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Home My WebLink About202-118STATE OF ALASKA ALASKA OIL AND GAS CONSERVATfON COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1a. Well Status: Oil ❑ Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑Q Suspended[] 20rac 25.111 20AAC 25.110 GINJ ❑ WINJ ❑ WAG❑ WDSPL ❑ No. of Completions: 11b. Well Class: Development Exploratory ❑ Service ❑ Stratigraphic Test ❑ 2. Operator Name: Hilcorp Alaska, LLC 6. Date Comp., Susp., or Aband.: 8/31/2018 14. Permit to Drill Number/ Sundry: 202-118 / 318-120 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 7. Date Spudded: 7/18/2002 15, API Number: 50-133-20515-00-00 4a. Location of Well (Governmental Section): Surface: 1718' FNL & 633' FWL of Sec. 10, T8N, R9W, SM Top of Productive Interval: N/A Total Depth: 3200' FNL, 534' FWL of Sec. 10, T8N, R9W, SM 8. Date TD Reached: 7/24/2002 16. Well Name and Number: Swanson River Unit (SRU) 213-10 9. Ref Elevations: KB: 15.83' GL: BF: 17. Field / Pool(s): Swanson Rover Sterling/Upper Beluga Gas Pool 10. Plug Back Depth MD/TVD: 0' MD / 0' TVD 18. Property Designation: FEDA028405 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 348538.2 y- 2485829.2 Zone- 4 TPI: x- N/A y- N/A Zone- 4 Total Depth: x- 348429.5 y- 2484331.7 Zone- 4 11. Total Depth MD/TVD: 4,105' MD / 3,180' TVD 19. DNR Approval Number: N/A 12. SSSV Depth MDfTVD: N/A 20. Thickness of Permafrost MD/TVD: N/A 5. Directional or Inclination Survey: Yes (attached) No ❑ Submit electronic and printed information per 20 AAC 25.050 13. Water Depth, if Offshore: N/A (ft MSL) 21. Re-drill/Lateral Top Window MD/TVD: N/A 22. Logs Obtained: List all logs run and, pursuant to AS 31 .05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary N/A 23. CASING, LINER AND CEMENTING RECORD CASING WT' PER GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT FT. TOP BOTTOM TOP BOTTOM PULLED 13-3/8" 68 K-55 Surface 92' Surface 92' DRIVEN 7" 29 L-80 Surface 1,989' Surface 1,804' 8-1/2" 285 sx 3-1/2" 9.2 L-80 Surface 4,102' Surface 3,734' 6-1/8" 482 sx 24. Open to production or injection? Yes ❑ No Q If Yes, list each interval open (MDTFVD of Top and Bottom; Perforation Size and Number; Date Perfd): N/A hvfF'LETT6R DA ._e/134118 VERIFIED 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/fVD) N/A N/A N/A 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes No Q Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) JAMOUNT AND KIND OF MATERIAL USED N/A N/A 27. PRODUCTION TEST Date First Production: N/A Method of Operation (Flowing, gas lift, etc.): Date of Test: N/A Hours Tested: Production for Test Period Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: Flow Tubing Press. Casing Press: I Calculated 24 -Hour Rate Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity -API (torr): Form 10-407 Revised 5/2017 CONTINUED ON PAGE 2 R2MFVS AAS OCT 2 5 201eubmit ORIGINIAL only �z 213/if 28. CORE DATA Conventional Corals): Yes ❑ No 0 Sidewall Cores: Yes ❑ No 0 If Yes, list formations and intervals cored (MD/TVD, FromfTo), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. N/A 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No ❑� If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top Permafrost - Base Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval information, including reports, per 20 AAC 25.071. Formation at total depth: 31. List of Attachments: Operations Summary, Schematic, MIT -IA, Photo document casing cut-off/cement top/welded plate. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Chad Helgeson Contact Name: Ted Kramer, Operations Engineer Authorized Title: Operations Manager Contact Email: tkramerffhilcom.com Authorized Contact Phone: 907-777-8420 D Signature: Date: [ Z [O INSTRUCTIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Item 1a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1b: Well Class - Service wells: Gas Injection, Water Injection, Water -Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 41b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 19: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY -123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Form 10-407 Revised 5/2017 Submit ORIGINAL Only 3il"AJ1...lk..-LLUC RKB: 309.8' / GL: 294' AMSL KB — THF: 15.83' 1 133/8" 92' 1A 2 3B " Tag fill 3,180' SLM 5/07/08 t. 4 Top of Cement 1,889' G13p Lott r ciBP 3i33 Sterling BO Upper Sterling BO Lower Sterling B4A 3-12" 4,102' of TD=4,105' PBI D=4,036' MAX HOLE ANGLE =35.00° @ 1,904' SRU 213-10 SCHEMATIC .I F W F 1. R V it F T A l r. PFR Fl1A A Tl nV UTC7n1D V D Interval Item Accum. 83' - Zone TubingHanger, Camffon `H' BPV profile, BT Lift Threads Btm 0' sof Comments CBP w/ 200' cement to surface 06/08/18 BO upper 3' - 6 Chemical Injection Sub w/ 1,000 psi chem valve, 3/8" cannot line OPEN 89' TOlow, 3,202' CBP w/ 239' cement 05/30/18 13' 80' F63,71T 2.813" 4.500" Baker'X'Ni le 2.813"Min ID 3,447' 33' 9' 6 CIBPw/41'cement—TOC 3,092'0529/18 06/02/7 98' 3,524' 3,528' Ma a Ran Bride Plugset 12/09/07 6 0' 0225/3 Staling B-6 Mama Range Bride Plugca w/ 10' cement set 1124/07 3,760' 4' 2.323" 2.992" I S' Tubin Patah 2.323" ID sort 5/20/07 Beluga 5' 2.323" 2.992" 5' Tubin Patch 2.323" ID set 5/20/07 1502/22103 12' A-stop,Daniels packoff, G-Stopset 8/18/03 9 1 3,851' 1 PX Plug set in `X' Nipple 2/23/03 ped with 7' of CaCOr 10 13,870' 2.813" 4.500" Baker `X' Ni le 2.813"Min ID 1I 3 950'I Baker uickDrill Plu artial set set222/03 PFR Fl1A A Tl nV UTC7n1D V Updated by DMA 09-13-18 Interval Accum. Date Zone Too Btm Amt sof Comments 12/10107 BO upper 3,190' 3,196' 6 6 OPEN 1127/07 TOlow, 3,202' 3215' 13' 6 IS012/09/07 0823/03 Steding B -3a 3,447' 3,456' 9' 6 IS05/20/07 06/02/7 Sterling B -4a 3,524' 3,528' 4' 6 ISO 0225/3 Staling B-6 3,750' 3,760' 10' 6 ISOB/18/03 08/04/02 Beluga 3,985' 4,000' 15' 6 1502/22103 Updated by DMA 09-13-18 Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date SRU 213-10 50-133-20515-00 202-118 5/29/18 1 8/31/18 Daily Operations: 05/29/2018-Tuesday Got waiver from AOGCC and BLM. Pull tubing plug with Pollard SL. SL tagged at fill 3,134'w/ 2.80" GR. Sign in and mobe to location. PTW and JSA. Rig up HLB E-line lubricator. PT to 250 psi low and 2,000 psi higf�i. RIH with 2.75" CIBP and tag fill at 3,134' KB. Pick up one 1' and set plug at 3,133'. Lost 200 Ib line tension. Pick up 30' and go back down and tag plug. POOH. Tools look good for a good set. Pug set with 300 psi on tubing. MU 2-1/2" x 30' bailer while mixing cement. Bottom feed pump would not work. Called and borrowed one from field. Filled bailer with 17 ppg cement. RIH w/bailer and tag plug at 3,133', picked up 30' and dumped cement on top of plug. (6 gals, 18'). Ran in hole with same and dumped same amount. Est TOC at 3,097'. CIP 1900 hrs. Rig down lubricator and break down tools. Take back shop to work on them tomorrow and be back Thursday morning at 7 am. I notified BLM when we would tag and PT. Told them on phone and E-mail I would keep them updated. t �,yS�'j�PC' j 1 �J 05/31/2018 - Thursday Sign in. Mobe to location. PTW and JSA. Rig up lubric or, PT to 250 psi low and 2,000 psi high. RIH with CCL and tie into schematic. Ta ess TOC at 3,092'. Witnby Quinn Sa' er with BLM. Ran tag log. POOH. Rigged up Crystal gauge on tubing. Pressure up tubing to 1,638 psi at 1000 hrs, 1,608 psi at 1015 hrs and 1,595 psi at 1030 hrs. Pressure test witnessed by Quinn Sawyer with BLM. POOH. RIH with 2.75" Geo CIBP and tie into schematic. Run correlation log and set plug at 2,089'. Lost 100 Ib line tension. Pick up 30' and go back and tag. POOH. Good set. Mix cement and fill 2-1/2" x 30' bailer with cement and tag plug at 2,089'. Dump cement on top of plug. Make second run of cement and dump on top of cement (est 40'). POOH. Good dump on both runs. Rig down lubricator, secure well and clean up around well. Will be back in AM at 7 am to finish up the dump bailing. Halliburton has a couple hours of cleaning tools and pump at their shop today when they get in. I have cement samples with me. 06/01/2018 - Friday Sign in. Mobe to location. PTW and JSA. Shutjob down for a few hours. Rig up lubricator, PT to 250 psi low and 2,000 psi high. RIH w/ 2-1/2" x 30' bailer and tie into schematic and tag TOC dump yesterday (2 bailer runs) at 2,058'. Dump bail cement. POOH good dump. Made 10 more bailer runs which gives us 74 gals of cement which is a approx 208' of cement. CIP at 1830 hrs and est TOC at. 1,881'. Had 1 miss-run and few problems with cement mixer and pump button hing real bad. Rig down lubricator and wait on cement. Samples are on Halliburton trailer. WOC. Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start DateEnd Date SRU 213-10 50-133-20515-00 1 202-118 1 5/29/18 1 8/31/18 Daily Operations: 06/04/2018 - Monday Sign in at office, permit/1SA. Go over job scope. Spot equipment, rig up slick line. PT LUB-2,500 lbs. - replace o -ring, retest - test good. RIH w/ 2.5" x 4' drive down bailer to 1,896'KB tag cement. POOH - talk w/ prod. Stand by for tools. Tools arrive - prep cement - build bailer. RIH w/ 2.5" x15' dump bailer to 1,890'KB w/t. RIH w/ same to 1,884'KB w/t. RIH w/ same to 1,878'KB w/t - OOH pin not sheared. Re run same to 1,878'KB w/t. RIH w/ same to 1,872'KB w/t. RIH w/ same to 1,866'KB w/t. RIH w/ same to 1,860'KB w/t. RIH w/ same to 1,854'KB w/t. RIH w/ 2.8" gauge ring to clean tubing walls down to 1,850'KB. OOH begin rig down. 06/06/2018- Wednesday On location - TGSM - ISA - permit - MOB to bull rail - MOB equipment to pad - rig up w/I - PT LUB 3,000 psi — good. RIH w/ 2.5" x 5' DD bailer to 1,806'KB wt — POOH. Standby to pressure test tubing/cement. Pressure tested from 1,762 psi to 1,703 psi for 30 minutes. RIH w/ swab mandrel and 3 v cups - fluid at surface - begin swab down to 1,800'KB. Change out cups- 3 new. RIH w/ same to 1,650'KB continue to swab to 1,800'KB. Well swabbed down to top of cement. Rig down w/I - secure well. MOB equipment to bull rail and fuel. Depart field. ETA PWL shop. 06/07/2018 - Thursday Sign in. Mobe to location. PTW and 1SA. Meet Vac truck filled with 14 bbl. Mix 33 sxs of salt which makes it approx. 10 ppg brine. Pump 14 bbls of brine down hole and let it swap with the air in the well. Bleed off 50 psi on well and monitor well for 2 hours. Will be back in AM to set CIBP at 200' and dump cement to surface. Allie and Amanda (inspectors/engineers) with BLM were out here to watch fluid being pumped in well. 06/08/2018 - Friday Mobe to location. Rig up lubricator. TP - 0 psi. RIH with 2.74" OD plug to 200'. Run correlation log. CCL to Top Plug is 7.7'. Pulled up to 192.3' stop depth and set plug at 200'. Lost 50 Ib line tension when plug set. Pick up 30' and went back down and tagged plug. POOH. Good set and tools looked ok. Had 0 psi on tubing when set. Amanda and Allie with BLM witnessed the plug set. Dump 78 gals of 11 Ib cement down tubing. Cement top was at the tubing hanger. Closed master and swab. Cement in place at 1045 hrs. Rig down equipment. Clean up work area. TP - 0 psi. 08/28/2018 -Tuesday Start excavating around cellar. Remove cellar while checking for contamination. Break up cement floor. RU wellhead saw and perform cut. IA did not have cement to surface 36' void. Pick up pallet of concrete. 08/29/2018- Wednesday BLM representative Amanda Eagle on location. Inspect wellhead and confirm plate documentation is correct. BLM is ready to weld marker plate. 08/30/2018 - Thursday Amanda Eagle on location to inspect wellhead cut and cement placement. Permission to Weld marker plate. Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date SRU 213-10 50-133-20515-00 202-118 5/29/18 8/31/18 Daily Operations. 08/31/2018 - Friday AOGCC representative Guy Cook on location to inspect wellhead cut depth, Cement to surface, and Marker plate documentation. vt am`� Al 4L r" WN AC AC 11 W F x i s+� ,tea 11 x s+� ,tea R PZ51 G 213-10 tubing 6.6-18 -06-Jun-18, 08:00:16, 1815 1500.0 1000.0 500.0 0.0 00:00 PSI G — PSI G 01:23:20 02:4640 Elapsed Time hh:mm:ss 04:10:00 PSI G 5.0 0.0 -5.0 -10.0 Co uLting Inc McLANE Well S.R.U. 213-10 Plug & Abandon Memo Via email Date: 30 August 2018 To: Hilcorp Alaska LLC....................................................Attu: Cole Bartlewski From: M. Scott McLane, PLS Project: Swanson River Unit 213-10 Well Plug & Abandon Survey Re: Project Summary This memo represents the plug and abandon survey performed by McLane Consulting Inc. (McLane) for Hilcorp's Swanson River Unit 213-10 well located in section 10 T8N R9W Seward Meridian, Alaska. The survey was performed on August 23, 2018. The scope of work consisted of providing accurate field elevations so the well could be plugged and abandoned per State requirements. Existing survey control was recovered and positional accuracy was confirmed by comparing (2) check shots on hard targets to existing data. To establish original ground elevation near the well casing, (2) survey measurements were observed at the perimeter of the pad in opposite positions from the well location, parallel to the tidal flat gradient. These elevations were averaged and assumed to fairly represent original ground in the absence of historical data. A top of pad elevation was also recorded adjacent to the well casing then (2) reference grade stakes were set with measurements to the proposed cutoff elevation. Enclosed is Exhibit A which includes pad asbuilt data from 2018 and a well casing cutoff detail with pad, original ground and proposed casing cutoff elevations. • Mean pad surface grade in vicinity of well casing: 294.5'± (2018) • Original ground elevation in vicinity of well casing: 293.0'± (2018) • Cutoff depth requirement: 3.0' below original ground elevation • Minimum casing cutoff elevation: 290.0' • Casing cutoff elevation as staked in field: 289.0' The cutoff mark elevation of 289.0', as referenced in the field, exceeds the required minimum cutoff elevation of 290.0'. P.O. Box 468 Soldotna, Alaska 99669 (907) 283-4218 Fax (907) 283-3265 Email msmclane@mclaneg.com Coreutbna Inc AMcLANE Please feel free to contact me if you have any questions or comments. Sincerely, M. Scott McLane, PLS McLane Consulting, Inc. �AN%X�'*\AI I 0.. A<.qs, �,I 49 7Ji* `9,t ,......... ....................00 111-27j� .100 / M. SCOTT Mc Nz. 4928—S Page 2 of 2 P.O. Box 468 Soldotna, Alaska 99669 (907) 283-4218 Fax (907) 283-3265 Email msmclane@mclaneg.com SCALE D 200 400 FEET OF A4 1 ,ys#1,I ; I .491H ,t i /..A .......... ...... 00 ... 00 /I i+ :M. SCOTT MELANIE SF ' 4928—S Z4 42 NOTES O SRU212-10 P&A 2 O U 24Uj o G 1. BASIS OF HORIZONTAL; NAD83 US FEET POSITION (EPOCH 2010) AND VERTICAL CONTROL (NAVD88) IS AN OPUS SOLUTION FROM NGS STATIONS TBON, TSEA AND ANC2 TO ESTABLISH CP -2. THE ALASKA STATE PLANE COORDINATES NAD 83 ZONE 4 IN FEET ARE: N = 2458384.578 E = 1483669.444 ELEV. = 212.690 (NAVD88) Consulting Inc M � ENGINEERING IM PING I SURVEYING I TESTING P.O. BOX 46850LOOTNA, M. 9"S' VOICE: 2134218 TAX: (807)z 2.5 EMAIL SAMCIANE®MCLWECO.COM SRU 213-10 P&Aj ASP NAD83, ZONE 4 N: 2,485,587.75 E: 1, 488, 574.91 ELEV. 294.4 WELL CASING CUT-OFF DETAIL WELL CASING TO BE REMOVED PAD ELEV = 294.5' ± O.G. ELEV = 293.0' ± I I I I 4'0 REFERENCED WELL CASING CUTOFF AT ELEV = 289.0' PROJECT HILLCORP ALASKA, LLC SWANSON RIVER FIELD WELL SRU 213-10 PLUG AND ABANDON EXHIBIT -A NAD 83, ASP ZONE 4 LOCATION SECTION 10 T8N R9W SEWARD MERIDIAN, ALASKA DATE: W=018 DRAWN BY: JAH SCALE: 1200' PROJECTNO. 1870 BOOKING. 17LB37 SHEET 1 • • OF Tip yw I//7, sv THE STATE Alaska Oil and Gas ofA LAsKA Conservation Commission -ice_ 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 *4r Main: 907.279.1433 ALAS"- Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson Operations Manager SCAMS Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Swanson River Field, Sterling/Beluga Gas Pool, SRU 213-10 Permit to Drill Number: 202-118 Sundry Number: 318-120 Dear Mr. Helgeson: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Hollis S. French Chair r� DATED this day of April, 2018. RBDMSMPR 0 51018 • • RECEIVED STATE OF ALASKA 1 208 ALASKA OIL AND GAS CONSERVATION COMMISSION 4 MAR 3 l APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1.Type of Request: Abandon Q • Plug Perforations❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend 0 Perforate 0 Other Stimulate ❑ Pull Tubing ❑ Change Approved Program❑ Plug for Redrill 0 Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: 0 2.Operator Name: 4.Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska,LLC Exploratory 0 Development Q 202-118 • 3.Address: 3800 Centerpoint Dr,Suite 1400 Stratigraphic 0 Service 0 6.API Number: Anchorage Alaska 99503 50-133-20515-00-00 • 7. If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? N/A 11Swanson River Unit(SRU)213-10 • Will planned perforations require a spacing exception? Yes 1:1 No 9.Property Designation(Lease Number): 10. Field/Pool(s): -a-Fe.-r(tit• ol-- -4 FEDA028405 • Swanson River/ as Pool tf./ j2� zi/G 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 4,105 • 3,737' • 3,180' 2,839' -1,214 psi 3,198' 3,810'(fill) Casing Length Size MD TVD Burst Collapse Structural Conductor 92' 13-3/8" 92' 92' 3,450psi 1,950psi Surface 1,989' 7" 1,989' 1,804' 8,160psi 7,020psi Intermediate Production 4,102' 3-1/2" 4,102' 3,734' 10,160psi 10,540psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic N/A N/A N/A Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): N/A;N/A N/A;N/A 12.Attachments: Proposal Summary Q Wellbore schematic Q 13.Well Class after proposed work: Detailed Operations Program 0 BOP Sketch 0 Exploratory ❑ Stratigraphic ❑ Development Q • Service 0 14. Estimated Date for 15.Well Status after proposed work: April 20,2018 Commencing Operations: OIL 0 WINJ 0 WDSPL ❑ Suspended 0 16.Verbal Approval: Date: GAS ❑ WAG 0 GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned 2 • 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: Chad Helgeson 777-8405 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramer@hilcorp.com Contact Phone: 777-8420 Authorized Signature: 6:11c,7*--- Date: 3/2(11 e COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 13 'Z O Plug Integrity [i' BOP Test ❑IP Mechanical Integrity Test EI Location Clearance Other: le r*eY' z o A#k zS 112(k) Z, L►ev r K e 't C.Q t-e7 ug treo!n "I"o 466,C G cx 4.,,a-..,es, eg= P l U s ,k ".5 ,-4-b Post Initial Injection MIT Req'd? Yes ❑ No ❑ ,� "D D 0 c 2018 Spacing Exception Required? Yes ❑ No d' Subsequent Form Required: RBDM; R :J APPROVED BY 4 �1,p Approved by: COMMISSIONER THE COMMISSION Date: U (� n t A 4 .. O/ lc. lJ' �\� i{� l _[� M /moi //� ..-b<—t Form ar Form 10-403 Revised 4/2017 Approved i i li r 77/Rl� from the date of approval. I��' Attachments in Duplicate 0\1 • 111 Well Prognosis Well: SRU 213-10 Hilcoru Alaska,LL Date:3/20/2018 Well Name: SRU 213-10 API Number: 50-133-20515-00 Current Status: Shut-In Gas Well Leg: N/A Estimated Start Date: April 20, 2018 Rig: N/A Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 202-118 First Call Engineer: Ted Kramer (907) 777-8420(0) (985) 867-0665 (M) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824(M) AFE Number: Current Bottom Hole Pressure: — 1,348 psi @ 2,852' TVD (Based on 0.473 psi/ft press. gradient) Maximum Expected BHP: —' 1,348 psi @ 2,852' TVD (Based on normal grad of btm interval) Max. Potential Surface Pressure: — 1,214 psi (Based on 0.1 psi/ft. gas grad. to Surf. 47 5-4) :-/I4.110_,/La 1116. . Brief Well Summary The SRU 213-10 well was drilled in July of 2002 as a Beluga slim-hole Gas well. All Casing strings, the 7" 29# surface casing, and the 3-1/2" 9.3#production casing were cemented to surface. The well was originally completed as a Beluga Gas well in August 2002. In February of 2003 the Beluga was abandoned under a plug and the well was completed in a series of Sterling gas sands working up hole in 2003 testing and setting plugs and cement. Tested were the B6, B4a, and the B3a sands. These sands were abandoned in May of 2007 and the BO lower sand perfed and tested in November of 2007. The BO lower was isolated with a plug in December of 2007 and the BO upper was perforated. These sands are still open but brought in fill covering the top perforation by 10'. A temporary plug was set in the X nipple and the well was TA'd. concur. t 1,e 140-J4/ or of Pelf 4gj i 41i The purpose of this Sundry is to P&A this well. 6u „/Aures our Vick f, ,41( Gtt:Mb to �,� wed ;ti Aew s4r~ds �4 Aja�� (econ.rk, ,„.1 ne'e� „vetoed 7r /nora ;�44 Slick-line Procedure: Up fne few molrhi eit /n3614 al eir low i+51re5, 1. Provide 24hr notice to AOGCC that Plug and Abandonment of well will commence per AOGCC regulations 20 AAC 112.(h). / /}be/identy�, 71j13 (/ at 7911f 2. MIRU Slickline. PT Lubricator to 2,000 psi Hi 250 Low.✓ MC I, q ((vGIr?r dearies. 3. PU RIH with retrieving tool and pull pack off plug at 2,662'. 4. PU 2.50" GR and RIH and tag fill ( last tag was @ 3,180'). 5/2 j 5. RD slickline. E line Procedure �egrr � ar AOtoi .f 5 MGR 1. MIRU E-line unit. Pressure test lubricator to 2,000 psi high 250 Low. 4j,rpr:715u.re 2. PU RIH W/CIBP and set at 3,140'. 4 --- "-- " �s ' k� � 3. PU Bailer and dump bail 35' of cement on top of CIBP (TOC @ 3,105'). WOC."Ma.Z'3 ' ' r`^ 4. RIH W/ E-line and tag TOC.yecord depth. •v- 5. 5. PU RIH W/CIBP to 2,089'.✓Set same. 6. PU bailer, Dump bail 200'of cement on top of CIBP(TOC @ 1889'). • • Well Prognosis Well: SRU 213-10 Hilcorp Alaska,LLi Date:3/20/2018 7. Pressure test plug to 1,500 psi. on chart or 30 min. 8. PU CIBP and RIH to 160'. Set same. 9. PU Dump Bailer. Place cement on top of CIBP to surface. 10. RDMO E-line. Post Rig Abandonment Procedures: 11. Excavate cellar,cut off casing 3' below natural GL. 12. Notify AOGCC and BLM 48hrs in advance. 13. Create well abandonment marker per 20 AAC 25.120 and BLM Onshore Order No. 2 III.G.10.The following must be bead-welded directly to the marker plate: 14. Hilcorp Alaska, LLC 15. PTD: 202-118 16. Well Name: SRU 213-10 17. API: 50-133-20515-00 18. Set marker plate per 20 AAC 25.120 and BLM Onshore Order No. 2 III.G.10,collect GPS coordinates. 19. Photo document casing cut-off and Welded Plate install. 20. Backfill excavation, close out location. Attachments: Actual Schematic Proposed Schematic Wellhead Drawing • • SRU 213-10Swanson River Unit 1NeII SRU 213-10 Last Completed 7/27/02 Hileor Alaska LLC SCHEMATICUpdated 5/07/08 RKB:309.8'/GL:294'AMSL Casing & Tubing KB—THF:15.83' Size Type Wt Grade ID Top Btm Hole Cmt Cmt Top 1 y 13-H" Conductor 68 K-55 12.415" Surf 92' - Driven < 7 Surface 29 L-80 6.184" Surf 1,989' 12-' " 93 bbl Surf. 13-3/8" ' 3-'/" Production 9.2 L-80 2.992" Surf 4,102' 6" 115 bbl Surf. 92' 2 - JEWELRY DETAIL s No. Death ID OD Item `' 1 15.83' - - Tubing Hanger,Cameron'H'BPV profile,IBT Lift Threads ,• 2 1743' - - Chemical Injection Sub w/1,000 psi chem valve,3/8"control line- 7' 3 2,662' 3.500" 3.5" PlugPackoff 1,989' 3A 2,680' 2.813" 4.500" Baker'X'Nipple(2113"Min ID) 4 3,198' - - Magna Range Bridge Plug set 12/09/07 .. , 5 3,440' - - Magna Range Bridge Plug(cap w/10'cement)set 11/24/07 6 3,444' 2.323" 2.992" 15'Tubing Patch(2.323"ID)swt 5/20/07 7 3,495' 2.323" 2.992" 5'Tubing Patch(2.323"ID)set 5/20/07 8 3,712' - - A-stop,Daniels packoff,G-Stop set 8/18/03 9 3,851' - - PX Plug set in'X'Nipple 2/23/03,capped with 7'of CaCO3 10 3,870' 2.813" 4.500" Baker'X'Nipple(2.813"Min ID) 11 3,950' - - Baker QuickDrill Plug(partial set)set 2/22/03 3 — ' - PERFORATION HISTORY 3A '4 Interval Accum. Date Zone Top Btm Amt spf Comments Tag fill12/10/07 BO upper 3,190' 3,196' 6' 6 OPEN 3,180'SLM 11/27/07 BO lower 3,202' 3,215' 13' 6 ISO 12/09/07 5/07/08 «; *" 08/23/03 SterlingB-3a 3,447' 3,456' 9' 6 ISO5/20/07 06/02/07 Sterling B-4a 3,524' 3,528' 4' 6 ISO , Sterling BO Upper 02/25/03 Sterling B-6 3,750' 3,760' 10' 6 ISO 8/18/03 *,'i — ``. ' ' 08/04/02 Beluga 3,985' 4,000' 15' 6 ISO2/22/03 4 , Sterling BO Lower 5 6 Sterling B3A 7 , , :. Sterling B4A 8 . -----1 Sterling B6 , '* \•_ ....t a..7.r ' r•r•r•r•r.r•r.r 1, .1f1• 7r11 J 1I ' Beluga C 3-1/2" , 4,102' _-" ks. 1 s:"1'' as TD=4,105' PBTD=4,036' MAX HOLE ANGLE=35.00°@ 1,904' Updated by DMA 07-14-17 • • 4 .., ti SRU 213-10 Swanson River Unit Well SRU 213-10 PROPOSED SCHEMATIC Last�omp�eted 7/27/02 Hihr,AlaskaLLC Updated 5/07/08 RKB:309.8'/GL:294'AMSL Casing & Tubing KB-THF:15.83' Size Type Wt Grade ID Top Btm Hole Cmt Cmt Top 1 _ }' t� 13-%" Conductor 68 K-55 12.415" Surf 92' Driven ','A . ' ' �'. ? + . ,� 7 Surface 29 L-80 6.184" Surf 1,989' 12-%" 93 bbl Surf. 13-3/8" . ^ +'" '" ,, 3-'h" Production 9.2 L-80 2.992" Surf 4,102' 6" 115 bbl Surf. 92' 'r� Top of Cement JEWELRY DETAIL 2 Al"' ±1,889' No. Depth ID OD Item R i k1 N'a �, 1 15.83' - - Tubing Hanger,Cameron'H'BPV profile,IBT Lift Threads I ^+ . ' *c "r t, IA +/-160' CIBP w/±160'cement to surface 1,989' + 2 1743' - - Chemical Injection Sub w/1,000 psi chem valve,3/8"control line 2A +/-2,089' CIBP w/±200'cement ' ' t -. ' 3A 2,680' 2.813" 4.500" Baker'X'Nipple(2.813"Min ID) 3B +/-3,140' CIBP w/35'cement-TOC @±3,105' 4 3,198' - - Magna Range Bridge Plug set 12/09/07 5 3,440' - - Magna Range Bridge Plug(cap w/10'cement)set 11/24/07 6 3,444' 2.323" 2.992" 15'Tubing Patch(2.323"ID)swt 5/20/07 7 3,495' 2.323" 2.992" 5'Tubing Patch(2.323"ID)set 5/20/07 ' , 8 3,712' - - A-stop,Daniels packoff,G-Stop set 8/18/03 9 3,851' - - PX Plug set in`X'Nipple 2/23/03,capped with 7'of CaCO3 10 3,870' 2.813" 4.500" Baker'X'Nipple(2.813"Min ID) 11 3,950' - - Baker QuickDrill Plug(partial set)set 2/22/03 3A _ . Io�."oC 3B` ,;. �;'" !...1" -3110 PERFORATION HISTORY Tag fill s.�► 3,180'SLM ,i°,i Interval Accum. 5/07/08 - ',S 4,,' Date Zone Top Btm Amt spf Comments e , - - Sterling BO Upper 12/10/07 BO upper 3,190; 3,196' 6' 6 OPEN 4 , 11/27/07 B0lower 3,202' 3,215' 13' 6 ISO 12/09/07 k "' 08/23/03 StellingB-3a 3,447' 3,456' 9' 6 ISO5/20/07 ' --..--. Sterling BO Lower 06/02/07 Stelling B-4a 3,524' 3,528' 4' 6 ISO -yr_ t , 02/25/03 Sterling B-6 3,750' 3,760' 10' 6 ISO 8/18/03 ''i +r ` , 08/04/02 Beluga 3,985' 4,000' 15' 6 ISO2/22/03 5 w 6 I• f Sterling B3A 7 , Sterling B4A - _.._...____: 8 1 , Sterling B6 . 4,,r:r:r:r:r:r:r:r , .•" .r.r1ryr 9 :1f�_ r1r 10 .. II • Beluga C 3-1/2" . - -' 4,102' 2 i �.:.�� l' TD=4,105' PBTD=4,036' MAX HOLE ANGLE=35.00°@ 1,904' Updated by JLL 03-19-18 • . • • Swanson River Unit la SRU 213-10 12/27/2017 llileorp Ala.ko,LL(: Swanson River Tubing hanger, Shaffer SRU 213-10 T55-AJO,7 X 3 1/2 BTC 13 3/8 X 7 X 3 1/2 lift and susp,w/3"Type H BPV, 3/8 non cont control line BHTA, NSCO,3 1/8 5M FE Tree, Block, Kvaerner, 7 1/16 5M FE X 3 1/8 5M, *woo double master, swab, ,.._._ ,., 3 1/8 5M outlets, FF trim Valve wing, OCT-20, 3 1/8 5M FE, HWO,AA IIMO Qty i V i;1'-►o 1i fp ;,, rli !;1� (I. 491 l '_ Void test goodjr1) Adapter,Shaffer-AJO, 250/5000 si p 7 1/16 5M stdd X 7 1/16 5M, 5/29/2009 �� ;-, w/1-'/control line exit, Tubing head, Shaffer ej N"" 6 1�4" seal pocket , T55-Ll, 13 5/8 3M X :my 7 i pin 71/165Mw/2- 21/165M SSO, 7"Type 1 secondary tU Ground level seal in head, - r o''' o 1-c, o, �.I� y ...4!;' t .lI•' Valve, NSCO, 2 1/16 5M - �\ %�I / . FE, HWO,AA Te' v - �I i I1 Qty 2 Iltr4... Void test good Casing head, IC 6L, _ ��"~— 250/2500psi 13 5/8 3M X 13 3/8 :"' l fr l_.-. 5/29/2009 SOW,w/2-2" LPO, 7" Ill__ _ ii i C-22 slips in head f-, 111111 li. •I '.. Ball valve 2"LP 0 I x00 Thousand Cubic Feet of Gas (" ") per Month o N 0 0 or Gas- Oil RatiMCFo 0 O O 00 M O C O O O o o O O oo O O N O O O O O o o ,o a—I a-1 a-1 a—I a-1 a-i ai ri M 1� N I i ,°�° 1 fi O o 11111111111 IIIIuIIIIIIuuIIIIIuIlIIIII ‘711IllIllIllIll I ,.I IIII IIIIIIIIIIIIIIIIIIII 1 > N IlIllIllIlfihlIll r '' 111111 IIIIIIIIIIIIIIIIIIIIIIIII i �1 o IIIIlIIIIlIIIIuIIuHIuIIIIIIIIIIIIIlIIIIIIIuIIIIIIIa !1 :_711 ' _ 1101111111101111111111111011111111111111111111 sr°' I iii1II " I I 1 v, _. ., � ' I I 1 aa _ � " ° ulIllIlullIllIll II Y cn o .111 II 01111 1 ! N III 11!10.11011111 1111111111111 $b°e444 r o _ II a s 1a ao'a ;_ 41 so4 , .��11"iiiuniiiiiiuiiiiiuiu Iv �i o Ill II 111111 Ill 111111 J ' - uIulIIIIuuIIIIIutuIiluhIIuiIIIIIuuiIIIIIIIu °°� a fT 0 O O O.-1 yluo j Jad JaleM 10 spina Jo y}uo j .iad HO to siane8 • 0 RECEIVED STATE OF ALASKA MAR 1 b 2018 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 1.Type of Request: Abandon ❑✓ • Plug Perforations❑ Fracture Stimulate ❑ Repair Well 0 Operations shutdown❑ Suspend 0 Perforate 0 Other Stimulate 0 Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well 0 Alter Casing ❑ Other: 0 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska,LLC Exploratory 0 Development Q• 202-11; • 3.Address: 3800 Centerpoint Dr,Suite 1400 Stratigraphic 0 Service ❑ 6.API Number: Anchorage Alaska 99503 50-13 0515-00-00 • 7. If perforating: 8.Well Name and Numb- : What Regulation or Conservation Order governs well spacing in this pool? N/A 1:1Swanso River Unit(SRU)213-10 ' Will planned perforations require a spacing exception? Yes ❑ No 9.Property Designation(Lease Number): 10. Field/Pool(s): 41. FEDA028405 • Swanson River/Ste 'n. �•ef Gas Pool • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): ' V Plugs(MD): Junk(MD): 4,105 ' 3,737' 3,180' 2,839' -1,214)13,198' 3,810'(fill) Casing Length Size MD TVD V Burst Collapse Structural Conductor 92' 13-3/8" 92' , ' 3,450psi 1,950psi Surface 1,989' 7" 1,989' k 8,160psi 7,020psi Intermediate �> Production 4,102' 3-1/2" 4,102' '3,734 10,160psi 10,540psi Liner Perforation Depth MD(ft): (Perforation Depth TVD(ft): (Tubing Size: 11Tu.'-• Grade: Tubing MD(ft): co See Attached Schematic See Attached Schematic N/A N/A Packers and SSSV Type: e-a . S"tMD(ft)and TVD(ft): N/A; N/A N/A; N/A .\ 12.Attachments: Proposal Summary Q Wellbore schematic 151 1..Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch 0 i %' Exploratory ❑ Stratigraphic 0 Development❑r • Service 0 14.Estimated Date for 15.Well Status after proposed work: April 15,2018 CommencingOperations: OIL 0 WINJ 0 WDSPL 0 Suspended 0 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned Q 17. I hereby certify that the foregoing is true and the procedur•approved herein will not be deviated from without prior written approval. Authorized Name: Chad Helgeson 777-8405 Contact Name: Ted Kramer Authorized Title: 0 erations Manager Contact Email: tkramerahilcorD.com �� Contact Phone: 777-8420 Authorized Signature: ,.////71 . �/!%!/ Date: 3`/Si 1 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a r-.resentative may witness Sundry Number: iz I l Plug Integrity ❑ BOP Test 0 Mechanical Integrity Test 0 Location Clearance ❑ o Other: TANNED - '$ Post Initial Injection MIT Req'd? Yes 0 No Ek Spacing Exception Required? Yes ❑ No Subsequent Form Required: / 4/0 7 APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: „„1Q��U mb it Form and Form 10-403 Revised 4/2017 Approved applic ��s i r�ir the da �An lats in Duplicate • Well Prognosis Well: SRU 213-10 Hileorp Alaska,LLQ Date: 3/14/2018 Well Name: SRU 213-10 API Number: 50-133-20515-00 Current Status: Shut-In Gas Well Leg: N/A Estimated Start Date: April 15, 2018 Rig: N/A Reg.Approval Req'd? 403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 202-118 First Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (M) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824 (M) AFE Number: Current Bottom Hole Pressure: — 1,348 psi @ 2,852' TVD (Based on 0.473 psi/ft press. gradient) Maximum Expected BHP: — 1,348 psi @ 2,852' TVD (Based on normal grad of btm interval) Max. Potential Surface Pressure: — 1,214 psi (Based on 0.1 psi/ft. gas grad. to Surf. Brief Well Summary The SRU 213-10 well was drilled in July of 2002 as a Beluga slim-hole Gas well. All Casing strings, the 7" 29# surface casing, and the 3-1/2" 9.3#production casing were cemented to surface. The well was originally completed as a Beluga Gas well in August 2002. ✓ In February of 2003 the Beluga was abandoned under a plug and the well was completed in a series of Sterling gas sands working up hole in 2003 testing and setting plugs and cement. Tested were the B6, B4a, and the B3a sands. These sands were abandoned in May of 2007 and the BO lower sand perfed and tested in November of 2007. The BO lower was isolated with a plug in December of 2007 and the BO upper was perforated. These sands ' are still open but brought in fill covering the top perforation by 10'. A temporary plug was set in the X nipple and the well was TA'd. The purpose of this Sundry is to P&A this well. Slick-line Procedure: 1. Provide 24hr notice to AOGCC that Plug and Abandonment of well will commence per AOGCC regulations 20 AAC 112.(h). 2. MIRU Slickline. PT Lubricator to 2,000 psi Hi 250 Low. 3. PU RIH with retrieving tool and pull pack off plug at 2,662'. 4. PU 2.50" GR and RIH and tag fill ( last tag was @ 3,180'). 5. RD slickline. E-line Procedure 1. MIRU E-line unit. Pressure test lubricator to 2,000 psi high 250 Low. 2. PU Bailer and dump bail 50' of cement on top of fill (TOC @ 3,130'+/-depending on tag). WOC. 3. RIH W/ E-line and tag TOC. Record depth. 4. PU RIH W/CIBP to 2,089'. Set same. 5. PU bailer, Dump bail 200' of cement on top of CIBP (TOC @ 1889'). 6. Pressure test plug to 1,500 psi. on chart for 30 min. • • Well Prognosis Well: SRU 213-10 Ili'carp Alaska,LU Date: 3/14/2018 7. PU CIBP and RIH to 160'. Set same. 8. PU Dump Bailer. Place cement on top of CIBP to surface. 9. RDMO E-line. Post Rig Abandonment Procedures: 10. Excavate cellar, cut off casing 3' below natural GL. 11. Notify AOGCC and BLM 48hrs in advance. 12. Create well abandonment marker per 20 AAC 25.120 and BLM Onshore Order No. 2 III.G.10.The following must be bead-welded directly to the marker plate: 13. Hilcorp Alaska, LLC 14. PTD: 202-118 15. Well Name: SRU 213-10 16. API: 50-133-20515-00 17. Set marker plate per 20 AAC 25.120 and BLM Onshore Order No. 2 III.G.10, collect GPS coordinates. 18. Photo document casing cut-off and Welded Plate install. 19. Backfill excavation, close out location. Attachments: Actual Schematic Proposed Schematic Wellhead Drawing SRU 213-10 Swanson River Unit • Well SRU 213-10 SCHEMATIC Last Completed 7/27102 Hilcor Alaska LLC SCHEMATIC Updated 5/07/08 RKB:309.8'/GL:294'AMSL Casing & Tubing KB-THF:15.83' Size Type Wt Grade ID Top Btm Hole Cmt Cmt Top 1 e f% I*,- A tl: 13-H" Conductor 68 K-55 12.415" Surf 92' - - Driven rd .-*/.4. : '4 7 Surface 29 L-80 6.184" Surf 1,989' 12-h" 93 bbl Surf. 13-3/8" .' x' . r` ,.4".,, .a 3-Y" Production 9.2 L-80 2.992" Surf 4,102' 6" 115 bbl Surf. 92' <. 2 '. ; JEWELRY DETAIL " �' No. Depth ID OD Item �' 1 15.83' Tubing Hanger,Cameron'H'BPV profile,IBT Lift Threads rlr�' 2 1743' - - Chemical Injection Sub w/1,000 psi chem valve,3/8"control line 7 3 2,662' - 3.500" 3.5"Packoff Plug 1,989' 3A 2,680' 2.813" 4.500" Baker'X'Nipple(2.813"Mm ID) 4 3,198' - - Magna Range Bridge Plug set 12/09/07 5 3,440' - - Magna Range Bridge Plug(cap w/10'cement)set 11/24/07 till 6 3,444' 2.323" 2.992" 15'Tubing Patch(2.323"ID)swt 5/20/07 7 3,495' 2.323" 2.992" 5'Tubing Patch(2.323"ID)set 5/20/07 4. 8 3,712' - - A-stop,Daniels packoff,G-Stop set 8/18/03 9 3,851' - - PX Plug set in'X'Nipple 2/23/03,capped with 7'of CaCO3 10 3,870' 2.813" 4.500" Baker'X'Nipple(2.813"Min ID) ,. 11 3,950' - - Baker QuickDrill Plug(partial set)set 2/22/03 3 PERFORATION HISTORY 3A - :t� Interval Accum. - +I Date Zone Top Btm Amt spf Comments Tag fill 12/10/07 BO upper 3,190' 3,196' 6' 6 OPEN 3,180'SLM 11/27/07 BO lower 3,202' 3,215' 13' 6 ISO 12/09/07 5/07/0808/23/03 Stelling B-3a 3,447' 3,456' 9' 6 ISO 5/20/07 „pow 06/02/07 SterlingB-4a 3,524' 3,528' 4' 6 ISO ' Sterling BO Upper 02/25/03 Sterling B-6 3,750' 3,760' 10' 6 ISO 8/18/03 .' " 08/04/02 Beluga 3,985' 4,000' 15' 6 ISO 2/22/03 4 itSterling BO Lower 2 ' 6 t I ._ Sterling B3A 7 , ty Sterling B4A 8 - Sterling B6 11f1r:f::0::::f x.k,:. 9 : . •titiS 10 t., le ; 11 Beluga C 3-1/2" , ' 4,102' ._ , ,, _ a:r..._ Ift, *ffi TD=4,105' PBTD=4,036' MAX HOLE ANGLE=35.00°@ 1,904' Updated by DMA 07-14-17 SRU 213-10 Swanson River Unit Well SRU 213-10 PROPOSES SCHEMATIC pdCompleted d 0 /07/27/02Last 5/ 78 Hilcor,Alaska LLC RKB:309.8'/GL:294'AMSL Casing & Tubing KB—THF:15.83' Size Type Wt Grade ID Top Btm Hole Cmt Cmt Top 13-H" Conductor 68 K-55 12.415" Surf 92' - - Driven J 7 Surface 29 L-80 6.184" Surf 1,989' 12-H" 93 bbl Surf. *;'4 10 3-Yz" Production 9.2 L-80 2.992" Surf 4,102' 6" 115 bbl Surf ;> Top of Cement JEWELRY DETAIL 2 ' ` ±1,889' , Depth ID OD Item '• Fw w 1 15.83' - - Tubing Hanger,Cameron'H'BPV profile,1113T Lift Threads 7„ r7 ..1. IA +/-160' CIBP w/±160'cement to surface 1,989' 2 1743' - - Chemical Injection Sub w/1,000 psi chem valve,3/8"control line 2A +/-2,089' CIBP w/±200'cement ' '°,. . .. , , 3 2,662' - 3.500" 3.5"Packoff Plug w/±35'cement 2 , I. , 3A 2,680' 2.813" 4.500" Baker`X'Nipple(2.813"Min ID) 4 3,198' - - Magna Range Bridge Plug set 12/09/07 5 3,440' - - Magna Range Bridge Plug(cap w/10'cement)set 11/24/07 6 3,444' 2.323" 2.992" 15'Tubing Patch(2.323"ID)swt 5/20/07 7 3,495' 2.323" 2.992" 5'Tubing Patch(2.323"ID)set 5/20/07 8 3,712' A-stop,Daniels packoff,G-Stop set 8/18/03 9 3,851' - - PX Plug set in'X'Nipple 2/23/03,capped with 7'of CaCO3 10 3,870' 2.813" 4.500" Baker'X'Nipple(2.813"Min ID) 11 3,950' - - Baker QuickDrill Plug(partial set)set 2/22/03 3 3A 4X II PERFORATION HISTORY Tag filly Interval Accurst. 3,180'SLM .` Date Zone Top Btm Amt spf Comments 5/07/08 "• 12/10/07 BO upper 3,190' 3,196' 6' 6 OPEN r ` i;. •, a _ Sterling BO Upper 11/27/07 BO lower 3,202' 3,215' 13' 6 ISO 12/09/07 � 08/23/03 SterlingB-3a 3,447' 3,456' 9' 6 ISO 5/20/07 41 4 i " ,,gi 06/02/07 SterlingB-4a 3524' 3528' 4' 6 ISO 02/25/03 Sterling B-6 3,750' 3,760' 10' 6 ISO8/18/03 .` Sterling BO Lower 08/04/02 Beluga 3,985' 4,000' 15' 6 ISO2/22/03 ii. 5 6 Sterling B3A *ill 7 +y, Sterling B4A 8 , a. ' , Sterling B6 ti.1.1•.y 1•S r•r•r•r_r•'V . ..� . v 11 t Beluga C 3-1/2" ''' '_ , -'• ' 1 4,102' - ! iff TD=4,105' PBTD=4,036' MAX HOLE ANGLE=35.00°@ 1,904' Updated by DMA 03-14-18 • • Swanson River Unit • SRU 213-10 12/27/2017 flileorp Al*An,I.1A Swanson River Tubing hanger, Shaffer SRU 213-10 T55-AJO, 7 X 3 1/2 BTC 13 3/8 X 7 X 3 1/2 lift and susp,w/3" Type H BPV, 3/8 non cont control line BHTA, NSCO,3 1/8 5M FE Tree, Block, Kvaerner, WV'_" 71/165MFEX31/85M, imam double master, swab, „ , 3 1/8 5M outlets, FF trim Valve wing, OCT 20, �, -1 3 1/8 5M FE, HWO,AA .4' •* / Qty 3 r J _ 4 7-e-ilt m'i' (-- NI 7, in,,,,_ liner ,,,_ ii A * ; (411 \ 110%..... ,---wo I ,I) (07---(01 j1 ,,�. 'Or 11` Ii -r — rai Void test good ( Adapter,Shaffer-AJO, 250/5000psi o -‘ 7 1/16 5M stdd X 7 1/16 5M, 5/29/2009 -_ w/ 1-'/control line exit, Tubing head, Shaffer '-ice ! 6%4” seal pocket T55 LI, 13 5/8 3M X :. 11 , lig- 7 ii■= 71/165Mw/2-21/165M I1 SSO, 7"Type 1 secondary LIP — Ground level seal in head, "' 1.lpiIii ! r■ ��‘ 1 I-1r°', ValveS , 21/16 5M , \ , FE, HWO,AA 1 • = Ifr - Qty 2 'IN 1 ... Void test good 1 250/2500psi Casing head, IC-6L, +' 5/29/2009 13 5/8 3M X 13 3/8 :NNE I r I®i-= SOW,w/2-2" LPO, 7" IN INI C-22 slips in head -J--(0 NI -il.j,;, Ball valve 2"LP I' • • x c Thousand Cubic Feet of Gas ("MCF") per Month o 0 0 or Gas-Oil Ratia o m O Oo r O 0 0 O O O O O N O O 0 O O o O O O O O O O O `i -Ia-1 rl .i .i .4 -, - m N 11 Oe cc 00 —` N 00 h. 11, 1 r-I — o N l ;.� a HIw ZN _ t+ > f6 K a CC 0 c CY -.J O °; Z 3 i O LA -a - oro V) CC 2cl. soPr ZQ LLI t , __ . ., _ , C aa " o v) —7.--i , , c J Q 0w J _. c acri Y v, 4< Q ._ 4,0oe Q a ao' o o C O0- 4 f 'ate CO V . O v J m N a` o 0o I O o o. -1 Ot 4P 0 O O o .1 O 0 0 .-+ 0 0 -I 0 .1 O youoW aad JaleM}o siaLieg Jo illuoiAl Jad nolo spites • Schwartz, Guy L (DOA) From: Ted Kramer <tkramer@hilcorp.com> Sent Wednesday, March 21, 2018 11:01 AM To: Schwartz,Guy L(DOA) Subject: FW: 10-403 Submittal - SRU 213-10 (PTD 202-118) Attachments: SRU 213-10 AOGCC 10-403 -2018-03-21 -Resubmittal.pdf Follow Up Flag: Follow up Flag Status: Flagged Guy, Attached is a copy of the Sundry application for SRU 213-10 that will be coming over to your office this afternoon by currier. This Sundry Application replaces the one that is already in your shop. The change in this application is in how we handle the first plug. Hilcorp will not be setting a CIBP above the fill and placing 35' of cement above the CIBP. The previous Sundry Application showed placing 50'of cement on top of the fill. Sorry for the confusion. t� np�,,,� Sincerely, Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC. ‘DIL-. 2/- 0 0 907-777-8420 5 C 985-867-0665 From:Juanita Lovett Sent:Wednesday, March 21, 2018 10:50 AM To:Ted Kramer<tkramer@hilcorp.com> Subject: 10-403 Submittal-SRU 213-10(PTD 202-118) Ted, This is scheduled to be delivered to AOGCC this afternoon. Juanita L Lovett Sr.Operations/Regulatory Tech Hilcorp Alaska, LLC 3800 Centerpoint Drive,Suite 1400 I Anchorage I AK 199503 (907)777-8332 I jlovettrhilcorp.com 1 ') Image Project Well History File Cover Page 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. Q.O~- l L<6 Organizing (done) Well History File Identifier ~O-Sided 1111111111111111111 ~escan Needed 111III11I1111111111 R.l7CAN -ø Color Items: 0 Greyscale Items: DIGITAL DATA OVERSIZED (Scannable) 0 Maps: D Diskettes, No. D Other, No/Type: 0 Other Items Scannable by a Large Scanner 0 Poor Quality Originals: OVERSIZED (Non-Scannable) D Other: 0 Logs of various kinds: NOTES: BY: Helen ~ "---'""" 0 Other:: , !' Date 1°, {).J °'1' 151 m(J 1111111111111111111 151 VU P BY: Helent:Maria) Project Proofing BY: Helen ~ 1 x 30 = a I 0 Date t~ ~ bt + -1- = TOT A"- PAGES ;;;../, '- , (Count d, oes 'not' lclude cover Shr))t~ iI,P' Date: I'D ~ bl./ /sl r V~ 11111111111111 II II Scanning Preparation Production Scanning Stage 1 Page Count from Scanned File: ~ I <6 (Count does include cover sheet) Stage 1 Page Count Matches Number in Scanning Preparation: Helen~ If NO in stage 1, page(s) discrepancies were found: VYES - , Date If) 1tY. Dlf YES NO NO 151 1# f BY: BY: Helen Maria Date: /s/ IIIIIII1I1111111111 Scanning is complete at this point unless rescanning is required. ReScanned 1111111111111111111 BY: Helen Maria Date: /sl Comments about this file: Quality Checked IIIIIII1I1111111111 8/24/2004 Well History File Cover Page.doc • Page 1 of 2 • Schwartz, Guy L (DOA) ZOZ -��g From: Schwartz, Guy L (DOA) Sent: Thursday, April 05, 2012 2:03 PM To: 'Tom Fouts - (C)' Subject: RE: Cancelation of Sundry for SRU 213 -10 Consider the Sundry 311 -249 withdrawn. Guy Schwartz Senior Petroleum Engineer AOGCC M' x 793 -1226 (office) 444 -3433 (cell) From: Tom Fouts - (C) [mailto :tfouts @hilcorp.com] Sent: Thursday, April 05, 2012 2:01 PM To: Schwartz, Guy L (DOA) Cc: Chet Starkel; Larry Greenstein Subject: RE: Cancelation of Sundry for SRU 213 -10 Guy, The sundry number is 311 -249. Thanks again, Tom Fouts ( (Irrstcr_rttit),rkl:rrrager Jiilc firm Alaska, LE,C tfouts @hilcorp.com Direct: l 0007) 777 -8398 Mobile: (907) 3r ;1 7.1 From: Schwartz, Guy L (DOA) [mailto:guy.schwartz @alaska.gov] Sent: Thursday, April 05, 2012 1:59 PM To: Tom Fouts - (C) Cc: Larry Greenstein; Chet Starkel Subject: RE: Cancelation of Sundry for SRU 213 -10 Tom, Can you give me a specific Sundry number so I can be sure? Guy Schwartz Senior Petroleum Engineer AOGCC 793 -1226 (office) 444 -3433 (cell) From: Tom Fouts - (C) [mailto:tfouts @hilcorp.com] Sent: Wednesday, April 04, 2012 3:55 PM To: Schwartz, Guy L (DOA) 4/5/2012 Page 2 of 2 • • Cc: Larry Greenstein; Chet Starke) Subject: Cancelation of Sundry for SRU 213 -10 Guy, Hilcorp Alaska, LLC requests to withdraw the Sundry for SRU 213 -10 which was approved on 8/11/2011. Thanks, Tom Fouts I Construction ,h2.tn,f +gc°r tfouts @hilcorp.com 1 Direct; (t)7) 4 ;4 7 ! t' 83() !Millie: -574g 4/5/2012 • • T JTf 1 Altall(KA SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 ►7L PHONE (907) 279 -1433 FAX (907) 276 -7542 Timothy C. Brandenburg Drilling Manger Union Oil Company of California aDD-- P.O. Box 196247 Anchorage, AK 99519 Re: Swanson River Field, Sterling Undefined Gas Pool, SRU 213 -10 Sundry Number: 311 -249 Dear Mr. Brandenburg: ' ,4140) Au £ all 4cd Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Daniel T. Seamount, Jr. Chair DATED this II day of August, 2011. Encl. 1 410 ( 1-4-. 1 #,Itt._ Elocr E STATE OF ALASKA til ,:\a, ' !i ,! ti l -daft ALASKA OIL AND GAS CONSERVATION COMMISSION sr-/-// APPLICATION FOR SUNDRY APPROVALS` ;; 4 ; ; flii & Ni ; OlIii. CliiffilISSian 20 AAC 25.280 r r)tltf 4 . q 1. Type of Request: Abandon El - Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Change Approved Program ❑ Suspend ❑ Plug Perforations Q - Perforate ❑ Pull Tubing ❑ Time Extension ❑ Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other: ❑ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Union Oil Company of California Development Ei , Exploratory ❑ 202 -118 - 3. Address: Stratigraphic ❑ Service ❑ 6. API Number: PO Box 196247, Anchorage, AK 99519 50- 133 - 20515 -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 0 SWANSON RIV UNIT 213 -10 - 9. Property Designation (Lease Number): 10. Field / Pool(s): FEDA028405 [Swanson River Unit] • Swanson River Field / Sterling Undef Gas Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 4,105' 3,737 3,180' 2,839 3,198' (Bridge plug) 3,180' (fill) Casing Length Size MD / TVD Burst Collapse Structural Conductor 92' 13 -3/8" 92' 92' 3,450psi 1,950psi Surface 1,989' 7" 1,989' 1,804' 8,160psi 7,020psi Intermediate Production 4,102' 3 -1/2" 4,102' 3,734' 10,160psi 10,540psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): N/A N/A N/A N/A N/A Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): N/A and N/A N/A and N/A 12. Attachments: Description Summary of Proposal 0 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Development E Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 8/23/ 11 Oil ❑ Gas ❑ WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: N/A WINJ ❑ GINJ ❑ WAG ❑ .Abandoned 0 Commission Representative: GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Chris Kanyer 263 -7831 Printed Name Timothy C. Brandenburg Title Drilling Manager Signature ^_ Phone 276 -7600 Date 8/4/2011 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 311-g,uq Plug Integrity [V] BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance Other: Subsequent Form Required: , 0 — '4.0 7. APPROVED BY I Approved by: / / COMMISSIONER THE COMMISSION Date: n R # Fi e 1 q� Form 10 -403 Revised 1/2010 U 161 t A ( DMS AUG 1 1 201E it in Duplicate evro 1 Swanson River Unit SRU 213 -10 Well SRU 213 -10 14\0•Last Completed 7/27/02 Actual Wellbore Schematic Updated 5/07/08 RKB: 309.8' / GL: 294' AMSL Casing & Tubing KB — THE: 15.83' Size Type Wt Grade ID Top Btm Hole Cmt Cmt Top ir L L 13-%" Conductor 68 K -55 12.415" Surf 92' Driven 7 Surface 29 L -80 6.184" Surf 1,989' 12 -' /<" 93 bbl Surf. 13 -3/8" 3 -Ys" Production 9.2 L -80 2.992" Surf 4,102' 6" 115 bbl Surf. 92' r _ JEWELRY DETAIL 2 ' No. Death ID OD Item 1 15.83' Tubing Hanger, Cameron `H' BPV profile, IBT Lift Threads 2 1743' - - Chemical Injection Sub w/ 1,000 psi chem valve, 3/8" control line 7 3 2,680' 2.813" 4.500" Baker `X' Nipple (2.813" Min ID) 1,989' 4 3,198' - - Magna Range Bridge Plug set 12/09/07 5 3,440' - - Magna Range Bridge Plug (cap w/ 10' cement) set 11/24/07 6 3,444' 2.323" 2.992" 15' Tubing Patch (2.323" ID) swt 5/20/07 7 3,495' 2.323" 2.992" 5' Tubing Patch (2.323" ID) set 5/20/07 8 3,712' - - A -stop, Daniels packoff, G -Stop set 8/18/03 9 3,851' - - PX Plug set in `X' Nipple 2/23/03, capped with 7' of CaCO3 10 3,870' 2.813" 4.500" Baker `X' Nipple (2.813" Min ID) 11 3,950' - - Baker QuickDrill Plug (partial set) set 2/22/03 4, PERFORATION HISTORY Interval Accum. 3 Date Zone Top Btm Amt spf Comments 12/10/07 BO upper 3,190' 3,196' 6' 6 OPEN Tag fill 11/27/07 BO lower 3,202' 3,215' 13' 6 ISO 12/09/07 3,180' SLM 08/23/03 StedingB -3a 3,447' 3,456' 9' 6 ISO5/20/07 5/07/08 06/02/07 StedingB -4a 3,524' 3,528' 4' 6 ISO t 02/25/03 Sterling B-6 3,750' 3,760' 10' 6 ISO 8/18/03 ',''` Sterling BO Upper 08/04/02 Beluga 3,985' 4,000' 15' 6 1502/22/03 4 Lo Sterling BO Lower 5 6 - Sterling B3A 7 :. Sterling B4A 8 Sterling B6 9 ., :::::::::'Z''. ti 10 4 �i. MI 11 Beluga C 3 -1/2" 4,102' ♦ ' TD = 4,105' PBTD = 4,036' MAX HOLE ANGLE = 35.00° @ 1,904' SRU 213 - 10 Actual Well Schematic 5- 07- 08.doc Updated by STP 2 -14 -11 evro Swanson River Unit SRU 213'10 `Well SRU 213 -10 "I'''..../0".. Last Completed 7/27/02 Proposed Wellbore Schematic h Updated 5/07/08 RKB: 309.8' / GL: 294' AMSL Casing & Tubing KB — THF: 15.83' Size Type Wt Grade ID Top Btm Hole Cmt Cmt Top 13 - %" Conductor 68 K -55 12.415" Surf 92' - - Driven 7 Surface 29 L -80 6.184" Surf 1,989' 12 -1/4" 93 bbl Surf. 13-3/8" : , 3- Production 9.2 L -80 2.992" Surf 4,102' 6" 115 bbl Surf. 92' 10.1 ppg Mud JEWELRY DETAIL ID 2 M No. Depth ID OD Item 1 15.83' - - Tubing Hanger, Cameron `H' BPV profile, IBT Lift Threads A +/ -150' CIBP w/ +/ -150' cement on plug (top job) r 2 1743' - - Chemical Injection Sub w/ 1,000 psi chem valve, 3/8" control line 1,989' B +1- 2,089' CIBP w/ +/ -200' cement dump bailed on plug 3 2,680' 2.813" 4.500" Baker `X' Nipple (2.813" Min ID) il 3. * C +/ -3, I55' Dump bail cement across perfs w/ +/- 35' cement on top 4 3,198' - - Magna Range Bridge Plug set 12/09/07 5 3,440' - - Magna Range Bridge Plug (cap w/ 10' cement) set 11/24/07 6 3,444' 2.323" 2.992" 15' Tubing Patch (2.323" ID) swt 5/20/07 1, 7 3,495' 2.323" 2.992" 5' Tubing Patch (2.323" ID) set 5/20/07 10.1 ppg 8 3,712' - A -stop, Daniels packoff, G -Stop set 8/18/03 9 3,851' PX Plug set in `X' Nipple 2/23/03, capped with 7' of CaCO3 Jl'Lid 10 3,870' 2.813" 4.500" Baker `X' Nipple (2.813" Min ID) 4 11 3,950' - Baker QuickDrill Plug (partial set) set 2/22/03 3 4 i tr ,, PERFORATION HISTORY " Interval Accum. Date Zone Top Btm Amt spf Comments 12/10/07 BO upper 3,190' 3,196' 6' 6 ISO .r• Sterling BO Upper 11/27/07 BO lower 3,202' 3,215' 13' 6 ISO 12/09/07 4 08/23/03 SterlingB -3a 3,447' 3,456' 9' 6 ISO5/20/07 06/02/07 SterlingB -4a 3,524' 3,528' 4' 6 ISO Sterling BO Lower 02/25/03 Sterling B-6 3,750' 3,760' 10' 6 ISO8/18/03 08/04/02 Beluga 3,985' 4,000' 15' 6 ISO2/22/03 5 6 7. Sterling B3A i '' 7 Sterling B4A $, 4 1 , Sterling B6 Si tif 9 r 10 _ 11,.. - IN 11 Beluga C 3 -1/2" 4,102' 4 ' TD = 4,105' PBTD = 4,036' MAX HOLE ANGLE = 35.00° @ 1,904' SRU 213 -10 Proposed P&A Well Schematic 8- 2- 11.doc Updated by CVK 8 -2 -2011 Chevron • • Swanson River Unit 11101 Well # SRU 213 -10 8/2/11 OBJECTIVE: • Complete reservoir, surface casing shoe, and surface abandonment. This well has no production potential or future wellbore utility. Current BHP: 1,000 psi @ 2,852' TVD Max Downhole Pressure: 1,000 psi @ 2,852' TVD (Based on current SITP) MASP: 937 psi (Based on actual reservoir conditions of the Sterling BO sand and dry gas (0.56 sp gr) gradient (0.022psi /ft) to surface) PROCEDURE SUMMARY: 1 Bail fill from +/- 3,180' to +/- 3,196'. Contingency: (If unable to establish injectivity) Reperf the Sterling BO Upper sands +/- 3,190' to +/- 3,196'. 2 Bullhead +/ -10.1 ppg KW mud in well. 3 Dump bail +/ -41' + /- 17.0ppg cement in well from +/- 3,196' to +/- 3,155'. r 4 WOC. 5 Tag TOC w/ 2.75" GR. Pressure test plug to I,500psi. 6 Set CIBP at +/- 2,089'. 7 Dump bail +/ -200' + /- 17.0ppg cement in well from +/- 2,089' to +/- 1,889'. 8 Tag TOC w/ 2.75" GR. Pressure test to I ,500psi. 9 Set CIBP at +/ -150'. 10 ND tree. 11 Perform cement top job on plug at +/ -150' to surface with + /- 15.6ppg class G cement. 12 Excavate cellar, cut off casing 3' below natural GL, set marker plate, collect GPS coordinates specifying coordinate system in daily report, backfill cellar. Close out location. SRU 213 -10 REVISED BY: CVK 8-2-11 I~NVUWVi1 Vli Vi~v v.a/ av i.aaa ,~ ~;; Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Wednesday, April 30, 2008 3:49 PM To: 'Greenstein, Larry P' Cc: Regg, James 13 (DOA) Subject: RE: Question on SRU 213-10 MIT Larry, Like I said, keep us informed regarding the perFormance of the well. That might have an influence on the scheduling of an MIT. I note ~ ~ ~.... from the production report that the well is not making any water. This is good. Hope it doesn't find it. Tom Maunder, PE AOGCC I ....a. s .,~ •. ~r From: Greenstein, Larry P [maiito:Greensteinlp@chevron.com] Sent: Wednesday, April 30, 2008 3:24 PM To: Maunder, Thomas E (DOA) Cc: Regg, James B (DOA) Subject: RE: Question on SRU 213-10 MIT ~~ ~(~~ ~ ®2t~08 Thanks Tom and Jim, Appreciate the consideration. Accordingly, we will schedule this well for an MIT late this year, if it is still flowing. In the meantime, I will make sure this well gets added to the 'Waivered Well Report' (even though it doesn't have an AA) so that we can monitor the rates and pressures on a monthly basis. Larry ,~ From: der, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Wednes April 30, 2008 1:50 PM To: Greenstein, Lar Cc: Regg, James B (DOA) / Subject: RE: Question on SRU -10 MIT Larry, I understand that you and Jim spoke this morning. I also asked him about this and we discussed. It is not necessary to do another MIT in M 008. The work performed in November 200 ~ acceptable. Keep us advised of the well's pert ance. Tom Maunder, PE AOGCC From: Green in, Larry P [mailto:Greensteinlp@chevron.com] Sent: Fr' ,February 22, 2008 4:29 PM 4/30/2008 Question on SRU 213-10 MIT • Page 1 of 2 • Maunder, Thomas E {DOA) From: Sent: Cc: Subject: Greenstein, Larry P [Greensteinlp@chevron.com] Friday, February 22, 2008 4:29 PM Maunder, Thomas E (DOA) Regg, James B (DOA) RE: Question on SRU 213-10 MIT ~ ~~` 3-Ili Attachments: SRU 213-10 Operation Summary.pdf; SRU 213-10 High-Low test.tif Yes there was Tom. Thanks for the quick turnaround. Prior to the unsucessful plugback (perfs didn't flow), the bridge plug with 10' of cement on top was positive tested to 1300# then negative tested to 300# sucessfully, per procedure. When the perfs above this plug didn't work, another bridge plug was run (this is the one that fit into the 6' window) with no cement on top. Per procedure, this plug was also positive tested to 1300# and negative tested to 300# successfully. f attached a summary that shows these two events about two weeks apart. If these could be used as proof of mechanical integrity, this would give us a year from then (last one was on 12/10!07) before needing another MIT. I found a copy of the chart from the first plug's test (attached), but not one from the second. Let me know what you think. Larry ~1iJNEE~ A P R ~ ~ 2008 From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Friday, February 22, 2008 2:50 PM To: Greenstein, Larry P Cc: Regg, lames B (DOA) Subject: RE: Question on SRU 213-10 MIT Larry, In conducting this latest work, was any pressure test done of the wellbore? I haven't looked at the file to see what was proposed. Tom From: Greenstein, Larry P [mailto:Greensteinlp@chevron.com] Sent: Friday, February 22, 2008 2:08 PM To: Maunder, Thomas E (DOA); Regg, James B (DOA) Subject: Question on SRU 213-10 MIT Tom & Jim, By rule, this monobore gas producer requires an annual MIT. The last MIT was done 5/07, so it is coming due this year. We have tried a couple of times, but finally have same flow coming out of this well, not much, but some. We had to slip a bridge plug into a 6' window to isolate some wet perfs to have this little bit of success. Please look at the attached schematic and give me some help as to how to perform an MIT now. In the past, like last May and before in August of 2003, we pressured upon the tubing after we had isolated all the existing perfs and before we made new perfs. Real clean, real easy. If this well continues to flow, BIG IF, we don't have that option. If the well stops flowing, this well will probably go back on the LTSI well monitoring report I send to you 4/30/2008 Question on SRU 213-10 MIT • Page 2 of 2 • quarterly. Would it be possible to use the X-nipple @ 2688' MD (2390' TVD 450' higher than perfs) to set a slickline retrievable plug and do the tubing pressure test to 1500 psi from there?? We haven't had any pressure troubles with this well so far. I know a monobore producer is unusual, but with us recompleting uphole each time, the possible expected pressures are only getting lower and lower. Let me know what you think is possible. Call me if you want to discuss. No hurry, we have time to consider some options. 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Y ~., • ~ - - - - -vov. ~' :. ;::; -.. - .. :,t.':.::.:' . - ..... _ -. .: -~ ~...r~ .... :... .... .. ~- - -_ - - - - - .. . 0 ::~'` .'_-.'.. 1~ :. _ _.... :-•~:~ t - -. - -"' '=fir' ,r M1 ... - ~__ _ _. ...--ter- - ,. ... ,y ...__ .. . • -- ... _. _ - ...- ..... _ .- 1~-~ ~ ~~is ~ . 11 •: 1 • Swanson River Unit SRU # 213-10 Drilling Program Schematic 12/10/07 API #: 50-133-205-15-00 CASING AND TUBING DETAIL Size Wt Grade Conn Top and Bottom and 13-3/8" 69 Weld Surf' 92' 7" 29 L-80 Butt Surf 1987' 3-1/2" 9.2 L-80 IMP Butt Surf 4102' Note: 3-1/2" tubing cemented at 4102'MD, 3729' TVD l lbbls returns to surface during cement job Cement Bond Log (8/1/02) confirms cement bonding over the entire interval 7" Surface Casing @ 1987' MD, 1802 TVD returns noted to surface during cement job Leak off test; mud wgt eq. of 15.9ppg @1802'TVD/1987'MD; .827psi/ft gradient w/out breaking reservoir. JEWELRY DETAIL (MD) NO. De th Item 1. Surf 3-1/2" Tbg h r w/Cameron "H" BPV rofile 2. 1750' 3-1/2" Chem In' Sub w/1000 si chem valve 3. 2688' Baker X Ni le with 2.813" profile 4a. 3198' Ma na Ran a Brid e Plu Sa. 3440' Ma na Ran a Brid a Plu A 3444' 15' Tubing Patch (2.323" ID) B 3495' S' Tubin Patch (2.323" [D) 4. 3712' "A" Sto @ 3714', Daniels Pack-off & "G" Sto @ 3712' 5. 3873' Baker X Ni le with 2.813" rofile w/ Plu & CaC03 6. 3950' BOT QuickDrill (Partial Set) CURRENT PERFORATION DATA (MD) one Top Btm Zone ~ Comments 30 3189.5 3195.5 Sterling 6 2" HC Omega (Open) 30 3201.5 3214.5 Sterling 6 2" HC Omega (Isolated) 33a 3447 3456 Sterling 6 2" HSD Powerjet (Isolated) 34a 3524.5 3528.5 Sterling 6 1-11/16" Power Spiral (Isolated) 3-6 3750 3760 Sterling 6 Power Jet HC (Isolated) Stray 3985' 4000' Beluga 6 Isolated w/two plugs (Isolated) SRU 213-10 TD = 4105' MD, 3732' TVD Directional Well Revised 1/29/08 BCA RKB to TBG Head = 16.5' Elevation 293.5 Feet Page 1 of 1 • Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Thursday, February 07, 2008 9:59 AM To: Tyler, Steve L Subject: SRU 213-10 (202-118) Steve, We recently received a 404 (report of sundry operations) from the plugging and perforating activities that took place in NovemberlDecember. The sundry reference a# the bottom right is trot correct. This work was authorized by 307-345. The work authorized by 307-082 was reported by 404 filed 6/20/07. You may wish to change the sundry reference on your document. Your attention to recording the proper work authorizations wiii be appreciated. Cail or message with any questions. Tom Maunder, PE AOGCC I~ ~~~ ~. ~ 2oa Zi~i2oos ~ y^ ~ (~ ~ STATE OF ALASKA 1~ ALASKA OIL AND GAS CONSERVATION COMMIS510N REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon Repair Well Plug Perforations ~ Stimulate Other Performed: Alter Casing ^ Pull Tubing^ Perforate New Pool ^ Waiver^ Time Extension^A~~- Change Approved Program ^ Operat. Shutdown^ Perforate ~ Re-enter Suspended Well^ 2. Operator Union Oil Company of California 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development Q Exploratory^ 202-118/Conservation Order #474 3. Address: P.O. Box 196247, Anchorage, AK 99519 Stratigraphic^ Service^ 6. API Number: 50-133-20515-00 - 7. KB Elevation (ft): 9. Well Name and Number: 16.6' SRU 213-10 8. Property Designation: 10. Field/Pool(s): Swanson River Field fG~~ D~1T~OS~ Swanson River Unit 11. Present Well Condition Summary: Total Depth measured 4105' feet Plugs (measured) 3712', 3873', 3950' ,3440', 3198' true vertical 3732' feet Junk (measured) none ^-~ Effective Depth measured 3198' feet true vertical 2857' feet Casing Length Size MD TVD Burst Collapse Structural Conductor 92' 13-3/8" 92' 92' 5,020 psi 2,270 psi Surface 1987' 7" 1987' 1802' 8,160 psi 7,020 psi Production 4105 3-1/2" 4,105' 3,737' 10,160 psi 10,530 psi rf ' ' V Pe oration depth: Measured depth: 3189.5 -3195.5 True Vertical depth: 2849'-2855' Tubing: (size, grade, and measured depth) 3-1/2", 9,2# L-80 4,105' Packers and SSSV (type and measured depth) None None 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 0 900 Subsequent to operation: 0 0.5 0 0 750 psi 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run Exploratory^ Development Q Service ^ Daily Report of Well Operations X 16. Well Status after work: Oil^ Gas ~ WAG ^ GINJ ^ WINJ ^ WDSPL ^ 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 Steve Tyler - 263-7649 ~3 Printed Name Timothy C. ran ~ rg Title Drilling Manager Signatu` Phone 907-276-7600 Date 1/29/2007 Form 10-404 Revised 0412006 ~ ~~~~ ~~~~ ~("~ ~ `~ ~~~~ ~ JAN 2 9 2~1 .~ i~ ~~~ Submit Original Only • • Swanson River Unit SRU # 213-10 Drilling Program Schematic 12/10/07 API #: 50-133-205-15-00 RKB to TBG Head = 16.5' Elevation 293.5 Feet CASING AND TUBING DETAIL Size Wt Grade Conn Ton and Bottom and 13-3/8" 69 Weld Surf 9 2' 7" 29 L-80 Butt Surf 1987' 3-1/2" 9.2 L-80 IMP Butt Surf 4102' Note: 3-1/2" tubing cemented at 4102'MD, 3729' TVD l lbbls returns to surface during cement job Cement Bond Log (8/1/02) confirms cement bonding over the entire interval 7" Surface Casing @ 1987' MD, 1802 TVD returns noted to surface during cement job Leak offtest; mud wgt eq. of 15.9ppg @1802'TVD/1987'MD; .827psi/ft gradient w/out breaking reservoir. .IF.WELRY DETAIL (MDl 3950' OC @ 3648' B6 5 6 stray TD = 4105' MD, 3732' TVD Directional Well NO. De th Item 1. Surf 3-I/2" Tb h r w/Cameron "H" BPV rofile 2. 1750' 3-1/2" Chem In' Sub w/1000 si chem valve 3. 2688' Baker X Ni le with 2.813" rofile 4a. 3198' Ma na Ran e Brid e Plu Sa. 3440' Ma na Ran e Brid e Plu A 3444' 15' Tubin Patch (2.323" ID B 3495' S' Tubin Patch 2.323" ID 4. 3712' "A" Sto 3714', Daniels Pack-off & "G" Sto 3712' 5. 3873' Baker X Ni le with 2.813" rofile w/ Plu & CaC03 6. 3950' BOT QuickDrill Partial Set CURRENT PERFORATION DATA (MDl Zone TOp Btm Zone S~f Comments BO 3189.5 3 ] 95.5 Sterlin 6 2" HC Ome a (O en) BO 3201.5 3214.5 Sterlin 6 2" HC Ome a (Isolated) B3a 3447 3456 Sterlin 6 2" HSD Power'et (Isolated) Boa 3524.5 3528.5 Sterlin 6 1-11/16" Power S iral (Isolated) B-6 3750 3760 Sterling 6 Power Jet HC (Isolated) Stra 3985' 4000' Belu a 6 Isolated w/two lu s (Isolated) SRU 213-10 Revised 1/29/08 BCA -B4a ~~~ • Chevron Francisco Castro Technical Assistant January 3, 2008 To: AOGCC Mahnken, Christine R 333 W. 7th Ave. Ste# 100 Anchorage, AK 99501 ~ ~ ~ ~ r~ Chevron North America Exploration and Production 909 W. 9th Avenue Anchorage, AK 99501 Tele: 907 263 7844 Fax: 907 263 7828 E-mail: fcbn~chevron.com °,'>~~~ JAN ~ 8 200 ' iNTER`lAL U`vELL LOG TYPE ~ SCALE LOG DATE ~, LOGGED i ' NOTES RUPJ B-LINE ~~ FILP~t ~ CD PD~~ c '~ ~ CLIS RU 213-10 PERFORATING RECORD 1.56" HSD/PJ/6SPF/60 DEG/GR/CCL " 1-Nov-07 3450 - 3455 1 1 1 DS PERFORATING RECORD 2" HSD/PJ OMEGA,'6SPF/60 3241 - SRU 213-10 DEG/GR/CCL 5" 27-Nov-07 3434 4 1 1 PDS PLUG SETTING RECORD MAGNA RANGE PLUG 3241 - SRU 213-10 GR/CCL 5" 24-Nov-07 3434 2 1 1 PDS c~Da ~~~~ ~tSgt~} SRv, 2,-3~ I O Please acknowledge receipt by signing and returning one copy of this transmittal .or FAX to X07 263 7828. Received y: Date: ~~~ • Page 1 of 4 • Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Monday, November 19, 2007 4:21 PM To: 'Tyler, Steve L' Cc: Walsh, Chantal [Petrotechnical}; Applewhite, Billy -APRs [contractor]; Dalebout, Joe; Harness, Evan ~ ~~ _ ~ ;~ Subject: RE: SRU 213-10 (~) Deviation from Sundry Ptan Steve, et al, I have spoken with Commissioner Foerster and she approves the change in the operations. Nothing further is needed. Call or message with any questions. Tom Maunder, PE AOGCC From: Tyler, Steve L [mailto:tylersl@chevron.com] Sent: Monday, November 19, 2007 3:59 PM To: Maunder, Thomas E (DOA) Cc: Walsh, Chantal [Petrotechnical]; Applewhite, Billy -APRs [contractor]; Dalebout, ]oe; Harness, Evan Subject: SRU 213-10 Deviation from Sundry Plan Tam We were unsuccessful in our attempt to push wellbore fluid (tagged @ 1726') away into the Boa sand. Probably do to the top of fill @ 3494'. We are planning on perforating 5' of the upper tbg patch (tbg patch (c~ 3444' to 3459'}, We will then "push" the fluid out of the wellbore with gas into the 63a sand. We will then continue with our Recompletion plan ~;;~` NOV ~ 3 2007 Drilling Engineer, Adviser Union Oil Company of California 1~Office: (907) 263-7649 1~Cell: (907) 350-6295 1reHome: (907) 696-1837 Fax: ($66) 244-1439 c~Email: tylerSl@chevron.com 11/19/2007 • • Swanson River Unit SRU # 213-10 Drilling Program Proposed Schematic 11/l API #: 50-133-205-15-00 RKB to TBG Head = 16.5' Elevation 293.5 Feet ~ Fill at 3494' =B4a TOC @ 3648' B6 S 3950' 6 _ stray d TD = 4105' MD, 3732' TVD Directional Well Size Wt Grade Conn Top and Bottom and 13-3/8" 69 Weld Surf' 92' 7" 29 L-80 Butt Surf 1987' 3-1/2" 9.2 L-80 IMP Butt Surf 4102' Note: 3-1/2" tubing cemented at 4102'MD, 3729' TVD l lbbls returns to surface during cement job Cement Bond Log (8/1/02) confirms cement bonding over the entire interval NO. De th Item 1. Surf 3-1/2" Tb h w/Cameron "11" BPV rofile 2. 1750' 3-I/2" Chem In' Sub w/1000 si chem valve 3. 2688' Baker X Ni le with 2.813" rofile A 3444' 15' Tubin Patch 2.323" ID B 3495' S' Tubin Patch 2.323" ID) 4. 3712' "A" Sto 3714', Daniels Pack-off & "G" Sto 3712' 5. 3873' Baker X Ni le with 2.813" rofile w/ Plu & CaC03 6. 3950' BOT QuiekDrill (Partial Set) CURRENT PERFORATION DATA (MD) Zone To Btm Zone S f Comments B3a 3447 3456 Sterlin 6 2" HSD PowerJet (Isolated) Boa 3524.5 3528.5 Sterlin 6 1-11/16" Power S iral (OPEN) B-6 3750 3760 Sterlin 6 Power Jet HC (Isolated) Stra 3985' 4000' Belu a 6 Isolated w/two lu s (Isolated) SRU 213-10 6/6/07 BCA • • SARAH PALlN, GOVERNOR C01~5EB~A A,lIOK O ~ I ~ 333 W 7th AVENUE, SUITE 100 i~. ~ii ~~t~~•~~~11~~•iiiiii---777 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Timothy C. Brandenberg Drilling Manager Union Oil Company of California PO Box 196247 Anchorage, AK 99519 ~~~+~~~~'' ~~~ ~ ~ 2007 ~'`~~ Re: Swanson River Field, Swanson River Undefined Gas Pool, SRU 213-10 Sundry Number: 307-345 Dear Mr. Brandenberg: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. P;tease note the conditions of approval set out in the enclosed form. When providing notice for a representative of the Commission to witness any required test, contact the' Commission's petroleum field inspector at (907) 659-3607 (pager) . 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. DATED this ~~day of November, 2007 Encl, Sincerely, °~ , ~ i -~s - ~~ ~~ REC~IV~D ~"Y~~ ~ STATE OF ALASKA ~ ALASKA OiL AND GAS CONSERVATION COMMISSION~hj ~~U ~ ~ ~~~~ APPLICATION FOR SUNDRY APPROVA ~~ IA~ska Oil ~ Gas Cans. Commission 20 AAC 25.280 .__~_____ 1. Type of Request: Abandon ^ Suspend ^ Operational shutdown ^ Perforate Q Waiver Other ^ Alter casing ^ Repair well ^ Plug Pertorations ^~ Stimulate ^ Time Extension ^ Change approved program ^ Pull Tubing ^ Perforate New Pool ^ Re-enter Suspended Well ^ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Union Oil Company of California Development ^ Exploratory ^ 202-118/Conservation Order #474 3. Address: Stratigraphic ^ Service ^ 6. API Number: P.O. Box 196247, Anchorage, AK 99519 50-133-20515-00 7. If pertorating, 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 ~ SRU 213-10 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): Swanson River Field 16.6' Swanson River Unit ' 12. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 4105' 3732' - 3558' 3205' 3712' Casing Length Size MD TVD Burst Collapse Structural Conductor 92' 13-3l8" 92' 92' 5,020 psi 2,270 psi Surface 1,800' 7" 1,800' 1,649' 8,160 psi 7,020 psi Intermediate Prpduction 4,105' 3-1/2" 4,105' 3,737' 10,160 psi 10,530 psi Liner Pertoration Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 3,524.5' - 3,528.5 3-1/2" L-80 4,105' Packers and SSSV Type: Packers and SSSV MD (ft): N/A N/A 13. Attachments: Description Summary of Proposal Q 14. Well Class after proposed work: Detailed Operations Program ^ BOP Sketch ^ Exploratory ^ Development Q Service ^ 15. Estimated Date for 1 07 C e~- `~~ 16. Well Status after proposed work: Q~ V Commencing Operations: t~ ~ l,~1 ~ ~~ ~ J ` 1 Oil ^ Gas Q Plugged ^ Abandoned ^ 17. Verbal Approval: Date: WAG ^ GINJ ^ WINJ ^ WDSPL ^ Commission Representative: 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Steve Tyler - 263-7649 Printed Name Timothy C Brandenburg Title Drilling Manager Signature - Phone Date C~-. F t ~ ~ ~ "~ d"~~- COMMISSION USE ONLY i ~~ ~ - J'4' Condit ons of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity ^ BOP Test ^ Mechanical Integrity Test ^ Location Clearance ^ Other: S~~ ~~ES ~ n "erpC~~v~ .. , ... ti~C~ ~ iz 2DD~ Subsequent Form Required: 1~.~ APPROVED BY Approved by: COM ER THE COMMISSION Date: ~/~ /~ -( Form 10-403 Revised 0612006 Submit in Duplicate • • SRU 213-10 Procedure Summary OBJECTIVE: • Isolate the Sterling B4A sand and recomplete well in the Sterling BO sand. PROCEDURE SUMMARY: • Squeeze well fluid back into formation through existing perfs-with field gas. • Run slickline bailer to determine fluid level. • Run Bridge Plug and set above patches at 3440(+/-) to isolate B4A perfs. • Dump bail approximately 10' of cement on plug • WOC 24 hrs. \\ (~ ~'~ C,orkC~.C.~- ~~S,PEL~tpr~sot' O~oh~Ow~r~SS • Pressure test to 1300 psi for positive test (12 hrs). Bleed down to 300 psi for negative test (12 hrs). ~ ~,}.~~S~S s~~\~t 1~~\~,(~~~t ust,,,` ~~ ~,~S~~k,r.~ a ~co~?cyc,~~+t ~-or~~rVt ~c~~ j$t~csSW~.S • Run 2 P3 Omega, 6 spf, 60 degree phase HC and perf~terlmg BO from 3202 to ~` yr, 3215'. ~t ~ t'S Contingency: • Isolate the BO perfs 3202' - 3215' with Bridge Plug at +1- 3200' and Perforate additional BO sands from 3190' - 3196'. • ~~ Swanson River Unit SRU # 213-10 Drilling Program Schematic 6/6/07 API #: 50-133-205-15-00 RKB to TBG Head = 16.5' Elevation 293.5 Feet ("ARTN(~ AND TTIRTN(: DF.TATT. Size Wt Grade Conn Two and Bottom and 13-3/8" 69 Weld Surf 92' 7" 29 L-80 Butt Surf 1987' 3-1/2" 9.2 L-80 IMP Butt Surf 4102' Note: 3-1/2" tubing cemented at 4102'MD, 3729' TVD 11 bbls returns to surface during cement job Cement Bond Log (8/1/02) confirms cement bonding over the entire interval 7" Surface Casing @ 1987' MD, 1802 TVD returns noted to surface during cement job Leak off test; mud wgt eq. of 15.9ppg @1802'TVD/1987'MD; .827psi/ft gradient w/out breaking reservoir. .TF.WF,T.RY DF.TATL (MDl 3950' OC @ 3648' B6 5 6 stray TD = 4105' MD, 3732' TVD Directional Well NO. De th Item 1. Surf 3-1/2" Tb h r w/Cameron "H" BPV rofile 2. 1750' 3-1/2" Chem In' Sub w/1000 si them valve 3. 2688' Baker X Ni le with 2.813" rofile A 3444' 15' Tubin Patch (2.323" ID B 3495' S' Tubin Patch 2.323" ID 4. 3712' "A" Sto 3714', Daniels Pack-off & "G" Sto 3712' 5. 3873' Baker X Ni le with 2.813" rofile w/ Plu & CaC03 6. 3950' BOT QuickDrill (Partial Set ('TTRRF.NT PF.RFnRATTON DATA fMDI Zone To Btm Zone S f Comments B3a 3447 3456 Sterlin 6 2" HSD PowerJet (Isolated) Boa 3524.5 3528.5 Sterlin 6 1-11/16" Power S iral (OPEN) B-6 3750 3760 Sterling 6 Power Jet HC (Isolated) Stra} ~ 39R~' L~1000' Belu;a 6 Isolated w/two lu s (Isolated) SRU 213-10 6/6/07 BCA =B4a i Swanson River Unit SRU # 213-10 Drilling Program Proi~osecl Schematic 11/12/07 API #: 50-133-205-15-00 RKB to TBG Head = 16.5' Elevation 293.5 Feet CASING AND TUBING DETAIL Size Wt Grade Conn Two and Bottom and 13-3/8" 69 Weld Surf' 92' 7" 29 L-80 Butt Surf 1987' 3-1/2" 9.2 L-80 IMP Butt Surf 4102' ~~ ~ roc Proposed Plug Set at 3440' +/- 3 Proposed Perf 3202'-3215' Proposed TOC 3450'+/- A B ~ ~ Fill at id94' _ =B4a TOC @ 3648' SRU 213-10 - - B6 5 3950' 6 stray 4 TD = 4105' MD, 3'732' TVD Directional Well Note: 3-1/2" tubing cemented at 4102'MD, 3729' TVD 1 lbbls returns to surface during cement job Cement Bond Log (8/1/02) confirms cement bonding over the entire interval 7" Surface Casing @ 1987' MD, 1802 TVD returns noted to surface during cement job Leak off test; mud wgt eq. of 15.9ppg @1802'TVD/1987'MD; .827psi/ft gradient w/out breaking reservoir. JEWELRY DETAIL MD NO. De th Item 1. Surf 3-1/2" Tb h r w/Cameron "H" BPV rofile 2. 1750' 3-1/2" Chem In' Sub w/1000 si chem valve 3. 2688' Baker X Ni le with 2.813" rofile A 3444' 15' Tubin Patch (2.323" ID B 3495' S' Tubin Patch (2.323" ID 4. 3712' "A" Sto n 3714', Daniels Pack-off & "G" Sto 3712' 5. 3873' Baker X Ni le with 2.813" rofile w/ Plu & CaC03 6. 3950' BOT QuickDrill (Partial Set) CURRENT PERFORATION DATA MD Zone To Btm Zone S f Comments B3a 3447 3456 Sterlin 6 2" HSD PowerJet (Isolated) Boa 3524.5 3528.5 Sterlin 6 1-11/16" Power S iral (OPEN) B-6 3750 3760 Sterlin 6 Power Jet HC (Isolated) Sn a~ ~_ 398>' 4000' Belu a 6 Isolated w/two lu s (Isolated) 6/6/07 BCA cA STATE OF ALASKA . ~ RECEI ALA~ OIL AND GAS CONSERVATION COM ION REPORT OF SUNDRY WELL OPERATIONSfULO 3 I 1. Operations Abandon U Repair Well TI Plug Perforations ~ Stimulate U '.. Other U C"í1¡) "-ViI1:5.. Vi,,,,'.·. /.:, Performed: Alter Casing D Pull Tubing D Perforate New Pool D WaiverD Time Extension D';JithVfage Change Approved Program D Opera!. Shutdown D Perforate [2] Re-enter Suspended Well D 2. Operator Union Oil Company of California 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development [2] Exploratory D 202-118/Conservation Order #474 3. Address: P.O. Box 196247, Anchorage, AK 99519 Stratigraphic D Service D 6. API Number: 50-133-20515-00 - 7. KB Elevation (ft): 9. Well Name and Number: 16.6' SRU 213-10 - 8. Property Designation: ~aA O~;~.s 10. Field/Pool(s): Swanson River Field - Swanson River Unit ./ 11. Present Well Condition Summary: Total Depth measured 4105' feet Plugs (measured) 3712', 3873', 3950' true vertical 3732' feet Junk (measured) none Effective Depth measured 3494' feet true vertical 3144' feet Casing Length Size MD TVD Burst Collapse Structural Conductor 92' 13-3/8" 92' 92' 5,020 psi 2,270 psi Surface 1987' 7" 1987' 1802' 8,160 psi 7,020 psi Production 4105 3-1/2" 4,105' 3,737' 10,160 psi 10,530 psi Perforation depth: Measured depth: 3524.5' - 3528.5' sCANNED JUL 1 ß 20D1 True Vertical depth: 3173' - 3178' Tubing: (size, grade, and measured depth) 3-1/2",9,2# L-80 4,105' Packers and SSSV (type and measured depth) None None 12. Stimulation or cement squeeze summary: Intervals treated (measured): RBDMS BFL .JUL 0 6 2007 Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 0 500 psi Subsequent to operation: 0 0 0 0 400 psi 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run Exploratory D Development [2] Service D Daily Report of Well Operations X 16. Well Status after work: oilD Gas [2] WAG D GINJ D WINJ D WDSPL D 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. ISUndry Number or N/A if C.O. Exempt: 307-082 Contact Steve Tyler - 263-7649 Printed Name Timothy C. Brandenburg Title Drilling Manager Signature ?-L? C ;; ~ Phone 907-276-7600 Date t:,~ ¿..:;;>-q ¿;/ L-/ - .- Form 10-404 Revised 04/2006 np , G , ~,' A , b:'\{ tJ ~ 4 ~"bm' 0""001 o"~ Well Name SRU 213-10 Primary Job Type Perforation - Post Production Jobs Primary Job Type Perforation - Post Production Daily Operations 5/10/200700:00 - 5/11/2007 00:00 Operations Summary No Operations 5/11/200700:00 - 5/12/2007 00:00 Operations Summary RIH w/2.80" Dummy Gun. Set down @ 2678', POOH. RIH w/2.795" GR. Tag fill @ 3481'. POOH. RIH w/1.75" GR. Tag @ 3481', POOH. RI w/2.80" Dummy Gun set down @ 2678'. Spanged to 2693', POOH. RI w/2" DD Bailer. Bailed from 3485' to 3490'. POOH w/ full Bailer of wet sand. RI bailed from 3490' to 3493'. POOH w/ full bailer of sand slurry, Swab & Master leaking. SDFN, 5/16/200700:00 - 5/17/2007 00:00 Operations Summary MIRU slickline, Made 8 runs w/2.5" Bailer. Bailed fill from 3485' to 3511'. SDFN, 5/17/200700:00 - 5/18/2007 00:00 Operations Summary Made 9 runs w/2.25" bailer. Bailed fill from 3507' to 3522'. SDFN_ 5/18/200700:00 - 5/19/2007 00:00 Operations Summary Made 8 runs w/2.25" bailer. Bailed fill from 3518' to 3537'. SDFN 5/19/200700:00 - 5/20/2007 00:00 Operations Summary RIH w/ PressurelTemp Survey tool to 3456', POOH. LD tools. Made 6 runs w/2.25" bailer from 3529' to 3538'. Made 2 runs w/1.75" bailer. Bailed fill from 3539' to 3545'. Made 4 runs w/2.25" bailer. Bailed fill from 3543' to 3554'. Cut wire, 5/20/200700:00 - 5/21/2007 00:00 Operations Summary RIH w/ tbg scratcher. Work tools through profile nipple @ 2688'. RIH w/2.80" Dummy gun, Tag fill @ 3547', POOH. RIH w/2.80" GR. Tag fill @ 3545', RD Slickline. RU Eline. RIH set 5' tb9 patch @ 3495' to 3500'. POOH. RIH set 15' tbg patch from 3444' to 3459'. POOH. RD Eline. 5/21/2007 00:00 - 5/22/2007 00:00 Operations Summary No Operations - Schlumberger crew sent to Grayling Pit 5/30/2007 00:00 - 5/31/2007 00:00 Operations Summary Pressure tubing up to 1450 psi for MIT 6/1/2007 00:00 - 6/2/2007 00:00 Operations Summary Cont MIT, high test after 18 hrs was 1444 psi. Neg test started at 501 psi and ended at 514 psi after 21 hrs. Made two dummy gun runs, one w/2.225" to 3444' and one 2.125" to 3542', 6/2/2007 00:00 - 6/3/2007 00:00 Operations Summary Ran 1-11/16"x4' Power spiral, 7.5 spf, 60 deg phase and perf from 3524.5' to 3528.5'. No pressure change. Plan to draw well down 30 psi. 6/5/2007 00:00 - 6/6/2007 00:00 Operations Summary Drew well down to 400 psi. and could not get well to come on. Had to pump 5 gal diesel to get 2" bailer to go. Made2 bailer runs and bailed sand from 3486' to 3494', Got fluid sample from 2000' and ran 2-1/8" swedge to 3494' RKB to TBG Head = 16.5' Elevation 293.5 Feet 2 3 3950' B3a B6 5 6 stray TD = 4105' MD, 3732' TVD Directional Well SRU 213-10 13-3/8" 7" 3- 112" 69 29 9,2 Weld 80 L-80 Surf' Butt Surf IMP Butt Surf 92' 1987' 4102' Note: 3-1/2" tubing cemented at 4102'MD, 3729' TVD 11 bbls returns to surface during cement job Cement Bond Log (8/1/02) confirms cement bonding over the entire interval 7" Surface Casing @ 1987' MD, 1802 TVD returns noted to surface during cement job Leak offtest; mud wgt eq. of 15.9ppg @1802'TVD/1987'MD; .827psi/ft gradient wlout breaking reservoir. 2" HSD Power Jet (Isolated) 1-11116" Power S ira1(OPEN) Power Jet HC (Isolated) Isolated w/two Iu s (Isolated) 6/6/07 BCA MIT SRU 213-10 5-30-07 . . Gentlemen, àô~" n 8 Here are the documents for the MIT on Swanson River well SRU 213-10. Thanks La rry «213-10 MIT 5-30-07 Chart.jpg» «MIT SRU 213-10 05-30-07.xls» Content-Description: 213-10 MIT 5-30-07 Chart.jpg MIT 5-30-07 Content- Type: image/jpeg Content-Encoding: base64 Content-Description: MIT SRU 213-10 05-30-07.xls SRU 213-10 05-30-07.xls Content-Type: application/vnd.ms-excel Content-Encoding: base64 5GANNE1J JUNO 1 20D? 1 of 1 5/31/20074:41 PM . . STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Email to:Bob_Fleckenstein@admin.state.ak.us;Jim_Regg@admin.state.ak.us;Tom_Maunder@admin.state.ak.us OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Unocal Alaska Swanson River/Swanson RiverUnit/213-10 Pad 05/30/07 Robert Bush not witnessed - OK'd by Jim Regg r} 5t~\ \ 01 \'-., êý q Packer Depth Pretest Initial 9 hrs 18 hrs Weill 213-10 I Type Inj. I none TVD I 3,680' Tubing 950 1,450 1,445 1,444 Intervall 0 P.T.D.I 2021180 I Type test I P Test psil 1450 Casing 0 0 0 0 P/FI P Notes: MD is top of cement plug. Monobore gas producer. OA 0 0 0 0 Perfs to be added => 3525' - 3529'. Tubing pressure tested with gas overnight (see attached chart). Annual MIT required. Weill I Type Inj. I I TVD I Tubing Interval PTD.I I Type test I I Test psil Casing P/FI Notes: OA Weill I Type Inj.1 I TVD I Tubing Interval I p.T.D.1 I Type test I I Test psi I Casing P/FI Notes: OA Weill I Type Inj.1 I TVD I Tubing I ntervall P.T.D.I I Type test I I Test psil Casing P/FI Notes: OA Weill I Type Inj.1 I TVD I Tubing Interval I P.T.D.I I Type test I I Test psil Casing P/FI Notes: OA /" TYPE INJ Codes D = Drilling Waist G=Gas I = Industrial Waistewater N = Not Injecting W = Water TYPE TEST Codes M = Annulus Monitoring P = Standard Pressure Test R = Internal Radioactive Tracer Survey A = Temperature Anomaly Survey D = Differential Temperature Test INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance T = Test during Workover o = Other (describe in notes) MIT Report Form BFL 9/1105 MIT SRU 213-10 05-30-07.xls Re: FW: 213-10 MIT . I do not have an inspector available for witness of the pressure test of 213-1 O. Please send a copy of the chart when the test is complete. Thank you. Jim Regg AOGCC Merle, Greg L wrote, On 5/30/2007 5:12 PM: Mr. Regg, He have 1450 psi on the tubing and a chart recorder on well 213-10 as of 2:00 P.M. this afternoon. Could we arrange for a witness for this MIT? Greg Merle From: James Regg [mailto:jim reqq@admin.state.ak.us] Sent: Friday, May 25, 20073:38 PM To: Merle, Greg L Subject: Re: FW: 213-10 MIT 1450 psi test is acceptable. Jim Regg Merle, Greg L wrote: Jim, ~'A.NNED JUN 0] 2007 From Phil Ayre. Greg Merle From: Ayer, Phil M Sent: Friday, May 25, 20072:03 PM To: Merle, Greg L Cc: Greenstein, Larry P; Tyler, Steve L; Bush, Robert E; Walgenbach, Christopher Subject: RE: 213-10 MIT Greg, The aniticípated max tbg pressure with the B4a perfs, as stated in step 7 of the flow procedure, is a shut in pressure of 1148 psig. I see Jim Regg has asked you a question concerning this. I am anticipating we will have a flowing tbg pressure somewhere between 680 and 950 psig 1 of3 5/31/2007 8:26 AM Re: F~: 213-10 MIT . . depending on permeability. Phil Phil Ayer MidContinent/ Alaska Business Unit Chevron North American Exploration and Production Company 909 West 9th Avenue, Anchorage, AK 99501 907-263-7620 (work) 907 -250-2711 (cell) 907-263-7847 (fax) From: James Regg rmailto:iim reqq@admin.state.ak.us] Sent: Friday, May 25, 2007 11:21 AM To: Merle, Greg L Cc: Greenstein, Larry P; Ayer, Phil M; Tyler, Steve L; Bush, Robert E; Walgenbach, Christopher Subject: Re: 213-10 MIT One more question (apologize for not including it in previous message) - Is the 950 psi tubing pressure that has been reported since 1/1/2006 the max pressure this well will see with the B4 perfs? Jim Merle, Greg L wrote: Jim, This would be a tubing test. Some sections of the piping that would be used to deliver gas to the well for the pressure test are rated ANSI 600 (1480 MAWP). This is the reason for the request to lower the test pressure to 1450 psi. Greg Merle From: James Regg [mailto:jim reqq@admin.state.ak.us] Sent: Friday, May 25, 20079:21 AM To: Merle, Greg L Cc: Greenstein, Larry P; Ayer, Phil M; Tyler, Steve L; Bush, Robert E; Walgenbach, Christopher Subject: Re: 213-10 MIT Greg et al - CO 474 requires annual demonstation of mechanical integrity and does not specify the method or pressure. We have received well pressures on a quarterly basis while the well has been shut 2of3 5/31/2007 8:26 AM Re: FW: 213-10 MIT . . in satifisying this requirement. An emnail sent to Larry Greenstein on Februrary 8, 2006 did advise that a pressure test would be required before placing 213-10 back in production (again, no specified pressure;1500 psi would be the test pressure requirement if this were an injector instead of a producer). That said, a little more information about why 1450 psi and not 1500 psi is necessary. (Something to do with the patch set over the B3A perfs and plan to perf B4 zone which is approximately 70 feet downhole?) Please justify the test pressure. Also, are you referring to a tubing test or IA pressure test? Jim Regg AOGCC Merle, Greg L wrote: Mr. Regg, We have set a plug over the B-3A sands in the monobore completion 213-10 and are intending to perforate the B-4A sands. We would like to perform an MIT on this well before adding the B-4A perforations. The recommended pressure for this MIT is 1500 psi. Due to piping rating considerations, we would like to use 1450 psi for this procedure. We intend to use a chart recorder and hold this pressure for 12 hours. I know that the holiday weekend is upon us so could we plan for an agency witness for next week? Greg Merle Jim Regg <jim regg(évadmin.state.ak.us> Petroleum Engineer AOGCC 30f3 5/31/2007 8:26 AM . . SARAH PALIN, GOVERNOR A",A~1iA OILAlVD GAS CONSERVATION COMMISSION 333 W. 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Timothy Brandenburg UNOCAL PO Box 196247 Anchorage, AK 99519 K<-"""::':"If"i#"'Þ""'~ '. . ~. \1"'4" -,', .'--'''''''''''' Re: Swanson River Field, Swailson River Undefined Gas Pool, SRU 2l3-.1J Sunchy Number: 307-082 &0 ~ \ \ ~ §f;t\NNEI) MAR û 9 2007 Dear Mr. Brandenburg: 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. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). 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, DATED this f day of March, 2007 Encl. 1. Type of Request: ~ .. STATE OF ALASKA 1-1.(7~RECEIVED n£. ALAS~IL AND GAS CONSERVATION COMMIA>N. ~ e V'", '1 APPLICATION FOR SUNDRY APPRðf'AL 'kMAR 022007 Çó 1brf' 20 AAC 25 280 .,. .1. n' n.... ~ _ Operational shutdown 0 PerforateL:J ¡" un ~if::h ~:~;). Plug Perforations [21 Stimulate 0 Time Exte~ßÇ¡ eryge Perforate New Pool 0 Re-enter Suspended Well 0 4. Current Well Class: 5. P7rmit to Drill Number: Development 0 ( Exploratory 0 20i-118/Conservation Order #474 Stratigraphic 0 Service 0 6. API Number: Suspend 0 Repair well 0 Pull Tubing 0 v,"".rD Abandon 0 Alter casing 0 Change approved program 0 2. Operator Name: Union Oil Company of California 3. Address: P.O. Box 196247, Anchorage, AK 99519 50-133-20515-00 I 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 0 No 0 SRU 213-10 ( 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): Swanson River Field 16.6' Swanson River Unit / 12. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 4105' 3732' 3558' 3205' 3712' Casing Length Size MD TVD Burst Collapse Structural Conductor Surface Intermediate Production Liner Perforation Depth MD (ft): 3,447' - 3,456 Packers and SSSV Type: N/A 13. Attachments: 92' 1,800' 13-3/8 " 92' 92' 7" 1,800' 1,649' 3-1/2" 4,105' 3,737' 5,020 psi 8,160 psi 2,270 psi 7,020 psi 4,105' 10,160 psi 10,530 psi Perforation Depth TVD (ft): 3,099' - 3,107' Tubing Size: 3-1/2" Tubing Grade: L-80 Packers and SSSV MD (ft): N/A 14. Well Class after proposed work: " Exploratory 0 Development 0 Service 0 16. Well Status after proposed work: Oil 0 Gas 0 Plugged 0 Abandoned 0 WAG 0 GINJ 0 WINJ 0 WDSPL 0 Tubing MD (ft): 4,105' Detailed Operations Program 15. Estimated Date for Description Summary of Proposal 0 BOP Sketch 0 3/15/2007 o Commencing Operations: 17. Verbal Approval: Commission Representative: 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Printed Name Timothy C Brandenburg Title Drilling Manager Signature? ~ C~ P~ ~ Y COMMISSION USE ONLY Date: Contact Steve Tyler - 263-7649 Date Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3 or; .,- 08 ;;¿ Plug Integrity D BOP Test 0 Mechanical Integrity Test 0 Location Clearance 0 Other: Subsequent Form Required: RBDMS 8Fl MAR 1 2 1007 Approved by: APPROVED BY THE COMMISSION Date: ð-' i ~ ~ Form 10-403 Revised 06/2006Ð lO~-1~t ~l ~ R , G \ \~ A L Submit in Duplicate Chevron === . . Trading Bay Unit Well # SRU 213-10 2/13/07 OBJECTIVE: · Isolate Sterling B-3a Sand and recomplete well in the Sterling B4a sand (sand lens#3) to recover 0.080 BCF of probable reserves. PROCEDURE SUMMARY: · Run slickline bailer to determine fluid level, obtain fluid sample and fill depth. · Squeeze well fluid back into formation thru existing perfs with field gas. · Run 5' Owens tubing patch and set at +/- 3515'. This patch will be utilized to set bridge plug in for isolation of Sterling B4a sand when depleted. · Run 15' Owens tubing patch and set from 3444' to 3459' to isolate Sterling Ba3 perfs from 3447' to 3456'. · Perform MIT with field gas. · Run 2" Powerjet, 6 spf, 60 degree phase HC and perf Sterling B4a from 3525' to 3529'. SRU 213-10 REVISED BY: BCA 2/13/07 RKB to TBG Head = 16.5' Elevation 293.5 Feet 2 3 3950' [::J B3a Fill 3558' Toe @ 3648' B6 5 6 TD = 4105' MD, 3732' TVD Directional Well 13-3/8" 69 29 9,2 Weld L-80 L-80 7" Butt IMP Butt 3- II2" Note: 3-1/2" tubing cemented at 41 02'MD, 3729' TVD 11 bbls returns to surface during cement job Cement Bond Log (8/1/02) confinns cement bonding over the entire interval 7" Surface Casing @ 1987' MD, 1802 TVD returns noted to surtàce during cement job Leak off test; mud wgt eq. of 15.9ppg @1802'TVD/198TMD; .827psi/ft gradient w/out breaking reservoir. 2" HSD PowerJet Power Jet hollow carrier Isolated w/two Iu s Updated 12/13/06 by LOPK "Added Fill" RKB to TBG Head = 16.5' Elevation 293.5 Feet 2 3 LJ TD = 4105' MD, 3732' TVD Directional Wen SRU 213-10 r 7" 69 29 9.2 Butt IMP Butt Weld L-80 L-80 3-112" Note: 3-1/2" tubing cemented at 4102'MD, 3729' TVD 11 bbls returns to surface during cement job Cement Bond Log (8/1/02) confirms cement bonding over the entire interval 7" Surface Casing @ 1987' MD, 1802 TVD returns noted to surface during cement job Leak off test; mud wgt eq. of 15.9ppg @1802'TVD/1987'MD; .827psi/ft gradient w/out breaking reservoir. 5. 6. 3873' 3950' & CaC03 2" HSD PowerJet Power Jet hollow carrier Isolated w/two lugs Updated 12/13/06 by LOPK "Added Fill" 2/12/07 BCA e e MICROFILMED 07/25/06 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE F:\LaserFicbe\CvrPgs _ Inserts\Microfilm _ Marker.doc e e ,.-...., I~C) '} r-7'~ (f'/ I 1'6 Subject: Re:Planning for SRFand NNA 2006 MITs From: James Regg<jimJegg@admin.state.ak;us> Date: Wed,,08 F~b 200614:07:29 -0900 ~~:;tú'~=~~~~'~,Tom.M~der <:toIll_ maunder@ådmíìista.te;ak;us> ' " m " ',', Z\~¡\W)(p \2-~q' ,,' This email documents our conversation 2/2/2006 and provides guidance regarding the required mechanical integrity determinations for the wells listed below. NNA #1 In accordance with DIO 28A (Rule 5), we would like to see another temperature survey with wellbore conditions replicating to the extent feasible those of the post-injection start teIIlPsurvey done 12-31-04. Also, the MIT due this year (December 2006}-shoutd"be performëd with the IA pressure dropped to 500 psi below the tubing pressure and monitored for 30 minutes. This test coupled with the imposed pressure for back-up purposes (no apparent communication from no pressure plots I reviewed) will confirm tubing integrity. -}~ CO 474 orders Unocal to demonstrate mechanical integrity annually. This does not specifically require the demonstration to be a conventional pressure test (MIT). One way this requirement can be satisfied is the monitored and reported annuli pressures as required in the Order ("Each annuli pressure must be monitored daily and reported to the Commission quarterly."). In addition, before restarting production in Well 213-10, Unocal will be required to perform a pressure test to demonstrate wellbore integrity. Long Term Shut In Injectors Based on our conversation, there are 6-8 injectors that fall into this category. You have suggested doing a low pressure MIT as a way to confirm integrity while the well is shut in. Commission's current thought is that no MIT is necesssary for a well that would be categorized "long term shut in" (no intent to inject in the well in foreseeable future). In lieu of an MIT, periodically sending a no plot would provide information to determine any developing problems with the well. Regulations at 20 AAC 25.115 require you to address these SI wells annually (due 3/31); the injection orders include provisions for monitoring and notification if leakage or pressure communication is identified. Before restarting injection in any ofthese wells, Unocal will be required to demonstrate mechanical integrity (could include temp survey, MIT, other type of demonstration). PCU #4 Strategy outlined in your message regarding PCU #4 is appropriate. You have satisfied the requirements of our regulations by performing the pre-injection MIT 10/25/2005. A Commission inspector should witness the MIT after restarting storage injection and the well's performance has stabilized; you can coordinate scheduling such a test with me. MIT Due Dates We did not talk about this subject but clarification is appropriate based on recent discussions with other operators and within the Commission regarding scheduling MITs. Mechanical integrity determinations are due on or before the anniversary date. The Commission must approve an extension to go beyond the due date. lof2 2/8/20062:07 PM Ke: Plannmg tor :SKr ana NNA 2UUÓ Mils e e For Admininstrative Approvals (well integrity, alternate demonstration of mechanical integrity), we are using the admin approval date to establish when the next mechanical integrity demonstration is due. Jim Regg AOGCC Greenstein, Larry P wrote: Tom/Jim, When you get a chance, could you call me (263-7661) to talk about a couple of MITs that will be coming up this year. They may be a little out of the ordinary depending how you define the MIT. NNA #1 (PTD #201-215)- calls for an MIT this year (every two years). We are constantly doing an MIT based on the backpressure held in the annulus (see previous letters in file). The backpressure could be altered for an inspector to verify integrity, if so desired. With the 'high set packer' in this well, we need to come to some agreement as to how to perform this MIT. Temp logs with test injection periods were used for the initial MIT on this well. SRF 213-10 (PTD #202-118) - called for an MIT last year (every year). This 3 1/2" monobore gas production well is not in use. We were originally considering converting this well into a gas storage well (with modifications to create a monitorable annulus), but decided against this. The well has remained shut-in and water appears to have entered the well bore (based on a wellhead pressure increase). Nothing is planned for this well in 2006 also. If we were to do something (recomplete uphole??) we would be able to do a pressure test MIT at that time. There is nothing in the budget, so I don't know if leaving this shut-in gas well idled until such time as we decide what to do next is adequate to meet the annual MIT requirements for an 'active gas well'. There is an uphole profile that would allow at least a fairly deep pressure test to be performed while it is in its idled condition. As usual, I would still like some time to discuss low pressure MITs with you as we still have a backlog of 6-8 wells pending your decision. On a shut-in well, I believe the normal 'operating condition' (ie shut-in) would allow a low pressure MIT to have validity. Let's discuss whenever you can. Also, I would like to inform you that we were unable to obtain the follow-up MIT on PCU #4 (PTD #201-193) gas storage well. Just about the time we had achieved a consistent stabilized gas injection (Xmas time after the injection compressor started up), the weather started getting real cold and all injection was stopped in this well. Prior to this time, the well was injecting using only the varying line pressure off the Enstar 20" line and the injection rates were all over the place. The best guess is that we will not start injection back up in PCU #4 until March at the earliest. We do have the successful pre-injection MIT and will plan on doing the follow-up MIT after injection stabilizes upon restarting injection this spring. Hope this is meets with your approval. Thanks for you time. Larry 20f2 2/8/20062:07 PM ú . ) STATE OF ALASKA ) ALASKA OIL AND GAS CONSERVATION COMMIS~ION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon U Performed: Alter Casing 0 Change Approved Program 0 2. Operator Unocal Alaska Name: Repair Well U Pull TubingO Operat. ShutdownO Plug Perforations U Perforate New Pool 0 Perforate 0 4. Current Well Class: Development 0 StratigraphicO StimulateU Other ~ Pool Correction WaiverO Time ExtensionO as of 8/7/2002 Re-enter Suspended WellO 5. Permit to Drill Number: ExploratoryO 202 - 118 ServiceO 6. API Number: 50-133-20515-00-00 9. Well Name and Number: SRU 213-10 10. Field/Pool(s): ~c.T' Swanson River,~ Undf Gas 1 SM. 3. Address: P.O. Box 19-0247 Anchorage, AK. 99519-0247 7. KB Elevation (ft): 17' 8. Property Designation: Swanson River Field/Swanson River Unit 11. Present Well Condition Summary: Total Depth measured 4105 true vertical 3737 feet feet Plugs (measured) none Junk (measured) none Effective Depth measured 4025 true vertical 3656 feet feet Casing Structural Conductor 92' Surface 1800' Intermediate Production 4105' Liner Length Size MD TVD Burst Collapse 92' 5020 psi 2270 psi 1649' 8160 psi 7120 psi 37;37' 10160 psi 10530 psi 13 3/8" 92' 1800' 7" 31/2" 4105' Perforation depth: Measured depth: 3985' - 4000' True Vertical depth: 3621' - 3635' Tubing: (size, grade, and measured depth) 31/2" 9.2# L-80 surface to 4105' MD Packers and SSSV (type and measured depth) none -31/2" monobore 12. Stimulation or cement squeeze summary: Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: SCANNED FEB 0 ? 2005 ( 13. Oil-Bbl Representative Daily Average Production or Injection Data Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 Subsequent to operation: 0 14. Attachments: Copies of Logs and Surveys Run Daily Report of Well Operations 0 0 5666 0 15. Well Class after proposed work: ExploratoryO Development 0 16. Well Status after proposed work: Oil 0 Gas 0 WAG 0 GINJ 0 WINJ 0 WDSPL 0 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: 0 0 0 1300 -Service 0 Contact Larry Greenstein @ 263-7661 pnn::~~::~¡? ~ Form 1 0-404 Revised 04/2004 Title Production Technician Phone 263-7661 Date 2/1/2005 Sfr7 ;2' 'SL£9¡nal Only ~ Ral/)1)~ Greenstein, Larry P From: Sent: To: Subject: McMains, Stephen E -AOGCC Tuesday, January 18, 2005 10:27 AM Larry Greenstein Swanson River Wells Larry, The following wells require paper work to reflect the current pools the well is producing from at this time. The forms need to be back dated to when production started for each well in the current and correct pools. *The following wells have the pool number after the name that requires corrected paper work: * 160-018 50-133-10135-00-00 Swanson River 212-10 772550 162-006 50-133-10137 -00-00 Swanson River 211-15 772550 160-022 50-133-10138-00-00 Swanson River 12-15 772520 162-002 50-133-10162-00-00 Swanson River 21-33WD 772550 202-118 50-133-20515-00-00 Swanson River 213-10 772520 *The only paper work required is a Report of Sundry Well Operations (10-404) for each well with date started production. * Here are the current Field & Pool codes we have in RBDMS and currently use in Swanson River Field: 772036 SWANSON RIVER, UNDEFINED WDSP 772100 SW ANSON RIVER, HEMLOCK OIL 77211 0 SWANSON RIVER, UNDEFINED OIL 772500 SW ANSON RIVER, TYONEK UNDF GAS 772520 SW ANSON RIVER, BELUGA UNDF GAS 772550 SWANSON RIVER, STERLING UNDF GAS 772555 SWANSON RIVER, GAS STORAGE If you have any question please call me, thanks Steve 1 ) Lf~~ DATA SUBMITTAL COMPLIANCE REPORT 9/7/2004 Permit to Drill 2021180 Well Name/No. SWANSON RIV UNIT 213-10 Operator UNION OIL CO OF CALIFORNIA Sfl"'- ¿ l Y Jut) Á.A~..L API No. 50-133-20515-00-00 MD 4105----- TVD 3737 ~ Completion Date 8/4/2002 ~ Completion Status 1-GAS Current Status 1-GAS UIC N ~---_._------------ ----~_.---.- REQUIRED INFORMATION Mud Log No Samples No Directional Survey No ----~~_.-----------_.- ---- - ----- --~--_._----~------------~-- - DATA INFORMATION Types Electric or Other Logs Run: SimPulse-Gamma Ray, Array, Induction/Density/CNUGRlSP/Caliper, Well Log Information: (data taken from Logs Portion of Master Well Data Maint) .-.... Log/ Electr Data Digital Dataset Log Log Run Interval OH/ Type Med/Frmt Number Name Scale Media No Start Stop CH Received Comments ~ ---_._---~---~ - C l...--t1138 Cement Evaluation 1 0 4014 Open 10/3/2002 GR Casing Collar Locator ~ C ~39 Induction/Resistivity 1 1987 4105 Open 10/3/2002 Platform Express (/-og .....cement Evaluation 5 Col L--° 4014 Open 1 0/3/2002 ~ Casing collar locator 5 Col ~ 4014 Open 10/3/2002 ~< --- Open Platform Express ".J.nduction/Resistívity 5 Col 1987 4105 10/3/2002 L~ .Density 5 Col -4987 4105 Open 10/3/2002 Platform Express ,j,.o~r Gamma Ray 5 Col ~ 4014 Open 1 0/3/2002 j.s:)g"----- Neutron 5 Col ð9ß7 4105 Open 10/3/2002 Platform Express ~ ",Gamma Ray 5 Co I 4987 4105 Open 1 0/3/2002 Platform Express '~ ..sP 5 Col ..:rg87 4105 Open 10/3/2002 Platform Express -I:;6g -éaliper log 5 Col ..1-987 4105 Open 10/3/2002 Platform Express 'èg Gamma Ray MD 25 Blu 1952 4105 Open 1 0/3/2002 beg' Gamma Ray Till) 25 Blu 1952 4105 Open 10/3/2002 cY6g GOmpletion 5 Blu 3800 4000 Open 10/3/2002 2" HSD Power Jet 6 SPF ~ ..-Mêutron 5 Blu 4981 4105 Case 10/3/2002 In Casing, Platform Express œ6 C Pds {/I'"'2447 Completion 3090 3614 Case 2/27/2004 Completion Record, 2" HSD 6 SPF Powerjet, 60 u~~fi/ Degree Phased Completion 'BM 3090 3614 Case 2/27/2004 Completion Record, 2" HSD 6 SPF Powerjet, 60 Degree Phased - BLUELlNE CULLED JÓ C lis (/(2447 Completion 3090 3614 Case 2/27/2004 Completion Record, 2" HSD 6 SPF Powerjet, 60 Degree Phased ------~._-~~.-._.._-_.- -- DATA SUBMITTAL COMPLIANCE REPORT 9/7/2004 Permit to Drill 2021180 Well Name/No. SWANSON RIV UNIT 213-10 Operator UNION OIL CO OF CALIFORNIA API No. 50-133-20515-00-00 MD 4105 TVD 3737 Completion Date 8/4/2002 Completion Status 1-GAS Current Status 1-GAS UIC N Well Cores/Samples Information: Name Interval Start Stop Sent Received Sample Set Number Comments ADDITIONAL INFORMATION y~ Daily History Received? {J)I N O/N -"', Well Cored? Chips Received? ~ Formation Tops Analysis Received? .~ --~------_._--~------------- ---------------------~- Comments: Compliance Reviewed By: ~ o!~ Date: " ,r~ -;¡=J-P,~ð--c7~~~:~.=~==::_-.-:: (2 -1 ,~>t..._---____-t-d- Unocal Alaska 909 W 91h Ave Anchorage, AK 99501 Tele: (907) 263-7889 Fax: (907) 263-7828 Email: oudeand@unocal.com UNOCALe """=-Alaska Debra A Oudean G & G Technician February 26, 2004 DATA TRANSMITTAL To: Lisa Weepie 333 W 7th Ave, Suite 100 AnchoraÇJe, AK 99501-3539 AOGCC From: Debra Oudean 909 W. 9th Avenue Anchorage, AK 99519-6247 Unocal Alaska Transmitting as follows: ,:,.:);,;,:,,¡~t!.lr!;':;t'?~'{' ~:h~'~..r+~,::~".,+.V;~~{;.; '/v;h r ~-":~?:~ :',1,:" ,'<¡'f:, ,(f',; 'ò, ":: .~.";,::,~.,::<";:W:' '. :...,:,::.. : ,c': LOG:' '., .:., INTERVALi1't:;:~'''.f'';~.''~::iP;t:'!:;:.¡:,;''';': j(~'H,,' <:: : WELL: ":: " .,:." .:, ,<",. - . LOG rYPE : .: : .:-. ... - . "- ',. :', SCALE: . DATE- LOGGED''-' B-LlNE FILM -CD' ) (øJ - C) I c¡ ~SCÜi32~-4' ICOMP-LET-IO-N-RE¿OÃ-D'-SA-F-Ê-1-~56-H-SD-PJ'-------------:ls-iN-CH-----T -1--1-;13/200311Ö17S=1-04S-6--------------1r---1' -------11 Jd LILI ~ _)6RUI2-15 lPERFRECORD111/16POWERSPIRALS7.5SPF l~_.!!~-~J_~-~!~!~00~15016-5018.5 I 11 01 ~JaL/J../~ } ('c{')"-[\'~U 12-15 ~~~PLETION RECORD 111/16 POWER SPIRALS 7.5 5 INCH 10/1/2003 5380-5141 1 1 1 J:Jl--J L)e¡ _.),sRU 213-10 COMPLETION RECORD 2 HSD 6 SPF POWERJET 60 51NGH 8/23/2003 3090-3614 1 111 }!fJUL - ~ '))'61 DEGREE PHASED 1- (/-, I.. læ- ði' SRU 242-16 ICOMPLETION REGORD 2.5 HSD 6 SPF PJ ¡5INGH I 8/23/2003[3590-4211 I 11 11 1 J!)Jj1j I J <9 j-~ 0 ) i SRU 32A-33 ICOMPLETION REGORD 1.56 HSD PJ 6SPF ¡SINGH 111/12/200319360-10815 ¡ 11 1 1 rt)LjLl!. /(R:3-a:;-:¡..1SRU34-28 RESERVOIR SATURATION TOOL_SIGMA MODE 151NGH I 1/10/200414300-7300 11 11~J()J-ILJJ. 19i(O~lSRU41A-8 GAMMARAYGCL 1.56 POWER JETS 1606HMX 5INGH I 2/12/200419740-10590 I 1 1f 11/:JJj'Jé. RECEIVED ,'./1"-. , . I., ,I ¡ Ir"'T. l-\ FIJ1 I'~ ,~ Pi '2 0 f11 f1 '~':"~.fif'~f:t~'<¡jf.;t..;' iç, ,th 1 ü - !l/~ FED 2 7 2004 {-\tasks Oil & Gas Cons. Commission þ;ljOOOrage Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to (907) 263-7828. I Received~eJl~\. y~(\ e,,,':"~fV,-- I Date: ~~. r\." ~ \~ ~~'\,\~ Ì'-. '^' (:¡./t" I '-I ,,¡tOo ~ D'TS 12111/3 /d/ It-{ 1/ II STATE OF ALASKA " ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVAL 20 ACC 25.280 Ops Shutdown D Perforate D Plug Perforations D Stimulate D Perforate New Pool D 4. Current Well Class Variance D Annular Disposal D Time Extension D Other 0 Re-enter Suspended Well D 5. Permj!Jo Drill Number: 202-118/Conservation Order No. 474 Development 0 Exploratory D 6. API Number:,~/ Statigraphic D Service D 50-133-20515-00 9. Well Name/Number: SRU 213-10 ./ 1. Type of request Abandon D Suspend D Alter Casing D Repair Well D Change Approved Program D Pull Tubing D 2. Operator Name: Union Oil Company of California/Unocal 3. Address: PO Box 19-0247, Anchorage, AK 99519 7. KB Elevation (ft): 16.6' RKB 8. Property Designation: Swanson River Field 11 Total Depth MD (ft): 4,105' Casing Structural TVD (ft): 3,737' Length 10. Field/Pool(s): Swanson River Unit PRESENT WELL CONDITION SUMMARY Eft Dep MD(ft): Eft Depth TVD (ft): 3,873' 3,510' Size MD TVD Conductor Surface 92' 1,800' 92 1,649' 13-3/8" 92' 1,800' 7" Intermediate Production 4105' 3,737' 4,105' 3-1/2" Liner Plugs (measured): 4,025' Burst Collapse 5,020 psi 8,160 psi 2,270 psi 7,020 psi 10,160 psi 10,530 psi Perf Depth MD (ft): 3,985-4,000' Packers and SSSV Type: Perf Depth TVD (ft): 3,621-3,635' Tubing Size: 3-1/2" Tubing Grade: L-80 Packers and SSSV MD (ft): Tubing MD(ft): 4,150' ~ ~ 12. Attachments: Detailed Operations Summary 13. Well Class after proposed work: Description Summary of Proposal 0 BOP Sketch D Exploratory D Development D 14. Estimated date for commencing operations: 15. Well Status after proposed work: 12/20/2003 / Oil D Gas D 16. Verbal Approval: Date: WAGD GINJD Comission Representative: 17. I hearby certify that the foregoing is true to the best of my knowledge. BY ORDER OF THE .-; COMISSION Date ORiGiNAL Printed Name: Philip Krueqer Title: S¡9nature:y/4. """Jt Phone: FOR COMMISSION USE ONLY Conditions of approval: Notify Commission so representative may witness Sundry Number: Plug integrity- BOP Test- Mechanical Integrity Test- Other: Subsequent form required 10- 404- Onginal $ígned By Salah Palin Commissioner Approved by: Submit in duplicate Service 0 Plugged D Abandoned D WINJ D WDSLP D Gas Storage Well 0 Contact: Steve Tyler (263-7649) Drilling Manager 263-7628 Date: 12/10/03 303 -.3~f?' Loc~Ë~ËIVt::D DEC 11 2003 Alaska Oil & Gas Cons. Commission Anchorage /r2/¡//03-- Form 10-403 Revised 2/2003 UNOCAL8 -r (: rJ rr t,,v RKB to TBG Head = 16.5' Elevation 293.5 Feet L ~ Size 13-3/8" 7" 3-1/2" Swanson L...:r Unit SRU # 213-10 Drilling Program Final Schematic 08/23/03 API #: 50-133-205-15-00 Wt 69 29 9.2 CASING AND TUBING DETAIL Grade Conn Top Weld Surf 92' L-80 Butt Surf L-80 IMP Butt Surf 1800' TVD 4105' TVD Bottom I Note: 3-1/2" tubing cemented to surface - L ~ 2 I 7" Surface Casing @ 1987' MD, 1802 TVD I NO. Depth 3 1. Surf 2. 1750' 3. 2688' 4. 3712' B3b /' 5. 3873' - - 6. 3950' Toe @3648' OIL 4 JEWELRY DETAIL Item 3-1/2" Tbg hgr w/Carneron "H" BPV profile 3-1/2" Chern Inj Sub w/lOOO psi chern valve Baker X Nipple with 2.813" profile "A" Stop @ 3714', Daniels Pack-off & "G" Stop @ 3712' Baker X Nipple with 2.813" profile wi Plug & CaC03 BOT QuickDrill (Partial Set) == B6 Zone Top B3B 3447 B-6 3750 Stray 3985' CURRENT PERFORATION DATA Btm Zone Spf Comments 3456 Sterling 6 2" HSD PowerJet 3760 Sterling 6 Power Jet hollow carrier 4000' Beluga 6 Isolated w/two plugs - 3950' ~ 6 5 -- A LJ \. TD = 4105' MD, 3737' TVD Directional Well SRU 213-10 Operation Plan Isolate B3A sand, Test BO sand, isolate BO / Then convert to a Gas Storage in B3b sand . RU Slickline RIH wI GR tag Fill. Rlli wI "G" Stop. Set @ ~3250'. RIH set pack- off on "G" stop. Dump bail 1 0' CaC03 & 10' of GP sand. Jug test well. RD / Slickline. . RU Eline. RIH wI 6' x 2" HSD PJ, 6 spf. Shoot B-O sand. . Suspend operations to test B-O sand. ./ . RU slickline. Bail down to pack-off @ 3250'. Retrieve same. RIH retreve "G" stop. RI wI GR tag fill. RD Slickline. . RU Eline. RIH wI Owen Tbg Patch. Set patch to straddle BO sand. POOH. RD /' Eline. /{~,..., ~."......~ _;.'.i~~ :-"..' .'L",..,:::1i n UNOCAL RKB to TBG Head = 16.5' Elevation 293.5 Feet L. L '-RqIRRlijU¥lffl~ ~~~ 3950' LI ~2 3 - BO // A - B3b Toe @ 3648' DIL 4 - B6 5 6 ===A TD = 4105' MD, 3737' TVD \. Directional Well Swanson ~ er Unit SRU # 213-10 Drilling Program PROPOSED Schematic API #: 50-133-205-15-00 Producing/Testing BO Sand ~ Size 13-3/8" CASING AND TUBING DETAIL Grade Conn Top Weld Surf 92' L-80 Butt Surf L-80 IMP Butt Surf 1800' TVD 4105' TVD Wt 69 29 9.2 Bottom 7" 3-112" I Note: 3-1/2" tubing cemented to surface I 7" Surface Casing @ 1987' MD, 1802 TVD I NO. 1. 2. 3. 4. JEWELRY DETAIL Item 3-112" Tbg hgr w/Carneron "H" BPV profile 3-112" Chern Inj Sub wl1000 psi chern valve Baker X Nipple with 2.813" profile "A" Stop @ 3714', Daniels Pack-off & "G" Stop @ 3712' Baker X Nipple with 2.813" profile wI Plùg & CaC03 BOT QuickDrill (Partial Set) PROPOSED JEWELRY I "G" Stop wi pack-on', 10' of CaC03 & 10' of sand pepth Surf 1750' 2688' 3712' 5. 6. 3873' 3950' .,; A I ~3250' Zone B-O B3B B-6 Stray CURRENT PERFORATION DATA Btm Zone Spf ,Comments 3206 Sterling 6 2" HSD PowerJet J!RO'POSED 3456 Sterling 6 2" HSD PowerJet 3760 Sterling 6 Power Jet hollow carrier 4000' Beluga 6 Isolated w/two plugs Top 3202 3447 3750 3985' ~,' , UNOCAL RKB to TBG Head = 16.5' Elevation 293.5 Feet L L - ~2 3 t j - BO / A i ò.I'" Î - B3b Toe @3648' DIL 4 - - B6 5 3950' 6 ==A LI \. TD = 4105' MD, 3737' TVD Directional Well Swanson er Unit SRU # 213-10 Drilling Program PROPOSED Schematic API #: 50-133-205-15-00 B3b Open for Storage ~ Size 13-3/8" CASING AND TUBING DETAIL Grade Conn Top Weld Surf 92' L-80 Butt Surf L-80 IMP Butt Surf 1800' TVD 4105' TVD Wt 69 29 9.2 Bottom 7" 3-112" I Note: 3-1/2" tubing cemented to surface I 7" Surface Casing @ 1987' MD, 1802 TVD I NO. 7. 8. 9. 10. JEWELRY DETAIL Item 3-112" Tbg hgr w/Carneron "H" BPV profile 3-112" Chern Inj Sub wll000 psi chern valve Baker X Nipple with 2.813" profile "A" Stop @ 3714', Daniels Pack-off & "G" Stop @ 3712' Baker X Nipple with 2.813" profile wI Plug & CaC03 BOT QuickDrill (Partial Set) p.epth Surf 1750' 2688' 3712' 11. 12. 3873' 3950' PROPOSED JEWELRY / A. I 3195' - 3210' I Owen Tbgl>atch Zone B-O B3B B-6 Stray CURRENT PERFORATION DATA Btm Zone Spf COIn~~nt~ 3206 Sterling 6 2" HSD PowerJet .PROPOSED 3456 Sterling 6 2" HSD PowerJet 3760 Sterling 6 Power Jet hollow carrier 4000' Beluga 6 Isolated w/two plugs Top 3202 3447 3750 3985' ( STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Type of request Abandon X Suspend 0 Operation Shutdown 0 Alter Casing 0 Repair Well 0 Plug Perforations 0 Change Approved Program 0 Pull Tubing 0 Perforate New Pool 0 2. Operator Name: 4. Current Well Class Union Oil Company of CalifornialUnocal 3. Address: Perforate X Variance 0 Annular Disposal 0 Stimulate 0 Time Extension 0 Re-enter Suspended Well 0 5. Permit to Drill Number: Other 0 202-118/Conservation Order No. 474 Development X Exploratory 0 6. API Number: Statigraphic 0 Service 0 50-133-20515-00 9. Well Name and Number PO Box 19-0247, Anchorage, AK 99519 7. KB Elevation (ft): 16.6' RKB 8. Property Designation: Swanson River Field 11. Present well condition summary Total depth: measured 4,105' Feet true vertical 3,737' Feet Effective depth: measured 3,873' Feet true vertical 3,510 Feet Casing Length Size MD Structural Conductor 92' 13-3/8" 92' Surface 1,800' 7" 1,800' I ntermed iate Production 4,105' 3-1/2" 4105' Liner Perforation depth: measured 3,985-4,000' true vertical 3,621-3,635' Tubing (size, grade, and measured depth) Packers and SSSV (type and measured depth) 3-1/2", L-80 @ 4,150' n/a 12. Stimulation or cement squeeze summary Intervals treated (measured) n/a Treatment description including volumes used and final pressure SRU-213-1 0 10. Field/Pool(s): Swanson River Unit Plugs (measured) 4,025' Junk (measured) n/a TVD Burst Collapse 92 5,020 psi 2,270 psi 1,649' 8,160 psi 7,020 psi 3,737' 10,160 psi 10,530 psi RE.CElVE f~4 i. 0"\ & GaS Cons. Lûrnmission A\aSt\8 II Anchorage 13 Representative Dailv Averaqe Production or Injection Data Oil-BBL Gas-Mcf Water-Bbl Prior to well operation Subsequent to operation 14. Attachments Daily Report of Well Operations: X 0 0 1028 2363 1800 0 Casing Pressure 0 0 Tubing Pressure 528 970 15. Well Class after proposed work: 0 Exploratory X Development 0 Service 16. Well Status after proposed work: Oil 0 WAG 0 17. I hearby certify that the foregoing is true to the best of my knowledge. Contact: Printed Name: Steve Tyler s¡gnature:/ ;/ ~ /' GINJ 0 Gas X WDSLP 0 WINJO Sundry Number: Title: Workover Foreman/Engineering Technician Phone: (907) 263-7649 1ðk3/ó3 Date: 9/4ef6'3 OCl 2" 1003\ Form 1 0-404 Revised 2/2003 IGINAL l UNOCAL~ RKB to TBG Head = 16.5' Elevation 293.5 Feet L -- L ~ 2 3 == B3b - Toe@3648' 4 - == B6 - 3950' ~ 6 5 -- A LI \. TD = 4105' MD, 3737' TVD Directional Well ( ~ Size 13-3/8" 7" 3-1/2" Swanson { ~r Unit SRU # 213-10 Drilling Program Final Schematic 08/23/03 API #: 50-133-205-15-00 Wt 69 29 9.2 CASING AND TUBING DETAIL Grade Conn Top Weld Surf 92' L-80 Butt Surf L-80 IMP Butt Surf 1800' TVD 4105' TVD Bottom Note: 3-1/2" tubing cemented to surface 7" Surface Casing @ 1987' MD, 1802 TVD NO. 1. 2. 3. 4. Depth Surf 1750' 2688' 3712' 5. 6. 3873' 3950' JEWELRY DETAIL Item 3-1/2" Tbg hgr w/Carneron "H" BPV profile 3-1/2" Chern Inj Sub wll000 psi chern valve Baker X Nipple with 2.813" profile "A" Stop @ 3714', Daniels Pack-off & "G" Stop @ 3712' Baker X Nipple with 2.813" profile wi Plug & CaC03 BOT QuickDrill (Partial Set) Zone Top B3B 3447 B-6 3750 Stray 3985' CURRENT PERFORATION DATA Btm Zone Spf Comments 3456 Sterling 6 2" HSD PowerJet 3760 Sterling 6 Power Jet hollow carrier 4000' Beluga 6 Isolated w/two plugs 8/22/2003 From To 0:00 '.--18:áÕ-Production finished preping well for perf job 18.:30 20:30 _~ob~ in E-line unit & spot equipment go over job wi SWS engineer 20:30 2~:30 PJSM_& R/up & test lubricator 250/2500 psi (ok) 22:30 0:00 Shut dn for crew rest (bed dn SWS crew @ lease house) -¡--r --l~-=.~_~-=-=~=.--- 8/23/2003 -------~-------~~ From To ------_._~.--~-----~--~-- 0:00 5:30 Shut dn for crew rest ~-- 5:30 6:30 __~tter:t9§imops wI production @ plant & discuss day plan wI both perf jobs & coil rlup 6:30 7:15 ___.Jra'(el to location PJSM - chk & warm equipment & perf safety & chk list - Production bleed well f/1300 psi t/1000 psi for under balance 7:35 Plup & arm 10' gun 2" HSD Power Jet hollow carrier wI 9' loaded @ 6spf & 60 deg phasing ~~9:'10--._RiD~& tag_PBTD @ 3647.8' & pull tie in pass t/3290' Rih & place gun on depth & perf B-3a sand interval f/344T t/3456' @ 0847 hrs tbg 9:10 9:50 _.ç_~~gun all shots fired & rldn & move t/ SRU 242-16 Turn well over to Production to flow - Initial rate SI1107 Psi & flowing @ 3.4 mmcfd @ 1046 psi _.~------ ,~ page 1 UN°f \L ALASKA RESOURf-=:S WELL SERVICE REPOR I' Date: Work being done: Supervisor: Wireline Unit Number: Tree Valve Condition Fluid level if Identified Zero Wireline at: Minimum Tubing ID: Start Tbg. & Csg. PSI Time 06:45 07:00 07:30 08:00 08:30 09:30 10:15 11 :15 11:45 12:50 13:30 14:15 14:45 16:15 17:15 18:00 18:30 19:00 19:30 20:20 22:00 Tool Cost: 8/18/2003 Plug & Cement Glynn Brown Top Kick Good Tubing Hanger 2.813 1220 Well Number location: AFE# I Charge Code: Pollard Wireline Crew: Total Wireline Miles: Max Depth (KB): Well KB: Max Tool aD: Ending Tbg & Csg PSI SRU 213-10 Swanson River AFE # 160873 Whitaker/Smith 37141 16.51 2.75" 1360 Work String Detail: RS, KJ, 10' Stem, KJ, OJ, SJ 3" GS $125.00 Operation Details Arrive @ Swanson River Field Discuss wi Foreman, hold safety meeting, sign in Check equipment @ Pad R/U, P.T., test - good RIH wi 3" SB to 3710' KB, pull A-Stop, reset @ 37141 KB, POOH RIH wi 2.35 Blind Box to 3714' KB, tag A-Stop, POOH Redress 3 1/2" Daniels Packoff-Plug Assembly RIH wi 3" GS & 3 1/2" Daniels Plug Assembly to 3714' KB, set Plug, POOH Positive test good RIH wi 3" GS & 3" G-Stop to 3712' KB, set Stop, POOH Negative test good Pumped 2 bbls of water down Tubing, repressured Tubing to 1400 PSI RIH wi 15' x 2.25" DD Bailer to 3710' KB, dumped cement, POOH RIH wi same to 3705' KB, dumped cement, POOH RIH wi same to 3700' KB, dumped cement, POOH RIH wi same to 3690' KB, dumped cement, POOH RIH wi same to 3690' KB, dumped cement, POOH RIH wi same to 3685' KB, dumped cement, POOH RIH wi same to 3680' KB, dumped cement, POOH RID, clean up, move equipment to 242-16 Depart Swanson River 3" SB $150.00 Description of any None tools or debris left in the hole: Brief Summary of Plug & cement Total Work Completed trotal Hours Worked 16 Ticket # : P-10115 Daily Cost: $ 2,705.00 Well Downtime Hr. Shut in NIA Approved by: 2.25" DD Bailer $100.00 Total Tool Cost $ 375.00 Total Hour Cost $ 2,330.00 Day # : 2 Cumulative Cost: $ 4,080.00 Wire Test 19, 19 Code: AFE # 160873 H2S PPM NIA ~(1A- 5"' Z-o / z-003 t;PJ CJ5/Zb/t2S Æ:Y ~ j ¿~/ò~ STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVAL 20 ACC 25.280 1. Type of request Suspend 0 Repair Well 0 Pull Tubing 0 Operation Shutdown 0 Plug Perforations 0 Perforate New Pool 0 4. Current Well Class Abandon X Alter Casing 0 Change Approved Program 0 2. Operator Name: Union Oil Company of California (UNOCAL) 3. Address: PO Box 196247, Anchorage, AK 99519 7. KB Elevation (ft): 16.6' RKB Perforate X Variance 0 Annular Disposal 0 Stimulate 0 Time Extension 0 Other 0 Re-enter Suspended Well 0 5. Permit to Drill Number: 202-118/Conservation Order No. 474 Exploratory 0 6. API Number: Service 0 Development X Statigraphic 0 50-133-20515-00 9. Well Name and Number SRU-213-1 oZ-c?"l,... - , l .f 10. Field/Pool(s): Swanson River Unit 8. Property Designation: Swanson River Field 11. Total Depth MD (ft): 4,105' Casing Structural Conductor PRESENT WELL CONDITION SUMMARY Total Depth TVD (ft): Effective Depth MD (ft): Eff Depth TVD (ft): 3,737' 3,873' 3,510 S~ MD TVD Length 92' 13-3/8" 92' 92 1,800' 7" 1,800' 1,649' 4,105' 3-1/2" 4105' 3,737' Surface Intermediate Production Plugs (measured): 4,025' Burst 5,020 psi 8,160 psi 10,160 psi Liner Perf Depth MD (ft): Perf Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD(ft): 3,985-4,000' 3,621-3,635' 3-1/2" L-80 4,105' Packers and SSSV Type: Packers and SSSV MD (ft): n/a /'ì n/a 12. Attachments: Detailed Operations Summ{ry X/ 13. Well Class after proposed work: Description Summary of Proposal 0 BO~etch 0 Exploratory 0 Development X 14. Estimated date for commencing operations: 15. Well Status after proposed work: 16. Verbal Approval: Date: Oil 0 Comission Representative: WAG 0 17. I hearby certify that the foregoing is true to the best of my knowledge. Printed Name: Steve Tyler GasX GINJ 0 Plugged D WINJD Contact: ålJG.t- Junk (measured): n/a Collapse 2,270 psi 7,020 psi 10,530 psi Service D Abandoned X WDSLP D Title: Workover Foreman/Engineering Technician 30'3.. /52- RE~)J[:~ MAY 2 0 2003 A\aska on & Gas Cons. Commission Anchorage ~) 2-ß( OJ Submit in duplicate Signature: //~ Phone: (907) 263-7649 FOR COMMISSION USE ONLY Conditions of approval: Notify Commission so representative may witness Sundry Number: Plug integrity- BOP Test- Mechanical Integrity Test- Other: Subsequent form required 10- tf 0 '1 Approved by: ~ ~ommissioner Form 10-403 Revised 2/2003 BY ORDER OF THE COMISSION tnI~!R\f)J¡¡1«~ I R-\!rj)fuJI f; ~,\9' ORIGINAL MAY 2? !n~1 Date Date: 5/21/03 (' Summary of Proposed Operations Unocal Alaska, SRU 213-10 5/19/03 I' 1. Plug off Sterling 8-6 Sand (3,750-3,760') /' 2. Set slickline run packoff in 3-1/2" casing with 30' of cement on top 3. Perforate Sterling 8-3A sand /' UNOCAL RKB to TBG Head = 16.5' Elevation 293.5 Feet L L ~'""~ 3950' LI TD = 4105' MD, 3737' TVD Directional Well ~ 2 3 - B6 4 5 -- A \. ( AFE # 159499 ~ Size 13-3/8" 7" 3-112" ( Swanson River Unit SRU # 213-10 Drilling Program Final Schematic 02/26/03 API #: 50-133-205-15-00 Wt 69 29 9.2 CASING AND TUBING DETAIL Grade Conn Top Weld Surf 92' L-80 Butt Surf L-80 IMP Butt Surf 1800' TVD 4105' TVD Hottom Note: 3-1/2" tubing cemented to surface 7" Surface Casing @ 1987' MD, 1802 TVD NO. 1. 2. 3. 4. 5. Zone Top B3B 3447 B-6 3750 Stray 3985' Depth Surf 1750' 2688' 3873 ' 3950' JEWELRY DETAIL Item 3-112" Tbg hgr w/Carneron "H" BPV profile 3-112" Chern Inj Sub wl1000 psi chern valve Baker X Nipple with 2.813" profile Baker X Nipple with 2.813" profile wI Plug & CaC03 BOT QuickDrill (Partial Set) CURRENT PERFORATION DATA Htm Zone Spf Comments 3456 Sterling Proposed 3760 Sterling 6 Power Jet hollow carrier 4000' Beluga 6 Isolated w/two plugs ~t1'~~'rJ§ '~pÞ w ;::; ---- ..,~¡-}diii¿/;;fi~2K.~'c" . ."'..,-,,..,~...~"....;~~~;-¿.~'.:'"..'<'.".~~'...." ~;fØ~'~fJr~~?xv I . "';¥.1~~';;¿i;:;L" - .. . .,.. ... -- . .. ~- ..... .-. .,.,.' "-.' " -." - '/f ."- Âf1ct~~wt l STATE OF ALASKA ALASKA 01 LAN 0 GAS CONSERVATION COM MISSION GAS WELL OPEN FLOW POTENTIAL TEST REPORT 1 a. TEST: INITIAL ~ 1b. TYPE TEST ANNUAL 0 MULTIPOINT ~ SPECIAL 0 OTHER STABILIZED 0 NON STABI LlZED 0 CONSTANT TIME 0 ISOCHRONAL ~ 2. Name of Operator 7, Permit No, UN\6tJ () lL. ú)MPft-"Ñ'f of c.JfL \Fo fZ. rJ lA (vtt0 Oc.AL-) 2.02- - l' 8 3, Address 8. API Number f'~o" ßO~ \'1Io'2..4r A-~C\-tORA-<.;e A-K- '1'15 19 50-';~~ -201;\&;-DO 4. ~csion(l'f Well I -;~ i Fw L- 5&.. to 'IS N 1l.4W S V\. 9. Unit or Lease Name It ~ f..uë: 'J~ J~~ ;g'OS..OH3¡\ W '50 Sot S2,. Š358,f 5"v4-r.)Ç"o10 R\vtil. UN tT " 10. Well Number AT T'")P PfO~UvíN.4 \t\ll'Et\lJtt;. N "0 '+::f-(5D. ttCfil W 150 50154,£tLf '"2- \~.- \ 0 , 'I 11. Field and Pool f\-TTÐTA-L t)t~'(t NbD 4-1-' S040~48t vJ 150 t;o'5Lf.~(4- -?wtt"-'Sol0 ~l"e~ RELÞ 5. Elevation in feet (indicate KB, DF etc.) \ 6. Lease Designation and Serial No. ¿or"C.''>L1 . ,~/~ 11:':>0:=-D ß<-J" J ~. L. \f<ì' ItEUtT\vt ,0 \~SL c:ïL ,R¡¿g':::31 A-o').~4-05 7)~F- .....,L1 V\ f_f.. .t:\4M~\" 12. Comple\ion Date 13. Total Depth c I 14~ Plugback T.D. ::f- (2.\.t \ 0'2- M C> -:.: 4 ( 0 "'I ~ Þ :::- 'tc2S; IV D -:::. ~ T ~ 1- IV ) ::: 31- C" /...f 16. Csg. Size Weight per foot, lb. I.D. in inches Set~tft. ~n '2-4 Coø '~4- ft~t~TVt 17, Tbg. Size f Weight per foot, lb. I.D, in inches Set a~\.f...Ù ~. 5 \ 9, J... '2~ q92 ~~31f1VJ> 18. Packer set at ft, 19, GOR cf/bbl. 20. API Liquid Hydrocarbons 21. Specific Gravity Flowing fluid (G) o"5~ 15. Type Completion (Describe) 3..5;' M()'~O 6DRE 6cA-S w';LL Perforations: From To 3'18Si 4°ocÎ 14þ 22, Producing thru: Tbg. ~ Csg. 0 23, Length of flo'^( channel (U if (0 S i'-^ \) 24. Reservoir Temp, 0 F. Mean Annual Temp, 0 F, Barometric Pressure (Pa), psia Prover Line X No. Size (in.) 1 . 2 II \ 1.5 2. 3. 4, 5. Vertical Depth (H) I 3 B:{-'TU,b I Flow Data Choke Pressure Orifice Size (in.) )( 1. o¡ I bLf- 3bl(b~ 4~b'f 50[t ¿If ;0 bt Ga, I % CO::> ! O.5b I 0 I N2 % HiS Prover 0 Tubing Data 0 Meter run Taps DA-t..nELS; p, PE Casing Data psig Diff. hw Temp. Pressure Temp, '0 F. psig 0 F. 6if ~ I, 40 t~ 6~ l5 tt..o13 211.. ~D I.o~ I '3t::. 2~:f- co bt I S5 2;'1. 2.0 î Pressure psig Temp. 0 F. Duration of Flow Hr. '-I '" b {,o"fQ , ö:ti;; [0 l\ \ ()°1" s¡¡ go 4<,)6'0 ~)' lD 5o;~ 15040 0 0 0 D D l.. l... 1- 'L.. fo Basic Coefficient Pressu re Flow Temp. Gravity Super Camp. Rate of Flow (24-Hour) ~ hwPm Factor Factor Factor Fb or Fp Pm Ft Fg Fpv Q, Mcfd No. 1 , 1..0 ~ I,) L+~ \~"b4- ' l. 4-0 \. CO 4- t',3b l" 0 1-{, £#"00 2, ~~i 4-2 ')...b. ~ 2. l5 4-. oh l. DoLt I,; 3 b \ I o""f3 ~fÐDO 3. ).0,; '-Fl. '32-- 44 1-\1. . to \ .. 0'05 \. ~~ í, t I 01-1 c¡,CCt>D 4. 'l...Q~¡; '+1- 'bs It bf 23~ro\) \ "coS i , ~~ ~ 1'0'1-'2. to}:roe> 5, )...0 ~ (I 42. ;? ~ q4 '2.; .Î() "~lf l, ;3b II Ob'J \0, ~ Ð 0 Temperature I for Separator for Flowing Pr T Tr Z Gas Fluid No, Oft. Gg G~ 1. \. b~ 521 l4S~ D. ~Ì>4- 2, l,l:,t ~2... \ ~SB 0,' b~ O~?b 3, l~ sS r;')...~ \~ '5; O. ~;¡- ~ Critical Pressure 6>~ 4. l a 5-2- S 2..::r 1 <8 6 (). ~ Critical Temperature ";4-' 5, t, S.:t S 2. '" i,5S \9'~ Form 10-421 CONTINUED ON REVERSE SIDE Submit in duplicate Rev. 7-1-80 Pc \, I ';rg PC2 ~f ,1Sl., b S'f Pf t2ò5 Pf2 1.~;)(lO,(,. No. Pt Pt2 PC2 - Pt2 Pw PW2 Pc2 - Pw2 Ps PS2 Pf2 - PS2 1. u;' O-~4(bl ,08S23 2. lOg5 "~'f2.'2-7 2..104'51 3. fO~O \0 'boO ?O6°~1 4. t D 1-b lÐ?2b"f1ø ;? SOD 5. to J...2. If)~ '+Xq. ~tt3'loo 25. ~~C'(SV OoJ 5 t AOF (Mcfd) I n Remarks: I hereby certify that the fo gOin~ uyc::;ect to the best of my knowledge >. .. Signed . ~ Title felwk('HV/ ~ Date I/I-S/OS ~ (If, ~ ~777.+-M-f2..Kw t4ff I f.o ~ 6;ot í ~Þv' AOF Fb Fp Fg Fpv Ft G Gg GOR hw H L n Pa Pc Pf Pm Pr Ps Pt Pw Q Tr T Z Form 10-421 DEFINITIONS OF SYMBOLS Absolute Open F low Potential. Rate of F low that wou Id be obtained if the bottom hole pressure opposite the producing face were reduced to zero psia. Basic orifice factor Mcfd/ \)hWpm Basic critical flow prover or positive choke factor Mcfd/psia Specific gravity factor, dimensionless Super compressibility factor=~ dimensionless Flowing temperature factor, dimensionless Specific gravity of flowing fluid (air=1.000), dimensionless Specific Gravity of separator gas (air=1.00), dimensionless Gas-oil ratio, cu. ft. of gas (14.65 psia and 60 degrees F.) per barrel oil (60 degrees F.) Meter differential pressure, inches of water Vertical depth corresponding to L, feet (TVD) Length of flow channel, feet (MD) Exponent (slope) of back-pressure equation, dimensionless Field barometric pressu re, psia Shut-in wellhead pressure, psia Shut-in pressure at vertical depth H, psia Static pressure at point of gas measurement, psi a Reduced pressure, dimensionless Flowing pressure at vertical depth H, psia Flowing wellhead pressure, psia Static column wellhead pressure corresponding to Pt, psia Rate of flow, Mcfd (14.65 psi a and 60 degrees F.) Reduced temperature, dimensionless Absolute temperature, degrees Rankin Compressibility factor, dimensionless Recommended procedures for tests and calculations may be found in the Manual Of Back-Pressure Testing Of Gas Wells, I nterstate Oil Compact Commission, Oklahoma City, Oklahoma. ~ .:f\-"- ~ SRU 213-10 - Gas Open Flow Potential Test n = 0.57, C = 7.55E-3, AOF = 23.95 mmcfd; Reservoir Pressure = 1285 psia 10000000 1000000 N < ca ëñ Co Ñ < """ f1. I N < ; f1. 100000 10000 1 10 Gas Rate, mmcfd 100 Gas Cft\Openmind\Swanson\SRU\213-10\Pressure Survey\OpenFlowTest_11012002 11/01/2002 ~~~ SRU 213-10 -- Data for Gas Well Open Flow Potential Test Calculations INPUT DATA Gas Gravity 0.56 Tcr 341 Res. Pr 1285 psia TVD Datum, ft 3620 Base Pressure, psia 15 Rankine Factor 460 Pcr 673 SITP 1178 psia Flowing Flowing Tubing Tubing Flowing Static Flow Duration, Flow Rate, Pressure, Pressure, Tubing Pressure, Differential, Period hrs mcfd psig Pþ psia pt2 psia2 Temp. of Pm, psig hw ~ 1 2 5600 1116 1131 1279161 54 91.4 3.80 2 2 8000 1070 1085 1177225 55 154.1 4.60 3 2 9900 1025 1040 1081600 56 212.8 5.10 4 2 10700 1011 1026 1052676 56 237.0 5.35 5 6 10800 1007 1022 1044484 55 239.2 5.40 '~~ O:\Gas Cft\Openmind\Swanson\SRU\213-1 0\Surveys\Pressure\SRU213-1 O_FourPoint Data Analysis A~c."'~e"" t * 4 ( UNOCAL8 AFE #154978 ( Swanson RIver Unit SRU # 213-10 Drilling Program Final Schematic 8/19/02 RKB to TBG Head = 16.5' Elevation 293.5 Feet L ~ SIZE WT 13-3/8" 69 7" 29 CASING AND TUBING DETAIL GRADE CONN TOP BOTTOM Weld Surf 92' Butt Surf 1800' TVD L-80 3-1/2" 9.2 L-80 IMP ButtSurf 4105' TVD -- L ~ 2 7" Surface Casing @ 1987' MD, 1802 TVD JEWELRY DETAIL NO. Depth Item 1 Surf 3-1/2" Tbg hgr w/Carneron "H" BPV profile 2 1750 3-1/2" Chern Inj Sub w/lOOO psi chern valve CURRENT PERFORATION DATA ZONE TOP BTM ZONEIFORMATION SPF COMMENTS A 3985' 4000' Beluga 6 Power Jet hollow carrier -- A L1 \. TD = 4105' MD, 3737' TVD Directional Well ( MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Randy Ruedrich dtfZ J) DATE: February 24,2003 Chair ~ f ò3 1. O~ A SUBJECT: Mechanical Integrity Tests THRU: Tom Maunder ¡<1:1-' IV! Unocal Petroleum Engineer '~{5-o3 SRU 213-10 202-118 FROM: Jeff Jones SRU Petroleum Inspector Swanson River Field NON- CONFIDENTIAL Well 213-10 Type Inj. N P.T.D. 202-118 Type test M Notes: Type INJ. Fluid Codes F = FRESH WATER INJ. G = GAS INJ. S = SALT WATER INJ. N = NOT INJECTING Packer Depth T.V.D. 1800 Tubing Test psi 1370 Casing Pretest Initial 15 Min. 30 Min. 0 0 0 0 0 1370 1370 1370 I nterval V P/F f Type Test M= Annulus Monitoring P= Standard Pressure Test R= Internal Radioactive Tracer Survey A= Temperature Anomaly Survey Interval 1= Initial Test 4= Four Year Cycle V= Required by Variance W= Test during Workover D= Differential Temperature Test 0= Other (describe in notes) Test's Details February 24, 2003: I traveled to Unocal's Swanson River Field to witness an MIT on well SRU 213-10. Unocal representative Kevin Cassidy was on hand for the test which was conducted in a safe and proficient manner. I anived to find the annulus pressured up with nitrogen to 1370 PSI and the annulus pressure recorded on a chart for the previous 5 hours. I monitored the annulus pressure for an additional hour and detected no pressure loss, passing the MIT. M.I.T.'s performed: 1 Number of Failures: Q Attachments: Pressure Chart copy (1) cc: Larry Greenstein (Unocal) Total Time during tests: ~ T""c,. "->(¿\ \.'t'? 0.- ~~~~ c:fS- ~~~~é::.~ ~~ \\. I~ \"'-<ë cD +\-..<::.>-~ ~-.)\-"a~,<-~ ~~~ \\'\~ -\-~~ ~I"t.. \\ ~" \J.- \ T \Ñ~ "> \L~\.~' T~,s ~S\- ~~ O-C-c..(:)""-X>\'\S~~~ Ö-.-Ç~, s.<L\-\\~ Ö-.~V <>.,.;v 'o\Ð~'~-\'\~\'ð ~~-\-~ ~\\.~~ ~ ( ~d' T Ck~ ,0 ~ ~-\,-~(t0~-\- ~\.\~~ 't"-~~;t-,-\-\ ~û--":,. \:)~~~t-~~~( ~31Ç'O<' MIT report form 5/12/00 L.G. MIT SRU 213-10 2-24-03 JJ.xls 3/5/2003 SRU 213-10 (PTD 202-118) 403 (Plug Perfs and perforate uphole) ( ( Subject: SRU 213-10 (PTD 202-118) 403 (Plug Perfs and perforate uphole) Date: Mon, 03 Feb 2003 15:26:38 -0900 From: Jack Hartz <jack_hartz@admin.state.ak.us> To: Thomas E Maunder <tom - maunder@admin.state.ak.us>, Robert Crandall <bob - crandall@admin.state.ak.us>, James B Regg <jim_regg@admin.state.ak.us> Gents, The situation at 213-10 has some other factors to consider before judging whether Unocal has operated the well appropriately. The pipeline pressure and capability of the well to lift water are both factors in whether the interval being tested is near depletion. Conversation with Sam AttaDarkwah this p.m. indicated the following: 1.) the production system pipeline pressure this well produces to is at 200-220 psi. The well must have enough pressure to meet that so a practical limit is about 320-350 psi flowing tubing pressure. 2.) It must be able to lift the small amount of water that is being produced. Darkwah estimates the marginal rate to lift water is about 2 MMcf/d which is rapidly approaching. I believe they plan to produce it until it reaches the lift limit. It appears there is a practical limit to the reserves in this well. Looking at the P/Z at a flowing tubing pressure of335 psia (bhfp of360 psia) indicates "practical" producible GIP of about 1 BCF assuming you can produce to a formation pressure of360 psia. Theoretical GIP is approximately 1.25 Bcfto a P/Z of 0 (assumes the sand face pressure is atmospheric pressure, 0 psig or 15 psia). Current recovery is about 800 MMcf or a recovery factor of about 80%. This also assumes the aquifer is not providing much pressure support, which the early pressure data does not seem to indicate. ,Without additional data to suggest otherwise. I think this is a situation of a limited sand lense that is depleting and the rate of depletion is compounded by water production. When the well cannot htt the 'water, it will have to be shut in or work over to shut offwater. I think the proposal to perfuphole is appropriate. Ja~ 'It 7 .01 , --.--. -- - . .-- . ~ --------~ -. . -.- . - -.- - -~", --.---- .-- "-- .--. .-------.--.----.. . -.-- _n_-.-__---.--------.---- .-.-.--..- .--.----------- -- -----'.-----~---- ----, . Nan1e: SRU213-10.XLS ~SRU213-10.XLS' Type: EXCEL File (application/msexcel) Encoding: base64 ««:t'''''««'WYV«@:«~¡W,¡¡WluX«'~U'';'^'''«««'«'~';':X'X;;.oH:(W'''''"':lA"«-"W""uu',u,;«,;,"(',¡,;¡-',;,;,z"x:«((w,(;.',«:-,,,:v-:cx«:,"X(X:(".;.W.;-',;(~W,,;(X:¡:<XXX«(" Jack Hartz <jack hartz@adInin.state.ak.us> Sr. Reservoir Engineer Alaska Oil & Gas Conservation Commission ~ =""~~~.".",;';,;;;;":;:;;';';;;=-W"':':">:';:'>I.""::.,:.,::"":,~""""",...,..,.,...,:,..,.=.....»>=>",..:r>=>>>,"",,, [Fwd: SRU 213-10 -- Supporting Data...NormaIPepletion from Current Zone] ( (' Subject: [Fwd: SRU 213-10 -- Supporting Data To Confirm Normal Depletion from Current Zone] Date: Fri, 31 Jan 2003 15:00:29 -0900 From: Robert Crandall <Bob_Crandall@admin.state.ak.us> . Organization: DOA-AOGCC To: "Maunder, Thomas" <tom_maunder@admin.state.ak.us> Lets talk RPC ,-.""'''''-''''''''''''''''''''''''''''''''''''''''''''''''''''''''''''''''''''........ """"'-'-'-.....--....-......-.-----....-.-..-....-....._-_...__...__....._..._.._-.._...._......__."'~""'--'"''''--''''--'-"......-...''."......-..-................-""----.--".."""-----""""'-""""""""--'---""-'''''''---''--''_.._m....._.-...-....-....-...--.,", Subject: SRU 213-10 -- Supporting Data To Confirm Normal Depletion from Cu rrent Zone Date: Fri, 31 Jan 2003 15:50:07 -0800 From: "Darkwah, Samuel A" <darkwahs@unocal.com> To: "Crandall, Robert P -AOGCC" <Bob_Crandall@admin.state.ak.us> «SRU 213-10 - Current & Potential Zones_for State.ppt» «SRU 213-10_Well data for Tom and Bob_013103.xls» Bob, Following up on the phone conversation I had with you and Tom yesterday, I have provided information in the attached files to demonstrate that the current zone from which the subject well is currently producing is being normally depleted. I do not have Tom's email so I will be glad if you can forward the documents to him as well. Please give me a call when you are ready to review the documents so I will try to answer any questions you might have about the sheets in the documents. Sincerely, Samuel Atta-Darkwah Petroleum Engineer Unocal Alaska darkwahs@unocal.com 907-263-7864 office 907-301-0811 cell 907-263-7874 fax ,..1 Name: SRU 213-10 - Current & Potential ".11 " :1 Zones_for State.ppt DSRU 213-10 - Current & Potential Zones for State.ppt Type: Microsoft PowerPoint Show I (appl ication/vnd. ms-powerpoint) ...;1 "'.'~"='~""""""='","""'"'.'.""""'''lli'''~'lli"'"Ølli~<lli",~l.~,~~~,~~~~"'~.:>=~~~~,~~,~"""~'"'"""'~.""""""""'"'''«».@=«"'''''"''''"lli'=''''''"'..»''''='".~'»''"''"»''='='''''-"'''"'' DSRU 213-10 Well data for Tom and Bob 013103.xls Name: SRU 213-10_Well data for Tom and Bob_013103.xls Type: Microsoft Excel Worksheet (application/vnd. ms-excel) Encoding: base64 ¡ I ~ 1 of 1 1/31/20033:19 PM (' STATE OF ALASKA ( ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS Jfhþ(O? k~ts--a~ I"L~ :J./3/0 "J J? \ZJ 0 è./ð 1- /0:5 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: Perforate: X Other: - 5. Type of well: 6. Datum elevation (OF or KB, etc.) Development: X 16.6' RKB Exploratory: 7. Unit or Property name Stratigraphic: Swanson River Unit Service: 2. Name of Operator UNOCAL 3. Address P.O. Box 19-0247 Anchorage, AK. 99519-0247 At top of productive interval @ 3750' MD; 3393' TVD 3172' FNL & 537' FWL Sec 10T8NR9W SM AK 8. Well number SRU 213-10 9. Permit number 202-118/Conservation Order No. 474 10. API number 50- 133-20515-00 11. Field/Pool Swanson River Unit/Swanson River Field 4. Location of well at surface 1,718' FNL, 633 FWL, Sec. 10, T8N, R9W SM AK At total depth @ 4105' MD; 3737'TVD 3200' FNL & 534' FWL of Sec 10 T8N, R9W S.M.AK 12. Present well condition summary Total depth: measured true vertical 4,105' feet 3,737' feet Effective depth: measured 4,105' feet Slickline Tagged fill, 12/26/02 @ 3,988' MD true vertical 3,737' feet 3,623' TVD Casing Length Size Cemented Measured depth True vertical depth Structural Conductor 92' 13-3/8" DRIVEN 92' 92' Surface 1,987' 7" 285sx 1,987' 1,802' Production 4,105' 3-1/2" 482sx 4,105' 3,737' measured Sterling B-6 3,750' - 3,760' true vertical Sterling B-6 3,393' - 3,398' Tubing (size, grade, and measured depth) 3-1/2",9.2#, L-80 Tubing. Surface to 4,105' MD. Packers and SSSV (type and measured depth) 3-1/2" Monobore 13. Attachements Perforation depth: Description summary of proposal: X Detailed operations program: BOP sketch: 14. Estimated date for commencing operation 2/15/2003 16. If proposal well verbally approved: 15. Status of well classification as: Oil: Gas: X Suspended: Name of approver Date approved Service: 17. I hereby certi~that the f re~.ng is tru~and correct to the best of my knowledge. Signed: "- - ~ Title: Project Manager a el A. Darkwah FOR COMMISSION USE ONLY Conditions of approval: Notify Commission so representative may witness Plug integrity- . . BOP Test- Location cleara~ce- Mechanical Integrity T est~ Subsequent form required 1 0- ~. 0 '-\ 'W'i\\~~,~ ~\,"\ \>I{.~. 'Q.v\'<. ~ <"0 ~~~ Date: 1/28/2003 Approval No. _? 03 ~-Ö;;)-7 ORIGINAL SIGNED BY M L-em Approved by order of the Commissioner Commissioner Date fJ hJ þ~ RBDMS 9FL ÆB 7 SUBMIT IN TRIPLICATE Form 10-403 Rev 06/15/88 I' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon: - Suspend: - Operation shutdown: Re-enter suspended well: Alter casing: Repair well: Plugging: !:..- - Time extension: Stimulåte: Change approved program: Pull tubing: Variance: Peñoratë: X Other: - 5. Type of well: 6. Datum elevation (OF or KB, etc.) Development: 25- 16.6' RKB Exploratory: - 7. Unit or Property name Stratigraphic: - Swanson River Unit Service: 2. Name of Operator UNOCAL 3. Address P.O. Box 19-0?47 Anchorage, AK. 99519-0247 4. Location of well at surface 1,718' FNL, 633 FWL, Sec. 10, T8N, R9W SM AK At top of productive interval @ 3750' MD; 3393' TVD 3172' FNL & 537' FWL See 10T8NR9W SM AK 8. Well number SRU 213-10 9. Permit number 202-118/Conservation Order No. 474 10. API number 50- 133-20515-00 11. Field/Pool. Swanson River Unit/Swanson River Field At total depth @ 4105' MD; 3737'TVD 3200' FNL & 534' FWL of See 10 T8N, R9W S.M.AK 12. Present well condition summary Total depth: measured true vertical 4,105' feet 3,737' feet Effective depth: measured 4,105' feet Slickline Tagged fill, 12/26/02 @ 3,988' MD true vertical 3,737'feet 3,623' TVD Casing Length Size Cemented Measured depth True vertical depth Structural Conductor 92' 13-3/8" DRIVEN 92' 92' Surface 1,987' 7" 285sx 1,987' 1,802' Production 4,105' 3-112" 482sx 4,105' 3,737' measured Sterling B-6 3,750' - 3,760' true vertical Sterling B-6 3,393' - 3,398' Tubing (size, grade, and measured depth) 3-112", 9.2#, L-80 Tubing. Surface to 4,105' MD. Packers and SSSV (type and measured depth) 3-1/2" Monobore 13. Attachements Perforation depth: Description summary of proposal: X Detailed operations program: - BOP sketch: 14. Estimated date for commencing operation 2/15/2003 16. If proposal well verbally approved: 15. Status of well classification as: Oil: Gas: X Suspended: - Name of approver Date approved Service: 17. I hereby certify that the ~ regoing is tru~and correct to the best of my knowledge. Signed: :tJ-o.- ø Title: Project Manager a ' I A. Darkwah FOR COMMISSION USE ONLY Conditions of approval: Notify Commission so representative may witness Plug integrity- BOP Tes~ Location clearance- Mechanical Integrity Test- Subsequent form required 10- Date: 1/28/2003 Approval No. Approved by order of the Commissioner Commissioner Date Form 10-403 Rev 06/15/88 SUBMIT IN TRIPLICATE SRU 213-10 Procedure Summary 1 RI and set Composite BP @ 3,950' MD on E/line. 2 Dump bail 1 0' of cemment on top of plug. 3 RI & perforate the Sterling B6 sand 3,750' to 3,760' MD. 4 RD E/line. 5 Put well on test. I UNOCALe AFE #154978 ScALE ~ Swanson lver Unit SRU # 213-10 Drilling Program Final Schematic 8/19/02 A/o r II 't vv ¡.J 'To ( RKB to TBG Head = 16.5' Elevation 293.5 Feet L. ~ CASING AND TUBING DETAIL SIZE WT GRADE CONN TOP BOTTOM 13-3/8" 69 Weld Surf 92' 7" 29 L-80 Butt Surf 1800' TVD 3-112" 9.2 L-80 IMP ButtSurf 4105' TVD -- L ~ 2 7" Surface Casing @ 1987' MD, 1802 TVD JEWELRY DETAIL NO. Depth Item 1 Surf 3-112" Tbg hgr w/Carneron "H" BPV profile 1750 3-112" Chern Inj Sub wllOOO psi chern valve , TM{~eí S18lIJN?= @ == 3160 Bb S/rN{;¡ =- = Hl:.o I 2 lQ'ef CM'OV\ T~p ~W\r..,~.tt PI"'5 CURRENT PERFORATION DATA ZONE TOP BTM ZONE/FORMATION SPF COMMENTS A 3985' 4000' Beluga 6 Power Jet hollow c~rrier ~, "'0" ~<tSO' -- == A L1 \. TD = 4105' MD, 3737' TVD Directional Well PR'Cpo'76 ) eERFo"Z.Þr"í(o~ Djfl1\ foR STER.LING[ ß h Oil GNí/lfìfJlI bO Jey~ ZoNE. B ToP 80TfpiVj 31-50 ?; 1-60 FoR./V1iYfj QI...j --?TER L lN6t SPF 6 GuAJ rtf6 P&vJe-&G ~ ~~ 1800 1600 1400 1200 1000 N ......... Q. 800 600 400 200 0 0 0.2 0.4 0.6 0.8 Gp, Bef SRU 213-10 y = -1?86.8x + 1687.4 R2 = 0.9949 ,-, ---_.____~4__----- P/Z=375, recoverable GIP approx 1 ~F ~ -----~_._--_.~-----<-.._-- -----~--~----,..-----_. -~.._._-- 1 1.2 1.4 ~-¿; ì ~~ ~\J{,~ rl~J-J¡7ð ~ ~ ( ~~C,,~~ ú ,-\{J~ ('. ~... . \ \ \- ~ -"'- \ - \ ~ "'~~ \~~ ,C) ()..~o..~C)e:Jt" ~~, \"~\~~. \ ~ \N<é\\ d\~-\Ù w~~m~\.-\:s.~\tO '\~\~ ~r¿\\.~(JS,. \"'~ ~"C~ Û\--öCO\ ~ ~~~\~ ~>~,>I...)"V1ke\'(¡ 'T~ -\o~--\- ~(),~ ~~\v--<J. ,II Ö\\"c SO ~ ~~(è-'V~> , ~()-~Î)0 V" \- Nê ~\02J~C\-\Ð ~ ~\s-4J~ ~1Cj3+~iu ú. S~~ ,:>o.r\.BJ, V\<è ~Sû~ ~ \ú..~,( (R) ($c~Q¡ O-LCD :B,,, It-- '" -\-0 ~k T'~0 ~O$ $i: éÕ rQ ~ , ß<3-"::>~ ð~ t=-~ ~l~~~. \'-t) ~Q\-Q \'I-DC9~ fro~~ ~~~\G $Q~ov'-be_~, Wð-~r~ {fð~~~~() "" h.G-s 'd'-~\Q.O-~. 'D.' '. ð9 \0<:> -\-\..' <::- \ '- .~'... '.+K Q6~1 \~ ~ \- (?\~ "" /, ~,~ ~(( \l ~T 'O~ ~ S \"'^-~~\ "G'\ ' 0", \-h ~Q \ CJ.\J~~~,"~ -\-,^-ìs. L.()\"'-.<? ç."M.D\..)~~ ~\~~e.\ \S ~ CD~& c.Ð0"SQ: Ð ~ac\-'\o~r( k\~dè, ~\).Xè\J<L ~- S:lèJÔ ;"S ~\'e ~~~ \ <5-~ -\Q:S-t>\.) \ ~:\. ~, *M ~"l\ 0--\-Q~"'0<t' ~\-Cè c:::.Cê.e.M'> .S\J~\~\ù~>" r, 7, ,-,.f " . ,~.,,~~-Cù~f" .. S"-7~ \~ ~~ \"?S0E- x0<è S>~'-' '\.~ ~\-~~. Ù.~~.\ S .. .. 'S:\ 1/ ~ '\~ \0 ,)()~c~~CJ~ ~ ~Q~ \<...~ 'JV\. h..<t ~'"\'.... \).j\ ,-. ~ ~, , \ I ~Ð I ~~~' ~ ~", ,~vJ), ~. .~blM- ~~ ~. ~~r ~~ ~! ~<; dltt.wi- Q¡J/.~:lv 'eu.J'1 tfkL,~\~J- tfr ~s ~ ,- ð'~J' St ì't ~~ ~wt("~ ~J¡/~. . ~~, I ì4<K:; /~MI$I~~~ ~ç ~ ('\P~ c<""'! ~¡í\t~l ~ 'tf'~,~'¿/t '1.0 cL(~:\ ~A, ðfuc- Cte~-tL~Við ,S ~ ~/$ltr3 ~ fJ \I P 3- 11 /) -() vJ ~ <r\ ;ß- /' 1-1 L¿ ~ ç \fJ éO 1 0 G /' 0 e ~ ~ f '] ~ ~ 8)1.. /" /, ~ èY:I ' -l b ~ L ;1 i: 0 = ,.. ::r 0 '" 0 0 FTP or Cum Gas ( \.;\~) -10. (» (X) 0 0 0 0 0 0 0 -10. '" 0 0 ~ 0 0 en (1) "'C r+ 0 Q. z 0 < 0' (1) 0 ~-.¿ § ,f' 0 0 JI --£~ III ()' ~ ð ;r ;{ ) -10. ~ 0 0 en XI c: N ..... W I ..... Q <V 0 rJ ~ ~. ~ 1/31/2003 3:20 PM Swanson River 213-10 (Beluga Sand 3985 - 4000) Gas Spec. Gravity . ~~) TVD of perfs. (ft) ~ Temp. (deg. F) 88 Surface Pressure Cum. Pressure of gas BHP calc. Date Test Type (psia) (BCF) z gradient (psia) P/z 8/5/2002 SITP 1352 0.000 0.8627 110 1462 1695 8/31/2002 SITP 1292 0.041 0.8672 105 1397 1610 10/31/2002 SITP 1162 0.220 0.8776 93 1255 1430 12/2/2002 SITP 858 0.510 0.9051 67 925 1021 t)~ {" I é{b3f 3tf$ <L\~d / .0- ) / 5(,?~ .-., .~V ~~ /\ L.¡ \f? ") ---- .~. SRU 213-10_Well data for Tom and Bob_0131032.xls SRU 213-10 -- POZ vs Cum Gas Production Plot 1800 - ., 1600 -_u_.':---- - - - - - - - - - - - ~ - - - - -- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- ----------------------------- "',._, -+ 1400 --___-_hu . - - - - - - - - - - - - -- - - - - - -- - - - - - - - -- - - - - - --- - - -- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- "'" 1200 - uuuuuuuuuuumumuu u u~u to 1000 - uuuuuuuuuu u, u - - -- - - - - - - ,m uuuum,mmum~muuuuummmmmmmmuuuuummummumuuuumuuuu." - _.' -'.U._' ~ , ~ . ~ 800 _mm, uu - m.. .u- uuuuuuumuuuuuumumumuu uuumu u~ u u u uu uummuuuuuu u?li' ~ij~U'~ I' FfP;;'3~(þir~.- " Gf/ r-p-- :;; b () 600 - .----- ------------------ ------------------ -----.- --------------------------------------------------'>-,.~<:-----_u_------. uu uuuzuu _u__uu_uu -Ud. d' _u - . Uu U .. - - -- - -- "'.., 400 ~-,-- -- -- - -- -~~:.~~:':"=~_:~::_::_-.:~~::_-:~:_:.~:------ - ---------- ----------------- -- U_------------:::-- --:-- U -:::~:---_:-- - - -~~~,;_:--- U_-~_:_~- - - - - - - - _. - _. - - - - - -- - - - - - -. - - - -. -- - - - ----- -- - - -- - - - - - --- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- ~ 200 0 0.00 ~i , I "- '..", 0.25 0.50 0.75 Cum Gas Produced, bcf 1.00 1.25 1.50 Gp"&- C¡f;o /1MC~ (f SRU 213-10 -- Well Test Data as of 1/05/03 Water Length Gross Oil Rate Form Gas Lift Tbg Csg Gas Rate Gas Rate WGR Date (hrs) (bpd) (bopd) (bwpd) (mcfd) (mcfd) (bw/mmcf) Press Press 1 0/3/2002 24 0 0 0 3397 0 0 1242 0 11/23/2002 24 0 0 0 9456 0 0 800 0 12/8/2002 24 0 0 0 7498 0 0 678 0 12/23/2002 24 119 0 119 4932 0 24.13 530 0 12/26/2002 24 187 0 187 4215 0 44.37 490 0 1/5/2003 24 239 0 239 3597 0 66.44 440 0 ~ ~, Gas Cft\Openmind\Swanson\SRU\213-1 O\Misc\SRU 213-1 O_Well Tests_01 0603 SRU 213-10 -- Well Tests 200 160 - - - - -- - - -- -- - - - - - - - - - -- -- - -- -- -- -- - -- -- - - - - -- - -- Latest Point by Greg Merle: Date = 01/22/03 - Gas Rate = 2.686 mmcfd Ptbg = 378 psig Gross Liq= 316 BWPD --~ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - ~ LL 120 ~. nnnnnnnnnnnnnnnnn ... -- - - - - - - - - - - - - - - - -- -- - - - - - - - - - - - - -- -- - - - - - -- - - - - - - - - - - - - - - - - - - - - - -- -- - - -- - - - - - - - -- - - - - - - - - - - _u- -- - - - - - - - -- - - - -~. u - - -- - - - - - -- -- - - -- -- 0 :! :! ~ co ~ C) 3: 80 - - - - - -- - -- -- - - u - - - - - - - - -- -- -- -- - - - - u - - -- - - - - - - - -- u -- -- u - - - - - - - - - - - - - - - -- -- -- u u - - - - -- -- - - -- u -- u u u u - -- - - - - - - - - - - -- - u - - - u -- -- - - - - -- - - - - -- -- u -- - - - -- -- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - . -~, 40 - - -- - -- - - - -- - - - - -- - -- -- -- - u - - - - - - -- u - -- u u - u - -- . - - - - - - - - - - - - - - - - - - - -- - --- -- - - -- - - - ---- - - - - - -- - - -- - -- - - - - - - - -- -- -- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - .. - - - - - - - - - - - . 0 8/30/2002 I . . . 9/30/2002 10/30/2002 11/30/2002 12/30/2002 1/29/2003 3/1/2003 3/31/2003 5/1/2003 ,Çonserw3tion Order No.4 7 4 ( http://www.state.ak.us/local/akpages/ADMIN/ogc/oindex/co/co474.htm (' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West Seventh Avenue, Suite 100 Anchorage Alaska 99501 Re' THE APPLICATION OF Union ) Conservation Order No. . Oil of 474 California ("UNOCAL") for an order ) Swanson River Field Allowing well SRU 213-10 to be ) Swanson River Undefined completed Gas Pool Without a tubing and packer. ) Swanson River Unit Well 213-1 0 ) ) July 17,2002 IT APPEARING THAT: 1. By application dated June 11, 2002, and received by the Alaska Oil and Gas Conservation Commission ("Commission") on June 11, 2002, Union Oil Company of California ("Unocal") requested an order from the Commission allowing the proposed Swanson River Unit ("SRU") 213-10 well to be completed without a tubing and packer as required by 20 MC 25.200(d). 2. Notice of opportunity for public hearing was published in the Anchorage Daily News on June 17, 2002 in accordance with 20 MC 25.540. 3. Unocal submitted additional information concerning the application by letter dated June 25,2002. 4. The Commission received no comments concerning the application or requests for a public hearing. 5. The Commission decided to issue an order without public hearing. FINDINGS: 1. Unocal is operator of the Swanson River Field. 2. Unocal proposes to drill the SRU 213-10 well to a depth of approximately 3735 feet TVD (4106' MD), from a surface location 1725 feet from the north line ("FNL") and 628 feet FWL, Section 10, T8N, R9W, SM to a bottom hole location of 3103 feet FNL, 552 feet FWL, Section 10, T8N, R9W, SM. 3. Unocal proposes to drill the well using a slim hole drilling technique, running small diameter casing, and completing the well without a tubing and packer. 4. Commission regulation, 20 MC 25.200(d), states: "AII producing wells capable of unassisted flow must be completed with down hole production equipment consisting of suitable tubing and a packer that effectively isolate the tubing-casing annulus from fluids being produced, unless the commission specifically approves production through the annulus to increase flow rate without jeopardizing ultimate recovery from the well." 5. Commission regulation, 20 MC 25.990(26), defines fluids as "any material or substance that flows or moves, whether in a semi-solid, liquid, sludge, gaseous, or other form or state." 6. Unocal is drilling the SRU 213-10 in order to produce gas reserves updip from the watered out SRU 212-10 well located on the same pad. The gas reserves developed contain methane with no H2S or CO2 which reduces risk of internal corrosion. 1 of 3 1/29/2003 1 :36 PM çonservation Order No.474 ( http://www.state.ak.us/local/akpages/ADMIN/ogc/oindexlco/c0474.htm 7. Formation pressure of the Beluga formation sands being produced ranges from normal hydrostatic, 8.6 ppg to abou~ 6 ppg equivalent. . 7 8. Producibility and viability of the well will depend on maintaining mechanical integrity of the casing. 9. Unocal proposes to construct the SRU 213-10 well as follows: 133/8 inch conductor casing driven to 80 feet, 7 inch L-80 surface casing run to 1800 feet TVO (1979' MD) and cemented to surface, and 31/2 inch L-80 production casing run to TO and cemented to the surface. 10. The 31/2-inch production casing will be cemented with a two-stage cement job consisting of a low weight lead slurry and conventional tail slurry to isolategas bearing productive zones. 11. The 7 -inch production casing will be set just below the maximum depth of fresh water and just above the targeted gas bearing shallow production zones. The anticipated leak off on the 7 -inch surface casing shoe is anticipated to be about 15.5 ppg equivalent. 12. Maximum anticipated surface pressure for the targeted depleted gas sands is expected to be around 600 to 800 psi. 13. The small diameter production casing precludes running a tubing and packer. 14. Without a tubing and packer, there are fewer options available for performing cleanouts and remedial work. Mechanical integrity failure could lead to the early abandonment of the well. CONCLUSIONS: 1. The SRU 213-10 well is targeting dry methane gas reserves and is not expected to encounter liquid hyd rocarbons. 2. The targeted gas reserves are capable of unassisted flow to surface, but only after hydrostatic pressure has been removed. 3. An exception to 20 AAC 25.200(d) is necessary to allow the drilling and completion of the SRU 213-10 well without a tubing and packer. 4. Gas produced by the 213-10 Well has no potential for corrosive products. 5. Mechanical integrity may only be tested on the inside of the production casing. 6. Failure of mechanical integrity will cause the well to be abandoned. 7. The drilling and completion of the SRU 213-10 well without a tubing and packer may result in a greater recovery of hydrocarbons, and will not cause waste nor jeopardize correlative rights. NOW, THEREFORE, IT IS ORDERED THAT: Unocal's application for an exception to 20 AAC 25.200( d) to allow the drilling and completion of the SRU 213-10 well without tubing and packer is approved subject to the following conditions: 1. A cement quality log must be run from TO to 200 feet into the surface casing prior to perforating the well. 2. A plug seating profile must be provided above the perforations or prospective perforation intervals to accomplish internal integrity tests. 3. Mechanical integrity must be demonstrated annually. 4. Each annuli pressure must be monitored daily and reported to the Commission quarterly. 5. Any pressure noted on the inner or outer annuli must be reported to the Commission on the next working day. The operator must implement corrective action, diagnostic work or increased surveillance as required by the Commission and obtain approval from the Commission to continue production operations at the well. 6. Failure to repair or prove mechanical integrity will result in expedited abandonment of the well. 2of3 1/29/20031:36 PM Conservation Order No.474 http://www .state.a(I'~/local/akPages/ ADM I N/ogc/oindexlcoho4 7.4 .hJm DONE at Anchorage, Alaska and dated July 17, 2002. Cammy Oechsli Taylor, Chair Alaska Oil and Gas Conservation Commission Daniel T. Seamount, Jr., Commissioner Alaska Oil and Gas Conservation Commission Conservation Order Index 30f3 1/29/2003 1 :36 PM Date To CC From: Re ( January 13, 2003 Jack Hartz - Senior Reservoir Engineer - AOGCC Jeff Smetanka - Advising Reservoir Engineer - Unocal Gas Team Sam A. Darkwah - Petroleum Engineer - Unocal Gas Team SRU 213-10 -- Four Point Test Data and Results SRU 213-10 was perforated in the undepleted Beluga Sands in the interval 3985' - 4000' MD on 8/4/02 and all of the well's current production is corning from this sand. In accordance with 20 AAC 25.225 (Alaska Administrative Code, Title 20 - Chapter 25), we conducted a modified isochronal flow-after-flow four point test on the recently perforated virgin interval on 11/1/02. This Memorandum (and attachments) presents the results of the subject test. Attachment 1 is the completed State of Alaska Gas Well Open Flow Potential Test Report with test results and calculations. Attachment 2 is a Log-Log plot of the data from the four point test. Attachment 3 is the recorded rate and pressure data from the field. Attachment 4 is the current schematic of the well. Also I would like you to clarify the following question for me: In the event the current zone waters out and we set a plug over it and move uphole and perforate a potential gas zone, will it be necessary to conduct a similar open flow potential test and submit the results to the State? If you have any questions please feel free to call me at 263-7864. Thank you. Enclosures: Attachment 1: Attachment 2: Attachment 3: Attachment 4: Gas Well Open Flow Potential Test Report Sheet for SRU 213-10 Log-Log Plot of Test Data. Recorded Flowing Gas Rate and Tubing Pressure Data From Field. CurrentWellbore Schematic for SRU 213-10. If found in order, please sign below and return a copy of this letter to me in the attached pre-paid envelope. Recei ved By Title Date 'l~P( 512-. ~'¿f ~ RECEIVE I ^ 1\1 1 h, 200. -~ ....AJ,,, i . v v RllRa Oil & Gas Cons. Commission Anchorage ( Unocal Corporation P.O. Box 196247 Anchorage. AK 99519-6247 Telephone (907) 276-7600 UNOCAL8 ";!¡Y@lIJIIJ Alaska October 27 2002 Alaska Oil and Gas Conservation Commission 333 West ih Avenue Anchorage, Alaska 99501 Attn: Cammy Taylor, Commissioner Re: Swanson River Form 10-407 SRU 213-10 Dear Com m issioner Taylor: Enclosed for your review is the second corrected Form 10-407 for SRU 213-10. The two areas of correction are: under NO.4 a correction of depth and leaselines for the top producting interval and at total depth. Core information is being submitted under No. 28. Due to the fact we found an old cellar that we could not identify on the proposed surface location, we moved the surface location approximately 25' from the unknown cellar. If there are any questions, please contact Jim Mosley at 263-7679. Sincerely, J'. J. ~Ie~ Senior Advising Drilling Engineer Enclosure RECEIVED OCT 3 12002 Alaska Oil & Gas Gons. Commlsslø.n Anchorage (' STATE OF ALASKA ( ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG OIL: GAS: X 2. Name of Operator UNION OIL COMPANY OF CALIFORNIA (UNOCAL) ,\~~~~;...'- 3. Address ¡'~~~~ P.O. BOX 196247 ANCHORAGE, AK 99519-6247 = 1fffn~ ,. 4. Location of well at surface t~, - ~' ; 1718' FNL and 633' FWL Sec. 10 T8N, R9W, S.M., AK ~iit.t~-' . '., ~ At Top Producing Interval l~.J.t_;.~J~~~-1~ @3985' MD; 3621' TVD 3172' FNL & 537' FWL Sec 10T8NR9W SM AK At Total Depth @ 4105' MD; 3737' TVD 3200' FNL & 534' FWL of Sec 10 T8N, R9W S.M. AK 5. Elevation in feet (indicate KB, OF, etc.) 6. Lease Designation and Serial No. 16.6' RKB Private 12. Date Spudded 13. Date T.D. Reached 14. Date Comp., Susp. or Aband. 15. Water Depth, if offshore 16. No. of Completions .I '"7/"'~ ,It"". cf.U:>OZ- 07/18/2002 07/24/2002 ~LUUL Compo <l I ~ On Shore feet MSL 1 17. Total Depth (MD+ TVD) 18. Plug Back Depth (MD+ TVD) 19. Directional Survey 20. Depth where SSSV set 21. Thickness of Permafrost 4105' MD 3737' TVD 4025' MD Yes: X No: n/a feet MD n/a 22. Type Electric or Other Logs Run SimPulse-Gamma Ray, Array, Induction/Density/CNUGRISP/Caliper, Platform Express Compensated, Neutron Log Casing, Caliper Log 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD TOP BOTTOM Surface 92' Surface 1800' 1. Status of Well Correction #2 SUSPENDED: CASING SIZE WT. PER FT. 13-3/8" 68# 7" 26# GRADE K-55 L-80 3-1 /2" 9.3# L-80 Classification of Service Well ABANDONED: SERVICE: ~. ..B_~;¿_Q2- i 'jC~ . \-~-., 4.;;<I~~':'i~!":;"':" ".:". ".. 7. Permit Number 202-118/Conservation Order No. 474 8. API Number 50- 133-20515-00 9. Unit or Lease Name Swanson River Unit 10. Well Number SRU 213-10 11 . Field and Pool Swanson River Unit HOLE SIZE DRIVEN 8-1 /2" AMOUNT PULLED 0 0 0 0 CEMENTING RECORD DRIVEN 285 sx Surface 4105' 6" 482 sx 24. Perforations open to Production (MD+ TVD of Top and Bottom and interval, size and number) SEE ATTACHED SCHEMATIC 25. TUBING RECORD DEPTH SET (MD) PACKER SET (MD) SIZE 3985'-4000' MD 3621' to 3635' TVD 6 Shots per foot with Thru Tubing Power Jet Hollow Carrier Gun 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production Method of Operation (Flowing, gas lift, etc.) 8/7/2002 Flowing Date of Test Hours Tested PRODUCTION FOR OIL-BBL GAS-MCF 8/07/2002 24 TEST PERIOD => 5666 Flow Tubing Casing Pressure CALCULATED OIL-BBL GAS-MCF Press. 1300 psi 0 24-HOUR RATE => 5666 28. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. See Attached Mud Log Formation Top Bottom Sterling 3202 3235 Sterling 3378 3382 Sterling 3448 3458 Sterling 3750 3770 Beluga 3985 4002 Form 1 0-407 Rev. 7-1-80 WATER-BBL CHOKE SIZE GAS-OIL RATIO 0 26 64 WATER-BBL OIL GRAVITY-API (corr) 0 Descriptions/Contents, etc Untested, not cored Untested, not cored Untested, not cored Untested, not cored See Production Test Data Item 27. RECEIVED OCT 3 12002 Alaska Oil.& Gas Gons. COmmissIon Anchorage CONTINUED ON REVERSE SIDE ~ n f\¡. ~. \ì '. '). 11 I ~ H B (1 M ~ \\JJ Submit in duplicate L ( ( 29. 30. GEOLOGIC MARKERS FORMATION TESTS NAME Include interval tested, pressure data, all fluids recovered and gravity, MEAS. DEPTH TRUE VERT. DEPTH GOR, and time of each phase. RECEIVED OCT 3 12002 AlasKaOi~& Gas Gons. Commission Anchorage 31. LIST OF ATTACHMENTS PERFORATION DATA SHEET, ABANDONDED WELL SCHEMATIC, SUMMARY REPORT OF OPERATIONS 32. I hereby certify that the foregoing is true and correct to the best of my knowledge SignWr~% V Trtle ') 1 J {j ~'-) 0 ¿ Date I NSTR UCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1: Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other space on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the productin intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21: Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). Item 23: Attached supplemental records for this well should show the details of any multiple stage cement- ing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water In- jection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". Form 10-407 . \ SRU 213-10 Well Log Daily Operations Summary July 14- Rig Released from KGSF location. 13-3/8" Conductor preinstalled on 213-10 Location to 76' below Grade. July 15 -Began Turnkey Rig Move July 16 - Turnkey Rig Move July 17 - Turnkey Rig Move and Rig Up finished at 2400 Hours July 18 -Rig Accepted 0000 Hours. Tested Diverter. PU 12-1/4" Bit and washed out Conductor to 120'. LD 12-1/4" & PU 8-1/2" BRA. Drilled to 300'. July 19 -Directionally Drilled to 1868' July 20 - Drilled to 2000' and made wiper Trip. Started Running 7" 26# Surface Casing. July 21 -Finished running 7" to 1989. Cemented 7" with 75 bbls of 12.5 ppg Lead and 18 bbls of 15.8 Tail. Cement circulated to Surface. ND Diverter and NU BOPE July 22 - Finished NUBOPE and tested same. PU 6" BRA and RIH. Tested Casing to 2500 psi. Drilled Cement and Float Equipment. July 23 -Drilled out to 2025'. Circulated and Conducted Casing Shoe Integrity Test to 15.9ppg Equivalent. Directionally Drilled to 3464'. July 24 - Drilling ahead. Expect to TD this morning and will run Platform Express Log. July 24 -Drilled to 4105' and Conditioned for logs. Pulled out of hole and Ran Platform Express Log July 25 -Logged from 4105' to 1987'. Ran Gamma Ray to Surface. RD Schlumberger. Started running 3- 1/2" Completion July 26 -Finished running 3-1/2" Production Tubingless completion to 4105' and cemented with 38 bbls of - lead and 77 bbls of tail. Cement circulated to surface with full returns. Plug bumped and held. ND BOP's and NU Tubing head flange and XMAS tree. Tested Tree to 3000 psi; ok. July 27 - Rigged down and prepared to move out rig. Rig released at 2400 hours 27 July 02. 28 July -Moved out Nabors Rig 129. 29 July -Stacked rig on 12A-I0. 30 July -Bermed stacked rig and cleaned up location 213-10. 31 July - Waited on Schlumberger to run CBL . 01 Aug -Rigged up and Ran Schlumberger CBL log from PBTD 4103' to Surface. Top of cement just below wellheads. Good bond all the way. 02 Aug -Rigged up Pollard and made dummy gun run to PBTD. Swabbed well down to 800 feet and prepared to perforate. Released Pollard. 03 Aug -Rigged up Production test equipment and temporary flowline 04 Aug -Rigged up Schlumberger and RIH with 2" Guns. Perforated 3985' to 4000' platform express log. Unloaded well and turned well over to production. ... UNDCALe SRU 213-10 wa.L AS-BlLT SlIFACE LOCATION DIAGRAM AS-BUilL T SRU 213-10 WELL ASP ZONE 4 NAD27 GRID N: 2485826.116 GRID E: 348551.293 LATITUDE: 60"48'05.0113" N LONGITUDE: 150"50'52.5358" W 171~' FNL 633 FWL SECTION 10 T8N. R9W. S.M.. AK ELEV. 293.5 FT. NAVD88 P.O. 80x 468 SOLDOTNA. AK 99669 Consultine Group Tssline TEL 907.283.4218 FAX 907.283.3265 2~ Alum. Cop SRU 212-10 WELL GRID N: 2485801.230 GRID E: 348527.781 ~ ¡ """\\" ....."'" ~ 0 F A l.. . , ~~~"""""'.1& " - I'~." * '..r " - -./' ''1' ... * ""49 TH "'. *~ .......,..".""",.."".""""", tIÞ ~ ,,- ~ ~ "...,..,......"....,',..,.."..,.. "" , ~ :,M. SCOTT McLANE.: ff ... I ",', ..~- " "'~ ", 4928-5 ,,' .s:-.. - I ?I~ '. .' " - I () þ,............, .:~<;) - I.. ~ESSI~"'\. \. ,,-' ,\""", PROJECT UNOCAL SRU 213-1Ø SURFACE LOCATION LOCATION 5wan&on F(lver Unli, Ala&1c.a DRAWN BY SCALE DATE DATE M.5.M, 1/IØ/Ø2 111 =4bØ' ~ ,'. I I I ~ , .~ I ~ I -.......¡ REVISION PROJECT/owe, Ø23Ø¿ 3 SHEET NO. OF UNOCAL8 AFE #154978 Swanson ~^ ;r Unit SRU # 213-10 Drilling Program Final Schematic 8/19/02 RKB to TBG Head = 16.5' Elevation 293.5 Feet L. ~ CASING AND TUBING DETAIL SIZE WT GRADE CONN TOP BOTTOM 13-3/8" 69 Weld Surf 92' 7" 29 L-80 Butt Surf 1800' TVD 1 3-1/2" 9.2 L-80 , llvfP ButtSurf 4105' TVD - L ~ 2 7" Surface Casing @ 1987' MD, 1802 TVD JEWELRY DETAIL NO. Depth Item 1 Surf 3-1/2" Tbg hgr w/Cameron "H" BPV profile 2 1750 3-1/2" Chern Inj Sub w/1000 psi chern valve PROPOSED PERFORATION DATA ZONE TOP BTM ZONE/FORMATION SPF COMMENTS A 3985' 4000' Beluga 6 Power Jet hollow carrier -- == A 11 \. TD = 4105' MD, 3737' TVD Directional Well SRU 213-10 Summary of Logs Run .L02 Run Depth Interval 4105'-1952' 4105' - 1987' L02S SlimPulse-Gamma Ray Array InductionJDensity/CNL/GR/SP /Caliper Platform Express Compensated Neutron Log in Casing Caliper Log Date 7-22-02 7-24-02 Survey Client: Unocal Survey Computation Method: Minimum Curvature Field: Swanson River Unit DLS Computation Method: Lubinski Structure: Swanson River Vertical Section Azimuth: 187.630° Well: 213-10 Vertical Section Origin: N 0.000 ft, E 0.000 ft Borehole: 213-10 TVD Reference: Borehole: KB UWUAPI#: 501332051500 309.8 ft above MSL Date: July 17,2002 Magnetic Declination: 20.792° Grid Convergence: -0.74022303° Total Field Strength: 55481.084 nT Scale Factor: 0.99992610 Dip: 73.6210 Declination Date: July 17, 2002 Location: N 60 48 4.945, W 150 50 52.644 Magnetic Declination Model: BGGM 2002 : N 2485819.433 ftUS, E 348545.820 ftUS North Reference: True North Coordinate System: NAD27 Alaska State Planes, Zone 4, US Feet Coordinate Reference To: Wellhead (True) Comment MD Incl Azim TVD vSec NS EW TF BR TR DLS (ft) (°) (°) (ft) (ft) (ft) (ft) (°) (° /1000) (° /1 OOft) (° /lOOft) Tie-In 0.00 0.00 0.00 0.00 0.00 0.00 0.00 -28.4 M 0.0 0.0 147.38 0.31 331.61 147.38 -0.32 0.35 -0.19 10.9 M 0.2 0.0 0.2 234.94 0.55 10.91 234.94 -0.93 0;97 -0.22 24.5M 0.3 44.9 0.4 265.01 0.40 24.53 265.01 -1.18 1.21 -0.15 127.3 M -0.5 45.3 0.6 305.94 0.52 127.33 305.94 -1.22 1.23 0.06 145.2 M 0.3 251.2 1.8 331.60 1.61 145.22 331.59 -0.90 0.86 0.35 147.7 M 4.2 69.7 4.4 363.94 2.63 147.74 363.91 0.01 -0.14 1.01 146.7 M 3.2 7.8 3.2 394.08 3.60 146.73 394.00 1.25 -1.52 1.90 146.9 M 3.2 -3.4 3.2 424.95 5.24 146.89 424.78 3.05 -3.51 3.20 -5.3 G 5.3 0.5 5.3 455.77 7.31 145.39 455.41 5.57 -6.30 5.08 -8.2 G 6.7 -4.9 6.7 486.58 9.22 143.67 485.90 8.80 -9.90 7.66 1.7 G 6.2 -5.6 6.3 515.83 10.71 143.91 514.71 12.45 -13.99 10.65 2.7G 5.1 0.8 5.1 545.23 12.10 144.22 543.53 16.66 -18.70 14.06 35.4 G 4.7 1.1 4.7 575.77 13.04 147.13 573.34 21.61 -24.19 17.80 47.5G 3.1 9.5 3.7 606.54 13.83 150.62 603.27 27.18 -30.31 21.49 49.2G 2.6 11.3 3.7 637.35 14.50 153.63 633.14 33.32 -36.97 25.01 38.2G 2.2 9.8 3.2 667.64 15.37 156.17 662.41 39.89 -44.04 28.31 52.3G 2.9 8.4 3.6 696.83 16.18 159.79 690.50 46.79 -51.40 31.28 39.4 G 2.8 12.4 4.4 726.31 17.27 162.75 718.73 54.39 -59.43 34.00 31.5 G 3.7 10.0 4.7 757.52 18.39 164.90 748.44 63.13 . -68.61 36.65 22.0 G 3.6 6.9 4.2 788.04 19.18 165.87 777.33 72.23 -78.12 39.13 31.9 G 2.6 3.2 2.8 818.83 19.86 167.11 806.35 81.83 -88.12 41.53 31.3 G 2.2 4.0 2.6 847.77 20.55 168.30 833.51 91.22 -97.89 43.66 38.3G 2.4 4.1 2.8 878.08 21.62 170.56 861.79 101.58 -108.61 45.66 50.1 G 3.5 7.5 4.4 908.61 22.74 173.92 890.07 112.69 -120.02 47.20 42.6 G 3.7 11.0 5.5 939.41 23.98 176.67 918.34 124.62 -132.19 48.20 50.9G 4.0 8.9 5.4 969.78 24.92 179.35 945.99 137.01 -144.75 48.63 44.7G 3.1 8.8 4.8 999.52 25.80 181.32 972.86 149.64 -157.49 48.55 57.8G 3.0 6.6 4.1 1029.73 26.54 183.87 999.98 162.91 -170.79 47.94 51.4 G 2.4 8.4 4.5 1059.94 27.26 185.80 1026.92 176.56 -184.41 46.79 49.2 G 2.4 6.4 3.7 1090.69 28.13 187.90 1054.15 190.85 -198.60 45.08 53.1 G 2.8 6.8 4.3 1121.14 28.54 189.03 1080.95 205.30 -212.89 42.95 -83.9 G 1.3 3.7 2.2 1153.07 28.57 188.47 1108.99 220.56 -227.98 40.63 1.1 G 0.1 -1.8 0.8 1184.72 29.36 188.50 1136.68 235.89 -243.13 38.37 -16.6 G 2.5 0.1 2.5 1215.60 30.17 188.02 1163.49 251.22 -258.31 36.17 -6.6 G 2.6 -1.6 2.7 1247.44 31.25 187.78 1190.87 267.48 -274.41 33.93 3.6G 3.4 -0.8 3.4 1278.36 32.27 187.90 1217.15 283.75 -290.53 31.71 11.8 G 3.3 0.4 3.3 1310.11 33.38 188;32 1243.83 300.96 -307.57 29.28 -40.2 G 3.5 1.3 3.6 1341.93 33.75 187.76 1270.35 318.55 -324.99 26.82 -99.4 G 1.2 -1.8 1.5 Survey @ 4105-TD.xls Page 1 of 2 **Projections and Interpolations in Italics** 7/25/2002-7:05 AM ( 1436.33 33.73 187.54 1348.85 370.99 -376.96 19.84 56.0 G -0.0 -0.2 0.1 1530.83 34.05 188.38 1427.29 423.68 -429.14 12.55 66.0G 0.3 0.9 0.6 1621.96 34.58 190.41 1502.57 475.02 -479.82 4.15 -17.9 G 0.6 2.2 1.4 1716.25 34.81 190.28 1580.09 528.63 -532.62 -5.48 -78.8 G 0.2 -0.1 0.3 1809.81 34.89 189.59 1656.87 582.05 -585.28 -14.71 -25.1 G 0.1 -0.7 0.4 1904.34 35.00 189.50 1734.36 636.16 -638.67 -23.69 -121.0 G 0.1 -0.1 0.1 1944.02 34.88 189.15 1766.89 658.88 -661.10 -27.37 -130.8 G -0.3 -0.9 0.6 2064.99 34.65 188.68 1866.26 727.84 -729.24 -38.06 -154.2 G -0.2 -0.4 0.3 2159.13 34.05 188.16 1943.98 780.95 -781.79 -45.84 -174.9 G -0.6 -0.6 0.7 2253.10 33.55 188.08 2022.07 833.23 -833.54 -53.22 -140.9 G -0.5 -0.1 0.5 2347.18 32.95 187.18 2100.75 884.81 -884.66 -60.07 -161.8 G -0.6 -1.0 0.8 2442.25 32.35 186.81 2180.80 936.10 -935.57 -66.32 -129.1 G -0.6 -0.4 0.7 2567.83 31.78 185.46 2287.22 1002.74 -1001.85 -73.45 -162.1 G -0.5 -1.1 0.7 2660.70 31.25 185.13 2366.39 1051.24 -1050.19 -77.93 -113.0 G -0.6 -0.4 0.6 2692.40 31.18 184.81 2393.50 1067.65 -1066.56 -79.36 -178.4 G -0.2 -1.0 0.6 2722.58 30.25 184.76 2419.45 1083.05 -1081.92 -80.64 178.9 G -3.1 -0.2 3.1 2754.06 29.02 184.81 2446.81 1098.59 -1097.43 -81.94 149.8 G -3.9 0.2 3.9 '2785.74 28.33 185.66 2474.60 1113.78 -1112.57 -83.33 175.7 G -2.2 2.7 2.5 2816.85 27.30 185.83 2502.12 1128.29 -1127.01 -84.78 -165.1 G -3.3 0.5 3.3 2848.74 26.30 185.23 2530.58 1142.66 -1141.32 -86.17 -159.3 G -3.1 -1.9 3.2 2879.42 25.45 184.48 2558.19 1156.03 -1154.66 -87.30 136.9 G -2.8 -2.4 3.0 2908.88 24.98 185.53 2584.84 1168.57 -1167.17 -88.39 -172.3 G -1.6' 3.6 2.2 2940.46 23.78 185.13 2613.60 1181.59 -1180.14 -89.61 176.1 G -3:8 -1.3 3.8 2972.20 22.65 185.33 2642.77 1194.09 -1192.60 -90.75 170.6 G -3.6 0.6 3.6 3004.07 21.48 185.86 2672.31 1206.06 -1204.52 -91.91 -165.5 G -3.7 1.7 3.7 3035.56 20.30 184.98 2701.73 1217.28 -1215.70 -92.97 176.8 G -3.7 -2.8 3.9 3066.45 19.40 185.13 2730.78 1227.76 -1226.14 -93.90 -172.6 G -2.9 0.5 2.9 3097.43 18.43 184.73 2760.09 1237.79 -1236.15 -94.76 -180.0 G -3.1 -1.3 3.2 3129.30 16.98 184.71 2790.45 1247.47 -1245.81 -95.56 -163.4 G -4.5 -0.1 4.5 3191.28 14.43 181.63 2850.11 1264.19 -1262.55 -96.52 150.4 G -4.1 -5.0 4.3 3284.72 14.33 181.86 2940.62 1287.27 -1285.75 -97.23 -177.5 G -0.1" 0.2 0.1 .- 3379.10 14.05 181.81 3032.12 1310.29 -1308.87 -97.97 -127.7 G -0.3 -0.1 0.3 3473.95 13.93 181.16 3124.16 1333.09 -1331.79 -98.57 6.7G -0."1 -0.7 0.2 3569.08 14.18 181.28 3216.44 1356.05 -1354.89 -99.06 -126.1 G 0.3 0.1 0.3 3662.77 13.98 180.13 3307.32 1378.67 -1377.68 -99.34 -137.3 G -0.2 -1.2 0.4 3754.76 13.80 179.43 3396.62 1400.55 -1399.76 -99.26 -106.2 G -0.2 -0.8 0.3 3848.83 13.70 177.91 3487.99 1422.63 -1422.11 -98.74 -77.0 G -0.1 -1.6 0.4 3943.68 13.75 177.03 3580.14 1444.78 -1444.60 -97.74 -125.2 G 0.1 -0.9 0.2 4036.76 13.45 175.16 3670.61 1466.23 -1466.43 -96.26 --- -0.3 -2.0 0.6 Projection to TD 4105.00 13.45 175.16 3736.97 1481.72 -1482.24 -94.92 -- 0.0 0.0 0.0 Survey @ 4105-TD.xls Page 2 of 2 **Projections and Interpolations in Italics** 7/25/2002.7:05 AM 'D-aily Operations Report, Well Name: SRU #213-10 Drill ( ~ ~ UNOCAL8 (: Date: Report #: July 26, 2002 13 Platform: SRU Project Objective: Field: Swanson River Rig: 129 Grass Roots Gas Well Drlg Contractor: Nabors Spud Date: 7/18/2002 Project: ~ days - hrs F/Spud: 8 days hrs Current Hole Size: 6.000 inches Present Depth: Drilling Hours: Footage Drilled: Average ROP: 4,105 ft hrs ft ftlhr RKB Height (ft): Last BOP Test: Pressure (High): Pressure (Low): 15.83 7/22/2002 3,000 250 AFE Cost: Daily Cost: Previous Cum: Cumulative Cst: $ $ $ $ 154978 1,672,923 63,196 662,433 725,629 HES Comments: None Days Without Accident: Safety MTGS.: 13.0 Date: I Spills: 0 I Spills to Date: 0 I AM Drill: PM Drill: Present Operation: Preparing to start cleaning mud tanks. Total POB: 19 76 DRLG: 1 Catering: Prod: -Welders: Rig Cont: 14 Other: Drilling 1: Donny Fowler Foreman 2: Jimmy Childress Pusher Rod Klepzig Casing Shoerrubing Information Size LB/ft MD TVD LOTfPPG 13 3/8" 68 92' 92' NA 7" 29 1987" 1802' 15.9 Slow Pump Rates: Pump: SPM Press: Liner: Strk: Depth 4 - Boats: 0 Helicopters: 0 L-U-P From To HRS Operations Detail '::::::::::~:::::::::::::::::~~:~2:::::::::~:::?::9.2:::::.........?.:.~9........9.¡:f.§'~!~!~::~:~~::f.~~!p.:p.!ë~::~!!5::~:~:::~!f.e.~~~::~~I!~::9.¡:f.§'~~~!¡:6:~::~r~~:~::~f.:~::~)J6::I9.?~::~~!:;::::::::::::::::::~:::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: "''''''''P'''''''''.'''''''Z:'ÕÕ''''''.''''''':r3õ''''''' ""'''Õ:'3Õ'''''' 'Rlëjgeëï"aõ\Ñï'¡"'ë¡¡:ë'liiat1'ñçjãQùfp''''Cãyëa''aõwï,'2jõmtšõftüb¡ñg"'wi,¡¡ëï:¡gg¡ñgëjõ;:;;ñc¡¡:ë~ïãfíñgtï~ãëi''''p;p-;;ïr;;:;ëfïõ"''''''''''''''''''''' . stIck wIth Sho€: at 41 ClO 1.5 off oottom,l Pullt:d 32M o'/er. stolng welgt',t to 70M and ~'ulled tr6e Had nc¡ lurtr,t:r ::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::~!!£~!~:~;:ef.~~(~~;::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::~::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::~:::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: P 2 30 ~\ ü(l Ü 30 Spacéd Oul luOlr,g WIng Wltr, :? 20 PuP Jt e 20' Pu¡:,. 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SRU #213.10 DriIl7.26-02.xls Page 1 of 2 Revised:7124/99 by MWD "D-aily Operations Report Well Name: SRU #213-10 Drill ~ UNOCALe ( Date: Report #: Aug ust 1, 2002 19 Platform: SRU Project Objective: Field: Swanson River Rig: 129 Grass Roots Gas Well Drlg Contractor: Nabors Spud Date: 7/18/2002 Present Depth: Project: ~ days - hrs Drilling Hours: F/Spud: 14 days hrs Footage Drilled: Current Hole Size: 6.000 inches Average ROP: 4,105 ft RKB Height (ft): hrs Last BOP Test: ft Pressure (High): ftIhr Pressure (Low): 15.83 7/22/2002 3,000 250 AFE Cost: Daily Cost: Previous Cum: Cumulative Cst: $ $ $ $ 154978 1,672,923 20,049 861,893 881,942 HES Comments: None Days Without Accident: 19.0 Date: I Spills: 0 I Spills to Date: 0 I AM Drill: Safety M I GS.: Morning safety meeting with Peak. Safety meeting with Schlumberger wîreline crew, I PM Drill: Present Operation: Shut down for night. Casing ShoelTubing Information Size LB/ft MD TVD LOT/PPG 13 3/8" 68 92' 92' NA 7" 29 1987" 1802' 15.9 Slow Pump Rates: Pump: SPM Press: Liner: Strk: Depth Preparing to rig up Pollard wireline to Swab. Total POB: 2 Drilling 1: Jimmy Childress 76 DRLG: 1 Catering: Foreman 2: Prod: -Welders: Pusher Rig Cont: 0 Other: 1 - Boats: 0 Helicopters: 0 L-U-P From 10 HRS Operations Detail ,::::::::::~:::::::::::::::::9.~:QQ:::::::::::::T@::::::........!:.9.2......:§.~p.r~?~~::f.~f.::~!~:~~:;::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::~:::::::::~::::::::::::::::::::::::::::::::::::::::::::::~:::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: P ì 00 7 :W 0 :10 p ;" 30 9 2u (JI,) Wa,l (,n Sctllumcerger 10 inn"", on localle,n 5ehlumOi:trger on location aT 07 2:. hrs. ., SPOl SChlumt,€:rgers eqUipmenl on Hercuhle: Imer Rigged IJP logging un¡¡ Held ~a1etv meellng and lob dl~,:u'S~lc.n with logging C,'t?,^' T eSI€-,j lubrlt:ator with BOP leSI pump and fresh waler to 1500 PSI hel~ 01' '"'''''''P'''''''''-'''''''§''3Õ''''''~''''''''J'''3Õ''''' '''''''s''ë:õ'''''' 'P;ckeëf~p"SëiïïÜJïïbëj'igË~?š"r:'r=;ïTf,::";¡"'3Š"¡F'c'B'OGRïCC'['ïë:g'i~¡ñg"tõõr"Ri~ñ"¡ñ"iï'õie"tõ"J'ÕT3¡"ãñ'a"tã'çge(j..t:ÕtfÓïT;-""'''''''''''''''''''''' Logged up from 4013 10 surface Rar, repeal c¡,e,::tIOr. trom 1e.50 to 21(,0 All deplhs correllaled with Platlorm "''''''''~'''''''''-''''''14'''3'Õ''''-''''''nrÕÕ'''''''''''''r3õ''''''Tãia''dõ'wñ'Ïõg'giñ'g'tõ'õïs"ãñëriiggëëfaõW:¡:¡"s'ëïïiü'm'bË3rger""Prõëflj'cffõñ'T5"šetHñg"Tñ"ãñër¡:Tg9¡ñg"up"flõvj'te'št¡ïï:~'"................................ eQUlpm~nl S.:hlumCerger off locallc.\n at 16 15 hrs Le:" SChlumocrger & crane on locallon for POllard s u\:-e . when swat>t"ng and f~r upcomIng perforating run. . . . 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SRU #213-10 Drill 08-01-02.)(\5 Page 1 of 2 Revi5ed:7124/99 by MWD ALASKA OIL AND GAS CONSERVATION COMMISSION PETROLEUM WEl']J RECORD - Commission use only - 10/10/2002 +----------------------------------------------------------------------+ PERMIT API WELL WELL LEASE -~~~~-- ---~~~~--- ------~~~----------I--~~~~--I~~~=I--~~~~-- 202-118-0 133-20515-00 SWANSON RIV UNIT 213-10 FEDA028405 +--------------------------------------------------------------------------+ I OPER OPERATOR GEOLOGIC ONOFF MULTI :~~~-I-------------~~~-------------- :~~~I------~~~~------- ~~~~~ ~=~~~ ~145000 UNION OIL CO OF CALIFORNIA 820 COOK INLET BASIN ON +--------------------------------------------------------------------------+ FLDPOL FIELD AND POOL MULTIPLE POOLS -:~~~-I------------~~~---------------- ~~~~~~I~~~~~~I~~~~~~I~~~~~~I~~~~~~ 772500 SWANSON RIVER, UNDEFINED 000000 000000 000000 000000 000000 +--------------------------------------------------------------------------+ UNIT UNIT ELEVATIONS DEPTHS NOM +~~~~~~~~~~~~~~~~~~:::~~~~~~~~~~~~~~~-~~~J[~~~;~~~::~~~~~f~+ ~~~=I~=~I~~~=I~=~I~~:I=~~I-~~I~~~ ~~~=I~~~I~~~=I~~I~:I=~~I-~~I~~ 172 N 0628. ~~--~~~-~~~~--~-~--~~--~~--~~~c~~~~--~c-----+ ~~~I~~~I-~~~- ~~?ï;~~I~~~- =~I~~~~~I=~~I~~~~-I~~I~~~=-~ ~- ---------------------------------------------------------------~---------+ '-"' INITIAL FINAL CURRENT REQUIREMENTS ~ SALES +~~~~~~~~~~-~J[)~~~~~~-~~~~~~~~~~_~~~~I~~~~~~~~~=~~~-~~_~~~~~I~+ PERMIT PERMIT DATE DATE DATE OF-~CORD I CONFID APPROVED ISSUED SPUDDED COMP, ETC CUR STATUS LAST UPDTD CODE +~~~~~~~~~~-~~~~~~~~~~-~~~~~(¿[~~~~~~~~-~~~~~~~~~~-~~~~~~~~~~~~~~~~~~~+ 0:2 ð¿ ;)It,3 --- 7 b ~ 9 35(- ~(¿3( 11 ¡-g N to 3:3 VV I yf~ <15 \ - . '-. Jd OðN -53 8 vJ //) ~ j\\ ^ "\. LJ 0() ~ ? <) /~ ? .. ALASKA OIL AND GAS CONSERVATION COMMISSION PETROLEUM WELL HISTORY PRE-AUDIT REPORT 10/14/2002 OPER FLD/PL CODE CODE + T PERMIT + R NUMBER + - ------- 1 C 2021180 + ----------------------------------------------------------------------------+ + MULTIPLE SURFACE LOCATION BOTTOM HOLE LOCATION + POOL CODES FEET D FEET D SE TWP RNG M FEET D FEET D SE TWP RNG M ; ---1---1---1---1--- ---- - ---- - -- --- ---- - ;;~~ ~ -~;~ ; ~~ ~~~ ~~;; ~ PERMIT PERMIT REQUIRD L API INITIAL APPROVED ISSUED S M D 0 T NUMBER CLS STATS ---------- ---------- - - - - - ---------- -- - ----- / / / / R + ----------------------------------------------------------------------------+ + WELL WELL ELEVATIONS LEASE DEPTHS + NAME NUMBER SORT CD FEET CD FEET NUMBER MD TVD + -------------------- ---------- ---- -- ---- -- ---- ---------- ----- ----- 3 KB 16 4105 3737 + -----------------------------------------------------------------------------+ UNIT GEO ON CONFD LATITUDE LONGITUDE FOOTAGE DRILLED NO ARA OFF CODE DE MN SEC DEG MN SEC YEAR FEET YEAR FEET YEAR FEET ~---- --- --- ----- -- -- ----- --- -- ----- ---- ----- ---- --------- ----- 4 + -----------------------------------------------------------------------------+ + DATE DATE FINAL CURRENT DATE OF SL ACT NUM SSSV PERM F + SPUDDED COMP,ETC CLS STATS CLS STATS CUR STATUS CD GRP COM DEPTH THCK M + ---------- ---------- --- ----- --- ----- ---------- -- --- --- ----- ---- - 5 07/18/2002 08/04/2002 DEV I-GAS / / *1* + $$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$+ .~- ALASKA OIL AND GAS CONSERVATION COMMISSION PETROLEUM WELL HISTORY UPDATE REPORT 10/14/2002 6. PERMIT NUMBER 202-118-0 UPDATED. ** END OF UPDATE. THERE ARE 6038 RECORDS ON THE WELL HISTORY MASTER FILE. ~ , ' Unocal Corporation ( P.O. Box 196247 Anchorage, AK 99501 Telephone (907) 263-7660 UNOCAL8 Jim Mosley Senior Advising Drilling Engineer Friday, September, 13, 2002 Alaska Oil and Gas Conservation Commission 333 West ih Avenue Anchorage, Alaska 99501 Attn: Commissioner Cammy Taylor Re: SRU 213-10 WELL PERMIT # 202-118 API # 50-133-20515-00 Dear Commissioner Taylor, Enclosed is a Sundry Notice Form 10-407 Completion Report as per the approved permit to drill. We have successfully drilled and completed the well. The date of testing was 4 August 02. Please accept my apologies for this report being slightly late. Should you need more details please do not hesitate to ask. As you will know we asked for and obtained permission to drill and complete this well as a Tubingless completion. The cementing of the production tubing went extremely well. Cement was circulated to the surface and the plug was bumped with 2900 psi on 26 July 02. We are calling this pressure test the initial mechanical integrity test on the well. Your approval called for a mechanical integrity test to be done annually. We did run a nipple profile in the well and will use this nipple to set a plug and perform the annual MIT next year (via negative pressure testing). The annual pressure test will set a plug in the profile nipple and bleed the tubing pressure to zero. We trust that this will meet with your approval. The Required CBL was run on 1 August and indicated excellent cement from TD to Surface. As you know we also have asked for a Field Wide Conservation Order on the Swanson River Field to allow for Tubingless completions. We sincerely believe that this completion configuration will increase the number of wells we can economically drill. Your assistance with this Conservation Order Request is sincerely appreciated. Thank you for your help in maintaining an efficient operation. If there are any questions, please contact Jim Harrison at 263-7809 or Jim Mosley at 263-7679. Sincerely, Jim Mosley ~~ JH/jm Enclosure Senior Advising Drilling Engineer UnocalAlaska RI@11VED SEP 21 2002 AIaSt<a CI& Gas Oons. GommtlS\oo Anchorage i I "- .,¡I iii' Unocal Alaska 909 W. 9th Avenue Anchorage, AI< 99501 Tele: (907) 263-7651 Fax: (907) 263-7828 E-mail: harrisonb@unocal.com UNOCALe Beverly Harrison Business Ventures Assistant To: AOGCC . Lisa Weepie . 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 aO;)-}l~ September 23, 2002 A-29RD A-29RD A-29RD A-29RD A-29RD A-29RD A-29RD ~ A-29RD B A-29RD \ A-29RD ~ I A-29RD 't ,. A-29RD ¡ A-29RD I A-29RD ¡ A-29RD i ¡ A-29RD ! ¡ A-29RD ! ! A-29RD i - I A-29RD ~ tto-oosl D-15RD2 - ! D-15RD2 ¡ DI-15 1 (p-ot/51 DI-15 . I ~"OS1! DI-16 \0\ ¡ DI-16 . ì" ú) I G-12RD3 rJ) ¡ G-12RD3 <9 I G-12RD3 'õ 0 <õ DATA TRANSMITTAL - ADN DIP DATA V" ADN DIP DATA Ý ADN DIP DATA V ADN DIP DATA v CEMENT BOND lOG / GR / CCL V CEMENT BOND lOG / GR / CCl v' CEMENT BOND lOG / GR / CCl V' CEMENT RETAINER CASING PUNCHER / CEMENT RETAINER CASING PUNCHER V EPOCH FINAL WELL REPORT WI FORMATION LOG ./ EPOCH FINAL WELL REPORT WI FORMATION LOG V EPOCH FINAL WELL REPORT WI FORMATION lOG V MWD/GR MD COMPOSITE FIELD PRINT V PERFORATION DEPTH CONTROL MEMORY GR I CCL V' PERFORATION DEPTH CONTROL MEMORY GR / CCL V PERFORATION RECORD 2 7/8" PJ HSD 6 SPFV PERFORATION RECORD 2 7/8" PJ HSD 6 SPF V SCHLUMBERGER FORMATION EVALUATION lOGS v VISION SERVICE MD COMPOSITE FIELD PRINT V PL ADVISOR /INJECTION PROFILE MEMORY PL T WIFLOVIEW v PL ADVISOR /INJECTION PROFILE MEMORY PL T W/FLOVIEW v COMPLETION RECORD 2" HSD, POWER JETS v COMPLETION RECORD 2" HSD, POWER JETS v' COMPLETION RECORD 2" HSD, POWER JETS v COMPLETION RECORD 2" HSD, POWER JETS / COMPLETION RECORD 10' CEMENT PLUG V COMPLETION RECORD 10' CEMENT PLUG ¡/" COMPLETION RECORD 2.5" HSD PJ V 2/5 INCH 2/5 INCH 2/5 INCH 5 INCH 5 INCH 2 INCH 2 INCH 2 INCH 2 INCH 5 INCH 5 INCH 2 INCH 5 INCH 5 INCH 5 INCH 5 INCH 5 INCH 5 INCH 5 INCH 5 INCH 5 INCH 8/2/2002 8/2/2002 8/2/2002 8/2/2002 8/5/2002 8/5/2002 8/5/2002 6/30/2002 8/1/2002 8/1/2002 6/30/2002 8/10/2002 8/10/2002 8/28/2002 8/28/2002 8/212002 6/30/2002 3/17/2002 3/17/2002 5/11/2002 5/11/2002 5/9/2002 5/9/2002 6/29/2002 6/29/2002 6/21/2002 12606-13220 1 B-Line 11950-12650 1 B-Line 12606-13220 1 CD 12029-12713 1 CD 5000-13211 1 B-Line 5000-13211 1 CD 5000-13211 1 Film 1680-1999 1 B-Line 1680-1999 1 Film 1786-13300 3 B-Line 1 CD 1 PAPER 1824-12685 1 B-Line 12720-13240 1 B-Line 12720-13240 1 Film 13100-13207 1 B-Line 13100-13207 ¡ 1 Film 1 CD 1824-13300 1 B-Line 9150-10050 1 B-Line f ¥ 9150-10050 1 CD 11950-12555 1 B-Line 11950-12555 1 Film 9800-1077 1 B-Line 9800-1077 ! 1 Film 13150-13608 1 B-Line 13150-13608 1 Film 13100-13696 1 B-Line Please acknowledge receipt by signing and returning one copy of this transmittal or fi~~. . §\I. 3-lE.~t,.~...~.......... "' ¡¡. . ~ ~ .. ':bA,I,. .. ~ Received d( ~ Date: Ocr 0;) 2~O2 Af'!:òl:'ì.-. ."",:'~ ,. - g~l\a viï & Ga$ COnEt OJmmiSSion Anchorage f' .1\ ~ ~njJ Q' COMPLETION RECORD 2.5" HSD PJ y/' I 51NCH COMPLETION RECORD POSISET PLUG 15' CEMENT V I 51NCH COMPLETION RECORD POSISET PLUG 15' CEMENT -/ I 51NCH COMPLETION RECORD POSISET PLUG 15' CEMENT V I 51NCH PERFORATING DEPTH CONTROL MEMORY GR / CCL .r I 51NCH PERFORATING DEPTH CONTROL MEMORY GR / CCL V- ! 51NCH COMPLETION REPORT 2" HSD POWER JETS ,./ I 5 INCH COMPLETION REPORT 2" HSD POWER JETS......... ! 5 INCH ¡ EPOCH MUD LOG V I 2 INCH EPOCH MUD LOG ./ I 2 INCH COMPLETION RECORD 2" HSD POWER JET V I 5 INCH COMPLETION RECORD 2" HSD POWER JET V I 5 INCH GR / CCL CORRELATION FLUID LEVEL DETERMINATION V 5 INCH GR / CCL CORRELATION FLUID LEVEL DETERMINATION V' 5 INCH COMPLETION RECORD 2" PJ HSD, 6 SPF V 5 INCH COMPLETION RECORD 2" PJ HSD, 6 SPF V' 5 INCH COMPLETION RECORD 2" PJ HSD, 6 SPF V 5 INCH COMPLETION RECORD 2" PJ HSD, 6 SPF V 5 INCH GR / CCL / PRESSURE / TEMPERATURE / TOP OF FLUID DETERMINATION V 5 INCH GR / CCL / PRESSURE / TEMPERATURE / TOP OF FLUID DETERMINATION ......--- 51NCH GR / CCL / TEMPERATURE / PRESSURE / TOP OF FLUID, SAMPLE ,¡/'"" 5 INCH GR / CCL / TEMPERATURE / PRESSURE / TOP OF FLUID, SAMPLE ~ 5 INCH GR / CCL TEMPERATURE, PRESSURE TOP OF FLUID, SAMPLE V 5 INCH GR / CCL TEMPERATURE, PRESSURE TOP OF FLUID, SAMPLE V 5 INCH COMPLETION RECORD 111/16" POWER PIVOT ./ 5 INCH COMPLETION RECORD 111/16" POWER PIVOT ¡/' 5 INCH COMPLETION RECORD POSISET PLUG 20' CEMENT PLUG ,/ 5 INCH CEMENT RETAINER CPST SETTING TOOL""'" 5 INCH MD FIELD PRINT ./ 2/5 INCH NEUTRON / GR / CCL ./ 2/5 INCH NEUTRON / GR / CCL V 2/5 INCH ¡ 5.5" THRU-TUBING POSISET PLUG CEMENT DUMPT BAILER 25' CEMENT PLUG~ 5 INCH I ¡ 5.5" THRU-TUBING POSISET PLUG CEMENT DUMPT BAILER 25' CEMENT PLUG f51NCH 2" HSD POWER JET 6 SPF COMPLETION RECORD v I 5 INCH ARRAY INDUCTION / DENSITY / CNL / GR / SP / CALIPER / PEX v ARRAY INDUCTION / DENSITY / CNL / GR / SP / CALIPER / PEX ./' CEMENT BOND LOG / GR / CCL ......... (2 G-12RD3 q G-12RD3 ~ G-12RD3 ~ G-12RD3 cP1 K-30RD 10~ K-30RD LRU C-1RD LRU C-1RD \D~O-1 \ ~~ \0 NNA-1 é) NNA-1 \ NNA-1 Õ ~ NNA-1 PEARL-1 PEARL-1 PEARL-1 PEARL-1 :::: PEARL-1 0 PEARL-1 I (t) PEARL-1 CJ PEARL-1 ~ PEARL-1 PEARL-1 SRU 12-15 Od-d- SRU 12-15 lðY' SRU 12-15 SRU 12-27 SRU 12-27 SRU 12-27 SRU 12-27 SRU 212- 27 SRU 212- 27 , SRU 213- 10 SRU 213- 10 SRU 213- 10 SRU 213- "()o 10 - SRU 213- \" 10 ~ S10RU 213- COMPENSATED NEUTRON LOG IN CASING v Q SRU 213- (\5 10 SLlMPULSE / GR / MD / FIELD PRINT / SRU 213- 10 SLlMPULSE / GR / VD / FIELD PRINT / SRU 23 33 111/16 ENERJET GUN COMPLETION REPORT V \ to 1 ,019 - CEMENT BOND LOG/GR/CCL v 5 INCH 5 INCH ; 51NCH i I 51NCH i 5INCH 2/5 INCH ! 2/5 INCH I 51NCH 6/21/2002 ¡ 13100-13696 6/27/2002 113150-13670 6/27/2002 I 13150-13670 ; 6/27/2002 ! 13150-13670 2/8/2002 ! 9544-12045 ! 2/8/2002 ¡ 9544-12045 7/15/2002 5300-5975 7/15/2002 5300-5975 10/31/1999 1473-6430 10/31/1999 ' 1473-6430 4/3/2002 8600-9750 4/3/2002 8600-9750 4/2/2002 8600-9790 4/2/2002 8600-9790 3/29/2002 5420-6066 3/29/2002 3690-4250 3/29/2002 5420-6066 3/29/2002 3690-4250 3/28/2002 3550-6954 3/28/2002 3550-6954 3/29/2002 3550-6607 3/29/2002 3550-6607 3/29/2002 100-6948 3/29/2002 100-6948 5/16/2002 5400-5600 5/16/2002 5400-5600 3/13/2002 4600-5642 6/27/2002 5600-6346 6/29/2002 6044-6912 6/26/2002 5600-6340 6/26/2002 5600-6340 8/20/2002 6025-6050 8/20/2002 6025-6050 8/4/2002 3800-4000 7/24/2002 1987-4105 7/24/2002 1987-4105 8/1/2002 0-4014 8/1/2002 0-4014 7/24/2002 1987-4105 7/18/2002 1952-4105 7/18/2002 1952-4105 5/19/2002 I 10350-10625 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 Film B-Line CD Film B-Line Film B-Line Film B-Line Vellum B-Line Film B-Line Film B-Line B-Line Film Film B-Line Film B-Line Film B-Line Film B-Line Film B-Line B-Line B-Line B-Line CD B-Line CD B-Line B-Line CD B-Line CD B-Line 2 B-Line 2 B-Line 1 B-Line Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to (907) 263-7828. ~= f"'% ~ ¡ t: ;."""v~~ ~=~ ReœiVedBY~l~~ Date: nv!rT A':?, ...... \.) ,j & Weekly Report for SRU 213-10 Subject: Weekly Report for SRU 213-10 Date: Wed, 24 Jul 2002 12:03:43 -0700 From: "Mosley, Jim I" <mosleyj@unocal.com> To: "'greg_noble@blm.gov'1I <greg_noble@blm.gov> CC: "'Tom_Maunder@admin.state.ak.us'" <Tom_Maunder@admin.state.ak.us> -, ~ "', \ (/' c)\..)CJ-\ ~ Greg. Here is a summary of our weekly activity on the SWanson River Unit 213-10 well. July 14- Rig Released from KGSF location. 13-3/8" Conductor preinstalled on 213-10 locationb to 76' below Grade. July 15 - Began Turnkey Rig Move July 16 - Turnkey Rig Move July 17 - Turnkey Rig Move and Rig Up finished at 2400 Hours July 18 - Rig Accepted 0000 Hours. Tested Diverter. PU 12-1/4" Bit and washed out Conductor to 120'. lD 12-1/4" & PU 8-1/2" BHA. Drilled to 300'. July 19 - Directìonally Drilled to 1868' July 20 - Drilled to 2000' and made wiper Trip. Started Running 7" 26# Surface Casing. July 21 - Finished running 7" to 1989. Cemented 7" with 75 bbls of 12.5 ppg lead and 18 bbls of 15.8 Tail. Cement circulated to Surface. NO Diverter and NU BOPE July 22 - Finished NUBOPE and Tested same. PU 6" BHA and RIH. Tested Casing to 2500 psi. Drilled Cement and Float Equipment. July 23 - Drilled out to 2025'. Circulateed and Conducted Casing Shoe Integrity Test to 15.9 ppg Equivalent. Directionally Drilled to 3464' July 24 - Drilling ahead. Expect to TD this morning and will run Platform Express log. Greg, I will keep you posted as to the outcome of the logs. Jim Mosley Jim Mosley Sr. Advising Drilling Engineer Unocal Alaska Union Oil Company of California 909 W. 9th Ave. P.O. Box 196247 Anchorage Alaska 99519-6247 OffICe 907-263-7679 CeH 907-351-8639 Home 907-694-4170 Fax 907-263-7884 EMAll Mosleyj@Unocal.com 1 of 1 7/26/20027:18 AM ( STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West Seventh Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF Union Oil of California ("UNOCAL") for an order Allowing well SRU 213-10 to be completed Without a tubing and packer. ) Conservation Order No. 474 ) Swanson River Field ) Swanson River Undefined Gas Pool ) Swanson River Unit Well 213-10 ) ) July 17, 2002 IT APPEARING THAT: 1. By application dated June 11, 2002, and received by the Alaska Oil and Gas Conservation Commission ("Commission") on June 11, 2002, Union Oil Company of California ("Unocal") requested an order from the Commission allowing the proposed Swanson River Unit ("SRU") 213-10 well to be completed without a tubing and packer as required by 20 AAC 25.200(d). 2. Notice of opportunity for public hearing was published in the Anchorage Daily News on June 17,2002 in accordance with 20 AAC 25.540. 3. Unocal submitted additional infonnation concerning the application by letter dated June 25,2002. 4. The Commission received no comments concerning the application or requests for a public hearing. 5. The Commission decided to issue an order without public hearing. FINDINGS: 1. Unocal is operator of the Swanson River Field. 2. Unocal proposes to drill the SRU 213-10 well to a depth of approximately 3735 feet TVD (4106' MD), from a surface location 1725 feet from the north line ("FNL") and 628 feet FWL, Section 10, T8N, R9W, SM to a bottom hole location of 31 03 feet FNL, 552 feet FWL, Section 10, T8N, R9W, SM. 3. Unocal proposes to drill the well using a slim hole drilling technique, running small diameter casing, and completing the well without a tubing and packer. 4. Commission regulation, 20 AAC 25.200(d), states: "All producing wells capable of unassisted flow must be completed with down hole production equipment consisting of suitable tubing and a packer that effectively isolate the tubing-casing annulus from fluids being produced, unless the commission specifically approves production through the annulus to increase flow rate without jeopardizing ultimate recovery from the well." ( ( 5. Commission regulation, 20 AAC 25.990(26), defines fluids as "any material or substance that flows or moves, whether in a semi-solid, liquid, sludge, gaseous, or other fonn or state." 6. Unocal is drilling the SRU 213-10 in order to produce gas reserves updip from the watered out SRU 212-10 well located on the same pad. The gas reserves developed contain methane with no H2S or CO2 which reduces risk of internal corrOSIon. 7. F onnation pressure of the Beluga fonnation sands being produced ranges from nonnal hydrostatic, 8.6 ppg to about 6 ppg equivalent. 8. Producibility and viability of the well will depend on maintaining mechanical integrity of the casing. 9. Unocal proposes to construct the SRU 213-10 well as follows: 133/8 inch conductor casing driven to 80 feet, 7 inch L-80 surface casing run to 1800 feet TVD (1979' MD) and cemented to surface, and 3~ inch L-80 production casing run to TD and cemented to the surface. 10. The 312-inch production casing will be cemented with a two-stage cement job consisting of a low weight lead slurry and conventional tail slurry to isolategas bearing productive zones. 11. The 7-inch production casing will be set just below the maximum depth of fresh water and just above the targeted gas bearing shallow production zones. The anticipated leak off on the 7 -inch surface casing shoe is anticipated to be about 15.5 ppg equivalent. 12. Maximum anticipated surface pressure for the targeted depleted gas sands is expected to be around 600 to 800 psi. 13. The small diameter production casing precludes running a tubing and packer. 14. Without a tubing and packer, there are fewer options available for perfonning cleanouts and remedial work. Mechanical integrity failure could lead to the early abandonment of the well. CONCLUSIONS: 1. The SRU 213-10 well is targeting dry methane gas reserves and is not expected to encounter liquid hydrocarbons. 2. The targeted gas reserves are capable of unassisted flow to surface, but only after hydrostatic pressure has been removed. 3. An exception to 20 AAC 25.200(d) is necessary to allow the drilling and completion of the SRU 213-10 well without a tubing and packer. 4. Gas produced by the 213-10 Well has no potential for corrosive products. 5. Mechanical integrity may only be tested on the inside of the production casing. 6. Failure of mechanical integrity will cause the well to be abandoned. Conservation Order No. 474 July 17,2002 Page 2 of3 ( ( 7. The drilling and completion of the SRU 213-10 well without a tubing and packer may result in a greater recovery of hydrocarbons, and will not cause waste nor jeopardize correlative rights. NOW, THEREFORE, IT IS ORDERED THAT: Unocal's application for an exception to 20 AAC 25.200(d) to allow the drilling and completion of the SRU 213-10 well without tubing and packer is approved subject to the following conditions: 1. A cement quality log must be run from TD to 200 feet into the surface casing prior to perforating the well. 2. A plug seating profile must be provided above the perforations or prospective perforation intervals to accomplish internal integrity tests. 3. Mechanical integrity must be demonstrated annually. 4. Each annuli pressure must be monitored daily and reported to the Commission quarterly. 5. Any pressure noted on the inner or outer annuli must be reported to the Commission on the next working day. The operator must implement corrective action, diagnostic work or increased surveillance as required by the Commission and obtain approval from the Commission to continue production operations at the well. 6. Failure to repair or prove mechanical integrity will result in expedited abandonment of the well. AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the Commission an applicatiön for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the 10-day period. An affected person has 30 days from the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order ofthe Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the Commission, the 30-day period for appeal to Superior Court runs from the date on which the request is deemed denied (i.e., lOth day after the application for rehearing was filed). Conservation Order No. 474 July 17, 2002 Page 3 of3 ( STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West Seventh Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF Union Oil of California ("UN OCAL") for an order granting an exception to the spacing requirements of 20 AAC 25.055(a)(4) to provide for the drilling and completion of the SRU 213-10 well in an undefined gas pool. IT APPEARING THAT: ) Conservation Order No. 475 ) ) Swanson River Field ) Swanson River Undefined Gas Pool ) Swanson River Unit Well 213-10 ) ) July 17, 2002 1. UNOCAL by letter dated June 3, 2002 has requested an order allowing a spacing exception to drill and test the Swanson River Unit ("SRU") 213-10 well in accordance with 20 AAC 25.055. The proposed well will be the second well drilled to Section 10, T8N, R9W, Seward Meridian ("S.M."), and it will be closer than 3,000' to an offset well capable of gas production. 2. The Commission published notice of opportunity for public hearing in the Anchorage Daily News and in the Peninsula Clarion on June 14, 2002,. pursuant to 20 AAC 25.540. 3. No protests to the application were received. FINDINGS: 1) The surface location of this well is 1725' from the north line ("FNL") and 628' from the west line ("FWL") of Section 1 0, T8N, R9W, S.M. The projected bottom hole location for this well is 3018' FNL, 465' FWL, of Section 10, T8N, R9W, S.M. 2) An exception to the well spacing provisions of20 AAC 25.055 (a)(4) is necessary for the drilling of this well as it will be the second well drilled to Section 10, T8N, R9W, S.M., and it will be closer than 3,000' to offset gas production well SRU 212-10 within the same pool. 3) UNOCAL sent notice of the application for spacing exception by certified mail to all offset owners, landowners, and operators of all properties within 3000' of the proposed SRU 213-10 well. ( CONCLUSIONS: 1) An exception to 20 AAC 25.055(a)(4) is necessary to allow drilling and completion of the SRU 213-10 well. 2) Granting a spacing exception to allow drilling and completion of the SRU 213-10 well will not result in waste or jeopardize the correlative rights of adjoining or nearby owners. NOW, THEREFORE, IT IS ORDERED: UNOCAL's application for exception to the well spacing provision of 20 AAC 25.055(a)(4) for the purpose of drilling and completing the SRU 213-10 well is approved. DONE at Anchorage, Alaska and dated July 17, 2002. ~9IL ~ð (f~~\ I I~~ '~ ..'\ / "'Y- 1\ . - '<JÞ ," .,. ......."" j. .~~~:~~~,.~ , r-~¡ I ¡"A,,~~ ~1l ¿,? "'111 ~ .~.. . . ~ , . , c'. C,. '\ ..n.~~ '. .". '-..., .' . t 1 it -, ., "'. .:...... ""-'."...... '... . . ,..' ~~ ,.,. -,-,.'.. Æ "\" :~" -~~.:[;. ~ ~~;~~.,; . ~-:)', >'~~_:~tl'';~ r !n~,~;/ AS 31.05 ~J/tðé~tDQr~ttìfh 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the Commíšsi6n"'~plication for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the 10-day period. An affected person has 30 days from the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the Commission, the 30-day period for appeal to Superior Court runs from the date on which the request is deemed denied (i.e., 10th day after the application for rehearing was filed). Conservation Order No. 475 July 17, 2002 Page 2 of 2 Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Swanson River Unit 213-10 Well . A-028405 and A-028077 Section 10, T8N, R9W, Seward Meridian Kenai Peninsula Borough, Alaska Unocal Alaska by application for a Permit to Drill dated June 11, 2002, and received by the Commission on June 11, 2002, has requested an exception to the production equipment requirements of 20 AAC 25.200(d) to complete the well as a tubingless, packerless development gas well. Surface Location: 1725 feet FNL and 628 feet FWL, Section 10, T8N, R9W, SM Anticipated Productive Interval: 2818' FNL, 590' FWL Bottom Hole Location: 3103' FNL, 552' FWL, S10, T8N, R9W, SM The Commission has tentatively set a public hearing on this application for July 23,2002 at 9:00 am at the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. A person may request that the tentatively scheduled hearing be held by filing a written request with the Commission no later than 4:30 pm on July 2, 2002. If a request for a hearing is not timely filed, the Commission will consider the issuance of an order without a hearing. To learn if the Commission will hold the public hearing, please call 793-1221. In addition, a person may submit written comments regarding this application to the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Written comments must be received no later than 4:30 pm on July 17, 2002, except that if the Commission decides to hold a public hearing, written comments must be received no later than 9:00 am on July 23, 2002. If you are a person with a disability who may need a special modification in order to comment or to attend the public hearing, please contact Jody Colombie at 793-1221 before July 19, 2002. (ß ~-~ C~ChSli Taylor, Chair Published Date: June 17,2002 ADN AO# 02214044 Published Date: June 17,2002 Clarion AO# 02214043 Unocal well 213-10 Subject: Unocal weD 213-10 Date: Mon, 15 Jul2002 15:33:36 -0700 From: "Johnston, David W -Contract" <johnstond@unocal.com> To: "Oechsli, Camille -Vendor" <Cammy_Oechsli@admin.state.ak.us>, "'tom - maunder@admin.state.ak. us'" <tom - maunder@admin.state.ak.us> Cammy, Tom Unocal asked me to prepare a draft conservation order for your consideration for its well 213-10 tubingless completion application. We understand that Dan may be out of the office, and because the well is a top priority, it is hoped that the attached draft may speed things along, ie, that the conservation order can be signed before Dan leaves. Ideally, Unocal would like approval of its request to complete the well without tubing and packer as soon as possible. I hope the attached document helps. Call me at 440-8706 if you have questions. Dave J. «WeIl213-10.doc» Name: Well 213-10.doc ,IWe11213-10.doc Type: WINWORD File (application/msword) Encoding: base64 lofl 7/16120027:11 AM Unocal Corporation P.O. Box 196247 Anchorage, AK 99501 Telephone (907) 263-7660 UNOCALe Jim Harrison Drilling Manager Monday, July 15, 2002 Alaska Oil and Gas Conservation Commission 333 West ih Avenue Anchorage, Alaska 99501 Attn: Commissioner Cammy Taylor Re: Amendment to Application for Permit to Drill (Form 10-401) SRU 213-10 PERMIT # 202-118 API # 50-133-20515-00 Dear Commissioner Taylor, Enclosed is a Sundry Notice Form 10-403 asking permission to amend the permit to drill for the Referenced SRU 213-10 well. This Sundry asks that we be allowed to change the well plan from a liner and tieback to a long string of Tubing. The proposed configuration we are seeking approval of is the Tubingless completion. As you know we have asked for a Conservation Order for this well. The public notice went out on 17 June and has been public for 30 days. AS you know we are tring to keep the rig from shutting down and having a costly delay in operations. Thank you for your help in maintaining an efficient operation. The Rig will be moving to the new well on or about the 16th of July. Your timely approval is respectfully requested. If there are any questions, please contact Jim Harrison at 263-7809 or Jim Mosley at 263-7679. Sincerely, , "- ~-~~ h-\~~ Jim Har~ ,-,I Drilling Manager Unocal Alaska JH/jm Enclosure RECEIVED JUL 1 5 2002 ORt I~~J/~L Alaska OU & Gas Gons. CommiSSIOn Anchorage 1. Type of request: STATE OF ALASKA ALLJ \ OIL AND GAS CONSERVATION COM~¡ ~ION ", .-\PPLlCATION FOR SUNDRY APPROVAß.. Abandon - Suspend - Operations shutdown - Re-enter suspended well - Alter casing - Repair well - Plugging - Time extension - Stimulate- Change approved program L Pull tubing Variance Perforate Other - f;f~ 0 ì II (, ÆT- ~I l <0 2. Name of Operator I 5. Type of Well: Development Exploratory Stratigraphic I Service 6, Datum elevation (DF or KB) L UNION OIL COMPANY OF CALIFORNIA (UNOCAL) 3. Address P.O. BOX 196247 ANCHORAGE, AK 99519 Elevaton of Location is 293.5' RKB = 31 feet 7, Unit or Property name 4. Location of well at surface 1725' FNL & 628' FWL of See 10, T8N, R98W At top of productive interval See Permit to Drill At effective depth See Permit to Drill At total depth See Permit to Drill Present well condition summary Total depth: measured true vertical Swanson River Unit 8. Well number 213-10 9. Permit number 202-118 10. API number 50-133-20515-0 11. Field/Pool Swanson River Unit 12. feet feet Plugs (measured) Effective depth: measured true vertical feet feet Junk (measured) Casing Length Size Cemented Measured depth True vertical depth Structural Conductor Surface Intermediate RE EI ED Production Liner ,JUL ~I 5 2002 Perforation depth: measured See attachment true vertical Alaska Oil & Gas Gons. GormmsSäOi¡ Anchorage Tubing (size, grade, and measured depth) Packers and SSSV (type and measured depth) . 13. Attachments XXX Description summary of proposal XXX Detailed operations program Copy of Notice of Public Hearing, Copy of Conservation Order Request Letter, Copy of Proposed Drilling Program L BOP sketch See 10-401 14. Estimated date for commencing operation 17 July 02 16, If proposal was verbally approved 15. Status of well classification as: Oil- Gas L Suspended Name of approver Date approved Service 17.1 hereby certify that the fOr~ing is tru\\: CO!T~.o the best of my knowledge. Signed Jim Harrisson ~;:, \ ,) !~_'frJ Title Drilling Manager ('ry -J , FOR COMMISSION USE ONLY Conditions of approval: Noti~mission so representative may witness Plug Integrity - BOP Test - Location clearance Mechanical Integrity Test SUbsequentform required 10- - 1.1-<)'1 Date If -T ~ 04- I Approval No. 302.... 2..J Ie:, Ooglnal Signed By Cammy Oechsli Taylor .ðQQroved by the order of the Commission Commissioner Date 11/l40~ Form 10-403 Rev 06/15/88 SUBMIT IN TRIPLICATE 0 ,- Swanson River Unit 213-10 ( Page 1 of 1 Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Swanson River Unit 213-10 Well A-028405 and A-028077 Section 10, T8N, R9W, Seward Meridian Kenai Peninsula Borough, Alaska Unocal Alaska by application for a Permit to Drill dated June 11,2002, and received by the Commission on June 11, 2002, has requested an exception to the production equipment requirements of 20 AAC 25.200(d) to complete the well as a tubingless, packerless development gas well. Surface Location: 1725 feet FNL and 628 feet FWL, Section 10, T8N, R9W, SM Anticipated Productive Interval: 28181 FNL, 5901 FWL Bottom Hole Location: 31031 FNL, 5521 FWL, S10, T8N, R9W, SM The Commission has tentatively set a public hearing on this application for July 23,2002 at 9:00 am at the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. A person may request that the tentatively scheduled hearing be held by filing a written request with the Commission no later than 4:30 pm on July 2, 2002. If a request for a hearing is not timely filed, the Commission will consider the issuance of an order without a hearing. To learn if the Commission will hold the public hearing, please call 793-1221. In addition, a person may submit written comments regarding this application to the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Written comments must be received no later than 4:30 pm on July 17, 2002, except that if the Commission decides to hold a public hearing, written comments must be received no later than 9:00 am on July 23,2002. If you are a person with a disability who may need a special modification in order to comment or to attend the public hearing, please contact Jody Colombie at 793-1221 before July 19, 2002. Cammy Oechsli Taylor, Chair Published Date: June 17, 2002 ADN AO# 02214044 Published Date: June 17, 2002 Clarion AO# 02214043 t:learln.Q...C.a.le.ndar http://www.state.ak.us/local/akpages/ADMIN/ogc/hear/SRUA213-10.htm 6/21/2002 Re: THE APPLICATION OF UNION OIL COMP ANY OF CALIFORNIA ("UNOCAL") for an order allowing well SRU 213-10 to be completed without a tubing and packer Conservation Order No XXXX Swanson River Field Swanson River Unit Well (SRU) 213-10 July XX, 2002 IT APPEARING THAT: 1. By application dated June 11, 2002, and received by the Alaska Oil and Gas Conservation Commission ("Commission") on June 11, 2002, Union Oil Company of California ("Unocal") requested an order from the Commission allowing the proposed Swanson River Unit ("SRU") 213-10 well to be completed without a tubing and packer as required by 20 AAC 25.200(d). 2. Notice of opportunity for public hearing was published in the Anchorage Daily News on June 17,2002 in accordance with 20 AAC 25.540. 3. Unocal submitted additional infonnation concerning the application by letter dated June 25, 2002. 4. The Commission received no comments concerning the application or requests for a public hearing. FINDINGS: 1. Unocal is operator of the Swanson River Field. 2. Unocal proposes to drill the SRU 213-10 well to a depth of approximately 3735feet TVD (4106' MD), from a surface location 1725 feet from the north line ("FNL") and 628 feet FWL, Section 10, T8N, R9W, SM to a bottom hole location of3103 feet FNL, 552 feet FWL, Section 10, T8N, R9W, SM. 3. Unocal proposes to drill the well using a slim hole drilling technique, running small diameter casing, and completing the well without a tubing and packer. 4. Commission regulations, 20 AAC 25.200(d), states: "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, unless the commission specifically approves production through the annulus to increase flow rate without jeopardizing ultimate recovery from the well." 5. Commission regulations, 20 AAC 25.990(26), defines fluids as "any material or substance that flows or moves, whether in a semi-solid, liquid, sludge, gaseous, or other fonn or state." 6. Unocal is drilling the SRU 213-10 in order to produce marginal attic gas reserves updip from the watered out SRU 212-10 well located on the same pad. ( 7. The gas reserves targeted for production from the SRU 213-10 well are considered marginal because they have already been partially depleted to about 6 ppg equivalent and will not flow against a pressure exerted by hydrostatic column of fresh water. 8. Producibility and economic viability of the well will depend on isolating the productive gas zones of interest from any water bearing zones. 9. The SRU 213-10 well is located in a remote location of the Swanson River Field, and there is no urban development nearby. 10. Unocal proposes to construct the SRU 213-10 well as follows: 133/8 inch conductor casing driven to 80 feet, 7 inch L-80 surface casing run to 1800 feet TVD (1979' MD) and cemented to surface, and 3~ inch L-80 production casing run to TD and cemented to the surface. 11. The 3~ inch production casing will be cemented with a two slurry cement job consisting of a low weight lead slurry and a conventional tail slurry to isolated gas bearing productive zones. 12. The 7 inch production casing will be set just below the m~ximum depth offresh water and just above the targeted gas bearing shallow production zones. The anticipated leak off on the 7 inch surface casing shoe is anticipated to be about 15.5 ppg equivalent. 13. Maximum anticipated surface pressure for the targeted depleted gas sands is expected to be around 600 to 800 psi. 14. The slim hole drilling technique significantly reduces the costs of completing a well in comparison to a conventionally drilled and cased well because of the smaller casing size and the time needed to drill and complete the well. 15. The small diameter production casing precludes running a tubing and packer. 16. Because of the lower cost associated with drilling and running a tubingless, slimhole completion, development of smaller hydrocarbon accumulations and marginal reserves are more likely to occur than with more expensive convention oil and gas drilling and completion techniques. 17. Tubingless completions have been used elsewhere around the world to promote development of marginal reserves. 18. Without a tubing and packer, there are fewer options available for perfonning cleanouts and remedial work, which could lead to the early abandonment of the well. 19. Because of the marginal reserves targeted for recovery, the life expectancy of the SRU 213-10 is expected to be relatively short. CONCLUSIONS: 1. The SRU 213-10 well is targeting low pressure, marginal gas reserves. ( 2. The targeted gas reserves are capable of unassisted flow the surface, but only after hydrostatic pressure has been removed 3. An exception to 20 AAC 2S.200(d) is necessary to allow the drilling and completion of the SRU 213-10 well without a tubing and packer. 4. The SRU 213-10 well is being drilled at a location updip to and that has been partially depleted by the existing SRU 212-10 well. 5. The SRU 213-10 well is not expected to encounter liquid hydrocarbons. 6. The SRU 213-10 well will likely result in production of gas that could not be produced economically using more expensive, conventional drilling and completion practices. 7. Because of the marginal reserves targeted for recovery, the SRU 213-10 well is expected to have a short life. Completing the well with tubing and packer would not increase the well's longevity before declining production forced the well's abandonment. 8. The drilling and completion of the SRU 213-10 well without a tubing and packer may likely result in a greater recovery of hydrocarbons than otherwise possible, and will not cause waste nor jeopardize correlative rights. NOW, THEREFORE, IT IS ORDERED THAT: Unocal's application for an exception to 20 AAC 25.200(d) to allow the drilling and completion of the SRU 213-10 well without tubing and packer is approved. . - a UNOCALft) AFE #154978 ( Swanson .River Unit SRU #213-10 Drilling Program 07/12/02 Revision #3 Objective: Drill SRU # 213-10 Grass Roots Gas Well. I. Surface Preparation" Install Cellar and Drive 13-3/8" conductor: Note: The adjacent well on the pad, SRU # 212-10, is appx 25' away from the proposed 213-10 Well. The existing well is shut-in due to water encroachment. The new well is an up dip replacement for the old well. Depletion, Lost Circulation, and Differential sticking are areas of concern during the drilling of the new well. Hot work procedures should be followed during any work on the pad due to the proximity of the old well. 1 Install cellar with 8' diameter x 6' long culvert. Final concrete cellar floor will be approximately 5' deep. 2. Prepare three 40' or longer joints of 13-3/8" 68# K-55 casing for conductor driving. The plan is to drive two joints if possible. If refusal is not achieved (100 blows/ft) then one additional joint will be available to continue driving. The drive shoe on the bottom of Joint #1 will have the collar welded on. Bevel collar at 45° with inside of bevel being higher than outside (so drive shoe will not collapse). See below. Cut off the pin end of Jt #1 for drive hammer to strike. Cut off the pin end of Joint #2 and bevel in preparation for field welding joints. Cut off collar of Jt #2 for driving. Leave pins and collar on Joint #3 since it is a contingency joint. Transport the three joints to location. Joint #1- collar welded on and beveled at 45 deg as shown below: L ~ L ~ Weld on Collar / '" Bevel drive shoe 3. Mobilize ToloffConstruction (776-8575) 70 ton crane and Delmag D-12 drive hammer. Utilize Toloff alignment template on top of cellar for driving first joint straight. Mobilize Peak welder including alignment clamp for proper welding of joint connections. Two welders may be needed to minimize cranelhammer time. Contact Keith Phillips-Unocal at 776-6710 for welding criteria. WELLPLAN213-10Ver3.DOC Page 1 7/12/2002/4:23 PM ( UNOCAL@> AFE #154978 ( Swanson Kiver Unit SRU #213-10 Drilling Program 07/12/02 Revision #3 4. Rig up drive hammer and crane, drive Joint #1. Cut-off drive damaged top end of Joint #1 and prep for weld connection to joint #2. Lift Joint #2 with crane and weld Joint #2 to Joint #1. Welding Specifications for K-55 casing: Preheat to 500°-700° F. Use rod E8010-G for Root and Hot Pass and Rod E8018-BZ for fill and cap. Call out Ray Gross-Unocal welding inspector at x6713 to visual and mag particle inspect the weld. 6. Drive Joint #2. Cut-off drive damaged end of Joint #2. If joint #2 has not met significant resistance, be prepared to drive joint #3. Maximum blow count (Refusal) is, 1 00 blows/ft. If refusal is met before 2 joints are driven, contact Drilling Superintendent and decide if refusal depth is sufficient. Options are limited if more depth is desired. Could drill conductor hole with water well rig and cement in 13-3/8". After rough cut, top of conductor should end up approximately about 3.5 feet below ground level. Make final cut on conductor when starting head is installed. See diverter rig up drawings for height of cut off and desired depth of Bradenhead flange. Install Baseplate on 13-3/8" conductor and terminate baseplate at Cellar Floor. Dress Cement floor of Cellar to support baseplate. 7. Rig down Toloff. Tag and note top of fill inside conductor. Note final depth of conductor below pad level and final blow count/ft. Demob Crane and water well rig if used. 8. Call out Cameron representative (or Steve Lawrence-Swanson Valve Shop Foreman) and Peak welder. Check welding instructions from Keith Phillips 776-6710. Check that conductor is K- 55 grade with Brinell hardness test. Weld 13-5/8" x 13-5/8" 3M SOW to conductor. Pressure test to 1000 psi. Top of SOW should be as per stack up drawing for proper diverter installation. Install two 4" threaded outlets with removable plugs to the 13-3/8" conductor just below the starting head. This will improve returns during the surface casing cement job. Angle one of the outlets such that Macaroni tubing can be inserted downthe 7" x 13-3/8" annulus for a contingent top job. 9 Make sump area in floor of cellar for easy pump out of cellar. 10 Call out McLane Engineering (283-4218) or certified surveyors to survey exact conductor location and surface elevation. Exact location and elevation will be needed to file with AOGCC and BLM. Note latitude and longitude for helicopter reference. WELLPLAN213-1 OVer3 .DOC Page 2 7/12/2002/4:23 PM ( Swanso'n .River Unit SRU #213-10 Drilling Program 07/12/02 Revision #3 UNOCAL(; AFE #154978 The attached file is the actual as built for the proposed well. UNDCAL8 SRU 213-10 WELL AS-BUILT SURFACE LOCAllON DIAGRAM AS-BUilL T SRU 213-1Q 'ßELL ASP ZONE 4 NAD2.7 GRID ~: 24.85826.116 GRID E~J.+8.551.293 LAlllUDE: 6(]'45'G5..011.3- N LON GIìU DE: 150"50.52,5356" W 171 ij' FNL OJJ PM.. SECT! ON 10 TBN. R9W, S.M" AK ELEV, 2.93,5 FT. N A \fJ M ""-""" I ...4ft¡. 0 F AL I, ~ ~~,. ,-'" ,. ",1~ 't :~I~> ~ "..T 4'1- =*~"49 TH.N "!*~ (//II.---.----.--.. .--.. .--.. ._--._.--._~ ~ := Ø/J.'---'--"'"'' ..... ..... ""'''''''¡JI#I ~ '\ :"~' 5CQTT MeLAN7-':! ~ "t ~""" 492.ß-S ....,~= ,¡~~......~ ~ "8.,\\.:;',,'-" P.D.Box 41513 5CJLDDTNA., AK 99669 ~ Conoulting Group ~,'1 c LA NET s&ting ~ ~[].ECf UNOCAL 5RU 213-IØ SURFACE LOCATION L.QCAl100 f.;wantoon ~1V8r Un1t., Altilølc:t9 M~1¡I,t Irr' DAlE ~ DoIIlE TEL 907.2.83..4218 FA.x 907.283.3265 1-1.&.H- '¡1tJ/ø-2 I". 6Ø 1 WELLPLAN213-1 OV er3.DOC Page 3 ~ r- t I I~ .~ / ~ I .'-/ P.:f\4S~ PRD.ECT jDl'.C. Ø23Ø23 s-EET NO. IF 7/12/2002/4:23 PM UNOCAL8 AFE #154978 ( Swanson Kiver Unit SRU #213-10 Drilling Program 07/12/02 Revision #3 II Shut-in Adjacent Well SRU # 212-10 1 Well SRU 212-10 will only be 25' away from the new well. Set a BPV in 212-10. Prior to moving in the Nabors Rig 129. A Gyro survey will have been run in the adjacent well prior to the rig arrival. NOTE: The BPV should be set before moving the rig on location. NOTE: A directional survey (GYRO) will have been run on the upper portion of this well. Ensure that the spider plot for the well has been updated to show the actual well path of the 212- 10 well. III. Mobilize Nabors Ri2129 (Formerlv H&R Ri2 9) ENSURE THAT THE RIG IS CLEANED OF ALL OIL BASE RESIDUES PRIOR TO MOVING TO 213-10. 1 Record RKB elevation to pad level and RKB distance above sea level. Post BLM and AOGCC approved pennits in rig office. Install well location sign in conspicuous location on rig. Have Peak stencil well location sign as follows: SRU #213-10 Unocal- Owner and Operator Surf. Location: 1718' FNL & 633' FWL of Sec. 10, T8N, R9W, SM (exactfootage is as per survey) 2 Install, calibrate, and test all gas detection equipment as per AOGCC guidelines. 3 Begin building water based spud mud. 4 Notify BLM and AOGCC 24 hours prior to diverter function test. BLM- Peter Ditton 267-1429 (w) or 522-3113 (h), or Greg Noble Fisk 267-1443(w) or 344- 0373(h) AOGCC - Tom Maunder 793-1250 (w) ; 345-0850 (cell) 5 NU diverter. One 12" diverter line shall end at least 100' from all rig emission sources. The end of the diverter shall have a lined pit or small tank to contain mud that will exit the line during function tests. The diverter line shall be secured to the ground to prevent movement. The line should be straight if possible. If a turn is needed, the turn shall be targeted. Drift the Bell nipple and Diverter with a 13-5/8" Test Plug prior to function testing the Diverter. Rig up Diverter lines and bell nipple. Accept the rig on Daywork only after complete rig up and successfully function testing the Diverter. 6 Function test 13-5/8" 5M diverter with State and BLM witness if available. WELLPLAN213-10Ver3.DOC Page 4 7/12/2002/4:23 PM (' UNOCAL8 AFE #154978 Swanson River Unit SRU #213-10 Drilling Program 07/12/02 Revision #3 7 Install gas monitors at both the old well and the new well cellars. If production does not have a continuous gas monitor, use portable gas sniffer to check 212-10's cellar once every 12 hours. IV. Drill 8-112" Hole 0' to 1989' MD; 1800' TVD Note: Have approved Permit to Drill from AOGCC and BLM on display. 1. Rotary drill out 13-3/8" conductor with 8-1/2" bit to just below base of conductor at +/- 85' RKB. (Conductor was driven to 76' below grade on 7/3/02) 8-1/2" SMITH FGXIPS MT Bit (4-1/2" reg pin) 6-3/4" Directional Motor (1.15 Deg) (4-1/2" Reg box x 4-1/2" XH box) 8-3/8" Stabilizer Built on Motor N/A UBHO SUB (4-1/2" XH Box by Pin) 6-3/4" Pony Collar (4-1/2" XH Box by Pin) 8-1/4" Stabilizer (4-1/2" XH Box by Pin) 6-3/4" MWD tool (4-1/2" XH by 4-1/2" XH) Inteq baffle plate for Contingency use of a single shot/multi shot tool 8-3/8" Stabilizer (4-1/2" XH by 4-1/2" XH) Two 6-3/4" DC's (4-1/2" XH Pin x 4-1/2" XH Box) CROSSOVER (4-1/2" XH Pin by 4-1/2IF Box) Five 5" HWDP (4-1/2 IF Box by Pin) 6-1/2" JARS (4-1/2" IF by 4-1/2" IF) CROSSOVER (4-1/2" IF Pin by 3-1/2" IF Box) 30 Joints of 3-1/2" HWDP (3-1/2" IF by 3-1/2" IF) 3-1/2" S 135 Drill pipe as needed (3-1/2" IF by 3-1/2" IF) Drill Pipe: 3-1/2" S-135, 13.3#, 3-1/2" IF with OD=4.75" and ID=2-9/16" (2.438" drift) Recmake-up torque = 8800 ft-lbs, max torque = 10,200 ft-lbs Tensile yield = 300,000 lbs. (Premium Class) WELLPLAN213-1 OV er3 .DOC Page 5 7/12/2002/4:23 PM ( . - t UNOCAL~ AFE #154978 (' Swanson River Unit SRU #213-10 Drilling Program 07/12/02 Revision #3 Field Structure Swanson River Unit Swanson River Unocal - 213-10 I I Date I Iwell 213-10 Borehole 213-10 Schlumberuer I BHA Data Sheet 8.5 Proposal IBHA# Ibha#18.5"Hole Fish. Neck Cum. Vendorl OD (inV OD (inV Max OD Bottoml Length Length Item Name Model Serial # Length (ft) ID(in) (in) Top Connection (ft) (ft) 1 8 1/2" Bit Generic 5.75 8.50 1.00 1.00 2.25 4.50 Reg Pin 2 A675M7830 (1.5 deg) Anadrill 6.75 7.50 4.50 REG Box 20.00 21.00 A675M7830SP 5.50 4.50 XH Box, 3 6 3/4" Collar 6.75 6.75 4.50 XH Box 10.00 31.00 2.81 4.50 XH Pin 4 Stabilizer 6.75 6.75 4.50 XH Pin 6.00 37.00 2.81 4.50 XH Box 5 PowerPulse Anadrill 6.75 6.75 4.50 XH Box 25.00 62.00 PowerPulse 5.11 4.50 XH Box, 6 Stabilizer 6.75 6.75 4.50 XH Pin 6.00 68.00 2.81 4.50 XH Box, 7 6 3/4" Collar 6.75 6.75 4.50 XH Box 30.00 98.00 2.88 4.50 XH Pin 8 Crossover 6.75 6.75 4.50 XH Pin 3.00 101.00 2.88 4.50 IF Box 9 5" HWDP 5.00 6.50 4.50 IF Box 31.00 132.00 3.00 4.50 IF Box, 10 Hydraulic Jar Dailey Petroleum S 6.50 6.50 4.50 IF Box 35.00 167.00 2.75 4.50 IF Pin 11 Crossover 6.75 6.75 4.50 IF Pin 2.00 169.00 2.81 3.50 IF Box 12 43/4" Collar (6 joints) 4.75 4.75 3.50 IF Box 186.00 355.00 2.25 3.50 IF Pin 13 31/2" HWDP (18 joints) 3.50 4.75 3.50 IF Pin 558.00 913.00 2.06 3.50 IF Box 14 3-1/2" 13.30 DPS, New 3.50 5.00 3.50 IF Pin 3.5, 13.3,New 2.76 3.50 IF Box Total Weight (Ibf) Below Jar (Ibf) 36234 10266.5 Total Len. 913.00 BHA Comments: Stábilizer Blade Length (ft) Mid-Pt. To Bit (ft) 0.58 2.75 2.40 33.44 2.40 64.14 Sensor Type D&I Distance To Bit (ft) 50.00 Bit Nozzles. Còunt Size(1/32 in) 3 13.00 Bent Housing Angle (deg) Bènd.Tó.Bóttøm Connection (ft) 1.50 6.03 TFA (in2) 0.39 Quality Control Created By: .burtonjOhn Ch.ecked By: WELLPLAN213-1 OVer3 . DOC Page 6 7/12/2002/4:23 PM ( . - t UNOCAL(; AFE #154978 (' Swanson River Unit SRU #213-10 Drilling Program 07/12/02 Revision #3 Note: 3-112" drill pipe will be used on the surface and production hole. (no 5" drill pipe) All drill string items will be rental equipment from Weatherford, or from Anadril or from Nabors. NOTE: Have UBHO Sub in BHA with wireline available in the event that the single shot gyro is needed to orient. The well will be drilled with new Rig owner, and a Kelly. As a result the well will be drilled with singles. Attention to the time on the slips without moving the pipe is an important item to pay attention to. The initial 500 feet are to be straight. Rotary drill and scribe a line on the tool joints from the surface. Upon reaching 500 feet, orient with the scribe line in a South Easterly direction roughly 50 degrees away from the offset well and start to nudge/slide drill until angle of about 3 degrees is obtained. Start taking MWD surveys and correct azimuth to the proposed well path. The planned 500 foot kick off point will begin the directional path to the South at an azimuth of 187 degrees. Because of magnetic interference during the upper hole, interval, MWD surveys will not be reliable. Plan to scribe line orient and then begin using the MWD tool after some minimum hole angle is attained. IE Rotate to 500 feet maintaining the scribe line. Orient to the scribe line at 500 feet with bit pointing SouthEast, then slide and kick off at 4 degrees per hundred feet. After making some 200 feet of directional hole, begin believing surveys from MWD. Adjust hole direction early. Have Azimuth as needed at 187 degrees by 1000'. If well control situation arises on surface hole, driller will operate divert valve and shut down mud pumps and engines. Crew will muster at pre-designated area. Drilling Parameters: Flow rate = 380 gpm (or max for 6" liners) Mud Weight = 9.5 ppg-l0.5 ppg Pump pressure limit = 2500 psi @380 gpm Bit nozzles recommended: 4-13' s Annular velocity in 3-112" x 8-112"= 155 ft/min at 380 gpm Annular velocity in 3-112" x 12-1/4" = 68 ft/min at 380 gpm 2 Slowly RIH with BHA. 3 Establish circulation with WBM. 4. Drill 8-112" hole from 0' to 1989'. Consider making up a 12-114" Stabilizer and washing out the first 90- feet, then laying down the 12-114" stabilizer. This may not be necessary, but should be considered. Alternatively the conductor can be washed out with a 12-114" bit prior to running the 8-112" assembly. The current plan is to use the 8-112" assembly to wash out the conductor, but either method is acceptable. WELLPLAN213-1 OVer3.DOC Page 7 7/12/2002/4:23 PM ( . - t UNOCAL(; AFE #154978 swanso~ ßiver Unit SRU #213-10 Drilling Program 07/12/02 Revision #3 Note: If lost circulation occurs, establish loss rate at full drilling circulation rate. Contact Drilling Superintendent or on call SuptlEng to discuss options. a) Begin drilling with water base-mud starting at 9.5 ppg and allow the mud weight to rise to 10.0 ppg. Maintain mud weight by controlling solids with desilter/desander operation. The cuttings will be hauled to Swanson River Field disposal site and mud will be hauled to Swanson River disposal well. NOTE: Utilize all fluid and waste transfert protocols and tracking Documents as per UNOCAL HES department. Recommended Mud Properties for Surface Hole: Density: 9.5-10.5 ppg Viscosity 44-100 sec/qt PV 12-16 cps YP 15-40 lb/1 00ft2 Gels 15-30 Fluid Loss NC to 6-14 cc API PH 9.0-9.5 KCL 3 % by Kick off point Contingency usage of lost circulation material on site includes: Seepage losses- Add 5-10 ppb graded calcium Carbonate Moderate Losses- Mix 10-30 ppb of Seal Fine & Medium while drilling and/or spot pills across loss zones. b) No known shallow gas zones exist, however, swabbing potential exists on all trips. Because of the age of the field and because of the large number of wells drilled in the field, there is always a possibility of some shallow gas accumulations occurring. We will continuously fill the hole on all trips while the diverter is in use. Discuss tripping procedures with all personnel. Do not POOH at high speeds. Use trip tank sheets. Continuously fill hole on all trips. Make Swab in potential test prior to pulling out of hole. c) Epoch will begin gas show mud logging at surface. Gas/H2S detection and monitoring drilling parameters will begin from the surface. d) Rig crews will participate in a pit drill or trip drill each tour. e) Accurately monitor trip tank and fill out trip sheets. f) Visually monitor hole at all times on trips. DO NOT USE STRIPPING RUBBER BELOW THE ROTARY TABLE. g) Monitor trip speed to avoid surging or swabbing formations. WELLPLAN213-1 OVer3 .DOC Page 8 7/12/2002/4:23 PM ( UNOCAL~ AFE #154978 Swanson River Unit SRU #213-10 Drilling Program 07/12/02 Revision #3 h) The offset well 212-10 did not have a multi shot survey above 2400 feet. A survey is being run on the old well as this document is being written. The surface location for 212-10 is 25' South West of the new well location so there should not be a proximity problem between the proposed well and 212-10 in the first 500 feet. Concerns about the proximity will be mitigated by nudging the new well to the South East early. i) A Magnetic Single shot or Multi-shot tool will be utilized as a check shot instrument. One survey will be taken at the end of each hole section to provide a check on the MWD survey data at each casing point. 5. Orient using either the UBHO and wire line single shot gyro, or use the Scribe line to orient the motor at 500 feet and begin directional drilling to the South East at the kick off point. Build angle and drill to about 800 feet with the Scribe line and begin using the MWD surveys as soon as they are available. Drill with hydraulics, and mud properties to the Surface casing point as per mud, bit, and directional plans. Circulate and condition hole for casing job. POOH breaking the 6-3/4" tools and standing same back along with the 3-1/2" drill pipe. Prepare to run casing. (No wireline logs will be run in surface hole section). NOTE: The 6-3/4" tools will be laid down in the mouse hole after running casing. Note: The 1989' MD; 1800' TVD casing point was chosen because the State Required minimum depth of casing to protect fresh water sands in the Swanson River Unit is 1700 feet. The 1989' MD; 1800' TVD was chosen to comply with this requirement. This will also provide less chance for lost circulation and a better chance for a good leak-off test. The exact TD can be adjusted within plus or minus a 40' zone to correspond to the 7" casing tall y. Use a carbide or some kind of flag (Nut plug pill) to estimate hole size to adjust upcoming cement volumes. 6. Plan to run the 7" casing slips prior to cementing using ropes from the rig floor. Have eye bolts, string, and rope available to lower the slips into place. Plan to run slips, land casing, break tie strings and retrieve lowering ropes prior to cementing. Returns will be taken through the wellhead outlets with hoses and vacuum trucks. \ WELLPLAN213-10Ver3.00C Page 9 7/12/2002/4:23 PM ( Swanson River Unit SRU #213-10 Drilling Program 07/12/02 Revision #3 UNOCAL8 AFE #154978 v. Run 7" 26 lb/ft K-55 Buttress casin2. ...:::::::: 13-3/8" Condo 92' MD Casin2: 7" 26#/FT L-80 Buttress Couplings Collapse 5410 psi, Burst 7240 psi, Tensile 604 Kips General Information: Total Depth: Previous CSG: Hole Size: M.W.: Top of Cement: Torque Values: 7" L 1989' MD; 1800' TVD 1989' MD/1800' TVD 13-3/8" Conductor @ 80' MD with 13-5/8" SOW casinghead 8.5" . 9.5 to 10.5 PPG (Estimated) Surface The 7", 29#, L-80, BTC casing should make up to the mark with about 6000 ft-#'s. Check make up to the mark by feeling the temperature of the couplings. Do not allow the casing to be made up too hot. Equipment Requirements: Float Shoe: Halliburton 7" Super Seal II (PDC Drillable) Float Shoe. Have float shoe "Baker- Locked" on the pin end Joint # 1 and also Baker-Lock the casing collar on Joint #1 Joint #2 Float Collar: 7" pup joint Plugs: Centralizers: WELLPLAN213-10Yer3.DOC Have casing collar Baker-Locked on Joint #2 and marked. Halliburton 7" Super Seal II Float Collar. Have float collar "Baker- Locked" on the pin end of Joint #3. Have appx 20' long pup joint on location in case casing does not make it down all the way to planned depth. Halliburton top and bottom non-rotating/PDC-drillable plugs (the 3 float equipment items above can be purchased thru Petroleum Equipment) One 12-1/8" x 7" solid straight blade centralizer below wellhead to help align casing in conductor. Install this centralizer with set screws just under the collar of the first fulljoint below the mandrel hanger. One 7" x 8-1/2" bow spring centralizer on every 4th joint from the shoe to surface as per BLM regulation. Page 10 7/12/2002/4:23 PM UNOCAL~ AFE #154978 ( Swanson River Unit SRU #213-10 Drilling Program 07/12/02 Revision #3 Landing Joint Ensure that there is not a casing collar in the BOP Stack when the casing is on bottom so that slips can be dropped if necessary. Top Job 10 jts 1" PVC tubing on hand for top job contingency. This tubing will have to be limber enough to run through the 4" outlets below the starting head. Casin2 Runnin2 Procedure: 1. Notify BLM at least 6 hours prior to running/cementing surface casing. 2. RU Weatherford casing crew. Test equipment and power packs before RU to run casing. Note:Use 75 ton T' YC slip type elevators, and RT 7" slips. Have 150 ton elevators on location. 3. "Baker-Lock" a float shoe (PDC drillable) to the bottom of casing joint #1 and "Baker-Lock" a float collar on bottom of Joint #3 prior to shipment. (80' float track). In addition, Joints #1-3 will have the factory collar Baker-Locked on the joint. 4. Casing will be run to bottom of the hole. Calculate tally so that casing will land with top of landing joint within 10 feet of rig floor. 5. Clean threads on first three joints in preparation for Baker-lock. 6. Retrieve bore protector. 7. RIH with T' 29 lb/ft L-80 Buttress. (Fill up CSG as required) 1 Joint of7" Casing with a Float shoe Baker-Locked onto the bottom. 1 Joint of 7" Casing. 1 Joint of 7" Casing with a Float collar Baker-Locked onto the bottom. (80' float track) Fill casing, PU casing and check floats 7" Casing to surface and landing joint to rig floor. 8. Slowly RIH with casing to bottom. Have Dowell's circulating swage on floor to wash pipe to bottom if needed. 9. RU Dowell's double plug 5M psi cementing head and surface lines. 10. Drain Stack and wash out same. Install Slips and land casing. Open side outlet valves and circulate the casing prior to beginning the cement job. Use hoses and Vacuum trucks to facilitate handling of fluids in the cellar. 11. Pressure test lines and equipment to 250/3.000 psi with fresh water. WELLPLAN213-10Ver3.DOC Page 11 7/12/2002/4:23 PM . - . UNOCAL~ AFE #154978 Swanson River Unit SRU #213-10 Drilling Program 07/12/02 Revision #3 12. Circulate at least a casing volume and condition mud for cement job. YP should be about 15. VI 7" Surface Casine Cementine Procedure: 1. Dowell will dry blend lead cement and tail cement before it is shipped. 2. Call out Dowell ahead of time. a) Spot clean mix water tank on location. b) Prepare lead slurry mix water. Note: mix water should be at least 45°F--70°F is optimum. c) The spacer will be 10 bbl of fresh water followed by a waterbase compatible mud push spacer, then lead followed by Tail slurry.. d) Borax to contaminate cement returns at surface. 3. Pump the following schedule. The goal is to bring cement to surface. Be prepared to divert returns at surface to vacuum truck when cement first appears. Contaminate with Borax. Pump Schedule: Volume Mud Weight (PPG) 8.3 Fluid Pumped Plug 10 bbls 208 Sacks 483 Sacks Plug 75 *** 8.3 12.8 15.8 Fresh water for pressure test Bottom "Non-rotatable/PDC Drillable" Plug Fresh water as a spacer Lead Slurry Tail Slurry: 1900'-2150' annulus plus 80 ft float track Top "Non-rotatable/PDC Drillable" Plug Displacement with cement unit (Water Based Mud) Reciprocate casing until just before plug bumps Bump plug 10.0 Note: Verify all depths and volumes before cement job. Note: a) The total pump time on lead cement is TBD b) Mix water with liquid additives for tail slurry. c) Use the cementing unit for pumping cement and displacement. WELLPLAN213-10Ver3.DOC Page 12 7/12/2002/4:23 PM UNOCAL6> AFE #154978 ( Swanson River Unit SRU #213-10 Drilling Program 07/12/02 Revision #3 d) Record displacement volume when plug is bumped. e) Float track is 3 bbl so maximum over-displacement should be 3 bbl. f) Extra tank and Borax retarder on location for excess cement returns g) Max pump = 8 BPM (to avoid exceeding annular velocity while drilling with . 6-3/4" collars at 380 gpm). h) Watch for cmt returns, and switch to tail slurry as soon as cement contaminated mud is observed. 4. Bump plug with 1000 psi over final displacement pressure. Hold pressure for 5 minutes. Release pressure and verify floats are holding. If plug does not bump or floats do not hold, keep well shut-in until tail slurry cement hardens. Divert returns to vacuum truck or tanks when cement first appears at surface. Contaminate cement with borax and haul to Swanson River Field disposal site. Lead Slurry Data (Actual data from lab test): Depth: 0' -1489' Total volume: 345 fe (using 30% excess in 8.5" x 7" open hole) NOTE: SRU #223-28 just started to see contaminated cmt returns at 100% excess pumped and had to do a top job. Gravel sloughing on the 8.5" hole section would warrant some additional cement volume. Final volumes will be detennined after the interval is drilled. 124 12.5 lb/gal 2.11 ft3/ sk Dry blended "G" cement with 2% BWOC D079 + 0.5% BWOC SOOI 4.5 Hours to 30 Bc and 5.5 Hours to 70 Bc 100° F 80° F Total sacks: Slurry Weight: Cement Yield: Cement Composition: Thickening Time: BHST: BHCT: Tail Slurry Data (Actual data from lab test): Depth: 1489'-1989' (500' of tail cement) Total volume: 99 ft3 (includes 80 ft shoe track and 30% excess in open hole) Total sacks: 85 Slurry Weight: 15.8Ib/gal Cement Yield: 1.16 ft3/ sk Thickening Time: 3.3 Hours to 30 Bc and 4.6 Hours to 70 Bc Cement Composition: "G" with 0.5% BWOC SOOI + 0.3% BWOC D065 + 0.2% BWOC D046 + 0.4% BWOC D167 100° F 80° F BHST: BHCT: WELLPLAN213-1 OVer3.DOC Page 13 7/12/2002/4:23 PM (, Swanson River Unit SRU #213-10 Drilling Program 07/12/02 Revision #3 UNOCAL~ AFE #154978 Capacities: 13-3/8" x 7": 0.5734 cuftlft 8-1/2" x 7": 0.1268 cuftlft 7" 26 lb/ft: 0.2148 cuft/ft Excess Requirements: Lead Slurry: 8-1/2" x 7" 30% excess Tail Slurry: 500 ft of 8-1/2" x 7" with 30% excess, plus 80' float track Underbalance concerns: VII. 1. 10 bbl of 8.3 PPG fresh water spacer (10 bbl = 442' in 8.5" x 7" annulus): .052 * 10.0 PPG mud*(1800' TVD-442')+ .052 * 8.3 PPG wash* 442' TVD=897 psi= 9.6 ppg MW Est. Pore pressure = 1800 * .433 psilFT = 779 psi = 8.3 ppg 5. After cement job, ND and raise diverter. Wash out diverter and wellhead on top of slips. Flush with rig water through 2" outlets on the starting head. Nipple up 13-5/8" by 7- 1/16" 5 M "B" Section. Test void to 1500 psi. Install 7-1/16" 5M by II" 5M DSAF. Note: If no cement returns are observed at surface, be prepared to pump top job with 1" PVC tubing as deep as possible (400' of PVC on location). Cement blend should be Class G neat. Discuss doing top job through 4" outlets below the starting head after the BOPE has been nippled up. 6. Fit test Wear Bushing and Test Plug in Cameron 13-5/8" x 7-1116" 5 M "B" Section. 7. NU II" BOP Stack on top of the 7-1/16" 5M by II" 5M DSAF. 8. Install two sets of 3-1/2" pipe rams. Test BOP stack to 3000 psi with 24 hr notice given to AOGCC and BLM. Pull test plug and install wear bushing. Drill 6" Straie:ht Hole from 1989' to 4106' MD MU the followine: BHA: 6" PDC on Anadril Motor: 6" SMITH S75PX PDC bit with 6 12's (3-1/2" Reg Pin) 4-3/4" A475M4560XP Motor withO.78 deg hsg. (3-1/2" IF box x 3-1/2" reg box) 5-7/8" Monel Stabilizer (3-1/2" IF Pin by Box) 4-314" MWD tool with GR (3-1/2" IF Pin x 3-1/2" IF Box) 5-7/8" Monel blade stab (3-1/2" IF Pin by Box) 4-3/4" Monel Drill Collar (3-1/2" IF Pin by Box) Baffle Plate N/A Six 4-3/4" Drill Collars (3-1/2" IF Pin by Box) 4-3/4" Dailey Hydraulic UplBumper Sub, 30' (3-1/2" IF Pin by Box) 2-1/4" ID Eighteen 3-1/2" HWDP (3-1/2" IF Pin by Box) 3-1/2" 13.3 # S-135 Drillpipe (3-1/2" IF box x pin) Page 14 7/12/2002/4:23 PM WELLPLAN213-1 OVer3 . DOC UNOCALfi) AFE #154978 swans!n River Unit SRU #213-10 Drilling Program 07/12/02 Revision #3 Field Structure Swanson River Unit Swanson River Unocal - 213-10 I I Date I well 213-10 Borehole 213-10 Schlumberger I BHA Data Sheet 6" Proposal IBHA# Ibha1 6" Fish. Neck Cum. Vendorl OD (in)/ OD(in)/ Max OD Bottoml Length Lèngth Item Name MOOèl Serial # Length (ft) ID(in) (in) Top Connection (ft) (ft) 1 6" Bit Generic 3.75 6.00 0.75 0.75 1.25 3.50 Reg Pin 2 A475M4560XP Anadrill 4.75 5.50 3.50 Reg Box 23.00 23.75 A475M4560XP 3.75 3.50 IF Box, 3 Monel Stabilizer 4.75 6.00 3.50 IF Pin 6.00 29.75 2.25 3.50 IF Box 4 4 3/4" Monel Collar 4.75 4.75 3.50 IF Box 5.00 34.75 2.25 3.50 IF Pin 5 Slimpulse wlGR Anadrill 4.75 4.75 3.50 IF Box 28.00 62.75 Slim-1 wlSGR 2.87 3.50 IF Box, 6 Monel Stabilizer 4.75 6.00 3.50 IF Pin 6.00 68.75 2.25 3.50 IF Box 7 4 3/4" Monel Collar 4.75 4.75 3.50 IF Box 31.00 99.75 2.25 3.50 NC38 (IF) Pin 8 43/4" Steel Collar (6 joints) 4.75 4.75 3.50 IF Box 186.00 285.75 2.25 3.50 IF Pin 9 Hydraulic Jar Dailey 4.75 4.75 3.50 IF Pin 30.00 315.75 2.25 3.50 IF Box 10 3 1/2" HWDP (18 joints) 3.50 4.75 3.50 IF Box 558.00 873.75 2.25 3.50 IF Box 11 3-1/2" 13.30 DP 3.50 5.00 3.50 IF Box 2.76 3.50 IF Box -aHA Comments: Total: Weight (IÞf) Below Jar (Ibf) 27286 12556.0 "Iotal Lèn. 873.75 Stêlbilizer Blade Lèngth (ft) Mid-Pt. To Bit(ft) 1.00 1.84 2.40 26.25 Sensor Type Distance To Bit (ft) Gamma Ra 47.95 D&I 56.95 Bit.No~les Count $1ze(1/32Ì1t) Bent Housing Angle (deg) Bend To Bottom Connection (ft) TFA(in,2) 0.00 WELLPLAN213-1 OVer3 .DOC Page 15 7/12/2002/4:23 PM . - t UNOCAL8 AFE #154978 (' Swanson River Unit SRU #213-10 Drilling Program 07/12/02 Revision #3 Drilling Parameters: Flow rate= 250-280 gpm (max for motor) Nozzles recommended = 6-12's Surface pressure Maximum = 3000 psi Mud weight= 10.0 to 9.5 ppg Annular velocity, 3-1/2" x 6" @ 280 gpm = 316 fpm 2. RIH and tag cement with drilling assembly. Pressure test 7" casing to 2..500 psi- 3. Drill out cement, float collar, and float shoe. 4. After drilling 25' of new formation, perform Leak -Off Test. Record all pressure, rates, and volumes of test and fax into office. The expected LOT gradient @ 1989' MD is:t 0.806 psi/ft or 15.5 ppg EMW (=25 bbl kick tolerance). Note: SRU #223-28 in 1997 had a LOT of21.1 ppg near this depth. The above 15.5 ppg is a conservative estimate. If the LOT is less than 15.5 ppg, discuss with Superintendent. NOTE: A 12.5 PPG EQ leak off will still give a 16 bbl kick tolerance. Have the Drilling Engineer recalculate and check the kick tolerance for the LOT ifit is less than 15.5 ppg Eq. . Acceptable swab kick tolerance is 16 bbl. Review with management on approval to proceed if swab kick tolerance is less than 16 bbls. The options are drill ahead if Leak off is greater than 12.5 ppg. Squeeze if it is less than 12.5 ppg. Contact the drilling engineer if a squeeze is indicated. 5. Drill 6" hole from 1989' to 4106' a) Planned mud weight is 10.0 ppg at the 7" shoe with gradual decreases if penetration rates indicate a need to drop to 9.5 ppg at TD, otherwise maintain 10.0 ppg. Precondition one pit of mud for the 6" production hole interval and switch to this pit of mud after the cement is drilled and the leak off test has been performed. Recommended Mud Parameters for 6" Production Hole Density 10.0-9.5 ppg PV 8-15 cps YP 12-18Ib/100ft2 Gels 6/15 Fluid Loss 6-10 cc API PH 9.0-10.5 Drilled Solids +/- 5% WELLPLAN213-10Ver3.DOC Page 16 7/12/2002/4:23 PM Swanson River Unit SRU #213-10 Drilling Program 07/12/02 Revision #3 UNOCAL(4) 6 VIII. AFE #154978 b) A trip sheet should be monitored closely for all trips in and out of the hole. c) Be prepared for loss circulation problems and hole cleaning problems. Try to maintain solids control to maintain a consistent mud weight; and reduce ECD's. d) TD is based on seeing the target sands. The planned TD is 3710' TVD. Geologist Erik Graven will be on location or on call in the office 263-7837 or home-345-4311 to help determine sufficient TD. Talk with Erik Graven on TD questions. e) Post type log on the rig floor. Note coals and try not to set surface casing in a coal. f) The 6" PDC BHA should be able to reach TD with one bit run. At TD, circulate bottoms up, make short trip to condition hole if necessary. Circulate and condition hole for casing job. Discuss necessity of short trip with Anchorage prior to attempting open hole logging pass. Wireline L022in2 Run Call out Erik Graven-Geologist 263-7837 or home-345-4311 for log witness. 1. 2. 3. 4. 5. RU Schlumberger Unit and triple combo tools with pack-off and pump-in sub. RIH with tools Platform Express: DITE/LDT/CNT/GR/Cal (appx 70' long) Log from TD at 4106' MD to appx 1989' (top to be determined by on site geologist). Continue logging to surface with GR. Check bottom hole temperature. Cement lab test was based on BHST of 100 deg F. Verify fishing neck dimensions on logging tools. If logging tools become stuck, be prepared for both 1) stripping over the wire to retrieve tools and 2) pulling out of the rope socket and retrieving tools with open hole fishing tools. Rig Down Schlumberger. Discuss necessity of wiper trip prior to running casing. RIH with cleanout assembly to TD, short trip if necessary to condition hole. Circ BU and POOH. Verify with geologist that the well is a keeper and the casing should be run. Need 2- 7/8" tubing cement stinger in field in case of P &A. Page 17 WELLPLAN213-1 OV er3.DOC 7/12/2002/4:23 PM . - t UNOCAL~ AFE #154978 ( Swanson River Unit SRU #213-10 Drilling Program 07/12/02 Revision #3 IX. Run 3-1/2" Production Casin2 to TD. Casin~: 13-3/8" J Use Best of Life 2000 pipe dope, (API modified dope is not recommended for 5" TKC)) Note: Use Weatherford's casing crews and equipment, no JAM computerized equipment needed. The make up torque should be about 3500 to 4000 ft-#'s L. 7" General Information: Total Depth: 4106' MD/ 3735' TVD Previous CSG: 7" @ 1989' MD Hole Size: 6" M.W.: 10.0 to 9.5 PPG (Estimated) Calc Top of Cement: Surface 3.5~~ ¿ Equipment Requirements: Float Shoe: Baker 3.5" Float shoe Have float shoe "Baker-Locked" to the bottom of jt # 1. Float Collar: Baker 3.5" Float Collar Have float collar "Baker-Locked" on the pin end of jt #2. Wiper Plugs: 3-1/2" bottom plug 3-1/2" Top wiper plug Centralizers: None 1 Notify BLM at least 6 hrs prior to running/cementing 3-1/2 2 Dowell will perfonn QAlQC checks on cement before it is shipped. Verify Cement Volume Requirements based on the caliper log and the requirement to cement to surface. Tail cement volume is to be to 500 feet inside the shoe of the T', and lead cement to the surface. OH logs caliper may indicate more cement is needed than is calculated in this procedure. Call out Dowell ahead of time. a) Have mix water available. Note: Mix water should be at least 45°F--70°F is optimum. 2. RU Weatherford casing Crew. Test equipment and power packs before RU to running casing 3. MU and Baker-Lock the first two joints of3-1/2" WELLPLAN213-1 ov er3 .DOC Page 18 7/12/2002/4:23 PM UNOCAL~ AFE #154978 Swanson River Unit SRU #213-10 Drilling Program 07/12/02 Revision #3 4. PU and verify flow path through float equipment. 5. RIH and verify floats are holding. 6. RIH with appx 4106' of3-1/2", L-80, Imp Buttress. spots. IJt 1 Jt IJt 56 Jts Rotate if necessary to RIH through tight 3.5" L-80 Imp buttress with a Baker float shoe Baker-Locked onto the bottom. 3.5" L-80 Imp buttress with a Float collar Baker-Locked onto the bottom. 3.5" L-80 IMP buttress with a Landing collar Baker-Locked onto the bottom. APPX of 3.5" 9.2 lb/ft L-80 Imp buttress to Surface One short joint of 3.5", 9 .2lb/ft L-80 Imp Buttress-- for correlation purposes should be available, placement in casing string will be directed after reviewing the logs 1 Jt Chemical injection Mandrel installed with Control line spaced so that the Injection mandrel will be at 1750'. Install control line protectors every other joint. 40 jts 3.5", 9.2 lb/ft L-80 Imp Buttress - Tubing as needed to the sùrface. 1 Jt Tubing hanger made up on pup joint with chemical injection line terminated on bottom of hanger. Have control line run to the floor from the top of the hanger. Landing joint with Tubing hanger threads and XO to plug dropping head. This joint should be a 20 foot pup joint to facilitate landing the tubing with the plug dropping head near the floor. Tag the hanger into the "B" section and pick same up 1 foot to facilitate getting returns to the surface. NOTE: While running casing into the hole, maintain pressure on control line and pump through same before the cement job, and again after the cement job to ensure that the mandrel is free of cement. 1 jt 7. Appx 30' from TD, MU plug dropping head and chicksan lines. 8. Land Tubing hanger and establish circulation via the outlet valves on the "B" Section. Take returns from the flow line and from the outlet valves, using a vacuum truck to take returns to the cellar via the outlets and to the flow line if the outlets plug. Check and note pump pressure. Circulate the hole clean and ensure that the returns via the outlets are 1 00%, otherwise pick hanger off seat and attempt to regain circulation. The cement job will be conducted with the hanger landed. There is additional risk to the control line for the chemical injection mandrel during any reciprocation, so only reciprocate the pipe if cement returns are lost or compromised. 9. MU the cement head. Pressure test to 3000 psi. Circulate until hole is clean. Pump sweep with hanger off seat and insure that the hole is clean prior to landing hanger. Reciprocate the tubing hanger and tubing a three foot stroke slowly until the hole is clean. Do not exceed annular velocity used to drill the hole, 145 gpm. 10. RU Dowell cementing line to cement head and pressure test the same to 250/3,000 psi. WELLPLAN213-10Ver3.DOC Page 19 7/12/2002/4:23 PM Swanson River Unit SRU #213-10 Drilling Program 07/12/02 Revision #3 UNOCAL(; AFE #154978 x. Cement 3.5" Production Casin2. Excess Requirements: Lead Slurry: 30% estimated excess in open hole subject to caliper log. No excess in the Surface Casing. Interval planned is from 1489' to Surface. Tail Slurry: 30% estimated excess in open hole subject to caliper log. No excess in the float track. Interval planned is from TD to 500 feet inside the surface casing. This is a gas block slurry. Batch mix the Tail slurry. Calculated TOC should come to Surface. Lead Slurry Data (Actual data should be checked with tinallab test): Total volume: Total sacks: Slurry Weight: Cement Yield: Recipe: Mix Water: Thickening Time: Fluid Loss: 220 fe 1 111 12.5 lblgal 2.11 ft3/sk Class "G" + 2.0% BWOC D079 + 0.50% BWOC SOOI Fresh Water PLUS 2.0 GPS D600G + 0.20 GPS D047 4.5 Hours to 30 Bc and 5.5 Hours to 70 Bc TBD Tail Slurry Data (Actual data should be checked with tinallab test): Total volume: 650 ft3 Total sacks: 483 Slurry Weight: 15.8lb/gal Cement Yield: 1.17 ft3/ sk Mix Water: Fresh Water Recipe: Class G + 0.50% BWOC SOOI + 0.30% BWOC D065 + 0.2% BWOC D046 + 0.4% BWOC D167 Thickening Time: 3.3 Hours to 30 Bc and 4.6 Hours to 70 Bc Fluid Loss: TBD Compressive Strength: TBD BHST: 125 F (verify with open hole logging tools) BHCT: 80 F Chern Wash 100 (Sta2e 1): Total Volume: 10 BBLs Fluid Weight: 8.33 PPG Additives: D122A (Mud Thinner) @ 0.500 gal/BBL: 7.5 gallons J237 (Fluid loss), 0.250 gal/BBL: 3.8 gallons WELLPLAN213-1 OVer3.DOC Page 20 7/12/2002/4:23 PM . - t UNOCAL@) ( Swanson River Unit SRU #213-10 Drilling Program 07/12/02 Revision #3 AFE #154978 Note: Verify all depths and volumes before cement job. Rathole volumes were not figured into calculations. Pump Schedule: Volume Mud Weight (PPG) 8.33 N/A 12.5 15.8 Fluid Pumped 10 1 111 Sacks 483 Sacks CWI00 Chern-wash 100 Bottom Plug Lead Slurry: 1489' to Surface @ 0% Excess in Casing Tail Slurry: 4106' to 1489' @ 30% excess in Open hole plus 0% excess in Casing and shoe track Baker drill pipe wiper plug Displacement with Dowell (6% KCL WATER) *** 36 BBLS 10.0 Pump at maximum rate (but no faster than the annular velocity used to drill the 6" x 3-1/2" DP hole) of3.5 bpm to enhance bond. 1. Mix and pump 10 bbl Chern-Wash CWIOO on the fly using the cementing unit displacement tanks. Drop Bottom Plug. 2. Pump the cement slurry using G cement with additives. Note: Density log caliper volumes may cause the volumes to be adjusted. Talk with Anchorage on final volume calculations. 3 If returns are lost, then reciprocate the Tubing for a three foot stroke keeping the hanger below the bottom ram. If overpull exceed 50000 pounds, cease reciprocating and land hanger immediately. 4 Drop Top wiper plug. Note: Flush cement from surface lines before dropping plug. 5 Pump 6% KCL water as displacement with Cementing Unit pumps at max rate 6 Slow pump rate just before plug bumps. Report volume and timing of any losses throughout job. Report whether reciprocation was done at any time throughout the job. Note: Discuss amount of over displacement to achieve bump of plug. There is only 1.5 bbl of capacity in the 80' shoe track. Discuss with Supt whether or not to over displace. 7 Bleed down pressure and check that floats are holding. Page 21 7/12/2002/4:23 PM WELLPLAN213-10Ver3.DOC UNOCAL(Ð AFE #154978 ( Swanson River Unit SRU #213-10 Drilling Program 07/12/02 Revision #3 8 Rig Down Cementers and lay down landing joint. 9 Install BPV and Nipple down BOPE 10 NU XMAS tree and test same to 3000 psi. 11 Rig down and move out XI. Complete with Wireline Unit After RÎf! has Moved Out. 1. Rig down and move out Nabors 129 2. Move in and Rig Up Pollard Unit to Swab Down the Tubing 3. Swab The Tubing to 2000 feet 4. Rig up flow lines to production facilities 5. Move in and Rig Up Schlumberger wireline 6. Test Lubricator 7. Make Dummy Weight Bar/Guage Ring Junk Basket Run 8. Pick up Wireline Guns and RIH to Perforate 9. Perforate as directed. 10. Put Well on Test 11. Add Perforations as directed. WELLPLAN213-1 OVer3 .DOC Page 22 7/12/2002/4:23 PM UNOCAL8 AFE #154978 ( Swanson River Unit SRU #213-10 Drilling Program 07/12/02 Revision #3 DIRECTIONAL PLAN ~ urmCALi1 SRU 213-10 Proposed Well Profile - Geodetic Report ~ i'I&pDl'1 D.11e: Clent Field. SlrudlJ't .' SICt: 'Well: Ekirehcll: UWIIAF.' Su!\t1!(l Nlmr: D.11e: Telt AHD I Dt41E:i'lC lalla Grid Cocn!In¡ft Syst¡en: Il;aIOf UUUl~: LOOJIIcf1 Grid KIE Y!X' Grid .COl'IYCf9l1lOl Ar¡¡¡Ie: Grid scale I'I£I\)r: J¡re . û :1))2 _\,~ .S_I~:t., R~~ Utll .S_'~'I R,.~ i SRJ 21:> 1 G ~;:: ,"""IIIIY 2D 10 : F'5¡! 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Or" :349.3.00 0.87 187.01 :3129<.4~ 1281.88 -1272:31 .1 Sò3.40 4.00 2484549.35 348313.01 t~ 60 797S{¡:):!8 W15084883222 TD 4008-.71 087 1.87 ;01 3735.00 1291.08 -128.1.4:3 -157.52 0.00 248454024 346371.77 N 6079786834 W 15Ct84æ:3849 WELLPLAN213-1 OV er3 . DOC Page 23 7/12/2002/4:23 PM UNOCAL@; AFE #154978 ( Swanson River Unit SRU #213-10 Drilling Program 07/12/02 Revision #3 'Y'"IRTI':.'AL S~IC.H VIHiI' ~ U-.:JCALI) C11.;nt: rJnoc:;; 1 jA;;;.1l : Fl.. le!: :U.H :P; S;~~ns'n R1v~r Unit £"t L"I..I:t U r... : :=';v..n~ :.n F.l,:..r ::.;. : t 1 ¡: n .r. t: H -:. 1 '1';:1 Ddt.;;; : .JtJn~ 1':', :: I:,,:.: t, ~ I I 500 11)".)0 ~::)" .I ~, s.:JC. 8 ~ lO ~. " 1; J:: qy ..... ¡:: :Co ..t:~ "ä 0 žt)!}ò ð. ; . m -;5i .~ . :e~ 'œ a:: ::> >- ! ~ ~o .=I.U ~d ..- j ~ I k\ L HCdd »)0 Hold Ar"!:"JIE! 0.87 3501} r ( "'" t 5{¡) I 8 ~ooo Vêrocal Sêe1iõf1 Dépa:f(Ufê alt87 .01 dêg fr.om (0.0, 0.0). (t mn = SOO feêt) WELLPLAN213-1 OVer3 .DOC Page 24 7/12/2002/4:23 PM . - . UNOCAL@> AFE #154978 ( Swanson River Unit SRU #213-10 Drilling Program 07/12/02 Revision #3 PLl.H VIIR ':¡l.;r~t: Unoç;;l ::l~-l p, ~ ¡.;,; 11 : Fl. I.::'!: ::'.f~;:¡f)!;,:l1 E1":~1 U,nit -- £tn¡:tur... : £-I'r;¿n!:: n F~ 1~:.; r EC,:;;l¡¡;;: 1 iti . .:. ':. (> t' t Ü;¡!;;,;, : 1 0 - Jun -.:. ,:'':1;;; -4O'J I .100 0 r 200 r I 400 ']'rUQ li10rtb 0 M;¡g D;c I E ':'0.81< ! e, ~ .200 ,2:J[) ......... -400 ,} '~ .:::\. ~ ~ f~ ~ ~ t1 :t I ... ^ ... J: ~ <:> z -4à0 -800 -000 ~ -800 0 W v 'iI '1/ .&Jò -1 (JOO J--- ~..............,.;.J......~:: ------- . ! ,.,' --+ -1 (¡CO -uoo .~:", I =e:t;": I I . :.!.OO 0 «< INEST .1:200 .4ð:) I 200 E.AST »> WELLPLAN213-1 OV er3 .DOC Page 25 7/12/2002/4:23 PM Swanson River Unit SRU #213-10 UNOCAL~ Drilling Program AFE #154978 07/12/02 Revision #3 r JTiì I ,m q] Jfþ lUJ" rem ~~ ~ ~J=2 0[- [J[ L~ L ~ L~ 0 rnl,) ~~ 0 ~ [ ~~ lUJlj ~ D jMoC J 13 3/8" ~"'"'''''' , 7" ~L[J?~ Starting head is a Cactus 13 5/8" 3M x 13 3/8" SOW, w/2-2" LPO Tubing spool is a Shaffer Oil Tools 55-L 1 Spool, 13 5/8" 3M x 7 1/16" 5M, w/2-2 1/16" 5M Std OL. Casing hanger, GBI, C-22, 13 5/8" x 7" Tubing hanger, Shaffer Oil Tools, AJO, 7 1/16" x 3 1/2" BTC top and bottom, 3" CIW type H BPV prep, Ext. Neck, with one control line port for chemical injection 3 %" NOTE: ONE SIDE OF THE TUBING SPOOL MAY HAVE BEEN BORED FOR A LARGER THROUGH BORE TO FACILITATE GETTING RETURNS DURING THE CEMENT JOB. WELLPLAN213-1 OVer3 . DOC Page 26 7/12/2002/4:23 PM . - a UNOCAL8 ( Swansòn River Unit SRU #213-10 Drilling Program 07/12/02 Revision #3 AFE #154978 3,000.0 1,250,000 - .... Q,¡ Q,¡ c.,;;; ~ 4,000.0 1,000,000 .... c.. Q,¡ C ¿ 5,000.0 750,000 6,000.0 500,000 UNOCALi 1,000.0 L 2,000.0 7,000.0 8,000.0 0 WELLPLAN213-1 OV er3 . DOC SRU 213-10 Kenai Peninsula, Alaska Depth vs. Time Summary 2,000,000 - Proposed SRU 213-10 - SRU 223-28, 1997 - ACTUAL TIME VS COST AFE PLANNED TIME VS COST -- 1,750,000 1,500,000 250,000 5 10 15 20 25 Time (Days) Page 27 7/12/2002/4:23 PM UNOCAL@> RKB to TBG Head = 16.5' Elevation 293.5 Feet L. -- L ~ 2 L1 \. TD = 4106' MD, 3735' TVD Directional Well WELLPLAN213-1 OV er3 .DOC AFE #154978 ~ SIZE WT 9-5/8" 47 7" 29 (: Swanson River Unit SRU #213-10 Drilling Program 07/12/02 Revision #3 CASING AND TUBING DETAIL GRADE CONN TOP K-55 Weld Surf L-80 Butt Surf BOTTOM 80' Driven 1800' TVD 3-1/2" 9.2 L-80 IMP Butt Surf with 3/8" ss methanol injection line Surf 7" Surface Casing @ 1989' MD, 1800 TVD 3735' TVD 1750' JEWELRY DETAIL NO. Depth Item 1 Surf 3-1/2" Tbg hgr w/Cameron "H" BPV profile 2 1750 Macco 3-1/2" SMO-1 Chern Inj Mandrel wllOOO psi chern inj valve PROPOSED PERFORATION DATA TOP BTM ZONE/FORMATION SPF COMMENTS -2125 -2135 A9 Sterling Sand 6 Confinn with log 6 Confinn with log 6 Confinn with log 6 Confinn with log 6 Confinn with log -2250 -2260 A10 Sterling Sand -2635 -2645 B3 Sterling Sand -2810 -2820 B5 Sterling Sand -3010 -3020 B6 Sterling Sand Page 28 7/1212002/4:23 PM ( Re: THE APPLICATION OF UNION OIL COlvtPANY OF CALIFORNIA ("UNOCAL") for an order allowing well SRU 213-10 to be completed without a tubing and packer Conservation Order No XXXX Swanson River Field Swanson River Unit Well (SRU) 213-10 July XX, 2002 IT APPEARING THAT: 1. By application dated June 11, 2002, and received by the Alaska Oil and Gas Conservation Commission ("Commission") on June 11, 2002, Union Oil Company of California ("Unocal") requested an order from the Commission allowing the proposed Swanson River Unit ("SRU") 213-10 well to be completed without a tubing and packer as required by 20 AAC 25.200(d). 2. Notice of opportunity for public hearing was published in the Anchorage Daily News on June 17,2002 in accordance with 20 AAC 25.540. 3. Unocal submitted additional information concerning the application by letter dated June 25,2002. 4. The Commission received no comments concerning the application or requests for a public hearing. FINDINGS: 1. Unocal is operator of the Swanson River Field. 2. Unocal proposes to drill the SRU 213-10 well to a depth of approximately 3735feet TVD (4106' MD), from a surface location 1725 feet from the north line ("FNL") and 628 feet FWL, Section 10, T8N, R9W, SM to a bottom hole location of3103 feet FNL, 552 feet FWL, Section 10, T8N, R9W, SM. 3. Unocal proposes to drill the well using a slim hole drilling technique, running small diameter casing, and completing the well without a tubing and packer. 4. Commission regulations, 20 AAC 25.200( d), states: "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, unless the commission specifically approves production through the annulus to increase flow rate without jeopardizing ultimate recovery from the well." 5. Commission regulations, 20 MC 25.990(26), defmes fluids as "any material or substance that flows or moves, whether in a semi-solid, liquid, sludge, gaseous, or other form or state." 6. Unocal is drilling the SRU 213-10 in order to produce marginal attic gas reserves updip from the watered out SRU 212-10 well located on the same pad. 7. The gas reserves targeted for production ftom the SRU 213-10 well are considered marginal because they have already been partially depleted to about 6 ppg equivalent and will not flow against a pressure exerted by hydrostatic column of ftesh water. 8. Pro duc ibility and economic viability of the well will depend on isolating the productive gas zones of interest ftom any water bearing zones. 9. The SRU 213-10 well is located in a remote location of the Swanson River Field, and there is no urban development nearby. 10. Unocal proposes to construct the SRU 213-10 well as follows: 133/8 inch conductor casing driven to 80 feet, 7 inch L-80 surface casing run to 1800 feet TVD (1979' MD) and cemented to surface, and 3~ inch L-80 production casing run to TD and cemented to the surface. 11. The 3 ~ inch production casing will be cemented with a two slurry cement job consisting of a low weight lead slurry and a conventional tail slurry to isolated gas bearing productive zones. 12. The 7 inch production casing will be set just below the maximum depth of ftesh water and just above the targeted gas bearing shallow production zones. The anticipated leak off on the 7 inch surface casing shoe is anticipated to be about 15.5 ppg equivalent. 13. Maximum anticipated surface pressure for the targeted depleted gas sands is expected to be around 600 to 800 psi. 14':<{he slim hole drilling techni signlfi antly reduces the costs 0 eting a we . comparison to a nventionally <if d and cased ecause of the' smaller g siz d the time needed to dri 11d C\J plete the well. 15. The small diameter production casing precludes running a tubing and packer. 16. cause of the lower cost assocÎ3tect with drilling and running a lJbingkss, sli ole completion, de pment ofs aller hydro carbo ccurnulations and marg I reserves ore likely to occ an wit ore expensive convention oil andg dr" g and completion techniques. 17. Tubingless completions have been used elsewhere around the world to promote development of marginal reserves. 18. Without a tubing and packer, there are fewer options available for performing cleanouts and remedial work, which could lead to the early abandonment of the well. 19. Because of the marginal reserves targeted for recovery, the life expectancy of the SRU 213..10 is expected to be relatively short. CONCLUSIONS: 1. The SRU 213-10 well is targeting low pressure, marginal gas reserves. (' 2. The targeted gas reserves are capable of unassisted flow the surface, but only after hydrostatic pressure has been removed 3. An exception to 20 AAC 25.200(d) is necessary to allow the drilling and completion of the SRU 213-10 well without a tubing and packer. 4. The SRU 213-10 well is being drilled at a location updip to and that has been partially depleted by the existing SRU 212-10 well. 5. The SRU 213-10 well is not expected to encounter liquid hydrocarbons. 6. The SRU 213-10 well will likely result in production of gas that could not be produced economically using more expensive, conventional drilling and completion practices. 7. Because of the marginal reserves targeted for recovery, the SRU 213-10 well is expected to have a short life. Completing the well with tubing and packer would not increase the well's longevity before declining production forced the well's abandonment. 8~ NOW, THEREFORE, IT IS ORDERED THAT: Unocal's application for an exception to 20 AAC 25.200(d) to allow the drilling and completion of the SRU 213-10 well without tubing and packer is approved. ( 5. Zonal Isolation Protection of USDWs and prevention of cross-flow are prime considerations. Designs lì,J v- ~ should provide a high level of assurance the cement sheaths and tubular connections will Y: - maintain adequate well integrity. 5l.L ú~" C~¡ ()øs/~J¿: v. C . There should be a high success rate for zonal isolation in areas where monobore 5~~~--- are proposed. - ~~u C~5 ~~. rç;rl--. l.sD[: . Completion design should incJude packers at all tubular overlaps for integrity belo 6. MonitOri:~rfacecasing. ~ ~ ~ó P~r/;:;;;:~ ~ Monitoring well annuli provides assurance of integrity for any wel~Ñ ~.- : Monobore completion design should include a monitorable annulus at least inside the - ;J~ surface casing, depending upon planned depth. ;::=- Production tubulars should include landing nipple profiles against which MITs can be ~ performed. . "'-------~ ./""'- Regular production rate monitoring is recommended to provide early indication of -- Y6~~' tubular failure. . I Jn~ I () ,.. .., v:;; . ~. . ~ . Regular tubular evaluation logs are recommended to ensure integrity. - ~\ö."'\o ,~c-'~, ~ ' ~\-;\~t)\~ b~Q:f\. !0a&-J) pL-g f"~ ~ ì ~ í" +.r;P ~ ~ 1J.AA I t\~ ~ \~~\S Co T ~ 'r>~"'\ ~\-Q:~Q\S CJ..~<Q_'S ~-\-... ~~a-~- o~~ \0 'S<ò+- ::rvtf- a.À0~"~s~p ~? L-- S>-p \0-<;.. (!) t' 0'5<G O-.f\ '\ ~-~ ~Â-Etb\;(j J ~s-l '\J!-!f ~ IT ~ . ~;.. J.r .'iI- 1= ,.~hð> ~ óVO.'.'..; ~ ( Ce-. "'/Iu~ 6--..~''''-'''- +t.. ~ I l)W\. -- f'¡ ~ /1 Î JA , /...-----/. / ~7 ~. (¡.. . '- ( «' ~ ?jÞ''Y vcY-A ~- 1 t.-~. ~ c.. ~ --r~ / ~ ~~ & .A-"t .ß--'""~ I (j - ~~~ C'5. Monobore Considerations AOGCC requires tubing and packer completions in order to isolate casing IDs, contain well pressure within tubing, protect USOWs, and provide well diagnostic capabilities. Following are specific criteria the Commission may use to screen proposed monobore completions. Criteria are arranged in no particular order, with brief anecdotal comments. "Relatively" appears often, and should be quantified where possible. 1. Pressure Generally, smaller diameter tubing (relative to casing) is rated to higher pressure than is casing. . Expected well pressure should be "relatively" low. ~/) J ; , \ .. .....- Pf2,{ -:;c Nor w..Ý - <;;t-Ô () 2. External Corrosion Certain naturally occurring impurities in gas and oil react with water to form highly corrosive acid. For example, CO2 and H2O form carbonic acid. Other acid gasses form similar compounds. High salinity formation water (very common) is also corrosive. V" . How corrosive is the subsurface environment in an area where monobores are ~s- proposed? .---"- v/ V~~4t.... ::: c.~+~ . Proposed cement should protect casing 00 from exposure to formation fluid~. " >t1~..t ~ pVZ:dc.s, I . Proposed casing and liner connections should be 1ST modified at minimum, or ? premium connections such as NSCC. -- ....-- ~----.~ . What are casing failure statistics in areas where monobore completions ¡; l þl'1 -? ) proposed? ";\c \ r "\ ... \ \. . ....~, -,/., \ez:; rt<:...., c"ü--s.\'''~ ~\ '-...) ~ c;..\ "'~~fè~~ ~ ~ ~ ----_..-~--- 3. Internal Corrosion ~~'" S ~ \Ce. \c~.. ~'\O~\x~ ,,~"':> ~~~~ \C)<":>~ ~ L.~\~ r See 2 above. ''Tubingless'' completions allow formation fluid flow directly insidè casing. Often corrosion is exacerbated by high pressure. v" ~a.J . Monobore completions should be limited to non-waterflood areas, for example, the gravity drainage portion of PSU. Expected water cut volumes should be relatively ~ low. ~ ~ . Expected gas lift depth should be relatively shallow. N t4- ",,,,;ø;P-';"''''''-'''';~~':-\ l , \ . ~odified or p!emium connectns are recommended as above. *íE ~ 4. Well Longevity '0 ~~ "\Ö-I"'> 'S. I~~ ~~\\~ Monobore completions should target relatively small hydrocarbon accumulations. Expected production life of a monobore should be short. Monobore integrity should V G~ A-t:e..Þf.~ ensure a design life of 10 to 15 years. ~) Dp,vtJ . ~. ;;!Æ~. Õ... }. ru I : I ¡! L.' '-1 L..:::i r (ffl Ie III J ¡ r ~u I~ l ~\ ~fY7 Æ\ L \ ! I g , n ì ; ¡ ,\ \ I \ ru bUu ~I UûLF1J í I l TONY KNOWLESf GOVERNOR AItASIiA OIL AND GAS CONSERVATION COMMISSION / ! ¡ ¡ ; 333 W. 7fH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 / l James Harrison Drilling Manager Unocal PO Box 196247 Anchorage AK 99519 Re: Swanson River Unit 213-10 Unocal Pennit No: 202-118 Surface Location: 1725' FNL and 628' FWL, Sec. 10, T8N, R9W, SM Bottomhole Location: 3018' FNL & 465 FWL, Sec. 10, T8N, R9W, SM Dear Mr. Harrison: Enclosed is the approved application for pennit to drill the above gas development well. The pennit to drill does not exempt you from obtaining additional pennits or approvals required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required pennits and approvals have been issued. In addition, the Commission reserves the right to withdraw the pennit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Codeunless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the tenns and conditions of this pennit may result in the revocation or suspension of the pennit. Blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25.035. Sufficient notice (approximately 24 hours) of the BOPE test perfonned before drilling below the surface casing shoe must be given so that a representative of the Commission may witness the test. Notice may be given by contacting the Commission petroleum field inspector on the North Slope pager at 659-3607. Sincerely, (~AA^ -- /(bkL~ 1~u C;~~echsli Taylor O' Chair BY ORDER OF THE COMMISSION DATED thisÂ0day of July, 2002 cc: Department ofFish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. ~ It -û,;f- STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 1 b. Type of well Exploratory Stratigraphic Test Development Oil Service Development Gas X Single Zone Multiple Zone 5. Datum Elevation (OF or KB) 10. Field and Pool 310' RKB Swanson River Field 6. Property Designation Swanson River Unit A-028405 17. Anticipated pressure (see 20 AAC 25.035 (e)(2) Maximum Surface 1307 psig. At total depth (TVD) 3735' Setting Depth Top Bottom TVD MD TVD 0 0 80 80 Pre Set WI Water Well Rig 0 0 1989' 1800' 274 Sacks = 374 cuft Class G blend 1650' 1540 4106' 3735' 400 Sacks = 463 cuft Class G blend 0' 0' 1650' 1540' NIA 1 a. Type of work Drill X Redrill Re-entry Deepen 2. Name of Operator Union Oil of California (dba Unocal) 3. Address P. O. Box 196247 Anchorage. Ak 99519-6247 4. Location of well at surface 1725' FNL and 628' FWL Sec. 10 T8N, R9W, SM AK At top of productive interval Sterling 2818' FNL & 490' FWL @ 2434' TVD Sterling At total depth S <!.-c... /0 TV. JJ I R." W S /VI - 3018' FNL & 465' FWL @ TO of 3135' TVD ~,<- 12. Distance to nearest 13. Distance to nearest well property line 747' 7. Unit or Property Name Swanson River Unit 8. Well Number 213-1 0 9. Approximate spud date 6/31/02 14. Number of acres in property Lease 2560 acres 25' at SHL (SRU #212-10) 16. To be completed for deviated wells Kickoff depth 500 feet Maximum hole angle 38° 18. Casing program size Specifications Hole Casin Weight Grade Coupling g 12.25 9-5/8" 8.5" Length MD 7" 47 26 80' 1989' L-80 L-80 Weld Buttress 6" 3.5" Liner 3.5" Tie back 9.2 L-80 IMP Butt 2450' 7" Csg 9.2 L-80 IMP Butt 1650 19. To be completed for Redrill, Re-entry and Deepen Operations R Ei""r:~ , t.t.wS q ("¡ q r: f\ ,) L 0 LUlffc 11. Type Bond (see 20AAC25.025) AK Statewide Oil & Gas Bond Number U 62-9269 Amount $200,000 15 Proposed depth (MD and TVD) 4106' MO 3735' TVD Quantity of cement E Alaslm Oil & lJOmmissu:m Anchorage 21. I hereby certify that the foregoing is true and correct to the best of my knowledge ( , "'\ Signed ~ \(L \~ Title: Drilling Manager Date d ~ :s~ 0 oJ.. C) Commission Use Only Permit Number API Number Approval da~ <¡{j:)- con~~;:~p~<§- Samples r~~~i~\ ~~ ~esê)C~ '5 ~~g requirek~l~- @' Hydrogen Sulfide measures Yes 0 D~nal Survey required ~ No Required working pressure for BOPE M 3M 5M 10M 15M Other: - . --'(@ISlgnedBYbyorderof r-J Á~ Approved by . _\Jè:lmmy&chSIi TaØ0ftnmissioner the commission Date / It?'Ís~u mV't l'n~trl'PII'cate Form 10-401 Rev. 12-1-85 AFE#134703 Form 401 AOGCC Permit To Drill SRU 213-10 ORIGINAL 4 See cover letter for other requirements 6/28/2002 .) UNDCALe SRU 213-10 WFlI SURFACE LOCATION , t I ! PROPOSED SRU 213-10 WELL ASP ZONE 4 NAD27 GRID N: 2485819.433 GRID E: 348545.820 LA TlTUDE: . 60848'04.9448" N LONGITUDE: 150850'52.6444" W 172~' FNL 628 FWL SECTION 10 T8N, R9W, S.M., AK ELEV. 293.5 FT. NAVD88 P.C. Box 46B SOl-CCTNA, AK 99669 ~ consulli~e Group ~ Tesllne TEl- 907.283.421 8 FAX 907.283.3265 111 }- f.u::J bP-j' ~~ 1/ ~ } I ! J )- }>. J . . PROJECT UNOCALSRU 213 -1Ø SURFACE LOCA rlON LOCATION Swanson ~iver Unfl, Alaska SCALE DATE DRAWN BY M.ô.M. DATE 3/21/(2)2 III = b(2)' ~ ~ " I I .4J /3 REVISION PROJE~T/DWG. Ø23Ø23 SHEET NO. OF Unit BOUndary~ ---- ISRU 213.10 ~ I Proposed SL rface N I --428'- ~ Ul- +g..--~ (S) ~ I I I 345000 I N ,-Þ: æ CD______-- (S) (S) (S) N ¡..þ rn (S) (S) (S) (S) .- A-028077 ...---. I I . J !--- I I I I I I I I I SRU 242-16 ~ Scale 0 500 1000 1500 2000 2500 3000 Feet .. -- -251,J . I .(0 ø 0 ø I 352077 I - - - --~~- - - + 1 G Ñ 0 ~. ëo CIO Il) N A-028405 SRU 34-10 0/ SRU 211-15 SRU 21 15 ;¡! 0 0- SRU 3 -15 SRU~ 5 R U 1 2 -.1 5 * ^ \ _\ SRU 32R-15 UNOCALO COOK_INLET Northern Swanson River -Unit Scale' Units' 1:12000 Interpreter. EPG FEET Dote' 24-May-2ØØ2 UNOCAL~ Swanson River Unit SRU 213-10 Well LOCATION MAPS AND PLATS LOCATION MAPS AND PLATS PROPOSED LOCATION PLAT THE PROPOSED UNOCAL WELL SRU 213-10 WILL BE LOCATED ON THE SAME PAD AS THE EXISTING SRU 212-10 WELL. THE P AD LOCATION AND LAYOUT OF THE EXISTING ROAD ARE SHOWN ABOVE IN SECTION 10. DEAD END PROPOSED 213-10 SURFACE LOCATION 242-16 *-- ----"", / \ / \ ----'--- / \ --- - .-/" LOCATION MAPS AND PLATS SRU 213-10 6 6/28/2002 UNO[AL~ Swanson Rive( ~nit SRU 213-10 Wel' CEMENT PROGRAM CEMENT PROGRAM 13-3/8" Casinq (Driven to 80') Note: This string is only for structural support of the wellhead, and diverter stack. 7" Casinq (8-1/2" Hole to 1800' TVD, 1979' MD): Cement volume based on open hole volume plus 30%, shoe joints, and annulus. The job will consist of a lead and tail and cement will be brought to surface. The estimated volume is as follows: 1400' x 0.1267 cuft/ff (8-1/2" x 7") X 1.3 = 230 cuff = 116 SXS (1.98 Yield) 80' x 0.5733 cuft/ff (13-3/8" by 7") X 1.0 = 45.8 cuff = 23 SXS (1.98 Yield) TOTAL = 276 cuff or 139 SXS Lead @ 1.98 Yield Tail 500' x 0.1267 cuft/ff (8-1/2" x 7") X 1.3 = 82 cuff = 71 sxs (1.18 Yield) 80' shoe joint x 0.2148 cuft/ff = 17.18 cuff = 14.5 sxs (1.18 Yield) Sq.'YL\cz. pQJ ~ \ '3 S. \Xt~ '~<r'''' ~C~~ (\ TOTAL: 276 + 82 + 17 ~= 374 cuff or ~XS Lead + 85 SXS Tail (1.16 yield lead and 1.98 Tail) = 2'74 Sxs Total Lead 3-1/2" Liner Casing (6" Hole to 4106' MD) Cement volume based on open hole volume plus 10°/Ó, shoe joints and annulus. The job will consist of a tail cement with returns brought to 300 feet above the top of the liner. The estimated total volume is as follows: Tail: (1689-1389)' X 0.208 cuft/ff (7") X 1.0 = 62.5 cuff = 54 sxs (1.16 Yield) (1989-1689)' X 0.1469 cuftlft (3.5 X 7) X 1.0 = 44.0 cuft = 38 sxs (1.16 Yield) (4106-1989)' X 0.1295 cuft/ff (6" x 3-1/2") X 1.3 = 356 cuft = 307 sxs (1.16 yield) 80' shoe joint X .0087 cuft/ff = .7 cuff = 0.6 sxs (1.16 yield) TOTAL: 62.5 + 44.0 + 356 + 1 cuff = 463 cuft = 400 sxs CEMENT PROGRAM SRU 213-10 7 6/28/2002 UNOCAL6., Swanson(.<iver Unit SRU 213-10 Well LOGGING PROGRAM LOGGING PROGRAM The following constitutes the proposed geological and evaluation logging program for the subject well. All tool suites should be available on location for all anticipated logging runs; final determination of which tools will be run will be based on hole conditions at the time of logging, and geologic results. All "Anticipated Logging Dates" are based on pre-spud estimates of drilling duration and should not be considered final. Unocal Drilling Engineer will notify Schlumberger 8-10 days in advance of any logging run (with updates as needed). 8-1/2" SURFACE HOLE FROM 1979' TO SHOE OF 13-3/8" @ +80' CASED HOLE LOGS ANTICIPATED LOGGING DATE: 10 July REQUIRED LOG Gamma Ray Log 6" PRODUCTION HOLE FROM +4106' TO SHOE OF 7" @ +1979' OPEN HOLE LOGS ANTICIPATED LOGGING DATE: 10 July PLANNED LOG MWD With DIRlGR to TD PLANNED LOG Platform Express - PEX AIT/DSI/RHOB/NPHI/GRlSP CASED HOLE LOGS PLANNED LOG OPTIONAL LOG FROM PBTD TO TOP OF 3-1/2" CEMENT GRlCCL (Will be run thru tubing rigless) USIT/CBT/GRlCCL (Dependent on Cement Job) CASED HOLE PERFORATING (INTERVALS TBD) PLANNED TOOL 2-1/2" POWER JET GUNS OTHER GEOLOGIC EVALUATION MUD LOGGING Mud logging will be conducted from the shoe of the 9-5/8" @ 80' until total depth. GAS DETECTION Gas detectors will be functional and running prior to spud. CORING No core is planned for this well. NOTES: All logs are to record UNION OIL COMPANY OF CALIFORNIA as the Company or Operator on the log header. ELEVATION LOGGING PROGRAM SRU 213-10 8 6/28/2002 Swanson(.~iver Unit SRU 213-10 Well LOGGING PROGRAM The rig site Ground Elevation is 293.5' AS MEASURED BY McLANE SURVEYING ON PROPOSED PLAT. The As built Plat will be furnished after the Pad is releveled and the wellhead is installed. The actual Rig KB will be measured after MIRU on location. All contractor Field Service Representatives will be notified of RKB in writing by Unocal, and will be responsible for relaying the correct RKB to the engineer( s) on location. UNOCAL~ LOGGING PROGRAM SRU 213-10 9 6/28/2002 UNOCAL~ SWANSON RIV('..1 UNIT SRU 213-10 Well ANTICIPATED FORMATION TOPS ANTICIPATED FORMATION TOPS Union Oil Company of California Proposed SRU 213-10 Well Elev 293.5 Geologic Tops and Correlations RKB 310 SRU 212-10 Proposed SRU 213-10 Marker MD TVD MD TVD TVDSS Difference Base Glacial 515 515 515 515 -205 0 L. Sterling 2600 2600 2810 2460 -2150 140 A9 2600 2600 2810 2460 -2150 140 A10 2700 2700 2915 2560 -2250 140 B3 3080 3070 3333 2935 -2625 135 B5 3255 3240 3475 310~ -2795 135 B6 3438 3415 3662 3285 -2975 130 Beluga 3550 3522 3770 3392 -3082 130 Total Depth 4106 3735 -3425 N/a ANTICIPATED FORMATION TOPS SRU 213-10 10 6/28/2002 UNOCAL81 SWANSON RIVER UNIT SRU 213-10 Well OFFSET WELL DATA OFFSET WELL DATA SWANSON RIVER UNIT WELL SUMMARIES 0 N 1.0 1.0 (0 ex> ~ T'"" 1.0 1.0 1.0 T'"" 1.0 1.0 T'"" T'"" C") C'\I a:I N T'"" 0) N T'"" T'"" I T'"" T'"" N N C'\I M M I ~ N M T'"" I I N N ~ C'\I N N c;; C") ~ C'\I ~ 0 T'"" C'\I C") ~ C") C'\I C'\I C'\I C'\I 20" -20" SPLC -20" - 22" 20" 22" - 20" 22" 22" 16" 22" 13-3/8" 13-3/8" 1000 22" ~, - 13-3/8' 13-3/8'\ 2000 9-5/8" ~ ¡" - {" - 9-5/8" 11-3/4" - 9-5/8" SP SP 3000 SPLC 13-3/8" 11-3/4" 11-3/4" - 13-3/8" 13-3/8" 10-3/4" 9-5/8" 4000 .SP -SP TO - 5000 - 7" ... 140 Q) TO 7" -SP Q) Trip Gas Days to -6000' ~ 140 10.50 190 140 170 12.50 90b-1/?" 10.50 180 8.50 9.50 .c 6000 . SP _SP -TO ... 9.50 c. - 9-5/8" 10-5/8" . SP -SP 8.50 Q) Key: C 7000 r CP =Collapsed Pipe "C 9-5/8" .SP ! -CP ~TO 0 = Days ;:j 8000 LC = Lost Circulation In -LC TO = Total Depth ca Q) LC .SP = LC Trend Line :E 9000 ~ 9-5/8" - 7" \oLC ,~;;,. - 10000 .SP 11 000 -LC SP TO LC I LC .SP 7" . . 5-1/2" . 7-5/8" LC TO 7" 7" TO TO TO 12000 sr 5-1/2" - LC 7" 7" 13000 7" TO 14000 440 1220 910 630 420 540 580 640 300 100 100 590 Days to TD OFFSET WELL OATA SRU 213-10 11 6/28/2002 UNO[AL~ SWANSON RI\f 1 UNIT SRU 213-10 Well MUD WEIGHT AND FRACTURE GRADIENT PROPOSED MUD WEIGHTS AND ANTICIPATED FRACTURE GRADIENT UNOCAL8 9.625" 3.5" 0 -;¡;-~ ..~ \ \ 1000 -ì\\,. 2000 - -~ SWANSON RIVER UNIT OFFSET MUD WEIGHTS, PROPOSED SRU 213-10 MUD WEIGHT, ANTICIPATED FRACTURE GRADIENTS, AND CASING PLAN 3000 - FRACTURE GRADIENT ~ -Production liner -ø-- ProductionTubing -Structural Casing ----Surface Casing . Formation Tops -PROPOSED MUD WEIGHT SRU 213-10 --- SRU242-16 SRU 212-10 - -SRU211-15 ....... I ~g~8' fg~ g¡ ~_tf6Iing . 2935 Top of 83 . 3105 Top of 85 == ~~~~ fgß gf ~~Iuga . 3735 PRO~~~~~D TOTAL 4000 i ! 5000 6000 7000 8000 9000 10000 8 9 10 11 12 13 14 15 Mud Weight (PPG) 16 17 18 19 20 MUD WEIGHT AND FRACTURE GRADIENT SRU 213-10 12 6/28/2002 UNOCAL4., Swanson R, r Unit SRU 213-10 RIG FOOTPRINT RIG FOOTPRINT 500 BBL Tiger Tank (Slops) ...... ... .......... .......... ........... ... 8. . . . . ¡ Choke House ¡ . D . . . . . : : . . . . : : . . : : . . . . ~ ~ ~ : ~ : : (1 : : 0 : Top Drivec::~n:: T~nk =¡" æ ~_Q)n j I { ~ ¡ I Sub 8 ¡ Diamond Tanks D ~ (J) ¡ D: - . 75 HpVacUnit ~ ¡ - ¡ Cuttings Tank ~ D ~ - ~ ~ ~ ¡ 500 BBL Tiger Tank ) - ~ - ~.s ~ ~ ~ ~ (- - ~ ~ ~ ~ -¡ :2 ¡ 130 B B L r-"'I r-"'I ---f!1 ~ ~ Trali~~:~~~~ted ~ '-' ~ ---f!1 ¡ - I Boiler I ¡ - - D 0 EJ ~ I Lockers I Shop I ~ \. - - ~ '---v---' :..........................................; ( Storaae Conexes ~ t Charge and Transfer Pumps - Pre-Mix CJ MI Shack XXX BBL Vertical Storage Tanks (Replaced wI Tiger Tank on Griner #1) Rig Footprint SRU 213-10 13 Bermed Area 6/28/2002 UNOCAL~ Swanson R~ r Unit SRU 213-10 DRilliNG PROCEDURE DRilliNG PROCEDURE Unocal Alaska Business Unit SRU 213-10 . - . GRASS ROOTS GAS WELL UNOCALe Prepared by: JIM Date: 04/19/02 Estimate for Grass Roots DRILL AND COMPLETE TIME PLAN No. Preliminary Procedure Time CUM CUM Depth Depth Estimate Time Time In Out (Hours) (Hours) (Days) (Feet) (Feet) Rebuild location pad, Relevel gravel. 0.0 0 0.0 Drive and set 2 jts of 13-3/8" Conductor Casing and 2 Install Cellar 0.0 0 0.0 3 Pre install Diverter Bag 12 12 0.5 0 0 4 MI & RU 30 42 1.8 0 0 5 NU DIVERTER LINES & FUNCTION TEST 12 54 2.3 0 0 6 Fill Pits with spud mud and prepare to spud 12 66 2.8 0 0 Directionally Drill 8-1/2" hole to 1989' MD, 1800' 7 TVD 18 84 3.5 0 1989 8 Make Wiper Trip & POOH 8 92 3.8 1989 1989 RU Csg Crew & Run 7"Surface casing to 1989' MD, 9 1800' TVD 6 98 4.1 1989 1989 10 Circ & Cmt Surf Csg. Displace with OBM 8 106 4.4 1989 1989 ND diverter, NU Csg Head & BOP's. Test BOPE to 250/3000 psi. Test Casing to 2500 psi, Drill out, and 11 Run LOT 16 122 5.1 1989 4106 12 Directionally Drill 6" hole to 4106'. (assume 50'/hr) 40 162 6.8 4106 4106 13 Make Wiper Trip & POOH LD DP 12 174 7.3 4106 4106 14 RU, Run Logs, RD Schlumberger 12 186 7.8 4106 4106 15 RU & Run Production Casing Liner 10 196 8.2 4106 4106 16 Circ & Cmt Production Casing Liner 10 206 8.6 4106 4106 17 Test Production Casing Liner to 2500 psi. 2 208 8.7 4106 4106 POOH with liner setting tools. Lay Down Running 18 Tools, and BHA 16 224 9.3 4106 4106 19 Run Tieback assembly, Land Same, and Install BPV 12 236 9.8 4106 4106 - 20 Begin Rig Down and Load out 8 244 10.2 4106 4106 21 Clean Pits and Prepare to RD 12 256 10.7 4106 4106 22 ND BOP & NU TREE. Pull BPV & Set TWC 4 260 10.8 4106 4106 23 Test Tree to 3000 psi & Pull TWC. Secure Tree. 5 265 11.0 4106 4106 43 Release Rig 265 11.0 44 265 11.0 45 265 11.0 59 265 11.0 90 265 11.0 Drilling Procedure SRU 213-10 14 6/28/2002 UNO[AL~ UNOCALI 1,000.0 L 2,000.0 SWANSON RIX '~ UNIT SRU 213-10 Well DAYS VERSUS DEPTH PLAN DAYS VERSUS DEPTH PLAN SRU 213-10 Kenai Peninsula, Alaska Depth vs. Time Summary 2,000,000 -Proposed SRU 213-10 - SRU 223-28, 1997 - ACTUAL TIME VS COST AFE PLANNED TIME VS COST - 1,750,000 1 ,500,000 3,000.0 \ 1,250,000 --- ¿ .... ~ ~ :; 4,000.0 \ 1.000.000 .... Q. ~ Q 5,000.0 \ 750,000 6,000.0 7,000.0 8,000.0 0 Days Versus Depth SRU 213-10 250,000 500,000 5 10 15 20 25 Time (Days) 15 6/28/2002 UNO[AL~ Swanson ~é gr Unit SRU 213-10 Well WELLHEAD DIAGRAM PROPOSED WELLBORE SCHEMATIC FOR MONOBORE COMPLETION RKB to TBG Head = 16.5' Elevation 293.5 Feet L ~2 L1 \. TD = 4106' MD, 3735' TVD Directional Well Wellhead Diagram SRU 213-10 ~ CASING AND TUBING DETAIL SIZE WT GRADE CONN TOP 9-5/8" 47 K-55 Weld Surf 80' Driven 29 L-80 1800' TVD Botiom 7" Butt Surf 3-1/2" 9.2 L-80 3735' TVD IMP Butt Surf with 3/8" 55 methanol injection 7" Surface Casing @ 1989' MD, 1800 TVD JEWELRY DETAIL NO. Depth Item 1 Surf 3-1/2" Tbg hgr w/Cameron "H" BPV profile 1550 Macco 3-1/2" SMO-1 Chern Inj Mandrel w /1 000 psi chern inj valve 1600 Baker Liner Hanger and Tieback PROPOSED PERFORATION DATA TOP BTM ZONE/FORMATION SPF COMMENTS 2 3 -2125 -2135 A9 Sterling Sand Confmn with log 6 -2250 -2260 AID Sterling Sand Confinn with log 6 -2635 -2645 B3 Sterling Sand Confinn with log 6 16 6/28/2002 UNO[AL~ Swanson ~{ ~r Unit SRU 213-10 Well WELLHEAD DIAGRAM WELLHEAD DIAGRAM Unocal Swanson River 2~0 r ) * r ) ~€t)° r : 0 : ~ ~ 0 L 'I r ) * r ) 7-1/16" 5,000 . {~~ cf~) - ~ ~-~~_. ~ 13-5/8" 3,000 rL- m . ~y- DL-~ 11 3-1/8" 5,000 Tree Run 3-1/8" 5,000 Wing 2-1/16" 5,000 Outlets 13-3/8" Casing 7" Casing 3 -1/2 Tubing Wellhead Diagram SRU 213-10 17 6/28/2002 UNOCAL~ Swanson Rl... 1r Unit SRU 213-10VVell LEAK OFF TEST PROCEDURE LEAK OFF TEST PROCEDURE 1. Clean out the rathole below the shoe, and drill 20' of new hole. Circulate and condition mud. 2. Pull the drill string into the shoe. Rig up to observe annulus pressures. 3. Close the pipe rams and pump down the drillpipe at a slow rate (1/4 - 1/3 BPM) if exposed formation is permeable. A non-permeable formation should be step tested to a predetermined pressure. 4. Measure the volume pumped and plot annulus pressure-vs-cumulative volume pumped. Compare annulus pressure to drill pipe pressure and confirm both are the same. Record and plot pressure versus volume pumped. The pumps should be shut down immediately upon indication of leak-off. Record the initial, shut down pressure and the pressure after 1, 2, and 3 minutes. 5. Release pressure and record the volume of fluid recovered in the trip tank. The point "8" shown in the attached graph at which the plot of drillpipe pressure stops increasing equally as the volume is pumped is called the P.I.T. limit, Leak Off, or pressure integrity test limit. The leak-off pressure is calculated as follows: Leak-off (EMW) = Mud weight in hole + P.I.I. (PSI) (0.052) X (shoe depth in TVD ft.) This equivalent mud weight should be made known to all drilling personnel to ensure it is not exceeded under any circumstances. See the drilling procedure for guidelines on expected LOT's or pressure integrity test limits for each casing shoe. TYPICAL PIT PLOT (psi) C ~L- SURFACE PR E S S- VOLUME PUMPED (BBlS) SHUT -IN-TIME (MIN) NOTES: Point "A" will have some variance until the system begins to pressure up. Point "B" is the leak off and has traditionally been abbreviated LOT. Point "C" is known as the injection pressure and is usually dependent on rate. Point "D" is measured 1 0 seconds after the pump is shut down and is known as the ftacture closure pressure. UNOCAL OIL COMPANY DEFINES AND USES THE FRACTURE CLOSURE PRESSURE AS THE LEAK OFF. Please identify whether the leak off is at Fracture closure or as traditionally defined. LOT Procedure SRU 213-10 18 6/28/2002 Swan{ n River Unit SRU 2Þ13.10 Well HAZARD ANALYSIS UNOCAL ALASKA WELL WORK HAZARD ANALYSIS SCREENING UNOCAL~ Hazard Analysis for APD 20AAC 25.005 (c) 4 Abnormal Pressure During the drilling of these shallow intervals, no abnormal pressures were encountered, however, during the life of any old field, there is a slight possibility that cement jobs from older wells can allow some fluids to migrate up hole. There have not been any cases of this reported during the drilling of newer wells in this field, but the potential does exist. Prior to all trips a swab in potential test will be conducted and the hole will be kept full at all times during the drilling of the shallow intervals. A trip tank will be used to monitor for correct fillups. Maximum pore pressure anticipated is 1670 psi at 3735' TVD total depth based on 8.6 ppg EMW. Offset wells were drilled with mud weights ranging from 9.5 to 12.5 ppg. The closest offset well is the SRU 212-10. The SRU 212-10 is located on the same pad. The New well the 213-10 is to be a replacement for the watered out 212-10. The new well, 213-10 is to be drilled up dip to allow for producing attic gas. Lost Circulation Water Based Mud and subsequently KCL completion brine is planned for the drilling fluid for this well. If excessive lost returns are encountered a Calcium Carbonate and LCM materials pill will be used to control losses. No Losses were recorded in the drilling of the offset well. In the event of lost circulation, adequate supplies of lost circulation material and water will be kept on location. Crews will be briefed on the strategy for dealing with losses should they occur. Some minor seepage losses should be encountered in the now depleted Sterling and Beluga sands. Shallow Gas The presence of shallow gas is well documented throughout the Kenai Peninsula and is associated with coal bed methane accumulations. The minimum amount of gas seen on the offset wells in the surface interval indicates only minimum methane associated with the coals. The Conductor pipe will be preset with a water well rig and a diverter will be nippled up on top of the 13-3/8" to drill the 8-1/2" surface hole. Hole fill on trips will be continuous until surface casing is set. Proximity The new welf will be drilled from a surface location about 25 feet from an existing shut in well. A spider plot, directional plan, and directional tools will be used to drill both the 8-1/2" and 6" hole sections. The well will be considered a directional well from spud. The offset well kicked off at 2400 feet and was vertical until that point. The proposed well will kick off at 500 feet and will be intentionally deviated to the South some 1500 feet above the offset well kick off point. The well plan addresses any possible interference or proximity concerns. H25 H2S production has not been identified in any of the Offset well information files available to Unocal. Waste Disposal Mud will be disposed of in the SCU 243-4 Mud Disposal Well. Cuttings will be placed in the Swanson River Solid Waste Cell. HAZARD ANALYSIS SRU 213-10 19 6/28/2002 UNOCAL~ Swanson ~.. 1r Unit SRU 213-10 \Nell CASING DESIGN INFORMATION Bottomhole Pressure Information The following presents data used for calculation of anticipated surface pressures (ASP) during drilling of the Swanson River SRU 213-10 well. The pore pressure gradient was estimated from the following information: BHP Well Q§i SRU 212-10 1100 SRU 212-10 900 Depth TVD 2435 3320 EMW. PPg 8.65 5.2 Comment Not depleted at this location Partially Depleted Beluga intervals The fracture gradient for the surface casing point was conservatively estimated at .806 psi/ft or 15.5 ppg. Casing Pore Casing Setti ng Fracture Pressure Mud Pore ASP Size Depth Gradient Gradient Weight Pressure Drilling ünJ (TVD ft) (Ibs/gal) (Ibs/gal) (lb/gal) (Q§i) (Q§il 7" 1,800' 15.5 8.65 9.5 805 1,364 based on FG 3.5" 3,735' 15.5 8.65 9.5 1,670 1,297 based on PP @ TD Procedure for Calculating Anticipated Surface Pressures While Drilling ASP is determined as the lesser of 1) surface pressure at breakdown of the formation at the casing seat plus 1 ppg safety factor with casing evacuated with gas. or 2) formation pore pressure at the next casing point less methane gradient to surface as follows: 6" Production Hole Section for 3-1/2" CasinQ from Surface, 0' TVD to 3,735' TVD 1) AS P 2) ASP = «FG+1 )x.052xD) - (MWx.052xD) = (16.5x.052x1800) - (0.10x.1800) = 1,544 psi OR = PPx..052xTVD'- (O.1gas gradient xTVD) = 8.65 x.052x3735 - (0.1 Ox3735) = 1,680 - 373 = 1,307 psi NOTE: See Kick Tolerance Sheets on following page for identification of swab kick tolerances for the 7" surface casing. CASING DESIGN INFORMATION SRU 213-10 20 6/28/2002 UNO[AL~ Swanson ~ 1r Unit SRU 213-10 Well CASING DESIGN INFORMATION CASING DESIGN Suñace Casing: 7", 26 #, L-80, Buttress Worst case for burst would be in the event of a gas kick while drilling at TO (3,735'). If the Maximum Anticipated Surface pressure were encountered, the SI pressure against the 7" surface casing would be 1544 psi at the shoe. The MASP would be some 180 psi less due to the gas gradient inside the casing. This is based on a 15.5 ppg fracture gradient plus 1 ppg safety factor with the casing full of gas. The burst load would then be 1364 psi. Burst load = 1364 psi. 7", 26#, L-80 rated @ 7240 psi for burst Safety Factor = 7240/1364 = 5.30 OK Worst case for collapse is if returns are lost while drilling below the 7" Surface Shoe Collapse = (10 x.052x 1,800') = 936 psi for full evacuation 26#, L-80 rated @ 5,410 psi collapse Safety Factor = 5410/936=5.77 OK Worst case for tension is if the shoe of the pipe were packed off and the resultant end area buoyancy did not apply. This is equivalent to using air weight. A 100,000 pound overpull is also assumed in the calculation. Tension = 1989' X 26# = 51,714 Max pull = 51.7+100 = 161.7 K Rated = 604K for body yield Safety Factor = 604/151.7=3.98 OK Production Casing: 3.5", 9.2#, L-80, Buttress Tubina (NOTE: Since the tieback will be instalted prior to peñoratina, the production strina desian has been shown as the hiahest loads, ie. after ria in place. Worst case for burst would be in the event of a gas kick while completing at TO (3735). If the Maximum Anticipated Surface pressure were encountered, the SI pressure against the 3.5" production casing would be 1,680 psi less the gas gradient to surface of 373 psi for a MASP of 1307 psi. Burst load = 1,307 psi. 3.5", 9.2#, L-80 is rated @ 10160 psi for burst Safety Factor = 10160/1307 = 7.77 OK Worst case for collapse is if plugged perforations occur while flowing the well. Collapse = (10 x.052x3735') 9.2#, L-80 rated @ 10,530 psi collapse = 1,942 psi for full evacuation Safety Factor = 10530/1942=5.45 OK Tension is checked at the surface. Tension at top = (4106'-0')(9.2#) + 50,000 Overpull allowance = 87750 3-1/2" 9.2# L-80 is rated = 207K for body yield. Safety Factor = 207/87=2.32 OK CASING DESIGN INFORMATION SRU 213-10 21 6/28/2002 UNOCAL\J Swanson ~ 'er Unit SRU 213-10 Well CASING DESIGN INFORMATION Maximum Kick Tolerance Calculations Well: CSG Shoe: SRU 213-10 7" General Information 1 7" Casing Shoe (fTom RT) 1,800 Feet (TVD) 2 Fracture pressure at the 7" Shoe 1,440.00 psi 3 Proposed TO of the 6" Hole (TV D) 3,735 Feet (TV D) 4 Maximum anticipated pore pressure 1,736.78 psi 5 Mud Weight See table PPG 6 Gas Gradient 0.10 psi/FT 7 Average open hole size 6.00 Inches 8 Drillpipe 00 3.50 Inches 9 Capacity of open hole by drillpipe 0.0231 BBL/FT 10 Height of gas colum in wellbore when top of gas is at the shoe HT Feet (TVD) Assumptions for Area: Fracture Pressure Gradient =.8 PSI/FT; and Pore Pressure Gradient = 0.465 PSI/FT. Gas bubble height in wellbore (Ht) calculation with gas bubble top at 9-5/8" shoe. Pshoe + Pgas bubble + Pmud = Pmax@TD Pshoe + GG*Ht + .052*MW*(Dm-Dshoe-Ht) = Pma.x@TD Gas Volume (GV) calcualtion at 9-5/8" shoe. GV = CAP*Ht Kick Tolerance calculation: Gas volume in wellbore at TD. PIVl = P2V2. Assume constant temperature. Kick Tolerance * Pmax@ TD = GV * FP Mud Weight (PPG) Gas Bubble Height Gas Volume @ Shoe (Feet) (BBLS) Kick Tolerance (BBLS) 7.0 7.2 7.4 7.6 7.8 8.0 8.2 8.4 8.6 8.8 9.0 9.2 9.4 9.6 9.8 10.0 10.2 10.4 10.6 10.8 11.0 1,544 1,559 1,572 1,585 1,597 1,608 1,619 1,628 1,638 1,646 1,654 1,662 1,669 1,676 1,683 1,689 1,695 1,701 1,706 1,711 1,716 36 36 36 37 37 37 37 38 38 38 38 38 38 39 39 39 39 39 39 39 40 30 30 30 30 31 31 31 31 31 31 32 32 32 32 32 32 32 33 33 33 33 CASING DESIGN INFORMATION SRU 213-10 22 6/28/2002 Variables Dshoe FP DTD Pma.x@TD MW GG ODoH ODDP CAP Ht UNOCALU Swanson f[ fer Unit SRU 213-1b Well CASING DESIGN INFORMATION CASING PROGRAM SUMMARY UNOCAL8 Swanson River Unit SRU 213-10 Well Casing Program Casing Casing Size (in) 7 3.5 Set From Set to (MD) (MD) 0 1989 0 4106 Casing Weight (ppf) 26 9.2 API Values Hole Casing Conn Size Burst Collapse Tension Grade Type (in) (psi) (psi) (K Ibs) L-80 Butt 8.5 7240 5410 604 L-80 Butt 6 10160 10530 207 Casing Design Frac Formation Design Factors Casing Casing Setting Setting Gradient Pressure Size Weight Casing Depth Depth at shoe at shoe MASP (in) (ppf) Grade (TVD) (MD) (ppg) (ppg) (psi) Burst Collapse Tension 7 26 L-80 1800 1989 15.5 1544.4 1364.4 5.306362 5.779915 3.981175 3.5 9.2 L-80 3735 4106 15.5 1680.003 1307.003 7.773509 5.421687 2.358297 Casing Design Discussion Maximum loads are used to calculate the safety factors. In the case of burst, the hole is evacuated with gas. In the case of Collapse, the inside of the casing is assumed completely empty. The tension safety factors are based on air weights of each string with an added 100,000 # overpull. The tubing string tension design is based on a 50,000 # overpull. CASING DESIGN INFORMATION SRU 213-10 23 6/28/2002 ,1 UNOCAL}ø Swanson River ( .itt SRU 213-10 Well DIVERTER AND BOP SPECS UNOCAL. DIVERTER AND BOP SPECS Swanson River Unit SRU 213-10 Well Diverter and BOPE Diverter The diverter will consist of a 13-5/8". 5.000psi Annular Preventer and a 12" O.D. non bifurcated vent line. The vent line will be full opening and integrated with the annular in the fail safe design as stipulated in 20AAC 25.035. The Vent Line will be a minimum of 100' away from any source of ignition. Blow Out Preventers The blowout preventor will consist of a 11 ". 5000psi Annular. a 11 ", 5.000 psi double ram preventor with pipe rams on top and blind rams on bottom, a 11". 5000 psi mud cross w/3-1/8", 5000 psi flanged outlets, and a 11", 5000 psi single ram preventor with pipe rams. Choke Manifold The choke manifold will be a 3-1/8", 5000 psi manifold. It will include 1 ea. remote controlled hydraulically actuated choke and one hand adjustable choke. Casing Test MASP Test BOPS Low/High Casing String Size (in) (psi) (psi) Size and Rating (psi) Conductor 1 3-3/8" N/A N/A 13-5/8" 5M Annular Function Surface 7 1364 2000 11", 5M Annular 250/3000 11 ", 5M Pipe Ram 250/3000 11 ", 5M Blind Ram 250/3000 Production 3.5 1307 2500 11". 5M Annular 250/3000 11", 5M Pipe Ram 250/3000 11 ", 5M Pipe Ram 250/3000 11", 5M Blind Ram 250/3000 DIVERTER AND BOP SPECS SRU 213-10 24 6/28/2002 UNOCALtø Swanson River { ~itt SRU 213-10 Well DIVERTER AND BOP SPECS CHOKE MANIFOLD DIVERTER AND BOP SPECS SRU 213-10 25 6/28/2002 UNOCAL'- Swan( n River Unit SRU 213-10 Well DIVERTER STACK UP Flow Line F ill Line I r' I \ 13-5/8", 5K, Shaffer G 11 -I - 1 ~ I 12", Hydraulic Ooerated I 1 1 13-5/8" , 5Mx 1 ~-fint fiM - - 12", . Diverter H = 2.5'@ CL I 60" T - 36" + f - - - . . 1 I 13-5/8" , 5Mx 13-5/8" , 3M 70.75'! 53.75" Need new 13-5/8" 3M ~i-"':I""'~nrr Uø~"'¡ 17" 8.5 II ~ + ~ ---- Welded 13-5/8" "....----..... UNOCAL81 Diverter Hookup Well SRU 213-10 Swanson River Unit Kenai Penninsula Drawn by: J.I.M. DIVERTER AND BOP SPECS SRU 213-10 26 6/28/2002 UNOCAL~ Swal1( n River Unit SRU 213-10 Well BOP SCHEMATIC Flow Line F ill Line I [' I ..... 13-5/8", 5K, Shaffer Annular ~ 1 ~ I 12", Hydraulic Operated Knife Valve I -I - I. I I I 12", Diverter Line 13-5/8", 5M x 13-5/8, 5M Diverter Spool - H = 2.5'@ CL 60" 36" * ... ... - Need new spool 13-5/8", 5M x 13-5/8", 3M Crossover Spool 70.75" 53.75" - - 17" 13-5/8" 3M Starting Head 8.5' + Welded ~ ---- UNOCAL81 Diverter Hookup Well SRU 213-10 Swanson River Unit Kenai Penninsula Drawn by: J.I.M. Date: 05-15-02 13-5/8" r ........... DIVERTER AND BOP SPECS SRU 213-10 27 6/28/2002 UNO[AL~ Swa"f \n River Unit SRU 213-10 Well MUD PROGRAM M-I. LL.C. 721 West First Avenue Anchorage, Alaska 99501 (907) 274-5564 (907) 279-6729 Fax ~ MUD PROGRAM Economics Summary r:\'()C.\L SRI' 213-1" Well SRU2t3;.10 . Target Cumula- Da)'"s tive Days Cumuladve Cost (S) Prodû,ct Costs ($) Engineering Costs ($) Drilling 8(1' -1989' .1 $20000 52500 $.22500 DriHing 1989' to 4 ~O6- 9 l3 $1 5000 55625 543125 Completion ... -~ $500 SI875 ~6 $,,4550(ì T" --- <......, -- '.........,.....,...... ' '1''''1111.'.'11'''' . IIlmJ!' 1 'I ., [".' . Engineering an: for ]\,.1-( Engineer only . a::::sumc\llieigln up to 9.5 ppg En the 6 ., 1ntervaJ. . No cost alh)\.vance is made for lost drcularion or stuck pipe- Mud Program SRU 213-10 28 6/28/2002 UNOCAL'-' Swal1( n River Unit SRU 213-10 Well MUD PROGRAM ( '()(~;\L SRI' 213-10 Interval Summary 80' - 1989' - MD 1800' TVD 7"Casing 8 1/2 "Hole Drilling Fluid System -~¡) n KCI Fk, Pro 1\"}' Key Products f\..1-1 Bar Fin Vis S~)da Ash Prll~. pacLL l)Dl\ut PlugiSAPP Bicarb C'allstic Snda/ KCL Kia-guard Solids Control Flü\\ Lìne Cleaners Desander De-siller Centrifuge Potential Problems I (ole Cleaning;' -right I loll' Bit BaBing lInle Enlargement Gas Kicks;' Coal Sloughing Interval Drilling Fluid Properties Depth Mud Plasöc: Yield Gel APi Total Interval Weight Viscosity Point Strength Ftuld: Loss Drilled. Solids (ft) fppg) (cp.) (lb.l100ft1) Clb.J100ft2) (mIl30min) (%) 80 8.8..9.2 &.10 20- 30 NJC < 20 3 or less 1000 9.0..9.5 7-12 15- 25 12 12 .... 15 .5 or less 1989 9.0..9.5 10..15 15 """"'" 25 12 < 10 5 or ¡ess . Build spud system \vilh KCl and FIn Vis.. Add Kla-Gard for solids encapsulation, . Utilize an SCtlLds control e{]tÜpment. . Raise viscclsi.ty jf gravel ßecÚons ;:we encountered, . PUlnp s\íveeps if required. . l\dd DD (drHHng detergent) oNutPlugo and SAPP for possible htti balling. . Potential PfobIems~ Running gravel. bit balling~ 5hallo\\ and s\velHng day! . L.o\ver fluid loss to bekr\\' HI cc's API by end of jntcnal \vith Pofy'pac additions. . Estimated vohuneusage barrel s. Note: 0Aud \'v'e~ghts of I ppg may be requÜedhecause pc'tentiat shallo\\ gas. Mud Program SRU 213-10 29 6/28/2002 UNOCAL4., Swan( n River Unit SRU 213-10 Well MUD PROGRAM l :$)(~¡\L Sl~" 2IJ-IU Interval Summary 1989' - 4106' MD 3 1/2" Tubing 6" Hole Drilling Fluid System ()o j KCI Fk, Pro t\"r Key Products f'vt-[ Bar " Fkl Vis S~Kla ¡\~h Pol~ p~K L1. Sohe.\ D~:-c$ cr Bicarb (.~Hblíc Soda' KCL: KIa-¡;uard t>rill XrDualllo l.ìthium Ilypochll}cÙe Solids Control Flow Lïl)(~ Cleaners Desander Desiller Centrifuge Potential Problems I [ole CI~aning 'fight llole Bit BaHing ] ¡ole Enlargement Gas Kicks / Coal Sloughing Interval DrilUngFluid Properties Depth (*) Interval Mud Weight P~astic Viscosity Y¡,eld Point Gel API Strength Fluid Loss Total DrUI.d- Sonds (1%) 5 or less 5 or less (ft) 2000 4000 (cp.) 8- 14 8- 14 (lb.l100'ft~) (lb./100ft:í) (mI130min) 10 - 20 .::. 10 6 .... 10 1 0 - 20 8 - 10 <: 5 (p PQ) 9.0-9.5 9.0-9.5 . Treat surfaüe mud to drill float coUar. cefnent~ and shoe- Treat this tluid for cement cont~unina- lion. Condition mud to ({I'(I KCI. l~o\\er nu~d ~üss as requLred. . Run all solids contr.aL l\dd KIa-guard for ackHtiünaf inh~bition. .t\-'Iaintain adequate YP and 3 RP~A reading for hole dean1ng L.o\\/er fluid loss \virh Pülypac UL and Dual 1710. .Add 2 ;t PPB .of Sohex if running coal becomes a problem. . Potential problems: (jas kicks, Bit haning, sloughing coal. . Run and cement 3 Tubing- . If needed use [tthium hypochlorite at 4 pph for a breaker for the Pro svslem. . [stimated addÙ10nal vo)unle usage 200 barrels. Mud Program SRU 213-10 30 6/28/2002 UNO[AL!~ Swa( In River Unit SRU 213-10 Well MUD PROGRAM r'()(~.\L SRI' 213-10 Interval Summary 1989' - 4106' MD 3 1/2" Tubing 6" Hole Lost Circulation R~(l)mml:IHk'd 1.C\.t Pill Fl)nnltla~ Problems Key Products [)ril1ing F] uid ()\:t Stat SafeCarb Flnt. \:tedi um" Cl)ar:-.l: Vtr~a- IIRP lost 'Circulation Pill (Slight losses) Volume of Mud fbarre Is) 30 SafeCa rb Medium (ppb) 10 (ppb) 1/4 M i.x II SafeCarb Fine (ppb) 10 Flo-Vis (ppb) 10 lost Circulation Pin ('Moderate losses) Volume of Mud (barrels) 40 Flo-Vis Mix II S.afeCarb Medium ( ppb) 15 SafeCarb Coarse ,(ppb) 10 ( ppb) 1/2 (ppb) 15 liostCirculationPil1 {Seve'rieLosses) Volume of Mud (barrels) 50 Mix II SafeCarb Medium (ppb) 20 SafeCa rb Coarse (ppb) 30 F]o-Vis (ppb) 15 (ppb) I . LCrv,t shmdd he added to nlud system. 1"-10 \hs should only be added if requfJed. . If possible" spot pin across theft zrHle. Apply moderate pressure into rhief lone. 100 psi) to sque{~ze pHI Mud Program SRU 213-10 31 6/28/2002 UNOCAL\J Well Summary Swa( ')n River Unit SRU 213-10 Well MUD PROGRAM ( $)C.\I., SRI' 213-10 C_ing Ho" Casing Depth TVD Mud Mud Sum Cumulative SiZe Size Program Systøm Weight Daya Mud Cost ";''!- 8 1 /2" (989' 1800' 3°0 KCL 8.8-9.5 S~2500 3 1 /~" 6 ., KeJ' lssue^'o. 1 CUlting.s Di~J'o.filll KeJ' Issue No.2 Drill tt;O!i{I.fiBuild-lI/J Kel,lss ue -~ . Hole StabilitJ' Sloughing Coal KeJ' Issue 4 Lo,sl Circulation Mud Program SRU 213-10 410Ú' J7J5' KC~l" 9.0-9.5 13 S4JI~5 6 16 S45500 . Cnuings Dispüsal\viH he an issue. tv1ud and cuuings should meet aU Svvanson River disposal requirements and limìta- tj on s. . Run as Hue a mesh screens on shakers" mud cleaner, and cen- tJit~uge if avaÜable to reduce the build up drm s()lidsin the mud. . iv1aintain mudv\'eiglns as per progranL Increase rhi;.."$logy as required by hole conditions. . tv1aimain adequate supphes of LCtv1 on localÏrJn.. LIse a com- bination of tine and medium Nut Plug, ~vn Seal, and !vHX II. Do not exceed 40 ppb or utilize coarse material \.\hhfJutCOB- tirmat10n from !vnVDand t\rlud f\ilotor representatives. 32 6/28/2002 UNO[AL~ Project Team Gus V./ik \V~:U"eh()use Ivlgr. t Swan(' n River Unit SRU 213-10 Well MUD PROGRAM r~()('_:\L SRI 213-10 Forest Slater Field Engineer ~ ... Jim Bro\vn Field Engineer f Lee De\vees Project Engineer f Deen Bryan Tech Servi ce . rvll Project Engineer and Engineeringtvlanager will coordinate l"lctween the 1 Inocal 0[- nce~tig, \varehouse, and the rvt.-J field engineers. . \VeH progress \vin be monitored to look for anyehanges \\'hkh win improve the efl]- caenev the üpelat~ün or avert uouble.. Project '¡'eaIn f'r.!lig Bieber 'fitle llístríct 1\1 anage r I}een Br)ran Tech Ser\'ice I."ee I}ewees Project Engineer \Varehouse i\'lanager Gus '\iik Mud Program SRU 213-10 33 \V ork Cellular 907274-5051 907229",1196 907 - 2 7 4-5003 907", 223-1634 907 -274-5533 907 -230-6653 907 776-8()80 ~}O7 252-42) 8 6/28/2002 UNOCAL~ DIRECTIONAL PROGRAM Swan( n River Unit SRU 213-10 Well DIRECTIONAL PROGRAM NOTE: The 213-10 well adjacent to the proposed well is watered out and currently is shut in as incapable of production. The 213-10 was drilled as a straight hole to 2400' and then directionally drilled. The proposed well will kick off at 500 feet, well above the kick off point on the offset well. The offset well drilled to the East and the proposed well will drill to the South. Given the proposed well path and the Inclination surveys on the offset well, the closest that the two well should come to each other is 25 feet. This is not perceived as a problem to require special nudging. The proposed well will be kicked off by orienting to the South and directional drilling with a motor. ~ UIIOmL8 SRU 213-10 Proposed Well Profile - Geodetic Report Rrplll'l D.1II: Jll'~ '.0 :{)).2 Santy I [u Ccmputltlcfl Mcítlod: 1t1'lIfurtl C~UI~" Ltr~~J CItn1: '~~.:CJ 't'cdlCòl Section AziIlUUt 1í!.7 01(1" fMtSel$nR,,'ei UfJl udY Verfc;¡JSKliQft~\'JB: N(lOC(¡n>E.Jc:J)~ Slrudan I Slot ':;el~. ''1 Rr.'ei .i SRJ ~t~ 13 .~ .00 Aœ1eltftœ. taun: KB Well: 213 1& --lalll'" ~ TW RøllranOll ENIlTØOA: 3; & (I ~ ~S~ I:¡ MSL Eknhch: 2131C F ..., SUBcdfGtcündLMIElmöœ: 17Q(OOn,~~ív!:h:I¡Sl !I'MJAIItt: ~Otcl.alflll: æUr.6" Surovy N.mtJ DiM: 21310: iF"5 ,'..hilI! Hl xœ fd.1f Field Stllltgtll: 5S4ro.r>i9 rT fonJ AHO t.IJ[¡ tEIIÞlIIIo: ì364i'" i129tOO n ,ISOtßHl34: "Itldl~ l.1ß2C" G(j(fCcctditIb! StDn: NhW "'.aw~~.è .:1hr~. Zè:!e'(, LlS Fee! Do"tllÖÐn 0IIt: 1:~r,e.2:, 2G::rt LoaItIcn~: ~J 00. OOt 3?J:6. 'w 1SU í!t.7!ì56.7i ltagrdt: DeclIUlIcfl NOdIt BG:lA 2}:)2 Lm1IIcfl GI1CIIUE'f1X: :!oJ 24.ß5;!rt 9413 I':IJB. E :1E545ÆrLJ nu.s KlJl1h IimIJtnœ: TII~ ttrtt GI1CI~1IQI AIIJ}It: .o.UOWr.ß~ TdàCDIfMag NcfIh -40 True Ml1i'il\: +2Ct8l)1" Gñd &me f'.1àDr. Orø.ìfrÆ10 I..oct4IJ:omIIIIr.Dn RtteNlIC!td To:. ¡'1i'êU~1!!!Ð l Sti'lll1ItI D KOP BId 41100 End 8td Drp 41100 Tatget SfØlilftD Erd Drp TD ID J \J ,t,ù. I \.J \.J ,J ,:J ,. ~.01 501100 0.00 187.01 50.).00 0.00 0.00 0,00 fOO.OO -tOO 187 :01 5£9.92 3.ê ~3A6 .0.43 700.00 8.00 187.01 693.35 13..94 .13.84 ~1.7'Q BOO.OO 12.00 187:01 197.81 31.:» .31.07 .3.82 SDO.OO 16.00 187.01 194.82 55.ê --55..07 ..s.77 1£00.00 20.00 187 .01 9f:S.91 86.38 ..ss.74 .1Q.54 1100.00 2-t00 187.01 1082.61, 123..84 .122.91 .15.11 1200.00 28..00 187 .01 1172.47 167.67 -16641 .2O.4tI 1m.00 32.00 187 :01 1259.05 217.66 .216.03 .26.55 1400.00 36.00 187.01 1341.94 273.56 ~211.52 .~.37 1431.46 37.26 187.01 1367.19 292.33 .290.15 .36:66 2583.37 37.26 187 ,01 2284.01 989.71 .Q82,32 .120.75 2fOO.OO 36.59 187.01 2297.:» 999.70 -992.24 .121.96 2700.00 32.59 187 :01 2379.00 1056..47 .100J~57 .128.89 2764.83 30..00 187.01 2435.00 1090.14 .10B200 .1 ;[!ß:OO 20.00 28..59 187 .01 2485.67 1107..35 .1099.œ .136.10 2000.00 24.59 187.01 2555.07 1152.1 1 .1143.50 .14.0.56 ~ DLS rtlOOaM 0.00 4.00 4.00 4.00 GI1CI t'oÐrdIrdU GeQ'''øllk CconJilltlls ~ J E'øs1mg L.IIttudt. lcngltillc 24. A.s:r N 6O.801373f1!'w 150.8479œ/f 2465819..43 348545.62 tf 60.ao137356 W 150.84796677 24@5815fi18 348545.36 N 60.ao1364OO W 1so.84796918 24@5a05.62 348543:94 N 6Oß0133570 W 150.84796829 2485788.42 348541.00 tf 60.80128857 W 150.84797815 4.00 2485764.46 348538.34 N 60.80122292 W 150.84?9G467 4.00 2485733.:84 348534.17 N 6O.8011,39Q2 W 150.84801577 4.00 245696.74 348529.12 N60.80103736 W15Cl84804136 4.002465653,31 348523.21 N 60.80091636 W 150.84807131 4.00 24@.Eœ3.7B 348516.48 N 60.80078263 W 150.84810540 4.00 2485548.:.¥J 3485C6.£6 N 60.80063)84 W 150.84814"357 4.00 2485529.79 348500.42 N 6O.800s7913i!1 W 150.84815639 0.00 2464B38.83 348412.40 N 60.79a6ð352 W 150.84863268 4.00 2484828.93 348411.05 N60.79E16f939 W150.S48Eœ46 4.00 2484772.70 348403.41 N 60.79a50530 W 150.84867824 4.00 248473fL32 3483£6.f!6 N 60.79841386 W 150..8487012.'5 4.00 2484722.27 348396.54 N 60.79836714 W 15o.a4871300 4.00 2484677..93 348300.51 N 60]982'4563 W 150.84874'3&3 G!HlC'oødIRlllln GICIJ¡JItk COiIrditd I ID J ad J ADII I M) J ~ I PI-S J ~ J .. IU . 1fŒrtNIit I &stll't laItMt I !.ong11J\t A. ~5 r~.01 lb.. 11b.S/ .1~1t. .~. moo:M 21:&J A.d' N60.796141J'w150.84876381 4.00 2484Œ6.29 348381:(0 tHìO.79005481 W 150.848791 æ 3100.00 16.59 187.01 274<2.14 1222'.40 .121326 .149.14 3mOO 12.59 187 ;01 2ð3&.89 1247..59 .1m27 .15.2.21 3300.00 8.59 187 .01 2937.17 1265.91 .1256,51 .154.413 3400.00 4.59 187.01 »36.49 1277.45 .1267,90 .155.136 34ð!64 1.25 187.01 3120.00 12ðt71 .1272.13 .1~,3ð 3493.08 0.87 187.01 :3129.45 1281.88 -1272.31 .1~.4O 4008.71 0.81 187.01 3735.00 1291.08 .12&1.4-3 .157.5.2 Directional Program SRU 213-10 34 4.00 2484.S8.3:33 4.00 2484566.12 4.00 2484.553.75 4.00 2484549.53 4.00 2484.549.35 ti 60.7979&540 W 150.84880077 ti 60.797933&1 W 150.84882136 N 60. 791905:)5 W 150.84882920 N 60.79780018 W 15C1.84883211 N 60.7978002'8 W 150,8488.1222 34fJJ77 .64 34æ75.15 348313,61 3483131~3 34æ13;01 0.00 2484.54024 348371.77 ti 60.797.86834 W 150.8488.:384.9 6/28/2002 UNO[AL~ Swal1( n River Unit SRU 213-10 Well DIRECTIONAL PROGRAM VERTICAL Sm:TIOJl VIIiW ~ ~ Cli!imt : ),i.; 11 : F'1.;¡1í1: Uncc;¡1 ::n-1O ¡rs:, Sv~nson Rlvgr Unit -. Structurg: S~~nson Rlvgr E'..,: lien J. t: 1ST. fJ 1 d¡;;¡ D;¡tg: Jun~ 10, 2D02 0 &10 '4::.. '''''t:;> ~OOO i::t J! en ~S)o 8' :! , . (þ i~ ~ ;¡;;œ .. it:: ~o 0 i...... ô 2.000 'w. ..... ,(3 ~ -~ 5 .. e"'" . í1) Q.1o::; » ~ ~ 2500 :F: WI Hdk1 ~Ie ;31.215" ~ -- /"' J . Hokf Ar.gr~ 0.87" 35:10 :tI ~500 (J 5fl0 'ÆOOO a &10 Vef'tlcalSedkJn Departure .81181.1)1 d&g from (0.0, €LO}.(1 in = 500 fëet) Directional Program SRU 213-10 35 6/28/2002 UNO[AL~ Swa"( n River Unit SRU 213-10 Well DIRECTIONAL PROGRAM PL1Jf VIlli Cll...nt: Unoc;¡l ~ ~1l: Fl.;ld: E::trll:-tur~ : :! 11 - 1 0 I t"':; :- Ev¡;¡ns:n FUv..r Unit E.vãins':n Rl v.;;¡r ~ E::r.:;¡lQ: D;¡t.;;¡ : 1 in . :::-:.0 rt 1D - Jun- ¡.:,O:! .40:) I .200 0 200 400 ( '1.rUQ R::Jrtb H;¡g Dwe I E ¡Q.81c, I 0 - '_.4 UICI ~ .2.00 .200 ........ ~. .400 ^ % 3 % .) ~ ""'- .~ £ =::ï l: ~ i z ..tKJO .600 ,&;)0 % .600 B ø V \¡ '!I .ttQO ---------Po..1I1ID .."r7%~:2 j\fl> J ~. . . we: ~~ .1000 .1000 .1200 .1200 ""'II 'c. '~TÐ : I .400 .200 «<WEST 0 200 EAST »> 400 Directional Program SRU 213-10 36 6/28/2002 UNO[AL~ SWi.L~SON RIVER UNIT SRU 213-10 PTD COVER LETTER Alaska Oil and Gas Conservation Commission 333 West ih Avenue Anchorage, Alaska 99501 Attn: Commissioner Cammy Taylor Re: Application for Permit to Drill (Form 10-401) Swanson River Unit 213-10 SRU 213-10 Dear Commissioner Taylor, Enclosed is a second revised application for permit to drill for the Swanson River 213-10 Well. The original PTD was for a deeper well. The first revision was for the requested Tubingless Completion configuration. This revision reverts back to the liner hanger and tieback string which we understand can be permitted immediately. This will help us to keep the rig working. The understanding we have is that the Conservation Order hearing will continue to be on the tentative schedule and that given no objections we can revert to the Tubingless configuration with a Sundry notice after the time frame for the Conservation Order hearing has expired. The ability to start the job and still keep the door open for the significant cost savings we will see as a result of the Tubingless configuration is very much appreciated. In addition Unocal would like to utilize the Nabors Rig 129, formerly Kuukpik/H&R rig 9, with its existing 12 inch diverter line to drill the well. The 12" diverter lines are more than adequate to handle any diverter operations that may be come necessary during the drilling of the 8-1/2" surface hole interval. The expected date for the drilling rig to arrive on location is approximately July 2nd or 3rd 2002, so your timely consideration for approval is appreciated. If there are any questions, please contact Jim Harrison at 263-7809 or Jim Mosley at 263-7679. Again, your assistance is appreciated. Sincerely, ~ &H~ Drilling Manager Unocal Alaska JH/jm Enclosure R,ECEIVED JUj'\J 2 8 2002 PTD Cover Letter SRU 213-10 Alaska Oil & Gas Gons. Commission 6/28/2002 Anchorage UNO[AL~ SW( 'ISON RIVER UNIT SRU 213-10 Well TABLE OF CONTENTS TABLE OF CONTENTS TABLE OF CONTENTS ............. ........... .... .......... .................. .................... ......... ...... ........................................ 2 PERMIT TO DRILL............................................................................................................................... ...........3 LOCATION PLAT. ............ ......... .............. ...... ......................... .............. ........ ........... ....... .... .............................. 4 LOCATION MAPS AND PLATS ..................................................................................................................... 6 C EMEN T PROGRAM.......................................................................................................................... ............. 7 LOGG IN G PROGRAM........................................................................................................................... .......... 8 ANTICIPATED FORMATION TOPS...........................................................................................................10 OFFSET WELL DATA ...................................................................................................................................11 PROPOSED MUD WEIGHTS AND ANTICIPATED FRACTURE GRADIENTS..................................12 RIG FOOTPRINT ..... ........ ............... ..................... ........ ......... ....... .............. ...... ................. ........ ..... ...... .......... .13 DRILLING PROCEDURE .......... ....... ............ .............. ............. ...... ........ ........ ........ ..... ............... ................... .14 DAYS VERSUS DEPTH PLAN ......... .... ....... ................... ........ ....... ....... ....... ..... .... ..... ............ .... ..... ............. ..15 PROPOSED WELLBORE SCHEMATIC FOR MONOBORE COMPLETION ......................................16 WELLHEAD DIAGRAM ....... ...... ............ ....... .............. .................. ........... ...... ................ ........ .... ...................17 LEAK OFF TES T PROCEDURE ..... .......... .......... ....... ............ ....... ........ ........ ........ ........ ........ ........................18 UNOCAL ALASKA WELL WORK HAZARD ANALYSIS SCREENING ..............................................19 BOTTO MH 0 LE PRESS URE INFORMATION.. ........ ........ .......... ....................... ......... ........ ............... ....... 20 C AS IN G DES I GN .... ........ ....... ..... ......... .................... .................................. ..... ................ ..... ....... ...... .......... .... 21 CASIN G PROGRAM SUMMARY.......... .... ........ ...... ................ .......... ................. ............ ..... .... ..... ............... 23 DIVER TER AND BOP SPEC S ....... ....... ................. ........ ........ ............. ..................... ........ ............. ............. .... 24 CHOKE MANIFOLD ...................................... ............... ................. .... .... ........... .............. ...............................25 DIVER TER S TACK UP . ...... ......... .... ................... ....... ................... ......... ...... ........ ..................... ...... ...............26 BOP SCHEMATIC ............................... .......................... ............... .... ......... ...... ......... ... .... ........ ...... ..... .... ........27 MUD PROGRAM.............................................................................................................................. ...............28 DIRECTIONAL PROGRAM.. ..... ....... ...... .... ... ... ... ... ....... .... ................ ..................... .... ... ...... ........... ............ ..34 i: ~L~ EI\JED JU'¡\ 1 r. r, q(\'~2 .. I \¡ L ö LUV w TABLE OF CONTENTS sru213-102 6/28/2002 AJaska Oil &: Gas t;omm¡SSIO!: Anchorage " ( UNOCAL8 c!amhZl( ( SWANSON RIVER UNIT SRU 213-10 6/25/2002 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 RECEIVED Re:Application for Permit to Drill (Form 10-401) Swanson River Unit 213-10 SRU 213-10 JUN 2 6 200Z Alaska Oil & Gas Cœs.CœIJissIon A11dIu~ Attn: Commissioner Cammy Taylor Dear Commissioner Taylor, Unocal has asked for approval to install a Tubingless style completion on the SRU 213-10 well. This configuration has been based on minimizing the cost of the installation. The economic justification for this well is to produce marginal attic gas reserves to the watered out 212-10 well located on the same pad. Because there is no liner or tieback string, this configuration is called a Tubingless completion. A small-diameter well that uses small-diameter casing when completed without tubing is defined as a Tubingless completion. To effect this completion a small diameter casing is cemented and then perforated opposite the producing zones. Tubingless completions are used mostly in small gas reservoirs that produce few, if any, liquids and are for the most part low in reservoir pressure, however, there are many documented cases of high pressure Tubingless gas completions. The specific reasons and arguments for selecting this configuration for the SRU 213-10 well are listed below. We respectfully request that approval be granted for this approach to the SRU 213-10 well design. 1. Most importantly the well has marginal reserves because the targeted zones are already," partially depleted and will not flow against a hydrostatic equal to a column of fresh water. ..",. 2. The location of the well is remote and there is no risk associated with urban development. 3. The well is shallow and will bea low pressure well at best. The main zones of interest are depleted to about 6 ppg equivalent. A partial column of water will kill any of the targeted zones. Producibility and economic viability are both dependent on isolating the zones of interest from any water bearing zones. 4. The cement design and placement plan to put cement across the low pressure intervals has risks associated with reduced fracture gradients across the partially depleted gas sands. For this reason a long lead slurry of low weight is planned to be used to fill the annulus to the surface on the 3-1/2" by 7" casing. The intent is that the lead cement column will serve as an effective packer. We understand that the current regulations require that for any producing we" that is capable of flowing; tubing and packer are required. We ask for a variance to this regulation because the well is incapable of flowing unless it is isolated from water and even when the well is isolated, the flowing pressures will be relatively low. The maximum anticipated surface pressure for the depleted sands will be considerably less than 1000 psi. A proposed course of action is to test the 7" by 3.5" ./ annulus prior to perforating thus demonstrating that containment is not an issue. A 1000 psi test on ~NOCAL. ( SWANSON RIVER UNIT SRU 213-10 6/25/2002 the annulus should be easy enough to obtain and should demonstrate that the cement will function as a packer. .--.----þ 5. We looked at the use of an External Casing Packer/as one method of enhancing the cement column in the event that cement does not circulate. This method could be accomplished by installing in the completion string an external casing packer (ECP). This external casing packer could be inflated with completion brine and would provide an additional barrier to supplement the cement. The ECP has a slightly larger OD than the casing string planned for the well and as a result could jeopardize the primary cement job. The external casing packer could be placed just above the shoe of the 7" casing and inflated after the cement plug bumps on the 3-1/2" cement job. A sliding sleeve could be placed in the tubing string at a depth inside of the surface casing string so that, in the event the cement fails to circulate above the sliding sleeve, a method of placing more cement into the annulus could be effected. This would have the effect of providing a means for a two stage cement job. This option is not one we believe is needed, but would make a good contingency option if the cement job went awry. The placement of the sliding sleeve would need to be above the external Casing Packer (ECP). We recommend against the ECP and sliding sleeve because of the costs, time, and risks to the primary cement job. 6. The plan is to cement the 3-1/2" to the surface with a two slurry cement job consisting of a low weight lead and a conventional tail slurry to isolate the gas bearing productive zones. 7. The 7" surface casing is being set just below the maximum depth of fresh water to protect the fresh water aquifers. The depth of the 7" is also just above the targeted gas bearing shallow zones. The 7" Surface Casing has more than adequate burst strength needed to contain the gas zones that will be drilled just below the 7" casing shoe. In the event that the 3.5" Production string were to develop a leak, the 7" casing will prevent any migration of gas to the shallower intervals. As shown in the Permit to drill, the anticipated leak off test on the 7" casing is 15.5 ppg equivalent. The zones of interest are depleted to about 6 ppg equivalent. The MASP on the targeted zones due to the depletion is expected to be around 600 to 800 psi. The anticipated 7" shoe strength is 1450 psi and is more than adequate to contain any of the zones of interest. . 8. A conventional Liner, LinerTop Packer, and Tieback is considered a Monobore Completion. This Alternative configuration (the Monobore) has been looked at from both a cost basis and from an integrity basis. The conclusion that was reached is that the friction losses expected across the liner hanger are believed to present a significant risk to getting a cement job on the zones of interest and have little chance of circulating above the liner top. Hence the (monobore) or liner configuration is seen as a bigger risk to isolating the zones of interest than is the Tubingless long string witli a conventional cement job. The economics of placing a liner in the hole and then running a tieback create similar costs to the DV tool option and would again jeopardize the economics of this project. A clean out of a liner top would also cause the same problems associated with a different string of pipe that the conventional DV tool creates. 9. Use of a conventional DV tool requires some length of interval where a marginal cement job can be tolerated. Unfortunately the proximity of the zones of interest to the surface casing shoe do not leave sufficient room to place and utilize a DV tool effectively. In addition, a conventional DV tool requires a cleanout, which in this case requires an added trip and a different string of pipe than was used to drill the well. These constraints are very detrimental to the project economics. 10. Slim hole drilling techniques have been proven to enhance the amount of reserves that can be economically developed. Development of smaller accumulations of hydrocarbons can be more easily justified when the Tubingless completion technique is used. The single risk associated with the Tubingless completion configuration is that there are not a lot of options to perform cleanouts and remedial work. When there are multiple pays that could justify work over operations, then the economics of casing a bigger hole are easy to justify, however, this is not the case for this well. Ii ( UNOCAL. ( SWANSON RIVER UNIT SRU 213-10 6/25/2002 11. The Tubingless completion risk is that the well bore could be expendable if un-fishable stuck tools were to occur. Because we believe that the completion is simple, the risk of junking the hole with wire line operations is JIlinimal. Future utility of this well bore SRU 213-10 is very limited, and we are willing to risk plugging and abandoning if mechanical problems were to occur. 12. The reserves are known to be dry gas with no heavy or liquid hydrocarbons. /' 13. Tubingless technology has been successfully used in many other locations to promote development of marginal reserves. It is a win/win opportunity to produce low cost reserves that we would like to demonstrate is a viable method to breath some new life into marginal plays. SUMMARY Unocal requests that a variance from the regulation be granted and that the proposed Tubingless completion configuration be approved. . Unocal is willing to demonstrate that the lead cement has effectively created isolation, ie a cement packer by testing the annulus to 1000 psi. This is several hundred psi above the expected MASP from the depleted zones. Unocal would prefer not to install an External casing packer and sliding sleeve for use as contingency sealing tools because of costs and risks to the primary cement job The risks associated with: (1) the liner hanger, (2) getting a cement job across the zones of interest, (3) potential for a required clean out of the liner and liner top packer hardware, and (4) costs associated with a liner or use of a DV tool are in our opinion sufficient reason to prefer the proposed Tubingless Completion. "..... The expected date for the drilling rig. to arrive on location is approximately July 03, 2002, so your timely consideration for approval is appreciated. If there are any questions, please contact Jim Harrison at 263-7809 or Jim Mosley at 263-7679. We would be happy to come over and present these reasons and discuss any other options at your convenience. Sincerely, .~ o;Harnson JH/jm Enclosure Drilling Manager ~~lþ~S~ ..~.;!Y"ø:t".. ç, f?" U I t,,,,*,.t!J I" ,J~.L -þ, <, {..w t f r-tf" ~ . ¡Q..:q rxJ./"; ("ble 7/ Z -:, /0 l . I. ..,¡ 5 J [ I) G (A.,1t ~Ctþt PiJ P ~ - t~ u.,,/ f ~....~ . 1 a. Type of work Drill X Redrill Re-entry Deepen 2. Name of Operator Union Oil of California (dba Unocal) 3. Address P. O. Box 196247 Anchorage. Ak 99519-6247 4. Location of well at surface 1725' FNL and 628' FWL Sec. 10 T8N, R9W, SM AK At top of productive interval Sterling 2818' FNL & 490' FWL @ 2434' TVD Sterling At total depth 3018' FNL & 465' FWL @ TD of 3735' TVD 12. Distance to nearest 13. Distance to nearest well property line 747' STATE OF ALASKA ALASKA Oil AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 MC 25.005 1 b. Type of well Exploratory Stratigraphic Test Development Oil Service Development Gas X Single Zone Multiple Zone 5. Datum Elevation (DF or KB) 10. Field and 001 310' RKB Swanson Iver Field 6. Property Designation Swanso River Unit A-028405 ( 7. Unit or Property Name Swanson River Unit 8. Well Number 213-1 0 9. Approximate spud date 6/31/02 14. Number of acres in p perty 11. ype Bond (see 20AAC25.025) Statewide Oil & Gas Bond umber U 62-9269 Amount 25' at SHl (SRU #212-10) $200,000 15 Proposed depth (MD and TVD) 4106' MD 3735' TVD 16. To be completed for deviated wells Kickoff depth 500 feet Maximum hole angle 38° 18. Casing program size Specifications Hole Casin Weight Grade Coupling g 12.25 9-5/8" 8.5" Length 17. Anticipated essure (see 20 AAC 25.035 (e)(2) Maximum Surfa e 1307 psig. At total depth (TVD) 3735' Settin epth Top Bottom TV MD TVD Quantity of cement MD 7" 47 26 L-80 L-80 Weld Buttress 80' 1989' 0 0 80 1989' 80 1800' Pre Set W / Water Well Rig 208 Sacks = 345 cuft Class G blend 483 Sacks = 658 cuft Class G blend 6" 3.5" 9.2 L-80 IMP Butt 4106' 0' 4106' 3735' 19. To be completed for Redrill, Re-entry and Deepen pe tions ~ , ~~ .~ RECEIVED JUN 11 2002 !\ft"' œ&Gas~£tß. ~"Ø~\iJ;i ~ 21. I h~rebY I' hat the re ,~g iS~: ~nd correct to the best of my knowledge Signe ' 'V\ T:"" \l.rr~ Sc:..'\Title: Drilling Manager Date Commission Use Only Permit Num.ber , Ó API Number Approval date ?-CXZ- / /p, 50-(33-ZôS/r=C:XJ Conditions of appro al Samples required Yes ~ Mud log required Yes ~ Hydrogen Sulfide easures Yes @> Directional Survey required ~ No Required worki pressure for BOPE 2M 3M 5M 10M 15M Other: Approved b Form 10- 01 Rev. 12-1-85 6 'I ~~ See cover letter for other requirements Commissioner AFE#134703 by order of the commission Date Submit in triplicate F rm 401 AOGCC Permit To Drill SRU 213-10 4 6/11/2002 lJ ni t Botlndary ~" ~ ...-- ISRU 213-10 - I Proposed SL race I ~~--- ~---- '-.I' I I I A-028077 ..... - - -- I I I _._.~ I ¡ I I ,-- I I I I I SRU 24216 . J ~ L_- --_._---~-- --.---.---. -- -~=_._~~~-~:::~ Scale --- =:J 0 500 1000 1500 2000 2500 3000 Feet ( r ...J Z u. ë:o 0 M ...J Z u. ëo a; N . I ~ ~ ~212-10 llß ~ I . ~65'J FWl 490'..-J FWL I A-028405 - SRU 34 10 q+ - Ru 21-15 :/ 211-15 S SRU .. .... - 5 ;:5 ;:5 SRU 3 1 SRLJ ~ 5RU 12 15 SRU 32R-15 .....J'x~----------'--'--- ~-'=-~-¥----------~-~---_._--~ -c=:=.:---.----- UNOCALœ Î\ :\ COOK_INLET Northern Swanson River Unit -- Soo"" . UniUo' 1912ØØØ FEET Oote' --.---.-------------..-..-...--.-----.-.....----- 24 Mav--2ØØ2 -'.-t nt..-",ete...' EPG --.---...-.--.........---..'"""'"-.---- ( UNDCALe SRU 213-10 WA I SURFACE LOCATION ( ( PROPOSED SRU 213-10 WELL ASP ZONE 4 NAD27 GRID N: 2485819.433 GRID E: 348545.820 LATITUDE: 60.48'04.9448" N LONGITUDE: 150.50'52.6444" W 1725' FNL 628' FWL SECTION 10 T8N, R9W, S.M., AK ELEV. 293.5 FT. NA VD88 f J ¡ ? r / f! .f.¿ -'-~ ' ~ ~ ~ .1- !! ~ } PROJECT UNOCAL 5RU 213 -1Ø 5U~ACE LOCATION LOCA TION 5wônôon River Unil, Alôôkâ DATE ORA WN BY M.5.M. DATE SCALE P.O. Box 468 SOLDOTNA, AK 99669 ~ Consulting Group ~ Testing TEL 907.283.4218 FAX 907.283.3265 3/21/Ø2 1\:bØI ~ u r' I / .~ /5 REVISION PROJECT /DWG. Ø23Ø23 SHEET NO. OF UNO[AL~ Swanson River Unit SRU 213-10 Well LOCATION MAPS AND PLATS LOCATION MAPS AND PLATS PROPOSED LOCATION PLAT THE PROPOSED UNOCAL WELL SRU 213-10 WILL BE LOCATED ON THE SAME PAD AS THE EXISTING SRU 212-10 WELL. THE PAD LOCATION AND LAYOUT OF THE EXISTING ROAD ARE SHOWN ABOVE IN SECTION 10. DEAD END PROPOSED 213-10 SURF ACE LOCATION 12~10 242-16 *--- ----""" / \ / \ --.......... / \ --- - .-/' LOCATION MAPS AND PLATS SRU 213-10 7 6/11/2002 UNO[AL~ Swanson Rivt( Jnit SRU 213-10 Well CEMENT PROGRAM CEMENT PROGRAM 9-5/8" CasinQ (Driven to 80') Note: This string is only for structural support of the wellhead, and diverter stack. 7" CasinQ (8-1/2" Hole to 1800' TVD . 1979' MD): Cement volume based on open hole volume plus 30°/0, shoe joints, and annulus. The job will consist of a lead and tail and cement will be brought to surface. The estimated volume is as follows: Lead 1489' x 0.1267 cuft/ff (8-1/2" x 7") X 1.3 = 245 cuft = 124 SXS (1.98 Yield) 500' x 0.1267 cuft/ff (8-1/2" x 7") X1.3 = 82 cuff = 71 sxs (1.18 Yield) 80' shoe joint x 0.2148 cuftlft = 17.18 cuff = 14.5 sxs (1.18 Yield) Tail TOTAL: 245 + 82 + 17 = 345 cuff or 208 SXS TOTAL (1.16 yield lead and 1.98 Tail) 3-1/2" Casing (6" Hole to 4106' MD) Cement volume based on open hole volume plus 10°/0, shoe joints and annulus. The job will consist of a lead and a tail cement with returns brought to the surface. The estimated total volume is as follows: Lead 1489' x 0.1469 cuft/ft (3.5" x 7") X 1.0 = 220 cuft = 111 SXS (1.98 Yield) (1989-1489)' X 0.1469 cuft/ff (3.5 X 7) X 1.0 = 73.45 cuff = 63.3 sxs (1.16 Yield) (4106-1989)' X 0.1295 cuftlft (6" x 3-1/2") X 1.3 = 356 cuff = 307 sxs (1.16 yield) 80' shoe joint X .0087 cuft/ff = .7 cuff = 0.6 sxs (1.16 yield) Tail: TOTAL: 220 + 73.5 + 356 + 1 cuff = 650 cuff = 482 sxs CEMENT PROGRAM SRU 213-10 8 6/11/2002 UNO[AL~ ( Swanson Kiver Unit SRU 213-10 Well LOGGING PROGRAM LOGGING PROGRAM The following constitutes the proposed geological and evaluation logging program. for the subject well. All tool suites should be available on location for all anticipated logging runs; final determination of which tools will be run will be based on hole conditions at the time of logging, and geologic results. All "Anticipated Logging Dates" are based on pre-spud estimates of drilling duration and should not be considered final. Unocal Drilling Engineer will notify Schlumberger 8-10 days in advance of any logging run (with updates as needed). 8-1/2" SURFACE HOLE FROM 1979' TO SHOE OF 13-3/8" @ +80' CASED HOLE LOGS ANTICIPATED LOGGING DATE: 10 July REQUIRED LOG Gamma Ray Log 6" PRODUCTION HOLE FROM +4106' TO SHOE OF 7" @ +1979' OPEN HOLE LOGS ANTICIPATED LOGGING DATE: 10 July PLANNED LOG MWD With DIR/GR to TD PLANNED LOG Platform Express - PEX AIT/DSI/RHOB/NPHI/GR/SP CASED HOLE LOGS PLANNED LOG OPTIONAL LOG FROM PBTD TO TOP OF 3-1/2" CEMENT GR/CCL (Will be run thru tubing rig less) USIT/CBT/GR/CCL (Dependent on Cement Job) CASED HOLE PERFORATING (INTERVALS TBD) PLANNED TOOL 2-1/2" POWER JET GUNS OTHER GEOLOGIC EVALUATION MUD LOGGING Mud logging will be conducted from the shoe of the 9-5/8" @ 80' until total depth. GAS DETECTION Gas detectors will be functional and running prior to spud. CORING No core is planned for this well. NOTES: All logs are to record UNION OIL COMPANY OF CALIFORNIA as the Company or Operator on the log header. ELEVATION LOGGING PROGRAM SRU 213-10 9 6/11/2002 UNO[AL~ SwansoJ rdver Unit SRU 213-10 Well LOGGING PROGRAM The rig site Ground Elevation is 293.5' AS MEASURED BY McLANE SURVEYING ON PROPOSED PLAT. The As built Plat will be furnished after the Pad is releveled and the wellhead is installed. The actual Rig KB will be measured after MIRU on location. All contractor Field Service Representatives will be notified of RKB in writing by Unocal, and will be responsible for relaying the correct RKB to the engineer( s) on location. LOGGING PROGRAM SRU 213-10 10 6/11/2002 UNOCAL~ SWANSON RI'( 1 UNIT SRU 213-10 Well ANTICIPATED FORMATION TOPS ANTICIPATED FORMATION TOPS Union Oil Company of California Proposed SRU 213-10 Well Elev 293.5 Geologic Tops and Correlations RKB 310 SRU 212-10 Proposed SRU 213-10 Marker MD TVD MD TVD TVDSS Difference Base Glacial 515 515 515 515 -205 0 L. Sterling 2600 2600 2810 2460 -2150 140 A9 2600 2600 2810 2460 -2150 140 A10 2700 2700 2915 2560 -2250 140 B3 3080 3070 3333 2935 -2625 135 B5 3255 3240 3475 3105 -2795 135 B6 3438 3415 3662 3285 -2975 130 Beluga 3550 3522 3770 3392 -3082 130 Total Depth 4106 3735 -3425 N/a ANTICIPATED FORMATION TOPS SRU 213-10 11 6/11/2002 UNOCAL8 SWANSON RIVER UNIT Ii SRU 213-10 Well OFFSET WELL DATA OFFSET WELL DATA SWANSON RIVER UNIT WELL SUMMARIES 0 N 10 10 <0 co ~ ..... 10 10 10 ..... 10 10 ..... ..... C'? N en N ..... 0> N ..... ..... I ..... ..... N N N ch ch ..... N I ~ N N ch N I C'? ~ N N ~ ~ N C'? ~ N c;; C'? N N N N 0 20" -20" SPLC -20" . 22" 20" 22" 20" 22" 22" 16" 13-3/8" 13-3/8" - 22" 1000 . 13-3/8' 2000 9-5/8" ~ {" - {" - 9-5/8" . 9-5/8" 11-3/4" SP SP 3000 SPLC 13-3/8" 13-3/8" 11-3/4" 11-3/4" . 13-3/8" 4000 1 0-3/4" .SP .SP TO - 5000 . 7" ... 140 () TO 7" .SP () Gas Days to -6000' LL 140 10.50 190 140 170 12.50 905-1/?" 10.50 180 8.50 9.50 - 6000 .. TO .c .SP .SP ... 9.50 c. . 9-5/8" 10-5/8" . SP .SP 8.50 Key: () C 7000 "C 9-5/8" .SP CP =Collapsed Pipe ~ .CP :. TO 0 = Days ~ 8000 LC = Lost Circulation tn .LC TO = Total Depth cv () LC aSP = LC Trend Line ::ã: 9000 ~ 9-5/8" . 7" ~LC ._cc 10000 .SP 11 000 -LC SP TO LC I LC .SP 7" . . 5-1/2" . 7-5/8" LC TO 7" 7" TO TO TO 12000 sr 7" b-1/2" 7" LC 13000 7" TO 14000 440 1220 910 630 420 540 580 640 300 100 100 Days to TD 590 OFFSET WELL OAT A SRU 213-10 12 6/11/2002 UNOCAL'" SWANSON RI'( ~ UNIT SRU 213-10 Well MUD WEIGHT AND FRACTURE GRADIENT PROPOSED MUD WEIGHTS AND ANTICIPATED FRACTURE GRADIENTS UNOCAL8 SWANSON RIVER UNIT OFFSET MUD WEIGHTS, PROPOSED SRU 213-10 MUD WEIGHT, ANTICIPATED FRACTURE GRADIENTS, AND CASING PLAN 9.625" 3.5" 0 -;¡;- -I.~ ~\\ . 1000 \ \ ~ \ ~ I I I I -FRACTURE GRADIENT -Production liner ""'ProductionTubing -Structural Casing ~Surface Casing - ~ . Formation Tops -PROPOSED MUD WEIGHT SRU 213-10 - SRU242-16 - -SRU 212-10 - -SRU 211-15 " ~ ~~';r8cg¡ '¡;.t¡'Sing 7000 ~' 2000 -35" II 2935 Top of 83 II 3105 Top of 85 II 3285 Top of 86 II 3392 TÖp of 8elu~a II 3735 PROJECTE) TOTAL DEPTH 3000 4000 ê !. s: 5000 Q. CD c 6000 8000 9000 10000 8 9 10 11 12 13 14 15 Mud Weight (PPG) 16 17 18 19 20 MUD WEIGHT AND FRACTURE GRADIENT SRU 213-10 13 6/11/2002 UNO[AL~ Swanso~ "jver Unit SRU 213-10 RIG FOOTPRINT RIG FOOTPRINT 500 BBL Tiger Tank (Slops) 1#..........................................8. 0 0 0 0 Choke House D Top Dn~c~:::: T~nk -11- 0$ m I { ~ ¡ ¡ - S~b ~ ¡ Diamond Tanks 0 ~ C/) ~ 0: _: 75 HpVacUnit ~ ~ - ~ Cuttings Tank ~ ~D ~ - ~ ~ ~ ~ 500 BBL Tiger Tank ) - ~- ~ 11 ~ ~ ~ ~ : ë: Q) : : "0 (9 0 - ~ ~ ~ -æ ~ ~ -æ ~ - I Boiler I ~ ,= = LyJ ~ 8 i............~...~~.~~~.~.~.~.~.~:....!.J ( Storaae Conexes + t CharQe and Transfer Pumps .:.t:. Cti ~ co Ü (- - 130 BBL Trailer-Mounted ~ Iso-Tanks ,;--.., ~ ~~ Bermed Area - Pre-Mix c::=J MI Shack XXX BBL Vertical Storage Tanks (Replaced wI Tiger Tank on Griner #1) Rig Footprint SRU 213-10 14 6/11/2002 UNOCAL~ Swanson ~ '!r Unit SRU 213-10 DRilliNG PROCEDURE DRilliNG PROCEDURE Unocal Alaska Business Unit SRU 213-10 GRASS ROOTS GAS WELL UNOCALG Prepared by: JIM Date: 04/19/02 Estimate for Grass Roots DRILL AND COMPLETE TIME PLAN No. Preliminary Procedure Time CUM CUM Depth Depth Estimate Time Time In Out (Hours ) (Hours) (Days) (Feet) (Feet) 1 Rebuild location pad, Relevel gravel. 0.0 0 0.0 Drive and set 2 jts of 13-3/8" Conductor Casing and 2 Install Cellar 0.0 0 0.0 3 Preinstall Di verter Bag 12 12 0.5 0 0 4 MI & RU 30 42 1.8 0 0 5 NU DIVERTER LINES & FUNCTION TEST 12 54 2.3 0 0 6 Fill Pits with spud mud and prepare to spud 12 66 2.8 0 0 Directionally Drill 8-1/2" hole to 1989' MD, 1800' 7 TVD 18 84 3.5 0 1989 8 Make Wiper Trip & POOH 8 92 3.8 1989 1989 RU Csg Crew & Run 7"Surface casing to 1989' MD, 9 1800' TVD 6 98 4.1 1989 1989 10 Circ & Cmt Surf Csg. Displace with OBM 8 106 4.4 1989 1989 ND diverter, NU Csg Head & BOP's. Test BOPE to 11 250/3000 ~Test Casing to 2500 psi, Drill out, and 16 122 5.1 1989 4106 Run LOT 12 Directionally Drill 6" hole to 4106'. (assume 50'/hr) 40 162 6.8 4106 4106 13 Make Wiper Trip & POOH LD DP 12 174 7.3 4106 4106 14 RU, Run Logs, RD Schlumberger 12 186 7.8 4106 4106 15 RU & Run Production Casing 8 194 8.1 4106 4106 16 Circ & Cmt Production Casing 8 202 8.4 4106 4106 17 Test Production Casing to 2500 psi. 2 204 8.5 4106 4106 18 Lay Down Landing Joint and Set BPV 3 207 8.6 4106 4106 19 Begin Rig Down and Load out 4 211 8.8 4106 4106 20 Clean Pits and Prepare to RD 8 219 9.1 4106 4106 21 ND BOP & NU TREE. Pull BPV & Set TWC 12 231 9.6 4106 4106 22 Test Tree to 3000 psi & Pull TWC. Secure Tree. 4 235 9.8 4106 4106 23 Release Rig 5 240 10.0 4106 4106 Drilling Procedure SRU 213-10 15 6/11/2002 UNO[AL~ SWANSON RI~' 'R UNIT SRU 213-10 Well DAYS VERSUS DEPTH PLAN DAYS VERSUS DEPTH PLAN UNOCALI SRU 213-10 Kenai Peninsula, Alaska Depth vs. Time Summary 2,000,000 1,000.0 _I -Proposed SRU 213-10 - SRU 223-28, 1997 - ACTUAL TIME VS COST AFE PLANNED TIME VS COST - 1,750,000 L 2,000.0 1,500,000 3,000.0 \ 1,250,000 - .... ~ .:: \ ~ 4,000.0 1,000,000 .... c. ~ ~ L 5,000.0 \ 750,000 6,000.0 \ 500,000 7,000.0 250,000 8,000.0 0 5 10 15 20 25 Time (Days) Days Versus Depth SRU 213-10 16 6/11/2002 Swan( n River unit SRU 2'13-10 Well PROPOSED WELLBORE SCHEMATICS PROPOSED WELLBORE SCHEMATIC FOR MONOBORE COMPLETION UNO[AL~ RKB to TBG Head = 16.5' Elevation 293.5 Feet L ~ -- L ~ 2 7" Surface Casing @ 1989' MD, 1800 TVD JEWELRY DETAIL NO. Depth Item 1 Surf 2 1750 3-1/2" Tbg hgr w/Carneron "H" BPV profile Macco 3-1/2" SMO-1 Chern Inj Mandrel w/lOOO psi chern inj valve PROPOSED PERFORATION DATA TOP BTM ZONE/FORMATION SPF COMMENTS -2125 -2135 A9 Sterling Sand 6 Confirm with log -2250 -2260 A10 Sterling Sand 6 Confirm with log L1 \. -2635 -2645 B3 Sterling Sand 6 Confirm with log TD = 4106' MD, 3735' TVD -2810 -2820 B5 Sterling Sand 6 Confmn with log Directional Well -3010 -3020 B6 Sterling Sand 6 Confirm with log NOTE: ADD 310 FEET TO SS DEPTHS FOR TVD RKB WellBore Schematic SRU 213-10 17 6/11/2002 ~ Þ \u J (lJ° 0 a 0 0 0 0 r ~ * r ~ Þ r~ 1wrf? c-~e(i)r) ~- -,,¡eo c-L D[] :0: :0: liU C~ c ~ c_~ 13-5/8" 3,000 rL- m Þ lu¡- D) --=o~ L; 1f UNO[AL~ 3-1/8" 5,000 Tree Run 7 -1/16" 5,000 13-3/8" Casing 3-1/2 Tubing Wellhead Diagram SRU 213-10 Swanson~' }r Unit SRU 213-10 Well WELLHEAD DIAGRAM WELLHEAD DIAGRAM Unocal Swanson River 2~0 r ~ I r ~ 3-1/8" 5,000 Wing 2-1/16" 5,000 Outlets 7" Casing 18 6/11/2002 UNO[AL~ Swanson ~ )r Unit SRU 213-10 Well LEAK OFF TEST PROCEDURE LEAK OFF TEST PROCEDURE 1. Clean out the rathole below the shoe, and drill 20' of new hole. Circulate and condition mud. 2. Pull the drill string into the shoe. Rig up to observe annulus pressures. 3. Close the pipe rams and pump down the drillpipe at a slow rate (1/4 - 1/3 BPM) if exposed formation is permeable. A non-permeable formation should be step tested to a predetermined pressure. 4. Measure the volume pumped and plot annulus pressure-vs-cumulative volume pumped. Compare annulus pressure to drill pipe pressure and confirm both are the same. Record and plot pressure versus volume pumped. The pumps should be shut down immediately upon indication of leak-off. Record the initial, shut down pressure and the pressure after 1,2, and 3 minutes. 5. Release pressure and record the volume of fluid recovered in the trip tank. The point "B" shown in the attached graph at which the plot of drillpipe pressure stops increasing equally as the volume is pumped is called the P.I.T. limit, Leak Off, or pressure integrity test limit. The leak-off pressure is calculated as follows: Leak-off (EMW) = Mud weight in hole + P.I. T. (PSI) (0.052) X (shoe depth in TVD ft.) This equivalent mud weight should be made known to all drilling personnel to ensure it is not exceeded under any circumstances. See the drilling procedure for guidelines on expected LOT's or pressure integrity test limits for each casing shoe. TYPICAL PIT PLOT (psi) C "---L- SURFACE PRESS. VOLUME PUMPED (BBLS) SHUT -IN-TIME (MIN) NOTES: Point" A" will have some variance until the system begins to pressure up. Point "B" is the leak off and has traditionally been abbreviated LOT. Point "C" is known as the injection pressure and is usually dependent on rate. Point "D" is measured 1 0 seconds after the pump is shut down and is known as the fracture closure pressure. UNOCAL OIL COMPANY DEFINES AND USES THE FRACTURE CLOSURE PRE~lJ3E~ THE LEAK OFF. Please identify whether the leak off is at Fracture closure or as traditionally define" : L t I V E D JUN 11 2002 Alaska au & Gas Cons. CommisSløn Anchorage LOT Procedure SRU 213-10 19 6/11/2002 Swan( 11 River Unit SRU 213-10 Well HAZARD ANALYSIS UNOCAL ALASKA WELL WORK HAZARD ANALYSIS SCREENING UNO CALf., Hazard Analysis for APD 20AAC 25.005 (c) 4 Abnormal Pressure During the drilling of these shallow intervals, no abnormal pressures were encountered, however, during the life of any old field, there is a slight possibility that cement jobs from older wells can allow some fluids to migrate up hole. There have not been any cases of this reported during the drilling of newer wells in this field, but the potential does exist. Prior to all trips a swab in potential test will be conducted and the hole will be kept full at all times during the drilling of the shallow intervals. A trip tank will be used to monitor for correct fillups. Maximum pore pressure anticipated is 1670 psi at 3735' TVD total depth based on 8.6 ppg EMW. Offset wells were drilled with mud weights ranging from 9.5 to 12.5 ppg. The closest offset well is the SRU 212-10. The SRU 212-10 is located on the same pad. The New well the 213-10 is to be a replacement for the watered out 212-10. The new well, 213-10 is to be drilled up dip to allow for producing attic gas. Lost Circulation Water Based Mud and subsequently KCL completion brine is planned for the drilling fluid for this well. If excessive lost returns are encountered a Calcium Carbonate and LCM materials pill will be used to control losses. No Losses were recorded in the drilling of the offset well. In the event of lost circulation, adequate supplies of lost circulation material and water will be kept on location. Crews will be briefed on the strategy for dealing with losses should they occur. Some minor seepage losses should be encountered in the now depleted Sterling and Beluga sands. Shallow Gas The presence of shallow gas is well documented throughout the Kenai Peninsula and is associated with coal bed methane accumulations. The minimum amount of gas seen on the offset wells in the surface interval indicates only minimum methane associated with the coals. The Conductor pipe will be preset with a water well rig and a diverter will be nippled up on top of the 13-3/8" to drill the 8-1/2" surface hole. Hole fill on trips will be continuous until surface casing is set. Proximity The new well will be drilled from a surface location about 25 feet from an existing shut in well. A spider plot, directional plan, and directional tools will be used to drill both the 8-1/2" and 6" hole sections. The well will be considered a directional well from spud. The offset well kicked off at 2400 feet and was vertical until that point. The proposed well will kick off at 500 feet and will be intentionally deviated to the South some 1500 feet above the offset well kick off point. The well plan addresses any possible interference or proximity concerns. H2S H2S production has not been identified in any of the Offset well information files available to Unocal. Waste Disposal Mud will be disposed of in the SCU 243-4 Mud Disposal Well. Cuttings will be placed in the Swanson River Solid Waste Cell. HAZARD ANALYSIS SRU 213-10 20 6/11/2002 UNO[AL~ Swanson ~ er Unit SRU 213-10 Well CASING DESIGN INFORMATION Bottomhole Pressure Information The following presents data used for calculation of anticipated surface pressures (ASP) during drilling of the Swanson River SRU 213-10 well. The pore pressure gradient was estimated from the following information: BHP Well Q.§Ï SRU 212-10 1100 SRU 212-10 900 Depth TVD 2435 3320 EMW. ppg 8.65 5.2 Comment Not depleted at this location Partially Depleted Beluga intervals The fracture gradient for the surface casing point was conservatively estimated at .806 psi/ft or 15.5 ppg. Casing Pore Casing Setting Fracture Pressure Mud Pore ASP Size Depth Gradient Gradient Weight Pressure Drilling 0nJ (TVD ft) (Ibs/gal) (Ibs/gal) (Ib/gal) (Q.§i) (Q.§i) 7" 1,800' 15.5 8.65 9.5 805 1,364 based on FG 3.5" 3,735' 15.5 8.65 9.5 1,670 1,297 based on PP @ TD Procedure for Calculating Anticipated Surface Pressures While Drilling ASP is determined as the lesser of 1) surface pressure at breakdown of the formation at the casing seat plus 1 ppg safety factor with casing evacuated with gas. or 2) formation pore pressure at the next casing point less methane gradient to surface as follows: 6" Production Hole Section for 3-1/2" Casina from Suñace, 0' TVD to 3,735' TVD 1) ASP 2) ASP = ((FG+1 )x.052xD) - (MWx.052xD) = (16.5x.052x1800) - (0.10x.1800) = 1,544 psi OR = PPx..052xTVD'- (0.1 gas gradient xTVD) = 8.65 x.052x3735 - (0.1 Ox3735) = 1,680 - 373 = 1,307 psi NOTE: See Kick Tolerance Sheets on following page for identification of swab kick tolerances for the 7" surface casing. CASING DESIGN INFORMATION SRU 213-10 21 6/11/2002 UNO[AL~ Swanson ~~. 9r Unit SRU 213-10 Well CASING DESIGN INFORMATION CASING DESIGN Suñace Casing: 7", 26 #, L-80, Buttress Worst case for burst would be in the event of a gas kick while drilling at TD (3,735'). If the Maximum Anticipated Surface pressure were encountered, the SI pressure against the T' surface casing would be 1544 psi at the shoe. The MASP would be some 180 psi less due to the gas gradient inside the casing. This is based on a 15.5 ppg fracture gradient plus 1 ppg safety factor with the casing full of gas. The burst load would then be 1364 psi. Burst load = 1364 psi. 7", 26#, L-80 rated @ 7240 psi for burst Safety Factor = 7240/1364 = 5.30 OK Worst case for collapse is if returns are lost while drilling below the 7" Surface Shoe Collapse = (10 x.052x 1,800') = 936 psi for full evacuation 26#, L-80 rated @ 5,410 psi collapse Safety Factor = 5410/936=5.77 OK Worst case for tension is if the shoe of the pipe were packed off and the resultant end area buoyancy did not apply. This is equivalent to using air weight. A 100,000 pound overpull is also assumed in the calculation. Tension = 1989' X 26# = 51,714 Max pull = 51.7+100 = 161.7 K Rated = 604K for body yield Safety Factor = 604/151.7=3.98 OK Production Casing: 3.5", 9.2#, L-80, Buttress Tubing Worst case for burst would be in the event of a gas kick while completing at TD (3735). If the Maximum Anticipated Surface pressure were encountered, the SI pressure against the 3.5" production casing would be 1,680 psi less the gas gradient to surface of 373 psi for a MASP of 1307 psi. Burst load = 1,307 psi. 3.5", 9.2#, L-80 is rated @ 10160 psi for burst Safety Factor = 10160/1307 = 7.77 OK Worst case for collapse is if plugged perforations occur while flowing the well. Collapse = (10 x.052x3735') 9.2#, L-80 rated @ 10,530 psi collapse = 1,942 psi for full evacuation Safety Factor = 10530/1942=5.45 OK Tension is checked at the surface. Tension at top = (4106'-0')(9.2#) + 50,000 Overpull allowance = 87750 3-1/2" 9.2# L-80 is rated = 207K for body yield. Safety Factor = 207/87=2.32 OK CASING DESIGN INFORMATION SRU 213-10 22 6/11/2002 UNOCAL'- Swanson ~ )r Unit SRU 213-10 Well CASING DESIGN INFORMATION Maximum Kick Tolerance Calculations Well: eSG Shoe: SRU 213-10 7" General Information 1 7" Casing Shoe (from RT) 1,800 Feet (TVD) 2 Fracture pressure at the 7" Shoe 1,440.00 psi 3 Proposed TD of the 6" Hole (TV D) 3,735 Feet (TVD) 4 Maximum anticipated pore pressure 1,736.78 psi 5 Mud Weight See table PPG 6 Gas Gradient 0.10 psi/FT 7 Average open hole size 6.00 Inches 8 Drillpipe 00 3.50 Inches 9 Capacity of open hole by drillpipe 0.0231 BBL/FT 10 Height of gas colum in wellbore when top of gas is at the shoe HT Feet (TVD) Assumptions for Area: Fracture Pressure Gradient = .8 PSI/FT; and Pore Pressure Gradient = 0.465 PSI/FT. Gas bubble height in well bore (Ht) calculation with gas bubble top at 9-5/8" shoe. Pshoe + Pgas bubble + Proud = Pmax@ TO Pshoe + GG*Ht + .052*MW*(DTO-Dshoe-Ht) = Pma.x@TO Gas Volume (GV) calcualtion at 9-5/8" shoe. GV = CAP*Ht Kick Tolerance calculation: Gas volume in wellbore at TD. PI VI = P2V2. Assume constant temperature. Kick Tolerance * Pmax@ TO = GV * FP Mud Weight (PPG) Gas Bubble Height Gas Volume @ Shoe (Feet) (BBLS) Kick Tolerance (BBLS) 7.0 7.2 7.4 7.6 7.8 8.0 8.2 8.4 8.6 8.8 9.0 9.2 9.4 9.6 9.8 10.0 10.2 10.4 10.6 10.8 11.0 1,544 1,559 1,572 1,585 1,597 1,608 1,619 1,628 1,638 1,646 1,654 1,662 1,669 1,676 1,683 1,689 1,695 1,701 1,706 1,711 1,716 36 36 36 37 37 37 37 38 38 38 38 38 38 39 39 39 39 39 39 39 40 30 30 30 30 31 31 31 31 31 31 32 32 32 32 32 32 32 33 33 33 33 CASING DESIGN INFORMATION SRU 213-10 23 6/11/2002 Variables Dshoe FP Om Pmax@TO MW GG ODoH ODDP CAP Ht UNOCAL'- Swanson ~ )r Unit SRU 213-10 Well CASING DESIGN INFORMATION CASING PROGRAM SUMMARY UNOCAL8 Swanson River Unit SRU 213-10 Well Casing Program Casing Casing Size (in) 7 3.5 Set From Set to (MD) (MD) 0 1989 0 4106 Casing Weight (ppf) 26 9.2 API Values Hole Casing Conn Size Burst Collapse Tension Grade Type (in) (psi) (psi) (K Ibs) L-80 Butt 8.5 7240 5410 604 L-80 Butt 6 10160 10530 207 Casing Design Frac Formation Design Factors Casing Casing Setting Setting Gradient Pressure Size Weight Casing Depth Depth at shoe at shoe MASP (in) (ppf) Grade (TVD) (MD) (ppg) (ppg) (psi) Burst Collapse Tension 7 26 L-80 1800 1989 15.5 1544.4 1364.4 5.306362 5.779915 3.981175 3.5 9.2 L-80 3735 4106 15.5 1680.003 1307.003 7.773509 5.421687 2.358297 Casing Design Discussion Maximum loads are used to calculate the safety factors. In the case of burst, the hole is evacuated with gas. In the case of Collapse, the inside of the casing is assumed completely empty. The tension safety factors are based on air weights of each string with an added 100,000 # overpull. The tubing string tension design is based on a 50,000 # overpull. CASING DESIGN INFORMATION SRU 213-10 24 6/11/2002 ßi Swanson River C. .itt SRU 213-10 Well DIVERTER AND BOP SPECS UNOCALrI UNOCAL8 DIVERTER AND BOP SPECS Swanson River Unit SRU 213-10 Well Diverter and BOPE Diverter The diverterwill consist of a 13-5/8". 5,OOOpsi Annular Preventer and a 12" 0.0. non bifurcated vent line. The vent line will be full opening and integrated with the annular in the fail safe design as stipulated in 20AAC 25.035. The Vent Line will be a minimum of 100' away from any source of ignition. Blow Out Preventers The blowout preventor will consist of a 11", 5000psi Annular, a 11",5,000 psi double ram preventor with pipe rams on top and blind rams on bottom, a 11", 5000 psi mud cross w/3-1/8", 5000 psi flanged outlets, and a 11", 5000 psi single ram preventor with pipe rams. Choke Manifold . The choke manifold will be a 3-1/8", 5000 psi manifold. It will include 1 ea. remote controlled hydraulically actuated choke and one hand adjustable choke. Casing Test MASP Test BOPS Low/High Casing String Size (in) (psi) (psi) Size and Rating (psi) Conductor 13-3/8" N/A N/A 13-5/8" 5M Annular Function Surface 7 1364 2000 11". 5M Annular 250/3000 11", 5M Pipe Ram 250/3000 11", 5M Blind Ram 250/3000 Production 3.5 1307 2500 11". 5M Annular 250/3000 11", 5M Pipe Ram 250/3000 11", 5M Pipe Ram 250/3000 11", 5M Blind Ram 250/3000 DIVERTER AND BOP SPECS SRU 213-10 25 6/11/2002 UNOCALt" Swanson River ( . Jitt SRU 213-10 Well DIVERTER AND BOP SPECS CHOKE MANIFOLD DIVERTER AND BOP SPECS SRU 213-10 26 6/11/2002 UNOCAL4." Swan( n River Unit SRU 213-10 Well DIVERTER STACK UP Flow Line F ill Line I / I '\ 13-5/8", 5K, Shaffer G ) I -I - L ~ I 12", Hydraulic ODerated I I 1 13-5/8" , 5Mx 1 ~-fi/R fiM -~ 12", . Diverter H = 2.5'@ CL I 60" T - - 36" + . f .. .. - . . l I 13-5/8" , 5Mx 13-5/8" , 3M 70.75'~ 53.75" Need new 13-5/8" 3M ~t~ri;nrr Uø~r1 17" 8.5 . " , ~ ---... Welded 13-5/8" ,...-----., UNOCALe! Diverter Hookup Well SRU 213-10 Swanson River Unit Kenai Penninsula Drawn by: J.I.M. DIVERTER AND BOP SPECS SRU 213-10 27 6/11/2002 UNO[AL~ Swan( n River Unit SRU 213-10 Well BOP SCHEMATIC Flow Line F ill Line I / I \ 13-5/8", 5K, G ~ 12", Shaffer Annular Hydraulic Operated ) r Knife Valve I I - I I 12", Diverter - I I 13-5/8", 5M x Line ---.- - 13-5/8, 5M Diverter Spool H = 2.5'@ CL 60" 36" * . . ... ... - Need new spool 13-5/8", 5M x 13-5/8", 3M Crossover Spool 70.75" 53.75" . . ... I - , 17" t , I 13-5/8" 3M Starting Head 8.5' .--- Welded UNOCAL81 Diverter Hookup Well SRU 213-10 Swanson River Unit Kenai Penninsula Drawn by: J.I.M. Date: 05-15-02 13-5/8" ~ RECE\VED ,JUN 1 '1 2002 "' ,0 ¡ ika on & Gas Cons. L,Ù\l¡ìI¡¡;:k Alas Anchoratje DIVERTER AND BOP SPECS SRU 213-10 28 6/11/2002 UNO[AL~ M-I. LL.C. 721 West First Avenue Anchorage, Alaska 99501 (907) 274-5564 (907) 279-6729 Fax Swan( n River Unit SRU 213-10 Well MUD PROGRAM ~ MUD PROGRAM Economics Summary DrLlhng 80' -1989' 4 Drilling 1989' to 4 9 Completi on .'"t .:, r:\()CAL SRl' 213-10 .'. . Yq.:~;~.~' /"P~û.' ,'EngiD~l',Ù1g,j' ~~~d~1 ~~"i(';.;:¡~~'§¡';A,¡',!~:b:"i~ ..~ $20000 S2500 13 $15000 S5625 16 $500 SI875 '.'. ." -'. . Engineering Cost$ are f(Jr 1\.1-1 Engineer only . assmne ,,,,"eight up to . cost Mud Program SRU 213-10 ppg in the 6" interval. js made for 10$1 drculation or stuck pipe. 29 $22500 125 $45500 6/11/2002 UNO[AL~ Swan( n River Unit SRU 213-10 Well MUD PROGRAM r N()(~~'\L SRI: 213-10 Interval Summary 80' - 1989' - MD 1800' TVD 7" Casing 8 1/2 "Hole Drilling Fluid System JOt;. KCl Fin Pro t"T Key Products [\,,1-[ Bar i Flo Vis Süda Ash': Poly pac l.. DDt"ur Plug/SAPP B ¡carb Caustíc Soda/ KCL"" Kia-guard Solids Control FIo\\' Line Cleaners Desander.i Desilter Centrifuge Potential Problems I role Cleaning / Tight IIole Bít Balling Ilole Enfargement Gas Kicks Coal Sloughing Interv,al Drilling IFI:uid Properties Depth Mud Plastic Yield Gel API Total Interval Wejght Viscosity Point Strength Fluid Loss Drilled. Solids (ft) (ppg) (cp.) (lbJ100ftI) (lb./100ft' (rnlf30min) {%. 80 8.8..9.2 5-10 20 - 30 NJC <.: 20 3 or less 1000 9.0..9.5 7..12 15 - 25 12 12- 15 5 or less 1989 9.0..9.5 10..15 15-25 12 <.: 10 c5 or less . Build spud system "\vith KCl and FIn \,lis. Add Kla-Gard for solids encapsulation. . all solids control eqlÜpment. . Raise visc()síty jf gra'i/el sections are encountered. . Punlp if requ ¡ red. . Add DD (drjlhng detergent) "Nut Plug, and SAP? for possible hit balling. . Potential Problems2 Running gra'veL bål balling, shallü\v and s\velling ,clay . L.O\i\/er flui d to 10 (>c's API end of !nterval \,~/ith Polypac additíctt1s. . E sti mated usage barrel s. Note: ~VhId ppg may be becau se potential gas. Mud Program SRU 213-10 30 6/11/2002 UNOCAL'- Swan(: n River Unit SRU 2'13-10 Well MUD PROGRAM 1- N()(:¡\L SRI.' 213-10 Interval Summary 1989' - 41'06' MD 3 1/2" Tubing 6" Hole Drilling Fluid System Ól\) KCl FIn Pro t-.:T Key Products r'vl-[ Bar / FIn Vis Soda A~h /' Polypac LL' Solte.\ De:;,co CT- .:' Bicarb,:' ('austic Sodai KCL..: Kia-guard Drill Xl/Dual FIo.' Lithium IIypochlorÙe Solids Control Flow LLne Cleaners Desander i Desilter ,:' Centrifuge Potential Problems Ilole Cleaning Tight I tole Bit Balling Hole Enlargement Gas Kicks. Coal Sloughing Interval Drilling Fluid Prope'rties Depth (*) Interval Mud Weight (ppg) 9.0-9.5 9.0-9.5 Plastic Viscosity Yield Poi nt Gel API Strength Fluid Loss T ot81 Drifled.. Solids e/o) 5 or less 5 or less (ft) 2000 4000 (cp.) 8 - 14 8- 14 (lb.l100~) (lb./10GW) (mI130min) 1 0 - 20 ~ 10 6 - 10 1 0 - 20 8 - 10 <: 5 . Treat surface mud to drill float collar~, cement~ and shoe. Treat. this fluid for cement contamina- tion. Condition rnud to KCl. Lo\"ler HuÎd as required. . Run all solids control. l\dd KIa-guard for addhional inhibition.. . 1\4aintain adequate and 3 RPL\¡1 reading for hole deanjng Lo\:ver fluid loss. \\ijth Polypac UL and Dual Flo. Add 2 4 PPB of Sohex if nmning coal becorues ¡} Ju'oblem. . Potential problems: Gas kicks, Bit balhng., sloughing coal. . Run and cement 3 Tubing. . If needed U5,e lithium hypochlorite at 4 r~pb for a breaker for the 1710 PrfJ system. . Estintated additional volume usage 200 barrels. Mud Program SRU 213-10 31 6/11/2002 UNOCAL.., Swan( n River Unit SRU 2'13-10 Well MUD PROGRAM t Nf)(~..\L SRL 213-10 Interval Summary 1989' - 4106' MD 3 1/2" Tubing 6" Hole Lost Circulation Rê'cümmencled LCrvt Pil1l:()l'lHHlas Problems Key Products DriHing FJuid ()rvl Sê'aJ SafeCarb Fine. \'1edium, Cüarse Ver~a- IIRP Lost Circulation Pil:1 (S,lightLosses) Volume of Mud (barrels) 30 Mix II S,afeCarb Fine (ppb) 10 (ppb) I SafeCarb Medium (ppb) 10 Flo,..Vis ( ppb) [0 Lost Circ.ulation Pill (Moderate Loss.es) Volume of Mud (barrels) 40 Mix II SafeCarb Medium (ppb) 15 SafeCarb Coarse (ppb) 10 Flo"Vis ( ppb~ 15 (ppb) 1/2 Lost Circulation piiU.(SevereLo$s,es) Volume of Mud (barre Is) 50 Ss'feCarb Medium (ppb) 20 (p,pb) I SafeCarb Coarse (ppb) Mix II FIo-Vis (ppb) 15 . should be added to mud system. Fin 'hs should only be added jf required. . If possible, spot pilI across then zone. i\pply moderate pressure into thief zone. Ion to squeeze pill Mud Program SRU 213-10 32 6/11/2002 UNO[AL~ Well Summary Swa~ n River Unit SRU 213-10 Well MUD PROGRAM ("N()(~¡\l., SRI ~ 213-10 C8ing Hole Casing Depth TVO Mud Mud Sum Cumulative Size Size Program System Weight Days Mud Cost T" 8 ] ....... 1989' 1800" 3~,ó KCL 8.8-9.5 4 $22500 f..!.. 3 Il2" ft' Ke.v Issue l~lo. 1 Cll ttillg.fìDi.\lJO¡\' al Kel' Issue lVO. 2 .... DrillS olills B II illl-lIl) KeJ.' ISSlle 3 .. Hole ..51n hiJilJ' Slougl1illg Coal Ke.v Issue 4 LO.fìt ('irCll/atioll Mud Program SRU 213-10 4106" 3'735' ]3 $43125 6f>",~ K C L 9.0-9.5 J6 $45500 . CnU1ngs Dispo5.:11 \~¡ill be an issue. Mud and cuttings should meet aU S\vanson Ri\,"cr disposal requirements and limita- tions. . Run a.:;; tine a mesh sicreens on shakers,lHud deaner, and cen- trifÜge jf 8\lailable to reduce the build np driB SCthds in the mud. . Maintain mud \\Ieights as per program. Increase rhc'ülogy as required by' hole c:onditions. . ~'1ai ntal n adequ.ate suppl j es of LC M on ] ocation - {J se a com- binaÜon of Hue and medium Nut Plug~ l'vU Seal., and NUX It Do not exceed pph or utilize coarse material \:vithoutCOH- fínnation from M\}¡'D and rvlud f\.'lotor representaÜveSí. 33 6/11/2002 UNOCAL'-' Project Team Gus \\lik \Varehouse Jv1gr. t Swan{ n River Unit SRU 213-10 Well MUD PROGRAM ( \f)('..\L SRI 213-10 I~ orest Slater Field Engi neeI' ~¥f. .-"Ü ~ J j m B1'O"'11 Field Engineer f Lee Dewees ProJect Engineer f Deen Bryan Tech Service . [vtl Pf(~iect and Engineering ]\'.1anager \\'îJl coordànate hetw'een the Unneal of- rig. \\arebouse, and the L'v1-1 field engineers. . \VeU progress \'\/in be. monitored to Inoki~)r an.ychanges \,,,,hich \\'tH irnprove the eili- the. operation Of avert U'ouhle.. Project 'I 'catn C.rdig Bieber 'Title O(-en Bryan District "'tanager T eell Servi.ce Lee Oewees Project Engineer "¡arehouse J\ilanager (;us "ilk Mud Program SRU 213-10 34 \~lork CcUular 901274-505] 907 229-t 196 9()7-27 4-5;003907 - 223-1634 907-274-5533 '907-230-6653 907 776..8680 907 252-42] 8 6/11/2002 UNOCALt- Swan( n River Unit SRU 213-10 Well DIRECTIONAL PROGRAM DIRECTIONAL PROGRAM NOTE: The 213-10 well adjacent to the proposed well is watered out and currently is shut in as incapable of production. The 213-10 was drilled as a straight hole to 2400' and then directionally drilled. The proposed well will kick off at 500 feet, well above the kick off point on the offset well. The offset well drilled to the East and the proposed well will drill to the South. Given the proposed well path and the Inclination surveys on the offset well, the closest that the two well should come to each other is 25 feet. This is not perceived as a problem to require special nudging. The proposed well will be kicked off by orienting to the South and directional drilling with a motor. ~ Ur«Iœ.e SRU 213-10 Proposed Well Profile - Geodetic Report Rtpœt DiM: Jlré HI :xú1SlI"ìtyJ[l.li CompullliGfl MØJlod: ~Itlffa¡m O~ure ¡'lJ:r:*J QmI: Ü'i~ 'f'crtlGal SlIGtiDn ADnlllll: 1 t7 010" FJDö: ~~'ì RÌt'e'f UìJl VIII1Ii:aJ StdIDII~: N ü{((.In ¡: {lOt)) ~ StIUl:lII'I I SJæt. . Sa!rt!n11 ~ ¡':;R;;J 21~ 10 ..... ...hI. .1\1') ArlmøŒ:.... . Gùun: KB Well: 21311} --lalll"" ~-.J' MlRdeIlllUllElmdol'l: 3;Üül!relálr.>!:I;¡MSl 9crehaH: 213m F 11''' SHilltdfGloulJd. LtiWI..l:lrliIIIœ:: 17(}COOni!!~j!!l¡¡:WSl .0MAJìIt. MiItJIe&Dedbøsm:ætiJj" &UlWllJNølltJDiøe: 21:l1GP5,I.ÀtIt!1Q æœ fœaJAddStnngll: :bf(IJ~49r,T fCMtI NIO;ODI 'iSIIDnIIa: 1ìJ.6t7" ¡' 12B1.00 n,l 5;DUU G~ ~~ n.fi2II" GMCcIonIí!IIII Sp/HI: WIfflJ"~ .slíté~ lctè4, us Feeì DecDlIÖOO OŒ'£u:'é- 2.5, 2X.l2 I.øcdoø LåII..ong: ~J 00. OOB73æ,'t'i 15f1 !!47!537i Iìa9I'dn Dec:ì I'Io1tDn I'ÌriIIIÉ Ef~ 2ID2 l«øtienGrldIŒ'tJX: ~J~q.tDkIJ~ E34eS45;mnU:i limthbtmnœ Tí~~Ö'ItI Gd.~IICtÅI19Ie: .o.Ì~" fàØ:tœr~NøIth""trueiMldl: +2).;OCt1~ Grid Sed.~: û~o Løo:ìItoontìøraes iW8l1Ctd f«:W~ ~ l Stihm m KOP BId 41100 End 8Id Dtþ4i100 T:arg.e¡l aIImi II Ehd Ot~ TD IDJ \J AD. J ~.J ~J ~J \:J ,: ~. 500..00 0.00 187.01 500.00' OJ» 0.00 0,00 fDD.oo 4-00 187.01 500.92 ~49 .3M .0.43 700.00 &00 187.01 6œ.35 13-94 .18.84 .1.10 BOO.oo 1WO 187.01 797.81 31.30 ..3Ul1 ~.82 9)1).00 16.00 187.01 894.82 55.49 -55.07 .a. IT 10J0..oo 20.00 187.01 989.91 88.38 -85.74 .10.54 1100.00 24..00 187.01 1œ2.61 123..84 ~ 122.91 .15, 11 12.00.00 2&.00 187.01 1172.47 Uti.67 .100A1 .:!7:J.46 13(0.00 32.00 187.01 1259.05 217Jj6 ~216.03 .26.55 1400.00 :3&00 187,01 1341.94 273.58 .271.52 ~.~ 1431.46 37.26 187.01 1367.19 292..33 .290.15 .~.OO 2583..37 37.26 187.01 2284.01 989.71 .QS2.~ .120.75 2EOO..00 36.59 187.01 2297.31) 999.70 ..e92:.24 .121.96 2700.00 32..59 187.01 2!79.&I) 105&47 .1 CÞ:IS,57 .12SJ!9 2764..83 30.00 187.01 2435.00 lD91114 .1062.00 .123,00 2fØ).00 2&59 187.01 2465.67 1107.35 .1099.00 .13'3.10 2S00..oo 24.59 187.01 2555.07 t152.11 .1143,50 .140.56 liD I Ðå I ~a/ ~5d ... J ~J ¡) 'I~J !iJ i~. 187..01 21.tl14 1222.40 .121326 .149.14 187..01 2838.89 1247.59 .123827 .152.21 187.01 2931.11 126~7 .1~S1 .154.46 187..01 ~.49 1277.45 .1257.90 .155.86 187 :.01 3tæ.00 1281.71 .1272.13 ,156.3a 187Jl1 :J1~.'5 1281.88 ,1272,31 ,156,40 187.01 3135.00 1~tœ .1231,43 .157.52 3100.00 113..59 3:!OO.oo 3:!OO.OO 3400.00 348164 3493.08 12.59 !.59 4..59 t25 0.87 400ß.71 0.87 Directional Program SRU 213-10 35 ~ DI..S nt~ 0.00 4.00 4.00 4.00 GrldCacnlkdll GlQpp¡k CœfdIutJs MmI'*'J I &stieg LItthde I ..... 2J:eJ A.ß1 N 6O.801mJ-w 1EiQ.84¡rgœfr 2485819.43 348545..82 t.60.80137356 W 150.84795677 2485815..98 348545.35 N 6O..801364C19 W 150.B4i'116918 2.œ51OOfi62 34854'3:94 N 60.80133510 W 150..847S6B29 24S578a..42 348541 :00 N 60..80128857 W150.84797815 4.00 2418576(.46 348538.34 N 60.80122292 W115O.8479£WB7 4.00 24185733.84 348534.17 N 60.8011330.2 W 150.84æ1577 4.00 24S5696.74 348529.12 tHJO.80103~ W150.84804136 4.00 2485653$1 348523.21 N eo.EKXl918æ W 150.84801131 4.00 2.418EðD.78 3485116.48 N 60.80078263 W 150..84810540 4.00 24f15S4íL.'3lI 34E15œi.95 N 6O.aril83:J84 W150.84814357 4.00 24185mR79 348500.42 N 6O..6OO5798i!J W 150.84815639 0.00 24184838..83 348412,40 N 60.798118B52 W 150.84863268 4.00 24184828.93 348411.03 N 6O.79!18EÐ39 W 150.84863946 4,00 24184772.70 348403.41 N60.198505æ Wl50.84867824 4.00 2484739.32 3483EE1.æ N 60.79841. W 150.84810125 4.00 248472227 3483£6.54 N 60.79836714 W 150.84871300 4.00 ~n93 348300.51 N60..79824563 Wl50.84874356 Gûd~ !ÏlQpsãk!CœrdØIb\s tU ~~ I &stllg LIIttà I ~ f"MM:M 2d~ ~.31 N eo.7fJ3t41.J-w 1I50.8487838~ 4.00 2:484æli29 348381.00 tUIO.79OO64ß1 W15t184879159 4.00 2.t34B83~'33 348377.64 N 6O.7'979fí640 W 150.8488œ77 4.00 24184565.1:2 348375.15 N60.797931JSJWl50.8488212ß 4.00 2484553J'E 34837'3.61 N 6O.797æ5æ 'II 1I50.~ 4.00 ~S3 34ii37'3.00 N61l797&ß78 Wl50.84813211 4.00 2484549.$5 34837'3..01 N 60.797&ß::!ß W 150..84883222 0.00 24184.540.24 348371.77 N60.7'97&l834 W150.848m4.9 6/11/2002 UNOCALf., Swan( n River Unit SRU 213-10 Well DIRECTIONAL PROGRAM ~ ~ U.uCAL8 VER'l"ICAL SlirrIOJr VIBW Cli¡¡¡nt: UnDc~1 "JI;.¡;ll: 111-10 ¡r'5:' Fl~ld: Sv~nsal1 Rlvgr Unit StrIJ,::tun;¡: SV~I1!;ün Rlvgr £,.,:t1e,n At: 1:6:"1".01 d¡;;':f D~t¡¡¡: JUI1¡;; IG, 10G2 lIP 0 ~f) 'I::'.' ....".... ~OOD ø....,.. .I!: -.. .~ W fSIG 8~ ~~ Ii œ ~8 -0 B. ~ 2öOO ðo. !~ e'ä ~a: G :;. ,æ ~""A; ,2 W LUU\I r.- Ho'ld ~Ie 3j.~. ~ Hold ~ C),ST B1ð, !:EI ,,500 ð OOð~OOO ~SIG VértJcailSéctiðn D@paOOf8 at 1.87.131 deg from (0-,0, (to). (1 in = SGO fe8t) Directional Program SRU 213-10 36 6/11/2002 UNO[AL~ Swan{ n River Unit SRU 213-10 Well DIRECTIONAL PROGRAM PLIJr VImr ~ C11.¡¡nt: ~1l: F1..,ld: Unoc;¡¡l 213-10 í~'5:, E't::nl,;tur.¡¡ : E'c;¡¡llil: D¡¡ to¡ : E.Vii'in5Qn R1 v.w¡r Unit E.vii'ins.:,n Rlv.w¡r ~ 1 in . .:::.:.Q !: t 10 -Jun-':::':'O 2 ,400 I .200 r 0 200 400 I) 'lrUQIItJ rtb H;;¡g DQC ¡ E: ':::Q,a.p ¡ 0 - ~J:IP'...U'aI ~ -200 -XlO -- ^ ^ .4C() ^ x:; g % .). . ..,.".. Q """ ~ ..000 ~ -«tJ .œo ~~ .&DO y v Ii{ .1ÐIXJ Þi¡1o . lID! -------------:1'1.. &;!.. wmr» :X"":1¥(' ~- . M;~-:¡:; .. -1000 .1~00 -1:2«1 -~.:!:? . ~ "~"~~'I:':r::? ~TD .0' >.200 «< WEST 0 200 EAST »> 400 Directional Program SRU 213-10 37 6/11/2002 UNOCAL'- swl11s0N RIVER UNIT SRU 213-10 PTD COVER LETTER Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Attn: Commissioner Cammy Taylor Re: Application for Permit to Drill (Form 10-401) Swanson River Unit 213-10 SRU 213-10 Dear Commissioner Taylor, Enclosed is a¡evisedapplication for permit to drill for the Swanson River 213-10 Well. The original PTD was for a deeper well. The well has been shortened from 5700' to 3700' and as a result the casing strings are all shallower. Since this was a 500 foot change in the surface casing depth, we respectfully submit this revised program. This well is planned as a directional hole to reach attic gas in the Sterling and Beluga formations. We are planning to drill and drive 13-3/8" casing to a depth of +/- 80' utilizing a local water well drilling contractor prior to the drilling rig arriving on location. We will then nipple up a diverter and drill to the 7" Surface casing point at 1800' TVD utilizing water base mud. Next, we will drill 6" hole to programmed well TD of 3735' TVD, 4106' MD utilizing 6%KCL Water Base Mud. Assuming the well is productive, a string of 3-1/2" casing will be run and cemented at Total Depth. The prospective intervals are partially depleted and are expected to have un-produced attic gas left over from the offset well SRU 212-10 that is down dip to this well. Well completion activities will commence after the drilling rig leaves location. As you know the Swanson River Unit is an older area with marginal economics. In an attempt to efficiently maximize the design and minimize the costs, we have engineered several items within the proposed drilling program which deserve special mention. First, given the number of penetrations in the field and the amount of data available, it is our intent to forego logging of the surface hole. Secondly, the well design is based on utilizing a slim hole tubing-less mono-bore configuration to drill and complete. This mono-bore will be installed as a long string and cemented to near Surface. The completion activities will take place after the rig has been moved out. In addition Unocal would like to utilize the Nabors Rig 129, formerly Kuukpik/H&R rig 9, with its existing 12 inch diverter line to drill the well. The 12" diverter lines are more than adequate to handle any diverter operations that may be come necessary during the drilling of the 8-1/2" surface hole interval. RECEIVED JUN 11 2002 Alaska Oil & Gas Com; vUIII..H,>Þ¡Ui: Anchorage pro Cover Letter SRU 213-10 . 6/11/2002 UNO[AL~ Application for Permit to Drill (Form 10-401) Swanson River Unit, South Kenai Peninsula SRU 213-10 Well. Page 2 swl1..s0N RIVER UNIT SRU 213-10 PTD COVER LETTER The expected date for the drilling rig to arrive on location is approximately June 31, 2002, so your timely consideration for approval is appreciated. If there are any questions, please contact Jim Harrison at 263-7809 or Jim Mosley at 263-7679. JH/jm Enclosure PTD Cover Letter SRU 213-10 ¿;¿VJT, ~ c r Jim Harrison Drilling Manager Unocal Alaska RECEIVED JUN 11 2002 Alaska Oil & Gas Gons. \';OrufíiISS;or Anchorage 2 6/11/2002 UNO[AL~ SW(.r ~SON RIVER UNIT SRU 213-10 Well TABLE OF CONTENTS TABLE OF CONTENTS TABLE OF CONTENTS ...... .... ......... ...... ........ ............... ..... ..... ....... ............. ...... ........... ........... ........ ....... ...... ....3 PERMIT TO DRILL............................................................................................................................. .............4 LOC A TI 0 N PLAT .... ........... ............. .......... ..... ....... ........ ........ ........... ..... ............... ..... ......... ........... ........ .... ....... 5 LOCATION MAPS AND PLATS ..................................................................................................................... 7 C EMEN T PROGRAM.............................................................................................................................. .........8 L OGG IN G PROGRAM......................................................................................................................... ............9 ANTICIPATED FORMA TI ON TO PS ...........................................................................................................11 OFFSET WELL DATA.. ............... ................ ........ ........... ........... .......... ....... ........... .................. ...... ......... ..... ..12 PROPOSED MUD WEIGHTS AND ANTICIPATED FRACTURE GRADIENTS ..................................13 RIG FOOTPRINT ..... ...... ...... ........ ......... .............. .... ............. .......... ..... .... .............. ..... ..... ....... ........ ........ ....... ..14 DRILLING PROCEDURE... ................. ..... ..... .... ........ ......... ...... ........ ..... ........ ...... .............. .......... ....... ....... ....15 DAYS VERSUS DEPTH PLAN ......................................................................................................................16 PROPOSED WELLBORE SCHEMATIC FOR MONOBORE COMPLETION ......................................17 WELLHEAD DIAGRAM.. ......... ............................ .... .... .......... ......... ..... .... ...... .............. .... ... ...... ..... .............. .18 LEAK OFF TES T PROCEDURE. ..................... ............ ........ ................................ .......... ......... ................ ......19 UNOCAL ALASKA WELL WORK HAZARD ANALYSIS SCREENING ..............................................20 BOTTOMH 0 LE PRESSURE INFORMATION ..........................................................................................21 CAS IN G DES I GN ... ............ .......... ......... .......... ......... ............ ...... ......... .... .......... ....... ........................... ........ .... 22 CASIN G PROGRAM SUMMARY........................ ......... .............. ............ ............................... ........ ..... ......... 24 DIVER TER AND BOP SPEC S ....................................... ......... ......... ....... ........ ................................ ....... ........ 25 CHOKE MANIFOLD ................................... ..... .... ..... .... ............ ... ........ ...... ....... .... .... ...... ... ...... ...................... 26 DIVER TER S TACK UP ....... ................. ....... ......... ....... ...... ......... .......................... ...................... ...... ....... ....... 27 BOP SCHEMATIC. .... ....... ...... .... .... ..... ........... .... ..... .................. .... ..... .... ... .... .......... ......... ....... ......... .............. 28 MUD PROGRAM............................................................................................................................. ................29 DIRECTIONAL PROGRAM......................................................................................REC.E.1YIP.35 JUN 11 2002 ,"'r.mm\SSIori Nas'ka Oil & Gas Cons. VV''' " Anctøa{18 TABLE OF CONTENTS sru213-103 6/11/2002 UNO[AL~ swlr~SON RIVER SRU 213-10 PTD COVER Alaska Oil and Gas Conservation Commission 333 West ih Avenue Anchorage, Alaska 99501 Attn: Commissioner Cammy Taylor Re: Application for Permit to Drill (Form 10-401) Swanson River Unit 213-10 SRU 213-10 Dear Commissioner Taylor, Enclosed is an application for permit to drill for e Swanson River 213-10 Well. This well is planned as a directional hole 0 reach attic gas in the Sterling and Beluga formations. We are planning to drill and ive 9-5/8" casing to a depth of +/- 80' utilizing a local water well drilling contractor prior the drilling rig arriving on location. We will then nipple up a diverter and drill to the 7" S rface casing point at 2150' TVD utilizing water base mud. Next, we will drill 6" hole to pr rammed well TD of 5710' TVD, 6080' MD utilizing oil base mud. Assuming the well is ~ oductive, a string of 3-1/2" liner casing will be run and cemented. A tieback tubing strin of 3-1/2" will then be run. The prospective intervals are partially depleted and are expe ed to have un-produced attic gas left over from the offset well SRU 212-10 that is dow dip to this well. Well completion activities will commence after the drilling rig leaves 10 tion. As you know the Swans River Unit is an older area with marginal economics. In an attempt to efficiently m imize the design and minimize the costs, we have engineered several items within t proposed drilling program which deserve special mention. First, given the number of enetrations in the field and the amount of data available, it is our intent to forego log' g of the surface hole. Secondly, the well design is based on utilizing a slim hole mono- ore configuration to drill and complete. This monobore will be installed as a liner and a ti back string. In addition Un cal would like to utilize the Nabors Rig 129, formerly Kuukpik/H&R rig 9, with its existing inch diverter line to drill the well. The 12" diverter lines are more than adequate t handle any diverter operations that may be come necessary during the drilling of the su ce hole. PTO Cover Letter SRU 213-10 5/31/2002 UNO[AL~ SWil~SON RIVER UNIT SRU 213-10 PTD COVER LETTER Application for Permit to Drill (Form 10-401) Swanson River Unit, South Kenai Peninsula SRU 213-10 Well. Page 2 The expected date for the drilling rig to arrive on location is approximately June 31, 2002, so your timely consideration for approval is appreciated. If there are any questions, please contact Jim Harrison at 263-7809 or Jim Mosley at 263-7679. ~.~ FoP.. Sincerely, J ~f\i1 ft l} ltQ; \ ~ O,..J Jim Harrison Drilling Manager Unocal Alaska t: JH/jm Enclos re PTD Cover Letter SRU 213-10 2 5/31/2002 1 a. Type of work Drill X Redrill Re-entry Deepen 2. Name of Operator Union Oil of California (dba Unocal) 3. Address P. O. Box 196247 Anchorage. Ak 99519-6247 4. Location of well at surface 1725' FNL and 628' FWL Sec. 10 T8N, R9W, SM AK At top of productive interval Sterling 2818' FNL & 590' FWL @ 2434' TVO Sterling At total depth 3103' FNL & 552' FWL @ TO of 5709' TVO 12. Distance to nearest 13. Distance to nearest well property line 747' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 1b. Type of well Exploratory Stratigraphic Test Development Oi.y' Service Development Gas X Single Zone Multiple Zone / 5. Datum Elevation (DF or KB) 10. Fiel and Pool 293' RKB Swa on River Field 6. Property Designation Sw nson River Unit A-028405 ( / 7. Unit or Property Name Swanson River Unit 8. Well Number 213-1 0 9. Approximate spud date 6/31/02 14. Number of acres in 1. Type Bond (see 20MC25.025) AK Statewide Oil & Gas Bond Number U 62-9269 Amount 25' at SHL (SRU #212-10) $200,000 15 Proposed depth (MD and TVD) 6080' MO 5710' TVO 16. To be completed for deviated wells Kickoff depth 500 feet Maximum hole angle 38° 18. Casing program size Specifications Hole Casin Weight Grade Coupling g 12.25 9-5/8" 8.5" 6" Length 17. Anticipated essure (see 20 AAC 25.035 (e)(2) Maximum Surf e 1634 psig. At total depth (TVD) 5710' Settin epth Top Bottom TV MD TVD Quantity of cement MD Tbg 7" 3.5" 3.5" 47 26 9.2 9.2 L-80 Weld L-80 Buttress L-80 IMP Butt L-80 IMP Butt 80' 2450' 6080' 2150 80 2450' 6080' 2150' 80 2150' 5710' 1935' Pre Set W / Water Well Rig 406 cuft Class G blend 572 cuft Class G blend Tieback String not Cemented '" 19. To be completed for Redrill, Re-entry and Deepen Op .~'( .,,~ ~ 0 AL 21. I hereby certify that the foregoing i rue and correct to the best of my knowledge Signed Q,.~ ,~ A1 j1'JA6aJTitle: Drilling Manager OVTn Commission Use Only Permit Number. /Q API Number . Approval date 202 -//U 50-/3-:S- ~~/ÇCt::J ~'") Conditions of approval Sa les requ~~ Yes No Mud log requireHes@ Hydrogen Sulfide measur Yes ~~ Dirac' urvey required ~ No Required working press e for BOPE 'M 3M 5M 10M 15M Other: by order of Approved by Commissioner the commission Date Form 10-401 Rev. AFE#134703 Date 3 M/~y t>?- See cover letter for other requirements Submit in triplicate ~( l Form 401 AOGCC Permit To Drill SRU 213-10 4 commisSHgh 1/2002 "".,-'... - UøøC~L. Sf\\) 213-'\0 ~ \ - aJPF",cJí?- \..oc",1\QN 2'" ~\uro. Co~ j~~ < fi { PRopostD SRÜ 2\3-\0 WELL Þ..s? z.ONE 4 N~027 GR\O N: 24858' 9.433 GR\O E: 348545.820 " LA 1\ T\J OE: 60'48' 0,\.9448 t'!, LONGIT\JDt: \50'5052.6444 V4 '725' f'NL 628' f''HL SEC1\ON ,0 18N, R9'H. S.M" ~K ELt'i. 293.5 n. NA\{)88 l } ¡ ;> 1 il 1!! ¡:;: s:>- ;f ~ \- ~ ç Ii~ ~ gl:..1!:. 9 PROJ£.Ci p.O. 60')(.466 501-00"'''''''' p..v:. 9 ~... ...\," ^\ ôfê!J '2\?1 \Ø ~~ÃCE \-OCA 1\OÑ ~ conf>\,¡\ting 6rOUp LOC"-"Q\'I "" c L.A N E. i ef> t ing Sulat'l&Ot'l f<\ver Ùt'I\~, Ala &~ \1'11 u L-~ 'OR"-"'" BY \°/0. 1E \ SC/o.LE \°/0.1< ~ \"'ISM \ ?>f'2Ï/Ø'\ 1".bØ' \ -rEI- 907.263.42' 6 ,,"'')(. 907.263.3265 .' r' r I .lJ..J < "'C -......J R£.'VISION PROJ£.C1" jO'NG. Ø2 ?JØ2?J S\1t.£.i NO. of' \ 345000 0000 5207'( ì'0 c..þ CD CD is)-- is) - is) -- I .--------- Unit BOUndary~ -- .- ISRU 213-10 Proposed 5 I N I c..þ ~- +9----- is) is) is) . rface~ 28'-- + llß '. I I I A-028077 ~---. I I I +- 251.J .. Ñ 0 ('l') N ëo CX) LO N A-028405 - ,--- 5RU 34-10 q+ I I 5RU 211-15 I I D FL4 I I I I N I 5RU 242-16 I 5RU 12-15 ...+:::> CX) *---- ~ is) I I is) is) is) 5RU 21-15 Kit SRU 3Y-15SRU ~ 5RU 32R-15 ------- Scale ^ UNOCALO 0 500 1000 1500 2000 2500 3000 Feet \ COOK_INLET Northern Swanson River Unit Scale: Units. 1912ØØØ Interpreter: EPC FEET Dote: 24-Moy-2ØØ2 UNOCALÍcÞ Swanson River Unit ( SRU 213-10 Well LOCATION MAPS AND PLATS LOCATION MAPS AND PLATS PROPOSED LOCATION PLAT THE PROPOSED UNOCAL WELL SRU 213-10 WILL BE LOCATED ON THE SAME PAD AS THE EXISTING SRU 212-10 WELL. THE PAD LOCATION AND LAYOUT OF THE EXISTING ROAD ARE SHOWN ABOVE IN SECTION 10. DEAD END PROPOSED 213-10 SURF ACE LOCATION 242-16 *--- .---~ / \ / \ -----.......... / \ ----- - .-/ LOCATION MAPS AND PLATS SRU 213-10 7 5/31/2002 UNOCALW Swanson RivE( Jnit SRU 213-10 Well CEMENT PROGRAM CEMENT PROGRAM 9-5/8" Casinq (Driven to 80') Note: This string is only for structural support of the wellhead, and diverter stack. 7" Casinq (8-1/2" Hole to 2450' MD): Cement volume based on open hole volume plus 300/0, shoe joints, and annulus. The job will consist of a lead and tail and cement will be brought to surface. The estimated volume is as follows: Lead 1950' x 0.1267 cuftlft (8-1/2" x 7") X 1.3 = 321 cuft = 162 SXS (1.98 Yield) 500' x 0.1267 cuftlft (8-1/2" x 7") X 1.3 = 82 cuft = 71 sxs (1.16 Yield) 80' shoe joint x 0.0364 cuftlft = 3 cuft = 2.5 sxs (1.16 Yield) Tail TOTAL: 321 + 82 + 3 = 406 cuft or 235 SXS TOTAL (1.16 yield lead and 1.98 Tail) 3-1/2" Casing (6" Hole to 6080' MD) Cement volume based on open hole volume plus 100/0, shoe joints and annulus. The job will consist of a tail cement with returns brought 300 feet above the top of the liner. The estimated total volume is as follows: Tail: (6080-2150)' X 0.1295 cuftlft (6" x 3-1/2") X 1.1 = 560 cuft = 482 sxs (1.16 yield) 80' shoe joint X .0087 cuftlft = .7 cuft = 0.6 sxs (1.16 yield) 300 feet excess TOL = 300' X .0371cuft/ft (7") = 11.14 cuft = 9.6 sxs (1.16 yield) TOTAL: 560 + .6 + 9.6 = 572 cu ft = 492 sxs CEMENT PROGRAM SRU 213-10 8 5/31/2002 UNO[AL~ swanso~ River Unit SRU 213-10 Well LOGGING PROGRAM LOGGING PROGRAM The following constitutes the proposed geological and evaluation logging program for the subject well. All tool suites should be available on location for all anticipated logging runs; final determination of which tools will be run will be based on hole conditions at the time of logging, and geologic results. All "Anticipated Logging Dates" are based on pre-spud estimates of drilling duration and should not be considered final. Unocal Drilling Engineer will notify Schlumberger 8-10 days in advance of any logging run (with updates as needed). 8-1/2" SURFACE HOLE FROM 2450' TO SHOE OF 9-5/8" @ +80' CASED HOLE LOGS ANTICIPATED LOGGING DATE: 10 July REQUIRED LOG Gamma Ray Log 6" PRODUCTION HOLE FROM +6080' TO SHOE OF 7" @ +2450' OPEN HOLE LOGS ANTICIPATED LOGGING DATE: 10 July PLANNED LOG MWD With DIRlGR to TO PLANNED LOG Platform Express - PEX AIT/DSI/RHOB/NPHI/GRlSP ,/' CASED HOLE LOGS PLANNED LOG OPTIONAL LOG FROM PBTD TO TOP OF 3-1/2" CEMENT GRlCCL (Will be run thru tubing rigless) USIT/CBT/GRlCCL (Dependent on Cement Job) CASED HOLE PERFORATING (INTERVALS TBD) PLANNED TOOL 2-1/2" POWER JET GUNS OTHER GEOLOGIC EVALUATION MUD LOGGING Mud logging will be conducted from the shoe of the 9-5/8" @ 80' until total depth. GAS DETECTION Gas detectors will be functional and running prior to spud. CORING No core is planned for this well. NOTES: All logs are to record UNION OIL COMPANY OF CALIFORNIA as the Company or Operator on the log header. ELEVATION LOGGING PROGRAM SRU 213-10 9 5/31/2002 swansoJ t{iver Unit SRU 213-10 Well LOGGING PROGRAM The rig site Ground Elevation is 293.5' AS MEASURED BY McLANE SURVEYING ON PROPOSED PLAT. The As built Plat will be furnished after the Pad is releveled and the wellhead is installed. The actual Rig KB will be measured after MIRU on location. All contractor Field Service Representatives will be notified of RKB in writing by Unocal, and will be responsible for relaying the correct RKB to the engineer(s) on location. UNO[AL~ LOGGING PROGRAM SRU 213-10 10 5/31/2002 UNOCALt., SWANSON RIV( 1 UNIT SRU 213-10 Well OFFSET MUD WEIGHTS ANTICIPATED FORMATION TOPS Union Oil Company of California Proposed SRU 213-10 Well Elev 293.5 Geologic Tops and Correlations RKB 310 SRU 212-10 Proposed SRU 213-10 Marker MD TVD MD TVD TVDSS Difference Base Glacial 515 515 515 515 -205 0 L. Sterling 2600 2600 2810 2460 -2150 140 A9 2600 2600 2810 2460 -2150 140 A10 2700 2700 2915 2560 -2250 140 B3 3080 3070 3333 2935 -2625 135 B5 3255 3240 3475 3105 -2795 135 B6 3438 3415 3662 3285 -2975 130 Beluga 3550 3522 3770 3392 -3082 130 Total Depth 6082 5710 5400 N/a OFFSET MUD WEIGHTS SRU 213-10 11 5/31/2002 UNO[AL~ SWANSON RIV( 1 UNIT SRU 213-10 Well OFFSET MUD WEIGHTS PROPOSED MUD WEIGHTS AND ANTICIPATED FRACTURE GRADIENTS -....,.---..,..--.-.----- ---_.__.._--_._,-_._~_._------- UNOCAL8 0 -;a;- - ~ 9625" \ \ . 1000 ~~ ~\ \ 3.5" / 2000 T' -- t 3000 - t \ 4000 i j 5000 J:- --=- -3.5" 6000 7000 8000 9000 10000 8 9 10 OFFSET MUD WEIGHTS SRU 213-10 SWANSON RIVER UNIT OFFSET MUD WEIGHTS, PROPOSED SRU 213-10 MUD WEIGHT, ANTICIPATED FRACTURE GRADIENTS, AND CASING PLAN I I I I -FRACTURE GRADIENT ~ -Production liner ....... Production Tubing -Structural Casing """'Surface Casing - ~ 1'1 Formation Tops -PROPOSED MUD WEIGHT SRU 213-10 -' SRU242-16 - - SRU 212-10 - -SRU 211-15 "'{o..n, T!'!J! k'fB;og III 2. ; ~~. p of 83 P of 85 ß gf ~~Iu£a Ii 5710 P tOJECTED TOTAL DEPTH 11 12 13 14 15 Mud Weight (PPG) 16 17 18 19 20 12 5/31/2002 UNOCAL~ Swanso~ ;ver Unit SRU 213-10 RIG FOOTPRINT RIG FOOTPRINT 500 BBL Tiger Tank (Slops) ................. ............. ............ ... . . . . : Choke House : . D . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . : ~ : : (ij : : ~ : : cu : : 0 : Top DriVec~:~:xs Tank -11- 0 $ I . ¡ ~ I ¡ - Sub i I Diamond Tanks 0 ~ (j) ¡ 0: : 75 HpVacUnit ~ : - : Cuttings Tank ~ ~D ~ - ~ ~ i ~ 500 BBL Tiger Tank ) - ~- ¡.!!! ~ ~ ~ ¡ (- - ~ ~ ~ ~ -~ :ä: ~ ~; ; ~ ~ - I Boiler I ~ D 0 [!] ~ I Lockers I Shop I ~ \. - - L..y-J '--y--l :..........................................; ( Storace Conexes ~ t Charqe and Transfer Pumps 130 BBL Trailer-Mounted ~ Iso-Tanks ~~ "---J "---J -- Bermed Area - Pre-Mix CJ MI Shack XXX BBL Vertical Storage Tanks (Replaced wI Tiger Tank on Griner #1) Rig Footprint SRU 213-10 13 5/31/2002 UNOCAL~ Swanso( 1iver Unit SRU 213-10 DRilliNG PROCEDURE DRilliNG PROCEDURE Unocal Alaska Business Unit SRU 213-10 GRASS ROOTS GAS WELL UNOCALe Prepared by: JIM Date: 04/19/02 Estimate for Grass Roots DRILL AND COMPLETE TIME PLAN No. Preliminary Procedure Time CUM CUM Depth Depth Estimate Time Time In Out (Hours) (Hours) (Days) (Feet) (Feet) 1 Rebuild location pad, Relevel gravel. 0.0 0 0.0 2 PreDrill and set 2 jts of 9-5/8" and Install Cellar 0.0 0 0.0 3 Preinstall Diverter Bag 12 12 0.5 0 0 4 MI & RU 30 42 1.8 0 0 5 NU DIVERTER LINES & FUNCTION TEST 12 54 2.3 0 0 6 Fill Pits with spud mud and prepare to spud 12 66 2.8 0 0 7 Directionally Drill 8-1/2" hole to 2150' 36 102 4.3 0 2150 8 Make Wiper Trip & POOH 14 116 4.8 2150 2150 9 RU Csg Crew & Run 7"Surface casing to 2150' 10 126 5.3 2150 2150 10 Circ & Cmt Surf Csg. Displace with OBM 12 138 5.8 2150 2150 ND diverter, NU Csg Head & BOP's. Test BOPE to 250/3000 psi. Test Casing to 2500 psi, Drill out, and 11 Run LOT 16 154 6.4 2150 2150 12 Directionally Drill 6" hole to 6100' . (assume 50'/hr) 80 234 9.8 2150 6100 13 Make Wiper Trip & POOH LD DP for Logs 18 252 10.5 6100 6100 14 RU, Run Logs, RD Schlumberger 16 268 11.2 6100 6100 15 RU & Run Production Liner Casing, RIH on DP 12 280 11.7 6100 6100 16 Circ & Cmt Production Liner Casing 8 288 12.0 6100 6100 17 Test Liner Top Packer to 2500 psi. POOH LD DP 14 302 12.6 6100 6100 18 PU Tieback Stinger, Tubing & RIH. 10 312 13.0 6100 6100 Sting into tieback, test same, space out and land 19 Tubing hanger 6 318 13.3 6100 6100 20 Test Tieback to 2500 psi. LD Landing Jt & Set BPV 4 322 13.4 6100 6100 21 ND BOP & NU TREE 12 334 13.9 6100 6100 22 Test Tree to 3000 psi & Pull TWC. Secure Tree. 6 340 14.2 6100 6100 23 Clean rig and Release Same. 24 364 15.2 6100 6100 Drilling Procedure SRU 213-10 14 5/31/2002 UNOCAL~ SWANSON RI{ .R UNIT SRU 213-10 Well DAYS VERSUS DEPTH PLAN DAYS VERSUS DEPTH PLAN UNOCAL8 Swanson River Unit SRU 213-10 Kenai Peninsula, Alaska Depth vs. Time Summary 1,000.0 2,000,000 - Proposed SRU 213-10 - SRU 223-28, 1997 - ACTUAL TIME VS COST AFE PLANNED TIME VS COST 1,750,000 ¿ 3,000.0 \ \ 1,250,000 Depth (feet) 4,000.0 \ \ 1,000,000 1,500,000 2,000.0 5,000.0 \ 750,000 L 6,000.0 \ 500,000 7,000.0 250,000 8,000.0 0 5 10 15 20 25 Time (Days) Wellbore Schematic SRU 213-10 15 5/31/2002 UNOCAL~ Swar( )n River unit SRU 213-10 Well PROPOSED WELLBORE SCHEMATICS PROPOSED WELLBORE SCHEMATIC FOR MONO BORE COMPLETION RKB to TBG Head = L -- 2 ?- Ç(~ 3 4 L ~ TD = 6080' MD, 5710' TVD Directional Well Wellbore Schematic SRU 213-10 ~ SIZE WT 9-5/8" 47 7" 26 CASING AND TUBING DETAIL GRADE CONN TOP BOTTOM L-80 Weld Surf 80' Pre Set L-80 Butt Surf 2450 Md' 3-1/2" 9.2 Liner 2150' 6080 Md' L-80 Butt Tubing: 3-1/2" 9.2 L-80 Butt Surf with 3/8" ss methanol injection line Surf 2150 Md' 2140 Md' JEWELRY DETAIL NO. Depth Item 1 Surf 3-1/2" Tbg hgr w/Cameron "H" BPV profile 2 2140 Macco 3-1/2" SMO-l Chern Inj Mdrl w/l000 psi chern inj valve 3 4 2150 Baker Liner Tieback seals 2150 Baker liner hanger, Packer, and PBR PROPOSED PERFORATION DATA TOP BTM ZONE/FORMATION SPF COMMENTS -2125 -2135 A9 Sterling Sand 6 Confirm with log -2250 -2260 A10 Sterling Sand 6 Confirm with log -2635 -2645 B3 Sterling Sand 6 Confirm with log -2810 -2820 B5 Sterling Sand 6 Confirm with log -3010 -3020 B6 Sterling Sand 6 Confirm with log 16 5/31/2002 UNO[AL~ 3-1/8" 5,000 Tree Run 7 -1/16" 5,000 Swanson ~.er Unit SRU 213-10 Well WELLHEAD DIAGRAM WELLHEAD DIAGRAM Unocal ~ Swanson River rll, 213-10 (I r '@ ~~~o 0 g-. 0 0 0 . ~ 0 L '(I . r , I r , , r~ ~J~? ~) - '3 ~ ...J r~ þ ~~ D) -{ L7 11 11" 3,000 9-5/8" Casing 3-1/2 Tubing Wellhead Diagram SRU 213-10 7" Casing 17 3-1/8" 5,000 Wing 2-1/16" 5,000 Outlets 5/31/2002 UNO[AL~ Swanson ~ 'er Unit SRU 213-10 Well LEAK OFF TEST PROCEDURE LEAK OFF TEST PROCEDURE 1. Clean out the rathole below the shoe, and drill 20' of new hole. Circulate and condition mud. 2. Pull the drill string into the shoe. Rig up to observe annulus pressures. 3. Close the pipe rams and pump down the drill pipe at a slow rate (1/4 - 1/3 BPM) if exposed formation is permeable. A non-permeable formation should be step tested to a predetermined pressure. 4. Measure the volume pumped and plot annulus pressure-vs-cumulative volume pumped. Compare annulus pressure to drill pipe pressure and confirm both are the same. Record and plot pressure versus volume pumped. The pumps should be shut down immediately upon indication of leak-off. Record the initial, shut down pressure and the pressure after 1, 2, and 3 minutes. 5. Release pressure and record the volume of fluid recovered in the trip tank. The point "8" shown in the attached graph at which the plot of drillpipe pressure stops increasing equally as the volume is pumped is called the P.I.T. limit, Leak Off, or pressure integrity test limit. The leak-off pressure is calculated as follows: Leak-off (EMW) = Mud weight in hole + P.I.T. (PSI) (0.052) X (shoe depth in TVD ft.) This equivalent mud weight should be made known to all drilling personnel to ensure it is not exceeded under any circumstances. See the drilling procedure for guidelines on expected LOT's or pressure integrity test limits for each casing shoe. TYPICAL PIT PLOT (psi) C ~~ SURFACE PRESS. - VOLUME PUMPED (88 LS) SHUT -IN-TIME (MIN) NOTES: Point ~~A" will have some variance until the system begins to pressure up. Point "B" is the leak off and is abbreviated LOT. Point "C" is known as the injection pressure and is usually dependent on rate. Point "D" is known as the fracture closure pressure and may not stabilize if permeable formations are exposed. LOT Procedure SRU 213-10 18 5/31/2002 Swar( )n River Unit SRU 213-10 Well HAZARD ANALYSIS UNOCAL ALASKA WELL WORK HAZARD ANALYSIS SCREENING UNOCAL~ Hazard Analysis for APD 20AAC 25.005 (c) 4 Abnormal Pressure During the drilling of these shallow intervals, no abnormal pressures were encountered, however, during the life of any old field, there is a slight possibility that cement jobs from older wells can allow some fluids to migrate up hole. There have not been any cases of this reported during the drilling of newer wells in this field, but the potential does exist. Prior to all trips a swab in potential test will be conducted and the hole will be kept full at all times during the drilling of the shallow intervals. A trip tank will be used to monitor for correct fillups. Maximum pore pressure anticipated is 2,550 psi at 5,710' TVD total depth based on 8.6 ppg EMW. Offset wells were drilled with mud weights ranging from 9.5 to 12.5 ppg. The closest offset well is the SRU 212-10. The SRU 212-10 is located on the same pad. The New well the 213-10 is to be a replacement for the watered out 212-10. The new well, 213-10 is to be drilled up dip to allow for producing attic gas. Lost Circulation Oil Based Mud and subsequently KCL completion brine is planned for the drilling fluid for this well. If excessive lost returns are encountered a Calcium Carbonate and LCM materials pill will be used to control losses. No Losses were recorded in the drilling of the offset well. In the event of lost circulation, adequate supplies of lost circulation material and water will be kept on location. Crews will be briefed on the strategy for dealing with losses should they occur. Some minor seepage losses should be encountered in the now depleted Sterling and Beluga sands. Shallow Gas The presence of shallow gas is well documented throughout the Kenai Peninsula and is associated with coal bed methane accumulations. The minimum amount of gas seen on the offset wells in the surface interval indicates only minimum methane associated with the coals. The Conductor pipe will be preset with a water well rig and a diverter will be nippled up on top of the 9-5/8" to drill the 8-1/2" surface hole. Hole fill on trips will be continuous until surface casing is set. Proximity The new well will be drilled from a surface location about 25 feet from an existing shut in well. A spider plot, directional plan, and directional tools will be used to drill both the 8-1/2" and 6" hole sections. The well will be considered a directional well from spud. The offset well kicked off at 2400 feet and was vertical until that point. The proposed well will kick off at 500 feet and will be intentionally deviated to the South some 1500 feet above the offset well kick off point. The well plan addresses any possible interference or proximity concerns. H2S H2S production has not been identified in any of the Offset well information files available to Unocal. Waste Disposal Mud will be disposed of in the SCU 243-4 Mud Disposal Well. Cuttings will be placed in the Swanson River Solid Waste Cell. HAZARD ANALYSIS SRU 213-10 19 5/31/2002 UNOCAL~ Swanson~: er Unit SRU 213-10 Well CASING DESIGN INFORMATION Bottomhole Pressure Information The following presents data used for calculation of anticip~ted surface pressures (ASP) during drilling of the Swanson River SRU 213-10 well. The pore pressure gradient was estimated from the following information: BHP Well Q.§i SRU 212-10 1100 SRU 212-10 900 Depth TVD 2435 3320 EMW, PPQ 8.65 5.2 Comment Not depleted at this location Partially Depleted Beluga intervals The fracture gradient for the surface casing point was conservatively estimated at .806 psi/ft or 15.5 ppg. Casing Pore Casing Setting Fracture Pressure Mud Pore ASP Size Depth Gradient Gradient Weight Pressure Drilling !lnJ (TVD ft) (Ibs/gal) (Ibs/qal) (Ib/gal) (Q§i) (Q§il 7" 2,150' 15.5 8.65 9.5 967 1,634 based on FG 3.5" 5,710' 15.5 8.65 9.5 2,568 1,997 based on PP @ TD Procedure for Calculatinq Anticipated Surface Pressures While Drilling ASP is determined as the lesser of 1) surface pressure at breakdown of the formation at the casing seat plus 1 ppg safety factor with casing evacuated with gas. or 2) formation pore pressure at the next casing point less methane gradient to surface as follows: 6" Production Hole Section for 3-1/2" Liner from 2.150' TVD to 5.710' TVD 1) ASP 2) ASP = ((FG+1 )x.052xD) - (MWx.052xD) = (16.5x.052x2150) - (0.1 Ox.2150) = 1,634 psi OR = PPx..052xTVD'- (0.1gas gradient xTVD) = 8.65 x.052x571 0 - (0.1 Ox571 0) = 2,568 - 571 = 1,997 psi NOTE: See Kick Tolerance Sheets on following page for identification of swab kick tolerances for the 7" surface casing. CASING DESIGN INFORMATION SRU 213-10 20 5/31/2002 UNOCAL~ Swanson F( er Unit SRU 213-10 Well CASING DESIGN INFORMATION CASING DESIGN Suñace Casing: 7". 26 #. L-80. Buttress Worst case for burst would be in the event of a gas kick while drilling at TO (5,710'). If the Maximum Anticipated Surface pressure were encountered, the SI pressure against the 7" surface casing would be 1634 psi. This is based on a 15.5 ppg fracture gradient plus 1 ppg safety factor with the casing full of gas. Burst load = 1634 psi. 7", 26#, L-80 rated @ 7240 psi for burst Safety Factor = 7240/1634 = 4.43 OK Worst case for collapse is if returns are lost while drilling below the 7" Surface Shoe Collapse = (10 x.052x 2,150') = 1118 psi for full evacuation 26#, L-80 rated @ 5,410 psi collapse Safety Factor = 5410/1118=4.83 OK Worst case for tension is if the shoe of the pipe were packed off and the resultant end area buoyancy did not apply. This is equivalent to using air weight. A 100,000 pound overpull is also assumed in the calculation. . Tension = 2450' X 26# = 63,700 Max pull = 63.7+100 = 163.7 K Rated = 604K for body yield Safety Factor = 604/163.7=3.68 OK Production Liner Casing: 3.5". 9.2#. L-80. Buttress Tubing Worst case for burst would be in the event of a gas kick while completing at TO (5710'). If the Maximum Anticipated Surface pressure were encountered, the SI pressure against the 3.5" production casing would be 1,997 psi. NOTE: Since the completion will be done in a monobore style, the calculations shown are for the 3-1/2" at the surface instead of at the liner top. Burst load = 1,997 psi. 3.5",9.2#, L-80 is rated @ 10160 psi for burst Safety Factor = 10160/1997 = 5.08 OK Worst case for collapse is if plugged perforations occur while flowing the well. Collapse = (10 x.052x571 0') 9.2#, L-80 rated @ 10,530 psi collapse = 2,969 psi for full evacuation Safety Factor = 10530/2969=3.54 OK Tension is checked in two places, the top of the liner after running and at the surface after running the tieback. Tension at top of liner = (6080'-2150')(9.2#) + 50,000 Overpull allowance = 86156 3-1/2" 9.2# L-80 is rated = 207K for body yield. Safety Factor = 207/86=2.40 OK Tension at the top of the tieback = (2150')(9.2) + 50,000 Overpull = 69780 3-1/2",9.2#, L-80 is rated = 207K for body yield. Safety Factor = 207/70 = 2.95 OK CASING DESIGN INFORMATION SRU 213-10 21 5/31/2002 UNO[AL~ Swanson~. 'er Unit SRU 213-1Ò Well CASING DESIGN INFORMATION Maximum SWAB Kick Tolerance Calculations Well: CSG Shoe: SRU 213-10 7" General Information 1 7" Casing Shoe (ftom RT) 2 Fracture pressure at the 7" Shoe 3 Proposed TD of the 6" Casing Hole (TVD) 4 Maximum anticipated pore pressure 5 Mud Weight 6 Gas Gradient 7 Average open hole size 8 Drillpipe OD 9 Capacity of open hole by drillpipe 10 Height of gas colum in wellbore when top of gas is at the shoe Variables 2,150 Feet (TVD) Dshoe 1,720.00 psi FP 5,710 Feet (TVD) DTD 2,568.00 psi Pmax@TD See table PPG MW 0.10 psi/FT GG 6.00 Inches ODOH 3.50 Inches ODDP 0.0231 BBL/FT CAP HT Feet (TVD) Ht Gas bubble height in wellbore (Ht) calculation with gas bubble top at 7" shoe. Pshoe + Pgas bubble + Proud = Pmax@ TO Pshoe + GG*Ht + .052*MW*(DTD-Dshoe-Ht) = Pmax@TO Gas Volume (GV) calcualtion at 9-5/8" shoe. GV = CAP*Ht Kick Tolerance calculation: Gas volume in wellbore at TD. PI VI = P2V2. Assume constant temperature. Kick Tolerance * Pmax@TD = GV * FP Mud Weight (PPG) Gas Bubble Height Gas Volume @ Shoe (Feet) (BBLS) Kick Tolerance (BBLS) 7.0 7.2 7.4 7.6 7.8 8.0 8.2 8.4 8.6 8.8 9.0 9.2 9.4 9.6 9.8 10.0 10.2 10.4 10.6 10.8 11.0 1,696 1,767 1,832 1,893 1,950 2,003 2,053 2,099 2,143 2,184 2,223 2,260 2,295 2,328 2,359 2,389 2,417 2,444 2,470 2,494 2,518 39 41 42 44 45 46 47 48 49 50 51 52 53 54 54 55 56 56 57 58 58 26 27 28 29 30 31 32 32 33 34 34 35 35 36 36 37 37 38 38 39 39 CASING DESIGN INFORMATION SRU 213-10 22 5/31/2002 UNOCALW Swanson~. er Unit SRU 213-10 Well CASING DESIGN INFORMATION CASING PROGRAM SUMMARY UNOCAL8 Swanson River Unit SRU 312-10 Well Casing Program Casing API Values Casing Casing Hole Set Size From Set to Weight Casing Conn Size Burst Collapse Tension (in) (MD) (MD) (ppf) Grade Type (in) (psi) (psi) (K Ibs) 7 0 2450 26 L-80 Butt 8.5 7240 5410 604 3.5 1950 6080 9.2 L-80 Butt 6 10160 10530 207 Casing Design Casing Grade L-80 L-80 Setting Depth (TVD) 2150 5710 Frac Gradient at shoe (ppg) 15.5 15.5 Formation Pressure at shoe (ppg) 1006 2672 Design Factors Casing Size (in) 7 3.5 Casing Weight (ppf) 26 9.2 MASP (psi) Burst Collapse Tension 1634 4.430845 4.838998 3.874278 1997 5.087631 2.045455 1.357092 Casing Design Discussion Maximum loads are used to calculate the safety factors. In the case of burst, the hole is evacuated with gas. In the case of Collapse, the inside of the casing is assumed completely empty. The tension safety factors are based on air weights of each string with an added 100,000 # overpull. The tubing string tension design is based on a 50,000 # overpull. CASING DESIGN INFORMATION SRU 213-10 23 5/31/2002 UNOCALt, Swanson Rivel..,nitt SRU 213-10 Well DIVERTER AND BOP SPECS UNOCAL8 DIVERTER AND BOP SPECS SWANSON RIVER UNIT SRU 213-10 Diverter and BOPE Diverter The diverter will consist of a 11", 5,OOOpsi Annular Preventer and a 12" 0.0. non bifurcated vent line. The vent line will be full opening and integrated with the annular in the fail safe design as stipulated in 20AAC 25.035. The Vent Line will be a minimum of 100' away from any source of ignition. Blow Out Preventers The blowout preventor will consist of a 11", 5000 psi Annular, a 11", 5000 psi double ram preventor with pipe rams on top and blind rams on bottom, a 11", 5000 psi mud cross w/ 3-1/8",5000 psi flanged outlets, and a 11", 5000 psi single ram preventor with pipe rams. Choke Manifold The choke manifold will be a 3-1/8", 5000 psi manifold. It will include 1 ea. remote controlled hydraulically actuated choke and one hand adjustable choke. Casing Test MASP Test BOPS Low/High Casing String Size (in) (psi) (psi) Size and Rating (psi) Conductor 9-5/8" N/A N/A 11", 5M Annular Function Surface 7" 1634 2000 11", 5M Annular 250/3000 Production 3-1/2" 1997 2500 11", 5M Annular 250/3000 Liner 11", 5M Pipe Ram 250/3000 11", 5M Pipe Ram 250/3000 11", 5M Blind Ram 250/3000 Production 3-1/2" 1997 2500 11", 5M Annular 250/3000 Tieback 11", 5M Pipe Ram 250/3000 11", 5M Pipe Ram 250/3000 11", 5M Blind ram 250/3000 DIVERTER AND BOP SPECS SRU 213-10 24 5/31/2002 ( UNOCAL. Swanson Rivet, -,nitt SRU 213-10 Well DIVERTER AND BOP SPECS CHOKE MANIFOLD DIVERTER AND BOP SPECS SRU 213-10 25 5/31/2002 UNO[AL~ Swa~ )n River Unit SRU 213-10 Well DIVERTER STACK UP F ill Line II",5K, Annular 11", 5M X 11",5M Diverter Spool with XO Outlets to 12" Diverter line UNOCALII Diverter Hookup Well SRU 213-10 Swanson River Unit Kenai Penninsula Drawn by: J.I.M. Date: 05-15-02 DIVERTER AND BOP SPECS SRU 213-10 . . 70.75" - 17" . . 26 ----- ----- I r' I \ G 1 I -I - I ~ I 12", Hydraulic Operated Knife Valve I I I - 60" 36" ~ - - ... 53.75" 11", 5M x 9-5/8, 3M Crossover Spool - I, 9-5/8" 3M Starting Head 8.5' Welded .~ 9-5/8" r----., 5/31/2002 Flow Line 12", Diverter I Line H = 2.5'@ CL I UNO[AL~ Swar( In River Unit SRU 213-10 Well BOP SCHEMATIC ~ ............... - - II", 5M, Shaffer Annular 41-1/2" ~ ~ I .. I I I .. II", 5M, Shaffer Double Gate ~ II II ~ I 33" ~ II II ~ 10.83' I' I w t 11", 5M, Mud Cross 24" .. .. II", 5M, Shaffer Single Gate ~ II II ~ 19-1/2" ~ I I I I 11", 5M, Spacer Spool 24" " ... 12" ~ 1 11" 5M 15.75" x 11" 5M + I I Cameron I I Riser 70.75" t -~ 2=- 11" 5M 26" x 11" 3M .- - - - ~ Cameron 'II' I I Tbg Spool I. 9-5/8" 3M UNOCALI¡ I I Starting Head 17" I I I I I - J- - - - _1- BOP Hookup Rev + I I I I . I I 8.5' I .~ SRU 213-10 9-5/8" Welded Swanson River Unit U Kenai Penninsula 7" Drawn by: J.I.M. DIVERTER AND BOP SPECS SRU 213-10 27 5/31/2002 UNO[AL~ Swar( n River Unit SRU 213-10 Well MUD PROGRAM M-I. L.L.c. 721 West First Avenue Anchorage, Alaska 99501 (907) 274-5564 (907) 279-6729 Fax ~ MUD PROGRAM Interval Summary UNOCAL SRU 213 -10 80' - 2450' MD 7" Casing 81/2" Hole J Drilling Fluid System Gel- Gelex J Key Products M-I Gel I M-I Bar I Soda Ash I Caustic Soda I Gelex I DO I SAPPI J Nut Plug ~ Solids Control Flow Line Cleaners I Centrifuge I Desander I Desilter ~ ,.. p~tential p~oblems Hole Clearung I Gravell Gas K1C~~~st'~=Tn~:::mg. j Interval Drilling Fluid Properties 1 à Depth Mud Plastic Yield Gel API Total Interval Weight Viscosity Point Strength Fluid loss DrilledSOI-1 ids (ft) (ppg) (cp.) (I b.l1 OOft2) (lb.l100ft2) (ml/30min) (%) 80 8.8-9.2 5-10 20 - 30 N/C < 20 3 or less ~ 1000 9.0-9.5 7-12 15 - 25 12 12 -15 5 or less 1 2450 9.0-9.5 10-15 15 - 25 12 < 10 5 or less '1'1' "III. " . Build spud system with pre. hydrated bentonite and Gelex in ftesh water. . Utilize all solids control equipment. . Raise viscosity if gravel sections are encountered. . Pump sweeps if required. . Add DD (drilling detergent) ,Nut Plug, and SAPP for possible bit bafug. . Potential Problems: Running gravel, bit balling, shallow gas, and swelling clay . Lower fluid loss to below 10 cc's API byend of interval with Polypac additions. . Estimated volume usage- 900 barrels. Note: Mud Weights of 10.0 ppg may be required beause of potential shallow gas. Mud Program SRU 213-10 28 5/31/2002 UNOCAL~ Swan( n River Unit SRU 213-10 Well MUD PROGRAM M-I. L.L.c. 721 West First Avenue Anchorage, Alaska 99501 (907) 274-5564 (907) 279-6729 Fax ~ Interval Summary UNOCAL SRU 213 -10 2450' - 6080' MD 3 1/2" Tubing 6 1/8" Hole Drilling Fluid System Versa- Drill Oil Mud Key Products Mapco 200 / Versawet / Versacoat / Versa HRP / VG69 / Ver- samod / Lime / Calcium Chloride / Safe Carb / Ventrol 401 Solids Control Shale Shakers / Desilter / Centrifuge ~ Potential Problems Coal sloughing, hole cleaning, drill solids buildup '1IIIt" . rr .. Inl( II. . Displace cement in 7" casing to oil based mud. . Drill ahead, maintain low shear rate values with VG69, Versamod, and Versa HRP. . Run centrifuge as needed to reduce solids buildup. . Pump weighted sweeps to aid in hole cleaning. Use Safe Carb (Calcium Carbnate) instead of barite for increases in mud density. . If sloughing coal becomes a problem, add 2- 4 ppb of Ventrol 401 to mud system or spot a concentrated pill of20- 25 ppb Ventrol401 across coal zone prior to trips. FOISevere coal sloughing consider raising mud weight. . Run and cement 3 1/2" liner ITom 6080' to 1950'. Run 3 1/2" tubing to 1950' . Displace well to 6 % KCI after running tubing. . Estimated volume usage is 900 barrels. Mud Program SRU 213-10 29 5/31/2002 UNO[AL~ M-I. L.L.c. 721 West First Avenue Anchorage, Alaska 99501 (907) 274-5564 (907) 279~729 Fax Interval Summary Swan( n River Unit SRU 213-10 Well MUD PROGRAM ~ UNOCAL SRU 213-10 2150' - 6080' MD 3 1/2" Tubing 6 1/8" Hole Lost Circulation Recommended LCM Pill Formulas Problems Key Products Drilling Fluid / OM Seal! SafeCarb Fine, Medium, Coarse / Versa- HRP --. _. Lost Circulation Pill (Slight Losses) Volume of Mud (barrels) 30 Mix II SafeCarb Fine (ppb) 10 (ppb) 10 .. .- SafeCarb Medium (ppb) 10 Lost Circulation Pill (Moderate Losses) Volume of Mud (barrels) 40 Mix II SafeCarb Medium (ppb) 15 (ppb) 15 -1111111 SafeCarb Coarse (ppb) 10 ,,- -UIIIL~r-'~ 1 ¡ ve:::~RP J ] :e::;iJ Lost Circulation Pin (Severe Losses) i Versa HRP - Polymer (ppb) ~ 1 -.n - Ii <-...-::--_.-1I'I'.-:::-ln .. - Volume Mix II SafeCarb of Mud Medium (barrels) (ppb) (ppb) 50 15 20 111- .<--'T]I II.nT' . --".1. SafeCarb Coarse (ppb) 30 . Versa HRP should be added last, only after all lost circulation material has been mixed. . Ifpossible, spot pill across theft zone. Apply moderate pressure (50 - 100 psi) to squeeze pill into thief zone. Mud Program SRU 213-10 30 5/31/2002 UNOCAL'- Swan( n River Unit SRU 213-10 Well DIRECTIONAL PROGRAM DIRECTIONAL PROGRAM NOTE: The 213-10 well adjacent to the proposed well is watered out and currently is shut in as incapable of production. The 213-10 was drilled as a straight hole to 2400' and then directionally drilled. The proposed well will kick off at 500 feet, well above the kick off point on the offset well. The offset well drilled to the East and the proposed well will drill to the South. Given the proposed well path and the Inclination surveys on the offset well, the closest that the two well should come to each other is 25 feet. This is not perceived as a problem to require special nudging. 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EJ):;29 FR 510 TeN R9N 8M t>JOrlhlnO {Y'¡ rn:USl EasUno no rnUSl 24B&!J19.43 J4854.ti.B2 24M139,::-i2 J48&..~.m 24B4.531,j'4 J4a3fJ2í.:l}3 24ß4455.81 3483.53.1') Directional Program SRU 213-10 31 5/31/2002 UNO[AL~ Swa~( n River Unit SRU 213-10 Well DIRECTIONAL PROGRAM ~ UIIOCAL8 WR.'1ICAL SL-1ION TIR .:ll..nt: l1n:, :;¡l W;;;¡ll: P:1¡;;l:1: 11::-1':' rÞ:!r S~..;:¡n:::cn P.1 v.. r r::rn! t - ~::: t ru: tl..lr.; : SI,';:¡n:::cn P.1 '':'; r S;;;¡ct1~n ~t: 187.10 :1~g I:'iõlt.;¡, : .1;¡~" ~:'2, 2':;':11 0 I.DPIòId:õiDIII>LlI ,';,.1','1:- ~ ')'71 11>''1:'.... .)¡.:p:llìn -----. , - þj 1&111,II>UI ¡'(.t IVt> ¡'(,I ì;¡¡¡;'~: h' );1¡';Uín p ([I- S! uS ~, o:ã: g ~ ~.a t:: œ ;:5 "'-" 0 ':IiVVi t ~ ~.oPJ ([Jr:T:I OM -m~ 0-- ~'5 $JŒ :;> :> 400J ~,g L-LlJ ~ Hnlrl Al"iJh~ 14...1 !=ie. i I 'Id~:i I. I 'I'll-I r:t- ". "::~::1~40'03'----~1 100J _I ¡ ¡ ~ 500J ~kJ Angle 1.00L' : , I 1 i - &00 ¡ , -11:00 0 1000 ;:000 \lertical Sec:tion Departure at '1B7.&I deg from (0.0.0.0). (1 in = 1 000 foo~ Directional Program SRU 213-10 32 5/31/2002 UNO[AL~ Swan( n River Unit SRU 213-10 Well DIRECTIONAL PROGRAM P:LU~ VIR ~ C11.;.nt: ;J.i¡; 11 : Unoc;¡l 11:!-lO ¡t"] F!..l,j: Stru:tllr.;; : !:'t;m~:.n !U ':.;¡r Un 1 t -- £','ÕÕiIì.::': n F:!' ':;;;,r Sc;¡l... : [jilt. : 1 1 n . : .:":' t' t 0: - H;¡jr- ¡':..:,;;: ...tOO -KlO . I ; (I ~1.."(I 400 (I -200 ~ tI1.¥~JI~ "'<'III "::ill'JVf '. 'J U' F"1:/.r "'/ (HIli ~ . 1õi11ll1111 a!) III f.)¡Ij I VI' :r,:~ r:¡¡;';':'I~ 0 '1ruQ .Korth t,ri3 !:"': >; E :;; ':. . !E') :- - :IDJ -400 t ! -400 ^ lí A :I: ~ c:: 0 z :& I'~ \~ l' , Dr..., :. {. -. .1, ..- -- . .1 __Eir.;.,. ~,)"'.J ,~-'..'''''''''' - t" .. ~ .- -.---_...~....- ......" ::r: i i I I I- t !)~~.!~, ~ , =:I 'm:;III.~I'.~i ,.1 , I 0 ~. :"~".;' i.~í'l~ ----- 1.. i,. I': 00 ~ I . ~ V (.. ~ 1;/ ~ i ~ i 11 .1nno----~~...~~.! --~_. J. T:Hn¡<.t -!!J::.............~I_,'......-r--{.','---'- i -1(OJ -- ". Il .r l' .' ~' ,,- ,'* ... ,,' i ., Ii ,",- II"~ ~:'........ ~ -. ,¡.'. I,' ~-..' ~ I II... Ii:!........ ~ . 1(". IJ. ~ ~ TO 1~,q.t "'~ 10-;,'1'" ¡ '¡ , .1 ;1))------ -'l!\\'l-l. ~. T~-~-~.'---'~". _J.'----_._-j,-_."",---------L_1~ ,',' !.~r-(~;""i.1 , . ..-----1r'.'.~'~....:~¡...r::..i1.~I:.l~I~' ~ ~ "", ~m . It! - . ';¡;';rIMI ¡¡:nl''':' I I (f:! !Y;¡;";~ .Ii." . 14CO ¡ ~ I.~.~ I -'300 -oco -14(0 ..to (I -23[1 [I IDJ EAST :;..::,,> 400 ..::;..:'"!::; \'~EST Directional Program SRU 213-10 33 5/31/2002 FOR INQUIRIES CONTACT LOCMION WHERE INVOICES WERE SUBMITTED DATE 3/, IHH'! d;J.. INVOICE/CREDIT MEMO NO. GROSS /ðð., -- VOUCHER NO. ) t .. V ~ FORM 4-28181 (REV. 11-95) PRINTED IN U.S.A. DETACH STUB BI:FOflE DEPOSITING CHECI( I TOTAL .... /O(). - ~ 1:0 j ~ ~OO 20 gl: , '. VENDOR NO. CHECK NO. DATE 3ì If/;¡:..(ò.;J. ¡;J ðð6 712 .. .>j I .r"'~ ~'. DISCOUNT . NET Union Oil Company of California Accounts Payable Field Disbursing 2006792 UNOCAL@~ ; ~, ë 1- ð C U : L. ( L. 1.. :; Õ ,- Date /i1AY 31/ O,}- Check Amount Wìf}f1f ¡(Jo, £'1: Void after six months from above date. l~ -( D.A. PAGE MAY 3 1 2002 j g ¡. ~ 8 ¡. j ? III UNO[AL~ SW{ ISON RIVER UNIT SRU 213-10 Well TABLE OF CONTENTS TABLE OF CONTENTS TAB L E OF CO NTEN TS ............... ............... ..................... ................................... ............................................. 3 PERMIT TO DRILL.. .................... ....................... ......... ...... ................ ........ .... ............. ...... ............. ........ .......... 4 LOC A TI 0 N PLAT.................................................................... ....... .................................................... .............. 5 LOCATION MAPS AND PLATS ..................................................................................................................... 7 C E ME N T PROGRAM...................................................................................................................... ................. 8 LOGG IN G PROGRAM................ ......................................... ....... ........... ...... ........................................ ...... ......9 ANTI CIP A TED FORMATION TO PS ...........................................................................................................11 PROPOSED MUD WEIGHTS AND ANTICIPATED FRACTURE GRADIENTS..................................12 RIG FOOTPRINT.... ...................... ......... .................... ....................................... ................. ................... ......... .13 DRILLING PR OC ED URE ........................................................................ ............................... ..................... ..14 DAYS VERSUS DEPTH PLAN ......................................................................................................................15 PROPOSED WELLBORE SCHEMATIC FOR MONOBORE COMPLETION......................................16 WELLHEAD DIAGRAM............... ............ ......... ................................................ .............. ...... ............. .......... .17 LEAK OFF TES T PROCEDURE.... ....................... ....... ........................................................................ ........ .18 UNOCAL ALASKA WELL WORK HAZARD ANALYSIS SCREENING ..............................................19 BOTTO MH 0 LE PRESS URE INFO RMA TI ON ............................ ...................... ....... ...................... ........... 20 C AS IN G DE S I G N .................. .................. ................ ....... ......... ...... ............... ...................... ................... ..........21 C AS IN G PROGRAM SUMMARY.................. ............... ........ ................................. .............. ......... ............... 23 DIVER TER AND BOP SPEC S ............ ...... ........... ....... ............... ..... .................... .................... ....................... 24 CHOKE MANIFOLD .......... ......... ................................. ....... ......... .......................... .......... ................... ..... ......25 DIVER TER S TACK UP .................................... ..... ........ .......... ....... ............. .................... ............... ....... ..... .... 26 BO PE S T A C K UP ............................... .................. ...................... ....................... ...................... ...... ..................26 BOP SCHEMATIC............ ......................... ................... ...... .............. ......................... ...... ....... ...... ........... .......27 MUD PROGRAM....................................................................................................................... ......................28 D IREC TI 0 N AL PROGRAM............ ............................................................................... .............................. .31 TABLE OF CONTENTS sru213-103 5/31/2002 ( TRANSMIT AL LETTER CHECK LIST CIRCLE APPROPRIATE LETTER/PARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER ;2 \ ~ - lU CHECK 1 ST ANDARD LETTER DEVELOPMENT x DEVELOPMENT RED RILL EXPLORA TION INJECTION WELL INJECTION WELL RED RILL Rev: 5/6/02 C\jody\templates WELL NAME CHECK WHAT APPLIES ADD-ONS (OPTIONS) MULTI LATERAL (If API number last two (2) digits are between 60-69) PILOT HOLE (PH) "-1() ~"" '\ ~ \) \ S "CLUE" The permit is for a new wellbore segment of existing well -' Permit No, API No. Production should continue to be reported as a function of the original API number stated above. In accordance with 20 AAC 25.005(t), all records, data and logs acquired for the pilot hole must be clearly differentiated in both name (name on permit plus PH) and API number (50 -70/80) from records, data and logs acquired for well (name on permit). ANNULAR DISPOSAL Please note that an disposal of fluids generated. . . INTO ANNULUS OF ANOTHER WELL ON SAME PAD L-) SPACING EXCEPTION Enclosed is the approved application for permit to drill the above referenced well. The permit is approved subject to full compliance with 20 AAC 25.055. Approval to perforate and produce is contingent upon issuance of a conservation order approving a spacing exception. (Companv Name) will assume the liability of any protest to the spacing exception that may occur. WELL NAME PROGRAM: Exp - Dev - Redrll - Serv - Wellbore seg - Ann. disposal para req - INIT CLASS GEOL AREA UNIT# ON/OFF SHORE 1. Permit fee attached. . . . . . . . . . . . . . . . . . . . . . . Y N 2. Lease number appropriate. . . . . . . . . . . . . . . . . . . Y N 3. Unique well name and number. .. . . . . . . . . . . . . . . . Y N 4. Well located in a defined pool.. . . . . . . . . . . . . . . . . Y N 5. Well located proper distance from drilling unit boundary. . . . Y N 6. Well located proper distance from other wells.. . . . . . . . . Y N 7. Sufficient acreage available in drilling unit.. . . . . . . . . . . Y N 8. If deviated, is wellbore plat included.. . . . . . . . . . . . . . Y N 9. Operator only affected party.. . . . . . . . . . . . . . . . . . Y N 10. Operator has appropriate bond in force. . . . . . . . . . . . . Y N 11. Permit can be issued without conservation order. . . . . . . . Y N 12. Permit can be issued without administrative approval.. . . . . Y N 13. Can permit be approved before 15-day wait.. . . . . . . . . . Y N 14. Conductor string provided. . . . . . . . . . . . . . . . . . . N 15. Surface casing protects all known USDWs. . . . . . . . . . . N 16. CMT vol adequate to circulate on conductor & surf csg. . . . . Y N 17. CMT vol adequate to tie-in long string to surf csg. . . . . . . . N 18. CMT will cover all known productive horizons. . . . . . . . . . N 19. Casing designs adequate for C, T, B & permafrost. . . . . . . N 20. Adequate tankage or reserve pit.. . . . . . . . . . . . . . . . N 21. If a re-drill, has a 10-403 for abandonment been approved. . . N 22. Adequate well bore separation proposed.. . . . . . . . . . . . N 23. If diverter required, does it meet regulations. . . . . . . . . . N 24. Drilling fluid program schematic & equip list adequate. . . . . N 25. BOPEs, do they meet regulation. . . . . . . . .~. . . . . . N . ..........' Aj~~ DATE 26. BOPE press rating appropriate; test to ~ ~~v psig. N ,,~~ '\> '\ «? 'S(J { ~~ \: I<::)i~ f/( '? It -C~ 27. Choke manifold complies w/API RP-53 (May 84). . . . . . . . N 28. Work Wi.1I occur without operation shutdown. . . . . . . . . . . Y ,~ 29. Is presence of H2S gas probable.. . . . . . . . . . . . . . . . Y Q:!) 30. Permit can be issued w/o hydrogen sulfide measures. . . . . Y N 31. Data presented on potential overpressure zones. . . . . . '. þ.,... Y N 32. Seismic analysis of shallow gas zones. . . . . . . . . . . . . ~ Y 33. Seabed condition survey (if off-shore). . . . . . . . . . . . . 34. Contact name/phone for weekly progress reports [exploratory ANNULAR DISPOSAL 35. With proper cementing records, this plan (A) will contain waste in a suitable receiving zone; . . . . . . . (B) will not contaminate freshwater; or cause drilling waste. .. to surface; (C) will not impair mechanical integrity of the well used for disposal; Y N (D) will not damage producing formation or impair recovery from a Y N pool; and (E) will not circumvent 20 MC 25.252 or 20 MC 25.412. Y N GEOLOGY: ENGINEERING: UIC/Annular: COMMISSION: TEM~~(I WELL PERMIT CHECKLIST COMPANY FIELD & POOL ADMINISTRATION APPR DATE / ~. ENGINEERING GEOLOGY ( APPR DATE APPR DATE Y N Y N SFD \-..J~ COT, . DTSO '? I ð2/D L. G:\geology\permits\checklist.doc <0 r~~ RSL~\c,K~ ~,\-~~'" \\t>..H-\~\~\.'\~ ~ ">\-~~~. ~~\,,~ ~~-=~" ~ C~JVR~ \<:...<>;.,-~...,~No~~"~- 65c)~{, ~">,~~~-\ 'ù£\<::)~ ~~a~--\~ c..~~~~ ~~~ ~ ~,~ \\ ,,~, \. ~ ~.... '\ ~ ~'"\ 0... t '"', - '\-.:S ~ ~ ) ~\i,,~" ,,",~\«. \i) \'~\~~,~\\~Q M:> ~1'." ~ \ ~ ".> '(~":.'t r--.. -\ \ \N~'> ~ +a ~ 1;z \j '-.'2 V ~.~,~ ~~Q. \~. \'-~ Comments/Instructions: ~¡¿t.( /' WELL PERMIT CHECKLIST COMPANY tlI10 c..t1... ( WELL NAME ;2../-::S -/6 PROGRAM: Exp - Dev ~ Redrll- Serv - Wellbore seg . Ann. disposal para req- FIELD & POOL 772-sc;::è:) INITCLASS ~V /9/f~ GEOLAREA 87/:) UNIT# (~.q77V ON/OFFSHOREO/7 ADMINISTRATION 1. Permittee attached. . . . . . . . . . . . . . . . . . . . . . . N 2. Lease number appropriate. . . . . . . . . . . . . . . . . . . N 3. Unique well name and number. .. . . . . . . . . . . . . . . . Y N . .......-::> ,-' / / . / .. . ( 4. Well located in a defined pool.. . . . . . . . . . . . . . . . . :S;4J~~Ó-;VZ ~~ ~ /-,L/c!./ uÞCc:£..¿. L.. (?'- 6. Well located proper dIstance from other wells.. . . . . . . . . Y -.r-It15 tu-,/I ~ ~ ~~ ¿5i~ - ~o ùc~ ~ -,- /J 7. Suffic~ent a~reage availabl~ in drilling unit.. . . . . . . . . . . ,...s.., ~./ .~, . A --!.) ¡?9 W; / i' ¥-Ö z. ; ~XA--KfAé-X- ß~-h~ r1¿) -n.7re.ð. í7 À . 8. If deviated, IS wellbore plat Included.. . . . . . . . . . . . . . N hŠ,4~ 25' - ~tf~. ~ 9. Operator only affected party.. . . . . . . . . . . . . . . . . . N 10. Operator has appropriate bond in force. . . . . . . . . . . . . Y) II 11. Permit can be issued without conservation order. . . . . . . . Y GV A~R .DAlE 12. Permit can be issued without administrative approval.. . . . . ø N ,If!::> ¿,. 'f~_óv 13. Can permit be approved before 15-day wait.. . . . . . . . . . C) ENGIN~4Gn7- 14. Conductor string provided. . . . . . . . . . . . . . . . . . . Y N 15. Surface casing protects all known USDWs. . . . . . . . . . ./'I'/l Y N r 16. CMT vol adequate to circulate on conductor & surf csg. . . . . Y N 17. CMT vol adequate to tie-in long string to surf csg. . . . . . . . Y N 18. CMT will cover all known productive horizons. . . . . . . . . . Y N 19. Casing designs adequate for C, T, B & permafrost. . . . . . . Y N 20. Adequate tankage or reserve pit.. . . . . . . . . . . . . . . . Y N 21. If a re-drill, has a 10-403 for abandonment been approved. . . Y N 22. Adequate wellbore separation proposed.. . . . . . . . . . . . Y N 23. If diverter required, does it meet regulations. . . . . . . . . . Y N 24. Drilling fluid program schematic & equip list adequate. . . . . Y N 25. BOPEs, do they meet regulation. . . . . . . . . . . . . . . . Y N 26. BOPE press rating appropriate; test to psig. Y N 27. Choke manifold complies w/API RP-53 (May 84). . . . . . . . Y N 28. Work will occur without operation shutdown. . . . . . . . . . . Y N 29. Is presence of H2S gas probable.. . . . . . . . . . . . . . . . Y N GEOLOGY 30. Permit can be issued w/o hydrogen sulfide measures. . . . . . Y ~ 31. Data presented on potential overpressure zones. . . . . .. . Ý N 32. Seismic analysis of shallow gas zones. . . . . . . .;2' . .. . A Y N ßPR I)AT~ 33. Seabed condition survey (if off-shore). . . . . . . . . . . . Y N . ~. 'f .ó2- 34. Contact name/phone for weekly progress reports [exp/o ory only] Y N . '''''Iq.ó~ ANNULAR DISPOSAL 35. With proper cementing records, this plan (A) will contain waste in a suitable receiving zone; . . . . . . . Y N (B) will not contaminate freshwater; or cause drilling waste. .. Y N to surface; (C) will not impair mechanical integrity of the well used for disposal; Y N (D) will not damage producing formation or impair recovery from a Y N pool; and (E) will not circumvent 20 AAC 25.252 or 20 AAC 25.412. Y N GEOLOGY: ENGINEERING: UIC/Annular: COMMISSION: A10hDl::vr~ ð::>nJr>k"¡;~. / APPR DATE APPR DATE Comments/Instructions: SF~ TEM COT DTS G:\geology\permits\checklist.doc