR � SUCTION VALVE #1 GAS LINE CUSTERR\ FLUID TANK/PIT Valve Position (O/C) StIN andpipe Pump Manifold l(PMl) 0 Manifold Pump Manifoltl2(PM2) O Pump Manifold 3 (PM3) C Pump Manifold4 (PM4) O Pump Manifold6(PMS) C Mud Kill Line 1 D Cross Kill Line 2 O HCR valve (Choke Line l) C Choke Line2 D Choke Choke Manifold l(CMl) O Manifold Choke Manlfold2(CM2) C Choke Manifold3(CM3) 0 Choke Manifold 41CM9) C Choke Manifold 51CM6) 0 Choke Manifold 61CM6) C Choke Manifold]ICM]) O Choke Manifold 81CM8) C Choke Manifold 91CM9) C Choke Manifold l0 (CM3f/) 0 Super Choke C Manual Choke C Rig MONCLA RIG #404 FLUID FLOW DIAGRAM NORMAL OPERATIONS CIRCULATING DOWN TUBING, UP CASING ANNULAS "THE LONG WAY" STANDPIPE PANIC NE RIG FLOOR #2 SUPER —I #J CHOKE 1 ll3 STRIPPER y3 1 y5 #7 --M 1� HEAD it if 1l (%4 jf2 UMP BOP STACK �4 1T #6 #6 rt 5 MANUAL J i] `\ CHOKE C `IN HCR LP VALVE SUCTION cns LINE BUSTERW\ FLUID TANK/PIT Valve Position 5[antlpipe Pump Manifold 1(PMl) 0 Manifold Pump Manifold 2 (PM21 C Pump Manifold3(PM3) 0 Pump Manifold9(PM4) C Pum Manifold5(PM51 0 Mud Kill Linel 0 Cross Kill Line 0 HCR valve (Choke Line l) C Choke Line2 0 Choke Choke Man'rfoltl 1(CMlI 0 Manifold Choke Manifoltl2(CM2) C Choke Manifold 3 (CM31 0 Choke Man'rfold 6 (CM01 C Choke ManHoltl 5 (CM51 0 Choke ManHold6(CM61 C Choke Manifold ] (CM]I 0 Choke Manifold B(CM81 C Choke ManRold9(CM9) C Choke Manifold 10 (CMI01 0 Super Choke C Manual Choke C Ri Floor Safe Valve 0 MONCLA RIG #404 FLUID FLOW DIAGRAM NORMAL OPERATIONS CIRCULATING DOWN TUBING, UP CASING ANNULAS "THE LONG WAY" STANDPIPE PANIC NE RIG FLOOR #2 SUPER —I #J CHOKE 1 ll3 STRIPPER y3 1 y5 #7 --M 1� HEAD it if 1l (%4 jf2 UMP BOP STACK �4 1T #6 #6 rt 5 MANUAL J i] `\ CHOKE C `IN HCR LP VALVE SUCTION cns LINE BUSTERW\ FLUID TANK/PIT Valve Position 5[antlpipe Pump Manifold 1(PMl) 0 Manifold Pump Manifold 2 (PM21 C Pump Manifold3(PM3) 0 Pump Manifold9(PM4) C Pum Manifold5(PM51 0 Mud Kill Linel 0 Cross Kill Line 0 HCR valve (Choke Line l) C Choke Line2 0 Choke Choke Man'rfoltl 1(CMlI 0 Manifold Choke Manifoltl2(CM2) C Choke Manifold 3 (CM31 0 Choke Man'rfold 6 (CM01 C Choke ManHoltl 5 (CM51 0 Choke ManHold6(CM61 C Choke Manifold ] (CM]I 0 Choke Manifold H nil.q .Alaska, LLC Attachment #1 Moncla Rig 404 BOP Test Procedure Attachment #1 Hilcorp Alaska, LLC - BOP Test Procedure: Moncla Rig 404, WO Program — Oil Producers, Water Injectors Pre Rig Move 1) Blow down well, bleed gas to Well Clean Tank that is vented thru flare to atmosphere 2) Load well with FIW to kill well. • Note: Fluid level will fall to a depth that balances with reservoir pressure. 3) Shoot fluid level at least 24 hours before moving on well. 4) Shoot fluid level again, right before ND/NU. Confirm that well is static. Initial Test (i.e. Tubing Hanger is in the Wellhead) If BPV profile is good 1) Set BPV. ND Tree. NU BOP. 2) MU landing joint. Pull BPV. Set 2 -way check in hanger. 3) Space out test joint so end of tubing (EOT) is just above the blind rams. 4) Set slips, mark same. Test BOPE per standard test procedure. If the tubing hanger won't pressure test due to either a penetrator leak or the BPV profile is eroded and/or corroded and BPV cannot be set with tree on. Profile and/or landing threads must be prepped while tree is off. Worst Case: BPV profile and landing threads are bad. 1) Attempt to set BPV through tree. If unsuccessful, shoot fluid level. 2) If fluid level is static from previous fluid level shots, notify Hilcorp Anchorage office that the well is static and the tree must be removed with no BPV. As approved in the sundry, proceed as follows: a) ND tree with no BPV b) Inspect and prepare BPV profile to accept a 2 -way valve, or prepare lift -threads to accept landing joint to hold pressure. If well is a producer and the culprit is scale, attempt to clean profile with Muriatic acid and a wire brush or wheel. c) Set 2 -way check valve by hand, or MU landing (test) joint to lift -threads d) For ESP wells - Ensure that cap is on cable penetrator e) NU BOP. Test BOPE per standard procedure. 3) If both set of threads appear to be bad and unable to hold a pressure test and / or a penetrator leaks, notify Operations Engineer (Hilcorp), Mr. Guy Schwartz (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness. As outlined and approved in the sundry, proceed as follows: a) Nipple Up BOPE b) With stack out of the test path, test choke manifold per standard procedure c) Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down -hole and not leaking anywhere at surface.) d) Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e) Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) H Hil... p AI. A., LLC Moncla Rig 404 BOP Test Procedure Attachment #1 f) Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn't hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 4) Pull hanger to surface. (Requires tubing cuts as necessary to free tubing). CBU to displace annulus and tubing with kill weight fluid. 5) If a rolling test was conducted, remove the old hanger, MU new hanger or test plug to the completion tubing. Re -land hanger (or test plug) in tubing head. Test BOPE per standard procedure. Subsequent Tests (i.e. Test Plug can be set in the Tubing -head) 1) Remove wear bushing. a) Use inverted test plug to pull wear busing. MU to joint of tubing. b) Thread into wear bushing c) Back out hold down pins d) Pull and retrieve wear bushing. 2) Break off test plug and invert same- RIH with test plug on joint of tubing. Install a pump -in sub w/ test line plus an open TIW or lower Kelly valve in top of test joint w/ open IBOP. 3) Test BOPE per standard procedure. STANDARD BOPE TEST PROCEDURE (after 2 -way check or test plug is set) 1) Fill stack and all lines with rig pump- install chart recorder on test line connected to pump -in sub below safety valve and IBOP in test joint assembly. 2) Note: When testing, pressure up with pump to desired pressure, close valve on pump manifold to trap pressure and read same with chart recorder (test pressures will be indicated in Sundry). 3) Referencing the attached schematics test rams and valves as follows. a) Close 1" valve on standpipe manifold, close valves 1, 2, 10 on choke manifold and close the annular preventer, open safety valve on top of test jt and close IBOP. Pressure test to 250 psi for 5 minutes and 2,500 psi high for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank and open annular. b) Close pipe rams and open annular preventer, close safety valve and open IBOP on test joint, close outside valve on kill side of mud cross, open 1" valve of standpipe, close valves 3, 4 & 9 on choke manifold, open valves 1 & 2 on choke manifold. Test to 250 psi for 5 minutes and 3,000 psi high for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. c) Test Dual Rams. If the well has dual tubing, and dual rams are installed in the stack, test the dual rams by picking up two testjoints with dual elevators and lowering them into stack and position them properly in the dual rams. Close rams. Test to 250 psi for 5 minutes and 3,000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. d) Close inside valve/open outside valve on kill side of mud cross, close valves 5 & 6 /open valves 3 & 4 on choke manifold. Test to 250 psi for 5 minutes and 3,000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. e) Close manual and super choke / open valves 5 & 6 on choke manifold. Pressure up to —1200 psi and bleed off 200 — 300 #s recording change and stabilization. If passes after 5 minutes, bleed of pressure back to tank. f) Close HCR (outside valve on choke side of mud cross), open manual & super choke. Test to 250 psi for 5 minutes and 3000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. 0 Hilrarp Alaska, LLC Moncla Rig 404 BOP Test Procedure Attachment #1 g) Close inside valve / open outside valve (HCR) on choke side of mud cross. Test to 250 psi for 5 minutes and 3000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. h) Ensure all pressure is bled off- open pipe rams and pull test joint leaving test plug / 2 -way check in place. Close blind rams and attach test line to valve 10 on choke manifold, close valve 7 & 8 / open valve 10 on choke manifold. Test to 250 psi for 5 minutes and 3000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. I) Test additional floor valves (TIW or Lower Kelly Valve) and IBOPs as necessary. STANDARD TEST PROCEDURE OF CLOSING UNIT (ACCUMULATOR) 1) This is a test of stored energy. Shut off all power to electric and pneumatic pumps. 2) Record "Accumulator Pressure". It should be+/- 3,000 psi. 3) Close Annular Preventer, the Pipe Rams, and HCR. Close 2nd set of pipe rams if installed (e.g. dual pipe rams). Open the lower pipe rams to simulate the closing volume on the blinds. 4) Allow pressures to stabilize. 5) While stabilizing: Record pressure values of each Nitrogen bottle and average over the number of bottles. (i.e. Report might read "10 bottles at 2,150 psi"). 6) After accumulator has stabilized, record accumulator pressure again. This represents the pressure and volume remaining after all preventers are closed. (The stabilized pressure must be at least 200 psi above the pre - charge pressure of 1,000 psi). 7) Turn on the pump and record the amount of time it takes to build an additional 200 psi on the accumulator gauge. This is usually +/- 30 seconds. 8) Once 200 psi pressure build is reached, turn on the pneumatic pumps and record the time it takes for the pumps to automatically shut-off after the pressure to builds back to original pressure (+/- 3,000 psi). Note: Make sure the electric pump is turned to "Auto', not "Manual" so the pumps will kick-off automatically. 9) Open all rams and annular and close HCR to place BOPE back into operating position for well work. 10) Fill out AOGCC report. FINAL STEP, FINAL CHECK 1) Test Gas Alarms 2) Double check all rams and valves, for correct operating position 3) Fill out the AOGCC BOPE Test Form (10-424) in Excel Format and e-mail to AOGCC and Juanita Lovett. Document both the rolling test and the follow up tests. HHilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Subject: Changes to Approved Sundry Procedure for Well G-20 (PTD 774-070) 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: Prepared: Asset Team Operations Manager Date First Call Operations Engineer Date THE STATE 01A L A S K__A_ GOVERNOR BILL WALKER January 7, 2015 Mr. Stan Golis Operations Manager — Cl Offshore Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 RE: No -Flow Verification Trading Bay Unit G-20 PTD 1740100 Dear Mr. Golis: Alaska! Conservation1 !' 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov On December 4, 2014 an Alaska Oil and Gas Conservation Commission (AOGCC) Petroleum Inspector witnessed a no -flow test of Trading Bay Unit G-20 located on the Grayling Platform in Cook Inlet. The well is operated by Hilcorp Alaska, LLC (Hilcorp). A subsurface safety valve is not required to be installed in this well based on the no -flow test result. A fail-safe automatic surface safety valve system capable of preventing uncontrolled flow must be maintained in proper working condition in this well as required in 20 AAC 25.265. The AOGCC Inspector confirmed that the proper test equipment — as outlined in AOGCC Industry Guidance Bulletin 10-004 — was rigged up to Trading Bay Unit G-20. The well performance was monitored for three hours with resulting flow rates (oil and gas) below the regulatory limits, passing the no -flow test. The subsurface safety valve must be returned to service if Trading Bay Unit G-20 demonstrates an ability to flow unassisted to surface. Any cleanout, perforating or other stimulation work in this well will necessitate a subsequent no flow test. Please retain a copy of this letter on the Grayling Platform. cc: P. Brooks AOGCC Inspectors Sincerely, James B. Regg" ,...._ �._ ........... ,_ ,.�. Petroleum Inspection Supervisor XANW ,SAN 13 2015 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon ❑ Repair Well ❑ Plug Perforations ❑ Perforate R] Other Q Install ESP Performed: Alter Casing ❑ Pull Tubing[21 Stimulate - Frac ❑ Waiver ❑ Time Extension EJ Change Approved Program ❑ Operat. Shutdown[] Stimulate -Other ❑ Re-enter Suspended Well 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska, LLC Development P] Exploratory ❑ Stratigraphic❑ Service ❑ 174-010 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage, AK 99503 50-733-20261-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0018730 Trading Bay Unit / G-20 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): McArthur River Field / Hemlock Oil & Middle Kenai G Oil Pools 11. Present Well Condition Summary: Total Depth measured 10,642 feet Plugs measured N/A feet true vertical 9,719 feet Junk measured 10,203 feet Effective Depth measured 10,537 feet Packer measured N/A feet true vertical 9,632 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Structural Conductor 356' 26" 356' 356' Surface 798' 20" 798' 798' 1,540 psi 520 psi Intermediate 5,099' 13-3/8" 5,099' 4,783' 3,090 psi 1,540 psi Production 10,626' 9-5/8" 10,626' 9,711' 6,870 psi 4,760 psi Liner RECEIVED C, IV D Perforation depth Measured depth 9,421 - 10,502 feet DEC 0 9 2014 True Vertical depth 8,645 - 9,601 feet A ^ GCC (� Tubing (size, grade, measured and true vertical depth) 4-1/2" 12.6# / N-80 9,451' (MD) 8,662' (TVD) Packers and SSSV (type, measured and true vertical depth) N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): SINK Dt L 17 2014 Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 1220 1230 Subsequent to operation: 311 81 8250 137 138 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run Exploratory❑ DevelopmentE] Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 16. Well Status after work: Oil Q Gas ❑ WDSPL ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 1314-358 Contact Dan Taylor Email dtaylor(WhiIcorp.com k Printed Name Dan Taylor,,- Title Operations Engineer Signature Phone (907) 777-8319 Date 12/8/2014 X RBCMS DEC 11 201 Form 10-404 Revised 10/2012 C Z- ��/ /�� Submit Original Only Hileorp Alaska, LLC RKB to TBG Hngr = 38.20' ESP Top MD: 9,322ft BTM MD: 9,451ft Intake MD:9,368ft INC: 26° 13 3/8in Btm MD: 5,099ft TVD: 4,782ft INC:26' G-Zone(1:5) Top MD: 9,421 ft Btm MD: 9,735 ft Top TVD: 8,635 ft Btm TVD: 8,917 ft Hemlock (1:6) Tag 10,162ft MD Top MD: 9,933 ft WO, 11/10/14-------------BtmMD:10,504ft w/ 6inX5-1/8in Shoe Top TVD: 9,093 ft - Top HB -4 Btm TVD: 9,603 ft Top of Float 10,538ft TVD:9,632ft INC: 28' McArthur River Field, TBU Well: G-20 As Completed: 11-17-14 CASING DETAIL SIZE (in) WT (ppf) GRADE CONN ID (in) TOP (ft) BTM (ft) 26 3.958 Hanger 2 9,322 Surf 356' 20 94 H-40 BTC 19.124 Surf 798' 133/8 61 & 68 K-55 BTC 12.415 Surf 5,099' 95/8 47 47 N-80 5-95 BTC BTC 8.681 8.681 Surf 1,621' 1,621' 4,407' H13-1 47 USS -95 BTC 8.535 4,407' 10,626' TUBING DETAIL 41/2" 12.6 N-80 SprMax 3.958 Surf 9,451' JEWELRY DETAIL No Depth (ft) Depth TVD (ft) ID (in) Item 1 38.5 38.5 3.958 Hanger 2 9,322 8,545 - XO 4.5in EUE Box X 4.5in EUE pin 9,483 9,495 11/11/2014 5 675 Series, 49STG, SH10000, 1-3/16in Open 9,324 8,548 9,656 shaft, #15Hsg, 1:3 AR, P/N 391249, S/N 5 40 Open GZN-5 6P14HP3197 9,735 11/11/2014 5 9 676 Series, 49STG, SH10000, 1-3/16in H13-1 9,346 8,567 - shaft, #15Hsg, 1:3 AR, P/N 391249, S/N 34 Open HB -1 9,933 61314111331977 10/24/1994 9,368 8,587 Open Gas Separator/ Intake, 675P 9,941 9,948 11/11/2014 5 Mtr Gauge, Zenith REV B, S/N Open 9,847 a,6s8 9,963 13460049402 3 j 9,451 8,661 - ESP Btm PERFORATION DETAIL Zone Top MD (ft) Btm MD (ft) Date SPF Total (ft) Condition GZN-1 9,421 9,447 11/11/2014 5 26 Open GZN-2 9,483 9,495 11/11/2014 5 12 Open GZN-4 9,616 9,656 11/11/2014 5 40 Open GZN-5 9,726 9,735 11/11/2014 5 9 Open H13-1 9,933 9,967 1/1/1991 4 34 Open HB -1 9,933 9,967 10/24/1994 6 34 Open HB -1 9,941 9,948 11/11/2014 5 7 Open H13-1 9,957 9,963 11/11/2014 5 6 Open HB -2 9,990 10,074 11/11/2014 5 84 Open HB -3,4 10,100 10,268 1/1/1991 4 168 Open HB -3 10,100 10,136 11/11/2014 5 36 Open H13-3 10,100 10,140 10/24/1994 6 40 Open HB -4 10,154 10,268 10/24/1994 6 114 Open HB -5 10,289 10,305 1/1/1991 4 16 Covered HB -5 10,289 10,305 10/24/1994 6 16 Covered HB -5 10,315 10,360 5/1/1974 4 1 45 Covered HB -5 10,315 10,420 3/1/1978 UK 105 Covered HB -5 10,315 10,444 1/1/1991 4 129 Covered HB -5 10,315 10,444 10/24/1994 6 129 Covered H13-5 10,395 10,420 5/1/1974 4 25 Covered HB -5 10,434 10,444 5/1/1974 4 10 Covered HB -5 1 10,434 10,450 3/1/1978 UK 16 Covered HB -6 10,470 10,490 3/1/1978 UK 20 Covered HB -6 10,472 10,502 5/1/1974 4 301 Covered Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-20 50-733-20261-00 1 174-010 10/18/14 11/15/14 Daily Operations: 10/18/14-Saturday N/D tree, clean & check threads on hanger. Got 10 rounds w/sub. N/U BOPE. M/U 13 5/8 5M spool to riser. N/U riser to well head. Stack 13 5/8 mud cross, double gate & annular. Wk on tq bolts. M/U all hyd lines to BOP & HCR valves. N/U bell nipple & drip pan. 10/19/14 - Sunday PTSM. PJSM. Cont. tq bolts on BOP flanges. Installed panic line. R/u scaffolding. Installed flow nipple. Installed floor H beam & floor panels. Function tested BOPE f/remote panel, good. Fitted beaver slide & installed. R/u 4 1/2 tj. Mu t/hanger. Installed flow line. Filled stack & surface eq. Close annular & perform pre-test, 250 low, 2500 high. Tested w/ pipe rams 250 low 3000 high. PTSM. PJSM. Housekeeping. Test BOPE Test w/ 4 1/2 t/j. Test witnessed by AOGCC Insp, Lou Grimaldi. Started test # 1, found choke valves not properly lined up for test. Re-aligned valves & opened to refill w/ test pump. While pumping, the test jt pressured up, bleed down. Pulled test jt finding no ported sub installed. AOGCC inspector shut down testing & went to the beach till issues were corrected & full pre-test completed successfully by rig crew. Meeting w/ rig crew. C/o sub on tj. Pre-test BOPE with night crew starting w/4 1/2 tj. Had failure on kill line valve. Will be getting a spare. C/O t/ 3 1/2" tj. 10/20/14 - Monday Testing w/ 3 1/2" tj. #1 test w/annular had leak while testing. Tested on pipe rams, had bleed off on high test. No visible leak above rams. Found choke HCR leaking. Greased valve. C/o K-3 valve. Restart pre-test. Annular to 200 psi low & 2500 psi high, all surface equipment to 250 psi low & 3000 psi high. Held each test for 5 min on chart. Accumulator test, flow sensor, pvt, g/I, all good. Housekeeping. Reorganize west deck. Test BOPE as per Hilcorp & AOGCC regulations. Witnessed by AOGCC Inspector, Lou Grimaldi. Test Annular 200 psi low and 2500 psi high, tested w/ 3 1/2 jt, good. 10/21/14-Tuesday Cont. Test BOPE as per Hilcorp & AOGCC regulations, Witnessed by AOGCC Inspector, Lou Grimaldi. Test surface valves and rams 250 psi low and 3000 psi high for 5 mins each. Tested w/ 3 1/2 & 4 1/2 test jts, all good. Break down test jts. R/u W/L, PT lubricator t/1500 good. RIH w/ GS t/ 270' pull "A" stop. RIH w/ 2" swedge t/271' knock out kobe & eq plug POOH. RIH w/GS t/ 271' pull pack off plug. RIH w/GS t/275' pull "A" stop. RIH w/ 2" swedge t/275' knock out kobe & eq plug POOH. RIH w/GS t/ 275' pull pack off plug. RIH w/GS t/ 278' to pull AD-2 stop, no latch. OOH w/sheared GS. RIH w/GS t/ 278' pull AD-2 stop. R/D wireline. M/U 4 1/2 tubing spear w/ 3.947 grapple, bumper sub & RIH t/ 52.15' tag TOH wk down t/ 53.0, unable to work down, discuss options. Decide to release grapple & r/u a-line to make cut before working spear in farther if unable to release. Mobe a-line unit. While waiting, chink under pipe rack, hang ladder by TT, housekeeping. Unload boat. Spot a-line unit. R/U E-Line & lubricator, test lubricator to 1100 psi test good. RIH W/ 2" CCL tool & 19/16" tbg punch, tag @ 9,716'. Log in & punch 12 holes f/ 9,696' to 9,699', POH W/ tbg punch & L/D same. M/U & RIH W/ 2 15/16" RTC to 9,922'. Log in & made cut on 4 1/2" pro. tbg @ 9,845'. POOH W/ E- line & L/D same. R/D E-Line. Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-20 50-733-20261-00 1 174-010 1 10/18/14 11/15/14 Daily Operations: 10/22//14 - Wednesday PTSM. PJSM. Cont. r/d a-line. L/d landing jt. M/u spear w/ 3.885 grapple. Rih t/ 56.1' tag no go at hanger. Back out hanger, I/d pins. P/u hanger, came free @ 120k. Cont pulling staging up t/ 180, wk string f/ 110 t/ 180 w/ no gain. Calculate stretch f/free point, numbers show free around 9,200'- 9,300'. Land hanger, shuck spear, stand back pulling assy. M/u landing jt. R/u a-line. Rih w/ 2 15/16 RTC, make cut @ 9,295'. POOH w/e-line cutter, spent. R/D. Rih spear hanger, back out I/d pins, pick up t/ 132k, had 1 bobble. Cont pulling @ 130k, stood back collar & jars, cont. pull hanger t/ floor. Control line free from btm of hanger at floor. Shuck spear, I/d hanger. R/u & circulate t/production. Pump 3 BPM, 145 psi, circ till clean. Took 117 bbls t/ fill, circ 98 bbls t/ production. Monitor well. R/u mouse hole. Work boat. Arrange pipe rack. Start pulling production string & tongs broke down. Get tongs from Dolly platform & change out. While waiting for tongs, c/o hyd pump on rig. L/D 4 1/2" production tbg, 66 jts, 1 GLM, 2.011'. Recovered 6 bands for control line but had sections of line missing. 10/23/14 - Thursday Cont. POOH I/d 4 1/2 12.6 production tubing. L/d total of 208 jts, 6- GLM = 6,436' up wt 46k, do 42k. Cont. POOH I/d 4 1/2 12.6 production tubing. L/d total of 295 jts, 14 GLM, 1 BV, landing nipple, 1 pup jt =9,256'. Clean & clear floor, wash drill deck, c/o foster tongs. Break down stand in derrick. P/U BHA #1, Overshot w/mill guide, xo, bumper jar, oil jar, 6- 4 3/4 drill collar, acc. jar, xo = 226.79'. 10/24/14 - Friday Cont. p/u collars. TIH w/ overshot assy. P/U 3 1/2 PH-6 wk string. 3 1/2" elevators not latching correctly. Housekeeping while getting another set delivered. Cont. TIH w/ overshot assy. P/U 3 1/2" PH-6 wk string. P/U 163 jts = 5,296', pu wt 80k, do 70k. Cont. TIH w/ overshot assy. P/U 3 1/2" PH-6 wk string. P/U t/ 9,277', up wt 140, do wt 100. Cont. rih t/ tag @ 9,307'. Cont s/o see overshot go over fish. Cont s/o t/ 90k, p/u t/ 160k. S/o bumping down t/ 80 k p/u t/ 153 wt dropped t/ 146k. Cont p/u free. L/D 1 jt POOH t/ 4,051'. 10/25/14-Saturday Cont. POOH, f/ 4,051't/ BHA. Wk BHA. L/d fish, 1- cut jt, 1- GLM, 8 full jts, the last 2 out had split pins, 269'. TOF @ 9,576'. Shuck overshot, redress w/ 4 7/8 grapple. P/u BHA #2, overshot w/mill guide, xo, bumper jar, oil jar, 6- 4 3/4 drill collar's, acc. jar, xo = 226.79. TIH w/ 3 1/2 PH-6 wk string t/ tag @ 9,578'. Cont s/o see overshot go over fish. Cont s/o set 15k dn, p/u t/ 170 24k over. Let jars bleed off. Cont p/u t/ 180, wt dropped set back do tagged 1.5' lower, p/u w/10k dropping off. POOH T/BHA. No fish recovery. Break down overshot. Had marks all the way up in grapple but not full contact. P/U BHA #3, 8.5" junk mill, bit sub, xo, bumper jar, oil jar, 6- 4 3/4 drill collar's, acc. jar, xo = 228.73. TIH t/5,516' up wt 90, do wt 70k. Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-20 50-733-20261-00 1 174-010 1 10/18/14 11/15/14 Daily Operations: 10/26/14-Sunday Cont. TIH w/ milling assy t/ 9,574', up wt 146, do 102. Sent in BOPE test notification to AOGCC f/ 10-28-14. P/U swivel, test kelly valve 250 low, 3000 high 5 min each good. RIH t/ tof @ 9,578', mill t/ 9,581', up wt 148, do 106, rot 120, tq 5500- 6500, circ @! 3 bpm, 250 psi. L/D swivel. POOH t/ BHA. Stand back BHA. L/d mill. Mill had 2-pieces of control line wrapped around it. Had wear pattern on bottom of mill. P/u BHA #4- Overshot w/ top ext, xo, bumper jar, oil jar, 6 4 3/4 drill collars, acc jar, xo= 229.79. TIH t/ 9,570', up wt 146, do 102. Cont. TIH, tag tof @ 9,581'. Cont. s/o 9,587' engaging grapple set do 20k, p/u t/ 170 jarring on it. Cont staging up t/ 230 84k, over jarring with no movement. R/U circ @ 5 bpm 650 psi. Cont. jarring, started moving, weight fell off dragging up hole at 160. Cont. pull drag falling t/ 150. R/d circulating equip. POOH t/5,765', up wt 96, do wt 74. 10/27/14 - Monday Cont POOH t/ BHA @ overshot. L/D fish. The collar was split on top milled jt & recovered a piece of control line in overshot. Had a lot of scale on tubing 2jts above & below GLM @ 9,751'. Recovered 8 jts, 1 GLM, 1-XA sleeve & cut jt = 244'. Shucked overshot. Cleared & cleaned floor. M/U 3 1/2 test jt. Fill stack & surface eq. Test BOPE as per Hilcorp & AOGCC regulations. Witness waived and early test consent by AOGCC Inspector, Jim Regg @ 14: 22 on 10-27-14. Test Annular 250 psi low and 2500 psi high, test all other eq 250 low & 3000 high. Tested w/ 3 1/2 jt, good. Pull test plug. Install wear bushing. L/d test jt, blow down. P/U BHA #5 - Wave btm shoe 8.375 od, 1-jt 8 1/8 wash pipe, top bushing, xo, bumper jar, oil jar, 6- 4 3/4 drill collars, acc jar, xo= 262.31'. TIH t/9,655', up wt 150, do wt 100. P/U power swivel. 10/28/14-Tuesday Wash & ream f/ 9,655't/ tag top of packer @ 9,868', up wt 150, do wt 110, rot wt 128 tq 5500 - 6000, circ @ 4 bpm 490 psi. Rev. circulate till clean @ 4 bpm, 530 psi. Scale in returns. L/D swivel, POOH. L/D BHA. Recovered some control line in shoe. P/U BHA #6, Overshot w/ top ext, xo, bumper jar, oil jar, 6 - 4 3/4 drill collars, acc jar, xo= 229.79. TIH to tag tof @ 9,856', up wt 148 do wt 106. Cont. s/o t/ 86k, observing overshot swallow fish. P/u t/ 170k, let jars bleed off. Cont. pull t/200, no go. Start jarring @ 200k 4x no go. Jar @ 220k 3x and came free. Pulled dragging @ 160k, +/- 20', then falling back t/ 152k. L/d single. POOH T/BHA. Start L/d. 10/29/14 - Wednesday Cont. L/d BHA, recover cut jt, seal assy, cut tail pipe = 57.46'. P/U 9 5/8 RTTS test packer, TIH t/ 9,857' and set packer. R/U test casing t/ 1500 f/ 30 min good. POOH I/d packer. PU MU packer retrieving tool assembly with 8 1/2 " OD flat bottom shoe, packer retriever spear, 4 3/4 " bumper, oil, (6) 4 3/4" drill collars, intensifier, crossover to 3 1/2 PH-6 work string. TIH to 8,605' hit tight spot. PU power swivel. Could not work shoe pass tight spot. Lay down power swivel and currently POOH. Will PU 8 1/2" OD tapered/string mill assembly. Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-20 50-733-20261-00 1 174-010 1 10/18/14 11/15/14 Daily Operations: 10/30/14 - Thursday Finish POOH with packer milling assembly. Wait on 8 7/16" OD tapered and string mills. Chain down BOP stack. Replace regulator on accumulator unit. Hooked up electric power to heater on stabbing board. Service rig. Offload mills from boat. PU MU milling assembly consist of: 8 7/16" OD tapered mill, 8 7/16" OD string mill, xover, 4 3/4" OD bumper, oil jar, (6) 4 3/4" OD drill collars, 4 3/4" OD intensifier, xover to 3 1/2 PH-6 work string. TIH. Tagged high at 8,390'. Lay down single. PU MU power swivel. Begin milling, torqueing from 7K to 9K and stalling. RPM 80, pumping at 3.5 bpm down tubing @ 200 - 300 psi, weight on mill 1-2K. Looks like BHA is too stiff. Will mill for 30 more minutes looking for change and discuss with Anchorage office. Top of packer is 9,882'. 10/31/14 - Friday Finish POOH with tapered/string mill assembly. Break out tapered mill/string mill. MU 7 1/2" OD bladed mill, 8 7/16" string mill, xover, 9'- 3 1/2 IF pup joint, 4 3/4 bumper, oil jars, (6) 4 3/4 drill collars, intensifier jar, xover to 3 1/2 PH-6 work string. TIH to 8,605'. Did not see tight spot at 8,390'. Lay down one joint. PU power swivel. Begin milling at 8,605' with 6K torque, 300 psi at 3.5 bpm with 2-3K weight on mill. Milled from 9,605'-8,610'/ 9,167'-9,168'/ 9,303'-9,305'/ 9,322'- 9,327', total of 13' milling at 4 tight spots. Picking up and laying down power swivel as necessary. TIH to 9,882' top of packer. Circulate 2x tubing volume reversing. POOH. Currently at 2,300' pulling out of hole. Will change out BHA to packer milling assembly. Fluid loss 10 bbls. 11/01/14-Saturday Finish POOH with string mill assembly. Break out assembly and lay down. PU MU 8 7/16" OD packer milling assembly. TIH to 9,882'. PU power swivel. Take parameters. Begin milling packer at 9,882'. 70-80 rpm, 550 psi @ 4.2 bpm with 7000 ft. lbs. torque. 2-3K weight on mill. Added CFS-520 to system. Approximately 3/4%, achieved torque reduction of 1300 ft. lbs. Milling packer with 5700 - 6000 ft. lbs. of torque. Milled 3', packer fell free, slacked off on packer to 9,895'. Begin POOH, packer hung up. Circulate and work pipe 30 minutes. Crew change. Will POOH working packer and milling as necessary. 11/02/14-Sunday POOH slow with packer milling assembly. Recovered remaining packer bottom nut. Break out packer milling tools and PU 8 3/8" cable shoe with 8' extension, jar, collars. TIH with milling assembly to 9,959' tag top of fill. PU power swivel begin washing and reversing down. 4 bpm @ 500 psi, 60 rpm with 5K torque. Getting small pebbles and large chunks of corrosion. Continue working pipe to unplug. Stopped making hole at 10,056'- 97' total. Worked for about an hour at 10,056' stopped milling. Getting gas back 360 units and loosing fluid. Circulate gas through buster. Continue to circulate gas until clear. POOH. Will change out shoe for mill. Will test BOPE when out of hole. Witness waived by Mr. Jim Regg. Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-20 50-733-20261-00 1 174-010 1 10/18/14 11/15/14 Daily Operations: 11/03/14 - Monday RD power swivel. POOH with cable shoe assembly. Had 50% wear on shoe, cables were pushed upward. Had 4 1/4" wear ring inside top bushing 13' up. Begin testing BOPS. 250 low / 3000 psi high. Shutdown and held monthly stand down safety meeting with production. Finish test BOPE with night crew. All test good. Witness waived by Mr. Jim Regg 11/2/2014. PU MU 8 7/16 bladed junk mill, xover, 9' 3 1/2 IF pup joint, 4 3/4 bumper, oil jars, (6) 4 3/4 drill collars, 4 3/4 intensifier, xover to 3 1/2 PH -6 work string. TIH to 10,056'. RU power swivel, begin circulating 600 psi @ 4.1 bpm, 5500 torque with 80 rpm, 3-4K weight on mill. Begin milling/washing fill/corrosion. Getting small rocks back in returns. 11/04/14 - Tuesday CONTINUED MILLING/WASHING FROM 10,056' TO 10,098'. CUTTING 30' CIRC LW THEN REV OUT. PIPE BEGAN PLUGGING IN REV THEN BECAME STUCK. COULD NOT ROTATE OR PUMP. WORKED PIPE UP TO 250K IN EFFORTS TO FREE TB. R/D POWER SWIVEL BECAUSE OF RATED WORK LOAD. SECURED WELL. SLIPPED AND CUT 120' OF DRILL LINE. M/U 10' PUP W/ SAFETY VALVE. ATTACHED KELLY HOSE. WORKED PIPE UP TO 220K WHILE PRESSURING UP DOWN TB. PIPE CAME FREE. CIRCULATED LW UNTIL SECOND RIG PUMP ARRIVED. R/D KELLY HOSE & VALVE. RIGGED POWER SWIVEL BACK UP. R/U SECONDARY MUD PUMP TO TIE INTO SYSTEM IN EFFORTS TO CIRCULATE FILL OUT OF 9 5/8" @ INCREASED RATE. EST — 8 BPM 800# PSI RATE LW AND TURNED 10 BBL PILL LOOSE. CUT DOWN TO EOJ AT 10,129' WITH NO PROBLEM. CIRCULATED BTMS UP TO VERIFY THAT HOLE WAS BEING CLEANED. NO SOLIDS AT BTMS UP W/ PILL. ATTEMPTED TO CIRC IN REV BUT PRESSURED UP. THEN HAD TO WORK PIPE FREE. PUMPED 2ND HIGH VIS PILL (30 BBL) TO SWEEP HOLE. 11/05/14 - Wednesday CHANGED OUT SWAB AND PERFORMED SCHEDULED MAINTENANCE ON RIG PUMP. CHANGED OIL IN RIG DRAWWORKS AND TRANSMISSION. REV CIRC HOLE VOLUME (680 BBLS) AT 4 BPM 425 PSI. LOOSING < 1/4 BPM. INSTALLED AIR STARTER AND FIRED UP SWIVEL. SET IT IN SERVICE. ESTABLISH PARAMETERS: 4 BPM 400#s LW, 6500#s FREE TORQ, 120 RPMs, 138k P/U, 116 S/0, 126 ROTATING WT. SLACKED OFF & TAGGED @ 10,1291. WORKED DOWN TO 10,133'W/ 2-3K WOB. CONNECTED MONCLA SWIVEL. FIRED UP UNIT AND EST PARAMETERS. SLACKED OFF AND TAGGED AT 10,133'. WORKING DOWN TO 10,134'. UNABLE TO GET ENOUGH TORQUE OUT OF MONCLA SWIVEL TO MAKE HOLE. TOTAL FLUID LOSS FOR THE DAY IS 96 BBLS. DECISION WAS MADE TO POOH. BROKE OFF SWIVEL AND L/D SAME. PULLED 36' TO END OF STAND DRAGGING 60K OVER. PULLED NEXT STAND WITH NO OVERPULL. POOH TO BHA. 11/06/14 - Thursday M/U BHA (8 7/16" 6 -bladed mill, xo, 3 1/2" IF pup, 4 3/4" B & 0 jars, 6- 4 3/4" DCs, Ajar, xo)- fresh oil jar. TIH and tagged @ 10,084'(50' high). R/U swivel provided by Moncla. M/U singles and rotated/washed (in rev- 4 BPM) down to 10,126' (EOJ) with minimal effort. M/U single #319 and rotated/washed down to 10,131' (3' off btm) picking up fill. Circ fill out. Continued trying to make hole with plugging getting worse. Attempted to make hole circ LW but would packoff on btm. Could not make hole circ LW. Continued trying to make hole in rev but had to shake plug loose several times. Continued trying to make hole with same problems occurring. While rev a plug out we noticed a pressure increase at btms up so we closed the safety valve below the swivel and broke that single off. Opened valve and blew out a quart of 2/3 golf ball size rocks and pebbles that was wedged in swivel. Decision was made to POOH. R/D swivel. POOH w/ milling assembly. Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-20 50-733-20261-00 1 174-010 10/18/14 11/15/14 Daily Operations: 11/07/14 - Friday Finished POOH w/ BHA #13 (8 7/16" bladed mill & jarring assm). B/D BHA- 0% wear on mill. Pumped out trip tank. Cleared and cleaned rig floor along with general house keeping while waiting on weather. M/U BHA #14 (6" x 5 1/8" SOD x RID Ocean Wave Shoe w/ flapper, 5- 5 3/4" x 5 1/8" WP, 4 3/4" x 2 1/4" Triple Conn Bushing w/ perf'd sub in place, IF pup, 4 3/4" x 2 1/4" B & 0 jars, 6- 4 3/4" x 2 1/4" DCs, 4 3/4" x 2 1/4" A Jar, 4 3/4" x 2 3/4" WS xo) = 391.29'. TIH to 10,126'. P/U power swivel w/ single #314 and M/U to string. Established parameters: 4 bpm 390#s, 142k P/U, 127k S/0, 130k rotating, 4800 torque, 100 RPMs. Rotated/ washed from 10,131' to EOJ at 10,157' in 2 3/4 hrs. Circ 11/2 tbg volumes. Made up next single and continued making hole. 11/08/14 - Saturday Continued rotating/washing w/ 6" shoe & 150' of 5 3/4" WP w/ flapper. Perforated sub in triple connection. Reached 10,176' and pressure spiked indicating chamber was full or as full as we were going to get it. Picked up and circ'd btms up at 2 BPM 1600#s. B/O L/D power swivel + 7 singles to clear derrick. POOH wet to BHA. B/D BHA recovering — 11/4 bbls of granular material up to fist sized rocks. Cleared and cleaned rig floor. M/U BHA # 15 - same as previous run (6" x 5 1/8" SOD x RID Ocean Wave Shoe w/ flapper, 5- 5 3/4" x 5 1/8" WP, 4 3/4" x 2 1/4" Triple Conn Bushing w/ perf'd sub in place, IF pup, 4 3/4" x 2 1/4" B & 0 jars, 6- 4 3/4" x 2 1/4" DCs, 4 3/4" x 2 1/4" A Jar, 4 3/4" x 2 3/4" WS xo) = 391.29'. TIH to 9,413' @ 0600 hrs. BOPE test witness requested @ 7: 53 AM 11/8/2014. Talked w/ Mr. Jim Regg @ 1854 hrs 11/8/2014 concerning the request. No response as of now. 11/09/14 - Sunday Finish TIH to 10,157'. P/U swivel w/ single #315- M/U to string. Checked parameters: P/U 148 S/0 118. Began circ & rotating- RT WT 130, TORQ 4300, RPMs 70, 3 BPM 380#s in rev. Tagged 4' of fill and washed back to TD @ 10,176'. Rotated/washed to 10,184' by 0930 hrs. Spent 2 hrs trying to get deeper (no hole made). Decision was made to POOH. Indications of being on metal. Checked injection rates at 1 BPM = 650#s, 2 BPM = 990#s, 2.5 BPM > 1700#s. Laid down swivel & single. POOH to BHA (wet) (coming out w/ 157 stands). B/D BHA standing collars back and laying down WP (5- jts) & jars. Recovered 1/2 bbl rocks- shoe 100% worn. Down to metal with a 2" chunk broken out. P/U TEST JOINT & INSTALLED TIW VALVE w/ PUMP -IN SUB. M/U TEST PLUG & PULLED WEAR BUSHING. PULLED & B/O TEST PLUG & FLIP. SET TEST PLUG & FILLED STACK. CLOSED HYDRIL & R/U TO FILL TEST JOINT & TESTED HYDRIL. FAILED TEST. AOGCC WITNESS WAIVED @ 9:59 PM 11/9/14 BY MR. JIM REGG. OPENED HYDRIL & PULLED TEST PLUG. B/O TEST PLUG & L/D TEST JOINT. CLEARED AND CLEANED RIG FLOOR. R/D FLOOR. TOOK OFF FLOOR PLATES & MATS. KNOCKED OUT PINS FOR H -BEAM & PULLED. SET SAME ON DECK. CLEANED OUT INSIDE OF DRIP PAN. PULLED EXTENDED PIPE TO DRESSING SLEEVE & SET ON PIPE RACK. PULLED DRIP PAN & SET ON RACK. INSTALLED HANDRAILS AROUND OPENING ON RIG FLOOR. BEGAN N/D HYDRIL CAP. B/O FLOW LINE UNION & HANG FLOWLINE. R/U PULL CABLES TO HYDRIL CAP & P/U. PULLED OLD HYDRIL RUBBER & SET NEW RUBBER IN PLACE. S/O ON HYDRIL CAP & SECURED SAME. Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-20 50-733-20261-00 1 174-010 10/18/14 11/15/14 Daily Operations: 11/10/14 - Monday HSM & JSA. Service rig & equipment. Finish torqueing cap on annular. Removed handrails around opening in rig floor. Installed pollution pan, connected hoses to pollution pan & bell nipple. Installed bell nipple riser & dresser sleeve. Installed H beam & floor plates. Picked up 3-1/2 test joint, made up inside BOP test plug, set test plug, filled stack. Tested annular low 250 high 2500, tested pipe rams, HCR valves, manual valves & manifold low 250 high 3000. Laid down 3-1/2 test joint. Tested blinds low 250 high 3000. Picked up 4-1/2 test joint, screwed into test plug. Tested annular low 250 high 2500, tested pipe rams low 250 high 3000. Pulled test plug, inverted test plug, set wear bushing, tested 4-1/2 IF safety valve low 250 high. Witness of test waived by Jim Regg. Made up 6" bit w/ 310' of tbg + scraper for 9 5/8" casing. FILL HOLE IF DISPLACEMENT IS LOST w/ TRIPPING. TIH TO 9,766'- SUCK OUT SLUG PIT & CLEAN w/ PRESSURE WASHER. R/D RENTAL SWIVEL & ROLLUP HOSES. P/U & MOVE SWIVEL ONTO WEST SIDE. P/U & MOVE SUPER VAC & SETUP. P/U & DRIFT 5 JOINTS OF 3.5 PH6 OFF RACK. P/U & M/U TIW VALVE ONTO 10ft PUP JOINT & S/O TO 10,180'. B/O RETURN LINE & HOOKUP INSIDE LEGROOM #3 TO PRODUCTION TO SHIP TO TRADING BAY. BEGIN CIRCULATING WELL, REV OUT SENDING RETURNS TO PRODUCTION @ 3 BPM 250 psi. SUCK OUT & CLEAN ACTIVE TANK w/ SUPERVAC. BLOW DOWN PUMP LINES AND R/D 2ND MUD PUMP FOR TRANSPORT. START OOH W/ BIT & SCRAPER. 11/11/14 - Tuesday Finish POOH w/ bit & scraper to BHA. Laid down collars & jar. Stood back 5 stands and broke off bit. Loaded out fishing equipment. Held PJSM covering TCP assembly. Positioned needed equipment onto pipe rack. M/U gauges on btm of 1st gun and proceeded w/ TCP assembly. Built 4 5/8" 5 & 6 SPF 60 degree phase TCP assembly. BHA = 863.67'. TIH w/ TCP assembly tagging 6' high at 10,178'(10,156'w/ elevation). Spaced out to R/U E-Line. R/U E-Line equipment and TIH w/ 1.70 GR/CCL. Pulled correlation strip and tied in with log titled PCL G-20 507332026100. Determined that we could perf 2' high (6' of fill since last trip). POOH & R/D E-Line. 11/12/14 - Wednesday HSM & cover JSAs. Serviced rig & equipment. R/D E-Line. Positioned guns as approved by Engs. Filled hole with 31 bbls. Dropped bar and fired TCP guns perforating GZN-1: 9,419'- 9,445' (new), GZN-2: 9,481'- 9,493' (new), GZN-4: 9,614'- 9,654' (new), GZN-5: 9,724'- 9,733' (new), HB-1: 9,939'- 9,946' (new), HB-1: 9,955'- 9,961' (new), HB-2: 9,988'-10,072' (new), HB- 3: 10,098'- 10,134' (new) (Millennium 1, 39 grm chrg). Monitored well for 15 mins. Pumped 18 bbls. Pulled above perfs slowly. Rev out 2 tbg volumes. POOH w/ spent guns. Foster tongs developed a non-pressurized seal failure. Could not repair. Switched to backup Foster tongs and they would only operate in low gear. Lost 2 hrs run time. Stood back 59 stands of workstring for a total in derrick of 80 stands. Laid down remaining workstring. Hold PJSM. B/D TCP assembly. All shots fired. Downhole gauges downloaded and data sent to office. Moved TCP racks to off side in order to load them out and began setting up ESP on pipe rack. 11/13/14 - Thursday HOLD SAFETY MEETING AND PREPARE TO RUN ESP. HOLD MEETING WITH CREW. MAKE UP AND TEST ESP ASSEMBLY. RIG UP WEATHERFORD TONGS AND LAY OUT TUBING ON PIPE RACKS AND TALLEY SAME. HOLD SAFETY MEETING WITH NIGHT CREW. START TIH WITH 4-1/2" 12.6# SUPERMAX TUBING, TESTING CABLE EVERY 1000'. CURRENTLY AT 2,792'. CONTINUE TIH WITH ESP ASSEMBLY, TESTING CABLE EVERY 1000'. CURRENTLY 3,614' IN HOLE AT REPORT TIME. Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-20 50-733-20261-00 1 174-010 1 10/18/14 11/15/14 Daily Operations: 11/14/14 - Friday HOLD SAFETY MEETING AND SERVICE RIG AND EQUIPMENT. CONTINUE TIH WHILE TALLYING AND DRIFTING 4-1/2" SUPERMAX TUBING AND TEST ESP CABLE EVERY 1,000'. 150 JOINTS IN HOLE 5,057', CHANGE OUT SPOOLS AND MAKE SPLICE. TEST CABLE. CONTINUE TIH WIT 4-1/2" SUPERMAX TUBING AND TEST CABLE EVERY 1,000'. HOLD SAFETY MEETING AND SERVICE EQUIPMENT. CONTINUE TIH AND TEST CABLE EVERY 1,000'. ON DEPTH INTAKE SUB AT 9,367' DPM. INSTALL HANGER, MAKE SPLICE AND TIE IN CONTROL LINE. 11/15/14-Saturday HOLD SAFETY MEETING. FINISH TESTING SPLICE. LAND HANGER AND RETEST, GOOD TEST. LOCK IN HANGER AND START RIGGING DOWN WEATHERFORD TONGS, SUMMIT SHEAVES IN DERRICK AND LAY OUT LANDING JOINT. RIG DOWN FLOOR, DRIP PAN, FLOW LINE. INSTALL HAND RAILS ON RIG FLOOR. RIG DOWN BELL NIPPLE, SCAFFOLDING, BOPS AND RISER. REMOVE OLD BOLTS FROM TUBING HEAD. HOLD SAFETY MEETING AND CUT BOLTS ON WELLHEAD. RIG UP PRODUCTION TREE, SSV AND WING VALVES. MEMORANDUM TO: Jim Regg P. I. Supervisor FROM: Johnnie Hill Petroleum Inspector State of Alaska Alaska Oil and Gas Conservation Commission DATE: 12/4/2014 SUBJECT: No Flow Test TBU G-20 Hilcorp PTD 1740100 12/4/2014: After the flight to the Grayling Platform I was greeted by the Production Operator Wayne Johnson. We reviewed the current condition of TBU G-20 and Hilcorp's planned no - flow test procedure. The well had been shut-in the previous day and depressured with the tubing and inner annulus open to communication and the flow line isolated from production. This well has a packer in it. Test equipment was plumbed from the top of the tree cap through a'/2" nipple, through a %" x %" tee with a 0-30psi calibrated pressure gauge, and out to a 1" ball valve just upstream of the ERDCO Armor -Flow meter (model 3461-03TO-13 scaled 0-1800 standard cubic feet per hour (SCFH)). A 1" air/water hose routed any well flow to a near -by open top barrel. Tho fn11^XAAnry +nhlo chrn%nic tcncf riAtA61Q- Time Pressures' (psi) Flow Rate Gas - scf/hr Liquid Remarks - al/hr 13:10 0/0/0 0 0 Tubing open to vent 13:40 0/0/0 0 0 Shut in tubing 14:40 0/0/0 0 0 Opened tubing; Opsi. 0 scfh 15:10 0/0/0 0 0 Shut in 15:40 0/0/0 0 0 Shut in 16:10 0/0/0 0 0 Opened tubing; Opsi. 0 scfh ' ' Pressures are T/IA/OA Summary: No gas or liquid was produced during the no -flow test. Attachments: 2 photos SCANNED JAN 1 4 2015 2014-1204—No-Flow TBU_G-20jh.docx Page 1 of 2 No -Flow Test - TBU G-20 (PTD 1740100) Photos by AOGCC Inspector J. Hill 12/4/2014 2014-1204_No-Flow_TBU_G-20,jh.docx Page 2 of 2 Pressure gauge and Flow meter Flow meter Regg, James B (DOA) From: Bob Finch - (C) <bfinch@hilcorp.com> Sent: Tuesday, November 04, 2014 9:32 AM To: Regg, James B (DOA) Subject: RE: Grayling Platform Moncal Rig 301 Well TBU G-20 BOPE Test Reportll/3/2014 Attachments: Moncla BOPE Test Procedures.pdf L, - Bob Bob Finch WSM (C) Hilcorp Alaska Cell 832-578-2246 Grayling Platform WSM 907-776-6754 SCA NHED NOV 2 0 2014 From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Tuesday, November 04, 2014 9:28 AM To: Bob Finch - (C) Subject: RE: Grayling Platform Moncal Rig 301 Well TBU G-20 BOPE Test Reportll/3/2014 Please send me the sequence of components tested so I can better understand the charts. Thank you. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim.regs@alaska.gov. From: Bob Finch - (C) [mailto:bfinch@hilcorp.com] Sent: Tuesday, November 04, 2014 6:58 AM To: Regg, James B (DOA); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (DOA) Cc: Juanita Lovett Subject: Grayling Platform Moncal Rig 301 Well TBU G-20 BOPE Test Reportll/3/2014 Bob Finch WSM (C) Hilcorp Alaska Cell 832-578-2246 Grayling Platform WSM 907-776-6754 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report Submit to: iim.regg(a�alaska.gov AOGCC. Inspectorsa(�.alaska.gov Phoebe. brooks@alaska. qov Contractor: Moncla - Rig No.: 301 DATE: 11/3/14 Rig Rep.: Anthony Edmond Rig Phone: 907-776-6751 Operator: Hilcorp Alaska LLC Op. Phone: 907-776-6754 Rep.: Bob Finch E -Mail bfinch@hilcorp.com Well Name: TBU G-20 PTD # 174-010 Sundry # 314-358 Operation: Test: Test Pressure (psi): Drilling: Initial: Rams: 250/3000 - Workover: X Weekly: X Annular: 250/2500 Explor.: Bi -Weekly: Valves: 250/3000 MASP: 0 ' MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: NA Test Result Test Result P Quantity Test Result Location Gen. P Well Sign P Upper Kelly 0 NA Housekeeping P Rig NA Lower Kelly 1 P PTD On Location P Hazard Sec. NA Ball Type I P Standing Order Posted P Misc. NA Inside BOP 1 P P P #4 Rams FSV Misc 0 NA BOP STACK: Quantity Size/Type Test Result MUD SYSTEM: Visual Alarm Stripper 0 NA Trip Tank P P Annular Preventer 1 135/8 P Pit Level Indicators P P #1 Rams 1 2 7/8 x 5 P Flow Indicator P P #2 Rams 1 Blinds P Meth Gas Detector P P #3 Rams 0 NA H2S Gas Detector P P #4 Rams 0 NA MS Misc 0 NA #5 Rams 0 NA #6 Rams 0 NA Quantity Test Result Choke Ln. Valves 1 31/8 P Inside Reel valves 0 NA HCR Valves 2 31/8 P Kill Line Valves 2 31/821/16 P Check Valve 0 NA ACCUMULATOR SYSTEM: BOP Misc 0 NA Time/Pressure Test Result System Pressure (psi) 2900 P CHOKE MANIFOLD: Pressure After Closure (psi) 1700 P Quantity Test Result 200 psi Attained (sec) 42 P - No. Valves 11 P Full Pressure Attained (sec) 214 P Manual Chokes 1 P Blind Switch Covers: All stations Yes Hydraulic Chokes 1 P Nitgn. Bottles Avg. (# and psi): 4 @ 2150 P CH Misc 0 NA ACC Misc 0 NA Test Results Number of Failures: 0 Test Time: 7_0 Hours Repair or replacement of equipment will be made within days. Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Remarks: On test # 8 on chart re -set pressure on low 250 psi. First time test pump operator had to high. MASP calculation based on alternate pressure gradient as approved in Sundry 314-358. 24 hr Notice Yes est Start Date/Time: est Finish Date/Time Date/Time 11/112014 6:38 By Jim 11/3/2014 14:00 (date) (time) Witness 11/3/2014 21:00 Form 10-424 (Revised 06/2014) 2014-1103_BOP_Moncla301_TBU_G-20.xisx ms�� 114 09 15 ,kk&-C,k 301 - F�� -rp UG-zo Prib 1-24oloo 11(3/t4 20 Z -16 - CA 10, CA I TO one 30 s � s�adw3a O 0 iJi31itl0�1 `v $ o y 1 I o a w �\ do ina iavHn�. { I L' 'A 10 OW 'ON iadHO ,l' o j/ 1 r S n _ k4v�cfa_ 3a i - Bd�cT 780-GZO fr+�, 1-74oitD �• 31� 3s VO n++ (� iZ4C rvo lu �s PJ4--1 5 - TO, Moncla BOP TEST At�CiO- 30 I --(Pa G-ze) 174-O 10 3/14 �j S/ L Fill stack w/ water through kill line with choke manifold open back to tank leave valve 8 closed. Close valve 10 when choke is full, close bag when stack is full, close k-3 valve, Fill test it with test pump till fluid comes out IBOP have a hand in wellhead room w/casing valve open monitoring it during all tests. Testw/27/8T9 1) - '200 low f/ 5 min, 2500 high f/ 5 min (All other tests 3000 high) Close, remove sensor from outside valve 11, 2) r open annular, test 200 low & 3000 high ---_ � g � : �f:�s choke 3} open IBOP (dart valve), close choke open valves 10 & K-3 4) Close choke open 7,5,9, close ------ . ,open K-2 HCR, use test sub f/.:. 5) Close choke open valves 4 & 6 6) _ _ open valves 1 & 3 pressure up to 700 + -psi &bleed down 200-300 psi w/ each 7) Close C*-'.- open choke valve 1 8) Close i:., open choke HCR Preform Accumulator test—then pull TJ With test jt in hole & system up to pressure. 1) Turn off electric & air pumps 2) Record accumulator pressure (+ - 3000psi) 3) Close Annular, pipe ram's, & her valves, open pipe rams to simulate blinds 4) While pressure is stabilizing check pressure in nitrogen bottles & record. 5) Record accumulator pressure 6) Turn on electric pump & time seconds to pressure up 200 psi, turn on air pumps & time till unit pressures up to 3000 psi & shuts off ( time will start from time electric pump starts till all pumps shut off) 9) Back out testlt & pull, . install test hose to choke manifold outside valve 11, close valves 1,2,3 ��' �\��%%%� THE STATE Fifa C : erid r- E �9's em-_ -_-, _ .f ., 1_ , . = ? 333 West Seventh Avenue =_ _= GOVERNOR SE:1�? PAk�,El.l. Anchorage Alaska 9950 3572 ep, u.. 907 s A. .f e" lox 9C/ x7 /:)!) Dan Taylor swap MAY 0 7 2014 ©1 Operations Engineer7L'f' � Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Re: McArthur River Field, Hemlock Oil Pool, Trading Bay Unit G-20 Sundry Number: 314-249 Dear Mr. Taylor: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, O Daniel T. Seamount, Jr. /7. Commissioner DATED thisday of April, 2014. Encl. Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Tuesday, July 01, 2014 9:56 AM To: 'Juanita Lovett'; Daniel Taylor Cc: samantha.carlisle@alaska.gov Subject: RE: Sundry Cancellation - Sundry # 314-249 - PTD 174-010 C,,20 Sundry 314-249 has been withdrawn. �tA. Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226) or (Guv.schwartz@alaska.gov). From: Juanita Lovett [mailtoJlovett hilcorp.com] Sent: Tuesday, June 24, 2014 10:40 AM To: Schwartz, Guy L (DOA); Daniel Taylor Subject: Sundry Cancellation - Sundry # 314-249 - PTD 174-010 Guy, Please withdraw the above mentioned sundry. It has been replaced by sundry # 314-358. Thank you, Juanita Lovett Sr. Operations/Regulatory Tech Hilcorp Alaska, LLC 3800 Centerpoint Drive Suite 100 Anchorage, AK 99503 Office: (907) 777-8332 Email: ilovett@hilcorp.com THE STATE of A 7 fig, � �;'7 /4" GOVERNOR SEAN PARNELL Dan Taylor Operations Engineer Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400"NED Anchorage, AK 99503 Re: McArthur River Field, Hemlock Oil Pool, Trading Bay Unit G-20 Sundry Number: 314-358 Dear Mr. Taylor: a.Ia.s ka �I an Gas 333 'Nest Seventh Avenue Anchorage, A!aska 99501-357% Main: 907.279.1433 Fax: 907.276.7542 Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, ;agthy P. o�ers4ter Chair DATED this 16day of June, 2014. Encl. RECEIVED STATE OF ALASKA JUN 0 6 2014 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS �� 20 AAC 25280 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool 0 Repair Well ❑ Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate E Pull Tubing Q Time Extension ❑ Operations Shutdown ❑ Re-enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other: Run ESP Q, 2. Operator Name: 4. Current Well Gass: 5. Permit to Drill Number: Hilcorp Alaska, LLC - Exploratory ❑ Development Stratigraphic ❑ Service ❑ 174-010 ' 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage, AK 99503 50-733-20261-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 228A Will planned perforations require a spacing exception? Yes ❑ No El Trading Bay Unit / G-20 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL0018730 I McArthur River Field / Hemlock Oil Pool 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): 10,642 9,719 10,537 9,632 � N/A 10,203 Casing Length Size MD TVD Burst Collapse Structural Conductor 356' 26" 356' 356' Surface 798' 20" 798' 798' 1,540 psi 520 psi Intermediate 5,099' 13-3/8" 5,099' 4,783' 3,090 psi 1,540 psi Production 10,626' 9-5/8" 10,626' 9,711' 6,870 psi 4,760 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 9,933 - 10,502 9,094 - 9,601 4-1/2" 112.6# / N-80 9,901 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Baker Model D Packer & SSSV - N/A 9,859' (MD) 9,028' (TVD) & N/A 12. Attachments: Description Summary of Proposal 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: 6/23/2014 Oil Gas ❑ WINJ ❑ GINJ ❑ WDSPL ❑ Suspended ❑ WAG ❑ Abandoned ❑ 16. Verbal Approval: Date: Commission Representative: GSTOR ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Dan Taylor Email dtaylor(Whilcorp.com Printed Name Dan Taylor Title Operations Engineer Signature Phone (907) 777-8319 Date 6/5/2014 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity ❑ BOP Test LrJ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Spacing Exception Required? Yes ❑ No OJ Subsequent Form Required: / a q c= APPROVED BY Approved by: COMMISSIONER THE COMMISSION / Date: �y ��b —/ �roho {�, Submit Form and Form 10-403 (Revised 10/201) App CR4iCj j INlAr 12 months from the date of approval. 111DpttapcE/r1M'§UN ouIiA 16 2 _. \yR, U9�jj, Hilcorp Alaska, LLQ Well Prognosis Well: G-20 Date: 6/2/2014 Well Name: G-20 API Number: 50-733-20261-00 Current Status: Producer Leg: 3 Estimated Start Date: June 23, 2014 Rig: NA Reg. Approval Req'd? 10-403 Date Reg. Approval Rec'vd: Regulatory Contact: Juanita Lovett 777-8332 Permit to Drill Number: 174-0100 First Call Engineer: Dan Taylor 907 777-8319 O 907 947-8051 M Second Call Engineer: James Young 907 777-8421 O AFE Number: Current Bottom Hole Pressure: Maximum Expected BHP: Max. Allowable Surface Pressure: Brief Well Summary 3,750 psi @ 9,347ft TVD / 10,218ft MD 3,750 psi @ 9,347ft TVD / 10,218ft MD 1,772 psi 0.40 psi/ft at mid -pert, Survey 2009 0.40 psi/ft at mid -pert, Survey 2009 2/3 TVD * 0.1 psi/ft + 1/3 TVD " 0.435psi/ft Grayling G-20 is an oil producing Hemlock completion currently on gas lift. On April 24, 2014 the well loaded up and died and has not kicked off again. After running a lead impression block it was observed to be collapsed tubing at +/-9,704ft MD. G-20 went off-line making 2,138bpd with a 6.5% oil cut (tested 4/15/14). This program outlines the procedure of removing the current gas lift completion, adding perforations to the G -Zone, and re -completing the well with an ESP., Procedure: 1. Bleed off well. 2. Rig up slick line. 3. Run in hole and shift'XA' sliding sleeve at 9,822ft. 4. Circulate down annulus +/-500bbis filtered inlet water. Work over fluid will be filtered inlet water unless well conditions dictate heavier brine is required. a. Shoot and record fluid level (consistent FL at +/-800ft MD). 5. Set back pressure valve. 6. Nipple down tree / nipple up BOP.�� P s 3� i 5• 7. Perform BOP test. a. If back pressure valve will not set with tree on refer to attached rolling test procedure. b. 8. Pull hanger and lay down. 9. Pull out of hole laying down production tubing (string weight to packer at 9,859ft MD,—110k1bs). a. If tubing does not pull: i. Rig up slick line. ii. Test lubricator. iii. Run in hole to +/-9,840ft MD (+/-19ft above packer) and make tubing cut. 10. Pickup 9-5/8in packer pulling tool. a. Burn over and latch packer. 11. Circulate bottoms up and pull out of hole. a. Close bag and spot lost circulation pill if needed. 12. Pick up 9-5/8in clean out assembly. a. Trip in hole and clean out to +/-10,500ft (last tag 10,203ft MD on 10/25/13). b. Fish in hole: 4/22/74, cut off "mule shoe, "N" Nipple plus 5ft of 4-1/2in 12.6ppf N-80 buttress tubing". c. Circulate bottoms up and pull out of hoe. 13. Pick up 9-5/8in test packer. a. Trip in hole to +/-9,800ft and test casing to +/-1,500psi and chart. b. Pull out of hole to +/-6,OOOft laying down work string. jl 14. Pick up storm packer. a. Trip in hole to +/-100ft, set and test packer. 15. Change out tubing spool and test. " 16. Pull storm packer and lay down. bre 17. Pull work string and 9-5/8in test packer and lay down. 18. Pick up tubing conveyed perforating assembly spacing out shots over the following intervals and perforate. 1 0 Hilcorp Alaska, LL Bench Top MD (ft) Btm MD (ft) Top ND (ft) Btm TV D (ft) Total (ft) GZN-1 9,421 9,447 8,635 8,658 26 GZN-2 9,483 9,495 8,691 8,702 12 GZIw4 9,616 9,656 8,810 8,846 40 GZN-5 9,726 9,735 8,909 8,917 9 HK -1 9,941 9,948 9,101 9,108 7 HK -1 9,957 9,963 9,116 9,121 6 HK -2 9,990 10,074 9,145 9,220 84 HK -3 10,100 10,136 9,243 9,275 36 HK -4 10,148 10,181 9,286 9,315 33 HK -4 10,191 10,229 9,324 9,358 38 HK -4 10,237 10,271 9,365 9,395 34 HK -5 10,314 10,371 9,434 9,484 57 HK -5 10,380 10,423 9,492 9,531 43 HK -5 10,431 10,445 9,538 9,550 14 HK -6 10,472 10,504 9,574 9,603 32 Well Prognosis Well: G-20 Date: 6/2/2014 a. Close bag and circulate out perf gas. b. Pull out of hole with TCP guns checking for all shots fired. 19. Pick up and run in hole with completion: a. ESP (with GLM's as alternate lift method). b. Cable c. Capillary Tubing d. Set ESP at +1-9,300ft MD. 20. Land Hanger and test. 21. Turn well over to production. 22. Complete a surface safety valve test and `no flow' test in compliance with AOGCC regulations. a. See 20 AAC 25.265. Well safety valve systems. Attachments: 1. As -built Well Schematic 2. Proposed Well Schematic 3. Current Well Head 4. BOP Stack 5. Rolling Test Procedure McArthur River Field, TBU SCHEMATIC Well: G-20 HacorpAlaska, LLC As Completed: 1/4/1985 RKB to TBG Hngr = 38.20' 1 TBG Cut: 4/22/74 @ 9,901ft 2 XA 13 1 P Last Tag 117 10/25/13 @ 10,203ft H B-5 5 H B-6 6 ` 8 CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 26" HB -1 1909.43' 3.958" 4-1/2" Camco "MMG" Mandrel Surf 356' 20" 94 H-40 Buttress 19.124" Surf 798' 13-3/8" 61 & 68 K-55 Buttress 12.415" Surf 5,099- 9-5/8" 47 47 47 N-80 5-95 USS -95 Buttress Buttress Buttress 8.681" 8.681" 8.535" Surf 1,621' 4,407' 1,621' 1 4,407' 10,626' TUBING DETAIL 4-1/2" 12.6 N-80 Buttress 1 3.958" Surf 9,901' JEWELRY DETAIL No Depth ID Item 1 305.18' 3.958" 4-1/2" Otis BV Landing Nipple HB -1 1909.43' 3.958" 4-1/2" Camco "MMG" Mandrel Open 3293.97' 3.958" 4-1/2" Camco "MMG" Mandrel 4445.85' 3.958" 4-1/2" Camco "MMG" Mandrel 5255.69' 3.958" 4-1/2" Camco "MMG" Mandrel 10,305' 5818.20' 3.958" 4-1/2" Camco "MMG" Mandrel 6223.13' 3.958" 4-1/2" Camco "MMG" Mandrel 2 601.61' 3.958" 4-1/2" Camco "MMG" Mandrel 6946.21' 3.958" 4-1/2" Camco "MMG" Mandrel 7290.49' 3.958" 4-1/2" Camco "MMG" Mandrel 7640.22' 3.958" 4-1/2" Camco "MMG" Mandrel 7955.85' 3.958" 4-1/2" Camco "MMG" Mandrel 8305.13' 3.958" 4-1/2" Camco "MMG" Mandrel 8618.75' 3.958" 4-1/2" Camco "MMG" Mandrel Open 8963.26' 3.958" 4-1/2" Camco "MMG" Mandrel 9310.38' 3.958" 4-1/2" Camco "MMG" Mandrel 9751.18' 3.958" 4-1/2" Camco "MMG" Mandrel 3 9821.91' Open 4-1/2" Otis "XA" Sleeve 4 9859, -9877' 5/1/1974 Baker Model T -V Perm. Packer with Seal Assembly 5 10,434' 10,444' 4-1/2" Otis "N" Nipple 6 HB -5 10,434' 4-1/2" Mule Shoe 7 10537' HB -6 Top of float collar 8 10626' Open Bottom of float shoe PERFORATION DETAIL Zone Top Btm Date Condition HB -1 9,933' 9,967' 1/1/1991 Open HB -3,4 10,100' 10,268' 1/1/1991 Open HB -5 10,289' 10,305' 1/1/1991 Open HB -5 10,315' 10,360' 4/1/1974 Open HB -5 10,315' 10,360' 5/1/1974 Open HB -5 10,315' 10,420' 3/1/1978 Open HB -5 10,315' 10,444' 1/1/1991 Open HB -5 10,395' 10,420' 5/1/1974 Open HB -5 10,395' 10,420' 4/1/1974 Open HB -5 10,434' 10,444' 5/1/1974 Open HB -5 10,434' 10,444' 4/1/1974 Open HB -5 10,434' 10,450' 3/1/1978 Open HB -6 10,470' 10,490' 3/1/1978 Open HB -6 10,472' 10,502' 4/1/1974 Open HB -6 10,472' 10,502' 5/1/1974 Open McArthur River Field, TBU Proposed Well: G-20 Hilcorp Alaska, LLC As Completed: Future RKB to TBG Hngr = 38.20' ESP Top MD: ^9,300ft TVD:-8,526ft INC: 26° Top of Float 10,538ft TVD: 9,632ft INC: 28° 13 3/8in Btm MD: 5,099ft TVD: 4,782ft I NC:26' GZone Top MD: 9,421 ft Btm MD: 9,735 ft Top TVD: 8,635 ft Btm TVD: 8,917 ft Hemlock Top MD: 9,933 ft Btm MD: 10,504 ft Top TVD: 9,093 ft Btm TVD: 9,603 ft CASING DETAIL SIZE (in) WT (ppf) GRADE CONN ID (in) TOP (ft) BTM (ft) 26 ±9,447' Hanger 26 2,274 Surf 356' 20 94 H-40 BTC 19.124 Surf 798' 133/8 61 & 68 K-55 BTC 12.415 Surf 5,099' 6,361 47 N-80 BTC 8.681 Surf 1,621' 95/8 47 S-95 BTC 8.681 1,621' 4,407' 8,605 47 USS -95 BTC 8.535 4,407' 10,626' TUBING DETAIL 31/2" 9.2 N-80 SprMax 2.992 Surf 1 9,350' JEWELRY DETAIL No Depth (ft) Depth TVD (ft) ID (in) Item 1 38.2 38.2 ±9,447' Hanger 26 2,274 2,270 2.833 GLM TBD 3,865 3,700 2.833 GLM ±9,656' 5,004 4,700 2.833 GLM 5,795 5,400 2.833 GLM 2 6,361 5,900 2.833 GLM 6,925 6,400 2.833 GLM 7,387 6,800 2.833 GLM HK- 8,051 7,400 2.833 GLM New 8,605 7,900 2.833 GLM 6 9,200 8,450 2.833 GLM (Orifice) 3 9,330 8,550 HB -3,4 Sliding Sleeve 4 9,350 8,571 Open ESP Top PERFORATION DETAIL Zone Top MD (ft) Btm MD (ft) Date Total (ft) Condition GZN-1 ±9,421' ±9,447' TBD 26 New GZN-2 ±9,483' ±9,495' TBD 12 New GZN-4 ±9,616' ±9,656' TBD 40 New GZN-5 ±9,726 ±9,735' TBD 9 New HB -1 1 9,933 9,967 1/1/1991 1 34 Open HK- ±9,941' ±9,948' TBD 7 New HK -1 ±9,957' ±9,963' TBD 6 New HK -2 ±9,990' ±10,074' TBD 84 New HB -3,4 10,100 10,268 1/1/1991 168 Open ±10,100' ±10,136' TBD 36 New HK -4 ±10,148' ±10,181' TBD 33 New HK -4 ±10,191' ±10,229' TBD 38 New HK -4 ±10,237' ±10,271' TBD 34 New HB -5 10,289 10,305 1/1/1991 16 Open HK -5 ±10,314' ±10,371' TBD 57 New HB -5 10,315 10,360 4/1/1974 45 Open HB -5 10,315 10,360 5/1/1974 45 Open HB -5 10,315 10,420 3/1/1978 105 Open 1-113-5 10,315 10,444 1/1/1991 129 Open HK -5 ±10,380' ±10,423' TBD 43 New H13-5 10,395 10,420 5/1/1974 251 Open 1-113-5 10,395 10,420 4/1/1974 25 Open HK -5 ±10,431' ±10,445' TBD 14 New 1-113-5 10,434 10,444 5/1/1974 10 Open HB -5 10,434 10,444 4/1/1974 10 Open HB -5 10,434 10,450 3/1/1978 16 Open HB -6 10,470 10,490 3/1/1978 20 Open . K Hilnirp Ahtoka. UA, Grayling Platform G-20 133/8X95/8X4% Valve, Vetco-200, 4 1/16 5M FE, HWO, EE trim Valve, master, WKM-M 4 1/16 5M FE, HWO, FF trim New Valve Specspool 4 1/16 5M FE X FE 4" Type H BPV profile O ( Tubing head, CIW-DCB, 13 5/8 3M X 11 5M, w/ 2- 2 1/16 5M 550, X bottom Casing head, CIW-WF, 13 5/8 3M X 13 3/8 casing thread bottom, w/ 2- 2 1/16 5M EFO BHTA, CIW, w/ internal knockup cap, 4 1/16 5M FE Grayling Platform G-20 Current 06/05/2014 Tubing hanger, CIW-DCB-FBB, 11 X 4'/: EUE lift tubing, w/ 4" type H BPV profile, 1/8" npt non cont control line, 7" Extended neck Hanger has been in well since 1974 BPV profile bad, threads possibly corroded out, will not give BPV back without 60" pipe wrenches and 4 men Valve, Wing, WKM-M, 4 1/16 5M FE, w/ 15" operator, EE trim Adapter, CIW-FBB, 11 5M FE X 4 1/16 5M, w/ 7" slick neck pocket, 1- % npt control line outlet Valve, WKM-M, 2 1/16 5M a FE,HWO,AAtrim Valve, CIW-F, 2 1/16 5M FE, HWO, AA trim Hilrorp Alnrka, LIA. Grayling Platform G-20 133/8X95/8X31/2 BHTA, Bowen, 3 1/8 5M X 2.5 Bowen quick union Valve, Swab, WKM-M, 3 1/8 5M FE, HWO, DD trim Valve, Wing, WKM-M, 2 1/16 5M FE, HWO, DD trim Valve, Master, WKM-M, 3 1/8 5M FE, HWO, DD trim Tubing head, S-8, 13 5/8 3M `1JA,'� x 11 5M, w/ 2- 2 1/16 5M �i SSO, w/ BG bottom w/ 1- 2 1/16 5M WKM-M valves Casing head, CIW-WF, 13 5/8 3M X 13 3/8 casing thread bottom, w/ 2- 2 1/16 5M EFO Grayling Platform G-20 Proposed 06/05/2014 Tubing hanger, Seaboard - ESP -EN, 11 X 3 1/2 EUE lift and Susp w/ 3" Type H BPV profile, 2- X CCL, Prepped for BIW penetrator Valve, Wing, WKM-M, 3 1/8 5M FE, w/ 15" OMNI operator, DD trim Adapter, Seaboard -ESP, 11 5M rotating flange x 3 1/8 5M rotating flange, w/ 4 11/16 pocket, w/ 2- % CCL, ported for BIW penetrator Valve, CIW-F, 2 1/16 5M FE, HWO, AA trim Hilcorp Alaska, LLC Attachment #1 Moncla 301 BOP Test Procedure Attachment #1 Hilcorp Alaska LLC. BOP Test Procedure: Moncla 301, Grayling Platform WO Program — Oil Producers, Water Injectors Pre Rig Move 1) Blow down well, bleed gas to Well Clean Tank that is vented thru flare to atmosphere 2) Load well with FIW to kill well. • Note: Fluid level will fall to a depth that balances with reservoir pressure. 3) Shoot fluid level at least 24 hours before moving on well. 4) Shoot fluid level again, right before ND/NU. Confirm that well is static. Initial Test (i.e. Tubing Hanger is in the Wellhead) If BPV profile is good 1) Set BPV. ND Tree. NU BOP. 2) MU landing joint. Pull BPV. Set 2 -way check in hanger. 3) Space out test joint so end of tubing (EOT) is just above the blind rams. 4) Set slips, mark same. Test BOPE per standard test procedure. If BPV profile is eroded and/or corroded and BPV cannot be set with tree on, Profile and/or landing threads must be prepped while tree is off. Worst Case: BPV profile and landing threads are bad. Conduct Rolling Test. Contact Mr. Guy Schwartz and Mr. Jim Regg with the AOGCC prior to rolling test. AOGCC may elect to send inspector. 1) Attempt to set BPV through tree. If unsuccessful, shoot fluid level. 2) If fluid level is static from previous fluid level shots, notify Hilcorp Anchorage office that the well is static and the tree must be removed with no BPV. As approved in the sundry, proceed as follows: a) ND tree with no BPV b) Inspect and prepare BPV profile to accept a 2 -way valve, or prepare lift -threads to accept landing joint to hold pressure. If well is a producer and the culprit is scale, attempt to clean profile with Muriatic acid and a wire brush or wheel. c) Set 2 -way check valve by hand, or MU landing (test) joint to lift -threads d) NU BOP. Test BOPE per standard procedure. 3) If both set of threads appear to be bad and unable to hold a pressure test, notify office via e-mail that neither profile will allow for a test of the BOP. As outlined and approved in the sundry, proceed as follows: a) Nipple Up BOPE b) With stack out of the test path, test choke manifold per standard procedure c) Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down -hole and not leaking anywhere at surface.) Moncla 301 • BOP Test Procedure Hileorp Alaska, LLC Attachment #1 d) Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e) Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) f) Record and report this test with notes in the remarks column that the tubing hanger/BPV profile wouldn't hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 4) Pull hanger to surface. (Requires tubing cuts as necessary to free tubing). CBU to displace annulus and tubing with kill weight fluid. 5) If a rolling test was conducted, remove the old hanger, MU new hanger or test plug to the completion tubing. Re -land hanger (or test plug) in tubing head. Test BOPE per standard procedure. Subsequent Tests (i.e. Test Plug can be set in the Tubing -head) 1) Remove Wear bushing. a) Use inverted test plug to pull wear busing. MU to 1 jt. of tubing. b) Thread into wear bushing c) Back out hold down pins d) Pull and retrieve wear bushing. 2) Break off test plug and invert same, and RIH on 1 joint of tubing. Install a closed TIW or lower Kelly valve in top of test joint. 3) Break joint off test plug and pull up to space the bottom of tool joint above blind rams. 4) Test BOPE per standard procedure. STANDARD BOPE TEST PROCEDURE (after 2 -way check or test plug is set) 1) Fill stack with rig pump and install chart recorder on the stack side of the pump manifold. 2) Note: When testing, pressure up with pump to desired pressure, close valve on pump manifold to trap pressure and read same with chart recorder. 3) Test all Rams and Valves 1) Open all rams and annular and close HCR to place BOPE back into operating position for well work. 2) Fill out AOGCC report. FINAL STEP, FINAL CHECK 1) Test Gas Alarms 2) Double check all rams and valves, for correct operating position 3) Fill out the AOGCC BOPE Test Form (10-424) in Excel Format and e-mail to AOGCC and Juanita Lovett. Hilrorp AInAm, UA, Grayling Platform 2014 Workovers BOP Drawing Moncla Grayling Platform BOP Stack Moncla 04/24/2014 t x . STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION �" APPLICATION FOR SUNDRY APPROVALS 20_pAC 25280 1.Type of Request: Abandon 0 Plug for Redrill 0 Perforate New Pool 0' Repair Well 0 Change Approved Program 0 Suspend 0 Plug Perforations 0 Perforate Q, Pull Tubing 0 Time Extension 0 Operations Shutdown 0 Re-enter Susp.Well 0 Stimulate 0 Alter Casing 0 Other. 0 2.Operator Name: 4.Current Well pass: 5. Permit to Drill Number. Hilcorp Alaska,LLC • Exploratory 0 Development 0 ' 174-010"' 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic 0 Service ❑ 6.API Nufnber. Anchorage,AK 99503 50-733-20261-00 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? CO 228A/ \ Will planned perforations require a spacing exception? Yes 0 No 0 ' Trading Bay Unit/G-20 ' 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0018730 • McArthur River Field/Hemlock Oil Pool• 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): 10,642 • 9,719- 10,537• 9,632' N/A 10,203 Casing Length Size MD TVD Burst Collapse Structural Conductor 356' 26" 356' 356' Surface 798' 20" 798' 798' 1,540 psi 520 psi Intermediate 5,099' 13-3/8" 5,099' 4,783' 3,090 psi 1,540 psi Production 10,626' 9-5/8" 10,626' 9,711' 6,870 psi 4,760 psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 9,933-10,502 • 9,094-9,601 4-1/2" 12.6#/N-80 9,901 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): Baker Model D Packer&SSSV-N/A • 9,859'(MD)9,028'(ND)&N/A 12.Attachments: Description Summary of Proposal Q . 13.Well Class after proposed work: Detailed Operations Program 0 BOP Sketch 0 Exploratory 0 Stratigraphic 0 Development 0• Service 0 14.Estimated Date for 15.Well Status after proposed work: 4/21/2014 Commencing Operations: Oil 0' Gas 0 WDSPL ❑ Suspended 0 16.Verbal Approval: Date: WINJ 0 GINJ 0 WAG 0 Abandoned 0 Commission Representative: GSTOR 0 SPLUG 0 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Dan Taylor Email dtaylor4hilcorp.com Printed Name Dan Taylor / Title Operations Engineer SignaturePhone (907)777-8319 Date 4/15/2014 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3 k‘*- • 22-n Plug Integrity 0 BOP Test 0 Mechanical Integrity Test 0 Location Clearance 0 Other: RBDM MAY 0 7 2014 0 .234/1- COMM',\51'� Spacing Exception Required? Yes 0 No d Subsequent Form Required: /O — £f 6 ( : i '/`.--,,.---7 APPROVED BY ��� Approved byy r ,,-/� COMMISSIONER THE COMMISSION Date: � YA6'11( gK3 yll� �7 fCQ \ 1�-1 Y!( � Submit Form �� d Form 10-403(Revised 10/2012) ApproveUr i t,D �i 4INr�r�Ont m the dale OTapproval. Attachments in Duplicate Well Prognosis Well: G-20 Hilcora Alaska,LLI Date:4/15/2014 Well Name: G-20 API Number: 50-733-20261-00 Current Status: Producer Leg: 3 Estimated Start Date: April 21,2014 Rig: NA Reg.Approval Req'd? 10-403 Date Reg.Approval Rec'vd: Regulatory Contact: Juanita Lovett 777-8332 Permit to Drill Number: 174-0100 First Call Engineer: Dan Taylor (907) 777-8319(0) (907)947-8051 (M) Second Call Engineer: James Young (907) 777-8421 (0) AFE Number: Current Bottom Hole Pressure: 3,750 psi @ 9,347ft TVD/10,218ft MD 0.40 psi/ft at mid-pert, Survey 2009 Maximum Expected BHP: 3,750 psi @ 9,347ft TVD/10,218ft MD 0.40 psi/ft at mid-perf, Survey 2009 Max.Allowable Surface 1,772 psi 2/3 TVD*0.1psi/ft+ 1/3 TVD Pressure: *0.435psi/ft Brief Well Summary Grayling G-20 is an oil producing Hemlock completion. This program calls for adding new perforations in the G-Zoneand in Bench 2 of the Hemlock in anticipation of adding rate/reserves. Future perforation depths are: Zone TOP MD (ft) BTM MD (ft) Length (ft) TOP TVD (ft) BTM TVD(ft) GZN-1 9,421 9,447 26 9,039 9,070 GZN-2 9,483 9,495 12 9,102 9,115 GZN-4 9,616 9,656 40 9,169 9,197 GZN-5 9,726 9,735 9 9,208 9,299 HK-2 9,990 10,010 20 9,335 9,353 Procedure: 1. Identify and record fluid level. 2. Hold pre-job safety meeting. 3. Prepare well for e-line perforating. a. Check well head pressure. b. Ensure crown and wing valves are closed. c. Bleed pressure from well head. d. Ensure there is no trapped pressure. e. Ensure there is proper lighting for operations. f. Keep excess personnel away from operations. g. Ensure perforating unit is grounded. 4. Rig up lubricator and wire line: a. Test lubricator to+/-2,500psi. 5. Run in hole with 3-1/2in Dummy Gun to tag. a. Last tag on 10-25-2013 with 3-3/4in GR found at 10,203ft. 6. Run in hole with perforating gun, GR and CCL. a. Tie in to correlation log. b. Well will be perforated while balanced. c. Perforate interval:Top Shot 9,421ft to Bottom Shot 10,010ft MD. d. Total number of runs to cover interval: +/-6. 7. Pull out of hole with perforating guns. 8. Rig down lubricator. 9. Turn well over to production. Attachments: 1. As-built Well Schematic Proposed Well Schematic McArthur River Field,TBU . , . . n SCHEMATIC Well: G-20 lliIeorp Alaska.LLC As Completed: 1/4/1985 CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. RKB to TBG Hngr=38.20' 26" Surf 356' , i [1 1 20" 94 H-40 Buttress 19.124" Surf 798' 13-3/8" 61&68 K-55 Buttress 12.415" Surf 5,099' 47 N-80 Buttress 8.681" Surf 1,621' 9-5/8" 47 S-95 Buttress 8.681" 1,621' 4,407' 47 USS-95 Buttress 8.535" 4,407' 10,626' TUBING DETAIL 4-1/2" 12.6 N-80 Buttress 3.958" Surf 9,901' JEWELRY DETAIL No Depth ID Item 1 305.18' 3.958" 4-1/2"Otis BV Landing Nipple 1909.43' 3.958" 4-1/2"Camco"MMG"Mandrel 3293.97' 3.958" 4-1/2"Camco"MMG"Mandrel 4445.85' 3.958" 4-1/2"Camco"MMG"Mandrel magommi 5255.69' 3.958" 4-1/2"Camco"MMG"Mandrel 5818.20' 3.958" 4-1/2"Camco"MMG"Mandrel 6223.13' 3.958" 4-1/2"Camco"MMG"Mandrel • 601.61' 3.958" 4-1/2"Camco"MMG"Mandrel 6946.21' 3.958" 4-1/2"Camco"MMG"Mandrel 2 7290.49' 3.958" 4-1/2"Camco"MMG"Mandrel 2 7640.22' 3.958" 4-1/2"Camco"MMG"Mandrel 7955.85' 3.958" 4-1/2"Camco"MMG"Mandrel 8305.13' 3.958" 4-1/2"Camco"MMG"Mandrel 8618.75' 3.958" 4-1/2"Camco"MMG"Mandrel - 8963.26' 3.958" 4-1/2"Camco"MMG"Mandrel 9310.38' 3.958" 4-1/2"Camco"MMG"Mandrel -- 9751.18' 3.958" 4-1/2"Camco"MMG"Mandrel 3 9821.91' 4-1/2"Otis"XA"Sleeve 11 4 9859'-9877' Baker Model"F-1"Perm.Packer with Seal Assembly I5 4-1/2"Otis"N"Nipple 6 4-1/2"Mule Shoe 7 10537' Top of float collar 8 10626' Bottom of float shoe XA 3 i PERFORATION DETAIL TBG Cut: 4 Zone Top Btm Date Condition 4/22/74 @ HB-1 9,933' 9,967' 1/1/1991 Open 9,901ft HB-3,4 10,100' 10,268' 1/1/1991 Open HB-5 10,289' 10,305' 1/1/1991 Open Last Tag: HB-5 10,315' 10,360' 4/1/1974 Open 10/25/13 @ HB-5 10,315' 10,360' 5/1/1974 Open 10,203ft II HB-5 10,315' 10,420' 3/1/1978 Open H B-5 HB-5 10,315' 10,444' 1/1/1991 Open 5 E. HB-5 10,395' 10,420' 5/1/1974 Open IM HB-6 HB-5 10,395' 10,420' 4/1/1974 Open 6 HB-5 10,434' 10,444' 5/1/1974 Open HB-5 10,434' 10,444' 4/1/1974 Open 7 MIMMINNIM HB-5 10,434' 10,450' 3/1/1978 Open 118-6 10,470' 10,490' 3/1/1978 Open L8 HB-6 10,472' 10,502' 4/1/1974 Open HB-6 10,472' 10,502' 5/1/1974 Open . , McArthur River Field,TBU PROPOSED Well:G-20 HileorpAlaska,LLC As Completed: 1/4/1985 CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. RKB to TBG Hngr=38.20' 26" Surf 356' [ 20" 94 H-40 Buttress 19.124" Surf 798' 13-3/8" 61&68 K-55 Buttress 12.415" Surf 5,099' 1 47 N-80 Buttress 8.681" Surf 1,621' 9-5/8" 47 5-95 Buttress 8.681" 1,621' 4,407' S 47 USS-95 Buttress 8.535" 4,407' 10,626' TUBING DETAIL ri 4-1/2" 12.6 N-80 Buttress 3.958" Surf 9,901' i JEWELRY DETAIL No Depth ID Item 1 305.18' 3.958" 4-1/2"Otis BV Landing Nipple 1,909.43' 3.958" 4-1/2"Camco"MMG"Mandrel 3,293.97' 3.958" 4-1/2"Camco"MMG"Mandrel 4,445.85' 3.958" 4-1/2"Camco"MMG"Mandrel 5,255.69' 3.958" 4-1/2"Camco"MMG"Mandrel 5,818.20' 3.958" 4-1/2"Camco"MMG"Mandrel 6,223.13' 3.958" 4-1/2"Camco"MMG"Mandrel 6,01.61' 3.958" 4-1/2"Camco"MMG"Mandrel 6,946.21' 3.958" 4-1/2"Camco"MMG"Mandrel 2 7,290.49' 3.958" 4-1/2"Camco"MMG"Mandrel 7,640.22' 3.958" 4-1/2"Camco"MMG"Mandrel 7,955.85' 3.958" 4-1/2"Camco"MMG"Mandrel 2 8,305.13' 3.958" 4-1/2"Camco"MMG"Mandrel - ll8,618.75' 3.958" 4-1/2"Camco"MMG"Mandrel 8,963.26' 3.958" 4-1/2"Camco"MMG"Mandrel 9,310.38' 3.958" 4-1/2"Camco"MMG"Mandrel 9,751.18' 3.958" 4-1/2"Camco"MMG"Mandrel 3 9,821.91' 4-1/2"Otis"XA"Sleeve 4 9,859'-9 877' Baker Model"F-1"Perm.Packer with Seal Assembly 5 4-1/2"Otis"N"Nipple 6 4-1/2"Mule Shoe 7 10537' Top of float collar 8 10626' Bottom of float shoe a 3 PERFORATION DETAIL XA Zone Top Btm Date Condition GZN-1 9,421' 9,447' TBD 4 GZN-2 9,483' 9,495' TBD GZN-4 9,616' 9,656' TBD Btm of TBG: - GZN-5 9,726' 9,735' TBD 9,901ft HB-1 9,933' 9,967' 1/1/1991 Open 4/22/74 Dip:21° HK-2 9,990' 10,010' TBD HB-3,4 10,100' 10,268' 1/1/1991 Open HB-1 HB-5 10,289' 10,305' 1/1/1991 Open Last Tag: HB-5 10,315' 10,360' 4/1/1974 Open 10/25/13 FIB-3-4 10,203ft HB-5 10,315' 10,360' 5/1/1974 Open Dip:27° HB-5 10,315' 10,420' 3/1/1978 Open Tbg Cut: HB-5 10,315' 10,444' 1/1/1991 Open 4/22/74 5 HB-5 HB-5 10,395' 10,420' 5/1/1974 Open HB-5 10,395' 10,420' 4/1/1974 Open 6 H B-6 HB-5 10,434' 10,444' 5/1/1974 Open 7 HB-5 10,434' 10,444' 4/1/1974 Open HB-5 10,434' 10,450' 3/1/1978 Open HB-6 10,470' 10,490' 3/1/1978 Open / HB-6 10,472' 10,502' 4/1/1974 Open \ HB-6 10,472' 10,502' 5/1/1974 Open ALASKA OIL AND GAS CONSERVATION COMMISSION November 15, 1995 TONY KNOWLES, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 FAX: (907) 276-7542 Chuck Beaucamp Field Superintendent UNOCAL 260 Caviar Street Kenai, Alaska 99611 Re: No-Flow Verification MRF Wells~ and G-26 Dear Mr. Beaucamp: On November 2, 1995 our Inspector, John Spaulding, witnessed "no-flow" tests on UNOCAL's McArthur River Field wells G-.20 (PTD 74-010) and G-26 (PTD 76-066). Gas lift to the wells had been shut-off and the wells bled to atmosphere pressure 24 hours before the inspector arrived. He observed the wells directed into a clean tank at separate intervals. No fluid flow was observed, there was a gas flow that was too small to measure. The wells were then shut-in; G-20 built up to 15 psi in 2 hours and bled to 0 psi in 5 minutes: G-26 did not build any · pressure in 2 hours. The Inspector concluded that subject wells were not capable of unassisted flow of hydrocarbons. McArthur River Field wells G-20 (PTD 74-010) and G-26 (PTD 76-066) meet the criteria of a "no-flow" performance test and as such are considered incapable of flow to the surface. Under the authority of 20 AAC 25.265(A) they are not required to have a fail safe automatic SSSV, however, the pilot and surface safety valve must be maintained in good condition and, if for any reason, the well(s) again becomes capable of unassisted flow of hydrocarbons, thc subsurface safety valve must be reinstalled and maintained in good working condition. Sincerely, Blair E. Wondzell~ PI Supervisor cc: John Spaulding bew/nf-mrf2w MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: David Johnston, DATE: Chairman'--~ November 2, 1995 THRU: Blair Wondzell, -~E~ FILE NO: P I. Supervisor ~,/,r' FROM: John Spaulding, ¢..., StYBJ[CT: Petroleum Insp. 1591hbcd.doc No Flow Test Unocal Grayling Platform Trading Bay Field Thursday November 2, 1995: I travelled to Unocal's Grayling Platform to witness No Flow tests on wells G-20 and G-26. Both wells were previously granted No Flow status, the wells were re-perforated and required a new test. On both wells the artificial lift gas and tubing were shut in and bled to atmospheric pressure 24 hours prior to my arrival. The wells were placed into ' clean tanks a~separate intervals and watched for fluid and gas flow. No fluid was observed and gas flow was positive but not measuable. The wells were then shut in and allowed to build pressure. G-20 built up to 15 psi over 2 hours and bled to 0 psi in 5 minutes; G-26 did not build any pressure in the same time frame. These wells meet or exceed the guidelines for No Flow status. I reccomend that the AOGCC grant NoFIow status to wells G-20 & G-26 on Unocai's Grayling Platform. Summary; Platform. 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IWWOZ) NOIJ. VAI{::ISN03 SVO IJNV llO (opls a~q,~a^aa UO .qUO)lan.tls · .~,T-';"'~=: -~O RI ,LIPISIq-S =":~ - . ~t-'d ,, INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item: 16: Indicate which elevation is used as reference (wher'e not otherwise shown) for depth measure- ments given in ether spaces on this form and in any attachments. Items 20, and 22:: If this well is completed for separate prcduction from r'nore than one interval zone (multiple completion), so state in item 20, and in ite'l1 22 show the prc:Jucing interval, or intervals, top(s), bottom(s) and name (s) (if any) for of1ly the intervJI reported in item 30. Submit a separate report (paGe) on this form, adequately identified, for each additional inter val to be seperately produc~', show- ing the additional data pertinent to such interval. Item26: "Sacks Cement": Attached supplemental records for this well should show the details of any mul- tiple stage cementing and the location of the cemen ting tool. Item 28: Submit a separate completion report on this form for each interval to be separately produced. (See instruction for items 20 and 22 above). 34. SUMMARY OF FORMATION TESTS INCLUDIN<; INTERVAL TESTED. PRESSURE DATA AND RECOVERIES OF OIL. GAS. WATER AND MUD 35. GEOLOGIC' MARKERS NAME ( .1. !\lEAS. DEPTH '1'RUE V1\:RT. D~TH :16. .CÓ-n,E DATA. A'lwrACU ,BRiEF' iPESCRIIPI:MaNS 'OF LITI'IOLOGY. POnOSHTY. FIC~CTURES.APPA:RENT ,Ð1\PS AN>ÐDE'lt'œC'l'EÐ SHOWS ,OF OIL, GAS OR WATEU. I l VI~EO,~I[[¥O ~o 510 /¢OINI1 ~o~ J, EOcI~St ~IITIIHC[ ~.v~zog!I~O ~o Iz.O ~£6L ~9t I!=~V OOlSV:I :SS'=IblQQV :f'lB'V'3 / Ig0// SVX'q..L 'NOISf'IOH 609P'I XO'Ei Od 'ONt '"/IOO/SdlH/W NVIAI/SV-il ! 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ZZ Z Z Z Z~ ZZ~. ZZ Z ~Z, Z Z .~,Z · · · · · · · · · · · ~0 0 0 0 0 0 0 0 z 0 0 (~ 000'000000 C) O0000 000000 O0 O0 O0000 O0 0 O0 O00000000000000 0000000000 O0000 O0 000 000000000000000 00000000000000000 000 0 ~j~O~t~ ~ ~ ~.~ ~ 4~ O~ O~,~.t~dO0000000 O0 000000~ 0 O0 tj~O~ ~,~j~O~ ~-,0 ~ O~d~,dt--~O0000000 O0 O000000 0 O0 or Z 'D -4 Z 0 0 0 0000000000 O0 O0000OOC) O00000 ooooooooooooo~ooooooooooo ooooooooooooo ooooooooooo ~~ ZZ ~ ~ ~~ ~Z~ Z ZZZ ZZZZ~ZZZZ F~mm O< ~or~ Or" g - 0 0 Z 0 0 0 '¥ 'S 'fl N! OD.ISY] ,,L~ OXJ, Fl 'l~l loe,~a ~llo.t ~01-~10 A~ A~A~AS ~gL-~-l~ iota-ns ox~o ~L--'O ~gL~O 1~ ::JJ.¥Cl A3A~iAS ::10 3dM. 801' NOIJ.¥gO1 :.iI~VN ll]/A iNYd ~00 'eTTaa:o3:T'L~O 3:o I!:.O uoT~Tt A3At ns ~0 :311J :~i:JJNOD l OdEi ~ u '/SI-Ill r',-i,~] o~r oo, ,o'o~oo o,,~:o o g o° o° §oo g oo O0 tl ~,~ 0 t~t~ C~ 0 0 0 0 0 0 0 t,1 t~ 0 ~1~ 0 0 C) 0 0 t,~ '4~ 0 C~ 0 ZZ iz rtl C: o Z · -( 0 ::Ill' 0 lie 0 · · e eeo cee eeo eoeee~ Z ZZZZZ~Z Z~Z~ZZZZ~Z ~0 00~00000~00000000~000000~0~. eee · e · e e e e e e e e e e e e e e e e e e e e e e e ~ ~00~~~~~~000~~~00~ ~ ~0~0~~00~'~~0.00~~~0~0 0 .-, r' 0-~ '11--< ~ O~le ZO 0 0 C, O0~O000000000000OO00OO0 00000.0 0 00-~:0:00000 ~ ~00 O000 . 0000 00~ 0~0 00~000000 000~ · · · · · · · · · P, JI,-~ 0,~ 3}l-efdl ,O Z~ZZ Z ZZ ZZ :~-'Z Z Z ZZZ ZZ ZZZ Z · · o · · · e ® o o o ® o ® o ~ZZZZ2~Z O00000 00.000 0 -,4 O, .~' O. 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