The URL can be used to link to this page

Home My WebLink About165-021CAUTION: 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:McLellan, Bryan J (OGC) To:Jerry Lau Cc:Donna Ambruz Subject:RE: NFU 41-35 IA Cement Plug - Sundry 325-707 (PTD #165-021) Date:Wednesday, February 4, 2026 11:05:00 AM Jerry, The proposed change is approved. Welcome to the Kenai team! Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Jerry Lau <jerry.lau@hilcorp.com> Sent: Tuesday, February 3, 2026 3:23 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: NFU 41-35 IA Cement Plug - Sundry 325-707 (PTD #165-021) Bryan, I am taking over duties from Scott Warner for his wells, as he is transitioning to the PBU team. For the NFU 41-35 IA cement plug scope, I am planning to use 15.3 PPG cement in lieu of the 12.5 PPG cement listed on the 10-403. I prefer the higher compressive strength and improved mechanical properties of the 15.3 PPG system, particularly since we plan to use the cement plug for isolation above the production packer and subsequently perforate through it. From a wellbore integrity standpoint, significant surface pressure would be required on the IA to approach casing burst. During pumping and cementing operations, the IA will be open to tanks to ensure wellbore integrity is maintained. Please let me know if you have any questions or would like to discuss further. I look forward to working with you. Regards, Jerry Lau Hilcorp – Kenai Operations Engineer Cell: (907) 360-6233 Office: (907) 564-5280 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 herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis 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 Other: IA Sqz/CTCO w/N2 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 12,812' 9,960' Casing Collapse Structural Conductor Surface 1,540psi Intermediate 3,810psi Production Liner 6,210psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Baker S3 Pkr; Baker Model D Pkr; N/A 7,966' MD/TVD; 8,496' MD/TVD; N/A, N/A 12,812' 10,009' 10,009' North Fork Tyonek Gas 20" 13-3/8" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 North Fork Unit (NFU) 41-35CO 720 Same 2951psi N/A Length November 27, 2025 10,985'2,529' 2-7/8" 10,985' Perforation Depth MD (ft): 8,451' 7" See Attached Schematic 6,330psi 3,090psi 246' 8,451' 246' 2,000' Size 246' 9-5/8"8,435' 1,904' MD Hilcorp Alaska, LLC Proposed Pools: 6.5# / N-80 TVD Burst 8,512' 2,000' Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 391210 165-021 50-231-10004-00-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Scott Warner, Operations Engineer AOGCC USE ONLY 9,960psi Tubing Grade: scott.warner@hilcorp.com 907-564-4506 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: m n P s 66 t 2 c N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.11.17 17:03:46 - 09'00' Noel Nocas (4361) 325-707 By Grace Christianson at 9:16 am, Nov 18, 2025 BJM 11/19/25 SFD 11/19/2025 X submit CBL to AOGCC and obtain approval before perforating Perforate CT BOP test to 3000 psi 10-404 Perform MIT on 2-7/8 x 9-5/8 annulus to 2200 psi once job is complete and well has been brought online within 30 days. DSR-11/19/25 11/20/25 Well Prognosis Well Name: NFU 41-35 API Number: 50-231-10004-00-00 Current Status: Producing Gas Well Permit to Drill Number: 165-021 Regulatory Contact: Donna Ambruz (907) 777-8305 First Call Engineer: Scott Warner (661) 487-0871 Second Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Maximum Expected BHP: 3820 psi @ 8683 TVD Based on 0.44 psi/ft Max. Potential Surface Pressure:2951 psi Based on 0.1 psi/ft gas gradient to surface Applicable Frac Gradient: 0.85 psi/ft using 16.4 ppg EMW LOT at the 7-5/8 int. casing shoe (LOT from offset 14-25. Unable to obtain FIT data from 41-35) (FIT from offset 42-35- 17.5 ppg EMW at the 9-5/8 surf casing shoe) Shallowest Allowable Perf TVD: MPSP/(0.85-0.1) = 2951 psi / 0.75 = 3934 TVD (Will not perforate above top of pool @ 4840 TVD) Top of Applicable Gas Pool: 4840 MD/ 4840 TVD Well Status: Producing Gas Well Currently producing 210 mcfd, 30 bwpd, @ 65 psi FTP Brief Well Summary North Fork 41-35 is a vertical well that was drilled, tested, completed, and shut in by SoCal in 1965. The well was re-entered and tested in 2001. After various ownership changes, facility and pipeline installations the well began producing in 2011. Production has been from the T-48, T-47, and T-40 sands only during the lifetime of the well. A plug was set in 2022 to isolate the T-47 and T-48 which shut of 10-20 bwpd and potentially ~230 mscf. The plug was milled in August 2025 and increased gas and water production to pre plug set rates. The purpose of this Sundry is to perform an IA packer squeeze to allow T-2A through T-36 up hole perforations. Notes Regarding Wellbore Deviation o Max deviation: 2° @ 9956 MD Min ID o 2.34 at 2300 MD (chemical inj sub) o 2-7/8 tubing jet cut @ 8512 Use caution when exiting/entering tubing Recent Tags o 8/29/25: CT milled cement and CIBP at 8375. Chased to 9000 and did not tag o 6/8/25: SL drift w/ 2.25 OD SB- SD @ 7966 WLM. RIH w/ 2 SB tagged at 8361 WLM E-line Procedure: 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250 psi low / 3,000 psi high o Recent SITP did not exceed 2100 psi 3. RIH with 2-7/8 Composite Bridge Plug and set at ~ 7960 MD o Do not set plug across collars o Tubing tally shows collars at ~7957 & 7965 MD Use 15.1 ppg EMW at 9-5/8" csg shoe for shallowest allowable perf calculation per Scott Warner's attached email. -bjm (FIT from offset 42-35- 17.5 ppg EMW at the 9-5/8 surf casing shoe) Well Prognosis 4. MU and RIH w/ tubing punch 5. Punch 2-7/8 tubing @ 7955-7950 o Packer is at 7966 MD 6. RU pump truck 7. Establish circulation from tubing to IA o 9.0 ppg brine expected to be on the backside from workover in 2010 o Burst pressure of 9-5/8 casing is 6330 psi. Do not exceed 1300 psi surface pressure without discussing with OE o If circulation cannot be established, additional tubing punches may be needed 8. Once circulation is established in both directions, circulate a minimum of 580 bbls of freshwater (until returns are clean): o IA volume = ~528 bbls i. 2-7/8 x 9-5/8 = 0.0664 bbl/ft x 7955 ft = ~528 bbls o Tubing volume = 0.0058 bbl/ft x 7960 ft = ~46 bbls 9. CMIT-TxIA to 1500psi (no chart required) o Verify casing and CBP integrity ahead of cement squeeze 10. RDMO Eline and pump truck 2-7/8 x 9-5/8 Fullbore Cementing and Coil Tubing Procedure: 1. RU cement truck, PT lines to 250 psi low / 4,000 psi high 2. Mix and pump ~12.5 ppg cement, taking returns up the 2-7/8 x 9-5/8 annulus o Manage IA back pressure to keep the cement from running away down tubing as needed 3. Planned TOC in IA is ±4,800 MD. (±210 bbls required) o 0.0664 bbl/ft x 3155 ft = ~210 bbls 4. Displace with 46 bbls of freshwater to CBP/ tubing punches o 0.0058 bbl/ft x 7960 ft = ~46 bbls o Use wiper ball down tubing 5. Hold ~670 psi on the tubing with the annulus pressure at 0 psi to ensure cement doesnt u-tube o IA contains: i. 3,155 of cement @ 12.5 ppg = 2,051 psi ii. 4,800 of freshwater @ 8.4 ppg = 2,096 psi o Tubing contains: i. 7,960 of freshwater @ 8.4 ppg = 3,477 psi 6. RDMO cementers 7. Wait for a minimum of 48 hrs on cement 8. MIRU EL and pressure control equipment 9. PT lubricator to 250psi Low / 3,000 psi High 10. RIH and tag TOC and complete CBL (submit CBL to AOGCC and obtain approval before perforating) 11. RD EL 12. MIRU CTU and provide 24 hour notice for BOP Test. 13. Conduct BOP test 250 psi low, 3000 psi high. 14. RIH w/ motor and mill 15. Mill cement, composite bridge plug and push to jet cut @ 8512 MD- POOH o Mill any restrictions/cement stringers found in tubing during the CBL o Pressure below CBP could be ~2500 psi 16. RIH w/nozzle, tag milled composite plug and push to bottom Well Prognosis o Bent motor and jars exiting the tubing in August 2025- RIH w/ drift/nozzle assembly only o Composite plug may have fallen to bottom. Ensure tubing/liner is free of restrictions to minimum of ~9000 MD 17. Reverse lift water from wellbore o Recovered 84 bbls of fluid post milling operations in August 2025 18. Trap N2 pressure on tubing per OE/RE recommendation for perforating. 19. RDMO CTU E-line Procedure: 20. MIRU E-line and pressure control equipment 21. PT lubricator to 250 psi low / 3,000 psi high 22. RIH and perforate T-2A T-36 sands from bottom up: Zone Top MD Btm MD Top TVD Btm TVD Footage T2A 5,075' 5,095' 5,075' 5,095' 20' T4 5,275' 5,300' 5,275' 5,300' 25' T4 5,345' 5,380' 5,345' 5,380' 35' T5 5,434' 5,459' 5,434' 5,459' 25' T7 5,685' 5,720' 5,685' 5,720' 35' T21 6,663' 6,683' 6,663' 6,683' 20' T21 6,696' 6,716' 6,696' 6,716' 20' T22 6,759' 6,769' 6,759' 6,769' 10' T36 7,616' 7,630' 7,613' 7,630' 14' o Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation o Use Gamma/CCL to correlate o Record Tubing pressures before and after each perforating run at 5 min, 10 min, and 15 min intervals post perf shot (if using switched guns, wait 10 min between shots) o Pending well production, all perf intervals may not be completed o If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations. o If necessary, use nitrogen to pressure up well during perforating or to depress water prior to setting a plug above perforations 23. RDMO 24. If necessary, run cap string to aid with water production if encountered post perforating. Post Perforation MIT: 1. Perform MIT on 2-7/8 x 9-5/8 annulus to 2200 psi once job is complete and well has been brought online within 30 days. Attachments: 1. Current schematic 2. Proposed Schematic 3. Coil Tubing BOP Schematic 4. Standard Well procedure N2 Operations Updated by DMA 09-17-25 SCHEMATIC North Fork Unit NFU 41-35 PTD: 165-021 API: 50-231-10004-00-00 PBTD = 10,913 MD TD = 12,812 MD RKB to GL = 15 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 20 Conductor 79 B Weld 15.01 Surf 246 13-3/8 Surf Csg 61/68 J-55 BTC 12.415 Surf 2,000 9 5/8 Intermediate Csg 43.5 N-80/P-110 BTC 8.755 Surf 8,451 7 Production Liner 26 P-110 BTC 6.276 8,330 10,985 2 7/8 Production Tubing 6.5 N-80 EUE 8RD 2.441 Surf 8,512 (jet cut) JEWELRY DETAIL No. Depth ID OD Item 1 2,300 Chemical Injection Sub ¼ SS injection line 2 6,310 DV Tool 3 7,966 2.875 8.755 9-5/8 Baker S-3 Packer 4 7,985 2.31 2-7/8 Sliding Sleeve (Opened 10/1/22). Sliding sleeve opens UP. 5 7,993 (3) 2 7/8 Blast Joints (7,993-8,052) 6 8,330 7.000 8.755 Liner top packer / Brown tie-back sleeve 7 8,496 2.875 6.276 7 Baker Model D packer 8 9,000 Junk- milled CIBP 8/29/25 9 9,960 Junk- Partially milled retainer @ 9,960 10 9,975 2.312 2.875 Fish- 2 7/8 6.5 tubing, BXN nipple, WLEG. 34 OAL 11 10,173 - 6.276 Whipstock @ 10,173 OPEN HOLE / CEMENT DETAIL 26 Est. TOC @ Surface. 625 sacks cement. 18-5/8 Est. TOC @ Surface. 2000 sacks cement. 12-1/4 Est. TOC @ 6,920. 800 sacks cement around shoe and 750 sacks cement through DV @ 6,313 (Est. TOC through DV @ 4,600). 8-5/8 Est. TOC @ 8,330. 900 sacks cement around shoe and 100 sacks cement squeezed at liner lap. 6 1/8 Sidetrack Est. TOC 10,009. 38 sacks cement plug from 10,859-10,654. 52 sacks cement plug from 10,250-10,009. PERFORATIONS Sand Top MD Btm MD Top TVD Btm TVD Amt Date Comments T-40 7,972 7,980 7,972 7,980 8' 12/7/22 Open T-40 8,005 8,045 8,005 8,045 40' 12/12/1965 (8/21/2010 11/13/2022) Open (reperfd 2x) T-47 8,512 8,531 8,512 8,531 19' 8/29/2025 Open T-47 8,530 8,540 8,530 8,540 10' 12/7/1965 Squeezed (prior to DST) T-47 8,563 8,602 8,563 8,602 39' 08/29/2025 Open T-48 8,683 8,690 8,683 8,690 7' 08/09/2025 Open Hemlock 10,805 10,860 10,805 10,860 55 11/11/1965 Isolated 20 Conductor 9-5/8 Csg 18-5/8 hole 7 Liner 8-5/8 hole 1 13-3/8 Csg 12-1/4 hole 9 6 1/8 Sidetrack PBTD = 10,009 TD = 10,859 MD 2 3 4 5 6 6 7 10 11 Max Deviation 2 deg @ 9,956 MD 8 Updated by SRW 11-10-25 PROPOSED North Fork Unit NFU 41-35 PTD: 165-021 API: 50-231-10004-00-00 PBTD = 10,913 MD TD = 12,812 MD RKB to GL = 15 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 20 Conductor 79 B Weld 15.01 Surf 246 13-3/8 Surf Csg 61/68 J-55 BTC 12.415 Surf 2,000 9 5/8 Intermediate Csg 43.5 N-80/P-110 BTC 8.755 Surf 8,451 7 Production Liner 26 P-110 BTC 6.276 8,330 10,985 2 7/8 Production Tubing 6.5 N-80 EUE 8RD 2.441 Surf 8,512 (jet cut) JEWELRY DETAIL No. Depth ID OD Item 1 2,300 Chemical Injection Sub ¼ SS injection line 2 6,310 DV Tool 3 7,966 2.875 8.755 9-5/8 Baker S-3 Packer 4 7,985 2.31 2-7/8 Sliding Sleeve (Opened 10/1/22). Sliding sleeve opens UP. 5 7,993 (3) 2 7/8 Blast Joints (7,993-8,052) 6 8,330 7.000 8.755 Liner top packer / Brown tie-back sleeve 7 8,496 2.875 6.276 7 Baker Model D packer 8 9,000 Junk- milled CIBP 8/29/25 9 9,960 Junk- Partially milled retainer @ 9,960 10 9,975 2.312 2.875 Fish- 2 7/8 6.5 tubing, BXN nipple, WLEG. 34 OAL 11 10,173 - 6.276 Whipstock @ 10,173 OPEN HOLE / CEMENT DETAIL 26 Est. TOC @ Surface. 625 sacks cement. 18-5/8 Est. TOC @ Surface. 2000 sacks cement. 12-1/4 Est. TOC @ 6,920. 800 sacks cement around shoe and 750 sacks cement through DV @ 6,313 (Est. TOC through DV @ 4,600). 8-5/8 Est. TOC @ 8,330. 900 sacks cement around shoe and 100 sacks cement squeezed at liner lap. 6 1/8 Sidetrack Est. TOC 10,009. 38 sacks cement plug from 10,859-10,654. 52 sacks cement plug from 10,250-10,009. PERFORATIONS Sand Top MD Btm MD Top TVD Btm TVD Amt Date Comments T2A 5,075' 5,095' 5,075' 5,095' 20' TBD Proposed T4 5,275' 5,300' 5,275' 5,300' 25' TBD Proposed T4 5,345' 5,380' 5,345' 5,380' 35' TBD Proposed T5 5,434' 5,459' 5,434' 5,459' 25' TBD Proposed T7 5,685' 5,720' 5,685' 5,720' 35' TBD Proposed T21 6,663' 6,683' 6,663' 6,683' 20' TBD Proposed T21 6,696' 6,716' 6,696' 6,716' 20' TBD Proposed T22 6,759' 6,769' 6,759' 6,769' 10' TBD Proposed T36 7,616' 7,630' 7,613' 7,630' 14' TBD Proposed T-40 7,972 7,980 7,972 7,980 8' 12/7/22 Open T-40 8,005 8,045 8,005 8,045 40' 12/12/1965 (8/21/2010 11/13/2022) Open (reperfd 2x) T-47 8,512 8,531 8,512 8,531 19' 8/29/2025 Open T-47 8,530 8,540 8,530 8,540 10' 12/7/1965 Squeezed (prior to DST) T-47 8,563 8,602 8,563 8,602 39' 08/29/2025 Open T-48 8,683 8,690 8,683 8,690 7' 08/09/2025 Open Hemlock 10,805 10,860 10,805 10,860 55 11/11/1965 Isolated 20 Conductor 9-5/8 Csg 18-5/8 hole 7 Liner 8-5/8 hole 1 13-3/8 Csg 12-1/4 hole 9 6 1/8 Sidetrack PBTD = 10,009 TD = 10,859 MD 2 3 4 5 6 6 7 10 11 Max Deviation 2 deg @ 9,956 MD 8 STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 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:Scott Warner To:Davies, Stephen F (OGC) Cc:Dewhurst, Andrew D (OGC); Starns, Ted C (OGC); McLellan, Bryan J (OGC); McKensie Neely Subject:RE: [EXTERNAL] NFU 41-35 (PTD 165-021, Sundry 325-707) - Questions Date:Wednesday, November 19, 2025 12:46:01 PM Attachments:image001.png image002.png image003.png image004.png image006.png image007.png Steve, For 14-25 I used the FIT from the 7-5/8 intermediate casing shoe since that is a closer depth to where we will be perforating in 41-35 rather than the surface casing shoe. For 42-35 I used the higher FIT test due to that being the initial test they got before drilling ahead and starting another FIT where they achieved a 15.1. Looking back I should have used the 15.1 EMW which would still allow a shallowest allowable perf at ~4307 TVD. As for 32-35 that is what I am seeing in our records as well. Drilling records noted that they drilled to 5810 days prior to setting the 7 casing and had multiple tight spots that required cleanouts and spotted a 20 bbl 16 ppg heavy pill on bottom prior to running and cementing the casing which wouldve filled the hole from 5810-5526. The hole was drilled out to the 5810 after cementing the casing in at 5570. Due to the number of open hole cleanouts prior to running the casing and performing the LOT, I expect the hole was washed out more than usual which led to reduced formation strength in this instance especially since it is abnormally low for this region. They also drilled out past the shoe 240 before pulling up into the shoe to perform the LOT which is not standard practice and exposed a larger surface area to the mud pressure than normal/other wells in the area. Thanks, Scott Warner Kenai Operations Engineer Office: (907) 564-4506 Cell: (907) 830-8863 1McLellan, Bryan J (OGC)From:Scott Warner <scott.warner@hilcorp.com>Sent:Wednesday, November 19, 2025 10:10 AMTo:McLellan, Bryan J (OGC)Subject:RE: [EXTERNAL] NFU 41-35 (PTD 165-021) cement sundryBryan, A CBL was run on 10/5/65 and all subsequent reports noted a TOC of 4600. Unfortunately I havent had any luck nding this CBL to verify that TOC. I did the following calculaons to help verify that cement pick. 750 sacks or 134 bbls were pumped for the 2nd stage cement job in the 9-5/8 through the DV tool and was displaced with 469 bbls. 9-5/8 capacity to 6310 is 470 bbls. 12-1/4 hole x 9-5/8 casing capacity is .0558 bbl/. They had full circulaon while displacing the cement and did not note any losses. In a perfect cement job, 134 bbls of cement in the annulus, displaced by 469 bbls should yield a TOC of 3909. 134 bbls / .0558 bbl/ = 2401 of cement 6310-2401 = 3909 est TOC If you assume a worst case given no losses were noted and 40% washout, that would yield a TOC of 4870. 134 bbls / .0558 bbl/ =2401 of cement 2401 x (0.6) = 1440 of cement 6310-1440 = 4870 est TOC I kept esmated TOC on the schemac at 4600 due to that being within the above calculaons and it is reasonable to believe the 4600 TOC pick came from the CBL that was run and also coincides with roughly ~30% washout. Scott Warner 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. 2Kenai Operations Engineer Office: (907) 564-4506 Cell: (907) 830-8863 To help protect your privacy, Microsoft Office prevented automatic download of this picture from the Internet. From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, November 18, 2025 3:30 PM To: Scott Warner <scott.warner@hilcorp.com> Subject: [EXTERNAL] NFU 41-35 (PTD 165-021) cement sundry Scott, Im reviewing the sundry application and have a question. How did you estimate the TOC above the DV tool outside 9-5/8 casing to be 4600 MD? Please send calculations? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 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. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 3While 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 notadversely 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. From:Davies, Stephen F (OGC) To:Scott Warner Cc:Dewhurst, Andrew D (OGC); Starns, Ted C (OGC); McLellan, Bryan J (OGC) Subject:NFU 41-35 (PTD 165-021, Sundry 325-707) - Questions Date:Wednesday, November 19, 2025 9:34:00 AM Attachments:image002.png image004.png image006.png image014.png Hello Scott, I'm conducting the geology portion of AOGCC's review for NFU 41-35, and I'm curious. Hilcorp's application provides the following applicable frac gradient information: Since NFU 41-35 is a very old well, the sparse records for it do not report any FIT /LOT information. So, we're forced to rely on data reported from offset wells. I quickly reviewed AOGCCs Well History Records for each of the NFU wells and found the following FIT / LOT data points: I could not find Hilcorps 16.4 ppg value for NFU 14-25 (PTD 210-111). Instead, I found the following: I also could not find Hilcorps 17.5 ppg value for NFU 42-35 (PTD 214-170). This is what I found in AOGCCs files: Hilcorps records may be more complete for these wells. Could you please provide references to where I can find those values? I also note that NFU 32-25 (PTD 210-088) reported a LOT of 12.8 ppg EMW from 5830 MD / 5028' TVD, which is about the same depth as, and about 1000' south of, Hilcorps shallowest proposed perforation at 5075 MD / TVD. I'm curious about that LOT value too, which seems abnormally low. Was that test instead an FIT? If not, do you have any additional information or thoughts about why that value is so low? Are Hilcorps records more complete for NFU 32-25 than AOGCCs? If so, please provide or point out that information for me in the Well History File. Hilcorp's estimated date for commencing operations in NFU 41-35 is November 27th. I will be on vacation beginning tomorrow, so a quick reply is appreciated. Please also copy Andy Dewhurst and Ted Starns with your reply. Thanks for Your Help and Be Well, Steve Davies Senior Petroleum Geologist AOGCC 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 Steve Davies at 907-793-1224 or steve.davies@alaska.gov 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: N2, Mill CIBP 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): 12,812'9,960' Casing Collapse Structural Conductor Surface 1,540psi Intermediate 3,810psi Production Liner 6,210psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng scott.warner@hilcorp.com 907-564-4506 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Scott Warner, Operations Engineer AOGCC USE ONLY 9,960psi Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 391210 165-021 50-231-10004-00-00 Hilcorp Alaska, LLC Proposed Pools: 6.5# / N-80 TVD Burst 8,512' 2,000' Size 246' 9-5/8"8,435' 1,904' MD 7" See Attached Schematic 6,330psi 3,090psi 246' 8,451' 246' 2,000' July 31, 2025 10,985'2,529' 2-7/8" 10,985' Perforation Depth MD (ft): 8,451' 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 North Fork Unit (NFU) 41-35CO 720 Same ~2951 N/A Length Baker S3 Pkr; Baker Model D Pkr; N/A 7,966' MF/TVD; 8,496' MD/TVD; N/A, N/A 12,812'10,009'10,009' North Fork Tyonek Gas 20" 13-3/8" See Attached Schematic m n P s R 66 t c 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 1:14 pm, Jul 22, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.07.22 12:34:17 - 08'00' Noel Nocas (4361) 325-433 CT BOP test to 3000 psi X DSR-7/22/25BJM 7/22/25 SFD 7/22/2025 10-404 JLC 7/23/2025 Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.07.23 14:31:55 -08'00'07/23/25 RBDMS JSB 072425 Well Prognosis Well Name:NFU 41-35 API Number:50-231-10004-00-00 Current Status:Producing Gas Well Permit to Drill Number:165-021 Regulatory Contact:Donna Ambruz (907) 777-8305 First Call Engineer:Scott Warner (907) 564-4506 (O)(907) 830-8863 (C) Second Call Engineer:Chad Helgeson (907) 777-8405 (O)(907) 229-4824 (C) Maximum Expected BHP:3820 psi @ 8683’ TVD Based on 0.44 psi/ft Max. Potential Surface Pressure:2951 psi Based on 0.1 psi/ft gas gradient to surface Top of Applicable Gas Pool:4840’ MD/ 4840’ TVD Well Status:Online gas producer flowing at 76 mcfd, 0 bwpd, 45 psi FTP Well Summary North Fork 41-35 is a vertical well that was drilled, tested, completed, and shut in by SoCal in 1965. The well was re-entered and tested in 2001. After various ownership changes, facility and pipeline installations the well began producing in 2011. Production has been from the T-48, T-47, and T-40 sands only during the lifetime of the well. A plug was set in 2022 to isolate the T-47 and T-48 which shut off 10-20 bwpd and potentially ~230 mscf. The purpose of this Sundry is to remove the cement and CIBP to open the T-47/T-48. Notes Regarding Wellbore x Deviation o Max deviation: 2° @ 9956 MD x Min ID o 2.34” at 2300’ MD (chemical inj sub) o 2-7/8” tubing jet cut @ 8512’ Use caution when exiting/entering tubing Procedure 1. MIRU Coil Tubing and pressure control equipment 2. PT BOPE to 250 psi low / 3,500 psi high a. Provide AOGCC 24hr notice for BOP test 3. RIH and mill cement and CIBP @ 8460’ a. CIBP is set at 8490’ and TOC is estimated to be at 8460’ b. SL tagged at 8377’ KB on 6/8/25 4. Push CIBP to bottom ~ 9900’ a. Last entry into 7” liner was to shoot T-48 (8683’-8690’) and T-47 (8512’-8530’) w/ 2-1/8” strip guns b. Be cautious of strip gun debris when pushing CIBP to bottom c. Drifted to 9000’ in 7” and did not tag on 5/24/15 d. 2-7/8” tubing jet cut at 8512’ 5. Reverse out wellbore with N2 a. 7” liner capacity – 55 bbls from top of fish @9960 b. 2-7/8” capacity – 49 bbls from tubing cut 6. RDMO Well Prognosis Attachments: 1. Current schematic 2. Proposed Schematic 3. Coil Tubing BOP Schematic 4. Standard Well procedure – N2 Operations Updated by JKO 7/7/25 SCHEMATIC North Fork Unit NFU 41-35 PTD: 165-021 API: 50-231-10004-00-00 PBTD = 10,913’ MD TD = 12,812’ MD RKB to GL = 15’ MM CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 20” Conductor 79 B Weld 15.01” Surf 246’ 13-3/8” Surf Csg 61/68 J-55 BTC 12.415” Surf 2,000’ 9 5/8” Intermediate Csg 43.5 N-80/P-110 BTC 8.755” Surf 8,451’ 7” Production Liner 26 P-110 BTC 6.276” 8,330’ 10,985’ 2 7/8” Production Tubing 6.5 N-80 EUE 8RD 2.441” Surf 8,512’ (jet cut) JEWELRY DETAIL No. Depth ID OD Item 1 2,300’ Chemical Injection Sub – ¼” SS injection line 2 6,310’ DV Tool 3 7,966’ 2.875” 8.755” 9-5/8” Baker “S-3” Packer 4 7,985’ 2.31” 2-7/8” Sliding Sleeve (Opened 10/1/22). Sliding sleeve opens UP. 5 7,993’ (3) 2 7/8” Blast Joints (7,993’-8,052) 6 8,330’ 7.000” 8.755” Liner top packer / Brown tie-back sleeve 7 8,490’ - 2.441” CIBP w/ 30’ cement dump bailed. Est. TOC = 8,460’ 8 8,496’ 2.875” 6.276” 7” Baker Model “D” packer 9 9,960’ Junk- Partially milled retainer @ 9,960’ 10 9,975’ 2.312” 2.875” Fish- 2 7/8” 6.5” tubing, BXN nipple, WLEG. 34’ OAL 11 10,173’ - 6.276” Whipstock @ 10,173’ OPEN HOLE / CEMENT DETAIL 26” Est. TOC @ Surface. 625 sacks cement. 18-5/8” Est. TOC @ Surface. 2000 sacks cement. 12-1/4” Est. TOC @ 6,920’. 800 sacks cement around shoe and 750 sacks cement through DV @ 6,313’ (Est. TOC through DV @ 4,600’). 8-5/8” Est. TOC @ 8,330’. 900 sacks cement around shoe and 100 sacks cement squeezed at liner lap. 6 1/8” Sidetrack Est. TOC 10,009’. 38 sacks cement plug from 10,859’-10,654’. 52 sacks cement plug from 10,250’-10,009’. PERFORATIONS Sand Top MD Btm MD Top TVD Btm TVD Amt Date Comments T-40 7,972 7,980 7,972 7,980 8' 12/7/22 Open T-40 8,005 8,045 8,005 8,045 40' 12/12/1965 (8/21/2010 11/13/2022) Open (reperf’d 2x) CIBP 8,490’ 9/29/2022 T-47 8,512 8,531 8,512 8,531 19' 5/15/2015 Isolated T-47 8,530 8,540 8,530 8,540 10' 12/7/1965 Squeezed (prior to DST) T-47 8,563 8,602 8,563 8,602 39' 12/10/1965 (8/20/10) Isolated (re-perf’d) T-48 8,683 8,690 8,683 8,690 7' 5/15/2015 Isolated Hemlock 10,805 10,860 10,805 10,860 55’ 11/11/1965 Isolated 20” Conductor 9-5/8” Csg 18-5/8” hole 7” Liner 8-5/8” hole 1 13-3/8” Csg 12-1/4” hole 9 6 1/8” Sidetrack PBTD = 10,009’ TD = 10,859’ MD 2 3 4 5 6 6 7 8 10 11 Max Deviation – 2 deg @ 9,956’ MD Updated by SRW 7/17/25 Proposed SCHEMATIC North Fork Unit NFU 41-35 PTD: 165-021 API: 50-231-10004-00-00 PBTD = 10,913’ MD TD = 12,812’ MD RKB to GL = 15’ MM CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 20” Conductor 79 B Weld 15.01” Surf 246’ 13-3/8” Surf Csg 61/68 J-55 BTC 12.415” Surf 2,000’ 9 5/8” Intermediate Csg 43.5 N-80/P-110 BTC 8.755” Surf 8,451’ 7” Production Liner 26 P-110 BTC 6.276” 8,330’ 10,985’ 2 7/8” Production Tubing 6.5 N-80 EUE 8RD 2.441” Surf 8,512’ (jet cut) JEWELRY DETAIL No. Depth ID OD Item 1 2,300’ Chemical Injection Sub – ¼” SS injection line 2 6,310’ DV Tool 3 7,966’ 2.875” 8.755” 9-5/8” Baker “S-3” Packer 4 7,985’ 2.31” 2-7/8” Sliding Sleeve (Opened 10/1/22). Sliding sleeve opens UP. 5 7,993’ (3) 2 7/8” Blast Joints (7,993’-8,052) 6 8,330’ 7.000” 8.755” Liner top packer / Brown tie-back sleeve 7 8,490’ - 2.441” CIBP w/ 30’ cement dump bailed. Est. TOC = 8,460’ 8 8,496’ 2.875” 6.276” 7” Baker Model “D” packer 8a TBD Junk- milled CIBP (TBD) 9 9,960’ Junk- Partially milled retainer @ 9,960’ 10 9,975’ 2.312” 2.875” Fish- 2 7/8” 6.5” tubing, BXN nipple, WLEG. 34’ OAL 11 10,173’ - 6.276” Whipstock @ 10,173’ OPEN HOLE / CEMENT DETAIL 26” Est. TOC @ Surface. 625 sacks cement. 18-5/8” Est. TOC @ Surface. 2000 sacks cement. 12-1/4” Est. TOC @ 6,920’. 800 sacks cement around shoe and 750 sacks cement through DV @ 6,313’ (Est. TOC through DV @ 4,600’). 8-5/8” Est. TOC @ 8,330’. 900 sacks cement around shoe and 100 sacks cement squeezed at liner lap. 6 1/8” Sidetrack Est. TOC 10,009’. 38 sacks cement plug from 10,859’-10,654’. 52 sacks cement plug from 10,250’-10,009’. PERFORATIONS Sand Top MD Btm MD Top TVD Btm TVD Amt Date Comments T-40 7,972 7,980 7,972 7,980 8' 12/7/22 Open T-40 8,005 8,045 8,005 8,045 40' 12/12/1965 (8/21/2010 11/13/2022) Open (reperf’d 2x) CIBP 8,490’ 9/29/2022 T-47 8,512 8,531 8,512 8,531 19' 5/15/2015 Open T-47 8,530 8,540 8,530 8,540 10' 12/7/1965 Squeezed (prior to DST) T-47 8,563 8,602 8,563 8,602 39' 12/10/1965 (8/20/10) Isolated Open T-48 8,683 8,690 8,683 8,690 7' 5/15/2015 Open Hemlock 10,805 10,860 10,805 10,860 55’ 11/11/1965 Isolated 20” Conductor 9-5/8” Csg 18-5/8” hole 7” Liner 8-5/8” hole 1 13-3/8” Csg 12-1/4” hole 9 6 1/8” Sidetrack PBTD = 10,009’ TD = 10,859’ MD 2 3 4 5 6 6 7 8 10 11 Max Deviation – 2 deg @ 9,956’ MD 8a STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: ______________________ Vision Operating 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 12812 feet 8490 feet true vertical 12812 feet 9960 feet Effective Depth measured 10009 feet 7966 / 8496 feet true vertical 10009 feet 7966 / 8496 feet 7972 - 7980 perforated straddle Perforation depth Measured depth 8005 - 8045 feet perforated straddle 7972 - 7980 True Vertical depth 8005 - 8045 feet Tubing (size, grade, measured and true vertical depth) 2-7/8" 6.5# / N-80 8512 8512 Packer 9-5/8" 7966 7966 Packers and SSSV (type, measured and true vertical depth) Packer 7" 8496 8496 SSSV NA 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: NA 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: North Fork / Tyonek Gas 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: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title:Contact Phone: Collapse N/A 1540 measured TVD Production measured true vertical Packer 2529 Casing Structural 8450 7 8451 10985 10985 2000 264 1904 246Conductor Surface Intermediate 20 13-3/8 Burst 124267 0 400 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 165-021 50-231-10004-00-00 200 W. 34th Avenue, #66 Anchorage, AK 99503 3. Address: 5. Permit to Drill Number:2. Operator Name N 4. Well Class Before Work: ADL 391210 North Fork Tyonek Gas North Fork Unit 41-35 Plugs Junk measured None 0.4 Representative Daily Average Production or Injection Data Casing Pressure Tubing PressureGas-Mcf MDSize 246 N/A 30902000 9/5/2008 9960 38106330 Length Liner 8435 Vice-President Finance and Reserves 337.849.5345 907-529-1645 S. Hennigan / T. Maunder, P.E. shennigan@gardesholdings.com stamunder@aol.com 322-464 Sr Pet Eng: 6210 Sr Pet Geo: Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 122 240 p k ft t Fra O s O 165 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Samantha Carlisle at 8:28 am, Jan 31, 2023 Claude Joseph Digitally signed by Claude Joseph Date: 2023.01.31 11:24:35 -06'00' BJM 7/22/25 RBDMS JSB 013123 DSR-2/1/23 200 W 34th Avenue, #66 Anchorage, AK 99503 January 31, 2023 Brett Huber, Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 RE: Report of Sundry Operations (Form 404) Vision Operating North Fork Unit #41-35 Permit to Drill: 165-021 Sundry: 322-464 API No.: 50-231-10004-00-00 Dear Commissioner Huber, Vision Operating, LLC hereby submits a Report of Sundry Operations (Form 404) with attachments for NFU 41-35. Vision successfully accomplished the operations described in the Sundry application and production has been realized. If you have any questions, please contact Steve Hennigan at 337-849-5345 or Tom Maunder, P.E., at 907-529-1645. They are both in the Central time zone. Sincerely, Claude Joseph Vice-President, Finance, and Reserves Vision Operating, LLC Claude Joseph Digitally signed by Claude Joseph Date: 2023.01.31 11:24:58 -06'00' 200 W 34th Avenue, #66 Anchorage, AK 99503 NFU 41-35 165-021…322-464 Page 1 | 3 North Fork 41-35 Operations Summary 165-021 50-231-10004-0000 Sundry # 322-464 2022/08/20 Operations and Safety meeting, R/U slickline on 41-35. Pressure test to 1500 psi. Initial WHP 40 psi. RIH w/ 2-7/8” swab mandrel. Noticed sand in returns. POH. RIH w/ 2-7/8” WL brush to 6600’. No obstructions. Resume swabbing. Swabbed FL from 2020’ – 3450’, 14 runs, recovered 14 bbls. 2022/08/21 R/U slickline on 41-35. Pressure test to 1500 psi. Initial WHP 52 psi. RIH w/ 2- 7/8” swab mandrel. Swabbed FL from 2380’ – 4750’, 21 runs, recovered 23.2 bbls., Total 37.2 bbls. 2022/08/24 Waiting on SL return, SITP 205 psi. 2022/08/25 R/U slickline on 41-35. Pressure test to 1500 psi. Initial WHP 180 psi. RIH w/ 2- 7/8” swab mandrel. Swabbed FL from 2300’ – 4850’, 20 runs, recovered 32.0 bbls., Total 69.2 bbls Well occasional blows <5 psi. 2022/08/26 Initial WHP 500 psi. Attempt to flow well, no good. R/U slickline on 41-35. Pressure test to 1500 psi. RIH w/ 2-7/8” swab mandrel. Swabbed FL from 2300’ – 3800’, 11 runs, recovered 15.0 bbls., Total 84.2 bbls. 2022/08/27 Initial WHP 580 psi. R/U slickline on 41-35. Pressure test to 1500 psi. RIH w/ 2- 7/8” swab mandrel. Swabbed FL from 2500’ – 5000’, 18 runs, unload 6 bbls, swabbed 34.9 bbls., Total 119.1 bbls. 2022/08/28 Initial WHP 890 psi. Attempt to flow well, no good. R/U slickline on 41-35. Pressure test to 1500 psi. RIH w/ 2-7/8” swab mandrel. Swabbed FL from 3300’ – 6500’, 16 runs, unloaded 6.0 bbls, swabbed 34.9 bbls., Total 160.0 bbls. 2022/08/29 Initial WHP 1200 psi. Attempt to flow well, bleeds down in 30 minutes. R/U slickline on 41-35. Pressure test to 1500 psi. RIH w/ 2-7/8” swab mandrel. Swabbed FL from 2650’ – 5900’, 11 runs, unloaded 9.0 bbls., swabbed 23.5 bbls, Total 192.5 bbls. Shut well in @ 1630, SITP 52 psi, SITP 1800 164 psi, SITP 2300 743 psi 2022/08/30 SITP 0100 938 psi, SITP 0600 1237 psi, SITP 1200 1436 psi 2022/08/31 SITP 0000 1461 psi, SITP 0600 1478 psi, SITP 0800 1482 psi Blow well down to 0 psi @ 0900…no fluid recovered. Restart pressure buildup… SITP 1200 495 psi, SITP 1800 1020 psi 2022/09/01 SITP 0000 1060 psi, SITP 0600 1069 psi, SITP 1200 1079 psi, SITP 1800 1089 psi 200 W 34th Avenue, #66 Anchorage, AK 99503 NFU 41-35 165-021…322-464 Page 2 | 3 2022/09/02 SITP 0000 1095 psi, SITP 0600 1102 psi, SITP 0800 1103 psi Blow well down to 15 psi @ 0900…no fluid recovered. Restart pressure buildup… SITP 1200 422 psi, SITP 1800 832 psi 2022/09/03 SITP 0000 839 psi, SITP 0600 842 psi, SITP 1200 848 psi, SITP 1800 853 psi 2022/09/04 SITP 0000 862 psi, SITP 0600 867 psi, SITP 1200 873 psi, SITP 1800 877 psi 2022/09/05 SITP 0000 881 psi, SITP 0600 884 psi, SITP 1200 887 psi, SITP 1800 892 psi 2022/09/06 SITP 0000 894 psi, SITP 0600 897 psi, SITP 1200 900 psi, SITP 1800 902 psi Wait on Eline availability. 2022/09/28 RU Eline. Run gauge ring to 8507’, no issues. RIH w/ BP. Attempt to set BP without success. POOH, all tools recovered. Trouble shot tools, GR fault. 2022/09/29 Remake tools and RIH to set BP. Correlate and set BP @ 8490’. Make 4 runs (1 misrun) dumping cement (7.3 gallons) on BP. Est. TOC 8460’. 2022/09/30 No activity. Wait on slickline. 2022/10/01 Operations and Safety meeting, R/U slickline on 41-35. Pressure test to 1500 psi. Initial WHP 488 psi. RIH w/ 2.30” GR to 8342’ SLM. FL @ 4130’. RIH w/ 2- 7/8” scratcher and work 7965’ – 7985’. RIH w/ shifting tool (3 runs) and open sliding sleeve at 7966’. WHP declined to 473 psi at 2300. 2022/10/02 Bring well into process @ 0600. WHP 473 psi. After initial rush, WHP declined to 66 psi @ 0900. Make further arrangements to swab. 2022/10/03 No activity. Wait on slickline. 2022/10/04 Operations and Safety meeting, R/U slickline on 41-35. Pressure test to 2500 psi. Initial WHP 65 psi. RIH w/ 2-7/8” swab mandrel. Swabbed FL from 4070’ – 4370’, 1 run, recovered 23.2 bbls. Had SL unit problems. R/D slickline. Final WHP -0- psi. 2022/10/05 Operations and Safety meeting, R/U slickline. Pressure test to 2500 psi. Initial WHP -0- psi. RIH w/ swab tools, FL 4310’. Swab from 4310’ – 7580’, XX runs, recovered 19 bbls. 2022/10/06 Operations and Safety meeting, R/U slickline. Pressure test to 2500 psi. Initial WHP -0- psi. RIH w/ 2” X 5’ DD bailer to 8406’, slowly drop down to 8440’. POOH w/ cement sample. Fluid level at 7510’. Make repeated runs with shifting tool in different configuration to assure sliding sleeve is open. Have production operator load well with gas to 760 psi. WHP dropped from 747 psi to 719 psi and fluid level dropped from 7510’ to 7870’. Sleeve is open. R/D slickline. 200 W 34th Avenue, #66 Anchorage, AK 99503 NFU 41-35 165-021…322-464 Page 3 | 3 Open well to production at 1600. Initial WHP 659 psi. Well stabilized by 2000. 342 mcf/d, 380 psi. Produced 1.5 bw. 2022/10/07 Flowing well…348 mcf/d, 385 psi. Produced 1.6 bw, 3.1 bw total. Continue flowing well… Oct 06 - 31 daily average 345 mcf, 340 psi, 7.3 bw Nov 01 – 12 daily average 336 mcf, 295 psi, 0.8 bw 2022/11/13 Make temperature / pressure run. Reperforate 8025’ – 8045’, 8005’ – 8025’ through blast joints. Gun stuck, leave gun in hole. 2022/11/15 Fish Eline tools with slickline. Full recovery. Continue flowing well… Nov 13 – 30 daily average 280 mcf, 267 psi, 4.3 bw Dec 01 – 06 daily average 258 mcf, 266 psi, 0.4 bw 2022/12/07 Add new perforations 7972’ – 7980’ through straddle. Gun initially stuck but freed. No junk left in hole. Continue flowing well… Dec 07 – 31 daily average 267 mcf, 240 psi, 8.4 bw Version: Final 20" Conductor @ 246' 1/4" chemical injection line 13-3/8" 61# & 68# 2000' MD ID-12.415" J-55 BTC 2000' TVD Chemical Injection Mandrel @ 2,300' 18-5/8" Hole TOC @ 4600' MD DV tool @ 6,310' TOC @ 6920' MD 9-5/8" baker S-3" Packer @ 7,966' Sliding Sleeve @ 7,985' (Open) (Sliding Sleeve opens up) 3 Blast joints 7,993' - 8,052' 9 5/8" 43.5#N-80 & P-110 8451' MD ID 8.755" BTC 8451' TVD Liner Top/Brown Tie-Back Sleeve @ 8,330' 7" Baker Model "D" Packer @ 8,496' 2-7/8" plug @ 8490' MD W/ ±30' CMT 2 7/8's 6.5# Tubing end @ 8,512' Jet cut Status Open Sleeve Open BP Isolated Partially milled retainer @ 9,960' Squeezed Fish 34' long, 2 7/8" 6.5# tbg on top, BXN nipple, WLEG Squeezed TOC @ 10,009' Isolated Isolated Whipstock @ 10,173' Isolated Squeezed Cmt Plug Squeezed TOC @ 10,765' 6.125" Sidetrack hole drilled to 10,859' (Uncased) 10985' MD 7" 26# P-110 BTC 10985' TVD TOC @ 10,913' ID 6.276" Liner @ 10,985' TD @ 12,812'8-5/8" Hole 10875' (5 x 0.5" holes) 8540' (5 x 0.5" holes) NFU 41-35 WBD Permit to Drill: 165-021 December 7, 2022 API No.: 50-231-10004-00-00 2-7/8" 6.5#N-80 EUE 8rd-M tubing 12 1/4" Hole Perforations MD/TVD 8005' - 8045' 8512.5' - 8530.5' 8530' (5 x 0.5" holes) 7972' - 7980' 8490' 10805' - 10860' 10786' (5 x 0.5" holes) 8683' - 8690' 8592' - 8602' 8563' - 8578' -7/8"plug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y Samantha Carlisle at 11:58 am, Aug 05, 2022 Claude Joseph Digitally signed by Claude Joseph Date: 2022.08.05 14:40:15 -05'00' 6)' %-0 '65 3UHVVXUH WHVW ZLUHOLQH OXEULFDWRU DQG SUHVVXUH FRQWURO HTXLSPHQW WR SVL SULRU WR ZHOOERUH HQWU\ GWV -/& Jeremy Price Digitally signed by Jeremy Price Date: 2022.08.24 12:54:59 -08'00' RBDMS JSB 082422 200 W 34th Avenue, #66 Anchorage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laude Joseph Digitally signed by Claude Joseph Date: 2022.08.05 14:40:44 -05'00' 1)8 3DJH 9LVLRQ2SHUDWLQJ :(//1$0(²1)837' 5HTXLUHPHQWVRI$$&I tĞůů^ƵŵŵĂƌǇ ƵƌƌĞŶƚ^ƚĂƚƵƐ͗ E&hϰϭͲϯϱŝƐĐƵƌƌĞŶƚůǇƐŚƵƚŝŶ͘ tĞůů,ŝƐƚŽƌǇ EŽƌƚŚ&ŽƌŬηϰϭͲϯϱ;E&hϰϭͲϯϱͿŝƐĂǀĞƌƚŝĐĂůǁĞůůǁŝƚŚĂƐŝĚĞƚƌĂĐŬƚŚĂƚǁĂƐĚƌŝůůĞĚ͕ ƚĞƐƚĞĚ͕ĐŽŵƉůĞƚĞĚĂŶĚƐŚƵƚŝŶĚƵƌŝŶŐϭϵϲϱďǇ^ŽĂů͘dŚĞǁĞůůǁ ĂƐƌĞͲĞŶƚĞƌĞĚ/ďǇ EŽƌƚŚƐƚĂƌŝŶϮϬϬϭĂŶĚǌŽŶĞƐƚĞƐƚĞĚ͘'ĂƐWƌŽůĂƐŬĂĂƉƉůŝĞĚĨŽƌĂ^ƵŶĚƌǇŝŶϮϬϬϱͲϲ ǁŚŝĐŚǁĂƐĚĞŶŝĞĚ͘/ŶϮϬϭϬŽǁŶĞƌƐŚŝƉǁĂƐƚƌĂŶƐĨĞƌƌĞĚƚŽƌŵƐƚƌŽŶŐŽŽŬ/ŶůĞƚ ĞĨĨĞĐƚŝǀĞŝŶϮϬϬϳ͘/ŶϮϬϭϬĂǁŽƌŬŽǀĞƌǁĂƐƉĞƌĨŽƌŵĞĚĂŶĚƚŚĞǁĞ ůůƚĞƐƚĞĚ͘&ŽůůŽǁŝŶŐ ƚŚĞŚŽŽŬƵƉŽĨƚŚĞWƉŝƉĞůŝŶĞĂŶĚĐŽŵƉůĞƚŝŽŶŽĨƚŚĞǁĞůůƐŽŶƚŚĞƉĂĚ͕ƚŚĞǁĞůů ǁĂƐƉƌŽĚƵĐĞĚ͘/ŶϮϬϭϯĂ^ƵŶĚƌǇǁĂƐƐƵďŵŝƚƚĞĚƚŽŽƉĞŶƚŚĞƐůŝĚŝŶŐƐůĞĞǀĞ͘/ŶϮϬϭϰ ŽǁŶĞƌƐŚŝƉ ǁĂƐ ƚƌĂŶƐĨĞƌƌĞĚ ƚŽ ŽŽŬ /ŶůĞƚ ŶĞƌŐǇ ;ĂŶĚ ƐƵďƐĞƋƵĞŶƚůǇ ƚŚƌŽƵŐŚ ďĂŶŬƌƵƉƚĐǇƚŽ'ůĂĐŝĞƌKŝůĂŶĚ'ĂƐͿ͘'ĂƌĚĞƐ,ŽůĚŝŶŐƐ;sŝƐŝŽŶͿƉƵƌĐŚĂƐĞĚƚŚĞĨŝĞůĚŝŶ ϮϬϮϬ͘ ǆŝƐƚŝŶŐWĞƌĨŽƌĂƚŝŽŶƐ WĞƌĨŽƌĂƚŝŽŶƐ Dͬds^ƚĂƚƵƐ ϴϬϬϱΖͲϴϬϰϱΖ^ůĞĞǀĞ ůŽƐĞĚ ϴϱϭϮ͘ϱΖͲϴϱϯϬ͘ϱΖKƉĞŶ ϴϱϯϬΖ;ϱǆϬ͘ϱΗ ŚŽůĞƐͿ^ƋƵĞĞǌĞĚ ϴϱϰϬΖ;ϱǆϬ͘ϱΗ ŚŽůĞƐͿ^ƋƵĞĞǌĞĚ ϴϱϲϯΖͲϴϱϳϴΖKƉĞŶ ϴϱϵϮΖͲϴϲϬϮΖKƉĞŶ ϴϲϴϯΖͲϴϲϵϬΖKƉĞŶ ϭϬϳϴϲΖ;ϱǆϬ͘ϱΗ ŚŽůĞƐͿ^ƋƵĞĞǌĞĚ ϭϬϴϬϱΖͲϭϬϴϲϬΖŵƚWůƵŐ ϭϬϴϳϱΖ;ϱǆϬ͘ϱΗ ŚŽůĞƐͿ^ƋƵĞĞǌĞĚ 1)8 3DJH ^ĐŽƉĞŽĨtŽƌŬ͗ xƌŝĨƚƚƵďŝŶŐĂŶĚĚĞƚĞƌŵŝŶĞĨůƵŝĚůĞǀĞů͘ x^ĞƚƉůƵŐŝŶƚƵďŝŶŐĂŶĚƉƌĞƐƐƵƌĞƚĞƐƚ͘ xƵŵƉďĂŝůĐĞŵĞŶƚ͘ xKƉĞŶƐůŝĚŝŶŐƐůĞĞǀĞ͘ x^ǁĂďǁĞůůŝŶ͘ xZƵŶƉƌŽĚƵĐƚŝŽŶůŽŐƐǁŝƚŚďŽƚƚŽŵŚŽůĞƉƌĞƐƐƵƌĞĂŶĚĞǀĂůƵĂƚĞ͘ x/ĨŶĞĞĚĞĚ͕ƌĞͲƉĞƌĨϴϬϬϱ͛ͲϴϬϰϱ͛ĂŶĚƉĞƌĨϳϵϳϮ͛ͲϳϵϴϬ͛͘ x^ǁĂďǁĞůůŝŶ͘ xWŽƐƐŝďůǇƌƵŶƉƌŽĚƵĐƚŝŽŶůŽŐƐǁŝƚŚďŽƚƚŽŵŚŽůĞƉƌĞƐƐƵƌĞĂŶĚĞǀĂůƵĂƚĞ͘ xdƵƌŶǁĞůůŽǀĞƌƚŽƉƌŽĚƵĐƚŝŽŶ͘ 'ĞŶĞƌĂůtĞůů/ŶĨŽƌŵĂƚŝŽŶ͗ ZĞƐĞƌǀŽŝƌWƌĞƐƐƵƌĞͬds͗ цϯϳϲϯƉƐŝΛϴϲϵϬ͛DͬdsͲƵƌƌĞŶƚǌŽŶĞ цϯϰϲϳƉƐŝΛϴϬϬϱΖDͬdsͲŽŶĞďĞŚŝŶĚ ^ůŝĚŝŶŐ^ůĞĞǀĞ D^W͗ ƵƌƌĞŶƚǌŽŶĞʹD^WϮϴϵϱƉƐŝ ŽŶĞďĞŚŝŶĚ^ůŝĚŝŶŐ^ůĞĞǀĞͲD^WϮϲϲϳƉƐŝ tĞůůŚĞĂĚdǇƉĞͬWƌĞƐƐƵƌĞZĂƚŝŶŐ͗ ĂŵĞƌŽŶϱŵ tŝƌĞůŝŶĞ>ƵďƌŝĐĂƚŽƌ ^ůŝĐŬůŝŶĞͬůŝŶĞ KWŽŶĨŝŐƵƌĂƚŝŽŶ͗ Eͬ tĞůůdǇƉĞ͗ 'ĂƐWƌŽĚƵĐĞƌ ƐƚŝŵĂƚĞĚ^ƚĂƌƚĂƚĞ͗ ϬϵͬϬϭͬϮϬϮϮ $OOSURSRVHGSHUIRUDWLRQVOLHZLWKLQWKH1RUWK )RUN7\RQHN*DV3RRODVGHILQHGLQ&2 6)' ŐƉ ƌĞͲƉĞƌĨϴϬϬϱ͛ͲϴϬϰϱ͛ĂŶĚƉĞƌĨϳϵϳϮ͛ͲϳϵϴϬ͛͘ 1)8 3DJH 3URFHGXUH 5HTXLUHPHQWVRI$$&I ϭ͘ZŝŐƵƉ^ůŝĐŬůŝŶĞ͘ Ϯ͘Z/,ǁͬϮЬ͟ŐĂƵŐĞƌŝŶŐƚŽϴϱϬϬ͛Dͬds͘EŽƚĞ&ůƵŝĚůĞǀĞů͘ ϯ͘ZŝŐƵƉůŝŶĞ͘ ϰ͘^ĞƚƉůƵŐŝŶϮϳͬϴ͟ƚƵďŝŶŐĂƚцϴϰϵϬ͛D͘ 5HJXODWLRQ$$&( ϱ͘dĞƐƚƚŽϯϬϬϬƉƐŝŽŶĂĐŚĂƌƚĨŽƌϭϱŵŝŶ͘DŽŶŝƚŽƌĂůůĂŶŶƵůŝĂŶĚƌĞĐŽƌĚ͘ ϲ͘ZůŝŶĞ͕Zh^ůŝĐŬůŝŶĞ͘ ϳ͘ƵŵƉďĂŝůцϯϬ͛ĐĞŵĞŶƚ͘ 5HJXODWLRQ$$&( ϴ͘^ŚŝĨƚƐůŝĚŝŶŐƐůĞĞǀĞΛϳϵϴϱ͛KWE͘/ĨƐůŝĚŝŶŐƐůĞĞǀĞĐĂŶŶŽƚďĞŽƉĞŶĞĚ͕ƚŚĞ ƐƚƌĂĚĚůĞǁŝůůďĞƉĞƌĨŽƌĂƚĞĚ͘ ϵ͘^ǁĂďǁĞůůŝŶ͘ ϭϬ͘ZƵŶƉƌŽĚƵĐƚŝŽŶůŽŐƐǁŝƚŚďŽƚƚŽŵŚŽůĞƉƌĞƐƐƵƌĞĂŶĚĞǀĂůƵĂƚĞ͘ ϭϭ͘/ĨŶĞĞĚĞĚ͕ƌĞͲƉĞƌĨϴϬϬϱ͛ͲϴϬϰϱ͛ĂŶĚƉĞƌĨϳϵϳϮ͛ͲϳϵϴϬ͛͘ ϭϮ͘^ǁĂďǁĞůůŝŶ͘ ϭϯ͘WŽƐƐŝďůǇƌƵŶĂĚĚŝƚŝŽŶĂůƉƌŽĚƵĐƚŝŽŶůŽŐƐǁŝƚŚďŽƚƚŽŵŚŽůĞƉƌĞƐƐƵ ƌĞĂŶĚ ĞǀĂůƵĂƚĞ͘ dƵƌŶǁĞůůŽǀĞƌƚŽWƌŽĚƵĐƚŝŽŶ͘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l—A GOVERNOR MIKE DUNLEAVY Stephen Ratcliff VP of Drilling Cook Inlet Energy, LLC 188 W Northern Lights Blvd., Suite 510 Anchorage, AK 99503 Re: North Fork Field, Tyonek Gas Pool, NFU 41-35 Permit to Drill Number: 165-021 Sundry Number: 320-025 Dear Mr. Ratcliff: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 w .aogcc.alaska.gov Enclosed is the approved application for the 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. Cinrerely DATED thiV�day of January, 2020. -413DMS�K' JAN 2 4 2020 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS on GCC 94 9An JAN 17 2020 AOGCC 1. Type of Request: Abandon ❑ Plug Perforations ❑� Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate E Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: COOK INLET ENERGY LLC Exploratory ❑ Development E • Stratigraphic ❑ Service ❑ 165-021 ' 3. Address: 6. API Number: 601 W 5TH AVENUE, SUITE 310, ANCHORAGE, AK 99501 50-231-10004-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 720 North Fork Unit 41-35 ' Will planned perforations require a spacing exception? Yes ❑ No 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL 391210 ' I North Fork, Tyonek Gas it. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 12812 12812 10009 10009 2893 None 9960 Casing Length Size MD TVD Burst Collapse Structural Conductor 246 20" 246 246 N/A N/A Surface 1904 13-3/8" 2000' 2517 3090 1540 Intermediate 18435 9 5/8" 8451' 8600 16330 3810 Production Liner 12529 7 10985 10985 9960 6210 Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 8005'-8045'/ 8512'-8690' 8005'-8045'/ 8512'-8690' 2-7/8" 6.5# N80 BTCM 8512' Packers and SSSV Type: Baker S3 Packer Packers and SSSV MD (ft) and TVD (ft): 7966' MD/TVD; Baker Model D Packer No SSSV 8496' MD/TVD; 12. Attachments: Proposal Summary Q Wellbore schematic Q 13. Well Class after proposed work: Detailed Operations Program BOP Sketch ❑ Exploratory p ry ❑ Stratigraphic ❑ Development ❑� Service ❑ 14. Estimated Date for 15. Well Status after proposed work: 2/1/2020 Commencing Operations: OIL F]WINJ ❑ WDSPL ❑ Suspended ❑ GAS WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Stephen Ratcliff Contact Name: Stephen Ratcliff Authorized Title: VP of Drilling Contact Email: sratcliff@glacieroil.com Contact Phone: 907-433-3808 � Authorized Signature: Date: � t� 2U COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Post -1E3DMS*VJAN 2 4 2020 Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exeption Required? / o No Subsequent Form Required Yes ❑ : ^ l V q APPROVED BY Approved by: \` COMMISSIONER } THECOMMISSION Date: [�L bA/ !gym Form 1d- vis 4/2o Appr ed application is valid for 12 months from the date 'QP rova1(31 . NALSubmit Form and Attachments in Duplicate 7k11 -0"'a GLACIER January 17th, 2020 Jessie Chmielowski, Commissioner Alaska Oil and Gas Conservation Commission 333 West 711 Ave., Suite 100 Anchorage, Alaska 99501 RE: Sundry Application Cook Inlet Energy, LLC: North Fork Unit 41-35 API: 50-231-10004-00-00 Dear Commissioner, Cook Inlet Energy (CIE) hereby submits a Sundry Application for NFU 41-35, PTD: 165-021 to set a plug in the tubing and add perforations. If you have any questions, please contact me at (907) 433-3808. Sincerely, Stephen Ratcliff VP of Drilling Cook Inlet Energy, LLC (a Glacier Oil & Gas owned company) 188 W Northern Lights Blvd, Suite 510 Anchorage, AK 99503 WELL NAME — NFU 41-35 Requirements of 20 AAC 25.005(f) Well Summary Current Status: Currently shut-in due to no flow. Scope of Work: • Rig Up Eline. • Set plug in tubing. • Add Perforations. • Rig down. General Well Information: Reservoir Pressure / TVD: MASP: Wellhead Type/Pressure Rating: BOP Configuration: Well Type: Estimated Start Date: 3763 psi @ 8690' MD / 8690' TVD 2893 psi Vetco Gray -5M - Wellhead Assembly Eline WLV Gas Producer February 1, 2020 2 GLACIER 1. Operational Procedure Requirements of 20 AAC 25.005 (c)(13) 1. Rig up Eline. 2. RIH with 2-1/4" gauge ring to 8500' MD. Note fluid level. 3. Set plug in 2-7/8" tubing at 8480' MD. 4. RIH with 1-3/4", 4 spf, 60 deg phase perforating guns and perforate the following intervals from bottom to top: (5 f -'? �2 w n� ? ) NFU 41-35 — Perf Intervals Top MD Base MD Footage Top TVD Base TVD Notes 7972 7980 8 7972 7980 New Interval 8164 8174 10 8164 8174 New Interval Tota I = 18 ft 5. Rig down Eline. 6. Turn well over to Production. 3 GLACIER Ina Ira 111111 20" Conductor 246' RVA 13-3/8" 1 61#&68# 2000' MD ID -12.415" J55 BTC 2000' TVD 18-518" Hole NFU 41.35 Proposed Schematic 1/4" chemical injection line TOC @ 4600' MD DV tool @ 6,310' TOC @ 6920'MD Version: 9-5/8" baker S-3" Packer @ 7,966' �7iYa Sliding Sleeve @ 7,985'(Closed) (Sliding Sleeve opens up) 3 Blast joints 7,993'- 8,052' 43.5#N-80 & P-110 8451' MD ID 8.755" BTC 8461' TVD 12 1/4" Hole Perforations MD/TVD IStatus 7972'-7980' New 8006- 8045' lsjeeve cl.,w 8164'- 8174' INe. 8512.5'- 8530.5' JP&A 8530'(5 x 0.5" holes) ISqueezed 8540'(5 x 0.5" holes) Squeezed 8563'- 8578' P&A 8592'- 8602' P&A 8683'- 8690' P&A 10786'S x 0.5" holes) Squeezed 10805' - 10860' Cml Plug 10875'(5 x 0.5" holes) Squeezed 6.125" Sidetrack hole drilled to 10,859' (Uncased) 7" 26# P-110 BTC 10985' MD ID 6.276" Liner @ 10,985' 10985' TVD note Baker Model 2-718" plug @ 8480' MD Tbing@12c 2 7/8" yt �y�.. ♦ Whipstock @ 10,173' TD @ 12,812' TOC @ 10,913' WLEG THE STATE OfALAS1-1 GOVERNOR BILL WALKER Stephen Ratcliff VP of Drilling Cook Inlet Energy, LL 601 W 5h Ave., Suite 310 Anchorage, AK 99501 Re: North Fork Field, Tyonek Gas Pool, NFU 41-35 Permit to Drill Number: 165-021 Sundry Number: 318-423 Dear Mr. Ratcliff: 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 The AOGCC denies the enclosed application for sundry approval relating to the above -referenced well. Under 20 AAC 25.200 any well capable of flowing to surface must have a suitable tubing and packer which creates a monitorable annulus. Perforating the tubing and casing to access gas zones above the existing packer would be a violation of 20 AAC 25.200. As provided in AS 31.05.080(a), 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. A person may not appeal an AOGCC decision to Superior Court unless reconsideration has been requested. Sincerely, xf%4V4�' Cathy F1. Foerster Commissioner DATED thi�0 day of September, 2018. RBDWV� OCT 0 21018 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 9n AA(. 91 98n RECEIVED SEP 2 0 2018 A0GQQ 1. Type of Request: Abandon ❑ Plug Perforations El Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate ❑✓ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: COOK INLET ENERGY LLC Exploratory ❑ Development ❑✓ Stratigraphic ❑ Service ❑ 165-021 3. Address: 6. API Number: 601 W 5TH AVENUE, SUITE 310, ANCHORAGE, AK 99501 50-231-10004-00-00 7. If perforating: �i,C%yL 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? 20 55 .i5 f Z.(. / North Fork Unit 41-35 Will planned perforations require a spacing exception? Yes ❑ No El 9. Property Designation (Lease Number): 10, Field/Pool(s): North Fork, U ADL 391210 e 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth ND: MPSP (psi): Plugs (MD): Junk (MD): 12812 12812 10009 10009 N3 None 9960 Casing Length Size MID ND Burst Collapse Structural Conductor 246 20" 246 246 NIA N/A Surface 1904 13-3/8" 00' 2517 3090 1540 Intermediate 8435 95/8" 8 8600 6330 3810 Production Liner 2529 7 1098 10985 19960 1 6210 Perforation Depth MO (ft): Perforation Depth ND (ft): Tubing e: Tubing Grade: Tubing MD (ft): 8005'-8045'/ 8512'-8690' 18005'-8045'/ 8512'-8690' 2-718" 6.5# N80 BTCM 8512' Packers and SSSV Type: Baker S3 Packer Packers and SSSV MD (ft) and ND (ft): 7966' MDf rVD; Backer Model D Packer No SSSV 8496' MD/TVD; 12. Attachments: Proposal Summary Wellbore sch a 4 13. Well Class after proposed work: Detailed Operations Program ❑� BOP Sket Exploratory ❑ Stratigraphic ❑ Development ❑✓ Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 9/28!2018 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS Q WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true andfAe procedure approved herein will not be deviated from without prior written approval. Authorized Name: Stephen Ratcliff Contact Name: Stephen Ratcliff Authorized Title: VP of Drilling Contact Email: smtcliff@glacieroil.com \^, , Contact Phone: 907-433-3808 Authorized Signature: "+ Date: 9/1412018 COMMISSION USE ONLY Conditions of approval: Notify Commis n so that a representative may witness Sundry Number: (�'L Plug Integrity ❑ BO Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: OCT 01301 Post Initial Injection MIT Req'd? Yes ❑ No ❑ RBDMS& Spacing Exception Required? Yes ❑ No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Submit Form and Form 10-403 Revised 4/2017 Approved aPPtcGU `I^ATrdate of approval. Attachments in Duplicate GLACIER 09/20/2018 Mr. Hollis French, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 RE: Sundry Application Cook Inlet Energy, LLC, a Glacier Oil and Gas Company (GLA): North Fork Unit #41-35 Permit to Drill: 165-021 API No.: 50-231-10004-00-00 Dear Mr. French, Glacier Oil & Gas, on behalf of Cook Inlet Energy, hereby submits a Sundry Request to abandon existing perforations and add new perforations to NFU 41-35. If you have any questions, please contact me at (907) 433-3808. Sincerely, Stephen Ratcliff VP of Drilling Glacier Oil & Gas Corp. 601 W. 5th Avenue, Suite 310 Anchorage, AK 99501 sratcliff@glacieroil.com 0: 907.433.3808 1 GLACIER WELL NAME — NFU 41-35 Requirements of 20 AAC 25.005(f) Well Summary Current Status: NFU 41-35 is currently shut in. Existing Perforations: MD/TVD Status j 8005' - 8045' I 8512 5' - 8530.5' Open (Sleeve Closed) Open _. 8530' i Squeezed 8540' i Squeezed 8563'-8602' Open 8683'-8690' Open 10786' ( Cement plug 10805 10860' Cement plug 10875' Squeezed Scope of Work: • Rig up Slickline. • Set plug and dump bail cement. • Open sliding sleeve. • Tubing punch above packer. • Use nitrogen/gas to move fluid level. • Close sliding sleeve. • Perforate selected intervals. • Rig down Eline. • Turn well over to production. General Well Information: Reservoir Pressure / TVD: 3,147 psi @ 7270' MD / TVD (0.433 psi/ft) MASP: 2,833 psi Wellhead Type/Pressure Rating:Eline Lubricator BOP Configuration: N/A Well Type: Gas Producer Estimated Start Date: 10/15/18 2 GLACIER Program 1. Rig up Slickline and Lubricator. Test lubricator to 3500 psi. 2. RIH with 2-3/4" GR to confirm accessibility (end of tubing at 8512' MD/TVD). a. Document fluid level. b. RIH with brush/scraper if needed. 3. RIH with 2-7/8" plug and set in tubing at -8500' MD. a. Regulation 20 AAC 25.112 (1)(E) 4. Pressure test tubing to 2500 psi for 15 mins and chart same. 5. Pressure test IA to 2500 psi for 15 mins and chart same. 6. Tag plug to confirm set depth. 7. RIH and dump bail 25' of cement on top of plug. a. Regulation 20 AAC 25.112 (1)(E) 8. Rig up nitrogen unit. 9. RIH and open sliding sleeve at 7985'. a. Monitor surface pressure. b. Sleeve opens shifting up. 30. Conduct injectivity test on 8005'-8045' perfs. a. Utilize nitrogen if necessary. b. Document injection rate. c. Do not exceed 4000 psi, without contacting Superintendent. 11. Rig down Slickline. 12. Rig up Eline. 13. RIH and tubing punch at — 7950' MD (above top packer). a. Monitor surface pressures and allow to equalize. 14. Rig down Eline. 15. Rig up Slickline. Rig up Nitrogen unit to Tubing and IA. a. Review Standard Well Procedure — Nitrogen Operations. 16. RIH and tag fluid level. a. Document surface pressure. 17. Utilize gas/nitrogen and increase pressure on tubing and IA. a. Increase pressures in increments of 500 psi. b. Do not exceed 4000 psi, without contacting Superintendent. 18. After pressure increase, tag fluid level. 19. Once fluid level is at or below 7500' MD, shift sliding sleeve closed. a. Hold pressure until sleeve is closed. b. Sleeve closes shifting down. 20. Bleed off pressure. 21. Check for fluid level. 22. RD Slickline. 23. RU Eline. 24. RIH with 2", 6spf, 60 deg phase perf guns. 3 GLACIER 25. Perforate the following intervals: Top, MD Bottom, MD Footage Top, TVD Bottom, TVD 5355' 5398' 43' 5355' 5398' 5675' 5725' 50' 5675' 5725' 5760' 5795' 35' 5760' 5795' 6850' 6860' 10' 6850' 6860' 7255' 1 7270' 15' 7255' 7270' a. Monitor and record surface pressure in 5 -minute intervals for 30 minutes after each pert run. 26. RD Eline. 27. Be prepared to utilize Slickline and swab with 2" swab cups, if necessary. 28. Turn well over to production through tubing. Variance Request: By adding the above perforations, Glacier O&G is proposing to produce the well up the tubing and production casing annulus simultaneously. Article 3 of the Alaska Administrative Code 25.200 stipulates that unless otherwise specifically approved by the commission, "all producing wells capable of unassisted flow must be completed with downhole production equipment consisting of suitable tubing and a packer that effectively isolate the tubing -casing annulus from fluids being produced". Glacier O&G believes that production above the packer in NFU 41-35 presents no safety or environmental risk and requests an exception to this requirement. The risks associated with annular production in the North Fork field are considered minimal, as summarized below: • No existing safety devices will be defeated or bypassed. NFU 41-35 is equipped with surface safety valves for well control and all production will continue to be routed through surface safety equipment. • North Fork wells produce a benign fluid consisting of 99.2% methane, 0.2% nitrogen, and 0.27% CO2 and less than 0.1% of ethane, propane, and butane. No condensate is produced in conjunction with the gas. NFU 41-35 has historically produced water with 0.0031% salinity. As such, there are no known instances of tubing leaks or downhole corrosion in the North Fork Unit. • NFU 41-35 is believed to have competent tubing and casing. As a precaution, an MIT of the 9-5/8" casing will be conducted prior to performing the perforations. Should the well fail an MIT, the well work will be postponed pending further evaluation. In addition, the 9-5/8" x 13-3/8" annulus will be monitored should the integrity of the 9-5/8" casing be compromised in the future. Tubing and annular pressures are monitored and reported daily. W GLACIER The interval to be produced through the annulus is not a known sand producer and the risk of eroding the production casing or the tubing is considered minimal. As a precaution, all wells are tested annually with an acoustic monitoring device to ensure they are produced at a sand free rate. Additional information: Regarding the proposed new perforations in North Fork Unit 41-35: 7Zo • Well spacing in this pool is governed by the statewide spacing requirements found in 20-RAA- 2>�. The statewide spacing requirements are modified by several spacing exception Conservation Orders granted by the Commission. Specifically, these Conservation Orders are: i. CO 601.000 (May 21, 2008) — North Fork 34-26 ii. CO 632.000 (August 19, 2010) — North Fork Unit 32-35 iii. CO 633.000 (August 19, 2010) — North Fork Unit 14-25 iv. CO 660.000 (September 27, 2012) — North Fork Unit 33-35 (undrilled) V. CO 661.000 (September 27, 2012) — North Fork Unit 23-25 vi. CO 662.000 (September 27, 2012) (Expired) — North Fork Unit 42-35 vii. CO 663.000 (September 27, 2012) — North Fork Unit 22-35 viii. CO 705.000 (November 14, 2014) — North Fork Unit 24-26 ix. CO 710.000 (December 4, 2014) — North Fork Unit 42-35 X. CO 714.000 (March 19, 2015) — North Fork Unit 22-26 (undrilled) The spacing requirements of 20 AAC 25.055(a)(4) require that "...not more than one well may be drilled to and completed in that pool on any governmental section: a well may not be drilled or completed closer than 3,000 feet to any well drilling to or capable of producing from the same Pool." • There are Conservation Orders modifying these requirements for all adjacent wells within the governmental section and within 3,000 feet of the North Fork Unit 41-35. The Conservation Orders specify that the wells subject to those Orders may be drilled, completed, tested and produced as long as they comply with the North Fork Unit Agreement, lease agreements, and all applicable Alaska and federal laws (or similar language). There are several other wells within the North Fork Unit open to this same pool (the North Fork Undefined Gas Pool). They are: i. NFU 42- 35, nearest open perforation 823 feet from 41-35 (CO 710.000) ii. NFU 34- 26, nearest open perforation 1,630 feet from 41-35 (CO 601.000) iii. NFU 14- 25, nearest open perforation 1,894 feet from 41-35 (CO 633.000) iv. NFU 32- 35, nearest open perforation 1,929 feet from 41-35 (CO 632.000) V. NFU 24- 26, nearest open perforation 2,595 feet from 41-35 (CO 705.000) A NFU 22- 35, nearest open perforation 2,964 feet from 41-35 (CO 663.000) vii. NFU 23- 25, nearest open perforation 3,586 feet from 41-35 (CO 661.000) • The proposed perforations will not conform to the spacing requirements of the governing regulation, 20 AAC 25.055. However, North Fork Unit 41-35 is currently capable of producing from 5 GLACIER the same pool as the adjacent wells, which are all subject to spacing exception Conservation Orders granted by the Commission at various times. All spacing exceptions were granted taking North Fork Unit 41-35's capability of producing from the same pool into consideration. • There is no spacing exception Order for the North Fork Unit 41-35 because it was the first well drilled into the pool. However, the proposed new perforations in 41-35 will not penetrate any additional pools. The various other spacing exception Conservation Orders considered 41-35 as being capable of producing from the same pool. This Sundry application to add additional perforations within the same pool will not materially change how the field is being produced (i.e. no new pools). Therefore, 41-35 is effectively governed by the Conservation Orders from all adjacent wells, and Glacier O&G believes an exception to 20 AAC 25.055 is not required for this Sundry request. E 19518" 143.5#N-80 8 P-110 8451' MD ID 8.755" BTC _ _ _ 8451' WE 12 1I4" Hole Perforations 8530'(5 x 0.5" holes) ISqueezed 8540'(5 x 0.5" holes) jLqueezed 8563'-8578' Open 8582'-8602' IODen 10985'TVD Hole NFU 41.35 Current Schematic TD 12,812' Version: CURRENT September 5, 2018 1/4" chemical injection line TOC Q 4600' MD DV tool 6,310' TOC Q 6920' MD Sliding Sleeve a 7,985' Closed (Sliding Sleeve opens up 3 Blast'oints 7,993'- 8,052' TOC Q 10,785' TOC @ 10,913' GLACIER 20" Conductor @ 246' 13-3/8" 61#&68# 2000' MD ID -12.415" J-55 BTC 2000'TVD 18-5ill" Hole 19518" 143.5#N-80 8 P-110 8451' MD ID 8.755" BTC _ _ _ 8451' WE 12 1I4" Hole Perforations 8530'(5 x 0.5" holes) ISqueezed 8540'(5 x 0.5" holes) jLqueezed 8563'-8578' Open 8582'-8602' IODen 10985'TVD Hole NFU 41.35 Current Schematic TD 12,812' Version: CURRENT September 5, 2018 1/4" chemical injection line TOC Q 4600' MD DV tool 6,310' TOC Q 6920' MD Sliding Sleeve a 7,985' Closed (Sliding Sleeve opens up 3 Blast'oints 7,993'- 8,052' TOC Q 10,785' TOC @ 10,913' NFU 41-35 Proposed Schematic GLACIER 20" Conductor 246' 13-318" 61# & 68# 2000' MID / ID -12.475" J-55 BTC 2000' TVD 18.5/8" Hole Perforations I -a -. MDrrVD Istatus I -j 5355' - 5398' New 5675' - 5725' New _-^-'-5795' New - 6860' New 1255 - 7270' New 5005'-8045' slams Gosaa xx il2.5'-8530.5' PSA 4,11 it Y(5 x 0.5" holes) Squeezed Y(5 x 0.5" holes) Squeezed 4563'-8578' P&A 5592' - 8602' P&A 5683'-8690' P&A G.T•, .��•' 6'(5 x 0.5" holes) Squeezed TOC Q 4600' MD DV tool 6,310' TOC (off 6920' MD Version: Proposed V1.0 September 5, 2018 ]Sliding Sleeve a 7,985'Gored I(Sliding Sleeve opens u �-r 3 Blast joints 7,993'. 8,052' 2-7/8" plug @ 8500' MD w/25ft cmt dump bailed on top 2 7/8's 6.5# Tubing end @ 8,512 Whipstock @ 10,173' Cmt Plug :s) Squeezed - drilled to 70,859' (Uncased) 10 BTC 10985' MD TOC 70,813' ri 10,985' 10985'TVD TD 12,812' Standard Well Procedure GLACIER Nitrogen Operations 1. MIRU Nitrogen Pumping unit and Liquid Nitrogen Transport. 2. Notify Pad Operator of upcoming Nitrogen operations. 3. Perform Pre -Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4. Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5. Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6. Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7. Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8. Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9. Place pressure gauges upstream and downstream of any check valves. 10. Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11. Ensure portable 4 -gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measure 02 levels. 12. Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1500 psi. Perform visual inspection for any leaks. 13. Bleed off test pressure and prepare for pumping nitrogen. 14. Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15. When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16. Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17. Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18. RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. V1.0 9/17/2018 .' Cook Inlet Energy_ RECEIVED MAY 2 8 2015 AOGGC May 28th, 2015 Cathy Foerster,Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage,Alaska 99501 Re: 10-404 Sundry 315-251 Completion Report Cook Inlet Energy, LLC: North Fork Unit#41-35(PTD 165-021) Dear Ms. Foerster, Cook Inlet Energy(CIE) hereby submits a completed form 10-404 and associated documents for NFU 41- 35 Approved Sundry 315-251 to cut tubing tail and perforate 2 new zones and re-perforate the lower production zone. If you have any questions, please contact me at(907)727 7404. Sinc , z,r47e,' ,_...e------v ---- Conrad Pe Drilling Manager Cook Inlet Energy 601 W.5th Avenue,Suite 310,Anchorage,AK 99501 (907)334-6745*(907)334-6735 fax NFU 41-35 Sundry Operations Report for 5/16/2015 0600 hrs: Pollard E-Line Crew and equip arrived, Held PJSM. Began R/U, M/U CCL, GR,Temp Survey Tool,weight bar. Test Lubricator to 3500 psi 0900 hrs: Held Safety Meeting with all (+ Production Lead) involved in the Cutting/Perfing procedure. Notify Neighbors of Project 0930 hrs: 655 psi WHP,Open well& RIH with E-Line Tool String 1130 hrs: made several passes and identified the 2 7/8" completion string BHA, made depth corrections. 1230 hrs: Sent management info, made calls to confirm depths of tools, depth of tubing cut and Perforation depths of interest with Conrad and Greg Kirkland 1300 hrs: POH and LID Temp tool, 1330 hrs: Change tools&RIH w/2.25 "Tubing Spectra Jet Cutter 1430 hrs: Make several passes to correlate depth before making 2 7/8"Tubing cut, 3.7 f/CCL t/Jet Cutter After conferring with management, cut tubing at 8512'= 2' below bottom of XO, Pick up then RIH to confirm cut tubing had fallen away, POH 1530 hrs: L/D Cutter Assy and P/U 7' 2 1/8" 60' phase 6 SPF Spiral Strip Shogun. 7'f/CCL t/Top Shot 1615 hrs: RIH w/7' Perf Gun Assy. Observed Fluid Level at 4750' = (960 psi underbalance), make several correlation passes 1730 hrs: Send Correlation Log to CIE Sr.Geologist Greg Kirkland, (Note: WHP 646 psi)Greg confirmed Go.-- Perf Depths IC , 1740 hrs: Fire Perf Guns:Top shot=8683', Bottom Shot=8690'=7', observed pressure increase of 2 psi /min avg.continue monitoring WHP 1840 hrs: POH while monitoring WHP, consistent 2 psi/min build rate, confirmed all shots fired, L/D 7' spent gun assy. P/U 18'Gun Assy. 1930 hrs: RIH with same type/Style of Strip Shoguns,WHP still at 2 psi/min build rate 2015 hrs: Make several correlation passes,7'f/CCL t/Top Shot 2100 hrs: Send Correlation Log to CIE Sr.Geologist Greg Kirkland, (Note: WHP 960 psi)Greg confirmed Perf Depths l� ilr 2120 hrs: Fire Perf Guns:Top Shot=8512.5'- Bottom Shot=8530.5' = 18', starting WHP 969 psi,gained 5 psi quickly then increased by 2 psi/min avg. POH 2220 hrs: R/D Pollard E-Line equipment and headed back to Nikiski Shop. Continue monitoring WHP 2330 hrs: Line up& pump Methanol to well. Line up well to closed choke manifold,with starting WHP 1240 psi,open well aggressivelythru choke then once pressure consistant with wide open choke then open "By-Pass"to Diffuser Tank 2337 hrs: Observed Fluid at Surface, NOTE: Recovered total of 12 bbls= 81.2 bbls since beginning. Collected 2 sample bottles toward end of fluid recovery 2345 hrs: adjusted choke to maintain 100 psi to 250 psi with 29/64 choke setting 0010 hrs: Observed Fluid had stopped and now"All"Gas Flow at a steady 113 psi with 15/64 choke setting 0015 hrs: Shut in well, Production will monitor WHP until it reaches 600 to 700 psi then feed Wellhead safety system and attempt to open well to Production Process 'FU 41-35 Current Schematic VE is CURRENT• Cook Inlet Energy_ May 16,2015 - 20"Conductor @ 246'I 18-5/8"Hole 1/4"chemical injection line Chemical Injection Mandrel @ 2,300' 13-3/8" 61#&68# 2000 MD ` ID-12.415" J-55 BTC 2000 TVD 12 1/4"Hole DV tool @ 6,310' Perforations MD 8005-8045 E """" 2-7/8"6.5#N-80 EUE 8rd-M tubing 8530-8540 (squeezed) 8563-8602 10786 10805-10860 10875 (squeezed) 8512.5-8530.NEW PERFS 8683-8690 NEW PERFS 9-5/8"baker S-3"Packer @ 7,966' 11' Sliding Sleeve @ 7,985'closed Sliding Sleeve opens up 3 Blast joints 7,993'-8,052' 9 518" 43.5#N-80&P-110 8451 MD ID-8.755" BTC 8451TVD , (♦ Brown Tie-Back Sleeve©8,330' 7"baker Model"D"Packer @ 8,496' 2 7/8's 6.5#Tubing end @ 8,512' Jet cut I . Perforations(squuezed)8,530'&8,540' — 4.1+ Perforations(Open)8,563-8,602' V— =x�y itA Fish 34'long,2 7/8's 6.5#tubing on top .- Partially milled retainer l 9,960' aallll IFS < TOC @ 10,009' Whipstock @ 10,173' Sidetrack hole drilled to 10,859'(Uncased ( TOC @ 10,765' � c Perforations(Squeezed)@ 10,875 7" 26#P-110 BTC 10985 MD .r�# Via. TOC 0 10,913' ID-6.276" Liner @ 10,985' 10985TVD TD @ 12,812 0F TSF evi, 1�j, s THE STATE Alaska Oil and Gas �1/� T L /1� /� X1`1 s Conservation Commission 1-1 ejj 2__._ __ 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main. 907.279.1433 �FALASY'� Fax: 907.276 7542 www.aogcc.alaska.gov Tyler Wagner II Drilling Engineer 6.9* O9- . Cook Inlet Energy, LLC 601 W. 5th Ave., Suite 310 Anchorage, AK 99501 Re: North Fork Field, Undefined Gas Pool, NFU 41-35 MAS 2 O 201 �� Sundry Number: 315-251 SC *A Dear Mr. Wagner: 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, Cathy . Foerster �,f,� Chair DATED this Is" day of May, 2015 Encl. RECEIVED STATE OF ALASKA lA P R 2 7 0G1 5 ALASKA OIL AND GAS CONSERVATION COMMISSION fn-S s 0 IC, APPLICATION FOR SUNDRY APPROVALS .ACG `7 20 AAC 25.280 1.Type of Request: Abandon❑ Plug for Redrill❑ Perforate New Pool❑ Repair Well❑ Change Approved Program ❑ Suspend 0 Plug Perforations❑ Perforate❑✓ . Pull Tubing❑ Time Extension ❑ Operations Shutdown❑ Re-enter Susp.Well 0 Stimulate❑ Alter Casing❑ Other: Cut tubing - 11 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Cook Inlet Energy,LLC Exploratory ❑ Development ❑., 165-021 • 3.Address: 6.API Number: Stratigraphic ❑ Service ❑ 601 W.5th Avenue,Suite 310,Anchorage,AK 99501 50-231-10004-00 • 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? North Fork Unit#41-35 . Will planned perforations require a spacing exception? Yes 0 No Q 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL 391210 • North Fork, undefined gas WGA 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): 12,812' 12,812' 10,009' 10,009' None none Casing Length Size MD TVD Burst Collapse Structural Conductor 246 20" 246' 246' N/A N/A Surface 1,984' 13-3/8" 2,000' 2,000' 3,090' 1,540' Intermediate 8,435' 9-5/8's 8,451' 8,451' 6,330' 3,810' Production Liner 2,529' 7" 10,985' 10,985' 9,960' 6,210 Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 8,005'to 8,045';8,530'-8,602' 8,005'-8,045';8,530'-8,602' 2-7/8's 6.5#N-80 BTC-M 8,045' Packers and SSSV Type: Brown 2 7/8"x 9-5/8"HS-16-1 Packer Packers and SSSV MD(ft)and ND(ft): 7,952'MD/ND,8,496'MD/TVD No SSSV 12.Attachments: Description Summary of Proposal Q 13.Well Class after proposed work: • Detailed Operations Program ❑., BOP Sketch ❑ Exploratory ❑ Stratigraphic❑ Development❑., Service ❑ 14.Estimated Date for ASAP 15.Well Status after proposed work: Commencing Operations: Oil ❑ Gas ❑✓ • WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: WINJ 0 GINJ ❑ WAG 0 Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG 0 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Tyler Wagner Email TYIer.Wagner at7.cookinlet.net Printed Name Tyler Wagner 907-433-3831 Title Drilling Engineer-4-27-2015 Signature � �� Phone Date COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 16 -OS1 Plug Integrity ❑ BOP Test 0 Mechanical Integrity Test ❑ Location Clearance ❑ Other: Spacing Exception Required? Yes ❑ No LVA Subsequent Form Required: I(.'•-ii0L1 I APPROVED BY : Approved by: P COMMISSIONER THE COMMISSION Date - 8 --t J-11-1Y Submit Form and Form 10-403(Revised 10/2012)7 Approved application is r'�r�" e ate of approval. / Attachments in Duplicate RBDMSL MAY 1 1 1015 crRif UI I V/ L /0�/_ - $: 9</ç RECEIVED • Cook Inlet Energy b!— APR 272015 AOGCG April 27, 2015 Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 Re: Application for Sundry Cook Inlet Energy, LLC: North Fork Unit#41-35 (PTD 165-021) Dear Ms. Foerster, Cook Inlet Energy (CIE) hereby submits a completed form 10-403 and application for sundry approval to cut tubing tail and perforate 2 new zones and re-perforate the production zone. a. 8,510' - 8,530' MD NEW b. 8,683' - 8,690' MD NEW c. 8,563' - 8,602' MD re-perforate If you have any questions, please contact me at(907) 433 3831. Sincerely, Tyler Wagner Drilling Engineer Cook Inlet Energy 601 W.5th Avenue,Suite 310,Anchorage,AK 99501 (907)334-6745*(907)334-6735 fax • NFU 41-35 -Well Summary Current Status: NFU 41-35 is currently producing Scope of Work: • Cut TBG • Perforate new zones General Well Information: MASP: 2800 psi Reservoir Pressure/TVD: 3662 psi @ 8690 MD/ 8690' TVD Wellhead Type/Pressure Rating: Vetco Grey 11"-5M BOP Configuration N/A Well Type: Gas Producer , Estimated Start Date: April 30, 2015 • Drilling Manager: Conrad Perry (907) 727-7404 Conrad.Perry@CookInlet.net Drilling Engineer: Tyler Wagner (907) 433-3831 Tyler.Wagner@CookInlet.net Production Manager: David Kumar (907) 433-3822 David.Kumar@CookInlet.net 2 NFU 41-35 Work Over Program Stage 1 1. Rig up lubricator and pressure test to 3500 psi 2. RIH with spectra jet cutter, Gamma, and CCL correlate Cutting Depth @,8510' MD a. Check with town make sure packer is @ 8496' b. Pup joint is 13.71' Below top of packer c. Cut 1' down from top of pup joint X/O @ 8509.7' (Cut @ 8,510.7') 3. POH with jet cutter, gamma,and ccl 4. RIB with 2-1/8" ShoGun Strip guns 5. Perforate from 8510 to 8530(pending on tubing cut) • 6. POH and lay down spent guns 7. RIH with 2 1-8" ShoGun Strip guns 8. Perforate from 8,563'- 8,602' • 9. POH and lay down spent gun 10. Pick up and RIH with 2 1-8" ShoGun strip guns 11. Perforate 8683'—8690' ' 12. POH and lay down spent guns 13. RIG down Eline. 14. If well does not come on, Start swabbing operation with pollard Wireline. 15. Turn well over to production 3 Current Condition NFU 4135 Final Completion Schematic Version: Current _ Cook Inlet Energy_ April 24,2016 120"Conductor 0 246' I .1 [ 185/8"Hole ll'': 4 1/4"chemical injection line 4 1 Chemical Injection Mandrel(0 2,300' 13-3/8" 81#888# 2000'MD i e► ID J-55 HTC 2000'TVD 12 1M"Hole Perforations DVtool t 6,310' NU 8005-8045 < I 2-7/8"6.5#N-80 EUE 8rd-M tubing 8530-8540 (squeezed) 8563-8602 10786 10805-10860 10875 (squeezed) 19-5/8"baker S-3"Packer©7,966' , .'4, - •- Sliding Sleeve 0 7,985'closed 3 Blast joints 7,993'-8,052' 9 5/8" 43.5#N-80 8 P-110 8451 MD ID- BTC 8451TVD I Brown Tie-Back Sleeve 0 8,330'j 4_ 7"baker Model"D"Packer @ 8,496' 2-7/8"BXN Nipple @ 8,552' I ewe '' , -,,; " Perforations(squueaad)8,530'&8,540' 2-7/8 WLEG 0 8,554 1 -._ '+• ,_ Perforations(Open)8,563'-8,602' Partially milled retainer @ 9,960'1 ;-7' ____ T�10,009' Whipstock 9 10,173'1 Sidetrack hole drilled to 10,859'(Uncased I iii ',A k • _ ' tr.-- TOC 0 10,765' 4: ` Perforations(Squeezed)0 10,875' 7" 28#P-110 HTC 10985 M D {.81A...1111199..4"........"....... TOC 0 10,913' 1 ID- (Liner @ 10,985' 109asTvo "'t P TO@12,812 4 Y Proposed Well Schematic NFU 41-35 Proposed Schematic Version:Proposed s Cook Inlet Energy_ Apra 24,2015 I:1 20"Conductor qg 246' 1� l 18-5/8"Hole Y` I II 4 - 1/4"chemical injection line it"14 Chemical Injection Mandrel©2,300' 13-3/8" 81#&88# 2000 MD u...- ID ID J-55 BTC 2000 TVD 12 114"Hole DV tool©6,310' Perforations MD 8005-8045 4 I 2-7/8"6.5#N-80 EUE 8rd-M tubing 8530-8540 (squeezed) 8563-8602 10786 10805-10860 10875 (squeezed) 8510-8530 NEWPBiFS 8683-8690 NEN FERFS 19-5/8"baker S-3"Packer®7,966' 4 - Sliding Sleeve(CO 7,985'closed F^ 3 Blast joints 7,993.-8,052' 9 5/8" 43.5#N-80&P-110 8451 MD ,t ID- BTC 8451TVD I r •Brown Tie-Back Sleeve(0 8,330' 7"baker Model"D"Packer 8,496' Ems_,,, 2 7/8's 6.5#Tubing end 0 8,509'Jet cut I - Perforations(s•uuezed 8,530'&8,540' L - , Perforations(Open)8,563'-8,602' """� Fish 37'long,2 7/B's 6.5#tubing on top Partially milled retainer 9,960'I ► r- 'T 4-„„____ TOC(d 10,009' I Whipstock@ 10,173'1 Sidetrack hole drilled to 10,859'(Uncased 17:14 .3'41 eir.-•--..- TOC @ 10,765' a t, ""+i"_ i� 3,y E.—. Perforations(Squeezed)©10,875' 7" 28#P-110 BTC 10985 M D Ali* �.....'...""...." TOC @ 10,913' I ID- Liner 10,886' 109851VD I 71 ITD @ 12,8121 5 RECE ED ' STATE OF ALASKA ' ALASKA OIL AND GAS CONSERVATION COMMISSION AP' 7 2015 APPLICATION FOR SUNDRY APPROVALS AOGCc 20 AAC 25.280 1.Type of Request: Abandon 0 Plug for Redrill❑ Perforate New Pool 0 Repair Well 0 Change Approved Program 0 Suspend❑ Plug Perforations❑ Perforate❑� Pull Tubing❑ Time Extension 0 Operations Shutdown 0 Re-enter Susp.Well 0 Stimulate 0 Alter Casing 0 other: Cut tubing 0 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Cook Inlet Energy,LLC Exploratory ❑ Development Q 165-021 3.Address: 6.API Number: Stratigraphic ❑ Service • 601 W.5th Avenue,Suite 310,Anchorage,AK 99501 50-231-10004-00 7.If perforating: :.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? North Fork Unit#41-35 Will planned perforations require a spacing exception? Yes 0 No 0 9.Property Designation(Lease Number): 10.Field/Pool(s): , ADL 391210 North Fork, un,,efined gas WGA 11. PRESENT WELL CONDITION SUMMA- Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): ffective De. ND(ft). Plugs(measured): Junk(measured): 12,812' 12,812' 10,009' 1,009' None none Casing Length Size M' ND Burst Collapse Structural Conductor 246 20" `4-� 246' N/A N/A Surface 1,984' 13-3/8" ,I1 10' 2,000' 3,090' 1,540' Intermediate 8,435' 9-5/8's .;,451' 8,451' 6,330' 3,810' Production Liner 2,529' 7" % 10,985' 10,985' 9,960' 6,210 Perforation Depth MD(ft): Perforation Depth ND(ft): ii .' g Size: Tubing Grade: Tubing MD(ft): l 8,005'to 8,045';8,530'-8,602' 8,005'-8,045';8,530'-8,6. /8's 6.5#N-80 BTC-M 8,045' Packers and SSSV Type: Brown 2 7R 9-5P" .-1 Packer Packers and SSSV MD(ft)and TVD(ft): 7,952'MD/TVD,8,496'MD/TVD No SSSV \ i 12.Attachments: Description Summary• Pro.o • 13.Well Class after proposed work: Detailed Operations Program ❑✓ BOP Ske ❑ Exploratory ❑ Stratigraphic❑ Development 0 Service 0 14.Estimated Date for ASAP / 15.Well Status after proposed work: Commencing Operations: Oil ❑ Gas 0 WDSPL 0 Suspended ❑ 16.Verbal Approval: Da -: WINJ 0 GINJ ❑ WAG 0 Abandoned ❑ Commission Representative: GSTOR 0 SPLUG 0 17.I hereby certify that the foregoing is true, d correct to the best of my knowledge. Contact Tyler Wagner Email Tyler.Wagner@cookinlet.net Printed Name Tyler Wagner / 907-433-3831 Title Drilling Engineer-4-27-2015 Signature Phone Date - - ' COMMISSION USE ONLY Conditions of approval: Notify'ommission so that a representative may witness Sundry Number: 315 r i Plug Integrity 0 BOP Test E Mechanical Integrity Test 0 Location Clearance ❑ Other: Spacing Exception Required? Yes 0 No 0 Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Submit Form and Form 10-403(Revised 10/2012) Approved application is valid for 12 months from the date of approval. Attachments in Duplicate • Cook Inlet Energy_ April 27, 2015 Cathy Foerster, Chair RECEIVED Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 APR 2 7 2015 Anchorage, Alaska 99501AOGCC Re: Application for Sundry Cook Inlet Energy, LLC: North Fork Unit#41-35 (PTD 165-021) Dear Ms. Foerster, Cook Inlet Energy (CIE) hereby submits a completed form 10-403 and application for sundry approval to cut tubing tail and perforate 2 new zones. a. 8,510' -8,530' MD b. 8,683' -8,690' MD If you have any questions, please contac e at(907) 433 3831. Sincerely, Tyler Wagner Drilling Engineer Cook Inlet Energy 601 W.5th Avenue,Suite 310,Anchorage,AK 99501 (907)334-6745*(907)334-6735 fax NFU 41-35 -Well Summary Current Status: NFU 41-35 is currently producing Scope of Work: • Cut TBG • Perforate new zones General Well Information: MASP: 2800 psi Reservoir Pressure/TVD: 3662 psi @ 8690 MD / 8690' TVD Wellhead Type/Pressure Rating: Vetco Grey 11"-5M BOP Configuration N/A Well Type: Gas Producer Estimated Start Date: April 30, 2015 Drilling Manager: Conrad Perry (907) 727-7404 Conrad.Perry@CookInlet.net Drilling Engineer: Tyler Wagner (907) 433-3831 Tyler.Wagner@CookInlet.net Production Manager: David Kumar (907) 433-3822 David.Kumar@CookInlet.net 2 NFU 41-35 Work Over Program Stage 1 1. Rig up lubricator and pressure test to 3500 psi 2. RIR with spectra jet cutter, Gamma, and CCL correlate Cutting Depth @ 8510' MD a. Check with town make sure packer is @ 8496' b. Pup joint is 13.71' Below top of packer c. Cut 1' down from top of pup joint X/O @ 8509.7' (Cut @ 8,510.7') 3. POH with jet cutter, gamma, and ccl 4. R1H with 2-1/8" ShoGun Strip guns 5. Perforate from 8510 to 8530 (pending on tubing cut) 6. POH and lay down spent guns 7. Pick up and RUT with 2 1-8" ShoGun strip guns 8. Perforate 8683'—8690' 9. POH and lay down spent guns 10. RIG down Eline. 11. If well does not come on, Start swabbing operation with pollard Wireline. 12. Turn well over to production 3 Current Condition NFU 41-35 Final Completion Schematic Version: Current Cook Inlet Energy_ April 24,2015 120"Conductor @ 246' 1 118.5/8"Hole 1 1/4"chemical injection line il '< I Chemical Injection Mandrel @ 2,300' 13-318" 81#&68# 2000'MD ....- ID ID J-55 BTC 2000'TVD 1 12 1/4"Hole 1 DV tool @ 6,310' Perforations ID 8005-8045 1 2-7/8"6.5#N-80 EUE 8rd-M tubing 8530-8540 (squeezed) 8563-8602 10786 10805-10860 10875 (squeezed) 19-518"baker S-3"Packer @ 7,966' I ''k: 'Sliding Slee'e @ 7,985'closed 1 13 Blast joints 7,993'-8,052' 1 9 518" 43.5#N-80&P-110 8451 MD ID- BIC 8451TVD , lb. Brown Tie-Back Sleese @ 8,33071 7"baker Model"D"Packer @ 8,496' 2-7/8"BXN Nipple @ 8,552' altl. Perforations(squuezed)8,530'&8,540' 2-7/8 WLEG @ 8,554 1 MI I !' Perforations(Open)8,563'-8,602' Partially milled retainer @ 9,960'1 -,J 'I, TOC @ 10,009' 1 Whipstock @ 10,173'1 0 ,,,. . Sidetrack hole drilled to 10,859'(Uncased 1 c'`' TOC @ 10,765' L PerforationsS ueezed 10,875' 7" 284 P-110 BTC 10985 MD - TOC @ 10,91(3 ID- Liner @ 10,985' 10985rVO TD @ 12,812 I 4 Proposed Well Schematic NFU 41-35 Proposed Schematic Version:Proposed Cook Inlet Energy April 24,2015 120"Conductor @ 246' 1 118-5/8"Hole 11/4"chemical injection line 1 1 Chemical Injection Mandrel @ 2,300' 13-3/8" 81#&88# 2000 MD —a ID J-55 BTC 2000 TVD 12 1/4"Hole - 1DVtool@6,310' 1 Perforations MD 8005-8045 1 2-7/8"6.5#N-80 EU E 8rd-M tubing 8530-8540 (squeezed) 8563-8602 10786 10805-10860 10875 (squeezed) 8510-8530 NEW F/8 FS 8683-8690 NEW FfftFS 19-5/8"baker S-3"Packer @ 7,966' ��— - [Sliding Sleeve @ 7,985'closed I 13 Blast joints 7,993'-8,052' 1 9 518" 43.5#N-80&P-110 8451 MD ie ID- BTC 8451TVD , Brown Tie-Back Sleeve @ 8,330'I 7"baker Model"D"Packer @ 8,496' 2 7/8's 6.5#Tubing end @ 8,509'Jet cut Perforations(squuezed)8,530'8 8,540' 1iT � Perforations(Open)8,563'-8,602' Fish 37'long,2 7/8's 6.5#tubing on top Partially milled retainer @ 9,960'1 s `. TOC @ 10,009' Whipstock@ 10,173'1 � 3 4C--- Sidetrack hole drilled to 10,859'(Uncased 1 F—----- TOC @ 10,765' J i..:".1.-Y1.17 � Perforations(Squeezed)@ 10,875' 7" 28#P-110 BTC 10985 M D I' .`,•t 9�- t�—` TOC @ 10,913' I ID- Liner a 10,985' 109857VD i''1 ITD @ 12,8121 5 ( • Davies, Stephen F (DOA) From: Tim Jones <Tim.Jones@cookinlet.net> Sent: Tuesday, April 28, 2015 4:34 PM To: Davies, Stephen F (DOA) Cc: Conrad Perry; Tyler Wagner Subject: RE: North Fork Unit 41-35 (PTD # 165-021) Hi Steve, I have answered each question below. Please let me know if you need any further information. Tim Regarding the proposed perforations in North Fork Unit 41-35: 1. What regulation or Conservation Order governs well spacing in this pool? (That line was left blank in Box 7 of the application form.) a. Well spacing in this pool is governed by the statewide spacing requirements found in 20 AAC 25.055. The statewide spacing requirements are modified by several spacing exception Conservation Orders granted by the Commission. Specifically,these Conservation Orders are: i. CO 601.000 (May 21, 2008)— North Fork 34-26 ii. CO 632.000 (August 19, 2010)—North Fork Unit 32-35 iii. CO 633.000 (August 19, 2010)—North Fork Unit 14-25 iv. CO 660.000 (September 27, 2012)—North Fork Unit 33-35 (undrilled) v. CO 661.000 (September 27, 2012)—North Fork Unit 23-25 vi. CO 662.000(September 27, 2012) (Expired)—North Fork Unit 42-35 vii. CO 663.000(September 27, 2012)—North Fork Unit 22-35 viii. CO 705.000 (November 14, 2014)—North Fork Unit 24-26 ix. CO 710.000 (December 4, 2014)—North Fork Unit 42-35 x. CO 714.000 (March 19, 2015)—North Fork Unit 22-26(undrilled) 2. What are the spacing requirements of that regulation or Conservation Order? a. The spacing requirements of 20 AAC 25.055(a)(4) require that "...not more than one well may be drilled to and completed in that pool on any governmental section: a well may not be drilled or completed closer than 3,000 feet to any well drilling to or capable of producing from the same pool." b. There are Conservation Orders modifying these requirements for all adjacent wells within the governmental section and within 3,000 feet of the North Fork Unit 41-35.The Conservation Orders specify that the wells subject to those Orders may be drilled, completed, tested and produced as long as they comply with the North Fork Unit Agreement, lease agreements, and all applicable Alaska and federal laws (or similar language). 3. Are any other wells in the North Fork Unit open to this same pool? a. There are several other wells within the North Fork Unit open to this same pool (the North Fork Undefined Gas Pool).They are: i. NFU 42-35, nearest open perforation 823 feet from 41-35 (CO 710.000) ii. NFU 34-26, nearest open perforation 1,630 feet from 41-35 (CO 601.000) iii. NFU 14-25, nearest open perforation 1,894 feet from 41-35 (CO 633.000) iv. NFU 32-35, nearest open perforation 1,929 feet from 41-35 (CO 632.000) v. NFU 24-26, nearest open perforation 2,595 feet from 41-35 (CO 705.000) vi. NFU 22-35, nearest open perforation 2,964 feet from 41-35 (CO 663.000) 1 • vii. NFU 23-25, nearest open perforation 3,586 feet from 41-35 (CO 661.000) 4. If so, what are the distances from the proposed perforations in North Fork Unit 41-35 to the open perforations in those wells? a. Please see answers to question 3 above. 5. Will the proposed perforations in North Fork Unit 41-35 conform to the spacing requirements of the governing regulation or Conservation Order? a. The proposed perforations will not conform to the spacing requirements of the governing regulation, 20 AAC 25.055. However, North Fork Unit 41-35 is currently capable of producing from the same pool as the adjacent wells, which are all subject to spacing exception Conservation Orders granted by the Commission at various times. All spacing exceptions were granted taking North Fork Unit 41-35's capability of producing from the same pool into consideration. b. There is no spacing exception Order for the North Fork Unit 41-35 because it was the first well drilled into the pool. However, the proposed new perforations in 41-35 will not penetrate any additional pools. The various other spacing exception Conservation Orders considered 41-35 as being capable of producing from the same pool.This Sundry application to add additional perforations within the same pool will not materially change how the field is being produced (i.e. no new pools). Therefore,41-35 is effectively governed by the Conservation Orders from all adjacent wells, and CIE believes an exception to 20 AAC 25.055 is not required for this Sundry request. From: Davies, Stephen F (DOA) [mailto:steve.davies@alaska.gov] Sent:Tuesday, April 28, 2015 8:35 AM To:Tyler Wagner Cc:Tim Jones Subject: North Fork Unit 41-35 (PTD# 165-021) Tyler, For perforations in a new well or for additional perforations proposed outside of existing perforated intervals, CIE's application must provide enough supporting documentation and enough time in advance for AOGCC to review that application to ensure that it conforms with governing rules or regulations. (See Regulation 20 AAC 25.015(b).) Regarding the proposed perforations in North Fork Unit 41-35: 1. What regulation or Conservation Order governs well spacing in this pool? (That line was left blank in Box 7 of the application form.) 2. What are the spacing requirements of that regulation or Conservation Order? 3. Are any other wells in the North Fork Unit open to this same pool? 4. If so, what are the distances from the proposed perforations in North Fork Unit 41-35 to the open perforations in those wells? 5. Will the proposed perforations in North Fork Unit 41-35 conform to the spacing requirements of the governing regulation or Conservation Order? The estimated date for commencing operations is listed as ASAP. Please be aware that all AOGCC personnel needed for review and approval of sundry applications may not be immediately available to meet rush requests. Please let me know if you have questions. Regards, Steve Davies Senior Petroleum Geologist 2 • Alaska Oil and Gas Conservation Commission (AOGCC) Phone: 907-793-1224 AOGCC: 907-279-1433 Fax: 907-276-7542 333 West 7th Avenue,Suite 100 Anchorage,AK 99501 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 Steve Davies at 907-793-1224 or steve.davies@alaska.gov. 3 • Davies, Stephen F (DOA) From: Davies, Stephen F (DOA) Sent: Tuesday, April 28, 2015 8:35 AM To: 'tyler.wagner@cookinlet.net' Cc: Tim Jones (Tim.Jones@cookinlet.net) Subject: North Fork Unit 41-35 (PTD# 165-021) Tyler, For perforations in a new well or for additional perforations proposed outside of existing perforated intervals, CIE's application must provide enough supporting documentation and enough time in advance for AOGCC to review that application to ensure that it conforms with governing rules or regulations. (See Regulation 20 AAC 25.015(b).) Regarding the proposed perforations in North Fork Unit 41-35: 1. What regulation or Conservation Order governs well spacing in this pool? (That line was left blank in Box 7 of the application form.) 2. What are the spacing requirements of that regulation or Conservation Order? 3. Are any other wells in the North Fork Unit open to this same pool? 4. If so, what are the distances from the proposed perforations in North Fork Unit 41-35 to the open perforations in those wells? 5. Will the proposed perforations in North Fork Unit 41-35 conform to the spacing requirements of the governing regulation or Conservation Order? The estimated date for commencing operations is listed as ASAP. Please be aware that all AOGCC personnel needed for review and approval of sundry applications may not be immediately available to meet rush requests. Please let me know if you have questions. Regards, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) Phone: 907-793-1224 AOGCC: 907-279-1433 Fax: 907-276-7542 333 West 7th Avenue,Suite 100 Anchorage,AK 99501 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 Steve Davies at 907-793-1224 or steve.daviesCa@alaska.gov. 1 Im~-'; Project Well History File Cow'-'Oage XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. L& ~__~- O~-J Well History File Identifier O,,a.,.,....,,o.,,,:,, Lo- ,0 o IIIIIIII!1111111111 /RescanNeeded IIIIIIIIIIIIIIIIII RESCAN DIGITAL DATA OVERSIZED (Scannable) Color items: [] Diskettes, No. [] Maps: Grayscale items: [] Other, No/Type [] Other items scannable by large scanner [] Poor Quality Originals: OVERSIZED (Non-Scannable) n Other: [] Logs of various kinds NOTES: [] Other Project Proofing BEVERLY ROBIN VINCENT SHERYt~'~CJlNDY BY: Scanning Preparation ~ x 30 = /~-~) BEVERLY ROBIN VINCENT SHERY~WINDY · + ~'~,,.0 = TOTALPAGES /7° Production Scanning Stage BY: PAGE COUNT FROM SCANNED FILE: / ~} PAGE COUNT MATCHES NUMBER IN SCANNING PREPARATION: ,~ YES NO Stage 2 IF NO IN STAGE 1, PAGE(S) DISCREPANCIES WERE FOUND' __ YES NO RESCANNEDBY: BEVERLY ROBIN VINCENT SHERYL MARIA WINDY DATE: /SI General Notes or Comments about this file: Quality Checked 12/10/02 Rev3N OTScanned.wpd 0 • 0 UNSCANNED, OVERSIZED MATERIALS AVAILABLE: f6,5' DZ I FILE # 1-40,5 �Ww't To request any/all of the above information, please contact: Alaska Oil & Gas Conservation Commission 333 W. 7th Ave., Ste. 100 Anchorage, Alaska 99501 Voice (907) 279-1433 Tax (907) 276-7542 STATE OF ALASKA ,, ALAI"OIL AND GAS CONSERVATION COMMIW)N REPORT OF SUNDRY WELL OPERATIONS 1' 4, 2 2 20,,, 1.Operations Abandon U Repair Well U Plug Perforations U Perforate U Other❑ 4°1k . . C`i. Performed: Alter Casing ❑ Pull Tubing❑ Stimulate-Frac ❑ Waiver❑ Time Extension❑ Change Approved Program ❑ Operat.Shutdown❑ Stimulate-Other ❑ Re-enter Suspended Well❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Armstrong Cook Inlet,LLC Development gg Exploratory❑165-021 3.Address: Stratigraphic ID Service ❑ 6.API Number. 1421 Blake St.,Denver,CO 80202 50-231100040000 • 7.Property Designation(Lease Number): 8.Well Name and Number: ADL-391210 . North Fork Unit#41-35 - 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): Undefined gas • 11.Present Well Condition Summary: Total Depth measured 12812 feet Plugs measured 8552' feet Tbg Plug true vertical 12812 feet Junk measured na feet Effective Depth measured 10009 feet Packer measured 7966 feet true vertical 10009 feet true vertical 7966 feet Casing Length Size MD TVD Burst Collapse Structural 246 20 246 246 na na Conductor Surface 1984 13 3/8 " 2000 2000 3090 1540 Intermediate 8435 9 5/8 " 8451 8451 6330 3810 Production Liner 2529 7 " 10985 10985 9960 6210 Perforation depth Measured depth 8005'-45' feet open True Vertical depth 8005'45' feet Tubing(size,grade,measured and true vertical depth) 2 7/8 " N-80 8554 8554 Packers and SSSV(type,measured and true vertical depth) NO SCSSV Baker Model S-3,Model D 7966',8505' 7966',8505' 12.Stimulation or cement squeeze summary: Intervals treated(measured): na SCANNED NOV 0 6 2ui3 Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: na 6-800 1-5 171 260psi on comp Subsequent to operation: na 485 1 156 219psi on comp 14.Attachments: 15.Well Class after work: Copies of Logs and Surveys Run Exploratory❑ Development Service ❑ Stratigraphic ❑ Daily Report of Well Operations 16.Well Status after work: Oil ❑ Gas 0 • WDSPL❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: Contact Stephen Hennigan Ph: (337)849-5345 Email shennigan(a�peiinc.com Printed Name r _ . Title Vice President-Engineering Sig ature - �. Phone (303)623-1821 Date \W 4— \' 11 romsr.rr.Fo-- =:`u Wilk -mSYla1ffi l rrn • RBD S OC 2 5 2 8,2 -/3 /mil RECEI A VED OCT222013 ARMSTRONG AOGCC Cookinlet,LLC October 9, 2013 Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Enclosed 10-404 for Armstrong Cook Inlet, LLC NFU#41-35(PTD No. 165-021) Dear Ms. Foerster, Armstrong Cook Inlet, LLC is providing the 10-404 for the above referenced well. Data provided includes the form, present WBS, and summary of activities. If you have any questions or require additional information, please contact me at(303)623-1821 or Stephen Hennigan at(337)849-5345, or Craig Rang at(907)252-6799. Sincerely, jcir Edward Teng Vice President-Engineering Armstrong Cook Inlet, LLC Enclosures Cc: Stephen Hennigan— Petroleum Engineers for Armstrong Cook Inlet, LLC 1421 Blake Street, Denver, CO 80202 (303)-623-1821 Ph (303)-623-3019 Fax • • North Fork Unit #41-35 Wellbore Schematic PTD 165-021 8/25/2010 Final 09 07 2013 J20"Conductor 246' 1/4"Chemical Injection Line 18-5/8"Hole 13-3/8"61#&68#J-55 BTC Casing @ 2,000' Chemical Injection Sub @ 2,300' 2.347"Drift ID,4.10"OD,L-80 12-1/4"Hole 2-7/8"6.5#N-80 EUE 8rd-M Tubing IL DV Tool @ 6,310' 9-5/8"Baker S-3"Packer @ 7,966' Sliding Sleeve @ 7,985' ■ Perforations 8,005'-8,045' 3 Blast Joints 7,993'-8,052' ► Brown Tie-Back Sleeve @ 8,330' lir 9-5/8"43.5#N-80&F.-no BTC Casing @ 8,451' 7"Baker Model"D"Packer @ 8,500' ,i/ ►� X-•IU• & ron•_installed Se• 2013 2-7/8"BXN Nipple @ 8,552' r !" 2-7/8"WLEG @ 8,554' Perforations(squeezed)8,530'&8,540' Perforations(open)8,563'-8,602' TOC @ 10,009' itirtoni Whipstock @ 10,173' 1 '40 Lril Sidetrack hole drilled to 10,859'(Uncased) TOC @ 10,765' Perforations @ 10,786' . '~ Perforations 10,805'—10,860' • - Perforations(Squeezed)@ 10,875' TOC @10,913' t 7"26#P-110 BTC Liner @ 10,985' TD @ 12,812' • • ARMSTRONG Cook Inlet LLC 1421 Blake Street, Denver, Colorado 80202 North Fork Unit #41-35 Sec 26-4S-14W PTD 165-021 Kenai Peninsula Borough, Alaska 3-Sep-13 PJSM.Test. RIH w/2.5"xline w/pxn plug body to 8563' wlm. POOH. Plug set. RIH w/2"SB w/3' prong to 8559' wlm. POOH. Prong set. RIH w/swabs to 7950'. No fluid. RIH w/2.5"42B0 shifting tool to 7993' wlm (in down pos to close). Tool kept falling thru. POOH,tool OK. RIH w/same tool w/knuckle jt to same latch. Fall thru, sit down several passes,wouldn't latch. POOH. RIH w/same BHA to shift up. Made several passes. Wouldn't latch. POOH. Rig down. Reinstall tree cap and wellhouse hatch. Release crew. SS is open. 29-Aug-13 PJSM. Make up tools, lubricator and BOP's.Test. RIH w/2" bailer to 9000'-did not tag. POOH. RIH w/2.25" blind box.Tag fluid @2520'. RIH w/2.5"42B0 shifting tool to 7985' Attempt to latch SS wo success. Wait on swab eqpmnt. W 0 Schwartz, Guy L (DOA) AoS-bZ1 From: Schwartz, Guy L (DOA) Sent: Friday, August 30, 2013 12:50 PM To: 'Stephen Hennigan'; Ferguson, Victoria L (DOA) �-�•�j Subject: RE: Armstrong North Fork Unit #41-35 PTD,a-IT-167 Setting the WL plug will not require a sundry. You may proceed with proposed work as written below and submit a 10-404 report with " plug Perforations" as well work that was done. Guy Schwarz- Senior Petroleum Engineer AJI..L 907-444-3433 cell n,m - -,ff� . From: Stephen Hennigan [ Sent: Friday, August 30, 2013 11:46 AM To: Schwartz, Guy L (DOA); Ferguson, Victoria L (DOA) Subject: Armstrong North Fork Unit #41-35 PTD 310-167 We need to get a response on this asap please. SCANNED OCT 2 8 2014 Water from the lower zone is killing the well and also impacting the dehy. We would like to set a plug in the lower completion assy to shut off the lower zone. Attached is the WBD. Below is the Baker log showing where the plug profile is: Tubing Tally Tubing Tally Operat+ng Compwiy: Airr"ong Represented by Well N._irne or Nun*n(. NFV#41-35 Lease ` Anchcr Pant Fi&4- Norri Fork County. Kondi RVJ Name Gleclw #1 Tuting;ae 1 rin r 2675 Weight lr :+fi'r 6.53 Geade N-8- Conrwctwi. EUE Make upTpr, Tubing Size 2 kin) Weight ilb"): Grade: connection: Make up Toro DESCRIPTION Joni No. Jts In Number Mots Strop Length Running Depths From To Final Dela F rom Mule Shood LEG 065 000 0.66 t3556.;J4 BXN nI 2.31 profile 2,21 0 1.13 065 1.78 5555.21 Tubing 2 7/8-6.59 N-80 oint 1 31.92 1.78 33.70 852329 2 7/8-6.50 Ni -80 Pup Joint 0 4.20 33.70 37.90 851909 Crossover$0-32 SIDE X 2 718 EUE 0 0.69 37.90 3859 8518.40 Seal Bore Ext. 80-32 0 9.38 38.59 47.97 850902 "B" Guide 7" Baker 84-32 Model "D' Packer 0 0 0.57 3.07 47.97 4654 48.34 51.61 We 45 8505.33 Locator Seal ass . 0 3 10 51.61 5531 8501.63 2 7f8.6.50 N-80 Pup Joint 1 8.15 55.31 63.46 8493.53 May we please have a verbal to perform the operation of: 1. RU WL lubricator and test to SIP +50% 2. Perform a guage ring run. 3. RIH w/ plug and set in profile at +-8551' 4. POOH S. RD 6. Return well to production. / 34fk Project Manager/Engineer - PETROLEUM ENGINEERS, INC. 500 Dover Boulevard, Suite 310 ; Lafayette, LA 70503 Office: 337-984-2603 2 Mobile: 337-849-5345 • • ARMSTRONG ( 00A ,,jiJIC November 16, 2011 if Er Mr. Daniel Seamount, Chair ii s ;� Alaska Oil and Gas Conservation Commission 333 West 7 Ave., Suite 100 : ,. ; f . ° Anchorage, Alaska 99501 RE: Report of Sundry Well Operations ! O� North Fork Unit Well #41 -35 (Sundry No. 311 -346) J" Dear Mr. Seamount, Armstrong Cook Inlet, LLC hereby submits it Report of Sundry Well Operations to open a sliding sleeve in North Fork Unit Well #41 -35 to produce a perforated interval previously isolated from the production stream. If you have any questions or require additional information, please contact me at (303) 623 -1821 or Bill Penrose at (907) 264 -6114. Sincerely, ARMSTRONG COOK INLET, LLC " Edward Teng Vice President, Engineering Enclosure 1424 Blake Street, Denver, Colorado 80202 Ph 303 -623 -1821 Fax 303 - 623 -3019 STATE OF ALASKA " • ALASKA. AND GAS CONSERVATION COMMISS• //--2 9-// REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon Li Repair Well U Plug Perforations ❑ Stimulate U Other U Open sleeve Performed: Alter Casing ❑ Pull Tubing ❑ Perforate New Pool ❑ Waiver ❑ Time Extension ❑ Change Approved Program ❑ Operat. Shutdown ❑ Perforate ❑ Re -enter Suspended Well ❑ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Armstrong Cook Inlet, LLC Development 1511 Exploratory ❑ 165 -021 3. Address: Stratigraphic❑ Service ❑ 6. API Number: 1421 Blake Street, Denver, CO 80202 , 50- 231 - 10004 -00 r° 00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL -391210 \. North Fork Unit #41-35 9. Field /Pool(s): North Fork Lt i1 k- 1t d &AS 1:1'P 2 10. Present Well Condition Summary: Total Depth measured 12,812 feet Plugs measured N/A feet true vertical 12,812 feet Junk measured N/A feet Effective Depth measured 10,009 feet Packer measured 7,966 feet true vertical 10,009 feet true vertical 7,966 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 246' 20" 246' 246' N/A N/A Surface 1,984' 13 -318" 2,000' 2,000' 3,090 psi 1,540 psi Intermediate 8,435' 9-5/8" 8,451' 8,451' 6,330 psi 3,810 psi Production Liner 2,529' 7" 10,985' 10,985' 9,960 psi 6,210 psi Perforation depth Measured depth 8005'4045', 8563' -8602' True Vertical depth 8005'- 8045', 8563' -8602' Tubing (size, grade, measured and true vertical depth) 2 -7/8" N-80 8,554' 8,554' Packers and SSSV (type, measured and true vertical depth) No SSSV Baker S4 pkr 7,966' 7,966' 11. Stimulation or cement squeeze summary: treated (measured): N/A + 1 I '4 6 ' Treatment descriptions including volumes used and final pressure: N/A )Y}a"•ks flit & Gag ems. Corfii`i6asi/tft 12. Representative Daily Average Production or Injection Data Oil -Bbl Gas -Mcf Water -Bbl ' Casing Pressure Tubing Pressure Prior to well operation: 0 528 1 BWPD 316 psi 1,768 psi Subsequent to operation: 0 2,175 1 BWPD 319 psi 1,935 psi 13. Attachments: 14. Well Class after work: Copies of Logs and Surveys Run N/A Exploratory ❑ Development is ,, Service ❑ Stratigraphic ❑ Daily Report of Well Operations Yes 15. Well Status after work: Oil ❑ - Gas is WDSPL ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 16. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 311 -346 Contact Bill Penrose 907 - 264 -6114 Printed Name Edward Ten, Title Vice President - Engineering / �I Ph one 303 -623 -1821 Date Nov. ` �� Signatu - .r \ _ -0//' corm 10 401 Rcviocd 10/2010 / Cubmit Original Only R: # MS NOV a 1 2ii‘" g""h-cis' • • • North Fork Unit #41 -35 Wellbore Schematic 11/4/2011 20" Conductor @ 246' 1/4" Chemical Injection Line ► 18 -5/8" Hole 13 -3/8" 614 & 684 J -55 BTC Casing @ 2,000' Chemical Injection Mandrel @ 2,300' ►- 12-1/4" Hole 2 -7/8" 6.54 N -80 EUE 8rd -M Tubing • IL DV Tool @ 6,310' 9 -5/8" Baker S -3" Packer @ 7,966' >< Sliding Sleeve @ 7,985' (open) � Perforations 8,005' - 8,045' 3 Blast Joints 7,993' - 8,052' I / Brown Tie -Back Sleeve @ 8,330' X 9 -5/8" 43.54 N -80 & P -110 BTC Casing @ 8,451' 7" Baker Model "D" Packer @ 8,500' >.< x 2 -7/8" BXN Nipple @ 8,552' Perforations (squeezed) 8,530' & 8,540' 2 -7/8" WLEG @ 8,554' Perforations (open) 8,563' - 8,602' TOC @ 10,009' Whipstock @ 10,173' Sidetrack hole drilled to 10,859' (Uncased) TOC @ 10,765' 1 Perforations @ 10,786' Perforations 10,805' — 10,860' Perforations (Squeezed) @ 10,875' TOC @ 10,913' 7" 264 P -110 BTC Liner @ 10,985' TD @ 12,812' • • ARMSTRONG WELL SERVICE REPORT Date: /J - (1_11 Well Number: mpg y )-- 35 Work being done: $t-i; r 1-- 4 -ma Stec" Location: itn c t.,a r p ; ,,, - Supervisor: Qi e )(: — AFE# ! Charge Code: Wireline Unit Number: Siem,,,ck - c k Pollard Wireline Crew: (-,,.e I166 y /,,,„, ,.) /(1 a,, Tree Connection Size/Type 2 -,g V J Total Wireline Miles: 3 Tree condition _,: _ Wire Test: ` f q Fluid Level if Identified ,3/4 Max Depth (KB): - q,6- 1 40 _1 Zero Wireline at: Tubing Hanger Well KB: t ol r i- Minimum Tubing ID: Max ,it .7 r3 1 3 Tool OD: .,2,.2 s _ Start Tbg. & Csg. PSI /4/s Ending Tbg & Csg PSI 54 it f % ( "`5 Time Operation Details WIL valve ' / S OS30 Gtcr. ve ect SLor 5 e4 - 45 / e -y..r; f.t e.. `t 1 d — ( 0 e° 4 are ;c.c u+ u.- P,> >K+ rA :ce.cr r_.,/r6. -t n o 'rao 2 s 5 t4 1 9 oqYr P,4. ((.i,..4 t...4 ti,, .4- r) 3, - esf .— loon g(1-F U/ zh'' (0 Si.,.. -4;-‘ fr)eit -IL, 7 / eig . S"' 4-21m lo,.. <(ee„z ii t Seve «t - ic ezetcu,t , nt,c.G ►•e.t 4e,..e - tr4,rci,�l.t Stee..c' r,nt, (U So ati-i ,. /‹,.....e ji> 7 q - (-AP- I-I f ifee.c jc.i-r f - irvt< . r ev 41,,,,I... 5 '. ce.,ld?., L4 to c,., }c a :.., pooh p i s 1 0,9 ii I'! Do".-' 17 3o Pe. 1 2t, r t Inc .,.1-: ar. I L 3o a eo r ■ vC r..+ < Ivo i f ) 7 ' Ro S L', F- I-,,-. fo ci ( 12-* `1- Work StringDetail:I f K's, Coe ^ , S 1 -c.-, k"'s', v51 c5 Size and Length 6"' g• • S ' S' 3' 7'4,` 7 ' Description of any tools or debris left in the hole: Brief Summary of SI-:(f CmK 51 c(r<ve eyeri . f 7 t5'f5' ,�i3 Total Work h-t ,=, -. c.�o 4 u Ore" ,s r, 4c.; el le, c c Completed Irotal Hours Worked' t Total Tool Cost( 12f 1 Total Hour Cost' 3, q2Y 1 1 Ticket # : Day* : Daily Cost: Li D Z -°-=-- e Cumulative Cost: - o 52 Well Downtime Hr. Shut i ✓ s I, H2S PPM p) f, f Approved by: Code: • • • . • SITOE ALASEA SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 Edward Teng Vice President, Engineering Armstrong Cook Inlet, LLC 1 1421 Blake Street ©d' Denver, CO 80202 Re: North Fork Field, North Fork Pool, NFU #41 -35 Sundry Number: 311 -346 Dear Mr. Teng: )i;%�` 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 e weekend. Si erely, di* 9 Com -. oner DATED this / day of November, 2011. Encl. • •TE OF ALASKA Ii "‘/ - I) i ifECE NEC) ALASKA OIL AND GAS CONSERVATION COMMISSION ° " '' '' �� APPLICATION FOR SUNDRY APPROVALS 4- 20 AAC 25.280 11 ors. Li USS10Mt 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Ch Pro ❑ Suspend ❑ Plug Perforations ❑ Perforate ❑ Pull Tubing ❑ Time Extension ❑ Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate 0 Alter Casing p I Other: Open sleeve 0 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Armstrong Cook Inlet, LLC Development © Exploratory ❑ - 165-021 3. Address: Stratigraphic ❑ service ❑ 6. API Number: 1421 Blake Street, Denver, Colorado 80202 - 50- 231 - 10004 -00 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes ❑ No 15 North Fork Unit #41-35 9. Property Designation (Lease Number): ! 10. Field/Pool(s): ADL391210 ` f North Fork 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): 12,812' 12,812' 10,009' 10,009' N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 246' 20" 246' 246' N/A N/A Surface 1,984' 13-3/8" 2,000' 2,000' 3,090 psi 1,540 psi Intermediate 8435' 9.6/8" 8,451' 8,451' 6,330 psi 3,810 psi Production • Liner 2,529' 7" 10,985' 10,985' 9,960 psi 6,210 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 8005' - 8045', 8563' -8602' 8005 -8045, 8563' -8602' 2 -7/8" N-80 8,554' Packers and SSSV Type: Pkr: Baker S-3, SSSV: None Packers and SSSV MD (ft) and TVD (ft): Pkr at 7,966' MD, TVD 12. Attachments: Description Summary of Proposal ❑ 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Development © Service ❑ 14. Estimated Date for 15. Well Status after proposed work: 11/7/2011 Commencing Operations: Oil ❑ Gas gg WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: //• 3 • it WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: Foe rs.E,..,r /Ql/czt.44 de p GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Bill Penrose 907 - 264 -6114 Printed Name Title Edward Teng Vice President, Engineering �Signa' } �.��/ Phone Date ��/• ter, 303-623 -1821 / • , o / COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3 fJ '5"i' ( Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Subsequent Form Required: `---VOL APPROVED BY Approved by: t , MISSIONER THE COMMISSION Date: /••• 9:0 /7 Submit in Duplicate �� Revised P Form 10-403 S visd 1/2010 NOV o9 ORG1NAL jrs,0/#//4/,‘,/ I , • • North Fork Unit #41 -35 Welibore Schematic 8/25/2010 J L 20" Conductor @ 246' 1/4" Chemical Injection Line • 18 -5/8" Hole 13 -3/8" 61# & 68# J -55 BTC Casing @ 2,000' Chemical Injection Mandrel @ 2,300' 0— 12-1/4" Hole 2 -7/8" 6.5# N -80 EUE 8rd -M Tubing • k DV Tool @ 6,310' 9 -5/8" Baker S-3" Packer @ 7,966' Sliding Sleeve @ 7,985' • .. Perforations 8,005' - 8,045' 3 Blast Joints 7,993' - 8,052' • Brown Tie -Back Sleeve ® 8,330' Q X r , 9 -5/8" 43.5# N -80 & P -110 BTC Casing @ 8,451' 7" Baker Model "D" Packer @ 8,500' X X 2 -7/8" BXN Nipple @ 8,552' 2 -7/8" WLEG @ 8,554' Perforations (squeezed) 8,530' & 8,540' Perforations (open) 8,563'- 8,602' TOC @ 10,009' * Whipstock @ 10,173' Sidetrack hole drilled to 10,859' (Uncased) TOC @ 10,765' 6 4 ),/ 4 Perforations @ 10,786' 'ms Perforations 10,805' – 10,860' a Perforations (Squeezed) @ 10,875' TOC @ 10,913' - r A , 7" 26# P -110 BTC Liner @ 10,985' TD @ 12,812' A • ARMSTRONG November 4, 2011 ECEI Mr. Daniel Seamount, Chair Alaska Oil and Gas Conservation Commission s 6:a?, C pis 333 West 7 Ave., Suite 100 Aw Anchorage, Alaska 99501 RE: Application for Sundry Approval Open Additional Interval, North Fork Unit Well #41 -35 (PTD No. 165 -021) Dear Mr. Seamount, Armstrong Cook Inlet, LLC hereby applies for approval to open a sliding sleeve in North Fork Unit Well #41 -35 to produce a perforated interval that is currently isolated from the production stream. Since a workover to recomplete NFU #41 -35 in 2010, the Tyonek interval 8,563' — 8,602' has been producing sales gas with negligible water. This interval's initial post - workover pressure was 3,618 psi. A shallower Tyonek interval at 8,005' — 8,045' has remained isolated behind a closed sliding sleeve because its initial post - workover reservoir pressure of 2,973 psi significantly differed from that of the deeper interval. Last week, after approximately a year of production, the well was shut in and a surface pressure buildup was recorded and extrapolated downhole to the open perforations. The reservoir pressure in the lower interval (8,563' — 8,602') is now 2,795 psi, within 178 psi of the isolated upper interval and Armstrong requests approval to open the sliding sleeve in this well to comingle the gas production from both intervals within the Tyonek Fm. If you have any questions or require additional information, please contact me at (303) 623 -1821 or Bill Penrose at (907) 264 -6114. Sincerely, ARMSTRONG COOK INLET, LLC Fla m ice- Edward Teng Vice President, Engineering Enclosures 1424 Blake Street, Denver, Colorado 80202 Ph 303 - 623 -1821 Fax 303 - 623 -3019 Page 1 of 2 • • Maunder, Thomas E (DOA) From: Bill Penrose [bill @solstenxp.com] Sent: Thursday, November 03, 2011 2:46 PM To: Maunder, Thomas E (DOA) Subject: RE: NFU #41 -35 Sundry Thanks, Tom. I'll probably get the FedEx'd signed sundry on Monday and will get it right over to the Commission. Etet Pervta4e Vice President / Drilling Manager FullColor_sma 310 K Street, Suite 700 Anchorage, Alaska 99501 Main 907 - 279 -6900 Direct 907 - 264 -6114 Cell 907-250-3113 From: Maunder, Thomas E (DOA) [mailto:tom.maunder @alaska.gov] Sent: Thursday, November 03, 2011 2:38 PM To: Bill Penrose Subject: RE: NFU #41 -35 Sundry Bill, I have spoken with the Commissioners and Commissioner Foerster has given her oral approval for Armstrong Cook Inlet, LLC to open the sliding sleeve at 7985' allowing both intervals to produce. We look forward to the hard copy sundry from Denver. Tom Maunder, PE AOGCC From: Bill Penrose [mailto:bill @solstenxp.com] Sent: Thursday, November 03, 2011 7:50 AM To: Maunder, Thomas E (DOA) Subject: NFU #41 -35 Sundry Tom, Here's a Sundry Application that's currently in Denver being signed by Armstrong's Ed Teng. He'II Then FedEx it up here so I can get it over to the Commission. Meanwhile, would you please look it over and consider issuing a verbal approval right away? Armstrong's under pressure from Enstar to make rate as soon as possible and the proposed action will significantly add to the rate coming from North Fork. I'll give you a call to discuss after you've had time to digest the application. Thanks and regards, 11/8/2011 • • • NFU — 41 -35 PrD to ' zl Well Inner Outer Status Pressure Temp Annulus Annulus 4/1/2011 4/2/2011 4/3/2011 4/4/2011 4/5/2011 4/6/2011 4/7/2011 4/8/2011 4/9/2011 4/10/2011 4/11/2011 ;h. 4 2.01'' 4/12/2011 `s.' "� V f s 4/13/2011 4/14/2011 4/15/2011 4/16/2011 4/17/2011 SI 2597 68 129 40 4/18/2011 SI 2850 33 115 40 4/19/2011 SI 2850 33 115 40 4/20/2011 SI 2642 47 136 40 4/21/2011 SI 2850 33 155 40 4/22/2011 SI 2850 33 131 40 4/23/2011 SI 2850 33 131 40 4/24/2011 SI 2850 33 131 40 4/25/2011 SI 2109 38 140 40 4/26/2011 SI 2109 38 140 40 4/27/2011 SI 2209 36 136 40 4/28/2011 Online 2298 56 148 40 4/29/2011 Online 2061 47 154 40 4/30/2011 Online 1624 45 146 40 5/1/2011 SI 2825 44 139 40 5/2/2011 Online 1178 43 262 40 5/3/2011 SI 3075 48 154 40 5/4/2011 SI 2925 38 136 40 5/5/2011 SI 2750 38 136 40 5/6/2011 Online 1435 36 136 40 5/7/2011 SI 2361 50 378 40 5/8/2011 Online 2361 50 378 40 5/9/2011 SI 2650 50 122 40 5/10/2011 SI 2650 50 122 40 5/11/2011 Online 1899 45 122 40 5/12/2011 Online 1899 45 122 40 $Z . • • u4 -3s Well Inner Outer Pi b ►b5 -o z t Status Pressure Temp Annulus Annulus 5/13/2011 SI 2652 48 255 40 5/14/2011 Online 1870 38 305 40 5/15/2011 Online 1480 54 90 40 5/16/2011 Online 1542 56 92 40 5/17/2011 SI 1623 56 95 40 5/18/2011 SI 1875 55 92 40 5/19/2011 SI 2100 45 91 40 5/20/2011 SI 2750 45 91 40 5/21/2011 SI 2656 45 91 40 5/22/2011 SI 2650 44 92 40 5/23/2011 SI 2653 44 92 40 5/24/2011 SI 2658 43 92 40 5/25/2011 SI 2665 43 92 40 5/26/2011 SI 2665 43 92 40 5/27/2011 SI 2665 43 92 40 5/28/2011 SI 2665 51 93 40 5/29/2011 SI 2665 51 93 40 5/30/2011 SI 2665 51 93 40 5/31/2011 SI 2665 51 93 40 6/1/2011 SI 2665 51 93 40 6/2/2011 SI 2665 51 93 40 6/3/2011 SI 2665 51 93 40 6/4/2011 SI 2665 51 93 40 6/5/2011 SI 2665 51 93 40 6/6/2011 SI 2665 51 93 40 6/7/2011 SI 2737 69 187 40 6/8/2011 SI 2737 69 187 40 afz— .. • North Fork Unit #41 -35 (jr 165--c:Z Proposed Wellbore Schematic -.- 5/24/2010 20" Conductor @ 246' 13 -3/8" 68# 1 -55 BTC Surface Casing @ 709' 18 -5/8" H ►. 13-3/8" 61# J -55 BTC Surface Casing "t4(P = 45; Chemical Injection Line @ 2,300' MC from 709' 2,000' 4 d - � 590 9-5/8" 43.5# P -110 BTC intermediate Casing @ 2408' r g' 12 -1/4" Hole 9 -5/8" 435# N -80 BTC Intermediate Casing AAUP, „3 `-'ps; 2 -7/8" 6.5# N -80 BTC -M Tubing String 01, from 2408' -5,535' �[a Njv = Z�4 (, ,,� `. DV Tool @ 6,310" ' 9 -5/8" Baker Model "S -3" ,�.._�,. Hydraulic -Set Packer @ 7,880' '�� " Sliding Sleeve- 1" Perfs: Y: Holes, 4 spf 8,005 8,045 Blast Joints'" Brown Tie -Back Sleeve @ 8,330'1 t 9 -5/8" 43.5# P -110 BTC Intermediate Casing from 7" Baker Model "D" Z Z 5,535' - 8,451' Permanent Packer @ 8,500' f s- Perfs: Five - W' Holes @ 8,530' // Squeezed Perfs: Five -''A" Holes @ 8,540' // Squeezed Perfs: %:" Holes, 4 spf 8,563' - 8,578' (Reperfed) TOC @ 10,009' '% *"' t Perfs: %" Holes, 4 spf 8,592' - 8,602' (Reperfed) Whipstock @ 10,173' .-t ... 9 ° 4 ,,^ 44 : ' z.* Sidetrack hole drilled to 10,859' (Uncased) TOC @ 10,765' r 1=R Perfs: Five - /" Holes, 4 spf @ 10,786' ' "$ ' ' Perfs: 'A" Holes, 4 spf 10,805' - 10,860' Perfs: Five - Holes @ 10,875' 1/ Squeezed IOC @10913' '`:'� -' A ■ 7" 26# P -110 BTC Production Liner @ 10,985' TD @ 12,812' STATE OF ALASKA • ALASKA •AND GAS CONSERVATION COMMISSI• GAS WELL OPEN FLOW POTENTIAL TEST REPORT 1a. Test: U Initial ❑ Annual ❑ Special 1b. Type Test: ❑ Stabilized ❑ Non Stabilized U Multipoint ❑ Constant Time ❑ Isochronal ❑ Other 2. Operator Name: 5. Date Completed: 11. Permit to Drill Number: Armstrong Cook Inlet, LLC Aug. 23, 2010 165 -021 3. Address: 6. Date TD Reached: 12. API Number: 1421 Blake Street, Denver, Colorado 80202 December 1, 1965 50- 2311000400 4a. Location of Well (Govemmental Section): 7. KB Elevation (ft): 13. Well Name and Number: Surface: 655' FNL, 659' FEL, Sec. 35, T4S, R14W,SM 780 North Fork Unit#41 -35 Top of Productive Horizon: 8. Plug Back Depth(MD +TVD): 14. Field /Pool(s): 652' FNL, 662' FEL, Sec. 35, T4S, R14W,SM 10009' MD & TVD North Fork Ill Total Depth: 9. Total Depth (MD + TVD): -51 665' FNL, 675' FEL, Sec. 35, T4S, R14W,SM 12812 MD & TVD QV\ &it CAA 4b. Location of Well (State Base Plane Coordinates): 10. Land Use Permit: 15. Property Designation: Surface: x- 200725.62 y- 2119860.18 Zone- 4 NA ADL 391210 TPI: x- 200722.85 y- 2119862.09 Zone- 4 16. Type of Completion (Describe): Total Depth: x- 200708.95 y- 2119850.78 Zone- 4 Initial Single Zone Dry Gas completianalLowergAse3) 17. Casing Size Weight per foot, Ib. I.D. in inches Set at ft. 19. Perforations: From To 7" 26 6.276 10985 8563" MD &TVD to 8602" MD &TVD 18. Tubing Size Weight per foot, Ib. I.D. in inches Set at ft. 2-7/8" 6.5 2.441 8554 20. Packer set at ft: 21. GOR cf /bbl: 22. API Liquid Hydrocardbons: 23. Specific Gravity Flowing Fluid (G): 8500' None (no liquid) NA 0.565 24a. Producing through: 24b. Reservoir Temp: 24c. Reservoir Pressure: 24d. Barometric Pressure (Pa): El Tubing ❑ Casing 165 F° 3618 psia @ Datum 8583 TVDSS 14.7 psia 25. Length of Flow Channel (L): Vertical Depth (H): Gg: % CO % N2: % H Prover: Meter Run: Taps: 8554' 8554' 0.565 0.338 1.028 0 NA 4" pipe 26. FLOW DATA TUBING DATA CASING DATA Prover Choke Pressure Diff. Temp. Pressure Temp. Pressure Temp. Duration of Flow No Line X Orifice psig Hw F psig F° psig F Hr. Size (in.) Size (in.) 1. X 12/64 2250 109 52 2250 52 2 2. X 16/64 2025 82 52 2025 52 1 3. X 24/64 1450 87 53 1450 53 1.5 4. X 32/64 1050 77 54 1050 54 1 5. X Basic Coefficient Flow Temp. Super Comp. Pressure Gravity Factor Rate of Flow No. (24 -Hour) 4 hwPm Pm Factor F Factor Q1 Mcfd Fb or Fp Ft g Fpv 1. 12.28 189.65 330 1.0078 1.33 1.0951 2920 2. 12.28 164.5 330 1.0078 1.33 1.0871 3488 3. 12.28 171.99 340 1.0068 1.33 1.0644 4811 4. 12.28 167.65 365 1.0058 1.33 1.0474 6173 5. Z 7e a (-1 . . A , for Separator for Flowing Temperature tidy . No. Pr T Tr z Gas Fluid Gg G 1. 3.3733 512 1.4884 0.8338 2. 3.0360 512 1.4884 0.8461 3. 2.1739 513 1.4912 0.8826 Critical Pressure 667 667 4. 1.5742 514 1.4942 0.9116 Critical Temperature 344 344 5. Form 10-421 Revised 1/2004 CONTINUED ON REVERSE SIDE Submit in Duplicate Pc ' 3008 pct 9048064 • Pf • 3618 p{ 13089924 No. Pt Pt Pc Pw Pw Pc Ps Ps Pf -Ps 1. 2250 5062500 3985564 2739 7502121 5587803 2. 2025 4100625 4947439 2478 6140484 6949440 3. 1450 2102500 6945564 1825 3330625 9759299 4. 1050 1102500 7945564 1433 2053489 11036435 5. 25. AOF (Mcfd) 7400 Mcf /D n 1.09989 Remarks: I hereby certify that the • -; - • ' true and correct to the best of my knowledge. x Sign - • — �i i — i - .�_ Title — 1 Date Apr. 28, 2011 DEFINITIONS OF SYMBOLS AOF Absolute Open Flow Potential. Rate of Flow that would be obtained if the bottom hole pressure opposite the producing face were reduced to zero psia Fb Basic orifice factor Mcfd/ 4 hwPm Fp Basic critical flow prover or positive choke factor Mcfd /psia Fg Specific gravity factor, dimensionless Fpv Super compressibility factor= dimensionless Ft Flowing temperature factor, dimensionless G Specific gravity of flowing fluid (air = 1.000), dimensionless Gg Specific gravity of separator gas (air = 1.00), dimensionless GOR Gas -oil ratio, cu. ft. of gas (14.65 psia and 60 degrees F) per barrel oil (60 degrees F) hw Meter differential pressure, inches of water H Vertical depth corresponding to L, feet (TVD) L Length of flow channel, feet (MD) n Exponent (slope) of back - pressure equation, dimensionless Pa Field barometric pressure, psia Pc Shut -in wellhead pressure, psia Pf Shut -in pressure at vertical depth H, psia Pm Static pressure at point of gas measurement, psia P Pr Reduced pressure, dimensionless Ps Flowing pressure at vertical depth H, psia x:1,.4 it 2 I' , Pt Flowing wellhead pressure, psia Pw Static column wellhead pressure corresponding to Pt, psia Alaska Oil & Gps Gang r mmissi Q Rate of flow, Mcfd (14.65 psia and 60 degrees F) roA Tr Reduced temperature, dimensionless Mlcl T Absolute temperature, degrees Rankin Z Compressibility factor, dimensionless Recommended procedures for tests and calculations may be found in the Manual of Back- Pressure Testing of Gas Wells, Interstate Oil Compact Commission, Oklahoma City, Oklahoma. Form 10-421 Revised 1/2004 Side 2 • ■ North Fork #41 -35 8583` Zone AOF Calculation • P12 - Ps2 100000000 - • 10000000 .. N a IA a, v. aw 1000000 • AOF = +/- 7400 Mcf/D 100000 100 1000 10000 100000 Qg (Mcf/D) STATE OF ALASKA . ALASKAOAND GAS CONSERVATION COMMIS• GAS WELL OPEN FLOW POTENTIAL TEST REPORT 1a. Test: U Initial Lf Annual Li Special 1b. Type Test: Lf Stabilized Li Non Stabilized [ j Multipoint ❑ Constant Time ❑ Isochronal ❑ Other 2. Operator Name: 5. Date Completed: 11. Permit to Drill Number: Armstrong Cook Inlet, LLC Aug. 23, 2010 165 -021 3. Address: 6. Date TD Reached: 12. API Number: 1421 Blake Street, Denver, Colorado 80202 December 1, 1965 50- 2311000400 4a. Location of Well (Governmental Section): 7. KB Elevation (ft): 13. Well Name and Number: Surface: 655' FNL, 659' FEL, Sec. 35, T4S, R14W,SM 780 North Fork Unit #41 -35 Top of Productive Horizon: 8. Plug Back Depth(MD +TVD): 14. Field /Pool(s): SW\ 652' FNL, 660' FEL, Sec. 35, T4S, R14W,SM 10009' MD & TVD North Fork 6 1 Total Depth: 9. Total Depth (MD + TVD): • 665' FNL, 675' FEL, Sec. 35, T4S, R14W,SM 12812 MD & TVD ti( n -�- G-Ac - P L 4b. Location of Well (State Base Plane Coordinates): 10. Land Use Permit: 15. Property Designation: Surface: x- 200725.62 y- 2119860.18 Zone- 4 NA ADL 391210 TPI: x- 200724.42 y- 2119862.8 Zone- 4 16. Type of Completion (Describe): Total Depth: x- 200708.95 y- 2119850.78 Zone- 4 Initial Single Zone Dry Gas co 17. Casing Size Weight per foot, Ib. I.D. in inches Set at ft. 19. Perforations: From To 7" 26 6.276 10985 8005" MD &TVD to 8045" MD &TVD 18. Tubing Size Weight per foot, Ib. I.D. in inches Set at ft. 2 -7/8" 6.5 2.441 7985 20. Packer set at ft: 21. GOR cf/bbl: 22. API Liquid Hydrocardbons: 23. Specific Gravity Flowing Fluid (G): 7966' None (no liquid) NA 0.56 24a. Producing through: 24b. Reservoir Temp: 24c. Reservoir Pressure: 24d. Barometric Pressure (Pa): 0 Tubing ❑ Casing 165 F° 3047 psia @ Datum 8025 TVDSS 14.7 psia 25. Length of Flow Channel (L): Vertical Depth (H): Gg: % CO % N2: % H Prover: Meter Run: Taps: 7985' 7985' 0.56 0.2 1.2 0 NA 4" pipe 26. FLOW DATA TUBING DATA CASING DATA Prover Choke Pressure Diff. Temp. Pressure Temp. Pressure Temp. Duration of Flow No Line X Orifice psig Hw F psig F psig F Hr. Size (in.) Size (in.) 1. X 12/64 1625 89 59 1625 59 0.5 2. X 16/64 1400 68 59 1400 59 0.5 3. X 24/64 925 60 59 925 59 0.5 4. X 32/64 625 73 59 625 59 0.5 5. X Basic Coefficient Flow Temp. Super Comp. No. (24 -Hour) h Pressure Factor Gravity Factor Factor Rate of Flow Fb or Fp Pm Ft Fg Fpv O MCfrf 1. 12.28 160.65 290 1.0009 1.3363 1.0683 2404 2. 12.28 141.63 295 1.0009 1.3363 1.0598 2943 3. 12.28 134.16 300 1.0009 1.3363 1.0407 3712 4. 12.28 147.99 300 1.0009 1.3363 1.028 4079 5. Temperature e'* 0 M 0 ': Z u ��for Separator for Flowing No. Pr T Tr z Gas Fluid Gg G 1. 2.4436 519 1.5131 0.8762 2. 2.1052 519 1.5131 0.8904 3. 1.3910 519 1.5131 0.9234 Critical Pressure 665 665 4. 0.9398 519 1.5131 0.9463 Critical Temperature 343 343 5. Form 10-421 Revised 1/2004 CONTINUED ON REVERSE SIDE Submit in Duplicate I Pc 2560 Pc 6553600 • Pf • 3047 p9 9284209 No. Pt pt2 Pct -Pt2 Pw Pw2 Pct -Pw2 Ps Ps Pf -Ps _ 1. 1625 2640625 3912975 1945 3783025 5501184 2. 1400 1960000 4593600 1688 2849344 6434865 3. 925 855625 5697975 1161 1347921 7936288 4. 625 390625 6162975 858 736164 8548045 5. 25. AOF (Mcfd) 4450 Mcf/D n 1.1996 Remarks: hereby certi that the for- • •' • • .'s true and correct to the best of my knowledge. iliiii,r4(---iir ; 1 , ' ' • led ` D - -= Title !� P Date Apr. 28, 2011 DEFINITIONS OF SYMBOLS AOF Absolute Open Flow Potential. Rate of Flow that would be obtained if the bottom hole pressure opposite the producing face were reduced to zero psia Fb Basic orifice factor Mcfd / 4 hwPm Fp Basic critical flow prover or positive choke factor Mcfd /psia Fg Specific gravity factor, dimensionless Fpv Super compressibility factor= 4 dimensionless Ft Flowing temperature factor, dimensionless G Specific gravity of flowing fluid (air = 1.000), dimensionless Gg Specific gravity of separator gas (air = 1.00), dimensionless GOR Gas -oil ratio, cu. ft. of gas (14.65 psia and 60 degrees F) per barrel oil (60 degrees F) hw Meter differential pressure, inches of water H Vertical depth corresponding to L, feet (TVD) L Length of flow channel, feet (MD) n Exponent (slope) of back- pressure equation, dimensionless Pa Field barometric pressure, psia c "l Pc Shut -in wellhead pressure, psia '� Pf Shut -in pressure at vertical depth H, psia Pm Static pressure at point of gas measurement, psia .• ViOwt Pr Reduced pressure, dimensionless � * 11% Ps Flowing pressure at vertical depth H, psia fy,� Pt Flowing wellhead pressure, psia �� c' w,1,2• ; vat O W Pw Static column wellhead pressure corresponding to Pt, psia Q Rate of flow, Mcfd (14.65 psia and 60 degrees F) Tr Reduced temperature, dimensionless T Absolute temperature, degrees Rankin Z Compressibility factor, dimensionless Recommended procedures for tests and calculations may be found in the Manual of Back- Pressure Testing of Gas Wells , Interstate Oil Compact Commission, Oklahoma City, Oklahoma. Form 10-421 Revised 1/2004 Side 2 North Fork #41 -35 8025' Zone AOF Calculation • Pf2 - Ps2 100000000 - • 10000000 N N QM 1000000 • AOF = +1- 4450 Mcf/D 100000 100 1000 10000 100000 Qg (Mcf/D) , • STATE OF ALASKA 0 ALASKA OIL AND GAS CONSERVATION COMMISSION GAS WELL OPEN FLOW POTENTIAL TEST REPORT la. Test: tyj Initial Li Annual Li Special 1b. Type Test: U Stabilized Li Non Stabilized Ld Multipoint 0 Constant Time 0 Isochronal 0 Other 2. Operator Name: 5. Date Completed: 11. Permit to Drill Number Armstrong Cook Inlet, LLC Aug. 23, 2010 165-021 3. Address: 6. Date TD Reached: 12. API Number: 1421 Blake Street, Denver, Colorado 80202 December 1, 1965 50- 2311000400 1 4a, Location of VVell (Governrnental Section): ' 7. KB Elevation (ft): 13. Well Name and Number: Surface: 655 FNL, 659' FEL, Sec. 35, T4S, R14W,SM 780 North Fork Unit #41-35 Top of Productive Horizon: 8. Plug Back Depth(MD+TVD): 14, FieldiPool(s): 652' FNL, 660' FEL, Sec. 35, T4S, R14W,SM 10009' MD & TVD North Fork Total Depth: 9. Total Depth (MD + TVD): 665' FNL, 675' FEL, Sec. 35, T4S, R14W,SM 12812 MD & TVD 4b. Location of Well (State Base Plane Coordinates): 10. Land Use Permit: 15. Property Designation: Surface: x- 200725.62 y- 2119860.18 Zone- 4 NA ADL 391210 TPI: x- 20072442 y- 2119862.8 Zone- 4 16. Type of Completion (Describe): ' Total Depth: x- 200708.95 y- 2119850.78 Zone- 4 Initial Single Zone Dry Gas completion (Upper Zone 8025) 17. Casing Size Weight per foot, lb, 1.0. in inches Set at ft. 19. Perforations: From To 7" 26 6.276 10985 8005" MD&TVD to 8045" MD&TVD 18. Tubing Size Weight per foot, lb. 1.0. in inches Set at ft. 2-7/8" 6.5 2.441 7985 StIANNED APR 2 9 2011 20. Packer set at ft: 21. GOR cf/bbl: 22. API Liquid Hydrocardbons: 23. Specific Gravity Flowing Fluid (G): 7966' None (no liquid) NA 0.56 24a. Producing through: 24b. Reservoir Temp: 24c. Reservoir Pressure: 24d. Barometric Pressure (Pa): 61 Tubing 0 Casing 165 F° 3047 psia t Datum 8025 1VDSS 14.7 pia 25. Length of Flow Channel (L): Vertical Depth (H): Gg: % CO % N2: % H2S: Prover: Meter Run: Taps: 7985 7985' 0.56 0.2 1.2 0 NA 4" pipe 26. FLOW DATA TUBING DATA CASING DATA - Prover Choke Pressure Diff. Temp. Pressure Temp. Pressure Temp. Duration of Flow No. Line X Orifice Size (in.) Size (in) Psig Hw F psig r psig F Hr. 1. X 12/64 1625 89 59 1625 59 0.5 2. X 16/64 1400 68 59 1400 59 0.5 3. X 24/64 925 60 59 925 59 0.5 4. X 32J64 625 73 59 625 59 0.5 5, X Basic Coefficient Flow Temp. Super Comp. , Pressure Gravity Factor Rate of Flow No. (24-Hour) II hwPm Pm Factor Factor Fg 01 Mcfd Fb or Fp Ft Fpv 1, 12.28 160.65 290 1.0009 1.3363 1.0683 2404 2. 12.28 141.63 295 1.0009 1.3363 1.0598 2943 3. 12.28 134,16 300 1.0009 1.3363 1.0407 3712 4. 12.28 147.99 300 1.0009 1.3363 1,028 4079 . 5. IIIIIIIMIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII for Separator for Flowing Temperature No. Pr Tr z Gas Fluid T Gg G 1. 2.4436 519 1.5131 0.8762 11111111111111111111110 2. 2.1052 519 1.5131 0.8904 3. 1,3910 519 1.5131 0.9234 Critical Pressure 665 665 4. 0.9398 519 1.5131 0.9463 Critical Temperature IIIIIIICMIIIIIII 343 5. Form 10-421 Revised 1/2004 CONTINUED ON REVERSE SiDE ' ,I "' , ubmit in Duplicate R. APR 2 a no — I Pc 2560 pc 6553600 li Pf . 3047 pf 9284209 No, Pt Pe P Pw Pw - Ec2-Pw 2 Ps Ps Pe-PS 1. 1625 2640625 3912975 1945 3783025 5501184 2. 1400 1960000 4593600 1688 2849344 6434865 3. 925 855625 .,. 5697975 , 1181 1347921 7936288 4. 625 390625 6162975 858 736164 8548045 ... 5. _ 25. AOF (Mcfd) 4450 Mcf/D n 1,1996 Remarks: I hereby certi that the for • ••• • 's true and correct to the best of my knowledge. '1".."1 ../411111,41r i . . igned gar Title .. ,,,.... . /. 1 ) Date Apr. 28, 2011 DEFINITIONS OF SYMBOLS AOF Absolute Open Flow Potential. Rate of Flow that would be obtained if the bottom hole pressure opposite the producing face were reduced to zero psia Fb Basic orifice factor Mcfdt 4 hwPm Fp Basic critical flow prover or positive choke factor Mcfdipsia Fg Specific gravity factor, dimensionless Fpv Super compressibility factor= 4 la dimensionless Ft Flowing temperature factor, dimensionless G Specific gravity of flowing fluid (air=1.000), dimensionless Gg Specific gravity of separator gas (air=1.00), dimensionless GOR Gas-oil ratio, cu. ft. of gas (14.65 psia and 60 degrees F) per barrel oil (60 degrees F) hw Meter differential pressure, inches of water H Vertical depth corresponding tot., feet (TVD) L Length of flow channel, feet (MD) n Exponent (slope) of back-pressure equation, dimensionless Pa Field barometric pressure, psia Pc Shut-in wellhead pressure, psia Pf Shut-in pressure at vertical depth H, psia Pm Static pressure at point of gas measurement, psia Pr Reduced pressure, dimensionless Ps Flowing pressure at vertical depth H, psia Pt Flowing wellhead pressure, psia Pw Static column wellhead pressure corresponding to Pt, psia Q Rate of flow, Mcfd (14.65 psia and 60 degrees F) Tr Reduced temperature, dimensionless T Absolute temperature, degrees Rankin Z Compressibility factor, dimensionless Recommended procedures for tests and calculations may be found in the Manual of Back- Pressure Testing of Gas We/is, Interstate Oil Compact Commission, Oklahoma City, Oklahoma. Form 10-421 Revised 1/2004 Side 2 North Fork #41-35 8025' Zone AOF Calculation Pf2 - Ps2 100000000 ._._ .... • 10000000 1000000 AOF — +1- 4450 Mcf/D 100000 100 1000 10000 100000 Qg (Mcf/D) , • Page 1 of 1 Aubert, Winton G (DOA) From: Alexey Sachivichik [ aexey .sachivichik @solstenxp.com] Sent: Wednesday, February 16, 2011 8:24 AM To: Aubert, Winton G (DOA) Cc: Bill Penrose; Brian Brigandi Subject: Armstrong NFU 41 -35 Winton, Yesterday, Feb 15 2011, I've submitted a Sundry Notice to re -enter suspended NFU 41 -35 well. During our telephone conversation this morning, you pointed that NFU 41 -35 well is not considered suspended (BX plug and brine are not a reasons for suspension), therefore doesn't require a Sundry Notice to re -enter the well. Could you please disregard the NFU 41 -35 Sundry Notice Application and discard it from your system. Thanks and regards 4' Senior Drilling Engineer. FEB 1 6 2011 310 K Street, Suite 700 Anchorage, Alaska 99501 office: 907 -279 -6900 cell: 907 575 7315 fax: 907- 264 -6190 2/16/2011 , STATE OF ALASKA -'e;df� - ALASKAIIIL AND GAS CONSERVATION COMMISSI• .0.1. /s// APPLICATION FOR SUNDRY APPROVALS 20 MC 25.280 1. Type of Request: Abandon ❑ Suspend ❑ Operational shutdown ❑ Perforate ❑ Waiver ❑ Ot r ❑ Alter casing ❑ Repair well ❑ Plug Perforations ❑ Stimulate ❑ Time Extension ❑ Change approved program ❑ Pull Tubing ❑ Perforate New Pool ❑ Re -enter Suspended Well 151 - 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number , Armstrong Cook Inlet, LLC. Development © - Exploratory ❑ 1.- r, 1 - 3. Address: ❑ Service ❑ 6. AP/ Number: 1421 Blake Street, Denver, CO 80202 I 31- 10004 -00- 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number property line where ownership or landownership changes: Spacing Exception Required? Yes ❑ No tg North F 41 -35 . 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): BLM A -02436 j 0?9h2 /O 780' North Fork Unit - 12. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth (ft) (measured): Junk (measured): 12812' - 12812' - 8325' 8325' CIBP 8325'; DMBP 8500' ' 7 Casing Length Size MD Burst Collapse Structural ‘ Conductor 246' 20" 246' 246' N/A N/A / Surface 1,984' 13-3/8" 2,000' \ ; ,00U 3,090 psi 1,540 psi Intermediate 8,435' 9-5/8" 8,451' � ` 6,330 psi 3,810 psi Production ` Liner 2,529' T 0, ` 0,985' 9,960 psi 6,210 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing `Tubing G Tubing MD (ft): 8005'- 8045', 8,564' - 8,602' 8005- 8045', 8,564'- 8,602' -7/8" )v 6.5#, N-80 8,554' Packers and SSSV Type: 9-518" Baker S-3 Packer, / Packers and' -V r 7,966' 7" Baker Model "D" Packer 8,500' 13. Attachments: Description Summary of - • --1 in Detailed Operations Program ❑ BOP Sk- , • i u- , ii tt • Development fg - Service ❑ 15. Estimated Date for i 1 •. fter proposed work: 18 -Feb -1 Commencing Operations: 01 ,. M Gas 15 - Plugged ❑ Abandoned ❑ / 17. Verbal Approval: Date: '14t GINJ ❑ WINJ ❑ WDSPL ❑ / Commission Representative: 18. I hereby certify that the foregoing is true and to the best of my knowledge. Contact Alexey Sachivichik (907) 264 -6112 i Printed Name Edward Teng (304 623 -1821 Title Vice - President Engineering Si r Phone / Date . 3 - S -J — /o D Z/ 10- Feb-11 COMMISSION USE ONLY Conditions of approval: Notify • • so that a representative may witness Sundry Number A_ (:). ( Plug Integrity ❑ : 4 P Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ RECEIVE) Other: FEB 1 6 2011 an & Gas Cans. CahMiSS1011 Subsequent Form R- uired: Anchorage APPROVED BY (Approved by: COMMISSIONER THE COMMISSION Date: I ro i u -4kj3 new ., v r' • , s FEB 1 2011- auomlt in uuplicare ORIGINAL • 02/09/11 A ARMSTRONG NFU #41 -35 (0,4 Ltlet i { Procedure to Prepare Well for Production Current Condition of Well • See current Wellbore Diagram (Attached) • The 2 -7/8" BXN nipple at 8,552' has a BX plug installed in it • Well has 6% KC1 brine (9.5 ppg) from the BXN to surface • Wellbore has only gas below the BXN at 8,552' • Reservoir pressure at 8,563' MD /TVD is 3,616 psi 1. Rig up Expro testing to the NFU 41 -35 wing valve. Pressure test the line between the tree and choke manifold to 4,500 psi. 2. Check wellhead and tree for pressure. Pull back - pressure valve. 3. Rig up Pollard slickline with lubricator and pressure test lubricator. Swab brine from the 2 -7/8" tubing as deeply as possible. 4. Re- pressure test lubricator (see Note below). RIH with BX plug pulling tool, latch and release the BX plug from the BXN nipple at 8,552'. Note: CAUTION! The well was gas - filled when the BX plug was originally installed and the well filled with brine above it. When the BX plug is pulled, the gas below the BXN nipple will be released and the well will come live. Maintain surface pressure integrity at all times while pulling the BX plug. 5. POH with BX plug. 6. Open well to test facilities. If the well does not flow on its own, RIH with slickline and swab brine from well until it flows. R/D slickline and release. 7. While the well is making water, limit rate to a maximum of one (1) bpm. When the well starts making predominantly gas, set the choke at 10/64" and limit gas flow rate to a maximum of 3.5 MMSCFD. Call the SolstenXP office when well is stabilized and prepare to shut in well. All of the load brine produced during this test will be stored in the test facility's water knockout tank and disposed of down the NFU 34 -26 disposal annulus. 8. Once the well has completely cleaned up, shut it in and ensure all valves on the tree are closed. 0 II North Fork Unit #41 -35 Wellbore Schematic 2/10/2011 J L 20" Conductor 246' 1/4" Chemical Injection Line ■ 1 L 20" Conductor 18-5/8" Hole 13 -3/8" 61# & 68# 1 -55 BTC Casing @ 2,000' Chemical Injection Sub @ 2,300' ►- 2.347" Drift ID, 4.10" OD, L -80 12 -1/4" Hole 2 -7/8" 6.5# N -80 EUE 8rd -M Tubing ■ A ■ DV Tool @ 6,310' 9 -5/8" Baker S -3" Packer @ 7,966' Sliding Sleeve @ 7,985' ■ u Perforations 8,005' - 8,045' 3 Blast Joints 7,993' - 8,052' ■ Brown Tie -Back Sleeve @ 8,330'1 g 9 -5/8" 43.5# N -80 & P -110 BTC Casing @ 8,451' 7" Baker Model "D" Packer @ 8,500' g 2 -7/8" BXN Nipple @ 8,552' ' _' Perforations (squeezed) 8,530' & 8,540' 2 -7/8" WLEG @ 8,554' Perforations (open) 8,563' - 8,602' TOC @ 10,009' , <' , Whipstock @ 10,173' 0t ` b'� ry;,. ', Sidetrack hole drilled to 10,859' (Uncased) TOC @ 10,765' w s x� 4 Perforations @ 10,786' a o ff f .,ti "� Perforations 10,805' — 10,860' :'11'4"A' : Perforations (Squeezed) @ 10,875' TOC @ 10,913' ,M . « fit A , 7" 26# P -110 BTC Liner @ 10,985' TD @ 12,812' • A ARMSTRONG RECEIVED Cook Inlet LL(' I 201' Mask an & Gas COAL Commission !luchwape February 10, 2011 Mr. Dan Seamount, Chairman Alaska Oil and Gas Conservation Commission 333 West 7 Ave., Suite 100 Anchorage, Alaska 99501 RE: Request for Sundry Approval Armstrong Cook Inlet NFU #41 -35 (PTD 165 -021) Dear Mr. Seamount, Armstrong Cook Inlet, LLC hereby applies for Sundry Approval to perform the work necessary to place the North Fork #41 -35 well into production. Armstrong proposes to pull a tubing plug from BXN nipple, unload load brine from the well and then place the well on production. Attached please find a Form 10 -403 Application for Sundry Approval and supporting documents for this work. If you have any questions or require additional information, please contact me at 303 - 623 -1821 or Alexey Sachivichik at 264 -6112. Sincerely, ARMSTRONG COOK INLET, _ p, • Ed Teng Vice President - Engineering Cc: Alexey Sachivichik — SolstenXP ARMSTRONG, Cooklnlel, LLC October 25, 2010 0 010 e Mr. Dan Seamount, Chairman �t�ic1S CQttS, c4 a ,�a�iDtt Alaska Oil and Gas Conservation Commission 333 West 7 Ave., Suite 100 Anchorage, Alaska 99501 Dear Mr. Seamount, RE: Sundry Completion Report Armstrong Cook Inlet, LLC North Fork #41.35 PTD No. 165-021 Sundry No. 310-167 Dear Commissioner Seamount, NOV 4 2 01 D Armstrong Cook Inlet, LLC hereby submits its Well Workover Completion Report for the work performed in working over its NFU #41 -35 well near Anchor Point on the Kenai Peninsula. Please find enclosed the following information for your files: 1) Form 10-404 Sundry Report of Operation. 2) Completion Schematic. 3) Well Operations Summary. 4) GR/CCL Log, 5) Gyro Survey. 6) Final Testing Report. If you have any questions or require additional information, please contact me at (303) 623 -1821 or Alexey Sachivichik at 264 -6112. Sincerely, ARMSTRONG COOK INLET, LLC Edward Teng Vice President - Engineering enclosures 1 /7A ni -z_ Cl--- On tn'1 nt oln� L99 IO1i rr— 01n2 4 , 17 7111n STATE OF ALASKA ALASKA AND GAS CONSERVATION COMMISSIS REPORT OF SUNDRY WELL OPERATIONS W(A" 1. Operations Abandon Repair Well Plug Perforations Li Stimulate U Other T fS f L01 Performed: Atter Casing ❑ Pull Tubing ❑✓ Perforate New Pool ❑ Waiver ❑ Time Extension ❑ Change Approved Program ❑ Operat. Shutdown ❑ Perforate Q Re -enter Suspended Well ❑ 2. Operator Armstrong Cook Inlet, LLC. 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development El Expkxatory ❑ • 165 -021 3. Address: 1421 Blake Street, Denver, Colorado 80202 Stratigraphic❑ Service ❑ 6. API Number: • 50-231-10004-00- 00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL 391210 North Fork Unit #41 -35 North Fork 1 10. Present Well Condition Summary: Total Depth measured 12, 812 feet Plugs (measured) 8,3 25 feet true vertical 12,812 feet Junk (measured) N/A feet Effective Depth measured 10,009 feet Packer (measured) 7,952 feet true vertical 10,009 feet (true vertical) 7,952 feet Casing Length Size MD j TVD Burst Collapse Structural Conductor 246' 20" 246' 246' N/A N/A Surface 1,984' 13 -3/8" 2,000 2,000' 3,090 psi 1,540 psi Intermediate 8,435' 9 -518" 8,451' 8,451' 6,330 psi 3,810 psi Production Liner 2,529' 7" 10,985' 10,985' 9,960 psi 6,210 psi Perforation depth: Measured depth: 8,005' - 8,045; 8,53 - 8,602' True Vertical depth: 8,005' - 8,0 45'; 8,530' - 8,602' Tubing (size, grade, measured and true vertical depth): 2 -7/8" N-80 8,554' 8,554' Packers and SSSV (type, measured and true vertical depth): Baker F -1 Packer 8,502' 8,502' 11. Stimulation or cement squeeze summary: Intervals treated (measured): N OV Q 3 2010 Treatment descriptions including volumes used and final pressure: i ij & C I! �'a'gion 12. Representative Daily Average Production or Injection Data AnChrapp- Oil-BbI Gas -Mcf I Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 2,300 1 0 0 2,400 Subsequent to operation: 0 2,100 1 0 0 1,750 13. Attachments: 14. Well Class after work: Copies of Logs and Surveys Run GR/CCL Log, Gyro Exploratory ❑ Development ❑� Service ❑ Daily Report of Well Operations Yes 15. Well Status after work: Oil ❑ Gas L-/j / WDSPL ❑ I GSTOR ❑ WAG ❑ GINJ ❑ WINJ ❑ SPLUG ❑ 16. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or WA if C.O. Exempt: 310 -067 Contact 907 - 279 -6900 Printed Name Ed Teng Title Vice-President, Engineering Signa Phone 303 -6 23 -1821 Date 10125 /2010 Form 10404 Revised 7/2009 FISOMS NOV O $ Oil Submit Original Only kv 61� • • North Fork Unit #41 -35 Wellbore Schematic 8/25/2010 20" Conductor @ 246' 1/4" Chemical Injection Line 18 -5/8" Hole JL 13 -3/8" 61# & 68# 1 -55 BTC Casing @ 2,000' Chemical Injection Mandrel @ 2,300' 12 -1/4" Hole 2 -7/8" 6.5# N -80 EUE 8rd -M Tubing DV Tool @ 6,310' 9 -5/8" Baker S -3" Packer @ 7,966' Sliding Sleeve @ 7,985' Perforations 8,005' - 8,045' 3 Blast Joints 7,993'- 8,052' Brown Tie -Back Sleeve @ 8,330' 9 -5/8" 43.5# N -80 & P -110 BTC Casing @ 8,451' 7" Baker Model "D" Packer @ 8,500' 2 -7/8" BXN Nipple @ 8,552' Perforations (squeezed) 8,530' & 8,540' 2 -7/8" WLEG @ 8,554' Perforations (open) 8,563' - 8,602' TOC @ 10,009' Whipstock @ 10,173' Sidetrack hole drilled to 10,859' (Uncased) / TOC @ 10,765' Perforations @ 10,786' Perforations 10,805' — 10,860' Perforations (Squeezed) @ 10,875' TOC @ 10,913' 7" 26# P -110 BTC Liner @ 10,985' TD @ 12,812' AR C e*)k Inlet LL North Fork Unit #41 -35 Operation Summary August 8"', 2010 Finish well displacement of 9.0 ppg brine thru short string. Well dead. Set BPV, ND tree, start NU BOP's. Test BOP'S correcting problems encountered. August 9 2010 Test BOP's correcting problems as encountered. Witnessed by AOGCC rep Chuck Scheve. Pull test darts /BPV's. Stab into short string with jt of 2 -7/8" tbg, BOLDS and pull shirt string hanger free. LD short string of 79 joints. Stab into long string, BOLDS & pull to 114L w/ no results. RU WL, RIH w/ jet cutter, cut tubing @ 7,922'. POH, RD WL and pull on tubing (65K weight of string). Pull hanger through floor & LD. POOH, LD tbg. Rack on trailer for trucking. Check for NORM with no indications. August 10 2010 Finish POOH, LD long string & jewelry. Change out bottom rams to 4 ". Set test plug, test same & both TD valves, set wear ring. MU overshot BHA & RIH. PU, strapping & drifting 4" drill pipe, RIH to 5,672'. August 11 th, 2010 RIH w/ overshot while PU DP off catwalk. Tag fish and mill over. Latch onto fish, monitor well, prepare to POOH. Brine and gas flowing f/ DP. Shut annular preventer, circ gas out. Monitor well, POOH w/ fish. MU pkr retrieving tool & RIH. Screw in to fish, rotate to open ports then rotate to release packer. Work pkr up & down, start circulating bottoms up. August 12' 2010 Finish CBU w/ gas -cut brine at BU. POOH w/ fished packer, monitoring well for swabbing. Circ well @ 1,300' to circ gas out. Continue POOH pumping out. Retriever pkr and 3 jts tubing tailpipe. Test annular preventer. RIH with DC's & HWDP and storm pkr. Set and test to 1,000 psi — OK. POH and start ND BOP'S for wellhead change -out. August 13 2010 NFBOP's, remove old tbg spool. NU new tbg spool, spacer spools, double stud adapter & BOP's. Test tbg spool void and flange breaks. Pull RTTS pkr. MU milling assy, RIH to 8,268', tag up. Mill on junk from 8,268' to 8,277'. August 14 2010 Cont to mill on junk f/ 8,277' to 8,327'. First BU had dirty, muddy fluid w/ gas cut. Isolated in pit for removal. At 8,327' mill starting to hang up / torque up. Have milled 59' of junk, junk baskets probably full. Start CBU @ 5:00, reciprocating & rotating off bottom, still torquing up. POOH, empty junk baskets and PU new mill, RIH. Kelly up and circ to 8,326', wash & work junk baskets. Mill to 8,328'. bill spinning but not making progress. Circulate and work junk baskets. Monitor well. POOH 5 stan s. Slip & cut drilling line. August 15 2010 Cut /slip drilling line. POOH w/ mill. Mill bald again. Clean junk baskets — no metal. LD mill. PU reverse circ baskett, RIH. Drop ball, work basket. POOH, no metal recovered. LD reverse basket. PU overshot mill and RIH to 5,818'. August 16 d ', 2010 Finish RIH. Attempt to mill over CIBP w/ burn shoe w/o success. Appears BP is spinning, unable to get torque/bite w/ numerous changes in RPM, weight & dry drilling. CBU, strap out of hole. Pull wear bushing, set test plug. Test BOPE. MU BHA w/ 6 -1/8 bit, RIH to 6,877', break circ. - -` August 17"', 2010 RIH to 7,692'. Repair hydraulic hose and drawworks auxiliary disk brake pads. Cont RIH to 8,328', tag up. Drill on bridge plug using various wts & RPM with some spudding. Broke through, cont in hole washing down to 8,461'. Tag up on cement and drill out to 7" retainer. Drill retainer, push to 8,541'. CBU. Continue RIH pushing retainers to 9,960'. August 18 2010 CBU 2 times to balance fluids and eliminate cement cuttings and spotty heavier fluid. POOH, LD Baker tools and send to town. MU 8 -1/2" bit on 9 -5/8" scraper. RIH w/ scraper to 7.950', CBU. Check for flow & POOH, laying down 42 jts then racking back amount of pipe needed for next scraper run. August 19 2010 POOH with BHA #8 and LD 9 -5/8" scraper. PU/MU 7" scraper & RIH to 8,704'. Cleaning pit system of dirty fluid and building new brine. Displace well with new 9.0 Brine. Start POOH laying down drill pipe. August 20 2010 LD DP & BHA. Pull wear bushing, ND flow nipple to annular, install shooting flange & lubricator. Test lubricator, RU Expro & gyro survey. Run gyro survey f/ TD to surf. Run gamma ray over log perf intervals. RU gun #1, RIH, correlate & shoot perfs 8,592' to 8,602 POOH. MU gun #2. August 21s 2010 RIH, correlate and shoot 3 p f guns on wireline. Run gauge ring/junk basket to 8,700'. Expro went to Kenai to load out 1 more n to finish job. Clean up loc & rig. RIH w/ Gun #5 shoot final set of perfs. RIH with 7" pkr, set @ 496) RD equipment, NU riser. RD floor of rig tongs /spinners, RU GBR tools for running 2 -7/8' , g. RIH w/ 2 -7/8" tubing per completion plan. August 22 ,d 2010 RIH w/ 2 -7/8" completion string, tag lower pkr. Sting in and space out. Pull out Jt #265, MU pups & hanger. Displace annulus with inhibited brine, chase with diesel & fresh brine. Terminate chemical control line, land tbg, RILDS. Pressure up to set pkr. RU slick line. Pull rod/ball /plug and open sliding sleeve. Test annulus to 3,000 psi. RIH w/ SL, close sliding sleeve. August 23r 2010 Finish slickline work, RD unit and load out. Fill tbg, install BPV. Clean & blow down surf lines. ND BOP's, NU production tree. Test to 5,000 psi. RD koomey house and cellar. RD top drive, service loop & torque tube. August 24 2010 Rig released @midnight. Rid down to move. Move rig components to main pad. August 27 2010 Expro rigging up test equip. August 28 2010 Expro rigging up test equip. RU Pollard slickline. Test equipment. RIH, tag bottom @ 9975' MD. Swab well to 2330', well started to flow, make 5 more runs & well started to flow, RD slickline, start flaring gas, approx. 500 MCFD w/ little water at midnight. August 20', 2010 Flow well to clean up, 12/64 choke, final —2.2 MMCFD. SI well. RU slickline, run gauges into well. Secure slickline. Open well at 12/64 ", 2365 psi WHP, 1.77 MMCFD. Having flare problems. Increase to 16/64 choke, 1850 psi WHP, 3.6 MMCFD. Order out new flare, arrived at 2300 hrs. August 30 2010 Flow on 1/64 choke, 3.7 MMCFD. Flow on 24/64 choke, flare tip failed, shut -in. Spot & RU new flare. Restart 4 point test, flow well on 12/64, 24/64, & 32/64 chokes for 4 point test, OK. Reduce choke settings to maintain gas rate at 2 MMCFD. August 31S 2010 Flow well to maintain 2 MMCFD, having surface & downhole icing. Shut in well to clear hydrates, and increase surface and downhole methanol injection. Resume flow, vary choke to try to prevent freezing, rate about 1 to 2 MMCFD. September 1S 2010 Flowing well, hydrate icing persists, install larger heater on wellhead, wrap tree in insulating blankets. Take first gas samples. Increase rate to maintain 3 MMCFD approx 4 hrs, then WHP & WHT fall off, pinch choke to warm well, 1.2 MMCFD to 1.4 MMCFD rate. September 2" 2010 Continue flowing well, adjust choke to keep well warm, rates 1.2 MMCFD to 2.2 MMCFD. September 3r 2010 Continue flowing well. Shut well in for PBU @ 10:00 hrs. EXPRO crews departed location for PBU. Pollard monitoring their equipment & wellhead during shut -in. EXPRO recorder on well set for 7 days. September 9 2010 EXPRO returned to site @ 07:00, 9/9/10. Pump methnanol to free SL. SL free, pull gauges. Set plug in tailpipe nipple, try to open sleeve on upper zone — shearing off. SDFN to redress tools. September 10 2010 Pollard shift sleeve, bleed down to check, find water level rising, last level at 90'. RD Pollard for the night. EXPRO flowing & monitoring well for the night, well started unloading, put heat on wellhead, continue flowing to clean up well. September 11 2010 Start Pt #2 of 4 -pt test, flowing on 16/64" for 1 hr. Start Pt #3 of 4 -pt test, flowing on 24/64" for 1 hr. September 12 2010 Flow well at 2 mmcfd, 1,700 psi, WHT 54 deg. No hydrates. September 13 2010 Flow well at constant 2 MMSCFD September 14 th , 2010 Flow well at 2 mmcfd, 1,750 psi, 10/64" choke, WHT 55 deg. No hydrates. September 15 2010 Flow well at 2 mmcfd, 1,750 psi, 10/64" choke, WHT 55 deg. No hydrates. September 16 th , 2010 Flow well at 2 mmcfd, 1,750 psi, 10/64" choke, WHT 55 deg. Conduct 4 -point test. Shut in well and rid down test equipment. September 25 2010 Pull gauges, shut sliding sleeve, bleed off well, fill tubing with diesel and brine, set BPV. A Gyrodata Directional Survey Field Copy Only, not definitive for ARMSTRONG COOK INLET LLC Lease: NORTH FORK UNIT Well: NFU #41 - 35 Location: CLACIER RIG ONE, KENAI BOROUGH, Job Number: AK08I OGME 185 Run Date: 20 Aug 2010 Surveyor: R TUCKER Calculation Method: MINIMUM CURVATURE Survey surface coordinates obtained from: Directional Drilling Company Survey Latitude: 59.796250 deg. N Longitude: 151.630600 deg. W Gyro: Bearings are Relative to True North Closure Calculated from Well Head Location Horizontal Coordinates Calculated from Well Head Location _ A Gyrodata Directional Survey ARMSTRONG COOK INLET LLC Location: CLACIER RIG ONE, KENAI BOROUGH Lease: NORTH FORK #41 - 35 Well: 41 - 35, 7" Job Number: AK0810GME 185 MEASURED I N C L AZIMUTH VERTICAL DOGLEG HORIZONTAL DEPTH DEPTH SEVERITY COORDINATES feet deg. deg. feet deg./ feet 100 ft. 0.00 0.00 0.00 0.00 0.00 0.00 N 0.00 E ALL DEPTHS AND COORDINATES REFERENCED TO RKB GLACIER ONE(2I') 100.00 0.12 322.16 100.00 0.12 0.08 N 0.07W 200.00 0.15 309.24 200.00 0.04 0.25 N 0.23W 300.00 0.21 291.04 300.00 0.08 0.40 N 0.50W 400.00 0.23 273.87 400.00 0.07 0.47 N 0.86W 500.00 0.22 271.03 500.00 0.01 0.49 N 1.26W 600.00 0.21 248.50 600.00 0.08 0.43 N 1.62W 700.00 0.48 174.58 700.00 0.46 0.06 S 1.75W 800.00 0.67 166.67 799.99 0.21 1.04S 1.58W 900.00 0.70 167.79 899.98 0.03 2.20S 1.32W 1000.00 0.68 180.26 999.98 0.15 3.39 S 1.19W 1100.00 0.66 187.94 1099.97 0.09 4.55 S 1.27W 1200.00 0.61 201.86 1199.96 0.16 5.62 S 1.55W 1300.00 0.65 199.40 1299.96 0.05 6.65 S 1.94W 1400.00 0.46 195.51 1399.95 0.19 7.58 S 2.24W 1500.00 0.49 201.08 1499.95 0.05 8.36 S 2.50W 1600.00 0.44 188.60 1599.95 0.11 9.14S 2.71W 1700.00 0.40 173.36 1699.94 0.12 9.87 S 2.72W 1800.00 0.23 182.87 1799.94 0.18 10.42 S 2.69W 1900.00 0.09 74.62 1899.94 0.27 10.61 S 2.63W 2000.00 0.09 201.06 1999.94 0.16 10.66 S 2.58W 2100.00 0.10 106.06 2099.94 0.14 10.76 S 2.53W 2200.00 0.18 109.96 2199.94 0.08 10.84 S 2.29W 2300.00 0.13 134.85 2299.94 0.08 10.97 S 2.06W 2400.00 0.03 138.79 2399.94 0.10 11.07 S 1.96W 2500.00 0.16 104.28 2499.94 0.14 11.13 S 1.80W 2600.00 0.01 158.55 2599.94 0.16 11.18 S 1.66W 2700.00 0.17 322.45 2699.94 0.18 11.07S 1.75W 2800.00 0.10 330.42 2799.94 0.07 10.87 S 1.88W 2900.00 0.15 350.92 2899.94 0.07 10.66S 1.95W A Gyrodata Directional Survey ARMSTRONG COOK INLET LLC Location: CLACIER RIG ONE, KENAI BOROUGH Lease: NORTH FORK #41 - 35 Well: 41 - 35, 7" Job Number: AK0810GME 185 MEASURED I N C L AZIMUTH VERTICAL DOGLEG HORIZONTAL DEPTH DEPTH SEVERITY COORDINATES feet deg. deg. feet deg./ feet 100 ft. 3000.00 0.30 356.10 2999.94 0.15 10.27S 1.98W 3100.00 0.30 52.49 3099.94 0.28 9.86 S 1.80W 3200.00 0.41 59.30 3199.94 0.12 9.52 S 1.29W 3300.00 0.66 60.36 3299.93 0.25 9.05 S 0.48W 3400.00 0.51 65.97 3399.93 0.16 8.58 S 0.43 E 3500.00 0.25 70.78 3499.92 0.26 8.33 S 1.04 E 3600.00 0.44 29.61 3599.92 0.30 7.92 S 1.44 E 3700.00 0.31 18.32 3699.92 0.15 7.33 S 1.72 E 3800.00 0.26 50.51 3799.92 0.17 6.92 S 1.98 E 3900.00 0.28 55.68 3899.92 0.03 6.63 S 2.37 E 4000.00 0.11 121.69 3999.92 0.26 6.54 S 2.65 E 4100.00 0.34 65.92 4099.92 0.29 6.47 S 3.01 E 4200.00 0.29 179.96 4199.91 0.53 6.60 S 3.28 E 4300.00 0.15 283.38 4299.91 0.35 6.82 S 3.15 E 4400.00 0.57 207.62 4399.91 0.55 7.23 S 2.79 E 4500.00 0.29 162.93 4499.91 0.41 7.91 S 2.63 E 4600.00 0.41 109.95 4599.91 0.33 8.27 S 3.04 E 4700.00 0.56 80.83 4699.90 0.28 8.32 S 3.86 E 4800.00 0.46 61.57 4799.90 0.20 8.05 S 4.69 E 4900.00 0.40 58.56 4899.90 0.06 7.68 S 5.34 E 5000.00 0.26 111.76 4999.90 0.32 7.58 S 5.85 E 5100.00 0.31 96.90 5099.90 0.09 7.69 S 6.33 E 5200.00 0.30 93.73 5199.89 0.02 7.74 S 6.86 E 5300.00 0.37 69.02 5299.89 0.16 7.65 S 7.42 E 5400.00 0.17 25.48 5399.89 0.27 7.39 S 7.79 E 5500.00 0.16 47.30 5499.89 0.06 7.17 S 7.95 E 5600.00 0.22 15.73 5599.89 0.12 6.89 S 8.11 E 5700.00 0.49 353.68 5699.89 0.30 6.28 S 8.11 E 5800.00 0.93 2.57 5799.88 0.46 5.04 S 8.10 E 5900.00 0.85 6.39 5899.87 0.10 3.49 S 8.22 E A Gyrodata Directional Survey ARMSTRONG COOK INLET LLC Location: CLACIER RIG ONE, KENAI BOROUGH Lease: NORTH FORK #41 - 35 Well: 41 - 35, 7" Job Number: AK0810GME 185 MEASURED I N C L AZIMUTH VERTICAL DOGLEG HORIZONTAL DEPTH DEPTH SEVERITY COORDINATES feet deg. deg. feet deg./ feet 100 ft. 6000.00 0.68 7.44 5999.86 0.17 2.16 S 8.38 E 6100.00 0.33 4.12 6099.86 0.35 1.28 S 8.48 E 6200.00 0.30 337.95 6199.85 0.15 0.75 S 8.40 E 6300.00 0.33 66.86 6299.85 0.44 0.39 S 8.57 E 6400.00 0.71 66.18 6399.85 0.38 0.03 S 9.40 E 6500.00 0.76 40.07 6499.84 0.34 0.73 N 10.39 E 6600.00 0.46 64.78 6599.83 0.40 1.40 N 11.18 E 6700.00 0.79 292.14 6699.83 1.15 1.83 N 10.90 E 6800.00 0.98 313.64 6799.82 0.38 2.68 N 9.64 E 6900.00 0.59 323.00 6899.81 0.41 3.68 N 8.72 E 7000.00 0.44 284.64 6999.81 0.36 4.19 N 8.04 E 7100.00 0.49 280.54 7099.80 0.06 4.36 N 7.25 E 7200.00 0.49 295.94 7199.80 0.13 4.63 N 6.44 E 7300.00 0.43 281.30 7299.80 0.13 4.89 N 5.69 E 7400.00 0.56 244.29 7399.79 0.33 4.75 N 4.88 E 7500.00 0.59 264.11 7499.79 0.20 4.49 N 3.93 E 7600.00 0.66 245.80 7599.78 0.21 4.20 N 2.90 E 7700.00 0.62 240.53 7699.78 0.07 3.70 N 1.90 E 7800.00 0.73 248.65 7799.77 0.15 3.20 N 0.83 E 7900.00 0.68 255.72 7899.76 0.10 2.82 N 0.34W 8000.00 0.48 254.53 7999.76 0.20 2.56 N 1.31W 8100.00 0.25 263.80 8099.75 0.23 2.43 N 1.93W 8200.00 0.36 229.05 8199.75 0.21 2.20 N 2.39W 8300.00 0.14 149.14 8299.75 0.36 1.89N 2.56W 8400.00 0.05 230.20 8399.75 0.14 1.75 N 2.53W 8500.00 0.04 325.28 8499.75 0.07 1.75 N 2.59W 8600.00 0.28 267.58 8599.75 0.26 1.77N 2.85W 8700.00 0.24 288.94 8699.75 0.10 1.83 N 3.29W 8800.00 0.28 287.90 8799.75 0.04 1.98 N 3.72W 8900.00 0.28 309.41 8899.75 0.10 2.20 N 4.14W 9000.00 0.14 220.73 8999.75 0.30 2.27 N 4.40W �i • A Gyrodata Directional Survey ARMSTRONG COOK INLET LLC Location: CLACIER RIG ONE, KENAI BOROUGH Lease: NORTH FORK #41 - 35 Well: 41 - 35,7" Job Number: AK0810GME 185 MEASURED I N C L AZIMUTH VERTICAL DOGLEG HORIZONTAL DEPTH DEPTH SEVERITY COORDINATES feet deg. deg. feet deg./ feet 100 ft. 9100.00 0.25 271.73 9099.75 0.20 2.18 N 4.70W 9200.00 0.38 247.02 9199.75 0.19 2.06 N 5.22W 9300.00 0.44 223.38 9299.74 0.18 1.65 N 5.80W 9400.00 0.99 219.87 9399.74 0.55 0.71 N 6.61W 9500.00 1.20 219.84 9499.72 0.22 0.76 S 7.84W 9600.00 1.55 220.61 9599.69 0.34 2.59 S 9.39W 9700.00 1.57 222.69 9699.65 0.06 4.63 S 11.20W 9800.00 1.80 219.54 9799.61 0.25 6.85 S 13.13W 9900.00 2.05 225.40 9899.55 0.32 9.32 S 15.41W 9932.00 2.10 223.98 9931.53 0.22 10.14S 16.22W Final Station Closure: Distance: 19.13 ft Az: 237.99 deg. • • Page 1 of 2 Regg, James B (DOA) (}~-~ ~ ~ ~ _~ Z. ( From: Regg, James B (DOA) Sent: Thursday, August 12, 2010 9:28 AM ~~`~ ~I tZ~+~ To: 'Bill Penrose'; Edward Teng; Brad Rasch Cc: DOA AOGCC Prudhoe Bay; Aubert, Winton G (DOA) Subject: RE: Report of BOPE Use Thank you for the report. Just a reminder that BOPE used are required to be tested before next wellbore entry per 20 AAC 25.285(f)(2) Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 _ i From: Bill Penrose [mailto:bill@solstenxp.com] Sent: Wednesday, August 11, 2010 4:26 PM To: DOA AOGCC Prudhoe Bay Cc: Edward Teng; Brad Rasch Subject: Report of BOPE Use In compliance with AOGCC Industry Guidance Bulletin N. 10-1003 dated August 9, 2010 (copy attached), this is to report the use of blowout prevention equipment to prevent the flow of fluids from a well. Date/Time of BOPE Use: August 11, 2010, 0600 - 0900 hrs Well/Location/PTD Number: NFU #41-35 /North Fork Unit near Anchor Point /PTD No. 165-021 Rid Name: Glacier #1 Operator Contact: Operator is Armstrong Cook Inlet, LLC. Contact is contract drilling manager Bill Penrose -contact information shown below. Operations summary: This is a cased hole workover with open perforations. Killed the well with 9.0 ppg brine, nippled up ROPE and tested same with witness by AOGCC's Chuck Scheve. Pulled and laid down two strings of tubing, having cut one off just above a packer safety joint at approx 8,000'. Ran in hole to fish safety joint. Milled over tubing stub above safety joint and rotated to release. Upon release of the safety joint, monitored well. Observed brine and gas flowing from drill pipe. Shut annular preventer, stabbed into drill pipe, lined up returns to go through choke manifold then gas buster then pits. Circulated brine until no more gas was observed. (Currently POH, suspect gas was a bubble trapped under the packer.) BOPE Used: Annular preventer Reason for BOPE Use: Divert fluids through choke manifold and gas buster to remove gas entrained in workover fluid. Actions Taken/To Be Taken: A packer and two bridge plugs remain to be removed from the well. Upon releasing/milling each, the well will be circulated to remove any trapped gas and the brine weighted up if at any time the well acts other than completely dead. ROPE used was last tested on August 9,2010. Please let me know if additional information is needed. Regards, ~i~ ~e~vus¢e Vice President /Drilling Manager 8/12/2010 Page 2 of 2 ~~. ~. 310 K Street, Suite 700 Anchorage, Alaska 99501 Main 907-264-6100 Direct 907-264-6114 Cell 907-250-3113 8/12/2010 • L J ~~GJ~[~ OCR GI~Q~~{Q /,E.....~..~o~~. Edward Teng c~ r Vice-President, Engineering ~ . ~ d' Armstrong Cook Inlet, LLC 1421 Blake Street Denver, CO 80202 Re: North Fork Field, Undefined Gas Pool, North Fork Unit #41-35 Sundry Number: 310-167 Dear Mr. Teng: 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 rehearing. A request for rehearing 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. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Sincerely, Daniel T. Seamount, Jr. Chair DATED this ?g day of June, 2010. Encl. o (~~~~'' ° RECEIVED ~ ~ • ~~~ STATE OF ALASKA ~ ~ ~ Q ~ 2010 dam'/~ ALASKA OIL AND GAS CONSERVATION COMMISSION ~~,~- APPLICATION FOR SUNDRY APPROVAL~aska 0~ ~~~ ~~• EQso~o 20 AAC 2s.2so antzh®rf~ue 1. Type of Request: Abandon ^ Plug for Redrill ^ Perforate New Pool ^ Repair Well ^ Change Approved Program ^ Suspend ^ Plug Perforations ^ Perforate [~ PuII Tubing [1~ Time Extension ^ Operations Shutdown ^ Re-enter Susp. WeN{~}" Stimulate ^ Alter Casing ^ Other: ^ 2. Operator Name: 'p~,a'°~ ` 4. Current Well Class: 5. Permit to Drill Number: Armstrong Cook Inlet, LLC Development Q - Exploratory ^ 165-021 ' 3. Address: Stratigraphic ^ Service ^ 6. API Number: 1421 Blake Street, Denver Colorado 80202 50-231-10004-00 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes ^ No ^~ North Fork Unit #41-35 9. Property Designation (Lease Number): 10. Field/Pool(s): 11 ~ ' r ~t- North Fork ( ~~~rYUG ~ S ADL391210 , ywrt d ~. 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): 12,812' - 12,812' - 10,009' 10,009' 8,325', RT ~ 8,500' WA Casing Length Size MD TVD Burst Collapse Structural Conductor 246' 20" 246' 246' NA NA Surface 1,984' 13-318" 2,000' 2,000' 3,090 psi 1,540 psi Intermediate 8,435' 9-5/8" 8,451' 8,451' 6,330 psi 3,810 psi Production Liner 2,529' 7" 10,985' 10,985' 9,960 psi 6,210 psi Perforation Depth MD (ft): / Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 8,005'-8,045'; 8,530'-8,602' 8,005'-8,045 ; 8,530'-8,602' 2-7/8" J 6.5# N-80 BTC-M 8,045' Packers and SSSV Type: Brown 2-7/8" x 9-5/8" HS-16-1 Packer Packers and SSSV MD (ft) and TVD (ft): 7,952' MD/TVD / 12. Attachments: Description Summary of Proposal ^ 13. Well Class after proposed work: Detailed Operations Program 0 BOP Sketch ^ Exploratory ^ Development ^- Service ^ 14. Estimated Date for 1-Aug-10 15. Well Status after proposed work: Commencing Operations: Oil ^ 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 Bill Penrose (907) 264-6114 Printed Name rd Ten Title Vice-President, En ineering Signature ~_ ___ Phone Date ~ ~ .a ~~ (303) 623-1821 ~_ COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ~~ ~ ''`~~ Plug Integrity^ BOP Test ~ Mechanical Integrity Test ^ Location Clearance ^ Other: ~~ S t D ~ ~ ~ t0 3~~~ ~'J S~ • Subsequent Form Required: (n - t{- D `i' , APPROVED BY ~ ~ ' Approved by: COMMISSIONER THE COMMISSION Date: ~ Y ,iUN ~ ~ Form 10-403 Revi 0 ~ ~ V Submit in Duplicate • WORKOVER PROCEDURE ARMSTRONG c~~iv«I". ~c NFU #41-35 Pre-Rig Work 1. MIRU slickline. Pull BPV. RIH with 1.80" gauge ring to ensure 2-7/8" tubing is clear. a. Note 1: Hydrates were encountered in 2001 (but not during SL work in 2005), requiring dump bailing of methanol and chipping to clear the tubing. b. Note 2: Last tag was in 2001; a 1.80" gauge rig would not pass 8,260'. The gauge ring came out with apparent drilling mud on it. 2. Re-install BPV. 3. RDMO slickline. Rig Work 1. MIRU Glacier Rig #1. N/LT BOPE and test to,~,00Q-psi w/ AOGCC witness. ~ 2. Pull BPV 3. R/LJ slickline, pressure test lubricator. RIH and retrieve 2-1/2" CA-2 blanking plug set in Camco "D" nipple at 7,962'. POH, RDMO slickline. 4. Record wellhead pressure, weight up brine in pits to sufficient density to kill well. ~~jSU~ ~~ 5. Bullhead sized calcium carbonate pill to perforations, displacing with kill-weight brine. ~~ c~G. i ~ ' 6. RU wireline, pressure test lubricator. RIH with CCL and 2-7/8" tubing punching charge (2 shots). Use CCL to locate packer at 7,952' and perforate 2-7/8" tubing 25' above the top of the packer (in the middle of the tubing joint above the Brown CC safety joint on the packer). POH, RDMO wireline. 7. Kill well by circulating brine down tubing, through tubing perforations and up annulus. Ensure well is dead. If it is not, raise brine weight 0.2 ppg and circulate again. Repeat as necessary until well is dead. wjp 4/23/10 • 8. With well dead, R/U to pull heater string. POH and lay down heater string. Check tubing for NORM and send to Equipment Engineering in Kenai for disposal. 9. Pull the 2-7/8" production tubing as follows: M/U a 2-7/8" landing joint to the tubing hanger. BOLDS and pick up tubing to neutral weight at the Brown packer at 7,952'. Rotate the tubing 25 turns to the right to disconnect at the Brown "CC" safety joint above the packer. POH with the 2-7/8" tubing string and lay down. Check tubing for NORM and send to Equipment Engineering in Kenai for disposal. 10. PU/MU 10,000' of drill pipe work string and stand back in derrick. MU Brown "CC" retrieving tool with overshot guide, RIH and rotate to the right onto the pin connection looking up on the portion of safety joint left in the hole. Once made up, continue turning; to the right 40 additional turns to release the Brown 2-7/8" x 9-5/8" HS-16-1 packer. ~ POH with packer/tailpipe assembly (Brown packer, 1 joint tubing, Camco "D" nipple, 2 joints tubing and venturi shoe). Lay down packer/tailpipe components, check for NORM and send to Equipment Engineering in Kenai for disposal. 11. MU 9-5/8" bridge plug milling assembly, RIH and mill on the Halliburton 9-5/8" "CJ" bridge plug at 8,325' until the slips let go. Chase the remainder of the bridge plug to the 7" liner top at 8,330' but do not mill on it there. POH, L/D 9-5/8" milling assembly. 12. MU~ retainer milling assembly and RIH. Mill through the remains of the 9-5/8" bridge plug at liner top if necessary then mill the Halliburton "DM" retainer at 8,500' until ~ retainer packer slips let go. 13. Chase retainer to bottom (cement at ±10,000') and record depth of top of fish. POH, LD 7" milling assembly. 14. M/LJ 9-5/8" casing scraper and RIH, scraping 9-5/8" casing to 7,950' (55' above top set of perforations). POH, LD 9-5/8" scraper. 15. M/LT 7" casing scraper, RIH, scraping 7" liner to 8,500' (63' above top un-squeezed perforation in lower perforated interval. POH, LD 7" scraper. 16. MIRU wireline, pressure test lubricator. RIH and re-perforate the lower intervals (8,563'-78' and 8,592'-8,602') then the upper interval (8,005'-45'). POH, LD perforating guns but do not RD wireline. 17. MU lower completion assembly as follows: a. 2-7/8" WL entry guide b. 2-7/8" XN-nipple w/ 2.31" profile c. 1 joint 2-7/8", 6.4#, N-80, BTC-M tubing d. 7" Baker Model "D" permanent production packer w/ 10' of seal bore extension wjp 4/23/10 18. RIH w/ above 7" packer/tailpipe assembly on wireline. Set packer in the middle of the casing joint closest to 8,500'. POH, RD and release wireline. / 19. MU upper completion assembly as follows: a. Baker locator/seal assembly with ±12' of seals b. XO c. ±455' of 2-7/8", 6.4#, N-80, BTC-M tubing w/ gas seal ring installed in each connection d. 2 ea 2-7/8" blast joints (±60' total) e. 2-7/8"Baker "CMU" sliding sleeve (in closed position, RHC valve installed in X- profile) f. 2 joints of 2-7/8", 6.4#, N-80, BTC-M tubing g. 9-5/8"Baker Model "S-3" hydraulic-set packer / h. 2-7/8", 6.4#, N-80, BTC-M tubing to 2,300' w/gas seal ring installed in each connection i. 2-7/8" chemical injection sub w/ 1/a" stainless steel injection line to surface j. 2-7/8", 6.4#, N-80, BTC-M tubing to surface w/gas seal ring installed in each connection 20. RIH w/ above 2-7/8" upper completion assembly: a. Note 1: Space out blast joints so they sit across the perforated interval 8,005' - 8,045' . b. Note 2: Strap the chemical injection line as run to tubing for the last 2,300'. 21. Slowly approach lower packer with seal assembly. (DO NOT PUMP - a sudden increase in pressure as the seal assembly enters the seal bore could prematurely set the hydraulic-set upper packer.) Continue to set down until the seals are fully engaged and the locator sub tags up on the lower packer. PU one foot, mark the pipe and space out. (Note: this will position the upper packer at ±7,880'.) 22. Make up tubing hanger and land out tubing in wellhead. RILDS. ~ 23. Test the lower packer, seals and liner lap by pressuring up on the 2-7/8" x 9-5/8" annulus to 400 si (70°Io of the 9-5/8", N-80 casing burst strength) for 15 minutes. 24. Set the upper packer by dropping ball & rod to the RHC valve and pressuring up on the tubing in steps to 4,000 psi and holding it for 15 minutes per the Baker service hand's ~ recommendation (this will also serve as the pressure test of the tubing). Release pressure. 25. RIH with shifting tool on slickline and open sliding sleeve located below the top packer. POH. wjp 4/23/10 • 26. Test the upper packer and casing by pressuring up on the 2-7/8" x 9-5/8" annulus to x+,400 psi (70% of the 9-5/8", N-80 casing burst strength) for 15 minutes, observing for returns from the tubing at the surface indicating bleed-by at the packer. Bleed off pressure. 27. RIH with shifting tool on slickline and close sliding sleeve. POH. 28. RIH and retrieve the ball & rod from the RHC valve then retrieve the RHC valve from the X-profile in the sliding sleeve. RDMO slickline. 29. Install BPV in tubing hanger. 30. ND BOPS, NU production tree. All tree components above the tubing spool are to be /`" new Vetco-Gray equipment. No old tree components are to be re-used. Test tree to 10,000 psi. 31. RDMO Glacier Rig #1. wjp 4/23/10 • North Fork Unit #41-35 Current Wellbore Schematic 5/24/2010 J 18-5/8" Hole 12-1/4" Hole L 20" Conductor @ 246' 13-3/8" 68# J-55 BTC Surface Casing @ 709' Heater String ~ 13-3/8" 61# J-55 BTC Surface Casing from 709' - 2,000' 9-5/8" 43.5# P-110 BTC Intermediate Casing @ 2408' 9-5/8" 43.5# N-80 BTC Intermediate Casing from 2408' - 5,535' \ DV Tool @ 6,310' Brown 2-7/8"x9-5/8" HS-16-1 Packer @ 7,952' 2-7/8" 6.5# N-80 BTC-M Tubing @ 8,045 Perfs: %" Holes, 4 spf 8,005'-8,045' Halliburton "C.J." Bridge Plug @ 8,325' Brown Tie-Back Sleeve @ 8,330' Halliburton "DM" Retainer @ 8,500' TOC @ 10,009' Whipstock @ 10,173' 9-5/8" 43.5# P-110 BTC Intermediate Casing i from 5,535' - 8,451' = Perfs: Five - %:" Holes @ 8,530' // Squeezed -__ Perfs: Five -'/:" Holes @ 8,540' // Squeezed Perfs: %" Holes, 4 spf 8,563' - 8,578' ~ Perfs: %" Holes, 4 spf 8,592' - 8,602' Sidetrack hole drilled to 10,859' (Uncased) TOC @ 10,765' .~ ~ '" Ma ~ A.y x° , i >m .PA's.. YNA 1' TOC @ 10,913' ~ ~~ TD @ 12,812' Perfs: Five - %" Holes, 4 spf @ 10,786' Perfs: %" Holes, 4 spf 10,805' -10,860' Perfs: Five - %:" Holes @ 10,875' // Squeezed 7" 26# P-110 BTC Production Liner @ 10,985' • North Fork Unit #41-35 Proposed Welibore Schematic -~ 5/24/2010 J ~ 20" Conductor @ 246' 13-3/8" 68# J-55 BTC Surface Casing @ 709' 18-5/8" Hole 13-3/8" 61# J-55 BTC Surface Casing Chemical Injection Line @ 2,300' from 709' - 2,000' 9-5/8" 43.5# P-110 BTC Intermediate Casing @ 2408' 12-1/4" Hole 9-5/8" 43.5# N-80 BTC Intermediate Casing 2-7/8" 6.5# N-80 BTC-M Tubing String from 2408' - 5,535' DV Tool @ 6,310' 9-5/8" Baker Model "S-3" Hydraulic-Set Packer @ 7,880' Sliding Sleeve Perfs: %" Holes, 4 spf 8,005'-8,045' Blast Joints Brown Tie-Back Sleeve @ 8,330' 9-5/8" 43.5# P-110 BTC Intermediate Casing from 7" Baker Model "D" 5,535' - 8,451' Permanent Packer @ 8,500' Perfs: Five - %" Holes @ 8,530' //Squeezed Perfs: Five - %:" Holes @ 8,540' //Squeezed Perfs: %" Holes, 4 spf 8,563' - 8,578' (Reperfed) TOC @ 10,009' ~ ~-~ ! ~'~~ -"` Perfs: %" Holes, 4 spf 8,592' - 8,602' (Reperfed) Whipstock @ 10,173' ~^r~`~. ~°~ ~ Sidetrack hole drilled to 10,859' (Uncased) TOC @ 10,765' ~,,:~` ~ Perfs: Five - %:" Holes, 4 spf @ 10,786' ~~ v°;, :_ Perfs: %" Holes, 4 spf 10,805' -10,860' Perfs: Five - %" Holes @ 10,875' // Squeezed TOC @ 10,913' 7" 26# P-110 BTC Production Liner @ 10,985' TD @ 12,812' .'~RMSTRO\(i ( ir~3i lnic~s. LI C' June 1, 2010 Mr. Daniel Seamount, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 RE: Application for Sundry Approval Workover of North Fork Unit Well #41-35 (PTD No. 165-021) Dear Mr. Seamount, Armstrong Cook Inlet, LLC hereby applies for approval to repair North Fork Unit Well #41-35, an onshore gas production well near Anchor Point on the Kenai Peninsula. We plan to commence Workover operations approximately August 1St, 2010 using the Marathon Glacier #1 rig to replace the current completion equipment and re-perforate existing intervals. Please find attached the following information for your review: 1) Form 10-403 Application for Sundry Approval 2) Workover Procedure 3) Current Wellbore Diagram 4) Proposed Wellbore Diagram If you have any questions or require additional information, please contact me at (303) 623-1821 or Bill Penrose at (907) 264-6114. Sincerely, ARMSTRONG Edward Teng Vice President, Engineering Enclosures Cc: Bill Penrose -Fairweather E&P Services, Inc. 1424 Blake Street, Denver, Colorado 80202 Ph 303-623-1821 Fax 303-623-3019 Page 1 of 1 Aubert, Winton G (DOA) From: Bill Penrose [billt~fepsi.com] ~~~ `l'am Sent: Monda ,June 07 2010 9:18 AM ~' To: Aubert, Winton G'(DOA} ~ ~ it~~'~`~~~ 2~ K~ ~ `~~ Subject: NFU #41-35 Pressures ~ '' ~ ~C`'~ ~~~~~ ~ ~ Winton, ~ , `~ rn ~ `' ~ ~ We expect the formation pressure in the 8,000' perfs to be about 3,413 psi and at 8,500' about 3,646 psi. Regards, ~i~2 ~e~vrode Vice President /Drilling Manager Fairweather E&P Services, Inc. 310 K Street, Suite 700 Anchorage, Alaska 99501 Main 907-264-6100 Direct 907-264-6114 Ce11 907-250-31 1 3 t ~s oz t ~~1~ f~E,, c.~c ~~ ! ,~ ~ti- 3, 17 G ~/.C. ~: " hrl .~.t. ~ ~ ~ ~4-tl ~.J . 4 ~ ir~.1 +~.. ~ ~r~ i4 ~ i... ~ to i ~ ! ~ ~' p t?~' . 6/7/2010 C~ i STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION NOTICE OF OWNERSHIP* ~n aac ~s n~~ 1. Name of Current Owner of Record; Gas-Pro Alaska, LLC 2. Address: PO Box 876 East Aurora, NY 14052 3. Notice is hereby given that the above named owner ~ ,landowner , of record for the oil and gas property described below has assigned or transferred interest in the property indicated below: Property Designation: ADL 733, ADL 2095, ADL 391210, ADL 391211, ADL 391597, ADL 391603, ADL 391143 Well: North Fork Unit #41-35 Legal description of property: Field or Unit: See Exhibit A .North Fork Unit Property plat attached 4. Effective date of assignment or transfer. 5. Percentage interest assigned or transferred: 15-Jul-07 100% 6. Assignee or Transferee (new owner): Armstrong Louisiana, LLC Address: 1421 Blake Street Denver, CO 80202 7. Assignor or Transferor (existing owner): Gas- Pro Alaska, LLC Address: PO Box 876 East Aurora, NY 14052 8. Assignor or Transferor hereby certifies that the foregoing is true and correct {attach Power of Attorney or other evidence of authority of person signing): ~~~ ~ Signature: Date: / ' rrl/~ ~ T l ~~ Printed Name: Barry Foote t it e: ~ 1 f / 'This form is required to be f+Ied with the Alaska Oil and Gas Conservation Commission within 15 days after a person becomes owner of a property pursuant to 20 AAC 25. 022 and upon all subsequent changes in ownership. Form 10-417 Rev.12/2005 • Exhibit A Lessor I Lease ~ Lease Gross Net ____ _ i-. _ Acres Acres ORIGINALLY ANCHORAGE 0211997, DATED ' 600.000 440.00 EFFECTIVE FEBRUARY 1, 1955 AND SUBSEQUENTLY TRANSFERRED TO THE STATE OF ALASKA AND ISSUED AS ADL 00733 E 40.00 ORIGINALLY ANCHORAGE 026708 AND 1,240.000 063 AO SUBSEQUENTLY TRANSFERRED TO THE STATE OF ALASKA AND ISSUED AS ADL 0209b _ __ 120.00 i ORIGINALLY ANCHORAGE 024363AND 1,920.000 1280.0( SUBSEQUENTLY TRANSFERRED 70 THE j STATE OF ALASKA AND ISSUED AS ADL 391210 __ _ _ ~ - . 480.00 .-_ __. _ _ __~ __. j _. .-. `- ORIGINALLY ANCHORAGE A-024363AND 2,520.000 1720.00 SUBSEQUENTLY TRANSFERRED TO THE I STATE OF ALASKA AND ISSUED AS ADL ++ ~ 391211 _.. _ _ 160.00 :, 320.00 (Segment 2) T4S. R14W. S.M. SEC.35: SE/4, W/2 (Segment 3) T45, R14W, S.M. SEC. 35: NE/4 _..... _ _ (Segment 1) T4S. R14W. S.M. SEC. 23: ALL, SEC. 24: NW/4, SEC.26: W/2, SEC. 27: E12, SW/4, E/2NW/4, SW14NW/4 __------ (Segment 2) T4S. R14W, S.M. SEC. 24:NE/4 (Segment 3} T4S, R14W, S.M. SEC. 24:S/2 Description (Segment 1) T4S, R14W. S.M. Section 36: NE'/,, SW'/,, N% SE'f,, SW%SE%. {Segment 2} T4S. R14W. S.M. Section 36: NW1/4 NW1/4 {Segment 3) T4S, R14W, S.M. Section 36: S/2NW/4,NEl4NW/4 (Segment 1) T4S. R/4W. S.M. Section 25: SW1/4, S1/2NW1/4, W1/2 SE114, SW1/4NE1/4 --___ (Segment 2) T4S. R13W, S.M Section 20: N/2SE/4, SW/4SE/4 (Segment 3) T4S. R14W, S.M. Section 25: N/2NW/4, NJ2NE/4, SE/4NE/4, E/25E/4 _.__ __- (Segment 4) T4S. R13W. S.M Section 20: N/2, SW/4 (Segment 1) T4S. R14W. S.M. SEC. 28: Ell, SEC. 33: Ell, SEC.34: ALL, _ __ 120.00 280.00 480.00 160.00 Exhibit A 160.00 I (Segment 4) T4S, R14W, S.M. SEC. 26: NE/4 _ 80.00 (Segment 5) T4S, R14W, S.M. _ ! ~ SEG. 26: E/2SE/4 : 80.00 -- (Segment 6) T4S. Ri4W. S.M. SEC. 26: W/2SEI4 ADL-390597 2,116.790:2,116.79 'T4S. R13W S.M. ~ ~ SEC. 20, Surveyed, SE4SE4, 40 acres; } ' ,SEC. 21, Surveyed, ALL, 640 acres; I$EC. 28, Surveyed, ALL, 640 acres; 'SEC. 29, Surveyed, ALL, 640 acres; j j SEC. 31, Surveyed, Fractional, S2SE4, E2E2NW4, and ASLS78-94 as shown on Plat No. 79-7 in the Homer _______.. Recording District, 156.79 acres ADL-390603 _. _ _ _-- :4,405.040 ; 4,405.04 .T4S. R13W, S.M. SEC. 1, Surveyed, Fractional, ALL, 640.88 acres; SEC. 2, Surveyed, Fractional, Lots 1 ihru 4, S/2NE/4, ~E/2SE/4, NW/4SE/4, N/2SW74, SW/4NWI4, 481.72 acres; SEC. 3, Surveyed, Fractional, ALL, 642.44 acres; SEC. 10, Surveyed, W/2NW/4, NW/4SW/4, 120 acres; SEC. 11, Surveyed, ALL, 640 acres; SEC. 12, Surveyed, ALL, 640 acres; ISEC. 13, Surveyed, ALL, 640 acres; `SEC. 14, Surveyed, SWl4, S/2NW/4, NW/4NW/4, :SEC. 15, Surveyed, SEl4NE/4, NEt4SW/4NE14, Nl2NW/4NE/4, SE/4NW/4NE/4, SE/4, Sl2SW/4, 320 acres i - ADL-391143 - _ --- ~ 3,840.000 ~ 3,840.000 T3S, R13W, S.M, .SEC. 23, Surveyed, by protraction, all, 640.00 acres; j SEC. 24, Surveyed, by protraction, all, 640.00 acres; I} SEC. 25, Surveyed, by protraction, all, 640.00 acres; 'SEC. 26, Surveyed, by protraction, all, 640.00 acres; iSEC. 35, Surveyed, by protraction, all, 640.00 acres; ;SEC. 36, Surveyed,_by protraction all, 640.00 acres• __ WELLS: _ _ ~ __. _ __ _ _ ___ i ~. _ _ _._. ------ N FORK UNIT 41-35 i ':. T4S. R14W. S.M. API 50-231-10004-00-00 SEC. 35 STATE OF ALASKA • ALASKA OIL AND GAS CONSERVATION COMMISSION DESIGNATION 4F OPERATOR 20 AAC 25.020 1. Name and Address of Current Owner of Record: Gas-Pro Alaska, LLC PO Box 876 East Aurora, NY 14052 2. Notice is hereby given of a designation of operatorship for the oil and gas property described below: Legal description of property: See Exhibit A Property Plat Attached: ^ 3. Name and Address of Designated Operator. Armstrong Cook Inlet, LLC 1421 Blake Street Denver, CO 80202 4. Effective Date of Designation: 15-Jul-07 S. Acceptance of operatorship for the above escribed property with all attendant responsibilities and obligations is hereby acknovrledged (attach Power of AttorneK or other evidence of authorit of erson sic Signature Date IL/~l ~ ~ ~~ VP Armstrong Oil & Gas, Inc., Printed Name Ed Kerr Title Manager Armstrong Cook Inlet. LLC 6. The Owner hereby certifies that the foregoi is true and correct jattach Power of Aitornev or other evidence of authority of person signing): Signature Date ~~~~ ~~ ~/'e S~ ~~'` ~ Printed Name Barry Foote ' Title ~ / 7. Approved: Commissioner Date Approved: Commissioner Date Approved: Commissioner Date (Requires approval by tvro Commissioners) Form 10-411 Rev. 7!2009 Submit in duplicate Exhibit A • Lessor ~ Lease Gross _ i Acres. ORIGINALLY ANGHORAGE 026887, DATED ~ 600.000 EFFECTIVE FEBRUARY 1, 1955 AND SUBSEQUENTLY TRANSFERRED TO THE STATE OF ALASKA AND ISSUED AS ADL 00733 Lease Description E Net Acres _ _ _ _ __ 440.00 (Segment 1) T4S, R14W, S.M. Section 36: NE%., SW"/,, N%s SE%., SW"/. SE%, 40.00 `, (egment 2) T4S. R14W. S.M. i Section 36: NW1/4 NW1/4 120.00 (Segment 3) T4S. R14W. S.M. ____ i Section 36: S12NW/4,NEl4NW/4 - ORIGINALLY ANCHORAGE 0211708 AND 11,240.000 360.00 SUBSEQUENTLY TRANSFERRED TO THE STATE OF ALASKA AND ISSUED AS ADL 0209b 120.00 280.00 480.00 _. _ _____ ORIGINALLY ANCHORAGE 024383AND 1,920.000 } 1280.00 SUBSEQUENTLY TRANSFERRED TO THE ` STATE OF ALASKA AND ISSUED AS ADL ~, 391210 --- _ i _. i ! 480.00 160.00 j ---- - i - ORIGINALLYANCHORAGE A-024363AND ~ 2,520.000 ; 1720.00 SUBSEQUENTLY TRANSFERRED TO THE STATE OF ALASKA AND ISSUED AS ADL I 1 391211 _ a ; 160.00 1 i ~~~ ~~ {Segment 1) T4S. R14W, S.M. Section 25: SW1/4, S1/2NW1/4, W1/2 SE1I4, SW1/4NE1/4 ___ (Segment 2} T4S. R13W. S.M Section 20: N/2SE/4, SW/4SE/4 (Segment 3) T4S. R14W. S.M. Section 25: N/2NW/4, N12NE/4, SE/4NE/4, E/2SE/4 __ _.. _-_ (Segment 4) T4S. R13W, S.M Section 20: N12, SW/4 ____ _ (Segment 1) T4S. R14W. S.M. SEC. 28: E/2, SEC. 33: E/2, SEC.34: AIL, _ _. (Segment 2) T4S. R14W. S.M. SEC.35: SE/4, W/2 (Segment 3) T4S. R14W, S.M. SEC. 35: NE/4 {Segment 1) T4S, R14W. S.M. SEC. 23: ALL, SEC. 24: NW/4, SEC.26: W/2, SEC. 27: E/2, SW/4, E/2NW/4, SW/4NW/4 {Segment 2j T4S. R14W, S.M. SEC. 24: NE/4 (Segment 3) T4S, R14W, S.M. SEC. 24:S/2 Exhibit A 160.00 ? {Segment 4) I T4S, R14W, S.M. SEC. 26: NE/4 _ __ 80.00 !. (Segment 5) __ T4S, R14W, S.M. SEC. 26: E/2SE/4 80.00 (Segment 6) i T4S. R14W. S.M. SEC. 26: W/2SE/4 _._ ADL-390597 _-- 2,116.790 ' 2,116.79 lT4S. R13W S.M. ISEC. 20, Surveyed, SE4SE4, 40 acres; ;SEC. 21, Surveyed, ALL, 640 acres; ~ SEC, 28, Surveyed, ALL, 640 acres; I SEC. 29, Surveyed, ALL, 640 acres; SEC. 31, Surveyed, Fractional, S2SE4, E2E2NW4, and ASLS78-94 as shown on Plat No. 79-7 in the Homer I .Recording. Distric#,.156.79 acres _ ADL-390603 i 'I - -_ ----- 4,405.040 j 4,405 04 iT4S. R13W. S.M, ;SEC. 1, Surveyed, Fractional, ALL, 640.88 acres; SEC. 2, Surveyed, Fractional, Lots 1 thru 4, S/2NE/4, sE/2SE/4, NW/4SE/4, N/2SW/4, SW/4NW/4, 481.72 acres; j SEC. 3, Surveyed, Fractional, ALL, 642.44 acres; SEC. 10, Surveyed, W/2NW/4, NW/4SW/4, 120 acres; SEC. 11, Surveyed, ALL, 640 acres; !SEC. 12, Surveyed, ALL, 640 acres; (SEC. 13, Surveyed, ALL, 640 acres; ! 1 `SEC. 14, Surveyed, SW/4, S/2NW14, NW/4NWi4, ?SEC.. 15, Surveyed, SE/4NE/4, NE/4SW/4NE/4, i N/2NW/4NE/4, SE/4NWl4NE/4, SE/4, S/2SW14, 320 acres I ._ ADL-391143 I --- 3,840.000 3,840 000 T3S. R13W, S.M. :SEC. 23, Surveyed, by protraction, all, 640.00 acres; ;, .SEC. 24, Surveyed, by protraction, all, 640.00 acres; ISEC_ 25, Surveyed, by protraction, all, 640.00 acres; ~ !SEC. 26, Surveyed, by protraction, all, 640.00 acres; ! ISEC. 35, Surveyed, by protraction, all, 640.00 acres; ,~ ~ _ (SEC. 36, Surveyed, by protraction~.all 640.00 acres _ .._ WELLS: ___~_ _ _ . _ _ _ _ _ _ _. _- ~ N FORK UNIT 41-35 _ i __ --- T4S. R14W, S.M. API50-231-10004-00-00 i i SEC. 35 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION DESIGNATION OF OPERATOR 20 AAC 25.020 1. Name and Address of Current Owner of Record: Gas-Pro Alaska, LLC PO Box 876 East Aurora, NY 14052 2. Notice is hereby given of a designation of operatorship for the oil and gas property described below: Legal descripiion of property: T4S, R14W, S.M. Sec. 35 Property Plat Attached: ^ 3. Name and Address of Designated Operator: Armstrong Cook Inlet, LLC 1421 Blake Street Denver, CO 80202 4. Effective Date of Designation: 15•Jul-07 5. Acceptance of operatorship for the above described property with all attendant responsibilities and obligations is hereby acknowledged (attach Power of Attorney or other evidence of authority of person si nin D t Si t ~~~`"1 ~~ U a e gna ure VP Armstrong Oil & Gas, Inc., Printed Name Ed Kerr Title Manager Armstrono Cook Inlet. LLC 6. The Owner hereby certifies that the f Ding is tn~e and correct (attach Power of Attor ney or other evidence of authority of person sionina)~ Date Si t ~ / /p~r%/ gna ure • Printed Name Barry Foote Title v' /" LUJ~ ~ 7. Approved: Commissioner Date Approved: Commissioner Date Approved: Commissioner Date (Requires approval 6y !vro Commissioners) Form 10-411 Rev. 712009 Submit in duplicate • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION NOTICE OF OWNERSHIP* 20 AAC 25.022 1. Name of Current Owner of Record: Gas-Pro Alaska, LLC 2. Address: PO Box 876 East Aurora, NY 14052 3. Notice is hereby given that the above named owner ~ ,landowner , of record for the oil and gas property described below has assigned or transferred interest in the property indicated below: Property Designation: AOL 391210 Well: North Fork Unii #41-35 Legal description of property: Field or Unit: T4S, R14W, S.M. Sec. 35 North Fork Unit Property plat attached 4. Effective date of assignment or transfer: 5. Percentage interest assigned or transferred: 15-Jul-07 100% 6. Assignee or Transferee (new owner): Armstrong Louisiana, LLC Address: 1421 Blake Street Denver, CO 80202 7. Assignor or Transferor (existing owner): Gas- Pro Alaska, LLC Address: PO Box 876 East Aurora, NY 14052 8. Assignor or Transferor hereby certifies that t aegoing is true and correct (attach Power of Attorney or other evidence of authority of person signing): f'~~/ ,,, .-. Signature: Date: ~/"! ~ /~ ~~ P i t d N F t Titl ~ ~ ~ r n e ame: Barry oo e e: ~ ~, .~ *This form is required to be filed with the Alaska Oil and Gas Conservation Commission within 15 days after a person becomes owner of a property pursuant to 20 AAC 25. 022 and upon all subsequent changes in ownership. Form 10-417 Rev.12/2005 • October 4, 2007 Bob Merrill Bureau of Land Management 6881 Abbott Loop Road Anchorage, Alaska 9907 Re: Gas Pro LLC Bond Number P-OS-O1 Dear Mr. Merrill: SARAH PAL/N, GOVERNOR 333 W. 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 pAx (907) 276-7542 ~~~~ NOV ~ ~ 207 Attached is a copy of the personal bond, P-OS-O1, being held for Gas Pro LLC in the amount $100,000. The bond is secured by a cash deposit of $100,000 held by the State of Alaska. See 20 AAC 2~.025(a)(2}. This bond meets the Alaska Oil and Gas Conservation Commission's single-well bonding requirements for the North Fork Unit No. 41-35 development well, which is located on State of Alaska lease ADL 391210. Thus, with respect to this well, bond P-OS-O1 replaces federal bond AKAA-085746 for the purposes of AS 20 AAC 25.025. State lease ADL 391210 was formerly known as Federal Lease A-24363, w°hich was transferred to the State of Alaska effective November 1, 2006. If you have any questions, please do not hesitate to contact the undersigned at (907)793- 1221). Sincerely, ,- Daniel T. Seamount, Jr. Commissioner Bureau of Land Management Bonding on Lease A-024363 and Nort... . . Hi Temple: You left a message on Bill Diel's voice mail regarding the Bonding on the North Fork Unit (well 41-35) and he asked me to contact you on this issue. I left you a voice mail but wanted to e-mail in case I missed you via phone today. In the decision by the BLM, dated November 1, 2006, waving administration and transferring the North Fork Unit and associated Leases to the SOA, there is the following paragraph: The lessee/operator has 30 days from the date of this decision to obtain, submit and receive SOA approval on a replacement bond assuming all liability of personnel lease bond AKAA-085746 currently held by the BLM in the amount of $10,000. On or before the 30th day, the lessee/operator must provide written request to release personnel lease bond AKAA-085746 and proof of approved replacement bond with assumption of liability by the SOA. Failure to provide this will result in delay of relinquishment of personnel lease bond by the BLM. By certified mail Keith Summar signed for the decision sent to Gas Pro Alaska LLC. The post office date stamp on the cert. card was November 9, 2006. All of the copies of the decision that were sent to the lessee were received, except for Alliance Energy Group which came back to the BLM on December 11, 2006 stamped "return to sender unclaimed unable to forward". Gas Pro Alaska LLC needs to obtain bonding from the SOA. Before I can do final transfer of well 41-35 to AOGCC, the BLM has to have proof of SOA bonding on lease A-24363 assuming all liability for BLM Bond AA-85746. I did contact AOGCC to let them know the BLM transferred the North Fork Unit and associated Lease to the SOA. That I would be sending them a letter transferring the well. I hope this helps answer your question? I will be out of the office from 10 am today until January 11, 2007. Bob Merrill, Mineral Law Specialist has been briefed on this issue and can answer any other questions you have. His number is 907-267-1262. Question regarding transfer of well can be directed to Tim Lawlor at 907-267-1442. Thank you and Happy Holidays. /s/ Melissa Ainsworth Mineral Law Specialist NIAFMSS Local User Support Bureau of Land Management- Alaska 907-267-1212, 907-271-5718 phone 907-267-1304 fax melissa -.·>=..1· -~. .~..' -. ,,~~ .'i{~;:¡¡'~ . ".~ Ij \ OV6'" 3 ~tji ,~ r; tG, 1 of 1 12/27/200610:13 AM " e e rru 1f 'ü' rr \ II. . " I~ ® Uuu:: It: (ñ'ln ì lill FRANK H. MURKOWSKI, GOVERNOR ALASKA. OIL AND GAS CONSERVATION COMMISSION 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Samuel G. Nappi President GasPro Alaska LLC 1909 South Harvard Avenue Tulsa, OK 74112 j Re: North Fork Unit, NFU #41-35 Sundry Number 305-291 (; Dear Mr. Nappi: The Commission denies the enclosed Application for Sundry Approval relating to the above-referenced well. The reasons for this denial are (1) there is a high likelihood that the U and L Tyonek sands are at sufficiently different pressures to allow cross flow if the sands are simultaneously open, and (2) your proposed procedure attempts to test the L Tyonek while the U Tyonek perforations are open. This denial is without prejudice to your right to resubmit an application in the future if you believe your proposed operation then meets the applicable standards under the Commission's regulations. As provided in AS 31.05.080(a), 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 rehearing. A request for rehearing 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. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Sincerely, ~.;'// "'¡/j/ Vf·· )--1, DATED this J.Ç day of March, 2006 Encl. Dan T. Seamount Jr. Commissioner D . Cf'f~liR~-t\ 'J/..J,aJ. 2..,01) C:"'r::../ . '. L..Vœf:!V~ STATE OF ALASKA (J//-0'" SfP 2 9 2005 ALASKA OIL AND GAS CONSERVATION COMMISSION . APPLICATION FOR SUNDRY APPROVALs4'aska 0" & Gas Cons. Commission , 20 AAC 25.280 Anchorage Abandon Suspend Operational shutdown Perforate Waiver Otner Aller casing 0 Repair well 0 Plug Perforations 0 Stimulate 0 Time Extension 0 Change approved program 0 Pull Tubing 0 Perforate New Pool D Re-enter Suspended Wen 0 2. Operator Name: 4. Current Well Cla~s; 5. Permit to Drill N mber: / GasPro Alaska LLC Development 0 Exploratory 3. AddrêSs: Stratigraphic 0 Service 1J/14/2018 15:40 FAX 1. Type of Request: e 1909 South Harvard Avenue Tulsa, OK 74112 7. KS Elevation (ft): 780' 9. Well Name and Number: Norlh Fork Unit #41·35 / 1 O. FleldIPools(~): North Fork Unit PRESENT WEL.L. CONDITION SUMMAR Total Depth TVD (ft): Effective Deptn MO (It)~ Effective Dept JV 12812 6326 a, Property Designation: BLM Lease A·024363 11. Total Depth MD (ft): 12812 Casing Structural Condut:tor 246' Sur/ace 2000' Intermediate 6<\1;)1' PrOduction 8451' Liner 2655' Perforation Depth MD (ft): 8005-6045 Packers and SSSV Type: 12. Attechments: L.ength SI~e 20" 246' 2000' 8451' 133/8" 9 5/8" 9 5/8" 7" Perforation Depth TVD (ft): 8005·8045 Brown 2 7/8" x 9 5/8" HS·16-1'\ o Commencing Operation!¡: 16. Verbal Approval: Commission Representative: 17. I nereby oertify that the foregoing is true a Printed Name Samuel G, appi Signature Conditions of approval: Plug Integrity D Other: Junk (measured): None ElUfst Collapse Tubing Grade: 6.5# N·aO Packer5 and SSSV MD (ft): Tubing MD (ft): 8046.1 B' 7952' 13. Well Class after proposed work: Exploratory 0 Development 0 /Service D 15. Well Status after proposed work: 011 0 Gas 0 / Plugged 0 Abandoned D WAG 0 GrNJ D WINJ 0 WDSPL 0 correct to the best of my knowledge. Contact Title President Phone e16-748-6775 Date COMMISSION USE ONL. Y ~ Met:nanlt:allntegrity Test D Samuel G. Nappi, President :Z7-Sep-05 Sundry Number: - ;;;1' / location Clearance 0 RBDMS 8Fl MAR 1 6 2006 APPROVE;D BY THE; COMMISSION COMMISSIONER Form 10·403 Revised 0712005 Date: '\ /1, L !\ L tv. I SubmIt In Duplicate 11/14/2018 15:41 FAX e e GAS PRO ALASKA LLC ~ 003/004 RECEIVED SEP 2 9 2005 NORTH FORK UNIT #41-35 Alaska Oil & Gas Cons. Commission Proposed Lower Tyonek Ss Test Procedure - Fall 2005 Anchorage (Attachment to AOGCC Fonn 10-403) Purpose: To determine the productivity of the Lower Tyonek Ss from 851O~8602' MD. Procedure: Run static gradient pressure test of Upper Tyonek Ss from 8000-45' MD. Stop static gradient pressure gauges at 2000' MD; 4000' MD; 6000' MD; 8025' MD. Fill tubing and backside with 7% KCL water Pull heat string / Nipple up BOP stack / Pull tubing and packer from hole I , If necessary, reverse circulate KCL to eliminate any ga.s Rill with 2 7/8" drill pipe and bit Drill out cmps at 8325' and 8500' (see attached well bore schematic) / Perforate Lower Tyonek Ss from 8510-40' MD; 8560-8602' MD with casing gun using 6 shots per ft at 60 degrees phas.e Rill with 2 7/8" tubing and packer; set packer between U and L Tyonek sands // NU wellhead Pressure test packer for integrity Swab well down, observe flow rate and fluid recovery; once well cleans up shut well in RIH wi static gradient pressure gauges stopping at 2000' MD; 4000' MD; 6000' MD; 8025' MD; 8525' MD (for 30 minutes); 8580' MD (stopping for 30 minutes) Flow test Lower Tyonek SS RIB: wi well test pressure gauges to 8475' MD. Begin flowing well at 1500 MCFD until flow rate and flowing tubing pressure have stabilized (estimated to / be at least four hours). Record gas rate and flowing tubing pressure every 15 minutes at the surface. Rate 1: Begin 4-hr flow at 375 MCFD or 15% choke setting Buildup 1: Shut-in well for 4 hours Rate 2; Begin 4-hr flow at 750 MCFD or 30% choke setting Buildup 2: Shut-in well for 4 hours J/14/2018 15:41 FAX e e Proposed Lower Tyonek Ss Test Procedure - Fall 2005 (cont.) ~ 004/004 Rate 3: Begin 4·hr flow at 1125 MCFD Or 50% choke setting Buildup 3; Shut-in well for 4 hours Rate 4: Begin 4-hr flow at 1500 MCFD or 75% choke setting Extended Rate: Lower choke setting to 63% and flow at 1250 MCFD for 96 hours (4 days). Mid-way through flow period catch two surface gas samples for composition and viscosity measurements. / Final Buildup: Shut-in well for 192 hours (8 days). L Tycnek T~sl Procedure for AOGCC pelmil- 2005 2 /14/2018 15:40 FAX e e ALLIANCE ENERGY GROUP 141 001/004 1909 South Harvard Tulsa, Oklahoma 74112 918-748-8775 (Fax) 918-748-8891 310 K Street Suite 200 Anchorage. Alaska 99501 907-264-6636 (Fax) 907-264-6654 FAX COVER SHEET Date: 9/27/05 Time: RECEIVE[) SEP 2 9 2005 Araska Oil & Gas Cons. Anchorage From: Sam Nappi Recipient Fax #: Please deliver these 1 pages To Mr Crandall Message: Ttank Yon -!t-Ø.- 11\ "1'\" Sam Nappi \ .j - -.." . -ta/~tr.JNIIIW fI,n <Ie' ~, ""rl~/_ -I'IW/Jr Ifll,""" 1'a41tJ' -,..,' ""''''17'11 pI"H'tZ' AU'S~'~tiftßtl' / : -Iflnt'''' - s·...... N~" .h:1?~~'r"'~ ¡y¡t'S'ð) - 6~~- ¡f'GIf.r. - taf'4ç' ('~s.a) ])~T ä.(-:¡("" '4'''' I I h/lN6' L__~.I ~ "2.8'2' NO~' -1/1 ~ .Is "p;~ 8.15" ~80 £V£ 811 8GB MI..,.,. $f,.,,,, ~ ( ,."I6ttI'W/~) c:1:I/.I"''7. Atta~Dt 12} . B<l41' I-H.r.l¡~ ~M ø,v.,.. 'A1t. 1J4«J' ,-,.... ""L~____A I' =-HN'~~' g n:::: ¡¡ 'ft-..r· .........., _/Jllr r . , C"",,_ MH""""',-w ..to", ~ 111I: ,,," ~ -.I'-N· '1/,._ œ APAP".. tH:'.~.". 'AICt .H. , ."lWH", - C/.~. '/Þoow, 'N·,KJ1.~ HI-k'f ~·I!H' of H. II ¥" Ot/HnI-II:1.'" 'é1MP,. zr $'"~.,. - .'1' '.fI., e."ÑÞ;" -IM.flr ~"'",.I .,,~ ... . H' -,.1..(1" S V2--I< J. (iJ 0.." ,. 44-1. CAe ÞH.-v*) 1 u~ e ,~ 99/17(2981 16:27 9187488891 t-mTHSTAR PAGE 03 4 '.'- .~ - """'" ""'d/( ~..-- ,p ICß. ( - L Ntl .'I('(L -4;:;S - ! .M7re.. AQ ",_ . ,lN' "8Ø·j~t· (JRIQ/NAL' CA$//fItll Tv8~d& 'O~r;4',¡¡ .- ÚndiIPA: r/Jn§'tP -.'(7,' tri. nos' l~U' ,/e-1'9 ~ ~nø'¡:nø I"/,"",t!!' -..1.t7 .9"'fs.~ 'I-rúØQrS'-SJ(I.~i'. 114'.~ II fl'Ar. 1/ AF h ~ It" n¿,r¡. -~&'e' Of IS ~·Af,;q.¡..I'frs. "'~-:I.. ' - . '0,0" ~. N..r.r JIb... -", -,. . ?l' .Mr. 4 J!io~ Ñ.61", IIpI « d", c"1;-Ñ"~HI~N8e.",,' 11~,../.,d Cø.'....~~- ~~fJe.u· ~ ifJ«J' -I/~ ~:. o;,"M,;../.. ..... -'-"SiI' i ¡~~,!Þ' , ' 181' .11.. lfi" J"ø-Ing -lno.~S· Q,II_ "'/11.1' , . e e ~ç A,SRCEner,gy- Servi~es ~' ritE & P TechnDIDgy , Well Kill Procedure NFU #41-35 · Notify agency representatives, BLM and AOGCC, 24 hrs prior to well kill operations. Notify surrounding residents of upcoming operations. · Fabricate and install insulated wellhouse with flag pole for wind sock. Hook up air heater to thaw well cellar and tree valves. · Service all valves on tree and wellhead. Rig up lubricator on tree. Pull back pressure valve. Record tubing pressure. Calculate kill weight fluid. · Rig up Pollard E-line unit. Pressure test lubricator to 2,500 psi. Make up and run in hole with APRS tubing cutter. Part tubing at 7,945'. Make up and run in hole with APRS tubing punch. Punch hole in tubing at 7,935'. Rig down Pollard E-line unit. Record shut in tubing pressure. · Pump and well kill job will be conducted during day light hours only. Hold pre- job safety meeting with all crew members. · Relocate surrounding residents and non-essential personnel to pre-planned area during pumping and kill operations. · Review emergency response and pad evacuation plan. Block access road to well location. Post individual at road block with two-way radio, cell phone, and list with names of all crew members on location. Conduct radio check with all crew members. · Rig up mixing and pump unit with choke skid. Pressure test all surface lines and equipment to 2,500 psi. Mix and pump kill weight fluid. Tubing volume is 46 bbls. Annulus volume is 528 bbls. · Circulate well thru choke to kill tank. Follow pumping schedule and maintain sufficient back pressure on well to remove gas. Vent gas to atmosphere. Note direction of wind sock while venting gas. · Freeze protect well with 5 bbls diesel. U-tube to annulus. Rig down pump unit. Set BPV. Secure tree and wellhead. Notify residents when area is secure. Contact BLM and AOGCC when job is complete. 12/612005 ~. ;;ýC: )(Î. 'f e ASRC Energy Services E & P Technology Emergency Response Plan Well kill Operations NFU 41-35 level 1 Incident: Response to incident can be handled by on-site resources: · First call is to Project Drilling Manager, Nick Scales · First aid or recordable injury transportable to medical clinic by on-site personnel. · Potential loss of primary well control · Major lost fluid returns while pumping · Unable to safely vent gas. · Small spill on pad. level 2 Incident: Requires additional resources from emergency response groups: · First call is to 911 emergency response. · Second call is to Project Drilling Manager, Nick Scales · Major accident emergency medical response required. · Well control incident, wellhead failure or lost pump. · Fire on location. · Major spill · Hazardous spill level 3 Incident: Requires additional resources from emergency response groups: · First call is to 911 emergency response · Second call is to Project Drilling Manager, Nick Scales · Multiple injuries · T otalloss of well control · Catastrophic spill · Explosion · Fire affecting all equipment on location. Effective reporting is essential to ensure information reaches the proper destination in the shortest time, and to provide assurance to the responsible management that appropriate resources are engaged and response actions are being initiated. 12/612005 ~JÇÇ: 1\1. , ! e . ,. ...;..>~:: ".:'<:::'.:.." AiiRm;!Energy Services E &. P Technology Emergency Response Plan Well kill Operations NFU 41-35 Contact Numbers: · Nick Scales, Project Drilling Manager Office Phone: (907) 339-6465 Cell Phone: (907) 830-5352 Home Phone: (907) 745-5863 · Kerry Marshall, HSE Manager Office Phone: (907) 776-6317 Cell Phone: (907) 398-0093 Home Phone: · ASRC Energy Services O&M Nikiski Dispatch Dispatch Phone: (907) 776-8441 12/612005 e North Fork 41-35 Proposed Work Over Schematic 20" 78 .6# - 246' 13-3/8" 61#-68# J-55 - 2000' 2-7/8" heater string - 2511' 2-7/8" 6.5# N-80 8RD TBG Tail @ 8046' Hal CIBP - 8325' TOL - 8330' 9-5/8" 43.5# N-80 - PliO - 8541' 7" Liner - 10,985' MDrrVD '] [' 0', 1'" 2 S Nippl, - lIT Otis Pos I S Nipple - 220 I' e AS.RC Energy Sep,vices E & P T~t!~løBY . , 'j:, Logging Program * Surface * Intermediate * Production Cameo MM Mandrel wi DMY valve- 7905' Brown HS-I6-1 PKR - 7952' Cameo D Nipple - 7983' Perfs (8005' - 8045') 0( 0( FILL tagged at 8260' FISH - II' wireline junk - top of fish @ 8313' 0( Hal Drillable BP @ 8500' Perfs (8563' - 8602') 0( Plug @ 10009' 0( Redrill Window (10166' -10207), plugged baek Perfs (10806' - 10860') -GR - GR, Res - GR, Res, Neutron De - Dipole Sonic, MDT Jake Flora 11-18-05 .. North Fork 41-35 Proposed Work Over Schematic e 20" 78.6# - 246' 13-3/8" 61#-68# J-55 - 2000' 2-7/8" heater string - 2511' Blast joint adjacent perfs TOL - 8330' 9-5/8" 43.5# N-80 - PlIO - 8541' Blast joint adjacent perfs 4-Yz" or 3-Yz" tbg to +/- 8765' 7" Liner - 10,985' MD!fVD I] Ilft..~ \?"i [I Camco DS Nipple @ +/-500' Test Port / Mandrel' 0( Production PKR @ +/- 7900' Sliding sleeve @ +/- 7940' Perfs (8005' - 8045') - ASRC Ener!Üv Services E & P Techn..l",gy '. 3 trip completion 1. RIH with lower duel PKR assembly wi plug in lower nipple, set lower mechanical pia, pressure up to set upper pia, RIH wi wireline to pull plug, pressure up to test lower PKR, unsting seals, POOH. 2. RIH wi workstring & RTTS PKR to below upper perfs, pressure up down workstring to test middle PKR, POOH. 3. RIH wi upper seal assembly & PKR, sting in, pressure up to test seals & set upper PKR, POOH. 4. RIH wi wireline, open desired production sleeve Hydraulic set production PKR & seal bore receptacle @ +/- 8200' Camco DS Nipple @ +/-8250' Sliding sleeve @ +/-8500' Perfs (8563' - 8602') Mechanical set Production PKR @ +/- 8700' 0( Plug @ 10,009' Perfs (10,806' - 10,860') Jake Flora 11-18-05 ) MEMORANDUM ) State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg, P. I. Supervisor DATE: June 9,2005 THRU: .--; \ / ,r/¡ '1' ;' /1//"·/ r¡ (./(,/ ¡; .,p" ¡ ¿, 0 ':? { \ FROM: Lou Grimaldi, Petroleum Inspector N, FoR.~ Lln~ 4\-35- SUBJECT: Location InsnAction PTD# I ~5- 01.1 Thursday, June 9, 2005; I made an inspection of the Gaspro 41-35 location in the Anchor Point area of the Kenai Peninsula. I found the location to be clean and in good condition. The wellhead seemed to be secure and in good repair. There is some white ASS plastic gaurds stacked around the outside of the fence surrounding the wellhead, this appears to be no problem. Attachments: Gaspro 41-35 06-09-05 LG a.jpg Gaspro 41-35 06-09-05 LG b.jpg Gaspro 41-35 06-09-05 LG c.jpg Gaspro 41-35 06-09-05 LG d .jpg Gaspro 41-35 06-09-05 LG e.jpg NON-CONFIDENTIAL SCANNED .JUN 2, 8 2005 Location Inspection Gaspro 41-35 06-09-05 LG.doc ") ) I &s -'Ö?-I North Fork Unit 41-35 Well Inspection Photos from AOGCC Inspector Lou Grimaldi June 9, 2005 ~ ~; .;¡.;.',,'........ L -~~~':',i'. . .:-.rb._:~"I.\~,; ':"~'''''~''~'~M,~ .:. ".11"._ ~h.I~',,,..~~.~ ::............. . c. ....._ ':~:~~':." NFU 41-35 S~C~NNED AUG 0 '92005 NFU 41-35 Well after repairs to heat string; removed cracked pipe above flange; unclear when repair was completed by operator 2005-0609_Location_NFU_ 41-35_lg.doc NFU 41-35 ......., ) ~~~j~çt:~1l1~1~~$:..··.·...... ............................... >. '.' . . ........................... ......... ................. .......... ............. ..' ~~~ltl:...Jä111esRi~g.ª.~ itl1_r9~~~å9MtP;sraF~¡~k~s> . J?~t~:Tue;~9 Apr.400$13:J5:40..~P~QQ. .. :kg . . ............................ ;':';;.:'".¡¡::.:::> :~..: :'.' :.: .. :: Thanks for returning my call. Attached are photos one of our inspectors took showing the split in heat string. Jim Regg AOGCC .~.rl.~p<:!~.~. .~.C:>J:1.... ..§tlPE:!~Y~ .r3C:>.~... , Content-Type: application/msword .20()5-0328_ Well_Inspect_North_Fork_Unit_ 41-35-photos.Jj.doc Content-Encoding: base64 4\l<1.\05 K:",d·~ 2x.tIAlVr Q¿prt'S~ N~<;;¢\¡- 2AercrÓ- for~kJ CCf'€6 cf- uJt!~_ h~J SCC-'~~(L~t:;f)\CSf0c ¡J.fU 4{-3,5' L1~D5" - sr~e -k ~e~;+4. 'S'l~ Ie- ~ f\J~ll 41-35 j '1Aes\d SiÆ,)\~'j c(pp1kc~.f;.- œr-G¡"t'~ -+. SPit t\eøJ- Gk-I~ (See. c~~eJ p~<;), .sCANNE[) MÞ Y 0 4 ZOO{S'" 1 of 1 4/19/2005 1:18 PM ) ) North Fork Unit 41-35 Photos by AOGCC Inspector Jeff Jones March 28, 2005 NFU 41-35 Heat String split 04/19/2005 15:43 9187488891 ') Date: April 19, 2005 Time: 1650 CDT From: Keith G. Sumn1ar NORTHSTAR KEITH G~ SUMMAR PETROLEUM GEOLOGIST 1909 South Harvard AvenUè Tulsa, Oklahoma 74112 918-748-8775 (Fax) 918·748-8891 kgsummar@aol,com FAX COVER SHEET Recipient Fax #: 907-276-7542 PAGE 01 ) ~~ C'~ " . 4,0-9 -l ~D Q¡( ~9 ¿ ~. ~ 0Q.<' ~~, Please deliver these 6 pages, including cover, to: Jim Regg Message: NFU 41-35 wellhead schetnatics If you do not receive all indicated pages contact Keith G. Summar at 918-748-8775 04/19/2005 15:43 9187488891 ,~1/Ø5/1996 07: 1~ 90n~V')88ø COOPER CAMERON CORPORATION CAMERON 600 E. 57TH PLACE Anchorage, AI..k" 9961 B NORTHSTAR CAMERON ) PAGE 02 PAGE 01 ft CAMERON Fax Machine 907-562-3880 Phone 907..562...2332 Cameron, WKM, McEvoy, Willis FAX TRANSMISSION Date: ,... -.r¡IJ/lI,/lj,. Page 1 of l't To: ~ 1rf).- ¡.I. fPy,~ ;'[(t Ib'l~¿ot.#f EII'~;!;¡ From: ~.~ ~,/~:,~."..,........._..,., Subj: ,.J,~~ FsÞ<" ¥I"~ Copy: (¡" ,..T.~,,,,, , ,. ".,nm___._""'"'' "........... . . "..-" -. (!",Wl'''' ~~... I.~~~ ~ ~dT;Í1"" TA r"áT Â~'MtI¡');' . . j>.r.t.-'&ArttJ. ~,.. d ìA.n r;-ty".t.rl.Ti.:~~ P.~JI~P,MW(.c.T: FÃlI1¡:Jt.ÙI~tP ~ ,«" .LA A--..."J/~-T;J.l, ~~". P¡M.,¡tl:.Á...¡; A·... .,A. "-i"AT C"l:&rt};_...Tk,ð.~ l~~ .b"AJt'4)~.4r....Als Ða2A". It" 11411UtM ~¿"~dp,j {Ø~~/Þ'ØJlIJ. r ~Û)/AJI~..t,,:l=_ \.'),- jI)o£. -oyl~ "'AJoIÆ4\~ A4td ddL n!',.- - M'À~'"7i)',f,.J.,,.¡JtßtJ<'i·'I~.(Q,d "',.~ 1!94$,a. ....... 71JJ¡-N. JA. '.. ........."',... .J, JÐ'nJ.~ ÞA4t.,~ I.-I' ('~H,.IW\ATi·~ u'L ;t)'/~J -rf'ðM U"'Ð~Af -z.. ~-c.U F.'(#It,) 04/19/2005 15:43 9187488891 01/05/1996 07:29 9075f)S80 NORTHSTAR CAMERON ) PAGE 03 PAGE: 62 ,r--\ ¡.1r6f~ /Jodi. For'k Jtl./l·3S I/,J~r ß.'flfJ fll61-!.ka. q-G ~O' , 10 ~ q" ~ I w.., ...J . 11> .' .....~ (~. .. S 1 .oj ......Jf. ...f ,.. r'M..~~,.,..lÞ"e . .'..-:.".. ... ,1.-""',' . ®: 5 .., ....~-) 3 r\~'~ ~ J -I .... ... ... :.~ ~ . - \ o "-7'·- 1 --- ~:=J .¡r~ ~ 04/19/2005 15:43 9187488891 01/05/1995 07: 29.. ,.". '" 9.~?~r)8~0 NORTHSTAR CAMERQN II ,,,,,/,,,..,... ., ) PAGE 04 PAGE: 03 Cameron Nortbstar North Fork # 41-35 'Equipment List 9..6-01 1. Shaffer starting head, 13 3/8~~ Srd bottom' {has been welded}~ 12" 3m toþ) Type K...D, PIN 3($0376 or 360J86, SIN 10277. 2. Rockwell Nordstròm plug valve, 2" line pipe, Fig... 3044, ASA - 1500~ EPS,.... 61313, WOO ~ 3600. 3. Cðmeron tubing spool~ type uDCB'~, 12" 3m bottom, 10" Sm top, Bore - 8 7/8"'~ PIN 20446...10..10..10, bottom flange has both R57 and R53 prep. 4. Rockwell NordstÏom p1ug,valv~, 2 1/16" FIE Sm. ,Fig. ..... 19045, plug and plug and body - STL. 5. CamerQµ gate valve, type ~~Fn, 2 1/16u 5m, PIN 32901-10..01, SIN 70746, Seat - STELL, BOdy - STL - 60 - 90. 6. Cameron tubing hèad ~dapter, 10'$ Sm studded bottom, 2 9/16'~ 5m dual five bolt studded tOp, PIN 20621-01) R-3 12" P-D Spec. 7., 8., 9. Cameron five bolt ga~e valves; 2 .'l~" x 2 9/16)) 5m, PIN 28385..01-1, SIN 70325, SIN 70948, SIN 70324. Fíg..... 20358':'6-1. 10. Cameron tree cap, ' PIN 19014, D, 2 ~!16", 3 1'2" P-D SpecÞ. 2 7/8" Srd in temal thread. 04/19/2005 15:43 01/05/1996 07:29 , ,-, 9187488891 9075j180 NORTHSTAR CAMERON ) PAGE 05 PAGE 134 Cameron Nortbstar North Fork # 41-35 9-6-01 pressures 13 3/8" Casing - Could not get the plug valve to operate 9 5/8" Casing - 600 psi Verified that the backpressure valve profile is Cameron type "H". Attempted to work the tie down pins without success, recommend trying an ìmpact wrench whett there is an air supply available. An of the Cameron valves operate fine; both of the Rockwell valves could not be operated. We were not able to break the bull plug out of the heater string side, this plug has a Y1" np1 plug welded into the top of it. Rigged up and pressure tested the tubing hanger body/neck seals and ring gasket to 5000 psi for 30 minutes, no leaks, bled the test pressure. Rigged up and pressure tested the 9 Sign casing slips, secondary seal and ring gasket to 1500 psi for 30 minutes, no leaks. Anempted tQ bleed the test pressure, it would not bleed o~ installed a gauge and recorded 60 psi on th~ void area. We may be able to inj eet plastic packing into the secondary seal to try and re-energize it after the casing pressure has been bled to 0 psi. The tubing spool may need to be rem.oved~ and a new secondary seal and slip seal installed if we oan not get a test after the plastic is injt!!cted. Will need to replace the Rockwell valves with new gate valves, instal1 companion flanges, tapped bull plugs, needle valves, and gauges. The tree will need to have flow tees and gate valves installed on it. 04/19/2005 15:43 9187488891 01/05/1996 07:29 gØ7S')380 NORTHSTAR CAMERON ') PAGE 05 PAGE 05 ~ I. t 10 -~ À\O"~ ::.rAö ~Gi1rL, Ft;¡J'¡¿ E 'tl-~'" ~~ ~ ~~~ Ute/) "It S~ AU. d<t.&1 "-t¿ G'Tc...JrJ..~ ,.-. ~-J'I ... .. Q. ~¡ ~ PatMal i¢ Q ,cl éA.P ....,. ~. ^~ '..ut PL()(ô @ .} ~¿¿ ~ t4' A~ e,,,,t p(lJ/4, ,) ~ AM ~ L.-,~.c.r fft...trr~ r VAl ,,4,. -ç .._. _ If l PttiM.Øtt4- "tel. Pta.J~ "AJ~ ® (, c-"""'Hr9-· ":.. ..... 'r, ':J -...""", ~"'\"",., À'" '-1101.· '-----... ~ " j.'/&. a'l, --V¡¡.aD ~ ......-. :... ~ 'r\(" T~" ¡.~ 611. ~ GATe. \11I.\01£ ---I ~ ~ ~." S" "--./l. . ~ ( .1 ..i , a -.."....... .. f"'>- ~ ~- :~~~__,-.~-J ~ ~ot~ ",¿ 0 I d. P tJ.'G. v A \ IJ~ ® '- ) ) MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg, '~e4 "3(2;5/10<; DATE: P. I. Supervisor t r March 7, 2005 FROM: Jeff Jones Petroleum Inspector SUBJECT: Well Inspection North Fork Unit 41-35 North Star Energy PTD- 165-021 March 7, 2005: I traveled to North Star Energy's North Fork Unit 41-35 well location to perform a routine inspection of the well. The well site had recently had some type of work performed as was evidenced by snow removal and marks left at the site by equipment. I inspected the site as much as was permitted by looking through the chain link fence, which was locked. I noted that the cellar was full of snowmelt, which made observation of the wellhead valves difficult. I also noted what appeared to be a heater string in the wellhead which had an approximately 12" long crack running vertically in the exposed piping, apparently caused by freezing. I investigated the possibility of recent well work being performed further and found that on February 20th and 21st 2005, Pollard Wire Line Co. and Cameron Well Head Services were on this location performing down hole pressure surveys on this well at the direction of North Star Energy (NSE). There were no NSE representatives on site during these operations. I checked with the AOGCC Anchorage office regarding notification of this activity and no record or notification of this activity was found. Summary: I performed a routine well location inspection at North Star Energy's North Fork Unit well #41-35 location, where unauthorized well work may have occurred. X Unclassified Classified SCANIiED APB 2 5 2005 ) ) MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg,1414\1o;' P. I. Supervisor DATE: March 7, 2005 FROM: Jeff Jones Petroleum Inspector SUBJECT: Well Inspection North Fork Unit 41-35 North Star Energy PTD- 165-021 March 7, 2005: I traveled to North Star Energy's North Fork Unit 41-35 well location to perform a routine inspection of the well. The well site had recently had some type of work performed as was evidenced by snow removal and marks left at the site by equipment. I inspected the site as much as was permitted by looking through the chain link fence, which was locked. I noted that the cellar was full of snowmelt, which made observation of the wellhead valves difficult. I also noted what appeared to be a heater string in the wellhead which had an approximately 12" long crack running vertically in the exposed piping, apparently caused by freezing. I investigated the possibility of recent well work being performed further and found that on February 20th and 21 st 2005, Pollard Wire Line Co. and Cameron Well Head Services were on this location performing down hole pressure surveys on this well at the direction of North Star Energy (NSE). There were no NSE representatives on site during these operations. I checked with the AOGCC Anchorage office regarding notification of this activity and no record or notification of this activity was found. Summary: I performed a routine well location inspection at North Star Energy's North Fork Unit well #41-35 location, where unauthorized well work may have occurred. X Unclassified Classified Attached: 2 photos from follow-up inspection of North Fork Unit 41-35 by Jeff Jones on 3/28/05 Ubr; 3/29/05) "T"')' 'Ì\.h\.iC::'~·~ fI. f)t) " 1.':' ~OT~ _vwjo\!\1:n~&7,~...:' .-it h l.' J t.. Vi ') ') North Fork Unit 41-35 Photos by AOGCC Inspector Jeff Jones March 28,2005 NFU 41-35 Heat String split North Fork Images Subject: North Fork Images Date: Wed, 05 Dec 2001 13:08:32 -0900 From: Winton Aubert <winton_aubert~admin. state.ak.us> Organization: AOGCC To: "Summar, Keith" <Kgsummar~aol.com> Mr. Summar, Sorry for the confusion. The attached should be the correct images of the site in question. Please contact me after review. Thank you, Winton Aubert I.............. : ....................... '"-"-" '- ' .................... ::' .................................................... 1 ..................... ~'me: NOrth'Fork 41:35 [~North Fork 41-35 location.bmp] Type: Paintbrush Picture (image/bmp)] lEncoding: base64 ............... II]~lH]ll~l~a ....................................................................................................................................................................................................................................................................................... ' ' . ! ground.bmp North Fork 41-35 well s~gn laying on ground bmp ~'-' - ~ Type: Paintbrush Picture (image/bmp) ! IEncoding: base64 ............................... - ........................................................................................................................................................................ ] ..................... ] Name: North FOrk well location 1.bmp ii'North Fork well location 1.bmp[ Type: Paintbrush Picture (image/bmp) Encoding: base64 I ................................................................................................. l ] ' ] Name: North Fork well.bmp [ ~'~North Fork well.bmp] Type: Paintbrush Picture (imageComp)] Encoding: base64 1 .................................................................................................. ! .............................................................................................................................................................................. 1 ofl 12/10/01 2:15 PM MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Camille Taylor, DATE: Commission Chair THRU: Tom Maunder, SUBJECT: P. I. Supervisor FROM: John H Spaulding, Petroleum Inspector 5~t3~~ 23, 2001 Location Inspection North Fork I was in the area witnessing a BOP test, and was requested by my supervisor to visit the North Fork well location. The last time I was on location - early Nov., there was some wire line equipment on the well performing a bottom hole pressure survey. Currently the equipment is no longer in place. The well guard has not been installed, this could pose a possible safety hazard as the well is located approximately 50 feet from a road. There are portions of an existing "PVC" or plastic well guard near the well. SUMMARY: I recommend that the well owner install some type of protective device around the well, with proper well nomenclature on a posted sign. This sign should be attached to the wellhead in a secure manner. Attachment: Pictures Non Confidential 11/06/2001 17:35 9187488891 NORTHSTAR North,tar Energy Group Inc. PHONE (918) 748-8775 (918) 748-8891 FAX COVER/MEMO PAGE 01 Date: November 6, 2001 From'. I~ Keith Summar ~ Samue! Nappi [~ J. Lawrence (Larry) Snead Recipient Fax #: 90%276-7542 Please deliver these 14 pages, including cover, to: . Alaska Oil & Gas Conservation Commission, Attn: Mr. Tom Maunder RECEIVED NOV 0 6 2001 Alaska Oil & Gas Cons. Commission Anchorage Message: Final report from MIT and flow test of North Fork 41-35 well NEG Fax Cover Page2 11/86/2881 17:35 9187488891 08:~5 FAX 406 NORTHSTAR OILFIELD CONSULTANTS,INC PAGE 82 ~oo2/ot~ UNIT #41-35 DALLY WORKOVER AND TEST REPORTS 9/19/01: RU with 2" steel hard line and swivels to blow dawn 2-718' x 2-7/8" x 9-5/8" annulus pressure through choke into test tank. SI pressure 120 psi. Blow down tank slowly to 0 psi, Ali gas, no liquid flow. Close In well for 30 minules and pressure built up to 10 psi, blew down immediately. Close tn annulus for 1 hour and pressure built to = 1 psi. Close in annulus and secure well. Leave test tank on well. SDFN. g/20/01 '. No work on well, CIW shipping well components to Kenal. 9121101 : Crews arrive location at 12 o'clock noon and start rigging up. Pollard boom truck used assist CIW in lifting valves from and to wellhead and Xmas tree. Check pressure on 2-718" x 2-7/8" x 9-518" annulus - 0 psi. ND Xmas tree and RU lubricator to pull BPV from heat string. Small amount of pressure, pull BPV OK. RU lubricator to pull BPV from production string. Small amount of pressure, pull BPV OK. Instruct Pollard welder to weld a XXH tee to short 2-7/8" nipple to be screwed into 'cOmpaniOn flange 0~i"he~t'stdng master valVe.' PreSsum'tes! sa~fl'6 rd' 5000"pSi in shop. 9122101 Visited with nelghbom (Ed and Karen). They are concerned about potential flooding of well location and roadway during spring run~off. : Place 2-7~8' 8 Rnd EUE nipple with lee with line pipe threads on heat string side. NU production side of Xmas tree with two 5000 psi, flow tee, 5000 psi swab valve, and 5000 psi wing valve, RU sliakline lubricator on swab valve, RU BJ to pressure test well. Pressure test top side of heat string master valve IO 1000 psi - held OK. Open master valve and pressure test 9,-5/8* tag, 2-7/8" Ibg, 2-718" x 9-518" packer, and lubing hanger assembly to 1000 psi (took 7-3/4 bbls of water to fill annulus). Production string pressured up to 1000psi. Check the tubing hanger- OK; conclude Ihat prong in CEV dummy previously removed. Held 4000 psi pressure OK for 15 minutes. Circulate 18 bbls of water down heater string at 3 BPM & 30 psi. Circulate OK. RI produ~Iion string with slick line and 2.26" gage ring to 8005' WLM, set down, probably on CA plug, RIH with KO tool and '1.50" lead Impression block. Imprint nol decipherable, but may be top of GLM latch w/o prong. RIH with ZOO" flchlng tool on KO tool, set down at 7928', cannot retrieve CEV. RIH with 1,90" lead Impression block and se! down at 7928', Good impression of latch, RIH with I-5/8" fishing tool on KO tool. Set down at 7928', no latch. RIH with 2.00" fishing tool on KO tool. Set latch at 7928' and use buml~er sub and oil jars for 45 minutes and shear safety pin in latch. Rehead tools, . RIH with 2,00" fishing tool on KO tool. Set latch at 7928' and use bumper sub and oil jars for 10 minutes, pulled free, POOH with CEV body. RIH with KO tool and 1-1/2 GL dummy valve wlo equalizing port. Set dummy valve in side pocket mandrel at 7928", RU BJ on wing valve to pressure test. Test swab valve, flow tee, top master valve, and wing valve to 3000 psi. Held OK for 15 minutes. Teal swab valve, flow tee, bottom master valve, and wing valve to 3000 psi. Held OK for 15 minutes. Test tbg, side pocket mandrel and dummy valve, CA plug, and tubing hanger to 3000 psi for 15 minutes, Held OK. SDFN. 11/86/2881 · 17:35 9187488891 ( NORTHSTAR PAGE 83 9/23/01: Start work m 11:00 AM. RIH and fish prong from CA at 7994' (same WLM as 8005' on previous day), Well on vacuum. RIH with 2-12.;' fishing tool end retrieve CA blanking plug body. with 1.90" gauge ring tO 8200' Did not RIH further due to oonoem about possible wireline junk in the hole. RIH with tandem pressure and temperature gauges and record the following for the top gauge (bottom gauge not recording accurately): Depth Temper~i'~re PreSsure ._(~_W. kM) , (°F) (~ia) 0 53.0 18,3 4000 88.4 1555.1 701,5 131.6 2828.6 7500 140.0 3033.7 7750 144,4 3139.6 SDFN 9124101' 8tarl work at 9:00 AM. Rig to swab with sliokline unit, ~me ....Ruld Level pull From "--I~c'over~, Remarks .............. (f._.~_ .t). (feet), (FOF) 9:47 645 750 0 ~.~.:~.o. ............... e4~ 8~o o ....... ._!.._0_;_08.. 645 . 750 0 Larger cups lO:l 1 845 1000 ..... 120 Pull .ecl.faster 10:16 .7.30. ............. ~ii~00 . ' 0 '-' 10:20 ..... 730 .......... 1000 ......... 0 10:24 715 1000 o .... · t0:45 720 .... 1000'" 200 Chg'd mandrel 10:57 825 1150 0 11 '.07 825 1 q 50 0 11;29 B25....... . ~.'-0~..0_~ ...... !30 ... Larger Cups .. ~.1 :~5 945 ..... !200 110 _!_1~44. 1030 1300 '6D' ................ 11:50 1065 1850 0 11:58 1060 1350 0 r----12:01 106([ 1400 0 12:29 1080 13,50 ..... 0 ' '~'h-g'~''cups ...... 12:33 I080 1400 170 _!.2_:..4_ 1_ .... 1_.19_o i6oo 110 12;52 1265 1600 0 12:59 1260 1700 I~D': ............. 13:0,9- t310 1750 10 ' ' 13:20 t.3.00 1700r 60 13:29 1330 ' ~I-~'50 0 11/0B/2001 ~1/04/2001 17:35 08:55 FAX 9187488891 NORTHSTAR 408 454(" "8 0ILFIELD CONSULTANT$,INC PAGE 04 ~ 004/014 Time FlUid Levei Pull From --I~e'c0very ..... Remarks ...... .... (_feet) (feet)_ _(FP__F).. 13,43 1330 1750 0 ~1_3_,'5§ .... 3_2_8_0_ . 1550 0 ....... AdJ_0do.m. et.~-_ 14:10 1270,. , .1650 160 14:20. 1370. 1650 ... '.'6.0,. ..... ' 14;36 ........... .1.3g.0 ........ 1710 60 , , ._ 14:44 14'10 1710 0 14:52 1355 1810 80 , ...... 1.5;0.!_ ............. !..355 ....... 1.850 20 15:18 1245 1650 110 (~l~nge cups 15:29 1225 1650 80 15:37 1185 1600 130 . 15:45 1120 1550 60 15:55 965 t540 60 16:02 795 1100 7'0 16:09 605 1000 110 16;24 465 1000 185 ........ 18:30 320...... soo ........ 24 .. ...... ~ 6j~6r'1~ 600 400 Walt started flowing solid stream of water at 4:40 PM, GT$ within 2 minutes. Flowed gas from well for 5 minutes through 2" ftowline into tank. Well flowing at high rate of gas and unloading large amounts of water. Close well In. Pressure in 10 minutes 1800 psi. Install bull plugs on all valves, Release Pollard Wlrellne. Clean up location. SDFN, 9/25101: Welting on test separafot and associated well test equipment, Cease daily report until test equipment arrives location, 10/17/0I; Advise AOGCC of resumption cf test. Some PTS equipment on location. 10118101: MI PT$, 8ecorp, and R&K equipment. 8tart rigging up. Visit Pollard Wlmllne and review test procedure. Visit BJ and discuss possible Mlmulatlon in event that flowback of well is not satisfactory. t0119/0i: Advise BLM of test. PT$, 8e(:orp, and Pollard Wlmllne finish rigging-up. S1 tbg pre,sum 2050 psi, R&K vacuum truck on location, start filling up tube side of heat exchanger. Use vac truck to clean water from wellhead (~ellar. Layout of test equipment shown on attached drawing, 11:30 - Unable to open Xmas tree valves completely. Wellhead frozen. Call out hot oiler and hot ei~' heater. 15:00 - Hot air heater arrives location, sta~'t heating vatvea end working same. Pour methanol down valves. Bo Brown of BLM on Iooatior~ to inspect operations, all OK, 16:00 - Hook up hot oiler to pump water down annulus and up 2-7/8" heat string. T~, -- 80"F, To.t -- 40CF. 18:30 - Run C-look on wimline. Sat down at 103', worked to 123', 18:50 - Run 2-1/4" gage dng (GR) to 155', work to 260'. t9:30 -Add weight fo GR and work GR from 260' ~o 570 ', 22:30 - Add weight to GR and work from 570' to 640', Continue clmulating hot water, T~, '- 85°F, T~u~ -' 50°F. 23'.00 tO midnight-Re-mn GR, tag at 610', Working GR. 11/0G/2881 ~1/0~/~001 1 ?: 35 gi 874888gl NORTHSTAR PAGE 05 10/20/01: 02:00 -Working GR to 640'. T~. = 130°F, T,~a = 85°F. PU bailer with chipping bottom, tag at 6'10' end work to 840'. POOH and recover hydrates. 02:40 - Re-run bailer and work from 640' to 670 ', POQH recover hydrates, 03:30 - Re-run bailer and work from 670' to 800' POOH recover hydrates. Ti. = 130oF, T~t = 85~F. 04;40 - Re-run bailer and work from 800' to 835', T~, = 150°F, Tout = 100°F. 06:00 - Run dump bailer with .3 quarts of methanol to 8;35', Change over lines on hot oiler to pump down heat string and up annulus. Discover that there is no water In the lines, pump was gas locked and not circulating hot water as indicated by pump pressure and temperature difference. 06;40 - RIH with 2-1/4" prong to 835', no progr~s. POOH, 07:30 ,- RIH with 2-114" prong to 835', no progress. POOH. Circulating hot water, 12:30 - RIH with prong and work to 1233'. Wait on temperature to dsc, T~, = 130°F, To~t --- 85"F, Chase hydrates to t,590' and break through, POOH. Tbg press [] 2200 pal, PU 2,3t GR and run to D nipple at 7982', PU tandem pressure gauged and RIH making stops every 1000"; Han~'g~uges in D nipple. POOH and laydewn lubrioetor, 17:15 - Start flowing well on 16/64" choke. %, = 132"F, To= = g2°F. Refer lo attached PTS report for hourly data. 24:00 - Flow testing'well, Flow rata = 1.596 MMCFD and flowing tubing head pressure = 2206 psig last 4 hours after rates and pressures stabilized. T~n = 138°F, T~u~ = 9§QF t0121101; 17:15 - Flow testing well on 16/64' choke. Flow rate = 1.600 MMCFD and flowing tubing head pressure = 2214 psig last 17 hours. Circulating heat string with hot oiler. Tat = 143°F, Twt = '102~F. Refer to attached PTS report for hourly data. 18;0(3 - Change choke size to 20164" and then to 24164" 24:00 - Flow testing well. Flow rate = 4,295 MMCFD and flowing tubing head pressure [] 1362 psi[si last 5-1/2 houm after rates and pressures stabilized, T~, = 138°F, T~u~ = 90~F 10122101: 00:00 to 24:00 - Flow testing well at 4,2 MMCFD and '1350 pslg on 24/64" choke. Circulating. heat string with hot oiler, 'T), = 138~F, TQ~t = 90~F, Refer to attached PT$ report for hourly data. 10123/01 00:00 to 16:40 - Flow testing well at 4,2 MMCFD and 1260 psig on 24/64" (~hoke. The hot oil truck used {o circulate the heat string lost a U-joint at 04;30, The tubing temperature decreased from 114°F to 74~F by 16:30. The tubing pressure decreased from 1340 pslg to 1260 psig by 16:30, Ran flowing pressure gradient from 7900 feet to surface from 10:40 to 14:35. Following data recorded: 11/0G/2001 17: 3§ 9187488891 1.1/04/2001 08:57 FAX 406 494f "8 NORTHSTAR OILFIELD CONSULTANT$,INC PAGE 06 ~006/014 Depth '¥e~'P~ra~re pressum (feat) (°F). (PAID) 7900 123.4 1599.9 7000 129.2 1565.8 BO00 126.9 1526,1 5000 t19.2 1486.0 4000 108,3 1445,9 ..... 3000. 95.4 1404.5. 2000 81.8 1364.1 15oo 7e. 1000 71.8 1320.2 .. 500 69.8 1298~8 0 73.9 1281,3 , .. i _ . Displaced the annulus with equivalent of 40 bbls of gas and then connected anhulus to the heat st~lng to equalize gas column between the annulus and the heat sa'lng, 'Presence of gas will freeze proteCt the casing and tubing. 16:38 to 24:00 - Well shutin for pressure buildup, PTa and Secorp released and started rigging down, R&K Industries start moving out PT$ equipment. Found the 2" flowline downstream of the choke manifold nearly plugged with hydrates. Flow path through the line was approximately %" in diameter. SITP inoreased from 1272 psig to 1339 pslg in 82 minutes. SITP increased to 23g0 pslg by midnlte,. 10/24/01: oo:oo to 24;00 - Shutin for pressure buildup. PTS and Secorp equipment moved off location by R&K Industries, Pressure inoreased from 2390 pslg Io 24.20 psig when surface readings with dead weight tester disoontinued at 07:00, 1012510'I' 00:00 to 24;00 - Shutin for pressure buildup, $1TP 2495 psig using 0-5000 psi gauge. Remove 500 bbl tank from location by R&K Industries. 10/26101- 00:00 to 24:00 - Shutin for pressure buildup, 10/27/0t: 00:00 to 24:00 - Sh.utin for pressure buildup. 101281: 00:00 to 24:00 -- Shutin for pressure buildup. 10129/01' 00:00 to 10,15 - Shutin for pressure buildup, 81TP = 2500 psig using 0-5000 psi gauge. lO:15 to 16:00 - POOH with pressure and temperature elements. Read data in field and report information to Butte office, WOO then SDFN, Refer to attached chad for bottom hole pressure and temperature data, 11/86/2881 11/04/200[ 17: 35 9187488891 NORTHSTAR 0~:58 FAX 406 494/ "8 OILFIELD CONSULTANT~, PAGE 87 10130101 08:00 to 20:00 - RIH wllh 0au§e ring and 8each for fill. 8tart losing weight at 8125', oontinue RIH to 8150'. POOH having hydrate problems and find ball of frozen drilling mud on gauge ring, Mud pulled from well from below 812§'. RIH with pressure and temperature recorders for stetlo pressure survey. Mal~e stops and re~;ord pressures as follows: Depth Pressure (feet) (pslg) '8100 3019.§4-- 8075 3009.32 8050 __ 802S ..... 2996,7~ 8000 2995146 7950 2992.62 7900 2989.7i ........... . ... 7000 2937.72. ..... _60~0 2878,70,,, 5000 28t8,42 ,, ...... 4000. 275~,90 3000 2693.49 ..... 2000 2628.34 , 1000 2560.92 ..9 ..... 2492.78 See, ute well as follows: Set blanking plug in D nipple at 7982 feet. Set back pressure valve in production tubing. Bleed pre. ute from annulus and heat string, Cameron Iron Works set baok pressure 'valve in heat string without bleeding pressure from welt, Close bvo master valves, swab valve, and wing valve on produoUon tubing. RemoVe pressure gauges from needle valves on tapped bull plugs on gate valves, Remove valve handles. Leave well in condition to take another pressure reoording In 30 to 60 days, Release Pollard Wlreline, SDFN. FINAL REPORT ~lnit~l~l~5 Surface Rec~de~ Fl~w ~te, Tub~9 Pre.urn, and Tubi.~ Tempemlure Oat~ ! 2~ 36 48 --1 ii- ! .. · o 72 84 96 3,00D E 2.(lO0 ~ 5OO 3,600 $~0o0 2,000 1,500 Un~l ~f41-35 Bottom Hole Re=ordeal Fl~ing & 5but~n Pressure and Temperature Data :' I t,O00 .............. 500 ~' -- Hot Ol~r F;lled 41 i ! ! ! 72 D6 t20 1~4 Elepse4 Time From St~ of I~rst I~=w P~riod, h=urs 24O 160 !:20 e .: Temp 192 0 11/06/200i 17:35 9187488891 NORTHSTAR ............ : .... : ...... ~- ~ '. ....... { ..... :. ..~ ...... . ........ ~ ..... : ..... . ......... : :. . ......... ......... .. . . .... . ............ .... ~. ..' .-:... .' · . .. ....... . ........ ~ ' . ..~ .. ,~ ..... . . '.... .......; · . ..... . ·... . . - ... :...: ...... :...~ ..... :...~ .... : .... ~ .............. ~...~...~>,~. ..... : ..... .:......~ ...~..~ .. ..... : ...~.. ~..::...~. ..... ....................... .]. ,: ..z ......... : ........... ; ..~ .........~.. .............. · ....... ~. ...... : ............... . .. ........... · . . ............. : ........ '. .... ~ ........... . .' . ' , ..... ...... : · . ........... . .....· .... : .......... ~ ....... .......... : ~ ~ : : . ........................... ; .............. ~.,. ............... ~ ~ ..... : ....................... :, ...... : ................ ~ ..... : ............................. ~ ............. : ..... ~ ....................L ............. ~ . ' " . - I ....... .. ..:.. .... .... ~ ..............: ....... ' ............ :~ ' "~ ..... : ...... .; .... ~ ........ : ................................. ~ ............ r' ','" . . . ~ . . . . ~ · . · ; : ...... ] ............... ) ..... ~ .... ~ ....... ~ ................. : ....... ~ ..... ; ....... : ..... ; .... ~ .... ].. , '....~ ..... .......... .. :.,.. .......... ..,, ........... ;,..~ ....... : ..... . .... : .......... . ............... ~.. : ..... , ........... . ..... ~ ..... ~ ............. : ,..~ ......... : .............. : ...... ] ....... ~. ...... [ ..... , PAGE 1 Fi ~ U.I. ~t," U.I,. ~4 ' 'roduction' 'estingServices -: nm~ ~ ~: hr." J": '-' ':: J'- ~' J:'~") J-' :- ' L-' "r---" :~[~. i~..~iUc ;,.-~. - i~- t~c~) ~:~ ~ P~: .- /e~ , ~ ~ ~ ~ a~ ~aamt~ l I [ ' " t.~ ;8~ ~~~ ~ 21~ I~ 1~ ~ 1~ !.~2 n~ ~;n ~J 173 ~ I.~ Z~ tg~ ~ J J 2i~ 1~2 160 ~ ~ ~ 1~4 ~1 ;~ '~ 1~ ~F ~ t~ ~_~ 3~ ~ ~ 2~ t12; I~ ~ ~ ~ 1~ n~ 9.10 ~ C ~10 O.~ 3JO~ Z~ ~ 2~ 113 ;SD ~ 114~ ~_~ ~1 9.10 ~ ; ~10 n~ ...... . . _ · ~ Z~ ~ ~ ili ;~ ~ 118~.~ ~ ~ 9.10 ~m ~ 9.i0 ~ ~2~ ~ ' ~95 1~; T~ '~ 115~0 ~ ~ ~.10 ~m ~ 9.10 ~_~ ~ 9.10 ~O ~ 8t~ ~10 !!4 14~ ~' '~!7~ 1~ ~ 0.~ '~ n~ ~' 9~' n~n 44 D~ 6~ ~ ~.~ ~tO 114 [49 27 41E2.~ t.~ O~ ~.40 ~' ~ 0 gAO 7~ lg~l~t O~ ~-~ ~15[ I f4 f4G 27 ~ ~-~ f.~ O~' 9A0 O.~ O gAO 7~ Q~ ~ ~15' !14 1~ 27 Sl12.~ _ !.. ~.~ 9~0~ ~ O gAO O.~ ~ 1;~ ~.~ ~ 114 1~ ~ la72,Q~ tJ~9 ~ 9.~ ~.~ O 9~ ~ ~:~ M.~ ~6, 115 1~ 27 ;14~ ?.~ ~ 9~ ~ O 9~ n~ ~ ~0 , ~ 2~ ~O0: ~ i14 1~ ~ 1~ 2.~ f~il ~7~ ~40 n=~ 0 ~ ~O0 0: e.4O i~ ~. .~:~ ~ ~l~J 112 1~ ~ {~ ~ T.63~ 0~ 9.~ ~.~ ' ' ~ ~ n~n 0 9_~ t~ ~ ~.~ ~0~ 11~ 14~ 27: t172~ 1.6tD 0~7 9~ n~ O g~ n~ 0 ~ ~ ~.~: ' ~ .... t12 149 ~ I~ ~ ~8~ ._~ " ;~ &~ ~ ~ ~14 1¢9 ~ t16Z~ ~;~1 ~n~ 9~, ~.~: O '9.( Q.~ 0 ),40 13,~ ~0 8~ofl ~1~ ~2 ~ 27',$t4 ~n~ ~.~ t,~ 9.40; 0_~ 0 9~ O.~ 6 9~ ~ ~O: 8~fl ~5 t~ 149 .. ~J lt4 2~ ;~ t,n~ 9~ o.~ G g.~ O.gO ~ O~ 14.5~ 'r~ 90-50 z~u 11S ~4,5 ~ lt4 2.~ 1,~ t~l~ ~C O.~ O ' 9.4Co.~ -' O ~.~ I~.QC ~ 9~ ~IE 115 T4 B 2G 108~_K 1.~ T,104 ~1C 0.~ O 9.4[ 0.~ t~ =~ g~ ~ .... If~ t~ 27L ~.oS~ 1.~9 L21T 9.~ 0.~: 0 9.~ 0.~ 0 ~.~ ~e.~ "~[-~ ~.5~ ~n ~S ~ ~1 ~] ~i ~.m7 ~ =~ ~ ~.~ o 9~ ~ ~6~ q;~J ~ J ~I~ ~ its t4O ~J t!4 2~l i~7 t.~3 9.~ 0.~ g 9~ a.~ OI '- -' --'~epnn~ts~ir pre !I/41ZgOt P.~e i ~,'u -Production'iesting ices .. -~ . ....... · ~_~: '" 1~ [_~.~ ~ 11[ 1~ 28 110 ~ ' ~ ~_~ . , ~t2 t~ ~ 26 ~ 2.~] - ~ I~' ~JOi ~ ~7 {lQ! 140 27 1~ ~ IT~ ~0:~ 'iT~!5~ ~ Ha t~ ~ ~ ~ ' 18~ tOi~ '~M2~' ~j 116 . Z~ ~ ltd 2.~ 3~8 I~l ~4C 0.~ q' ~ Q~ O 9.48; OJ 0 0 ~ I~-~;1~ ~-~m, ~ 11~ ~ ~ 110 ~ ~ l~ ~ ~0 g l~ ~ 0 9.4[ · OJ 0 ~ 27~ I1~ 1~ " tl2 ~ ~] 111 31~00 ' !~ 0~ [_~ 13~ t10 ~ ~ ill ~1~ ' O~ ;~.5~ ' 13~ 110 ~ 35! it5 ~.~ 4~ ~ 11~ __ ~ O' tl~ o.~ 0 11~ ~ e 0 " ~ ~-m 1~C : "1~0 ~10 ~ 3B 1~ ~J. 110~ --11fl ~. ~; 113 Z~ '~5 3.~6 t1.~ : 0~0 9 ~ ~O: 0 11~ 0 0 0 ~ ._ ~! !18,~ ' T~ t~O ~ , ~: 116 ~ ~ 3~ ~t~ ~ b t~ a.~ O 1~.~ Q Q 0 ~ 5~Jt12.~ 1~ 111 ~ JtE ~ ~ 3.~ 1i10 ~.~] ~ 11.~ ~ 0 1i~ 0 0 0 .... ~k~ ] 7:00 11~D t~ 1~' ~] ~ ~5 2.~0 ~ 4~9l ti~0 0.~ ._ O 11.~ O~! 0 11,~ O 0r . 0 [ ~l~ 'YT:~. ll~ a~ 112 ~5l ~ ill! 2-~ ~ ~:~i 1t~ g.~ 0J_ 11.~ O~ 0 1~ ~ 0 ' ' O ~nn' ~ ~5.~[ ~ ] t~: . " 1~2] ~1 ~ t~ ~.~ by'piS 11,'1129Q1': ' Pa.~2 .._ ~'roduetionTestingServiees '~ " ~ [~l~h [: J ~ I- I 1~ 2~ ~1 i12 49~ 18-~ 12~0 I ' 1~ 1t8 '~ ~ 114 ~ 4~! E~ 1~.~ ~ : O; 11.~ O~ O 11.~ . .U O , 0 .... t~ 111 ~] ~ t16 2~' ~ ~ao ~&~ ~ = ~ ~1~ 0.~ e; la.~ ~ 0', ls~ Ol .... O] -0 -~ ~flO 130~ a~ ~$2 ~ ~' 105 2.~n 4.~ ?.1~2J 11~ D~ O ~t~O o.~ ' e [t.~ ~ O. 0 r~m ~ ~ 13[~ -' l~q 11; z/~: ~E ltO~ 2~ 4.~K 7.4~ ~t-~l 6.~ O 1~.~ ~ G 11.~ e C ' ~_~ ' _~ q~ ' ' ~ t~] ~ ~ 111 ~ 4.t~ ~.T61 i1.~ ~ ~ 11~ 0.~ . . O tl~ O ~ O' ~-~' ' '~ la[~O :: 1~ ' ' ~t4~ ~51 J ~1 111 ~_~ -~ ~ X~D 1~ '~5 ~ 1~ 2~ 4~ 8_tOD 11~'- e.~ O tl~ ~ · 11~ o O e ~ ~DI 137.~ 13Iol ' ~S~ ~ ~ 110 -~.~ ~12 ~-,~m .,~ ~' 1~.~ ~' . ~ '~5 275 '.36 1~ z~O ~o 8~ 11~0 ~.~ 0 ~ ~ 0 11~ 0 0 0 .] - ~ ~ ~O~O '~.~Q ~ -- ?~ 2~ ' ~ 106 ' .. ' . ..j i~D - ~.~ . Sl.~ a~ a 1~.~ C CZ l~roduction Testing Services DEPT. OF ENVIRONMENTAl, CONSERVATION DIVISION OF ENVIRONMENTAL HEALTH SOLID WASTE PROGRAM 410 WILLOUGHBY AVE., SUITE 303 JUNEAU, ALASKA 99801 http://www.state.ak.us[dec/deh NY KNOWLES, GOVERNOR RECEIVED OCT ~ 0 ~00i Alaska Oil & Gas Cons. Commission Anchorage Telephone: (907) 465-5162 Fax: (907) 465-5362 October 26, 2001 Ms. Lisa Pekich Senior Environmental Coordinator Phillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Reference: Issuance of Permanent Closure Approval for Inactive Reserve Pits located at KRU Ugnu SWPT-1 on the North Slope and North Fork Unit 41-35 on the Kenai Peninsula Dear Ms. Pekich: The Alaska Department of Environmental Conservation (ADEC) has completed review and public notice for three inactive reserve pit closure applications and requests for permanent closure approval. The closure applications provided the required information describing the history of the reserve pit(s), the present condition of the reserve pits(s), results of any required water sampling and an assessment of the potential risks posed by the drilling waste to human health and the environment. At these locations, the reserve pits ~have been backfilled and there is no exposed drilling waste. ADEC ..coordinated review of the closure requests with the appropriate land owners/managers. Public notice requesting comments on the closure requests was publiShed September 20 and 21_, 2001 in the Anchorage Daily News and posted on the state web site September 21, 2001. No public comments objecting to closure approval were received in response to this public notice. ADEC has determined that the reserve pits at these sites meet the closure requirements of 18 AAC 60.440. Closure Approval under authority of 18 AAC 60.440 (j), ADEC grants permanent closure approval 'to Phillips Alaska Inc. for the inactive reserve pits at the following two' sites: · . . Well Name API Number MTRS Landowner North Fork Unit 41-35 50-231-10004-00 Sec. 35 T04 S, R 014 W, SM Private KRU Ugnu SWPT-I 50-029-20914-00 Sec 7, T 12N, RIOE,UM DNR 1 I Phillips Alaska, Inc. Ms. Lisa L. Pekich October 26, 2.001 Page 2 of 2 Terms and Conditions This final closure approval is subject to the following terms and conditions: 1) 'In accordance with 18 AAC 60.440(1), the Department will require additional investigation, assessment, monitoring or remediation if new information regarding conditions at the reserve pit facilities indicates that further actions are necessary to protect human health or the environment. 2) The approval .granted by this letter is for the inactive drilling waste reserve pit(s) only. Closure for the pad as a whole (if required) must be coordinated between the owner/operator and the appropriate land owner/manager. Any person who disagees with any portion of this decision may request an adjudicatory hearing in accordance with 18 AAC 15.200-310. The request should be mailed to the Commissioner of the Department of Environmental Conservation, 555 Cordova Ave. Anchorage, AK 99501. If a hearing is not requested within thirty (30) days of the date of this letter, the right of appeal is waived. If an adjudicatory hearing is requested and granted, this decision remains in full effect during the adjudicatory process. Sincerely, Heather T. Stockard Solid Waste Program Manager Heather Stockard@envircon.state.ak.us CC: Ed Dersham - PO Box 537, Anchor Point, AK 99556 William L Friar, BP Exploration Jim Haynes, ADNR, Anchorage Gary Schultz, ADNR, Fairbanks MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: THRU: FROM: / Camille Taylor, DATE: Chair _\.,.. Tom Maunder, ~i~.~~\ SUBJECT: P. I. Supervisor John H Spaulding, Petroleum Inspector October 27, 2001 Location Inspection North Fork unit .'.,~~!~.~! :~,:~. ~,, .,~.,.,..~.,...,., .. ,.._... ...... .. ~.,_...., , "' .... .i,:~" ,'~"~..~..- 0,9. ~ Oct. 27~ 2001: Recently the Operator / Owner conducted flow tests on the well. When I visited the well there was 2500psi on the tree cap gauge. I had some concerns as to how the well was left upon'completion of the flow tests. I contacted the Operators rep., John Evans, a consultant from Butte, MT. He informed me that the well had been shut in with a pressure bomb installed. These tools are used to gather information on the bottom hole pressure build up while the well is shut in. The bomb is being pulled today 10129101 to gather the data. Once the tools are out of the hole a blanking plug will be set in the ~D" nipple, pressure bled off above the plug as well as the annular area. Once all of this is accomplished a back pressure valve will be set in the wellhead profile and the well head valves will be secured. Non Confidential MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: THRU: FROM: Camille Taylor, DATE: Commission Chair Tom Maunder, ~ ~ ~X~ SUBJECT: P. I. Supervisor ~_c~;f John H Spaulding, Petroleum Inspector September 23, 2001 Location Inspection North Fork I was in the area witnessing a BOP test, and was requested by my supervisor to visit the North Fork well location. The last time I was on location - early Nov., there was some wire line equipment on the well performing a bottom hole pressure survey. Currently the equipment is no longer in place. The well guard has not been installed, this could pose a possible safety hazard as the well is located approximately 50 feet from a road. There are portions of an existing "PVC" or plastic well guard near the well. ~UMMARy: I recommend that the well owner install some type of protective device around the well, with proper well nomenclature on a posted sign. This sign should be attached to the wellhead in a secure manner. Attachment: picture,,,s Non Confidential ALASHA OIL AND GAS CONSERVATION CO~lP~iSSION September 18, 2001 TONY KNOWLES, GOVERNOR 333 W. 7'm AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-353g PHONE (907) 279-1433 FAX (907) 276- 7542 Mr. Christopher Pace Financial Responsibility Program 410 Willoughby Avenue, Suite 303 Juneau, Alaska 99801-1795 Re: North Fork Unit #41-35 Well Completion Status and Expected Production Dear Mr. Pace: Gas-Pro Alaska LLC ("Gas-Pro") is currently planning to conduct flow tests on the North Fork #41-35 well. The Alaska Oil and Gas Conservation Commission ("AOGCC") currently classifies this well as a gas production well that is shut in. North Fork ~41-35 is a vertical well with a Sidetrack that was drilled, tested, completed and shut in during 1965. The mudlog from the well records methane from 2,000 feet measured depth ("MD") to the total depth at 12, 812 feet MD. The only indication of any gas other than methane is a single notation "C3" that occurs on the mudlog at 10,200 feet MD. The shallowest oil indicator in the well also occurred at 10,200 feet in the form of a slow, faintly fluorescent sample cut. Cement plugs seal this potential oil,bearing zone in both the original well bore and the sidetrack. The program proposed by Gas-Pm consists only of testing the Tyonek Formation through existing perforations between 8,005 to 8,045 feet MD. These perforations are located 2,150 feet above the shallowest indication of oil, and are separated from it by a bridge plug. Historical well test information found in AOGCC's files indicates that this portion of the Tyonek produced only dry gas and water. It is my opinion that North Fork ~41-35 will produce only dry gas and associated water during Gas-Pro's proposed test. If you have any questions, please call me at (907) 793-1224. Petroleum Geologist ,~9/18/2001 11:§7 NORTHSTAR Northstar Energy Group Inc. PHOI~ (918) 748-8775 FAX (918) 748-8891 FAX COVER/MEMO PAGE 01 Date: J~ Keith Summar E] Samuel Nappl E] J. Lawrence (Larry) Snead Recipient Fax #: Please deliver the following ~ pages, including cover, to: Message: No~',lLal:axOoveO. 91B74BBB91 09/18/~001 11:57 Gas-Pro'A['. ska LLC 1909 So. Harvard Axe.= Ttflsa, Oklahoma 74112 Phone (918) 748-$77~ 9c Fax (918) 748-8891 it,ll.::: ::7--L_J! iii i I NORTHSTAR o_.fr , -'--.,, PAGE 82 September 17, 2001 Mr. Steve Davies, Petroleum Geologist Stste of Alaska Oil & Gas Conservation Commission 333 W. 7~ Sic. 100 Anchorage, AK 99501 Dear Steve, Attached please find a completed Form 10-403, Application For Sundry Approval, for the proposed flow test of the North Fork Unit No.41-35 well..I have also included a schematic of the well's casing and tubing and detailed descriptions of the procedure from both our consulting engineer, Mr. John Evans, and Halliburton Energy Services. We apologize for not applying for this permit sooner. While we had every intention of notifying AOGCC prior to any testing so that your agency could send witnesses, we mistakenly believed that, sihce the North Fork Unii is a' Federal Unit, we only required approval from the Bureau of Laud Management. HES will perform the flow test. The differences between the two plans are that we will not flow the well for 7 days or at thc rates called for in the I-lES plan. Our intent is to flow the well for a total of 3 days at a maximum rate of 4.0 MMCFOPD to minimize waste of gas, impact on the environment and inconvenience to the people living in the __ to veBt the gas aad..ex~_ ........ the volume of gas vented vicinity of the test. We inland ........................... _e~_ _.that ............ will not exceed 12.0 MMCFG. Note on the wcllbore schematic, cement plugs at IO,00F, 10,207', 10,765' and 10,913'. It also appears that the redrilled section, drilled from the window in the casing (10,165- 207') to a redrill TD of 10,859', was plugged from 10,854' to 10,654'. Thus, the Hemlock Conglomerate has at least three cement plugs ~md. two bridge plugs between it and the Tyonek gas sand we are going to flow test. It is our opinion that there is no possibility of communication between the Tyonek and the Hemlock. Also, as we discussed by phone, regarding Form 10-403's Section 4b., LocatiOn of Well. ($tat~ Base Plane Coordinates), I do not have an answer for'that question. I have, however, spotted the well by Governmental Section, Township and Range. As we discussed on the phone, time is critically important to us as cold weather is approaching and we have had some difficulty coordinating all the necessary sub- contractors. A prompt response will be greatly appreciated. Please let me know if you have any questions or require additional information. Sincerely, _. Keith G. Summar, Vice President Attachments RECEIVED SEP I 8 2_001 ,, , ALASKA 333 ANCHORAGE, OIL & GAS CONSERVATION COMMISSION W. 7TH AVE, SUITE 100 AK 99501-3539 TO: FACSIMILE TRANSMITTAL SHEET DATE: FAX NUMBER: TOTAL NO. OF PAGES INCLUDING COVER: PHONE NUMBER: SENDER'S REFERENCE NUMBER: YOUR REFERENCE NUMBER: [] UR. GENT [] FOR REVIEW [] PLEASE COMMENT [] PLEASE REPLY [] PLEASE RECYCLE NOTES/COMNIENTS: PHONE NO. (907) 279-1433 FAX NO. (907) 276-7542 ALASKA OIL AND GAS CONSERVA~I~ION COP~ISSION Mr. Keith G.Summer GasPro Alaska, LLC 1909 S. Harvard Ave. Tulsa, OK 74112 TONY KNOWLES, GOVERNOR 333 W. 7TM AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 North Fork Unit 41-35 GasPro Alaska, LLC Permit No: 165-021 Sundry Approval No: 301-274 Sur Loc: 655' FNL, 659' FEL, See. 35, T4S, R14W, SM Dear Mr. Summer: Enclosed is the approved sundry application to re-enter and test the above referenced well. The permit approval does not exempt you from obtaining additional permits required by law from other governmental agencies, and does not authorize conducting testing operations until all other required permitting determinations are made. Waste fluids generated from this testing operation must be disposed of in an approved manner. We note that according to our records, you do not operate or have not communicated to the Commission that you have access to another operator's Class II disposal well CTU blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25.286. BOPE and tests for wireline operations must be tested in accordance with 20 AAC 25.287. Sufficient notice (approximately 24 hours) of the' CTU BOPE tests, must be given so that a representative of the Commission may witness the tests. Notice may be given by contacting the Commission petroleum field inspector on the N6rth Slope pager at 659-3607. There is an inspector that resides on the Kenai who will then contact you. Please note that it is likely that our inspector will visit and inspect your operation prior to possible CTU activities. We request that your representative provide a contact phone number to the commission. Sincerely, Cammy Ol~chsli TaylorO Chair BY ORDER OF THE COMMISSION DATED this?~'~ day of September 2001 jjc/Enclosures CC: Department ofFish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. 't' SEP-17-OI liON 12:28 PH STATE OF' ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVAL P, 01/01 20 AAC 25.280 AlerCaling , ..RepairWell D p~jP~r~raionsl-! PeCtate ~ Var~n~ ~ Top ~ · ~: ........ ~~ , . . ....................... Total depth~ meamumd /~/~ ~t Piup (~Bumd) ~e~ve deptn~ meaau~ ~~./ ......... ~t JUnK (m~u~) ~ ~ ~~ ~ ~et · Ca~ Le~ ab ~~ MD ~~ d~: m.~ d~: ~-~~ ' P~ a~ ~SV ~ a~ ~~ d~th), . ~ ,. ,. ..... 13, A~~' ~Uon S~ ~P~ ~ ~ ~ms Pmgr~ ~e ~ ~ ...... _ .... : ...m, :.7 ' ' : '~.~ ........ 1& V~ ~ Dm: 117. Wea ~ ~r ~ ~ ..... ~' ~ . ~ ~,~ ..... '. m.,_ ,, - ...... ~ p~ ~-t~ ~_~~~ . _. ~,~ ~~~L _ _. Commi~ign U~ Only , i iiii . · BY' ORDER OP THI~ COMMISSION DUPLICATE SEP 1 7 2001 Alaska 0il & Gas Cons. Cornmissiori A'nchorage 09/19/200i 14: 59 9187488891 NORTHSTAR .. Directions to North lZork 41-35 well PAGE 02 From Kenai: South on Sterling Highway to Anchor Point. Go east on North Fork Road in Anchor Point. Follow road approximately 8 miles to Holly Lane. Once you pass the turnoffto Nikolaevsk you are approximately one-half mile from Holly Lane. Turn right onto Holly Lane. Wellhead will be on the left, approximately 500 feet down the road. From Homer: The North Fork Road forms a broad U on the east side of the Sterling Highway intersecting the highway twice. Going north on the Sterling Highway from Homer to Anchor Point it is best to skip the southern intersection of North Fork Road with the highway and continue on to Anchor Point and then mm east on the northern intersection of North Fork Road with the highway. The wellsite is a.pl'>roximately 8 miles / / RECEIVED SEP 1 2001 AlaSka Oil & Gas Corls. L;oi~lln.lssiu~ ~nchorao~ ,/ ? 89/17/2801 1G:27 9187488891 NORTHSTAR _ ,~. F'~'~" /¢'~' ' , 4 , i ......... I SEP-12-2001 13:27 NORTHSTAR PAGE P.01 04 Oilfield Consultants, Inc. 3910 Harrison Avenue' Butte, ~ ~9701 Office: 406-494-2504 Fax: 406-494-2578 email: g~vans~in-tch.com September 12. 2001 To; Northstar Energy Group, Inc. '190g South Harvard Avenue Tulsa, OK Fax No, 918-748-8891 Attention: Keith Summar , ,, Re: Unit #41 Test Procedure Dear Keith: Please find attached a copy of the overall test procedure for the Unit #41-~35 Tyonek perforations. Individual components of the plan include procedures to repair the wellhead/Xmas tree, conduct the MIT, prepare the wellborn for the test, and perform the well test. ' After you and Sam have re.,ad and concur with the procedure, I would like to forward it to key service company in =Anchorage and Kenai'for their comments, suggestions, and details, Regards, John Evans 09/17/200i i6:27 91B?4BB891 SEP-12-21~i 13:27 ,~' NORTHSTAR PAGE .P.02 05 UNIT #41-35 TEST PROCEDURE The following are procedures for 1. Repairing the wellhead/Xmas tree equipment 2. Conducting a mechanical integrity test of the a, Wellhead/Xmas tree a~emblage, b. 9-5/8" casing, o. 2-7/8" production tubing, d, 2-7/8" x 9-5/8' packer, e. Cameo side pocket mandrel and OEV, and f. Cameo D nipple ancl blanking plug. 3. Preparing the wellbore for the pressure transient test. 4, PerfOrming a flow test'and pressure buildup (i.e:, pressure transient ) test. W,,ellhead/Xmae Tree Repair 1. . Move in two 400-bbl test tank and spot on the down-wind side of the location, Load 400 bbl of water in one of the tenka. Install a second valve on the Cameron tubing head by bolting it to the existing Cameron gate valve. Connect the ~--7/8" x 9-5/8' annulus to the test tank through the two Cameron valves, . . Spot a pump truck on location, Connect lines between the tank, flow line to the annulus, and the pump truck so that the well can be killed in the event the annulus does not blow down and begins to flow gas to the tank. Blow down the 600-psi annulus pressure to the test tank. Open the se0ond (outside) valve on the tubing head. Be cautioned: there may be diesel fuel in the annulus. Avoid any spills. No open flame or lighted smoking materials on location. a. If the well will not blow down, either (1) the CEV dummy has been removed, there is a leak in the production tubin~l string, or the pa~ker i~ leaking, or (2) them is a hole in the c, ae~ng wliich is hydraulically connected to a gas charged sand. 1) Pull the BPV from the heater string side. 2) Kill the well by pumping water into the annulus and up the heater string, Several stages of pumping may be neoesealy, 09/17/2001 16:27 91B74BBBgl SEP-l~-~001 1J: 28 ~,,, I' NORTHSTAR P. EI] b, If the annulus will blow down and remain dead, fill the annulus with water, As per Cameron's recommendation, install new, rebuilt, or re~ondltioned equipment on wellhead as follows: 1 ) Remove the old valve on the 9-5/8" casing head and replaoe it w'~h a 3000 psi bali valve. 2) Remove the new Cameron gate valve from the existing Cameron gate valve. Redress the existing and the new valve. 3) Remove the 2-1/16" plug valve on the tubing and replace it with the new Cameron gate valve. Install a tapped bull plug and needle valve on the valve. 4) Adds new lower master valve and a flow tee to the production string side. Add a new 2" 5000 psi gate valve in the wing side of the flow tee, bN,pte= All valve~ and any ~tin, gs that are t,o be re-used must e rebuilt and shop tested prior to replacing on the "' Wellhead Or Xrna~ tree; ........... . Pressure pulse the 9-5/8" x 13-3/8" annulus in an attem~ to cause the leak in the ~aslng sli .pa/.aec, ondanJ, slipeJ_rtng gasket area to seal, If unsuccessful, inject plastic packing into Ihs area to seal leak. Mee,haniosl Integrity Test 1. Fill the 9-~/8" x 13-3/E' annulus with water, Install a pressure gauge on the bleeder valve and monitor pressures during subsequent parts of MIT, 2. Fill the 2-7/8" x 2-?/8" x 9-5/8" annulus with water. Install a pressure gauge on the bleeder valve and monitor pressures during subsequent parts of MIT. 3, If not already removedt pull the back pressure valve from the heater string side. 3. Rig up slickline lubricator on the production string.side.. a. Pressure test lubricator, Xmas tree, and back pressure valve (BPV) to 3000 psi. .. b, Pull BPV~. Slowly bleed off any pressure existing under the BPV. If them/s no pressure on the production ~ring after the BPV has beer~ removed, there may be a blanking plug In the Camco D nipple at 7983'; otherwise, there is no blanking plug but the well is dead, If there/s pressure on theproduction string that cannot be bio.down after the BPV has been removed, there is no blanking plug and the well is capable of flowing, 5EF~-12-200! l~: 28 i' NORTHSTAR PAGE P.04 07 Note: when the Camco =D" plug is removed, the well is alive and capable of flowing. Full well control and s&fsty measures must be 4. Rig up slick-line lubricator on the production string side. a. RIH with a sinker bar with a gauge ring to.the D nipple. If there is no blanking plug, plaoe a blanking plug in the D nipple, Note: RIH slowly past Otis "S" nipples at 117' and 2201' because~there may be blanking plugs in these nipples, b. Pressure test the production string side to 3000 psi to determine the integrity_ of the tubing hanger, tubing, CEV and side pocket mandrel at 7905', and the blanking plug at 7983'. Monitor the pressure on the tubing/oasing annulus. Do not allow the ~ressure on the annulus to exceed 1000 psi. c. If the pressure on the tubing/casing annulus increases, the most likely, e~.umes of leakage is the CEV in the sidepo~ket mandrel or a leak in the tubing string. 1) Shut down the pumps. 2) 'RIH wilh a kickover tool, retrieve the CEV dummy valve, and repla=e the same. d, Repeat Step 4b. Notes: If a pressure test cannot be obtained at Step 4b, there is probably a leak in the tubing Str~ng.. · If the production string side Is suGcessfully tested and them is still pressure on the annulus, a leak in the casing or a~ leaky packer exists; . . ,, In either of the above cases, the well ~an not be safely tested. Tha well must be killed and downhole problems repaired. §, Pressure test the 2-7/8' x 2-7/8" x 9-5/8' annulus, tubing hanger, and packer to 1000 psi. 6. Hook up the heat string side to the boiler. Pressure test to 1000 psi. Circulate water to ensure that the heat string is free of obstacles and that hot water can be freely circulated down the heat string during the test to avoid freezing problems, Ensure that the boiler Is operating satisfactorily. PAGE M.~b OB Wellbore preparation 1. Rig up ~oiled tubing (CT) equipment Including BOP's, tubing injector, and N,, pressure test to 3000 psi. 2. Rig up Halliburton test separator, choke manifold, flare sleek, chemical inje~ion pump, et~. Pressure test to 3000,psi. 3. Conn?t,t.h.e production string x CT annulus to flow through the choke mainfold into the test separator. 4. RIH with CT open ended. Cimulate water from the well while RIH, Clean out the well ~o PBTD of 8325'. Note that there is 11' of wireline junk in. the well at 8235, Vent prodtmed HO and N2 gases through the flare staol( and capture all liquids in the test tank. While cleaning out, attempt to minimize flow of gas from the well ao that pressure drop between the reservoir and the wellbore is minimized,' 5, Rig up electric line lubricator with full pad(off and grease control equipment. PreSsure test to 3000 psi. 6. RIH with a chemical cutter for 2-7/8", N-80 tubi.ng, Cut off th..e~p,a.o, ker .. extension 2' below the Cameo D nipple. RIH slowlY to 8060' t0 ven~y that the cut-off tubing loints have fallen and oleared 1he bottom of the perforations. Remov.a! of the paoker extension wilt ensure ~ .n.o flow re.~lrictions are pm-sent m the wellbore and will permit meaningml temperature measurements opposite o! the perforated interval. Flow Test And Pre. insure Buildup Test i 1. Following the olean out and laying down of the chemical cutting equipment, shut well in for 24bourn to allow pressures in the reservoir and te~l~erature~ in the wellbore to equalize. 2. Rig .up sliokline lubricator on the produ~'lion string side. Pressure test lubncatot and rnsster valve to 3000 psi. ' tic ressure and te er~ture survey before any fluids are 3, Run st~ p mi3 ,, , wn from the well Run survey from GL to 7000' in 1000 stops. withdra 'L ..... ~nd 7980' Obtain lower stops at 7500, 775D, · 4. First flow period, Produce the well for 24 hours at .2. MMCFD. Do not change choke setting after the initial flow rate has been established, Circulate hot water down Ihs heat string to prevent freezing, Measure gas, water, and an~ hydrocarbon liquids through the separator meters.. Store all pmdue, ed I~quids in the test tank and vent all produced gas to the atmosphere, 09/17/2001 16:27 918748BBgi SEP-12-2~B1 i3:29 ~ NORTHSTAR Land pressure and temperature recorders at 7980', inside, of the tubing. Record all flowing pressures. Run a flowing pressure an~l temperature gr=dient at end of first flow period using the same stops as in Step 3. Second flow period. Produoe the well for 48 hours at ~.4 MMCFD. Do not change choke setting after the second flow rate has been established. Land pressure and temperature reoorders at 7980', inside of the tubing.. Record e. II flowing pressures and flow rates. Run a flowing pressure aha temperatum_gmSient at end of the second flow period using the same stops as in Step 3. After running the flowing gradient, obtain temperature and pressure recordinCla at 1-foot intervals from 8050' to bottom of tub_lng string..This data will-be used to determine points of fluid entry Into the wellbore Trom the perforations. 6. Pressure buildup period. Shut-in the well for 120 hours. Land pressure and temperature recorders'at 7980'. Record all shutin pressures; Run shut-in pressure and temperature gradient at end of the pressure buildup using the ~ame stops as in Step 3, 7, During teat, obtain samples of gas, any liquids (water, condensate, mud filtrate, ale.), and any solids (scale, iron compounds, formation fines, etc.) that were recovered from the well. ' , ' . .. 09/17/2001 lB: 27 9107488091 NORTHSTAR PAGE ~I:.I-'-I;~-~UU1 13: ;~ I ' ' P,l~t 10 Key Northstar, Agency, and ~e~vic, e Company Representatives: 1. Sam Nappi- Northstar 2. Kelth Summer- Northstar 3. John Evans- Northstar Consultant 4. ? - Alaska OII and Gas Conservation Commission ,5. ?- aLU 6, Halliburton Services- Sieve Myem, 907-275-E819 Test separator, flare sta~, and rela~d equipment , . 7. R & K Indu~-trie~ - Robert Peterkin, 907-283-3777 Boiler, test tank, roustabouts 8, Ken Kubiak - Cemeron Iron Works, 907-562-23~2 Wellhead and Xmas tree equipment and testing g. APRS - Bill Applewhlte~ 907:283-9576 Eleotric rme and d~eml~l cutter 10, Pollard Wirellne - Fred Pollard, 907-283-7006 Sllekllne services, pressure and temperature elements 11. ? - water hauler 12. ? - water and liquid hydrocarbon disposal 13. ? -safety specialists and monitoring' TOTAL P.O? 09/17/2001 ,,~ 16:27 9187488891 NORTHSTAR HALLIBURTON PAGE 11 Work, cope 1, Obtain necessary state approvals and permits to accomplish workscope as outlined below. 2. Perform :Iobsite Visitation as per HMS process for Surface Testing. Inspect location . and wellhead for propers:connections needed for testing and discuss equipmem placement and rig up procedures with company representative. 3. Due to the long time frame since a~y work has been performed on this well, lIES strongly recommends integrity testing be performed on all components of the well. · Pedorm mechanical integrity tests on outer aimulus, inner annulus, and tubing strings. · Prep well for surface test. 1, Rig up and pressure test surface testing equipment as outlined in procedures 2, Rig up combustible gas detection/alarm system and calibrate for 10% LEL sensitivity., 3, Displace tubing with nitrogen as outlined in procedures. 4. Run Spartek electronic memory recorders as outlined in procedures. 5. Perform reservoir limits test as outlined in procedures, "~ 6, Shut in well for build-up as outlined in procedures, Leave surface testing equipment in place until data or~ electwuic memory recorders has b.een retrieved and verified as acceptable, 7. Retrieve Spartek dectronic memory recorders at end of build-up as outlined in procedures. Download data on location and verify all data is acceptable. 8. Rig down surface test equipment and secure well as per company representative, '9. All data will be collected by Steve Myers and sent to Kim Thornton in Houston for analysis. 09/17/2881 16: 27 9187488891 NORTHSTAR PAGE 12 HALLIBURTON . Mechanical Integrity Test Preparation Remove swab valve on long string side and install production block tee with valve. Compatibility should be verified during $obsite Visitation. It is HES' understanding that Cameron Oil Tools in Anchorage has the correct'block tee and valves that belong on this wellhead. 2. Install pressure gauges on wellhead and casing, 3, Rig up test pump and' chart recorder, Pressure test short string side ~o 3000# sgaiust BPV and hold for 15 minutes. Bleed off pressure and record on chart. 4, Pressure test long string side to 3000# against BPV and hold for 15 minutes. Bleed off pressure and record on chart. 5, Open 9s/s'' casing valve and record pressure. Open 13~&'' casing valve and record pressure, , . Rig up Cameron lubricator and pressure test to 3000#. Pull BPV on long string side, Record pressures on tubing and casing. Rig up test pump to casing valve, Rig up lines to tank to allow returns from long string side. Pressure up casing to $00~ to ensure dummy/valve is installed in the OL.M ~ 7892'. Record pressures on wellhead and easing, Hold pressure for 5 minutes, 8. If dununy Valve is holding, prooeed tO mechanical integrity test. If dummy valve is leaking, rig up wireline to pull dummy valve. Make drift run to top of plug ~ 7982'. Pull dummy valve, redress accordingly, run dummy valve back in hole, Repeat step 7 until pressure test is successful. 1, Secure well for mechanical integrity test. 09/i7/200i i6:27 9187488891 NORTHSTAR PAGE HALLIBURTON Mechanical Integrity Test Rig up test pump and cl~art recorder to long string side. Pressure test tubing to 3000// and record pressure test. * lftubing does not test and 9~/,'' annulus does not pressure up, rig up wireline to pull plug in the Camco "D" nipple ~ 7982'. Make sure drift run has been made before pulling plug. , . Pull plug in "D" nipple, redress, run.in hole and set plug. , Repeat pressure test as outlined above. · Iftubir~g does not test and 9~/,'' annulus pressures up, rig up wireline to pull dummy valve. Redress dummy valve and run valve in hole. · Repeat pressure test on long string side. 1, Rig up wirelinc and pull plug in "D" nipple ~ 7982'. , Rig up test pump and chart recorder to 27&'' annulus, Pressure test to 1500//and hold for 15 minutes, Record pressure test on chart, Note pressures on the 133/~'' annulus. and 27/:'' short string side, 3. Redress plug, rig up wireline and mn plug back in hole an set in "D" nipple $ 7982'. 4. Secure well for surface test equipment rig up, 09/1712001 16:27 9187488891 NORTHSTAR PAGE 14 HALLIBURTON EMR / Surfnce Test Procedure 1, Spot equipment, flare stacks, and fluid tank as per $obsite Visitation layout. 2, Rig up surface test equipment as directed by Project Leader. 3, After surface test equipment is rigged up, pressure test as follows: · Pressure test asainst lower master valve and surface safely valve to 3000~ · Pressure test against .surface safety valve to heater inlet valves to 3000# · Pressure test heater coils / separator to ! 000ti. Hi pressure shut down should be function tested to I000# hi / 50~ low during pressure test. · Pressure test gas outlet lines to flare stacks with 50# air pressure. · After pressure test, blow lines to fluid tank with air. Rig up wireline and pressure test lubricator to 3000#. RIH and pull dummy valve in GLM ~ 7892'. ' 2, Displace tubing with nitrogen to surface. 3. Install dummy valve in GLM ~ 7892'. 4. Retrieve plug in "D" nipple ® 7982', 5. Make drift run to TD ~ 8325', . Leave well in static condition for 2 hours before running EMR,'s, Program EMR's with the following program: Period Duration Sample Pate 1 minute 5 seconds 4 hours I minute 24 hours 5 seconds :24 hours 10 seconds 24 hours 30 seconds 90 hours 1 minute 24 hours 5 seconds 24 hours 10 seconds 24 hours 30 seconds End of Test 1 minute 09/17/2001 16:27 cJ187488891 ,.. NORTHSTAR PAGE 15 HALLIBURTON , 1 10, EMR / Surface Test Procedure - Continued 1LIH with EMR's making gradient stops. Stops should be made at the following depths at lO-minute intervals. Record depth/time at each stop on Surface Testing loblog Stop Depth Duration Surface 10 minutes 2000' 10 minutes 4000' 10 minutes 6000' 10 minutes 6300' 10 minutes 6600' 10 minutes 6900' 10 minutes 7200' 10 minutes 7500' 10 minutes 7800' 10 minutes "D' ~ipple ' End'ofTest Set EMR's in "D" nipple. POH with wireline. Rig down wireline. Leave well in static condition for 2 hours before opening well to warm heater bath on test unit, EMR's must be in fast sample rates before opening well. Open well to unit to warm heater bath, Once heater is warm, open well to unit, and clean up well at a maxhnum rate of 7 MMScf/d. Do not exceed 12 hours on clean-up rate, Record pressures/rates at 30-minute intervals during clean-up period. Project Leader will determine end of clean-up period, Once well has been cleaned up, well should be produced at a rate sufficient to keep well unloading fluid, ideally around 4 MMgcf/d, Well must be kept in critical flow throughout the stabilized rate for 168 hours and the choke must not be moved. Pressure ranges should be kept at 750# backpre~sure with a minimum wellhead pressure of 1500#. Pressures/rates should be recorded at l-hour intervals once well has stabilized. Project Leader will make pressure/rate determination, 11. Project Leader will determine end of stabilized flow at 165 hours. EMR's should be in fast samples 2 hours' before ending test, 12, Shut in well at wing val~re as directed'by Project Leader. Shut wing valve as quickly as possible. Monitor wellhead for leaks and record wellhead pressures at l-minute intervals for the first hour of the shut-in period. Record on STE report. 0g/1712001 .~, 16:27 9187488891 (. NORTHSTAR PAGE 16 HALLIBURTON EMR / Surface Test Procedure - Continued 13. 14, Secure well for build-up. Secure test equipment on location until EMR's have been pulled and data is acceptable. Project Leader will determine end of build-up. At end of build-up, rig up wireline and pressure test lubricator to 3000~. .15, Open well. and record pressures, RIH with wireline to equalize plug. POH with wireline. 16, RIB wi~h wireline to pull EMR's, Oradient stops wil! need to be made at the following depths/duratiOn: ' 1, 'Stop D~ Duratiou 7800' I 0 minutes 7500' I 0 minutes ~ 7200' I0 minutes 6900' 10 minutes 6600' 10 minutes 6300' 10 minutes 6000' 10 minutes 4000' 10 minutes 2000' 10 minutes Surface 10 minutes 17. Shut in well and retrieve EMR's. Download EMPCs on location and verify data is acceptable. 18. Once data is acceptable, rig down Surface Test equipment and send to R & K Industrial for cleaning. 09/17/2001 16:27 9i 8748889i NORTHSTAR PAGE 17 HALLIBURTON Post-Test Workscope 1. Rig up wireline to tubing long string. Pressure test lubricator to 3000~. RIH with plug and set plug in Camco "D" nipple ~ 7982', ?OH with wireline and verify tubing plug is holding. 2, Rig down wireline. Rig up test pump and freeze protect well as directed by company representative. 3. Rig up Cameron on short side and pressure test lubricator'to 3000#. 4, Set BPV in tubing short side. Bleed pressure off tree and monitor for BP¥ leaks, Once BPV in short side is in place and holding, proceed to step 4. 5, Rig up Cameron On long side and pressure test lubricator to 3000#. 6, Set BPV in robing long side. Bleed pressure off tree and monitor for BPV leaks. Once BPV in long. side is in place and holding, proceed to step 7, Freeze protect wellhead/valves as directed by company representative, 8. Secure well as directed by company representative. 0 R T H $(.,'A R ~ n e r'g y G r'o ~p I~ c . ~ 1909 So. Harvard Ave. Tulsa, Oklahoma 74112 Phone (918) 748-8775 Fax (918) 748..889t April 24, 2001 Mr. John D. (Jack) Hartz, P.E. Senior Reservoir Engineer State of Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue Ste. 100 .. Anchorage, AK 99501 ECEIVED APR SO 2001 il.~ka 0il & ~a~ COns. ~nehorage C°~nr~ission Dear Mr. Hartz, Enclosed please find the information you requested regarding the DST of the Hemlock in the SOCAL No.41-35 North Fork Unit well. Our engineer, Spencer Offord, has attached his analysis of the data including calculations and supporting text. Please feel free to contact either Spencer or myself if you have any questions or require additional data. Sincerely, Keith G. Summar Vice President of Exploration Northstar Energy Group, Inc. Enclosures Northfork 41-35 DST Analysis The DST from the Hemlock zone in the subject well was analyzed using techniques as described in the classic text Petroleum Engineering Drilling and Well Completions% by Carl Gatlin (Copy Write 1960, by Prentice-Hall, Inc.). Various sections of the text will be referred to here for clarity. This DST was run on the interval from 10,808 - 10,859'. 1. Volume of fluid recovered during the test, and the average daily fluid rate from the well. (from 13.1 and 13.2 page 260 of referenced text) V = bL where V = volume recovery of a particular liquid (in this ease, oil and salt water), b = capacity of pipe in bbl/ft., and L- length of pipe filled, ft. With b = d^2/1000, where d = inside diameter of the pipe (4 ½" drillpipe assumed from bottom to top of fluid for maximum volume). Therefore, in this test, V =(3.83^2)/1000 * (160' + 215')= 5.50 bbls. There was 160' of salt water produced, and 215' ofoil produced. From this volume, an approximation of the average fluid rate can be computed from q = 1440*V/t where q is in bbl/day, t = test time in minutes, and V = the volume of oil recovered. Therefore, in the 41-35 test q = 1440'5.50/65 = 121.85 bbls. The 65 minutes was used as the total flow for this test, as it was assumed all of the fluid recovery entered the drill pipe during the first flow period. Had the second period been included, the total q would have been much smaller. The purpose of this assumption was to maximize the possible flow capability of the well from Hemlock zone. The estimated productivity index of the well is computed by J = q / (ICIP - FFP), where q =daily flow rate, ICIP is the Initial Closed-in Pressure, and FFP is the Final Flowing pressure. For the purposes of this analysis, the ICIP was assumed to be the maximum reservoir pressure recorded during the test, or 4163 psi. The FFP was assumed to be the lowest flowing pressure recorded, or 1211 psi. These assumptions maximize the flow capability of the well. Therefore, J = 121.85/(4163-1211) = .041277 bbl/day/psi. Now, assuming a minimum flowing gradient of 0.2 psi/ft, in a blow-out situation, the well's capability for flowing to the surface may be calculated from Q(max) = J * Maximum drawdown = .041277' (4163-2000) = 89.28 Barrels/day. This analysis represents the corresponding flow rate based on DST productivity: It should be noted that this analysis included the volume of salt water produced during the test. Additionally, the 2000 psi flowing gradient in the "blow- 'out" case was calculated from recommended minimum flowing gradient suggested by the AOGCC. It should also be noticed that even if a flowing gradient approaching 0 psi/ft is used, the maximum flow would only be = .041277 * (4163) = 171.8 BOPD. Please refer to pages 260 - 263 of the referenced text (attached to this page) for a complete discussion of the methods used i.n this analysis. The DST is also included in the pages. · · · 'i'- ! 0 0 0 Petroleun~ Engineering DRILLING AND WELL COMPLETIONS CARL GATLIN l)cpart.u'nt of Petroleum Engineerin~j, The l'niversity of 7'exa.~ PRENTICE-HALL, INC. Englewood Cliffs, N.J. 26O DRILL STEM TESTING [Chap. 13 RECOVERY-15' Drilling Mud No Gas, Oil or Water INSIDE RECORDER RECOVERY-15' Drilling Mud No Gas. Oil or Water INSIDE RECORDER OUTSIDE RECORDER OUTSIDE RECORDER (A) (B) PLUGGED ANCHOR PLUGGED TOOL Fig. 13.11. Illustration of doubh, pressure chart analysis. Courtesy Johnson Testers. 13.51 Estimation of Formation Productivity Quantitative :m:tlysis of drill stem test data with regard to formation prociuctivity is not highly accurate. This is a natural consequence of the relatively short flow test period, which does not permit, attainment of steady state conditions. In many cases, however, the reservoir pressure, formation permeability, productivity index, and exteut of formation damage may be cal- culated with reasonable accuracy from drill stem test data. The following sequence illustrates a general analysis procedure. A. A qualitative inspection of the pressure ehar~ should be made to insure that the sequence of event~ is understood and that no irregularities or tool failures ~:curred. The pressures listed below should be taken from the chart and recorded. They are comput~ by measuring the extension (deflection) above the base line and obtaining the corresponding pressure from a calibration curve for the recorder us~. Drill stem test pressures were considered rather inaccurate at one ti~ne; however, current instruments are reportedly accurate to 1% and can deter changes of ~ psi. Various chart magnification techniques are used to obtain more accurate chart deflections. (1) Initial hydrostatic pressure (IHP), exerted by mud column (2) Initial closed4n pressure (ICIP) (3) In~fial ~ow~n~ pressure (IFP), ~he lowest pressure recorded ~ust after the ~ool is opened ~4) Final flowing pressure (FFP), ~he pressure just before the tool is closed (5) F~nal closed4n pressure (FCIP) (6) F~nal hydrostatic pre~ure (FHP) These p&uts are shown ~n F~gure 13.12. The mud colu~ presures IHP and FHP should be compar~ with those calculated from the mucl density. This serves as a rough cheek on the pressure recorder. B. The quantity of fluid recovered during the test. should be computed. In eases where flowing pro- duction is obtained, the producing rate may be measured at the surf aec by metering through a test. separator and/or tank. If only gas is reem'ered, its volume may be measured with an orifice well tester or pitot tube. In most eases, however, the amount of recovered liquid is measured in terms of feet of fillup in the drill pipe. This procedure often leads t o rather ambiguous descriptions when the recovered liquids are mixtures, such as slightly oil-cut mud, oil-cut mud, heavily oil-cut mud, gas-cut nmd, oily gas-cut mud, etc. Unless such descriptions are accompanied by a percentage estimate or unless the company in- volved has some standard code defining these terms, it is virtually i~npossil)le to know just how much of each fluid is involved. A l)ortal)h' hand crank centrifuge may })e used 1,o check the liquid samples as the drill pipe is withdrawn, allowing percentage compositions to be reported. In highly successful tests the quantity of these mixtures nlay })C negli- gible with respect to clean oil recovery. The volume of liquid recovered in the pipe is (13.1) V = bL where I' = volunm recovery of a partic, uhtr li{luid, b = capacity of pipe, L = length of pipe filled, ft A common rule of thumb for b is: d~ (13.2) b = 1000 where d = inside diameter of pipe, in. This is often a satisfactory (3% error) approxima- tion of b = (~d~/4)12 in'a/ft = 0.00097 d 9702 in.*/bbl The average oil flow rote over the test time interval is then: 1440Vo q°= t where qo = bbl/day t = test time, rain 1'o = oil volume recovered, bbl C. Estimates of formation permeability, reservoir pressure, and extent of formation danmge may now be made. The effective permeability to the flowing fluid is obtained from the pressure build-up curve. Recall equation (12.20) P, _ P~ = O.163qouoBo log to + At k~ Sec. 13.5] ANALYSIS OF TEST DATA 261 where O.163qo~oBo/koh--m, the slope of the linear portion of the buildup curve Equation 112.20) may be expressed in fundamental units as , qo'Bo~o t + At (12.20a) p/ - p ~., = ~ In where p,', p,,' =atm qo' = tank oil flow rate, cc/sec h' = cm If the shut-in period following the flow period is sufficiently long that after-production effects are eliminated, the pressure build-up curve may be plotted. Since the volume below the packer and tester valve is quite small, the time required to eliminate the after-production effect is, in general, not excessive. It is commonly recommended that thc shut-in period should equal thc flow period. Thc initial closed-in pressure may nornmlly be t~ken as an accurate value of p,; this value may serve to guide the extrapolation beyond the final shut-in pressure, allowing a more accurate slope to be obtainS. In order to estimate formation damage, it is again necessary to compare the tmaltered flow capacity from pressure build-up analysis with some measure of the average capacity including that of thc altered zone. Again, the productivity index based on the average flow rate during the test may t)e used. This, however, requires that certain assumptions be made concerning the effective draim~gc radius during the flow test. Ih, call that the oil PI was defined in Chapter 12 as 7.07~,A (12.9) .i0 = q,,B,, _ p, - p,,, ~o ln(rJr~) or in fundamental tmits as 2~LA' q,,' B,, _ (12.9a) J" = p/ - p,,,' ~,, ln(rdr,O The term kh.."~ is commonly called the trans~nissit)il- ity factor. Solving Eq. (12.9a) for this, l:or drill stem test. purposes, it is often assumed that ln(rd'r,,) ~ 2r: hence Eq. 113.3) beconms: 113.4) k ~,, /~ P"' - P'"' This amounts to assun~ing that rd'r~, ~ 500. As we have noted }wrote, radial flow computations are not particularly sensitive to r,./r,,,, since the term appears tls It logarithm, l:rom E(I. (12.20a) it is seen that k U,, /~t' -l~(p,,' - p,,.') At or \ ~0/By 4~r \m/ Note: Subscripts J and BU designate values ob- tained from productivity index and build-up tests, respectively. However, m may be expressed as Ap, Ap~ m = In 10 = 2.:--~ where Ap, = pressure drop per common (base 10) logarithm cycle from the buildup curve If we now equate qo' in EtlS. (13.4)and (13.5), i.e., the average producing rate for the flow test interval, then our standard definition of productivity ratio becomes, conveniently, (.12.24) PR = k~ = or (t3.6) PR '"' 5.5 Equation (13.1i) is the same :ts th:tt presented by Dohm et al.,a except that the inverse of tim PR was used and denoted ~s a dttmagc factor: I p, -- P,,, (13.7) DF = ~ = 0.183 Ap, We will use Eq. (13.6), as it. is consistent with Chapter 12. The validity of this ntther empirical approach has l)een verified by electric :malyzer s[ttdies Itlld tiehl experience. It is no[ Its precise t[s data based on imstco~npletional flow tests which :;re carried out mtder more stabilized conditions. l,'urthemum', thc PR value obtained from drill stem tes[ {It;Ltl cltllllO[ be expected to correspontl with htter results, owing [o l)ossible pernwability al[er:t- tions during thc completion process. IIowever, ¢ltlall- ti~ative ut ilization of pressure chart dar tt has proved to be a useful [ool. l~]xample 13.1 ilhtstrates the ealcuhttions involved. Examplc 13.1 The pressure chart for a DWI' is ~ix-m~ in Figure 13.1:2. Other :tvaihthh~ ~lat:t :tre listed Interval h,st. ed = 9990- I 0,0 ! 1) ft, Mud density = 9.8 Ib,"gal Recovery = 200 ft nmd, 7500 ft ch'an 40°.\PI ~fil. no wat, r No water })lankct run Drill pipe = 4.'.,-in., 16.6 ll)/ft tiM. = 3.$26 in.) I. The Se(ltlellct' of OV{qlt.'4 iS ch'ar ['1'Olll. the cJl:trt. Note th:tt the pressure aplmrentlY stabilize{l ~htrinK the initi:tl closed- in period, hr'lit't* the static reservoir lm'ssurc is l)rol)al)ly very closely :tpln'oxinnttcd by .1500 psig. thc I('IP. 262 ( 1 6 2 Fig. 13.12. Sketch of DST chart for Ex,~mph; 13.1. (1) Iltl' = 5120. psig (4) FI:I (2) ICIP = 45(X1 psig (5) FCII' = -1325 psig (3) IFP = 250 psig (6) Fill' = 5140 psig will be checked by the build-up curve extrapolation. 2. The initial and final hydrostatic pressures, 5120 ami 5140 psig, may be (.onq)ared with the value cah'ul:~ted from the mud density: 9.8 p, = ~ × .433 × 10,000 = 5100 psig This is excellent agreement. 3. The oil recovery during the 80-rain flow h,st was: (3.83)~ Vo-- l(X)0 X 7500 = ll0 The corn,spon(ling aw~rage daily oil producing rate is: 14.t0 X l l0 = 1980 bhl/day q° = 80 4. Next, the pre.~,;ure buihl-up section is divided into eon- w.fient At incre,nenLa an(l thc l)re~ures at succcssiw'~ intervals an~ tabulated.~ These .re shown as p Figure 13.12. Note that the pro(hating time t was ~0 ,nih. Pressure, arm At, rain (t + ~t/At) p~ = 3460 10 9 p, = 3900 20 5 p, = 'l 190 30 3.67 p~ = 43~ 40 p, = 4375 p, = 44~ ~ 2.~] p~ = 4410 70 2.14 The build-up curve is plotted as Figure 13.13. NoW that only the last two points fall on thc extrapolation to p, = ICIP = 4'500 psig. This illustratz:s the advantage of obtaining an ICIP for extrapolation purposes. (a) The productivity ratio may be calculaWd from Eq. (13.6). Ap~ = 4500 - 4200 = 300 psi per cycle = m io~ -- 4500 p~ = FFP = 2700 psig and . ./3oo \ (b) The estimated productivity iudex is: 1980 Jo = 45OO - 2700 = 1.1 bbl tank oil/day/psi at a PR = 0.92" or, DRILL STEM TESTING 4000 3000 2000 1000 0 1 2 3 4 5 6 8 10 t +~Xt Fig. 13.13. l'ressurc ht,ihh,l~ cvrw, for Examph, 13.1. 1.1 .lo =-- = 1.2atal'R = l .92 NoW that the formation volume factor B,, is omitted. Actually, the oil recoven,d in the drill pil)~' is m,ith,,r tank oil nor reservoir oil, but something in betwevn. If PI'T m' other data are availabh, so that B, may })evst. i,mted, thy calculations may be rcfin('d. Th(' seriousness of this omission is, however, minor as far as DST estimates are coBeerned. (c) Calculation of unalten,d reservoir pcrmea})ility rvquin's a knowledge, of fluid viscosity. Since it is unusual to have such data at tile time of a DST, Black has presented thc correlation of Figure 13.14, which nmy he used for oil viscosity estimates. Using ~o = 0.4 cp for 40%XPI oil ko= ~'163q~" = (.163)(1980)(0.4) = 0.022 d or _o2 md mA (300) (20) (d) An estimate of thc producing rate and possibility of flow- ing production completion may bc made. For oil to flow naturally, the bottom hole producing pressure must bc high enough to support thc flowing column to the surface, while compensating for the frictional losses enroute. T/w estimation of thc gradient in a vertical flow string is complicated by thc following principal factors: (1) As the fluid moves upward, pressure is s~,adily decrease(l, allowing gas to evolve continuously from solution. (2) Any gas in thc flow string expands as thc pressure is re- duced, hence thc average density of thc oil-gas (and possibly waWr) mixture decreases as depth dccreas('s. (3) Thc effective viscosity of this mixture also changes with gas evolution and expansion, nmking friction loss calcula- tions difficult. Sec. 13.51 ANALYSIS OF TEST DATA 263 ri 45 g ._~ o 25 2o 15 0 1 2 3 4 5 E 7 Viscosity of saturated reservoir oil af Pa 8 tr, centipoise Fig. 13.1,1.. Correl:ttion of API gravity with reservoir oil visco.4ty. After l~l;u:k,2 courtesy AIME. A reason,flAy accurate method of solving such problems is av:til:tlfie;s howew,r, some of the data required arc not generally :w:filabh; at the time of testing. Austml, although generally pessimistic apl~roach, is to assume a flow string gradient equal to the static stock t:mk oil gradient. This is equivalent to assuming that the lightening effect of free and/or ~iissolx'vd gas emnpensates for frictional losses in the tubin~ and surface piping. Therefore, for .t0~..XP[ oil, thc necessary hotton~ hole producing pn,ssun, for flowing production p,~ = 0.358 x 10,000 = 3580 psig The corresponding flow rate based on the DST productivity index is: qo = Jo(p~ - p~) = (1.1)(4500 - 3580) -- 1000 bbl./day Certainly this well could be expected to flow naturally. 13.52 Formation Water Analysis Chemical analysis of formation water samples are valuable for numerous purposes. Among these are electric log interpretation and subsequent determina- tions of the source of produced water. However, there is always considerable question as to whether drill stem test samples are representative of actual formation water. Consider .'t test which recovers only salt water. When the test tool is opened, mud, mud filtrate, diluted formation water, and perhaps finally formation water will enter the pipe, if the tool is left open long enough. A .-.'ingle sample could not be considered representative of the unaltered formation water. However, if continu- ous sampling is performed and the results are plotted as shown in Figure 13.15(A), the constant salinity section may be taken as reasonably representative of undiluted formation water. If, however, the results are as shown in 13.15(B), it is probable that a representative sample was not obtained. 13.6 Wire Line Formation Testing A wire lin(,, form:~tion test.er is :tv:tilal)h', which has found consideral)h., :tppli(:ation in areas whcr(., (;onvcntional open hol(: test, lng is tm(lcsiral)lc.~ Proper applic:tti()n of this devi(:(: h.'ts, in many eases, siml)lifie, d l)r(;('oniph.'tion testing all(J made it feasil)le to (;vahlate possibly pr() W~ter Water cushion 12 cush~ Z5 i i Mud fi~rote ~ so~ water ~ 10 10 0 0 _ 0 20,000 40,000 60,000 80,000 0 20,000 40,000 60,000 I~),ooo Chloride content, ppm Chloride content, ppm (A) Example of us~l ~rlotion of salini~/ (B) Example of unsuff~:ient yield to recover with depth in reco~red water column representative water Fig. ! 3.15..M~,~hod of plotting water an.'dysis data to determine if s:~ml)h' was r(,presvnt:~- tive. After BI:tek,'-' ('otlrto.? AIM]';. ~ STATE OF ALASKA ~' ,SKA OIL AND GAS CONSERVATION COM~ :ION APPUCATION FOR SUNDRY APPROVALS 1. Type 01 Request: Abandon __ Suspend __ Alter casing __ Repair well Change approved program __ 2. Name pi Operator Gas-Pro Alaska llc 3. Address P.O.Box 3050 Soldotna,AK 99669 4. Location of well at sudace 659~ FEL, 655' FNL, Sec.35, At top of productive interval 8005' At effective depth 8325' At total depth 12,812' 12. Present well condition summary Total depth: measured Effective depth: Oper~on shutdown __ Re-enter suspended well x_..~ Plugging __ Time extension __ Stimulate Pull lubing __ Variance __ Perforate __ Other-~_..._., Casing Structural Conductor Sudace Intermediate Production Liner Perforation depth: T4S, R14W, SM 5. Type of Well: Development Exploratory Stratigraphic Service See attached detail feet Plugs (~easured) feet feet feet true vertical 12,18 2 ' measured true vertical 8325' Length 246 ' 781b. Junk (measured) Size Cemented Measured depth 20" 625 Sks. - 2000' 61&68 lb 13 3/8 8451' 431b 9 5/8 2655' 261b. 7" measured 8005' to 8045' true vertical Tubing (size, grade, and measured depth) 2 7/8" 2000 '1550 Sks Packers and SSSV (type and measured depth) 900Sks Top @ 8330' N-80 Set @8046' tail Brown 2 7/8 X-9 5/8 HS-16-1Pkr. Detailed operations program .Z... 15. Status of well classification as: Oil_... Gas ~ 13. Attachments Description summary of proposal 14. Estimated date for commencing operation September'10, 1999 6. Datum elevation (DF or KB) 780' 7. Unit or Property name NorthFork Unit 8. Well number 41-35 Date approved 16. II proposal was verbally approved Name of approver Service 9. Permit number 6.5"-o ~...I 10. APl number 50- feet 11. Field/Pool Sec.35,T4S, R14W, SM True vertical depth 246' 2000' 8145' shoe @ 10,985' · Set 0 7944~ BOP sketch __ Suspended 17. I hereby,¢.~)~ Nat the, Joregoing issue and correct to the best of my knowledge. ?:/"~ ' .,. . ./..-" // S,gned ~ ~ ,.~ 'Title General Manag - f/c.,,,--'- / FOR CO'MISSION USE ONLY Conditions of approval: Notify Commission so representative may witness Plug integrity ~ BO,,~st"'"'- ~ Locadon clearance ~, ,,,,. ~ ,~ ,,., Oog~echanical Integrity Test __ Subseq. ue~nt form required 10...'?'/-d order of the Commission Commissioner Date Sept. 1. 1999 I Approval No..~ ye_./-~',.~ Date (~ .. c~ ..~C) 10-403 Rev 06/15/88 43- SUBMIT IN TRIPLICATE 02:~4 PM GAS--PRO ALASKA LLC ., ( GAS-PRO ALASKA, LLC PHONE- (907) 262-4291 FAX: (907) 262-7389 PACSlMILE TRANSMITTAL SHEET · . ~111 ~ · ' i!' -- _ .~..- .... ..~ ....... ~ ....... . ......_.._ .... To: From: Blair Wondzell Phi!!ip laFleur Company: DATE: FAX NUMBER= ~,~- c~ ~- ~._%"-~ZTOTA-L--'"'~O. OF PAGES INCLUDING PHONE NUMBER: SENDER'S REFERENCE NUMBER: YOUR RE FE RE~E'"N--UMBER: · 7'T: I I I . [JEt. I I I III IIIII1.1 . [ ...... I I [] URGENT 'II'FOR RENEW L~LEASE COMMENT i:3 PLEASE REPLY C! PLEASE RECYCLE .. NOTES/COMMENTS, RECEIVED SEP C,a 1999 Alaska Oil & Gas Cons; Comml,~ler~ Anchorage :1,70 CORRAL STREET, P O BOX 3050 SOLDOTNA, AK 99669 S[~P--0,-~--99 0:2 :56 PM PIx. 907,262.4291 GAS--PRO ALASKA LLC GAS-PRO Alaska, LLC 170 Corral Ave Soldotna AK 99669 Fax 907.262.7389 September 2, 1999 NoFth Fork Unit Gas W ell #41-35 MIT & Re-Test Workscope . , 6. 7, 8. 9. 10. lt. 12. 13. 14. 15. 16. 17, 19, 21. Obtain necessary approvals and permits to accomplish workscope as outlined below. Survey location and perform necessary site prep work, Prop well for mechanical integrity test by testing wellhead, and installing production tee below swab valve. Perfonu mechanical integrity test on outer annulu~ inner annulus and tubinl~ strinss, Prep well for well test, Ri8 up and pressure test well test equipment.* Rig up and test combustible t~s sensins/alarm system.** Displace tvbinff to nitrogen. Run electronic memory g, auses and set in D nipple. Perform flow test,; Shut in well for b~ild-up Re-open well and perform 4 pt test. Retrleve.electrOnic. memory 8suites, Secure well: Analyz~ well test data, Perform reservoir limits test desifn if necessary,.,.. Prep well for reservoir limits test, Perform reservoir limits test. ' Retrieve electronic memory sauges. Secure well, Rig down all equipment. Analyze reservoir limits test data, Pa~ 1 of 5 S~P--O~--~ 02 ::~7 P~I GI::IS--PRO I:II_i::ISK~ LLC ~07:26:27559 (,:.' *Note: Dual Rare system will be used to control direction of gas. Gas ~ilI be vented as per permiRing requirements **Note: 6 combustible gas % LEL sensors will be placed in strategic locations and monitored 9.4 hours per day during flowing conditions by qualified personnel. Two visual/audible alarm systems will be placed as well as wind socks to monitor wind direction. Prep well for Mechanical Integrity Test 1. Remov~ swab valve on long string side and install minimum 3000 psi production tee with valve. Flow tec should have 2 1/16" 5Ii flange downstream ofvalve. 2. Install 0-$000 psi pressure gauges on wellhead and casing. 3. Rig up test pump and chart recorder and pressure test short string side to 3000 psi against BPV and hold for 15 minutes. Bled off pressure. Note test on chart recorder. 4, Pressure long string side to 3000 psi against BPV and hold for 15 minutes. Bled off pressure. Note test on chart recorder. 5. ~ 9 5/8" casing valve and note pressure. Open 13 3/8" casing valve and note pressure. 6. Rig up lubricator and presgtre test lubricator to 3000 psi. Pull BPV on long string side. Note wellhead pressure and casing pressure, .7. Rig up pump skid to casing valve. Rig up to take returns from long string side. Pressure casing to 500 psi to ensure dummy valve is insttdled in GLM (~ 7592'. Note wellhead pressure and hold for 5 minutes. g. If dummy valve is holding proofed to mechanical integrity test. ,~ Ii'dummy valve is leaking rig up wireline lubricator and go in hole to pull dummy valve. Reinstall redressed dummy valve. Note: drii~ run should be made prior to retrieving dummy valve. Repea'~ step 7. 9, Secure well, Perform Mechanical Integrity Test Rig up pump skid to long string side. Pressure test tubing to 3000 psi. Note test on chart · If tubing does not test and 9 $/$" annulus do~s not pressure up, rig up wireline lubricator and go in hole to pull CA tubing plug set in "D" nipple (~ Pag~2 Note: if not previously done, drift run should be made prior ~o retrieving tubing plug, Redress plug and re-run. Perform drift run to TD during redressing of tubing plug. Repeat tubing pressure test, · If tubing does not test and 9 5/$" annulus pressures up, $o in hole and retrieve dummy valve installed in GKM ~ 7S92'. Note: if not previously done, drift run should be made prior to pulling dummy valve. Redress and re-run. Repeat tubing pressure test. 1. Ri8 up wi.reline lubricator and pressure test go 3000 psi. Go in hole to retrieve CA tubing plug set in "D" nipple at 7082'. Note: if not.previously done, drift mn should be made prior to pulling CA tubing plug, 2. Rig up pump skid to 2 7/8" x 9 $/8" annulus. Pressure test to 1:500 psi and hold for 30 minutes. Note pressure test on chart r~order. Note pressure on 13 3/8" annulus. Note pressure on. short string side. 3. Run and set CA tubing plug in "D" nipple ~ 7082'. 4. Secure well. Rig up Well Testing Equipment Spot well test equipment per layout diagrmn. Construct berm sufficient to contain 110% of 400 Bbl tank volume. Pig up well test equipment. Pressure test equipment as follows: · Pressure test tree against lower master valve, surface lines to choke manifold and choke manifold to 3000 psi. · Pressure test flow lines to the front of the heater to 2000 psi. · Pressure test heater coils and separator to 1000 psi. · Pressure test liquid lines downstream of separator to tanks to 500 psi, Pressure test 8as linc to stack to 50 psi (can be done with al0 Blow all lines to tanks with air, Rig up and pressure test wireline lubricator to 3000 psi. (}IH and pull dummy valve in C~LM (~ 7892', Displace tubing with 500 SCF nitrogen taking returns from annulus. Reinstall dummy valve in GLM {~7892'. Retrieve CA tubing plug. If not previously done, make drift run to TI) (~ 8325'. Page 3 of 5 SEP--0~--99 02:40 PI'I GAS--PRO ALASKA LLC 90?262?389 ( ',, P.06 9. Run in hole with tandem electronic memory recorders programmed as follows: . 10. 11. 12. 13. 14. 16. 18. 19. 20. 21, 22. 23. 24. 25, Period Duration Sample Rate 10 minutes 30 seconds 2 hours 5 minutes 23 hours 2 minutes 3 hours 5 seconds 6 hours 15 seconds 16 hours 1 minute 24 hours 2 minute Set gauges in "D" nipple ~ 7082'. POOH. Record and note static surface pressure. Open well to flow on 6/64" adjustable choke. Maintain constant rate by increasing choke as pressure declines. *** Cltan up well at maximum stabilized flow rate with no greater than 1000-psi dr~wdown at surface. Flow well at stabilized rate for +/- 24 hours taking readings &i 1 $ minute intervals during first 12 hours and 30 minute intervals for remainder of flow per/od. Shut well in for build up by closing ~ valve, Valve must be closed within 10 seconds, Monitor for leaks. Record surface .pressure at 1 minute intervals for first 30.~ ---- ...................... minutes. Aider 48 hour build up reopen well to flow at prior stabilized .r.a..t..~, Flow well for 2 ~--" hours after rate has stabilized, ' ...... "'"""'"" "" :"' ':"": Cha~e choke to reduce flow r~te by 22%, Flow well for 2 hours..~'"' Change choke to reduce flow rate by 25%, Flow well for 2 hours. ~..' 4/'; .it.~ ( i!~. ,-~..,. i~;~' ,'"~' ~'''','' Change choke to reduce flow rate by 25%. Flow well for 2 hours, ~ .... :!'~' '~'/ ...... Shut well in at wing valve. ug and set 'in D nipple at ?082', POOH.'Z''~' ~ Run in hole with CA pl '~ ~.?'-'"?""'/"' ........ "' Bleed surface pressure to 0 psi. Monitor well for leaks. /.~ Rig up lubricator and install BPV in long string side. Secure well. Download gauges, transmit gauge da~a, and well test report for analysis. Page 4 of' ~ SE~P--O~--99 02 :41 PM GAS--PRO ALASKA LLC 90726275:~9 1~.07 ***Note: MAXIMUM CLrMIvIULATIVE GAS WILL NOT EXCEED 70MMCF. ESTIMATHD CUMMULAT~ TO BE UNDER 50MMCF. If you have any questions plesse contact; Phillip Lafleur Gas.Pro Alaska llc 907.262.4291 Page $ of $ SEP--0~--99 02:42 PP1 · GAS--PRO ,, ALASKA LLC 90?262?389 '\ . . P.08 0 m .0 · Walking ./wa~ng..surfaces Jlllll Ilml Ill O ..... ) ....... GAS--PRO ALASKA LLC 907,.26';:'7589 P.09 m m immmmml KF!.~ I. ~ . . ................................. ......... Iff ..... _ m m ! I 'l mmmmm ..... , ..... '1 .................... .[~ ........ ............ ,, ...... IIIII BUREAU OF LAND MANAGEMENT ~ 6 .~- cd ~ [ .. U ned States Department of the I terior ANCHORAGE FIELD OFFICE 6881 Abbott Loop Road ANCHORAGE, ALASKA 99507-2599 http ://www. anchorage, ak. blm.gov/ North Fork Unid3160 May 25, 1999 ,c uU- -2-.-7 ~EOL ,A~ ~T ...... _ , , I Phillip A. Lafleur Gas-Pro Alaska, LLC P.O. Box 3050 Soldotna, Alaska 99669 De~ Mr. Lafleur: We ~e approving your request for a 45 day extension to submit ~ updated E~ibit "B" for ~e No~ Fork Unit based on your letter of May 5, 1999. The revised Exhibit "B" should be submitted prior to July 12, 1999. Should you not receive the approved assi~ents for ~e State leases within time to meet this new deadline please contact us to discuss ~ additional extension. Wi~ reg~d to the seismic limited license a~eement, we have noted the pl~ of development for the North Fork Unit and would like to be kept apprised of ~y developments with the license approval. Should you have any questions regarding these, or any other oil and gas operational matters, please contact Peter Ditton at (907) 267-1429. ' CC: . .. s'!a]r'Woa ,n,. .... AOGCC 3001 Porcupine Drive Sincerely, ,/ J. Dav~DrmasTGroup Manager Anchorage, AK 99501-3192 RECEtVED Kenneth A. Boyd ~a~I/a 0il & Gas 0oas. [lomm[sg[m:..: State of Alaska, Department &Natural Resources, Division of Oil and Gas Anchoral~e 550 West 7th Avenue, Suite 800 Anchorage, AK 99501 Ph.) 907.262.4291 5/10/1999 Mr. J. David Dorris BLM Group Manager 6881 Abbott Loop Rd. Anchorage, Alaska 99507 Gas-Pro Alaska llc 170 Corral Ave. Suite # 1 P.O.Box 3050 Soldotna, Alaska 99669 Fax) 907.262.7389 "~ ~REAU OF I. AND MANAGEMEI~" Dear Mr. Dorris, Gas-Pro Alaska llc, as the North Fork Unit operator, hereby requests a 45-day extension to respond to your letter dated April 12t~, 1999 regarding an updated Exhibit The BLM has approved the transfer of Marathon Oil Company's interest in the North Fork unit to Gas-Pro Alaska lie.. We are currently waiting for the State .of Alaska's response and/or approval of the state lease assignments of Marathon's interest to Gas-Pro in the unit. I would hope an extension of 45 days would be sufficient for the assignments to be approved and/or a decision be made. Upon the approval of the assignments and/or a decision being made, we would respectfully submit a revised Exhibit "B' reflecting all of the transferred interest of record. Anadarko Petroleum and ARCO Alaska Inc. are currently evaluating our request for a limited license agreement, which would grant access to the seismic data that was shot across the North Fork leases in 1997. Upon receiving the license agreement from Anadarko, Gas-Pro will set a date and time to discuss the data with the BLM. Sincerely, General Manager Cc: Kenneth A. Boyd, State of Alaska DNK, Division' of Oil and Gas Dora Soria,. Arco Alaska. Marlo Garza, Anadarko Petroleum. Brock Riddle, Marathon Oil Company Ye~ r Csg. Hd. Hemlock Z. Dry Gas Kena i Z. · Table Xl II (Cont.) GAS PRODUCTION At Pressure Base 14.65 psi GO°F Blown or Total lost Used Sold Injected BELUGA RIVER FIELD i~63 1954 TOTAL BIRCH HILL FIELD 13,538 136,937 15o,475 13,538 136,537 150,475 13,538 136,537 150',47~ 65,331 65,331 65,331 FALLS CREEK FIELD 18,582 104,555 NORTH FORK 18,582 i04,595 18,582 104,555 TOTAL - ALL FIELDS 1966 6,820,879 CUMULATIVE - ALL FIELDS 20,043,400 34,356,153 61,237,216 41,217,032 81,280,616 2,826,175 7,3Ol,901 4,816,315 24,445,478 33,574,538 45,533,237 28,769,613 45,569,325 ALASKA INDIVIDUAL WELL PRODUCTION AS OF 11/03/95 WELL-NAME: N FORK UNIT 41-35 API: 231-10004-00 LEASE: FEDA024363 OPERATOR: UNION OIL CO OF CALIFORNIA FIELD/POOL: NORTH FORK, UNDEFINED SALES CD - ACCT GRP - 000 ** GAS PRODUCTION ** FINAL STATUS: DEV I-GAS CURRENT STATUS: DEV SI 1966 JAN FEB MAR METH FLOWING FLOWING DAYS 1 1 OIL WTR GAS 58,188 46,407 1966 TOTALS OIL WATER APR MAY JUN JUL AUG SEP OCT NOV DEC GAS 104,595 CUM OIL CUM WATER CUM GAS 104,595 TO: Mike Minder (AOGCC) DATE' October 31, 1990 FROM: Ralph Holman (Unocal) RE: North Fork 41-35 . Mechanical Integri .ty Test ~/'/'~ '~-~- - i'~'i'~,'~ ~' ,' +,~ ?~.,..;~. ~'t' ~.,...I, ?,~.f- ,...._.._~ ~ i~ /,..~ On October 12, 1990 a test was run to test the mechanical integrity ~'~'~"' .... of the casing and packer. There were no witnesses from AOGCC or BLM present. The following procedure was used: 1. Pulled backpressure valves in tubing and heater string. 2. Rigged up BJ pump truck and pumped 11 bbls. fresh water at 400 psi. ~: ,. ~a~¢~,.~. ~ ~.~,~ ~. ...................... 3. Tubing/casing would not pressure up beYond 400 psi. 4. Shut down pump truck and rig down. 5. Rigged up slick line unit and pulled CA tubing plug at 7983' md. 6. Redressed CA plug, ran in and set in "D" nipple at 7983'. 7. Hooked up annulus to tank and BJ pump to tubing. 8. Pumped 40__bb!s, f,r~esh wat.e.r, h.a,,d.....r,,~,t.,~..r.~_S..,t.o_tar~k. Note: Tubing is in communication with annulus through Camco mandrel with CEV dummy valve at 7905' md. 9. Closed annulus valve and installed test gauge on annulus and heater string valves. 10. Pumped..~.b_,bls. fre_sh wat, e~r and pressured up tubing, heater string and casing to 1500 psi. Held 1500 psi for 35 minutes. Had 5 psi bleed off. 11. Bled off pressure and rigged down pump and tank trucks, 12. Ran backpressure valves in tubing and heater striRgs. 13. Secured well. This test was witnessed by the undersigned: Bob Smith (Unocal) cc: Joe Dygas (BLM) Bob Smith enclosure E. G. Myers Wireline Service P.O. Box 57 Kenai, Alaska 99611 (907) 283-7333 Wireline File Record Company Unocal Location North Fork Unit Record Sheet No. 1 Job Completion Date Well No. 41- 35 Wireline Operator(s) Type Survey Completed K.B. 10-12-90 Sleeves are open to zone Pardue/Myers Impression Block Run Remarks Amount of Fill in Casing Clean Out Data Dewaxed, From To Hardwax Softwax Bailed, From To Material Recovered Descaled, From To Comments Fluid Level @. Tubing Pressure Casing Pressure Last Wireline Job Completed None Job Completion Remarks: (Well conditions encountered, abnormal equipment installed, fish left in hole, was scale present, etc). 10-10-90 10-11-90 10-12-90 Traveled to location. Rigged up slickline unit. Ran in hole 2.5" wire to check tubing clear. Ran in hole, latch and pull prong. Ran in hole, latch and pull plug. Returned to shop for the night to redress plug. Traveled to location. Ran in hole, set C.A. plug in D nipple @ 7983'. Pulled out of hole. Ran in hole with K-kickover tool to pull C.E.V. valve body '(record showed prong already.pulled). Made 2 trips after valve. No problem kicking over into pocket, didn't latch valve and tools would fall out of pocket and down hole while attempting to jar down. Assume valve body already pulled. Returned to shop for the night. Equipment still rigged up on well. Waiting for M.I.T. test on well. Tubing and casing tested good. Not necessary to run dummy valve into side pocket mandrel. Rigged down. Returned to shop. RECEIVED NOV ! 0j.& Gas C0.s. ohorag 5O 40 'o " ' / STATE OF ALASKA (' AL , OIL AND GAS CONSERVATION COMM _,N ~ APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon __ Suspend __ Operation shutdown __ Re-enter suspended well __ Alter casing __ Repair well __ Plugging __ Time extension __ Stimulate Change approved program __ Pull tubing __ Variance __ Pedorate __ O'T~'~r ~ 2. Name of Operator 5. Type of Well: 6. Datum elevation ~)f'"Xo r KB) Development X 780 feet Union Oil Companj/ of California ExploratoryZ 3. Address p.0. BOX 190247 Stratigraphic__ 7. Unit or Property name Anchoraoe. Alaska 99519-0247 Service__ North Fork Unit 4. Location of well at surface 8. Well number 659' FEL, 655' FNL, Sec. 35, T4S, R4W, SM 41-35 At top of productive interval 9. Permit number At effective depth 10. APl number 5°-,2,3//~ At total depth 11. Field/Pool 12. Present well condition summary - See attached mechanical detai 1. Total depth: measured feet Plugs (measured) true vertical feet Effective depth: measured feet Junk (measured) true vertical feet Casing Length Size Cemented Measured depth True vertical depth Structural Conductor Surface Intermediate ~i:tTcti°n RE'¢EIV.ED Perforation depth: measured AU G ~) 1 1990 true vertical Alaska.0ff & Gas Cons. Tubing (size, grade, and measured depth) Packers and SSSV (type and measured depth) ,, 13. Attachments DesCription summary of proposal -Z- Detailed oPerations program __ BOP sketch __ X - Mechanical detail i 14. Estimated date for commencing oPeration i51 Status of well classification as: 16. If proposal was verbally apprOved Oil __ Gas.__ Suspended X Name of approver 'Date approved . Service' ,,, 17. I he~/y~ertify that th~regoi~ is true and correct to the best of my knowledge. ',/~¢s Slgne Title , ' 'FOR ¢OMMISSa::)N UflE ONLY .. I . ' ' ' I Approval No. Condlbons of approval: N~ ~tify Commiss)on so representative may witness ' Plug integrity __ BOP. Test __ Location clearance __ I Mechanical Integrity TestT~ Subsequent form required 10- ~ ' / ' ORIGINAL SIGNED BY Approved by order of the Commissioner LONNIE O. SMITH Commiss, ioner Date ~ J"'J / ,,.~.' Form 10-403 Rev 06/15/88 Approved COpy, ' Returned SUBMIT IN TRIPLICATE 07/24/90 NORTH FORK UNIT PROCEDURE M.I.T. . . . . . . . RU pressure equipment over No. Fork Unit 41-35. Pressure test lines to 2000 psi for 10 minutes. Check casing annulus/tubing for pressure and note same. Fill tubing and annulus with water to surface. Pressure up tubing to 1500 psi and hold for 30 minutes. Bleed down pressure and pressure up casing/tubing annulus to 1500 psi and hold for 30 minutes. Bleed down pressure, RD pressure equipment and secure well. NKS:da RECEIVED AU G ~ 1 1990 Nasl{a .Oil & Gas Cons. Commission ~nchorage ?=.--90 THU ~ 5 : 4m~. D.L.M. Anr_~h . Ak . (" - (' DEPART~I~NT OF ~ATURAL RESOURC~ DIVISION OF OIL AND ~S ~EVE COWPER, GOVERNOR EO. BOX 7O34 ANCHORAGE, ALASKA 99510-7034 PHONE: (907) 762-2553 (907)762-2547 June 8, 1990 Unocal Oil and Oas Division Unocal Corporation P. O. Box 190247 Anchorage, _Ala, ka. 99519-0247 Attention: Robert T. Anderson Manager, Lands Alaska Region Subject: North Fork Unit Twenty-Fifth Plan of Development and Operation Dear Mr. Anderson: The Division of Oil and Oas has reviewed the proposed Twenty-Fifth Plan of Development and Operation for the North Fork Unit, dated April :30, 1990. This Twenty- Fifth Plan is approved subject to the concurrent approval of the U.S. Department of Interior, Bureau of Land Management. Pursuant to 11 AAC 83.343 -- 11 AAC 83.346, a Twenty-Sixth Plan of Development and Operations for the North Fork Unit will be due in this office at least 90 days prior to the termination of the Twenty-Fifth Plan, that is on or before March 20, 1991. esLtJirecto~r. Eason cc: Joseph A. Dygas, BLM i$PODAPPR. NFU,txt SEP-- 6--90 THU I .~ : 46 ]~= . L. I'1 . Anch . Ak . P. 04 3 so(984) Hr. Robert T, Anderson UNOCAL P.O, Box 190247 Anchorage, Alaska 99519-0247 June 7, 1990 Dear Hr. Anderson: Your Apr11 30, 1990 application for approval of the Twenty-Fifth Plan of Development and Operations for the North Fork Unit ts approved, subject to the concurrent approval of the state of Alaska. A copy of the approved plan is attached, · , Please submit the Notice of Intent Sundry Notice (Form 3160-5] to perform the mechanical integrity test on North Fork Unit Well No, 4t-35 by July 31, 1990. Sincerely, tlrlglnal signed Adon 8eldlltz Ooseph A. Oyga8 Chief, Branch of' Lease Operations Dtvtston of Ntneral Resources Attachment - NFU POD (2 pp,) cc: Mr. James Eason Department of Natural Resources 0t~ and Gas Dtvtston (N/attachment) bcc: NFU POD Ftle (w/agtachmen%)'. 984- Se ~ dl ttz: as: 06/07/90: NFUPOD S E !:'-- 6--98 THU :1. 5 '-44 I~. I. VI. Ankh . Ak . ? ( ~ Uno¢,l Corporation "~ P.O. Box l g0247 Anchorage, Alaska gg$1g-0247 Telephone (g0?) 276-7600 P. ~2 UNOCAL ) April 30, 1990 Robert T, Anderson Manager, Lands Alaska Region APR ., · reau of Land ManaB& Anohorage, A! Mr. Joseph A. Dygas, Chief Branch of Lease Operations Division of Land Management Anchorage District Office 222 W. 7th Ave., %13 Anchorage, AK 99§13-7§99 Mr. James Eason, Director Division of Oil and Gas Department of Natural Resources P.O. Box 7034, l~. #1360 Anchorage, AK 99§10-7034 Development and Operation No. 14-08-0001-8679 Gentlemen: Pursuant to the provisions of Section 10 of the North Fork Unit Agreement, Unocal, as Unit Operator, submits the following as 1ts Twenty-fifth Plan of Development and Operations for the North Fork Unit Area: A. This Plan shall cover the period from JUn__e. 20, 1~..0 to Ju.j~~~9..9__l.. In accordance amendment to 11 AAC 83.343 (c), this Plan is hereby submitted ninety (90) days in advance of scheduled expiration date. Be DEVELOPMENT PLANS Proposed development plans for the North Fork Unit are being put on hold pending abvailability of a marketer for the gas. Until such time that a marketer can be found to develop this gas, plans to develop the Unit will be left in a suspended status. j. 8EP-- 6--98 THU I 5 : 45 I~. L. FI. Anch . Ak . Mr. Joseph A. Dygas Mr. James Eason April 30, 1990 Page -2- C. NFU .#41-35 M. I. T, The Mechanical Integrity Test for NFU #41-35 will be conducted during this plan period. The Unit Operator respectfully resubmits this request for approval of the foregoing as the Twenty-fifth Plan of Development and Operation for the North Fork Unit Area, per your letter of April 12, 1990. - Very truly yours, Robert T. Anderson APPROVED: BUREAU OF LAND MANAGEMENT Minerals Management This ~ Day of_ , 1990 APPROVED: DEPARTMENT OP NATURAL RESOURCES Division of Oil and Gas This Day of , 1990 By: ...... _ NKS:bdb 6--9~ THU 15 : 47 :B . I . M . Rnch . ~k . .. . P. L~ Mr. Joseph A. Dygas Mr. James Eason April 30, 1990 Page -2- C. NFU #41-35 M. I.._T. The Mechanical Integrity Test for NFU #41-35 Will 'be 'conducted 'd~ing this plan period. The Unit Operator respectfully resubmits this request for approval of the foregoing as the Twenty-fifth Plan of Development and Operation for the North Fork Unit Area, per your letter of April 12, 1990. Very truly yours, By: ! Robert T. Anderson APPROVED: APPROVED: BUREAU OF LAND MANAGEMENT Minera 1 s ..~..~gg~ent ..This ..... _Day of ..... By: __. DEPARTMENT OF NATURAL RESOURCES Division of Oil and Gas '. NKS:bdb GAS RESERVE POTENTIAL NORTH FORK UNIT 41-35 KENAI BOROUGH, ALASKA Prepared for MOUNTAIN ALASKA ENERGY H. J. RAMSAY AND ASSOCIATES, INC. Petroleum Engineering Consultants July 1, 1988 1580 Lincoln Street. Suite 680 Denver. Colorado 80203 (303) 832-3330 Mr. Lester D. Sitter President Mountain Alaska Energy, Inc. P. O. Box 19 Anchorage, AK 99510 North Fork Unit 41-35 Dear Mr. Sitter: Pursuant to your request, the records for the subject well have been reviewed to determine its producing capability and gas reserve potential. The results are summarized as follows: 1) The Tyonic sand member from 8,005 to 8,046 ft. was produced on a four-point back pressure test at the maximum rate of 6,720 MCFPD with a back pressure of 295 psia. With a 160-acre drainage area, the estimated reserves are 4,196 MMCF; with 320-acre drainage, reserves are estimated to be 8,382 MMCF. 2) The Tyonic sand member from 8,563 to 8,602 ft. was produced on a cased hole drill stem test at the rate of 1,770 MCFPD with a back pressure of 180 psia. Estimated reserves for this member are 1,996 and 4,004 MMCF for 160- and' 320-acre drain- age, respectively. 3) Three additional untested Tyonic sand members have, accord- ' lng to open hole log analysis,'a total original gas-in-place of 8.8 and 17.6 BCF for 160- and 320-acre drainage, re- spectively. These sands are in the depth range from 6,745 to 7,262 ft. 4) Nine shallower untested Beluga-Sterling sand members, rang- ing in depth from 2,055 to 5,508 ft. are prospective for gas production according to open hole log calculations. The original gas-in-place for these sands collectively ranges from 18.5 to 37 BCF for 160- and 320-acre drainage, re- spectively. 5) After accounting for royalty, operating expense, and state production taxes, tbe upper tested Tyonic sand member alone is estimated to be capable of generating the following net cash flow to 100 percent working interest: Drainage Area, Acres Net Cash Flow 10% Present Worth Unrisked 160 $4,864,464 $2,969,977 320 $9,716,792 $4,632,437 Drainage Area, Acres Net Cash Flow 10% Present Worth Risk Adjusted 160 320 $3,648,348 $4,858,396 $2,227,483 $2,316,218 The following discussion reviews the details of this investi- gation. GEOLOGY The Standard Oil Company of California (now Chevron) North Fork Unit 41-35 is located in the NE/4 of Section 35-4S-14W, Kenai Borough, Alaska. This area on the southern side of the Kenai Peninsula is known as the Epperson Knob area and is sparsely drilled. The well is located on a structural high enclosing some 3,500 acres with a closure of about 600 feet on the Hemlock formation. While there are other exploration tests in this general trend, North Fork Unit 41-35 is the only well drilled on this specific structure. The main exploration target of interest has been the Hemlock formation. However, this review is focused in the shallower Tyonic and Beluga-Sterling formations. These formations can generally be described as .non-marine sandstones and claystones interbedded with coal which is probably the source of the gas. These sands are productive elsewhere through the Cook Inlet area. Two geophysical interpretations have been provided by Mountain Alaska Energy. One of these, dated October, 1986, shows the North Fork Unit structure to be bounded on the northwest and southeast sides by faults. The structure is on a horSt (upthrown) block between these two faults. Other than the bounding faults, this interpretation shows the structure to be relatively free' of faults. A more recent interpretation shows essentially the same bounding faults and the same horst block. However, this interpretation also shows additional faul. ts traversing the structure which, if present, could possibly act as reservoir boundaries. North Fork 41-35 is located in one of these smaller fault blocks which has a potential drainage area free of faulting of about 640 acres. Since other wells have not been drilled on the structure, the areal extent of the producing sands cannot be evaluated. A downdip gas-water contact, if present, could also limit production. Volumetric gas-in-place calculations have been made based on 160- and 320-acre drainage areas. The calculated formation permeability demonstrates that the well is capable of draining 640 acres provided there are no faults, sand pinch outs, or gas-water contacts to limit the areal extent of the productive reservoir. For the purpose of this report, the gas-in-place within the smaller 160- acre drainage area is considered to be proven. The gas-in-place in the second 160 acres comprising a total drainage area of 320 acres is considered to be probable. This is a subjective classification because there is no physical evidence indicating that the drainage area will be limited to 160 acres. Normal spacing for a well of this type in the state of Alaska is 640 acres. With an adequate gas market to encourage development drilling on the structure, 640 acres could prove to be the actual reservoir size. WELL HISTORY North Fork Unit 41-35 was spudded in August, 1965, and reached a total depth of 12,812 feet. After redrilling the lower part of the hole and testing the Hemlock formation, two of the lower Tyonic sand members were tested in December, 1965. The deeper of the two sands was perforated from 8,563 to 8,579 and 8,592 to 8,602. This sand produced at the rate of 1,770 MCFPD over a three and a half hour test. Flowing tubing pressure was 165 psig. The upper sand was perforated from 8,005 to 8,046 feet. These perforations flowed at the rate of 4,360 MCFPD over a one hour fifty minute test. Flowing tubing pressure was 450 psig. The well was then completed as a shut-in gas well capable of producing from only the upper sand. The lower sand is isolated from the upper sand by two bridge plugs, one in the 9 5/8 inch production casing and the other in the 7 inch liner. Enclosure 1 is a schematic diagram of the mechanical condition of the well. In January, ~1966, a four-point back pressure test was run with the following results: Flowing Tubing Flow Flow Pressure Rate _Time psig MCFPD hrs. 2,410 2,386 1/2 2,070 3,531 1/2 1,410 4,720 1/2 280 6,720 1/2 Subsequent mechanical integrity tests have been conducted by setting a plug inside the tubing below the production packer. The casing was then pressured to 1,000 psi for 30 minutes. The well has successfully passed these tests. The well is believed to be capable of production without further expenditures from the upper sand in its present mechanical condition. Surface equipment will be needed to process the wellhead gas which will be installed by the gas purchaser, Mountain Alaska Energy. GAS RESERVES Reservoir properties for the two tested Tyonic sands were evaluated from open hole logs using the procedure described in Enclosure 2. The better quality'upper Tyonic sand has 28 feet of pay .. with a porosity of 18.4 percent and a water saturation of 40.7 percent. Permeability calculated from the flow test results is 22.57 md. The original gas-in-place is 4,520 MMCF per 160 acres, or 9,041 MMCF for a 320-acre drainage area. The lower Tyonic sand has 16 feet of pay with a porosity of 18 percent, water saturation 50 percent, and a calculated permeability of 10.35 md. On 160-acre drainage, this interval has original gas-in-place of 2,296 MMCF and for 320 acres, 492 MMCF. Enclosure 3 summarizes other reservoir properties and reserve calculations. A wellhead sample of gas from the upper sand was analyzed with the following results: Mol % Mol % Me thane 98.1 Nitrogen 1.2 Ethane 0.3 Argon Trace Propane 0.1 Hydrogen 0 Butane 0 Hydrogen Sulfide 0 Pentane 0 Carbon Dioxide 0.2 Hexane 0 Helium Trace Specific Gravity 0.56 Ultimate gas recovery was estimated using a computer simulation taking into account the specific deliverability of each of the two Tyonic sands, the original gas-in-place, and the economic limit. The following results were calculated: Drainage Area, Acres Recoverable Gas, MMCF Recovery Factor, % Depletion Time, Yrs. Perforations 8,005- 8,046 ]60 320 4,196 8,382 92.8 92.7 15.3 29.5 Drainage Area. Acres Recoverable G~.'.~, MMCF Recovery Factor, % Depletion Time, Yrs. Perforations 8,563 - 8,578 8,592 - 8,602 ].60 320 1,996 4,004 86.9 87.2 14.0 28.6 The shallower untested Tyonic and Beluga-Sterling sands were evaluated by open hole log calculations. (See Enclosures 2 and 4). These results are considered to be subject to more interpretative risk than for the tested sands because the depositional history of these sands may be somewhat different than the deeper tested sands. Since these sands have not been tested, the presence of gas is not proven. However, other shallow sands were analyzed also and were rejected because of high water saturations indicating that the calculated results span a range of likely results. Three additional Tyonic sands are indicated to be productive. Collectively, these sands contain 8,816 MbICF of original gas-in-place on 160-acre drainage. For 320-acre drainage, the gas-in-place would be twice as much. Nine Beluga-Sterling sands show potential for gas production. These sands have a total gas-in-place of 18,453 MMCF on 160-acre drainage, or 36,906 MMCF for 320 acres. ECONOMIC PROJECTIONS Economic projections were prepared for just the upper tested Tyonic sand alone assuming that gas marketing to the City of Homer will start by mid-1989. While the lower sand is capable of production and could add gas reserves by commingling it with the upper sand, Mountain Alaska Energy has opted to produce the well with its present mechanical arrangement in order to avoid the additional investment to commingle the lower zone with the upper. The option of doing this work sometime in the future is not precluded by initially producing the upper sand alone. Mountain Alaska Energy advises that the gas market in the City of Homer is capable of taking 1,000 MCFPD for the first two years. Start-up date is projected to be August, 1989. After two years the market is anticipated to increase to 2,000 MCFPD and~.will remain at this level as long as the well is capable of producing at this rate. Mountain Alaska Energy plans to operate their system with a minimum back pressure of 100 psig on the well. Once the well is incapable of producing at 2,000 MCFPD under these conditions, its rate will then decline according to the deliverability tests available on the zone. On 160-acre drainage it is expected that the well can produce at 2,000 MCFPD until mid-1993. For 320-acre drainage, this rate can be sustained until mid-1996. Operating expense for'the well, exclusive of the gas processing and pipeline system, was estima.ted to be $3,000 per month. Mountain Alaska Energy has advised that the wellhead gas price would be $1.65 per MCF. Net revenue interest for the. well is 87.5 percent and the production tax rate is estimated to be 10 percent. These parameters result in an economic limit producing rate of 76 MCFPD.. Enclosures 5 and 6 are production plots for 160- and 320-acre drainage, respectively. Enclosures 7 and 8 are yearly cash flow projections for the two drainage areas. These projections are made on an unrisked basis. Enclosures 9 and 10 are similar cash flow projections where the net operating income has been adjusted by a risk factor. The risk adjustments were derived from a recent survey of the Society of Petroleum Evaluation Engineers' membership. The first 160 acres of drainage area is considered to be proved developed shut-in reserves which, according to the survey, has a concensus risk adjustment of 75%. The second 160 acres of drainage area is considered to be probable developed shut-in reserves with a concensos risk adjustment of 25%. On a weighted average basis, the 320-acre projection is risk adjosted by 50%. However, this is an overly conservative approach, limited by software capability. It woold be more realistic to risk adjost the first half of the reserves produced by 75%, and then risk adjust the second half of the production by 25%. A hand calculation using this approach to risk adjustment increases risk adjusted 10% present worth from $2,316,218 (Enclosure 10) to $2,755,000. We appreciate the opportunity to provide this service to you. Should there be any questions or additional work needed, please advise. Yours very truly, H. J. RAMSAY AND ASSOCIATES, INC. H. J. Ramsay, Jr. President Registered Professional Engineer LIST OF ENCLOSURES Enclosure 1 2 3 4 5 6 7 8 9 10 Description Page Well Diagram .................................. 8 Discussion of Log Calculations ................ 9 Gas Reserve Estimates ......................... 11 Evaluation of Shallow Untested Sands .......... 12 Production Plot - 160 Acres ................... 13 Production Plot - 320 Acres ................... 14 Unrisked Cash Flow Projection - 160 Acres ..... 15 Unrisked Cash Flow Projection - 320 Acres ..... 16 Risked Cash Flow Projection - 160 Acres ....... 17 Risked Cash Flow Project~ipn - 320 Acres ....... 18 ENCLOSURE 2 DISCUSSION OF LOG CALCULATIONS Discussion Water resistivity was calculated from the SP log (Schlumberger Charts SP-1 and SP-2) with the following results. These values were also confirmed with the salinity of water recovered on drill stem tests: Rw, ohm-meters Temperature, OF Equiv. NaC1 ppm DST NaC1 ppm Perforations 8,005-8,046 Perforations 8,563-8,578 8,592-8,602 0o 60 0.90 143 146 4,700 3,100 3,600 3,700 True formation resistivity was calculated from the laterolog corrected for borehole effects (Schlumberger Chart Rcor-1). Dep'th of invasion was found to be very small and a correction for invasion was not made. Cross-plots of the three porosity log.~ (sonic, density, neutron) were generally not satisfactory. The sandstone pay contains very large amounts of clay. In addition, there are.highly variable amounts of an unidentified heavy mineral(s). The neutron 'log was not compensated and the many corrections needed made the neut~'on log porosity values questionable. A reasonable 'match to the sandstone lithology was obtained for several sonic-density log cross-plots and these values were used to derive the following relationship to calculate effective porosity from the sonic log:"- 0e - Atlo8 - Atma = Atlo8 - 54.5 Atf - Atma (189 - 54.5) Clay content was estimated from the density and sonic logs using normal sandstone matrix values: Vsh = Calculation Procedure The sands were divided into layer units having common log values and the following analytic procedure was followed: 1) Evaluate clay content as described above. 2) Evaluate effective porosity as described above. ENCLOSURE 2 (Cont.) 3) Calculate water saturation using the following total shale water saturation eqoation: Sw -- a Rw(1-Vsh) [ + ] (Vsh) 2 4(Pem 1/2 Vsh 2(Pem R-~ a Rw Rt(1-Vsb) Rsh where: a = 1 Rsh = log reading in adjacent shale Rw, Vsh, (~e, Rt as described above 4) Net pay was determined using a 55 percent water saturation cutoff. Tbe untested Beluga-Sterling and Tyonic sands were evaluated as described above, adjusting the water resistivity value of 0.60 ohm- meters at 143OF for each sand's respective bottom-hole temperature. 10 ENCLOSURE 3 GAS RESERVE ESTIMATES RESERVOIR DATA D'r'air~age A'r-ea. Ac'res Net Pay, Ft. Pc,'rosity: % Water Sa,~uraticcr~ Bc~ttc~m-Hole Pressure~ ~sia Bottom-Hole Te~. ~ oF Gas Gravity ~' Cor, der~sate Yield, B/MM TEST DATA Gas Rate. ~4CFPD Cor, der~sate Rate, BOPD Water Rate, BWPD Flowi;.'~.n. Tubi'ng P~essure: Flnw Time: hrs. Slome Ca!c. Pe'r. meability~ md VOLUMETRIC DATA Ori .q i r,a! Gas-In-Place, Wellhead P'messure, msia Reo,:,verabie Gas, MMCF Recove'ry Factnr-. % · - Deoletior~ Ti~le, yrs. Ecor, c,~ic Limit, MCFPD msia MMCF PERFORATIONS 8~ 005-8,046 PERFORATIONS 8,563-8.578 8,592-8~602 160 320 160 320 28 28 16 liB. 4 18. 4 18 18 40. 7 40. 7 50 50 S259 3259 35'95 3595 143 143 146 i46 0.56 0.56 0.56 0.56 0 0 0 0 6720 6720 i770 1770 O 0 0 0 0 0 0 0 295 295 180 180 0.5 0.5 3.5 3.5 0. 839 0. 839 0. 839 0. ~339 22.57 22.57 10.35 1vi. 55 '~'-' 2296 4~0 904i 4592 i15 115 i!5 li= 4195.5 8~82.3 1995.7 4003.~ 92.8 92.7 86.9 87.2 15.3 29.5 14.0 28.6 76 76 76 76 EVALLJAT :[ ON OF SHALLOW UNTESTED SANDS Top Bottc, rl~ Net Pay Ft. Ft. F't. Elf. Water- Est. Est. Pc, ros i t y Sat. Pressure Temp. % % p s i a oF Z Fact o'r Ori il. Gas-Ir,.-P 1 ac.e -- h~CF Pet- NMCF Pet'- Acre Foot 160 Acres £ELUbA-STERLING SANDS 2055 2070 15 2463 2482 19 2677 2700 3245 ~,~.,.~ 10 3532 3555 23 4882 4896 9 5191 5197 G 5358 5382 21 5488 5508 18 TYONIC SANDS 6745 6845 7254 6765 20 6860 13 7262 8 31.6 30.5 840 99 0. 919 29. 4 35. 6 1000 102 0. 908 2'7.0 ~6. 1 1090 1 ~ ~ 0.901 30. 1 30.3 1320 108 0. 888 24.3 28.9 i440 110 0. 882 26.7 41.5 1990 120 0. 865 26.4 45.0 2110 122 0. 864 29.2 45.4 2180 123 0. 863 :~,'D ? b'~ · 32.3 36' 5 c-,"o,~. 124 0 862 Total OGIP, 27. 1 41. 1 2740 23.7 33.9 2780 27. I 37.3 2950 Total OGIP, Tc, tat OGiP, 560 1345 577 1 439 1264 851 767 2822 957 1378 941 903 1067 3584 1403 4040 18453 Beluga-.-Sterling Sands 133 0.866 134 0.867 137 0.871 Tyonic Sands 1313 1304 1486 Both Fc, rn~at i,:,ns 4202 271.;'7 1902 8816 i (:3 ' i MI3.~AIN AI_~i~ ENERGY. INC. ID: I LEASE:. NO~ITH FI3::IK UNIT 4i-:~ WELI~ FIELD:. WILDCAT OPERATOR: COt~TY: KEF;AZ STATE: ALA~A C~ TYONIC SA,~ 8005-,46. 160 ACR~3 DRAINAGE I , I ---~--! ....... , I , . 0 t-~ ~989 ~990 ~99~ ~992 i993 i994 i995 ~996 t997 ~998 1999 2000 200~ 2002 2003 2004 2005 2006 2007 2008 0 o o o o o o I i , I : FIEld: WIL~DAT OP~AT~R: CHEV~J~N C~'Y: K~I STAT~" ALASKA TYONIC SAN~ B005-46. ~20 ACRE~ D~AINABE t I ...... i989 i990 i99i i992 i99S i~d4 i995 i996 i997 i998 i999 2000 200i 2002 200S 2004 2005 2006 2007 2008 0 o~' YEAR I, ELL CNT 1969 I 199~ 1 . .,~: 1~I 1 .;j 1998 1 1~3 I 1~4 I .. 1°~°~ I 1~ I I~7 I 1~ I .. 1~ 1 ~I 1 ~.: TOT GROSS PRODOCT I~---- BBL OIL MCF G~S 98,800 368, 808 450, 80~1 7~, 873 ~, 438 159, 876 139, ~2 184, 7~ 79, ~7 GI~GI~ 63, 7~G ~j 161, ~8 Pf(ODoCTION RATE FORECAST. ~ EVALUATI~W MOUNTAIN AL~KA ENERGY, I~. ENCLOSURE 7 ..... ~T PF(ODUCT I~ ........ PRICE .... BBL OIL ~ GAS OIL ~ 8 0.~ 0.~0 78, 750 0.80 I. 650 315,~ B.~ I.~ ~3,7~ ~.~ 1.6~ 616, 7~ 8. ~ I. ~ 459, 751 8. ~ 1. G~ 319, ~7 0. ~ 1. 650 91,~1 ~.~ 1.~ 53, 91~ 0. ~0 1. G~ 42, 116 0. ~ 1.6~ 55, 760 O. 08 i. 6~ 3,~i,~ 0.~ 1.6~ 1~:37 -----F-~ALES INCOME OIL $ ~ $ TOTAL 12), 93~ i2), 936 519,750 519, 75~ 649, ~7 649, 1,017,66I 1,~17,~: 7~, 5~ 7~, 5~' ~7, ~I 527, 375, 1% 375, 1~ ~7~, 376 ~7~, 37E 2~1,319 ~1,31': 151,2~ 151,2~L i15,~I 115,~I 88, '~ ~, ~E 69, ~91 69, G, ~, ~3 G, ~, 292 YEAR TAXES 1988 0 1989 12, ']'34 I~F~ 51,975 1991 64, %9 I~F:J2 183, 1993 1~1,766 1~ 75,859 I~ ~, 748 I'~% 37, ~ 15, 11,~2 TOT ~, 8~ · EXPENSES WFP--TAX OPER TOTAL 9, ~0 36, ~8 36,800 36, 800 36,800 36, ~8 36, ~8 ~,~ 36, ~ 36, 8~ 0 21,994 87, 975 100, %9 139, 958 137, 766 111,859 88, 7~ 73,520 63, 238 56, 132 51,121 47, 522 44,895 42, 75, ~ ----NET ..... OTHER---- OPER IN~ COSTS I07,944 0 431,775 0 548, 719 0 89'~, 55~ 0 879, B95 0 646,731 0 438, GGi 0 ~1,676 0 ~, 139 0 145,187 0 67,699 44, 057 ~6, 5~ 16,~ 0 ~4, ~4 NET CASH FLOW 0tMiJ_ATIVE I0.~) PCNT DISCDUNTE~ 187,944 187,944 '~,3i2 94,312 431,775 539, 719 355, 558 ~8,719 i, ~, 43~ 487,677 857,547 899, ~ 1, ~7, ~8 612, 2~ I, ~9, 747 873,895 2, ~7, 8~ 544,626 6~6, 731 3,514,613 3~, 888 ~,~ 379, ~6~ 438, ~1 3, 953,274 ~24, %5 ~I, 676 4,254, 9~ 1~0,637 2~9, 139 4, ~4, ~89 ~, 638 2, ~3, i45, 187 4,6~, 216 ~,936 I~, ~7 4, 7~9, 362 ~, ~ 2, ~4,687 67,699 4,777, ~1 31, ~2 2, 9~, 249 44,~7 4,~1,118 12, 7~2 26, ~2 4,847, ~ 6, ~5 2, ~, ~7 I6, ~4 4, ~4,464 3, 970 2, ~9,977 4, 86% ~4 4,864, V64 2, %9, 977 2, ~9, 977 PRESENT I~ORTH PROFILE PCNT DSCNT $ VALUE 0. BB 4, ~, 464 I5.~ 2,401, 20. 00 I, 976, 740 30. ~ 1, 4~, 6~ ~. ~ 1, ~, 618 ULTIMATE GROSS CU~ PROD GROSS FUTURE RES GROSS FUTURE RES NET GROSS WELL COUNT NET WELL ~UNT INTERESTS YR MO WORI<INT 88 7 1.80~088 OIL (BBL) 0 OIL REV INT 0. 875800 GAS (~CF> 4, 16I, 588 4, IGl, 588 3, 641,398 0. ~0 ~qS REV 0.875~ PFEP~D BY: HJR EFFECTIVE DATE: JULY LEASE iD: I LEASE h~,~: ~TH FO~K UI(!T WELL ~.E: STATE: ALASKA COUNTY: KENAI FIELD: WILDCAT OPERATOR: Q~EVRON RES CAT: PR~D DEVELOPED b-I~UT-IN TYONIC SAND 8~-46, 160 ACRES DRAINAGE 15 ~DUCTIOh RATE FOEEC~T mD Ev~u~TION MOUNTAIN ~ASKA ENE66¥, I~C. ENCLOSURE 8 WELL ----6 ~lYSS P~DUCTI~---- YEA~ CNT BBL (]IL WY' GAS -----NET PRODUCTION ...... PRICE--- BBL OIL )m~F ~ OIL mS ~ 1991 1 ~) 450, ~0~ ...'; 1992 I (~ 7~, ~ 1993 I ~ 7F_~, ~ 1994 I ~ 7~, ~ . i~ 1 8 7~, ~ ~ 1 ~ 339, .~.~ ~ I ~ 2~, 5~2 C] TOT g 8,318,4~ YEAR TAXES ':~,' i969 12,994 i.'.;i 199~ 51,975 i99i E~, 969 ~ 1~3 i03,~ I~ 183, 9~ 69, ~ ~9, ~3 ~'~'~1 41, ' ~ 216, ~8 '.: TOT lj~jg~ EXPENSES. ~P-TAX OPE{:{ TOTAl. 21,994 87, 975. i~, %9 139, 139~ 950 139, 95g 139, I36, ~ I~, 783 94,277 B5,~3 7i,~ 83 i, 628 78, 75~ ~. ~ 1. G.~ 315,800 0.~ l.G~ 51~,3~2' ~.~ l.G~ ~i3,974 ~.00 1.6~ 312,8~ &~ 1.6~ 276, ~ 0.~0 1.6~ ----.-NET---- ----OTHER .... O~ER INLT~ COSTS i~)7,944 431,7~ 548,719 899, 5~ 899, ~Q 721, ~7 ~, I~, ~ 493' ~5,~ 337,233 28i, 7~ 3~, 6~ 716, 7~ PRESENT WORTH PROFILE PCNT DSL'ffr $ V~UE O. ~ 9, 716, 79?. 15.~ 3, ~62, Cd). ~ 2, F:f~, ~3 3~.~ I, 742, 516 4~. ~ i, P.~2, i97 ~. ~ 9~J, 458 ULTI~TE GROSS CL~ PROD GROSS FUTU~ RES GROSS FUTU~ RES ~T G(~39S ~LL CD~T NET ~LL COUNT INTE~STS YR ~ ~INT ~ 7 1.~ OIL (BBL) OIL REV INT ~. CAS (MCF) B, 31B, 45,.9 8, 31 B, 455 0. GAS REV iNT lB:]7 OIL $ -SALES INC~E, G~S $ TOT~ s 0 0 !29, 938 519, 750 519,750 649, 687 649, ~39, 5~ 1, ~9, 69~, Ggl 69~, 891 353, ~B 353,058 2, 1gg, 278 ~, 1~, 378 12, ~, 769 12, ~, 769 NET CASH FLOW- CUMULATIVE 10.0~ DCNT DISCOUNTED ~ 0 ~ 0 i87,944 1~7,944 %~ 312 34,312 431,775 53Q, 719 355, 55& 449,870 ~,713 t,~,43B 407,677 G~,~7 8~, 5~ 1, ~7, ~ G 12, C~ 1, ~9, 747 8~, 5~ 2, ~7, ~ 5~, 545 2, ~2G, ~ 699, ~ 3, 787, ~ ~, 9~ 2, 5~, 24~ B~, ~ +, g~, ~8 459, ~5 2, ~, 197 ~9, ~ 5, ~5,679 404, ~5 3, Y~, ~ 721,857 6,277, ~6 3~ ~3 3, 7~, ~5 5~, I~ 6, ~3, 6~ 227, 611 3, %~, 8% 488,493 7,~, 131 170, 8~ 4, I~, 751 ~5, ~6 7,763,157 128,778 4, ~, 5~ 337,233 8, I~, 3~ 9~, 4~3 4,327, ~ 881,752 8, ~, 142 7% 0~ 4, ~i, 03~ 1,334,6~ 9,716,792 231,403 W,632,437 9,716,7~ 9,716,7~ ~,632, V37 4,6~,437 PREPARED BY: H JR EFFECTIVE DATE: JULY LEASE ID: F, L~ ~: NORTH FOR~ UNIT 4t-35 64ELL STATE: ALASKA COUNTY: RENAl FIELD: WILDCAT OPE~TOR: CHEVRON RES CAT: P~O~BLE DEVELOPED SHUT-IN TYONIC SAND 80~4~, 388 ACRES DRAINAGE 16 1988 1989 19~ 199I 1992 1~3 19~ 19"~ 19~6 i~7 19~8 19~ Cd{O1 TO~ YEAR TAXES 1988 ii 19~9 12, 994 1~ 51,975 1991 64, %9 1992 103, 9f~t 1993 i~I, 7~ 1~ ~, 8~ 1~ ~, 7~ I~ 37, ~ I~7 ~7, 238 1~ 15~ I~1 TOT ~, ~ m GROSS PRO6tK~T I[~---- BBL OIL MCF G~ 0 450, ~ 7~, ~ 7~, 873 ~, 3~, ~ ~J, 876 139, 442 I~, 733 ?9, ~ 61,612 ~, 726 161, ~ P~ODUCTICwN RATE FCHF~ECAST' AND EVi~TID~ ~TAIN F-W_ASKA ENERGY, 1NC. ENCLOSURE 9 -----~-r PRODOCTI~ ..... PRICE----- BBL OIL MCF GAS OIL mS 0 0.00 78,750 0. ~ i. 650 315, ~]~ 0.~ 1.6~ 616,7~ ~.~ I.~ 4~,~1 ~.~ 1.6~ ~7,~ ~.~ i.~ 1~,076 0.~ 1.~ 91,64i 8.~ i.B~ 69,~i 0.~ 1.6~ 42, i16 ~.~ i.6~ 64i, ~ 0. ~ i. 6~ OIL $ .SALES I~CO~ ~ GAS $ TOT~ 0 12-'9, 938 0 519, 75~ 519, 0 649, 687 649, 0 1,839, 5~ I, ~9, 0 I,~17,~I I,~17,~ ~ 7~, ~ 7~, ~ ~7, ~i ~7, 0 375, I~ 3~, 0 272,376 272, 0 201,319 ~I,3I 0 i 15, ~I i 15, 0 69, 49i 69, ~ 6, ~, ~3 6, 'EXPE~E$ OPER TOTAL 0 0 9, O~l~) 21,994 38, 000 87,975 ~, ~ 139, ~ ~, ~ 137, 7~ ~, ~ 11 I, 859 36, ~ 73, ~ ~, ~ 63, 2~ ~, ~ ~, 132 ~, ~ 51,121 ~, ~ 47,522 ~, ~ 44,895 ~, ~ 42, ~9 ~, ~ 75, ~ ~3,0~ I, 143,8~ PRESENT WORTH PRDFI~ ------NET--- ----OTHER--- DPER INCOME CT.~3 T S (RISK 75%) ~) 0 80, 9~ 3~3, 831 411,539 0 659, 9~ I 0 485, ~8 0 ~6, 257 156,854 1~, 890 75, ~65 · 33, ~43 i9, 9~6 3, ~, ~ +~CT CASH FLOW. ANNOAL ~TIVE 10.00 POWT DIS(~OL~(TE 0 0 0 60, ~8 ~, 9~ 70, 7~ 70, 73 323, 83i ~4,789 ~, ~9 337, 4~.' 411, 5~ 816, ~8 ~5, 7~ 643, 16 674, ~ I, 4~, ~I 4~], I~ 1, 1~31 ~9, 921 2, 1~, 912 ~, 619 I, 510, 92 485, ~8 2, 635, ~0 273, ~ l, 7~, ~ ~8, ~ 2, ~4, ~ 168, 724 1, ~, 31 2~, 257 3,19i,213 1~,478 2,~, 79 i~, ~ 3, ~, ~ ~, 473 2, 12~, 27 1~,8~ 3,4~,~7 4i,~ 75, ~5 3, 5~, ~ 26, 2~ ~ 193, 51~ ~, ~4 3, ~, 7~ 16,172 2, ~, ~' ~,~3 3,~15, B39 9,571 2,219, ~'~ 19, 9~ 3, 6~, 745 5, 2~7 2, ~4, ~ 12, ~ 3, ~, 348 2, 978 2, ~7, ~8~ 3, 848, 3~ 3, 648,348 2, ~7, ~3 2,227, ~ ULTIMATE GROSS CUM PROD GROSS FUTURE RES GROSS .FUTURE RES h~'T GROSS WELL COUNT NET ~LL COUNT INTERESTS YR MO WORKINT 88 7 l.~kktO0 OIL (BBL) ~S (MCF) 0 ~, I61,588 0 0 0 4, 161, 5~8 0 3,641,3~ OIL REV INT mS REV INT 0. 875~0~ 0. 8750t~ PREPARED BY: HJR EFFECTIVE ~TE: JULY 1, 196~) LEASE ID: I LEASE NAME: NORTH FORK UNIT WElL N~D~ME: STATE: ALAS~dq ~TY: KE~I FIELD: WILDCAT DPE~TOR: CHEVRON RES CAT: PROVED DEVELOPED SHUT-IN TY(tNIC SAND 8805-46, 160 A(ZFES Di~qlNAGE YE~ WELL ~NT 19~ I989 1990 I9~1 1~ 1993 1~]4 1995 19% 1~97 199~ 199~ C~01 TOT ----GROSS PRODUCTI~ - BBL OIL NEF GAS 0 583, 247 0 ~83, 387 0 403, 0 339,414 0 287, 241 0 244, 542 0 !, 50~, 452 0 8, 318, ~55 PRODUCTION ~TE FORECAST ~D E~ALUATI~ {'EQUNTAIN ALASKA ENEMY, INC. ENCLOSURE 10 ----N~ PRODUCTION ..... --PRICE BEL OIL {'~CF GAS OIL GAS OIL $ SALES I NC(YME GAS $ TOTAL 12~, 9~ 12~, 92 519, 75~ 519, ~ 649, 6~7 649, 6~ I, 039, ~ 1, ~, ~ 1, ~39, ~ 1, ~, 5~ 1,~,~ 1,~,~ 697, 89i 697, 8~ 414, 7~ 414, 7~ 2, i~, 278 2, I~, 21 12, ~, 769 12, ~, 76( YEAR TAXES 1988 ~l 1989 12, 994 1990 51,975 1~1 64, 969 1992 1{3,950 1993 1~3, 950 19~4 I{}3, 950 1997 84, 206 1998 69, 789 1999 ~, 277 ~ 49, 003 2801 41,470 F.*'8C"8 216, 628 EXPENSES. WFP-TAX DPER TOTAL ~ 0 0 0 9,800 21,994 0 36, ~ 87, 975 ~) 36, 0{~ 10~, %9 ~ 38,000 139, 950 0 3~, ik]O 139, 958 0 38, (~ 139, 950 0 3S, (k~ i36, ~ 38, ~ i~, 789 0 36, ~ 85, ~3 0 3~, ~ 77, 8 3~, ~ 7i, 3~6 PRESENT WORTH PROFILE PCNT I)SCNT $ VALLE 0. ~ 4, 858, 3% I5.~ 1,731,094 ~.00 1,34i,031 38. ~ 871,2~ ~.~ Gll,~ ~. ~ '4~, 7~ ULTIMATE GROSS CUt4 PROD GFtilSS FUTURE RES GROSS FUTURE RES NET GROSS WELL COUNT NET WELL COUNT INTERESTS YR ~ WORKINT 88 7 ----NET .... --OTHER---- [hOER INCOME CO~TS (RIS~ 50%) 0 0 53, 972 0 215, 888 0 274,359 449, 775 0 449, 775 449, 775 0 449, 775 0 43% ~I 8 3G8, 9~ 244,246 0 21k2, 513 168,617 140, 876 0 687,3[5 0 4,858, 3% 0 OIL (BEC> ~ (MCF) i) "8,318, 455 0 8,318, 455 0 7,278, 648 OIL REV INT. ~ REV INT ~1. 875~88 ~]. 875~0 ~'T CASH FLOW A~NUAL ~TIVE lit. Q~ {~T DIgCOt~TE' ~, 972 ~, 972 47, i~ 215, ~ ~9, 8~ 1~, 779 ~74, ~ ~, 219 ~, ~ ~8, 449, ~5 ~3, ~ ~, I~ 7~, ~9, ~5 I, ~3, 769 ~78, ~73 I, ~9,~ 1,893,~ ~,975 1,~, ~9, ~5 ~, ~3, 3i9 ~, 977 1, ~,~ 3, I~,7~ 1~,7~ I, ~i,~J ,2~, ~ 3, 679, ~5 ~, ~7 ~, ~, ~,513 3,~1,~8 ~,~9 ~, 114,7~ 140,876 ~, 19i,~7i 37,~i6 ~7, ~ 4, ~, 3% 115, 7~ 4,~,~ 4,8~,~ 2,316,218 ~,316,21~ PREPARED BY: HJR EFFECTIVE DATE: JULY 1, LEASE ID: 2 LEASE ~: NORTH FORK UNIT WELL lilME: STATE: ALASKA COU~W: KENAI FIELD: WILDCAT OPE~TO{h CHEV~ ~S ~T: ~OF:~SLE DEVELO~D 9HUT-IN TYONIC SAND 8005-4.6, 3~ ACRES D~INAGE ,. ' STATE OF ALASKA i(, .,diON ALAS(. ,.,,IL AND GAS CONSERVATION COM APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon [] Suspend [] Operation Shutdown ~. Re-enter suspended well 1-;., Alter casing [] Time extension ~.. Change approved program '.~ Plugging '[] Stimulate [] Pull tubing [] Amend order [] Perforate [] Other 2. Name of Operator CHEVRON U.S.A. INC. 3. Address P.O. Box 5043, San Ramon, CA 94583-0943 4. Location of well at surface 659' FEL, 655' FNL, Sec. 35, T4S, R4W, S.M. At top of productive interval At effective depth At total depth 5. Datum elevation (.iiD~' or KB) 780 6. Unit or Property name North Fork 7. Well number 41-35 8. Permit number 9. APl number 50-- 10. Pool feet 11. Present well condition summary Total depth: measured true vertical - See attached mechanical detail feet Plugs (measured) feet Effective depth: measured true vertical feet Junk (measured) feet Casing Length Size Structural Explanation- Conductor Surface t ECEIVED Intermediate ProductionLiner JA 2 1987 Perforation depth: mea~ Oil & Gas Cons. Commission Anchorage true vertical Cemented Measured depth True Vertical depth Subject well had a casing integrity test performed during April, 1986. A tubing plug was se~ at 7982' (see attached tubing detail). The casing was then pressure tested to 1000 psi for 30 minutes. A chart of that test is attached. We request approval to leave this well shut-i per the conditions of the Twenty-first plan of Development and Operations. Tubing (size, grade and measured depth) Packers and SSSV (type and measured depth) 12.Attachments Description summary of proposal [] Detailed operations program [] X - Mechanical detail, casing inte~lrity pressure chart 13. Estimated date for commencing operation BOP sketch [] 14. If proposal was verbally approved Name of approver Date approved 15. I hereby certify that the foregoing is true and correct to the best of my knowledge Signed ~'~ ~1 ~ Title I~'[~,kl~[:~., Jo{u'[ ~0~ Date Commission Use Only Conditions of approval Notify commission so representative may witness ~ Approval No. ~ Plug integrity ~ BOP Test ~ ~cation clearanceI '~ ~' ~ , .~,~..., ... ~, :~..,; . ~..,;. ..~. z .....~' "'~""~' by order of ..... ,. ., ..: .,, Approved by ,. ~ "'""' · ~ .'.,"" Commissioner the commission Date ~ " Form 10-403 Rev 12-1-85 Submit in triplicate j" .,~ 0 0 Oil & Bas ~o~. Commission I i T'o IO '~o?~ P-ID P~" ~.P_ i I RECEIVEI) JAN 2 7 1987 Alaska 0il & Gas Cons. Commission Anchorage 20 ~78, r.e --( 'i p~'-'?-roOo,:/]- '.T P-..I O Pi,.,? 1o7~,5" J 1 r, t-', IO~ I i.~-t I RECEIVED JAN 2 7 1987 Alaska 011 & Gms Cons. Commission Anchorage DEPARTMENT OF NATURAL RESOURCES DIVISION OF OIL AND GAS BILL SHEFFIELD, GOVERNOR P.O. Box 7034 ANCHORAGE, ALASKA 99510.7034 November 25, 1986 Chevron U.S.A. Inc. 6001 Bollinger Canyon Road P. O. Box 5043 San Ramon, CA 94583-0943 Attn: Mr. W. 3. Vasilauskas Manager, Non-Operated 3oint Ventures Subject: North Fork Unit Well #41-35 Casing Integrity Test Dear Mr. Vasilauskas: I am in receipt of your letter of November 20, 1986, requesting written approvai from the State of Aiaska of the Sundry Notice regarding the casing integrity test of the North FOrk Unit Weii No. 41-35. Please be advised that the Division of 0il and Gas does ,not approve Sundry Notices for weiI tests.. 'I am forwarding your request to the Aiaska Oii and Gas Conservation Commission for its action, if such action is' within its domain. Yours truly, · .Catherine S. Fortney ~ . Unit Manager / cc: Commissioner C. V. Chatterton, AOGCC 3189A RECEIVED DEC 0 1 1986 A!,-,..,,".', r~i~ & (~as Cons. Commission .~r, chorage Chevron ( Chevron U.S.A. Inc. 6001 Bollinger Canyon Road, San Rarnon, California Mail Address: P.O. Box 5043, San Ramon, CA 94583-0943 Production Department Western Region W. J. Vasilauskas Manager Non-Operated Joint Ventures November 20, 1986 Approval of Casing Integrity Test NFU #41-35 Ms. K. Brown, Director Division of Oil & Gas Dept. of Natural Resources P. O. Box 7034 Anchorage, AK 99510 Dear Ms. Brown: Chevron U.S.A. Inc. has still not received written approval of the Sundry Notice concerning the casing integrity test of North Fork Unit well #41-35. Please send us an approved copy so that we may complete our, records. Any questions may be addressed to Mr. J. G. Brookley (415) 842-0321. Very truly yours, OGB'bms IRECEIVED NOV 2 5 D1V)SION OF OIL & GAS ANOHOiP~GE,. ALASi(A .... RECEIVED DEC 0 ! 1986 AI~s~ Oil & Gas Cons. Commi~/Oil Anohorago · , · (F~rmerly 9-331) DEPARTMENT'oF'THE i'NTERIOR.c,,'u'"er-'d,)'"'trucu°"' o,, r,- BUREAU OF.,.' *'ID MANAGEMENT SUNDRY NO:I'ICE ' REPORTS ON WELLS iD. not ue this form for proposals to drill or to deepeu or plug back to · d~f~erent reservoir. Use '*APPLICATION FOR PERMIT--** for such OIL ~q~ GA1 D OTHEI w EI, L W ELL 2. NAME Or Chevron U.S.A. Inc.. 3. AnnaEBs oF OI'ERATOB P.O. Box 107839 Anchora§e, AX 99510 LEASE DERIONATION AND IBitlAI, NO. A-024363 Ir INDIAN, ALLOTTEE OB TIZBI NAME ?. UNIT AGREEMENT NAME J. LOCATION OF WELL (Report location clearly and In accordance with any StAte requirementa, o Se~ also space 17 below.) At surface 659' FEL, 655" FNL Section 35, T4S, R14W, S.M. lA. ELEVATIONS (Show whether ur. rE. GU, etr,) K.B. = 780' North Fork North Fork WILL HO, ~1-35 10. fIELD AilD POOL, OR WILD~AT Sec. 35, T4S, R14W, S.M. Kenai J Alaska 16. Cl~ecJc Appropr, ale Bo~c To lndicale Natur~ of Notice, Report, or OtJmr Data NOTICB OF INTENTION TO: SHOOT On ACIDrZ" ABANDON' '(Other) LEAVE SHUT IN SUBftEqUBN~ B.BPOI~r OF: FRACTURE TRE&TMEilT ALTERING CASINO SHOOTING OR AClDIZING ABANDONMENI~e (Other) , (NOTE: Report results or multlp3e eompleUon on W~ll Completion or RecoLnpletlon Report and log form.) U~:S¢'KZnE rnOl'OSgD OR COMPLETED OPEBATIO.'~ (Clearly state all p,.rtlne,,t details, and ;lye pertluent dates. Including estimated date of sL~rtinr any proposed work. Xf well is dlr~cUonnJly drilled. ~ive subsm'f~ee locations and measured and true vertlen3 depths for nil mtrkers and sones perU- nest to th;s wor~.) ' Subject well had a casing integrity test performed during April, 1986. A tubing plug was set at 7982' (see attached tubing detail). The casing was then 'pressure tested to 1000 psi for 30 minutes. A chart from that test is attached. We request approval to leave this well shut in per the conditions of the Twenty- First Plan of Development and Operations. RECEI.VED DEC - 8 1986 Alaska 0ii & Gas Cons. Commission " Anchorage certif t. ha. the foregoing SIG/~TED (This spa r Federal or S~te offic~ use) is trde and correct TITLE APPROVED BY CONDITIONS OF APPROVAL, L~ AN~: TITLE DATE *See Insl~u~ions on Reverse Side Title 18 U.S.C. Sebtion 1001, makes it a crime for any person knowingly and willfully to make to any department ur ·gency of the ' United States uny false, fictitious or fraudulent statements or representations as to any matter within its jurisdiction, ! /,-' ~v~a 9 RECEIVED ' DEC - 8 '. .. Ala.ska Oil & 6as Cons. Oomm!~s;on Anc~ora~ I, · I i.,3- t ! · mmm P/u'c,- / oc/~,~_ /0,=/',.5,,.3- ~._ ,, _ DEC Alaska Oil · t~as Cons. IN REPI,Y REFEII TO: United tates Department of the I terior GF. OI.(')GICAI~ SI.'R VEY Box 25046 Denver Federal Center Denver, Colorado 80225 Office of Energy Resources Branch of Oil and Gas Resources January 5, 1977 Mr. Thomas R. Marshall Chief Petroleum Geologist Division of Oil and Gas 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Marshall: Enclosed are the results .of our analyses of samples from the following wells, furnished to. us by your office. Standard Oil Company of Californi~ Sec. 35, T45, R14W SM Standard Oil Company of California Anchor Point No. 1 Sec. 10, T5S., R15W SM Our general interpretation of these analyses is that both sections are thermally imma'ture with respect to liquid petroleum hydrocarbon generation. In addition, the organic matter in most of the sediments analyzed does not yield a significant amount of .hydrocarbons upon pyrolysis (Pyrolytic HC/ Organic Carbon < 20%)~ suggesting that the sediments are not potential oil source rocks. An exception to this generally unfavorable oil source potential is the deeper part of the North Fork section (i.e., from 11,900 to 12,500 feet). Samples. from this interval have very good organic richness (,~2% organic carbon) and undergo relatively high conversion of organic matter to hydrocarbons upon pyrolysis (pyrolytic HC/Organic Carbon > 40%). The organic matter in these sediments is, however, thermally immature at this locality, .and would appear to require further burial metamorphism equivalent to about five thousand feet of additional overburden to be considered effective oil source rocks. The organic-rich (dominantly coaly) Tertiary section is. known to be productive of gas. Our investigations are primarily aimed at evaluation of oil source potential. RECEIVED .'J^tt ;, 6 l Tr Copy t°: L. ~3,~!~!,M..F~p~~ grltt G,~9 C,, ,, , Sincerely, George E, Claypool, Research Chemist Branch of 0±1 and Gas Resources SOC'~L-iq~.'.th Fork Unit 41-35 i"' ~ch cuttings 'It~em Depth Organic Pyrolytic HC Volatile HC Interval Carbon yield content (ft.) wt. % wt.% ppm 1. 1500-30 1.19 0.25 610 1830 1380 540 2. 5010-20 16.2 3.00 3. 5530-40 17.2 3.80 4. 6150-60 3.69 0.53 Pyro I. HC Org. Carbon % 21.0 18.5 22.1 14,.4 Tmax oC 460 464 458 462 lith Description, coal/f.g./clastic 5/95/0 20/40/40 40/20/40 lO/2O/7O 5. 6610-2- 4.62 0.65 6. 7100-10 36.8 4.60 7. 7740-50 30.2 3.77 . 8. 8220-30 12.9 1.50 9. 8890-8900 '14.8 10. 9260-70 15.1 11. 10,240-5'0 12. 10,540-50 15.2 14.8 260 1510 1330 580 2.90 1090' 14.1 12.5 12.5 11.6 19.6 3.'10 770 20.5 2.76 790 17.8 2.'20. 720 14.9 460 452 458 456 458 460 462 460 15/857o 7O/lO/2O 8O/lO/lO 6o/3o/lo 40/40/20 50/30/20, 30150120. 40~30~30 ~3. 10,890-900 4.76 0.45 93 9.5 462 15/8o/5 14. 11,060-70 4.33 15. 11,340-50 2.28 ~6. 11,520-30 1.82 ~ . O00-10 2 26 7 11, . .8. 12,060-70 1.87. ..cl. 12,300-10 2.15 0.68 225 15.7 462. 0..30 110 13.2 464 0.38 135 20.9 464 1.00 430 44.3 46.2 0.55 190 29.4 464 0.89 225 41.4 464 15/7o/15 5/70/25 5/85/lO 0/95/5, 0/90/10, 20. 12,49.0-500 21. 12,780-90 1.87 1.40 0.15' 120 10.7 , .. 0.82 260 43.9 466 464 o/9o/lo 2/88/lO SOC,~U-An'_'hor. Point No. 1 - Dj" ~Item , Cuttings Organic Pyrolytic HC Volatile HC Carbon yield content wt .% wt.?o ppm 21.0 3.08 960 Depth Interval (ft.) 1. 5090-5100 2. 6050-'50 3. 7000-10 4. 7980-90 5. 8840- 50 6. 9100-10 ' 9590- 9600 B. 10,030-40 9. 10,220-30 ]0. 10,730-40 1l. 11,110-20 11 , 350-60 13. 11,640-50 14. 12,140-50 15. 12,340-50 "6. 12,800-10 1.7. 13,120-30' lB. 13,720-30 19. 13,990-14,0'00 20. 14,340-50 14,510-00 15.0 2.03 770 9.34 1.60 530 6.38 1.22 500 2.30 0.33 110 1.23 0.14 220 4.12 0.50 220 1.93 ,0.30 270 1.41 0.25 190 1.1i 0.10 140 8.66 1.22 380 12. 0.95 0.'09 140 1.72 0.54' 0.45 8.66 0.24' 200 0.06 100 0.05 100 0.90. 280 0.98 0.15 1.07 0.18 1.94 0'.25 0.68 0.10 !70 170 190 180 21. 0.78 0.14 2.0 Pyrol. HC Org. Carbon % Truax oC 14.6 462 13.5 458 17.1 462 19..1 460 14.3 468 11.4 468 12.1 462 15.5 466 17~7 464 9.0 .466 14.1 460 9.5 464 14.0 466 11.1' 464 11.1 468' 10.4 462 15.3 470. 16]8 472 12.9 466 14.7 470 17.0 470. lith Dcscriptiop coal/f, g.~c last~ c 50/30/20 '"~'* ...i 25/75/0 ~ 15/65/20. 30/30/40 ,' 15/8o/.5 5/95/o 5/85/lO lO/9O/O 2/58/40 2/70/28 35/50/15 2/90/8 5/75/2O 2/50/48 0/50/50 40/30/30 2/49/49 2/58/40 6/50/50 o/5o/5o 0/70/30 ' ' SOC%L-North Fork Unit 41-35 - Ditch cuttings Item Depth Organic Pyrolytic HC Volatile HC Interval Carbon yield content (ft.) wt. % wt.% ppm 1. 1500-30 1.19 0.25 bi0 2. 50]0-20' ]6.2 3.00 1830 . . . 7. . . 10. 11. 12. 13. 14. 5530-40 17.2 6150-60 3.69 6610-2- 4.62 7100-10 36.8 7740-50 30.2 8220-3'0 8890-8900 9260-70 12.9 '14.8 3.80 o.53 0.65 4.6o 3.77 1.50 2.90 15.1 3.10 10,240-50 15.2 2.76 10,540-50 14.8 2.20 1.0,890-900 4.76 0.45 11,060-70 4.33 0.68' 2.28 1.82. 2.26' 1.87 15. 11,340-50 16. 11,520-'30 17. 11,900-10 18. 12,060-70 19. 12,300-I0 20. 12,490-500 21. 12,780-90 2.15 0.30 0.38 1.00 0.55 0.89 1380 540 ,260 1510 1330 580 1090 770 790 720 93 225 110 135 430 190 225 Pyro 1. HC Org. Carbon 21.0 18.5 22.1 14,.4 14.1 ,' 12.5 12.5 '11.6 19.6 20.5 17.8 14.9 9.5 15.7' 13.2. 20.9 44.3 29.4 ' 4'1.4 .1.87. 0.82 260 43.9 1.40 0.15 120 10.7 · Tmax oC 460 464 458 462 460 452 458 456 458 460 462 46'0 4'62 462 464 464 462 . 464 464 466 464 ltth Descripti( coal/f, g./clast' 5~95~0 20/40/40 40/20/40 10/20/70 1518510 70/10/20 80110110 60130110 40/40/20 50130/20 30150120 40/30/30 .siso/s .15/70/15 5/70/25 5185110 o1 o/ o 0/95/5 0/90110 o/9o/lo ~-/88/1o RECEIVED ~)lvt~lot~ et '011 ~tld ~a~ ?SD 32 (Rev. 4.67).-Prinlud in U.S.A. ( "~ J .... ' * ~ '~' '*: '"" c ~ il S;-IEL~ DEVELOPME'[~T COJ~P -~Y TO' ALASKA EXPLORATION DIVISION DXTE DECEHBER 6, 1976 ATTN' GRANT VALENTINE GEOCHEMICAL SERVICE REFERENCE SUBJECT SOtJRCE ROCK AND MATURITY STUDY, STANDARD OF CALIFORNIA NoR'rll FORK UNIT NO. 41-35., SFC. 35 T4S R14W, SI/WARD IIM., COOK INLET BASIN, ALASKA I attach a letter that you may use to transmit the results of our geochemical study to the State of Alaska. This information should suffice to comply with our agreement to release the results of our studies to the pub 1 i c. Attachment JRC/vl - cc' J. R. Casta~o (w/attachments') DIVIS~,;.)I,I Oft C)i'I :.",i",i!.~ GAS A. NCi-ti?~i; >.. ¢'~ SOURCE ROCK AND MATURITY STUDY STANDARD OF CALIFORNIA NORTH FORK UNIT NO. 41-35 SECTION 35 T4S R14W, SEWARD B & M., COOK INI.ET RASIN, AI.ASKA DECEMBER 6, 1976 Vitrinite Reflectance Study A total of 13 ditch samples were prepared for vitrinite reflectance study. For the shale samples, the vitrinite was concentrated by non-oxidative acid solution of the inorganic matrix. Standard A.S.T.M. procedures are followed for polishing and examining the specimens. The results of the study are summarized on the individual histograms and on the table shown below. On the histograms, each vitrinite reflectance reading is shown to the nearest 0.01% reflectance in oil (%Ro), and the values are summed up for each 0.1% Ro group. In the table, the maximum and minimum reflectance give the extremes in the readings, the (arithmetic) mean Ro is given with the limits of uncertainty calculated for 95% confidence limits. TABLE 1 VITRINITE REFLECTANCE STUDY .I]EPTH,FT, ,LAB. NO. .SAMPLE TYPE MAX RO% ,MIN RO% , MEAN R0+-95% CONFIDENCE LIMITS 11990-12110 13116 Ditch .54 .28 .39-+...02 11990-12000 13107' Ditch,Coal .45 .31 .38-+.01 12090-12100 13108' " " .63 .32 .45_+.02 12230-12240. 13109* " " .62 .43 ,53+-.01 12230-12420 13117 " .67 .27 .42_+.03 12240-12250 13110* " C6al .67 .27 .49_+.03 12330-12340 13111* " " .58 .39 .51_+.02 12400-12410 13112* " " . .66 ' .36 .53+.02 12540-12590. 13118 '" .80' .26 .43-+.03 12570-12580 13113* " Cbal .'62 .37 .53-+.01 12670-12680 13114* " " .58 .37 .. 50-+.'01 12670-12810 13119 " " .60 .31 .39+-.02 12730-12740 13115* " Coal .69 .36 .51_+.02 * These samples are coals, which were prepared without using any acid treatment. OlVlS~(')i<l OF 011 AND GAS SOURCE ROCK AND MATURIlrY STUDY STANDARD OF CALIFORNIA NORTtl FORK UNIT NO. 41-35 SECTION 35 T4S R14W, SEWARD B & M.~ COOK INLET /I/~SIN, ALASI'.,\ DECEMBER 6, 1976 Page 2 In c~rder to ol~tain hetter data from the very small samples, we hand picked coal ch'il~s Frul, s(:vera'! inLervals. The data from the coals provide good data needed to determine the burial history. Some of the methods used to determine 'the burial metamorphic. history are summarized in the attached table taken from a publication by Hood and CastaHo. These methods are related through the use of the LOM (Level of Organic Metamorphism) scale reported by Hood et al in the AAPG Bulletin. The teChniques for measuring the level of organic metamorphism reflect the irreversible effects of temperature and time, hence, of thermal history. Therefore, the reflectance data can be tied readily into the LOM or coal rank scales. Source Rock Richness Studs_ To evaluate the organic richness of the ditch samples, we deter- mined both their organic carbon (Corg) and the effective carbon (Ceff) contents. Organic carbon, or acid-insoluble carbon, represents the total amount of organic matter in the rock, and it is determined by measuring the total amount of carbon dioxide evolved during combustion of an acid-treated sample. On the other hand, effective carbon reflects the 'fraction Of organic c~rbon which is thermally convertible to petroleum. As estimates of effective carbon, we used two laboratory pyrolysis, procedures. One method,, pyrolysis- fluorescence (PF) is a rapid means of evaluating the petroleum generating potential, by measuring (in arbitrary PF units) the amount of fluorescing bitumen generated on heating. PF values in rocks can range from zero to several thousand units. For additional data, refer to Heacock and Hood (1970). The .second method, pyrolysis-FID (P-FID) provides a measure of the amount of organic matter which can be converted thermally to hydrocarbons. A small amount of sample (less than 200 milligrams) is heated in.a flowing stream of pure nitrogen at temperatureS increasing from room temperature, to 7507C at a rate'.of'25°C per minute. The volatile organic compounds are'distilled~t temperatures less' than about'300°C. At higher temperatures .nonvolatile organ, ic matter is pyrolyzed to form volatile hydrocarbons. The di'stillation (D) and pyrolysis (P) products are carried (by nitrogen) to a hydrogen flame ionization detector (FID). The FID signal can be converted to precent .hydro- carbons or percent carbon by calibration with a petroleum wax. For further 'data on the method and 'instrumentation see Eggertsen and Stross (1972). Non-carbonate carbon was run on sixteen ditch samples, (Table 2). These samples were mostly shale and siltstone, as most.of what little coal there is was-utilized for other studies. SOURCE ROCK AND MATURITY STUDY STANDARD OF CALIFORNIA NORTH FORK UNIT NO. 41-35 SECTION 35 T4S R14W, SEWARD B & M., COOK INLET BASIN, ALASKA DECEMBER 6, 1976 Page 3 TABLE 2 NON-CARBONATE CARBON ANALYSIS DEPTH, FT. Il900-11910 Il910-11920 990-12000 12DO0-12010 2090-121 O0 12240-12250 12330-12340 12340-12350 12400-12410 12410-12420 12540-12550 12550-12560 12570-12580 12580-12590 12680-12690 12800-12810 LEACHING FACTOR(1 ) .8O57 .7558 .8223 .7609 .7716 .7732 .8013 .7714 .7752 .8157 .7830 .7289 .7525 .7790 .7722 .7562 WT. % ORGANIC CARBON, CORG(2)- 2.29 1.65 1.86 1.58 1.54 1.45 2.48 2.42 3.09 2.30' 2.02 2.23 2.16 2.22 l. 68 '1.74 (1) WT .Leached Sample Wt Original Sample (2) Wt~ Carbon Wt.. Original Sample X 100 Pyrolysis -FID Data are summarized on the attached source rock log 'plotted at a scale of one inch equals 100 feet and on Table 3. As shown on Table 3, we ran coal and shale .samples separately for P-FID.. However, we iran the original unpicked sample for pyrolysis-flurescence. And, as only a few cOal chips ran. gave a very high reading, .the PF and FID values do not correspond in all cases. SOURCE ROCK AND MATURITY STUDY STANDARD OF CALIFORNIA NORTH FORK UNIT NO. 41-35 SECTION 35 T4S R14W, SEWARD B & M.. COOK INLET BASIN, ALASKA Page 4 TABLE 3 PYROLYSIS-FID STUDY DEPTH', .F~. SAMPLE TYPE D/P RATIO llgO0-11910 Il910-11920 11990-12000 12000-12010 12090-12100 12100-12110 12230-12240 12240-12250 12330-12340 12340-12'350 1.2400-12410 12410-12420 12540-12550 12550-12560 12570-12580 12580-12590 12670-12680 12680-12690 12730-12740' 12790-12800 12800-12810 DECEMBER 6, 1976 TOTAL HC YIELD WT % Ditch, picked shale .044 1.939 " " " .031 2. 550 " " Coal .018 5.545 " " Shale .020 .1.912 " " " .030 O. 417 " " " .033 O. 497 " " Coal .009 2.564 " " Shale .48 O. 197 " " " O. 037 O. 838 " " " .028 1.45,5 " " " ..038 . .768 " " " .031 " ' 1.225 " " " .024 ' O. 707 " " Coal .044 0.929 " " · Shale .067 0.324 " " " .022 1. 773 " " " . O19 .624 " '" ". .023 1.46.4 " " " .020 1.234 " " " .035 1.031 " " " .113 .349 References Eggertsen, F.T. and Stross, F.H., 1972, Flame Detection Method for Determini]ng Organic Carbon in Water, Anal. Chem. V. ,44 P709-714. Heacock, R.L., and Hood~ A.., 1.970, Process for Measuring the Live Carbon of. Organ.ic Samples, U. S. Patent 3,508,877, April 28, 1970. Hood, A., and Casta~o, J. R., 1974, Organic Metamorphism: Its Relationship to Petroleum Generation .and Application to Studies of Authigenic Minerals, CCOP Tech. Bulletin, Vol. 8, P.85-118. , RM-IO0 (4.71) '1 ~ RM.IO0 (4-71) SHELL OIL COM;., Y SOURCE ROCK LOG STATE OR PROV~ Alaska | COUNTY ~ Anchora~ze Basin 1 ~ FIELD OR ~I~EA _ I_ _1_ Standard of Ca].iforni~OMPANY N~--35 SURVEY BLK. ELEV. COMM, COMP, SHE',;, 3IL COMPANY SOURCE ROCK LOG STATE OR PROV~ Alaska / Standard of Californi~OMPANY i' COUNTY / i I 1N°rth F°rk Un~tT. R. NO'41--35 Anchorage Basin ' i I [ ~ FIELDOR AREA I -3 ~ SURVEY BLK. ELEV. COMM, COMP, T.D. PRODUCTION ELEC. LOG RADIOACTIVE MICROLOG LATE RD LOG T,D, PI{ODUCTION ELEC. LOG RADIOACTIVE MICROLOG LAT'(": Ir:lO LOG ~~ Std. = 36 ± 2 units. Scale is 1" = 100'. Zero to five is plotted as five by plotter. SAMPLED BY: DATE ANALYZED BY: J. M0hundro DATE PLOTTED BY: N. West DATE >' TOTAL FLUORESCENT UNITS O SCALE O T . o o o t-. · 0 0 0 0 0 0 ,0 '.3' "'.7;... ~~:i ~ ~'; ~ ~'.: I I l i'.i~ , , ,, . .... ! I i ,, TM~'T~'' I" i i t,, , 1'-~4-~:i ............ ~,i. '. ~'~ ! I';~ ~ , ~ .~"Y.'..Y.'.'.. ". ::} I ~: , ~ ' ,~ ' I ~ ;~,1 ~ ~ , " ' ~' ~ ~ ~':':"~ ' ' 'il~:' '}' ',:':' ,t,~ , - ~''"i ,:,' ~ ,~ ,;~1 DEPTH AND REMARKS 'i2000 ....... Scale is 1" = 100'. SAMPLED BY: DATE ' ANALYZED BY: M. L. Weiss DATE N. Wes t PLOTTED BY: LU DATE >- .i 0 I , '1 ~:Y ROL Y S IS" F, I WT -%-J. DEPTH ' AND REMARKS 12000 ....... . , J ,1.O ! !"lO[O. : , ' , : , ' ,'=-7;"r- ~.~.~oO ii ' ...... ~oo - 'i' :'.,", , ,", ,,,,,' : i:~:~,,, ' ~'.!:' ~? ',, · .... i Il ' '.':" I ' ;,. '''t .... ; 4-4-; ....... ;_J... '; , ; ...... .. I;, ''1. I ii',' :': ':"J--" 'ii,j,. Ill i i,~.. ,, ;t.. i iii i.I !F'-t'''- ................... i.:, i;::i! ..i ~:!i! - :J26oo .... "-' · :;" 12()()() ........... ,. , i r '1'"1 i ' "{'~oo ..... .1.2400 '--12500 ,,. .... 12800 . ....... ..... i'f~66 ].2400 ........ t' -- .......... 12500 -- ""-i'2 C~ob .... 12 700 -- 12800 - J , COAt SPORI' CARP, ON- IZA1 ION 8UT,JAH~ BLACK 1'IIFRMAL ALTERA11ON INDEX STI, PUN (i.~.~ r~m. I- NONE IYELLOW! 2-SLIGHT (B. ROWN- YEILOWJ 3-MODERATE 3.5 {BP, OWN} - ~: 4- STRO,%IG JSLAC. K) VITRINITE REFLECTANCE INIERNA~ CASTA~O, HOB~OF THIS PUBL COAL IRe. Az) PCTROGR.! Figure VII-4. Some scales of organic mctamorpl~ism (Hood et al., in prcss). .. CDk,!PANY -' STANDARD DF BALIF-BRN]:A %;'ELL BR @'UTCRE',P - NDRTH F@RK NB- ql-35 DEPTH Ei'R SAMPLE- ND. - 1 lqDD 1211D · LAB NB. - 131lB. · L@CATIBN - 35 4S iq?l STATE - AK .- o 18. (Il Z 14. .0 H I- tm. <: .IF E~ 3. O. o . I i , . , i I I i I i I I I i I I i 1 d d d - ,,; ,.. -. PBBBT o. ~,,,:i. ,..~, ST^NOARO BF CALIFBRNI^ . . ?,?L_L BR ~UTCRSP - NBRTH' ~-m~,,- . r ~.:m~ NB 41-35 DEPTH B...R SAM?LE N@. - 1 lCt°D 12DOD "LAB NE). - 13107. L@CATI@N 'SS 45 ; STATE- AK lq. '118. iS. -- 7 1-4. H 13 !- ' > · El ~o. Z ; . .o · ,i .o %. · - ' PERCENT · CB~i, aNY - STANDARD BF CALIFI~RNIA t'IELL F~R BUTCRBP ' N~RTH F@RK N@. 41-35 ' DEPTH NR SAMPLE NB. - 120cD 1210O .. LAB NB. - 1310@ · , LBCATIBN -35 4S 14~ · . STATE - AK '- 20. lq. 18. 17. 16. b-Il! 0 . 4. 1. PERCENT CB~,,,'P^Igf - ST^I,D^RD BF CAI TF@RNIA V.,"ELL aR @UTDRD-P-- N@RTH F@RK N@. 41-3S DEPTH ~R S~t,~PLE. ND. - 12230 12240 LAB ND. - 1310R L~CATIDN - 3S 4S 1471 " STATE- AK 20. 17. Z ~.4. .D 12. m' 121 . Oo ! ci 6 6 '6 .......... B~t-.,'P^l',h' - STANDARD @F B^LIFIgRNIA VtELL ~R BUTCRE)P - I,,JEIRTH F'~RK NB. Zl DEPTH EIR S^I,,PLE NB. - 12230 124213 . LAB NE).' - 13117 LDC^T]:~N - 35 4S STATE- AK > I~. - ~] 0 IL 12] .~' .17' .4, O. 1]' 0 EDN~ANY -- STANDARD @F EA LIFDRN]:A ~'~'D !~ BR @UTIZ:R~P - NDRTH F@RK ND. 41-3S DEPTH DR 'S^!~PI F. N@ ' - -12330 123.-40 LAB ND. - 13111 L@E^-I-Z@N - 35 4S 14~'1" STATE- AK 18. 17. iS. -. · o. · 21. - :20. I8. 17'. !3. I-'1 1 1 3°- I': Eik, IPA NY - STANDARD BF CAI ]-FIgRNZA ~IELL BR BUTCR~P - NBRTH FEIRK NEt. q l-3S DEPTH @R SAI,:~LE NB. - 12qOD 1241D' . . LAB NB. - .13112 LIgCATIBN - 35 4S lq.',',' STATE- AK 2.- 1. CE!i,/~ANY - STANDARD BF CALIFBRNIA -WEll ~ BUTCREIP - NBRTH .FBRK NE). 41-3S . DEPTH ,BR SA~PLE I~. - 12540 12SqO ~ _' _' _' _' _' _' _' _' _~).. LAB NE).. - 131 itS' LBBATI@N -' 35 4S lqW · STATE- AK .. · ::20. Ici. 17. _~ 10. El' bJ 7. lB. -4. 6 d 6 .. d -d d -. d -, d d ........... r~ · t · " ' ' PE.I~iCENT : · . . . C@WP^NY - STANOARD @F CALIFBRNIA ~;ELL ~ BUTCF~P - N@RTH F@RK N@. 41-35 LAB ND. - 13113 LBCATIBN - 35 45 DEPTH I~ SAMPLE I',D. - 12570 12580 .o STATE- AK Zl4. [] - H ~.3. .<: > 12. ~ - [] ffl '7'. '~ . ' 2. .' pERCENT -. .-o C~V?^NY - ST^NO^RD @F C^LIF@RNI^ LAB NE]. -' 13114 o. .. . ~'tEL.L BR BLJTCR-~,P - N~'RTH F@RK ND. 4i'-35 L@CATI@N - 35 4S DF_Pm m S^,~! F I,~.- -- 12S70 12SBO '~ ': " SI^-i'~' ---/~!~ _ ~" ' '~'- -' -, - .. . '.. . . ,~ .- ..... .. - . . ' -- : -.o' .. . ~ . . _ ''..:. - % · . - ___ · . .. - . _. ~- o . . -. . , -' .- '% . o .- . · . .: :' · · - -. . - .? ' .- '~ ~ ' .. '~. . . . ~ '' - .. . _ : . -. . -_. -' .~ -- . , - _ '.-. . .. -.'. . . ..... - . . · · - · _ - . . : · . _- ..... -. .. _ -~ .- .. .- -. . . -% .~ . -~-'... ~.~. . -. . : · . . ' .... ~ :. . .. - . ........ .' _, ', _ . .: · - . .. -" . -' '.-_"- . - ' ~ . . . . . . - . . . . · · _. · ._% .. . _ _ . · . · . _ . · - -. . .. . : . . . - _. -. · _ J i I i I I I I i I I I I I I I i i i i I I I i i I I I I I i *' I l~ _ 15. 12. ~o. - _. . ... . .. . . CBN,~ANY - STAkOARO BF CALIF@RNIA ~'~EI I ~,R BUTCRBP - N@RTH F@RK NB. 41-35 DEPTH ~R SAt,~PLE N~. - 12~70 12810 LAB' NB. - 1311q' LBCATI@N - 3S 4S 14',~' STATE- AK < > ~:2. I_..! 1 ! [] to. ~.q. 6 6 6 '6 6 d 6 d d 'd-. " ...... · · o. 3. CBMP^NY - ST^NO^RO BF C^LZF'BRNI^ ,,'lB L BR BLITCR@P ". N'SR~. FBRK NB. 41'-35 . . . . I . _ y. · . . . . -. - . ._ ,,. · .. .'.~:~.' . ', - . · . - . . ~'~ .. ... · . . . .. · ~. · . · . . ' .. . _ - · - . _. · , : - o. . , - : . · I · . . .~_ _: ....... .. . . .- - . . - I ·, . .'* -.- . · ~- .. ...... · ' ' --.;T - , - ~ .. . . _ , . . .- ~ . . -: - ___ ._ -_ ...... = - --o . . .. °. .. . .. - . . -. ~ . ~ __ ,;''" o ' . o 7'' · . . . . . . . ' - - ~ -'7-.-- - · - - o . .... . _ · _. · _ - '-- _ ..-- - TI __ ~ a ~ i' I'i { I i i ' I I i i i ' · "i" i I i i - I i'' i ' { I i I i I ' 'i ' ' I I i -- .. ~ ~ - ,A - - ~,h I. ~ ~ f '. LBBATZBN - 35 AS lqW..' . · DEPTH BR SAMPLE ND. - 12730 127413 ... ST^-i~ - AK -' .., ... · d '- d d d - - . . .. ,. Cook Inlet, Alaska Summary of brief petrographic study of eight thin sections from cores of the Socal 41-35 North Fork Unit well, sec. 35, T.4S., R. 14W., S. M. Study by: Bela Csejtey, Jr. Alaska Mineral Resources Branch U. S. Geological Survey Depth of core samples: 11,537, 11,544, 11,700, 11,708 Rock name: volcanic graywacke Rock material (predominantly of volcanic origin): Crystals plagioclase K-feldspar hornblende biotite quartz magnetite zircon clinopyroxene. very small amounts Alteration products (various amounts) sericite clay .minerals epidote chlorite Rock fragments of approximately andesitic to latitic compositiom, with devitrified matrix, containing plagioclase and hornblende phenocrysts. Few fragments appear to be chert. Texture: Ail crystals occur as separate broken angular grains. Many feldspars are slightly altered and have a "cloudy" appearance. Ail hornblende is fresh. Rock fragments are subrounded, Sorting is fair. There is only a minimal amount of matrix. Rock has a clastic texture and shows bedding or stratification. Deposition: Probably under water Most rock material derived from nearby volcanic tuffs (crystal tuffs and/or lithic tuffs) Very short transportation Volcanic material mixed with very minimal s.~,'~m~[~ ,t~,"i~ ~i~, non~.. ¥.~l..~an~ic origin ~.,~,f ~,,-.~ ~u; , ,. .... Fast rate of deposition ., ....... ~,," , ,. .... ~....~ O.~V~Sf "" ~ ~'", .... ......... .,. (')fi. ,'<~..,~.'-~:. ,.., ~ ~., .,'.,., ~, .' r -~, ~ ..,... .... To the Oil and Gas Supervisor United States Geological Survey' Anchorage, Alaska . . Tmm OF DEVE 0? E ORE FORK um: ' AREA ! -o8-ooo .-867 .... -- . . - ~ . The North Fork Unit Well No. 41-~5 was completed as a gas producing well on De6e~be'r 20, 1965, and was thereafter shut-in as no market now exists for the gas which might be produced therefrom. T_e_s.~ts t~e__t~ma_~t.~aa~_hut,in established the o~en flow ~otenti. al of the well at .~_~_!0~MCF~/~D_._ .an_d~,,.9~pable~0f P~0ducin_ : g ga.~s_.~i~n payi~_~.~n~.~uant~iti~_es. Purm;e_nt to the provisions of Section 10 of the North Fork Unit Agreement.,' Standard Oil Company of California, ~s Unit' Operator, proposes the following Plan of D, evelopment and Operation for th~ North Fork Unit Area ~6r your approval: · . A. PERIOD ' This Plan shall cover the period from June 20, 1968 to June 20, 1969. B. DRILLING PROGRAM As there is no market outlet for the gas deposit found in the Unit Area, Unit Operator proposes no further drilling operations in 'the' Unit Area during the period of this Plan unless either .a market develops which would Justify further drilling, .or the Secretary of the Interior determines that further drilling is necessary for timely development and proper conservation, of the oil and gas resources in the unitized area. In the event either contingency.. occurs, Unit Operator will submit its proposal for drilling o~.er- ations as a supplement' to this Plan. . · C. PRODUOTION PROGRAM ~nit Operator proposes to use all diligent effort to work towards developing a ma_~ket for the gas found in the Unit Area, which will Justify producing the North Fork Unit Well No. 41-35 and further developing the Unit 'Area. The Unit Operator reserves the right to propose modifications to this Plan if economic conditions or geological requirements so warrant; however,' no modi- fications of this Plan will be made without first-obtaining'permission from the U. S. Geological Survey. -. ~e Unit Op.erator respectfully requests the Supervisor of the U. S. Geological Survey to approve the foregoing as the Third Plan. of Development and Operation for the North Fork Unit Area. STANDARD OIL COMPAI~Y OF. C~RNIA UNIT OPERATOR - ' '~'} ' : ' " ' ~""~'/ ' ~' " " ' 'i'. .-.. .. C. V. Chatterton -District' Superintendent-'':''- ':-'.':." : . . -.... -: .. . .. . . .- -. . . -. .. . · . . . . . . . .. . . . . .. .. - . . . - . -. _ . . · . -. .. .. EXPLORATION DEPARTMENT ANCHORAGE DISTRICT R. I. L. EVORSEN DISTRICT SUPERINTENDENT P. O. BOX 7-839 ANCHORAGE ALASKA 99501 ADril 1, 1966 State of Alaska Division of Mines & Minerals 3001 Porcupine Drive Anchorage, Alaska Attention: Mr. T. R. Marshall, Jr. Gentlemen: In accordance with the Oil & Gas Regu~lation ~2007. ~l of the State of Alaska, ditch samples and core samples from cores 1 through 6 from the Standard Oil Company of California, Operator, North Fork ~41-~5 Well, Section 35, T-4-S, R-14-W, S.M., are hereby transmitted to the State of Alaska. Yours very truly, · I. Levorsen // ~ DLM: s c Enclosure Date:Received .... by:~7~~,, .........-"'/~'/ ............. ,, ,'~~ , i"~ ~": STANDARD OIL COl ' ANY-OF CALIFORNIA,~. ' "" i~f~;~ .... ..... ' ........ "' I~' ~"':' :' ":* " )- "'' * ' ' ' :' """~ ~ . I ~ I '.. "-": ..... - .... ' ~ .""" - ~ .' , ~, c,: ~:. · "~::'~"":'?:'-' ~l .'- WESTERN OPE~TIONS, INC. :' -'~~'~~~[[:~I= .~?.~ . '" ""'~'" "'";~J'::L~::""f ~ ' MONTHLY wELL PRODUCTION ~ ~W ~tt ~~ .~ ~ -: : : - =: .. 1~ - ~V GAS - ~ ~,~ -:.~.,~-~,-~.~:-,,~-~'---.E~Ioraco~ ~orth Fork Un~c Janua~, 1966 ~. ~,,-~,~a ' ' . ~w WltL ~ :~'~;~/~-~:~':~t~ ~.' :*~ :~ ~' . . : .' '~ '.' - ~ . . DATE - ~: m ~CT~ ~tt .-. - s~,~,~ ~.;.-2~?.-'~'~:'-?:t~:* ~'~ .~- ' '- -.::'".L :~-_-~. . - ....~ .- . ~3 ~s~,o~Mu . -- . J,~,~ ,.-...,:.,/~::f~.~:~...:~..','~,: ,_.-.: Kena[ Bor~gh ..... ' ~ ~ ~, I, ~i1.~(~ ~(~, ' ~_ ' ~ttl~ ;~':-.:./--.:'.:.'~-~{~'-:> ~;-:. : ~ '= . . ~~ :,~ : ' .' d.'~;.-:, ........ .... : ='. ' .'-:.. ~,, . .... - - ~CI~ 10~S~I~ ~E - ~ ~A~' ~: ~*1~!1~ ~l~mW~ll~ ~11 ~' - ' .... J'~'~'1:' '- IT~, M · .. ., -.-',_.. :- -..--;::'.,::'_-')_.' -;<~-:- --- .. . ".':--TO~,~L M~)NT'HLY ' ' 'DAILY AVERAGE - :' PRESSORE ~-RAV '~-"R' '" Iq' i:,'-','_',.~-!-;-:~, :. -..,,..;.. ./. '~ .... - -- -~--'~_ : .- : . ..... · .... ,, - ,,,v .~.,,. . ~,,~,-,-v,,,~ -~.,. .~.~. II . : tl~, ' O; . ' IAII~,I,t O1[:'-'-:.';' J.::: ~ WA~I~ - i -",MCF GA~ DAYS OIL WATER GAS ' CASING TU$1NG ITY GAS/~SL OIt ~ DI[FIN'.-', .~.. ':. _ .' ..... ~-; .' - - .. ~ ..... l . . _ ",:'~ ,,,~-,,.,,~. ! ~ ,.-:-~--- .~i -. ....... -,"~,,~,'-,-~-',',t-;~I -:~ ..... ' ...... --'-: -'- - I . · '-' - ',.' '.- ........ - ..... -'--' · · ~-.-'~ .. - ' .- .:.'., . ' ;: ,,-.--~-~;- -:~,/~-.-:, ';-., '-- ,:-;..;,'--~;:-.' -- : -"'- t .- . . . ,I . . , .. ...... .,, . ,- :-~,..,. ; , - . . ........ ,._.,.~ . -'-_,:~:--.'. ' I~ ..::...- ....:.: :;;,,~.:..:..,:.l-,..~..:....:.t-...:.'; - ! - : ".::' . - . ~ -. - . . ..- ....... : -.~:, v- . ., ' .." ..'.~;.. ~.'. :~,,~:~::.:,.. I.. :~,;...... '-.--.--'-:.~::~',:,:-,-:':,I ::-'-;,:"...'--' ....... .-. ' - - ' ': ." ..:-'.---'.-,-,'---, ,:,'.' .... - .... :,.;-'.-" .' ',:';.'-t ..:' - - - :-'.,'j '. ".: ..:'C.~.?:'--',~.,,'.'-'. .... .-:-~.~.~--:- ' - ' ' ~ ._ ...... :,'::.'," ' :-. ' .... '-: '.:~ . · · ' · .' ; ~. -~....~. · ff,~."~':'-' ' : - '- .' '.;--',~,~:4:...'.;1%.,: 'u :- %"-.:'".. ' .- . - , ! I, ' ... ,:. - ':.;.' ,'..: .- -' .' . · · ",:.':-.-;':, .~. I.:.'-5,:~:4: :. -. .... -'-': ---;'.-;~':::~'~,.'---'.-:;: -"1~ - '-'.'-": :. ' - -.' ' - , - ~ : '-- '; ~ .~ -- --' ' -' .-.: :-'. '- :; "-" -' ' · :.'" ~}'.T::-'-':-:' - '.' '.!':,,. .... :.:-.-..:,.?:,~:~i~.'::..-.-!-':.'.-" .',.'-'-:. -.'. ~Og.~ FORK I.N'~ ~F, AS~ A-0243~ --:.:...: i; .-':::'::':':; .'..' "-'. ·. .': "t'.: ..'~'~.c.~-'-' --.' ..... .-- .". - '-."..'-.~ '~C-:-':-'~'~ ° ' I · . ~ '--:- ' ' , - ,-. : ' ' .. : · °'-: .. ' .*'" -:'~::,,.'-: .'. .- .'. - ' · . '- :;>-"'"'" -'~'-'.-. '~ ;.:-'--:*.,-':': ...... "' - ' - - ' ' i .... ' ": ' -' ' ".' . -:-'- · -.' :' ' - ...... '..' ' . · . ' - '-' , ' :.'m':~,)~ ' ' ,-'.;~- I ." "'"% ~ -~ ; .~' . - - I - · .- .- -'- .'-'-:' . ' - · -:.-,~,~., · .~.~[~1~ 00 t2.,: .,.:.':.Lt~:~,~-:.--'.:.--'." .- - $$?3615 ! : - .':'-. '..:°..~ii.::5'-1170 1250 ..... ...... ~ . .. : ...:l-:.-..,..:,:.~..,.~.?~ · ..i:.:....:, - ,. a.-_-::,,;~_~_'_~,)-: ......... .. , . . ...: - . . . . .-...-. . ,- . . . .. .. . . ....:!.....,..~, · .-.;.,~ . ., ......... _._. .... ..: . ...... . .:. .. . . - ,.~ ,,.. ....__,, . . ...... .. ..........-.,. : . I1~_.--:' -~i-,' · i.-'% "- :';~5-..:-';:1- .... ' " - .... ":'~" "--- ~_0~ T ~T~(~i" ~i~ ,~4' O~T~"_ . ' - . - :.:' .:-v.::..:- .- ' ' -~.::'-- : :":::'-: '~;'..-,-~:.'.~:-';~-:-.::- .--.,',:':-..:" ." . --:.-': - -'- - -.- '----.,:-, :; :'.~ :,,'~:.~:~4' ".-.: - i . .:.',. !~-:.:.,. ,~., _ ,'--. .' .::~,::,..,,..-., ~::.:-:~-!:::-'.;-.-.::-'_, ..,~....~:. --. -,_--:-,-,:,._ ._: --.. -'.- .:,:::;c.:. - - '-.. - ..' .-~,-' ':.' :.' ---- ':.:;-i~ .'~'"'""?.~:-;.:~..!-::- .... .::.r-'-.-" ' '.." '..'.' ....... ' " '.'-.'-:'.~"' I~,~_,~;'. . ---:,--' .... ?":-'~'.' .... '~'. - -'.'~-.~:::_ ' .. .'-'-"r -' - ' - ' - -: .... '.."-.. -';~-';'-'.'.'--' '."' I:~'--- - '- - ~..:' D:[STI~I~UT:~:I~I="-:.~:'-". .... -,::-..';.':~'-' - - - ',..':: : :' .'-' -:---:. -',' ;:.:-' .- ~.; ;:',:..-. :: -~ - ;,".--;' '.. .. - · .. '.'~':~ ~'.~.~L~ .£~-,,. ' ~ ~-.;;. ~ :-~ .... :-- - . :;~. .... . -. '..' . ~' . : ' '...- .v -- -..:--- ' '..~.:: --- :- '":-;~.- -~::~:E';~5- -.',-':..~:- ..... · ' : II1:.~.~. . - ~ - "-:-. I ..... - -~'~--.~..-"..: .... .-.- I -'.-.--:.-. ' '-. - , . ' ~. - · ,. ' .............. '--::- --~-,z~'.,:;~ .... -.--.' .. · ' ...... ~-~--',-'/-'--: --:, ~'..., I : ..- ,, -,~:~ -(:' - --- ::- .... '..,.- - ', ..... ' ' - ' - .-: ' . ' ..... .,- --. -:"-,':~.:' "~,;~".:?:~e:- : .-'-:.~-,,V,.. '.: '~ -' -'. · ~ .... .:-:. ~ .... -' , ..... '. - : .... - ,.-, ,. .~:,-. ,,f~,. .. I~::.'-'-' .- ,.*~_-I,u,s,~,S;', ~;:--~,-:~,t,~(n (2)- . .. - ..... :-~ -:..:--.,:.:m..~ ..-.--..- ...... ~-~::- . ! -,..~ ..... ..-. .~. II - ... -. . . . · . - . . - : . - .. :........'..;:., .- . · : .--.'.',.-.~. I:=~.::.-~--. ':::-- ~aca'.::."-'T.., ~,' l~r,hal] ¢~---' - -'--, '- -.- .'-:. .... ;'~ ';':'. :-:-..". · ' '..'.'. I-'~-'.~Z'-.~ ' ' :,::' ! ' . ' ' ' ' ~ d' ." ' · -.'-~' ' - - ' '. '----' - .- '- ' '- ; --'.. : ~ -, · t ' ~ '. ''~ .o ~ T~I~. _~.-~ '.. . · . -- .. :. - - .. . , . ~' ~..... _ · . _ . .. · ~...: , : .:- ....', :..' % - . ~ , :o".-". [ '.. !',.~: - . . ::-.=- ~ha-&t.:~tc l~a£tataS Co~en7 '- C. ~, :~ar~T (,)-.--; :-" - -" · ._.-.-.:...-.....,;.I,'.',.-.~.;~--?;,-I .:. .:~..:-- ..~ J+:F: '. · :" .' "" ! ".:/_~?L:2'.:~'j;: ':" - -' -'~-..'.'-'.-:-- - .:-~:- ~ -.'-_' - - - ' ' .-..": ..... ..-'.~' --~:;',L'-::.,":.:". . ' "'-.'}'. ': '. ..... : ' ' .- -.',~" ".":::~?~ ! . I.i .-,::- - - ,. ~ I .... ~,--:.~:-.~:~. :.- ..... . .-.-. - I~, ~,. 1~:~:~ ([~ .- --,- ... .. ..... ...:,~ .... --.;::,-:,~ .,..-.- ..... . · .-.,.~ .. - .~ -:~t~.-.';'-;~- ..... . : . . .... . . _ ~. ..... .:. ..... .: .'. ..... · !:-'~::::. ' ' :. -::..:-::-.!;,:,-'.:'.?..'--~'"" -" ": ' - ', . ~, 1~. ~,ttca~ ~1) - . ' . -'~. ';.- '.:::: --'.,2'.::'.:..- - .."' - . ," ":...'~:.~ :. :~!~ ~:~a~::-' . - " · .:-..9'.~:..-";:..~'~ ~ · ~ . ~,~_,~. . " .... : ' -~:;.' ::'..':':. :' '.:".:: (% L. ~. ~ ~ -'~- L,, ~,.. ~:-:.i.~j~ ~ ~-. _."..-'. ':~- - ,:~'-.,?~'.;.'" -.:-.- . ' I . -' . . ' '- - ' " ' ,. .. - ' - . · · .. ~ ~ ~' ..:.$~.~o, ° I:i~:...'' : .. ,'-..~:.':~:.:.-:'.' ~, ~o ~,m~ -... -- -. . - - . .. .-~. ....-'.-. . . '-~-~-- ........ >.'-~;,~ ...... · ' - -~ - -- · ' .-. ' ..... .' i~i--, .- "' .,:;.F.~::'.:t'!".'i.':. ' t'Co I~o. I,It.I~¢~ . - -- ~. .. ' "- ~' '.-.~' '..'. ;.-. "" .:.L .... .".' ' ..... :.. '~'..~ ~.~ :"~-' ' - "' '- i -.~?:'-':'.~.:-~:~:'-' ' .. "- . -- . - ' ,' ' 'i. ' : '2.- ..... ! -~- . -% .-~ ~ - . . . 8 - ' - ---' - · . ' - · J,.'~& ! .~ -' .- ~' '~' '~ ~ ~ ~'~ -..:J. ' ¢ -..~r?'~ ---- " - '~-:~ ---" " £~ l.m:~c~.o~ , . .- -i -'-- :' ' . '-.' -~.': - "::.-'~ ~'-.~:~ :. '. "-.:' . ' . ~--.- ' ' - - · -.-...' ~...':.-~' -.'-;-":-" .'-: .... ' ' · 'i'..",.'~ : ' ~ ' ' " ' · 'C_q~'-~l '~'~'~.~t~ . . ~ - · . . . ,. ,.. , '~. _ -~- . . . ..~Z..~ ~ -~ .- . .. . . x2 ~, ! .. . · .... . ......!~.? ,~, .... , :-,. .... - . . ....~:~ .;~:;...~..; ,~- ~ t[ ..<...,,:,.,.....,. .,~,;~:'~-t':';'- ' - ..... -"-'~ ~;' °~',,~ :' ~\ - . .. .-. . ._ .:.,~.~:.!~ .., "' ' ' · -~'r '4". : .'- ~. . .... ;:.,~ ;.;A-'" . . . _, :-{~.;,:~ ?" .... .~-.: .....~ . ... - .. .-.-.- . .... ;~.-. '. . . '.. :.~- · -O STANDARD .OIL COMPANY:-OF~'CALIFoRNi~-~.'~/:!!"-'i'" -:~,<----:~-.-, ~, .¢-~.--, - , :- .,~,.- ....-:.:.: .-_~:...-_.. . - _ -_ : . . _: . .'.:.;-..... . .- _ . - , . MONTHLY WELL-PRODUCTION ":': :":'-"' " · NORTH FORK UNIT ' FEBRUARY 1966' ' -. -..... .... ... . · I~CllOIV TOWMS~IIP -.. .le, AN~ . IM . ' PAG~ . · -:.' I.l~...l~lJ O.1 IA,IIILS WAT~I · .:.:~'- -..::'.: .. .- _. .: . . .'~ , ~. - :..- . .- -. -. .... -; .. ·., - · . · .o....-.. ;/ .. · -- . . . . .-. . . '~....~. .. ::-,~'.,.... - ...: . . · :°.'.": ': .....~ ~ · .~ . . .... - .::.' .: ?.' ......' . .: · . ..~..'-~o.. - , · ... · · . T. "Thl tic .': . . . . · . . ,. NORTH FO~J( '1~ 45249 Linton- 2 -1 Couprry - C. R. - Section 4: )loratton 15 DAILY AVERAGE .' ' PRESSURE' OIL WATEI GAS - ' . ...:..-:..-., .... . _. · :... - . ;.-. - .. - . - _ - -- . ..... :-:-:~ ' .. :~-.-.,; .--'- :. _ - '- :" ~'"' -.i'~:/-.'.':. -.::!:,../..-. - - .. - - "2." ._--.. -..- -.~,~ . .: ./. , -(. :-~.'-..,: - .,:..-:-:, .-_-.-: .:.-.- ... .--..: ...... .:.:.._ '. .:..o: .. · -.:-..i(.:.'y'. :::; ':::.'"'"': '-' -"':?':' - :'::::'"-._,.--.-.,..:.::._.. · :- .~: .... -~;~:-' - -1 ' "''' - . -..:..': 1' :' "" ' ' '-' "::- :'-.:"!-"::-:-.' - '1: }..:: '" ' "-"::;-:-"' ' ' "/--::/i:. :::');} -' -,_-" i-.,:::-. :'::-":'"' . :-'.. ,. ~ . ... ._ -~......:.... ~ . ...:..:._. · - .... .... :--.: . - . .'- . .- .. . · · .-. ~ - :. . .. :-..,,~ .. · .- -.. ..... : .... :-,:..:.. . :_: .- Z-; ~'" .. . ~': .-: · -_ :'- .-...?:;.,. _ · · . .- L. Hill' R. S, e4Otf . P,~3,,, MAd*..I..~. _._~ · !: .,c ,.o,o. """"-~:"~'""~,"~ C.~,--~ ~¢, ~ .. :-:... _....:~.:~,~ .-~_ .?-:,_.:. ~ ~ .- I~i[ I I_t_~_~1,111~_ .-:.='-' .:.:.:..-:: _::.'::.:.-..:_.t-~'' ; ~ .~'. .... ,,.-:, 11 & IN~t ~ON~ :':.'-: C':.::."'~:' :: -' 13 .- ~y 04~ MIA ~ .- ~,... wm~co,o ,coy:.-':'--':-:' ~'?--; .,'.', · . -:. --.-.., :..:--.~:._::,,:.~:?._.-?-/~ - On/IIL':OIt" '~,....D~..'.H': '. i :.' .-.'.:: ,' ' : -'.:;!.:':..._' _ ..::--'-?y,:.:.'.-.:.,.: _. .. ..._ .. !:~.?-'.i!' -..-.- . . · : 'i-'-? · . ,.~ -. ._ - EXPLORATION DEPARTMENT ANCHORAGE DISTRICT R. I. LEVORSEN DISTRICT ~zUP£RINTENDENT P. O. BOX 7-839 ANCHORAGE ALASKA 99501 February ll, 1966 S. O. COMPANY OF CALIFORNIA, OPERATOR NORTH FORK UNIT 41 & 41A-35 WELL SECTION INDUCTION ELECTRICAL LOGS AND , , State of Alaska, Department of Natural Resources Petroleum Branch of Division of Nines & Minerals 3000 Porcupine Drive Anchorage, Alaska 99504 Attention: Mr. T. R. ~rshall, Jr. Gentlemen: We are transmitting: 1. Induction Electrical Log From Surface to Total Depth 2. Mad Log From 245-12,812' . , 3. Induction Electrical Log of Redrill (41A-35) from 10,168-10, 859 ' One sepia each of the above and one blueline each of the above are enclosed. Please hold this material in a confidential status for the prescribed two year minimum period. Yours very truly, R. I. Levorsen j v~ ABS:sc Enclosure RECEIVED FEB ! 5 966 DIVISION OF MINES & MINERALS.. ANCHOP, AGE Production Test - North Fork #41-35 Standard Oil Company of California On January 18, 1966 went with Bill Wunnicke of U.S.G.S., Bill Whitney and Bob Leverson of Standard Oil Company of California to Standard's North Fork #41-35 to witness a production test of that well completed as a gas producer. Status of Well T.D. 12,812' - Sidetracked and redrilled 10,165'-10,859' Casing - 9 5/8" cmetd. 8,451' 7" liner cmtd 10,985'~, top at 8,330'. Old hole plugged 10,868'-10,765' and 10,350'-10,165. Tested open hole 10,805'-10,860' (wet) Plugged 10,859'-10,650' and 10,215'-10,025' Tested thru perf. 8,563'-78' and 8,592'-8602' (wet). Bridge plugs 8,500' and 8,330' Perf. 7" 8,005'-8,045' DST 4,360 MCF with 3/4" bean. 2-7/8 production tubing 8,045' with packer at 7,945'. Pressure bomb on wire line to bottom. Well had been shut-in for 20 days prior to test except for short test previous day (1-17-66) when pressure at bottom was 3,409 psi and at surface 2,841 psi. TEST: __ , 12:21 p.m. opened thru 12/64" bean diff. Head temp. Pressure above bean Rate-MCF at 12:42 p.m. opened thru 12/64" bean-98°F below orifice 17 psi 3.6 3.05 chge 12:44 p.m. At 1:11 p.m. 16/64-85° 31-1/2 4.35 3.9 chge 1:14 p.m. At 1:53 p.m. 24/64-38~ 56-1/2 5.3 4.5 Chge 1:58 p.m At 2:36 p.m. 32/64-6" 95 6.51 2.95 pulled bomb. chge 2:46 p.m. At 3:00 p.m. 64/64 +30° 76 6.1 6.0 3~5 p.m. shut in. 40°F 43-1/2° 45" 46" 46° 2410 psi 2070 1415 990 280 2.225 3,400 4,840 3,602 6,890 Karl L. VonderAhe Est. gravity .565 (from comp. same as Birch Hill #22-25) orifice coefficient used 203,000(est.-tables only to -50"F) Last used 193,000(will be calculated later) When opened ~n 32/64 bean the formation of hydrates caused resulting readings to be erratic. Apparently this size bean caused the volumes and pressures to be critical for the formation of hydrates as when the bean was increased to a 64/64 the lines cleared of hydrates within a few minutes. Morm P--7 SUBMIT IN DUPLIC~.i '...;'L-- O~ ALASKA (sc',.~- .... strm t OIL AND GAS CONSERVATION CON',MISSION ,,v,, ._.'_~, COMPLETION OR RECOMPLET[ON REPORT AND LOG* la. 'tYPE OF ~VELL: ozI, J--J ~AS WELL W~:LL VB~ ~ Other ~. TYPE OF COMPLE~ON: OVER ~ ~NDEEP' BACK gESVR. W E L L Other NAIVE OF OP]~RATOR Standard O5.1 Company of California, Western Operat±ons, Inc. S. ADDRESS OF OPERATOR P. O. Box 7-839, Anchorage, Alaska 4. LOCATION OF WELL (Re~ort location clearly a~d itl accordance with any State requirements)* At surface 659' West and 655' South from Northeast corner of At top prod. l~a~'~Pe~0rt}~el~'~'4S' R. 14.W, S.B.aM. .. · - ~,'. .I Effective: July 1, 19~"&C~--~ 5. LEASE DESIGNATION AND SERIAL' NO. ~' A-024353 6. IF INDIAN, ALLOTTEE OR TRINE NAME 7. UNIT AGREEMENT NAME ~or t:h Fork S. FARM OR LEASE NAME North Fork WELL NO. 41-35 10. FIELD AND POOL, OR %ViLDCAT Wildca~ 11. SEC., T., R., M., 0a BLOCK AND ~URvE¥ OR AREA At total depth 14. PERMIT NO. DATE ISSUED J July 29, 1965 35, T.4S, R 14 W; S.B. & M. 12. BOROUGH JJ'. 13. STATE Kenai Pen. Alaska 15. DATE SPUBDED J 16. DATE T.D. REACHF~B I17. DATE COMPL. (Ready tO vrod.)18. ELEVATIONS (DF, RgR, RT, OR, ETC.)* J19' ELEv' cASIN°nEAD Aug.9 ~65 Oct.' 31, 196~ Dec. 20, 1965 ':'780' K.B. · 764' 20. T~TAL DF_~TH, MD & 12,812 'D 10173 ' -10859 ,. J 2 1. PLUO, BAC~ T.D., MD & TVD J 8500 22. IF btULTIPLE COMPL., HOW MANYs Single ROTARY TOOLS CABLE TOOLS J 0-T.D. -~5~' 23. INT.ERVALS DRILLED BY 24. PRODUCING INTERVAL(S), OF Tills COMPLETION--TOP, BOTTOM, NAME (MD AND TVD)s .. 8005' - 8045' J 25. WAS DIRECTIONAL SURVE ~ MADE JYes 26. T,PE ELECTRIC AND OTaER LoGs RUN I.ES, DIL, Sonic, Micro, F.D.L., CDM, Mud-log J 2 7. WAS WELL CORED Yes 2S. CASI~o size WEI~.T. LR./~T. A,,,o~T PULLED 20" 78.6 ........ 13 3/8,:__ ,9 5/8" , 61 and 68 43.5 CASING RECORD (Repor~ all ztrOtgs se~ in well) DEPTH SET (MDi HOLE SIZE CEMENTING RECORD 246' 26" " 625 sacks '2000' ' 18 5/8" 2000 sacks 8451 12 1/4" ' 1550 sacks 29. LINER RECORD SIZE 51 TOF (MD) 8330 BOTTOM (MD) SACKS CEMENT' 10~985 900 5 -%'" holes at 10,786' (WSO) 4 - ½" H/F 10,805' .- 10,860',8563'-8573' 4.'- %" H/F 8,563' - 8578', 8592'-8602' 4 - ½" H/F 8,005' - 8,045' 33.* i[ 30. TUBING RECORD SCREEN (MD), SIZE - .. 2 718 2 7/8 . 82. . ACID, SHOT, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH 'INTERVAL (MD) 10,785' '.' ' 8,S3'.o'. 8,540' 8~330' 100 sacks DEPTH SET (MD) PACKER SET (MD) "2511 ~Heater StrinR)j AMOUNT AND KIND OF MATERIAL USED Squeezed w/180 sacks cement " "w/150 " " " .. w/150 " " [.WELL STATUS (Producing or I,' shut-in) ' J'...'! '.: Shut in PRODUCTION . ' . .. EATm FIRST PRODUCTION Dec. 13, 1965 DATE OF TEST 1- i q -o9' '" FLOW. TU~ii~'O P~F. SS. Flowing HOURS TESTED J CHOKE SIZE J PROD'N. FOR O. IL--BBL. ' [ TEST iPERIOD 2 16/64"' ' > -- :'" 0 ' >' -- GAS--MCF. WATER--BBL. GAS-OIL RATIO I c7o I I "" 34. DI~'.POSiTION OF OAS (8Old, USet~ for.fuel, ve~ted,.eto.) ....... TEST WZ~NESSgD a~ Flared ' .. ~. Vonder Ahe ~5. WATER--BBL. OIL GRAVITY-AP1 (CORR.) (" ........ 36. LIST OF ATTACHM;'~NTS ~ . ,' . Induction Electrical log and Mud-Log transmitted' by Exploration DePt..Feb. 10, 1966 I hereby certify thatj;he foregoing.anS.-attached information is complet6 and correct as determined from all available' records., ~ .'" ..'" /k'.... .' . " ' ' "'' '' /%/;' '"+/.' '-,'~-..'/ z'/,/"/,~.,z. District ' Superintendent :.' "' ' February 10 1966 SIGNEDL /' · . " ....... : / ...... TITLE '": DATE ' ' 'C.~ V. CHATTER~0N ..... :. , *(See Instructio-.-, and Spaces [or Additional Data"on Revers~ gide) ' .,. !: '":k ......... ~ . / FEB ! ; DI4-12 State of Alaska ..... Department of Natural Resources Sec.: 35 DIVISION OF MINES AND MINERALS Petroleum Branch INDIVIDUAL WELL RECORD T. 4'S R · '1/,T,T S M~ridian Permit No. 65-21 Issued 7-29-65 OperatorStandard Oil Co. of CalifLocation (Surface) 660 FNL & 660 FEL Sec. 35 Lease No. A-024363 or Owner L No.rth Fork Unit Loc. (Bottom) Well No. 41-35 Spud Date_ 8~-?-65 Suspended Area Anchor Point Drilling ceased Abandoned Total Depth 12,812' Redril, led 10,165 - 10,859 Elevation Completed (F-GL-P) 12-20-65 B/D. Gray APl Cut_ _ :- % Gas ~5~3/ Casing: M~F~, Bean /~( /64 CP psi, TP ,E.__~'7'0 ~ psi Size .LDepth Sx Cmt PerfJlO,785'WNSO-squeeze~lugs. J 1..0~868' - 10,765' , 10,786' WSO 20" 246 ' 625 10,805 ' - 10,860' DST~wet __. 10,350 ' - ~0.165 ' ~ 13, ~/8''~-~ 2000t ................ 9 5/8" 8451' (750~V 6313' 8,563' - 78' ),~..~ 10,859'-10,650~ in redrilled .... . ( su0e ..... 8' 9z. ...... 7" Lnr 10985' 900 8,005' -45' Tested Br. PE. 8,500' ~0=:~330 - :" ......... "*""" GEOLOGIC FORMATIONS Surface Lowest Teste~ .~ : .= . ~: PRODUCTIVE HORIZONS Name Depth Contents Year Jan Feb · . WELL STATUS Mar._ .... Apr : Ma.,y June July ,, ~,f~ .' , ~ : Aug Sept Oct Nov Dec . :=:: : £ ;;~ ~ Tested redrilled hole 10,808'-10,859' - 380 rise oil and salt water Perf. 8,563'-78' and 8,592'-8,602' Tested 1770 MCF BHP 470 psi T.P. 165 psi 369 rise water Perf. 8,005'-45' Tested 4,360 M0F 3/4" bean B~P 884 psi T.P. 450 psi . ::.-: Cpmp!eted with prod tbg. 2 7/8" to 8.,046' with PaCker .... 7,944' and heater string 2 7/8" to 2,511' Remarks .- CONTRACTOR: Coastal Drilling Company COMPLETION REPORT - NEW WELL STANDARD OIL COMPANY OF CALIFO?,N.. .IA ,. WESTERN OPERATIONS, I.NC. - OPERATOR AREA: Kenai Peninsula, Anchor Point Area, Alaska LAND OFFICE: Anchorage Lease No.: A-024363 PROPERTY: NORTH FORK UNIT WELL NO: NORTH FORK UNIT #41-35 LOCATION: Surface: 655' South and 659' West of Nor'theast Corner, Section 35, T. 4 S., R. 14 W., Seward B & M K. B. is 15' above ground ELEVATION: 780' K. B. DATE: January 31, 1966 DRILLED BY: Coastal Drilling Company, Rig #3 DATE COMMENCED DRILLING: August 9, 1965 DATE COMPLETED DRILLING: December 20, 1965 DATE OF OPEN FLOW POTENTIAL TEST: January. 18, 1966 SUMMARY TOTAL DEPTH: 12,812' REDRILLED: 10,173'-10,859' JUNK: None CAS ING: 20" cemented at 246' 13 3/8" cemented at 2000' 9 5/8" cemented at 8451' 7" liner cemented at 10,985' with top at 8330' PLUGS: 10,913'-10,985' 10,765'-10,868' 10,173'-10,350' 10,654'-10,854' (in redrill) 10,009'-10,250' (across milled section) C.I.B.P. at 8325' Page 2 PERFORATIONS: 5 - ~" jet holes at 10,785' (squeezed) 5 - ~" jet holes at 10,786' (WSO) 4 - ~" jet holes/foot 10,805'-10,860' (cemented off) 5 - ~" jet holes at 8530' (squeezed) 5 - ~" jet holes at 8540' (squeezed) 4 - ~" jet holes/foot 8563'-8573' 4 - ~" jet holes/foot 8563'-8578' 4 - ~" jet holes/foot 8592 '-8602 '~.~i'_~ '" 4 - ~" jet holes/foot 8005 '-8045' WELL LOGS: 1. Schlumberger Dual Inducation Laterolog 2. Schlumberger Induction Electrical Log 3. Schlumberger Sonic Log 4. Schlumberger Proximity Log - Microlog 5. Schlumberger Compensated Formation Density Log 6. Schlumberger Caliper Log 7. Schlumberger Continuous Dipmeter 2000' - 8437' 246' - 12,805' 246' - 12,794' 2000' - 8,435' 2002' - 8,440' 8449' - 11,170' 2002' - 12,796' 10. Core Laboratories, Mud Log, 8. Schlumberger Gamma Ray - Neutron 7500' - 10,920' 9. Schlumberger Cement Bond Log, Run ~1, 200'-2000'. (In 13 3/8") Run ~2, 3700'-8449' (In 9 5/8") Run ~3, 8300'-10,908' (In'7") Run #4, 9000'-10,909' (Sq. job at 10,785') Run #5, 8300'-9300' (Sq. job at 8530') Run ~6, 8300'-9300' (Sq. job at 8540') 246' - 12,812' WELL LOGS, REDRILL: 1. Schlumberger Induction-Electrical Log 2. Schlumberger Sonic Log 10,168' - 10,857' 10,168' - 10,856' FORMATION TESTS: HCT #1 WSO Test at 10,785' WNSO HCT #2 WSO Test'at 10,786' WSO - OK HCT #3 Production test of perforated interval 10,805' - 10,860' HCT #4 Production test of perforated interval'8563' - 8573' HCT #5 Production test of perforated interval 8563' - 8578' & 8592' - 8602' HCT #6 Production test of perforated interval 8005' - 8045' HFT #1 Open hole test of the interval 10,808' - 10,859' in redrill COMPLETION REPORT Page 3 NORTH FORK UNIT #41-35 S__ECTION 35, T. 4 S.~ R. 14 W.~. Seward B & M -- ,--1 11 i , , i - ' STANDARD OIL COMPANY OF CALIFORNIA, WESTERN OPERATIONS~ INC. - OPERATOR AuKust 9~ 1.96.5 Spudded at 8:00 AIM., AugUst 9, 1965. Drilled 12%" hole to 246i. Ran 26" hole opener with 12%" pilot bit and opened hole to 122', 70-71 pcf mud August 10~_ 1965. Opened hole to 26" to 246'. Circulated and conditioned mud. Ran and cemented 20", 78.60#, Grade "B", Buttweld conductor at 246' with 625 sacks cement around shoe. Conductor equipped with Baker Float Shoe and 3 centralizers at 10', 30' and 50' above shoe. Mixed cement in 25 minutes, displaced in 5 minutes with 6 bbls water. Average slurry 115#. Preceeded with 20 bbls water. Full circulation and good cement returns to surface. Cement in place at 5:15 P.M. Cut and recovered 22' of 20" conductor. August .1..1.., 1.96~5 Welded on landing flange and installed BOPE. Tested blind rams to 250 psi - OK. Au2us.t 12, 1965 Picked up drilling assembly and 18 5/8" hole opener. Tested Hydril with 250 psi for 15 min. - OK. Cleaned out cement 225' - 246' and circulated. Pulled and laid down hole opener. Ran 12 ~" bit and drill- ed to 976'. Core Laboratories commenced mud logging from 246'. August.!3,_.1965 68-69 pcf mud Drilled 12 %" hole to 2000'. Circulated and conditioned mud for logs. ~UgUSt 14, 1965 68-74 pcf mud Ran Schlumberger Dual Induction Laterolog. Tool failed. Ran Sonic log 2000'-246'. Attempted to run Induction Electrical log. Tool failed. Reran Induction Electrical log 2000'-246'. Ran 18 5/8" hole opener and opened hole to 591,. ~uRust 15~ 19.66 Opened hole to 18 5/8" to 1831'. 75-77 pcf mud COMPLETION REPORT Page 4 NORTH FORK UNIT #41-35 SECT_IO.N~35.~ T. 4 S. ~ R.. 14 W.. ~ .Sew. ard B & M STANDARD OIL COMPANY OF CALIFORNIA, WESTERN 'OPERAtiONS, INC. -' dPE~TOR August 16, 1.96__5 Opened hole to 18 5/8" to 2000'. Circulated and conditioned mud for 13 3/8" casing. Ran and cemented 13 3/8" casing. CEMENTING DETAIL , , Cemented 13 3/8" casing at 2000' with 2000 sacks cement around shoe. Mixed cement in 85 mimutes, displaced in 32 minutes with 1690 cuft mud. Used 1440 cuft mixing water, average slurry 116~. Preceeded with 10 bbls water and no bottom plug. Bumped top plug with 1500 psi. Full circulation and good cement returns to surface. Cement in place at 7:05 P.M. Used Halliburton equipment. Displaced with rig pumps. Hookload weight before cementing 122,000~. CASING DETAIL K. B. to top of 13 3/8" casing 18 joints 13 3/8", 68~, J-55, SSR casing Cut and Recovered 34 joints, 13 3/8", 61#, J-55, S8R casing Casing Landed at 732.75 - 24.05 15.77 708.70 1275...... 53 2000.00 ' Casing equipped with Baker Guide shoe, Baker Flexiflow Fill up Collar at 1964', 5 (five) centralizers on each of 5 collars above shoe. August..17, .... 196~ Removed BOPE, welded on landing flange and reinstalled BOPE. Tested BOPE to 2500 psi for 15 minutes. H~ld OK. August Magnaglowed drill collars. Ran 12%" bit. Tested pipe rams and'Hydril to 2500 psi, for 15 minutes - OK. Drilled out float collar at 1964' and cement to shoe at 2000'. Drilled 12~" hole to 2563'. August_..!9~2.2, 1965 Drilled 12~" hole to 4742'. 69 pcf mud 69-79 pcf mud COMPLETION REPORT PaRe 5 NORTH FORK UNIT #41-35 _S. ECTION 35,~T._4 S., R. 14....W., Seward B & M STANDARD OIL COMPANY OF CALIFORNIA, WESTERN OPERATIONS, INC. - OPERATOR August 23~ .1965 Lost circulation while drillin§ at 4833'. Mixed lost circulation material and reduced mud weight to 76 pcf. Regained full circulation after 10 hours..L_ost app~w{m~t-~.300.bbls 79 pcf mud. Drilled ahead to 4920'. -- ~gust 24 - Septemb.~r 4, !96~5 Drilled 12%" hole to 8415'. 74-77 pcf mud September .5~ 1965 Drilled 12%" hole to 8451'. Circulated and conditioned mud for logs. Schlumberger ran Dual Induction - Laterolog 8440'-2000' Induction- Electrical log 8440'-2002' and Compensated Formation Density log 8440'- 2002'. 76.5-77 pcf mud September 6,.1965 Ran bit and reamed 8390'-8451'. Circulated and conditioned mud. Ran Proximity Microlog 8435'-2000', Sonic log 8429'-2000' and Cement Bond log 2000'-200'. 76~5 pcf mud September 7~ 1965 Ran bit and cleaned out fill 8425'-8451'. Circulated and conditioned mud. Ran Continuous Dipmeter 8435'-2002'. Ran bit and circulated and conditioned mud for 9 5/8" casing. peptemb~r...9, !965 Made short trip. Circulated and conditioned mud. Ran and cemented 9 5/8" casing. C__E_MEN~,!,NG' DETAIL ,. Cement 9 5/8" ca~ ng at 8451' in 2 (two) stages with 1550 sacks cement. ?irst ~tage around shoe with 800 sacks cement treated with 0.5% HR-4 Retarder. Mixed cement in 30 minutes, displaced in 50 minutes with 626 barrels mud. Used 99 bbls mixing water, average slurry 118#. Preceeded with 10 bbls water and no bottom plug. Bumped top plug with 1700 psi. COMPLETION REPORT Page 6 NORTH FORK UNIT #41-35 SECTION 35,. T.. 4 S., R.. 14 !.l., Seward B & M STANDARD OIL COMPANY OF CALIFORNIA, WESTERN OPERATIONS, INC. - OPERATOR _C_ementinA Deta. i! (C. on~t ' d) Had partial circulation before shoe job, full circulation during cement job and partial during displacement. (Lost approximately 150 bbls mud before job) Second Stage cemented with 750 sacks through DV ports at 6310'-6313'. Circulated. All 750 sacks cement treated with 0.5% HR-4 retarder. Mixed cement in 55 minutes, displaced in 32 minutes with 469 bbls mud. Used 93 bbls mixing water, average slurry 118~. Preceeded with 10 bbls water. Closed parts with 2000 psi. Bled off to 0 psi. Had partial circulation before and during "DV" job, full circulation while displacing. Used Halliburton equipment. (Engine for mixing pump broke down during shoe job. Finished cement job using Coastal's D-700 for mixing pump. Hookload weight: Before cementing 310,0005. After cementing before landing 300,000~. At time of landing 300,000~. CASING DETAIL Above K.B. - 5.50 62 joints 9 5/8", 43.5~, P-110, LgR, Rg. 3,= 2413.25 75 joints 9 5/8", 43.5#, N-O0, LgR, Rg. 3 = 3127.65 20' joints 9 5/8", 43.5#, P-il0, L8R, Rg. 3 ~ 774.92 DV Collar · 3.00 53 joints 9 5/8", 43.5~, P-110, LSR, Rg. 3 = 2137.52 Casing cemented at 8451' 2407.75 5535.40 6310.32 6313.32 8450.84 Casing equipped with Halliburton Float shoe, Halliburton Self-Fill Differential Fill Up Collar at 8406' and 15 centralizers (one on each of first 9 joints, one on joint below "DV" and one on each of next five joints above "DV".) Removed BOPE and landed 9 5/8" casing. Cut and recovered 21.69' of 9 5/8" casing. Installed and tested landing flange to 3000 psi for 15 minutes. Held OK. SDptem_ber~ 10~ 1965 Reinstalled BOPE. Picked up drill collars and rubbered 4.~'' drill pipe. S~eptember 11, 1.9.65 Tested Rams to 5000 psi. Ran in and drilled out DV collar at 6310'-6313'. Tested BOPE to 3000 psi - OK. Drilled out Float Collar and cement from 8404' to shoe at 8451'. Drilled 8 5/8" hole 8451'-8552'. Conditioned mud to 75 pcf. Septembe..r 12, 1965 Drilled 8 5/8" hole 8552'-11,375'. Increased mud weight to 78 pcf at 10,860' 75-79 pcf mud Page 7 COMPLETION REPORT NORTH FORK UNIT ~41-35 SECTION 35.~ T. 4 S., .R..14 U.~ Seward B & M STANDARD OIL COMPANY OF CALIFORNIA, WESTERN OPERATIONS, INC. - OPERATOR October 4, 1965 Drilled 8 5/8" hole to 11,405'. Circulated and conditioned mud for logs. 79 pcf mud 9ctober .5~..1965 Ran Schlumberger Induction-Electrical log 11,403'-8449', Borehole Com- pensated Sonic log 11,394'-8449' and Cement Bond log in 9 5/8" casing 8449'-3700'. Circulated and conditioned mud. Ran Continuous Dipmeter 11,389'-8449'. 80 pcf mud 0_ctober .6~ 19.6p. Ran Schlumberger Sidewall Sample gun and shot 20 sidewall samples. Recovered 16. Ran 8 5/8" bit and junk sub. Drilled 8 5/8" hole to 11,442'. 80 pcf mud October ~,,7.,~, ,,1965 Drilled 8 5/8" hole to 11,502'. 79.5-80.5 pcf mud O_ctober 8, 19_65 Drilled 8 5/8" hole to 11,534'. Picked up core barrel and jars. Cored 7 5/8" hole to 11,549'. Core ~1: .11,534'-11,549'. Cut and recovered 1 5 I .... ¥i"."~'2/73~:~':r~:~~~ ...... '~:.'.." .; .,' .......... '. ,~ ............. .... 80 pcf mud O__cto_bber 9, 1965 Ran 8 5/8" bit, opened hole 11,534'-11,549' and drilled ahead to 11,611'. 80-80.5 pcf mud O~_tob.e,r !,.0,-11, 1,9,65 Drilled 8 5/8" hole 11,611'-11,693'. Magnaglowed junk sub, shock sub, crossover and all collars. Circulated and conditioned mud. 80-80.5 pcf mud COMPLETION REPORT Page 8 NORTH FORK UNIT #41-35 SECTION 35~ T 4 S ~ R. 14 U Seward B & M __ · , · · ~ , __ STANDARD OIL COMPANY OF CALIFORNIA, WESTERN OPERATIONS, INC. ' OPERATOR October 12~ 1965 Cored 7 5/8" hole to 11,713'· Core 4~2: 11,693'-11,713'. Cut and recovered 20'. -- 80.5-81 pcf mud _O_ctober 13.~. 19_65 Laid down core barrel and ran 8 5/8" bit. Opened hole 11,693'-11,713' and drilled ahead to 11,763'. 80.5 pcf mud October .1~-17~ 1965 Drilled 8 5/8" hole 11,763'-11,940'. Circulated and conditioned mud. 77-80 Dcf mud October 18,'1965 Made short trip and circulated. Ran Schlumberger Induction-Electrical log 11,928'-11,403', Sonic log 11,928'-11,394', Continuous Dipmeter 11,923'-11,000' and Caliper log 11,170'-8449'. Took Sidewall Samples. Lost 6 bullets in hole. 80 pcf mud. O_c_tober...19., 1965 Ran in and spotted gel pill at 11,000'. Pulled to 10,950' and circulated and conditioned mud for 7" casing. Pulled out and picked up bit and junk sub. Ran in and rubbered drill pipe. Unloaded 7" casing. 79-81 pcf mud Octobe~ .20,...1965 Drilled 8 5/8" hole 11,940'-11,998'. Reamed tight spot at 11,912' and circulated. Octob:e.r,,21 ~ ~2,_2,_~_ 1965 Drilled 8 5/8" hole to 12,206'. 79-80 pcf mud. 77-80 pcf mud Page 9 COMPLETION REPORT NORTH FORK UNIT #41- 35 SECTION 35, T. 4 S.,..R. 14 ~;., Seward B & M STANDARD OIL COMPANY OF CALIFORNIA, WESTERN OPERATIONS, INC. - OPERATOR Oqtober ~3, 1965 Drilled 8 5/8" hole to 12,264'. Circulated and conditioned mud to combat lost circulation. Drilled ahead to 12,334'. 78 pcf mud October 24~..1965 Drilled 8 5/8" hole to 12,452'. Added weight material and increased mud weight to 82 pcf. 78-82 pcf mud 0_ctober 25,. 1,965 Drilled 8 5/8" hole to 12,541'. Lost pump pressure. Pulled and checked for washout. October 26, 1.9.65, Found washed out driltrol body. Replaced same. Ran in and reamed 12,175'- 12,337'. Pipe became stuck at 12,337'. Unable to circulate. Worked bumper sub and pipe. Regained circulation. Worked pipe free. after two hours. Circulated and conditioned mud at 12,327'. Drilled 8 5/8" hole to 12,529'. 80-83 pcf mud O~tober 27-29~ 1965 Drilled 8 5/8" hole to 12,739'. Circulated and conditioned mud. 84 pcf mud October 39~ 1965 Cored 7 5/8" hole 12,739'-12,746'. 84 pcf mud October 31, .~965 Pulled core barrel. Core #3: 12,739'-12~746!... Cut and recovered 7'. Opened hole 12,739'-~7-~~[-~I~-f~'~'i"~iB-57~8--.hole to 12,812' T.D. Cir- culated and conditioned mud for logs. 84.5 pcf mud COMPLETION REPORT Page 10 NORTH FORK UNIT #41-35 SECTION 35~ T. 4 S.~ R. 14 .W., .Seward B & M STANDARD OIL COMPANY OF CALIFORNIA, WESTERN OPERATIONS, INC. - OPERATOR N~pvember 1~ 1965 Ran Schlumberger Induction Electrical log and Sonic log 12,805'-11,928', Continuous Dipmeter 12,796'-11,923' and Caliper log 12,796'-8451'. Ran 8 5/8" bit to 11,100' and circulated for 7" casing liner. Core Laboratories Mud Logging Unit Released at 11:59 ~.M., November 1, 1965. November 2...& 3~ 1965 Spotted gel pill at 11,100' Ran 2655' of 7" 26# P-110 L8R liner to 10,985'. Top at 8330'. Casing equipped with Brown Type "V" Float shoe, Brown Baffle Collar at 10,903'· No Centralizers· Top of Brown "Tie-Back:' sleeve at 8330'. CE~iENT ING DETAIL Cemented 7" liner at 900 sacks construction cement, treated with 0.4% HR-4 Retarder. Mixed cement in 30 minutes. Displaced in 46 minutes with 1220 cu ft. mud. Used 630 cu ft. mixing water, average slurry 116~. Preceeded with 50 cu ft. water and 30 cu ft. "Mud Kil". Used no bottom plug. 'Bumped top plug with 220 psi. Full circulation· Cement in place at 12:42 A.M., November 3, 1965. Pulled and laid down liner hanger. Ran 8 5/8" bit to top of liner at 8330'. Circulated· Closed pipe rams and pressure tested linerlap. Break down pressure 2300-2350 psi, pressure held at 2200 psi. Cement job on 7" x 9 5/8" lap at 8330': Ran Halliburton 9 5/8" RTTS tool on 4%", 16.60~ drill pipe and tagged top of 7" liner at 8330'. Picked up and set tool at 8172'. Obtained breakdown on lap with:~mud at 2500 psi and 14 cu ft./min rate. Mixed and pumped 100 sacks construction cement treated with 0.4% HR-4 retarder Preceeded cement with 10 cuft water and 30 'cu ft. "Mud Kil". Followed with 10 cu ft. water. Displaced cement with 683 cu ft. mud. Cleared tool by 30 cu ft. and used hesitation method last 15 cu ft. of displace- ment. Pressure built in stages from an initial of 2200 psi to a final maximum of 4500 psi. Held 1000 psi on annulus. Cement in place at 9:00 P.M., November 3, 1965. Approximately 19 cu ft. or 45 lineal feet of cement left in 9 5/8" casing above 7" x 9 5/8" lap (top of cement · 8285') leaving ~84 sacks of cement squeezed away through lap. Bled drill pipe and annulus to zero. Picked up on tool and backscuttled hole clean - observed no cement returns. November 4, ~96.5 Ran 8 5/8" bit and located firm cement at 8270', indicating 21 sacks left in 9 5/8" and 79 sacks squeezed away thorugh.lap. Cleaned out to top of liner at 8330' and circulated. Tested liner lap with 2750 psi for 15 minutes - OK. Pulled and changed bit. .. COMPLETION REPORT Page 11 NORTH FORK UNIT #41-35 SECTION 35~ T 4 N ~ R. 14 ~7 Seward B & M · · , , ~,e ~ STANDARD OIL COMPAN~ OF C~LIFORNIA, WESTERN OPERATIONS, INC. - OPERATOR Npvember 5, 1965 Ran 6 1/8" bit and cleaned out to 10,913'. Circulated and pulled out. Ran Schlumberger Cement Bond Log 10,908'-8300'. Ran Schlumberger carrier gun and shot 5 - ½" holes at 10,875'. Ran tester. 85 pcf mud November 6~ 1965 Attempted to set packer. Packer failed. Pulled and found two packer rubbers missing. Reran tester· HCT ~1: Shut-off test on 5-~" jet holes in 7" liner at 10,785'. Tool assembly: 2 outside BT recorders, 4' of 2 7/8" perf'd tail pipe, 7" type "C" Hookwall packer, VR safety joint, hydraulic jars, 2 inside BT recorders, hydrospring tester, with 5/8" tester bean and dual closed-in pressure valve. Ran on 8290' of 4~", 16 60#, FHDP and 2419' of 3~'~ 13 30# IFDP Used 2730' of water cushion Set · , · · · packer at 10,733', with 17' of tail to 10,750'. Opened tester at 10:36 A.M for 5 minutes pressure release· Weak air blow for five minutes. Shut in tester at 10:42 A.M. for 60 minutes ISI pressure period. Opened tool to.,surface at 11:42 A.M. for 2 hrs. 24 mins. flow test· After opening to surface had few air bubbles then dead next 33 mins, weak air blow next 8 mins., then dead next 48. min. Closed tool and sursed perforations (to see if tool were plusged) and re opened tool at 1:07 P.M. Had weak air blow next 29 minutes, then dead next 30 min. or balance of open flow test. No gas to surface. Shut in tool at 2:06 P.M. for 60 minutes FSI pressure· Pulled packer loose at 3:06 P.M. Recovered 403' rise (5.73bbl) mud and cement cut mud. Fi__nal Pre..ss.ure Data: ~Depth Gauge IH ISI IF FF FSI FH Top inside 10,722 Bottom inside 10,726 Top outside 10,745 Bottom outside 10,749 6354 2487 1296 1284/1524 3114 6368 2500 1291 1288/1544 3135 6383 2498 1392/1538 1312/2588 3310 6404. 2525 1320/1323 1320/2917 3349 Conclusion: Charts indicate a plugged test. WNSO at 10,785'. ~pvember.7, ~965 6306 6334 6340 6385 Ran 6 1/8" bit and circulated. Squeeze Job ~1 on 5-~" jet holes in 7" at 10,785'. .Ran Halliburton "DM" retainer on 44" and 3~" drill pipe and set same at 10,681'. Obtained breakdown on holes with mud at 2900 psi. Pressure broke back to 1600 psi and pumped mud away at 19 cu ft./min, rate. Mixed and pumped 180 sacks construction cement treated with 0.4%, HR-4 retarder and.'~ud Kil". Pre- ceeded cement with 30 cu ft. "Mud Kil". Followed cement with 10 cu ft. water. Displaced cement with 774 cu ft. mud. Cleared retaimer by 11 cu ft. COMPLETION REPORT Page 12 NORTH FORK UNIT #41-35 SECTION 35 T. 4 $.~ R. 14 !l., Seward B & M STANDARD OIL COMPANY OF CALIFORNIA, WEST~'RN OpERATiONS, INc."- OpERAT'OR and used hesitation method for last 11 cu ft. of displacement. Spent 2 hr. and 15 minutes staging cement. Held 2250 psi back pressure on annulus during squeezing operations. Pressure built fron an initial of 1400 psi to a maximum of 3200 psi. Dropped back to 1600 psi and built to a final maximum of 2200 psi during squeezing. Bled-off annulus and drill pipe to zero. Cement in place at 3:00 P.M. Pulled out of retainer and backscuttled - no cement observed. Stabbed back into re- tainer and pressured to 2400 psi.- Shut-off pump and pressure bled back to 1300 psi. Pulled out of retainer and tripped out. November 8, 1965 Ran to top of Halliburton retainer at 10,681' and circulated. Drilled out retainer and located top of cement at 10,691', indicating 17 sacks cement left in 7" casing and 163 sacks squeezed away through holes. Drilled out cement to 10,787'. Circulated and conditioned mud at 10,913'. Ran Schlumberger carrier gun and jet perforated 5-~" holes at 10,786' at 9:00 P.M. Had "Mud Spray" through oil saver on lubricator while pulling "perforating gun. Mud weight 82.5 pcf. Closed wireline rams and observed 250 psi on casing. Started Schlumberger out of hole. At 9:40 PM, casing pressure had dropped to 50 psi. At 9:55 P.M., casing pressure had dropped to 0 psi. At 10:15 P.M., Schlumberger out of hole, well dead and fluid was down 20' from overflow. Started in hole with drill pipe to condition mud. 83-84 pcf mud. NOvember 9 & 10~ 1965 Circulated and conditioned mud to 86 pcf. Ran Cement Bond log 10,909'- 9000'. Ran Tester. H.CT ~2, Shut-off Test 6n 5-~" Jet Holes in 7" Liner at_!0,786.'.~_ Tool Assembly: Same as for HCT #1. Ran on 8290' of 4%", 16.60# FHDP.and 2419' of 3%", 13.30~ IFDP. Used 2730' of water cushion. Set packer at 10,733', with 17' of tail to 10,750'. Opened tester at 10:09 P.M. for five minutes pressure release. Puff blow, dead 2 min. and weak bl~ next 3 minutes. Shut in tester at 10:14 P. M. for 1 hr. 16 minutes. ISI pressure period. Opened tool to surface at 11:30 P.M. for 1 hr 35 minutes flow test. No blow. Dead 62 min. Closed tool and surged perf's next 3 minutes. Re opened to surface at 12:35 A.M. November 10, 1965. Puff 1~; and dead next 30 minutes or balance of teat. Pulled and rec 70' rise in 4%" DP, all mud. Shut in tool at 1:08 A.M. for 60 minutes. FSI pressure. Pulled packer loose at 2:08 A.M. COMPLETION REPORT Page 13 NORTH FORK UNIT #41-35 SECTION 35, T. 4 .N., R. 14 U., Seward B & M STANDARD OIL COMPANY OF CALIFO?,NIA, WESTERN OPERATIONS, INC. - OPERATOR Final Pressure Data: Depth Gauge __ Top inside 10,718 Bottom inside 10,722 Top outside 10,745 Bottom outside 10,749 WSO - OK. IH ISI IF FF FSI FH 6548 3451 1218/1223 1218/1263 2187 6528 6577 3472 865/1236 1519/1280 2213 6554 5560 3461 1251 1251/1292 2217 6536 6599 3496 1257/1260 1257/1301 2240 6577 Ran 6 1/8" bit to'10,913'. Circulated and conditioned mud. Equalized 10 bbls 90 pcf. Black Magic 1.Iud. Estimated top at 10,652'. ,Novem..b..er 11-14.~ 1965 Ran Schlumberger carrier gun and shot 4 - ~" jet holes/foot 10,805' - 10,860'. Ran tester. ~CT #3, Production test on perforated interval 10~805'-10~.860'. Tool Assembly: Same as for HCT #1 and #2. Ran on 8290' of 4~", 16.60#.FHDP and 2419' of 3~", 13.30# IFDP. Used 2730' of water cushion. Set packer at 10,733', with 17' of tail to 10,750'. Opened tester at 1:19 P.M. for 5 min. pressure release. Observed weak air blow 2~ minutes then dead. Shut in tester at 1:24 P.M. for 120 min. ISI pressure period. Opened tool to surface at 3:24 P.M. November 11, 1965 for 66 hr. 20 min. flow test. No blow when tool opened for flow test and dead next 42 min. (4:06 P.M.), weak to very weak air blow next ~12 hrs. (3-4:00 AM 11/12/65), med. air blow next ~24 hrs. when gas surfaced (2:45 AM 11/13/65) with decreasing gas blow (occasionally heading) for next ~31 hrs. or balance of open flow test. No fluid ~o'surface. Shut-in and backscuttled out calculated 28 bbl/net rise (1970') all muddy water. Maximum salinity 195 G/G. Shut in tool at 9:44 A.M. November 14, 196~ for backscuttling. Pulled packer loose at 11:10 A.M. Final Pressure Data: Depth Oaug._e I_.H.H .!S! I_~F F_~F FSI F_~H Top Inside 10,719 6450 5053 1228/1248 1230/1757 Ail Clocks Bottom inside 10,723 6471 5078 1253/1300 1250/2030 ran out Top outside 10,746 6467 5070 1273/1321 1275/1794 Bottom outside 10,750 6500 5105 1265/1307 126~/2260 Conclusion: Test OK. Ran 6 1/8" bit and cleaned out to 10,913'. Circulated and conditioned mud. 82-84 per mud COMPLETION REPORT Page 14 NORTH FORK UNIT ~41-35 SECTION 35,. T. 4 N.~ R. 14 U., Seward B & M STANDARD OIL COMPANY OF CALIFORNIA, WEST~.RN OPERATIONS, INC. - OPERATOR November 15~ !96p Ran open ended drill pipe to 10,868'. Equalized 35 sacks cement. Preceed- ed cement with 30 cu ft. water, and followed by 5 cu ft. water. Cement treated with "Mud Kil" and 0.4% HR-4 retarder. Displaced with 756 cu ft. mud. Cement in place at 7:30 A.M. Pulled 3 stands and reversed out. Pulled. Ran 6 1/8" bit and circulated and conditioned mud at 10,600'. Ran in and located top of plug at 10,765'. Circulated. N~.ovember 16,..,19.65 Circulated until 2:00 P.M. Commenced redrill (41A-15) at 2:00 P.M. November 16, 1965. Pulled out. Ran Servco Milling tool to 10,165'. Circulated. Commenced milling 7" casing at 10,165'. November !_7..,. 1~96_5 Cut through 7" casing at 12:15 A.M. Milled 10,165'-10,190'. Pulled and changed blades in mill. Reran milling tool and milled to 10,197'. Npvember jl8..~ 19.65_ 82 pcf mud Milled to 10,207'. Milled a total of 42' from 10,165' to 10,207'. Circulated hole clean. Pulled. Ran 10 5/8" underreamer and opened milled section 10,165'-10,207'. Circulated and conditioned mud at 10,350'. Pulled. November 19,.. 196_5 83 pcf mud Ran Halliburton stinger and washed hole i0,165'-10,207'. Unable to get below 10,233'. Pulled and ran 6 1/8" bit. Cleaned out 10,207'-10,350'. Circulated and pulled. Ran open ended drill pipe. Circulated and con- ditioned mud at 10,350'. November..20, 19,65 83 pcf mud Equalized 100 sacks construction cement and 15 sacks sand through 4%" & 3%" drill pipe hung at 10,350'. Cement treated with "Mud Kil". Preceeded with 30 cu ft. water and followed by 5 ct ft. water. Displaced with 700 cu ft. mud. Pulled 6 stands, closed rams and applied 2000 psi surface pressure. Cement in place at 1:45 A.M. Estimated top of cement at 9837' in 7". Reversed out trace of cement. Pulled and W.O.C. Ran 6 1/8" bit. .. COMPLETION REPORT Page 15 NORTH FORK UNIT #41-35 SECTION 35~ T. 4 N., R. 14 U., Seward B & M STANDARD OIL COMPANY OF CALIFORNIA, ~.~STERN OPERATIONS, INC. - OPERATOR Hit top of liner. Pulled and changed bit. Ran new bit and located top of cement at 9886'. Cleaned out soft cement to 10,050'. 82-84 pcf mud NoveMber 2_1, 1965 Cleaned out cement to 10,094'. W.O.C. Drilled out cement to 10,173'. Circulated to clean hole. Ran and set whipstock at 10,173', faced S 66° E. 82-83 pcf mud Npvemb~r 22~ 19.65. Drilled off whipstock 10,173'-10,181' with 4 3/4" bit. Ran 6 1/8" bit and opened hole 10,173'-10,182'. Drilled 6 1/8:' hole to 10,208'. November Drilled 6 1/8" hole 10,208-10,481'. 81-83 pcf mud November 27, 1.76.5 Added a total of 6500 gallons of diesel to mud system. Circulated and conditioned mud. Drilled 6 1/8" hole to 10,595'. 80 pcf mud November 28 and 29, !965 Drilled 6 1/8" hole to 10,750'. Circulated and conditioned mud. Pulled. Ran core barrel. November 3.0.,...196..5' Cored in 6 1/16" hole to 10,825'. Core ~/4: 10,750'-10,790'. Cut and recovered 40 '. 80-83 pcf mud pecem~er 1, 1965 Cored in 6 1/16" hole to 10,$59' T. D. Core ~5: 10,790'-10,849'. Cut and recovered 59'. Core ~6: 10,849'-10,859'. Cut. and recovered 10'. Circulated and conditioned mud. Pulled. COMPLETION REPORT Page 16 NORTH FORK UNIT ~/41-35 SECTION 35~ T. 4 N..,. R. 14 U Seward B & M STANDARD OIL COMPANY OF CALIFORNIA, WESTERN OPERATIONS, INC. - OPERATOR December 2~ 1965 Ran Schlumberger Induction-Rlectrical log 10,857'-10,168' and Sonic log 10,856'-10,168'. Ran 6 1/8" bit and cleaned out to 10,859'. 10' of fill on bottom. Circulated and conditioned for open hole test. ~ecember~ 3, 1965~ HFT ~1 Interval 10,808'-10,859'. Tool Assembly: 2 outside BT recorders 42' of 3 7/8" ' perf d tail pipe, left hand, dual 5%" type open hole packer, VR safety joint, hydraulic jars, 2 inside BT recorders, hydrospring tester, 5/8" bean and dual closed-in pressure valve. Ran on 7884' of 4~"~ 16.60# DP, 2606' of 3%" 13.30# DR 280' of 4 3/4" drill collars, etc. Used 2500' of water cushion. Set top packer 10,802' end bottom packer at 10,808', with 51' of tail to 10,859'. Opened tester at 1:20 A.M. for 5 minutes pressure release, l~eak air blow for 5 min.. Rotated to shut in tester at 1:25 A.M. for 60 min. ISI pressure. Rerotated to shut in tester at 2:25 A.M. for 90 min. ISI pressure period. Opened tool to surface at 3:35 A.M. for 3 hr. 35 min. flow test. Had weak air blow first 50 min then increased to medium air blow last 10 min. indicating tool probably not shot-in. Bled to 0 psi after 60 min. then weak air blow next 30 min. Weak wit blow next 60 min. then medium air blow balance of test. No gas to surface. Pulled and recovered 380' net rise. Top 215' black slightly gassy oil (Est. ~30~ AP1) next 2500' muddy water cushion, next 160' muddy salt water (Max. salinity 1400.G/G at bottom) and bottom 5' sand. Charts indicated original 60 min. ISI was actually open flow test, therefore test was actually open 4 hrs. and 35 minutes. Shut in tool at 7:30 A.M. for 90 minutes FSI pressure. Pulled packer loose at 9:00 A.M. Final Pressure Data: Depth Gause Top inside t0,792' Bottom inside 10,796' Top outside 10,855' Bottom outside 10,859' IH ISI IF FSI FH 6162 4072 1154/1234 Chart Time Expired 6242 5058 1223 3585 6242 6275 4124 1260/1287 Chart Time Expired 6258 4077 1258/1325 3605 6258 Conclusion: Good mechanical open hole test. Not too much jarring required to unseat packers. Packers in very good shape upon pulling. No rubber left in hole. Ran 6 1/8" bit and circulated and conditioned mud at 10,100'. 81 pcf mud Dgcember,,. 4,,~. 196_5 Cleaned out to 10,859'. Circulated and pulled out. Ran in open ended. P~ e 17 COMPLETION REPORT NORTH FORK UNIT #41-35 STANDARD OIL COMPANY OF CALIFORNIA, WESTERN OPERATIONS, INC. - OPERATOR' De. ce.mb.e.r. 5, 1965 Plug #1: Equalized 38 sacks construction cement treated with "Mud Kil" and 0.4% HR-4 Retarder through 4~" x 3~" drill pipe hung at 10,854'. Reciprocated pipe while cementing. Preceded cement with 30 cu ft. water and followed by 5 cu ft. water. Displaced cement with 750 cu ft. mud. Estimated top of cement at 10,654'. Spotted 10 bbls. high viscosity Gelpil% at 10,300'. Plug #2: Equalized 52 sacks construction cement treated as above at 10,250'. Reciprocated pipe and preceeded with 30 cu ft. water and followed with 9 cu ft. water. Displaced with 700 cu ft. mud. Pulled to 9867' and backscuttled. Cement in place at 5:30 ~.M. After 12 hours, located top of cement at 10,009'. Pulled out. NOTE: Resumed operations in original hole at 6:00 P.M., 12/5/65. Ran Schlumberger carrier gun and shot 5-~" jet holes at 8530. December 6~ 1965 Sgueeze Job on 5 - ~" holes at 8530'. Set HOWCO "DM" Retainer at 3410'. Obtained breakdown with mud at 2500 psi at 12 cuft./min. Mixed and pumped in 200 sacks cement treated with 0.3% HR-4 and "Mud Kil~. Preceded cement with 30 cu ft. water, and followed with 5 cu ft. Displaced with 678 cu ft. mud. Cleared retainer by 12'. Cement in place at 6:00 A,M. Estimated 12 sacks cement inside 7" (Top estimated at 8473') and 188 sacks squeezed through holes. Final squeeze pressure 3600 psi,. held 1000 psi on annulus during sq~eze job. W.O.C. and ran 6 1/8" bit. December 7~ 196~ Drilled out retainer at 8410 Located top of firm cement at 8520' indicating 180 sacks squeezed through holes. Circulated at 9500'. Ran cement Bond Log 9300'-8300'. Ran Schlumberger Carrier gun and shot 5 x 4" holes at 8540'. .Squeeze Job on 5 - ~" holes at 8540'. Set HOWCO "DM" retainer at 8410'. Obtained breakdown at 3000 psi at 12 cu ft./min, rate. Mixed and pumped in 150 sacks construction cement treated with 0.3% HR-4 and "Mud Kil". Preceeded with 30 cu ft. water and followed with 5 cu ft. water. Displaced with 686 cu ft. mud. Cleared retainer by 10 cu, ft. and staged last 10 cu ft. Pressure built from initial of 3200 psi 'to final of 5000 psi. Held 2500 psi on annulus. Cement in place at 11:30 P. M. COMPLETION P~EPORT Page 18 NORTH FORK UNIT #41-35 SECTION 35, T. 4..N. ~. R. 14 u., Sew. ard B &.M STANDARD OIL COMPANY OF CALIFORNIA, ~ESTERN OPERATIONS, INC. - OPERATOR Dgcember 8, 1965 Pulled retainer setting tool. Ran 6 1/8" bit and drilled out retainer at 8410'. Cleaned out firm cement 8520'-8540' , indicatin5 146 sacks squeezed through perforations. Ran to 9500' and circulated. 81 pcf mud December...9.~ 1965 Ran Cement Bond Log 9300'-~300'. Ran Schlumberger Carrier gun and shot 4-~" jet holes/foot ~563'-8573'. HCT ~4 Production Test on Perforated Interval 8563'-8573'. Tool Assembly: 2 outside BT recorders, 4' of 2 7/8" perforated tail pipe, 7" type "C" Hookwall packer, VR safety joint, hydraulic jars, 2 inside BT recorders, hydrospring tester, 5/8" bean and dual closed- in pressure valve. Ran on 8192' of 44", 16.60~ D.P~277' of 3%", 13.30~ D.P. Used 277' of water cushion. Set packer at 8519', with 17' of tail to 8536'. Opened tester at 1:15 P.M. for 5 min. pressure release. Ueak air blow increasing to strong during 5 min. pressure release. (After shut-in, observed gas to surface during bleed down of drill pipe). Shut in tester at 1:20 P.M. for 3 hr. 40 min. ISI pressure period. Opened tool to surface at 5:10 P,M. for 3 hr. 40 min. flc~ test. Turned well to flare and observed few initial sprays of water but no solid slugs. Flowed well thru 3/4" surface bean. Tubing pressure 25 psi first 40 min., 35 psi next 35 min. and 25 psi next 25 min. Shut-in at surface at 6:50 P.M. to install prover. Open thru 3/4" orifice in prover at 7:00 P.m. (tubing pressure built to 140 psi during shut-in) pressure at prover bled from 90 psi to 10 psi next 5 min., to 18 psi next 3 min. (rate at this time =220 }1CF/D). Heading fresh water spray next 12 min. heading mud spray next 15 min, thru steady fresh water spray next 15 min or end of test. Rotated tool to final shut-in and bled drill pipe to zero. Flared gas while bleeding down and gas appeared dry, Shut in tool at 7:50 P.M. for 60 min. FSI pressure. Pulled packer loose at 8:50 P.M. Pulled and recovered 415' rise (equivilent 4 bbls.) Top' 405'~ muddy fresh water and bottom 10' sand. Final Pressure Data: __ DgDth Gau~e 'IH ISI I_~F ~ F~ F_~H Top inside 8504 4942 3619 444/419 551/350 3431 4894 Bottom inside 8508 5003 3610 419 339 3420 4939 Top outside 8531 4972 3637 649/553 702/388 3443 4972 Bottom outside 8535 4909 3599 483 374 3406 4892 Conclusion: Good mechanical test. COMPLETION REPORT Page 19 NORTH FORK UNIT #41-35 .,SECTION 35~ T. 4N.~ R. 14 Il..,. Seward B & M STANDARD OIL COMPANY OF CALIFORNIA, NESTERN OPERATIONS, INC. - OPERATOR p~cember 10~ 1965 Ran bit and circulated and conditioned mud at 9000'. Ran Schlumberger Carrier gun and perforated with 4 - ~" jet holes/foot 8563'-8578' and 8592'-8602'. Ran Halliburton tester. December 11, 1965 HCT ~5 Production Test on Perforated Interval 8563~579' and B592'-860Z' Tool Assembly: 2 outside BT recorders, 4' of 2 7/8" perforated tail pipe, 7" type "C" Hookwall packer, VR safety joint, hydraulic jars, 2 inside BT reocrders, hydrospring tester, 5/8" bean and Dual Closed-In pressure valve. Ran on 8192' of 4~", 16.60~ D.P.~ 277' of 3~", 13.30~ D.P. Used no cushion. Set packer at 8519', with 17' of tail to 8536'. Opened tester at 1:22 AM. for 5 min. pressure release. Weak air blow increasing to strong after 3 min. with gas to surface after 5 min. (After shut-in, flared well during drill pipe bleed down). Shut in tester at 1:27 A.M. for 2 hr. 3 min. ISI pressure period. Opened tool to surface at 3:30 A.M. for 12 hr. flow test. Flared well immediately. Gas burned with good blue flame with occasional fine water sprays. Flowed well thru 16/64" surface bean for 1 hr. (Tubing pressure increased and stabilized at 300 psi after 20 min. Turned well thru prover with 3/4" orifice and observed 610 M/D rate at 4:20 A.M.) Changed surface bean to 32/64" at 4:30 A.M. and flowed well 1 hour and 50 minutes. (Tubing pres. sure dropped to 200 psi, then built to 400 psi and rat hole mud surfaced and flare went out at 4;50 AM. Intermittant water spray and declining tubing pressure next 40 minutes' and well cleaned up. Tubing pressure stabilized at 300 p.si. Turned flow thru proverand observed 1160 M/D rate at 5:50 A.M) Changed bean to 48/64" at 6:20 A.M. and flowed well 2 hours 20 minutes. (Had mud and water spray 5 minutes and well cleaned up. T. P. stabilized at 140 psi. Turned thru prover with 1 1/4" plate and observed 1150 M/D rate at 6:55 A.M. Returned flow thru flare line and well produced muddy spray and some sand particles next 60 minutes. Occasionally clean next 40 minutes. Changed surface bean to 32/64" at 8:40 A.M. and flowed well 3 hours and 30 minutes. (Occasionally clean next 20 minutes then spray put out flare. Difficulty next 25 min. keeping flare lit. Steady flare and water spray next 60 minutes then flare went out. ~ Intermittent flare next 25 minutes then steady next 70 min.) Changed to 48/64" bean at 12 Noon and flowed well 3 hrs. 30 min. (T.P. stabilized at 165 psi. Turned thru prover with 1" orifice and observed 1770 M/D rate at 12:30 P.M. Well produced steady next 3 hrs 30 minutes or balance of test) Shut in tool at 3:30 P.M. for 2 hr. FSI pressure. Pulled packer loose at 5:30 P.M. Pulled and recovered 369' fluid rise (equivileD£ to 3.3 bbls.) All muddy water 220 g/g Nacl max. COMPLETION REPORT Page 20 NORTH FORK UNIT ~/41-35 SECTION 35 T. 4, N.,, R. 14 W.~ Sew, ar4 B.,& M , , STANDARD OIL COMPANY OF CALIFORNIA, WESTERN OPERATIONS, INC. - OPERATOR Final Pressure Data: ,Depth Gau~e Top inside 8500' Bottom inside 8504' Top outside 8524' Bottom outside 8528' IH ISI IF FF FSI FH 4881 3603 740/424 465/452 3557 4850 4868 3594 801/529 527/476 3549 4842 4928 3634 882/711 610/525 3593 4901 4908 3616 1063/942 628/515 3580 4875 Conclusion: Good mechanical test. Circulated and conditioned mud at 9000'. December 12 and 13~ j~965 Circulated and pulled out. Ran and set Halliburton "DM" Retainer at 8500'. Ran Schlumberger Carrier gun and shot 4-24'' jet holes/foot 8045'-8005'. Ran Tester. HCT ~6 Production Test on Perforated Interval 8005'-8045' Tool Assembly: 2 outside BT recorders, 4' of 2 7/8" perforated tail pipe, RTTS type Hookwall packer, VR safety joint, hydraulic jars, 2 inside BT recorders, hydrospringtester, 5/8" bean and dual closed-in pressure valve. Ran on 7945' of ;.~" 16 60~/ FHDP Used no cushion. "I'2 , · . act packer at 7967', with 16' of tail to 7983'. Opened tester at 9:45 P. M. for 5 min. pressure release. Weak air blow increasing to strong during 5 min. (Gas surfaced during drill pipe bleed down and flared same) Shut in tester at 9:50 P.M. for 2 hrs. 5 min. ISI pressure period. Opened tool to surface at 11:55 P.M. 12/12/65 for 8 hrs. 30 min. flow test. Flared well immediately. Gas burned with good blue flame. Flowed well thru 16/64" surface bean for 40 min. (tubing pressure increased and ice formed downstream from bean) Changed to 32/64" bean at 12,:35 A.M. and flowed well 4 hrs. (Tubing pressure stabilized at 580 psi. Observed~e thru prover at 1:10 A.M. Rat :Hole mud spray surfaced at 1:40 A.M. and--flame went out. Inter- mittant to steady flame to 3:10 A.M. Shut-in at surface next 25 min. to change union. Tubing pressure built to 1500 psi. Re-open;Tubing Pressure stabilized at 780 psi with water spray and some hydrates at 4:20 A.M. Obse___~rved 3370 M/~e thru prover at 4:35 A.M.) Changed to 48/64" bean at 4:35 A.M. and flowed well 2 hrs. (Tubing pressure 450 psi. Observed 4360 M/D rate thru prover at 6:35 A.M.) Changed to 32/64" be~n-~-~:3-f-'~'~{'~"--~ flowed well 1 hr. 50 min. Tubing pressure stabilized at 810 psi for balance of test.) Shut in tool at 8:25 A.M. 12/13/65 for 2 hr. FSI pressure. Pulled packer loose at 10:25 A.M. Pulled and recovered 40' muddy water, 210 g/g. COMPLETION REPORT Page 21 NORTH FORK UNIT #41-35 SECTION 35~ T. 4 N.~ R. 14 ~.~ Seward B & M STANDARD OIL COMPANY OF CALIFORNIA, WESTERN OPERATIONS, INC. - OPERATOR Pressure Data: Depth Gauge IH ISI IF FF FSI FH Top inside 7949 Bottom inside 7953 Top outside 7973 Bottom outside 7977 4589 3423 176/642 408/1157 3345 4506 4531 3410 175/544 405/1158 3322 4524 4563 3405 136/614 362/1127 3316 4563 4613 3435 301/618 320/1149 3352 4519 Conclusion: Good mechanical test. Circulated and conditioned mud at 8327'. December 14~ ~965 Ran and set Halliburton "C.I." bridge plug at 8325'. Ran and set Baker Retrievable bridge plug at 6051'. Closed Hdril and pressure tested to 1000 psi for 10 minutes - OK. Removed BOPE and installed tubing flange. Tested to 3000 psi - OK. Reinstalled BOPE. Dec. em, ber. ,15 ~ .,1965 Pressure tested Blind rams to 2500 psi - OK. Ran in. Tested pipe rams and Hydrill to 2500 psi - OK. Retrieved bridge plug at 6051'. Circulated and conditioned mud at 8300'. December 16~ .!965 Circulated. Pulled and laid down drill pipe. Picked up 2 7/8" production tubing. December 17 and 18. 1965 Ran 2 7/8" production tubing. TUBING DETIAL Production String: K. B. To ground level Ground level to landing flange Landing flange Pup joint 3 joints 2 7/8" tubing Otis "S" Nipple in Pos. #2 66 joints 2 7/8" tubing Otis "S" Nipple in Pos. #1 181 Joints 2 7/8" tubing Camco MMMandrel Assembly with CEV 14.75 1.26 0.70 3.66 95.06 1.60 2082.44 1.58 5690.75 13.07 K. B. Depth 16.01 16.71 20.37 115.43 117.03 2199.47 2201.05 7891.80 7904.87 COMPLETION REPORT Page 22 NORTH FORK UNIT #41-35 SECTION 35.~ T. 4 N., ~. ~4 W., Seward B & M STANDARD OIL COMPANY OF CALIFORNIA, WESTERN OPERATIONS, INC. - OPERATOR Tubing Detail (cont'd) 1 joint 2 7/8" tubing Brown CC Safety joint 1 pup joint Brown 2 7/8" x 9 5/8" HS-16-1 packer 1 joint 2 7/8" tubing Camco "D" Nipple 2 joints 2 7/8" tubing Venturi Shoe Tubing Landed at K. B. Depth 31.62 7936.49 1.42 7937.91 6.14 7944.05 7.94 7951.99 29.79 7981.'78 0.92 7982.70 62.57 8045.27 0.66 8045.93 8046' NOTE: Ail tubing 2 7/8", 6.5#, N-80, 8 R Rg.2. Heater String: K. B. Depth K. B. To Ground Level G. L. To Landing Flange Landing Flange 3 joints 2 7/8" tubing Otis "S" Nipple in Pos. #2 76 joints 2 7/8" tubing with beveled collars and beveled collar on bottom of tubing string Heater String landed at 14.75' 1.26 16.01 .70 16.71 90.27 106.98 1.61 108.59 2402.55 2511.14 511'. Removed'BOPE and installed dual x-mas tree. D_ec.embe.r 19 ,.. 196j} Displaced mud with water. Filled tubing with 28 bbls. (2500') diesel. Well started flowing slowly. December 20~ 196.~ Flowed well and obtained samples. Flared gas. Shut well in at 5:30 A.M. Tubing pressure i2800 psi. Set packer at 7944' with 4000 psi. Installed Cameron Back Pressure Valves in tubing strings. Rig released at Midnight, December'20, 1965. COMPLETION REPORT Page 23 NORTH FORK UNIT ~41- 35 SECT.IQN 35, T. 4N., R. 14 II., Seward B & M STANDARD OIL COMPANY OF CALIFORNIA, WESTERN OPERATIONS, INC. - OPERATOR DEVIATION DATA DEPTH DEV IAT ION DEPTH DEV IAT ION 246' 0° 10' 8295' 0° 30' 398' 0° 15' 8721' 1° 00' 1134' 0° 15' 8911' 0° 30' 1600' 0° 15' 9096' 0° 30' 1842' 0° 15' 9288' 0° 50' 2000' 0° 00' 9804' 1° 30' 24107 0° 00' 9956' 2° 30' 2719' 0° 30' 10,070' 2° 15' 2997 0° 15' 10,136' 2° 00' 3215' 1° 00' 10,207' 2° 45' 3525' 0° 15' 10,283' 2° 00' 3832' 1° 30' 10,350' 1° 30' 3898' 0° 45' 10,443' 2° 00' 4055' 0° 30' 10,604' 2° 00' 4242; 0° 15' 10,764' 1° 15' 4304' 0° 20' 10,866' 1° 15' 4672' 0° 45' 10,980' 1° 00' 4762' 1° 10' 11,135' 1° 45' 5178 0° 30' 11,254' 2° 30' 5730' 0° 45' 11,375' 3~ 00' 6117' 0~ 15' 11,611' 3~ 00' 6553' 0° 45' 11,845' 6~ 30' 7240' 0° 30' 11,998' 7° 00' 7829' 1° 15' 12,137' 6~ 15' 8049' 1° 00' 12,334' 5~ 00' S. R. HAN 14166 SRH/sat - ! I~ 'Mb. 2nd - Min. "'' ' Ticket _Flow Time 6~ ~ ~ ~0 Dote ~ 2 ~ ~ Humber Cb~d In l s~ Mi~ 2nd Min. Kind H.,libu~n ~re.. Time ~0 ~ .... of Job ~ ~0~ Di~i~ Pressure Fbid ~ice , Depth B~nked D~lling BT. Hoar Top ,,,P.R.D. Ho.. ~ ~53~ ~ ~.k_ _B~ation ' Initial Hydro To~l Bo~m ~ud Pressure ~ ~06 ~ ~ ~2 ~pth ~ O z ~5~' Packer ~ ~'~' Formation i~Pres. ~080 ~072 Te~ ~0~08' ~ 10~59' Tested ~l~wP~s. -- ~ ~2~ Hole Size ~ ~../~ Perfs. ~Bo~. ~ _ Sur~ce ~. Bottom ~.? Pres. ~_ 2 ~ ~2' Cho~ Cho~ . Final Closed in Pres. . Size & Kind ~ ;H~ ~* Drill ~llars ....... ~ .,Drill Pi~ ~ a Z~ A~ve Tes~r Final Hydro Mud ' ~ud Pmssu~ = ~ Mud , , Depth Blanked Temperature , .F E~. Anchor Size C~. Gauge ~'~ F~TO ~f _ , ~ 'F At.al- · Length BT. H~r Dep~s Dep~ .P.R.D. Ho. ~ ~ 2~ ~ Cl~k ... M~;. From, ~.~ ~ ~ ~$.~ ..... T~;~r Va!ve iniHal Hydro TYPB ~OUN~ De~ Bock Mud Pr~. ~70 ~2 Cushbn ~G~ ~ Ft. Pres. Valve Initial CI~ i~ Pres. ~O~ ~{.0~ Recovered ~ Feet of Initial ~ ~0 ~ ,~. ' Flow Pr.. _ Z 1278 Recovered 1.60 F~ Final Closed .... , ' ,, Final Hydro Oil Water .,_Mud~. , ,,~ , ~~'~ , _~.~.l. Gmvi~ ~ ,,. , Spec., ~avi~ Depth : Blon~d Gas _ , . Su~ce " ~ ~ " ~u~ ~ BT. H~r Tool A.~. Tool ..P~R.D. N~. 2~,252 ~[~ Cm~k .Opened I :20 A.H~ P.M. Initial Hydro ~ud Pr~., "'~ -~7~ .... Remarks ,. ~ DO~ ~{~, ~.0, ~'F~A~ Initial Clmd Initial ~ ~7~ i ~ ' ~ ...... ~..; ~ 25 ~ z~~ ~ ~ ......... Flow Pre,. --~ 2 ~ ~ in P~s. = Final Hydro I ii Iiii II I f I i III FORMATION TEST DATA · . i Io~ed~ln Is-I- &Un. ~ '~'~"-~'~'~~ ~ ' Ticket ow Time ~ ~ ~ ~0 Date 0~ ~0~ Number ............... I.~ G. 2nd Min.i ~ D ~ Kind Hallibu~n AN~}tO~G~ . ~.. Time ~ of Job Dt.~i~ . ~ssu~ Fie~ ~ice ~ ~ ~rre~ed Te~er Wi~ess ~ ~:~ , epth ~O~ ~. Blan~d Drilling ~ c ~p Gaug~____~ ~ ~f Contra~or Hou~ Top T. -~ ~2~ .R.D. Ho. Cl~k ~etlen Packer ~iti~l Hydro ~ ~ F ~ ~ ~ ~8 T°~l BoSom Cud Pressure ~ Dep~ Packer : nitial Closed ~ ~ 2B ~ O ~ ~ Inbrv, I ~ P~s. Test~ Tested ' , n~al .... ~asiag or "iow ProS. I 1 ~1~9 Hole Size Perf~ [Bat ..... '" :~ 3oo i 12"~ .... :inal .... Surface BoSom :~w Pres. 2 '~ ~ ~ ~ Choke Choke z ......... ' O I.D. . ~EHGTH · :inal Clos~ ~ G~ ~ ~ Size ~ Kind Drill ~llan n.P~s. '. . " _ _ ~ Drill Pipe ,. . Above Tes~r ..... Mud Mud :inal Hyd~ ~5.~ ~G' ' ~ud P~ssure ~- Weight ~is~sJ~ II ~ i . I ~ i [ :e~. ~uge . ~. ~f ·F A~ual & ~ngth OD~ ' ~. , ........... BT. H~r Dep~s Depth of K.~.D. No .... , .... c~ . Mea. F~ ......................... Tenet V. lve ......... F~. ~ AMOUNT Initbi Hydro Depth Back ~d Pr~ ...... ,. , Cushion ....... Ft. Pres. Yelve F~. Initial CIo~d Initial I ............................... Pl~ P~s. Z Recovered Fm of ....... , ,, ,, ....... I~ ......., . ~ ~, , , , Flow P~s. 2 RecoY~ F~ of , , Final Closed in Pr~. ~,,, Recovered Fe~ of . ~ , ,,, i ~ ~, . ~ Final Hydro Oil Waif~ z ..... .-~. A.P.I. ~Yi~ Spec. Gmyi~ Mud P~s .[_~ I[ ..I.II Ii II i i , .... i i i De~ Blanked Gas Sur~ce ~. Gauge ....Ftc_ ~ _ ~f G~pvi~ Pressure ... psi . . I I . J L I I I Iii I IIIl[ll I I I I ] .............. BT. H~r T~I ~.~. Tool *-~. P.R.D. No. ,,,, Cl~k Opened P.~. Closed P.~. K~ ~ . I ~1 I II III I i ~ I III . . In.iai Hydro Mud Pr~. Remar~ ~ . , ,_ , , ~, ................ · Initial in Pres. ....~n:t:al ' I FIo~Pres. 2 ' * i ii - _~ i i i .... i iii iq I. I i i i , ii Fbal I . ~ ~, Final CIo.d in Pres. ,.,,~ .... ,, , final Hydro Mud P~s. FORMATION TEST DATA Gau~e ,,Ho. PI P~ P8 m253 Firat Period Time hfl- oOOO .089 .178 .267 Gauge ,,N. o. P0 I)1 PSIG ,, ,,115~ ,~73 1192. 1203 ,000. .o468 . O936 , ., .lhob' :, °2340 1212 ,,, Ps 1217 :!.525 Ill, 1! U I ,, REMARKS: 1167 1,185 , 1197 12o5 1213 Depth 10~ 792 ' Init&al Cioeecl In' Pressure Time Deft. .0~88 .1376 .3~ho .55o~ .6190 Depth, o000 ,,,, ,0~5 .070 , ~ , ,.~, .~05 , ~. L t+O PSIG Temp. 1217 2597 3160 3461 3655 3787 3887 ~o25 4072 .175 ~210 ? _ ~5,, °280 , , , _ ..3~5o ,, '96' ,. 1213 2783 ~, 2,3,8 ,~So-~ 368~ Clock 12 Second Flow Period Time Deft. PSIG Temp. Clock III o000 123~ i i 24 1223 hour .292 .~8 .584 3797 , ..1248. 125,6 1258 3891 3967 4023 ho58. o73o ' ' ' 16 ........ * C~L~RT"TI~' ~'PI~ AT THE END Or APPROXIMATELY 1278 Ticket I~o. 382465 Final Cleeed In PfesIure TheDefl. _ .000" ~lT hour i 111111, 11 , ° 000 .o3~ ,06!0, .o~m,5, .1220 ,183o 02135 °2440 ,.2745 .2900 c! 10 PSIG .... 1278 2.1~7 ., 2849 · ..3038 ...3187. i .3306 _. 3205 .._ · 3~86 .... 398~**~ AAinutes 60 MINUTES OF 2ND FLOW. UNABLE TO READ. '*~,* .LAST INTERVAL = ~; NINUTES. Iii Illll Il ~ . i i Illl I Ill SPECIAL PRESSURE DATA iiii ii ,,,... ~ · No. 1252 Fir~ Flow Period PSIG r, o000 .0924 .1848 .2772 · 3696 __ .462o 1227 1215 .1235 1249 1254 1260 Initial Closed In' P~enure Time Deft. .000 .o667 .1.334 o20Ol .2668 i°.~ .3335 .4oo2 _ .4669 .5336 t-Fo PSIG ?emi). 1260 2671 3224 3521 3709 3839 3936 4014 4077 Clock 12 hour Second Fbw Period Time Defl. .000~' .000 .450 PSIG Temp. Corr. 1279 1287 Ticket 382; Final Closed In Pressure Time Deft. PSIG Tmp. .... . Gauge No' Po P~ .Ob6b P2 .0928 P, , P4 ,, P, p~ P, _ Reading Interval 01392 .1856 .2320 . :],52~ 1230 1211 ,, 1230 1244 1251 1258 .6oo0 Depth o000, 00339 .O67,8 ,, ., .1o!7,, .1695 .2034 .2373 .27:]1,.2 03050 ,, Zd 4124 ¢,ock . 1258 o000 1289 2581 3164 3421 ,,,1426 .2852 .4278 3662 .5704 3795 · 7130 3891 3964 4o26 4077 128.9 1294 _ 1304 1313 ,, ,13,25 hour iii :0313 .062,~ , .00939 .!2~. 2 ' ....1~6.S ..,1878 .., .2:1.~1 . .... . ...2SO~. "/.,'i .28'1'7 . .2~?o .... 13,2,5 . , 2,062 , ,., 2,512. .281o . .3o3'~ . ~ 3419 . 3~?h Minutes REMARKS: * CHART TIME EXPIRE~ AT THE END OF APPROYIMAT~,Y ~B MINUTES OF 2ND wt.~_~ ~* 'I~ST INTERVAL = 5 NINUTES. SPECIAL PRESSURE DATA UNITED STATES DEPARTMENT OF THE INTERIOR G£OLOGICAL SURVEY Budgot Bureau ~o. 4~-R356.&. Approval oxpiros IZ-31-60. L~ Omc~ ..... .~.n..q~.o.~.~_~_e. .......... ............ LESSEE'S MONTHLY REPORT OF OPERATIONS State ............ .A..l..a..s..k..a. .......... Co~tll .................................... Field ........... .~p___l_.o.~_a__Lo. ry .................................. TAe followin~ is a oorreo~ repor~ of operatior~s and prod~e~ioz~ (inel~dir~ drillin~ and prod~cir~ wells) for t; e mo, th of .............. .V.._e..c..e..m.b...e..r.. .......... , , ..... .,15e~t's address ....... ]~.,...0.,._]~.O~..?_-__8.~9 .............................. Company .......... (' ..................................4n......................... $iS~ed ............. C -.~-.V: - -E~T~ERT01~ ~: .............. Pl,,ne ................................................................................... ,'lger~i' s title----D/-s~-v~et---Super-i-n~e~/er~t .... WELL O&xo BARRELS Oe OIL J GRAVITY CV. FT. OF OAS GALLO)TS Or BARRELS or REly[ARKS eec. A)TD TWF. R~)TGE ~TO, Z'nemmD RECOVERED none, 8o shire) d-re and renult of test for pooiho J~ or ~ (Tn thousands) (}ASOLINE WATER (If (lit dr/llLuz, depth; if shut down, cause; NE% CONFIDEN] !A,L .- NORTH FORI: UNIT ~& 1-35 EX..P.ORATORY ~ELL 35 T4S R14~ Cored in 6 1/8" hole lo, 25' - 1£,859' T.'.). Ran I-ES and Sonic Lot . ' ............................... Ran Open Hole Formation 1:est of ~he inter'~al 10,808'-10,859' Opened t~.ol Eot 3 hrs. 3~i min. flow test. Shut in tester f~ 90 min. FSI. Pulled res .er and recovered 380' net rise (21~ oil = 1.~.6 bbls. 160' saint water = 1.17 bl)ls and 5' sand). · Cleaned cut to10,859' ami equalized 38 sa,:ks cement a~ 10,81 (Plug i~l) Estimated top of cement at 10,,554'. Plug I~2: Equalizei 52 sacks cemenl' at 10,250'.accr,)ss milled section. Located top of plug at 1~),009'. Shot 5 x ~" holes at 8530' Set reta~.ner a ~ 8410' ;queezed holes vi':h 200 sacks cemenl Cleaned c.ut to 10,009;. Ran CBL. Shot 5 x ½" holes at 854~ Set retainer a~- 8410'. '.queezed aoles at 8540' w/150 sacks .cement. Clean:d .o~t to ~500~. ~an CBL. Shot 4 x ~" holes, foot 856.~' - 8573' and r~n HCT I~4. Flowe, dry gas at 300 - 350 HCF/I rate. Recover,~d 415' rat rise. Circulated at 9000'. ~eperf~)rated 856~ ' - 8573', and p,;rforated 8573 * - 8578' ani 8592' - 8602'. Ran HC~ I~5 on i:~tervals 8563' - 8~ Observed 1150 .~CF/D rate.: 140 psi, 48/64" bean with some wa: Set D..H bridge ~lug at 85(t0'. Shc~ 4 x ~" holes/foot 8005' - 8045' for HCT ¢~( Observed dry as flow of 4360"1~ DISTI.IBb'I.ION: rate on 32/64" bean. T.I. 810 psi. Set retrievabl·- plug at (i051* and instalL;d tubing head. Stat~ - ~.R.,~arslmi1 Set packer a~ t944'. Ra~ 2511' of 2 7/8" heater string. C. ~ Pe~ry Removed BOPE a ~d instalh~d x-mas ~ree. D::splaced mud and R. R~ Rit~er flied well clean. Set lacker with 4000 ~si and shu~ veil gxplc.ration Rig releaised a- midnight 12-20-65. File Open fl~ pote~tial test to be ru~ at a l~ter date. 8 60.2 *, wateT. No?n.--There were ..................................... runs or ~les of oil; ............................................ M on. f~. of ga~ sold; ............................................. runs or s~les of gasoline during the month. (Write "no" where spplla~ble.) NoTa.--Repor~ on this fo~n i~rei~ui]~l ~rie~ ~]~e~ar month, regardless of the status of opera,ions, ~nd mus~ be filed in duplioste wi~h She supervisor by t~ 6~, ~ t~e tue~on~h~ unless otherwise dire~d by ~he supervisor. FOFXl2 9-829 18-46700-8 u.s. GOVIRNMENT PnlNVln8 office DIV ~oN OF ~F..S & ~tNF-~..-~ , ( .... ... ~CHORAGE I I i ; Anchorage, Alaska December 16, 196~ PRESS RELEASE Standard Oil Company of California, Western Operations, Inc.,. Operator, Richfield Oil Corporation, Sunray DX Oil Company, Union Oil Company, and ~rathon Oil Company today announced a new dry gas discovery in their North Fork Unit ~41-S5 Well. This well is located l0 miles north of Homer and 8 miles east of Anchor -Point. It tested .at.. rates of approximately S, S70 ~F per day of dry gas on a 1/2" surface choke from a sand at "a depth of 8,00~'. d,Z.~,x. ,i, .. UNITED STATES DEPARTMENT OF THE INTERIOR GEOLOGICAL SURVEY Budget Bureau No. 42-RS~LS. Approval expires 12-31-60. ~A.0 0mC~ ..A~h~ra~e ............. ~ .u,~.~ A.-.O~3ti3 ............... U.,T ..... ~r.tk..~k_.~n~t ....... LESSEE'S MONTHLY REPORT OF OPERATIONS ~ Or ~ ~P. RANGB WR~ DAn GAINS 0r ~ARRR~ Or RE~AR~8 NO, P~uomn (~ ~o~) ~E~VBRRD nono, 8o 8~te) ds~ ~d rMMt ~ o~t of ~ ....... 35 T4S ~14~ To,al Depth 12, ~12'. Ran I-ES, So~c and (:onC~nuous D~pm~Ce~ Ran and ce~ente,i 2655 * of 7*' liner a~ 10,91~5' Cop aC 8330 Cleaned ou~ ~o t330' and f:queezed liner 1at with 100 sacks cement. Tested lSner 'lap ~o 2750 ~si - OK Cleaned out cem, in 7** liner ~o L0,913'. f.hot 5-~i~* holes al 10,785* and tested '~C~ I~1) W.N.S.O. ~,luEged test. Sqtmezed holes 10,785* wiCh 18~) sacks cen~en=. Cleaned our cement and sho~ 5-%" holes a~ 1~),786* and tesCed (t~ t~2) %~S0 - OK. Perfora' inte~aLlO.805 -10k8~.0* ~'i~h 4-%" holes/'fi,ot. Ran H~ ~3. Opened foz 66 h~)urs flow test. ~e~overed ].970' nec muddy water. E, tualSzed 3~ sacks camenc a~ 10,868', ~op of cemen~ ac 10,76~*. ~11ei ouC 42* section in 7'* casing 10,207'-1( ,165' and equali.zed 100 sacks ce~ent ac 10,350', across milled s~cC$on. Dztlled ou~ fi~ c~menC to 10,173* Se~ whipstock a" 10,173' ~.nd redrilled in ( 1/8" hole 10.750 *. Cored. :o 10.825'. Co~iDz DIS~~ION: % · ~.S.G.S. - ~?. J L~nton. (2) ~aCe - T,; ~, M~rsha1X (1) "-" .t o ', OlVISI.O~ OF MINES a .MINE~ ANCHO~ ~E merit :d No~.--There were ...................................... runs or sales of oil; ............................................ M cu. ft. of Sas sold; ............................................. runs or sales of gasoline durin~ the month. (Write "no" where applicable.) HOTE.--l~eport on this form is required for each calendar month, regardless of the status of operations, and must be, filed in duplicate with the supervisor by the ~h of the succeeding month, unless otherwise directed by the supervisor. ~ 9-8~9 O'anuary 1950) l~-aa?oo-s U.S. GOVERNMENT PRINTING Of'PiCK ST~ ,F ALASKA SUB~rXT ZN TRY'''~ ' (Other inetrueti~ OIL AND GAS CONSERVATION COMMISSION verse Mde) .TE· SUNDRY NOTICES AND REPORTS ON WELLS (Do not use this tore top proposals to drill or to deepen or plug bask to & different reservoir, Use "APPLICATION FOR PERMIT--" for much propoealL) O,'-W..LL [~] OAewE,.,. [--] OTHn Exploratory NAME OF OFEK&TOa Standard Oil Company of California, Western Opera~tons, Inc. 8, ADDBEEB OF OPERATOR I'. O. Box 7-839, Anchorage, Alaska 99501 4. ~.OCATZON Or WELL (Report location clearly and in accordance with any State requireme,~tL· Bee also space 17 below.) At sur~ee 659* West and 655~ South fr~ NortheRs= Corner of Section 35 T. 4 S., R. 14 W., Seward Base and Meridian 14. FSRMI~ .NO, IS. ELUVAT~ONS (Show whetheF Dr, BT, o~ e~.) Effective: July 1, 1964 LEASE DESIGNATION AND BBRIAT, NO, A-024363 6. IF INDIAN, ALLOTTEE OR TRIBE. NAME ?, UNIT AGREEMENT NAME · '. North Fork Unit: . 8, FARM OR LEABE NAME North Fork Unit . 9. W~..L NO. 10. YIELD AND FOOL., OR WILDCAT BUuVBT O~,' &aBA ':'R. 14W. SB&M 35-T. 4S. , , 12. BOROUGH .. 'J 18. STATE Kenai.J Alaska 16. Check Appropriate Box TO Indicate .Nature o{ Notice, Report, or Other Data ' NO~*CS OF INTuNTZON TO: SUBSEQUENT REPORT OF'** FRACTUUE TREAT MULTIPLE. COMPLETE FRACTURE TREATMENT · SHOOT OR ACXDXZB ABANDONe SHOOTING OR ACXDIZING REPAIR WELL CHANGE PLANE (Other) (Other) NOTE: Report results of multiple completion on Well ompletion or Reeompletion Report and Log form.) .. DESCRIBE PROPOSED OR COMPLETED OPERA~IONE (Clearly state all pertinent details, and give. pertinent dates, including eKimated date of starting any' proposed work. I~ well is direotlonaHy drilled, give subsurface loeb, lens and measures and true vertical depths for rdl markers and sones pert1*' mt to thio work,) * ....... Confirm~ng telephone conversation VonDerahe-~iCney, December 3, 1965, .:'. ".-" ~i ~ORE DONEI' l, Equalized 35 sacks cement at 10,868', top at 10,765'. ": . ~.:.:::, ..:. .... ..? 2. Milled out 42' section in 7" casin§ 10,207~-10,165'. '" 3. Opened milled section to l0 5/8", '.': '4. ~.qualized 100 sacks cement at .10,350~, across milled :section. 5. Drilled out £irm 'cement to 10,173~. ' 6. Set ~h~pstock at 10,173', and redrilled in 6 1/8" hole to. 10,750'~".. ., cored 10,750'-10,859' T, D. .' '" :. ', 7. Ran Z-ES and Sonic ~o§. .... " 8.. Set packers at 10,802'-~0,808" and tested ~n open ho'le interval ~0,808'- 10,859'. Recovered 380* net rise durin~ a 3 hr. 35'min;" flow test; Formation yelded o~l and salt ~ater. 'Interval tested tight and-w.e.~. ,., .. PRO?OS~.; l. Equalize cement plug' in 6 1/8" hole ~0,859'-~0,650'... ,. ,..'. 2. Equalize cement plu§ across stub.end o~ 7" 'line~ 10,2~5:-10,025'. above 10,115 ~ .) ,::J ~. ".' ~'~ · '". ' (Top to be~,, 3. Shoot 5 x holes, at 8530' and squeeze ~ith .est .... i00 sacks. cement,. , ,, 4. ' Clean out to ~:~0,'025 ~, .... ' .. 5". Run C.B.~. ' · :'. ..... :"' .' 6. Depending on C.B.L. wi[l per~orate and test the inter~bls "8563'-8573 , :. .'.,' ,, . . ... . , and 8005 ' ' 8045 ' · 18. X herebF eert, ti~t~tt~-t~Toreg?)~..,.~__e,,!~' a~ ~,~ . (This space fez Federal .or I~tato/~f~so uso) APPROVED BT co~m~xo~n o~. ~'FR'O?AL, LF ~: / *See Indmcflons on Reverse Side .( · .~,,V,olOj~ OF.MINES & 'M,~RA,..: AJ',!CHORAG~ Form ST/"""' OF ALASKA SUB~IT zN (Other instrue~ OIL AND GAS CONSERVATION COMMISSIONverse side) .'ATE· on re- SUNDRY NOTICES AND REPORTS ON WELLS (Do not use this form for proposnls to drill or to deepen or plug back to a di~erent reservoir, Use "APPLICATION FOR PERMIT--" for such proposals,) oIL wE~.L [-] OAS Exploratory WELL ~*~ OTHER NAMB OF OFERA~Oi Standard Oil Company of California~ W0I 8. ADDRESS OF Or~sATOR P. O. Box 7-839, 'Anchorage, Alaska 99501 4. LOCATION OF WELL (Report location clearly and in accordance with any State requirementLO See also space 17 below.) At surface 659' 14est and 655' South from Northeast Corner of Section 35, T. 4 S., R. 14 I4., Seward Base and Meridian 14. ~ltMIT NO. 15. ELEVATIONS (Show whether DF..BT. OB. eto.) Effective: July 1, 1964 LEASB DESIGNATION' AND fBBBIAL A-0 243 63 INDIAN, ALLOTTE~ OE ?, UNIT AGREEMENT NAME North Pork Unit 8. FARM OR LEASE NAMB North Pork Unit 9. WELL NO. ~41-35 . 10. FIELD AND POOF~ OR WILDCAT - .Wildcat ,, 11. SRO.. T,, R.. M. on BL~. A~fD SURVBT Ou ARBA 35 - T 4 S, R 14 ~., SB&H 12. BOROUGH -, '[ 18. Kenai ] .Alaska xe. Check Appropriate Box TO Indicate .Nature si~ Notice, Report, or Other Data. NOTIeB OF XNTUNTION TO: . SUBS]BQUBNT RuFOR~ OF': T,,T WATER ,HUT-OFF ~'~ PULL OR 'ALT,R CA,I,G ~'~ WATER,HUT-OF, ~'~ . R.PAIRING WELL ~ ..oo. I--I L-=.L ,.oo.,. oR Ac,pi.. I I ARA'DONM..T* :l--I "' aSPire WaLL . i' J CHINO, ,LAI~, ~ (Other)' .. ,' (Other) · [ ] ' ' . (_NoTs. :..Report_results. o.~. multiple, eom. p!etlo.n Oh',Well ' · ' . ' , , , ' · ~ompienon or aeeompiet.!en a~or~ aaa z,ogroFm0, . ,., l~. DaSCRIBE I'aOPOSED OR COMPL~'L'aD O~'ERATIOiS (Clearly Kate all pertinent details, and ~lve pertinent dates, ineludinf estimated date of startinf an ' . .p~,po+s,,ed+~or_~.I~ w~l Is dlreetlo~ d~li,~ rive subsur~iee lo,~tlons and measured and 'true vertical depths for all markers and 'sones pert[-' ' ' . SUBSEQUENT I~PORT . . i.... ..' '........' ,.:.:.: ...: , ' 2. 3. 4, 5. 60' 7. 8. 9 o , · WORK DONE: ; Cemented 2655' of 7" liner at 10,985'. top at 8330'.. · '," Squeezed liner· lap with 100 sacks cement and tested to 2750 ;UsA Cleaned out cement in 7" liner to 10,913'. Ran' CBL and gamma ray - neutron collar logs. :'. '"" Shot 5 x %" holes at 10,785' and tested. (WNSO) .. "". .... Squeezed holes at 10,785'. with 180 sacks, cement. ": ' . . ,.... Shot 5 x ~" holes at 10,786' and' test'ed~ :.(WSO .-...ok),. i:~:~,,"!~-:'~',',,;,~ Perforated with 4 x %" holes/£oot 10,805' - 10,860,. .. Ran tester. HOT ~3, 10,805' - 10,860': " Used 2730' of water cushion, set packer at 10,733'. Opened'"t°oL' for ',., 66 hrs. flow test, Dead first 42 min, weak to Very weak blow' next ..... 12 hours. Medium air blow next 24 hours when gas to surface'~ .... "' ~'' Decreasing gas blow for balance-,.,'.ibf test. Recovered 1970' {~Udd~' .::' .' water rise,salinity.l'95%,.' ' : "' .'. ,,'. :'. Plug back)mill out seCtion in 7" casing a~ '+ 10,200~ 'and"redrt'lL,. (This space £0T Federal or State office use) APPROVED BY CONDITIONS OF APPRO~AY~ IF ~: TITLE ,, · *See Instructions on Revene Side Form ST/' JF ALASKA suB~z~ z~ (Other instruct!. OIL AND GAS CONSERVATION COMMISSION verse side) ATE. ~n re- SUNDRY NOTICES AND REPORTS ON WELLS (Do not use this form for proposnls to drill or to deepen or plug back to a different reservoir. Use "APPLICATION FOR PERMIT--" for such proposals.) OIL WI~LL ~-] OAS -'-'-'. [-] OTH~a Exploratory 2. NAME OF OPERATOa Standard 0il Company, of California~ WOI 8. ADDRE88 OF OFg~A~ ~, 0. Box 7-839~ Anchorage~ Alaska 99501 4. LOCATION or WELL (Report location clearly and In accordance with any S~te requ[~ements, e 8~ also space 17 below.) At ourf~ce 659e WesC and 655~ Sou~h from Nor~heas~ Corner of SecCion 35 T. 4 S., R. 14 W.,. Seward Base and ~r~d[an .. 14. PBnMI~ NO. 1~. ~VATI~N8 (S~ wh~er Dr, .RT, OB, ~) mmmm mmemmmmmmmm Effective: July 1, 1964 §. LE&~JE DESlONATION AND aRRIAL NO. A-024363 ___ 6. IF INDIAN, ALLOTTEE OR TIIIBE NAME ?. UNIT AGnEEMENT NAME North Fork Unit ~. FARM OR LEA,~ NAME North Fork Unit 9. WBY, L NO. ,. (~41-35 10. FIELD AND FOOL~ OR WILDCAT Wildcat ,U~¥ET OR AI~A 35 - T 4 S. It 14 W., SB&M 22. BOROUGH, .. ~1 :tS. SWATh Kena i ~'J Alaska 16. Check Appropriate Box TO Indicate Nature of Notice, Report, or Other Data NOTZCE O, Z'~'NTZOX SUBSEQUENT RBPOR~ OF': FRACTURE TREAT MULTIPLE. COMPLETE FRACTURE TREATMENT ALTERING CARING ,HOOT OR ACIDIZE ' ABANDONS ,~ ,HOOTING OR ACIDlY. lNG ] ] ' ABANDONMENTS ' I--J REPAIR WELL ' CX~ANGR PLAN, (Other) ' , if ] (Other) NOTE Report results of multi lee 1 · ~ .: _ . _ P o petlon on Well .' , uompletion or ~eeomptetion ~eport and M~ form.) :. lT. DESCRIBE PnO~SnD OR COMPLeteD OPBRATIO~S (Clearly state ~11 pertinent details, and ~lve pertinent dates, ineludlnE ~mated date of_i~rtlnf any" p~posed ~r~ Xf ~11 is di~o~on~y d~ wive mub~e htions ~nd mess,Ired and true vertie~ depths for '~1 markers and sones ~rtt-' PRESENT STATUS: neat to this work.) · T.D.. 12,812';' 13 3/8" casing at 2000' .." '" '..' :.'":.':' '.. +: . , :,, 9 5/8" casing at 8451';. 2655' of 7" liner !'.. :- .': ..:", PERFORATIONS: . . ... ,., PIt0POSE: ' , ,. (~emented. at 10,985', top .at 8330'.. Effective depth... 10,913"..· ' .... "'....."". 5 x. ~". holes at 10', 785 (T~TS0, squeezed) ' ' ..' :.. .- '"' .. ' . " 5 x. %" ' " "" 10,786 (WSO) ". ' ' .~. · ... Z~ X ~" holes/foot: 10,805' '- 10,860'.. " :.: .., '." · . .., .' , '. ...' . 1. Equalize 35 sacks cement at 10,868' est top. at 10,728"' :' , ' , ' 'e · ,' 2. Run mill and mill out + 30' section of' 7" casing at ,; ' ,,., .., " + 10,200' ...... · . 3..... Open milled section and place + 300t cement plug .'from. '~ :' "i'.: · + 10,100" - 10,400'. --. ". '. ~"" '.; 4.. D-rill out plug to 10,185 '+ set whipstock .nd'!~'irectional17 · .:,'. "' drill 6" hole to + 10,980T.'..'' ...; '. '. .'. ..... . ... '....' 5.Run logs and cement approximately 1000', of 5".. :liner on' bottom. ' · , 6. Test liner lap. . ~!~,.:>. [,, ,.,, ..... :.',. ,,... ,.., 7. Obtain WSO's as necessary.' .. "1: ~: '~,. 8. Perforate and test a's indicated. :".'-'" '.'. : · ?!'V'!'~.;i::.:,,.::~ ...: .:_ .....,...,:.. :.:., .i~ i','"~'i;,::','..;'/,': '.,' .~ .... ; '-f( ...... . ___ . . ,. · / ~ ~ " . ~' ' . . . APPROVED B~ , . CONDITXO~ OF ~PRO~A~ ~. ~ ~' .. " . ., . .. ; . ', .. .. · .., . .. . '~x~LE District Superintendent nA~ 'No___~vember 22j--~1965 · . TITLE "' . ......" *See Instructions on Reverse Side . , . , . · . . . · . ,.. · . . ,. · · .. , . , ,, · . Form 9-331 (~[ay 1963) ,IITED STATES s,BmT ixk ?r,IC,XTE* (Other tnstr jus on re- DEPART ~NT OF THE iNTERIOR ve,'~side> ~h'~EOLOG ICAL SURVEY /%'# Form approved. Budget Bureau No. 42-R{424. 5. LEASE DESIGNATION AND SERIAL NO. A-0X~z~3 6. IF iNDiAN, ALLOTTEE Oft ~?RIBB NAME ..... :c AND REPORTS ON WELLS SUX./..,'.Y ,'--.,...; ...-.~ (Do ~ot use thJx f, .','.~ f.r pn)posals ' drill or to deepen or plug back to a different reservoir. Usc "APPLICATIO% FOR PERMIT--" for such proposals.) ~. 7. UNIT AGREEMENT NAMe] ..... L~ ,;ASw~r, ~ o~n~a Exploratory North Fork Unic ~. N,LM~ 02 OPEgATOR 8. FARSi OR LEAS~ NAME S:andard 0il Company of California, W0I North Fork Un2t 3, ADDRESS OF OPERATOg 9. WELL NO.' P. 0. Box 7-839, Anchorage, Alaska 99501 .~;41-35 ~, LOCATION Oi,' W};LL (Report location clearly and in accordance with any State requirements.* See also space 17 below.) At surface T. 4 S., R. 14 '.f., Seward Base and Meridian 10. FIELD AND I'OOLy OR '~V1LDCAT Wildcat SURVEY OR AREA 14, PERMIT NO. 15. ELEVATIONS (Show whether OF, RT, GR, etc.) 35-T. 4 S, R 14 W., SB&M 12. COUNTY OR PARISH 13. STATE Kenai Aiaska 16. Check Appropriate Box To Inc!iccte Nature o[ Notice, Report, or Other Data NOTICE OF INTENTION TO : i.'i~.kCT,,i~E TREAT ]1~ MULTIPLE COMPI,ETE .'~ i i ~ - ~'i' Olt ACIDIZ~ ABANDON* i;.;i'.~,~ WELL CHANGE PLANS SUBSEQUENT REPORT OF: ' FRACTURE TREATMENT ALTERING CASINO SHOOTING OR ACIDIZING ABANDONMENT* (Other) (NOTE: Report re.-~:iis ,' 'i" h: (x;:aph,i;o;. i,:'. Well Comple~ion qr ]i,,c,,-'n; ;, :;..:, -.':....,,r: .'::,d I .... ' , ..':a.~ 17, Di..h,',;iBE Iq~OI,(}.MEI)OR ('(~.\ii'I.ETI.:D OPERATIONS (Clearly state all pertinent details, and give pertinent dates, including cstilnated date of Starting SPy propo.scd work. If well is direetionall¥ drilled, give subsurface location.~ and measured and trlle vertical depths for all markcu's and zones perti- nent to this work,) * - . .. 7;~; ., Confirming telephone conversation Wunnecke - S. R. Hansen 11-2-'65.. PreScn~ Status: T.D. 12,812' 13 3/8" casing at 2000'. 9 5/8" casing at 8451' Hole size 8 5/8" " 'Propose: Obtain WSO at 10,785' 2arforate and test selected interval 10,805' 1. Run + 266,~" of 7" liner to + i0,950'. (Top .at + 8350') 2. Cement around shoa with 900 sacks cement. 3. Obtain breakdown of liner lap and squeeze with 100 sacks cement. 4. Clean out to top of cement inside liner ' '. '' 5. ?zessure test 7" x 9 5/8" liner lap. Re squeeze if not successful. . 6 llun ~ement Bond Log, and Gamma Ray - Neutron Collar Log. 7. 8' ::' l: 2, -" -.. - 10,860' . ' .. .1303 DIVISION OF Mii~ES '&.MIN~ ANCHO~GE' ~8. I "ercby certify, that-'~e~Toregotng is true and correct TITLE zntenoen~ District Super .... DATE NOvember' 2, 19 65 (~i,i~ ~pace for Federal or State office use) CONDITIONS OF APPROVAL, IF ANY: TITLE *See Instructions on Reverse Side Form 9-331 (May 1963) " .... IITED STATES S~BmT IN. "" [ (Other ins~ DEPA IT OF THE INTERIOR verse side)q GEOLOGICAL SURVEY ICAT~* , on re- SUNDRY NOTICES AND REPORTS ON WELLS (Do not use this form for proposals to drill or to deepen or plug back to a different reservoir, Use "APPLICATION FOR PERMIT--" for such proposaJE.) OIL WELL O GAS WaLL O OTHER Exploratory NAMB OF OPERA,OR . Standard Oil Company of California, Western O~eratiop_s, lac, ADDBBmSt OF O~'~IsATOR ' - - - P. 0. Box 7-839. Anchorage. Alaska 99501 LOCATION OF WBt.t, (Repoit location dearly ind in accordance with any 8tats requirementLo 8es also space 17 below.) At surface 659* West and 655* South from Northeast Corner of Section 35, T. 4 S., R. 14 W., Seward Base and Heridian 14, P~P. RMI~ NO. mmmmm Form approved. Budget Bureau No. 42-R1424. G. LEASE DESIGNATION AND SERIAL NO. A-02'4363" 9. IFINDIAN~, ALLOTTEE OR TRIBE NAME .. . · · ?, UNIT AGRBEMENT NAME North 'jFork Unit' 8. FARM OR LBASR.-NAME. ,. North"Fork Unit. 9. Wl~LL NO..' L, ,. , 10. FIELD AND POOLp OR WILDCAT . .. suave? oR . ' :[ . ~: ·, '.,; . J15. BLBVATIONS (Show whether DF, RT, U~ etc.) 10. Check Appropriate Box To Indicate Nature of Notice, Report, or Other Datq :"-" iL-i ::' .... :~ ;_:,..... !-.,. ._. NOTICE OF INTENTION TO: SUBSmQUBINT RBpouT.' 0.F: .... ,., ',, · I--I I--I 'RACTURJTRlaATMlaNTI I SHOOT OR AClDIZN ABANDONS RE,AT'WE'-'. I J CHA~OB ~,,ANS I I (Other) NoTn: Report results ~f mu'ttiPie 'ebmpleflsn ·on. Well (Other)Inject waste water be~veencas~n~ ~ompletion or Reeompletion Report'and Log ~o~m.)'. i?. DESCRIR~, PRO~'OSED OR CO.~PLETSD OPERATIONS (Clearly state all pertinent details, and ~lve pertinent dates, inelud~h~!estl'mated"date c~.s~ an~' proposed work. If well i8 direetionally drilled, ~rive subsurface Iomtions and measured and true vertieaV, depths ~or ail markers, and zones perti- nen~ to this work.) * '~ '/ ... !: c- !', ?~ !:,.. :-. ., " ....... casin§ annulus. 13 3/8" casin~ cement:ed Co surface at: 2000'. (2) st:ages; shoe aC 8~51', second s~age at 6313'. Top second sca~e ac 6920'. ]:nJectt. on w~il be made into sands be~,~een 2100~ and ..... :'.~:o~': of.-'..9:' ".13./8" ' ":. annulus cemant. All sands exposed t:o inject:ion are ind,.cared t0" b~i]noS~hyd.~o~a~b6n bear~.ng and bel0v any fresh water sources, .. - , ~., , ... ,.~ .-% 18. I hereby certify thalh.t~for~e~, h~ is true and,~,,,.,,=' %-.'~.. ,'.: .; · ,,..]',t SlONED W. ~. c. v.' CliAxx~:a~0a ' TXTLa ~.Diat~i~t Superintmdent' 19{ (This space for Federal or fJM~ omee use) ,, CONDITIONS OF *See Instructions on Reverse Sid, Form P~3 ST%'"'-- F ALASKA IN TRIF' --. [ (Other inetructi~ OIL AND~ GAS C~... _RVATION COMMISSION verse ~lde) ~. SUNDRY NOTICES AND REPORTS ON WELLS (Do not use this form for proposals to drill or to deepen or plug back to a different reeervoir. Uae "APPLICATION FOR PERMIT--" for such proposals.) oIL wELr` ~] oTsn Exploratory 2. NAMn or OPERATOR. Stan:lard Oil Company of California, WOZ 8, ADDEESS OF OFmUATOit P. 0. Box 7-839, Anchorage, Alaska 99501 4. ~.OCATZON Or WEt, r` (Report location clearly and in accordance with any 8tats requirementL$ See also space 17 below.) At surface 659' West and 655' South from Northeast Corner of Seotion 35, T. 4 S., R. 14 W., Seward Base and Meridian 14. PERMIT NO. la. ELeVATiONS (Show whethe~ Df, .aT, OB, et~) · Effective: July 1, 1964 A-024363 -~. IF INDIAN, ALLOTTEB OR TRIB"' NAME ?. UNIT AGREEMENT NAME . North Fork Un~ 8. FARM OR LEASE NAME North Fork IIniC 9. wwLr` NO. #41235 10. FIELD AND FOOL; OR WILD(.~AT 18. , . Check Appropriate Box TO Indicate .Nature ol~ Notice, Report, or Other Data; NO~I(~B OF INTENTION TO: ,' . EUBSEq~EWT ~OB~ (Other) Injec~ waste water between ca~in~ (NOTe: Report results, of multiple eompleti0n' on We~ . · · ' Completion or Reeomptetion Report and Log form..) . .. 17, DESCRIBE I'aO~OSED OR COMPLETED OPERATIONS (Clearly state all pertinent details, and give pertinent dates, including_estimated date of starting any proposed work. If ~ell ia dire~tlon~lly dztlled, give subsur~oe loe~tions and measured and t~ue vertical depths roy all markers and nones perti- nent to this work.) · . , . !.:.... ,..: , ',' . ~.. .r. ,:, ;. Propose injecC wasCe water from subJecC well drillin~ operations inC'o'."i3.:.'3/8" ii:i "~.:!' '.? ." x 9 5/8" casin~ annulus. 13 3/8" casing cemented, to surface aC .2000', ,9 tel..aRced.in t'~o (2) stages: Shoe aC 8451', second stage aC 6313'. Top second " stage ac 4600*, first stage at 6920'. Injection. will be made into sands between 2000' and Cop of 9 5/8" annulus cement. All sands exposed ~o injection'..are tn.-" '. dicaCed Co be non-hydrocarbon bearin~ and 'below any fresh water sOUrces. ". !"' ".' . . · 18. X hereby certify that the £o;~olnf..is t, ue and GG~'~ SXO~D ~v ~t.~..~/~~~ ~_ v_ ~A~n~N (This spaee~o~ ~e~ o~ S~ o~ u~) CONDITIONS OF ~BO~ ~ ~ TITLE District SuperinCenden~ ' .TLn ?,t" eSee Instructions on Reverse Side .% ,:~._ .':~ :,, ~.: '. <~ % .': ~, ';+' ',, .., ~.,../, _... '.'. ,..... i-: i':' ';'"' c, ' .... ;~' '~ ~ ... .,, · : , ~ -., }'...: .[..,' . 'v .::i ', ..... ~'~ .... ,,~2 ,;. '~ t.~ ,', ~ ,,~.,~,~{ '~:","''}" .... . %'[I r. . · ~£ ",,.".,,~..:.,..l:"..i ,'.'!....,, ,, .- .-~',~ :.:: '(,~ ,":, ,; '. ... ,,~ ,~.' ,,.,~ .... ~...-, · ~., '..... ?' ;,..-....' ... :.. ('. ,, :'....; .. " ',. ,~ '.i~ '.' .~.,f~?.k',,")i~AG~- .... !:i'!i)A~n, October..., 1965 , ,111 ~, ~; .. ..~ . ..~. s""" '":' "" "',, ,2'i J.' d ~.Z}A~ .' :, 2.. - :.'.4 :':~ :. ,.~ ~:.,. · ~.~. j ~: :~ ;[~ ". , UNITED STATES DEPARTMENT OF THE INTERIOR GEOLOGICAL SURVEY ~udge~ Bureau No. Approval expires I~31~. ~NO O~C~ Anchorage ~.. .. .................................. ~ Nu~,_.A=.02.4.3_O_l ............. U,,T ........................................... LESSEE'S MONTHLY REPORT OF OPERATIONS Sta'~e ....... .A..1..a.,s..k..a. ............... Gogr~d Field E.xj~lora tor~ Ti~e followi~ is a oorreo~ repor~ of opera~io~ and prod~ctio~ (i~elu~i~ drilli~ a~d prod~oi~ wel~s) for the mo~th & 0c~ober , ~9 65. Standard Oil Company of California J~e~t's address P. 0. Box 7-839 Uo~, ~estern Operations Inc. ................................................................. ........ ~ ~ ............................................................ ~ ..................... - ........................................................ ~. ~ I / , " , PAo~e 272 - 8461 - , _ C. V. Chatterton .................................................................................. ~ s Zi~le ~f~ ........ SEC. AND GALLONS or BARBZM OF REMARKS ~ or ~ TWP. RANGE WB~ D&vs Cp. FT. or OAS ~o. PaOD~OBD ~AR~ OF O~ O~ OA~B WATER (h th~) RB~VB~D none, M CONFIDE~L - NOR~ FO~ ~I'~ ~41-35 ' T4S R14W Drilled.'8 5/8" hole 11,1[,0~ - 11,,~05~ "?. · ~ (~., . Ran lo~s and 2,~ok sidewal.1 sample ~. -- Drilled a'aead :o 11,53~~ Cored 7 ~ tS" h,~le 11~53~; - ll,5~')J. Drilled t'm 11, i93'. ~oreg 11,693' - 11.71~~ Drilled C~ 12, ~39~ Cored 12.739' - Drilled t~' 12,~12' T.D. . , . ,. DISTRIB~i0N: U.S.G.S. ' W. ~. Linton (2) .::?..-~ ~~~. State - T. R. ~rshall (l ) ...... i..,..:l ....... · ~ C. ~. Per~y (:.) . .... . .... :'-',. R.R. Either ..... Producin~ ..~. .... Bxplorati,~n . . .<~,~ Land ..... NE; NE. 35 NoTn.--There were ...................................... runs or sales of oil; ............................................. M on. fi. of gas sold; ........... : ................................. runs or sales of gasoline during the month. (Write "no" where applioable.) NOT~..--l%epor~ on this form is required for 'each oalendar month, regardless of the status of operations, and must be filed in duplicate with the supervisor by the 6th of the succeeding month, unless otherwise direo~ed by the supervisor. Forth 9-8~9 .. ,(January 1960) lO--~STM-8 il. I. ~OVIItNMKNT PIIINTINI OI'~lCf UNITED ST^TES DEPARTMENT OF THE INTERIOR GEC, LOGICAL SURVEY l~udgct Bureau No. 42-I~356.5. Approval expires ~so oFac~ Anchorage .... Auu2'43'63 .............. I.EAS£ NUMBER ................................ UNIT ........................................... Alaska Coz~j Field Exploratory ... TAe /ollourin~ is ~ correc~ repor~ of operations ~d prod~otio~ (i~oZ~di~ driZH~ a~d prod~c~ for ~e mon~ o/ ............ ~_~.P.~.~.~ ............ ,10_~.~.., ....~.~.P.~.~.[~...9~.~...9.?.~R~.~X..9~..~!.~~ .... ~go~'s address P.O. ~.~ 7-839 ~,~cn,, Western Operations, Inc. ..................... ~ ~...~...m ..... ~ ............................. ~,. u~-, ,~ ..... ,...~._~.__~,.~...-- ........... ~.~.; ...... ~..=~ ....... · ,.. .................................... ...................... ............... c .............. P~o~. .......................... 222~8~fil ........................................~.~'. ,~tl. .... gi.[r-i.t---Su~-in~ndonl .... SEC. AN:'; ~o~ ~ 35 Or. F~. oF OAS (In thousands) - NORTH Drilled 1 le 7543' hole. Ra cemented sacks 'ound shoe 6313'. 2nstalled :ested BOPE Drilled o and sh to 11,190 Drilling DISTRIBUT .S.G.S. -T C. W. Per R. R. Rit Producing Explorati Land Linton (2) :rshail (1)[ .) .) OALLON8 OF OASOLINE ~ECOVERED FORK 8451'. 5/8" ca: and 750 ]~ARRELS OF W~ma (if none, so stat, o) .. iT t;41-3~ Ran logs ~ing at ~ ~acks REMARKS (If drilling, deoth: if ,,hut. clowm, cauao~ eonten~; of ~] · Conditioned 451' with 800 ough DV at Ok. 5/8". hole wi=h 50 oe and d: )0 psi. :illed 8 NoTm.--There were .................... ~' ................. runs or s-".Ios of oil; .............................................. M cu. ft. of g~s sold; ............................................. runs or sales of gasoline during the month. (V~rrite "no" where applicable.) NoT~.--lteport on this form is required for each calendar month, regardless of the status of operations, and must be filed in duplicate with the supervisor by the 6th of the succeeding month, unless otherwise directed by the supervisor. :~o,--m ,(JaIltlaa'y 1950) 16--2&?6(P'8 U.S. GOV~i~NMIrN? FeiNTING · ., SEP !a UNITED STATES ( DEPARTMENT OF THE INTERIOR GEOLOGICAL SURVEY ~Budgo~ Bureau No. Approval expires 12-81-60. ..... A~_02~6~ .......... ........................................... MONTHLY REPORT OF OPERATIONS State .......... 3J.aaka ........... Oou~ty .................................... Field ...... : ............ ~.x. :g_l_ 9.r.a%.o_..r~j .......................... TAe followir~ is a oorreo~ report of operation, s and prod~ot~o~ (ir~ol~dir~ drillir~ arid prod~oir~ w et~8 ) for t ~,~ ,,~o ,~ t ~, of ............... ~S.u._s.._~_, ............. , Zgg!., ....... _S_~.a.."..d_.a__r..d...P..%3...C..o.~r.a__n_L.o...~___C..a..t_A_~._o.r~.~.~, .4gon,$'8 address ......... ..P.;.._0.,....B..q.~..~..-..8..3.~ ........................... C, ompar~y ...I.4,.e~_.s..~9..r..n....0.P,e..r..a..t..i..0..n..S.~....~.N.c.z ......... .................................... ~ko_x__ai~__,_.A._~..a..sk_a ....................... S~,~e~ ......... :~._.L:__': .... :..:'_:.:::.:::'."._: ...... :!"':.~-._~;. ...... C. V. CHATTERTON ...... : .... Ph, or~ ......................... .2. 2.2_ .-..8..~_.6_ .!. ........... i ............................ ~/~t's tit'le .... D£s=ric~..S uper_i~te~n~ .... SRo. AND B&BRELS OF Orr. (JR~YITY GASOT-TNE Wi~Ea (H (If ~i~, d~m: R shut ~wn, ~ Or ~ ~. ~OZ W~ ~.u Or. FT. or Oas OAL~S or Baaaz~ or ~E~ARK8 ~O0 ~DUOBD (~ tho~) ~VERBD n0~Op M 8~t8) da~ ~d rmult of ~t f~ 35 ~48 R14~ Spudded August 9, 1965. Drilled 12~" hole ~o 24, i'. ope~.ed hole :o 26" to 246' ten ented Z0" 79f/ conc.uctor at 246' with 62~ sacl~ s cement. Installad and te BOPE. ]~rill~ d 12~" hol,,. to 200C ', ran 1)gs and ope~'~ed hc le ~o 18 5,18". .. Oeme~te, lJ 3/8" casing a~ 2000"with 20)0 sacks e,~e~t around sho~. %nsta.lled and test: .. ed BOPB. D~illed 12%" ~ole 200C '-7~3'. Drtl~inl ahead. I ~ · },.. u.'S.~-w. ~. Lingo= State ~ ~. R. Marshall [~) ] ~. w. ~;r~. (1) ~. ~. l~.cc~r- (1) Produai~ ~g gxplora~ ion ~ ~add .. . . , , , ., ~ ,,, No~,~.--There were ' runs or sales of oil; ' ' M 0u. ft. of gas sold; ............................................. runs or sales of gasoline during the month. (Write "no" where applicable.) No~.--Report on this form is required for each calendar month, regardless of the status of operations, and must be filed in duplicate with the supervisor by the 6th of the succeeding month, unless otherwise directed by the supervisor. ~ 9-829 : (J'fi~.LI~'~ 'J.O~JO) ,, 11H~?~,"~ U.l. 4i~riltUEIEUT"PSlUl'llle, OF'P'ICE ,, , .. July 29, 1965 8t,and~d Oil Compm~y of Calg. fornia P.O. Box 7-$39 A~¢tmr,age, Alaska ~nit 41-35 I ~ ~c. lo~i~ a copy Of the Petro, ie~m E~qliue, er ~0 L $~reet 1965 t~.0. l~ox ?-839 Ane~.rage, al~$~ 99501 r~i~:?~:~. ~e. S~tlon 2~7.41 o~ the Ala:~ Oil a~ ~a~ ,, O~"IX APPLICATION FOR PERMIT TO DRILL, DEEPEN OR PLUG BACK APPLICATION TO DIIILL~ DEEPEN [] PLUG BACK [] NAME OF COMPANY OR OPERATOR DAT~,, standard Oil Company of California, Western Operations, Inc. Address City P. 0. Box 7-839 Anchora~e~ DESCRIPTION OF %VELL AND LEASE July 12, 1965 State Alaska Name of lease { ~Vell number { Elevation (ground) { North Fork Unit ~741-35 %Vell location (give footage from section lines) Section--township--range or block & survey ,, Approximately 660' South and 660' West From N, E, Corner of Section 35, T,dS., R.14W.; : Field & reservoir (If wildcat, so state) I County Wildcat { Kenai Borough Distance, in miles, and direction from nearest town or post office i 10 miles East of Anchor point Nearest distance from proposed location to property or lease line: Proposed depth: { Rotary or cable tools _ :!:12,200' { Rotary. Number of acres in lease: 2480 I Distance from proposed location to nearest drilling, completed or applied--for well on the same lease: 660 feet Firs~ Well .... ~eet [Approx. date work will star~ Julv 12:1965 Number of wells on lease, incluc~ing this well, completed in or drilling to this reservoir: One if lease, purchased with one or more wells drilled, from whom purchased: Name Address Status of bond None required Remarks: (If this is an application to deepen or plug back, briefly describe work to be done, giving present producing zone and expected new producing zone) 18 $/8" t3 3/8" G! lb. & 4~1 lb. 20IWI' 2~ lac. X2 l/~'* 9 5/8" ~{ {/2 ii,. 8500' ~ CERTIFICATE: I, the undersigned, state that I am th~Dist- Supt. of the SOCo of Calif., WOI, Producing (company), and that ! am authorized by said company to make this report; and that this report was pre- pared under my supervision and direction and that the facts stated therein are true, correct and complete to the best of my knowledge. Permit Number: ,, 7/ Approval Date: .~: ~l ~ ~ ~ :: m .......... :~ c~ .......... ,,. Approved 3' Alqska ,Oi{ & Gas , ' '~ Cons~rvcfiion CornmJ?~'e~ ~o~ee: ~efore seud~g ~ this fo~ be sure that ~ou have givep all ~ormation requested. Much ~ecessary corres~na- ence wffi thus ~ avoided. Signature Ce V. CHATTERTON · Alaska Oil and Gas Conservation Commission l; Application t6 Drill, Deepen or Plug Back il Form No. P-1 I A uthorized by Order No. 1 Effective October l, 1958 ;B&M Anchorage, Alaska July 12, 1965 RECE!VE,,D ;,UL; DIV!SJON OF ,\4~i",,~2S & ANE;HO~AGE qlne Standard Oil Compa~ of California, Western Operations, Inc. as operator for itself, Richfield Oil Corporation, Union Oil Compamy of California and Sunray D-X Oil Company announces they are making preparations to drill an exploratory well on the Southern Kenai Peninsula approximately 8 miles east of Anchor Point in sec. 35, T-4-S, R-14-W. ~]ae well is to Be designmted' the North Fork Unit No.. 41 - 35. _ Coastal Drilling Ccmpa~ has Been awarded the drilling contract. Drilling is expected .to commence in about two weeks..