The URL can be used to link to this page

Home My WebLink About191-1391. 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? 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): 11,506 See schematic Casing Collapse Structural Conductor Surface 1,540psi Intermediate 3,090psi Production 8,530psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: 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 McArthur River Hemlock Oil, Middle Kenai G Oil, Middle Kenai Gas Same 9,946 9,401 8,131 3,024psi 9,401 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 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Operations Manager STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017594 / ADL0018730 191-139 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-733-20037-01-00 Hilcorp Alaska, LLC Trading Bay Unit G-01RD Length Size Proposed Pools: L-80 TVD Burst 8,506 11,220psi MD 5,750psi 3,090psi 327' 2,120' 7,319' 327' 2,160' 9,921'7" 26" 13-3/8" 327' 9-5/8"8,450' 2,160' Perforation Depth MD (ft): 8,450' 8,597 - 9,195 3,352' 7,440 - 7,954 Other: Install ESP CO 228A 10/15/2025 4-1/2" Hyd Pkr & TRSSSV 8,071 (MD) 6,995 (TVD) & 434 (MD) 434 (TVD) 11,479' 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 10:50 am, Oct 02, 2025 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2025.10.02 10:09:43 - 08'00' Dan Marlowe (1267) 325-601 MGR16OCT2025 10-404 DSR-10/2/25A.Dewhurst 08OCT25 * BOPE pressure test to 3500 psi. Annular to 2500 psi. * Approved for a 14 day flow test without setting the production packer. 24/7 man watch. * State witnessed no-flow performance test after 14 days of production to operate without production packer set and tested. * Failing no-flow test will require packer set and SSSV state witnessed performance test within 5 days after initial 14 day flow test. JLC 10/20/2025 10/20/25 RWO to Install ESP Well: G-01RD Well Name:G-01RD API Number:50-733-20037-01-00 Current Status:Offline development well Leg:Leg #2 (NE corner) Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:191-139 First Call Engineer:Casey Morse (907) 777-8322 Second Call Engineer:Eric Dickerman (907) 564-4061 Maximum Expected BHP:3,888 psi @ 8,638 TVD 0.45psi/ft assumed Max. Potential Surface Pressure: 3024 psi 0.1psi/ft to surface Brief Well Summary Oil producer G-01RD has historically been completed in the Middle Kenai G oil pool and Hemlock Oil Pool. In 2021 the ESP started displaying erratic parameters. The pump was shut off, and SITP built up to over 2300psi in 12hrs. Diagnostics and production testing revealed a potential leak at the Liner Top Packer resulting in communication with the Middle Kenai Gas Pool uphole. A RWO was performed in 2022 to isolate the oil pools and complete the well for gas only production. The well was not capable of producing sustained gas rates due to facility limitations and water production. The plug isolating the oil pools was removed following approval of CO 796 to commingle the oil and gas pools. Attempts to flow the well were unsuccessful, and the well was subsequently shut in after 6 months per the conditions of CO 796. In 2024 the SITP climbed back to a high of ~2500psi. A plug was set to temporarily isolate the Oil Pools again. Perforations were added within the Middle Kenai Gas Pool as defined by CO 228A. Another attempt was made at producing gas unsuccessfully. Gas production rates were insufficient to overcome the associated water production given the tubing size and facility constraints, so this attempt to convert the well to gas production was unsuccessful. This well historically made significant oil production as an ESP completion. This procedure aims to return the well to ESP completion to enable production of higher fluid volumes. This will potentially return the well to its original oil production volumes from ~2021 timeframe with opportunity for dewatering the gas sands and enabling gas production up the annulus that would otherwise not be possible given the facility limitations. In June of 2025, Hilcorp requested an amendment to and extension of Conservation Order 796 to allow for commingled flow of the Hemlock Oil Pool, Middle Kenai G Oil Pool, and The Middle Kenai Gas Pool . Hilcorp hereby requests approval to commingle production as detailed in its request from June 2025 to amend and extend CO 796. The goal of this project is to return the well to ESP completion and commingle production from the Hemlock Oil Pool, Middle Kenai G Oil Pool, and The Middle Kenai Gas Pool. 6.7 ppge Hilcorp hereby requests approval to commingle production as detailed in its request from June 2025 to amend and extend CO 796. RWO to Install ESP Well: G-01RD Pertinent wellbore information: - 5/30/22: MIT-IA to 3000psi PASSED confirming 9-5/8 casing integrity down to packer at 8071 MD Recent History: - 6/13/21: RWO to add packer and SSSV following failed no-flow test. Returned to production at 11k liquid and <175MCFD - 8/6/21: ESP electively shut down due to erratic parameters. o Amps dropped off, vibration went up, and intake pressure rose from 500 to 1500psi in 2 hours o Shutoff ESP and SITP built from 80psi to 2300+psi in less than 12hrs o Suspected casing or 7 LTP leak - 11/3/21: AOGCC authorizes 6 months of comingled flow via CO 796. - 11/4/21: Well comes on at ~500MCFD and no water (250psi FTP) - 5/1/22: Comingled production period expired and well SI. Final rates were 50mcfd, 0 bwpd at 250psi - 5/22/22: RWO to pull ESP and install GL/packer/SSSV completion o Set 7 CIBP at 10,050 MD. o Set GL completion with packer at 8071 MD.MIT-IA to 3000psi PASSED - 6/18/22: Brought well online with GL: 3000 bwpd, minimal net gas - 6/24/22: STP Log o No obvious signs of gas nor fluid entry. o Appears to be coming from behind tubing tail (8071 8,506 MD) - 9/2/22: Coil drillout of CIBP to return the well to oil production o 7 CIBP at 10,050 MD underreamed out and pushed to 10,718 MD o Had 0.7bpm losses before milling, and complete vac afterwards - 9/3/22: Well returned to production with GL at 90bopd, 4500water and <50MCFD Fgas at 175psi - 3/27/23: Well electively shut in. Production had declined to 0bopd, 3000bwpd and minimal Fgas - 10/10/24: test for gas o SITP climbed to ~2500 psi o Set an expandable plug above the Hemlock and G zones o Perforate the Middle Kenai Gas Pool o Attempt to flow the well unsuccessfully RWO to Install ESP Well: G-01RD 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: 130bbl d. IA to packer: 450bbl e. Casing to top open perf: 3bbl 3. Set BPV/TWC, ND tree, NU BOP a. Notify AOGCC 48hrs in advance for witness b. Test to 250psi low/3,500psi 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, release packer, and POOH with gas lift completion a. Packer shear pinned at 58k 6. MU retrieving tools on work string and TIH to retrieve expandable plug 7. PU cleanout BHA and cleanout to +/- 11,300 or as deep as practical 8. MU TCP guns on workstring. TIH to shooting depth per Engineers perf table. a. RU Eline and run gamma correlation pass to confirm depth 9. Actuate firing head to re-perforate Hemlock and G oil zones 10. Circulate well clean, and ensure static, POOH with TCP guns. 11. PU and run ESP completion per the proposed schematic 12. Set BPV, ND BOPEs, NU tree, test same. 13. Turn well over to production 14. Schedule SVS testing with AOGCC as per regulations. Attachments: 1. Well Schematic Current 2. Well Schematic Proposed 3. Wellhead Diagram Current 4. Wellhead Diagram Proposed 5. BOP Drawing 6. Fluid Flow Diagrams 7. RWO Sundry Revision Change Form - Ensure well control available for circ of trapped gas under tubing tail. - mgr * 14 day flow test without packer set approved with 24/7 man watch. Lubricate TWC if possibility of pressure below. - mgr _____________________________________________________________________________________ Updated By: JLL 05/07/25 SCHEMATIC Grayling Platform Well: G-01RD Last Completed: 05/30/22 PTD: 191-139 API: 50-733-20037-01-00 RKB to MLLW ELEV = 103 TD = 11,506 PBD = 11,430 MAX HOLE ANGLE = 39.10 @ 7225 RKB to TBG Hngr = 42.68 Tree connection: 4-1/16 Bowen 2 1 3 4 5 HB-2 G-2 G-3 G-4 G-5 HB-4 HB-5 HB-7 HB-6 4-5/8 Perf Gun @ 11,409 G-6 G-7 HB-3 26 13-3/8 9-5/8 7 Fish @11337 G-1 HB-1 TOC 8575' CBL 2/15 1992 X Damaged casing Middle Kenai Gas CASING DETAIL Size WT Grade Conn ID MD Top MD Btm 26 Surf. 327 13-3/8 61 J-55 Butt 12.515 Surf. 2,160 9-5/8 47 N-80 Butt 8.681 Surf 79 40 N-80 Butt 8.835 79 6,275 43.5 N-80 Butt 8.755 6,275 8,179 47 N-80 Butt 8.681 8,179 8,450 (TOW) 9-5/8 DV Collar 4,903 4,905 7 29 P-110 Butt 6.184 8,127 11,479 TUBING DETAIL 4-1/2 12.6 L-80 IBT 3.958 Surface GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date 1 2,2162,1683.992IPOR-15 16 DOME 1158 6/16/22 2 4,1943,8133.992IPOR-15 16 DOME 1126 6/16/22 3 5,5044,8863.992IPOR-15 16 DOME 1095 6/16/22 4 6,3295,5693.833IPO-1 20 DOME 1020 6/15/22 5 7,0876,1943.833IPO-1 20 DOME 994 6/15/22 6 8,0206,9513.83324 ORIFICE 6/3/22 Zone Top MD Btm MD Top TVD Btm TVD Amt Last Opr. Status F-2 8,597 8,613 7,440 7,453 16 12/18/24 Open F3 8,840 8,860 7,646 7,663 20 12/18/24 Open F-7 9,179 9,195 7,940 7,954 16 12/18/24 Open G-01 10,089 10,120 8,715 8,742 31 05/28/22 Isolated 10/11/24 G-2 10,140' 10,170' 8,759' 8,785' 30' 05/28/22 Isolated 10/11/24 10,140' 10,170' 8'759' 8,785' 30 05/28/22 Isolated 10/11/24 G-3 10,225' 10,257' 8,833' 8,861' 32' 05/28/22 Isolated 10/11/24 10,244' 10,264' 8,849' 8,867' 20 05/28/22 Isolated 10/11/24 G-4 10,278' 10,340' 8,879' 8,933' 62' 05/28/22 Isolated 10/11/24 10,280' 10,342' 8,881' 8,935' 62 05/28/22 Isolated 10/11/24 G-5 10,395' 10,415' 8,981' 8,999' 20' 05/28/22 Isolated 10/11/24 10,398' 10,418' 8,984' 9,001' 20 05/28/22 Isolated 10/11/24 10,440' 10,460' 9,021' 9,038' 20 05/28/22 Isolated 10/11/24 G-6 10,532' 10,548' 9,101' 9,115' 16 05/28/22 Isolated 10/11/24 G-7 10,600 10,614' 9,161' 9,173' 14 05/28/22 Isolated 10/11/24 HB-1 10,622 10,637 9,180' 9,194' 15 05/28/22 Isolated 10/11/24 HB-1 10,628' 10,670' 9,186' 9,223' 42' 05/28/22 Isolated 10/11/24 10,628' 10,676' 9,186' 9,228' 48 05/28/22 Isolated 10/11/24 HB-2 10,689 10,718 9,240 9,265 29 05/28/22 Isolated 10/11/24 HB-3 10,846' 10,860' 9,377' 9,389' 14 05/28/22 Isolated 10/11/24 HB-4 10,863' 11,000' 9,392' 9,509' 137' 05/28/22 Isolated 10/11/24 10,939 10,954 9,457' 9,470' 15 05/28/22 Isolated 10/11/24 10,890' 11,006' 9,415' 9,515' 116 05/28/22 Isolated 10/11/24 HB-5 11,038 11,048 9,542' 9,550' 10 05/28/22 Isolated 10/11/24 11,040' 11,070' 9,544' 9,569' 30' 05/28/22 Isolated 10/11/24 11,042' 11,122' 9,545' 9,614' 80 05/28/22 Isolated 10/11/24 HB-6 11,155' 11,170' 9,642' 9,655' 15' 05/28/22 Isolated 10/11/24 11,156' 11,240' 9,643' 9,715' 84 05/28/22 Isolated 10/11/24 HB-7 11,255' 11,280' 9,728' 9,749' 25' 05/28/22 Isolated 10/11/24 11,266' 11,290' 9,737' 9,758' 24 05/28/22 Isolated 10/11/24 _______ _____________________________________________________________________________________ Updated By: JLL 05/07/25 SCHEMATIC Grayling Platform Well: G-01RD Last Completed: 05/30/22 PTD: 191-139 API: 50-733-20037-01-00 Cement Details 13-3/8"17-1/2 Hole: Cemented with 2900sxs class G. Lost returns after 271bbls out of the shoe. Ran 1-1/2 pipe outside 13-3/8 casing. Found ToC at 88. Cemented with 210 sacks, and got returns back to surface.ToC at Surface. 9-5/8 12-1/4 Hole: Cemented with 1200sxs (265bbls) of 114# (15.25ppg) class G cement. Shoe was at 8994 MD in G-01 parentbore.1/9/92 CBL showed primary job ToC at 6010 MD 2nd Stage: Pumped 1500sxs class G cement through DV collar at 4903 MD.Volumetric ToC at surface (no log) 78.5 Hole: Cemented with 205bbls 15.8ppg class G cementSaw 30bbls cement circd off top of liner at 8127 MD. 2/15/92 CBL shows ToC at 8575 MD 09/02/22: Milled plug debris to ~10,718 5/23/22: Caliper shows casing damage in 7 casing from 8,127 9200 MD. Appears to be washed out casing/cement, no ID restrictions. Worst is 8,127 - 8400' MD 03/29/21: Cleaned out to 11,224 12/17/00: Left 10.14 long fish consisting of coil tubing motor and bit. _____________________________________________________________________________________ Updated By: CDM 09/30/25 PROPOSED Grayling Platform Well: G-01RD Last Completed: 05/30/22 PTD: 191-139 API: 50-733-20037-01-00 RKB to MLLW ELEV = 103 TD = 11,506 PBD = 11,430 MAX HOLE ANGLE = 39.10 @ 7225 RKB to TBG Hngr = 42.68 Tree connection: 4-1/16 Bowen 2 1 4 5 5 3 HB-2 G-2 G-3 G-4 G-5 HB-4 HB-5 HB-7 HB-6 4-5/8 Perf Gun @ 11,409 G-6 G-7 HB-3 26 13-3/8 9-5/8 7 Fish @11337 G-1 HB-1 TOC 8575' CBL 2/15 1992 X Damaged casing Middle Kenai Gas CASING DETAIL Size WT Grade Conn ID MD Top MD Btm 26 Surf. 327 13-3/8 61 J-55 Butt 12.515 Surf. 2,160 9-5/8 47 N-80 Butt 8.681 Surf 79 40 N-80 Butt 8.835 79 6,275 43.5 N-80 Butt 8.755 6,275 8,179 47 N-80 Butt 8.681 8,179 8,450 (TOW) 9-5/8 DV Collar 4,903 4,905 7 29 P-110 Butt 6.184 8,127 11,479 TUBING DETAIL 4-1/2 12.6 L-80 IBT 3.958 Surface Zone Top MD Btm MD Top TVD Btm TVD Amt Last Opr. Status F-2 8,597 8,613 7,440 7,453 16 12/18/24 Open F3 8,840 8,860 7,646 7,663 20 12/18/24 Open F-7 9,179 9,195 7,940 7,954 16 12/18/24 Open G-01 10,089 10,120 8,715 8,742 31 05/28/22 Open G-2 10,140' 10,170' 8,759' 8,785' 30' 05/28/22 Open 10,140' 10,170' 8'759' 8,785' 30 05/28/22 Open G-3 10,225' 10,257' 8,833' 8,861' 32' 05/28/22 Open 10,244' 10,264' 8,849' 8,867' 20 05/28/22 Open G-4 10,278' 10,340' 8,879' 8,933' 62' 05/28/22 Open 10,280' 10,342' 8,881' 8,935' 62 05/28/22 Open G-5 10,395' 10,415' 8,981' 8,999' 20' 05/28/22 Open 10,398' 10,418' 8,984' 9,001' 20 05/28/22 Open 10,440' 10,460' 9,021' 9,038' 20 05/28/22 Open G-6 10,532' 10,548' 9,101' 9,115' 16 05/28/22 Open G-7 10,600 10,614' 9,161' 9,173' 14 05/28/22 Open HB-1 10,622 10,637 9,180' 9,194' 15 05/28/22 Open HB-1 10,628' 10,670' 9,186' 9,223' 42' 05/28/22 Open 10,628' 10,676' 9,186' 9,228' 48 05/28/22 Open HB-2 10,689 10,718 9,240 9,265 29 05/28/22 Open HB-3 10,846' 10,860' 9,377' 9,389' 14 05/28/22 Open HB-4 10,863' 11,000' 9,392' 9,509' 137' 05/28/22 Open 10,939 10,954 9,457' 9,470' 15 05/28/22 Open 10,890' 11,006' 9,415' 9,515' 116 05/28/22 Open HB-5 11,038 11,048 9,542' 9,550' 10 05/28/22 Open 11,040' 11,070' 9,544' 9,569' 30' 05/28/22 Open 11,042' 11,122' 9,545' 9,614' 80 05/28/22 Open HB-6 11,155' 11,170' 9,642' 9,655' 15' 05/28/22 Open 11,156' 11,240' 9,643' 9,715' 84 05/28/22 Open HB-7 11,255' 11,280' 9,728' 9,749' 25' 05/28/22 Open 11,266' 11,290' 9,737' 9,758' 24 05/28/22 Open _______ _____________________________________________________________________________________ Updated By: CDM 09/30/25 PROPOSED Grayling Platform Well: G-01RD Last Completed: 05/30/22 PTD: 191-139 API: 50-733-20037-01-00 Cement Details 13-3/8"17-1/2 Hole: Cemented with 2900sxs class G. Lost returns after 271bbls out of the shoe. Ran 1-1/2 pipe outside 13-3/8 casing. Found ToC at 88. Cemented with 210 sacks, and got returns back to surface.ToC at Surface. 9-5/8 12-1/4 Hole: Cemented with 1200sxs (265bbls) of 114# (15.25ppg) class G cement. Shoe was at 8994 MD in G-01 parentbore.1/9/92 CBL showed primary job ToC at 6010 MD 2nd Stage: Pumped 1500sxs class G cement through DV collar at 4903 MD.Volumetric ToC at surface (no log) 78.5 Hole: Cemented with 205bbls 15.8ppg class G cementSaw 30bbls cement circd off top of liner at 8127 MD. 2/15/92 CBL shows ToC at 8575 MD 09/02/22: Milled plug debris to ~10,718 5/23/22: Caliper shows casing damage in 7 casing from 8,127 9200 MD. Appears to be washed out casing/cement, no ID restrictions. Worst is 8,127 - 8400' MD 03/29/21: Cleaned out to 11,224 12/17/00: Left 10.14 long fish consisting of coil tubing motor and bit. Grayling Platform G-01RD Valve, Master, WKM-M, 4 1/16 5M FE, HWO, EE trim Valve, Upper master, WKM-M, 4 1/16 5M FE, HWO, EE trim Valve, Swab, WKM-M 4 1/16 5M FE, HWO, EE trim BHTA, Bowen, 4 1/16 5M FE x 7' quick union top Adapter, Cactus-EN-6.25', 11 5M stdd x 4 1/16 5M stdd top, w/ 2- 1'npt control line exits Casing head, Shaffer KD, 13 5/8 3M x 13 3/8 SOW, w/ 2- 2' LPO 13 3/8' 9 5/8' Tubing head, Cactus-C29L, 13 5/8 3M x 11 5M, w/ 2- 2 1/16 5M SSO, w/ 9 5/8 HPS bottom 4 ½ Tubing hanger, Cactus-EN- CCL, 4 ½ EUE 8rd lift and susp x w 6 ¼ od ext neck, 4' type H BPV profile, DD-NL material Valve, Wing, SSV, WKM-M, 4 1/16 5M FE, w/ 15' air operator Grayling Platform G-1rd 13 3/8 X 9 5/8 X 4 1/2 Grayling Platform G-01RD-Proposed 04/29/2022 BHTA, Bowen, 4 1/16 5M FE x 7' quick union top Casing head, Shaffer KD, 13 5/8 3M x 13 3/8 SOW, w/ 2- 2' LPO 13 3/8' 9 5/8' Tubing head, Cactus-C29L, 13 5/8 3M x 11 5M, w/ 2- 2 1/16 5M SSO, w/ 9 5/8 HPS bottom 4 ½ Adapter, FMC A-3-EC, 11 5M X 4 1/16 5M, prepped for BIW electro sub, 3- ½ npt continuous control line exits X3 control line Valve, Upper master, WKM-M, 4 1/16 5M FE, HWO, EE trim Valve, Swab, WKM-M 4 1/16 5M FE, HWO, EE trim Valve, Wing, SSV, WKM-M, 4 1/16 5M FE, w/ 15' air operator Grayling Platform G-1rd 13 3/8 X 9 5/8 X 4 1/2 Tbg hanger, FMC-TC-1A-EN- EC-CCL, 11 5M X 4 ½ TC-2 lift and susp, w/ 4' Type H BPV profile, 3- 1/4 continuous control line ports Grayling Platform BOP Stack HAK 404 Hilcorp Alaska, LLCHilcorp Alaska, LLCChanges to Approved Rig Work Over Sundry ProcedureSubject: Changes to Approved Sundry Procedure for Well G-01RD (PTD 191-139)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 1 From:Casey Morse <casey.morse@hilcorp.com> Sent:Saturday, October 4, 2025 8:16 AM To:Rixse, Melvin G (OGC) Subject:RE: [EXTERNAL] PTD 191-139 Grayling G-01RD Packer Test Mel, It would be great to ow the well before setting the packer. Were not sure how it will behave after the years of ow tests and shut-ins and what sort of gas contribution well get when we de-water the wellbore with an ESP. With the packer un-set initially, we can evaluate the ow characteristics for a few days. If the gas contribution is low, we plan to conduct a no ow test after 14 days of production. If we get signi cant gas contribution, we would set a plug in the X nipple with slickline and pressure up the tubing over 3000 psi to set the packer. We could then pressure up the IA to test it at 1500 psi. Thank you, Casey Morse Operations Engineer Cook Inlet O shore Hilcorp Alaska, LLC (907) 777-8322 From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Friday, October 3, 2025 3:38 PM To: Casey Morse <casey.morse@hilcorp.com> Subject: [EXTERNAL] PTD 191-139 Grayling G-01RD Packer Test Casey, Are you setting the packer? If so, how? Will you test the packer? If so, how? Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 O ice 907-297-8474 Cell CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 2 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 1/16/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240116 Well API #PTD #Log Date Log Company Log Type AOGCC ESet # BCU 09A 50133204450100 224113 10/26/2024 YELLOWJACKET SCBL BCU 12A 50133205300100 214070 8/21/2024 YELLOWJACKET GPT-PLUG-PERF BRU 233-23T 50283202000000 224088 12/28/2024 AK E-LINE PPROF BRU 233-27 50283100260000 163002 12/31/2024 AK E-LINE PPROF BRU 243-34 50283201240000 208079 12/27/2024 AK E-LINE PPROF GP 03-87 50733204370000 166052 12/25/2024 AK E-LINE CBL GP AN-17A 50733203110100 213049 12/16/2024 AK E-LINE CBL GP AN-17A 50733203110100 213049 12/21/2024 AK E-LINE Perf GP BR-03-87 50733204370000 166052 1/3/2025 AK E-LINE CBL IRU 44-36 50283200890000 193022 1/3/2024 AK E-LINE Depth Determination/Plug IRU 44-36 50283200890000 193022 12/26/2024 AK E-LINE DepthDetermination KU 31-07X 50133204950000 200148 12/3/2024 AK E-LINE Perf MPU B-21 50029215350000 186023 1/4/2025 AK E-LINE PlugSettingRecord MPU H-08B 50029228080200 201047 12/28/2024 AK E-LINE Welltech MRU G-01RD 50733200370100 191139 12/12/2024 AK E-LINE IPROF MRU G-01RD 50733200370100 191139 12/18/2024 AK E-LINE Perf MRU M-25 50733203910000 187086 12/3/2024 AK E-LINE Perf MRU M-25 50733203910000 187086 12/19/2024 AK E-LINE Perf PBU 01-37 50029236330000 219073 11/23/2024 HALLIBURTON PPROF PBU 06-05 50029202980000 178020 12/21/2024 HALLIBURTON RBT PBU 06-19B 50029207910200 224095 12/11/2024 HALLIBURTON RBT PBU 11-38A 50029227230100 198216 11/27/2024 HALLIBURTON TEMP PBU 14-31A 50029209890100 224090 11/11/2024 HALLIBURTON RBT PBU L-103 50029231010000 202139 11/25/2024 HALLIBURTON IPROF PBU M-207 50029238070000 224141 12/25/2024 HALLIBURTON RBT PBU P2-55 50029222830000 192082 12/5/2024 HALLIBURTON PPROF PBU S-15 50029211130000 184071 11/18/2024 HALLIBURTON RBT TBU M-25 50733203910000 187086 12/13/2024 AK E-LINE Perf T39958 T39959 T39960 T39961 T39962 T39963 T39964 T39964 T39965 T39966 T39966 T39967 T39968 T39969 T39970 T39970 T39971 T39971 T39972 T39973 T39974 T39975 T39976 T39977 T39978 T39979 T39980 T39981 MRU G-01RD 50733200370100 191139 12/12/2024 AK E-LINE IPROF MRU G-01RD 50733200370100 191139 12/18/2024 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.01.16 13:56:40 -09'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 10/30/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20241030 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BRU 221-26 50283202010000 224098 10/20/2024 AK E-LINE Perf BRU 233-23T 50283202000000 224088 10/14/2024 AK E-LINE Perf BRU 241-23 50283201910000 223061 10/12/2024 AK E-LINE Perf GP-ST-18742-33 50733203060000 177032 10/9/2024 AK E-LINE LeakDetect/Packer IRU 11-06 50283201300000 208184 10/4/2024 AK E-LINE Plug/Perf MPU B-28 50029235660000 216027 10/4/2024 READ CaliperSurvey MPU F-13 50029225490000 195027 10/15/2024 READ CaliperSurvey MPU L-36 50029227940000 197148 10/17/2024 READ CaliperSurvey MRU G-01RD 50733200370100 191139 10/10/2024 AK E-LINE Hoist NCIU A-21 50883201990000 224086 10/8/2024 AK E-LINE CBL NCIU B-01B 50883200930200 224097 10/1/2024 AK E-LINE CBL NCIU B-01B 50883200930200 224097 10/11/2024 AK E-LINE Perf PBU 06-18B 50029207670200 223071 10/2/2024 HALLIBURTON RBT PBU 14-32B 50029209990200 224073 10/13/2024 HALLIBURTON RBT PBU C-18B 50029207850200 209071 10/2/2024 HALLIBURTON RBT PBU C-18B 50029207850200 209071 10/2/2024 HALLIBURTON WSTT PBU NK-26A 50029224400100 218009 10/14/2024 HALLIBURTON PPROF PCU 02A 50283200220100 224110 9/30/2024 AK E-LINE CBL PCU 02A 50283200220100 224110 10/4/2024 AK E-LINE Perf SDI 3-25B 50029221250200 203021 10/17/2024 AK E-LINE Patch Please include current contact information if different from above. T39726 T39727 T39728 T39732 T39733 T39734 T39735 T39736 T39737 T39738 T39739 T39739 T39740 T39741 T39742 T39742 T39743 T39744 T39744 T39745 MRU G-01RD 50733200370100 191139 10/10/2024 AK E-LINE Hoist Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.11.01 13:27:33 -08'00' 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 11,506 See schematic Casing Collapse Structural Conductor Surface 1,540psi Intermediate 3,090psi Production 8,530psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Ryan Rupert Contact Email:Ryan.Rupert@hilcorp.com Contact Phone:(907) 777-8503 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: ________________ CO 228A 10/7/2024 4-1/2" Hyd Pkr & TRSSSV 8,071 (MD) 6,995 (TVD) & 434 (MD) 434 (TVD) 11,479' Perforation Depth MD (ft): 8,450' 10,089 - 11,290 3,352' 8,715 - 9,758 9,921'7" 26" 13-3/8" 327' 9-5/8"8,450' 2,160' MD 5,750psi 3,090psi 327' 2,120' 7,319' 327' 2,160' Length Size Proposed Pools: L-80 TVD Burst 8,506 11,220psi STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017594 / ADL0018730 191-139 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-733-20037-01-00 Hilcorp Alaska, LLC Trading Bay Unit G-01RD AOGCC USE ONLY 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 Hemlock Oil, Middle Kenai G Oil Middle Kenai Gas 9,946 10,718 9,265 3,024psi N/A m n P s 1 6 5 6 t T N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 10:22 am, Sep 20, 2024 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2024.09.20 09:36:14 - 08'00' Dan Marlowe (1267) 324-539 SFD 9/20/2024BJM 10/3/24 Variance to 20 AAC 25.112 approved for 1-year flow period. Plug at 10,000' MD will need to be removed when the Hemlock and Middle Kenai G are to be abandoned so hydrocarbons in these pools can be confined to their indigenous strata. Perforate New Pool P 10-404 DSR-9/27/24JLC 10/3/2024 Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.10.07 13:04:12 -08'00'10/07/24 RBDMS JSB 100824 Plugback for Gas only flow Well: G-01RD Well Name: G-01RD API Number: 50-733-20037-01-00 Current Status: Offline development well Leg: Leg #2 (NE corner) Regulatory Contact: Juanita Lovett (8332) Permit to Drill Number: 191-139 First Call Engineer: Ryan Rupert (907) 301-1736 (c) Second Call Engineer: Dan Marlowe (907) 398-9904 (c) Maximum Expected BHP: 3,888 psi @ 8,638’ TVD 0.45psi/ft assumed Max. Potential Surface Pressure: 3024 psi 0.1psi/ft to surface Brief Well Summary Oil producer G-01RD has historically been completed in the Middle Kenai G oil pool and Hemlock Oil Pool. It was a stable well historically, until 2021 when the ESP instantaneously started displaying erratic parameters. The pump was shut off, and SITP built up to over 2300psi in 12hrs. the well had been a no-flow well when producing from the Oil Pools. Diagnostics, and production testing revealed that the deep casing or Liner Top Packer had likely been compromised resulting in communication with the Middle Kenai Gas Pool uphole. A RWO was performed in 2022 to isolate the oil pools and complete the well for gas only production. Upon returning to production, the well made only water. Given the likely behind pipe flow, it was unclear as to the source of the water, but it seemed to be from a source within the Gas Pool, and not from the oil pools below. Given that no hydrocarbons were being produced from the gas Pool, the plug was removed, and communication reestablished with the oil pools. The well was subsequently shut in after ~6months of water only production. Since then, SITP has climbed back up to ~2500psi. This procedure aims to temporarily isolate the Oil Pools, and attempt gas production through the compromised casing again. If the gas production does not sustain again, the procedure includes a provision to perforate additional gas sands below the production packer in an effort to reestablish flow. All planned perforations below are within the Middle Kenai Gas Pool as defined by CO 228A. The goal of this project is to establish deep gas production from the Middle Kenai Gas Pool. Pertinent wellbore information: - TRSSSV installed - 5/30/22: MIT-IA to 3000psi PASSED confirming 9-5/8” casing integrity down to packer at 8071’ MD Hilcorp requests a variance to not place cement on top of the retrievable plug. By not permanently abandoning the Oil Pools, Hilcorp is preserving the option to return the well to oil production should the gas work in this sundry be unsuccessful. Hilcorp requests up to a 1-year flow period with this uncemented temporary plug in place (gas production lasted for ~6 months last time). At the end of the 1-year period, the oil pools will be properly abandoned per regulation, the well SI, or the gas zones abandoned per regulation (future sundry) Variance to 20 AAC 25.112 approved for 1-year flow period. Plug at 10,000' MD will need to be removed when the Hemlock and Middle Kenai G are to be abandoned to confine hydrocarbons to their indigenous strata. -bjm Plugback for Gas only flow Well: G-01RD Recent History - March-2021: Elective ESP swap RWO o Liquid had dropped from 10k to 4k. o Gas was testing at <175mcf before RWO o Cleanout 7” liner to 11,224’ MD (base H-6 perfs) almost all perfs open now o Test packer obtains passing MIT to 1700psi at 9,825’ MD and above o Ran ESP Æ back to prior rates of 11k liquid and <175mcfd - 4/17/21: FAILED NFT, but SITP still less than 200psi. well left shut in - 6/13/21: RWO to add packer and SSSV. Returned to production at 11k liquid and <175MCFD - 8/6/21: ESP electively shut down due to erratic parameters. o Amps dropped off, vibration went up, and intake P rose from 500 to 1500psi in 2 hours o Shutoff ESP and SITP built from 80psi to 2300+psi in less than 12hrs o Casing or 7” LTP leak from gas source appears to be communicating with wellbore now - 11/3/21: AOGCC authorizes ~6 months of comingled flow. - 11/4/21: Well comes on at ~500MCFD and no water (250psi FTP) - 5/1/22: Comingled production period expired and well SI. Final rates were 50mcfd, 0 bwpd at 250psi - 5/22/22: RWO to pull ESP and install GL/packer/SSSV completion o EL 5.97" junk basket run made it to 10,091' MD (No tag, just stopped there) o Caliper from 10,091' - 7800' MD Showed wall loss from Top 7" liner at 8127’ MD to 9200'. Worst damage is from Top 7” liner to 8400' MD. o Set 7” CIBP at 10,050’ MD. Losses went from complete vac to <0.25bpm after plug set o Set GL completion with packer at 8071’ MD. MIT-IA to 3000psi PASSED - 6/18/22: Brought well online with GL: 3000 water, minimal net gas (casing leak only production) - 6/24/22: STP Log o No obvious signs of gas nor fluid entry. o Appears to be coming from behind tubing tail (8071’ – 8,506’ MD) - 9/2/22: Comingle o Since no hydrocarbon production from Middle Kenai Gas Pool now, Hilcorp asks to return to Middle Kenai G Oil and Hemlock Oil Pool production Hemlock/G zone o 7” CIBP at 10,050’ MD underreamed out and pushed to 10,718’ MD o Had 0.7bpm losses before milling, and complete vac afterwards - 9/3/22: Comingled well back online with GL at 90bopd, 4500water and <50MCFD Fgas at 175psi - 3/27/23: Well electively shut in. Production had declined to 0bopd, 3000bwpd and minimal Fgas Plugback for Gas only flow Well: G-01RD E-Line Temporary Plug Procedure 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250psi low / 3500psi high a. RIH and set a temporary expandable bridge plug at ±10,000’ MD (8,638’ TVD) b. Base Middle Kenai Gas Pool at 10,045’ MD (8,678’ TVD) c. G/Hemlock oil zone reservoir pressure expected to be ~3000psi at 10,815’ MD / 9350’ TVD 3. RDMO EL Hilcorp requests a variance to set this temporary plug greater than 50’ above top perf. The set depth location was chosen based on the 5/23/22 caliper of the 7” casing. E-Line Perforation Procedure 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250psi low / 3500psi high 3. RIH and perforate Middle Kenai Gas Pool sands from ±8,100’ - ±10,000’ MD (±7,020’ - ±8,638’ TVD) a. Base Middle Kenai Gas Pool at 10,045’ MD (8,678’ TVD) b. Pressures: i. Sidetrack window at 8,560’ MD (7,409’ TVD): LOT at 16.0PPG ii. Worst case pressure assuming 0.45psi/ft reservoir pressure and 0.1psi/ft gas gradient could create a 10.3ppg at the top sundried perf (7,020’ TVD) 4. RDMO EL Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic Base Middle Kenai Gas Pool at 10,045’ MD (8,678’ TVD) Variance is not required for a temporary plug. -bjm CBL run 2/14/1992 indicates M Kenai Gas Pool is cement- isolated from underlying Tyonek and Hemlock.SFD perforate Middle Kenai Gas Pool sands from ±8,100’ - ±10,000’ MD (±7,020’ - ±8,638’ TVD) Base Middle Kenai Gas Pool at 10,045’ MD (8,678’ TVD) _____________________________________________________________________________________ Updated By: JLL 09/18/24 SCHEMATIC Grayling Platform Well: G-01RD Last Completed: 05/30/22 PTD: 191-139 API: 50-733-20037-01-00 CASING DETAIL Size WT Grade Conn ID MD Top MD Btm 26”Surf.327’ 13-3/8”61 J-55 Butt 12.515”Surf.2,160’ 9-5/8” 47 N-80 Butt 8.681”Surf 79’ 40 N-80 Butt 8.835”79’6,275’ 43.5 N-80 Butt 8.755”6,275’8,179’ 47 N-80 Butt 8.681”8,179’8,450’ (TOW) 9-5/8” DV Collar 4,903’4,905’ 7”29 P-110 Butt 6.184”8,127’11,479’ TUBING DETAIL 4-1/2”12.6 L-80 IBT 3.958”Surface 8,506’ Jewelry Details No.Depth MD Depth TVD ID OD Item 1 434’434’3.813 5.980 TRSSSV 2 8,071’ 6,995’ 3.990 8.250 9-5/8" x 4-1/2" LTC 32.3-43.5# Hyd Packer (58K shear) 3 8,126’7,043’3.813 5.000 4-1/2" LTC X-Nipple 4 8,506’7,364’3.958 5.000 4 1/2" IBT collar made to WLEG (mule shoe) GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date 1 2,216’2,168’3.992”IPOR-15 16 DOME 1158 6/16/22 2 4,194’3,813’3.992”IPOR-15 16 DOME 1126 6/16/22 3 5,504’4,886’3.992”IPOR-15 16 DOME 1095 6/16/22 4 6,329’5,569’3.833”IPO-1 20 DOME 1020 6/15/22 5 7,087’6,194’3.833”IPO-1 20 DOME 994 6/15/22 6 8,020’6,951’3.833”24 ORIFICE 6/3/22 Zone Top MD Btm MD Top TVD Btm TVD Amt Last Opr.Status G-01 10,089’10,120’8,715’8,742’31’05/28/22 Open G-2 10,140'10,170'8,759'8,785'30'05/28/22 Open 10,140'10,170'8'759'8,785'30’05/28/22 Open G-3 10,225'10,257'8,833'8,861'32'05/28/22 Open 10,244'10,264'8,849'8,867'20’05/28/22 Open G-4 10,278'10,340'8,879'8,933'62'05/28/22 Open 10,280'10,342'8,881'8,935'62’05/28/22 Open G-5 10,395'10,415'8,981'8,999'20'05/28/22 Open 10,398'10,418'8,984'9,001'20’05/28/22 Open 10,440'10,460'9,021'9,038'20’05/28/22 Open G-6 10,532'10,548'9,101'9,115'16’05/28/22 Open G-7 10,600 10,614'9,161'9,173'14’05/28/22 Open HB-1 10,622’10,637’9,180'9,194'15’05/28/22 Open HB-1 10,628'10,670'9,186'9,223'42'05/28/22 Open 10,628'10,676'9,186'9,228'48’05/28/22 Open HB-2 10,689’10,718’9,240’9,265’29’05/28/22 Open HB-3 10,846'10,860'9,377'9,389'14’05/28/22 Open HB-4 10,863'11,000'9,392'9,509'137'05/28/22 Open 10,939’10,954’9,457'9,470'15’05/28/22 Open 10,890'11,006'9,415'9,515'116’05/28/22 Open HB-5 11,038’11,048’9,542'9,550'10’05/28/22 Open 11,040'11,070'9,544'9,569'30'05/28/22 Open 11,042'11,122'9,545'9,614'80’05/28/22 Open HB-6 11,155'11,170'9,642'9,655'15'05/28/22 Open 11,156'11,240'9,643'9,715'84’05/28/22 Open HB-7 11,255'11,280'9,728'9,749'25'05/28/22 Open 11,266'11,290'9,737'9,758'24’05/28/22 Open Cement Details 13-3/8"17-1/2” Hole: Cemented with 2900sxs class G. Lost returns after 271bbls out of the shoe. Ran 1-1/2” pipe outside 13-3/8” casing. Found ToC at 88’. Cemented with 210 sacks, and got returns back to surface.ToC at Surface. 9-5/8” 12-1/4” Hole: Cemented with 1200sxs (265bbls) of 114# (15.25ppg) class G cement. Shoe was at 8994’ MD in G-01 parentbore. 1/9/92 CBL showed primary job ToC at 6010’ MD 2nd Stage: Pumped 1500sxs class G cement through DV collar at 4903’ MD.Volumetric ToC at surface (no log) 7”8.5” Hole: Cemented with 205bbls 15.8ppg class G cementSaw 30bbls cement circ’d off top of liner at 8127’ MD . 2/15/92 CBL shows ToC at 8575’ MD 09/02/22: Milled plug debris to ~10,718’ 5/23/22: Caliper shows casing damage in 7” casing from 8,127’ – 9200’ MD. Appears to be washed out casing/cement, no ID restrictions. Worst is 8,127 - 8400' MD 03/29/21: Cleaned out to 11,224’ 12/17/00: Left 10.14’ long fish consisting of coil tubing motor and bit. By Anne Prysunka at 12:43 pm, Oct 03, 2022 _____________________________________________________________________________________ Updated By: JLL 09/18/24 PROPOSED Grayling Platform Well: G-01RD Last Completed: 05/30/22 PTD: 191-139 API: 50-733-20037-01-00 CASING DETAIL Size WT Grade Conn ID MD Top MD Btm 26”Surf.327’ 13-3/8”61 J-55 Butt 12.515”Surf.2,160’ 9-5/8” 47 N-80 Butt 8.681”Surf 79’ 40 N-80 Butt 8.835”79’6,275’ 43.5 N-80 Butt 8.755”6,275’8,179’ 47 N-80 Butt 8.681”8,179’8,450’ (TOW) 9-5/8” DV Collar 4,903’4,905’ 7”29 P-110 Butt 6.184”8,127’11,479’ TUBING DETAIL 4-1/2”12.6 L-80 IBT 3.958”Surface 8,506’ Jewelry Details No.Depth MD Depth TVD ID OD Item 1 434’434’3.813 5.980 TRSSSV 2 8,071’ 6,995’ 3.990 8.250 9-5/8" x 4-1/2" LTC 32.3-43.5# Hyd Packer (58K shear) 3 8,126’7,043’3.813 5.000 4-1/2" LTC X-Nipple 4 8,506’7,364’3.958 5.000 4 1/2" IBT collar made to WLEG (mule shoe) 5 ±10,000'±8,638'Temporary Retrivable Bridge Plug0,000 ±8,638 Temporary Retrivable Bridgee Plug GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date 1 2,216’2,168’3.992”IPOR-15 16 DOME 1158 6/16/22 2 4,194’3,813’3.992”IPOR-15 16 DOME 1126 6/16/22 3 5,504’4,886’3.992”IPOR-15 16 DOME 1095 6/16/22 4 6,329’5,569’3.833”IPO-1 20 DOME 1020 6/15/22 5 7,087’6,194’3.833”IPO-1 20 DOME 994 6/15/22 6 8,020’6,951’3.833”24 ORIFICE 6/3/22 Zone Top MD Btm MD Top TVD Btm TVD Amt Last Opr.Status Middle Kenai Gas ±8,100'±10,000'±7,020'±8,638'±1,900'Future Proposed G-01 10,089’10,120’8,715’8,742’31’05/28/22 Open G-2 10,140'10,170'8,759'8,785'30'05/28/22 Open 10,140'10,170'8'759'8,785'30’05/28/22 Open G-3 10,225'10,257'8,833'8,861'32'05/28/22 Open 10,244'10,264'8,849'8,867'20’05/28/22 Open G-4 10,278'10,340'8,879'8,933'62'05/28/22 Open 10,280'10,342'8,881'8,935'62’05/28/22 Open G-5 10,395'10,415'8,981'8,999'20'05/28/22 Open 10,398'10,418'8,984'9,001'20’05/28/22 Open 10,440'10,460'9,021'9,038'20’05/28/22 Open G-6 10,532'10,548'9,101'9,115'16’05/28/22 Open G-7 10,600 10,614'9,161'9,173'14’05/28/22 Open HB-1 10,622’10,637’9,180'9,194'15’05/28/22 Open HB-1 10,628'10,670'9,186'9,223'42'05/28/22 Open 10,628'10,676'9,186'9,228'48’05/28/22 Open HB-2 10,689’10,718’9,240’9,265’29’05/28/22 Open HB-3 10,846'10,860'9,377'9,389'14’05/28/22 Open HB-4 10,863'11,000'9,392'9,509'137'05/28/22 Open 10,939’10,954’9,457'9,470'15’05/28/22 Open 10,890'11,006'9,415'9,515'116’05/28/22 Open HB-5 11,038’11,048’9,542'9,550'10’05/28/22 Open 11,040'11,070'9,544'9,569'30'05/28/22 Open 11,042'11,122'9,545'9,614'80’05/28/22 Open HB-6 11,155'11,170'9,642'9,655'15'05/28/22 Open 11,156'11,240'9,643'9,715'84’05/28/22 Open HB-7 11,255'11,280'9,728'9,749'25'05/28/22 Open 11,266'11,290'9,737'9,758'24’05/28/22 Open Cement Details 13-3/8"17-1/2” Hole: Cemented with 2900sxs class G. Lost returns after 271bbls out of the shoe. Ran 1-1/2” pipe outside 13-3/8” casing. Found ToC at 88’. Cemented with 210 sacks, and got returns back to surface.ToC at Surface. 9-5/8” 12-1/4” Hole: Cemented with 1200sxs (265bbls) of 114# (15.25ppg) class G cement. Shoe was at 8994’ MD in G-01 parentbore. 1/9/92 CBL showed primary job ToC at 6010’ MD 2nd Stage: Pumped 1500sxs class G cement through DV collar at 4903’ MD.Volumetric ToC at surface (no log) 7”8.5” Hole: Cemented with 205bbls 15.8ppg class G cementSaw 30bbls cement circ’d off top of liner at 8127’ MD . 2/15/92 CBL shows ToC at 8575’ MD 09/02/22: Milled plug debris to ~10,718’ 5/23/22: Caliper shows casing damage in 7” casing from 8,127’ – 9200’ MD. Appears to be washed out casing/cement, no ID restrictions. Worst is 8,127 - 8400' MD 03/29/21: Cleaned out to 11,224’ 12/17/00: Left 10.14’ long fish consisting of coil tubing motor and bit. David Dempsey Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.dempsey2@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 09/29/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20220929 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# TBU G-01RD 507332003701 191139 6/24/2022 AK E-Line Depth MPU I-17 500292321200 204098 7/17/2022 AK E-Line Perf Please include current contact information if different from above. T37079 T37080 TBU G-01RD 507332003701 191139 6/24/2022 AK E-Line Depth Kayla Junke Digitally signed by Kayla Junke Date: 2022.09.30 13:12:11 -08'00' 5HJJ-DPHV%2*& )URP%URRNV3KRHEH/2*& 6HQW:HGQHVGD\6HSWHPEHU$0 7R&ROH%DUWOHZVNL &F5HJJ-DPHV%2*& 6XEMHFW5(>(;7(51$/@5(6/%&78RQ*UD\OLQJ*%23(WHVWUHSRUW $WWDFKPHQWV6FKOXPEHUJHU5HYLVHG[OV[ ŽůĞ͕ dŚĂŶŬǇŽƵ͘ƚƚĂĐŚĞĚŝƐĂƌĞǀŝƐĞĚƌĞƉŽƌƚǁŝƚŚƚŚĂƚĐŚĂŶŐĞ͘ WŚŽĞďĞƌŽŽŬƐ ZĞƐĞĂƌĐŚŶĂůǇƐƚ ůĂƐŬĂKŝůĂŶĚ'ĂƐŽŶƐĞƌǀĂƚŝŽŶŽŵŵŝƐƐŝŽŶ WŚŽŶĞ͗ϵϬϳͲϳϵϯͲϭϮϰϮ CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. &ƌŽŵ͗ŽůĞĂƌƚůĞǁƐŬŝфĐďĂƌƚůĞǁƐŬŝΛŚŝůĐŽƌƉ͘ĐŽŵх ^ĞŶƚ͗tĞĚŶĞƐĚĂǇ͕^ĞƉƚĞŵďĞƌϭϰ͕ϮϬϮϮϵ͗ϮϭD dŽ͗ƌŽŽŬƐ͕WŚŽĞďĞ>;K'ͿфƉŚŽĞďĞ͘ďƌŽŽŬƐΛĂůĂƐŬĂ͘ŐŽǀх ^ƵďũĞĐƚ͗Z͗΀ydZE>΁Z͗^>dhϭŽŶ'ƌĂǇůŝŶŐ'ͲϬϭKWƚĞƐƚƌĞƉŽƌƚ͘ 'ŽŽĚĐĂƚĐŚŵĂ͛Ăŵ͘/ƚǁĂƐĂŶĞƌƌŽƌŽŶŵǇĞŶĚ͘^ŚŽƵůĚďĞƌĞƉůĂĐĞĚǁŝƚŚ͞W͟ĂƐƚŚĞƌĞǁĂƐŶŽĨĂŝůƵƌĞ͘ &ROH%DUWOHZVNL +LOFRUS$ODVND//& 6U:HOOVLWH6XSHUYLVRU5LJ0DQDJHU (PDLOFEDUWOHZVNL#KLOFRUSFRP 2IILFH &HOO +LOFRUS$ODVND//& ŽŵƉĂŶǇďƵŝůƚŽŶŶĞƌŐǇ &ƌŽŵ͗ƌŽŽŬƐ͕WŚŽĞďĞ>;K'ͿфƉŚŽĞďĞ͘ďƌŽŽŬƐΛĂůĂƐŬĂ͘ŐŽǀх ^ĞŶƚ͗dƵĞƐĚĂǇ͕^ĞƉƚĞŵďĞƌϭϯ͕ϮϬϮϮϰ͗ϮϯWD dŽ͗ŽůĞĂƌƚůĞǁƐŬŝфĐďĂƌƚůĞǁƐŬŝΛŚŝůĐŽƌƉ͘ĐŽŵх ^ƵďũĞĐƚ͗΀ydZE>΁Z͗^>dhϭŽŶ'ƌĂǇůŝŶŐ'ͲϬϭKWƚĞƐƚƌĞƉŽƌƚ͘ ŽůĞ͕ dŚĞŚŽŬĞ>Ŷ͘sĂůǀĞƐŝŶĐůƵĚĞĚ͞&W͕͟ďƵƚƚŚĞƌĞǁĞƌĞŶŽƌĞŵĂƌŬƐƌĞŐĂƌĚŝŶŐĂĨĂŝůͬƉĂƐƐ͖ƉůĞĂƐĞĂĚǀŝƐĞ͘ hd/KE͗ǆƚĞƌŶĂůƐĞŶĚĞƌ͘KEKdŽƉĞŶůŝŶŬƐŽƌĂƚƚĂĐŚŵĞŶƚƐĨƌŽŵhE<EKtEƐĞŶĚĞƌƐ͘ 7%8*5' 37' ƌĞǀŝƐĞĚƌĞƉŽƌƚǁ dŚĂŶŬǇŽƵ͕ WŚŽĞďĞ WŚŽĞďĞƌŽŽŬƐ ZĞƐĞĂƌĐŚŶĂůǇƐƚ ůĂƐŬĂKŝůĂŶĚ'ĂƐŽŶƐĞƌǀĂƚŝŽŶŽŵŵŝƐƐŝŽŶ WŚŽŶĞ͗ϵϬϳͲϳϵϯͲϭϮϰϮ CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. &ƌŽŵ͗ŽůĞĂƌƚůĞǁƐŬŝфĐďĂƌƚůĞǁƐŬŝΛŚŝůĐŽƌƉ͘ĐŽŵх ^ĞŶƚ͗dƵĞƐĚĂǇ͕^ĞƉƚĞŵďĞƌϲ͕ϮϬϮϮϭϬ͗ϯϵD dŽ͗ZĞŐŐ͕:ĂŵĞƐ;K'Ϳфũŝŵ͘ƌĞŐŐΛĂůĂƐŬĂ͘ŐŽǀх͖ƌŽŽŬƐ͕WŚŽĞďĞ>;K'ͿфƉŚŽĞďĞ͘ďƌŽŽŬƐΛĂůĂƐŬĂ͘ŐŽǀх͖KK' WƌƵĚŚŽĞĂǇфĚŽĂ͘ĂŽŐĐĐ͘ƉƌƵĚŚŽĞ͘ďĂǇΛĂůĂƐŬĂ͘ŐŽǀх ^ƵďũĞĐƚ͗^>dhϭŽŶ'ƌĂǇůŝŶŐ'ͲϬϭKWƚĞƐƚƌĞƉŽƌƚ͘ 'ŽŽĚŵŽƌŶŝŶŐ͕ ƚƚĂĐŚĞĚŝƐƚŚĞKWƚĞƐƚƌĞƉŽƌƚĨƌŽŵ'ƌĂǇůŝŶŐ'ͲϬϭZĐŽŝůũŽďŽǀĞƌƚŚĞǁĞĞŬĞŶĚ͘ ZĞƐƉĞĐƚĨƵůůǇ͕ &ROH%DUWOHZVNL +LOFRUS$ODVND//& 6U:HOOVLWH6XSHUYLVRU (PDLOFEDUWOHZVNL#KLOFRUSFRP 2IILFH &HOO +LOFRUS$ODVND//& ŽŵƉĂŶǇďƵŝůƚŽŶŶĞƌŐǇ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ll BOPE reports are due to the agency within 5 days of testing* SSu bm it t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner: Rig No.:1 DATE: 9/1/22 Rig Rep.: Rig Email: Operator: Operator Rep.: Op. Rep Email: Well Name:PTD #1911390 Sundry #322-454 Operation: Drilling: Workover: x Explor.: Test: Initial: x Weekly: Bi-Weekly: Other: Rams:250/2500 Annular:250/2500 Valves:250/2500 MASP:2318 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 0NA Permit On Location P Hazard Sec.NA Lower Kelly 0NA Standing Order Posted NA Misc.NA Ball Type 0NA Test Fluid Water Inside BOP 0NA FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 1 1.75 P Trip Tank NA NA Annular Preventer 0 N/A NA Pit Level Indicators NA NA #1 Rams 1 Blind Shear P Flow Indicator NA NA #2 Rams 1 Blind Shear P Meth Gas Detector NA NA #3 Rams 1 1.75"/Pipes P H2S Gas Detector NA NA #4 Rams 1 1.75" slips P MS Misc 0NA #5 Rams 0 N/A NA #6 Rams 0 N/A NA ACCUMULATOR SYSTEM: Choke Ln. Valves 2 2" FMC P Time/Pressure Test Result HCR Valves 0 N/A NA System Pressure (psi)2950 P Kill Line Valves 0 N/A NA Pressure After Closure (psi)2780 P Check Valve 1 2" Flapper P 200 psi Attained (sec)N/A NA BOP Misc 2 EQ ports P Full Pressure Attained (sec)N/A NA Blind Switch Covers: All stations Yes CHOKE MANIFOLD:Bottle Precharge:NA Quantity Test Result Nitgn. Bottles # & psi (Avg.): 0 NA No. Valves 6P ACC Misc 0NA Manual Chokes 2P Hydraulic Chokes 0NA Control System Response Time:Time (sec) Test Result CH Misc 0NA Annular Preventer 0 NA #1 Rams 12 P Coiled Tubing Only:#2 Rams 12 P Inside Reel valves 1P #3 Rams 14 P #4 Rams 14 P Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:0 Test Time:4.0 HCR Choke 0 NA Repair or replacement of equipment will be made within days. HCR Kill 0 NA Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 8/26/2022 Waived By Test Start Date/Time:9/1/2022 12:00 (date) (time)Witness Test Finish Date/Time:9/1/2022 16:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Schlumberger Sean Boyden Hilcorp Alaska Cole Bartlewski TBU G-01RD Test Pressure (psi): Sboyden@slb.com cbartlewski@hilcorp.com Form 10-424 (Revised 08/2022) 2022-0901_BOP_Schlumberger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y Anne Prysunka at 4:02 pm, Aug 02, 2022 'LJLWDOO\VLJQHGE\'DQ0DUORZH '1FQ 'DQ0DUORZH RX 8VHUV 'DWH 'DQ0DUORZH '/% ; &7 %23 WHVW WR SVL %-0 '65 ; GWV -/& Jeremy Price Digitally signed by Jeremy Price Date: 2022.08.19 13:25:20 -08'00' RBDMS JSB 082222 tĞůůtŽƌŬWƌŽŐŶŽƐŝƐ tĞůů͗'ͲϬϭZ tĞůůEĂŵĞ͗'ͲϬϭZW/EƵŵďĞƌ͗ϱϬͲϳϯϯͲϮϬϬϯϳͲϬϭͲϬϬ ƵƌƌĞŶƚ^ƚĂƚƵƐ͗'ĂƐ>ŝĨƚWƌŽĚƵĐĞƌ>ĞŐ͗>ĞŐηϮ;EĐŽƌŶĞƌͿ ƐƚŝŵĂƚĞĚ^ƚĂƌƚĂƚĞ͗ƵŐƵƐƚϭϱ͕ϮϬϮϮZŝŐ͗,<ϰϬϰ ZĞŐ͘ƉƉƌŽǀĂůZĞƋ͛Ě͍ϰϬϯĂƚĞZĞŐ͘ƉƉƌŽǀĂůZĞĐ͛ǀĚ͗ ZĞŐƵůĂƚŽƌǇŽŶƚĂĐƚ͗:ƵĂŶŝƚĂ>ŽǀĞƚƚ;ϴϯϯϮͿWĞƌŵŝƚƚŽƌŝůůEƵŵďĞƌ͗ϭϵϭͲϭϯϵ &ŝƌƐƚĂůůŶŐŝŶĞĞƌ͗<ĂƚŚĞƌŝŶĞK͛ŽŶŶŽƌ;ϵϬϳͿϳϳϳͲϴϯϳϲ;KͿ;ϮϭϰͿϲϴϰͲϳϰϬϬ;DͿ ^ĞĐŽŶĚĂůůŶŐŝŶĞĞƌ͗ŚĂĚ,ĞůŐĞƐŽŶ;ϮϭϰͿϲϴϰͲϳϰϬϬ;DͿ Current Bottom Hole Pressure: 2710 psi @ 6,932’ TVD Gas zone based on ESP Gauge 4/11/22 Maximum Expected BHP (oil zone): 3190 psi @ 8715’ TVD Oil zone based on ESP Gauge 4/5/18 Maximum Potential Surface Pressure: 2318 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) ƌŝĞĨtĞůů^ƵŵŵĂƌǇ 'ͲϬϭZŝƐĂ'ͲŽŶĞĂŶĚ,ĞŵůŽĐŬWƌŽĚƵĐĞƌƚŚĂƚǁĂƐĐŽŶǀĞƌƚĞĚƚŽĂŶ^WĨƌŽŵĂĚƵĂůƐƚƌŝŶŐŐĂƐͲůŝĨƚĐŽŵƉůĞƚŝŽŶŝŶKĐƚŽďĞƌ ϮϬϭϮ͘/ŶDĂƌĐŚϮϬϮϭƚŚĞ^WǁĂƐƌĞƉůĂĐĞĚĂŶĚĂĐůĞĂŶŽƵƚǁĂƐƉĞƌĨŽƌŵĞĚ͘ĨƚĞƌƚŚĞǁĞůůǁĂƐďƌŽƵŐŚƚŽŶůŝŶĞƚŚĞǁĞůůǁĂƐ ŶŽůŽŶŐĞƌĂďůĞƚŽƉĂƐƐĂŶŽĨůŽǁƚĞƐƚ͘dŚĞ^WǁĂƐƉƵůůĞĚĂŶĚĂ Ŷ^WƉĂĐŬĞƌΘ^^^sǁĞƌĞŝŶƐƚĂůůĞĚŝŶĞĂƌůǇƐƵŵŵĞƌϮϬϮϭ͘ ĨƚĞƌĂĨĞǁŵŽŶƚŚƐŽĨƉƌŽĚƵĐƚŝŽŶ͕ƚŚĞ^WŐĂƐůŽĐŬĞĚĂŶĚƚŚĞƚƵďŝŶŐĂŶĚ/ƉƌĞƐƐƵƌĞƐĐůŝŵďĞĚƚŽϮϰϬϬƉƐŝĨƌŽŵĂŶ ƵŶŬŶŽǁŶůĞĂŬƚŽĂŐĂƐǌŽŶĞ͘ǁŽƌŬŽǀĞƌǁĂƐĐŽŵƉůĞƚĞĚŝŶĂŶĂƚƚĞŵƉƚƚŽĚŽĚŝĂŐŶŽƐƚŝĐƐĂŶĚĚĞƚĞƌŵŝŶĞǁŚĞƌĞƚŚĞŐĂƐǁĂƐ ĐŽŵŝŶŐĨƌŽŵĂŶĚƌĞƚƵƌŶƚŚĞǁĞůůďĂĐŬƚŽƉƌŽĚƵĐƚŝŽŶ͘ ĐĂůŝƉĞƌǁĂƐƌĂŶĂŶĚŝƚƐŚŽǁĞĚƚŚĞϳ͟ĐĂƐŝŶŐŝŶƉŽŽƌĐŽŶĚŝƚŝŽŶ ŶĞĂƌƚŚĞƚŽƉŽĨƚŚĞůŝŶĞƌ͘dŚĞƉŽŽƌĐĂƐŝŶŐŝƐĨƌŽŵΕϴϭϱϬʹ ϵϮϬϬ͛D͘/ƚŝƐƌĂƚƚǇĂůůƚŚƌŽƵŐŚƚŚĞƌĞǁŝƚŚƐĞĐƚŝŽŶƐŽĨϭϬϬйǁĂůůůŽƐƐ͘ƐǇŽƵŐĞƚĚĞĞƉĞƌƚŚĞĐĂƐŝŶŐŝŶƚĞŐƌŝƚǇŝŵƉƌŽǀĞƐ͘ ĞĐĂƵƐĞŽĨƚŚĞůĂƌŐĞƐĞĐƚŝŽŶŽĨƉŽŽƌĐĂƐŝŶŐ͕ŝƚǁĂƐƉƌĞƐƵŵĞĚƚŚĞŐĂƐǁĂƐĐŽŵŝŶŐƚŚƌŽƵŐŚƚŚŝƐƐĞĐƚŝŽŶŽĨĐĂƐŝŶŐĂŶĚƚŚĞ ďĞƐƚƉůĂŶĨŽƌǁĂƌĚǁŝƚŚƚŚĞŚŝŐŚĞƐƚĐŚĂŶĐĞŽĨƐƵĐĐĞƐƐƚŽƌĞƚƵƌŶƚŚŝƐǁĞůůƚŽƉƌŽĚƵĐƚŝŽŶǁŽƵůĚďĞƚŽƐĞƚĂƉůƵŐĂďŽǀĞƚŚĞŽŝů ƉĞƌĨŽƌĂƚŝŽŶƐƚŽƐŚƵƚƚŚĞŵŽĨĨ͘ϳ͟ƉůƵŐǁĂƐƐĞƚĂŶĚϮϱ͛ŽĨĐĞŵ ĞŶƚĚƵŵƉďĂŝůĞĚŽŶƚŽƉŽĨŝƚĂŶĚƚŚĞŶĂϰ͘ϱ͟ŐĂƐůŝĨƚ ĐŽŵƉůĞƚŝŽŶǁĂƐƌĂŶ͘ tŚĞŶƚŚĞǁĞůůǁĂƐďƌŽƵŐŚƚŽŶůŝŶĞŝƚŶĞǀĞƌƉƌŽĚƵĐĞĚĂŶǇŐĂƐ͘dŚĞŽŶůǇƉƌŽĚƵĐƚŝŽŶǁĂƐΕϯϬϬϬďǁƉĚ͘>>ǁĂƐƌĂŶĂŶĚŝƚ ǁĂƐĚĞƚĞƌŵŝŶĞĚƚŚĞǁĂƚĞƌǁĂƐĐŽŵŝŶŐŝŶĨƌŽŵďĞŚŝŶĚƚŚĞƚƵďŝŶŐƚĂŝů͘dŚĞůŽŐǁĂƐƌĂŶĚŽǁŶƚŽƚŚĞƚŽƉŽĨƚŚĞƉůƵŐĂŶĚ ŶĞǀĞƌƐŚŽǁĞĚĂŶǇŝŶĚŝĐĂƚŝŽŶŽĨŐĂƐĨůŽǁŝŶŐ͘dŚĞŽďũĞĐƚŝǀĞŽĨƚŚŝƐƉƌŽŐƌĂŵŝƐƚŽŵŝůůŽƵƚƚŚĞϳ͟ƉůƵŐĂŶĚƌĞƚƵƌŶƚŚŝƐǁĞůůƚŽ ƉƌŽĚƵĐƚŝŽŶ͕ƉƌŽĚƵĐŝŶŐŐĂƐĂŶĚŽŝůĂƐĂƉƉƌŽǀĞĚďǇK'ϳͬϮϬͬϮϮ͘ >ĂƐƚĂƐŝŶŐWƌĞƐƐƵƌĞdĞƐƚ͗ ϬϱͬϯϬͬϮϬϮϮĂƚϴϬϳϭ͛ĂƚϮϱϬϬƉƐŝŐĂŶĚĐŚĂƌƚĞĚĨŽƌϯϬŵŝŶƵƚĞƐ͘ WƌŽĐĞĚƵƌĞ͗ ϭ͘D/ZhĐŽŝůĞĚƚƵďŝŶŐ Ϯ͘EhKWƐĂŶĚƚĞƐƚƚŽϮϱϬƉƐŝͬϮϱϬϬƉƐŝŚŝŐŚ Ă͘EŽƚŝĨǇK'ϰϴŚŽƵƌƐŝŶĂĚǀĂŶĐĞŽĨƚĞƐƚƚŽĂůůŽǁƚŚĞŵƚŽǁŝƚŶĞ ƐƐƚĞƐƚ ϯ͘DhŵŝůůŝŶŐ,ǁŝƚŚϯ͘ϴϬ͟ŵŝůůĂŶĚĂ,ĂŝůĞǇƵŶĚĞƌƌĞĂŵĞƌĨŽƌĐĞŶƚƌĂůŝǌĂƚŝŽŶ Ă͘ZŝŐƵƉƚŚĞƚŽŽůƐƐƵĐŚƚŚĂƚƚŚĞƵŶĚĞƌƌĞĂŵĞƌďůĂĚĞƐĂƌĞĨĂƌĞŶŽƵŐŚĂďŽǀĞƚŚĞŵŝůůƚŚĂƚŵŽƐƚŽĨƚŚĞ /WƐŚŽƵůĚďĞŵŝůůĞĚŽƵƚďĞĨŽƌĞƚŚĞďůĂĚĞƐƌĞĂĐŚƚŚĞƉůƵŐ͘dŚŝƐƐŚŽƵůĚďĞĂďŽƵƚϴ͘͟dŚĞďůĂĚĞƐĂƌĞ ƉƌŝŵĂƌŝůǇĨŽƌĐĞŶƚƌĂůŝǌĂƚŝŽŶ ϰ͘Z/,ĂŶĚƚĂŐdKĂƚΕϭϬϮϮϯ͛D ϱ͘ƐƚĂďůŝƐŚĐŝƌĐƵůĂƚŝŽŶǁŝƚŚ&/tŽƌϲй<ů ϲ͘DŝůůƚŚƌŽƵŐŚĐĞŵĞŶƚĂŶĚϳ͟/WĂŶĚƉƵƐŚƚŽďŽƚƚŽŵ Ă͘Ϯϳ͛ŽĨĐĞŵĞŶƚ ď͘WůƵŐŝƐϭϵ͟ůŽŶŐǁŚĞŶƐĞƚ dŚĞŽďũĞĐƚŝǀĞŽĨƚŚŝƐƉƌŽŐƌĂŵŝƐƚŽŵŝůůŽƵƚƚŚĞϳ͟ƉůƵŐĂŶĚƌĞƚƵƌŶƚŚŝƐǁĞůůƚŽ ƉƌŽĚƵĐƚŝŽŶ͕ƉƌŽĚƵĐŝŶŐŐĂƐĂŶĚŽŝůĂƐĂƉƉƌŽǀĞĚďǇK'ϳͬϮϬͬϮϮ͘ tĞůůtŽƌŬWƌŽŐŶŽƐŝƐ tĞůů͗'ͲϬϭZ Đ͘/ŶŶĞƌƉůƵŐďŽĚǇŚĂƐϯ͘ϲϴϳ͟K͕ŽŶĐĞĐŽŝůŚĂƐŵĂĚĞΕϳ͟ŽĨƉƌŽŐƌĞƐƐŵŝůůŝŶŐŽŶƉůƵŐŝƚƐŚŽƵůĚďĞĂďůĞ ƚŽďĞƉƵƐŚĞĚƚŽďŽƚƚŽŵ ϳ͘ZDKdh ϴ͘dƵƌŶǁĞůůŽǀĞƌƚŽƉƌŽĚƵĐƚŝŽŶƚŽďƌŝŶŐŽŶůŝŶĞ ƚƚĂĐŚŵĞŶƚƐ͗ ϭ͘ƵƌƌĞŶƚtĞůůďŽƌĞ^ĐŚĞŵĂƚŝĐ Ϯ͘WƌŽƉŽƐĞĚtĞůůďŽƌĞ^ĐŚĞŵĂƚŝĐ ϯ͘ƵƌƌĞŶƚtĞůůŚĞĂĚŝĂŐƌĂŵ ϰ͘KWƌĂǁŝŶŐ ϱ͘&ůƵŝĚͬ&ůŽǁŝĂŐƌĂŵ ϲ͘ZtK^ƵŶĚƌǇŚĂŶŐĞ&Žƌŵ hƉĚĂƚĞĚďǇ͗:>>ϬϳͬϭϮͬϮϮ DĐƌƚŚƵƌZŝǀĞƌ&ŝĞůĚ͕dh tĞůů͗'ͲϬϭZ ŽŵƉůĞƚĞĚ͗ϬϱͬϯϬͬϮϮ^,Dd/ 5.%WR0//:(/(9 ¶ 7' ¶ 3%' ¶ 0$;+2/($1*/( q#¶ 5.%WR7%*+QJU ¶ 7UHHFRQQHFWLRQ%RZHQ +% * * * * +% +% +% +% ϰͲϱͬϴ͟WĞƌĨ'ƵŶΛ ϭϭ͕ϰϬϵ͛ * * +% ´ ´ ´ ´ &ŝƐŚΛϭϭϯϯϳ͛ * +% 72& &%/ (67 72& ¶ &DOF ; ^/E'd/> ^ŝǌĞ td 'ƌĂĚĞ ŽŶŶ / D dŽƉ D ƚŵ Ϯϲ͟ ^ƵƌĨ͘ ϯϮϳ͛ ϭϯͲϯͬϴ͟ ϲϭ :Ͳϱϱ Ƶƚƚ ϭϮ͘ϱϭϱ͟ ^ƵƌĨ͘ Ϯ͕ϭϲϬ͛ ϵͲϱͬϴ͟ ϰϳ EͲϴϬ Ƶƚƚ ϴ͘ϲϴϭ͟ ^ƵƌĨ ϳϵ͛ ϰϬ EͲϴϬ Ƶƚƚ ϴ͘ϴϯϱ͟ ϳϵ͛ ϲ͕Ϯϳϱ͛ ϰϯ͘ϱ EͲϴϬ Ƶƚƚ ϴ͘ϳϱϱ͟ ϲ͕Ϯϳϱ͛ ϴ͕ϭϳϵ͛ ϰϳ EͲϴϬ Ƶƚƚ ϴ͘ϲϴϭ͟ ϴ͕ϭϳϵ͛ ϴ͕ϰϱϬ͛;dKtͿ ϵͲϱͬϴ͟sŽůůĂƌ ϰ͕ϵϬϯ͛ ϰ͕ϵϬϱ͛ ϳ͟ Ϯϵ WͲϭϭϬ Ƶƚƚ ϲ͘ϭϴϰ͟ ϴ͕ϭϮϳ͛ ϭϭ͕ϰϳϵ͛ dh/E'd/> ϰͲϭͬϮ͟ ϭϮ͘ϲ >ͲϴϬ /d ϯ͘ϵϱϴ͟ ^ƵƌĨĂĐĞ ϴ͕ϱϬϲ͛ &OHDQHGRXWWR¶ /HIW¶ORQJILVKFRQVLVWLQJRIFRLOWXELQJPRWRUDQGELW &OHDQHGRXWILOOWR¶'30)LVKQRWUHFRYHUHG WZ&KZd/KE^ ŽŶĞ dŽƉD ƚŵD dŽƉds ƚŵds ŵƚ ^W& >ĂƐƚKƉƌ͘ ^ƚĂƚƵƐ 'ͲϬϭ ϭϬ͕Ϭϴϵ͛ ϭϬ͕ϭϮϬ͛ ϴ͕ϳϭϱ͛ ϴ͕ϳϰϮ͛ ϯϭ͛ ϱ ϬϱͬϮϴͬϮϮ /ƐŽůĂƚĞĚ 'ͲϮ ϭϬ͕ϭϰϬΖ ϭϬ͕ϭϳϬΖ ϴ͕ϳϱϵΖ ϴ͕ϳϴϱΖ ϯϬΖ ϲ ϬϱͬϮϴͬϮϮ /ƐŽůĂƚĞĚ ϭϬ͕ϭϰϬΖ ϭϬ͕ϭϳϬΖ ϴΖϳϱϵΖ ϴ͕ϳϴϱΖ ϯϬ͛ ϱ ϬϱͬϮϴͬϮϮ /ƐŽůĂƚĞĚ 'Ͳϯ ϭϬ͕ϮϮϱΖ ϭϬ͕ϮϱϳΖ ϴ͕ϴϯϯΖ ϴ͕ϴϲϭΖ ϯϮΖ ϲ ϬϱͬϮϴͬϮϮ /ƐŽůĂƚĞĚ ϭϬ͕ϮϰϰΖ ϭϬ͕ϮϲϰΖ ϴ͕ϴϰϵΖ ϴ͕ϴϲϳΖ ϮϬ͛ ϱ ϬϱͬϮϴͬϮϮ /ƐŽůĂƚĞĚ 'Ͳϰ ϭϬ͕ϮϳϴΖ ϭϬ͕ϯϰϬΖ ϴ͕ϴϳϵΖ ϴ͕ϵϯϯΖ ϲϮΖ ϲ ϬϱͬϮϴͬϮϮ /ƐŽůĂƚĞĚ ϭϬ͕ϮϴϬΖ ϭϬ͕ϯϰϮΖ ϴ͕ϴϴϭΖ ϴ͕ϵϯϱΖ ϲϮ͛ ϱ ϬϱͬϮϴͬϮϮ /ƐŽůĂƚĞĚ 'Ͳϱ ϭϬ͕ϯϵϱΖ ϭϬ͕ϰϭϱΖ ϴ͕ϵϴϭΖ ϴ͕ϵϵϵΖ ϮϬΖ ϲ ϬϱͬϮϴͬϮϮ /ƐŽůĂƚĞĚ ϭϬ͕ϯϵϴΖ ϭϬ͕ϰϭϴΖ ϴ͕ϵϴϰΖ ϵ͕ϬϬϭΖ ϮϬ͛ ϱ ϬϱͬϮϴͬϮϮ /ƐŽůĂƚĞĚ ϭϬ͕ϰϰϬΖ ϭϬ͕ϰϲϬΖ ϵ͕ϬϮϭΖ ϵ͕ϬϯϴΖ ϮϬ͛ ϱ ϬϱͬϮϴͬϮϮ /ƐŽůĂƚĞĚ 'Ͳϲ ϭϬ͕ϱϯϮΖ ϭϬ͕ϱϰϴΖ ϵ͕ϭϬϭΖ ϵ͕ϭϭϱΖ ϭϲ͛ ϱ ϬϱͬϮϴͬϮϮ /ƐŽůĂƚĞĚ 'Ͳϳ ϭϬ͕ϲϬϬ ϭϬ͕ϲϭϰΖ ϵ͕ϭϲϭΖ ϵ͕ϭϳϯΖ ϭϰ͛ ϱ ϬϱͬϮϴͬϮϮ /ƐŽůĂƚĞĚ ,Ͳϭ ϭϬ͕ϲϮϮ͛ ϭϬ͕ϲϯϳ͛ ϵ͕ϭϴϬΖ ϵ͕ϭϵϰΖ ϭϱ͛ ϰ ϬϱͬϮϴͬϮϮ /ƐŽůĂƚĞĚ ,Ͳϭ ϭϬ͕ϲϮϴΖ ϭϬ͕ϲϳϬΖ ϵ͕ϭϴϲΖ ϵ͕ϮϮϯΖ ϰϮΖ ϭϬΘϭϲ ϬϱͬϮϴͬϮϮ /ƐŽůĂƚĞĚ ϭϬ͕ϲϮϴΖ ϭϬ͕ϲϳϲΖ ϵ͕ϭϴϲΖ ϵ͕ϮϮϴΖ ϰϴ͛ ϱ ϬϱͬϮϴͬϮϮ /ƐŽůĂƚĞĚ ,ͲϮ ϭϬ͕ϲϴϵ͛ ϭϬ͕ϳϭϴ͛ ϵ͕ϮϰϬ͛ ϵ͕Ϯϲϱ͛ Ϯϵ͛ ϱ ϬϱͬϮϴͬϮϮ /ƐŽůĂƚĞĚ ,Ͳϯ ϭϬ͕ϴϰϲΖ ϭϬ͕ϴϲϬΖ ϵ͕ϯϳϳΖ ϵ͕ϯϴϵΖ ϭϰ͛ ϱ ϬϱͬϮϴͬϮϮ /ƐŽůĂƚĞĚ ,Ͳϰ ϭϬ͕ϴϲϯΖ ϭϭ͕ϬϬϬΖ ϵ͕ϯϵϮΖ ϵ͕ϱϬϵΖ ϭϯϳΖ ϲ ϬϱͬϮϴͬϮϮ /ƐŽůĂƚĞĚ ϭϬ͕ϵϯϵ͛ ϭϬ͕ϵϱϰ͛ ϵ͕ϰϱϳΖ ϵ͕ϰϳϬΖ ϭϱ͛ ϰ ϬϱͬϮϴͬϮϮ /ƐŽůĂƚĞĚ ϭϬ͕ϴϵϬΖ ϭϭ͕ϬϬϲΖ ϵ͕ϰϭϱΖ ϵ͕ϱϭϱΖ ϭϭϲ͛ ϱ ϬϱͬϮϴͬϮϮ /ƐŽůĂƚĞĚ ,Ͳϱ ϭϭ͕Ϭϯϴ͛ ϭϭ͕Ϭϰϴ͛ ϵ͕ϱϰϮΖ ϵ͕ϱϱϬΖ ϭϬ͛ ϰ ϬϱͬϮϴͬϮϮ /ƐŽůĂƚĞĚ ϭϭ͕ϬϰϬΖ ϭϭ͕ϬϳϬΖ ϵ͕ϱϰϰΖ ϵ͕ϱϲϵΖ ϯϬΖ ϴ ϬϱͬϮϴͬϮϮ /ƐŽůĂƚĞĚ ϭϭ͕ϬϰϮΖ ϭϭ͕ϭϮϮΖ ϵ͕ϱϰϱΖ ϵ͕ϲϭϰΖ ϴϬ͛ ϱ ϬϱͬϮϴͬϮϮ /ƐŽůĂƚĞĚ ,Ͳϲ ϭϭ͕ϭϱϱΖ ϭϭ͕ϭϳϬΖ ϵ͕ϲϰϮΖ ϵ͕ϲϱϱΖ ϭϱΖ ϰ ϬϱͬϮϴͬϮϮ /ƐŽůĂƚĞĚ ϭϭ͕ϭϱϲΖ ϭϭ͕ϮϰϬΖ ϵ͕ϲϰϯΖ ϵ͕ϳϭϱΖ ϴϰ͛ ϱ ϬϱͬϮϴͬϮϮ /ƐŽůĂƚĞĚ ,Ͳϳ ϭϭ͕ϮϱϱΖ ϭϭ͕ϮϴϬΖ ϵ͕ϳϮϴΖ ϵ͕ϳϰϵΖ ϮϱΖ Ϯϰ ϬϱͬϮϴͬϮϮ /ƐŽůĂƚĞĚ ϭϭ͕ϮϲϲΖ ϭϭ͕ϮϵϬΖ ϵ͕ϳϯϳΖ ϵ͕ϳϱϴΖ Ϯϰ͛ ϱ ϬϱͬϮϴͬϮϮ /ƐŽůĂƚĞĚ :ĞǁĞůƌǇĞƚĂŝůƐ EŽ͘ĞƉƚŚ D ĞƉƚŚ ds/ K /ƚĞŵ ,ĂŶŐĞƌ ϭ ϰϯϰ͛ ϰϯϰ͛ ϯ͘ϴϭϯ ϱ͘ϵϴϬ dZ^^^s Ϯ Ϯ͕Ϯϭϲ͛ Ϯ͕ϭϲϴ͛ ϯ͘ϵϵϮ ϳ͘Ϭϲϯ ϭͲϭͬϮ͟'>Dϭʹ^WDϭͲϭͬϮΗ'>s/WKZͲϭϱ ϰ͕ϭϵϰ͛ ϯ͕ϴϭϯ͛ ϯ͘ϵϵϮ ϳ͘Ϭϲϯ ϭͲϭͬϮ͟ '>D Ϯ ʹ ^WDϭͲϭͬϮΗ'>s/WKZͲϭϱ ϱ͕ϱϬϰ͛ ϰ͕ϴϴϲ͛ ϯ͘ϵϵϮ ϳ͘Ϭϲϯ ϭͲϭͬϮ͟ '>D ϯ ʹ ^WDϭͲϭͬϮΗ'>s/WKZͲϭϱ ϲ͕ϯϮϵ͛ ϱ͕ϱϲϵ͛ ϯ͘ϴϯϯ ϲ͘ϰϭϬ ϭͲϭͬϮ͟'>Dϰʹ^WDϭΗ'>s/WKͲϭ ϳ͕Ϭϴϳ͛ ϲ͕ϭϵϰ͛ ϯ͘ϴϯϯ ϲ͘ϰϭϬ ϭͲϭͬϮ͟'>Dϱʹ^WDϭΗ'>s/WKͲϭ ϴ͕ϬϮϬ͛ ϲ͕ϵϱϭ͛ ϯ͘ϴϯϯ ϲ͘ϰϭϬ ϭͲϭͬϮ͟ '>D ϲ ʹ ^WDϭΗ'>s/WKͲϭ ϯ ϴ͕Ϭϳϭ͛ ϲ͕ϵϵϱ͛ ϯ͘ϵϵϬ ϴ͘ϮϱϬ ϵͲϱͬϴΗǆϰͲϭͬϮΗ>dϯϮ͘ϯͲϰϯ͘ϱη,ǇĚWĂĐŬĞƌ;ϱϴ<ƐŚĞĂƌͿ ϰ ϴ͕ϭϮϲ͛ ϳ͕Ϭϰϯ͛ ϯ͘ϴϭϯ ϱ͘ϬϬϬ ϰͲϭͬϮΗ>dyͲEŝƉƉůĞ ϱ ϴ͕ϱϬϲ͛ ϳ͕ϯϲϰ͛ ϯ͘ϵϱϴ ϱ͘ϬϬϬ ϰϭͬϮΗ/dĐŽůůĂƌŵĂĚĞƚŽt>';ŵƵůĞƐŚŽĞͿ ϲ ϭϬ͕ϬϱϬ͛ ϴ͕ϲϴϭ͛ Ͳ Ͳ ϳ͟/WǁͬϮϳ͛ĐĞŵĞŶƚ ;dKϭϬ͕ϬϮϯ͛Ϳ hƉĚĂƚĞĚďǇ͗<'KϳͬϮϱͬϮϮ WZKWK^DĐƌƚŚƵƌZŝǀĞƌ&ŝĞůĚ͕dh tĞůů͗'ͲϬϭZ ŽŵƉůĞƚĞĚϱͬϯϬͬϮϮ 5.%WR0//:(/(9 ¶ 7' ¶ 3%' ¶ 0$;+2/($1*/( q#¶ 5.%WR7%*+QJU ¶ 7UHHFRQQHFWLRQ%RZHQ +% * * * * +% +% +% +% ϰͲϱͬϴ͟WĞƌĨ'ƵŶΛ ϭϭ͕ϰϬϵ͛ * * +% ´ ´ ´ ´ &ŝƐŚΛϭϭϯϯϳ͛ * +% 72& &%/ (67 72& ¶ &DOF ; ^/E'd/> ^ŝǌĞ td 'ƌĂĚĞ ŽŶŶ / D dŽƉ D ƚŵ Ϯϲ͟ ^ƵƌĨ͘ ϯϮϳ͛ ϭϯͲϯͬϴ͟ ϲϭ :Ͳϱϱ Ƶƚƚ ϭϮ͘ϱϭϱ͟ ^ƵƌĨ͘ Ϯ͕ϭϲϬ͛ ϵͲϱͬϴ͟ ϰϳ EͲϴϬ Ƶƚƚ ϴ͘ϲϴϭ͟ ^ƵƌĨ ϳϵ͛ ϰϬ EͲϴϬ Ƶƚƚ ϴ͘ϴϯϱ͟ ϳϵ͛ ϲ͕Ϯϳϱ͛ ϰϯ͘ϱ EͲϴϬ Ƶƚƚ ϴ͘ϳϱϱ͟ ϲ͕Ϯϳϱ͛ ϴ͕ϭϳϵ͛ ϰϳ EͲϴϬ Ƶƚƚ ϴ͘ϲϴϭ͟ ϴ͕ϭϳϵ͛ ϴ͕ϰϱϬ͛;dKtͿ ϵͲϱͬϴ͟sŽůůĂƌ ϰ͕ϵϬϯ͛ ϰ͕ϵϬϱ͛ ϳ͟ Ϯϵ WͲϭϭϬ Ƶƚƚ ϲ͘ϭϴϰ͟ ϴ͕ϭϮϳ͛ ϭϭ͕ϰϳϵ͛ dh/E'd/> ϰͲϭͬϮ͟ ϭϮ͘ϲ >ͲϴϬ /d ϯ͘ϵϱϴ͟ ^ƵƌĨĂĐĞ ϴ͕ϱϬϲ͛ &OHDQHGRXWWR¶ /HIW¶ORQJILVKFRQVLVWLQJRIFRLOWXELQJPRWRUDQGELW &OHDQHGRXWILOOWR¶'30)LVKQRWUHFRYHUHG WZ&KZd/KE^ ŽŶĞ dŽƉD ƚŵD dŽƉds ƚŵds ŵƚ ^W& >ĂƐƚKƉƌ͘ ^ƚĂƚƵƐ 'ͲϬϭ ϭϬ͕Ϭϴϵ͛ ϭϬ͕ϭϮϬ͛ ϴ͕ϳϭϱ͛ ϴ͕ϳϰϮ͛ ϯϭ͛ ϱ ϬϱͬϮϴͬϮϮ KƉĞŶ 'ͲϮ ϭϬ͕ϭϰϬΖ ϭϬ͕ϭϳϬΖ ϴ͕ϳϱϵΖ ϴ͕ϳϴϱΖ ϯϬΖ ϲ ϬϱͬϮϴͬϮϮ KƉĞŶ ϭϬ͕ϭϰϬΖ ϭϬ͕ϭϳϬΖ ϴΖϳϱϵΖ ϴ͕ϳϴϱΖ ϯϬ͛ ϱ ϬϱͬϮϴͬϮϮ KƉĞŶ 'Ͳϯ ϭϬ͕ϮϮϱΖ ϭϬ͕ϮϱϳΖ ϴ͕ϴϯϯΖ ϴ͕ϴϲϭΖ ϯϮΖ ϲ ϬϱͬϮϴͬϮϮ KƉĞŶ ϭϬ͕ϮϰϰΖ ϭϬ͕ϮϲϰΖ ϴ͕ϴϰϵΖ ϴ͕ϴϲϳΖ ϮϬ͛ ϱ ϬϱͬϮϴͬϮϮ KƉĞŶ 'Ͳϰ ϭϬ͕ϮϳϴΖ ϭϬ͕ϯϰϬΖ ϴ͕ϴϳϵΖ ϴ͕ϵϯϯΖ ϲϮΖ ϲ ϬϱͬϮϴͬϮϮ KƉĞŶ ϭϬ͕ϮϴϬΖ ϭϬ͕ϯϰϮΖ ϴ͕ϴϴϭΖ ϴ͕ϵϯϱΖ ϲϮ͛ ϱ ϬϱͬϮϴͬϮϮ KƉĞŶ 'Ͳϱ ϭϬ͕ϯϵϱΖ ϭϬ͕ϰϭϱΖ ϴ͕ϵϴϭΖ ϴ͕ϵϵϵΖ ϮϬΖ ϲ ϬϱͬϮϴͬϮϮ KƉĞŶ ϭϬ͕ϯϵϴΖ ϭϬ͕ϰϭϴΖ ϴ͕ϵϴϰΖ ϵ͕ϬϬϭΖ ϮϬ͛ ϱ ϬϱͬϮϴͬϮϮ KƉĞŶ ϭϬ͕ϰϰϬΖ ϭϬ͕ϰϲϬΖ ϵ͕ϬϮϭΖ ϵ͕ϬϯϴΖ ϮϬ͛ ϱ ϬϱͬϮϴͬϮϮ KƉĞŶ 'Ͳϲ ϭϬ͕ϱϯϮΖ ϭϬ͕ϱϰϴΖ ϵ͕ϭϬϭΖ ϵ͕ϭϭϱΖ ϭϲ͛ ϱ ϬϱͬϮϴͬϮϮ KƉĞŶ 'Ͳϳ ϭϬ͕ϲϬϬ ϭϬ͕ϲϭϰΖ ϵ͕ϭϲϭΖ ϵ͕ϭϳϯΖ ϭϰ͛ ϱ ϬϱͬϮϴͬϮϮ KƉĞŶ ,Ͳϭ ϭϬ͕ϲϮϮ͛ ϭϬ͕ϲϯϳ͛ ϵ͕ϭϴϬΖ ϵ͕ϭϵϰΖ ϭϱ͛ ϰ ϬϱͬϮϴͬϮϮ KƉĞŶ ,Ͳϭ ϭϬ͕ϲϮϴΖ ϭϬ͕ϲϳϬΖ ϵ͕ϭϴϲΖ ϵ͕ϮϮϯΖ ϰϮΖ ϭϬΘϭϲ ϬϱͬϮϴͬϮϮ KƉĞŶ ϭϬ͕ϲϮϴΖ ϭϬ͕ϲϳϲΖ ϵ͕ϭϴϲΖ ϵ͕ϮϮϴΖ ϰϴ͛ ϱ ϬϱͬϮϴͬϮϮ KƉĞŶ ,ͲϮ ϭϬ͕ϲϴϵ͛ ϭϬ͕ϳϭϴ͛ ϵ͕ϮϰϬ͛ ϵ͕Ϯϲϱ͛ Ϯϵ͛ ϱ ϬϱͬϮϴͬϮϮ KƉĞŶ ,Ͳϯ ϭϬ͕ϴϰϲΖ ϭϬ͕ϴϲϬΖ ϵ͕ϯϳϳΖ ϵ͕ϯϴϵΖ ϭϰ͛ ϱ ϬϱͬϮϴͬϮϮ KƉĞŶ ,Ͳϰ ϭϬ͕ϴϲϯΖ ϭϭ͕ϬϬϬΖ ϵ͕ϯϵϮΖ ϵ͕ϱϬϵΖ ϭϯϳΖ ϲ ϬϱͬϮϴͬϮϮ KƉĞŶ ϭϬ͕ϵϯϵ͛ ϭϬ͕ϵϱϰ͛ ϵ͕ϰϱϳΖ ϵ͕ϰϳϬΖ ϭϱ͛ ϰ ϬϱͬϮϴͬϮϮ KƉĞŶ ϭϬ͕ϴϵϬΖ ϭϭ͕ϬϬϲΖ ϵ͕ϰϭϱΖ ϵ͕ϱϭϱΖ ϭϭϲ͛ ϱ ϬϱͬϮϴͬϮϮ KƉĞŶ ,Ͳϱ ϭϭ͕Ϭϯϴ͛ ϭϭ͕Ϭϰϴ͛ ϵ͕ϱϰϮΖ ϵ͕ϱϱϬΖ ϭϬ͛ ϰ ϬϱͬϮϴͬϮϮ KƉĞŶ ϭϭ͕ϬϰϬΖ ϭϭ͕ϬϳϬΖ ϵ͕ϱϰϰΖ ϵ͕ϱϲϵΖ ϯϬΖ ϴ ϬϱͬϮϴͬϮϮ KƉĞŶ ϭϭ͕ϬϰϮΖ ϭϭ͕ϭϮϮΖ ϵ͕ϱϰϱΖ ϵ͕ϲϭϰΖ ϴϬ͛ ϱ ϬϱͬϮϴͬϮϮ KƉĞŶ ,Ͳϲ ϭϭ͕ϭϱϱΖ ϭϭ͕ϭϳϬΖ ϵ͕ϲϰϮΖ ϵ͕ϲϱϱΖ ϭϱΖ ϰ ϬϱͬϮϴͬϮϮ KƉĞŶ ϭϭ͕ϭϱϲΖ ϭϭ͕ϮϰϬΖ ϵ͕ϲϰϯΖ ϵ͕ϳϭϱΖ ϴϰ͛ ϱ ϬϱͬϮϴͬϮϮ KƉĞŶ ,Ͳϳ ϭϭ͕ϮϱϱΖ ϭϭ͕ϮϴϬΖ ϵ͕ϳϮϴΖ ϵ͕ϳϰϵΖ ϮϱΖ Ϯϰ ϬϱͬϮϴͬϮϮ KƉĞŶ ϭϭ͕ϮϲϲΖ ϭϭ͕ϮϵϬΖ ϵ͕ϳϯϳΖ ϵ͕ϳϱϴΖ Ϯϰ͛ ϱ ϬϱͬϮϴͬϮϮ KƉĞŶ :ĞǁĞůƌǇĞƚĂŝůƐ EŽ͘ĞƉƚŚ D ĞƉƚŚ ds/ K /ƚĞŵ ,ĂŶŐĞƌ ϭ ϰϯϰ͛ ϰϯϰ͛ ϯ͘ϴϭϯ ϱ͘ϵϴϬ dZ^^^s Ϯ Ϯ͕Ϯϭϲ͛ Ϯ͕ϭϲϴ͛ ϯ͘ϵϵϮ ϳ͘Ϭϲϯ ϭͲϭͬϮ͟'>Dϭʹ^WDϭͲϭͬϮΗ'>s/WKZͲϭϱ ϰ͕ϭϵϰ͛ ϯ͕ϴϭϯ͛ ϯ͘ϵϵϮ ϳ͘Ϭϲϯ ϭͲϭͬϮ͟ '>D Ϯ ʹ ^WDϭͲϭͬϮΗ'>s/WKZͲϭϱ ϱ͕ϱϬϰ͛ ϰ͕ϴϴϲ͛ ϯ͘ϵϵϮ ϳ͘Ϭϲϯ ϭͲϭͬϮ͟ '>D ϯ ʹ ^WDϭͲϭͬϮΗ'>s/WKZͲϭϱ ϲ͕ϯϮϵ͛ ϱ͕ϱϲϵ͛ ϯ͘ϴϯϯ ϲ͘ϰϭϬ ϭͲϭͬϮ͟'>Dϰʹ^WDϭΗ'>s/WKͲϭ ϳ͕Ϭϴϳ͛ ϲ͕ϭϵϰ͛ ϯ͘ϴϯϯ ϲ͘ϰϭϬ ϭͲϭͬϮ͟'>Dϱʹ^WDϭΗ'>s/WKͲϭ ϴ͕ϬϮϬ͛ ϲ͕ϵϱϭ͛ ϯ͘ϴϯϯ ϲ͘ϰϭϬ ϭͲϭͬϮ͟ '>D ϲ ʹ ^WDϭΗ'>s/WKͲϭ ϯ ϴ͕Ϭϳϭ͛ ϲ͕ϵϵϱ͛ ϯ͘ϵϵϬ ϴ͘ϮϱϬ ϵͲϱͬϴΗǆϰͲϭͬϮΗ>dϯϮ͘ϯͲϰϯ͘ϱη,ǇĚWĂĐŬĞƌ;ϱϴ<ƐŚĞĂƌͿ ϰ ϴ͕ϭϮϲ͛ ϳ͕Ϭϰϯ͛ ϯ͘ϴϭϯ ϱ͘ϬϬϬ ϰͲϭͬϮΗ>dyͲEŝƉƉůĞ ϱ ϴ͕ϱϬϲ͛ ϳ͕ϯϲϰ͛ ϯ͘ϵϱϴ ϱ͘ϬϬϬ ϰϭͬϮΗ/dĐŽůůĂƌŵĂĚĞƚŽt>';ŵƵůĞƐŚŽĞͿ *UD\OLQJ3ODWIRUP *5' sĂůǀĞ͕DĂƐƚĞƌ͕t<DͲD͕ ϰϭͬϭϲϱD&͕,tK͕ ƚƌŝŵ sĂůǀĞ͕hƉƉĞƌŵĂƐƚĞƌ͕ t<DͲD͕ ϰϭͬϭϲϱD&͕,tK͕ƚƌŝŵ sĂůǀĞ͕^ǁĂď͕t<DͲD ϰϭͬϭϲϱD&͕,tK͕ ƚƌŝŵ ,d͕ŽǁĞŶ͕ϰϭͬϭϲϱD& ǆϳΖ͛ ƋƵŝĐŬƵŶŝŽŶƚŽƉ ĚĂƉƚĞƌ͕ĂĐƚƵƐͲEͲϲ͘ϮϱΖ͕͛ ϭϭϱDƐƚĚĚǆϰϭͬϭϲϱDƐƚĚĚ ƚŽƉ͕ǁͬϮͲϭΖ͛ŶƉƚĐŽŶƚƌŽůůŝŶĞ ĞǆŝƚƐ ĂƐŝŶŐŚĞĂĚ͕^ŚĂĨĨĞƌ<͕ ϭϯϱͬϴϯDǆϭϯϯͬϴ^Kt͕ǁͬ ϮͲϮΖ͛>WK ϭϯϯͬϴΖ͛ ϵϱͬϴΖ͛ dƵďŝŶŐŚĞĂĚ͕ĂĐƚƵƐͲϮϵ>͕ ϭϯϱͬϴϯDǆϭϭϱD͕ ǁͬϮͲϮϭͬϭϲϱD^^K͕ ǁͬϵϱͬϴ,W^ďŽƚƚŽŵ ϰЪ͛͛ dƵďŝŶŐŚĂŶŐĞƌ͕ĂĐƚƵƐͲEͲ >͕ϰЪhϴƌĚůŝĨƚĂŶĚ ƐƵƐƉǆǁϲЬŽĚĞǆƚŶĞĐŬ͕ϰΖ͛ ƚǇƉĞ,WsƉƌŽĨŝůĞ͕ͲE> ŵĂƚĞƌŝĂů sĂůǀĞ͕tŝŶŐ͕^^s͕t<DͲD͕ ϰϭͬϭϲϱD&͕ǁͬϭϱΖ͛ ĂŝƌŽƉĞƌĂƚŽƌ 'ƌĂǇůŝŶŐWůĂƚĨŽƌŵ 'ͲϭƌĚ ϭϯϯͬϴyϵϱͬϴyϰϭͬϮ *UD\OLQJ3ODWIRUP %236WDFN +$. +,/&253$/$6.$//& 6ZDFR6XSHUFKRNH%ORRH\/LQH7R*DV%XVWHU/ŶůĞƚ Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 06/14/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL TBU G-01RD (PTD 191-139) PPROF 05/28/2022 Please include current contact information if different from above. PTD: 191-139 T36703 Kayla Junke Digitally signed by Kayla Junke Date: 2022.06.17 10:18:40 -08'00' Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 06/06/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL TBU G-01RD (PTD 191-139) PUNCH 05/16/2022 Please include current contact information if different from above. PTD:191-139 T36690 Kayla Junke Digitally signed by Kayla Junke Date: 2022.06.08 13:42:25 -08'00' 5HJJ-DPHV%2*& )URP:DGH+XGJHQV&:DGH+XGJHQV#KLOFRUSFRP! 6HQW0RQGD\0D\30 7R'2$$2*&&3UXGKRH%D\5HJJ-DPHV%2*&%URRNV3KRHEH/2*& &F-XDQLWD/RYHWW$$22IIVKRUH.DUVRQ.R]XE& 6XEMHFW+$.7%8*5'%23(7HVW5HSRUW $WWDFKPHQWV+$.[OV[ WůĞĂƐĞƐĞĞĂƚƚĂĐŚĞĚKWdĞƐƚZĞƉŽƌƚϱͲϮϵͲϮϮ͘ dŚĂŶŬƐ͕ tĂĚĞ,ƵĚŐĞŶƐ tĞůů^ŝƚĞDĂŶĂŐĞƌ ,<ZŝŐϰϬϰ ;ϵϬϯͿ ϯϯϭͲϲϳϭϭʹ ǁĂĚĞ͘ŚƵĚŐĞŶƐΛŚŝůĐŽƌƉ͘ĐŽŵ 7KHLQIRUPDWLRQFRQWDLQHGLQWKLVHPDLOPHVVDJHLVFRQILGHQWLDODQGPD\EHOHJDOO\SULYLOHJHGDQGLVLQWHQGHGRQO\IRUWKHXVHRIWKHLQGLYLGXDORUHQWLW\QDPHG DERYH,I\RXDUHQRWDQLQWHQGHGUHFLSLHQWRULI\RXKDYHUHFHLYHGWKLVPHVVDJHLQHUURU\RXDUHKHUHE\QRWLILHGWKDWDQ\GLVVHPLQDWLRQGLVWULEXWLRQRUFRS\RIWKLV HPDLOLVVWULFWO\SURKLELWHG,I\RXKDYHUHFHLYHGWKLVHPDLOLQHUURUSOHDVHLPPHGLDWHO\QRWLI\XVE\UHWXUQHPDLORUWHOHSKRQHLIWKHVHQGHU VSKRQHQXPEHULVOLVWHG DERYHWKHQSURPSWO\DQGSHUPDQHQWO\GHOHWHWKLVPHVVDJH :KLOHDOOUHDVRQDEOHFDUHKDVEHHQWDNHQWRDYRLGWKHWUDQVPLVVLRQRIYLUXVHVLWLVWKHUHVSRQVLELOLW\RIWKHUHFLSLHQWWRHQVXUHWKDWWKHRQZDUGWUDQVPLVVLRQ RSHQLQJRUXVHRIWKLVPHVVDJHDQGDQ\DWWDFKPHQWVZLOOQRWDGYHUVHO\DIIHFWLWVV\VWHPVRUGDWD1RUHVSRQVLELOLW\LVDFFHSWHGE\WKHFRPSDQ\LQWKLVUHJDUGDQG WKHUHFLSLHQWVKRXOGFDUU\RXWVXFKYLUXVDQGRWKHUFKHFNVDVLWFRQVLGHUVDSSURSULDWH &$87,217KLVHPDLORULJLQDWHGIURPRXWVLGHWKH6WDWHRI$ODVNDPDLOV\VWHP'RQRWFOLFNOLQNVRURSHQ DWWDFKPHQWVXQOHVV\RXUHFRJQL]HWKHVHQGHUDQGNQRZWKHFRQWHQWLVVDIH 7%8*5' 37' STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* SSu b m i tt t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Owner/Contractor: Rig No.:404 DATE: 5/29/22 Rig Rep.: Rig Phone: 907-776-6754 Operator: Op. Phone: 907-776-6754 Rep.: E-Mail Well Name: PTD #11911390 Sundry #322-261 Operation: Drilling: Workover: x Explor.: Test: Initial: Weekly: x Bi-Weekly: Other: Rams:250-3500 Annular:250-3500 Valves:250-3500 MASP:2431 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen.P Well Sign P Upper Kelly 0NA Housekeeping P Rig P Lower Kelly 0NA PTD On Location P Hazard Sec.P Ball Type 1P Standing Order Posted P Misc.NA Inside BOP 1P FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0NATrip Tank NA NA Annular Preventer 1 13-5/8" 5K P Pit Level Indicators PP #1 Rams 1 2-7/8"x5-1/2" 5K P Flow Indicator NA NA #2 Rams 1 Blind 5K P Meth Gas Detector PP #3 Rams 0NAH2S Gas Detector PP #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NA Quantity Test Result Choke Ln. Valves 1 2-1/16" 5K P Inside Reel valves 0NA HCR Valves 2 2-1/16" 5K P Kill Line Valves 2 2-1/16" 5K P Check Valve 0NAACCUMULATOR SYSTEM: BOP Misc 0NA Time/Pressure Test Result System Pressure (psi)3000 P CHOKE MANIFOLD:Pressure After Closure (psi)1900 P Quantity Test Result 200 psi Attained (sec)18 P No. Valves 11 P Full Pressure Attained (sec)82 P Manual Chokes 1P Blind Switch Covers: All stations Yes Hydraulic Chokes 1P Nitgn. Bottles # & psi (Avg.): 4 x 2240psi P CH Misc 0NA ACC Misc 0NA Test Results Number of Failures:0 Test Time:4.5 Hours Repair or replacement of equipment will be made within days. Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 5-27-22/9:23am Waived By Test Start Date/Time:5/28/2022 22:00 (date) (time)Witness Test Finish Date/Time:5/29/2022 2:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Hilcorp Tested with 4-1/2" test joint, Tested gas alarms. Annular closing time on 4-1/2" TJ 15sec. VBR closing time 9sec on 4- 1/2" test joint. Blind rams closing time 9sec. HCR closing time 2sec. Chad Johnson/Joe Steiner Hilcorp Alaska Wade Hudgens/K. Kozub TBU G-01RD Test Pressure (psi): wade.hudgens@hilcorp.com Form 10-424 (Revised 02/2022) 2022-0529_BOP_Hilcorp404_TBU_G-01RD 9 9 9 9 9 9 9 99 9 9 -5HJJ Annular closing time on 4-1/2" TJ 15sec. VBR closing time 9sec on 4- 1/2" test joint. Blind rams closing time 9sec. HCR closing time 2sec. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Wade Hudgens - (C) To:Regg, James B (OGC);DOA AOGCC Prudhoe Bay Cc:Katherine O"Connor;Karson Kozub - (C);Chad Helgeson Subject:Trading Bay Unit G-01RD (PTD 191-139) (Sundry 322-261) Report for BOPE used to prevent flow Date:Saturday, May 28, 2022 12:01:42 AM Some people who received this message don't often get email from wade.hudgens@hilcorp.com. Learn why this is important Good evening Mr. Regg, I am writing to report the use of using our BOPE’s to prevent the flow of fluids on 5/27/22 at 17:15hrs. Details of the event are below. Our plan forward is to pull out of hole with our storm packer, then test the BOPE components used. BOPE was used on 5/22/2022 @ 17:15hrs Well Information: Trading Bay Unit G-01RD/Grayling Platform/PTD 191-139 HAK 404: Rig Operator All American Oilfield Contact: Wade Hudgens/Karson Kozub 907-776-6754 BOPE used: 2-7/8”-5.5” VBR, HCR Kill Operations Summary: * All fluid is 8.5ppg filtered inlet water A retrievable storm packer was placed at 3,045ft on 5/25 and pressure tested for the change out of a tubing adapter spool. The tubing adapter spool was changed out, BOPEs were nippled back up and tested after adapter change. Work string was then ran to retrieve the storm packer on 5/27. Circulated bottoms up, FOSV was installed on the workstring in the closed position, the storm packer was then successfully engaged with the work string, opening the storm valve in the packer (packer still set). By design, the storm valve lets IA and tubing pressure from below the packer communicate to surface through the tubing only. IA was fluid packed and no change in fluid level was observed No pressure was observed below the packer, a workstring volume was pumped down the work string (30BBL FIW) and the workstring went on a vacuum. Well was monitored for flow for 30min, no flow observed, workstring still on a vacuum. Annular was closed and workstring was picked up to release the storm packer. IA monitored and went on a vacuum. Monitored IA, and pumped 1.5BPM down the IA. No pump pressure observed. 20BBL FIW pumped. Workstring and IA on vacuum Continued pumping 1.5BPM down IA. Opened annular, set pipe in slips, removed pup joint with pump in sub that was above the FOSV. Continue to monitor IA from the rig floor. Fluid was observed rising in the BOPE stack, hole fill turned off, VBR pipe rams and Kill HCR were closed Well monitored for pressure buildup. Final SITP 0psi, Final SICP 310psi Reason for BOPE use: To prevent fluid flow from the well сссссссс FRUUHFWGDWHLVMEU 9 9 9 9 -5HJJ Trading Bay Unit G-01RD (PTD 191-139) HAK 404: BOPE used: R pipe rams and Kill HCR were closed Actions taken: Last BOPE test 5/22/22 Once well was stable with initial pressures T/IA - 0psi/310psi, Lube and bleed was used until the IA was bled to 0psi. Final pressures T/IA 0psi/0psi – Total 110BBLS FIW pumped (Completed Time 22:13) Surface to surface circulation could not be established due to high formation losses Pump 100bbl FIW down the IA, monitor well. Tubing and IA on a vacuum Pump 90bbl FIW down the workstring. Tubing and IA on a vacuum Actions to be taken: BOPE test of used components when the tubing and storm packer is pulled out of hole. Please let me know if you need any more information. Thanks, Wade Hudgens Well Site Manager Rig 404 (907) 776-6754 – O (903) 331-6711 - C The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 9 9 Lube and bleed was used until the IA was bled to 0psi. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________TRADING BAY UNIT G-01RD JBR 06/15/2022 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:0 Good test. Annular close: 15sec rams: 7sec HCR: 1sec 18 bottle blatters @ 1050psi avg. Test Results TEST DATA Rig Rep:Castagine/SteinerOperator:Hilcorp Alaska, LLC Operator Rep:Hudgens/Linaman Contractor/Rig No.:Hilcorp 404 PTD#:1911390 DATE:5/22/2022 Type Operation:WRKOV Annular: 250/3500Type Test:INIT Valves: 250/3500 Rams: 250/3500 Test Pressures:Inspection No:bopAGE220529070744 Inspector Adam Earl Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time MASP: 2431 Sundry No: 322-261 Location Gen.:P Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Drl. Rig P Hazard Sec.P Misc NA Upper Kelly 0 NA Lower Kelly 1 P Ball Type 1 P Inside BOP 1 P FSV Misc 0 NA 11 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13 5/8 P #1 Rams 1 2 7/8 X 5 1/2 P #2 Rams 1 Blind P #3 Rams 0 NA #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 2 1/16 P HCR Valves 2 2 1/16 P Kill Line Valves 2 2 1/16 P Check Valve 0 NA BOP Misc 0 NA System Pressure P3000 Pressure After Closure P1850 200 PSI Attained P17 Full Pressure Attained P82 Blind Switch Covers:PAll Stations Nitgn. Bottles (avg):P4@2200 ACC Misc NA0 NA NATrip Tank P PPit Level Indicators NA NAFlow Indicator P PMeth Gas Detector P PH2S Gas Detector 0 NAMS Misc Inside Reel Valves 0 NA 9 9 9 9 9 9 9 9 9 9 9 9Annular close: 15sec rams: 7sec HCR: 1sec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y Samantha Carlisle at 2:56 pm, May 02, 2022 'LJLWDOO\VLJQHGE\'DQ0DUORZH '1FQ 'DQ0DUORZH RX 8VHUV 'DWH 'DQ0DUORZH X BOP test to 3500 psi Provide 48 hrs notice for AOGCC to witness casing test after setting patch. Provide 48 hrs notice for AOGCC to witness MITIA. DSR-5/4/22BJM 5/5/22 10-404 DLB 05-04-2022 Downhole commingling of production for leak locating purposes is authorized. X dts 5/6/2022 JLC 5/6/2022 Jeremy Price Digitally signed by Jeremy Price Date: 2022.05.06 10:38:29 -08'00' RBDMS SJC 051322 tĞůůtŽƌŬWƌŽŐŶŽƐŝƐ tĞůů͗'ͲϬϭZ tĞůůEĂŵĞ͗'ͲϬϭZW/EƵŵďĞƌ͗ϱϬͲϳϯϯͲϮϬϬϯϳͲϬϭͲϬϬ ƵƌƌĞŶƚ^ƚĂƚƵƐ͗^WWƌŽĚƵĐĞƌ >ĞŐ͗>ĞŐηϮ;EĐŽƌŶĞƌͿ ƐƚŝŵĂƚĞĚ^ƚĂƌƚĂƚĞ͗DĂǇϭϬ͕ϮϬϮϮ ZŝŐ͗,<ϰϬϰ ZĞŐ͘ƉƉƌŽǀĂůZĞƋ͛Ě͍ϰϬϯ ĂƚĞZĞŐ͘ƉƉƌŽǀĂůZĞĐ͛ǀĚ͗ ZĞŐƵůĂƚŽƌǇŽŶƚĂĐƚ͗:ƵĂŶŝƚĂ>ŽǀĞƚƚ;ϴϯϯϮͿ WĞƌŵŝƚƚŽƌŝůůEƵŵďĞƌ͗ϭϵϭͲϭϯϵ &ŝƌƐƚĂůůŶŐŝŶĞĞƌ͗<ĂƚŚĞƌŝŶĞK͛ŽŶŶŽƌ ;ϵϬϳͿϳϳϳͲϴϯϳϲ;KͿ ;ϮϭϰͿϲϴϰͲϳϰϬϬ;DͿ ^ĞĐŽŶĚĂůůŶŐŝŶĞĞƌ͗ŚĂĚ,ĞůŐĞƐŽŶ ;ϵϬϳͿͲϳϳϳͲϴϰϬϱ;KͿ ;ϵϬϳͿϮϮϵͲϰϴϮϰ;DͿ Current Bottom Hole Pressure:2710 psi @ 6,932’ TVD Gas zone based on ESP Gauge 4/11/22 Maximum Expected BHP (oil zone):3302 psi @ 8715’ TVD Oil zone based on ESP Gauge 4/5/18 (7.3 ppg) Maximum Potential Surface Pressure:2431 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) ƌŝĞĨtĞůů^ƵŵŵĂƌǇ 'ͲϬϭZŝƐĂ'ͲŽŶĞĂŶĚ,ĞŵůŽĐŬWƌŽĚƵĐĞƌƚŚĂƚǁĂƐĐŽŶǀĞƌƚĞĚƚŽĂŶ^WĨƌŽŵĂĚƵĂůƐƚƌŝŶŐŐĂƐͲůŝĨƚĐŽŵƉůĞƚŝŽŶŝŶKĐƚŽďĞƌ ϮϬϭϮ͘/ŶDĂƌĐŚϮϬϮϭƚŚĞ^WǁĂƐƌĞƉůĂĐĞĚĂŶĚĂĐůĞĂŶŽƵƚǁĂƐƉĞƌĨŽƌŵĞĚ͘ĨƚĞƌƚŚĞǁĞůůǁĂƐďƌŽƵŐŚƚŽŶůŝŶĞƚŚĞǁĞůůǁĂƐ ŶŽůŽŶŐĞƌĂďůĞƚŽƉĂƐƐĂŶŽĨůŽǁƚĞƐƚ͘dŚĞ^WǁĂƐƉƵůůĞĚĂŶĚĂ Ŷ^WƉĂĐŬĞƌΘ^^^sǁĞƌĞŝŶƐƚĂůůĞĚŝŶĞĂƌůǇƐƵŵŵĞƌϮϬϮϭ͘ ĨƚĞƌĂĨĞǁŵŽŶƚŚƐŽĨƉƌŽĚƵĐƚŝŽŶ͕ƚŚĞ^WŐĂƐůŽĐŬĞĚĂŶĚƚŚĞƚƵďŝŶŐĂŶĚ/ƉƌĞƐƐƵƌĞƐĐůŝŵďĞĚƚŽϮϰϯϭƉƐŝĨƌŽŵĂŶƵŶŬŶŽǁŶ ůĞĂŬƚŽĂŐĂƐǌŽŶĞ͘ƉĂĐŬĞƌůĞĂŬǁĂƐŝĚĞŶƚŝĨŝĞĚǁŝƚŚƚŚĞŚŝŐŚŐĂƐƉƌĞƐƐƵƌĞƐ͕ĂŶĚĂƐĞĂůͲƚŝƚĞƚƌĞĂƚŵĞŶƚǁĂƐĂƉƉůŝĞĚƚŽĨŝǆ ƚŚĞůĞĂŬŝŶƚŚĞƉĂĐŬĞƌĂƐƐĞŵďůǇŽŶKĐƚŽďĞƌϭϱďƵƚǁĂƐƵŶƐƵĐĐĞƐƐĨƵů͘ ƚĞŵƉůŽŐǁĂƐƌƵŶŝŶƐŝĚĞƚŚĞƚƵďŝŶŐƚŽƚŚĞƚŽƉŽĨƚŚĞ^W;ϳ͕ϵϮϰ͛ͿǁŝƚŚƚŚĞǁĞůůĨůŽǁŝŶŐŐĂƐĂŶĚŶŽĐŽŽůŝŶŐĞĨĨĞĐƚǁĂƐ ƐĞĞŶŽŶƚŚĞůŽŐ͕ǁŚŝĐŚǁŽƵůĚŝŶĚŝĐĂƚĞǁŚĞƌĞƚŚĞŐĂƐǁĂƐĐŽŵŝŶŐĨƌŽŵ͘tĞŚĂǀĞĐŽŶĐůƵĚĞĚƚŚĂƚƚŚĞŐĂƐŝƐĐŽŵŝŶŐĨƌŽŵ ďĞůŽǁϳ͕ϵϮϰ͛ďĂƐĞĚŽŶƚŚŝƐĚĂƚĂ͘dŚĞ^WƉƌĞǀĞŶƚƐĐŽůůĞĐƚŝŶŐĚĂƚĂĂŶǇĚĞĞƉĞƌƚŽĚŝĂŐŶŽƐĞƚŚĞƉƌŽĚƵĐŝŶŐŐĂƐǌŽŶĞ͘ ĐŽŵŝŶŐůŝŶŐĂƵƚŚŽƌŝǌĂƚŝŽŶƚŽĨůŽǁƚŚĞŐĂƐĂŶĚŽŝůǌŽŶĞƐĂƚƚŚĞƐĂŵĞƚŝŵĞǁĂƐŽďƚĂŝŶĞĚŝŶŽƌĚĞƌƚŽƚƌǇĂŶĚƋƵĂŶƚŝĨǇƚŚĞŐĂƐ ĂĐĐƵŵƵůĂƚŝŽŶƐŝǌĞ͘dŚŝƐǁĂƐŐƌĂŶƚĞĚƚŚƌŽƵŐŚƉƌŝůŽĨϮϬϮϮ͘dŚĞǁĞůůǁĂƐƐĞƚƵƉǁŝƚŚĂƚƵďŝŶŐƉůƵŐĂďŽǀĞƚŚĞ^WĂŶĚĂŶ ŽƌŝĨŝĐĞǀĂůǀĞǁĂƐŝŶƐƚĂůůĞĚŝŶƚŚĞƚŽƉŵĂŶĚƌĞůƚŽĨůŽǁŐĂƐ͘tŚŝůĞĨůŽǁŝŶŐŐĂƐĨƌŽŵƚŚĞǁĞůůǁŝƚŚƚŚĞ^WƐŚƵƚŝŶƚŚĞĨůƵŝĚ ĨƌŽŵƚŚĞŽŝůǌŽŶĞ;ϵϴйǁĂƚĞƌͿƐůŽǁůǇŬŝůůƐƚŚĞŐĂƐǌŽŶĞ͘ dŚĞĐƵƌƌĞŶƚŽďũĞĐƚŝǀĞŽĨƚŚŝƐƉƌŽŐƌĂŵŝƐƚŽƉƵůůƚŚĞ^WĂŶĚĐŽŵƉůĞƚĞĚŝĂŐŶŽƐƚŝĐǁŽƌŬƚŽĚĞƚĞƌŵŝŶĞǁŚĞƌĞƚŚĞŐĂƐǌŽŶĞŝƐ ĐŽŵŝŶŐĨƌŽŵ͘dŚĞƉƌŝŵĂƌǇŽďũĞĐƚŝǀĞŝƐƚŽƌĞƚƵƌŶƚŚŝƐǁĞůůƚŽĂŶŽŝůƉƌŽĚƵĐĞƌďǇƉĂƚĐŚŝŶŐŽĨĨƚŚĞŐĂƐ͘/ĨƚŚŝƐŝƐŶŽƚƉŽƐƐŝďůĞ͕ ƚŚĞƐĞĐŽŶĚĂƌǇŐŽĂůŝƐƚŽƚƵƌŶƚŚŝƐǁĞůůŝŶƚŽĂŐĂƐůŝĨƚĞĚƉƌŽĚƵĐĞƌƚŽĚŝĂŐŶŽƐĞƚŚĞŐĂƐĐŽŶƚƌŝďƵƚŝŶŐǌŽŶĞĂŶĚĚĞƚĞƌŵŝŶĞ ƌĞƉĂŝƌͬƚƌĞĂƚŵĞŶƚͬĨůŽǁŽƉƚŝŽŶƐŽŶĐĞƐŽƵƌĐĞŝƐŝĚĞŶƚŝĨŝĞĚ͘,ŝůĐŽƌƉŝƐƌĞƋƵĞƐƚŝŶŐĂĐŽŵŵŝŶŐůŝŶŐĂƵƚŚŽƌŝǌĂƚŝŽŶĨŽƌĨůŽǁŝŶŐƚ ŚĞ DŝĚĚůĞ<ĞŶĂŝ'Θ,ĞůŵŽĐŬKŝůƉŽŽůǁŝƚŚDŝĚĚůĞ<ĞŶĂŝ'ĂƐWŽŽůŝĨƚŚĞŐĂƐůŝĨƚĞĚĐŽŵƉůĞƚŝŽŶŝƐƌƵŶ͘/ĨŶĞŝƚŚĞƌŽĨƚŚŽƐĞ ŽƉƚŝŽŶƐĂƌĞŽƉĞƌĂƚŝŽŶĂůůǇǀŝĂďůĞ͕ĂƉůƵŐǁŝůůďĞƐĞƚĂŶĚƐƵƐƉĞŶĚƚŚŝƐǁĞůů͘ tĞůůŽŶĚŝƚŝŽŶƐ͗ >ĂƐƚĂƐŝŶŐWƌĞƐƐƵƌĞdĞƐƚ͗DĂƌĐŚϯϬ͕ϮϬϮϭΛϵ͕ϴϮϱ͛ƚŽϭ͕ϱϬϬƉƐŝŐĂŶĚĐŚĂƌƚĞĚĨŽƌϯϬŵŝŶƵƚĞƐ͘ ƵƌƌĞŶƚĐŽŶĚŝƚŝŽŶ͗ϮϰϬƉƐŝΛϰϬͲϱϬŵĐĨĚŐĂƐ >ĂƐƚ^/ĚĂƚĂǁͬϵͲĚĂǇďƵŝůĚƵƉŽŶƉƌŝůϵ͖ƉƌĞƐƐƵƌĞƐdͬ/ͬKͬKKʹϮϯϭϮͬϮϯϭϮͬϮϮϲͬϭϳ dŽƉŽĨŽŝůͲďĞĂƌŝŶŐƐĂŶĚƐ;ďŽƚƚŽŵŽĨŽĂůͺϯϵͿʹϭϬ͕ϬϲϲĨƚD WZZŝŐWƌŽĐĞĚƵƌĞ;EŽŶƐƵŶĚƌǇZĞƋƵŝƌĞĚͿ͗ ϭ͘ Zh^ůŝĐŬůŝŶĞ͕WdϮϱϬ>ͬϯ͕ϱϬϬ,W^/ Ă͘ >ŽĐŬŽƉĞŶdZ^^s ď͘ WƵůůƉůƵŐĨƌŽŵƚƵďŝŶŐ Đ͘ /ŶƐƚĂůůƉůƵŐŝŶƐƚĂƚŝŽŶϭ Ϯ͘ <ŝůůƚŚĞǁĞůůǁŝƚŚ&/t;ϴ͘ϱƉƉŐͿ͕ďƵůůŚĞĂĚĂŵŝŶŝŵƵŵŽĨϴϬϬďď ůƐ;ϳϬϱďďůǁĞůůǀŽůƵŵĞͿƚŽĞŶƐƵƌĞĂůůŐĂƐŝƐ ƉƵƐŚĞĚĂǁĂǇ ,ŝůĐŽƌƉŝƐƌĞƋƵĞƐƚŝŶŐĂĐŽŵŵŝŶŐůŝŶŐĂƵƚŚŽƌŝǌĂƚŝŽŶĨŽƌĨůŽǁŝŶŐƚŚĞ DŝĚĚůĞ<ĞŶĂŝ'Θ,ĞůŵŽĐŬKŝůƉŽŽůǁŝƚŚDŝĚĚůĞ<ĞŶĂŝ'ĂƐWŽŽůŝĨƚŚĞŐĂƐůŝĨƚĞĚĐŽŵƉůĞƚŝŽŶŝƐƌƵŶ͘Ĩ Punch tubing above pump to assist with well kill. - bjm tĞůůtŽƌŬWƌŽŐŶŽƐŝƐ tĞůů͗'ͲϬϭZ Ă͘ /ĨŶĞĐĞƐƐĂƌǇĨŽƌŝŶĐƌĞĂƐĞĚŝŶũĞĐƚŝŽŶƌĂƚĞŽƌƚŽďĞĂďůĞƚŽĐŝƌĐƵůĂƚĞ ď͘ ZhůŝŶĞ͕WdϮϱϬ>ͬϯ͕ϱϬϬ,W^/ Đ͘ Z/,ĂŶĚƉƵŶĐŚƚƵďŝŶŐĂďŽǀĞƉƵŵƉĨŽƌĐŝƌĐƵůĂƚŝŽŶ Ě͘ ZůŝŶĞ ZŝŐWƌŽĐĞĚƵƌĞ;ƐƵŶĚƌǇƌĞƋƵŝƌĞĚͿ ϯ͘ D/Zh,<ϰϬϰ ϰ͘ <ŝůůƚŚĞǁĞůůǁŝƚŚ&/t͕ĐŝƌĐƵůĂƚĞϴϬϬďďůƐƚŽĞŶƐƵƌĞŶŽĂĚĚŝƚŝŽŶĂůŐĂƐŝŶĨůŽǁĞĚĚƵƌŝŶŐZh ϱ͘ ^ĞƚWs͕EƚƌĞĞ͕EhKWĂŶĚƚĞƐƚƚŽϮϱϬW^/ůŽǁͬϯ͕ϱϬϬW^/ŚŝŐŚ EŽƚĞ͗EŽƚŝĨǇK'ϰϴŚŽƵƌƐŝŶĂĚǀĂŶĐĞŽĨƚĞƐƚƚŽĂůůŽǁƚŚĞŵƚŽǁŝƚŶĞƐƐƚĞƐƚ ϲ͘ DŽŶŝƚŽƌǁĞůůƚŽĞŶƐƵƌĞŝƚŝƐƐƚĂƚŝĐ͘ŝƌĐƵůĂƚĞ&/tĂƐŶĞĞĚĞĚƚŽŬŝůůǁĞůů͘ EŽƚĞ͗KW͛ƐŵĂǇďĞĐůŽƐĞĚĂƐŶĞĞĚĞĚƚŽĐŝƌĐƵůĂƚĞƚŚĞǁĞůůĚƵƌŝŶŐƚŚŝƐƉƌŽũĞĐƚ ϳ͘ hŶƐĞĂƚŚĂŶŐĞƌĂŶĚWKK,ǁŝƚŚ^WĐŽŵƉůĞƚŝŽŶ Ă͘ WĂĐŬĞƌƌĞƋƵŝƌĞƐϰϬ<ƚŽƐŚĞĂƌ͕ƐƚƌĂŝŐŚƚƉƵůůƚŽƌĞůĞĂƐĞ͕ŽŶĐĞƉĂĐŬĞƌŝƐĨƌĞĞǁĂŝƚĂŵŝŶŝŵƵŵŽĨϯϬŵŝŶ ĨŽƌĞůĞŵĞŶƚƐƚŽƌĞůĂǆ͕;ĚŽŶ͛ƚƚƌǇƚŽĨŽƌĐĞƚŚĞƉĂĐŬĞƌŽƵƚǁŝƚŚŽƵƚƚĂůŬŝŶŐƚŽĞŶŐŝŶĞĞƌͿ ϴ͘ ŽŵƉůĞƚĞĚŝĂŐŶŽƐƚŝĐǁŽƌŬĂƐŶĞĞĚĞĚƚŽĚĞƚĞƌŵŝŶĞůŽĐĂƚŝŽŶŽĨŐĂƐĨůŽǁ͕;ƐŽŵĞŽƉƚŝŽŶƐůŝƐƚĞĚďĞůŽǁͿ͗ Ă͘ ĂůŝƉĞƌůŽŐ ď͘ >ĞĂŬĚĞƚĞĐƚůŽŐ Đ͘ ĂƐŝŶŐĚƌŝĨƚƐ Ě͘ dĞƐƚƉĂĐŬĞƌ͕ƚĞƐƚŝŶŐĐĂƐŝŶŐ ϵ͘ WhdĞƐƚWĂĐŬĞƌ͕;ŵŝŶŝŵŽĨϯϬ͕ϬϬϬůďƐŚĂŶŐŝŶŐďĞůŽǁͿZ/,ĂŶĚƐĞƚĂƚϯ͕ϬϬϬ͛ ϭϬ͘ WKK,ǁŝƚŚƚƵďŝŶŐ ϭϭ͘ WƌĞƐƐƵƌĞƚĞƐƚƉĂĐŬĞƌĂŶĚĐĂƐŝŶŐƚŽϯϱϬϬW^/ ϭϮ͘ EKWĂŶĚƚƵďŝŶŐŚĞĂĚ͕ĂŶĚŝŶƐƚĂůůŶĞǁƚƵďŝŶŐŚĞĂĚ ϭϯ͘ EhKWΘƚĞƐƚĂŶǇĐŽŶŶĞĐƚŝŽŶƐƐĞƉĂƌĂƚĞĚĚƵƌŝŶŐǁŽƌŬ Ă͘ EŽƚŝĨǇK'ϰϴŚŽƵƌƐŝŶĂĚǀĂŶĐĞŽĨƚĞƐƚƚŽĂůůŽǁƚŚĞŵƚŽǁŝƚŶĞƐƐƚĞƐƚ ϭϰ͘ Z/,ĂŶĚƌĞƚƌŝĞǀĞƚĞƐƚƉĂĐŬĞƌ͕ĞĨŽƌĞůĂƚĐŚŝŶŐƉĂĐŬĞƌƌĞǀĞƌƐĞďŽƚƚŽŵƐƵƉ ϭϱ͘ DĂŝŶƚĂŝŶĐŝƌĐƉĂƚŚǁŚĞŶƌĞůĞĂƐŝŶŐƉĂĐŬĞƌ ϭϲ͘ ZĞůĞĂƐĞƉĂĐŬĞƌ͕ĐŝƌĐƵůĂƚĞďŽƚƚŽŵƐƵƉ ϭϳ͘ WKK,ĂŶĚ>ƚĞƐƚƉĂĐŬĞƌ ŽŶƚŝŶŐĞŶĐǇKƉƚŝŽŶϭ;ƐĐĞŶĂƌŝŽͲĐĂƐŝŶŐĚƌŝĨƚƐ͕ĂŶĚĐĂůŝƉĞƌŝŶĚŝĐĂƚĞƐŚŽůĞŝŶĐĂƐŝŶŐďĞůŽǁůŝŶĞƌƚŽƉĂŶĚĂďŽǀĞ ŽŝůďĞĂƌŝŶŐǌŽŶĞΛϭϬ͕Ϭϰϯ͛Ϳ ϭϴ͘ WhĂŶĚƌƵŶцϱϬϬ͛ůŝŶĞƌƉĂƚĐŚƚŽŝƐŽůĂƚĞŐĂƐůĞĂŬ;^ĞĞƉƌŽƉŽƐĞĚƐĐŚĞŵĂƚŝĐηϭĨŽƌĚĞƚĂŝůƐͿ ϭϵ͘ WhƚĞƐƚƉĂĐŬĞƌ͕Z/,ĂŶĚƚĞƐƚĐĂƐŝŶŐĂďŽǀĞƚŚĞƚŽƉŽĨƚŚĞƉĂƚĐŚ͕ƚŽĞŶƐƵƌĞĂůůůĞĂŬƐǁĞƌĞĐŽǀĞƌĞĚďǇƚŚĞƉĂƚĐŚ ϮϬ͘ Wh^WĂŶĚ'>ŽŵƉůĞƚŝŽŶ;^ĞĞWƌŽƉŽƐĞĚ^ĐŚĞŵĂƚŝĐηϭĨŽƌĚĞƚĂ ŝůƐͿ͕Z/,ĂŶĚůĂŶĚ^WǁŝƚŚƚŚĞďŽƚƚŽŵŽĨƚŚĞ ĂƐƐĞŵďůǇĂƚцϴ͕ϭϬϬ͛ Ϯϭ͘ ^ĞƚĂŶĚƚĞƐƚƉĂĐŬĞƌƚŽϮ͕ϱϬϬƉƐŝĐŚĂƌƚŝŶŐĨŽƌϯϬŵŝŶƵƚĞƐ 'ŽƚŽƐƚĞƉϯϭ ŽŶƚŝŶŐĞŶĐǇKƉƚŝŽŶϮ;^ĐĞŶĂƌŝŽʹĐĂƐŝŶŐĚƌŝĨƚƐďƵƚƵŶĐůĞĂƌŽĨŐĂƐƐŽƵƌĐĞͿ ϮϮ͘ WhƌĞƚƌŝĞǀĂďůĞƉĂĐŬĞƌĂŶĚ'>ĚĞƐŝŐŶ;^ĞĞWƌŽƉŽƐĞĚƐĐŚĞŵĂƚŝĐηϮĨŽƌĚĞƚĂŝůƐͿ Ϯϯ͘ Z/,ĂŶĚƐĞƚƉĂĐŬĞƌĂŶĚƚĞƐƚƚƵďŝŶŐ Ϯϰ͘ ^ĞƚĂŶĚƚĞƐƚƉĂĐŬĞƌƚŽϮ͕ϱϬϬƉƐŝĐŚĂƌƚŝŶŐĨŽƌϯϬŵŝŶƵƚĞƐ EŽƚĞ͗KŶĐĞƌŝŐŝƐŽĨĨǁĞůů͕KƉĞƌĂƚŝŽŶƐǁŝůůĨůŽǁƚŚĞǁĞůůǁŝƚŚŐĂƐůŝĨƚ͕ĂŶĚŵŽƌĞĚŝĂŐŶŽƐƚŝĐǁŽƌŬǁŝůů ďĞĐŽŵƉůĞƚĞĚƚŽĨŝŶĚŐĂƐƐŽƵƌĐĞ͘ sĂƌŝĂŶĐĞZĞƋƵĞƐƚ͗,ŝůĐŽƌƉǁŝůůƌĞƋƵŝƌĞĂĚĚŝƚŝŽŶĂůK'ĂƉƉƌŽǀĂůƚŽĨůŽǁƚŚĞŐĂƐĂŶĚŽŝůƐĂŶĚƐĐŽŵŵŝŶŐůĞĚ ĨŽƌƚŚĞĚŝĂŐŶŽƐƚŝĐƚĞƐƚŝŶŐŽŶƚŚĞǁĞůů͘/ƚŝƐĞǆƉĞĐƚĞĚƚŚĂƚƚŚĞǁĞůůǁŝůůĨůŽǁŝŶƚŚŝƐĐŽŶĨŝŐƵƌĂƚŝŽŶĨŽƌϱͲϲŵŽŶƚŚƐ ƵŶƚŝůĞƋƵŝƉŵĞŶƚĐĂŶďĞŽďƚĂŝŶĞĚƚŽŝƐŽůĂƚĞƚŚĞŐĂƐͬŽŝůǌŽŶĞƐ͘ Provide 48 hrs notice for AOGCC to witness MITIA. - bjm Commingling is allowed for leak locating purposes only. bjm Provide 48 hrs notice for AOGCC to witness MITIA. - bjm Casing patch not tested. Production rates will be the measure of success. Circulate or bullhead down IA immediately after unseating hanger. -bjm Packer to be set at +/- 7900' MD per diagram attached. - bjm Diagram does not show GLMs. tĞůůtŽƌŬWƌŽŐŶŽƐŝƐ tĞůů͗'ͲϬϭZ ŽŶƚŝŶŐĞŶĐǇKƉƚŝŽŶϯ;^ĐĞŶĂƌŝŽʹĂƐŝŶŐĚĂŵĂŐĞďƵƚĂĐĐĞƐƐŝďůĞďĞƚǁĞĞŶϴ͕ϭϮϳĂŶĚϭϬ͕ϬϲϲĂŶĚĐĂŶŶŽƚ ŝĚĞŶƚŝĨǇŐĂƐƐŽƵƌĐĞͿ Ϯϱ͘ ^ĞƚƉůƵŐĂďŽǀĞϭϬ͕Ϭϰϯ͕͛ĚƵŵƉĐĞŵĞŶƚŽŶƚŽƉŽĨƉůƵŐ Ϯϲ͘ WhƉĞƌŵĂŶĞŶƚƉĂĐŬĞƌĂŶĚ'>ĚĞƐŝŐŶ;^ĞĞWƌŽƉŽƐĞĚƐĐŚĞŵĂƚŝĐηϯĨŽƌĚĞƚĂŝůƐͿ Ϯϳ͘ Z/,ƐĞƚƉĂĐŬĞƌĂŶĚƚĞƐƚƚƵďŝŶŐƚŽϯ͕ϬϬϬƉƐŝĂŶĚĐĂƐŝŶŐƚŽϮ͕ϱϬϬƉƐŝĐŚĂƌƚŝŶŐĨŽƌϯϬŵŝŶƵƚĞƐ 'ŽƚŽƐƚĞƉϯϭ ŽŶƚŝŶŐĞŶĐǇKƉƚŝŽŶϰ;^ĐĞŶĂƌŝŽʹĐĂƐŝŶŐĚĂŵĂŐĞƚŚĂƚĐĂŶŶŽƚďĞƉĂƚĐŚĞĚŽƌǌŽŶĞƐŝƐŽůĂƚĞĚͿ Ϯϴ͘ ^Ğƚϳ͟ƉůƵŐĂďŽǀĞĐĂƐŝŶŐĚĂŵĂŐĞ Ϯϵ͘ ƉƉůǇΕϭϬϬϬƉƐŝƚŽĞŶƐƵƌĞƉůƵŐƐĞƚ ϯϬ͘ ^ƵƐƉĞŶĚǁĞůůĨŽƌĂĚĚŝƚŝŽŶĂůĨƵƚƵƌĞŽƉĞƌĂƚŝŽŶƐ &ŽůůŽǁŝŶŐƐƚĞƉƐĂƉƉůǇǁŝƚŚĂůůĐŽŶƚŝŶŐĞŶĐŝĞƐ ϯϭ͘ ^ĞƚWs͕EKW͕EhƚƌĞĞĂŶĚƚĞƐƚ͘ ϯϮ͘ dƵƌŶǁĞůůŽǀĞƌƚŽƉƌŽĚƵĐƚŝŽŶ͘ ϯϯ͘ ŽŶĚƵĐƚ^s^ƚĞƐƚŝŶŐƉĞƌK'ƌĞŐƵůĂƚŝŽŶƐ ƚƚĂĐŚŵĞŶƚƐ͗ ϭ͘ ƵƌƌĞŶƚtĞůůďŽƌĞ^ĐŚĞŵĂƚŝĐ Ϯ͘ WƌŽƉŽƐĞĚKƉƚŝŽŶηϭtĞůůďŽƌĞ^ĐŚĞŵĂƚŝĐ ϯ͘ WƌŽƉŽƐĞĚKƉƚŝŽŶηϮtĞůůďŽƌĞ^ĐŚĞŵĂƚŝĐ ϰ͘ WƌŽƉŽƐĞĚKƉƚŝŽŶηϯtĞůůďŽƌĞ^ĐŚĞŵĂƚŝĐ ϱ͘ WƌŽƉŽƐĞĚKƉƚŝŽŶηϰtĞůůďŽƌĞ^ĐŚĞŵĂƚŝĐ ϲ͘ ƵƌƌĞŶƚtĞůůŚĞĂĚŝĂŐƌĂŵ ϳ͘ WƌŽƉŽƐĞĚKƉƚŝŽŶηϭtĞůůŚĞĂĚŝĂŐƌĂŵ ϴ͘ WƌŽƉŽƐĞĚKƉƚŝŽŶηϮtĞůůŚĞĂĚŝĂŐƌĂŵ ϵ͘ KWƌĂǁŝŶŐ ϭϬ͘ &ůƵŝĚͬ&ůŽǁŝĂŐƌĂŵ ϭϭ͘ ŚŽŬĞŝĂŐƌĂŵ ϭϮ͘ ZtK^ƵŶĚƌǇŚĂŶŐĞ&Žƌŵ Dump 25' minimum of cement. - bjm Provide 48 hrs notice for AOGCC to witness MITIA. - bjm Separate sundry required for Contingency 4. Depends on well status. For option #3, need to determine and agree with AOGCC which pool the gas will be allocated to before this option is put on production. - bjm Pressure test and tag cement per 20 AAC 25.112(c)(1) -bjm DĐƌƚŚƵƌZŝǀĞƌ&ŝĞůĚ͕dh tĞůů͗'ͲϬϭZ ƐŽŵƉůĞƚĞĚ͗ϬϲͬϭϯͬϮϭ hƉĚĂƚĞĚďǇ͗:>>ϬϳͬϬϲͬϮϭ ^,Dd/ 5.%WR0//:(/(9 ¶ 7' ¶ 3%' ¶ 0$;+2/($1*/( q#¶ 5.%WR7%*+QJU ¶ 7UHHFRQQHFWLRQ%RZHQ +% * * * * +% +% +% +% ϰͲϱͬϴ͟WĞƌĨ'ƵŶΛ ϭϭ͕ϰϬϵ͛ * * +% ´ ´ ´ ´ &ŝƐŚΛϭϭϯϯϳ͛ * +% 72& &%/ (67 72& ¶ &DOF ; ^/E'd/> ^ŝǌĞ td 'ƌĂĚĞ ŽŶŶ / DdŽƉ Dƚŵ Ϯϲ͟ ^ƵƌĨ͘ ϯϮϳ͛ ϭϯͲϯͬϴ͟ ϲϭ :Ͳϱϱ Ƶƚƚ ϭϮ͘ϱϭϱ͟ ^ƵƌĨ͘ Ϯ͕ϭϲϬ͛ ϵͲϱͬϴ͟ ϰϳ EͲϴϬ Ƶƚƚ ϴ͘ϲϴϭ͟ ^ƵƌĨ ϳϵ͛ ϰϬ EͲϴϬ Ƶƚƚ ϴ͘ϴϯϱ͟ ϳϵ͛ ϲ͕Ϯϳϱ͛ ϰϯ͘ϱ EͲϴϬ Ƶƚƚ ϴ͘ϳϱϱ͟ ϲ͕Ϯϳϱ͛ ϴ͕ϭϳϵ͛ ϰϳ EͲϴϬ Ƶƚƚ ϴ͘ϲϴϭ͟ ϴ͕ϭϳϵ͛ ϴ͕ϰϱϬ͛;dKtͿ ϵͲϱͬϴ͟sŽůůĂƌ ϰ͕ϵϬϯ͛ ϰ͕ϵϬϱ͛ ϳ͟ Ϯϵ WͲϭϭϬ Ƶƚƚ ϲ͘ϭϴϰ͟ ϴ͕ϭϮϳ͛ ϭϭ͕ϰϳϵ͛ dh/E'd/> ϰͲϭͬϮ͟ ϭϮ͘ϲ >ͲϴϬ /d ϯ͘ϵϱϴ͟ ^ƵƌĨĂĐĞ ϳ͕ϵϮϰ͛ &OHDQHGRXWWR¶ /HIW¶ORQJILVKFRQVLVWLQJRIFRLOWXELQJPRWRUDQGELW &OHDQHGRXWILOOWR¶'30)LVKQRWUHFRYHUHG WZ&KZd/KE^ ŽŶĞ dŽƉD ƚŵD dŽƉds ƚŵds ŵƚ ^W& >ĂƐƚKƉƌ͘ ^ƚĂƚƵƐ 'ͲϬϭ ϭϬ͕Ϭϴϵ͛ ϭϬ͕ϭϮϬ͛ ϴ͕ϳϭϱ͛ ϴ͕ϳϰϮ͛ ϯϭ͛ ϱ Ϭϭͬϭϲͬϭϰ KƉĞŶ 'ͲϮ ϭϬ͕ϭϰϬΖ ϭϬ͕ϭϳϬΖ ϴ͕ϳϱϵΖ ϴ͕ϳϴϱΖ ϯϬΖ ϲ ϮͬϭϵͬϭϵϵϮ KƉĞŶ ϭϬ͕ϭϰϬΖ ϭϬ͕ϭϳϬΖ ϴΖϳϱϵΖ ϴ͕ϳϴϱΖ ϯϬ͛ ϱ ϭϬͬϮϳͬϭϮ ZĞƉĞƌĨ 'Ͳϯ ϭϬ͕ϮϮϱΖ ϭϬ͕ϮϱϳΖ ϴ͕ϴϯϯΖ ϴ͕ϴϲϭΖ ϯϮΖ ϲ ϮͬϭϵͬϭϵϵϮ KƉĞŶ ϭϬ͕ϮϰϰΖ ϭϬ͕ϮϲϰΖ ϴ͕ϴϰϵΖ ϴ͕ϴϲϳΖ ϮϬ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ 'Ͳϰ ϭϬ͕ϮϳϴΖ ϭϬ͕ϯϰϬΖ ϴ͕ϴϳϵΖ ϴ͕ϵϯϯΖ ϲϮΖ ϲ ϮͬϭϵͬϭϵϵϮ KƉĞŶ ϭϬ͕ϮϴϬΖ ϭϬ͕ϯϰϮΖ ϴ͕ϴϴϭΖ ϴ͕ϵϯϱΖ ϲϮ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ 'Ͳϱ ϭϬ͕ϯϵϱΖ ϭϬ͕ϰϭϱΖ ϴ͕ϵϴϭΖ ϴ͕ϵϵϵΖ ϮϬΖ ϲ ϮͬϭϵͬϭϵϵϮ KƉĞŶ ϭϬ͕ϯϵϴΖ ϭϬ͕ϰϭϴΖ ϴ͕ϵϴϰΖ ϵ͕ϬϬϭΖ ϮϬ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ϭϬ͕ϰϰϬΖ ϭϬ͕ϰϲϬΖ ϵ͕ϬϮϭΖ ϵ͕ϬϯϴΖ ϮϬ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ 'Ͳϲ ϭϬ͕ϱϯϮΖ ϭϬ͕ϱϰϴΖ ϵ͕ϭϬϭΖ ϵ͕ϭϭϱΖ ϭϲ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ 'Ͳϳ ϭϬ͕ϲϬϬ ϭϬ͕ϲϭϰΖ ϵ͕ϭϲϭΖ ϵ͕ϭϳϯΖ ϭϰ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ,Ͳϭ ϭϬ͕ϲϮϮ͛ ϭϬ͕ϲϯϳ͛ ϵ͕ϭϴϬΖ ϵ͕ϭϵϰΖ ϭϱ͛ ϰ ϭͬϭϳͬϮϬϬϭ KƉĞŶ ,Ͳϭ ϭϬ͕ϲϮϴΖ ϭϬ͕ϲϳϬΖ ϵ͕ϭϴϲΖ ϵ͕ϮϮϯΖ ϰϮΖ ϭϬΘϭϲ ϴͬϮϲͬϭϵϵϱ KƉĞŶ͕ĨƌĂĐΖĚ ϭϬ͕ϲϮϴΖͲ ϭϬ͕ϲϰϯΖ ϭϬ͕ϲϮϴΖ ϭϬ͕ϲϳϲΖ ϵ͕ϭϴϲΖ ϵ͕ϮϮϴΖ ϰϴ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ,ͲϮ ϭϬ͕ϲϴϵ͛ ϭϬ͕ϳϭϴ͛ ϵ͕ϮϰϬ͛ ϵ͕Ϯϲϱ͛ Ϯϵ͛ ϱ Ϭϭͬϭϲͬϭϰ KƉĞŶ ,Ͳϯ ϭϬ͕ϴϰϲΖ ϭϬ͕ϴϲϬΖ ϵ͕ϯϳϳΖ ϵ͕ϯϴϵΖ ϭϰ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ,Ͳϰ ϭϬ͕ϴϲϯΖ ϭϭ͕ϬϬϬΖ ϵ͕ϯϵϮΖ ϵ͕ϱϬϵΖ ϭϯϳΖ ϲ ϮͬϭϵͬϭϵϵϮ KƉĞŶ ϭϬ͕ϵϯϵ͛ ϭϬ͕ϵϱϰ͛ ϵ͕ϰϱϳΖ ϵ͕ϰϳϬΖ ϭϱ͛ ϰ ϭͬϭϳͬϮϬϬϭ KƉĞŶ ϭϬ͕ϴϵϬΖ ϭϭ͕ϬϬϲΖ ϵ͕ϰϭϱΖ ϵ͕ϱϭϱΖ ϭϭϲ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ,Ͳϱ ϭϭ͕Ϭϯϴ͛ ϭϭ͕Ϭϰϴ͛ ϵ͕ϱϰϮΖ ϵ͕ϱϱϬΖ ϭϬ͛ ϰ ϭͬϭϳͬϮϬϬϭ KƉĞŶ ϭϭ͕ϬϰϬΖ ϭϭ͕ϬϳϬΖ ϵ͕ϱϰϰΖ ϵ͕ϱϲϵΖ ϯϬΖ ϴ ϴͬϮϲͬϭϵϵϱ KƉĞŶ ϭϭ͕ϬϰϮΖ ϭϭ͕ϭϮϮΖ ϵ͕ϱϰϱΖ ϵ͕ϲϭϰΖ ϴϬ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ,Ͳϲ ϭϭ͕ϭϱϱΖ ϭϭ͕ϭϳϬΖ ϵ͕ϲϰϮΖ ϵ͕ϲϱϱΖ ϭϱΖ ϰ ϴͬϮϲͬϭϵϵϱ KƉĞŶ ϭϭ͕ϭϱϲΖ ϭϭ͕ϮϰϬΖ ϵ͕ϲϰϯΖ ϵ͕ϳϭϱΖ ϴϰ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ,Ͳϳ ϭϭ͕ϮϱϱΖ ϭϭ͕ϮϴϬΖ ϵ͕ϳϮϴΖ ϵ͕ϳϰϵΖ ϮϱΖ Ϯϰ ϲͬϮϰͬϭϵϵϰ KƉĞŶ ϭϭ͕ϮϲϲΖ ϭϭ͕ϮϵϬΖ ϵ͕ϳϯϳΖ ϵ͕ϳϱϴΖ Ϯϰ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ :ĞǁĞůƌǇĞƚĂŝůƐ EŽ͘ĞƉƚŚ D ĞƉƚŚ ds/ K /ƚĞŵ ϰϮ͘ϲϴ͛ ϰϮ͘ϲϴ͛ /tͲͲ^W͕ϭϭ͟ǆϰͲϭͬϮ͟/důŝĨƚĂŶĚƐƵƐƉ͕ǁͬϰ͟dǇƉĞ,Ws WƌŽĨŝůĞ,ĂŶŐĞƌ ϭ ϰϮϱ͛ ϰϮϱ͛ ϯ͘ϴϭϯ ϱ͘ϵϲϱ dZ^s͕EͲ^>/D͕ ^d͕ϱ< Ϯ ϰϰϱ͛ ϰϰϱ͛ ϯ͘ϵϯϬ ϴ͘ϱϬϬ ϵͲϱͬϴΗǆϰͲϭͬϮΗ>dϯϲͲϰϳη,ǇĚƌŽƐĞƚƵĂů^WWĂĐŬĞƌ ϯ ϰϲϳ͛ ϰϲϳ͛ ϯ͘ϴϭϯ ϰ͘ϱϬϬ ϰͲϭͬϮΗ,ǇĚƌŝůϱϲϯyͲEŝƉƉůĞ ϰ Ϯ͕ϯϬϲ͛ Ϯ͕Ϯϰϰ͛ ϯ͘ϵϵϮ ϳ͘Ϭϲϯ '>DηϭͲ^WDϭϭͬϮΗ'>s/WKZͲϮWŽƌƚ^ŝǌĞϮϰ ϱ ϰ͕ϮϯϮ͛ ϯ͕ϴϰϰ͛ ϯ͘ϵϵϮ ϳ͘Ϭϲϯ '>DηϮͲ^WDϭϭͬϮΗ'>s/WKZͲϮWŽƌƚ^ŝǌĞϮϰ ϲ ϱ͕ϱϴϮ͛ ϰ͕ϵϱϭ͛ ϯ͘ϵϵϮ ϳ͘Ϭϲϯ '>Dηϯ Ͳ ^WDϭϭͬϮΗ'>s/WKZͲϮWŽƌƚ^ŝǌĞϮϰ ϳ ϳ͕ϵϮϰ͛ ϲ͕ϴϲϵ͛ ͲͲ ϱ͘ϭϯϬ ŝƐĐŚĂƌŐĞͲ dE͕ϰϭͬϮ͕͟ϴZh͕ϰϭϲͬϰϮϬ^^͕ϲϳϱy WE͗ϵϬϬϬϯϭϬϬϱ ϳ͕ϵϮϲ͛ ϲ͕ϴϳϭ͛ ͲͲ ϲ͘ϳϱϬ WƵŵƉ ;ϮͿ Ͳ ϲϳϱ^ĞƌŝĞƐ͕^,ϭϯϬϬϬt ϳ͕ϵϳϬ͛ ϲ͕ϵϬϵ͛ ͲͲ ϲ͘ϳϱϬ /ŶƚĂŬĞ ϳ͕ϵϳϭ͛ ϲ͕ϵϬϵ͛ ͲͲ ϱ͘ϭϯϬ hƉƉĞƌͬ>ŽǁĞƌ^ĞĂůƐ ϳ͕ϵϵϰ͛ ϲ͕ϵϮϵ͛ ͲͲ ϱ͘ϲϮϬ DŽƚŽƌ ;ϮͿ Ͳ ϱϲϮ<D^Ϯ͕>dͬhd͕ϱϬϬ,W ϴ͕Ϭϲϭ͛ ϲ͕ϵϴϲ͛ ͲͲ ϰ͘ϱϬϬ ĞŶƚƌŝůŝǌĞƌͬŶŽĚĞ DĐƌƚŚƵƌZŝǀĞƌ&ŝĞůĚ͕dh tĞůů͗'ͲϬϭZ ƐŽŵƉůĞƚĞĚ͗&ƵƚƵƌĞ hƉĚĂƚĞĚďǇ͗:>>ϬϰͬϭϵͬϮϮ WZKWK^ KƉƚŝŽŶηϭ 5.%WR0//:(/(9 ¶ 7' ¶ 3%' ¶ 0$;+2/($1*/( q#¶ 5.%WR7%*+QJU ¶ 7UHHFRQQHFWLRQ%RZHQ +% * * * * +% +% +% +% ϰͲϱͬϴ͟WĞƌĨ'ƵŶΛ ϭϭ͕ϰϬϵ͛ * * +% ´ ´ ´ ´ &ŝƐŚΛϭϭϯϯϳ͛ * +% 72& &%/ (67 72& ¶ &DOF ; ^/E'd/> ^ŝǌĞ td 'ƌĂĚĞ ŽŶŶ / D dŽƉ D ƚŵ Ϯϲ͟ ^ƵƌĨ͘ ϯϮϳ͛ ϭϯͲϯͬϴ͟ ϲϭ :Ͳϱϱ Ƶƚƚ ϭϮ͘ϱϭϱ͟ ^ƵƌĨ͘ Ϯ͕ϭϲϬ͛ ϵͲϱͬϴ͟ ϰϳ EͲϴϬ Ƶƚƚ ϴ͘ϲϴϭ͟ ^ƵƌĨ ϳϵ͛ ϰϬ EͲϴϬ Ƶƚƚ ϴ͘ϴϯϱ͟ ϳϵ͛ ϲ͕Ϯϳϱ͛ ϰϯ͘ϱ EͲϴϬ Ƶƚƚ ϴ͘ϳϱϱ͟ ϲ͕Ϯϳϱ͛ ϴ͕ϭϳϵ͛ ϰϳ EͲϴϬ Ƶƚƚ ϴ͘ϲϴϭ͟ ϴ͕ϭϳϵ͛ ϴ͕ϰϱϬ͛;dKtͿ ϵͲϱͬϴ͟sŽůůĂƌ ϰ͕ϵϬϯ͛ ϰ͕ϵϬϱ͛ ϳ͟ Ϯϵ WͲϭϭϬ Ƶƚƚ ϲ͘ϭϴϰ͟ ϴ͕ϭϮϳ͛ ϭϭ͕ϰϳϵ͛ dh/E'd/> ϰͲϭͬϮ͟ ϯ͘ϵϱϴ͟ ^ƵƌĨĂĐĞ цϳ͕ϴϲϱ͛ &OHDQHGRXWWR¶ /HIW¶ORQJILVKFRQVLVWLQJRIFRLOWXELQJPRWRUDQGELW &OHDQHGRXWILOOWR¶'30)LVKQRWUHFRYHUHG WZ&KZd/KE^ ŽŶĞ dŽƉD ƚŵD dŽƉds ƚŵds ŵƚ ^W& >ĂƐƚKƉƌ͘ ^ƚĂƚƵƐ 'ͲϬϭ ϭϬ͕Ϭϴϵ͛ ϭϬ͕ϭϮϬ͛ ϴ͕ϳϭϱ͛ ϴ͕ϳϰϮ͛ ϯϭ͛ ϱ Ϭϭͬϭϲͬϭϰ KƉĞŶ 'ͲϮ ϭϬ͕ϭϰϬΖ ϭϬ͕ϭϳϬΖ ϴ͕ϳϱϵΖ ϴ͕ϳϴϱΖ ϯϬΖ ϲ ϮͬϭϵͬϭϵϵϮ KƉĞŶ ϭϬ͕ϭϰϬΖ ϭϬ͕ϭϳϬΖ ϴΖϳϱϵΖ ϴ͕ϳϴϱΖ ϯϬ͛ ϱ ϭϬͬϮϳͬϭϮ ZĞƉĞƌĨ 'Ͳϯ ϭϬ͕ϮϮϱΖ ϭϬ͕ϮϱϳΖ ϴ͕ϴϯϯΖ ϴ͕ϴϲϭΖ ϯϮΖ ϲ ϮͬϭϵͬϭϵϵϮ KƉĞŶ ϭϬ͕ϮϰϰΖ ϭϬ͕ϮϲϰΖ ϴ͕ϴϰϵΖ ϴ͕ϴϲϳΖ ϮϬ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ 'Ͳϰ ϭϬ͕ϮϳϴΖ ϭϬ͕ϯϰϬΖ ϴ͕ϴϳϵΖ ϴ͕ϵϯϯΖ ϲϮΖ ϲ ϮͬϭϵͬϭϵϵϮ KƉĞŶ ϭϬ͕ϮϴϬΖ ϭϬ͕ϯϰϮΖ ϴ͕ϴϴϭΖ ϴ͕ϵϯϱΖ ϲϮ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ 'Ͳϱ ϭϬ͕ϯϵϱΖ ϭϬ͕ϰϭϱΖ ϴ͕ϵϴϭΖ ϴ͕ϵϵϵΖ ϮϬΖ ϲ ϮͬϭϵͬϭϵϵϮ KƉĞŶ ϭϬ͕ϯϵϴΖ ϭϬ͕ϰϭϴΖ ϴ͕ϵϴϰΖ ϵ͕ϬϬϭΖ ϮϬ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ϭϬ͕ϰϰϬΖ ϭϬ͕ϰϲϬΖ ϵ͕ϬϮϭΖ ϵ͕ϬϯϴΖ ϮϬ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ 'Ͳϲ ϭϬ͕ϱϯϮΖ ϭϬ͕ϱϰϴΖ ϵ͕ϭϬϭΖ ϵ͕ϭϭϱΖ ϭϲ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ 'Ͳϳ ϭϬ͕ϲϬϬ ϭϬ͕ϲϭϰΖ ϵ͕ϭϲϭΖ ϵ͕ϭϳϯΖ ϭϰ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ,Ͳϭ ϭϬ͕ϲϮϮ͛ ϭϬ͕ϲϯϳ͛ ϵ͕ϭϴϬΖ ϵ͕ϭϵϰΖ ϭϱ͛ ϰ ϭͬϭϳͬϮϬϬϭ KƉĞŶ ,Ͳϭ ϭϬ͕ϲϮϴΖ ϭϬ͕ϲϳϬΖ ϵ͕ϭϴϲΖ ϵ͕ϮϮϯΖ ϰϮΖ ϭϬΘϭϲ ϴͬϮϲͬϭϵϵϱ KƉĞŶ͕ĨƌĂĐΖĚ ϭϬ͕ϲϮϴΖͲ ϭϬ͕ϲϰϯΖ ϭϬ͕ϲϮϴΖ ϭϬ͕ϲϳϲΖ ϵ͕ϭϴϲΖ ϵ͕ϮϮϴΖ ϰϴ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ,ͲϮ ϭϬ͕ϲϴϵ͛ ϭϬ͕ϳϭϴ͛ ϵ͕ϮϰϬ͛ ϵ͕Ϯϲϱ͛ Ϯϵ͛ ϱ Ϭϭͬϭϲͬϭϰ KƉĞŶ ,Ͳϯ ϭϬ͕ϴϰϲΖ ϭϬ͕ϴϲϬΖ ϵ͕ϯϳϳΖ ϵ͕ϯϴϵΖ ϭϰ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ,Ͳϰ ϭϬ͕ϴϲϯΖ ϭϭ͕ϬϬϬΖ ϵ͕ϯϵϮΖ ϵ͕ϱϬϵΖ ϭϯϳΖ ϲ ϮͬϭϵͬϭϵϵϮ KƉĞŶ ϭϬ͕ϵϯϵ͛ ϭϬ͕ϵϱϰ͛ ϵ͕ϰϱϳΖ ϵ͕ϰϳϬΖ ϭϱ͛ ϰ ϭͬϭϳͬϮϬϬϭ KƉĞŶ ϭϬ͕ϴϵϬΖ ϭϭ͕ϬϬϲΖ ϵ͕ϰϭϱΖ ϵ͕ϱϭϱΖ ϭϭϲ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ,Ͳϱ ϭϭ͕Ϭϯϴ͛ ϭϭ͕Ϭϰϴ͛ ϵ͕ϱϰϮΖ ϵ͕ϱϱϬΖ ϭϬ͛ ϰ ϭͬϭϳͬϮϬϬϭ KƉĞŶ ϭϭ͕ϬϰϬΖ ϭϭ͕ϬϳϬΖ ϵ͕ϱϰϰΖ ϵ͕ϱϲϵΖ ϯϬΖ ϴ ϴͬϮϲͬϭϵϵϱ KƉĞŶ ϭϭ͕ϬϰϮΖ ϭϭ͕ϭϮϮΖ ϵ͕ϱϰϱΖ ϵ͕ϲϭϰΖ ϴϬ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ,Ͳϲ ϭϭ͕ϭϱϱΖ ϭϭ͕ϭϳϬΖ ϵ͕ϲϰϮΖ ϵ͕ϲϱϱΖ ϭϱΖ ϰ ϴͬϮϲͬϭϵϵϱ KƉĞŶ ϭϭ͕ϭϱϲΖ ϭϭ͕ϮϰϬΖ ϵ͕ϲϰϯΖ ϵ͕ϳϭϱΖ ϴϰ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ,Ͳϳ ϭϭ͕ϮϱϱΖ ϭϭ͕ϮϴϬΖ ϵ͕ϳϮϴΖ ϵ͕ϳϰϵΖ ϮϱΖ Ϯϰ ϲͬϮϰͬϭϵϵϰ KƉĞŶ ϭϭ͕ϮϲϲΖ ϭϭ͕ϮϵϬΖ ϵ͕ϳϯϳΖ ϵ͕ϳϱϴΖ Ϯϰ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ :ĞǁĞůƌǇĞƚĂŝůƐ EŽ͘ĞƉƚŚ D ĞƉƚŚ ds/ K /ƚĞŵ ,ĂŶŐĞƌ ϭ цϰϮϱ͛ цϰϮϱ͛ ^^^s Ϯ цϰϱϬ͛ цϰϱϬ͛ ,ǇĚƌŽƐĞƚƵĂů^WWĂĐŬĞƌ ϯ цϰϳϱ͛ цϰϳϱ͛ yͲEŝƉƉůĞ ϰ цϳ͕ϴϲϱ͛ цϲ͕ϴϮϬ͛ ͲͲ ŝƐĐŚĂƌŐĞ ͲͲ WƵŵƉ ͲͲ /ŶƚĂŬĞ ͲͲ hƉƉĞƌͬ>ŽǁĞƌ^ĞĂůƐ ͲͲ DŽƚŽƌ цϴ͕ϬϬϬ͛ цϲ͕ϵϯϰ͛ ͲͲ ĞŶƚƌŝůŝǌĞƌͬŶŽĚĞ ϱ цϵ͕ϱϬϬ͛ цϴ͕Ϯϭϱ͛ WĞƌŵĂŶĞŶƚ,ǇĚƌĂƵůŝĐ/ƐŽůĂƚŝŽŶWĂĐŬĞƌ ϰͲϭͬϮ͟ĐĂƐŝŶŐ цϭϬ͕ϬϬϬ͛ цϴ͕ϲϯϴ͛ WĞƌŵĂŶĞŶƚ,ǇĚƌĂƵůŝĐ/ƐŽůĂƚŝŽŶWĂĐŬĞƌ DĐƌƚŚƵƌZŝǀĞƌ&ŝĞůĚ͕dh tĞůů͗'ͲϬϭZ ƐŽŵƉůĞƚĞĚ͗&ƵƚƵƌĞ hƉĚĂƚĞĚďǇ͗,ϱͬϮͬϮϮ WZKWK^KWd/KEϮ 5.%WR0//:(/(9 ¶ 7' ¶ 3%' ¶ 0$;+2/($1*/( q#¶ 5.%WR7%*+QJU ¶ 7UHHFRQQHFWLRQ%RZHQ +% * * * * +% +% +% +% ϰͲϱͬϴ͟WĞƌĨ'ƵŶΛ ϭϭ͕ϰϬϵ͛ * * +% ´ ´ ´ ´ &ŝƐŚΛϭϭϯϯϳ͛ * +% 72& &%/ (67 72& ¶ &DOF ; ^/E'd/> ^ŝǌĞ td 'ƌĂĚĞ ŽŶŶ / D dŽƉ D ƚŵ Ϯϲ͟ ^ƵƌĨ͘ ϯϮϳ͛ ϭϯͲϯͬϴ͟ ϲϭ :Ͳϱϱ Ƶƚƚ ϭϮ͘ϱϭϱ͟ ^ƵƌĨ͘ Ϯ͕ϭϲϬ͛ ϵͲϱͬϴ͟ ϰϳ EͲϴϬ Ƶƚƚ ϴ͘ϲϴϭ͟ ^ƵƌĨ ϳϵ͛ ϰϬ EͲϴϬ Ƶƚƚ ϴ͘ϴϯϱ͟ ϳϵ͛ ϲ͕Ϯϳϱ͛ ϰϯ͘ϱ EͲϴϬ Ƶƚƚ ϴ͘ϳϱϱ͟ ϲ͕Ϯϳϱ͛ ϴ͕ϭϳϵ͛ ϰϳ EͲϴϬ Ƶƚƚ ϴ͘ϲϴϭ͟ ϴ͕ϭϳϵ͛ ϴ͕ϰϱϬ͛;dKtͿ ϵͲϱͬϴ͟sŽůůĂƌ ϰ͕ϵϬϯ͛ ϰ͕ϵϬϱ͛ ϳ͟ Ϯϵ WͲϭϭϬ Ƶƚƚ ϲ͘ϭϴϰ͟ ϴ͕ϭϮϳ͛ ϭϭ͕ϰϳϵ͛ dh/E'd/> ϰͲϭͬϮ͟ ϯ͘ϵϱϴ͟ ^ƵƌĨĂĐĞ цϴ͕ϬϳϬ͛ &OHDQHGRXWWR¶ /HIW¶ORQJILVKFRQVLVWLQJRIFRLOWXELQJPRWRUDQGELW &OHDQHGRXWILOOWR¶'30)LVKQRWUHFRYHUHG WZ&KZd/KE^ ŽŶĞ dŽƉD ƚŵD dŽƉds ƚŵds ŵƚ ^W& >ĂƐƚKƉƌ͘ ^ƚĂƚƵƐ 'ͲϬϭ ϭϬ͕Ϭϴϵ͛ ϭϬ͕ϭϮϬ͛ ϴ͕ϳϭϱ͛ ϴ͕ϳϰϮ͛ ϯϭ͛ ϱ Ϭϭͬϭϲͬϭϰ KƉĞŶ 'ͲϮ ϭϬ͕ϭϰϬΖ ϭϬ͕ϭϳϬΖ ϴ͕ϳϱϵΖ ϴ͕ϳϴϱΖ ϯϬΖ ϲ ϮͬϭϵͬϭϵϵϮ KƉĞŶ ϭϬ͕ϭϰϬΖ ϭϬ͕ϭϳϬΖ ϴΖϳϱϵΖ ϴ͕ϳϴϱΖ ϯϬ͛ ϱ ϭϬͬϮϳͬϭϮ ZĞƉĞƌĨ 'Ͳϯ ϭϬ͕ϮϮϱΖ ϭϬ͕ϮϱϳΖ ϴ͕ϴϯϯΖ ϴ͕ϴϲϭΖ ϯϮΖ ϲ ϮͬϭϵͬϭϵϵϮ KƉĞŶ ϭϬ͕ϮϰϰΖ ϭϬ͕ϮϲϰΖ ϴ͕ϴϰϵΖ ϴ͕ϴϲϳΖ ϮϬ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ 'Ͳϰ ϭϬ͕ϮϳϴΖ ϭϬ͕ϯϰϬΖ ϴ͕ϴϳϵΖ ϴ͕ϵϯϯΖ ϲϮΖ ϲ ϮͬϭϵͬϭϵϵϮ KƉĞŶ ϭϬ͕ϮϴϬΖ ϭϬ͕ϯϰϮΖ ϴ͕ϴϴϭΖ ϴ͕ϵϯϱΖ ϲϮ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ 'Ͳϱ ϭϬ͕ϯϵϱΖ ϭϬ͕ϰϭϱΖ ϴ͕ϵϴϭΖ ϴ͕ϵϵϵΖ ϮϬΖ ϲ ϮͬϭϵͬϭϵϵϮ KƉĞŶ ϭϬ͕ϯϵϴΖ ϭϬ͕ϰϭϴΖ ϴ͕ϵϴϰΖ ϵ͕ϬϬϭΖ ϮϬ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ϭϬ͕ϰϰϬΖ ϭϬ͕ϰϲϬΖ ϵ͕ϬϮϭΖ ϵ͕ϬϯϴΖ ϮϬ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ 'Ͳϲ ϭϬ͕ϱϯϮΖ ϭϬ͕ϱϰϴΖ ϵ͕ϭϬϭΖ ϵ͕ϭϭϱΖ ϭϲ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ 'Ͳϳ ϭϬ͕ϲϬϬ ϭϬ͕ϲϭϰΖ ϵ͕ϭϲϭΖ ϵ͕ϭϳϯΖ ϭϰ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ,Ͳϭ ϭϬ͕ϲϮϮ͛ ϭϬ͕ϲϯϳ͛ ϵ͕ϭϴϬΖ ϵ͕ϭϵϰΖ ϭϱ͛ ϰ ϭͬϭϳͬϮϬϬϭ KƉĞŶ ,Ͳϭ ϭϬ͕ϲϮϴΖ ϭϬ͕ϲϳϬΖ ϵ͕ϭϴϲΖ ϵ͕ϮϮϯΖ ϰϮΖ ϭϬΘϭϲ ϴͬϮϲͬϭϵϵϱ KƉĞŶ͕ĨƌĂĐΖĚ ϭϬ͕ϲϮϴΖͲ ϭϬ͕ϲϰϯΖ ϭϬ͕ϲϮϴΖ ϭϬ͕ϲϳϲΖ ϵ͕ϭϴϲΖ ϵ͕ϮϮϴΖ ϰϴ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ,ͲϮ ϭϬ͕ϲϴϵ͛ ϭϬ͕ϳϭϴ͛ ϵ͕ϮϰϬ͛ ϵ͕Ϯϲϱ͛ Ϯϵ͛ ϱ Ϭϭͬϭϲͬϭϰ KƉĞŶ ,Ͳϯ ϭϬ͕ϴϰϲΖ ϭϬ͕ϴϲϬΖ ϵ͕ϯϳϳΖ ϵ͕ϯϴϵΖ ϭϰ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ,Ͳϰ ϭϬ͕ϴϲϯΖ ϭϭ͕ϬϬϬΖ ϵ͕ϯϵϮΖ ϵ͕ϱϬϵΖ ϭϯϳΖ ϲ ϮͬϭϵͬϭϵϵϮ KƉĞŶ ϭϬ͕ϵϯϵ͛ ϭϬ͕ϵϱϰ͛ ϵ͕ϰϱϳΖ ϵ͕ϰϳϬΖ ϭϱ͛ ϰ ϭͬϭϳͬϮϬϬϭ KƉĞŶ ϭϬ͕ϴϵϬΖ ϭϭ͕ϬϬϲΖ ϵ͕ϰϭϱΖ ϵ͕ϱϭϱΖ ϭϭϲ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ,Ͳϱ ϭϭ͕Ϭϯϴ͛ ϭϭ͕Ϭϰϴ͛ ϵ͕ϱϰϮΖ ϵ͕ϱϱϬΖ ϭϬ͛ ϰ ϭͬϭϳͬϮϬϬϭ KƉĞŶ ϭϭ͕ϬϰϬΖ ϭϭ͕ϬϳϬΖ ϵ͕ϱϰϰΖ ϵ͕ϱϲϵΖ ϯϬΖ ϴ ϴͬϮϲͬϭϵϵϱ KƉĞŶ ϭϭ͕ϬϰϮΖ ϭϭ͕ϭϮϮΖ ϵ͕ϱϰϱΖ ϵ͕ϲϭϰΖ ϴϬ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ,Ͳϲ ϭϭ͕ϭϱϱΖ ϭϭ͕ϭϳϬΖ ϵ͕ϲϰϮΖ ϵ͕ϲϱϱΖ ϭϱΖ ϰ ϴͬϮϲͬϭϵϵϱ KƉĞŶ ϭϭ͕ϭϱϲΖ ϭϭ͕ϮϰϬΖ ϵ͕ϲϰϯΖ ϵ͕ϳϭϱΖ ϴϰ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ,Ͳϳ ϭϭ͕ϮϱϱΖ ϭϭ͕ϮϴϬΖ ϵ͕ϳϮϴΖ ϵ͕ϳϰϵΖ ϮϱΖ Ϯϰ ϲͬϮϰͬϭϵϵϰ KƉĞŶ ϭϭ͕ϮϲϲΖ ϭϭ͕ϮϵϬΖ ϵ͕ϳϯϳΖ ϵ͕ϳϱϴΖ Ϯϰ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ :ĞǁĞůƌǇĞƚĂŝůƐ EŽ͘ĞƉƚŚ D ĞƉƚŚ ds/ K /ƚĞŵ ,ĂŶŐĞƌ ϭ цϰϮϱ͛ цϰϮϱ͛ ^^^s Ϯ цϭ͕ϮϬϬ͛ цϭ͕ϮϬϬ͛ '>Dϭ цϮ͕ϰϬϬ͛ цϮ͕ϯϮϮ͛ '>D Ϯ цϰ͕ϮϬϬ͛ цϯ͕ϴϭϴ͛ '>D ϯ цϱ͕ϱϬϬ͛ цϰ͕ϴϴϯ͛ '>Dϰ цϳ͕ϬϬϬ͛ цϲ͕ϭϮϱ͛ '>Dϱ цϳ͕ϴϬϬ͛ цϲ͕ϳϲϱ͛ '>D ϲ ϯ цϳ͕ϵϬϬ͛ цϲ͕ϴϰϵ͛ WĂĐŬĞƌ ϰ цϳ͕ϵϮϱ͛ цϲ͕ϴϳϬ͛ yͲEŝƉƉůĞ ϱ цϴ͕ϬϳϬ͛ цϲ͕ϵϵϰ͛ t>' DĐƌƚŚƵƌZŝǀĞƌ&ŝĞůĚ͕dh tĞůů͗'ͲϬϭZ ƐŽŵƉůĞƚĞĚ͗&ƵƚƵƌĞ hƉĚĂƚĞĚďǇ͗:>>ϬϰͬϭϵͬϮϮ WZKWK^ KƉƚŝŽŶ ϯ 5.%WR0//:(/(9 ¶ 7' ¶ 3%' ¶ 0$;+2/($1*/( q#¶ 5.%WR7%*+QJU ¶ 7UHHFRQQHFWLRQ%RZHQ +% * * * * +% +% +% +% ϰͲϱͬϴ͟WĞƌĨ'ƵŶΛ ϭϭ͕ϰϬϵ͛ * * +% ´ ´ ´ ´ &ŝƐŚΛϭϭϯϯϳ͛ * +% 72& &%/ (67 72& ¶ &DOF ; ^/E'd/> ^ŝǌĞ td 'ƌĂĚĞ ŽŶŶ / D dŽƉ D ƚŵ Ϯϲ͟ ^ƵƌĨ͘ ϯϮϳ͛ ϭϯͲϯͬϴ͟ ϲϭ :Ͳϱϱ Ƶƚƚ ϭϮ͘ϱϭϱ͟ ^ƵƌĨ͘ Ϯ͕ϭϲϬ͛ ϵͲϱͬϴ͟ ϰϳ EͲϴϬ Ƶƚƚ ϴ͘ϲϴϭ͟ ^ƵƌĨ ϳϵ͛ ϰϬ EͲϴϬ Ƶƚƚ ϴ͘ϴϯϱ͟ ϳϵ͛ ϲ͕Ϯϳϱ͛ ϰϯ͘ϱ EͲϴϬ Ƶƚƚ ϴ͘ϳϱϱ͟ ϲ͕Ϯϳϱ͛ ϴ͕ϭϳϵ͛ ϰϳ EͲϴϬ Ƶƚƚ ϴ͘ϲϴϭ͟ ϴ͕ϭϳϵ͛ ϴ͕ϰϱϬ͛;dKtͿ ϵͲϱͬϴ͟sŽůůĂƌ ϰ͕ϵϬϯ͛ ϰ͕ϵϬϱ͛ ϳ͟ Ϯϵ WͲϭϭϬ Ƶƚƚ ϲ͘ϭϴϰ͟ ϴ͕ϭϮϳ͛ ϭϭ͕ϰϳϵ͛ dh/E'd/> ϰͲϭͬϮ͟ ϯ͘ϵϱϴ͟ ^ƵƌĨĂĐĞ цϴ͕ϬϬϬ͛ &OHDQHGRXWWR¶ /HIW¶ORQJILVKFRQVLVWLQJRIFRLOWXELQJPRWRUDQGELW &OHDQHGRXWILOOWR¶'30)LVKQRWUHFRYHUHG WZ&KZd/KE^ ŽŶĞ dŽƉD ƚŵD dŽƉds ƚŵds ŵƚ ^W& >ĂƐƚKƉƌ͘ ^ƚĂƚƵƐ 'ͲϬϭ ϭϬ͕Ϭϴϵ͛ ϭϬ͕ϭϮϬ͛ ϴ͕ϳϭϱ͛ ϴ͕ϳϰϮ͛ ϯϭ͛ ϱ Ϭϭͬϭϲͬϭϰ KƉĞŶ 'ͲϮ ϭϬ͕ϭϰϬΖ ϭϬ͕ϭϳϬΖ ϴ͕ϳϱϵΖ ϴ͕ϳϴϱΖ ϯϬΖ ϲ ϮͬϭϵͬϭϵϵϮ KƉĞŶ ϭϬ͕ϭϰϬΖ ϭϬ͕ϭϳϬΖ ϴΖϳϱϵΖ ϴ͕ϳϴϱΖ ϯϬ͛ ϱ ϭϬͬϮϳͬϭϮ ZĞƉĞƌĨ 'Ͳϯ ϭϬ͕ϮϮϱΖ ϭϬ͕ϮϱϳΖ ϴ͕ϴϯϯΖ ϴ͕ϴϲϭΖ ϯϮΖ ϲ ϮͬϭϵͬϭϵϵϮ KƉĞŶ ϭϬ͕ϮϰϰΖ ϭϬ͕ϮϲϰΖ ϴ͕ϴϰϵΖ ϴ͕ϴϲϳΖ ϮϬ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ 'Ͳϰ ϭϬ͕ϮϳϴΖ ϭϬ͕ϯϰϬΖ ϴ͕ϴϳϵΖ ϴ͕ϵϯϯΖ ϲϮΖ ϲ ϮͬϭϵͬϭϵϵϮ KƉĞŶ ϭϬ͕ϮϴϬΖ ϭϬ͕ϯϰϮΖ ϴ͕ϴϴϭΖ ϴ͕ϵϯϱΖ ϲϮ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ 'Ͳϱ ϭϬ͕ϯϵϱΖ ϭϬ͕ϰϭϱΖ ϴ͕ϵϴϭΖ ϴ͕ϵϵϵΖ ϮϬΖ ϲ ϮͬϭϵͬϭϵϵϮ KƉĞŶ ϭϬ͕ϯϵϴΖ ϭϬ͕ϰϭϴΖ ϴ͕ϵϴϰΖ ϵ͕ϬϬϭΖ ϮϬ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ϭϬ͕ϰϰϬΖ ϭϬ͕ϰϲϬΖ ϵ͕ϬϮϭΖ ϵ͕ϬϯϴΖ ϮϬ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ 'Ͳϲ ϭϬ͕ϱϯϮΖ ϭϬ͕ϱϰϴΖ ϵ͕ϭϬϭΖ ϵ͕ϭϭϱΖ ϭϲ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ 'Ͳϳ ϭϬ͕ϲϬϬ ϭϬ͕ϲϭϰΖ ϵ͕ϭϲϭΖ ϵ͕ϭϳϯΖ ϭϰ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ,Ͳϭ ϭϬ͕ϲϮϮ͛ ϭϬ͕ϲϯϳ͛ ϵ͕ϭϴϬΖ ϵ͕ϭϵϰΖ ϭϱ͛ ϰ ϭͬϭϳͬϮϬϬϭ KƉĞŶ ,Ͳϭ ϭϬ͕ϲϮϴΖ ϭϬ͕ϲϳϬΖ ϵ͕ϭϴϲΖ ϵ͕ϮϮϯΖ ϰϮΖ ϭϬΘϭϲ ϴͬϮϲͬϭϵϵϱ KƉĞŶ͕ĨƌĂĐΖĚ ϭϬ͕ϲϮϴΖͲ ϭϬ͕ϲϰϯΖ ϭϬ͕ϲϮϴΖ ϭϬ͕ϲϳϲΖ ϵ͕ϭϴϲΖ ϵ͕ϮϮϴΖ ϰϴ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ,ͲϮ ϭϬ͕ϲϴϵ͛ ϭϬ͕ϳϭϴ͛ ϵ͕ϮϰϬ͛ ϵ͕Ϯϲϱ͛ Ϯϵ͛ ϱ Ϭϭͬϭϲͬϭϰ KƉĞŶ ,Ͳϯ ϭϬ͕ϴϰϲΖ ϭϬ͕ϴϲϬΖ ϵ͕ϯϳϳΖ ϵ͕ϯϴϵΖ ϭϰ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ,Ͳϰ ϭϬ͕ϴϲϯΖ ϭϭ͕ϬϬϬΖ ϵ͕ϯϵϮΖ ϵ͕ϱϬϵΖ ϭϯϳΖ ϲ ϮͬϭϵͬϭϵϵϮ KƉĞŶ ϭϬ͕ϵϯϵ͛ ϭϬ͕ϵϱϰ͛ ϵ͕ϰϱϳΖ ϵ͕ϰϳϬΖ ϭϱ͛ ϰ ϭͬϭϳͬϮϬϬϭ KƉĞŶ ϭϬ͕ϴϵϬΖ ϭϭ͕ϬϬϲΖ ϵ͕ϰϭϱΖ ϵ͕ϱϭϱΖ ϭϭϲ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ,Ͳϱ ϭϭ͕Ϭϯϴ͛ ϭϭ͕Ϭϰϴ͛ ϵ͕ϱϰϮΖ ϵ͕ϱϱϬΖ ϭϬ͛ ϰ ϭͬϭϳͬϮϬϬϭ KƉĞŶ ϭϭ͕ϬϰϬΖ ϭϭ͕ϬϳϬΖ ϵ͕ϱϰϰΖ ϵ͕ϱϲϵΖ ϯϬΖ ϴ ϴͬϮϲͬϭϵϵϱ KƉĞŶ ϭϭ͕ϬϰϮΖ ϭϭ͕ϭϮϮΖ ϵ͕ϱϰϱΖ ϵ͕ϲϭϰΖ ϴϬ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ,Ͳϲ ϭϭ͕ϭϱϱΖ ϭϭ͕ϭϳϬΖ ϵ͕ϲϰϮΖ ϵ͕ϲϱϱΖ ϭϱΖ ϰ ϴͬϮϲͬϭϵϵϱ KƉĞŶ ϭϭ͕ϭϱϲΖ ϭϭ͕ϮϰϬΖ ϵ͕ϲϰϯΖ ϵ͕ϳϭϱΖ ϴϰ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ,Ͳϳ ϭϭ͕ϮϱϱΖ ϭϭ͕ϮϴϬΖ ϵ͕ϳϮϴΖ ϵ͕ϳϰϵΖ ϮϱΖ Ϯϰ ϲͬϮϰͬϭϵϵϰ KƉĞŶ ϭϭ͕ϮϲϲΖ ϭϭ͕ϮϵϬΖ ϵ͕ϳϯϳΖ ϵ͕ϳϱϴΖ Ϯϰ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ :ĞǁĞůƌǇĞƚĂŝůƐ EŽ͘ĞƉƚŚ D ĞƉƚŚ ds/ K /ƚĞŵ ,ĂŶŐĞƌ ϭ цϰϮϱ͛ цϰϮϱ͛ ^^^s Ϯ цϭ͕ϮϬϬ͛ цϭ͕ϮϬϬ͛ '>Dϭ цϮ͕ϰϬϬ͛ цϮ͕ϯϮϮ͛ '>D Ϯ цϰ͕ϮϬϬ͛ цϯ͕ϴϭϴ͛ '>D ϯ цϱ͕ϱϬϬ͛ цϰ͕ϴϴϯ͛ '>Dϰ цϳ͕ϬϬϬ͛ цϲ͕ϭϮϱ͛ '>Dϱ цϳ͕ϴϬϬ͛ цϲ͕ϳϲϱ͛ '>D ϲ ϯ цϳ͕ϵϬϬ͛ цϲ͕ϴϰϵ͛ WĂĐŬĞƌ ϰ цϳ͕ϵϮϱ͛ цϲ͕ϴϳϬ͛ yͲEŝƉƉůĞ ϱ цϴ͕ϬϬϬ͛ цϲ͕ϵϯϰ͛ t>' ϲ цϭϬ͕ϬϱϬ͛ цϴ͕ϲϴϭ͛ WůƵŐ Mid Kenai G Oil: 9,972’ – 10,625’ MD Hemlock Oil: 10,626’ – 11,292’ MD West Foreland Oil: 11,247’ – 11,506’ MD - bjm DĐƌƚŚƵƌZŝǀĞƌ&ŝĞůĚ͕dh tĞůů͗'ͲϬϭZ ƐŽŵƉůĞƚĞĚ͗&ƵƚƵƌĞ hƉĚĂƚĞĚďǇ͗,ϰͬϮϴͬϮϮ WZKWK^ KƉƚŝŽŶ ϰ 5.%WR0//:(/(9 ¶ 7' ¶ 3%' ¶ 0$;+2/($1*/( q#¶ 5.%WR7%*+QJU ¶ 7UHHFRQQHFWLRQ%RZHQ +% * * * * +% +% +% +% ϰͲϱͬϴ͟WĞƌĨ'ƵŶΛ ϭϭ͕ϰϬϵ͛ * * +% ´ ´ ´ ´ &ŝƐŚΛϭϭϯϯϳ͛ * +% 72& &%/ (67 72& ¶ &DOF ^/E'd/> ^ŝǌĞ td 'ƌĂĚĞ ŽŶŶ / D dŽƉ D ƚŵ Ϯϲ͟ ^ƵƌĨ͘ ϯϮϳ͛ ϭϯͲϯͬϴ͟ ϲϭ :Ͳϱϱ Ƶƚƚ ϭϮ͘ϱϭϱ͟ ^ƵƌĨ͘ Ϯ͕ϭϲϬ͛ ϵͲϱͬϴ͟ ϰϳ EͲϴϬ Ƶƚƚ ϴ͘ϲϴϭ͟ ^ƵƌĨ ϳϵ͛ ϰϬ EͲϴϬ Ƶƚƚ ϴ͘ϴϯϱ͟ ϳϵ͛ ϲ͕Ϯϳϱ͛ ϰϯ͘ϱ EͲϴϬ Ƶƚƚ ϴ͘ϳϱϱ͟ ϲ͕Ϯϳϱ͛ ϴ͕ϭϳϵ͛ ϰϳ EͲϴϬ Ƶƚƚ ϴ͘ϲϴϭ͟ ϴ͕ϭϳϵ͛ ϴ͕ϰϱϬ͛;dKtͿ ϵͲϱͬϴ͟sŽůůĂƌ ϰ͕ϵϬϯ͛ ϰ͕ϵϬϱ͛ ϳ͟ Ϯϵ WͲϭϭϬ Ƶƚƚ ϲ͘ϭϴϰ͟ ϴ͕ϭϮϳ͛ ϭϭ͕ϰϳϵ͛ dh/E'd/> ϰͲϭͬϮ͟ ϯ͘ϵϱϴ͟ ^ƵƌĨĂĐĞ цϭ͕ϰϬϬ͛ &OHDQHGRXWWR¶ /HIW¶ORQJILVKFRQVLVWLQJRIFRLOWXELQJPRWRUDQGELW &OHDQHGRXWILOOWR¶'30)LVKQRWUHFRYHUHG WZ&KZd/KE^ ŽŶĞ dŽƉD ƚŵD dŽƉds ƚŵds ŵƚ ^W& >ĂƐƚKƉƌ͘ ^ƚĂƚƵƐ 'ͲϬϭ ϭϬ͕Ϭϴϵ͛ ϭϬ͕ϭϮϬ͛ ϴ͕ϳϭϱ͛ ϴ͕ϳϰϮ͛ ϯϭ͛ ϱ Ϭϭͬϭϲͬϭϰ KƉĞŶ 'ͲϮ ϭϬ͕ϭϰϬΖ ϭϬ͕ϭϳϬΖ ϴ͕ϳϱϵΖ ϴ͕ϳϴϱΖ ϯϬΖ ϲ ϮͬϭϵͬϭϵϵϮ KƉĞŶ ϭϬ͕ϭϰϬΖ ϭϬ͕ϭϳϬΖ ϴΖϳϱϵΖ ϴ͕ϳϴϱΖ ϯϬ͛ ϱ ϭϬͬϮϳͬϭϮ ZĞƉĞƌĨ 'Ͳϯ ϭϬ͕ϮϮϱΖ ϭϬ͕ϮϱϳΖ ϴ͕ϴϯϯΖ ϴ͕ϴϲϭΖ ϯϮΖ ϲ ϮͬϭϵͬϭϵϵϮ KƉĞŶ ϭϬ͕ϮϰϰΖ ϭϬ͕ϮϲϰΖ ϴ͕ϴϰϵΖ ϴ͕ϴϲϳΖ ϮϬ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ 'Ͳϰ ϭϬ͕ϮϳϴΖ ϭϬ͕ϯϰϬΖ ϴ͕ϴϳϵΖ ϴ͕ϵϯϯΖ ϲϮΖ ϲ ϮͬϭϵͬϭϵϵϮ KƉĞŶ ϭϬ͕ϮϴϬΖ ϭϬ͕ϯϰϮΖ ϴ͕ϴϴϭΖ ϴ͕ϵϯϱΖ ϲϮ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ 'Ͳϱ ϭϬ͕ϯϵϱΖ ϭϬ͕ϰϭϱΖ ϴ͕ϵϴϭΖ ϴ͕ϵϵϵΖ ϮϬΖ ϲ ϮͬϭϵͬϭϵϵϮ KƉĞŶ ϭϬ͕ϯϵϴΖ ϭϬ͕ϰϭϴΖ ϴ͕ϵϴϰΖ ϵ͕ϬϬϭΖ ϮϬ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ϭϬ͕ϰϰϬΖ ϭϬ͕ϰϲϬΖ ϵ͕ϬϮϭΖ ϵ͕ϬϯϴΖ ϮϬ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ 'Ͳϲ ϭϬ͕ϱϯϮΖ ϭϬ͕ϱϰϴΖ ϵ͕ϭϬϭΖ ϵ͕ϭϭϱΖ ϭϲ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ 'Ͳϳ ϭϬ͕ϲϬϬ ϭϬ͕ϲϭϰΖ ϵ͕ϭϲϭΖ ϵ͕ϭϳϯΖ ϭϰ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ,Ͳϭ ϭϬ͕ϲϮϮ͛ ϭϬ͕ϲϯϳ͛ ϵ͕ϭϴϬΖ ϵ͕ϭϵϰΖ ϭϱ͛ ϰ ϭͬϭϳͬϮϬϬϭ KƉĞŶ ,Ͳϭ ϭϬ͕ϲϮϴΖ ϭϬ͕ϲϳϬΖ ϵ͕ϭϴϲΖ ϵ͕ϮϮϯΖ ϰϮΖ ϭϬΘϭϲ ϴͬϮϲͬϭϵϵϱ KƉĞŶ͕ĨƌĂĐΖĚ ϭϬ͕ϲϮϴΖͲ ϭϬ͕ϲϰϯΖ ϭϬ͕ϲϮϴΖ ϭϬ͕ϲϳϲΖ ϵ͕ϭϴϲΖ ϵ͕ϮϮϴΖ ϰϴ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ,ͲϮ ϭϬ͕ϲϴϵ͛ ϭϬ͕ϳϭϴ͛ ϵ͕ϮϰϬ͛ ϵ͕Ϯϲϱ͛ Ϯϵ͛ ϱ Ϭϭͬϭϲͬϭϰ KƉĞŶ ,Ͳϯ ϭϬ͕ϴϰϲΖ ϭϬ͕ϴϲϬΖ ϵ͕ϯϳϳΖ ϵ͕ϯϴϵΖ ϭϰ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ,Ͳϰ ϭϬ͕ϴϲϯΖ ϭϭ͕ϬϬϬΖ ϵ͕ϯϵϮΖ ϵ͕ϱϬϵΖ ϭϯϳΖ ϲ ϮͬϭϵͬϭϵϵϮ KƉĞŶ ϭϬ͕ϵϯϵ͛ ϭϬ͕ϵϱϰ͛ ϵ͕ϰϱϳΖ ϵ͕ϰϳϬΖ ϭϱ͛ ϰ ϭͬϭϳͬϮϬϬϭ KƉĞŶ ϭϬ͕ϴϵϬΖ ϭϭ͕ϬϬϲΖ ϵ͕ϰϭϱΖ ϵ͕ϱϭϱΖ ϭϭϲ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ,Ͳϱ ϭϭ͕Ϭϯϴ͛ ϭϭ͕Ϭϰϴ͛ ϵ͕ϱϰϮΖ ϵ͕ϱϱϬΖ ϭϬ͛ ϰ ϭͬϭϳͬϮϬϬϭ KƉĞŶ ϭϭ͕ϬϰϬΖ ϭϭ͕ϬϳϬΖ ϵ͕ϱϰϰΖ ϵ͕ϱϲϵΖ ϯϬΖ ϴ ϴͬϮϲͬϭϵϵϱ KƉĞŶ ϭϭ͕ϬϰϮΖ ϭϭ͕ϭϮϮΖ ϵ͕ϱϰϱΖ ϵ͕ϲϭϰΖ ϴϬ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ,Ͳϲ ϭϭ͕ϭϱϱΖ ϭϭ͕ϭϳϬΖ ϵ͕ϲϰϮΖ ϵ͕ϲϱϱΖ ϭϱΖ ϰ ϴͬϮϲͬϭϵϵϱ KƉĞŶ ϭϭ͕ϭϱϲΖ ϭϭ͕ϮϰϬΖ ϵ͕ϲϰϯΖ ϵ͕ϳϭϱΖ ϴϰ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ ,Ͳϳ ϭϭ͕ϮϱϱΖ ϭϭ͕ϮϴϬΖ ϵ͕ϳϮϴΖ ϵ͕ϳϰϵΖ ϮϱΖ Ϯϰ ϲͬϮϰͬϭϵϵϰ KƉĞŶ ϭϭ͕ϮϲϲΖ ϭϭ͕ϮϵϬΖ ϵ͕ϳϯϳΖ ϵ͕ϳϱϴΖ Ϯϰ͛ ϱ ϭϬͬϮϳͬϭϮ KƉĞŶ :ĞǁĞůƌǇĞƚĂŝůƐ EŽ͘ĞƉƚŚ D ĞƉƚŚ ds/ K /ƚĞŵ ,ĂŶŐĞƌ ϭцϭ͕ϰϬϬ͛цϭ͕ϰϬϬ͛ ϯ͘ϵϱϴ t>' Ϯ цϭϬ͕ϬϬϬ͛ цϴ͕ϲϯϴ͛ ĞŵĞŶƚŽŶƉůƵŐ ϯ цϭϬ͕ϬϮϱ͛͛ цϴ͕ϲϴϭ͛ WůƵŐ Not Approved - BJM *UD\OLQJ3ODWIRUP *5'&XUUHQW dƵďŝŶŐŚĂŶŐĞƌ͕/tͲͲ^W͕ ϭϭyϰЪ/důŝĨƚĂŶĚƐƵƐƉ͕ǁͬ ϰΖ͛ ƚǇƉĞ,WsƉƌŽĨŝůĞ͕ϱЬE͕ ϰͲϯͬϴĐŽŶƚŝŶƵŽƵƐĐŽŶƚƌŽůůŝŶĞ ƉŽƌƚƐ͕ƉƌĞƉƉĞĚĨŽƌ/t ƉĞŶĞƚƌĂƚŽƌ,d͕ŽǁĞŶ͕ϰϭͬϭϲϱD&ǆ ϳΖ͛ƋƵŝĐŬƵŶŝŽŶƚŽƉ ĂƐŝŶŐŚĞĂĚ͕^ŚĂĨĨĞƌ<͕ ϭϯϱͬϴϯDǆϭϯϯͬϴ^Kt͕ǁͬ ϮͲϮΖ͛ >WK ϭϯϯͬϴΖ͛ ϵϱͬϴΖ͛ ϰЪ͛͛ yϰĐŽŶƚƌŽůůŝŶĞ sĂůǀĞ͕hƉƉĞƌŵĂƐƚĞƌ͕ t<DͲD͕ ϰϭͬϭϲϱD&͕,tK͕ƚƌŝŵ sĂůǀĞ͕^ǁĂď͕t<DͲD ϰϭͬϭϲϱD&͕,tK͕ ƚƌŝŵ sĂůǀĞ͕tŝŶŐ͕^^s͕t<DͲD͕ ϰϭͬϭϲϱD&͕ǁͬϭϱΖ͛ ĂŝƌŽƉĞƌĂƚŽƌ 'ƌĂǇůŝŶŐWůĂƚĨŽƌŵ 'ͲϭƌĚ ϭϯϯͬϴyϵϱͬϴyϰϭͬϮ $GDSWHU&,:7RDGVWRRO0 6WGG;0)(SUHSSHGIRU ó(1QHFNòQSWFRQWLQXRXV FRQWUROOLQHSRUWV%,:SHQHWUDWRU SRUW dƵďŝŶŐŚĞĂĚ͕/tͲ͕ ϭϯϱͬϴϯDyϭϭϱD ǁͬϮͲϮϭͬϭϲϱD^^K͕ yďŽƚƚŽŵ dƵďŝŶŐŚĞĂĚŝƐďĂĚ ƐĞĐŽŶĚĂƌǇƐĞĂůĂŶĚƌŝŶŐũŽŝŶƚ ďĂĐŬŽŶďŽƚƚŽŵ ^ĞĂůƚŝƚĞŝŶƐƚĂůůĞĚƚŽŵĂŬĞ ŚŽůĚ *UD\OLQJ3ODWIRUP *5'3URSRVHG2SWLRQ ,d͕ŽǁĞŶ͕ϰϭͬϭϲϱD&ǆ ϳΖ͛ ƋƵŝĐŬƵŶŝŽŶƚŽƉ ĂƐŝŶŐŚĞĂĚ͕^ŚĂĨĨĞƌ<͕ ϭϯϱͬϴϯDǆϭϯϯͬϴ^Kt͕ǁͬ ϮͲϮΖ͛ >WK ϭϯϯͬϴΖ͛ ϵϱͬϴΖ͛ dƵďŝŶŐŚĞĂĚ͕ĂĐƚƵƐͲϮϵ>͕ ϭϯϱͬϴϯDǆϭϭϱD͕ ǁͬϮͲϮϭͬϭϲϱD^^K͕ ǁͬϵϱͬϴ,W^ďŽƚƚŽŵ ϰЪ͛͛ ĚĂƉƚĞƌ͕&DͲϯͲ͕ ϭϭϱDyϰϭͬϭϲϱD͕ƉƌĞƉƉĞĚ ĨŽƌ/tĞůĞĐƚƌŽƐƵď͕ϯͲЪŶƉƚ ĐŽŶƚŝŶƵŽƵƐĐŽŶƚƌŽůůŝŶĞĞǆŝƚƐ yϯĐŽŶƚƌŽůůŝŶĞ sĂůǀĞ͕hƉƉĞƌŵĂƐƚĞƌ͕ t<DͲD͕ ϰϭͬϭϲϱD&͕,tK͕ƚƌŝŵ sĂůǀĞ͕^ǁĂď͕t<DͲD ϰϭͬϭϲϱD&͕,tK͕ ƚƌŝŵ sĂůǀĞ͕tŝŶŐ͕^^s͕t<DͲD͕ ϰϭͬϭϲϱD&͕ǁͬϭϱΖ͛ĂŝƌŽƉĞƌĂƚŽƌ 'ƌĂǇůŝŶŐWůĂƚĨŽƌŵ 'ͲϭƌĚ ϭϯϯͬϴyϵϱͬϴyϰϭͬϮ dďŐŚĂŶŐĞƌ͕&DͲdͲϭͲEͲ Ͳ>͕ϭϭϱDyϰЪdͲϮůŝĨƚ ĂŶĚƐƵƐƉ͕ǁͬϰΖ͛dǇƉĞ,Ws ƉƌŽĨŝůĞ͕ϯͲϭͬϰĐŽŶƚŝŶƵŽƵƐ ĐŽŶƚƌŽůůŝŶĞƉŽƌƚƐ *UD\OLQJ3ODWIRUP *5'3URSRVHG2SWLRQ sĂůǀĞ͕DĂƐƚĞƌ͕t<DͲD͕ ϰϭͬϭϲϱD&͕,tK͕ ƚƌŝŵ sĂůǀĞ͕hƉƉĞƌŵĂƐƚĞƌ͕ t<DͲD͕ ϰϭͬϭϲϱD&͕,tK͕ƚƌŝŵ sĂůǀĞ͕^ǁĂď͕t<DͲD ϰϭͬϭϲϱD&͕,tK͕ ƚƌŝŵ ,d͕ŽǁĞŶ͕ϰϭͬϭϲϱD& ǆϳΖ͛ ƋƵŝĐŬƵŶŝŽŶƚŽƉ ĚĂƉƚĞƌ͕ĂĐƚƵƐͲEͲϲ͘ϮϱΖ͕͛ ϭϭϱDƐƚĚĚǆϰϭͬϭϲϱDƐƚĚĚ ƚŽƉ͕ǁͬϮͲϭΖ͛ŶƉƚĐŽŶƚƌŽůůŝŶĞ ĞǆŝƚƐ ĂƐŝŶŐŚĞĂĚ͕^ŚĂĨĨĞƌ<͕ ϭϯϱͬϴϯDǆϭϯϯͬϴ^Kt͕ǁͬ ϮͲϮΖ͛>WK ϭϯϯͬϴΖ͛ ϵϱͬϴΖ͛ dƵďŝŶŐŚĞĂĚ͕ĂĐƚƵƐͲϮϵ>͕ ϭϯϱͬϴϯDǆϭϭϱD͕ ǁͬϮͲϮϭͬϭϲϱD^^K͕ ǁͬϵϱͬϴ,W^ďŽƚƚŽŵ ϰЪ͛͛ dƵďŝŶŐŚĂŶŐĞƌ͕ĂĐƚƵƐͲEͲ >͕ϰЪhϴƌĚůŝĨƚĂŶĚ ƐƵƐƉǆǁϲЬŽĚĞǆƚŶĞĐŬ͕ϰΖ͛ ƚǇƉĞ,WsƉƌŽĨŝůĞ͕ͲE> ŵĂƚĞƌŝĂů sĂůǀĞ͕tŝŶŐ͕^^s͕t<DͲD͕ ϰϭͬϭϲϱD&͕ǁͬϭϱΖ͛ ĂŝƌŽƉĞƌĂƚŽƌ 'ƌĂǇůŝŶŐWůĂƚĨŽƌŵ 'ͲϭƌĚ ϭϯϯͬϴyϵϱͬϴyϰϭͬϮ *UD\OLQJ3ODWIRUP %236WDFN +$. +,/&253$/$6.$//& 6ZDFR6XSHUFKRNH%ORRH\/LQH7R*DV%XVWHU/ŶůĞƚ +LOFRUS$ODVND//&+LOFRUS$ODVND//&Changes to Approved Rig Work Over Sundry Procedure6XEMHFW &KDQJHVWR$SSURYHG6XQGU\3URFHGXUHIRU:HOO*5'37'6XQGU\;;;;;;$Q\PRGLILFDWLRQVWRDQDSSURYHGVXQGU\ZLOOEHGRFXPHQWHGDQGDSSURYHGEHORZ&KDQJHVWRDQDSSURYHGVXQGU\ZLOOEHFRPPXQLFDWHGWRWKH$2*&&E\WKHULJZRUNRYHU5:2³ILUVWFDOO´HQJLQHHU$2*&&ZULWWHQDSSURYDORIWKHFKDQJHLVUHTXLUHGEHIRUHLPSOHPHQWLQJWKHFKDQJH6HF 3DJH 'DWH 3URFHGXUH&KDQJH 1HZ5HTXLUHG"<1+$.3UHSDUHG%\,QLWLDOV+$.$SSURYHG%\,QLWLDOV$2*&&:ULWWHQ$SSURYDO5HFHLYHG3HUVRQDQG'DWH$SSURYDO$VVHW7HDP2SHUDWLRQV0DQDJHU 'DWH3UHSDUHG)LUVW&DOO2SHUDWLRQV(QJLQHHU 'DWH From:McLellan, Bryan J (CED) To:Josh Allely - (C) Cc:Aras Worthington; Katherine O"connor; Dan Marlowe; Roby, David S (CED) Subject:RE: G-01RD (PTD# 191-139) Request to flow under evaluation for 6 months Date:Wednesday, November 3, 2021 2:35:00 PM Josh, You should have received the approved comingling order today, CO 796. You do not need to submit a Sundry to return the well to production in its current status, as long as you are following the conditions of the comingling order. A bit of clarity for the order on condition #4: 4. In the time periods of January 1st to 15th, 2022 and April 1st to 15th, 2022, Hilcorp shall shut in the well to collect a new shut-in well pressure survey. Results of these surveys shall be provided to the AOGCC within 5 days of their collection. The intent is to collect a stable, static bottom hole pressure data point at some time within the above two date ranges. The well does not need to be shut-in for the entire 15 day periods, only long enough to reach stable bottom-hole pressure. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Josh Allely - (C) <Josh.Allely@hilcorp.com> Sent: Wednesday, October 27, 2021 8:54 AM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Cc: Aras Worthington <Aras.Worthington@hilcorp.com>; Katherine O'connor <Katherine.Oconnor@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com> Subject: G-01RD (PTD# 191-139) Request to flow under evaluation for 6 months Bryan I understand we are still waiting on the co-mingling order to be issued, but in the meantime, we would like to continue the conversation around flowing the well under evaluation. On August 6th 2021, well G-01RD (ESP producer) on the Grayling platform experienced a gas breakthrough event. As a result, Tubing and IA pressure climbed to 2400 psi. This well is equipped with a vented high set packer. The vent on the packer was shut and the IA was bled, however, it quickly pressured back up. After several attempts to regain integrity by cycling the vent valve, it was determined a component of the packer assembly was compromised. A seal-tite treatment to fix the leak in the packer assembly was attempted on 10/15 but was unsuccessful. Hilcorp requests permission to flow G-01RD for 6 months in its current condition to help understand the new reservoir conditions and use this data to plan a workover to be completed this spring. It is our intent to use the pressure gauge on the ESP intake along with production rates to help understand the size of the gas structure from which we are producing, rather than a pressure build-up analysis. This is to avoid unnecessarily cycling well pressures as this may lead to ESP cable damage due to repeated gas-decompression of the cable. Thanks, and feel free to call with any questions. Josh Allely Well Integrity Engineer Cook Inlet Basin – Hilcorp Alaska 907-777-8505 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 11,506 feet N/A feet true vertical 9,946 feet 11,337 & 11,409 feet Effective Depth measured 11,224 feet 445 feet true vertical 9,701 feet 445 feet Perforation depth Measured depth 10,089 - 11,290 feet True Vertical depth 8,715 - 9,758 feet Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6 / L-80 7,924 MD 6,869 TVD 445 (MD) 425 (MD) Packers and SSSV (type, measured and true vertical depth)Hydro Dual ESP Pkr 445 (TVD) Halliburton TRSV, NE-SLIM 425 (TVD) 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Contact Name: Authorized Title: Contact Email: Contact Phone: TVD measured true vertical Packer Other: Pull/Replaced ESP measured Collapse 7" 11,479 MD 327 2,160 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: 4. Well Class Before Work: 0 Representative Daily Average Production or Injection Data 1,3340 Casing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 191-139 50-733-20037-01-00 Plugs ADL0018730 / ADL0017594 Trading Bay Unit G-01RD 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 321-236 89 Authorized Signature with date: Authorized Name: 8,765 WINJ WAG 249 Gas-Mcf 1,338 N/A Oil-Bbl 0 Water-Bbl Intermediate N/A Junk 5. Permit to Drill Number: 278 McArthur River Field / Middle Kenai G & Hemlock Oil PoolsN/A measured 8,450 3,352 Size 92 Production Casing Structural Liner Length 327 2,160 Conductor Surface 8,530psi 26" 13-3/8" 9-5/8" 8,450 907 777-8434 11,220psi 327 2,120 7,319 9,921 Karson Kozub kkozub@hilcorp.com Tubing Pressure 1,540psi 3,090psi 3,090psi 5,750psi Hilcorp Alaska, LLC 2. Operator Name Senior Engineer: Senior Res. Engineer: Daniel E. Marlowe Operations Manager Burst Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 4:01 am, Jul 12, 2021 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.07.09 09:00:02 -08'00' Dan Marlowe (1267) DSR-7/13/21 SFD 7/16/2021RBDMS HEW 7/14/2021 BJM 8/9/21 McArthur River Field, TBU Well: G-01RD As Completed: 06/13/21 Updated by: JLL 07/06/21 SCHEMATIC RKB to MLLW ELEV = 103’ TD = 11,506’ PBD = 11,430’ MAX HOLE ANGLE = 39.10q @ 7225’ RKB to TBG Hngr = 42.68’ Tree connection: 3-1/2” EUE 8rd 2 3 5 1 6 4 7 HB-2 G-2 G-3 G-4 G-5 HB-4 HB-5 HB-7 HB-6 4-5/8” Perf Gun @ 11,409’ G-6 G-7 HB-3 26” 13-3/8” 9-5/8” 7” Fish @11337’ G-1 HB-1 TOC 8,127 CBL 2/15 1992 EST TOC 355’ Calc 10/7 1967 X CASING DETAIL Size WT Grade Conn ID MD Top MD Btm 26” Surf. 327’ 13-3/8” 61 J-55 Butt 12.515” Surf. 2,160’ 9-5/8” 47 N-80 Butt 8.681” Surf 79’ 40 N-80 Butt 8.835” 79’ 6,275’ 43.5 N-80 Butt 8.755” 6,275’ 8,179’ 47 N-80 Butt 8.681” 8,179’ 8,450’ (TOW) 9-5/8” DV Collar 4,903’ 4,905’ 7” 29 P-110 Butt 6.184” 8,127’ 11,479’ TUBING DETAIL 4-1/2” 12.6 L-80 IBT 3.958” Surface 7,924’ 03/29/21: Cleaned out to 11,224’ 12/17/00: Left 10.14’ long fish consisting of coil tubing motor and bit. 10/24/12: Cleaned out fill to 11337’ DPM, Fish not recovered. PERFORATIONS Zone Top MD Btm MD Top TVD Btm TVD Amt SPF Last Opr. Status G-01 10,089’ 10,120’ 8,715’ 8,742’ 31’ 5 01/16/14 Open G-2 10,140' 10,170' 8,759' 8,785' 30' 6 2/19/1992 Open 10,140' 10,170' 8'759' 8,785' 30’ 5 10/27/12 Reperf G-3 10,225' 10,257' 8,833' 8,861' 32' 6 2/19/1992 Open 10,244' 10,264' 8,849' 8,867' 20’ 5 10/27/12 Open G-4 10,278' 10,340' 8,879' 8,933' 62' 6 2/19/1992 Open 10,280' 10,342' 8,881' 8,935' 62’ 5 10/27/12 Open G-5 10,395' 10,415' 8,981' 8,999' 20' 6 2/19/1992 Open 10,398' 10,418' 8,984' 9,001' 20’ 5 10/27/12 Open 10,440' 10,460' 9,021' 9,038' 20’ 5 10/27/12 Open G-6 10,532' 10,548' 9,101' 9,115' 16’ 5 10/27/12 Open G-7 10,600 10,614' 9,161' 9,173' 14’ 5 10/27/12 Open HB-1 10,622’ 10,637’ 9,180' 9,194' 15’ 4 1/17/2001 Open HB-1 10,628' 10,670' 9,186' 9,223' 42' 10 & 16 8/26/1995 Open, frac'd 10,628'- 10,643' 10,628' 10,676' 9,186' 9,228' 48’ 5 10/27/12 Open HB-2 10,689’ 10,718’ 9,240’ 9,265’ 29’ 5 01/16/14 Open HB-3 10,846' 10,860' 9,377' 9,389' 14’ 5 10/27/12 Open HB-4 10,863' 11,000' 9,392' 9,509' 137' 6 2/19/1992 Open 10,939’ 10,954’ 9,457' 9,470' 15’ 4 1/17/2001 Open 10,890' 11,006' 9,415' 9,515' 116’ 5 10/27/12 Open HB-5 11,038’ 11,048’ 9,542' 9,550' 10’ 4 1/17/2001 Open 11,040' 11,070' 9,544' 9,569' 30' 8 8/26/1995 Open 11,042' 11,122' 9,545' 9,614' 80’ 5 10/27/12 Open HB-6 11,155' 11,170' 9,642' 9,655' 15' 4 8/26/1995 Open 11,156' 11,240' 9,643' 9,715' 84’ 5 10/27/12 Open HB-7 11,255' 11,280' 9,728' 9,749' 25' 24 6/24/1994 Open 11,266' 11,290' 9,737' 9,758' 24’ 5 10/27/12 Open Jewelry Details No.Depth MD Depth TVD ID OD Item 42.68’ 42.68’ CIW-DCB-ESP, 11” x 4-1/2” IBT lift and susp, w/4” Type H BPV Profile Hanger 1 425’ 425’ 3.813 5.965 TRSV,NE-SLIM, STD,5K 2 445’ 445’ 3.930 8.500 9-5/8" x 4-1/2" LTC 36-47# Hydroset Dual ESP Packer 3 467’ 467’ 3.813 4.500 4-1/2" Hydril 563 X-Nipple 4 2,306’ 2,244’ 3.992 7.063 GLM#1 - SPM 1 1/2" GLV IPOR-2 Port Size 24 5 4,232’ 3,844’ 3.992 7.063 GLM#2 - SPM 1 1/2" GLV IPOR-2 Port Size 24 6 5,582’ 4,951’ 3.992 7.063 GLM#3 - SPM 1 1/2" GLV IPOR-2 Port Size 24 7 7,924’ 6,869’ -- 5.130 Discharge- BTN, 4 1/2”, 8RD EUE, 416/420SS, 675X PN:900031005 7,926’ 6,871’ -- 6.750 Pump (2) - 675 Series, SH13000CCW 7,970’ 6,909’ -- 6.750 Intake 7,971’ 6,909’ -- 5.130 Upper/Lower Seals 7,994’ 6,929’ -- 5.620 Motor (2) - 562 KMS2, LT/UT, 500HP 8,061’ 6,986’ -- 4.500 Centrilizer/Anode Rig Start Date End Date HAK 404 6/9/21 6/15/21 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit Number 50-733-20037-01 191-139 Well Name G-01RD Daily Operations: 06/10/2021 - Thursday Mobilize crew from Tyonek Platform to Grayling. Hold orientation. Organize drill deck. Off load work boat. Set base beams. Install spreaders. Set carrier. Set accumulator house and miscellaneous rig equipment. Remaining rig crew arrived from the Tyonek @ 22:00hrs. Boat arrived with equipment @ 23:00. Assisted crane off loading boat. Staging equipment for rig up. Fly on Mast and secure pins, Raise Mast prep mast to spool tuggers and drill line, spot mud pumps and pits. 06/11/2021 - Friday Raise derrick. Spool on drill line and tuggers. Lower derrick back down. Rig up fill line to pits. Off load work boat. Rig up mud pump. Continued off loading boat, Rig up panic line and choke line to manifold . Built 4-1/2" Test Joint. Hooked up circulating lines for well kill. Took on FIW in pits. PJSM w/ Production discussed well kill, Lined up to pump down Tbg returns up IA to production. Pumped 400 bbls of IFW @ 3bpm with no returns. SD pump tubing on vac. Switched hoses and pumped 20bbls down IA, SD pump well on vac. Prep Tree to N/D, Removed flowline and cap with blind flange. Break and fly out wing valve and SSV. N/D Tree. Inspected penetrator and lift threads all good. Installed lifting eye on top of riser, M/U 13-5/8" x 11" DSA to Riser and Landed on wellhead, N/U 13-5/8" Mud Cross, Dbl Gate and Annular. MU Choke/Kill lines. Torque up connections 06/09/2021 - Wednesday Mobilize Pollard slick line crew to platform. JSA - TGSM with production. Spot equipment. Pressure test lubricator at 250 L/2500 H. RIH with 3.75" gauge ring to 5700' SLM without issue. RIH with GS 4 1/2" AD-2 stop to 5630' SLM w/t shear stop pull up to 5598' SLM (5622' RKB) w/t set w/t shear and POOH. RIH with 4 1/2" GS w/ DD pack off plug (w/4 Kobe Knockouts. Requires min 55" prong from top of AA stop to Kobes). Run to 5594' SLM (5618' RKB) w/t shear w/t POOH. Use jumper hose from IA to tubing. Pressure up lubricator prior to opening. RIH w/ 4 1/2" GS w/ 4 1/2" GS w/ 4 1/2" AA stop to 5991' SLM (5616" RKB) w/t shear and POOH. RIH w/ 4 1/2" GS w/ 4 1/2" catcher sub to 6687' SLM (5612' RKB) w/ set w/ shear and POOH. RIH w/4 1/2" OM-1 KOT w/ 1 5/8" JDS to 5519' SLM (0' correction for KB from deck zero) with locate latch. Come free. POOH with dummy GLV station #3. **Tools coated in heavy paraffin. RIH w/ 4 1/2" OM-1 KOT w/ 1 5/8" RK RT with circulation valve to station 3 at 5519' RKB. Locate, set/shear and POOH, OOH. Rig down. No further activity. Rig Start Date End Date HAK 404 6/9/21 6/15/21 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit Number 50-733-20037-01 191-139 Well Name G-01RD Daily Operations: Monitor tubing and annulus for pressure build up. Bleed gas from tubing to gas buster. Tubing static and annulus on slight vacuum. BOLDS. Pull tubing hanger and lay down. POOH 6 stands from 8004' to 7664'. Summit meg check good. Pick up vent packer, SSSV and x-nipple assembly. Make cable splice. Run control lines and actuate vent valve. Opens at 3000 psi. Pumping 20 bbls FIW every 30 minutes. RIH with stands out of derrick installing cannon clamps on every joint. P/U 133 K, S/O 95 K. PU/MU and serviced Tubing Hanger, cut cable and terminated penetrator to hanger. Dress tubing hanger with control lines. Connected umbilical cord and landed completion with 95k down on Hanger putting EOT @ 8,060'. Final cable check was good. RILDS. Pack and test seals to 5k for 15mins-good test. RU Pollard SL, RIH w/ball and rod and set in RHC plug body @ 467'. POOH RD SL. R/U Testing equipment, Filled Tubing with 6 bbls of FIW, Pressured up on tubing to 3,800psi and held pressure for 30mins per Tripoint packer setting procedure. Bled off. Filled IA with 19bbls of FIW. MIT-IA/Packer to 1,500psi, charted for 30mins-good test. Bled off IA and R/D Testing equipment. Test Chart in folder for viewing, BO/LD Landing Joint, Set BPV, R/D Power Tongs, Clean, cleared and removed rig floor and stairs, R/D pump and pits. Unstrung drill line and tuggers, Disconnect Kill/Choke lines and Koomey control lines from stack Scope and Lay over Mast. Currently N/D BOP's at report time. FIW loss today: 309 bbls FIW loss total: 859 bbls. Torque dead man bolts. Raise and scope derrick. Install and tighten guy wires. Install rig floor and stairs. Chain down stack. Rig up accumulator hoses. Hook up service lines. Offload work boat. Function test BOPE. Troubleshoot and resolve Koomey remote issues. Install weight indicator. Attempt to shell test BOP. Not holding high pressure. Back out test joint. Pull BPV and set two-way check. Install test joint. Shell test BOPE (good). Test BOPE at 250 L/2500 H. AOGCC (Bob Noble) witnessed test. Pull two-way check. Pump 20 bbls FIW down hole. Break down test joint. Install stairs to rig floor. Rig up McCoy tongs. Platform gas alarm/abandon platform drill. Hung cable sheaves and elephant trunk, pulled rope through sheave to spooler. Jacked rig to center the hole, MU 4-1/2" Landing Joint with TIW, Checked IA pressure 225psi with analog gauge. Hooked up digital gauge IA = 190psi. Contacted town engineer to discuss plan forward. Hooked up high pressure bled off hose to IA. Production operator managing IA bled off per town engineer design @ 20psi/hr. Filled Pits with FIW, Lay out circulating hoses. Pollard, Summit and Tripoint services hands on board @ 19:00hrs. Production continued monitoring bled off of IA @ ~20psi/hr. Assist crane to organize deck for better egress paths. Broke down production tree so it will fit through well hatch. Organized and marked hammer wrenches. IA bled off to 0psi. R/U Kelly hose to IA valve. Started pumping FIW down IA at 3.5-4bpm/0psi. Continued pumping IA volume at report time. FIW loss today: 340 bbls FIW loss total: 550 bbls. 06/13/2021 - Sunday 06/12/2021 - Saturday charted for 30mins-good test. MIT-IA/Packer to 1,500psi, c Pull tubing hanger and lay down. POOH 6 stands from 8004' to 7664'. Summit meg check good. Pick up vent packer, SSSV and x-nipple assembly. Make c Rig Start Date End Date HAK 404 6/9/21 6/15/21 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit Number 50-733-20037-01 191-139 Well Name G-01RD Daily Operations: 06/14/2021 - Monday Nipple down BOPE. Break stripper head off of annular preventer. Dress hanger/tubing spool. Finish dressing tubing hanger. Pick up and organize tools. Unbolt drawworks and drive line. N/U tree. R/U to test tree. Simops: R/D doghouse. Drain oil from drawworks. Coil high pressure hoses in offshore basket. Test void at 5000 psi. Make up safety valve to tree. Torque all bolts. Back load boat with pits and mud pump. Prepare mast for removal. Continue with general rig down miscellaneous and preparing loads for the boat. Sent AAO night rig crew to the Steelhead to offload and spot equipment. Assist crane loading out boats and moved 404 and equipment and staged on the Steelhead for Upcoming RWO. Crew scrub decks, etc. Sent remaining AAO crew to the Steelhead @ 05:30. Simops: Slickline MIRU @ 01:00hrs and currently prep well for production. 06/15/2021 - Tuesday RU Slickline. PT to 500 PSI low, 1500 PSI high. PASS. RIH w/ 2" JDC w/ 3.54" bell guide to 465' kb, w/t. POOH w/ ball and rod. RIH w/ 4 1/2" GS to 469' kb. w/t, POOH w/ 4 1/2" plug. RIH W/ 4 1/2" OM-1 and 1 5/8" JDS to 2305' KB. Sit down at sta. 3. W/t, POOH, after shearing off of upper valve. Re-pin tools, PJSM w/ day crew, permit, breakfast. RIH w/ same to 5599' KB. W/t, pooh w/o valve. Re-pin OM-1. JDS not sheared. RIH w/ same to 5599' KB. W/t, pooh w/o valve. Re-pin OM-1. JDS sheared. RIH w/ 4 1/2" GS, w/o dogs, to 5660' kb. Tag catcher sub. Correct measurements, POOH. FL found @ 2680' KB.RIH w/ 4 1/2" OM-1 and 1 5/8" JDS to 5601' kb, locate. W/T at 5599' KB, POOH w/o valve. RIH w/ same to 5599' KB, latch up. W/T, POOH w/ pocket protector. RIH W/ 4 1/2" OM-1 w/ 1 1/2" dummy valve to 5599' KB, locate. W/T, POOH w/o valve. RIH w/ 4 1/2" GS to 5660' KB, w/t. POOH w/ empty catcher sub. RIH w/ 5' of 1 1/2" stem and 1.64" swedge to 5670' KB, w/t. POOH after knocking out KOBES. FL rose to 2200' KB. RIH w/ same to 5675' KB, w/t. POOH w/ A stop. RIH w/ same to 5677' kb, W/T. POOH w/ DD Packer plug. FL @ 2100' KB. RIH w/ same to 5680' KB, w/t. POOH w/ AD-2 stop. RD. FLOOR SAFTY VALVES: STATE OF ALASKA TEST DATA Upper Kelly 0 . NA - Lower Kelly Reviewed By: 1x MUD SYSTEM: OIL AND GAS CONSERVATION COMMISSION P,1. Supry 17 zoz.1 P - BOPE Test Report for: TRADING BAY UNIT G-01 RD ' Comm Contractor/Rig No.: Hilcom 404 PTD#: 1911390 - DATE: 6/12/2021 - Inspector Bob Noble Insp Source Operator: Hilcorp Alaska, LLC Operator Rep: Brumley Rig Rep: Reed Inspector Type Operation: WRKOV Sundry No: Test Pressures: Inspection No: bopRCN210613173252 3000 Rams: Annular: Valves: MASP: Housekeeping: P TypeTest: INIT 321-236 - ' 250/2500- 250/2500 ' 1594 - 2 —5002500/2500 Related Insp No: Pressure After Closure FLOOR SAFTY VALVES: Quantity TEST DATA Upper Kelly 0 . NA - Lower Kelly MISC.INSPECTIONS: MUD SYSTEM: Ba [I Ball Type ACCUMULATOR SYSTEM: P - Inside BOP P/F P Visual Alarm 0 Time/Pressure P/F Location Gen.: P _" Trip Tank NA - NA - System Pressure 3000 P Housekeeping: P Pit Level Indicators P - P Pressure After Closure 2300 _P PTD On Location P Flow Indicator NA - NA - 200 PSI Attained 38 P " Standing Order Posted P Meth Gas Detector P - P-- Full Pressure Attained _ 134 P Well Sign P H2S Gas Detector P - P Blind Switch Covers: All stations ' P Drl. Rig P MS Misc NA_" NA Nitgn. Bottles (avg): 6 (a) 2000 - P " Hazard Sec. _ P _ ACC Misc 0_ NA Misc NA FLOOR SAFTY VALVES: BOP STACK: Quantity Size P/F Stripper Quantity P/F Upper Kelly 0 . NA - Lower Kelly 0 • NA - A - Ba [I Ball Type 1 _' P - Inside BOP 1 P FSV Misc 0 NA BOP STACK: Quantity Size P/F Stripper 0 NA Annular Preventer 1 - 13 5/8" - P - #1 Rams 1 2 7/8' x 5 1/2"- P_ #2 Rams 1 ' Blinds - P #3 Rams _ 0 NA #4 Rams 0 NA #5 Rams 0 NA 46 Rams _ 0 NA Choke Ln. Valves 1 - 2 1/16" P - HCR Valves 2 12 1/16" _ ' P Kill Line Valves 2 2 1/16" ' P Check Valve 0 NA BOP Misc 0 NA Number of Failures: 0 1Test Results Remarks: All alarms were tested by TOTCO. Good test CHOKE MANIFOLD: Quantity P/F No. Valves 11 _ P - Manual Chokes 1 P - Hydraulic Chokes 1 _ P CH Misc 0 NA INSIDE REEL VALVES: (Valid for Coil Rigs Only) Quantity P/F Inside Reel Valves 0 _ NA Test Time 4.5 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 11,506 feet N/A feet true vertical 9,946 feet 11,337 & 11,409 feet Effective Depth measured 11,224 feet N/A feet true vertical 9,701 feet N/A feet Perforation depth Measured depth 10,089 - 11,290 feet True Vertical depth 8,715 - 9,758 feet Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6 / L-80 7,861 MD 6,816 TVD Packers and SSSV (type, measured and true vertical depth)N/A & N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Contact Name: Authorized Title: Contact Email: Contact Phone: Hilcorp Alaska, LLC 2. Operator Name Senior Engineer: Senior Res. Engineer: Daniel E. Marlowe Operations Manager Burst kkozub@hilcorp.com Tubing Pressure 1,540psi 3,090psi 3,090psi 5,750psi 907 777-8434 11,220psi 327 2,120 7,319 9,921 Karson Kozub 327 2,160 Conductor Surface 8,530psi 26" 13-3/8" 9-5/8" 8,450 3,352 Size 101 Production Casing Structural Liner Length Intermediate N/A Junk 5. Permit to Drill Number: 298 McArthur River Field / Middle Kenai G & Hemlock Oil PoolsN/A measured 8,450 323 Gas-Mcf 68 N/A Oil-Bbl 197 Water-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 321-052 96 Authorized Signature with date: Authorized Name: 10,422 WINJ WAG STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 191-139 50-733-20037-01-00 Plugs ADL0018730 Trading Bay Unit G-01RD 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: 4. Well Class Before Work: 137 Representative Daily Average Production or Injection Data 614,223 Casing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 7" 11,479 MD 327 2,160 TVD measured true vertical Packer Other: Replaced ESP measured Collapse PL G Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 2:33 pm, Apr 22, 2021 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.04.22 14:08:20 -08'00' Dan Marlowe (1267) BJM 5/19/21 SFD 4/22/2021 RBDMS HEW 4/23/2021 DSR-4/22/21 McArthur River Field, TBU Well: G-01RD As Completed: 04/03/21 Updated by: JLL 04/18/21 SCHEMATIC RKB to MLLW ELEV = 103’ TD = 11,506’ PBD = 11,430’ MAX HOLE ANGLE = 39.10q @ 7225’ RKB to TBG Hngr = 42.68’ Tree connection: 3-1/2” EUE 8rd 1 3 4 2 HB-2 G-2 G-3 G-4 G-5 HB-4 HB-5 HB-7 HB-6 4-5/8” Perf Gun @ 11,409’ G-6 G-7 HB-3 26” 13-3/8” 9-5/8” 7” Fish @11337’ G-1 HB-1 TOC 8,127 CBL 2/15 1992 EST TOC 355’ Calc 10/7 1967 CASING DETAIL Size WT Grade Conn ID MD Top MD Btm 26” Surf. 327’ 13-3/8” 61 J-55 Butt 12.515” Surf. 2,160’ 9-5/8” 47 N-80 Butt 8.681” Surf 79’ 40 N-80 Butt 8.835” 79’ 6,275’ 43.5 N-80 Butt 8.755” 6,275’ 8,179’ 47 N-80 Butt 8.681” 8,179’ 8,450’ (TOW) 9-5/8” DV Collar 4,903’ 4,905’ 7” 29 P-110 Butt 6.184” 8,127’ 11,479’ TUBING DETAIL 4-1/2” 12.6 L-80 IBT 3.958” Surface 7,861’ 03/29/21: Cleaned out to 11,224’ 12/17/00: Left 10.14’ long fish consisting of coil tubing motor and bit. 10/24/12: Cleaned out fill to 11337’ DPM, Fish not recovered. PERFORATIONS Zone Top MD Btm MD Top TVD Btm TVD Amt SPF Last Opr. Status G-01 10,089’ 10,120’ 8,715’ 8,742’ 31’ 5 01/16/14 Open G-2 10,140' 10,170' 8,759' 8,785' 30' 6 2/19/1992 Open 10,140' 10,170' 8'759' 8,785' 30’ 5 10/27/12 Reperf G-3 10,225' 10,257' 8,833' 8,861' 32' 6 2/19/1992 Open 10,244' 10,264' 8,849' 8,867' 20’ 5 10/27/12 Open G-4 10,278' 10,340' 8,879' 8,933' 62' 6 2/19/1992 Open 10,280' 10,342' 8,881' 8,935' 62’ 5 10/27/12 Open G-5 10,395' 10,415' 8,981' 8,999' 20' 6 2/19/1992 Open 10,398' 10,418' 8,984' 9,001' 20’ 5 10/27/12 Open 10,440' 10,460' 9,021' 9,038' 20’ 5 10/27/12 Open G-6 10,532' 10,548' 9,101' 9,115' 16’ 5 10/27/12 Open G-7 10,600 10,614' 9,161' 9,173' 14’ 5 10/27/12 Open HB-1 10,622’ 10,637’ 9,180' 9,194' 15’ 4 1/17/2001 Open HB-1 10,628' 10,670' 9,186' 9,223' 42' 10 & 16 8/26/1995 Open, frac'd 10,628'- 10,643' 10,628' 10,676' 9,186' 9,228' 48’ 5 10/27/12 Open HB-2 10,689’ 10,718’ 9,240’ 9,265’ 29’ 5 01/16/14 Open HB-3 10,846' 10,860' 9,377' 9,389' 14’ 5 10/27/12 Open HB-4 10,863' 11,000' 9,392' 9,509' 137' 6 2/19/1992 Open 10,939’ 10,954’ 9,457' 9,470' 15’ 4 1/17/2001 Open 10,890' 11,006' 9,415' 9,515' 116’ 5 10/27/12 Open HB-5 11,038’ 11,048’ 9,542' 9,550' 10’ 4 1/17/2001 Open 11,040' 11,070' 9,544' 9,569' 30' 8 8/26/1995 Open 11,042' 11,122' 9,545' 9,614' 80’ 5 10/27/12 Open HB-6 11,155' 11,170' 9,642' 9,655' 15' 4 8/26/1995 Open 11,156' 11,240' 9,643' 9,715' 84’ 5 10/27/12 Open HB-7 11,255' 11,280' 9,728' 9,749' 25' 24 6/24/1994 Open 11,266' 11,290' 9,737' 9,758' 24’ 5 10/27/12 Open Jewelry Details No.Depth MD Depth TVD ID OD Item 42.68’ 42.68’ CIW-DCB-ESP, 11” x 4-1/2” BTC lift and susp, w/4” Type H BPV Profile Hanger 1 2,242’ 2,190’ 3.992 7.063 GLM#1 - SPM 1 1/2" GLV IPOR-2 Port Size 24 w/Dummy 2 4,168’ 3,792’ 3.992 7.063 GLM#2 - SPM 1 1/2" GLV IPOR-2 Port Size 24 w/Dummy 3 5,518’ 4,898’ 3.992 7.063 GLM#3 - SPM 1 1/2" GLV IPOR-2 Port Size 24 w/Dummy 4 7,861’ 6,816’ -- 5.130 Discharge- BTN, 4 1/2", 8RD EUE, 416/420SS, 675X PN:900031005 7,863’ 6,818’ -- 6.750 Pump- 675 Series, SH13000CCW, 45S, INC, 15, 1:1 XRO, 316 PN: 103000698 (x2) 7,906’ 6,854’ -- 6.750 Intake- 675-513X, S/A, AR, X2, INC, 416SS P/N:900600078 7,908’ 6,856’ -- 5.130 Seals (Upper and Lower) 513 Series, BPBSBPB 7,930’ 6,875’ -- 5.620 562 MOTOR KMS2, LT, 500HP, 1800V, 171A (x2) 7,997’ 6,932’ -- 4.500 Centrilizer/Anode Rig Start Date End Date HAK 404 3/24/21 4/3/21 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit Number 50-733-20037-01 191-139 Well Name G-01RD Daily Operations: 03/25/21 - Thursday Clean and organize decks for incoming boat load. Assist crane crew with off loading boat. Install lifting eye to top of riser and 13 3/8 "5M X 11" 5M DSA to bottom of riser. Land riser and DSA on wellhead. Stack mud cross, double gate BOP and Annular on riser. Assist electrician with running power cables. C/O manual choke valve on choke manifold. Expectations / Safety meeting with both crews and production to go over platform emergency procedures and protocols. Raise mast, secure lower guy wires. Torque up bolts on riser and BOPE. Hang rig floor, stairs and beaver slide. Continue to torque bolts on BOPE. R/U choke & kill line, accumulator lines, pressure up accumulator unit, function test BOPE. PTSM. R/u winterization for cellar, spot heater start warming cellar, spot pump & mix pit, run circulating lines, dress rig floor- install bails, r/u tongs, run FIW to pump. 03/26/21 - Friday Build 3 1/2" and 4 1/2" test joints. R/U test pump, chart and run test line to rig floor. Install 3 1/2" test joint and fluid pack BOPE. Shell test BOPE from pipe rams down w/ 250 psi low and 2500 psi high. Annular will not hold pressure. Change out Annular preventer. Finish torqueing bolts on annular. Assist crane with offloading mud pits from boat and setting in place on deck. Abandon Platform Drill. Install 3 1/2" test jt. and R/U to test BOPE. Test BOPE w/ 3 1/2" and 4 1/2" test joints to Hilcorp and AOGCC standards. All components tested to 250 psi low and 2500 psi high. Test gas alarms and PVT's with Quadco reps. All components passed. AOGCC witness of test waived by Jim Regg. Blow down lines, attempt to center over well ran out of adjustment, boat load out pulling eq. from Steelhead & jacking cylinders. Unload boat & spot Summit pulling eq. pull test joint, & blanking sub. Send boat to King to get jacking unit. Skid racking mat toward well center. backload boat. Modify hand rail to accept slide. R/U jacks, pull clamps, skid rig south to well center, secure same, unload mud products from boat. Install circulating head to annular, breakdown test joint, cont. r/u Summit pulling eq. hang sheave in derrick, M/U landing joint. Dress slips. 03/24/21 - Wednesday Set and pin mast to A-leg, pin lifting rams to mast, install stairs on rear of carrier, unload drilling spool off of mast. Assist crane crew with backloading boat and arranging the deck. Circulate well to production, pump 1060 bbls FIW down tubing FCP 1225psi, no returns, monitor well tubing went on vac. Continue housekeeping and organizing. Tighten up bolts on spreader beams, hook up bang board, offload boat. Stage racking beam , Koomey house, dog house, choke house, mud pump, rig floor and BOP equipment. Cont. unload boat, send to King for next boat load, organize deck, prep mast to stand. Check well good, install BPV, N/D tree, unload boat wk on circulating head l/D pins. Prep wellhead, cap lines, check penetrator cap & "O" ring, check lift threads good, install blanking sub. Prep & stand mast, string up blocks, & tugger lines, lay down mast, cont. arrange decks. AOGCC witness of test waived by Jim Regg. All components tested to 250 psi low and 2500 psi high. Shell test BOPE from pipe rams down w/ 250 psi low and 2500 psi high. Circulate well to production, pump 1060 bbls FIW down tubing FCP 1225psi, no returns, monitor well tubing went on vac. Stack mud cross, double gate BOP and Annular on riser. Rig Start Date End Date HAK 404 3/24/21 4/3/21 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit Number 50-733-20037-01 191-139 Well Name G-01RD Daily Operations: Prep for backload, cont. mixing size salt pill. Assist crane crew w/ offloading and back loading boat. Change out McCoy power tongs with Gills. Dress Gills to make up 4 3/4" BHA. Continue mixing sized salt pill. Filling hole 5 bbl every 20 min. Make up clean out BHA and to 214'. Offloading 3 1/2 PH6 work string sent from the Steelhead. Finish offloading 3 1/2 PH6 work string and equipment sent from the Steelhead. Strap work string, RIH w/ clean out BHA picking up 3 1/2 PH6 work string. Filling hole 5 bbl every 20 min. t/3630', up wt 46k, dn wt 40k. Cont. RIH w/ clean out BHA picking up 3 1/2 PH6 work string. Filling hole 5 bbl every 20 min. t/8100', up wt 87k, dn wt 64k, go through liner top @ 8127' had small bobble. Cont. RIH w/ clean out BHA picking up 3 1/2 PH6 work string. Filling hole 5 bbl every 20 min. t/10,000', up wt 118k, dn wt 72k. R/U pump 320bbls @ 3bpm, 55 psi, w/ no returns, arrange deck while pumping, spot power swivel & cutting box, tally pipe. Cont. RIH w/ clean out BHA picking up 3 1/2 PH6 work string. Filling hole 5 bbl every 20 min. f/10,000' t/10721', set down, work through tight spot, pulling heavy, c/o elevators, cont. wk through clean. 03/29/21 - Monday P/U and dress T-Bar. Run T-Bar down, engage and pull BPV. L/D T-Bar. P/U 4 1/2" YC elevators and landing jt. Make up into hanger, verify no pressure on annulus and back out LDS. Unseat hanger w/ 82K. Pipe picked up free @ 110K. Pull hanger to rig floor. Cut flatpack and ESP cable loose from hanger and attach snakes to pull same to Summit spools. Break off and L/D hanger and landing jt. (Pumped 60 bbl FIW down annulus), POOH racking back 4 1/2" completion f/ 7952' to 4013'. Removing clamps and bands. Summit pooling ESP and flat line on spools. Pump 5 bbl FIW to fill hole every 20 min. (Mixing sized salt pill while tripping out) L/D 1 ea. GLM, Change out ESP spools, POOH racking back 4 1/2" completion f/ 4013' to 2427'. Removing clamps and bands. Summit spooling ESP and flat line on spools. Pump 5 bbl FIW to fill hole every 20 min. (Continue to mix sized salt pill while tripping out) L/D 2 ea, GLM, Cont. POOH standing back 4 1/2" completion t/ ESP assy. Clear floor & c/o handling tools for pump assy. L/D ESP Assembly, 2- pumps, upper & lower seals, 2 motor assy, had full recovery, had scale build up starting on lower seal assy. Clear & clean floor, r/d summit pulling eq. prep for backload, cont. mix size salt pill. Install flange bolts on circulating head, install circulating line to pits. 03/28/21 - Sunday 03/27/21 - Saturday Work through tight spot @ 10,721' several times (dn wt 80k, up wt 135k). RIH w/ clean out BHA picking up 3 1/2 PH6 work string f/10,721' to 11,224' where we took weight. Attempt to work down, No joy. Rig up to circulate, pump 80 bbl sized salt pill and chase with FIW spotting pill in 3 1/2" X 7" annulus. Shut in TIW to prevent u-tubing. P/U power swivel, R/U hoses, static lines and controls on rig floor while allowing pill to soak into perforations. After 20 min. pump 126 bbl FIW @ 3 bpm down back side to fill hole. Continue R/U of power swivel. (Hoses crossed and loose on reel making them difficult to unspool.) R/U static lines, connect hydraulic lines to swivel and M/U TIW valve and X/O to PH6. M/U swivel to work string and pump 85 bbl FIW down pipe w/ no returns. Switch to pumping down back side and pump 66 bbl FIW to fill hole to top of annular. Shut down pump and fluid level stated slowly falling. Attempt to pump down tubing and fluid level dropped out of sight. Call town and discuss options with engineer. Blow down lines, Break off power swivel, l/d single, R/D swivel, pull safety valve & saver sub, C/O handling tools to pull wk string. POOH l/d 3 1/2" wk string f/11206' up wt 138-145k, dn wt 70, t/9534' up wt 116k, dn wt 70k, Cont. POOH l/d 3 1/2" wk string t/4751'. Pump 5 bbl FIW to fill hole every 20 min. ( Pull hanger to rig floor. C verify no pressure on annulus and back out LDS. Rig Start Date End Date HAK 404 3/24/21 4/3/21 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit Number 50-733-20037-01 191-139 Well Name G-01RD Daily Operations: 03/31/21 - Wednesday Test BOPE on 3 1/2" and 4 1/2" test joints 250 L/2500 H. Fail/Pass due to leaking connections on test joint. Pull test joint and test plug and lay down same. Change out handling tools. RIH with packer with 4 1/2" production tubing out of derrick from 1098' to 4252'. Adding 5 bbls FIW every 20 minutes. RIH with packer with 4 1/2" production tubing out of derrick from 4252' to 8109', up wt 78k, dn wt 60k, tih into 7" liner @ 8127' clean. Adding 5 bbls FIW every 20 minutes. Cont. RIH with packer with 4 1/2" production tubing out of derrick to 8817'. C/O handling eq. P/U 3 1/2" PH-6 wk string tih t/9871', up wt 100k, dn wt 68k. Work pipe while holding 2k right hand tq. working down to get packer into set position set @ 9885', set down 23k. Fill hole w/fiw 90 bbls, pressure up t/ 1750psi hold for 30 min had 150 psi pressure drop. Set down 30k total on packer, retest with same result. POOH t/ 9825' reset packer, fill hole 55 bbls. Pressure up t/ 1700psi hold for 30 min good. R/D test eq/ pull packer free let elements relax. POOH l/d 3 1/2" wk string f/9825' t/9747'. 04/01/21 - Thursday POOH l/d 3 1/2" wk string from 9747' to 8848'. Change out handling equipment to 4 1/2". Investigate crown sheave grease fitting that was not taking grease. POOH standing back production tubing to 5350'. Pumping 5 bbls down hole every 20 minutes. Continue POOH standing back tubing to 4500'. Repair and inspect air slips. Continue POOH standing back tubing and lay down packer. Clean & clear floor. Cut & slip drill line, 60'. R/U running eq. for ESP assembly. P/U & service ESP assy, P/u tandem motors & lower seal assy, service same. Cont. p/u & service ESP assy, = upper seal, intake, tandem pump, ported sub, discharge = 136', test cable/MLE good. Clear floor start changing out handling tools. 03/30/21 - Tuesday Cont. POOH l/d 3 1/2" wk string f/4751' to BHA. Lay down clean out BHA. Pump 5 bbls FIW every 20 minutes. Clear rig floor. Change out handling equipment. RIH with packer assembly picking up PH6 work string to 1098'. East Skagit crane down due to oil seal leak. Mobilize crane mechanic to platform to troubleshoot. Housekeeping & rig maint. while crane mechanic diagnosed issue. Found PTO bearing, seal out and rear main seal leak. Discuss options for plan forward while repairs are being made. Decide to hang off & test BOPE. Send notification & contact AOGCC while making plan to hang off & test, witness was waived & permission to test early by AOGCC inspector Jim Regg @ 20:37. R/U run stand of 4 1/2" tubing, pull & l/d both joints & 1 jt of 3 1/2" wk string for test joints. M/U valve assy & p/u test plug on 3 1/2" test joint, M/U same to string. RIH hang string off test plug. Rig up test eq. fill stack & surface eq. shell test 250 /2500, on annular good. Attempt testing, had slow leak, troubleshoot, chase down to possible test plug leak, re- seat, re-test good. Fill hole w/fiw 90 bbls, pressure up t/ 1750psi hold for 30 min had 150 psi pressure t packer into set position set @ 9885', s Send notification & contact AOGCC while making plan to hang off & test, witness was waived & permission to test early by AOGCC Pressure up t/ 1700psi hold for 30 min good. R Adding 5 bbls FIW every 20 minutes. Rig Start Date End Date HAK 404 3/24/21 4/3/21 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit Number 50-733-20037-01 191-139 Well Name G-01RD Daily Operations: RIH with ESP to 2638'. Meg check every +-1000'. Inspect seal rings and change out as needed. Laid down top of stand #22 (joint 44 damaged). Run GLM and pick up single joint of tubing after running GLM. Fill hole with 5 bbls FIW every 20 minutes. RIH with ESP from 2638' to 5311'. Meg check every +-1000'. Inspect seal rings and change out as needed. RIH with ESP from 5311' to 5742'. Meg check every +-1000'. Inspect seal rings and change out as needed. P/U GLM #3 had some metal fragments in thread protector, L/D GLM cleanout on deck before running, debris appeared to be possible AR bearing pieces. RIH with ESP from 5742' to 6539'. Meg check every +-1000'. Inspect seal rings and change out as needed. C/O cable spool, splice cable & Meg same, (splice landed on joint 210 6645'~. RIH with ESP from 6539' to 7960' Meg check every +-1000'. Inspect seal rings and change out as needed. P/U hanger & landing joint, make up same. Make penetrator splice. 04/03/21 - Saturday Finish making cable splice at tubing hanger. Make up penetrator and terminate motor leads. Test good. Terminate flat pack lines at hanger. Land tubing hanger putting pump at 8005'. Meg test good. RILDS. Test hanger body at 5000 psi/5 minutes. Lay down landing joint. Set TWC. Prepare to remove rig floor. Rig down tubing tongs. Rig down Summit equipment. Load out rig floor tools. Disconnect accumulator hoses. Disconnect kill line from stand pipe. Move doghouse. Remove doghouse stairs. Scope derrick down. Lay derrick over. N/D BOPE, R/D choke & kill lines, break bolts on BOPE while backloading boat, unstack BOPE & riser. Prep well head, N/U tree, install flow lines, cont. Prep eq. for load out, test hanger neck seals & void t/5k good, test tree, had flange leak, re-torqued, re-test t/ 5k good. Pull TWC, install tree cap. Turn well over to production. 04/02/21 - Friday RIH with ESP to 2638'. Land tubing hanger putting pump at 8005'. 1 Guhl, Meredith D (CED) From:Karson Kozub - (C) <kkozub@hilcorp.com> Sent:Monday, May 17, 2021 2:41 PM To:McLellan, Bryan J (CED) Cc:Juanita Lovett Subject:Trading Bay Unit G-01RD (PTD191-139) ESP Workover Attachments:G-01RD Proposed 2021-05-17 (V2).pdf GoodAfternoonBryan, IforgottoaddanXͲnippleontheproposedschematicthatwassubmittedforGͲ01RD.Attachedisanupdated schematicwiththeXͲnipplebelowthepacker. IalsoplantosetaplugabovetheESPandcirculatethroughthelowestGLVinordertokeepdebrisoutoftheESP. ThechangestothesubmittedsundryareinREDbelow.Pleaseletmeknowifyouwouldlikeitsubmitteddifferently. LastCasingPressureTest: 03/30/2021at9,825’at1,500psigandchartedfor30minutes. PreͲrigwork: 1. RUSL,Pressuretestlubricatorto250psilow/1,500psihigh 2. Setaplugat±5,550’tokeepdebrisoutoftheESP 3. PullGLVat5,518’forcirculation 4. RDSlickline Procedure: 1. MIRUHAK404 2. CirculatethewellthroughESPGLVtoproduction. a. WorkoverfluidwillbeFIW. b. BOP’swillbeclosedasneededtocirculatethewell. 3. SetBPV,NDtree,NUBOPandtestto250psilow/2,500psihigh. a. Note:NotifyAOGCC48hoursinadvanceoftesttoallowthemtowitnesstest. 4. Monitorwelltoensureitisstatic. 5. UnseathangerandPOOHwith±400’ofESPcompletion 6. InstallESPpacker,XͲnippleandSSSV(seeschematicforspecificdepths) 7. RIHandlandESPwiththebottomoftheassemblyat±8,000’. 8. Setandtestpackerto1,500psichartingfor30minutes 9. RUSlickline a. SetGLVat±5,518’, b. Pulltubingplugat±5,550’ 10. SetBPV,NDBOP,NUtreeandtest. 11. Turnwellovertoproduction. 12. ConductSVStestingperAOGCCregulations. Regards, KarsonKozub 2 Mobile: +1 (907) 570-1801 kkozub@hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address: 3800 Centerpoint Drive, Suite 1400 Stratigraphic Service 6.API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): McArthur River Field / Middle Kenai G & Hemlock Oil Pools 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 11,506'11,337 & 11,409 Casing Collapse Structural Conductor Surface 1,540 psi Intermediate 3,090 psi Production 8,530 psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email:kkozub@hilcorp.com Contact Phone: (907) 777-8434 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Other: Pull / Replace ESP 9,946'11,224'9,701'1,594 psi 9,921'7" Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. 6/1/2021 4-1/2" Daniel E. Marlowe N/A & N/A 10,089 - 11,290 N/A & N/A Tubing Grade:Tubing MD (ft): 8,715 - 9,758 Perforation Depth TVD (ft): 12.6 / L-80 9-5/8"8,450' 2,160' 11,479' Perforation Depth MD (ft): 8,450' 3,352' 2,120' 7,319' 327' 2,160' 26" 13-3/8" 327' TVD Burst 7,861' 11,220 psi Tubing Size: MD 3,090 psi 327' 191-139 50-733-20037-01-00Anchorage, AK 99503 Hilcorp Alaska, LLC Trading Bay Unit G-01RD N/A COMMISSION USE ONLY Authorized Name: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0018730 Authorized Signature: Operations Manager Karson Kozub PRESENT WELL CONDITION SUMMARY Length Size 5,750 psi N/A Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Meredith Guhl at 11:28 am, May 12, 2021 321-236 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.05.12 09:18:16 -08'00' Dan Marlowe (1267) X 10-404 DLB DSR-5/12/21DLB 05/12/2021 ; ADL0017594 X BJM 5/19/21 BOP Test to 2500 psi dts 5/19/2021 JLC 5/20/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.05.20 13:26:10 -08'00' RBDMS HEW 6/2/2021 Well Work Prognosis Well: G-01RD Well Name:G-01RD API Number:50-733-20037-01-00 Current Status:ESP Producer Leg:Leg #2 (NE corner) Estimated Start Date:June 1, 2021 Rig:HAK 404 Reg. Approval Req’d?403 Date Reg. Approval Rec’vd: Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:191-139 First Call Engineer:Karson Kozub (907) 777-8434 (O) (907) 570-1801 (M) Second Call Engineer:Katherine O’Connor (907) 777-8376 (O) (214) 684-7400 (M) Current Bottom Hole Pressure:1,992 psi @ 6,932’ TVD 0.288 psi/ft (5.6 ppg) based on ESP Gauge 5/6/21 Maximum Expected BHP:2,294 psi @ 6,932’ TVD 0.330 psi/ft (6.4 ppg) based on ESP Gauge 4/5/18 Maximum Potential Surface Pressure:1,594 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) Brief Well Summary G-01RD is a G-Zone and Hemlock Producer that was converted to an ESP from a dual string gas-lift completion in October 2012. In March 2021 the ESP was replaced and a cleanout was performed. After the well was brought online the well was no longer able to pass a no flow test. We plan to pull the ESP to install an ESP packer and SSSV per regulations to return the well to production. Last Casing Pressure Test: 03/30/2021 at 9,825’ at 1,500 psig and charted for 30 minutes. Procedure: 1. MIRU HAK 404 2. Circulate the well through ESP to production. a. Work over fluid will be FIW. b. BOP’s will be closed as needed to circulate the well. 3. Set BPV, ND tree, NU BOP and test to 250psi low/2,500psi high. a. 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 ±400’ of ESP completion 6. Install ESP packer and SSSV (see schematic for specific depths) 7. RIH and land ESP with the bottom of the assembly at ± 8,000’. 8. Set and test packer to 1,500psi charting for 30 minutes 9. Set BPV, ND BOP, NU tree and test. 10. Turn well over to production. 11. Conduct SVS testing per AOGCC regulations. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Current Wellhead Diagram 4. Proposed Wellhead Diagram 5. BOP Drawing 6. Fluid/Flow Diagram 7. Choke Diagram 8. Rolling BOP Test Procedures 9. RWO Sundry Change Form Procedure Superseded McArthur River Field, TBU Well: G-01RD As Completed: Future Updated by: JLL 05/14/21 PROPOSED RKB to MLLW ELEV = 103’ TD = 11,506’ PBD = 11,430’ MAX HOLE ANGLE = 39.10q @ 7225’ RKB to TBG Hngr = 42.68’ Tree connection: 3-1/2” EUE 8rd 2 3 5 1 6 4 7 HB-2 G-2 G-3 G-4 G-5 HB-4 HB-5 HB-7 HB-6 4-5/8” Perf Gun @ 11,409’ G-6 G-7 HB-3 26” 13-3/8” 9-5/8” 7” Fish @11337’ G-1 HB-1 TOC 8,127 CBL 2/15 1992 EST TOC 355’ Calc 10/7 1967 X CASING DETAIL Size WT Grade Conn ID MD Top MD Btm 26” Surf. 327’ 13-3/8” 61 J-55 Butt 12.515” Surf. 2,160’ 9-5/8” 47 N-80 Butt 8.681” Surf 79’ 40 N-80 Butt 8.835” 79’ 6,275’ 43.5 N-80 Butt 8.755” 6,275’ 8,179’ 47 N-80 Butt 8.681” 8,179’ 8,450’ (TOW) 9-5/8” DV Collar 4,903’ 4,905’ 7” 29 P-110 Butt 6.184” 8,127’ 11,479’ TUBING DETAIL 4-1/2” 12.6 L-80 IBT 3.958” Surface ±7,861’ 03/29/21: Cleaned out to 11,224’ 12/17/00: Left 10.14’ long fish consisting of coil tubing motor and bit. 10/24/12: Cleaned out fill to 11337’ DPM, Fish not recovered. PERFORATIONS Zone Top MD Btm MD Top TVD Btm TVD Amt SPF Last Opr. Status G-01 10,089’ 10,120’ 8,715’ 8,742’ 31’ 5 01/16/14 Open G-2 10,140' 10,170' 8,759' 8,785' 30' 6 2/19/1992 Open 10,140' 10,170' 8'759' 8,785' 30’ 5 10/27/12 Reperf G-3 10,225' 10,257' 8,833' 8,861' 32' 6 2/19/1992 Open 10,244' 10,264' 8,849' 8,867' 20’ 5 10/27/12 Open G-4 10,278' 10,340' 8,879' 8,933' 62' 6 2/19/1992 Open 10,280' 10,342' 8,881' 8,935' 62’ 5 10/27/12 Open G-5 10,395' 10,415' 8,981' 8,999' 20' 6 2/19/1992 Open 10,398' 10,418' 8,984' 9,001' 20’ 5 10/27/12 Open 10,440' 10,460' 9,021' 9,038' 20’ 5 10/27/12 Open G-6 10,532' 10,548' 9,101' 9,115' 16’ 5 10/27/12 Open G-7 10,600 10,614' 9,161' 9,173' 14’ 5 10/27/12 Open HB-1 10,622’ 10,637’ 9,180' 9,194' 15’ 4 1/17/2001 Open HB-1 10,628' 10,670' 9,186' 9,223' 42' 10 & 16 8/26/1995 Open, frac'd 10,628'- 10,643' 10,628' 10,676' 9,186' 9,228' 48’ 5 10/27/12 Open HB-2 10,689’ 10,718’ 9,240’ 9,265’ 29’ 5 01/16/14 Open HB-3 10,846' 10,860' 9,377' 9,389' 14’ 5 10/27/12 Open HB-4 10,863' 11,000' 9,392' 9,509' 137' 6 2/19/1992 Open 10,939’ 10,954’ 9,457' 9,470' 15’ 4 1/17/2001 Open 10,890' 11,006' 9,415' 9,515' 116’ 5 10/27/12 Open HB-5 11,038’ 11,048’ 9,542' 9,550' 10’ 4 1/17/2001 Open 11,040' 11,070' 9,544' 9,569' 30' 8 8/26/1995 Open 11,042' 11,122' 9,545' 9,614' 80’ 5 10/27/12 Open HB-6 11,155' 11,170' 9,642' 9,655' 15' 4 8/26/1995 Open 11,156' 11,240' 9,643' 9,715' 84’ 5 10/27/12 Open HB-7 11,255' 11,280' 9,728' 9,749' 25' 24 6/24/1994 Open 11,266' 11,290' 9,737' 9,758' 24’ 5 10/27/12 Open Jewelry Details No.Depth MD Depth TVD ID OD Item 42.68’ 42.68’ CIW-DCB-ESP, 11” x 4-1/2” IBT lift and susp, w/4” Type H BPV Profile Hanger 1±375’±375’ SSSV 2 ±400’ ±400’ Packer w/ Vent valve 3 ±430’ ±430’ X Nipple 4 ±2,242’ ±2,190’ 3.992 7.063 GLM#1 5 ±4,168’ ±3,792’ 3.992 7.063 GLM#2 6 ±5,518’ ±4,898’ 3.992 7.063 GLM#3 7 ±7,861’ ±6,816’ -- 5.130 Discharge ±7,863’ ±6,818’ -- 6.750 Pump ±7,906’ ±6,854’ -- 6.750 Intake ±7,908’ ±6,856’ -- 5.130 Seals ±7,930’ ±6,875’ -- 5.620 Motor ±8,000’ ±6,934’ -- 4.500 Centrilizer/Anode McArthur River Field, TBU Well: G-01RD As Completed: 04/03/21 Updated by: JLL 04/18/21 SCHEMATIC RKB to MLLW ELEV = 103’ TD = 11,506’ PBD = 11,430’ MAX HOLE ANGLE = 39.10q @ 7225’ RKB to TBG Hngr = 42.68’ Tree connection: 3-1/2” EUE 8rd 1 3 4 2 HB-2 G-2 G-3 G-4 G-5 HB-4 HB-5 HB-7 HB-6 4-5/8” Perf Gun @ 11,409’ G-6 G-7 HB-3 26” 13-3/8” 9-5/8” 7” Fish @11337’ G-1 HB-1 TOC 8,127 CBL 2/15 1992 EST TOC 355’ Calc 10/7 1967 CASING DETAIL Size WT Grade Conn ID MD Top MD Btm 26” Surf. 327’ 13-3/8” 61 J-55 Butt 12.515” Surf. 2,160’ 9-5/8” 47 N-80 Butt 8.681” Surf 79’ 40 N-80 Butt 8.835” 79’ 6,275’ 43.5 N-80 Butt 8.755” 6,275’ 8,179’ 47 N-80 Butt 8.681” 8,179’ 8,450’ (TOW) 9-5/8” DV Collar 4,903’ 4,905’ 7” 29 P-110 Butt 6.184” 8,127’ 11,479’ TUBING DETAIL 4-1/2” 12.6 L-80 IBT 3.958” Surface 7,861’ 03/29/21: Cleaned out to 11,224’ 12/17/00: Left 10.14’ long fish consisting of coil tubing motor and bit. 10/24/12: Cleaned out fill to 11337’ DPM, Fish not recovered. PERFORATIONS Zone Top MD Btm MD Top TVD Btm TVD Amt SPF Last Opr. Status G-01 10,089’ 10,120’ 8,715’ 8,742’ 31’ 5 01/16/14 Open G-2 10,140' 10,170' 8,759' 8,785' 30' 6 2/19/1992 Open 10,140' 10,170' 8'759' 8,785' 30’ 5 10/27/12 Reperf G-3 10,225' 10,257' 8,833' 8,861' 32' 6 2/19/1992 Open 10,244' 10,264' 8,849' 8,867' 20’ 5 10/27/12 Open G-4 10,278' 10,340' 8,879' 8,933' 62' 6 2/19/1992 Open 10,280' 10,342' 8,881' 8,935' 62’ 5 10/27/12 Open G-5 10,395' 10,415' 8,981' 8,999' 20' 6 2/19/1992 Open 10,398' 10,418' 8,984' 9,001' 20’ 5 10/27/12 Open 10,440' 10,460' 9,021' 9,038' 20’ 5 10/27/12 Open G-6 10,532' 10,548' 9,101' 9,115' 16’ 5 10/27/12 Open G-7 10,600 10,614' 9,161' 9,173' 14’ 5 10/27/12 Open HB-1 10,622’ 10,637’ 9,180' 9,194' 15’ 4 1/17/2001 Open HB-1 10,628' 10,670' 9,186' 9,223' 42' 10 & 16 8/26/1995 Open, frac'd 10,628'- 10,643' 10,628' 10,676' 9,186' 9,228' 48’ 5 10/27/12 Open HB-2 10,689’ 10,718’ 9,240’ 9,265’ 29’ 5 01/16/14 Open HB-3 10,846' 10,860' 9,377' 9,389' 14’ 5 10/27/12 Open HB-4 10,863' 11,000' 9,392' 9,509' 137' 6 2/19/1992 Open 10,939’ 10,954’ 9,457' 9,470' 15’ 4 1/17/2001 Open 10,890' 11,006' 9,415' 9,515' 116’ 5 10/27/12 Open HB-5 11,038’ 11,048’ 9,542' 9,550' 10’ 4 1/17/2001 Open 11,040' 11,070' 9,544' 9,569' 30' 8 8/26/1995 Open 11,042' 11,122' 9,545' 9,614' 80’ 5 10/27/12 Open HB-6 11,155' 11,170' 9,642' 9,655' 15' 4 8/26/1995 Open 11,156' 11,240' 9,643' 9,715' 84’ 5 10/27/12 Open HB-7 11,255' 11,280' 9,728' 9,749' 25' 24 6/24/1994 Open 11,266' 11,290' 9,737' 9,758' 24’ 5 10/27/12 Open Jewelry Details No.Depth MD Depth TVD ID OD Item 42.68’ 42.68’ CIW-DCB-ESP, 11” x 4-1/2” BTC lift and susp, w/4” Type H BPV Profile Hanger 1 2,242’ 2,190’ 3.992 7.063 GLM#1 - SPM 1 1/2" GLV IPOR-2 Port Size 24 w/Dummy 2 4,168’ 3,792’ 3.992 7.063 GLM#2 - SPM 1 1/2" GLV IPOR-2 Port Size 24 w/Dummy 3 5,518’ 4,898’ 3.992 7.063 GLM#3 - SPM 1 1/2" GLV IPOR-2 Port Size 24 w/Dummy 4 7,861’ 6,816’ -- 5.130 Discharge- BTN, 4 1/2", 8RD EUE, 416/420SS, 675X PN:900031005 7,863’ 6,818’ -- 6.750 Pump- 675 Series, SH13000CCW, 45S, INC, 15, 1:1 XRO, 316 PN: 103000698 (x2) 7,906’ 6,854’ -- 6.750 Intake- 675-513X, S/A, AR, X2, INC, 416SS P/N:900600078 7,908’ 6,856’ -- 5.130 Seals (Upper and Lower) 513 Series, BPBSBPB 7,930’ 6,875’ -- 5.620 562 MOTOR KMS2, LT, 500HP, 1800V, 171A (x2) 7,997’ 6,932’ -- 4.500 Centrilizer/Anode McArthur River Field, TBU Well: G-01RD As Completed: Future Updated by: JLL 05/06/21 PROPOSED RKB to MLLW ELEV = 103’ TD = 11,506’ PBD = 11,430’ MAX HOLE ANGLE = 39.10q @ 7225’ RKB to TBG Hngr = 42.68’ Tree connection: 3-1/2” EUE 8rd 2 3 5 1 6 4 HB-2 G-2 G-3 G-4 G-5 HB-4 HB-5 HB-7 HB-6 4-5/8” Perf Gun @ 11,409’ G-6 G-7 HB-3 26” 13-3/8” 9-5/8” 7” Fish @11337’ G-1 HB-1 TOC 8,127 CBL 2/15 1992 EST TOC 355’ Calc 10/7 1967 CASING DETAIL Size WT Grade Conn ID MD Top MD Btm 26” Surf. 327’ 13-3/8” 61 J-55 Butt 12.515” Surf. 2,160’ 9-5/8” 47 N-80 Butt 8.681” Surf 79’ 40 N-80 Butt 8.835” 79’ 6,275’ 43.5 N-80 Butt 8.755” 6,275’ 8,179’ 47 N-80 Butt 8.681” 8,179’ 8,450’ (TOW) 9-5/8” DV Collar 4,903’ 4,905’ 7” 29 P-110 Butt 6.184” 8,127’ 11,479’ TUBING DETAIL 4-1/2” 12.6 L-80 IBT 3.958” Surface ±7,861’ 03/29/21: Cleaned out to 11,224’ 12/17/00: Left 10.14’ long fish consisting of coil tubing motor and bit. 10/24/12: Cleaned out fill to 11337’ DPM, Fish not recovered. PERFORATIONS Zone Top MD Btm MD Top TVD Btm TVD Amt SPF Last Opr. Status G-01 10,089’ 10,120’ 8,715’ 8,742’ 31’ 5 01/16/14 Open G-2 10,140' 10,170' 8,759' 8,785' 30' 6 2/19/1992 Open 10,140' 10,170' 8'759' 8,785' 30’ 5 10/27/12 Reperf G-3 10,225' 10,257' 8,833' 8,861' 32' 6 2/19/1992 Open 10,244' 10,264' 8,849' 8,867' 20’ 5 10/27/12 Open G-4 10,278' 10,340' 8,879' 8,933' 62' 6 2/19/1992 Open 10,280' 10,342' 8,881' 8,935' 62’ 5 10/27/12 Open G-5 10,395' 10,415' 8,981' 8,999' 20' 6 2/19/1992 Open 10,398' 10,418' 8,984' 9,001' 20’ 5 10/27/12 Open 10,440' 10,460' 9,021' 9,038' 20’ 5 10/27/12 Open G-6 10,532' 10,548' 9,101' 9,115' 16’ 5 10/27/12 Open G-7 10,600 10,614' 9,161' 9,173' 14’ 5 10/27/12 Open HB-1 10,622’ 10,637’ 9,180' 9,194' 15’ 4 1/17/2001 Open HB-1 10,628' 10,670' 9,186' 9,223' 42' 10 & 16 8/26/1995 Open, frac'd 10,628'- 10,643' 10,628' 10,676' 9,186' 9,228' 48’ 5 10/27/12 Open HB-2 10,689’ 10,718’ 9,240’ 9,265’ 29’ 5 01/16/14 Open HB-3 10,846' 10,860' 9,377' 9,389' 14’ 5 10/27/12 Open HB-4 10,863' 11,000' 9,392' 9,509' 137' 6 2/19/1992 Open 10,939’ 10,954’ 9,457' 9,470' 15’ 4 1/17/2001 Open 10,890' 11,006' 9,415' 9,515' 116’ 5 10/27/12 Open HB-5 11,038’ 11,048’ 9,542' 9,550' 10’ 4 1/17/2001 Open 11,040' 11,070' 9,544' 9,569' 30' 8 8/26/1995 Open 11,042' 11,122' 9,545' 9,614' 80’ 5 10/27/12 Open HB-6 11,155' 11,170' 9,642' 9,655' 15' 4 8/26/1995 Open 11,156' 11,240' 9,643' 9,715' 84’ 5 10/27/12 Open HB-7 11,255' 11,280' 9,728' 9,749' 25' 24 6/24/1994 Open 11,266' 11,290' 9,737' 9,758' 24’ 5 10/27/12 Open Jewelry Details No.Depth MD Depth TVD ID OD Item 42.68’ 42.68’ CIW-DCB-ESP, 11” x 4-1/2” IBTlift and susp, w/4” Type H BPV Profile Hanger 1 ±375’ ±375’ SSSV 2 ±400’ ±400’ Packer w/ Vent valve 3 ±2,242’ ±2,190’ 3.992 7.063 GLM#1 4 ±4,168’ ±3,792’ 3.992 7.063 GLM#2 5 ±5,518’ ±4,898’ 3.992 7.063 GLM#3 6 ±7,861’ ±6,816’ -- 5.130 Discharge ±7,863’ ±6,818’ -- 6.750 Pump ±7,906’ ±6,854’ -- 6.750 Intake ±7,908’ ±6,856’ -- 5.130 Seals ±7,930’ ±6,875’ -- 5.620 Motor ±8,000’ ±6,934’ -- 4.500 Centrilizer/Anode Superseded Grayling Platform G-01rd Current 03/04/2016 Tubing head, CIW-DCB, 13 5/8 3M X 11 5M w/ 2- 2 1/16 5M SSO, X bottom Grayling Platform G-1rd 13 3/8 X 9 5/8 X 4 1/2 Valve, WKM-M, 2 1/16 5M FE, HWO, DD Qty 2 Adapter, CIW-Toadstool, 11 5M Stdd X 4 1/16 5M FE, prepped for 5 ¼ EN neck, 3- ½ npt continuous control line ports, BIW penetrator port Tubing hanger, CIW-DCB-ESP, 11 X 4 ½ BTC lift and susp, w/ 4'’ type H BPV profile, 5 ¼ EN, 2- continuous control line ports, prepped for BIW penetrator Valve, swab, WKM-M, 4 1/16 5M FE, HWO, T-24 Valve, lower master, WKM-M, 4 1/16 5M FE, HWO, T-24 BHTA, CIW, 4 1/16 5M FE X Cameron internal blanking nut Cross, stdd, 4 1/16 5M X 3 1/8 5M X 2 1/16 5M Valve, wing, WKM-M, 2 1/16 5M FE, HWO, T-24 Valve, WKM-M, 3 1/8 5M FE, w/ MA-16 operator Casing head, Shaffer KD, 13 5/8 3M X 13 3/8 SOW, w/ 2- 2'’ LPO,2'’LP CIW ball valve Grayling Platform G-01rd Proposed 05/10/2016 Tubing head, CIW-DCB, 13 5/8 3M X 11 5M w/ 2- 2 1/16 5M SSO, X bottom Grayling Platform G-1rd 13 3/8 X 9 5/8 X 4 1/2 Valve, WKM-M, 2 1/16 5M FE, HWO, DD Qty 2 Adapter, CIW-Toadstool, 11 5M Stdd X 4 1/16 5M FE, prepped for 5 ¼ EN neck, 4- ½ npt continuous control line ports, BIW penetrator port Tubing hanger, CIW-DCB-ESP, 11 X 4 ½ IBT lift and susp, w/ 4'’ type H BPV profile, 5 ¼ EN, 4- continuous control line ports, prepped for BIW penetrator Valve, swab, WKM-M, 4 1/16 5M FE, HWO, T-24 Valve, lower master, WKM-M, 4 1/16 5M FE, HWO, T-24 BHTA, CIW, 4 1/16 5M FE X Cameron internal blanking nut Cross, stdd, 4 1/16 5M X 3 1/8 5M X 2 1/16 5M Valve, wing, WKM-M, 2 1/16 5M FE, HWO, T-24 Valve, WKM-M, 3 1/8 5M FE, w/ MA-16 operator Casing head, Shaffer KD, 13 5/8 3M X 13 3/8 SOW, w/ 2- 2'’ LPO,2'’LP CIW ball valve Grayling Platform BOP Stack HAK 404 HILCORP ALASKA, LLC SwacoSuperchokeBlooey LineTo Gas BusterInlet Rig 404 BOP Test Procedure Attachment #1 Attachment #1 Hilcorp Alaska, LLC - BOP Test Procedure: Rig 404, WO Program – Oil Producers, Gas Producers, Water Injectors Pre Rig Move 1) Blow down well, bleed gas to Well Clean Tank that is vented thru flare to atmosphere 2) Load well with kill weight fluid. x Note: Fluid level will fall to a depth that balances with reservoir pressure. x Shoot fluid levels as needed. 3) Confirm that well is static. Initial Test (i.e. Tubing Hanger is in the Wellhead) If BPV profile is good 1) Set BPV. ND Tree. NU BOP. 2) MU landing joint. Pull BPV. Set 2-way check in hanger. 3) Space out test joint so end of tubing (EOT) is just above the blind rams. 4) Set slips, mark same. Test BOPE per standard test procedure. If the tubing hanger won’t pressure test due to either a penetrator leak or the BPV profile is eroded and/or corroded and BPV cannot be set with tree on. Profile and/or landing threads must be prepped while tree is off. Worst Case: BPV profile and landing threads are bad. 1) Attempt to set BPV through tree. If unsuccessful, shoot fluid level. 2) If fluid level is static from previous fluid level shots, notify Hilcorp Anchorage office that the well is static and the tree must be removed with no BPV. As approved in the sundry, proceed as follows: a) Fill well with KWF if the fluid is not to surface b) ND tree with no BPV Inspect and prepare BPV profile to accept a 2-way valve, or prepare lift-threads to accept landing joint to hold pressure. If well is a producer and the culprit is scale, attempt to clean profile with Muriatic acid and a wire brush or wheel. c) Set 2-way check valve by hand, or MU landing (test) joint to lift-threads d) For ESP wells - Ensure that cap is on cable penetrator e) NU BOP. Test BOPE per standard procedure. 3) If both set of threads appear to be bad and unable to hold a pressure test and / or a penetrator leaks, notify Operations Engineer (Hilcorp), Mr. Bryan McLellan (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness. As outlined and approved in the sundry, proceed as follows: a) Nipple Up BOPE b) With stack out of the test path, test choke manifold per standard procedure c) Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down-hole and not leaking anywhere at surface.) d) Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e) Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) Rig 404 BOP Test Procedure Attachment #1 f) Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn’t hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 4) Pull hanger to surface. (Requires tubing cuts as necessary to free tubing). CBU to displace annulus and tubing with kill weight fluid. 5) If a rolling test was conducted, remove the old hanger, MU new hanger or test plug to the completion tubing. Re-land hanger (or test plug) in tubing head. Test BOPE per standard procedure. Subsequent Tests (i.e. Test Plug can be set in the Tubing-head) 1) Remove wear bushing. a) Use inverted test plug to pull wear busing. MU to joint of tubing. b) Thread into wear bushing c) Back out hold down pins d) Pull and retrieve wear bushing. 2) Break off test plug and invert same- RIH with test plug on joint of tubing. Install a pump-in sub w/ test line plus an open TIW or lower Kelly valve in top of test joint w/ open IBOP. 3) Test BOPE per standard procedure. STANDARD BOPE TEST PROCEDURE (after 2-way check or test plug is set) 1) Fill stack and all lines with rig pump- install chart recorder on test line connected to pump-in sub below safety valve and IBOP in test joint assembly. 2) Note: When testing, pressure up with pump to desired pressure, close valve on pump manifold to trap pressure and read same with chart recorder (test pressures will be indicated in Sundry). 3) Referencing the attached schematics test rams and valves as follows. a) Close 1 st valve on standpipe manifold (PM1), close valves 8,10 &11 on choke manifold and close the annular preventer, open safety valve on top of test jt and close IBOP. Pressure test to 250 psi for 5 minutes and xxx psi (see sundry) high for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank and open annular. b) Close pipe rams and open annular preventer, close safety valve and open IBOP on test joint, close outside valve on kill side of mud cross (K2), open PM1, close valves 5,7 & 9 on choke manifold, open valve 10 on choke manifold. Test to 250 psi for 5 minutes and xxx psi (see sundry) high for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. c) Test Dual Rams. If the well has dual tubing, and dual rams are installed in the stack, test the dual rams by picking up two test joints with dual elevators and lowering them into stack and position them properly in the dual rams. Close rams. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. d) Close manual and super choke / open valves 7 & 9 on choke manifold. Bleed pressure from step b or c recording change and stabilization. If passes after 5 minutes, bleed off pressure back to tank. e) Close inside valve (K1) / open outside valve on kill side of mud cross (K2), close valves 2,4 & 6 / open valves 5,7 & 9 on choke manifold. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. f) Close valves 1 & 3 / open valves 4 & 6 on choke manifold. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. Rig 404 BOP Test Procedure Attachment #1 g) Close HCR (CL2) open valves 2,4 & 6 on choke manifold. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. h) Close inside valve (CL1) / open outside valve (HCR) on choke side of mud cross. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. i) Ensure all pressure is bled off- open pipe rams and pull test joint leaving test plug / 2-way check in place. Close blind rams and attach test line to valve 11 on choke manifold, close valve 1,2 & 3 / open valve 11 on choke manifold. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. j) Test additional floor valves (TIW or Lower Kelly Valve) and IBOPs as necessary. STANDARD TEST PROCEDURE OF CLOSING UNIT (ACCUMULATOR) 1) This is a test of stored energy. Shut off all power to electric and pneumatic pumps. 2) Record “Accumulator Pressure”. It should be +/- 3,000 psi. 3) Close Annular Preventer, the Pipe Rams, and HCR. Close 2 nd set of pipe rams if installed (e.g. dual pipe rams). Open the lower pipe rams to simulate the closing volume on the blinds. 4) Allow pressures to stabilize. 5) While stabilizing: Record pressure values of each Nitrogen bottle and average over the number of bottles. (i.e. Report might read “10 bottles at 2,150 psi”). 6) After accumulator has stabilized, record accumulator pressure again. This represents the pressure and volume remaining after all preventers are closed. (The stabilized pressure must be at least 200 psi above the pre- charge pressure of 1,000 psi). 7) Turn on the electric pump and record the amount of time it takes to build an additional 200 psi on the accumulator gauge. This is usually +/- 30 seconds. 8) Once 200 psi pressure build is reached, turn on the pneumatic pumps and record the time it takes for the pumps to automatically shut-off after the pressure to builds back to original pressure (+/- 3,000 psi). Note: Make sure the electric pump is turned to “Auto”, not “Manual” so the pumps will kick-off automatically. 9) Open all rams and annular and close HCR to place BOPE back into operating position for well work. 10) Fill out AOGCC report. FINAL STEP, FINAL CHECK 1) Test Gas Alarms 2) Double check all rams and valves, for correct operating position 3) Fill out the AOGCC BOPE Test Form (10-424) in Excel Format. Document both the rolling test and the follow up tests. Hilcorp Alaska, LLCHilcorp Alaska, LLCChanges to Approved Rig Work Over Sundry ProcedureSubject: Changes to Approved Sundry Procedure for Well G-01RD (PTD 191-139)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 (P G-O(.erb Pi -t 1C11139O Regg, James B (CED) From: Regg, James B (CED) I�� 15/7( -7-6r,74Sent: Friday, May 7, 2021 11:34 AM<i To: Julie Wellman - (C) Subject: RE: Grayling G-01 Temporary 30 -Day Flow Under Man -Watch TBU G-01RD PTD 1911390 Failed No -Flow Tests 4/17/2021, 5/1/2021 Before AOGCC can make a decision regarding this request Hilcorp must provide a written analysis with supporting data showing why Hilcorp thinks this is near -bore charging, including but not limited to: - Comparison of G-01RD performance to other completions in same producing zone - Evidence of fluid loss during workover (volume, type) # days produced since well was put on production following workover - Volumes produced since workover (oil, gas, water, other) - Current GOR - Rig 404 schedule This information request is in accordance with 20 AAC 25.300 and is due not later than May 14. Jim Regg Supervisor, Inspections AOGCC 333 W. 7'h Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Julie Wellman - (C) <Julie.Wellman@hilcorp.com> Sent: Thursday, May 6, 20212:02 PM To: Regg, James B (CED) <jim.regg@alaska.gov> Subject: Grayling G-01 Temporary 30 -Day Flow Under Man -Watch Hello Jim, Per our conversation this afternoon, Hilcorp may flow Grayling G-01 with a 24 hour man watch per 20 AAC 25.265(j)(2) for a temporary approval period of 30 days, at which point we will re -attempt the no flow test and revisit the temporary approval with you as needed. Meanwhile, we will begin on a workover program to install a packer and SSSV for when we can fit it into this season's rig program if it is needed. G-01 has traditionally passed a no flow test, and we did not shoot any new zones. We did, however, uncover some perfs during a cleanout that haven't flowed in some time. We believe that between the lack of recent production and the over 3000 bbl of losses during the workover, that there is near -wellbore charging around these newly uncovered perfs that will resolve as the well produces and returns to steady state. Thank you for your consideration, Julie Wellman Regulatory Tech — Hilcorp Alaska, LLC o: 777-8505 1 c: 360-265-4397 hdie.WellmanGihdcot ccom The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. THE STATE May 3, 2021 ALASKA GOVERNOR MIKE DUNLL'AVY Mr. Dan Marlowe Operations Manager — CI Offshore Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 RE: No -Flow Verification Trading Bay Unit G-01 RD PTD 1911390 Dear Mr. Marlowe: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov On May 1, 2021 an Alaska Oil and Gas Conservation Commission (AOGCC) Petroleum Inspector witnessed a second no -flow test of Trading Bay Unit G-01RD located on the Grayling Platform in Cook Inlet. The previous test was unsuccessful in demonstrating a gas flow rate below the allowed limit. Refer to my April 21, 2021 letter. For this subsequent test the AOGCC Inspector confirmed that the proper test equipment — as outlined in AOGCC Industry Guidance Bulletin 10-004 — was rigged up on Trading Bay Unit G- 01RD. The well performance was monitored for approximately 3 hours consisting of 1 -hour pressure build up periods followed by 30 -minute (minimum) flow monitoring checks. There was no liquid flow to surface during the no -flow test, however, gas flow rates exceeded the allowed limit. The results witnessed by AOGCC on May 1, 2021 indicate a failed no -flow test. Trading Bay Unit G-01RD must be equipped with a fail-safe automatic safety valve system capable of preventing uncontrolled flow — including a surface controlled subsurface safety valve or AOGCC-approved alternate — as required in 20 AAC 25.265. Please retain a copy of this letter on the Grayling Platform. Sincerely, James B. Regg ';,e "ego o"''27as-09 James B. Regg Petroleum Inspection Supervisor ecc: P. Brooks AOGCC Inspectors MEMORANDUM TO: FROM Jim Regg 1 5131Z94 P. I. Supervisor l Adam Earl Petroleum Inspector State of Alaska Alaska Oil and Gas Conservation Commission � • 1_�'S�B3►�ii►�il SUBJECT: No Flow Test TBU G-01 RD Hilcorp Alaska LLC PTD 1911390 - 5-01-2021: 1 traveled out to Grayling Platform to witness a second attempt at a No -Flow test on G-01 RD. I verified calibration on the test gauges. The well was rigged up with 1 - inch bleed lines to an Armor -Flow SCF/H meter, then out to a deck tank. The fluid level was estimated @1800 feet (fluid level shot). The following table shows test details: Time Pressures' (psi) Flow Rate Gas - scf/hr Liquid - al/hr Remarks 1345 Shut in for test 1400 3.05 / 3.05 / 23 Shut in 1415 5.08 / 5.08 / 23 Shut in 1430 6.92 / 6.92 / 23 Shut in 1445 8.52 / 8.52 / 23 1800 0 Oen to flow; meter max'd out 1450 4.51 / 4.51 / 23 1800 0 Meter max'd out 1555 2.55 / 2.55 / 23 1800 0 Meter max'd out 1500 1.47 / 1.47 / 23 1800 0 Meter max'd out 1505 0.95 / 0.95 / 23 1800 - 0 Meter max'd out 1510 0.76 / 0.76 / 23 1750 0 1515 0.71 / 0.71 / 23 1750 0 Shut in for pressure build 1530 4.46 / 4.46 / 23 Shut in 1545 7.21 / 7.21 / 23 Shut in 1600 9.19 / 9.19 / 23 Shut in 1615 10.5 / 10.5 / 23 1800 - 0 Oen to flow; meter max's out 1620 5.25 / 5.35 / 23 1800 - 0 Meter max'd out 1625 3.28 / 3.28 / 23 1800 0 Meter max'd out 1630 2.04 / 2.04 / 23 1800 0 Meter max'd out 1635 1.33 / 1.33 / 23 1800 0 Meter max'd out 1640 1.0/1.0/23 1800 0 Meter max'd out 1645 0.9/0.9/23 1800 0 Meter max'd out 1700 0.8/0.8123 1750 0 End test ' Pressures are T/IA/OA 2 Gas flow not to exceed 900 scf/hr; Liquid flow not to exceed 6.3 gal/hr 2021-0501 No-Flow_TBU_G-01R13ae.doex Pagel of 2 The gas flow rate remained at or above the 1800 scf/h max meter reading during the flow periods until the pressure declined to 0.88 psi (where there was an indication of the gauge needle movement). The high volume, low pressure signature was very repeatable and predictable. It was decided to suspend the test after second flow period — deemed a test failure. Looks like some steady formation gas here. Attachments: none 2021-0501 No-Flow_TBU_G-01 RD ae.docx Page 2 of 2 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg f�N DATE: 5-03-2021 P. I. Supervisor FROM: Adam Earl SUBJECT: No Flow Test Petroleum Inspector TBU G-01 RD - Hilcorp Alaska LLC PTD 1911390 - 5-01-2021: 1 traveled out to Grayling Platform to witness a second attempt at a No -Flow test on G-01 RD. I verified calibration on the test gauges. The well was rigged up with f - inch bleed lines to an Armor -Flow SCF/H meter, then out to a deck tank. The fluid level ✓ was estimated @1800 feet (fluid level shot). Tha fnlln\A/Inn fnhIA chn"m tact riatailC' Time Pressures' (psi)Gas Flow Rate' - scf/hr Liquid - al/hr Remarks 1345 Shut in for test 1400 3.05 / 3.05 / 23 Shut in 1415 5.08 / 5.08 / 23 Shut in 1430 6.92 / 6.92 / 23 Shut in 1445 8.52 / 8.52 / 23 1800 0 Oen to flow; meter max'd out 1450 4.51 / 4.51 / 23 1800 0 Meter max'd out 1555 2.55 / 2.55 / 23 1800 0 Meter max'd out ' 1500 1.47 11.47 / 23 1800 - 0 Meter max'd out - 1505 0.95 / 0.95 / 23 1800 0 Meter max'd out ' 1510 0.76 / 0.76 / 23 1750 0 1515 0.71 / 0.71 / 23 1750 0 Shut in for pressure build ' 1530 4.46 / 4.46 / 23 Shut in 1545 7.21 / 7.21 / 23 Shut in 1600 9.19 / 9.19 / 23 Shut in 1615 10.5 / 10.5 / 23 1800 0 Oen to flow; meter max's out 1620 5.25 / 5.35 / 23 1800 0 Meter max'd out - 1625 3.28 / 3.28 / 23 1800 0 Meter max'd out - 1630 2.04 / 2.04 / 23 1800 0 Meter max'd out - 1635 1.33 / 1.33 / 23 1800 0 Meter max'd out - 1640 1.0/1.0/23 1800 0 Meter max'd out - 1645 0.9/0.9/23 1800 0 Meter max'd out 1700 0.8/0.8/23 1750 0 End test Pressures are T/IA/OA 2 Gas flow not to exceed 900 scf/hr; Liquid flow not to exceed 6.3 gal/hr 2021-0501 No-Flow_TBU_G-01 RD ae.docx Pagel of 2 The gas flow rate remained at or above the 1800 scf/h max meter reading during the ✓ flow periods until the pressure declined to 0.88 psi (where there was an indication of the gauge needle movement). The high volume, low pressure signature was very repeatable and predictable. It was decided to suspend the test after second flow period ✓ — deemed a test failure. Looks like some steady formation gas here. Attachments: none 2021-0501_No-Flow_TBU_G-Ol RD_ae.docx Page 2 of 2 THE STATE °fALASKA April 21, 2021 GOVERNOR MIKE DUNLEA\'Y Mr. Dan Marlowe Operations Manager — CI Offshore Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 RE: No -Flow Verification Trading Bay Unit G-01 RD PTD 1911390 Dear Mr. Marlowe: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaska.gov On April 17, 2021 an Alaska Oil and Gas Conservation Commission (AOGCC) Petroleum Inspector witnessed a no -flow test of Trading Bay Unit G-01RD located on the Grayling Platform in Cook Inlet. The well is operated by Hilcorp Alaska, LLC (Hilcorp). The AOGCC Inspector confirmed that the proper test equipment — as outlined in AOGCC Industry Guidance Bulletin 10- 004 — was rigged up on Trading Bay Unit G-01RD prior to the test. The well performance was monitored for approximately 3 hours consisting of flow rate checks each preceded by 1 -hour pressure build up periods. There was no liquid flow to surface during the no -flow test, however, gas flow rates exceeded the allowed limit. The results witnessed by AOGCC on April 17, 2021 indicate a failed no -flow test. Within 14 days, Trading Bay Unit G-01RD must be either retested or equipped with a fail-safe automatic safety valve system capable of preventing uncontrolled flow — including a surface controlled subsurface safety valve or AOGCC-approved alternate — as required in 20 AAC 25.265. A subsequent failure of the no -flow test will result in shutting in the well until an approved subsurface safety valve can be installed and successfully tested. Please retain a copy of this letter on the Grayling Platform. Sincerely, James B. Reggligilily signed Datea2021.04.20616:3457James-N'00' James B. Regg Petroleum Inspection Supervisor ecc: P. Brooks AOGCC Inspectors MEMORANDUM TO: Jim Regg P. I. Supervisor FROM: Adam Earl Petroleum Inspector State of Alaska Alaska Oil and Gas Conservation Commission ��L��Zcrcl DATE: 4-18-2021 SUBJECT: No Flow Test TBU G-01 RD Hilcorp Alaska LLC PTD 1911390 - 4-17-2021: 1 traveled out to the Trading Bay Unit Grayling Platform to witness a No - Flow test on well G-01 RD. I was told the well had been open to bleed for nearly four days. Mike Abbot and Aaron D. were the Hilcorp representatives on the job. The well v seemed to be out of balance and didn't act normal. Test results table shows how the test proceeded and why I did not pass it. The well gas flow rate was clearly over the allowed limit of 900 scf/hr, appearing to exceed the meter's maximum measurement range. The tubing and inner annulus were tied together at surface and able to be isolated with ball valves. The followina table shows test details: Time Pressures' Flow Rate' Remarks (psi) Gas — scf/hr Liquid — al/hr 1230 0.2/0.2/20 Shut well in for test 1330 6/6/20 >1800 none Opened to flow; 5 -minute monitoring period; pressure decline from 6 psi to 2.2 psi. Flow meter upper limit exceeded for entire 5 -minute monitoring period. 1430 2.3/3.5/20 >1800 to none Opened to flow; 5 -minute whisper monitoring period; pressure decline from 2.5 psi - whisper 1530 11/13.2/20 >1800 - none Opened to flow; 5 -minute monitoring period; pressure decline from 13 psi to 7 psi. Flow meter upper limit exceeded for entire 5 -minute monitoring eriod. ' Pressures are T/IA/OA ' Gas flow not to exceed 900 scf/hr; Liquid flow not to exceed 6.3 gal/hr Attachments: Photo 2021-0417_No-Flow_TBU G-O1RD_ae.doex Page 1 of 2 No Flow Test — TBU G-01 RD (PTD 1911390) Photo by AOGCC Inspector A. Earl 4/17/2021 Flow meter at max limit: 2021-0417_No-Flow_TBU G-O1RD_ae.docx Page 2 of 2 1.Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address: 3800 Centerpoint Drive, Suite 1400 Stratigraphic Service 6.API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): McArthur River Field / Middle Kenai G & Hemlock Oil Pools 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 11,506'11,337 & 11,409 Casing Collapse Structural Conductor Surface 1,540 psi Intermediate 3,090 psi Production 8,530 psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email:kkozub@hilcorp.com Contact Phone: (907) 777-8434 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Authorized Signature: Operations Manager Karson Kozub PRESENT WELL CONDITION SUMMARY Length Size 5,750 psi N/A COMMISSION USE ONLY Authorized Name: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0018730 191-139 50-733-20037-01-00Anchorage, AK 99503 Hilcorp Alaska, LLC Trading Bay Unit G-01RD N/A TVD Burst 7,872' 11,220 psi Tubing Size: MD 3,090 psi 327' 2,120' 7,319' 327' 2,160' 26" 13-3/8" 327' 9-5/8"8,450' 2,160' 11,479' Perforation Depth MD (ft): 8,450' 10,089 - 11,290 3,352' N/A & N/A Tubing Grade:Tubing MD (ft): 8,715 - 9,758 Perforation Depth TVD (ft): Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. 3/1/2021 4-1/2" Daniel E. Marlowe N/A & N/A 12.6 / L-80 Other: Pull / Replace ESP 9,946'11,294'9,761'1,594 psi 9,921'7" Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 11:50 am, Jan 26, 2021 321-052 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.01.26 09:31:03 -09'00' Dan Marlowe (1267) X gls 2/1/21 10-404 404 X DLB 01/26/2021 Pull / Replace ESP DSR-1/27/21 OIL * 2500 psi BOPE test * No flow test required post RWO * MIT casing 1500 psi 30 min Comm. n Required? Yes 2/2/21 dts 2/2/2021 JLC 2/2/2021 RBDMS HEW 2/3/2021 Well Work Prognosis Well: G-01RD Date: 01/25/2021 Well Name:G-01RD API Number:50-733-20037-01 Current Status:ESP Producer Leg:Leg #2 (NE corner) Estimated Start Date:March 1, 2021 Rig:HAK 404 Reg. Approval Req’d?403 Date Reg. Approval Rec’vd: Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:191-139 First Call Engineer:Karson Kozub (907) 777-8434 (O) (907) 570-1801 (M) Second Call Engineer:Katherine O’Connor (907) 777-8376 (O) (214) 684-7400 (M) Current Bottom Hole Pressure:2,294 psi @ 6,932’ TVD 0.330 psi/ft (6.4 ppg) based on ESP Gauge 4/5/18 Maximum Expected BHP:2,294 psi @ 6,932’ TVD 0.330 psi/ft (6.4 ppg) based on ESP Gauge 4/5/18 Maximum Potential Surface Pressure:1,594 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) *** This is a no flow well 04/19/2018 Brief Well Summary G-01RD is a G-Zone and Hemlock Producer that was converted to an ESP from a dual string gas-lift completion in October 2012. The ESP was last replaced in April 2018. The current ESP is experiencing down-hole pump issues with productivity falling off. We plan to pull the current ESP completion and replace it with new ESP equipment. Last Casing Pressure Test: 10/24/2012 at 9,850’ at 1,500 psig and charted for 30 minutes. (New test to be done on step 7 below) Procedure: 1. MIRU HAK 404 2. Circulate the well through ESP to production. a. Work over fluid will be FIW. b. BOP’s will be closed as needed to circulate the well. 3. Set BPV, ND tree, NU BOP and test to 250psi low/2,500psi high. a. 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 with cleanout assembly, Circulate bottoms up, POOH. 7. RIH with retrievable packer, set at ± 9,850’ and pressure test casing to 1,500psi for 30min charted, POOH 8. PU, RIH with ESP/Gas-lift Combo completion. 9. Land ESP with the bottom of the assembly at ± 8,000’. 10. ND BOP, NU wellhead and test. 11. Turn well over to production. 12. Conduct SVS testing per AOGCC regulations. 13. Conduct No-flow test per AOGCC regulations due to cleanout Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Current / Proposed Wellhead Diagram (Same) 4. BOP Drawing 5. Fluid/Flow Diagrams 6. Rolling BOP Test Procedures 7. RWO Sundry Change Form MIT casing 7" No-Flow (BHP = 6.4 ppg) McArthur River Field, TBU Well: G-01RD As Completed: 04/08/18 Updated by: JLL 04/30/18 SCHEMATIC RKB to MLLW ELEV = 103’ TD = 11,506’ PBD = 11,430’ MAX HOLE ANGLE = 39.10q @ 7225’ RKB to TBG Hngr = 42.68’ Tree connection: 3-1/2” EUE 8rd 1 3 4 2 HB-2 G-2 G-3 G-4 G-5 HB-4 HB-5 HB-7 HB-6 4-5/8” Perf Gun @ 11,409’ G-6 G-7 HB-3 26” 13-3/8” 9-5/8” 7” Fish @11337’ G-1 HB-1 TOC 8,127 CBL 2/15 1992 EST TOC 355’ Calc 10/7 1967 CASING DETAIL Size WT Grade Conn ID MD Top MD Btm 26” Surf. 327’ 13-3/8” 61 J-55 Butt 12.515” Surf. 2,160’ 9-5/8” 47 N-80 Butt 8.681” Surf 79’ 40 N-80 Butt 8.835” 79’ 6,275’ 43.5 N-80 Butt 8.755” 6,275’ 8,179’ 47 N-80 Butt 8.681” 8,179’ 8,450’ (TOW) 9-5/8” DV Collar 4,903’ 4,905’ 7” 29 P-110 Butt 6.184” 8,127’ 11,479’ TUBING DETAIL 4-1/2” 12.6 L-80 IBT 3.958” Surface 7,872’ 12/17/00: Left 10.14’ long fish consisting of coil tubing motor and bit. 10/24/12: Cleaned out fill to 11337’ DPM, Fish not recovered. 04/04/18: Cleaned out fill to 11,294’ PERFORATIONS Zone Top MD Btm MD Top TVD Btm TVD Amt SPF Last Opr. Status G-01 10,089’ 10,120’ 8,715’ 8,742’ 31’ 5 01/16/14 Open G-2 10,140' 10,170' 8,759' 8,785' 30' 6 2/19/1992 Open 10,140' 10,170' 8'759' 8,785' 30’ 5 10/27/12 Reperf G-3 10,225' 10,257' 8,833' 8,861' 32' 6 2/19/1992 Open 10,244' 10,264' 8,849' 8,867' 20’ 5 10/27/12 Open G-4 10,278' 10,340' 8,879' 8,933' 62' 6 2/19/1992 Open 10,280' 10,342' 8,881' 8,935' 62’ 5 10/27/12 Open G-5 10,395' 10,415' 8,981' 8,999' 20' 6 2/19/1992 Open 10,398' 10,418' 8,984' 9,001' 20’ 5 10/27/12 Open 10,440' 10,460' 9,021' 9,038' 20’ 5 10/27/12 Open G-6 10,532' 10,548' 9,101' 9,115' 16’ 5 10/27/12 Open G-7 10,600 10,614' 9,161' 9,173' 14’ 5 10/27/12 Open HB-1 10,622’ 10,637’ 9,180' 9,194' 15’ 4 1/17/2001 Open HB-1 10,628' 10,670' 9,186' 9,223' 42' 10 & 16 8/26/1995 Open, frac'd 10,628'- 10,643' 10,628' 10,676' 9,186' 9,228' 48’ 5 10/27/12 Open HB-2 10,689’ 10,718’ 9,240’ 9,265’ 29’ 5 01/16/14 Open HB-3 10,846' 10,860' 9,377' 9,389' 14’ 5 10/27/12 Open HB-4 10,863' 11,000' 9,392' 9,509' 137' 6 2/19/1992 Open 10,939’ 10,954’ 9,457' 9,470' 15’ 4 1/17/2001 Open 10,890' 11,006' 9,415' 9,515' 116’ 5 10/27/12 Open HB-5 11,038’ 11,048’ 9,542' 9,550' 10’ 4 1/17/2001 Open 11,040' 11,070' 9,544' 9,569' 30' 8 8/26/1995 Open 11,042' 11,122' 9,545' 9,614' 80’ 5 10/27/12 Open HB-6 11,155' 11,170' 9,642' 9,655' 15' 4 8/26/1995 Open 11,156' 11,240' 9,643' 9,715' 84’ 5 10/27/12 Open HB-7 11,255' 11,280' 9,728' 9,749' 25' 24 6/24/1994 Open 11,266' 11,290' 9,737' 9,758' 24’ 5 10/27/12 Open Jewelry Details No.Depth MD Depth TVD ID OD Item 42.68’ 42.68’ CIW-DCB-ESP, 11” x 4-1/2” BTC lift and susp, w/4” Type H BPV Profile Hanger 1 2,250’ 2,197’ 3.992 7.063 GLM#1 –SPM 1-1/2” w/ dummy valve 2 4,176’ 3,799’ 3.992 7.063 GLM#2 –SPM 1-1/2” w/ dummy valve 3 5,526’ 4,904’ 3.992 7.063 GLM#3 –SPM 1-1/2” w/ dummy valve 4 7,872’ 6,826’ -- 5.620 Bolt-On Discharge 7,873’ 6,827’ -- 6.750 Pump (x2) - 675 Series, 45 stg SH16000 7,911’ 6,859’ -- 6.750 Intake 7,913’ 6,861’ 5.130 Seals (Upper and Lower) 513 Series, BPBSL 7,930’ 6,875’ -- 5.620 Motor (x2)–562 Motor, KMSLT 500HP/1800V/165.5A 7,997’ 6,932’ 5.620 Centralizer/Anode McArthur River Field, TBU Well: G-01RD As Completed: FUTURE Updated by: KDK 01/13/21 PROPOSED RKB to MLLW ELEV = 103’ TD = 11,506’ PBD = 11,430’ MAX HOLE ANGLE = 39.10q @ 7225’ RKB to TBG Hngr = 42.68’ Tree connection: 3-1/2” EUE 8rd 1 3 4 2 HB-2 G-2 G-3 G-4 G-5 HB-4 HB-5 HB-7 HB-6 4-5/8” Perf Gun @ 11,409’ G-6 G-7 HB-3 26” 13-3/8” 9-5/8” 7” Fish @11337’ G-1 HB-1 TOC 8,127 CBL 2/15 1992 EST TOC 355’ Calc 10/7 1967 CASING DETAIL Size WT Grade Conn ID MD Top MD Btm 26” Surf. 327’ 13-3/8” 61 J-55 Butt 12.515” Surf. 2,160’ 9-5/8” 47 N-80 Butt 8.681” Surf 79’ 40 N-80 Butt 8.835” 79’ 6,275’ 43.5 N-80 Butt 8.755” 6,275’ 8,179’ 47 N-80 Butt 8.681” 8,179’ 8,450’ (TOW) 9-5/8” DV Collar 4,903’ 4,905’ 7” 29 P-110 Butt 6.184” 8,127’ 11,479’ TUBING DETAIL 4-1/2” 12.6 L-80 IBT 3.958” Surface ±7,872’ 12/17/00: Left 10.14’ long fish consisting of coil tubing motor and bit. 10/24/12: Cleaned out fill to 11337’ DPM, Fish not recovered. 04/04/18: Cleaned out fill to 11,294’ PERFORATIONS Zone Top MD Btm MD Top TVD Btm TVD Amt SPF Last Opr. Status G-01 10,089’ 10,120’ 8,715’ 8,742’ 31’ 5 01/16/14 Open G-2 10,140' 10,170' 8,759' 8,785' 30' 6 2/19/1992 Open 10,140' 10,170' 8'759' 8,785' 30’ 5 10/27/12 Reperf G-3 10,225' 10,257' 8,833' 8,861' 32' 6 2/19/1992 Open 10,244' 10,264' 8,849' 8,867' 20’ 5 10/27/12 Open G-4 10,278' 10,340' 8,879' 8,933' 62' 6 2/19/1992 Open 10,280' 10,342' 8,881' 8,935' 62’ 5 10/27/12 Open G-5 10,395' 10,415' 8,981' 8,999' 20' 6 2/19/1992 Open 10,398' 10,418' 8,984' 9,001' 20’ 5 10/27/12 Open 10,440' 10,460' 9,021' 9,038' 20’ 5 10/27/12 Open G-6 10,532' 10,548' 9,101' 9,115' 16’ 5 10/27/12 Open G-7 10,600 10,614' 9,161' 9,173' 14’ 5 10/27/12 Open HB-1 10,622’ 10,637’ 9,180' 9,194' 15’ 4 1/17/2001 Open HB-1 10,628' 10,670' 9,186' 9,223' 42' 10 & 16 8/26/1995 Open, frac'd 10,628'- 10,643' 10,628' 10,676' 9,186' 9,228' 48’ 5 10/27/12 Open HB-2 10,689’ 10,718’ 9,240’ 9,265’ 29’ 5 01/16/14 Open HB-3 10,846' 10,860' 9,377' 9,389' 14’ 5 10/27/12 Open HB-4 10,863' 11,000' 9,392' 9,509' 137' 6 2/19/1992 Open 10,939’ 10,954’ 9,457' 9,470' 15’ 4 1/17/2001 Open 10,890' 11,006' 9,415' 9,515' 116’ 5 10/27/12 Open HB-5 11,038’ 11,048’ 9,542' 9,550' 10’ 4 1/17/2001 Open 11,040' 11,070' 9,544' 9,569' 30' 8 8/26/1995 Open 11,042' 11,122' 9,545' 9,614' 80’ 5 10/27/12 Open HB-6 11,155' 11,170' 9,642' 9,655' 15' 4 8/26/1995 Open 11,156' 11,240' 9,643' 9,715' 84’ 5 10/27/12 Open HB-7 11,255' 11,280' 9,728' 9,749' 25' 24 6/24/1994 Open 11,266' 11,290' 9,737' 9,758' 24’ 5 10/27/12 Open Jewelry Details No.Depth MD Depth TVD ID OD Item 42.68’ 42.68’ CIW-DCB-ESP, 11” x 4-1/2” BTC lift and susp, w/4” Type H BPV Profile Hanger 1 ±2,250’ ±2,197 3.992 7.063 GLM#1 2 ±4,200’ ±3,818 3.992 7.063 GLM#2 3 ±5,525’ ±4,904 3.992 7.063 GLM#3 4 - - -- 5.620 Bolt-On Discharge - - -- 6.750 Pump - - -- 6.750 Intake - - 5.130 Seals (Upper and Lower) 513 Series, BPBSBPB -- - -- 5.620 Motor (x2) ±8,000’ ±6,934’ 5.620 Bottom of ESP LT at 8127 ft MIT casing at 9800 ft ... 1500 psi Grayling Platform G-01rd Current 03/04/2016 Grayling Platform BOP Stack HAK 404 VBR blinds Valve Position(O/C)Standpipe PumpManifold1(PM1) OManifold PumpManifold2(PM2) OPumpManifold3(PM3) CPumpManifold4(PM4) OPumpManifold5(PM5) CMud KillLine1OCross KillLine2OHCRvalve(ChokeLine1) CChokeLine2OChoke ChokeManifold1(CM1) OManifold ChokeManifold2(CM2) CChokeManifold3(CM3) OChokeManifold4(CM4) CChokeManifold5(CM5) OChokeManifold6(CM6) CChokeManifold7(CM7) OChokeManifold8(CM8) CChokeManifold9(CM9) CChokeManifold10(CM10) OSuperChoke CManualChoke CRigFloor SafetyValve O Valve Position(O/C)Standpipe PumpManifold1(PM1) OManifold PumpManifold2(PM2) CPumpManifold3(PM3) OPumpManifold4(PM4) CPumpManifold5(PM5) OMud KillLine1OCross KillLine2OHCRvalve(ChokeLine1) CChokeLine2OChoke ChokeManifold1(CM1) OManifold ChokeManifold2(CM2) CChokeManifold3(CM3) OChokeManifold4(CM4) CChokeManifold5(CM5) OChokeManifold6(CM6) CChokeManifold7(CM7) OChokeManifold8(CM8) CChokeManifold9(CM9) CChokeManifold10(CM10) OSuperChoke CManualChoke CRigFloor SafetyValve O Rig 404 BOP Test Procedure Attachment #1 Attachment #1 Hilcorp Alaska, LLC - BOP Test Procedure: Rig 404, WO Program – Oil Producers, Gas Producers, Water Injectors Pre Rig Move 1) Blow down well, bleed gas to Well Clean Tank that is vented thru flare to atmosphere 2) Load well with FIW to kill well. x 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.) Rig 404 BOP Test Procedure Attachment #1 f) Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn’t hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 4) Pull hanger to surface. (Requires tubing cuts as necessary to free tubing). CBU to displace annulus and tubing with kill weight fluid. 5) If a rolling test was conducted, remove the old hanger, MU new hanger or test plug to the completion tubing. Re-land hanger (or test plug) in tubing head. Test BOPE per standard procedure. Subsequent Tests (i.e. Test Plug can be set in the Tubing-head) 1) Remove wear bushing. a) Use inverted test plug to pull wear busing. MU to joint of tubing. b) Thread into wear bushing c) Back out hold down pins d) Pull and retrieve wear bushing. 2) Break off test plug and invert same- RIH with test plug on joint of tubing. Install a pump-in sub w/ test line plus an open TIW or lower Kelly valve in top of test joint w/ open IBOP. 3) Test BOPE per standard procedure. STANDARD BOPE TEST PROCEDURE (after 2-way check or test plug is set) 1) Fill stack and all lines with rig pump- install chart recorder on test line connected to pump-in sub below safety valve and IBOP in test joint assembly. 2) Note: When testing, pressure up with pump to desired pressure, close valve on pump manifold to trap pressure and read same with chart recorder (test pressures will be indicated in Sundry). 3) Referencing the attached schematics test rams and valves as follows. a) Close 1 st valve on standpipe manifold, 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 xxx psi (see sundry) high for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank and open annular. b) Close pipe rams and open annular preventer, close safety valve and open IBOP on test joint, close outside valve on kill side of mud cross, 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 xxx psi (see sundry) high for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. c) Test Dual Rams. If the well has dual tubing, and dual rams are installed in the stack, test the dual rams by picking up two test joints with dual elevators and lowering them into stack and position them properly in the dual rams. Close rams. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. d) Close 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 xxx psi (see sundry) 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 off 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 xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. Rig 404 BOP Test Procedure Attachment #1 g) Close inside valve / open outside valve (HCR) on choke side of mud cross. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. 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 xxx psi (see sundry) 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 2 nd set of pipe rams if installed (e.g. dual pipe rams). Open the lower pipe rams to simulate the closing volume on the blinds. 4) Allow pressures to stabilize. 5) While stabilizing: Record pressure values of each Nitrogen bottle and average over the number of bottles. (i.e. Report might read “10 bottles at 2,150 psi”). 6) After accumulator has stabilized, record accumulator pressure again. This represents the pressure and volume remaining after all preventers are closed. (The stabilized pressure must be at least 200 psi above the pre- charge pressure of 1,000 psi). 7) Turn on the pump and record the amount of time it takes to build an additional 200 psi on the accumulator gauge. This is usually +/- 30 seconds. 8) Once 200 psi pressure build is reached, turn on the pneumatic pumps and record the time it takes for the pumps to automatically shut-off after the pressure to builds back to original pressure (+/- 3,000 psi). Note: Make sure the electric pump is turned to “Auto”, not “Manual” so the pumps will kick-off automatically. 9) Open all rams and annular and close HCR to place BOPE back into operating position for well work. 10) Fill out AOGCC report. FINAL STEP, FINAL CHECK 1) Test Gas Alarms 2) Double check all rams and valves, for correct operating position 3) Fill out the AOGCC BOPE Test Form (10-424) in Excel Format. Document both the rolling test and the follow up tests. Hilcorp Alaska, LLCHilcorp Alaska, LLCChanges to Approved Rig Work Over Sundry ProcedureSubject: Changes to Approved Sundry Procedure for Well G-01RD (PTD 191-139)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 RECEIVED AIL OIL AND GAS CONSERVATION COMWSION REPORT OF SUNDRY WELL OPERATIONS APR 3 0 2018 1.Operations Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Pull Tubing 0 � .r.:..` r • n ❑ Performed: Suspend 1:1 Perforate ❑ Other Stimulate ❑ Alter Casing 0 Cha�ig� pr.r-.'-ro. am ❑ Plug for Redrill 0 Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Well 0 Other: Replaced ESP 0 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development 0 Exploratory ❑ 191-139 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage,AK 99503 50-733-20037-01 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0018730 Trading Bay Unit G-01 RD 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&Hemlock Oil Pools 11.Present Well Condition Summary: Total Depth measured 11,506 feet Plugs measured N/A feet true vertical 9,946 feet Junk measured 11,337&11,409 feet Effective Depth measured 11,294 feet Packer measured N/A feet true vertical 9,761 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Structural Conductor 327' 26" 327' 327' Surface 2,160' 13-3/8" 2,160' 2,120' 3,090 psi 1,540 psi Intermediate 8,450' 9-5/8" 8,450' 7,319' 5,750 psi 3,090 psi Production 3,352' 7" 11,479' 9,921' 11,220 psi 8,530 psi Liner Perforation depth Measured depth 10,089-11,290 feet True Vertical depth 8,715-9,758 feet St 01 Tubing(size,grade,measured and true vertical depth) 4-1/2" 12.6#/L-80 7,872(MD) 6,826(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: 134 45 4287 1152 200 Subsequent to operation: 379 89 10583 94 108 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations 0 Exploratory ❑ DevelopmentE Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run 0 16.Well Status after work: Oil 0 Gas ❑ WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ 0 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: 317-240 Authorized Name: Stan W.Golis Contact Name: Dan Marlowe Authorized Title: Operations Manager Contact Email: dmarlowetV hilcoro.com Authorized Signature: ..4,.+,. (.1/4) Date: b q 156 f Igo Contact Phone: (907)283-1329 RSD Si ' MAY 0 12018 Form 10-404 Revised 4/2017 Submit Original Only McArthur River Field,TBU H 0 SCHEMATIC • Well: G-01RD Eii, 1°c",1_i.r. As Completed: 04/08/18 CASING DETAIL RKB to TBG Hngr=42.68' Size WT Grade Conn ID MD Top MD Btm Tree connection:3-1/2"EUE 8rd 26" Surf. 327' 13-3/8" 61 1-55 Butt 12.515" Surf. 2,160' I J 47 N-80 Butt 8.681" Surf 79' 6 40 N-80 Butt 8.835" 79' 6,275' 9-5/8" 43.5 N-80 Butt 8.755" 6,275' 8,179' i13-3/8" 47 N-80 Butt 8.681" 8,179' 8,450'(TOW) OE 9-5/8"DV Collar 4,903' 4,905' 1 1 7" 29 P-110 Butt 6.184" 8,127' 11,479' TUBING DETAIL 4-1/2" I 12.6 I L-80 I IBT I 3.958" I Surface I 7,872' I i 2 Jewelry Details I 3 No. DMD Depth ID OD Item 42.68' 42.68' CIW-DCB-ESP,11"x 4-1/2"BTC lift and susp,w/4"Type H BPV Profile Hanger I 1 2,250' 2,197' 3.992 7.063 GLM#1-SPM 1-1/2"w/dummy valve 2 4,176' 3,799' 3.992 7.063 GLM#2-SPM 1-1/2"w/dummy valve t 3 5,526' 4,904' 3.992 7.063 GLM#3-SPM 1-1/2"w/dummy valve 7,872' 6,826' -- 5.620 Bolt-On Discharge n' 4 7,873' 6,827' 6.750 Pump (x2)-675 Series,45 stg SH16000 4 7,911' 6,859' -- 6.750 Intake 7,913' 6,861' 5.130 Seals(Upper and Lower)513 Series,BPBSL 7,930' 6,875' 5.620 Motor(x2)-562 Motor,KMSLT 500HP/1800V/165.5A 7,997' 6,932' 5.620 Centralizer/Anode L . 9-5/8" PERFORATIONS G-1 Zone Top MD Btm MD Top TVD Btm TVD Amt SPF Last Opr. Status - G_2 G-01 10,089' 10,120' 8,715' 8,742' 31' 5 01/16/14 Open 10,140' 10,170' 8,759' 8,785' 30' 6 2/19/1992 Open G-3 G-2 10,140' 10,170' 8'759' 8,785' 30' 5 10/27/12 Reperf G-410,225' 10,257' 8,833' 8,861' 32' 6 2/19/1992 Open G-3 10,244' 10,264' 8,849' 8,867' 20' 5 10/27/12 Open G-5 10,278' 10,340' 8,879' 8,933' 62' 6 2/19/1992 Open - G-6 G 4 10,280' 10,342' 8,881' 8,935' 62' 5 10/27/12 Open = G-7 10,395' 10,415' 8,981' 8,999' 20' 6 2/19/1992 Open G-5 10,398' 10,418' 8,984' 9,001' 20' 5 10/27/12 Open 10,440' 10,460' 9,021' 9,038' 20' 5 10/27/12 Open G-6 10,532' 10,548' 9,101' 9,115' 16' 5 10/27/12 Open G-7 10,600 10,614' 9,161' 9,173' 14' 5 10/27/12 Open HB-1 10,622' 10,637' 9,180' 9,194' 15' 4 1/17/2001 Open = HB-1 Open,frac'd HB-2 10,628' 10,670' 9,186' 9,223' 42' 10&16 8/26/1995 10,628'- HB-1 - 10,643' HB-3 10,628' 10,676' 9,186' 9,228' 48' 5 10/27/12 Open HB-4 HB-2 10,689' 10,718' 9,240' 9,265' 29' 5 01/16/14 Open HB-3 10,846' 10,860' 9,377' 9,389' 14' 5 10/27/12 Open - HB-5 10,863' 11,000' 9,392' 9,509' 137' 6 2/19/1992 Open I HB-6 HB-4 10,939' 10,954' 9,457' 9,470' 15' 4 1/17/2001 Open 10,890' 11,006' 9,415' 9,515' 116' 5 10/27/12 Open HB-7 11,038' 11,048' 9,542' 9,550' 10' 4 1/17/2001 Open HB-5 11,040' 11,070' 9,544' 9,569' 30' 8 8/26/1995 Open •:•A • : 11,042' 11,122' 9,545' 9,614' 80' 5 10/27/12 Open .:; .:4-s/8"PerfGun @ 11,155' 11,170' 9,642' 9,655' 15' 4 8/26/1995 Open HB-6 11,156' 11,240' 9,643' 9,715' 84' 5 10/27/12 Open RKB to MLLW ELEV=103' HB-7 11,255' 11,280' 9,728' 9,749' 25' 24 6/24/1994 Open TD=11,506' PBD=11,430' 11,266' 11,290' 9,737' 9,758' 24' 5 10/27/12 Open MAX HOLE ANGLE=39.10°@ 7225' 12/17/00:Left 10.14'long fish consisting of coil tubing motor and bit. 10/24/12: Cleaned out fill to 11337'DPM,Fish not recovered. 04/04/18:Cleaned out fill to 11,294' Updated by: JLL 04/30/18 • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date G-01RD Moncla 404 50-733-20037-01 191-1393/29/18 4/8/18 Daily Operatid`ns: = 03/29/18-Thursday PJSM.Continued to offload#2 M/V work boat.Spot 404 rig equipment. Raised derrick and r/u drilling line,catlines, lowered derrick down. Continued spot pits, choke house and set accumulator house. R/U Total Safety Sys and Quadco Sys to the rig. R/U all accumulator lines f/choke house. Help production r/u hose to tree and pump down 4 1/2" 12.6# IBT.Total pumped 129 bbls w/ann open t/production. Bleed tank,shut down and monitor well for 2 hrs.Well is static. R/D lines and set BPV w/NOS hand. Prepped &tested void 500-2500 all good.Continued N/D tree. Dismantle swab valve, master valve,wing valve, adapter flange and remove from well room w/production help take on 75 bbls FIW in rig tank.Continued n/d tree and plug off control lines on hanger. 03/30/18-Friday Continue N/U BOPE, mud cross, dbl gates, Hydril. Hooked up accumulator line to BOP stack.Torque up all flanges and "Eolts. R/'U derrick,secured guywires.Spotted power pack for tongs. R/U floor,set tool platform. M/U x overs for test jt and R/U all test equipment. Install stairs to rig floor and offload m/v boat w/ESP pulling eq. R/U test eq.w/3 1/2"test joint and make up to hanger.Shell test,well head Ids leaking. Repack Ids w/NOS hand,all good. Continue pre test and call out AOGCC inspector Adam Earl.Tested all BOPE to 250-2500 psi high as per sundry in accordance with Hilcorp and AOGCC. Witness by inspector Adam Earl.Tested w/3 1/2"and 4 1/2"test joint, all good. Production elec w/total safety tested gas alarms-pvt system, all good. Pulled blanking sub and b/d test jts. N/U spool on Hydril, r/u ESP pulling eq. 03/31/18-Saturday Cont. R/U pulling equipment. Pull BPV, m/u landing jt, BOLDP w/nos hand. Pull hanger t/floor, came off seat @ 79k, string moving @ 94k, level out @ 92k. Prep&I/d hanger,set up slide. Pull first 3 jts&I/d string up cable sheave&hang same.Cont. POOH 1/d 40'tot 35' jts,stand back 30'jts,t/7898', up wt 64k. Cont. POOH t/2300'. R/U &pump 35 bbls to purge tubing. Continue POOH and standing back 4 1/2" IBT production string t/ESP assy. PJSM, inspect&start breaking down assembly. Have found some holes in the upper pump assy so far. 04/01/18-Sunday Cont. l/d esp assy,total initial findings, 3 holes in the upper pump section.Clean &clear floor.C/o handling eq. M/U running tool &install wear bushing. P/U BHA-6"mill, bumper sub,fishing jar,4-4 3/4" DC,xo= 145.5'. C/O handling tools. RIH p/u 3 1/2" PH-6 wk string t/4025'. R/U t/production and pump down 3 1/2" PH-6 work string circulate hydrocarbon out of the annular. Pumped total 280 bbls of FIW,oil &gas returns turning t/water.Shut down monitor well,went on vac.Continue p/u 3 1/2" ph6 work string t/8994'. Mix 80 bbl sized salt pill in mixing tank.Tested GLM w/dummy valves t/3500 psi,good. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date G-01RD Moncla 404 50-733-20037-01 191-139 3/29/18 4/8/18 Daisy:Operations 04/02/18-Monday Unload boat&tally pipe. R/U circulate to production. Pump 200 bbls, no returns. Cont. rih p/u 3 1/2"wk string t/10,017', up wt 94k, dn wt 68k. Finish mixing 80 bbl SS pill. Pump&spot 80 BBL size salt pill, pump 4BPM, 550psi max circulating pressure. Cont.TIH p/u 3 1/2"wk string t/10710', up wt 98k, dn wt 70k.Tagged up @ 10710', attempt to p/u, unable,wk pipe jarring @ 15k, no joy. C/O elevators t/150t&r/u t/pump.Wk stuck pipe,jarring @ 20k OP, pump @3.5 bpm, 690 psi, started getting oil returns. R/U t/take returns to production, pump @ 3.5 BPM 670 psi, circulating till clean @ 130 bbls pumped, losing 2/3 of returns. Wk stuck pipe,jarring @ 25k op, pump 3.25 bpm,500 psi,string came free.Cont.work pipe 20' up and down, PUW 100k,SOW 70k.CBU and spot 20 bbls salt pill @ 10700'and shut down w/ pumping last rate 60 bbls hr. R/D joint 341 and Moncla due a inspection on the derrick pins,all good. N/U stripping head & DSA w/11"x13 5/8" adapter spool. P/U power swivel and make up on joint 341. Brake circ. pumping down SW @3.5 bbl/min @400psi. Cont milling f/10700'-10705'. Torque 5-7. @10705,seems to be clean. Cont.wash/ream to 10731'w/pump pressure @ 3.5 bbl/min @ 200 psi. Loss rate 85/hr w/90%returns.Added one drum CFS-520 to pits. PU joint 342. MU to swivel. Cont wash and reaming from 10731'to 10824'. 04/03/18-Tuesday Cont.wash & ream down t/10865',start packing off, blew stripping rubber,cleared plug. CBU 1.5x @ 3.2 bpm, 250 psi, shut down c/o stripping rubber. Cont.wash & ream,f/10865't/10880', pump 3.4 BPM 240 psi, up wt 94k, dn wt 68k, rot wt 82k. Fighting issues packing off& losing partial circulation, lost stripping rubber. Pump 65bbls size salt pill &spot, shut down,change out stripping rubber, Circulate excess pill out of hole&capture at surface, cont.wash &ream t/10927'.Continue washing and ream f/10927'T/11144' Pumping @ 3.5 bbls l/w 350 psi and Reverse Circ @ 3.5 @ 375 PSI SOW 70k POW 98k Rot 80 RPM 40. Lost rate @ 0230(35 bbls hr w/pumping) circulate clean each connection. 04/04/18-Wednesday Cont. Wash & ream f/11,144't/11,268'circ 3.4 bpm, @ 350 psi, up wt 70k, dn wt 98k, rot 80 RPM,4k tq, rot wt,80k. Power swivel died during connection,troubleshoot unable to re-start. Finish m/u swivel w/tongs.Wash down t/11,294' up wt 91k, dn wt 71k(pumps on ).Circulate hole clean @ 4 BPM,540 psi.Treat fluid w/chlorine. R/U w/production to swap hole to clean FIW.Ship treated fluid to Trading Bay.Tot pumped 1014 bbls @ 6.5 bbls min and 135 bbls f/rig tank. Set back power swivel, r/d pumping eq. &lines. POOH 1/d singles,3 1/2" Ph6 work-string t/8370' PUW off bottom 98k. L/d 94 jts. 04/05/18-Thursday Cont. POOH 1/d 3 1/2" PH-6 wk string. LID cleanout assembly, 6" mill had wear on face&leading outside edge. Note: recovered 16 bbls^ solids from c/o. Clear&clean floor. L/d &breakdown swivel, c/o handling tools, pull stripping head adaptor. R/u wear ring tool &pull wear bushing. Install 13 5/8"spool on annular. R/U summit sheave back in derrick and string esp cable t/rig floor. PJSM, P/U &service tandem motors 562 kmslt 500 hp, lower seals. • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date G-01RD Moncla 404 50-733-20037-01 191-139 3/29/18 4/8/18 Dail Op erations: 04/06/18-Friday Cont. M/U ESP assy,finish servicing lower seal, upper seal, dual pump assy, discharge& pressure sub.Test cable&cap line,good.Cont. RIH with assy on 4 1/2" IBT L-80 12.6# tubing t/3006'checking line&cable every 1000',good. Cont. RIH with assy on 4 1/2" IBT L-80 12.6# tubing t/4188' checking line&cable every 1000',good. Make a splice @4188' due to damaged cable and flat pack. Cont. RIH with assy on 4 1/2" IBT L-80 12.6# tubing t/5056'checking line&cable every 1000',good. Had operating wheel failure on cable spooler,wk on repair. 04/07/18-Saturday Repair spooler&test good. Cont. RIH w/ESP assy. RIH w/4 1/2" IBT tubing t/6531'testing every 1000'.Swap spools, make cable splice&test,good. Cont. RIH w/ESP assy, p/u 4 1/2" IBT tubing t/7213'testing cable every 1000'. Note: Talked to AOGCC,Jim Regg, he granted us an extension for BOPE test if needed to finish well.Cont. RIH w/ESP assy, p/u 4 1/2" IBT tubing t/7952.57'testing cable every 1000'.Tot joints run 4 1/2" IBT 252 joints and 3 GLM. P/U hanger, and landing joint. Make up penetrator and terminate cables, m/u control lines through hanger,tested all good. Land hanger placing assy tail @ 7997'.SOW 62K RILDS and B/O landing joint. L/D same and set BPV w/NOS hand.Cont. R/D Summit equipment. R/D rig floor, prep rig 404 for removal. Prep to remove BOP and Prep scope derrick down, lay over. Remove all accumulator lines from bop stack. 04/08/18-Sunday N/D 13 5/8" 5M BOPE (washing components as needed). Removed drill line from draw works-spooled up same-set spool inside derrick. Finished cleaning rig tank. N/U tree assisting production personnel and NOS rep with hookups. NOS rep tested hanger neck seals to 500 psi 5 mins,5000 psi 5 mins-tested hanger void 500 psi 5 mins 5000 psi 15 mins (had to repack void to achieve test).Assisted production in reorienting tree. Continued moving accessory equipment to West side of platform. Shell tested (visual)tree to 500 psi &5000 psi-pulled TWC.Turned well over to production @ 1730 hr. SOF Thr • 4 s� THE STATE • Alaska Oil and Gas of LAsKA Conservation Commission z 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 ALASY' Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov April 25, 2018 Mr. Stan Golis Operations Manager—CI Offshore Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 RE: No-Flow Verification SCANNED Trading Bay Unit G-01RD PTD 1911390 Dear Mr. Golis: On April 19, 2018 an Alaska Oil and Gas Conservation Commission (AOGCC) Petroleum Inspector witnessed a no-flow test of Trading Bay Unit G-01 RD located on the Grayling Platform in Cook Inlet. The well is operated by Hilcorp Alaska, LLC (Hilcorp). The AOGCC Inspector confirmed that the proper test equipment—as outlined in AOGCC Industry Guidance Bulletin 10- 004 — was rigged up on Trading Bay Unit G-01RD prior to the test. The well performance was monitored for three hours. Gas flow rates at the end of three separate flow checks preceded by 1- hour pressure build up periods were within the allowable rate limits. There was also no liquid flow to surface during the no-flow test. Trading Bay Unit G-01RD may be produced without a subsurface safety valve. A fail-safe automatic surface safety valve system capable of preventing uncontrolled flow must be maintained in proper working condition in this well as required in 20 AAC 25.265. The subsurface safety valve must be returned to service if Trading Bay Unit G-01 RD 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, --../(1Z4effia'Reg James B. Regg j Petroleum Inspection Supervisor ecc: P. Brooks AOGCC Inspectors • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg \cat) 4/Z$/1$ DATE: 4/21/2018 P. I. Supervisor FROM: Adam Earl SUBJECT: No Flow Test Petroleum Inspector TBU G-01 RD Hilcorp Alaska LLC �� .f PTD 1911390 S4/19/18: I traveled out to Grayling platform to witness a No-Flow Test to be conducted by lead operator, Kenny Wingard. The well to be tested was TBU G-01 RD, an ESP production well. I walked down the rig-up, the well, and lines/valves coming off. The tubing and inner annulus (IA) were tied together at surface due to the packer-less °- completion. The well had been opened to bleed down to zero for the last 24 hours. The test would consist of the well shut in and pressures recorded every 30mins. The tubing/IA would be opened to flow through a low flow meter on the hour, 3 consecutive — times. The following table shows test details: Time Pressures' Flow Rate2 Remarks (psi) Gas—scf/hr Liquid — gal/hr 8:20 0 /0/0 - Well shut in 8:50 0.35/ 0.35/0 ' Pressure check 9:20 0.73/ 0.73/0 • 700 - 0 Opened to meter; gas rate declined to 350 scf/hr in 3 min 9:50 0.75/0.75/0 ' Pressure check 10:20 1.07/ 1.07/0 - 750 • 0 Opened to meter; gas rate declined to 550 scf/hr in 3 min 10:50 1.0 1.0/ 0 Pressure check 11:20 1.42/ 1.42/ 0 - 850 - 0 Opened to meter; gas rate declined to 600 scf/hr in 3 min 1 Pressures are T/IA/OA 2 Gas flow not to exceed 900 scf/hr; Liquid flow not to exceed 6.3 gal/hr The well demonstrated flow rates during the test that support a passing no flow v determination. Attachments: Photos (2) Test Equipment Certifications ._ 2018-0419_No-Flow_TBU_G-01 RD_ae.docx Page 1 of 0 • . 0 , 7, o az V � do vel m Acari R m \-11 go' teel Ca ,,, ..,.. «�� OfOcog� No ,' w 0 � 1f 4 61 d N Z U m U y O U ^� R— zEN V N N N /' . •J ._ C ' U O. .N.F G V S W �� L. r:° nza a1. a ° o `a> 2 p. d N N '6 to m.ro�.�- Z O .mom.H U P. c ='n c y oz m 1 o = m s, DC m p q > N U H. ' 2 y'c-. d - 2 waw C 'O mila QQ c. I cn N O g a 0 ZI d- 9 ao el M ^ a r/� UcTV. ' o ,.ark sus„;✓�*" 0 cn VI a 0 ` op N a i2. L d W Iiii ¢ $ v rn v rn E O O ^ r N y <� a3 r s ~� a F w cu p N 0 Q =- (7co CC.PA to U fq `+ m�� m a m CO un (V, 0 k Vie Jf o 8 $ La o ,v' cu i V ` t 4 I— >,co 3 -a � O � N >4; fi LL. • _ O C m• ? 1.— O co Z 0 F • • • ..- • ` riI '., „,--d'fi P.' , , -;•.--. ' f''--- - : At I • ,' i 1 eN i »f / : 1 ,i 1 i!g!E . •L,..,._. ° :i '-' 7.; i e 4-4 , : ..t 5 CS Tci *: i 1. o 1 0 rn , j ti .,,,,t,,,•. 1:,,,. '•(^- ',.., ', 4..** 4 V."- " ; ' ''''.:" - ' ' CU 21 CA CA • 1 0 i . 4 i -...'"'10t10,.t:..i. iiim.. ��i.� *' • .. 4.1 ,.,s11 Qr C. Ln - a, #4i ,,,.,,-;' , * 1! Z czN o ' ; i ,.41' o 44 N C wo H ,$ 1, to a,, �„ O B G i 0 i 8 4 U x C R Q — $ �' 3 ._a w o w �," di . . ' \ ,1 ,„, 4 ,....,... ** . , 4 c) - -i , , „., ..„ 4 • • OF Tji y ��\%I//7 • THE STATE Alaska Oil and Gas gf � �'-9� r T A A Conservation Commission F`-ib,• � ALj 1S��! �l 1 " } _= 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov June 27, 2017 • Mr. Stan Golis Operations Manager—CI Offshore Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 RE: No-Flow Verification - Correction Trading Bay Unit G-01RD SCANNED !,.:}-". 1 I 20 PTD 1911390 Dear Mr. Golis: On January 27, 2014 an Alaska Oil and Gas Conservation Commission (AOGCC) Petroleum Inspector witnessed a no-flow test of Trading Bay Unit well G-01 RD 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-01 RD. The no-flow test consisted of a series of flow and shut in periods. During the flow monitoring periods, no liquid production was observed and gas flow rates were measured from 1850 scf/hour bleeding down rapidly to less than 1 scf/hour. Pressures during the test remained less than 1 psi. The test results meet AOGCC acceptance criteria for a passing no flow test. The subsurface safety valve must be returned to service if Trading Bay Unit G-01 RD 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. This letter supersedes and replaces the letter previously issued for this well dated February 7,2014 (corrected test date). Please retain a copy of this letter on the Grayling Platform. Sincerely, James B. Regg Petroleum Inspection Supervisor cc: P. Brooks AOGCC Inspectors • oFTi� • • 0).1.I�7:* THE STATE Alaska Oil and Gas ti � ofLAS��.1-1 Conservation Commission ow - A � i i 333 West Seventh Avenue 1 T GOVERNOR BILL WALKER..4411" Anchorage, Alaska 99501-3572 '°'1 Main: 907.279.1433 AAS Fax: 907.276.7542 www.aogcc.alaska.gov Stan W. Golis Operations Manager j11.� Q 4 2(.11Y. Hilcorp Alaska, LLC SC Mati 3800 Centerpoint Dr., Ste. 1400 Anchorage, AK 99503 Re: McArthur River Field, Middle Kenai G and Hemlock Oil Pools, TBU G-01 RD Permit to Drill Number: 191-139 Sundry Number: 317-240 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, 6 Cathy P. Foerster (71‘ Chair DATED this esti of June, 2017. RBDMS I,V JUN 2 6 2017 • • • RECEIVED STATE OF ALASKA JUN 1 2 2017 ALASKA OIL AND GAS CONSERVATION COMMISSION OTS/� ( /7 APPLICATION FOR SUNDRY APPROVALS eek 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 0 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 ' 191-139 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service 0 6.API Number Anchorage,AK 99503 50-733-20037-01 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-01RD - 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0018730 McArthur River Field/Middle Kenai G&Hemlock 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): 11,506 • 9,946 • 10,908 . 9,431 • 2,425 psi N/A 11,337&11,409 Casing Length Size MD TVD Burst Collapse Structural Conductor 327' 26" 327' 327' Surface 2,160' 13-3/8" 2,160' 2,120' 3,090 psi 1,540 psi Intermediate 8,450' 9-5/8" 8,450' 7,319' 5,750 psi 3,090 psi Production 3,352' 7" 11,479' 9,921' 11,220 psi 8,530 psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 10,089-11,290 8,715-9,758 4-1/2" 12.6#/L-80 7,811' Packers and SSSV Type: s Packers and SSSV MD(ft)and TVD(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: 7/10/2017 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: dmarlowe@hilcorp.com �/ Z• 1 �( / Zp I 1 Contact Phone: (907)283-1329 Authorized Signature: cs'�i�w+► p4v1 Date: C L COMMISSION SE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number 3 t? - 2410 Plug Integrity ❑ BOP Testy Mechanical Integrity Test ❑ Location Clearance ❑ ,4---__ _ 6 'I S la Other: /. 2 SuO ..,c g 6 f" .7--,-.;(- Post Initial Injection MIT Req'd? Yes ❑ No ❑ RBDMS L-- JUN Z 6 2017 Spacing Exception Required? Yes ❑ No id Subsequent Form Required: / `- 1 0 / / APPROVED BY Approved by: - 4,— COMMISSIONER THE COMMISSION Dater - iS—/7 f1c1 Gil /1— ,00e.Q6/7 0Rcloi4p Ii L.� SubmnFormane Form 10-403 Revised 4/2017 Ir 0 I lid for 12 months from the date of approval. Attachments in Duplicate • • • Well Work Prognosis Well: G-01RD Hilcorp Alaska,LLC Date: 06/06/2017 Well Name: G-01RD API Number: 50-733-20037-01 Current Status: ESP Producer Leg: Leg#2 (NE corner) Estimated Start Date: July 10, 2017 Rig: Moncla 404 Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Juanita Lovett (8332) Permit to Drill Number: 191-139 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: 3,296 psi @ 8,715'TVD 0.393 lbs/ft(7.27 ppg) based on ESP Gauge Maximum Expected BHP: 3,296 psi @ 8,715'TVD 0.393 lbs/ft(7.27 ppg) based on ESP Gauge) Maximum Potential Surface Pressure: 2,425 psi Using 0.1 psi/ft gradient 20 MC 25.280(b)(4) ***This is a no flow well 01/27/2014 AL Brief Well Summary ��zC G-01RD is a G-Zone and Hemlock Producer that was converted to and ESP from a dual string gas-lift completion in October 2012. The current ESP is experiencing down-hole pump issues with productivity falling off. We plan to pull the current ESP completion and replace with new ESP equipment. ,/ Last Casing Pressure Test: 10/24/2012 at 9850' at 1,500 psig and charted for 30 minutes. Procedure: 1. MIRU Moncla 404 2. Attempt to pump through ESP to circulate hydrocarbon off the well to production. 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/2,500psi high. (Note: Notify AOGCC 48 hours in advance of test to allow them to witness test). w 4. Monitor well to ensure it is static. 5. Unseat hanger and POOH with ESP completion. 6. If needed - RIH with cleanout assembly, Circulate bottoms up, POOH. 7. PU, RIH with ESP/Gas-lift Combo completion. 8. Land ESP with the bottom of the assembly at±8,000'. 9. ND BOP, NU wellhead and test. 10. Turn well over to production. 11. Conduct SVS testing per AOGCC regulations. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Current/Proposed Wellhead Diagram (Same) 4. BOP Drawing 5. Fluid/Flow Diagrams 6. Rolling BOP Test Procedures 7. RWO Sundry Change Form H . McArthur River Field,TBU SCHEMATIC Well: G01RD ni•°r ��°�° �� As Completed: 6/28/2016 CASING DETAIL RKB to TBG Hngr=42.68' Size WT Grade Conn ID MD Top MD Btm Tree connection:3-1/2"EUE 8rd 26" Surf. 327' 13-3/8" 61 J-55 Butt 12.515" Surf. 2,160' ii 47 N-80 Butt 8.681" Surf 79275' L26 40 N-80 Butt 8.835" 79' 6, ' 9-5/8" 43.5 N-80 Butt 8.755" 6,275' 8,179' 3-3/8° 47 N-80 Butt 8.681" 8,179' 8,450'(TOW) 9-5/8"DV Collar 4,903' 4,905' 7" 29 P-110 Butt 6.184" 8,127' 11,479' TUBING DETAIL fj 4-1/2" I 12.6 I L-80 I IBT I 3.958" I Surface 7,811' f 1-6 Jewelry Details III No. DepthMDDepth ID OD Item hl 1 2,567' 2,462' 3.992 GLM 2 4,310' 3,907' 3.992 GLM 3 5,535' 4,912' 3.992 GLM ,/� 4 6,507' 5,717' 3.992 GLM 5 7,379' 6,423' 3.992 GLM 7 i /�45 +cJ 6 7,552' 6,559' 3.992 GLM �„7r 7,813' 6,776' -- Bolt-On Discharge d IP 1ti 7,814' 6,777' -- Pump(x2)675 Series 045 Stg SH12000 7 7,857' 6,813' -- Intake X 7 7,876' 6,829' -- Motor(x2)562 Motor,KMSUT/KMSLT 500 HP 7,942' 6,885' 3.992 Bottom of ESP L .9-5/8" PERFORATIONS - G-1 Zone Top MD Btm MD Top TVD Btm TVD Amt SPF Last Opr. Status G-2 6-01 10,089' 10,120' 8,715' 8,742' 31' 5 01/16/14 Open 10,140' 10,170' 8,759' 8,785' 30' 6 2/19/1992 Open G-3 G-2 10,140' 10,170' 8'759' 8,785' 30' 5 10/27/12 Reperf G-4 10,225' 10,257' 8,833' 8,861' 32' 6 2/19/1992 Open - G-3 10,244' 10,264' 8,849' 8,867' 20' 5 10/27/12 Open G-5 10,278' 10,340' 8,879' 8,933' 62' 6 2/19/1992 Open G-6 G 4 10,280' 10,342' 8,881' 8,935' 62' 5 10/27/12 Open 10,395' 10,415' 8,981' 8,999' 20' 6 2/19/1992 Open - G-7 G-5 10,398' 10,418' 8,984' 9,001' 20' 5 10/27/12 Open 10,440' 10,460' 9,021' 9,038' 20' 5 10/27/12 Open 6-6 10,532' 10,548' 9,101' 9,115' 16' 5 10/27/12 Open G-7 10,600 10,614' 9,161' 9,173' 14' 5 10/27/12 Open HB-1 10,622' 10,637' 9,180' 9,194' 15' 4 1/17/2001 Open HB-1 Open,frac'd HB-2 HB-1 10,628' 10,670' 9,186' 9,223' 42' 10&16 8/26/1995 10,628'- - 10,643' E HB-3 10,628' 10,676' 9,186' 9,228' 48' 5 10/27/12 Open HB-4 HB-2 10,689' 10,718' 9,240' 9,265' 29' 5 01/16/14 Open HB-3 10,846' 10,860' 9,377' 9,389' 14' 5 10/27/12 Open HB-5 10,863' 11,000' 9,392' 9,509' 137' 6 2/19/1992 Open _ HB-6 HB-4 10,939' 10,954' 9,457' 9,470' 15' 4 1/17/2001 Open 10,890' 11,006' 9,415' 9,515' 116' 5 10/27/12 Open HB-7 11,038' 11,048' 9,542' 9,550' 10' 4 1/17/2001 Open ,',y ,'.Fish@11337' HB-5 11,040' 11,070' 9,544' 9,569' 30' 8 8/26/1995 Open :•:•:•:•�:•' 11,042' 11,122' 9,545' 9,614' 80' S 10/27/12 Open .:.:.:.:.:.:.:.:.#5.t.:. •.•.•.•.•.•.•.•. ..4-5/8"Pert Gun@ 11,155' 11,170' 9,642' 9,655' 15' 4 8/26/1995 Open 7" :•;•;•;•;•,•,•,•,••11.409' HB-6 11,156' 11,240' 9,643' 9,715' 84' 5 10/27/12 Open RKB to MLLW ELEV=103' HB-7 11,255' 11,280' 9,728' 9,749' 25' 24 6/24/1994 Open TD=11,506' PBD=11,430' 11,266' 11,290' 9,737' 9,758' 24' 5 10/27/12 Open MAX HOLE ANGLE=39.10°@ 7225' 12/17/00:Left 10.14'long fish consisting of coil tubing motor and bit. 10/24/12: Cleaned out fill to 11337'DPM,Fish not recovered. 6/26/2016: Tagged fill/scale at 10,908'with S/L(3"bailer). Updated by: iLL 07/26/16 • McArthur River Field,TBU • Iti IIII PROPOSED Well: G 01RD ii 11.1-1.a.ri As Completed: FUTURE CASING DETAIL RKB to TBG Hngr=42.68' Size WT Grade Conn ID MD Top MD Btm Tree connection:3-1/2"EUE 8rd 26" Surf. 327' 13-3/8" 61 J-55 Butt 12.515" Surf. 2,160' J 47 N-80 Butt 8.681" Surf 79' 26" 40 N-80 Butt 8.835" 79' 6,275' 9-5/8" 43.5 N-80 Butt 8.755" 6,275' 8,179' 13-3/8" 47 N-80 Butt 8.681" 8,179' 8,450'(TOW) h 9-5/8"DV Collar 4,903' 4,905' 7" 29 P-110 Butt 6.184" 8,127' 11,479' TUBING DETAIL ' 4-1/2" I 12.6 I L-80 IBT I 3.958" 1 Surface I 17,810' ' b I 1 1-6 I hl Jewelry Details Depth Depth ill Na. MD TVD ID OD Item f 1 ±2,565' ±2,460' 3.992 GLM 1 til 2 ±4,310' ±3,907' 3.992 GLM - 3 ±5,535' ±4,912' 3.992 GLM 4 ±6,510' ±5,719' 3.992 GLM r� 5 ±7,380' ±6,423' 3.992 GLM v____di 6 ±7,550' ±6,557 3.992 GLM 7 Bolt-On Discharge -- -- -- Pump 7 -- -- -- Intake X. X -- -- -- Motor ±8,000' ±6,934' 3.992 Bottom of ESP Z .19-5/8" PERFORATIONS - G-1 Zone Top MD Btm MD Top TVD Btm TVD Amt SPF Last Opr. Status G-2 G-01 10,089' 10,120' 8,715' 8,742' 31' 5 01/16/14 Open 10,140' 10,170' 8,759' 8,785' 30' 6 2/19/1992 Open G-3 G-2 10,140' 10,170' 8'759' 8,785' 30' 5 10/27/12 Reperf - G-410,225' 10,257' 8,833' 8,861' 32' 6 2/19/1992 Open G-3 10,244' 10,264' 8,849' 8,867' 20' 5 10/27/12 Open G-5 10,278' 10,340' 8,879' 8,933' 62' 6 2/19/1992 Open G-6 G 4 10,280' 10,342' 8,881' 8,935' 62' 5 10/27/12 Open ' 10,395' 10,415' 8,981' 8,999' 20' 6 2/19/1992 Open G-7 6-5 10,398' 10,418' 8,984' 9,001' 20' 5 10/27/12 Open 10,440' 10,460' 9,021' 9,038' 20' 5 10/27/12 Open G-6 10,532' 10,548' 9,101' 9,115' 16' 5 10/27/12 Open G-7 10,600 10,614' 9,161' 9,173' 14' 5 10/27/12 Open HB-1 10,622' 10,637' 9,180' 9,194' 15' 4 1/17/2001 Open HB-1 Open,frac'd E HB-2 HB-1 10,628' 10,670' 9,186' 9,223' 42' 10&16 8/26/1995 10,628'- 10,643' HB-3 10,628' 10,676' 9,186' 9,228' 48' 5 10/27/12 Open HB-4 HB-2 10,689' 10,718' 9,240' 9,265' 29' 5 01/16/14 Open HB-3 10,846' 10,860' 9,377' 9,389' 14' 5 10/27/12 Open HB-5 10,863' 11,000' 9,392' 9,509' 137' 6 2/19/1992 Open _ HB-6 HB-4 10,939' 10,954' 9,457' 9,470' 15' 4 1/17/2001 Open 10,890' 11,006' 9,415' 9,515' 116' 5 10/27/12 Open :.•. . . 11,038' 11,048' 9,542' 9,550' 10' 4 1/17/2001 Open :.:.:•:•:•:.Fish @11337' HB-5 11,040' 11,070' 9,544' 9,569' 30' 8 8/26/1995 Open yb • 11,042' 11,122' 9,545' 9,614' 80' 5 10/27/12 Open . . . . . . ...8 .:.:a-s/EPerfcun@ 11,155' 11,170' 9,642' 9,655' 15' 4 8/26/1995 Open HB-6 11,156' 11,240' 9,643' 9,715' 84' 5 10/27/12 Open RKB to MLLW ELEV=103' HB-7 11,255' 11,280' 9,728' 9,749' 25' 24 6/24/1994 Open 11,266' 11,290' 9,737' 9,758' 24' 5 10/27/12 Open TD=11,506' PBD=11,430' MAX HOLE ANGLE=39.10°@ 7225' 12/17/00:Left 10.14'long fish consisting of coil tubing motor and bit. 10/24/12: Cleaned out fill to 11337'DPM,Fish not recovered. 6/26/2016: Tagged fill/scale at 10,908'with S/L(3"bailer). Updated by: JLL 06/12/17 • • Grayling Platform G-01rd Current 03/04/2016 HiIcorp Alaska,IAA: Grayling Platform Tubing hanger,CIW-DCB-ESP, G-1rd 11 X 4'/:IBT lift and susp,w/ 13 3/8 X 9 5/8 X 3 1/2 4"type H BPV profile,5'''A EN, 3-3/8 continuous control line ports,prepped for BIW penetrator BHTA,CIW,41/16 5M FE X Cameron internal blanking nut III III 14 0ii 1 Valve,swab,WKM-M, /It i. 2Cross,stdd,41/16 5M X 41/16 5M FE,HWO, l A� T-24 ''‘,•,- 3 1/8 5M X 2 1/16 5M n..._.._. ni r Valve,wing,WKM-M, "''ii\ yl 2 1/16 5M FE,HWO, iuj ' JI QO � Valve,WKM-M,3 1/8 SM FE,w/ T-24 ii MA-16 operator filit Norm 111 Valve,lower master,WKM-M, lip��- 4 1/16 5M FE,HWO,T-24 LIM IIIIIIIII. ,II sir "' ., Adapter,CIW-Toadstool,11 5M Stdd X 4 1/16 5M FE,prepped for 5%EN neck,3-'/z npt continuous I control line ports,BIW penetrator port Tubing head,CIW-DCB, Q .—_ ./ 1. 13 5/8 3M X 11 5M -■ I i'• . 1• «.= w/2-2 1/16 5M SSO, X bottom �� i i�� Valve,WKM-M,21/16 SM FE, HWM,, 1 ��L ' �I • i' .:I-l it' 1I1 t-,,.._ Casing head, II IS Shaffer KD, I /— I 1st 13 5/8 3M X 133/8 SOW,w/2-2" LPO, I■• I_h1€1 •1-•; 2"LP CIW ball valve • • • II Grayling Platform 2016 BOP Stack Moncla 05/13/2016 Hilrnrp Alnrka.,l.lL lit III tit tit tit 4.54' • Hydric 0 GK 13 5/8-5000 Ill Iii tit 111111 __._._. 2 7/8-5.5 - Shaffer SL p variables 2.83' 135/85M - Blinds 11)=1 07 OO Choke and Kill valves 2 1/16 5M - U ■■ :' 2.26' 1,1( it I .II 4—M1 ud/165MCrossEFO ' J' Riser 135/8 SM FE X 135/85M FE 14.20' lit iii lit lii Ill III III Ill Ill Spacer spool 13 5/8 5M FE X11 5M 2.75' II III Mil III C _ 000UoU 00 : 0 : : : : : UUoUU 0 N M a 2 a0 2 2 2 2 2 2 2 CO 2 u a a a 2 2 G U U U U U U U U U -- c1 N N 7 VI N . N 4+1 a V1 LO N CO Ql .-I 'O 'O -O -O -O 0 -0 '6 -O a -0 -O -O -O -O -O O O O O O L N w 0 w w w w 4-0 0 0 0 0 0 0- - -0 0 N Y U - C C C C C C C C C G C C C C 1U O L > i NN ; J 22222' ggg2u2' U j O6OdO. O - d 0000000000 0 0 = 22222 5 = USL LU .0 L L L L L U U U g jV1 0 . a'o a1 n o 0 0 a w oC '� o [_ L LL Y U L,,12IS C 0 ►� ►4 N Cr) N . OO . � ' mak' in . (0 . U Lu 2z r z--.4-1 J cc LLI Q a a0 K) ._ - ZO v)U L C 2 U Ii K U W a oLL aw 1)L'COi if H m NO -, 111111 - _ D_ 0 m CO H U) L11 u CL H CT0 Z0 H CO z O ° ~ w Z � jz mH ri ? . J (n J H ❑ o_ A Z Z o OC OOH OF- ZQ QQc/) D f � UJOc Q O Z U J J W011 H • JOZw in aF Y LLZ1_ c �D z Q _ m F J 0 U V i2 0100 • o o u o u o 0 o u o : : : : : : : ; . 0 o • _ UUUuuuuuu 0 ti ry m a Ln v .--1 ry co v Ln . n co m .-i -O -D 'O Tl 'O p 'II V 'O 'O "o 'O '6 'O 'O '6 O O O O O 0 0 0 0 0 0 0 42_ 0 0 W U N y- w µ. w w .c _ _ _ _ v C C C C C C c � � w t C G G G1 � t0 tp t0 0 O i ! ! ! ry ry f g g g g g 5 g g ° U N n n , c:,,,. c c j Y U1 N N N N CU N U) Ol y Y N O d d d = - U U U U U U U U U U U c N g a O. Y Y = U U U U U U U U U U U N a d y O Q o o w 2 C U N 11 I I,4 N C) N , 00 L Q0 U W E Z [—..--•: :-...-7 Q J a cc ill ¢w a0 rn , - .. ZO II I K j U-I CC fJ_> O K OJ aa � `` 11■1111il[3I.I* EBiD OQ 7.7 mH U) a u a n 0 z • Q H U) CO Q J D z Z a Z ~ w U z CD L....1 of IQ a � � Z ❑ a c D O U } Q Q � 5wzCD s a - Z N < OOmO 1 , J J J D J N N O ° Z = 25tH r JOO M Lri mw a U_ Z p � 0m Z 0 H Z 5 Q . , D4 or D 0 CC 0 • i 11 Moncla Rig 404 BOP Test Procedure Hilcorp 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.) • • Moncla Rig 404 BOP Test Procedure Hilrorp Alaska,LLC 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 15`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 Hilcurp Alaska,LLC 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. • 0 0 � � / :5. mg 2 a o a) c 2E X02 / 2kw/ § � a E / � 3 ) ƒ § i �m/ f a = 0 � >,, CO To > _ • \.§ a. 0_ 2 CO• .--(') n -0 ■ ■ / ® 2 ,_ _. cc ca $ / 2 �Z c c Co 2J A / / U - . & 0 ± \ 7 I— LI U\ E as � 0 co '§- § - 2 = cU Q \ -0 0 L. k � k E Zr.) ° a) % 0 9 / : a. L. / / C) 4 O g a) -0 2 § � = � CO C k / /C C Lu cu o 0 a co 0 k a E % co a as « @' 0 ■ a X c c - o » c) & q 0 . o ® Ca 0 2 .§ a a. U 2 o c. � � / � J CD 0 2 0 / k .0Z1 0 \ // C / co m m < « @ < I RECEIVED STATE OF ALASKA AIL OIL AND GAS CONSERVATION COM ION JUL 2 6 2016 REPORT OF SUNDRY WELL OPERATIONS AOGCC 1.Operations Abandon ❑ Plug Perforations El Fracture Stimulate ❑ Pull Tubing 0 Operations shutdown ❑ Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing❑ Change Approved Program 0 Plug for Redrill ❑ Perforate New Pool ❑ Repair Well El Re-enter Susp Well❑ Other: Install ESP/GL Combof 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development 0 Exploratory 0 191-139 3.Address: 3800 Centerpoint Drive,Suite 1400 StratigraphicD Service 0 6.API Number: Anchorage,AK 99503 50-733-20037-01 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0018730 Trading Bay Unit/G-01 RD 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&Hemlock Oil Pools 11.Present Well Condition Summary: Total Depth measured 11,506 feet Plugs measured N/A feet true vertical 9,946 feet Junk measured 11,337&11,409 feet Effective Depth measured 10,908 feet Packer measured N/A feet true vertical 9,431 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Structural Conductor 327' 26" 327' 327' Surface 2,160' 13-3/8" 2,160' 2,120' 3,090 psi 1,540 psi Intermediate 8,450' 9-5/8" 8,450' 7,319' 5,750 psi 3,090 psi Production 3,352' 7" 11,479' 9,921' 11,220 psi 8,530 psi Liner Perforation depth Measured depth 10,089-11,290 feet �p �y True Vertical depth 8,715-9,758 feet SCA�INE,0 O C i 3 . 2016 Tubing(size,grade,measured and true vertical depth) 4-1/2" - 12.6#/L-80 7,811'(MD) 6,774'(ND) 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: 134 214 3725 52 105 Subsequent to operation: 364 240 9721 131 148 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations 0 Exploratory❑ Development0 Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil 0 Gas ❑ WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR 0 WINJ 0 WAG ❑ GINJ 0 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: 316-179&316-332 0 IL Contact Trudi Hallett(907)777-8323 Email thallettCcDhilcorp.com Printed Name Stan W.Golis Title Operations Manager LJ Signature 't' i'"y�I`t--i /Phone (907)777-8356 Date 7/z 6 / )G Form 10-404 Revised 5/2015 �- RBDMS \ ., Jt)_ 2 9 2016 Submit Original Only McArthur River Field,TBU H i SCHEMATIC • Well: GO1RD , As Completed: 6/28/2016 n u• �i"k CASING DETAIL RKB to TBG Hngr=42.68' Size WT Grade Conn ID MD Top MD Btm Tree connection:3-112"EUE 8rd 26" Surf. 327' 13-3/8" 61 J-55 Butt _ Surf. 2,160' 47 N-80 Butt 8.681 Surf 79' J [L26' 40 N-80 Butt 8.835 79' 6,275' 0-5/B" 43.5 N-80 Butt 8.755 6,275' 8,179' 3-3/8" 47 N-80 Butt 8.681 8,179' 8,450' 1 9-5/8"DV Collar 4,903' 4,905' ill1 7" 29 P-110 Butt 6.184 8,127' 11,479' 2 TUBING DETAIL 4-1/2" I 12.6 I L-80 I IBT I 3.958 I Surface I 7,811' NOTE:H Window cut from 8,450'to 8,516'.Original 9-5/8"@ 8,994'MD(7,746'TVD) @ 3 Ill 4 Jewelry Details @ 5 No. Depth ID Item 1 2,567' 3.992 GLM 1 6 2 4,310' 3.992 GLM 7 3 5,535' 3.992 GLM 8 4 6,507' 3.992 _ GLM , j 9 5 7,379' 3.992 GIM 10 6 7,552' 3.992 GLM 11 17 7,811' Ported Pressure Sub 4-1/2"Discharge Adapter 12w/velocity fuse X X 8 7,813' -- Bolt-On Discharge 9 7,814' -- Pump(x2)675 Series 045 Stg SH12000 L .�9-5/8' 10 7,857' -- Intake 11 7,876' -- Motor(x2)562 Motor,KMSUT/KMSLT 500 HP 12 7,942' 3.992 Bottom of ESP _ PERFORATIONS 17= G-1 Zone Top MD Btm MD Top TVD Btm TVD Amt SPF Last Opr. Status - G-2 G-01 10,089' 10,120' 8,715' 8,742' 31' 5 01/16/14 Open 10,140' 10,170' 8,759' 8,785' 30' 6 2/19/1992 Open G-3 G-2 10,140' 10,170' 8'759' 8,785' 30' 5 10/27/12 Reperf G-4 G-3 10,225' 10,257' 8,833' 8,861' 32' 6 2/19/1992 Open 10,244' 10,264' 8,849' 8,867' 20' 5 10/27/12 Open = G-5 10,278' 10,340' 8,879' 8,933' 62' 6 2/19/1992 Open - G-6 G 4 10,280' 10,342' 8,881' 8,935' 62' 5 10/27/12 Open G 7 10,395' 10,415' 8,981' 8,999' 20' 6 2/19/1992 Open G-5 10,398' 10,418' 8,984' 9,001' 20' 5 10/27/12 Open 10,440' 10,460' 9,021' 9,038' 20' 5 10/27/12 Open G-6 10,532' 10,548' 9,101' 9,115' 16' 5 10/27/12 Open G-7 10,600 10,614' 9,161' 9,173' 14' 5 10/27/12 Open HB-1 10,622' 10,637' 9,180' 9,194' 15' 4 1/17/2001 Open HB-1 Open,frac'd HB-2 10,628' 10,670' 9,186' 9,223' 42' 10&16 8/26/1995 10,628'- HB-1 10,643' HB-3 10,628' 10,676' 9,186' 9,228' 48' 5 10/27/12 Open HB-4 HB-2 10,689' 10,718' 9,240' 9,265' 29' 5 01/16/14 Open HB-3 10,846' 10,860' 9,377' 9,389' 14' 5 10/27/12 Open HB-5 10,863' 11,000' 9,392' 9,509' 137' 6 2/19/1992 Open HB-6 •,•••••••••••••••••••••.-.- HB-4 10,939' 10,954' 9,457' 9,470' 15' 4 1/17/2001 Open 10,890' 11,006' 9,415' 9,515' 116' 5 10/27/12 Open HB-7 11,038' 11,048' 9,542' 9,550' 10' 4 1/17/2001 Open Fish @11337'....... HB-5 11,040' 11,070' 9,544' 9,569' 30' 8 8/26/1995 Open 11,042' 11,122' 9,545' 9,614' 80' 5 10/27/12 Open 11,155' 11,170' 9,642' 9,655' 15' 4 8/26/1995 Open •• •• \ HB-6 11,156' 11,240' 9,643' 9,715' 84' 5 10/27/12 Open RKB to MLLW ELEV=103' HB-7 11,255' 11,280' 9,728' 9,749' 25' 24 6/24/1994 Open TD=11,506' PBD=11,430' 11,266' 11,290' 9,737' 9,758' 24' 5 10/27/12 Open MAX HOLE ANGLE=39.10°@ 7225' 12/17/00:Left 10.14'long fish consisting of coil tubing motor and bit. 10/24/12: Cleaned out fill to 11337'DPM,Fish not recovered. 6/26/2016: Tagged fill/scale at 10,908'with S/L(3"bailer). Updated by: JLL 07/26/16 • 0 n. Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date G-01RD Moncla 404 50-733-20037-01 191-139 6/22/16 6/28/16 Daily Operations: 06/22/2016-Wednesday Continued laying out/rigging up misc W/O equip.Opened well on both sides to atmosphere. Removed pumpin spool from top of tree and NOS rep landed BPV. 1030 hrs worked M/V Titon bringing on riser, mud cross w/valves,double gate,annular,parts connex and Total Safety equipment. N/D tree. N/U 13 5/8"x 5M BOPE dressed w/2 7/8"x 5" variable pipe rams. Installed clamps and secured carrier to strong back beams. Raised derrick and secured with guy lines. Scoped out and leveled same,secured with guy lines. Positioned driller's shack, relocated accum and choke house, connected their lines. Pinned rig floor in place and began securing same. 06/23/2016-Thursday Finished modifying rig floor supports. Installed hand rails around rig floor.Centered up and secured BOP stack. Installed offside stairs to rig floor.Worked M/V Titon at 1130 hrs off loading,cutting boxes, Knight tools,tongs and power pack+ driller side walkways. Installed walkways and stairs to shack. Mounted steps from rig floor to deck,walkway to deck and driller's shack to walkway. Checked precharge on accum bottles/good. Mounted remote accum panel.Spotted tong power pack and R/U tongs on floor. Prep floor with handling tools. M/U 3 1/2"test jt w/4 1/2" blank ported sub w/x- overs on btm, pumpin,safety valve& IBOP on top. Filled stack and closed annular.Shell tested to 2500#s-working thru leaks. Pretested BOPE to 250 low/2500 high with slight consistent unlocated leak. Pulled BPV and installed 2-way check, test now holds. Pulled 2-way check and installed BPV(no pressure under 2-way check). Performed safety walk-thru checking all shackles and fire extinguishers, identifying potential hazards w/caution tap and general house keeping and organizing in prep for AOGCC rep. 06/24/2016-Friday Continued w/house keeping, organizing and safety walk-thru in prep for AOGCC inspector. Pulled BPV and set 2-way check, landed test jt and filled riser.Attempted to test BOPE as per Sundry but failed to hold pressure. Located problem in 2-way check finding a cut 0-ring, replaced same and reinstalled.Tested BOPE as per Sundry in accordance to AOGCC and Hilcorp guidelines to 250#s low/2500#s high.Tested w/3 1/2" &4 1/2"tb. Performed successful accum draw down test.Test witnessed by Lou Grimaldi,AOGCC. B/0 test jt and pull 2-way check,take off blank ported sub and screw into hgr, back out hold down pins.String came off hgr at 75k, pulled uphole 2'at 93k.Set slips and R/U circ lines LW. Pumped LW at 3 BPM 240 PSI to rig tank,got oily returns at 122 bbls pump("'3/4 returns.Generated NPFT form and sent 700 bbls returns to TBPF thru well clean tank. B/O pump line. Pulled hanger to surface and worked same.Changed elevators and slip inserts. R/U Summit to POOH w/ESP assy.Started POOH w/3 1/2"9.2#TC-Il production tb and ESP assy. Stopped at 0400 hrs to adjust brakes on draw works.COOH-20 jts out at report time=7,331'. 06/25/2016-Saturday continued POOH,w13.1-A19,Z#TC-11.p.roduction_strin w.L ESP asst'from 7,.331',Bumping 10 bbls every 20 jts(laying down tb). 1000 hrs changed out reda cable spools at 98 of 245 jts out(=4,853'). 1600 hrs held fire and abandon drill. Finished POOH to pump assy. Laid down ESP assembly,found holes in top pump and upper tandem motor was grounded. R/D Summit equipment.Cleared and cleaned rig floor. R/U Pollard SL w/full lubricator, made 5 trips in hole w/3" bailer. Bailed from 10,906'to 10,908' recovering 3 gals of scale and formation fines(minimual recovery on last three runs).Worked M/V Titan while running slickline, back loading old production string and ESP assy,Onloaded new ESP assembly and 4/2" 12.6#IBT production tb. . , • I Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date G-01RD Moncla 404 50-733-20037-01 191-139 6/22/16 6/28/16 Daily Operations: 06/26/2016-Sunday Finished R/D Pollard S/L. Prepped rig floor to run 4 1/2"tb. Ran in/racked back two stands of prod tb,received plan forward at 0852 hrs to RIH w/ESP assy. Prepped rig floor to run Summit ESP production assy in conjunction with gas lift capability.Assembled Summit dual 500 HP motors w/cent and gauge on btm (serviced motors w/oil). R/U sheaves in derrick w/cable and flatpack loaded. M/U lower&upper tandem seals,attached flatpack and reda cable, performed electrical checks. M/U intake, dual pumps,discharge, pressure sub,x-over and handling jt.TIH w/ESP assy picking up 4 1/2" 12.6#L-80 IBT& IBT Mod tubing off deck, rabbitting and torqueing to mark, checking cable every 1,000'. 130 of 239 jts in the hole at report time=4,256'. 06/27/2016-Monday Continued RIH w/Summit ESP+gas lift capability(SPM w/dummies Idd) picking up 4 1/2" 12.6#L-80 IBT tb singles off deck-from 4,256'to 7,896'. Made up hanger&landing jt, plumbed ESP penetrator and chemical lines. Landed hanger @ 83k w/EOT at 7,941.62'. Electrical tested good. NOS rep serviced hanger and ran in hold down pins. B/O L/D landing jt and set BPV. R/D Summit.Cleared and cleaned rig floor. R/D power tongs, removed handrails and stairs and floor supports, R/D floor. Pumped 100 bbls of NPF to TBPF thru water clean tank. Bled down accum unit,disconnected lines, scoped down and laid over derrick. Rolled up and loaded accum lines in basket. N/D BOPs. N/U tree. 06/28/2016-Tuesday Finished N/U tree.Tested hgr void 500#s f/5 mins and 5000#s f/15 mins. Pulled BPV and installed 2-way check,shell tested tree to 5000#s f/5 mins.Turned well over to production. • • • 1.,OF zo �* I//7,'� THE STATE Alaska Oil and Gas o f T sKA Conservation Commission 14 333 West Seventh Avenue 1 - C GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 �. O�-� Main: 907.279.1433 ALAS Fax: 907.276.7542 www.aogcc.alaska.gov Stan W. Golis Operations Manager /�{ s M p+e i *..1 Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: McArthur River Field, Middle Kenai G&Hemlock Oil Pools, TBU G-01RD Permit to Drill Number: 191-139 Sundry Number: 316-332 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, Cathye1/4/E(7 Foerster Chair DATED this 24y of June, 2016. RBDMS /AK A16 . RECEIVED STATE OF ALASKA HN 14 2016 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS /` �i/ b 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Repair Well LI Operations shutdown LI Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing 0 Change Approved Program III Plug for Redrill ❑ Perforate New Pool 0 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 LI • 191-139 ' 3.Address: 3800 Centerpoint Drive,Suite 1400Stratigraphic ❑ Service ❑ 6.API Number Anchorage,AK 99503 50-733-20037-01 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 11,/ Trading Bay Unit/G-01RD - 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0018730 ' McArthur River Field/Middle Kenai G&Hemlock 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): 11,506 9,946 • 11,337 • 9,798 , 2,425 psi N/A 11,409 Casing Length Size MD ND Burst Collapse Structural Conductor 327' 26" 327' 327' Surface 2,160' 13-3/8" 2,160' 2,120' 3,090 psi 1,540 psi Intermediate 8,450' 9-5/8" 8,450' 7,319' 5,750 psi 3,090 psi Production 3,352' 7" 11,479' 9,921' 11,220 psi 8,530 psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 10,089-11,290 . 8,715-9,758 3-1/2" 9.2#/L-80 7,945 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(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 LI Stratigraphic ❑ Development 0 • Service ❑ 14.Estimated Date for 15.Well Status after proposed work: 6/20/2016 Commencing Operations: 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. Contact Trudi Hallett(907)777-8323 Email thallett@hilcorp.com Printed Name Stan W.Golis Title Operations Manager 1- Signature t^' (T-4--; n i Phone (907)777-8356 Date ( I I COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: (._.c -332_ Plug Integrity ❑ BOP Test 4s Mechanical Integrity� Test [1 Location Clearance ❑ Other: ( '2--S—OC.) p i C')�-"s . (-7.7, S I Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No Subsequent Form Required: /Orf 0'4 RBDMS 0V JUN [ 4 2016 I / APPROVED BY Approved by: / M COMMISSIONER THE COMMISSION Date: - Z )6'-/t, r cI 'ill ,109// .-;, _ _ , , .. Ofif erliNAL SubForm ane Form 10-403 Revised 11/2015 I for 12 months from the date of approval. Attachmentss in Duplicate 41) Well Work Prognosis Well: G-01RD • Hilcorp Alaska,LLC Date: 06/14/16 Well Name: G-01RD API Number: 50-733-20037-01 Current Status: ESP Producer Leg: Leg#2 (NE corner) Estimated Start Date: June 20th, 2016 Rig: Moncla 404 Reg.Approval Req'd? 403 Date Reg. Approval Rec'vd: Regulatory Contact: Juanita Lovett(8332) Permit to Drill Number: 191-139 First Call Engineer: Trudi Hallett (907)-777-8323 (0) (907) 301-6657 (M) Second Call Engineer: Dan Marlowe (907) 283-1329 (0) (907) 398-9904 (M) Current Bottom Hole Pressure: - 3,500 psi @ 9,254' TVD (mid perf of 10,710' MD) Maximum Expected BHP: - 3,500 psi @ 9,254' TVD (mid perf of 10,710' MD) Max. Potential Surface Pressure: 2,425 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) Brief Well Summary G-01RD is a G-Zone and Hemlock Producer that was converted to and ESP from a dual string gas-lift completion in October 2012.The current ESP is experiencing down-hole pump issues with productivity falling off since December 2015. We plan to pull the current ESP completion and replace with new ESP equipment. Hilcorp will attempt a cleanout run to PB I"D @ 11,430'- if successful; will add new perforations within the West Foreland Oil Pool. Last Casing Pressure Test: October 24th 2012 at 9850' at 1,500 psig and charted for 30 minutes. *Please note changes in red with the following procedure to Approved Sundry 316-179. Procedure: 1. MIRU Moncla Rig 404. 2. Attempt to pump through ESP to circulate hydrocarbon off the well to production. If necessary, RU e-line and RIH to+/-7,850' and punch tubing. (Using FIW as workover fluid) 3. ND Wellhead, NU BOP and test to 250psi low/2,500psi high. (Note: Notify AOGCC 48 hours in advance of test to allow them to witness test). 4. POOH with tubing string and ESP pump laying down the same. a. PU 7" bit/scraper CO assembly. RIH to tag for fill or to PBTD @ 11,430'. '' b. POOH w/CO assy. RIH with guns and perforate well according the final perforation request. 5. PU, RIH with ESP completion. 6. Land ESP with the bottom of the assembly at+/-7,985'. 7. ND BOP, NU wellhead and test. 8. Turn well over to production. Attachments: 1. Current Wellbore Schematic 2. Current Wellhead Diagram 3. Proposed Wellbore Schematic 4. Proposed Wellhead Diagram (same as current) 5. BOP Drawing 6. Fluid/Flow Diagrams 7. Rolling BOP Test Procedures 8. RWO Sundry Change Form McArthur River Field,TBU H • SCHEMATIC • well: G-01RD As Completed: 04/06/15 Hilemu Alaska,LLC CASING DETAIL RKB to TBG Hngr=42.68' Size WT Grade Conn ID MD Top MD Btm Tree connection:3-1/2"EUE 8rd 26" Surf. 327' 13-3/8" 61 J-55 Butt Surf. 2,160' 47 N-80 Butt 8.681 Surf 79' J 6" 40 N-80 Butt 8.835 79' 6,275' 9 5/8 43.5 N-80 Butt 8.755 6,275' 8,179' L13-318" 47 N-80 Butt 8.681 8,179' 8,450' 9-5/8"DV Collar 4,903' 4,905' ' 7" 29 P-110 Butt 6.184 8,127' 11,479' TUBING DETAIL 3-1/2" I 9.2 I L-80 I TC-Il I 2.992 I Surface I 7,945' NOTE:H Window cut from 8,450'to 8,516'.Original 9-5/8"@ 8,994'MD(7,746'TVD) Jewelry Details No. Depth ID Item 1 7,945' - Discharge,Bolt-On 2 7,946' - Pump(x2)SH12000 -_ 1 3 7,991 - Seals 2 4 8,006' - Motor(x2)550 HP nua 3 5 8,062' - Centrilizer/Anode �_ 4 5 PERFORATIONS tr i Zone Top MD Btm MD Top TVD Btm TVD Amt SPF Last Opr. Status S,9-5/8" G-01 10,089' 10,120' 8,715' 8,742' 31' 5 01/16/14 Open 10,140' 10,170' 8,759' 8,785' 30' 6 2/19/1992 Open G-2 10,140' 10,170' 8'759' 8,785' 30' 5 10/27/12 Reperf 10,225' 10,257' 8,833' 8,861' 32' 6 2/19/1992 Open _ G 3 10,244' 10,264' 8,849' 8,867' 20' 5 10/27/12 Open G-1 _ 10,278' 10,340' 8,879' 8,933' 62' 6 2/19/1992 Open G-2 G-4 10,280' 10,342' 8,881' 8,935' 62' 5 10/27/12 Open G-3 10,395' 10,415' 8,981' 8,999' 20' 6 2/19/1992 Open G-5 10,398' 10,418' 8,984' 9,001' 20' 5 10/27/12 Open E G-4 10,440' 10,460' 9,021' 9,038' 20' 5 10/27/12 Open G-6 10,532' 10,548' 9,101' 9,115' 16' 5 10/27/12 Open G-5 G-7 10,600 10,614' 9,161' 9,173' 14' 5 10/27/12 Open G-6 1-1B-1 10,622' 10,637' 9,180' 9,194' 15' 4 1/17/2001 Open s G-7 Open,frac'd 10,628' 10,670' 9,186' 9,223' 42' 10&16 8/26/1995 10,628'- HB-1 10,643' 10,628' 10,676' 9,186' 9,228' 48' 5 10/27/12 Open HB-2 10,689' 10,718' 9,240' 9,265' 29' 5 01/16/14 Open HB 1 HB-3 10,846' 10,860' 9,377' 9,389' 14' 5 10/27/12 Open 10,863' 11,000' 9,392' 9,509' 137' 6 2/19/1992 Open HB-2 HB-4 10,939' 10,954' 9,457' 9,470' 15' 4 1/17/2001 Open HB-3 10,890' 11,006' 9,415' 9,515' 116' 5 10/27/12 Open 11,038' 11,048' 9,542' 9,550' 10' 4 1/17/2001 Open HB-4 HB-5 11,040' 11,070' 9,544' 9,569' 30' 8 8/26/1995 Open 11,042' 11,122' 9,545' 9,614' 80' 5 10/27/12 Open HB-5 11,155' 11,170' 9,642' 9,655' 15' 4 8/26/1995 Open HB-6 HB-6 11,156' 11,240' 9,643' 9,715' 84' 5 10/27/12 Open HB-7 HB-7 11,255' 11,280' 9,728' 9,749' 25' 24 6/24/1994 Open Fill cleaned out to 11337' 11,266' 11,290' 9,737' 9,758' 24' 5 10/27/12 Open SPM.Fish on top 7" .'.11,409' RKB to MLLW ELEV=103' 12/17/00:Left 10.14'long fish consisting of coil tubing motor and bit. TD=11,506' PBD=11,430' 10/24/12: Cleaned out fill to 11337'DPM,Fish not recovered. MAX HOLE ANGLE=39.10°@ 7225' Updated by: JLL 05/04/15 McArthur River Field,TBU PROPOSED Well: G-01RD As Completed: Future Hileer,,Alaska,LL(: • CASING DETAIL RKB to TBG Hngr=42.68' Size WT Grade Conn ID MD Top MD Btm Tree connection:3-1/2"EUE 8rd 26" Surf. 327' 13-3/8" 61 1-55 Butt Surf. 2,160' 47 N-80 Butt 8.681 Surf 79' -.I] �6" 40 N-80 Butt 8.835 79' 6,275' 9-5/8" 43.5 N-80 Butt 8.755 6,275' 8,179' 13-3/8" 47 N-80 Butt 8.681 8,179' 8,450' 9-5/8"DV Collar 4,903' 4,905' 1 7" 29 P-110 Butt 6.184 8,127' 11,479' TUBING DETAIL 3-1/2" I 9.2 I L-80 I TC-II I 2.992 I Surface I ±7,860' V NOTE:H Window cut from 8,450'to 8,516'.Original 9-5/8"@ 8,994'MD(7 46'TVD) V �' Jewelry De .ils / „ kb�, No. Depth ID Item .., 04., i. (00/ 1 1 r 1 ±7,985' Bottom of ESP ® 1 X PERF•'ATIONS Zone Top MD Btm MD Top TVD :tm TVD Amt SPF Last Opr. Status G 95/8' G-01 10,089' 10,120' 8,715' 8,742' 31' 5 01/16/14 Open 10,140' 10,170' 8,759' 8,785' 30' 6 2/19/1992 Open G-2 10,140' 10,170' 8'7 •' 8,785' 30' 5 10/27/12 Reperf 10,225' 10,257' :,:33' 8,861' 32' 6 2/19/1992 Open G-3- G-1 10,244' 10,264' 8,849' 8,867' 20' 5 10/27/12 Open _ 10,278' 10,340' 8,879' 8,933' 62' 6 2/19/1992 Open G-2 G-4 10,280' 10,342' 8,881' 8,935' 62' 5 10/27/12 Open = G-3 10,395' 10,4 ' 8,981' 8,999' 20' 6 2/19/1992 Open G-5 10,398' 10'18' 8,984' 9,001' 20' 5 10/27/12 Open G-4 10,440' 1,460' 9,021' 9,038' 20' 5 10/27/12 Open G-6 10,532' 10,548' 9,101' 9,115' 16' 5 10/27/12 Open G-5 G-7 10,600 10,614' 9,161' 9,173' 14' 5 10/27/12 Open G-6 HB-1 10,622' 10,637' 9,180' 9,194' 15' 4 1/17/2001 Open G-7 Open,frac'd 10,' 8' 10,670' 9,186' 9,223' 42' 10&16 8/26/1995 10,628'- HB-1 10,643' 0,628' 10,676' 9,186' 9,228' 48' 5 10/27/12 Open HB-2 10,689' 10,718' 9,240' 9,265' 29' 5 01/16/14 Open HB 1 HB-3 10,846' 10,860' 9,377' 9,389' 14' 5 10/27/12 Open 10,863' 11,000' 9,392' 9,509' 137' 6 2/19/1992 Open HB-2 H,-4 10,939' 10,954' 9,457' 9,470' 15' 4 1/17/2001 Open HB-3 10,890' 11,006' 9,415' 9,515' 116' 5 10/27/12 Open 11,038' 11,048' 9,542' 9,550' 10' 4 1/17/2001 Open HB-4 HB-5 11,040' 11,070' 9,544' 9,569' 30' 8 8/26/1995 Open 11,042' 11,122' 9,545' 9,614' 80' 5 10/27/12 Open - HB-5 11,155' 11,170' 9,642' 9,655' 15' 4 8/26/1995 Open HB-6 HB-6 11,156' 11,240' 9,643' 9,715' 84' 5 10/27/12 Open Fill cleaned out = HB-7 HB-7 11,255' 11,280' 9,728' 9,749' 25' 24 6/24/1994 Open to 11337'SPM. 11,266' 11,290' 9,737' 9,758' 24' 5 10/27/12 Open Fish on top ,., .eitio je WF ±11,310' ±11,420' ±9,775' ±9,871' ±110' Future Proposed 4-5/8"Perf `' Gun @ 11,409' '• d /RKB to MLLW ELEV=103' 12/17/00:Left 10.14'long fish consisting of coil tubing motor and bit. TD=11,506' PBD=11,430' 10/24/12: Cleaned out fill to 11337'DPM,Fish not recovered. MAX HOLE ANGLE=39.10°@ 7225' Updated by: JLL 06/14/16 0 s Grayling Platform . iiG-01rd Current 03/04/2016 Hilrnrp:UaMka.Lit Grayling Platform Tubing hanger,CIW-DCB-ESP, G-1rd 11 X 4'/:IBT lift and susp,w/ 13 3/8 X 9 5/8 X 3 1/2 4"type H BPV profile,5 Y.EN, 3-3/8 continuous control line ports,prepped for BIW penetrator BHTA,CIW,4 1/16 5M FE X Cameron internal blanking nut III aI• itiiiit III^151 Valve,swab,WKM-M, ® 4 1/16 5M FE,HWO, / 0 Cross,stdd,4 1/16 5M X Ed' O 3 1/8 SM X 2 1/16 SM T-24 ®' uI-11 uir,Valve,wing,WKM-M, 2 1/16 SM FE,HWO, 'F®�®�, '� 001 0 Valve,WKM-M,3 1/8 5M FE,w/ . T-24 0 I I; .I MA-16 operator �•rI^II I` ®® e � Valve,lower master,WKM-M, ®/ 4 ', 4 1/16 5M FE,HWO,T-24 ®®® bill .p iimim '•' '5� Adapter,CIW-Toadstool,11 5M Stdd X 4 1/16 5M FE,prepped for 5'4 EN neck,3-'/2 npt continuous lip-4m-_ control line ports,BIW penetrator Ell lip 'iport Tubing head,CIW-DCB, •—Imo`` 13 5/8 3M X 11 5M mni 1 I . II.- w/2-2 1/16 5M SSO, igi j— ITI X bottom I Valve,WKM-M,2 1/16 5M FE, HWO,DD® �_ I' folA ii■ �BIIN®.. Clty 2 III aI MBr Casing head, I, Shaffer KD, II 1 III 13 5/8 3M X 133/8SOW,w/2-2" f 6 LPO, UUI �al ;lI-I.:; 2"LP CIW ball valve Grayling Platform 2016 BOP Stack Moncla 03/04/2016 HiI n it:%luau.Lib fit II? Ill liiltl 4.54' • Hydril 411111113 GK 13 5/8-5000 Ili hii iii iii iii 27/8-ss Shaffer SL variables 2.83' v 13 5/8 SM _ Blinds Choke and Kill valves 2 1/16 5M _ r 1I1 III 1!1'41 111 I 7 2.26 T i ! r. P r i i ( y i i 1114 -4 it /S 440 = 111 ill (/1111 III ! 1!I 1!1'1!1111 iU Riser 135/85M FE X 135/85M FE 14.20' Iil Iii Iil Ill Iii III III III iii I!! 3.00' Spacer spool 135/85M X 135/85M 111 Ill 111 III i11 III Ili 111 1!I Spacer spool 2.75 135/85M FEX 115M Iii 1111 Iii Iib Iii O i a 0 0 u 0 u O O u O O u u O u O u u O D U 0 0 Cl. .'-' :7.4t-1 o • N M V in N M O 01 t0 N 00 01 2 0 2 2 2 2 2 2 2 2 2 u 22222 a a u u u u U u U U U o .-1 N M V 1l1 0 r1 N M V N t0 N 00 01 , -0 .0 -0 -0 -0 -0 -O V V V O 0 0 0 0 L u 0000000000 Y C 'E 'E C C 0) C C C C C C C C C C S L j gi' g10 j C N N N N N N N N O a o0a oc =c 0 o 0 Y 0 v Y Y Vn1 2 L > 112as _ YUtLLCLLLLLLUi :1 0'V y O O O. O O O 0 C U C L.00 0 H g7 111 -Abaft" G .1 t1 N 0) N . M . lA (O ow QZ �.. 1-..4-1 XLU Q a a0 r7 . a . ZO 0 U 2 U o O O Lii a tl d W UL H 0 _ s ilii 1644111111 NCLIC. .... 1 L4D [is CL d 111111 O Q CO F- w H a a III ❑ z H z U, o Z ~ w 0_ ow CO 0 1 _Icn . D — H a- b" r Z • O 1 Z Q O owQU Et U fY < 0 0 Z 0 U JJ > w D4 D4 _ O o2or 2 D r O w r JOZ > N) Q� � Z � � 000 Z Q 0 H J ❑ J U u_ E 0 C •O O V O V O 0000 0 ,.., V O V O u V O u V 0 0 O _ e♦ .-I N en t} 0 "'� eY N 01 a Vf to , 00 0T 2 m f f f 2 f 2 2 f 2 6 6 0_ d 0 V 0 V V V V V V V V o .Y N en O in 0) ei N 01 O N ID N 00 01 e-I V V V V 0 0 V V 0 V V V 0 V V V 0 0 t.0 _O O .0 N :S' 0 0 0 0 0 4?- _O y Y = = = = C "" 0) C C C C C C C C C C Y t > 0 2 2 2 2 C w - J 2 f f 2 2 2 2 2 2 2 5 0 > > EEEEE = w 0 0 0 0 0 0 0 0 0 0 0. 0 0 7 7 0 L L t t t L L L L L I i0 d o. 6 0_> X Y S V 0 U V V V V V V V U V to 2 H 6 V 0) Vili a 70 _Ne 0 .2 - O] 0, V T 00 O 2 u.irwa.rrr. 1/ 11 4k r _ OD _ - - II) _ (O _ 0 W Z z no.-■I ---.11-i a CLCe L1J a LLI a0 N) _ 't _ ZO 4k w 0 cc I 4 O ccI OJ b s lim...._ ne i# �"_ Y 6 ii iii O Q ml- Co wLJI d 1-U d ell 0 z a u) co Q J z O Z F-- w Z a ( z Q 0EL _,(nom 2 opZ U) < Q Q CC LU a z goo � o ,/o _ o2Z2 Joo Lo _ aN LLZp - 0m z O I I- Z o Q i D 0 Et U • • Moncla Rig 404 BOP Test Procedure �►��rp Alaska.1.1K. 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 Mewl)Alaska,LLCAttachment#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 15t 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 earor,,Alaska.LEA. #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. . • • � � cl a) C5. oco a 0 rts c 2E ao ° / < kg E < Ef 0 ' 2 0 E0 > @ § ƒ= CL c a a o.< a' - - - zo / � � - _oft AS > = :1-. \\ a ƒ / % / 01 -a ■ ■ 2 \ � ` � k k $ % a)>- 00 2W A / / @ 15 B TO; ti 0 / 2 Q a / Q. cL � � v-- $2 0 a C % § / a) & _o § 15. J§ < -C cp E E � / 3 M ® 2 k . 2 _ 2 t \ 0 g a) 2 co_ § //C a vi a Gp c LU a) TO @ ■ U o. 2 .4 o 0. ($ 0. V. .4 citle‘ L" ° a > o Ct. X o E o. 2 2 » e § & m ; ® o § q / k a) 2 3 x 7Ci 2 it v .. « _ 0 ELI -. a) / 0 & / a o co 2 k CO a. < 0_ • • , Schwartz, Guy L (DOA) From: Schwartz, Guy L(DOA) Sent: Thursday, June 23, 2016 10:23 AM To: 'Trudi Hallett' Subject: RE:G-01RD PTD 191-139 (Sundry 316-179) Trudi, Change to completion is approved. Last casing test was in 2012 so you are good there. Update the MOC as required. Guy Schwartz Sr. 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(Guy.schwartz@alaska.gov). From: Trudi Hallett {mailto:thallettOhilcorp.com] Sent: Thursday, June 23, 2016 7:59 AM To: Schwartz, Guy L (DOA) Subject: RE: G-01RD PTD 191-139 (Sundry 316-179) Guy—please find the attached updated proposed schematic for the change proposed below.We upsized the tbg since we added the gas lift portion.Thanks and have a great day. Trudi Hallett From: Trudi Hallett Sent: Monday, June 20, 2016 11:25 AM To: 'Schwartz, Guy L(DOA)' Cc: Juanita Lovett; Stan Golis Subject: RE: G-01RD PTD 191-139 (Sundry 316-179) Good Morning,Guy— Hilcorp has decided that the fishing/perf job proposed below is not economic with our current cost environment and has pulled the plug on that proposed program that was sent over via change of approved program last week. Please cancel this request. INSTEAD, Hilcorp wishes to make a quick SL tag and only make a cleanout run IF necessary to uncover Hemlock perforations.We will also be running a back-up gas lift string along with the ESP as a redundant system if and when this ESP decides to fail again. I have attached the newest proposed schematic and updated procedure. Please advise on how you would like us to proceed.Again,apologies for the changes—appreciate your patience. Thanks- 1 • • TruSi. From: Trudi Hallett Sent: Tuesday, June 14, 2016 4:06 PM To: 'Schwartz, Guy L (DOA)' Cc: Juanita Lovett; Stan Golis Subject: G-01RD PTD 191-139 (Sundry 316-179) Good Afternoon, Guy— Per our conversation, attached you will find the current approved sundry for the G-o1RD ESP change out as well as the Change to Approved Program. Courier has been dispatched to deliver this afternoon. Again,the plan is to begin rig MOB to the Grayling Platform on Monday,June zoth.We will pull the dead ESP, make a CO run and if successful will add new perk as stated on the change form.We will then run in with the new ESP. If you have any questions,please do not hesitate to contact me. Thanks- Trltioti. Trudi Hallett I Operations Engineer Cook Inlet Offshore Asset Team I Hilcorp Alaska,LLC Hilcorp A Company Built on Energy thallett@hilcorp.com 0: 907.777.8323 C: 907.301.6657 2 0(- McArthur River Field,TBU H • PROPOSED I Well: G-01RD �i 1 As Completed: Future IIilroru Alaska,t.l.f. CASING DETAIL RKB to TBG Hngr=42.68' Size WT Grade Conn ID MD Top MD Btm Tree connection:3-1/2"EUE 8rd 26" Surf. 327' 13-3/8" 61 J-55 Butt Surf. 2,160' 47 N-80 Butt 8.681 Surf 79' .141 1..26" 4o N-80 Butt 8.835 6,275' 9-5/8" 43.5 N-80 Butt 8.755 6,275' 8,179' 13-3/8" 47 N-80 Butt 8.681 8,179' 8,450' 1 9-5/8"DV Collar 4,903' 4,905' i ' 7" 29 P-110 Butt 6.184 8,127' 11,479' TUBING DETAIL 2 4-1/2" I 12.6 I L-80 I IBT I 3.958 l Surface 1 ±7,860' NOTE:H Window cut from 8,450'to 8,516'.Original 9-5/8"@ 8,994'MD(7,746'TVD) 3 4 Jewelry Details Alit i 5No. Depth ID Item 1 ±2,565' - GLM 6 2 ±4,305' - GLM al 3 ±5,535' - GLM 4 ±6,510' - GLM WE 5 ±7,395' - GLM 6 ±7,600' - GLM D 7 7 ±7,985' - Bottom of ESP r X ,S,9-5/8' PERFORATIONS Zone Top MD Btm MD Top ND Btm ND Amt SPF Last Opr. Status G-01 10,089' 10,120' 8,715' 8,742' 31' 5 01/16/14 Open =G-1 G-2 10,140' 10,170' 8,759' 8,785' 30' 6 2/19/1992 Open 10,140' 10,170' 8'759' 8,785' 30' 5 10/27/12 Reperf G-2 G-3 10,225' 10,257' 8,833' 8,861' 32' 6 2/19/1992 Open g. G-3 10,244' 10,264' 8,849' 8,867' 20' 5 10/27/12 Open 10,278' 10,340' 8,879' 8,933' 62' 6 2/19/1992 Open G-4 G-4 10,280' 10,342' 8,881' 8,935' 62' 5 10/27/12 Open 10,395' 10,415' 8,981' 8,999' 20' 6 2/19/1992 Open G-5 G-5 10,398' 10,418' 8,984' 9,001' 20' 5 10/27/12 Open G-6 10,440' 10,460' 9,021' 9,038' 20' 5 10/27/12 Open G-7 G-6 10,532' 10,548' 9,101' 9,115' 16' 5 10/27/12 Open G-7 10,600 10,614' 9,161' 9,173' 14' 5 10/27/12 Open HB-1 10,622' 10,637' 9,180' 9,194' 15' 4 1/17/2001 Open Open,frac'd 10,628' 10,670' 9,186' 9,223' 42' 10&16 8/26/1995 10,628'- HB-1 -HB-1 10,643' 10,628' 10,676' 9,186' 9,228' 48' 5 10/27/12 Open HB-2 HB-2 10,689' 10,718' 9,240' 9,265' 29' 5 01/16/14 Open HB-3 HB-3 10,846' 10,860' 9,377' 9,389' 14' 5 10/27/12 Open 10,863' 11,000' 9,392' 9,509' 137' 6 2/19/1992 Open HB-4 HB-4 10,939' 10,954' 9,457' 9,470' 15' 4 1/17/2001 Open 10,890' 11,006' 9,415' 9,515' 116' 5 10/27/12 Open HB-5 11,038' 11,048' 9,542' 9,550' 10' 4 1/17/2001 Open HB-6 HB-5 11,040' 11,070' 9,544' 9,569' 30' 8 8/26/1995 Open 1-18-7 11,042' 11,122' 9,545' 9,614' 80' 5 10/27/12 Open Fill cleaned out to 11337' HB-6 11,155' 11,170' 9,642' 9,655' 15' 4 8/26/1995 Open PM.Fish on top 11,156' 11,240' 9,643' 9,715' 84' 5 10/27/12 Open .•-0 11,255' 11,280' 9,728' 9,749' 25' 24 6/24/1994 Open .•a-s/e-PerfGun @ HB-7 11,266' 11,290' 9,737' 9,758' 24' 5 10/27/12 Open ••u.ao9' U/� Avo RKB to MLLW ELEV=103' TO=11,506' PBD=11,430' MAX HOLE ANGLE=39.10"@ 7225' 12/17/00:Left 10.14'long fish consisting of coil tubing motor and bit. 10/24/12: Cleaned out fill to 11337'DPM,Fish not recovered. Updated by: JLL 06/20/16 • SOF rit, • • Iy7:cs. THE STATE Alaska Oil and Gas of Conservation Commission ____ ALASKA. r2_ - 333 West Seventh Avenue C GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 OFA ,i" Main: 907.279.1433 ALAS Fax: 907.276.7542 www.aogcc.alaska.gov Stan W. Golis V 'w Operations Manager C Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 Anchorage,AK 99503 Re: McArthur River Field, Middle Kenai G and Hemlock Oil Pools, TBU G-01 RD Permit to Drill Number: 191-139 Sundry Number: 316-179 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, aitt t 4 Cathy . Foerster ,, Chair DATED this iti?"day of March, 2016. RBDMS tv MAR 1 1 2016 • • RECEIVED STATE OF ALASKA MAR 0 4 2016 ALASKA OIL AND GAS CONSERVATION COMMISSION f -r5 -51/0 //6, APPLICATION FOR SUNDRY APPROVALS 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❑ 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 • 191-139 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number Anchorage,AK 99503 50-733-20037-01 - 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 CI / Trading Bay Unit/G-01RD - 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0018730 • McArthur River Field/Middle Kenai G&Hemlock 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): . 11,506 s 9,946 - 11,337 , 9,798 2,425 psi N/A 11,409 Casing Length Size MD TVD Burst Collapse Structural Conductor 327' 26" 327' 327' Surface 2,160' 13-3/8" 2,160' 2,120' 3,090 psi 1,540 psi Intermediate 8,450' 9-5/8" 8,450' 7,319' 5,750 psi 3,090 psi Production 3,352' 7" 11,479' 9,921' 11,220 psi 8,530 psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 10,089-11,290 ` 8,715-9,758 3-1/2" 9.2#/L-80 7,945 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(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 El Exploratory LI Stratigraphic Cl Development 2 - Service ❑ 14.Estimated Date for 15.Well Status after proposed work: 4/1/2016 Commencing Operations: OIL CI ' 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. Contact Trudi Hallett(907)777-8323 Email thallette.hilcorp.com Printed Name Stan W.Golis Title Operations Manager Signature L.3/-20-C Phone (907)777-8356 Date 3( 4 1 I to COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Le — l-7 9 Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance CI Other: fc2o .c .. m...__. Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No l ' Subsequent Form Required: /D—y()y RBDMS VV' MAR 1 1 2016 APPROVED BY Approved by: (u "`.1 , COMMISSIONER THE COMMISSION Date: ?—(0.—/ U K 1.„--(Li. G Subs in Form and Form 10-403 Revised 11/2015 ��444�p�� i t i lid for 12 months from the date of approval. Attachments in Duplicate • • Well Work Prognosis Well: G-01RD Hilcorp Alaska,LLC Date: 03/04/16 Well Name: G-01RD API Number: 50-733-20037-01 Current Status: ESP Producer Leg: Leg#2 (NE corner) Estimated Start Date: April 1, 2016 Rig: Moncla 404 Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Juanita Lovett (8332) Permit to Drill Number: 191-139 First Call Engineer: Trudi Hallett (907)-777-8323 (0) (907) 301-6657 (M) Second Call Engineer: Dan Marlowe (907) 283-1329 (0) (907) 398-9904 (M) fd`l- Current Bottom Hole Pressure: — 3,500 psi @ 9,254' TVD (mid perf of 10,710' MD) 131" Maximum Expected BHP: — 3,500 psi @ 9,254' TVD (mid perf of 10,710' MD) Max. Potential Surface Pressure: 2,425 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) Brief Well Summary G-01RD is a G-Zone and Hemlock Producer that was converted to and ESP from a dual string gas-lift completion in October 2012. The current ESP is experiencing down-hole pump issues with productivity falling off since December 2015. We plan to pull the current ESP completion and replace with new ESP equipment. Last Casing Pressure Test: October 24th 2012 at 9850'at 1,500 psig and charted for 30 minutes. / (.- LJ/kic-- — Procedure: • �-t 1. MIRU Moncla Rig 404. tod'' 2. Attempt to pump through ESP to circulate hydrocarb off the well to production. If necessary, RU e-line and RIH to+/-7,850' and punch tubing. (Usin FIW as workover fluid) 3. ND Wellhead, NU BOP and test to 250psi low/2,500psi hi h. (Note: Notify AOGCC 48 hours in advance of test to allow them to witness test). L---4 ea;t(".� x.5 4. POOH with tubing string and ESP pump laying down the same. 5. PU, RIH with ESP completion. 6. Land ESP with the bottom of the assembly at+/-7,985'. 1 7. ND BOP, NU wellhead and test. A c'r 8. Turn well over to production. „;Ll- Attachments: 1. Current Wellbore Schematic 2. Current Wellhead Diagram 3. Proposed Wellbore Schematic (same as current) 4. Proposed Wellhead Diagram (same as current) 5. BOP Drawing 6. Fluid/Flow Diagrams 7. Rolling BOP Test Procedures 8. RWO Sundry Change Form McArthur River Field,TBU � SCHEMATIC � Well: G-01RD nil r ,�Ia kll.1.1.c As Completed: 04/06/15 CASING DETAIL RKB to TBG Hngr=42.68' Size WT Grade Conn ID MD Top MD Btm Tree connection:3-1/2"EUE 8rd 26" Surf. 327' r 13-3/8" 61 J-55 Butt Surf. 2,160' 1 ! 47 N-80 Butt 8.681 Surf 79' J 26" 40 N-80 Butt 8.835 79' 6,275' 9 5/8 43.5 N-80 Butt 8.755 6,275' 8,179' 13-3/8" 47 N-80 Butt 8.681 8,179' 8,450' 9-5/8"DV Collar 4,903' 4,905' I 7" 29 P-110 Butt 6.184 8,127' 11,479' TUBING DETAIL 3-1/2" I 9.2 I L-80 1 TC-Il I 2.992 1 Surface 1 7,945' NOTE:H Window cut from 8,450'to 8,516'.Original 9-5/8"@ 8,994'MD(7,746'TVD) Jewelry Details_ No. Depth ID Item 1 7,945' - Discharge,Bolt-On 2 7,946' - Pump(x2)SH12000 1 3 7,991 - Seals 12 4 8,006' - Motor(x2)550 HP 3 5 8,062' - Centrilizer/Anode 4---i4 t, 5 x PERFORATIONS L� Zone Top MD Btm MD Top TVD Btm TVD Amt SPF Last Opr. Status L 19-5/8" G-01 10,089' 10,120' 8,715' 8,742' 31' 5 01/16/14 Open 10,140' 10,170' 8,759' 8,785' 30' 6 2/19/1992 Open G-2 10,140' 10,170' 8'759' 8,785' 30' 5 10/27/12 Reperf 10,225' 10,257' 8,833' 8,861' 32' 6 2/19/1992 Open G-3 = G-1 10,244' 10,264' 8,849' 8,867' 20' 5 10/27/12 Open _ 10,278' 10,340' 8,879' 8,933' 62' 6 2/19/1992 Open G-2 G-4 10,280' 10,342' 8,881' 8,935' 62' 5 10/27/12 Open G-3 10,395' 10,415' 8,981' 8,999' 20' 6 2/19/1992 . Open 0-5 10,398' 10,418' 8,984' 9,001' 20' 5 10/27/12 Open G-4 10,440' 10,460' 9,021' 9,038' 20' 5 10/27/12_ Open G-6 10,532' 10,548' 9,101' 9,115' 16' 5 10/27/12 Open 0-5 0-7 10,600 10,614' 9,161' 9,173' 14' 5 10/27/12 _ Open 0-6 HB-1 10,622' 10,637' 9,180' 9,194' 15' 4 1/17/2001 Open G-7 Open,frac'd 10,628' 10,670' 9,186' 9,223' 42' 10&16 8/26/1995 10,628'- HB-1 10,643' 10,628' 10,676' 9,186' 9,228' 48' 5 10/27/12 Open HB-2 10,689' 10,718' 9,240' 9,265' 29' 5 01/16/14 Open HB-1 HB-3 10,846' 10,860' 9,377' 9,389' 14' 5 10/27/12 Open 10,863' 11,000' 9,392' 9,509' 137' 6 2/19/1992 . Open HB-2 HB-4 10,939' 10,954' 9,457' 9,470' 15' 4 1/17/2001Open HB-3 10,890' 11,006' 9,415' 9,515' 116' 5 10/27/12 . Open 11,038' 11,048' 9,542' 9,550' 10' 4 1/17/2001 Open H• B-4 HB-5 11,040' 11,070' 9,544' 9,569' 30' 8 8/26/1995 Open 11,042' 11,122' 9,545' 9,614' 80' 5 10/27/12 Open H• B-5 11,155' 11,170' 9,642' 9,655' 15' 4 8/26/1995 Open HB-6 HB-6 11,156' 11,240' 9,643' 9,715' 84' 5 10/27/12 Open H• B-711,255' 11,280' 9,728' 9,749' 25' 24 6/24/1994 Open HB 7 11,266' 11,290' 9,737' 9,758' 24' 5 10/27/12 Open y4 Fill cleaned out to 11337' Ej+ SPM.Fish on top .N7:'.., 4-5/8"Pert Gun@ 7" .•..•.•.•.•.'.11,409' RKB to MLLW ELEV=103' 12/17/00:Left 10.14'long fish consisting of coil tubing motor and bit. TD=11,506' PBD=11,430' 10/24/12: Cleaned out fill to 11337'DPM,Fish not recovered. MAX HOLE ANGLE=39.10°@ 7225' Updated by: JLL 05/04/15 PROPOSED • McArthur River Field,TBU • Well: G-01RD As Completed: Future ['aeon,Alaska,1.1.1: CASING DETAIL RKB to TBG Hngr=42.68' Size WT Grade Conn ID MD Top MD Btm Tree connection:3-1/2"EUE 8rd 26" Surf. 327' 193;88; 3-3/8" 61 J-55 Butt Surf. 2,160' 47 N-80 Butt 8.681 Surf 79' 26" 40 N-80 Butt 8.835 79' 6,275' 9 5/8 43.5 N-80 Butt 8.755 6,275' 8,179' 13-3/8" 47 N-80 Butt 8.681 8,179' 8,450' 9-5/8"DV Collar 4,903' 4,905' 1 7" 29 P-110 Butt 6.184 8,127' 11,479' TUBING DETAIL 3-1/2" I 9.2 I L-80 I TC-II I 2.992 I Surface I ±7,860' NOTE:H Window cut from 8,450'to 8,516'.Original 9-5/8"@ 8,994'MD(7,746'TVD) Jewelry Details No. Depth ID Item r--'-'iI 1 ±7,985' Bottom of ESP CI 1 X PERFORATIONS Zone Top MD Btm MD Top TVD Btm TVD Amt SPF Last Opr. Status �s-5/s" G-01 10,089' 10,120' 8,715' 8,742' 31' 5 01/16/14 Open 10,140' 10,170' 8,759' 8,785' 30' 6 2/19/1992 Open G-2 10,140' 10,170' 8'759' 8,785' 30' 5 10/27/12 Reperf 10,225' 10,257' 8,833' 8,861' 32' 6 2/19/1992 Open G-3 10,244' 10,264' 8,849' 8,867' 20' 5 10/27/12 Open 10,278' 10,340' 8,879' 8,933' 62' 6 2/19/1992 Open ==-- G-2 G-4 10,280' 10,342' 8,881' 8,935' 62' 5 10/27/12 Open G-3 10,395' 10,415' 8,981' 8,999' . 20' 6 2/19/1992 Open G-5 10,398' 10,418' 8,984' 9,001' 20' 5 10/27/12 Open G-4 10,440' 10,460' 9,021' 9,038' 20' 5 10/27/12 Open G-6 10,532' 10,548' 9,101' 9,115' 16' 5 10/27/12 Open - G-5 G-7 10,600 10,614' 9,161' 9,173' 14' 5 10/27/12 Open G-6 HB-1 10,622' 10,637' 9,180' 9,194' 15' 4 1/17/2001 Open G-7 Open,frac'd 10,628' 10,670' 9,186' 9,223' 42' 10&16 8/26/1995 10,628'- HB-1 10,643' 10,628' 10,676' 9,186' 9,228' 48' 5 10/27/12 Open HB-2 10,689' 10,718' 9,240' 9,265' 29' 5 01/16/14 Open HB-1 HB-3 10,846' 10,860' 9,377' 9,389' - 14' 5 10/27/12 Open 10,863' 11,000' 9,392' 9,509' 137' 6 2/19/1992 Open _ _ - HB-2 HB-4 10,939' 10,954' 9,457' 9,470' 15' 4 1/17/2001 Open HB-3 10,890' 11,006' 9,415' 9,515' 116' 5 10/27/12 Open 11,038' 11,048' 9,542' 9,550' 10' 4 1/17/2001 Open HB-4 HB-5 11,040' 11,070' 9,544' 9,569' _ 30' 8 8/26/1995 Open 11,042' 11,122' 9,545' 9,614' 80' 5 10/27/12 Open HB-5 11,155' 11,170' 9,642' 9,655' 15' 4 8/26/1995 Open - HB-6 HB-6 11,156' 11,240' 9,643' 9,715' 84' 5 10/27/12 Open HB-711,255' 11,280' 9,728' 9,749' 25' 24 6/24/1994 Open HB 7 11,266' 11,290' 9,737' 9,758' 24' 5 10/27/12 Open I ,ti Fill cleaned out to 11337' - - .1" SPM. Fish on top 7" .•.•.•.•.•.•.•.•.'.11,409' RKB to MLLW ELEV=103' 12/17/00:Left 10.14'long fish consisting of coil tubing motor and bit. TD=11,506' PBD=11,430' 10/24/12: Cleaned out fill to 11337'DPM,Fish not recovered. MAX HOLE ANGLE=39.10°@ 7225' .._ Updated by: JLL 03/03/16 • •, II Grayling Platform G-01rd Current 03/04/2016 llilMvp ktaska.ILIA: Grayling Platform Tubing hanger,CIW-DCB-ESP, G-1rd 11 X 4)4 IBT lift and susp,w/ 13 3/8 X 9 5/8 X 3 1/2 4"type H BPV profile,5 34 EN, 3-3/8 continuous control line ports,prepped for BIW penetrator BHTA,CIW,41/16 5M FE X Cameron internal blanking nut ul •I 1111 11111.. iimiir el—Iwo nl Valve,swab,WKM-M, • ®® Cross,stdd,4 1/16 5M X 4 1/16 5M FE,HWO, T-24 3 1/8 5M X 2 1/16 5M 1:0 1.1 MINI III Valve,wing,WKM-M, K-f® '01 ft 0)0Er O Valve,WKM-M,3 1/8 5M FE,w/\......, . 5M FE,HWO, . e��i T-24 Al MA-16 operator M . , '4 ,j(• If 1 p l U 14v - Valve,lower master,WKM-M, o 4 1/16 5M FE,HWO,T-24 ®®• Milt III 1• 1 Adapter,CIW-Toadstool, 11 5M Stdd X 4 1/16 5M FE,prepped for 5''/EN neck,3-'/2 npt continuous 1' - control line ports,BIW penetrator v port Tubing head,CIW-DCB, o w.� , 13 5/8 3M X 11 SM .ail I ■= w/2-2 1/16 5M SSO, ree s I i L ,n X bottom Valve,WKM-M,2 1/16 5M FE, ri' 41 0 HWO,DD ii,,, S ,l®�I' \ 1■ 4(�®11� 'r 1.:; Qty 2 III i.l Casing head, _ Shaffer KD, Itl '— III 135/83MX 133/8 SOW,w/2-2" i LPO, 10 I @ ,Ill-1•; 2"LP CIW ball valve 0 • Grayling Platform 2016 BOP Stack Moncla niIrnrls ii,��ka�.LK03/04/2016 4.54' 0 0 s i f i fffi I tl fffr z 7/8-5.5Shaffer SL variables Cilik—/-1 * i V 4t 2.83' �• r• 13 5/8 SM Blinds / Choke and Kill valves 2 1/16 5M III i n Illi Uri 14 o 7 iii 111,',jj ''',9, 2.26 i I' •,,'M�■ , iii ' x riff, � i1,' 1 �Mil 'Valli! III 11111'—^— r 1 Milli' if I Riser 13 5/8 5M FEX 13 5/8 5M FE 14.20' III III 1111111 I I#I 11101 III III 3.00' Spacer spool 13 5/8 5M X13 5/8 5M iii iii lii lii III Spacer spool T v IUJ till T 2'75' 13 5/8 5M FE X 11 5M C •V • - O(] O V O V Q O V � 0 V � V O V V O V V O • a o N 01 V 01 .---7 N T V 01 CO I, 00 01 2 5 5 5 2 5 02 2 2 2 2 2 2 2 2 u O_ O. 1 0. 0. U U V U 0 U U 0 U O - N 01 0) in 0 - N 01 a N CO N CO Ol rl V V 'O 0 9 0 V -0 V V -0 V .0 0 V V O 0000 U NC w _O O O O O O Y 0! C E C C C -- (0 C C C C C C C C C t 55222 0) w -' J 2 2 2 2 2 2 2 2 2 2 5 m >> W• EEEEE p_ O_ C C j Y 0 Y 0 . Y Y Y Y Y Y N J Y E E E -' cc0 0 0 0 0 0 0 0 0 0 0 0. m ,°�' N 0 J J J J7 = 0 -c L L L L L L L L L L 0 A > O. O. O. O_ d Y X 2 U V V V V U V V V V V V1 5 V1 nv w � .Q w 0 0 10 G c LL m N V . 00 0 V, 2 li z - 1/ 11 4k N - - In (O . U �---a I 11-7 Z z 1 ■ a O 0 In . 't Z 0 (0U 2U K O CCw o as �> J 10 => 1 111 p1la. i d ElilLi aU 0 < m F U) w a lel LJI Q.- all a z z 0 0 Z ~ w v — z CO H of aLi � � H II a_ Z z Q L O co H Z Q Q Q (n D • ❑• W U f Qo > ° J O J > W 1111 /1 Qou, o ❑ ❑ f� c9W r'� _ Ozw NDu_ z I m z Q = F-J a U U_/ U C • O '= D O u 0 0 0 O O u 0 O u O v O u u 0 u u 0 0 O N 2 2 2 2 2 v u O. a a a a O D U U U U U U U 0 IN COCrto 0 ,1 IN m a In is n CO 01 '0 V V a V 0 -0 -0 tv 9 U -oa 'O Ut 'O O O O O O L 0 0 0 0 0 0 0 0 0 0 Y C C C C 1.) y C C C C C C C C C C t L C ] 0 o. a a E n < < > y 000000000) 0 E E EE E m o 0 0 0 0 0 0 0 0 0 o a A _0 r. J J J J J = U L L L t t t .0 L L L L 0 M a a a a a Y Y = U U U U U U U U U V U IA C 14 0. 73.7) y O O _ O u N C S N U m O Ng 110 C I II N O) qk I', 00 . 4k 1.0 . (0 . 4k U w 2 Z 1 •I a J CK LU a a0 N) , •Ct . ZO U> U C O CaI O b (/ 11 ilii 043. 110.• 1 Elillj O Q CO I- CO CO w HCL a 0 Z Q U) CO Q J z Z O Z ~ w 0 k Q o a I J C0 Li Z _ n o f 0 U } Q Q j QoEt ILI om0 J J D J 4 N _ 0 Q 2 Z = 2 > i r' J ON w a L.L Z a r� 1n a O 0 O Z m Q o 1- Z p O J J D 0 CC 0 • • Moncla Rig 404 BOP Test Procedure Hilcorp 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.) • • Moncla Rig 404 BOP Test Procedure flaeorp Alaska,UK, #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 15`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 Haeurp Alaska,LLCAttachment#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. • ill � � a / > � 2 0 a Q _ e >o § 2 E 0 �U2 § ka« Ef - 0 S � )U) Isn m % o e \ 2 f E a R a » - . .. = 0 CA / _0 X � >,.To = I Ate > . � .- g7 / .u) es -0 0 ■ 3 \ o ,_ z k k $ c cy>" Co 2W x / / • 0 tl k o6 Z. §sz a cokO x 244 \k x g� X » % C a) 0 & . O § J 7 <.a 144 E § / 0 = ® O 2 0 ' 2 a / L. t'' .§ / ZS § C »7 \ / / E. 2 Jp 2 W > 2 0 (a@ 2 § � § 1-4 0 0. Em a.c as « @ > 0 a. Q. U) X E 0 c © 2 e ca e0 m .0 a o k < § 0 . 4.4 § e a) 2 � q x 7 £ < u0 Ell .. © © .0 ¢ $ E 0 t. ° / / 2 o CU & 21 0 2 2 CO< a STATE OF ALASKA AL -...KA OIL AND GAS CONSERVATION COM,...JSION REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon ❑ Repair Well 0 Plug Perforations ❑ Perforate ❑ Other 0 Replaced ESP Performed: Alter Casing ❑ Pull Tubing0 Stimulate-Frac Cl Waiver ❑ Time Extension❑ Change Approved Program ❑ Operat.Shutdown❑ Stimulate-Other ❑ Re-enter Suspended Well❑ 4.Well Class Before Work: 5.Permit to Drill Nu er 2.Operator -- " TED ;� 6 . Name: Development El Exploratory❑ 191-139 'i ; tk. Hilcorp Alaska,LLC 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic❑ Service ❑ 6.API Number: Ml'!l 0 4 2015 Anchorage,AK 99503 50-733-20037-01 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0018730 Trading Bay Unit/G-01 RD A. • CC 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): McArthur River Field/Middle Kenai G&Hemlock Oil Pools 11.Present Well Condition Summary: Total Depth measured 11,506 feet Plugs measured N/A feet true vertical 9,946 feet Junk measured 11,409' feet Effective Depth measured 11,430 feet Packer measured N/A feet true vertical 9,879 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Structural Conductor 327' 26" 327' 327' Surface 2,113' 13-3/8" 2,160' 2,120' 3,090 psi 1,540 psi Intermediate 8,450' 9-5/8" 8,450' 7,319' 5,750 psi 3,090 psi Production 3,352' 7" 11,479' 9,921' 11,220 psi 8,530 psi Liner Perforation depth Measured depth See Schematic feet SCANNED MA" 2 0 LG'Iti True Vertical depth See Schematic feet Tubing(size,grade,measured and true vertical depth) 3-1/2" 9.2# L-80 7,945'(MD) 6,887'(ND) Packers and SSSV(type,measured and true vertical depth) Packer- N/A SSSV-NA 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: 304 111 6,735 112 110 Subsequent to operation: 315 213 7,605 113 140 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 El 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: 315-173 Contact Dan Taylor Email dtaylor@hilcorp.com Printed Name Dan Ta : Title Operations Engineer i Signature Phone 907 777-8319 Date 5/4/2015 Form 10-404 Revised 10/2012 -?,/?, ` , RBDMa mit prA naQnly15 McArthur River Field,TBU • H SCHEMATICWell: G-01RD Hileoq Ala.ke.l.l,f. As Completed: 04/06/15 CASING DETAIL RKB to TBG Hngr=42.68' Size WT Grade Conn ID MD Top MD Btm Tree connection:3-1/2"EUE 8rd 26" Surf. 327' 13-3/8" 61 J-55 _ Butt Surf. 2160' 47 N-80 Butt 8.681 Surf 79' JL40 N-80 Butt 8.835 6275' • 9-5/8" 43.5 N-80 Butt 8.755 6275' 8179' 13-3/8" 47 N-80 Butt 8.681 8179' 8,450' 9-5/8"DV Collar 4903' 4905' I 7" 29 P-110 Butt 6.184 8127' 11,479' I I TUBING DETAIL 3-1/2" I 9.2 I L-80 I TC-II I 2.992 I Surface I 7,945' NOTE:H Window cut from 8,450'to 8,516'.Original 9-5/8"@ 8,994'MD(7,746'TVD) Jewelry Details No. Depth ID Item 1 7,945' - _ Discharge,Bolt-On 2 7,946' - Pump(x2)SH12000 I 1 3 7,991 - Seals 1 2 4 8,006' Motor(x2)550 HP 3 5 8,062' - Centrilizer/Anode 4 El 5 ® PERFORATIONS dr Zone Top MD Btm MD Top TVD Btm TVD Amt SPF Last Opr. Status �9-5/e" G-01 10,089' 10,120' 8,715' 8,742' 31' 5 01/16/14 Open G-2 10,140' 10,170' 8,759' 8,785' 30' 6 2/19/1992 Open 10,140' 10,170' 8'759' 8,785' 30' 5 10/27/12 Reperf 10,225' 10,257' 8,833' 8,861' 32' 6 2/19/1992 Open G-3 10,244' 10,264' 8,849' 8,867' 20' 5 10/27/12 Open G-1 _ 10,278' 10,340' 8,879' 8,933' 62' 6 2/19/1992 Open G-2 G-4 10,280' 10,342' 8,881' 8,935' 62' 5 10/27/12 Open G-3 10,395' 10,415' 8,981' 8,999' 20' 6 2/19/1992 Open G-5 10,398' 10,418' 8,984' 9,001' 20' 5 10/27/12 Open G-4 10,440' 10,460' 9,021' 9,038' 20' 5 10/27/12 Open G-6 10,532' 10,548' 9,101' 9,115' 16' 5 10/27/12 Open G-5 G-7 10,600 10,614' 9,161' 9,173' 14' 5 10/27/12 Open G-6 HB-1 10,622' 10,637' 9,180' 9,194' 15' 4 1/17/2001 Open ET- G-7 Open,frac'd 10,628' 10,670' 9,186' 9,223' 42' 10&16 8/26/1995 10,628'- HB-1 10,643' 10,628' 10,676' 9,186' 9,228' 48' 5 10/27/12 Open HB-2 10,689' 10,718' 9,240' 9,265' 29' 5 01/16/14 Open HB 1 HB-3 10,846' 10,860' 9,377' 9,389' 14' 5 10/27/12 Open _ 10,863' 11,000' 9,392' 9,509' 137' 6 2/19/1992 Open HB-2 HB-4 10,939' 10,954' 9,457' 9,470' 15' 4 1/17/2001 Open HB-3 10,890' 11,006' 9,415' 9,515' 116' 5 10/27/12 Open 11,038' 11,048' 9,542' 9,550' 10' 4 1/17/2001 Open o HB-4 HB-5 11,040' 11,070' 9,544' 9,569' 30' 8 8/26/1995 Open HB-5 11,042' 11,122' 9,545' 9,614' 80' 5 10/27/12 Open 11,155' 11,170' 9,642' 9,655' 15' 4 8/26/1995 Open HB-6 HB-6 11,156' 11,240' 9,643' 9,715' 84' 5 10/27/12 Open HB-7 HB-7 11,255' 11,280' 9,728' 9,749' 25' 24 6/24/1994 Open Fill cleaned out to 11337' 11,266' 11,290' 9,737' 9,758' 24' 5 10/27/12 Open PM.Fish on top ..4-5/8"Perf Gun @ RKB to MLLW ELEV=103' 12/17/00:Left 10.14'long fish consisting of coil tubing motor and bit. TD=11,506' PBD=11,430' 10/24/12: Cleaned out fill to 11337'DPM,Fish not recovered. MAX HOLE ANGLE=39.10°@ 7225' Updated by: JLL 05/04/15 Hilcorp Alaska, LLC Ilileurp Alaska.IAA Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-01RD 50-733-20037-01 191-139 4/2/2015 4/6/2015 Daily Operations: 04/02/15-Thursday Set BPV,n/d tree,prep hanger,check lift threads on hanger,good. M/u 2'spool t/riser&n/u riser. N/U BOP. Install scaffold around BOP stack. 04/03/15-Friday R/u accumulator lines.Setup BOP scaffolding,installed flow nipple&flow line. R/u drain lines. Installed flow line t/gas-buster. R/u test pump. Unload&back load boat.Test PVT system. Back load Boat. M/u 3 1/2 test jt,fill stack&valve manifolds w/water.Shell test t/2500 had leak on riser. Bleed off,re-tq flange,good. Test BOPE as per Hilcorp&AOGCC regulations.Witness waived by AOGCC Jim Regg @ 17:40 on 3-31-15.Tested w/3 1/2 test jt, 250 low,2500 high. Break down test jt. M/u safety valve. M/u landing jt.Stock floor w/pulling equip. Pull hanger @ 95k.Cont.pull assembly dragging @125 steady out @ 120k. L/d hanger. L/d landing jt. Hung sheaves for cable&flat pack. Pull 3.5"9.2# tubing t/7,576'. 04/04/15-Saturday Cont. POOH standing_back 3.5"9.2# tubing,ti Bump,.1.1g dn wt 25kL/D jt w/discharge sub.&1 jt tubing. L/D 1-pump. Gas show @/TT. Monitor, no flow. R/U circulated 59 bbls fill hole.Cont circ 60 bbls.Shut down&monitor 15 min. No flow, no gas. Cont. Pull&I/d pump&motor assembly. Pulled 244 jts. L/D 157 clamps total,one clamp missing pin and bent,all others in good shape. Coil up remaining cable&r/d slobber hose.Prep spools&backload boat. Load cable spool&flat pack into spoolers. Run cable& inj.line over sheave t/floor&secured. P/U&serviced 2-7.25"motor's,gauge,centralizer/anode,tandem seal's. 04/05/15-Sunday _ Cont. pill ESP assembly&service.Test leads&gauge good, TIH w/3'"9.2 TC-II tubing t/4,984'. M/U Tq. 2300.Testing cap lines &cable every 1,000'. Swap out cable spools,fill hole, splice cable&test good. Cont.TIH w/TIH w/3'A"9.2 TC-II tubing t/8,016', testing every 1,000', up wt 112k,do 90k. P/U/M/U hanger&landing jt.Start making up penetrator splice. 04/06/15-Monday Cont. m/u penetrator splice&injection lines t/Hanger.Test same,good. Land Hanger w/umbilical cord t/penetrator.Test after landed,good. Run in 1/d pins, pack off hanger seal. L/D landing jt.Set BPV. Clean&clear floor. Removed floor panels.Cleaned H- beam&pulled. Installed hand rails,pulled flow nipple,washed false rotary beams.Cleaned drip pan&removed.Cleaned BOP stack. R/d scaffolding&N/D BOP&riser. N/U tree,test void t/250&5000,good,install flow lines&wing valves,plug in power lead&test good. Break lines t/pits, pump,gas-buster,roll up electrical t/same. • V\°\17 Tk� $�w\�� s� THE STATE Alaska Oil and Gas i?, '�" �� OfALAs A Conservation Commission 17.-_-::-.1::-= z _ - 333 West Seventh Avenue Anchorage, Alaska 99501-3572 �� GOVERNOR BILL WALKER 9 *4' Main: 907.279.1433 OF*7;77-14. ALAS Fax: 907.276.7542 www.aogcc.alaska.gov Dan Marlowe SEED 'i '-':, 101 (, 09( Operations Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: McArthur River Field, Middle Kenai G and Hemlock Oil Pools, TBU G-01RD Sundry Number: 315-173 Dear Mr. Marlowe: 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, i , /7?2,64)7.7, Cathy P oerster Chair DATED this 3/ day of March, 2015 Encl. RECEIVED STATE OF ALASKA MAR 2 7 201 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOGCC 20_AAC 25280 JJ 1.Type of Request: Abandon I=1 Plug for Redril ❑ Perforate New Pod❑ Repair WeliC Change Approved Program❑ Suspend❑ Plug Perforations❑ Perforate❑ Pull Tubing ' Time Extension❑ Operations Shutdowi❑ Re-enter Susp.Wel❑ Stimulate❑ Alter Casin] Other: Replace ESP 0 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. Hilcorp Alaska,LLC Exploratory ❑ Development 0- 191-139 3.Address: Stratigraphic ❑ Service ❑ 6.API Number. 3800 Centerpoint Drive,Suite 1400,Anchorage,AK 99503 50-733-20037-01 • 7.If perforating: / 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? NA J Will planned perforations require a spacing exception? Yes ❑ No❑ Trading Bay Unit/G-01RD • 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0018730 • McArtur River Field/Middle Kenai G&Hemlock 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): 11,506 * 9,946 • 11,430 - 9,879 . N/A 11,409' Casing Length Size MD TVD Burst Collapse Structural Conductor 327' 26" 327' 327' Surface 2,113' 13-3/8" 2,160' 2,120' 3,090 psi 1,540 psi Intermediate 8,450' 9-5/8" 8,450' 7,319' 5,750 psi 3,090 psi Production 3,352' 7" 11,479' 9,921' 11,220 psi 8,530 psi Liner 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 7,912' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): N/A&N/A N/A&N/A •12.Attachments: Description Summary of Proposa 0 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch 0 Exploratory ❑ StratigrapHLl Development 0• Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 4/10/2015 Oil 0 • Gas ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned El Commission Representative: GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Dan Marlowe Email dmarlowe@hilcorp.com Printed Name Dan Marlowe Title Operations Engineer ,/ y tau.---, !'N,"r/t�uq— Signature `'?// n��' Phone (907)283-1329 Date 3/27/2015 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity ❑ BOP Test 10 Mechanical Integrity Test El Location Clearance ❑ Other: 5�) r., .6z,p /,,f` C m-S/tiT / Spacing Exception Required? Yes ❑ No Z Subsequent Form Required: J 6 t i oil D / APPROVED BY Approved by:P / COMMISSIONER THE COMMISSION Date: 3 ...3/15" ... 6,7 3 ,�7- 3/91/�s /YI3-3e�% Submit Fon and Form 10-403(Revised 10/2012) orRitiocittlspcif:12 months from the date of approval. N i 1 Attachments in Duplicate RBDMSci APR - 3 2015 Well Work Prognosis Well: G-01RD Hil[axp Alaska,IV: Date: 03/27/15 Well Name: G-01RD API Number: 50-733-20037-01 Current Status: ESP Producer Leg: Leg#2 (NE corner) Estimated Start Date: April 10, 2015 Rig: Moncla 301 Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Juanita Lovett (8332) Permit to Drill Number: 191-139 First Call Engineer: Dan Taylor (907)-777-8319 (0) (907)-947-8051 (M) Second Call Engineer: Dan Marlowe (907) 283-1329 (0) (907) 398-9904 (M) AFE Number: Budgeted Cost: Current Bottom Hole Pressure: —3,500 psi @ 9,254' TVD (mid perf of 10,710' MD) Maximum Expected BHP: —3,500 psi @ 9,254' TVD (mid perf of 10,710' MD) Max.Anticipated Surface Pressure: 0 psi (Using 0.435psi/ft. to surface) Brief Well Summary G-01RD is a G-Zone and Hemlock Producer that was converted to and ESP from a dual string gas-lift completion in October 2012. The ESP was replaced October 2013 and again January 2014. The current ESP experienced a down-hole electrical failure March 27, 2015. We plan to pull the current ESP completion and replace with identical equipment. Last Casing Pressure Test: October 24th 2012 at 9850' at 1,500 psig and charted for 30 minutes. Procedure: 1. MIRU Pulling Unit. 2. Attempt to pump through ESP to circulate hydrocarbon off the well to production. If necessary, RU e-line and RIH to+/-7,850' and punch tubing. 3. ND Wellhead, NU BOP and test to 250psi low/2,500psi high. (Note: Notify AOGCC 48 hours in advance of test to allow them to witness test). 4. POOH with tubing string and ESP pump laying down the same. 5. PU, RIH with ESP completion. 6. Land ESP with the bottom of the assembly at+/-7,985'. 7. ND BOP, NU wellhead and test. 8. Turn well over to production. Attachments: 1. Current Wellbore Schematic 2. Current Wellhead Diagram 3. Proposed Wellbore Schematic (same as current) 4. Proposed Wellhead Diagram (same as current) 5. BOP Drawing McArthur River Field,TBU SCHEMATIC Well: G01RD • HilcaryAluka•LLC As Completed: 02/18/14 CASING DETAIL RKB to TBG Hngr=42.68' Size WT Grade Conn ID MD Top MD Btm Tree connection:3-1/2"EUE 8rd 26" Surf. 327' 13-3/8" 61 1-55 Butt Surf. 2160' 47 N-80 Butt 8.681 Surf 79' J - 40 N-80 Butt 8.835 79' 6275' 9-5/8" 43.5 N-80 Butt 8.755 6275' 8179' 13-3/8" 47 N-80 Butt 8.681 8179' 8,450' 9-5/8"DV Collar 4903' 4905' 7" 29 P-110 Butt 6.184 8127' 11,479' TUBING DETAIL 3-1/2" I 9.2 I L-80 I TC-II I 2.992 I Surface I 7,912' NOTE:H Window cut from 8,450'to 8,516'.Original 9-5/8"@ 8,994'MD(7,746'TVD) Jewelry Details No. Depth ID Item 1 7,913' Discharge Head 2 7,915' Pump(x4) r 1 3 7,971' Pump Intake 2 4 8,003' Motor(x2) rte'3 5 8,075' Bottom of ESP Assembly 4 =5 PERFORATIONS Zone Top MD Btm MD Top TVD Btm TVD Amt SPF Last Opr. Status g-5/a° G-01 10,089' 10,120' 8,715' 8,742' 31' 5 01/16/14 Open 10,140' 10,170' 8,759' 8,785' 30' 6 2/19/1992 Open G-2 10,140' 10,170' 8'759' 8,785' 30' 5 10/27/12 Reperf 10,225' 10,257' 8,833' 8,861' 32' 6 2/19/1992 Open -1--- G-3 10,244' 10,264' 8,849' 8,867' 20' 5 10/27/12 Open G-1 p 10,278' 10,340' 8,879' 8,933' 62' 6 2/19/1992 Open G-2 G-4 10,280' 10,342' 8,881' 8,935' 62' 5 10/27/12 Open G-3 10,395' 10,415' 8,981' 8,999' 20' 6 2/19/1992 Open G-5 _ 10,398' 10,418' 8,984' 9,001' 20' 5 10/27/12 Open - G-4 10,440' 10,460' 9,021' 9,038' 20' 5 10/27/12 Open G-5 G-6 10,532' 10,548' 9,101' 9,115' 16' 5 10/27/12 Open 6-7 10,600 10,614' 9,161' 9,173' 14' 5 10/27/12 Open La G-6 HB-1 10,622' 10,637' 9,180' 9,194' 15' 4 1/17/2001 Open _ G-7 Open,frac'd 10,628' 10,670' 9,186' 9,223' 42' 10&16 8/26/1995 10,628'- HB-1 10,643' _____ 10,628' 10,676' 9,186' 9,228' 48' 5 10/27/12 Open HB-2 10,689' 10,718' 9,240' 9,265' 29' 5 01/16/14 Open - HB-1 HB-3 10,846' 10,860' 9,377' 9,389' 14' 5 10/27/12 Open 10,863' 11,000' 9,392' 9,509' 137' 6 2/19/1992 Open H• B-2 HB-4 10,939' 10,954' 9,457' 9,470' 15' 4 1/17/2001 Open HB-3 10,890' 11,006' 9,415' 9,515' 116' 5 10/27/12 Open 11,038' 11,048' 9,542' 9,550' 10' 4 1/17/2001 Open HB-4 HB-5 11,040' 11,070' 9,544' 9,569' 30' 8 8/26/1995 Open H• B-5 11,042' 11,122' 9,545' 9,614' 80' 5 10/27/12 Open 11,155' 11,170' 9,642' 9,655' 15' 4 8/26/1995 Open - HB-6 HB-6 11,156' 11,240' 9,643' 9,715' 84' 5 10/27/12 Open H• B-7 11,255' 11,280' 9,728' 9,749' 25' 24 6/24/1994 Open HB-7 11,266' 11,290' 9,737' 9,758' 24' 5 10/27/12 Open Fill cleaned out to 11337' ,_ SPM. Fish on top ••4-5/3"Pert Gun @ RKB to MLLW ELEV=103' 12/17/00:Left 10.14'long fish consisting of coil tubing motor and bit. TD=11,506' PBD=11,430' 10/24/12: Cleaned out fill to 11337'DPM,Fish not recovered. MAX HOLE ANGLE=39.10°@ 7225' Updated by: JLL 02/18/14 McArthur River Field,TBU H PROPOSED Well: G-01RD As Completed: Future • Ilileorp:11a.k.,1.1X CASING DETAIL RKB to TBG Hngr=42.68' Size WT Grade Conn ID MD Top MD Btm Tree connection:3-1/2"EUE 8rd 26" Surf. 327' 13-3/8" 61 1-55 Butt _ Surf. 2160' 47 N-80 Butt 8.681 Surf 79' J j L6" 40 N-80 Butt 8.835 79' 6275' 9-5/8" 43.5 N-80 Butt 8.755 6275' 8179' 133/8" 47 N-80 Butt 8.681 8179' 8,450' 9-5/8"DV Collar 4903' 4905' I 7" 29 P-110 Butt 6.184 8127' 11,479' TUBING DETAIL 3-1/2" I 9.2 I L-80 I TC-II I 2.992 I Surface I ±7,900' NOTE:H Window cut from 8,450'to 8,516'.Original 9-5/8"@ 8,994'MD(7,746'TVD) Jewelry Details No. Depth ID Item 1 ±8,075' Bottom of ESP Assembly '" 1 r . PERFORATIONS Zone Top MD Btm MD Top ND Btm TVD Amt SPF Last Opr. Status S69-5/8" G-01 10,089' 10,120' 8,715' 8,742' 31' 5 01/16/14 Open 10,140' 10,170' 8,759' 8,785' 30' 6 2/19/1992 Open G-2 10,140' 10,170' 8'759' 8,785' 30' 5 10/27/12 Reperf 10,225' 10,257' 8,833' 8,861' 32' 6 2/19/1992 Open G-3 G-1 10,244' 10,264' 8,849' 8,867' 20' 5 10/27/12 Open 10,278' 10,340' 8,879' 8,933' 62' 6 2/19/1992 Open G-2 G-4 10,280' 10,342' 8,881' 8,935' 62' 5 10/27/12 Open 0-3 10,395' 10,415' 8,981' 8,999' 20' 6 2/19/1992 Open G-5 10,398' 10,418' 8,984' 9,001' 20' 5 10/27/12 Open G-4 10,440' 10,460' 9,021' 9,038' 20' 5 10/27/12 Open G-6 10,532' 10,548' 9,101' 9,115' 16' 5 10/27/12 Open G-5 G-7 10,600 10,614' 9,161' 9,173' 14' 5 10/27/12 Open G-6 HB-1 10,622' 10,637' 9,180' 9,194' 15' 4 1/17/2001 Open G-7 Open,frac'd 10,628' 10,670' 9,186' 9,223' 42' 10&16 8/26/1995 10,628'- HB-1 10,643' 10,628' 10,676' 9,186' 9,228' 48' 5 10/27/12 Open HB-2 10,689' 10,718' 9,240' 9,265' 29' 5 01/16/14 Open HB 1 HB-3 10,846' 10,860' 9,377' 9,389' 14' 5 10/27/12 Open _ 10,863' 11,000' 9,392' 9,509' 137' 6 2/19/1992 Open HB-2 HB-4 10,939' 10,954' 9,457' 9,470' 15' 4 1/17/2001 Open HB-3 10,890' 11,006' 9,415' 9,515' 116' 5 10/27/12 Open 11,038' 11,048' 9,542' 9,550' 10' 4 1/17/2001 Open HB-4 HB-5 11,040' 11,070' 9,544' 9,569' 30' 8 8/26/1995 Open HB-5 11,042' 11,122' 9,545' 9,614' 80' 5 10/27/12 Open 11,155' 11,170' 9,642' 9,655' 15' 4 8/26/1995 Open o HB-611,156'11,156' 11,240' 9,643' 9,715' 84' 5 10/27/12 Open s HB-7 11,255' 11,280' 9,728' 9,749' 25' 24 6/24/1994 Open HB 7 11,266' 11,290' 9,737' 9,758' 24' 5 10/27/12 Open Fill cleaned out to 11337' PM. Fish on top .'4-5/8"Perf Gun @ RKB to MLLW ELEV=103' 12/17/00:Left 10.14'long fish consisting of coil tubing motor and bit. TD=11,506' PBD=11,430' 10/24/12: Cleaned out fill to 11337'DPM,Fish not recovered. MAX HOLE ANGLE=39.10"@ 7225' Updated by: JLL 03/27/15 Grayling Platform G-01rd Current 08/22/2012 H7kuT.%Ia.ka.LU. BHTA, CIW,4 1/16 5M FE X Grayling Platform Cameron internal blanking nut Tubing hanger, CIW-DCB- G-1 rd ESP, 11 X 4 1/2 IBT lift and 133/8X95/8X31/2 11111161W susp,w/4"type H BPV profile, 5' EN, 2-3/8 111 111 lei continuous control line ports, prepped for BIW penetrator Valve, swab,WKM-M, 0 p Cross, stdd,4 1/16 5M X 4 1/16 5M FE, HWO, 3 1/8 5M X 2 1/16 5M T-24 "C Is,111111s1 Valve,wing,WKM-M, rte,* o I' 'I 2 1/16 5M FE, HWO, o'.v1� 0 Valve,WKM M, p1/8 5M FE, T-24 1- 1 w/MA-16 operator SI PM 151 /e el0 Valve, lower master,WKM-M, atm( 0 7 4 1/16 5M FE, HWO,T-24 0$10 Is,C------2 Is, Adapter, CIW-Toadstool, 11 5M Stdd X 4 1/16 5M FE, prepped for 5' ESP neck, 2-1/2 npt continuous . control line ports Tubing head, CIW-DCB, ,_..3. . Grayling Platform . 11 BOP Stack(Moncla 301) tntr•orll aIa+wa.t.!4 mimi1:710 III Ill 111 111 111 111 ii 3.74' Shaffer 1313 5/8 5M 5M II IIi11ii111 I 1.11.11.1111. 111 III 111 1111111 snail ow-u —0 Dual Flex 3-1/2 X 3-1/2 4.67' . mall 13 5/8-50001111 n Blind Rams WNW:,IRE lit lil Iillil IiI Choke and Kill Valves 21/16 561 w/Unibolt connections for hoses (� Illi2.!1 111 I11 11101 2.00' !" 4 !Pi's Oil'11111 III IIIIIIIIIIIIIh IlI III III III Iii Riser,135/85M FE X135/8 5M API 813 hub 13.70' Moncla 301 BOP Test Procedure Haeor�,nim9ka, Attachment#1 Attachment #1 Hilcorp Alaska LLC. BOP Test Procedure: Moncla 301, Grayling Platform WO Program — Oil Producers, Water Injectors Pre Rig Move 1) Blow down well, bleed gas to Well Clean Tank that is vented thru flare to atmosphere 2) Load well with FIW to kill well. • Note: Fluid level will fall to a depth that balances with reservoir pressure. 3) Shoot fluid level at least 24 hours before moving on well. 4) Shoot fluid level again, right before ND/NU. Confirm that well is static. Initial Test(i.e.Tubing Hanger is in the Wellhead) If BPV profile is good 1) Set BPV. ND Tree. NU BOP. 2) MU landing joint. Pull BPV. Set 2-way check in hanger. 3) Space out test joint so end of tubing (EOT) is just above the blind rams. 4) Set slips, mark same. Test BOPE per standard test procedure. If 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. 2) 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 • Moncla 301 BOP Test Procedure Hilcorp Alaska,LLC Attachment#1 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.) 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. 3) Pull hanger to surface. (Requires tubing cuts as necessary to free tubing). CBU to displace annulus and tubing with kill weight fluid. 4) If a rolling test was conducted, remove the old hanger, MU new hanger or test plug to the completion tubing. Re-land hanger(or test plug) in tubing head. Test BOPE per standard procedure. Subsequent Tests(i.e.Test Plug can be set in the Tubing-head) 1) Remove Wear bushing. a) Use inverted test plug to pull wear busing. MU to 1 jt. of tubing. b) Thread into wear bushing c) Back out hold down pins d) Pull and retrieve wear bushing. 2) Break off test plug and invert same, and RIH on 1 joint of tubing. Install a closed TIW or lower Kelly valve in top of test joint. 3) Break joint off test plug and pull up to space the bottom of tool joint above blind rams. 4) Test BOPE per standard procedure. STANDARD BOPE TEST PROCEDURE(after 2-way check or test plug is set) 1) Fill stack with rig pump and install chart recorder on the stack side of the pump manifold. 2) Note: When testing, pressure up with pump to desired pressure,close valve on pump manifold to trap pressure and read same with chart recorder. 3) Test all Rams and Valves 1) Open all rams and annular and close HCR to place BOPE back into operating position for well work. 2) Fill out AOGCC report. FINAL STEP, FINAL CHECK 1) Test Gas Alarms 2) Double check all rams and valves,for correct operating position 3) Fill out the AOGCC BOPE Test Form (10-424) in Excel Format and e-mail to AOGCC and Juanita Lovett. Document both the rolling test and the follow up tests. Pages NOT Scanned in this Well History File XHVZE This page identifies those items that were not scanned during the initial scanning project. They are available in the original file and viewable by direct inspection. //'/~ F ileNumberof We llHistoryFile PAGES TO DELETE Complete RESCAN [] Color items - Pages: n Grayscale, halftones, pictures, graphs, charts- Pages: Poor Quality Original - Pages: Other- Pages: DIGITAL DA/T-A ~// Diskettes, No. ,/ Other, No/Type OVERSIZED · n · Logs .of vadous kinds · Other COMMENTS: Scanned by: Beverly Diann~than Lowell Date: [] TO RE-SCAN Notes: Re-Scanned by: Beverly Dianna Vincent Nathan Lowell Date: Is~ w\�� 177,'s) THE STATE Alaska Oil and Gas 01'� °fALASKA Conservation Commission 4t"itt GOVERNOR SEAN PARNELL 333 West Seventh Avenue 0 p. Anchorage, Alaska 99501-3572 ALAS Main: 907.279.1433 Fax: 907.276.7542 SCANNED MAY 1 6 2a 14 Ted Kramer Operations Engineer I� Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Re: McArthur River Field, Middle Kenai G & Hemlock Oil Pools, Trading Bay Unit G-01 RD Sundry Number: 313-650 Dear Mr. Kramer: 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, le),„ Daniel T. Seamount, Jr. Commissioner a DATED this 2 day of January, 2014. Encl. W D STATE OF ALASKA $ RECE �'� )F_ ir, e 1 2013 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS ,ADCC; 20 AAC 25.280 1.Type of Request: Abandon❑ Plug for Redril ❑ Perforate New Pod ❑ la Repair Wel❑ Change Approved Program 0 Suspend❑ Plug Perforations❑ Perforate V Pull Tubind] Time Extension❑ Operations Shutdown❑ Re-enter Susp.Wel ❑ Stimulate❑ Alter Casino] Other. Run ESP • ❑Q 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. Hilcorp Alaska,LLC Exploratory ❑ Development El. 191-139 • 3.Address: Stratigraphic ❑ Service ❑ 6.API Number 3800 Centerpoint Drive,Suite 100,Anchorage,AK 99503 50-733-200037-01 • 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? - CO aZ$A. lfb Will planned perforations require a spacing exception? Yes ❑ No [2' Trading Bay Unit/G-01RD 9.Property Designation(Lease Number): 10.Field/Pool(s): / ' ADL0018730 - McArtur River Field/Middle Kenai 08,Hemlock Oil Pools , 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth ND(ft): Effective Depth MD(ft): Effective Depth ND(ft): Plugs(measured): Junk(measured): ' 11,506 9,946 - • 11,430 9,879 - N/A 11,409' Casing Length Size MD 7VD Burst Collapse Structural Conductor 327' 26" 327' 327' Surface 2,113' 13-3/8" 2,160' 2,120' 3,090 psi 1,540 psi Intermediate 8,450' 9-5/8" 8,450' 7,319' 5,750 psi 3,090 psi Production 3,352' 7" 11,479' 9,921' 11,220 psi 8,530 psi Liner Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Schematic / See Schematic 3-1/2" 9.2#L-80 7,865 Packers and SSSV Type: Packers and SSSV MD(t)and ND(ft): Packer:N/A and BP-61 SSSV Packer:N/A and SSSV:3)3'(MD)303'(ND) 12.Attachments: Description Summary of Proposal ❑✓ / 13.Well Class after proposed work: Detailed Operations Program n BOP Sketch n/ Exploratory ❑ Stratigraphi4 Development n- Service n 14.Estimated Date for •fPKJb 15.Well Status after proposed work: 1/15/244.3.24 Y Commencing Operations: Oil Q• Gas ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Ted Kramer Email tkramerMilcom.com Printed Name Ted Kramer Title Operations Engineer Signature „4 ' _%_____ Phone (907)777-8420 Date 12/31/2013 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: X3 —'&30 Plug Integrity ❑ BOP Test ® Mechanical Integrity Test ❑ Location Clearance ❑ Other: ` Sae,p - t� ,? 6-00e 1 RBDMS MAY 0 9 2014 Spacing Exception Required? Yes ❑ No [' Subsequent Form Required: /0"�Ib II APPROVED BY I Approved by: / / inn A LHE COMMISSION Date: I 1,162. / I.L'l 4,110111 ,,Qd 1/2111 Submit Form and Form 10-403(Rev-ed 10/2012) Approved application is valid for 12 months from the date of approval. Attachments in Duplicate 0100/(/f(y 14 Well Work Prognosis Well: G-01RD Hilcorp Alaska,LLC Date: 12/27/2013 Well Name: G-01RD API Number: 50-733-20037-01 Current Status: ESP Producer / Leg: Leg#2 (NE corner) Estimated Start Date: January 15, 2014 / Rig: Moncla 404 Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Juanita Lovett(8332) Permit to Drill Number: 191-139 First Call Engineer: Ted Kramer (907)-777-8420(0) (985)-867-0665(M) Second Call Engineer: Dan Marlowe (907)283-1329 (0) (907) 398-9904 (M) AFE Number: Budgeted Cost: $1,769,508 Current Bottom Hole Pressure: -3,500 psi @ 9,254' TVD (mid pert of 10,710' MD) Maximum Expected BHP: -3,500 psi @ 9,254' TVD (mid pert of 10,710' MD) Max.Anticipated Surface Pressure: 0 psi (Using 0.435psi/ft.to surface) Brief Well Summary G-01RD is a G-Zone and Hemlock Producer that was converted to and ESP from a dual string gas-lift completion in October 2012. As part of the workover the inner annulus was pressure tested October 24th 2012 to 1,500 psig and charted for 30 minutes. The ESP experienced a down-hole electrical failure July 22, 2013. The ESP was replaced in October 2013 and failed again December 16th 2013. We plan to pull the current ESP completion and replace with identical equipment. We plan to add G-Zone ench 1 and Hemlock Bench 2 with E-line Guns. Procedure: 1. MIRU Moncla 404 Pulling Unit. 2. Attempt to pump through ESP to circulate hydrocarbon off the well to production. If necessary, RU e-line and RIH to+/-7,850'and punch tubing. 3. ND Wellhead, NU BOP and test to 250psi low/2,500psi high.(Note: Notify AOGCC 48 hours in advance of test to allow them to witness test). 4. POOH with tubing string and ESP pump laying down the same. 5. Pick up E-line guns and perforate G-1 and HB-2. Monitor fluid levels. POOH with Guns./ 6. PU,RIH with ESP completion. y Ac "AA- pe•a.raw. 7. Land ESP with the bottom of the assembly at+/-7,985'. 8. ND BOP, NU wellhead and test. 9. Turn well over to production. 10. RDMO Moncla 404 Pulling unit. 11. Conduct a no-flow test within 2 weeks of achieving stabilized flow. Attachments: 1. Current Wellbore Schematic 2. Current Wellhead Diagram 3. Proposed Wellbore Schematic 4. Proposed Wellhead Diagram(same as current) 5. BOP Drawing McArthur River Field,TBU .11 SCHEMATICe11 As Completed: 08/08/22/13 Hilcorp Alarka,LLC CASING DETAIL RKB to TBG Hngr=42.68' Size WT Grade Conn ID MD Top MD Btm Tree connection:3-1/2"EUE 8rd 26" Surf. 327' 13-3/8" 61 1-55 Butt Surf. 2160' lr _ 47 N-80 Butt 8.681 Surf 79' J 6° 40 N-80 Butt 8.835 79' 6275' 9-5/8" 43.5 N-80 Butt 8.755 6275' 8179' 13-3/8" 47 N-80 Butt 8.681 8179' 8,450' 9-5/8"DV Collar 4903' 4905' I 7" 29 P-110 Butt 6.184 8127' 11,479' TUBING DETAIL 3-1/2" I 9.2 I L-80 I TC-ll I 2.992 I Surface I 7,832' NOTE:H Window cut from 8,450'to 8,516'.Original 9-5/8"@ 8,994'MD(7,746'TVD) e...3 Y Jam- /S✓ Jewelry Details No. Depth ID Item 4 5 k 'v 1 7,834' Bolt On Head,Discharge Sub Assy JJ�� 2 7,835' (2)Pumps-DR1750 CR-CTT 97 Stg s_._a1 3 7,875' Pump Intake 12 4 7,894' Motor-45610,4106,Maximus 3 5 7,925' Btm ESP Assembly 4 5 g PERFORATIONS Zone Top MD Btm MD Top ND Btm TVD Amt SPF Last Opr. Status 1s-s/s" 10,140' 10,170' 8,759' 8,785' 30' 6 2/19/1992 Open G-2 10,140' 10,170' 8'759' 8,785' _ 30' 5 10/27/12 Reperf 10,225' 10,257' 8,833' _ 8,861' 32' 6 2/19/1992 Open G-3 10,244' 10,264' 8,849' _ 8,867' 20' 5 10/27/12 Open 10,278' 10,340' 8,879' 8,933' _ 62' 6 2/19/1992 Open G-4 10,280' 10,342' 8,881' 8,935' 62' 5 10/27/12 Open G-2 10,395' 10,415' 8,981' 8,999' 20' 6 2/19/1992 Open G-3 G-5 10,398' 10,418' 8,984' 9,001' - 20' 5 10/27/12 Open 10,440' 10,460' 9,021' 9,038' 20' 5 10/27/12 Open G-4 G-6 10,532' 10,548' 9,101' 9,115' _ 16' 5 10/27/12 Open G 5 G-7 10,600 10,614' 9,161' 9,173' 14' 5 10/27/12 Open HB-1 10,622' 10,637' 9,180' 9,194' 15' 4 1/17/2001 Open G-6 Open,frac'd G-7 10,628' 10,670' 9,186' 9,223' 42' 10&16 8/26/1995 10,628'- HB-1 10,643' 10,628' 10,676' 9,186' 9,228' 48' 5 10/27/12 Open HB-3 10,846' 10,860' 9,377' 9,389' 14' 5 10/27/12 Open 10,863' 11,000' 9,392' 9,509' _ 137' 6 2/19/1992 Open HB-4 10,939' 10,954' 9,457' 9,470' 15' 4 1/17/2001 Open 10,890' 11,006' 9,415' 9,515' 116' 5 _ 10/27/12 Open = HB-1 11,038' 11,048' 9,542' 9,550' 10' 4 1/17/2001 Open HB-3 HB-5 11,040' 11,070' 9,544' 9,569' 30' 8 8/26/1995 Open 11,042' 11,122' 9,545' 9,614' 80' 5 10/27/12 Open - HB-4 11,155' 11,170' 9,642' 9,655' 15' 4 8/26/1995 Open HB-6 11,156' 11,240' 9,643' 9,715' 84' 5 10/27/12 Open - HB-5 11,255' 11,280' 9,728' 9,749' 25' 24 6/24/1994 Open HB-6 HB-7 11,266' 11,290' 9,737' 9,758' 24' 5 10/27/12 Open = HB-7 ,L Fill cleaned out to 11337' WI' SPM.Fish on top 12/17/00:Left 10.14'long fish consisting of coil tubing motor and bit. ea-s/s"Pertcu"a 10/24/12: Cleaned out fill to 11337'DPM,Fish not recovered. 7" .. _ ,;11,409' RKB to MLLW ELEV=103' TD=11,506' PBD=11,430' MAX HOLE ANGLE=39.10°@ 7225' Updated by: JLL 9/20/13 . II Grayling Platform G-01 rd Current 08/22/2012 Hiles Alaska,L1A: BHTA, CIW,4 1/16 5M FE X Grayling Platform Cameron internal blanking nut Tubing hanger, CIW-DCB- G-1rd ESP, 11 X 4'h IBT lift and 133/8X95/8X31/2 susp,w/4"type H BPV profile, 5%EN, 2-3/8 iii �� continuous control line ports, prepped for BIW penetrator Valve, swab,WKM-M, '1,4Cross, stdd,4 1/16 5M X 4 1/16 5M FE, HWO, of o 3 1/8 5M X 2 1/16 5M T-24 0:0 PSI NMI 1.1 Valve,wing,WKM-M, 4-74,011-11 1iIIIi ValveWKMM3 1/8 5M FE• w/MA-16 operator 1. 111 , OQ Valve, lower master,WKM-M, =,:t1/ o 4 1/16 5M FE, HWO,T-24 Q Q Q .i IiI Adapter, CIW-Toadstool, 11 5M Stdd X 4 1/16 5M FE, prepped for 5'/4 ESP neck,2-'/z npt continuous control line ports Tubing head, CIW-DCB, r--1--1ce'' 13 5/8 3M X 11 5M,w/2- =Mil _ 2 1/16 5M SSO,X bottom • �� i lit Valve,WKM-M,2 1/16 5M FE, � ' �,� HWO, DD �'_ *le o t_.' o Qty2 1I oo.� � � N I11 1• i.i I EN-4 Casing head, Shaffer KD, III II1 III 135/83MX f 133/8 SOW,w/2-2" r (') LPO, so MIMI a1-I. 2"LP CIW ball valve Ii McArthur River Field,TBU • eii SCHEMATIC Proposed: 12/31/13/31/13 Hilum*Alaska,LIZ CASING DETAIL RKB to TBG Hngr=4268' Size WT Grade Conn ID MD Top MD Btm Tree connection:3-1/2"EUE 8rd 26" Surf. 327' 13-3/8" 61 1-55 Butt Surf. 2160' 47 N-80 Butt 8.681 Surf 79'....1] - 6 40 N-80 Butt 8.835 79' 6275' 9-5/8" 43.5 N-80 Butt 8.755 6275' 8179' [L2 3-3/8" 47 _ N-80 Butt 8.681 8179' 8,450' 9-5/8"DV Collar 4903' 4905' I7" 29 P-110 Butt 6.184 8127' 11,479' TUBING DETAIL 3-1/2" I 9.2 I L-80 I TC-Il I 2.992 1 Surface I 7,832' NOTE:H Window cut from 8,450'to 8,516'.Original 9-5/8"@ 8,994'MD(7,746'TVD) Jewelry Details No. Depth ID Item 1 +/-7,830' Top of Pump 2 +/-7,875' Pump Intake '1 3 , +/-7,895' Motor 4 +/-7,925' Bottom of ESP Assembly i____i 23 =14 PERFORATIONS Zone Top MD Btm MD Top TVD Btm TVD Amt SPF Last Opr. Status S.9-5/8" G-01 10,089' 10,120' 31' 5 Proposed Proposed 10,140' 10,170' 8,759' 8,785' 30' 6 2/19/1992 Open G-2 10,140' 10,170' 8'759' 8,785' 30' 5 10/27/12 Reperf 10,225' 10,257' 8,833' 8,861' 32' 6 2/19/1992 Open ` G-3 10,244' 10,264' 8,849' 8,867' 20' 5 10/27/12 Open _ 10,278' 10,340' 8,879' 8,933' 62' 6 2/19/1992 Open G-2 G-4 10,280' 10,342' 8,881' 8,935' 62' 5 10/27/12 Open G-3 10,395' 10,415' 8,981' 8,999' 20' 6 2/19/1992 Open G-5 10,398' 10,418' 8,984' 9,001' 20' 5 10/27/12 Open G-4 10,440' 10,460' 9,021' 9,038' 20' 5 10/27/12 Open G-5 G-6 10,532' 10,548' 9,101' 9,115' 16' 5 10/27/12 Open G-7 10,600 10,614' 9,161' 9,173' 14' 5 10/27/12 Open G-6 HB-1 10,622' 10,637' 9,180' 9,194' 15' 4 1/17/2001 Open G-7 Open,frac'd 10,628' 10,670' 9,186' 9,223' 42' 10&16 8/26/1995 10,628'- HB-1 10,643' 10,628' 10,676' 9,186' 9,228' 48' 5 10/27/12 Open 'Y 10,718' 29' HB-1 HB-3 10,846' 10,860' 9,377' 9,389' 14' 5 10/27/12 Open 10,863' 11,000' 9,392' 9,509' 137' 6 2/19/1992 Open HB-4 10,939' 10,954' 9,457' 9,470' 15' 4 1/17/2001 Open HB-3 10,890' 11,006' 9,415' 9,515' 116' 5 10/27/12 Open 11,038' 11,048' 9,542' 9,550' 10' 4 1/17/2001 Open HB-4 HB-5 11,040' 11,070' 9,544' 9,569' 30' 8 8/26/1995 Open r T HB-5 11,042' 11,122' 9,545' 9,614' 80' 5 10/27/12 Open 11,155' 11,170' 9,642' 9,655' 15' 4 8/26/1995 Open HB-6 HB-6 11,156' 11,240' 9,643' 9,715' 84' 5 10/27/12 Open HB-7 11,255' 11,280' 9,728' 9,749' 25' 24 6/24/1994 Open HB-7 Fill cleaned out to 11337' 11,266' 11,290' 9,737' 9,758' 24' 5 10/27/12 Open PM.Fish on top 4-5/8"Perf Gun @ 77 (.11,409' RKB to MLLW ELEV=103' 12/17/00:Left 10.14'long fish consisting of coil tubing motor and bit. TD=11,506' PBD=11,430' 10/24/12: Cleaned out fill to 11337'DPM,Fish not recovered. MAX HOLE ANGLE=39.10°@ 7225' Updated by: DEM 12/31/13 , . . ii Grayling Platform G-01rd Current 08/22/2012 Nilrnrp:mark..Iii BHTA, CIW,4 1/16 5M FE X Grayling Platform Cameron internal blanking nut Tubing hanger, CIW-DCB- G-1rd ESP, 11 X 4'/z IBT lift and 133/8X95/8X31/2 11111„' susp,w/4"type H BPV profile, 5%EN, 2-3/8 'I' II !et continuous control line Cit------4 ports, prepped for BIW penetrator Valve, swab,WKM-M, 0-11 Cross, stdd,4 1/16 5M X 4 1/16 5M FE, HWO, r:/ o 3 1/8 5M X 2 1/16 5M T-24 0:0 I.1 1111.1111101-1 .-.- Valve,wing,WKM-M, x/0,-10 I .I 2 1/16 5M FE, HWO, °I 0Valve,WKM-M, 3 1/8 5M FE, T-24 [15k,....0 0 - I. 1 w/MA-16 operator •-rilai III t ; - $ • Valve, lower master,WKM-M, Ai( 0 7 4 1/16 5M FE, HWO,T-24 Q O Q 1.1 1.- Adapter, CIW-Toadstool, 11 5M Stdd X 4 1/16 5M FE, prepped for 5'/4 ESP neck,2-'A npt continuous I C. control line ports Tubing head, CIW-DCB, — ; • 13 5/8 3M X 11 5M,w/2- :BEI 2 1/16 5M SSO,X bottom ��_ 1I1 a III Valve,WKM-M,2 1/16 5M FE, ® _ ,-1 o. _ � � o HWO, DD �/a °ill , ale Ili.' Qty 2 lel 1 III 111— dam._ Casing head, 111. Shaffer KD, t II 13 5/8 3M X 13 3/8 SOW,w/2-2" LPO, ISI ' aIle 0 ■i . 2"LP CIW ball valve .. , , fi Grayling Platform Moncla Rig BOP 01/01/2013 llileap Alaska.1.11: Grayling Platform 2014 Workovers BOP Drawing(Moncla) • • iii iii Ili III iii ill I I ili Will I III III III I .. H Variable 2//B 5 1.61 tame. Blind Mem III 111 111 I Choke and MI Valves 2 1/16 SM sv/Uniboh connections for hoses �"'"s k. III III i l I I IAD '" ASV I' III III III I 11 II. I! :Ii II. RliM,13 S/6 SM Amp 10' 13 S/6 SM amp 11 Ii1 1: I' 1• 13 SAX11DSA I , I 1112,11'SM Flame It 6• 11'SM Flrlp • ' • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMIION • REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon ❑ Repair Well ❑ Plug Perforations ❑ Perforate❑ Other IS Install ESP Performed: Alter Casing ❑ Pull Tubing El Stimulate-Frac ❑ Waiver❑ Time Extension❑ Change Approved Program El Operat.Shutdown❑ Stimulate-Other El Re-enter Suspended Well❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Development p Exploratory❑ 191-139 Hilcorp Alaska,LLC 3.Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic❑ Service❑ 6.API Number: Anchorage,AK 99503 50-733200370100 ' 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0018730 • Trading Bay Unit/G-01 RD ' 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): McArthur River Field/Middle Kenai G&Hemlock Oil Pools 11.Present Well Condition Summary: Total Depth measured 11,506 feet Plugs measured N/A feet true vertical 9,946 feet Junk measured 11,409' feet t-p ,<, f Effective Depth measured 11,430 feet Packer measured N/A feet 1,30 {' true vertical 9,879 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Structural Conductor 327' 26" 327' 327' Surface 2,113' 13-3/8" 2,160' 2,120' 3,090 psi 1,540 psi Intermediate 8,450' 9-5/8" 8,450' 7,319' 5,750 psi 3,090 psi Production 3,352' 7" 11,479' 9,921' 11,220 psi 8,530 psi Liner SCANNED U zo13 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 7,832'(MD) 6,792'(TVD) Packers and SSSV(type,measured and true vertical depth) Packer- N/A SSSV-NA 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: 235 109 5781 126 128 Subsequent to operation: 65 32 4835 118 117 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: Oil El • Gas ❑ WDSPL❑ GSTOR El WINJ El 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: 313-401 ✓ Contact Ted Kramer Email tkramer@hilcorp.com Printed Name Ted Kramer / Title Sr.Operations Engineer Signature �f �~`�'"�� Phone 907 777-8420 Date 9/20/2013 Form 10-404 Revised 10/2012 J ,�., RBDMS OCT 11 2 bmit Original Only • • McArthur River Field,TBU Well: G-01RD SCHEMATIC As Completed: 08/22/13 Hilearp Alaska,LLf. CASING DETAIL RKB to TBG Hngr=42.68' Size WT Grade Conn ID MD Top MD Btm Tree connection:3-1/2"EUE 8rd 26" Surf. 327' 13-3/8" 61 J-55 Butt Surf. 2160' 47 N-80 Butt 8.681 Surf 79' 6" 40 N-80 Butt 8.835 79' 6275' 9-5/8" 43,5 N-80 Butt 8.755 6275' 8179' 13 3/8' 47 N-80 Butt 8.681 8179' 8,450' 9-5/8"DV Collar 4903' 4905' S 7" 29 P-110 Butt 6.184 8127' _ 11,479' TUBING DETAIL 3-1/2" I 9.2 I L-80 I TC-II I 2.992 I Surface I 7,832' NOTE:H Window cut from 8,450'to 8,516'.Original 9-5/8"@ 8,994'MD(7,746'TVD) Jewelry Details No. Depth ID Item 1 7,834' Bolt On Head,Discharge Sub Assy 2 7,835' (2)Pumps-DR1750 CR-CTT 97 Stg _ _ 1 3 7,875' Pump Intake 2 4 7,894' Motor-456 10,4106,Maximus was 3 5 7,925' Btm ESP Assembly 0 4 . 5 ill ® PERFORATIONS Zone Top MD Btm MD Top ND Btm ND Amt SPF Last Opr. Status ss/8" 10,140' 10,170' 8,759' 8,785' 30' 6 2/19/1992 Open G-2 10,140' 10,170' 8'759' 8,785' 30' 5 10/27/12 Reperf 10,225' 10,257' 8,833' 8,861' 32' 6 2/19/1992 Open G-3 10,244' 10,264' 8,849' 8,867' 20' 5 10/27/12 Open 10,278' 10,340' 8,879' 8,933' 62' 6 2/19/1992 Open G-4 10,280' 10,342' 8,881' 8,935' 62' 5 10/27/12 Open G• -2 10,395' 10,415' 8,981' 8,999' 20' 6 2/19/1992 Open G-3 G-5 10,398' 10,418' 8,984' 9,001' 20' 5 10/27/12 Open 10,440' 10,460' 9,021' 9,038' 20' 5 10/27/12 Open G-4 G-6 10,532' 10,548' 9,101' 9,115' 16' 5 10/27/12 Open G-5 G-7 10,600 10,614' 9,161' 9,173' 14' 5 10/27/12 Open HB-1 10,622' 10,637' 9,180' 9,194' 15' 4 1/17/2001 Open - G-6 Open,frac'd G-7 10,628' 10,670' 9,186' 9,223' 42' 10&16 8/26/1995 10,628'- HB-1 10,643' 10,628' 10,676' 9,186' 9,228' 48' 5 10/27/12 Open HB-3 10,846' 10,860' 9,377' 9,389' 14' 5 10/27/12 Open 10,863' 11,000' 9,392' 9,509' 137' 6 2/19/1992 Open HB-4 10,939' 10,954' 9,457' 9,470' 15' 4 1/17/2001 Open 10,890' 11,006' 9,415' 9,515' 116' 5 10/27/12 Open HB-1 11,038' 11,048' 9,542' 9,550' 10' 4 1/17/2001 Open H• B-3 HB-5 11,040' 11,070' 9,544' 9,569' 30' 8 8/26/1995 Open 11,042' 11,122' 9,545' 9,614' 80' 5 10/27/12 Open HB-4 11,155' 11,170' 9,642' 9,655' 15' 4 8/26/1995 Open HB-6 11,156' 11,240' 9,643' 9,715' 84' 5 10/27/12 Open HB-5 11,255' 11,280' 9,728' 9,749' 25' 24 6/24/1994 Open - H• B-6 HB 7 11,266' 11,290' 9,737' 9,758' 24' 5 10/27/12 Open H• B-7 Fill cleaned out to 11337' PM.Fish on top 12/17/00:Left 10.14'long fish consisting of coil tubing motor and bit. a-s/a"Perf Gun @ 10/24/12: Cleaned out fill to 11337'DPM,Fish not recoveral. RKB to MLLW ELEV=103' TD=11,506' PBD=11,430' MAX HOLE ANGLE=39.10°@ 7225' Updated by: JLL 9/20/13 • . Hilcorp Alaska, LLC Ilawir')Alaska,I1,C Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-01RD 50-733-20037-01 191-139 8/5/2013 8/22/2013 Daily Operations: '` 08/05/13-Monday Rigging up. 08/06/13-Tuesday Rigging up. 08/07/13-Wednesday Finish mounting derrick onto carriage, pin off&hook up hydraulic cylinders to derrick base. Dress out derrick in preparation to half mass&raise. Hook up driller's console, raise&scope up derrick. Move&hook up choke house&manifold. Perform hazard walk around,place pump lines in tray, load rig pump on M/V Champion&transfer to east side of platform.Hook up pump lines to rig pump. Run pump lines to well bay&tie in to casing valve. Fill up rig tank with 200 bbls of FIW. Filling G-01RD annulus with FIW pumping 2 bpm,scope down derrick&lay over same in preparation of n/u bop's. 08/08/13-Thursday Remove pump lines from annulus&hook up to tubing. Pump 180 bbls of FIW down tubing.Total of 690 bbls pumped into well. Install BPV&clean lifting threads.Install riser with two foot spacer spool extension,bop's,&Hydril.Torque down all same. Install drip pan with lines. Retrace accumulator lines from west end of platform&hook up hydraulic extensions to bop's. Power& pressure up Koomey manifold&function test bop's from main panel station. R/U rig floor,hand rails,stairways with support braces. Unload equipment from M/V Champion.R/U test joints&equipment. Land test joint. R/U test pump lines to test joint& prepare to test bop's.Testing bop's&related equipment per AOGCC regulations on chart. Test 31/2"VBR rams.blind rams.HCR.choke manifold,(2)3-1/2"ph-6 TIW valves,&(1)3-1/2" ph-6 ibop valve to 250 low&3000 high per AOGCC regulations. Witness of test waived by Jim Regg,AOGCC.Test Hydril to 250 low&1500 high. Hold all test on chart for 5 minutes. Perform draw down test.Starting psi 3200,draw down 1600 psi,200 psi in 27 seconds. 134 seconds to build back up to 3200 psi. Unload&spot ESP equipment. Hold PJSM with crew on rigging up ESP equipment&sheaves.R/U ESP spools, connex,&sheaves in preparation of pulling ESP from G-01RD well. Back out hold down pins from tubing hanger,stab&M/U landing joint. Pull tubing hanger to rig floor, Cut&hang ESP umbilical cord thru sheave&flat pack thru sheave.L/D tubing hanger.POOH with 3-1/2"9.2#L-80 TC-II production tubing,removing cannon clamps, reeling umbilical line&flat pack onto spools.Total of 224 joints pulled out of hole @ 0600 hrs. Depth=744' 08/10/13-Saturday POOH with 3-1/2"9.2#TC-II production tubing,spooling up flat pack&ESP umbilical cord. Break out joint above pump& had 2 gallons of scale piled on top of ESP.Gather sample&send to shore base to analyze. L/D ESP, had 1/16"of scale build up on inside wall of ESP sections. Decision made to make clean out trip.Order washout shoe,jars,&x-o subs to RIH&wash out past perforations.Clean floor&work area. ELU 3:112"_9,3#Qh-6 work string in singles with crane. Simultaneously using crane to back load equipment while P/U pipe. Change out tongs,POOH with 20 stds of 3-1/2"ph-6 tubing. Install wear bushing,strap&caliper washout assembly with 6"piranha deep throat mill,(2)5"boot baskets, bumper jars,oil jars,&(4)4-3/4"drill collars. P/U BHA same&RIH. RIH with 20 stds of 3-1/2"9.3#ph-6 tbg.P/U 3-1/2"9.3#ph-6 tubing,transferring pipe in singles with crane from pipe rack.Total of 50 joints out of 120P/U @ 0600 hrs. 08/11/13-Sunday Service rig&equipment. P/U&RIH with 3-1/2"9.3#ph-6 work string,moving pipe in singles from west side pipe rack over to rig floor on east side of platform.Total of 79 joints picked up with BHA @ 09:30 hrs.Total depth of 2677'.Secure well&clean top deck of house keeping hazards. Rig transmission not wanting to stay in gear.Troubleshoot&found speed shift sensor was bad. Attempt to repair sensor,rig not shifting.,Williams in contact with transmission tech. Rig downtime:waiting on transmission tech. Cleaning rig handrails&performing general housekeeping while waiting. 08/12/13-Monday Transmission on Williams rig down. Waiting on transmission technician. Rig up chemical equipment to G-01RD well. Pump scale inhibitor treatment,total of 1935 bbls of treatment pumped into"G"&"HB"sands. 14 • Hilcorp Alaska, LLC • Hilcorp Alaska,LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-01RD 50-733-20037-01 191-139 8/5/2013 8/22/2013 i 5 Transmission technician arrived at platform @ 0930 hrs.Troubleshoot transmission.Obtain wiring harness from Williams yard,tie in wiring harness.Transmission showing fault codes.Troubleshoot&found manual road shifter had kicked out. Engage gear&test run transmission.P/U 41 joints of 3-1/2"9.3#ph-6 tubing,transferring tubing in singles with crane.Total of 120 joints of 3-1/2" 9.3#ph-6 production tubing picked up with BHA.Install 3-1/2"ph-6 pin x 3-1/2"TC-II box cross over&RIH with 65 stands of 3- 1/2"9.2#L-80 TC-II tubing from derrick. SLM tubing out of derrick same.Total depth @ 0600 hrs=8127'. : 13-Wednesday Service rig&equipment.RIH with 3-1/2"9.2#TC-II production tubing&tag @ 10,418.40'. POOH laying down 30 jts of 3-1/2"TC-II tubing to wash with.RIH with 15 stands of TC-II tubing to 10,410'.Install stripping rubber&P/U power swivel.R/U dead man lines &stiff arms to begin washing. Break circulation pumping down annulus&out tubing at lbpm&200 psi.Attempt to begin washing at 10,418'unable to maintain returns. Bring rate up to 3 bpm&450 psi.Getting approximately 1.5 bpm on returns.Wash fill from 10,418'to 10,587'at 3 bpm&450 psi. Unable to rotate due to max torque on TC-II tubing.Circulating bottoms up on each connection. Received scale cuttings back on returns.Obtain samples.TC-II crossover sub gaulding up due to excessive use during connections.Circulate bottoms up&prepare to POOH. L/D swivel,pull stripping rubber,&prepare to POOH. POOH with 3-1/2" TC-II tubing,racking pipe in derrick.Total of 50 stands out of hole @ 0600 hrs=depth of 7,367'. Note:total fluid losses to well= 337 bbls in last 24 hrs. 08/15/13-Thursday Service rig&equipment.Continue POOH with 3-1/2"TC-II production tubing&60 stands of 3-1/2"9.3#PH-6 work string racking pipe in derrick.Break down&rack back 2 stands of 4-3/4"drill collars. L/D jars&boot baskets.Recovered large pieces of scale inside boot baskets.Obtain samples. Pull wear bushing. R/U test joints&plug to begin testing BOP'S. Test BOPE per AOGCC regulations.Test 3-1/2"VBR pipe rams,blind rams,choke manifold,HCR&kill line all to 250 psi low&3000 psi high.Test Hydril to 250 psi low&3000 psi high. Hold all test on chart for 5 minutes.Obtain Koomey draw down test.Starting psi=3200,stabilized psi =1600,200 psi in 32 sec.,built up to 3200 psi in 148 sec.BOP test witness waived by Jim Regg,AOGCC,on 8/14/13. Pull test plug &L/D test assembly. Install wear bushing.Obtain permit&pump oil to Trading Bay facility from rig tank.Clean out rig tank to fill with FIW for washing.P/U 6"piranha mill&RIH with BHA.RIH with 60 stands of 3-1/2"9.3#P-110 PH-6 tubing to 3,935.55'. P/U& RIH with 3-1/2"PH-6 tubing. Picking up pipe in singles with crane.Depth @ 0600 hrs=4,817.36'with 148 jts of 3-1/2" PH-6 tubing P/U&RIH. 08/16/13-Friday Service rig&equipment.Continue P/U 3-1/2"9.3#P-110 PH-6 workstring&RIH. Using crane to P/U tubing in singles.Total of 265 joints P/U @ 1800 hrs=8,505'. Continue P/U 3-1/2"9.3#PH-6&RIH with total of 330 joints to 10,578'. 08/17/13-Saturday Service rig&equipment.Continue P/U 3-1/2"9.3#PH-6 tubing&RIH.Tag @ 11,005'. R.0 power swivel&stripper rubber to begin washing. Fill up annulus&break circulation. Hole took 337 bbls to formation while P/U tubing.Wash&ream from 11,005'to 11,030',pumping 4 bpm&getting 2 bpm on returns.Attempt to wash&mill at 11,030'tubing torqueing erratically&stalling out. Attempt to spud with 20k down.Obstruction solid.Decision made to suspend washing operations @ 11,030',circulate bottoms up @ 11,030'pumping 4 bpm @ getting 2 bpm on returns.R/D power swivel&stripper rubber head. Make 15 stand wiper trip to 10,084.25', RIH to 11,030'&R/U stripping rubber head. Reverse circulate(2)bottoms up @ 3bpm loosing 1.5 bpm to formation. POOH laying down 3-1/2"9.3#PH-6 production tubing,transferring pipe in singles with crane.55 joints layed out @ 0600 hrs, Depth=9,298'. Fluid lost to formation last 24 hrs=1087 bbls.Total of 1424 bbls FIW lost for job. Service rig&equipment.Continue L/D 3-1/2"9.3#P-110 PH-6 tubing.Total of 186 joints layed down @ 1800 hrs.Continue L/D 3- 1/2"9.3#PH-6 work string.Total of 282 joints layed down.Depth @ 0600 hrs=2,173'. • S Hilcorp Alaska, LLC IliI orp:lla.ka.L1,C Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-01RD 50-733-20037-01 191-139 8/5/2013 8/22/2013 Daily Operations: 08/19/13-Monday Service rig&equipment.Waiting on weather,sustained winds at 38 mph&gusts to 42 mph.Continue L/D 3-1/2"9.3#PH-6 work string.Total of 346 joints layed down&transferred to west deck. L/D BHA,(4)4-3/4"d.c.,bumper&oil jars,(2)5" boot baskets, 15 stands of 3-1 2"9.2#L-80 TC- II 9.2#TC-II production tubing off of deck&RIH. POOH with 5 s / &6"piranha mill. P U 30 jts of 3 1 2"9.2 C p / J / p g II production tubing&rack back in derrick. R/U ESP equipment in preparation of running G-01RD ESP. P/U ESP assembly with ESP technicians, making umbilical cord tie-ins&connecting flat pack control lines. 08/20/13; °aY P./U.G-Q1BD ESP assembly..w th UP technicians, making umbilical cord tie-ins&connecting flat pack control lines. RIH w/ESP, splice ESP line and continueRlH w/ESP,testing control lines&cable every 20 stds. 08/21/13-Wednesday Held safety meeting and JSA review w/Production and Day Crew.Continue TIH w/ESP assembly and 244 jts 3-1/2 9.3#, L-80 TC2 production tbg to 7,984'. Total clamps-125 tbg clamps, 15 equipment clamps,2 splice clamps and 5 bands. Install tbg hanger and making slice at hanger. Land tbg, RD. RD rig floor and ND BOP's. Install Production Tree.Test seals&void to 5000 psi for 30 min.(good test). Pull back pressue valve set two way check,test tree to 3200 psi for 30 minutes(good test).Hook up flow line and making electrical connection to tree. Brought on ESP at 40 Hz.Well unloading.Total fluid lost to well during workover 5575 bbls. 08/22/13-Thursday Held safety meeting and JSA review w/day crew. Raise derrick and RD operations. III STATE OF ALASKA • . ALASKA OIL AND GAS CONSERVATION COMMISSION z WELL COMPLETION OR RECOMPLETION REPORT AND LOG la. Well Status: Oil O ` Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended❑ 1b. Well Class: 20MC 25.105 20MC 25.110 Development El • Exploratory ❑ GINJ ❑ WINJ ❑ WAG ❑ WDSPL ❑ No. of Completions: Service ❑ Strigraphic Test ❑ 2. Operator Name: 5. Date Comp., Susp., or 12. Peanut to Drill Number: HilcorpAlaska, LLC Abend.: 10/31/2012 191 -139 312 'ZLG 3. Address: 3800 Centerpoint Drive, Suite 100 6. Date Spudded: 13. API Number: Anchorage, AK 99503 1/7/1992 50- 733200370100 • 4a. Location of Well (Governmental Section): 7. Date TD Reached: 14. Well Name and Number: Surface: 1,888' FSL, 1,388' FEL, Sec 29, TON, R13W, S 2/10/1992 Trading Bay Unit/ G -011D- Top of Productive Horizon: 8. KB (ft above MSL): 103' . 15. Field/Pod(s): 2,472' FNL, 2,158' FEL, Sec 28, T9N, R13W, S GL (ft above MSL): McArthur River Field Total Depth: 9. Plug Back Depth(MD +TVD): Middle Kenai G Pool • 2,307' FNL, 1,456' FEL, Sec 28, T9N, R13W, S 11,430' (MD) / 9,879' (TVD) Hemlock Oil Pod • 4b. Location of Well (State Base Plane Coordinates, NAD 27): 10. Total Depth (MD + TVD): 16. Property Designation: Surface: x- 212296.3 y- 2502423.9 Zone- G & H • 11,506' (MD) / 9,948' (TVD) ADL0018730 . TPI: x- 216825.2 y- 2503245.2 Zone- G 11. SSSV Depth (MD + TVD): 17. Land Use Permit: Total Depth: x- 217530.9 y- 2503393.5 Zone - WF • 303' (MD) / 303' (TVD) 18. Directional Survey: Yes ❑ No x 19. Water Depth, if Offshore: 20. Thickness of Permafrost MD/TVD: (Submit electronic and printed information per 20 AAC 25.050) 125 (ft MSL) MA 21. L/V o�g7s tamed (List all logs here and submit electronic and printed information per 20AAC25.071): 22.Re -driU /Lateral Top Window MD/TVD: 23. CASING, LINER AND CEMENTING RECORD Ait+t SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING PER GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED Ak) ! 1 4 Q. S 24. Open to production or injection? Yes N' No ❑ 25. TURNG RECORD If Yes, list each interval open (MD +TVD of Top and Bottom; Perforation SIZE DEPTH SET (MD) PACKER SET ( MD/TVD) Size and Number): ` 3-1/2" 7,885' WA � 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Q a i - �L a.�Z.e61- S e4- r 1 r f- Was hydraulic fracturing used during completion? Yes ❑ No ❑ DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED /t!U eh7 s 27. PRODUCTION TEST Date First Production: JA Method of Operation (Flowing, gas lift, etc.): Date of Test: Hours Tested: Production for Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: Test Period -.► Flow Tubing Casing Press: Calculated Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity - API (corr): Press. 24 -Hour Rate 28. CORE DATA Conventional Core(s) Acquired? Yes ❑ Nog Sidewall Cores Acquired? Yes ❑ No If Yes to either question, list formations and intervals cored (MD +TVD of top and bottom of each), and summarize lithology and presence of oil, gas or water (submit separate sheets with this form, if needed). Submit detailed descriptions, core chips, photographs and laboratory analytical results per 20 AAC 25.071. A1/74 RBDMS NOV 3 0 201 � - SCANNED MAR 13 2D13 6 Form 10 -407 Revised 10/2012 CONTINUED ON REVERSE 1 ‹•r S SU mit original only ." • • 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? fl Yes gi No If yes, list intervals and formations tested, briefly summarizing test results. Attach separate sheets to this form, if Permafrost - Top needed, and submit detailed test information per 20 AAC 25.071. Permafrost - Base A4 Formation at total depth: 31. List of Attachments: 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Ted Kramer Email: tkramerahilcorD.com Printed Name: Ted Kramer Title: Sr. Operations Engineer Signature: Phone: 907 777 -8420 Date: 11/30/2012 INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10 -404 well sundry report when the downhole well design is changed. Item lb: Classification of Service wells: Gas Injection, Water Injection, Water - Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: The Kelly Bushing and Ground Level elevations in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50- 029 - 20123- 00 -00). Item 20: Report true vertical thickness of permafrost in Box 20. Provide MD and TVD for the top and base of permafrost in Box 28. Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut -in, or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Submit detailed description and analytical laboratory information required by 20 AAC 25.071. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Form 10-407 Revised 10/2012 McArthur River Field, TBU • SCHEMATIC • well: G -01RD As Completed: 10/31/2012 ' Hilc°rp Alaska, LLC CASING DETAIL Size WT Grade Conn ID MD Top MD Btm TVDBtm RKB to TBG Hngr = 42.68' 26" Surf. 327' 13 - 3/8" 61 J - 55 Butt Surf. 2160' 2113' Tree connection: 3 - 1/2" EUE 8rd 47 N -80 Butt 8.681 Surf 79' J 1 9 5/8" 40 N -80 Butt 8.835 79' 6275' 5523' 43.5 N -80 Butt 8.755 6275' 8179' 7086' 2 47 N -80 Butt 8.681 8179' 8,450' 7318' [1.26" 3 - 3/8" 9 -5/8" DV Collar 4903' 4905' 4393' 7" 29 P -110 Butt 6.184 8127' 11,479' 9927' 1 TUBING DETAIL 3 -1/2" 1 9.2 1 L -80 1 Butt 1 2.992 1 Surface 1 7,865' 1 6,820' NOTE: H Window cut from 8,450' to 8,516'. Original 9 -5 /8" @ 8,994'MD (7,746'TVD) Jewelry Detail Top No. Depth Length ID OD Item 1 303' N/A .25" Control Line 2 303' 27" 2.812" 4.508" SLB BP -61 Safety Valve Landing Nipple 7 3 7,865' 1.55 6.75" Bolt On Head, Discharge Sub Assy 3 4 7,867' 39.5" 6.75" (2) Pumps - SLB, 17000N II 4 5 7,906' 1.1" 7.25" Pump Intake 5 6 7,925' 27.4' 7.38" Motor -SLB 738,14, E142 Dominator RK -S III 6 7 7,930' 7,930' N/A 1.48" SLB 5KVA Cable 9 8 8 7,985' 1.751 5.63" Btm ESP Assembly 9 7,985' 7,985' Flat Pack - .410" x .710" PERFORATIONS .9 -s /B" Zone Top MD Btm MD Top TVD Btm TVD Amt SPF Last Opr. Status 10,140' 10,170' 8,759' 8,785' 30' 6 2/19/1992 Open G-2 10,140' 10,170' 8'759' 8,785' 30' 5 10/27/12 Reperf 10,225' 10,257' 8,833' 8,861' 32' 6 2/19/1992 Open G-3 10,244' 10,264' 8,849' 8,867' 20' 5 10/27/12 Open 10,278' 10,340' 8,879' 8,933' 62' 6 2/19/1992 Open G -2 G 4 10,280' 10,342' 8,881' 8,935' 62' 5 10/27/12 Open 10,395' 10,415' 8,981' 8,999' 20' 6 2/19/1992 Open ▪ G -3 G -5 10,398' 10,418' 8,984' 9,001' 20' 5 10/27/12 Open G -4 10,440' 10,460' 9,021' 9,038' 20' 5 10/27/12 Open G -6 10,532' 10,548' 9,101' 9,115' 16' 5 10/27/12 Open G -5 G -7 10,600 10,614' 9,161' 9,173' 14' 5 10/27/12 Open - G -6 HB -1 10,622' 10,637' 9,180' 9,194' 15' 4 1/17/2001 Open G 7 Open, frac'd 10,628' 10,670' 9,186' 9,223' 42' 10 & 16 8/26/1995 10,628' - H B -1 10,643' 10,628' 10,676' 9,186' 9,228' 48' 5 10/27/12 Open HB -3 10,846' 10,860' 9,377' 9,389' 14' 5 10/27/12 Open 10,863' 11,000' 9,392' 9,509' 137' 6 2/19/1992 Open HB -4 10,939' 10,954' 9,457' 9,470' 15' 4 1/17/2001 Open HB -1 10,890' 11,006' 9,415' 9,515' 116' 5 10/27/12 Open HB -3 11,038' 11,048' 9,542' 9,550' 10' 4 1/17/2001 Open HB -5 11,040' 11,070' 9,544' 9,569' 30' 8 8/26/1995 Open HB -4 11,042' 11,122' 9,545' 9,614' 80' 5 10/27/12 Open 11,155' 11,170' 9,642' 9,655' 15' 4 8/26/1995 Open - HB -5 HB -6 11,156' 11,240' 9,643' 9,715' 84' 5 10/27/12 Open - HB -6 11,255' 11,280' 9,728' 9,749' 25' 24 6/24/1994 Open HB 7 11,266' 11,290' 9,737' 9,758' 24' 5 10/27/12 Open ▪ HB -7 Fill cleaned out to 11337' SPM. Fish on top ------- 12/17/00: Left 10.14' long fish consisting of coil tubing motor and bit. a -s /a" Perf Gun @ 10/24/12: Cleaned out fill to 11337' DPM, Fish not recovered. 7'' 11,409' .- \ RKB to MLLW ELEV = 103' TD = 11,506' PBD = 11,430' MAX HOLE ANGLE = 39.10° @ 7225' Revised 11/28/2012 by JLL STATE OF ALASKA ALL OIL AND GAS CONSERVATION COM.SION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon ❑ Repair Well ❑ Plug Perforations ❑ Perforate El Other El Install ESP Performed: Alter Casing ❑ Pull Tubing 1 Stimulate - Frac ❑ Waiver ❑ Time Extension❑ Change Approved Program ❑ Operat. ShutdownD Stimulate - Other ❑ Re -enter Suspended WOO 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development El Exploratory ❑ 191 -139 Hilcorp Alaska, LLC 3. Address: 3800 Centerpoint Drive, Suite 100 Stratigraphic❑ Service ❑ 6. API Number: Anchorage, AK 99503 50- 733200370100 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0018730 Trading Bay Unit / G -01 RD 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field /Pool(s): McArthur River Field / Middle Kenai G & Hemlock Oil Pools 11. Present Well Condition Summary: Total Depth measured 11,506 feet Plugs measured N/A feet true vertical 9,946 feet Junk measured 11,409' feet Effective Depth measured 11,430 feet Packer measured N/A feet true vertical 9,879 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Structural Conductor 327' 26" 327' 327' Surface 2,113' 13 -3/8" 2,160' 2,120' 3,090 psi 1,540 psi Intermediate 8,450' 9 -5/8" 8,450' 7,319' 5,750 psi 3,090 psi Production 3,352' 7" 11,479' 9,921' 11,220 psi 8,530 psi Liner 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 7,865' (MD) 6,820' (TVD) 303' (MD) Packers and SSSV (type, measured and true vertical depth) Packer - N/A BP -61 SSSV 303' (TVD) 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 o r Injection D Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 1440 1440 Subsequent to operation: 132 45 3921 90 100 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: Oil p 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 -266 Contact Ted Kramer Email tkramer@hilcorp.com Printed Name Ted Kramer Title Sr. Operations Engineer Kr Signature <! /7 '° Phone 907 777 -8420 Date 11/30/2012 Form 10 -404 Revised 10/2012 Submit Original Only n • McArthur River Field, TBU SCHEMATIC • well: G -01RD As Completed: 10/31/2012 , Hi!carp Alaska, LIA: CASING DETAIL Size WT Grade Conn ID MD Top MD Btm TVDBtm 26" Surf. 327' RKB to TBG Hngr = 42.68' 13 - 3/8" 61 1 - 55 Butt Surf. 2160' 2113' Tree connection: 3 - 1/2" EUE 8rd 47 N -80 Butt 8.681 Surf 79' Ji , 1 9 S /8 „ 40 N -80 Butt 8.835 79' 6275' 5523' 6" 43.5 N -80 Butt 8.755 6275' 8179' 7086' 2 47 N -80 Butt 8.681 8179' 8,450' 7318' 13 -3/8" 9 -5/8" DV Collar 4903' 4905' 4393' 7" 29 P -110 Butt 6.184 8127' 11,479' 9927' 1 TUBING DETAIL 3 -1/2" 1 9.2 1 L -80 1 Butt 1 2.992 1 Surface 1 7,865' 1 6,820' NOTE: H Window cut from 8,450' to 8,516'. Original 9 -5/8" @ 8,994 (7,746'TVD) Jewelry Detail No. p pp h Length ID OD Item 1 303' N/A .25" Control Line 2 303' 27" 2.812" 4.508" SLB BP -61 Safety Valve Landing Nipple 7 3 7,865' 1.55 6.75" Bolt On Head, Discharge Sub Assy it 3 4 7,867' 39.5" 6.75" (2) Pumps - SLB, 17000N 4 5 7,906' 1.1" 7.25" Pump Intake 5 6 7,925' 27.4' 7.38" Motor -SLB 738,14, E142 Dominator RK -S 6 7 7,930' 7,930' N/A 1.48" SLB SKVA Cable 9 8 7,985' 1.751 5.63" Btm ESP Assembly 8 9 7,985' 7,985' Flat Pack - .410" x .710" ® PERFORATIONS S,9 Zone Top MD Btm MD Top TVD Btm TVD Amt SPF Last Opr. Status 10,140' 10,170' 8,759' 8,785' 30' 6 2/19/1992 Open G-2 10,140' 10,170' 8'759' 8,785' 30' 5 10/27/12 Reperf 10,225' 10,257' 8,833' 8,861' 32' 6 2/19/1992 Open G-3 10,244' 10,264' 8,849' 8,867' 20' 5 10/27/12 Open 10,278' 10,340' 8,879' 8,933' 62' 6 2/19/1992 Open G -2 G 4 10,280' 10,342' 8,881' 8,935' 62' 5 10/27/12 Open 10,395' 10,415' 8,981' 8,999' 20' 6 2/19/1992 Open G -3 G -5 10,398' 10,418' 8,984' 9,001' 20' 5 10/27/12 Open G -4 10,440' 10,460' 9,021' 9,038' 20' 5 10/27/12 Open G -6 10,532' 10,548' 9,101' 9,115' 16' 5 10/27/12 Open G -5 G -7 10,600 10,614' 9,161' 9,173' 14' 5 10/27/12 Open - G -6 HB -1 10,622' 10,637' 9,180' 9,194' 15' 4 1/17/2001 Open G 7 Open, frac'd 10,628' 10,670' 9,186' 9,223' 42' 10 & 16 8/26/1995 10,628' - HB-1 10,643' 10,628' 10,676' 9,186' 9,228' 48' 5 10/27/12 Open HB -3 10,846' 10,860' 9,377' 9,389' 14' 5 10/27/12 Open 10,863' 11,000' 9,392' 9,509' 137' 6 2/19/1992 Open HB -4 10,939' 10,954' 9,457' 9,470' 15' 4 1/17/2001 Open HB -1 10,890' 11,006' 9,415' 9,515' 116' 5 10/27/12 Open HB -3 11,038' 11,048' 9,542' 9,550' 10' 4 1/17/2001 Open HB -5 11,040' 11,070' 9,544' 9,569' 30' 8 8/26/1995 Open - H B -4 11,042' 11,122' 9,545' 9,614' 80' 5 10/27/12 Open 11,155' 11,170' 9,642' 9,655' 15' 4 8/26/1995 Open HB -5 HB -6 11,156' 11,240' 9,643' 9,715' 84' 5 10/27/12 Open - H B -6 11,255' 11,280' 9,728' 9,749' 25' 24 6/24/1994 Open HB 7 11,266' 11,290' 9,737' 9,758' 24' 5 10/27/12 Open H B -7 Fill cleaned out to 11337' PM. Fish on top -* 12/17/00: Left 10.14' long fish consisting of coil tubing motor and bit. i 4 -5/8° Perf Gun @ 10/24/12: Cleaned out fill to 11337' DPM, Fish not reco Bred. 7" 11,409' RKB to MLLW ELEV = 103' TD = 11,506' PBD = 11,430' MAX HOLE ANGLE = 39.10° a@D 7225' Revised 11/28/2012 by JLL Hilcorp Alaska, LLC Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G -01 RD 50- 733 - 20037 -01 191 -139 8/25/2012 10/31/2012 Daily Operations: 08/27/12 - Monday N/U 2' Spacer Spool and single BOP with Dual rams. Dual preventor cannot rotate 90 degrees for dual string alignment due to BOP height and A -leg clearance. BOP test not completed due to accumulator failure and delay on quickconnects. Straighten out guy wires. Raise and pin derrick String Draworks. Prepare to set up rig floor. 08/28/12 - Tuesday Rig up pump lines and rig floor. Rig test acquired. Test pump function test and plumb. Fill Riser, bled air and close. Attempt to test blind rams. New test pump will not achieve 2,500 psi high, test OK to 250 psi low. Switch over to rig pump and test blind rams to 3,000 psi. Accumulator function testing OK. Build lubricator sub / joint for eline work Pull check valve on long string, RIH and verify depths w/ 1.8" gauge ring to 2,800'. Fluid depth at 800'. POOH Pull check valve on short string, RIH and verify depths w/ 1.8" gauge ring to 2,800'. Fluid depth at 800'. POOH RIH with 2.2" gauge ring to 600'. R/U Spectra 1 -1/8" cutter and cut tubing at 418'. POOH. Wireline stopping with rope socket at SSSV. Work repeatedly with max tension 2,400 pounds, solid impact, no sticking, free downward movemment. POOH with E line. No tools, wire is from rope socket weakpoint. Short string light steady gassy blow RP. Pull 3.5" tubing close blind rams. SS still on light blow open to tams open blind rams install BPV in SS. RIH LS with 2.25" gauge ring and work from 49 -51' KB. Stickgauge ring, work free and POOH. Work on test pump so can finish BOP test after wireline work. Made 1.8" gauge run again after beating on restriction, all goo clear to 600'. M/U and RlHwith 1.68" Radial Cutting torch. 08/2942- Wednesday Cut long string @ 478'. POOH with RCT, laydown same. Pull 3.5" joint and install BPV in LS. SET BPVS. Test BOPS 200 psi low / 3,000 psi high. Rig up Weatherford Dual tools, pull BPVS. Workboth strings to 75K, no movement. Switched and worked short string, released at 90K, bent joint. Lay down same. Latch backonto both strings and work repeatedly up to 75K -120K. dose dual pipe rams. Pump 20 bbls FIW, well static no vapors. Wait on wireline to male another cut attempt. RU Eline, set strings in tension in Dual slips @ 80K. RlHwith Gauge Ring both strings verify cut depths and restrictions. RlHwith String shot for scale removal @ 2,731' in LS. POOH. RIH with puncher @ cut depth. POOH. RIH and cut LS @ 2,731' leaving 15' fishing neckabove LS top GLV @ 2,746'. POOH. RD E line. Rig up floor to pull duals. POOH LD Both strings and control lines. 08/30/12 - Thursday Continue POOH with Dual string. Dual operations ceased. Continue POOH with L /S. Shut down. POOH to rig Dual equipment. POOH with long string. Cut retrieved and clean cut. Rig down floor and Dual BOPs reconfigure rig and floor for single string handling. Pull off BOPs and lower floor. Prepare floor with handling tools and prepare to RlHwith Guide BHA for eline fish in Short String. Change Rams in BOP to 3.5 ". PU overshot 7 -3/4" w/o grapple and 3.5" DP. RIHand set over TOF on LS @ 415'. RU slicWine, RIHJDC rope socket overshot attempt to retrieve E line cutter assembly. Check weight @ 6,000' slickline 750'. PU at 7000' PU at S/L max of 1,800 lbs. POOH w S /L. POOH with 14 jts 3.5" DP and lay down. RIHw/ Mill 8.5" OD. Spot and PU Power Swivel and single. Swivel again having RH rotational problems swap hoses to mill with reverse controls. Tag up milling to dress off cut flare at 415' MD. Feather milling to prevent junk Approx 8" milled, RD swivel, POOH 08/31/12 - Friday Rig up new tongs and train for operation. RIH w/ 7 -3/4" OS w/ 2 -7/8" Grapple and 14 jts 3.5 ", engage fish. Overpull string to neutral @ 65K and set in slips. Lay down single. R/U slicltine make 3 overshot runs and 1 LIB run, indications are fill probably scale above rope socket. RD Slickline. RU wireline. Pull 15K over SW to 80K and set in slips. RlHwith Tubing puncher to correlate to 15' above first open collar above tag and shoot @ 7,999'. POOH MU and RIH with Spectra tubing cutter and cut pipe at 7,999' positive wieight indicator and collar shift on OCL. POOH and Rig down Eline. PU out of slips string is free, gas lift mandrel interfence noticable, no more than 80K to pull side by side. Fill hole change Pipe rams to 2 -7/8 ". POOHaying down 13 joints 3.5" DP, overshot and original cut joint. Continue POOH w/ 2 -7/8" Tubing. Change out new tubing tongs provided by Williams without full compliment inserts and backups. No backups for 2 -7/8" utilizing old tong procedures again. Continue POOH utilizing pipe wiper, string is oily, general apperance Ok No overtorque noted on breakout. Install beaver slide to reduce camp noise. • Hilcorp Alaska LLC Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G -01RD 50- 733 - 20037 -01 191 -139 8/25/2012 10/31/2012 ,D0* °Pere , 14 09/01/12 - Saturday Continue POOH with SS and lay down total 247 2 -7/8" buttress tubing, 7 buttress pup joints and 7 ea GLV's. Male up 5 -3/4" OS with 7 -3/4" oversized guide and 2 -7/8" grapple. RlHwith 86 jts, tag up on fish @ 2,711'. Install wireline pump in sub on Lower Telly valve. Latch fish, pull in tension to 110K set in slips. RU Hine. RIH w 1.62" gauge ring to 4,929' - 5,029'. Losing weight stick work backup hole, attempt to work down, slack off tension to 6K over neutral, reattempt losing hole to 4,970'. Male deision to cut. POOH. MU string shot RIH to cut zone @ 4,875', detonate. POOH. RIH with Tubing puncher cannot get past 4,856'. POOHand run scratcher losing hole. Decision to make bailer runs on slick line. Continue working scratcher. POOH to swap to slickline. POOH with Eline scratcher still in hole depth possibly 4,838' has a fishing neck will attempt retrieve w/ slicWine. 09/02/12 - Sunday Move Eline unit /slickline unit. Finish wireline unit, swap service rig. Run all possible variations of slickline bailers and chisel point after losing hole and restriction /blockage moved up to 2,980'. Begin RU Wireline. Confer with Senior Engineer to attempt Bling back -off. RD wireline. PU power swivel. Rotate 10 rounds to left, pipe free, added SW approx 40K. Rackback swivel in derrick POOH. Rack back drill pipe lay down 77 wet joints below overshot. On breakon jt 78, an instantaneous pressure release of sufficient pressure unloaded the wire line scratcher and significant scale. Scratcher previously lost and last estimated to be @ 2,980' ?. Secure well immediately, TIW valve stabbed and Annulus closed. 0 psi on annulus 0 flow. Pump 50 bbl FIW down annulus & vent oil /gas and water to pit. Shut in. Monitor well, calculate depths and pressures. Original fish top at 2,911' plus 77 joints (2,425') of production string. Blockage of pressure trap was 5,336' +/- original depth. Estimated String weight without blocks is now 20K. Estimated LOF remaining is 2,695' ?, 2 -7/8" 6.5 # 17.5K, and 2 -3/8 "? 2.5K 540'. Total estimated fish length +/- 3,248'. Putting the new TOF estimated between the GLMS @ 8,189' - 8,612' without hole drag. 09/03/12 - Monday Pressure up on annulus and vent tubing attempt to create circulation. Used several different combinations and vent procedures. Verify annulus holding a column of fluid oil, always backafter bullhead and bleed. Always backto zero pressure from 500 -800 psi. Tubing shuts -in in a minute to 100 psi in 3 minutes to 225. Rig down safety chains on tubing, remove night cap and gauge. Bleed tubing off on 2' line fast vent. Work pipe to the crown, attempt to dislodge scale plugs with brake stops radical. Also pulled to crown beating with hammers, solid sounds good indicator of scale fill. Fill annulus well takng about 3 BWPH. Tubing pressures vary after bleed offs on build rate and pressure achieved max on tubing 300 psi in 15 minutes. Breakfirst joint rotate 4 threads on buttress, vent rotating slowly stop rotate, observe, and repeat. Lay down 1st joint, weight unkiown but packed tight with shale. Repeat process many trapped gas pockets most connections have dome bridge of scale that breaks with venting process. Some joints unload shale some stay packed. Two pressure pockets in GLM joint. Rotate releasing pressure slow until thread jump. Install mud bucket, pickup joint with TIW. Ready dig shale from threads and install TIW. Fish coming dry, checkng joints for fill. Fill annulus. Continue POOH laying down LS to x -over to 2 -3/8" @ 8,031' . Change elevators and slip dies to handle 2 -3/8 ". POOHw 5 joints 2 -3/8" depth TOF 8,188', 7 joints above next GLM in LS. PU 5 -3/4" OS with 7 -3/4" guide and new 2 -7/8" grapple. Change out Tongs, elevators, and slips to 2 -7/8" DP. MU BI-A. Open Blind Rams, 0 pressure on casing. RIHwith pipe from derrick 42 stands, re- torque all center stand connections after BBO. Slips not biting, changing out slips. Replace slips with larger rig slips, won't bite, repair smaller Cavins. Continue RIH w/ pipe from derrick. 09/04/12 - Tuesday RIH with approx. 5,854' DP, well flowing . SI well. SICP 75 psi, secure well line to pump. Open well, continue RlHfrom 5,854' - 7,985', jt # 253. PU Power swivel on Joint 254. Workdown Jt 254, no fish top. Pick up joint 255 and tag up on fish. POOH for wash pipe run, lay down single. Set back swivel. POOH. Noticed shield on block sheave cover folded back on blocks, secure well. Set blocks down, take derrick photos, secure and lock pipe rams, disable hydraulics to GO (blind rams). Close all kill and choke line valves. Wait on daylight to utilize crane and man basket to inspect derrick. 09/05/12 - Wednesday Y, W ww Perform derrick repairs. • Hilcorp Alaska, LLC • Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G -01RD 50- 733 - 20037 -01 191 -139 8/25/2012 10/31/2012 Daily Operations: 09/06/12 - Thursday Finish derrick repairs. String new drill line and install on rig. RIHwith workstring. POOH with workstring to inspect fishing tools. POOH with 60 stands of work string, continue to POOH. 09/07/12 - Friday POOH with overshot. Inspected bottom of guide, indicates rotating on top of flaired fish. Run carbide and dress top of fish with mil control and latch fish. Recount workstring to confirm stands, prepare for BOPE test. Test BOPE 200 psi low / 3,000 psi high. RIH and remove tubing hanger plug. Install wear bushing. M/U 5.75" Overshot dressed for 2 -7/8" tubing. RIHNith 2 -7/8" IF workstring 126 stands, p/u Power swivel and single joint of 2 -7/8" Worlstring. Mill over the top of fish but unable to male any hole. Call for slickline crew with Impression blocky shut down power swivel to POOH. 09/08/12 - Saturday POOH racking doubles in the derrick Replace winch lines and cables, inspect connections on power swivel. POOHracking doubles, remove overshot to inspect. No wear on the carbide, but wear mark internal on the control. R/U slickine. P/U section of lubricator, pump in sub and wireline packoff head. M/U tool string consisting of 1 -3/4" stem, oil jars and spang jars. M/U 8" LIB. RIH, tag fluid at 430', and obstruction at 7,977'. Tag and POOH RIH with LIB to obstruction at 7,977' close hyd jars, open spang and jar down on fish, made 4 jar down hits without picking up off of fish. POOH. Remove 8" LIB, had good impression of 2 -7/8" tubing body. Rig down slickline and rack equipment. M/U cutter, 4 joints of wash pipe, jars, drill collars and accelarators. Swing fishing equipment to v -door to prepare for fishing operations. M/U fishing string, consisting of Wavy bottom shoe, poor boy friction cutter, 4 joints of 8.125" wash pipe, bumper jars, oil jars, 4 drill collars, 4.73" Od, accelarator jars, and rotary sub. RIHNith fishing assembly and 2 -7/8" IF workstring. 09/09/12 - Sunday RIH with fishing tools on 2 -7/8" IF work string. Worked over top of fish, pick up double and continue over top of fish. M/U power swivel and pick up single joint. M/U a second single joint to place cutter in position. Begin outside cut with poor boy cutter. One hour on 2 -3/8" with poor boy cutter, shut down pump, open bag and pull up hole to checkif fish is free. Pull up 6 feet into a collar, fish is not cut in two yet, lower backto exact position, leave pump off and bag open, begin operations again. Rotate on fish with poor boy cutter, making pick up every hour to collar appx. 6 foot above cut zone. 2 -3/8" tubing is not cut yet, continue operations with cutter. Continue to rotate with poor boy cutter making pick up to check for cut each hour, return to exact mark and begin cutting operations again. Still no release on pipe. Continue to rotate in attempt to cut pipe. Pull up to joint to remove single and lay down power swivel. Power swivel hung in derrick P/U tongs and begin tripping workstring and fishing tools. Workstring out of hole, lay down accelarators and begin racking drill collars, layout oil jars and bumper jars, begin removing wash pipe. 09/10/12 - Monday POOH with cutter, spring arms are expanded and not closed enough to provide cutter friction against the 2 -3/8" tubing. M/U overshot with carbide mill guide to mill over fish top and latch tubing string. P/U crossover, jar assembly and drill collars. RII -With work string to top of fish. RIH with workstring, checking torque on each joint in case a blind backoff is required once fish is engaged. On bottom with hollow mill cutlip guide dressed with carbide to 2.875" ID, 5.75" lower extension, Bowen 5.75" OD Serie! 150 overshot with 2.875" basket grapple and mill control packer, bumper /oiljars, 4 drill collars, accelartor jars. Begin working over fish top, using power swivel. Tag top of fish and engage power swivel to begin milling over and latch 2 -7/8" tubing. POOH3nd inspect overshot. Out of hole with workstring, begin to rack back fishing assembly. L/D small tong and M/U tongs to remove and rack drill collars. Remove and L/D oil jars and bumper sub. ND fish in the overshot. Marks indicate the top of fish entered the control guide but did not engage the overshot grapples. ID through the cut lip guide is larger, indicating milling over hard surface. • Hilcorp Alaska, LLC • HiI( orp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G -01RD 50- 733 - 20037 -01 191 -139 8/25/2012 10/31/2012 Daily Operations: 09/11/12 - Tuesday M/U assembly range is 1. asse b consisting of Bull Dog segmented Box Tap with 3.50" IF box up connection. Catch ra e s 50 to 5.50". / Y g g g p p g Connections thread locked for safety. RIH with 2-7/8" IF workstring, fish is no longer located at 7,967', moved down hole or broken off at point of poor boy cutter useage. Add additional joint and workdownhole. Add second joint and workdownhole to engage fish. P/U third joint of workstring and tag top of fish. Work over fish with weight, adding right hand torque until making up buttress connections. Continue to add torque to workstring, pickup string weight fish is latched, calculate backoff weights and prepare to make blind backoff at second joint above packer. Since we have a different fish top and a loose fish on btm, decided to trip pipe, remove the box tap and immediately pickup the overshot to latch new fish top (2 -3/8 ") tube and male a e -line gauge run, if successful run strip log and make cut. 09/12/12 - Wednesday Remove box tap overshot, replace with grapple overshot for 2 -3/8" tube. P/U 5.75" Od 150 series Bowen overshot. P/U worktring and RIH to top of 2 -3/8" tube, work over top of fish, engage with grapple. RIHwith a -line, tag top of fish in overshot at 8,053' work thru and downhole to 8,548' tag obstruction. Run log to determine location of obstruction, workthru and down to depth of 9,850'. Log from 9,850' to 8,053'. POOHwith a -line swedge and lay down tools. P/U hole punch to exhaust when running tubing cutter. POOH with a -line to replace CCL. RIH to 9,850' tag obstruction. Pull up hole, log three gas lift mandrels, locate and shoot holes at 9,843' - 9,846'. POOH and pick up tubing cutter. RIH and cut tubing at 9,833' with 20K over string weight, positive indication of cut. POOH with Orbital cutter. Out of hole with orbital cutter, cutter is expended. R/D a -line. Rig up to reverse circulate the casing clean prior to pulling out of hole. Pick up TIW and make up for circulation. L/D pup joint and rackthree stands to the derrick, pulling slowly, hanging and releasing while pulling out. Pull approx. 220.5' from a -line cut and tag obstruction. Worfng tools at obstruction, possible 2 -3/8" gas lift mandrels offset causing larger OD's to collide and become tight inside the 7" casing. 09/13/12 - Thursday P/U power swivel and stab on top of workstring. Prepare to pump NXS Lube to spot in casing across the stuck fish. Begin working down to release stuck tools by using bumper jars and weight of drill collars. Continue to work down on tools, fish begins moving down hole, work up hole freely. L/D single joint and pull up hole with next single. Continue to work tools while rotating workstring both left and right, fish released from overshot. RIHwith additional joint to reconnect. POOH with workstring, fishing assembly and overshot. Redress overshot and added extension for deeper catch on 2 -3/8" tube. Male up assembly using Baker Loc on threads. Pick up bumper sub, oil jars, drill collars, and accelartors, begin RlHwith work string. On bottom with overshot, pickup single joint to space out and latch top of fish. Pull up to ensure overshot engaged, pickup power swivel, install both stiff arms with cables. • • Hilcorp Alaska, LLC Hilcorp Alaska, LL(: Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G -01RD 50- 733 - 20037 -01 191 -139 8/25/2012 10/31/2012 Operations: : 09/14/12 - Friday Reduce torque on power swivel. On top of fish. With power swivel connected attempt to rotate torque from short string tubing. L/D power swivel to rig up a -line for strip log run from first mandrel @ 8,173', log up hole to overshot. Pad -eyes being installed on skid beams for power swivel. 7/8" cables on board with new chains and ratchet binders to hold power swivel. Eline running strip logs to determine exact depths prior to making cut. Continue working E -line while manipulating workstring and 2 -3/8" tubing to determine movement in the string. POOHwith a -line and make up Radial Torch cutter. Workstring to allow a -line tools to move freely downhole to objective. Mahe cut at 8,163', exactly 10' above the GLM in the short string. POOHwith Radial torch and a -line tools, indication of cut thru a -line cable and positive indication of torch igniting. Racke -line to the side and prepare to workfish. Work fish, in attempt to free up from current location inside the 7" liner. Nb upward movement. R/U power swivel, added the 7/8" cables, chains and binders to secure in position. Working torque to 2,500 # left hand and 3,500 # of right hand torque. Workstring backed off, re- engaged and turned 4,000 # of torque into the workstring, full string weight back. Worked pipe to attempt movement. No visible movement in the string. R/U a -line with free -point tools and RIHto bottom of fish at 8,163'. Begin making multiple free point runs at varying overpulls to determine location of stuckpipe. Pull workstring up to 28K over pull at the fish. No indications or determination of movement in the 2 -3/8" tubing. POOHwith e -line to remove free -point tools, and place (LL at lowest point in the a -line tool string. Plan to confirm the cut is complete in the short string above the gas lift mandrel, 2L tool installed on E -line for lowest point in string, running in hole to top of GLM in short string side, begin logging up hole to male determination. E -line cannot confirm clean cut. POOHto make up chemical cutter. Chemical cutter on the e-line, CLL log previous to this run showed to cut pipe. RIH to 7' above the GLM in the Short string. P/U workstring in block pull to 114K and fired cutter. Hanging weight is now substantially Tess. Will verify cut upon retrieval of eline. 09/15/12 - Saturday POOH with eline and chemical cutter. OOHwith e -line, pick up on string, workstring is free, Iaydown 10 joints and begin pulling doubles. Plan to ask for waiver on BOP test in order to run workstring in hole and avoid having pipe in derrickduring high winds. Out of hole with workstring, removing accelerator jars, 4 drill collars, oil and bumperjars. P/U overshot with 2 -3/8" tubing. Begin breaking out short string fish and laying down for tally and final measurement. E-line crew preparing tool string to run in hole with 8" Impression Block. Fishing Tool Supervisor preparing skirted spear for next run. Recovered 9 full joints of 2 -3/8" completion tubing from the short string side, 1 pup joint and 2 cut joints, one in the overshot and the second on the bottom of recovered fish. E -line is rigged up with 8" impression bkockand preparing to start in hole to top of obstruction. RIH with LIB, tag obstruction at 8,111'. POOH. P/U 6" LIB, RIH and tag obstruction at 8,111'. Both runs were zero at rig floor. POOHwith tool string. Tagged at top of 7" liner again. POOH. P/U the 5.5" LIB, RIHto 8,111'. Continue to stop at top of liner, tagging low side of liner top. POOHto Iaydown a -line. R /D, pickup skirted spear for 2 -7/8" tubing inside of 7" liner. Begin pickng up BHA. P/U work string and RIH. Run 121 double stands in hole from derrick P/U 8 singles from the V -door and run in hole. Worktools past the 7" liner top and on top of fish. 09/16/12 - Sunday On top of fish, appears to have latched into 2 -7/8" tubing. Working string, jarring on fish at 130K, fish is moving up hole. Continue to work tubing, pull and lay down a single joint and pulled on stand and racl'd in the derrick. Waiting on high winds to subside. Prepare equipment for BOPEtest. Check Od's of both test plug and wear bushing, order 4 -1/2" IF pin x 2 -7/8" IF pin connection in order to run test plug and recover wear bushing. Begin rigging up to pull wear bushing using test plug. RIHto hanger and pull the wear bushing. Remove and prepare the test plug. RlHwith test plug, landed in hanger, run in two pins. Pressure test BOP 200 psi low / 3,000 psi high. Jim Regg, AOGCC, waived witness of test. Test super choke, TIW and prepare to pull test sub joint and close Blinds. Shut down all operations, wind speed is at 80 MPH plus gusts. • Hilcorp Alaska, LLC Hi!carp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G -01 RD 50- 733 - 20037 -01 191 -139 8/25/2012 10/31/2012 Daily Operations: 09/17/12 - Monday Prepare rig to pull workstring and fishing tools. Pulling out of hole with doubles. Racling doubles in derrick. Out of hole racking up drill collars, remove jars, and pull up to rig floor with spear and fish. Breakout 2 -7/8" completion tubing and begin laying down fish to deck. Fish is broken down and laid on deck. P/U overshot for 2 -3/8" long string and begin malting up overshot and BHA for next run in hole. RIH with BHA and work string to top of long string fish. Continue in hole with BHA. On bottom with BHA, rotate pass the 7" liner, tag top of long string fish engage with overshot @ 8,169'. R/U eline with EL and impression block. RIH tag obstruction at gas lift mandrel 8,181' E Tine measurements. POOH reconfigure tools string. Rerun to same spot, unable to work thru, POOH, rig down eline and prepare for power shutdown on platform. 09/18/12 - Tuesday P/U power swivel, make up to work string and begin checking weight for blind back off operations. POOH with workstring and BHA. Rack drill collars, Iaydown jars, pull up overshot with GLM and 2 -3/8" tubing. Laid down fish which included 1 Gas lift mandrel, 1 pup joint, and 11 full joints of 2 -3/8" completion tubing. Bottom joint has a collar. Breakdown overshot and replace grapples, prepare tools for next fishing trip. Remove recovered tubing, mandrel, and pup joints from v -door Iaydown area. Paint long string tubing to insure separation of two completion strings. Mahe up overshot, pickup bumper sub /oil jars, 4 drill collars, and pickup accelerators. Make up work string and begin tripping in hole, BHA consist of 5.75" OD, series 150 Overshot with 2.375" baslet grapple and mill control packer. Ran all doubles in the derrickand begin picking up 9 single joints to reach top of fish at 8,416'. Latch short string, pick up weight of tubing and moving, stop to discuss options prior to pulling against short string. Laydown the power swivel and prepare to workshort string tubing. E -line preparing to rig up if unable to workpast the long string. Pulling short string tubing, with top 2 -3/8" mandrel above the long string, begin pulling out of hole with short string, pulled past second gas lift mandrel in SS against mandrel in LS. Continue pulling up hole notice friction weight increase at mandrels. Pulling free. Currently pulled up hole 1,739.5' with short string from top of fish as engaged with overshot. Short string and overshot are now in the 9 -5/8' casing, pulling out of hole with short string. Out of hole with workstring, lay down bumper and oil jars, racking drill collars, prepare to pull overshot to rig floor. 09/19/12 - Wednesday Pull up to fish to inspect tubing, Iaydown overshot with 6 ft cut 2 -3/8" tubing nub. Rig up elevators and slips. Pickup tongs for 2- 3/8" tubing, fill hole with produced water and begin Iaydown operations. Laydown 4 GLM. Pickup overshot with new grapple to latch 2 -3/8" EUE tube. RIH to top of 7" liner, picking up 3 single joints to reach top of fish. Latch top of long string tubing, begin working torque to packer in attempt to cut shear pins and stretch packer. Continue to work torque downhole. Working packer to cut shear pins, at 1800 hrs begin jarring at 30K over, pulling to 160K in tension after jar action, will increase jar action in stages. Continue jarring on packer. Continue jarring at max pull, overpull after jar action to max on rig with 6 lines. Stop jarring and prepare to blind back off at top of packer in the 2 -3/8" EUE pin connection. Pick up power swivel, make up to work string, torque to 7,100 and begin working BBO into the 2 -3/8" tubing string. Backoff in the 2 -3/8" EUE collar at top of packer. Rig down power swivel. Secure work string with TIW for crew meal. Pull out of hole with workstring and BHA. Out of hole with workstring and top of BHA. Remove accelarators, rack4 drill collars, remove the bumper /oil jars and pulled overshot with fish above the rig floor to begin Iaydown process. Lay down overshot with first joint, begin brealing out 2 -3/8" long string and laying down to tally lengths. 09/20/12 - Thursday Pulling and laying down long string fish. Top of fish is now at 9,633.18'. Pickup overshot to latch 2 -3/8" tubing collar. Male up grapple with mill control to latch collar and prepare to RlHwith BHA and workstring. Pickup workstring with BHA, running in hole, bundling Tong string production tubing with thread protectors for offloading. Run in all pipe in derrick picking up singles to reach top of fish at 9,633'. Pickup, drift and make up 35 single joints of workstring to tag top of fish. Latch top of fish at 9,633' begin jarring to release packer, getting solid jar action less friction from deviation in the wellbore. Pull up hole two feet dragging weight. Lay down single joint, pickup lost weight, pick up single, attempt to latch fish. Unable to re- engage. Prepare to trip pipe and inspect fishing BHA. Rig down power swivel, lay down singles, begin pulling 150 doubles and rackng to the derrick. On surface with workstring. Laydown and rack BHA. Pull up with fish. Hilcorp Alaska, LLC • Hiltorp Ala.ka, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G -01RD 50- 733 - 20037 -01 191 -139 8/25/2012 10/31/2012 Daily OperatOrts: 09/21/12 - Friday Run in hole with Overshot to latch short string tube and release packer at 9,919'. Continue to trip in hole to latch short string. Pick up power swivel, rotate into the 7" liner, laydown swivel, continue running in hole with workstring, pick up 5 singles and latch top of short string. Working jars on packer in attempt to pull free. Tail pipe from short string is on top of the blast joints below the hyd packer. Continue to jar on packer, seeing movement, packer is sliding down hole but taking weight when pulling up. Continue working packer, prepare to blind back off to top of packer in order to move to long string for slickline run below packer and to fish slickline tools. Back off complete, due to short length of remaining completion string on short string side, weight is not legible. Lay down single and swivel, pick up single and pull out of hole racking 153 stands in the derrick Out of hole with workstring begin removing accelatator, racking 4 drill collars. Laydown bumper /oil jars, remove overshot, recovered cut joint that is perforated (22 ft) of 2 -3/8" completion tubing with perforations, pin down. Pickup overshot with grapple to latch 2 -3/8" buttress collar on short string completion side. Begin running in hole with BM and workstring. Continue to run in hole with BHA and workstring to top of short string fish (collar). 09/22/12 - Saturday Latch top of short string, work fish in attempt to release and recover packer and long string tail pipe. j SlickJine crew on board, swing unit into position waiting on electrician to connect power supply while crew lay out tool string. Run in hole with 1.80" guage ring, tag top of fish in overshot @ 9,842'. POOH and make up 1.75" guage ring using measurements from first run, tag obstruction at 9,867' beat down on obstruction. POOH to pick up 1 -1/2" pump bailer. Run in hole with 1 -1/2" pump bailer, double section, bailing fill from inside short string, making hole, recovering some scale and fill. Rerun bailer in attempt to reach depth and male eline cut. Continue bailing scale and fill, recovering full bailer each run. RlHwith 1 -1/2" impression blocktag obstruction at 9,894' slickline measurement. POOHto review impression and decide next step in operation. Impression of metal junkin tubing, probably located in the SSD. Rig up pump and begin circulating down tubing taking returns from casing to the rig tank, 2 bbls per minute, good returns, displaced the workstring and short string tubing. Shut down pump and rig up slicldine with blind box. RIHto 9,894' jar down on obstruction, no movement. POOH Rig down slickline, pick up power swivel. Ready for Blind BackOff, working string while adding torque, unusual movements, continue operations while slackng off and pulling on fish. Weight dropped off but still attached to fish, pull up on fish, move up hole 2 feet with 30K over string weight. Pacler is moving up hole or tubing is moving against other stuck junk and debris. Working string, jar up on fish, work down and continue upward jarring, circulating down tubing taking returns from the casing, jar for an hour, fish is unstuck, pull out of hole to inspect BHA. Pulling out of hole g g gJ kp p g slower than usual as some workstring joints have loosened, re- tighten center joints in doubles and continue to rackwork string in derrick. Out of hole with BHA. Move to long string side with operations. 09/23/12 - Sunday Rig up slickline. Hang sheeves, string .125 slickline, and pick up 5.75" impression block, tag up at 8,140' (top of 7" liner) unable to pass with this tool. Pull out of hole, re configure the tool string, bevel the 5.5" impression blockand run in hole, work by the liner and down to top of fish. Tag obstruction at 9,886' slickline measurement. POOHwith impression block. (impression of a -line tool string rope socket on the low side of 7" liner) Make up JDC pulling tool on slickline tool string and RIH to top of fish @ 9,886', work tools, latch rope socket, begin working jars with 500# overpull. Continue to jar on tool string, fish is moving, jar harder and pulled the fish free. Out of hole with slickline tools and e-line tools. Male up redressed 5.5" impression blockand RIH to top of fish at 9,897' slickline measurements. Change in depth is 11 feet. Pooh with LIB. Male up overshot for long string side to latch 3 -3/4" Od. Make up bumper /oil jars, make up 4 drill collars, and accelarators. Will torque each joint of workstring going in hole as signs of possible loose threads in the IF connections. On bottom with overshot, workng with power swivel to rotate and latch over fish. Working overshot with swivel, getting friction bite, pulling off at 15K, continue to workon fish by rotating, torquing up. Rig up slickline ran thru workstring and tag obstruction at 9,894 slicldine measurement. POOH and check LIB. Modify star bit to replicate swedge in attempt to open ID and move bent metal out of the way. Working tools, sticking but jarring free without problem. Continue to work on top of obstruction. Hilcorp Alaska, LLC Hileorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G -01RD 50- 733 - 20037 -01 191 -139 8/25/2012 10/31/2012 Daily Operations: # 09/24/12 - Monday Slickline in hole jarring down on top of fish in long string, attempt to get thru top of packer and gauge for eline cutter to release lower completion. POOH with slickline, rig down and rack equipment. With power swivel backin position, right turn over top of tubing fish to engage overshot /grapple, friction bite on the tubing, jarring down with bumper sub, jar down several times to bury fish inside grapple. Attempt to back off fish with left hand torque. Unable to remain engaged. Decision to pull out of hole, lay down power swivel, pulling weight thru first 35 feet. Pulling out of hole with BI-A racking doubles in the derrick. Pick up BHA assembly and start operations, running workstring in the hole. On bottom with overshot BHA, pick up power swivel to rotate over fish and attempt blind backoff or jar fish free. Working over top of fish in attempt to latch fish and perform backoff of tubular to top of RDH packer. Rotating to left with torque while jarring down on top of fish. Unable to retain enough torque to blind backoff connections. (Lost and loose fish around top of current fish include lower part of XA sleeve, 2 -1/4" OD Steel Jet cutter body, and collar from short string tubing.) Remove power swivel, POOHracking workstring to the derrick. 09/25/12 - Tuesday Out of hole with work string, laydown and rack BHA, begin completion of BOPEtest. Test BOPE 200 psi low / 3,000 psi high. Jim Regg, AOGCC, waived witness of test. Pull and cut drill line and male up milling assembly to remove metallic obstruction on top of packer. Pull test plug from hanger. R/U surface well head equipment, cement bailer and start mixing product. Run in hole to top of fish at 9,887' dump cement using 40 ft bailer system. POOH Refill the fill bailer at rig floor, rerun to top of fish and dump cement. POOH with e -line cement dump bailer. Refill with cement capable of full hardning in 3.5 hours. Stab thru BOP stac(Cland surface equipment back thru Annular preventor, close surface lubricator. RlHwith third bailer run. Rig down e-line. 09/26/12 - Wednesday Install wear bushing and add 1/2 drum of NXS Lube to assist in torque reduction during milling operations. Begin mating up BHA for mill run. RIH to bottom with mill, check cement for hardness, surface sample ready within 3 hours, which confirms downhole cement is ready to hold junkfor milling operations. Tag top of fish at 9,852', pull up, remove single, add two pup joints, pickup swivel and single joint to begin milling. Milling over fish, recovery is cement and metal. 6ntinue milling operations, reverse circulating at 2.5 bbls per minute. Pressure climbing, lifting green cement and metal from fish. Made 2.5 feet, stop milling to allow cuttings to clean up in the workstring. Top batch of cement is still curing. Waiting on green cement to firm up. Start up pumps and begin milling operations, recovering cement, metal, and rubber. Milling down thru fish with recoveries, ports stopping up, pickup off fish, stop pumps, reverse and pump back down hole to clear the workstring and mill. String clear, begin reverse circulating at 3 barrels per minute and start milling on fish. Hard milling on fish, recovering metal and cement, stalling and torquing up, made total of 9 feet 09/27/12 - Thursday Milling on top of fish at 9,861' pipe measurement. Milling operations began at 9,852' made total of 9 feet, able to piclup clean from top of fish and move back to top without any problems, indicating hole is cleaned to 9,861'. Mill is turning clean with little or no torque, prepare to spud down on fish top in order to rearrange milling pattern. Spud and workon fish making hole again intermittently continue milling approx another 1.5 feet. Good fine cuttings in returns some carbide evidence stop maing hole. Circ tubing clean lay down single hang off swivel, Pull 4 stands adjust draworls and POOH w/ workstring to BHA. Pull BHA. Mill is center cored but well worn no carbide chunking. M/U 6" OD Bladed stabilized mill with carbide inserts, bit sub Stabilizer, 6 ea 4- 3/4" DC, Jars and RIH with workstring. PU power swivel tag up on fish @ 9,859' with B Sub /Jars open mill to 9,863' 4 -5K WOB starting to torque up and plug off at report time. 09/28/12 - Friday Continue milling from 9,863', torquing and plugging off a bit. Continue milling plugging off at mill periodically about once an hour total depth achieved 9,869'. Early returns not identifiable as tubular probability of wirleine tools. Last 8 ' of milling good tubing cuttings. Depth now 9,869'. Depth from top of packer est 15 -17 feet. Grc tubing clean, hang off swivel, pull 2 stands hang off blocks. Slip and cut drilling line 100'. POOHto Milling BHA. Rack back Collars lay down jars change out mill. M/U new 6" insert mill, RIH with BHA. RIH with workstring from derrick. • • . Hilcorp Alaska, LLC tti�cori, Alaska. LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G -01RD 50- 733 - 20037 -01 191 -139 8/25/2012 10/31/2012 Daily Operations: 09/29/12 - Saturday RIH with pipe out of derrick, tag up on liner top. Roll over and into liner top utilizing tongs. Continue RIH with pipe from derrick total in hole 304 jts. Rig up dual stiff arm cable and power swivel. P/U 2 singles, M/U swivel and brealcirculation above fish. Wash down to TOF tag 9,867'. B/S open mill to 9,880'. Significant scale at times in returns. Grculate DP clean set back swivel and POOH. 09/30/12 - Sunday Continue POOH to BHA. L/D 2 DCs stand back 4 DC and BHA. L/D jars and Bumper Sub Stanbilizer and Mill. Mill is smooth worn no coring evidence. M/U Washover assembly 6" Smooth OD Shoe with 4 -3/4" ID , 1 jt 5 -3/4" WP Drive Sub, Bumper, Jars and 4 ea DCs and x -over to DP. Total BHA length is 187.67. Change out handling tools, RIH with 1 stand DP from derrick. RIH w/ pipe from derrick, 153 stds/ 306 jts. P/U 2 singles, jt number 308 tag fish top at 9,881'. P/U power swivel begin washover ops. Washing over tubing above packer, heavy scale, some asphaltine and metal cuttings in returns. State %tified of BOP test 24 hour notice. Continue washover milling ops @ 9,884' + high torque whipping on swivel. 10/01/12 - Monday Continue washing reaming over tubing above packer. Washover and mill to 9,896' recovering some loose junkappears to be mill control packoff pieces from run where guide was lost off overshot. Kb carbide left on shoe torquing up on junk and bouncing. Circ tubing clean st back swivel, POOH to change Shoe. POOH change to change shoe fish up in washpipe cannot break (NO MOUSEHOLE). Cannot stick shoe back in hole to risky loosing junk. Fight Shoe off washpipe install protector with blind plate. RIH break out jars and bumper. Lay down washpipe and recover fish from inside. P/U new Burning Shoe 6" OD x 4 -3/4" ID new joint of washpipe as old waspipe joint still has junk Jarring assembly and colllars same as previous run and RlHwith pipe from derrick. P/U Power swivel and 2 singles and Tag up on fish top @ 9,896' +/- with some junkon top. Continue milling washover ops. 10/02/12 - Tuesday Washover and mill to 9,897' +/- circ tubing. Gear) cuttings throughout - acceptable cuttings volumes. Grc tubing clean. POOH with 80 stands. Depth of washover shoe is @ +/- 4,856' SW. Rig up for testing. Test BOP 200 psi low / 3,000 psi high. ec stack clean, retrieve wear bushing with work string suspended below test plug, reverse test plug suspend workstring below test plug for testing. Tested choke manifold and accumulator while waiting on test plug. 1 valve failure in Manifold repaired cycling and grease. Accumulator passed but back up air system failure due to broken air dryer vent that has happened in the last 24 hours. Pressure setting bourdon tube is worn need to replace to bring accumulator to 3,000' psi. Kill line rerun per witness instructions. Low pressure tests difficult to maintain below 550. Rig down from test. Pull test plug, reinstall wear bushing pull test plug proved extemely difficult could not releaase off of wear bushing several attempts many problems. RIHwith 80 stands. P/U Power Swivel. Establish Circ and continue washover milling ops mill not malting progress increase WOB to 4 -5 K before pulling. 10/03/12 - Wednesday Continue working mill. POOH. Lay down BHA, break OD shoe, good internal wear pattern indicating over fish. MU BI-14 5 -3/4" OS with cutlip guide and 4 -3/4" spiral grapple, adapter, 1 jt washpipe. RIHand tag top of liner /fish. P/U power swivel. RlHwith power swivel, work down over top of fish and latch. P/U 160K hit w/ Jars, lept slipping off. POOH w/ work string racking same back. 10/04/12 - Thursday Break down BHA. MU BHA with 6" OD X 4 -3/4" ID burning shoe. RlHwith jarring BHA and 104 stands from derrick. Continue RIH to top of liner work through. RIH to TOF, level rig, P/U power swivel and mill / wash over packer. Circulate bottoms up, set back swivel and POOH. Change Mill, RIH with BHA and pipe from derrick. PU Power swivel and resume washover ops @ 9,900' + / -. 10/05/12 - Friday Continue milling. R/D power swivel and POOH POOH to BHA. Break down BHA and lay down leaking jars. Make up 5 -7/8" OS with 4 -5/8" grapple. P/U Jars and RlHwith collars and pipe from Derrickto top of liner. R/U P/U single, circ off top of line, worksurge and wash. P/U power swivel, install stiff arm cables and rotate through top of liner. Set backswivel and continue in hole. RIHto TOF, 153 stands to 9,876'. P/U power swivel, install stiff arm cables, P/U single workdown and latch fish. R/U and secure elevators for jarring ops. Working /Jarring Fish @ 160K. • • . Hilcorp Alaska, LLC • HiIc-orpAlaska,LLC \/ell operations Summary Well Name API Number Well Permit Number Start Date End Date G -01RD 50- 733 - 20037 -01 191 -139 8/25/2012 10/31/2012 Daily Operations: -. flt.: 10/06/12 - Saturday Continue Jarring fish moving after hitting at 184K pull fisrt stand 130 -140k Continue POOH to BHA. Breakdown BHA including RDH packer. M/U BHA 5.75" OS with 2.702" grapple and RIHwith pipe from Derrick. P/U power swivel prepare to workover fish. Tag fish at 9,905'. L/D single, P/U Pup joint, R/U power swivel workover fish. POOH slow to liner top, normal trip mode to BHA. 10/07/12 - Sunday POOH and L/D BHA. Break down overshot and L/D bad jars. MU BHA 5 -3/4" OS with dewssoff guide and 2 -3/8" grapple and RIH with pipe from derrick. P/U pup joint and space out under top single. R/U Power Swivel and Tension cables. Dressover Fish top @ 9,905'. Work string down full length of pup joint, string appears to be traveling downhole. Pickup one single verify string moving down hole. Pump down tubing to clear tubing top for possible spear run. Est. TOF 9,926'. Release tension lines, set backPower Swivel, lay down 2 singles and pup joint. POOH rack back in derrick. 10/08/12 - Monday RIH with pipe out of derrick. P/U Power swivel, P/U singles and Tag fish @ 9,926'. POOH70 stands. Continue POOH to top of fish. Overshot was engaged on an adapter sub not in BHA schematic. Cut tubing with rigid cutter to lay down. Build lift sub and handling eqquipment modifications to handle blast joints. String is plugged. L/D blast joints in doubles 3 ea and 1 single twisted off /parted at the pin. M/U BHA consisting of 5 -3/4" OD OS with 2.702 " Grapple and RIHw pipe from derrick 149 stands. 10/09/12 - Tuesday Continue RIH move 8 joints from pipe rackand strap. Pick up 8 singles RIH and tag 7' high SS cutoff. P/U power swivel roll over fish top and engage longstring on depth. POOH. RIH w/ 3 stands, verify pushing fish SW change looks positve for fish in OS, catch unable to verify loss of fish. POOHto BHA. L/D Accelerators and rack back collars. L/D Jars, BS, Break Fish Joint, and L/D Blast joints. L/D in doubles 40' lengths. New TOF is 10,405'. Prepare to test BOPE Test BOPE 200 psi low / 3,000 psi high. All good except on valve in Choke Manifold #7. Can make test with enough grease but 2 consecutive problems will change valve later today. Problems with test plug holding low pressure. After pressuring up against pipe rams with TIW in place weeping stops. Will modify SOP to energize first. Pull test plug reinstall wear bushing. l-ble is full took only displacement to fill before test 20 bbls. 10/11/12 - Thursday P/U M/U BHA, 6" wavey bottom shoe with wire grap inside washpipe. RlHwith pipe from derrick. Rig maintenance and repairs. 10/12/12 - Friday Continue RIH 124 stands plus 10' tag up on liner top. R/U Power swivel and tension cables rotate through liner top. R/D Swivel. Continue RIH w pipe from derrick tag up on fill about 10' above fish apprx. 10,270'. R/U Power Swivel and tension lines, wash down to above fish top 10,400' + / -. Wash down to 10,450'. Wash down returns slugs of sand, scale and debris, minimal metal returns on magnet. Circ. bottoms up, set back swivel, release tension lines and change elevators. POOHto BHA. Rack back and lay down jars and washpipe. M/U BHA 0/S 5 -3/4" OD grapple 2.75" ID, Extension, B /S, 01, 6ea 4 -3/4" DCs Accelerators x -over total Wind gusting in excess of 50 mph. Shut down w/ 54 stands in derrick Waiting length 222.85. RIHw / pipe from derrick d gust g e p / g on weather. 10/13/12 - Saturday Continue RIH while wind down to 40 mph. RIHTag up on fish @ 10,405'. Pickup Foster tongs, rotate over and latch fish. Workfish to 200K in 10K increments set in slips. Leave set in slips @ 200K, slackoff and rig up to circulate. Start to Work fish, 4 stands and a single out of hole. Developed transmission leak Secure well. Close pipe rams and install TIW. Rig Shut down. 10/15/12 - Monday Transmission repair completed. POOHto BHA. Rack back and lay down BHA, Overshot, 2 blast joints, pup joint, sliding sleeve, 1 jt tubing, locator and seal assembly. M/U BHA 6" OD Shoe w 4 -3/4 ID , 1 jt washpipe , adapter, drive sub, BS, OJ, 4 ea 4 -3/4 DCs, and x -over total length 184.39'. RlHwith pipe from derrick work through liner top fairly easy. Continue RIH, Pick up Power Swivel tag up space out and begin milling on packer on joint 327. 10,485 + / -. • Hilcorp Alaska, LLC HiIcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G -01RD 50- 733 - 20037 -01 191 -139 8/25/2012 10/31/2012 Daily Operations: W 10/16/12 - Tuesday Continue to Mill over 3.0' +/- shoe worn out at top of slips on pacler. Circulate bottoms up good cuttings throughout washover process. Lay down single and set back power swivel. POOH to burning Shoe and change same. RIH with new shoe 6.0" OD x 4 -3/4" Rough ID and same BHA. Total BHA length 185.28. RIH w/ pipe from derrick work past liner top and continue to joint 326' 10,471'. P/U Power swivel and single joint 327.Transmission Ieakng, shut down for repairs. 10/17/12 - Wednesday Rig repairs and maintenance. BOPETest choke manifold and accumulator. Choke Manifold tested 200 psi low / 3,000 psi high. Mount valve body and function test. Reassemble transmission mounts, braces and shrouds. Load test. Resume Tag up and burn over packer. Mill over and chase to 10,503' tally depth. Grc Bottoms up. POOH. 10/18/12 - Thursday POOH to BHA, rack back Collars and L/D BHA. Test BOPE 200 psi low / 3,000 psi high. Witness of test waived by Jim Regg, AOGC. Pickup overshot to fish packer after wash over operation. Make up jars, drill collars and accelerators. Male up BHA Overshot with Spiral Grapple. Make up work string and RIH. Pick up foster tongs, replace dies, use 60 inch pipe wrench for additional backup. RIH with BHA and work string making up to torque requirements. All stands in hole, pickng up singles from V -door. Tag top of fish 10,506'. Working over fish while circulating, work down hole to 10,546' rotating, pressuring up while reverse circulating fill. Unable to work below this depth, jar down on fish in attempt to engage overshot. Weight is 115K up and 95K slackoff. Pressure on pump increased after jarring indicating possible fish in overshot. Grculating bottoms up to clean out. Latch over fish, begin jarring 80K over string weight, jarred 6 times, came loose, weight indications are 8K over string weight which can indicate fish and drag from depth. Laydown swivel and prepare to POOH with BHA. Working fish up hole having to jar at least 3 times per stand, currently working 4th stand and continue to jar up the hole. Racking double stands to the derrick. POOH with BHA and Work string in the 9 5/8" casing. 10/19/12 - Friday On surface with BHA, laid down accelerator jars, rack drill collars, lay down bumper /oil jars, remove overshot with permanent packer and 8 foot seal bore assembly. Remove fish from overshot. Pickup 1 joint of 5 -3/4" wash pipe and 5 -3/4" cable shoe with cut lip guide, pickup bumper jars /oil jars, 4 drill collars, and accelerator jar. Pickup work string and begin RIH with BHA. Pick up power swivel and single joint, engage rig pump, breakcirculation and start washing down hole to depth 10,533' pipe measurement. Pickup singles and wash down hole to 10,659' circulating 10 minutes per joint before mating connections. Continue circulating washing down hole adding 4 additional single joints of workstring to 10,786' pipe measurement. Continue washing and circulating down hole, currently have 336 full joints of workstring and BHA. Swing 20 additional joints from pipe rack to V -door, continue circulating and working down hole. Continue to wash down hole using cable shoe and wash pipe, current depth is 10,880'. Pickup rabbit and add singles under power swivel and continue wash out operations, current depth is 10,911'. Depth 10,942' circulating heavy. Worksingle joint, pulling free, circulate workstring volume. 10/20/12 - Saturday Current depth is 11,006' with cable shoe, wash pipe and BHA. Circulating at 3 BPM, recovering formation sand and other debris. Top off rig tank with filtered produced water, wash down to 11,037.5' circulate 15 minutes. Pickup single working down to 11,070' across the HD -5 perforations, continue to work, rotate and add weight. Circulate clean, laydown single joint, rack power swivel and begin POOH with work string and BHA. POOH and rack 3 stands. Continue pulling out of hole with BHA. Rack work string in derrick, 172 stands, pull up to BHA and begin removing accelerator jars. Rackdrill collars, bumper /oil jars. Pickup wash pipe and remove cable shoe. Pickup new cable shoe modified with carbide on bottom to clean out perforations and wash over fish. Male up bumper /oil jars, make up 4 drill collars and accelerators. RIHwith work string from the derrick. Ran all stands in hole, pick up power swivel, pick up single joint and start washing fill, current at 11,070' wash down to 11,090'. POOHusing mud bucket (wet string). 10/21/12 - Sunday Out of hole, trip was wet due to sand and fill in the workstring, bumper /oil jars and the shoe. Completed clean out of work string and tools. Inspect BHA and reassemble for trip in hole. RIHwith BHA and work string. On btm with work string and BHA, pick up swivel, begin circulating. Washing thru fill and circulating at 3 BPM. • • Hilcorp Alaska, LLC Hileorp Alaska. LLC Well operations Summary Well Name API Number Well Permit Number Start Date End Date G -01RD 50- 733 - 20037 -01 191 -139 8/25/2012 10/31/2012 ittOyOperat '� 10/22/12 - Monday Washing down over obstruction and fill, current depth is 11,101'. Begin mixing 100 bbl EEC -10 sweep while working, allow time for reaction and gel effect to occur. Gel material is ready for circulation, begin washing down hole, current depth is 11,133'. Pickup joint and wash down to 11,164', circulating workstring displacement. Continue operation cleaning down to 11,196' with full recovery of debris. Pickup another single joint and begin washing down to 11,227.5', circulating for 30 minutes to ensure clean returns. Wash through 11,227.5' with good returns using FEC -10 sweeps. Circulate clean. Pick up single joint, made hook on single joint, working heavy torque with power swivel working down hole with single joint. Working up and down rotating over obstruction. Work heavy torque several times and backup with single joint to ensure casing is clear. Depth is 11,259', continue adding single joints washing down to 11,337'. F- avy torque with power swivel work joints down, then pulled backup hole and rerun to depth several times. Working at 11,337' unable to wash down thru this area. Decision made to discontinue wash over and begin circulating fluids clean. Check with Trading Bay to ship fluids from rig tankand use filtered produced water to clean out well bore while pumping direct to the Trading Bay facility. Trading Bay has issued a hold for shipping fluids at this time. 6ntinue circulating the wellbore while waiting on permission to pump fluids to Trading Bay. 10/23/12 - Tuesday Reverse circulating the well bore to insure all sand, metal and polymer is out of the hole. Shut down rig pumps and begin cleaning rig tanks, hoses, connections and inspect. Rig up pump to circulate using Filtered water. Pump from the return tankto beam tank and reverse circulate wellbore. Continue filling the main rig tankwith clean filtered inlet water, pump at 3.5 bbls per minute, full returns. Well cleaned over time, now lookng at clean sample with trace of oil in the top of sample bottles. Shut backside in and begin pressuring up on formation, pressure increasing to 1900 Psi at 2 bbls per minute, shut off pump pressure dropping, turn on pumps at 3 bbls per minute pressue at 1950 then began breaking back to 1000 Psi, formation taking fluid at 2 bbls per minute. Injection rate established. Pump tanks dry to beam tank. Lay down two singles, begin working back through perforations to POOH with BHA. 10/24/12 - Wednesday Continue to pull thru perforations with BHA, work free, laydown total of 4 singles. Began tripping and rackng doubles in the derrick. POOH with work string, breakout accelerators, and break drill collars. Laying down drill collars, remove and layout bumper oil jar combo, remove wash pipe and Carbide shoe with Cable shoe combination. Pickup 7" Tripoint test packer with work string and begin running in hole. Ran in hole with workstring from derrick, Set packer at 9,850' pressure up on casing to 1,500 psi, ran chart for 30 minutes, casing holding 1500 psi, test completed. Mix chemicals. Using rig pump, established injection rate. 6emicals mixed (first batch) begin pumping into formation. Mix second batch of chemicals. Pump second batch of chemicals, bull heading into formation with 367 barrels. 10/25/12 - Thursday Continue Chemical pumping operations with 1.5 bbls per minute at 2,200 psi, pumping filtered water at 1 bbl per minute. Begin surface BOPE testing. Stop BOP test. Fluid began circulating, stop pumping, added weight to pacler and test backside. Continue pumping filtered water (bull heading chemicals into the formation). 10/26/12 - Friday Complete injection of scale inhibitors, including 97.5 barrels of preflush consisting of 330 gallons Baler Petrolite WAW- 5206 mixed with 90 barrels of FIW, 367 barrels scale pill (1925 gallons of SW -4004 with321 Bbls of FIW) Plus 850 bbls of over flush to force into perforations. Unseat packer with straight pull release, fluid dropped by 28 barrels, pull out of hole rackng doubles to the derrick. Replace tong dies, check rig and begin operations. Out of hole with packer, lay out for shipping to dock, pick up test plug, pulled the wear bushing, Stab test plug, rig up to begin completion of BOPE test as per requirements. Test BOPE 200 psi low / 3,000 psi high. Witness of test waived by Jim Regg, AOGC . Prepare for perforating gun run. Move pipe from rig mat to the pipe rack while swinging gun carriers to the additional pipe racklocated at the rig. Moving guns from top of new pipe rackto the rig mat, then to the rig floor and begin making up pressure temperature sensor, and begin adding perforating guns per layout. Makng up perforating runs in order of spacing, continue operations. • • ° Hilcorp Alaska, LLC Hi Icor') Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G -01RD 50- 733 - 20037 -01 191 -139 8/25/2012 10/31/2012 Daify,Operations a , x t 10/27/12 - Saturday RIH with work string to spot perforating guns in proper position at multiple zones. Continue operations. Pick up final stand, tag bottom at 11,337'. Pickup off fish, remove single and rig up a -line to log on depth. E line rigging up with logging tools, and prepare to run in hole and log. Ran logs, pulled off bottom and removed two single joints, adjustment made based on log and length of single joint above slips. Total length removed is 53'. Rig up eline backon top of work string and running in hole to run final correlation logs. Running in hole to begin log run. Final correlation log performed, changes lookgood, approval from Anchorage confirmed, Schlumberger confirms accurate placement of perforating guns and verify by signing logs. Pull out of hole with a -line. Rig down eline, Schlumberger setting up monitors, drop ball and allow to fall to tools. Begin pumping slowly to push ball to bottom, pressure building slowly. Pressure at 1,425 psi, guns fired, open needle valve, on vacuum, monitoring the well. Will allow to seek level, then add additional fluids, well stopped sucking after 15 minutes. Adding filter water, Pump 6 bbls, well started sucking, shut down pump, after 5 minutes stop sucking, prepare to shoot echo meter to checkfluid levels. Rig up floor to pull and break out work string in singles, rack on pipe rack and continue out of hole to lay down the perforating guns. Currently breaking out work string to laydown on pipe rack during move to next well. Continue to pull out of hole with expended perforating guns. 54 single joints laid out and racked to pipe rack. Maintaining control of well, fluid is being replaced as we pull BM. 10/28/12 - Sunday Continue operations. Pulling out of hole, breaking out work string to singles and laying pipe to pipe rack Operations continue, lay down Schlumberger guns, and rack for shipping, pick up 13 stands in derrick and run in hole, pull out of hole breaking out single joints and racking to the pipe rack. Remove 2 -7/8" pipe rams from BOP and replace with 3 -1/2" pipe rams, test. Swinging 20 joints of 3.5" 9.2# TOl completion tubing to the rig for tally and installation in the well bore. Remove rig tongs and pickup make up special tongs for completion. Check against new tubing. Check equipment for proper Id, clearance and connections, HYT elevators are at heliport along with crossovers for TIW connections backto completion string TCII instead of buttress. Schlumberger moving spool and ESP to rig side and stacking equipment on North pipe rack. 10/29/12 - Monday Test BOP stack to insure no leaks, pressure up on accumulator to control the annular. Pickup HYT elevators and begin picking up new completions string. Measure each joint, tally totals, drift to insure ID is clear and male up each joint using 2,500 psi torque. RIH with new tubing, total of 242 joints, with one joint on the deckand the second one made up with Schlumberger equipment. Pull out of hole racking doubles to the derrick. Pick up test plug and run in to hanger, latch and retrieve the wear bushing. Replace tongs to handle ESP pump, pick up clamps, swing in lower assembly, making up equipment. 10/30/12 - Tuesday Hang sheeves in derrick, string ESP cables. Pick up lower ESP assembly and lower into well bore. Well is secure, no control issues. Pull ESP cable to ESP equipment. M/U connections. ESP is ready to install. Pick up single joint and strap with cannon clamps. Pick up double stands to run in hole, RIH with ESP, strapping Cannon clamps in tubing collars. Test cable to insure integrity. Continue RIH with ESP clamping every other collar. Continue making up stands, clamping cable and injection lines to the completion string and RIH. Change cable spool. M/U stands and clamping with Cannon cross coupling clamps, RIH with completion. Continue operations. ESP system is 26 stands from installation of the hanger assembly. II • • i M Hilcorp Alaska, LLC Hitcurp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G -01 RD 50- 733 - 20037 -01 191 -139 8/25/2012 10/31/2012 ,Doty Operations: 10/31/12 - Wednesday RIH with ESP system, reach depth to install safety valve nipple. Pickup safety valve (hydraulic nipple) and swing to rig, male up on completion, hook up control lines and pressure test for Teaks. Note ( Schlumberger BP -6I Landing nipple with dummy safety valve installed. Use 3 -1/2" GS pulling tool to remove dummy valve. (rose control line needle valve at tree prior to pulling valve). RIH single joint and 4 stands, make up crossover to hanger and install hanger on the completion string. Splice connector to the cable and allow to dry and cure. M/U control line connector to the SCSSSV nipple, test and cap the chemical injection lines. Pickup landing joint, make up to hanger, remove Schlumberger sheaves from rig derrick begin racking tools and removing from rig floor. Install final clamps to the ESP control cable. Lower the hanger assembly and stab into position, checkat wellhead, good landing, run in hold down pins and secure. Check for seal, test good. Remove landing joint, remove rig floor, begin unbolting BOPS' ready to unstab, begin removing riser flange bolts from wellhead and stackfor next well. BOP on the deck riser pulled up thru the deck and laid down for next well. Picking up well head and begin installation as per production foreman. L4(1610 Regg, -James B (DOA) From: Regg, James B (DOA) Sent: Wednesday, October 31, 2012 10:01 AM e,� (0\ ;1k1 To: Paul Langley - (C); Brooks, Phoebe L (DOA) e ft Cc: DOA AOGCC Prudhoe Bay; Mike Dunn; Ted Kramer; Chris Myers; Juanita Lovett; Michael Foust; Wayne Johnson Subject: RE: MIT Test G -01 RD You do not need to send this report to AOGCC. Retain copy of test chart in your records and document test result in Report of Sundry Operations, Form 10 -404 that will be sent when work on G -01RD is completed (closing out approved sundry # 312 -266. Jim Regg �� AOGCC " 0 SGANHED 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907 - 793 -1236 From: Paul Langley - (C) [mailto:plangley@ hilcorp.com] Sent: Tuesday, October 30, 2012 9:42 AM To: Regg, James B (DOA); Brooks, Phoebe L (DOA) Cc: DOA AOGCC Prudhoe Bay; Mike Dunn; Ted Kramer; Chris Myers; Juanita Lovett; Michael Foust; Wayne Johnson Subject: MIT Test G -01 RD State of Alaska DOA Mr. Jim Regg Ms. Phoebe Brooks s oi i P-A-Qcc As per our phone conversation please find the MIT conducted on G -01RD. PTD 1911390 Trading Bay Unit, Grayling Platform. Workover rig is the Williams # 404. MIT conducted as per regulations using 7" packer to determine integrity of the liner lap and 9 5/8" casing to surface. As per instructions we pressure tested to 1,500 Psi and held the test for 30+ minutes. No pressure lost and we can provide a snapshot of the chart if requested. Currently installing the Electric Submersible Pump system. Thank you and best regards Paul Langley 1 • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: jim.recici alaska.gov, doa.aodcc.prudhoe.bay @ alaska.dov; phoebe.brooks(N.alaska.gov OPERATOR: Hilcorp Energy LLC FIELD 1 UNIT / PAD: McArthur River Field/Trading Bay Unit/Grayling DATE: 10/25/12 OPERATOR REP: Paul Langley AOGCC REP: No Witness Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min, Well G -01 RD Type . N TVD 9,266' Tubing Interval 0 P.T.D. 1911390 Type test M Test psi 1500 Casing 1,500 P/F Notes: Workover, recomplete as ESP, test casing and liner Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA TYPE INJ Codes TYPE TEST Codes INTERVAL Codes D = Drilling Waste M = Annulus Monitoring I = Initial Test G = Gas P = Standard Pressure Test 4 = Four Year Cycle I = Industrial Wastewater R = Internal Radioactive Tracer Survey V = Required by Variance N = Not Injecting A = Temperature Anomaly Survey 0 = Other (describe in notes) W = Water D = Differential Temperature Test Form 10 -426 (Revised 02/2012) MIT G - 01 RD (2) • • Pr igt o Regg, James B (DOA) From: Mike Dunn [mdunn @hilcorp.com] ��i�idv Sent: Thursday, August 16, 2012 8:00 AM To: Regg, James B (DOA); Schwartz, Guy L (DOA); Ferguson, Victoria L (DOA) Cc: Paul Langley - (C); Wayne Biart - (C) Subject: RE: FW: BOP drawing to handle 2 -7/8" X 2 -3/8" tapered string Jim, Guy, Victoria The permit to drill number for G -01RD is 191 -139 SCANNE 'AA'( Z01 For the Grayling workover program, that includes the workover repair of 28 wells, there are a total of 10 wells that are currently completed as duals, and will be recompleted as singles. The wells are G -01RD, G -14, G -06RD, G -08RD, G -18, G -30, G -31, G -33, G -34RD, and G -40. G -01RD is the next well the Williams Rig will work on, followed by G -14. Both sundrys have been approved, but we would like to modify the BOP schematic for both wells. The others are planned for late this year or next year and do not have sundry applications submitted yet. The configuration of the stack is dependent on whether we think we can pull the two strings individually, or pull them simultaneously. In the case of G -01RD, we cannot pull the strings individually as the gas lift mandrels will not pass the split hanger of the other string. And because it is a tapered string, we need rams for 2 -7/8" and 2 -3/8 ". In the next well, G -14, we think we can pull the two 3 -1/2" strings individually (which would be faster), but we need to be prepared to pull them together. We would put single rams I the lower pipe set, and dual 3 -1/2" rams in the upper BOP. The proposal to place a ram type BOP on top of the annular is based on the experiences of our wellsite consultants who have performed these types of jobs in other places, and have had to close the dual BOPS during a well control event. They have told me that using a set of dual pipe rams at the very top, where one can see the rams form the work platform, is the only practical way to line up the two strings where they need to be, before closing the dual rams. As you know, lining up the pipe is not an issue with a single string — the annular is closed which centers it, and the pipe rams close around the string. With a dual, the two strings must be lined up in the correct direction and correct spacing, otherwise the rams will not seal around them. Please advise. Thanks. Mike Dunn111enior Engineer Hilcorp Alaska, LLC Office: (907) 777 -8382 Mobile: (907) 351-1191 From: Regg, James B (DOA) [mailto:jim.regg @alaska.gov] Sent: Wednesday, August 15, 2012 6:35 PM To: Mike Dunn Cc: Paul Langley - (C); Wayne Biart - (C); Schwartz, Guy L (DOA); Ferguson, Victoria L (DOA); DOA AOGCC Prudhoe Bay Subject: Re: FW: BOP drawing to handle 2 -7/8" X 2 -3/8" tapered string AOGCC policy is to accept - at reviewing engineer's discretion - an email request to amend a sundry if work has not been j commenced under previously approved sundry. Otherwise a revised sundry must be submitted. 1 • • I am not familiar with your proposed BOP stack arrangement (rams above annular). I defer to Guy and Victoira to address this very unusual request as part of their review. Demonstration of use of upper rams may be required to be part of BOPE testing. Is G -01RD next well for Williams 404? Are there other planned workovers that have this same issue? It would be appreciated if you reference the permit to drill number (unique identifier) associated with the well name in your correspondence. Mike Dunn <mdunn @hilcorp.com> wrote: Jim, After an exhaustive search effort, we have not been able to find dual VBRs that fit this particular Shafer stack, to handle dual 2 -3/8" and 2 -7/8" tapered strings (G -01RD) with one set of rams. As such, we must add a single gate BOP on top of the annular, to allow us to put 2 -7/8" dual rams in one set (upper), and 2 -3/8" dual rams in another set. We prefer to place the single BOP on top, so if we do have to close the rams, we can visually line up the two strings before closing the ram. Enclosed is the original 10 -403 and BOP schematic that assumed we could find VBRs. Also enclosed is the revised BOP drawing with the additional single gate BOP to accommodate a second set of dual rams. We are asking for a ch na ge to the Sundry. Is there a more formal process to make this change, or is this e -mail good enough? Thanks, Mike Dunn j Senior Engineer Hilcorp Alaska, LLC Office: (907) 777 -8382 Mobile: (907) 351 -4191 2 • • _01 A P� IgJ lM , Sititet, 31 Z- -266 HILCORP GRAYLING 13 -5/8" 5M BOP STACK SHAFFER SL SGL 101 :„._, DRESSED 2 -7/8" DUAL 1.44' SPACER SPOOL ON, 2' SHAFFER SPHERICAL 3.75' SHAFFER LXT DBL DRESSED 2 -3/8" DUAL 3.96' UNE 1 a7' DRESSED CSO MUD CROSS v _ 1.74' I (* = { r z � • ., m = �� v �- ��u ^)= • • • rT) Tr 5 7 AltAs[A SEAN PARNELL, GOVERNOR tr1 ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMHSSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 $ 201 Ted E. Kramer Sr. Operations Engineer Hilcorp Alaska, LLC kO 1 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Re: McArthur River Field, Middle Kenai G & Hemlock Oil Pools, TBU G -01RD Sundry Number: 312 -266 Dear Mr. Kramer: 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, a y P oer r Chair DATED this /day of August, 2012. Encl. 0 , ��/` RECEIVED STATE OF ALASKA "'t JUL 18 2012 ALASKA OIL AND GAS CONSERVATION COMMISSION ADG V V APPLICATION FOR SUNDRY APPROVALS V 20 MC 25280 1. Type of Request: Abandon ❑ Plug for Redd, ❑ Perforate New Pod ❑ Repair We.N ❑ ,.V Change Approved Program ❑ Suspend ❑ Plug Perorations ❑ Perforate El - PuN Tubing � 411,i' I 1 Time Extension ❑ Operations Shutdown ❑ Re -enter Susp. Wel ❑ Stimulate ❑ Alter Casing ❑ Other tnsta l ESP/Recoma4ete El 2. Operator Name: 4. Current Well Gass: 5. Permit to EMU Number. Hilcorp Alaska, LLC Development p • Exploratory ❑ 191 -139 3. Address: Stratigraphic ❑ Service ❑ 6. API Number. 3800 Centerpoint Drive, STE 100, Anchorage, AK 99503 50733200370100 • 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. WeN Name and Number. property line where ownership or landownership cianges: Spacing Exception Required? Yes ❑ No 0 Trading Bay Unit G -01RD 9. Property Designation (Lease Number): 10. Field /Pool(s): - ADL0018730 - McArthur River Field / Middle Kenai G, Hemlock 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): 11,506 , 9,945 • 11,430 9,870 N/A 10,500' & 11,409' (fish) Casing Length Size MD TVD Burst Collapse Structural Conductor 327' 26" 327' 326' Surface 2,113' 13 -3/8" 2,160' 2,119' 3,090 psi 1,540 psi Intermediate 8,450' 9 -5/8" 8,450' 7,311' 5,750 psi 3,090 psi Production 3,352' 7" 11,479' 9,913' 11,220 psi 8,530 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 10,140' to 11,280' 8,752' to 8,873' Short String 2 -3/8" & 2 -7/8" Short String 4.6# N -80 & 6.4# L -80 Short String 8,032' Long String 2 -3/8" & 2 -7/8" Long String 4.6# N -80 & 6.4# L -80 Long String 8,032' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 7" Otis RDH dual packer; 7" Otis RDH dual packer, SS & N/A 9,922' (MD) 8,571' (TVD) and 9,919' (MD) 8,569' (TVD) ; 9,922' (MD) 8,571' (TVD) & N/f 12. Attachments: Description Summary of Proposal El 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Development El Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 8/1/2012 Oil G - Gas ❑ WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: N/A 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 Ted Kramer Printed Name Ted E. Kramer Title Sr. Operations Engineer Signature d Phone (907) 777 -8420 Date 7/18/2012 COMMISSION USE ONLY '") Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3� (� '2(0 Plug Integrity ❑ BOP Test V Mechanical Integrity Test ❑ Location Clearance ❑ C . V, u 5 Other: re f 1 5 1G 3&G& p5 / , i ti' r✓ h .%� G�i l G r •- 5,72- , ' keit ea, •le`c Pi ,- s L,.v e 'h t o? i -? ei o f fl v 'Ft/ b i a CI I, r' caG t r el G ' c i j a. /i l Y1 /- -. Subsequent Form Required: i / APPROVED BY 9 / Approved by: COMMISSIONER THE COMMISSION Date: 9 j " ( y -� AUG i u i� /�7 0 R LRBDMS HU 0 1 � D .licate / / / I G I N A II • • Well Work Prognosis Well: G -01RD Elilrnrp Alaska, LLC Date: 07/12/2012 Well Name: G -01RD API Number: 50- 733 - 20037 -01 Current Status: SI Dual String Producer Leg: Leg #2 (NE corner) Estimated Start Date: Aug 1, 2012 Rig: William Rig 5 Reg. Approval Req'd? 403 Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts 777 -8398 Permit to Drill Number: 191 -139 First Call Engineer: Ted Kramer (907)- 777 -8420 (0) (985)- 867 -0665 (M) Second CaII Engineer: Mike Dunn (907) 777 -8382 (0) (907) 351 -4191 (M) AFE Number: Budgeted Cost: Current Bottom Hole Pressure: — 3,500 psi @ 9,254' TVD mi perf of 10,710' MD) Maximum Expected BHP: — 3,500 psi @ 9,254' TVD f ( new perfs being added) Max. Anticipated Surface Pressure: 0 psi 'IV kk sing 0.435psi /ft. to surface) Brief Well Summary G -01RD is a shut -in G -Zone and Hemlock Producer. It was originally completed as a dual string gas lifted well and has been shut in since 2010. The well has a history of gas lift problems culminating in 2010 when it was shut in due to not taking gas. Scale and asphaltenes have also plagued this well resulting in a lost set of slick line tools and wire being left in the long string when a tubing clean out was attempted. The plan is to pull the current dual string completion, clean the well out to PBTD, re- perforate the hemlock and • G -zone and run an ESP. Procedure: 1. Plumb FIW lines to circulate down the annulus and up the tubing, through the tree, to circulate the wellbore and insure no gas is present in the string. 2. Notify AOGCC 48 hours in advance of pending BOPE test. Set BPV in both strings, ND tree, NU dual BOPE. Test BOP equipment per AOGCC guidelines to 250 psi LOW and 3000 psi HIGH on the rams. ✓ 3. RU E -line with jet cutter and cut both tubing strings just above the packer. 4. RU dual elevators and tongs. 5. PU landing joint and make -up to tubing hanger. Pull hanger up to floor height. Install stripper rubber. Circulate at least 2 bottoms up to adequately clean hole. 6. RIH with overshot on the work string and latch onto the Tong string tubing stub. Pull 35K over string weight and pull RDH dual packer and the rest of the long string out of the snap collet in the bottom packer. POOH and lay down same. 7. PU RIH with Mill Shoe packer milling assembly to packer at 10,500'. Mill packer and retrieve same. 8. RU Slickline and RIH with LIB to fish at 11,210' and tag for recovery. 9. Fish CT motor at 11,210'. POOH with same. 10. RIH with Bit and Scraper to 11,280ft. Circulate hole clean. . • Well Work Prognosis Well: G -01RD Hilcorp Alaska, LLC Date: 07/12/2012 11. MU Schlumberger TCP guns on workstring and RIH. RIH with a -line Gamma Ray tool and Correlate guns on depth. Position guns to perforate as follows: Bench Top MD Btm. MD Feet , , GZN 2 10,140 10,170 30 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . , , GZN 3 10,244 10,264 20 .. .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . GZN 4 10,280 10,342 62 .... ................................................................................................................................................................................. ............................... , , GZN 5 10,398 10,418 20 . . . . . . . . . . . . . . . . . . . . . . ... .. ... . . . . . . . . . . . . . .. . ... . . . . . . . GZN 5 10,440 10,460 20 GZN 6 10,532 10,548 16 GZN 7 10,600 10,614 14 HK 1 10,628 10,676 48 HK 3 10,846 10,860 14 HK 4 10,890 11,006 116 HK 5 11,042 11,122 80 HK 6 11,156 11,240 84 ........................... ............................... ............................................................................................................................... ............................... HK 7 11,266 11,290 24 12. Measure fluid losses from Trip tank after guns fire and record rate. If fluid losses are manageable continue filling hole from trip tank to keep the well dead. 13. POOH with guns. LD same. Confirm that all charges fired. 14. RD E -line. RD Schlumberger. 15. RU ESP vendor Sheaves for Electrical Cable and Flat pack and conduct cable cutting drill. 16. PU ESP and assemble going into well as per vendor assembly instructions and best practices. 17. RIH with ESP as per vendor instructions. Measure electrical continuity every 1,500'. ✓ 18. Hang of ESP at 8,077 ft. ( + / -) - 50 feet above the 7" liner top at 8,032'. 19. Set BPV in tubing ND BOP, NU wellhead and test tree. a 20. Have platform electrician shoot TDR down electrical cable for future reference. 21. Turn well over to Production Supervision (TOPS) for ESP startup. 22. RDMO pulling unit. it • • McArthur River Field, TBU SCHEMATIC Well: G -01RD Hilcnrp:Vu�ka, l.l.c As Completed: 02/26/92 Casing Detail RKB to TBG Hngr= 42.68' SIZE WT GRADE CONN ID TOP BTM TVD BTM Tree connection: Dual 3 -1/2" EUE 8rd 26" Surf. 327' 13 -3/8" 61 J -55 Butt Surf. 2160' 2113' A 1 9 -5/8" 47 N -80 Butt 8.681 Surf 79' IM 9 -5/8" 40 N -80 Butt 8.835 79' 6275' 5523' ii imp 9 -5/8" 43.5 N -80 Butt 8.755 6275' 8179' 7086' 4 1∎ s 9 -5/8" 47 N -80 Butt 8.681 8179' H 84500 7318' 111 i 9 -5/8" DV Collar 4903' 4905' 4393' B 1 ∎ ' ' 7" 29 P -110 Butt 6.184 8127' 11,479' 9927' 2 Tubing Detail 1 , L S 2 -7/8" 6.4 L -80 Butt 2.441 0' 8031' 6961' • 2 -3/8" 4.6 N -80 Butt 1.995 8032' 10,583' 9151' e' SS 2 -7/8" 6.4 L -80 Butt 2.441 0' 8031' 6961' 2 -3/8" 4.6 N -80 Butt 1.995 8032' 9936' 8578' NOTE: H Window cut from 8,450' to 8,516'. Original 9-5/8" @ 8,994'MD (7,746'TVD) „ Short String Long String O _ '� 3 NO. Depth( Depth ID Item No. Depth Depth ID Item MD) (TVD) (MD) (TVD) ® �` = ),� A 299' "FM" SCSSV 1 310' "FM" SCSSV B -1 2,670' 2,548' 2.347 2 -7/8" GLM 2A 2,737' 2,606' 2.347 2 -7/8" GLM D , 4 B -2 3,948' 3,612' 2.347 2 -7/8" GLM 2B 4,197' 3,815' 2.347 2 -7/8" GLM B -3 5,170' 4,610' 2.347 2 -7/8" GLM 2C 5,328' 4,741' 2.347 2 -7/8" GLM 13-4 6,252' 5,504' 2.347 2 -7/8" GLM 2D 6,062' 5,344' 2.347 2 -7/8" GLM B -5 7,157' 6,250' 2.347 2 -7/8" GLM 2E 6,732' 5,903' 2.347 2 -7/8" GLM A E o 5 B -6 7,905' 6,852' 2.347 2 -7/8" GLM 2F 7,285' 6,349' 2.347 2 -7/8" GLM C 8,031' 7,291' 1.995 X -Over 2 -7/8" 2G 7,775' 6,743' 2.347 2 -7/8" GLM 7 to 2 -3/8" X -Over 2 -7/8" F 6 3 8,031' 6,960' 1.995 D -7 8,420' 7,705' 1.9 2 -3/8" GLM X 2 -3/8" 2120107 600'wire, 2 D -8 8,907 8,103' 1.9 2 -3/8" GLM 4A 8,189' 7,096' 1.9 2 -3/8" GLM cutter bars &tool D -9 9,367 8,478' 1.9 2 -3/8" GLM 4B 8,612' 7,452' 1.9 2 -3/8" GLM string stuck in LS D -10 9,817' 8,542' 1.9 2 -3/8" GLM 4C 9,037' 7,814' 1.9 2 -3/8 " GLM 8/24/05: Jet cut tubing 3 / 2 -3/8" "XA" 4D 9,426' 8,153' 1.9 2 -3/8 " GLM tail @ 9936' 9.860'. E 9,887' 8,542' 1.875 Sliding Sleeve 4E 9,842' 8,504' 1.9 2 -3/8" GLM G - 2 7" "RDH" Dual 2 - 3/8" "XA" F -1 9,922' 8,565' 7.94 Pkr 5 9,879' 8,533' 1.875 Sliding Sleeve G - F -2 9,936' 8,578' EOT 7" "RHD" Dual ' 8,571' 1.94 G - G ±10,491' 1.791 2- 3 /8 " "XM' Pkr Nipple 7 10,053' 8,680' 1.916 Blast Joints Collet Catcher 2 -3/8" "XA" I G - 5 H ±10,493' 1.92 8 10,472' 9,050' 1.87 1 Sun and Ball Sliding Sleeve G 8 1 ±10,500' 1 . 9 92 WLEG Straigh Shot H • 9 9 10,507' 9 1.995 Locator 10 10 10,500' 9,067' 4 "BWH" Perm Pkr 11 1: =I 2 -3/8 " 11 10,549' 9,116' 1.791 Nipple 12 12 10,583' 9,149' 1.995 WLEG PERFORATIONS 8/10/05: Ran 1.75" = HB_1 GR to 10600' KB. = Zone Top Btm Top Btm Amt SPF Last Status MD MD TVD TVD Opr. G -2 10,140' 10,170' 8,759' 8,785' 30' 6 2/19/1992 Open HB -4 G -3 10,225' 10,257' 8,833' 8,861' 32' 6 2/19/1992 Open HB -5 G -4 10,278' 10,340' 8,879' 8,933' 62' 6 2/19/1992 Open 12/17 /00 - C . motor, G -5 10,395' 10,415' 8,981' 8,999' 20' 6 2/19/1992 Open etc. top @ 11,210'. = HB-6 HB -1 10,622' 10,637' 9,180' 9,194' 15' 4 1/17/2001 Open i = HB -7 HB -1 10,628' 10,670' 9,186' 9,223 ' 42' ' 10 &16 8/26/1995 open, frac'd 1o,62e' 10,643' HB -4 10,863' 11,000' 9,392' 9,509 137 6 2/19/1992 Open 148-4 10,939' 10,954' 9,457' 9,470' 15' 4 1/17/2001 Open 45/8" Perf Gun HB -5 11,038' 11,048' 9,542' 9,550' 10' 4 1/17/2001 Open @ 11,409' HB -5 11,040' 11,070' 9,544' 9,569' 30' 8 8/26/1995 Open HB -6 11,155' 11,170' 9,642' 9,655' 15' 4 8/26/1995 Open RKB to MLLW ELEV = 103' HB -7 11,255' 11,280' 9,728' 9,749' 25' 24 6/24/1994 Open TD = 11,506' ETD = 11,430' MAX HOLE ANGLE = 39.10° @ 7225' 12/17/00: Left 10.14' long fish consisting of coil tubing equipment- 1.75" Drag Bit, Baker 1- 11/16" Mach 1 Motor, & Circ. Sub. Top is A 11,210'. Revised 7/12/2012 by TDF 11 • ` McArthur River Field, TBU Hileorp Alaska, LLI: PROPOSED Well: G -01RD As Completed: 02/26/92 Casing Detail RKBtoTBG Hn r= 42.68' SIZE WT GRADE CONN ID MD MD TVD BTM 9 TOP BTM. Tree connection: Dual 3 -1/2" EUE 8rd 26" Surf. 327' I] 13 - 3/8" 61 1 -55 Butt Surf. 2160' 2113' J 9 - 5/8" 47 N -80 Butt 8.681 Surf 79' 9 -5/8" 40 N -80 Butt 8.835 79' 6275' 5523' 9 -5/8" 43.5 N -80 Butt 8.755 6275' 8179' 7086' 9 -5/8" 47 N -80 Butt 8.681 8179' 8,450' 7318' ' 9 -5/8" DV Collar 4903' 4905' 4393' 7" 29 P -110 Butt 6.184 8127' 11,479' 9927' Tubing Detail { 3 -1/2" I 12.7 1 L -80 I Butt 1 2.75 I Surface 1 ±7,977' I ±6,915' NOTE: H Window cut from 8,450' to 8,516'. Original 9 -5/8" @ 8,994'MD (7,746'TVD) 1 Jewelry Detail NO. Depth(MD) Depth ID Item 2 (TVD) 1 ±7,947' ±6,889' "XN" Nipple atr- 3 2 ±7,977' ± 6,915' ESP 3 ±8,077' ± 7,000' Pheonix Guage PERFORATIONS Zone Top Btm Top Btm Amt SPF Last Status MD MD TVD TVD Opr. G-2 10,140' 10,170' 8,759' 8,785' 30' 6 2/19/1992 Open ±10,140' ±10,170' ±8'759' ±8,785' Future Reperf G -3 10,225' 10,257' 8,833' 8,861' 32' 6 2/19/1992 Open ±10,244' ±10,264' ±8,849' ±8,867' Future Perf 10,278' 10,340' 8,879' 8,933' 62' 6 2/19/1992 Open G-4 ±10,280' ±10,342' ±8,881' ±8,935' Future Perf = G -2 10,395' 10,415' 8,981' 8,999' 20' 6 2/19/1992 Open G -5 ±10,398' ±10,418' ±8,984' ±9,001' Future Perf G -3 ±10,440' ±10,460' ±9,021' ±9,038' Future Perf G 4 G -6 ±10,532' ±10,548' ±9,101' ±9,115' Future Perf G -7 ±10,600 ±10,614' ±9,161' ±9,173' Future Perf G -5 HB -1 10,622' 10,637' 9,180' 9,194' 15' 4 1/17/2001 Open G -6 Open, frac'd = G -7 HB -1 10,628' 10,670' 9,186' 9,223' 42' 10 & 16 8/26/1995 10,628'- 10,643' ±10,628' ±10,676' ±9,186' ±9,228' Future Perf HB -3 ±10,846' ±10,860' ±9,377' ±9,389' Future Perf 10,863' 11,000' 9,392' 9,509' 137' 6 2/19/1992 Open HB -4 10,939' 10,954' 9,457' 9,470' 15' 4 1/17/2001 Open ±10,890' ±11,006' ±9,415' ±9,515' Future Perf FE HB -1 11,038' 11,048' 9,542' 9,550' 10' 4 1/17/2001 Open HB -5 11,040' 11,070' 9,544' 9,569' 30' 8 8/26/1995 Open HB -3 ±11,042' ±11,122' ±9,545' ±9,614' Future Perf HB -4 HB -6 11,155' 11,170' 9,642' 9,655' 15' 4 8/26/1995 Open ±11,156' ±11,240' ±9,643' ±9,715' Future Perf - HB -5 11,255' 11,280' 9,728' 9,749' 25' 24 6/24/1994 Open HB -7 HB -6 ±11,266' ±11,290' ±9,737' ±9,758' Future Perf - HB -7 @ 11 , 09 Gun ��- -: > -^- @ 11,409' RKB to MLLW ELEV = 103' TD = 11,506' ETD = 11,430' MAX HOLE ANGLE = 39.10° @ 7225' 12/17/00: Left 10.14' long fish consisting of coil tubing equipment- 1.75" Drag Bit, Baker 1- 11/16" Mach 1 Motor, & Circ. Sub. Top is (a 11,210'. Revised 7/12/2012 by TDF • • Well Work Prognosis Well: G -01RD Hilrnrp Alaska, LLf. Date: 07/12/2012 Williams Workover Rig • Grayling Platform BOP 2012 111 11. 11 lit lit lit III IV Width 4.16' 3.74' Weight 13,1004 Iil 1 11 111111 III • Sha1Nr L Total BOP height above • 13 5/8 5M LWS a� 138/85M 9. min dimensions -..- 948' min Length 7.73'_ 3.00' 17.68' max Width across body 2.72' Width across flanged = outlets 4.00' _ -'_• _ Weight95001bs • 9.00' //► , 11iiliiliitii � i. ! Mud Cross 2850165 w/ valves OiI 'r' IMR] t a I cII ��l' 1.74' 111 111 111 • Riser above drill deck 1 1 1 1 1 1 This number will vary from well to well 1.00' to 3.00' V Drill Deck 13 5/8 5M Riser 8500165 15.00' 11 .' 111 111 111 Spacer Spool 135/85M X 135/85M 1.95' 1800165 111 II III Crossover Spool 135/85M X115M 1800165 2.83' Top of Wellhead • • Ferguson, Victoria L (DOA) From: Ted Kramer [tkramer ©hilcorp.com] Sent: Tuesday, July 31, 2012 8:41 AM To: Ferguson, Victoria L (DOA) Cc: Schwartz, Guy L (DOA) Subject: RE: G -01 RD ESP /Recomplete: Sundry(312 -266) PTD(191 -139) Victoria, Sorry for the late response, I have been out of State on a medical issue for my daughter. Answers to your questions are below in blue: Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC. 0 907 -777 -8420 C 985- 867 -0665 From: Ferguson, Victoria L (DOA) ( mail to :victoria.ferguson(aalaska.govl Sent: Friday, July 20, 2012 4:17 PM To: Ted Kramer Cc: Schwartz, Guy L (DOA) Subject: G -01RD ESP /Recomplete: Sundry(312 -266) PTD(191 -139) Ted, 1. Procedure does not include a step to pull tubing strings. Will dual rams be used? We do plan to use dual rams. But will attempt to cut and pull dual tubing string one at a time. This should work as long as the tubing strings are not wrapped around each other and the gas lift mandrels can slide by each other. If not, we will pull both at same time using dual elevators. 2. Pressure test the casing either CMIT or after the tubing is pulled We will plan to pressure test after tubing and upper packer is pulled. 3. Your procedure says "no new perfs being added" whereas the schematic shows a number of new perfs That is not correct. Perforations will be added as listed in the table. I apologize for this oversite. 4. For your MASP calculation what are your assumptions for ft/gradient for oil, gas, water Since the Grayling 1RD has not produced for a long while, offset wells were used. Assumptions used: • nearest offset well that had a 3 month static test during the 2009 three month shut in for the Redoubt Volcano shut in. The nearest well to G -1RD was M -25. I started from that mid perf pressure and corrected for depth to G -1RD mid perf. • Well will be a 91% watercut well similar to M -25. • Water Specific Gravity is 1.02 — Measured from other wells on Grayling • Oil Gravity of 32.2 • Used 1,000 feet of oil on top of the tubing string as a safety factor. 1 • Calculation shows that well will not flow to surface which is consistent with other wells on Grayling Platform. 5. In the well summary, the producing characteristics of the well or offset well would be useful Since the G -1RD has not produced for a while the closest offset is M -25 which was an ESP well. M -25 is a 91% water cut well and makes approximately 3,000 bpd total fluid. 6. In step 20, what is "TDR "? A TDR is a time - domain reflectometer (TDR). It can be used in ESP installations to map the electrical cable down -hole. The process is to shoot a TDR prior to the well being placed on production. If there is a subsequent electrical fault in the esp cable, then a followup TDR is conducted and the two traces compared. The Change in the TDR can tell us if the electrical short is in the feed through connector just below the well head or if the motor is shorted down hole. If it is just below the well head, the repair is a lot less. We can pick up the tubing, replace the lower connector and set the well back down and re -start it. Thanx, Victoria Victoria Ferguson Senior Petroleum Engineer State of Alaska Oil & Gas Conservation Commission 333 W. 7th Ave, Ste 100 Anchorage, AK 99501 Work: (907)793 -1247 victoria.ferquson(a alaska.gov 2 Facility No Flows • Page 1 of 1 Regg, James B (DOA) From: Johnson, Wayne E [johnsonw@chevron.com] ~ Sent: Friday, February 06, 2009 3:11 PM ~Ql~ 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 ~ ~'TD 11 b -~ 3 l /A-22L: No flow on May 27, 2004 ~1s: Shut In ~~ 1`1(-- 13 c] :~G-1 L: No flow May 27, 2004 ~ - - ~°° ~-•---- -- ~'G-31 s: No flow November 23, 200 PNj i~~t _ ci7 Z X31 L: Shut In 'c~-32: No flow April 21, 2003 --- P~ ~~`f- ~~ -33s: Shut In ~ ~~~, eft -33L: No flow November 23, 2004 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 uNOCa~~~b u 1`l 1- ~ 3q CASING AND TLiBING DETAII, slzE W r GxaDE coNN ID nID ~ oP MU is 1 M. 1 V U n 11V1 2e" sore 327' RKB to TBG Hn r = 42.68' 9 13-3/S" 61 J-55 Butt Surf. 2160' 2113' Tree connection: Dual 3-112" EUE 8rd 9-5/8" 47 N-80 Bntt 5.681 Surf 79' 9-5/8" 40 N-80 Butt 8.835 79' 6275' 5523' A 1 9-5/8" 43.5 N-SO Butt 8.755 6275' 5179' 7086' ' 9-5/S" 47 N-80 Butt 8.651 8179' H 8450' 7318 9-g'R" D1' Collar ---°- -------_--------------°-----._ °-_----------------~.-_-__---------- 4903' 4905' 4393' 7" 29 P-110 Butt 6.184 8127 11,479' 9927 Tubing: LS 2-7/S" 6.4 L-SO Butt 2.441 0' 8031' 6961' 2-3/8" 4.6 N-SO Bntt 1.995 8032' 10,583' 9151' SS 2-7/8" 6.4 L-SO But[ 2.441 0' 8031' 6961' B 2-3/S" 4.6 N-80 Butt 1.995 5032' 993(' 857R' 2 H W indow cut r/ 8450' to 8516'. Original 9-5/8" ~ 8994' MD (7746' TVD) JEWELRY DETAIL NO. Depth TVD ID Item 42.68' Cameron 11" Split Tbg Hngr Dual 3-I@"Butt X EUE. C D E F '24/05: Jet cut tubing 3 it (8J 9936' & beat off I wireline. 7 G H 9 11 A. 299' Otis "FM" SCSSV ~i 3 2~2~~~7 2670' 2,548' 2.347 2-7/S" GLM 3948' 3,612' 2.347 2-7/8" GLM 6~U'Wire, 2 cutter 5170' 4,610' 2.347 2-7/8"GLM bars and tool string 6252' 5,504' 2.347 2-7/8"GLM a stuck in long string 7157' 6,250' 2.347 2-7/8"GLM 7905' 6,852' 2.347 2-7/8" GLM , 5031' 1.995 Crossover, 2 7/R" X 2-3!R" 8 12 /10/05: Ran 1.75° R to 10600' KB. potted Sized Salt pill o control fluid loss. T. motor, etc. lop 11,210'. ~~~~ . 8420 7,291' 1.9 2-3/S"GLM #8 8907 7,705' 1.9 2-3/8" GLM #9 9367 8,103' 1.9 2-3/S" GLM #10 9817 5,478' 1.9 2-3/8" GLM 6 1•°, 9887 R,S42' LS75 2-3;8" Otis "X:1" Sliding Sleeve F. 9922' 8,565' 1.94 7" Otis "RDH" Dual Packer, SS sel 9936' R,57R' ? EC)T as of Si24/OS -tubing tail jrt cut & beat olr G, +- 10,391' LT)I 2-3/R" Otis "YN" Nipplt`, LR?5 H. +/- 10,493' 1.92 Otis Collet Ca[cher Sub and Ball I. Btm+~'- 10,500' 1.992 Otis WLEG G-2 1 310' Otis "FM" SCSSV #1 2737' 2,606' 2.347 2-7/8" GLM #2 4197' 3,815' 2.347 2-7/8" GLM G-4 #3 5328' 4,741' 2.347 2-7/8" GLM #4 6062' 5,344' 2.347 2-7/S" GLM G-5 #5 6732' 5,903' 2.347 2-7/S" GLM #6 7285' 6,349' 2.347 2-7/8" GLM #7 7775' 6,743' 2.347 2-7/8" GLM 3 8031' 6,960' 1!)95 Crossover. 2.7/R" X 2-3i 8" 1 ~ ~ #8 ~ 8189' 7,096' 1.9 ~ ~ 2-3/8" GLM #9 8612' 7,452' 1.9 2-3/S" GLM #10 9037' 7,514' 1.9 2-3/8" GLM #11 9426' 8,153' 1.9 2-3/S" GLM #12 9842' 5,504' 1.9 2-3/8" GLM 5 9R79' R,533' 1.875 2-3:'$" Otis "SA" Sliding Sleeve 6 9919' 8,571' 1.94 7" Otis "RHD" Dual Packer HB-1 7 10,053' 8,650 1.916 Otis Blast Joints, (not Bush, 3/16" gap when made-up) 8 10,472' 9,050' LR?5 2-3,'R" Otis "?IA" Sliding Sleeve 9 10,507 9,075' 1.995 Otis Straight Slot Locator, w/ 9.95' Otis 3.22" seal Assy 10 DIL 10,500' 9,067' 4.00 Otis "BWH" Perm Pkr (10,500' DIL) HB-4 17 10,5d9' 9,116' 1_741 t-3($" Otis "X" Nipple, 1.875 12 btm 10,583' 9,149' 1.995 WLEG HB-5 HB-6 12/17/00: Left 10.14' long fish consisting of coil tubing equipment - 1.75" Drag Bit, Baker 1-1 I/16" M ach 1 Motor, & Circ. Sub. Top is ~ 11,210'. HB 7 PERFORATION DATA Zone Top Btm Amt SPF Last Opr. Present Condition ~ c~;p~' . G-2 10,140' 10,170' 30' 6 2119/92 Open , , 19.8t' 0-5/8' Perf '~`cun ~ 11,dos'. G-3 10,225' 10,257 32' 6 2/19/92 Open G4 10,278' 10,340' 62' 6 2/19/92 Open G-5 10,395' 10,415' 20' 6 2/19/92 Open RKB to MLLW ELEV = 103' HB-1 10,622' 10,637' 15' 4 1117/01 Open TD = 11,506' ETD = 11,430' HB-1 10,628' 10,670' 42' 10 & 16 8/26195 Open, frac'd 10,628'- 10,643' MAX HOLE ANGLE = 39.10° ~ 7225' HB-4 10,663' 11,000' 137' 6 2118/92 Open HB-0 10,939' 10,954' 15' 4 1/17/01 Open HB-5 11,038' 11,048' 10' 4 1/17/01 Open HB-5 11,040' 11,070' 30' 6 8/26/95 Open HB-6 11,155' 11,170' 15' 4 8/26/95 Open HB-7 11,255' 11,280' 25' 24 6/24/94 Open F:\transfer\My Documents\Temp Files\G-1Schm9-17-97. doc REV ISED: 10/17/05 by BGA Trading Bay Unit Well # G-1RD Completed 2/26/92 DRAWN BY: SLT Page 1 of 1 Regg, James B (DOA) From: Regg, James B (DOA) Sent: Friday, February 06, 2009 8:50 AM ' l~lG~ Z'~~~ ~~ I To: 'myersc@chevron.com' Cc: Fleckenstein, Robert J (DOA) Subject: No Flow Determinations 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 STATE OF ALASKA ) ALA5. )OIL AND GAS CONSERVATION COMMI_.:>ION REPORT OF SUNDRY WELL OPERATIONS Casing Length Size MD TVD Structural Conductor 327' . 26" 327' 326' Surface 2,113' 13-3/8" 2,160' 2,119' Intermediate 8,450' 9-5/8" 8,450' 7,311' Production 3,352' 7" 11,479' 9,913' Liner Representative Daily Average Production or Injection Data Gas-Met Water-Bbl Casing Pressure o 84 1 ,340 o 85 1,360 15. Well Class after proposed work: ExploratoryD Development [] 16. Well Status after proposed work: Oil[] Gas D WAG D 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 1. Operations Abandon U Repair Well U Performed: Alter Casing D Pull TubingD Change Approved Program D Operat. Shutdown D 2. Operator Union Oil Company of California Name: 3. Address: PO Box 196247, Anchorage, AK 99519 7. KB Elevation (ft): RKB to tbg hanger 42.68' 8. Property Designation: Grayling Platform 11. Present Well Condition Summary: Total Depth measured 11,506 feet true vertical 9,945 feet Effective Depth measured 11,430 feet true vertical 9,870 feet Perforation depth: Measured depth: 10,140 to 11,280' True' Vertical depth: 8,752 tó 8,873' Tubing: (size, grade, and measured depth) Packers and SSSV (type and measured depth) 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Prior to well operation: Subsequent to operation: 14. Attachments: Copies of Logs and Surveys Run Daily Report of Well Operations Oil-Bbl 35 29 x Contact Steve Tyler 263-7649 Printed Name Timothy C. Brandenburg Signature ?~~ eX / Form 10-404 Re¿4/2004 /.: Plug Perforations U Stimulate U Other ~ . Tubing punch Perforate New Pool D Waiver D Time Extension D Perforate D Re-enter Suspended Well D 4. Current Well Class: 5. Permit to Drill Number: Development [] ExploratoryD 191-139 StratigraphicD ServiceD 6. API Number: 50-733-20037-01 9. Well Name and Number: G-01 RD 10. Field/Pool(s): Trading BaylHemlock, G-Zone Plugs (measured) nla Junk (measured) 10,500, 11,409 (fish) Burst Collapse 3,090 psi 5,750 psi 11,220 psi 1,540 psi 3,090 psi 8,510 psi See schematic for detail: 2-3/8" and 2-7/8" on Short and Long Strings. 7" Otis RDH dual pkr @ 9,922' and 9,919'; 7" Otis "RDH" Dual Packer, SS set @ 9,922' nla ~ l' ,r.....\-.. I ....\ìì ,~) '''~', CiOO,';' (1;.....'ii·'·,St.~"'~\.~¡¡....1, I trJ··.E- ·I(~ (~ J. l_ .3 \\,:3 ~'";;I~d -\'.oS~. 1,1 ~iÍl""'':.oIL.... ,.. ¡ Tubing Pressure 140 140 Service D GINJ D WINJ D WDSPL D Sundry Number or N/A if C.O. Exempt: nla RBDMS BFL SEP 1 6 2005 Title Drilling Manager Phone 907-276-7600 ,. Date 9/14/2005 AFE 164287 ~ G.l: f t .~. l Submit Original Only Primary Job Type Perforating Jobs LeaselSerial ADL0018730 I Primary Well bore Affected Main Hole AFE No. QC Eng 164287 Daily Operations 6/28/200500:00 - 6/29/2005 00:00 Operations Summary No activity. 8/11/200516:30 - 8/12/2005 00:00 Operations Summary RU, MU 1-11/16" tool string, test lubricator to 1500psi. MU 1-13/16" jet cutter. RIH on G-01RD short string, set down at 8031'. POOH. 8/12/200500:00 - 8/13/2005 00:00 Operations Summary LD cutter. MU and RIH with 1-9/16" tbg punch. RIH in short string and set down at 8,051'. POOH. RU slickline. Hold safety meeting. MU 1-1/4" tool string and 1.825 GR. Test lubricator to 2,500 psi. RIH on short string with 1.825" GR to 9941'. RIH w/20' x 1-11/16" dummy guns and set down at 8,060'. POOH. Adjust tool string configuration and find 1-11/16" Dummy Gun (5' guns + knuckle on 1-1/4" tool string), to 9,943'. POOH. RD wireline. 8/13/200500:00 - 8/14/200516:00 Operations Summary RIH w/1-13/16" jet cutter into short string. Cut tail pipe, at 9,936'. Indications are the tubing tail did not drop. POOH, shut in well. MU 1-9/16" tbg punch (total of 8 - 1/4" shots), RIH on short string and shoot from 9,935' - 9,937'. All shots fired. Turn well over to production. 8/14/200516:00 - 8/15/200516:00 Operations Summary RU slickline. RIH and knocked off previously cut tbg tail (cut @ 9936'). RD. Turned well over to production. 40 Trading Bay Unit Well # G-1RD Completed 2/26/92 CASING AND TUBING DETAIL SIZE WT GRADE CONN ID MD TOP MD BTM. TVD BTM RKB to TBG Hngr = 42.68' 26" Surf. 327' Tree connection: Dual 3 -1/2" EUE 8rd 13 -3/8" 61 3 -55 Butt Surf. 2160' 2113' Elm 9-5/8" 47 N -80 Butt 8.681 Surf 79' 9 -5 /8" 40 N -80 Butt 8.835 79' 6275' 5523' A l LL 9 -5/8" 43.5 N -80 Butt 8.755 6275' 8179' 7086' t 9 -5/8" 47 N -80 Butt 8.681 8179' * 8450' 7318' 9 -5'8" I)') Collar -- 4903' 4905' 4393' 7" 29 P -110 Butt 6.184 8127' 11,479' 9927' t Tubing: LS 2 -7/8" 6.4 1.-80 Butt 2.441 0' 8031' 6961' 2 -3/8" 4.6 N -80 Butt 1.995 8032' 10,583' 9151' B t ) SS 2 -7/8" 6.4 L-80 Butt 2.441 0' 8031' 6961' 2 2 -3/8" 4.6 N -80 Butt 1.995 8032' 9936' 8578' I * Window cut f/ 8450' to 8516'. Original 9 -5/8" (4 8994' MD (7746' TVD) r ■ ) JEWELRY DETAIL NO. Depth TVD ID Item t 42.68' Cameron 11" Split Tbg Hngr Dual 3-1/2 "Butt X EUE. 'IR:ItI "Iltiv/. C 3 A. 299' Otis "FM" SCSSV II. 2 -71" Daniels "DSO" Gas Lift Mandrels, 4" a 4.75" Eccentric Body t . #1 2670' 2,548' 2.347 2 -7/8" GLM #2 3948' 3,612' 2.347 2 -7/8" GLM D #3 5170' 4,610' 2.347 2 -7/8" GLM I I 4 #4 6252' 5,504' 2.347 2 -7/8" GLM #5 7157' 6,250' 2347 2 -7/8" GLM L t #6 7905' 6,852' 2.347 2 -7/8" GLM t (. 8031° 1.995 Crossover, 2 -7/8" X 2 -3/8" E ":T _ --w. 5 D. 2 -3/8" Daniels "DSO" Gas Lift Mandrels, 2.9" x 4.25" Eccentric Body #7 8420 7,291' 1.9 2 - 3/8" GLM F 6 #8 8907 7,705' 1.9 2 -3/8" GLM #9 9367 8,103' 1.9 2 -3/8" GLM #10 9817 8,478' 1.9 2 -3/8" GLM }„ 9887' 8,542' 1.875 2 -3/8" Otis "XA" Sliding Sleeve F. 9922' 8,565' 1.94 7" Otis "RDH" Dual Packer, SS set 3 G Lo2 (: sTRIN, 4' of 2 -3/8" tubing tail = G-3 1 310' Otis "FM" SCSSV H 10,408' 7 ' lt" Daniels "DSO" Gas Lift Mandrels, 4" x 4.75 Eccentric Both G -4 #1 2737' 2,606' 2347 2 -7/8" GLM #2 4197' 3,815' 2.347 2 -7/8" GLM G -5 #3 5328' 4,741' 2.347 2 -7/8" GLM #4 6062' 5,344' 2.347 2 -7/8" GLM ` 8 #5 6732' 5,903' 2.347 2 -7/8" GLM 9 #6 7285' 6,349' 2.347 2 -7/8" GLM #7 7775' 6,743' 2.347 2 -7/8" GLM I. 10 3 8031' 6.960' 1.998 Crossover, 2-7/8" X 2 -3/8" 11 4 2 - .1t" Daniels - DSO" Gas Lift Mandrels, 2,9" s 4,25" Eccentric Body #8 8189' 7,096' 1.9 2 -3/8" GLM #9 8612' 7,452' 1.9 2 -3/8" GLM 12 #10 9037' 7,814' 1.9 2 -3/8" GLM #11 9426' 8,153' 1.9 2 -3/8" GLM /.. #12 9842' 8,504' 1.9 2 -3/8" GLM 2/14/04: Ran 1.75" EE HB -1 ° 9879' 8,533' 1.875 Star bit to 10600'. 6 9919' 8,571' 1.94 7" Otis "RHD" Dual Packer 7 10,053' 8,680 1.916 Otis Blast Joints, (not flush, 3/16" gap when made -up) Spotted Sized Sall pill 8 10,472' 9,050' 1.875 2 3'9" ()t➢s "N. A' Shan, ' z to control fluid loss. HB -4 9 10,507 9,075' 1.995 Otis Straight Slot Locator, w/ 9.98' Otis 3.22" seal Assy 10 DIL 10,500' 9,067' 4.00 Otis "BWH" Penn Pkr (10,500' DIL) HB -5 10,549' 9,116' 1.791 2 -3/8" Otis "X" Nipple, 1.875 12 10,582' 9,148' 1.995 WLEG 10.81' 4-5/8" PERF HB -6 btm 10,583' 9,149' GUN@ 11,406' HB -7 PERFORATION DATA Zone Top Btm Amt SPF Last Opr. Present Condition G -2 10,140' 10,170' 30' 6 2119192 Open L , G -3 10,225' 10,257' 32' 6 2/19192 Open G-4 10,278' 10,340' 62' 6 2/19/92 Open RKB to MLLW ELEV = 103' G -5 10,395' 10,415' 20' 6 2119/92 Open TD = 11,506' ETD = 11,430' HB -1 10,628' 10,670' 42' 10 & 16 8/26/95 Open, frac'd 10,628'- 10,643' MAX HOLE ANGLE = 39.10° @ 7225' HB 4 10,863' 11,000 137' 6 2119192 Open HB -5 11,040' 11,070' 30' 8 8/26195 Open HB-6 11,155' 11,170' 15' 4 8/26/95 Open HB -7 11,255' 11,280' 25' 24 6/24/94 Open \ \ak- anchorage \groups \DRILLING \Users \TylerS\2005 Projects\2005 Grayling \G -1 RD Tubing Punch AFE_164287 \Schematics \G -1 Schm08I405.doc REVISED: 08/14/05 DRAWN BY: SLT ((lj ~c ';:J ''\\\ ¡ I f~t) \ t ¡ \.--~'::.. ! L.~~ ,..;:::;- r"r;] ¡ ¡ \ 1¡ I 1-1 [ ¡ ¡ I r- \ U j , ~ '-'-'.- \.1 r~"'\ it, \ ! l J \ ,U:-\~ FRANK H. MURKOWSKI, GOVERNOR AI/A~1iA. OIL AND GAS CONSERVATION COMMISSION 333 W. ?TH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907)27&7542 June 23, 2004 Dwight Johnson Field Superintendent U nocal PO Box 196247 Anchorage, Alaska 99519 RE: No-Flow Verification Trading Bay Unit G-01RD, PTD 191-139 G-02RD, PTD 182-067 G-17RD, PTD 178-003 G-28RD, PTD 200-038 Dear Mr. Johnson: On May 27, 2004, AOGCC Petroleum Inspector John Spaulding witnessed "no flow tests" at Unocal's Grayling platform, Trading Bay Unit, Wells G-01RD (short and long string completions), G-02RD, G-17RD, and G-28RD. Each well was opened to atmosphere through flow measurement equipment with suitable range and accuracy and monitored. An immeasurable flow of gas and no liquid hydrocarbons were produced to surface during the test. The subsurface safety valve may be removed from service in each of the wells listed above based on the no-flow test results. A fail-safe automatic surface safety valve system capable of preventing uncontrolled flow must be maintained in proper working condition in each well as required in 20 AAC 25.265. The subsurface safety valve must be returned to service in any well that demonstrates an ability to flow unassisted to surface. Please retain a copy of this letter on the Grayling platform. Sincerely, \~ ~TJ '0~b- )~~c James B. Regg 17 Petroleum Inspection Supervisor cc: Bob Fleckenstein MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg . Kéqtj b{;;zjCtr' P. I. Supervisor l ( DATE: June 22,2004 \~\/ \~o¡ FROM: John Spaulding, Petroleu m Inspector SUBJECT: "No Flows" Unocal Grayling Platform 5 wells p-¡-~ .~ I ß1.-- Ob 7 June 15, 2004: I traveled to Unocal's Grayling platform to witness "No Flows" on 5 wells, defined as follows. The platform was shut in for some upgrades while I was there. All wells were ready to commence testing upon my arrival. The same bleeding and testing procedures were used on all 5 wells. G-2RD: Well was bled to the well clean tank and after sufficient bled was then vented to atmosphere. Gas flow was positive but not measurable, no fluids observed. Recommend for no flow status. 11<2>--CD3 G-17RD: Positive but not measurable gas flow, no fluids observed. Recommend for no flow status. 'ZOo-D'3'b G-28RD: Positive but not measurable gas flow, no fluids observed. Recommend for no flow status. 19/- /39 G-1 RDL: Positive but not measurable gas flow, no fluids observed. Recommend for no flow status. G-1 RDS: Positive but not measurable gas flow, no fluids observed. Recommend for no flow status. SUMMARY; I witnessed the successful no flow tests on the Grayling Platform Attachments: none NON-CONFIDENTIAL 2004-0615_no_flows- TBU- Grayling(5wells).doc THE MATERIAL UNDER THIS COVER HAS BEEN MICROFILMED ON OR BEFORE NOVEMBER 13, 2000 E E pL E W M A T E .RI A 'LU N D E R I · THIS MARKER C:LO~M.DOC ~-'"-" STATE OF ALASKA ALASKA Ol' AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation shutdown Stimulate Plugging -- Perforate X Pull tubing After casing Repair well Pull tubin~l Other 2. Name of Operator UNION OIL COMPANY OF CALIFORNIA (UNOCAL) 5. Type of Well: Development Exploratory Stratigraphic Service 3. Address P.O. BOX 196247 ANCHORAGE, AK 99519 - 6247 Location of well at surface Leg 2, Cond.40 1886' FSL & 1386' FEL, Section 29, T9N, R13W, SM At top of productive interval 2827' FSL & 3158' FWL, Section 28, T9N, R13W, SM At effective depth At total depth 2960' FSL & 3823' FWL, Section 28, T9N~ R13W, SM at 11,506' MD Present well condition summary Total depth: 11506 feet 9945 feet x measured Plugs (measured) tree verti~l Effective depth: measured 11430 feet Junk (measured) true vertical 9883 feet 6. Datum elevation (DF or KB) 103' KB above MSL 7. Unit or Property name Trading Bay Unit 8. Well number G-1RDL 9. Permit number ~'/'- / 3 ? --~-39/94-230 10. APl number 50-733-20037-01 11. Field/Pool McArthur River/Hemlock ORIGINAL 12. feet Casing Length Size Cemented Measured depth True vertical depth Structural 327' 26" Driven 327' 327 Conductor Surface Intermediate 2160' 13-3/8" 3100 sx 2160' 2017' Production 8994' 9-5/8" 2700 sx 8994' 7678' Liner 3352' 7" 1000 sx 8127'-11479' 6941 '-9820' Perforation depth: measured 10628'-10670'; 10863'-11000', 11040'-11070'; 11155'-11170'; 11,155'-11,170'; 11255'-11280' true vertical 9186'-9223'; 9390'-9509'; 9541'-9567'; 9639'-9652'; 9725'-9747' 13. 14. Tubing (size, grade, and measured depth) Packers and SSSV (type and measured depth) Packers: Dual @ 9919' & 9922', Single ~ 10507' SSSV: Offs ~ 317' Stimulation or cement squeeze summary Intervals treated (measured) Treatment description including volumes used and final pressure LS: 2-7/8" x 2-3/8", 6.4# & 4.6#, L-80 @ 10583' SS: 2-7/8" x 2-318", 6.4# & 4.6#, L-80 @ 9945' Alaska 0il & Gas Cons. Col Anchorage Representative Daily Average Production or Injection Data OiI-Bbl Gas-Mcf Water-Bbl Casing Data Tubing Pressure Prior to well operation 8/2/95 254 225 750 1345 220 Subsequent to operation 9/21/95 397 214 939 1380 i15. Attachments 16. Status of well classification as: __ Copies of Logs and Surveys run Daily Report of Well Operations Oil X Gas Suspended 1 i71 I hereby certify that the for~°i~ i~ ~ ,tru, (e,~d/tor~.~c~t~~/b~est of my knowledge. ISigned G. Russell Schmidt ~~ '~o,,~~e Drilling Manager 120 Service Form 10-404 Rev 06/15/88 Date SUBMIT IN ,mission Unocal Corporation Oil & Gas Operations 909 West 9th Avenue, P. L). Box 196247 Anchorage, Alaska 99519-6247 Telephone (907) 276-7600 UNOCAL ) October 31, 1995 Alaska Mr. Russ Douglas, Commissioner Alaska Oil & Gas Conservation Comm. 3001 Porcupine Drive Anchorage, Ak. 99501-3192 Dear Mr. Douglas: Re' Grayling Platform Well G-1RDL APl Number 50-733-20037-01 On August 26, 1995 the following intervals were reperforated in Well G-1RDL: BENCH TOP (MD) BOTTOM (MD) FEET HB 1 10628 10670 42 HB5 11040 11070 30 HB6 11155 11170 15 TOTAL 87 Attachment Very truly yours, ! Candace Williams fl0V 0 8 1995 AlaSka 0il & Gas Cons. C0mmissior~ Anchorage '-"'-'~' STATE OF ALASKA ALASKA O~L AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: 2. Name of Operator Operation shutdown ..... Pull tubing After casing UNION OIL COMPANY OF CALIFORNIA (UNOCAL) 3. Address P.O. BOX 196247 ANCHORAGE, AK 99519- 6247 4. Location of well at surface Leg 2, Cond.40 1886' FSL & 1386' FEL, Section 29, T9N, R13W, SM At top of productive interval 2827' FSL & 3158' FWL, Section 28, T9N, R13W, SM At effective depth Stimulatew .._ Plugg.~.~ -,, Repair well 5. Type of Well: Development ~ Exploratory m Stratigraphic __ Service At total depth 2960' FSL & 3823' FWL, Section 28~ T9N, R13W, SM at 11,506' MD 12. Present well condition summary Total depth: measured 11506 feet true vertical 9945 feet Perforate X Pull tubing Other 6. Datum elevation (DF or KB) 103' KB above MSL feet 7. Unit or Property name Trading Bay Unit 8. Well number G-1RDL 9. Permit number .-94-~9194-230 10. APl number 50-733-20037-01 11. Field/Pool McArthur River/Hemlock Plugs (measured) Effective depth: measured i 1430 feet Junk (measured) true vertical 9883 feet Casing Length Size Cemented Measured depth True vertical depth Structural 327' Conductor Surface Intermediate 2160' 13-3/8" 3100 sx 2160' 2017' Production 8994' 9-5/8" 2700 sx 8994' 7678' Liner 3352' 7" 1000 sx 8127'-11479' 6941'-9820' Perforation depth: measured 10628'-10670'; 10863'-11000', 11040'-11070'; 11,155'-11,170'; 11255'-11280' true vertical 9186'-9223'; 9390'-9509'; 9541'-9567'; 9639'-9652'; 9725'-9747' Tubing (size, grade, and measured depth) LS: 2-7/8" x 2-3/8", 6.4# & 4.6#, L-80 @ 10583' SS: 2-7/8" x 2-3/8", 6.4# & 4.6#, L-80 @ 9945' Packers and SSSV (type and measured depth) Packers: Dual (~ 9919' & 9922', Single ~ 10507' SSSV: Otis @ 317' 13. Stimulation or cement squeeze summary Intervals treated (measured) OCT 2 ~dask~ .0il & Gas Cons. C0 'Anchorage 14. Treatment description including volumes used and final pressure ...Representative Daily Average Production or Injection Data OiI-Bbl Gas-Mcf Water-Bbl Casing Data Tubing Pressure Prior to well operation 8/2/95 254 225 750 1345 220 Subsequent to operation 9/21/95 397 214 939 1380 120 15. Attachments 16. Status of well classification as: Copies of Logs and Surveys run Daily Report of Well Operations .~ ~ Oil X Gas Suspended Service 7' I hereby certify that the f°l~°~...i~..~I ~rrec~'~the best °f mY kn°wledge' ;igned G. Russell Schmidt_j~',~LV~-/.~ifle Ddlling Manager Date /'~: Form 10-404 Rev 06115188 /' SUBMIT IN DLJPLICA~E ~missi0n Unocal Corporation Oil & Gas Operations 909 West 9th Avenue, P.u. I~ox 196247 Anchorage, Alaska 99519-6247 Telephone (907) 276-7600 UNOCAL October 23, 1995 Alaska OCT 2'[ 1995 Alaska .~il .& Gas Cons. Commission =. ~ch0rage Mr. Russ Douglas, Commissioner Alaska Oil & Gas Conservation Comm. 3001 Porcupine Drive Anchorage, Ak. 99501-3192 Dear Mr. Douglas: Re: Grayling Platform Well G-1RDL APl Number 50-733-20037-01 On August 26, 1995 the following intervals were perforated in Well G-1RDL: BENCH TOP (MD) BOTTOM (MD) FEET REPERFORATED HB1 10,628 10,670 42 HB5 11,040 11,070 30 PERFORATED HB6 1!,155 11,170 15 TOTAL 87 Very truly yours, Candace Williams Attachment Ralph P. Holman Engineer Technician Unocal P.O. Box 196247 Anchorage, Alaska 99519-6247 March 9, 1995 Mr. Russ Douglas Commissioner Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 On September 4, 1994 the following intervals were perforated in well G-1RDL (AP150-733-20037-01) in the McArthur River Field: BENCH TOP (MD) I-lB5 11,040 BoTroM (MD) 11,070 30 TOTAL 30 FEET Since[ely, STATE OF ALASKA ALAE-'- OIL AND GAS CONSERVATION (' -"' ,MISSION REPOR, OF SUNDRY WELL Or .--RATIONS 1. Operations performed: Operation shutdown __ Stimulate Pull tubing __ Alter casing__ __ Plugging __ Perforate X_ Repair well __ Pull tubing __ Other__ 2. Name of Operator Union Oil Company of California (Unocal) 3. Address P.O. Box 196247, Anchorage, Alaska 99519-6247 4. Location of well at surface Leg #2, Conductor #40 1886' FSL & 1386' FEL, Section 29, T9N, R13W, SM At top of productive interval 2827' FSL & 3158' FWL, Section 28, T9N, R13W, SM At effective depth At total depth 2960' FSL & 3823' FWL, Section 28, T9N, R13W, SM at 11,506' MD 5. Type of Well: Development X_ Exploratory ~ Stmtigraphic Service __ 6. Datum elevation (DF or KB) KB 103' 7. Unit or Property name Trading Bay Unit 8. Well number G-1RD feet 9. Permit number/approval number 91 -t39/94-230 10. APl number 50-733-20037-01 11. Field/Pool McArthur River/Hemlock 12. Present well condition summary Total depth: measured 11506 true vertical 9945 Effective depth: measured 11430 true vertical 9883 Casing Structural Conductor Surface Intermediate Production Liner Perforation depth: measured feet Plugs (measured) feet feet Junk (measured) feet Length Size Cemented Measured depth 327' 26" Driven 327' 2160' 13 3/8' 3100 sx 2160' 8994' 9 5/8' 2700 sx 8994' 3352' 7" 1000 sx 8127'-11479' 10628'-10670', 10863'-11000', 11040-11070, 11255'-11280' True vertical depth 327' 2017' 7678' 6941'-9820' true vertical 9186'-9223', 9390'-9509', 9541-9567, 9625'-9647' 13. Stimulation or cement squeeze summary 14. Tubing (size, grade, and measured depth) LS: 2 7/8" x 2 3/8", 6.4# & 4.6#, L-80 @ 10583' SS: 2 7/8' x 2 3/8", 6.4# & 4.6#, L-80 @ 9945' Packers and SSSV (type and measured depth) Packers: Dual @ 9919' & 9922', Single @ 10507' SSSV: Otis @ 317' RECEIV D Intervals treated (measured) APR 2 0 1995 Treatment description including volumes used and final pressure ,,~(a IJil & Gas Cons. Commission Representative Daily.Ave. ra.cle Production or Inl~n Data,A~ctlora: ~ OiI-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation Subsequent to operation 15. Attachments Copies of Logs and Surveys run__ Daily Report of Well Operations 7. I hereb,~'~erti.fy that tbe,,~or~going is true and correct to the best of my knowledge. Signed .~,,.~'~G/J~ 6/~~ 302 302 771 1300 90 663 396 879 1360 110 16. Status of well classification as: Oil X_ Gas ~ Suspended __ Service Form 10-404 Rev 06/15/88 SUBMIT IN DUPLICATE f~--- STATE OF ALASKA - --- A 'C& OIL AND GAS CONSERVATION CO[ SION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation shutdown Pull tubing __ Alter casing__ 2. Name of Operator UNION OIL COMPANY OF CALIFORNIA (UNOCAL) 3. Address P.O. BOX 196247 ANCHORAGE, AK 99519 4. Location of well at surface 1886' FSL & 1386' FEL, Sec. 29, T9N, R13W, SM At top of productive interval 10,140' MD 2827' FSL & 3158' FWL, Sec. 28, T9N, R13W, SM At effective depth 11,430' MD 2924' FSL & 3817' FWL, Sec. 28, T9N, R13W, SM At total depth 11,506' 2960' FSL & 3823' FWL, Sec. 28, T9N, R13W, SM Stimulate Plugging __ Perforate __ Repair well m Pull tubing OtherX 5. Type of Well: Development Exploratory Stratigraphio Service ORIGINAL 6. Datum elevation (DF or KB) 103' RKB above MLLW feet 7. Unit or Property name TRADING BAY UNIT 8. Well number G-1RD 9. Permit number/approval number 91 - 139/94-339 10. APl number 50 -733-20037-01 11. Field/Pool MCARTHUR RIVER/HEMLOCK 12. Present well condition summary Total depth: measured true vertical 11506' 9943' feet feet Plugs (measured) 11430' Effective depth: measured true vertical 11403' 9876' feet feet Junk (measured) 11376' Casing Structural Conductor Surface Intermediate Production Liner Length 26" 13-3/8" 9-5/8" 7" Perforation depth: measured Size Cemented Measured depth Driven 327' True vertical depth 61# 3100 sx 2160' 40,43.5,47# 2700 sx 29" 1000 sx 10628'-10643';10628'-10670';10683'-11000';10140'-10170';10225'-10257' 10278'-10340';10395'-10415' true vertical 9186'-9198'; 9186'-9223'; 9390'-9509'; 8759'-8785'; 8833'-8861' 8879'-8933'; 8981 '-8999' Tubing (size, grade, and measured depth) LS 2-7/8" x 2-3/8" 6.4# & 4.6# L-80 10,583' SS 2-7/8" x 2-3/8" 6.4# & 4.6# L-80 9945' Packers and SSSV (type and measured depth) Otis ROH pkr 9922' Otis FM SSSV 299 Otis PKR @ 10507' r) !~ r' r, I ~1 i- r~ 13. Stimulation or cement squeeze summary I~L ~ L I V L I~' Intervals treated (measured) N/A jAI I 2 4 1995 Treatment description including volumes used and final pressure N/A AIsska Oil & Gas Cons. Commission Anchor; . 14. Prior to well operation N/A Subsequent to operation N/A Representative Daily Average Production or Injection Data OiI-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure 15, Attachments Copies of Logs and Surveys run Daily Report of Well Operations X 16. Status of well classification as: Oil X Gas __ Suspended Service 17. I here~c~e~and correct to the best of my knowledge. Signed G. Russell Schmidt Title Drilling Manager Form 10-404 Rev 06/15/88 Date 1/18/95 SUBMIT IN DUPLICATE 13-3/8" 61~ ,/-55 7'29~ P-I' 10 TOL @ 8127' 40, 43.5 & 47~11 N-~O@ 8994' 7'L@ 11479' TUBING DETAIL: L$: 2-7/8', &4#, L-80 BUTTRESS ($P Cl.) 2-3/8'. 4.~, L-80 8~$S ($P CL) SS: 2-7/8', &4#, L-80 8~65 (SP C~ 2-3f8'. 4.6~, L-80 BUTTRESS (SP CA.) SHORT STRING ohs 2.z~. mG n~T SSSV GUa ~ ~, 2e70' (2.?/~ GLM ~4 ~, ~' G~I ~10 ~ gelT o~ o1~ 24r1' 'xA. SLF. EVE ~ mm~ OT~ 'f~H' OUN. PKR e ~2Z OTIS 2~' ~ Na~LE · ~41' 11 LONG STRING 1) OTIS 2.?/1" TI~3RET SSSV ~ ~1~ G.M ~ ~ zr~ (2.7/~ OLM ,4 GI.I,1,7 ~ 77'/5' Q.M ~10 ~ eO3T ~ ~S~~T~ I~) FIB4 101~21'* I O~71T COMPLETION ( 3-25-92 ) UNION OIL COMPANY OF CAUFORNIA (dba UNOCAL) RECEIV JAN 2 4- 19, Ataska 0il & Gas Cons. Anchor; /~/$/~.~) ¥//~--~,~) ~/.~//~ DRAWN: DAC SCALE; NONE DATE: 8-7-92 D 5 3mmission G-1RD (SHORT STRING) REQ 3 DAYS U.O. 56.05% G-1RD (SHORT STRING) DAY 1 (12129194) 9-5~8" @ 8994' 7" @ 8127'-11,479' RU LUB & C.T.U. TEST TI3000 PSI. RIH WI1.5" WASH NOZZLE. DOWN WT WENT FROM 6000# TO 4000# & UP WT @ 2500#. HIT MAX PULL @ 9700' OF 26,000#. INCREASE W2 RATE-NO CHANGE. POOH. APPEARS THAT THE 2-3~8" TBG IS CORKSCREWED OR KINKED. DID NOT RUN 1-11/16" DUMMY GUN. RELEASE C.T.U. 12/29/94 (~ 18:00. RECEIVED JAN 2 4 ]995 Alaska Oil & Gas Cons. Commission Anchor; STATE OF ALASKA AL ~, OIL AND GAS CONSERVATION CON. 31ON APPLIC/ rlON FOR SUNDRY APPROVALS 1. Type of request: Abandon __ Suspend __ Operations shutdown __ Re-enter suspended well__ Alter casing__ Repair well __ Plugging __ Time extension __ Stimulate -- Change approved program __ Pull tubing _ _ Variance __ Perforate X OtherX___ 2. Name of Operator UNION OIL COMPANY OF CALIFORNIA (UNOCAL) 3. Address P.O. BOX 196247 ANCHORAGE, AK 99519 4. Location of well at surface 5. Type of Well: Development X_ Exploratory Stmtigraphic __ 1886' FSL & 1386' FEL, Sec. 29, R9N, R13W, SM At top of productive interval 10,140' MD 2827' FSL & 3158' FWL, SEC. 28, TgN, R13W, SM At effective depth 11,430' MD 2924' FSL & 3817' FWL, SEC. 28, T9N, R13W, SM At total depth 11,506' 2960' FSL & 3823' FWL, Sec. 28, T9N, R13W, SM 6. Datum elevation (DF or KB) 103' RKB ABOVE MLLW 7. Unit or Property name TRADING BAY UNIT 8. Well number G-1RD feet 9. Permit number 10. APl number 50 -733-20037-01 11. Field/Pool MCARTHUR RIVER/HEMLOCK 12. Present well condition summary Total depth: measured true vertical 11506' 9943' feet feet Effective depth: measured 11430' feet true vertical 9876' feet Plugs(measured) 11430' Junk (measured) 11376' ORIGINAL Casing Length Size Cemented Structural 26" DRIVEN Conductor Surface Intermediate 13-3/8" 61 Cf 3100 sx Production 9-5/8" 40, 43.5, 47Cf 2700 sx Liner 7" 29" 1000 sx Perforation depth: measured true vertical Measured depth 327' 2160 Tubing (size, grade, and measured depth) LS 2-7/8"x 2-3/8" 6.4Cf & 4.6Cf L-80 10,583' SS 2-7/8" x 2-3/8" 6.4Cf & 4.6Cf L-80 9945' Packers and SSSV (type and measured depth) Otis ROH pkr 9922' Otis FM SSSV 299 Otis PKR @ 10,507' True vertical depth RECEIVED DEC 2 2 1994 AlaSka Oil & Gas Cons. C0mmissi0 Anch0ra, :e 10628'-10643';10628'-10670';10683'-11000;10140'-10170';10225'-10257'; 10278'-10340';10395'-10415' 9186'-9198'; 9186'-9223'; 9390'-9509';8759'-8785'; 8833'-8861'; 8879'-8933';8981'-8999' 13. Attachments Description summary of proposal _ _ Detailed operations program~. BOP sketch 14. Estimated date for commencing operation 115. DECEMBER 19, 1994 16. If proposal was verbally approved Oil X_ Gas Name of approver Date approved Service 17. I hereby certify that the for~o/i~g is(~e~~t to the best of my knowledge. Signed G. Russell Schmidt j~:k~,M~,~J~Title Drillinq Manager FOR COMMISSION USE ONLY Status of well classification as: __ Suspended Date 12/19/94 Conditions of approval: Notify Commission so representative may witness Plug Integrity __ BOP Test Location clearance Mechanical Integrity Test Subsequent form required 10- Approved by the order of the Commission Original Signed By David W. Johnston I Appr°val (~'c/_ ~ ,~ Approved Copy Rjaturngd Commissioner Date Form 10-403 Rev 06/15/88 SUBMIT IN TRIPLICATE McArthur River Field Grayling G-1RD Short String Coiled Tubing Clean -Out Procedure Page: 1 Note: BOP Shear Test was completed (witnessed by Mitchell Damm) on 12/07/94 1) Verify tree/CT BOP connections before moving CTU to the Grayling Platform. (Thread: 3-1/2" 8rd; Flange: 3-1/8" RX25 5M psi) 2) Hold safety meeting and discuss procedure w/coiled tubing personnel and production personnel before starting job. Fill out CT pre-job checklist. Review CT's working history before using coil. 3) RU Dowell CTU, Nitrogen Unit, pump skid, choke line, double choke manifold, kill line, flow tank, and return tank. The Production Foreman and Engineer have allowed taking returns to the separator. Mix-up -_- 70 BBLS of 3% KCI water using FIW. 4) NU BOP on G-1RD Short String (located in Leg 4). Flanged connections will be used. 5) Pressure test BOP, 1-1/2" CT, and all surface lines to 3,000 psi for 10 minutes. Use Nitrogen for pressure test. 6) Complete BOP Inspection 7) MU CT BHA #1 as follows: 1) 1-3/4" wash nozzle 2) 1-11/16" tandem check valve 8) Rill 1.5" CT w/BHA #l--do not exceed 100 FPM. Maintain gas injection while RIH. Begin pumping KC1 water as soon as CT enters the well. Take returns to the separator. While cleaning-out, keep well slightly underbalanced to aid clean-out. Bottom-hole pressure is 2~500-2~700psi. Note: Monitor weight indicator and pump pressures while RIH. Scale obstructions might be encountered throughout tubing. 9) Wash scale from 8:000'-9~944'. Use gas lift to assist solids removal. Discuss alternative plans w/office if wash nozzle is ineffective removing scale. lOs) If wash nozzle is ineffective, RIH w/BHA #2: 1) 1-3/4" mill 2) 1-11/16" motor 3) 1-11/16" tandem check valve 10b) Mill scale from 8,000-9,944'.\; pump 3% KCI water for fluid Make several passes to ensure scale has been removed. 11) POOH w/BHA #2 and 1-1/2" CT. 12) RD CTU. NDBOP. MoveCTUtoG-33L R~L~[~'{~v 13) Before slickline work, keep well shut-in. DIe ~- 2 lc3c3t~ ~,~a~a ~ii & 6as Cons. Commission Anchora e MWD G1RDSPRO. DOC 12/19/94 McArthur River Field Grayling G-1RD Short String Coiled Tubing Clean -Out Procedure Page: 2 After Coiled Tubing Operations: Slickline: 1) 2) RU slickline unit. Test lubricator to 3,000 psi for 10 minutes. Lubricator shall have a pump-in slab. RIH w/1.75" tubing scratcher.. Run entire assembly outside of tubing (TBG Tail ~ 9944') plus another 5'. Verify tubing is clear for GR mn. POOH. 3) RIH w/1.75" GR--dummy gun needs to be _= 30' in length. Minimum restriction is 1.875". 4) Run GR assembly outside of tubing plus another 5'. If GR does not pass or hangs ups, discuss w/ office. 5) POOH w/dummy. RD slickline. 6) Before producing the well, discuss producing the well with the office. Wireline Perforating: Hold wireline pre-job safety meeting. 1) RU Schlumberger wireline unit. have a pump-in sub. 2) 3) 4) 5) 5) 6) Test lubricator to 3~000 psi for 10 minutes. Lubricator shall RIH w/Schlumberger 1-11/16" hollow carrier gun #1 ( 0° - 4 SPF), MOD, and CCL/GR tool; make tie-in pass w/CCL. Reperforate G-Zone Benches 5' 10d40'-10d70' EL. Well will be shut-in during perforating operations. POOH w/CCL/GR. RIH w/remaining guns (w/out GR tool). Make tie-in pass w/CCL; and reperforate G-Zone Benches 2-4: 10~225'-10257'; 10~278-10~340'; 10~295'-10~415' EL. RD wireline unit. Turn well over to production. 0il & Gas Cons. Commission Anchora ~, MWD G1RDSPRO.DOC 12/19/94 / 13-3/8' 61# J-55 @ 216(y 7"29~ P410 TOL @ 8127' 9-5/8' 40. 4&5 & 47# N-80@ 8994' TBG HGRS ~ 4Z8~' 5 E TUBING OETAIL: L$: 2-7/8'. 6,4#. L-80 BUTTRESS ($P CD 2-3/8'. 4.6~. L-80 B~SS ($P CL) SS: 2-7/8'. 6,4#, L-80 BUTTRESS ($P Ct~ 2-3/8'. 4.6~. L-80 B~SS (SP CL) 11 SHORT STRING OTIS 2-7/8' T~G RET SSSV G[.M 4H ~ ~ (2-7~ ~4~ ~ ~7 ~ ~ (2-~ C) 2-7/~; 2~t~' X43VER ~ D) Olds 2.1~' 'XA' SLEEVE E) OT~ q~OH' 0UN. PKR ~ 9a2Z F) O~S 2~V.' 'XN- N~PLE ~ ~e4t' 7'L@ 11479' WELL TBUS G-1 RD ,Vd- ~-//mo'- ~= / COMPLETION ( 3-25-92 ) UNION OIL COMPANY OF CALIFORNIA (dba UNOCAL) LONG STRING 1) OTiS 2-7/~ TBG RET SSSV ~ 311~ GLM ~ ~ ~ (2-7~ ~ ~41~ ~ ~4~ ~7~ ~2~ ~ 2~ s~ ~T ~~ ~ 0~2~~~ 11) O~~~~el~ DEC 2 2 19 Gas Cons. Comm]ssio Ar~cl~ora ~ HO.1 ~0~2~.1064,T (14,~3o4~le,.20RES~COAIEDFRAC) HO.1 I o621r, iM?o' H6.4 10963'. 11000* ~6'1 h,,~7o'-iI,~O ! ....... ~/ ~/171~') DRAWN: DAC SCALE: NONE DATE: 8-7-92 ii i ii i '/'~'~"% i[ I Page 2 of 38 March 1992 · i I! The BOP commonly found on Doweil Schlumberger (DS) coiled tubing units (CTUs) is manufactured t~/Texas 011 Toota (TO'T~. This is available in 8 range of .,sizes (bom), pressure ratk'~$ a, rx:i SemVtC~__ (e.g., t.i~S, Arctk: or Stafxiard service). The model most commonly used is the 3-in., lO,O00-psi Working Pressure, H~$ service Quad BOP. It is this model on which the diagrams and text in this sect~ n are based. Stud-Up Fla.ge Top Conneclion~ SUe Port (K]II Port) · i i i · i jr --~ ii ii ~ COILED TUBING ~ OPERATORS MANUAL The following components are identified in F~jure 1 and 2. · BOP Body · Blind Ram~ · Shear Rams · 8llp Rams · Pipe Rams Manu~l Loc~ Handle Pressure Port BI/nd-Ram Equatizlng Valve (RamNo.~) Shear Rmrm r~,.,,~ (Ram No. 2) (Ram No. 3) PI~ Rams (Ram~.4) Hydraulk~ Acama~ with Ram Position Incaca~r DEC 2 299 ' Oil & Gas Cons. commission · h1~ch0~'~ ~ PERMIT DATA 91-139 SURVEY 9 i-139 CBT 91-139 DIL/SGL 91-139 DIL/SGL 91-139 FWS2 91-139 FWS2 91-139 MUD 91-139 PERF 91-139 PET 91-139 SDL/BDP 91-139 SDL/BDP 91-139 SDL/DSN 91-139 SDL/DSN 91-139 407 91-139 DAILY WELL OP 91-139 F~ SURVEY 91-139 SURVEY P r',./ 91-139 W ~ ' - ' S 91-139 5182 Are dry ditch samples Was the well cored? Are well tests required?_ ~s Well is in compliance k...--~L Initial AOGC;E Individual Geological Materials T DATA_PLUS Well Ii]ventory D 0-11479 L 8102-11409 L 8453-11478 L 8453-11478 L 8453-1147~ L 8453-11478 L 8500-11506 L 10900-11315 L 8102-11412 L 8453-11479 L 8453-11479 L 8453-11479 L 8453-11479 R COMP DATE: 02/26/92 R 01/07/92-02/26/92 R 100-11430 ~2;~ R 0-11479 S 8490-11510~ SS#832 T 8300-11515, OH-DIL required? yes .~~nd received? ye~na!ysis & description received? Comments Page' 1 Date' 01/19/94 SCALE DATE_RECVD 02/21/92 5 02/'21/92 5 02/21/92 2 02/21/92 2 02/21/92 5 02/21/92 2 02/21/92 5 04/20/93 5 02/21/92 2 02/21/92 5 02/21/92 5 02/21/92 2 02/21/92 10/05/92 10/05/92 01/07/93 02/21/92 04/10/92 02/21/92 .4 Unocal North Ame Oil & Gas Division Unocal Corporation 909 West 9th Ave., P.O. Box 190247 Anchorage, Alaska 99519-0247 Telephone (907) 276-7600 Alaska Region UNOCAL DOCUMENT TRANSMITTAL RECEIVED APR £ O 199~ Alaska Oil & Gas Cons. Commission April 16, 1993 TO: Larry Grant FROM' Kirk Kiloh LOCATION: 3001 PORCUPINE DRIVE ANCHORAGE, AK 99501 ALASKA OIL & GAS CONSERVATION COMM. LOCATION: P.O.BOX 196247 ANCHORAGE AK 99519 UNOCAL TRANSMrlTING AS FOLLOWS ' TRADING BAY UNIT 1 blueline and 1 sepia Logs from specified wells listed below "5g0---O~- D-5RD Perforating Record 77-~Z- --D-7RD Perforating Record Perforating Record 'Perforating Record · Perforating Record .Perforating Record Completion Record 10-18-92 10-19-92 11-30-92 11-22-92 11-29-92 12-04-92 6-29-92 6,~-'q5' --' D-20 Completion Record 6-16-92 D-28 D-43RD · D-47 G-1RD M-3 M-7 Completion Rex~°rd :~ .... : ~'6-20-92 Perforating Record Perforating Record Perforating Record Perforating Record Perforating Record Continuous Gyro Tool Cement Bond Tool 11-21-92 11-25-92 10-17-92 12-03-92 12-18-92 ;, 7-24-92 7-24-92 M-28 Perforating Depth Control 8-12-92 M-29 Tubing Patch Record 11-13-92 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COPY OF TRANSMITTAL. THANK YOU TItI$ DOCU1VIENT RECEIVED BY: DATF~D: STATE OF ALASKA ALASI':"'"'31L AND GAS CONSERVATION CC'~'"~MISSION REPOR', OF SUNDRY WELL OI-_RATIONS 1. Operations performed: Operation shutdown __ Stimulate __ Plugging __ Perforate X_ Pull tubing __ Alter casing__ Repair well __ Pull tubing __ Other..._~' 2. Name of Operator 6. Datum elevation Union Oil Company of Califomia (Unocal) 3. Address P.O. Box 196247, Anchorage, Alaska 99519-6247 4. Location of well at surface Leg #2, Conductor #40 1886' FSL & 1386' FEL, Section 29, T9N, R13W, SM At top of productive interval 2827' FSL & 3158' FWL, Section 28, T9N, R13W, SM At effective depth At to~al depth 2960' FSL & 3823' FWL, Section 28, T9N, R13W, SM at 11,506' MD 12. Present well condition summary Total depth: measured 11506 feet true vertical 9945 feet Type of Well: Development X K~ 103' Exploratory Stmtig rap h ic Plugs (measured) Effective depth: measured 11430 feet true vertical 9883 feet feet 7. Unit or Property name Trading Bay Unit 8. Well number G-1RD 9. Permit number/approval number ~,.; 91 439 43-~/t.. 10. APl nurr~ber' 50-733 -20037-01 11. Field/Pool McArthur River/Hemlock Junk (measured) Casing Structural Conductor Surface Intermediate Production Liner Length Size Cemented Measured depth True vertical depth 327' 26" Driven 327' 327' 2160' 13 3/8" 3100 sx 2160' 2017' 8994' 9 5/8" 2700 sx 8994' 7678' 3352' 7" 1000 sx 8127'- 11479' 694 1'-9820' 1 o628'-10670', 1 o863'-11000', 11255'-11280' Perforation depth: measured true vertical 9186'-9223', 9390'-9509', 9625'-9647' Tubing (size, grade, and measured depth) LS: 27/8" x 23/8", 6.4# &4.6#, L-80@ 10583' SS: 2 7/8" x 2 3/8", 6.4# & 4.6#, L-80 @ 9945' Packers and SSSV (type and measured depth) Packers: Dual @ 9919' & 9922', Single @ 10507' SSSV: Otis @ 317' 13. Stimulation or cement squeeze summary Intervals lreated (measured) 14. Treatment description including volumes used and final pressure Prior to well operation Subsequent to operation RE( EIVED. MAR 0 Alaska 0il & Gas Cons. Oomf~iss Anchorage Representative Daily Average Production or Injection Data OiI-Bbl Gas-Mcf Water- Bbl Casing Pressure 493 0 851 1 350 Tubing Pressure 90 4~ 0 8~ 1350 15. Attachments 16. Status of well classification as: Copies of Logs and Surveys run Dally Report of Well Operations Oil X Gas Suspended Signed ,L~J F ](/~'-~ ,/~~ Title ~'"~(.L~ Service Form 10-404 Rev 06/15/88 SUBMIT IN DUPLICATE STATE OF ALASKA · . ,, ALASK~ -!LAND GAS CONSERVATION CC ~41SSION APPLIC0_, ION FOR SUNDRY Al-. ROVALS 1. Tyl~e of re~'~est: Abandon ' Suspend Operations shutdown ' Re-enter suspended well ?~.L ~,~ Alter casing Repair well Plugging Time extension Stimulate Change approved program Pull tubing Variance Perforate X Other 2. Name of Operator -- 15. T~e of Well: -- 6.-~-atum eleva~n (DF or KB) Union Oil Company of California (UNOCAL) I Development X KB 103' ' I Exploratory ~ feet 3. Address I Stratigraphic 7. Unit or Property name P.O. Box 196247, Anchorage, Alaska 99519-6247 I Se~ce -- Trading Bay Unit 4. Location of well at surface Leg #2, Conductor #40 1886' FSL & 1386' FEL, Section 29, T9N, R13W, SM At top of productive interval 2827' FSL & 3158' FWL, Section 28, T9N, R13W, SM At effective depth At total depth 2960' FSL & 3823' FWL, Section 28, TgN, R13W, SM at 11506' MD 12. Present well condition summary Total depth: measured 11506 feet Plugs (measured) true vertical 9945 feet 8. Well number G-1RD 9. Permit number 91-139 10. APl number 50-733-20037-1 11. Field/Pool McArthur River/Hemlock Effective depth: measured 11430 feet Junk (measured) true vertical 9883 feet Casing Length Structural 327' Conductor Surface Intermediate 2160' Production 8994' Liner 3352' Perforation depth: measured true vertical Size Cemented Measured depth True vertical depth 26" Driven 327' 327' 13 3/8" 3100 sx 2160' 2017' 9 5/8" 2700 sx 8994' 7678' 7" 1000 sx 8127' - 11479' 6941'-9820' 10628'- 10670', 10863'- 11000' 9186'-9223',9390'-9509' Tubing (size, grade, and measured depth) LS: 2 7/8"x2 3/8", 6.4# & 4.6#, L-80 @ 10583' MAR 0 3 !99;5 SS:2 7/8"x2 3/8", 6.4# & 4.6#, L-80 @ 9945' Packers and SSSV (type and measured depth) Packers: Dual @ 9919' & 9922', Single (~g~"0JJ & Gas Cons. SSSV: Otis @ 317' , .......... 13. Attachments Description summary of proposal __ Detailed operations programX__ BO~J~-~::t~u 14. Estimated date for commencing operation 3/93 16. If proposal was verbally approved Name of approver Date approved 5. Status of well classification as: Oil X Gas Suspended Service 17. I here ify g is true and correct to Signed ~/(r',{',-~ ...,,'~~ Title FOR COMMISSION USE ONLY Conditions of approval: Notify Commission so representative may witness Plug Integrity _ BOP Test Location clearance Mechanical Integrity Test_ Subsequent form required 10- Approved by the order of the Commission David W. johnStOn JApproval No./% '.~ Commissioner Date Form 10-403 Rev 06/15/88 SUBMIT IN TRIPLICATE February 19, 1993 Grayling, Well G-1RD perforatinq procedure 1. Hold safety meeting. 2. RU electric line unit. 3. Pressure test lubricator to 2500 psi for five minutes. 4. Shut down all welding and radio transmissions. 5. RIH and perforate intervals as instructed by Unocal (When gun is 200' below surface, welding and radio transmissions may resume.) 6. POOH. (When gun is 200' below surface, shut down all welding and radio transmissions.) 7. Repeat steps 5,6 and 7 as needed to perforate the following intervals: BENCH MEASURED TRUE VERTICAL TOTAL FEET HB7 11,255'-11,280' 9625'-9647' 25' TOTALS 25' STATE OF ALASKA ALASK'"~-%LAND GAS CONSERVATION CC .... iSSlOh0R I GIN ^ REPOR'I OF SUNDRY WELL OPI:.r ATIONS Operations performed: Operation shutdown __ Stimulate __ Plugging __ Perforate X_ Pull tubing __ Alter casing__ Repair well __ Pull tubing m Other m , o , Name of Operator Union Otl Company of California (Unocal) Address P.O. Box 196247, Anchorage, Alaska 99519-6247 5. Type of Well: Development X Expk)mton/ Location of well at su/ace Leg #2, Condu::tor #40 1886' FSL & 1386' FEL, Section 29, T9N, R13W, SM At top of productive interval 282.7' FSL & 3158' FWL, Section 28, TgN, R13W, SM At effective depth At total depth 2960' FSL & 3823' FWL, Section 28, T9N, R13W, SM at 11,506' MD 6. Datum elevation (DF' or KB) KB 103' 7. Unit or Property name Trading Bay Unit 8. Well number G-1RD 9. Permit number/approval number 91-~9~ / .3 ~ 10. APl number 50 -733 -2OO37 -01 11. Field/Pool McArthur River/Hemlock feet 12. Present well condition summary Total depth: measured 11506 feet true vertical 9945 feet Plugs (measured) Effective depth: measured 11430 feet true vertical 9883 feet Casing Structural Conductor Surface Intermediate Production Liner Junk (measured) Length Size Cemented Measured depth True vertical depth 327' 28" Driven 327' 327' PerforaUon depth: measured 2160' 13 3/8' 3100 sx 2160' 2017' 8994' 9 5/8" 2700 sx 8994' 7678' 3352' 7" 1000 sx 8127'-11479' 6941 '-9820' 10628'-10670'. 10863'-11000'. 11255'- 11 280' true vertical 9186'-9223', 9390'-9509', 9625'-9647' Tubing (size, grade, and measured depth) LS: 2 7/8" x 2 3/8', 6.4# & 4.6#, L-80 @ 10583' SS: 2 7/8" x 2 3/8", 6.4# & 4.6#, L-80 @ 9945' Packers and SSSV (type and measured depth) Packers: Dual @ 9919' & 9922', Single @ 10507' s v: r i'V O 13. Stimulation or cement squeeze summary Intervals lreated (measured) Treatment description including volumes used and final pressure Alaska, Oil & 6as Cons. Anchorage 14. Prior to well operation Subsequent to operation Representative Daily Average Production or Injection Data OiI-Bbl Gas-Mcf Water-Bbl Casing Pressure 247 1900 592 1330 1965 ~ 2100 ~ .... 242 ~-., 1380 Tubing Pressure 110 15. Attachments Copies of Logs and Surveys run~ Dally Report o! Well Operations 16. Status of well classification as: Oil X Gas Suspended Sen/ice 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. SUBMIT IN DUPLICATE STATE OF ALASKA ALASK"--"L AND GAS CONSERVATION CC-"qlSSION APPLIC ION FOR SUNDRY AF, ROVALS 1..Type of request: Abandon __ Suspend Alter casing__ Repair well Change approved program __ 2. Name of Operator Union Oil Company of Califomia (UNOCAL) 3. Address P.O. Box 196247, Anchorage, Alaska 99519-6247 Operations shutdown Re-enter suspended well Plugging __ Time extension __ Stimulate __ Pull tubing _ Variance Perforate X Other 4. Location of well at surface Leg #2, Conductor #40 1886' FSL & 1386' FEL, Section 29, 'rgN, R13W, SM At top of productive Interval 2827' FSL & 3158' FWL, Section 28, T9N, R13W, SM At effective depth 5. Type of Well: Development Exploratory 6. Datum elevation (DF or KB) KB 103' 7. Unit or Property name Trading Bay Unit 8. Well number G-1RD 9. Permit number 91-139 10. APl number 50 - 733 - 20037 - 1 11. Field/Pool McArthur River/Hemlock At total depth __2960' FSL & 3823' FWL, Section 28, T9N, R13W, SM at 11506' MD 12. Present well condition summary Total depth: measured 11506 feet Plugs (measured) true vertical 9945 feet Effective depth: measured 11430 feet Junk (measured) true vertical 9883 feet Casing Length Structural 327' Conductor Surface Intermediate 2160' Production 8994' Liner 3352' Perforation depth: measured true vertical Size Cemented Measured depth True vertical depth 26" Driven 327' 327' 13 3/8" 3100 sx 2160' 2017' 9 5/8" 2700 sx 8994' 7678' 7" 1000 sx 8127'-11479' 6941 '-9820' 10628'-10670', 10863'-11000' RECEIVED Tubing (size, grade, and measured depth) L$: 2 7/8'W2 3/8", 6.4# & 4.6#, L-80 @ 10683' NOV 5 0 1992 SS:2 7/8'x2 3/8", 6.4# & 4.6#, L-80 @ 9945' Packers and SSSV (type and measu'ed depth) Packers: Dual @ 9919' & 9922', Single @105o~rlaska Oil & Gas Cons. SSSV: Otis @ 317' ;Anchorage; 13. Attachments Description summary of proposal __ Detailed operations programX__ BOP sketch 14. Estimated date for commencing operation I15. 16. If proposal was verbally approved Oil X_ Gas Name of approver Date approved Sen/ice 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. ¢ondltira-~ of ro ~otl~ Commission so representati~ may witness Plug Integrity _ BOP Test Location clearance Mechanical Integrity Test_ Subsequent form required 10- ,YO ~,~ ;. Approved bY the order of the Commission Status of well classifK;ation as: Suspended oRIGINAL SIGNED BY ~USSELLA. DOUG~ Commissioner Form 10-403 Rev 06/15/88 SUBMIT IN TRIPLICATE November 25, 1992 Grayling,..Well G-~RD perforating Drocedure 1. Hold safety meeting. 2. RU electric line unit. 3. Pressure test lubricator to 2500 psi for five minutes. 4. Shut down all welding and radio transmissions. 5. RIH and perforate intervals as instructed by Unocal (When gun is 200' below surface, welding and radio transmissions may resume.) 6. POOH. (When gun is 200' below surface, shut down all welding and radio transmissions.) 7. Repeat steps 5,6 and 7 as needed to perforate the following intervals: BENCH MEASURED TRUE VERTICAL TOTAL FEET HB7 11,255'-11,280' 9625'-9647' 25' Note: After perforating HB7 put well in test for a minimum of twelve hours and record rate and water cut information. If instructed by Unocal representative, continue perforating the following intervals: HB4 10,938'-10,953' 9354'-9367' 15' HB4 10,990'-11,005' 9398'-9411' 15' TOTAL: 55' STATE OF ALASKA ALAS :)IL AND GAS CONSERVATION COk ;SION WELL COMPLETION RECOMPLETION NEPORT AND LOG Submit in duplicate Form 10-407 rev. 7-1-80 CONTINUED ON REVERSE SIDE 1. Status of Well ~ :~' ~'~ ~:, '~ ~ .~: .~ ~ ~ Classification of Service Well · : 2. Name of Operator ' ~'~ 7. Permit Number Union Oil Company of C~ifomia (UNOCAL) ~~ 91--139 3. Addre~ , ,~ ~ 8. APINumber P. O. Box 1 ~247, Anchorage, Alaska ~519~~ 50--7~-2~37-01 4. Location of well at sudace Leg ~2, Conductor ~40 ~ ~ .~ ~ 9. Unit or Lease Name 1~' FSL ~d 1~' FEL, Section ~, T9N, R13W, S.M. ~ ~;.??:~. --,-,,~ r~.~ Trading Bay Unit At Top Producing Inte~ ~ ~r~_EJ. 10. Well Number 2827' FSL and 31~' ~L, Section 28, TgN, R13W, S.M. at 10140' MD I~~~. ~' FSL ~d ~23' ~L, Section 28, T9N, R13W, S.M. at 115~' MD ~--~~ McA~ur R~er Field G' Zone , 5. 1El~afi°n~' RKB inabovefeet MLLW(indicate KB, DF, etc.) 6. Le~eADL 1Designation87~ ~d Seri~ No. Hemlock 12. Date Spudded 13. Date T.D. Reached 14. Date Comp., Susp. or Abed. 15. Water Dep~, E offshore ~ 16. No. of Completions .. 1/07/92 ~10~2 ~/92 125 Feet MSL~ Two 17. Tot~ Dep~ (MD+~D) 18. Plug Back Dep~ (MD+~D) 19. Direc~on~ Su~ 20. Dep~ where SSSV set [21. ~ickness of Permafrost 115~' MD / 9945' ~D 11430' MD / 9~' ~D YES ~ NO ~ SS:299',LS:310'feet MD~ N/A ~. Type Electdc or O~er Logs Run DI~S2/GR; SD~DSN/G~CAL; CB~G~CCL; P~/G~CC~ GYRO SURV~ 23. CASING, LINER AND CEMENTING RECORD PER ~. G~DE TOP i BO~OM HOLE SIZE CEMENTING RECORD AMOUNT PULLED 26' Sudace 327' Dr~en 13--3/8' 61 · J-55 Su dace 2160' 17-1~' 31 ~ sxs 9-5/8' 40, ~.5 &47~ N-~ Sudace 89~' 12--1/4' 27~ sxs Se~on milled f/~' to 8516' MD 7' ~ P- 110 8127' 11479' 8-1 ~' 1 ~ sxs 24. Pedorafions open to Production (MD+~D of Top ~d Bo~om ~d 25. ~BING RECORD inte~, size ~d number) SIZE J DE~ S~ (MD) ~ PACKER S~ (MD) HB--I: 1~28' - 1~' MD (91~' - 91~' ~D) 6 HPF (frac) LS: 2--7/8 x 2-3/8 10~' DuN ~ ~19', Single ~ 10~7' HB--I: 1~28' - 1~70' MD (9186' -- ~3' ~D) 6 HPF SS: 2--7/8 X 2--3/8 9~5' DuN ~ ~' HB-4: 10~' -- 11~' MD (93~' - 9~9' ~D) 6HPF ~. ACID, F~C~RE, CEMENT SQUE~E, ~C. DE~ INTERVAL (MD) ~ AMOUNT & KIND OF MATERIAL USED G-2: 10140' - 10170' MD (8759' - 87~' ~D) 6 HPF G-3: 10~5' - 10257' MD (~' - ~1' ~D) 6 HPF 1~28' - 1~' Fra~ w/1~ 16-20 Resin Coated Carbol~e G--4: 1~78' -- 1~' MD (~79' -- ~' ~D) 6 HPF G--5: 1~95' -- 10415' MD (8981' - 8~' ~D) 6 HPF 27 PRODUCTI~ TEST Date First Production J Me~od of Operation (Flowing, gas lift, etc.) Febma~ 28, 1~2~ SS: 139 gro~ 115 net, 17.4% cut (gasliff) LS: 562 gross/~5 net, 47.5% cut (gasliff) Date of Test Hours Tested PRODUCTI~ FOF OIL-BBL GAS--MCF WATER-BBL CHOKE SIZE J GAS--OIL ~TIO TEST PERIOD FIowTubing Casing Pre~ure CALCU~TED OIL-BBL ~S-MCF WATER--BBL OILG~VI~-A~ (corr) Pre~. 24--HOUR ~TE 28. CORE DATA Bdef descdpfion of Ii, elegy, porosi~, fra~res, apparent dips ~d presenGe of oil, gas or water. Submit core chips. ·/~s~,a Oij ~ Ga;. Co;-~s. Com~issio, .... 29. ;30. GEOLOGIC MARKERS FORMATION TESTS NAME Include interval tested, pressure data, all fluids recovered and gravity, MEAS. DEPTH TRUE VERT. DEPTH GOR, and time of each phase. Top "G" Zone 9716' 8396' TVD Top Hemlock 10628' 9186' I'VD Top West Foreland 11290' 9758' TVD 31. UST OF AI-i'ACHMENT8 32. I heml0~f oertih/Bat Be foregoing is t[ue and correct to the best of my knowledge Ga~ $. Bush/~'~ D~illing Mgr August 17, 1~ INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1' Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21' Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). Item 23: Attached supplemental records for this well should show the details of any multiple stage cement- ing and the location of the cementing tool. Item 27: Method of Operation' Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water In- jection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". 26' @ 327' TBG HGRS (~ 42.85' 13-3/8" 61 # J-55 @ 2160' P-110 TOL @ 81 2T 9-5/8' 40, 43.5 & 47# N-80 @ 8994' TOP OF WINDOW @ 845o' 5 7" L @ 11479' ETD = 11430' TUBING DETAIL: LS: 2-7/8', 6.4#, L-80 BU'i-I-RESS (SP CL) 2-3/8', 4.6#, L-80 BUTTRESS (SP el) SS: 2-7/8", 6.4#, L-80 BU-I-I'RESS (SP CL) 2-3/8', 4.6#, L-80 BUTTRESS (SP CL) 11 SHORT STRING A) OTIS 2-7/8' 'I'BG RET SSSV @ 299' B) DANIELS 'DSO' GLM'S GLM #1 @ 267O' (2-7/8') GLM #3 @ 5170' GLM #4 @ 625Z GLM #5 @ 715T GLM #6 @ 79O5' GLM #7 @ 8420' (2-3/8') GLM #8 @ 89OT ~ GLM #10@9817' C) 2-7/8' x 2-3/8' X-OVER ~ 8031' D) OTIS 2-3/8' "XA" SLEEVE @ 988T E) OTIS "RDH" DUAL PKR ~;~ 9922' F) OTIS 2-3/8' "XN' NIPPLE (~ 9941' G) 2-3/8' REENTRY GUIDE @ 9945' · G' ZONE: G-2 lol 40'- 10170' G-3 10225'- t025T G-4 10278'- 10340' G-5 10395'. lO415' LONG STRING 1) OTIS 2-7/8' TBG RET SSSV @ 310' 2) DANIELS "DSO' GLM'S GUM #1 @ 2737' (2-7/8") GLM #2 @ 4197' GLM #3 @ 532a' GLM #5 @ 6732' GLM #6 @ 7285' GLM #7 @ 7775' GLM #8 @ 8189' (2-3/e") GLM #9 @ 861 Z GLM #10 @ 9O37' GLM #12 @ 984Z 3) 2-7/8' x 2-3/8' X-OVER @ 8131' 4) OTIS 2-3/8' 'XA' SLEEVE @ 9879' 5) OTIS 'RDH' DUAL PKR 6) 2-3/8' STEEL BLAST JTS (3.09 OD) F/1 OO53' TO 10487' 7) OTIS 2-3/8' 'XA' SLEEVE @ 10472' 8) 2-3/8' STR SLOT LOCATOR & SEAL ASSY F/10507' TO 10517' g) OTIS 2-3/8' 'X" NIPPLE (~ 10549' 10) 2-3/8' RE-ENTRY GUIDE (~ 10583' 11) OTIS 'BWH' PERM PKR @ IOS~O'DIL HEMLOCK ZONE: HB-1 10628'- 10643' (14,600~ 16-20 RESIN COATED FRAC) HB-I 10628'- 10670' HB-4 10863.- 11000' WELL TBUS G-1 RD COMPLETION ( 3-25-92 ) UNION OIL COMPANY OF CALIFORNIA (dba UNOCAL) DRAWN' DAC SCALE: NONE DATE' 8-7-92 UNOCAL TUBULAR DETAIL WELL #: o-1 RD GRAYLING PLATFORM PAGE I o£ 1 DATE: FEBRUARY 12, 1992 AFE NO.; $11426 STRING: LINER DETAIL; 7", 29#, P-110, BD'TTRESS FOREMAN: 1 TIW CLS SET FLOAT SHOE 2.45 11476.55 11479 JT.#1 1 .]OINT7',29#, P-110 BU'YI'. CASING (w/ CENTRALIZER IN MIDDLE) 6.184 42.53 11434.02 11476.55 1 TIW FLOAT COLLAR, P-Il0, BUI~RESS 0.96 11433.06 11434.02 JT.#2 1 JOINT7",29#, P-110 BUTT. CASING (w/ CENTRALIZER IN MIDDLE) 6.184 44.15 11388.91 11433.06 1 TIW "L" LANDING COLLAR, P-110 BUTI'RESS 0.75 11388.16 11388.91 JT.#3 1 JOINT7",29#, P-110 BU'I~. CASING (w/ CENTRALIZER ON COLLAR) 6.184 42.97 11345.19 11388.16 JT.#4 1 JOINT7",29#, P-110 BUTI'RESS CASING 6.184 44.59 11300.6 11345.19 5-40 46 JOINTS 7", 29#, P-Il0 BUTI'. CSG. (w/ CENTRALIZER ON EA. COLLAR) 6.184 1557.52 9743.08 11300.6 .IT#41 1 JOINT7",29#, P-110 BLrI'FRESS CASING 6.184 44.19 9698.89 9743.08 42-68 27 JOINTS 7", 29#, P-110 BUWI'RESS CASING 6.184 1171.5 852739 9698.89 (CENTRALIZERS ON EVERY OTHER COLLAR) 0 852739 852739 69-71 3 JOINTS 7", 29#, P-110 BUT'FRESS CASING 6.184 128 839939 852739 72-76 5 JOINTS 7", 29#, P-110 BLYI~. CASING (CENTRALIZER ON EA. COLLAR} 6.184 213.66 8185.73 839939 JT#77 1 JOINT7",29#, P-110 BUTTRESS CASING 6.184 43.46 814227 8185.73 1 TIW DTH-S HYDRAULIC HANGER; L-80 3.43 8138.84 814227 1 TIW S-6 LINERTOPPACKER 11.75 8127.09 8138.84 8127.09 0 0 0 0 0 0 0 0 0 0. 0 0 0 0 ,, 0 ,, 0 0 0 0 NOTE: TOTAL O F 58 BOW SI'RI NG CENTRALIZERS RAN 0 I 0 0 ., UNOCAL TUBULAR DETAIL WELL #: O-1 RD GRAYLING PLATFORM PAGE 1 o£ 2 DATE: MAR~ 25, 1992 AFE NO.: 311426 STRING: LONG STRING; 2-3/8' 4.6~ N-80 SC BlflTRESS TLIBING FOREMAN: 1 PUMP OUT RE-ENTRY GUIDE 1.995 3.2 0.74 10582.39 10583.13 1 JOINT 2-3/8" 4.6#, L-80, SC BLrI~RESS TUBING 1.995 2.7 32.08 10550.31 10582.39 1 OTIS "X" LANDING NIPPLE 1.875 2.91 1.32 10548.99 10550.31 1 JOINT 2-3/8" 4.6#, L-80, SC BUTTRESS TUBING 1.995 2.7 31.85 10517.14 10548.99 1 OTIS 3.22" SEAL ASSY. w/ST. SLOT LOCATOR 4.02" x 1.995" 9.98 10507.16 10517.14 1 JOINT 2-3/8" 4.6#, L-80, SC BIJI~RESS TUBING 1.995 2.7 31.71 10475.45 10507.16 1 OTIS "XA" SSD/SLEEVE 1.875 3.25 3.78 10471.67 10475.45 1 2-3/8" 4.6#, L-80, SC BLYITRESS PUP Tr. 1.995 2.7 5.12 10466.55 10471.67 21 OTIS BLAST JOINTS * 1.916 3.09 413.2 10053.35 10466.55 4 JOINTS 2-3/8" 4.6#, L-80, SC BUI~RESS TUBING 1.995 2.7 126.37 9926.98 10053.35 1 OTIS "RDH" 7" PACKER 7.84 9919.14 9926.98 1 2-3/8" 4.6#, L-80, SC BLYITRESS PUP Tr. 1.995 2.7 4.12 9915.02 9919.14 1 JOINT 2-3/8" 4.6#, L-80, SC BUYrRESS TUBING 1.995 2.7 31.9 9883.12 9915.02 1 OTIS "XA" SSD / SLEEVE 1.875 3.25 3.78 987934 9883.12. 1 JOINT 2-3/8" 4.6#, L-80, SC BUTTRESS TUBING 1.995 2.7 29.6 9849.74 987934 1 DANIEL - D - SO GLM ** 1.9 7.25 9842A9 9849.74 13 JOINTS 2-3/8" 4.6#, L-80, SC Bu'YrRESS TUBING 1.995 2.7 408.86 9433.63 9842.49 1 DANIEL - D - SO GLM ** 1.9 7.25 942638 9433.63 12 JOINTS 2-3/8" 4.6#, L-80, SC BUITRESS TUBING 1.995 2.7 381.76 9044.62 942638 ,, 1 DANIEL- D - SO GLM ** 1.9 7.2 9037A2 9044.62 13 JOINTS 2-3/8" 4.6#, L-80, SC BUT'tRESS TUBING 1.995 2.7 418.25 8619.17 9037.42 ,, 1 DANIEL- D - SO GLM ** 1.9 7.27 8611.9 8619.17 13 JOINTS 2-3/8"4.6#, L-80, SC BUTrRESSTUBING 1.995 2.7 415.36 8196.54 8611.9 ., 1 DANIEL - D - SO GLM ** 1.9 7.17 818937 8196.54 5 JOINTS 2-3/8" 4.6#, L-80, SC BUITRESS TUBING 1.995 2.7 157.45 8031.92 818937 1 CROSS OVER SUB; 2-3/8" BUTTRESS x 2-7/8" BLrI'TRESS 1.995 3.5 0.73 8031.19 8031.92 8 JOINTS 2-7/8" 6.4#, L-80, SC BUTTRESS TUBING 2.441 3.22 248.63 7782.56 8(131.19 1 DANIEL- D - SO GLM ** 1.9 7.17 777539 7782.56 .. 16 JOINTS 2-7/8" 6.4#, L-80, SC BU'I~RESS TUBING 2.441 3.22 483.12 7292.27 777539 1 DANIEL- D - SO GLM ** 1.9 7.15 7285.12 7292.27 18 JOINTS 2-7/8" 6.4#, L-80, SC BUTTRESS TUBING 2.441 3.22 546.1 6739.02 7285.12 1 DANIEL- D - SO GLM ** 1.9 7.15 6731,87 6739.02 ., 22 JOINTS 2-7/8" 6.4#, L-80, SC BUTTRESS TUBING 2.441 3.22 663.07 6068.8 6731.87 ,,, 1 DANIEL- D - SO GLM ** 1.9 7.15 6061.65 6068.8 ,,, 24 JOINTS 2-7/8" 6.4#, L-80, SC BI./rrRESS TUBING 2.441 3.22 726.28 533537 6061.65 1 DANIEL- D - SO GLM ** 1.9 7.13 5328.24 533537 37 JOINTS 2-7/8" 6.4#, L-80, SC BUI~RESS TUBING 2.441 3.22 1123.64 4204.6 532824 1 DANIEL- D - SO GLM ** 1.9 7.15 4197A5 4204.6 ,,, 48 JOINTS 2-7/8" 6.4#, L-80, SC BUTTRESS TUBING 2.441 3.22 1453.46 2743.99 4197.45 1 DANIEL- D - SO GLM ** 1.9 7.14 2736.85 2743.99 80 JOINTS 2-7/8" 6.4#, L-80, SC BLrrrRESSTUBING ~ ~ ~ ][~ ! ~/ ~ !).441 3.22 242135 315.5 2736.85 1 OTIS "FM" SCSSV, TUBING RETRIEVABLE 2.313 4.76 5.65 309.85 315.5 8 JOINTS 2-7/8"6.4#,L-80, SC BUTTRESS TUBING ~C"t~ - ~ ~ 2.441 3.22 241.28 68.57 309.85 .. ? 2-7/8", 6.4#,. L-80 SC BUTrRESS PUP JOINTS ] 2.44~1, J 3.22 24.71 43.86 68.57 Anchoage UNOCAL TUBULAR DETAIL WELL #: 0-1 RD GRAYLINO PLATFORM PAGE2 of 2 DATE: MARCH 2~, 1992 AFE NO.: 311426 STRING: LONG STRING; 2--3/8" 4.6~ N--80 SC BIll.HESS TLIBINO FOREMAN: ,, I CROSS OVER SUB; 2-7/8" BUq'TRESS x 3-1/2" BUI~FRESS 2.441 3.53 0.35 43.51 43.86 I CIW 11" SPLIT HANGER; 3-1/2" BLrFTRESS x 3-1/2" EUE 0.83 42.68 43.51 LANDED BELOW RKB 42.68 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0~ 0 0 0 ., 0 0 0 , 0 ,, 0 0 0 .,, NOTE: * OTIS BLAST JT. DIDN"r MU FLUSH, 3/16" GAP 0 '* GLMS ARE 2.9" · 4.25" ECCENTRIC BODY, f/2-3/8' & 4" · 4.75' 0 ECCENTRIC BODY f/ 2-7/8" 0 0 0 0 0 UNOCAL TUBULAR DETAIL WELL ~; O-I RD GRAYLING PLATFORM PAGE 1 o£ 1 DATE: MARCH 25, 1~2 AFE NO.: 311426 STRING: SHORT STRING; 2--3/8'* & 2-7,/8' L-80, SC BIJTTRESS TUBING FOREMAN: 1 OTIS RE-ENTRY GUIDE 1.995 3.2 0.89 99442,5 9945.14 1 OTIS COLLET CATCHER SUB 1.92 3.1 1.67 994258 994425 1 OTIS "XN" LANDING NIPPLE 1.791 2.9 1.38 99412 994258 1 2-3/8" 4.6#, L-80, SC BUTrRESS PUP JOINT 1.995 2.7 10 99312 99412 1 OTIS "RDH" T' PACKER 8.75 9922.45 99312 I JOINT 2-3/8" 4.6#, L-80, SC BIJFI'RESS TUBING 1.995 2.7 31.81 9890.64 9922.45 1 OTIS "XA" SSD / SLEEVE 1.875 3.25 3.78 9886~6 9890/~4 2 JOINTS 2-3/8" 4.6#, L-80, SC BUTTRESS TUBING 1.995 2.7 63.02 9gl3~4 9886~6 ., 1 2-3/8" DANIEL-D-SO GLM 1.9 4.25 7.3 981654 9823~g4 14 JOINTS 2-3/8" 4.6#, L-80, SC BUTrRESS TUBING 1.995 2.7 442.65 9373~9 981654 I 2-3/8" DANIEL-D-SO GLM 1.9 7.3 936659 9373~9 14 JOINTS 2-3/8" 4.6#, L-80, SC BUI~RESS TUBING 1.995 2.7 452.63 8913.96 9366.59 I 2-3/8" DANIEL-D-SO GLM 1.9 7.31 8906.65 8913.96 ,. 15 JOINTS2-3/8" 4.6#, L-80, SC BUTTRESS TUBING 1.995 2.7 479.12 842753 8906~5 I 2-3/8" DANIEL-D-SO GLM 1.9 7.35 8420.18 8427.53 12 JOINTS 2-3/8" 4.6#, L-80, SC BUTTRESS TUBING 1.995 2.7 388.15 8032.03 8420.18 I CROSS OVER SUB; 2-3/8" BUTTRESS x 2-7/8" BUTTRESS 1.995 3.53 0.7 8031 33 8(I52.03 4 JOINTS 2-7/8" 6.4#, L-80, SC BUTrRESSTUBING 2.441 3.22 118.75 7912.58 8(13133 1 2-7/8" DANIEL-D-SO GLM; 3.6" x 4" x 4.75" x 2.347" 7.13 7905.45 7912.58 24 JOINTS 2-7/8" 6.4#, L-80, SC BurrRESS TUBING 2.441 3.22 740.99 7164.46 7905.45 I 2-7/8" DANIEL-D-SO GLM; 3.6" x 4" x 4.75" x 2.347" 7.15 715731 7164.46 30 JO1NTS 2-7/8" 6.4#, L-80, SC BUTrRESS TUBING 2.441 3.22 896.22 6259.09 715731 1 2-7/8" DANIEL-D-SO GLM; 3.6" x 4" x 4.75" x 2.347" 7.15 6251.94 6259.09 35 JOINTS 2-7/8" 6.4#, L-80, SC BUITRESS TUBING 2.441 3.22 1075.12 5176~2 6251.94 1 2-7/8" DANIEL-D-SO GLM; 3.6" x 4" x 4.75" x 2.347" 7.12 5169.7 5176~2 40 JOINTS 2-7/8" 6.4#, L-80, SC BLrITRESS TUBING 2.441 3.22 1214~8 3954~2 5169.7 1 2-7/8" DANIEL-D-SO GLM; 3.6" x 4" x 4.75" x 2.347" 7.13 3947.69 3954~'2 42 JOINTS 2-7/8" 6.4#, L-80, SC BurrRESS TUBING 2.441 3.22 127028 2677.41 3947.69 1 2-7/8" DANIEL-D-SO GLM; 3.6" x 4" x 4.75" x 2.347" 7.17 267024 2677.41 78 JOINTS 2-7/8" 6.4#, L-80, SC BUYrRESS TUBING 2.441 3.22 2365.76 304.48 267024 1 OTIS '~-~M" SCSSV 5.65 298.83 304.48 2-7/8" 6.4#, L-80, SC BUTI~ESS PUP JOINTS 2.441 3.22 20.28 278.55 298.83 7 JOINTS 2-7/8" 6.4#, L-80, SC BUTTRESS TUBING 2.441 3.22 210.24 68.31 278.55 2-7/8" 6.4#, L-80, SC BUTI~E$S PUP JOINTS 2.441 3.22 24.45 43.86 6831 , , 1 CROSS OVER SUB; 2-7/8" BUTTRESS x3-1/2" BUTTRESS 2.441 3.5 0.35 43.51 43.86, I CIW 11" SPLIT HANGER; 3-1/2" BUTTRESS 0.83 42.68 43.51 42.68 0 SHORT STRINO WAS RUNDUALw/LONG grRINO PZR~22'gS, ~919' LS MF_AS. ~t$I(3 £Jil /~, ~o c,, .... ~, ......... :...~ o ,,, ~n~h~r~,~,~ 0 0 WELL HISTORY TBUS G-1 REDRILL AFE 311426 1/07/92 1/08/92 8619 ' 8619 ' COMMENCE OPERATIONS ON WELL TBUS G-1 REDRILL AT 1200 HOURS. RIG UP TO PUMP DOWN THE TUBING. KILL WELL WITH FIW BY PUMPING DOWN THE 3-1/2" TUBING THROUGH THE OTIS "XA" SLEEVE AT 8546' TM TAKING RETURNS FROM THE CASING WING VALVE TO THE PRODUCTION WELL CLEAN TANK. MONITOR WELL-ON VACUUM. SET BACK PRESSURE VALVE. REMOVED THE PRODUCTION TREE AND INSTALLED AN 11" 5M x 13-5/8" 5M DSA AND 13-5/8" RISER AT 2400 HRS. NIPPLE UP 13-5/8" 5M RAM PREVENTERS AND 13- 5/8" 3M ANNULAR PREVENTER. MODIFIED THE FLOW NIPPLE. INSTALLED THE RAM BLOCKS: 3-1/2" PIPE ON TOP; BLIND SHEARS IN MIDDLE; 5" PIPE ON BOTTOM. TESTED BLOWOUT PREVENTION EQUIPMENT AS FOLLOWS: CHOKE MANIFOLD VALVES TO 300 PSI (LOW) AND 3000 PSI (HIGH); ANNULAR PREVENTER TO 300 PSI (LOW) AND 2100 PSI (HIGH); 3-1/2" PIPE RAMS TO 300 PSI (LOW) AND 3000 PSI (HIGH); CHOKE, KILL, FLOOR, AND IBOP VALVES TO 300 PSI (LOW) AND 3000 PSI (HIGH). PULLED BACKPRESSURE VALVE AND INSTALLED 3-1/2" LANDING JOINT. UNSEATED THE HANGER AND FILLED THE WELL WITH 129 BBLS OF FIW. PULLED THE SEALS OUT OF THE OTIS "BWH" PACKER AT 8570' TM WITH 100K OVERPULL. CIRCULATED BOTTOMS UP-HAD MODERATE GAS BUBBLING FROM THE FLUID CONTAINING 15-20 PPM H2S. CIRCULATE THE WELL THROUGH THE GAS BUSTER. CHECK FLUID LOSS-WELL TAKING 60 BPH. PULL OUT OF HOLE LAYING DOWN SINGLE 3-1/2" GASLIFT COMPLETION AT 2400 HOURS. R'ECEiYED TBUS G-1 REDRILL (AFE 311426) WELL HISTORY PAGE 2 OF 16 1/09/92 8619' FINISH PULLING OUT OF HOLE LAYING DOWN SINGLE 3-1/2" GASLIFT COMPLETION. CHANGED THE UPPER PIPE RAMS TO 5" BLOCKS AND TESTED SAME TO 300 PSI (LOW) AND 3000 PSI (HIGH). PICK UP AND TIGHTEN KELLY CONNECTIONS. PRESSURE TEST THE UPPER AND LOWER KELLY COCKS TO 300 PSI (LOW) AND 3000 PSI (HIGH). RIG UP HLS WIRELINE. RAN AN 8.125" OD GAUGE RING AND JUNK BASKET TO THE PACKER AT 8570'. GAUGE RING SET DOWN AT THE DV COLLAR AT 4900'. SEVERAL ATTEMPTS WERE REQUIRED TO WORK BY THE DV COLLAR. MADE UP A 9-5/8" EZSV ON A BAKER WIRELINE SETTING TOOL. RAN IN AND SET THE RETAINER AT 8560' WLM. WELL QUIT TAKING FLUID ONCE THE RETAINER WAS SET. RAN IN HOLE WITH HLS CBL/VDL/GR/CCL. LOGGING FROM 8560' WLM AT 2400 HOURS. 1/10/92 8562' RAN CBL/VDL/GR/CCL FROM 8560' TO 5300' ( GR FAILED TO OPERATE. RAN SCIENTIFIC DRILLING GYRO SURVEY ON HLS WIRELINE. MADE UP A HALLIBURTON EZSV STAB-IN ASSEMBLY ON 5" 19.5# DRILL PIPE AND RAN IN HOLE PICKING UP DRILL PIPE. TAGGED THE RETAINER AT 8562' DPM (8560' WLM). CIRCULATED BOTTOMS UP AND STABBED INTO THE RETAINER. RIGGED UP HALLIBURTON SURFACE CEMENTING LINES AND TESTED SAME TO 5800 PSI. ESTABLISHED AN INJECTION RATE OF 4.25 BPM AT 350 PSI INTO THE "G" ZONE PERFORATIONS FROM 10178' TO 10507' MD. PRESSURE BLED TO ZERO WITH THE PUMP OFF. PRESSURE TESTED THE 9-5/8" CASING TO 3000 PSI FOR 30 MINUTES AGAINST THE UPPER PIPE RAMS. SQUEEZED THE "G" ZONE PERFORATIONS FOR ABANDONMENT AS FOLLOWS: MIXED AND PUMPED 478 SXS "G" CEMENT WITH ADDITIVES MIXED TO 15.8 PPG; DISPLACED THE CEMENT WITH 122 BBL FIW AND PRESSURE INCREASED RAPIDLY TO 5800 PSI (152 BBL DISPLACEMENT TO THE RETAINER); UNSTABBED FROM THE RETAINERAND REVERSED OUT THE EXCESS CEMENT; CIP AT 2205 HOURS (382 CU FT THRU THE RETAINER). PREPARE TO CHANGE OVER TO MILLING MUD AT 2400 HOURS. R 'CEIVED TBUS G-1 REDRILL (AFE 311426) WELL HISTORY PAGE 3 OF 16 1/11/92 8562' 1/12/92 8560' 1/13/92 8560' 1/14/92 8560' PUMPED OILY FLUID FROM THE ACTIVE SYSTEM TO TBU ONSHORE FACILITY VIA PRODUCTION GROSS LINE. CLEANED THE ACTIVE SYSTEM AND TRIP TANK. SHIPPED PREHYDRATED GEL FROM THE RESERVE PIT TO BUILD MILLING MUD IN THE ACTIVE SYSTEM. CHANGED THE WELL OVER TO MUD THROUGH THE RETAINER STAB-IN ASSEMBLY AT 8550' DPM TAKING RETURNS TO PRODUCTION. PULLED OUT OF HOLE LAYING DOWN EXCESS DRILL PIPE. SET WEAR BUSHING. MADE UP BHA #1 ( TRISTATE SECTION MILL ) AND RAN IN TO 8450' DPM AT 2400 HOURS. DOWN 1/2 HOUR WORKING ON THE ROTARY TABLE BLOWER. CUT 9-5/8" 47# N-80 CASING AT 8450' DPM. MILLED WINDOW SECTION FROM 8450' TO 8506'. WORK ON ROTARY BLOWER FOR ONE HOUR. CONTINUED MILLING AT 8506' AND BLADES APPEAR TO BE MILLED OFF (NO SHOULDER AT STUB). LAST DEFINITE SHOULDER WAS AT 8495'. CIRCULATE BOTTOMS UP. TRIP FOR SECTION MILL #2 AT 2400 HOURS. COMPLETED PULLING OUT WITH SECTION MILL #1. BLADES WERE COMPLETELY MILLED OFF. RAN IN HOLE WITH SECTION MILL #2 TO 6600' DPM. SLIPPED AND CUT DRILLING LINE. CONTINUED IN HOLE TO 8450' DPM. ATTEMPT TO BREAK CIRCULATION - MILL PLUGGED. CLEARED OBSTRUCTION IN MILL, OPENED CUTTERS AND GAUGED SECTION FROM 8450' TO 8482' DPM. PULLED UP TO CHECK STUB AT 8450' DPM. PULLED CUTTER INTO CASING FOR CONNECTION - HAD SOME TROUBLE GETTING THE ARMS TO COLLAPSE. GAUGED THE SECTION FROM 8450' TO 8497' DPM. MILLED SECTION FROM 8497' TO 8530' DPM. CIRCULATED BOTTOMS UP TO REMOVE METAL CUTTINGS. TRIP FOR UNDERREAMER. FOUND BLADES GONE ON THE SECTION MILL. MADE UP AND RAN IN HOLE WITH 15" UNDERREAMER TO 8450' DPM. UNDERREAMED SECTION TO 15" FROM 8450' TO 8486' DPM. TOOL BEGAN RUNNING ROUGH AND THE PENETRATION RATE DROPPED. TRIPPED TO CHECK UNDERREAMER. UNDERREAMER ARMS SHOWED A WEAR PATTERN FROM RUNNING ON THE CASING STUB -DID NOT COMPLETELY MILL THE CASING. RAN IN WITH SECTION MILL #3 TO 8455' DPM. ATTEMPTED TO BREAK CIRCULATION - MILL PLUGGED. ATTEMPTED TO UNPLUG THE MILL - NO GOOD. PULLED OUT OF HOLE WET. RAN IN HOLE WITH MILL #4 AT 2400 HOURS. TBUS G-i REDRILL (AFE 3~L426) WELL HISTORY PAGE 4 OF L6 1/15/92 8560' FINISHED RUNNING IN WITH MILL #4 FILLING THE DRILL PIPE EVERY 5 STANDS. BROKE CIRCULATION AT 8430' DPM. OPENED THE BLADES AT 8450' AND GAUGED DOWN TO THE STUB AT 8485' DPM. BEGAN MILLING SECTION AT 8485' DPM (APPEAR TO BE RUNNING ON JUNK). MILLED FROM 8485' TO 8505' DPM. PUMPED A HI VIS SWEEP AROUND BEFORE MAKING A CONNECTION. MADE THE CONNECTION AND LOCATED THE STUB AT 8505' DPM BY STACKING OUT 10K OF WEIGHT ON THE MILL. BEGAN MILLING AGAIN, LOST ALL TORQUE, AND BEGAN SLIDING DOWNHOLE. CIRCULATED WELL CLEAN. PULLED INTO THE CASING AND PUMPED A DRY JOB. TRIPPED FOR MILL #5. RAN IN HOLE FILLING EVERY FIVE STANDS AT 2400 HOURS. 1/16/92 8560' FINISHED RUNNING IN HOLE WITH MILL #5 TO 8430' DPM. ATTEMPTED TO BREAK CIRCULATION - MILL PLUGGED. ATTEMPTED TO UNPLUG MILL NO GOOD. DROPPED THE BAR AND PRESSURED THE DRILL PIPE TO OPEN THE PUMP OUT SUB. CIRCULATED AROUND A HI VIS SWEEP. TRIPPED FOR MILL #6. RAN IN WITH A TRISTATE LOCKOMATIC WITH SECTION MILL CUTTERS TO 8430' DPM. FILLED THE DRILL PIPE EVERY FIVE STANDS. RABBITTED AND RATTLED THE BHA AND DRILL PIPE. BROKE CIRCULATION AND REAMED FROM 8488' TO 8498' DPM. MILLED SECTION IN THE 9-5/8" CASING FROM 8498' TO 8507' DPM. 1/17/92 8560' MILLED SECTION IN THE 9-5/8" CASING FROM 8507' TO 8530' PUMPING HI VIS SWEEPS EVERY ONE TO TWO HOURS AS NEEDED. CIRCULATED WELL CLEAN AND TRIPPED OUT WITH SECTION MILL. CUTTERS ON MILL WERE 95% WORN WITH A 9.875" OD CUTTER SWEEP REMAINING. MADE UP 15" OD UNDERREAMER ARMS ON THE LOCKOMATIC TOOL BODY AND RAN IN PLUGGED FILLING EVERY FIVE STANDS TO 8430'. REAMED FROM 8450' TO 8486'. UNDERREAMED SECTION TO 15" OD FROM 8486' TO 8500'. UNDERREAMER DEVELOPED HIGH TORQUE (STALLED TABLE SEVERAL TIMES) AND COULD NOT WORK BELOW 8500'. CIRCULATED WELL CLEAN AND TRIPPED TO CHECK TOOLS. 1/18/92 8560' RECEIVED SERVICED RIG AND CUT DRILLING LINE. PICKED UP SECTION MILL #7 AND RAN IN HOLE. BROKE CIRCULATION AT 8440' AND WASHED DOWN TO 8475'. REAMED FROM 8475' TO 8506' AND LOST 700 PSI OF PUMP PRESSURE. TRIPPED TO CHECK TOOLS. BOWEN JARS PARTED AT THE TOP OF THE MANDREL - LEFT 31' OF FISH IN THE HOLE. TOP OF FISH AT 8476'. TESTED BOPE TO 250 PSI (LOW) AND 3000 PSI (HIGH). TBUS G-1 REDRILL (AFE 311426) WELL HISTORY PAGE 5 OF 16 1/18/92 (cont) MADE UP AN 8.125" OD OVERSHOT DRESSED WITH A 6.25" BASKET GRAPPLE AND RAN IN HOLE. ENGAGED FISH AT 8476' - PUMP PRESSURE INCREASED 200 PSI AND PICKED UP 12K OF DRAG OVER UP WEIGHT. TRIPPED TO CHECK TOOLS - RECOVERED ENTIRE FISH. 1/19/92 8560' LAID DOWN FISH AND FISHING TOOLS. CUTTERS ON MILL WERE 50% WORN, SLIGHTLY ROLLED, AND APPEARED TO BE RUNNING ON JUNK. MADE UP SECTION MILL #8 AND RAN IN HOLE. BROKE CIRCULATION AT 8440' AND WORKED DOWN TO 8492'. REAMED FROM 8492' TO 8516'. ATTEMPTED TO WORK DEEPER - NO GOOD. CIRCULATED WELL CLEAN. TRIPPED FOR OPEN ENDED DRILL PIPE WITH A 3-1/2" TUBING TAIL. RAN IN AND BROKE CIRCULATION AT 8440'. RIGGED UP HALLIBURTON FOR LEAKOFF TEST. 1/20/92 8560' RAN LEAKOFF TEST WITH 68 PCF MUD. PUMPED AWAY AT 1/4 BPM WITH 2620 PSI (16.0 PPG EMW). PRESSURE BLED TO 2385 PSI AND STABILIZED AFTER 13 MINUTES. CLEANED OUT FILL WITH THE TUBING TAIL TO 8519'. CIRCULATED WELL CLEAN. LAID IN A KICK OFF FROM 8519' AS FOLLOWS: PUMPED 10 BBL FRESH WATER; 30 BBL 2% CAUSTIC/FIW; 10 BBL FRESH WATER; 38 BBLS (230 SXS) "G" CEMENT WITH ADDITIVES MIXED WITH FIW TO 17.5 PPG; 14.5 BBL FIW; DISPLACED WITH 126.5 BBL 68 PCF MUD AT 7 BPM. PULLED 8 STANDS OF DRILL PIPE AND REVERSE OUT AT 7785'. CLOSED THE UPPER PIPE RAMS AND BRAIDEN HEAD SQUEEZED 8.5 BBLS AT 2800 PSI. HELD 2600 PSI SQUEEZE PRESSURE FOR 3.5 HOURS. BLED BACK 6 BBLS - 2.5 BBLS CEMENT SQUEEZED AWAY. PULLED OUT LAYING DOWN EXCESS DRILL PIPE AND TUBING TAIL. RIG DOWN ONE HOUR TO WORK ON DC DRIVE. PICKED UP AN 8-1/2" STEERABLE MOTOR ASSEMBLY AND RAN IN HOLE. 1/21/92 8560' BROKE CIRCULATION AND WASHED FROM 7995' TO 8347'. SINGLED IN WITHOUT PUMP FROM 8347' TO 8409' LOOKING FOR CEMENT (CIRCULATED BETWEEN SINGLES). CIRCULATED BOTTOMS UP FROM 8405' - CONTAMINATED MUD. CONTINUED IN AND FOUND FIRM CEMENT AT 8460' (10' BELOW THE CASING "E IVY: E D ~ 8470'. TRIPPED FOR OEDP WITH A 3-1/2" TUBING STINGER. STUD BACK MOTOR ASSEMBLY. PICK UP ~.~,b.m~'~'~?~ ~ ~ ~o~ 15 JOINTS OF TUBING WITH A ~LE SHOE. ~ IN HOLE PICKING UP 32 JOINTS OF DRILL PIPE ku~-, CIRCUITED WELL CLX. RIGGED UP HALLIB~TON Auch0raQ~ TBUS G-1 REDRILL (AFE 311426) WELL HISTORY PAGE 6 OF 16 1/21/92 (cont) 1/22/92 8473' 1/23/92 8719' 1/24/92 8979' 1/25/92 9254' RrCEIVED SURFACE LINES AND TESTED SAME TO 3000 PSI. BROKE CIRCULATION AND LAID IN KICK OFF PLUG FROM 8470' AS FOLLOWS: PUMPED 10 BBL FRESH WATER; 30 BBL 2% CAUSTIC/FIW; 10 BBL FRESH WATER; 25 BBLS (151 SXS) "G" CEMENT WITH ADDITIVES MIXED WITH FIW TO 17.5 PPG; 14.5 BBL FIW; DISPLACED WITH 127 BBL 69 PCF MUD AT 7 BPM. PULLED UP AND REVERSED OUT AT 8098'. ESTIMATED 35 BBLS OF WATER RETURNS. PULLED OUT LAYING DOWN 41 JOINTS OF DRILL PIPE AND 15 JOINTS OF 3-1/2" TUBING. PICK UP STEERABLE MUD MOTOR DRILLING ASSY (BHA #1). RAN IN HOLE WITH A STEERABLE MUD MOTOR DRILLING ASSEMBLY WITH A 1 DEGREE BENT HOUSING. TAGGED CEMENT AT 8149' AND CLEANED OUT SOFT CEMENT TO 8404'. CIRCULATED AND WAITED ON CEMENT. CLEANED OUT CEMENT FROM 8404' TO 8454'. ORIENTED MUD MOTOR AND TIME DRILLED FROM OFF THE PLUG FROM 8454' TO 8473'. CONTINUED TIME DRILLING OFF THE PLUG FROM 8473' TO 8477'. DRILLED 8-1/2" HOLE WITH STEERABLE MOTOR ASSEMBLY FROM 8477' TO 8545'. CHANGE WELL OVER TO MILPARK "NEW DRILL" PHPA POLYMER SYSTEMAND PULLED TO THE SHOE. BUILT SURFACE VOLUME. RAN BACK TO BOTTOM AND ATTEMPTED TO ORIENT THE MUD MOTOR - HAD TELECO SURFACE EQUIPMENT PROBLEMS. CHANGED OUT PUMP PRESSURE TRANSDUCER AND CABLE. DRILLED 8-1/2" HOLE FROM 8545' TO 8719' WITH STEERABLE MOTOR ASSEMBLY. DRILLED 8-1/2" HOLE FROM 8719' TO 8763'. CIRCULATED BOTTOMS UP AND TRIPPED FOR A NEW BIT AND LOCKED UP ROTARY DRILLING ASSEMBLY. TIGHT HOLE AT 8690'. CHANGED OUT TELECO TOOL, MADE UP BHA #2, AND RAN IN HOLE TO 8755'. CLEANED OUT FILL TO 8763'. DRILLED 8- 1/2" HOLE TO 8979'. TRIP FOR BHA CHANGE. DRIFT ANGLE IS 2 DEG BELOW PROJECTED WELL COURSE. CONTINUED TO TRIP OUT FOR BHA CHANGE. PERFORM BOPE TEST - TEST RAM PREVENTERS AND FLOOR VALVES TO 300 PSI (LOW) AND 3000 PSI (HIGH); TEST ANNULAR PREVENTER TO 300 PSI (LOW) AND 2100 PSI (HIGH). MADE UP BHA #3 WITH RR BIT #2 AND RAN IN TO 8928'. REAMED FROM 8928' TO 8979'. DRILLED 8-1/2" HOLE FROM 8979' TO 9254'. TBUS G-1 REDRILL (AFE 311426) WELL HISTORY PAGE 7 OF 16 1/26/92 9584 ' 1/27/92 9760' 1/28/92 10069' 1/29/92 10258' DRILLED 8-1/2" HOLE FROM 9254' TO 9370'. CIRCULATED BOTTOMS UP AND MADE A SHORT TRIP TO THE CASING SHOE - TIGHT HOLE AT 9180' AND 9086'. TRIP IN OK. DRILLED 8-1/2" HOLE FROM 9370' TO 9584'. CIRCULATED BOTTOMS UP AND TRIPPED FOR A NEW BIT AND BHA. TIGHT SPOTS FROM 9450' TO 9398' AND AT 9170'. MADE UP BIT #3 ON BHA #4 AND RAN IN HOLE. REAMED FROM 9529' TO 9585'. DRILLED 8-1/2" HOLE FROM 9585' TO 9670'. WAUKESHA #1 HAD A MECHANICAL FAILURE (DOWN TO ONE PRIME MOVER). PULLED TO THE SHOE FOR REPAIRS. RIG DOWN 8.5 HOURS. RAN AND DRILLED FROM 9670' TO 9760'. ELECTRICAL SHORT IN THE DRILLER'S CONSOLE BURNED WIRING -COULD NOT GET OFF BOTTOM. RESTORED RIG POWER. RIG DOWN 1 HOUR FOR REPAIRS. DRILLED 8-1/2" HOLE FROM 9760' TO 9942'. CIRCULATED BOTTOMS UP. PULL OUT FOR A WIPER TRIP. HAD TIGHT HOLE FROM 9779' TO 9739' AND 9688' TO 9625'. FAST LINE CLAMP CAME LOOSE ON THE DRAWWORKS WILL RUNNING THE BLOCKS DOWN FOR THE NEXT STAND. HUNG OFF THE BLOCKS. RIGGED UP TO CIRCULATE THROUGH THE DRILL STRING WITH THE BIT AT 9625' WHILE MAKING REPAIRS. INSPECTED THE CLAMP. SLIPPED AND CUT DRILLING LINE. WORKED THROUGH THE TIGHT SPOT AT 9625' AND PULLED TO THE SHOE. HUNG OFF THE BLOCKS. CHANGED OUT THE FAST LINE CLAMP U-BOLTS AS AN ADDED SAFETY PRECAUTION. RAN IN TO 9912' AND SAFETY REAMED TO 9942'. DRILLED 8-1/2" HOLE TO 10069'. DRILLED 8-1/2" HOLE FROM 10069' TO 10222'. CIRCULATED BOTTOMS UP. DROPPED A SURVEY AND PUMPED A DRY JOB. TRIP FOR BIT. TIGHT HOLE FROM 9966' TO 9757'. UP TO 75K OVERPULL AND 20 TO 30K DRAG THRU OPEN HOLE TO THE SHOE. LAID DOWN 33 JOINTS OF "E" DRILL PIPE ON THE TRIP OUT. ALL STABILIZERS WERE THE SAME GAGE AS WHEN ORIGINALLY RUN IN THE HOLE. MADE UP BIT #4 ON THE SAME BHA, CHANGED OUT THE TELECO TOOL, AND RAN IN HOLE. BROKE CIRCULATION AT 4685'. PICKED UP 33 JOINTS OF "S" DRILL PIPE. MADE CHECK SURVEYS WITH THE NEW MWD TOOL AT 8848', 9064', AND 10208'. WORKED THROUGH TIGHT HOLE FROM 10071' TO 10132' AND REAMED THE LAST 50' TO BOTTOM. DRILLED 8-1/2" HOLE FROM 10222' TO 10258'. TBUS G-1 REDRILL (AFE 311426) WELL HISTORY PAGE 8 OF 16 1/30/92 10515' 1/31/92 10667' 2/01/92 10891' 2/02/92 11023' DRILLED 8-1/2" HOLE FROM 10258' TO 10448'. RUN A SURVEY AND CIRCULATED BOTTOMS UP. MADE A WIPER TRIP. PULLED INTO TIGHT HOLE AT 10285'. COULD NOT WORK PAST - PICKED UP KELLY AND CIRCULATED THROUGH THE TIGHT SPOT. REAMED FROM 10255' TO 10285'. CIRCULATED OUT SINGLES WITH SPOT REAMING FROM 10255' TO 10102'. SET BACK THE KELLY AND PULLED SLOWLY FROM 10102' TO 9354'. RAN IN HOLE AND WASHED FROM 10177' TO 10408'. REAMED THROUGH A BRIDGE AT 10408' TO BOTTOM. DRILLED 8-1/2" HOLE FROM 10448' TO 10515'. DRILLED 8-1/2" HOLE FROM 10515' TO 10531'. CIRCULATED BOTTOMS UP. MADE A WIPER TRIP FROM 10531' TO 9238' - SOME TIGHT HOLE. DRILLED FROM 10531' TO 10667'. CIRCULATED BOTTOMS UP AND PUMP A DRY JOB. TRIP FOR A NEW BIT AND BHA. TIGHT HOLE AT 10275' AND 10245'. LAID DOWN TWO NBLC'S AND PICKED UP A NBDC AND STOOD BACK IN THE DERRICK. TESTED BOPE AS FOLLOWS: TEST ANNULAR TO 2100 PSI; TEST RAM TYPE PREVENTERS, CHOKE MANIFOLD, AND FLOOR VALVES TO 250 PSI (LOW) AND 3000 PSI (HIGH). FINISHED TESTING BOPE. INSTALLED THE WEAR BUSHING. RAN IN WITH BIT #5 ON BHA #6. SAFETY REAM 60' TO BOTTOM. DRILLED 8-1/2" HOLE FROM 10667' TO 10805'. DRILLED AT 4 TO 8 FT/HR WITH HIGH TORQUE FROM 10765' TO 10800'. CIRCULATED BOTTOMS UP. MADE A WIPER TRIP TO 9929' - TIGHT HOLE AT 10671'. PRIME MOVER #1 (WAUKESHA) DOWN - DAMAGED CRANK SHAFT. DRILLED FROM 10800 TO 10891'. DRILLED 8-1/2" HOLE FROM 10891' TO 11023'. CIRCULATED BOTTOMS UP AND PUMPED A DRY JOB. TRIP FOR A NEW BIT AND BHA. WORKED THROUGH TIGHT HOLE AT 10763' AND HAD 75K DRAG FROM 10950' TO 10310'. CHANGED BHA AND TESTED MWD TOOL. BIT WAS 1/8" UNDERGAUGE, NEARBIT STABILIZER WAS UNDERCUT, NEXT TWO STRING STABILIZERS WERE 1/8" UNDERGAUGE. RAN IN HOLE WITH BIT #6 ON BHA #7. STUCK PIPE AT 9885' WHILE TRIPPING IN HOLE. JARRED UP AND DOWN. PICKED UP THE KELLY A CIRCULATED AT 150 GPM (NO RESTRICTION). REDUCED MUD WEIGHT TO 70 PCF. CONTINUED JARRING DOWN AT 2400 HOURS. TBUS G-1 REDRILL (AFE 311426) WELL HISTORY PAGE 9 OF 16 2/03/92 11023' 2/04/92 11023' 2/05/92 11023' CONTINUED JARRING DOWN ON STUCK PIPE. MIX UP 46 BBLS OF MINERAL OIL BASED SPOTTING FLUID TO 71 PCF. SPOTTED 10 BBLS ACROSS THE FISH LEAVING 36 BBLS IN THE DRILL PIPE. PILL IN PLACE AT 0350 HOURS. CONTINUED JARRING DOWN ON STUCK PIPE. MOVED SPOTTING PILL 1/2 BBL EVERY 30 MINUTES. RIGGED UP APRS ON HLS WIRELINE AND ATTEMPTED A BACKOFF AT 992'- NO GOOD. JARRED ON AND WORKED STUCK PIPE AT 9885'. RIGGED UP AND RAN FREEPOINT - STRING FREE AT 9744'. PARTIALLY FREE BETWEEN NONMAGNETIC COLLARS AT 9781' AT 2400 HOURS. ATTEMPTED A BACKOFF BETWEEN THE NONMAGNETIC DRILL COLLARS AT 9781'. MANUALLY BACKED OFF UP THE HOLE WHILE WORKING TORQUE DOWN TO THE BACKOFF POINT. SCREWED BACK IN AND TIGHTENED THE CONNECTION. MADE A SECOND ATTEMPT WITH THE SAME RESULTS. LOGGED THE BACKOFF AT THE BOTTOM OF THE JARS AT 9744'. PULL OUT AND RIG DOWN APRS/HLS. TRIP FOR FISHING TOOLS. FOUND JARS BACKED OFF IN THE BOTTOM SERVICE BREAK - LEFT 3.94' OF LOWER HOUSING WITH A BOX LOOKING UP. TOP OF FISH AT 9740'. BROKE OUT THE BULL PLUG ON THE GOOSE NECK OF THE SWIVEL - CLEANED, DRESSED AND REINSTALLED SAME. MADE UP A SCREW-IN SUB ON TRISTATE FISHING TOOLS AND RAN IN HOLE. SLIPPED AND CUT DRILLING LINE ON THE WAY IN HOLE. SCREWED INTO THE FISH AT 9740'. DOWN JARRED ON FISH - CAME FREE AFTER 12 HITS. PULLED OUT OF HOLE SLOWLY TO THE SHOE. CIRCULATED OUT THE SPOTTING FLUID - CAUGHT 150 BBLS IN THE RESERVE PIT. PUMPED A DRY JOB AND TRIPPED TO CHECK RECOVERY. FINISHED TRIPPING OUT OF HOLE WITH THE FISH. HAD 100% RECOVERY OF THE BHA. CHANGED OUT THE KELLY SPINNER. CHANGED THE BHA AND CHECKED THE BIT. RAN IN WITH BIT #6 ON BHA ~9 TO 8435'. CIRCULATED AND CONDITIONED MUD. CONTINUED IN HOLE AND SET DOWN AT 10062'. REAMED AND WASHED FROM 10012' TO 10166'. CONTINUED IN HOLE AND SET DOWN AT 10816'. REAMED FROM 10816' TO 10888'. EXTREMELY HIGH ROTARY TORQUE. STALLING OUT THE TABLE WITH VERY LITTLE PROGRESS. CIRCULATED AND CONDITIONED MUD. PUMP DRY JOB AND TRIP TO CHECK ASSEMBLY. TBUS G-1 REDRILL (AFE 311426) WELL HISTORY PAGE 10 OF 16 2/06/92 11023' 2/07/92 11084 ' 2/08/92 11168' 2/09/92 11358' 2/10/92 11506' FINISHED PULLING OUT OF HOLE. PULLED 25K OVER NORMAL DRAG AT 6149'. NO VISIBLE DAMAGE TO DRILL STRING OR BHA. RIGGED UP DIALOG AND MADE A FEELER RUN WITH 20' OF 1-5/8" SINKER BARS WITH CCL TO 8400'. RAN IN WITH 64 ARM CALIPER AND LOGGED FROM 8400' TO SURFACE. CHANGED OUT ROTARY TABLE. RAN IN HOLE WITH BIT #7 ON BHA #9 TO 8372'. FILLED THE PIPE AND LOAD TESTED THE ROTARY TABLE. RAN IN TO 10847' AND REAMED TO 10890' WITH 750 TO 800 AMP ROTARY TORQUE. FAST COUPLING BETWEEN ROTARY MOTOR AND TRANSMISSION ON ROTARY TABLE IS OVERHEATING. PULL TO SHOE FOR REPAIRS. FINISHED PULLING TO OUT OF HOLE TO THE CASING SHOE. ALIGN MOTOR AND TRANSMISSION SHAFTS ON THE ROTARY TABLE. SHIM ROTARY TABLE SKID. RAN IN AND REAMED FROM 10890' TO 11023'. TABLE CONTINUING TO STALL OUT WHILE REAMING WITH 'LITTLE OR NO WEIGHT ON BIT. DRILLED 8-1/2" HOLE FROM 11023' TO 11084'. CONTINUING TO HAVE PROBLEMS WITH EXCESSIVE TORQUE STALLING THE TABLE. TRIP TO SHOE TO WORK ON DC GENERATORS. FINISHED PULLING TO OUT OF HOLE TO THE CASING SHOE. CHANGED GENERATOR LEADS TO ASSIGN ROTARY TABLE TO PRIME MOVER #3. RAN IN AND REAMED FROM 11045' TO 11084'. DRILLED 8-1/2" HOLE FROM 11084' TO 11109'. TRIP FOR BIT. LAID DOWN 300' OF HWDP ON TRIP OUT. TESTED RAM TYPE PREVENTERS, CHOKE MANIFOLD, AND FLOOR VALVES TO 300 PSI (LOW) AND 3000 PSI (HIGH). TESTED ANNULAR PREVENTER TO 300 PSI (LOW) AND 2500 PSI (HIGH). MADE UP BIT #6RR ON BHA #9 AND RAN IN TO 11067'. SAFETY REAMED FROM 11067' TO 11109'. DRILLED FROM 11109' TO 11168'. DRILLED 8-1/2" HOLE FROM 11168' TO 11358'. CIRCULATED BOTTOMS UP AND TRIPPED FOR A NEW BIT. LAID DOWN TELECO TOOL AND NONMAGNETIC DRILL COLLARS. MADE UP BIT #8 ON BHA #10 AND RAN IN HOLE. FILLED PIPE AT 8405'. CONTINUED IN HOLE TO 11308'. REAMED TO 11358'. DRILLED 8-1/2" HOLE FROM 11358' TO 11500'. CIRCULATED AND CONDITIONED MUD FOR LOGS. MADE A SHORT TRIP TO THE 9-5/8" CASING SHOE. TIGHT HOLE FROM 11430' TO 11029'. LEDGES AT 10546' AND 9745'. TRIP IN WITH NO PROBLEMS AND CIRCULATED BOTTOMS UP. DROPPED TBUS G-1 REDRILL (AFE 311426) WELL HISTORY PAGE 11 OF 16 2/10/92 (cont) 2/11/92 11506' 2/12/92 11506' A SINGLE SHOT SURVEY. TRIPPED OUT SLM FOR WIRELINE LOGS. TIGHT HOLE FROM 11370' TO 11121'. SLM = +6 FT CORRECTION. CORRECTED TD IS 11506' TMD. LAID DOWN NONMAGNETIC LEAD COLLARS. RIGGED UP HALLIBURTON LOGGING SERVICES. FINISHED RIGGING UP WIRELINE. RAN IN HOLE WITH LOG RUN #1 (DIL/FWS2/GR). HAD a TOOL FAILURE AT 9000' WLM. TRIPPED TO CHECK TOOLS - SONIC FAILED. CHANGED OUT TOOLS AND RAN IN HOLE. TAGGED BOTTOM AT 11480' WLM. LOGGED THE INTERVAL FROM 11478' TO 8453'. TRIP FOR LOG RUN #2 (SDL/DSN/GR/CAL). LOGGED INTERVAL FROM 11479' TO 8453'. RIGGED DOWN LOGGERS. MADE UP BIT #8RR ON BHA #11 AND RAN IN HOLE TO 8131'. FILLED THE PIPE AND SLIPPED AND CUT THE DRILLING LINE. CONTINUED IN TO 11442' AND WASHED DOWN TO 11480'. UNABLE TO WASH DEEPER. CIRCULATED AND CONDITIONED MUD FOR RUNNING 7" LINER. CHANGED UPPER PIPE RAMS TO 7" RAM BLOCKS AND TESTED SAME TO 2100 PSI. RIGGED UP AND RAN 7" 29# P-110 BUTTRESS LINER FILLING EVERY JOINT. MADE UP A TIW MODEL "DTH-S" HYDRAULIC SET LINER HANGER WITH MODEL "S-6" LINER TOP PACKER. CIRCULATED ONE LINER VOLUME TO ENSURE THE THE LINER WAS CLEAN. RAN IN THE HOLE WITH THE LINER SLOWLY ON 5" DRILL PIPE (DRIFT ALL DP). FILLED THE PIPE EVERY FIVE STANDS TO 9600'. CONTINUED IN THE HOLE AND TAGGED BOTTOM AT 11479' MD. BROKE CIRCULATION AND BEGAN RECIPROCATING THE PIPE ( 50 FT STROKES ). RIGGED UP, TESTED SURFACE LINES TO 4500 PSI, AND CEMENTED THE 7" LINER AS FOLLOWS: 40 BBLS OF 10 PPG DUAL SPACER; 10 BBLS OF DRILL WATER; 20 BBLS OF 8.5 PPG SUPER FLUSH; 10 BBLS OF DRILL WATER; 205 BBLS (1000 SXS/llL0 CU FT) OF 15.8 PPG "G" CEMENT WITH LIQUID ADDITIVES; DROPPED DRILL PIPE PLUG; 10 BBLS OF DRILL WATER; AND 258 BBLS OF 71 PCF MUD TO BUMP THE WIPER PLUG. CEMENT IN PLACE AT 2230 HOURS. PRESSURED TO 3000 PSI TO SET THE LINER HANGER WITH THE SHOE AT 11479' MD AND THE PACKER TOP AT 8127' MD. THE LINER WAS STUCK ON BOTTOM AND COULD NOT BE RECIPROCATED AFTER RELEASING THE DRILL PIPE WIPER PLUG. ROTATED OUT OF THE HANGER AND SET THE LINER TOP PACKER. REVERSED OUT 30 BBLS OF CEMENT AND ALL SPACERS. TBUS G-1 REDRILL (AFE 311426) WELL HISTORY PAGE 12 OF 16 2/13/92 11506' 2/14/92 11506' 2/15/92 11506' PULLED TEN STANDS AND LAID DOWN THE CEMENTING HEAD. CONTINUED OUT OF THE HOLE AND LAID DOWN 75 JOINTS OF 5" "E" DRILL PIPE. RAN IN AND LAID DOWN HWDP. CHANGED PIPE RAMS - UPPER TO 5" RAM BLOCKS AND LOWER TO 3-1/2" RAM BLOCKS. TESTED RAMS AND INSTALLED WEAR BUSHING. LAID DOWN 8-1/2" STABILIZERS. MADE UP BIT #8RR AND A 9-5/8" CASING SCRAPER ON BHA #12 AND RAN IN TO THE LINER TOP AT 8127' DPM. TRIP FOR 6" BIT. MADE UP BIT #9 ON BHA #13 AND RAN IN HOLE PICKING UP 96 JOINTS OF 3-1/2" 13.30# "E" DRILL PIPE. CROSSED OVER TO 5" DRILL PIPE AND CONTINUED IN HOLE TO THE LINER TOP AT 8127' DPM. CLEANED OUT CEMENT STRINGERS FROM 8127' TO 8197'. RIG DOWN 0.5 HOURS - GROUND FAULT RELAY ON ROTARY TABLE ASSIGNMENT WAS TRIPPING OUT. CONTINUED IN AND TAGGED CEMENT AT 11279'. WASHED AND DRILLED CEMENT TO THE LANDING COLLAR AT 11388' DPM. DRILLED THE I2~NDING COLLAR AT 11388' DPM. DRILLED MEDIUM HARD CEMENT TO 11430' DPM (FLOAT COLLAR AT 11433' DPM). H2S ALARM - MASKED UP AND SHUT WELL IN. FALSE ALARM. CIRCULATED WELL CLEAN AND TRIPPED FOR CASED HOLE LOGS. RIGGED UP DIA-LOG. RAN MINIMUM ID CALIPER LOG FROM 8130' (LINER TOP) TO SURFACE. PICKED UP SDI GYRO. RAN GYRO SURVEY FROM 11430' TO 8130' AND TIED INTO GYRO RAN ON JANUARY 9, 1992. RIGGED DOWN DIALOG AND RIGGED UP HALLIBURTON LOGGING SERVICES. PRESSURE TESTED THE LUBRICATOR TO 1000 PSI. RAN IN HOLE WITH CBL/GR/CCL AND LOG SET DOWN AT 8370' WLM. COULD NOT WORK BELOW 8408' WLM. TRIPPED OUT AND PICKED UP A 100# SINKER BAR. REPLACED THE BOWSPRING CENTRALIZER WITH A ROLLER TYPE CENTRALIZER. RAN IN HOLE TO 11430' WLM. RAN CBL/GR/CCL FROM 11430' WLM ETD TO TOP OF LINER AT 8127' WLM. TRIPPED TO CHANGE TOOLS. RAN IN WITH PET/GR/CCL. LOGGED FROM 11430' WLM ETD TO THE LINER TOP AT 8127' WLM. TRIPPED OUT AND RIGGED DOWN WIRELINE. CEMENT BOND ON LINER WAS GOOD. MADE UP A 9-5/8" RTTS PACKER AND RAN IN HOLE TO 3075' DPM ALLOWING THE PIPE TO FILL. MADE UP A HOWCO MULTISERVICE VALVE AND CONTINUED IN THE HOLE WITH DRY PIPE. SET THE RTTS PACKER AT 8091' DPM. PRESSURED THE ANNULUS AGAINST THE UPPER PIPE RAMS TO 850 PSI AND OPENED THE TESTER VALVE. DRAWDOWN TESTED THE LINER LAP TO 1268 TBUS G-1 REDRILL (AFE 311426) WELL HISTORY PAGE 13 OF 16 2/15/92 (cont) 2/16/92 11506' 2/17/92 11506' RECEJVED PSI - OK. FILLED THE DRILL PIPE AND PRESSURE TESTED THE LINER LAP TO 3100 PSI - OK. TRIPPED OUT WITH THE TEST PACKER. CHANGED THE LOWER PIPE RAMS TO 5" BLOCKS AND THE UPPER PIPE RAMS TO 5" x 3-1/2" VARIABLE BORE. PERFORMED WEEKLY BOPE TEST TO UNOCAL SPECIFICATIONS. CLEANED ACTIVE SYSTEM. MADE UP BIT #10 ON BHA #15 AND RAN IN TO 11430' ETD. PUMPED THE FOLLOWING SPACERS WHILE RECIPROCATING PIPE: 50 BBLS CAUSTIC SODA/FIW; 20 BBLS HEC/FIW WITH 25# PER BBL COARSE FRAC SAND; AND 100 BBLS DIRT MAGNET/FIW. CIRCULATED SPACERS AROUND WITH FIW AT 8 BPM. REVERSE CIRCULATED WITH FIW UNTIL RETURNS WERE CLEAN. PUMPED A 20 BBL HEC SPACER AND DISPLACED THE WELL WITH FILTERED 3% KCL/FIW BRINE. CIRCULATED AND FILTERED BRINE. PULLED OUT AND LAID DOWN SCRAPERS. RIGGED UP HALLIBURTON LOGGING SERVICES AND TESTED THE LUBRICATOR TO 1000 PSI. RAN IN HOLE WITH A 15' 4-5/8" PERFORATING GUN. CONTINUED IN HOLE WITH 4-5/8" PERFORATING GUN. LOCATED THE GUN ON DEPTH AND PERFORATED HB-1 FROM 10628' TO 10643' DIL WITH 32 GRAM 6 HPF DEEP PENETRATING CHARGES. TRIP OUT WITH GUNS AND OPERATOR PULLED OUT OF THE ROPE SOCKET IN THE LUBRICATOR. GUN FELL TO BOTTOM. PICKED UP FRAC ASSEMBLY AND RAN IN HOLE. CIRCULATED ONE DRILL PIPE VOLUME AND SET THE PACKER WITH THE TAIL AT 10507' DPM. PRESSURE TESTED THE ANNULUS TO 2000 PSI. RIGGED UP DOWELL SURFACE FRAC LINES. HELD A PREFRAC SAFETY MEETING. PRESSURE TESTED SURFACE LINES TO 10000 PSI. CONDUCTED DATA FRAC: INJECTIVITY TEST - PUMPED 150 BBLS OF 3% KCL/FIW BRINE AT 15 BPM WITH 8300 PSI; STEP RATE TEST - 102 BBLS 3% KCL/FIW; CALLIBRATION TEST - 120 BBLS CROSS LINKED GEL AT 15 BPM WITH 7820 PSI FOLLOWED BY 164 BBLS 3% KCL/FIW. STANDBY 3 HOURS TO ANALYZE DATA FRAC INFORMATION. PUMPED ADSORPTION SCALE INHIBITOR TREATMENT AS FOLLOWS: 2000 GAL 5% L-47 SCALE INHIBITOR; 164 BBL OF 3% KCL/FIW AT 10 BPM WITH 6400 PSI. PUMPED FRAC STIMULATION AS FOLLOWS: 70 BBL CROSSLINKED GEL; 10 BBLS OF 4 PPA 16-20 RESIN COATED CARBOLITE; 20 BBLS OF 8 PPA 16-20 RESIN COATED CARBOLITE; 51 BBLS OF 12 PPA 16-20 RESIN COATED CARBOLITE; 142 BBLS OF WF-40 GEL; SCREENED OUT AT 2.5 BPM WITH 9370 PSI. TBUS G-1 REDRILL (AFE 311426) WELL HISTORY PAGE 14 OF 16 2/17/92 (cont) 2/18/92 11506' 2/19/92 11506' 2/20/92 11506' PLACED 14600# OF PROPPANT THROUGH THE PERFORATIONS. RIGGED UP AND REVERSED OUT THE EXCESS SLURRY IN THE DRILL PIPE. PULLED 5 STANDS AND BLEW DOWN ALL LINES. FINISHED PULLING OUT AND LAYING DOWN THE FRAC ASSEMBLY. UNLOADED THE BUNDLE CARRIER. RAN IN HOLE WITH BIT #10 ON BHA #13 TO 10703' DPM AND REVERSE CIRCULATED ONE DRILL PIPE VOLUME. CONTINUED IN HOLE AND TAGGED SAND AT 11243'. REVERSED OUT SAND TO THE TOP OF THE PERF GUN FISH AT 11409' DPM (LENGTH OF FISH = 19.81'). REVERSE CIRCULATED AND FILTERED BRINE. RIG DOWN ONE HOUR DUE TO PLATFORM AC POWER FAILURE. TRIP FOR TUBING CONVEYED PERFORATING ASSEMBLY. MADE UP AND STOOD BACK THE CONTROL HEAD AND LUBRICATOR. PICKED UP THE TUBING CONVEYED PERFORATING ASSEMBLY. RAN IN HOLE TO 11000' FILLING THE DRILL PIPE TO ACHIEVE 3400 PSI AT 9450' TVD. RIGGED UP HALLIBURTON LOGGING AND RAN A GR/CCL TO PLACE THE GUNS ON DEPTH. SET THE PACKER AT 10572' PLACING THE TOP SHOT AT 10628' DIL. SHOT A FLUID LEVEL TO CONFIRM THE UNDERBALANCE. INSTALLED AND TESTED SURFACE LINES TO 4000 PSI. PRESSURED UP ON THE ANNULUS TO 1800 PSI AND PERFORATED THE HEMLOCK AS FOLLOWS: 10628' - 10670' AND 10863' - 11000' WITH 4-5/8" VANN GUNS LOADED 6 HPF WITH 32 GRAM DEEP PENETRATING CHARGES. GUNS FIRED AT 1630 HOURS WITH A LIGHT BLOW. OPENED THE PACKER BYPASS AT 1635 HOURS AND REVERSED THE DRILL PIPE CLEAN. RELEASED THE PACKER AND CIRCULATED BOTTOMS UP. WELL WAS TAKING 7 BPH OF WATER. TRIP OUT WITH PERFORATING ASSEMBLY. LAID DOWN TCP GUN ASSEMBLY. ALL SHOTS FIRED. RAN IN WITH A BIT AND SCRAPER TO 11409' ETD. CIRCULATE WELL CLEAN. WELL TAKING 15 BPH OF BRINE FLUID. TRIP FOR PERMANENT PACKER. RAN IN WITH A 7" × 3-1/2" OTIS "BWH" PERMANENT PACKER TO 10500' AND BROKE CIRCULATION. DROPPED THE PACKER SETTING BALL. RIGGED UP AND TESTED SURFACE LINES TO 5000 PSI. SET THE PACKER AT 10500' DIL WITH 2000 PSI PRESSURE. TESTED THE BACK SIDE TO 1500 PSI. PULLED OUT AND LAID DOWN THE SETTING TOOL. MADE UP AN OTIS "JPN" ISOLATION PLUG AND RAN IN TO 3500'. SLIPPED AND CUT THE DRILLING LINE. CONTINUED IN THE HOLE WITH THE PLUG. TBUS G-1 REDRILL (AFE 311426) WELL HISTORY PAGE 15 OF 16 2/21/92 11506' 2/22/92 11506' 2/23/92 11506' SET THE "JPN" PLUG IN THE PERMANENT PACKER AT 10500' DIL. TESTED THE PLUG TO 1000 PSI. PULLED TO 10450' AND SPOTTED 4 SXS OF 20-30 MESH SAND ON TOP OF THE PLUG. CIRCULATED AND FILTERED FLUID TO 70 NTU'S. TRIP OUT FOR TCP GUNS. MADE UP VANN SYSTEMS/HRS "TCP" PERFORATING ASSEMBLY. RAN IN TO 10415' FILLING THE DRILL PIPE WITH 3% KCL/FIW TO ACHIEVE 2000 PSI AT 8950' TVD. RIGGED UP HLS ELECTRIC LINE AND RAN GR/CCL CORRELATION LOG TO PLACE GUNS ON DEPTH. SET PACKER AT 10076' WITH THE TOP SHOT AT 10140'. SHOT FLUID LEVEL TO CONFIRM THE UNDERBALANCE. INSTALLED AND TESTED SURFACE LINES TO 3000 PSI. PRESSURED THE ANNULUS TO 2100 PSI AND PERFORATED THE "G" ZONE AS FOLLOWS: 10,140' TO 10170'; 10225' TO 10257'; 10278' TO 10340'; AND 10395' TO 10415' WITH 32 GRAM 6 HPF DEEP PENETRATING CHARGES. GUNS FIRED AT 2142 HOURS. HAD A LIGHT BLOW INCREASING TO A MODERATE BLOW. REVERSED THE DRILL PIPE CLEAN. CIRCULATED BOTTOMS UP WHILE FILTERING FLUID. TRIPPED OUT AND LAID DOWN "TCP" PERFORATING ASSEMBLY. ALL SHOTS FIRED. MADE UP AND RAN IN WITH "JPN" PLUG RETRIEVING TOOL. TAGGED SAND AT 10482' AND REVERSED OUT TO THE PLUG AT 10500'. OBSERVED WELL - 3 BPH LOSSES. RECOVERED PLUG FROM THE PACKER. OBSERVE WELL - 45 BPH LOSSES. CIRCULATED BOTTOMS UP AND MONITORED LOSSES - 45 BPH LOSSES. TRIPPED OUT AND'LAID DOWN THE PLUG. MADE UP AN OTIS 4' LONG SEAL ASSEMBLY AND RAN IN HOLE. CONTINUED IN HOLE WITH THE SEAL ASSEMBLY AND STABBED INTO THE PACKER AT 10500'. MONITOR WELL - ANNULUS STANDING FULL / DRILL PIPE TAKING FLUID. MIXED AND SPOTTED A 50 BBL SIZED SALT PILL DOWN THE DRILL PIPE. STABBED INTO THE PACKER AND SQUEEZED AWAY 20 BBLS INTO THE HEMLOCK WITH A FINAL SQUEEZE PRESSURE OF 1000 PSI. UNSTABBED AND REVERSED OUT THE EXCESS SIZED SALT PILL. MONITORED WELL - HEMLOCK TAKING 3 BPH OF FLUID. PULLED OUT OF HOLE LAYING DOWN DRILL PIPE AND COLLARS. PULLED THE WEAR BUSHING AND SET THE TEST PLUG. CHANGED THE UPPER PIPE RAMS TO DUAL 2-3/8" BLOCKS. CHANGED THE LOWER PIPE RAMS TO DUAL 2-7/8" BLOCKS. TESTED THE DOOR SEALS TO 2100 PSI. RIGGED UP DUAL HANDLING EQUIPMENT. RUN DUAL GASLIFT COMPLETION. TBUS G-1 REDRILL (AFE 311426) WELL HISTORY PAGE 16 OF 16 2/24/92 11506' 2/25/92 11506' 2/26/92 11506' CONTINUED TO RUN TAPERED 2-7/8" x 2-3/8" DUAL GASLIFT COMPLETION. HAD TROUBLE WORKING THE DUAL PACKER INTO THE LINER TOP AT 8127'. CONTINUED TO RUN TAPERED 2-7/8" x 2-3/8" DUAL GASLIFT COMPLETION. MADE UP OTIS "FM" TUBING RETRIEVABLE SUBSURFACE SAFETY VALVES ON THE LONG AND SHORT STRINGS AND TESTED THE CONTROL LINES TO 5000 PSI. CONTINUED IN HOLE AND WORKED THE LONG STRING TAIL INTO THE PERMANENT PACKER AT 10500' DIL. TESTED THE SEALS TO 500 PSI AGAINST THE FORMATION. SPACED OUT THE TUBING STRINGS AND MADE UP THE DUAL SPLIT HANGERS. ATTACHED AND TESTED THE CONTROL LINES TO 5000 PSI. LANDED THE COMPLETION WITH THE STRAIGHT SLOT LOCATOR ONE FOOT ABOVE THE SEAL BORE OF THE PERMANENT PACKER. TESTED THE SEALS IN THE PERMANENT PACKER TO 500 PSI. DROPPED THE DUAL PACKER SETTING BALL IN THE SHORT STRING. SET THE 7" OTIS "RDH" PACKER WITH 1450 PSI. PRESSURED TO 2500 PSI AND ATTEMPTED TO SHEAR OUT THE SETTING BALL - PRESSURE RELIEF ON THE MUD PUMP SHEARED. ATTEMPTED TO SHEAR OUT WITH RIG PUMP WITH 3200 PSI - NO INDICATION OF SHEAR OUT. RIGGED UP HALLIBURTON AND PUMPED DOWN THE SHORT STRING AT 1.25 BPM WITH 4200 PSI - APPEARS TO BE PUMPING INTO THE FORMATION WITH NO RETURNS ON THE ANNULUS. DROPPED THE SETTING BALL ON THE LONG STRING TO SHEAR OUT THE GUIDE SHOE OF THE WL REENTRY GUIDE. PUMPED INTO THE FORMATION AT 1.2 BPM WITH 1800 PSI (NO INDICATION OF SHEAR OUT. MADE SEVERAL ATTEMPTS WITH THE SAME RESULTS. SET BACK PRESSURE VALVES. NIPPLE DOWN BOPE. NIPPLE UP CIW 11" x 3-1/2" DUAL 5M PRODUCTION TREE. INSTALLED THE PRODUCTION CHOKES AND THE SURFACE SAFETY VALVES. DEMOBILIZED EQUIPMENT FROM RIG #54 TO RIG #55. RELEASED RIG FROM TBUS G-1 REDRILL AT 2400 HOURS. Scienti{ic Drilling International. Inc. I~Sll gestuind Drive Anchorage, Alaska 99518 Finder Survey UNOCAL Corporation P.O. Box 190Z47 Anchorage, Alaska 99519-0Z47 Interpolated Survey, 1~ {oct intervals Site Name : GRAYLING WELL ~ G-I REDRILL Site Location : TRADING BAY UNIT (TBU) McARTHUR RIVER FIELD KENAI PENINSULA BOROUGH COOK INLET, ALASKA Job Number : 45FG0292006 Latitude : 60.838 Survey Date(s> : 14-FEB-92 Survey Engineer : RANDY PICARD Calculation Method : Radius o{ Curvature Survey Depth Zero : RKB Proposal Direction : ?8.3990 Grid Correction : 0.0 Depth Measured in : Feet Comments : * AZIMUTHS ARE REFERENCED TO'TRUE'NORTH , · ~: . * FINDER SURVEY FROM 8S7S' MD TO 11,~30' MD JAN - l 199~ A)aska OiJ & Gas Cons. ;Anchorage , SURVEY TIED INTO SDI SURVEY OF 10-JAN-gZ, 0' TO 8S50' Scienti{ic Drilling International, Inc. Job number : 45FG0ZBZ~X~6 & 48FB0192007 page 1 Date : 14-Feb-gZ Interpolated Survey, I~X~ foot intervals UNOCAL Corporation WELL: Graying 6-1Redrill, TBU, McRrthur River Field, Cook Inlet, Rlaskm Meas'rd Vert. Vert. Inc Rzimuth Coordinates D-leg Depth Depth Sect'n Deg Deg Latitude Depart'r 1.~.0 I~.~X~ 0.0 O. SZ 152.89 0.00N 0.00E 0.00 200.0 Z00.00 0.4 0.59 134.58 0.788 0.57E 0,.19 300.0 Z99.99 0.8 0.30 134.42 1.3ZS 1.1ZE 0.29 400.0 399.99 1.Z 0.37 131.20 1.728 1.55E 0.07 500.0 4BB.BB 1.4 0.13 150.24 Z.088 1.B3E 0.25 500.0 599.99 1.5 0.14 8B.82 Z.I?S 2.02E 0.14 700.0 899.99 1.7 0.03 10B.13 2.195 Z.l?E 0.11 800.0 ?BB.BB 1.7 0.12 173.80 Z.ZBS 2.25E 0.11 900.0 899.99 1.? 0.24 180.49 2.808 2.28E 0.12 1000.0 BBB.gB 1.B 0. Z3 109.08 2.B18 2.4BE 0.27 1100.0 10BB.BB 2.1 0.08 25.3B Z.BZS 2.70E 0.Z3 1Z00.0 I1BB.BB 2.3 0.25 i10. B2 2.738 Z.B3E 0.25 1300.0 1ZBB.BB Z.8 0.31 38.82 2.805 3.38E 0.34 1400.0 13BB.89 8.4 4.18 ?B.?I 0.558 8.80E 3.B8 1500.0 14BB.31 18.B ?.B8 71.84 2.18N 18.83E 3.87 1S00.0 15B?.?Z 34.5 12.31 B1.SB 8.23N 33.B4E 4.8G 1700.0 1894.89 5B.B 15.92 ?3.28 11.83N 8?.?ZE 4.13 1800.0 1790.20 BB.4 18.51 75.18 19.57N 88.1BE 2.85 1900.0 1884.35 1ZZ.O 20.84 78.88 Z?.?SN 11B.BSE 2.38 2000.0 1B78.84 160.0 23.83 77.12 38.38N 155.85E 3.00 2100.0 2087.0B 203.0 27.17 75.84 48.08N 1B?.?BE 3.34 2200.0 2154.54 251.5 30.82 77.83 58.?BN 245.08E 3.87 2300.0 223B.07 304.9 33.74 78.38 67.89N ZB?.ZBE 2.B5 2400.0 2322.47 380.1 33.25 78.52 ?B.94N 351.38E 0.50 2800.0 2408.15 414.8 33.14 78.39 8B.BBN 405.00E 0.13 2800.0 2490.10 489.1 3Z.88 78.31 100.88N 45B.Z2E 0.48 2?00.0 2874.47 5ZZ.B 32.28 ?B.32 lll.?4N 510.7BE 0.42 2800.0 2859.05 578.2 32.23 78.39 122.51N 583.05E 0.05 2900.0 2743.53 82B.? 32.45 78.?9 133.09N 815.48E 0.31 3000.0 2827.87 883.4 32.55 ?B.1B 143.35N 88B.Z2E 0.24 3100.0 2Bll.B2 737.8 33.07 7B.28 153.47N 721.45E 0.52 3200.0 2BB5.88 792.2 33.18 ?B,82 183.47N ?75.18E 0.21 3300.0 3079.17 847.2 33.82 ?9.8? 173.37N 8ZB.30E 0.46 3400.0 3182.32 BOZ.8 33.87 ?B.85 183.24N 883.B?E 0.27 3500.0 3245.14 BSB.8 34.31 79.84 193.12N 93B.14E 0.44 3800.0 33Z?.81 1015.3 34.57 B0.33 202.88N BB4.85E 0.38 3?00.0 34OB.B4 1072.0 34.80 80.51 Z12.31N 1050.82K 0.11 3800.0 3492.08 llZB.1 34.98 81.04 ZZ1.48N 1107.14E 0.49 3900.0 3573.94 1188.4 35.10 81.33 230. ZSN 1183.87E 0.21 4000.0 3858.00 1243.5 34.81 81.B3 Z3B.5?N 1ZZO. 41E 0.80 4100.0 373?.87 130~I~.8 35.47 82.19 248.50N 1Z??.ZSE 0.8? 4200.0 3B19.24 135B.? 35.G1 82.57 254.21N 1334.8BE 0.28 4300.0 3900.48 1418.9 35.78 83.04 ZB1.SZN 1392.?BE 0.32 4400.0 3981.83 1475.1 35.70 B3.B3 ZGB. 15N 1450. BIE 0.53 Scientific Drilling International, Inc. Job number : 45F60Z92006 & 45F60192002 page 2 Date : 14-Feb-92 Interpolated Survey, 100 ~oot intervals UNOCRL Corporation WELL: Graying 6-1Redrill, TBU, McRrthur River Field, Cook Inlet, Rlaska Maas'rd Vert. Vert. Inc Rzimuth Coordinates D-leg Depth Depth Sect'n Deg Deg Latitude Depart'r /100~ ~5~),0 4063.25 1532.5 34.87 84.90 273.77N 1508.30E 1.0~ 46(~.0 4145.33 1589.3 34.81 85.47 278.56N 1565.23E 0.33 47~.0 42Z8.43 1644.6 32.77 82.49 284.40N 1620.53E Z.63 48~.0 4312.01 1699.5 33.83 76.45 294.42N 1674.48E 3.48 49~0.0 4393.72 1757.1 36.57 76.24 308.03N 1730.49E Z.74 5~.0 4474.24 1816.3 36.17 75.91 322.30N 1788.04E 0.45 510~.0 4555.28 1874.9 35.56 76.37 336.34N 1844.92E 0.67 5Z00.0 4637.33 1932.0 34.17 76.39 349.80N 190~.48E 1.39 53~NZ).0 4720.13 1988.0 34.04 76.99 362.71N 1955.05E 0.36 54(~).0 480Z.64 2044.5 34.76 77.75 375.06N Z010.17E 0.84 5500.0 4884.88 2101.4 34.58 78.66 386.69N Z065.86E 0.55 56~Z).0 4967.03 2158.4 34.96 79.72 397.38N 21Z1.87E 0.71 5700.0 5049.Z8 2Z15.3 34.36 80.59 407.11N 2177.90E 0.78 58(~.0 5131.55 ZZ7Z.1 34.93 81.75 415.83N 2234.08E 0.87 5900.0 5213.35 2329.5 35.30 82.54 423.89N 2291.08E 0.59 6~NZ)0.0 5295.83 2385.9 33.55 77.70 433.39N 2346.74E 3.25 6100.0 5379.63 2440.5 32.60 75.37 446.10N 2399.81E 1.59 6200.0 5463.65 2494.7 33.08 75.69 459.65N 2452.31E 0.51 6300.0 5547.24 2549.5 33.50 75.81 473.16N 2505.S1E 0.43 8400.0 S630.50 2604.8 33.76 76.62 486.35N 2559.30E 0.52 6500.0 5713.70 2660.3 33.62 77.12 498.95N 2613.32E 0.31 6600.0 5798.74 2716.0 34.10 77.71 5ii.09N 2687.70E 0.58 6700.0 5879.62 2771.9 33.96 78.90 522.44N ZTZZ.SOE 0.68 6800.0 5962.52 2827.9 34.04 79.81 532.77N 2777.45E 0.52 6900.0 6045.14 2884.2 34.55 80.75 S4Z.Z8N 2832.99E 0.74 7~.0 6126.85 2941.7 35.84 81.40 551.22N 2889.93E 1.34 71~.0 6206.85 3~1.6 37.90 81.59 560.10N 2949.26E Z.OB 7200.0 6285.15 3063.8 39.02 81.38 589.30N 3010.77E 1.13 7300.0 6363.01 3126.4 38.72 81.71 578.53N 3072.85E 0.36 7400.0 6441.24 3188.6 38.34 82.(~) 587.38N 3134.51E 0.42 7500.0 6519.57 3250.6 38.53 81.59 596.23N 3196.04E 0.32 7600.0 66(~.15 3309.8 34.05 74.84 608.31N 3253.93E G.(~) 77(~9.0 8683.22 3365.4 33.62 74.87 622.85N 3307.67E 0.43 7800.0 6766.93 3419.9 32.70 74.81 637.18N 3360.47E 0.9Z 7900.0 6851.31 3473.5 3Z.ZZ 75.27 651.01N 3412.32E 0.54 800~.0 6936.34 35Z6.1 31.Z8 76.02 664.06N 3463.30E 1.82 8100.0 702~.98 3575.9 28.61 73.36 677.24N 3511.43E Z.98 8200.0 7110.40 3624.0 29.51 68.35 693.16N 3557.31E Z.59 8300.0 7196.25 3674.4 3Z.16 67.39 712.47N 3604.78E Z.70 84(Z~.0 7279.82 37Z8.3 34.45 67.35 733.60N 3655.46E Z.29 85~.0 7362.02 3784.2 34.98 67.13 755.63N 3707.97E 0.54 86(~Z).0 7444.93 3839.5 33.00 73.11 774.63N 3760.525 3.88 8700.0 75Z9.07 3893.4 32.43 78.1Z 788.05N 381Z.86E Z.77 88(Z~).0 7614.22 3945.9 30.81 78.99 798.45N 3864.Z4E 1.68 Scienti{ic Drilling International, Inc. Job number : 45FGOZSZ006 & 4SFC~lgZO~Z page 3 Da're : 14-Feb-92 Interpolated'Survey, 1(~ ~oo~ interval5 UNOCAL Corporation WELL: Graying G-1Redrill, TBU, Mcfirthur River Field, Cook Inlet, Mee~'rd Ver~. Ver~. Inc Rzimu~h Coordinates D-leg Depth Depth Sec~'n Deg Deg Latitude Depar~'r 89~;;~).0 7700.59 3996.3 29.72 78.47 808.30N 3913.G76 1.12 9~.0 7787.85 4045.4 29.21 77.43 818,57N 3981.776 0.72 9100.0 7874.83 4094.8 29.92 77.89 8ZB.ZON 4009.956 0.72 9Z00.0 7961.18 4144.9 30.26 77.80 839.84N 4058.956 0.34 9300.0 8047.32 4195.7 30.74 77.98 850.49N 4108.576 0.49 9400,0 8132.88 4247,4 31.61 78,02 861,25N 4159.216 0.8? 9500,0 8217.62 4300.5 32,51 78.16 872.21N 4211.146 0,90 9600.0 8301.61 4354.8 33.25 78,39 883.24N 4264.306 0.?5 9700,0 8385.6? 4409.0 32.34 79,21 893,76N 4317.436 1.01 9800,0 8470.35 4462.2 31.93 ?8,53 904.03N 4369.626 0,55 9900,0 8555.52 4514,5 31,27 78,45 914,48N 4420.966 0,66 10000,0 8641.16 4566.2 30,89 78,18 924.94N 4471,526 0.40 10100.0 8727.47 4616.? 29.78 77,55 935.56N 4520.896 1.15 10200.0 8814,32 4666.2 29.65 ??,4? 946.28N 4669.296 0.14 10300.0 8901,48 4715.2 29.05 ??,44 956.92N 4617.136 0,60 10400,0 8989.00 4763.6 28.82 77.76 967.31N 4664.396 0.28 10500,0 9076,68 4811.? 28.67 77.95 977.43N 4711.406 0.18 10600,0 9164,64 4859.3 28.13 77,93 987.37N 4757.916 0,54 10700,0 9252,?7 4906.5 28.27 77,84 997,28N 4804,126 0,15 10800.0 9340.42 4954.7 29.30 77.88 1007.41N 4851.196 1.03 10900,0 9427.18 5004,4 30.32 78,13 1017,74N 4899.826 1,03 11000,0 9512.98 5055.8 31.50 ?8,59 1028,11N 4950,136 1.20 11100.0 9598.29 5107.9 31.40 79,23 1038.14N 5001.336 0.35 11200.0 9683.85 5159.? 30.95 79,69 1047,61N 5052.226 0.51 11300,0 9769.79 5210.8 30.54 79.48 1056.85N 5102.506 0.42 11400,0 9856,3? 5260.8 29.52 80.41 1065.59N 5151.786 1.12 11430,0 9882,E3 5275.5 29.05 80.45 1068,03N 5166,256 1.57 Depth Horiz. Displ. Direction 11430.0 527S.490 78.320 Scientific Drilling Inte_.~ational, 13511 Westwind Dr. Anchorage, Alaska 99516 907/ 349-7686 Inc. UNOCAL CORP G-1, TBU, McARTHUR RIVER FLD, GRAYLING PLATFORM 9 JAN92 UNOCAL Grayling G-1 Redrill Surveyed 14 Feb 92 COOK INLET, MD Incl Azimuth 0E 0.0 0.0 0.00 7E 100.0 0.5 152.89 2E 200.0 0.6 134.58 7E 300.0 0.3 134.42 7E 400.0 0.4 131.20 3E 500.0 0.1 150.24 9E 600.0 0.1 88.62 4E 700.0 0.0 108.13 1E 800.0 0.1 173.60 · 5E 900.0 0.2 180.49 4E 1000.0 0.2 109.08 5E 1100.0 0.1 25.38 6E 1200.0 0.2 110.92 5E 1300.0 0.3 36.52 5E 1400.0 4.2 78.71 7E 1425.0 5.5 71.15 7E 1450.0 6.3 69.19 0E 1475.0 7.1 69.61 6E 1500.0 8.0 71.64 2E 1525.0 8.9 75.17 0E 1550.0 9.9 78.73 5E 1575.0 11.1 81.72 3E 1600.0 12.3 81.58 0E 1625.0 13.1 80.20 6E 1650.0 14.2 77.10 2E 1675.0 15.2 75.34 8E 1700.0 15.9 74.28 9E 1725.0 16.8 74.54 8E 1750.0 17.4 74.49 1E 1775.0 17.9 74.93 9E 1800.0 18.5 75.18 0E 1825.0 19.0 75.69 5E 1850.0 19.6 76.20 3E 1875.0 20.1 76.42 1E 1900.0 20.8 76.66 1E 1925.0 21.7 77.21 3E 1950.0 22.3 77.03 3E 1975.0 23.1 77.07 4E 2000.0 23.8 77.12 5E 2025.0 24.7 77.12 5E 2050.0 25.5 76.93 5E 2075.0 26.4 76.68 4E 2100.0 27.2 76.84 ALASKA RECEIVED Alaska 0ii & Gas Oons. Oomtni$$ion Anchorage 4E 4E 5E 6E 8E 1E 4E 7E OE 3E 6E 9E 1E 3E 5E 7E 9E 1E 2E 3E 5E 6E 7E 8E 9E 0E 0E 1E 2E 3E 5E 6E 7E 8E 9E 1E 2E 4E 5E 6E 8E 9E 1E 3E 4E 5E 7E 9E 0E 2E 3E 5E 6E 8E 9E 1E 2E 4E 5E 7E 2125.0 2150.0 2175.0 2200.0 2225.0 2250.0 2275.0 2300.0 2325.0 2350.0 2375.0 2400.0 2425.0 2450.0 2475.0 2500.0 2525.0 2550.0 2575.0 2600.0 2625.0 2650.0 2675.0 2700.0 2725.0 2750.0 2775.0 2800.0 2825.0 2850.0 2875.0 2900.0 2925.0 2950.0 2975.0 3000.0 3025.0 3050.0 3075.0 3100.0 3125.0 3150.0 3175.0 3200.0 3225.0 3250.0 3275.0 3300.0 3325.0 3350.0 3375.0 3400.0 3425.0 3450.0 3475.0 3500.0 3525.0 3550.0 3575.0 3600.0 28.0 28.8 29.9 30.8 31.9 32.6 33.4 33.7 33.9 33.6 33.4 33.2 33.2 33.2 33.2 33.1 33.1 32.9 32.8 32.7 32.7 32.8 32.4 32.3 32.2 32.5 32.4 32.2 32.4 32.6 32.5 32.5 32.6 32.6 32.6 32.5 32.5 32.8 32.8 33.1 33.1 33.1 33.0 33.2 33.4 33.5 33.6 33.6 33.8 33.8 33.8 33.9 34.0 34.1 34.2 34.3 34.2 34.2 34.4 34.6 16.97 76.83 77.16 77.63 77.75 78.03 77.99 78.38 78.54 78.28 78.32 78.52 78.25 78.48 78.38 78.39 78.31 78.49 78.24 78.31 78.26 78.32 78.31 78.32 78.18 78.09 78.35 78.39 78.50 78.55 78.55 78.79 78.62 78.68 78.80 79.19 79.23 79.20 79.09 79.28 79.39 79.34 79.54 79.62 79.33 79.66 79.73 79.67 79.84 79.90 79.79 79.85 79.90 80.04 79.88 79.84 80.10 80.17 80.30 80.33 8E OE 1E 3E 5E 6E 8E OE 2E 4E 6E 8E 0E 1E 3E 6E 8E 0E 2E 4E 6E 8E OE 2E 4E 7E 9E 1E 4E 6E 9E 1E 4E 7E 0E 3E 6E 8E 1E 4E 7E 0E 3E 5E 5E 4E 3E 1E 9E 8E 6E 4E 2E 0E 8E 6E 3E 1E OE 362~.0 3650.0 3675.0 3700.0 3725.0 3750.0 3775.0 3800.0 3825.0 3850.0 3875.0 3900.0 3925.0 3950.0 3975.0 4000.0 4025.0 4050.0 4075.0 4100.0 4125.0 4150.0 4175.0 4200.0 4225.0 4250.0 4275.0 4300.0 4325.0 4350.0 4375.0 4400.0 4425.0 4450.0 4475.0 4500.0 4525.0 4550.0 4575.0 4600.0 4625.0 4650.0 4675.0 4700.0 4725.0 4750.0 4775.0 4800.0 4825.0 4850.0 4875.0 4900.0 4925.0 4950.0 4975.0 5000.0 5025.0 5050.0 5O75.O 5100.0 34.6 34.6 34.6 34.6 34.8 34.9 35.1 35.0 34.8 34.7 35.0 35.1 35.0 35.0 35.0 34.6 35.2 35.3 35.5 35.5 35.6 35.7 35.8 35.6 35.8 35.9 35.9 35.8 35.8 35.7 35.6 35.7 35.7 35.1 34.8 34.9 35.1 35.2 35.2 34.8 34.5 34.0 33.4 32.8 32.3 32.8 33.3 33.8 34.5 35.2 36.0 36.6 37.0 37.1 37.0 36.2 35.2 34.8 35.6 35.6 80.33 80.35 80.52 80.51 80.80 80.88 80.98 81.04 81.20 81.58 81.37 81.33 81.36 81.81 81.72 81.93 82.01 81.96 82.11 82.19 82.26 82.35 82.43 82.57 82.66 82.77 83.22 83.04 83.34 83.77 83.80 83.93 84.21 84.59 84.96 84.90 84.89 85.10 85.29 85.47 85.67 85.52 84.61 82.49 79.66 77.39 76.65 76.45 76.34 76.17 76.31 76.24 76.16 76.10 76.08 75.91 76.09 76.28 76.03 76.37 8E 6E 5E 4E 2E 1E 0E 9E 8E 7E 6E 5E 5E 4E 4E 3E 3E 3E 3E 3E 3E 4E 4E 4E 5E 5E 6E 7E 8E 9E 0E 1E 2E 2E 3E 2E 1E 0E 9E 7E 6E 5E 4E 3E 1E 0E 9E 8E 7E 6E 5E 4E 3E 2E 2E 1E OE 0E 9E 9E 512~.o 5150.0 5175.0 5200.0 5225.0 5250.0 5275.0 5300.0 5325.0 5350.0 5375.0 5400.0 5425.0 5450.0 5475.0 5500.0 5525.0 5550.0 5575.0 5600.0 5625.0 5650.0 5675.0 5700.0 5725.0 5750.0 5775.0 5800.0 5825.0 5850.0 5875.0 5900.0 5925.0 5950.0 5975.0 6000.0 6025.0 6050.0 6075.0 6100.0 6125.0 6150.0 6175.0 6200.0 6225.0 6250.0 6275.0 6300.0 6325.0 6350.0 6375.0 6400.0 6425.0 6450.0 6475.0 6500.0 6525.0 6550.0 6575.0 6600.0 35.3 34.6 34.4 34.2 34.4 35.0 34.9 34.0 33.9 34.6 35.0 34.8 34.7 35.0 34.9 34.6 34.6 34.5 34.5 35.0 34.4 34.5 34.5 34.4 34.7 35.1 35.0 34.9 35.0 35.3 35.2 35.3 36.1 36.4 35.7 33.5 32.5 32.3 32.4 32.6 32.8 33.0 33.0 33.1 33.2 33.3 33.3 33.5 33.7 33.8 33.6 33.8 34.1 34.1 33.7 33.6 33.7 34.0 34.2 34.1 /6.05 76.33 76.39 76.39 76.82 76.59 76.83 76.99 77.54 77.57 77.46 77.75 77.87 78.25 78.25 78.66 78.91 79.17 79.49 79.72 79.91 80.35 80.49 80.59 80.84 80.99 81.36 81.75 81.83 81.99 82.40 82.54 81.69 80.84 79.26 77.70 76.13 75.64 75.42 75.37 75.67 75.94 75.87 75.69 75.69 75.69 76.07 75.81 76.11 76.18 76.24 76.62 76.58 76.67 76.67 77.12 77.28 77.13 77.28 77.71 8E 8E 8E 8E 8E 8E 8E 8E 8E 9E 9E 0E 0E 1E 1E 2E 2E 3E 4E 5E 5E 6E 7E 8E 9E 9E 0E 1E 1E 2E 3E 4E 5E 6E 6E 7E 6E 6E 5E 3E 2E 1E OP.. 9E 8E 7E 6E 5E 4E 3E 2E 1E 0E 9E 8E 8E 7E 6E 5E 6625.0 6650.0 6675.0 6700.0 6725.0 6750.0 6775.0 6800.0 6825.0 6850.0 6875.0 6900.0 6925.0 6950.0 6975.0 7000.0 7025.0 7050.0 7075.0 7100.0 7125.0 7150.0 7175.0 7200.0 7225.0 7250.0 7275.0 7300.0 7325.0 7350.0 7375.0 7400.0 7425.0 7450.0 7475.0 7500.0 7525.0 755O.O 7575.0 7600.0 7625.0 7650.0 7675.0 7700.0 7725.0 7750.0 7775.0 7800.0 7825.0 785O.O 7875.0 7900.0 7925.0 7950.0 7975.0 8000.0 8025.0 8050.0 8075.0 8100.0 33.5 33.5 33.7 34.0 33.9 33.9 34.1 34.0 33.9 33.9 34.2 34.5 35.0 35.2 35.5 35.8 36.2 36.6 37.2 37.9 38.1 38.7 38.9 39.0 39.1 38.9 38.6 38.7 38.5 38.2 38.4 38.3 37.8 37.7 37.9 38.5 38.7 37.4 35.3 34.0 33.5 33.6 33.9 33.6 33.3 33.2 33.0 32.7 32.8 32.6 32.4 32.2 32.0 31.7 31.5 31.3 31.3 31.1 30.2 28.6 /8.31 78.43 78.76 78.90 79.24 79.59 79.93 79.81 80.05 80.34 80.41 80.75 80.86 80.95 81.36 81.40 81.42 81.47 81.80 81.59 81.72 81.25 81.28 81.38 81.44 81.61 81.49 81.71 81.80 82.28 82.22 82.00 82.23 82.95 82.64 81.59 79.33 77.29 75.80 74.84 74.80 74.70 74.79 74.87 74.75 74.78 74.77 74.81 74.95 75.02 75.06 75.27 75.22 75.55 75.68 76.02 76.17 76.15 75.04 73.36 4E 2E 1E 9E 6E 4E 2E 9E 7E 4E 2E 9E 7E 4E 2E 9E 6E 4E 8125.0 8150.0 8175.0 8200.0 8225.0 8250.0 8275.0 8300.0 8325.0 8350.0 8375.0 8400.0 8425.0 8450.0 8475.0 8500.0 8525.0 8550.0 28.2 28.2 28.7 29.5 30.2 31.1 31.7 32.2 32.6 33.2 33.9 34.5 34.6 34.8 34.8 35.0 34.8 34.4 71.56 70.06 69.34 68.35 68.30 68.08 67.55 67.39 67.38 67.21 67.10 67.35 67.15 67.21 67.13 67.13 67.16 67.12 MD 8550.00 8575.00 8600.00 8625.00 8650.00 8675.00 8700.00 8725.00 8750.00 8775.00 8800.00 8825.00 8850.00 8875.00 8900.00 8925.00 8950.00 8975.00 9000.00 9025.00 9050.00 9075.00 9100.00 9125.00 9150.00 9175.00 9200.00 9225.00 9250.00 9275.00 9300.00 9325.00 9350.00 9375.00 9400.00 9425.00 9450.00 9475.00 9500.00 9525.00 Incl 34.37 32.88 33.00 33.37 33.47 33.19 32.43 31.55 30.74 30.67 30.81 30.51 30.30 29.97 29.72 29.46 29.31 29.16 29.21 29.86 30.08 29.88 29.92 30.16 30.31 30.18 30.26 30.29 30.40 30.71 30.74 30.77 30.83 31.33 31.61 31.44 31.91 32.01 32.51 32.63 Az imuth 67.12 72.38 73.11 75.08 76.35 77.71 78.12 78.30 78.44 79.00 78.99 78.87 78.44 78.56 78.47 77.90 77.69 77.62 77.43 77.50 77.32 77.42 77.69 77.52 77.57 77.69 77.80 77.89 78.10 77.98 77.98 78.13 78.14 78.00 78.02 78.28 77.79 77.79 78.16 78.07 9550*00 "32.94 9575.00 33.18 9600.00 33.25 9625.00 33.48 9650.00 33.30 9675.00 32.62 9700.00 32.34 9725.00 33.01 9750.00 32.69 9775.00 32.10 9800.00 31.93 9825.00 32.00 9850.00 31.80 9875.00 31.51 9900.00 31.27 9925.00 31.15 9950.00 31.12 9975.00 31.11 10000.00 30.89 10025.00 30.51 10050.00 30.28 10075.00 30.04 10100.00 29.78 10125.00 29.67 10150.00 29.90 10175.00 29.91 10200.00 29.65 10225.00 29.51 10250.00 29.51 10275.00 29.26 10300.00 29.05 10325.00 29.26 10350.00 29.33 10375.00 28.87 10400.00 28.82 10425.00 28.97 10450.00 28.91 10475.00 28.98 10500.00 28.67 10525.00 28.57 10550.00 28.57 10575.00 28.44 10600.00 28.13 10625.00 28.16 10650.00 28.21 10675.00 28.18 10700.00 28.27 10725.00 28.50 10750.00 28.79 10775.00 29.01 10800. O0 29.30 10825.00 29.65 10850.00 29.83 10875.00 30.07 10900.00 30.32 10925.00 30.53 10950.00 30.88 10975.00 31.28 11000.00 31.50 11025.00 31.65 77.78 78.13 78.39 78.16 78.54 78.98 79.21 78.49 78.55 78.73 78.53 78.35 78.33 78.38 78.45 78.42 78.33 78.22 78.18 78.36 78.22 78.02 77.55 77.33 77.32 77.51 77.47 77.74 77.54 77.30 77.44 77.58 77.30 77.36 77.76 77.72 77.76 77.84 77.95 77.98 77.77 77.67 77.93 78.02 77.93 77.88 77.84 77.77 78.00 77.88 77.88 78.05 78.02 78.04 78.13 78.51 78.35 78.42 78.59 78.72 11050. O0 11075. O0 11100. O0 11125. O0 11150. O0 11175. O0 11200.00 11225.00 11250.00 11275.00 11300.00 11325. O0 11350.00 11375.00 11400.00 11425.00 11430.00 11479.00 31.41 31.40 31.40 31.16 31.19 31.11 30.95 30.90 30.69 30.56 30.54 30. O0 29.50 29.34 29.52 29.42 29.05 29.05 79.1~ 79.12 79.23 79.52 79.55 79.46 79.69 79.52 79.64 79.45 79.48 79.87 80.28 80.38 80.41 80.36 80.45 80.45 PE[IMI[ # ?/ - COMPLEI'ION DATE WELL NAME AO~CC .(]EOII_OGI(;A!_ MATEI~IAI_.S INVENTOFIY I._IST J chcck ott or list data as il is rcccivcd J cored ilitcrvals LOG I'YPE 9} 1 iJ ?_6T i z! I 4i i~} i si PlO. , oo5,~/_ //3~o" ' Z v~-9' -//u'~o°' . ~?'S'.9 / _//¢ 79 ,,/ R/".~'-- //V'. ?' ! . Z/o~ -//ff/-~ ALASKA OIL AND GAS CONSERVATION COMMISSION WALTER J. HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7,542 SEPTEMBER 24, 1992 GARY BUSH UNION OIL COMPANY OF CALIFORNIA P O BOX 190247 ANCHORAGE, ALASKA 995 19 RE:' 91-0139 TRADING BAY UNIT G-1RD COMPLETION REPORT 67-0047 TRADING BAY UNIT G-1 P&A PAPER WORK · 91-0099 TRADING BAY UNIT G-14ARD COMPLETION REPORT 68-0080 TRADING BAY UNIT G-14 P&A PAPER WORK 69-0055 TRADING BAY UNIT G-14A P&A PAPER WORK 72-0021 GRANITE PT STATE 32-13 P&A PAPER WORK DEAR MR. BUSH, OUR FILES INDICATE THAT UNION OIL COMPANY OF CALIFORNIA IS THE OPERATOR OF THE REFERENCED WELLS. WE HAVE NOT RECEIVED THE APPROPRIATE COMPLETION REPORTS FOR PLUGGING AND ABANDONMENT OR WELLS PRODUCING. AUGUST MONTHLY PRODUCTION REPORTS INDICATE THAT TWO WELLS ARE PRODUCERS FOR THIS YEAR. WE HAVE NO PAPER WORK (407 FORM) SHOWING THE COMPLETIONS FOR THESE WELLS OR PLUGGING AND ABANDONMENT OF THE ORIGINAL WELL (AS INDICATED). ACCORDING TO 20 AAC 25.010(C), "THE OPERATOR SHALL FILE WITH THE COMMISSION WITHIN 30 DAYS AFTER COMPLETION, ABANDONMENT, 'OR SUSPENSION OF THE WELL A WELL COMPLETION OR RECOMPLETION REPORT (FORM 407) AND ALL INFORMATION REQUIRED BY 20 AAC 25.070 AND 20 AAC 25.071." IT IS THE OPERATOR RESPONSIBILITY FOR COMPLIANCE WITH COMMISSION REGULATIONS. THIS PAPER AUDIT PROCESS IS GOING TO BE AN ON GOING PROCEDURE AS FACTS BECOME KNOWN, I HOPE YOU CAN CORRECT THESE SITUATION AS QUICK AS POSSIBLE. PLEASE LET ME KNOW IF THERE IS ANY PROBLEM WITH SUBMITTING THESE FORMS AS REQUIRED IN A TIMELY MANNER. SINCERELY, STEVE MCMAINS STATISTICAL TECHNICIAN Memorandum UNOCAL DOCUMENT TRANSMITTAL April 10, 1992 TO' John Boyle FROM: Kirk Kiloh LOCATION: 3000 PORCUPINE DRIVE ANCHORAGE, AK 99501 ALASKA OIL & GAS CONSERVATION COMM. , LOCATION: P.O.BOX 196247 ANCHORAGE AK 99519 UNOCAL TRANSMITTING AS FOLLOWS TRADING BAY UNIT G-1RD 2 boxes washed/dried cuts from 8490' - 11510' PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND THIS DOCUMENT TRANSMITTAL. THANK YOU RECIEVED BY: DATED'. RETURNING ONE COPY OF FORM 1-0C03 (REV. 8-85) PRINTED IN U.S.A, Unocal North Americar~''' Oil & Gas Division Unocal Corporation P.O. Box 190247 Anchorage, Alaska 99519-0247 Telephone (907) 276-7600 UNOCAL DOCUMENT TRANSMITTAL Alaska Region February 21, 1992 COURIER TO: John Boyle 3001 Porcupine Drive Anchorage AK 99501 ALASLA OIL & GAS CONSERVATION COMMISSION FROM: Kirk Kiloh P O Box 196247 Anchorage AK 99519-6247 LOCATION: Alaska Region Transmitting as Follows: __Tr_adingB?yUnjt, McArthur myer Field, G-1RD 1 sepia and 1 blueline as follows: /Mudlog ~ · /SDL/DSN 2"& 5" ~3DL 2'! & 5" ' DIL 2': & 5:' ~'~WS2 2"& .5" ~/CBL,,//. ~"PET ~/ '~Lis tape and listing ~/ ff'~/°~'~"-- C/Survey disk and listing PLEASE ACKNOWLEDGE RECEIPT OF THIS SIGNING AND RETURNING ONE COPY. THANK YOU. RECEIVED BY: ~~ ,~..~r DATED: DOCUMENT TRANSMITYAL BY RECEIVED FEB 2 1 1992 Alaska OH & Gas Cons. Commission Anchorage ALASKA OIL AND GAS CONSERVATION COMMISSION · December 10, 1991 WALTER J. HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 Gary S. Bush Regional Drilling Mgr UNOCAL Corp. P. O. Box 196247 Anchorage, AK 99519-0247 re: TBUS G-1RD UNOCAL Corp., Inc. Permit No. 91-139 Sur. Loc. 1886'FSL, 1386'FEL, Sec 29, T9N, R13W, SM Btmhole Loc. 3150'FSL, 3924'FWL, Sec. 28, T9N, R13W, SM Dear Mr. Bush: Enclosed is the approved application for permit to drill the above referenced well. The permit to drill does not exempt you from obtaining additional permits required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permitting determinations are made. The Commission will advise you of those BOPE tests that it wishes to witness. Sinc~erely, ~ ,,'"'- ~ Lonn[e C. {Smith, Co~issioner Alaska Oil and Gas Conservation Co~ission BY ORDER OF THE COMMISSION dlf/Enclosures cc: Department of Fish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. ~'---, STATE OF ALASKA ALASK, IL AND GAS CONSERVATION Cl. vllSSION PERMIT TO DRILL 20 AAC 25.005 la. Type ofwork Drill r-J Redrill ~ lib. Type ofwell. Exploratory J-'J Stratigraphic Test [] Development Oil J-"xJ Re-Entry j-'J Deepen r-JI Service J-J Development Gas [--J Single Zone J--J Multiple Zone J--J 2. Name of Operator 5. Datum elevation (DF or KB) 10. Field and Pool Union Oil Company of California (Unocal) 103' RT above MSL feet Mc,Nthur River Field 3. Address 6. Property Designation G" Zone/Hemlock P.O. Box 196247 Anchorage, AK 99519 ADL 18730 4. Location of well at surfaceLeg #2, Conductor #40 7. Unit or Property name 11. Type Bond (SEE 20 ACC 25,025~ 1886' FSL & 1386' FEL, Sec 29, T9N, R13W, S.M. Trading Bay Unit United Pac. Ins. Co. At top of productive interval @ 10607' MD (9158' TVD) 8. Well number Number 3013' FSL & 3050' FWL, Sec. 28, T9N, R13W, S.M. TBUS G-1RD U62-9269 At total depth TD @ 11716' TMD (10103' 'rVD) 9. Approximate spud date Amount 3150' FSL & 3924' FWL, Sec. 28, T9N, R13W, S.M. 01-02-92 $200,000 12. Distance to nearest 13. Distance to nearest well 14. Number of acres in property 1 $ Proposed depth (MD AND TV~ property line 5400 Acres (G-zone WIPA) 2130 feet N/A feet 17299 Acres (Hemlock WIPA) 11,71 6 feet 16. To be completed for deviated wells 17. Anticipated Pressure(s. 20 AAC 25.0.35 (e)(2)) Kickoff depth feet Maximum hole angle Maximum surface 758 ps~ At total depth (TVD) 4,~346 psig 18. Casing program Setting Depth size Specifications Top Bottom Quantity of cement Hole Casing Weight Grade Coupling Length MD TVD MD TVD (include stage data) 8-1/2" 7" 29# :~-110 Butt 3,565 8,150 7,053 11,715 10,103 19. To be completed for Redrill, Re-entry, and Deepen Operations Present well condition summary RECEIVED Total depth: measured 11,419' feet Plugs (measured) true vertical 9,767' feet NOV 2:7 1991 Effective depth: measured 11,125' feet Junk (measured) true vertical 9,$16' feet Alas.lc, a, .Oil & Gas Cons. L, umm~ssi0~ ,--, ~nch0rage Casing Length Size Cemented Measured depth True vertical depth Structural 327' 26# Driven 327' 327' Conductor Surface 2160' 13-3/8" 3100 sxs 2160' 2113' Intermediate Production 8994' 9-5/8" 2700 sxs 8994' 7746' Liner 2603' 7' .540 sxs 881 6'-11419' 7603'-9767' Perforation depth: measured true vertical See attached perforation record 20. Attachments Filing fee ~ Property Plat J-1 BOP SketchJ~ Diverter Sketch J-J Drilling Program Drilling fluid program ~ Time vs depth plot J'-J Refraction analysis E] Seabed report J-J 20 AAC 25.050 requirements E] 21. I hereby certify that the f~egoing is true and correct to the best of my knowledge Signed Gary S. Bush ~-~ , ~ Date ~-~--~-~ ,..,.~ Title Regional Drilling Manager ('~ .~ Commission Use Only Permit Number '~'--J JAPrn"umber .~ JApproval date,., ,.~. ~ J See cover letter ¢'/-/,.~ ? J50- ~3'~- ,2-- oo,3' ~-o I J /~ ) U"' ~/"/ Jforother requirements C~nditions of approval Samples required J-J Yes.,,~' No Mud log ~:e~uired J--J Ye's ~ No Hydrogen sulfide measures ~ Yes ~ No Directional survey,equlred ,.~ Yes ~ No Required working pressure for BOPE ~, [~ 2M;_J~ 3M; ~ 5M; F-] 10M; kJ 15M; Other: ..~7 ~- I L-~/~'--;~J~ by the order of _Appr.?ed by . ~//~,,~.,~k~. ',/,,~..~... ~....,~f,~ Commissioner the commission Date / Z '-/~--~' t Form 10-401 Rev. 12-1-85 ~' Submit in triplicate ALASKA OIL AND GAS CONSERVATION COMMISSION December 2, 1991 WALTER J. HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 ADMINISTRATIVE APPROVAL NO. 80.62 Re: The application of Union Oil Company of California, operator of the Trading Bay Unit (TBU), to drill and complete the TBU G-1 RD well. Mr. Gary S. Bush Regional Drilling Manager UNOCAL Corp. P. O. Box 190247 Anchorage, AK 99502-0247 Dear Mr. Bush: Your application of November 26, 1991 for a permit to drill the TBU G-1 RD was received November 27, 1991. Redrilling and completion of this well will provide additional oil recovery from the McArthur River Middle Kenai "G" Zone and Hemlock oil pools. The Alaska Oil and Gas Conservation Commission hereby authorizes the drilling of the G-1 RD well pursuant to Rule 5 of Conservation Order No. 80. Sin~~'SlfiNED BY .IISSELL A. DOUGLASS RuSsell A. Douglass Commissioner BY ORDER OF THE COMMISSION PERFOI~T'rON RECORD TBUS G-1 7/23/91 "G" ZONE 10,178'- 10,208' MD 10,340'- 10,375' MD 10,450'- 10,470' MD 10,495'- 10,507' MD 8735'- 8760' TVD 8874'- 8899' TVD 8961'- 8978' TVD 8999'- 9007' TVD OPEN-PROD OPEN-PROD OPEN-PROD OPEN-PROD HEMLOCK ZONE 10,898'- 11,100' MD 10,764'- 10,878' MD 10,703'- 10,750' MD 9333'- 9501' TVD ISOLATED-PROD 9224'- 9317' TVD ISOLATED-PROD 9173'- 9211' TVD ISOLATED-PROD NOTE: ALL HEMLOCK PERFORATIONS ARE ISOLATED FROM PRODUCING BY TRIPLE PACKER JUNK AT 8712' LEFT IN HOLE ON 7/6/91. LONG STRING STUB ON PACKER PRESSURE TESTED TO 3000 PSI ON 7/7/91 WITH NO LEAKOFF TO HEMLOCK ZONE TO CONFIRM ISOLATION. SQUEEZED PERFORATIONS 10,180'- 10,200' MD 10,340'- 10,360' MD 10,450'- 10,470' MD 11,360'- 11,395' MD 11,136'- 11,340' MD 8737'- 8754' TVD 8870'- 9747' TVD 8961'- 8978' TVD 9718'- 9747' TVD 9532'- 9701' TVD SQZD-WSO SQZD-WSO SQZD-WSO SQZD-PROD SQZD-PROD RECEIVED NOV 2 1(t91 Alaska OiJ a Gas Cons. Commission Anchorage TlUtDING BAY UNIT TBUS G-1 REDRILL PROCEDURE 1. Move Rig 54 over TBUS G-i, Leg 2, Conductor 40. 2. Kill well with 3% KCL completion fluid. 3. Install BPV'S, nipple down tree, nipple up BOPE. Test BOPE and choke manifold to 3000 psi per AOGCC regulations. 4. Pull and lay down single production string. 5. Run bit and scraper to 8570' (Top of perm packer). 6. Set cement retainer at 8560'. Squeeze to abandon existing wellbore. 7. Mill window in 9-5/8" casing from 8450' to 8550'. 8. Lay kickoff plug from 8560' to 8400' and braiden head squeeze the 9-5/8" shoe. 9. Kickoff and drill 10" of new formation. Perform leakoff test. Resqueeze shoe, if necessary. 10o Redrill 8-1/2" hole from 8450' to 11716'. 11. Run logs. 12. Run and cement liner. 13. Cleanout, test lap, run gyro, and run CBL. 14. Change over to completion fluid. 15. Perforate HB-1 and HB-4 with TCP guns. 16. Set retainer to isolate HB-4. Filter fluid. 17. Data frac / frac HB-1. 18. Clean out frac sand. Drill retainer. RECEIVED 0 V £ 1991 Alaska Oi~ & ~as Cons. Commission Anchorage TBUS G-1 REDRILL PA~E 2 OF 2 19. Set permanent packer above HB-1. 20. Set isolation plug and sand out. 21. Filter completion fluid. 22. Perforate" G" Zone with TCP guns. 23. Recover packer plug. 24. Run dual gaslift completion. 25. Remove BOPE, install tree and flowlines. Release rig. Alaska Oil & Gas Oons. Commission Anchorage TRADING BAY UNIT TBUS G-1 REDRILL ANTICIPATED PRESSURES: MAXIMUM SURFACE PRESSURE CALCULATION FOR 8-1/2" HOLE MUD WEIGHT 9-5/8" CASING SHOE DEPTH 9-5/8" CASING SHOE FRAC GRADIENT TD OF 7" CASING POINT PORE PRESSURE GRADIENT GAS GRADIENT 72 PCF = 0.500 PSI/FT 8450' MD / 7324' TVD O.9O PSI/FT l1716'MD / 10103' TVD 0.450 PSI/FT 0.0 PSI/FT ASSUME THAT 25% OF THE WELLBORE IS DISPLACED DURING A GAS KICK ( HOLE FILLED WITH 75% MUD AND 25% GAS ). MAXIMUM SURFACE PRESSURE = BHP - MUD/GAS HYDROSTATIC PRESSURE MSP = BHP- (3/4 MUD + 1/4 GAS) MSP =(10103 FT * .450 psi/ft) -((.75 (10103 FT * .500 PSI/FT)) + (.25 (10103 FT * 0 PSI/FT))) MSP = 758 PSI THE GREATEST HYDROSTATIC PRESSURE AT THE 9-5/8" SHOE (HPsh) IS WHEN THE GAS BUBBLE REACHES THE SHOE, IF A CONSTANT BHP IS APPLIED. A CONSERVATIVE ESTIMATE WOULD BE THE MAXIMUM SURFACE PRESSURE (MSP) PLUS THE HYDROSTATIC PRESSURE AT THAT CASING DEPTH (HPcsg). HPsh = MSP + HPcsg HPsh = 758 PSI + ( 7324 FT * .500 PSI/FT ) = 4420 PSI FPsh = FRAC GRAD * TVDshoe FPsh = 0.90 PSI/FT * 7324 FT = 6592 PSI HPsh = 4420 PSI IS LESS THAN THE FRACTURE PRESSURE AT THE 9-5/8" SHOE, FPsh = 1980 PSI AND THEREFORE ADEQUATE TO HANDLE THE WELL KICK. THIS SCENARIO IS CONSIDERED EXTREME, SINCE A 206 BBL ENTRY IS REQUIRED TO DISPLACE 25 PERCENT OF THE WELL BORE. TI~DING B~Y UNIT TBUS G-1 REDRILL MUD PROGRAM PLUG AND ABANDONMENT MUD WEIGHT FUNNEL VISCOSITY PLASTIC VISCOSITY YIELD POINT PH 64 TO 68 PCF 50 TO 70 SEC/QT 8 TO 15 CP 15 TO 25 #/100 SQ FT 9 TO 10 9~5/8" WINDOW MILLING MUD WEIGHT FUNNEL VISCOSITY 68 TO 70 PCF 70 TO 150 SEC/QT 8-1/2" HOLE SECTION ( 7'__' CASING 8450' TO 11716' SECTION ( GENERIC MUD #2 ) MUD WEIGHT FUNNEL VISCOSITY PLASTIC VISCOSITY YIELD POINT PH API FLUID LOSS HPHT @ 200 SOLIDS 68 TO 72 PCF 45 TO 55 SEC/QT 12 TO 10 CP 8 TO 16 #/100 SQ FT 9.5 TO 10.5 4 TO 6 CC 15 TO 18 CC 5 TO 8 PERCENT CASING AND TUBING DESIGN WELL TBUS G-1REDRILL CASING STRING 7" LINER FIELD MCARTHUR RIVER FIELD BOROUGH GRAYLING PLATFORM STALE ALASKA DATE 11/23/91 DESIGN BY D. A. CHUDANOV 1. HUD WT. I #/~. HYD GR. I pst/ft. MUD WT. II t$/q. HYO. GR. II ASSUMPTIONS: 0.50 psi/ft gradient on outside, void on inside for collapse 0'.50 psi/ft gradient on inside, void on outside for burst WEIGHT W/ BF INTERVAL , DESCRIPIION CASING SIZE Bottom Top LENGTH Wt. Grade lhread lbs IENSION MINIbUM -top oF SIRENGTH section TENSION lbs 1OOO lbs 1. 7" liner 11715' 8150' 3565' 29~ P-110 BUTTRESS !03~14 (IO103'TVD) (7324'%VD) 103,414 955 psl/ft. M.S.P. IDF COLLAPSE COLLAPSE PRESS. G RESIST. bottom tension _ psi ps! CDF 9.2 5052 8510 1.7 INTERNAL BURST MINIMUM PRESSURE YIELD psi psi BDF 5052 11220 2.2 i 26"@ 327' 13-3/8" 61 # J-55 @ 2160' TOP OF 3--1/2' JUNK @8619' FISH PLUGGED @ 8705' TOP OF 1-1/2' CT JUNK @ 8620' 7" TOL @ 8816' 9-5/8" 40, 43.5 & 47# N-80 @ 8994' RKB = 0.00' TRIPLE -- PACKER ~) 8696' TUBING DETAIL 3-1/2', 9.2#, N-80 BUTTRESS TUBING WITH SPECIAL CLEARANCE CPLGS 1) 3-1/2' EU 8RD x 3-1/2' BUTTX-OVER 2) OTIS SSSV NIPPLE & BXE VALVE @ 312.72' 3) PTA 'DSO' GASLIFT MANDRELS GLM #1 @ 2766.67' GLM #2 @ 4316.40' GLM #3 @ 5527.93' GLM #4 @ 6654.43' GLM #5 @ 7057.40' GLM #6 @ 7558.57' GLM #7 @ 8034.22' GLM #8 @ 8504.66' 4) OTIS 'XA' SLIDING SLEEVE @ 8546.18' 5) 4' OD SEAL ASSY W/STR SLOT LOCATOR FROM 8580.99' TO 8590.94' PROD PKR W/TAIL ( SET ON DP ) 6) OTIS 'X' LANDING NIPPLE @ 8595' DPM 7) WlRELINE REENTRY GUIDE @ 8609' DPM 8) OTIS 'BWH" PERM PKR @ 8570' DPM SEE PREVIOUS SCHEMATIC FOR DETAILS ON TRIPLE PKR AND COMPLETION ( LS PLUGGED ISOLATING HEMLOCK) BLAST JOINTS -- PERMANENT -- PACKER @ 10585' 7" 29# N-80 @ 11419' CMT RET ~ 11125' G ' ZONE PERFORATIONS 0178'- 10208' OPEN - PROD 0340'- 10375' OPEN - PROD 0450'- 10470' OPEN - PROD 0495'- 10507' OPEN - PROD HEMLOCK ZONE PERFORATIONS 10703'- 10750' ISOLATED - PROD 10764'- 10878' ISOLATED - PROD 10898'- 11100' ISOLATED - PROD WELL TBUS G-1 COMPLETION (7-16-91) UNION OIL COMPANY OF CALIFORNIA (dba UNOCAL) DRAWN: DAC SCALE: NONE DATE: 8-8-91 26"@ 327' 13-3/8" @ 2160' / TUBING DETAIL: 7" TOL @ 8150' SS: DUAL 2-7/8" x 2-3/8' 6.4# & 4.6# BUTT 9-5/8" WINDOW @ 8450' LS: DUAL 2-7/8' x 2-3/8' 6.4# & 4.6# BUTT DUAL PKR ~ 99(XT BLAST JOINTS -- PERMANENT -- PACKER ~, 1 ' G ' ZONE PERFORATIONS 7" L @ 11715' HEMLOCK ZONE PERFORATIONS ( FRAC HB-1 ) WELL TBUS G-1RD PROPOSED COMPLETION UNION OIL COMPANY OF CALIFORNIA (dba UNOCAL) DRAWN: DAC SCALE: NONE DATE: 10-21-91 BELL NIPPLE J FLOWLINE 3' KILL LINE WITH TWO 2' 5M VALVES KILL LINE FROM MUD PMP & CEMENT UNIT 13-5/8' 3000 PS! ANNULAR ,J 13-5/8' 5M FLANGE PiPE RAMS BLIND RAMS I "J PIPE RAMS DOUBLE GATE 5M 13-5/8" 5M FLANGE 4' CHOKE LINE WITH ONE REMOTE & 1 MANUAL 4" 5M VALVE ~;[:, , ([:, J CONNECTED TO CHOKE MANIFOLD (SEE MANIFOLD DRAWING) 13-5/8' 5M FLANGE SINGLE GATE 5M RISER 13-5/8' 5M FLANGE I I , 10' 5M x 13-5/8' 5M ADAPTER CAMERON 5M SPOOL 13-5/8" BOPE 5M STACK GFIAYLING PLATFORM UNION OIL COMPANY OF CALIFORNIA (dba UNOCAL) DRAWN' DAC APP'D: GSB SCALE: NONE DATE: 11-23-91 TO GAS BUSTER TO DERRICK VENT I I 3-1/8" TO WELL CLEAN TANK /\ 4-1/16" 5-1/8" 4-1/16" AUTOMATIC CHOKE 3-1/16" ,3-1/16" ,/~ ,3-1/16" 3-1/16" / FROM CHOKE LINE AUTOMATIC CHOKE VALVES UPSTREAM OF CHOKES ARE 10,000 PSI GATE TYPE VALVES DOWNSTREAM OF CHOKES ARE 5,000 PSI GATE TYPE CHOKE MANIFOLD GRAYLING PLATFORM UNION OIL COMPANY OF CALIFORNIA (dba UNOCAL) DRAWN: DAC APP'D: GSB SCALE: NONE DATE: 11/26/89 MIXING PIT 4O BBLS MIXING PIT IS A ONE LEVEL BELOW TH E ACTIVE SYSTEM 185 BBLS VOLUME PIT TRIP TANK 45 BBLS 185 BBLS SUCTION PIT 125 BBLS DEGASSER I I I I i 67 BBLS DESILTERI 24O BBLS SHAKER SHAKER ! I CENmlFUGE RESERVE PIT 475 BBLS NOTE: THE SYSTEM WILL BE EQUIPPED WITH A DRILLING PIT LEVEL INDICATOR WITH AUDIO & VISUAL WARNING DEVICES. EQUIPMENT LIST 1) RESERVE PIT 2) DEGASSER 3) (2) SHAKERS 4) PIT LEVEL INDICATOR (VISUAL & AUDIO) 5) FLUID FLOW SENSOR 6) TRIP TANK 7) PIT AGITATORS 8) DESILTER 9) CENTRIFUGE 10) MIXING PIT UNOCAL GRAYLING MUD PIT SCHEMATIC DRAWN BY: DAC APP'D: GSB SCALE: NONE DATE: 11-30-89 GREAT LAND DIRECTIONALDRILLING, INC. Client .... : UNOCAL Field ..... : Hemlock Well ...... : G-01 Redrill 11/o6/91 Computation...: MINIMUM CURVATURE Section at .... : N 81.12 E RKB Elevation.: 103.00 ft Magnetic Dcln.: 27.00 E PROPOSED WELL PROFILE SURFACE LOCATION: 1886 FSL 1386 FEL S29 T9N R13W SM TARGET LOCATION : 2220 FNL 3350 FWL S28 TgN R13W SM 1174 N 4736 E OF WELL HEAD MARKER MEAS INCLN VERT-DEPTHS SECT DIRECTION REL-COORDINATES DL IDENTIFICATION DEPTH ANGLE BKB SUB-S DIST BEARING FROM-WELLHEAD /100 KOP DROP 1.37/100 8450 34.98 7324 7221 3728 N 63.94 E 978 N 3621 E <TIE 8500 34.30 7365 7262 3756 N 67.37 E 990 N 3647 E 4.00 8600 32.93 7448 7345 3810 N 74.25 E 1008 N 3699 E 4.00 END OF DROP 8700 31.56 7533 7430 3863 N 81.12 E 1020 N 3750 E 4.00 TOP GISST TOP HEMLOCK TD 10026 31.56 8663 8560 4557 N 81.12 E 1127 N 4436 E 10607 31.56 9158 9055 4861 N 81.12 E 1174 N 4736 E 11716 31.56 10103 10000 5441 N 81.12 E 1264 N 5310 E UNOCAL G-01 RD Oct. 22, 1991 Target Locations Target MD TVD Nor,t.h J East. Of well head ................... 9~8 .......... KOP 8450 '7324 3621 ToP 61 SST 10026 8663 1094 4436 Top HEMLOOCK 10607 9158 1174 4736 TD 11716 10103 1234 5266 ,, Well Path Locations H0r "l .... Ea'S.t N°rth I Ea,st TOtal of well hea Difference Diff. "978J 3621'" ....~ ...... 0 ' ..... ' 0 .... ~ '0 1127 4436 33 0 33 1174 4736 0 0 0 1264 5310 30 44 53 Well Profile KO 8450 34.98 Degrees N 63.94 E Drop 1.368/100 4.00 Dogleg End Drop @ 8700 31.56 Degrees N 81.12 E ~arker ldenLQfication ~ A! KO= onoP~i.37/too c! TD UNOCAL .HO T/D SEC1N- ZNCLN. 8460 7324' 3726: 34.98; 6700~ 7533' 3863;:. 31.98 ii7i6: iOi03., 544i 3i.56. G-O! Redr l.! VERTICAL SECTION VIEH Section at: N Bt.12 E TVO Scale.: ! inch = 500 feet Oep. Scale.: ! inch = 500 feet IOraNn ..... : ii/06/9! 7200- 7700' T- 7g~_ ............ %'- ' --* ; ............ 1 % · Sect'io~-Departure. i UNOCAL_ Narker-Zdent::l f icat:lon 140 H/S F../N Al KB 0 OH OE B] KOP ORi~'l,37/tO0; 8450 976 N 362t E IENO OF ~ 6700' 1020:N 3750 E TO :li7t6 1264 N 53:1.0. E 3500-' ,"---.--- G-O I. Redr i 11 PLAN VIE CLOSURE ..... : 5456. ft N 76.6! E DECLINATION.: ~-7.00 E SCALE .......: ! inch = tO00 feet DRA#N .......: iI/06/9! ~eBt_ Land-DJrectJonal DrJ'llin# 3000' ;~500~- 2000- iO00- . ~.~.~.. .-I .......... .- ~._' ~... ._ , ..... 500- ----- _l '- I '" ..,, "~ ............ ....... ~ ...~;... .. ........ ! ! ............. ? ........ ........ ! ................. ~ ......................................... ; .... 500- -I ...... ' .... i .-- ~___ _ iO00- _! ........................... ~ ............... ,t.- ...................... 8000~ --.~ .......... ,, ..... L ......... ~ ......... ~500~ -- ---~ ........................ i ' - ! 300~' ! .......... ...................... ~ ......... _1. ........... ~ ....................... : .......... '~00:,-,'.- 0 ~00'=: iO00--- i§OOf-'-' ~OOO?'. ~0~' 3000~.-- 3500? ~000~ 4500'-. §000. Unocal North Americ;,'~ Oil & Gas Division Unocal Corporation P.O. Box 190247 Anchorage, Alaska 99519-0247 Telephone (907) 276-7600 UNOCAL Robert T. Anderson Manager, Lands Alaska Region November 26, 1991 Mr. Russell Douglass Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 TRADING BAY UNIT STATE OF ALASKA Permit to Drill Well: TBUS G-1RD Dear Mr. Douglass: In accordance with AOGCC Regulation 20 AAC 25.005 (Permit to Drill), enclosed please find check number 11175 in the amount of $100.00, payable to the State of Alaska, Department of Revenue to cover the permit fee for the above captioned well. Also enclosed is form 10-401 in triplicate, covering the subject permit for your approval. Should you have any questions, please contact the undersigned at 263-7604. Thank you in advance for your consideration. RAP:da Enclosures Very truly yours, Robert A. Province Landman STATE OF ALASKA Al '~ OIL AND GAS CONSERVATION COi'~ :~SION APPLIC'-' rlON FOR SUNDRY A, , ROVALS 1. Type of request: Abandon X_ Suspend Operations shutdown Re-enter suspended well__ Alter casing__ Repair well __ Plugging __ Time extension __ Stimulate __ .. Change approved program 'puli tubing Variance Perforate Other 6. Datum elevation (DF or KB) 2. Name of Operator 15. Type of Well: I Development X Union OII Company ot California (Unocal) Exploratory --._~- 3. Address Stratigraphi~ ~ Service ~ P.O. Box 196247 Anchorage, AK 99519 Location of well at surface Leg #2, Conductor #40 1886' FSL & 1386' FEL, Sec. 29, T9N, R13W, S.M. At top of productive interval 3208' FSL & 3180' FWL, Sec. 28, T9N, R13W, SM @ 10178' MD At effective depth 3299' FSL & 3697' FWL, Sec. 28, 'l'gN, R13W, SM @ 11,125' MD At tolal depth 3316' FSL & 3860' FWL, Sec. 28, T9N, R13W SM @ 11,419' MD 103' RT above MSL feet 7. Unit or Property name Trading Bay Unit 8. Well number G-1 9. Permit number 67 -47 10. APl number 133 -20037 11. Field/Pool G" Zone/Hemlock 12. Present well condition summary Total depth: measured true vertical 11,41 9' feet Plugs (measured) 9,767' feet Effective depth: mea{ured true vertical 11,1 25' feet Junk (measure(0 9,516' feet Casing Length Structu~ral 327' Conductor Surface 2160' Intermediate Production 8994' Liner 2600' Perforation depth: measured Size Cemented Measured depth True vertical depth 26" Driven 327' 327' true vertical 13- 3/8" 3100 sxs 2160' 2113' 9-5/8" 2700 sxs 8994' 7746' 7" 540 sxs 8816'- 11419' 7603'- 9767' See attached perforation record Tubing (size, grade, and measured depth) 3-1/2", 9.2# N-80 Buttress @ 8590' Packers and SSSV (type and measured depth) 9-5/8" Otis BWH single production pkr @ 8570' Otis $SSV @ 313' RECEIVED NOV 2 7 1991 Alaska 0il & Bas Cons. C0mmissi0r Anchorage.' 13. Attachments Description summary of proposal X_ Detailed operations program__ BOP sketch X 14. Estimated date for commencing operation January 2, 1992 16. If proposal was verbally approved Name of approver Date approved 5. Status of well classification as: Oil X Gas Suspended Sen/ice 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed Gary S. Bush ~..~.(::L,-~k. -'~, (~--,~...~ Title Regional Drilling Manager (~ _ ,...-~. '~OR COMMISSION-USE ONLY Conditions ot approval: N~ti~ cdrtimission so representative' may witness ' Plug Integrity )k BOP Test Location clearance Mechanical Inti~jrity Test Subsequent form required 10- . Approved by the order of the Commission Form 10-403 Rev 06/15/88 ORIGINAL '~'"~'~'~' Oommissioner ITEM (1) Fee (2) Loc ,. ** CHECK LIST FOR NEW WELL PERMITS ** APPROVE DATE [2 thru' '" (3) Admin~ /2~//~:/~/13] -/ [10 & 13] [14 thru 22] (5) BOPE .~,~.~ ?,~-~--~/ [23 thru 28] Lease $ Well Is permit fee attached ............................................... 2. Is well to be located in a defined pool .............................. 3. Is well located proper distance from property line ................... 4. Is well located proper distance from other wells ..................... 5. Is sufficient undedicated acreage available in this pool ............. 6. Is well to be deviated & is wellbore plat included ................... 7. Is operator the only affected party .................................. 8. Can permit be approved before 15-day wait ............................ e 10. 11. 12. 13. 14. 15. Does operator have a bond in force ................................... Is a conservation order needed ....................................... Is administrative approval needed .................................... Is lease nLrnber appropriate .......................................... Does well have a unique name & n~rnber ................................ YES 16. 17. 18. 19. 20. 21. 22. Is conductor string provided ......................................... Will surface casing protect all zones reasonably expected to serve as an underground source of drinking water .................. Is enough cement used to circulate on conductor & surface ............ Will cement tie in surface & intermediate or production strings ...... Will cement cover all known productive horizons ..................... Will all casing give adequate safety in collapse, tension, and burst. Is well to be kicked off from an existing wellbore ................... Is old wellbore abandonment procedure included on 10-403 ............. Is adequate wellbore separation proposed ............................. NO REMARKS 23. 24. 25. 26. 27. 28. 29. 30. 31. 32. Is a diverter system required ........................................ Is drilling fluid program schematic & list of equipment adequate ..... Are necessary diagrams 8 descriptions of ~~:--BOPE attached .... Does BOPE have sufficient pressure rating -- test to~d~:~<::~ psig ..... Does choke manifold comply w/API RP-53 (May 84) ...................... Is presence of H2S gas probable ...................................... FOR EXPLORATORY & STRATIGRAPHIC WELLS: Are data presented on potential overpressure zones ................... Are seismic analysis data presented on shallow gas zones ............. If offshore loc, are survey results of seabed conditions presented... Additional requirements ............................................. 0 geology' DWJ ..... ena ineer in~:: MTM.~. LCs';? ~ BEW~_ RAD ~ JH.~ ~ rev 03/29/91 jo/6.011 ......... IkITIA'L G'EO] UNIT ON/O'FF POOL CLASS STATUS AREA ~ SHORE o t So '" Additional remarks' Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify finding information, information, of this nature is accumulated at the end of the file under APPENDIX. No special 'effort has been made to chronologically organize this category of information. * HHHH HHHH * * HI~HH HHHH H H A LL LL II BBBB U U RRRR TTTTT O N N * * HHHH HHHH H H AA LL LL II B B U U R R T O O NN N * * HHHHHHf~]HHH HHHH A A LL LL II BBBB U U RRRR T O O N N N * * HHHX~q~U~]H/4/~{ H H AAAA LL LL II B B U U R R T O O N NN * * HHHH. HHHH H H A ALL LL II BBBB U R R T O N N * * HHHH HH/4H * *HHHH HHHH L O G G I N G S E R V I C E S , I N C . * . * . * . * . * LIS TAPE VERIFICATION LISTING COMPANY: UNOCAL WELL: TBU G-1 RD API #: 50-133-20037-01 DATE: 02-11-92 FIELD: McARTHUR RIVER BOROUGH: KENAI STATE: ALASKA LOGS: DIL/FWS2 SDL/DSN2 RECEIVED FEB 2 ! 1992 Al~sk~ Oil & G~s Cons. Commission Anchorage Page 1 REEL HEADER RECORD .............................. TYPE 132 SERVICE NAME DATE ORIGIN OF DATA REEL NAME REEL CONTINUATION NUMBER PREVIOUS REEL NAME COMMENTS: --- COMCEN --- 92/02/18 --- ANCH --- 137214 ****************************************************************************** TAPE HEADER, RECORD TYPE 130 SERVICE NAME --- COMCEN DATE --- 92/02/18 ORIGIN OF DATA --- ANCH TAPE NAME --- 0 TAPE CONTINUATION NUMBER --- 1 PREVIOUS TAPE NAME ,.- -'~' .. COMMENTS: . · ****************-*************************************************************** FILE HEADER RECORD TYPE 128 FILE NAME ~ SERVICE SUB LEVEL NAME VERSION NUMBER DATE OF GENERATION MAX. PHYSICAL ,RECORD LENGTH FILE TYPE OPTIONAL PREVIOUS FILE NAME --- COMCEN.001 --- 92/02/18 --- 1024 --- LO ****************************************************************************** COMMENT RECORD TYPE 232 FILE HEADER FILE NUMBER: 01 DEPTH INCREMENT: 0.25' FILE SUMMARY TOOL CODE START DEPTH STOP DEPTH DIL FWS2 SDL DSN2 REMARKS: 11494.75 8300.00 11496.75 8302.00 11515.00 8405.75 11515.00 8405~75 THIS FILE CONTAINS.MAIN PASS DATA FOR DIL/FWS2 AND FOR SDL/DSN2_LOGGING SUITES. Page 2 DELTA T ANOMOLY IN SEVERAL INTERVALS CAUSING DELTA T TO STRAIGHT LINE, APPARENTLY DUE TO TRAVEL TIME LOCKING ON AN INCORRECT PEAK. REPEAT SECTION #2 OF SDL/DSN2 DATA WAS SPLICED TO THE MAIN PASS FROM 11310' TO 11515'. LIS FORMAT DATA INFORMATION RECORD TYPE 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 REPR 65 65 65 65 65 65 65 65 65 65 65 65 65 65 65 65 65 65 65 65 65 65 65 SIZE CATEGORY MNEM 60 0 DBUN 60 0 WN 60 0 CN 60 0 FN 60 0 LONG 60 0 LATI 60 0 SECT 60 0 TOWN 60 0 RANG 60 0 COUN 60 0 STAT 60 0 CTRY 60 0 LUN 60 0 RUN 60 0 APIN 60 0 MRT 60 0 ST 60 0 UNIT 60 0 RMFB 60 0 RMCB 60 0 EDP 60 0 DMF 60 0 LMF UNITS TYPE 34 COMPONENT F TBU G-1 RD UNOCAL MCARTHUR RIVER .0000 .0000 29 09N 13W KENAI ALASKA USA 9000 1 501332003701 DEGF KB .0000 .0000 .0000 .0000 .0000 KB Page 0 65 60 0 CBD1 8450.0000 0 65 60 0 CBF .0000 0 65 60 0 APD 103.0000 0 65 60 0 EUCF IN 0 65 60 0 PD MSL 0 65 60 0 DD 11506.0000 INFORMATION- TYPE REPR 0 65 0 65 0 65, 0 65 0 65 0 65 0 65 0 65 0 65 0 65 0 65 0 65 0 65 0 65 0 65 0 65 0 65 0 65 0 65 0 65 ~ECORD TYPE 34 SIZE CATEGORY MNEM UNITS COMPONENT 60 0 SON 137214 60 0 FL 1886' FSL 60 0 LUL STERLING 60 0 OS1 DIGL/FWS2/GR 60 0 ENGI WASHER/MCKAY 60 0 WITN MCCALL/KILOH 60 0 TLAB 630 60 0 BHT 170.0000 60 0 DFT~ PHPA POLYMER 60 0 DFD 71.0000 60 0 DFV 54.0000 60 0 DFPH 9.0000 60 0 DFL 7.0000 60 0 MST 66.0000 60 0 RMS .4500 60 0 MFST 70.0000 60 0 RMF .2500 60 0 MCST 66.0000 60 0 RMC .7000 60 0 RMB .1800 & 1386' FEL Page 4 0 65 60 0 EKB 103.0000 0 65 60 0 BS 8.5000 0 65 60 0 CBL1 8453.0000 0 65 60 0 CS 9.6250 0 65 60 0 CWl 47.0000 0 65 60 0 CSD 8450.0000 0 65 60 0 BLI 11479.0000 0 65 60 0 TLI 8453.0000 0 65 60_ 0 DATE 02-11-92 0 65 60 0 TCS 30 0 65 60 0 DL 11481.0000 0 65 60 ' 0 MSS PIT 0 65 60 0 MFSS MEAS. DATUM FORMAT SPECIFICATION RECORD TYPE 64 ENTRY BLOCKS: TYPE SIZE REPR. CODE ENTRY 1 1 66 0 2 1 66 0 3 2 79 136 4 1 66 1 5 1 66 1 8 4 73 30 9 4 65 .liN i1 2 79 7 12 4 68 -999.000 14 4 65 F 15 1 66 68 16 1 66 1 0 1 66 0 DATUM SPECIFICATION BLOCKS: MNEM SERVID SERVICE# UNITS DEPT GR FWS2 137214 DT FWS2 137214 ITT FWS2 137214 ILM DIL 137214 ILD DIL 137214 F GAPI US/F OHMM API CODE FILE~ SIZE #SAMP REPR. 00000000 0 4 1 68 00000000 0 4 1 68 00000000 0 4 1 68 00000000 0 4 1 68 00000000 0 4 1 68 00000000 0 4 1 68 Page 5 ClLD DIL 137214 MMHO 00000000 0 4 1 68 SGRD DIL 137214 OHMM 00000000 0 4 1 68 TENS FWS2 137214 LB 00000000 0 4 1 68 DLOD FWS2 137214 LB 00000000 0 4 1 68 TT21 FWS2 137214 00000000 0 4 1 68 TT22 FWS2 137214 00000000 0 4 1 68 TTll FWS2 137214 00000000 0 4 1 68 TT12 FWS2 137214 00000000 0 4 1 68 SP DIL 137214 00000000 0 4 1 68 GR SDL 137214 GAPI 00000000 0 4 1 68 FDSN DSN2 137214 CPS 00000000 0 4 1 68 NDSN DSN2 137214 CPS 00000000 0 4 1 68 NPHI DSN2 137214 DECP 00000000 0 4 1 68 NRAT DSN2 137214 C/C 00000000 0 4 1 68 DPE SDL 137214 00000000 0 4 1 68 DPHI SDL. 137214 DECP 00000000 0 4 1 68 DRHO SDL 137214 G/C3 00000000 0 4 1 68 FSDL SDL 137214 CPS 00000000 0 4 1 68 NSDL SDL 137214 ' CPS 00000000 0 4 1 68 PE SDL 137214 00000000 0 4 1 68 PELC SDL 137214 00000000 0 4 1 68 QL SDL 137214 00000000 0 4 1 68 QS SDL 137214 00000000 0 4 1 68 QPE SDL 137214 00000000 0 4 1 68 RHOB SDL 137214 G/C3 00000000 0 4 1 68 CALI ~DL 137214 IN 00000000 0 4 1 68 TENS SDL 137214 LB 00000000 0 4 1 68 DLOD SDL 137214 LB 00000000 0 4 1 68 DATA RECORD TYPE 0. DEPT = 11515.000 GR = -999.000 DT = -999.000 ITT = -999.000 ILM = -999.000 ILD = -999.000 CILD = -999.000 SGRD = -999.000 TENS = -999.000 DLOD = -999.000 TT21 = -999.000 TT22 = -999.000 TTll = -999.000 TT12 = -999.000 SP = -999.000 GR = 57.134 FDSN = 2047.074 NDSN = 12068.660 NPHI = .335 NRAT = 6.842 DPE = .534 DPHI = .710 DRHO = .063 FSDL = 37591.910' NSDL = 23618.430 PE = 6.190 PELC = 5.923 QL = .107 QS = -.324 QPE = .134 RHOB = 1.479 CALI = 3.518 TENS = 3234.269 DLOD = -6.167 DEPT = 11415.000 GR = 33.659 DT = 64.428 ITT = .000 ILM = 6.767 ILD = 8.235 CILD = 121.436 SGRD = 16.535 TENS = 5646.380 DLOD = 1806.399 TT21 = 444.900 TT22 = 599.500 TTll = 534.600 TT12 = 363.800 SP = 38.536 GR = 49.885 FDSN = 3032.820 NDSN = 14615.510 NPHI = .239 NRAT = 5.592 DPE = .096 DPHI = .063 DRHO = .075 FSDL = 6405.238 NSDL = 17645.980 PE = 4.033 PELC = 4.095 QL = .036 QS = .002 QPE = -.031 Page 6 RHOB = DLOD = 2.546 1187.889 8.667 TENS = 5544.460 DEPT = ITT = CILD = DLOD = TTll = GR = NPHI = DPHI = NSDL = QL = DLOD = 11315.000 GR = .000 ILM = 99.192' SGRD = 1762.741 TT21 = 602.800 TT12 = 47.190 FDSN = .419 NRAT = .148 DRHO = 18438.070 PE = -.039 QS = 2.407 CALI= 1053.286 55.671 DT = 9.445 ILD = 9.448 TENS = 434.600 TT22 = 443.900 SP = 1490.753 NDSN = 9.270 DPE = .074 FSDL = 3.112 PELC = .014 QPE = 9.279 TENS = 85.108 10.081 5612.407 617.900 31.499 11908.600 .055 8243.350 3.252 -.070 5397.242 DEPT = ITT = CILD = DLOD = TTll = GR = NPHI = DPHI = NSDL = QL = DLOD = 11215.000 GR = .000 ILM = 50.603 SGRD = 1699.239 TT21 = 544.300 TT12 = 46.432 FDSN = .193 NRAT = .141 DRHO = 17807.980 PE = -.009 US = 2.418 CALI= 1023.761 49.246 DT = 15.834 ILD = 19.219 TENS = 392.900 TT22 = 382.200 SP = 4140.873 NDSN = 4.733 DPE = .043 FSDL = 2.981 PELC = -.004 QPE = 8.324 TENS = 76.236 19.762 5533.136 552.300 25.833 16888.100 .002 7566.017 2.938 .022 5408.566 DEPT = 11115.000 ITT = .000 CILD = 46.601 DLOD = 1754.804 TTll = 512.500 GR = 37.262 NPHI = .130 DPHI = .108 NSDL = 17582.070 QL = -.001 RHOB = 2.472 DLOD = 1017.~682 GR = ILM = SGRD = TT21 = TT12 = FDSN = NRAT = DRHO -- PE = QS = CALI= 44.206 DT 15.519 ILD 22.701 TENS 391.300 TT22 379.400 SP 5938.188 NDSN 3.496 DPE .049 FSDL 3.022 PELC .038 QPE 8.282 TENS 69.136 21.459 5499.162 531.600 17.687 17891.000 .012 6934.350 3.008 .007 5351.944 DEPT = ITT = CILD = DLOD = TTll = GR = NPHI = DPHI = NSDL = QL = 11015.000 GR = .000 ILM = 68.644 SGRD = 1651.613 TT21 = 562.300 TT12 = 59.531 FDSN = .398 NRAT = .137 DRHO = 19351.430 · PE = -.023 QS = 2.424 CALI= 90.789 DT = 10.286 ILD = 20.208 TENs = 425.300 TT22 = 405.000 SP = 1370.783 NDSN = 9.381 DPE = .121 FSDL = 4.085 PELC = -.021 QPE = 12.838 TENS = 72.196 14.568 5374.593 596.400 17.826 11081.280 .205 8624.350 4.395 -.155 5465.188 Page 7 DLOD = 1127.101 DEPT ITT = CILD = DLOD = TTll = GR = NPHI = DPHI = NSDL = QL = DLOD = 10915.000 GR = .000 ILM = 28.180 SGRD = 1663.520 TT21 = 521.400 TT12 = 40.755 FDSN = .145 NRAT = .113 DRHO = 17680.160 PE = .021 QS = 2.463 CALI= 1022.893 48.768 DT 22.984 ILD 34.419 TENS 365.500 TT22 376.100 SP 5404.933 NDSN 3.782 DPE .051 FSDL 2.810 PELC -.019 QPE 8.315 TENS 71.352 35.487 5250.024 506.100 31.117 17616.350 .009 7075.684 2.854 -.022 5170.753 DEPT = ITT = CILD = DLOD = TTll = GR = NPHI = DPHI = NMDL = QL = DLOD = 10815.000 GR = .000 ILM = 41.998 SGRD = 1695.271 TT21 = 522.200 TT12 = 43.132 FDSN = .157 NRAT = .102 DRHO = 17574.070 PE = -.022 QS = 2.482 CALI= 1038.523 49.549 DT = 11.970 ILD = 28.132 TENS = 409.200 TT22 = 377.000 SP = 5023.472 NDSN = 4.005 DPE = .050 FSDL = 2.905 PELC = -.012 QPE = 8.320 TENS = 70.496 23.811 5250.024 555.600 40.481 17336.220 .007 6822.794 3.137 -.116 5057.508 DEPT = ITT = CILD = DLOD = TTll = GR = NPHI = DPHI = NSDL = QL = DLOD = 10715.000 .000 50.932 1719.084 557.200 43.511 .196 .152 17973.520 .017 2.399 1028.103 GR = ILM = SGRD = TT21 = TT12 = FDSN = NRAT = DRHO = PE = QS = CALI -- 46.896 DT 15.561 ILD 20.704 TENS 382.800 TT22 400.OO0 SP 4128.292 NDSN 4.601 DPE .047 FSDL 2.781 PELC .018 QPE 8.120 TENS 80.416 19.634 5295.322 523.400 37.896 16365.900 .004 7810.461 2.841 -.030 5102.806 DEPT = ITT = CILD = DLOD = TTll = GR = NPHI = DPHI = NSDL = QL = DLOD = 10615.000 .000 63.176 1831.403 615.100 79.446 .520 .197 17745.890 .026 2.325 1005.524 GR = ILM = SGRD = TT21 = TT12 = FDSN = NRAT = DRHO = PE = QS = CALI -- 90.417 DT = 12.637 ILD = 19.473 TENS = 460.200 TT22 = 417.700 SP = 1156.201 NDSN = 11.112 DPE = .007 FSDL = 2.811 PELC = .031 QPE = 9.277 TENS = 86.040 15.829 5340.620 610.300 44.766 11070.670 .008 8610.572 2.677 .067 4921.614 Page 8 DEPT = ITT = CILD = DLOD = TTll = GR = NPHI = DPHI = NSDL = QL = DLOD = 10515.000 GR = .000 ILM = 100.897 SGRD = 1778.617 TT21 = 577.500 TT12 = 85.023 'FDSN = .425 NRAT = .150 DRHO = 19831.070 PE = .000 QS = 2.403 CALI= 1135.785 91.136 DT = 7.522 ILD = 10.458 TENS = 506.800 TT22 = 415.000 SP = 1340.495 NDSN = 10.323 DPE = .143 FSDL = 3.987 PELC = .007 QPE = 13.770 TENS = 75.312 9.911 5227.375 630.000 68.698 11924.280 .279 9260.238 4.511 -.262 5918.168 DEPT = ITT = CILD = DLOD = TTll = GR = NPHI = DPHI = NSDL = QL = DLOD = 10415.000 .000' 68.625 1854.026 552.800 47.,722 .222 .154 18114.610 -.035 2.396 1330.308. GR = ILM = SGRD = TT21 = TT12 = FDSN = NRAT = DRHO = PE = QS = CALI= 49.779 DT = 10.291 ILD = 14.849 TENS = 412.800 TT22 = 402.000 SP = 3686.371 NDSN = 5.142 DPE = .054 FSDL = 2.840 PELC = .007 QPE = 8.429 TENS = 80.708 14.572 5204.726 547.100 44.635 16334.700 .012 7906.794 2.994 -.077 5317.971 DEPT = ITT = CILD = DLOD = TTll = GR = NPHI = DPHI = NSDL = QL = RHO8 = DLOD = 10315'000 GR = .000 ILM = 50.865 SGRD = 1692.890 TT21 = 560.700 TT12 = 49.198 FDSN = .195 NRAT = .127 DRHO = 17909.610 PE = -.027 QS = 2.441 CALI= 992.498 60.060 DT = 15-507 ILD = 24.398 TENS = 401.700 TT22 = 404.700 SP = 4018.468 NDSN = 4.668 DPE = .057 FSDL = 2.874 PELC = -.007 QPE = 8.389 TENS = 74.164 19.660 5012.210 564.500 33.062 16165.480 .017 7414.794 3.101 -.114 4876.316 DEPT = ITT = CILD = DLOD = TTll = GR = NPHI = DPHI = NSDL= QL = DLOD = 10215.000 GR = .000 ILM = 52.883 SGRD = 1810.368 TT21 = 638.900 TT!2 = 83.167 FDSN = · 550 NRAT = .275 DRHO = 20436'340 PE = .035 QS = 2.196. CALI= 1127.101 95.095 DT = 15.163 ILD = 18.641 TENS = 418%400 TT22 = 423.100 SP = 1024.572 NDSN = 12.434 DPE = .102 FSDL = 3.331 PELC = .036 QPE = 13.829 TENS = 92.720 18.910 5159.428 639.600 47.085 10977.420 .134 12747.680 2.526 .402 5170.753 Page '9 DEPT = ITT = CILD = DLOD = TT11 = GR = NPHI = DPHI = NSDL = QL = DLOD = 10115.000 .000 95.116 1738.929 558.600 46.010 .194 .127 17713.980 -.006 2.440 995.537 GR = ILM = SGRD = TT21 = TT12 = FDSN = NRAT = DRHO = PE = QS = CALI= 47.809 DT = 7.991 ILD = 10.565 TENS = 420.200 TT22 = 409.400 SP = 4182.024 NDSN = 4.684 DPE = .045 FSDL = 2.682 PELC = .005 QPE = 8.374 TENS = 76.360 10.514 5057.508 567.400 43.425 16878.090 .000 7267.127 2.814 -.066 4774.396 DEPT =- ITT = CILD = DLOD = TTll = GR = NPHI = DPHI = NSDL = QL = DLOD = 10015.000' .000 119.897 1780.602 569.000 93.290 .324 .081 18138.250 .025 2.517 970.788 GR = ILM = SGRD = TT21 = TT12 = FDSN = NRAT = DRHO = PE = QS = CALI -- 109.401 DT ~= 7.526 ILD = 8.579 TENS = 362.000 TT22 = 418.100 SP = 1821.633 NDSN = 7.975 DPE = .094 FSDL = 3.624 PELC = .032 QPE = 12.617 TENS = 78.348 8.340 5000.886 511.100 77.849 12518.850 .123 6967.571 4.089 -.232 4808.369 DEPT = ITT = CILD = DLOD = TTll = GR = NPHI = DPHI = NSDL = QL = DLOD = 9915.000 GR = .000 ILM = 136.391 SGRD = 1683.364 TT21 = 730.400 TT12 = 45.699 FDSN = .647 NRAT = .444 DRHO = 20825.710 PE = .OO4 QS = 1.917 CALI= 1040.261 56.940 DT = 6.558 ILD = 8.497 TENS = 483.000 TT22 = 515.500 SP = 849.737 NDSN = 13.364 DPE = .036 FSDL = 3.473 PELC = .016 QPE = 13.468 TENS = 97.280 7.332 4876.316 631.600 78.949 9785.275 .007 17618.130 3.541 -.034 4729.099 DEPT = ITT = CILD = DLOD = TTll = GR = NPHI DPHI = NSDL = QL = DLOD = 9815.000 .000 113.526 1766.711 524.400 47.885 .136 .092 17566.610 .029 2.498 957.762 GR = ILM = SGRD = TT21 = TT12 =' FDSN = NRAT = DRHO = PE = QS = CALI --' 48.723 DT = 7'227 ILD = 10.277 TENS = 422.600 TT22 = 380.000 SP = 5530.162 NDSN = 3.739 DPE = .053 FSDL = 2.997 PELC = .031 QPE = 8.861 TENS' 70.148 8.809 4864.992 584.100 76.916 17818.870 .019 6793.127 2.807 .095 4683.801 Page 10 80~'I8 = mQ 0£C'EOI = MO 000'SI~6 = mdMQ' 096'6L~9 ESI' 9g6'g g89'9~98 9~I' O£L'~L~gI S00'I6 00E'~E9 I08'E899 088'£I- 918'8L = QOHQ = SNHm 080'6 = iH~D = ~OHH = ado ~so'- = s0 = H0 = HaS& 6II' = OHHQ = IHd~ = ad~ III'8 = mkncLN = IHdN = NSQN 90E'0£LI = NSQ~ = HO = zzmm ooo's89 = ~zmm = ~OHQ = SNam SAA'0~ = (rams = ~H~o LL0'~86 ~0' 086'EI[6I 8~I' E69'08 00~'E~9 606'SlLI 000' 000'SI96 98~'I699 S90'- 8Eg'96T8 000' 08E'gL09I A~8'EII 009'£8S £0S'8E99 ~8'II 8~0'~8 = SNam = ado 900' = = OHad = HQSM EO0' = OHHQ 8LI' = sham £8S'6 = = ~HI 099'S = D~II 000' = m~ 9E9'89~ = SNMm 09E'8 £60'- = ado S90'- 980'£ = OHad g68'~ 8~I'8E~L = q~S~ ~T0' 000' = adQ 989'9 08L'~619I = NS~N SOL'010~ 9~'88 = dS 000'£09 00S'T9S = ~mm 009'019 6~'90L9 = SHam 88~'II 960'9I = ~HI ~II'0I ~68'8£ = m~ 6IS'ES 8SE'OS6 = QOHG = IT, D IE~'E = SOHH = S0 SS0' = HO = ad 068'08SLI = HQSN = OHHQ 6EI' = IHdQ = mkqLM ~6I' = IHdN = NSG& ESO'~S = HD = I~mm ~08'~StI = QOHQ = ~HDS 996'0L = ~HID = D~II 000' ' = mmI = HO 000'SI96 = mdaQ 919'Ig6~ = SNHm 9~9'8 LEO'- = ad5 610' 0LS'g = OHad 96L'g 910'0SS8 = HQS& L90' 6~0' = adQ 800'9 066'0SSSI = NSQN 8~A'£00~ IE0'06 = dS 00~'6~9 00S'6~S = ~mm 009'919 9L~'~£9~ = SHam 698'£ 9ES'~ = ~HI L~S'T ~S9'0LOI = QOHQ = I'l%fO L9E'g = 8OHH = S0 890'- = HO = ad 09E'9~S8I = HQSN = OHHQ ~LI' = IHdQ = mkr~R g9g' = IHdN = NS~& ~06'0S = HO = ~Imm 009'S6S = IImm = t~mm 9~t'ttAI = QOHQ = (1HOS ~99'0g~ = ~HID = D2/I 000' = &mi = HO 000'gI£6 = m~HO ITT = CILD = DLOD = TT11 = GR = NPHI = DPHI = NSDL = QL = DLOD = .000 ILM = 110.787 SGRD = 1687.333 TT21 = 597.200 TT12 = 87.888 FDSN = .351 NRAT = .184 DRHO = 20558.250 PE = .008 US = 2.347 CALI= 1046.339 6.631 ILD = 9.127 TENS = 433.700 TT22 = 426.200 SP = 1711.204 NDSN = 8.372 DPE = .160 FSDL = 5.222 PELC = -.002 QPE = 11.612 TENS = 9.026 4649.827 597.800 77.915 12344.370 .515 10299.680 5.867 -.322 4479.960 DEPT = ITT = CILD = DLOD = TTll = GR = NPHI = DPHI = NSDL = QL = DLOD = 9215.000 GR = .000 ILM = 89.469 SGRD = 1730.990 TT21 = 740.700 TT12 = 56.600 FDSN = .470 NRAT = .649 DRHO = 21386.610 PE = .046 US = 1.580 CALI= 1030.273 75.816 DT = 24.084 ILD = 9.857 TENS = 526.800 TT22 = 494.700 SP = 910.511 NDSN = 12.842 DPE = -.007 FSDL = 3.703 PELC = -.022 QPE = 20.890 TENS = 105.924 11.177 4638.503 711.300 70.517 10076.220 .005 29139.680 3.816 -.056 4378.040 DEPT = ITT = CILD = DLOD = TT11 = GR = NPHI = DPHI = NSDL = QL = DLOD = 9115.000 GR = .000 ILM = 107.199 SGRD = 1842.119 TT21 = 583.000 TT12 = 91.002 FDSN = .222 NRAT = .066 DRHO = 18029.890 PE = .008 US = 2.541 CALI= 1438'424 96.226 DT = 6.684 ILD = 7.185 TENS = 433.700 TT22 = 421.600 SP = 2845.200 NDSN = 5.976 DPE = .093 FSDL = 3.540 PELC = -.005 QPE = 12.848 TENS = 79.556 9.328 4593.205 594.500 80.199 14652.130 .107 6714.127 3.831 -.145 4898.966 DEPT = ITT = CILD = DLOD = TTll = GR = NPHI = DPHI = NSDL = QL = DLOD = 9015.000 GR = .000 ILM = 185.200 SGRD~= 1834.182 TT21 = 617.400 -TT12 = 45.034 FDSN = .245 NRAT = .191 DRHO = 18438.250 PE = .027 QS = 2.335 CALI= 1092.364 57.639 DT = 3.989 ILD = 4.915 TENS = 430.300 TT22 = 433.300 SP = 3208.218 NDSN = 5.651 DPE = .051 FSDL'= 2.717 PELC = -.031 QPE = 8.448 TENS = 93.316 5.400 4513.934 606.600 70.321 15623.650 .006 8793.793 2.612 .052 4412.013 DEPT = ITT = 8915.000 .000 Ga ~ = 106'.032 DT = 8.647 ILD = 79.652 11.519 Page 12 CILD = DLOD = TT11 = GR = NPHI = DPHI = NSDL = QL = RHOB = DLOD = 86. 814 SGRD = 1783.380 TT21 = 587.000 TT12 = 98.794 FDSN = .335 NRAT = .094 DRHO = 18928 . 340 PE = -. 026 US = 2. 494 CALI= 1114.074 9.925 TENS = 437.200 TT22 = 425.200 SP = 1795.213 NDSN = 8.184 DPE = .129 FSDL = 4.260 PELC = .030 QPE = 12.448 TENS = 4502.609 593.400 77.028 12660.100 .274 7741.683 4.480 -.110 4604.529 DEPT = 8815.000 ITT = .000 CILD = 100.301 DLOD = - 1750.835 TT11 = 571.900 GR = 99.781 NPHI = .296 DPHI = .081 NSDL = 17708.890 QL = .043 RHOB = 2.517 DLOD = 1082.813 GR = ILM = SGRD = TT21 = TT12 = FDSN = NRAT = DRHO = PE = QS = CALI= 102.084 DT = 7.840 ILD = 8.453 TENS = 436.300 TT22 = 413.200 SP = 2145.606 NDSN = 7.518 DPE = .067 FSDL = 3.304 PELC = -.010 QPE = 13.332 TENS = 79.968 9.970 4423.338 613.300 73.772 13899.180 .047 6743.017 3.534 -.115 4344.066 DEPT = ITT = CILD = DLOD = TTll = GR = NPHI = DPHI = NSDL QL = DLOD = 8715.000 GR = .000 ILM = 102..364 SGRD = 1774.648 TT21 = 611.300 TT12 = 78.227 FDSN = .254 NRAT = .060 DRHO = 18475.800 PE = -.053 QS = 2.551 CALI= 956.025 92.408 DT = 8.820 ILD = 7.617 TENS = 484.300 , TT22 = 431.900 SP = 2269.605 NDSN = 7.171 DPE = .118 FSDL = 4.259 PELC = .021 QPE = 17.877 TENS = 82.956 9.769 4434.662 700.200 62.428 14025.600 .213 6932.794 4.475 -.108 4049.630 DEPT = ITT = CILD = DLOD'= TTll = GR = NPHI = DPHI = NSDL = QL = DLOD = 8615.000 .000 134.777 1671.457 588.1oo 40.614 .233 .172 17946.980 .005 2.367 945.60~ GR = ILM = SGRD = TT21 = TT12 = FDSN = NRAT = DRHO = PE = US = CALI -- 45.043 DT = 5.335 ILD = 4.946 TENS = 433.200 TT22 = 423.800 SP = 3400.329 NDSN = 5.369 DPE = .036 FSDL = 2.781 PELC = .014 QPE = 8-234 TENS = 84.068 7.420 4185.523 608.100 79.263 15732.300 .000 8101.128 2,707 .037 4026.981 DEPT = ITT = CILD = 8515.000 GR = .000 ILM = 143.765 SGRD = 104.846 DT = 5.567 ILD = 5.003 TENS = 81.844 6.956 4253.471 Page 13 DLOD = 1794.493 TT21 = 424.600 TT22 = 590.000 TTll = 608.000 TT12 = 453.200 SP = 58.931 GR = 88.692 FDSN = 1617.455 NDSN = 11712.620 NPHI = .368 NRAT = 8.403 DPE = .127 DPHI = .141 DRHO = .103 FSDL = 8363.793 NSDL = 18959.160 PE' = 3.615 PELC = 4.015 QL = -.003 QS = .007 QPE = -.200 RHOB = 2.418 CALI = 9.797 TENS = 4072.279 DLOD = 1001.182 DEPT = 8415.000 GR = 38.196 DT = 84.976 ITT = .000 ILM = ~ 20000.000 ILD = 11.418 CILD = 87.582 SGRD = .100 TENS = 4117.577 DLOD = 1651.613 TT21 = 401.100 TT22 = 567.500 TT11 = . 576.800 TT12 = 404.200 SP = 43.601 GR = 38.334 FDSN = 1804.326 NDSN = 10902.790 NPHI = .321 NRAT = 7.012 DPE = 28.365 DPHI = .152 DRHO = -.519 FSDL = 2942.128 NSDL = 6-565.160 PE = 41.366 PELC = 51.815 QL = -.009 QS = .008 QPE = -5.225 RHOB = 2.399 CALI = 8.460 TENS = 3891.088 DLOD = 985.551 DEPT = 8315.000 GR = 61.402 DT = 79.368 ITT = 7.000 ILM = 20000.000 ILD = 20.874 CILD = 47.908 SGRD = .100 TENS = 4117.577 DLOD = 1667.488 TT21 = 406.100 TT22 = 538.200 TTll = 538.500 TT12 = 403.600 SP = 44.447 GR = -999.000 FDSN = -999.000 NDSN = -999.000 NPHI = -999.000 NRAT = -999.000 DPE = -999.000 DPHI = -999.000 DRHO = -999.000 FSDL = -999.000 NSDL = -999.000 PE = -999.000 PELC = -999.000 QL = -999.000 QS = -999.000 QPE = -999.000 RHOB = -999.000 CALI = -999.000 TENS = -999.000 DLOD = -999.000 ****************************************************************************** FILE TRAILER RECORD TYPE 129 FILE NAME SERVICE SUB LEVEL NAME VERSION NUMBER DATE OF'GENERATION MAX. PHYSICAL RECORD LENGTH FILE TYPE OPTIONAL NEXT FILE NAME --- COMCEN.001 --- 92/02/18 --- 1024 --- LO --- COMCEN.002 FILE HEADER RECORD' TYPE 128 FILE NAME SERVICE SUB LEVEL NAME VERSION NUMBER DATE OF GENERATION --- COMCEN. 002 --- 92/02/18 Pag~ 14 MAX. PHYSICAL RECORD LENGTH FILE TYPE OPTIONAL PREVIOUS FILE NAME --- 1024 --- LO --- COMCEN.001 ****************************************************************************** COMMENT RECORD TYPE 232 FILE HEADER FILE NUMBER: 02 DEPTH INCREMENT: 0.25 FILE SUMMARY TOOL CODE START DEPTH STOP DEPTH DIL 11489.75 FWS2 11491.75 SDL--->REPEAT #2 11515.00 DSN2-->REPEAT #2 11515.00 11297.75 11299.75 11244.75 11244.75 THIS FILE CONTAINS REPEAT SECTION DATA FOR DIL/FWS2 AND REPEAT SECTION #2 DATA FOR SDL/DSN2 LOGGING SUITES. DELTA T ANOMOLY IN SEVERAL INTERVALS CAUSING DELTA T TO STRAIGHT LINE, APPARENTLY DUE TO TRAVEL TIME LOCKING ON AN INCORRECT PEAK. LIS FORMAT DATA ****************************************************************************** INFORMATION RECORD TYPE 34 TYPE REPR sIZE CATEGORY MNEM UNITS COMPONENT 0 65 60 0 DBUN F 0 65 60 0 WN TBU G-1 RD 0 65 60 0 CN UNOCAL 0 65 60 0 FN MCARTHUR RIVER 0 65 60 0 LONG .0000 0 65 60 0 LATI .0000 0 65 60 0 SECT 29 0 65 60 0 TOWN 09N 0 65 60 0 RANG 13W 0 65 60 0 COUN KENAI 0 65 60 0 STAT ALASKA 0 65 60 0 CTRY USA Page 15 0 65 60 0 LUN 9000 0 65 60 0 RUN 1 0 65 60 0 APIN 501332003701 0 65 60 0 MRT .0000 0 65 60 0 ST .0000 0 65 60 0 UNIT DEGF 0 65 60 0 RMFB .0000 0 65 60 0 RMCB .0000 0 65 60 0 EDP .0000 0 65 60 0 DMF KB 0 65 60 0 LMF KB 0 65 60 0 CBD1 8450.0000 0 65 60 0 CBF .0000 0 65 60 0 APD 103.0000 0 65 60 0 EUCF IN 0 65 60 0 PD . MSL 0 65 60 0 DD 11506.0000 INFORMATION RECORD TYPE 34 TYPE REPR SIZE CATEGORY MNEM UNITS COMPONENT 0 65 60 0 SON 0 65 60 0 FL 0 65 60 0 LUL 0 65 60 0 OSl 0 65 60 0 ENGI 0 65 60 0 WITN 0 65 60 0 TLAB 0 65 60 0 BHT 0 65 60 0 DFT 137214 1886' FSL & 1386' FEL STERLING DIGL/FWS2/GR WASHER/MCKAY MCCALL/KILOH 630 170.0000 PHPA POLYMER Page 16 0 65 60 0 DFD 71.0000 0 65 60 0 DFV 54.0000 0 65 60 0 DFPH 9.0000 0 65 60 0 DFL 7.0000 0 65 60 0 MST 66.0000 0 65 60 0 RMS .4500 0 65 60 0 MFST 70.0000 0 65 60 0 RMF .2500 0 65 60 0 MCST 66.0000 0 65 60 0 RMC .7000 0 65 60 0 RMB .1800 0 . 65 60 0 EKB 103.0000 0 65 60 0 BS 8.5000 0 65 60 0 CBL1 8453.0000 0 65 60 0 CS 9.6250 0 65 60 0 CWl 47.0000 0 65 60 0 CSD 8450.0000 0 65 60 0 BLI 11479.0000 0 65 60 0 TLI 8453.0000 0 65 60 0 DATE 02-11-92 0 65 60 0 TCS 30 0 65 60 0 DL 11481.0000 0 65 60 0 MSS PIT 0 65 60 0 MFSS MEAS. DATUM FORMAT SPECIFICATION RECORD TYPE 64 ENTRY BLOCKS: TYPE SIZE REPR. CODE ENTRY 1 1 66 0 2 1 66 0 Pag~ 17 3 2 79 136 4 1 66 1 5 1 66 1 8 4 73 30 9 4 65 .liN 11 2 79 7 12 4 68 -999.000 14 4 65 F 15 1 66 68 16 1 66 1 0 1 66 0 DATUM SPECIFICATION BLOCKS: MNEM SERVID SERVICE~ UNITS API CODE FILE# SIZE ~SAMP REPR. DEPT F 00000000 0 4 1 68 GR FWS2 137214 GAPI 00000000 0 4 I 68 DT FWS2 137214 US/F 00000000 0 4 1 68 ITT FWS2 137214 00000000 0 4 1 68 ILM DIL 137214 OHMM 00000000 0 4 1 68 ILD DIL 137214 OHMM 00000000 0 4 1 68 CILD DIL 137214 MMHO 00000000 0 4 1 68 SGRD DIL 137214 OHMM 00000000 0 4 1 68 TENS FWS2 137214 LB 00000000 0 4 I 68 DLOD FWS2 137214 LB '00000000 0 4 1 68 TT21 FWS2 137214 00000000 0 4 1 68 TT22 FWS2 137214 00000000 0 4 1 68 TTll FWS2 137214 00000000 0 4 1 68 TT12 FWS2 137214 00000000 0 4 i 68 SP DIL 137214 00000000 0 4 1 68 GR SDL 137214 GAPI 00000000 0 4 1 68 FDSN DSN2 137214 CPS 00000000 0 4 1 68 NDSN DSN2 137214 CPS 00000000 0 4 1 68 NPHI DSN2 137214 DECP 00000000 0 4 1 68 NRAT DSN2 137214 C/C 00000000 0 4 1 68 DPE SDL 137214 00000000 0 4 1 68 DPHI SDL 137214 DECP 00000000 0 4 1 68 DRHO SDL 137214 G/C3 00000000 0 4 1 68 FSDL SDL 137214 CPS 00000000 0 4 1 68 NSDL SDL 137214 CPS 00000000 0 4 1 68 PE SDL 137214 00000000 0 4 1 68 PELC SDL 137214 00000000 0 4 1 68 QL SDL 137214 00000000 0 4 1 68 QS SDL 137214 00000000 0 4 1 68 QPE SDL 137214 00000000 0 4 1 68 RHOB SDL 137214 G/C3 00000000 0 4 1 68 CALI SDL 137214 IN 00000000 0 4 1 68 TENS SDL 137214 LB 00000000 0 4 1 68 DLOD. SDL 137214 LB 00000000 0 4 1 68 ****************************************************************************** DATA RECORD TYPE 0 DEPT = 11515.000 GR = -999.000 DT = -999.000 ITT = -999.000 ILM = -999.000 ILD = -999.000 CILD = -999.000 SGRD = -999.000 TENS = -999.000 Page 18 DLOD = TT11 = GR = NPHI = DPHI = NSDL = QL = DLOD = -999.000 TT21 = -999.000 TT22 = -999.000 -999.000 TT12 = -999.000 SP = -999.000 57.134 FDSN = 2047.074 NDSN = 12068.660 .335 NRAT = 6.842 DPE = .534 .710 · DRHO = .063 FSDL = 37591.910 23618.430 PE = 6.190 PELC = 5.923 .107 QS = -.324 QPE = .134 1.479 CALI = 3.518 TENS = 3234.269 -6.167 DEPT = ITT = CILD = DLOD = TT11 = GR = NPHI = DPHI = NSDL = QL = DLOD = 11415.000 GR = 44.336 DT = 64.652 .000 ILM = 7.586 ILD = 8.652 115.575 SGRD = 17.448 TENS = 5680.354 1798.462 TT21 = 442.100 TT22 = 592.400 534.900 TT12 = 362.000 SP = 48.224 49.885 FDSN = 3032.820 NDSN = 14615.510 .239 NRAT = 5.592 DPE = .096 .063 DRHO = .075 FSDL = 6405.238 17645.980 PE = 4.033 PELC = 4.095 .036 QS = .002 QPE = -.031 2.546 CALI = 8.667 TENS = 5544.460 1187.889 DEPT = 11315.000 GR = 54.580 DT = 77.868 ITT = .000 ILM = 9.221 ILD = 11.247 CILD = 88.909 SGRD = 11.259 TENS = 5601.082 DLOD = 1794.493 TT21 = 448.400 TT22 = 630.400 TTll = 601.100 TT12 = 432.300 SP = 37.202 GR = 47.190 FDSN = 1490.753 NDSN = 11908.600 NPHI = .419 NRAT = 9.270 DPE = .055 DPHI = .148 DRHO = .074 FSDL = 8243.350 NSDL = 18438.070 PE = 3.112 PELC = 3.252 QL = -.039 QS = .014 QPE = -.070 RHOB = 2.407 CALI = 9.279 TENS = 5397.242 DLOD = 1053.286 ****************************************************************************** FILE TRAILER RECORD TYPE 129 FILE NAME SERVICE SUB LEVEL NAME VERSION NUMBER DATE OF GENERATION MAX. PHYSICAL RECORD LENGTH FILE TYPE OPTIONAL NEXT FILE NAME --- COMCEN.002 --- 92/02/18 --- 1024 --- LO --- COMCEN.O03 ******************************************************************************* FILE HEADER RECORD TYPE 128 FILE NAME SERVICE SUB LEVEL NAME VERSION NUMBER DATE OF GENERATION --- COMCEN. 003 --- 92/02/18 Page 19 MAX. PHYSICAL RECORD LENGTH FILE TYPE OPTIONAL PREVIOUS FILE NAME --- 1024 --- LO --- COMCEN.002 ****************************************************************************** COMMENT RECORD TYPE 232 FILE HEADER FILE.NUMBER: 03 DEPTH INCREMENT: 0.25 FILE SUMMARY TOOL CODE START DEPTH STOP DEPTH SDL--->REPEAT ~1 11515.00 11272.50 DSN2-->REPEAT #1 11515.00 11272.50 REMARKS: THIS FILE CONTAINS REPEAT SECTION #1 DATA FOR SDL/DSN2 LOGGING SUITES. LIS FORMAT DATA ****************************************************************************** INFORMATION RECORD UNITS TYPE 34 COMPONENT F TBU G-1 RD UNOCAL MCARTHUR RIVER .0000 .0000 29 09N 13W KENAI ALASKA USA 9000 1 501332003701 TYPE REPR SIZE CATEGORY MNEM 0 65 60 0 DBUN 0 65 60 0 WN 0 65 60 0 CN 0 65 60' 0 FN 0 65 60 0 LONG 0 65 60 0 LATI 0 65 60 0 SECT 0 65 60 0 TOWN 0 65 60 0 RANG 0 65 60 0 COUN 0 65 60 0 STAT 0 65 60 0 CTRY 0 65 60 0 LUN 0 65 60 0 RUN 0 65 60 0 APIN Page 20 0 65 60 0 MRT 0 65 60 0 ST 0 65 60 0 UNIT 0 65 60 0 RMFB 0 65 60 0 RMCB 0 65 60 0 EDP 0 65 60 0 DMF 0 65' 60 0 ~ 0 65 60 0 CBD1 0 65 60 0 CBF 0 65 60 0 APD 0 65 60 0 EUCF 0 65 60 0 PD 0 65 60 0 DD DEGF KB IN MSL .0000 .0000 .0000 .0000 .0000 8450.0000 .0000 103.0000 11506.0000 ****************************************************************************** INFORMATION RECORD TYPE 34 TYPE REPR SIZE CATEGORY MNEM UNITS COMPONENT 0 65 60 0 SON 137214 0 65 60 0 FL 1886' FSL 0 65 60 0 LUL STERLING 0 65 60 0 OS1 DIGL/FWS2/GR 0 65 60 0 ENGI WASHER/MCKAY 0 65 60 0 WITN MCCALL/KILOH 0 65 60 0 TLAB 630 0 65 60 0 BHT 170.0000 0 65 60 0 DFT PHPA POLYMER 0 65 60 0 DFD 71.0000 0 65 60 0 DFV 54.0000 0 65 60 0 DFPH 9.0000 & 1386' FEL Page 21 0 65 60 0 DFL 7.0000 0 65 60 0 MST 66.0000 0 65 60 0 RMS .4500 0 65 60 0 MFST 70.0000 0 65 60 0 RMF .2500 0 65 60 0 MCST 66.0000 0 65 60 0 RMC .7000 0 65 60 0 RMB .1800 0 65 60 0 EKB 103.0000 0 65 60 0 BS 8.5000 0 65 60 0 CBL1 8453.0000 0 65 60 0 CS 9.6250 0 65 60 0 CWl 47.0000 0 65 60 0 CSD 8450.0000 0 65 60 0 BLI 11479.0000 0 65 60 0 TLI 8453.0000 0 65 60 0 DATE 02-11-92 0 65 60 0 TCS 30 0 65 60 0 DL 11481.0000 0 65 60 0 MSS PIT 0 65 60 0 MFSS MEAS. DATUM FORMAT SPECIFICATION RECORD TYPE 64 ENTRY BLOCKS: TYPE SIZE REPR. CODE ENTRY 1 1 66 0 2 1 66 0 3 2 79 80 4 1 66 1 5 1 66 1 8 4 73 30 9 4 65 .liN Page 22 11 2 79 12 12 4 68 -999.000 14 4 65 ~ 15 I 66 68 16 I 66 1 0 i 66 0 DATUM SPECIFICATION BLOCKS: MNEM SERVID SERVICES UNITS API CODE FILES SIZE #SAMP REPR. DEPT F 00000000 0 4 1 68 GR SDL 137214 GAPI 00000000 0 4 1 68 FDSN DSN2 137214 CPS 00000000 0 4 1 68 NDSN DSN2 137214 CPS 00000000 0 4 i 68 NPHI DSN2 137214 DECP 00000000 0 4 1 68 NRAT DSN2 137214 C/C 00000000 0 4 I 68 DPE SDL 137214 00000000 0 4 1 68 DPHI SDL 137214 DECP 00000000 0 4 1 68 DRHO SDL 137214 G/C3 00000000 0 4 1 68 FSDL SDL 137214 CPS 00000000 0 4 i 68 NSDL SDL 137214 CPS 00000000 0 4 i 68 PE SDL 137214 00000000 0 4 1 68 PELC SDL 137214 00000000 0 4 i 68 QL SDL 137214 00000000 0 4 1 68 QS SDL 137214 00000000 0 4 1 68 QPE SDL 137214 00000000 0 4 I 68 RHOB SDL 137214 G/C3 00000000 0 4 1 68 CALI SDL 137214 IN 00000000 0 4 i 68 TENS SDL 137214 LB 00000000 0 4 i 68 DLOD SDL 137214 LB 00000000 0 4 i 68 ****************************************************************************** DATA RECORD TYPE 0 DEPT = 11509.250 GR = 52.739 FDSN = 2130.622 NDSN = 12155.610 NPHI = .352 NRAT = 6.621 DPE = 6.153 DPHI = .715 DRHO = -.029 FSDL= 37773.910 NSDL = 22707.430 PE = 9.436 PELC = 10.499 QL = -.050 QS = .058 QPE = -.531 RHOB = 1.470 CALI = 8.500 TENS = 1773.412 DLOD = 9.898 DEPT = 11409.250 GR = 43.356 FDSN = 1791.407 NDSN = 12548.400 NPHI = .369 N-RAT = 8.129 DPE = .001 DPHI = .286 DRHO = .030 FSDL = 11030.020 NSDL = 18954.250 PE = 2.850 PELC = 2.822 QL = .006 QS = .028 QPE = .014 RHOB = 2.179 CALI = 8.659 TENS = 5578.434 DLOD = 1102.785 DEPT = 11309.250 GR = 105.038 FDSN = 1521.594 NDSN = 11993.030 NPHI = .424 NRAT = 9.147 DPE = .079 DPHI = .084 DRHO = .047 FSDL = 6318.572 NSDL = 17141.980 PE = 4.341 Page 23 a:tlt:~I, NflO::)N.~ ~a~.T. &O tIN~ 8~/~0/~6 --- N~OHOO --- m~ 0~I --- ~0I --- 8~/~0/~6 --- £ 00 ' HHOHO~ --- .............................. (IHOOHH H~I~ HTI& ~EO'6 = I'I~O 6S0' = SO S££'~I = ac)Ia IIS'~ = 80H~ 6£0' = ~O TOO'£OLS = SNH~ Sit' = EEO