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169-086
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: Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool?N/A Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 11,570 N/A Casing Collapse Structural Conductor Surface 1,540psi Intermediate Production 3,810psi Liner 7,020psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Casey Morse Contact Email:Casey.Morse@hilcorp.com Contact Phone:(907) 777-8322 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Other: Replace ESP 9/26/2025 11,255'847' 3-1/2" 10,196' N/A & N/A N/A & N/A 10,510' Perforation Depth MD (ft): 9,420 - 11,150 10,510' 7" 8,680 - 10,111 9,595'9-5/8" 369' 26" 17-3/4" 13-3/8" 497' 4,810' MD 3,090psi 497' 4,680' 497' 4,810' Length Size Proposed Pools: 369' 369' L-80 TVD Burst 9,201 6,330psi STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0018730 169-086 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-733-20198-00-00 Hilcorp Alaska, LLC Trading Bay Unit G-32 AOGCC USE ONLY 8,160psi Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Operations Manager Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY McArthur River Middle Kenai G, Hemlock & West Foreland Oil Same 10,450 11,085 10,059 1,863psi N/A No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 1:09 pm, Sep 12, 2025 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2025.09.12 12:12:50 - 08'00' Dan Marlowe (1267) 325-559 A.Dewhurst 16SEP25 DSR-9/12/25MGR24SEP2025 * BOPE test to 2500 psi. 48 hour notice to AOGCC for opportunity to witness. * If barriers are disturbed, i.e., fill clean out etc will require a witnessed no-flow test to continue operation with a SSSV. * Safety valve system performance test within 5 days of installation. 48 hour notice.10-404 JLC 9/25/2025 Gregory C Wilson Digitally signed by Gregory C Wilson Date: 2025.09.25 14:55:15 -08'00'09/25/25 RBDMS JSB 092625 ESP Swap Well: G-32 Well Name:G-32 API Number: 50-733-20198-00 Current Status:ESP Oil Producer Leg:Leg #2 NE Corner Estimated Start Date:September 15, 2025 Rig:404 Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:169-086 First Call Engineer:Casey Morse (907) 777-8322 (O) (603) 205-3780 (M) Second Call Engineer:Eric Dickerman (907) 564-4061 (O) Maximum Expected BHP:2,726 psi @ 8,625’ TVD ESP Intake Pressure after 70-day SI in 2023 Maximum Potential Surface Pressure: 1,863 psi** Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) **This is a No-flow well as of 01/25/2013 Brief Well Summary G-32 is a comingled G & West Forelands producer completed with an ESP installed in August 2017. This workover will replace the failing pump and perform a well cleanout if needed. Pertinent well-bore information: Last casing test 01/05/2013 at 9,350’ Inclination: Deviation gets as high as 35 degrees at 7,862’ Pertinent History x January 2013: Conversion from gas lift to ESP, re-perforate G-zone and West Forelands on TCP x August 2014: RWO to replace failed ESP x August 2017: RWO to replace failed ESP Procedure: 1. MIRU HAK 404 2. Circulate well: a. Workover fluid will be filtered inlet water (8.4ppg) b. Ensure any wellbore fluids are fully displaced with KWF either via circulating or bullheading c. Tubing Volume: 80bbl d. IA to ESP: 574bbl e. Casing to top open perf: 1bbl 3. Set BPV/TWC, ND tree, NU BOP a. Notify AOGCC 48hrs in advance for witness b. Test to 250psi low/2,500psi high / 2,500 Annular c. BOPE will be used as needed to circulate the well 4. Monitor well to ensure it is static 5. Unseat hanger and POOH with ESP completion 6. Test casing to above 2,125psi at ±9,175’ (8,500’ TVD x 0.25 = 2125psi) and chart for 30 minutes. POOH. 7.Contingent cleanout to +/- 11,085’ if needed 8. PU and run ESP completion per the proposed schematic 9. Set BPV, ND BOPE’s, NU tree, test same. 10. Turn well over to production 11. Schedule SVS testing with AOGCC as per regulations. 12. If a cleanout is performed, schedule a no-flow test per AOGCC regulations ESP Swap Well: G-32 Attachments: 1. Well Schematic Current 2. Well Schematic Proposed 3. Wellhead Diagram Current/ Proposed (Same) 4. BOP Drawing 5. Fluid Flow Diagrams 6. RWO Sundry Revision Change Form _____________________________________________________________________________________ Updated By: JLL 09/12/17 SCHEMATIC ___________________________ McArthur River Field Well: G-32 Last Completed: 08/22/17 PTD: 169-086 API: 50-733-20198-00 CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 26” 1” wall 24” Surf. 369' 17-3/4”0.312” wall Conductor 17.126” Surf. 497' 13-3/8" 61 J-55 Butt 12.515" Surf. 4,810' 9-5/8" 47 N-80 Butt 8.681” Surf. 75’ 43.5 N-80 Butt 8.755” 75’ 7,802’ 47 N-80 Butt 8.681” 7,802’ 10,465’ 47 S-95 Butt 8.681” 10,465’ 10,510' 7 29 N-80 Butt 6.184" 10,408’ 11,255' TUBING DETAIL 3-1/2" 9.2 L-80 IBT 2.992” Surf 9,201’ JEWELRY No.Depth (MD) Depth (TVD)ID OD Item 1 42.80’ 42.8’ Tubing Hanger – Cameron WF 2 9,201’ 8,491’ N/A 5.13” Bolt-On Discharge 9,202’ 8,492’ N/A 5.38” Pump (x3) 66 Stage, SJ10000 9,272’ 8,553’ N/A 5.13” Gas Separator/Intake 9,274’ 8,554’ N/A 5.13” Tandem Seals – 513 Series, BPBSL 9,292’ 8,570’ N/A 5.62” Motor (x2) 562 Motor, KMSUT & KMSLT, 500 HP 9,356’ 8,625’ N/A 5.62” Centralizer/Anode PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Status G 9,364' 9,370' 8,632' 8,637' 6' Squeezed G 9,386' 9,390' 8,651' 8,654' 4' Squeezed G-1 9,420' 9,444' 8,680' 8,701' 24' Open G-1 9,435' 9,444' 8,693' 8,701' 9' Open (DIL depths) 4-22-08 G-2 9,465' 9,490' 8,719' 8,740' 25' Open G-2 9,466' 9,493' 8,720' 8,743' 27' Open G-2 9,504' 9,516' 8,752' 8,763' 12' Open G-3 9,542' 9,588' 8,785' 8,824' 46' Open G-3 9,542' 9,590' 8,785' 8,826' 48' Open G-4 9,607' 9,623' 8,840' 8,854' 16' Open G-4 9,612' 9,622' 8,844' 8,853' 10' Open G-4 9,630' 9,653' 8,860' 8,879' 23' Open G-4 9,630' 9,654' 8,860' 8,880' 24' Open G-4 9,632' 9,652' 8,861' 8,878' 20' Open (DIL depths) 5-2-08 G-5 9,697' 9,774' 8,917' 8,982' 77' Open G-5 9,711' 9,718' 8,929' 8,935' 7' Open (DIL Depths) 5-2-08 WF-2 10,536' 10,571' 9,616' 9,645' 35' Open WF-2 10,538' 10,573' 9,618' 9,646' 35' Open WF-2 10,588' 10,601' 9,659' 9,669' 13' Open WF 10,610' 10,622' 9,677' 9,686' 12' Open WF-3 10,648' 10,655' 9,707' 9,713' 7' Open WF-3 10,649' 10,656' 9,708' 9,714' 7' Open WF-3 10,668' 10,686' 9,723' 9,738' 18' Open WF-3 10,668' 10,684' 9,723' 9,736' 16' Open WF-3 10,695' 10,697' 9,745' 9,747' 2' Open WF-3 10,703' 10,727' 9,751' 9,771' 24' Open WF-3 10,739' 10,785' 9,780' 9,817' 46' Open WF-4,5 10,825' 10,963' 9,850' 9,961' 138' Open WF-4 10,848' 10,870' 9,868' 9,886' 22' Open WF-6 10,994' 11,046' 9,986' 10,027' 52' Open WF-7 11,094' 11,150' 10,066' 10,111' 56' Open _____________________________________________________________________________________ Updated By: JLL 09/09/25 PROPOSED McArthur River Field Well: G-32 Last Completed: FUTURE PTD: 169-086 API: 50-733-20198-00-00 Tagged fill @ 11,085’ 1/4/13 26 Max hole angle is 34.8q @ 4,300’ Original RKB = 42.80' TOL @ 10,408’ 9-5/8 7” 1 2 13-3/8 TD = 11,570’ PBTD = 11,209’ 17-3/4 CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 26” 1” wall 24” Surf. 369' 17-3/4”0.312” wall Conductor 17.126” Surf. 497' 13-3/8" 61 J-55 Butt 12.515" Surf. 4,810' 9-5/8" 47 N-80 Butt 8.681” Surf. 75’ 43.5 N-80 Butt 8.755” 75’ 7,802’ 47 N-80 Butt 8.681” 7,802’ 10,465’ 47 S-95 Butt 8.681” 10,465’ 10,510' 7 29 N-80 Butt 6.184" 10,408’ 11,255' TUBING DETAIL 3-1/2" Surf ±9,200’ JEWELRY No.Depth (MD) Depth (TVD)ID OD Item 1 42.80’ 42.8’ Tubing Hanger – Cameron WF 2 ±9,200’ ±8,490’ N/A Bolt-On Discharge Pump Gas Separator/Intake Tandem Seals Motor Centralizer/Anode PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Status G 9,364' 9,370' 8,632' 8,637' 6' Squeezed G 9,386' 9,390' 8,651' 8,654' 4' Squeezed G-1 9,420' 9,444' 8,680' 8,701' 24' Open G-1 9,435' 9,444' 8,693' 8,701' 9' Open (DIL depths) 4-22-08 G-2 9,465' 9,490' 8,719' 8,740' 25' Open G-2 9,466' 9,493' 8,720' 8,743' 27' Open G-2 9,504' 9,516' 8,752' 8,763' 12' Open G-3 9,542' 9,588' 8,785' 8,824' 46' Open G-3 9,542' 9,590' 8,785' 8,826' 48' Open G-4 9,607' 9,623' 8,840' 8,854' 16' Open G-4 9,612' 9,622' 8,844' 8,853' 10' Open G-4 9,630' 9,653' 8,860' 8,879' 23' Open G-4 9,630' 9,654' 8,860' 8,880' 24' Open G-4 9,632' 9,652' 8,861' 8,878' 20' Open (DIL depths) 5-2-08 G-5 9,697' 9,774' 8,917' 8,982' 77' Open G-5 9,711' 9,718' 8,929' 8,935' 7' Open (DIL Depths) 5-2-08 WF-2 10,536' 10,571' 9,616' 9,645' 35' Open WF-2 10,538' 10,573' 9,618' 9,646' 35' Open WF-2 10,588' 10,601' 9,659' 9,669' 13' Open WF 10,610' 10,622' 9,677' 9,686' 12' Open WF-3 10,648' 10,655' 9,707' 9,713' 7' Open WF-3 10,649' 10,656' 9,708' 9,714' 7' Open WF-3 10,668' 10,686' 9,723' 9,738' 18' Open WF-3 10,668' 10,684' 9,723' 9,736' 16' Open WF-3 10,695' 10,697' 9,745' 9,747' 2' Open WF-3 10,703' 10,727' 9,751' 9,771' 24' Open WF-3 10,739' 10,785' 9,780' 9,817' 46' Open WF-4,5 10,825' 10,963' 9,850' 9,961' 138' Open WF-4 10,848' 10,870' 9,868' 9,886' 22' Open WF-6 10,994' 11,046' 9,986' 10,027' 52' Open WF-7 11,094' 11,150' 10,066' 10,111' 56' Open Grayling Platform G-32 Current 04/12/2013 Grayling Platform BOP Stack HAK 404 HILCORP ALASKA, LLC Hilcorp Alaska, LLCHilcorp Alaska, LLCChanges to Approved Sundry ProcedureSubject: Changes to Approved Sundry Procedure for Well: Trading Bay Unit G-32 (PTD 169-086)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 ALASKA • ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon 0 Plug Perforations ❑ Fracture Stimulate ❑ Pull Tubing CI Operations shutdown ❑ Performed: Suspend 0 Perforate ❑ Other Stimulate ❑ Alter Casing 0 Change Approved Program 0 Plug for Redrill 0 Perforate New Pool 0 Repair Well ❑ Re-enter Susp Well 0 Other: Replace ESP 0 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development Q Exploratory❑ 169-086 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage,AK 99503 50-733-20198-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0018730 Trading Bay Unit G-32 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A McArthur River Field/Middle Kenai G Oil&West Foreland Oil Pools 11.Present Well Condition Summary: Total Depth measured 11,570 feet Plugs measured N/A RECEIVED true vertical 10,450 feet Junk measured N/A feet SEP 18 2017 Effective Depth measured 11,085 feet Packer measured N/A feet true vertical 10,059 feet true vertical N/A feetACC Casing Length Size MD TVD Burst Collapse Structural 369' 26" 369' 369' Conductor 497' 17-3/4" 497' 497' Surface 4,810' 13-3/8" 4,810' 4,680' 3,090 psi 1,540 psi Intermediate Production 10,510' 9-5/8" 10,510' 9,595' 6,330 psi 3,810 psi Liner 847' 7" 11,255' 10,195' 8,160 psi 7,020 psi Perforation depth Measured depth 9,420-11,150 feet staIJV f1 True Vertical depth 8,680-10,111 feet Tubing(size,grade,measured and true vertical depth) 3-1/2" 9.2#/L-80 9,201'(MD) 8,491'(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: 130 73 4737 70 82 Subsequent to operation: 154 97 7052 66 84 14.Attachments(required per 20 AAc 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations ID Exploratory ❑ DevelopmentE Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run 0 16.Well Status after work: Oil 2 Gas ❑ WDSPLD 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: 317-230&317-343 Authorized Name: Stan W.Golis Contact Name: Dan Marlowe Authorized Title: Operations'- Manager Contact Email: dmarlowe@hilcorp.com M, c Authorized Signature: ., .A.. (14:3 Date: i / I e> ( I 1 Contact Phone: (907)283-1329 , f P%i ' *2 'I'DDMS # SE`' 2 5 2017 Form 10-404 Revised 4/2017 7 Submit Original Only or • McArthur River Field Well: G-32 SCHEMATIC Last Completed: 08/22/17 Hilcorp Alaska,LLC PTD: 169-086 API: 50-733-20198-00 CASING DETAIL Original RKB=42.80' SIZE WT GRADE CONN ID TOP BTM. 26" 1"wall 24" Surf. 369' 1 17-3/4" 0.312" wI Conductor 17.126" Surf. 497' L 13-3/8" 61 J-55 Butt 12.515" Surf. 4,810' 26 47 N-80 Butt 8.681" Surf. 75' 9-5/8" 43.5 N-80 Butt 8.755" 75' 7,802' L , 47 N-80 Butt 8.681" 7,802' 10,465' 17-3/4 47 S-95 Butt 8.681" 10,465' 10,510' 7 29 N-80 Butt 6.184" 10,408' 11,255' TUBING DETAIL 3-1/2" 9.2 L-80 IBT 2.992" Surf 9,201' L , JEWELRY No. Depth Depth ID OD Item 13-3/8 (MD) (TVD) 1 42.80' 42.8' Tubing Hanger-Cameron WF 9,201' 8,491' N/A 5.13" Bolt-On Discharge 9,202' 8,492' N/A 5.38" Pump(x3)66 Stage,SJ10000 9,272' 8,553' N/A 5.13" Gas Separator/Intake 2 9,274' 8,554' N/A 5.13" Tandem Seals-513 Series,BPBSL 9,292' 8,570' N/A 5.62" Motor(x2)562 Motor,KMSUT& KMSLT,500 HP 9,356' 8,625' N/A 5.62" Centralizer/Anode PERFORATION DETAIL - ) Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Status tug"' G 9,364' 9,370' 8,632' 8,637' 6' Squeezed G 9,386' 9,390' 8,651' 8,654' 4' Squeezed G-1 9,420' 9,444' 8,680' 8,701' 24' Open LFA G-1 9,435' 9,444' 8,693' 8,701' 9' Open(DIL depths)4-22-08 2 G-2 9,465' 9,490' 8,719' 8,740' 25' Open G-2 9,466' 9,493' 8,720' 8,743' 27' Open = G-2 9,504' 9,516' 8,752' 8,763' 12' Open G-3 9,542' 9,588' 8,785' 8,824' 46' Open G-3 9,542' 9,590' 8,785' 8,826' 48' Open _ G-4 9,607' 9,623' 8,840' 8,854' 16' Open G-4 9,612' 9,622' 8,844' 8,853' 10' Open _ G-4 9,630' 9,653' 8,860' 8,879' 23' Open G-4 9,630' 9,654' 8,860' 8,880' 24' Open TOL @io,4A8' 9-5/8 L G-4 9,632' 9,652' 8,861' 8,878' 20' Open(DIL depths)5-2-08 G-5 9,697' 9,774' 8,917' 8,982' 77' Open G-5 9,711' 9,718' 8,929' 8,935' 7' Open(DIL Depths)5-2-08 WF-2 10,536' 10,571' 9,616' 9,645' 35' Open _ WF-2 10,538' 10,573' 9,618' 9,646' 35' Open WF-2 10,588' 10,601' 9,659' 9,669' 13' Open WF 10,610' 10,622' 9,677' 9,686' 12' Open WF-3 10,648' 10,655' 9,707' 9,713' 7' Open WF-3 10,649' 10,656' 9,708' 9,714' 7' Open WF-3 10,668' 10,686' 9,723' 9,738' 18' Open WF-3 10,668' 10,684' 9,723' 9,736' 16' Open WF-3 10,695' 10,697' 9,745' 9,747' 2' Open WF-3 10,703' 10,727' 9,751' 9,771' 24' Open Tagged fill @ WF-3 10,739' 10,785' 9,780' 9,817' 46' Open _ 11,085'1/4/13 _ WF-4,5 10,825' 10,963' 9,850' 9,961' 138' Open WF-4 10,848' 10,870' 9,868' 9,886' 22' Open 7 L , WF-6 10,994' 11,046' 9,986' 10,027' 52' Open WF-7 11,094' 11,150' 10,066' 10,111' 56' Open TD=11,570' PBTD=11,209' Max hole angle is 34.8°@4,300' Updated By:JLL 09/12/17 S • 1111 Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date G-32 Moncla 404 50-733-20198-00 169-086 8/17/17 8/22/17 Daily Operations FF 08/17/2017-Thursday Transferred Moncla crews and night WSM to Grayling Platform (day WSMs changed out). Began working M/V Titan receiving 2nd load of W/O package. Onloaded front and rear strong-back beams and rig carrier-called for welder to reposition spacer pads on strong-back beams to fit Grayling skids. M/V departed to King (partially loaded still) to pick up more W/O equip. Positioned strong back beams. Worked M/V Titan (3rd load) receiving draw works, driller's shack,A-frame,tool connex, spreader bars, derrick and racking mat beam w/racking mat. Mounted spreader bars. Set rig carrier in place and secured. Mounted draw works on carrier, installed driveshaft. Mounted A- frame and derrick on carrier. Set drill's shack in place, continued spotting rig equipment on drill deck. NOS rep set BPV (well on vacuum) and pressure tested tubing hanger void -5000 psi-GOOD TEST. NOS rep worked Lock Down Screws. Removed flow lines from WH tree. Set test pump under carrier. Worked M/V Titan (4th Load)-offloaded walkways, koomey, choke house, BOPE, tongs, parts connex, X-0/sub basket, stairs and landings. Mounted walkways on carrier, spotted koomey and racking mat beam. Broke/removed every other nut on WH flange. MU and laid out koomey lines. Boat backed off platform, waiting for tide change. Spotted choke house. Presently N/D tree. 08/18/2017 Friday Used flange splitters, penetrating oil, wedges and sledge hammers w/32k pull from crane to separate tree from tb head.Threads in hanger are in good shape- installed blanked and ported test sub-worked tree thru deck hatch with both crane lines. N/U 13 5/8" 5M BOPE stack using 13 5/8" x 11" 5M adapter, 20' risor, mud cross w/ HCR & manual valves, double pipe rams w/blinds & 2 7/8" x 5" varibles plus annular. 1230 hrs worked M/V Titan w/final load of w/o equipment from King. Mounted rig floor- installed floor supports. Lifted drill line spool from derrick then half mast derrick. Strung up air hoist lines. Finished NU BOPE stack torqueing all flange to specs. MU koomey and choke lines to BOPE. Pressured up koomey. RU test pump, MU kill line to K3 valve. Scoped out derrick-securing all guy lines. Strung up air hoist lines. RU McCoy tongs and power pack, moved handling equipment to rig floor. RU water flood line to choke manifold. With NOS Rep assisting MU 3-1/2" PH-6 test joint w/3-1/2" PH-6 Box X 3-1/2" IF Pin X-over w/ported sub on bottom- pump-in sub,SV, IBOP on top. Pre-test BOPE - 250 psi Lo 3000 psi Hi. Working out all leaks. Presently repacking hanger void in search of small leak. • S Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date G-32 Moncla 404 50-733-20198-00 169-086 8/17/17 8/22/17 Daily Operations: , 08/19/2017-Saturday Continued pretesting BOPE 250 low 3000 high working out all leaks.Tested all BOPE to 250 psi low 3000 psi high as per Sundry in accordance to Hilcorp &AOGCC requirements-test witnessed by Brian Bixby/AOGCC. 2- FPs, 1- on choke HCR-corrected by functioning valve, the other was a visual LEL fault at panel-corrected by replacing broken antenna. Performed successful koomey draw-down test. Broke down hanger test subs- NOS pulled BPV- M/U landing jt and screwed into hanger- NOS backed out hold down pins. Set up rig tank and pump w/ PVT, H2S and LEL sensors. Worked M/V Titan onloading Summit pulling/running equipment plus ESP components along w/extra tb and production items. Held abandon platform drill directed by production. Finish setting up rig tank and pump w/ PVT, H2S and LEL sensors. Fill rig tank with 80 BBL FIW. Raised rig floor and added spool on top of Hydril. Swapped out McCoy tongs-dressed tong for 3 1/2" tb. RU Summit spoolers. Pull tubing hanger to floor- PUW= 127k. Summit reps removed control lines and power cable from tubing hanger. NOS rep assisted with LD test joint and tubing hanger. RU Summit sheaves. POOH standing back 1 stand of 3-1/2" 9.2# L-80 IBT tubing passing flat pack and power cable thru Summit sheaves back to spooling units. Summit prepped flat pack and power cables to POH. POOH standing back 3-1/2" 9.2# L-80 IBT tubing in derrick removing cannon clamps and spooling up flat pack and power cable. Pump 6 BBL FIW every 10 stands. 57 stands OOH at report time = EOT @ 5,635'. 08/20/2017-Sunday Continued POOH from 5,635' w/Summit ESP assy racking back 3 1/2" 9.2# L-80 IBT production tb- pumping displacement+every 20 stands. Changed out Summit power cable spool. Finished POOH to ESP assy- (143 stand of tb in derrick). 0930 to 1000 hrs mustered in galley due to gas alarm caused by penetrator leak on G-21 during hanger void test by NOS. P/U as high as possible to observe condition of pumps-found 2-smalls hole in top pump and 5 small holes in btm pump- motor lead was cut partially thru at top hole. Lowered assy down and cut cable and control lines- began dismantling pumps. Scale on coupler between pumps- pumps turn normally. No other abnormalities noticed during B/D. Cleared and cleaned rig floor- prepped floor to RBI w/new Summit ESP assy. Pumped 52 bbls to fill hole. Offloaded pulled cable and onloaded new power cable from M/V. Summit reps MU ESP assembly. PU new, dual 500 HP motors, gauge and centralizer anode. Serviced motors filling with oil.Tested motors - leak at motor lead seal -separated motors and replaced seal. Serviced motors again -GOOD TEST. Pumped 10 BBL FIW every hour on the hour. MU lower and upper tandem seal sections, intake sub and 3 pumps. MU discharge, ported pressure sub and 3-1/2" 8RD X IBT x-over sub bucked up to 3-1/2" 9.2# L-80 IBT tubing joint. Tested power cable and flat pack. Pumped 10 BBL FIW every hour on the hour. Held PJSM with Summit covering RIH with ESP assembly. Power pack for tongs failed to start- Platform Electrician troubleshot power pack. Changed out tong power pack with backup power pack unit. Seal on valve body blew on McCoy tongs- R/D McCoys R/U Gills. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date G-32 Moncla 404 50-733-20198-00 169-086 8/17/17 8/22/17 Daily Operations: 08/21/2017- Monday Finished R/U Gill tongs- ran second air line for tong backups (1st being used by Summit to install pins in cable clamps). Tallied 20 stands of tb-drift being dropped per stand.TIH w/Summit dual 500HP ESP assy on (rerun) 3 1/2" 9.2# L-80 IBT tubing-testing electrical every 1000'. Made splice in power cable w/76 stands in hole-this will put the splice at 4,172 MD'. Finish TIH w/Summit dual 500HP ESP assy on (rerun) 3 1/2" 9.2# L-80 IBT tubing from 5,040' to 9,313' (143 stands).Tested insulation every 1000'. Pumped 12 BBL FIW every 20 stands. Drifted tubing out of derrick. MU tubing hanger. Summit reps plumbed control lines and power cable thru hanger. Pumped 10 BBL FIW every hour on the hour. NOS ran in lock down pins- pulled landing jt and set BPV. 08/22/2017 -Tuesday Cleared rig floor. N/D 2' 13 5/8" 5M spool from annular-disconnect all guys lines- unstrung air hoist lines-scoped in /laid over derrick-dismounted floor- moved stairways. N/D BOPE. Drained and R/D rig pump &tank. N/U tree- assisted production w/all tree hookups. NOS rep tested hanger void to 500 psi f/5 mins, 5000 psi f/15 mins. Pulled BPV and set TWC-shell tested tree to 5000 psi f/ 15 mins. Pulled TWC.Turned well over to Production. Continued to RD prepping for move to Well G-21. RD test pump, koomey and choke house. Removed drill line- prepped derrick for crane pick and move- rolling up air and electric lines. M/V Titan arrives at 22:00 HRS. Worked boat to offload clearing deck space for W/O package backloads. Continued working boat- backloaded derrick, rig tank and pump. Removed draw works, A-frame, walkways and stairs from carrier. 03:00 HRS- M/V Titan waiting for tide change to approach platform. Backloaded carrier to boat. Removed spreader bars-spotted strong back beams on drill deck over G-21 and reattached spreader bars. • v,OF Tit • • 40*1/7, A THE STATE Alaska Oil and Gas 9� 0.f Q LV c Conservation Commission _s 1 l 333 West Seventh Avenue / GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 OF Main: 907.279.1433 AL'A: 1‘1.-SFax: 907.276.7542 www.aogcc.alaska.gov Stan Golis Operations Manager ® AU 11 1.2017 Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 Anchorage, AK 99503 Re: McArthur River Field, Middle Kenai G Oil and West Foreland Oil Pools, G-32 Permit to Drill Number: 169-086 Sundry Number: 317-343 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, CLQcC — Hollis S. French Chair DATED this 1 day of August, 2017. RBDMS L - AUG - 9 2017 • • RECEIVED STATE OF ALASKA JUL 2 401 ALASKA OIL AND GAS CONSERVATION COMMISSION PQ'5 of i /7 APPLICATION FOR SUNDRY APPROVALS AOGC l 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing E Change Approved Program D. Plug for Redrill ❑ Perforate New Pool I:j• Re-enter Susp Well ❑ Alter Casing l Other: Replace ESP ID 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska,LLC Exploratory ❑ Development 2, 169-086 • 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage,AK 99503 50-733-20198-00 • 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 0 / Trading Bay Unit G-32 ' 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0018730 . McArthur River Field/Middle Kenai G Oil and West Foreland 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): 11,570 10,450 . 11,085 • 10,059 , 2,513 psi N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 497' 17-3/4" 497' 497' Surface 4,810' 13-3/8" 4,810' 4,680' 3,090 psi 1,540 psi Intermediate Production 10,510' 9-5/8" 10,510' 9,595' 6,330 psi 3,810 psi Liner 847' 7" 11,255' 10,195' 8,160 psi 7,020 psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 9,420-11,150 . 8,680-10,111 3-1/2" 9.2#/L-80 9,198 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): N/A&N/A N/A&N/A • 12.Attachments: Proposal Summary U Wellbore schematic El 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch 0 Exploratory ❑ Stratigraphic ❑ Development U. Service ❑ 14.Estimated Date for 15.Well Status after proposed work Commencing Operations: 8/15/2017 OIL E. WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Stan W.Golis Contact Name: Dan Marlowe Authorized Title: Operations Manager Contact Email: dmarlowe@hilcorp.com �t • f Contact Phone: 907)5 283-1329 Authorized Signature: �M�.h Date: Z� l i COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: - k-7- 34-(S Plug Integrity ❑ BOP Test i Mechanical Integrity Test ❑ Location Clearance ❑ Other: A 3 0 ex. f,r„, 40 e 7:;;1--- Post Post Initial Injection MIT Req'd? Yes ❑ No ❑ f �,_�©t..j RBDMS i,,_ AUG - 9 2017 Spacing Exception Required? Yes ❑ No 2 Subsequent Form Required: l L APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: ? )` t 1 7/41 /7- g-/-/ 4c„\ f 74 v �I , Form 10-403 a ed 4/2017 p a pNtAillid for 12 months from the date of approval. Attachments in Duplicate • • Well Work Prognosis Well: G-32 flilcarp Alaska,i.r.c Date: 07/18/2017 Well Name: G-32 API Number: 50-733-20198-00 Current Status: ESP Producer Leg: Leg#2 NE Corner Estimated Start Date: August 15, 2017 Rig: Moncla 404 Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Juanita Lovett (8332) Permit to Drill Number: 169-086 First Call Engineer: Dan Marlowe (907) 283-1329 (0) (907) 398-9904 (M) Second Call Engineer: Stan Golis (907) 777-8356 (0) Current Bottom Hole Pressure: 3,381 psi @ 8,680'TVD 0.390 lbs/ft(7.49 ppg)based on ESP Gauge SIBHP Maximum Expected BHP: 3,381 psi @ 8,680'TVD 0.390 lbs/ft(7.49 ppg)based on ESP Gauge SIBHP Maximum Potential Surface Pressure:2,513 psi** Using 0.1 psi/ft gradient 20 MC 25.280(b)(4) **This is a No-flow well as of 01/25/2013 • Brief Well Summary �`� ,F4.1) ty G-32 is a comingled G & West Forelands producer completed with an ESP installed August 22, 2014. This workover will replace the failing pump and add new perforations in the HK-2a and HK-7. '11 Last Casing Test: 01/05/2013 1 Procedure: 1. MIRU Moncla 404 2. Attempt to pump through ESP to circulate hydrocarbon off the well to production. If necessary, RU e-line and RIH to±9,175' and punch tubing. Work over fluid will be FIW. BOP's will be closed as needed to circulate the well. 3. ND Wellhead, NU BOP and test to 250psi low/3,000psi 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. RIH and test casing to 1,500psi at±9,175' and chart for 30 minutes. POOH. (omit per email dated 07/17/17) o` .� VT's 7. RU E-line and perforate per program 8. PU and run ESP completion. 9. Set BPV. NU tree,test same. 10. Turn well over to production 11. Schedule SVS testing with AOGCC as per regulations. Attachments: 1. Well Schematic Current 2. Well Schematic Proposed 3. Wellhead Diagram Current/Proposed (Same) 4. BOP Drawing 5. Fluid Flow Diagrams 6. RWO Sundry Revision Change Form cArthur River Field ell: G-32 .11 li SCHEMATIC Last Completed: 08/22/14 Hilcorp Alaska,1a.c PTD: 169-086 API: 50-733-20198-00 CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. Original RiB=42.80' 26" 1"wall 24" Surf. 369' 0.312" 17-3/4"[] wall Conductor 17.126" Surf. 497' 1 13-3/8" 61 J-55 Butt 12.515" Surf. 4,810' 47 N-80 Butt 8.681" Surf. 75' 9-5/8" 43.5 N-80 Butt 8.755" 75' 7,802' 26 47 N-80 Butt 8.681" 7,802' 10,465' L , 47 S-95 Butt 8.681" 10,465' 10,510' 17-3/4 7 29 N-80 Butt 6.184" 10,408' 11,255' TUBING DETAIL 3-1/2" 9.2 L-80 IBT 2.992" Surf 9,198 JEWELRY L , Depth Depth No. (MD) ID OD Item (TVD) 13-3/8 1 42.80' 42.8' Tubing Hanger-Cameron WF 9,198' 8,489' N/A 6.75 Bolt-On Discharge 9,199' 8,490' N/A 6.75 Pump(x2)675 Series SH10000 2 9,244' 8,529' N/A 5.13 Tandem Seals 9,262' 8,544' N/A 5.62 Motor(x2)562 Series 340 HP 9,325' 8,598' N/A Centralizer/Anode PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Status G 9,364' 9,370' 8,632' 8,637' 6' Squeezed G 9,386' 9,390' 8,651' 8,654' 4' Squeezed G-1 9,420' 9,444' 8,680' 8,701' 24' Open G-1 9,435' 9,444' 8,693' 8,701' 9' Open(DIL depths)4-22-08 IIII G-2 9,465' 9,490' 8,719' 8,740' 25' Open 111 G-2 9,466' 9,493' 8,720' 8,743' _ 27' Open iff 2 G-2 9,504' 9,516' 8,752' 8,763' 12' Open G-3 9,542' 9,588' 8,785' 8,824' 46' Open G-3 9,542' 9,590' 8,785' 8,826' 48' Open G-4 9,607' 9,623' 8,840' 8,854' 16' Open G-4 9,612' 9,622' 8,844' 8,853' 10' Open G-4 9,630' 9,653' 8,860' 8,879' 23' Open G-4 9,630' 9,654' 8,860' 8,880' 24' Open G-4 9,632' 9,652' 8,861' 8,878' 20' Open(DIL depths)5-2-08 717L@10,408' 6-5 9,697' 9,774' 8,917' 8,982' 77' Open 9-5/8 L , G-5 9,711' 9,718' 8,929' 8,935' 7' Open(DIL Depths)5-2-08 WF-2 10,536' 10,571' 9,616' 9,645' 35' Open WF-2 10,538' 10,573' 9,618' 9,646' 35' Open WF-2 10,588' 10,601' 9,659' 9,669' 13' Open WF 10,610' 10,622' 9,677' 9,686' _ 12' Open WF-3 10,648' 10,655' 9,707' 9,713' 7' Open _ WF-3 10,649' 10,656' 9,708' 9,714' 7' Open _ WF-3 10,668' _ 10,686' 9,723' 9,738' 18' Open WF-3 10,668' 10,684' 9,723' 9,736' 16' Open WF-3 10,695' _ 10,697' 9,745' 9,747' _ 2' Open WF-3 10,703' 10,727' 9,751' 9,771' 24' Open WF-3 10,739' 10,785' 9,780' 9,817' 46' Open Tagged fill @ WF-4,5 10,825' 10,963' 9,850' 9,961' _ 138' Open 11,085'1/4/13 WF-4 10,848' 10,870' 9,868' 9,886' 22' Open 7„ WF-6 _ 10,994' 11,046' 9,986' 10,027' 52' Open L , WF-7 11,094' 11,150' 10,066' 10,111' 56' Open TD=11,570' PBTD=11,209 Max hole angle is 34.8°@4,300' Updated By:JLL 09/19/14 ,11 • cArthur River Field liCell: G-32 PROPOSED Last Completed: Future flacon)Alaska,LLC PTD: 169-086 API: 50-733-20198-00 CASING DETAIL Original RKB=42.80' SIZE WT GRADE CONN ID TOP BTM. 26" 1"wall 24" Surf. 369' 1 - 17-3/4" 0.312" Conductor 17.126" Surf. 497' wall L 13-3/8" 61 J-55 Butt 12.515" Surf. 4,810' 26 47 N-80 Butt 8.681" Surf. 75' 9-5/8" 43.5 N-80 Butt 8.755" 75' 7,802' Z , 47 N-80 Butt 8.681" 7,802' 10,465' 17-3/4 47 S-95 Butt 8.681" 10,465' 10,510' 7 29 N-80 Butt 6.184" 10,408' 11,255' TUBING DETAIL 3-1/2" 9.2 L-80 IBT 2.992" Surf ±9,200' L , JEWELRY No. Depth Depth ID OD Item 13-3/8 (MD) (TVD) 1 42.80' 42.8' Tubing Hanger-Cameron WF Bolt-On Discharge Pump 2 Tandem Seals Motor ±9,325' ±8,598' N/A Centralizer/Anode PERFORATION DETAIL ri Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Status G 9,364' 9,370' 8,632' 8,637' 6' Squeezed G 9,386' 9,390' 8,651' 8,654' 4' Squeezed G-1 9,420' 9,444' 8,680' 8,701' 24' Open �` G-1 9,435' 9,444' 8,693' 8,701' 9' Open(DIL depths)4-22-08 2 G-2 9,465' 9,490' 8,719' 8,740' 25' Open G-2 9,466' 9,493' 8,720' 8,743' 27' Open G-2 9,504' 9,516' 8,752' 8,763' 12' Open G-3 9,542' 9,588' 8,785' 8,824' 46' Open G-3 9,542' 9,590' 8,785' 8,826' 48' Open _ G-4 9,607' 9,623' 8,840' 8,854' 16' Open G-4 9,612' 9,622' 8,844' 8,853' 10' Open G-4 9,630' 9,653' 8,860' 8,879' 23' Open G-4 9,630' 9,654' 8,860' 8,880' 24' Open TOL @10,408' G-4 9,632' 9,652' 8,861' 8,878' 20' Open(DIL depths)5-2-08 9-5/8 L G-5 9,697' 9,774' 8,917' 8,982' 77' Open G-5 9,711' 9,718' 8,929' 8,935' 7' Open(DIL Depths)5-2-08 H-2A ±9,917' ±9,952' ±9,104' ±9,133' ±35' Proposed H-7 ±10,463' ±10,494' ±9,557' ±9,582' ±31' Proposed WF-2 10,536' 10,571' 9,616' 9,645' 35' Open WF-2 10,538' 10,573' 9,618' 9,646' 35' Open WF-2 10,588' 10,601' 9,659' 9,669' 13' Open WF 10,610' 10,622' 9,677' 9,686' 12' Open WF-3 10,648' 10,655' 9,707' 9,713' 7' Open WF-3 10,649' 10,656' 9,708' 9,714' 7' Open WF-3 10,668' 10,686' 9,723' 9,738' 18' Open WF-3 10,668' 10,684' 9,723' 9,736' 16' Open Tagged fill @ WF-3 10,695' 10,697' 9,745' 9,747' 2' Open 11,085'1/4/13 WF-3 10,703' 10,727' 9,751' 9,771' 24' Open WF-3 10,739' 10,785' 9,780' 9,817' 46' Open 7 L WF-4,5 10,825' 10,963' 9,850' 9,961' 138' Open WF-4 10,848' 10,870' 9,868' 9,886' 22' Open WF-6 10,994' 11,046' 9,986' 10,027' 52' Open TD=11,570' PBTD=11,209' WF-7 11,094' 11,150' 10,066' 10,111' 56' Open Max hole angle is 34.8°@4,300' Updated By:1LL 07/14/17 Grayling Platform . H G-32 Current 04/12/2013 Hilcnirp Atiuska,1.1A: Grayling Platform Tubing hanger,CIW-DCB-ESP, G-32 11 X 4'A IBT lift and susp,w/ 133/8X95/8X31/2 4"type HBPVprofile,5'EN, 2-3/8 continuous control line ports,prepped for BIW penetrator BHTA,Bowen,4 1/16 5M X 7"- 5SA Bowen top .............. 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Z a O I I _ c o tXw OJ o �> LL J C7 K= ■ 1U => F I� cI m llrlll .._ -1- Y "' O¢ m III I— (/) w ._ ll H CT IP 0 Z I- I— C/) O 0 I Zw 0_ Dz m a 0 a' J CO J -- H r--- 1 2 _ A : 0- b.- CZ 0 cc Ita ~ QD QOU J O I1/ oU- Qh 2 0 2 0 f o f _JOZ � 1� _ aN ILZ � � - m z Q = 1- __I o N 0 Moncla Rig 404 BOP Test Procedure H;ie„rp Alaska,1,1,c Attachment#1 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.) • • Moncla Rig 404 BOP Test Procedure Hiloorp Alaska,LL(. 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 15t 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 ft 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 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 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. 11 • • Moncla Rig 404 BOP Test Procedure Hilrorp Alaska,iIr, 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(-F/-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. • . — a) .>_ ca ao o � � , co Do) U > o a) (aL 0 Q. a U• o Q Q.d L E - E 0 C -a oo C d N • E Q O m)- = (1) I 0.Q E > E Q -o (1) O MI d CO.-- D QL cc ._a m > 7:3 2 _ II o a) L Z CU 0 a N 06 N .a>- a)..0 Z 0 C o CU N L L 0 c U 45 L O _o O O (6 a is a) > a) _, a ✓ ami Q as d > C Lt. N Q a) R _ .0 m 0U U p 0 2 O Lm O L a)w Q a) CD w aU a) OL O d " a a m .Q _o I `O — (p L U co a) a) -0 ' 0 w CDo...r..m vs • Q c) X cn .� R I- U ••! O to X o L a m X m N L I w U CO u ij O mZ.' U �x . TsEv 2 o co 0 n in Q � Q a • S OF T' rai&A y/,�4. THE STATE Alaska Oil and Gas o f TT ccKA Conservation Commission 333 West Seventh Avenue r.T I GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 OF ALAS Fax: 907.276.7542 www.aogcc.alaska.gov Stan W. Golis Operations Manager Hilcorp Alaska, LLC SCANNED .1 :\ , . 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: McARthur River Field, Middle Kenai G and West Foreland Oil Pools, TBU G-32 Permit to Drill Number: 169-086 Sundry Number: 317-230 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, D I Cathy Foerster Chair DATED this 1 Z day of June, 2017. RBDMS t JUN - 7 2017 • RECEIVED 11 STATE OF ALASKA J 467 / ALASKA OIL AND GAS CONSERVATION COMMISSION AOG APPLICATION FOR SUNDRY APPROVALS 20 MC 25.280 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing 0 • Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Replace ESP ^ 0 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska,LLC Exploratory ❑ Development 0 • 169-086 - 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service 0 6.API Number: Anchorage,AK 99503 50-733-20198-00 • 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-32 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0018730 ' McArthur River Field/Middle Kenai G Oil and West Foreland Oil Pools . 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth ND(ft): Effective Depth MD: Effective Depth ND: MPSP(psi): Plugs(MD): Junk(MD): 11,570 10,450 11,085 10,059 2,513 psi N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 497' 17-3/4" 497' 497' Surface 4,810' 13-3/8" 4,810' 4,680' 3,090 psi 1,540 psi Intermediate Production 10,510' 9-5/8" 10,510' 9,595' 6,330 psi 3,810 psi Liner 847' 7" 11,255' 10,195' 8,160 psi 7,020 psi Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 9,420-11,150 • 8,680-10,111 3-1/2" 9.2#/L-80 9,198 Packers and SSSV Type: Packers and SSSV MD(ft)and ND(ft): N/A&N/A N/A&N/A 12.Attachments: Proposal Summary 0 Wellbore schematic 0 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: 7/1/2017 OIL 0 ' WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Stan W.Golis Contact Name: Dan Marlowe Authorized Title: Operations Manager Contact Email: drnarlOWe@hilCOrp.COm e 04 Contact Phone: (907)283-1329 Authorized Signature: +�Li n Date: Oy 'zO{1 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: , 4 2 0 Plug Integrity ❑ BOP Test Ei Mechanical Integrity Test ❑ Location Clearance ❑ ��F 0,111 Other: t 3000 S Od" ftp / 1 Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No EY Subsequent Form Required: /6 (0``l RBDMS (, JuoV — 7 2017 APPROVED BY Approved by: '444_1V____. COMMISSIONER THE COMMISSION Date:6 _ /2 ..--/ 7 ?K� 1/7l 17- / �/(7 g 7 0 r� � I I A Su n Form and Form 10-403 Revised 4/2017 lid for 12 months from the date of approval. Attachmentsis in Duplicate • Well Work Prognosis Well: G-32 Hilcorp Alaska,LLC Date: 06/01/2017 Well Name: G-32 API Number: ' 50-733-20198-00 Current Status: ESP Producer Leg: Leg#2 NE Corner Estimated Start Date: July 01, 2017 Rig: Moncla 404 Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Juanita Lovett (8332) Permit to Drill Number: 169-086 First Call Engineer: Dan Marlowe (907) 283-1329 (0) (907) 398-9904 (M) Second Call Engineer: Stan Golis (907) 777-8356 (0) Current Bottom Hole Pressure: 3,381 psi @ 8,680'TVD 0.390 lbs/ft(7.49 ppg)based on ESP Gauge SIBHP Maximum Expected BHP: 3,381 psi @ 8,680'TVD 0.390 lbs/ft(7.49 ppg)based on ESP Gauge SIBHP Maximum Potential Surface Pressure:2,513 psi" Using 0.1 psi/ft gradient 20 MC 25.280(b)(4) **This is a No-flow well as of 01/25/2013' Brief Well Summary G-32 is a comingled G & West Forelands producer completed with an ESP installed August 22, 2014. This workover will replace the failing pump. i Last Casing Test: 774- 7 01/05/2013 ' ' Procedure: 1. MIRU Moncla 404 2. Attempt to pump through ESP to circulate hydrocarbon off the well to production. If necessary, RU e-line and RIH to±9,175' and punch tubing. Work over fluid will be FIW. BOP's will be closed as needed to circulate the well. 3. ND Wellhead, NU BOP and test to 250psi low/3,0001 h. (Note: No, ify 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. RIH and test casing to 1,500psi at±9,175' and chart for 30 minutes. POOH. ft I c5c1 7. PU and run ESP completion. 8. Set BPV. NU tree,test same. -- 9. Turn well over to production 10. Schedule SVS testing with AOGCC as per regulations. Attachments: 1. Well Schematic Current 2. Well Schematic Proposed 3. Wellhead Diagram Current/Proposed (Same) 4. BOP Drawing 5. Fluid Flow Diagrams 6. RWO Sundry Revision Change Form • H . cArthur River Field Well: G-32 SCHEMATIC Last Completed: 08/22/14 Hilcorp Alaska,LL€ PTD: 169-086 API: 50-733-20198-00 CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. Original RKB=42.80' 26" 1"wall 24" Surf. 369' 17-3/4" 0.312" Conductor 17.126" Surf. 497' 1 A wall 13-3/8" 61 J-55 Butt 12.515" Surf. 4,810' Z47 N-80 Butt 8.681" Surf. 75' 26 9-5/8" 43.5 N-80 Butt 8.755" 75' 7,802' 47 N-80 Butt 8.681" 7,802' 10,465' L , 47 S-95 Butt 8.681" 10,465' 10,510' 17-3/4 7 29 N-80 Butt 6.184" 10,408' 11,255' TUBING DETAIL 3-1/2" 9.2 L-80 IBT 2.992" Surf 9,198 JEWELRY L I . Depth Depth ID OD Item (MD) (TVD) 13-3/8 1 42.80' 42.8' Tubing Hanger-Cameron WF 9,198' 8,489' N/A 6.75 Bolt-On Discharge 9,199' 8,490' N/A 6.75 Pump(x2)675 Series SH10000 2 9,244' 8,529' N/A 5.13 _ Tandem Seals 9,262' 8,544' N/A 5.62 Motor(x2)562 Series 340 HP 9,325' 8,598' N/A Centralizer/Anode PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Status G 9,364' 9,370' 8,632' 8,637' 6' Squeezed G 9,386' 9,390' 8,651' 8,654' 4' Squeezed G-1 9,420' 9,444' 8,680' 8,701' 24' Open L G-1 9,435' 9,444' 8,693' 8,701' 9' Open(DIL depths)4-22-08 G-2 9,465' 9,490' 8,719' 8,740' 25' Open 6-2 9,466' 9,493' 8,720' 8,743' 27' Open 2 G-2 9,504' 9,516' 8,752' 8,763' 12' Open A G-3 9,542' 9,588' 8,785' 8,824' 46' Open G-3 9,542' 9,590' 8,785' 8,826' 48' Open G-4 9,607' 9,623' 8,840' 8,854' 16' Open G-4 9,612' 9,622' 8,844' 8,853' 10' Open G-4 9,630' 9,653' 8,860' 8,879' 23' Open G-4 9,630' 9,654' 8,860' 8,880' 24' Open G-4 9,632' 9,652' 8,861' 8,878' 20' Open(OIL depths)5-2-08 TOL @10,408' G-5 9,697' 9,774' 8,917' 8,982' 77' Open 9-5/8 A G-5 9,711' 9,718' 8,929' 8,935' 7' Open(DIL Depths)5-2-08 WF-2 10,536' 10,571' 9,616' 9,645' 35' Open WF-2 10,538' 10,573' 9,618' 9,646' 35' Open WF-2 10,588' 10,601' 9,659' 9,669' 13' Open WF 10,610' 10,622' 9,677' 9,686' 12' Open WF-3 10,648' 10,655' 9,707' 9,713' 7' Open _ WF-3 10,649' 10,656' 9,708' 9,714' 7' Open WF-3 10,668' 10,686' 9,723' 9,738' 18' Open WF-3 10,668' 10,684' 9,723' 9,736' 16' Open WF-3 10,695' 10,697' 9,745' 9,747' 2' Open WF-3 10,703' 10,727' 9,751' 9,771' 24' Open WF-3 10,739' 10,785' 9,780' 9,817' 46' Open Tagged fill @ WF-4,5 10,825' 10,963' 9,850' 9,961' 138' Open 11,065'1/4/13 WF-4 10,848' 10,870' 9,868' 9,886' 22' Open 7„ WF-6 10,994' 11,046' 9,986' 10,027' 52' Open L , WF-7 11,094' 11,150' 10,066' 10,111' 56' Open TD=11,570' PBTD=11,209 Max hole angle is 34.8°@4,300' Updated By:JLL 09/19/14 • �cArthur River Field Well: G-32 PROPOSED Last Completed: Future Hilcorp Alaska,LLC PTD: 169-086 API: 50-733-20198-00 CASING DETAIL Original RKB=42.80' SIZE WT GRADE CONN ID TOP BTM. 26" 1"wall 24" Surf. 369' I NMI17-3/4" O.312" wall Conductor 17.126" Surf. 497' L 13-3/8" 61 J-55 Butt 12.515" Surf. 4,810' 26 47 N-80 Butt 8.681" Surf. 75' L , 9-5/8" 43.5 N-80 Butt 8.755" 75' 7,802' 47 N-80 Butt 8.681" 7,802' 10,465' 17-3/4 47 5-95 Butt 8.681" 10,465' 10,510' 7 29 N-80 Butt 6.184" 10,408' 11,255' TUBING DETAIL 3-1/2" 9.2 L-80 IBT 2.992" Surf ±9,200' L L. JEWELRY Depth Depth 13-3/8 No. ID OD Item (MD) (TVD) 1 42.80' 42.8' Tubing Hanger-Cameron WF Bolt-On Discharge Pump 2 Tandem Seals Motor ±9,325' ±8,598' N/A Centralizer/Anode PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Status G 9,364' 9,370' 8,632' 8,637' 6' Squeezed G 9,386' 9,390' 8,651' 8,654' 4' Squeezed 111 G-1 9,420' 9,444' 8,680' 8,701' 24' Open G-1 9,435' 9,444' 8,693' 8,701' 9' Open(DIL depths)4-22-08 IS 2 G-2 9,465' 9,490' 8,719' 8,740' 25' Open G-2 9,466' 9,493' 8,720' 8,743' 27' Open G-2 9,504' 9,516' 8,752' 8,763' 12' Open G-3 9,542' 9,588' 8,785' 8,824' 46' Open = G-3 9,542' 9,590' 8,785' 8,826' 48' Open G-4 9,607' 9,623' 8,840' 8,854' 16' Open = G-4 9,612' 9,622' 8,844' 8,853' 10' Open G-4 9,630' 9,653' 8,860' 8,879' 23' Open I-- G-4 9,630' 9,654' 8,860' 8,880' 24' Open TOL @10,408 9-5/8 d G-4 9,632' 9,652' 8,861' 8,878' 20' Open(DIL depths)5-2-08 G-5 9,697' 9,774' 8,917' 8,982' 77' Open G-5 9,711' 9,718' 8,929' 8,935' 7' Open(DIL Depths)5-2-08 WF-2 10,536' 10,571' 9,616' 9,645' 35' Open _ WF-2 10,538' 10,573' 9,618' 9,646' 35' Open WF-2 10,588' 10,601' 9,659' 9,669' 13' Open WF 10,610' 10,622' 9,677' 9,686' 12' Open = WF-3 10,648' 10,655' 9,707' 9,713' 7' Open = WF-3 10,649' 10,656' 9,708' 9,714' 7' Open WF-3 10,668' 10,686' 9,723' 9,738' 18' Open WF-3 10,668' 10,684' 9,723' 9,736' 16' Open WF-3 10,695' 10,697' 9,745' 9,747' 2' Open = WF-3 10,703' 10,727' 9,751' 9,771' 24' Open Tagged fill @ = WF-3 10,739' 10,785' 9,780' 9,817' 46' Open 11,085'1/4/13 WF-4,5 10,825' 10,963' 9,850' 9,961' 138' Open WF-4 10,848' 10,870' 9,868' 9,886' 22' Open 7 Z , WF-6 10,994' 11,046' 9,986' 10,027' 52' Open WF-7 11,094' 11,150' 10,066' 10,111' 56' Open TD=11,570' PBTD=11,209' Max hole angle is 34.8°@ 4,300' Updated By:JLL 06/01/2017 • . HH . •Grayling Platform G-32 Current 04/12/2013 tllilrnrp 4.14irka,1.t.f. Grayling Platform Tubing hanger,CIW-DCB-ESP, G-32 11 X 4'A IBT lift and susp,w/ 13 3/8 X 9 5/8 X 3 1/2 4"type H BPV profile,5''AA EN, 2-3/8 continuous control line ports,prepped for BIW penetrator BHTA,Bowen,4 1/16 5M X 7"- 5SA Bowen top 1st i ni 411111 Valve,swab,WKM-M, 0:3 4 1/16 5M FE,HWO, �i Cross,stdd,4 1/16 5M X T-24 4 1/16 5M X 2 1/16 5M p. ni IMO u. Wi1. t; • Valve,wing,WKM-M, , a�a, \„ ' Valve,WKM-M,4 1/16 5M FE,w/ 2 1/16 5M FE,HWO, I�t � I zs * � � MA-16 operator - T-24 - 1,4ysTre I.I � Valve,lower master,WKM-M, �" 111111P 4 1/16 5M FE,HWO,T-24 u� n ill.' Adapter,CIW-Toadstool, 11 5M Stdd X 4 1/16 5M FE,prepped for 5'/4 EN neck,2-'/2 npt continuous – control line ports,BIW penetrator — port Tubing head,CIW-DCB, '— mii—' 13 5/8 3M X 11 5M,w/ mil ■ ■ lir; 2-2 1/16 5M SSO,X bottom III 1 I I Valve,WKM-M,2 1/16 SM FE, R seal installed in head kg� HWO,DD Q tE 6 off, � I i�� >��� ., �, Qty 2 III _ * trr. • f r. Casing head,CIW-WF, � " 13 5/8 3M X 13 3/8 SOW, 1.11 itti in, tio w/2-2 1/16 5M EFO Iil / 1!1 CA slips hung off in wellhead . in GPling Platform 2016 BOP Stack Moncla 05/13/2016 ftilrnrIn;Ilarka.LTA. Maarilnfrill i 4.54' PIHydril 4 GK 13 5/8-5000 Iii iii Ill 111111 27/8-5.5 Shaffer SL vara/8tiles imp 2.83' FI! 13 5/8 5M - ' Blinds .tel * Choke and Kill valves Ill ploWtl IP 21/16SM o; 2.26' ''�1 ii x i A Ir ,� � 1' 1/1 lil lil liI lit 1 1\—' 7. 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O ¢ mI— U) a !—u a • • 1a z Q J z D O Z Uw Z ajz Q _ O J U)J Q •71" OU .-- , _ 0_ , .1- . ,1: « D , O—', , wZC� Up OJ � OJ a a � 0O >z I 1- u 0Z to 0 o o 0co w S z m ¢ 0 H Z 117 Q ' 4 • OW W n U cG 0 • • Moncla Rig 404 BOP Test Procedure Hilearp Alaska,LLC Attachment#1 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.) S 11 Moncla Rig 404 BOP Test Procedure IIilanrp Alaska,LIA 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 1st 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 1st 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 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 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. • • • Moncla Rig 404 BOP Test Procedure 1[i6LLC»rp Alaeka, 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. . ` . • • 41.: - 0 / > 02 O Q _ m a > § 2E� o0 / 2k °/§ a« E / 0f ) in- a.) 0 > > § / §I �� f E «0. = o �/ _0 �� > _ I • \.§ a_ f / %• / n � ■ a) 2 \ ._ 2 k k % §a )>" Et 2 J CD to % � "6 oc .- § U $ $ o a > LL. Cs1 0 a) CO / L. _ a ■ co .cQ \ -0 0 e o k < k w 0 E § 9, O k ƒ ./ a a JD / CD Uc c »7 co C = 2 / . cor EX Gp 2 u a) _ > §7. ■ J > a) caC / 4 G 0.< / 0 CI as O. 0 it . 2 x % t E - Ds q Q § 2 a & � g .< 44 ea / / § ° Q a 0 � w / � / .. _ Ws e © E0 / 1-4 c u 0- 2 k \ 9 0 < ± • • Bettis, Patricia K (DOA) From: Dan Marlowe <dmarlowe@hilcorp.com> Sent: Wednesday,June 7, 2017 6:35 AM To: Bettis, Patricia K (DOA) Cc: Juanita Lovett Subject: RE:TBU G-32 (PTD 168-086): Sundry Application Patricia G-32 was TD'd November 11, 1969 at 11,570' MD ( 10,450'TVD) The original Drilcon log called this 10,417.47'TVD so I am betting they just had a typo on the 10-407 Let me know if you have any further questions Thanks Dan Marlowe Hilcorp Alaska, LLC Operations Engineer Office 907-283-1329 Cell 907-398-9904 Email DMarlowe@hilcorp.com Hilcorp A Company Built on Energy From: Bettis, Patricia K(DOA) [mailto:patricia.bettis@alaska.gov] Sent:Tuesday,June 06, 2017 3:32 PM To: Dan Marlowe<dmarlowe@hilcorp.com> Subject:TBU G-32 (PTD 168-086): Sundry Application Good afternoon Dan, On Form 10-403, Box 11, it is stated that the total depth for TBU G-32 is 11,570' MD(10,450'TVD). On Form 10-407 Well Completion or Recompletion Report and Log,the total depth is reported as 11,570' MD and 15,417'TVD. Was the total depth TVD of 15,417 an error on the Form 10-407? Would you please verify the depths. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 1 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS RECEIVED SEP 2 2 2014 AOGCC 1. Operations Abandon ❑ Repair Well ❑ Plug Perforations ❑ Perforate ❑ Other ❑Q Replaced ESP Performed: Alter Casing ❑ Pull Tubing 2] Stimulate - Frac ❑ Waiver ❑ Time Extension[:] Change Approved Program ❑ Operat. Shutdown[--] Stimulate - Other ❑ Re-enter Suspended Well❑ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska, LLC Development ❑Q Exploratory ❑ Stratigraphic❑ Service ❑ 169-086 3. Address: 3800 Centerpoint Drive, Suite 1400 6. AFI Number: Anchorage, AK 99503 50-733-20198-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0018730 Trading Bay Unit G-32 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): McArthur River Field / Middle Kenai G Oil and West Foreland Oil Pools 11. Present Well Condition Summary: Total Depth measured 11,570 feet Plugs measured N/A feet true vertical 11,417 feet Junk measured N/A feet Effective Depth measured 10,408 feet Packer measured N/A feet true vertical 9,512 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Structural Conductor 497' 17-3/4" 497' 497' Surface 4,810' 13-3/8" 4,810' 4,680' 3,090 psi 1,540 psi Intermediate Production 10,510' 9-5/8" 10,510' 9,595' 6,330 psi 3,810 psi Liner 847' 7" 11,255 10,194' 8,160 psi 7,020 psi Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth) 3-1/2" 9.2# / L-80 9,198' (MD) 8,489' (TVD) Packers and SSSV (type, measured and true vertical depth) Packer - N/A SSSV - 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: 258 180 6624 82 110 Subsequent to operation: 296 106 6509 91 99 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run Exploratory❑ Development ❑ Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 16. Well Status after work: Oil 0 Gas ❑ WDSPL❑ IGSTOR ❑ 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: 1314-455 Contact Dan Taylor Email dtaylor(Whilcorp.com Printed Name Dan Taylor'` Title Operations Engineer Signature Phone (907) 777-8319 Date 9/22/2014 t Form 10-404 Revised 10/2012 I1L;L..1nQ JLF 4 Submit Original Only 13-3/8 9-5/8 Hilcorp Alaska, LLC Original RKI3 = 42.80' 7" TD =11,255' Max hole angle is 34.8° @4,300' 70L @ 10,408' SCHEMATIC McArthur River Field Well: G-32 Last Completed: 08/22/14 PTD: 169-086 CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 17-3/4" .312 wt Conduct. G Tubing Hanger Surf. 497' 13-3/8" 61# J-55 9,199' 12.515" Surf. 4,810' 9-5/8" 47 & 43.5 S-95 & N-80 5 8.535" Surf. 10,510' 7 29 # N-80 Centralizer/Anode 6.184" 10,408' 11,255' TUBING DETAIL 3-1/2" 9.2# L-80 IBT 2.992" Surf 9,198 Updated By: JLL 09/19/14 PERFORATION DETAIL JEWELRY No. Depth OD Item 1 42.80' G Tubing Hanger 2 9,198' 6.75 Bolt -On Discharge 3 9,199' 6.75 Pump (x2) 675 Series SH10000 4 9,244' 5.13 Tandem Seals 5 9,262' 5.62 Motor (x2) 562 Series 340 HP 6 9,325' 9,444' Centralizer/Anode Updated By: JLL 09/19/14 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) Comments G 9,364' 9,370' 8,632' 8,637' Sqzd G 9,386' 9,390' 8,651' 8,654' Sqzd G-1 9,420' 9,444' 8,680' 8,701' Open G-1 9,435' 9,444' 8,693' 8,701' Open (DIL depths) 4-22-08 G-2 9,465' 9,490' 8,719' 8,740' Open G-2 9,466' 9,493' 8,720' 8,743' Open G-2 9,504' 9,516' 8,752' 8,763' Open G-3 9,542' 9,588' 8,785' 8,824' Open G-3 9,542' 9,590' 8,785' 8,826' Open G-4 9,607' 9,623' 8,840' 8,854' Open G-4 9,612' 9,622' 8,844' 8,853' Open GA 9,630' 9,653' 8,860' 8,879' Open G-4 9,630' 9,654' 8,860' 8,880' Open G-4 9,632' 9,652' 8,861' 8,878' Open (DIL depths) 5-2-08 G-5 9,697' 9,774' 8,917' 8,982' Open G-5 91711' 9,718' 8,929' 8,935' Open (DIL Depths) 5-2-08 WF -2 10,536' 10,571' 9,616' 9,645' Open WF -2 10,538' 10,573' 9,618' 9,646' Open WF -2 10,588' 10,601' 9,659' 9,669' Open WF 10,610' 10,622' 9,677' 9,686' Open WF -3 10,648' 10,655' 9,707' 9,713' Open WF -3 10,649' 10,656' 9,708' 9,714' Open WF -3 10,668' 10,686' 9,723' 9,738' Open WF -3 10,668' 10,684' 9,723' 9,736' Open WF -3 10,695' 10,697' 9,745' 9,747' Open WF -3 10,703' 10,727' 9,751' 9,771' Open WF -3 10,739' 10,785' 9,780' 9,817' Open WF -4,5 10,825' 10,963' 9,850' 9,961' Open WF -4 10,848' 10,870' 9,868' 9,886' Open WF -6 10,994' 11,046' 9,986' 10,027' Open WF -7 11,094' 11,150' 1 10,066' 10,111' Open Updated By: JLL 09/19/14 Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-32 50-733-20198-00 1 169-086 8/16/14 8/22/14 Daily Operations: 08/16/14 -Saturday Rigging up. 08/17/14 -Sunday Rigging up. 08/18/14 - Monday FINISH RIGGING UP. SET ACCUMULATOR UNDER PIPE RACK, HOOK UP CONTROL LINES. HOOKED UP GAS BUSTER. SET BACK PRESSURE VALVE. BOPE TEST WITNESS WAIVED BY JIM REGG @12:58 PM 8/18/2014. N/U 13 5/8" RISER. BEGAN BREAKING BOLTS ON TREE TO REMOVE. NOTICED 13 5/8" RISER WOULD NOT HAVE ENOUGH ROOM TO LINE UP STRAIGHT. NIPPLE BACK UP TREE, WHILE WAITING ON 11" RISER TO ARRIVE TO RIG. HOOKING UP GAS SENSORS. TEST SAME. M/U X-0 WEEP HOLE SUB TO TEST JT. REMOVE TREE. N/U RISER, BOPE, INSTALL RIG FLOOR, WIND WALLS, HOOK UP CONTROL LINES TO BOPE. 08/19/14 -Tuesday R/U AND TEST 13 5/8" BOPE AND COMPONENTS TO 5 MIN EACH 250 LOW 2500 HIGH. ALL TEST GOOD. WITNESS OF TEST WAIVED BY JIM REGG, AOGCC. R/D TEST EQUIPMENT. PERFORM ACCUMULATOR TEST. OFFLOAD EQUIPMENT, SPOT IN PLACE. RETRIEVE BACK PRESSURE VALVE. BACK OUT HOLD DOWN PINS IN HANGER. CHECK CSG SIDE FOR PRESSURE. PULL HANGER W/98K. MONITOR WELL. PULLTO RIG FLOOR, L/D SAME. PULL 2 STDS RUN CABLE THROUGH SHEAVES. CONNECT TO REEL, CONTINUE POOH. POOH RACKING BACK 3 1/2" 9.2# L-80 TBG IN DIRK REMOVING CLAMPS AND SPOOLING UP CABLES. CHANGED OUT CABLE SPOOL @ 5,400'. CONTINUE POOH. L/D ESP PUMP ASSY. 08/20/14 - Wednesday L/D ESP PUMP A_N_D_MOTQR. BACKLOAD SPOOLS WITH OLD CABLE AND ESP ASSY. BRING UP NEW ESP ASSY AND NEW SPOOLS. INSTALL SHEAVES BACK IN DRK W/ NEW CABLE. PICKING UP NEW ESP ASSY. CONNECT CAPILLARY LINES AND REDA CABLE. TEST CABLE CONNECTION W/PRODUCTION METER SENSOR READER (ZENITH METER BROKEN IN TRANSIT). PRODUCTION METER NOT READING PROPERLY. L/D ESP PUMP. PULL ABOVE FLOOR AND MONITOR WELL. PERFORM HOUSEKEEPING WHILE WAITING ON SENSOR AND METER TO ARRIVE. P/U MTR AND INSTALL REDA CABLE TO PHOENIX SENSOR. 08/21/14 - Thursday Make up ESP assembly and make cable and flat pack. Start TIH with 3.5" IBT Production tubing stand out of derrick with Reda cable and flat pack installing cannon clamps every other connection, also testing cable every 1000' while TIH. Continue TIH with 3.5" IBT Production tubing with Reda and flat pack cable, testing ever 1000'. Test Reda cable and make splice on cable @ 5,027' DPM, retest splice and continue TIH with production tubing. Finish splice continue TIH with 3.5" IBT production tubing installing cannon clamps every other tooljoint. Splice landed on top of joint 157 and 5,155' Depth at 6 am 7,853' total 241 jts 08/22/14 - Friday Finish TIH with 3-1/2" IBT production tubing, ESP Assembly, Reda cable and flat pack. Clean rig floor and make up landing joint while waiting on the penetrator to arrive. Equipment arrived, cut and splice Reda cable. Rig down shelves in derrick. Install hanger and prepare to land tubing. Land tubing and lock in same. Assist with Reda cable. End of Centerlizer 9,325', Intake 9,243', Discharge 9,198'. Start rigging down rig floor, tongs and scope and lay derrick down nipple down bope and riser. Clean hanger bowl and nipple up tree. Finish installing tree, test void to 1500 psi and shell test tree to 5000 psi for 5 min each on chart. Both test good. THE STATE GOVERNOR SEAN PARNELL Dan Taylor Operations Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99516 Re: McArthur River Field, Middle Kenai G & West Foreland Oil Pool, Trading Bay Unit G-32 Sundry Number: 314-455 Dear Mr. Taylor: 169-- ash Alaska Gii and Gas 333 West Seventh Avenue Anchorage, Alaska 99501-3572 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. DATED this U day of August, 2014. Encl. cerely, Daniel T. Seamount, Jr. Commissioner STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25 280 AUG 0 5 2014 AOGCC 1. Type of Request: Abandor ❑ Plug for Redril ❑ Perforate New Pool ❑ Repair Well ❑ Change Approved Program ❑ Suspenc ❑ Plug Perforations ❑ Perforate ❑ Pull Tubing D Time Extension ❑ Operations Shutdowr ❑ Re-enter Susp. Wel❑ Stimulate ❑ Alter Casing ❑ Other: Replace ESP - I] 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska,LLC Exploratory ❑ Development 0 Stratigraphic ❑ Service ❑ 169-086- 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage, AK 99503 50-733-20198-00 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 ❑ Trading Bay Unit / G-32 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL0018730 McArthur River Field / Middle Kenai G Oil and West Foreland Oil Pools I 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MID (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 11,570 11,417 10,408 9,512 N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 497' 17-3/4" 497' 497' Surface 4,810' 13-3/8" 4,810' 4,680' 3,090 psi 1,540 psi Intermediate Production 10,510' 9-5/8" 10,510' 9,595' 6,330 psi 3,810 psi Liner 847' 7" 11,255' 10,194' 8,160 psi 7,020 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schematic See Schematic 3-1/2" 9.2# / L-80 9,198 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): N/A N/A 12. Attachments: Description Summary of Proposal P-1 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch Ej Exploratory ❑ Stratigraphic ❑ Development Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 8/11/2014 Oil Gas ❑ WINJ ❑ GINJ ElWAG WDSPL ❑ Suspended ❑ ElAbandoned E]Commission 16. Verbal Approval: Date: Representative: GSTOR ElSPLUG El 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Dan Taylor Email dtaylor(aihilcorp.com Printed Name Dan Tayl Title Operations Engineer Signature Phone (907) 777-8319 Date 8/5/2014 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity ❑ BOP Test Q Mechanical Integrity Test ❑ Location Clearance ❑ Other: _ Spacing Exceptio uired? Yes ❑ No Q� Subsequent Form Required: i t j APPROVED BY Approved b COMMISSIONER THE COMMISSION Dat . MW ROD SForm 3t AUG1e1S�101 ' ) -7 t 1 �144 RI(411 A p i tNvAt4ollths r mt e date of approval. Submit Form and Attachments in Duplicate Ililcorp Alaska, LLQ Well Prognosis Well: G-32 Date: 8/5/2014 Well Name: G-32 API Number: 50-733-20198-00 Current Status: Producer Leg: 2 Estimated Start Date: Aug11, 2014 Rig: Moncla 404 Reg. Approval Req'd? 10-403 Date Re . Approval Rec'vd: Regulatory Contact: Juanita Lovett 777-8332 Permit to Drill Number: 169-086 First Call Engineer: Daniel Taylor 907 777-8319 O 907 947-8051 M Second Call Engineer: I James Young 907 777-8421 O AFE Number: Current Bottom Hole Pressure: Maximum Expected BHP: Max. Allowable Surface Pressure: Brief Well Summary 3,350 psi @ 8,600ft TVD / 9,290ft MD 3,350 psi @ 8,600ft TVD / 9,290ft MD 2,400 psi 0.39 psi/ft at mid-perf based on BH gauge data 0.39 psi/ft at mid-perf based on BH gauge data 0.1 psi/ft " 9,371 ft mid perf Grayling G-32 went down on the evening of Aug 3, 2014. Prior to shut down the well was producing through an ESP a gross rate of 6,887bpd with a 5% oil cut. The plan forward is to have the Moncla 404 rig mobilize from the King Platform and get on the NE corner of the Grayling platform cattycorner to the Moncla 301. Procedure: 1. Rig up Moncla 404 over G-32. 2. Pump down the tubing and take returns to production. 3. Set back pressure valve. 4. Nipple down wellhead and nipple up BOP. a. Test BOP's to 250psi low / 2 400psi-high and chart (Notify AOGCC 48hrs prior to conducting BOP test). 5. Pull out of hole with ESP and completion string laying down the same. a. Spooling back capillary lines and cable. b. Removing cannon clamps Pick up and run in hole with ESP completion and set ESP bottom at +/-9,300ft. a. Spooling out capillary lines and cable. b. Running cannon clamps every joint for 6 joints and every other joint to surface. 7� 7. Land hanger and test to 1,500psi on chart. Gs� 8. Nipple down BOP. ,�aoy.5 9. Nipple up tree and test. t 7 14 Attachments: 1. As -built Well Schematic 2. Proposed Well Schematic 3. Current Well Head 4. BOP Stack 5. Rolling Test Procedure 13-318 9-518 Hileorp Alaska, LLC. Original RKB = 42.80' 6,7 8 7„ TD = 11,255' Max hole angle is 34.8° @ 4,300' TOL (q) 10,408' 61141a1 : II YTfro CASING DETAIL McArthur River Field, TBU Well: G-32 As Completed: 1/13/2013 SIZE WT GRADE CONN ID TOP BTM. 17-3/4" .312 wt Conduct. 1 Surf. 497' 13-3/8" 61N 1-55 12.515" Surf. 4,810' 9-5/8" 7 47 & 43.5 # 29 k S-95 & N-80 N-80 8.535" 6.184" Surf. 10,408' 10,510- 11,255' TUBING DETAIL 3-1/2" 9.2N L-80 IBT 3.5" Surf 9,198' PERFORATION DETAIL JEWELRY DETAIL No. Top Depth Btm Depth OD Item 1 9,197' 9,198' 4.5" Crossover Pressure Head 2 9,198' 9,199' 6.75" Bolt On Head, Top of ESP 3 9,199' 9,242' 6.75" 3 -stage Pump (x3), 96 stages, 112000N 4 9,242' 9,244' 6.75" Pump Intake - BOI, 675/738 RLOY 5 9,244' 9,261' 7.38" Protectors (2) 6 9,261' 9,295' 7.38" Motor - 900 hp 738, 18, E-180 Dominator RK -5 7 9,295' 9,297' 4.50" Base Gauge -xT 150 Type I, Viton/Aflas 8 9,297' 9,299' 5.62" GLM Anode, Centralizer PERFORATION DETAIL Zone Top (MD) Btm (MID) Top (TVD) Btm (TVD) Comments G 9,364' 9,370' 8,632' 8,637' Sqzd G 9,386' 9,390' 8,651' 8,654' Sqzd G-1 9,420' 9,444' 8,680' 8,701' Open G-1 9,435' 9,444' 8,693' 8,701' Open (DIL depths) 4-22-08 G-2 9,465' 9,490' 8,719' 8,740' Open G-2 9,466' 9,493' 8,720' 8,743' Open G-2 9,504' 9,516' 8,752' 8,763' Open G-3 9,542' 9,588' 8,785' 8,824' Open G-3 9,542' 9,590' 8,785' 8,826' Open G-4 9,607' 9,623' 8,840' 8,854' Open G-4 9,612' 9,622' 8,844' 8,853' Open G-4 9,630' 9,653' 8,860' 8,879' Open G-4 9,630' 9,654' 8,860' 8,880' Open G-4 9,632' 9,652' 8,861' 8,878' Open (DIL depths) 5-2-08 G-5 9,697' 9,774' 8,917' 8,982' Open G-5 9,711' 9,718' 8,929' 8,935' Open (DIL Depths) 5-2-08 WF -2 10,536' 10,571' 9,616' 9,645' Open WF -2 10,538' 10,573' 9,618' 9,646' Open WF -2 10,588' 10,601' 9,659' 9,669' Open WF 10,610' 10,622' 9,677' 9,686' Open WF -3 10,648' 10,655' 9,707' 9,713' Open WF -3 10,649' 10,656' 9,708' 9,714' Open WF -3 10,668' 10,686' 9,723' 9,738' Open WF -3 10,668' 10,684' 9,723' 9,736' Open WF -3 10,695' 10,697' 9,745' 9,747' Open WF -3 10,703' 10,727' 9,751' 9,771' Open WF -3 10,739' 10,785' 9,780' 9,817' Open WF -4,5 10,825' 10,963' 9,850' 9,961' Open WF -4 10,848' 10,870' 9,868' 9,886' Open WF -6 10,994' 11,046' 9,986' 10,027' Open WF -7 11,094' 11,150' 10,066' 10,111' Open 13-3/8 9-5/8 Iiileorp Alaska, LLC Original RIB = 42.80' T' TD =11,255' Max hole angle is 34.8° @4,300' 7tN. @ 10,408' PROPOSED McArthur River Field Well: G-32 Last Completed: 01/13/2013 PTD: 169-086 CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 17-3/4" .312 wt Conduct. G 9,364' Surf. 497' 13-3/8" 61# J-55 9,386' 12.515" Surf. 4,810- ,810'9 9-5/8" 5/8" 47 +.5 S-95 & N-80 9,444' 8.535" Surf. 10,510' 7 29# N-80 8,693' 6.184" 10,408' 11,255' TUBING DETAIL 3-1/2" 9.2# L-80 I IBT 1 3.5" Surf JEWELRY No. Depth OD Item 1 ±9,300' Top (TVD) Bottom of ESP Updated By: JLL 08/05/14 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) Comments G 9,364' 9,370' 8,632' 8,637' Sqzd G 9,386' 9,390' 8,651' 8,654' Sqzd G-1 9,420' 9,444' 8,680' 8,701' Open G-1 9,435' 9,444' 8,693' 8,701' Open (DIL depths) 4-22-08 G-2 9,465' 9,490' 8,719' 8,740' Open G-2 9,466' 9,493' 8,720' 8,743' Open G-2 9,504' 9,516' 8,752' 8,763' Open G-3 9,542' 9,588' 8,785' 8,824' Open G-3 9,542' 9,590' 8,785' 8,826' Open G-4 9,607' 9,623' 8,840' 8,854' Open G-4 9,612' 9,622' 8,844' 8,853' Open G-4 9,630' 9,653' 8,860' 8,879' Open G-4 9,630' 9,654' 8,860' 8,880' Open G-4 9,632' 9,652' 8,861' 8,878' Open (DIL depths) 5-2-08 G-5 1 9,697' 9,774' 8,917' 8,982' Open G-5 9,711' 9,718' 8,929' 8,935' Open (DIL Depths) 5-2-08 WF -2 10,536' 10,571' 9,616' 9,645' Open WF -2 10,538' 10,573' 9,618' 9,646' Open WF -2 10,588' 10,601' 9,659' 9,669' Open WF 10,610' 10,622' 9,677' 9,686' Open WF -3 10,648' 10,655' 9,707' 9,713' Open WF -3 10,649' 10,656' 9,708' 9,714' Open WF -3 10,668' 10,686' 9,723' 9,738' Open WF -3 10,668' 10,684' 9,723' 9,736' Open WF -3 10,695' 10,697' 9,745' 9,747' Open WF -3 10,703' 10,727' 9,751' 9,771' Open WF -3 10,739' 10,785' 9,780' 9,817' Open WF -4,5 10,825' 10,963' 9,850' 9,961' Open WF -4 10,848' 1 10,870' 9,868' 9,886' Open WF -6 10,994' 1 11,046' 9,986' 10,027' Open WF -7 11,094' 1 11,150' 10,066' 10,111' Open Updated By: JLL 08/05/14 Grayling Platform G-32 13 3/8 X 9 5/8 X 3 1/2 Valve, swab, WKM-M, 4 1/16 5M FE, HWO, T-24 Valve, wing, WKM-M, 2 1/16 5M FE, HWO, T-24 Valve, lower master, WKM-M, 4 1/16 5M FE, HWO, T-24 Tubing head, CIW-DCB, 13 5/8 3M X 11 5M, w/ 2- 2 1/16 5M SSO, X bottom R seal installed in head Casing head, CIW-WF, 13 5/8 3M X 13 3/8 SOW, w/ 2- 2 1/16 5M EFO CA slips hung off in wellhead BHTA, Bowen, 4 1/16 5M X 7"- 55A Bowen top Grayling Platform G-32 Current 04/12/2013 Tubing hanger, CIW-DCB-ESP, 11 X 4 % IBT lift and susp, w/ 4" type H BPV profile, 5 X EN, 2- 3/8 continuous control line ports, prepped for BIW penetrator Cross, stdd, 4 1/16 5M X 4 1/16 5M X 2 1/16 5M Valve, WKM-M, 4 1/16 5M FE, w/ MA -16 operator Adapter, CIW-Toadstool, 11 5M Stdd X 4 1/16 5M FE, prepped for 5'/4 EN neck, 2-'/z npt continuous control line ports, BIW penetrator port Valve, WKM-M, 2 1/16 5M FE, HWO, DD 20 Qty 2 Hilrnrp Alsoku, MA Grayling Platform 2013 BOP Stack (Moncla) 09/19/2013 Hilcorp Alaaka,11C Attachment #1 Moncla Rig 404 BOP Test Procedure Attachment #1 Hilcorp Alaska, LLC - BOP Test Procedure: Moncla Rig 404, Grayling 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. 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 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.) Hileorp Alaeka, LLC Moncla Rig 404 BOP Test Procedure 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) Referencing the attached schematics test rams and valves as follows. a) Close C-1 (inside gate valve on choke side of mud cross) and close the annular preventer. Pressure test to 200 psi for 5 minutes and 1,500 psi high for 5 minutes. If passes after 5 minutes on each, bleed off back to tank and open annular. b) Close Pipe Rams. Test to 200 psi for 5 minutes and 3,000 psi high for 5 minutes. If passes after 5 minutes on each, bleed off back to tank and open pipe rams. 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 200 psi for 5 minutes and 3,000 psi for 5 minutes. If passes after 5 minutes on each, bleed off back to tank and open rams. d) Open C-1. Flow through the choke manifold and purge air. Test the choke manifold starting with the outer most valves, to 250 psi low and 3,000 psi high, for 5 minutes each, as follows: (Valve numbers are in reference to Diagram B) i) Valves 1, 2, 10. After test, open same. ` Moncla Rig 404 BOP Test Procedure Hileorp Alaska, l.l.0 Attachment #1 ii) Valves, 3, 4, 9. After test, open valves 3 & 4. Leave 9 closed. iii) Valves 5, 6, 9. After test, open valves 5 & 6, leave 9 closed. iv) Valves, 7, 8, 9. After test, open all valves. e) Close C-2. This is the HCR (the hydraulic controlled remote) valve just outside C-1 on choke side of mud cross. Test to 250 psi low and 3,000 psi high. After test, open HCR, close C-1. f) Blind Rams. Make sure test joint is above the blind rams. Close blind rams. Test to 200 psi Low for 5 minutes and 3,000 psi High for 5 minutes. Bleed down pressure. g) Bleed off all pressure. Line up pumps to pump down tubing. h) Test K-1, K-2, and K-3 on the kill (pump -in) side by pressuring up on tubing. Test to 200 psi Low for 5 minutes and 3,000 psi High for 5 minutes. i) Test floor valves TIW (or Lower Kelly Valve) and IBOP. 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. Moncla Rig 404 BOP Test Procedure Hileorp Alaaka, LLC Attachment #1 Diagram A-1: Grayling BOP stack and Riser Arrangement — Typical for Single Completion M M Hilrorp Alaska, LLC Diagram B: Grayling Choke Manifold Moncla Rig 404 BOP Test Procedure Attachment #1 From Bop Choke Line 2 1/16 5M Unibolt Flange Valve Type #1 National Ball Valve B3260, 3'/4" Ball port, 6000psi working pressure #2 National Ball Valve 83260, 3 '/4" Ball port, 6000psi working pressure #3 National Ball Valve B2650, 2 9/16" Ball port, 5000psi working pressure #4 National Ball Valve B2650, 2 9/16" Ball port, 5000psi working pressure #5 National Ball Valve B2650, 2 9/16" Ball port, 5000psi working pressure #6 National Ball Valve B2650, 2 9/16" Ball port, 5000psi working pressure #7 National Ball Valve B2650, 2 9/16" Ball port, 5000psi working pressure #8 National Ball Valve B2650, 2 9/16" Ball port, 5000psi working pressure #9 National Ball Valve B3260, 3'/4" Ball port, 6000psi working pressure #10 National Ball Valve B1560, 1 '/2" Ball port, 6000psi working pressure Hilcorp Alaska, LLC Moncla Rig 404 BOP Test Procedure Attachment #1 �g K V_W i z 41 a pW qS i> O .6 m < a a Z0 Q r � Y e 2 r D J CD Z CO ~ � O _ Z Z O U 20 CDt V v o ad g VC) FEW O -J _j W 03;� _ 0 (� oa a�z �N > J O Z W LLZ�LU �a Q= J D C) C) Hileorp Alaska, LLC Moncla Rig 404 BOP Test Procedure Attachment #1 Schwartz, Guy L (DOA) From: Daniel Taylor <dtaylor@hilcorp.com> Sent: Thursday, August 07, 2014 10:55 AM To: Schwartz, Guy L (DOA) Subject: RE: G-32 RWO (PTD 169-086) Guy, The ESP was replaced in March of 2013. The casing was not tested at that time. The casing test will be performed and in the future all ESP wells that have not had a casing test within the past 4yrs will have a casing test incorporated in the application for Sundry approval. Thank you sir. Regards, Daniel Taylor 907-947-8051 From: Schwartz, Guy L (DOA) [mailto;guy.schwa rtz@alaska.gov] Sent: Thursday, August 07, 2014 10:12 AM To: Daniel Taylor Subject: G-32 RWO (PTD 169-086) Dan, When was the last time the ESP was pulled and was the 9 5/8" casing tested? If it hasn't been tested in the last 4-6 yrs or so it will need to be done with test packer. It would be helpful if this info was included in the sundry application ( for any ESP workover). 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.aov). STATE OF ALASKA ALA OIL AND GAS CONSERVATION COMAION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon ❑ Repair Well ❑ Plug Perforations ❑ Perforate El Other El Installed ESP Performed: Alter Casing ❑ Pull Tubing El Stimulate - Frac ❑ Waiver ❑ Time Extension❑ Change Approved Program ❑ Operat. Shutdown❑ Stimulate - Other ❑ Re -enter Suspended WOO 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska, LLC Development El Exploratory ❑ 169 -086 3. Address: 3800 Centerpoint Drive, Suite 100 Stratigraphic Service ❑ 6. API Number: Anchorage, AK 99503 50- 733 - 20198 -00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0018730 ' Trading Bay Unit G -32 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field /Pool(s): ` McArthur River Field / Middle Kenai G Oil and West Foreland Oil Pools 11. Present Well Condition Summary: Total Depth measured 11,570 feet Plugs measured N/A feet true vertical 11,417 feet Junk measured N/A feet Effective Depth measured 10,408 feet Packer measured N/A feet true vertical 9,512 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Structural Conductor 497' 17 -3/4" 497' 497' Surface 4,810' 13 -3/8" 4,810' 4,680' 3,090 psi 1,540 psi Intermediate Production 10,510' 9 -5/8" 10,510' 9,595' 6,330 psi 3,810 psi Liner 847' 7" 11,255 10,194' 8,160 psi 7,020 psi Perforation depth Measured depth See Schematic feet SCANNED BAR 2413 True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth) 3-1/2" 9.2# / L -80 9,198' (MD) 8,489' (TVD) 9 9 p ) " ' ( ) Packers and SSSV (type, measured and true vertical depth) Packer - N/A SSSV - N/A RECEIVED_ 12. Stimulation or cement squeeze summary: 'C FR 1 3 2013 Intervals treated (measured): N/A AOGCC 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: 150 140 3500 1150 180 Subsequent to operation: 170 50 4200 100 120 14. Attachments: 15. Well Class after work: • Copies of Logs and Surveys Run Exploratory❑ Development El Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 16. Well Status after work: r Oil IE Gas ❑ WDSPL❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 312 -359 Contact Chet Starke) Email cstarkelt�hiIcorr).COCTm Printed Name Chet Starkel Title Asset Team Leader Signature •fr Phone 907 777 -8344 Date 2/13/2013 1 BDMS FEB z -zZ l3 Form 10-404 Revised 10/2012 B 1 � ���� 7 f' / Submrt Original Only • SCHEMATIC . McArthur River Field, TBU Well: G -32 §lilmrp Alaeka, 114 Completed: 01/13/2013 Original RKB = 42.80' MN./ CASING AND TUBING DETAIL 1, SIZE WT GRADE CONN ID MD TOP MD BTM. 1 7 -3/4" .312 wt Conduct. Surf. 497' 13 -3/8" 61# J -55 12.515" Surf. 4,810' 9 5/8" 47 & 43.5 S-95 & 8.535" Surf. 10,510' 13 - 3/8 # N - 80 7 29 # N - 80 6.184" 10,408' 11,255' Tubing: 3 - 1/2" 9.2# L -80 IBT 3.5" Surf 9,198' Jewelry Detail No. Top Depth Btm Depth OD Item 1 9,197' 9,198' 4.5" Crossover Pressure Head 2 9,198' 9,199' 6.75" Bolt On Head, Top of ESP 3 9,199' 9,242' 6.75" 3 -stage Pump (x3), 96 stages, J12000N 4 9,242' 9,244' 6.75" Pump Intake - BOI, 675/738 RLOY 5 9,244' 9,261' 7.38" Protectors (2) 6 9,261' 9,295' 7,38 Motor -900 hp 738, 18, E -180 Dominator R K -S 1 7 9,295' 9,297' 4.50" Base Gauge - XT 150 Type I, Viton /Aflas 2 8 9,297' 9,299' 5.62" GLM Anode, Centralizer 3 4 5 Perforation Detail 6, 7 Zone Top(MD) BTM(MD) Top(TVD) BTM(TVD) Comments G 9,364' 9,370' 8,632' 8,637' Sqzd _ 8 G 9,386' 9,390' 8,651' 8,654' Sqzd G -1 9,420' 9,444' 8,680' 8,701' Open ■ G -1 9,435' 9,444' 8,693' 8,701' Open (DIL depths) 4-22 - 08 ■ G -2 9,465' 9,490' 8,719' 8,740' Open TOL @ 10,408' G -2 9,466' 9,493' 8,720' 8,743' Open G -2 9,504' 9,516' 8,752' 8,763' Open G -3 9,542' 9,588' 8,785' 8,824' Open 9 -5/8 G -3 9,542' 9,590' 8,785' 8,826' Open G -4 9,607' 9,623' 8,840' 8,854' Open G -4 9,612' 9,622' 8,844' 8,853' Open G -4 9,630' 9,653' 8,860' 8,879' Open G -4 9,630' 9,654' 8,860' 8,880' Open G -4 9,632' 9,652' 8,861' 8,878' Open (DIL depths) 5 -2 -08 G -5 9,697' 9,774' 8,917' 8,982' Open ■ G -5 9,711' 9,718' 8,929' 8,935' Open (DIL Depths) 5 -2 -08 WF -2 10,536' 10,571' 9,616' 9,645' Open WF -2 10,538' 10,573' 9,618' 9,646' Open WF -2 10,588' 10,601' 9,659' 9,669' Open WF 10,610' 10,622' 9,677' 9,686' Open MN_ WF -3 10,648' 10,655' 9,707' 9,713' Open WF -3 10,649' 10,656' 9,708' 9,714' Open WF -3 10,668' 10,686' 9,723' 9,738' Open WF -3 10,668' 10,684' 9,723' 9,736' Open A , 7+ WF - 10,695' 10,697' 9,745' 9,747' Open WF -3 10,703' 10,727' 9,751' 9,771' Open WF -3 10,739' 10,785' 9,780' 9,817' Open TD= 11,255' WF -4,5 10,825' 10,963' 9,850' 9,961' Open Max hole angle is 34.8 @ 4,300' WF -4 10,848' 10,870' 9,868' 9,886' Open WF -6 10,994' 11,046' 9,986' 10,027' Open WF -7 11,094' 11,150' 10,066' 10,111' Open Revised 02/12/13 by JLL • • Hilcorp Alaska, LLC Ilihorp Weekly Operations Summary Well Name API Number IWell Permit Number Start Date End Date G -32 50- 733 - 20198 -00 169 -086 11/28/2012 1/13/2013 Daily Operations: 11/28/12- Wednesday Blow well down to initiate Kill for workover. Rig down and prepare for Skid. Hook up Hydraulics. Skid rig over G -32. Prepare to rig up. 11/29/12 - Thursday Repair pump and service rig while waiting on a -line crews to arrive location. R/U E -line & RIH to 9,268' with 2.650" od gauge & POOH with same. P/U & M/U 1- 11/16" 4 SPF 0 deg phase gun & RIH to 9,276' ELM. P/U and log guns on depth & perforate tbg from 9,257' to 9,260'. POOH & R/D E -line. R/U & hook up lines to tbg & csg. Attempt to reverse well clean with FIW pumping at 2BPM without success. R/D lines on tree, and set BPV. ND tree. 11/30/12 - Friday N/U Riser spools, BOP's and lines. Install rig floor and walls, raise and scope out derrick. Connect control lines to BOP's, connect electric power to test pump. Hang off block & change out drill line. Tested Swaco choke valves to 250 psi low & 3,500 psi high on chart for 5 min each test. Test BOPE, 250 psi low & 3,500 psi high. Witness of test waived by Jim Regg, AOGCC. Test Hydril to 1,500 psi. New Pipe rams failed to test. Ordered out new set. Installed New 4 -1/2" pipe rams. Retested same 250 psi low & 3, 500 psi High. Test ok. Backed out hanger pins. Screw in landing jt & tighten same. Attempt to pull hanger /pipe free. Pulled up to a maximum of 160K, app 55K over calc pipe weight. Seeing approx. 2 - 3" of travel. Pipe begins to move with 90K Ibs of pull. Re- checked all hanger pins. Continue working pipe up to 170K before breaking free. Continue working pipe slowly until hanger reached surface. Remove hanger. 12/01/12 - Saturday Install tarps below floor and around BOP's. Install heater line. Reposition air line and N2 bottles for Kommey unit. POOH with 4 -1/2" production strapping same. Note: found SCSSV control line broke below first band below hanger and safety valve. +/- 280' of control, line left in well. 200 Jts laid down at report time. 12/02/12 - Sunday Continue POOH & L/0 4 -1/2" production tbg and valves. Clean floor and change out 4 -1/2" rams to 2 -7/8" rams. M/U test plug & land same. Test rams, TIW valve & IBOP to 250 psi low & 3,500 psi high on chart for 5 min. Tested annular preventer to 250 psi low & 2,500 psi high on chart for 5 min. B/O TIW valve and IBOP form test jt. Pull test plug and break out and L/O test jt and plug. P/U and M/U milling BHA # 1 ( 8.500" od shoe, 8.125" od jt of washpipe, 8.125" drive sub, 3 -1/2" x 4 -1/2" x -over, 4 -3/4" bumper sub, 4 -3/4" oil jar, 4 -3/4" collars, 4 -3/4" slingerjar, 2 -7/8" x 3 -1/2" x -over, total length= 195.45' ). Repair break water lines & air clutch for cat head. RIH with BHA # 1, picking up 2 -7/8" 10.40# IF Drill pipe off deck. 175 jts in hole. 12/03/12 - Monday Continue RIH with milling BHA # 1. Tagged up on packer @ 9,268' DPM Rigged up power swivel. Pump lines froze up. Work on thawing out lines & pump. 12/04/12 - Tuesday Line up pump on casing, started reversing at 1 BPM w/ 400 psi and got oil in returns on DP after 85 bbls pumped. Swapped pump to DP and bullheaded 40 bbls into formation. Mill on Otis BWH @ 9,268' DPM 9,270' with 2000 wt down, 1 BPM, at 60 RPM taking no returns on DP. 12/05/12 - Wednesday Continue mill from 9,270' to 9,272' DPM. Unable to make more hole. Attempted to break out kelly jt and power swivel, unable to do so because of TIW valve being frozen up with ice and unable to close same. Thaw out TIW valve and swivel with Mag -Tec heater. Close TIW valve, B/O power swivel and M/U pump in hose. Bull head 50 bbls of FIW into formation at 2 bpm /900 psi. B/O & L/0 pump in hose, power swivel and kelly hose. POOH with milling BHA #1. Change Williams power tongs for PTS power tongs. Continued POOH with BHA #1. Changed out PTS tongs for Williams tongs, continued POOH with BHA #1. 12/06/12 - Thursday Continue POOH with 2 -7/8" DP & BHA # 1. Stand back 4 -3/4" collars. B/O & L/0 jars. B/O burning shoe. M/U milling BHA # 2 and RIH. Rig up power swivel & pump lines. Suction discharge on Schlumberger tank frozen. Work to thaw same. 12/07/12- Friday, 044 Continue thawing lines on Schlumberger pump. Mill BWH packer 9,270' DPM, with 8 - 10 k down, 70 rpm, pumping at 1 -1/2 BPM get 1 BPM back. Reverse 2 DP volumes & blow down lines. B/O & L/O power swivel. Chased packer down hole to 9,285' tagged up with 5000 down. POOH with BHA #2. Rack back drill collars & laid down BHA #2. Retrieve wear bushing & installed test plug in hanger. Testing BOP rams, blinds, TIW, IBOP, choke manifold and lines to 250 psi low / 3,500 psi high on chart f/ 5 min each test. • Hilcorp Alaska, LLC H, ►corpAI,L.k,,L►c Weekly Operations Summary Well Name API Number IWell Permit Number Start Date End Date G -32 50- 733 - 20198 -00 169 -086 11/28/2012 1/13/2013 Daily Operations: 12/08/12 - Saturday Continue testing BOP to 250 psi low & 3,500 psi high on chart for 5 min. Repair chart recorder. Test annular to 250 psi low 2,500 psi high on chart for 5 min. Witness of test waived by Jim Regg, AOGCC. M/U & P/U BHA# 3, RIH to 9,278' dpm tagged packer with 5k down and packer bore moved down hole. Chased down hole to 9,370' & sat down 30k on packer bore. P/U wt =112K / SO wt = 92K, P/U 112k & bumped down with 5K down on packer P/U to 120k and packer started moving up hole. POOH to 8,440' and packer hung up. Jarred up with 30K over P/U wt continued POOH. POOH to 8,173' packer hung, jarred packer free with 35K. Continue POOH with BHA #3 & packer. 12/09/12 - Sunday Continue POOH with BHA #3. L/0 overshot, bumper sub, oil jar, & washpipe. B/O overshot, washpipe, bumper sub, and jars. P/U and M/U BHA #4, RIH to 10,360' and tagged up with 2000 wt down. P/U 12' & rig up power swivel. Rig up lines and attempt to reverse circulate. Bleed pressure on casing to -0- & started pumping down DP with 800 psi and got returns on casing. Stopped pumping after circulated 15 bbls. Lined up on csg and reversed out with 1000 psi @ 1 -1/2 bpm at 75 bbl pumped lost returns and pressure increased to 1200 psi and lost returns. Swap lines to pump down DP, after pumping 1/2 bbl pressure was 1700 psi w/ no returns. Stopped pumping and let pressure drop 800 psi and got returns on casing lined up to pump down casing at 06:00. 12/10/12 - Monday Continue washing down @ 1 -1/2 bpm from 10,360' to 10,380'. Closed hydril adjusted closing pressure and attempted to reverse and found DP plugged. Lined up on DP and attempted to blow plug in DP by pressuring up to 3000 psi. Unable to clear plug from pipe. With hydril closed, slacked off and attempted to mill down pumping at 1 -1/2 BPM with 1100 psi w/o success. Upper perfs taking all of fluid being pumped, pipe torqueing up and hydril leaking. POOH with BHA # 3 using mud bucket, ( pipe wet) pipe plugged from drive bushing on wash pipe to top of collars plugged with sand and rubber. Drive bushing was plugged soild with rubber. Pull wear bushing and installed test plug. Ran in 4 hold down pins and closed blind rams. Nipple down Hydril & set on deck. Start breaking out bolts on top of hydril. 12/11/12 - Tuesday Continue breaking out bolts on top of annular preventor. Remove rubber for top of preventor. Install new rubber and torque up bolts on annular cap. P/U annular and stab on to BOP stack & torque up bolts. R/U rig floor. P/U M/U landing jt. Close annular & test to 250 psi low / 2,500 psi high for 5 min on chart, all test OK. Install legs under rig floor. Hang tarps around BOP stack. Pull landing jt and test plug. Install wear bushing, wash out sand from inside of drill collars. Continue cleaning inside of collars. 12/12/12 - Wednesday R/U tongs, install wind walls and hand rails on rig floor. P/U and M/U BHA #5. RIH milling BHA 5 & 2 -7/8" drill pipe to 10,281'. P/U power swivel & kellyjoint. Reverse wash from 10,281' to top of BHW packer @ 10,419' DPM pumping at 2 bpm with 550 psi. Mill from 10,419' to 10,422.50' with 3 -6k down, pumping @ 2 -1/2 bpm, with 800 psi. 12/13/12 - Thursday Continue milling on BHW packer from 10,422.50' to 10,425' and packer started moving down hole. Continue milling and chasing packer body down hole to 10,672'. Continued washing, milling and working pipe & unable to get deeper than 10,673'. P/U off bottom and circulate well. 12/14/12 - Friday POOH with 2 -7/8" DP, BO and LO BHA # 5. P/U & M/U BHA # 6, RIH to 10,660' with 2 -7/8 DP. P/U power swivel, continue in hole to 10,672' tagged fish with 10k down, P/U and had 10k drag. R/D power swivel and POOH with 2 -7/8" DP with 2k drag. 12/15/12 - Saturday POOH with 2 -7/8" DP and BHA #6. Continue out of hole, BO & LO BHA. Full recovery, packer bore, 10' pup & wireline re -entry guide. Pull wear bushing, set test plug, clean BOP stack. 12/16/12 - Sunday Continue cleaning rig while waiting on State Inspector to start testing BOP's, safety valves, lines and manifolds. Attempted to test choke manifold and bottom valves of choke was iced up. Inspector stated that he would not approve rig going back to work until a solution was found to keep all line and manifolds ice free. Project shutdown for rig winterization improvements. • • Hilcorp Alaska, LLC Hileorp Alaska, LLC Weekly Operations Summary Well Name API Number IWell Permit Number Start Date End Date G -32 50- 733 - 20198 -00 169 -086 11/28/2012 1/13/2013 Daily Operations: 12/17/12 - Monday Project shutdown for rig winterization improvements. 12/18/12 - Tuesday Project shutdown for rig winterization improvements. 12/19/12 - Wednesday No operations to report. 12/20/12 - Thursday No operations to report. 12/21/12 - Friday P/U and M/U TriPoint packer and storm valve and RIH and set at 500'. Set packer, close valve and test same to 500 psi on casing. POOH. 12/22/12 - Saturday No operations to report. 12/23/12 - Sunday No operations to report. 12/24/12 - Monday No operations to report. 12/25/12 - Tuesday No operations to report. 12/26/12 - Wednesday No operations to report. 12/27/12 - Thursday Install 13 -5/8" rubber into annular body and torque down top bonnet onto main body of annular. Nipple up Annular BOP. Connect hydraulic control lines and attempted to function to annular. Regulator for annular pressure not fuctioning correctly, it will not hold a steady pressure. 12/28/12 - Friday P/U test joint and TIW valve, screw into test plug, close annular and tested same to 250 low / 2500 high for 5 min ( tested OK ). B/O test joint and TIW valve & L/0 same. Close blind rams and tested to 250 psi low / 3500 high for 5 min ( tested ok ). Continue winterization of rig. 12/29/12 - Saturday r o Waiting on State Inspector to arrive on platform. Inspector checked winterization of all equipment on rig 404 (rig, BOP's, pumps and all other related equipment passed inspection). Test BOP pipe rams, blind rams, choke manifodls, lines, IBOP & TIW valves to 250 psi low & 3500 psi high on chart for 5 min. Tested annular to 250 psi low & 2500 psi high on chart for 5 min (all equipment tested ok). Test witnessed by Lou Grimaldi, AOGCC Inspector. Went over inspection of gas detection system with State Inspector and was told we had to move lights and alarm horn to different location for alarm to be heard clearly by all hands on deck and rig floor and so the lights could bee seen by driller. Inspector also advised that the system was not working correctly due to no difference in H2S or common alarms. Found pit level indicator was not reading correctly it showed 27 bbls less fluid in pits than actual strapped reading. We will move alarms and warning lights so the can be heard and seen by driller. Adjusted pit level indicaters to match fluid level in pits. Waiting on State approval to resume operations. 12/30/12 - Sunday Waiting on State approval to resume operations. 12/31/12 - Monday Recieved permision to return to work at 11:06 hrs under the condition that gas detection system on rig met state requirments. Attempting to integrate rig mounted gas detection into platform system in order to give 2 distinct warnings with audible and visual indicators for methane and H2s gases & unable to do so. At 13:00 hrs called Total Safety for gas detection system. Attempt to integrate gas detection systems while W/O TSS to arrive platform. • • Hilcorp Alaska, LLC Hikori, Alaska, LLC Weekly Operations Summary Well Name API Number IWell Permit Number Start Date End Date G -32 50- 733 - 20198 -00 169 -086 11/28/2012 1/13/2013 Daily Operations: 01/01/13 - Tuesday P/U & M/U Storm valve stinger & RIH to 486'. Screw into valve, equalize DP pressure and unset storm packer. Break circulation with 1 bpm 250 psi. Pumped 30 bbls & increased rate to 2 BPM 450 psi. R/U lines & pumped +/- 300 bbls of oil and water to Trading Bay at 2 BPM 450 psi. Shut down pumps monitored for flow and recieved 3 bbls back in 5 min. Circulate at 2 BPM on choke holding 300 psi back pressure. Monitor well for flow. R/D lines pump in sub and TIW valve. POOH slow with 2 -7/8" DP and storm packer. On fifth stand out of hole, tongs gave up. Change out tongs for back up set, attempted to break out DP w/o success. Continue POOH & L/D storm packer. Continue POOH to surface with 2 -7/8" DP. P/U & M/U milling BHA ( bladed junk mill, scraper, bit sub, bumper jar, oil jar, drill collars, acc jar, x -over totla lenght = 104.69. RIH with mill BHA and 2 -7/8" DP, P/U and R/U power swivel. 01/02/13 - Wednesday Continue in hole to 10,650' with 2 -7/8" DP and milling assy. P/U power swivel, R/U Kelly line and dead lines. Closed hyd and broke circulation @ 2 -1/2 bpm with 500 psi, got returns after pumping 30 bbls. Washed down from 10,650' to 10,675' and lost returns. Swap to manifold and tried to circulate down DP, found plugged. Attempted to break plug by surging DP with pressure and movement without success. R/D power swivel, Kelly hose and dead man lines. R/U mud bucket. POOH with DP and milling assy. Pipe pulling wet. Repair hose on Hyd tongs. Continue POOH with DP & milling assy. to bumper jar and found same plugged solid with sand. Wash out sand plug from bumper jar, scrapper and mill. M/U milling BHA and RIH with same & 2 -7/8" DP (depth at report time = 4,500'). 01/03/13 - Thursday Continue in hole 10,675'. R/U power swivel and dead man lines. Wash and ream from 10,675' to 11,085" with 3.5 to 4 BPM 80 to 100 RPM. At each Kelly down circulated 20 mins, at each third Kelly down circulated 1 hour. Unable to circulate, also lost down hole pipe movement. Pipe stuck above jars. Working pipe with 84K over P/U weight, surging DP with 2000 psi. Regained circulation and worked pipe free and up hole to 11,070'. Circulated well with one pump at 3 bpm, swap manifold and reverse out at 2 -1/2 bpm. 01/04/13 - Friday Continue reversing out at 3 BPM 800 psi. Reverse wash and ream from 11070' to 11080' at 11080' lost all returns. P/U to 11,070' regained returns. Needed 60K over pull to work pipe free. Attempted same 3 additional times with same results. Swapped valves on manifold and washed down circulating down DP from 11,070' to 11,085'. Pipe torqued up and and needed 64K over pull to jar free. Attempted same 3 additional times with same results. POOH with milling assy. B/O and lay out milling BHA. P/U and M/U TriPoint test packer. RIH to 9,350' with 2 -7/8" DP & packer, space out and set packer with 35k wt down. Fill hole and R/U pressure test pump and lines. 01/05/13 - Saturday R/U lines to chemical injection pump and test same to 5,000 psi. Rig up Scale Inhibitor Squeeze Equipment and Mix chemical injection fluids. Pressure test lines to 2,000 psi while adjust variable relief valve. Bull head Preflush - 5 drums Baker Petrolite WAW -5206 (mutual solvent) mixed with 75 bbls FIW, 1.75 bpm @ 1650 psi. Bull head Scale Inhibitor Pill - 44 drums Baker Petrolite SCW -8225 mixed with 420 bbls FIW, 1.75 bpm building to 2.50 bpm @ 1650 psi. Bullhead 600 bbl FIW Displacement at varying rates of 1.25 - 2.75 at pressures varying from 800 -1,700 psi. R/D squeeze equipment and lines. POOH with 2 -7/8" and test packer. 01/06/13 - Sunday Continue POOH with 2 -7/8" DP and test packer. Continue POOH with 2 -7/8" DP and test packer. B/O & L/D TriPoint test packer. P/U & M/U TCP gun assy. RIH with 10 stds of 2 -7/8" DP and tongs broke down. Change out hyd tongs, hookup new hydraulic lines and continue in hole with2 -7/8" DP and TCP gun assy to 10,914'. R/U E -line unit. 01/07/13 - ,Monday Finished rigging up a -line and correlate guns on depth. R/D a -line and R/U pump lines and test same to 3,000 psi for 5 min. Pressured up on DP and fired guns with 2,000 psi, good indication on shot monitor that guns fired. Monitor well. R/U & shoot fluid level. POOH laying down 2 -7/8" DP. Break out and lay out TCP guns. 01/08/13 - Tuesday Continue laying out TCP guns. RIH with 80 stds of 2 -7/8" DP & 2 stds of 4 -3/4" DC & POOH laying out same. Rig up and pull wear bushing. Change out rams from 2 -7/8" to 3 -1/2 ". Test BOP's, 3 -1/2" rams, blind, safety valves & manifolds to 250 psi low/ 3,500 psi high and annular to 250 psi low / 2,500 psi high on chart for five min. Witness of test waived by Jim Regg, AOGCC. Start changing out brakes on draw works. • Hilcorp Alaska, LLC 0 • llileorp Alaska. LLC Weekly Operations Summary Well Name API Number IWell Permit Number Start Date End Date G -32 50- 733 - 20198 -00 169 -086 11/28/2012 1/13/2013 Daily Operations: 01/09/13 - Wednesday Continue to slip and cut drill line. R/U to run 3 -1/2" production tbg. P/U M/U 3 -1/2" Butt production tbg & RIH with same t/ 3,750'. Continue P/U M/U 3 -1/2" Butt production tbg & RIH with same t/ 9,024'. POOH w/ 3 -1/2" Butt production tbg. Stand back in derrick t/ 6,735'. 01/10/13 - Thursday Continue POOH f/ 6,735' w/ 3 -1/2" Butt production tbg. Stand back in derrick. Stage ESP assy on catwalk, spot spoolers & R/U conex. P/U ESP assembly, hang sheaves f/ cable & flat pack. Service pump, install control lines & cable termination & test ea. RIH w/ ESP assy on 3 -1/2" IBT tubing t/ 3,541', testing cable & flat pack t/ 2,500 psi every 1,000' +/ -, all good. e5( 01/11/13 - Friday RIH w/ ESP assy on 3 -1/2" IBT tubing f/ 3,541' t/ 4,982' testing cable & flat pack t/ 2,500 psi every 1000' + / -, all good. C/O cable spool & prep t/ splice. Continue RIH w/ ESP assy on 3 -1/2" IBT tubing f/ 4,982' t/ 9,260' testing cable & flat pack t/ 2,500 psi every 1000' +/ - , all good. P/U & M/U tubing hanger, CIW -DCB -ESP 11 "x 4 -1/2" IBT lift & susp, w /4" TYPE H BPV profile. M/U t/ hanger 1/2" & 3/8" control line & BIW enetrator & test all ....good. Land Hanger, up wt 125, do wt 100, run in I/d pins, pull landing 't. TWC installed. Pack p g g p P p gl hanger void & test t/ 5,000, good. Prep t/ I/d derrick & N/D BOP's. R/D ESP running equipment. 01/12/13 - Saturday Nipple down BOP'S & riser. Nipple up tree & test void to 5K. Tested OK. Turn well over to Production for final hook up. Demobilize. 01/13/13 - Sunday Demobilize. • 8 , OF O ���s A THE STATE Alaska Oil and Gas "031g' ALASKA Conservation Commission wh „ GOVERNOR SEAN PARNELL 333 West Seventh Avenue OF p. Anchorage, Alaska 99501 -3572 ALAS Main: 907.279.1 433 Fax: 907.276.7542 February 6, 2013 Mr. Chris Myers Field Superintendent Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524 -4027 APR 1 i 2013 SCANNED RE: No -Flow Verification Trading Bay Unit G -32 PTD 1690860 Dear Mr. Myers: On January 25, 2013 an Alaska Oil and Gas Conservation Commission (AOGCC) Petroleum Inspector witnessed a no -flow test of Trading Bay Unit well G -32 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 -32. The no -flow test consisted of a series of shut in periods each followed by opening the well to monitor for flow to surface. During the flow monitoring periods, there was no liquid production to surface and gas was measured at rates less than 180 standard cubic feet per hour. The subsurface safety valve must be returned to service if Trading Bay Unit G -32 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. Sincerely, James B. Regg Petroleum Inspection Supervisor cc: P. Brooks AOGCC Inspectors MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg; P. I. Supervisor FROM: John Crisp, Petroleum Inspector DATE: January 25, 2013 SUBJECT: No Flow Test Grayling Platform TBU G-32 PTD # 1690860 January 25, 2013: 1 traveled to Hilcorp's Trading Bay Unit (TBU) "Grayling" Platform to witness a blowout prevention equipment test on TBU G-03RD2 and to witness an AOGCC-required no flow test on TBU G-32. When I arrived on the Grayling Platform I witnessed well TBU G-32 rigged up with no flow equipment as required by AOGCC Guidance Bulletin 10-004, Appendix A (No Flow Test Equipment). No gas or liquid flow could be seen from the temporary hose. This was observed intermittently for 1 hour. TBU G-32 was shut in for 1 hour to observe the tubing pressure build up. Approximately 1 psi build up was witnessed during the 1 hour shut in period. When the tubing was opened to the Armor Flow methane flow meter (S/N 993632), an initial flow rate registered 180 standard cubic feet per hour (SCFH) which declined to 0 SCFH in 2 minutes. I witnessed 0 SCFH flow for 1 hour. Summary: I witnessed a successful No Flow Test performed on Grayling Platform well TBU G-32 as per AOGCC's test procedure & equipment arraignment [20 AAC 25.265(k) and AOGCC Industry Guidance Bulletin 10-004]. Attachments: none Non -Confidential 2013-0125—No-Flow TBU_G-32_jc.docx 3 . 6-3z _ • P i69o366 Regg, James B (DOA) From: Regg, James B (DOA) Sent: Wednesday, January 02, 2013 11:46 AM To: 'Ted Kramer' Cc: Jack Anderson - (C); Tim Heard - (C); Schwartz, Guy L (DOA); Brooks, Phoebe L (DOA) Subject: RE: Williams Rig 404 - Returning to Work Attachments: BOPE test results for Williams 404 06 -23 -12 - 12 -08 -12 (2).pdf We track and trend this stuff for rigs; attached is Williams 404 history thru 12/8/12. Summary: out of the 18 tests conducted (4 witnessed by AOGCC), 4 reports had no failures (the average number of failures is "2 "). There were a total of 36 failures: 3 Misc. Inspections; 2 Annular Preventer; 5 Pipe Rams; 1 Manual Choke; 1 Hydraulic Choke; 2 CH Misc; 1 Ball Type; 2 Inside BOP; 3 ACC. Misc; 4 No. Valves; 5 Kill Line Valves; 2 HCR Valves; and 5 Gas Detectors. Breakdown: Misc. Inspections — 1 out of 18 reports included this failure (quantity of 3 dealing with housekeeping type issues p p (q Y g p g Yp issues) Annular Preventer — 2 out of the 18 reports included this failure. Pipe Rams — 5 out of 18 reports included this failure. Inside BOP — 2 out of 18 reports included this failure. ACC Misc. — 3 out of 18 reports included this failure (2 reports referenced an air pump failure, the other was the N2 bottle was low). No. Valves — 3 out of 18 reports included this failure (2 reports reference valve # 7, the other valve # 5 & 6). Kill Line Valves — 2 out of 18 reports included this failure (failure quantity was 2 & 3). HCR Valves - 2 out of 18 reports included this failure (quantity of 1 each). Gas Detectors — 2 out of 18 reports included this failure (quantity of 4 and 1). CH Misc. —1 out of 18 reports included this failure (quantity of 2). The remaining categories were 1 failure each (Manual Chokes, Hydraulic Chokes, Ball Type). Jim Regg AOGCC 333 W. 7th Ave, Suite 100 SCANNED APR 1 7 2013 Anchorage, AK 99501 907 - 793 -1236 From: Ted Kramer [mailto:tkramer @hilcorp.com] Sent: Wednesday, January 02, 2013 11:23 AM To: Regg, James B (DOA); Schwartz, Guy L (DOA) Cc: Jack Anderson - (C); Tim Heard - (C) Subject: RE: Williams Rig 404 - Returning to Work Jim, Thanks for clarifying this. I wanted you and Guy to know that In order to drive towards continuous improvement I have asked our WSM to start a log of each failure incurred on the BOP test. The log will include four items: 1. Nature and Explanation of the failure (equipment related, maintenance related, etc.) 2. What was done to correct the problem. 3. How long it took to correct it. 1 4. How failure can be prevented the future. • My desire is that if we see a piece of equipment that is consistently failing, then we can change it out to correct it. If it is repeatedly due to a maintenance item, then we can correct that too. My feeling is that if we do not track the failures, then with the changing of personnel due to rotation of crews and supervision, we are doomed to repeat them. Looking at the most recent test failures (4). Two were equipment related- Gas and H2S alarms needed to have different tones. These were corrected by changing equipment. We should not see these failures again. The other two were from having valves that leaked. Corrected by greasing the valves. Both the kill line valve and the choke manifold misc. were FP so they were corrected while the inspector was there. My direction to my WSM was why can't we grease the valves before the test each week so they do not leak. Therefore the valves are maintained and the failures are eliminated. I believe this will get us heading down the right path. Any suggestions of what you have seen work with other operators to eliminate failures would be gladly received. Respectfully, Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC. 0 907 - 777 -8420 C 985 -867 -0665 From: Regg, James B (DOA) [mailto:jim.regg(aalaska.gov] Sent: Monday, December 31, 2012 11:05 AM To: Ted Kramer; Schwartz, Guy L (DOA) Cc: Jack Anderson - (C); Keith Elliott; DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (DOA) Subject: RE: Williams Rig 404 - Returning to Work The BOPE test report attached to your email shows 4 failures; if repairs were not completed and retest witnessed by AOGCC Inspector during his inspection, the report needs to reflect the # of days to make repairs. Should also add note that this BOPE test was initial following extended shutdown for winterization, otherwise there could be confusion later as to why there was more than 1 week between BOPE tests. I have highlighted the relevant sections with corrections and attached the corrected report. Hilcorp is authorized to recommence workover operations at TBU G -32 using Williams 404. ,/ Jim Regg 19 AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907 - 793 -1236 2 • • From: Ted Kramer [mailto:tkramerCthhilcorp.com] Sent: Monday, December 31, 2012 8:50 AM To: Regg, James B (DOA); Schwartz, Guy L (DOA) Cc: Jack Anderson - (C); Keith Elliott Subject: Williams Rig 404 - Returning to Work Jim and Guy, This e -mail is to follow up on our meeting of last week. The AOGCC state inspector (Lou Grimaldi) was out over the weekend conducting both an inspection of the winterization improvements and a BOP test. I believe you will find confirmation in Lou's report that the rig passed in both areas. Mr. Grimaldi also gave the rig a punch list of additional items that he wanted to see changed and asked our rig consultant to call him and let him know when this short list had been corrected. Our WSM called him yesterday after completing these items. I felt the need to write to answer a question That Jim asked me last week as to how during witnessed BOP inspections rig 404 experienced several test failures and when the test was not witnessed no failures were encountered. Hilcorp (and I) took that question very seriously and we instituted a focused effort to improve our workover crew consistency (through knowledge) of the BOP Test. This effort included not only education of how to perform the test but also incorporated why the BOP equipment is necessary. It included BOP education, practice drills, and pop quizzes. We believe this effort is paying dividends as evidenced by the attached bop testing report of a witnessed test with no failures. Hilcorp understands that this no failure test result is not the end to your question but a beginning of producing consistent testing results without failures. Hilcorp now asks that the AOGCC allow Williams Rig 404 to return to work to complete the workover of the G -32 well. Hilcorp offers the following in support of that decision: 1. Winterization efforts have been completed. a. A winterization plan adopted that is repeatable on other legs of the platform. b. Including temperature monitoring to insure freeze ups are not occurring. c. Plan to function test BOP before running in the well if our temperature monitoring indicates equipmen temperatures falling below freezing. 2. BOP Crew Training has Been Completed a. Understanding of the BOP Stack and Why it is Critical to Cook Inlet Operations b. Understanding of how the BOP test is conducted and roles and responsibilities for carrying out the test Hilcorp requests that the AOGCC let us know as soon as possible as our crew change out occurs this weekend. Allowing us to return to work today will allow us the time to plan how to best integrate the incoming crew with the new training. Delay will cause us to consider postponing bringing the next crew in. I will be on my cell today if you need to discuss anything with me. / Ted Kramer ti AS t: Senior Operations Engineer bA :ate/0.4s 4.04 ) (CI Hilcorp Alaska LLC Cell 985 - 867 -0665 3 Date Well PTD Witnessed Operalon #Failures Failure Type Operator Comments Inspector Comments Mlsc. Pipe Manual Hydr. Ball Inside ACC No. Kill OCR Gas Inspect. Annular Rams Chokes Chokes CH 'MS' Type BOP Mlse Valves ,Z es s Valves Detectors Tested Pipe rams on 41/2 and 2 7/8" test pints. They Tested Viol's on 2 7/8 & 41/2 test loons Annular prevented were in between company men and did not have a well hyd seals failed, 10 hours dung test to change prevented. First Plan onboard so 1 could not check for a hazard section. TRADING 640 test for rig in state Long test tint partially due to 10 hours spent changing annular prevented. Otherwise good test for first test in- 06/23/12 UNIT 1-05RD 1981200 Grimaldi Initial Workover 1 1 state Pipe Rams failed, remove and replace wdh new 2 7/8" pipe TRADING BAY rams, annular failed, cleaned BOP stack annular passed 07/01/12 UNIT G -05RD 1981200 Waived Weekly Workover 2 1 1 TRADING BAY Test was successful with one Fail Pass on the pump 07/10/12 UNIT G -05RD 1981200 Waived Weekly Workover 1 1 side HCR. During the test we had some problems with the manual valves on the MII lisle side, they are now working and testing correctly, however we plan to replace them prior to next schedule ROPE TRADING BAY test. In addition, one of the Inside Mop was leaking and will 07/31/12 UNIT G -29RD 1920520 Waived Initial Workover 3 1 2 also be replaced as well. • Nydrau30 super Choke leaked initially to atmosphere. Valve 6.600 choke was cloud & 3000 psi was placed on body of super choke & then cycled open • close -open 6 leak to atmosphere could not be seen again. Sager coke panel had no using or DP pressure gauges mnrtooral. DM vane failed mst & was changed out & tested OK I witnessed 4 POW's tested wt, one failure. Power swivel was not picked up & no BOP valves were amched swiv0 Manual choke on choke manifold could not be cycled due. FP's: 805V, Dart Valve, hydraulic super choke, super choke saner., tat bound up against choke house, actuator was panel, manual choke, power swivel, & OCR choke valve In r dal choke was tested m Npkeflow OK Iko choke addition I ordered new systems to reach compliance for the ^ice ^'f°id vales vane ulkda led heraue Mega kzied OKaher Super choke which included two MD Totco pressure transducer flush wrthrkan watw opera.. & OOrOwtor Rep'a syspered with high pressure connections for test gauges. One will deiriR hangingwoway check m beuusmgour leak;theslad Meta ap monttor the casing pressure while the second mondors doll msl pad, B onIYA ma ni(0 was tested & 8,e katr ttmop, word wali ld . s pipe pressure. One sensor was replaced for the gas detectors atmosphere was iv abaeea, apk otter cycling g 6 & noskeg ngsupup w and all are functioning properly at this time choke the leak could nor be seen again mallow or high test prs6sure 3 valves & one deck tested lac kill line Integra, Idol not rec.. all valves in Operators DM manifold De tested for compliance s Confusion over what on ale M AWCC B equipment actually installed for thins WO After talkingw.. my Supervisor Pm Reggd was requested the Operator submit equipment Int than being 1034 for tin WO. KR choke was cycled & flushed before d would hold test presswe.Test tome on this report is a ender. of the time ks3Mnr spent to perform dys witnessed test TRADING BAY 08/08/12 UNIT G -2960 1920520 Crisp Weekly Workover 7 1 1 2 1 1 1 TRADING BAY 08/14 /12 UNIT G -29RD 1920520 Waived Weekly Workover 0 TRADING BAY 08/21/12 UNIT 1-29RD 1920520 Waived Weekly Workover 0 2 -7/8" dual stnng ram installed above annular, VBR fad, replaced w/ 2 -7/8" ram - Pass; Blind ram tested 8/27; methane • TRADING BAY 8112s alarms failed shortly after testing - repairs 6/30, rig floor 08/29/12 UNIT G -01RD 1911390 Waived 109101 Workover 5 1 A reconfigured; new test pump, replaced accumulator Kill line valves failed /passed, replacements are being redressed TRADING BAY and ,all be changed on 9 /14/2012 3 manual valves faded 09/07/12 UNIT G -01RD 1911390 Waived Weekly Workover 3 3 passed Leak in crossover above the TIW yalve,(repaired) leak in pressure hose connection (repaired) Needle valve leak on pressure test pump, (replaced) Manual valve (K -1 valve) leaked, cleaned, grease and tested good (Actual time to test TRADING BAY 5hrs 30 minutes, test 5 hrs 30 minutes, test plus weather hold 09/15/12 UNIT G -01RD 1911390 Waived Weekly Workover 1 1 total 11 Marc Testing began at 22:00 PM 9/24/12 Completed 0700 AM 9/25/12 Pipe Ram failure above 2000Psh remove, Inspect, (no TRADING BAY damage( replaced, did not test, New rams flown to life, 09/25/12 UNIT G -03RD 1911390 Waived Weekly Workover 1 1 installed tested good Difficult test due to ram blowing on equipment Tarped Air pump non operable parts enroll.. Valve rm 7 test function and tested OK. Inside superchoke valve leaked cycled, cycle and grease valve test OK Accumulator needs new Breasetl and retested OK. Air pump 1808 due to broken pressure sensor for ACC auto start. Not failed but worn an dryer. Parts on order, rig has 2 days for repast. Rig TRADING BAY should be monitored for freezing conditions as there is 10/02/12 UNIT G -0160 1911390 Grimaldi Weekly Workover 2 1 1 not anywintenzation Date Well PTD Witnessed? Opera00n 73 Failures Fai!we Type Operator Comments Inspector Comments Mist AnnWar Ape Manual Hydr• CH Misc Bap Inside ACC No Imle HCR Gas Inspect. Reins Chokes Chokes Type BOP Mist Valves Valves Valves Detectors Choke manifold Valve no 7 test function cycle and grease valve test OK low but not high will change ASAP. Changed TRADING BAY valve 0 1 in Choke manifold tested 200 -3000 psi All good Chart 10/10/12 UNIT G -03RD 1911390 Waived Weekly Workover 1 1 recorder certified this date Total safety gas felt complete. Rig broke Down test done in sections Test Choke manifold and Choke line and accumulator from 1500- 1700 Valve 4 5 & 0 6 choke manifold greased and cycled ak Heater wired up in choke house today. Note we have 3 spare full Nitrogen bottles as well not in the system. AM pump on accumulator not working properly will be replaced asap. Close time on Annular was 70 second Close time on Pipe and Blind rams was 10 TRADING BAY seconds Final Test was from 0930 -1230 on 10/18 10/18/12 UNIT G -03RD 1911390 Waived Weekly Workover 3 1 2 Test began on 10 -25-12 at 21:30 PM, Pump Failure, No pumps available to perform test, repairs made, retest 1300 hours 10- TRADING BAY 26-12. No failures on BOPE test. ROPE test completed on 10- 10 /26 /12 UNIT 0 -01RD 1911390 Waived Weekly Workover 0 26- 120318.30 Hoiirs • Flange below Single BOP w/ Dual Rams failed to test NO BOP Platform fihhy /cluttered, equipment poorly bid out and change nng gasket repaired and tested 11/11 Bottom of l a GeneraVNOUSekeepirigl. Rig /Bthy aed Riser leaked on top of wellhead tightened and test OK. House haxerd001 (rid Rig) One lout of 3) N1 bottle bled off to keeping Issues were being res0vled by new news antl WSM 500 psi bnnging average to. down too for operation. Lower Flange on spool below dual rams leaked and was NItrogenl lose bottle will be changed asap Close time Annular 41 sec. Close time Pipe rams ]sec. Accumulator remote lights not tightened al all pnor to test (poor handover between are faulty Lights replaced with LED Housekeeping enure deck c rews and company rep's). All in all poor performance in a daunung situation. Oilcorp should be better prepared of TRADING BAY washed down hoses organized on going progress. 11/10/12 UNIT G -10 1680800 Grimaldi Weekly Workover 5 3 1 1 they want to operate in Cook Inlet. Test will be done again with 2 -7/8' pipe rams and Door va0es TRADING BAY as soon as production tbg is recnvered.Innal test of 0 -1/2" pipe 12/01 /12 UNIT 6-32 1690860 Waived Initial Workover 1 1 rams tailed, replaced rams and test was successful TRADING BAY 12/08/12 UNIT G -32 1690860 Waived Weekly Workover 0 Totals: 36 3 2 5 1 1 2 1 2 3 4 5 2 5 • c • w \� O � j, / s9 THE STATE Alaska Oil and Gas F � '+ a ' � • °fA LASKA Conservation Commission GOVERNOR SEAN PARNELL 333 West Seventh Avenue (4'ALASY'P' Anchorage, Alaska 99501 -3572 Main: 907.279.1 433 Fax: 907.276.7542 Michael Dunn Senior Reservoir Engineer Hilcorp Alaska, LLC b>iE l A 1 3800 Centerpoint Drive, Suite 100 ©S,p Anchorage, AK 99503 t Re: McArthur River Field, Middle Kenai G & West Foreland Oil Pool, Trading Bay Unit G -32 Sundry Number: 312 -359 Dear Mr. Dunn: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy P Foerster Chair DATED this day of October, 2012. Encl. • TqRECEIV STATE OF ALASKA I � � SEF 1 9 2012 ALASKA OIL AND GAS CONSERVATION COMMISSION ���� APPLICATION FOR SUNDRY APPROVALS 20 MC 25.280 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pod ❑ Repair Well ❑ Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate IS • Pull Tubing El • Time Extension ❑ Operations Shutdown ❑ Re-enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other: Complete 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number. Hilcorp Alaska, LLC Development El Exploratory ❑ 169-086 3. Address: 3800 Centerpoint Drive, Suite 100 Stratigraphic ❑ Service ❑ 6. API Number. Anchorage, AK 99503 50- 733 - 20196-00 - 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number property line where ownership or landownership ctanges: Spacing Exception Required? Yes ❑ No El Trading Bay Unit / G-32 ' 9. Property Designation (Lease Number): 10. Field /Pool(s): ADL0018730 ' McArthur River Field / Middle Kenai G Oil and West Foreland Oil Pools 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): 11,570 , 11,417 ' 10,405 9,509 N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 497' 17 -3/4" 497' 497' 1 Surface 4,810' 13 -3/8" 4,810' 4,680' 3,090 psi 1,540 psi Intermediate Production 10,510' 9 -5/8" 10,510' 9,595' 6,330 psi 3,810 psi Liner 847' 7" 11,255' 10,194' 8,160 psi 7,020 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schematic See Schematic 4 -1/2" 12.6# / L -80 9,371' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 9 -5/8" Otis BWH Perm Packer / 7" Otis BWH Perm Packer and Otis SSSV 9,275' (MD) 8,555' (TVD) / 10,245' (MD) 9,379' (ND) and 304' (MD) 304' (ND) 12. Attachments: Description Summary of Proposal 12 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch El Exploratory ❑ Development El ' Service ❑ 14. Estimated Date for 15. Well Status after proposed work: 10/5/2012 Commencing Operations: Oil G • Gas ❑ WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: N/A GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Michael Dunn Printed Name icha unn Title Sr. Reservior Engineer Signature ,l `� un Phone (907) 777-8382 Date 9/18/2012 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: . 5 + 2 - 3 5ci Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance ❑ Other: 3 30 A -i "S i ±U 35 U Pc l Subsequent Form Required: 1 0 — ii. 0 ii APPROVED BY Approved by: (LW/177 `-1 1. r)).-t.4,7(1 ,_,�__ COMMISSIONER HE COMMISSION Date: l(,) " 5 - Z r ile D MS UL I U U 1U1 znz O � ll� RIG Form 10 -403 Revised 1/2010 / Submit in Duplicate • Well Work Prognosis Well: G -32 }Warp Alaska, !LC Application Date: 9/18/2012 Well Name: G -32 API Number: 50- 733 - 20198 -00 Current Status: Oil Producer Leg: Leg #2 (NE corner) Estimated Start Date: October 5, 2012 Rig: Williams Rig 404 Reg. Approval Req'd? 10 -403 Date 10-403 submitted: September 18, 2012 Regulatory Contact: Tom Fouts 777 -8398 Permit to Drill Number: 169 -086 First Call Engineer: Mike Dunn (907) 777 -8382 (Office) (907) 351 -4191 (M) Second Call Engineer: Ted Kramer (907) 777 -8420 (0) (985) 867 -0665 (M) AFE Number: 1222891 Budgeted Cost: Well Status, Pressures: The well is an active producer on gas lift. When lift gas is turned off, the well stops flowing. Recent scale squeezes show the well to go on vacuum when scale inhibitor is pumped. The estimated bottom hole pressures shown below are based on the most recent gas lift survey (June 2010) showing a BH flowing pressure of 1849 psi, and an estimated reservoir pressure of 3200 psi. Since then, water injection has been restarted at a nearby injector (G -05), so reservoir pressure is expected to have increased slightly. Reservoir and surface pressures are estimated as follows: Current BHP: "' 3,500 psi @ 9407' TVD /10280' MD .37 psi /ft., (7.1 ppg) at mid -perf of G &WF Max. Exp'd BHP: ^' 3,500 psi @ 9407' ND .37 psi /ft. (Same zone to be re- perforated) Max. Possible SP: 2560 psi Using 0.10 psi /ft back to surface Brief Well Summary G -32 is a West Foreland and G -zone producer located near the northern end of the mid -field ridgeline. The well is currently making approximately 3200 bfpd at 93% water cut for approximately 200 bopd oil production. This well is supported to the west by the recently repaired G -05 injector which is injecting approximately 7200 bfpd into re- perforated G -zone and Hemlock zones. With new perforations and an ESP this well has the potential to make between 5000 and 7000 bfpd at an average water cut of 91% to 94 %. Procedure Summary: 1. Note: WR SSSV was pulled on 7/22/03 and never re- placed. This well has passed a no -flow test. 2. At least 1 day prior to rig move, stop lift gas to well and bleed as necessary to allow well to kill itself with produced fluid. Shoot fluid level at least twice to get an estimate of bottomhole pressure. 3. At least and close to 24 hours prior to BOP test, notify AOGCC of upcoming test. 4. Release rig from previous well (G -14). LD mast. Skid rig due west over the G -32 well slot. 5. RU E -line. Cut tubing just below the sliding sleeve and approximately 18' above the locator sub (i.e. in the middle of the 36.47' joint between sub and sleeve). WLOH. 6. Circulate FIW down annulus and up tubing to kill well and displace all oil and gas from well. Allow well to stabilize. Shoot fluid level. 7. Set BPV in profile. If it will not seat, shoot fluid again to confirm well is static. As described in Attachment 1 (BOP Test Procedure and Drawings), if the fluid level is below the surface, the well is static and dead, remove tree, clean out profile by hand, attempt to set 2 -way check, and set BOP and NU same. Test BOPE either on top of 2 -way check (per standard test procedure) or with a rolling test while well is taking fluid (per Attachment 1). • • Well Work Prognosis Well: G -32 Hilcarp Alaska, Li.0 Application Date: 9/18/2012 8. Prepare to pull completion. 9. MU to lifting threads and pull hanger and tubing. CBU. If a rolling test was done to test BOP, LD one joint of tubing, MU test plug to top of tubing string (or new hanger with 2 -way check), land in tubing head, and conduct a full BOPE test per standard procedure. 10. From the cut above the seal assembly, pull the completion tubing. LD tubing, check for NORM. 11. RIH with overshot and pack -off assembly and latch onto stub. Pressure up on backside to 1400 nsi for 30 minutes and chart same to confirm that casing integrity is intact. 12. Pull the seal assembly and fish the upper packer and lower packer per detailed fishing procedure. Lower packer is expected to have fill on top. 13. Clean out well to PBD, which is reported to be junk (including original perf guns and a 5 -7/8" rotary shoe) and fill on top of the liner landing collar. The top of junk was tagged at 11,168' using original RKB DPM. Landing collar is at ETD of 11,208'. 14. MU Schlumberger TCP guns on workstring and RIH. RIH with E -line or memory GR tool on slickline. Position guns to perforate as follows, using the Hilcorp Digital Database Log (DDL) as the reference log. Proposed Perforations: Tie -In Log Depths (Shoot These) Bench Top MD Btm. MD Feet GZN 1 9,420 9,444' 24 GZN 2 9,466' 9,493' 27 GZN 2 9,504' 9,516' 12 GZN 3 9,542' 9,590' 48 GZN 4 9,612' 9,622' 10 GZN 4 9,630' 9,654' 24 GZN 5 9,697' 9,774' _ 77 WF 2 10,538' 10,573' 35 WF 3 10,649' 10,656' 0,656 7 WF 3 10,668' 10,686' 18 WF 4 10,848' 10,870' 22 15. When the guns detonate, the reduction of skin damage could cause the well to drink fluid until the fluid level finds the balance point between reservoir pressure and the column of fluid in the well. There is no need to circulate the hole, following the perforation event. After detonation, monitor well by shooting a fluid level. It is OK to fill the hole twice or thrice to verify the well is static, but there is no reason to continue to fill the hole while it is taking fluid. Do not pump polymer and /or salt to slow the fluid Toss. Once the well is determined to be static, POOH with guns. LD same. Confirm that all charges fired. 16. Run ESP and 3 -1/2" tubing. Place bottom of pump within 100' of the top G -zone perf at approximately 9300' MD (8576' TVD). Run SSSV nipple at 300'. Land hanger and secure all penetrations. 17. Set BPV. ND BOP, install new tree. Turn well over to Production for final hookup of ESP. Place well on production. 18. Well is expected to make between 5000 and 7000 bfpd at 90% — 94% water cut at 1000 psi BHFP. 19. Gradually bring ESP up to full speed. Place well on test. Test for several days to measure cut and rate. • • W ell Work Prognosis Weli: G -32 tlilenrp.Alaeka . u,€ Application Date: 9/18/2012 As -built (Old) Wellbore Schematic Oman al RKB = -i C Nr 7•A n ' 17 -i .. '.anduct. - Surf. :- ® .�r• - - - -- - 1 Q i3 -3�8 510 1 -55 _ _ Turf. 7 9 ;'? 47 & S-95 j. Surf. :._- 1' - 3rd 4350 N8. 290 N-80 = - -- iQy7 -- ` -- I 3 Tubing: 4112' 12.50 1. " 5; Near 3.358' Surf =_ _ 1 - JEWELRY 6 ',0 Dept" It 7 1. 304' Otis 555V Nipple w /flapper 2. 2242' PTADSOGLM #1 1 8 13 -318 3. 3711' PTA DSO GLM #2 9 4. 5109' PTADSOGLM #3 i 10 5. 5175' PTADSOGLM #4 6. 7052' PTA DSO GLM. #5 11 7. 7733' PTADSOGLM #6 ® 8. 8384' PTA D50 G LM #7 1= 9. 877$' PTA DSO GLM #8 14 10. 9220' PTA DSO GLM #9 11. 9238' 1.513" Otis XASlidin8Sleeve 12. 9275' D 9 -5/8' Otis BWH Perm 15 13. 9278' 5'OD seal eau w/ slot locetorl4- 1 /2 Butt Box by ain IMMO down) 14. 9329' 3.813" OtisX nipple 15. 9370' Wi re l ine re -entry guide 1 ' L ? i +•'s' 11= 16. 10.425' DIL Otis7" BHW Perm 4.11 17. 10,435'DIL 2.635" Otis 3- 1 /2 ' XNnipple 9-5 8 18. 10,436' OIL Wireline re-entry guide Perforation Detail ® Zane -:: TnpITVD) BTMIT C :: - , .menu 16 335. 5,532 9,537 1e4 „ 9,385 _._.: 8,551 8,554 Sali 1 ' u -1 9,320 _ . __ 8 8.1 7. open 6 -1 9,435 = - -- 8,593 8,701 Open ;Dr- ieptes14- 22-75 6-2 9,455 - - -_ 8,719 9,740 Open lS 6 -2 3,504 , ._; 8,752 9,753 C :_ 6 -3 9,542 3355 9.795 892= :_ _- 6-4 9,507 '3.523 9,940 9954 a, el 6-4 9,530 9,553 8 9,579 Open 6.4 9:532 9.552 5.551 5.875 Open DiL5ept6s15 -2 - :t 6 -5 9,597 9,774 5.317 9,992 Open 6 -5 9,711 4.719 3923 9,935 Opec;DLDe :tns13.2 -:5 , WF-2 10,535' 10,571' : ;_: 3,545 Open WF-2 10.599' 10.501' ? '_33 9,553 Open WF 10,510' 10522' _ 5 9,555 Open WF-3 10,548' 10:555' E -. 9,.713 Open ID = 11.570' wF -3 10.558' 10.594 _ " 23 9,735 Open Max hole any leis34,S" g 4:500' WF-3 10,695' 10,597' 3 745 9,747 Open WF-3 10,703" 10 3. 3771 Open WF-3 10,739' 10. 3.780 9,817 2Fer w'F 10 A 25' 10:353' 3.95: 3.351 ..,. _ ., WF-6 10.994' 11,045' 9,355 10,027 pen WF-7 11,094' 11,150' 10,05E 10,111 Dpen I . 0 Well Work Prognosis Well: G -32 HileurpAlaska,LlC Application Date: 9/18/2012 Proposed (New) Wellbore Schematic 011a lit a1 RKB = 42.50 CASING AND TUBING DETAIL i MIMI" SIZE GRADE CONN ID MD TOP MD UM I II, 17 - 3/4 7 .312 U2 Dorduct. Surf. 497` 4 1 5 -3. +5` 61F _55 12.515" Surf. .510' .9-5.6, 471 43 5-95 & 6.535' Surf. 10510' b N-50 ) i_ S 7 294. N 6.154' 10,498' 11,255' Tubing: 3 -1 9.31r 1 -50 IDS TC-II 2.955' _ Surf -- _.. Jewelry Detail No. Depth ID Item 1 ±304 Nipple for WR SSSV 2 2.313" 3-1/2 Otis S titling S Iee'v? 2.725' XN Nipple - No ID ESP Top Assembly No ID Pump Intake _ ±4,3'10'' No ID Bott e, !bull nose; 7 4 Proposed Perforation Detail :one TopIMD) BTMIMD} TopIND) BTMITVDj Feet Comments G-1 ±9420 '..9,444 :5. 55' ±3,701' 24 5 sof 6 0-2 ±9.466' ±9,493 --_ :3.743 27 5 =^t 0-2 09,504 ±9.51' .' __ 12 _ am 0-5 ±9,5 29.58: :5. __ .1: 45 .: vf 0-4 29.612 :_ :_: : - _ -- ._ 10 5 ,0 .r 2 ±9: a3 7 :3._5-. :5.351 3.5K 24 540 TOL 8 16406' 0 -5 :: i. y.77-' 1'8,91? 15,952' 77 5 agf Z , NF -2 _ :1.0,579 ±9.615 :2.546 35 54pf 9 -c 3 bVF -3 :_:.349 ±10,135 :2,715 :9.714 7 5 a ViF -3 010,663 ±10.53`_ ±5, :9,735' 1B 5 5pf 4F-4 ±10.13488' ±1o.6': ±9.553 -: _ 7.5 22 5 :of L 7" TD =11 .256' Max hole anele is 34.B° &. 4.300' • Well Work Prognosis Well: G -32 Application Date: 9/18/2012 Hilcorp Alaska, LLf. Williams Workover Rig - • Grayling Platform BOP 2012 III III IMM IiI Width 4.16' 3.74' Weight 13,1008 Iii Iii III Iii iii • , Sh Total BOP height above II 13 — drill deck 135/85M LWS _. - - -.. dimensions — — — 9.48' min Length 7.73' '. 3 11.48' max Width across body 2.72' _ Width across flanged - -- outlets 4.00' = 7 = — Weight 9500lbs - _ — .•■••1*•• • 9.00' • r r ^ ; III 1 1 1 1 1 1 III III ; r t11 i Mud Cross 1 28501bs w/ valves i t 14 Mc: 1 � M � l i ®1 1.74' 1 `�♦_ . Iii III III III III r 1 ��� • Riser above drill deck 11 I I I I This number will vary from well to well 1.00' to 3.00' Drill Deck 13 5/8 5M Riser 85001bs 15.00' 1 } 111 1111 III Spacer Spool 135/85M X 135/85M I 195' 18001bs 11J .11 (11 ' Crossover Spool 4' 135/85M X 11 5M 1800Ibs 2 ( Rill 8 I> Top of Wellhead • Well Work Prognosis Well: G -32 Nilcorp Alaska, LLC Application Date: 9/18/2012 Diagram A -1: Grayling BOP stack and Riser Arrangement — Typical for Single Completion Williams Workover Rig Grayling Platform BOP 2012 nifttninlirtittlA Weatherford Rental BOP Width 4.16' I 3 74 Shaffer 13 5/8 5M • r itt;rttlrftlrft ift) Shaffer LW8 135 /86MLWS _ 135185M dimensions © Length 7.73' 3.00' Width across body 2.72' Width across flanged outlets 4.00' • s �, a*, III I I / I M h� M j M� 1.74' J 1�r .1 111 III 1 lil lit K -3 K -2 K -1 C -1 C -2 `NCR' • Mud Cross Riser above drill deck This number will vary from well to well 100' to 3 00' Drill Deck 13 6/8 6M Riser 860016s 13 5/8 5M X 15.017 3 1/8 5M EFO III III II Spacer Spool 136/86M X 135/85M 1.95' 18001bs ] 1111 III 11I Crossover Spool 136/86MX 115M 18001bs 2.83' III_ III V Top of Wellhead 40 • • . H Well Work Prognosis Well: G -32 Hilcarp Alaska, LLC Application Date: 9/18/2012 Diagram A -2: Grayling BOP stack and Riser Arrangement — Typical for Dual Completion Williams Workover Rig Grayling Platform BOP 2012 Shaffer SL 135/8 SM _ 1.44' • It MURTIRTFrit 13 5/8 5M > ;� �S}pacerrssp�o{oll 2.00' 111II11Li1- L[ll -IIYl_ l{ • • O 0 /l III III Ill III III III I . Weatherford Rabbi BOP / I Width 4.18' 374' Shaffer 13 6/S 6M III 111 ill I I - 8halTer LW8 _ 136 /86M LWS — - 13 SM r t, _ Length 7. 7 ' © ' i Y p../ Length ions _ I — 3.00 Width across body 2.77 _ Width across flanged outlets 4.00' )1211 • NEM n �L 1I1 °' II l C� � iJr y r± r ► [ I" I 1 I I `7 IQ 1. 74 g. r . `1 -. Y' V . lil lil �j K -3 K -2 K -1 C -1 C- 2'HCR" s Mud Cross Riser above drill deck This number will vary from well to well 100' to 300 I 4 Drill Deck 13 6/8 6M Riser 86001bs 135/85MX 3 1/8 5M EFO .41111.44,0000 15.00' L Itt III Ill Spacer Spool 135/8 X135/85M 1.95' 18001bs III III • III III Crossover Spool 138/8 X11 5M 18001bs 2.83' III II Top of Wellhead Diagram B: Grayling Choke Manifold • • . /4 Well Work Prognosis Well: G -32 Hilcorp Alaska, LLC Application Date: 9/18/2012 To Gas Buster All National type To Panic line 2 1/16 5M 1502 Union ball valves _ t q 1 / C . • I3. \ MIKI cm'3 .- " " Chokes are 90 degrees off 1 r I in drawing in order to show detail IN Ii E, n : ;,. i; :1 1 iv I� m� �� 1 , , , .. Swaco - ,, illi \ III MI 6 I I 11101 8 ill 1 ilidia 1 I 'ill 1 1 1111 II, , , 11 �' �i ' lioll From Bop Choke Line 2 1/16 5M Unibolt Flange Valve Type #1 National Ball Valve B3260, 3' /4" Ball port, 6000psi working pressure #2 National Ball Valve B3260, 3 1 /4" Ball port, 6000psi working pressure #3 National Ball Valve B2650, 2 9/16" Ball port, 5000psi working pressure #4 National Ball Valve B2650, 2 9/16" Ball port, 5000psi working pressure #5 National Ball Valve B2650, 2 9/16" Ball port, 5000psi working pressure #6 National Ball Valve B2650, 2 9/16" Ball port, 5000psi working pressure #7 National Ball Valve B2650, 2 9/16" Ball port, 5000psi working pressure #8 National Ball Valve B2650, 2 9/16" Ball port, 5000psi working pressure #9 National Ball Valve B3260, 3'/4" Ball port, 6000psi working pressure #10 National Ball Valve B1560, 1 '/2" Ball port, 6000psi working pressure • Hilcorp Alaska LLC. BOP Test Procedure: Williams Rig 404, Grayling 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. 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 October 2, 2012 1 i • c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for Teaks to ensure that the fluid is going downhole 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 this BOP ram and Annular tests are complete, 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 Tubinghead) 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, 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) Referencing the attached schematics test rams and valves as follows. a) Close C -1 (inside gate valve on choke side of mud cross) and close the annular preventer. Pressure test to 200 psi for 5 minutes and 1500 psi high for 5 minutes. If passes after 5 minutes on each, bleed off back to tank and open annular. b) Close Pipe Rams. Test to 200 psi for 5 minutes and 3000 psi high for 5 minutes. If passes after 5 minutes on each, bleed off back to tank and open pipe rams. October 2, 2012 2 0 • 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 200 psi for 5 minutes and 3000 psi for 5 minutes. If passes after 5 minutes on each, bleed off back to tank and open rams. d) Open C -1. Flow through the choke manifold and purge air. Test the choke manifold starting with the outer most valves, to 250 psi low and 3000 psi high, for 5 minutes each, as follows: (Valve numbers are in reference to Diagram B) i) Valves 1, 2, 10. After test, open same. ii) Valves, 3, 4, 9. After test, open valves 3 & 4. Leave 9 closed. iii) Valves 5, 6, 9. After test, open valves 5 & 6, leave 9 closed. iv) Valves, 7, 8, 9. After test, open all valves. e) Close C -2. This is the HCR (the hydraulic controlled remote) valve just outside C -1 on choke side of mud cross. Test to 250 psi low and 3000 psi high. After test, open HCR, close C -1. f) Blind Rams. Make sure test joint is above the blind rams. Close blind rams. Test to 200 psi Low for 5 minutes and 3000 psi High for 5 minutes. Bleed down pressure. g) Bleed off all pressure. Line up pumps to pump down tubing. h) Test K -1, K -2, and K -3 on the kill (pump -in) side by pressuring up on tubing. Test to 200 psi Low for 5 minutes and 3000 psi High for 5 minutes. i) Test floor valves TIW (or Lower Kelly Valve) and IBOP. 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 +/- 3000 psi. 3) Close Annular Preventer, the Pipe Rams, and HCR. Close 2 " set of pipe rams if installed (eg 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 2150 psi "). 6) After accumulator has stabilized, record accumulator pressure again. This represents the pressure and volume remaining after all preventers were closed. (The stabilized pressure must be at least 200 psi above the pre- charge pressure of 1000 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 October 2, 2012 3 • • original pressure ( +/- 3000 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. October 2, 2012 4 • Well Work Prognosis Well: G -32 Hilearp Alaska, LLC Application Date: 9/18/2012 Well Name: G -32 API Number: 50- 733 - 20198 -00 Current Status: Oil Producer Leg: Leg #2 (NE corner) Estimated Start Date: October 5, 2012 Rig: Williams Rig 404 Reg. Approval Req'd? 10 -403 Date 10-403 submitted: September 18, 2012 Regulatory Contact: Tom Fouts 777 -8398 Permit to Drill Number: 169 -086 First CaII Engineer: Mike Dunn (907) 777 -8382 (Office) (907) 351 -4191 (M) Second Call Engineer: Ted Kramer (907) 777 -8420 (0) (985) 867 -0665 (M) AFE Number: 1222891 Budgeted Cost: Well Status, Pressures: The well is an active producer on gas lift. When lift gas is turned off, the well stops flowing. Recent scale squeezes show the well to go on vacuum when scale inhibitor is pumped. The estimated bottom hole pressures shown below are based on the most recent gas lift survey (June 2010) showing a BH flowing pressure of 1849 psi, and an estimated reservoir pressure of 3200 psi. Since then, water injection has been restarted at a nearby injector (G -05), so reservoir pressure is expected to have increased slightly. Reservoir and surface pressures are estimated as follows: Current BHP: ^ 3,500 psi @ 9407' ND /10280' MD .37 psi /ft., (7.1 ppg) at mid -pert of G &WF Max. Exp'd BHP: ^ 3,500 psi @ 9407' ND .37 psi /ft. (Same zone to be re- perforated) Max. Possible SP: 2560 psi Using 0.10 psi /ft back to surface Brief Well Summary G -32 is a West Foreland and G -zone producer located near the northern end - of -the, mid -field ridgeline. The well is currently making approximately 3200 bfpd at 93% water cut for approximately 200 bopd oil production. This well is supported to the west by the recently repaired G -05 injector which is injecting approximately 7200 bfpd into re- perforated G -zone and Hemlock zones. With new perforations and an ESP this well has the potential to make between 5000 and 7000 bfpd at an average water cut of 91% to 94 %. Procedure Summary: 1. Note: WR SSSV was pulled on 7/22/03 and never re- placed. This well has passed a no -flow test. 2. At least 1 day prior to rig move, stop lift gas to well and bleed as necessary to allow well to kill itself with produced fluid. Shoot fluid level at least twice to get an estimate of bottomhole pressure. 3. At least and close to 24 hours prior to BOP test, is2ILAS2GCS of upcoming test. 4. Release rig from previous well (G -14). LD mast. Skid rig due west over the G -32 well slot. 5. RU E -line. Cut tubing just below the sliding sleeve and approximately 18' above the locator sub (i.e. in the middle of the 36.47' joint between sub and sleeve). WLOH. 6. Circulate FIW down annulus and up tubing to kill well and displace all oil and gas from well. Allow well to stabilize. Shoot fluid level. 7. Set BPV in profile. If it will not seat, shoot fluid again to confirm well is static. As described in Attachment 1 (BOP Test Procedure and Drawings) if the fluid level is below the surface, the well is static and dead, remove tree, clean out profile by hand, attempt to Set eheck, and set BOP and NU same. Test BOPE either on top of 2 -way check (per standard test procedure) or with a rolling test while well is taking fluid (per Attachment 1). • • . • /4 Well Work Prognosis Well: G -32 Hilcorp Alaska, LLC Application Date: 9/18/2012 8. Prepare to pull completion. 9. MU to lifting threads and pull hanger and tubing. CBU. If a rolling test was done to test BOP, LD one joint of tubing, MU test plug to top of tubing string (or new hanger with 2 -way check), land in tubing head, and conduct a full BOPE test per standard procedure. 10. Pull and fish the gas lift completion, upper packer, and lower packer per detailed fishing procedure. Lower packer is expected to have fill on top. 11. Clean out well to PBD, which is reported to be junk (including original perf guns and a 5 -7/8" rotary shoe) and fill on top of the liner landing collar. The top of junk was tagged at 11,168' using original RKB DPM. Landing collar is at ETD of 11,208'. 12. MU Schlumberger TCP guns on workstring and RIH. RIH with E -line or memory GR tool on slickline. Position guns to perforate as follows, using the Hilcorp Digital Database Log (DDL) as the reference log. 13. Proposed Perforations: Tie -In Log Depths (Shoot These) Bench Top MD Btm. MD Feet GZN 1 9,420 9,444' 24 GZN2 ................ 466' ............. ............................_ 493' .... ............................... 27 GZN ............................._ 9,504' 9, 516' ...................... .............._ GZN3 ..... ......................... ... ............................_ 590 ' .............................. 48 GZN 4 9 . , 612 ' ........................ 9 , 622 ' ........ ............................_ .................. GZN4 9, 630' ............... ............................_ 6 54 ' ........ ............................. ...... GZN 5 9,697' 9,774' 77 WF2 .. ..........................._ 538 ' ......... ..........................._ 573 _..........................._ . . . . . . . . . . . . . . . . . WF 3 ........ .............. 10 , 656 ' ................ ............... WF 3 10,668' .............. ......... 18 .......... WF4 10, 848' .......... ..........................._ 870 ' ............... ................._ . . . . . . . . . . . . 14. When the guns detonate, the reduction of skin damage could cause the well to drink fluid until the fluid level finds the balance point between reservoir pressure and the column of fluid in the well. There is no need to circulate the hole, following the perforation event. After detonation, monitor well by shooting a fluid level. It is OK to fill the hole twice or thrice to verify the well is static, but there is no reason to continue to fill the hole while it is taking fluid. Do not pump polymer and /or salt to slow the fluid Toss. Once the well is determined to be static, POOH with guns. LD same. Confirm that all charges fired. 15. Run ESP and 3 -1/2" tubing. Place bottom of pump within 100' of the top G -zone perf at approximately 9300' MD (8576' TVD). Run SSSV nipple at 300'. Land hanger and secure all penetrations. 16. Set BPV. ND BOP, install new tree. Turn well over to Production for final hookup of ESP. Place well on production. 17. Well is expected to make between 5000 and 7000 bfpd at 90% — 94% water cut at 1000 psi BHFP. 18. Gradually bring ESP up to full speed. Place well on test. Test for several days to measure cut and rate. • • . in Well Work Prognosis Well: G -32 Hilcorp Alaska, LLC Application Date: 9/18/2012 As -built (Old) Wellbore Schematic Original RKB = 42,80' CASING AND TUBING DETAIL SQE .. 3t1DE COrtr. v pop TOP MO BTM. - 17 -3/4" .312 Conduct. Surf. 497' wall 104 1 13 -3/8' 618 1-55 12515' Surf. 4,310 17 9 -5/8' 47 & 5-95 & 9335' Surf . 10,510 4358 N -80 7 29 8 N -80 5.184` 10,408' 11 255 Tubing a 4 4 1268 1 - 80 TD5 Spec Clear 3 953 5.; 4 JEWELRY 6 Depth IC Item �i 304' Otis SSW Nipple wjRapper I 2. 2242' PTADSOGLM41 s 13 -3/8 3. 3711' PTAD5O 9 4 5100' PTA D5O G LM #3 10 5. 6175' PTA DSO GLM #4 � c 5 7052' PTA DSOGLM #5 1. ]. A v b‘ . 7733' PTADSOGLM #6 V 8. 8384' PT.A DSO GLM #7 ® 12 9. 8778' PTA 14 10. 9220' PTA DSOGLM #9 II 11. 9238' 3.8:3" OtisxASlidingSlee'e 12. 9275' DIL 9 -5/8" Otis BWH Perm) ' M la 13. 9278' 5" OD seal gispiwint slot beater (4-1/2 Butt Box by pin down) 14. 9329' 3.8 :3" Otis X nipple 15. 9370' W i re l ine re-entry guide ratg mot , 16. 10,425' DIL Otis 7"BHW Perm p Li ) 17. 10,435' DIL 2.535" Otis 3 - 1 /2 ' XNnipple 9 -51 18. 10,436' DIL Wirel ine re-entry guide Perforation Detail .-_ 16 2 cne Top (MD) BTM(MD} Top(TVD;I BTMITVD) Comments 9,364' 9,37C' 8,632' 9,637' 59Z-.0. 3 9,386' 9,390 8,651' 8,554' Sgalt C I - 3 -1 9.420' 9,444 8.580' 8,701' Open 6 -1 9,435' 9,444 3 593 9,701 Open IDIL depths, 4 -22-08 3-2 9,465' 9A9C 9,719 8,740' Open , is 3-2 9,504' 9,516' 8,752 8,763' Open 3 -3 9 .542' 9.588' 8,785 8,824 Open 3-4 9,607 3.623' 8,840 9,854' Open 6.4 9,630 9,653 8,860' 9,879 Open 6-4 9,632 3.652 8,861 9,878' Open pit. depths/ 5 -2.08 6 -5 9,697 9 3.917 9.982 Open IL 3-5 9.711 9 '18 3 929 3935 Open :OIL Depths) 5 -2 -03 i'if -2 10,536' 10.571 9.515 9 Open Ju'F -2 10,588' 10,601' 9,559 9,569' Open Wf . 10,510' 10,622' 9,677' 9,585' Open WF -3 10,648' 10,655' 9,707 9,713' Open TD = 11,570' 'IF -3 10,658' 10,684' 9,723 9,735' Open Max hole aneleis34.8' `, 42,00' WF -3 10,695' 10,697' 9,745 9,747' Open i4'F -3 10,703' 10,727' 9,751' 9,771' Open i...4 ,%.,41. WF -3 10,739' 10,785' 9,780' 9,817' Open 01F -4 10,825' 10,953' 9.85C' 9,961' Open WF-6 10,994' 11,046' 9,995 10,027 Open WF -7 11,094' 11,150' 10,055 10,111 Open • • • . . ii Well Work Prognosis Well: G -32 IIil,-orl, %la4a III Application Date: 9/18/2012 Proposed (New) Wellbore Schematic Original RaB = 42.80' - CASING AND TUBING DETAIL i SIZE 'NT GRADE CQNN ID MD TOP F}D BTM. I 17-3/4' .3120 Conduct. Surf. 497' 13 -3/8' 616 . -55 12.515' surf. 4,810' 9-5/8' 47 X4 5µm 8 .535' Surf. 10,510' 13 -313 7 298 N-80 6.184' 10,408' 11,255' 1. 2 9 18 L -80 TD6 TC -I I 2.956` 5 -'f 19,100' Jewelry Detail No. Depth ID Item 1 ±304' Nipple for WR 555V 2 2.813 3-1/2" Otis Sliding Sleeve 2.725"' XN Nipple 4 No 10 ESP Top ASSembFy 2 5 NO ID Pump Intake 6 ±9,300' No ID Bottom (bull nose! 4 Proposed Perforation Detail 5 Zone Top(MD) BTM(MD) Top(TVD) BTM(TVD) Feet Ccmments 0-1 ±942D 19,444' ±8,680' ±8,701' 24 _tpf - ` 0-2 ±9,466' 19,493" ±8,720' ±8,743' 2 7 SW r 0-2 ♦9,504' ±9,516' ±8,752' 1 11 5d,9 0-5 ±9,542' 19,590' ±8,785' ±8,826' 48 5 mu , .S-4 ±9,612' ±9,622' ±8,844' ±8,853' 10 5 , ` 5 -4 ±9,630' 19,654' ±5,860' ±8,880' 24 5Agf V _ , .. TOL g 10,03' 5 ±9,697' ±9,774' x ,917' x,982' 7 5 N. 5'F -2 ±10,538' ±10,573' ±9,618' ±9,646' 35 55;g - 9 - S WF -3 ±10,649' 1 ±9,708' ±9,714' 7 5Ig( WF -3 ±10,668' ±10,666' ±9,723' ±9,733' 18 5 N WF-4 ±10,848' ±10,870' ±9,565' ±9,886' 22 5 L 7' SUPERSEDED UPERSEDED Max x hale angels 34.8' ,. 4„300' • • Well Work Prognosis Well: G -32 Hilcorp Alaska, LLC Application Date: 9/18/2012 Attachment 1: Standard BOP Test Procedure Williams Rig 404, Grayling 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. - 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. 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 downhole and not leaking anywhere at surface.) • • Well Work Prognosis Well: G -32 Hilcorp Alaska, LLC Application Date: 9/18/2012 b. Hold a constant pressure on the equipment and monitor the fluid /pump rate into the well. Record the pumping rate and pressure. c. Once this BOP ram and Annular tests are complete, test the remainder of the system following the normal test procedure (choke valves, gas detection, etc) d. 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 Tubinghead) 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, 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) Referencing the attached schematics test rams and valves as follows. a) Close C -1 (inside gate valve on choke side of mud cross) and close the annular preventer. Pressure test to 200 psi for 5 minutes and 1500 psi high for 5 minutes. If passes after 5 minutes on each, bleed off back to tank and open annular. b) Close Pipe Rams. Test to 200 psi for 5 minutes and 3000 psi high for 5 minutes. If passes after 5 minutes on each, bleed off back to tank and open pipe rams. 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 200 psi for 5 minutes and 3000 psi for 5 minutes. If passes after 5 minutes on, each, bleed off back to tank and open rams. • • Well Work Prognosis Well: G -32 Hikorp Alaska, LLC Application Date: 9/18/2012 d) Open C -1. Flow through the choke manifold and purge air. Test the choke manifold starting with the outer most valves, to 250 psi low and 3000 psi high, for 5 minutes each, as follows: (Valve numbers are in reference to Diagram B) i) Valves 1, 2, 10. After test, open same. ii) Valves, 3, 4, 9. After test, open valves 3 & 4. Leave 9 closed. iii) Valves 5, 6, 9. After test, open valves 5 & 6, leave 9 closed. iv) Valves, 7, 8, 9. After test, open all valves. e) Close C -2. This is the HCR (the hydraulic controlled remote) valve just outside C -1 on choke side of mud cross. Test to 250 psi low and 3000 psi high. After test, open HCR, close C -1. f) Blind Rams. Make sure test ioint is above the blind rams. Close blind rams. Test to 200 psi Low for 5 minutes and 3000 psi High for 5 minutes. Bleed down pressure. g) Bleed off all pressure. Line up pumps to pump down tubing. h) Test K -1, K -2, and K -3 on the kill (pump -in) side by pressuring up on tubing. Test to 200 psi Low for 5 minutes and 3000 psi High for 5 minutes. i) Test floor valves TIW (or Lower Kelly Valve) and IBOP. 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 +/- 3000 psi. 3) Close Annular Preventer, the Pipe Rams, and HCR. Close 2 set of pipe rams if installed (eg 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 2150 psi "). 6) After accumulator has stabilized, record accumulator pressure again. This represents the pressure and volume remaining after all preventers were closed. (The stabilized pressure must be at least 200 psi above the pre- charge pressure of 1000 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 ( +/- 3000 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. • Well Work Prognosis Well: G -32 Hilcorp Alaska, LLC Application Date: 9/18/2012 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. • • Ferguson, Victoria L (DOA) From: Mike Dunn [mdunn @hilcorp.com] Sent: Tuesday, October 02, 2012 1:48 PM To: Ferguson, Victoria L (DOA) Cc: Schwartz, Guy L (DOA); Regg, James B (DOA) Subject: RE: TBU G -32 (PTD 169 -086, Sundry 312 -359) Rolling BOP Test Attachments: Williams 404 BOP Test Procedure 10- 2- 2012.docx Victoria, We have no indications that casing is bad on this well. If we have to test the casing, we would propose to test against the existing packer as part of the fishing procedure by latching onto the seal assembly with a packoff and overshot, and test the annulus to 1400 psi. (The packoff is rated to 1500 psi.) We can chart it for 30 minutes. That would save us about $40,000 for the cost of a rental test packer and round trip time. Please advise. If acceptable, I will add that detail to step number 10 in the procedure and send it over. The revised BOP test procedure with the choke manifold test before the rolling test is attached. Mike Dunn ; Senior Engineer Hilcorp Alaska, LLC Office: (907) 777 -8382 Mobile: (907) 351. -4191 From: Ferguson, Victoria L (DOA) jmailto: victoria.ferguson@aalaska.govl Sent: Tuesday, October 02, 2012 11:39 AM To: Mike Dunn Cc: Schwartz, Guy L (DOA); Regg, lames B (DOA) Subject: TBU G -32 (PTD 169 -086, Sundry 312 -359) Rolling BOP Test Mike, Jim Regg reviewed the rolling BOP test and had the following suggestion: If both set of threads are unable to hold a pressure test then: 1. Nipple up BOPE 2. With stack out of the test path, test choke manifold 3. Conduct rolling test of rams and annular 4. Test remaining BOPE Please make this change in the rolling test procedure and email me a copy. Also, where will you pressure test the casing in this packerless ESP completion? Thanx, Victoria Victoria Ferguson Senior Petroleum Engineer State of Alaska Oil & Gas Conservation Commission 1 Facility No Flows Regg, James B (DOA) Page 1 of 1 From: Johnson, Wayne E (johnsonw@chevron.com] ~ Sent: Friday, February 06, 2009 3:11 PM ~~~ To: Regg, James B (DOA) Cc: Santiago, Johnny T; Greenstein, Larry P; Bartolowits, Paul D; Lovett, Juanita L Subject: Facility No Flows Attachments: G-33 8-95.doc; A-22dwg comp11-9-79.DOC; G-1 Schm9-17-97.doc; G-31 Schm9-10-89.doc; G-32 Schematic 5-13-08.DOC ./ ,, «G-33 8-95.doc» «A-22dwg comp11-9-79.DOC» «G-1 Schm9-17-97.doc» «G-31 Schm9-10-89.doc» «G-32 Schematic 5-13-08.DOC» .~ Jim, Here is your well schematics. '~A-22s: Shut In ~ ~rD I'] b --c; 3 1 /A-22L: No flow on May 27, 2004 ~1s: Shutln ~~ I`1(- i3~ :~G-1 L: No flow May 27, 2004 '`G-31 s: No flow November 23, 2004 ~ i<<t - u7 Z „.6l~31 L: Shut In 't~-32: No flow April 21, 2003 --~, ~'~ ~~`f- ~~ -33s: Shut In _ -33L: No flow November 23, 2004 a_ ~ ~. }} Wayne E. Johnson Operations Supervisor MidContinent/Alaska Business Unit Chevron North America Exploration and Production Grayling 907-776-6632 King Salmon 907-776-6692 Monopod 907-776-6672 Mobile 907-398-9942 2/6/2009 Grayling Platform Well # G-32 I~,~ -C~~~ Completed 6/23/91 (Revised 5/13/08) Original RKB = 42.80' CASING AND TUBING DETAIL ~/4 SIZE WT GRADE CONN iD MD TOP MD BTM. 17-3/4" .312 wall Conduct. Surf. 497' 13-3/8" 61# J-55 12.515" Surf. 4,810' 9-5/8" 47 & 43.5 # S-95 & N-80 8.535" Surf. 10,510' 7 29 # N-80 6.184" 10,408' 11,255' Tubin 4-1/2" 12.6# L-80 TDS Sec Clear 3.958" Surf 9371' JEWELRY NO De th ID Item 1. 304' Otis SSSV Ni le w/Fla er 2. 2242' PTA DSO GLM #1 3. 3711' PTA DSO GLM #2 4. 5100' PTA DSO GLM #3 5. 6175' PTA DSO GLM #4 6. 7052' PTA DSO GLM #5 7. 7733' PTA DSO GLM #6 8. 8384' PTA DSO GLM #7 9. 8778' PTA DSO GLM #8 10. 9220' PTA DSO GLM #9 11. 9238' 3.813" Otis XA Slidin Sleeve 12. 9275' DIL 9-5/8" Otis BWH Perm Pkr 13. 9278' S" OD seal assy w/str slot locator (4-1/2 Butt Box by in down 14. 9329' 3.813" Otis X ni le 15. 9370' Wireline re-entr aide 16. 10,425' DIL Otis 7" BHW Perm Pkr 17. 10,435' DIL 2.635" Otis 3-1/2" XN ni le 18. 10,436' DIL Wireline re-entr aide Perforations TD = 11,255' Max hole angle is 34.8° @ 4,300' G-22 Schematic Zone To BTM Comments G 9364' 9370' S zd G 9386' 9390' S zd G-1 9420' 9444' O en G-1 9435' 9444' O en DIL de the 4-22-08 G-2 9465' 9490' O en G-2 9504' 9516' O en G-3 9542' 9588' O en G-4 9607' 9623' O en G-4 9630' 9653' O en G-4 9632' 9652' O en DIL de the 5-2-08 G-5 9697' 9774' O en G-5 9711' 9718' O en DIL De the 5-2-08 WF-2 10,536' 10,571' O en WF-2 10,588' 10,601' O en WF 10,610' 10,622' O en WF-3 10,648' 10,655' O en WF-3 10,668' 10,684' O en WF-3 10.695' 10,697' O en WF-3 10,703' 10,727' O en WF-3 10,739' 10,785' O en WF-4,5 10,825' 10,963' O en WF-6 10,994' 11,046' O en WF-7 11,094' 11,150' O en REVISED: 5/13/08 DRAWN BY: BCA Page 1 of 1 Regg, James B (DOA) From: Regg, James B (DOA) Sent: Friday, February 06, 2009 8:50 AM To: 'myersc@chevron.com' Cc: Fleckenstein, Robert J (DOA) Subject: No Flow Determinations ~~~ Z~~~L ~`~ We've just completed an update/review of AOGCC "no flow wells" database and found a few dual completions that are not clear if the no flow determinations were on long string or short string. Wells in question are: > Trading Bay State (Monopod) A-22; PTD 170-031 > Trading Bay Unit (Grayling) G-01 RD; PTD 191-139 > Trading Bay Unit (Grayling) G-31; PTD 169-072 > Trading Bay Unit (Grayling) G-32; PTD 169-086 > Trading Bay Unit (Grayling) G-33; PTD 170-011 I would appreciate it if you could provide: 1) current well schematic for the listed wells; 2) current status of the LS and SS completions; 3) Union's understanding of which string the no flow determination applies to and why. Call if you have any questions about this request. Thank you in advance. Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 2/6/2009 RC<.rCl VCV STATE OF ALASKA MAY 2 Q 2OOH ALAS~OIL AND GAS CONSERVATION COMMI~N REPORT OF SUNDRY WELL OPERATIOI~~ka Oil & Gas Cons, Commission 1. Operations Abandon Repair Well Plug Perforations Stimulate Other Performed:: Alter Casing ^ Pull Tubing^ Perforate New Pool ^ Waiver^ Time Extension^ Change Approved Program ^ Operat. Shutdown^ Perforate Q Re-enter Suspended Well^ 2. Operator Union Oil Company of California 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development 0 ~ Exploratory^ 169-086 ~ 3. Address: P.O. Box 196247, Anchorage, AK 99519 Stratigraphic^ Service^ 6. API Number: 50-733-20198-00 + 7. KB Elevation (ft): 9. Well Name and Number: 42,80' Trading Bay Unit G-32 y 8. Property Designation: 1-0. FieldlPool(s): Grayling Platform/ADL 18730 McArthur River/west Forelands & G Zone 11. Present Well Condition Summary: i !/~0 Total Depth measured 11,2fi~" feet ~ ~ Plugs (measured) true vertical ~ feet ~'• 7.~' Dp Junk (measured) !o Effective Depth measured 10,405 feet true vertical 9,509 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 49T 17-3/4" 49T 49T Surface 4,810' 13-3/8" 4810' 4,680' 3090 psi 7540 psi Intermediate Production. 10,510' 9-5/8" 10,510' 9,595' 6330 psi. 3810 psi Liner 84T 7" 11,255' 10,194' 8160 psi 7020 psi. Perforation depth: Measured depth: See attach SChetllatlC ~~~NGD MAY 2 2 208 True vertical depth: See Attach Schematic Tubing: (size, grade, and measured depth) 4-1/2" L-80 9,371' Packers and SSSV (type and measured depth) 9-5/8" Otis BWH Perm Pkr; 7".Otis BWH Perm Pkr 9275' DIU 10,425' DIL 12. Stimulation or cement squeeze summary: Intervals treated (measured): N/A RAMS BFL MAY 2 2 2DD8 Treatment descriptions including volumes ased 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: 80 391 1378 1330. psi 200 psi Subsequent to operation: 167 ~ 642 2261 1330 psi 200 psi 14. Attachments: 15. Well Class after work: Copies of togs and Surveys Run Exploratory^ Development ~ Service Daily Report of Well Operations X 16. Well Status after work: OilO ~ Gas ^ WAG ^ GINJ ^ WINJ ^ WDSPL ^ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if CO. Exempt: N/A Contact Steve Tyler - 263-7649 Printed Name Timothy C. Brandenburg Title Drilling Manager Signature Phone 907-276-7 Form 10-404 Revised. 04/2006 ~ ~ ~ ~ ~ ~ L.. 600 Date 5/13/2008 s'f 2i• '} ~ Submit ina ~~ 'Chevron Chevron -Alaska Daily Operations Summary Well Name Field Name API/UWI Lease/Serial Orig KB Elev (RIB) Water Depth (ft) G-32 MCARTHUR 507332019800 ADL0018730 99.0 11,160.00 Jobs AFE No. OC Eng UWDAK R8027 EXP Daily Operations 4/21/200800:00 - 4/2Z/2008 00:00 Operations Summary Ran 3.69" GR to 10,405'. Ran 3-318"x20' dummy gun to 10,000'. 4/22/2008 00:00 - 4/23/2008 00:00 Operations Summary Ran GR/CCL from 10,000' to 9100'. Perfed w/2-718" erf un from 9423' to 9432'. Ran 2-7/8" perf gun and set down at 9423'. Could not run below this depth due to obstruction. (9435'-94 L) 4/23/2008 00:00 - 4/24/2008 00:00 Operations Summary Rarr CCL, wt bar and tag fill at 9423'.. 5/2/2008 00:00 -.5/3/2008 00:00 Operations Summary Run Pollard 2.9"dummy guns in prep for pert, Perforate lower G4 9632'-9652' DIL and G5 9711'-9718' DIL) Zones with 2 7/8" Powery'et guns 5/3/2008 00:00 - 5/4/2008 00:00 Operations Summary Attempt to pass bridge of 9423' to perforate. Graying Plt Well # G-32 Completed 6/23/91 (Revised 5/13/08) Original RKB = 42.80' CASING AND TUBING DETAIL ./4 SIZE WT GRADE CONN ID MD TOP MD BTM. 17-3/4" .3iz wan Conduct Surf. 497' 13-3/8" 61# J-55 12.515" Surf. 4,810' 9-5/8" 47 & 43.5 # S-95 & N-80 8.535" Surf. 10,510' 7 29 # N-80 6.184" 10,408' 11,255' Tubin 4-1/Z" 12.6# L-80 TDS Sec Clear 3.958" Surf 9371' JEWELRY NO De th ID Item 1. 304' Otis SSSV Ni le w/Fla er 2. 2242' PTA DSO GLM #1 3. 3711' PTA DSO GLM #2 4. 5100' PTA DSO GLM #3 5. 6175' PTA DSO GLM #4 6. 7052' PTA DSO GLM #5 7. 7733' PTA DSO GLM #6 8. 8384' PTA DSO GLM #7 9. 8778' PTA DSO GLM #8 10. 9220' PTA DSO GLM #9 11. 9238' 3.813" Otis XA Slidin Sleeve l2. 9275' DIL 9-5/8" Otis BWH Perm Pkr 13. 9278' S" OD seal assy w/str slot locator (4-1/2 Butt Box by in down 14. 9329' 3.813" Otis X ni le 15. 9370' Wireline re-entr aide 16. 10,425' DIL Otis 7" BHW Perm Pkr 17. 10,435' DIL 2.635" Otis 3-1/2" XN ni le 18. 10,436' DIL Wireline re-entr aide Perforations TD = 11,255' Max hole angle is 34.8° @ 4,300' G-22 Schematic Zone To BTM Comments G 9364' 9370' S zd G 9386' 9390' S zd G-1 9420' 9444' O en G-1 9435' 9444' O en DIL de the 4-22-08 G-2 9465' 9490' O en G-2 9504' 9516' O en G-3 9542' 9588' O en G-4 9607' 9623' O en G-4 9630' 9653' O en G-4 9632' 9652' O en DIL de the 5-2-08 G-5 9697' 9774' O en G-5 9711' 9718' O en DIL De the 5-2-08 ~/ WF-2 10,536' 10,571' O en WF-2 10,588' 10,601' O en WF 10,610' 10,622' O en WF-3 10,648' 10,655' O en WF-3 10,668' 10,684' O en WF-3 10.695' 10,697' O en WF-3 10,703' 10,727' O en WF-3 10,739' 10,785' O en WF-4,5 10,825' 10,963' O en WF-6 10,994' 11,046' O en WF-7 11,094' 11,150' O en REVISED: 5/13/08 DRAWN BY: BCA CheVr±mn ~nci5co Castro Chevron North ~rica Exploration and Production - Technical Assistant 909 W. 9th Avenue _~,~< = -;~ Anchorage, AK 99501 `"~'"' Tele: 907 263 7844 Fax: 907 263 7828 E-mail: fcbn@chevron.com DATE- May 16, 2008 To: AOGCC Mahnken, Christine R ~~,~~~ MAY ~ 2808 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 SSG 1 ~ "~ -c~3 lR~(~Uo ~ t ~ X5'3 ~j /i~-o~ ~ rc~2s" ~ 'd 1(pc7J`~c7 3 hJ 01`ES - ~!a'ELL LOG TYPE SCALE LOG DATE INTERVAL BOGGED RtJN ~ &LINE CD ~S' PDS. DUs PLUG SETTING PDS, RECORD 8.125" LAS, GP 18742 BAKER PLUG SET PDF, 32RD GR/CCL 5" 29-Feb-08 9604-9615 PS-3 1 1 DLIS PDS, LAS, GP 18742 DIPOLE SONIC PDF, 32RD IMAGER TOOL - CNL 5" 27-Feb-08 330-4221 ~ PS-2 1 -~ 1 DLI& ~ PDS, LAS, GP 18742 CASING EVALUATION PDF, 32RD USIT - GR/CCL 5" 27-Feb-08 330-9940 PS-2 1 1 DLIS PDS, PERFORATION DLIS, SRU 32A-15 SHOOT RECORD 5" 11-A r-08 5554-5582 1 1 1 LAS PDS, PERFORATING DLIS, TBU G-32 RECORD 5" 22-A r-08 9423-9432 PS-2 1 1 LAS PERFORATING PDS, TBU G-32 RECORD 5" 2-Ma -08 9620-9706 PS-3 1 1 DLIS Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to"907 263 7828. Received ey~ / Date: ~_r RECE''''O MAY 1 5 LOOß Union Oil~pany of California 909 W. 9th ue Anchorage, 99501 Tele: (907) 263-7889 E-mail: oudeand@chevron.com Fax: (907) 263-7828 .' ., _, . (' _. (»{\IH~~.ion Debra Oudeém:.~.?i ()I\ r.. \j(~,J.rtll). Technologist Anct\()!~)~ Chevron Date: May 11, 2006 To: AOGCC Helen Warman 333 W. ¡th Ave. Ste#100 Anchorage, AK 99501 i' ¡f'',;1.it'>~,,-,\';'; {: ~\i;Ìiro""\;"""- <: (-" ~, V .. ,.-------.........,....--..--.-....,.""'..,...,..,-........." HAPPY VALLEY- . A10 ) MUL TIFINGER IMAGING . TOOL .,........."'.."..--........----........".....------...."............--....-...'........'........-, ) COMPLETION RECORD 2' OMEGA HSD 6SPF .....".........-----....--.--,.. : 7250-8020 ) pds,1xt '204-186 ¡ 502312002800 ) 204-207 I 502312002900 ..___.__.__........... ....'.......____., .·_u·.....___·__,·"·,·,·"·,__·_______.·''",.,·,_..._·..·....__. HAPPY VALLEY- : HALLIBURTON MAGNA CIBP " 5 INCH ) A11 . SETTING RECORD 16-Nov- : 6720-7190 . 1 : 05 pds ) 204-207 ISÓ2:J12002900 :HÄPPVIÌALlËY- ) 2.5 POWERGET HSD GUN / ) A11 I PERFORATION RECORD : 51NCH 16-Nov- :6830-6990 : 2 ) 05 204-207 502312002900 .¡ ... HÄppvVÄl.l.EY- COMPLETION RECORD ' 51NCH ,.."...."'...........-......---.... 10-Nov- 7990-9085 A11 HALLIBURTON CIBP FOR 3.5' 05 CASING /2.5 HSD POWER JET 6 SPF PERF ...........,......"."" -----,-,,,,,,.,,.., ................ '5 INCH Ò1:May: 199-054 501331012501 SCU 21A-09 COMPLETION RECORD 2.5 10095- OMEGA HSD 6 SPF 06 10450 190-147 507331005501 TBF A-01 RD COMPLETION RECORD 2 5 INCH 02-Feb- 5300-6015 HSD POWER JETS 4SPF 06 167-080 m :SÓ7332õó6soõ' ... TBU 0-01 fCOMPLETIONRECORD33ïs" 5 INCH 'ii:F81>: 9280-9414 HSD POWER JET 6 SPF, 60 i 06 PHASING P' .............""... ...... 198-064 507332026701 TBU G-21RD COMPLETION RECORD 2.25 5 INCH 29-Jan- 9615·9833 , POWERJET HSD GUNS, 4 06 SPF, 60 DEG, GAMMA RAY / CCL CORRELATION 169-086 507332049800 TBU G-32 COMPLETION RECORD 2.875 : 5 INCH 31-Jan- 9180-9950 POWERJET HSD GUNS, 4 06 SPF, 60 DEG, GAMMA RAY / CCL CORRELATION ...........-...--..,-..,........ , pds,txt . pds . pds pds Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to (907) 263-7828. I Received By, C. ~___- I Dale s-- f'>j()ý ALAS~ O~~ ~ CONSERVATION COPlPI~SSION FRANK H. MURKOWSKI, GOVERNOR 333 W. 7~ AVENUE,'SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 April 22, 2003 Dwight Johnson UNOCAL Field Superintendent PO Box 196247 Anchorage, Alaska 99519 RE: No-Flow Verification TBU Well G-32 PTD 169-086 Mr. Johnson: On April 21, 2003, our Inspector Lou Grimaldi witnessed a '"no-flow test" on Unocal's Grayling Platform. Well G-32 was tested. Mr. Grimaldi arrived on Grayling Platform and found the well isolated from the production system and '~lowing" to an atmospheric vessel. Over the course of 3 hours, the well was shut-in, allowed to build up, then opened to flow 3 times.. On each occasion, the well quickly died. No-flow was confirmed using a Unocal meter and a "bubble bucket". It has been concluded that TBU well G-32 (169-086) meets the criteria of a "no-flow" performance test and as such, is considered incaPable of unassisted flow to the surface. The well's performance meets the criteria at 20 AAC 25.265 (b). Therefore the well is not required to have a fail-safe automatic SSSV, however, the pilot and SSV must be maintained in satisfactory operating condition. If for any reason the well again becomes capable of unassisted flow of hydrocarbons, the SSSV must 'be returned to service. A copy of this letter should be maintained in the respective well file on board Grayling. TEM:\jjc Sincerely, Thomas E. Maunder, PE Sr. Petroleum Engineer CANN£D-.." ,5 003 MEMORANDUM TO' THRU' State of Alaska Alaska Oil and Gas Conservation Commission RandyRuedrich, (~,~~ DATE: April21,2003 Commissioner P. I. Supervisor FROM' Lou Grimaldi, SUBJECT: Petroleum Inspector No-Flow Test Unocal Grayling G-32 McArthur River Field TBU PTD 169-086 NON-CONFIDENTIAL Monday, April 21, 2003: I witnessed a No-Flow verification on UNOCAL's Grayling platform well #G-32 in the McArthur River field. Following is a timeline and well status during test. O7OO fluid. 0715 0745 0800 0830 0845 0945 Well flowing to well clean tank at less than 1 psi & less than180 scf, no Shut-in well. SITP 0 psi, open well to gas flow gauge, zero flow. Shut-in well @ 0 psi SITP 0 psi, open well, zero flow. Shut-in well SITP 0 psi, Open to atmosphere. Zero flow. Note' The gauge used to check flow was incapable of measuring below 180 scf or above 2000 scf. 100-psi gauge used to check tubing pressure. Zero flow indicated by hose in bucket. This well exhibited inability to flow to surface unassisted and I recommend it be granted No-Flow status. I explained to Ernie Henderson (Platform Lead Operator) that any cleanout, perforating or other stimulation would require another No-Flow test. SUMMARY: I witnessed No-Flow verification on UNOCAL's Grayling platform well #G-32 in the McArthur River field. NON-CONFIDENTIAL CC; Dwight Johnson (Unocal), J.C. Waski (Grayling platform) Attachment: None No-Flow UNOCAL TBU G-32 04-21-03 LGl.doc No Flow Test Equipment Grayling G-32 AL/(? ~ Oil AND GAS CONSERVATION REPORT OF SUNDRY WELL OPERATION 0 R I A [ 1. Operations performed: Operation shutdown ~ Pull tubing ~ Alter casing __ Stimulate __ Plugging __ Perforate Repair well __ Pull tubing ~ Other 2. Name of Opera,,iN. CeA1-' ) I 5. Type of Well: I Development _A.. Onion Oil Company of Californi~ Exploratory__ 3. Address Stratigraphic __ P. O. BOX 190247 ! Anch. ! AK ~ 99519 Service __ 6. Datum elevation (DF or KB) 103 ' RT above MI.l'.~et 7. Unit or Property name TRADING BAY UNIT 4. Location of well at sudace Leg # 2, Conductor # 470 1882' FSL & 1383' FEL, Sec 29, T9N, R13W, SM At top of productive interval 1854' FNL & 1015' FWL, Sec 28, T9N, R13W, SM @ At effective depth 1811' FNL & 2089' FWL, Sec 28, T9N, R13W, SM @ 9364'M 11160' 8. Well number G-32 9. Permit number/approval number D 69-86/90-754 10. APl number MD50_ 133-20198 111' Fi~I~'°~ONE/WEST FORELA 12. Present well condition summary Total depth: measured true vertical 11,570' feet Plugs (measured) 10,417' feet Effective depth: measured true vertical 11,160' feet 10,086' feet Junk (measured) Casing Length Size Cemented Measured depth Structural Conductor Sudace 497' 17-3/4" 850 SXS 497' Intermediate 4810' 13-3/8" 2500 SXS 4810' Production 10510' 9-5/8" 2000 SXS 10510' Liner Perforation depth: measured True vertical depth 497' 4664' 9564' true vertical See attached perforation record Tubing (siZe, grade, and measured depth).-1/2zt / ,,, 7" Otis Packers and SSSV (type and measured depth) 13. Stimulation or cement squeeze summary Intervals treated (measured) 12.6#, L-80 Buttress @ 9370' "BWH" isolation pkr 9-5/8" Otis "BWH" Otis SSSV ¢ 304' See attached history 14. Treatment description including volumes used and final pressure @ 10425 ' production pkr @ 9280' KEf'ElY SS: Prior to well operation T,S: Subsequent to oper~MINGLRD RepresentmiveDailyAverageProductionorlnjectionData OiI-Bbl Gas-Mcf Water-Bbl CasingPressure 392 252 8 990 131 92 425 990 479 0 1642 1200 Alaska 0il & Gas Cons. c0mmtsSWt~ Tubing Pressure 140 140 120 15. Attachments Copies of Logs and Surveys run __ Daily Report of Well Operations __ 16. Status of well classification as: Oil-x- Gas_ Suspended __ Service 17. I hereby certify that the foregoing is true and correct to the best of my knowledge, Gar~. Bus~ Signed ~. ~ ~. Form 10-404 Rev 0/~15/88QJ Regional Drilling Manager Title Date SUBMIT IN DUPLICATE PERFORA?ION RECORD TBUS G-32 6/23/91 "G" ZONE 9364'- 9370' MD 9386'- 9390' MD 9465'- 9490' MD 9504'- 9516' MD 9542'- 9588' MD 9607'- 9623' MD 9630'- 9653' MD 9697'- 9774' MD 8609'- 8614' TVD 8627'- 8631' TVD 8696'- 8717' TVD 8729'- 8740' TVD 8761'- 8801' TVD 8816'- 8830' TVD 8836'- 8855' TVD 8892'- 8957' TVD SQZD-PROD SQZD-PROD OPEN-PROD OPEN-PROD OPEN-PROD OPEN-PROD OPEN-PROD OPEN-PROD WEST FORELAND ZONE 10536'- 10571' MD 10588'- 10601' MD 10610'- 10622' MD 10648'- 10655' MD 10668'- 10684' MD 10695'- 10697' MD 10703'- 10727' MD 10739'- 10785' MD 10825'- 10963' MD 10994'- 11046' MD 9584'- 9612' TVD 9626'- 9637' TVD 9644'- 9654' TVD 9674'- 9680' TVD 9691'- 9785' TVD 9713'- 9715' TVD 9720'- 9739' TVD 9748'- 9785' TVD 9817'- 9928' TVD 9953'- 9993' TVD 11094'- 11150' MD 10033'- 10078' TVD OPEN-PROD OPEN-PROD OPEN-PROD OPEN-PROD OPEN-PROD OPEN-PROD OPEN-PROD OPEN-PROD OPEN-PROD OPEN-PROD OPEN-PROD RECEIVED AU G ~ 9 1991 Alaska Oil & Gas Cons. Comm'tss'~en ~Anchorage ~ STATE OF ALASKA A( .,KA OILAND GAS CONSERVATION COMM(' 3N 0 R ~ G ~ N A -~,:: APPLICATION FOR SUNDRY APPROVALS :' ' Suspend __ Operabon shutclown __ Re. enter suspended well _.._ Repair wel~ __ Plug~ng __ Time extenaon __ S]~m ulate __ Pull tubing __ Variance __ Perforate ~ Other __ l ' 5. Type of Well: 6. ~ent .~ Stratigral~ic ~ 7. measured 11,570' feet Plugs (measured) true vert, cal 10,417 ' feet Datum elevation'iOF or KB) ' 103' R~ nhov~ MT.T.W feet.. Unit or Property name Trading Bay Unit 8. Well number C-32 "9. '~ermit n~Jmber" ~;q-~6 . 10. APl number 50-- 133-20198-00 ,, Field/Pool J~cArthur River 1L; Zone, west ~'oreJ. an(z 1. Type of Request: Abandon ~ "' 2. Name of Operator O.nion Oil,. Co. of Calif. (UNOCAL.) 3. Address POB 190247, Anch, AK 99519-0247 4. Location of well at sudace Leg #2, Conductor #47 1882' FSL & 1383' FEL, Sec. 29, T9N, R13W, SM At top of productive interval Top of "G" zone at 9346' MD 1854' FNL & 1015' FWL, Sec. 28, T9N, R13W, SM At effective depth 11,208' MD i814' 1~lI., & 2060' I=,4~, Sec. 28, TgN, Ri3W, SM At total depth 1 l, 570 ' MD i847' FRL & 2269' YWL, Sec. 28, TgN, RI3W, SM ' 12.' Present well condition summary ' Total depth: Effective depth: measured 11,208 ' feet Junk (measured) true vertical 10,124' feet Si~ Cemented Measureddepth ~ueve~icadep~ 17 3/4" 850 sx 497' 497' 13 3/8" 2,500 sx 4,810' 4,664' 9 5/8" 2,000 sx 10,510' 9,564' 9,364'-9,774' & 10,536'-11,150' RECEIVED Casing Length Structural 497' Conductor 4,810 ' Surface Intermediate 10,510' Production Liner Perforation depth: .measured 4 1/2" 12.6# L-80 TDS AU G B t991 Alaska 0il & Gas Cons. C0mmiSs'ten Anchorage Tubing (size, grade, and measured depth) Packers and SSSV (type and measured depth) Otis SSSV Nipple w/BXE ball valve @ 303.62', Otis "SA" @ g,237.85', Otis 9-5/8" "BWH" perm pkr @ 9,275' DIL, Otis 7" "BWH" perm pkr @ 10,425' DIL iii iii ilml ii iii i 13, Attachments Desc~iPti0n summary of proposal ~ Detailed operations program __ BOP sketch __ Oil _../ Gas_ Suspended __ oats ) ~,,~ Approval No. 9/ 14. Estimated'date for commencing operation........ ! 15. status'of well classification as: II September 1991 I Ov~II 16. ff prolX~ ~ verbally approv~-~l Name of approver Date appr Service 17. I hereby c~fl/that the foregoing is true and correct t(~l'the best of my knowledge. Signed / ~ ~dX~o~ ~. ~.~,~ T~e Re.ional Drillin. Manager (;~ (~ , FOR COMMISSION USE ONLY - - ' ' Conditions of ~lbr~otify Commission so representative may witness Plug integrity __ BOP Test __ Location clearance __ Mechanical Integrity Test __ Subsequent form required 10- ~c' ORIGINAL SIGNED BY LONNIE C. SMITH Commissioner Approved by order of the Commissioner Form 10-403 Rev 06/15/88 Date SUBMIT IN TRIPLICATE '~ August 19, 1991 G-32 Perforating Procedure 1. RU slick line, run gauge and tag bottom. 2. Hold saftey meeting. 3. RU electric line unit. 4. Pressure test lubricator to 2,500 psi for five minutes. 5. Shut down all welding and radio transmissions. . RIH and perforate intervals as instructed by Unocal representative (welding & radio transmissions may resume when gun is 200' below surface). 7. POOH (shut down all welding and radio transmissions). 8. Repeat steps 5, 6 & 7 as needed to perforate in the following intervals: "G" Zone Measured: 9,364'-9,774' West Foreland Measured: 10,536'-11,150' STATE OF ALASKA ( (] ~ ~ ~ ~ N J~ L ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon __ Suspend __ Alter casing __ Repair well __ Change approved program ~ Nameof_O,o~ratQr _ . 40%~%of Well: hzon ui± ~ompany of ca±ifornia (U Development ~._~.. ! Exploratory "3. Add~ess ! Stratigraphic . 9 --~ :2. 4 '7 . Service ~ n_ Rnv 1 qn247, ~,nnh_: A~( 9951 4. Location of well at sudace Leg # 2, 1882' FSL & 1383' FEL, At top of productive interval Top of 1854' FNL & 1015' FWL, At effective depth 11,208 ' 1814' FNL & 2060' FWL, At total depth 11,570 ' 1847' FNL & 2269' FWL, Operation shutdown __ Re-enter suspended well __ Plugging __ Time extension __ Stimulate __ Pull tubing ~ Variance ~ Perforate __ Other Conductor #47 Sec. 29, T9N, R13W, SM "G" zone at 9364' MD Sec. 28, T9N, R13W, SM MD Sec. 28, T9N, R13W, SM MD Sec. 28, T9N, R13W, SM 6. ~)~)t~r9 el~:~io~(~jEKB~LL~eet 7. Unit or Property name Trading Bay Unit 8. Well numberG-32 9. Permit number 69-86 10. APl number 50-- 133-20198 11. Field/~7o~A£- Lliu£ "G" Zone/West Forela] 12. Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical Casing Structural Conductor 497 ' Sudace 4810 ' Intermediate Production 10 510 ' Liner Perforation depth: measured Length true vertical 11,570 ' feet Plugs(measured) 10,417 ' feet 11,2 0 8 ' feet Junk (measured) 10,124 ' feet Size Cemented 17-3/4" 13-3/8" 9-5/8" 850 SXS 2500 SXS 2000 SXS Measured depth lcu~r~a~'aepm 497' 497' 4810' 4664' 10,510' 9564' See attached 3-1/2", 9.2#, N-80 Butt; LS @ 10446' SS @ 9309' Tubing (size. grade, and measured depth) Otis RDH dual @ 9295'; Otis RH single @ 10312'; Otis SSSV SS @ 279' LS @ Packers and SSSV (type and measured depth) 317' 13. Attachments Descri"Ption summary of proposal ._~ Detailed operations program __ BOP sketch 14. Estimated date for commencing operation 15. Status of well classification as: 'December 26, 1990 16. If proposal was verbally approved Oil ~ Gas __ Suspended __ Name of approver Date approved Service '1Z I hereby certify that the~g i~e a~orre~,the best of my knowledge. Signed GARY. S~,,~B~' L~_.D~ Title REGIONAL DRILLING M~NAG~ FOR COMMISSION USE ONLY Conditions of approval: Notify Commission so representative may witness I Approval No./~ Plug integrity __ BOP Test __ Location clearance __ Mechanical Integrity Test __ Subsequent form required 10-... Approved Copy Approved by order of the Commission Form 10-403 Rev 06/15/88 ORIGINAL SIGNEI~(Br9missi°ner LONNIE C. SMITH Date (~/C~/~ ~ .- SUBMIT IN TRIPLICATE ~d P~RFORATION RECORD TBUS G-32 "G" ZONE 9364 9386 9424 9438 9470 9506 9555 9614 9630 9702 '-937 '-939 '-942 '-944 '-949 '-951 '-958 '-962 '-965 '-977 0'MD 0'MD 8'MD 4'MD 0'MD 6'MD 8'MD 3'MD 3'MD 4'MD 8609 8627 8661 8672 8700 8731 8772 8822 8836 8896 '-8614'TVD '-8631'TVD '-8665'TVD '-8677'TVD '-8717'TVD '-8739'TVD '-8801'TVD '-8830'TVD '-8855'TVD '-8957'TVD HEMLOCK ZONE 10,540 10,652 10,670 10,695 10,707 10,725 10,739 10,766 10,848 10,994 11,013 11,094 11,130 '-10, '-10, '-10, '-10, '-10, '-10, '-10, '-10, '-10, '-11, '-11, '-11, '-11, 571'MD 655'MD 684'MD 697'MD 716'MD 727'MD 753'MD 774'MD 963'MD O08'MD 046'MD 120'MD 140'MD 9588 9678 9693 9713 9723 9737 9748 9770 9835 9952 9966 10,032 10,062 '-9612'TVD '-9681'TVD '-9704'TVD '-9715'TVD '-972~TVD '-9739'TVD '-9759'TVD '-9776'TVD '-9927'TVD '-9962'TVD '-9994'TVD '-10,054'TVD '-10,070'TVD WORKOVER PROCEDURE TBUS G-32 (9-10-90) · · MOVE RIG 54 OVER TBUS G-32, LEG 2, CONDUCTOR 47. KILL WELL WITH COMPLETION FLUID. · · · · INSTALL BPV'S, NIPPLE DOWN TREE, NIPPLE UP BOPE. PULL AND LAY DOWN DUAL G/L PRODUCTION STRING. RUN BIT AND SCRAPER TO 10408'. (TOP OF 7" LINER). CLEAN OUT INSIDE 7" LINER TO 11209'. · · PRESSURE TEST 9-5/8" CASING WITH RTTS PACKER. CHANGE OVER TO CLEAN COMPLETION FLUID. · 10. 11. REPERFORATE WEST FORELAND UNDERBALANCED WITH TUBING CONVEYED GUNS. SET RETRIEVABLE BRIDGE PLUG AT 10,350' AND SAND OUT. CHANGE OVER TO CLEAN COMPLETION FLUID. 12. 13. 14. 15. 16. REPERFORATE "G" ZONE UNDERBALANCED WITH TUBING CONVEYED GUNS. RECOVER RETRIEVABLE BRIDGE PLUG. RUN SINGLE G/L COMPLETION. REMOVE BOPE AND INSTALL SINGLE TREE. RETURN WELL TO PRODUCTION AND MOVE OFF. NOTE: SBHP ANTICIPATED TO BE 4025 PSI AT 9450' TVD. WORKOVER FLUID WELL BE FILTERED INLET WATER WITH NACL AS REQUIRED FOR WELL CONTROL. 3" KILL LINE WITH TWO 3" 5M VALVES 1_ -"d) .... ~'j) ., , KILL LINE FROM MUD PMP &: CEMENT UNIT BELL NIPPLE 13-5/8" 3000 PSI ANNULAR PIPE RAMS i FLOWLINE 13-5/8" 3M FLANGE ADAPTER 3M x 5M 13-5/8" 5M FLANGE BLIND RAMS I '"-"q DOUBLE GATE 5M 13-5/8" 5M FLANGE 4" CHOKE LINE WiTH ONE REMOTE & 1 MANUAL 4" 5M VALVE CONNECTED TO CHOKE MANIFOLD (SEE MANIFOLD DRAWING) PIPE RAMS I [ [: I 13-5/8" SM FLANGE SINGLE GATE 5M 13-5/8" 5M FLANGE RISER " ! 10" 5M x 13-5/8" 5M ADAPTER CAMERON 5M SPOOL l I 15-5/8" BOPE 5M STACK GRAYLING PLATFORM UNION OIL COMPANY OF CALIFORNIA (dba UNOCAL) DRAWN: DAC APP'D: GSB SCALE: NONE DATE: 11/26/89 17-5/4" @ 497' ~3-~/8" 480' / 7" TOL @ 9-5/8" @ 10510' 10408' 7"L @ 11255' / 4 1) 2) ~) 4) 5) 6) TUBING DETAIL: 1/2", 9.2#, N-80 TUBING SUBSURFACE SAFETY VALVE GAS LIFT MANDRELS "XA" SLIDING SLEEVE PERMANENT PKR @ 9275' "X" LANDING NIPPLE RE-ENTRY GUIDE "G" ZONE PERFORATIONS' 9420'- 9445' 9465'- 9492' 9505'- 9516' 9545'- 9590' 9607'- 9656' 9697'- 9774' WEST FORELA ND PERFORATIONS' 10558'- 10575' 10588'- 10601' 10648'- 10657' 10668'- 10688' 10705'- 10719' 10735'- 10760' 10765'- 10782' 10825'- 10965' 10992'- 11054' 11095'- 11152' UNION WELL TBUS G-52 PROPOSED COMPLETION OIL COMPANY OF CALIFORNIA (dba UNOCAL) DRAWN' DAC SCALE' NONE DATE' 9- 10- 90 WELL TBUS G-32 WF ZONE VII ? . 8 9 10 11 CASING & ABANDONMENT DETAIL I.) Kelly Bushing at 0.00' II.) Cameron Dual Tubing Hanger at 39.00' II1.) 17 3/4', 0.312' Spiral Weld Casing at 497' IV.) 13 318', 61~, J-55 Casing at 4810' V.) Top 7°, 29~, N-80 Liner at 10,408' VI.) 9 5/8°, 43.5~ & 47+, S-95 & N-80 Casing at 10,510' VII.) Bottom 7', 29~', N-80 Liner at 11,255' TUBING DETAIL LONG STRING: 3 1/2", 9.2#, N-80 TUBING 1.) Otis Ball Valve at 316.74' 2-11.) Otis 'CX° Gas Lift Mandrels at: 2) 2224:50; 3) 2905.02' 4) 3679.08' 5) 4446.81' 6) 5189.04' 7) 5795.06' 8)'6303.60' 9) 6777.15' 10) 7193.15' 11) 7549.00' 12.) Otis 'XO' Sleeve at 9259.44' 13.) Otis 'RDH' Dual Packer from 9294.76' to 9303.41' 14.) Otis 'XO' Sleeve at 10,278.09' 15.) Otis 'RH° Single Packer from 10,311.70' to 10,317.88' 16.) Otis 'X' Nipple at 10,317.88' 17.) Bottom of Otis Catcher Sub at 10,445.82' SHORT STRING: 3 1/2", 9.2#, N-80 TUBING A.) Otis Ball Valve at 278.95' B-K.) Otis 'CX° Gas Lift' Mandrels at: B) 2188.09' C) 2867.25' D) 3638.36' E) 4411.98' F) 5153.89' G) 5765.64' H) 6269.50' I) 6745.04' J) 7166.36' K) 7524.40' L.) Otis 'XO° Sleeve at 9228.29' M.) Otis 'RDH' Stinger with Collett at 9294.76' N.) Otis 'RDH' Dual Packer from 9294.76' to 9303.41° O.) Otis 'Q' Nipple at 9305.41' P.) Bottom of Baker Hydra Trip Sub at 9309.49' PERFORATION RECORD DA TE INTERVAL CONDITION 11/21/69 9364'-9370' Open for Production 9386'-9390° 9424'-9428' 9438'-9444' 9470'-9490' G ZONE 9506'-9516' 9555'-9588' 9614'-9623' 9630'-9653' 9702'-9774' 10540'-10571' Open for Production 10652'-10655' 10670'-10684' 10695'-10697' WEST 10707'-10716' 10725'-10727' 10739'-10753' FORELAND 10766'-10774' 10848'-10963' 10994'-11008' ZONE 11013'~11046' 11094'-11120' 11130'-11140' WELL TBUS G-32 WELL SCHEMATIC UNION OIL COMPANY OF CALIFORNIA LOS AN~£L[$ WELL TE U$ G-32 CASING & CEMENT DETAIL VOLUMES SHOWN ARE (CMT. VOL./HOLE VOL.) 26' 1' WALL, DRIVEN TO 369' 17 3/4', 0,312' WALL AT 497' 850sxs (978ft3/643ft~) LOST I:;JETURNS AFTER 650sxs PUMPED CSG TESTED AT'4OOpsi TOP CMT, 3334' 13 3/8',61~,J-55 CSG AT 4810' 2500sxs (3775ft-~/2900ft~) CSG TESTED w/1500psi DV COLLAR, 7804' TOP 7',29~',N-80 LINER AT 10408' ' COMP. 11/23/69 9 5/8',43.5~&47~,N-80&S-95 CSG AT 10510' 2000sxs (2300ft~/3464ft~) 2 STAGE CMT 1500sxs THRU SHOE, 500sxs DY 7',29~',N-80 LINER AT 11255' 225sxs (259ft~/109ft3) CMT FOUND ABOVE LINER TOP NOTE: ALL CMT TOP ARE THEORETICAL GRAYLING PLATFORM CASING & CEMENT DETAIL UNION OIL COMPANY OF CALIFORNIA _ _ Unocal Nor~ Amc Oil & Gas Division t.J~ocA, P.Q. ~ox Anc.-.Oraqe. A~as~a Te~eonone tgo~ ~ Recj~an April 16, 1990 Alaska Oil & Gas ConservAtion Commission 3001 Porcupine Dr. A~chorage, kK 99504 Attn: Ms. Elaine Johnson Dear Ms. Johnson: T have attached surface survey locations of the "Lags" and conductors for the four platforms in the Trading Bay Unit as well as the Union Oil-operated Monopod and Granite Point Platforms. I was unable to locate any plats from a registered surveyor but I hope this will meet your needs. Yours very truly, Regional Drilling Manager GSB/lew APR 197 CONDUCTOR GRAYLING DISTANCE &.DIRECTIONS FROM SE CORNER SEC. "Y" COORD. "X" ¢OORD. WELL # 29~ TgN, R13W FSL 1804 LEG #3: LAT = 60050, 22.569" LONG :151°36' 46.519" 2,502,352.30 212,272.70 1 2 3 4 5 6 7 8 9 lO ll 12 2,502,346.65 2,502,350.14 2,502,354.64 2,502,358.05 2,502,358.77 2,502,356.46 2,502,352.20 2,502,347.99 2,502,345.80 2,502,350.83 2,502,354.60 2,502,351.47 212,269.32 212,266.48 212,266.55 212,269.49 212,273.94' 212,277.80 212,279.28 212,277.68 212,273.75 212,270.89 212,272.33 212,274.88 G-22 G-21 G-26 G-25 G-24 G-20 G-36 G-34 & RD G-23 & RD G-33 G-27 & 28 1789 1802 1806 lB10 1810 1808 1804 1800 1798 1803 1806 1803 LEG ~4: LAT = 60°50' 22.832" LONG =151°36' 48. 042" 2,502,380.80 212,197.90 1831 13 2,502,374.34 212,196.66 14 2,502,376.65 212,192.79 15 2,502,380.90 212,191.32 16 2,502,385.11 212,192.92 17 2,502,387.30 212,196.85 18 2,502,386.45 212,201.28 19 2,502,382.96 212,204.12 20 2,502,378.46 212,204.05 21 2,502,375.05 212,201.11 22 2,502,378.50 212,198.27 23 2,502,381.63 212,195.72 24 2,502,382.27 212,199.71 LEG ~l: 2,502,455.60 212,226.40 .LAT = 60o50' 23.575" LONG :151°36' 4Z. 505" ' (Reserved for Compressors) G-14A 1825 G-19 1827 G-13 1831 G-15 1835 G-5 1838 1837 G-3 1833 G-2 1829 G-11 1825 G-lO 1829 G-17 & RD 1832 G-7 1832 · 1906 LEG #2: LAT = 60050' 23.313" LONG =151°36' 45. 982" 2,502,427.10 212,301.20 1880 37 38 39 40 41 42 43 44 45 46 47 48 2,502,421.45 212,297.82 G-12, RD & 2 1874 2,502,424.94 212,294.98 G-31 1878 2. 502,429.45 212,295.05 G-4 1882 2,502,432.85 212,297.99 G- 1 1886 2,502,433.57 212,302.44 G-9 1886 2,502,431.26 212,306.31 G-18 1884 2. 502,427.00 212,307.78 G-14 1880 2,502,422.80 212,306.18 G-30 1876 2',-502,420.60 ..... i ....... 2'12','302.25 .................. GZ8 '& RD ........ 1874 2,502,425.63 212,299.39 G-6 1879 2,502,429.40 212,300.83 G-32 1882 2,502,426.27 212,303.38 G-16 1879 FEL 1409 1413 1415 1415 1412 1408 1404 1402 1'404 1408 1411 1409 1407 1486 1487 1491 1493 1491 1487 1483 1480 1480 1486 1483 1488 1484 1458 1383 1386 1389 1389 1386 1382 1378 1376 ...... 1378 1382 1385 1383 1381 UNION OIL & GAS DIVISION WESTERN REGION ANCHORAGE DISTRICT TO: State of Alaska FROM' Graydon Laughbaum TRANSMITTAL DATE' December 29, 1969 WELL NAME' TBU G-32 (21-28) Transmitted herewith are the following: Run No. Final Sepia Blue Scale 1 RECEIPT ACK~NOWLEDGED: 'RETURN RECEIPT TO' Induction Electrical Log Dual Induction Laterlog BHC Sonic/Caliper Log BHC Sonic/Gamma Ray BHC Sonic/Caliper/Gamma Ray Log Formation Sonic Log (Fs) Compensated Formation Density Formation Density Log. (Fd) Neutron Log Formation Neutron Log (Fn) High Resolution Dipmeter (HDT) CDM Safety Print CDM or Printout CDM or Polywog Plot CDM Polar Plots Proximity aicrolog/Caliper Log Gamma Ray-Neutron Log Gamma Ray Collar Log Cement Bond Log Sidewall Neutron Porosity Log Laterlog 3 Mud log Core Descriptions, Conventional, No. Core Descriptions, Sidewall Core Analysis Formation Tests Directional Surveys Core Chips Sample Cut DJYJSION OF O!/AND GAS ANCHOI~E DATE: Union Oil & Gas Division - Western Region Anchorage District P. O. Box 6247, Airport Annex Anchorage, Alaska 99503 Attn: Rochelle Carlton Union Oil Compan 3alifornia unlen 507 W. Northern Lights Blvd., Anchorage, Alaska 99503 Telephone (907) 277-1401 7 "? ~ ~'" ~ecember 24, 1969 / ~ Mr. Thomas R. Marshall, Jr. State Petroleum Supervisor Division of Oil & Gas 3001 Porcupine Drive Anchorage, Alaska 99504 Re: TBUS G-32 (21-28) Well Completion Report Dear Mr. Marshall: Enclosed please find corrected copies of the P-7 form on the above captioned well. The production~ata was erroneously submitted a few weeks ago. ~ District Production Superintendent RCH/dp Encl. (2) FORM 401-ANC-W (8/67) Form P--7 -- SUBMIT IN DUPLICATE* · ', See other In- - St ruct ions on cOMMiTTEE ~,,e,-~ .~d~ STATE OF ALASKA OIL AND GAS CONSERVATION _IL I ' _ WELL COM,,PLETJ ON OR,REC.QMPLETION REPORT AND LOG* 'la. TYPE OF WELL: ozI, WELL WELL E] DRY E] ot~er b. TYPE OF COMPLE~ON: WELL OVER EN BACK EESVR. Othe~ ,, , ~2. NAME OF OP~RATO~ Union 0il Company of California 507 W. Northern LiEhts Blvd., AnchoraEe, AlaSka 3 4. LOCATION 0F WELL (~pOtt J0C~tJ0. Cle~lM ~d i~ ~CCOrd~C8 ~{~ e~y ~te req~/~e.~)* At surface At top prod, intervaI reported below At total dep~ Long String §. AP1 N'U'JNEF.~C.~,~ CODE 50-133-20198 ii. L~.ASE DESlG~C~TIO~ AND SER/AL NO. ADL 18730 7, IF IiN-DIA_~T, A.T.~O~ OR TRIBE NA_ME 8. UNIT,FAI{NI OR LEASE NAME Trading Bay Unit 9. W~.r~ NO, -- State G-32 (2Z-28) 10. FT~t.n A~TD POOL, OR WILDCAT, McArthur River-West Forelam 11, SEC., T., R., M., (BO'i'I~M HOLliI SeC. 28, T9N, R13W,,.. SM. 69~86 ~- CASING RECOR.D (Report all strings set in well) · C.~SIi~G SIZE DEPTH S~T (1VID) _ ~ SIZE LINER TOP (MD~ (MD) SACKS CEMEi~T* .i, ,., .%. . PACi~]m S~T 28: PEI{FOI~kTIONS OPEN TO DATE FIRST PI%ODUCTION 11/24/69 DAT]~ OF TE~T, I-~O131~S TE~TED 11/25/69 24 FLOW ~BING ~' 110 0 _ DISPOSITION OF GAS ICTION METHOD (Flowh~.g, gas lift, pumping--size and~ type of~pulnp) :< ~lowing CHOICE SIZE [PROD'N FOR 124 CALCUT.~A. TF_,D OIL~I3BL, ~-~o~ ~ 316 2 -- .. (~:~ro~ucir~ or G~=~2 W&~B~. OIL ~[~-~ (C~.) ~ ~1 4 LIST OF' ATTACHMENTS I:1 ,/ ,,, , I her~b~ ~rtif~ that Xhe~orel.ol~ a~ir~l~formatlon , , ~.~./~mann - --- *(Sie Instructions and S~ces for AdditiOnal Data on ReVerse Side) 12/24/69 iNSTRUCTIONS Geflerah This form is designed for submitting a complete ~nd correct well completion report, and log on all iyp~s of lands and leases in'Alaska Item: :l&: Indicate which elevation is Used as refe~redce (Where not o~h~rwise shown) for depth me~sure~'7 r~en~s~iYen in other spaces on this'form and n any. attachments.' · ~ 2 '4 "~' -'ltfm$ 20, and 22:: If this well is completed fol; separalo production from more than one (multiple:completion), so'state in item 20, and in item 2~ show the P~cducing inte'~.val, ~z! trite:revolt,,. top(s), bottom(s) and name (s) (if any) for only the. interval ~'eported in:it'em 30...Subm~t:a se'p~ate (page) on this form, adequately identified, for each adclitio'nal intmval tO be~.seberateLy pro&/~ed.,/ lng the additional data pertinent, to such': interval; : ~ ~. :i.. '~ ':':i: .... Item2& "Sacks Cement": Attached sUpplemental records for this well ~should ShOw'the details of any' mul- tiple stage cementing and'tJ~e loCation of the cementing tool. . item 28:,'Submit 'a separ~te.~completion report on ii, is form for each interval 'to be separately produced. (See' instruction for items ~20 and i22 above). ' ·-{} 34. SUMMARY O1~ FOI~iMATION TF_,STS INcLuDIN(~ INTEI~VAr; :~D,.~-~URE DATA ~ ~OV~ OF 01L, G~. "~ ~ · , ~ ~ ~ , , ~.~ , , " '' .,. .;. ; :, ? ~:~' ~ 3~: ~ORg iDATA, A~A~I[ BRIE~ .D~CRIPI~ONS OF LI~O~G~,....POHOS~TY. FRACAS, APP~NT DiPS ..,: AND ~DE'FKC~D SIIOWS*.;OF ~OIL, G~ OR WA~-''{, ~ ?' ~: . . , , . .; . :' . '" ' .. :' ; : ' " ~ ~ . ': , , ~, :. : ,,. _ ,~ ' .: ,.: . ._ .. , ;. , ': ~ F~rm No. P--4 STATE OF ALASKA OIL AND GAS CONSERVATION COMMITTEE MONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS SUBMIT IN DUPLICATE is.AP1 NUM. ERiCA.L ~ODE TRM - OKG -~ ! 50-~33-20198 k~.V ~ iS. LEA~E DESiGNAT'ION A.%-D T. IF INDIA~, ALOi t~,E O1~ TRIBE NAME OIL ~-~ GAS [~] WELL WELL OTHER NA2~E OF OPERATOR Union Oil Company of California 3. ADDP. ESS OF 507 W. Northern Lights Blvd·, Anchorage, Alaska 99503 4. LOCATION OF Conductor #47, Leg #2, 1882'N, 1383'W from SE corner Section 29~ T9n, R13W, SM. · 8. L~'N'IT,F.~:~ OR LEASE NAME Trading Bay Unit 9. wELL NO State G-32 (21-28) 10. l"l.l~J.~ A_ND POOL. OR WILDCAT · K ' "G" zd naz McArthur River-~est t~oreland i1. SEC., T., R., 1~I., (BO~I~FOM HOLE oB,rEcrrvE) Section 28, T9N, R13W, SM. 12. P]~R/V~IT 69-86 13. REPORT TOTAL DEPTH AT END OF MONTH, CI-I_A-NGES IN HOLE SIZE, CASING A-N-D CE1ViENTING JOBS INCLUDING DEPTH SET AND VOLU'M'ES USED, PEB. FOHATIONS. TESTS A_N"D RESULTS. ~Ni~~,~LE AND SIDE-TP,~CKED HOLE AND A-NY OTHER SIGNIFICANT CH. ANG'ES IN HOLE CONDITIONS. -' i~JCJJOJ~ TRADING BAY UNIT STATE 0-32 (2.1-2.8),, NOVEMBER 19,69 Continued drlg 12-1/4" hole from 10,317' to 10,496'. Made wiper run. Circ clean. POH. 'RU Schlum, ran DIL (TD 10,499'), GR density & sonic logs. Circ& cond for csg. Drld 10,496'-10,510'. POH. Ran 253 its 9-5/8" 43.5# & 47# N-80 & S-95 buttress csg. Hung w/shoe @ 10,510'. DV collar @ 7802'. Cmtd thru shoe @ 10,510' w/1500 sx Class "G" cmt w/l% CFR-2. Bumped plug, OK. Opened DV @ 7802'. Circ cmt thru DV w/500 sx "G" ' cmt. Closed DV. CIP..i:30 p~. 11/5/69_. Rmvd BOP's & riser. Landed csg. Instld 12" 3000# x 10" 5000# tbg head. Tstd OK. Instld riser & BOE. Tstd OK. Drld out DV @ 7802'. Tstd w/2000# OK. RIH. Drld out FC, cmt & shoe. CO to 10,510'. Conditioned mud. Drld 8-1/2" hole 10,510'-11,570'TD. POH. RU Schlum. Ran DIL to 11,550'. Tool malfunctioned. RI w/density log, stopped @ 8600'. PO, reran DIL, tool stopped @ 4600'. PO. RD Schlum. RI w/poorboy junk bskt to 10,520'. PO, no rec. Ran DIL, unable to run below 5720' RD Schlum. RI w/da to 11,570' · , no fill. Circ & cond mud & hole. Rec some free crude oil. Hole problems are a combination of dp rubbers & various mud. Ran Schlum DIL & sonic log. Sonic malfunctioned. Ran density log, stuck tool. Worked free. POH. RI, circ & cond hole w/4a, no fill on btm, tight hole @ 11,400'. Ran Schlum density tog, dip meter & sidewall sample gun. Circ & cond hole for lnr. Ran 20 its 7" 29# N-80 buttress~csg on TIW lnr hngr. Hung w/shoe @ 11,255' & top lnr hngr @ 10,408'. Cmtd thru shoe w/225 sx "G" w/l% CFR-2. CIP 3:30 am 11/15/69. RIH with 8-1/2" bit & 9-5/8" csg scraper, top cmt @ 10,350'. Drld out cmt ~0~50'- 10,408', top lnr. PO, RI w/6" bit & 7" scraper. Drld out cmt & CO to ll,209'ETD. 2 ' Ran D-A GRN correlation log. Set EZ drill BP @ 10, 65 . Shot four 1/2" holes @ 9890' (top Hemlock Zone for zone segregation sqz). RI w/RTTS too~, set @ 9730'. Sqzd perfs w/150 sx "G" cmt. Max press 4900#, held OK. CIP 4:45 am......!1/17/69. RI & drld firm cmt 9802'-9905'. Tstd perfs @ 9890', w/2375 psi OK. Drld'BP @ 10,265' & CO to top of lnr @ 10,408'. RI w/6" bit. Drld on junk fm BP @ top lnr @ 10,408. l"orm No. P---4 REV. STATE OF A. LASKA OIL AND GAS CONSERVATION COMMITTEE MONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS W~'LL W~LL OTHER 2. NAME OF OPEI%ATOR Union Oil Company of California 3. ADDRESS OF OPERATOR 4. LOCATiON OF WELL SUBMIT IN DUPLICATE PAGE TWO AP1 NUA{ERiCAL CODE LEASE DESIGNATION AND SERIAL NO. 7. IF INDIART, ALOTI~E OR TRIBE NAME 8. L~.'IT,F.A~RA{ OR LEASE NA/~E Trading Bay Unit 9. %VELL NO. State G-32 (21-28) 10. l.U~.:i.l~ AND POOL, OR WILDCAT 11. SEC., T., R., Ri., (BO'I~OM HOLE OBJEc~rvE) 12. PERMIT NO. 13. REPORT TOTAL DEPTH AT END OF MONTH, CI4_.A. NGES IN HOLE SIZE, CASING AND CEMENTING JOBS INCLUDING DEPTH SET A1N-D VOLUATES USED, PEi~FO'RATIONS, TESTS A/XID I{ESULTS, FISHING JOBS, JLr~K IN HOLE A2qD SIDE-~CKED HOLE AND A.NY O~I-IER SIGNIFICA~qT C~IANGF~ IN HOL~ CONI)ITIONS. TRADING BAY UNIT STATE 0-32 (21-28). N0V.EMBER 1.969 RI w/6" bit. Drld on junk fm BP @ top lnr @ 10,408'. CO to 11,208'. Displaced mud w/73#.salt wtr. Spotted 75# Invermul pill on btm. Perfd West Foreland Zone intervals from 10,540'-11,140', & "G" Zone intervals from 9264'-9774' w/4" thru csg guns, 4 hpf. Ran and landed dual 3-1/2" tbg strings. Long String hung @ 10,445' w/single pkr @ 10,317'. Short String hung @ 9309' w/dual pkr set @ 9305'. Rmvd BOE. Instld & tstd dual tree. Displaced Invermul & salt wtr w/diesel. RIG RELEASED 6:00 pm 11/23/69. SmN~m~'~~,j~.:' ~,~.~~~Z4%~z Dist. Drlg. Supt. nAT~ 12/15/69 . -- Vo.~,. -', ~,e.F/ NOTE--Report on this~ is required for each calendar month, regardless of the status of operations, aha must ~ filec~ in duplicate with *,he Division of Mi.es & Minerals by the 15th of ,,he succeeding month, unless o,,herwise directed. FORM ,369 4-63 'RINTE~ IN U.S.A. UNION OIL CO/-APANY OF CALIFORNIA Document ¥: (' ;mi??ol FROM.. Union Oil Company AT Anchorage TRANSMITTING THE FOLLOWING: NO. · j." / ~ Chrc.~::ological l)rilling l{istor ~, Tradi;tg Be.), Unit State G-32 ' D E ~ 1 0 ~ae~ , t FROM Union Oil Company Anchorage TRANSMI~ING THE FOLLOWING: ~ State of Alaska Well Completi~)n (P-7) ~eport TBUS G-32 (21-28) LS & SS J kll"~lJl il' J~ ., , .,, .... /I,~orm P 7 / / SUBMIT iIN DUPLICATE* STATE. OF ALASKA ,,se~ other ' ' . strUct ions on W LL (OMPL TIOM OR R COMPL TIOM AMD LOG * ~a, TYPE OF WELL: On, ~ ~ts ~ ~ ;c. b, TYPE OF COMPLE~ON: ~ ~. ~ ;~- .7.~ ~ · ~ ' ,,-~ o¥~ ~~D~E~' ~c~ ~" ~-~ , '~'~ ~ ,, Union Oil ~9~pan~ of ~alii~n~ ~ . ' '3. ADDR~8~ OF OPERATOR " :. ., HLB Long String OKG- 50-133-20198 ADL 18730 ~. IF INDIAN, ALIX)TTEE OR - :~ - :- -- 8. UHIT,FAILt~ OR LEASE NAME Tradin~ Bay U, ni,,t. Sta'~e G~32 (21~28,,) .' 1O. FIEI.D ~ POOL; OR WILdCaT 507 W. Northern Lights Blvd.s, Anchor~.":i~Laska ~99503 . ~. LOCATION OF WELL (Re~;ort location clearly ~.d ia accord~ a.Y ~Ze r~ui~e~enZ,)* ' ~ McArthur River-West ,Foreland At top prod, lffterval reported below ~ ~. From surface location 1615'N~2& 3~17'~ ~.; ~,.~ ' " "~ ~ ' Sec. 28~' T 9N, R 13W, SM I At total dep~ ~:. ~ ~ ~" u' . ............... ~. .......................................... ~ .............. ~: .............. ::: ......... f~.~.~i'...,.~n,v~,~.,~. ~,.,-.~ ::. 69-86 ..... ; '. i0/1/69 I 11/lk/6~ I 11/23/6t ~ ~ ab0~e ISL ' .-,: !~, 59' above .~SL ~ { ~ / ~W~Y* ~ c, { aOTNRY T~0L~ ~ I .... ' CABLE TOOLS ; . ~ I;~ :~ , ' I , ' I ~ :/' -' I " ' '!" : ' West Foreland. 105~O ~ & 95~0 TVD - 111~0 ~ ~& ~0~9 ~D . , .... : , -. yes . 24.~ TYPE ELECTHIC 2~ND OTHE~ .. .. - :. '-, CA~I~G RECX)I~D (Re~ all strips set in , - - CA~G S~ZE D~ ~ (~) REC~' ~O~T ~"~ " sx LINER SIZE TOP ]11 28. PERFORATIONS OPEN 0540-71 10725-27 ~0652-55 o10739-53~ o10766-74~ i0670-84 ~ ~0695-97 ~'10848-96~;.:.~. 0707-16 3BOTTOBi (MD) SACKS CEMENT* (Interval, size and number) ! non-4 11094-120 c,~ 11130-140 ~ PRODUCTION 27. ct ~ mz~ : DATE FIRST Pi%ODUCTION f~K~D OF il/24/69 METHO'D (Flowh~g, gas lift, a~ type of purap) ~2~ATE O, ,E,T.~/69 tti°u~s24{?' .:!i', [C~OXE SIZ".C*r~~ O~.~sT~OV'~ .0~ 150 0 , ':.~. , ,~' 5064 ~ ~2. ~IST 0~' AT~AC~,ENTS .... ' GA~---1V~C~.~. WATEP,,--BBL, [ OIL GRAVITY-Ai:~ ]TES~ WITNESSED BY " - ;"'~~ - "ore~~tts'ched~'nf~'atton Is corn plete and', co rre bt as determined from alVa va liable 'records ~~/~ TITLE Dist.li Dr~ling Supt. DATE 12/3/69 (S~e Instructions and S~ces for AdditiO,al Data on Reverse Side) "' - WA~ AND MUD. .. ~... :': ' . , , ,,~ : .. ... .i:'~ ~; .L, . , , . . ... . .-~..~-~ ~ ~. · ~. , · ........ . {.. . '" "- ' ~ ' - ~ 2..' ~ ' , . ~- . :' ~ --: ~idd~e K~i ""E" 6710'' ~one ~ . ~iddle Ke~ai'"F" 776~.' .-... ~ · ' ~idd~:e Keuai "'G" 9210' .... . -;:; ' : - _. ~ .... ,~ .... ~ ....... H - ~' ., 9922 ' ,. ... ~ .... N~L Fore~an~ .~ ~. ~ .... . .... ~ ... ~. '. < ... ~.: . ,'~. [/4,~ ~ ......... , .... :- .... /i/ AND D~PEC~'~I) SIIOW~ O~ O!~, ~ OR~'W~. ~; ~ .... ..~ : ::' ' ~ ' .. .. L , ,/ ,, , ,, , ~ ~' ~ ~- C: ::~: . . .. .': : .~ · ~... :. H'~ ~' . · ' ...: ...: ..: .-. ~:-' ,. ~.. ~-. E . _ ~ ..... ~--. :. .--.. - . '~' ~. . c .... ' ..... ": ; .... ' :::' ~/ ':- · ~-- : L. ' " :." ' : . _ ~ . ..' -:: .~ ~. ..- ......... INSTRUCTIONS - . General: This form is designed for submitting a complete and correct well completibn report end log on all types of lands and leases in Alaska. ' ..... - Item:..16: Indicate w~hich elevation is used as ·reference (wh.L~r.e not bther,w~se shown) for depth m~asure~' 'ments given in other (Spaces 'on this form and in any attachments. . _ - ItemS!.20, and ll:: If'.}this well is completed for separato production from more than one ~n~erva[- (multiple completion)',, so state in item ~0,'~ ahd in item ~ show the p[cdvcing i~tfrval, o~r int~'fvals} · top(s), bottom(s) and~name (s) (if-any) for only the interval reported in item 30. Submit a separate '}'epo~t~ · L. L.' '.'-- .... {page) on this form, :adequatelY.':Jidentifiedj:Jfc~'r each additional inte, val to be s.~perately produced, ~shoW--: ing the ao~ditional data pertine~,t to sUch :interval. .:' r,:, It®m26: "Sacks Ceme. nt": Attached suppleme~'.n, taF records for this welt'sho?d show the detai!s of any mul- tiple stage cementing-and the location of!~he'c'ementing tool. '~ ~.-?~.~ -,%~." .Item 28: Submit a separate completion reP°~:t o:r~, this form f..~r each;;"inte~val,,to be separat6~ly produced. ¥ ._ :(See instruction for items 20 ar~t 22 abov~).i.:i ;< _ :-:" : .:- ..... ,': ...... ~:.; -- ..,,,~::;:~ . .... : :.; ...... : . ,.':.]? ..~ ,: . LEASE UNION OIL CO. OF CALIFOI I I SHEET D DRILLING RECORD ~llgt~tl, l ~ Trading Bay Unit , , Vv~ELL NO. G-32 FIELD McArthur River DATE 9/30/69 10/ 1/69 10/ 2/69: 10/~3/69 10/ 4/69 10/ 5/69 10/ 6/69 10/ 7/69 10/ 8/69 10/ 9/69 10/10/69 10/10/69 10/11/69 10/12/69 E. T. D. 369 510 510 721 2,112 3,068 4,017 4,824 4,824 4,824 4,824 4,810 4,810 5,482 DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS Moved rig on location from well G-1 workover, Completed N.U, to spud well, Spud well at 12:00 Noon. Hit cement in conduc- tor at 245', Drilled to 510', Laid down heavy wall and drill pipe in derrick, Opened holw w/22" underreamer to 510', Had trouble getting through bottom of conductor. WIH w/18" mill to check for restrictions, Rigged up to run casing. Ran 12 joints, 17-3/4", .312" wa!l, spiral weld casing .... Ran 5" d p to stab in shoe and cemented w/850 sx class "G'" cement. Lost returns w/650 sx away. POH w/d.p. WOC 4 hrs. N.U. riser assembly and 20" hydril. Test hydril and csg w/400//. Drilled out to 528' w/15" bit P h and p u 12-1/4'~ bit Drld and surveyed w/Sperry Sun gyro to 721', · Drill. ed and surveyed w/Gyroscope to 1258', Drill ahead & survey w/single shots to 2084', D & S 12-1/4" hole to 3068', RIH w/Dynadril! Run #1 w/i-t/2: kick sub. Dynadrilled 3068-3325'. Drilled & surveyed 12-1/4" hole 3325-40!7'. Drilled & Surveyed 12-1/4" hole 40i7-4824'. Trip for new bit at 4055'. Trip to chg Bi~ at 4272'. ID 4824' at 4:00 a.m., 10/8/69. Opnd 12-1/4" hole to 17" 505' to 3023', Open 12-1/4" hole to 17" 3023' to 4500', Opened to TD at 4824' at 5:00 a,m,, 10/10/69, POH and made Up full gauge HO and made wiper trip circulating bottoms up, Rigged up and ran 123 jts 13-3/8" 61# J-55 buttress csg and landed same with float shoe at 4810', Made up cementing head and circulated capacity of casing, 13-3/8" Casino Detail 2,60 41,62 1,87 4686,67 40,24 37,00 4810,00 l jr. 120 j ts. j jr. Baker "G" circulating differential fill up shoe, 13-3/8" 61f/ J-55 buttress casing, Baker "G" circulating differential fill up collar, 13-3/8" 61~/ J-55 buttress casing ~Cut landing jr, 13/3-8" 6].~~ J-55 buttress casing. -' ~ ' above ro~arv_,~ Distance from cas~n~d to 1' Setting depth Cemented w/2000 sx class "G" w/5% gel, 1% D-31, and 1/2 cu.ft./sk perlite followed by 500 sx class "G" neat. Mixing time 68 minutes. Displaced w/4080 cu. ft. mud. Displacement time 58 minutes. Bumped plug w/2000~-". CIP and job compl, ete at 1:30 a,m., 10/i!/69. Released pressure and float held ok. WOC 4 hrs. Released csg and held ok. Cut 13-3/8" csg and 17-3/4" csg and ND 20" hydri!l. Welded or: Cameron "WF" csg hd. housing 1.2" 3000(.~ ~P x 13-3/8" slip,~:n weld 13 tm w/two 2" 500'0~? WP FLGp outlets. Test weld w/3000(-" 1.5 minutes. ~:U BOPS and tested blind ra~s and casing w/1500#. PU bha and magna-fluxed all. connections. Changed out 22 jts h,w,d.p, Wilt to float collar at 4770', Changed pipe rams and test w/1500# ok. Test Hydril w/1500J~ ok. Drilled float collar and shoe, Made trip for mew bit at 5345', }{ad 2 i~r, power failu~7e on panel boards. Lost. all power to rig, Changed powc~ contactor sw~tch and drilled ahead. UNION OIL CO. OF CALIFORNIA DRILLING RECORD SHEET D PAGE NO. 2 LEASE Trading Bay Unit WELL NO....G-32 FIELD ~,_.,)rthur River DATE E.T.D. DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS 10/13/69 10/14/69 10/15/69 10/].6/69 10/17/69 10/18/69 10/19/69 10/20/69 10/21/69 10/22/69 10/23/69 10/24/69 10/25/69 10/26/69 10/27/69 10/28/69 10/29/69 10/30/69 10/31/69 ll/ 1/69 1]./ 2/69 6,1.79. 6,323 6,626 6,884 7,126 7,612 7,862 8,090 8,347 8,427 8,447 8,572 8,954 9,145 9,394 9,608 9,811 10,025 10,160 10,248 10422 Drilled and surveyed 12-t/4" hole to 624!'. Had excessive, right walk. Changef out 23 jts h.w.d.p. PU Dynadrill deflection tool and WIH. Dr!d to 6323' in 7 hrs. POH. WI}{ w/bi~ ~Jll and new drlg assembly. Drld to and trip for new bit ,~?12. D & S 6463-6643'. Trip for new bit at 6626'. Left 1 cone in ho].e. RIt{ w/NB # -13 & drld 17'/2 hrs. Trip for NB #14 at 6643'. Rotated slowly past junk & drld 6643-6830'. POt{ for Dynadrill ~/3 at 6'830'. Ran Dynadrill w/2: kick sub 6830-6914'. ~o indication of junk on Dynadrill rtln. D & S 12-i/4" hole 6914-7234'. Hole turned from N63E and 28~ to N56E,and 27: on Dynadrill #3. Trip for NB at 7126'.' D & S 12-1/4" hole. D & S 12-1/4" hole. D & S w/12-i/4" bit from 7862 to 8090'. Right hand walk at 1-1/2: per 100', PU Dynadrill to turn hole back to left. Drilled ' ' . POH to change B~, WIH to 8162' and drilled w/1)yna~ri!t to 8162' ahead 60' to 8222'. Ran single shot survey on wire line, Survey indicated no turn from tool run. Drilled ahead to 8373' and dulled bit. Dropped survey and'POH. Survey 'o~ . Made up Dynadrill w/2 kick sub and indicated 3° of r~oat turn in 151' ~ WIH to 8373', Oriels. ted and drilled 54'. POH w/Dynadrill. Made up g~\ and WIH. Reamed thru Dynadrill run and drld ahead to 8447'. POi{ because of excess torque and left one cone in hole. Made up 11,-3/4" Globe junk basket and WIH. Cut 2-1/2' of core but recovered no junk, Will w/bit and drilling assembly. Milled on junk three hours and made trip for new bit ~26. Drilled on junk three hours, Recovered 4-5 lbs (approx. 75%) of junk 'in junk sub. WIH w/bit ~27 and worked past junk. Pulled bit after 102' because of excess torque. Made up new bit ~/28 and WIii. D & S 12-1/4" hole, Course holding at N72E since 8572', D & S 12-1/4" hole, N73E at 9i05'. Tri, ps for new bits at 8982' & 9105'. D & S 12-1/4" hole. Trips 'for new bit at 9224' - N75E, 9414'-N78E. D & S 12-1/4" hole. Trip for new bit at 9570' - N78E, Do~-a 1-1/2 hours plugging air and cooling water lines for rig down - ~!55. D & S 12-1/4" hole. Trips for new bit at 9696' and 9790'. NS1E at 9790'. Drld 12-1/4" hole 9811 to 10025'. Drld 12-1/4" hole 10025 to 10160'. · Drld 12-1/4" hole 10160' to 10248'. ~ · _ .~...~ . Had tl Drld 12-1/4" hole 10248 to !042~' Trip for new bit ae ~"?~ ght hole at 95S7-9849' 7537-779'~' UNION OIL CO. OF CALIFORNIA DRILLING RECORD SHEET D PAGE NO., 3 .. LEASE. Trading Bay Unit VV-ELL NO. G-32 FIELD l,~cAr.thur River DATE E.T.D. DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS 11/ 3/69 11/ 4/69 11/ 5/69 11/ 6/69 11/ 7/69 · 11/ 8/69 .. 11/ 9/69 1]./10/69 11/11/69 11/1.2/69 li/13/69 10,496 10,510 10,510 10,659 !1,137 11,279 11,424 li,570'TD ll,570'TD 11,570 Drld 12-1/4" hole 10422 to 10496'. Cond. hole for logs. POH. Hole in good condition. RU Schlumberger--ran DIL. Schlumberger TD=10,499'. Ran GR/Density & BHC Sonic TD to 4810'. RD Schl. and Rill w/d.a. Drld 10496 to 10510' & circ. . bottoms up. POll & RU to run 9-5/8" csg. Ran & Cmtd 253 ]ts (10469') 9-5/8", 43.5[; & 47~~, N-80&S-95, N-S, buttress casing at 10510'. Halco DV collar at 7804'. Mix and pump 1500 sx class "G" w/l% CFR-2 cmt thru shoe Bump ~ ~ · pxug & float held. Mix and pump 500 sx class "G" cmt thru DV collar. Close collar & CIP 1:30 p.m., 11/5/69 .~ Remove BOP & riser, NU Cameron casing spool, cut off 'and land 9-5/8". Test spool 3000# ok. NU riser & BOP. 9-5/8" Casing'Detail ! - Top 2.08 41.92 1.50 41.87 2.00 2368.43 248,49 2.08 li45.71 6580.52 41.81 10476.4l 33.59 10510.00 ljt 58 j ~s 6 ]ts 28 j ts 158 j ts 253 j ts B.K.D.B. Halco FI. oat Shoe 9-5/8" 47~? S-95 buttress csg Halco Float Collar 9-5/8" Ditto Halco Side Fill Diff, COllar 9-5/8" Ditto 9-5/8" 47// N-80 buttress csg Halco DV Collar 9-5/8" Ditto 9-5/8" 43.5¥J N-80 Buttress csg 9-5/8" 47~' N-80 buttress csg Final Setting Depth 10,464.50 10,420.63 8,052.20 7,803.71 7,801.63 6,655.92 75.40 33.59 Drill DVCoilar ~ 7802' Side fill collar at 10421' float collar ~ 10z~65' and shoe at 10510'. Making new hole at 8:30 a.m., ]1/6/69. DRill 8-1/2" hole 10510' to 10659' w/trip for new bit at 10621'. Survey at ].0621' 36:45' N89E. PU two 6-1/4" drill collars· Drill 8-1/2" hole w/trip for new bit at !0875'. Survey at 10746' 36: l~90E. Drill & survey 8-1/2" hole w/trip for new bit at !t!37'. Change brake blocks 4 hrs. Drill & survey 8-1/2" hole. Drill & survey 8-1/2" hole. Trip for new bit at 11403'. Hit bridge GIH at 11279'. Drill, ream, and C.O. 11279' to 11359' - 6-1/2 hrs. Wash out 11359- 11403' w/out turning rotary table. Drill 11403' to 11434'/3 hfs and made 6 stand si~ort trip. Had 60' fill after short trip. Drill 8-1/2" hole, w/trip for n.b. at 11468' - no hole trouble. Reached TD 11570' at !0:30 p.m. 11/11/69. Circ. &cond. for logs· RU Schlumberger. Ran DIL to 11,550'. Yool malfunctioned. Ran Density log· . XD Schl R!I{ Tool stopped at 8600'. Re-ran DiL, unable to run below 4600' ~' . w/8-1/8" wash pipe w/shoe and poor boy catcher to fish drill pipe rubbers. Ran to 10520' (10' below 9-5/8" shoe). No recovery. Ran DIL and again was unable to run below 57~0' _~ RD Scht PU DA c7 t ~ ,-- ,_ , :'~0 or · Ran drl~ ~ssembly to !I,.,,0 ': fill indications of junk in hole Circ d to cond. hole and mud. Recovered estimated 4 bb!s free crude oil. >Iud was , UNION OIL CO. OF CALIFORNIA DRILLING RECORD SHEET D PAGE NO LEASE Trading Bay Unit" %YELL NO. G-32 FIELD McArthur River DATE 11/].3/69 (¢ont ' d. ) 11/14/69 11/15/69 11/16/69 Z1/17/69 11/18/69 11119/69 11/20/69 n/21/69 11/22/69 E. T. D. 11,570' 11,570' 1].,205' 11,208 11,208 1].,208 11,208 11,208 11,208 DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS viscous in spots. POH. RU Schl. Ran DIL & Sonic. Ran DenSity and stuck same at 1].458'. Worked same free and POh, Ran drlg assembly. Tight t~o!e at 11,400' No fill on btm. Circ'd out free crude oil & gobs of polymer. Polymer appears to be separating from the mud. Cont'd. to cond mud and hole. P~II. RU Schl. Ran Density, tlRD, & Sidewall Samples. Cond hole for liner. Rigged and ran 20 j ts 7" 29# N-gO buttress liner w/T1W liner hanger. tiung 7" lip. er w/shoe at 11255', float collar at 11208' and top of liner hanger at 1.0408', C~ntd w/225 sx class "G" w/l% CFR-2. Bumped plug w/3000~} floats held ok. CIP at 3:30 a.m.~ 11/15/69. POH. PU drlg assembly w/9-5/8" casfng scraper. Drld cmt from 10350' to top of liner hangec at 10408'. Circ hole cie.an. POH. Picked up 3-1/2" d,p'. 'Rill w/6" bit and casing scraper. Drld firm cement from top of liner hanger at 10408' to 10438'. Dr!d soft cmt from 11.128' to 11208'; top of landing coIlar. Circ'd hole clean. 7" Liner Detail 7" Baker Model "G" Shoe 1 j t. 7" 29# N-SO butt, casing 7" Baker " ' ~ "G" no~e~ Collar 7" TIW Landing Collar 19 j ts. 7" 29# ~-BO butt. casing 7" TIW Liner Hanger Landed below zero 2,39 11,252,72 41.57 i1,211,15 1.72 11,209.43 .85 11,208.58 781.14 10,&27.44 19.44 10,408,00 !Do4o ,oo -0- 11,255.11' Bottom 11,255.11 POli. RU Schl, Attempted to run Ganuma Ray--':ieutron Correlation log. After seven hours of tool malfunction's, rigged dorm Schl. Sent Scl~l. unit & equipment to beach. Down 3 hrs. waiting on Dresser Atlas Unit. RU Dresser Atlas. Ran Gamma Ray-~;eutron Correlation log. from 11208' to 9200'. Perf. 4 holes at 9890'. Set "EZ Drill" bridge plug at ].0265'. Set RTTS tool at 9730', B.D. formation w/3900#. Pumped into formation !0 cu,ft./min, at 3900#. Mixed 150 sx class "G" w/l% CFR-2. Squeezed i10 sx into formation, leaving 40 sx in casing, Haximum pressure 5000#, standing pressure 4900#. Bled to zero. No flow back. CIP 4:45 a.m., 11/17/69. Reversed d.p. clear. POH, PU 8-i/2" bit. WIH to top of cemen~ at 9802', Drilled firm cmt to 9905'. Tested squeeze w/_400.~? ok. Drill. ed EZ Drill bridge plug at 10265' and cleaned out to top of liner at 10408'. POH and cracked bearing on main dra-wworks shaft. Waiting on parts. Waiting on parts. Repaired main shaft on dra,,~¢orks. WIH to ETD at 11208'. Displace mud w/7''':.~; salt water and then spotted 200 bbl. 75# invert emulsion pill on btm for shooting fluid. Dresser Atlas perf 4 holes per foot w/4" casing gun carriers 9364-9370, 9386- 9390, 9424-9428, 9438-9444, 9470-9490, 9506-9516, 9555-9588, 9614-9623, 9630- 9653, 9702-9774, 10540-10571, 10652-10655, 10670-10684, 10695-10697, 10707- 10716, 10725-10727, 10739-10753, 10766-10774, 10848-].0963, 10994-11008, 11013- 11046, 11094-1].120, 11.130-11140'. JC 3:30 p.m., 11/21/69, Lost 30' section of gun in hole. Checked top of gun at 111.78' - did not recover. RD. DA & RU Weatherford oil tools dual tubing tools. Change rams in BOP and start running dual 3-1/2" tubing strings. Ran & landed dual string 3-i/2" N-S ..~.-,; buttress tubing, Lon,;~. Strir~.z - 340 jts (10318') w/O~-is dual ,D;, pkr at 9295' and singlJz wk~ pkr at UNION OIL CO. OF CALIFORNIA DRILLING RECORD SHEET D PAGE NO LEASE Trading Bay Unit VCELL NO. G-32 FIELD McArthur River DATE E.T.D. DETAILS Of OPERATIONS, DESCRIPTIONS & RESULTS 11/22/69 (cont ' d. ) 11/23/69 11,208 11,208 10312'. Short Strfnz - 303 its (9188') w/seal nipple at 9295'. Chase setting balls down w/Otis w.1. unit. Set both pkers and tested ok. N.D. BOP, remove BOP and riser, install & NU Cameron dual tree and test 5D00# ok. Pul.]. ball valves and open "XO'~ sleeve at 10278' and disp. cap. of tubing and volume between pkrs w/diesel, 24,800 gal. Otis closed "XO" sIeeve and turned over to production at 6:00 p.m., 11/23/69. GRAYLING PLATFORM G-32 ~ORKOVER WELL HISTORY PAGE 1 DATE MW ETD COMMENTS 06/05/91 11208' COMMENCED OPERATIONS ON TBUS G-32 WORKOVERAT 1200 HOURS ON 6/5/91. SKID RIG #54 OVER LEG #2, CONDUCTOR #47 AND RIG UP SURFACE LINES. RIG UP SLICKLINE ON THE LONG STRING AND PULL THE SSSV. RUN A 1.625" OD WIRELINE SCRATCHER TO 10445' WLM (TAIL). RIG UP SLICKLINE ON THE SHORT STRING AND PULL THE SSSV. 06/06/91 11208' RAN A 1.625" OD WIRELINE SCRATCHER AND SET DOWN AT 8480' WLM. PULLED OUT OF HOLE AND RIGGED DOWN SLICKLINE. RIGGED UP 1.25" COILED TUBING UNIT ON THE LONG STRING. MADE UP 1.5" OD MUD MOTOR AND 1.59" OD MECHANICAL TUBING CUTTER ON 1.25" OD COILED TUBING. PRESSURE TESTED THE LUBRICATOR TO 3000 PSI. RAN IN AND SET DOWN AT 4100' CTM. TRIPPED TO CHECK TOOLS - KNIFE BLADE RELEASED EARLY. RAN IN AND SET DOWN AT 4446' CTM (GLM #5). TRIPPED TO CHECK TOOLS - OK. RAN IN WITH CUTTERTO 10200' CT}{. ATTEMPTED TO CUT TUBING FOR 4.5 HOURS. TRIPPED TO CHECK TOOLS - LEFTMUD MOTOR AND CUTTER IN HOLE (CT ADAPTER FAILED). PUMPED DOWN THE LONG STRING CHECKING FOR RETURNS ON THE SHORT STRING - NO RETURNS. RIGGED UP COILED TUBING ON THE SHORT STRING FOR A CLEANOUT RUN WHILE WAITING ON NEWMUD MOTORS. 06/07/91 11208' MADE UP A 1.4" OD WASH TOOL ON 1.25" OD COILED TUBING. PRESSURE TESTED THE LUBRICATOR TO 3000 PSI. RAN IN WITH COILED TUBING AND TAGGED FILL AT 8501' CTM. WASHED FILL FROM 8501' TO 8511' CTM (PUMPING DOWN THE COILED TUBING AT 0.5 BPM, PUMPING DOWN THE 3 1/2" X CT ANNULUS OF 1.3 BPM.). PICKED UP TO CHECK DRAG AND HAD 4000# OVERPULL FROM 8511' TO 8130' CTM. WORKED BETWEEN 8400' 8030' CTM ATTEMPTING TO CLEAN UP THE HOLE. PULLED OUT OF HOLE. RIGGED UP COILED TUBING ON THE LONG STRING. MADE UP MUD MOTOR AND MECHANICAL TUBING CUTTER. RAN IN HOLE TO 10210' CT}{. PULLED UP TO 10200' CTM AND CUT THE LONG STRING AFTER 2 HOURS OF ROTATING. PULLED OUT OF HOLE TO CHECK TOOLS - LEFT MUD MOTOR AND. CUTTER IN THE HOLE (CT ADAPTERFAILED). PULLED OUT OF HOLE WITH COILED TUBING. CHANGED BOTH TUBING STRINGS AND THE "G" ZONE OVER TO 3% KCL/FIW BRINE. RIGGED UP WIRELINE ON THE LONG STRING. RAN IN WITH TUBING PUNCH AND SET DOWN AT 5631' WLM. TRIPPED TO CHECK TOOLS AND HUNG UP AT 5410' WLM. WORKED TOOLS FOR 30 MINUTES AND CAME FREE. 06/08/91 11208' RECEIVED AU G t 9 1991 Alas~ Oil .& Gas Cons. Com~ss'~e~ 'Anchorage CIRCULATED DOWN THE LONG STRING TAKING RETURNS ON THE ANNULUS. CHANGED OVER ANNULUS TO 3% KCL/FIW BRINE. INSTALLED BACKPRESSURE VALVES AND REMOVED THE PRODUCTION TREE. NIPPLED UP BOPE AND TESTED SAME TO UNOCALSPECIFICATIONS (TEST CSO RAMS AND KELLY ON FIRST TRIP OUT). PULLED BACK PRESSURE VALVESAND INSTALLED THELANDING JOINTS. RIGGED UP DUAL SLIPS AND ELEVATORS. PULLED 185K AND PRODUCTION STRING STARTED TO MOVE. CHECKED INDIVIDUAL STRING WEIGHTS - LONG STRING WAS 20K LIGHTER THAN THE SHORT STRING. WELL TAKING 1 BPM OF FLUID. SPOTTED A 50 BBL SIZED SALT PILL DOWN THE SHORT STRING. DATE 06/09/91 06/10/91 06/11/91 06/12/91 GRAYLING PLATFORI~ G-32 WORKOVER W-wr.r. HISTORY PAGE 2 ETD COMMENTS 11208' CIRCULATED TO BALANCE THE WELL AFTER PUMPING THE SIZED SALT PILL. PULLED OUT OF HOLE LAYING DOWN THE DUAL 3-1/2" GAS LIFT COMPLETION. RECOVERED ENTIRE SHORT STRING TO THE COLLET ASSEMBLY ABOVE THE DUAL PACKER. RECOVERED THE LONG STRING TO 5414.5' TM. RIGGED DOWN TUBINGHANDLING EQUIPMENT. CHANGED THE TOP PIPE RAMS TO 5" BLOCKS. 11208' PRESSURE TESTED THE TOP PIPE RAMS, CSO RAMS, KELLY COCKS, AND STANDPIPE VALVE TO 300 PSI (LOW) AND 3000 PSI (HIGH). MADE UP 7 5/8" OD OVERSHOT WITH A 3 7/8" BASKET GRAPPLE AND RAN IN HOLE. ENGAGED FISH AT 5414' DPM. JARRED ON FISH WITH 130K OVERPULL FOR 1 HOUR AND PACKER SHEARED LOOSE. PULLED UP 15' AND JARRED AT 100K OVERPULL FOR 30 MINUTESAND FISH CAME FREE. CIRCULATED WELL CLEAN. PULLED OUT OF HOLE SLOW TO THE TOP OF FISH. RIGGED UP TUBING HANDLING EQUIPMENT. LAID DOWN FISH INCLUDING 5 GLMS, DUAL PACKER, AND LONG STRING TUBING TO THE CUT AT 10184' TM. MADE UP A 7 5/8" OD OVERSHOT WITH A 3 1/2" BASKET GRAPPLE ANDRAN IN HOLE. 11208' CONTINUED RUNNING IN HOLE WITH OVERSHOT ASSEMBLY AND SET DOWN AT 9431' DPM. CIRCULATED AND WORKED THROUGH THE TIGHT SPOT. CIRCULATED BOTTOMS UP FROM 9471' DPM - HAD SOME GAS AND SALT PILL MATERIAL. CONTINUED RUNNING IN HOLE AND SET DOWN AT 10169' DPM. WASHED DOWN TO THE TOP OF FISH AT 10183' DPM. CIRCULATED BOTTOMS UP. WASHED DOWN AND ENGAGED FISH AT 10205' DPM. JARRED ON PACKER ONE TIME WITH 100K OVER-PULLAND FISH CAME FREE. CIRCULATED WELL CLEAN. PULLED FIVE STANDS - PACKER SWABBING. CIRCULATED AND WORKED PACKER TO WEAR DOWN ELEMENTS. PULLED ANOTHER FIVE STANDS - STILL SWABBING. CIRCULATED AND WORKED PACKER. PULLED OUT OF HOLE SLOW TO PREVENT SWABBING. CHECKING FILL UP. PACKER HANG UP AT WEAR BUSHING. DRAINED THE BOP STACK - FOUND A 1" X 15" PRESSURE BOMB WEDGED BETWEEN THE PACKERAND WEAR BUSHING. LAID DOWN THE BALANCE OF THE COMPLETION. CLEARED THE RIG FLOOR. MADE UP AN 8 1/2" BIT AND RAN IN HOLE TO THE LINER TOP AT 10410' DPM. CIRCULATED WELL CLEAN. 11166' CIRCULATED BOTTOMS UP. TRIP FOR LINER CLEAN OUT ASSEMBLY. MADE UP SHOE AND CATCHER SUB ON 3-1/2" DRILL PIPE. RAN IN HOLE ON A TAPERED DRILL STRING AND TAGGED FILL AT 11050' DPM. CLEANED OUT FILL FROM 11050' TO 11166' DPM. CIRCULATED BOTTOMS UP. TRIP TO CHECK TOOLS-LEFT 5-7/8" ROTARY SHOE IN HOLE. RAN IN HOLE WITH A 5-7/8" OD CONCAVE MILL AND JUNK SUB AND TAGGED AT 11,166' DPM. RECEIVED 2 9 1991 Oil & Gas Cons. Commission Anchora,cje GRAYLING PLATFORM G-32 ~ORKOVER W~.L HISTORY DATE MW 06/13/91 ETQ 11169' 06/14/91 11169, 06/15/91 11168' 06/16/91 11168' RECEIVED PAGE 3 COMMENTS MILLED ON JUNK FROM 11166' TO 11169' DPM. PULLED OUT OF HOLE TO CHECK MILL. MILL SHOWED SOME FACE WEAR AND JUNK SUB WAS FULL OF METAL. MADE UP 9- 5/8" RTTS PACKER AND RAN IN HOLE ON 5" DRILL PIPE TO 9350' DPM. SET PACKER AND PRESSURE TESTED CASING TO 3000 PSI. PULLED OUT AND LAID DOWN THE RTTS PACKER. RIGGED UP WIRELINE. RAN IN WITH A 9- 5/8" EZSV WITH BRIDGE PLUG KIT AND SET DOWN AT 9300' WLM. WORKED THROUGH THE TIGHT SPOT. RAN CCL LOG TO CORRELATE THE EZSV. STUCK THE EZSV AT 9327' WLM. SET THE RETAINER TO RELEASE THE SETTING TOOL. PULLED OUT OF HOLE AND RIGGED DOWN WIRELINE. PICKED UP AN 8-1/2" BIT. RAN IN AND DRILLED THE RETAINER. PUSHED THE JUNK TO THE LINER TOP AT 10407' DPM. TRIPPED FOR A 5-7/8" CLEAN OUT ASSEMBLY. PICKED UP A 5-7/8" CONCAVE JUNK MILL. RAN IN AND TAGGED THE RETAINER JUNK AT 10407' DPM. WORKED JUNK INTO THE LINER TOP AND PUSHED SAME TO 11168' DPM. CIRCULATED BOTTOMS UP. PULLED OUT OF HOLE ANDLAID DOWN MILLING ASSEMBLY. RAN 8-1/2" BIT AND 9-5/8" CASING SCRAPER TO THE LINER TOP AT 10410' DPM. PULLED OUT AND LAID DOWN BIT AND SCRAPER. RIGGED UP WIRELINE. RANJUNK BASKET AND GAUGE RING TO THE LINER TOP. MADE UP AN EZSV WITH A BRIDGE PLUG KIT. RAN IN HOLE WITH AN EZSV WITH BRIDGE PLUG KIT ON WIRELINE. LOCATED THE EZSV AT 9412' DIL. ATTEMPTED TO SET THE RETAINER-SHORT IN THE SETTING TOOL. TRIPPED TO REWIRE THE SETTING TOOL. RAN IN AND SET THE EZSV AT 9412' DIL. PULLED OUT AND RIGGED DOWN WIRELINE. MADE UP AN EZSV ON 5" DRILL PIPE AND RAN IN HOLE. TAGGED THE EZSV/BP AT 9417' DPM. PULLED UP TO 9295' DPM AND SET THE RETAINER. UNSTABBED FROM THE RETAINER AND BROKE CIRCULATION. RIGGED UP HOWCO SURFACE CEMENTING LINES. ESTABLISHED A BREAKDOWN ON THE G-06 PERFORATIONS FROM 9364'-9370' DIL AND 9386'-9390' DIL AT 2900 PSI. INJECTED 2 BPM AT 2800 PSI. SQUEEZED THE PERFORATIONS WITH 250 SACKS CLASS "G" CEMENT WITH ADDITIVES AS PER THE SQUEEZE REPORT DATED 6/15/91. CEMENT IN PLACE AT 1130 HOURS. UNSTABBED FROM THE RETAINER AND PULLED 5 STANDS. RIGGED DOWN SURFACE LINES AND LEVELED THE DERRICK. PULLED OUT OF HOLE AND LAID DOWN THE SETTING TOOL. TEST BOPE TO UNOCAL SPECIFICATIONS. FINISHED TESTING BOPE. MADE UP A 8-1/2" BIT AND RAN IN HOLE. TAGGED FIRM CEMENT AT 9282' DPM. DRILLED FIRM CEMENT FROM 9282' TO THE RETAINER AT 9295' DPM. DRILLED THE RETAINER AT 9295' DPM AND HARD CEMENT TO THE RETAINER AT 9417' DPM. DRILLED THE RETAINER AT 9417' DPM AND PUSHED THE JUNK TO THE LINER TOP AT 10407' DPM. CIRCULATED WELL CLEAN AND TRIPPED FOR A 5-7/8" CONCAVE JUNK MILL. RAN IN AND TAGGED RETAINER JUNK AT 10407' DPM. MILL ON RETAINER JUNK TO WORK SAME INTO THE 7" LINER. DATE 06/17/91 06/18/91 06/19/91 ETD 11163' 11163' 11160' GRAYLING PLATFORM G-32 WORKOVER W-~J. HISTORY PAGE 4 COMMENTS CONTINUED TO MILL ON RETAINER JUNK TO WORK SAME THROUGH THE LINER TOP AT 10407' DPM. PUSHED JUNK TO 11163' DPM. CIRCULATED WELL CLEAN. PULLED OUT AND LAID DOWN 4-3/4" DRILL COLLARS AND MILLING ASSEMBLY. MADE UP A 9-5/8" CASING SCRAPER ON 5" DRILL PIPE AND RAN IN HOLE TO THE LINER TOP AT 10407' DPM. TRIP FOR A 7" CASING SCRAPER. MADE UP A 7" CASING SCRAPER ON A TAPERED DRILL STRING AND RAN IN HOLE TO 11150' DPM. CLEANED OUT FILL TO 11,159' DPM ETD. CIRCULATED WELL CLEAN. MIXED AND PUMPED "DIRT MAGNET" SPACER. DISPLACED WELL BORE WITH CLEAN 3% KCL/FIW BRINE SHIPPING RETURNS TO TRADING BAY UNIT ONSHORE FACILITY. CLEAN ACTIVE SYSTEM. CIRCULATED AND FILTER FLUID. CONTINUE TO CIRCULATE AND FILTER FLUID TO LESS THAN 48 NTU AT THE FLOWLINE. SHIPPED 190 BBLS OF DIRTY FLUID TO TRADING BAY UNIT ONSHORE FACILITY. PULLED OUT AND LAID DOWN BIT AND SCRAPER. MADE UP HOWCO TEST HEAD. MADE UP TUBING CONVEYED PERFORATING ASSEMBLYANDRAN IN HOLE ON A TAPERED DRILL STRING. LEFT ENOUGH PIPE DRY TO ACHIEVE A 700 PSI DRAWDOWN DURING PERFORATING. PLACE GUNS ON DEPTH BY DRILL PIPE. RIGGED UP WIRELINE. RAN GAMMA RAY CORRELATION LOG. SET THE PERFORATING PACKER AND RAN A CONFIRMATION LOG. RIGGED DOWN WIRELINE. RIGGED UP AND TESTED SURFACE LINES TO 3000 PSI. SHOT A FLUID LEVEL TO CONFIRM UNDERBALANCE. DROPPED THE FIRING BAR. GUNS FIRED AFTER 2 MINUTES 14 SECONDS. PERFORATED THE WEST FORELAND AT 8 HPF WITH 25 GRAM DEEP PENETRATING CHANGES IN 4-5/8" CARRIERS AS FOLLOWS: WF-1 10536'-10571', 10588'- 10601', 10610'-10622'; WF-2 10648'-10655', 10668'- 10684', 10703'-10727', 10739'-10760'; WF-3 10760'- 10785'; WF-4 10825'-10963'; WF-5 10994'-11046'; WF- 6 11094'-11135' (ALL DEPTHS DIL). WELL HAD A RAPID FLUID RISE FOLLOWING PERFORATING. RELEASED THE PACKER AND REVERSED TWO DRILL PIPE VOLUMES. CIRCULATED ONE HOLE VOLUME THE LONG WAY. WELL TAKING 30 BPH OF BRINE. MIXED AND PUMPED A 50 BBL SIZED SALT PILL. SQUEEZED AWAY 12 BBLS AND FLUID LOSSES STOPPED. PULLED OUT OF HOLE WITH THE TCP GUNS-ALL SHOTS FIRED. MADE UP A 6" BIT AND SCRAPER. RAN IN AND TAGGED FILL AT 11152' DPM. CLEANED OUT TO 11160' DPM ETD. CIRCULATED WELL CLEAN. TRIPPED FOR AN ISOLATION PACKER. MADE UP A 7" OTIS "BWH" PERMANENT PACKER WITH A 10' X 3- 1/2" PUP, "XN" NIPPLE, AND REENTRY GUIDE TAIL ASSEMBLY. RAN IN HOLE ON DRILL PIPE TO 10425' DIL. DROPPED THE SETTING BALL AND WAITED ON SAME TO FALL. RECEIVED AUG 2 9 1991 ~aS~1 .Oil & Gas Cons. Commissien /tnchorage DATE 06/20/91 06/21/91 06/22/91 06/23/91 ETD 11160' 11160' 11160' 11160' GRAYLING PLA~FOI~G-32 WORKOVER WR~z. HISTORY PAGE 5 SET 7" OTIS "BWH" PACKER AT 10425' DIL. TESTED THE PACKER FROM THE BACKSIDE TO 500 PSI. SHEARED OFF THE PACKER AND TRIPPED FOR AN ISOLATION PLUG. MADE UP ANOTIS "JP" PLUG ON DRILL PIPE. RAN INAND SET THE PLUG IN THE ISOLATION PACKER. SPOTTED SIX SACKS OF FRAC SAND AT THE END OF THE DRILL PIPE. PULLED UP TO 10,000' DPM. LET SAND SETTLE FOR ONE HOUR. CIRCULATEDAND FILTERED FLUID TO65NTU'S AT THE FLOWLINE. TRIP FOR TCP GUN ASSEMBLY. MADE UP 6", 8 HPF, 25 GRAM CHARGE TUBING CONVEYED GUN ASSEMBLY AND RAN IN ON 5" DRILL PIPE. PIPE WAS FILLING ON ITS OWN. PULLED OUT OF HOLE LOOKING FOR A LEAK. FOUND BAR PRESSUREVENT LEAKING. REPLACED BAR PRESSURE VENT AND RAN IN HOLE. CONTINUED RUNNING IN WITH TCP GUN ASSEMBLY. RIGGED UP WIRELINE. RAN GR/CCL CORRELATION LOG. SETTHE PERFORATING PACKER AND RAN A CONFIRMATION LOG. RIGGED DOWN WIRELINE. DROPPED THE FIRING BAR AND PERFORATED THE FOLLOWING G-ZONE INTERVALS: G-l, 9420'-9444'; G-2, 9465'-9490'; G-3, 9542'-9588'; G- 4, 9607'-9623'; AND G-5 9697'-9774' (ALL. DIL MEASUREMENTS). REVERSED DRILL PIPE CLEAN. WELL TAKING 23 BPH OF BRINE. SPOTTED A SIZED SALT PILL TO CONTROL FLUID LOSS. PULLED OUT OF HOLE ANDLAID DOWN TCP GUN ASSEMBLY (ALL SHOTS FIRED). RAN IN HOLE WITH A "JP" PLUG RETRIEVING TOOL. CIRCULATED OUT EXCESS SALT PILL AND SAND DOWN TO THE PLUG. LATCHED THE PLUG AND PULLED OUT OF HOLE. CONTINUED TO PULL OUT OF HOLE AND LAID DOWN "JP" PLUG. MADE UP A 9-5/8" OTIS "BWH" PERMANENT PRODUCTION PACKER WITHANS' SEAL BORE EXTENSION ON 5" DRILL PIPE. RAN IN HOLE AND SET THE PACKER AT 9280' DPM (9275' DIL). TESTED THE BACKSIDE TO 500 PSI. SHEARED OFF THE PACKER AND TRIPPED OUT OF HOLE. CHANGED THE TOP PIPE RAMS TO 4-1/2" BLOCKS AND TESTED SAME. RIGGED UP TO RUN 4-1/2" SINGLE GAS LIFT COMPLETION. RAN IN HOLE WITH THE COMPLETION HYDROTESTING TO 5000 PSI. FINISHED RUNNING SINGLE 4-1/2" GAS LIFT COMPLETION. SPACED OUT WITH THE STRAIGHT SLOT LOCATOR 18" ABOVE THE PERMANENT PACKER. LANDED THE TUBINGHANGER (4- 1/2" EU 8RD TOP & BOTTOM) WITH THE TUBING TAIL AT 9370' TM, LOCATOR AT 9279' TM, XA AT 9238' TM, AND SSSV AT 303' TM. PACKED OFF AND TESTED HANGER. TESTED PACKER SEALS TO 500 PSI. INSTALLED AND TESTED PRODUCTION TREE. RELEASED RIG TO TBUS G-~ WORKOVER AT 2400 HOURS ON 6/23/91. RECEIVED AUG 2 9 991 :Oil :& Gas Cons. Commissieu Anchorage A! RKB = 0.00' TBS HGR ~ 42.80' L 0.,.% 12 WALL @ 497' / J-55 @ 4810' i G 2 9 1991 Gas Cons. ~ommissiO~ Rnchorage 7" TOL ~ 10408' 9-5/8" 43.5 & S;~. 1~ 14 N-80 & S-95 @ 10510' 7" 29# N-80 ~lm ' '''''L @ 11255' 11 TUBING DETAIL: 4--1/2", 12.6#, L-80 TDS TUBING WITH SPECIAL CLEARANCE CPLGS 1) ,~-1/2 EU 8RI) PIN x 4-1/2 TBS PIN X-OVER 2) OTIS SSSV NIPPLE W/BXE BALL VALVE ~ 303.62' 3) PTA 'DSO' C, ASLFT UANDR~S AS FlU.OIl/S: gLId ~1 · 2242.24' MD GLIJ #2 · 3710.62' MD OLId 1~3 0 5100.26' MD GLU l~4 · 6175.11' MD GLU d~5 0 7052.06, MD OLM ~6 · 7732.77' MD GLU ~7 · 8333.74' MD GLM ~8 · 8776,86' MD GLU #9 · 9220.15' MD 4) OTIS "Y.A" SLIDING SLEEVE 0 9237.86, 5) ONE (1) dOINl' 4-1/2' CUlT TUBING 6) 5" OD SEAL AS~f W/ STR SLOT LOCATOR · 9278.04' (4--1/2 BUTT BOX-UP x PIN-DOWN) 7) ONE (1) JOINT 4-1/2" BUTT TUBINe 8) OTIS "X" LANDINg NIPPLE · 9329.25' 9) ONE (1) ,JOINT 4-1/2" BU1T TUBING 10) WIRELINE RE-E~ GUIDE · 9370.45' (BOTTOM) 11) OTIS 9-5/8" "BWH" PERM PKR AT 9275' OIL ~2) OhS ~-~/2- "XN" · ~0436, OL ~) W~EUNZ RE-ENTRY mJ~O£ · ~04=6, OL (eorrou) 14) OTIS 7" "BWH" PERM PKR AT 10428' OL "g '* ZONE PERFORATIONS 9364'- 9370' SQZD - PROD 9386'- 9390' SQZD - PROD 9465'- 9490' OPEN - PROD 9504'- 9516' OPEN - PROD 9542'- 9588' OPEN - PROD 9607'- 9623' OPEN - PROD 9630'- 9653' OPEN - PROD 969?- 9774' OPEN - PROD WEST FORELAND PERFORATIONS 10536'- 10571* OPEN - PROD 10588'- 10601' OPEN - PROD 10610'- 10622' OPEN - PROD 10648'-' 10655' OPEN - PROD 10668'- 10684' OPEN - PROD 10695'- 10697' OPEN -- PROD 1070;]'- 10727' OPEN - PROD 10739'-10785' OPEN - PROD 10825'- 10963' OPEN - PROD 10994'- 11046° OPEN - PROD 11094'-- 11150' OPEN - PROD WELL TBUS G-32 COMPLETION ( 6-23-91 ) UNION OIL COMPANY OF CALIFORNIA(dbo UNOCAL) DRAWN: DAC SCALE: NONE DATE: 8-8-91 ; T REPOR and PLAN of SUB-SURFACE SURVEY UNION OIL COMPANY T.B'U. G-32' COOK INLET, ALASKA JOB NO.. DATE NOVEMBER 1969 DRILLING CONTROL CORPORATION LONG BEACH, CALIFORlgIA . DRILLING CONTROL CORP. · SHEET NO., ' SURVEY DATA SHEET ~ .. · COMPANY Union Oil Cc~any'' , ., ,. DATE · November 1969 JOB NO. . WELL T,B.U, 'G-32 FIELD· Cook IDler ' ' COUNTY. ' "sTATE, Alaska [ " NIEASURED DRIFT TRUE DEVIA~ON DPJi=T RECTANGULAR COORDINATES . DEPTH ANGLE VER~CAL COURSE DIREC~ON , , , -~ DEPTH ' - . NORTH SOUTI{ EAST - WEST , , ,, -. - i~ - [ *.r''' "~" 500 ' 500 00 · ' .': ASS ~VERTIC~, ' ' ' , .' · :' ''~ '' ' ' ' 15 · '' 32 530 . 0° 40' " 530 00 35'.., :~' S'65°.W ~.-. :' . . 680 0° 35, 680 00 1 53 N 64° W ... , 52 1 69 831 0° 15' 831 00 66 S 81° W 42 2 34 ~ 1043 0o 20, 1043 00 1 23 N 05° E 1 65 I 2 23 · · 1258 0° 10' 1258 00 63 '~ .N 59° E ' '.97 . 1 69 :! ,. 1509 0° 30' 1508 99 2 19 N 30© W 2 87 2 79 ' , 1725 0° 20' 1724 ,99 1 26 N 81° E 4 07 . 1 55 · 2034 0° 20' 2033 99 1 80 S 85° E 3 91 ~ 24 · ~ 2337 0° 20: 2336 98 1 76 S 55° E 2 90 1 68 · ~2647 0° 30' 2646 97 2 71' S 74° E 2 15 4 29 2989 0° 45' 2988 94 4 48 S 55° E ' 42 7 96 3060 0© 45' 3059 93 93 N 08° W 50 7 83 3124 2° 15' 3123 88 2 51 N 05° W 3 00 7 61 %~'/ 3186 3° 45' 3185 75 4 05 N 05° E . 7 03 ' - 7 96 3250 5° 15' 3249 48 5 86 'N 25° E 12 34 10 44 · 3405 9° 00' 3402 57 24 25 N 320 E 32 91 23 29 .. 3591 14° 00' 3583 05 45 00 N 36°~E 69 32 49 74 3811 19© 15' 3790 75 72 53 N138° E 126 47 ' 94 39 , 4029 24° 15' 3989 51 89 54 N'41° E 194i05 - 153 13 · 4248 29© 15' 4180 59 '107 01 N 43° E' 272'31 226 11 4605 30© 45' 4487 40 182 53 . N 44° E 403 61 ~ 352 91 4821 30© 15, 4673 99 108 8t N 46° E , 479 20 431 18 , 5082 29° 00' 4902 27 126.54 N 48° E 563 87 525 22 ' · ~-~ 5345 28° 15' 5133 95 124 48 N 49° E ~ 645 54 619 16 , : : i.' ? ' : - ' · ,: ,: · ' . , . : . , , , DRILLING CONTROL CORP. ~E£y ~o.~ 2 SU~VZY DA?~ 81rlz? ., . - . COMPANY ,.. Union Oil Cc~p~y .' , · DATE.' Noven~oer 1969 jos NO. WELt T.B.U. G-32 FIELD ,Cook..,Inlet , BOUNTY ~_ '_. ~ STATE, Alaska TRUE DEVIATION DBiFT RECT~G~R COORDINATES .. . MEASURED DRITT VERTICAL REMARK~ DEFI~ ANGLE COUP, S~ D~N DEFI~ . , NORTH SOUTH EAST WEST : - 5636 29° 30' 5387'23 143' 29 · N 51° E · 735 71 . . . 730 52 , 6012 30° 15' 5712 03 '189 42 .- N.56° E' 841 63 . 887 56. 6241 29° 30' 5911 34 112 76 N 60° E 898 01 985 21 · 6361 26° 15' 6018 96 53 07 N 55° E ~' 928 45 ' · 1028 68 6484 24° 15' 6131 10 50 52 '~ N 55° E 957 43 1070 06 · . 6626 24° 15' 6260 57. 58 32 N 59° E 987 47 , 1120 05 . 6825 28° 00' 6436 28 93142 ' N 63° E- 1029 88 1203 29 6952 27° 00' 6549 44 57 66 N 56° E 1062 12 1251 09 . · ,, 7126 28° 00' 6703 07 81!69 N57° E 1106 61 1319 60 7432 33° 15' 6958 97 167 78 N 60° E 1190 50' 1464 90 . . 7674 33° 15' 7161 35 132 69 '.N 63° E· 1250 74 · 1583 13 7862 34° 50' 7,316 29' 106 49 , N 63° E 1299 09 1678 01 · 8090 33° 15, 7506 96 125 01 ~ N 66° E 1349 94 1792 21 · 8222 30° 15, '7620 99 '66 50 N 67° E 1375 92 1853 42 · '. ~'/ 8373 31° 00~ 7750 43 77 77. ·N 70° E 1402 52 , 1926 50 . . 8449 29° 30' 7816 58 37 42' N 71° E 1414 71 1961 86 8572 28° 00' 7925 18 57 74 ·N 72° E - 1432 55 2016 77 8796 29° 15' 8120 62 109 45 N 72° E 1471 37 2120 86 8982 31° 00' 8280 05 95 90 N 72° E 1500 97 2211 97 9105 31° 00' 8385 48 63 35 N 73° E~ 1519 49 2272 55 · -. 9224 30° 15' 8488 28 59 95 N 75° E .1535 01 ~ 2330 46 9416 30~ 30' 8653 71 97 44 N 78° E 1550 27 2425 77 '. 9570 31° 45' 8784 66 81 04 I N 78°. E 1567 12 2505 04 · 9696 31° 45' 8891 80 66 30 N 81° E 1577 49 ·'2570' 52 r~ '. 9939 32° 00' 9097 88 128 77 N 83° E ~ 1593 18 ' · 2698 33 · DRILLING ~CONTROL· CORP. SHEET NO. SURVEY DATA 8HE~.T . ' - . · COM,ANY , Union OiI Ccmpany' ,' - , DATE November 1969 ' Joe NO. ' WELL T.B.U G-32 FIELD Cook Inlet: " COUNTY . ' ' 8TATE. . ""~aska ' .,,'. MEASURED DRIFT TRUE DEVIATION DRIFI' ' . 'RECTANGULAR COO~ATF~ I · . VERTICAL COURS~ D]RZCTION · , , " ,,, , 'REMARKS DEPTH ANGLE DEPTH ' . NOI~TH SOUTH EAST WEST :, , 10,280 34° 15' 9379 75 , 191 91 - N 86° E 1606 57 · 2889 77 · 10,621 36° 45' 9652 98 204 03 'N 89° E 1610 13 . . 3093 77 -' ,. :' ., 10,746 36° 00~ 9754 1i 73 47 EhST 1610 13 3167 24 · .11,006 37° 00' 9961 75 ·156 47 S 85° E · 1596 49 3323 11 . · · ' · 11,221 36© 15' '10,135 13 127 13 S 84° E -i 1583 20 3449 54 '·11,403 36° 00' 10,282 37 106 98 S 81° E ' ·1566 47 3555 20 · 11,570 36° 00' 10,417 47 98 16 .' S_81o E ,1551 12 3652 15 CI_DS~ 3967.t26' N 66° 59' E FOR: \ \ \ \ \ \ · COU ~1~ $_ - ~TE OF SURVEY OC'?OT~'fi~9. 9 _ '~ 9~%9 .:' ,~ ~""'q ~ ~'~'~ ',. ,: ..... · ~ I .... ~ c~ ~'~ ?~ '* ' ' · · ..... -._:: ?./ :(.',,,':~,'?( ::.'. ,::.... · . -,:.,..~...: :-;.(.~/ ::.'"'--.,....-.,,:::,:,;: ,,. :: ..... . - . .:,'. : :_? . '. -- ,. - . : :. .. ,~',EASURED D E_._V_._I._A .... ~..! .q_N_ _.. ............................................. ~O_TAL_ C_O_ORD.!iNATES ............. _C.._L .0 S ....U. R E..S ........... DOG LEG"SECTION .... DEPT_H ........ ANGLE ......Q_!_RE.C.T.!.C.N TVD ........... ~._UB_.S__~_A ........ k_A _T! T U_ . P_ _E __ D:~P~_R~UR__E ...... D_!._s]'ANCE ....... AN.G_L.E ....... SEVERIT_Y_.___D_!.S'FANCE. ORIGIN .... LOCATED AT MD : 0.00 500 0 O' S OE 50 530 0 40' S 65W 52 . 680 ........ 0 35' 831 0 15' S 81W 83 1043 0 20' N 5E 104 1258 0 10' N 59E 125 , TVD = O. O0, 0.00 401,00 9.~9 ....... 430.99 0.98 731,98 2.98 943,98 7,98 1158,98 LATITUDE : 0.00, DEPARTURE : 0.00 o~Oo o.oo ........... O.oO .......... o.'oo ....... o,ooo 0.i4s 0131W 0.34"-~ .... 65.00W ........... 2,222 .... 6','52N ........ i.-68W ................. 1.'76'N-'72.82W ........ 0.362 0.41N 2.33W ............. 2,37'N' 79.85W .......... 0,268 1.64N ........ 2~23W .......... 2,77"-N'53.56W ............ 0.218 --1.96N 1,69W 2,.59 N 45'~73W 0,'-'i26 8.97 ...... I409.97-' 3.86N ....... 2.79W .............. ~.'75' N'35.a2w ........... 0.208 4~97 ...... 1625'9'7 ............ ~"06N .... I"55W 4,34-N'20.asw .......... 0.320. 3.96 ...........1934.96 3,90N ........... 0.-24E ...... 3,91N'- 3'.52E ............. 0.026 6.96 ............. 2237.96 2.89N ............ 1'.68E .......... 3',34-'N"30.19E ........... 0.056 6.94 ......... 25~.94 ............... 2.'14N ............ ~-~'2'8E ........ ~ .... 4.79- N 63',35E .......... 0,069 8,91 2889,91 0,41S --7,95E --7.96 S 86,99E .... 0~-094 0.00 -0,34 -1.35 -I .98 -t .41' -0.79 -i .05. 0.16 !o74 2.68. 4.78 . 39 0 30' N 30W 150 IN""/~25 ...... 0 20' ........ N -8 lE ................. 1 72 2034 0 20' S $5E 203 2337 0 20~ S 53E 233 2647 0 30~ S 74E 264 2989 ............... 0 .45' ........... S .... 55E ............. 298 ..... ~ 3060 0 45' N 8W 3059.91 2960,91 5124 .............2 15' ........... N ...... 5W ....... 3123.86 ...... 302~.86 3186 3 45' N 5- 3185,73 3086,73 3250 5 15' N 25- 3249,46 3150,46 3405 9 O' N 32- 3402,55 3303.55 3591 14 O' N 36- 3583.02 3484.02 0.50N 7.82E ........... 7.83--N-'86.32E ......... 1.937 .......... 7. 3.00~-" ..... 7.60E ............... 8.17 N 68.43E ............. 2.346 ............... 8. 7.04N 7.95E 10.62 N 48.47E 2.553 lO. 1.2.35N ......... fOo43E ........ 16.16 N'-40.18E ...............3.358 32.91N ...... 23.28E ........... 40,31N-35.27E .......... 2.478 3311 19 15' N 38- 379 .4029 ........... 2~...[5' N 4~- 398 4248 29 15' N 43: 418 4505 30 45' N 44E 448 ~'"~1 30 15' N 46E 467 -'")~,,.,~2 29 O' N 48E ~'90 ~345 ....... 2a 18" ......... N 49E ..... S~3 5636 29 30' N 51E 538 6012 30 15' N 56E 571 6241 6361 0.72 9.49 ......... 3890'49 0.56 ..... ~o8~,'56- 7.37 ............ 4388.37 3.'96 .......~574.96 2,24 480'3,24 3,9! 5034,91 3691.72 126.47N 94.38E 15 .81N 36 73E 2 400 t3& 194.04N "~i53.12E ......... 247.18'-N-"38.27E ......... 2.348 ........ 2Ih. "272.30N ..... 226~!0E ....... 353.94--N 39.70E ......... 2.319 ....... 3~4. 403,61N 352.90E .......... 536,13''N-41.16E ...... 0.442 ........ 482. 47~,20N ........ 431,I7E-~ ........ 644.6.3 N' 41';98E ......... 0.523 ...... 584. 563.87N 525.21E 770.58 N 42.96E 0.610 '703. 645,53N .......... ~19,16E ..... 894.47 N 43.80E ............ 0.338 .......... 822. 7.19 ......... 5288,'-19 ........ 735",-71N .......... 730,52E ..... 1'036,79' N"44.79E ........... 0.542 ...... 959. 1.99 ..... 5612.9.9 84'i-",6'3N~ .... 887'.-55E-~>~-1223~-15~-'N--"46.52E ............ 0.691 ----1145~ 29 30' ....... N .... 60E .... '591'1"30 ........ 5'812,30 898,'02N ..... 985'.-2'1E ..........i333.0'7-'N~-'~'/.65E .......... 0.929 ..... 1-25;~ ...... 26 .... i5" ......... N--55E .......... 6018.92 ........ 591'9-; 92 928-';'4'6 N- ....... 1028,69E ........ i385,73""-N- 47.93E ........... 3.334 ....... 1309. 6484 24 15' N 55E 6131.07 6032,07 957,43N 1070,07E 1435.87 N 48,17E 1,626 1359. __ 07. 43' 29= 8 31..-: .. - 79 59 19 84 . _ 2~ 93'- 867' 78 19 662 ~ ..........24 .... 1"~'F-' -N--'5-gE .............. 6'250-, 54 ......... 6-i"~--:1.-'.-5'~ .... 9-8'?-~-~-1-N-- -1 'i-2'0;-06 E .........!4'93,20' ~' N'--4'8"~5 9'E ........... l, 156 .........1416. . . ~.~ W E L L C 0 M P' L E T I 0 N R E P 0 R T PAGE ...... / ']'c::_.~__ ...................... U_._N!.O_N._ _O !.._.L .... C_.O_, .... OE .~_A~L_!_E,_.G_~.}.~_.9_EI~k_~O.M~LET_!.~_~..REpOR~._P.B~_PA~ED_ 11/.!2/69 "']TANGENTIAL MEI'FOD M6ASU. BEO.. D .E_._V .... I__A .... T I ..... Q__N .... ; ..... : ..................................... ~OTA.L__CO~RDINATE~ ..... C L 0 S U R E S DOG LEG SECTION D E..P_!M. A. NG LE___D_[B_..~_C_.T__I_.O~ ___!V D ......... _~U_B_.__~ E.A._ L_~?_!~ U.D.E ...... ~_~'P AR TUR.E .......~_! s T ANC E._]~_._.ANGL E ']-~EvERI TY_.._.O I S T ANC . . 682~ ..... 28 ..... 0_~ __N ..... 6SE 64~6.25 6~37.25 1029.89N 120S,~OE --158~,86 N 49.qqE Z,080--1510.1'~-' 11.26 ........ 28 ...... 0..~_ ....N .... 5.7.E .... 67.03'0~-'-~-'-'6604o04 ..... 1106,62N- -'~319.61E~'~ 1722.20 N 50, .1432 ......... 33.157 .... ~ ..... 60E ..... 6958,94 ..... 6859.94 .... 1190.51N ......... 1464.91E__ _1887.67 N 50. 7674 33 !.5..'__ N.._63E 7161.32 7062.32 1250.75.N ..... 1583.14E ...... 2017.60 N 51. .__~.._8_6_2 3_~___~_0..' ~L_...6._~._E_ 7316.26__7217,26__1299,09N 1678.01E 2122.12 N 52, .~,q,90 ........ 33 ..... 1.5.~ .... _N...__66E 7506.93 7407.93 1349.94N 1792.22E 2243.74 N 53. 22 30 ].5' N 67E 7620.96 ...... --:~52i';'-96---l-3-75;92N ..... 1853'43E'~/d .... ............................................. · ........ . ....... ' ...... ..... ]'_Zsos.sz N 8373 31 O' N 70E 7750°39 7651.39 1402,52N .1926;51E 2382.96 N 53, 844~ ..... 29 ~0' N 71E 7816.54 7717.54 1414.70N 1961,,90E 2418.76 N 54. 67E 2.662 O1E 0.633 89E ........... 1.786 68E 0,679 25E 0.664 01E 0.915 41E 2.307 94E 20E 156,6. 1647. 1813. _. 194,6. 2052. 2177. _ . 224¥. 1.127 232!. 2.08~1 2358. 85.7~ ...... 28 ........ O~ ..... N .... 72E ........ 7925..1R ....... 7826.,_i~ ...... ~432,55N ....... 2016.81E ..... 2473.81N 54.61E 8796 29 15' N 72E 8120.58 8021.58 i466.37N 2120.91E 2578.47 N 55.34E 8982 ..... 31 ....... 0.[__ N.___72E ....... 8280,0.1 818~.01 1495.97N .... 2212..02E 2670.39 N 55.92E 91.05 .............. 3.1 ...... 0__~_ __~__..73E ...........8385.44 8286.44 1514.49N 2272,60E ..... 2'731.01 N 56.31E 9224 30 15' N 75E 8488.24 8389.24 1530.01N 2330.5 9416 ...... 30-30'-~ ..... N .... 78E ......... 8653'67 ........... 8554~'6~----i'550.27'~'- -2425.8 9570 31 45' N 78E 8784.63 8685.63 1567.12N 2505.0 9696 31 45' N 81E 8891.77 8792.77 1577.49N 2570.5 OE x 2787.86 N 56.71E 2E~/~--'2878.88 N 57.41E 9E 2954.88 N 57.97E 8E ..... 3016.01 N 58.46E 1.280 2416. 0.558 2525. '0. 940 2-"620. 0.418 2683° 1.063 274~. 0.800 2838. 0.811 291~. 1.252 2982. 9.93.9 .... 32 ........ O' ...................................... 1028Q ............34 15.~ ...... B .... 86E .... 9379..71 ........ 9280,7.1 .... 16.06.57N ..... 2889.83E___._~.3306.39 N 60. 10621 36 45' N 89E 9652.94 9553.94 1610.13N 3093.83E//3~87.74 N 62. 10746 36 O' N 90E 9754.07 9655.07 1610.13N 3167.31E 3553.08 N 63. ."'-11006 37 O' S 85E 9961.71 9862.71 1596.49N 3323.18E 3686.78 N 64. l~X~<~l 36 i~-~- 'S 84E 10135,10 1.0036.10 1583.20N 3449.62E 3795.58 N 65. __ -- ' 11~03 36 O' S 81E 10282.34 10183.34 1566.47N 3555.28E ~ 3885.08 N 66. 11570 35 O' S 81E 10417.45 10318.45 1551.11N 3652.23E 3967.96 N 66. N 83E 9097.85 8998.85 1593.18N 2698.39E 3133.61 N 59.44E 0.446 3106. 9ZE 0,816 32~7. 50E 0,893 3477. 05E 0.764 3544. 33E ......... 1.206 '-3682. 34E 0.445 3794. 22E 0.981 3884. 98E ........... 0.000 ..... 3967. 32 31 .. 81 ., 33 80 80' 16 81 36 47 91 07 70 02 73- 96 - --..:- CLOSURE 3967.96 N 66- 59' E ............................. UJ_N.!_..O_N__.O[__L _C._o__: ..... O:F___C_A_L'_I_~_: ..__.G.--]2_ .__W_~_LL___.C_OM?_LE~ !__~,_N ..R~_E_~_OR_T__p_R EP_.:AR__.~_ D__ .! 1/12/69 ........ TANGE'NT DEPTH TVD SUB SEA LATITUDE DEPARTURE .... -ND-TVD VER T I c'AL ..................................... 7- D I F F E R-E'~-C-E .........CORRECTION ..................................... 699 699.00 600°00 0.50N -to77W 799 799,00 700,00 0.44N -2,20W 899 899,00 800,00 0,81N -2,30W 999 999,00 90.0,00 1,39N -2,25W 1299 1399 1499 1599 1099.00 1000..00 1.73N -2.09W 1199.00 1100.00 1.88N -1"84W 1299.00 1200~00 Z.~7N -1.87W 1399.00 ......... 1300'0'0 ............. 3.03N -2.'31W 1499.00 1400.00 3,79N -2.74W 1599.00 1500.00 3.94N -2.27W 0 0 . 1699 1699.00 1600.00 4.03N -1.69W .... 1799 1799.00 1700"00 4.02N -1.12W 1899 1899.00 1800.00 3.97N---O.54W 1999 1999.00 1900.00 3.92N .O.03E 2099 2099."00 ...... PO00.O0 3.68N --0.55E 2199 2'199.0'0 ..... 2100.00 3.35N 1,02E 0 0 0 0 0 0 ................................................. 0 0 --=- .................................................. 7' 0 0 ,. 0 0 o: 2299 2299.00 2200.00 3.02N 1.50E 2399 2399.00 2300.00 2.74N 2.20E _ __ 2499 . 2499.00 2400.00 2.50N 3.04E 2599 2599.00 2500.00 2.26N 3.88E 2699 2699.00 2600.00 1.75N 4.84E ~99 2'799.00 ...... ~700.00 .............. 1-',OON 5'~iE .__ ....... ~.899 2899.00 2800.00 2999 2999.-00 ....... 2900'"'00 .....................3099 309.9. O0 ....... 30'00~-00 3199 31'-9'9-,-00 -~ 1 oO ,-0o · ' 3300 329_9_._t~_0_ _ ~200._.?.0 ...... 3401 3399.00 3300.00 0,25N 6,98E -0.28'S .... 7,'93E 2.o3N 7.68E ........ 8~-14N 8;~7E 19.OON 14.58E -32",-'4~-~--' 3504 3499.00 3400.00 52.36N 37.41E 3 .... C 0 N P L E T I 0 N R E P 0 R T PAGE ..... F_O_~ .... EV..E_N__!~_O_?EE.'[__OF_ ...... ~_UB SEA DEPTH LATITUDE DEPARTURE DIFFERENCE CORRECTION .... 3714 3699. O0 3600. O0 101.23N 74.66E L 5 3820 3799 ..0_0_ .... 3.700..00 _ __ !29.28N .......... 96.82E 21 3930 3899_._..0_0 ..... 3800.00 163.. 28. N ...... 126.38E 31 '.__4ZX4.0 .3_9_9_9..,_0_0 3..90Q,.._00 19 ?. 94N__156.75E 41 ../,,~155 4099.00 ....... 4000,00 ............. 238,90N 19~.,..~5: 56 269 4199,00 ..... 4!00.00 ......... 280.19N ....... 233.72- 70 ._4386 ................. 9299°00 4200.00 322.99N 275.05- 87 ...... 4502 ..................... ~399.00 ........ 4300..00 ...... ~6.5.78N ........ 3.16..37: 103 5618 4499.00 4400.00 408.32N 357.77- !.19 zt.Z.3~ 4599.00 4500.00 4.8.83N 399.72: 135 4850 4699.00 4600.00 488.48N 441.49- 151 4964 4799.00 4700.00 525.57N 482.68- 165 5078 4899.00 4800.00 562.66N 523.87- 179 -. ...... 5.1~2 4999.00 4900.00 597.97N 564.44E 193 ....... 5305 5099.00 5000.00 633.22N 605.00E 206 5420 5199.00 5100.00 658.71N 647.77E 221 5535 5299.00 5200.00 704.31N 691.74E 236 5650 5399.00 5300.00 739.56N 736..23E 251 5766 5499.00 5400.00 772.17N 784.58E 267 5881 559~.00 5500.00 804.79N 832.92E 282 5997 5699.00 5600.00 837.40N 881.27E 298 _27~-~'11Z 5799.'00 ..... 5700'00 ...... 866.25-~ ..... 93'0'18E 313 0227 5899.00 5800.00 894.54N 979.18E 328 6339 5999.00 5900.00 922.82N 1020.64E 340 6449 6099.00 6000.00 949.15N i058.23E 350 6558 6199.00 6100.00 973.19N 1096.30E 359 ._ _ 6670 6299.00 6200.00 996.76N 1138.28E 37'1 6783 6399.00 6300.00 1020.89N 1185.65E 384 15 ', 16 15 15 6895 6499.00 6400.00 1047.77N 1229.81E 396 12 / W E L L _. ~_O_?_._P. L E T I 0 N R E P 0 R T PAGE INTERPOLATED VALUFS FOR EVEN 100 FEET OF SUB SEA DEPTH · .................................. -U'~"i-~J ~--~- i-[--~-~ ~-"- ~' ~-- "-'~-A-['~--~"" .... GL~3~-~-E]]~.~-~.~`~`{~_[``E~T.~-.r~-~R~[S~.~T-~REP~A~RE`~-~1/~2/69 ........... TANGENT I AL-"ME'YHOD MEASURED TOTAL C 00 R-D-i-'~'~' T~'S-- ....... M-D' TV5 ............. -~'ERT I CAL -O E P'-~"-H ....................:~-~-~)- ..... ~'OE~ --SE'~ .............'L AT'I TUD'E ........ DEPARTURE D I' F FERENC-E- .... CORRECTION .................................... 7O08 7~21 7241 7360 7480 _/..7..6o o ?2O 7841 7961 808l 8197 6699-"0b- 660b~-0'0-- -~i05.-45'N ~'3i7~'~1~ 67'99'-'-00 6-700.00 ~[38"'6/N ..... 1374.'L0: 6899"'00 6800.0'6 ..... i~70.86N ......... 143'0-','87- 6999.00 6900.00 .... 1202,~3N '1~88.31- 709~.00 7000.00 1232.19N ~846.'?~- 7199'00 ....... ~lO0"O0 1262.50N .... ~6-06':"2~- 7299.00 7200.00 1293.'TON 1667o44'- 7399.00 7300.00 132~.~5N 1727.57: T499.'00 ...... ~400.0b .......... 1347""82~- --1787'46~ 7599.00 ...... 7'500~-00 .......... 1370-~9~N'-- 409 422 442 46I 481 501 521 542 562 582 !841.64- 598 20 20 21 20 i6 8313 8429 8542 8657 8771 8887 7699.00 7600.00 1391.96N 1897.49: 7799.00 7700~00 .... 1411'~7N ....... ~952'~51- 7899,'0b- -~800.00 .... 1428'~25N-=--'2003,59E 7-999.00 - 7900"O0 ....... i'44'5.'33N ..... 2056"15E 8099,'00 -8000,00 ....... 1-462'~'63N ..... 2i09,-41E 8199.00- '8100.06 ....... 1480.93N ....... 2165,72E 614 16 630 16 643 13 658 15 672 688 16 900 9].2 923 935 946 -,~'"~5 8 8299.00 8200.00 1499.31N 2222,92E 8399.'00 ..... 83001'00 ....... i5~6.54N ..... 2280'o23E-- 8499.00 ..... 8400'00 ....... ~53]..33N- 2336.70E 8599"'00 8500'"'00 ...... i543.5/N- '2394~32E 8699,-o0 ........ 86Oo.-O0 ..... 1556o10N .... 2453,26E 8799.00 ...... 8700.-00 ......... i568.'5iN ..... 2513:87E 705 17 722 17 .................................................... . 737 15 753 16 770 17 788 18'--'- 9705 9823 9940 10061 10304 ~899.00 8800.00 LSZS.04N 2575.06E 89q'~'~'06 ..... 8900.-00 ~585o66N ...... 2637.08E 9-0~";~ ..... 900'0-;00 .... 1'593,24N ...... 2699;'17E --9~"9'~-~'0~ --~i0'0;06- 1597-~99'N- 2767.09E 929~'0b-- ~-200-~"'0~ ..... I6'0'2~]7'~---2'~35-~-0iE 9399°00 9300.0'-~- - ~'606':82~ ' ~'~'~'23E 806 18 824 18 ..................................................... 84~ t7 862 2i 883 21 905 22 I04.29 9499.00 9400.00 1608.12N 2978.89E 930 25 _D_E_E~TH TVD .. $_UB__$_EA _1ATITUDE DEPARTURE DIFFERENCE CORRECTION 1o554 ~599.00 ...... 9500.00 -'~"~o~Z4BN .... 305B.?SSE 955 10678 _7699.00_ ._~600_,0.0 1610.13N_ 3127.29E 979 [080.2 9799._00 ........ 9700.00 ...... I607.i8N .... 3201.03E 1003 10927 9899'._00 ..... 9800_,__00 ........1600.61N_ _3276,.iOE 1028 '_~J_0_5.2 9999,00 9900,00 I593,64N 3350,37E 1053 ,1,,,.~176 I 0.099_. OO_ _!.0.000, OO 1585._._97N_. _3~_~.3.29E 1077 24 .3.0_0 10_!_9.9_, O0 __ 10100. O0 ........ !_5 Z.~.- 9~N_ __31~9._5._,._~_7 E_ ..... 1101 ._.!.1424 1029_~ ._0.0 .....~_.0_ 2. .0__ ~_..~ ~.0~ ............ "+__5 ~ 47_~_8N ~Sb7.Z3E ..... _!..! 25 _!3.547 l_0_3_9._9;_0.0 _ _~l_Q_3_O__Q._.__O_~O~ ....... _1._5_5~_~_2._1__N3638,99E ~ 1148 23 .............................................. · INTERPOLATED VALUES FOR EVEN 1000 FEET OF HEASURED DEPTH : MEASURED . · DE PTH T 0 T A'F'-- ~-'[3-O-R-U' i N~ T E~ ................. M-D~--T VD- .......... VERTICAL' ............................................ TVD SUB SEA LATIT-U'D-~- ......... D-EP'ART[J-R"~ D-~-F'F"E-RE~-C~ -' CORRECTION ,, 1000 999.00 900.00 1.39N -2.25W 1 1. 2000 1999.'00 i900'00 3~92N O,04E 1 0 . . 3000 2999.00 2900.00 -0.27S 7.93E i 0 - -4000 3963.00 3864.00 ...... i'SS'OSN ..... 5000 4830.00 ...... ~731'00 537~26~ .... ~9-5-,66E 170 133 ../,,~000 570].,,00 -5602.00 838o25N 882.54E 299 129 JO0 659"i'o 00-- 6492-~-0 O- ..... fo 74 ,.'4"ON --i270':'a0 E ~09 110 ..... 8000 743'1 -:-00 ..........7'-332'~-'-Ob- .... t-3~. 9-'.'~-6'N .... 1747';'1'4E--- '-569 160 ....... 9'000- ....... ~-2 ~ 5-~"0 ~ ....... '-~j-'i"~ is- ~ b-O ......... 1,~+98 ~. 68N .... -222'0",-88 E-- ........ 705 13'6 ............................ : .............................................................. o 63E IO000 9 1 z-, 8..,.90 90~+9.00 1595.58N 2732 ........... ~_~_~8'52 ................. 1~7 [ lO0'O 9956.00 9857.00 ~596.8~N 3319.58E 1044 MEASURED P, ECTED DEPTH VERTICAL. DEPTH TiME COURSE TOTAL sURVEY TAE~ULATION ~HEET ' ' .: " ~ SURVEY '~ ' ~ JOB.NO,' · .:': :."' -.. . ,:, :,.::..:..,, - ... ,.. .~: ..-.:: . . .... . - . _~ . DIRECTION OF INCLINATION OBSERVED CORRECTED COURSE DISPLACEMENT NORTH TOTAL DISPLACEMENT"~.. : . :::- . ? SOUTH EAST / WEST , I l: ' ' FROM Graydon Laughbau~ AT. 2805 Denali Street TRANSMITTING THE FOLLOWING: ii Directional Surveys TBU G-52 i,.i ~,, l~rrn No. P--4 REV. STATE OF ALASKA SUBMIT IN DUPLICATE OIL AND GAS CONSERVATIO. N COMMITTEE MONTHLY REPORT O:F DRILLING AND WORKOVER OPE;RATIONS ~ APZ NU~IEmC~L CODE 50-133-20198 1':' ,",~ ~__._. 2. NAME OF OPEI{ATOR Uni,,on 0il Company of California 3. ADDRESS OF OPERATOR . 507 W, Northern Lights' Blvd.. Anchorage. Alaska 99503 4. LOCATION OF WELL -- Conductor #47, Leg #2, 1882'N, 1383'W front SE corner Section 29, TgN, K13W, $~. ADL 18730 IF INDIA]~, ALOTTEE O~=~.T~E NAME 8. LrNIT,F.~RA~I OR LEASE NAME Trading Bay Unit 9. WELL NO. State G-32 (21-28) 10. FieLD A-ND POOL, OR WILDCAT . .. ~.. ^_ Middle Kenai "G" McArthur ~v=£-West Foreland i1. SEC., T., FL., M., (BOTTOM HOLE o~~_~ Sec. 28, T9N, R13W, SM. 12. PERMIT NO. 69-86 13. REPOFLT TOTAL DEPTH AT END OF MONTH, CI-I~NGES IN HOLE SIZE, CASING AND CEIVlE~TING JOBS INCLUDING DEPTH SET AdNID VOLLrMES USED, PERFOI~ATIONS, TESTS AND RESULTS, FISHING JOBS, JUNK IN HOLE AND SIDE-TRACKED HOLE AND ANY OTH]gR SIGNIFICANT CH3~,GES IN HOL~ CONDITIONS. TRADING BAY UN%T STATE. ~-32 (,21,-28),, OCTOB, ER 1969 Spudded @ 12:00 Noon 10/1/69. Drld 15" hole to 510'. Opened hole to 22" to 510'. Ran 18" mill. Milled thru conductor shoe @ 369'. Ran 12 its 17-3/4" .312 wall spiral weld, SOW csg, hung w/Howco duplex shoe @ 497'. Cmtd thru shoe 850 sx "G". Lost returns after mixing 650 sx. Cmt to surf. WOC 4 hrs. Cut off 17-3/4" csg. Instld 20" Hydril. Drld out cmt & shoe. CO to 510'. Drld 12-1/4" hole 510'-3021', kick off point. DDrld 3021'3325'. Drld to 4824'. Opened 12-1/4" hole to 17" hole 0'-4824'. Conditioned hole. Ran 123 its 13-3/8" csg. Hung w/shoe @ 4810'. Cmtd w/2000 sx "G" mixed with 1/2 cuff. prlt per sk, 6% gel, 1% D-3i followed by 500 sx "G". CIP 1:30 am 18/11/69. Instld 12" S 900 csg head & 12" S 900 BOE. Drld 12-1/4" hole to 6626'. Bit locked, lost 1 cone in hole. RI w/junk sub. Drld on junk. PO, rec one cone. Drld to 10,317'. Now drilling. 14. I hereby certi~ th&t-the fo/~'going is true arid correct sm~~' ~.L,~~ =vu~ Dist. Drlg. Supt. ~.~ 11/12/69 NOTE--Repoa o~ this ~ is requ~d for each ~lendar month, regardless of the status of operations, and mu~ ~ filed in dupli~te with the Division of Mines & Minerals by the 15th of the succeeding month, unless othe~ise directed. Mr. Wade S. McAlister, Landman Union Oil Company of California 2805 Denali Street Anchorage.~ Alaska 99503 Dear Sir' Re- Trading Bay Unit State G-32 21-28 Union Oil Company of California, operator In reference to the subject offshore drill-site the following stipulations are required to protect fish and game resources' I. No material foreign to the environment will be discharged from this platform. This includes garbage~ trash, refuse~ petroleum and/or its products, drilling mud~ and debris. 2 Drill-ing operations are not '-n i.J i'''+ .... ~'~ ,.~:,.~, = wikh ' ' " , commercial fishing. 3 The Habitat Biologist's Office~ 1018 In+~'~ ' = ~ . ,~,~-=~ ~,at.ionai Airpor~ Road Anchorage Alaska 99502, w-ill be nu~if~ed~"~ ' "' ' ~ ,~.,rNor to the abandonment of' this location. Statement' The foregoing provisions do not reliev,e, i:he lessee arid/or his con'~r'actor's or assignees of any responsibili'~;ies or provisions required by ~ =' State "~ t .... ' .... law or regulation o'r ~ne of Alas~,., or he fcue~'a't governmant. ~ ; ,.? ' :: . · , ,:... ,~ .r ~,:.:.. .~ -: ...:, ,:~ Robert .:: Wi-,- '~.,~ ' H,.oi uat Form REV. 9-3o-e~ STATE O'F ALASKA SUBMIT IN TRIP1 (Other instructions o ,, reverse side) OIL AND GAS CONSERVATIO'N ,COMMITTEE . A~PPLICATION FOR PERMIT T° DRILL, DEEPEN, oR PLUG BACK la. TypI or wo,,~c DRILL J~J DEEPEN [-J PLUG BACK b. TYPIg Or W~LL OIL ~--] aA8 J--1 ' 81NGLI r--] MULTIPI'IR~.] ZONB ZONE 8. UNIT~FARM OR LEASE NAME WILL WiLL · ,. NAME OF OP~TOR TRADING BAY UNIT UNION OIL COMPANY OF CALIFORNIA 3.ADDRESS O~ OPEItATOR 2805 Denali Street, Anchorage, Alaska 99503 ~.LOCATIONO~WEL'. Conductor 47, Leg 2, 1882' N, 1383' V~, from the At surface SE corner, Sec. 29, T9N, R13W, S.M. At~ro~o.eU~o~.~o,e~.l.op "G" 1690' S, 820' E, from NW corner, Sec. 28, TgN, R13W. 13. DISTANCE IN MILES AND DIRECTION FY/OM NEAREST TOWN ORPOST OI~FIC~:* 19.. 23 Air miles NW of Kenai, Alaska 14. BOND IIqFORA4ATION: .T~PEState wides~ ,n~/o~ No. United Pacific Insurance Co. B-5537.2 _,~o~, $100,000.00 15. DISTANCE FROM PROPOSED*(AlsoLOCATiONpRoPERTYto nearest TOoR NEARESTLEASEdrig. unit,LINE'if any,FT' 880 ' t1!' ~TO' OF ACI~F'~ IN LEA'SE,'.3840 . I,. NO. ACRES ASSIGNEDTo TH,S160W~LL 18. DISTANCE FROM PROPOSED LOCATION* PR~)POSED DEpTH 20. ROTARY OR CABLE TOOLS TO NEAREST WELL D~ILLING. COMPLET]~D, OR APPLIED FOR FT. 13501 11,610' MD - 10,650' VD Rotary 21. ELEVATIONS (Show whether DF, RT. ~.R, etc.) 22. APPROX. DATE WORK WILL START* 99' RT above MSL Sept.. 10, 1969 23. PROPOSED CASING AND CEM~NG ~ROGRAM ' g. WELL NO. State G-32' 21-28 . ,, 10. rIEMD AND POOL,o~4~d~&Kenai____ ,, McArthur River w~.~t ~nraland I1. SEC. T.. R., M., (BOTTOM HOLI~- OI~ECTIVE) Sec. 28, T9N, R13W~ S.M. SIZE OF HOLE SIZE OF CASING WEIGHT PER FOOT GRAI3~ [ S~ING DEPTH QUANTITY or ,, 22" 17 3/4" ,312 wall sp[ril weld .500' 6,* 8.00 sks'"'- cement to 'surface c. 17'! 13 3/8" 6]~. T-SS 4RDD" o~ 3000 sks - cement tO surface 12~" 9 5/8" 45,~ &'47~ 1~ & P 10500" ~- 2000 Sks. f~///~ 8~" 7" ~9.~. N-80 10320-i1610,~. 400 sks fO//¢ ,, Cement 17 3/4" CSG in 22" Hole at 500'. Install 20" Hydrfl. Drill 12¼" Directional Hole to 4800'. Open to 17" and cement 13 3/8" CSG at 4800". Install BOE. Drill 12¼". Directional Hole to 10,400' (Top of West Foreland). Run Electric Logs. Cement 9 5/8 CSG at 10,400'. Drill 8½" Directional Hole to 11,600' TD. Run Electric Logs. Cement 7" liner 10,300' to ll,600'o Block Squeeze above and below Hemlock for zone segregation. Perforate "G" & West Foreland sands. Complete for production through dUal 3½" tubing strings. Bottom Hole Location: 890' S, 1885' E from NW comer, Sec. 28, T9N., R13W., S.M. 1~ ABOV~ SPACE DI~SCI~IBE PROPOSED Pi~OGRAM: If ~ ~ to dee~n or pl~ ~. give ~ on p~nt p~u~ive ~ ~d p~ ~w p~du~ive ~. If p~l ~ ~ dr~ or ~n ~ ~o~, five ~ent ~ on ~bs~a~ ~t~ ~d m~d ~d ~ue refill dept. Gl~ b~ut prevenMr~~./ ~. I heartily ~the ~~ b ~~ / s,G~~~~~~~~' ~ ( ~. Augsst 18z 1969 ~ L6 ndm a n (This spa~ ~r S~te offl~ u~) COND~ONS OF ~V~, ~ ~: [S~L~ AND CO~ CHI~ ~~ ~ ~ ~~: ~ ~ ~o ~ See Transmittal Letter D~ON~ SURLY ~~ A.P.L ~C~ CODE " - //~~- / /// Alaska 0il and Gas ' / *~ I.~o., ~ Reve~ Side 27,.1969 , 27. 1960 J I G'I9 G-5 ~2- G- A I<- x\\\\"x , ,-- Prol~ T/W TMD TVD ""'-e~-? ~K-5 TMD 8990 TVD 84Z9 (21-Z8) 8HL I I ~6 lO' 10,650' G-18 6-1 (14-29) 6-2 ($4-29) 6-11 ($2- $2) D-II UNION- U~RAi~HON t ADL- 17514. D-I (14-28) lJ~i G-30 6-5 (IZ- $$) D-7 I9N- RI3W G-6 (S4-~8) G -14A G-12 (34-53) UNION-MARATHON ADL 1873C I D-17 N D-2 UN ION OIL COMPANY OF CALIFORNIA ALASKA DISTRICT WELL LOCATION MAP UNION OIL CO OPERATOR UNION TRADING BAY STATE UNIT ( al-28 DATE AUG 4,.1969 SCALE I": 2000' 19' 'DOg' ~!:'IS a registered survey plat attached . well located proper distance from property line ...... Swell located undedicated acrea e ava .... ~.-'- .'.'; '.:;' ~...:i:'"-.-.-.~::~'CHECK,LIST FOR NEW WELL PERMITS --1. Zs well to be ~ocated in a defined. Lease & Well No. 77,/~..~,~:/ ~i~ - :~ '''~ I to be ..... :.. operator the only affecte~ party... operator have a bond tn force ..... ;-.:,... ;:::~:...-~,.. ..... ,. ' cement' ~ d to 'c ~ ;e- on 'conductor ~and surface '"~11 surface csg. ~nternal butst equal :::5:':¢;i::~:~;~::~-~:t'o' Will all casing give adequate safety tn colla)se and tension · Additional Requirements: "~,," ~ --"~:?~'~ -~ ::/~ ~-~:~ Approval,
