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Home My WebLink About204-014Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov November 14, 2025 Erika Denman Permitting Lead Oil Search Alaska, LLC P.O. Box 240927 Anchorage, Alaska 99524-0927 Re: Location Clearance Placer 1 (PTD 2040140) Placer 3 (PTD 2152040) Dear Ms. Denman: Placer 1 and Placer 3 were exploration wells drilled in 2004 and 2016, respectively. Both were subsequently suspended. Surface abandonment operations at Placer 1 and Placer 3 were witnessed by Alaska Oil and Gas Conservation Commission (AOGCC) Inspectors in March 2025. The post- abandonment location inspections were done on August 14, 2025. Based on AOGCC inspections, the Placer 1 and Placer 3 drill sites are compliant with onshore location clearance requirements as stated in 20 AAC 25.170. The AOGCC requires no further work on the subject well or location at this time. However, Oil Search Alaska, LLC remains liable if any problems occur with these wells in the future. Sincerely, Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.11.14 14:46:53 -09'00' Gregory C Wilson Digitally signed by Gregory C Wilson Date: 2025.11.17 07:33:39 -09'00' Oil Search (Alaska), LLC a subsidiary of Santos Limited 601 W 5th Avenue Anchorage, Alaska 99501 (T) +1 907 375 4600 santos.com Santos – Former Placer Unit – November 1, 2025 Status Report Page 1 October 28, 2025 Mr. Alex Zinck Alaska Department of Natural Resources Division of Oil & Gas 550 W. 7th Ave. Suite 1100 Anchorage, AK 99501-3563 Re: Quokka Unit - Placer 1 and 3 P&A Project LONS 15-006 Final Status and Completion Report Mr. Zinck, Oil Search (Alaska), LLC, a subsidiary of Santos Limited (Santos), provides this as the final Completion Report for LONS 15-006 – Quokka Unit (Formerly Placer), Placer Wells 1 and 3, Plug and Abandon Unit Plan of Operations Amendment Decision, issued October 21, 2024. In accordance with LONS 15-006, Plug and Abandonment (P&A) activities at Placer wells 1 and 3 (Project) were conducted between November 2, 2024 and May 1, 2025. Santos performed the final Project activities between May 1, 2025 and November 1, 2025 (Report Period). During the Report Period, Santos performed the following tasks: • Demobilized equipment and vacated the ice roads and pads. Trash and debris were removed and transported for disposal at a permitted disposal facility; • Summer stickpicking and site cleanup along previously constructed ice roads and ice pads (Attachment A); and • Performed final site inspection August 12, 2025 with the Alaska Oil & Gas Conservation Commission via helicopter (Attachment B). Attachment A includes an overview of the project area and ice roads constructed as part of the Project (Figure 1). Photos of the completed wells are provided in Attachment B. No tundra disturbance events occurred during the Reporting Period. A well abandonment survey was prepared for both wells and they are included in Attachment C. As a condition of this approval also attached is a certified As-Built Survey of the well location in hard copy, as well as a digital GIS file containing the location. If you have any questions or would like additional information, please let me know. Santos – Quokka Unit – November 1, 2025 Status Report Page 2 Sincerely, Erika Denman Permitting Lead Attachment A: Figure 1 – 2024/2025 Placer Ice Roads Attachment B: Project Photos Attachment C: Well Abandonment Survey for Placer 1 and Placer 3 Santos – Former Placer Unit – November 1, 2025 Status Report Attachment A. Figure 1 - Placer 1 & 3 Ice Roads Overview Milne POint KuPaRuK RiveR OOOguRuK SOutheRn Miluveach PiKKa QuOKKa PRudhOe Bay AFP DLS L C STAGING AREA B UGNU PAD E MPU MS J G HI HEM'S AIRSTRIP K KCS CPF-1 / KOC MS F MS C CPF-2 F 3R D 3Q A CPF 3M 3N 3K3I 3J 3H TEXACO3ACPF-3 3C 3B 1R 3G 3F 1Q 33-29E 1GW SAK 11 2W 2U 1Y 1A2X2T SWPT 1 1C2V2Z 2A 1M1E1D2C1FW SAK 14 2B 2D 2M 2H 2F 1L 1J (WSPP) 2E2G 2K MS E 3S FOUR CORNERS ODS L OPP MS B 3T MUSTANG MS D SOTP 1H KIC KIC W SAK 06 NOC 3O W SAK 18 1B W SAK 24A M CAMAI' NOP NDB NPF BOAT LAUNCH K3 RAVEN GSP Pigging Pad GSP Tie-In TIP STP Project Location 0 1 20.5 Miles 0 2 41 Kilometers NAD 1983 StatePlane Alaska 4 FIPS 5004 Feet Created on: 4/22/2025, Created by: JB. Project: AP-DEV-IR_planningIceRoads_2024 Layout: AP-DEV-IR-PE-M_iceRoads_2024_prepacking Map Frame: AP-DEV-IR-PE-M_iceRoads_2024_prepacking PLACER ICE PADS PLACER ICE ROADS PIKKA PIPELINES LAKES TO USE GRAVEL PADS GRAVEL ROADS PIPELINES OTHER QUOKKA UNIT PRODUCTION UNITS OTHER Santos STP OIL SEARCH (ALASKA) LLC A SUBSIDIARY OF SANTOS LTD PIKKA DEVELOPMENT Figure 1 - Placer 1 & 3 Ice Roads Overview Placer 3 Placer 1 Santos – Former Placer Unit – November 1, 2025 Status Report Attachment B. Project Photos Santos – Former Placer Unit – November 1, 2025 Status Report Placer 1 Well Site (August 14, 2025) Placer 3 Well Site (August 14, 2025) ,. / - - 10 .. _ .. 11 >. r .. - Santos – Former Placer Unit – November 1, 2025 Status Report Attachment C. Well Abandonment Surveys 2025-0814_Location_Clearance_Placer-1_gc Page 1 of 3 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: 8/17/2025 P. I. Supervisor FROM: Guy Cook SUBJECT: Location Clearance Petroleum Inspector Placer 1 Oil Search Alaska (Santos) PTD 2040140; Sundry 324-516 8/14/2025: I arrived at Santos’ Pikka for the helicopter flight to Placer exploration pad. We flew out to location and hovered above Placer #1. The location was verified by GPS. The location was very clean with no signs of trash, debris or hydrocarbons left behind. We hovered around the drill-site and looked for anything that needed to be removed/cleaned up while I took pictures. After I was satisfied that the area was clean, we left location. Attachments: Photos (4)    2025-0814_Location_Clearance_Placer-1_gc Page 2 of 3 Location Clearance Inspection – Placer #1 (PTD 2040140) Photos by AOGCC Inspector G. Cook 8/14/2025 2025-0814_Location_Clearance_Placer-1_gc Page 3 of 3 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: __________________ Service Stratigraphic Test 2. Operator Name:6. Date Comp., Susp., or Aband.: 03/31/2025 14. Permit to Drill Number / Sundry: 3. Address: 7. Date Spudded: 15. API Number: 50-103-20481-00 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: 1009' FSL, 19' FWL, Sec. 33 T12N, R7E, UM Placer #1 Top of Productive Interval: 2299' FLS, 498' FWL, Sec. 4, T11N, R7E, UM 9. Ref Elevations: 17. Field / Pool(s): RKB 30' / 55' AMSL Kuparuk River Field / Kuparuk River Oil Pool Total Depth: 2169' FSL, 515' FWL, Sec. 4, T11N, R7E, UM 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 N/A (ft MSL) 22.Logs Obtained: 23. BOTTOM 16" H-40 135' 9.625" L-80 2528' 373 bbls AS III Lite, 170 sx LiteCrete 7" L-80 7467' 190 sx Class G 6.125"7761' open hole 24. Open to production or injection? Yes No 25 26 Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate Sr Res EngSr Pet GeoSr Pet Eng none Oil-Bbl: Water-Bbl: 230# frac sand 7029' - 7357' 12 bbls 15.8 ppg Class G Water-Bbl: PRODUCTION TEST N/A Date of Test: Oil-Bbl: Flow Tubing 7375' - 7385' Permanently Abandoned Gas-Oil Ratio:Choke Size: Per 20 AAC 25.283 (i)(2) attach electronic information 26# 7761' Surface 62.5# 40# 135' Surface 7467' SIZE DEPTH SET (MD) none PACKER SET (MD/TVD) 24" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Oil Search Alaska LLC (Santos) WAG Gas CASING WT. PER FT.GRADE CEMENTING RECORD 5972434 1470' MD SETTING DEPTH TVD 5972304 TOP HOLE SIZE AMOUNT PULLED 451755 451771 TOP SETTING DEPTH MD If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date perf'd or liner run): See cement reports from P&A activities 1590'3.5" 2/27/2004 7761' MD / 6289' TVD N/A 601 W. 5th Avenue, Anchorage, AK. 99501 451290 5976426 ADL 389132 N/A BOTTOM CASING, LINER AND CEMENTING RECORD Surface Surface 6.125" TUBING RECORD 8.5" 12.25" 142 sx AS I Surface Surface 2528' Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment By Meredith Guhl at 11:38 am, May 22, 2025 xG RBDMS 5/1/2025 JSB -00 DSR-6/3/25 204-014/324-516 BJM 11/11/25 Conventional Core(s): Yes No Sidewall Cores: 30 MD TVD Placer 1 Top Kuparuk 7539' 6111' Base Kuparuk 7560' 6127' 31. List of Attachments: 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Digital Signature with Date: Contact Name: Nick Miller Contact Email:Nick.Miller@santos.com Contact Phone: General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: Authorized Title: Senior Completions Engineer 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. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. 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). 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. Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). 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. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment; or 90 days after log acquisition, whichever occurs first. Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. 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. 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. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071. 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. Formation Name at TD: TPI (Top of Producing Interval). Authorized Name and INSTRUCTIONS Yes No Well tested? Yes No 28. CORE DATA If Yes, list intervals and formations tested, briefly summarizing test results for each. Attach separate pages if needed and submit detailed test info including reports and Excel or ASCII tables per 20 AAC 25.071. NAME If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired. 29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered) FORMATION TESTS Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov 4/24/2025 1MBDFSDVU1MBDFS8FMMIFBE$BQ 1MBDFS4VSGBDF#BDLGJMM 1MBDFS%JSU#BDLGJMM Surface Casing 9-5/8" 47# L80 BTC 2,528' MD/2,268' TVD 12-¼Hole Size Production Casing 7" 26# L80 BTC 7,467' MD/6,053' TVD 8 ½Hole Size Cement Retainer @ 7,385' MD 79 bbls of 11ppg Permafrost Cement pumped down 3-½Kill String and into 3-½x 7" IA to Surface 10' Sand Plug @ +/- 7,375' MD 203 bbls of 15ppg Cement laid in 7" Casing from 7,047' MD to 1,700' MD 16 Conductor 115' MD/TVD Placer 1 P&A Well Schematic 4.7.2025 Base Permafrost ~ 1300' MD/TVD TD 6-1/8" Open Hole 7,761' MD/6,289' TVD 12 BBL (328' Length) Cement Plug @ +/- 7,047' MD 3-1/2 9.3# L80 EUE-8rd Kill String landed @ +/- 1,590' MD 22 bbls of 15ppg Lead Cement and 50 bbls of 11ppg Permafrost Tail Cement squeezed from Surface down 7" x 9-5/8" OA Cement observed at surface on all strings after wellhead cut Top Kuparuk 7,539' MD Base Kuparuk 7,560' MD 11.0ppg LSND Mud 6-1/8" Open Hole Ce m e n t Ce m e n t Ce m e n t Ce m e n t Ce m e n t Ops Summary Report All Jobs - AOGCC Job Type Start Date End Date Start Depth (ftKB) Depth Prog (ft) Dens Last Mud (lb/gal)Summary P&A 3/7/2025 3/8/2025 0 Verify no VR plugs in IA or OA. IA =0 psi OA = 410 psi. Bleed fluid from OA to 0 psi. P&A 3/8/2025 3/9/2025 0 Pull BPV. Bleed OA from 200 psi to 0 psi. P&A 3/9/2025 3/10/2025 0 Test 7" casing to 2,000 psi - PASSING Test. Pump 110 bbls of diesel down OA for injectivity test. OA pressure broke over at 1750 psi and established Injectivity. Increase injectivity from 0.25 bpm up to 5 bpm. Pressure at end of OA injectivity test was 5.0 bpm at 940 psi. P&A 3/12/2025 3/13/2025 0 MIRU LRS CTU #3 with 2" coiled tubing. Spot choke skid and RU iron to return tanks. Set deadman blocks. Spot in twin pumper and RU diesel tanker, 60/40 methanol vac, and slick water vac. Spot in triplex with methanol pup. P&A 3/13/2025 3/14/2025 0 Troubleshoot deck engine to enable it to Regen. Load coil with diesel and drift coil with 1.25" ball. Test BOPE to 300 psi low / 4,000 psi high. Passing Test. P&A 3/14/2025 3/15/2025 0 RIH with 2" coiled tubing and 2" down jet nozzle. Jet out brine and mud in 7" casing at 2.0 bpm with slick water. Tag cement top at 6957' ctmd and set down -4k. Chase brine and mud to surface at 2.5 bpm. Freeze protect coil and kill string with diesel. AOGCC representative (Kam StJohn) arrived on location and witnessed coil tag and Passing Pressure test of casing to 2500 psi. P&A 3/15/2025 3/16/2025 0 Lay down coiled tubing lubricator and injector. Clear snow from around pad. RU hard line from OA to return tanks. RU HES cementers for OA downsqueeze. Pump 22 bbls of 15.0 ppg class G cement followed by 58 bbls of 11.0 ppg ArcticCem down OA. Pressure at end of cementing was 78 psi. Wait 15 minutes, pressure was at 34 psi. Squeeze 1.5 bbls of 11.0 ppg ArcticCem down OA. Wait 15 minutes, pressure was 50 psi. Close gate valve on OA and cleanup iron to tanks. RDMO cementers. Pick up coil injector, lubricator and MU coil cementing BHA with ball drop nozzle. P&A 3/16/2025 3/17/2025 0 MU lubricator to BOP's and PT to 4,200 psi. P&A 3/17/2025 3/18/2025 0 RIH with 2" ball drop cement nozzle to tag TOC at 6960' CTMD and pick up to 6935'. RU HES Cement equipment and pump 160bbls of 15ppg to lay in 7" casing while pulling out of hole at 16fpm at midnight. P&A 3/18/2025 3/19/2025 0 Complete pumping and laying 203bbl of 15ppg cement from 6960' CTMD to 1700' CTMD' displacing cement out of coil tubing with 30bbls of Gel and 22bbls. Wash top of cement from 1700'CTMD' and chased it to surface. RIH with CT to 1700' CTMD and Freeze protect to surface with 60/40 Methanol. Blow down coil with HES N2. Rig down CT, clean out return tanks and De-mob LRS CT. P&A 3/21/2025 3/22/2025 0 Circulate 79 bbls of 11 ppg cement down Tubing while taking returns out IA. Saw good 11 ppg cement at surface. P&A 3/23/2025 3/24/2025 0 Excavate to 4.5' below Ground Level around Conductor. P&A 3/24/2025 3/25/2025 0 Cut off Well Head 4'1" below Ground Level. P&A 3/29/2025 3/30/2025 0 AOGCC Austin McLeod witnessed cut depth and cement top. Top Cap Plate welded on. Pictures sent to AOGCC. P&A 3/31/2025 4/1/2025 0 Backfill excavation to Tundra Level with gravel. Bring in organic top soil to create mound. Pikka Field Enviromental Coordinator inspected and approved. Close out Placer 1 ice pad. Well Name Wellbore Name PTD # Start Drill Date End Drill Date Page 1 of 1 Well Name Placer 1 Wellbore Name Original Hole PTD # Start Drill Date End Drill Date Placer 1 Casing Cut –Cemented to Surface Placer 1 P&A Welded Plate Marker Placer 1 Surface ackƱll Placer 1 "irt ackƱll 2025-0329_Surface_Abandon_Placer-1_am Page 1 of 3 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: 3/30/2025 P. I. Supervisor FROM: Austin McLeod SUBJECT: Surface Abandonment Petroleum Inspector Placer #1 Oil Search Alaska LLC (Santos) PTD 2040140; Sundry 324-516 3/29/2025: I traveled to location and met with Santos representative Nick Frazier to witness the surface abandonment/cutoff of the well. All strings had hard cement to surface. Cement integrity verified with a sledgehammer. The well was cut off four feet below tundra grade. The marker plate was ¼-inch thick steel and didn’t extend beyond the conductor. I requested “Santos” be added to the plate. There were, what appeared to be, two 27/8-inch tubing strings outside the conductor that had hard cement in them. I was told these strings were used to pump cement/stabilize the conductor when set. Tubing tails were supposedly at the conductor shoe. They were approximately six inches below the top of the now cutoff well. The information below was welded to the plate: Placer #1 PTD 204-014 API 50-103-20481-00-00 Oil Search Alaska Santos No issues with this inspection. Attachments: Photos (3) 9 9 9 9 9 9 James B. Regg Digitally signed by James B. Regg Date: 2025.05.01 15:02:48 -08'00' 2025-0329_Surface_Abandon_Placer-1_am Page 2 of 3 Surface Abandonment – Placer #1 (PTD 2040140) Photos by AOGCC Inspector A. McLeod 3/29/2025 Two 2 7/8 inch tubing strings outside the conductor 2025-0329_Surface_Abandon_Placer-1_am Page 3 of 3 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section: 33 Township: 12N Range: 7E Meridian: Umiat Drilling Rig: n/a Rig Elevation: n/a Total Depth: 7761 ft MD Lease No.: ADL391027 Operator Rep: Suspend: P&A: X Conductor: 16" O.D. Shoe@ 115 Feet Csg Cut@ Feet Surface: 9-5/8" O.D. Shoe@ 2528 Feet Csg Cut@ Feet Intermediate: 7" O.D. Shoe@ 7467 Feet Csg Cut@ Feet Production: O.D. Shoe@ Feet Csg Cut@ Feet Liner: O.D. Shoe@ Feet Csg Cut@ Feet Tubing: 3.5" O.D. Tail@ 1590 Feet Tbg Cut@ Feet Type Plug Founded on Depth (Btm) Depth (Top) MW Above Verified Fullbore Bridge plug 7385 ft 6957 ft 8.6 ppg C.T. Tag Initial 15 min 30 min 45 min 60 Min Result Tubing 2875 2769 2705 2651 2603 IA 2930 2824 2760 2706 2658 OA 632 601 575 553 534 Initial 15 min 30 min 45 min Result 2nd Attempt Tubing 2791 2752 2719 2689 IA 2847 2808 2775 2744 OA 538 523 514 502 Initial 15 min 30 min 45 min Result 3rd Attempt Tubing 2821 2801 2787 IA 2872 2850 2832 OA 495 491 487 Remarks: Attachments: Brad Gathman Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): F P Good tag on top of cement with coil tubing. 4.0 bbls in and 4.0 bbls returend for MIT. Test 1 - pressure failed to stabilize. Test 2 - pressure failed to stabilize. Test 3 - pass; pressure loss less than 2% of initial test pressure after 30 min. March 14, 2025 Kam StJohn Well Bore Plug & Abandonment Placer 1 Oil Search Alaska PTD 2040140; Sundry 324-516 none Test Data: F Casing Removal: rev. 3-24-2022 2025-0315_Plug_Verification_Placer-1_ksj 9 9 9 9 9 9 99 9 9 9 9 9 9 9 9 9 9 9 9 99 99999 9 9 9 9 9Þ9 9 9 9 9 9 99 9 99 9g Test 3 - pass; pressure loss less than 2% of initial test pressure after 30 min James B. Regg Digitally signed by James B. Regg Date: 2025.04.16 14:17:25 -08'00' 1 Guhl, Meredith D (OGC) From:McLellan, Bryan J (OGC) Sent:Monday, March 10, 2025 3:33 PM To:Miller, Nicklaus (Nick) Cc:Davies, Stephen F (OGC) Subject:![EXT]: RE: Placer #1 Sundry Number 324-516 (Oil Search Alaska LLC) To help protect youMicrosoft Office preautomatic downloadpicture from the Int Nick, Based on the additional background information mentioned in your email below, Oil Search has approval to proceed with the P&A without running the cement bond log across the 7” casing. All other conditions of approval still apply. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Miller, Nicklaus (Nick) <Nick.Miller@santos.com> Sent: Wednesday, February 12, 2025 10:28 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: Placer #1 Sundry Number 324-516 (Oil Search Alaska LLC) Bryan, Good morning! We’re geƫng close to performing the P&A work on both Placer wells and I came across some new/addiƟonal informaƟon regarding Placer #1 that I’d like to share with you. ASRC ExploraƟon LLC (AEX) originally submiƩed an abandonment package back in early 2016 that was approved, and I’ll show some important details of that package later in this e-mail. The informaƟon I’d like to review revolves around plugging the uncased porƟon of the wellbore and effecƟvely segregaƟng uncased and cased porƟons of the well. Per our approved sundry, we have a variance approval to 20 AAC 25.112 (a)(1)(C), 20 AAC 25.112 (a)(2) and 20 AAC 25.112 (b) to cement off the open hole secƟon of the well conƟngent on the following condiƟon being met: CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 Santos would like to forego running the above menƟoned CBL based on new informaƟon sourced from the original ASRC abandonment sundry approved in 2016. Minimum calculated TOC outside 7” casing is 7,162’ per aƩached schemaƟc. The top of cement plug inside 7” is 7,062’ MD. Worst case, that puts TOC outside 7” casing 100’ below where we can effecƟvely log to with a CBL. Santos does not feel that running a CBL to conﬁrm isolaƟon of the hydrocarbons in the Kuparuk sand is necessary for the following reasons that were originally submiƩed by ASRC: 3 4 In summary, we have a 305’ column of cement outside the 7” casing which creates a very competent shoe effecƟvely eliminaƟng verƟcal movement of ﬂuids within the uncased porƟon of the wellbore. Santos will place an addiƟonal 5,400’ of cement inside the 7” to ensure no ﬂuid movement in casing. Thank you, Nicklaus Miller Senior CompleƟons Engineer t:1 (406) 690-2896 | e: nick.miller@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter Santos Ltd A.B.N. 80 007 550 923 Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may be confidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy. Please consider the environment before printing this email 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No Placer #1 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 7,761'6,289' 7,029' 5,710' Casing Collapse Structural Conductor Surface Intermediate Open Hole Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name:Jared Brake Contact Email: brajg@santos.com Contact Phone: 832-330-4359 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 3/1/2025 3.5" Perforation Depth MD (ft): 7,467' N/A 294' N/A 6.125" 16" 9.625" 105' 7"7,437' 2,498' 115' 2,268' 6,053' 115' 2,528' 6,289'7,761' L-80 TVD Burst 1,590' MD Oil Search Alaska LLC (Santos) Length Size Proposed Pools: Perforation Depth TVD (ft): STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 391027, 391023 Exploratory 204-014 601 w. 5th avenue, Anchorage ak 99501 50-103-20481-00 PRESENT WELL CONDITION SUMMARY AOGCC USE ONLY Tubing Grade:Tubing MD (ft): Well Integrity & Intervention Engineer Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior writte n approval. Authorized Name and Digital Signature with Date: Tubing Size: m n P 2 6 5 6 t _ N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Well Integrity & Intervention Engine 324-516 By Grace Christianson at 4:22 pm, Sep 09, 2024 10-407 2534 psi - bjm Provide 48 hrs notice for AOGCC opportunity to witness pressure test to 2500 psi and tag of cement plug at ~7062' MD after CT mud cleanout is complete. Notify AOGCC if tag is deeper than 7250' MD. Provide 48 hrs notice for AOGCC opportunity to witness wellhead cutoff before and after annulus topoff. Photo-document cement in annuli before installing marker plate, marker plate installed, backfilled hole. Provide 10 days notice to AOGCC for final site clearance inspection during snow-free period, before 9/30/25. X Variance to 20 AAC 25.112(a) & (b) conditionally approved. See comments in application. SFD 10/28/2024 -00 SFD Abandon Cement used in OA and surface cement plug must be permafrost type cement per 20 AAC 25.112(e) . DSR-9/11/24 X BJM 10/29/24 JLC 10/30/2024 Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.11.01 09:27:04 -08'00'10/31/24 RBDMS JSB 110124 Oil Search (Alaska), LLC a subsidiary of Santos Limited 601 W 5th Avenue Anchorage, Alaska 99501 PO Box 240927 Anchorage, Alaska 99524 (T) +1 907 375 4642 —santos.com 1/1 September 9th, 2024 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7 th Avenue Suite 100 Anchorage, Alaska 99501 Re: Application for Sundry Approval on P&A of Placer 1 Exploration Well Commissioner, Please find attached Form 10-403 Application for Sundry Approval to abandon the Placer 1 Exploration well; the well was deemed as not a commercial find in accordance with 20 AAC 25.105 (e)(1). In Accordance with 20AAC 25.105 (e)(2)(B) and (C) the statement proposed work; please see the attached proposed P&A process, wellbore schematics with a summary for each step, and variance request to 20 AAC 25.112 (a) (1) (C), 20 AAC 25.112 (a) (2) and 20 AAC 25.112 (b) to cement off the open hole section of the well. The open hole section of the well has a single Kuparuk C sand that is 5.6’ of net reservoir without the possibility of crossflow. Cementing off the open hole section below the cast iron retainer / cement plug would require the use of a rig to pull the kill string. Santos Ltd is proposing to perform the process rigless as outlined in the proposal. Yours sincerely, Jared Brake Well Integrity & Intervention Engineer Oil Search LLC open hole section of the well has a single Kuparuk C sand that is 5.6’ of net reservoir 1For Internal Use onlySantos Placer 1 Location 2For Internal Use onlySantos Placer 1 &# proposed Ice Road access 3For Internal Use only+The Placer 1 well was deemed not commercial in value by ConocoPhillips in 2004 It was plugged with a 7” cast iron cement retainer with a sand and cement plug on top. The open hole section was left with 11 lbs/gal mud left in it. The wellbore below the kill string was left loaded with 11 lbs/gal mud, VR plugs installed in the IA and OA with a BPV in the tubing hanger.+Diesel was circulated down the kill string and up the IA for freeze protect. The OA was injected into at 2 bpm with Diesel freeze protect and displaced to the shoe.Current StatusSantos Placer #1Placer #1 Current StatusGL: 25' MSLRKB: 55' MSLProducing Zone TopsKuparuk Sands top - 7539' MDKuparuk Sands bottom - 7560' MD6-1/8" Open hole 7,385' RKB To TD 7761' MD / 6289' TVDBase of 16" 62.58 lbs/ft conductor set @ 115' MD BPVBase of 9-5/8" 40 lbs/ft L80 Surface casing @ 2528' MD / 2268 TVD (12-1/4" hole size)BPV Installed & VR plugs installed in IA & OA valves11.0 ppg mud Diesel Fresh waterFresh water Base of 7" 26 lbs/ft Lb L-80 BTC at 7467' MD / 6053' TVDDiesel Diesel3.5" 9.3 lbs/ft L-80 EUE- 8rd set at 1590' MD Top of cement assessed between 6010' MD - 7162' MD calculatedBaker N-1 Cast Iron Cement Retainer set at 7385' MDCement Sand11.0 ppg Mud 11.0 ppg mud11.0 ppg mud 4For Internal Use only+This evaluation of the Placer 1 well shows that there is a single pay sand in the open hole interval. That is the Kuparuk Cand it is 5.6’ of net reservoir without the possibility of crossflow.+A variance is requested to 20 AAC 25.112 (a) (1) (C), 20 AAC 25.112 (a) (2) and 20 AAC 25.112 (b) to cement off the open hole section of the well. +Due to the 7” casing plug and retainer at 7385’, along with the 3.5” tubing tail being at 1590’, it is not advisable to mill out the retainer with an expandable mill due to the risk of damaging unsupported coil in 7” casing. A rig would be required to pull the tubing and mill the retainer to cement off the open hole section.Waiver needed for Cementing open hole sectionAgree. Density log indicates upper 15' of this 20-foot thick reservoir istight and likely cemented by siderite. Density and gamma ray curvessuggest only about 5' TVD of net sand/pay in this well. SFDVariance approved on the condition thata Cement log is run to verify cement outside the 7" csgabove the existing cement plug. During the 7" casing cementjob, 26 of the 36 bbls of cement were lost and the wellwas flowing after cement was in place, before cement set.CBL will verify a barrier outside casing above the Kuparuk.-bjm 5For Internal Use only+Establish injection down OA with diesel for 1.5 times annular volume (107 bbls) up to 1000 psi or 5 bpm.൞If annulus pressures up during displacement, perforating the 7” annulus will be assessed for circulating in cement from bottom up.+Displacement calculations-൞9-5/8” 40# L-80 x 7” 26# L-80 casing shoe at 2528’൞(.0282 bpf x 2528) = 71.3 bbls൞(71.3 x 1.5) = 106.95 or 107 bbls displacement volume+CMIT-TxIA to 2000 psi to ensure casing integrity and cement plug integrity.OA Injection TestSantos Placer #1Placer #1 OA injection TestGL: 25' MSLRKB: 55' MSLProducing Zone TopsKuparuk Sands top - 7539' MDKuparuk Sands bottom - 7560' MD6-1/8" Open hole 7,385' RKB To TD 7761' MD / 6289' TVDBase of 16" 62.58 lbs/ft conductor set @ 115' MD BPVBase of 9-5/8" 40 lbs/ft L80 Surface casing @ 2528' MD / 2268 TVD (12-1/4" hole size)BPV Installed & VR plugs removed11.0 ppg mud Diesel Fresh waterFresh water Base of 7" 26 lbs/ft Lb L-80 BTC at 7467' MD / 6053' TVDSeawater Seawater3.5" 9.3 lbs/ft L-80 EUE- 8rd set at 1590' MD Top of cement assessed between 6010' MD - 7162' MD calculatedBaker N-1 Cast Iron Cement Retainer set at 7385' MDCement Sand11.0 ppg mud 11.0 ppg mud 11.0 ppg mud 6For Internal Use only+Displace OA with 15 PPG Class G cement to 110% volume or squeeze pressure once the OA is displaced with 71.3 bbls of cement.+Displacement calculations-൞9-5/8” 40# L-80 x 7” 26# L-80 casing shoe at 2528’൞(.0282 bpf x 2528’) = 71.3 bbls൞(71.3 x 1.1) = 78.42 or 79 bbls of cement +Contingency is to perforate 7” liner below kill string and circulate cement into the OAOA CementSantos Placer #1Placer #1 OA CementGL: 25' MSLRKB: 55' MSLProducing Zone TopsKuparuk Sands top - 7539' MDKuparuk Sands bottom - 7560' MD6-1/8" Open hole 7,385' RKB To TD 7761' MD / 6289' TVDBase of 16" 62.58 lbs/ft conductor set @ 115' MD BPVBase of 9-5/8" 40 lbs/ft L80 Surface casing @ 2528' MD / 2268 TVD (12-1/4" hole size)BPV Installed & VR plugs removed11.0 ppg mud Diesel Fresh waterFresh water Base of 7" 26 lbs/ft Lb L-80 BTC at 7467' MD / 6053' TVDCement Cement3.5" 9.3 lbs/ft L-80 EUE- 8rd set at 1590' MD Top of cement assessed between 6010' MD - 7162' MD calculatedBaker N-1 Cast Iron Cement Retainer set at 7385' MDCement Sand11.0 ppg Mud 11.0 ppg mud 11.0 ppg mudContingency cement plug not approved as part of this sundry. Detailed contingencyplan must be approved by AOGCC. -bjm 7For Internal Use only+RIH with 2” coil and tag top of cement plug, start washing with jet swirl nozzle and Kcl from tag depth to surface, displacing out 11.0 ppg mud. Not to exceed 50% POOH speed of AV’s.+Displace tubing back to Diesel freeze protect once nozzle isenteringtubing at 1590’Coil Mud DisplacementSantos Placer #1Placer #1 Coil DisplacementGL: 25' MSLRKB: 55' MSLProducing Zone TopsKuparuk Sands top - 7539' MDKuparuk Sands bottom - 7560' MD6-1/8" Open hole 7,385' RKB To TD 7761' MD / 6289' TVDBase of 16" 62.58 lbs/ft conductor set @ 115' MD Base of 9-5/8" 40 lbs/ft L80 Surface casing @ 2528' MD / 2268 TVD (12-1/4" hole size)BPV Installed & VR plugs removedDiesel Fresh waterFresh water Base of 7" 26 lbs/ft Lb L-80 BTC at 7467' MD / 6053' TVDCement Cement3.5" 9.3 lbs/ft L-80 EUE- 8rd set at 1590' MD Top of cement assessed between 6010' MD - 7162' MD calculatedBaker N-1 Cast Iron Cement Retainer set at 7385' MDCement Sand11.0 ppg mud 11.0 ppg mud11.0 ppg mudTop of cement plug tagged at 7062' MDWash through settled mud until unable to to penetrate hard cement. -bjmAfter cleaning out mud, pressure test cement plug to 2500 psi.Provide 48 hrs notice for AOGCC opportunity to witness pressure test and cement tag.Notify AOGCC if cement tag depth is deeper than 7250' MD. -bjm 8For Internal Use only+RIH with 2” coil and tag top of cement plugat 7062’MD, start laying in 15 ppg Class G cement with required delaying agents for coil and cement ball drop nozzle.+Lay in cement from tag depth to 1650’MD+Cement calculations;൞7” 26# L-80 from 7062’ – 1650’ ൞(.0383 bpf x5412’) = 207 bbls+Drop ball and pump 20 bbl, 20# Biozan pill while backwashing tubing to surface.+Wait 24-hours and pressure test cement plug (AOGCCWitnessed)Coil Cement DisplacementSantos Placer #1Placer #1 Coil cement plugGL: 25' MSLRKB: 55' MSLProducing Zone TopsKuparuk Sands top - 7539' MDKuparuk Sands bottom - 7560' MD6-1/8" Open hole 7,385' RKB To TD 7761' MD / 6289' TVDBase of 16" 62.58 lbs/ft conductor set @ 115' MD Base of 9-5/8" 40 lbs/ft L80 Surface casing @ 2528' MD / 2268 TVD (12-1/4" hole size)BPV Installed & VR plugs installed in IA & OA valvesSeawater Fresh waterFresh water Base of 7" 26 lbs/ft Lb L-80 BTC at 7467' MD / 6053' TVDCement Cement3.5" 9.3 lbs/ft L-80 EUE- 8rd set at 1590' MD Baker N-1 Cast Iron Cement Retainer set at 7385' MDCement Sand11.0 ppg mudTop of cement plug tagged at 7062' MD11.0 ppg mud11.0 ppg mud Top of cement assessed between 6010' MD - 7162' MD calculated 9For Internal Use onlyTop cement plugSantos Placer #1+Top well off with cement by pumping down the kill string and taking returns up the IA until good cement to surface plus 20 bbls.+Cement calculations are as follows;൞Tubing is 3.5” 9.3# L-80 to 1590’൞(.0087 bpf x1590’)= 13.8 bbls (14 bbls)൞Casing displacement is7”26#from 1590’ to 1650’൞(.0383 x60’)= 2.3 bbls (3 bbls)൞IA displacement of3.5”9.3# L-80 tubing x7”26# L-80casing from Surface to 1590’൞(.0264 x 1590’) = 42 bbls൞(14 + 3 + 42) + 20 = 79 bbls of cement+Allow cement to cure, cut wellhead 6’ below ground levelper 20 AAC 25.120 and have State witness top of cement in tubing and annuli. Weld on the abandonment plate per 20 AAC 25.120, pull cellar and backfill hole.Placer #1 Surface plugGL: 25' MSLRKB: 55' MSLProducing Zone TopsKuparuk Sands top - 7539' MDKuparuk Sands bottom - 7560' MD6-1/8" Open hole 7,385' RKB To TD 7761' MD / 6289' TVDBase of 16" 62.58 lbs/ft conductor set @ 115' MD Base of 9-5/8" 40 lbs/ft L80 Surface casing @ 2528' MD / 2268 TVD (12-1/4" hole size)BPV Installed & VR plugs removedCement Fresh waterFresh water Base of 7" 26 lbs/ft Lb L-80 BTC at 7467' MD / 6053' TVDCement Cement3.5" 9.3 lbs/ft L-80 EUE- 8rd set at 1590' MD Top of cement assessed between 6010' MD - 7162' MD calculatedBaker N-1 Cast Iron Cement Retainer set at 7385' MDCement Sand11.0 ppg mud11.0 ppg mud11.0 ppg mudPermafrost cement is required for surface cement plug. -bjmPhoto document cement inside annulus, abandonment plate installed, backfilled hole. -bjm 1For Internal Use onlySantos Placer 1 LocationSuperseded 2For Internal Use onlySantos Placer 1 &# proposed Ice Road accessSuperseded 3For Internal Use only+The Placer 1 well was deemed not commercial in value by ConocoPhillips in 2004, plugged with a 7” cast iron cement retainer with a sand and cement plug on top. The open hole section was left with 11 lbs/gal mud left across it. The wellbore below the kill string was left loadedwith 11 lbs/gal, VR plugs installed in the IA and OA with a BPV in the tubing hanger.+Diesel was circulated down the kill string and up the IA for freeze protect. The OA was injected into at 2 bpm with Diesel freeze protect and displaced to the shoe.Current StatusSantos Placer #1Superseded 4For Internal Use only+This evaluation of the Placer 1 well shows that there is a single pay sand in the open hole interval. That is the Kuparuk Cand it is 5.6’ of net reservoir without the possibility of crossflow.+A variance is requested to 20 AAC 25.112 (a) (1) (C), 20 AAC 25.112 (a) (2) and 20 AAC 25.112 (b) to cement off the open hole section of the well. +Due to the7” casing plug and retainer at 7385’, along with the 3.5” tubing tail being at 1590’, it is not advisable to mill out the retainer with an expandable mill due to the risk of damaging unsupported coil in 7” casing. A rig would be required to pull the tubing and mill the retainer to cement off the open hole section.Waiver needed for Cementing open hole sectionSuperseded Agree. Density log indicates upper 15' of this 20-foot thick reservoir is tight and likely cemented by siderite. Density and gamma ray curves suggest only about 5' TVD of net d/ i 5For Internal Use only+Establish injection down OA with diesel for 1.5 times annular volume up to 1000 psi or 5 bpmOA Injection TestSantos Placer #1Superseded 6For Internal Use only+Displace OA with cement to 110% volume or squeeze pressure.+Contingency is to perforate 7” liner below kill string and circulate cement into the OAOA CementSantos Placer #1Superseded 7For Internal Use only+Displace mud down to cement plug with coiled tubing, swap well over to 3% Kcl.Coil displacementSantos Placer #1Superseded 8For Internal Use only+After well displacement, lay in cement plug to 300’ +/- below kill string+Allow to cure for 24 hours and pressure test. (State Witnessed)Coil Cement plugSantos Placer #1Superseded 9For Internal Use onlyTop cement plugSantos Placer #1+Top well off with cement by pumping down the kill string and taking returns up the IA until good cement to surface plus 10 bbls.+Allow cement to cure, cut wellhead 6’ below ground level and have State witness top of cement in tubing and annuli. Weld on the abandonment plate, pull cellar and backfill hole.Superseded 1 McLellan, Bryan J (OGC) From:Brake, Jared (Jared) <Jared.Brake@contractor.santos.com> Sent:Wednesday, October 16, 2024 4:52 PM To:McLellan, Bryan J (OGC) Cc:Senden, Robert (Ty); Davis, Rachel (Rachel) Subject:RE: Placer 1 (PTD 204-014) P&A sundry questions Attachments:Placer 1 T13871_MUDLOG_MD.pdf; Placer 1 P&A .pdf Bryan, Attached are the following items requested below. Please let me know if there is anything else required. 1. A cement log does not appear to have been ran to prove tops of cement behind the intermediate casing. The well was taking losses prior to pumping the Intermediate cement on 3/10/2004, the plug was successfully bumped, and cement placed away, but estimated tops are from 7162’ – 6010’ MD as per drilling reports. 2. Attached is a copy or the Mud Log, however it does not appear to have had any porosity logs ran on this well across the Intermediate section. 3. Cement types and volumes have been added into the presentation attached. Jared Brake Well Integrity & Well Intervention Engineer m: 1 (832) 330-4359| e: brajg@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, October 3, 2024 1:47 PM To: Brake, Jared (Jared) <Jared.Brake@contractor.santos.com> Subject: ![EXT]: Placer 1 (PTD 204-014) P&A sundry questions Jared, Could you provide the following in support of the P&A sundry application: SCMT used to determine TOC outside 7” casingLit hology and mudlog for hole section between surface casing shoe and TOC behind 7” casingC ement types, volumes and volume calculations. Bryan CGBANNERINDICATOR Jared, Could you provide the following in support of the P&A sundry application: 1. SCMT used to determine TOC outside 7” casing 2. Lithology and mudlog for hole section between surface casing shoe and TOC behind 7” casing 3. Cement types, volumes and volume calculations. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 2 Bryan.mclellan@alaska.gov +1 (907) 250-9193 1 Regg, James B (OGC) From:Regg, James B (OGC) Sent:Monday, November 27, 2023 11:45 AM To:Davis, Rachel (Rachel) Subject:RE: Placer 1 (PTD #204-014) & Placer 3 (PTD #215-204) Well Inspection Clarification To reiterate what I stated to Robert Tirpack during our 11/21 phone conversaƟon, follow the regulaƟons that were acƟve at the Ɵme of suspension. Only reason for a winter inspecƟon would be if you cannot check well pressures during the summer inspecƟon. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907‐793‐1236 From: Davis, Rachel (Rachel) <Rachel.Davis@santos.com> Sent: Monday, November 27, 2023 11:07 AM To: Regg, James B (OGC) <jim.regg@alaska.gov> Subject: Placer 1 (PTD #204‐014) & Placer 3 (PTD #215‐204) Well Inspection Clarification Hello, Santos would appreciate some clariﬁcaƟon for the Placer 1 and Placer 3 well inspecƟons to help ensure we remain in compliance. It is our understanding that we would follow the Guidance BulleƟn/RegulaƟons regarding suspended wells that were acƟve at the Ɵme of approval. Below is the current status of the wells: Placer 1 A suspension renewal was submiƩed by ASRC and approved on 3/1/22 – valid for 5 years unƟl 3/1/27. A well inspecƟon was arranged and completed with ASRC on 6/22/21. Placer 3 A Sundry was submiƩed and approved to Suspend on 3/17/16 ‐ valid for 10 years unƟl 3/17/26. A well inspecƟon was arranged and completed with ASRC on 6/22/21. If we follow the regulaƟons that were acƟve at Ɵme of suspension approval, we will take the following steps for both Placer 1 and Placer 3: A well inspecƟon will be completed within 24 months before September 30th of every calendar year ending in 0 or 5. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2  NoƟce will be submiƩed via web noƟce to the AOGCC 10 days prior to inspecƟon.  Within 30‐days aŌer the well inspecƟon, a Report of Sundry 10‐404 will be submiƩed.  We will submit the 10‐403 Suspension Renewal ApplicaƟon within 60 days of suspension expiraƟon, ensuring the latest well inspecƟon takes place within 24 months of suspension expiraƟon. Since both Placer 1 and 3 are remote, it is our understanding that two inspecƟons would be required, one during the winter and a second inspecƟon during the summer. Appreciate your Ɵme and please let me know if you have any quesƟons! Thank you, Rachel Davis Technical Assistant t:1 (907) 375‐4678 | e: rachel.davis@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter Santos Ltd A.B.N. 80 007 550 923 Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may be confidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy. 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Date Inspected: 6/I2/2021 - LJ Inspector: Brian Bixby ' ` Type of|nspection: Subsequent - Well Name: PLACER1 _ Date AOG[[Notified: 6/16/2021 Permit Number: 2040140 - Operator: AJR[Exploration, LLC Suspension Approval: Sundry _ # 304'105 ' Operator Rep: Erik Kenning SuspensionOate: 4/11/2004 ~ Wellbore Diagram Avail? Location Verified? Photos Taken? |fVerified, How? GPS Offshore? El Well Pressures (psi) Tubing: � /4: OA: VVeUheadCondidon Didn't Look atthe wellhead asitwas covered. Condition of Cellar Has some wood initbut looks tobeclean. Surrounding Surface Condition Good Comments Fluid in Cellar? L] 8PV|nstaUed? 1-1 VR Plug(s) installed? LJ Supervisor Comments � Photos (4)attached. Operator not prepared tocheck well pressures during this inspection. I/ Thursday, July lS'Z02l Suspended Well Inspection — Placer #1 (ASRC Exploration LLC) PTD 2040140 AOGCC Inspection #susBDB210623063806 Photos by AOGCC Inspector B. Bixby 6/22/2021 2021-0622_Suspend_Placer- 1photos_bb.docx Pagel of 2 x _, t { a� ti 2021-0622_Suspend_Placer-l_photos_bb.docx Page 2 of 2 THE STA'L'E °fALASKA GOVERNOR MIKE DUNLEAVY March 2, 2021 Ms. Elena M. Romerdahl Perkins Coie 1029 West Third Avenue, Suite 300 Anchorage, AK 99501-1981 Re: Docket Number:OTH-21-005 Request to Accept 2018 Site Inspection Report Dear Ms. Romerdahl: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.claska.gov 2cq -o1q By letter dated February 25, 2021, you requested, on behalf of ASRC Exploration, LLC (AEX), that the Alaska Oil and Gas Conservation Commission (AOGCC) accept the site inspection reports included with the February 25' letter in lieu of the site inspections that the AOGCC's notice of violation (NOV) letter dated February 4, 2021, required to be conducted within 14 -days of AEX's receipt of the NOV letter. AOGCC has reviewed your submitted reports and request and determined that the submitted information is sufficient to meet the needs of the site inspection that was required this winter. However, the submitted information is not sufficient to meet the suspended well site inspection requirements of 20 AAC 25.110 and as such AEX is still required to conduct AOGCC witnessed suspended well site inspections once the well sites are snow- and ice -free this year. Questions regarding this letter should be directed to Dave Roby at dave.robvaa alaska.eov or 907- 793-1232. Sincerely, DIgUlynyn.a by Jeremy ,.pd. M. Price °ar'01A302 13%�:36-09'W' Jeremy M. Price Chair, Commissioner PeRKINSCOIe March 26, 2021 VIA ELECTRONIC MAIL Commissioner Jeremy Price, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Attn: Jody Colombie, iodv.colombiena,alaska.gov Re: Docket No. OTH-21-005 Analysis of Violation Dear Commissioner Price: 1029 West Third Avenue • -1907 279 8561 Suite 300 O .1.907 276 3108 Anchorage. AK 99501.1981 perkmscoiecom Elena M. Romerdahl ERomerdahl@perkinscoic.com D. +1.907.263.6914 F. +1.907.263.6428 Attached please find an analysis prepared by ASRC Exploration, LLC ("AEX") in response to the Notice of Violations in Docket OTH-21-005 ("Notice") on February 15, 2021 regarding AEX's failure to comply with the requirements in 20 AAC 25.110(e) for suspended wells for the Placer 1 and Placer 3 wells. As requested in the Notice, the attached analysis discusses how the violations described in the Notice occurred and what AEX plans to do in the future to ensure such violations do not happen again. We hope that the attached satisfies the Commission's request. If we can provide any additional information, please let me know. Respectfully, Elena Romerdahl Counsel for AEX Analysis of Violations Docket Number OTH-21-005 As requested by Commissioner Price in the February 4, 2021 Notice of Violation (the "Notice"), ASRC Exploration, LLC ("AEX") provides the following discussion of how the violations described in the Notice occurred and what AEX will do in the fixture to ensure such violations do not happen again AEX is a small subsidiary of Arctic Slope Regional Corporation (ASRC) that operates one unit on Alaska's North Slope, the Placer Unit, which contains three wells: Placer #1, Placer #2, and Placer #3. When AEX acquired and took over as operator of record for the Placer Unit from ConocoPhillips Alaska, Inc. in June 2010, the unit contained two wells that had been drilled by BP: Placer #1 and Placer #2. Placer #1 had been suspended on April 11, 2004 and an initial suspended well inspection had been conducted on August 13, 2004. AEX successfully drilled the Placer #3 well in 2016 with the help of service companies and contractors including ASRC subsidiary ASRC Energy Services Alaska, Inc. ("AES") and then suspended Placer #3 on March 17, 2016. An initial suspended well inspection was conducted on August 4, 2016. On August 23 and 24, 2018, representatives from AEX and AES completed an inspection of the Placer Unit that included inspection of Placer #1 and Placer #3. This inspection confirmed that the Placer #1 and Placer #3 wellheads were secure and that the areas surrounding the wells were in good condition. AEX submitted the report that AES produced following that inspection to the Commission on February 25, 2021. As described in the Notice, AEX failed to submit suspended well inspection reports prior to September 30, 2010, 2015, and 2020 for Placer #1, failed to submit a well inspection report prior to September 30, 2020 for Placer #3, and failed to apply for a suspension renewal by December 31, 2010 for Placer #1 as required under 20 AAC 25.110. After AEX assumed operatorship of the Placer Unit it contracted with AES to complete work required to satisfy State of Alaska regulatory requirements, including the requirements under 20 AAC 25.110 for maintaining wells in suspended status. Although AEX has utilized AES to complete work required to comply with the Placer Unit Plan of Development and AOGCC regulations, the Commission's Notice alerted AEX to the fact that additional oversight and monitoring by AEX is required to ensure compliance with all of the Commission's suspended well requirements. In order to ensure that AEX complies with all suspended well requirements under 20 AAC 25.110 going forward, AEX will provide its internal regulatory compliance lead with dedicated training on AOGCC requirements applicable to the Placer Unit, including but not limited to suspended well requirements. AEX is also in the process of implementing a compliance tracking system to calendar compliance deadlines for the suspended wells going forward, including reminders to inform the Commission of upcoming inspections. This system will ensure that AEX is aware of all regulatory deadlines and able to satisfy all regulatory requirements in a timely manner. AEX will share this system with AES but will maintain ownership and control over the system to ensure that direct accountability for satisfying AOGCC requirements remains within AEX going forward. On March 26, 2021, AEX informed Commission staff that the inspection of Placer #1 and Placer #3 required by the Notice will be conducted this summer by Oil Search Alaska (OSA) on behalf of AEX. AEX and OSA will be in regular communication with the Commission prior to and after this inspection to ensure that all requirements under 20 AAC 25.110 are satisfied and that AEX has addressed any outstanding concerns the Commission may have. AEX appreciates the Commission's attention to this matter and assures the Commission that it is committed to ensuring that AEX complies with all AOGCC requirements going forward for the duration of its time as operator of the Placer Unit. If AEX can provide the Commission with any additional information or answer any questions, please let us know. -2- Colombie, Jody J (CED) From: Romerdahl, Elena M. (Perkins Coie) <ERomerdahl@perkinscoie.com> Sent: Friday, March 26, 2021 3:58 PM To: Colombie, Jody J (CED); Roby, David S (CED) Subject: Docket No. OTH-21-005 Analysis of Violations Attachments: Docket No. OTH-21-005 Analysis of Violations.pdf Categories: Yellow Category Jody and Dave, Attached please find AEX's written analysis of the violations identified in Docket No. OTH-21-005. Thank you again for the additional extension. Please let me know if we can provide any additional information. Elena Elena Romerdahl I Perkins Cole LLP PARTNER 1029 West Third Avenue Suite 300 Anchorage, AK 99501-1981 D. +1.907.263.6914 M. +1.202.487.8657 E. ERomerdahl(fterkinscoie.com From: Roby, David S (CED) <dave.roby@alaska.gov> Sent: Wednesday, March 24,20215:03 PM To: Romerdahl, Elena M. (ANC) <ERomerdahl@perkinscoie.com> Cc: Colombie, Jody J (CED) <jody.colombie@alaska.gov> Subject: RE: ASRC Letter Hi Elena, Yes I think an extension to Friday would be fine. Regards, Dave Roby 907-793-1232 CONFIDENTIALITY NOTICE This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at 907- 793-1232 or dave.robv@alaska.eov. From: Romerdahl, Elena M. (Perkins Coie) <ERomerdahl@perkinscoie.com> Sent: Wednesday, March 24, 20214:58 PM To: Roby, David S (CED) <dave.robv@alaska.gcrv> Cc: Colombie, Jody J (CED) <iodv.colombie@alaska.sov> Subject: RE: ASRC Letter Dave, I apologize, I think there may have been a miscommunication with my client regarding who would be submitting the written explanation last week. Would it be possible to request an extension until Friday to provide that analysis to you? Again, I apologize for the late response. Elena Elena Romerdahl I Perkins Coie LLP PARTNER 1029 West Third Avenue Suite 300 Anchorage, AK 99501-1981 D. +1.907.263.6914 M. +1.202.487.8657 E. ERomerdahlrnloerkinscoie.com From: Roby, David S (CED) <dave.robv@alaska.gov> Sent: Wednesday, March 24, 20214:20 PM To: Romerdahl, Elena M. (ANC) <ERomerdahI6Dperkinscoie.com> Cc: Colombie, Jody J (CED) <iodv.colombie@alaska.gov> Subject: RE: ASRC Letter Elena, Jody Colombie asked me to respond to your email below. In our notice of violation letter (see attached) we had three requirements for ASRC. First was to do a site visit within 2 weeks of receipt of the letter, we later waived this requirement via the letter from Commissioner Price dated March 2n' after we were provided documentation of site visits ASRC had conducted in the past few years. The second was to conduct an AOGCC witnessed suspended well site inspection of the locations once the snow and ice has cleared from the locations, this is still pending as you noted in your email below. The third thing was within 30 days of receipt of the letter (an email from Jody to you dated February 17th [see attached] set the due date for this as March 18th) ASRC had to submit an explanation of how the violations occurred and what they were doing to ensure they wouldn't happen in the future. We have not received third item yet, even though it was due last week, and as such we cannot commit to what if any future action we may take on this matter at this time. Regards, Dave Roby 907-793-1232 CONFIDENTIALITYNOTYCE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at 907- 793-1232 or dave.robv@alaska.¢ov. Sent from myiPhone Begin forwarded message: From: "Romerdahl, Elena M. (Perkins Coie)" <ERomerdahl@perkinscoie.com> Date: March 24, 2021 at 12:25:37 PM MST To: "Colombie, Jody J (CED)" <jody.colombie@alaska.gov> Subject: RE: ASRC Letter Hi Jody, Our understanding based on Commissioner Price's March 2, 2021 letter (attached) is that the NOV issued in Docket OTH-21-005 will be resolved once an inspection is completed this summer as long as all well site inspection requirements under 20 AAC 25.110 are satisfied. Would it be possible to obtain confirmation that our understanding is correct? Elena Elena Romerdahl ) Perkins Cole LLP PARTNER 1029 West Third Avenue Suite 300 Anchorage, AK 99501-1981 D. +1.907.263.6914 M. +1.202.487.8657 E. ERomerdahlAAperkinscoie.com From: Romerdahl, Elena M. (ANC) Sent: Tuesday, March 2, 20211:57 PM To: 'Colombie, Jody 1 (CED)' <lodv.colombie@alaska.gov> Subject: RE: ASRC Letter Thanks, Jody. We appreciate the quick response to this request. I will pass this along to ASRC. Elena Elena Romerdahl ) Perkins Cole LLP PARTNER 1029 West Third Avenue Suite 300 Anchorage, AK 99501-1981 D. +1,907.263.6914 M. +1.202.487.8657 E. ERomerdahlGDoerkinscoie.com From: Colombie, Jody 1 (CED) <jody.colombie@alaska.gov> Sent: Tuesday, March 2, 20211:46 PM To: Romerdahl, Elena M. (ANC) <ERomerdahl@perkinscoie.com> Cc: Colombie, Jody J (CED) <jodv.colombie@alaska.gov> Subject: ASRC Letter Please see attached. Jody J. Colombie AOGCC Special Assistant Alaska Oil and Gas Conservation Commission State of Alaska 333 West 7h Avenue Anchorage, AK 99501 Phone Number: 907-793-1221 Email: iodv.colombie(a)alaska.eov NOTICE: This communication may contain privileged or other confidential information. If you have received it in error, please advise the sender by reply email and immediately delete the message and any attachments without copying or disclosing the contents. Thank you. NOTICE: This communication may contain privileged or other confidential information. If you have received it in error, please advise the sender by reply email and immediately delete the message and any attachments without copying or disclosing the contents. Thank you. NOTICE: This communication may contain privileged or other confidential information. If you have received it in error, please advise the sender by reply email and immediately delete the message and any attachments without copying or disclosing the contents. Thank you. PeRKINSCOIe February 25, 2021 VIA ELECTRONIC MAIL Commissioner Jeremy Price, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Attn: Jody Colombie, iodv.colombie(&alaska.gov 1029 West 1 hard Avenue • d 907 279 8561 Sate 300 O -1907 276 3108 Anchorage. AK 99501 1981 perkmscoie corn Re: Docket No. OTH-21-005 Request to Accept 2018 Site Inspection Report Dear Commissioner Price: Elena M. Romerdahl ERomerdahl@perkinscoie.com D. +1.907.263.6914 F. +1.907.263.6428 ASRC Exploration, LLC ("AEX") received the Notice of Violations in Docket OTH-21- 005 ("Notice") on February 15, 2021 regarding AEX's failure to comply with the requirements in 20 AAC 25.110(e) for suspended wells for the Placer 1 and Placer 3 wells (the "Wells"). The Notice requests that AEX submit an explanation regarding how the described violations occurred and what AEX will do in the future to ensure such violations do not happen again within 30 days of receipt of the Notice. The Notice also requires AEX to conduct a site inspection of the Wells within 14 days and a more thorough suspended well site inspection next year as soon as the site is free of snow and ice. On February 16, I contacted Ms. Colombie to inform her that AEX had just received the Notice on February 15 and request an extension of time to comply with the Notice. On February 17, Ms. Colombie confirmed that the deadline to submit the written explanation was extended to March 18 and that the deadline to complete the site inspection was extended to March 13, 2021. Upon receipt of the Notice last week, AEX began to gather information regarding the logistics and approvals required to complete the requested site inspection. A list of the requirements for conducting an inspection is attached as Exhibit A. To summarize, conducting a site inspection for the Wells will require AEX to locate a helicopter in the Deadhorse area with availability to transport those conducting the inspection from tundra take -off access locations (approximately 50 miles from Deadhorse) to the Wells; obtain required approvals and permits from the North Slope Borough, U.S. Fish & Wildlife February 25, 2021 Page 2 Service, adjacent operators, and leaseholders along the access route; and plan logistics for all personnel participating in the inspection, including ensuring that all personnel comply with COVID-19 restrictions applicable to intrastate travel to the North Slope. As noted in Exhibit A, AEX is in the process of preparing for a site inspection but anticipates that obtaining required permits will take a minimum of 30 days and likely could take longer. Although AEX has not provided the Commission with inspection reports as required under 20 AAC 25.110, AEX did complete a site visit and inspection of the Wells in September 2018. A copy of the inspection report prepared by AEX following that inspection (the "2018 Inspection Report") is attached hereto as Exhibit B. AEX did not provide notice to the Commission within 10 days of completing the inspection and an opportunity for Commission inspectors to accompany AEX as required under subsection (e), and did not provide the Commission with a Report of Sundry Well Operations as required under subsection (f). However, the 2018 Inspection Report does provide a description of the condition of the wellhead and surface location; a plat showing the location of the suspended wells; and photographs clearly showing the condition of the wellheads and surrounding location as required under subsection (f). The 2018 Inspection Report does not include an update of information and documentation required under 20 AAC 25.110(b), but AEX can confirm that none of the 20 AAC 25.110(b) information has changed.' A wellbore schematic is attached as Exhibit C. AEX also inspected the Placer #1 wellhead during the 2015-2016 drilling operation of the Placer #3 well. AEX had constructed an ice -pad in the vicinity of Placer #1 for staging equipment, which allowed for a close inspection of the Placer #1 wellhead. A copy of the photographs taken during that inspection are attached as Exhibit D. In light of the timeline for obtaining required approvals and permits and securing transportation, the logistical difficulties associated with a winter inspection and COVID- 19 restrictions, and the resulting costs associated with conducting an inspection of the Wells by March 13, AEX respectfully requests that the Commission accept the 2018 Inspection Report as supplemented with updated 20 AAC 25.110(b) information in lieu of requiring a site inspection by March 13. If the Commission determines that an additional site inspection is required to satisfy the requirements of 20 AAC 25.110 for the Wells, AEX requests that the Commission permit that inspection to take place during the summer to AEX farmed into BP's working interest to drill Placer #1 & #2 in 2004. AEX took over the operatorship of the Placer Unit in 2010. No changes have been made to the Placer # 1 Well since suspension in 2004. February 25, 2021 Page 3 allow for time to obtain required permits and authorizations, secure helicopter transportation to the Wells, and maximize the amount of obtainable information. AEX appreciates the Commission's consideration of this request. If we can provide any additional information to support this request, please let me know. Respectfully, Elena Romerdahl Counsel for AEX RA.,& Uo,, LLP EXHIBIT A Placer Wells Site Inspection Requirements 1. Secure transportation in Deadhorse for transport to and from Wells from tundra take -off access points. o Access via tundra (not preferred): The possible tundra take -off access locations are approximately 50 road miles from Deadhorse. The area where the Wells are located is approximately 7 miles across the tundra to existing gravel roads. The existing gravel road ends at Mustang Pad. • Use of Rolligon during winter snow cover will likely cause tundra damage, which AEX would like to avoid at all costs. o Access via Helicopter (preferred): ■ Helicopter is required to avoid tundra damage while accessing Placer#I & Placer -#3 wellheads during winter season. NOTE: Securing helicopter in Deadhorse will likely require at least 30 days advance notice. o General Requirements (Tundra or Helicopter access): ■ Prepare and submit application for a cultural site clearance of access route from North Slope Borough for Traditional Land Use Inventory. ■ Prepare and submit application for North Slope Borough Land Management Regulations permit. • NOTE: the NSB generally requests that these permits are submitted a minimum of 30 days in advance. ■ AEX will require Letters of Non Objection from all lease owners prior to accessing Placer wellheads. ■ Obtain any USF&WS clearances required due to presence of polar bear dens along route (if applicable). • NOTE: obtaining USF&WS clearance for route adjacent to polar bear dens would likely require more than 30 days' notice. ■ Discuss and coordinate site access with other operators in area. EXHIBIT A ■ Obtain permission to use existing infrastructure such as the Mustang pad (closest staging location to Placer wells; previously used during Placer #3 drilling operations) for staging equipment (if applicable) to off-road tundra access point (if necessary) 2. Plan logistics for all personnel involved. o Travel to and from Deadhorse o Lodging o Seasonal protective gear o Safety training for winter travel to Wells 3. Confirm compliance with state and local COVID-19 restrictions applicable to intrastate travel to Deadhorse, AK. o 14 -day temperature log required prior to departure o COVID-19 testing upon arrival in Deadhorse o Self -isolation until test results received -2- ASRC ENERGY SERVICES Aleaka, Inc. Memorandum Date: September 17, 2018 To: Erik Kenning, ASRC, Land Management and Enforcement From: Stewart Seaberg, AES, Regulatory and Technical Services Subject: Placer Unit Reconnaissance August 23, 2018 Trip Report Erik Kenning of ARSC Exploration (AEX) and Stewart Seaberg of ASRC Energy Services Alaska, Inc. (AES) flew to Deadhorse on the afternoon of August 22 to conduct Placer Unit reconnaissance surveys scheduled for August 23 and 24. The purpose of the surveys was to: • revisit and inspect Alaska Department of Natural Resources (ADNR) August 2016 vegetation plots on the Placer Well #3 Ice Road • inspect Placer #1 and Placer #3 wellheads • examine Placer Well locations to place potential ice and gravel pads to support an Early Production Facility (EPF) • evaluate potential ice road routes from Mustang Pad and Drill Site 3S (DS -35) to support EPF • evaluate potential gravel road routes from Mustang Pad and DS -3S to support long-term oil and gas production and development After arriving in Deadhorse at approximately 1630, we checked into our rooms at the Little Red Services (LRS) camp. After LRS camp orientation, we contacted our Pilot Dave McKnight and met him at the Pathfinder Aviation hangar at the Deadhorse airport, where we went over our survey plan. We agreed to have a weather check the next morning (Aug 23) at 0730 to plan an appropriate take -off time. The following provides a chronological summary of the survey on August 23: 0715 — Pathfinder Pilot McKnight indicated that weather was not favorable and the ceiling was too low to safely conduct the Placer Unit Survey area. 0815 — Pilot McKnight reported the ceiling remained too low; however, the weather forecast anticipated improvement by 1000. He remained at the hangar to monitor the weather from the airport. 0915 — Pilot McKnight called to inform us that the ceiling had lifted and it was now safe for helicopter operation. 0935 — Assisted the pilot in pushing the helicopter out of the hangar and on to the tarmac. While waiting for fuel delivery to the helicopter, we went over helicopter safety and operations briefing. We discussed our survey objectives for the day. The pilot uploaded the GPX files sent the previous day, but the files were not compatible with the pilot's GPS. 1026—Started up helicopter. 1031— Helicopter lift-off from Deadhorse Airport. 1055 — Landed at Alaska Department of Natural Resources (ADNR) Plot 3 on road (coordinates in decimal degrees: latitude 70.29, longitude -150.27) to inspect ADNR tundra vegetation plot established 3900 C Street, Suite 700, Anchorage, Alaska 99503 • (907) 339-6200 • fax (907) 339-5475 • www.asrcenergy.com Exhibit B - 1 of 12 September 17, 2018 ASRC Exploration in August 2016 (see Figure 1). While flying to Plot 3, the ice road route was not apparent from the air. Close inspection at the on road plot coordinates noted some minor tussock compaction and disturbance (Photo 1). Tussock disturbance appeared fairly minor and green grasses and/or sedges were growing on the sides and tops of the disturbed tussocks (Photo 2). Photo 1: Plot 3 on road - Minor tussock disturbance Photo 2: Plot 3 on road -Tussocks showing revegetation The on road plot was located on an elevated mound covered by tussocks that appeared to be two or three feet above the elevation of the surrounding tundra. This could explain why this location exhibited signs of tundra disturbance during the Alaska Department of Natural Resources (ADNR) site visit in August of 2016. Although some evidence of tundra disturbance remain (primarily tussock compaction and shearing), the on road site appears very similar to the adjacent areas beyond the footprint of the ice road. 15597.001 / 18-105 2 Rev. 1 Exhibit 8 - 2 of 12 September 17, 2018 ASRC Exploration Figure 12018 Placer Well Field Survey Area NnD .Ab EIMR.roZ.4 PES RTS Is Im OOl.mzd. OWl3 is 15597.001 / 18-105 3 Rev. 1 Exhibit B - 3 of 12 September 17, 2018 ASRC Exploration 1125 — Departed from Plot 3 1133 — Landed at ADNR Plot 1 on road (coordinates Latitude 70.34 Longitude -150.43). Inspection of this area indicated the coordinates for Plot 1 in the ADNR report from Aug 4, 2016 site inspection were transposed. Our inspection found the ADNR coordinates for the off road plot were actually the on road plot and ADNR coordinates for the on road plot were located off the ice road footprint. The ADNR on road plot was located in an area elevated above the surrounding area and covered by tussocks. This site showed less signs of tussock disturbance than Plot 3. There was some indication of tussock compaction and tussock vegetation impacts (Photo 3), but this site appeared to be revegetating well (Photo 4). Photo 3: Plot 1 on road plot -Tussocks show some signs of minor disturbance Photo 4: Plot t on road - Tussocks revegetating well 15597.001 / 18-105 4 Rev. 1 Exhibit B - 4 of 12 September 17, 2018 ASRC Exploration 1207 - Depart Plot 1 1209 - Landed at Placer Well #1 and conducted an inspection of Placer Well #1 wellhead and the surrounding area. Fabric cover over wellhead appeared in good shape and the required sign is hanging from the wellhead (Photo 5). The well cellar consisted of an upright 60 -inch corrugated metal pipe (CMP). Approximately three feet of the CMP is above the ground level. The area around the well consisted of patterned ground wetlands with well -drained tundra polygons and wet swales between the polygons. Photo 5: Placer Well #1- Placer wellhead The area surrounding the Placer Well #1 is relatively flat with no fish -bearing lakes or steams in close proximity to the wellhead. There do not appear to be any terrain features or environmental resources that would limit the placement or orientation of future ice pads or permanent gravel pads in the vicinity of the Placer Well #1. 1231- Departed Placer Well #1 1234 - Landed at Placer Well #3 and conducted an inspection of Placer Well #3 wellhead and surrounding area (Photo 6). The fabric covering the wellhead was attached to the wellhead and cellar, but was worn and ripped in several places. The fabric at the top of the wellhead was ripped, exposing the top of the wellhead. A 5 -gallon bucket currently covers the top of the wellhead. The fabric skirt that is attached to the mud line cellar with a pair of ratchet straps remains secure. There were several rips in the fabric skirt above the cellar (Photo 7). The cellar consists of a large steel pipe with a serrated bar grating placed on top of the steel pipe. The Placer Well #3 sign is attached to the outside of the cellar. 15597.001/18-105 5 Rev.I Exhibit B - 5 of 12 September 17, 2018 ASRC Exploration Photo 6: Placer Wellhead #3- Placer wellhead Photo 7: Placer Wellhead #3- Rip In the fabric skirt 15597.001 / I8-105 6 Rev. I Exhibit B - 6 of 12 September 17, 2018 ASRC Exploration A fish -bearing tributary of the Miluveach River flows west of the Placer #3 well site. A rangefinder measured the distance between the stream and the wellhead. The Placer #3 Wellhead was 197 meters (646 feet) from the downstream point and 176 meters (577 feet) from the upstream point of the stream (see Figure 2). Mitigation Measure 1.c. of the North Slope Areawide Lease Sale prohibits the siting of all infrastructure within a 500 -toot setback from all fish -bearing streams. This setback will need to be maintained or an exception to the mitigation measure would need to be obtained from the Director of the Alaska Department of Natural Resources, Division of Oil and Gas. The terrain surrounding Placer Well #3 consists of relatively flat patterned ground tundra. The area to the west and north appears to gradually slope downward towards the unnamed stream. The slope becomes steeper in the areas closer to the stream. This should be a consideration when planning well pad location and orientation. Well pads should attempt to avoid areas west and northwest of the Placer Well #3 to avoid the need for a thicker pad and to avoid encroachment into the fish -bearing stream buffer. 15597.001 /18-105 7 Rev. 1 Exhibit B - 7 of 12 September 17, 2018 ASRC Exploration Figure 2 Placer Well #3 Stream Setback N 'I I I sash ' % 72S ft I 577 ft ` Placer I , % r, Proposed Pipeline -;; Well Location QAEX ASRC EXPLORATION Proposed Road 500 ft Fish -Bearing Stream Buffer PLACER WELL#3 STREAM SETBACK Proposed Pad AEx Placer Well Field Survey Placer Well Remnnaissance Tnp Report SCALE: FIGURE' 0 150 30o z Fee NPD 83 A.a SI,WAnue Za.u4 AF_RT311L'11..e17md WIVV", 15597.001 / 18-105 8 Rev. 1 Exhibit B - 8 of 12 September 17, 2018 ASRC Exploration 1314 - Depart Placer #3 1320 - Landed near the ice road crossing of the only documented fish -bearing stream in the ice road corridor. Since the ice road alignment was not visible from the air, the location of the stream crossing site was not readily apparent. The stream was inspected upstream and downstream of the presumed crossing site and no disturbance or evidence of the ice road crossing was observed. 1343 — Departed ice road crossing 1351 — Arrived at Mustang Road 11 (MR -11), the only proposed Mustang Road crossing site of a fish - bearing stream. The site appeared to be a good site for a crossing because of the relatively narrow stream channel (approximately 5 feet wide and incised approximately 2-3 feet deep) (Photos 8 and 9). Since the channel was well defined and relatively narrow at the crossing site, it appeared to be a good location for a culvert crossing. Photo 8: MR -17 Crossing Site—Looking Upstream 15597.001 / 18-105 9 Rev. 1 Exhibit B - 9 of 12 September 17, 2018 ASRC Exploration Photo 9: MR -11 • Crossing Site - Looking Downstream 1405 - Departed MR -11 1410 — Arrived at Mustang Road 10 (MR -10) to inspect the proposed road -crossing site of this linear waterway. The proposed crossing site appeared to be very wet with open water and soft organic substrate. An alternative site 80 to 100 meters east of the proposed site (latitude 70.33734, longitude - 150.39139) was much better suited for a stream crossing (Photo 10). There was not open water at this alternative location, although the area would likely be inundated during break up and high water events. Photo 10: MR-10-Aerialvim of water body crossing location. The red line indicates the proposed crossing area. The blue line indicates the alternative crossing area. 15597.001 / 18-105 10 Rev. 1 Exhibit B - 10 of 12 September 17, 2018 ASRC Exploration 1428 — Departed MR -10. After departing MR -10, the helicopter conducted aerial reconnaissance surveys of the previously used ice road route, the proposed pipeline route, and the proposed road route between the Mustang Pad and the Placer Well #3. A reconnaissance surveys of the proposed road and pipeline between Placer #3 and Drill Site 3S (DS -3S) was also conducted. When retuning to the Mustang Pad a single 55 -gallon drum (coordinates latitude N 70.31647, longitude W 150.37729) was located and inspected (Photo 11). The drum is located near the winter 2015/16 ice road. The drum was identified and inspected during ice road construction in January of 2016. As noted in 2016, it appears that the drum has been at this location for several years. The drum has been drained of its contents, and the plug/bung is missing. A small amount of water in the drum was likely a result of blowing snow during the winter. Photo 11: Abandoned Drum - (coordinates latitude N 70.31647, longitude W 150.37729) 1509 — Departed Mustang Pad Area 1536 — Arrived at Deadhorse Airport to conclude the reconnaissance survey. The survey was successful in providing an overview of potential road and pipeline routes that could support the development and production from the Placer #1 and #3 wells. All of the proposed road and pipeline routes between the Placer Well locations and the Mustang Pad appear to be feasible. The surveys did not identify any unique features along the pipeline or the gravel road routes that would eliminate any of these routes from further study. Current regulatory constrains that could potentially affect the alignment of the gravel road and pipeline include a 500 -foot setback from fish -bearing streams. Currently the Miluveach River and an unnamed tributary are the only documented fish bearing streams in the survey area. ADNR Lease Mitigation Measure A.l.c requires all infrastructure to maintain a 500 -foot setback from these streams, as well as all fish bearing lakes. 15597.001 / 18-105 11 Rev. 1 Exhibit B -11 of 12 September 17, 2018 ASRC ExDloration This 500 -foot fish stream setback would also apply to the Placer Well #3 Pad. The Placer #3 wellhead is a minimum of 600 feet from the unnamed tributary to the Miluveach River. Pad design and orientation should attempt to avoid the 500 -foot setback, to the extent practicable. Locating infrastructure within the buffer requires AEX to demonstrate that locations within the buffer are environmentally preferred. Although the likelihood of a polar bear Benning along the Miluveach River would be low, the terrace along the east side of the Miluveach River is identified as an area supporting potential polar bear denning habitat. The US Fish and Wildlife Service requires a 1.6 KM (1.0 mile) "operational exclusion zone" around any active polar bear den. Should an active polar bear den be documented in the area, the use of the road could be restricted if portions of the road are within a mile of the active den. The potential road alignment and pipeline alignment between Placer Well sites and DS -3S did not appear to support any unique features that would eliminate either of these routes from further study. The route to DS -3S crosses two unnamed stream that have not been documented as fish bearing streams. In summary all proposed road and pipeline alignments surveys in August 2018 appear to be viable alternatives. Minor modifications or alignment shift may be necessary to avoid sensitive habitats, cultural resource sites, challenging terrain or to comply with regulatory agency recommendations. 15597.001/18-105 12 Rev.I Exhibit B - 12 of 12 0 Placer 1 Actual - Suspension Schematic Exploration Well - Confidential Conductor: Pjf 16", 62.58# Set @ +/- 115' MD Surface Casing 9-5/8" 40# L-80 OTC - Float Collar to Surface Float Collar: Weatherford - Single Valve 9-5/8" 32-53# BTC Box x Pin (2) Joints Casing: 9-5/8" 40# L-80 OTC Float Shoe: Weatherford - Single Valve 9-5/8" 32-534 BTC Box Up Intermediate / Production Casing: 7" 26# L-80 BTC - Roat Collar to Surface Float Collar: Weatherford - Single Valve 7" 20-35# BTC Box x Pin (2) Joints Casing: 7" 26# L-80 BTC Float Shoe: Weatherford - Single Valve 7" 20-35# BTC Box Up Wt X- iIi4111,n r r r C., X-7.1751: Atiyulr737: p r ,- r -MI 1: Diesel 11 0 pPg Flu.d Sand Plug 6-1/8" Open Hole 11.0 PPG LSND Mud KRKBa P u:.ei ®Sc Acc 25' Ice Pad Height (Abovee SS) 30' Nordic Rig 3 RKB lips 3-1/2', 9.3#, L-80, EUE-8rd Mod 1011 String landed @ +/- 1,590'. Well was freeze protected w/ diesel below base of Permafrost and a Back Pressure Valve was installed tubing hanger. 1b PPG FIT =750 os 91 nod Mud 2268' TVD 12 BBL (328' Lenalh) Cement Ptuq spotted on top of Sand Plua. �t Estimated (T 7.357MD to 7,029' MD CTM) Class G + Additives (1.2 GPS 0600, 1.0 % D20, 0.4% 065, 0.35% D800, .1 GPS D47) Slurry Weight 15.8 Ppg 10' Sand Plug sootted on too of reta"ner following pressure test. Sand Plug Top Estimated @ +/- 7375' MD Coil Tagged Top a 1/- 7,357' MD ClM Prior to Yu!o V�nq Lenin .' Baker N-1 Cast Iron Cement Retainer. (Retainer Top @ +/- 7,385' MD RKB - Retainer Pressure tested to 2500 psi) 14 PPG FIT - 950 p i5, 110 one Mud, 6053'M Exhibit C - 1 of 1 Placer 1 - Suspension Schematic v1.0 prepared by Mark Chambers 04/15/04 N C O a-+ l6 L W Q O UD C 0 m L u U d lD r -I O N r -I O N UD C N v L U U .Q C O U N Q _C ru Q) CU xk v U (O d U x X w hA C L L }I v N m m CL hA N C =3 �L ::3 C 'C O F O U Fm L O r -I _ v O o U It V � U m Q m CL O d _Ql k .1 Placer#1 wellhead with Kuukpik Rig in the background during Placer#3 drilling operations (2016) Exhibit D - 2 of 3 Colombie, Jody J (CED) From: Colombie, Jody J (CED) Sent: Wednesday, February 17, 2021 8:48 AM To: Romerdahl, Elena M. (Perkins Coie) Cc: Colombie, Jody 1 (CED) Subject: RE: Request for Extension Docket No. OTH-21-005 Categories: Yellow Category Elena, Site inspection is now due March 13, 2021. Other Information is now due March 18, 2021. Jody From: Romerdahl, Elena M. (Perkins Coie) <ERomerdahl@perkinscoie.com> Sent: Tuesday, February 16, 20214:12 PM To: Colombie, Jody J (CED) <jody.colombie@alaska.gov> Subject: Request for Extension Docket No. OTH-21-005 Hi Jody, As we discussed, AEX just received the attached February 4, 2021 Notice of Violations (Docket No. OTH-21-005) yesterday. The Notice requires AEX to conduct a site inspection by February 18 and to provide information regarding the violations within 30 days of receipt of the letter. In light of AEX's late receipt of the letter, we would like to request an extension until March 18 to comply with the Notice. If I can provide you with any additional information to support the request, please let me know. Thank you for your consideration. Elena Elena Romerdahl I Perkins Cole LLP PARTNER 1029 West Third Avenue Suite 300 Anchorage, AK 99501-1981 D. +1.907.263.6914 M. +1.202.487.8657 E. ERomerdahl(fterkinscoie.com NOTICE: This communication may contain privileged or other confidential information. If you have received it in error, please advise the sender by reply email and immediately delete the message and any attachments without copying or disclosing the contents. Thank you. THE STATE 01ALASKA GOVERNOR MIKE DUNUAVY February 4, 2021 Mr. Chait Borade President ASRC Exploration, LLC 3900 C Street, Suite 800 Anchorage, AK 99503 Re: Docket Number:OTH-21-005 Notice of Violations Failure to Inspect Suspended Wells Failure to Renew a Well Suspension Placer 1 (PTD 204-014) Placer 3 (PTD 215-204) Dear Mr. Borade: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogc c.a I aska.gov The Placer 1 well was initially drilled by ConocoPhillips Alaska, Inc. and suspended on April 11, 2004. ASRC Exploration, LLC (ASRC) became operator of the well on June 28, 2010. The well had an initial suspended well inspection conducted on August 13, 2004 but has not been inspected since. Suspended well inspections were required prior to September 30, 2010, 2015, and 2020. The Placer 3 well was drilled by ASRC and suspended on March 17, 2016 and had an initial suspended well inspection conducted on August 4, 2016. Placer 3 well did not have its required inspection by September 30, 2020. 20 AAC 25.110(e) requires suspended wells to be inspected "...within 24 months before September 30 of every calendar year ending in 0 or 5, except that a suspended well is not required to undergo a subsequent inspection under this subsection if the initial inspection under this subsection occurred within the prior 24 -month period." Additionally, 20 AAC 25.110(i)(1) requires the designated operator of a suspended well that was suspended prior to January I, 2006, to apply for a suspension renewal by December 31, 2010. Despite being suspended on April 11, 2004, a request for suspension renewal has never been submitted for the Placer 1 well. In total this makes five violations of the Alaska Oil and Gas Conservation Commissions regulations for suspended wells. Within 30 days of receipt of this letter, ASRC is requested to submit an explanation for how these violations occurred and what ASRC will do in the future to ensure such violations do not happen again. In addition, to ensure the integrity of the wellheads ASRC must conduct a site inspection ■ Complete items 1, 2, and 3. ■ Print your name and address on the reverse so that we can return the card to you. ■ Attach this card to the back of the mailpiece, or on the front if space permits. 1. Article Addressed to Mr. Chait Borade President ASRC Exploration, LLC 3900 C Street, Suite 800 Anchorage,. AK 99503 X/ ent 4,10 / / 0 Addre, B-Recelved by (Printed Named C. Date of Deli cr.k—%f2KKtL4,9 D. Is delivery address different f D( Item 17 ❑ Yes If YES, enter delivery address below: ❑ No ra Ln C3 ra D-' S O n! ru C3 C3 C3 C3 CID .A O 03 ra M1 U.S. Postal Service" CERTIFIED MAIL® RECEIPT Domestic Mail only 3.Service Type ail r D gist MFxpressCN I I'll ll I'll I'I I III IN I II VIII II III I II III III ❑ Adult Signature tl Mall C Registered 9590 9402 4351 8190 1878 74 ❑ Adult signature Restricted Delivery rcedined Mail® Coiled Mail Restricted Delivery C Collect on Delivery C Colied on Delivery Restricted Delivery ^'nsured Mall ^saw Mail Restricted Delivery ever $600) C Registered Mail Restricted Dey Return vch Receiptfw erchandise C Signature Confiion^" ❑Signature Confirmation Restricted Delivery 2. Article Number (Transfer from Service label) 018 0680 0022 2049 10 51 PS Form 3811, July 2015 PSN 7530-02-000-9053 Domestic Return Receipt ra Ln C3 ra D-' S O n! ru C3 C3 C3 C3 CID .A O 03 ra M1 U.S. Postal Service" CERTIFIED MAIL® RECEIPT Domestic Mail only Notice of Violation Docket No: OTH-21-005 February 4, 2021 Page 2 of 2 for the two wells within the next 14 days. As soon as the site is snow- and ice -free next year you must conduct a more thorough suspended well site inspection. Both inspections must be witnessed by the AOGCC's inspection staff. In lieu of the thorough suspended wells site inspection next year ASRC may choose to permanently plug and abandon these wells this winter. Information requested in this notice is in accordance 20 AAC 25.300; failure to comply with this request will be an additional violation. The AOGCC reserves the right to pursue additional enforcement action in connection with this Notice of Violation. Questions regarding this letter should be directed to Dave Roby at dave.robyaalaska.gov or 907-793-1232. Sincerely, Jeremy M. ° W`M`.g"tlb' lnemy M.Mtt WM.M31.M" Price 1"213�OV Jeremy M. Price Chair, Commissioner • LoF � THE STATE Alaska Oil and Gas 4 - ®f /e Conservation Commission LSKA - -fi ,+ 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 O�ALAS�P Fax: 907.276.7542 www.aogcc.alaska.gov Teresa Imm President ASRC Exploration, LLC 3900 C Street, Suite 1000 Anchorage, AK 99503 Re: Exploratory Field, Exploratory Pool, Place 1 r^ F Permit to Drill Number: 204-014 � � � '� Sundry Number: 316-048 Dear Ms. Imm: 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, ÀY / J Cathy '. Foerster Chair DATED this 3 day of February, 2016. RBDMS FEB 0 4 2016 . • • RECEIVED STATE OF ALASKA • JAN 2 5 201 ALASKA OIL AND GAS CONSERVATION COMMISSION 1 5 APPLICATION FOR SUNDRY APPROVALS AO+ C /4 20 AAC 25.280 1.Type of Request: Abandon 0• Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: ❑ 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: ASRC Exploration LLC Exploratory ❑✓ Development ❑ 204-014 ' 3.Address: Stratigraphic ❑ Service El 6.API Number: 3900 C Street Suite 1000 Anchorage,AK 99503 50-103-20481-00 7. If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? N%l' Will planned perforations require a spacing exception? Yes ❑ No ❑/ Placer# 1 9. Property Designation(Lease Number): 1402 10. Field/Pool(s): ADL 391027, A91041 Exploratory - 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effectiv Deepth MD: Effective pthTVD: MPSP(psi): Plugs(MD): Junk(MD): 7,761 6,289 ' 3 6,269' 7,357' Casing Length Size MD TVD Burst Collapse Structural Conductor 105' 16" 115' 115' Surface 2,498' 9.625" 2,528' 2,268' Intermediate 7,437' 7" 7,467' 6,053' Open Hole 294' 6.125" 7,761' 6,289' Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): N/A N/A 3.5" L-80 1,590 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): 12.Attachments: Proposal Summary Q Wellbore schematic 0 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑' ' Stratigraphic ❑ Development ❑ Service ❑ 14.Estimated Date for 15.Well Status after proposed work: March 1,2016 Commencing Operations: OIL ❑ WIND ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned 0 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact R.M.Lemon Email nlernon U( asrc.cot71 Printed Name Teres m n � nTitle President ASRC Exploration,LLC ii 1(46- ,{_/'ice \J-81L-AA-412-LI zz ik Signature Phone:339-6014 Date COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. Plug Integrity e . BOP Test 01 Mechanical Integrity Test ❑ Location Clearance rrl cr.-0A- Z- r.-0 1- Z-D!G Other: 1-. /IL1 C1 C C. C,n""e1L.$ ccs;-S; G rv#-- 16 Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No Subsequent Form Required: i i.) - ! 0 '77— APPROVED 'TAPPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: 2.. -,3-/4 Submit Form and �10-403 Revised 11/2015 r v d t s olid for 12 months from the date of approval. Attachments in Duplicate /-, '/ 0 � it ; BDMSc'- 042016 FEB • • • ASRC EXPLORATION LLC RECEIVED JAN 2 5 2016 A subsidiary of Arctic Slope Regional Corporation CP AOGCC January 22, 2016 Cathy Foerster AOGCC Commissioner, Chair 333 W 7th Ave, Suite 100 Anchorage,AK 99501 RE: Application for Sundry Approval to Abandon the Placer#1 Well (PTD 204-104) Dear Cathy, Please find attached Form 10-403 Application for Sundry Approval to abandon the Placer#1 well (PTD 204-104). In accordance with 20 AAC 25.105 (e)(1) the reason for abandoning the well; it is deemed that the development requirements are not commercial. In accordance with 20 AAC 25.105 (e)(2)(A); the Kuparuk sand is abnormally geo- pressured with an equivalent mud weight of 9.9 ppg as measured by MDT in 2004. This gradient of 0.51 psi/ft exceeds the 0.50 psi/ft gradient as defined by AOGCC to be abnormally geo-pressured. In accordance with 20 AAC 25.105 (e)(2)(B) and (C) the statement of proposed work; please find the following proposed permanent abandonment summary procedure,wellbore schematics, and variance requests to 20 AAC 25.112 (a)(1)(C), 20 AAC 25.112 (a)(2),and 20 AAC 25.112 (b). Sincerel , ihriLcSaf , "Nr esa Imm President ASRC Exploration, LLC 3900 C STREET• SUITE 1000 •ANCHORAGE ALASKA•99503 •(907)339-6014• FAX(907) 339-6028 • Placer#1 P&A Summa Procedure IPTD 204-104 API 50-103-20481-00) Scenario 1: 1. Notify AOGCC 24 hours prior to commencing abandonment operations. 2. Remove the black plastic wrapping to expose the FMC gen 5 wellhead and WKM tree. Use scaffolding and visqueen to erect a warming hooch and swab valve access platform for making up lubricators. Warm the wellhead and tree with a Tioga heater. Check and record pressures: • 3-1/2" tubing • IA (3-1/2" x 7" annulus) • OA (7" x 9-5/8" annulus) Verify that VR (valve removal) plugs are removed from the IA and OA. Cycle and grease all valves on the tree, IA, and OA. 3. RU pump truck. a. Test lines to 4,000 psi. b. Line up to the 3-1/2" tubing or the IA. Install a chart recorder and pressure test the 7" casing to 2,500 psi with diesel for 30 minutes. Record the pressure test and send the chart to ASRC in Anchorage. c. Line up to the OA. Establish injectivity at 2 bpm with 10 barrels of diesel. Expect injectivty at less than 1,000 psi surface pump pressure, do not exceed 2,500psi pressure. Scenario 2 (Contingency): If injectivity cannot be established a contingency procedure will be prepared to perforate the 7" casing for circulating cement. Confirm the wellhead is clear and a deep obstruction is the cause (indicated from the volume pumped). 4. RU slickline unit. Drift the 3-1/2" tubing for running an inflatable bridge plug and tag the cement plug to satisfy 20 AAC 25.112 (g)(1); estimated top of the cement plug is 7,062' MD. 5. RU e-line unit. Set an inflatable bridge plug in the 7" casing at 1,650' MD. Adjust the setting depth as needed to accommodate the setting tools below the tubing tail (as per the a-line and bridge plug companies' recommendations). 6. Tag the bridge plug with the setting tool or a blind box (as per the e-line and bridge plug companies' recommendations to satisfy 20 AAC 25.112 (g) (1)). 7. Rig up cementers and test lines to 4000 psi; line up to the OA. 8. RU hot oil truck and test lines to 4,000 psi; line up to the 3-1/2" tubing and line up to take returns up the IA. Circulate and warm the diesel and wellbore as recommended by the cementing company. Page 2 of 7 • Placer#1 P&A Summa' Procedure (PTD 204-104,API 50-103-20481-00) 9. Down-squeeze the OA with 75 Bbls of 15.8 ppg Arctic Set cement to place cement from surface to 100' below the surface casing shoe. 10. Line up cementers to the 3-1/2" tubing and line up to take returns up the IA. 11. Pump 5 Bbls freshwater spacer, mix and pump 65 Bbls of 15.8 ppg Arctic Set cement down the 3-1/2" tubing while taking returns up the IA. Pump additional cement as needed to get 15.8 ppg returns at surface. s 12. WOC. cc)a t-ne—,�_ 13. Cut off the wellhead and all casing strings and the tubing string (16", 9-5/8", 7" and 3-1/2") at least 3 feet below original ground level (per 20 AAC 25.170). 14. Weld a 16" cap onto the casing stub with required well identification information (per 20 AAC 25.120). 15. Take photos of the welded 16" cap. 4 c.z=..yZ. ��'` � ) 16. Remove cellar and back fill cellar hole. Take photos of mound. / (6 Page 3 of 7 . • • Placer#1 P&A Summa'Procedure (PTD 204-104.API 50-103-20481-00) Placer 1—Current Status as Suspended 1 L115' MD Section Lb/ft Grade Thread Top MD Btm MD Btm TVD 16" 63 B PEB Surface 115 115 9-5/8" 40 L-80 BTC Surface 2,528 2,269 7" 26 L-80 BTCM Surface 7,467 6,053 6-1/8"OH NA NA NA 7,467 7,761 6,289 3-%2" 9.3 L-80 8RD EUE Surface 1,590 1,557 1,948' MD 2,000' MD TEE 2,528' MD 2,653' MD 11 ppg fluid 6,010' MD—maximum calculated TOC(1,457') 7,162' MD—minimum calculated TOC(305') I 1 1 1 7,062' MD 15.8 ppg 313' Cement 7,375' MD sand 10' �— 7,385' MD 82' 7,467' MD FIT 14 ppg 72' Freshwater 7,539' MD Kuparuk MDT9.9 ppg 21' Diesel 7,560' MD 11.0 ppg 11 ppg 201 Cement LSND Mud 7,761' MD MEM Sand Page 4 of 7 • - Placer#1 P&A Summa1Procedure (PTD 204-104,API 50-103-20481-00) Scenario 1 Placer 1—P&A: Down-squeeze OA,set inflatable bridge plug,circulate cement IA IL____ 115' MD Section Lb/ft Grade Thread Top MD Btm MD Btm TVD 16" 63 B PEB Surface 115 115 9-5/8" 40 L-80 BTC Surface 2,528 2,269 7" 26 L-80 BTCM Surface 7,467 6,053 6-1/8"OH NA NA NA 7,467 7,761 6,289 4 3- 2° 9.3 L-80 8RD EUE Surface 1,590 1,557 10-. 1,650' MD I!Sr' oma•■ i , 2,000' MD AL2,528' MD 2,653' MD 11 ppg fluid 6,010' MD—maximum calculated TOC(1,457') 7,162' MD—minimum calculated TOC(305') ai t g 1 7,062' MD 15.8 ppg 313' Cement 7,375' MD sand 10' i l 7,385' MD 82' AL 7,467' MD FIT 14 ppg 72' 7,539' MD Kuparuk MDT 9.9 ppg 21' Diesel 7,560' MD 11.0 ppg 11 ppg 201' Cement LSND Mud 7,761' MD Sand Page 5 of 7 • Placer#1 P&A Summa�Procedure (PTD 204-104.API 50-103-20481-00) Scenario 2 Placer 1—P&A Contingency:Set inflatable bridge plug (deeper), perf 7",circulate cement OA& IA • / / / / / / 115' MD / / / / / Section Lb/ft Grade Thread Top MD Btm MD Btm TVD / / / / / / 16" 63 B PEB Surface 115 115 / / / / / / 9-5/8" 40 L-80 BTC Surface 2,528 2,269 / /.. / / / 7" 26 L-80 BTCM Surface 7,467 6,053 / / / . / / / 6-1/8"OH NA NA NA 7,467 7,761 6,289 / / / " 3-'/2" 9.3 L-80 8RD EUE Surface 1,590 1,557 / / / / / / / / / / / / / / / A: % / 2,528' MD / = 2,628' MD / , / / r / 2,650' MD / / / / • ll ppg 5 / fluid / / / / 6,010' MD—maximum calculated TOC(1,457') / 7,162' MD—minimum calculated TOC(305') / / / / / i 7,062' MD / / ?€; / / / / / / / / / 15.8 ppg / 313' / / ; It / Cement / / / ';r / / / / / 7,375' MD / sand / 10' 7,385' MD / / 82' / 7,467' MD FIT 14 ppg 72' 7,539' MD Kuparuk MDT9.9 ppg 21' 7,560' MD 11.0 ppg 11 ppg 201' Cement LSND Mud 7,761' MD MEE Sand Page 6 of 7 41/ Variance Requests: Player#1 P&A (PTD 204-104.API 50-103-20481-00) ASRC Exploration LLC (AEX) requests variance to 20 AAC 25.112 (a)(1)(C), 20 AAC 25.112 (a)(2), and 20 AAC 25.112 (b); plugging of the uncased portion of the wellbore, and effectively segregating uncased and cased portions of the well. It is the opinion of AEX that the intent of these requirements to isolate the hydrocarbons within the Kuparuk sand is satisfied with the existing conditions in this wellbore; and is supported by the following claims. 1. There are no other strata in the uncased portion of the wellbore with sufficient porosity volume, and permeability for hydrocarbons within the Kuparuk sand to migrate. 2. There is competent 7" casing, an effective external seal at the 7" casing shoe, and effective internal seals above the 7" casing shoe to effectively segregate uncased and cased portions of the wellbore to prevent vertical movement of fluid within the wellbore. 2.1. On 3/11/2004; a successful pressure test of the 7" casing to 2,500 psi for 30 minutes was performed prior to drilling out the 7" casing shoe track. This pressure test is a demonstration of competent 7" casing. 2.2. On 3/11/2004; a formation integrity test (FIT) to 14 ppg equivalent mud weight (EMW) was performed after drilling 20 feet of new hole beyond the rathole at 30 feet below the 7" casing shoe. This pressure test is a demonstration of a competent 7" casing shoe. 2.3. Volumetric calculations of the cement volume pumped result in a column of cement in the annulus above the 7" casing shoe in a range between 305 feet and 1,457 feet. The 1,152-foot range in cement column height represents a 26-barrel volume of mud or cement lost during pumping 336 total barrels of mud and cement. Even in the worst case if all 26 barrels of volume lost was cement and not mud the resulting 305-foot column of cement is sufficient to maintain a competent 7" casing shoe. 2.4. On 3/16/2004; a cast iron cement retainer was set inside the 7" casing at 7,385'; 82 feet above the 7" casing shoe. A successful pressure test of the 7" casing and cement retainer to 2,500 psi for 30 minutes was performed. This pressure test is a demonstration of competent 7" casing and effective isolation of the uncased portion of the well by the cast iron cement retainer. 2.5. On 4/11/2004; a 12-barrel cement plug was placed above a 10-foot sand plug on top of the cast iron cement retainer by the displacement method using coiled tubing. This 313-foot cement plug will prevent vertical movement of fluid within the wellbore inside the 7" casing. 3. The proposed permanent abandonment procedure will demonstrate competent 7" casing again by pressure test, and the location and integrity of the 12-barrel cement plug by tagging it with slickline. f<. Page 7 of 7 e e 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. cQ. 0 4 - () 1 LJ- Well History File Identifier Date b / a. ~ t)(P I'; hî-P J 0 X 30 = . ~ 00 + ,,<..$ = TOTAL PAGES 335 I ~ 7 I (Count does not include cover sheet) IIY1 P Date: S. a. d-I ÐlP Isl r II 111111111111111111I Organizing (done) D Two-sided /111/1111/1" 111111 RESCAN ~olor Items: D Greyscale Items: DIG!T AL DATA d Diskettes, No. ~ther, NofType: G1ì I D Poor Quality Originals: D Other: NOTES: Date51d-~00 BY: ~ Project Proofing BY: ~ Scanning Preparation BY: ~ Production Scanning D Rescan Needed III" 111111 II 111111 OVERSIZED (Scannable) D Maps: D Other Items Scannable by a Large Scanner OVERSIZED (Non-Scannable) ~09S of various kinds: D Other:: VY\f III 11111I11111 11II1 Isl Stage 1 Page Count from Scanned File: 33 ro (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: V YES NO BY ~ . Date sl ;l;t/ 0(,; I'; m p Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: Scanning is complete at this point unless rescanning is required. ReScanned BY: Maria Date: Comments about this file: Isl 11I1111111111111111 III 11111111I11 111I1 Isl Quality Checked III "1111111" 11111 1 0/6/2005 Well History File Cover Page. doc SIMIT OF ASEA /SEAN PARNELL,GOVERNOR ALASKA OIL AND GAS 333 W.71h AVENUE,SUITE 100 CONSERVATION COMMISSION ANCHORAGE,ALASKA 99501-3539 PHONE (907)279-1433 FAX (907)276-7542 June 14, 2010 Ms. Teresa Imm RECEIVED Director-Resource Development Arctic Slope Regional Corp. SEWED FEB 2 5 ZD14 JUN 17 2010 3900 `C' Street, Suite 801 Anchorage, Alaska 99503-5963 ALASKA LAND FO) Za`F _O I LI Dear Ms. Imm: The Alaska Oil and Gas Conservation Commission (Commission) has received your notice of the transfer of ownership to Arctic Slope Regional Corp. (ASRC) for the `placer 1 Well uparuk River, (API 50132048100, PTD # 204 'located on leases "ADL039102'Tand ADL0391023), from ConocoPhillips Alaska, Inc, Union Oil Company of California and ExxonMobil Production Company. The Placer 1 Well is currently under Suspended Status. As a result, ASRC may not undertake any work on this well until such time as it has obtained Commission I approval to do so. Should ASRC desire to undertake any work on this well, you will need to supply the Commission with a Surety Bond (form 10-402A) and a Designation of Operator (form 10-412). In addition an Application for Sundry Approval (form 10-403) is required for any proposed work. Sincerely, i 16,- - I Daniel T. Seamount, Jr. Chair, Commissioner cc: Weldon Taylor, ExxonMobil Alaska Production Company t, David Brown, ConocoPhillips(Alaska), Inc. Kevin Tabler, Union Oil Company of California MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg, ~p~ ~ o (~~~04 DATE: August 13, 2004 P.I. Supervisor (~ ~,©4-©r~ 7 ~ ac-~r ~ ~ FROM: Jeff Jones, SUBJECT: Location Clearance Petroleum Inspector Well Site Inspections Exploration NPRA Placer 2 PTD 2040330 Spark 4 PTD 2040080 Spark 8 August 13, 2004: I traveled with CPAI representative Chris Brown via helicopter to inspect Conoco-Phillips Alaska Inc.'s (CPAI) Placer #2, Spark #4 and Spark #8 exploration well sites for the purpose of final location clearances. The Placer #2 exploration well has been plugged & abandoned and a site inspection revealed several large chunks of concrete on the surface that should be buried or removed prior to final approval. A small amount of "ponding", depressions left from drilling activities filling with water, was visible at this site and may require a small amount of additional fill material prior to approval. The Spark #4 exploration well has been plugged and abandoned and a site inspection revealed several large cement chunks that should be buried or removed and a "ponding" condition that will require more fill to meet the AOGCC requirements for final approval. The Spark #8 exploration well was not drilled but a conductor hole was drilled and subsequently filled in. This site also exhibited a "ponding" condition and will require additional fill material prior to final approval. During this trip I also was able to inspect the Carbon #1 and Placer #1 wellheads, which were wrapped with a black plastic to protect them from nesting ravens. I noted six old 55-gallon drums near the Carbon #1 wellhead of unknown origin. Chris Brown indicated she would have the substandard items corrected and notify the AOGCC when completed. Summary: I inspected CPAI's exploration well sites Placer #1 & #2, Carbon #1, and Spark #4 & #8 in the NPRA. ~~~~b~e~ 1Y:hi~ ~ ~ ~U~~ Placer #1 (ConocoPhillips) Location Clearance Inspection Photos from AOGCC Inspector Jeff Jones August 13, 2004 Placer #1 wellhead Placer #2 (ConocoPhillips) Location Clearance Inspection Photos from AOGCC Inspector Jeff Jones August 13, 2004 Placer #2 -cement chunks, ponding ~~ ~, 5C •~ ~ ~3 ~ o o ~ o' ~ c~ ~ D c c ~. .-. ~- n o p tin O '~ O O 3 D= ~y nr no _rt O C7 ~D n ~D N ~D Cf O 7 w~ N ~ O ~ CD ~ O L (D L O 7 (D Spark #8 (ConocoPhillips) Location Clearance Inspection Photos from AOGCC Inspector Jeff Jones August 13, 2004 Spark #8 - conductor only; ponding Carbon #1 (ConocoPhillips) Location Clearance Inspection Photos from AOGCC Inspector Jeff Jones August 13, 2004 Carbon #1 wellhead ~ • -,~_ -=~- -ti ~~, _ ~; ~~ . ~: MICROFILMED 03!01/2008 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE F:~LaserFiche\CvrPgs_InsertslMicrofilm Marker.doc Permit to Drill 2040140 MD 7761 r I f M~ .u-~~ DATA SUBMITTAL COMPLIANCE REPORT 4/24/2006 Well Name/No. PLACER 1 Operator CONOCOPHILLIPS ALASKA INC REQUIRED INFORMATION TVD 6289./ Completion Date 4/11/2004 Current Status SUSP Mud Log Yes Completion Status SUSP Samples No )pu..ð ;Z) r-t~tj'~<{ API No. 50-103-20481-00-00 UIC N Directional Survey Yes DATA INFORMATION Types Electric or Other Logs Run: Dipole Sonic, CMR/MDT, MSCT Well Log Information: Log/ Data Type -¡rn- : Rpt Digital Med/Frmt CAse ~ ~ -l.og-. ~... ~/' .~ C Lis ~ 4c W C Dls Ep,/ C Dls ~. .~/ 4dg ~ g/ í.ßrJf Electr Dataset Number \-;\~ Name Directional Survey Directional Survey Density Density Induction/Resistivity Induction/Resistivity See Notes ! 1 t-f.'CS See Notes See Notes '12607 See Notes ~08 ~9 Formation Tester Sonic See Notes Formation Tester (data taken from Logs Portion of Master Well Data Maint ""0 W'D Log Log Run Interval OH/ Scale Media No Start Stop CH Received ~- 5/24/2004 5/24/2004 Blu 110 7761 Open 5/24/2004 Blu 100 2250 Open 5/24/2004 ~\) Blu 100 7720 Open 5/24/2004 TVÖ Blu 100 6250 Open 5/24/2004 0 0 Open 5/24/2004 111 7696 Open 5/24/2004 0 0 Open 8/3/2004 0 0 Open 8/3/2004 7540 7558 Open 8/3/2004 6208 7777 Open 8/3/2004 5 Col 7533 7563 Open 8/3/2004 5 Col 7540 7558 Open 8/3/2004 5 Blu 6236 7730 Open 8/3/2004 5 Blu 6236 7730 Open 8/3/2004 0 0 11/23/2004 Sonic Sonic \> ~V u1r Report: Final Well R . Comments DGRlCTN/SLD DGR/CTN/SLD ROPIDGRlEWR DGRlEWR CORE ANALYSIS vr/ bt J \.<t ~~ '1 LDWG LWD tt: \ '3 () ~ GeoChemical Report (CD included) GeoChemical Report on CD (doc,pdf,xls formats) MDT & MSCT PDS Graphics xis data Diploe Sonic Imager DLlS, LAS, PDS, XLS formats Mechanical Sidewall Coring Tool Modular Formation Dynamics Tester Dipole Sonic Imager Dipole Sonic Imager Epoch Final Well Report w/CD Revised 7 Jan, 2005 New Report & CD . Permit to Drill 2040140 M~7761 lRPt- DATA SUBMITTAL COMPLIANCE REPORT 4/24/2006 Well Name/No. PLACER 1 TVD 6289 Completion Date 4/11/2004 See Notes Completion Status SUSP ~ ~ ~g ~ Mud Log Mud Log See Notes See Notes ;=~ Pds ~923 Sonic ~II Cores/Samples Information: Name ~Ítings ADDITIONAL INFORMATION Well Cored? Y /~ Chips Received? Y / ~ Analysis G/ N Received? Comments: ~~ fC) I ) '&~ "ß /)~~9 Compliance Reviewed By: 0.... ¡VI Ö o..-V\~ o.-ìvb2 Col 2 Col 2 Col 2 Col Interval Start Stop 100 7760 " 71 ~c... ~ '" 1 f\~ H V' ù ~~.,. ~ ('^; ¿ 5G..\J.J¡-Új C>_ill'~ O-,^f\J~f; J S We.. ~v\Qk, I ~) Y\ "I u-lts ~ \1 J k ltt t.. ~ ~~ Operator CONOCOPHILLlPS ALASKA INC API No. 50-103-20481-00-00 Sent Current Status SUSP UIC N 0 0 1/13/2005 Black Oil Full PVT Stud¡ Report w/C~ J 3 8~ 110 7761 Open 1/13/2005 110 7761 Open 1/13/2005 Drilling Dynamics 110 7761 Open 1/13/2005 LWD/Lithology Log 110 7761 Open 1/13/2005 Gas Ratio Log 6236 7730 8/18/2004 DIPOLE SONIC IMAGER . Sample Set Number Comments 1137 Cores and/or Samples are required to be submitted. This record automatically created from Permit to Drill Module on: 2/2/2004. Received Daily History Received? (Y)N G)N Formation Tops ~t> C,X~) 2; 0 yfD(=) (.. .x l- 5 ) . Date: J ~ ~ J.~ ~ . Conocd)hil ips . FROM: Sandra D. Lemke, AT01486 ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage AK 99510-0360 RE: Placer 1 PERMIT 204-014 DATE: 03/14/2006 TO: Ceresa Tolley AOGCC 333 w. ¡th Ave., Site 100 Anchorage, Alaska 99501 Ft ~C~/f...\ 41.,k. .... M41? J 12"D '011 ~ . $ ¿OO, G,I, ~ 'ô .4¡¡c/¡o. Oh,. C. "'8ge ~Ji...' v/ol1 TRANSMITTAL CONFIDENTIAL DA TA Transmitted: Hardcopy report _Geochemical Analysis Results: Placer 1 Well Samples 2004, North Slope, Alaska; by ConocoPhillips Subsurface Technology, November 2005; Authors: Albert Holba and Vicki Webb. Please check off each item as received, promptly sign and return the transmittal to the address below To all data recipients: All data is confidential until State of Alaska designated AOGCC release date Data marked PROPRIETARY is indefinitl!'Y confidential and is available onJyto C!~ne~f!rlt!e'!rtners cc: Justin,]7óccan1ra.. ... 'ccanera, CP1 c¡eolo1st Receipt: ~"O ~ Date: Return receipt to: ConocoPhillips Alaska, Inc. ATTN: S. Lemke, ATO-1486 700 G. Street Anchorage, AK 99501 GIS-Technical Data Management I ConocoPhillips I Anchorage, Alaska I Ph: 907.265.6947 I Sandra.D.Lem,ke@conocophillips.com .~....{ - \::)( ~l hi-l · . ConocJPt,illips TRANSMITTAL CONFIDENTIAL DA TA FROM: Sandra D. Lemke, AT01486 ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage AK 99510-0360 RE: Placer 1 PERMIT 204-014 DATE: 1/13/2005 TO: Helen Warman Alaska Oil & Gas Conservation Commission 333 W. th Ave, Suite 100 Anchorage, Alaska 99501-3539 Transmitted: Hardcopy report and CDROM digital well data REVISION (dated 117/2005) _Epoch-Final Well Report; Mudlogging data; Morning reports; LAS Data; PDF Color image files and hardcopy; DML; Lithology Remarks. Formation Log (MD), Formation Log (TVD), Drilling Dynamics (MD), LWD/Lithology (MD), Gas Ratio Log (MD) Please check off each item as received, promptly sign and return one of the two transmittals to address below. The other copy is for your records To all data recipients: All data is confidential until State of Alaska designated AOGCC release date Data marked PROPRIETARY is indefinitely confidential and is available only to owners and partners / zi cç.;,/'ÄñCiY'AnJi'r,/ou>oCPAI . eqJog' t (~eceiPt:/1íé4Á' /{ ~#£f( 4~ '..........1. ?/¡ ¡/I...- Refürh reclipt to: (/ ConocoPhillips Alaska, Inc. [/ ATTN: S. Lemke, ATO-1486 700 G. Street Anchorage, AK 99501 Daœ: )f~- GIS-Technical Data Management I ConocoPhillips I Anchorage, Alaska I Ph: 907.265.6947 I Sandra.D.Lem,ke@ConocoPhillips.com ;)fJ Lf- 0 f 1..-1 F:!-~ · . eonoc6Pt,illips TRANSMITTAL CONFIDENTIAL DA TA FROM: Sandra D. Lemke, AT01486 ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage AK 99510-0360 RE: Placer 1 PERMIT 204-014 DATE: 01/11/2005 TO: Helen Warman Alaska Oil & Gas Conservation Commission 333 W. ih Ave, Suite 100 Anchorage, Alaska 99501-3539 Transmitted: Hardcopy report and CDROM digital data _Schlumberger WCP Oilphase-DBR, Placer #1 Black Oil Full PVT Study Report; Report#200400086; 12/1/2004 , C. ~ ±t,. I J. ~b'8 1 ~c.(..t ,~ Please check off each item as received, promptly sign and return one of the two transmittals to address below. The other copy is for your records To all data recipients: All data is confidential until State of Alaska designated AOGCC release date Data marked PROPRIETARY is indefinitely confidential and is available only to owners and partners CC. )"ody ^)Jr1'~'rAI rJ. AI. 1~1" ~ceiPt://~/(;/- j{~~ Return receipt to: I" ConocoPhillips Alaska, Inc. 1/ ATTN: S. Lemke, ATO-1486 700 G. Street Anchorage, AK 99501 Date: }S/o6- I GIS-Technical Data Management I ConocoPhillips I Anchorage, Alaska I Ph: 907.265.69471 Sandra.D.Lem,ke@ConocoPhillips.com ~Ôy-(jt-f AI~ ::?ctf- ~ (4 . Co~illips . . FM- TRANSMITTAL CONFIDENTIAL DA TA FROM: Sandra D. Lemke, AT01486 ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage AK 99510-0360 RE: Placer 1 PERMIT 204-014 DATE: 8/18/2004 TO: Alaska Oil and Gas Commission 333 W. 7th Avenue, Suite 100 Anchorage, Alaska 99510 Transmitted: Schlumberger CDROM Diqitalloq data ~~ _ LDWG formatted Open Hole Edit; 6237-7760' md; logged 3/12/2004; Job 10687766 CPAI is waiting on color log prints from Schlumberger for distribution Please check off each item as received, promptly sign and return one of the two transmittals to address below. The other copy is for your records To all data recipients: All data is confidential until State of Alaska designated AOGCC release date Data marked PROPRIETARY is indefinitely confidential and is available only to owners and partners ~:.::y~~t(rtt! Date: tJíS~'t5 {ef Return receipt to: ConocoPhillips Alaska, Inc. ! I / & ' ATTN: S. Lemke, ATO-1486 700 G. Street Anchorage, AK 99501 Prepared by: Sandra D. Lemke ConocoPhillips Alaska, Inc. Global Information IS-Tech Data Management 907.265.6947 Sandra. D. Lemke@ConocoPhillips.com RECEIVED AUG 1 82004 Alaska Oil & Gas ClJns. Commission Anchorage r:~ · . ~illips TRANSMITTAL CONFIDENTIAL DA TA FROM: Sandra D. Lemke, AT01486 ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage AK 99510-0360 RE: Placer 1 ')~" /,1 PERMIT 204-0Cl'2r'-"- .-v -( DATE: 8/3/2004 TO: Alaska Oil and Gas Commission 333 W. 7th Avenue, Suite 100 Anchorage, Alaska 99510 Transmitted: Schlumberger log data _~DROM - Field MDT, DLlS, PDS and Field MSCT PDS files 7558-7540'md; Job 10687766 If /)., l.D ð -g ~ CRDOM - Processed Dipole Sonic DLlS, LAS and PDS files 7777-6208' md; Job 1068776611. (rÀ b lJ q Schlumberaer loa prints ~ Modular Formation Dynamics Tester 3/12/2004 ~ Mechanical Sidewall Coring Tool- 3/14/2004; 7533-7563' md ~ Dipole Shear Sonic Imager - TVD 3/12/2004 ~Dipole Shear Sonic Imager - MD 3/12/2004 ~~ Humble Geochemical Services Hardcopy Report and CDRO~ ~ ~07 ., v Summary Geochemistry Report, Placer 1, North Slope, Alaska Please check off each item as received, promptly sign and return one of the two transmittals to address below. The other copy is for your records To all data recipients: All data is confidential until State of Alaska designated AOGCC release date Data marked PROPRIETARY is indefinitely confidential and is available only to owners and partners CC: ~CPN'tOI9gist Receipt: f/ ~ l;VfVVvC Date: Return receipt to: ConocoPhillips Alaska, Inc. ATTN: S. Lemke, ATO-1486 700 G. Street Anchorage, AK 99501 Prepared by: Sandra D. Lemke ConocoPhillips Alaska, Inc. Global Information IS-Tech Data Management 907.265.6947 Sandra.D.Lemke@ConocoPhillips.com · e ConocJ'Phillips TRANSMITTAL CONFIDENTIAL DA TA FROM: Sandra D. Lemke, AT01486 ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage AK 99510-0360 RE: Placer 1 PERMIT 204-014 DATE: 5/24/2004 TO: Alaska Oil and Gas Commission 333 W. ih Avenue, Suite 100 Anchorage, Alaska 99510 Transmitted: Digital data _ Sperry Sun LDWG LWD LIS log data; Image views files (PDF, cgm, tiff, emf+viewer) ì~ t> þ~ 1 1 ~ L{ If D _ Sperry Sun definitive Directional Survey 4/4/2004 (\, Þ MJ Report Binder t) ri 1 ì\~(k.{,'t{L i ') Jj~-\ _ Core Labs Core Analysis results, Placer 1, CL57111-1 04080 (6~ '" I<" ð _ Halliburton Sperry Sun- Directional survey MWD SVY 617 report - hardcopy ~ Hardcopy LOQ data - 1 print Sperry Sun MWD logs ROP/DGR/EWR 2"&5" MD ,~ f!,C)fA) - , _DGR/EWR 2"&5" TVD ~I} bM.1 _DGR/CTN/SLD 2"&5" MD ~n h~) _DGR/CTN/SLD 2"&5" TVD "'~ b~J Please check off each item as received, promptly sign and return one of the two transmittals to address below. The other copy is for your records To all data recipients: All data is confidential until State of Alaska designated AOGCC release date Data marked PROPRIETARY is indefinitetyconfidential and is available only to owners ant!partners CC: x~... . . CJ1ffgeoI09. ist Receipt: v~. U~ Date: Return receipt to: ConocoPhillips Alaska, Inc. ATTN: S. Lemke, ATO-1486 700 G. Street Anchorage, AK 99501 Prepared by: Sandra D. Lemke ConocoPhillips Alaska, Inc. Global Information IS-Tech Data Management 907.~ ~~Ðmke@conocoPhilliPs.com MAY 2 4 2004 A öt{ "01'-( Alaska Oil & Gas Cons. Commission Anchorage e ConocriPhillips e Paul Mazzolini Exploration DrillingTeam Leader Drilling & Wells P. O. Box 100360 Anchorage, AK 99510-0360 Phone: 907-263-4603 April 29, 2004 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West ¡th Avenue Suite 100 Anchorage, Alaska 99501 Subject: Well Completion Report for Placer #1 (204-014/304-105) Dear Commissioner: On behalf of itself and other owners, ConocoPhillips Alaska, Inc. submits the attached Well Completion Report for the recently suspended"éxploration well Placer #1, Drilling Permit No. 204-014 as specified in 20 AAC 25.071. We request that this data be held confidential as required under AS 31. 05.035(c) and 20 AAC 25.537(d). If you have any questions regarding this matter, please contact me at 263-4603. Sincerely, JJ II iIL-. P. Mazzolini Exploration Team Leader CP AI Drilling RECEIVED APR 2 9 2 AIaate Q'J & G.t, 1'__ 004 ~~ PM/skad e STATE OF ALASKA e ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Plugged 0 Abandoned U Suspended 0 WAG 0 20AAC 25.105 20AAC 25.110 1a. Well Status: Oil 0 Gas U GINJ 0 2. Operator Name: o WDSPl 0 WINJ No. of Completions _ ConocoPhillips Alaska, Inc. 3. Address: P. O. Box 100360, Anchorage, AK 99510-0360 4a. location of Well (Governmental Section): Surface: 1009' FSL, 19' FWL, Sec. 33, T12N, R7E, UM At Top Productive Horizon: 2299' FSL, 498' FWL, Sec. 4, T11 N, R7E, UM Total Depth: 2169' FSL, 515' FWL, Sec. 4, T11 N, R7E, UM 4b. location of Well (State Base Plane Coordinates): Surface: x- 451290 y- TPI: x- 451755 y- Total Depth: x- 451771' y- 18. Directional Survey: Yes 0 NoU 21. logs Run: Dipole Sonic, CMRlMDT, MSCT 22. CASING SIZE WT. PER FT. GRADE 1600 62.5# H-40 9.625" 40# L-80 7" 26# L-80 6.12500 5976426 . 5972434 5972304 'j Zone-4 Zone-4 Zone- 4 Other_ S. Date Comp., Susp., or Aband.: April 11, 2004 6. Date Spudded: February 27,2004 .j 7. Date TD Reached: March 12,2004 8. KB Elevation (It): RKB 30' I 55' AMSL 9. Plug Back Depth (MD + TVD): 7029' MD I 5710' TVO 10. Total Depth (MD + TVD): 7761' MD 16289' TVD I 11. Depth where SSSV set: none 19. Water Depth, if Offshore: NIA feet MSL 1b. Well Class: Development 0 Exploratory 0 Service 0 Stratigraphic Test 0 12. Permit to Drill Number: 204-014 I 304-105 13. API Number: 50-103-20481-00 14. Well Name and Number: Placer #1 15. Field/Pool(s): Kuparuk River Field Kupruk River Oil Pool 16. Property Designation: ADL 389132 17. Land Use Permit: nla 20. Thickness of Permafrost: 1470' MD CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD I TOP BOTTOM HOLE SIZE CEMENTING RECOR'h. A. M. OUNT PUllED Surface 135' 2400 142sxASI r(J-;Ct-I.I Surface 2528' 12.25' 373 bbls AS III Lite, 170 sx LiteCrete " &;..;, V'/-.D Surface 7467' 8.500 190 sx Class G ArC r. - 7761' 6.125' open hole n 2 y 2(' cement plug from 70~~M v~4 sand plug @ 7357' MD CTM, ceme ~. (S~'-- . 24. TUBING RECOR ",-, -""1lCIIIotJ SIZE DEPTH SET (MD) PACKER SET (MD) 3.5" 1590' none 23. Perforations open to Production (MD + TVD of Top and Bottom Interval, Size and Number; if none, state 'none"): none 26. Date First Production nla Date of Test Hours Tested 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 7029' - 7357' 12 bbls 15.8 ppg Class G 7375' -7385' 230# frac sand PRODUCTION TEST Method of Operation (Flowing, gas lilt, etc.) suspended GAS-MCF Flow Tubing Casing Pressure press. psi 27. Production for Test Period --> Calculated Oll-BBl Oll,BBl WATER-BBl GAS-MCF WATER-BBl CHOKE SIZE IGAS-Oll RATIO Oil GRAVITY - API (corr) Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary). Submit core chips; if none, state "none". ~S?6A.J:;;;6....J .!:"ðC~;;;;: t:;!!;·;-¡ r .-. : 'I. 'IX uf1 :~:._.¡ Form 10-407 Revised 2/2003 24-Hour Rate -> CORE DATA ,--~--......,."",,~,......:, , TO BE SENT UNDER SEPARATE COVER CONTINUED ON REVERSE SIDE Submit in duplicate MAY 0·4 200~ ~¡;- IfØJMS BfL 28. e GEOLOGIC MARKERS 29. e FORMATION TESTS NAME MD TVD Include and briefly summarize test results. List intervals tested, and attach detailed supporting data as necessary. If no tests were conducted, state "None". Placer 1 Top Kuparuk Base Kuparuk 7539' 7560' 6111 ' 6127' NIA 30. LIST OF ATTACHMENTS Summary of Daily Operations, Directional Survey, Schematic, As-Built 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Mark Chambers @ 265-1319 Printed Name P. ~~olini Signature 1...-..£ ,j.. ¿e.¿- Title: Phone Drillino Team Leader Date Þr/ Z7 /ô;'- 1'1~ t!IÞIn2>.£lZS .hC>/l- 7.;fUC. .#~VA.J/ INSTRUCTIONS Prepared by Sharon Allsup-Drake 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 1a: Classification of Service wells: Gas injection, water injection, Water-Alternating-Gas Injection, salt water disposal, water supply for injection, observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: the Kelly Bushing elevation in feet abour mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: True vertical thickness. Item 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 23: 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 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, Other (explain). Item 27: If no cores taken, indicate "none". Item 29: List all test information. If none, state "None". Form 1 0-407 Revised 2/2003 Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: PLACER #1 PLACER #1 ROT - DRILLING n1433@ppco.com Nordic 3 Start: 2/24/2004 Rig Release: 3/17/2004 Rig Number: Spud Date: 2/26/2004 End: 3/17/2004 Group: 2/2412004 22:00 - 00:00 2.00 MOVE MOVE MOVE Depart location for Placer pad. 2/25/2004 00:00 - 06:00 6.00 MOVE MOVE MOVE Move from 3F pad to 2C pad 06:00 - 08:00 2.00 MOVE OTHR MOVE 2hour crew change due to missed communications concerning pad selected as stopping location. 08:00 - 18:00 10.00 MOVE MOVE MOVE Finish move to Placer location. 18:00 - 20:00 2.00 MOVE OTHR MOVE Prepare liner and rig mats. 20:00 - 22:30 2.50 MOVE POSN MOVE Spot and set rig over well. Level rig and berm rig. 22:30 - 00:00 1.50 DRILL RIRD RIGUP Change out diverter flange. Load pipe shed. Accept rig at Midnight 2/25/04 2/26/2004 00:00 - 06:30 6.50 DRILL RIRD RIGUP Continue load pipe shed, change out diverter flange, fix suction rubbers on pits 3 & 4. RIU floor to pick up 4" dp. C/O saver sub and dies on Top Drive. Take on 580 bbl 9.6 ppg spud mud. 06:30 - 10:30 4.00 DRILL RIRD RIGUP Set diverter flange on conducter. Set diverter and M/U to flange. Attempt to test flange to conductor seals. No test. 10:30 - 14:00 3.50 DRILL RIRD RIGUP Found that diverter flange spool would not seal due to interference with 4 " outlets. Outlet spacing set up for standard weld on starter head is not the same as that for the "Alpine" slip on spool. Cut out and re weld 4" conductor outlets. 14:00 - 20:00 6.00 DRILL RIRD RIGUP Set and test FMC starting spool. N/U diverter, 16" diverter discharge line, riser and mousehole. 20:00 - 22:00 2.00 DRILL RIRD RIGUP Function test diverter and conduct Shallow gas diverter drill. Test gas detectors and Accumulator drawdown. Test witnessed by J. Spalding, AOGCC. 22:00 - 00:00 2.00 DRILL PULD RIGUP Pre job safety meeting. Pick up spiral HWDP and stand in derrick. 2/27/2004 00:00 - 02:30 2.50 DRILL PULD RIGUP P/U 4" and 31/2" HWDP and stand back 10 Stands. P/U 4" HT#* dp and stand back 17 stands. 02:30 - 04:30 2.00 DRILL RIRD RIGUP Service TD. C/O washpipe packing & bearing in ODS link tilt ram. Pressure test mud line to standpipe manifold to 3500 psi. 04:30 - 05:30 1.00 DRILL PULD RIGUP P/U BHA components. 05:30 - 06:30 1.00 DRILL PULD RIGUP PJSM for spud. MIU BHA #1 and RIH to Conductor shoe. 06:30 - 10:30 4.00 DRILL OTHR RIG UP Thaw frozen standpipe. 10:30 - 12:30 2.00 DRILL DRLG SURFAC Break circulation and spud well. Spud at 11 :00 2/27/04. Drill to 135". /' POOH for MWD BHA 12:30 -15:00 2.50 DRILL PULD SURFAC M/U MWDILWD tools. Load MWD. RIH 15:00 - 16:30 1.50 DRILL DRLG SURFAC Drill to 302'. Circulate and POOH 16:30 - 17:30 1.00 DRILL PULD SURFAC Load nuclear sources and P/U SDC. 17:30 - 21 :30 4.00 DRILL DRLG SURFAC drill to 494' 21 :30 - 00:00 2.50 DRILL TRIP SURFAC Back ream & POOH. P/U 6 ea. 6 1/8 " SDC and RIH. PU = 45K, SO = 45 K, RWM=40K, 1620 PSI 2 180 SPM 2/28/2004 00:00 - 12:00 12.00 DRILL DRLG SURFAC Directional drill from 494' to 1400'. PU = 82K, SO = 74 K, RW = 77K. Torque on Bot = 6200-6700 ftlb. Torque off bot = 3500-3700 ftlb. PP = 2900 psi at 530 gpm. 12:00 - 00:00 12.00 DRILL DRLG SURFAC Directional drill from 1400' to 2191' (2017' TVD) . PU = 80K, SO = 77 K, RW = 77K. Torque on Bot = 11300 ftlb. Torque off bot = 7100 ftlb. PP = 3000 psi at 530 gpm. 2/29/2004 00:00 - 04:00 4.00 DRILL DRLG SURFAC Directional Drill from 2191' to 2548'. 04:00 - 05:30 1.50 DRILL CIRC SURFAC Survey, CBU and confirm casing seat depth, Circulate 30 bbl viscous sweep. Printed: 4/23/2004 3:37:05 PM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: PLACER #1 PLACER #1 ROT - DRILLING n1433@ppco.com Nordic 3 Start: 2/24/2004 Rig Release: 3/17/2004 Rig Number: Spud Date: 2/26/2004 End: 3/17/2004 Group: 4.50 DRILL OTHR SURFAC Rig generators shutdown. Restart and found problem in SCR breaker system. Blowdown standpipe and work on SCR. By pass to highline power SCR breakers and re-establish power to rig. 2.00 DRILL CIRC SURFAC Re-establish circulation at reduced rate. Work pipe and attempt to rotate. Work up torque and break pipe free. Increase pump and free pipe with 82 K string tension. Establish full circ. at 500 gpm & 2850 psi. P/U = 95K, S/O = 70K. Rot Torque = 6.5 - 7 K ftlb. Ream to bottom. CBU. Pump Hi Visl Hi weight sweep. Circulate and load casing tools to pipe shed simultaneously. Circulate and condition mud. Load casing tools. Blow down TD. Flow check. POOH slick to 1550'. Pumo out to 1350 due to swabbing. POOH standing back DP & HWDp. LD upper BHA DC. PJSM and unload Nuc. Sources. Download logging tool data.Continue LD BHA, Motor and bit. PJSM and RIU casing tools P/U landing joint and dummy run. UD landing joint. PJSM and start running 9 5/8" 40 ppf L-80 csg. Run shoe and float joints, check floats. Run 10 Joints wI centralizer on each joint filling as run. Lost 6 bbl while RIH. Break circulation and confirm PVT. Vis of returns + 300 sec. RIH to 1160' wI full returns. 1 Bow spring per joint to joint 18 and 1 per 3 joints beyond. Break circ at 1160'. Pump 15 bbl. Full returns. RIH. P/U = 70K. S/O = 60K. Took weight at 1290'. P/U to 1280'. Break circ and wash down to 1320'. Wash back from 1320" to 1280'. Stop pump and RIH to 1320' WI 20 k drag diminishing with depth. RIH to 2180'. P/U 90K S/O 70K. Full returns. Circulate at 2180'. Pump up to 5 bpm @ 350 psi. PU = 90K SO = 70 K RIH to 2495'. PU landing joint and wash to bottom. Circulate @ 2 bpm & 200 psi. PU = 95K SO = 70 k increase to 5 bpm @ 480 psi. full returns. Recriprocate while circ. RIU cement head. Circ and recrip at 5 bpm. & 220 psi. PU = 112 K. and SO = 95 K. PJSM for cement job. 3.00 CEMENT PUMP SURFAC Continue recriprocation and Mix and pump 10 bbl CW 100 @ 4.2 bpm & 211 psi. Test lines to 3100 psi. Mix and pump 40 bbl CW100 @ 6 bpm & 440 psi. Drop bottom plug. Mix and pump 48 bbl 10.5 ppg Mud Push II @4.5 bpm & 137 psi. Mix and pump 373 bb110.7 ppg ALS III @ 7 bpm & 449 psi. Mix and pump 73 bb112.0 ppg Litecrete. Cement returns first seen at surface & diverted to vac trucks. Drop top plug and land casing. Displace wI 20 bbl H20 and 167.74 bbl mud. Bump plug. Check floats OK. EST 45 bbl good cement EXcess retums to surface. RD and CU cementing and casing equip. Clean floor. 2/29/2004 05:30 - 10:00 10:00 - 12:00 12:00 - 12:30 0.50 DRILL CIRC SURFAC 12:30 - 15:30 3.00 DRILL TRIP SURFAC 15:30 - 21 :00 5.50 DRILL PULD SURFAC 21 :00 - 23:00 2.00 CASE RURD SURFAC 23:00 - 00:00 1.00 CASE RUNC SURFAC 3/1/2004 00:00 - 02:30 2.50 CASE RUNC SURFAC 02:30 - 02:45 0.25 CASE CIRC SURFAC 02:45 - 04:30 1.75 CASE RUNC SURFAC 04:30 - 04:45 0.25 CASE CIRC SURFAC 04:45 - 05:15 0.50 CASE RUNC SURFAC 05:15 - 06:30 1.25 CASE RUNC SURFAC 06:30 - 07:30 1.00 CASE CIRC SURFAC 07:30 - 08:30 1.00 CASE RUNC SURFAC 08:30 - 12:30 4.00 CEMENTCIRC SURFAC 12:30 - 15:30 15:30 - 16:30 1.00 CASE RURD SURFAC 16:30 - 17:00 0.50 CASE RURD SURFAC 17:00 - 00:00 7.00 CASE NUND SURFAC 3/2/2004 00:00 - 02:30 2.50 WELCTL NUND SURFAC 02:30 - 05:00 2.50 WELCTL NUND SURFAC 05:00 - 12:00 7.00 WELCTL NUND SURFAC 12:00 - 17:00 5.00 WELCTL BOPE SURFAC LD landing Joint and send out tools. NU diverter, Blooie Line & 16" diverter slip on flange. Install 95/8" casing neck - Install FMC Gen V wellhead - Test to 1000 psi Rig PU slings & lift & set BOP stack on casing head NU BOPE - modify (to accomadate wellhead height) & install riser Test BOPE - Hydril to 250 & 3500 psi - pipe rams, blind rams, choke & kill valves, choke manifold valves, top drive IBOP's, floor safety & IBOP to 250 & 5000 psi - performed accumlator closure test - AGOCC Jeff Jones waived witnessing of test - Pull test plug - set wear bushing - LD Printed: 4/23/2004 3:37:05 PM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: PLACER #1 PLACER #1 ROT - DRILLING n1433@ppco.com Nordic 3 Start: 2/24/2004 Rig Release: 3/17/2004 Rig Number: Spud Date: 2/26/2004 End: 3/17/2004 Group: 3/212004 12:00 - 17:00 5.00 WELCTL BOPE SURFAC test jt. 17:00 - 23:00 6.00 DRILL PULD SURFAC Rig up to PU drill pipe - PU & std back 39 stds(117 its.) 4' drill pipe 23:00 - 00:00 1.00 DRILL PULD SURFAC Load 23 its. 4' HWDP in pipe shed 3/3/2004 00:00 - 02:30 2.50 DRILL PULD SURFAC MIU BHA #2-motor and MWD. Upload MWD 02:30 - 04:00 1.50 RIGMNT RSRV SURFAC Service top drive 04:00 - 05:30 1.50 DRILL PULD SURFAC RIH wI BHA #2. P/U flex collars. Test MWD 05:30 - 06:30 1.00 DRILL PULD SURFAC UD 2 its 3-1/2" SWDP and P/U 4" HWDP. 06:30 - 08:30 2.00 DRILL PULD SURFAC M/U Ghostreamer. RIH wI 3-1/2' SWDP out of derrick and UD 3-1/2" SWDP 08:30 - 10:30 2.00 DRILL TRIP SURFAC RIH picking up 4" DP (39 its)from pipe shed - RIH to 2427' top cmt- Clean out to top of FC @ 2447' 10:30 - 11 :00 0.50 DRILL CIRC SURFAC CBU 11 :00 - 12:00 1.00 DRILL OTHR SURFAC RU & test casing to 2500 psi for 30 mins. RD 12:00 - 14:00 2.00 CEMENT DSHO SURFAC Clean out shoe track & rat hole to 2548' - drill 20' new hole to 2568' 14:00 - 15:00 1.00 DRILL FIT SURFAC RU & perform FIT to 16.0 ppg EMW - RD 15:00 - 16:00 1.00 DRILL CIRC INTRM1 Change well over to 9.6 ppg LSND mud - clean out surface equip 16:00 - 00:00 8.00 DRILL DRLG INTRM1 Drill 8 1/2" hole f/2568' to 3184' MD 2772' TVD ADT - 5.19 hrs.= ART - 4.02 hrs. AST 1.17 hrs. WOB 5/15 k RPM 85 GPM 502 @ 2150 psi String wt. PU 76 SO 65nO ROT 75 Torque on/off btm - 6200/4500 ft. Ibs. 3/412004 00:00 - 04:00 4.00 DRILL DRLG INTRM1 Drill from 3184' to 3633' 04:00 - 05:30 1.50 RIGMNT RGRP INTRM1 Circulate wI #1 mud pump while replacing swabs in #2 mud pump 05:30 - 12:00 6.50 DRILL DRLG INTRM1 Drill from 3633' to 4415' MD - 3710' TVD ADT 6.30 hrs= ART 6.07 hrs AST .23 hrs. WOB 10/25 RPM 85 GPM 510 @ 3000 psi String wt. PU 90 SO 79 ROT 85 Torque on/off btm. - 8000/6000 ft.lbs. 12:00 - 14:00 2.00 DRILL DRLG INTRM1 Drill 8 1/2" hole f/4415' to 4650' Same parameters as above 14:00 - 16:00 2.00 DRILL OTHR INTRM1 Flow line plugged off - pushed wear bushing out of hole - Clean out flow line 16:00 - 20:30 4.50 DRILL DRLG INTRM1 Drill 8 1/2" hole fl 4650' to 5077' Same parameters as above 20:30 - 21 :30 1.00 DRILL CIRC INTRM1 Circulate btms up - Flow check (static) Pull 2 stds. 21 :30 - 23:30 2.00 DRILL OTHR INTRM1 Drain stack - flush stack - reinstall wear bushing 23:30 - 00:00 0.50 DRILL DRLG INTRM1 RIH wash & ream last std. to 5077' Drill 8 1/2" hole f/5077' to 5143' MD - 4270' TVD WOB 10/20 RPM 85 GPM 510 @ 3200 psi String wt. PU 95 SO 93 ROT 93 Torque on/off btm. - 9000/6000 ft. Ibs. 1200hrs. to 0000 hrs. ATD 5.03 hrs. = ART-4.13 hrs. AST .9 hrs. Note: Pumped weighted hi-vis sweeps @ 4070' & 4835' - good results 3/5/2004 00:00 - 05:30 5.50 DRILL DRLG INTRM1 Drill 8 1/2' hole f/5143' to 5616' WOB 10/25 RPM 85 GPM 500 05:30 - 06:00 0.50 DRILL OTHR INTRM1 Swivel packing blew out - Std. back 1 std. - Blow down TD - RU head pin to circulate 06:00 - 07:00 1.00 DRILL OTHR INTRM1 Replace swivel packing (circulate @ 245 gpm @ 1200 psi) 07:00 - 07:30 0.50 DRILL CIRC INTRM1 MU TD - work pipe & circ - hole in good condition 07:30 - 12:00 4.50 DRILL DRLG INTRM1 Drill 8 1/2" hole f/5616' to 5976' MD - 4901' TVD WOB 10/25 RPM 85 GPM 500 @3600 psi String wt. PU 105 SO 95 ROT 100 Printed: 4/23/2004 3:37:05 PM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: PLACER #1 PLACER #1 ROT - DRILLING n1433@ppco.com Nordic 3 Start: 2/24/2004 Rig Release: 3/17/2004 Rig Number: Spud Date: 2/26/2004 End: 3/17/2004 Group: 3/512004 07:30 - 12:00 4.50 DRILL DRLG INTRM1 Torque on/off btm - 12000/8000 ft. Ibs. ADT - 6.04 hrs. = ART 4.83 hrs. AST 1.21 hrs. 12:00 - 13:30 1.50 DRILL OTHR INTRM1 Replace swab on MP# 2 - Circ wI MP #1 @ 252 gpm @ 1050 psi 13:30 - 21 :30 8.00 DRILL DRLG INTRM1 Drill 8 1/2" hole f/5976' Same parameters as above 21 :30 - 22:00 0.50 DRILL OTHR INTRM1 Replace swab #2 MP 22:00 - 00:00 2.00 DRILL DRLG INTRM1 Drill 8 1/2" hole f/5976' to 6710' MD - 5467' TVD WOB 15/20 RPM 85 GPM 490 @ 3600 psi String wt. PU 107 SO 105 ROT 107 Torque onloff btm.- 14000/10000 ft.lbs. 1200 to 0000 hrs. ADT 6.34 hrs. = ART 4.16 hrs AST 2.18 hrs. 3/6/2004 00:00 - 02:00 2.00 DRILL DRLG INTRM1 Drill 8 1/2" hole f/6710' to 6870' 02:00 - 02:30 0.50 DRILL OTHR INTRM1 Replace swab in MP#1 (circ wI MP#2) 02:30 - 04:00 1.50 DRILL DRLG INTRM1 Drill 8 1/2" hole f/6870' to 6972' MD - xxxx' TVD WOB 15/25 RPM 85 GPM 490 @ 3900 psi String wt. PU 125 SO 100 ROT 110 Torque onloff btm. - 14,000/10,000 0000 to 0400 ADT- 2.26 hrs. ART 2.15 HRS. AST .11 hrs. 04:00 - 05:30 1.50 DRILL CIRC INTRM1 Pump weighted hi-vis sweep & circulate hole clean for trip 05:30 - 12:00 6.50 DRILL TRIP INTRM1 POOH on TT f/ 6972' to 6402' - hole started swabbing - Pump out fl 6402' to 5645' - Continue to POOH on TT - Std back HWDP-jars - Flex DC's 12:00 - 15:00 3.00 DRILL PULD INTRM1 Handle BHA - LD stab - check bit - down load MWD - Change out pulser - up load MWD( change liners in MP f/5" to 4 1/2" while handling BHA) 15:00 - 15:30 0.50 DRILL TRIP INTRM1 RIH wI BHA to 1098' - Attempt to shallow test MWD - swivel packing leaking - Blow down TD 15:30 - 16:30 1.00 DRILL OTHR INTRM1 Replace swivel packing 16:30 - 00:00 7.50 DRILL TRIP INTRM1 RIH to 1098' - shallow test MWD - Continue RIH to 6877' - wash & ream to 6972' - Circulate & work pipe -observed large amout of cuttings @ shakers @ btms. up - (cuttings au gar froze up shut down & clean out) Brought pumps back on line hole started taking fluid ( lost approx 180 bbls) slowed pumps worked pipe - mixing LCM pill 3/7/2004 00:00 - 00:30 0.50 DRILL OBSV INTRM1 Circulate & work pipe - losses static - Observed gain in mud volume 00:30 - 01 :00 0.50 WELCTL OBSV INTRM1 Shut down pumps & monitor well for flow - well flowing - Shut in well @0038 hrs. - SIDPP - 21 psi SICP 0 pis - monitor pressure for 20 mins. FDPP 0 CFPO Open well & observed slight flow - Well appears to be breathing after losses - Notified Field Drilling Superintendent 01 :00 - 02:30 1.50 DRILL DRLG INTRM1 Prep to drill - MWD not responding - trouble shoot MWD - Dril 8 1/2" hole fl 6972' to 7005' - MWD still not responding WOB 25 RPM 85 GPM 440 @ 3200 psi ADT - .25 hrs. 02:30 - 03:30 1.00 DRILL CIRC INTRM1 Circulate btms up - prep to POOH 03:30 - 06:30 3.00 DRILL TRIP INTRM1 POOH f/7005' to 4296' (25 stds.) - Circulate & check MWD - still not responding 06:30 - 10:00 3.50 DRILL TRIP INTRM1 Monitor well - continue POOH to Change out MWD- 10:00 - 12:00 2.00 DRILL PULD INTRM1 Blow down kill line - check bit - Down load MWD - Change out pulser - Up load MWD - 12:00 - 18:00 6.00 DRILL TRIP INTRM1 RIH to 475' - pulse test MWD(OK) - RIH to 3500' - Pulse test MWD(OK) - Circulate btms up @ 3500' - Continue RIH to 6587'(fill pipe every 10 Printed: 4/23/2004 3:37:05 PM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: PLACER #1 PLACER #1 ROT - DRILLING n1433@ppco.com Nordic 3 Start: 2/24/2004 Rig Release: 3/17/2004 Rig Number: Spud Date: 2/26/2004 End: 3/17/2004 Group: 3/7/2004 12:00 - 18:00 6.00 DRILL TRIP INTRM1 stds.) 18:00 - 20:00 2.00 DRILL REAM INTRM1 Wash & ream f/ 6587' to 7005' - Circulate btms up 20:00 - 00:00 4.00 DRILL DRLG INTRM1 Drill 8 1/2' hole fl7oo5' to 7250' MD - 5881' TVD WOB 15/25 RPM 80 GPM 440 @ 3400 psi String wt. PU 140 SO 95 ROT 115 Torque on/off btm - 9500/8500 ft. Ibs. ADT - 2.33 hrs.= ART - 1.25 hrs. AST - 1.08 hrs. 3/8/2004 00:00 - 03:00 3.00 DRILL DRLG INTRM1 Drill 8 1/2" hole f/7250' to 7477' MD 6061' TVD WOB 10/25 RPM 75/80 GPM 434 @ 3500 psi String wt. PU 145 SO 95 ROT 116 Torque on/off btm - 10,000/8,000 ft. Ibs. ADT - 1 .5 hrs.= ART - 1.5 hrs AST - 0 hrs. 03:00 - 04:30 1.50 DRILL CIRC INTRM1 Circ hole clean for wiper trip 04:30 - 07:00 2.50 DRILL WIPR INTRM1 Wiper trip f/7477' to 6590' - RIH wash & ream last 90' to btm 07:00 - 09:00 2.00 DRILL CIRC INTRM1 Pump sweep & circulate hole clean for casing - Flow check 09:00 - 14:00 5.00 DRILL TRIP INTRM1 POOH - Hole in good condition - (SLM) - to 1098' 14:00 - 17:30 3.50 DRILL PULD INTRM1 LD ghost reamer - Std. back HWDP - jars - NM flex DC's - Down load MWD - LD BHA - bit - motor - float sub - MWD 17:30 - 18:00 0.50 DRILL OTHR INTRM1 MU wash tool & flush BOP stack - Blow down TD 18:00 - 20:30 2.50 DRILL OTHR INTRM1 Pull wear bushing - set test plug - Change btm. pipe rams f/4" to 7" - Test door seals to 3500 psi - pull test plug 20:30 - 23:00 2.50 CASE RURD INTRM1 RU to run 7" casing - change bails, RU fill up tool, stabbing board, work platform, tongs, csg e;evators & slips 23:00 - 00:00 1.00 CASE RUNC INTRM1 PJSM - Run 7" casing as follows: FS, 2 its. 7" 26# L-80 BTCM, FC, 1 it. 7' 26# L-80 BTCM -(BakerLoc 1st 4 connections) - Trouble w/ GBR casing tongs 3/9/2004 00:00 - 00:30 0.50 CASE OTHR INTRM1 Change out GBR casing tongs 00:30 - 05:30 5.00 CASE RUNC INTRM1 Continue running 7" 26# L-80 BTCM csg - 59 jts. to 2511' 05:30 - 06:30 1.00 CASE CIRC INTRM1 Break circulation & circulate 7" casing vol· 4 B/M @ 260 psi· string wt. PU 80 SO 57 06:30 - 10:00 3.50 CASE RUNC INTRM1 Continue running 7' 26# L-80 BTCM csg - 100 its. total - 4266' - not getting proper mud returns 10:00 - 11 :30 1.50 CASE CIRC INTRM1 Break circulation & circulate btms up + @ 1 BPM 350 psi - hole taking fluid @ 24 BPH lost 35 bbls - 11 :30 - 13:00 1.50 CASE RUNC INTRM1 Continue running 7" 26# L-80 BTCM csg - 110 its. total - hole still taking fulid 1.5 bbls per 10 jts. 13:00 - 14:30 1.50 CASE CIRC INTRM1 Break circulation & circulate btms up+ @ 1.5 to 2 BPM @ 380 psi - losing fluid @ 12 BPH -lost 18 bbls 14:30 - 16:45 2.25 CASE RUNC INTRM1 Continue running 7" 26# L-80 BTCM csg - 140 its. total - hole giving back some fluid 16:45 - 18:45 2.00 CASE CIRC INTRM1 Break circulation & circulate btms up 1 BPM @ 429 psi - Hole taking fluid @ 30 BPH - lost 60 bbls 18:45 - 21 :30 2.75 CASE RUNC INTRM1 Finish running 7" 26# L-80 BTCM csg. 175 jts. & (1) 10' pup - to 7440.75' - PU hanger & landing it. land casing in wellhead on FMC 7' fluted hanger w/ shoe @ 7467' - FC 7387' 21 :30 - 22:00 0.50 CASE RURD INTRM1 RD fill up tool - RU cmt head 22:00 - 00:00 2.00 CEMENTCIRC INTRM1 Break circulation - Circ & condition mud for cmt. iob @ 1to 3 bbls/ min 350 psi - hole taking fluid lost 56 bbls -28 BPH lost rate 3/10/2004 00:00 - 01 :00 1.00 CEMENTCIRC INTRM1 Continue to circ & condition mud for cmt iob - lost 24 bbls - Held PJSM - Pumped 15 bbls LCM pill 01 :00 - 02:30 1.50 CEMENT PUMP INTRM1 Cement 7" csg as follows: Pumped 5 bbls CW-100 - test lines to 3500 psi - Pumped 15 bbls CW-100 @ 4BPM @ 673 psi - Dropped btm plug - Pumped 33 bbls Mud Push XL @ 13.0 ppg @ 4.5 BPM @ 714 psi- Printed: 4/23/2004 3:37:05 PM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: PLACER #1 PLACER #1 ROT - DRILLING n1433@ppco.com Nordic 3 Start: 2/24/2004 Rig Release: 3/17/2004 Rig Number: Spud Date: 2/26/2004 End: 3/17/2004 Group: 3/10/2004 01 :00 - 02:30 1.50 CEMENT PUMP INTRM1 Pumped 36 bbls tail slurry (Class G w/ additives) @ 15.8 ppg @ 5.4 BPM @ 850 psi - Dropped top plug wI 20 bbls water fl Dowell - Switch to rig pumps & displace w/11.0 ppg LSND mud @ 5 BPM @ 390 psi for first 183 bbls. -Increased pumps to 7 BPM wI CW-100 @ shoe wI 440 to 500 psi Spacer @ shoe 548 to 833 psi Cmt to shoe 833 to 910 psi - slowed pumps to 3 BPM for last 20 bbls 493 to 630 psi Bumped plug wI 1100 psi - CIP @ 0230 hrs. - Check floats - floats held Lost lost 26 bbls mud during cmt. job 02:30 - 06:30 4.00 CEMENTOTHR INTRM1 Observed 7" X 9 5/8" annulus flowing - Shut hydril - Monitor pressure ISIP - 40 psi - FSIP - 70 psi - bleed off pressure & open Hrdril - well still flowing - 06:30 - 07:00 0.50 CEMENT PULD INTRM1 RD cmt head & LD landing jt. 07:00 - 08:00 1.00 WELCTL NUND INTRM1 Install FMC 7" pack-off 7 test to 5000 psi for 10 mins. 08:00 - 09:00 1.00 DRILL RIRD INTRM1 Clear rig floor - LD cmt head, csg elevators, OX subs, - Install drilling bails 09:00 - 11 :00 2.00 WELCTL EQRP INTRM1 Install test plug - Change btm pipe rams f/7' to 4" 11 :00 - 16:30 5.50 WELCTL BOPE INTRM1 Test BOPE - Hyril to 150 psi low & 3500 psi high - pipe rams, blind rams, kill & choke line valves, choke manifold valves, TD IBOP, floor safety & dart valves to 150 psi low & 5000 psi high - Accumulator closure test - Test witnessed & Approved by Lou Gramaldi AOGCC 16:30 - 18:30 2.00 WELCTL EQRP INTRM1 Pull test plug - install wear bushing - Change saver sub in TD - blow down choke & kill lines 18:30 - 00:00 5.50 DRILL PULD INTRM1 MU BHA #4 - motor - MWD - orient motor - MU bit & remaining MWD componets - up load MWD - PU 1 NM flex DC & pulse test MWD wI 252 gpm @ 1200 psi - Held kick drill - pump through choke - Blow down 3/11/2004 00:00 - 01 :30 1.50 DRILL PULD INTRM1 Finish PU BHA #4 - Load RA sources - change out jars RIH wI HWDP 01 :30 - 03:00 1.50 DRILL TRIP INTRM1 RIH wI BHA #4 - PU 36 jts. 4" DP to 2261' - fill pipe & test MWD 03:00 - 03:30 0.50 DRILL SFTY INTRM1 Held table top stripping drill & pre drilling reservoir meeting while crew 03:30 - 05:00 1.50 DRILL TRIP INTRM1 Continue RIH f/2261' to 5663' - fill pipe 05:00 - 05:30 0.50 RIGMNT RSRV INTRM1 Service TD 05:30 - 08:00 2.50 DRILL TRIP INTRM1 Continue RIH f/ 5663' to 7351' - tag top of cmt. 08:00 - 09:45 1.75 CEMENTCOUT INTRM1 Clean out cmt & wiper plugs to 7372' 09:45 - 11 :45 2.00 DRILL CIRC INTRM1 Circulate hole clean for csg test 11 :45 - 13:00 1.25 CASE DEQT INTRM1 RU & test 7" casing to 2500 psi for 30 mins. RD 13:00 - 15:45 2.75 CEMENT DSHO INTRM1 Drill out shoe track - cmt, FC, cmt & FS to 7467' 15:45 - 18:00 2.25 DRILL OTHR INTRM1 Calibrate Totco equipment wI Totco rep. 18:00 - 18:45 0.75 DRILL DRLG INTRM1 Clean out rat hole to 7477' & Drill 20' new hole to 7497' 18:45 - 19:30 0.75 DRILL CIRC INTRM1 Circulate hole clean for FIT - Flow check (static) - Blow down TD 19:30 - 20:30 1.00 DRILL FIT INTRM1 RU & perform FIT to 14.0 ppg EMW w/950 psi w/11.0 ppg mud @ 6053' TVD - RD 20:30 - 00:00 3.50 DRILL DRLG PROD Drill 6 1/8" hole f/7497' to 7645' MD 6195' TVD WOB 8/12 RPM 70 GPM 276 @ 2800 psi String wt. PU 120 SO 95 ROT 105 ADT - 3 HRS. 3/12/2004 00:00 - 02:30 2.50 DRILL DRLG PROD Drill 6 1/8" hole f/7645' to 7761 'MD 6289' TVD WOB 8/12k, RPM 80, 276 gpm @ 3000 psi. PU wt 120k, SO wt 95 k, 105k rotating wt. ADT - 2.0 hrs 02:30 - 03:30 1.00 DRILL CIRC PROD Circulate two bottoms up. 03:30 - 04:30 1.00 DRILL WIPR PROD Short trip to 7" casing shoe (Backream), monitor well, RIH 04:30 - 05:00 0.50 DRILL CIRC PROD Pump up survey, circ and condition f/logs. 05:00 - 06:00 1.00 DRILL TRIP PROD Drop hollow 2.3/8" rabbit wI 120' wire attatched down drill pipe. Printed: 4/23/2004 3:37:05 PM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: PLACER #1 PLACER #1 ROT - DRILLING n1433@ppco.com Nordic 3 Start: 2/24/2004 Rig Release: 3/17/2004 Rig Number: Spud Date: 2/26/2004 End: 3/17/2004 Group: 3/12/2004 05:00 - 06:00 1.00 DRILL TRIP PROD Backream to 7" casing shoe. Blow down top drive. 06:00 - 12:00 6.00 DRILL TRIP PROD Monitor well. POOH, check crown-o-matic on first stand pulled. 12:00 - 13:00 1.00 DRILL PULD PROD Handle BHA - Std. back HWDP & jars - LD - NM flex DC's 13:00 - 16:30 3.50 DRILL PULD PROD PJSM - Remove RA sources fl MWD - Down load MWD - Pull pulser- LD MWD - flush motor wI fresh water - LD motor & bit - Clean up rig floor 16:30 - 00:00 7.50 LOG RURD PROD PJSM - RU Schlumberger - Run Log #1 - Dipole Sonic - Run log #2 CMR 3/13/2004 00:00 - 01 :00 1.00 LOG ELOG PROD POOH wI Schlumberger WL(Run log #2 CMR) unable to get below 1900' 01 :00 - 02:00 1.00 LOG RURD PROD RU fl DP conveyed logging tool. 02:00 - 03:30 1.50 LOG PULD PROD PU/MU MDT/CMR logging toolstring. 03:30 - 04:30 1.00 LOG DEQT PROD Surface test toolstring. 04:30 - 05:00 0.50 LOG SFTY PROD PJSM wI Schlumberger on running in hole wI toolstring and drillpipe. 05:00 - 13:30 8.50 LOG DLOG PROD RIH wI Schlumberger toolstring on 4" DP to 7350' . RIH slow. Circ 10 min at every 20 stands run. 13:30 - 16:00 2.50 LOG CIRC PROD Circ & condo mud - 32 units gas on btms up - Held PJSM while circ. - Hang scheve in drk - MU side entry sub 16:00 - 18:00 2.00 LOG OTHR PROD RIH wI wet connect to 7000' - pump down wet connect & latch in - secure clamp on SES - pull test to 2000 Ibs. - RD fill up hose & blow down 18:00 - 00:00 6.00 LOG DLOG PROD RIH & log Running CMR & MDT 3/14/2004 00:00 - 02:45 2.75 LOG DLOG PROD Finish running MDT on drill pipe - POOH to SES - POOH wI WL - LD SES & RD SWS 02:45 - 04:00 1.25 LOG CIRC PROD Circulate btms. up+ f/7350' - max. gas 641 units - flow check well (static) 04:00 - 11 :00 7.00 LOG DLOG PROD POOH wI logging tools on 4" DP - (hole fill short of calc.) monitor well observed slight trickle 11 :00 - 14:30 3.50 LOG PULD PROD LD logging tools 14:30 - 15:30 1.00 DRILL OBSV PROD Monitor well - well static 15:30 - 16:30 1.00 LOG RURD PROD RU SWS for MSCT 16:30 - 22:00 5.50 LOG ELOG PROD RIH w/ MSCT - took core samples - POOH - Checked samples OK - RD SWS 22:00 - 00:00 2.00 DRILL TRIP PROD MU 6 1/8" OH - RIH for clean out run - 3/15/2004 00:00 - 01 :30 1.50 DRILL TRIP PROD RIH w/6 1/8" hole opener for clean out run. Fill pipe. 01 :30 - 03:00 1.50 DRILL OTHR PROD While filling pipe, trip tank hose failed. Spilled 2 1/2 to 3 bbls mud in cellar into secondary containment. Repaired hose, clean up cellar. 03:00 - 05:45 2.75 DRILL TRIP PROD Continue RIH w/6 1/8" hole opener. Service Tesco top drive washpipe @ shoe. 05:45 - 06:15 0.50 DRILL TRIP PROD Continue RIH w/6 1/8" hole opener to 7752'. Break circulation.. Washpipe packing leaking. Blow down top drive. 06:15 - 06:45 0.50 DRILL TRIP PROD POOH 4 stands to work on wash pipe packing. 06:45 - 08:00 1.25 DRILL CIRC PROD Circ wI headpin while PJSM and change out washpipe packing. 08:00 - 08:30 0.50 DRILL TRIP PROD RIH to 7752'. 08:30 - 11 :15 2.75 DRILL CIRC PROD Circ and condition mud and hole. Max gas units 590 units 11:15 -12:30 1.25 DRILL REAM PROD UD single dp, backream 4 stands. 12:30 - 13:00 0.50 DRILL CIRC PROD Locate leak on Tesco top drive hydraulic hoses. Circ wI headpin while tighten auxiliary pressure and return hoses, where they connect to top drive. 13:00 - 13:45 0.75 DRILL OBSV PROD Monitor well. OK. Pump dry job 13:45 -18:00 4.25 DRILL TRIP PROD Continue POOH w/6 1/8" hole opener 18:00 - 00:00 6.00 DRILL RIRD PROD Unload 3 1/2" tbg fl pipe shed - full service TD - Move HWDP in derrick to run cmt retainer Printed: 4/23/2004 3:37:05 PM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: PLACER #1 PLACER #1 ROT - DRILLING n1433@ppco.com Nordic 3 Start: 2/24/2004 Rig Release: 3/17/2004 Rig Number: Spud Date: 2/26/2004 End: 3/17/2004 Group: RIH wI Baker N1 cast iron cement retainer on 4" dp. Set Baker N1 cast iron cement retainer @ 7385'. UD single dp. PU wt 140k SO wt 83K RU & circ mud in hole. Circ. at 6 bpm, 1220 psi. Pressure test 7" csg and retainer to 2500 psi. Mix and spot 230 # frac sand on top of retainer. Blow down circ hose and kill line. Fill trip tank and clean out under rotary bushing. POOH and stand back dp. UD XOs and retainer running tool. PU BOP washing tool and wash stack. Blow down TD. PU wear bushing tool and pull WB. RU to run 31/2" suspension kill string. Remove Diverter from sub and clean pits for move to next well. Run 50 jts 3 1/2 " 9.3 ppf EUE 8 rd L-80 tbg wI wireline guide shoe. MU tbg hanger. Land TBg at 1590.49' RILDS. Set 2 way check. Note: DNR rep Gary shultz made visit to pad. ACS rep Willie showed him around. ND annular preventer. Install Lifting plate and NU annular. Rig slings. Jack rig up to allow headroom for Bridge crane block. Bring tree into cellar, warmup and NU WKM 3 1/8" 5m tree assembly. RlU to test tree. TWC failed. Pull and redress TWC. Retest to 5000 psi. OK. RD test equip. PJSM for Freeze protect and Formation injectivity test. RU to freeze protect and conduct Injection test utilizing cellar kill manifold. Failed pressure test. Rework manifold and retest to 3000 PSI. Freeze protect inner annulus. Pumped 40 bbl @ 4 bpm & 600 psi. Increased to 6bpm @ 1000 psi. and pumped 25 bbl. Diesel cut at 65 bbl total pumped. Slow to 2 bpm @ 200 psi. Had clean diesel return at total 75 bbl diesel pumped. Shut in IA. 2.00 CMPL TN SEaT SUSPEN RU to outer annulus. Attempt pressure test manifold. No test. Attempt to isolate leak. Bypass manifold and rig directly to annulus wing vavle. Test lines to 3300 psi. 0.50 CMPL TN OTHR SUSPEN Injectivity test below 9 5/8 " surface casing wI H20 @ 0.5 bpm. Breakdown at 0.6 bbl &435psi. Pump total of 4.2 bbl @ 0.5 bpm. Final injection pressure was 385 psi. SI for 10 Min. ISIP + 387 psi. FSIP = 219 psi. Bleed back too small to register. 0.50 CMPL TN FRZP SUSPEN Pump 15 bbl water preflush at 3.3 bpm & 450 psi. Change over to diesel and test line to 1000 psi. Pump 55 bbl diesel @ 2.2 bpm. liP = 600 psi. FIP = 700 psi. 1.00 CMPL TN RURD SUSPEN RID hot oil lines. Set BPV. Secure well. Release rig at Midnight 3/17/04 3/16/2004 00:00 - 05:30 5.50 CASE PTCH SUSPEN 05:30 - 06:15 0.75 CASE PTCH SUSPEN 06:15 - 08:00 1.75 CASE CIRC SUSPEN 08:00 - 09:00 1.00 CASE MIT SUSPEN 09:00 - 11 :00 2.00 CASE PTCH SUSPEN 11 :00 - 11 :30 0.50 CASE OTHR SUSPEN 11 :30 - 15:30 4.00 CASE PTCH SUSPEN 15:30 - 16:15 0.75 CASE OTHR SUSPEN 16:15 - 17:00 0.75 CASE PULD SUSPEN 17:00 - 20:30 3.50 CASE RURD SUSPEN 20:30 - 23:00 2.50 CASE PUTB SUSPEN 23:00 - 00:00 1.00 CASE PUTB SUSPEN 3/17/2004 00:00 - 05:30 5.50 CMPL TN NUND SUSPEN 05:30 - 08:00 2.50 CMPL TN RURD SUSPEN 08:00 - 13:00 5.00 CMPL TN SEaT SUSPEN 13:00 - 13:30 0.50 CMPL TN SFTY SUSPEN 13:30 - 19:30 6.00 CMPL TN SEaT SUSPEN 19:30 - 20:00 0.50 CMPL TN FRZP SUSPEN 20:00 - 22:00 22:00 - 22:30 22:30 - 23:00 23:00 - 00:00 Printed: 4/23/2004 3:37:05 PM REV DATE I BY I CK I M'P Ie DESCRIPll0N \REVI DATE I BeCK I M'P 1 2/17/04 AJR MJH PER K04009ACS 1 NOTES: ' ßtR~>-1'(~ 2 ..)~". ~i '¡~ I ') \ì ~EI3J 3+ "i- ,( ) 56 . '.........01 tYIl ¡ 03 f "< 1) BASIS OF HORIZONTAL & VERTICAL ~~ THI~ -\ ~//~ \~¡~ 112M! ,,\~\' LOCA TlON IS USGS MONUMENT WOODS. 'Jv " "; SU~ '¡EY , \ K208 Ì'-,) 0 111N r>, ¡ 2) COORDINATES SHOWN ARE ALASKA ',' "v:.. \'J¿ l : ~ ! · I\}' v' J STATE PLANE ZONE 4, NAD 27. .---·!--->f~). : ~,.~----'---~/ ; - ----- -----~--"~- 3) GEOGRAPHIC COORD. ARE NAD 27. ~""'--l1c:- ~~j! " l ~~~~'~ '! è,,\ ! '0 4) ELEVATIONS SHOWN ARE BRITISH __0-7 Òo : () . \_ ___ _ \1) Oò '" ~ . ,_\1 ; ____ PETROLEUM MEAN SEA LEVEL DATUM. ¡ A"(ft>: t\ \'~): - 't èj Ìl . 5) ALL DISTANCES SHOWN ~RE TRUE. rl ? \\ "<Ô \J '"() I ", ,.! ~ 6) ICE PAD IS ROTATED 13 WEST FROM --.-.-- Ú,j---------- ¡ ----\--··-~~·-f1.. , " ' NORTH. 211" .., 2' ,. ç-'~, \ ~ ~ ¡ " 7) DATE OF SURVEY: 2/16/04. '~-. ---.___ r-"\ "--1) r~ ,(\ \~ ! FB L04-02, pp 64-66. L. . ~~-.( ~~ ì ¡ i \ l\.. ¡ ~ 15\..,J19:;o ï:-...~ ,\ I~ '- 29 :<8 ~-...J',~2S 1\2: '17 C~'\ l)! ¡, 52 3e\ :u;o\ 31 ¡ 32- \ ;;tllll i DESCRIPllON N A so<! --::;ì ~ -y ~~ ~rJ ,.0' .A -- 0" '. ~ '/P' 'Z:' ,~ ~ --""1 ~ 0. Va VI - . \ C'~ ~ -. . \ arJ \ --~ '7 . \ \~~ ~) \ , \ \ 2Q9 ....1 tJI~ ~g5~d_- \ g.\- _ _ - -ð,OrJ ~l--~--- ~ci ~ J2 .'" VICINITY MAP Scale: 1" = 2 Miles PLACER 1 LOCATED WITHIN PROTRACTED SECTION 33, T 12 N. R 7 E UMIAT MERIDIAN LAT.= 70'20'47.021" LONG.= 150'23'43.392- Y = 5976426.45 X = 451290.60 19' F. W.L, 1009' F.S.L GROUND ELEV. = 21.6' RIG PAD ELEV. = 25.0' ~, ~ ROOÒ :;... - r; tJI. ~ \ e P o~ -- ~~~"'1t.""" C __ "£ ~.. r:- OF "'_ __ 77'0rJOO .4i~::\ ~ ........... .... ~ .;'<:' .... .... IIIf'Â · r .-" ... ....f: I -- -I..... ..... I: ¡J1.!~ \" if .....1...... ... .... ..... ... I' 1.1.1 i ,I.......... .... ... ...1...................., \II'!:;Q~ :cri/l ,~ \ LAN J. ROOKUS l pø \ ~""" ~LS-8ø03~..<J' ¡ t.. ~ ...... /, ~ . ~I .. () ~ ...~. . "'~<;) ~ SURVEYOR'S CERTIFICA TE ._....:::~~~~~..4i I HEREBY CERTIFY THAT I AM PROPERLY REGISTERED AND LICENSED TO PRACTICE LAND SURVEYING IN THE STATE OF ALASKA AND THAT THIS PLAT REPRESENTS A SURVEY DONE BY ME OR UNDER MY DIRECT SUPERVISION AND THAT ALL DIMENSIONS AND OTHER DETAILS ARE CORRECT AS OF FEBRUARY 16, 2004. \ \ L--- PLACER 2 32 ¡33 514 LOCATED WITHIN PROTRACTED SECTION 32, T 12 N. R 7 E UMIAT MERIDIAN LA T.= 70'20'46.930" LONG.= 150'23'44.529- Y = 5976417.44 X = 451251.65 20' F.E.L., 999' F.S.L GROUND ELEV. = 22.2' RIG PAD ELEV. = 25.0' ~ LOUNSBURY at ASSOCIATES, INC. SUIIV!IYORS BNGINDRS PLANNBlIS , Con 0 cJPhiiii ps Alaska, Inc. CADD FILE NO. / / I DRA'MNG NO: LK601D541 2 17 04 AREA: 00 MODULE: XXXX UNIT: M1 PLACER 1 AND 2 EXPLORATION WELL CONDUCTORS AS-BUILT LOCATION CEA-M1XX-601D541 I PART: 1 OF 1 REV: 1 e Placer 1 Well Events e Date Summary 04/11/04 RIH WI CEMENT NOZZLE AND TAG SAND TOP AT 7357'. CIIRCULATED 30 BBLS BRINE 11 PPG, PUMPED 5 BBLS OF FRESH WATER, LAYED IN 12 BBLS OF CLASS G CEMENT FOLLOWED BY 5 BBLS FRESH WATER AND 33 BBLS OF 11 PPG BRINE. TOP OF CEMENT SHOULD BE AT 7029' . DIESEL FP TO 2000' Conductor: 16", 62.58# Set @ +/- 115' MD Surface Casing 9-5/8" 40# L-80 HIC - Float Collar to Surface Float Collar: Weatherford Single Valve 9-5/8" 32-53# BTC 130)( x Pin (2) Joints Casing: 9-5/8" 40# L -80 BTC Float Shoe: Weatherford - Single Valve 9-5/8" 32-53# BTC I3OJ( Up ¡Iii Placer 1 Actual - Suspension Schematic Exploration Wen - Confidential TD 12-1/4" Holei (à; +/- 2,528' MD/2,268' TVD-RKB Intermediate I Prlc~~uction Casing: 7" 26# L -80 BTC - Float Collar to Surface Float Collar: Weatherford - Single Valve 7" 20-35# BTC Box :~ (2) Joints Casin9: 7" 26# L-80 BTC Float Shoe: Weatherford - Single Valve 7" 20-35# BTC Box Up TD 8-1/2" Hole (æ +/-1,461' MD 16,053' TVD-RIŒ Top Kuparuk 7,539' MD-RKB Base Kuparuk 7,560' MD-RKB MDT Pressure Samples confirm 9.9 ppg EMW in the Kuparuk TD 6-1/8" OpenUi(l~f~ (Õ) +1-1,161' MD I 6,289' TVD-RKB RIŒ Assumed (Õ) 55' Above 55 25' Ice Pad Height (Above S5) 30' Nordic Rig 3 RKB 3-1/2",9.3#, L-80, EUE-8rd Mod Kill String landed @ +/- 1,590'. 16 PPG FIT - 750 psi. 9.7 ppg Muc(, 2268' TVD 12 BBL (328' Lenqth) Cement Pluq spotted on 7 Class G + Additives (1.2 GPS 0600,1.0 % 020,0.4% 065,0.35% 0800. .1 GPS 047) Slurry Weight 15.8 ppg 10' Sand Plug spotted on top of retainer following pressure test. Sand Plug Top Estimated @ +/- 7375' MD Baker N-l Cast Iron Cement Retainer. (Retainer Top @ +/- 7,385' MD RKB - Retainer Þressure tested to 2500 psi) 14 PPG FIT - 950 psi. 11.0 ppg Mud, 6053' TVD Placer 1 Suspension Schematic v1. 0 prepared by Mark Chambers 04/15/04 e Halliburton Sperry-Sun North Slope Alaska ConocoPhillips Exp Exploration 2004 Placer 1 Placer #1 Job No. AKMW2893106, Surveyed: 12 March, 2004 Survey Report 2004 15 April, e Your Ref: API 501032048100 Surface Coordinates: 5976426.45 N, 451290.60 E (70020' 47.0210" N, 150023' 43.3922" W) Grid Coordinate System: NAD27 Alaska State Planes, Zone 4 Survey Ref: svy617 Surface Coordinates relative to Project: 13.55 S, 58.40 W (Grid) Surface Coordinates relative to Structure: 13.93 S, 58.31 W (True) Kelly Bushing Elevation: 56.00ft above Mean Sea Level Kelly Bushing Elevation: 56.00ft above Structure 5i ---I '''''Y-5U., P.~tl,.._L,J N G 5 e FtV I t:Jª 5 A Halliburton Company Halliburton Sperry-Sun Survey Report for Exploration 2004 - Placer 1 . Placer #1 Your Ref: API 501032048100 Job No. AKMW2893106, Surveyed: 12 March, 2004 ConocoPhillips Exp North Slope Alaska Measured True Sub-Sea Vertical Local Coordinates Global Coordinates Dogleg Vertical Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastings Rate Section Comment (ft) (ft) (ft) (ft) (ft) (ft) (ft) (0/100ft) 0.00 0.000 0.000 -56.00 0.00 0.00 N O.OOE 5976426.45 N 451290.60 E 0.00 MWD Magnetic 110.00 0.000 0.000 54.00 110.00 0.00 N O.OOE 5976426.45 N 451290.60 E 0.000 0.00 240.17 0.220 49.460 184.17 240.17 0.16 N 0.19 E 5976426.61 N 451290.79 E 0.169 -0.14 333.33 0.310 31.520 277.33 333.33 0.49 N 0.46 E 5976426.94 N 451291.06 E 0.130 -0.43 420.37 0.310 58.570 364.37 420.37 0.82 N 0.78 E 5976427.26 N 451291.39 E 0.167 -0.72 e 513.23 0.390 53.430 457.23 513.23 1.14 N 1.25 E 5976427.58 N 451291.86 E 0.092 -0.98 604.56 0.440 65.820 548.55 604.55 1.47 N 1.82 E 5976427.90 N 451292.43 E 0.112 -1.24 697.19 0.780 123.250 641.18 697.18 1.27 N 2.67 E 5976427.70 N 451293.28 E 0.710 -0.93 788.62 2.070 127.280 732.58 788.58 0.08S 4.51 E 5976426.34 N 451295.10 E 1.414 0.62 878.88 3.280 141.160 822.74 878.74 3.08S 7.42 E 5976423.33 N 451298.00 E 1.511 3.95 972.93 5.880 163.130 916.49 972.49 9.785 10.51 E 5976416.60 N 451301.04 E 3.287 10.98 1064.51 8.970 175.580 1007.29 1063.29 21.395 12.42 E 5976404.98 N 451302.88 E 3.785 22.73 1156.33 14.100 176.620 1097.23 1153.23 39.71 5 13.63 E 5976386.65 N 451303.97 E 5.591 41.06 1247.72 16.360 176.680 1185.40 1241.40 63.67 S 15.03 E 5976362.68 N 451305.22 E 2.473 65.02 1343.10 18.470 173.700 1276.41 1332.41 92.10 S 17.47 E 5976334.23 N 451307.47 E 2.401 93.54 1437.28 24.020 171.770 1364.16 1420.16 125.93 S 21.85 E 5976300.38 N 451311.64 E 5.939 127.65 1530.95 26.060 171.460 1449.02 1505.02 165.155 27.64 E 5976261.12 N 451317.17 E 2.182 167.28 1626.78 30.670 173.560 1533.32 1589.32 210.28 S 33.51 E 5976215.96 N 451322.74 E 4.921 212.78 1721.16 37.430 175.940 1611.48 1667.48 262.87 5 38.25 E 5976163.34 N 451327.14 E 7.299 265.56 1816.21 40.800 176.250 1685.21 1741.21 322.69 5 42.32 E 5976103.49 N 451330.83 E 3.551 325.44 1911.23 42.110 174.530 1756.43 1812.43 385.38 5 47.39 E 5976040.77 N 451335.49 E 1.827 388.29 e 2005.29 43.250 173.850 1825.58 1881.58 448.82 5 53.85 E 5975977.29 N 451341.53 E 1.307 452.04 2100.54 43.680 174.550 1894.71 1950.71 514.00 S 60.47 E 5975912.06 N 451347.73 E 0.678 517.55 2195.11 42.490 173.540 1963.78 2019.78 578.25 5 67.17 E 5975847.77 N 451354.01 E 1 .454 582.13 2289.87 41.320 172.750 2034.30 2090.30 641.095 74.71 E 5975784.89 N 451361.15 E 1.354 645.42 2385.38 41 .520 172.450 2105.92 2161.92 703.75 5 82.85 E 5975722.18 N 451368.88 E 0.295 708.60 2478.78 41.770 171.670 2175.72 2231. 72 765.22 5 91.43 E 5975660.65 N 451377.05 E 0.616 770.66 2554.67 41 .290 171.500 2232.53 2288.53 814.995 98.79 E 5975610.83 N 451384.09 E 0.650 820.96 2649.05 40.860 170.940 2303.68 2359.68 876.28 S 108.25 E 5975549.49 N 451393.16 E 0.600 882.94 2743.51 39.600 172.620 2375.80 2431.80 936.65 S 116.99 E 5975489.06 N 451401.50 E 1.760 943.92 2838.47 38.750 172.900 2449.41 2505.41 996.16 S 124.55 E 5975429.50 N 451408.67 E 0.914 1003.91 2933.43 39.020 173.460 2523.33 2579.33 1055.355 131.63E 5975370.27 N 451415.37 E 0.467 1063.52 3026.06 39.770 172.630 2594.91 2650.91 1113.705 138.75 E 5975311.87 N 451422.11 E 0.989 1122.31 3122.42 39.380 173.180 2669.19 2725.19 1174.625 146.33 E 5975250.90 N 451429.30 E 0.544 1183.69 3216.77 38.710 173.100 2742.46 2798.46 1233.63 5 153.43 E 5975191.85 N 451436.01 E 0.712 1243.13 15 April, 2004 - 16:37 Page 2 of 5 DrillQuest 3.03.06.002 Halliburton Sperry-Sun Survey Report for Exploration 2004 - Placer 1 - Placer #1 Your Ref: API 501032048100 Job No. AKMW2893106, Surveyed: 12 March, 2004 ConocoPhillips Exp North Slope Alaska Measured True Sub-Sea Vertical Local Coordinates Global Coordinates Dogleg Vertical Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastings Rate Section Comment (ft) (ft) (ft) (ft) (ft) (ft) (ft) ("/1000) 3311.70 40.170 173.910 2815.78 2871.78 1293.55 S 160.25 E 5975131.89 N 451442.44 E 1.631 1303.43 3405.60 39.880 172.380 2887.68 2943.68 1353.50 S 167.45 E 5975071.89 N 451449.25 E 1.092 1363.81 3500.76 40.920 172.130 2960.15 3016.15 1414.61 S 175.76 E 5975010.73 N 451457.17 E 1.106 1425.48 3596.03 40.730 171.720 3032.24 3088.24 1476.28 S 184.51 E 5974949.01 N 451465.51 E 0.345 1487.75 3690.02 40.460 171.500 3103.61 3159.61 1536.78 S 193.44 E 5974888.44 N 451474.04 E 0.325 1548.89 e 3784.87 41 .830 172.690 3175.04 3231.04 1598.59 S 202.01 E 5974826.58 N 451482.22 E 1.664 1611.29 3879.48 41.690 173.070 3245.61 3301.61 1661.12 S 209.82 E 5974764.00 N 451489.62 E 0.306 1674.30 3973.89 41 .360 173.210 3316.29 3372.29 1723.26 S 217.30 E 5974701.81 N 451496.69 E 0.363 1736.89 4068.79 40.860 172.520 3387.79 3443.79 1785.17S 225.04 E 5974639.85 N 451504.04 E 0.711 1799.28 4163.27 40.250 172.680 3459.58 3515.58 1846.09 S 232.96 E 5974578.89 N 451511.55 E 0.655 1860.71 4258.08 39.540 172.600 3532.32 3588.32 1906.40 S 240.75 E 5974518.53 N 451518.95 E 0.751 1921.52 4352.61 38.790 172.300 3605.61 3661.61 1965.58 S 248.59 E 5974459.30 N 451526.41 E 0.818 1981.21 4447.50 37.970 172.240 3679.99 3735.99 2023.96 S 256.51 E 5974400.87 N 451533.95 E 0.865 2040.12 4542.14 39.290 174.630 3753.93 3809.93 2082.65 S 263.25 E 5974342.14 N 451540.31 E 2.105 2099.19 4636.02 39.330 175.200 3826.57 3882.57 2141.89S 268.52 E 5974282.86 N 451545.19 E 0.387 2158.64 4730.47 40.770 174.650 3898.86 3954.86 2202.42 S 273.90 E 5974222.30 N 451550.18 E 1.570 2219.38 4825.04 40.170 174.740 3970.81 4026.81 2263.54 S 279.58 E 5974161.14 N 451555.46 E 0.637 2280.73 4920.07 39.320 174.130 4043.88 4099.88 2324.01 S 285.46 E 5974100.63 N 451560.96 E 0.984 2341.47 5014.32 40.030 173.420 4116.42 4172.42 2383.83 S 291.99 E 5974040.78 N 451567.09 E 0.894 2401.64 5108.61 39.390 173.260 4188.95 4244.95 2443.66 S 298.98 E 5973980.90 N 451573.69 E 0.687 2461.88 5204.21 40.740 174.300 4262.12 4318.12 2504.83 S 305.64 E 5973919.69 N 451579.95 E 1.576 2523.41 e 5299.08 40.340 173.980 4334.21 4390.21 2566.17 S 311.93 E 5973858.31 N 451585.85 E 0.475 2585.06 5394.22 39.510 174.130 4407.17 4463.17 2626.90 8 318.26 E 5973797.54 N 451591.78 E 0.878 2646.11 5488.56 40.980 174.120 4479.18 4535.18 2687.53 8 324.50 E 5973736.87 N 451597.62 E 1.558 2707.05 5581.47 40.220 174.250 4549.72 4605.72 2747.688 330.62 E 5973676.68 N 451603.36 E 0.823 2767.50 5675.79 42.570 173.710 4620.48 4676.48 2809.70 S 337.17 E 5973614.62 N 451609.50 E 2.520 2829.85 5772.13 42.110 173.230 4691.69 4747.69 2874.17 S 344.55 E 5973550.11 N 451616.46 E 0.584 2894.74 5867.00 41.030 173.510 4762.66 4818.66 2936.69 S 351.82 E 5973487.53 N 451623.32 E 1.155 2957.69 5961.79 40.150 173.350 4834.64 4890.64 2997.96 S 358.87 E 5973426.22 N 451629.98 E 0.935 3019.36 6053.73 41.510 172.660 4904.21 4960.21 3057.628 366.20 E 5973366.51 N 451636.92 E 1.558 3079.47 6151.24 40.640 172.500 4977.72 5033.72 3121.15 S 374.47 E 5973302.93 N 451644.78 E 0.899 3143.54 6246.05 39.660 171.980 5050.18 5106.18 3181.738 382.72 E 5973242.30 N 451652.64 E 1.092 3204.66 6341.02 38.410 171.790 5123.95 5179.95 3240.94 S 391.16 E 5973183.04 N 451660.69 E 1.322 3264.46 6435.16 39.520 172.420 5197.15 5253.15 3299.58 8 399.29 E 5973124.35 N 451668.44 E 1.252 3323.65 6530.45 38.610 172.510 5271.13 5327.13 3359.11 S 407.17 E 5973064.77 N 451675.93 E 0.957 3383.70 15 April, 2004 - 16:37 Page 3 of 5 DrillQuest 3.03.06.002 Halliburton Sperry-Sun Survey Report for Exploration 2004 - Placer 1 - Placer #1 Your Ref: API 501032048100 Job No. AKMW2893106, Surveyed: 12 March, 2004 ConocoPhillips Exp North Slope Alaska Measured True Sub-Sea Vertical Local Coordinates Global Coordinates Dogleg Vertical Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastings Rate Section Comment (ft) (ft) (ft) (ft) (ft) (ft) (ft) (°/1000) 6625.43 39.760 173.030 5344.75 5400.75 3418.64 S 414.71 E 5973005.19 N 451683.09 E 1.259 3443.70 6719.50 41.050 172.660 5416.38 5472.38 3479.14 S 422.31 E 5972944.64 N 451690.29 E 1.395 3504.68 6813.89 40.410 172.900 5487.91 5543.91 3540.24 S 430.05 E 5972883.49 N 451697.64 E 0.698 3566.26 6908.78 39.100 172.660 5560.86 5616.86 3600.44 S 437.68 E 5972823.24 N 451704.87 E 1.390 3626.94 7003.16 38.470 172.540 5634.43 5690.43 3659.07 S 445.29 E 5972764.57 N 451712.10 E 0.672 3686.06 e 7098.76 38.120 172.830 5709.46 5765.46 3717.83 S 452.84 E 5972705.76 N 451719.26 E 0.412 3745.30 7193.08 40.200 172.410 5782.59 5838.59 3776.89 S 460.49 E 5972646.64 N 451726.54 E 2.223 3804.86 7288.00 39.010 171.790 5855.72 5911.72 3836.83 S 468.80 E 5972586.66 N 451734.46 E 1.321 3865.36 7383.00 37.860 171.870 5930.13 5986.13 3895.28 S 477.20 E 5972528.15 N 451742.47 E 1.212 3924.40 7419.83 37.600 171.840 5959.26 6015.26 3917.59 S 480.39 E 5972505.82 N 451745.52 E 0.708 3946.93 7504.96 36.820 172.540 6027.06 6083.06 3968.60 S 487.39 E 5972454.77 N 451752.19 E 1.042 3998.41 7598.67 36.700 172.580 6102.14 6158.14 4024.20 S 494.65 E 5972399.12 N 451759.09 E 0.131 4054.49 7695.08 35.760 172.570 6179.91 6235.91 4080.71 S 502.01 E 5972342.57 N 451766.08 E 0.975 4111.47 7761.00 35.760 172.570 6233.40 6289.40 4118.91 S 506.99 E 5972304.33 N 451770.82 E 0.000 4149.99 Projected Survey All data is in Feet (US Survey) unless otherwise stated. Directions and coordinates are relative to True North. Vertical depths are relative to Well. Northings and Eastings are relative to Well. Global Northings and Eastings are relative to NAD27 Alaska State Planes, Zone 4. The Dogleg Severity is in Degrees per 100 feet (US Survey). Vertical Section is from Well and calculated along an Azimuth of 173.080° (True). Based upon Minimum Curvature type calculations, at a Measured Depth of 7761.00ft., The Bottom Hole Displacement is 4149.99fl., in the Direction of 172.983° (True). e 15 April, 2004 - 16:37 Page 4 of 5 DrillQuest 3.03.06.002 Halliburton Sperry-Sun Survey Report for Exploration 2004 - Placer 1 - Placer #1 Your Ref: API 501032048100 Job No. AKMW2893106, Surveyed: 12 March, 2004 ConocoPhillips Exp North Slope Alaska Comments Measured Depth (ft) Station Coordinates TVD Northings Eastings (ft) (ft) (ft) Comment 7761.00 6289.40 4118.91 S 506.99 E Projected Survey e Survey tool program for Placer 1 - Placer #1 From Measured Vertical Depth Depth (ft) (ft) To Measured Vertical Depth Depth Survey Tool Description (ft) (ft) 0.00 0.00 7761.00 6289.40 MWD Magnetic e 15 April, 2004 - 16:37 Page 5 of 5 DrillQuest 3.03.06.002 - PRESSURE INTEGRITY TEST CONOCOPHILLIPS Alaska, Inc. Well Name: Placer #1 Rig: Nordic #3 Date: 3/16/2004 Drilling Supervisor: Rizek/Mickey pump used: I #1 Mud Pump I. Type of Test: I Casing Integrity Test Only r ...1 Pumping down I annulus and DP. I'" Hole Size: 16-3/4" 1..\ Casing Shoe Depth II Hole Depth RKB-CHF: I 25.51Ft 7,467 IFt-MDI 6,053IFt-TVD 7,385IFt-MD I 5,988IFt-TVD Caslnq Size and Description: 17" 26#/R J-55 BTC-MOD 1..1 Casinq Test Pressure InteqritvTest Mud Weight: 11.0 ppg Mud Weight: ppg Mud 10 min Gel: 16.0 Lb/100 Ft2 Mud 10 min Gel: Lb/100 Ft2 Test Pressure: 2,500 psi Rotating Weight: Lbs Rotating Weight: 110,000 Lbs BlocksfTop Drive Weight: Lbs BlocksfTop Drive Weight: 24,000 Lbs Desired PIT EMW: ppg Estimates for Test: 2.3 bbls Estimates for Test: 0 psi I Volume Input J-o '-\-0 \ ~ Volume/Stroke Pump Rate: Strokes ~ 0.0470 Bbls/Strk ~ e I..l Obbls I.. EMW = Leak-off Pressure + Mud Weight = Go to PIT Plot. 0 0.052 x TVD 0.052 x 6053 + This is a Casing Test #### ppg PIT 15 Second Shut-in Pressure, psi Fill in FIT Columns ==> 3000 . - Lost 30 psi during test, held = 98.8% of test pressure. :"*~'$.!.~l*~"..;~J:,~l 1~1.. .<Ii. 2500 - -; 2000· 1.~-I~lFf) - w a: ::I ~ 1500· W æ 1000- / soo-/ 0/" o 5 10 1S 20 25 Shut-In time, Minutes o PIT Point APR ) 7 ZUOl 'In J~ .J _OI'~:;' "11 ¡-- 3 2 Barrels ~CASING TEST _LEAK-OFF TEST Comments: Casing Test Pumping Strks psi o 0 2 185 ,.,.""Jªºº, //400 8 520 1 0 620 12 720 14 830 16 925 18 1025 :':-:';-:';';';':20: ';':':";1"2,(), '}:i~i iiiªjö' 'ï"·~::::.:.::::::::::) ;:;:;.;:;:;:;:;:;:;:;:::::::; . .:::~{f!.JJ~øø "':::H~:ß:/J;mQ ':'~: :f14$.9 ::::f:ª-Q:JßØø 'f':??ðß9Q: :::/JB:ð1~Q ::\/3.Q 1900 /,:\:38 2000 40 2110 42 2230 44 2340 46 2450 47 2500 30 Volume Pumped 2.2 tsbls Shut-in Min psi o 2500 1 2490 2 2485 3 2482 4 2480 5 2479 6 2479 7 2479 8 2479 9 2479 10 2479 15 2475 20 2475 25 2470 30 2470 Volume Bled Back 2.21 tsbls 7.0 Strkjmin ... Pressure In-:egrlty I est Pumping Shut-in Strks psi Min psi o 0.25 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5 5.5 6 6.5 7 7.5 8 8.5 9 9.5 10 Vo ume Pumped 0.0 tsbls Vo ume Bled Back Itsbls ..- (S) (L ""-1 a: èX)~-O\ ~ê RECEIVED APR 0 7 2004 AtIiII.'GllCa nr-'U'v ,WItaIII . . ~ ConocoPhillips Alaska, Inc. Bayview Geological Facility 619 East Ship Creek Ave., Suite 102 Anchorage, AK 99510 phone 907.263.4859 TO: AOGCC 333 WEST 7TH ANCHORAGE, AK. 99510 DATE: APRIL 13, 2004 AIRBILL: Airland 5271836 AFT#: CPBV04-04-13-34 CHARGE CODE: N.AK.EXPL. OPERATOR: ConocoPhillips Alaska,lnc. SAMPLE TYPE: DRY CUTTINGS NUMBER OF BOXES: 25 NAME: SCOUT #1 PLACER #1 SAMPLES SENT: PLACER #2 ONE COMPLETE SET OF DRY CUTTING FROM PLACER #1. PLACER #2 AND SCOUT #1 AS RECEIVED FROM THE RIG. ~ ~c.¡- \!Jl'-f PLACER #1 100'-7761' tf-/(37 #- /1 J 8 #=-IC 3q ~aC{-()) PLACER #2 J,e'1'-o(:)<,. SCOUT #1 0'-9118.7' 450' -8050' UPON RECEIPT OF THESE SAMPLES PLEASE NOTE ANY DISCREPANCIES AND SEND A SIGNED COpy OF THIS TRANSMITTAL TO: RECEIVED BY, tJ () ~ ConocoPhillips Alaska Inc. BAYVIEW GEOLOGIC FACILITY 619 E. Ship Creek Ave. ANCHORAGE, AK. 99510-0360 ATTN: D. L. Przywojski ABV-100 DATE: I) ~~ ~'f Cc: A. ANDREOU CPAI G. WILSON CPAI ~,I e e Paul Mazzolini Exploration DrillingTeam Leader Drilling & Wells ConocóP'hillips P. O. Box 100360 Anchorage, AK 99510-0360 Phone: 907-263-4603 April 5, 2004 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West ¡th Avenue Suite 100 Anchorage, Alaska 99501 RECEIVED APR - 6 2004 Alaska Oil & Gas Cons. Commission Anchorage Subject: Application for Sundry Operations on Placer #1 (204-014) Dear Commissioner: ConocoPhillips Alaska, Inc. hereby submits the attached Application for Sundry Approval to effect a suspension of the Placer #1 onshore exploratory well in the Kuparuk River Unit. As indicated in the attachments, the well was spudded 2/27/04 and TD'd on 3/12/04. After drilling Placer #2 the decision has been made to suspend Placer #1. This suspension is being requested to evaluate the results of Placer #1 and #2. If you have any questions regarding this matter, please contact me at 263-4603. Sincerely, ?J f11~ P. Mazzolini Exploration Team Leader CPAI Drilling PM/skad , 1. Type of Request: Abandon Alter casing RECEIVED ALASKA Oil AND GAS CONSERVATION COMMISSION APR - 6 2004 APPLICATION FOR SUNDRY APPROVAl_. k O'I&G C C ., 20 AAC 25.280 JO $ a I as ons. OlTlffilSSIOn o Suspend 0 Operational shutdown 0 Perforate 0 Variance An~riJg.lnnular Dispos.O o Repair well 0 Plug Perforations 0 Stimulate 0 Time Extension 0 Other 0 o Pull Tubing 0 Perforate New Pool 0 Re-enter Suspended Well Change approved program 2. Operator Name: ConocoPhillips Alaska, Inc. 3. Address: P. O. Box 100360, Anchorage, Alaska 99515 7. KB Elevation (ft): 55' AMSL & / 30' RKB STATE OF ALASKA e 4. Current Well Class: Development 0 Stratigraphic 0 5. Permit to Drill Number: Exploratory 0 Service -0 204-014 6. API Number: 50-103-20481-00 9. Well Name and Number: Placer #1 8. Property Designation: ADL 389132 11. Total Depth MD (ft): 7761' Casing Structural Conductor Surface Intermediate Open Hole Perforation Depth MD (ft): N/A Packers and SSSV Type: Total Depth TVD (ft): Effective Depth MD (ft): 6289' Length Size 10. Field/Pools(s): Exploratory PRESENT WELL CONDITION SUMMARY Effective Depth TVD (ft): Plugs (measured) Junk (measured): TVD Burst Collapse MD 105' 16" 115' 2498' 9.625" 2528' 7437' 7" 7467' ~ 0\1~\ 7761' /z¡o/fv\ '"\ I (;¡ 115' 2268' 6053' 6289' Perforation Depth TVD (ft): N/A Packers and SSSV MD (ft): Tubing Grade: n/a Tubing MD (ft): n/a Tubing Size: n/a none 12. Attachments: Description Summary of Proposal 0 Detailed Operations Program 0 BOP Sketch 0 14. Estimated Date for Commencing Operations: 16. Verbal Approval: Commission Representative: none 13. Well Class after proposed work: Exploratory 0 Development 0 15. Well Status after proposed work: Oil 0 Gas 0 WAG 0 GINJ 0 Abandoned 0 WDSPL 0 Service 0 Plugged 0 WINJO 4/5/2004 Date: Contact 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Mark Chambers @ 265-1319 Printed Name P. Mazzolini Signature ?~Y1arF Title Drilling Team Leader Phone 263-4603 COMMISSION USE ONLY Date 04¡ ÞIø / ~t>04- Conditions of approval: Notify Commission so that a representative may witness Plug IntegrityO Sundry Number: '1Ô '-l / ó 1 BOP Test 0 Mechanical Integrity Test 0 Location Clearance 'R Other: .., ri"'\O ' D:::>V '"So, ~~1'""\.'ì.\'0~ \' c..TßC)t' \-e<;\-. '\ \'<:..-<:>-C;\\'S.~S~ C"G~ ·\-Ò ~e c;0~~\:<-c. Form 10-403 Revised 2/2003 --- COMMISSIONER BY ORDER OF THE COMMISSION ;Re~fr-Jf RBDMS BFL /; I SUBMIT IN DUPLICATE · e Placer 1 Well Suspension Procedure Confidential 04/05/04 The Placer #1 Owners plan to suspend the Placer #1 well this season to facilitate future pool delineation from the well bore and/or an extended production test to ascertain reservoir volumes associated with the discovery. The Placer #1 well encountered 17' gross Kuparuk C sand. Rotary sidewall core data indicate permeabilities ranging from 0.01 md to 3546 md, and petrophysical models suggest an average permeability of approximately 600 md in the basal 6 feet of the reservoir. MDT sampling in the well recovered 26 API crude at very low drawdowns (212 psi), also indicative of high formation permeabilities and deliverabilities. Thus, the well appears fully capable of producing in paying quantities. Consequently, suspending the well will allow the Owners to incorporate the 2004 Placer #1 and Placer #2 results into the geologic and reservoir models for the area; results of this re-evaluation will determine future delineation or development activities associated with the discovery. Cu ITent Well Status: 9-5/8" 7" 6-1/8" Surface Casing Intermediate Casing Open Hole @ 2,528' MD / 2,268' TVD-RKB @ 7,467' MD / 6,053' TVD-RKB @ 7,761' MD / 6,289' TVD-RKB A Baker N-1 Cement Retainer was set @ 7,385' MD (82' above 7" Intermediate Casing Shoe) and pressure tested to 2500 psi. A 10' sand plug was spotted on top of retainer and a 3-1/2" kill string was landed @ 1,590' MD. The 9-5/8" x 7" annulus, 3-1/2" x 7" annulus and 3-1/2" tubing are freeze protected with diesel. Placer #1 schematics have been attached for review. 1. Notify AOGCC 24 hours in advance of all well suspension operations. Hold pre-job meeting with all personnel to discuss objectives, as well as safety and environmental issues. 2. Mobilize and rig up Dowell - Coil Tubing and Cementing units. 3. RIH w/ coil and tag top of sand plug to confirm location. 4. Spot a balanced cement plug from Top of Sand Plug @ 7,375' MD to 7,115' MD. Total interval is approximately 260' in length (see attached schematic for cement plug detail). 5. POOH and freeze protect tubing w/ diesel. Note: Plan to leave 11.0 ppg kill weight mud in well from the top of the cement plug to the tubing tail. 6. Set BPV in tubing hanger. 7. Clear ice pad location and demob all materials and equipment. On behalf of itself and other owners, ConocoPhillips Alaska, Inc. submits the attached data for the Placer 1 Well, Drilling Permit No. 204-014 as specified in 20 MC 25.071. We request that this data be held confidential as required under AS 31. 05.035(c) and 20 MC 25.537(d). MAC 04/05/04 .. Conductor: 16", 62.58# Set @ +/- 115' MD Surface Casing 9-5/8" 40# L-80 BT(- Float Collar to Surface float Collar: Weatherford Single Valve 9-5/8" 32-53# BTC Box x Pin (2) Joints Casing: 9-5/8" 40# L-80 BTC float Shoe: Weatherford - Single Valve 9-5/8" 32-53# BTC Box Up Placer 1 Proposed Suspension Schematic Exploration Well - Confidential TD 12-1/4" Hole ¡i'j) +/- 2,528' MD/2,268' TVD-RKB Intermediate / P'rodulCtion Casing: 7" 26# L -80 BTC - Float Collar to Surface float Collar: Weatllerford - Single Valve 7" 20-35# BTC Bo]( )[ Pin (2) Joints Casing: 7" 26# L-80 BTC float Shoe: Weatherford - Single Valve 7" 20-35# BTC Bo]( Up TD 8-112" Hole (i'j) +/-1,461' MD I 6,053' TVD-RKB 411 Top Kuparuk 7,539' MD-RKB Base Kuparuk 7,560' MD-RKB MDT Pressur~samples confirm 9.9 ppg EMW in the Kuparuk TD 6-1/8" Open HJ(Þ~iEi (iD +1-1,161' MD 1 6,289' TVD-RKB Ii RI<B Assumed (iD 55' Above SS 25' Ice Pad Height (Above SS) 30' Nordic Rig 3 RKB 3-1/2",9.3#, L-80, EUE-8rd Mod Kill String landed @ +1- 1,590'. 16 PPG FIT - 750 psi, 9.7 ppg Mud, 2268' 1VD 10 BBL (+1- 260') Cement Plug spotted on top of Sand. (Top Cement Estimated @ 7,115' MO) 50 sacks Class G + Additives (0.3% 065.0.06% B155, 02% 046) Slurry Weight Slurry Yield Thickening Time 15.8 ppg 1.16 cu-ft/sk 4:00 to 5:00 Hrs 10' Sand Plug spotted on top of retainer following pressure test. (Sand Plug Top Estimated @ +/- 7375' MD) Baker N-1 Cast Iron Cement Retainer. (Retainer Top @ +/- 7,385' MD - Retainer Pressure tested to 2500 psi) 14 PPG FIT - 950 psi, 11.0 ppg Mud, 6053'1VD Placer 1 Suspension Schematic v1. 0 prepared by Mark Chambers 04/04/04 . . . e e (h) In this section, "drilling waste" means the following substances identified as a hazardous waste in 40 C.F .R. 261: (1) drilling mud, drilling cuttings, reserve pit fluids, ce t-contaminated drilling mud, completion fluids, formation fluids associate Ith the act of drilling a well permitted under 20 AAC 25.005, and any ad water needed to facilitate pumping of drilling mud or drilling cuttings; (2) drill rig wash fluids and drill ri mestic waste water; and (3) other substances that the mission determines upon application are wastes associated with the act 'lling a well permitted under 20 AAC 25.005. (i) For purposes of this s on, in AS 31.05.030 (e)(2), "oil or gas well" means a well permitted under AS . 5.090, other than a water well associated with oil or gas exploration and prod on. .9/22/96, Register 139; am 11/7/99, Register 152 thDrity: AS 31.05.030 C. \' Þ:'C \--<.>. '- '" \' \' \\~, ~D s.~<>"",£J ¿~\"'1. ~<"'<""'CJ&J\.\"~):~(J "\\'<é,\,"\f'--~\~~~e,\, \'~CJ\U ~\-..m\}~' ARTICLE 02 \,ro~0C:~\)(è Dc~'J \'~"'\C"o.\">~. {)ê,. Q~.o -\:ù ABANDONMENT AND PLUGGING ",r. .\ \ o~ r __~ - l ' ...f_..-L \µ0..\\Q\""\..\ \Iè.<L,{'-T\'--{ ~Q \:- S \ () ({ .-\-'\G-C "'--.0 f \C>~ To$ t>o\-. '(0,'1"''':> ~ 'LO \ bc;\'Û,"\.J\-\...<t ~\'<:'''O<L'\~ ~\\ $()$¿~ \..::J(:)~.~\-.cr\~_'~'\G$\G: ~'~'~o\'--''> o...~ , O~\'-~ +~.~Cc\\\oo~. ",L\'<J~~\~Q\\æð~ ~. O-Q<¡J\ì<..o.\:' k "'So \o.-t\()I'.-S. T '.!~'\j\~.c\~~\\ bCts.~) c, \---À-\---£: '-AX \ \. \~,'\-<.aA:'\c> ~ -t-"~ c vA ~ N9-S ~~..\-\~ S'::'l'7VC~ w~\.J'\~ ~\l,-h·. Tì--t ~~\\\.OŒ ~'> \,ee'''t:~s.s0'''' ~~~('..'.'~ \ ':> c:,. Q LV ~ . \ \ìè u:J Y\. ~ (.~ c.~ ~~ \')C:l-\ ~ ¡~~~~~~~iNT OF WELLS. c..'þ À .~ s ~c;,'-.:>~<è>-\- k9-"1t~L't \.--( (ó ~o "1 (a) All wells that have been permitted on a property under 20 AAC 25.005 must be abandoned before expiration of the owner's rights in that property or if, after notice and hearing, the commission orders abandonment for safety reasons or because the operator has effectively abandoned operations prior to the expiration of the lease. If the owner is the landowner, all wells that have been permitted on a property by 20 AAC 25.005 must be abandoned within one year following permanent cessation of the operator's oil and gas activity within the field where the wells are located or according to an abandonment scpedule approved by the commission, unless the wells are earlier abandoned for safety reasons. Section 105. Abandonment of wells 107. Plugging well branches 110. Suspended wells 112. Well plugging requirements 115. Shut-in wells 120 . Well abandonment marker 140 . Water wells 170. Onshore location clearance 172. Offshore location clearance 37 e e (b) A well drilled onshore or from a fixed offshore platform must be abandoned before removal of the drill rig unless the well is completed as an oil, gas, or service well or is suspended, or unless well operations are shut down in accordance with 20 AAC 25.072. Each well drilled from a fixed offshore platform must be abandoned before the platform is removed or dismantled. (c) A well drilled offshore from a mobile bottom-founded structure, jack-up rig, or floating drilling vessel must be abandoned before removal of the drill rig unless (1) the well is completed as an oil, gas, or service well; or (2) subsea equipment for well re-entry is properly installed and either the well is suspended or well operations are shut down in accordance with 20 AAC 25.072. (d) A well drilled from a beach, artificial island, or shifting natural island must be abandoned before removal of the drill rig unless the well is completed as an oil, gas, or service well or is suspended, or unless well operations are shut down in accordance with 20 AAC 25.072 and plans for maintaining the integrity of the location are approved by the commission. (e) An Application for Sundry Approvals (Form 10-403) must be submitted to and approved by the commission before work is begun to abandon a well, except that oral approval may be obtained from the commission if it is followed within three days by the submission of an Application for Sundry Approvals for final approval by the commission. The commission will attach conditions to its approval as necessary to protect freshwater and hydrocarbon resources. The Application for Sundry Approvals must include (1) the reason for abandoning the well; and (2) a statement of proposed work, including (A) information on abnormally geo-pressured strata; (B) the manner of placement, kind, size, and location, by measured depth, of existing and proposed plugs; (C) plans for cementing, shooting, testing, and removing casing; (D) if the Application for Sundry Approvals is submitted after beginning work, the name of the representative of the commission who provided oral approval, and the date of the approval; and (E) other information pertinent to abandonment of the well. History: Eff. 4/13/80, Register 74; am 4/2/86, Register 97; am 1117/99, Register 152 Authority: AS 31.05.030 20 AAC 25.107 PLUGGING WELL BRANCHES. (a) An operator may plug a well branch before abandoning or suspending the well. If a well branch has not been completed, the operator shall plug the well branch before 38 . . . . . . e e removal of the drill rig, unless well operations are shut down in accordance with 20 AAC 25.072. (b) An Application for Sundry Approvals (Form 10-403) must be submitted to and approved by the commission before work is begun to plug a well branch, except that oral approval maybe obtained from the commission if it is followed within three days by the submission of an Application for Sundry Approvals for final approval by the commission. The provisions of 20 AAC 25.105 (e) apply to the application, except that instead of including the reason for abandoning the well, the application must include the reason for plugging the well branch and the reason for not immediately abandoning or suspending the well. (c) The provisions of20 AAC 25.112 (a) - (c) and (e) - (i) apply to plugging a well branch. (d) This section does not apply to the temporary plugging of a well branch for production control purposes. History: Eff. 11/7/99, Register 152 Authority: AS 31.05.030 20 AAC 25.110 SUSPENDED WELLS. (a) If allowed under20AAC 25.105, tnecommission will, upon application by the operator under (b) of this section, approve the suspension of a well if (1) the well (A) enCQUnters hydrocarbons of sufficient quality and quantity to indicate that the well is capable of producing in paying quantities, as reasonably demonstrated by well tests or interpretive formation evaluation data; for purposes of this paragraph, "paying quantities" means quantities sufficient to yield a return in excess of operating costs; (B) is a candidate for redrilling; (C) has potential value as a service well; or (D) is located on a pad or platform with active producing or service wells; and (2) the operator justifies to the commission's satisfaction why the well should not be abandoned, and, if the well is not completed, why the well should not be completed; sufficient reasons include the (A) unavailability of surface production or transportation facilities; (B) imprudence of security maintenance of a completed well in a shut-in status; (C) need for pool delineation and evaluation to determine the prudence of pool development. (b) An Application for Sundry Approvals (Form 10-403) must be submitted to and approved by the commission before plugging operations are begun in a well for which 39 e e suspension is proposed, except that oral approval may be obtained from the commission if it is followed within three days by the submission of an Application for Sundry Approvals for final approval by the commission. Approval will be conditioned as necessary to protect freshwater and hydrocarbon resources. An Application for Sundry Approvals must include (1) the reason for suspending the well and information showing that the applicable criteria for suspension under (a) of this section have been met; and (2) a statement of proposed work, including (A) information on abnormally geo-pressured strata; (8) the manner of placement, kind, size, and location, by measured depth, of existing and proposed plugs; (C) plans for cementing, shooting, testing, and removing casing; (D) if the Application for Sundry Approvals is submitted after beginning work, the name of the representative of the commission who provided oral approval, and the date of the approval; and (E) other information pertinent to suspension of the well. (c) At the operator's request accompanying the submission, information submitted to show that the applicable criteria for well suspension under (a) of this section have been met will be kept confidential (1) for the period specified under AS 31.05.035 (c), if the information is described in 20 AAC 25.071 (b); or (2) for the time that the information has value as a trade secret, if the information is not described in 20 AAC 25.071 (b) but is determined by the commission to constitute a trade secret under AS 45.50.940 (d) A well approved for suspension must be plugged in accordance with the requirements of 20 AAC 25.112, except that the requirements of 20 AAC 25.112(d) do not apply if (l) a wellhead is installed or the well is capped with a mechanical device to seal the opening; and (2) a bridge plug capped with 50 feet of cement or a continuous cement plug extending 200 feet within the interior casing string is placed at or above 300 feet below the surface; the commission will waive the requirement of this paragraph for a development well drilledftom a pad or platform, if the commission determines that the level of activity on the pad or platform assures adequate surveillaooe .of that development well. ( e) Until a suspended well has been abandoned or re-entered, the operator shall maintain the integrity of the location, provide the commission with a well status report every five years, and clear the location in accordance with 20 AAC 25.170 (a)(2) or (b) or with 20 AAC 25. 172(c)(2) or (d), as applicable. History: Eff. 4/2/86, Register 97; am 1117/99, Register 152 Authority: AS 31.05.030 40 . . . . . . e e 20 AAC 25.112 WELL PLUGGING REQUIREMENTS. (a) Plugging of the uncased portion of a wellbore must be performed in a manner that ensures that all hydrocarbons and freshwater are confined to their respective indigenous strata and are prevented from migrating into other strata or to the surface. The minimum requirements for plugging the uncased portion of a wellbore are as follows: (1) by the displacement method, a cement plug must be placed (A) from 100 feet below the base to 100 feet above the top of all hydrocarbon-bearing strata; (B) from the well's total depth to 100 feet above the top of all hydrocarbon-bearing strata; (C) from the well's plugged back total depth to 100 feet above the top of all hydrocarbon-bearing strata, if all hydrocarbon-bearing, abnormally geo-pressured, and freshwater strata below are isolated; however, the commission will approve plugging from the top of fill or the top of junk instead of from the plugged back total depth, if the commission determines that the objectives of this subsection will be met; or (D) from 100 feet below the base to 50 feet above the base of each significant hydrocarbon-bearing stratum and from 50 feet below the top to 100 feet above the top of each significant hydrocarbon-bearing stratum; (2) by the displacement method, a cement plug must be placed from 100 feet below the base to 50 feet above the base of each abnormally geo-pressured stratum and from 50 feet below the top to 100 feet above the top of each abnormally geo-pressured stratum; (3) by the displacement method, a cement plug must be placed from 150 feet below the base to 50 feet above the base of the deepest freshwater stratum. (b) Plugging of a well must include effectively segregating uncased and cased portions of the wellbore to prevent vertical movement of fluid within the wellbore. The minimum requirement for plugging to segregate uncased and cased portions of a wellbore is one of the following: (1) by the displacement method, a continuous cement plug must be placed from 100 feet below to 100 feet above the casing shoe; (2) by the downsqueeze method using a retainer set no less than ,50 f_,but no more than 100 feet above the casing shoe, a volume of cement sufficient to fill the wellbore from the retainer to 100 feet below the casing shoe must be pumped through the retainer, and cement must be pumped above .the retainer to cap it with a 50 foot cement plug; (3) by the downsqueeze method using a production packer set no less than 50 feet but no more than 500 feet above the casing shoe, a volume of cement sufficient to fill the wellbore from 100 feet below the casing shoe to the packer must be pumped through the packer, and cement must be pumped above the packer to cap it with a 50 foot cement plug. 41 e e (c) Plugging of cased portions of a wellbore must be performed in a manner that ensures that all hydrocarbons and freshwater are confined to their respective indigenous . strata and are prevented from migrating into other strata or to the surface. The minimum requirements for plugging cased portions of a wellbore are as follows: (1) perforated intervals must be plugged by one of the following methods: (A) by the displacement method, a cement plug placed from 100 feet below the base to 50 feet above the base of the perforated interval and from 50 feet below the top to 100 feet above the top of the perforated interval; (B) by the displacement method, a cement plug placed from the well's total depth to 100 feet above the top of the perforated interval; (C) by the displacement method, a cement plug placed from the well's plugged-back total depth to 100 feet above the top of the perforated interval, if all hydrocarbon-bearing, abnormally geo-pressured, and freshwater strata below are isolated; however, the commission will approve plugging from the top of fill or the top of junk instead of from the plugged- back total depth, if the commission determines that the objectives of this subsection will be met; (D) by the downsqueeze method using a cement retainer or production packer set no less than 50 feet but no more than 500 feet above the perforated interval, a volume of cement pumped through the retainer or packer sufficient to fill the wellbore from 100 feet below the base of the perforated interval to the retainer or packer; (E) if the perforations are isolated from open hole below, a . mechanical bridge plug set no more than 50 feet above the top of the perforated interval, and either a minimum of 75 feet of cement placed on top of the plug by the displacement method or a minimum of 25 feet of cement placed on top of the plug with a dump bailer; (2) casing stubs within outer casing must be plugged by one of the following methods: (A) by the displacement method, a cement plug placed from 100 feet below the stub to 100 feet above the stub; (B) by the downsqueeze method using a retainer set 50 feet above the stub, a volume of cement pumped below the retainer sufficient to fill the c.asing stub with 150 feet of cement, and cement pumped above the retainer to cap it with a 50 foot cement plug; (C) if the casing stub annulus is cemented, a mechanical bridge plug set no more than 25 feet above the casing stub, and either a minimum of75 feet of cement placed on top of the plug by the displacement method or a minimum of 25 feet of cement placed on top of the plug with a dump bailer; (3) if freshwater is present, the smallest diameter casing string extending to the surface must be plugged by one of the following methods: . 42 . . . e e (A) by the displacement method, a cement plug placed from 100 feet below the depth of the surface casing shoe to 100 feet above the depth of the shoe; (B) a mechanical bridge plug set 100 feet below the depth of the surface casing shoe and at least 200 feet of cement placed on top of the plug. (d) Plugging of the surface of a well must meet the following requirements: (1) by the displacement method, a cement plug at least 150 feet in length, with the top of the cement no more than five feet below original ground level onshore, or between 10 and 30 feet below the mudline datum offshore, must be placed within the smallest diameter casing string; (2) either (A) all annular space open at the surface onshore, or in communication with open hole and extending to the mudline datum offshore, must be plugged with cement to seal the annular space in a manner satisfactory to thei commission; or (B) all casing interior to the surface casing must be recovered to a depth of 100 feet or more below the original ground level onshore or the mudline datum offshore and the casing stubs plugged with cement as provided in (c)(2)(A) of this section; if the cement plug is extended to within the distance from the surface specified in (1) of this subsection, the requirement of (1) of this subsection need not be met. (e) Cement used for plugging within zones of permafrost must be designed to set before freezing and have a low heat of hydration. (t) Each of the respective intervals of a wellbore between the various 1ÙUg$ must be filled with fluid of sufficient density to exert a hydrostatic pressure exceeding the greatest formation pressure of permeable formations in the intervals between the plugs at the time of abandonment. (g) Except for surface plugs, the operator shall record the actual location and integrity of cement plugs, cement retainers, or bridge plugs required by this section, using one of the following methods, which in the case of a cement retainer or bridge plug may be performed before cement is placed on top of the plug: (1) placing sufficient weight on the plug to confirm its location and to confirm that the plug has set and a competent plug is in place; (2) testing the plug to hold a surface pressure of 1,500 psig or 0.25 psi/ft multiplied by the true vertical depth of the casing shoe, whichever is greater, and tagging the plug to confirm location; however, surface pressure may not subject the casing to a hoop stress that will exceed 70 percent of the minimum yield strength of the casing. (h) At least 24 hours notice of plugging operations must be given to the commission so that a representative of the commission can witness the operations. 43 tit e (i) The commISSIon will, in its discretion, approve a variance from the requirements ofthìs section if the variance provides for at least equally effective plugging . of the well and prevention oft1uid movement into sources of hydrocarbons or freshwater. History: Eff. 11/7/99, Register 152 Authority: AS 31.05.030 20 AAC 25.115 SHUT-IN WELLS. (a) No later than March 31 of each year, an operator shall file with the commission a report on completed development or service wells that have been shut in for 365 days or longer as of January 1 of that year. The report must provide (1) the current known mechanical condition of the well, including the condition of installed tubing and casing strings; (2) the date the well was shut in and the circumstances surrounding the decision to shut in the well; and (3) an analysis of the future utility of the well. (b) The commission will require an operator of a shut-in well to file additional infonnation as the commission considers necessary to ensure that freshwater and hydrocarbon sources are protected. History: Eff. 11/7/99, Register 152 . Authority: AS 31.05.030 20 AAC 25.120 WELL ABANDONMENT MARKER. (a) The exact surface location of an abandoned well must be shown by a steel well abandonment marker. The marker must be a marker plate meeting the requirements of (b) of this section. However, upon the request of the surface owner, and if the commission detennines that a marker post does not create a hazard or obstacle, the commission will approve a marker post meeting the requirements of (c) of this section. (b) A marker plate must be (1) at least 1/4 inch thick; (2) at least 18 inches square or in diameter; and (3) welded to and must cover the outermost casing string. (c) A marker post must (1) be at least four inches in diameter and at least 10 feet long; (2) be set in cement inside well casing or finnly welded with supporting fillets to the top of a steel plate secured to the casinghead or casing stub; (3) extend from four to six feet above final ground level; and (4) be closed at the top with a screw cap, welded plate, or cement plug. . 44 Placer #1 - Weekly Progress 'port (Thru 03121104) Well Date Placer #1 02/24/04 Placer #1 02/25/04 Placer #1 02/26/04 Placer #1 02/27/04 Placer #1 02/28/04 Placer #1 02/29/04 Placer #1 03/01/04 Placer #1 03/02/04 Placer #1 03/03/04 Placer #1 03/04/04 Placer #1 03/05/04 Placer #1 03/06/04 Placer #1 03/07/04 Placer #1 03/08/04 Placer #1 03/09/04 Placer #1 03/10/04 . Operations Summary :>o~ -t}\~ Rig released to move (3F-19 to Placer #1) at 22:00. Finish move and start rig up for spud. Accept rig at Midnight 2/25/04 Finish rig up. PU drill pipe to spud. Diverter test witnessed by AOGCC. Confirm RKB to GL = 31.0'. P/U HWDP and 4" d.p. M/U BHA. Thaw standpipe. Spud well @ 11:0 hrs and drill to 135'. M/U L WD tools and drill to 494' Directional drill 494' to 2191'. ART = 10.57 hr. AST = 10.1 hr. Directional drill 2191' to 2548' (Csg Point). Circulate and condition mud to run casing - Lost rig power. Work on SCR. Re-established power to rig. Circulate and condition mud. Pooh. Begin RIH w/ 9-5/8" casing string. Run, Land and Cement 9 5/8" casing at 2528.35' with full cement returns to surface. N D Diverter. Install FMC wellhead and test - NU and test BOPE - PU and stand back 4" DP - Load 4" HWDP in shed - Prepare to MU BHA # 2. MU BHA #2 - Test MWD - LD 3.5" HWDP - PU 4" HWDP and 4" DP - RIH tag cement @ 2427' - Cleanout to FC @ 2447'. Test casing to 2500 psi - Clean out shoe track and 20' of new hole - Perform FIT to 16.0 ppg - Change over to 9.6 ppg LSND mud. Drill 8 1/2" hole f/ 3184' to 3633'. Work on pump. Drill from 3633' to 4650' - Unplug flow line - Drill f/ 4650' to 5077' - Reinstall WB - Drill f/ 5077' to 5143'. Drill to 5616' - Replace swivel packing - Drill to 5976' - Replace swab #2 MP - Drill to 6623' - Replace swab #1 MP - Drill to 6710'. Drill f/ 6710' to 6870' - Replace swab in MP #1 - Drill to 6972' - Circulate hole clean for trip - POOH - Change pulser in MWD and LD stab - RIH - Repair swivel packing- Pulse test MWD - RIH to 6877' - W&R Circulate - losses static - observed gain in mud volume - well flowing - Shut in and monitor pressure - no pressure build up - Prepare to drill - MWD failure - drill to 7005' MWD still not working - POOH - Change out MWD. Drill f/7250' to 7477' TD - Circ - Wiper Trip - Circ - POOH - LD BHA - RU to Run csg. - PJSM - Run 7" csg Run 7" csg (59 jts). to 2511' Circulate - Run 7" csg (100 jts) to 4266' - Circulate - Run 7" csg 110 jts.to 4681' - Circ - Run 7" 140 jts. to 5951' - Circ - Finish running 7" csg 175jts. - land csg. Continue to circ for cmt job - Cmt 7" csg - Annulus flowing back - Shut in Hydril & monitor well 70 psi in 4 hrs. - Set & test pack off to 5000 psi - RU & test BOPE - MU BHA # 4 Placer #1 03/11/04 Placer #1 03/12/04 Placer #1 03/13/04 Placer #1 03/14/04 Placer #1 03/15/04 Placer #1 03/16/04 Placer #1 03/17/04 Fi~U BHA # 4 - PU 36 jts. 4" DP - RIH - C~ut cmt f/7351' to 7372' - Test csg to'~"pSi - Drill out shoe track - Work on Totc~uip - Drill to 7497' - Perform FIT to 14.0 ppg - Drill to 7645' Drill f/7645' to 7761' - Circ hole clean - Wiper trip to 7" shoe - Monitor well - RIH - Circ hole clean - Drop rabbit - Pump & back ream to 7" shoe - monitor well - POOH LD BHA - RU SWS - Run Sonic Log - Attempt to run CMR Log - Unable to get CMR past 1900'. POOH w/ Log #2 - MU MDT/CMR - test tools - RIH w/ tools on 4" DP to 7000' - MU SES - Wet connect & latch in - RIH & log with CMR/MDT Log with CMR/MDT - POOH w/ WL & DP - LD tools - MU MSCT - RIH & take cores - POOH RD SWS - RIH with Hole Opener for clean out run. RIH for clean out run, cleanup spill in cellar, RIH to bttm', washpipe leaking, POOH to shoe, circ, replace washpipe packing, RIH, Circ, Backream to shoe, monitor well, dry job, POOH, Unload tbg f/pipe s Set 7 retainer at 7385' MD. Spot sand on top of retainer. POOH and run 3 1/2" suspension tubing to 1590.49' NO BOP. NU and test tree. Freeze protect IA Injectivity test and Freeze protect OA. Set BPV. RR at midnight 3/17/04 e e dO~-O\~ Placer #1 - Weeklv Proaress Report (Thru 03/07/04) Well Date Placer #1 02/24/04 Placer #1 02/25/04 Placer #1 02/26/04 Placer #1 02/27/04 Placer #1 02/28/04 Placer #1 02/29/04 Placer #1 03/01/04 Placer #1 03/02/04 Placer #1 03/03/04 Placer #1 03/04/04 Placer #1 03/05/04 Placer #1 03/06/04 Placer #1 03/07/04 y~ Operations Summary Rig released to move (3F-19 to Placer #1) at 22:00. Finish move and start rig up for spud. Accept rig at Midnight 2/25/04 Finish rig up. PU drill pipe to spud. Diverter test witnessed by AOGCC. Confirm RKB to GL = 31.0'. P/U HWDP and 4" d.p. M/U BHA. Thaw standpipe. Spud well @ 11:0 hrs and driB to 135'. M/U LWD tools and drill to 494' Directional drill 494' to 2191'. ART = 10.57 hr. AST = 10.1 hr. Directional drill 2191' to 2548' (Csg Point). Circulate and condition mud to run casing- Lost rig power. Work on SCR. Re-established power to rig. Circulate and condition mud. Pooh. Begin RIH wI 9-5/8" casing string. Run, Land and Cement 9 5/8" casing at 2528.35' with full cement returns to surface. ND Diverter. Install FMC wellhead and test - NU and test BOPE - PU and stand back 4" DP - Load 4" HWDP in shed - Prepare to MU BHA # 2. MU BHA #2 - Test MWD - LD 3.5" HWDP - PU 4" HWDP and 4" DP - RIH tag cement @ 2427' - Cleanout to FC @ 2447'. Test casing to 2500 psi - Clean out shoe track and 20' of new hole - Perform FIT to 16.0 ppg - Change over to 9.6 ppg LSND mud. Drill 8 1/2" hole f/3184' to 3633'. Work on pump. Drill from 3633' to 4650' - Unplug flow line - Drill f/4650' to 5077' - Reinstall WB - Drill f/5077' to 5143'. Drill to 5616' - Replace swivel packing - Drill to 5976' - Replace swab #2 MP - Drill to 6623' - Replace swab #1 MP - Drill to 6710'. Drill f/6710' to 6870' - Replace swab in MP #1 - Drill to 6972' - Circulate hole clean for trip - POOH - Change pulser in MWD and LD stab - RIH - Repair swivel packing- Pulse test MWD - RIH to 6877' - W&R ,---.. b ~c.-\~\ ~~ Circulate - losses static - observed gain in mud volume - well flowing - Shut in and monitor pressure - no pressure build up - Prepare to drill - MWD failure - drill to 7005' MWD still not working - POOH - Change out MWD. Þ\1ê:.S(V'~\··\\) ~'-\ ~ ~ Q.. \~\~tf'\-~~\S:- c:..û~ '\ \1"-. ~ ~ ~\ -1"'\ Re: Placer 1 - Temporary Suspension . Subject: Re: Placer I - Temporary Suspension From: Thomas Maunder <tom _ maunder@admin.state.ak.us> Date: Tue, 16 Mar 2004 15:27:55 -0900 To: "Chambers, Mark A" <Mark.A.Chambers@conocophillips.com> CC: "Mazzolini, Paul" <Pau1.Mazzolini@conocophillips.com>, "Allsup-Drake, Sharon K" <Sharon.K.Allsup-Drake@conocophillips.com> . Mark, et al: Your message accurately reflects our discussion yesterday. The 403 for the upcoming activities should be for an operational SD since the intent is to resume some sort of operation (run liner or some sort of cementing). When you have the information from Placer 2, then you will be able to prepare the sundry necessary to resume operations and "do what you propose to do". If the "suspension" route is proposed, please look at sections 110 and 105 of the regulations and "answer" the questions/points listed there. Tom Maunder, PE AOGCC Chambers, Mark A wrote: Tom: Good afternoon. I am going to send you a fax with a schematic showing the Placer 1 well and how we intend to leave it while drilling the Placer 2 well. I will also send the pressure results from our cement retainer test conducted this morning. Below is a summary of our discussion yesterday afternoon concerning the Placer 1 well and CPAI's desire to preserve the open hole interval below the 7" casing shoe: * Set Cement Retainer @ 7,385' MD ( 82' above 7" casing shoe). Pressure test retainer to 2500 psi. Place ± 10' sand plug on top of retainer. Run ± 1,585' MD kill string and freeze protect to below base Permafrost with diesel. Freeze protect 7" x 9-5/8" annulus to below base Permafrost with diesel. Install tree. Rig down and move Nordic 3 to Placer #2. * Drill Placer #2. * Based on results of Placer #2 move Nordic 3 or a Coil Unit back to Placer #1 and perform the following: Nordic 3 Run 3-1/2" Liner Pull kill string, Drill-up cement retainer, Clean out production interval, Run 3-1/2" cemented liner w/ liner top packer and hanger, Re-run kill string, Freeze protect w/ diesel, Install tree, RDMO. Nordic 3 P&A Pull kill string, Sting into cement retainer, Pump cement below retainer, Unstring and spot cement on top of retainer, Spot surface cement plug, Cement 7" x 9-5/8" annulus, RDMO - Cement volumes per AOGCC Regulations. Coil Unit Prep for Long Term Temporary Suspension RIH and spot cement on top of retainer, Pooh and install BPV in tubing hanger, Install tree, RDMO - Cement volumes per AOGCC requirements. lof2 3/16/20043:47 PM Re: Placer I - Temporary Suspension Note: No cement W~d be pumped below the cement re~ner per our discussion. Sharon Allsup-Drake will forward a Sundry Notice for the Placer #1 well this afternoon and will attached the above referenced documentation. Please let me know if any of the above assumptions are incorrect or if we need to add steps to the procedures outlined above. Thanks for the help. I look forward to hearing from you Regards, Mark Chambers Sr. Exploration Drilling Engineer ConocoPhillips Alaska, Inc. 265-1319 20f2 3/16/20043:47 PM · STATE OF ALASKA . ALASKA Oil AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVAL 20 AAC 25.280 / Operational shutdown ¡;r 1. Type of Request: Abandon D Alter casing D Change approved program D Suspend IT! Repair well D Pull Tubing D 2. Operator Name: ConocoPhillips Alaska, Inc. 3. Address: P. O. Box 100360, Anchorage, Alaska 99515 7. KB Elevation (ft): 54' AMSL 8. Property Designation: ADL 389132 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (It): 7761' 6289' Casing Length Size Structural Conductor 105' 16" Surface 2498' 9.625" Intermediate 7437' 7" Open Hole 3.5" Perforation Depth MD (ft): N/A Packers and SSSV Type: Plug Perforations D Perforate New Pool D Perforate D Stimulate D Variance D Time Extension D Ø~\Y, :';:::1- Other D 4. Current Well Class: Development D Stratigraphic D Exploratory 0 Service D Re-enter Suspended Well 5. Permit to Drill Numbe~ 204-014 6. API Number: 50-103-20481-00 9. Well Name and Number: Placer #1 10. Field/Pools(s): Exploratory PRESENT WELL CONDITION SUMMARY Effective Depth TVD (ft): Plugs (measured) Junk (measured): 7385' MD TVD Burst Collapse 135' 2528' 7467' 7761' 135' 2268' 6053' 6289' Perforation Depth TVD (ft): N/A Packers and SSSV MD (ft): Tubing MD (ft): n/a none 12. Attachments: Description Summary of Proposal 0 Detailed Operations Program D BOP Sketch D 14. Estimated Date for Commencing Operations: 3/1512004 16. Verbal Approval: Date: 3/15/04 Commission Representative: Tom Maunder 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Printed Name P. Mazzolini Signature '?o.-..iL rv¡~ Tubing Size: n/a Tubing Grade: n/a none 13. Well Class after proposed work: Exploratory 0 Development D 15. Well Status after proposed work: Oil D Gas D WAG D GINJ D Service D Plugged D WINJ D Abandoned D WDSPL D Contact Mark Chambers @ 265-1319 Title Drilling Team Leader Phone 263-4603 COMMISSION USE ONLY 03/;"1 4 Date ~CJO Conditions of approval: Notify Commission so that a representative may witness Plug IntegrityD BOP Test D Mechanical Integrity Test D Sundry Number: Jf) f'-ð77 Location Clearance D ~ ~~\\'t:I~'> ~ c....~ \ '" '\. '? \\. \V\.~ Form 10-403 Revised 2/2003 \4AR 1 6 ZOO .'" COMMISSIONER BY ORDER OF t'!) 'I.AlL THE COMMISSION Date:v'/ IJ *'v { OR1GINAL LF'i!lTjjfiii,i~ ~.-, LU.D 1 ¡¡ ~gt~. .....~ SUBMIT IN DUPLICATE Chambers, Mark A . . To: Cc: Subject: Tom Maunder (E-mail) Mazzolini, Paul; Allsup-Drake, Sharon K Placer 1 - Temporary Suspension Tom: Good afternoon. I am going to send you a fax with a schematic showing the Placer 1 well and how we intend to leave it while drilling the Placer 2 well. I will also send the pressure results from our cement retainer test conducted this morning. Below is a summary of our discussion yesterday afternoon concerning the Placer 1 well and CPAl's desire to preserve the open hole interval below the 7" casing shoe: · Set Cement Retainer @ 7,385' MD (82' above 7" casing shoe). Pressure test retainer to 2500 psi. Place +1- 10' sand plug on top of retainer. Run +1- 1,585' MD kill string and freeze protect to below base Permafrost with diesel. Freeze protect 7" x 9-5/8" annulus to below base Permafrost with diesel. Install tree. Rig down and move Nordic 3 to Placer #2. . Drill Placer #2. · Based on results of Placer #2 move Nordic 3 or a Coil Unit back to Placer #1 and perform the following: Nordic 3 Run 3-1/2" Liner Pull kill string, Drill-up cement retainer, Clean out production interval, Run 3-1/2" cemented liner wi liner top packer and hanger, Re-run kill string, Freeze protect wi diesel, Install tree, RDMO. Nordic 3 P&A Pull kill string, Sting into cement retainer, Pump cement below retainer, Unstring and spot cement on top of retainer, Spot surface cement plug, Cement 7" x 9-5/8" annulus, RDMO - Cement volumes per AOGCC Regulations. Coil Unit Prep for Lonq Term ~~uspension RIH and spot cement on top of retainer, Pooh and install BPV in tubing hanger, Install tree, RDMO - Cement volumes per AOGCC requirements. Note: No cement would be pumped below the cement retainer per our discussion. Sharon Allsup-Drake will forward a Sundry Notice for the Placer #1 well this afternoon and will attached the above referenced documentation. Please let me know if any of the above assumptions are incorrect or if we need to add steps to the procedures outlined above. Thanks for the help. I look forward to hearing from you Regards, Mark Chambers Sr. Exploration Drilling Engineer ConocoPhillips Alaska, Inc. 265-1319 Conductor: 16", 62.58# Set @ +1- 115' MD Surface Casing 9-5/8" 40# L-80 BTC - Float Collar to Surface Float Collar: Weatherford - Single Valve 9-5/8" 32-53# BTC Box x Pin (2) Joints Casing: 9-5/8" 40# L-80 BTC Float Shoe: Weatherford - Single Valve 9-5/8" 32-53# BTC Box Up Intermediate I Production Casing: 7" 26# L-80 BTC - Float Collar to Surface Float Collar: Weatherford - Single Valve 7" 20-35# BTC Box x Pin (2) Joints Casing: 7" 26# L-80 BTC Float Shoe: Weatherford - Single Valve 7" 20-35# BTC Box Up -~~--_.~ Top Kuparuk 7,539' MD-RKB Base Kuparuk 7,560' MD-RKB ¡Iii Placer 1 Posed Completion Schematic Exploration Wen - Confidential --_.,--~ MDT Pressure Samples confirm 9.9 ppg EMW in the Kuparuk RIŒ Assumed (êù 55' Above 5S 25' Ice Pad Height (Above SS) 30' Nordic Rig 3 RKB 3-1/2",9.3#, L-80, EUE-8rd Mod Kill String landed @ +1- 1,585'. Well to be freeze protected wi diesel below base of Permafrost. +1- 10' Sand Plug spotted on top of retainer following pressure test. Baker Oil Tools Cement Retainer Top set @ 7,385' MD I Pressure tested to 2500 psi Placer 1 - Suspension Schematic v1.0 prepared by Mark Chambers 03/16/04 Pump Rate Volume Input Volume/Stroke I. '0.0470IBbIS/Strk[. Casing Test ... 7.0 Strk/min PRESSURE INTEGRITY TEST CONOCOPHILLlPS Alaska, Inc. Nordic #3 Date: I 3/16/2004 Pump used: I #1 Mud Pump I... ... Pumping down I annulus and DP. ... Rig Rizek/Mickey Placer #1 Well Name: Drilling Supervisor Strokes Shut-in Pumping Shut-in Min psi Strks psi Min psi o 2500 0 1 2490 0.25 2 2485 0.5 3 2482 1 d. 4 2480 1.5>\ ". ... 5 2479 2 6 2479 2.5 7 2479 3 8 2479 3.5 9 2479 4 10 2479 4.5 15 2475 5 20 2475 5.5 25 2470 6 30 2470 6.5 7 7.5 8 8.5 9 9.5 e= 10 est Pressure In-:egrity o 185 300 4ºQ. 520 620 720 830 925 1025 112.0 !:!:.:.:,:,::::::\:: tg;tø J9ºQ 1390: 1#1:$.Q. 1:590 1690 &iijö 1900 2000 2110 2230 2340 2450 2500 Pumping Strks psi Hole Depth 7,385IFt-MD I 5,988IFt-TVD I... Only Casing Shoe Depth I 7,467 IFt-MDI 6,053 1 Ft-TVD 17" 26#/Ft )-55 BTC-MOD Integrity Test Type of Test Hole Size: 16-3/4' RKB-CHF: 25.51F Casinq Size and Description: ... Casing o 2 4~ 8 10 12 14 16 18 20:.; :;:;·i:;·;:i\ 22 24> ......,¿. 26..:.: 2.8' 30: 32 34 .~; 38 40 42 44 46 47 Pressure InteqritvTest Mud Weight: ppg Mud 10 min Gel: Lb/100 Ft2 Rotating Weight: Blocksff op Drive Weight: Desired PIT EMW: Estimates for Test: Casinq Test Mud Weight: Mud 10 min Gel: Lbs Lbs ppg o psi 11.0 ppg 16.0 Lb/100 Ft2 2,500 psi 110,000 Lbs 24,000 Lbs 2.3 bbls Test Pressure: Rotating Weight: Blocks/T op Drive Weight: Estimates for Test: Obbls [... PIT 15 Second Shut-in Pressure, psi Fill in FIT Columns ==> Go to PIT Plot. 0 0.052 x 6053 + ...L = = Leak-off Pressure + Mud Weight 0.052 x TVD EMW , i( E Lost 30 psi during test, held I 98.8% of test pressure. .........~."L~....I .I I I , "'~;-1:;:¡::~«'8'~~~«,......w":~'t.m".',...~'^~w,:-I<::"'".~':.i(, j #### ppg This is a Casing Test 3000 2500 AA I.. / / 2000 500 w a: :J (/) (/) w a: c. 000 Vo ume Bled Back ItSbls Vo ume Pumped 0.0 tSbls Volume Bled Back 2.21 tSbls Volume Pumped 2.2 tSbls I 3 0 5 10 15 20 25 30 Shut-In time, Minutes 0 PIT Point 2 _LEAK-OFF TEST Barrels / oj"'" o .....CASING TEST Comments: 500 ., TOTAL P.01 . 1 . FRANK H. MURKOWSKI, GOVERNOR AI~ASHA OIL AND GAS CONSERVATION COMMISSION Paul Mazzolini Drilling Team Leader ConocoPhillips (Alaska), Inc. PO Box 100360 Anchorage, AK 99510 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Re: Placer #1 ConocoPhillips (Alaska), Inc. Pennit No: 204-014 Surface Location: 1009' FSL, 19' FWL, Sec. 33, T12N, R7E, UM Bottomhole Location: 1539' FSL, 582' FWL, Sec. 4, TUN, R7E, UM Dear Mr. Mazzolini: Enclosed is the approved application for pennit to drill the above referenced exploration well. This 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. A weekly status report is required from the time the well is spudded until it is suspended or plugged and abandoned. The report should be a generalized synopsis of the week's activities and is exclusively for the Commission's internal use. All dry ditch sample sets submitted to the Commission must be in no greater than 30' sample intervals from below the pennafrost or from where samples are first caught and 10' sample intervals through target zones. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless 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 te and conditions of this pennit may result in the revocation or suspension of the pennit. ease provide at least twenty-four (24) hours notice for a representative of the Commission 0 w·t.hess any required test. Contact the Commission's North Slope petroleum field insp tor t 9 607 (pager). BY ORDERßF THE COMMISSION DATED thi~ day of January, 2004 cc: Department ofFish & Game, Habitat Section wlo encl. Department of Environmental Conservation w/o encl. .- W6A- 1(2.2-/ wotf- . STATE OF ALASKA . ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 1a. Type of Work: Drill0 Redrill U Re-entry 0 2. Operator Name: ConocoPhillips Alaska, Inc. 3. Address: 1b. Current Well Class: Stratigraphic Test 0 Exploratoryl.:j Development Oil U Multiple Zone 0 Service 0 Development Gas 0 Single Zone 0 5. Bond: ~ Blanket U Single Well 11. Well Name and Number: Bond No. 59-52-180 Placer #1 P.O. Box 100360 Anchorage, AK 99510-0360 4a. location of Well (Govemmental Section): Surface: 1009' FSL, 19' FWL, Sec. 33, T12N, R7E, UM Top of Productive Horizon: 2217' FSL, 502' FWL, Sec. 4, T11 N, R7E, UM / Total Depth: 1539' FSL, 582' FWL, Sec. 4, T11N, R7E, UM ,/ 4b. location of Well (State Base Plane Coordinates): Surface: x- 451290'/ y- 5976427 16. Deviated wells: Kickoff depth: 800 ~ 18. Casing Program Size Hole 24" Casing 16" 12.25" 8.5" 6.125" 9.625" 7" 3-1/2" 19 Total Depth MD (It): Casing Structural Conductor Surface Intermediate Production Liner Perforation Depth MD (ft): 20. Attachments: Filing Fee Property Plat ft. Maximum Hole Angle: Weight 63# 40# 26# 9.3# Specifications Grade Coupling B PEB L-80 BTC L-80 BTC-M L-80 EUE-8rd 6. Proposed Depth: MD: 8689' " 12. Field/Pool(s): TVD: 6981' / 7. Property Designation: ,,-r-> /t þL .oz.,>,;?:> 7 .J.Id(389132 8. land Use Permit: Exploratory NIA 13. Approximate Spud Date: February 15, 2004 ./ 14. Distance to Nearest Property: 9. Acres in Property: 1280 " 3063' at Target zoneff 10. KB Elevation 15. Distance to Nearest Well within Pool: none, 54' AMSL 17. Anticipated Pressure (see 20 MC 25.035) v ~ Max. Downhole Pressure: 3160 psig I Max. Surface Pressure: 2417 psig Setting Depth Quantity of Cement Bottom c. f. or sacks TVD (including stage data) 115' 230 sx AS I 2302' 500 sx AS III Lite & 200 sx LiteCrete 6114' 170 sx Class G + additives 6981' 270 sx Class G + additives / ./ ./ 40° Top length 80' 2531' 7524' 8659' MD Surface Surf. Surf. Surf. TVD Surface Surf. Surf. Surf. MD 115' 2561' 7554' 8689' (To be completed for Redrill and Re-Entry Operations) I Effective Depth MD (It): Effective Depth TVD (It): Junk (measured) Cement Volume MD TVD PRESENT WELL CONDITION SUMMARY Total Depth TVD (It): Plugs (measured) Length Size o o BOP Sketch0 Diverter Sketch 0 21. Verbal Approval: Commission Representative: I Perforation Depth TVD (ft): Drilling Program[2] Time v. Depth Plot 0 Seabed Report 0 Drilling Fluid Program [2] Date: Shallow Hazard Analysis [2] 20 AAC 25.050 requirements [2] 22. I hereby certify that the foregoing is true and correct to the best of my knowledge. Printed Name P. Mazzolini Signature V~ VVl~ Contact Mark Chambers @ 265-1319 Title Drilling Team Leader Phone Date 0 I 1(:) c¡ I Zoo 4- PreDared bv Sharon AI/suo-Drake Commission Use Only Permit to Drill , / I _ . '/' / I API Number: .' ./ Permit APpr~v~ Number: 2D1' ()/y. 50- /ô3'- 2ðt/BI··Lt) Date: 'l.3~tf Conditions of approval: Sa les re øYes 0 No Mud log required dro 0 Yes .l8l. No Directional survey required \ \." o f S { Wt HtA fKU f'VL . ~~~over letter iafiiV1:U :JlfÑ R Zå04 COMMISSIONER Alaska Oil & Gas Cons. C~ìS '0/1 BY ORDER OF Anchorage THEOOMMISS"," Da'" 6/ ~ð ;y Submit in duplicate Form 10-401 Revised 3/2003 . ----- nDIf"fNAL -.j ¡ \ LJ · ConocoPhillips Alaska, Inc~ General Drillina Procedure Placer # 1 1. MIRU Nordic Rig 3 over pre-installed 16" conductor casing. Weld landing ring on conductor. 2. NU Diverter and function test same. Notify regulatory agencies 48 hours prior to test. 3. PU Directional BHA and prepare to spud. 4. Spud well and directionally drill 12-1/4" hole to 9-5/8" surface casing point at +1- 2,561' MD 1 2,302' ND as outlined in directional plan. Run MWD 1 LWD'fogging tools in drill string as required for directional monitoring and formation data gathering. 5. Circulate and condition well bore. Perform short trip. POOH to Run Casing. 6. Run and cement 9-5/8" 40# L-80 BTC casing to surface. / Note: Light weight permafrost cement lead slurry and Dowell LiteCrete high compressive, lightweight tail slurry will be utilized to assure cement returns to the surface in a one-stage job. Adequate excess cement will be pumped to ensure cement reaches the surface during the ('/ cement job. A Top Job may only be performed after consultinq with the AOGCC. 7. ND Diverter System. Install and test BOPE. 8. PU Directional BHA. RIH and cleanout to top of float equipment. Test casing to 2500 psi for 30 minutes. Notify regulatory agencies 48 hours prior to test. Drill out cement, float collar, float shoe and 20' to 50' of new hole. Perform LOT 1 FIT not to exceed 16.0 ppg EMW. These test results must demonstrate that the integrity of the casing shoe will be sufficient to contain the anticipated wellbore pressures. " 9. Directionally drill 8-1/2" hole to 7".jntermediate casing point at +1- 7,554' MD / 6,114'ND as outlined in directional plan. Run MWD 1 LWD logging tools in drill string as required for directional monitoring and formation data gathering. 10. Circulate and condition well bore. Perform short trip. POOH to Run Casing 11. Run and cement 7" 26# L -80 BTC casing to surface. / 12. PU Directional BHA and RIH. Cleanout to top of float equipment. Test casing to 2500 psi for 30 minutes. Notify regulatory agencies 48 hours prior to test. Drill out cement, float collar, float shoe and 20' to 50' of new hole. Perform LOT 1 FIT not to exceed 13.5 ppg EMW. 13. Directionally drillß-1/8" hole to planned TD at +1- 8,389' MD /6,752' ND as outlined in directional plan. Run MWD / LWD logging tools in drill string as required for directional monitoring and formation data gathering. 14. Circulate and condition well bore. Perform short trip. POOH to run open hole Logs. , 15. RU E-Line Unit. RIH and Log Well as required. RD E-Line Unit. 16. PU Drill Pipe Conveyed Logging Tools. RIH and Log Well as required. POOH and LD Drill Pipe Conveyed Logging Tools Note: Log results will determine plan to Complete or Plug and Abandon well bore. ORJGJNÞ\L e ConocoPhillips Alaska, Inc. 17. RIH to TO. 18. Circulate and condition well bore. Perform short trip. POOH to run Production Liner. 19. Run and cement 3-1/2" 9.3# L-80 EUE 8rd Mod production liner. / 20. Circulate out any excess cement and displace well to seawater. 21. POOH laying down 4" drill pipe. 22. RIH and install 3-1/2" 9.3# L-80 EUE 8rd Completion Assembly. Prior to stinging into liner top w/ /' completion assembly, test casing to 3500 psi for 30 minutes. Notify regulatory agencies 48 hours prior to test. 23. Sting into SBE and land tubing hanger. With annulus open, pressure test tubing to 3500 psi for 5 minutes and monitor annulus for returns. 24. Bleed down pressure in tubing to 1500 psi. While holding 1500 psi on tubing pressure 3-1/2" x 7" annulus to 3500 psi for 5 minutes. Bleed pressure in tubing to zero and shear RP valve in lower GLM. 25. NO BOPE, NU Tree and Test to 5000 psi. Freeze protect well with Diesel. Rig down and move off Nordic Rig 3. Note: Well bore will either be tested, temporarily suspended or P&A'd as per AOGCC regulations / 26. MIRU well testing equipment and surface test tanks. Perform production tests as required. Produced fluids will be either re-injected into the formation or trucked to Kuparuk or Alpine production facilities. 27. Upon completion of testing, plug and abandon or temporarily suspend the well as per AOGCC regulations. 28. Thoroughly clean location and block off further ice road access to ice location. ORIGINAL e ConocoPhillips Alaska, Inc. Formation Evaluation: Anticipated logging, coring and testing for this well is as follows: I. Logging 12-1/4" Surface Interval LWD: 8-1/2" Intermediate Interval LWD: GR / Res / Neu / Den v GR / Res 6-1/8" Production Interval LWD: E-Line / DP Conveyed: GR / Res / Neu / Den / PWD VC Sonic / MDT / CMR / Rotary Sidewall Cores II. Coring None planned. III. Mudlogging ./ Mudlogging service should be in operation from the base of the surface conductor casing to TD. Service most likely will include ROP on 5' intervals, lithology, total gas, sample collection, gas analysis of cuttings, gas chromatography, and H2S detection Sixty-foot (60') USGS Gas Hydrate Samples will be collected from Surface to 3000' MD-RKB. Thirty-foot (30') wet and dry samples will be collected from Surface to Surface Casing Point. Thirty-foot (30') wet and dry samples will be collected from Surface Casing Point to Intermediate Casing Point. Thirty-foot (30') wet and dry samples will be collected from Intermediate Casing Point to well TD. Ten-foot (10') wet and dry samples, or continuous, collected across all shows and all target intervals. IV. Flow Testing Currently, ConocoPhillips plans to complete and test the Placer #1 well. Flow testing and pressure bUild-up tests will be used to determine formation properties and estimate the commerciality of this exploratory well. Reservoir stimulation may be performed in the form of an acid or frac treatment. The flow period will be determined on-site in response to analysis of initial flow period, PBU and fluid properties. The well will be flowed to temporary surface production facilities consisting of gas separation and fluid storage tanks. Produced fluids will either be trucked to an existing production facility or re-injected into the formation following completion of the flow testing operations. ORIGINAL Rig: Unknown Location: Exploration Client: ConocoPhillips Alaska, Inc. Revision Date: 1/05/04 Prepared by: Mike Martin Location: Anchorage, AK Phone: (907) 265-6205 Mobile: (907) 229-6266 email: martin13@slb.com < TOC at Surface < Permafrost < 16" 62.58# casing in 24" OH TD at 115 MD 115 TVD) Mark of Schlumberger Preliminary Job Design based on limited input data. For estimate purposes only. Schlulbepgøp Volume Calculations and Cement Systems Volumes are based on NO excess in the permafrost with slurry to surface. Conductor Slurry ARCTICSET I @ 15.7 ppg -0.93ft3Jsk 1.745 ft3/ftx 115' x 1.00 (No excess) = 1.268 ft3Jft x 5' (Shoe Joint) = 200.7 ft3 + 6.3 ft3 = 207.0 ft3 10.93 ft3Jsk = Round up to 230 sks 200.7 ft3 6.3 ft3 207.0 ft3 222.6 sks Have 230 sks of additional cement on location for if necessary for a second stage BHST = 25°F, Estimated BHCT = 25°F. NOTE: Casing will float if not weighted or chained down r1f)IGIN-AL \."" Î\ i Rig: Unknown Location: Exploration Client: ConocoPhillips Alaska, Inc. Revision Date: 1/5/2004 Prepared by: Mike Martin Location: Anchorage, AK Phone: (907) 265-6205 Mobile: (907) 229-6012 email: martin13@slb.com < TOC at Surface Previous Csg. < 16", 62.6# casing at 115' MD < Base of Permafrost at 1,558' MD (1,575' TVD) < Top of Tail at 1,600' MD < 9 5/8", 40.0# casing in 12 1/4" OH TO at 2,561' MD (2,302' TVD) Mark of Schlumberger SehtulblPllP Preliminary Job Design based on limited input data. For estimate purposes only. Volume Calculations and Cement Systems Volumes are based on 350% excess in the permafrost and 35% excess below the permafrost. The top of the tail slurry is designed to be at 1,600' MD. Lead Slurry Minimum pump time: 190 min. (pump time plus 90 min.) ARCTICSET Lite @ 10.7 ppg - 4.28 ft3/sk 0.7632 ft31ft x (115') x 1.00 (no excess) = 0.3132 ft3/ft x (1558' -115') x 4.50 (350% excess) = 0.3132ft3/ft x (1600' -1558') x 1.35 (35% excess) = 87.8 ft3 + 2033.8 ft3+ 17.8 ft3 = 2139.4 ft3 1 ~k = Round up éY::.kS Have 310 sks of additional Lead on location for Top Out stage, if necessary. 87.8 ft3 2033.8 ft3 17.8 ft3 2139.4 ft3 499.9 sks Tail Slurry Minimum pump time: 130 min. (pump time plus 90 min.) LiteCRETE @ 12.0 ppg - 2.28 ft3/sk 406.3 ft3 34.1 ft3 440.4 ft3 193.2 sks 0.3132 ft3/ft x (2561' -1600') x 1.35 (35% excess) = 0.4257 ft31ft x 80' iShoe Joint) = 406.3 ft3 + 34.1 ft = 440.4 ft31 2.2~ = Round up t~kS BHST = 49°F, Estimated BHCT = 65°F. (BHST calculated using a gradient of 2.6°F/100 ft. below the permafrost) PUMP SCHEDULE Pump Rate Stage Stage Time Cumulative Stage (bpm) Volume (min) Time (bbl) (min) CW100 5 50 10.0 10.0 Drop Bottom Plug 5.0 15.0 MudPUSH II 5 50 10.0 25.0 Lead Slurry 7 381 54.4 79.4 Tail Slurry 6 81 13.5 92.9 Drop Top Plug 5.0 97.9 Displacement 9 173 19.2 117.1 Slow Rate 3 15 5.0 122.1 MUD REMOVAL Recommended Mud Properties: 9.8 ppg, Pv < 15, Ty < 15. As thin and light as possible to aid in mud removal during cementing. Spacer Properties: 10.5 ppg MudPUSH* II, Pv? 17-21, Ty ? 20-25 Centralizers: Recommend 1 per joint across zones of interest for proper cement placement. ¡ð. L.. iÎ?''''';. . Rig: Unknown Location: Exploration Client: ConocoPhillips Alaska, Inc. Revision Date: 1/5/2004 Prepared by: Mike Martin Location: Anchorage, AK Phone: (907) 265-6205 Mobile: (907) 229-6266 email: martin13@slb.com Previous Csg. < 9 5/8", 40.0# casing at 2,561' MD SchllllblPDep Preliminary Job Design based on limited input data. For estimate purposes only. Volume Calculations and Cement Systems Volumes are based on 75% excess. Tail slurry is designed for? 800' MD annular length. Tail Slurry Minimum thickening time: 150 min. (Pump time plus 90 min.) 15.8 ppg Class G + 0.2%046, 0.3%D65, 0.1%0800 -1.17 ft3/sk (adjust retarder to give desired thickening time) 0.1268 ft3/ft x 804' x 1.75 (75% excess) = 0.2148 ft3/ft x 80' JShoe Joint) = 178.4 ft3 + 17.2 = 195.6 ft3/1.1 Is = Round up 0 17 ks 178.4 ft3 17.2 ft3 195.6 ft3 167.2 sks BHST = 148°F, Estimated BHCT = 115°F. (BHST calculated using a gradient of 2.6°F/100 ft. below the permafrost) PUMP SCHEDULE Pump Rate Stage Stage Time Cumulative Stage (bpm) Volume (min) Time (bbl) (min) CW100 6 20 3.3 3.3 Drop Bottom Plug 5.0 8.3 MudPUSH II 6 30 5.0 13.3 Tail Slurry 6 35 5.8 19.1 Drop Top Plug 5.0 24.1 Displacement 6 266 44.3 68.4 < Top of Tail at Slow Rate 3 20 6.7 75.1 6,750' MD < 7",26.0# casing in 8 1/2" OH TO at 7,554' MD (6,114'TVD) MUD REMOVAL Recommended Mud Properties: 10.6 ppg, Pv < 15, Ty < 15. As thin and light as possible to aid in mud removal during cementing. Spacer Properties: 12.0 ppg MudPUSH* II, Pv? 19-22, Ty ? 22-29 Centralizers: Recommend 1 per joint across zones of interest for proper cement placement. Rig: Unknown Location: Exploration Client: ConocoPhillips Alaska Revision Date: 1/5/2004 Prepared by: Mike Martin Location: Anchorage, AK Phone: (907) 265-6205 Mobile: (907) 229-6266 email: martin13@slb.com Top of Tail at < 7,204' MD < Liner Top at 7,404' MD Previous Csg. 7",26.0# casing at 7,554' MD Preliminary Job Design based on limited input data. For estimate purposes only. Schlullbepg8P Volume Calculations and Cement Systems Volumes are based on 60% excess. Displacement is calculated with a 4.0"-14.0# drill string. Tail Slurry Minimum thickening time: 130 min. (pump time plus 90 min.) 15.8 ppg Class G + 2.0 gps D600G + 0.02% B155 + 0.3% 065 + 0.2 gps 047 -1.16 ft3/sk Liner Cap: 3 0.1276 ft 1ft x 200' x 1.00 (no excess) = Liner Lap.: 0.1480 ft3/ft x (7554' - 7404') x 1.00 (no excess) = Annular Volume: 0.1378 ft3/ft x (8689' - 7554') x 1.60 (60% excess) = Shoe Volume: 3 0.0488 ft 1ft x 80' x 1.00 (no excess) = Totals: 25.5 ft3 + 22~2 ft.3. 250.2 ft3 + 4.4 ft3 = 302.3 ft31 1.1 Is = Round up t 27Q ks BHST = 171°F, Estimated BHCT = 131°F. (BHST calculated using a gradient of 2.6°F/100 ft. below the permafrost) 25.5 ft3 22.2 ft3 250.2 ft3 4.4 ft3 302.3 ft3 260.6 sks PUMP SCHEDULE Pump Rate Stage Stage Time Cumulative Stage (bpm) Volume (min) Time (bbl) (min) CW100 5 20 4.0 4.0 MudPUSH II 5 30 6.0 10.0 < 31/2",9.3# casing Tail Slurry 5 56 11.2 21.2 in 6 1/8" OH Drop Top Plug 5.0 26.2 Displacement 5 81 16.2 42.4 Slow Rate 3 10 3.3 45.7 TD at 8,689' MD (6,981' TVD) Mark of Schlumberger MUD REMOVAL Recommended Mud Properties: 11.0 ppg, Pv < 15, Ty < 15. As thin and light as possible to aid in mud removal during cementing. Spacer Properties: 12.5 ppg MudPUSW II, Pv? 19-22, Ty '? 22-29 Centralizers: Recommend 1 per joint from 7404' MD to TO for proper cement placement. IGINi~L · Placer 1 ProposW Completion Schematic Exploration Well - Confidential (Success Case "KeeperH / Top Set) t[onocòi'hillips Conductor: 16", 62.58# Set @ +1- 115' MD J[.J rL I .. I Tubing Hanger: FMC Gen V Hanger wi 3-1/2" L-80 EUE 8rd Mod pup joint installed (Special Drift Hanger to 2.920" wi Pup Joint Installed). Spaceout Tubing Pups (as required): 3-1/2" 9.3# L-80 EUE 8rd Mod (Special Drift Tubing to 2.920") Surface Casing 9-5/8" 40# L-80 BTC - Float Collar to Surface Tubing (as required): 3-1/2" 9.3# L-80 EUE 8rd Mod (Special Drift Tubing to 2.920") Float Collar: Weatherford - Single Valve 9-5/8" 32-53# BTC Box x Pin (2) Joints Casing: 9-5/8" 40# L-80 BTC - I .- .. I I I .. Landing Nipple: 3-1/2" Cameo 'DS-Nipple' wi 2.875" No-Go Profile set @ +1- 500' MD I TVD-RKB (Lock = 2.906" OD) Tubing (as required): 3-1/2" 9.3# L-80 EUE 8rd Mod Float Shoe: Weatherford - Single Valve 9-5/8" 32-53# BTC Box Up Gas lift Mandrel (4 Total): 3-1/2" x 1" Cameo 'KBUG' GLM wi dummy valves and latches, 6' handling pups installed on top and bottom TD 12-1/4" Hole (ã) 2,561' MD/2,302' TVD-RKB Position GLM's in the following locations: .MJ2 .:rw. Intermediate I Production Casing 7" 26# L -80 BTC - Float Collar to Surface Float Collar: Weatherford - Single Valve 7" 20-35# BTC Box x Pin Tubing (as required): 3-1/2" 9.3# L-80 EUE 8rd Mod Gas lift Mandrel (1 Total): 3-1/2" x 1-1/2" Camco 'MMG' GLM wi Dump Kill Valve (3000 psi casing to tubing shear). 6' handling pups installed on top and bottom (2) Joints Casing: 7" 26# L-80 BTC Float Shoe: Weatherford - Single Valve 7" 20-35# BTC Box Up Tubing (1 Joint): 3-1/2" 9.3# L-80 EUE 8rd Mod II" Sliding Sleeve: Baker 3- W' CMU Sliding Sleeve wi 2.813" Camco DS No-Go Profile (Lock = 2.856" OD), EUE 8rd Box x Pin, 6' handling pups installed on top and bottom Tubing (1 Joint): 3-1/2" 9.3# L-80 EUE 8rd Mod Liner Top Packer I Hanger Assembly (Non-Rotating): Packer Setting Depth Planned (Õ) 150' above 7" Casing Shoe. TD 8-1/2" Hole (ã) 7,554' MD 1 6,114' TVD-RKB .J l Packer: Baker 5" x 7" lXP Liner Top Packer (5.969" OD, 4.408" ID) Nipple: Baker 5" RS Nipple (5.563" OD, 4.375" ID) Hanger: Baker 5" x 7" HMC Liner Hanger (5.924" OD, 4.408" ID) Seal Bore Receptacle (SBR): Baker 80-40 Casing Seal Bore Receptacle 17' wi 15' of Effective Seals (5" OD, 4" ID) Crossover Sub: Baker 5" BTC Box x 3-1/2" EUE 8rd Mod Pin Production liner: 3-1/2" 9.3# L -80 EUE 8rd Mod TD 6-1/8" Open Hole (ã) 7,859' MD 16,347' TVD-RKB Success Case Depth ~200' MD Below Kuparuk Landing Collar: Baker wi 3-1/2" EUE 8rd Mod Box x Pin (1) Joints Casing: 3-1/2" 9.3# L-80 EUE 8rd Mod TD 6-1/8" Open Hole (ã) 8,389' MD I 6,752' TVD-RKB Failure Case Depth ~200' MD Below J4 TD 6-1/8" Open Hole (ã) 8,689' MD / 6,981' TVD-RKB Permitted Depth ~500' MD Below J4 Float Collar: Baker - Single Valve wi 3-1/2" EUE 8rd Mod Box x Pin (2) Joints Casing: 3-1/2" 9.3# L-80 EUE 8rd Mod Float Shoe: Baker - Single Valve wi 3-1/2" EUE 8rd Box Up IGINI\L Placer 1 Schematic v1.0 prepared by Mark Chambers 12/31/03 7 2 , X). I / "2 L 1 L Placer 1 tops (TVDSS) MD INC AZI TVD NS EW DLS VS MAPN MAPE LAT LONG Base Perm ëfrœt 1360 1434.55 25.38 173.08 1414.00 -137.26 16.65 4.00 138.27 5976289.53 451306.22 70°20'45.6' 150°23'42.91 OW Tap West Sak 1570 1677.95 35.12 173.08 1624.00 -258.84 31.40 4.00 260.74 5976167.87 451320.18 70°20'44.41 150023'42.479W Base West Sak 2025 2268.73 40.15 173.08 2079.00 -632.71 76.76 0.00 637.35 5975793.75 451363.10 70°20'40.81 150023'41.154W caD 2348 2691.31 40.15 173.08 2402.00 -903.21 109.58 0.00 909.83 5975523.07 451394.15 70°20'38.1, 150023'40.195W C40 K-5 2800 3282.66 40.15 173.08 2854.00 -1281.74 155.50 0.00 1291.14 5975144.28 451437.61 70020'34.4150023'38.854W C50 np (K-3) 3975 4819.92 40.15 173.08 4029.00 -2265.76 274.88 0.00 2282.37 5974159.61 451550.58 70°20'24.7, 150023'35.367W Marane (K-2) 5300 6553.43 40.15 173.08 5354.00 -3375.39 409.50 0.00 3400.14 5973049.23 451677.98 70°20'13.8: 150023'31.437W 00 (Base M 0' air 5400 6684.26 40.15 173.08 5454.00 -3459.14 419.66 0.00 3484.50 5972965.43 451687.59 70°20'13.01 150023'31.140W e Tap HRZ 5752 7144.78 40.15 173.08 5806.00 -3753.92 455.42 0.00 3781.45 5972670.44 451721.43 70°20'10.11 150023'30.096W C:ZO (m id-upper r 5925 7371.12 40.15 173.08 5979.00 -3898.80 473.00 0.00 3927.39 5972525.47 451738.07 70°20'08.61 150023'29.583W Base HRZ 5975 7441.76 40.15 173.08 6033.00 -3944.03 478.48 0.00 3972.94 5972480.21 451743.26 70°20'08.2: 150023'29.423W K-l 6040 7521.57 40.15 173.08 6094.00 -3995.11 484.68 0.00 4024.40 5972429.09 451749.1270°20'07.7: 150023'29.242W Tap Kuparuk 6120 (Kuparuk D) '.::J Kuparuk C 6120 7626.23 40.15 173.08 6174.00 -4062.11 492.81 0.00 4091.89 5972362.05 451756.81 70°20'07.0 150023'29.005W ª "\ :::tJ Mi luveð:h (LCU) 6140 7652.40 40.15 173.08 6194.00 -4078.86 494.84 0.00 4108.76 5972345.29 451758.74 70°20'06.9 150023'28.946W .J4 S<nd 6545 8182.26 40.15 173.08 6599.00 -4418.03 535.99 0.00 4450.42 5972005.89 451797.68 70°20'03.5' 150023'27.745W """""..- TD ('0200' MD be 6657 ú; ~- z ::t> r e e e Conversion Results For: Permitted TD ASP Zone 4: 451835.745971674.10 70.33342031 150.39071410 UTM Zone 5 X=597984.965397 Y =7804983.337555 Meridian: U TIIN R7E Section 4 3740.63FNL 1539.37FSL 4698. 18FEL 581.80FWL 70 deg 20 min 0.313 see 150 deg 23 min 26.571 see Conversion Complete OR1GINAL e e Conversion Results For: SL Placer 1 ASP Zone 4: 451349 5976440 70.34643276 150.39491341 UTM Zone 5 X=597765.225398 Y=7806426.640495 Meridian: U T12N R7E Section 33 4257.36FNL 1022.65FSL 5202.52FEL 77.46FWL 70 deg 20 min 47.158 see 150 deg 23 min 41.688 see Conversion Complete Conversion Results For: Target @ Kuparuk C ASP Zone 4: 4517585972352 70.33527106 150.39138009 UTM Zone 5 X=597951.120912 Y=7805188.50481O Meridian: U TIIN R7E Section 4 3063. 15FNL 2216.85FSL 4778.43FEL 501.56FWL 70 deg 20 min 6.976 see 150 deg 23 min 28.968 see Conversion Complete I..' 'A L ~ ;I . ~ ! Nt" e e Conversion Results For: Target Jurassic J4 Sand ASP Zone 4: 451798.945971994.88 70.33429608 150.39102934 UTM Zone 5 X=597968.946147 Y=7805080.421809 Meridian: U TIIN R7E Section 4 3420.05FNL 1859.95FSL 4736. 17FEL 543.81FWL 70 deg 20 min 3.466 see 150 deg 23 min 27.706 see Conversion Complete Conversion Results For: Planned TD ASP Zone 4: 451813.665971866.57 70.33394578 150.39090324 UTM Zone 5 X=597975.353820 Y =7805041.588717 Meridian: U TIIN R7E Section 4 3548.28FNL 1731.72FSL 4720.97FEL 559.01FWL 70 deg 20 min 2.205 see 150 deg 23 min 27.252 see Conversion Complete !r-I"!AL ¡ tJ 1\1. e ConocoPhillips GeoReport e Survey: Start Date: Company: Engineer: Tool: Tied·to: Survey 30.00 0.000 0.000 30.00 -24.00 0.00 0.00 5976426.881 451290.459 SL(1009'FSL& 19'FWL, See 100.00 0.000 0.000 100.00 46.00 0.00 0.00 5976426.881 451290.459 200.00 0.000 0.000 200.00 146.00 0.00 0.00 5976426.881 451290.459 300.00 0.000 0.000 300.00 246.00 0.00 0.00 5976426.881 451290.459 400.00 0.000 0.000 400.00 346.00 0.00 0.00 5976426.881 451290.459 500.00 0.000 0.000 500.00 446.00 0.00 0.00 5976426.881 451290.459 600.00 0.000 0.000 600.00 546.00 0.00 0.00 5976426.881 451290.459 700.00 0.000 0.000 700.00 646.00 0.00 0.00 5976426.881 451290.459 800.00 0.000 0.000 800.00 746.00 0.00 0.00 5976426.881 451290.459 900.00 4.000 173.083 899.92 845.92 -3.46 0.42 5976423.415 451290.857 1000.00 8.000 173.083 999.35 945.35 -13.84 1.68 5976413.033 451292.048 1100.00 12.000 173.083 1097.81 1043.81 -31.07 3.77 5976395.787 451294.027 1200.00 16.000 173.083 1194.82 1140.82 -55.08 6.68 5976371.759 451296.783 1300.00 20.000 173.083 1289.91 1235.91 -85.76 10.40 5976341.068 451300.305 1400.00 24.000 173.083 1382.61 1328.61 -122.94 14.91 5976303.863 451304.573 1434.55 25.382 173.083 1414.00 1360.00 -137.26 16.65 5976289.525 451306.218 Base Permafrost 1500.00 28.000 173.083 1472.47 1418.47 -166.44 20.19 5976260.325 451309.568 1600.00 32.000 173.083 1559.05 1505.05 -216.07 26.21 5976210.665 451315.266 1677.95 35.118 173.083 1624.00 1570.00 -258.84 31.40 5976167.867 451320.176 Top West Sak 1700.00 36.000 173.083 1641.94 1587.94 -271.57 32.95 5976155.127 451321.637 1800.00 40.000 173.083 1720.73 1666.73 -332.68 40.36 5976093.981 451328.653 1805.68 40.227 173.083 1725.07 1671.07 -336.31 40.80 5976090.348 451329.070 1900.00 40.227 173.083 1797.08 1743.08 -396.78 48.14 5976029.835 451336.012 2000.00 40.227 173.083 1873.43 1819.43 -460.89 55.91 5975965.680 451343.373 2100.00 40.227 173.083 1949.78 1895.78 -525.00 63.69 5975901.525 451350.733 2200.00 40.227 173.083 2026.13 1972.13 -589.12 71.47 5975837.370 451358.093 2269.25 40.227 173.083 2079.00 2025.00 -633.51 76.86 5975792.944 451363.190 Base West Sak 2300.00 40.227 173.083 2102.48 2048.48 -653.23 79.25 5975773.216 451365.454 2400.00 40.227 173.083 2178.83 2124.83 -717.34 87.03 5975709.061 451372.814 2500.00 40.227 173.083 2255.18 2201.18 -781.45 94.80 5975644.906 451380.175 2561.33 40.227 173.083 2302.00 2248.00 -820.77 99.57 5975605.562 451384.689 95/8" Csg Pt @ 2561' MD 2600.00 40.227 173.083 2331.53 2277.53 -845.56 102.58 5975580.752 451387.535 2692.31 40.227 173.083 2402.00 2348.00 -904.74 109.76 5975521.534 451394.329 C-80 2700.00 40.227 173.083 2407.87 2353.87 -909.67 110.36 5975516.597 451394.896 2800.00 40.227 173.083 2484.22 2430.22 -973.79 118.14 5975452.442 451402.256 2900.00 40.227 173.083 2560.57 2506.57 -1037.90 125.92 5975388.288 451409.616 3000.00 40.227 173.083 2636.92 2582.92 -1102.01 133.69 5975324.133 451416.977 3100.00 40.227 173.083 2713.27 2659.27 -1166.12 141.47 5975259.978 451424.337 3200.00 40.227 173.083 2789.62 2735.62 -1230.23 149.25 5975195.824 451431.698 3284.32 40.227 173.083 2854.00 2800.00 -1284.29 155.81 5975141.727 451437.904 C40 K-5 3300.00 40.227 173.083 2865.97 2811.97 -1294.34 157.03 5975131.669 451439.058 3400.00 40.227 173.083 2942.32 2888.32 -1358.46 164.81 5975067.514 451446.419 3500.00 40.227 173.083 3018.67 2964.67 -1422.57 172.58 5975003.360 451453.779 3600.00 40.227 173.083 3095.02 3041.02 -1486.68 180.36 5974939.205 451461.139 3700.00 40.227 173.083 3171.37 3117.37 -1550.79 188.14 5974875.050 451468.500 3800.00 40.227 173.083 3247.72 3193.72 -1614.90 195.92 5974810.896 451475.860 3900.00 40.227 173.083 3324.06 3270.06 -1679.02 203.70 5974746.741 451483.221 4000.00 40.227 173.083 3400.41 3346.41 -1743.13 211.47 5974682.586 451490.581 4100.00 40.227 173.083 3476.76 3422.76 -1807.24 219.25 5974618.432 451497.942 DIf"'I' f^ r~!¡!., ~,,:,' ""_··It..~_ e ConocoPhillips GeoReport e Survey 4200.00 40.227 173.083 3553.11 3499.11 -1871.35 227.03 5974554.277 451505.302 4300.00 40.227 173.083 3629.46 3575.46 -1935.46 234.81 5974490.122 451512.662 4400.00 40.227 173.083 3705.81 3651.81 -1999.57 242.59 5974425.968 451520.023 4500.00 40.227 173.083 3782.16 3728.16 -2063.69 250.36 5974361.813 451527.383 4600.00 40.227 173.083 3858.51 3804.51 -2127.80 258.14 5974297.658 451534.744 4700.00 40.227 173.083 3934.86 3880.86 -2191.91 265.92 5974233.504 451542.104 4800.00 40.227 173.083 4011.21 3957.21 -2256.02 273.70 5974169.349 451549.465 4823.31 40.227 173.083 4029.00 3975.00 -2270.96 275.51 5974154.398 451551.180 K-3 4900.00 40.227 173.083 4087.56 4033.56 -2320.13 281.48 5974105.194 451556.825 5000.00 40.227 173.083 4163.90 4109.90 -2384.24 289.25 5974041.040 451564.185 5100.00 40.227 173.083 4240.25 4186.25 -2448.36 297.03 5973976.885 451571.546 5200.00 40.227 173.083 4316.60 4262.60 -2512.47 304.81 5973912.730 451578.906 5300.00 40.227 173.083 4392.95 4338.95 -2576.58 312.59 5973848.576 451586.267 5400.00 40.227 173.083 4469.30 4415.30 -2640.69 320.37 5973784.421 451593.627 5500.00 40.227 173.083 4545.65 4491.65 -2704.80 328.14 5973720.266 451600.987 5600.00 40.227 173.083 4622.00 4568.00 -2768.91 335.92 5973656.112 451608.348 5700.00 40.227 173.083 4698.35 4644.35 -2833.03 343.70 5973591.957 451615.708 5800.00 40.227 173.083 4774.70 4720.70 -2897.14 351.48 5973527.802 451623.069 5900.00 40.227 173.083 4851.05 4797.05 -2961.25 359.26 5973463.648 451 630.429 6000.00 40.227 173.083 4927.40 4873.40 -3025.36 367.03 5973399.493 451637.790 6100.00 40.227 173.083 5003.75 4949.75 -3089.47 374.81 5973335.338 451645.150 6200.00 40.227 173.083 5080.09 5026.09 -3153.58 382.59 5973271.184 451652.510 6300.00 40.227 173.083 5156.44 5102.44 -3217.70 390.37 5973207.029 451659.871 6400.00 40.227 173.083 5232.79 5178.79 -3281.81 398.15 5973142.874 451667.231 6500.00 40.227 173.083 5309.14 5255.14 -3345.92 405.92 5973078.720 451674.592 6558.75 40.227 173.083 5354.00 5300.00 -3383.59 410.49 5973041.026 451678.916 Moraine (K-2) 6600.00 40.227 173.083 5385.49 5331.49 -3410.03 413.70 5973014.565 451681.952 6689.73 40.227 173.083 5454.00 5400.00 -3467.56 420.68 5972956.998 451688.557 C30 (Base Moraine) 6700.00 40.227 173.083 5461.84 5407.84 -3474.14 421.48 5972950.410 451689.313 6800.00 40.227 173.083 5538.19 5484.19 -3538.26 429.26 5972886.256 451696.673 6900.00 40.227 173.083 5614.54 5560.54 -3602.37 437.03 5972822.101 451704.033 7000.00 40.227 173.083 5690.89 5636.89 -3666.48 444.81 5972757.946 451711.394 7100.00 40.227 173.083 5767.24 5713.24 -3730.59 452.59 5972693.791 451718.754 7150.77 40.227 173.083 5806.00 5752.00 -3763.14 456.54 5972661.219 451722.491 Top HRZ 7200.00 40.227 173.083 5843.59 5789.59 -3794.70 460.37 5972629.637 451726.115 7300.00 40.227 173.083 5919.94 5865.94 -3858.81 468.15 5972565.482 451733.475 7377.36 40.227 173.083 5979.00 5925.00 -3908.41 474.16 5972515.851 451739.169 C20 (Mid-upper HRZ) 7400.00 40.227 173.083 5996.28 5942.28 -3922.93 475.92 5972501.327 451740.836 7442.85 40.227 173.083 6029.00 5975.00 -3950.40 479.26 5972473.837 451743.990 Base HRZ 7500.00 40.227 173.083 6072.63 6018.63 -3987.04 483.70 5972437.173 451748.196 7527.99 40.227 173.083 6094.00 6040.00 -4004.98 485.88 5972419.219 451750.256 K-1 7554.18 40.227 173.083 6114.00 6060.00 -4021.77 487.92 5972402.413 451752.184 7" Csg PI 7554'MD 7600.00 40.227 173.083 6148.98 6094.98 -4051.15 491.48 5972373.018 451755.556 7632.77 40.227 173.083 6174.00 6120.00 -4072.16 494.03 5972351.996 451757.968 Placer 1 Kuparuk C 7658.96 40.227 173.083 6194.00 6140.00 -4088.95 496.07 5972335.191 451759.896 Miluveach (LCU) 7700.00 40.227 173.083 6225.33 6171.33 -4115.26 499.26 5972308.863 451762.917 7800.00 40.227 173.083 6301.68 6247.68 -4179.37 507.04 5972244.709 451770.277 7900.00 40.227 173.083 6378.03 6324.03 -4243.48 514.81 5972180.554 451777.638 8000.00 40.227 173.083 6454.38 6400.38 -4307.60 522.59 5972116.399 451784.998 8100.00 40.227 173.083 6530.73 6476.73 -4371.71 530.37 5972052.245 451792.359 8189.42 40.227 173.083 6599.00 6545.00 -4429.04 537.33 5971994.877 451798.940 J4 Sand 8200.00 40.227 173.083 6607.08 6553.08 -4435.82 538.15 5971988.090 451799.719 ORIGI~JAL e ConocoPhillips GeoReport e Survey 8300.00 40.227 173.083 6683.43 6629.43 -4499.93 545.93 5971923.935 451807.079 8389.42 40.227 173.083 6751.70 6697.70 -4557.26 552.88 5971866.568 451813.661 Planned TD (1732'FSL & 55£ 8400.00 40.227 173.083 6759.78 6705.78 -4564.04 553.70 5971859.781 451814.440 8500.00 40.227 173.083 6836.12 6782.12 -4628.15 561.48 5971795.626 451821.800 8600.00 40.227 173.083 6912.47 6858.47 -4692.27 569.26 5971731.471 451829.161 8689.42 40.227 173.083 6980.75 6926.75 -4749.60 576.22 5971674.104 451835.742 6 1/8" Open Hole +N/-S It 0.00 Drilled From: Tie-on Depth: Above System Datum: Declination: Mag Dip Angle: +EI-W It 0.00 Well Ref. Point 30.00 It Mean Sea Level 24.87 deg 80.66 deg Direction deg 173.083 Wellpath: Placer 1 Current Datum: Magnetic Data: Field Strength: Vertical Section: SITE 8/14/2003 57465 nT Depth From (TVD) It 30.00 Height 54.00 It Targets Placer 1 Kuparuk C -Polygon 1 -Polygon 2 -Polygon 3 -Polygon 4 -Plan hit target 6174.00 6174.00 6174.00 6174.00 6174.00 -4072.16 -4164.24 -3740.10 -4020.93 -4515.00 494.03 5972351.996451757.968 170.58 5972262.022451433.961 808.93 5972681.972452074.994 1150.78 5972398.945452414.972 681.89 5971907.982451942.934 70 20 6.976 N 70 20 6.070 N 70 20 10.241 N 70 20 7.479 N 70 20 2.620 N 150 23 28.969 W 150 23 38.415 W 150 23 19.772 W 150 23 9.790 W 150 23 23.484 W Annotation 30.00 7632.77 8189.42 8389.42 8689.42 30.00 6174.00 6599.00 6751.70 6980.75 SL (1009'FSL & 19'FWL, Sec33-T12N-R7E Tgt Kup-C (2217'FSL & 502'FWL, Sec4-T11N-R7E J4 Sand (1860'FSL & 544'FWL, Sec4-T11N-R7E) Planned TD (1732'FSL & 559'FWL, Sec4-T11N-R7E) / Permitted TD (1539'FSL & 582'FWL, Sec4-T11N-R7E) RIGINAL lalliburton Sperry-Sun e Planning Report ~·'I.·y...SLn Ø,UL.L.ING sê~vlC:&S 'W.uJUt:1Iiir(:N¡;:uMIi-".....· Field: Exploration 2003 Map System: US State Plane Coordinate System 1927 Geo Datum: NAD27 (Clarke 1866) Sys Datum: Mean Sea Level Map Zone: Coordinate System: Geomagnetic Model: Alaska, Zone 4 Well Centre BGGM2002 Site: Placer Site Position: Northing: 5976440.000 ft Latitude: 70 20 47.158 N From: Map Easting: 451349.000 ft Longitude: 150 23 41.688 W Position Uncertainty: 0.00 ft North Reference: True Ground Level: 0.00 ft Grid Convergence: -0.37 deg Well: Placer 1 Slot Name: Surface Position: +N/-S -13.50 ft Northing: 5976426.881 ft Latitude: 70 20 47.025 N +EI-W -58.46 ft Easting : 451290.459 ft Longitude: 150 23 43.396 W Position Uncertainty: 0.00 ft Reference Point: +N/-S -13.50 ft Northing: 5976426.881 ft Latitude: 70 20 47.025 N +EI-W -58.46 ft Easting : 451290.459 ft Longitude: 150 23 43.396 W Measured Depth: 30.00 ft Inclination: 0.000 deg Vertical Depth: 30.00 ft Azimuth: 0.000 deg Wellpath: Placer 1 Drilled From: Well Ref. Point Tie-on Depth: 30.00 ft Current Datum: SITE Height 54.00 ft Above System Datum: Mean Sea Level Magnetic Data: 8/14/2003 Declination: 24.87 deg Field Strength: 57465 nT Mag Dip Angle: 80.66 deg Vertical Section: Depth From (TVD) +N/-S +EI-W Direction ft ft ft deg 30.00 0.00 0.00 173.083 Plan: Placer 1 (wp07) Date Composed: 10/24/2003 Version: 44 Principal: Yes Tied-to: From Well Ref. Point Plan Section Information 30.00 0.000 0.000 30.00 0.00 0.00 0.00 0.00 0.00 0.00 . 800.00 0.000 0.000 800.00 0.00 0.00 0.00 0.00 0.00 0.00 1805.68 40.227 173.083 1725.07 -336.31 40.80 4.00 4.00 17.21 173.08 7632.77 40.227 173.083 6174.00 -4072.16 494.03 0.00 0.00 0.00 0.00 Placer 1 Kuparuk C 8189.42 40.227 173.083 6599.00 -4429.04 537.33 0.00 0.00 0.00 0.00 8389.42 40.227 173.083 6751.70 -4557.26 552.88 0.00 0.00 0.00 0.00 8689.42 40.227 173.083 6980.75 -4749.60 576.22 0.00 0.00 0.00 0.00 Survey 30.00 0.000 0.000 30.00 0.00 0.00 0.00 0.00 0.00 0.00 SL (1009'FSL & 19'FWL, Se 100.00 0.000 0.000 100.00 0.00 0.00 0.00 0.00 0.00 0.00 MWD 200.00 0.000 0.000 200.00 0.00 0.00 0.00 0.00 0.00 0.00 MWD 300.00 0.000 0.000 300.00 0.00 0.00 0.00 0.00 0.00 0.00 MWD 400.00 0.000 0.000 400.00 0.00 0.00 0.00 0.00 0.00 0.00 MWD 500.00 0.000 0.000 500.00 0.00 0.00 0.00 0.00 0.00 0.00 MWD 600.00 0.000 0.000 600.00 0.00 0.00 0.00 0.00 0.00 0.00 MWD 700.00 0.000 0.000 700.00 0.00 0.00 0.00 0.00 0.00 0.00 MWD 800.00 0.000 0.000 800.00 0.00 0.00 0.00 0.00 0.00 0.00 MWD 900.00 4.000 173.083 899.92 -3.46 0.42 3.49 4.00 4.00 0.00 MWD 1000.00 8.000 173.083 999.35 -13.84 1.68 13.94 4.00 4.00 0.00 MWD r ! f\I ^ f m ~'\,~ ,{''¡¡\ ~_~ talliburton Sperry-Sun e Planning Report ..p.u'\( 'v-sun OAI..LIIIì~ séU''lVlêèis ".IIi.IttJt~iø:'Ii'}"OSfC.~,,,"" Survey 1100.00 12.000 173.083 1097.81 -31.07 3.77 31.30 4.00 4.00 0.00 MWD 1200.00 16.000 173.083 1194.82 -55.08 6.68 55.49 4.00 4.00 0.00 MWD 1300.00 20.000 173.083 1289.91 -85.76 10.40 86.38 4.00 4.00 0.00 MWD 1400.00 24.000 173.083 1382.61 -122.94 14.91 123.84 4.00 4.00 0.00 MWD 1434.55 25.382 173.083 1414.00 -137.26 16.65 138.27 4.00 4.00 0.00 Base Permafrost 1500.00 28.000 173.083 1472.47 -166.44 20.19 167.67 4.00 4.00 0.00 MWD 1600.00 32.000 173.083 1559.05 -216.07 26.21 217.66 4.00 4.00 0.00 MWD 1677.95 35.118 173.083 1624.00 -258.84 31.40 260.74 4.00 4.00 0.00 Top West Sak 1700.00 36.000 173.083 1641.94 -271.57 32.95 273.56 4.00 4.00 0.00 MWD 1800.00 40.000 173.083 1720.73 -332.68 40.36 335.12 4.00 4.00 0.00 MWD 1805.68 40.227 173.083 1725.07 -336.31 40.80 338.77 4.00 4.00 0.00 MWD 1900.00 40.227 173.083 1797.08 -396.78 48.14 399.69 0.00 0.00 0.00 MWD 2000.00 40.227 173.083 1873.43 -460.89 55.91 464.27 0.00 0.00 0.00 MWD 2100.00 40.227 173.083 1949.78 -525.00 63.69 528.85 0.00 0.00 0.00 MWD 2200.00 40.227 173.083 2026.13 -589.12 71.47 593.44 0.00 0.00 0.00 MWD 2269.25 40.227 173.083 2079.00 -633.51 76.86 638.16 0.00 0.00 0.00 Base West Sak 2300.00 40.227 173.083 2102.48 -653.23 79.25 658.02 0.00 0.00 0.00 MWD 2400.00 40.227 173.083 2178.83 -717.34 87.03 722.60 0.00 0.00 0.00 MWD 2500.00 40.227 173.083 2255.18 -781.45 94.80 787.18 0.00 0.00 0.00 MWD 2561.33 40.227 173.083 2302.00 -820.77 99.57 826.79 0.00 0.00 0.00 95/8" Csg PI @ 2561' MD 2600.00 40.227 173.083 2331.53 -845.56 102.58 851.76 0.00 0.00 0.00 MWD 2692.31 40.227 173.083 2402.00 -904.74 109.76 911.38 0.00 0.00 0.00 C-80 2700.00 40.227 173.083 2407.87 -909.67 110.36 916.34 0.00 0.00 0.00 MWD 2800.00 40.227 173.083 2484.22 -973.79 118.14 980.93 0.00 0.00 0.00 MWD 2900.00 40.227 173.083 2560.57 -1037.90 125.92 1045.51 0.00 0.00 0.00 MWD 3000.00 40.227 173.083 2636.92 -1102.01 133.69 1110.09 0.00 0.00 0.00 MWD 3100.00 40.227 173.083 2713.27 -1166.12 141.47 1174.67 0.00 0.00 0.00 MWD 3200.00 40.227 173.083 2789.62 -1230.23 149.25 1239.25 0.00 0.00 0.00 MWD 3284.32 40.227 173.083 2854.00 -1284.29 155.81 1293.71 0.00 0.00 0.00 C40 K-5 3300.00 40.227 173.083 2865.97 -1294.34 157.03 1303.84 0.00 0.00 0.00 MWD 3400.00 40.227 173.083 2942.32 -1358.46 164.81 1368.42 0.00 0.00 0.00 MWD 3500.00 40.227 173.083 3018.67 -1422.57 172.58 1433.00 0.00 0.00 0.00 MWD 3600.00 40.227 173.083 3095.02 -1486.68 180.36 1497.58 0.00 0.00 0.00 MWD 3700.00 40.227 173.083 3171.37 -1550.79 188.14 1562.16 0.00 0.00 0.00 MWD 3800.00 40.227 173.083 3247.72 -1614.90 195.92 1626.74 0.00 0.00 0.00 MWD 3900.00 40.227 173.083 3324.06 -1679.02 203.70 1691.33 0.00 0.00 0.00 MWD 4000.00 40.227 173.083 3400.41 -1743.13 211.47 1755.91 0.00 0.00 0.00 MWD 4100.00 40.227 173.083 3476.76 -1807.24 219.25 1820.49 0.00 0.00 0.00 MWD 4200.00 40.227 173.083 3553.11 -1871.35 227.03 1885.07 0.00 0.00 0.00 MWD 4300.00 40.227 173.083 3629.46 -1935.46 234.81 1949.65 0.00 0.00 0.00 MWD 4400.00 40.227 173.083 3705.81 -1999.57 242.59 2014.24 0.00 0.00 0.00 MWD 4500.00 40.227 173.083 3782.16 -2063.69 250.36 2078.82 0.00 0.00 0.00 MWD 4600.00 40.227 173.083 3858.51 -2127.80 258.14 2143.40 0.00 0.00 0.00 MWD 4700.00 40.227 173.083 3934.86 -2191.91 265.92 2207.98 0.00 0.00 0.00 MWD 4800.00 40.227 173.083 4011.21 -2256.02 273.70 2272.56 0.00 0.00 0.00 MWD 4823.31 40.227 173.083 4029.00 -2270.96 275.51 2287.61 0.00 0.00 0.00 K-3 4900.00 40.227 173.083 4087.56 -2320.13 281.48 2337.14 0.00 0.00 0.00 MWD 5000.00 40.227 173.083 4163.90 -2384.24 289.25 2401.73 0.00 0.00 0.00 MWD 5100.00 40.227 173.083 4240.25 -2448.36 297.03 2466.31 0.00 0.00 0.00 MWD 5200.00 40.227 173.083 4316.60 -2512.47 304.81 2530.89 0.00 0.00 0.00 MWD 5300.00 40.227 173.083 4392.95 -2576.58 312.59 2595.47 0.00 0.00 0.00 MWD 5400.00 40.227 173.083 4469.30 -2640.69 320.37 2660.05 0.00 0.00 0.00 MWD 5500.00 40.227 173.083 4545.65 -2704.80 328.14 2724.64 0.00 0.00 0.00 MWD 5600.00 40.227 173.083 4622.00 -2768.91 335.92 2789.22 0.00 0.00 0.00 MWD ORIGINAL talliburton Sperry-Sun e Planning Report ......... of ·y...sun ~fUL.L,/II1iI !ÍI.~VIC:.. ")tu.iMtU'''r«l;¡;:~....lo- Survey 5700.00 40.227 173.083 4698.35 -2833.03 343.70 2853.80 0.00 0.00 0.00 MWD 5800.00 40.227 173.083 4774.70 -2897.14 351.48 2918.38 0.00 0.00 0.00 MWD 5900.00 40.227 173.083 4851.05 -2961.25 359.26 2982.96 0.00 0.00 0.00 MWD 6000.00 40.227 173.083 4927.40 -3025.36 367.03 3047.54 0.00 0.00 0.00 MWD 6100.00 40.227 173.083 5003.75 -3089.47 374.81 3112.13 0.00 0.00 0.00 MWD 6200.00 40.227 173.083 5080.09 -3153.58 382.59 3176.71 0.00 0.00 0.00 MWD 6300.00 40.227 173.083 5156.44 -3217.70 390.37 3241.29 0.00 0.00 0.00 MWD 6400.00 40.227 173.083 5232.79 -3281.81 398.15 3305.87 0.00 0.00 0.00 MWD 6500.00 40.227 173.083 5309.14 -3345.92 405.92 3370.45 0.00 0.00 0.00 MWD 6558.75 40.227 173.083 5354.00 -3383.59 410.49 3408.40 0.00 0.00 0.00 Moraine (K-2) 6600.00 40.227 173.083 5385.49 -3410.03 413.70 3435.03 0.00 0.00 0.00 MWD 6689.73 40.227 173.083 5454.00 -3467.56 420.68 3492.98 0.00 0.00 0.00 C30 (Base Moraine) 6700.00 40.227 173.083 5461.84 -3474.14 421.48 3499.62 0.00 0.00 0.00 MWD 6800.00 40.227 173.083 5538.19 -3538.26 429.26 3564.20 0.00 0.00 0.00 MWD 6900.00 40.227 173.083 5614.54 -3602.37 437.03 3628.78 0.00 0.00 0.00 MWD 7000.00 40.227 173.083 5690.89 -3666.48 444.81 3693.36 0.00 0.00 0.00 MWD 7100.00 40.227 173.083 5767.24 -3730.59 452.59 3757.94 0.00 0.00 0.00 MWD 7150.77 40.227 173.083 5806.00 -3763.14 456.54 3790.73 0.00 0.00 0.00 Top HRZ 7200.00 40.227 173.083 5843.59 -3794.70 460.37 3822.53 0.00 0.00 0.00 MWD 7300.00 40.227 173.083 5919.94 -3858.81 468.15 3887.11 0.00 0.00 0.00 MWD 7377.36 40.227 173.083 5979.00 -3908.41 474.16 3937.07 0.00 0.00 0.00 C20 (Mid-upper HRZ) 7400.00 40.227 173.083 5996.28 -3922.93 475.92 3951.69 0.00 0.00 0.00 MWD 7442.85 40.227 173.083 6029.00 -3950.40 479.26 3979.36 0.00 0.00 0.00 Base HRZ 7500.00 40.227 173.083 6072.63 -3987.04 483.70 4016.27 0.00 0.00 0.00 MWD 7527.99 40.227 173.083 6094.00 -4004.98 485.88 4034.34 0.00 0.00 0.00 K-1 7554.18 40.227 173.083 6114.00 -4021.77 487.92 4051.26 0.00 0.00 0.00 7" Csg PI 7554'MD 7600.00 40.227 173.083 6148.98 -4051.15 491.48 4080.85 0.00 0.00 0.00 MWD 7632.77 40.227 173.083 6174.00 -4072.16 494.03 4102.01 0.00 0.00 0.00 Placer 1 Kuparuk C 7658.96 40.227 173.083 6194.00 -4088.95 496.07 4118.93 0.00 0.00 0.00 Miluveach (LCU) 7700.00 40.227 173.083 6225.33 -4115.26 499.26 4145.43 0.00 0.00 0.00 MWD 7800.00 40.227 173.083 6301.68 -4179.37 507.04 4210.02 0.00 0.00 0.00 MWD 7900.00 40.227 173.083 6378.03 -4243.48 514.81 4274.60 0.00 0.00 0.00 MWD 8000.00 40.227 173.083 6454.38 -4307.60 522.59 4339.18 0.00 0.00 0.00 MWD 8100.00 40.227 173.083 6530.73 -4371.71 530.37 4403.76 0.00 0.00 0.00 MWD 8189.42 40.227 173.083 6599.00 -4429.04 537.33 4461.51 0.00 0.00 0.00 J4 Sand 8200.00 40.227 173.083 6607.08 -4435.82 538.15 4468.34 0.00 0.00 0.00 MWD 8300.00 40.227 173.083 6683.43 -4499.93 545.93 4532.93 0.00 0.00 0.00 MWD 8389.42 40.227 173.083 6751.70 -4557.26 552.88 4590.68 0.00 0.00 0.00 Planned TD (1732'FSL & 55 8400.00 40.227 173.083 6759.78 -4564.04 553.70 4597.51 0.00 0.00 0.00 MWD 8500.00 40.227 173.083 6836.12 -4628.15 561.48 4662.09 0.00 0.00 0.00 MWD 8600.00 40.227 173.083 6912.47 -4692.27 569.26 4726.67 0.00 0.00 0.00 MWD , 8689.42 40.227 173.083 6980.75 / -4749.60 576.22 4784.42 0.00 0.00 0.00 61/8" Open Hole Targets Placer 1 Kuparuk C 6174.00 -4072.16 494.03 5972351.996451757.968 70 20 6.976 N 150 23 28.969 W -Polygon 1 6174.00 -4164.24 170.58 5972262.022451433.961 70 20 6.070 N 150 23 38.415 W -Polygon 2 6174.00 -3740.10 808.93 5972681.972452074.994 70 20 10.241 N 150 23 19.772 W -Polygon 3 6174.00 -4020.93 1150.78 5972398.945 452414.972 70 20 7.479 N 150 23 9.790 W -Polygon 4 6174.00 -4515.00 681.89 5971907.982451942.934 70 20 2.620 N 150 23 23.484 W -Plan hit target ORIGiNAL lalliburton Sperry-Sun e Planning Report ............ 'Y-SU"'I þ!'tILL//II(I f:jÈlAV~C::.UI ,"II ItU.l~.l'fI'~H."" {~:o..""" Casing Points 2561.33 2302.00 9.625 12.250 9 5/8" Csg PI @ 2561' MD 7554.18 6114.00 7.000 8.500 7" Csg PI 7554'MD 8689.42 6980.75 6.125 6.125 61/8" Open Hole Formations 1434.55 1414.00 Base Permafrost 0.000 0.000 1677.95 1624.00 Top West Sak 0.000 0.000 2269.25 2079.00 Base West Sak 0.000 0.000 2692.31 2402.00 C-80 0.000 0.000 3284.32 2854.00 C40 K-5 0.000 0.000 4823.31 4029.00 K-3 0.000 0.000 6558.75 5354.00 Moraine (K-2) 0.000 0.000 6689.73 5454.00 C30 (Base Moraine) 0.000 0.000 7150.77 5806.00 Top HRZ 0.000 0.000 7377.36 5979.00 C20 (Mid-upper HRZ) 0.000 0.000 7442.85 6029.00 Base HRZ 0.000 0.000 7527.99 6094.00 K-1 0.000 0.000 7632.77 6174.00 Kuparuk C 0.000 0.000 7658.96 6194.00 Miluveach (LCU) 0.000 0.000 8189.42 6599.00 J4 Sand 0.000 0.000 Annotation 30.00 30.00 SL (1 009'FSL & 19'FWL, Sec33- T12N-R7E 7632.77 6174.00 Tgt Kup-C (2217'FSL & 502'FWL, Sec4-T11N-R7E 8189.42 6599.00 J4 Sand (1860'FSL & 544'FWL, Sec4-T11N-R7E) 8389.42 6751.70 Planned TD (1732'FSL & 559'FWL, Sec4-T11N-R7E) 8689.42 6980.75 Permitted TD (1539'FSL & 582'FWL, Sec4-T11N-R7E) ORIGINAL 2003 Geodetic System; US StaÍ\>PI.ne Coordinate SysÍ\>m 1927 !';llìpsoid; NAD27 (Clarke 1866) . Zone: A1aska~ Zone 4 Magnetic Model; BGGM2002 Syste.m Datum: lVlean Sea Level ~ Local North: True North SITE DETAILS Pla""r Site Centre Northing; 5976440.000 Easting: 451349.000 Water Depth: 0.00 Positional Uncertainty: 0.00 COllvergenc~: NO.372 WELL DETAILS Name +Nf-S +Ef-W Northing Easting Latitude Longitude Slot Pla('.er 1 -B.50 -58.46 5976426.881 451290.459 Y 70'20'47.025N 150"23'43.396W NfA J 0- I ~ o Q ~ ~ ~. 600 Vertical Section at 173.08" {ZOOOftlin] SECTION DETAILS See MD Iue Azi TVD +Nf-S +Ef·W DLeg TFace VSec Target 30.00 0.000 0.000 30.00 0.00 0.00 O.W 0.000 0.00 800.00 0.000 0.000 800.00 0.00 0.00 0.00 0.000 0.00 1805.68 40.227 173'(}83 1725.07 -336.31 40.80 4.00 173.083 338.77 7632.77 40.227 173.083 6J74.00 ·4072.16 494.03 0.00 0.000 4102.01 PJac.er 1 Kuparuk C 8189.42 40.227 173.083 6599.00 ·4429.04 537.33 (1.00 0.000 4461.51 8389.42 40.227 173.083 6751.70 -4557.26 552.88 0.00 O.(JOO 4590.68 8689.42 40.227 I 73'()83 6980.75 ·4749.60 576.22 0.00 0.000 4784.42 7" *'111iiI! II I SITE DETAILS FlELI) DETAILS [>facer 'Exploration 2003 Geüdetíc System: US State Plane Coordinate f.'ystem 1927 Ellipsoid: NAD27 [Clarke 1866) , l...one~ Alaska.l..oue 4 Magnetic Model: ßGGM2002 System Datum: Mean Sea I,evel Local North: True North illips Site Centre Northing: 5976440.000 IèasÜng: 451349.000 Water Depth: 0.00 Positional Uncertainty: 0.00 Cùnvergence: -0.372 WELL mtfAILS Name +N/,S +Ei-W Northing Eastlng Latitude Longitude Slot " :¡¡ ~ + " ~ W6!(-)JI£¡¡st(+) [1000WinJ SECTION nETAILS See MD Ine A2i TV!) +N/-S +Ei,W DLeg TFace VSec Tal'g'H ¡ 30.00 0.000 0.000 30.00 0.00 0.00 0,00 0.000 0.00 2 800.00 0.000 0.000 800.00 0.00 OAO 0.00 0.000 0.00 3 1805.68 40.227 173.083 1725.07 -336.31 40.80 4.00 173.083 338.77 4 7632.77 40.227 173.083 6174.00 ·4072.16 494.03 0.00 0.000 4102.01 !'Jacer 1 Kuparuk C 5 8189.42 411.227 173.083 6599.1111 -4429.04 537.33 0.00 0.0011 4461.51 6 8389.42 40.227 173.1183 6751.70 -4557.26 552.88 Mil 0.000 4590.68 7 8689.42 40.227 173.083 6980.75 4749.60 576.22 0.00 0.000 4784.42 e ConocoPhillips Alaska, Inc. Placer #1 Drilling Hazards Summary (Post in Rig Floor Doghouse Prior to Spud) 12-1/4" Hole / 9-5/8" Casina Interval Event Risk Level Mitigation Strategy Conductor Broach Low Monitor cellar continuously during interval. Moderate Mud gas detection, Increased mud weight, Decreased mud viscosity, Decreased circulating times, Controlled drilling rates, Low mud temperatu res. Moderate./ Diverter drills, increased mud weight. Reduced I Cautious trip speeds while drilling surface hole. Geologist on location to assist in picking surface casing shoe depth above the CBO/K10 marker. Moderate Reduced trip speeds, Mud rheology, Proper hole filling (use of trip sheets), Pumping out of hole, Flow checks. Moderate Attention to hole cleaning, Wiper trips Gas Hydrates Abnormal Pressure in Surface Formations Hole swabbing on trips Sticky Clay I Tight Hole Running Sands and Gravels Lost Circulation Low Maintain planned mud parameters, Elevated mud viscosity from spud, High density sweeps. Low Reduced pump rates, Mud rheology, Lost circulation material, Use of low density cement slurries 8-1/2" Hole / 7" Casing Interval Event Abnormal Reservoir Pressure Risk Level Mitigation Strategy High'/ Well control drills, Increased mud weight, Top set casing string. Sticky Clay I Tight Hole Moderate Hole swabbing on trips Moderate Lost circulation Moderate Differential Sticking Low Hydrogen Sulfide gas Low / 6-118" Hole / 3-112" Liner Interval Event Risk Level Abnormal Reservoir Pressure High ./ Differential Sticking Moderate Lost circulation Moderate Hydrogen Sulfide gas Low / Attention to hole cleaning, Wiper trips Reduced trip speeds, Mud rheology, Proper hole filling (use of trip sheets), Pumping out of hole, Flow checks. Reduced pump rates, reduced trip speeds, mud rheology, lost circulation material Good drilling practices, Mud lubes, Keep string moving, Avoid stopping wi BHA across sands. H2S drills, detection systems, alarms, standard well control practices, mud scavengers Mitigation Strategy Well control drills, increased mud weight, contingencies for top set casing string. Good drilling practices, Mud lubes, Keep string moving, Avoid stopping wi BHA across sands. Reduced pump rates, reduced trip speeds, mud rheology, lost circulation material H2S drills, detection systems, alarms, standard well control practices, mud scavengers ORIGINAL e ConocoPhillips Alaska, Inc. Well Proximity Risks: None. Drilling Area Risks: Shallow Hazards: Examination of the offset wells, Colville #1, Kookpuk #1, Atlas #1, reveal no subsurface hazards such as abnormal v pressure or lost circulation zones. A Seismic Analysis was performed for the Placer #1 well and Pore Pressure / Fracture Gradient Curves derived. Again, no indications of abnormal pressure or weak formations were seen particularly at shallow v depths. The mud weights planned for Placer #1 are conservatively based on those used during drilling of the Palm v offsets. Prudent and precautionary drilling/tripping techniques will be emphasized while drilling this well with specific regards to potential shallow gas hazards. Drillinq Risks: See attached Seismic Pore Pressure Analysis for more detail. See attached Drilling Hazards Summary. Annular Pumpina ODerations: Incidental fluids developed from drilling operations will be hauled to the nearest permitted Class II disposal well. (Note that cement rinseate will not be injected down the dedicated disposal well but will be recycled or held for an open annulus.) The Placer #1 surface/intermediate casing annulus will be filled with diesel after setting intermediate casing and prior to the drilling rig moving off of the well. If isolation is required per regulations over significant hydrocarbons, then sufficient cement volume will be pumped during the Intermediate/production cement jobs to cover those formations. PAl may request approval to inject or dispose of fluids in the, Placer #1,9-5/8" x 7" annulus at a later date. This request would be made after sufficient data is available to meet the requirements of AOGCC's 20 AAC 25.080. Geologv: Formation Anticipated geologic markers, depth uncertainty, fluid properties, and pore pressures are as follows: Permafrost - Base West Sak - Top West Sak - Base C-80 C-40 / K-5 K-3 K-2 / Moraine - Top C-30 / Moraine - Base HRZ - Top C-20 (Mid-Upper HRZ) HRZ - Base K-l Marker Kuparuk C-Sand Miluveach (LCU) J-4 (Jurassic UJU) Total Depth (Planned) DeDth (TVD-SS) 1360' 1570' 2025' 2348' 2800' 3975' 5300' 5400' 5752' 5925' 5975' 6040' 6120' 6140' 6545' 6657' Uncertainty Possible Fluid Ixgg +/- 250' +/- 200' +/- 200' +/- 200' +/- 200' +/- 150' +/- 200' +/- 150' +/- 150' +/- 50' +/- 50' +/- 50' +/- 50' +/- 50' +/- 50' +/- 150' Oil Oil Oil Estimated pressures use calculated gradients derived from Palm 1 MDT data. ORIGINAL Pore Pressure Estimated (Dsi) 659 817 1033 1134 1411 1783 2350 2405 2569 2584 2630 2663 3500-3700 3017 3185 3283 / " e ConocoPhillips Alaska, Inc. Procedure for Calculating Maximum Anticipated Surface Pressure: MASP is determined as the lesser of 1) surface pressure at breakdown of the formation at the casing seat with a gas gradient to the surface, or 2) formation pore pressure at the next casing point less a gas gradient to the surface as follows: 1) MASP = [(FG x 0.052) - 0.11] x D Where: MASP = Maximum Anticipated Surface Pressure FG = Fracture Gradient at the casing seat in Ib/gal 0.052 = Conversion factor from Ib/gal to psi/ft 0.11 = Gas Gradient in psi/ft (above 10,000' 1VD) D = True vertical depth to casing seat in ft from RKB -OR- 2) MASP = FPP - (0.11 x D) Where: FPP = Formation Pore Pressure at the next casing seat MASP Calculations 1. Drilling below 16" Conductor Casing MASP = [(FG x 0.052) - 0.11] x D = [(11.8 x 0.052) - 0.11] x 115' = 58 Dsi -OR- MASP = FPP - (0.11 x D) = 1065 - (0.11 x 2302') = 812 psi 2. Drilling below 9-5/8" Surface Casing MASP = [(FG x 0.052) - 0.11] x D MASP = [(13.1 x 0.052) - 0.11] x 2302' MASP = 1315 psi -OR- MASP = FPP - (0.11 x D) = 3179 - (0.11 x 6114') = 2506 psi 3. Drilling below 7" Intermediate Casing MASP = [(FG x 0.052) - 0.11] x D MASP = [(16.4 x 0.052) - 0.11] x 6114' MASP = 4541 psi -OR- MASP = FPP::" (0.11 x D) = 3160 - (0.11 x 6752') = 2417 psi .. Casing Design Performance Properties Size Weight GradE~./ connectio/ (ppf) 16" 63.0 B PEB 9-5/8" 40.0 L-80 BTC 7" 26.0 L-80 BTC Mod 3-1/2" 9.30 L-80 EUE-8rd Mod ORIGINAL Burst Collapse I Tensile Yield (psi) (psi) Conductor Casing 5,750 3,090 916 M 7,240 5,410 604 M 10,160 10,530 207 M .conOCOPhilliPS Alaska, Inc.e Production Hole (LSND) Kuparuk I J-4 Density (ppg) 11.0-11.4 ¡/ Funnel Viscosity 45 - 55 (seconds) Yield Point 25 - 35 (cP) Plastic Viscostiy 18 - 24 (lb/100 sf) Chlorides < 600 PH 9 - 9.5 API Filtrate <6 HTHP Filtrate < 10 MBT < 20 Solids (%) < 18 Note: The possibilitv exists that Placer #1 is in communication wi Kuparuk and reservoir pressure is elevated due to / iniection. Therefore. the Drillinq Fluid Properties referenced above are based on actual results from Palm (3S- ./ Pad) and not the attached Seismic Pore Pressure Analysis. Drillinq fluid System: Equipment for Nordic Rig 3 is on file with AOGCC. Drilling fluid practices will be in accordance with the regulations stated in 20 MC 25.033. Maximum Anticipated Surface Pressure and Casing Desiqn: The following information is used for calculation of the maximum anticipated surface pressures for the planned well: Casing Size Casing Setting Depth Fracture Pore Formation MASP Drilling Gradient Pressure Pore Gradient Pressure 16" 115' MD / 115' 1VD 11.80 ppg 8.90 ppg 53 psi NA 9-5/8" 2,561' MD / 2,302' 1VD 13.10 ppg 8.90 ppg 1065 psi 58 psi 7" 7,554' MD /6,114' 1VD 16.40 ppg 10.00 ppg 3179 psi rJ' 3-1/2" 8,389' MD / 6,752' 1VD 16.50 ppg 9.00 ppg 3160 psi - 24 ./ psi Permit 8,689' MD / 6,981' TVD Requested Permit Depth To Allow For Depth Control Uncertainty * FPP = 1VD x MW x .052 Note: MASP Information, outlined above, is based on the attached Seismic Pore Pressure Analysis. ORIGINAL e ConocoPhillips Alaska, Inc. DRILLING FLUID PROGRAM. PRESSURE CALCULATIONS. AND .DRILLING AREA RISKS Placer # 1 Drillina Fluid Properties: Placer #1 Property Grids Surface Hole (Extended Bentonite) Spud to Base of Permafrost Initial Value Final Value Base of Permafrost to Total Depth Initial Value Final Value Density (ppg) 10.0 10.0 10.0 10.0 v' Funnel Viscosity 150 120 - 150 120 - 150 75 - 120 (seconds) Yield Point 45 - 60 45 - 60 45 - 60 25 - 45 (cP) Plastic Viscostiy 25 - 35 20 - 35 20 - 35 20 - 30 (lb/100 sf) 10 sec Gel Strength 20 - 30 15 - 25 15 - 25 12 - 20 (lb/100 sf) 10 min Gel Strength 45 - 65 40 - 60 40 - 60 35 - 45 (lb/100 sf) PH 8.5 - 9.5 8.5 - 9.5 8.5 - 9.5 8.5 - 9.5 API Filtrate (cc) 8 - 15 <8 <8 <6 Solids (%) 5-8 5-8 5-8 6 - 10 Intermediate Hole (LSND) Initial Value Final Value Final Value Final Value Final Value Through C-40 Through Through HRZ TO Morraine 6J Density (ppg) 9.5 - 9.8 10.0 10.6 10.8 ./ Funnel Viscosity 35 - 41 38 - 45 40 - 50 40 - 50 45 - 55 (seconds) Yield Point 22 - 26 25 - 32 25 - 34 25 - 34 25 - 34 (cP) Plastic Viscostiy 10 - 15 15 - 20 18 - 22 18 - 24 18 - 24 (lb/lOO sf) Chlorides < 600 < 600 < 600 < 600 < 600 PH 9 -9.5 9 -10 9 -10 9 -10 9 -10 API Filtrate <6 4-5 4-5 4-5 4-5 HTHP Filtrate < 10 < 10 <10 < 10 < 10 MBT < 20 < 20 < 20 < 20 < 20 Solids (%) <11 < 12 < 14 < 14 < 18 ORIGfN,ÄL e e ConocJPhillips Interoffice Communication To: Andy Andreou Jerry Veldhuis ATO - 1312 ATO - 1300 From: Bill Kilsdonk PR - 2018 Date: 17 November, 2003 Subject: Pre-Drill Seismic Pore Pressure Analysis for Proposed Placer Well CONFIDENTIAL Cc: Dallam Masterson Mike Faust Jim Blankenship ATO - 1476 ATO - 1376 PR - 2022 The purpose of this memo is to report and review a seismic velocity based pore pressure estimate for the proposed Placer well. Summary Seismic velocity data were used to estimate pore pressure gradients likely to be encountered in the Placer well, which has been proposed for the 2003 drilling season. Local normal compaction trends and local velocity-to-pore pressure gradient translations were established using control from the Colville, Kookpuk, and Atlas 1 offset wells. ¡./ To estimate pore pressure gradients, local normal compaction trends and translation functions were established from the control wells and then applied to scaled seismic velocities in a 3D seismic sub-volume containing the proposed surface location, well bore path, and ~rget. The velocity data indicate no apparent shallow hazards at the proposed location. However, based on seismic velocity and offset data, moderately elevated pore pressure gradients (10.5 to V' 11.5 PPG) are expected in the HRZ shale and slightly elevated gradients are possible just ./ below permafrost. Seismic Processina: The accuracy of seismic pore pressure analysis depends critically on the accuracy of the input velocity field. The velocities used in this study were generated using ConocoPhillips' proprietary A VEL 1,2 program, an automated high-resolution velocity analysis program developed by ARCO Exploration and Production Technology. This process produces a seismic velocity field defined 1 Swan, H.W., 2001, Velocities trom amplitude variations with offset, Geophysics, v. 66, no. 6, p. 1735-1743. 2 Kan, T. K., and Swan, H. W., 2001, Geopressure prediction trom automatically-derived seismic velocities, Geophysics, v. 66, no. 6, p. 1937-1946. lJRIGINAL e e at every COP and every 4 milliseconds. A VEL seismic velocities used in this study were smoothed by averaging over 7 COPs in the inline direction and within a 250 millisecond window to minimize velocity field instabilities derived from noise, lack of signal, and variations in COP fold. In addition, based on sonic and seismic velocity data from the area, raw A VEL velocities were scaled by 90% to better match sonic profiles and ensure that pore pressure gradient variations were calculated accurately and at the correct depths. Experience with pore pressure analyses in Alaska and worldwide has shown that scaling seismic velocities to match sonic logs can correct for seismic velocity anisotropy and improve both the accuracy and the precision of pre- drill pore pressure estimates. Apparent pressure buildups can result from velocity changes due to local lithology changes. For example, the low-velocity, low-density HRZ shales show up as over-pressured zones, though they are often drilled with out problems using relatively low mud weights. Calibrations used in previous reports over-estimated pore pressure in the HRZ by several PPG. The calibration used in this report has been modified to better-fit gradients indicated by the offset mud weight data and better estimate the pore pressure gradient in the HRZ. Other potential causes of apparent pressure anomalies include errors in the velocity pick and lor inaccuracies in shallow seismic velocities due to low fold. Potential for the Presence of Gas Hvdrates and Seismic Pressure Prediction It is possible that methane hydrates in or around the base of the permafrost transition zone will exhibit acoustic properties that are not sufficiently different from permafrost to be differentiated seismically. Nevertheless, hydrates can pose a significant drilling risk if proper safeguards are not in place. Gas-charged sands and hydrates within the permafrost zone are thought to have contributed to the blowout at the Cirque #1 well (approximately 10 miles southeast of Oberon #1 and 11 miles east-southeast of Titania #1). A thin zone of over-pressured, gas-charged sands was observed at the base of permafrost in the Cirque #2 well. Previous analysis (Heinlein, 20003) shows that there is~arent!!1dica!!Q~-9f the presªD!::e o(m;¡S hydrates or free gas wi~rbE(low the ~mafrostl§l.Y~Lon either2D or 30 seismic data in the area surroundin t Cirque ells. Thin gas-charged sands sitting immediately below the permafrost (in the K-10 in erva also may not appear as a potential pore pressure anomaly on 20 or 30 seismic. Pressure Prediction Procedure: Phillip's PPFG software (developed by ARCO Exploration and Production Technology) was used to estimate pore pressure gradients. Data from three existing wells (Colville, Kookpuk, and Atlas 1) were used to establish local ,/ normal compaction trend lines and a local velocity vs. pressure translation model. The model has been updated from previous models (Wyndriski 1999; Heinlein and Kilsdonk, 2000; Buggenhagen, 2002) to include additional data and to better fit all available data. The current model differs in details from earlier models but produces similar results with improved fits to offset well data. Procedure 1.) Normal Compaction Trend Lines (NCTL) were determined for seismic sub-volumes containing the prospect and the offset wells. Seismic velocity and offset well data from the Placer area indicate very slight regional variations in the intercept, but not the slope, of the NCTL. Velocity to pore pressure gradient transforms did not vary between offset wells, so the local well based models were used for seismic pressure analyses. 3 Heinlein, K. H., 2000, Pre-drill seismic pore prediction forrr~osed well location: Cirque #3, Phillips Alaska, Inc. ORoiNAL e e 2.) In the Placer area the seismic NCTL has a logarithmic slope of -3.7e-5 and an intercept that varies slightly and gently between 155 and 165 milliseconds/foot. The seismic NCTL's of these seismic data have the same logarithmic slope as the local sonic NCTL's (-3.7e-5) but the intercepts are slightly shifted from intercepts of 160 milliseconds/foot and 150 milliseconds/foot at Kookpuk and Colville respectively 3.) The inverse ratio of interval transit times recorded by wireline sonic logs (~T) in the existing wells or by seismic velocities (ITT) at the proposed well location, to interval transit times predicted by downward extensions of the NCTLs were calculated. These values are the interval transit time ratios, ITTnITTo. 4.) A translation trend model was established by comparing interval transit time ratios (ITTn/TTo) to mud weights in offset wells. This model calculates pore pressure gradients (PPG) using the Eaton's equation4 for pore pressure. or equivalently PPG = OBG - [OBG - PPGn] (ITT nITT o}N VESNESn = (ITTnITTo}N where: PPG is the pore pressure gradient OBG is the overburden gradient PPGn is the normal (not over-pressured) pore pressure gradient ITTn is the normal (not over-pressured) interval transit time ITTo is the observed interval transit time N is the Eaton exponent. VES is the vertical effective stress VESn is the normal (not over-pressured) vertical effective stress In this case appropriate values of N were found to lie between 0.8 (best-fit) and 1.0 (high- side estimate). 5.) Fracture gradients were calculated using the Eaton method. Inputs are bulk density, the calculated pore pressure gradient profile, and a Poisson's Ratio profile (a West Cameron model was used for consistency with previous pore pressure studies). Bulk densities were computed from seismic data using the equation Rhob = A - B*ITT Using the scaled seismic velocity data, this equation fit density data collected in offset wells with A = 2.806, B = 0.0041 in the Placer area. Pressure Calibration from Offset Control Wells Data from three (3) offset wells were analyzed to calibrate parameters for pre-drill seismic based pore pressure estimates. The calibration wells, Colville, Kookpuk, and Atlas 1, are local to and share - within a close approximation - compaction trends with Placer. Colville Figure 1 shows sonic velocity based pore pressure / fracture / overburden gradient analyses of this well plotted with observed mud weights, formation tops, and drilling data. Pore pressure gradient calculations using both best-fit and high-end calibrations are shown. The left track 4 Eaton, Ben A, 1975. The equation for geopressure prediction ffom well logs, SPE 5544. n r? I I t\f ~.,,/~~,~ Eg~ - e contains the wireline sonic ~T (black curve) with the NCTL (red line). The right track contains the pore pressure gradient calculations (blue curves), actual mud weights (green curve), and the calculated fracture gradient (red curve). Casing points, areas of hole problems, and formation tops are as labeled. Mud weights, sonic data, and drilling data indicate low pore pressure gradients « 10 PPG) down to approximately 5500 feet, where an increase in ~T (decrease in velocity) indicates that pore pressure gradients rise to a local peak of 10.5 ppg. This occurs at or very near the top of the Pebble Shale unit. The sonic ~T data show a second increase (decrease in velocity) just below 7000 feet at the top of the Mid Jurassic Unconformity. This change in sonic velocity extends from the Mid Jurassic Unconformity down to the Sag River Sand. Calculated pore pressure gradients through this section are higher than observed mud weights by 0.6 to 1.0 PPG. The difference suggests that sonic velocities in this zone may slow due to a lithology change rather than an increase in pore pressure. Initial shut-in pressures from a drill-stem test in the Sag River Sand indicate pore pressure gradients near 10 PPG and support the interpretation that the velocity change may not be not due to low pore pressures, but instead may reflect a lithology change below the Mid Jurassic Unconformity. Comparing the seismic trace (extracted from a 3D seismic volume) with the sonic log at the Colville location indicate that the seismic velocity data must to be scaled in order to match the sonic data. This adjustment was necessary to produce a seismic pore pressure analyses with correct depths. Figure 2 shows overlays of the scaled seismic and sonic based pore pressure gradient analyses plotted with observed mud weights, formation tops, and drilling data. With the required adjustment the match above the Mid Jurassic Unconformity is very good. Interestingly, in contrast to the sonic data, the seismic velocities do not decrease below the mid Jurassic Unconformity. Figure 3 shows the seismic pore pressure analyses, which indicate that pore pressures are below 10 PPG except for the interval between the Pebble Shale and the Upper Jurassic Unconformity. The sonic NCTL has a logarithmic slope of -3.7e-5 and an intercept of 150 microseconds/foot. The seismic NCTL has the same logarithmic slope but is shifted by 18 microseconds/ft to an intercept of 168. Kookpuk Figure 4 shows similar (best-fit and high-end) sonic-based pore pressure gradient estimates for Kookpuk. Note that, although the slope of the sonic NCTL is the same as Colville, the intercept differs slightly. The analysis shows pore pressure gradients that exceed 10 PPG in 4 depth intervals. 1) At about 2600 feet, near the top of the sonic log slow velocities indicate pore pressures between 10.7 and 11 PPG. The well flowed at this depth with 9.1 PPG mud in the hole, indicating higher pore pressures. The flow was stopped with 11 PPG kill mud, indicationg that the pore pressure was, at least slightly, lower. 2) From about 4100 to about 4400 feet the sonic analyses indicate pore pressure gradients between 10.6 and 11 PPG. The mud weight of 11.7 PPG was sufficient to drill this section without notable trouble suggesting that the best-fit (lower estimate) is more nearly correct than the high-side estimate in this well. 3) From just above the top of the HRZ at about 5700 feet to the Upper Jurassic Unconformity the sonic analyses indicate Pore pressure gradients between 10.5 and 11.3 PPG. A local increase in mud weight to 11.2 PPG in this section suggests that the sonic analyses are accurate. ORIGINAL -- e 4) Between the Mid Jurassic unconformity and the Sag River Sand a decrease in sonic velocity would suggest pore pressure gradients between 11.3 and 12 PPG. However, this section was drilled with 10.5 PPG mud without apparent incident. As with Colville, the decrease in velocity below the Mid Jurassic Unconformity is most likely due to a lithology change rather than a pore pressure decrease. In contrast to Colville, the seismic velocity data (Figure 5) slow near the Mid Jurassic Unconformity but do not slow near the HRZ. In this well, although the sonic data reflect pore pressure nicely (with the exception of the section between the Mid Jurassic unconformity and the Sag River Sand), the seismic velocity data do not seem to be a good indicator of pore pressure gradients (Figure 6). Atlas 1 Figure 7 shows similar (best-fit and high-end) sonic-based pore pressure gradient estimates for Atlas 1. Note that, although the slope of the sonic NCTL is the same as Colville and Kookpuk, the intercept differs slightly. The analysis shows pore pressure gradients that exceed 10 PPG below 6500 feet, beginning near the top of the HRZ. At least two possibilities exist to explain why the mud weights are lower than the pore pressure gradient calculated from sonic in this interval: (1) the over pressured section is low permeability shale and although it was drilled underbalanced the low permeability prevented flow; (2) either all or part of the decrease in sonic velocity is related to a lithology change rather than an increase in pore pressure gradient. Of these, the first is more consistent with the other wells in this study, many of which have seen increased pore pressure gradients, indicated by increased mud weights, in the interval near and just below the HRZ. Figure 8 shows the seismic PPFG analyses for Atlas 1. Pore pressure gradients increase from 9 PPG at 5500 feet (shallower than indicated by the sonic log) to 10.25 to 10.5 PPG at 7300 feet. The magnitude of the seismic pore pressure gradient increase is more consistent with the mud weights than the sonic pore pressure analysis. Seismic Pore Pressure Analyses for Proposed Well Seismic velocity data for pore pressure gradient estimates were scaled by 90% in accordance with the corrections necessary in the offset control wells. Pore pressure gradients for the proposed well were calculated using the NCTL and Eaton type relationship developed from the offsets. Placer Figure 9 shows the seismic PPFG estimate for the Placer deviated well path. The vertical axis is TVD. The shallow velocity data indicate normal pore pressure gradients (9 PPG) down to ý about 1750 feet. Below 1750 feet the estimated gradient rises to a value between 9.7 and 9.8 PPG at about 2800 feet. Below 2800 feet, estimated pore pressure gradients drop and reach 9.1 PPG at approximately 3850 feet. The velocity data below 3850 feet imply a second increase in PPG to a maximum value between 9.9 and 10.2 at about 5750 feet. By analogy with Colville, Kookpuk and Atlas 1, the increase in this section probably corresponds to the top of the HRZ. Estimated pore pressure gradients drop sharply below 5850 feet to between 9.6 and 9.8 PPG and remain roughly the same to almost 7000 feet Figures 10 and 11 show comparisons of the best-fit and high PPG estimates along the deviated well path (thick black line) with the estimate from the seismic velocity trace at the top-hole location. Wile they are not identical, differences are small. The seismic velocity trace from the top-hole location indicates rising pore pressure below 7000 feet. However, changes in velocity data within that depth range may actually reflect lithology changes below the Mid Jurassic Unconformity as interpreted in the Colville and Kukpuk Of set wells. ! ~\f ~ ~ 1\~ e e Figure 12 shows comparisons of ITT data from the three nearest offset wells (Colville, Kookpuk, and Atlas 1) with the seismic ITT Trace from the Placer Top Hole location. The Placer location shows an increase in ITT (decrease in velocity and increase in implied PPG) at the expected HRZ level, similar to Colville. It also shows an increase in ITT below 7000 feet. By analogy with the Colville sonic and Kookpuk seismic, this change may be a response to lithology changes below the Mid Jurassic Unconformity rather than to increasing pore pressure gradients. Figure 13 is an arbitrary depth transect, cut from a 3D seismic ITT volume, connecting Colville with the proposed Placer location and well bore path. Although the velocity field is fairly uniform on this cross section, there are some differences worth noting. Both wells show velocity reversals between 4,000 and 6,000 feet, however the reversal is of higher magnitude and extends over a greater depth range in Colville than in Placer. On the cross section, the reversals seem to come and go along a bright reflector that may be near the top HRZ. This reversal is also present in the Colville sonic data and is coincident with slightly elevated mud weights, indicating that the reversal reflects a zone of slightly elevated pore pressures. A similar pattern is developed on an arbitrary transect between Kookpuk and Placer (Figure 14) although the seismic reversal dies out toward Kookpuk and is absent at the Kookpuk location, the Kookpuk sonic data do show a reversal in the corresponding interval. The seismic reversal at Placer is intermediate between the two offsets. It exists (in contrast to Kookpuk, where it is present in the sonic data but absent in the seismic data), but is smaller and weaker than the reversal at Colville. Because the seismic reversal in Placer is consistent with data (Colville sonic, seismic velocity, and mud weight; Kookpuk sonic and mud weight) that indicate slightly elevated pore pressure gradients, the reversal in this (near HRZ) section at Placer is interpreted to result from an increase in pore pressure gradient. Figures 15 and 16 show best-fit and high-end pore pressure gradient cross sections between Colville and Placer, while a pore pressure gradient is clearly indicated below 5000 feet in placer its magnitude and depth extent are less than in Colville. Conclusions Seismic velocity data indicate no shallow hazards at tt.Vh ~ro osed well location. ( However, velocities indicate pore pressure gradients up t 10....:.5 PG may occur in the section containing the HRZ and Pebble Shale units. .,< ORiGl tit e FIGURE CAPTIONS Figure 1. Best-fit and high-end sonic PPFG estimate of Colville. The magnitude of the best-fit and high-end overpressure estimate match the mud weight nicely everywhere except in the section between the Mid Jurassic Unconformity and the Sag River Sand. Because this section was drilled with mud weight lower than gradients calculated from sonic, and because initial shut in pressures in the Sag River sand were near 10 PPG, it is possible that the low sonic velocity and apparently higher pore pressure gradients may actually be caused by a lithology change in this interval rather than high pore pressures. Figure 2. Comparison of sonic data with scaled seismic data at the Colville location. Left Track Black: Sonic log Red: Scaled seismic ITT. In contrast to the sonic, the seismic data at this location do not slow in the interval between the Mid Jurassic Unconformity and the Sag River Sand. Middle Track Black: Best fit pore pressure gradient estimated from sonic log Green: Best fit pore pressure estimate from scaled seismic ITT. Good agreement of top over pressure with sonic. Middle Track Black: High end pore pressure gradient estimated from sonic log Red: High end pore pressure estimate from scaled seismic ITT. Figure 3. Best-fit and high-end seismic PPFG estimate of Colville. The magnitude of the best-fit and high-end overpressure estimate match the mud weight nicely (although the High side estimate slightly over-predicts gradients just above 6000 feet). Initial shut in pressures of roughly 9 and 10 PPG indicate near normal pore pressures at depth. Although the seismic seems to under-predict the ISIP at -7900 feet, some of the difference may be due to pressure added by through hydrocarbon buoyancy. Figure 4. Best-fit and high-end sonic PPFG estimate of Kookpuk. The magnitude of the best-fit overpressure estimate matches the mud weight nicely everywhere except in the section between the Mid Jurassic Unconformity and the Sag River Sand. Because this section was drilled with mud weight lower than gradients calculated from sonic, it is possible that the low sonic velocity and apparently higher pore pressure gradients may actually be caused by a lithology change in this interval rather than high pore pressures. Figure 5. Best-fit and high-end seismic PPFG estimate for Kookpuk. The seismic estimates are, for the most part, poor matches to the mud weights. The increase in pore pressure indicated by an increase in mud weights near the HRZ is undetected by the seismic velocity at this location. In addition, a suspect increase in pore pressure gradients indicated by low seismic velocity near the Mid Jurassic Unconformity is not supported by mud weight or drilling data. Contrast this with the seismic estimate for Colville (Figure 19) which indicates increased gradients near the HRZ but not near the Mid Jurassic Unconformity. Figure 6. Comparison of seismic data with sonic data at Kookpuk. In contrast with the sonic log, the seismic data do not detect the velocity low in the HRZ. However, in ORIGÎ e e contrast to the seismic data at Colville, the Kookpuk seismic data do detect low velocities near the Mid Jurassic Unconformity. Left track Black: Sonic log Red: Scaled seismic ITT from trace at Kookpuk location Middle track Black: Best-fit (based on all other offset wells) pore pressure estimate from sonic log Green: Best-fit pore pressure estimate from seismic ITT data. Riqht track Black: High-end (based on all other offset wells) pore pressure estimate from sonic log Red: High-end pore pressure estimate from seismic ITT data Figure 7. Best-fit and high-end sonic PPFG estimate for Atlas 1. The estimates indicate normal, or near normal pore pressure gradients down to about 6400 feet (near the top of the HRZ) in close agreement with the mud weights. At the top of the HRZ the sonic velocities indicate an increase in pore pressure gradient that reaches between 10.6 and 11 PPG by the base of the HRZ, and may slightly exceed 11 PPG just below the base of the HRZ. The depth of this increase is supported by an increase in mud weights at the same depth, however the magnitude of the mud weight increase is much les than the estimated pore pressure increase. At least two explanations are possible. (1) The section was drilled under-balanced but did not flow due to very low permeability; (2) the sonic velocity over-predicts the pore pressure increase due to a lithology effect, and the increase in pore pressure is either absent or much less than indicated by the log. Figure 8. Best-fit and high-end seismic PPFG estimate of Atlas 1. The seismic data indicate normal pore pressure gradients (9 PPG) down to about 5500 feet. The seismically estimated pore pressure gradient increase below 5500 feet occurs at a shallower depth than indicated by either the sonic data (Figure 23) or the mud weight. However, the value of the best fit gradient is nearly identical to the mud weight from below the LCU to the bottom of the hole. Figure 9. Best-fit and high-end seismic PPFG estimate for the Placer deviated well path. Gradient values were manually extracted from 3D seismic pore pressure gradient volumes along the projected well path. Estimated gradients are normal (9 PPG) to about 2800 feet (TVD) where the begin to rise to a local peak of between 9.7 PPG (using the best fit regional calibration) and 9.8 PPG (using the high end regional calibration) at about 2800 feet. Estimated gradients decrease below 2800 feet and are nearly normal « 9.5 PPG) between 3700 feet and 4500 feet. Below 4500 feet gradients increase to a peak between 9.9 and 10.2 PPG at about 5700 feet. Below 5700 feet gradients fault to between 9.6 and 9.7 PPG and remain in that range to the bottom of the planned well path just above 7000 feet. Figure 10. Best-fit seismic PPFG estimate for the placer top hole (spud) location (blue) overlain by the estimated pore pressure from the deviated well path (black). The curves are quite similar but not identical. Figure 11. High-end seismic PPFG estimate for the placer top hole (spud) location (blue) overlain by the estimated pore pressure from the deviated well path (black). The curves are quite similar but not identical. ORIGI e e Figure 12. Comparison of scaled seismic and sonic data from Placer offsets with Seismic ITT trace below the Placer spud location. Seismic ITT data at Placer seem to increase (velocity decreases) at about 5800 feet, roughly equivalent to the depth of the Pebble Shale I HRZ in the offsets, indicating an increase in pressure gradient through this section. The data also shoe allocal ITT high (velocity low) at a depth equivalent to the Mid Jurassic unconformity in the offsets. Offset data indicate that overpressures indicated by velocity data in the section just below the Mid Jurassic Unconformity should be viewed with suspicion, since the section was drilled (in Colville and Kookpuk) with low mud weights and, apparently, without trouble. Left Track (track 1) - Colville sonic and seismic ITT Black: Sonic log Red: Scaled seismic ITT (shifted to match the sonic intercept in the overlay). In contrast to the sonic, the seismic data at this location do not slow in the interval between the Mid Jurassic Unconformity and the Sag River Sand. However, both curves slow in an upper zone near the Pebble Shale Unit. Track 2 - Scaled seismic ITT trace below the Placer Spud LocationTrack 3 - Kookpuk sonic and seismic ITT data Black: Sonic log Red: Scaled seismic ITT (shifted to match the sonic intercept in the overlay). Track 4 - Atlas 1 sonic and seismic ITT data Black: Sonic log Red: Scaled seismic ITT (shifted to match the sonic intercept in the overlay). Figure 13. Seismic cross section showing variation in seismic ITT between the Placer deviated well path and the Colville location. Gradient contours, for the most part follow reflectors, although local variations exist both in the Placer are and in the Colville area. Figure 14. Seismic cross section showing variation in seismic ITT between the Placer deviated well path and Kookpuk. Figure 15. Seismic cross section showing variation in seismically estimated pore pressure gradient (best-fit regional calibration) between the Placer deviated well path and the Colville location. Figure 16. Seismic cross section showing variation in seismically estimated pore pressure gradient (high-end regional calibration) between the Placer deviated well path and the Colville location. ORIGI~jA 11/1320/03 B. Kílsdonk Project: NPRA_03 Well: Colville NCTL: 150, -3.7e-5 Modifîed Eaton Method: e = 0.8, 1.0 Cono ¡lIips DEPTH (D8!um settD MSL) 17 C.'ti!le FEET 17 1000 2000 3000 3000 4000 4000 5000 5000 6000 6000 7000 8000 8000 9000 9000 60 80 100 120 140 160 180 8 = 14S.S5t " -U5me-8S '* Kick I Flow X Drill stem Test I!I leak-off Tem - Formation Top .... Sidetrack location 10 11 12 13 14 Iniga! 15 16 17 18 19 10000 20 LogariUlmic .. Casing Depltl + Repeat Formation Test li Produooon Pressure tB1 Lost Circulation Zone; ... stuck Pipe Location Z Freeform High and Best-Fit Calibrations igure 1 ./ ConocoPhillips Colville 1000 Red Line: Seismic ITT Black: Sonic Green: Seismic PPG (best-fit) Black: Sonic PPG (best-fit) Red: Seismic PPG (high side) Black: Sonic PPG (high-side) tlEPTH (D8ÍUrn $etto MSL) MSL 2000 . - \ .c ¡ .. .c \. '""""Cl~ . · - . ~ '\ '\" ~ . ~ , ..... ) . : ~ - Æ- . · . -~ . ~ '. . :~f?k .. , "c . _c_ C . C . >. ..,. ... , ., ,.~/ .. c' - ¡ , ~ . ..~:! ~::;". - , ~ ,~, " .. .. - .. .. -~! ,.,~.~..- ;.,--" . . - '-" . . ~ J ..--- "'-- "" 1~ .. c..·. w- ..: ¡¡;;t< . -1-" _. . c I, , -":,. . . , . . . - ~l "'"7 . <: . . -" -~ . . 1 ] · ;- . . . . - - 'i .c . . . .. ,~ - ~'''< ... . - .cc· , . ,. ., .. - ... .. ...... ..... . ' .. .. -' .' . . . . , 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 13000 13975 10,0 10,5 11,0 10.5 11.0 9.0 9.5 9.0 9.5 10,0 30 100 120 60 11.5 Figure 2 Conoc;Phillips 11/1320/03 Project: NPRA_03 Well: Colville NCTL: 167, -3.7e-5 Modified Eaton Method: e = 0.8, 1.0 B. Kìlsdonk DEPYH ([I¡¡jum ,etiD MSL) MSL Ce¡fil!e 1000 ---- ---- FEET _ _ _ _ . M, n 1000 2000 2000 ,¡ooo 4000 5000 5000 6000 6000 7000 7000 80W} 8000 9000 ··9000 10000 40 60 80 100 120 140 160 180 8 NCT!. Intercept at GL ::: 157 J34 LogarÏÖlmic Slope'" -3.ì'e-8§ .... Cuing Depth ... Kick t flow + Repeat formation Teat }{ Drill stem Tellt Å Production Preeeure e¡ Leak-off Teat tEl Lost Circulation Zonee - formation Top ... stuck Pipe Location .... Sidetrack Location :z freeform 9 10 11 12 1:} 14 15 IlIlgal 16 17 18 19 10000 20 High and Best-Fit Calibrations Figure 3 8. Kilsdonk Project: NPRA_03 Well: Kookpuk NCTL: 160, -3.7e-5 Modified Eaton Method: e = 0.8, 1.0 Conoc;Phillips 11/1320/03 DEPTH (D8ium setlo MSL) 18 Kutp.t FEET 1000 18 2000 :3000 4000 5000 [;000 7000 8000 9000 10000 10200 40 60 80 100 120 140 160 200 8 MCn. Intercept at Gl " 15S!S7 Logaritllmic Slope" -3.SSme-iS ... CMing Dep1ll * Hick I Flow + Repeat Formation Teat x Drill stem Teat li ProllucUon Preaeure I!.I Leak-off Tellt t8! loat Circulation Zonee - Formation Top ... Stuck Pipe Location ..... Sidetrack Location Z Freeform 9 10 11 12 10 14 15 ¡big!\! 16 17 18 19 20 High and Best-Fit Calibrations Figure 4 8. Kilsdonk Project: NPRA_03 Well: Kookpuk NCTL: 160, -3.7e-5 Modified Eaton Method: e = 0.8, 1.0 Conoc;PhiUips 11/1320/03 DEPTH (08jUffi ¡ettD M$L) M$L b.tplk FEET M$L 1000 1000 2000 2000 3000 3000 4000 4000 5000 5000 fJOOO fJOOO 7000 7000 3000 3000 BOOO BOOO 10000 10200 40 fJO logarilhmic ... Cuing Depth ... Repem formation Test t:. Prcdllc1îon Prellllllre ß1 lost Circlltation Zones ... SWclI: Pipe I.ocation X freefcrm 30 100 120 140 1fJO 130 3 in " -3.maie-aS * Kick 1 flow )( Drill Stem Teat e¡ leak-off Teat - formation Top ... Sidel:rulc l.oca1îon 9 10 11 12 13 14 Iblgal 15 1<; 17 18 19 20 High and Best-Fit Calibrations Figure 5 ~/ ConocoPhillips Red Line: Seismic ITT Black: Sonic ITT DEPTH (OeDJm settD M$L) M$L \ . .~ . . \ " 1000 " \ 2000 -- . 3000 - 4000 :: . . 5000 ,,000 ,.,.,.-:. i ..', 7000 - "'~. ,. "" BOOO 9000 Kookpuk~ t~,~··· >, . ...... 10000 11000 ," ,,' 12000 - ..,. 13000 ~~... 13975 Green: Seismic PPG (best-fit) Black: Sonic PPG (best-fit) Red: Seismic PPG (high side) Black: Sonic PPG (high-side) . ~, ~ , k ..... .. -1= - '.. '.' ~ ~ .,. ., " i· ""- ,..", """ ~\:<.. ~ - . ~~ ... ~.~ {~_ J l___ '~~ -. . .\~~~~~ '- '" <~ '~~,~ ~. , .. ;-/) .. . .:',~~'.,.' ¡ // ... - :~::::~=:::::~, ..... . ~ .~~. ". ~r '~""~~,,,:,;_< """'" """ '~" "" ,'1,1, . ',,- "''', '\ .....- ., - " -.., .-' , . l -~ / ..,'~ -- { " -~~ " . . ; - 13 9 10 GO BO 100 120 140 1GO 1BO 200 t¡ 10 11 1c' ~ d. , r- . " ."" .. I , . '., : 11 12 ".., Figure 6 B. Kilsdonk Project: NPRA_03 Well: Atlas 1 NCTL: 150, -3.7e-5 Modified Eaton Method: e = 0.8, 1.0 ConocJ¡)hiUips 11/1320/03 IIEPTH (Daium zetro RKB, 107ft WOl'e MSl) 31 AtI:u_1 FEET 7000 31 1000 1000 2000 2000 3000 3000 4000 4000 5000 5000 6000 6000 7000 7407 40 60 30 100 120 140 160 130 8 158.881 :: -U181$e-85 * Kick t flow :x Drill stem T ellt 1:1 Le:ilk-off Tellt - Formation Top '" Side1rack Location 10 11 12 13 15 it; 17 13 19 7407 20 Logarithmic 10.. Casing DepUI + Repeat formation Tellt A Production Pressure ø LOllt Circulation Zonell ... stuck Pipe Location Z frelltorm High and Best-Fit Calibrations Figure 7 B. Kilsdonk Project: NPRA_03 Well: Atlas 1 NCTL: 155, -3.7e-5 Modified Eaton Method: e = 0.8, 1.0 "Þ'/ ConocoPhillips 11/1320/03 1000 Atlas _1 DEPTH (Datum zettD RtŒ ,1 07 It aDove MSL) O__~_ ...--... -......- 2000 2000 :)000 3000 4000 4000 5000 5000 5000 7000 7000 Ii.. + Teat li Production Pressure o Lost Circulation Zones .... SI1¡cl! Pipe Location :z Freeform 7407 40 50 30 NCT!. Inwrcept at OL :: 155 lIIgW'iUrmic Slope" -3.Ume-S5 * Kick t flow X Drill stem Teat ~ LeaJ¡~1IfI' relit - I"ormatilm Top ..... SidlrtrMk Location 100 120 140 150 130 3 12 13 14 IlI/gal 13 19 7407 20 High and Best-Fit Calibrations Figure 8 Seismic PPG vs TVD Placer Deviated Hole 1000 2000 - 3000 c ~ 4000 5000 6000 7000 8 o 9 PPG (emw) 9.5 10 10.5 ~/ ConocoPhillips 11/13/03 B. Kilsdonk DEPTH (D<dJJrn $eíto RKB. MSL) MSL · .. .. ~ : , 1" '" . ,. 1000 .... 2000 :.. .. '.' .'....('11II--. ..,.. 11II.. .11II'.& ilt'iiiilll i 3000 · . .. . '. . ." r ¿ .... . . . 4000 5000 6000 · .. ..... ... . . . .. 7000 :. . .. . ,.. . . ,. . 8000 '.' .. .. : 60 80 100 L ::: 1¡~ Logarithmic ::: -3.1e-85 9 10 11 Project: NPRA_03 Well: PlaceUop_hole + Dev (black) NCTL: 143-3.4e-5 Modified Eaton Method: e == 0.8 \ , \ \ \ \ \ 1. :&·'1",,~· . ,'''' . l'~~\ .. l. . ~ . .... . .~ .. . : .~.. Best-fit calibration I . i : . :. . : . . ........ ì & \ ," '\ " . .. , . $ . " .\ . ... . - .. .. 13 14 15 IlÞtgal FEET MSL · 1000 · 2000 ,. .... . . . . .. .. . '. 3000 ,4000 .\ \ \ 1... \ \,. * 5000 , .. 6000 \ 8000 3000 . - . . · 1. 10000 . , ," . 1 i 1 11000 . *.. '. .. 12000 " -- 13000 . . 11-. 14000 18 19 20 Figure 10 17 Cono Project: NPRA_03 Well: PlaceUop_hole + Dev (black) NCTl: 143-3.4e-5 Modified Eaton Method: e::: 1.0 ¡lIips 11/13/03 B. Kilsdonk DEPTH (O"iurn $etiD RKB, MSL) MSL 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 13000 14000 40 60 logarithmic FEET MSL l \ .. L :.. · \: . \ . - . . .\~t -' · . ~'.". '. .".'1Ii !IIi'. . . .'. . . . ..,¡ ..... ... 11IIII11II11I'- 'I... ~ - - , 'I. - · - , \ \ . .. . - \ 'I. . t , \ . .. ~. ... ,.. :. - ,. .. \ .. - , . .- .. -. .. - , .. \ ,.,,.. .. ... :!ø. , . .. . ''{ \ \: \ ,. . :\ , ;'*.~ : . : .~ ~ ..: . 1 . .. .- ... . = .- . ' ....... - , . ... .. '. j High calibration i , " : , , -. .. . , : k. .- , 1000 2000 3000 4000 5000 6000 7000 aooo 9000 10000 12000 1:3000 80 100 l=1U ::: -3.1e-8/i 14000 19 20 120 140 160 180 8 £i 10 11 12 16 17 18 Figure 11 -1U-31E OSG ~ 1 2 Colville Black: sonic HT Red: Scaled seismic (shifted) Placer Top Hole Lac Scaled seismic HT tlEPIH (Oaium setto RIŒ. MSL) -107 - Th- :' . . -r=-S ~ . 1000 ~. . .' .. ~ n . . ~ , .' . ~" . ..... .:.:.::.. . 2000 . '.: U 3000 ~ '., ~. , , , ." .... .. . ,c ~. . ~ 4000 - . 5000 .. E;OOO · ~... . 7000 -'-- ... -. . · . '-... 8000 -- ',moo 10000 , , 1 11000 · ..... ... .. 12000 ' .. -- -- .' ... - ." .. 13000 -- ...... ... 13975 E;O . . . ... . f . : - ,- .~r . : , : . . . .. .. . - .- '""' . - .. . . ! . ," . - .. .. .. ~ , .. . ,-" - , "; : . :. .. 80 100 120 140 80 100 120 3 Kookpuk Black: sonic HT Red:Sc~edse~micITT ( shifted) :~., .- . -... .. .--.. . -..-'-'- - ~ E;O 80 100 120 140 180 4 Atlas 1 Black: sonic ITT Red: Scaled seismic ITT ( shifted) DEPTH ,-,. -107 1000 :: . ':! . , .- '. · , · - - 2000 . 3000 , 5000 E;OOO 7000 8000 9000 .. 10000 11000 . ... .. . . .. .. - 'j . -' 13000 · , . · ',' , . 80 13975 e;o 140 Figure 12 11/13/03 B. Kilsdonk Project: NPRA_03 Seismic ITT cross section Arbitrary Transect Cono ¡lIips ConocóPhillips Project: NPRA_03 Seismic ITT cross section Arbitrary Transect 11/13/03 B. Kilsdonk Co Project: NPRA_03 Seismic PPG cross section NCTl: 143-3Ae-5 Modified Eaton Method: e = 0.8 ¡nips 11/13/03 8. Kilsdonk 15 ~//' ConocoPhillips Project: NPRA_03 Seismic PPG cross section NCTL: 143-3.4e-5 Modified Eaton Method: e == 1.0 11/13/03 B. Kilsdonk ð In_line ~ e 9 e 1 4 0 2000 4000 6000 00 eooo lCiC1ùO 12000 50 DO ¡€lure 16 Placer #1 Proposed 1/15/04 SFD -:......-- Kuparuk River Oil Pool Boundary (CO 349A) N '" I e e Conoc~hillips Post Office Box 100360 Anchorage, Alaska 99510-0360 Mark Chambers Phone: (907) 265-1319 Fax: (907) 265-1336 Email: Mark.A.Chambers@conocophillips.com January 8, 2004 RECEIVED JAN I 2 2004 Alaska Oil & Gas Cons. Commission Anchorage Commissioner State of Alaska Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Application for Permit to Drill: Placer #1 (Exploratory Test) Surface Location: Target 1 Location (Kuparuk C-Sand): Bottom Hole Location (Planned): Bottom Hole Location (Permitted): 1009' FSL, 19' FWL, 2217' FSL, 502' FWL, 1732' FSL, 559' FWL, 1539' FSL, 582' FWL, See. 33, T12N, R7E, UM See. 04, TllN, R7E, UM See. 04, TllN, R7E, UM See. 04, TllN, R7E, UM Dear Commissioner: ConocoPhillips Alaska, Ine. hereby applies for a Permit to Drill an onshore exploratory well, the Placer #1, from the location referenced above approximately 9 miles North West of the Kuparuk River Unit's 2M Pad. This well will be accessed via ice road originating from 2M Pad and drilled using Nordic Rig 3. /' The Placer # 1 is designed to penetrate, evaluate and test the production potential of the objective sands. As indicated in the attachments, the drilling program will entail drilling a 6-1/8" well bore through the objective with a full logging suite for evaluation. Based upon favorable log data, ConocoPhillips plans to run a 3-1/2" production liner and test post-rig. The proposed casing program will utilize 9 5/8" surface casing, 7" intermediate casing, 3-1/2" production liner and 3-1/2" tubing. Please find attached information as required by 20 MC 25.005 (a) and (c) for your review. Pertinent information attached to this application includes the following: 1) Form 10-401 Application for Permit to Drill per 20 MC 25.005 (a). 2) Fee of $100 payable to the State of Alaska per 20 MC 25.005 (c) (1). ¡ í 1_ e e 3) A directional plat showing the surface and bottom hole locations proposed for the well per 20 MC 25.005 (c) (2). 4) Diagrams and descriptions of the BOP and diverter equipment to be used (Nordic Rig 3) as required by 20 MC 25.035 (a) (1) and (b). 5) A complete proposed casing and cementing program is attached as per 20 MC 25.030. A well bore schematic is also attached visually depicting the proposed well. 6) The drilling fluid program, in addition to the requirements set forth in 20 MC 25.033 are attached in this APD package. 7) Seismic refraction or reflection analysis as required by 20 MC 25.061(a) are attached in this APD package. 8) PHILLIPS does not anticipate the presence of H2S in the formations to be encountered in this well. However, H2S monitoring equipment will be functioning on the drilling rig as is the ,/ standard operating procedure in the Kuparuk River Unit drilling operation. Complete mudlogging operations such as type log generation and sample catching are planned. The following are ConocoPhillip's designated contacts for reporting responsibilities to the Commission: 1) Completion Report (20 MC 25.070) Sharon Allsup-Drake, Drilling Technologist 263-4612 2) Geologic Data and Logs (20 MC 25.071) Beverly Burns, Geologist 263-4978 The anticipated spud date for this well is February 15, 2004. If you have any questions or require further information, please contact Mark Chambers at (907) 265-1319 or Paul Mazzolini at (907) 263-4603 Sincerely, ¡J.'/JILL Mark Chambers Sr. Exploration Drilling Engineer cc: CONFIDENTIAL Paul Mazzolini Mark Chambers Andy Andreou Mike Morgan Placer #1 Well File ATO-1570 ATO-1566 ATO-1312 ATO-1438 Þ( . \- SHARON K. ALLSUP-DRAKE CONOCOPHILLIPS 3760 PERENOSA ANCHORAGE AK 99515 Valid Up To ·CII 2/ ~ I __ ·:-'td·· ..... .' / ." '. ') 2 '84? ,qO?q '" ···.~:::~c~:~.¿¿¿S)_ .Þz...... ..~....:;,,-.è....1 /....... 2 ?ßI/·'O, 5',7" .....~ 1015 2QiA' - tJ2:14/31 $ 1è2:? 0(: ß DATE e e ':03 . '00, 4 I..: . . TRANSM1T AL LETTER CHECKLIST CIRCLE APPROPRIATE LETTERIP ARA GRAPH S TO BE INCLUDED IN TRANSMITTAL LETTER WELL NAME t'l ûe&r- I PTD# 20 t/-- 0/ t/ CHECK WBA T APPLIES ADD-ONS (OPTIONS) MULTI LATERAL (If API Dumber last two (2) digits are between 60-69) "CLUE" Tbe permit is for a new wellbore segment of existing well ~ Permit No, API No. Production. sbould continue to be reported as a function' of the original API number. stated above. BOLE In accordance with 20 AAC 25.005(1), all records, data and logs acquired for tbe pilot bole must be clearly differentiated in botb name (name on permit plus PH) and API Dumber (50 70/80) from records, data and logs acquired for well (name on permit). Pll..OT (PH) SPACING EXCEPTION / DRY DITCH SAMPLE Rev: 07/]0/02 C\jody\templates Tbe 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 e:xception. {Company Name) assumes tbe liability of any protest to tbe spacing . exception tbat may occur. All dry ditch sample sets submitted to tbe Commission must be in no greater than 30' sample intervab from below tbe permafrost or from wbere samples are first caugbt and 10' sample intervals througb target zones. ~'~~~Field & Pool Well Name: PLACER 1 Program EXP _~ Well bore seg D PTD#: 2040140 Company CONOCOPHILLlPS ALASKA INC Initial ClasslType EXP / PEND GeoArea 890 Unit On/Off Shore On Annular Disposal D Administration 1 Permitfe~ attached. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . Yes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 .Leasenumb~r .appropriate. . . . . . . . . . . . . . . . . . . . . . . Yes. . . . . . . . . . . . . . . . . . . 3 .U!1ij;U~ well.n.ame .aod rwmbe( . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Yes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 WeJIJocatedinad.efil1edpool.... ......... ....... yes.... . Explora.tol)'we lI.withi!1the KuparukRiyer.Unit,.very.neartbebouodaryoftheKuparukßiv~rOjIPool(C0432.B) 5 WeJI .located prop~r distaoceJ(om driJliog ul1itbpul1d.ary. . . . . . . . . . . . . . . . . . . . . . Yes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 WeJI Jo.cated prop~r dLstaoceJ(om otbeJ wells. . . . . . . . . . . . . . . . . . . . Yes. . . . . . Neaf~st wells .a(e.3.miles away (KookpYk t & ColvilJ~ 1.>.. . . . . . . . . . . . . . . . . . . . . . . . . . 7 ~uffici~mt .acreaQ.e.ayailable in.dfilJioQ. unit. . . . . . . . . . . . . . . . . . Yes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Jf.deviated, isweJlboJe platJl1cluded . . . . . . . . . . . . . . . . . . . . . . Yes. . . . . . . . . . . . . . . . . . . . . . . . . . . .. ........... . . . . . . . . 90per.ator onJy- affected pa.rty. . . . . . . . . . . . . . . . . . . . . . . . . . .. .. Yes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Oper.ator ba.s.appropriate.b.ood i!1Jorce. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Yes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Permitc.ao be issu.ed witbo.ut conS~l"\{ation ord~r. . . . . . . . . . . . . . . . . Yes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Appr Date 12 Pe(mitc.ao be issu.ed witbout admil1istr.ativ.e.approvaJ . . . . . . . . . Yes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SFD 1/22/2004 13 Can permit be approved before 15-day wait Yes 14 WeJlJo.cated withil1 area and.strata .authorized by.lojectioo O(de( it (puUO# in.commeots) (For NA . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 All wells.withirUI4.mile.are.a.of (eyiew ideotlfied (Fo(servicewelJ ol1lY-L . . . . . . . . . . . . . . NA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Pre.-prOduced.iojeçtor; dyratjo.n.ofpre-p(odyctiooless.than3.mol1tbs.(For.selYicewelI only) .. NA............,¡............................. ........................... 17 ACMPFindingp{Com;isteocy.h.as bee!1issuedJor.tbis prpiect . . . . . . .. . . . . . . . Yes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. .................. Engineering Appr Date WGA 1/22/2004 Geology Appr SFD Date 1/29/2004 Geologic Commissioner: hf~ - 18 Cooductor strin.Q.Pfovided . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Yes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 ~urface.casil1g.pfotects.allkoown.USDWs........ ....... .... yes...... .NoUSOWc Properly.setand.cement~d.s.urfÇ$Q.s.atisfiesinteotoJ25.03(c)(3).SFD........... . 20 CMT.vPl.a.dequ.ate.to circul.ate.on.col1d.uctor.& su.rf.csg . .Yes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 "CMT.vpla.dequ.ate.to tie-in .long striog to surf CS-9. . . . . . . . . . . . . . . . . N.o. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 .CMT.will c;oyerall kl10wn pro.ductiye borilons. . . . . . . . . . . . . . . . Yes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 .C.asiog de.sigos adequate. for C,T, B&.permafrpsL . . . . . . . . . . . . . . . . . . . . . Yes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 Adequate.tankage.of reserve pit . . . . . . . . . . . . . . . .. ............ Yes. . . . . . . Nordic 3.. . . . . . . . . . . . . . . . . . . . .. ................... . . . . . . . . . 25 Jfa.re-drilt has.a. t004.03 fOJ abandonment beeo appfoved . . . . . . . . . NA . . . . . . . New welt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 Adequate wellb.ore. separatjon proposed. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Yes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 Jf.diverte.r f~quife.d. does it meetreguJa.tiOl1s. . . . . . . . . . . . . . . . . . . . . . . Yes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. .............................. 28 .DfilJiogf\uid.PJogfamsc.hematlc.&.~quipJisLadequate.... ..... . . . . . . . . . Yes. . . .. . . Max.MW 11.A.ppg.. .. . . . . . . . . .. . . . . . . . . .... . . . . . .. . . .... . 29 .BOPEs,.do .they m.eetreguJatiOI1 . . . . . . . . . . . . . . . . . . . . . . . Yes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 BOPE press ratiog appropriate; te.st tp(put psig in .commel1ts) . . . . . . . . . . . . . . . . . . . Yes. . . . . . . Test to 3500. psi min.. MSP .2417. psi.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31Choke.manifold compJies w/.Þ.PLRP-53. (M.ay B4L . . . . . . . . . . . . . . . . . . . . . Yes. . . . .. .............................. . . . . . . . . . . . . . . . . . . . . 32 WOJk will oC;CUr withOytoperationsbutdown. . . . . . . . . . . . . . . . . . . . . . . . . . . . . Yes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 Js. pres.eoce. oJ H2S gas. pJob.able. . . . . . . . . . . . . . . . . . . . . . . . . . . . Np. . . . . . . . . . . . . . . . . . . . . . . . 34 Mecbanical.coodjtioo of. weJls withil1 AOß verified. (For.service well onJy) ..... . . NA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . e - - - - - - - - ~ - - - - - - - - - - - - - - - - - - - - - - - - - 35 Permitc.ao be issu.edwlo.h.)'drogen sulfide measur:.es. ........... . yes..... . Natyrally.occu.rring.H2Shasootbeen.enco.uoter:.edin.tbispo rtion.oJthegeOloQ.ic.s.ectjon.... . 36 .D.ata.Pf~seotedon.potentialovefpres.sure'zol1es. .............. Yes. . .S~ismicveJo.cityanddat.ajndicate.nosbaJlowbazards..b.utpres.sure.Qradieotsupto.lOc5ppgEMWmay-occyril1 . 37 ~eismic.analysjs.of sbaJlow gaszoo~s . . . . . . . . . . . . . . . . . . . . . . . Yes. . . . . . . I-IßZ. There is.spme potel1ti.al. foreJ~vated press.ure.io the KupaJyk.d.ue to iojectioo at Palm or.western.KRU. . 38 .Seab.edconditioo SUl"\{ey 1if off-shore). .......................... ..... NA . . . . . . . This. w~lI.wjILb.e.mu.dlogge.d; ga.sand H2S de.tectoJs will be ys.ed.. . . . . . . . . . . . . . . . 39 .Co.ntactname/phoneJQrweekly progress.reRorts [e2<ploratory .ooly). ..... .. . . . . . . . . . Yes. ... .MarkChambefs" 265:-t3.19. . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . .... ...... Date: Engineering Commissioner: Date Public Commissioner Date /j?/t/f e e Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify finding information. information of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made to chronologically organize this category of information. I I I I I I I I I I I I I I I I I I I ConocoPhillips Subsurface Technology 2005 Geochemical Data Report Geochemical Analytical Results: Placer-l Well, North Slope, Alaska By Albert G. Holba Vicki Webb ConocoPhillips Subsurface Technology, Data Report November, 2005 Geochemical analytical data for core extracts, sidewall core extracts, MDT oil and MDT gas samples from the 2004 wells, Placer-l and Placer-2, are reported here. Table 1 provides sample identification and description as well as an inventory of analyses performed on the samples. Analyses of oil and rock samples were performed by Baseline Resolution Inc. (current address: 143 Vision Park Blvd., Shenandoah, TX, 77384). Placer samples are referenced - to Baseline project codes 04-223-A and 04-259-A. Data is provided in-the Vendor Data Appendices. Gas analyses were performed at Isotech Laboratories, (1308 Parkland Court, Champaign, Illinois, 6J821) under Isotech Job 4971. Gas compositions and isotopic ratios (carbon and deuterium) MDT gases are provided in the Miscellaneous Vendor Data section of the Vendor Data Appendices. Wet, bagged cuttings were analyzed by a new method, POPI pyrolysis, at Humble Geochemical Services (218 Higgins Street, Humble Texas, 77338). The intent was to predict the API gravity of oil stained cuttings. The method was calibrated to oils from the neighboring Kuparuk River Field. Kuparuk Field oils were the incorrect calibration standard. The basic pyrolysis results, however, are sound and accurate for the Placer oil type. The Humble POPI report is included in the Miscellaneous Vendor Data section of the Vendor Data Appendices. Samples were analyzed in 2004 under the technical work agreement for the Placer wells, WBT.161097.IB. ConocoPhillips Subsurface Technology Number of Pa~es I I I I I, I I I I (I I I I I I I I I I 2005 Geochemical Data Report Table of Report Contents Report text (1 page). Table of Contents. Table 1 - Sample Identification (1 page). Distribution list. Vendor Data Appendix Miscellaneous Vendor Data Baseline DGSI Sample List Soxhlet Extraction Results(1 page). MPLC, Medium Pressure Liquid Chromatography Fractionation (1 page). Carbon Isotopes Oil Fractions (1 page). Gas Analysis (1 page). POPI Pyrolysis Report (19 pages) Gas Chromatouams and numerical data for Whole Oil (WGC): Sample ID Raw Data Depth Formation File Number Placer 1 US134018 US134019 Placer 2 US134153 US134154 US134155 GI040408, G2040245, 7558.0 7556.5 Kuparuk C, MDT (3 pages); Kuparuk C, SWC-18 (3 pages); 8199.0 8211.0 8217.0 Kuparuk C, core chip (3 pages); Kuparuk C, SWC (3 pages); Kuparuk C, core chip (3 pages); G2040255, G2040253, G2040254, Gas ChromatouaphvlMass Spectrometry (GCIMS) saturate hydrocarbon chromatograms and numerical data; Placer 1 US134018 US134019 M204061O, 7558.0 M2040611, 7556.5 Kuparuk MDT Kuparuk SWC-18 Gas Chromato~raphvrrandem Mass Spectrometry (GCIMSIMS) saturate hydrocarbon mass chromatograms and numerical data; Placer 1 US134018 MS040183, 7558.0 Kuparuk MDT Gas Chromato~raphvlMass Spectrometry (GCIMS) aromatic hvdrocarbon chromatograms and numerical data. Placer 1 US134018 US134019 MI040594, M1040596, 7558.0 7556.5 Kuparuk MDT Kuparuk" SWC-18 2 (17 pages); (17 pages); (16 pages); (15 pages); (15 pages); I I~ I I I I I I I I I I I I I I I I I TABLE 1. Sample Identification c Q) 0 Q. C 0 > :I: e II) 0 :¡:¡ :¡:¡ 0 cp U ell 0 .,J ell :¡:¡ I! .... 0 0 :I: :I: ell I 0 1¡ II) :¡:¡ en .... 1< C) ë ell en 0 Q) c C) .,J en II) z Q. Q. W ell Õ U ell ::¡¡¡¡ E 0 := en c( II) II) .... .... a :¡:¡ èñ Q) Q) 0 0 Q) Q) ell en en Q. Q. 0 .!! Depth :E O..!. ~ Õ E ::¡¡¡¡ ::¡¡¡¡ ::¡¡¡¡ .s 0 >< ~ ~ c( e - - - .... II) II) Sample_ID Site Name Sample Type (ft) Formation 0 .c 0 0 0 0 0 ell ell en ::¡¡¡¡enen ;: c( C) C) C) Je .!! C) C) US134158 Placer 1 MDT Gas 7558 Kuparuk C X X US134018 Placer 1 Oil 7558 Kuparuk C X X X X X X X X US134019 Placer 1 SWC 7556.5 Kuparuk C X X X X X X US134153 Placer 2 Core Chips 8199 Kuparuk C X X US134154 Placer 2 SWC 8211 Kuparuk C X X US134155 Placer 2 Core Chips 8217 Kuparuk C X X ConocoPhillips Subsurface Technology DISTRIBUTION LIST: Albert Holba (CoP/ Sub-Surface Technology) Justine Boccanera ConocoPhillips Alaska Inc. Post drill Summary reports & partners To Justine Boccanera ConocoPhillips Records, Houston (1 copy) (1 copy) (4 copies) 2005 Geochemical Data Report I I I I I I I I I \1 I 'I I I I I ( I I I (1 archive copy). 3 [ ¡:- ~.w '11- BASELINE CGSI ANALYïlcCAL LABORATORIES I t GEOCHEMICAL ANALYSIS OF Placer 1 Samples I 1 Prepared For: ConocoPhillips ,I I 1 I Periormed By: Baseline DGSI I Project: 04-223-A April 2004 I BASELINE DGSI, U.S.A. BASELINE DGSI, Brasil 8701 New Trails Drive, The Woodlands, Texas 77381-4241, Tel: 281.681.2200, Fax: 281-681-0326 E-mail: info@baselinedqsLcom, Rua Jardim Botênico 674/413, Jardim Botânico, 22460-030 Rio de Janeiro (RJ) - Brazil Tel/Fax: + 55.21/2259.5992 E-mail: office@reslabsolintec.com.br Web: http://www.baselinedqsLcom A . ,!'I~I.~F:HH'" PLACER 1 PLACER 1 I Field í.~r~tj.! CP272563 04-223-A CP272564 04-223-A I Lab ID · -'1j1"il,1 US134018 US134019 - '-- IiJi1eptih ={=.1iìHl[.... OIL SIDEWAll CORE 7558 FT 7556.5 FT TABLE OF CONTENTS I I I I I r SOXHLET I· ' :.. ,Company: 'CONOCOPHILLlPS . . . Pröject '#: 04-259-A:·:· Client ID Lab ID ~ock Net .Extract % EOM ! . · I' ! . . I' .~ . (ppm) . uS1'~4j§~'":'- US134154 ::;::..' :.: ::_:.··_Ù.$.:t~4J5~·~~:~..·.· .. .. Cï:)2726$$:__·.h.... _, . J4.·.Oª~_{ CP272669 11.3078 . . ·CP2726.70:. .;..':J_?~€5ª,1.º::-~~ .. :. p.pºªª :: _ : ~.,~.~·:.::~~fÞJ':·:~:_.. : ~.·_::,:.~·~2.34 . 0.0013 0.01 115 . ~- 035076 .;,_..:.::.º:'º§~;:',__~..' ':.':," ''':~~6Öi ' . ........". .." "" - .,._............,... . . ... . _..~ -"~~""" -,-,,_.. ~ . . .. ~-".. _.~~ . - ~, .' .... ~ . .... ~ ..-.- . -.,. . . . ..~,. .. ~ -,-- ... 'I-~ . - _.., ....- I r { I ", ,," ri, ...., ., ... . " . - -- .-. .,. .. Y. ,"' . . .". '" ~ ~ "".~. . . .' . . '" r r I '-: . . . ,.--........ .'.. ~. .' ., , . . .. .., .~ ... _ ~'_"~""" L .. . . ... . .' .. . . . . ~ ....... - .. . . . . .'.-, ... .... -. .... . I I I .... . ~: Baseline Resolution, Inc., 143 Vision Park Blvd., Shenandoah, Texas 77384 . Phone: 281-681-2200 . Fax: 281-681-0326 . Email: info@brilabs.com MPLC cr t ID L biD Sample SAT ARO NSO ASPH % % % % len a i .' ~ I , .' ~ I , .' ~ I ., .' ~ I , .' ~ I SAT ARO NSO ASPH Ø9rrtPª!1Y: QøN~ø~e'FlIL.4IP'$ US134018 US134019 CP272563 CP272564 0.0722 0.0504 0.0269 0.0204 Basellne/DGSI - USA 870 I New Trails Drive, The Woodlands. rx 77381-4241 Telephone: 281-681-2200 Facsimile: 281-681-0326 E-moil: info@baselined~Jsi.çorn Web Sile: h!lp://www.boselinedgsLcom 0.0132 0.0120 0.0095 0.0081 0.0035 O¡{JOA'ó 37.26 40.48 Baseline DGSI - Bradl Rue Benjamin Balisla 55/ 301 Jardim BotÔnico. 22461-120 Rio de Janeiro (RJ) - Brozil Tel/Fox: .¡. 55.21 /5377893 E-mail: ssp@solinfec.Gorn.br e.~ºJø~JI~.: ...,<º,ª.~~aª~A I 18.28 23:8~ 13.16 16~Oj 4.85 8.93 I ISOTOPES I Company: CONOCOPHILLIP$ ProJ~ct#: 04-223-A s:1JC ;;:1JC ...1JC ,,1JC s:lJC Client ID Lab ID U u. o. 0 U . .. Î' .. . Resin Asph Whole US134018 CP272563 ..3CL8 -30.1 -30.1 -29.8 r ( ( 'I 1 1 ( ( 1 I (, Basel1ne/DGSI . USA 8701 NewTIO~s Drive. The Wc)odlands. TX 77381-42,41 Telephone: 281-681-2200 Facsimile: 281-68 J -0326 E-mail: in:lo@basatinedgsi.com Web Site: hltp:/Iwww.baselinedgsl.com Baseline DGSI . Brazil Rua Benjamin Batista 5S I 301 Jmdim Bolðnico. 22461-120 Rio de Janeiro fRJ) - 8razil Tel/Fax: + 55.21 15377893 E-moll;$spG.1i$oüntec.com.br ANALYS1S RE::¡OrtT Lab#: Sample Name/Number: Company: Date Sampled: Container: Field/Site Name: Location: Formation/Depth: Sampling Point: Date Received: Component Carbon Monoxide ------------ Hydrogen Sulfide ------------. He I iu m -------------------------- Hydrogen ----------------------. Argon --------------------------- Oxygen ------------------------- Nitrogen ------------------------ Carbon Dioxide --------------- Methane -----------------------. Ethane -------------------------- Ethyl ene -----------------------. Propane ------------------------ Iso-butane --------------------- N-butane ----------------------- Iso-pentane -------------------. N-pentane --------------------- Hexanes + --------------------- 66247 Placer #1 ConocoPhillips, Alaska 3/14/2004 500 ml stainless Placer #1 Job #: 4971 Cylinder: B 4/12/2004 5/20/2004 Date Reported: Chemical mol. % nd nd 0.0112 nd nd nd 0.53 0.29 92.97 4.23 nd 1.28 0.169 0.252 0.0622 0.0542 0.148 Delta 13C per mil Delta 15N per mil Delta D per mil -17.25 -43.97 -30.64 -1 82.7 -1 52.2 -29.78 -29.69 -30.61 -157.2 Total BTU/cu.ft. dry @ 60deg F & 14.7psia, calculated: 1076 Specific gravity, calculated: 0.604 nd = not detected. na = not analyzed. Isotopic composition of carbon is relative to VPDB. Isotopic composition of hydrogen is relative to VSMOW. Calculations for BTU and specific gravity per ASTM 03588. Chemical compositions are normalized to 100%. Mol. % is approximately equal to vol. %. Chemical anaësis based on standards accurate to within 2% (A1ISOTE H Laboratories, Inc. 1308 Parkland Ct. Champaign, IL 61821 217/398-3490 I r··· re r May 2004 HGS Reference: 04-2371 ConocoPhillips Placer #1 Well, North Slope, AK D Humble Geochemical Services Division of Humble Instruments & Services, Inc. 218 Higgins Street Humble, Texas 77338 P.O. Box 789 Humble, Texas 77347 Telephone: 281-540-6050 Fax: 281-540-2864 f: Summary Geochemistry Report: r ConocoPhillips Plàcer-l Well, North'Siope, Alaska Executive Summary I I I. I I [ I I [ W~t, bagg~d cuttings collected at 5 ft. intervals over 7~~5-7590 ft. at th~ Placer-I, Alaska, well were delivered to H;umble Geochemical on 14 March 2004 for pyrolytic analysis and assessment of res~rv<?ir and oit quality, Also delivëred ~ere a s~ple of the drilling fluid and. a sample of a ·drilling fluid ad~îtive identified as Lubt~x. The follo~ing data and cOJ?clusjQns were delivered via e-mail oJ? 15 March 2004, based Qn pyrolyti~ and gas chromatographic study of those samples: . Reservoir Qu.ality: · Based 011 the pyrolytic r~spons,e of the cuttings, the most oil-productiv~. interval is 7545-50 it., where about 60% of the hydròëàrbpn pyrolytic response is from noil. n Within the reservoir, that response drops to 40% from 7540-45 ft. and 7550-55 ft., and to about 25% from 7555..60 ft. The r€maining hydrocarbon response is due to kerogen (from shale), to tar, and tQ.drilling additive. , , Oil Quality: · The overall hydrocarbon response· is low for all these ·cuttings, which makes the oil quality asseSsment more diffièult. The pyrolytic signature from the 7545-50 ft. is atypical··to that of other oil-productive intervals S.tudied at Kupatuk. Specifically, it has a higher. proportion of light hydrocâtbon~, and lower levels of thermally distillable. (higher boiling oil). Using compositional modeling, we determine that the oil quality is ",20 API. However, the elevated light components do not appear to be consistent with this calculated API, implying a higher API may be closer to reality due to possible mixing with a lighter oil. ,~ · Extracts from two intervals, 7550-55 ft. and 7560-65 ft.., show <Hear oil signatures. The former yielded very little extract and the signatlite carries an odd over even preference from n-Cl-5-21, while. the latter sample yielded'much more extract, and carries a signature more typical of a mature öit The light hydrôcarbon portions of these oils were nót preserved, likely due to sample handling. Some mud additive contamination is evident, but it is minor. Humble Geochemžcal Servžces Page 1 of9 [ May 2004 HGS Reference: 04-2371 ConocoPhillips Placer #1 Well, North Slope, AK Introduction e / Wet, bagged cuttings collected at 5 ft. intervals over 7525-7590 ft. at the Placer-I, Alaska, well were delivered to Humble Geochemical on 14 March 2004 for pyrolytic analysis and assessment of reservoir and oil quality. Also delivered were a sample of the drilling fluid and a sample of a drilling fluid additive identified as Lubtex. The objective of this work was to quickly characterize both oil and reservoir quality based on the patented "POPI" (pyrolytic oil productivity index) technology (Jones and Tobey, 1999), and based on the newly developed CoMod (compositional modeling) technology developed at Saudi Aramco by Jones and Halpern (2003). These assessments were to be used in operational decision-making at the well site, and hence the rapid turn-around requirement. The samples were received at Humble Geochemical at 14: 15 on 14 March and an assessment of oil and reservoir quality was delivered at 19: 15 on 15 March. Our assessment was based on calibration data compiled from numerous Kuparuk and West Sak oil and core samples. The calibration work was initiated in 2003. The pyrolytic technique must be calibrated to the oil types present in the system studied, because oils that are genetically unrelated can yield different pyrolýtic profiles. It is the pyrolytic profile of the oil stained rock on which these technologies are based. These profiles are comprised of a light volatiles component (L V - the oil that is thermally desorbed from the rock at 195°C), a thermally desorbed component (TD - the oil that is thermally desorbed from the rock (¡.. between 195°C and approximately 400°C, before oil asphaltenes and/or kerogen crack), and a thermally cracked component (TC - the asphaltenes and/or kerogen that cracks at temperatures approximately> 400°C) (Jones et aI., 2003). Obstacles to these objectives were the quality of the cuttings themselves, the presence of organic additives in the mud system, the presence of shale particles intermixed with samples from reservoir zones," and an auto-sampler malfunction that delayed analyses for 6 hours overnight. Surprisingly, the PDC bit cuttings taken within the suspected reservoir zone were only lightly oil-stained compared to the core samples we calibrated to. Further, much of the pyrolytic response in these samples was found to be due to bits of overlying shale which caved/were carried with the mud system into the reservoir zone. The techniques applied are based on the pyrolytic response of the oil within the reservoir, and therefore interference from mud additives and kerogen must be mathematically "removed" via the compositional modeling process. Sample Preparation Cuttings were water-washed and sieved through a 20 mesh sieve to remove the largest pieces, which were suspected to be cavings, and the material that passed through 20 mesh was sieved again through a 60 mesh sieve to isolate even smaller particles. The <60 mesh cuttings were dried at 50°C, and then ground to a powder and pyrolyzed on the Humble Instruments Source Rock Analyzer. The samples were heated isothermally at 195°C for 3 (. Humble Geochemical Services Page 2 of9 ! I ~ I ( I May 2004 HGS Reference: 04-2371 ConocoPhillips Placer #1 Well, North Slope, AK minutes, and then to 630°C at 25°C/min., under a stream of helium. Thermally desorbed and thermally cracked hydrocarbons were monitored via flame ionizàtion detector (FID). The cuttings which did not pass through the 60 mesh sieve, but did pass through the 20 mesh sieve were treated identically as the <60 mesh samples. We observed no difference in the pyrolytic response of the> 60 mesh and < 60 mesh samples, and the conclusions drawn are based on the < 60 mesh sample data. Two cuttings, 7550-7555 ft., « 60 mesh) and 7560-7565 ft., « 20, > 60 mesh) were selected for extraction in methylene chloride and examined by gas chromatography (GC). Likewise, the Lubtex drilling fluid additive was examined by dc. Results and Discussion l I II I I The pyrolytic yields for these cuttings are presented in Table 1. Most striking is the low level of hydrocarbons encountered (LV + TD+ TC) compared to Kuparuk corè samples examined earlier (Table 2). The total yield for the Placer-1 cuttings varied from 0.66-1.41 mg HC/g rock compared to art average of approximately 12 thg HC/g rock for core samples from four Kuparuk wells. Some dilution is to be expected for Guttings, however, particularly with PDC drill cuttings. Also striking is the domination of the yields by the TC component. As is discussed below, this· is undoubtedly the result of shale contamination in the reservoir sand cuttings. The pyrolytic profiles of cuttings samples are presënted in Appendix A. All the samples yielded profiles more characteristic of a source rock, such as à shale (dòminated by a large thermally cracked [TC] éomponent), rather than àn oil-stained reservoir rock, with the possible exception of samples from 1530-35 ft., 7540.;.45 ft., 7545"-50 ft., and perhaps 7550- 55 ft. This attests to the high degree of shale contamination intermixed with the sandstone reservoir cuttings. Thus, reservoir quality and oil quality assessments made strictly on the POPI values will not be valid. Under these circumstances, we must apply the compositional modeling algorithms developed by Jónes and Halpern (2003) to "remove" the shale and drilling additive contaminants from the pyrolytic profile. Additionally, we extracted two samples to obtain a GC fingerprint of the oil to assist us in assessing oil quality. I I I ( (' rt I Appendix B presents the extract GC sígnatures for såmples at 7550-7555 ft. and 7560.:.7565 ft., as well as the GC signature of thè drilling additive Lubtex. The extract chromatograms yielded high quality oil signatures with n-alkanès extending from approximately i1-C9 through n-C31. The light ends of the extract have been removed, presumably during sàmple handling. The extracted oil does not appear to be biodegraded. While contamination from Lubtex is eŸident in the oil signatures, at least one other contaminant, eluting at approximately 44 minutes, is also present. Based on the chtomatogràþhic signatures, we would expect this oil to be among the higher quality oils encountered at Kuparuk / West Sak - API gravity in the 27-33 range. Applying the compositional modeling algorithms of Jones and Halpern (2003) to the pyrolytic data illustrated in Appendix A, the most oil-productive interval is 7545-50 ft., Humble Geochemical Services Page 3 of9 May 2004 HGS Reference: 04-2371 ConocoPhillips Placer #1 Well, NOlih Slope, AK where about 60% of the hydrocarbon pyrolytic response is from "oil (Figure 1)." Within the reservoir, that response drops to 40% from 7540-45 ft. and 7550-55 ft., and to about 25% from 7555-60 ft. The remaining hydrocarbon response is due to kerogen (from shale), to tar, and to drilling additive. e Using' the CoMod algorithms to assess the oil quality at 7545-50 ft., one notes that the pyrolytic signature from the 7545-50 ft. is atypical to that of other oil-productive intervals studied at Kuparuk (Figure 2). Specifically, it has a higher proportion of light hydrocarbons, and lower levels of thermally distillable (higher boiling oil). Using compositional modeling, we determine that the oil quality is ~20 API. However, the elevated light components do not appear to be consistent with this calculated API, implying a higher API may be closer to reality due to possible mixing with a lighter oil. Summary These Placer-l cuttings presented multiple difficulties because of the low residual oil staining within the cuttings, the high levels 'of shales mixed with the sandstone reservoir intervals, and the presence of a lighter oil, which differed from the Kuparuk and West Sak oils. We had previously calibrated our pyrolytic response based on these oils. Nevertheless, using CoMod technology, we determine that the most productive reservoir interval occurs at 7545-50 ft. Using the calibrations based on Kuparuk and West Sak oils, the oil quality was assessed at ~ 20 API. (I However, we note that the presence of an excess of light volatiles in the oil, as shown by the pyrolytic profile, suggests that either (1) a light drilling additive contaminant has been introduced, or (2) a lighter, higher API oil, to which we did not calibrate, exists in the reservOIr. MarkH. Tobey Brian Jarvie W. David Weldon Dan M. Jarvie 25 May 2004 (e Humble Geochemical Services Page 4 of9 :f,',' ~ I.. r- I ( I May 2004 HGS Reference: 04-2371 ConocoPhillips Placer #1 Well, North Slope, AK References Jones, Peter l and Mark H. Tobey (1999), The Pyrolytic Oil Productivity Index, US Patent 5,866,814 Jones, Peter J. and H.I. Halpern (2003), Compositional Modeling, Provisional Patent . application Jones, Peter l, H.I. Halpern, D.M. Jarvie, D.W. Weldon, lM. AI-Dubaisi, and S.M. AI- Qathami (2003)~ New Applications to Assess Reservoir Quàlity in Oil Reservoirs Using Pyrolytic Techniques, Presented at the AAPG Annual Convention, May 2003, Salt Lake City, UT [ I [I I I I I I I fI I '.. Humble Geochemical Services Page 5 of9 May 2004 HGS Reference: 04-2371 ConocoPhillips Placer #1 Well, North Slope, AK Table 1. Pyrolytic yields for Placer-1 cuttings. Initial Uepth f-inal Uepth LV IU 1<'; (ft. ) (ft.) (mg HC/g rock) (mg HC/g rock) (mg HC/g rock) LV+TD+TC 7525 7530 0.11 0.10 1.03 1.24 7530 7535 0.10 0.42 0.90 1.41 7535 7540 0.08 0.23 0.57 0.89 7540 7545 0.13 0.18 0.93 1.23 7545 7550 0.30 0.27 0.82 1.39 7550 7555 0.10 0.13 0.83 1.06 7555 7560 0.11 0.12 0.76 1.00 7560 7565 0.11 0.13 1.08 1.32 7565 7570 0.10 0.12 0.98 1.20 7570 7575 0.05 0.06 0.59 0.70 7575 7580 0.06 0.07 0.70 0.83 7580 7585 0.05 0.06 0.55 0.66 7585 7590 0.04 0.06 0.61 0.71 Humble Geochemical Services Page 6 of9 . (. (e I May 2004 HGS Reference: 04-2371 ConocoPhillips Placer # 1 Well, North Slope, AK Table 2. Pyrolytic yields for core samples from selected Kuparuk wells. HGS ID Client ID Well Depth (It.) 03-2126-689~ .LJsn3~Zeß ,~~;JQ '" ß293:9., 03-2126-68961.USÞªØ~l?ø 2¡¡-10"..626.5':$ . 03-2126-689E!? IlS93\í27:Q~¡:-1Ø' ... ·ß.3.02.6, . 03-2126-6696& l.JS03~271 2~~1p' 63"(J6.8. 03-?126-689~ U~@~272 2!;~tO. ~3.1~~2,. Oa-2126-68.9ºp'l:JS039:273 ~1;ë'tO .' 63Jp;J' 0}..2126-68966, .US039274,2'Ë-'Ø ..Q.ª17.7.. 03-2126;.689QT' UsQª~~75:~¡::"1 Q. 6.339.8 03-2126-689$.ß: US0:39'27ß: ~E-1º ßa54S 03-2126-68969 USO~9277 2E-1!i). 6371.2 03-2126-68.987USQª92~,5 3H-09 6869.7 oa.-212f$-äage¡8 .u.S019296 ~H-Q~. '6873.6 03-2126-689811 USP39297 3H-Q9 6a81.7.. 03-2126-68990 US·Oq.929ª. :»H-09 "(ì884;!;l OH12Q-€!8991 USO~92~9. '31'-1-09, .' Qªa$.3 , Q3-212e-,ß8992 USO~93.Ø'O .aH-O(;! SffSß.2 ,,º;}:212p.6?~93 . USO~9301 38009., 6897:2 03-2126-68994 US039302. 3H-09 6900.9 03~2126-à8995 .US039303 3H-ß9 6907.8 ,. :~~"212~Sa96 ,US0393043H-d9 6914.0 Q3-2'~2e-ð89Ø7 US039305 3H-09 6919.7 J)3-2126-~9:{~ß::US0393Q6 3H-OQ " 6921<1'; I I I I I I . I .;.Q3-2126-69019 U.S039791 3B-14 .o3~2126-690~º, .US0397923B-.14 03-2126-696211,)$039793 3B-14 Q.3:2126-690~: pS039794 3B-14 03-2126-69023:. JJS03979,~ 31;F11t 03-212S'-69Q39 'I:JS03.9.ß24 :,2.E-17 03.-2126-69040., US039'E~2¡';'2E-17.. 03-2126-e9041USQ~9826. 2.E-17 . 03-2126-69042 USQp.Q.&,27 2E1-17 I I I I I I ,. Humble Geochemical Services I 6304:4 6315.5 . 6a39.5 6486.2 J~ß17.8 .. ~9J8:Q 5!1$!1!.O 5~$'ip. . ~942~0 LV IU (rñg HÇg róck) (mg HClg róck) .·h1p 3.0 '.1:18 2.3 2.rJ7 7.5 2.07 7.0 . .2.44 9.8 ~..11 6.0 2.14 9.2 1.53 6.0 1.34 4.3 1.70 . 5.1 2.04 1.20 . . 1.14 . ,., : .1.29 1.69 " 1:~8 1.3_~ 1.78.'. 1,51 2·49 1:4ß O,~ 1.80 . .1.46 1.~ 3.19 " 3.41" 1.8 2.8 2.2 ., 2.6.. 4.6. . 4.7, 4.1 5.9 :. 3.1' 6,9' ':,. 3.7 1,6 4..8 ,4.9' 3,1 . 1t1. .. ,.13.2 . 1~$~ 1,57 .. 3.~,· 1.~8 1.8 ...2,~ ,..; .....". M: .3,6 . _., ~ . .' Page 7 of9 Il; (mg HC/g rock) 3.77 "- 2.71 7.45 5.29 8.86 6.43 . 8.82 4.83 .,. 4.63 . 5.15_p '.. ~> ". · ß.41 ". 2.23... .. : US.. .. 2.10.. ,~.27. ... · ~.06 ....' 2.61 .._.' 3.55.... . 2.61... '. .4.67 _J" .3.14 ...... · ,.1,6~ ..'. .4.!?2.. 4.77 H..... 3.12.... 7.94.. . . ; 9..56 .. . , ~. ,,';." .,~ 'v ~, ..5.24........ 4.1.4 '_,. . '. 15.14.. ,.' 7.16...... LV+TD+TC 7.96 6.15 17.Q1 14.38 21.06 14.56 20.19 . 12.30 10.25 11.92 10.~4 6.23 5.29 5.99 9.60 8.06 6.08 11:·24 , 7.82 14.00 '" 8.30 .. .3.83 '. 11,11 11,,10 7..51 28.19 2.6.19 Me.. 8.35 27.16 12.14 .. March 2004 HGS Reference: 03-2130/03-2217 Ouachita Exploration, LLC SchramrnlWorley #1 Well, Milam County, TX Figure 1. Relative percent of pyrolytic hydrocarbon response at the Placer 1 well, based on the compositional modeling work of Pete Jones. Composition of Residual Staining: %Oil %Tar %Shale 0.0 Ii) N Ii) '" i Q '" Ii) '" i Ii) '" Ii) '" I Q 00 Ii) '" 100.0- 90.0- 80.0- 70.0- 60.0 50.0- 40.0- 30.0- 20.0 10.0- Measured Depth Humble Geochemical Services Page 8 of9 -..-..- .. .. .. .. .. .. - ~ .. ~-- .. .. .. - .. .. .. - .. .. .. .. .. March 2004 HGS Reference: 03-2130/03-2217 Ouachita Exploration, LLC SchrammJWorley #1 Wen, Milam County, TX Figure 2. Oil quality at the Placer 1 well 7545-50 ft., based on the compositional modeling work of Pete J. Jones: The Magenta curve is the pyrolytic response of the sample, which is shown to have a relatively high TC peak. CoMod utilized an Oil End-Member from a core sample (Light blue curve, Kuparuk 2Z-18 well, #69013, ~ 29 API); a Tar End-Member from the asphaltene fraction of an oil sample (Red curve, Kuparuk 2G-07 wen, West Sak A~ Sand, 14.7 API, #68938), aKerogenEnd~Member (Brown curve, Palm-1A well, #75764, 9040-60 ft.), and a Mud-Additive End- Member from a Lubtex sample (Turquoise curve). The green curve is the Recalculated pyrolytic curve that represents the response expected from the modeled end-member components (in this case 74 % oil and 26 % tar) and is fit to the sample's response in Magenta; however, the fit is not very good. Finally, the Blue curve is the CoMod Corrected pyrolytic response that is obtained by taking the actual pyrolytic response and subtracting the portion due to non-migrated components (i.e., kerogen, in this sample's case, the modeled % of kerogen was 0%). The pyrolytic response shown by the blue curve is not similar to the oil End-Member utilized inCoMod and the estimated API Gravity 20.1 API. It is also observed that the actual sample (Magenta: cn:rve): has an' ex;cess· of l:ìght components that could be the result of a light drilling additive or a lighter hydrocarbon that is not consistent with the 20.1 API oil staining as assessed by CoMod. The interpretation from CoMod therefore reflects the existence of very light oil-staining with API in the lower range of productive wells in the area. These results seem to be compromised by sample quality (dilution from cavings) and may be more pessimistic for this reason. 0.01 I ~O,riginal ~Recalcu.lated ~Oil End-Mem·ber: 29 API- Tar End-Member ~Mud Additive ~Corrected -Kerogen in Shale I.. 0.015 0.013 '. 0.011 -- 0.009 ,. 0.007 ~ :;: -- 0.005 -- 0.003 , 0.001 0.009 -- 0.008 -- 0.007 -- 0.006 -- ..., "¡¡ 0.005 :;: 0.004 0.003 -- 0.002 -- 0.001 01 1 -20 30 7545-50 ft. pyrogram 80 1 ' 13'0 180 1 230 1 ' 280 330 1 ' 380 , 1 430 , 1 480 530 , 1 580 -0.001 630 Data Step Humble Geochemical Services Page 9 of9 May 2004 HGS Reference: 04-2371 Humble Geochemical Services Co no coPh illips Placer #1 Well North Slope, AK APPENDIX A: Cuttings Pyrograms Appendix A Page 1 of 5 ConocoPhillips Placer #1 Well, North Slope, AK I ~ I I I I I I (. I I I I I I I .. I .. ~.._--- .. May 2004 HGS Reference: 04-2371 4.00E+06 3.50E+06 3.00E+06 - (I) II) S 2.50E+06 Q. ~ 2.00E+06 ~ ·1.50E+06 ü: 1.00E+06 5.00E+05 O.OOE+OO o Placer-l Cuttings: 7525-7530 ft. 500 600 700 100 200 300 400 Time Interval 4.00E+06 3.50E+06 3.00E+06 - (I) II) S 2.50E+06 - Q. ~ 2.00E+06 - œ: o 1.50E+06· ü: 1.00E+06 5.00E+05 O.OOE+OO o 300 500 600 700 100 200 400 Time Interval ------ - ConocoPhillips Placer #1 Wen, North Slope, AK 4.00E+06 3.50E+06 3.00E+06 <It II) S 2.50E+06 Q. ~ 2.00E+06 œ: o 1.50E+06 ü: 1.00E+06 5.00E+05 (lOOE+OO o 100 200 300 400 500 600 700 Time Interval 4.0~HE+06· 3.50E+06 3.00E+06 - Placer-l Cuttings: 7540-7545 ft. (I). II) S 2.50E+06 - Q. . ~ . 2.00E+06 œ: o 1.50E+06- ü: 1.00E+06 5.00E+05 O.OOE+OO o 100 200 300 400 600 500 700 Time Interval Humble Geochemical Services Appendix A Page 2 of 5 May 2004 HGS Reference: 04-2371 4.00E+06 3.50E+06 3.00E+06 C) III 5 2.50E+06 0. ¡g 2.00E+06 - « o 1.50E+06- i::ï: 1.00E+06 5.00E+05 O.OOE+OO o 100 200 300 400 500 600 Time Interval 4.00E+06 3.50E+06 3.00E+06 (\) III 5 2.50E+06 0. ¡g 2.00E+06 « o 1.50E+06- i::ï: 1.00E+06 5.00E+05 O.OOE+OO o 100 200 300 400 500 600 Time Interval Humble Geochemical Services 700 700 4.00E+06 3.50E+06 3.00E+06 (\) III 5 2.50E+06 - c. ¡g 2.00E+06 - « o 1.50E+06 i::ï: 1.00E+06- 5.00E+05 O.OOE+OO o 4.00E+06 3.50E+06 - 3.00E+06 (\) III 5 2.50E+06 - c. ¡g 2.00E+06 « o 1.50E+06 i::ï: 1.00E+06 5.00E+05 O.OOE+OO o --~-, Appendix A Page 3 of 5 - ....-........ ConocoPhi11ips Placer #1 Well, North Slope, AK 100 200 300 400 500 600 700 Time Interval Placer-l Cuttings: 7560-7565 ft. 100 200 300 400 500 600 700 Time Interval .......... .. - -,......--.... May 2004 HGS Reference: 04-2371 4.00E+06 3.50E+06 3.00E+06 () If) 5 2.50E+06 Q. ~ 2.00E+06 0:: C 1.50E+06 ü: 1.00E+06 5.00E+05 - O.OOE+OO o Placer-l Cuttings: 7565-7570 ft. 200 300 400 500 600 700 100 Time Interval 4.00E+06 3.50E+06 3.00E+06 - () If) 5 2.50E+06 Q. ~ 2.00E+06 0:: C 1.50E+06 ü: 1.00E+06- 5.00E+05 O.OOE+OO o 300 600 700 100 200 400 500 Time IRterval ..-..-..- .. ConocoPhillips P1acer#1 Wen, North Slope, AK 4.00E+06 3.50E+06 3.00E+06 () If) 5 2.50E+06 Q. ~ 2.00E+06 - 0:: C 1.50E+06 ü: 1.00E+06 5.00E+05 O.OOE+OO o Placer-l Cuttings: 7570-7575 ft. 100 200 300 400 500 600 700 Time Interval 4.00E+06 3.50E+06 - 3.00E+06 - () If) 5 2.50E+06 - Q. ~ 2.00E+06 - 0:: c 1.50E+06- ü: 1.00E+06 - 5.00E+05 O.OOE+OO o 100 200 300 400 500 600 700 Time Interval Humble Geochemical Services Appendix A Page 4 of 5 May 2004 HGS Reference: 04-2371 Humble Geochemical Services ,~''- - 4.00E+06 3.50E+06 3.00E+06 () III c 2.50E+06 o c.. :ß 2.00E+06 0:: C 1.50E+06 ¡:¡: 1.00E+06 5.00E+05 O.OOE+OO o Placer-l Cuttings: 7585-7590 ft. 100 300 400 500 600 200 700 Time Interval Appendix A Page 5 015 ----- --------- ConocoPhillips Placer #1 Well, North Slope, AK I ~ I I I I I I I . I I I I I I ~ I May 2004 HGS Reference: 04-2371 Humble Geochemical Services ConocoPhillips Placer #1 Well North Slope, AK APPENDIX B: Extract GC Data Appendix B Page 1 of 5 ConocoPhillips Placer #1 Well, North Slope, AK May 2004 HGS Reference: 04-2371 ConocoPhillips Placer #1 Well, North Slope, AK Figure 1. Gas chromatogram of standard oil for the purpose of peak identification and comparison to the Placer # 1 Well extracts. FID1 A. (Q:11IDATAI04-2301ISTD0314AD) pA y C o ü f q I C N o è: '" o è: 1000 - " ~[() o~ '0 C , C 800- y C <.0 o è:.... o è: '" 0" ~~ ,;:", <.;~ ..! s: '" "'0 ü~ c! I~ o '=5 'N ~ Cf5 ~ ã: c~ ~ ü c~ y CL() Ÿ c'" . N y- c: ~ OJ cÿ C ö: CD -0 U5 600- 400- -0 .... 0 0 è: Y I 0 C ::;¡; I 0..1 ::;¡; 200 - N -¡J ~~:dl o~---_:t¡¡~t o I 10 I 20 " L() '" .... OJ '" '" y '" '" '" '" '" y y 0 0 y C C C è: è: C I I I I I I I I 30 40 50 60 70 80 90 mlr Humble Geochemical Services Appendix B Page 2 of 5 .. .. .. .. .. .. .. .. .. .. .. .. .. .. ...... .. May 2004 HGS Reference: 04-2371 .. .. .. .... .. Figure 2. Gas chromatogram of Lubtex drilling mud additive used at the Placer #1 well. FID1 A. (Q:\1\DATA\04-2301\LU8ETEXD) pA 1000- 800- 600- 400- 200- o I 10 I 20 Humble Geochemical Services ---L-~l~ I 30 I ' , , , I ' , , , I ' , , , I 40 50 60 70 Appendix B Page 3 of 5 .. .. .. ConocoPhillips Placer # 1 Well, North Slope, AK I 80 I 90 I min May 2004 HGS Reference: 04-2371 Figure 3. Gas chromatogram of Placer #1 cuttings, 7550-7555 ft., «60 mesh fines) extract. FID1 A, (Q:\1\DATA\04-2301\WE81334A.D) pA 8 f3 ê: ¿ 9 60- 50- 40- "<j" <:? c: 30 '" ~ N <:? c: 20 LO Yet:: c:~ü Ü, J.!..cCOm ~I 00 ~ , ~ è:g~fj I \ j C( c:U c t:~~ Üü , , C:C:LO f3 '<0 C:N <.( c: tÏ >. ~I¡f o è: <0 tf Ll: .- I 20 I 30 I 40 I 50 I 60 Humble Geochemical Services Appendix B Page 4 of 5 ~. ~ .. .. .. .. .. .. .. .. I 70 ConocoPhillips Placer # 1 Wen, North Slope, AK. "<j" '" <.( c: <0 i.3 è: I 80 .. .. .. I 90 I mill .. ~ - .. .. .. .. .. .. .. .. .. .. - .. I .. ~ May 2004 ConocoPhiUips HGS Reference: 04-2371 Placer #1 Well, North Slope, AK Figure 4. Gas chromatogram of Placer #1 cuttings, 7560-7565 ft., «20, >60 mesh fines) extract. FID1 A, (Q:\1\DATA\04-2301\WE81336AD pA 140- 120- 100- 80 "" vS' -r- c: c.:>""'" CL Ü ~~ 60- ' üü ü c: " :2 =coo 9 C\I Y C') Y c: ~ , - c: 40 õ: :::> 1::> ~ 0 c: § C\I C') 20- t3 C') c ü C C ~ - I I I I I I I I I 0 10 20 30 40 56 60 70 80 90 min Humble Geochemical Services Appendix B Page 5 015 .. I I ANALYTICAL LABORATORIES il..~ ..-1 ,. I .'¡"BASELINE DGSI r I I ( I I WHOLE OIL GC ANAL YSIS ( I ( I ( :1 WHOLE OIL GC Company: Country: Basin: Lease: Block: Field: Well Name: Latitude: Longitude: CONOCOPHILLlPS UNITED STATES NORTH SLOPE Client ID: Project #: Lab ID: Sample Type: Sampling Point: Formation: Geologic Age: Top Depth: Bottom Depth: PLACER 1 Whole Oil GC Trace u :2; ::c: U ;:¡: en U :2; n ~ \D U :2; ::c: ug ~ co CJ U C7\ ~ ~ ~ z ~ g ª ..... .... '"" ..... ..... .." U U ..... U :2; :2; {J \D :2; :2; ..... U r- :2; .-I U Z a ..... {J Z ..... ..... {J :2; a.. ~ ~ ï:::: ..... u C7\ :2; ..... U = :2; <"I U :2; ~ U <"I :2; <"I ..... ~ ~ :2; <"I U :2; ~ C7\ Z ~ .-I ... ~ ~ ~ S E ~ ~ ~I 0 rl ~ ~ - ~ j~ wl.j_jìJwJJ~~ H g:¡ ~ U ,.......-. ...À.. US134018 04-223-A CP272563 OIL EARLY CRETACEOUS 7558 FT FT G1040408.D .." '"" U '" :2; <"I r- U '"" Z(JCO~ ZC"oJNa ~~8~C'Jm"'Q'OLO zg§J~Q~86 ~ ~ 0 - Z:2;§i~ ~ .-I U Z ~ PristaneJPhýtane 1.9'0 !fl.. BZlifCs tf29 P1 16108 Tr1 11.89 Pristaneln C17 0.69 B. TOUnC7 1.17 P2 11.18 Tr2 10.20 Phytane/n C18 0.43 C. (n CEi+nC7)I(CH+MCH) O:6~ Pa 3.46 Tra 3.85 n C1a1n C19 1.07 I. Isoheptane Value 0.92 5N1 7.34 Tr4 3.24 n C17/nC29 4.59 F. nC7/MCH OA6 N2 8.16 Trs 7.10 CPIMarzt 1.05 U. CH/MCP 1.33 6N1 53.78 Tr7 2.01 Normal Paraffins 28_6 H. nC7/2MH 3.14 K1 1.00 Tr8 3.34 Isoprenoids 4.9 S. n C6"22DMB 29.52 K2 0.58 C1 0.09 Cycloparaffins 5.9 H. Heptane Value 17.20 5N1/6N1 0.14 C2 0.49 Branched (iso-) Paraffins 3.3 MCH/nC7 2.18 P:v'N2 0.42 C3 0.21 BTX aromatics 2.9 mpXYUnCa 1.08 Ih(24DMP/23DMP) -0.84 C4 0.08 Resolved unknowns 53.8 Cs 0.13 ¡Thompson, K.F.M.,1983.GCA:V.47, p.303. 2Mango, F.D.,1994.GCA: V.58, p.895. 3Halpcm,H.I.,1995,AAPG Bull: V.79, p.80l. 4Marzi,1993,OrgG;20,130l. I I I I I I ,I I I iI' "" ( I l I II Company: Well Name: Depth: Sampling Point: CONOCOPHILLlPS PLACER 1 7558 - FT Client ID: Project #: Lab ID: File Name: US134018 04-223-A CP272563 G1040408.D Peak Compound Ret. ppt ppt Label Name Time Area I .' ~ I (Area) (Hght) 1C4 N04 105 N05 220MB CP 230MB 2MP 3MP NOS 220MP MOP 240MP 223TMB BZ 33DMP OH 2MH 230MP 11'DMCÞ 3MH 1C3DMCP 1 T30MCP 3EP 1T20MCP N07 ISTO MCH 113TMCP EOP 124TMCP 123TMOP TOL NOB IP9 MXYL PXYL O>GYL NC9 IP10 NC10 IP11 NC11 NC12 IP13 IP14 NC13 IP15 NC14 IP16 NC15 Iso-alkane C4 NormalAlkaneC4 Iso-alkane C5 NormaIAlkäne,C5. 2,2-0imethylbutane Cycloperitane 2,3-0imethylbutane 2-Methylpentane 3-Methylpentane Normal All<ane'C6 2,2-0imethylpentane Méthylcyclqþent~r;ìø 2,4-0imethylpentane 2,2,3-Triroethylbl;itân'e Benzene 3,3-Dimèthylpantane Cyclohexane 2~Mèthylhe~ane 2,3-0im~th~lpent~ne 1, 1 "iQJrnetqYJcycl:qpeMt~né 3-Methylhexane 1-cis;;3-DÎmèthylcyôlóperitäne 1-trans-3-Dimethylcyclopentane 3-Ethylpentane 1-trans-2-Dimethylcyclopentane Normal Alkane,Ci Internal Standard Methylcyct6hèXäne' 1,1,3,- Trimethylcyclopentane Ethylcycloþèntânè 1,2,4- Trimethylcyclopentane 1,2,3- Trimethylcyc;lóperitane Toluene Normal, AlkaneC:$' Isoprenoid C9 m-Xylene p-Xylene o..:Xýlene Normal Alkane C9 Isoprenoid C 1'0 Normal Alkane 010 Isoprenoid 'C11 Normal Alkane C11 Normal Alkane 012 Isoprenoid C 13 Isoprenoid C14 Normal Alkane C13 Isoprenoid. C 15, Normal Alkane C 14 Isöþrenoid C 16 Normal Alkane C 15 3.824 3;938 4.365 4~E3qO 5.048 5:521 5.555 5.635 5.934 a.~47 7.031 7/0a5 7.226 '7.3'85 7.858 Et075 8.187 'R581 8.634 . ·,aj!7~3 8.929 9.1'66 9.282 9.347 9.397 10,C)05 10.231 1.0. aVo 11 .045 11.460 11.918 12.294 12.611 t$;30!7 17.200 '1"Et41$ 18.480 19;68'1 21.102 23.093 26.715 '28;Ø'17 31.979 3G,898 37.639 40.396 41.504 44.946 45.832 48.'489 49.910 15337 37197 28224 33165 1111 5298 2595 17661 12239 32796 689 26~82 1549 250 9471 552 34635 tt197 3587 3451 13302 7475 6944 954 12145 35213 31755 76772 4797 3927 4334 5032 41037 42281 6173 34441 11210 15594 40718 7004 42959 8772 49547 49226 13554 8730 51840 15450 53425 23957 57670 14448 33991 23758 26.614 774 3512 1743 11857 7783 20156 418 14424 813 116 4401 249 17389 5'569 1756 1605 6386 3499 3240 788 5508 16211 14393 32686 1960 1673 1794 2064 16381 15203 2274 12971 4173 5334 14560 2299 14683 2839 16040 1591:0 3501 2777 16625 4728 16293 5474 15836 1.64 3.'98 3.02 3.55 0.12 0.57 0.28 1.89 1.31 3.51 0.07 2.79 0.17 0.03 1.01 0.06 3.71 1.20 0.38 0.37 1.42 0.80 0.74 0.10 1.30 3.77 3.40 8.22 0.51 0.42 0.46 0.54 4.39 4;53 0.66 3.69 1.20 1.67 4.36 0.75 4.60 0.94 5.31 5.27 1.45 0.94 5.55 1.65 5.72 2.57 6.18 3.41 8.03 5.61 6.29 0.18 0.83 0.41 2.80 1.84 4.76 0.10 3.41 0.19 0.03 1.04 0.06 4.11 1.32 0.42 0.38 1.51 0.83 0.77 0.19 1.30 3.83 3.40 7.72 0.46 0.40 0.42 0.49 3.87 3.59 0.54 3.06 0.99 1.26 3.44 0.54 3.47 0;67 3.79 3.76 0.83 0.66 3.93 1.12 3.85 1.29 3.74 Company: Well Name: Depth: Sampling Point: CONOCOPHILLlPS PLACER 1 7558 - FT Client ID: Project #: Lab ID: File Name: US134018 04-223-A CP272563 G1040408.D Peak Compound Ret. ppt ppt Label Name Time Area I -.. I (Area) (Hght) NC16 Normal Alkane C16 53.766 49298 14597 5.28 3.45 IP18 IsøprenoidC18 55.699 24018 5040 2.57 1.19 NC17 Normal Alkane C17 57.419 47168 13778 5.05 3.26 IP19 Isopr¢noidC 19 (Pristana) 57.775 3.2364 6347 3.47 1.50 PHEN Phenanthrene 58.817 3726 793 0.40 0.19 NC18 NormalAlkaneC18 60,891 39239 11213 4.20 2.65 IP20 Isoprenoid C20 (Phytane) 61.346 17051 2861 1.83 0.68 NC19 Normal Alkane C19 E)4.195 36630 10t84 3.92 2.41 NC20 Normal Alkane C20 67.349 33440 9292 3.58 2.20 NC21 Normal Alkane C21 70..362 28470 8003 3.05 1.89 C25HBI Highly Branch Isoprenoid C25 70.613 1954 465 0.21 0.11 NC22 Normal AlkaneC22 73.245 25629 7120 2.74 1.68 NC23 Normal Alkane C23 76.009 23989 6636 2.57 1.57 NC24 Normal AlkaneC24 78;6151 20349 5672 2.18 1.34 NC25 Normal Alkane C25 81.211 18792 5075 2.01 1.20 NC26 Normal Alkane C26 83.665 16202 4104 1.74 0.97 NC27 Normal Alkane C27 86.026 13519 3561 1.45 0.84 NC28 Normal Alka'ne. 028 88.308 10365 2658 1.11 0,63 NC29 Normal Alkane C29 90.515 10286 2412 1.10 0.57 . NC30 Normal 'Alkane/GaO 92~64a 7449 1845 0,80 0.44 NC31 Normal Alkane C31 94.706 5921 1407 0.63 0.33 NC32 Normal Alkane G32 96,705 4218 962 0.45 0.23 NC33 Normal Alkane C33 98.642 5037 956 0.54 0.23 NC34 Normal Alkane C34 100:523 3005 676 0.32 0.16 NC35 Normal Alkane C35 102.364 2616 528 0.28 0.13 NC36 Normal Alkane C36 104.347 1720 313 0.18 0;07 NC37 Normal Alkane C37 106.565 1220 223 0.13 0.05 NC38 Normal Alkane G38 tOR086 1110 163 0.12 0.04 NC39 Normal Alkane C39 111 .995 901 115 0.10 0.03 NC40 Normal Alkane C40 115.389 867 91 0.09 0.02 NC41 Normal Alkane C41 119.362 694 70 0.07 0.02 ~, ,( f \ I I I I ,,. I f I WHOLE OIL GC Company: Country: Basin: lease: Block: Field: Well Name: latitude: longitude: CONOCOPHllLlPS UNITED STATES NORTH SLOPE PLACER 1 Whole Oil GC Trace Client ID: Project #: lab ID: Sample Type: Sampling Point: Formation: Geologic Age: Top Depth: Bottom Depth: .... .... u .., z .,.., .... .... u u z z '" .... N U .... Z U ::; Z U Z .... co .... U .... Z U Z '" .... u z ~ u z ~ ~ u u z Z N N U '" Z .., -! N ~ ~ u z ø.. co H .... ø.. H '" U Z ~ .., ø.. :> .... H 'I ø.. .... .. H ..... .... ::: US134019 04-223-A CP272564 SIDEWAll CORE EARLY CRETACEOUS 7556.5 FT FT .... N U .,.., Z N U Z ~ U z~ u ZCO", NN ~~g.... ~~~~.~\Q z~~g~8::;:; co - zu.., z u z ...:¡ ~ .... Z H co !:ÊÍ.... '. tz1 OQ ~ii._ \ ¡;~ f.II~IJ' l'kU ,.1wl¡j·U~~ ~l.! ~.tJlU!liU.~ ÞristanøJPh~arie Pristaneln C17 Phytaneln'C1S n C1a1n C19 n C17/nC29 CPt Marzi4 Normal Paraffins Isoprenoids Cy.cloparaffins Branched (iso-) Paraffins 'STX aromatiC$ Resolved unknowns 'P;1 P2 P3 5N1 '1\12 6N1 K1 K2 $N1/6N1 P:lN2 :ii:ï(24DMP/23DMP) '1.9â 0.70 0.42 1.15 4.96' 1.06 31.3 6.4 0;2 0.0 0;4 61.4 A."B;zjÍ'iÖ~ ,., B. TOUn C7 C. (nCis+nCj)/(CH'+MCt"l), I. Isoheptane Value F .n:C7/M(3H U. CH/MCP R. nC7/2MH S. n Cal22DMB H. Heptane Val.ue MCH/nC7 mpXYUri'Cs 1.08 O;3~; 0.58 a.at 4.81 10.96 21.20 2.68 L49 17;44- 4.47 1.33 6.41 4.77' 65.58 0.86 0.48 0.1'0, 0.28 lThompson, K.F.M.,1983.GCA:V.47, p.303. 2Mango, F.D.,1994.GCA: V.58, p.895. 3Halpem,H.I.,1995,AAPG Bull.: V.79, p.801. 4Marzi,1993,OrgG;20,1301. G2040245.D :;; .... u U Z Z ~ Tr1 Tr2 Tr3 Tr4 Trs Tr7 Trs C1 C2 C3 'C4 Cs 19;01, 17.67 2.92 1.61 4.53 1.92 3.35 0.09 0.66 0.25 Company: Well Name: Depth: Sampling Point: CONOCOPHILLlPS PLACER 1 7556.5 - FT Client 10: Project #: Lab 10: File Name: US134019 04-223-A CP272564 G2040245.0 Peak Compound Ret. ' ppt ppt' "' ~ - Name Time Area - . ~ I Î -.. H. ht IC4 Iso-alkane C4 NC4 Normal Alkane. C4 IC5 Iso-alkane C5 NCS Normal Alkane C5 220MB 2,2-Dimethylbutane CP Cydopentane 230MB 2,3-Dimethylbutane 2MP 2-Methylperitané 3MP 3-Methylpentane NG6 Normal Alkane C6 6.525 88 17 22DMP 2,2-Dimethylpentane 7.149 17 5 MCP Mßthylcyclopentane 7.208 113 49 24DMP 2,4-Dimethylpentane 223TMB 2,2,3-Trimethylbutáne BZ Benzene 33DMP 3,3-Dimethylpentahe CH Cyclohexane 8.254 543 241 2MH 2-Methylhexane 8.6.32 216 91 230MP 2,3-Dimethylpentane 8.672 119 55 11 [)MGP 1,1-:-Dimethylcyclopentane 8.761 134 47 3MH 3-Methylhexane 8.963 391 148 1 C3DMCP 1-cis":3-Dimethylcyclopentane 9.190 256 98 1T30MCP 1-trans-3-Dimethylcyclopentane 9.302 257 101 3EP 3-Ethylpentë:me 9.360 45 33 1 T2DMCP 1-trans-2-Dimethylcyclopentane 9.410 530 213 NC7 Normal Alkane C7 10.001 2368 820 ISTO Internal Standard MCH Methylcyelohexane 10.8g5 6356 2599 113TMCP 1,1.3,- Trimethylcyclopentane 10.993 531 192 ECP Ethylcyclopentane 11.408 340 120 124TMCP 1 ,2,4- Trimethylcyclopentane 11 .842 543 214 123TMCP 1,2,3- Trimethylcyclopentane 12.206 739 287 TOL Toluene 12.597 2547 446 NC8 Normal Alkane C8 15.154 12703 4182 IP9 Isoprenoid C9 17.011 3207 1153 MXYL m-Xylene 18~247 14928 5246 PXYL p-Xylene 18.321 3983 1692 OXYL o-Xylène 19;502 9641 2659 NC9 Normal Alkane C9 20.881 34388 12461 IP10 Isoprenoid C1'O 22.855 7493 2413 NC10 Normal Alkane C10 26.469 64607 22067 IP11 Isoprenoid C 11 27.759 14305 4531 NC11 Normal Alkane C11 31.719 100526 31453 NC12 Normal Alkane C12 36.630 118653 37128 IP13 Isoprenoid C13 37.355 31138 9140 IP14 Isoprenoid C14 40.102 22736 7375 NC13 Normal Alkane C 13 41.228 135917 41103 IP15 Isoprenoid C15 44.642 29631 9276 NC14 Normal Alkane C14 45.548 144253 42527 IP16 Isoprenoid C16 48.182 60103 14669 NC15 Normal Alkane C 15 49.616 142936 40029 I I I I I I I Company: Well Name: Depth: Sampling Point: CONOCOPHILLlPS PLACER 1 7556.5 - FT Client ID: Project #: Lab ID: File Name: US134019 04-223-A CP272564 G2040245.D Peak Compound Ret. ppt ppt Label Name Time Area I ... I (Area) (Hght) NC16 IP18 NC17 IP19 PH EN NG18 IP20 NC19 NC20 NC21 C25HBI NC22 NC23 NG24 NC25 NC26 NC27 NC28 NC29 NCaO NC31 NC32 NC33 NC34 NC35 NC36 NC37 NC3S NC39 NG4Q NC41 I ,. I ( I.. l. I I I I I Normal Alkane C16 Isoprenoid 018 Normal Alkane C17 IsoprenoidCt9(Pnstane) Phenanthrene Normal' Alkane'C18 Isoprenoid C20 (Phytane) Normal AlkÇine C19 Normal Alkane C20 Normal AlkånØC21 Highly Branch Isoprenoid C25 Normal AlkaneC2;2 Normal Alkane C23 Norrtlál·Alkané'C24 Normal Alkane C25 Normal AlkaneC26 Normal Alkane C27 Normal Alkane C28 Normal Alkane C29 Normal AlkaneC30 Normal Alkane C31 NönncllÄlkane:Q32 Normal Alkane C33 Normal Alkane'C3.4 Normal Alkane C35 Normal Alkane C3S Normal Alkane C37 Normal Alkane Ca8 Normal Alkane C39 :No'rrnal,Þilkår:1Ø,¢~Ø Normal Alkane C41 53.462 55.373 57.104 57.459 58.632 6C).$66 61.007 a~;a60 67.000 . 7(tOe5 70.246 72i882 75.636 Ÿ8~~$a 80.827 '8'3;273 85.634 a7.910 90.114 92.240 94.297 9a.2$4 98.232 100.1'09 101.936 103;,842 105.981 1'Öa.39·1 111 .185 ,1'14¡'$St 118.113 128936 62046 119166 83343 9247 101169 41994 ·87872 85365 '68178 3404 61413 55292 47740 43918 37458 31304 23661 24014 17972 13650 9665 11473 7081 6595 4088 3279 3102 2502 :2056 1520 37182 13345 34351 15821 2219 28766 7458 25361 22857 19608 886 17560 15483 13411 12145 103'89 8574 6351 5981 4445 3598 2457 2356 1598 1447 833 588 492 311 260 171 M ~;:;~"'r- ..,.~~:::;"'''' . ~ 0 ,,0_ _,__000- - 0 zuu",,,,OMMMUZZZU U..,. I zzuu8uuuZ Z Z ~ 1 I Z Z :z: :z: :z: :Z:uJ" ... . . I .1 ., y-. ~ Trj . . 195~24 Tr2 4.17 Tr3 1.74 Tr4 0.99 T~~. .' . -" '" . 2};3 Tr7 1.62 Trs 0.15 C1 C2 0.05 C3 C" 0.93 Cs 0.02 G2040255.D WHOLE OIL GC . lThompson, K.F.M.,1983.GCA:V.47, p.303. 2Mango, F.D.,1994.GCA: V.58, p.895. 3Halpern,H.I.,1995,AAPG BulL V.79, p.80I. 4Marzi,1993,OrgG;20,130I. .p'rístan~Phytë:m~ . ..' 1.14 A. BZlrCa P,I~. . 1.61 ,.'.. Pristaneln C17 1.49 B. TOUn C7 46.80 P2 1.06 Phytane/n CIS 0.81 C. ~n C6+~ C7~/(ÇH+MCH} 0.13 P3 6.95 n C1a1n C19 1.05 I. Isoheptane Value 0.47 5N1 1.64 n.CI7InC~9' ... 1.34 F. . n C7/fv1C;H . 0.14 N~. ' .1.65 CPI Marzi4 1.03 U. CH/MCP 3.20 6N1 87.09 N~~'~ì Paraffins 7.7 R. n C7/2MH . . 4.20 K1 1.09 Is~prenoids 1.6 S. n CJ22DMB Ki 0.39 Cycloparaffins 0.7 H_ Heptane Value 7.10 5N1/6N1 0.02 Branch~~(~so-)P~r.affins. .. 0.2 MCH/nC7 7.27 P3/N~. 4.21 .. . . STX aroma~ics 4.0 mp~Yl!nCa . 28.32 l.n(24I?MP/23DM~) Resolved unknowns 85.0 ang02 ~ aJ';~ ~ e~ CD"'~::: :::::: ::: u c.. U 0.. UØ,.¡ U u...:.D. :z: H H . _ ': r ~ ÞO :a ¡:; '" o E-o Whole Oil GC Trace Kuparuk C Eciriy çretaceou~ 8199 FT FT Client ID: Project #: . Läi) I[): Sample Type: Sampling Point: Formation: G~olo9ic: Age: Top Depth: Bottom Depth: Comp~ny: Country: BCisin: Lease: Block: . Field: V\I~II Name: Latitude: Longitude: PLACER 2 US134153 04-259-A CP21~66à CORe'CHIPS .. CONOCQPHILLlPS UNITED STATES N()RTH SI..Öf'~·. - . ':" .' :":~-~~"~1 6.'906: : .: ::, :-~:)~?~~':,":~:~ <·:·1~$~2.·:>:·~:.':-"~:1:,' '~.-:='~':~'::="~-~,'~-:'~;~" 11.071 16Ò 43 . '"'' ',. . '1 i~89 ". ,,' ':'~','" ~J3": ;. .; '" , '.. >'S§,;_ 11.914 128 37 . . '.. .. '. "1'2.274: :'. . . ~'o' -: '1:39': :: ~".. :':::. . . 43~':~:~ ..,. "12','61'1'''' "'24991:--' ·····6577::··- ,. .:.,1~;.225 . "-. ~':'" ..::'. ·f4§·;,::.·..·".~.·':.··:ft~···~ .. 17.042 276 81 : 1·'8..27f:·· 1. ~á?:$.::~ . :-~.~:'::. 4·~~ª.-::· '::'" 18.340 7770 1533 ..... ". ..: 1·9.:.§~~:. . . .~.':' :)$4~~;. . j~~~~:.':: ~: ~~: :~.'" .,~. ".., '·-.:·~C~·- ".: --..... ..... 20.922 546 165 _ .."... . .' ·::""··'22'.áh' .'. .... ':'·:·::··1'.3$?::"·:~.~, .:·.·:'·'~3i::· 26.490 1049 165 "'_ .. .__.... ... ., ·.~~t7~ª._~.:X·~:~,:~:::,:~~2.·~·~::::.·:·.,~;.·:·"·.f)J'..'~.:,_ ,. 31.726 510 127 ,,, ".' ""?~:§~º~:~'~':<:~~::::::ã6Ô ~"'~'" ...~ 2Q$:;'-: 37.354 432 98 ··'.·'.~9:'Ö9º,~~:.:.'..::.·. ':: :173'5::..;':..·.· <3àä'.: 41.205· 1940 368 .. ........, '.. .... ...... ,,, ... ·44·~~?(::·~·.· .':':'. :j~~~(':.: .::<:··__3~·~:··::~-:..,~··,y·:'<':::~:r. . 45.512 4876 970 .4ájßª··~ .. :",; ·~4.1'5.~·'..·~·5ß7 49.575 3283 768 '.' 8~'125·:·· .. ·214ä.· ': 372:' .~.,." ~ '. --......... ...,,.,,, ..""".,,""'~.... '.......~ - "-"'-"-"'~" ..."........'. ,,,,,,",,..~ 8.367 1765 673, . . :·;".~·.~·~.:ª)4f·; -':". ;: "~' ":' +~~~,~.~>.:..~: ~':~:~ª:,~~,.~:~: ~.'.~~' 8.770 116 44 . , . .'C '::'. 'ª. ª.$~.:..~' . ~'?~E··:.~: . >: l-.i.:·.~ .4:i.;;>::;;;i~!::\;;~~: : . . :" :...~-:~~~~'.':.::: : .':": :~,~:. '~~l:~T ~~.~.~: ~~~·t~.:" ~~. - .;;i~':.~::~ .~,:~;:-:'::.~,~j'=~.~.:: 9.404 207 70' .. ..... . '-' ., -'. ". ~.~.,. .~:~~6 . . ..' ::~ ~.< :?$.:'.~:"': ,:": 9.510 332 . . 1'b~.11Èf···' ::~:. '" ,:~ª4L.: : ..-_',.....~..,..".. .......... .~... .....T._.... ':"" ,",.. .... 128 , ., ,,,. ...., 7.34f '.':~"~~~'~",': h.5.~i~~~L :_·~~~'~?~§';~:L~L:iZT~~; 5.974 . :1-- .'" : ..··..6~Ø62. . ..~§::~;:i'~::·,.~~:~:~tti~.=DF·-C:,:',c··:~~;~~t):Ei}~:;;!T. g.310 4117 . .~.'. _:~ ·~:?ºt·::L:::'~:'~:..:·~ ',~iê~;IT: ~":: ~·~~,.~:..':Ay?;x~:~:r~:';Y:;·:·~·~~~?~:·:-;.'2:,~·CX~::·T:. IC4 Iso-alkane C4 "-·ÑC4>~:~:~::"~_"",rÑor~ã(Ã.I.~ãñ~··~'~:~,-' " ....".:~ ':::.-' .-..... IC5 Iso-alkane C5 .NC~:~,':.:··:·::?: '. ·::':.Når~~r4Î~n~~Lç~':' '~·%ß9~~;~;:-._..,~...,.,,~.. b~~!~6\W~~'!~~~ ..::,~- .'~'-' 2,~Pfv1S...... . 'CO' ,_ ?~:pi,r1]~!hYI~~~~n~,.. :::2fV1P·~:.>.:.' ".:. ." 2~M~th¥JP~ntånø::.' 3M~" "_." . ... ,'" ~~~~.t.~X~E~~~~~~ ,. .. _ . . ,,~~_6:-.;'.:,·.".:..: N9rEi~!:AI~aQ:~.ç~~.. .'. .. 220MP 2,2-0imethylpentane ···..·M¢P':::'.:~·>:· ":' . 'M~t~ŸÎq~I~P,~ñ'tàn~" ., ..~:... '-"- .. ..,,"~~,9I~,~.,. ./" .~: '.' :.' 2},1,~.9i~~!b.ylp'~n,~éi~è. . _' .' ...... u,._", .' .. ?23TMB. ' "', .?,2·~:Jri.n,:¡~tl)ylbyt~r,1e BZ Benzene ;~..:·~~QM~.. :. '. '~t3~Dl~~tbY(é~ñ~~~~~~~~'. >L~~H ":'.~ .'__~" ·"·::j~{~~~~;~è~~ñe::':: ".', ..,. . . '." .." - ...... . ~3~.~~ .. . .. . .2,~-q.im~!hy'Ip'~,nta~.e . ,,",' J,~ OM CP.~· ...., . ·1,·1~º!n.1et~yICyclbpe~ta~.~,: . . . ': "~~~""'h'''''' ...~~~~~~yl~:~x~~_~".~_...... ".... ." ... .. 1·.Ç?PMP P .' .: '1 ~ci~~~~~þ.íme.~h.Ylgy(:lopen~â,rI~ '. . 1T3PMCP. 1-trans-3-0imethylcyclopentane ~ 3~~,'., ,:" .-'; ," 37.gt~.Y~Þ~~.fáh~.'.':·'.· . . .. ',. '". ':' . ~.T?p-MCP . .1~!~~~s~2-~ir:n~thylcyclopentane t-JCy '.,....:,.. N9jæ,~t~J~.~he· CT..: ,'.' . ISTO Internal Standard ' . MC~' . ' ': :':" ""'.. :.. M~!.0Yicyçiö.h~xa.ne u'. _._~11~T,,~Cp', "',.,,,, },,1,'.3.~:·n.i~~!~.ylc;y~l~p,,~~~a~~ . " I;.CP "::'" . ':' .' .EtrylcYclop,E!nt~~e·. '. ,. !?~I.M(~P . .1!?.4-T~imethy~cyc~ope~!~ne ,. . . .....,., . . ··.~·??T~ÇP "'. ,.; 1 ,?,~Tri.mE}~hyJ.cy<?!opé~t~rte~ TOL Toluene .. '~þ':ª'..:~.:, "·~~~C?~m~iAIJ<?n~·Cª·.. __ ,':,::':~,~':" . . .'" . IP~_ , .." . .....Is0r:?~~,~oi~. c;'~" ·~X:YL..., . "<m-?<yle~e " . . ~~'(~.....,,' ..... ..p-?<yl~n.~., h ... ......... . '. 9XYL:. : . '., 6-?<ylerie, . . , ,". NC9 Normal Alkane C9 . IP,1.0· . '-::.::~'·.}s~prênöid.Þ~9·:"·:·:; ..." ,. NC10 Normal Alkane C10 ·..'I.ê,1.1"-· '- ~,':Js~Pf~~ÖÎª.'ª1f :......:':. ". NC11 Normal Alkane C11 '''NC1~~'" . ..' "~NòrmaiÀlkåneÖ1·~.·:~.:. :''> "'-' ~." ......"..--. . 1P'.13 , . . ~sopr~..n.<?i~..C1.3 .. ...' 'IP14" '. " " IsÖp~er.oj<i è14 NC13 Normal Alkane C13 .. .: :ìP1~"',-·".":' '.'. ..... ..~. i$opr~noid :¢'1~ '~-- ... . NC14 Normal Alkane C14 iÞ1~" .... , .'," Is'òp¡:è~oi,d C·+ä'·, NC15 Normal Alkane C15 . ro ..,.."". " "", ~"" '" ~ . ~ , . .LU . .. ...., ". ~ ,.... .". I I I I '( I 11 I I I I Peak Compound Ret. ppt Label Name Time Area . (Area) US134153 04-259-A CP272668 G2040255.D Client ID: Project #: LablD: File Name: CONOCOPHILLIPS PLACER 2 8199 - FT Company: Well Name: Depth: Sampling Point: I I I . 755" 386' 928 959 405 1311 620 13154 1459 . 1448 . 72 1441 1439 128"( , 1163 1016 904 686 644 466 611 387 259 218 142 216 209 100 65 52 302<j':':" '2103 3375 5034 1719 5476 4412 52Q() 5733 4995 447 5422 5009 ·4798 4270 . 3!?~13 3301 2569 2518 1858 3581 1738 1218 1606 691 1700 1309 858 669 567 53.419- ~ . "~'" ~"' . 55.34(. 57.060 57.408 58.505 I.'. ~0.~19 , 60.986 63.818 . 66.961 69.966 70.213 72..843 75.599 78.246 80.791 83.238 85.597 87.873 90.076 92.201 94.260 96.252 98.195 100.083 101.909 103.886 106.068 108.526 111.351 114.380 Normal Alkane ç 1~. . · l:;oprenoidÇ1~:1 Normai Alkane C17 Is~pr~noi~ (;.19 (Prist8:n~) Ph~nanthrene · Norma(A!kane cj'ä Isòprl3noid C20 (Þiiytarie) N~.¡'mal Alkanè Ç~9 Nörmal Alkane C;lÖ , ~ç)~~~I, J.\1~.~ri~ C,2:1.' l-iighly Branch .Is()pre.noid C25 .~orrpa' Alkane C?2 Normal Aikane C23' . ,.' " ", . · Norm~,1 Alkan~ G2~ . Normal Alkane C25 . N~r~.~tAli(å~ë C2.6" .' Normal Alkane C27 f;iormaÚ\l.kane ,C2~. . Normal Alkane.C29 Nårmal Alk~me ë30: ~ ' '''' '. I I Normal Alkéme C31 . ," ~ . . . .. " . · N()rrn.al ~-'kqne C32 Normal Alkane C33 Normal Alkane C34 . Normal Alkane C35 · Norm~I.Alkan~.Çª~_... Normal Alkane C37 Normal Alkane C38 . . . Normal Alkane C39 Normal Alkane C40 Normal Alkane C41 ~ ~ - , .. - . .'~' NC16 ',.". . .IP.~.~ Ncil leJ~:. PHçN NC18 IP20 · NÇ1~. NC20 : NC2t: I.'",~, ..."...... "",o.,,,:,,~'...J ''';~''_ ,. . C25HBI NC22 I NC23 N,Ç.2{, NC25 . ".. ~"' ., . ",: ..~C.,2~;;- NC27 ··NG?~· NC29 ::",ç~~::'. NC31 NC32 : NC33 N034 NC35 NC36 NC37 NC38' NC39 NC40 NC41 'Peak ,. C"mpÔUnd Rêt Label Name Time US134153 04-259-A CP272668 G2040255.D Client ID: Project #: Lab ID: File Name: CONOCOPHILLlPS PLACER 2 8199 - FT Company: Well Name: Depth: Sampling Point: 1Thompson, K.F.M.,1983.GCA:V.47, p.303. 2Mango, F.D.,1994.GCA: V.58, p.895. 3Halpem,H.I.,1995,AAPG Bull.: V.79, p.80I. 4Marzi,1993,OrgG;20,130I. I ~ Tr1...._. .. ::.::c·..· ~q.~..~~: Tr2 18.80 Tr3' . 2.56 Tr4 ..... 1.24 T:r~.: . :::.~·.:~~."'..::.ª.:?O Tr7 .... ...2-59 Trs' . . .: 0.52 C1 G . .2 C3 C~ . Cs . 0.82 0.05 0.14 . ~.~. ,.... F:\ P2 P3 5N1 N2 : 6N1 K1 K2 5~1r6t.'11: .: . P3/N2 . . ,.. . . . .. . .1~(2:4O'~~/.2.3D~f') . . ···~..41 0.89 , ::. ~~:7~ . 2.25 .... ...~-;:j~~?: 89.31 :: '0.88 0.39 .,O:º.~ 1.20 ~ ~ '~d)'"' "'~~~ """ C") U U U .... <'> .... N <'> <'> U Z Z Z N... \Dr- O\OM<,><'>UZ _ ¡ U N ~ N N. ~.N.1_~~~~ J lliJJ..l.J.~ ~ ~ ; U t..J U Z Z Z G2040253.D EARLY CRETACEOUS 8211 FT FT Client ID: Project #: LablD: Sample Type: Sampling Point: Formation: Geologic Age: Top Depth: Bottom Depth: ~ ~ " · 5 , ~MiJÍ,u.J~i¡L~ 1.~ \t~ '. . '-... ~.... ...." ~~ .:, ..B"?!!? P~::. B. TOLln~7 . .1.~.45 c~ jn .ca+~ .c.7)/(CH+:fv19J:i> ':" ,.~~~7 L. Isoheptane, Valu~.. ,. ...... 0.38 F:... :~,9l~Çtl_::~ .... :'~.: :..;.:~..º~26 U. CH/MCP 5.10 R:; . 'pC7t2~.H". ·~·.·15'.·12 S. n Cs/22DMB _,' .. L . .. ... . H. .... tfept,ane: Y~Jue. :: . MCHln C7 . . . ~.pxYYn ~8 19.:9.3 3.80 ...: 8.47 ... .... '"' .... ~ u Z ~ u Z ~ on '" ¡:;: .... In .... u Z ... .... u Z WHOLE OIL GC US134154 04-259-A CP272669 CORE CHIPS 0.23 0.57 :. :....~:·~1 0.81 . . :.:- :,'3.93 ._. ~n ,,. ....., ~ _...._ .. ',.~' .......~.... .' 0.97 ':~;2 3.2 . ..OA- 0.0 c' 3.4 82.7 Pristane/Phytane Pristaneln C17 . , -.. ph,~an~/n5::1~' n C1sln C19 '! ¢:iiE ~~è. ~....::< ' CPI Marzi4 Ncirm,~1 paraffins Isopre~oids. . Cycl()paratfil,1.s.·· .B~an?he.d.. ~i~o~). .Par~ffin~ BT!< .~ro~at!c_~. . Resolved unknowns I '" u Z r .... ... u Z o .... U Z 0\ U Z == U :z: I ... >- >c ..:I '" 0 ~ ... " I ..:I >- >< 0 I Company: CONOCOPHILLlPS Country: UNITED STATES r Basin: NORTH SLOPE Lease: Block: Field: Well Name: PLACER 2 Latitude: Longitude: I Whole Oil GC Trace ( ..:I >- ~ 8.127 1326 202 8.351 2470 1044 8.732 276 123 8.751 221 102 8.850 .222 89 9.054 568 214 9.275 550 214 9.385 575 222 9.446 75 62 9.490 1099 453 10'.071 4174 1544 10.887 15878 6335 11.055 767 226 11.467 1034 355 11.897 696 254 ,. . 12.256 914 335 12.583 68671 24540 15.17.8 15007 4782 17.028 3567 1200 18.257 87702 32129 18.323 39440 10221 19'.500 '48624 16066 20.883 17251 6068 22. 8~8 3278 996 26.462 21033 6813 27.7 56 4721 1388 31.700 20358 6924 36.604 27086 8647 37.341 10636 2982 40.091 18716 ~844 41.197 37805 11229 44.629 28592 9097 45.519 81008 22141 41194 9891 49.576 53270 13626 484 203 7.333 824 199 6.680 1l1l!!llRl k,·U Re Tirrie ~ US134154 04-259-A CP272669 G2040253.D Client ID: Project #: LablD: File Name: 1H(_1 [I L.I" Iso-alkane C4 Norl11al Alkane C4 Iso-alkane C5 Normal Alka~e C5 . ..2,2-gjme.thylbutane . . CYclopentane. 2,3-Dimethylbutane 2-Methylpentane 3-Methylpentane Normal Alkane C6 2~~.-Dimet~ylpentane Methylcyclopentane 2,4-Dimethylpentane 2,2,3- Trimethylbutane Benzene .3.'.3~Dimethylpentane Cyclohex~ne 2-Methylhexane 2,3-Dimethylpentane 1 ,1-Dimethylcyclopentane 3~Methylhexane ,. 1 ~cis-3-Dimethylcycl~pentane 1-trans-3-Dimethylcyclopentane 3-Ethyl pentane. 1-trans-2-Dimethylcyclopentane Normal Alkane C7 Internal Standard Methylcyclohexane .1,1,3,-Trimethylcyclopentane Ethylcyclopentane 1,2,4- Trimethylcyclopentane 1,2,3-Trimethylcyclopentane Toluene Normal Alkan.e C8 Isoprenoid C9 m-Xylene , p-Xylene o-Xylene Normal Alkane C9 Isoprenoid C 1 0 Normal Alkane C 10 Isoprenoid Cí1 Normal Alkane C11 . NOrnl'al Alkane C12 Isoprenoid C13 ·Isoprenoid C14 Normal Alkane C 13 Isoprenoid ~15 Normal Alkane C 14 1§2prenoid C 16 Normal Alkane C 15 CONOCOPHILLlPS PLACER 2 8211 - FT NC15 IC4 NC4 IC5 NC5 22DMB CP 23DMB 2MP 3MP .NC?..... 22DMP MG? 24DMP 223TMB: BZ 3~IjMP CH 2MH 23DMP 11 DMCP 3MH 1 C3DMCP 1T3DMCP 3EP 1T2DMCP N·C7. ISTD MCH 113TMCP ECP 124TMCP 123TMCP TOl NC8 IP9 MXYl PXYl OXYL NC9 IPi0 NC10 IP11 NC11 NC12 IP13 IPi4 NC13 IPi5 NC14 Peak . Label II; Company: Well Name: Depth: Sampling Point: ~... _ .. -~ ,,~. ~ " n .....,u ... _... _..... ... . . ~. ..' ...-. ~ ...~" " .' , ...... .......... .... . -.. '.".. '......'... ... ~- ,.,~. --- ~~. . . .... 7481 1872 3973 . _1~18.·.·. 836 7447 . 7536 . : :811.9 3925 1954· 1089 3945: 1860. '1.9.15 1363 ·~~~~,,·i:.· 1394 '1fß}:'" '"'' 1225 1qp.;L:·: . 1149 ?e~... 596 ~~~:.. 399 264·:: 273 1:43': . 74 :79: 42 . . , ..u,.' ,.... 'r'. .·u,·,..· 30614 ~236' 19155 . 1q940: 4401 ~"-~ "--- .-".~- 35478 46595 . :44039 25666 :.7322. 7212 2?O,34 6804 . 63~1" 5035 5667 5258 4528 4879 4.5j,$ . 5776 3185· 2522 ..~~80 .' 2241 :.14~$ . 1643 '1168 864 ·'885 467 .. ~ -- .. . . ..., ... ~_._~-- -" ~...." --" ~ 53.418 : 55.346 57.061 . 57.407 . 58.465 6q.5.~2.: . 61.005 è3~:85r ,~ 66.967 :69.970 . 70.211 ··'i2,·ši¿".. . 75.601 · ..7ft244 80.787 ·83.232 :. . 85.593 8r871 90.071 92.203 94.257 96.249 98.188 · '100.070 101.896 · 103.806 106.058 108.537 111.080 114.277 117.953 " I I I { I I I I , . ....~ . . . " " ._, n" ~, . .. . . ,.,~ ..,. -. . . NC16 --jp1-ã· '.< NC17 I.P1~·· PHEN Në1S' '.' IP20 t-J¢f9-.:r~:·'<· :. . NC20 ·N.Ç,f,j..:..,., _ C25HBI N.¢?2·~·::·, NC23 ::NÇ'~4" . NC25 NC26: NC27 . NC28' NC29 . NÇªO' ~ NC31 ··NC32· NC33 .. NC34 NC35 : NC36 NC37 NC38 NC39 ·NC40. NC41 ( ( I ( , . . . Peak Compound Ret. ppt ppt Label Name Time Area . (Area) US134154 04-259-A CP272669 G2040253.D Client ID: Project #: LablD: File Name: _. .. Normal Alkane C 16 I¿ôpre.ñô¡d :¢ 1 ~... ". :...- Normal Alkane C17 " l~op'~eÒòid:Ç1.~(~rj~taneL:· Phenanthrene -Norm~I~¡~?n.~~ç 1.ª.¡:·: . .Is~pr~~?_!d Ç.29 .~~.~ytan~) . Nor!i1?IAlkän~'C1ß . Normal Alkane C20 . :·N·~r~~!AI~a·t:'é.C~i -,.' .. . . ~ig~.ly S.ra.~ch .Isop'renoi~ C25 Normal Alki:Ù;eC22 :. Normal Alkane C23 . Norm81ÂlkaneC24 Normal Alkane C25 N~rmaíÀlkane¢2§ Normal Alkane C27 NoÚna' Alkane C2$. ::'. Normal Alkane C29 Non:nal·A.lk~ne C30 Normal Alkane C31 . N()rmal :AI~an.~ ç~?. . Normal Alkane C33 . . NC!rrilal Alkane G34 Normal Alkane C35 Normal AI'kane Cà6 . - ~ - - ~ Normal Alkane C37 . ' -. ,~" ", Normal Alkane C38 Normal Alkane C39 . .. .., . . . Noï-mal Alkane C40 Normal Alkane C41 .. ... . " CONOCOPHILLlPS PLACER 2 8211 - FT Company: Well Name: Depth: Sampling Point: I [ WHOLE OIL GC Ll. Ll. t..-.( ~ J.I Company: Country: Basin: Lease: Block: Field: Well Name: Latitude: Longitude: CONOCOPHILLlPS UNITED STATES NORTH SLOPE . ,. . . PLACER 2 Client ID: Project #: LaIJID: Sample Type: Sampling Point: Formation: Geologic Age: Top Depth: Bottom Depth: US134155 04-259-A CP272670 CORE CHIPS Kuparuk C EARLY CRETACEOUS 8217 FT FT Whole Oil GC Trace G2040254.D ..:¡ o E-< ..:¡ >- >< :>: ... ~ ..:¡ >< >< o :x: u :x: 00 rl ~~ ~ ~ 8 :: ('\J ~ g ~ OJ ~ ~ ~ <'J ~ ~ U") (- M ~ ~ 8 6 ~ ~ ilð~~lJJilizol~2~ ~ ~~g ~~~g ~oo~~~ug~~~~~~g~~Qj~~~gg . rl 0: E ;:~ 1.11 H Z 0: a. ~ i Z J Z Z ~ ,-1,1 a. H ~\.~L H .. L I. . d ..1 r- . ! II.II~ . I ~ Pristane/Phytane 1.85 A BZ1n C6 P1 3.16 Tr1 . 165.96 Pristaneln C17 1.12 B. TOUn C7 22.08 P2 1.37 Tr2 7.52 Phytaneln C,å 0.41 C. (n C6+n C7)/(CH+MCH) 0.16 P3 5.15 Tr3 1.99 nC1alnC19 1.11 I. Isoheptane Value 0.48 5N1 2.29 Tr4 1.27 n C17ln C29 1.66 F. n'C7/MCH 0.19 N2 1.92 Trs 3.27 CPI Marzi4 1.20 U. CH/MCP 3.37 6N1 86.11 1.78 Nonnal Paraffins 6.8 R. n C7/2MH 5.90 K1 0.86 . 0'27 Isoprenoids. 1.4 S. n CJ22DMB K2 0.42 C1 0.00 Cycloparaffins 1.7 H. Heptane Value 1 0~76 5N1/6N1 . 0.03 C2 0.05 Branched (iso-) Paraffins 0.4 MCHln C7 5.14 PiN2 2.68 C3 0.01 BTX aromatics' 9.1 mpXÝUn Ca 10.15 In(24DMP/23DMP) -1.21 C4 0.92 Resolved unknowns 78.5 Cs 0.02 ¡Thompson, K.F.M.,1983.GCA:V.47, p.303. 2Mango, F.D.,1994.GCA: V.58, p.895. 3Halpem,H.I.,1995,AAPG Bull.: V.79, p.80I. 4Marzi,1993,OrgG;20,130I. .. ,~ . ,.~. ~ ..... .., .. .. , .. ..:.....:.......'..:';.~~.."""""l';.....~ -~" .. "'25922''<:' ",'1Ü~~4': . .~.o..54 ." ~11.. 148.3 . : 52.4. 874 328 · .198$::' _... ..49t-. 111362 42385 . 1275ä·...··· ::: 38~¢' 2456 827 .89439'.',':'" 33.1:7:3':>:' 40087 10692 · . .:493.1 ?": '.: .:. '1'6446 9046 3146 . :1374' .41.5.'.:':'. .... 9793 3009 '1'825:: . '484' : '. .~ . .. . -- . ~ -~~ 7519 2591 .' ., . . , ~ L~_ . ,. '. ~ .' . 6275·. : 2005· 1912 513 : 36~1 . . 91'2' . 7322 1735 ·~Ùå3 . . :1'226 . . ~'-.~ . '. 16341 3831 }335 ..... "1492 : 10320 2362 10.978" 11.147 11.556 11.987 . 12.345 . 12.669 : 15.254 17.093 . 18.314 18.379 . .' 19-.551 20.928 ~2:89.6 .. 26.486 :. 2~.7]6 31.713 '36.610 37.354 .. 40.092 . 41.200 -, .... - -. .44.626 . 45.507 .' '48.-155 49.570 JC4 Iso-alkane C4 . NC4,> .. .,_.. -..... '~NôrmâJ Ë\ï~,ä~~'¢1':: ....-. '. '.: .."'" ';-- .^ IC5 Iso-alkane C5 ~iç?:;::"·::··:· . ". Norm~1 ~Alk.an~.·Ç.?:·.. ":.'t~~;~::"'~·-·" ·::'~··~·Þ'!2~~6~;~~~t~.~~ . ........ ..........-- · ~.3D~~~ .2,3.-Pi.r:n.~t~ylb.~t~n.e. . :2Me .. '. 2-Methylpentane: . ~MP. .. 3-M.~thylpentane... · NCe .':. '.. No6Ïiåf:Alkane C6. . ~ '" ... "~~'. - . , . . . ~ ~ 0-- _ ~, _ .. ._ 22.,?~P " 2,2:o.i~~~~ylp.e.nt~!.1e, MCP' .... MettiylcY.èI~pent~~~ 24DMP. .. 2,4-Dir:nethylpentane .. 2231MB 2,2,à·ttin1é~y)být~~e ::" BZ Benzene · á3DMP: ·~13.gi~~th.Ylpeh~äiï.e ~H Cy~lo.he~~n.~ · 2MH .:'·2;M,ê~hÿlh~al1e.:. 23D~P'd' n. 2,3-[)i_~E?thylpe.ntane 11Q,~Ç'P .'" '. :1~1-D'æ~thylcYFI.9.p:~nt~n~ 3MH 3-Methylhexane . '1 ë3DMCP :. ...... .1-ciS~~~Öim~thYI~yçi~peï,tane·.., 1 T3D~CP 1 ~tra.ns-3~Dimet~yl.~yclopentane, 3ËÞ',:: 3-EthYlpenta~ë·_ '-. 1 T2o.MCP 1-trans-2~t?imet~.ylcyclopenté~m~ N'C7' Normål Alkane 'C7 .. ~ ,~~ .....,. ... . "" ~ ISTD Internal Standard MCH. .. .·.MethYI·cyêloh·~~~n~ . ~ 1. ~T~CP . 1 1!3,~ ~ri~ethylcyclope~tane .. EÇP: . . ~thylcY~lopentane.. ' 12~Tfv1,C~ . 1,2,~~ l".rimethyl.cyclop_e~,t~n~ .123TMcp. . ·1.,2·,.3~T~i.rr,iethy!cyclopentane TOL Toluene . ,'. .:~¢ª. NorrT1~1 Âlkané Ö8 .If'~ . Isopren()i~ ~~ .' M)Ç.YL m-XyJene . PXYL,. . . . p-Xyl~~~.. qxy~ .. :':.. .... . o~Xyleri~. NC9 Normal Alkane C9 IP10' 'Isoprfmòid ~10.. : NC10 Normal Alkane C10 . ·Pff;'·... .. :lsbprenoidÇ11. NC 11 Normal Alkane C 11 '. NC12" : Norma¡"Älkarie C12 1~1~... . ...lso~~~noi~C1..3 ; IP14' Isoprerio!dÇt4 NC13 Normal Alkane C13 . ÎP15 Isoprenoid cts NC14 Normal Alkane C14 · IP16 . Isoprenoid ·è16 NC15 Normal Alkane C15 I I '." 7487 8076 ··85Ei. 398 ..:67..1..':·...,..:.. 1336 . ~ ~. ,.~ .....' ~. ·11'90 1195 . :.:1?4 2161 , '5043" I II I I ,I! 8.161 8.435 8.817 8.853 ,'8.940.- 9.143 ·::·~~~65. . 9.476 . ." R539 9.581 : 10.165,. ... . . . . :2:1'3? 3578 ..: :~2.f:····.: 211 . :?2~,:·;.;,·, 464 470 472 '~4~ . 908 1910 ! I . ',' .., .. . 0" .,~ , , . ". · _. .'J~.~::<: :..:..-1J. 101 48 ".' 1'29. ::~'.: :'.;'4.ª,..-. 134 63 '::':5~3à'<:'" "18(L, : '. . . ".. '_,'.' ".. r '0' , ~ ..... ."_ . . 23 11 ::2·3~9',~.~.:. ·.':1·t~.3. ::;,..., 119. 33 23 .' ·{O~~~-..·_·'· .-,.----.......',. ._~.---- -~--..._- -" -0" . .. - '5.988 .. 6.019 6.112 6.361 . 6~ 749 7.348 7.407 7.534 ·7.681 . " I 0.,., .,..,...._ I I I I , .-" ........... - - ~ .' .- - ,,'~, -- -- . - Peak Compound et. ppt ppt Label Name Time Area Height (Area) (Hght) . ....~,..,. ". . ~.-- ",' ......... US134155 04-259-A CP272670 G2040254.D Client ID: Project #: Lab ID: File Name: CONOCOPHILLlPS PLACER 2 8217 - FT Company: Well Name: Depth: Sampling Point: ~··ii_'I'~__ _. lIII!IItß't-.u ...... · .. .' "': ., ,. .. -:: , - .. - .. .- .! . - -. - - . - ~ I .1. . .:. -. . NC16' . Normal Alkane C16 .. . .. ...... 5'3~416 '6728 1531 Isoprenoid C18 '. . Normal Alkane C 17 IsoprE!noid G19 (Pristane) Phenanthrene NornialAlkane C 18 Isoprenoid C20 (Phytane) Normal Alkane C 19 Normal Alkane C20 Normal Alkane C21 Highly Bran.ch Isoprenoid C25 Normal Alkane C22 Normal Alkane C23 Normal Alkane C24 Normal Alkane C25 Normal Alkane C26 Normal Alkane C27 Normal Alkan~ C28 Normal Alkane C29 Normal Alkane ¿3D Normal Alkane C31 Normal Alkane C32 Normal Alkane C33 Normal Alkane C34 Normal Alkane C35 Normal Alkane C36 Normal Alkane C37 Normal Alkane C38 Normal Alkane C39 Normal Alkane C40 Normal Alkane C41 430 1261 941 1214 1599 782 1565 1807 1236 228 1490 1604 1267 1354 954 1260 681 775 444 729 372 281 247 157 274 334 149 116 US134155 04-259-A CP272670 G2040254.D 2572 5224 5873 4479 ·7724 3175 '6986 8656 427? 1815 7371 5444 5543 5013 3492 4684 ·2646 3142 ·1936 4762 1809 1245 1180 979 2630 2055 1443 1242 Client ID: Project #: LablD: File Name: 55.348 57.059 57.390 58.489 60.520 60.883 63.822 66.958 69.966 70.212 72.846 75.599 78.244 80.789 83.234 85.596 87.87.5 90.075 92.204 94.262 96.251 98.186 100.117 102.086 103.880 106.066 108.539 111.334 CONOCOPHILLlPS PLACER 2 8217 - FT IP18. NC17 IP19. PHEN NC18 IP20 . NC19 NC20 NC21 C25HBI NC22 NC23 NC24 NC25 NC26 NC27 NC28 NC29 NC30 NC31 NC32 NC33 NC34 NC35 NC36 NC37 NC38 NC39 NC40 NC41 Company: Well Name: Depth: Sampling Point: SATURATE GCMS ANAL YSIS I I I ,( I I , I I r I:, " I I r I I I CGSI A'NALYTICAL LABORATORIES I 1 Definition and utility of the ratios can be found on our website www.BaselineDGSI.com 2A=Source Age; D=Depositional environment; M= Maturity; B=Possible Biodegradation 3Thermal equilibrium value of the biomarker ratio and in brackets the approximate VR value at which this value is reached :. ',,~ I. . ~t~f,~n~~/~o, p~.h,·.,~.~ .::. .... . 'j .' . . T~~y~lic: ~~rp~~~~!H~p¡:¡~~~$.·· ,'" TricyèÌic terpaiiØs/Steranes . :,:iº,~,~:8, ,.,.9.' .:;;,,' 0.41 ¥, .... ' .~_.qo (~/1~'> .,: 2.34 . MID. ,:··.1.9C>..(1.4%) ;'1..:~¡". . , . ·;.r:¡J1t-,;:·:':.... b.06 .::' .:0'.' ·0;60 :,:·:.'·b...· ,.;,", " . I~,. :.'~ ""I"'~' ,',' . O.Ö5 "'-, ... .,'.: '..... ..:~.07:.MID::-..: , 0.1..~ _ )'11, ..,: ~..P5 (9.7%) B . " '., .:,..... . .-' o.~~.. ~D . 1.:00 .(~,,~%) . .~~2~,.:~. . . '0.58 . M . . 0..6Ö·(0.?~~} ,P~85. ,D. . . c.M Ö '.. 0.57.. .. }~ 1..87 D '0.08 .·:0 . " '-'''1. ,. :"'. -.,."",: ,'" ,...j."'. . ,.f'. . . 0.78 Ö ,,_ _ T '2.27 'A 1(:'J~~r.·III: 9.1·~,~~~.~~!H~p~~:~, ':.'':/ ~:~::':,. _:'. ~;~~:ä~;~~~~r:~::.,:·~··:. ": . Bì,sf.'~rriJpan~(~op~.~~. . '. "" Di~~9panelHopane.:. . ¥~.rßþ1ne/~(}pary~.·. .. ~~:~ór~h9~~relþ.~~.P~r1~¡. . .. ,."",. '" '.. Ts/(Ts+ Tm) trlsnorhopê!nes ;~~~!~/9~ :H?p~~ê,~.:~.·," '; ':." . .1-i.~~S/(~-t:~)., ~o.r.n~~~p'a~e~ H35/H34HomÖhopan~s " . ~ n~..: -.~ . :".. .. ~., .~. ,. ,-. "I ¡,' '.' 'r ë21Je.trac~Cl.if!l:iop. an...~, , S&1)~e~~~yçlÎ!¥9.2.~.,Iri.9yc:l!~ .C~3/Ç~4 Tric¥Cllp .~~rp~nl¥s .' . 91,~!Ç~ªJ"rigY~~~.,t~rp~r~"~· ,.:.,.... Ç26/P~5T!icyCIi~.t~~paD~ .,-. '., ' (C28+C29 Tricyc!iês)f[s )'. ... . ."'7 ~. , '~',o. . %Ç2;'~~P§:(:2t~t~,'~~:;';::~:C ,: .><. ' ·:·".::3~~~: "',..þ':;::, ~~:·;::~.~~I:~: :.'."..:':~:. . ....:..:... : ..:·.·..~c. - ..:~;~~::~;::..::::-~::.:' ~9~?,~~~~..~2,~_71.~ .,. ..' ~2~~.. "~'" ~oç~ß·,.~a~.(~1.?).:.~.. ·.....,·~7~5. . .q:. ~929§~a.~J~17).. ..... '" . ,:,:40:2' Ö.. ~1.(S+.~}(Ç;9 atl,a)·(2.17f,::·::.' .,.',.:: ...., '. 0.52 .: M.. ;: :()~~5(O.~8%) ß~~/(ß.~S+_aaR) (~29H217) ....: . . .. '0.48. .' ~ . q.?0(~.9~0) (¢i1~C;~)i(C2i+C28+~)(217) : 0.20···· . .. .. ~ . c~7ic2~:{<iß~S) (21a}:·:·:··.·~··:· .....:... . . ,,: ··.·0'.88· .... ....0·.·:· , . -.- . q~~{9~~·(å~ß.·~)(21·ä.)··..:,:. .'" '.' ., ".- .:·.'.0;·~2· q:. g.i~s~e~/a~~S.~~r (C27~:(~1:~1)· .": ..1.5.4.iWD:.. '1~ÖO (1.4°1.0) p39··~~,~~~lnCiex (~1~)<::.:·. ~.46 '. . 0 . - ·:ØÏi~h(JP::· . ÞfØJ~Çt #} '. ·l.~Þ·fP: .. : . . . .$~mþle..Typ~: "$~fupJ~ng 'Pøi lit:· . . :·.·F9tmª~~Qo::·.· .... ". Geoiogic Age; : Top Depth: ' Bottom Depth: EARI+Y CRETACEOUS: 7558':a=1: : FT .. ·O~~·34Q1:8.. ':. O+~~~'~A CR27Z~~) OlL.·····.:· SATURATE GeMS ~~w ~~"Wl ~~L- I I I M2040610.D m/z 218: bb Steranes I ~J'-..\)J,}MJJ'v¡1 Ñ\ ~ Vi,,^- ~ tf 1 M2040610.D m/z 217: Steranes 1 .. .I.. .1 ., ~L.. w ..I. .Jl,~1L.L'k~ I I M2040610.D m/z 191: Tri- and Pentacyclics r I PLAOt:R 1 I UNITED STATJ=$" NQRf~ $~()PJ;: I 217 CHOL 5 f1 cholane (;n~ernf3J standard) :. 62.278 5524 1339 100.0 100,0 125 H30_125 C30 17a(H)-hopane (125) 76.513 . 2586· 507 46.8 37.9 125 ~CAR y-carotane 125 BCAR ~-carotal1e " . ' 88.040 1037 82. 18.8 6.1 177 L24BNR1 24.28-bisnorlupane isomer 177 ' LA24BNR 17 ~(Í-1)24.28-bisn~rlupane 177 LB24BNR 17ß(H)24,28-bisnorlLJP,ane 177 L24BNR2 . 24.28-b~srlO~upane isomer 177 L24NOR 24-norlupane . " 177 DH30S C30 S dèmethYlat~.~opane 177 DH30R C30 S demethylated hopane DH31S C31 S demethylated h()p~~~' 177 DH31R C31 S demethyla.ted hopane 177 DH3?S ,C32 S ~emethylated hopane 177 DH32R C32 S demethyiated hopåne 177 . DH3;3S . C~.3 S dell1ethyl~ted ~opan~. 177 . DH33R C33 S demethyl~ted hoþane 177 DH34S C34 S d~niethylated hopane .177 DH34R C34 S demethylated hopane l:;~. 9, tric;¥c;lic terpane 44.548 1174 282 21.3 21.1 C;20 tricyclic terþane . ·47.602 ' 4480 1002 8'1:1 74;.$·· tricyclic terpane 50.678 5183 1239 93.8 92.5 191 TR22 C22 tricyclic terpane 53.386 277fj 649 50.3 48.5 191 TR23 C23 tricyc:lic terpane 56.384 14292 3501 258.7 261.5 191 TR24 C24 tricyclic terpane 57.944 7661 1924 138.7 143,1' 191 C24DEOL C24 des-A-oleanane , 191 C24DELUP C24 des-A.,luPëlne . 191 TR25A C25 tricyclic tërpane (a) 61.043 4352, 920 78.8 68.7 191 TR258 C25 bicyclic terpane (b) 61.108 3130 930 56.7 69.5 ,""" C24DEURS C24 des-A-ursane 191, 191 C24DEHOP è24 des,,E.,hoþane ' . 191 TET24 C24 tetraqiclic terpane (TET) 63.014 3288 867 59.5 64.8 191 TR26A C26 tricyclic terpane (a) 63.274 2971 698 53.8 52.1 191 .TR2~ª C26 tricvcHc terpane (b) 63.448 2829 729 51.2 54.4 191 TR28A C28 tricyclic terpane (a) 68.128 3205 812 58.Ø 6ÚJ> 1~·~;. TR288 C28 tricyclic terpane (b) 68.453 2831 713 51.2 53.2 191 TR29A C29 tricyclic terpane (a) 69.471 3606 885 65.3 66:1 191 TR298 C?9 tricyclic terpane (b).. 69.861 3400 805 61.6 60.1 191 TS Ts 18a(H)-trlsnorhopane 70.879 5734 1373 .', 103.8.. '10:2..5'· 191 TM T m 17 a(H)-trisnorhopane 71.746 7622 2107 138.0 157.4 191 TR30A C30 tricyclic terpane (a). 12:050 23Ó6 572 ':: 41,7'. 42,7, 191 TR30B C3~ tricyclic ~~rp'ane (b) 72.483 2667 604 48.3 45.1 191 H28 C2817a18a21ß(H)-bisnorhopane 73;805 1958 307 35.4 22..9. 1<~1··· NOR25H C29 Nor-25-hopane 1,91 H29 C29 Tm 17a(H)21ß(i-I)-norhopane 74.715 22790 5724 412.6 427.5 191 C29TS C29 T s 18a(H)-nomeohopane 74.845 '6401 1490 115.9 111.3 191 DH30 C30 17a(H)-diähopåJ1e 75.213 2818 668 51.0 49.9 . .. 191' . M29 C29 normoretane 75.755 2100 523 38.0 39.1 191 oleanane C3017a(H)-hopane 76.513 38185 10133 691.3 756.8 . ~: rl';~) ·."r:2i, ., lJ$1a4~1ij . : 04-22~~A . ,. <:P272563 .... '"' "....".. M2Ö4Ó61·0J) ¢I,~~( II:): ' Þføjéët #; .~~þ ,p; F'Uë'Nåme: . çÖNbÇQÞHI~l..ìp$ '. PLACeR 1 755ß,.Þt C<>rnpªrlY: Well Name: [)epth: 5ampl! hgF'oiryt: 268.8 1 ~4.0 ~Ø~:9 ,~ ,~?:~.. 129.~ , J3.6..~ , , '.93.5 . 88.6 . 69.0' 69.7 47.2'. 87.6 94.~ ' 53.9 24.2 ~2.3. . 68.4' 58.9 49.1 '99.3·.' ,7.9.~, 58.6 '·'65j.., : 95.1 '. 91.6 23.5 24.0 56.4 ,37.1, 25.7 27.2 ' 20.2 15.2 ...47:~ : 29.t ". 6.3 7;8 287.0 , ,2o.7~0 41.9 187.4 1~4J . 142.1 96.0 108.1 72.2 892 . "I "''''. ~'. . , .63.~ .102A ·92.6 60.1. 51.0 . aO.6. .' 89.0. 6~.6· 74.5 105.a 85.4 '66.2 80.3 105.9.. 97.4 2~.5 24.3 54.1 ,37.2 25.0 '28.6 22A ·13J~ ' 61.6 48-.2 6;2 ·7.9 ,- - ',' (-, ... '. . , . 3599 ...~5~t,· . 494 2617 . j?~i~:'::'~' ' .- ..~~~.5.. '12~2: . . .~i.~6<, ~04'. .93~ . .632 '." ..1173.:" :·..j~~6 ~., 722 ,..324 567 . 91~ 789 ,,658. 1.?30 . 10?~ 785 "874 1274 1226. ' 315 ~?1: 755 497 344 364 270 .204, 6~! 389, 85 : 105 15854· ,1143..?:~· ~317 10354 . ~ .~'" ," ¡.' . ". . ~1?? 7851 5303" , 5969 ' ~~~1.·,:. 49.30 3~,11 ' 5654 5:119 ' 3322 2815 4450 4~1.4 . 3788 4118 . 5847 4~.1.6',. 3£)57 4433' 5650 5~~3 1577 . 1343, 2986 2057 1382 157ß 1239 763 3405, . 2660 343 434 .. . : ~r .' 78.571 · 7§&~:t ::"'_ 7$,1515 80.196 80.543 82.060 82.536 84.010 , 84.595 86.003 86.7'83 53.797 65.701 70.316 72.743' 73.35.0 73.761 73.891 74.671, 69.601 · 69.818 : ··i1.~~.8 72..093' 73.740 73,891 75.278 75.386 ' 65.701 · 66.546' '. 67.759 67.9.11 .,6~:6~9 · 68.778 . 69.623 70;576 . .', !~~603 75.690' - '. """ "~. .. ..:... -. I I " ~ . C31 22S 17a(H) hopane .C~1.'22~ 1?a(1-I) Jic)p~n~ ' gammacerane · C32 225. ~?a(~)~o.~a.ne . C32, 22R .17~(H) h()pa~~" . C,33 ~2~ 1?a(~) hopan~.. 'C3322R 17a(H) hOPélne C34 22S17 a(H)hopane 'C34 22~:17ci(H) hopan~ C35 22S 17a(H) hopane "C3522R 17a(H),hop~~e . ,,' '., . · .c~21 sterane . _ . . C27,ßa 20~ diasterane C27 aa 20R sterane . . ~ , .. '. . C28åa. 20R steràne C29 0.0. 205 sterane '. C2~ßß 2QRster~ne(+5 ßaa) · , C29 ßß ~OS s~er.~ne C29' aå.20R ster~ne ~7 ßß 20R sterane , C27 ßß20S sterane Ç28 .ßß 20R ster~ne C28 .ßß205st~rane C29 ßß 20R sterane' C29 ßß 20Ssterane C30 ßß. 20R ste~ane C30 ßß20S steran'e . C~i ßa 20$ ~iasterane C2r'3a20R diasten:me C?8 ßa 205 diastera~e .a . C28 ßa ?OS diasterane: b " t2~ ßa ~~.R dia~ter~n~~ C28,ßa 20R diéister~ne'b" ê29. ßa 20S diaster~rie, . , C29. ßa20R djast~rane' , C30 t~tr~cyclic poIYp'~en~id... _ ',C30 tetra cyclic polypn~noid . ' ',' "...' . . .~---;,.. T aràxer~ne : . I ',_,OV I 191' ·'.'.:T~ 191 H31S t91,::·':;:·H~jiä~;i{ 191 GAM 191 H32S 1.~1':" .' ,..:~,.~~~i:·~<\ :',,' 191 H33S 191 H33R , ~91 ~34,$ 191 .H34R 1~1., H_~~S 191 . H35R 217 . 5~1 217 '.: 'PIA275 217 C27R ?H:Ì,···:}:::;:!:~g§it;,;· 217 C29S 217' . C29BBR 217 C29BB$ 217 , . C29R 218 C27ABBR 218'" C27~BBS 3,1~,. C28~~~. 61£\ C28AB~S ;218 C29ABBR 218 '. C29ÂBBS 218 C30ABBR 218 C30ABBS 2~9 027$ 259' . D27R ,~,'~~::r':' "·:'::'~i¡~~:~lii."i"" 259 D28RA 259'.' D28RB 259 D29$ 259 D29R 259 C30TP1 259 .' . C30jp2 I I I I I I I I Peak Compound Ret. ppm ppm on Label Name Time Area (Area) (Hght) ., 0$1$.491:8" , .: 04"~~~-A' '. CP27Z5ß3 M2Ö4ö61ö.D ' ¢lièr1~IÞ:' Þroj~ct #: ~~Þ. iP¡ FilëNáme: , CONbëoÞHI~JJp$ PLACER 1 7558 - FT I COmPé1ny: ' W~II Name: Depth: Sàri1þling Point: 0.13 >0,42:.. 3.10 0.18 0,41 ,'. 2.34 [Steranes]/[Hopanes] [rricydic terpahèS]/[Höþèi1èS}, jJricyclic terpanes]/[Steranes] (105 0.10 0;60 0.79 0.06 0.10' 0.58 0~85 Bistibrhbþàtië/Hòþane Norhopane/Hopane Diahopane/Hopane OleananelHopane . GammaceranelHopane Moretanel(Moretane+Hopane) . H32 S/(S+R) Homohopanes H35/H34 Homohopanes Ø~O$· 0.56 . '.' O,()1 .0,05· 0.60 0.07 oJ:i5 0.39 0.26 0.43 0.28 Ts/(Ts+ Tm) trisnorhopanes C29Ts/C29 Hoþâhe 0.61 0,09 0.57 C24 T etracyclidC26 Tricyclics 0.08· ·1.82 0.77 0.08 ,1.87 0.78 Terpenoids C19/C23 Tricyclic.terpanes C23/C24 TricyClic terpanes C26/C25 Tricyclic terpanes 0.22 1,15 0.20 .:1,$4 (C21+C22)/(C27+C28+C29) (217) Diaster/aao..Ster (C27) (217) ,.', 0.86 ' 0.46 0,58 1.08 0.52 0.50 0.92 SIR (C29 aaa) (217) S/(S+R).(C29 aaa) (217) ßß/(aa+ßß) (C29) (211); aßßS/aaaR (C29) (217) åa.$ 27.6 3~t8 0.87 0.71 1.15 42:4 .19.0 ·ðít6· Steroids %C27 aßßS (218) %C28 a~ßS (218) %C29 aßßS (218) C27/C29 (aßßS) (218) C28/C29 (aßßS) (2~8) C29/C27 (aß~~) <2.18) %C27 aà&R ·(2'17>.' %C28 aaaR (21.7) %t29 aaaR (217) 32.5 30.5 37.0 0.88 0.82 1.14 " 32A. 27.5 40.2 .. .1.Mi_ )-- .....'....,......,.. ....,......., ..........".,...'...'....,.....,........................... , ~ . , Mis ... . V$1 ~401ª 04-22~~A êp27~$ß~ M2040610.D , 'çli~r1fl()·~.. Þtöj¢çt#~:: · ~~þi p: File Name: ÖQN ÖGPpHll..I"IP$ PLACEA. 1 755ß ~Ft ÇÖrn PCiOY: Weli N~lTIe: Depth: Sâmþling Point: - - - ~ - -. ~ - -- - - - ~ Sampl e: US134018 Ion Mass 191 1 2 0 0 0_ 1 0 0 0 0_ 8000_ 6 0 0 0_ 4000_ 2 000_ ~~~~ '^--'---~ ~_,~".J..\"",.w.lfuM JlJ J,,^,,~, ,J...¡.,J.AV--VV~ 50'.0 60'.0 70',0 Retention Time (min) 80',0 90'.0 File: M2040610. D\data. ms Date & Time: 6 ADr 04 2: 28 pm Sampl e: US134018 Ion Mass 1 91 1 200 O. 9000. 6000. 3000. ~~~~\J~ 6 g'. 0 72'.0 75'.0 78'.0 81'.0 84'.0 87'.0 Ion Mass 177 3000. 2000. 1000. ~ '\..Jw 6 g'. 0 72'.0 75'.0 78'. 0 81'.0 84'.0 87'. 0 1600_ Ion Mass 205 1200. 800. 400. ~~Av 6 g'. 0 72'.0 75'.0 78'.0 81'.0 84'.0 87'.0 Ion Mass 163 2000. 1000. ~~\~ 6 g'. 0 7 i. 0 75'.0 78'.0 81'.0 84'.0 87'.0 Retention Time (min) LIe: M2040610. D\dat". ms Ite & Time: 6 Apr 04 2:28 pm I I ' I \ \ I \ I I I ( \ \, I I Sample: US134018 2000. Ion Mass 217 1000. r I vJ~JJJNJJY)vf\AJ.~'~ ~ 66'.0 6a'.0 70'.0 72'.0 74'.0 76'.0 Ion Mass 21a 1500. 1000. 500. )~W'~'Ll~~ Jw 66'.0 6 a'. 0 70'.0 72'.0 74'.0 76'.0 Ion Mass 259 900. 600. 300_~ ~ vJJ J ~ ~ '^vv 66'.0 6a'.0 70'.0 72'.0 74'.0 76'.0 500. Ion Mass 231 400. 300. ~fJJI~~¡~ ~ 200. 66',0 6 a'. 0 70'.0 72'.0 74'.0 76'.0 Retention Time (min) l File: M2040610. D\data. ms Date & Time: 6 I\pr 04 2: 28 pm Sampl e: Ion Mass 217 1500. 1200. 900. 600. 300. US134018 ~ Ion Mass 218 2000. 1500. 1000. 500. File: M2040610. D\data. ms Date & Time: 6 Apr 04 2: 28 pm 45'.0 45'.0 48'.0 48'.0 Retention Time (min) 51'.0 51'.0 JvlvJl~\~ 54'.0 57'.0 '^^~..~~ 54'.0 57'.0 Sample: US134018 Ion Mass 123 I 5000. r ~ ~ C") . '000. N ::: N I I 3000. ; C") ~ ~ M o M I ~ .; .. 2000.:;: N N . ~ ~ ~ M ~ I ~ ~ ~ r-- ~ N 0 ~ ~ N ~. C") oO"lr-- ~ oo~ 00 00 ~M~' I 1000. ~ ~~f-\\Jv ~Mtl~~~ I 16'.0 ' 18.0 20'.0 ' 22.0 I 24.0 Ion Mass 193 I 1 000 O. f ~ C") 8000. ~ I o I 6000. ~ I 4 000. I, 2000. N ~ ~ ~ 0 ~ 00 r-- o M M 0"I00~ ~NM N g::;r Ág N ~'~ .. 0 C") ~ . ~;j' ~ ::;":~ 16.0 . ~ ~ ^ ::: ;i 18.0· ~ 20.0 r 22.0 ' 24.0 m" ".." '''''N. R.ceot"" Time {mi"' Date & Time' A . pr04 2:28pm ~ M r-- u:i f"\ 0 ~ N r-- u:io 0"1 NN ~ ~ LtÏ u:i N I N ~ 1 26.0 28'.0 0 ~ NO 'N ~~ N u:i N j. m~ ~ N~ 0 ~ . M o r-- r--N c:Ö N N \.....11 ~I IJ'\J. 26'.0 28'.0 N 0"1 N m N Sampl e US134018 Ion Mass 177 300 0_ 2 50 0_ 2 0 0 0_ 1 5 0 0_ 1 0 0 O_ m r- eo [ .1.0 m o N 1.0 r- N ; 1.0 500_ cè ,-; 1.0 l"- V ~ ~ 69'.0 72.0 file: M20406'!' ')\ Date & Timr data. 04 2: 28 75 J) "" ro <:!' L1) .-I I"- "" I"- o .~ L1) L1) I"- u1 I"- 87 M .--I L1) 1.0 I"- 78'.0 Retention Time .--I I"- L1) ..--1 coM I"-CO o:i I"- min 1.0 (\ .--I M .'<7' o L1) CO . o CO 81 o o 1.0 o N ro 84 o o File: M20406l0. D\data. IDS Date & Time: 6 Aor 04 48.0 m 2 E-< 52'.0 Retention Time minI o N W '<:I' If) 56'.0 60.0 64 m r- w m . OOw If) ~ '<:I' W 0000. 00 'dN rl ~~ o 1 0 0 0_ N N p:; E-< ~ ~ ~ '<:I' N E-< µ]~ E-<I.q-..¡ ~ o N p:; E-< .--1 N p:; E-< 2 0 0 0_ 3 0 0 0_ '<:I' N p:; E-< 4 0 0 0_ - - - ,- - ~ - Sampl e: US134018 Ion Mass In· - (Y) N p:; E-< - - o (Y) ::r: Sa mpl e US134018 Ion Mass 191 1 2 0 0 0_ 1 0 0 0 0_ 8000_ 0\ N ::r: 6000_ U) rl M ::r: 4 000_ o 87 U) l!) (Y) :r: U) M (Y) ::r: P:: (Y) U) (Y) "1' ::r: (Y) :r: P:: \D "" (Y) l!) 0) ::r: 0 0\ M l!) 0) M 0) ~ 84',0 o 81 P:: N M ::r: I~ U) N M ::r: P:: ~ M ::r: 69.0 fil e: H Date & Time' r 04 2: 28 min) \D "" 0 0\ (Y) '-O,~ 0) \D rl \D r-"" ~ ¡~ r- 78',0 Retention Time o :r¡ 5:: :'J :J 75 o ~ E-< 72 U) E-< <t: ¡:Q 0\ 0\ N N P:: P:: E-< E-< ~ 0) II! NO) P::N E-< P:: E-< 2 0 0 0_ File: M2040610.D\data. Date & Time: 6 Apr 04 2: 28 om 51'.0 52.0 53'.0 54'.0 55'.0 Retention Time min) 56'.0 57'.0 58 o 59.0 400_ co 10 \D r-I co . r- a . 10 a 200-UI~~l J \D If) 0\ r-I If) ^ \D co a N 10 \D "<r M N II) "<r "<r co N 10 II) "1' \D M II) r- (Y) co "<r II) 0) M co \D 10 600_ \D M o:r r-I 10 N 0\ m (Y) II) 800_ m m o r- II) 1000_ 1200_ 1400_ - -- ~ - - ~ - Sa mpl e US134018 Ion Mass 217 1600_ rl N U) - - ~ - - - - -- Sample: US134018 Ion Mass 217 1 800_ 1 500_ 1 2 0 0_ 900_ 600_ M M ~ N N U1 rl 0 rl 0 M ~ r-- ~ 300_ M ~ ~I 60'.2 60'. 9 Date & Tilte: File: ~f2040610. D\data. InS "Dr 04 2: 28 om ,..:¡ o ;:r:: u M M ~ r-- ~ ro M U1 U1 N rl (Y) ro r-- ~ r-- Cf\ ~ .; Cf\ 0 0 .; rl ro LA, N N ~ ~ ~ ro ~ ro ,JV ~~ rl . ~ N ~ 61'.6 62', 3 Retention Time (min) 63', 0 63',7 64', 4 File: M2040610. D\data. IDS Date 'Time: 6 Apr 04 2: 28 pm 66'.0 68'.0 70'.0 72'.0 Retention Time (min) 1500_ 1 2 0 0_ 900_ 600_ \D 0'1 N I"- o 0'1 rl . (V)"!' \D W 300_JL_~_~ ('t) 10 rl I"- W rl rl 0'1 I"- W 0'1 10 l"- I"- W \D co 10 I"- W W 10 I"- ro cr\.O rl W WO W o ('t) . W rl' co"!' I"- .co U)\O N COW co W cri W \ J ('t) W ('t) cri W \D N 0'1 . "!' 0'1 \D .0 rl V ( \D I"- 10 o l"- I o ~ J: ~ ~ 16 0'1 \CO ~ J ~f\ co 0'1 co W . qorl 1"-1"- rl I"- J co co ('q'1 o,n ('q'1 I"- . N f}:; co N U 1 ('t) ('t) rl \1_ II) 0'1 N U \ 74.0 co I"- N\D ·co IO(V) v~_t(;~ f}:; 0'1 N U 76'.0 (V) 10 N \D I"- (V) rl 10 \D I"- II) l"- N ~ H Q \D qo 10 W \D co rl co cri \D f}:; l"- N U ('t) 0'1 o N I"- f}:; 111 111 0'1 N U ,II) 111 111 m N U - - ,.--. - - ---- ,.......- - ,-- - Sampl e: US134018 21 0 0_ Ion Mass 217 1 80 0_ M N W cri \D - - ~ - - - -- ~-==...~ rile: Date 112040610. D\data Time' "r 04 2: 28 72~ 0 Retention Time (~in) 300_ 600_ 66 (Y) ll) rl r- '" M "I' "" If) '-P rl o l"- ll) '" <.0 C\! o <.0 <.0 o <D ~ lI) l.O <D 68'.0 en .-l ll) .-l r-CI'> ~~ <D<.D ~ \ \ '" o .-i a:;¡ '" rl o (') 0:> <.D (') 1.0 C'1 M . ri'" N<.o en <.D 70',0 .-I ('. rl ° r- Jl\ '" .-l (') o r-en ~ "tf"i 9:) r'r- 0:> ° lI) M ro r- <.D '" .-Ir- "', '.-I rir- r- ro a:;¡ N N r- (Y) cc <:T' <.0 ro r- ('. r- 74 M<D ~~~ "I' ~ r- I"- .-I I"- '" ~ I"- o 76.0 ç,:;U) p::¡p:¡ ~~ 0° (')(') uU \ lI) r- C\! '" r- (') rl lI) <D I"- 900_ U) p::¡ ~ ro !):; N p::¡ U ~ OJ N U 1 200_ U) (1) ~ l"- N o 1500_ 1 800_ Sa mpl e 10 n Mass 218 US134018 !):; p::¡ ~ l"- N U ¡:t; p::¡ ~U) enp::¡ ~~ N U Fil e: M2040610. D\data. IDS Date & Time: 6 ADr 04 2: 28 Dm 66'.0 68'.0 70 o 12'.0 Retention Time (minI 74'.0 400_ 600_ 800_ 1 000_ I~ ~ co \D N , Q M r- ,\0 LO ~ co r-I 0 co '" \0 r- r-:' a:i co m ~ ~ ~\ ",g JJ\D ~: rl '" "". \0 200-LL ~_1 ~ ({} \ [I) r- N Q Sarnpl e Ion Mass 0:; r- N Q US134018 259 t:Q [I) ,:¡;CO u¡N roO N o ~ ~ co N Q -- [I) '" N Q - co .-I co 0\ \D "" M 0"" .\0 0.-1 r-. ^~-~ ~ ¡:¡:; '" N o q¡, ro ~ ~ M '. \D. '" ~ :\~o~ r- N I '" LO . \D .-I "" r- ID' \ ~ o .-I M N r- co M '" N o r- o r- N r- - .-I \D r- M r-r-I '" co M r- - \D r- '<I' "" r- ~ - - M r--I LO N ~ p., r- r-8 PO E-M co M U \ vM 76'.0 1 Definition and utility of the ratios can be found on our website www.BaselineDGSl.com 2A=Source Age; D=Depositional environment; M= Maturity; B=Possible Biodegradation 3Thermal equilibrium value of the biomarker ratio and in brackets the approximate VR value at which this value is reached ·i%i~~: iÄ~Þ.)Þ·;· . . :$ampJ~T)'Þe.; .Sam"Uri>··· Point: :: ført.f~ti:~:. ... :: ::' ($~Qi:øg¡çAgø~ .: . Tô.p Oepth{\.· '. Bottom Depth: ~~~~il~~(~'9P~I)~~.:·~~;: ::~:~~:~>~',~,~:¿.;, (:. :L'·o. .~: :~..'::.": ,:, 9)~':~,·:, Jf::l;';.:':.; ;;';':: >,':.::;) : . Tr¡cyêlict~~anø$/HOpanes:··.." '. " .0.41. M . >1.00 (1.4%): Trï~ybî¡c t~lPå~~äïs1ê~ri~·::~·!:. -:~ .: : ~ . -- "'~':24 :"'MlD ::~.~:iö.o {t~4·%t ", . '.~ -. ",'." 9t~~.h~~~~'?9#.~~~~:>L';:~<I'::·:.· .,. ..". ·q~"h,1~~~~n~/H~p~~-,e. ' NorhåpanéJHopanë· ' , 1'-' >-- ,¡ "':'.... ... ~.' ¡ ,.... ." ..... .... ',,: ~~~~~~~'?P~f.1~r.!~p~~~" .. D. )~~o.panei~lopan,e, . . ' . ' . 'I tIß~f~~~~(H.~p'~e. ..'" ' 25~no¡"-tlopa:n~oþ'a;Iie¡. :.. "; -...... '.',' ~. ': "~".' ~. :".. ·.~"'·'1~·"·. .. !~((~ ~+!rY1),t~~.?~r~,9~~~~~. Gf'~!~/~.~.:~.pP-~~~~~'>,', :. H~2 $/(~+~) .H.0ri19~ôp~n~s... 'H35íH34"Hó'ri;'cihopá~ks~': ~,-:'\~ ........,.......-,.:...,"". ~----,...,r...,~~..,~. _. .~--.; :.'. '"._~_a,_ -,-""" C24 Tetraêydic/Hopane . .,' .. . ...~___1.~...._..,<:~ ':'~ ."_~ \',''':' ':-,~":",'_, ".:.,.1 ,"" ·Ç~4'iT~~~¥~~~~?~:;Ir.~¥~~!~ ~~~/i~:~~~,···"·· C2ßIG~5.rricyclic te,tþë;1n~. . ~¿2à~C29 ·~ri~~~1¡~)lf.i~~:)i:;- 0..06 . e" O~59"'" .o~.o6 .0:08 :' we>'.. ' 0.11' ..~. ~~.o5,(q.7!0) . ,8 , '~'. r . ~.43 MID . ~ .ao (1.~0/~~. .. ...~2,~~'O: M; · .::: ',' ,': "', 0 ,. ,..;' .,,'. .",,~,,~.~~ " ~.., .O:,~.o (.o:~,r~J, . ...·,O~~5 . . D·:. .., . ;::·:··io.·q.~ '.. ~ . '..0:'5,1:. .~Þ";-"" 1.85 .0. 0;.09·...; :D~:·~· -. I " ,'. - :- - ,- ... ....,. ':,"" -. ';. ,·\:/·~·~~~.,~,.:..·.Å.:.,>'· ..",. ... ... . ~q~;:~~ß.,ß.·$l~J ~~.~:;::'~;¿~:/;i:X·~:: . u:~ , ,~3?:~, -.>:',.0.' :..:(", ':.. %~8 cißß.S. (218) '. 29.5. D ·~>~~11~~;:;;j,):.,. ." "":,,.. ,.[i;;'·'·: g.:: ~fJ*;rr~~(~~~i i~'i if:.2L:..:" . ::, <.' ::.;j:,~'(~:':6~~, .,~. .'.,.:'.9.55 (~~ª~ r ß.ß.$/(ßßS.ta.~R) (t:z'9)'(217) .'. OA7.· M .0.7.0'(.0.9°/9) (ê2~*é.~~);¿ç;'~+ê~i~~~f{~~'7.f.. ..~, ':'.',. .:'Ö~19· ' , ..-." C27/~,è:,(~~~~~~J~~8>, ..=:'.:: ',~". ' . . '. Ö.~7 ,: 9 '._. ~8/C29:(cißß. S){21, ~)..:.:';...::: . 0.7,.,8.. ',.0.' :::' .._. . . , . _... .: - ~ ... .>,,' . . _'.' . ~. J . _ . . ,,'. . r""" .. .' ... "... " blas~er/~~a Ster (C27.)(217) . 1.43..' MID'., 1..0.0 <'1..40/0) , "" ..... . ~~. .......' r' ~...~. r' , .." " .': .. , ,." "'- ~~o.Steran~ Ind.~xJ?1~) . " :, :.;ß~24 q;':':\_~: ':<.:/. . " ". .... ...... . .. ,.. .. . . . .. ,.. . . , , - .:·::~A~~YT~l;tACEÖ~:~ : . '.. 75S6.SFT . FT ...:O~1$.4Q1$··· . '/'Q4-~a3-A . : ¢'Þ2.7ZS64 §I[)F;WA~I.. 'CORE . ~~W/\MU~JLL M2.o4.o611.D m/z 218: bb Steranes ..JJlA JI-.. V yJ (I Nv \ ~ \ N \ ~ V "'"' ~ M2040611.D m/z 217: Steranes .1. . ~hw ..,Jl.~~L~~ --J M2.o4.o611.D m/z 191: Tri- and Pentacyclics ~ .~ B~~..':;~J4~¡Lg~~· Cømpå.Oy: CØNbcoÞHrLLipS·::>· Country: UNITeD STAtES $~$tn: . . NÖRtl:t$~QÞ~ . L.ea~e: $Iotl<: Fielçt: W~II Name: P~è~R 1 l.atittld~~ Longiti,Jd.~: .. SATU::RATE....G:CMS::...... I I ,I [ 1 I I r ( I' 44.54&. 1759, ~~7 31.0 28.2 47..624 6447 1493 113.7 108.8 .' 50.700 . .7545 1794 133.1 130.8 53.407 4127 950 72.8 '692 56.406 20505 5219 361.8 380.4 57.966 11094 2916 195.7 . 212.5 61.043 5733 1288 101.1 93.9 61.129 .4869 1296 85.9 94.$ 63.015 4961 1122 87.5 81.8 63.275 4429 1079 78.1 78.6 63.448 4279 1029 75.5 75.0 68.128 4722 1182 83.3 86_2 68.453 4037 1077 71.2 78.5 69.493 5549 1273 97.9 92.8 69.883 5135 1167 90.6 . 85.1 70.880 8534 2164 150.6 157.7 71.746' 11530 2933 203.4 213:8 72.071 3693 895 65.2 65:2 72.483 3968 799 70.0 58.2 7:Ü305 ~231 427 ·57;0 31_1 74.715 33513 7921 591.3 571.3 , ' 74.867 9945 235? 175.5 171.7 15j~13 "4218 1Ö03 75.5 · 73.1 75.777 3387 ·742 59.8 54.1 76.513 56336 13659 993.9 995.6 5 ß cholane (internål s@nciard) C30 17o.(H)-~opane (12~) y-carotane ß-carotane 24,28-bisnorlupane. ispr,ne~' . 17 a(H)24,28-bisnorlupane 17.ß(H)24,28-bls~~riupane 24,28-bisnorlupane isome~ 2+norlupan~ '. " . . 'C~O S. ?E!me~¥,at~9 ..~C)þ~n.ê:. C30 S demethylated hÞpane C31'. S d~methylated ÞoP~~~:. u' C3t S dëmèthyi~tèd h'Qþånë . C32 S dem~tl1yJ~te9h'>.J(;Il1e C32 S deme~ylated hopan~ C33 S demethylated lu}pa~e C3.3 S demethylated hòpane , (;34 S demethylat~d hopane C34 S demethylated hoparie C19 tricyclic terpane C20 tricyclic terpane C21 tricyclic terpane C22 tricyclic terpan~ C23 tricyc~ic terpam;!, . C24 tricyclic terp~~e. C24 des-A-oleanane C24 des-À-Iupane C25 tricyclic terpane (a) C25 tricyclic terpane (b) ...º~~:g~,JiJgrsane CZ4 des-E-hopane . C~4 tetracyclic terpane (TET) G26 .tricyc~ic t~rpane (a) C26 tricyclic terpane (b) C28 tricyc~ic terPaile (a) C28 tricyclic terpane (b) C29 tricyclic terpane'(a)' C29 tricyclic terpa~e (b) T s 18a(H)-trisnorhop~ne . . . . Tm 17a(H)-trisnorhopane ¢30 triGycli¢ t~rþà.n~{ä) C30 tricyclic terpane (b) C28 17 a 18021 P{H)-bisriorhopane (;29 ~or-25-hop~n~ ~29 Tm 17.o.(H)21ß(H)~~or~op~ne , C29 Ts 18a(H)-riomeohopane C3017a(H)-diahopane C29 normoretane 62.300 " . $6'68 ..1312 100,0 100'.0 76.51'3' .3940 741 69.5 54.0' 88.040 1456 . '112 25.7 8.2 TR308 H28 N0R25H H29 C29TS DH30 CHOL H30_125 GCAR BCAR L24BNR1 LA248NR LB24BNR L24BNR2 L24NOR DH30S DH30R DH31S bH31 R DH32S DH32R DH33S DH;33R DH34S DH34R TR19 TR20 TR21 TR22 T~23 TR24 C24DEOL C24DELUP TR25A TR25ß C24DEURS C24DEHOP TET24 TR26A TR268 TR28A TR288 TR29A TR298 19'- 191 191 191 191 191 191 191 191 217 125 125 125 177 177 177 177 177 177 117 177 177 177 177 177 177 177 177 191 191 191 191 191 191 191 ,4;~~,ê 191 Peak'···· 'CompoUnd ppm. . . ppm"·.···· Qr) .., Label Nélw¢ . (Areél) . (f1ght)· . 051a4019 04~223-A CP21~$ß4 M2040611.D Client,ID:" . . PrQj~~t #: . ~~þ JP=. t=ileNäme: çoNÞGqpHH.J..IP$·..· PLACÊR .1 7556.5 ~·Ft Cørl1pct'ny:" . Well Name: De.pth: SampliogP.Øint: , ..... .,.... . . .,.' . .. ,., ..... 23059 5384 406.8 392.4 . . -, - 169_~~ , 3.555 .292.7 259.1 . 3~&.: . 7.1 t.. '57 ,0 $~.~ 14859 3349 262.2 244.1 . : ,r' .·~·1J~ªY6.~.:::: "··".'~::·1~ª~r ~,'~t~,' ::::::j~~:~.,:> .·~·'·:~:'·:·:174~~~.~:·.· 11b42. .' 2399 :. . 194.8 '174~9' . '.' ::~,:?~f~'!:' ~:'.~ '. :~1:3§Š,~:,~'~:":' : . '1'3~,: ~.~" .';". ")~~~~r::' 8328 . 1805 146.9 :J3Ü~.. > ... . '~55~'{r:":- ,.",:-~, ~Ei3' ::.' ,:'. ''','. ;"·97:r"· ,.,~' ë"':é5~5~:' ;, '., ~".. . ~'> ,'" ~".!o.Þ - ... ": _..:. '. . .; .~'.':'.' .. ..' :. . . .'. :: '.'.1'.-:... 6997 1324. ·123.4···· 96.5 ,.;;. 47?q ,:' .:~~," .,.:" ~~9.'''':'' :......···:833:·::--.'::,.· :~:6Š~~·:::;:. . 8121 1621 14;3;3 1'Útt::: '. .': i:ªå~"', .::"" ". :·:..1ê#q'.'.···· " j~?~9"'- -'r ' ,1.~4~ªi::: 5324 963'. . 93'~9 70~2 '. . 4~~~"';' ,. '''1~5 ·:,'SO.g',·: 36:'(~" 6781 . . 837'. 119.6 fh.o:· . .. . .;..,,'J~·~i'- /.. J,~:1·~!(:.~ " 1,4(i7,' ..,,, .~,1Ó7·.€(.· ·5285· ·1125· . 93.2 82.0. ·,·.,~å~š:·.. ,'··~954·:.'I.::::··.·~ºY?·.··:·: ".' .:~<~~:~":;' .. 8473 1937 ,.·149.5 . 141.2 : .. ''\:'. ,....~.>..>...."- ~ . <". _; ~.I, ., "',." . .....,,'~ '.- I. '''i:~'' ,~',."" ..6~55·,·.: . 1~~3' '. '122.['. .' .113.:9 . ~3,~7" 1102 . . . ~~·..2 . . :8~.~.. ':6~~9 . 1323' ·nO.1 ...... ,96.4 ' "..:·82?8 ",_..1~~4 145.7 . 1.~~.,~ .:?~!5 , 1630.... 140;7 '1.18.8 '2010 438 . 35.5 31.9 . 1'9,0.1 . 436 33,5':" 31.~ ' 4é94. ',. 1050 7$.è' 76.5 . ·.~985·, :. .,J1,O~. 54.~ ' ~1;~ . 2135 . 479 37.7 34.9 231~''':, ." <46~340.~· ,., 34,.~ 1698 409· . 30;0 29;8 .;.... . .' ." " 'I" ...... ~' . " . 'I . ,,",' . . ~ , , 1157 '.,. }32·.· .. 29.4' ":?4:2': 50~~. ,..;. "..' ,.~a,t ',.' . ..89.8 . 6~:2 4078 ' .566 . 71..9 '41.3,', , .. ...~~~ .....,.. ,~~,~.'. .;, .}·l ''''~~~'''' .?89.' ".137, . ,,19.4' ., .'~,O.o' '. ",'~ . . ....:~......- 'I -, .., 78.593 78.832 '1$,157 80.197 " ''',''~å(iš43 . å~~o~~ . :>82.537 . . 84~01 0 .~.. ·~4~p9'$~~,·'·.· 86.003 .' --,....._"'..... '." y. ......- \ . .' ~6-?8~·. .53.819 :, .'.6~~?g1;, . 70.316 :. '72:743 ...' . 73.371 ~,' ..:, . 73.161 . 73.891 .74.672' .;.~9,~23 69~818 . , 7·1.898 72~,093 ?9~ ?6~ .79..,89~ . 75.300 '.;·?5·;'3~7, 65.7Ò1 66.546 ß7.781 "67.~11 68.691 : 6f¡.778 69.623 ., 70;'576 ..J5..~g~ " 75.712' ' t$jt::.r~;t[~!}Gt;,~'t·;,;i~;tt~~\*erane 191 H31S (;31 22S 17a(H) hopane 1~+.:·,ª/8~'1,ij;~~;¡Mi;;':;/':,·Q~~I%êili;,22R 17 a.<H)' hopane 191 GAM gammaceranø 191 H~2S C32 22S 17a(H) hopane .... .. .~.;,...~...- ...'..,.......~,...~.~.....' ,.~. ···"·...1·· ...,~. ..,~ '~""~'''''','' "';j,''':~ ..~.,.",.'.' . 191 . H32R 'Ç3222R·17.a(H)hcii)a~e~·' ':,"'. . '. 191 H~3~ ~322.S.17a(H);~o.pa.~.è , 191" . .~.33R :.'. Ç~.3 ?2R¡17a.{t-:Q Þ<?r?~.ne..~:. 191 H34S 634225 17a(H) hopane . ..' ..' ~ ~'l" . . . .", .... ." . .... " '.:...". ".~. ':.....,- ." ".," r- 'II.! ,:,.' 191 H34~' . . .C3.4.22R·17a(t-n .hop~tle , . .....,. 191 H~5S;. . ~.3~.~2S17~(H).~~P?~,~.,. 191 ·H35R'. -:~3522.R .17a(H)hoparie. 217 S21 C21 st~rarJe. : ,',....., 217 . DIf.27S. 'C;?7 ßa"20~.di~ster~ne . 217 C27R C~7 aa 2,?R~te¡'~n.e.. 217 C28R C28 aa-?~R st.~.rarie· 217 C29S C29 aa 20S ~terane' 217 C29BBR .:C29.ß'ß~OR ~t~;~~è(+·~·ßacir'.'~'· ' 217 C29BBS,C29 ßß.~O~ ~te~a~e, 217 C29R . C29 aa:iORsterane' 21 ~ C27 ABBR : .927 ßß 29R ,stera.n~,_ 218 C27Aß~~ . . C27 ßß. 20Ssterarie , 218 . C2,8;A.sBR C2~ ßß 20~,steran~. 218 . C28ABB$ . C28 ßß 20S .sterane 218. ë29ABBR. . C29 ßß~~R st~ra~e 218 .c2,9AB~S . '(;29 ßß 20S sterane 218 C30ABBR C30 ßß 20R sterane " .., ": ' ~~, , I'" ", . 218 C30ABBS' C30ßß 20S ~terane 259 027S C~7. ßa 205 diastera.n~ 259 . . ·E.>27R. ·C??ßa2ÓR~iasterane. . 259 028SA C2~ ßa20s. diast~ra~~ a 259 '.D28SB . C28ßa29S diasteranéb 259 b28RA , (;28 ß.a 20R diaste!~f:I. e.' 'a, 259" D28RE;1 'C28 ßa 20Rdiastercmeb 259 D29S . C29. ßa. ~O, S. diastera~e. . 259 .., 0,29R:· . C29· ß(l20R diasterane 259 C3~TP1 . . C.30t~tracy~!ic P'?lyp~~n~.i9.. 259 C30TP2 .': C3Q tetracyç:lic polypr~hdid. ' .... I . . . . [ : . ',. I I I I ( Peak Compound Ret. ppm ppm on label Name Time Area . (Area) (Hght) ··Cliehf·IP·:··· ·O$·1.3401Ø::;·· Prp:ject #= 04-~~3-Þ<' . LctÞ n)t CP272$ß4. File Name: M2040611.D ·CQNö:CQÞHïLIJp$.· ..' . PLACER 1 7556.5 - FT . Company: Well Name: Depth: Sampling Point: I I Steroids Òfo~27 o.ßßS (218) , ,32.9 34.ß %C28 aßßS (218) . 29.5 . 29.3 %C29 aßßS (218) 37.7 36.1 C27/C29 (aßßS) (218) 0.87 0.96 C28/C29 (aßßS) {218) 0.78 0;81 C29/C27 (o.ßßS) (~18) 1.15 1.04 %C2! o.o.aR (217) 33.3 3à9 OfoC28o.åaR (217) 28.7 20.5' %C29 o.aaR (217) ,.. 38.0 ' 39.6' SIR (C29 aa.a) (217) 1.12 0;88 S/(S+R) (C29 ac:ta) (217) 0.53 0.47 ßß/(~a+ßß) (C~9)(217) 0.51 0.59 aßßS/aaaR (C29)(~17) 0.87. (C?1 +C22)/(C27+C28,~C29) (21,7) 0.19 0.21 Diaster/aao. Ster (C27) (217) 1.43 1.92 Terpenoids C19/C23 Tricyclict~rpanes 0.09 0.07· C23/C24 Tricyclic terpan'es 1_85 1.79 C26/C25 Tricyclic terr:?anes 0.82 0.82 C24 TetracyclidG26 Tricyclics 0.57 0.53 C24 T etr~cÿ¢Ii¢lHQP~ne . ¡ Q,o,g 0,0$ T srr m trisnorhopanes 0;74 0;74. Ts/(Ts+ Tm) trisnorhopanes 0.43 0.42 C29Ts/¢29 Hòp~h~, 0.30 Ò.3P, Bisnorhopane/Hopane 0.06 CUJ3 . NorhopanelHopane 0.,59 0.58 DiahopanelHopahe O,Öå ' 0.07.' Oleanane/Hopane Gammacerane/Hopane 0,(16 '0;05 Moretane/(Moretane+Hopane) 0.10 0.09 H32 S/(S+R) Homohopanes (),q8 O.sa H35/H34 Homohop~nes 0.85 0.75 [Steranes]/[Hopanes] 0.18 0.14 [rricyclic terpanes]/[Hopanes] 0.41 0.44 [r ricyclic terpanes]/[S~eranesJ 2.24 3.10 ..'''.:....'..'...''.....'......,...'.";".:..:':.:.'.'......:..',....'...,..'....'.'.:.... .....,.',.,.'.;.. . .. ""'." .. ",' Miscellaneous 'lj$1~4Ø19 . 04"~?$'-A" ¢þ~7Z~ß4 M2Ö4()611.D 'þl'iéh~'lþ:" prdj~¢t i#= L~Þ ít>: . File Né:lrtie: ¢ÖþJþÇ(jÞHIL..Liþ$ PLACÉR 1 7 !i56.5 - ,FT Cprnpétny: W¢II Nëime: [)eptl1: Sampling Point: .---. r-~ -=-. ..........- ~ '""- - -- ~ ---~ ~ ~ ---- '-.... ~ Sampl e: US134019 1800Q Ion Mass 191 1 50 0 0_ 1 2 0 0 0_ 9000_ 6 0 0 å_ 3000_ ~""--Á- ~J....LvJ...-~ ~. ~. "'- \'M. ""lAJ;ij ,LJ ,} Vv I Á\",J..., J.A v...vvv~ 50'.0 60'.0 70',0 Retention Time (min) 80'.0 90',0 File: M2040611. D\data. InS Date & Time: 6 Aor 04 5: 04 om Sampl e: US134019 Ion Mass 191 1 500 o. 1 000 o. 5000. ~~~~~~ 69'.0 72'.0 75'. 0 78'.0 81'.0 84'.0 87'.0 Ion Mass 177 4000_ 3000. 2000. 1000. ~L ^----^-- 69. 0 72'.0 75'.0 78'.0 81'.0 84'.0 87'.0 Ion Mass 205 2000_ 1000. ~J~ 69'.0 72'. 0 75'.0 78'.0 81'.0 84'.0 87'.0 Ion Mass 163 3000. 2000. 1000. ~ .,., A. ~ ~ ,~vv'vwrJ'V\,.AJ '~ ~ \ ~ 69.0 72'.0 75'.0 78'.0 81'.0 84'.0 87'.0 Retention Time (min) ll~: M2040611. D\dllta. ms It" & Time: 6 Apr 04 5:04 pm Sa mpl e: US 1 34 0 1 9 3000. Ion Mass 217 i I I { I 'I 2000. lOO°vJ wW JJ. MAA· J ~jl M J tvJv· ~ 66'.0 68'.0 70'.0 72'.0 74'.0 76',0 Ion Mass 218 2000. 1000. ~~Wj~ ~lfvJL··~~L L 66'.0 68'.0 70'.0 72'.0 74'.0 76'.0 Ion Mass 259 1200. I 800. 400~vJ~'~~~ ,I 66'.0 68'.0 70'.0 72'.0 74'.0 76'.0 Ion Mass 231 600. 500. J I ' 200. ~,\,~\V~\;l~'V ~~ 400. 300. 66'.0 68'.0 70'.0 72'. 0 74'.0 76'.0 Retention Time (min) 1 ",lle: M2040611. D\data. ms lte & Time: 6 Apr 04 S: 04 pm Sampl e: Ion Mass 217 2000. 1500. 1000. 500. US134019 ~ 3000_ Ion Mass 218 2000. 1000_ ile: M2040611. O\data. ms He & Time: 6 Apt' 04 5: 04 pm 45'.0 45'.0 48'.0 48'.0 Retention Time (min) 51'. 0 51'.0 J~~IJMJw\~ 54'.0 57'.0 JIv,~..~~ 54'.0 57'.0 N CD I.C M I- N r-I C'ì N N o o q' M U") N r-I r-I q' N C'ì q' q' q'M I.C NI- OM I.C~LI) o q' N B . .~ ~~r~\ 20'.0 2 2, 0 24'. 0 I- r-I M N N o o q' ..; N q' o N N I- q' I.C ' I.C r-I M . ' N "'~~ ~~~~ ~ o r-I . U") '" N C'" r-I ,,...;~ N ~ r-I ,~ ~ 20. 0 22' 0 ' . 24.0 Retention Time (min 16'.0 IS'. 0 1 File: M2040611. D\data. Oate & Time: 6 IIpr Oq ;: Oq pm :1 3000. 2000. 1000. 16'.0 Ion Mass 193 SOOO. 6000. 4000. 2000. I ( I I I I I I I I I 4000. 5000. IS'. 0 U") r-I I- W N Ò I.C N wO NN U") W I.C IUl N r- C' 26'.0 2S'.0 0 I.C N . 0 I.CN NU") W N I ) ) M ) N r-I ~ a:i N --...J- ~ 26',0 2S'.0 I .' I 1 Sampl e US134 019 Ion Mass 123 6000. Fil e: Date M2040611 T irne: D\data. 'r 04 5 04 69.0 72'.0 75.0 78'.0 Retention Time minI 81 o 84 o 87 o 1 0 0 0_ o r- ill ro ill o ill CD CD ro <:r CD M r- OJ r- N N l1) CD . . ill <.DON rl NU)O . COr- uf'J r- r- 0P ,R' OJ Oj~ ~ ~~ ~~ ;~l/~ l1) rl ro ill N r- M M r- r- ~ M m l1) 'N roM r-ro ro r- r- (fI rl (T) . <:r o l1) ro . o ro l1) l1) r- u-) r- (T) H l1) CD r- 2 0 0 0_ Sa mpl e US134019 Ion Mass 177 4 000_ 3 0 0 0_ r- '-D ro "" r- l1) H r- <:r r- File: M2040611. D\data. ms Date & Time: 6 1\pr 04 - 1 0 0 0_ 2000_ 30 0 0_ 4 0 0 0_ 6000_ 7 0 0 0_ 5000_ 44 M N ~ E-< ----- Sampl e Ion Mass 191 US134019 - o 0'1 rl ~ E-< ~ 48.0 o N ~ E-< t-........... rl N ~ E-< -- 52'.0 Retention Time N N ~ E-< - minI 56'.0 co M 0'1 M o r--: r- ll) ~- q< ~ E-< - -.. ~ 0<41 <If) ~ ~~ E&< E-<(\D ~$! E-< rl 0 r- rl tÓ om 0 U) ~ M q.j 0 ~ tÓ --"'" .~~ 60.0 64',0 U) .--I (Y) :r:: o C') :r: (J) N :r: Sampl e US134019 1 8000_ Ion Mass 191 1 5 0 0 0_ 1 2 0 0 0_ 9000_ 6000_ ¡:¡; .--I C') :r: U) N (Y) :r:: ::;:: E-i ¡:¡; N (Y) :r:: .(/) 8 m 0J U (J) .--I C') a\ ro 1-^1----.. r--N Lf1Lf1 N'<1' roro roro I~I 8i.o U) Lf1 (Y) :r:: ¡:¡; '<1' C') :r: U) '<1' (Y) :r:: r-- Lf1 CD o (J) . Lf1 (') . 00 (Y) -",,~L 84 o p::; (Y) (Y) :r:: U) (Y) (Y) :r: o 81 min) 78'.0 Retention Time r-- '<1' (J) or--. (Y) co I.DN nL r~~ o fY) ::;:: 75',0 U) E-i D\data 'r 0 72'.0 pm ~ CD ¡:r¡ NCD ~ ~ E-i 5: 0 3000_ H20406 Time Fil e: Date 1 8 0 0_ 1 50 0_ 1 20 0_ 0) 900_ L!) q< ,...; L!) \0 0) 600_ 0 Ñ q< Ii) q< 0) OJ 0 co \0 Ñ OJ co r- M Ii) .--I 0 m Ñ OJ å å ,...; Ul Ul 10 10 L!) 300-L ~ ~ \ \ ~~. 51',0 52',0 53,0 File: M2040611. D\data. IDS Date , Time: 6 Apr 04 54 o 55',0 Retention Time minI 56 \0 ~ \0 M Ul t o 2100_ --- ---- ......-.-.. - Sampl e: US134019 Ion Mass 217 57 o - ....-- ..--. .-1 N UJ <:r .-1 o <:r I/) '-'" -~ -- m L!) co <:r L!) m q< 0 .--I <:r N . , lfl L!) 10 L!) <:r m m m 10 - m M co \0 10 m m o [- 10 co o N [- 10 ---. ""'9i::"_ -- ~ ---'" M N ) N \ a\ ) L!) '-i-- ~ 58.0 59.0 Sampl e: US134019 Ion Mass 217 1 800_ c3 ::r: u 1 5 0 0_ 1 200_ 900_ 600_ '<1' (Y) If) Qj N If) 1.0 1.0 N If) r- (V) If) 0 0 rl N (Y) Qj (Y) 1.0 1.0 1.0 1.0 .;. 1.0 300_ ,lV 60'. 2 60'. 9 61',6 62'. 3 Retention Time (min) 63'.0 63',7 64'.4 file: M2040611. D\data. ms Da te & Time: r 04 5: 04 em File: H2040611. D\data. InS Date & Time: 6 ADr 04 5: 0 66',0 68',0 70',0 7i,o Retention Time (minI co '<1' 0 rl 0 g:: q< -D 0 ' 40~~_Jyl ~ 800_ 1 200_ I"') 10 r-I t- \0 rl 00 t- r-: ro\O o \0 t- \0 ro r- t- oo ,-J> m .-I \0 \00 ' \0 01"') 0010 t- rl, \0\0 N , ro 00 . ~ ~~ \ ~ t I"') \0 (Y) m \0 \0 N 0\ '" 10 ~ ~ t- N U \ J I CD m CD r-I rot- \0 t- .-I t- ~ ~ Ç> ú)-I ~ ro ro N N r- \ I"') 00 ... Ñ r- ~ CD N U \ ; 1 en m N U '- ..., n q< .1"') n 10 r- \0 Ÿ 74 N N o '<1' {V) ~ o 'D 0 1<1 0 r- I"') , t- ... U"JX) r- r-M .0 r- (Y) 10 m 76',0 10 r- N \0 r- .-I r-I m t- \0 1 6 0 0_ I.D ... 10 I.D I.D ro r-I 00 m I.D I.D t- 10 o r- I"') m o N r- en p:¡ ffi N U p:; m N U ~ p:¡ p:¡ m N U 2 0 0 0_ U) t- N ,:( H Q 2 4 0 0_ f") N \D m I.D 2 80 0_ .-. .-- --- - Sampl e: US134019 Ion Mass 217 .--... ......-... ..---- .--- - - - -- - --- --- ~, rUe: Date H2040611 Time: D \da ta r 04 400~ ßOO_ 66', \D '<1' If) \D \D r-f '<1' '<1' u1 \D r-f o r- u1 \D - o 68 W\\ r-fr-f CO .-I r-C1\ r-:r-: \D\O o r-f o (Y1 CO \D r<) \D (T) .-1m r-f\D N l \D o r-f cé \D 1 2 0 0_ 70 o r-r<) 0'0<:1' ..-1 0'0 , \DO M o co r<) (T) óg r-'<1' o r- 12',0 Retention Time (min) r-f C'ì o r-f or- co co ° r- C'ì co <:!' If) \D r- N r- C'ì CJ) «) C'ì r- 14 _~' N r- \D '<1' r- () 76', 0 <'1 r-f t!) \D r- IÝU) a:ro ~ = r<T'ì cu \ ro ro N N r- p::; ø:\ ~ co N U 1 6 0 0_ U) p:¡ ¡:Q 0< co N U U1 p:¡ ~ I- N U U) p:¡ ~ N U 2000_ p::; Ç(\ ~ r- N U 2 4 0 0_ Sa mpl e: US 13 401 9 2800j~ ~ Ion Mass 218 p::; ¡:Q ø:\ ,:¡; <J\ N U File' M2040611.0\data. Date 'Time: 6 ADr 04 68.0 p:; r- 01 Q ~~ .- Sampl e US134019 Ion Mass 259 14 00_ U} r- ('\ Q 1 200_ 1 000_ BOO_ 600_ 400_ 200_ 66',0 (V) If) .-i n, Or- Ow r- \0 If) 0\- W ~ W r- w ;;¡III roOO ('\ro QN Q I ~ ro 01 Q ~ co 01 ,0 Iw co co 00 CXJ '-0 <1\ No ~ '- U) 0'1 01 o 70'.0 o "" co a\ '-0 \10 (V) o If) ~ ~ 0'1 01 Q -..- 7i.o Retention Time (min) ~ --~ ~~ -- rl If) '-0 (V) !' If) c>1 01 W !' A< !' !' ME-< !' rl "" A<o 0'1 .;. E-<(V) co If) ~u M !' M U~ r- r- .;. l r- ~ 74'.0 76'.0 ro M rl rl r- ~ CXJ (V) 0'1 rl N 01 r- r- N r- - ~ GCMS/MS ANAL YSIS DGSI ANALYTICAL LABORATORIES .,1 r ,I. ( I 1 ; I II I I I I I SATURATE GCMSMS -wíJ RESULTS SATURATE GCMSMS ANALYSIS CLIENT ID: US134018 FRACTION SATURATE BASELINE ID: CP272563 DATAFILE: MS040183.D I I I Ii It! .!~~-~I:;J:fJ¡,_,9,~.~ I Company: CONOCOPHILLlPS Country: UNITED STATES Basin: NORTH SLOPE Lease: Block: Field: Well Name: PLACER 1 Latitude: Longitude: Project #: LablD: Client ID: Sample Type: Sampling Point: Formation: Geologic Age: Top Depth: Bottom Depth: SATURATE GCMSMS r ( 04-223-A CP272563 US134018 OIL EARLY CRETACEOUS 7558 FT FT 358->217: C26 Steranes MS040183.D -. Ie (on Areaf Appl~ TEV;$ ..te .~- .~~7'.$t¢f~'Ö~~'.'··": %28 Steranes ;%2~Stê~~høs' , %27 Diasteranes %2äpia~t~råhés: " %29 Diasteranes <,:,:' :' " ,:~'~ :: . ~:. ,'.' ':. . . ·á1..2 ' 29.2 ~.9.6 33.3 " ·2f3.å 39.9 'D" D 0: D :D D . ,..,': ~-J>w",JJwI .,,"~ D C30 Sterane Index 0.10 ¢3p~j,sç~&frirqþYI::~'~r~r~.J~ø~~·. .......,.. .';O,Q.$,:··. C2t,dØß?(~ix(i-tftßØ)'i'" " C28 aßß/(aaa+a.ßß) 629' ~Pß/(~a~+~ßß) C30 aßß/(aaa+a.ßß) C27,$Î(S*f{) C28~/(~~R) ',," . Ç2~,Sj(~tRf ' C30 r 414->217: C30 Steranes I 'iiO::64'" 0.69 M O:S4"M 0.60 M ,,0.48,' 0.46 0,'54 0.37 I t<' .-..JL~~L~. Diasteranes/Steranes 1.12 ......... I 24~NO,~di~~hol~st~n,e ra~,io (NDR) 24;.~érçþ()le~ta,I1,~·i'a~io(N<f~) · 21-Norcholestane ratio 0.15 A 0.26' 'A 0.13 DIM 414->231: C30 Methylsteranes A fi.,' ( Dinosterane ratio 4~'~~tbyì~~¢r~pe:rØtio,. , .,'. , 0:0.8 ~ lAJw ~ ~}VI\ Ol~~~~~~,}~~e~(~): i' :;' ..' bè~Þ:..·'.91~~.nap.~'·:·lpq,ª>c,",,(,~~),· ~~~~~7~ran~ Inde~ ~%) '~ica~ih~ríe'l¡'de~:(?&). ',' ' DiaHopan~ Index (%) JPP',:,,,· I"~~ ,:'.": 3.4 0:04· 10n response factored areas. Definition and utility of the ratios can be found on our website www.BaselineDGSl.com 2A=Source Age; D=Depositional environment; M= Maturity ~hermal equilibrium value of the biomarker ratio and in brackets the approximate VR value at which this value is reached 0.6 A . ";'·,'·Ä..'.·(' . D .·ND o ..Q Company: Well Name: Top Depth: Bottom Depth: Acquisition Parameters: CONOCOPHILLlPS PLACER 1 7558 Client 10: Lab ID: FT Fraction: FT File Name: A SAT 0.2UL 1000_1 RES 70EV 700UA 250C AR=4E-7MBAR CE=2 US134018 CP272563 SATURATE MS040183.D Peak Label .. nil Area Area Res. Count ppm ~ -". ø 330.3"':'>217.2: Internal Standard ISTD 5ß-Cholane 49.542 2439527 100.0 100.0 358~3';">217 .2:C26 DesmethylstèraÌ1es D26N24baS 13ß.17 a.24-nordiacholestane 20S 50.643 47477 1.9 1.9 D26N24baR 13ß.17 a,24-nordiacholestane 20R 51.720 36653 1.5 1.5 D26N27baS 13ß.17 a.27 -nordiacholestane 20S 52.540 263555 10.8 10.8 D26N24abS 13a.17ß.24-nordiacholestane 20S 52.751 14317 0.6 0.6 D26N24abR 13a.17ß,24-nordiacholestane 20R 53.383 51186 2.1 2.1 D26N27baR 13ß.17 a.27 -nordiacholestane 20R 53.618 207464 8.5 8.5 D26N27abS 13a.17ß.27 -nordiacholestane 20S 54.648 75823 3.1 3.1 D26N27abR 13a.17ß,27 -nordiacholestane 20R 55.210 103520 4.2 4.2 S26N24aaaS Sa, 14a, 17 a.24-norcholestane 20S 56.265 27115 1.1 1.1 S26N24abbR 5a.14ß.17ß.24-norcholestane 20R 56.475 70557 2.9 2.9 S26N24abbS 5a.14ß,17ß.24-norcholestane 20S 56.850 45604 1.9 1.9 S26N24aaaR 5a.14a, 17 a.24-norcholestane 20R 57.553 54065 2.2 2.2 S26N21 21-norcholestane 57.740 115442 4.7 4.7 S26N27baaR 5ß.14a, 17 a.27 -norcholestane 20S 57.928 29012 1.2 1.2 S26N27aaaS 5a.14a.17a.27-norcholestane 20S 58.022 117985 4.8 4.8 S26N27abbR 5a.14ß, 17ß.27 -norcholestane 20R 58.209 177879 7.3 7.3 S26N27abbS 5a.14ß, 17ß.27-norcholestane 20S 59.240 138844 5.7 5.7 S26N27aaaR 5a.14a.17 a,27 -norcholestane 20R 59.240 120070 4.9 4.9 372~3~:>217 .2:.G27' Desmethylsterånes D27baS 13ß.17 a-diacholestane 20S 54.648 3845167 157.6 84.3 D27baR 13ß.17 a-diacholestane 20R 55.960 2470674 101.3 73.1 D27abS 13a, 17ß-diacholestane 20S 56.944 901595 37.0 17.1 D27abR 13a.17ß-diacholestane 20R 57.623 1274577 52.2 37.7 S27aaaS 5a, 14a.17 a-cholestane 20S 60.270 1129803 46.3 22.7 S27abbR Sa, 14ß, 17ß-cholestane 20R 60.598 1404539 57.6 45.7 S27abbS 5a.14ß.17ß-cholestane 20S 60.903 1098334 45.0 39.3 S27aaaR 5a.14a.17 a-cholestane 20R 61.699 1056036 43.3 24.4 386.4->217 .2:C28Desmethylsteral1es·' D28baSA 13ß.17a-diaergostane 20S (24S) 57.787 1130507 46.3 35.8 D28baSB 13ß.17 a-diaergostane 20S (24S) 57.975 1164330 47.7 38.0 D28baRA 13ß.17 a-diaergostane 20R (24R) 59.240 781436 32.0 21.5 D28baRB 13ß,17a-diaergostane 20R (24R) 59.380 823005 33.7 31.2 D28abS 13a, 17ß-diaergostane 20S 60.153 613901 25.2 25.2 D28abRA 13a, 17ß-diaergostane 20R 61.043 441573 18.1 18.1 D28abRB 13a, 17ß-diaergostane 20R 61.161 343690 14.1 14.1 C28UNK9 C28 Unknown 9 61.934 443461 18.2 18.2 S28aaaSA 5a.14a.17a-ergostane 20S 63.620 235593 9.7 8.3 S28aaaSB 5a,14a.17a-ergostane 20S 63.761 276119 11.3 9.1 S28baaR 5ß,14a.17a-ergostane 20R S28abbR 5a,14ß.17ß-ergostane 20R 64.136 1022044 41.9 49.5 S28abbS Sa, 14ß.17ß-ergostane 20S 64.417 730134 29.9 36.1 S28N21 21-norstigmastane 64.862 143201 5.9 5.9 S28aaaR 5a,14a.17a-ergostane 20R 65.400 577649 23.7 20.5 Company: Well Name: Top Depth: Bottom Depth: Acquisition Parameters: I CONOCOPHILLlPS PLACER 1 7558 Client ID: Lab ID: FT Fraction: FT File Name: A SAT 0.2UL 1000_1 RES 70EV 700UA 250C AR=4E-7MBAR CE=2 US134018 CP272563 SATURATE MS040183.D Peak label Compound Retention Area Area Resp fact . , " ", , , ,Time Countpp, m Î '. .. II 4ØO~~>217.2:¢29Desmèt~y!sieI'åÍlê~:·,~ D29baS 13ß, 17 a-diastigmastane 20S D29baR 13ß, 17a-diastigmastane 20R D29abS 13a,17ß-diastigmastane 20S D29abR 13a, 17ß-diastigmastane 20R C29UNK5 C29 Unknown 5 S29aaaS Sa, 14a, 17 a-stigmastane 20S S29abbR 5a, 14ß, 17ß-stigmastane 20R S29baaR 5ß,14a,17a-stigmastane 20R S29abbS Sa, 14ß, 17ß-stigmastane 20S S29aaaR Sa, 14a,17 a-stigmastane 20R I I I " , 4-14~4-:c>217 .2:C3JDe$methYlstêtàn~$ 60.622 2694178 110.4 103.8 62.191 1771084 72.6 84.9 62.800 586195 24.0 24.0 63.995 948730 38.9 38.9 64.745 656686 26.9 26.9 66.431 736485 30.2 32.4 67.017 905193 37.1 56.6 67.228 888024 36.4 50.2 68.446 737255 30.2 28.1 62.871 199632 8.2 11.1 62.964 249294 10.2 16.1 64.581 318246 13.0 22.5 64.932 53520 2.2 2.2 65.096 52628 2.2 2.2 66.384 159624 6.5 6.5 66.876 64671 2.7 2.7 67.040 36632 1.5 1.5 67.204 50263 2.1 2.1 68.680 132784 5.4 7.1 68.867 36702 1.5 1.5 69.078 16752 0.7 0.7 69.429 157961 6.5 14.0 69.547 172437 7.1 15.7 69.664 45935 1.9 1.9 69.898 21566 0.9 0.9 70.952 168593 6.9 12.3 71.116 14106 0.6 0.6 71.233 8460 0.3 0.3 72.193 12708 0.521 0.521 56.148 83450 3.4 3.4 56.944 91873 3.8 3.8 57.530 74982 3.1 3.1 57.764 31794 1.3 1.3 58.303 65933 2.7 2.7 58.724 320938 13.2 13.2 60.060 162623 6.7 6.7 61.816 137279 5.6 5.6 62.191 132571 5.4 5.4 62.472 148252 6.1 6.1 63.011 110529 4.5 4.5 63.152 237041 9.7 9.7 63.222 56224 2.3 2.3 63.433 179937 7.4 7.4 64.370 132835 5.4 5.4 65.377 23806 1.0 1.0 I D30nPbaSA D30nPbaSB D30nPbaR D30nPabSA D30nPabSB D30nPabR DC30UNK7 DC30UNK8 DC30UNK8A S30nPaaaS C30UNK10 S30iPaaaS S30nPabbR S30nPabbS S30nPbaaR S30iPabbR S30nPaaaR C30UNK14 S30iPaaaR C30UNK16 I I 13ß, 17 a-dia-24-n-propylcholestane 20S 13ß, 17 a-dia-24-n-propylcholestane 20S 13ß, 17 a-dia-24-n-propylcholestane 20R 13a, 17ß-dia-24-n-propylcholestane 20S 13a, 17ß-dia-24-n-propylcholestane 20S 13a,17ß-dia-24-n-propylcholestane 20R dia-C30 Unknown 7 dia-C30 Unknown 8 dia-C30 Unknown 8A Sa, 14a, 17 a-24-n-propylcholestane 20S C30 Unknown 10 5a, 14a, 17a-24-iso-propylcholestane 20S Sa, 14ß, 17ß-24-n-propylcholestane 20R 5a,14ß,17ß-24-n-propylcholestane 20S 5ß,14a, 17 a-24-n-propylcholestane 20R 5a, 14ß, 17ß-24-iso-propylcholestane 20R 5a,14a, 17a-24-n-propylcholestane 20R C30 Unknown 14 5a, 14a, 17 a-24-iso-propylcholestane 20R C30 Unknown 16 I 38~.4Ç->231.2:C2~lVIethylsteranl!s , l D283MbaS DC28UNK16 D283MbaR DC28UNK3 DC28UNK17 D284MbaS D284MbaR S283MaaaS S283MabbR , S283MabbS S284MaaaS S284MabbR S283MaaaR S284MabbS S284MaaaR XS28aaaR 3ß-Methyl-13ß, 17a-diacholestane 20S dia-C28 Unknown 16 3ß-Methyl-13ß, 17a-diacholestane 20R dia-C28 Unknown 3 dia-C28 Unknown 17 4a-Methyl-13ß, 17 a-diacholestane 20S 4a-Methyl-13ß,17a-diacholestane 20R 3ß-Methyl-5a, 14a, 17 a-cholestane 20S 3ß-Methyl-5a, 14ß, 17ß-cholestane 20R 3ß-Methyl-5a, 14ß, 17ß-cholestane 20S 4a-Methyl-5a, 14a, 17 a-cholestane 20S 4a-Methyl-5a.14ß,17ß-cholestane 20R 3ß-Methyl-5a, 14a, 17 a-cholestane 20R 4a-Methyl-5a,14ß.17ß-cholestane 20S 4a-Methyl-5a, 14a, 17a-cholestane 20R Sa,14a,17a-ergostane 20R Company: Well Name: Top Depth: Bottom Depth: Acquisition Parameters: CONOCOPHILLlPS PLACER 1 7558 Client ID: Lab ID: FT Fraction: FT File Name: A SAT O.2UL 1 000_1 RES 70EV 700UA 250C AR=4E-7MBAR CE=2 US134018 CP272563 SATURATE MS040183.D Peak Label Compound ' Retention Area Area' . Time Count ppm mo. . -. .. 'I . . ... 400.4->231.2: C29 Methylsteranes D293MbaSA 3ß-Methyl-13ß ,17 o.-diaergostane 20S 59.193 24277 1.0 1.0 D293MbaSB 3ß-Methyl-13ß,170.-diaergostane 20S 59.404 21946 0.9 0.9 DC29UNK27 dia-C29 Unknown 27 59.966 45786 1.9 1.9 DC29UNK28 dia-C29 Unknown 28 60.177 37211 1.5 1.5 D293MbaRA 3ß-Methyl-13ß.170.-diaergostane 20R 60.762 18373 0.8 0.8 D293MbaRB 3ß-Methyl-13ß.170.-diaergostane 20R 60.903 21427 0.9 0.9 D294MbaSA 40.-Methyl-13ß.170.-diaergostane 20S 61.816 132771 5.4 5.4 D294MbaSB 40.-Methyl-13ß,170.-diaergostane 20S 62.004 141119 5.8 5.8 D294MbaRA 40.-Methyl-13ß,170.-diaergostane 20R 63.269 77301 3.2 3.2 D294MbaRB 40.-Methyl-13ß,170.-diaergostane 20R 63.386 99243 4.1 4.1 D294MabS 40.-Methyl-130., 17ß-diaergostane 20S 64.159 96549 4.0 4.0 D294MabRA 40.-Methyl-130.,17ß-diaergostane 20R 65.026 69366 2.8 2.8 S293MaaaSA_4abRB 3ß-Methyl-50.,140.,170.-ergostane 20S + 65.119 97412 4.0 4.0 4a-methyl-13a,17b-diaergostane 20R S293MaaaSB 3ß-Methyl-50.,140..170.-ergostane 20S 65.283 50195 2.1 2.1 S293MabbR 3ß-Methyl-50.,14ß,17ß-ergostane 20R 65.658 68264 2.8 2.8 S293MabbS 3ß-Methyl-50., 14ß, 17ß-ergostane 20S 65.939 91348 3.7 3.7 S294MaaaSA 40.-Methyl-50.,140.,170.-ergostane 20S 66.291 42649 1.7 1.7 S294MaaaSB 40.-Methyl-50..140., 17 a-ergostane 20S 66.408 67344 2.8 2.8 S294MabbR 40.-Methyl-50.,14ß,17ß-ergostane 20R 66.619 132616 5.4 5.4 S294MabbS_3MaaaR 40.-Methyl-50., 14ß, 17ß-ergostane 20S + 66.900 205726 8.4 8.4 3b-Methyl-5a,14a, 17a-ergostane 20R S294MaaaR 40.-Methyl-50.,14a,170.-ergostane 20R 68.001 85273 3.5 3.5 XS29aaaR 50.,140.,17 a-stigmastane 20R 68.446 36435 1.5 1.5 414.4-->231 ~2: C30· Methylsteranes S302MaaaS 20.-Methyl-50., 140., 17 o.-stigmastane 20S 67.415 32882 1.3 1.3 S303MaaaS 3ß-Methyl-50..140.,17a-stigmastane 20S + (coelution) 67.884 156165 6.4 6.4 S302MabbR 20.-Methyl-50..14ß.17ß-stigmastane 20S + (coelution) 68.071 29836 1.2 1.2 S302MabbS 20.-Methyl-50.,14ß,17ß-stigmastane 20S 68.212 15744 0.6 0.6 S303MabbR 3ß-Methyl-50.,14ß,17ß-stigmastane 20R 68.493 101596 4.2 4.2 BBDINO ßß-dino (?) S303MabbS 3b-Methyl-5a,14b,17b-stigmastane 20S + (coelution) 68.703 105375 4.3 4.3 S304MaaaS 40.-Methyl-50.,140., 17 a-stigmastane 20S 69.031 59434 2.4 2.4 S304MabbR 40.-Methyl-50..14ß,17ß-stigmastane 20R 69.429 84267 3.5 3.5 S304MabbS_2MaaaR 40.-Methyl-50..14ß.17ß-stigmastane 20S + 69.664 110596 4.5 4.5 20.-Methyl-50.,140.,170.-stigmastane 20R + (coelution) S303MaaaR 3ß-Methyl-50.,140., 17 o.-stigmastane 20R + (coelution) 69.874 97999 4.0 4.0 DS4aSS20R 40.,23S,24S-trimethyl-20R-cholestane DS4aSR20R 40..23S.24R-trimethyl-20R-cholestane S304MaaaR 40.-Methyl-50..140., 17 o.-stigmastane 20R 70.975 59756 2.4 2.4 DS4aRR20R 40.,23R.24R-trimethyl-20R-cholestane DS4aRS20R 40.,23R,24S-trimethyl-20R-cholestane Company: Well Name: Top Depth: Bottom Depth: Acquisition Parameters: CONOCOPHILLlPS PLACER 1 7558 Client ID: Lab ID: FT Fraction: FT File Name: A SAT 0.2UL 1000_1 RES 70EV 700UA 250C AR=4E-7MBAR CE=2 US134018 CP272563 SATURATE MS040183.D Peak Label Compound Retention Area Area Resp fact , , " , , . ,',' ' , " ,Time ., Count , ppm, "". Î - < .. II 41~.4->259.2: 'Tetracytlit '.,polyprel1ôlas:.andC3qáßpr()pYlst~ra~ê~:: S303PaaaS 3ß-Propyl-5a, 14a,17 a-cholestane 20S 69.781 20427 0.8 0.8 PP1 Tetracyclic polyprenoid 69.921 20179 0.8 0.8 t PP2_S303PabbR Tetracyclic polyprenoid+ 3ß-propyl-5a,14ß, 17ß-cholestane 20R 70.085 43218 1.8 1.8 S303PabbS 3ß-Propyl-5a.14ß,17ß-cholestane 20S 70.366 20567 0.8 0.8 S303PaaaR 3ß-Propyl-5a,14a,17 a-cholestane 20R 71.139 20475 0.8 0.8 ( 414á~j 1'91~·~:.' 'Pentacyc:lic: Tritetpel10ids REARNGHOP Rearranged hopane 63.550 77380 3.2 3.2 OLEANOID13 5(4~3)abeo-3a(H) 5ß-Oleanane I TRITERP14 C30 unknown triterpane 66.970 18326 0.8 0.8 OLEANOID15A Oleanoid OLEANOID15 Oleanoid OLEANOID16 Oleanoid C30UNKT2 5(4~3)abeo-3ß(H)-Oleanane 68.094 78610 3.2 3.2 OLEANOID17 3ß-methyl-24-nor-1 (1 0~5)abeo-1 Oß(H), 18a-oleanane 68.493 19763 0.8 0.8 TRITERP17 A C30 plant terpane ( DH30 Diahopane 69.102 293414 12.0 12.0 TRITERP18 C30 unknown triterpane 69.570 23596 1.0 1.0 OL 18a 18a Oleanane OL 18b 18ß Oleanane H30ab 17a,21ß-Hopane 71.116 3646485 149.5 345.7 H30N30 30-Norhomohopane 71.373 183570 7.5 7.5 H30TS 18a,17ß-Neohopane 71.748 301070 12.3 12.3 H30aa 17a,21a-Hopane 72.006 115551 4.7 4.7 H30ba 17ß, 21a-Hopane (Moretane) 72.310 221082 9.1 29.4 GamA Gammacerane-A 74.980 103993 4.3 1.9 GamB Gammacerane-B 75.097 21748 0.9 0.3 414:2.,..>313~3:.Bica'dil1an~s B30W Bicadinane W (cis, cis, trans) I B30T Bicadinane T (trans, trans, trans ) B30T1 Bicadinane T1 B30R Bicadinane R ,27~~3-:>203;2:".NØrpregl1anes NORPREG1 Norpregnane-1 ( NORPREG2 Norpregnane-2 NORPREG3_ 4 Norpregnane-3+Norpregnane-4 30.216 33992 1.4 1.4 NORPREG5 Norpregnane-5 NORPREG6 Norpregnane-6 30.755 35936 1.5 1.5 I NORPREG7 Norpregnane-7 31.294 12213 0.5 0.5 NORPREG8_9 Norpregnane-8+Norpregnane-9 31.809 100423 4.1 4.1 NORPREG10 Norpregnane-10 32.090 25209 1.0 1.0 NORPREG11 Norpregnane-11 32.793 50255 2.1 2.1 NORPREG12 Norpregnane-12 33.566 8378 0.3 0.3 Company: Well Name: Top Depth: Bottom Depth: Acquisition Parameters: CONOCOPHILLlPS PLACER 1 7558 Client ID: Lab ID: FT Fraction: FT File Name: A SAT 0.2UL 1 000_1 RES 70EV 700UA 250C AR=4E-7MBAR CE=2 US134018 CP272563 SATURATE MS040183.D Peak Label Compound ' Retention , Time Area Area Resp fi· Count ppm, Î -. · ~ ~ 33Q,.3,~~~1,.~:T~~r..~yc:lit::s", " OesAOL Oes-A-Oleanane OesALUP Oes-A-Lupane OesA T ARAX Des-A- T araxastane DesEHOP Des-E-Hopane 48.956 50.385 128508 538999 5.3 22.1 5.3 22.1 41 ó.4d~18.2:, ,r.no~b~risåtÜr~t~dC3ÔP~rit~hYcÎic,irltei:peno.iCJs Bicadinene Bicadinene OL 1318ene OL 12ene OL 18ene 0L12ene18a Un~Peak1 Olean-13(18)-ene Olean-12-ene Olean-18-ene 18a -Olean-12-ene Unknown peak 1 426;+>2Ò5~2:', C31Pel1~cycliètrit~rp~~9ids" H312Mab C312a-Methylhopane H31abS C31 22S 2a-Methylhopane H31 abR C31 22R 2a-Methylhopane H313Mab C31 3ß-Methylhopane 71.350 50446 2.1 2.1 74.348 300589 12.3 12.3 74.723 241494 9.9 9.9 75.144 57916 2.4 2.4 Parameter (Area) Formula Steranes %~7Steranes(372.,.>217,386.,.>217,400.,.>217) %C28 Steranes (372->217,386->217,400->217) I' %C29 ,Steranes(372->217 ,386..;>217;400"~217.) , %C27 Diasteranes (372->217,386->217,400->217) I %C28 Diasteranes (372.,.>217,389->217,400:'>217) %C29 Diasteranes (372->217,386->217,400->217) I C30Steran¢ Index '(414-;:"217) I C30iso/n-propyl Steranelndex(414->217) 027. aßß!~~ag.+àßß)i(3~~.,.>21?) ..' ' ~28 .a~ß/(aa,a+a~~),(386~>2~7) 'Ó29 : tißß/(aaa+<xßß) '(400':>217) C30 aßß/(a~~+aßß) (414->217) 027 S/(S+R) .(;372->217) ~8 S/(S+R) (386->217) C29 S/(S+R) (400.,.>217) C30 S/(S+R) (414->217) I 24~NordiäêhÓìestane.·Ratio. (NOR) ';(3'58->217) 24-Norcholestane Ratio (NCR) (358->217) 21.,.N?rC:holestane Ratio (358.;>217) ( DinosteraneRatio (414->231,)' I 4-Methyl Sterane Ratio (400->217,414->231) Terpanes Qie~n~rlË{lhdex(%)(412.,>191) Gammacerane Index (%) (412->191) Qi~hopanelndex(%) (412->1'91) Bicadinane Index (%) (412->191,412->369) DesA Olèanane,lndex(%) (330->191)' TPP (358->217,414->259) I [ [ 1 00*(S27.aaaS+S27 abbRrS27abbS+S27aaaR)/(S27 aaaS+S27 abbR+S27abbS+S27aaäR+S28 aaaSA+S28aaaSB+S28abbR+S28abbS+S28aaaR+S29aaaS+S29abbR+S29abbS+S29aaaR) 1 00* (S28aaaSA+S28aaaSB+S28abbR+S28abbS+S28aaaR)/(S27aaaS+S27abbR+ S27abbS+S27aaaR+S28aaaSA+S28aaaSB+S28abbR+S28abbS+S28aaaR+S29aaaS+ S29abbR+S29abbS+S29aaaR) 1 00*(S29aa~S+S~9abbR+S29abbS+S29~aØ~)/(S2!a~aS+S?7élþbR+S27à~bS+S27åaaR+S28 . aaaSA+S28aaaSB+S28ªþbR+S28abbS+~28~aäR~S29aaaS+S29abbR+S29abb$+S29aaaR)' 1 00* (D27baS+D27baR)/(D27baS+D27baR+D28baSA+D28baSB+D28baRA+D28baRB+ D29baS+D29baR) 1 OO*(D28baSA±D28baSE3+028baRA+D28b8RB)/(D27baS+[)27baR+P28b8SÅfD28baSB+ 028 baRA+D28baRB+D29baS~D29baR) , " 1 00*(D29baS+D29baR)/(D27baS+D27baR+D28baSA+D28baSB+D28baRA +D28baRB+ D29baS+D29baR) " ", :. '. , , . (S30N.RaaaS+S3(l~pabb~+$3QNP~þbS'+s3()NPa.a~R)/(S27aa~s+S27abbRt$27'~bb~+ . S27aaaR,+~.?~aa.aSA-I;S48~aa~§+~28abÞ~+S28abþ~fS28aa.élR+S2~,aaaS+S29abbR+ S29abqS+S2~a~aR+S3Q~Pélaà9+§30tiJp~þþRt,$3PNRåbb,s+sàQ~p~~~R)" ., (S30iPaaaS+S~OiPaaa,~~~(~.~.~N~a~,a~,+~3,~~,~aa~,Ô~.~3?iPa~aS+S30iPaaaR) );.(S27aÞÞR+.S27~bb$)/(~.??å:a~S~S27~ÞÞRt~~i~b~§+S27aaaR . ,..(S28abbR+S~~~bb~)~~~28a~aS~"'~28aa~SB+S28abbR+S28abbS+S28aaaR) (S29abbR+S29ábþS)/(S29aáë!$+S29aÞbR+94ßaqbS+S29aaaR) (S30NPabbR+S30NPabb~.)/(S30NPaaaS+S30NPabbR+S30NPabbS+S30NPaaaR) , S27é1aaS/(S27aaa$+S27aaaR) (S28aaaSA+S28aaaSB)/(S28aaaSA+S28aaaSB+S28aaaR) S29aaaS/(S29åaaS*S49aaa~) (S30NPaaaS)/(S30NPaaaS+S30NPaaaR) (D27baST~27b,åR:+-P?ß~á$,~~p~~þasš~q~~baRA~q2.~Þ~RB+D~9~élS~Ö2~Þ~Bl,.,. ' .(S;27aaaS"'§27~bbRfS??~Þ.~.9+§27ë!~,~~S~$.~~CI~~+S28.~,aaSa+$2?abbR~:S2~abb.S: . S28aaaR+S29äaa$+S2,$ab:)g~S2·~ªbþ.9o¡.§?ª~àáRj: " ' .... . . ,. '(D26N24baSfD26N24bC!rW([)2'é¡N2~båS¡D26N24b~R:I-[)26N2j'ba$+b26N?7båR) (S26N24aaaS+S26N24abbR+S26N24abbS+S26N24aaaR)/(S26N24aaaS+S26N24abbR+S26N 24abbS+S26N24aaaR+S26N27aaaS+S26N27abbR+S26N27abbS+S26N27aaaR) S26N211(S26N21. +S2~~24C1~aS+S26N24,~þÞR+$'~6N24abbS+S26N24äaaR+ S26N27aaaS+S?6N27é1QbR+S26N27abbS+S26N27aaaR) , (bS4aSS20R+DS4aSR~0.R~DS4~R~20~tpS4aR$2QR)/($303MaaaR+DS4aSS20Rë+- DS4áSR20R+D,S4é1.RFµOR+DS4:åR~~QR). S304MaaaR/(S29aaaR+S304MaaaR) 1 OO*(QL 18a+OL 18b)/(H30äb+OL18à+OL1Sb) 1 OO*(GamA+GamB )/(H30ab+GamA+GamB) 1 00*DH30/(DH30+H~Oab) 1 OO*(B30T ~B30T1 +B30R)/(H30ab+B30T +B30T1 +B30R) 100*DesAOU(DE!sAOL +DesEHOP) (2*PP1 )/(2*PP 1 +D26N27baS+D26N27baR+S26N27aaaS+S26N27abbR+S26N27abbS+ S26N27aaaR) Sample: US134018 60000. Ion Mass 358.350->217.200 4 0 0 0 O. 2 0 000. ~vJ\~~/',"^, 52'.0 56'.0 60'.0 64'.0 68'.0 72'.0 800000. Ion Mass 372.400->217.200 600000. 400000. 200000. 52'.0 ~~J~~~L 56'.0 60'.0 64'.0 68'.0 72'.0 Ion Mass 386.400->217.200 200000. 100000. 500000. 52'.0 ~ JvL 'v-~láJ,j~~ 56'.0 60'.0 64'.0 68'.0 72'.0 Ion Mass 400.400->217.200 400000. 300000. 200000. 52',0 56'.0 ^~~L,~l\~L 60.0 64.0 68.0 72'.0 100000. Ion Mass 414.400->217.200 5 0 000. 4 0 000. 30 000. 20000. 52'.0 56'.0 ~~ 60'.0 64'.0 L~~L~.. 68'.0 72'.0 10 000. Retention Time (min) File: MS040163. D\datD.. mø Dat.e " Time: I I Sample: US134018 I Ion Mass 414.400->217.200 50 000. 400 0 O. I I I ,I I ( 3000 O. 2000 O. 10000. ~~ 62'.0 64'.0 Ion Mass 414.400->231.200 20000. I ( J~~~ 66'.0 68'.0 ~~.~ 70.0 72.0 74.0 , ~ I AN ~ ^ JvJ ~ ~i J~ ~ f\ \ I ~ ~ ' 10000. 62'.0 64'.0 { I ( I I Ion Mass 1914.40 Fila, MS040183.D\data.m. Date II Time: 66'.0 68'.0 Retention Time (min) k 70'.0 72'.0 74'.0 Sample:_ US 134 0 18 ------~--,~._~- Ion Mass 414.400->231.200 20000_ 100 0 a. ~ I \ ^ Jv J \¡ \/ J ~ ,V \ J \ \ I ~ ~ ' jVw l; I ~ 62'.0 64'.0 66'.0 6S'.0 70'.0 72'.0 74'.0 Ion Mass 2414.40 Ion Mass 414.400->98.100 SOO. 600. ~ II I 200. i ~' I V I' ~ i J 1tIV1 ~ ' j 62'.0 6~.0 ! 1 fll II I . \, ~ I ) ~ \ II~·~ M~~\~~~ 70'.0 72'.0 74'.0 400_ /' 66'.0 6S'.0 Retention Time (min) Filo: MS040J.83.D\do.to..mllJ D",t.., ,r.. Timflil.: 'I I US134018 Sample: 412 400->191.200 Ion Mass . 800000. 600000. 400000. I 200000. I 63'.0 412 400->369.300 6000Q Ion Mass . 66'.0 ~ 69.0 - } ~~^ 72.0 ~ ~'} 75.0 78'.0 I 40000. 20000. I ~~.. 72.0 69'.0 78'.0 I 63',0 412 400->397.400 Ion Mass . 66'.0 90000. I 60000. 30000. f I 63'.0 412 400->313.300 Ion Mass . 66',0 - 72.0 78'.0 2000. ( I 1000 ~ 1\ -j f ~ I ~ ¡ ~. \ {~ \ ~ ~ , I' I ~ ¥ '\ ~~ ~ I ~ h ~ Y'~~~~~,~~ 78',0 75',0 I 63'.0 66',0 69'.0 Retention Time (min) 72'.0 File: MS0401BJ. D\data.m. DAte" Time: 0:; ro ro .Q e- ('.; :z ~ i;'1 """ \D (1) N \D f'") e- Lf) f'") \D '<1' """ r-I N I.D 62.0 60.0 0:; ro ro ro e- N Z \D N (f) ¡ (f) .Q .Q ro r- N Z \D N (f) 0:; .D .Q ro r- N Z \D N (f) (f) ro ro ro r-I e- N N Z Z \D \D N N (f) (f) o 58 cr:: ro c¡¡ c¡¡ "'" N Z \D N (f) CI) .Q .Q ro "'" N Z \D N (f) (minI ¡:t; .D .Q o c¡¡ I.D "'" CTI N Z If! I.D Lf) (f) N ro (f) c¡¡ coc¡¡ "",""" r-£ \D\D <r)N (f) L 56'.0 Retention Time 0:: .Q ro "'" (\J Z \D N D r- (Y) '<1' "'" tD çr; .Q ro r- N Z \D (\J D (j) .Q C1 e- N Z \D N D çr; iU .D r- N Z I.D N D N N (1) f'") tD 54'.0 Sample US13401B Ion Mass 358.350->217.200 60000_ U¡ I1J .Q r- 5 0 000_ N Z I.D N D 4 0 0 0 0_ 30000_ 20000_ U¡ I ro .Q '<1' 0:: N (!j Z .Q \D '" N N 0 z 1 000 0_ I.D N D co '" r- 0 N N ~ r-I 0 lk1 <r) 1h ~ 50'.0 52'.0 File: M5040183.D\data Date 6< Time: ~ ~ - !:t; m m m ::>: '=I' CD N [/) -- !:t; .a .a m ::>: '=I' CD [/) N .a [/) .a m , ::>: '=I' ro N [/) cr:; 11 11 11 ):; [/)n mC) m [~ m tJ ::>: '=I' CD N [/) !:t; .a .a m ::>: [/) M .a CD .a N m [/) ::>: M ro N [/) " [/) m m m ::>: (Y) ro N [/) - M W M M W ro M y o N o M W !:t; m ª '=I' ro N t- t- rl o W o 66'.0 o 64 6z'.0 Retention Tune (minI 60.0 - - --""" - -- Sample: US134018 Ion Mass 386.400->231.200 60000_ [/) m .a ::>: '=I' ro N Q 50000_ 40000_ 30000_ [/) ru w !:t; 2 0 0 0 0_ ~ M ru ~ .a M z ::>: ro :J M N ro co Q N N t- U Q M Q ~ Z :J ro N U M Q w U) ~ z 10 0 0 O_ N N P t- N ro U) 0) r- N M U U) w U) Q vÅ- w U) \ r 56'.0 58.0 File: MS0401B3.D\data.ms Date & Time: W .--I N 0) U) o co M 0) U) 800000_ 700000_ 600000_ 500000_ 400000_ 300000_ . 200000_ 100000_ File: MS0401B3.D\data.ms Date & Time: Sample: Ion Mass 412,400->191.200 US134018 .Q CU o (Y) :r: U) P-I r- E-< 0 q< N r-I co 0 :r: r-I E-< Q r-I (Y) 0 P-I ;:.::: H :r: r-I ~ r-I co p:; If) Z ~ c:Q'Io r- ~ (Y) (Y) (Y) ~ co ~ ¡M(Y) (Y) If) CIJ co E-< <:r 0 d:r> r-I r- H (Y) ~~ ~(Y) q< c:; r- U H r- CU If) ,~,~, ~ E-< ~ ,ALE, rf"-r- IJ\..I~' r- L.I 1---1- , , Ll.,,,,,, , I 63',0 66',0 75',0 78'.0 Retention Time (OOn) File: MS040183.D\data.ms Date (,. Time: 62'.0 64'.0 66'.0 68'.0 Retention Time (minI 70'.0 "'" 4000_ ~ lYw--v~ 1-1- L- ----1 { L I -L_^ --~ r- N (Y) r-t r- ~ 8 000_ r- LO 0) r-t W W 0) "'" N W r- o r- N W l e- O) LO (Y) W N "'" o "'" W N N 00 LO W r-t W (Y) W W W (Y) r- W W N o U)W CO . cor- COW ~ N o (Y) U) çG ..Q ..Q CO ~~ g~ U)::E N o (Y) U) ~ ,~ çG co CO CO ~ o (Y) U) e- (Y) N ~. W 12000_ 00 "'" If) W W U) CO CO CO ~ o (Y) U) 16000_ "'" W 0) N W r-t r- "'" LO W C4 ..Q ..Q CO ~ !'") o ("11 U) çG ..Q ..Q çG CO CO ::E CO "'" CO o ::E ("11 ("11 U) 0 ("11 U) "'" (Y) LO ("11' m"'" !'")w "'" W 2 0 0 0 0_ (Y) o r-t W W U) co CO CO ~ ("11 o ("11 U) U) ..Q ..Q CO ~ ("11 o (Y) U) çG CO co CO ::E NI U) ..Q ..Q co ~ "'" o (Y) U) 24000_ 28 0 0 0_ Sample Ion Mass 414 US134018 400->231 - 200 ~ - - - - - - - ~ ~ I I } I I I I I I I I , a_ e~BASELINE DGSI A N A L Y TIC ALL A B ,0 RAT 0 R I E S AROMATIC GCMS ANAL YSIS I I!..~ I~~~~ ~ ~~~~..Š=_I~~~._.e.~.~ I Company: CONOCOPHILLlPS Country: UNITED STATES Basin: NORTH SLOPE Lease: Block: Field: Well Name: PLACER 1 Latitude: Longitude: I AROMATIC GCMS US134018 04-223-A CP272563 OIL Client ID: Project #: Lab ID: Sample Type: Sampling Point: Formation: Geologic Age: Top Depth: Bottom Depth: I EARLY CRETACEOUS 7558 FT FT m/z 253: Monoaromatic steroids M1040594.D I . ··0:21 0.47 ..0.41 23.3 28.6 37.4 '10.7 1.85 . .1.31. 3.57 :;·;,M. ":1~0(1.3%) M ·M D .D D D (C?O+C21)œ'T~§('·.·. T AS #1 20/20+27 TAS#2 21i21+28 %26 T AS %27 T AS %28 T AS o/~29 TÀ8:':' .. .' I r ,1" C28/C26 20S T AS _..,." ... ',", .'. .',_,', ,u...,.. C28/C~7 20R TAS, \,. , . ' Dia/Regular C27 MAS 1Ifo27·MÅS. .. ,.1 ',... %28 MAS 0/029 MAS ',.' (C21~C22)/~ M~~. TASi(f\J1AS+TA$)' ',.' T A28/(T A28+MA29) . . . I I ~~~,~,uJ~~ 'D D '.0.. M 1.0(1.3%) M M 1.0 (0.8%) m/z 231: Triaromatic steroids M1040594.D I ( 0.31 A .0..53 A,' Dinosteroid Index ê4ÎÇ3,£C~::M~~i~r:::f..·(··, I ~~~,-"."J~l.~ i I [:,) I t: III ~ II i:') I [:,I....,. ~ ~ i'U m'I [OJ I [~~ II [~.ln'I:,) I "-{oj ¡ II [e]~] I (OJ I [:,I..___ MP,:-1T.:,·,···;;··..:,i;·· .. ':':"::':O]~'M ; Rc(a) if Ro < 1.3 (Ro%) 0.80 M R~(b)if Ro> 1 ~3 (Ro%) '. 1.87 M MPI-2 0.75 M ÒNR-1 . 6.70 M DNR-2 2.57 M TNR1 q.76:' M TDE-1 3.96 M TD'É~2 '. 0.24 . M . MDR 2.07 M R,.~ (~bo/~f . o.~ 72 ':M MDR23 1.11 M MORt n.75 M DBT/Phenanthrene 0.30 D I m/z 245 Triaromatic Methylsteroids M1040594.D I I ~.)I¡fiJJ'4 ~ J ~ ~ ( I 1Definition and utility of the ratios can be found on our website www.BaselineDGSl.com 2A=Source Age; D=Depositional environment; M= Maturity 3Thermal equilibrium value of the biomarker ratio and in brackets the approximate VR value at which this value is reached I Company: Well Name: Depth: Sampling Point: CONOCOPHILLlPS PLACER 1 7558- FT Client ID: Project #: Lab 10: File Name: US134018 04-223-A CP272563 M1040594.D : ' Peak . .~~òun·d Ret. ppm ppm" .Ion Label Name Time Area . . ~ I (Area) (. · I 230 OTP Ortho-terphenyl (internal 9754 2426 300.0 300.0 92 16AB G16 Alkyl Benzene .·::.'1,1~.49:··. 2607'., ' '., ':34;9.1 322.4 92 17AB C17 Alkyl Benzene 71.510 10257 2452 315.5 303.2 92 18AB C18 Alkyl Benzene 75.697 8320·: 2162 255.9 267.4 92 1 THI092 D¡.methyl dibenzothiophene 1 77.474 2296 342 70.6 42.3 92 2THI092 Dimethyl dibenzothiophene.i ' . }8:213 2984. 374 91.8 46.2 92 19AB C19 Alkyl Benzene 79.444 6949 1914 213.7 236.7 92 20AB C20 Alkyl Benz~ne.: ","I, ", :1509 1.74.5 "'186.;6 8?,.8.9.2 92 21AB C21 Alkyl Benzene 86.077 5546 1542 170.6 190.7 C22 Alkyl B~n~~n~ : '::8.9;085 . . ... ......" .:"/ 92 22AB 4007," '1125' 123:2 . 139.1 92 23AB C23 Alkyl Benzene 91.935 3346 916 102.9 113.3 Phytanyl Benzene ~ '. " " " 92 PHYBz '93.85.3 1498 252 46~1 31.2 92 24AB C24 Alkyl Benzene 94.644 2847 686 87.6 84.8 92 25AB C25 Alkyl Benzene '··97.248 2.238.:. 602: 68.8 74.4 92 26AB C26 Alkyl Benzene 99.729 1952 459 60.0 56.8 .. .. ,I,.",,"'. .." ..: 106 16A TM C16 Alkyl Toluene (metå) .·J:ì5..915··· 14454 3579 .'444:6 '442.6 106 16A TO C16 Alkyl Toluene (ortho) 66.865 9021 2084 277.5 257.7 106 17ATM C17 Alkyl Toluene (meta) 70.806 13252 3177 ..407.6. 392.9 106 17 A TO C17 Alkyl Toluene (ortho) 71.668 7337 1795 225.7 222.0 106 18A TM C18 Alkyl Toluene (meta) 9757 2515 300.1 311,0 106 18A TO C18 Alkyl TolueneJ0rt~?t '. .... .... 75.855 5744 1408 176.7 174.1 ;. " ' ,,~.:,: :' "2965,'.' " ",,'.\ 52.:1:..; 106 1THI0106 Dimethyl dibenzåthiopheilE31}: .,,;;;;:..,:: . . 77.474 423' .9,1:2 106 2THI0106 Dimethyl dibenzothiop~~~: 2 78.248 2088 320 64.2 39.6 106 19A TM C19 Alkyl Toluene (meta) 78:829 7828 2202 240.8 272.3 106 1 9A TO C19 Alkyl Toluene (ortho) 79.585 4462 1169 137.2 144.6 106 20A TM C20 Alkyl Toluene (meta) 82.277 6366·.. 1715 195.8 212.1 106 20ATO C20 Alkyl Toluene (o_rt~o) 83.016 3626 920 111.5 113.8 ~;, . 106 21ATM C21 Alkyl Toluene 'Uneta) 85.496 ..4844 1205 149.0 149.0 106 21ATO Ç21 Alkyl Toluene (ortho) 86.200 3232 794 99.4 98.2 106 22A TM Ç22 Alkyl Toluene (meta) 88;.522 4675 1220 143.8 150.9 106 22A TO C22 Alkyl Toluene.(ortho). 89.226 2835 657 87.2 81.2 106 23A TM C23 Alkyl Toluene (mêtar .9'1.372 37.55 960 115.5. 118.7 106 23ATO 923 Alkyl Toluene.(ort~o) 92.058 1934 505 59.5 62.4 106 24ATM C24 Alkyl ToILlenè'(meta) :' ~4,099 ..3018. 78], 92;8 97.3 106 24ATO C24 Alkyl Toluene (ortho) 94.785 1667 385 51.3 47.6 106 PHYTL Phytanyl Toluene 95.(70 . 13.963 2132 429.5 263;6 106 25A TM C25 Alkyl Toluene (meta) 96.703 2340 554 72.0 68.5 '. 106 25A TO (;25 Alkyl Toluene (ortho) 97.371 1123. '288, 34.5. 35.6 106 26A TM C26 Alkyl Toluene (meta) 99.201 2209 468 67.9 57.9 .. 106 26ATO C26 Alkyl Toluene (ortho) 99.870 947 227 29.1 28.1 134 15AI C15 Aryl Isoprenoids 60.761 4355 858 133.9 106.1 134 16AI C16 Aryl Isoprenoids 65.968 3755 739 115.5 91.4 134 17AI C 17 Aryl Isoprenoids 70.630 1639 286 50.4 35.4 134 18AI C18 Aryl Isoprenoids 74.782 3762 855 115.7 105.7 134 19AI C19 Aryl Isoprenoids 77 .087 4048 832 124.5 102.9 134 20AI C20 Aryl Isoprenoids 86:904.' :256.1.: 640.,'; . 78.8.···· 79.1' 134 21AI C21 Aryllsopren~ids 83.719 1451 335 44.6 41.4 134 22AI C22 Aryl Isoprenoids" 134 ISOR Isorenieratane I r I I I I I I I Company: Well Name: Depth: Sampling Point: CONOCOPHILLlPS PLACER 1 7558- FT Client ID: Project #: LablD: File Name: US134018 04-223-A CP272563 M1040594.D . ..' Peak Compound Ret... ppm ppm Ion label Name Time Area I - . ~. I (Area) (Hght) : 142 142 149 156 156 156 156 156 156 156 156 156 156 161 168 168 168 168 168 170 170 170 170 170 170 170 170 170 170 178 184 184 184 184 184 184 184 184 184 184 191 191 191 191 192 192 192 192 2MN 1MN MTTC578 2EN 1EN 26DMN 27DMN 1317DMN 16DMN 23DMN 14DMN 15DMN 12DMN MTTC8 2MBP DPM 3MBP 4MBP DBF BB_EMN AB_EMN 137TMN 136TMN 146135T 236TMN 127TMN 167126T 124TMN 125TMN PH EN 1357 1367 1247 1257 2367 1267 1237 1236 1256 DBT BH32 BH33 BH34 BH35 3MP 2MP 9MP 1MP 37.855 393981 67745 12117.5 8377.4 '. . ' " . '. 1',' . ~.:- ,;~,~., . - 39.086 . '. 23790ê. <. 40828 .. 7317.2 5048.8 .' . .. 1295.8 ." 46:036 ,"42131. 6248'. 772.6 46.141 8911 2714 274.1 335.6 '46.950 .109439. 18458 '. 3366.0, .2282.5:. 47.109 110020 18729 3383.8 2316.0 ..48;11.1. '239.357 34064 7361,8 4212.4: 48.358 169751 28696 5221.0 3548.6 ...... "'1:~,,' \,., '. 4744 49.536 264.13. 812.4 586.6 49.642 58828 8820 1809.4 1090.7 49]30 32.77 ~"" .6445 1008.0 797.0, 50.680 34859 5577 1072.1 689.7 2-.Methylnaphthalene 1-Methylnaphthal~nE:} 5,7,8,-triMe-MTTChroman 2-Ethylnaphthalene . 1-Ethylnaphthalene 2,6-Dimethylnaphthalene 2.7 -Dimethylnaphthalene 1,3 & 1,7-Üimethylnaphthalenes. 1,6-Dimethylnaphthalene 2,3-Dimethylnaphthàlerië 1 ,4-Dimethylnaphth~le~e, . 1 ,5-Dimethylnap~t~al,ène 1 ,2~Dimethylnapht~al~ne 8-Me.,MTTChroman.> . .' 2-Methylbiphenyl. . Diphenylmethane.:. ' 3-Methylbiphenyl 4-Methylbiphenyl. .... Dibenzofuran Ethyl-methyl-NaphthàÚ3n~ . Ethyl-methyl-Naphthalene 1 ,3,7- Trimethylnaphtilålene 1,3,6- Trimethylnaphthalene (1,4,6+1,3,5)-T~im:~thY'¡8~phth~I~6~~·:~C'. '" ." "t 2,...3.6- TrimethYln~~~th~.I~~e, 1,2,7 - Tri,methylné!phthale~'1, (1,6,7+1 ,2,6)- T.rimethyl~~p,h,t~a!,~n~~ 1 ,2,4- Trimethylnaphthál~ne::;,' ,t' 'I': " ,! -,,'" 1, ,2,5- Trimethylnaphthalene Phenanthrene 1.3,5.7-Tetramet~ylna~h~h~I~~~. . ". 1,3,6,7-Tetramethyì'1aph,ttialel'1,~::" ';,;.':,,' (1,2,4,7+ 1 ,2,4,6+ 1 ,4,6,7)- T etramethylnaphthalenes 1,2,5.7-TetramethylnaplÎttJ~I~,ri~"·::!',;,r:':;':?;::"-{';\::,: :,1"""""" 2,3.6,7-Tetramethyln~~ht~~I.en,e.;"<,, .' 1 ,2,6.7-Tetramethyinäpbthal~~~:. ','ii' 1 ,2,3,7 - Tetramethy,.lnaphth~le~~ .1. 1,2,3,6-Tetramethylné!pbttJalei1'~,i ,'I '. 1,2,5.6- T etramethylnaphthalene Dibenzothiopherie., C32 Benzohopane C33 Benzohopane ... C34 Benzohopane C35 Benzohopane'. 3-Methylphenanthr~ne '.' 2-Methylpher1éinthren'e:, .... 9-.Methylphenanth~~~~.. 1-Methylphenanthrene ,'',-,'"'''' . <. ~,',., I,:., , ": 46.511 ';",'4~0762 53.196 5~.847 55.289 '55.025 . 56.239 56.697 . 57.066 , , ':', " . ':,,' ~ '" I " , , 58'.,139. 58.403 59.318 ',·····(60':251 60.690 7Ö.208 64.649 :65:8jo 66.566 .", ': ·".,',66..7'60 67.129 ..: ,'67.:$S?,'" ' 67.745 ., '. ,,' 6~;Ö27 68.730 "<ê8~94{ 115.879 ;116.917 117 .849 ,t1~.0~O ' 75.152 5462 "¡535~.,', 70550 , :"25E)3$ 19146 '4å~12',.' 20635 '71~074 93874 ,å?~:~t:, .'. . 63330 80337 " '''''·,..'''",'''''')',':.'1''""",;,:"" .10206' 40403 73405 ' 23209 .2879:~· 25211 ·.\::1'~7:i:3.'·' . 5582 '\,,1º~21,:' . 4290 "':81'~4' 25368 ? ~?5º,' 2564 238à.\, 1268 ,,'\,1' "':""17.38::: 37374 916 ··',:.Ø~4::¡'·,:·'·': 12074 '436ò ;. 2971 6483···· 3321 12051' 15997 12672: ' 11447 12113 1866:'" 7402 15199 3918 6Q70 4886 ,'" ¡', 27.65' t 1124 23P3,. ..... 948 H>4e' 5595 .4428.. .... 752 .' 564" 309 ··'140 8525 ,,9172,.;, 11677 'ª~~~," 168.0 ,164·6 2169.9 , . 788.4:: 588.9 '14.85.9'.., 634.7 2198.3 .' 2887.2 ?5~1 ~'~::',:;: '" 1947.8 2470.9 ,313;9 '. 1242.7 2.257.7 713.8 885.6. 775.4 423.6 171.7 '326)' 131.9 251.1'. 780.2 €)69.p 78.9 7,3:2 . 39.0 '22.7' 1149.5 1276.4' 1625.7 1227..1: '. 113.3 ··~1.0ß 1493.1 . ',., ':.': 539~,2:".> 367.4 801'.:7:;, 410.7 1490.2 1978.2 ~ 5EF:9 ..,' . 1415.5 , 428.~:.i: 1497.9 . 230~á .... 915.3 187R5'" 484.5 750.6, 604.2 341.9 139.0 284;~,.· 117.2 203~9 .... 691.9 547.6. 93.0 69.7 38.2 '.17.3. 1054.2 ,·····.11~4.2 ....' 1444.0 1074.pt. Company: Well Name: Oepth: Sampling Point: --. .: 'Peak - ~~!1 Labe~. ~ 198 198 198 198 198 198 206 206 206 206 206 206 206 206 206 206 206 212 219 226 231 231 231 231 231 231 231 231 231 231 231 231 231 231 231 245 245 245 245 245 245 245 245 245 245 245 245 245 245 CAD 12467PMN 12357PMN 4MDBT 23MDBT 1MDBT 36DMP 26DMP 27DMP 39DMP 29DMP 17DMP 23DMP 19DMP 18DMP 12DMP 9_10DMP DMDBT RET TMDBT 231 A20 231B21 231C26 231 D26 TADMD1 TADMD2 231E28 231F27 T ADMD3 C29TA1 C29TA2 TADMD4 231 G28 TADMD5 C29T A3 C3S C4S E2S E3SC3R E4SC4R S2S DA S3S DB S4SE2R E3R E4R DC DD CONOCOPHILLlPS PLACER 1 7558 - FT Client 10: Project #: Lab 10: File Name: US134018 04-223-A CP272563 M1040594.0 f, : :\" .. "d . .. Ret. . . . ppm'" ppm'" .. .. - Time Area I -'. I (Area) (Hght) Cadalene 1,2,4,6,7 -Pentamethylnaphthalene 1,2,3,5,7 -Pentamethylnaphthalene 4 Methyl Dibenzothioph~n~: 2 & 3 Methyl Dib~~~~thiophenes 1 Methyl Dibenz6tf1'¡QP,h:en~' :1' ',", 3,6-Dimethylphenanth~.~.ne 2,6-Dimethylphenanthrel1~ ....' 2.,7-Dimethyl~he~~~t~r~n~i<'··'·'·'·':""·":::' ........ >.. ....... (3,9+3,10+2, 1 0+1,3)-Öim~t~ÿlpr~.néi,t;I,i9r.~·n~~ ................ (2,9+1,6)-Dim~th~lphenan~~r~nes 1, 7 -Dimethylphen~nt~r~¡'ë,' .:.: '. 2 ,3-DimethyJphen~n,t~~~n~,. 1 ,9:-Dimethylphenêllthrefle': "'.: '.. 1,8-Dimethylphenanthrene 1,2-Dimethylphenånth~ene 9, ~ O-Dimethylphemanthrene Dimethyldibenzothiophene' Retene T rimethyldibenzothiophene C20 Triaromatic Steroid C21 Triaromatic C26 20S Triaromatic ~ " , ' ." ,., .',' " " .' ," I ' I C27 20S & C26 20R Triaro,matic. . '. C28 23,24-Cholestane Triaromatic " "', ' . ',' ",: ':':',~: ", . ',":,''' ;' ,:" ,I (:28 23,24-CholestaneT riaroma.tic:: '. C28 20S Triaromatic C27 20R Triaromatic C28 23,24-Cholestane Triaromatic C29 T riaromatic C29 Triaromatic C28 23,24-Cholestane Triarom~tic; . C28 20R T riaromatic C28 23,24-Choles~hëT~¡arorT19ti9.-.·'" C29 Triaromatic C27 20S 3-MethyIT~i~rol11atic Ste}rqid,: C27 20S 4-Methyl Triarom<:itic ~t~r~i?q . C28 20S 2-MethyJ TriaromatiCSt~rgicl:, Ç28 20S 3-Methyl & C27 20R 3-Methyl T AS C28 20S 4-Methyl&C27 20F3,4-rV1.~thyl:rAS C29 20S 2-Methyl Triaromatic Steroid Triaromatic Dinosteroid a·, C29 20S 3-Methyl Triaromatic Steroid Triaromatic Dinosteroidb :.' ,;. " , .~: .' ,'.," ';, 66.162 , "Z:i()?3, 73.340 . ,73.498 74.272 75.0?1 79.391 79:638 79.743 '. 89:254' . 80.447 '::.80.605' . 80_869 . ..80:992 81.415 81:907 82.558 7B.230 86.182 ,8J.p]3 92.217 1902 "',3583\:'" 2230 , '33692 24243 16312 6793 " , ' I,', ''',.'....~.". ".." ')~5Q3: . 8278 .>.63Q65:: . 32126 . ¡2§i~~. ': 9046 6647 4~49 819 141277 6805 :136915, 7565 C29 20S 4-Methyl~~?8~.~~~~-~~~~yITAS C28 20R 3-MethyIT~afomélt¡cêi~'r2j9/:' C28 20R 4-Methyl Triaromatic Steroid Triaromatic Dinosteroid c" T riaromatic Dinosteroid d 103.863 1050464 106.045 106.572 106.766 ,'oJ ",:',',. 107.399 107.522 107.769 107.962 .108.8.07 109.000 10~.·Ó88 110.302 106.537 107.171 1Qr.733 108.068 108,648, 108.912 109.071 109.246 109.669 109.845 109.968 110.584 1.10_759 110.865 6842 16263 505 568 12672 8382 56B 2409 1659 .,1913.. 10986 ,,717 3136 1164. 1697 627 3584 4553 686 800 2771 1926 3390 . 249å , 2959 2160' 2789 400 568 7264' 5009 3301 1417 3205 2048 :··129~3·. 5396 ~949..... 2162 1461 1155 189 5873' 1626 4243. 1802 ,iJ?69," 1593 . .3222 110 197 2104 1495 191 471 406 182 2282 356 735 258 341 123 588 776 123 185 370 .419 555 353 516 469 618 58.5 110:2 68_6 1036.3 745.6 501.7 208.9 415.3 254.6 1939._ '( 988.1 "774.6. 278.2 453,,5. 204.4 149.1 25.2 4345.2 209.3 .4198.7 232.7 ".'.235..6: 210.4 500.2 15.5 17.5 389.7 257.8 17.5 74.1 51.0 31.2 337.9 . 22.1 96.5 35.8 52.2 19.3 110.2 140.0 21.1 24.6 85.2 ,59.2 104.3 76.6 91.0 66.4 85.B 49.5 98.7. 70.2 898.3 . 619.4 408.2 175.2 396.3 253.3 1603..0 667.3 735~ T 267.4 '433.9, 180.7 142.8 23.4 726.3 201.1 524·7··.· 222.8 218.8 197.0 39804 13.6 24.4' 260.2 184_9 23.6 58.2 50.2 22.5 282.2 44.0 90.9 31.9 42.2 15.2 72.7 96.0 15.2 22_9 45.8 51.8 68.6 43.7 63.8 58.0 76.4 I Company: Well Name: Depth: Sampling Point: CONOCOPHILLlPS PLACER 1 7558- FT Client ID: Project #: LablD: File Name: US134018 04-223-A CP272563 M1040594.D .. Peak Compound Ret. ppm ppm' · I . ~ - Name Time Area I -' ~ I (Area) (Hght) - I I I I I I [ I [ 245 245 245 245 245 253 253 253 253 253 253 253 253 253 253 253 253 253 253 253 S2R S3R DE S4R DF S253A S2536 S253C S253D S253E S253F S253G S253H S2531 S253J S253K S253L S253M S253N S2530 029 20R 2-Methyl,Tri~r(:nTl~~,~,,~t~~oi.~,_,.,. 029 20R 3-Met,hyJ .Jriaror!låt'c,ê~~r~ièf".·'·· Triaromatic Dinosteroid e 029 20R 4-MethyITriâ~omatit'~tè'roid:," Triaromatic Dinosteroid f C?1 Ring-C MonoaromatlC St~róid '. C~2 Monoaromatic,st~roid , , ' 027 Reg 5ß(H),1 Oß(CIi3}20S C27 Dia 10ß(H),~~(C.H3)?0~",.<, '.', ..... " '.' ."..' C27 Dia1 OßH,5ßCH3 20R+Reg,5ßI:i.. 1'qßÇ~3:2ÖR.' 027 Reg5a(H),10ß~~H3},20,S, ..' .'i' ....,/. ........ C28 Dia 1 OaH,5aCH3~OstR~g5ßI..:t 1 PßC.t.4;3,2PS,: "',' .' ,....' , C27 Reg 5a(H).',1 Oß(CH~) 20R C28 Reg 5a(H),1 Oß(CM:3J?O§ "i' ,:,<, ,:,:'..'" C28 Dia 10aH,5aCH3 2~R~~ep~~~,~0~<?H320R,. 029 Dia 10ßH,5ßCH320S+R.~g5ß,H1:9ßCH320S" C29 Reg 5a(H)10ß(~~3)~,OS'{""i C28 Reg 5a(H),1,Oß(CH3)'20~::':i:' 029 Dia 1 OßH,5ß~H~ 20.~::~7~?ß~, ~?ß~H3 ~?~ C29 Reg 5a(H),10ß(CH~)'?OR,'i(\ ,:", "":,:" 111.287 ...1+iAS"S 111.639 112.079 112.202 840476 86.939 96.879 97.037 , "98'.497. 98.638 99.04~,' 100.327 ".10p.468 1 00.644 '100.784 1 02.069 1 02.315' , 1 02.456 ':.104::0$2'" 759 :,. '..' ': . ',-';"-..: ii;::'~' '.;;.' ':. . ',.:2E)84,r 2309 243~.'·, 3370 2771 2582 831 2970 :,2882\;, . 999 ,.,'~~t.1l, ' 656 2802 '42~0': 522 ,; >':!:1459 3310 ":'" .,8,~'l:,: 210 ,526, 414 470: 834 6615 536 200'·, 727 f:ì70" 219 " ,71.6 181 "",'" ,", ?14, 717 902, 172 '239,,: 579 ,,··.:.,::16~ 23.3 .82.6 71.0 74.8 103.7 ,'85.2 79.4 25.6 91.3 88.6',' 30.7 117.2 20.2 ,:".:>,.,,23:7 86.2 ,130.1 16.1 44.9 101.8 .", .,""·,'.'27~6'''':i·· 26.0 65.Q 51.2 58~1 103.1 82.2 66.3 24.7 89.9 82.9 27.1 8R~ 22.4 26.5" 88.7 111.5 21.3 29.6 71.6 20:2' Company: Well Name: Depth: Sampling Point: CONOCOPHILLlPS PLACER 1 7558- FT Client ID: Project #: Lab ID: File Name: US134018 04-223-A CP272563 M1040594.D .. .. -~ ~ ~ - - .. . " \.~ r ......... . . Miscellaneous Ratios ~y Areas - By Heights . . . .'. I. , -. . . . , . .' ':\ Triaromatic Steroids,mlz231", (C20+C21)IL T AS 0.24 T AS #1 20/20+27 0:55 TAS #2 21/21+28 0.44 %26TAS 2K1 %27T AS 24.5 %28T AS ·37-4 %29T AS 12.0 C28/C26 20S T AS ,1:32 C28/C27 20R T AS 1.31 1.53 . ' Monoaromatic Steroids m/z 253 Dia/Regular C27 MAS 3.64 %27 MAS 35.0 %28 MAS 33.1 %29 MAS 31.9 ,(C21+C22)IL MAS, 0.17 TAS/(MAS+ TAS)'· T A28/(T A28+MA29), 0.73 Triaromatic Methylsteroids m/z 245 Dinosteroid Index . 0.31 0.36 C4/C3+C4 Mester 0.53 0.54 P~enanthrenes and Naphthalenes MPI-1 0.71 0.75 MPI-2 0.75 0.77 Rc(a) if Ro < 1.3 (Ro%), · .0.80 0.82 Rc(b) ¡fRo> 1.3 (Ro%) 1.87 1.85 , ' DNR-1 6.70 5.77 DNR-2 2.57 2.74 TNR1 0.76 0.90 TDE-1 3.96 3.97 TDE-2 0.24 0.29 MDR 2.07 2.20 Rm (Ro%) 0.72 0.72 MDR23 1.11 1.13 MDR1 0.75 0.75 DBT /Phenanthrene 0.30 0.29 8 0 0 0 0_ 7 0 0 0 0_ 6 0 0 0 0_ 50000_ 4 0 0 0 0_ 30000~ 2 0 0 0 0_ 10 0 0 0_ Sampl e: - - Ion Mass 142+156+170+184 US134018 File: H1040594. D\clata. IUS z :2: N '- :z :2: r-f } l 40'.0 - - :z riI N ~ ~ "\ - - - :z :2: Q r- r-f M r-f z :2: Q w r-f I Z :2: Q i :<'-) :!In Ç'-i r< ¡ :z :2: Q N r-f '--~ I.....-... L. ~ 50'.0 r- w ~:z M ~ rill ~ z ~ .--I N r- :2: M..... r- ~ N E-< .--f ~r- ~ ~ ~w~ -A1w At,,¡ vi .~I ~J~'v\--'~,~ 60'.0 70'.0 - - - - :z :2: rill II) II) :z ;g E-< E-< w M It) E-< M W ~.--f .--f N w:z .--f E-< -r:2: r- r- .-tE-< w M W .--f :z .--f M N ;g E-< It) N .--f Retention Time (minI ( M3) W to N .--f E-< II) Q Sampl e: US134018 1 0 0 0 0_ Ion Ma s s 1 8 4 + 1 98 + 21 2 +2 2 6 9000_ 8 0 0 0_ 7 0 0 0_ 6 0 0 0_ 5000_ 4 0 0 0_ 3000_ 2 0 0 0_ 1 000_ \ \ II Date h Time: File: M1040So iata. ms : 04 1:02 em r- Uì f') .--I I I, ~,~ V 64',0 r- '" f') .--I r- <;J' N .--I r- Uì e- N '" .--I N .--I '" r-f') f')N r- C-~ .--I '" .--! f') N ~ E-< W ~ <;J' '" Lf) N .--! E-< W ~ Q E-< W ~ f') N E-< W Q E-< W ~ .--! Z :E P,Z r-::8 "'P, "f'r- NUì .--If') N .--! \ ~/A~~w}\~\ ~ ~N~ J '\ 68',0 72',0 76',0 Retention Time (min) . M4) , E-< W o :E E-< -/'JA' A, f J \,~~ ~J4¡ 80',0 84',0 ~ --- ----. - - - - Sarnpl e: US134018 Ion Mass 17S+192+206 1 S 0 0 0_ z w ::r: p. 15000_ ~ 1 2 0 0 0_ ~ N p. ~ rl 9000_ p. ~ M 6 0 0 0_ p. ~ Q \D N ~ Q ~ r- 3 0 0 O_ N Q \D M ~~,\~,~ 70'.0 7i.o 74'.0 76'.0 Retention Time (min) 7S'.0 File: MI040594. D\data. ms Date & Time: 6 Apr 04 1: 02 pm (Ml) .,.. vi' so'. 0 - .- ~ p. ~ Q CT\ M ~ Q ~~ Q CT\ N ~ Q CT\ .--t ~ Q M N ~ Q ro rl ~ Q N r-I ~ Q o ) ~'-~ si.o Sample: US134018 Ion Ma s s 2 2 6 5000. E-< a¡ ~ E-< 4 0 0 0_ 3 0 0 0_ 2 0 0 0_ 1 0 0 0_ o co N r-- r-- lJf ~j f~ 78', 0 80', 0 82'.0 Retention Time (min) Date & Time rile: H10405°' 'data. ms r 04 1: 02 P!'1 . 1 9) \J I\j 84',0 J C') \.D co "1' co 86'.0 File: HI040594. D\data. IDS Date (. Time: 6 ADr 04 2 0 0_ ~ 400_ 1.0 ~ r-i:'J C'I M. Q4 .--0 )-I 102.0 104 o m r-I m "f' o M 106.0 21 108.0 Retention Time (minI U) N N fiI ~ r Jr- o n \ - -MJr- _011 m r-N NO ."f' 00 . 000 MO M U) N U) ~ ~ Q ~ 110 o 00 o "f' o I ~ M C t 112.0 I/) m 1.0 N r-I 0 00 M M r-r-I M MO m. r- .1/) N M"f'''f' V-_~_~/~~~ p:; N U) U) M U U) "f' U p:; M fiI ~ U) M U) 600_ 111 Q fiI Q U Q p:; "f' U) 800_ p:; M U U) M fiI I p:; N fiI U) "f' U) p:; "f' riI Q Q p:; M U) - 1 0 0 0_ 1 2 0 0_ 8arnpl e Ion Mass - U8134018 245 - - - - ~ -- p:; "f' U U) "f' riI - - ~ - --.... -- ~I ¡., Q Sampl e: US134018 Ion Ma s s 2 31 4 0 0 0_ 'í> N C\ .--I C') N 3 0 0 0_ 2 0 0 0_ o N ~ .--I C') N .--I N p:¡ .--I C') N co N W .--I C') N co N ø .--I f'î N U) N U .--I C') N e- N µ. .--I f'î N 1 000_ .--I ~ 1 N 'l~ "1'~ .--I ~ ~Lf'l ~ à ~ ~ ª u ~.. ~~~~~~JJ,»~Uk~ 85',0 90',0 f'î ~ &i N U 95',0 10Ò,O 105.0 110.0 Ion Mass 253 900_ ~ C') Ul N U) p:¡ C') Ul N U) 600 :><: C') Ul N U) ø 'J C\ f'î ..., f'î W Ul LI} Ul f'î N N N Ul U) U) Z U) N f'î CI) Ul N CI) 1 2 0 0_ U f'î Ul N U) :E C') ~ ~ ~ g :h Nf) ~ ~ yN~, 'i~J'~~~~~~I~ 300_ ~~~ ~~v/~W~¡IfJ¡~ 85'.0 90'.0 95',0 10Ò.0 Retention Time (min) 105.0 11Ò.O File: H1040594. D\data. InS Date & Time: , 04 1: 02 ern 1M2) 6 0 0 0_ 50 0 0_ 4000_ 3000_ 2 0 0 0_ 1 0 0 0_ ----~~-- - - - - - - - ~- ,'-', Ion Mass 91 +92 Sample: U8134018 7000_ '\ .11 I ~ -~ File: HI040594. D\data. InS - - - - ~-- rf'~')Y\' 40'.0 50'.0 ~I'r 1111 W,I~, ~~ (r ~~ ~~I~~~~~~~~ ~ 60'.0 70'.0 80'.0 90'.0 100.0 110.0 120.0 Retention Time (minI ( M1 3) , Sample: US134018 9000_ Ion Mass 105+106 8000_ 7 000_ 6 000_ 5000_ 4 0 0 0_ 3 0 0 0_ 2 0 0 0_ 1 00 0_ ,\ )"\ i'l ,~IM·tlll 40'. 0 Date File: H10405' 1ata. rns , ~. 1: 02 .- I - ) I ! '\1 h " ,,1 f~ Jr INI "" 'rI . 5~.0 60,0 ~ ., )~'rj ~ I ~'II,~J~P~It4 j~Iw,\~~'¡r;~~ ''Ii' I f ~ ,It., r I 70',0 80',0 Retention Time (min) 100.0 120.0 110.0 90',0 '11 4 ) - - -- ----- Sampl e: US134018 Ion Mass 133+134 5000_ 4 0 0 0_ 3 0 0 0_ 2 0 0 0_ 1 0 0 0_ ..J),I File: MI040594. D\data. IDS n::.t-ICIIL't';ma" t:;.:aru-nA '.n?.....n --....¡ T. I~ \1' I,' J I II '~II, I . ,U, I' 1 ~ I ~,I }' I ~ ~ I 40'.0 50'.0 60'.0 70'.0 80'.0 Retention Time (min) ( M1 6) , - -- \~~ ~~~t~~ 90'.0 110.0 100.0 -....... - ~ ~ -=~ ~ 120.0 I I r I I I I [ I ( I I ( I ~. i.~ ~~=..7..~,.I~~=._,e-§.~ I Company: CONOCOPHILLlPS Country: UNITED STATES Basin: NORTH SLOPE Lease: Block: Field: Well Name: PLACER 1 Latitude: Longitude: AROMATIC GCMS m/z 253: Monoaromatic steroids M1040596.D Client ID: Project #: Lab ID: Sample Type: Sampling Point: Formation: Geologic Age: Top Depth: Bottom Depth: US134019 04-223-A CP272564 SIDEWALL CORE EARLY CRETACEOUS 7556.5 FT FT .~. . (on Areas) 1 Appl;! TEv;j ono- ¡ :. . I . '.. ...' ..' . :. (Ç~P+q2~)ð; ,'·T1i~,.Y<,:;::::I\"i':::/:""'.~'''·~;;/:;:\'''''.':' TAS #120/20+27 J"AS,#2 'Z1/?;1:+~ª:',,:' :;,..., ":,,,::':~:C %26 T AS ,O:2p·,:;:f\I1\.;," 1.0 :(1~~%) 0.47 M þ.39:i,.:::¡'M., I. ,<:'i 24.3 D %28 T AS C28/C26 20S T AS Dia/Regular C27 MAS 3.33 34.5 D %28 MAS %29 MAS (~~1 +C~2)~~A~"" ',' TÂ~¡{M~,$'t:lf~.ß:l::¡:;·:::t':·~:/·;;·:·,::,' :~' :~. !1\?~/(TA28+MA29~ 0.17 M ,:O:rÓ;.'i:,M:,i, , 0.74 M 1.0 (0.8%) 1.0 (1.3%) :. 1'::',.", , " ,,;, ',',".!";',' -",,"1:,,','; Dinosteroid Index 0.31 A 'O'.5~:: ,A:,,' 11(~ Iron. ~1~,'~~I~"'~~,it~~..~~ 1(;J.""lm~.J1'I~I"'('}hl(']~JlI~II*"___ Rc(a) if Ro < 1.3 (Ro%) 0.80 M Rç(bf¡f:ijb'~:,1\,3:¡,(8è~)J:;·:.,3,>~;i,i ,..' ,",:.1.:,' :,:':1.å:f:f,:M:'", MPI-2 0.76 M :";6:86', "K," ,", ' DNR-2 2.21 M TN~1': TDE-1 'Oefinition and utility of the ratios can be found on our website www.BaselineDGSl.com 2A=Source Age; O=Oepositional environment; M= Maturity 3Thermal equilibrium value of the biomarker ratio and in brackets the approximate VR value at which this value is reached .w.r.~~~,\M~~ m/z 231: Triaromatic steroids M1040596.D I ~~~~-J~~~ m/z 245 Triaromatic Methylsteroids M1040596.D r ~~)JJJIjI M Jv ~ ~ Company: CONOCOPHILLlPS Client ID: US134019 Well Name: PLACER 1 Project #: 04-223-A Depth: 7556.5 - FT Lab ID: CP272564 Sampling Point: File Name: M1040596.D ~, ~ H - Î - 230 OTP Ortho-terphenyl (internal standard) 74.958 34793 7957 300.0 300.0 92 16AB C16 Alkyl Benzene 66.671 39090 8764 337.1 ,330.4 92 17AB C17 Alkyl Benzene 71.509 34198 7702 294.9 290.4 92 18AB C18 Alkyl Benzene :·',.~8~4{" ' :7022,:,' ~44.4,; 264:7.' 92 1THI092 Dimethyl dibenzothiophene 1 77.491 7224 969 62.3 36.5 92 2THI092 Dimethyl dibenzothiophene 2 ':::78.:23.0 ' " '::i',7140:,; 6Üf 36.0 92 19AB C19 Alkyl Benzene 79.461 23072 6145 198.9 231.7 92 20AB C20 Alkyl Benzene I' , , " , ":,18?~2.{,' ,161.7 ' 188.8-" 82.',892.' " " ,'5()07 92 21AB C21 Alkyl Benzene 86.094 18163 5066 156.6 191.0 92 22AB C22 Alkyl Benzene ,89.102 14212 3751 122.5" , 141:4' 92 23AB C23 Alkyl Benzene 91.952 12100 3188 104.3 120.2 92 PHYBz Phytanyl Benzene 93.835 4629" 730 39.9 27.5 92 24AB C24 Alkyl Benzene 94.662 9351 2510 80.6 94.6 92 25AB C25 Alkyl Benzene 97248' 8~64, 2041 71.3 77~O " 92 26AB C26 Alkyl Benzene 99.746 5898 1481 50.9 55.8 106 16A TM C16 Alkyl Toluene (meta) ß.ê.:ª15: <, ' " "'"i::':4?7Iª ,') 1Q779',' ',412.0'" 406.4 106 16ATO C16 Alkyl Toluene (ortho) 66.883 30280 6202 261.1 233.8 106 17 A TM C17 Alkyl Toluene (meta) 76.823, ,':43636" · 105,25 " ,376.2' " 396.8:', 106 17ATO C17 Alkyl Toluene (ortho) 71.685 25172 5834 217.0 220.0 106 18A TM C18 Alkyl Toluene (meta) 75:063 ""','36373 8797 313.6 331.7 ' 106 18ATO C18 Alkyl Toluene (ortho) 75.855 20540 4765 177.1 179.7 . ' ,,'" "~" ,':,',',: ,1299 106 1THI0106 Dimethyl dibenzothiophene 1 77.509 6224,' 53.7' 49.0' 106 2THI0106 Dimethyl dibenzothiophene 2 78.247 6270 1129 54.1 42.6 106 19A TM C19 Alkyl Toluene (meta) 78;846 24888 6322 214.6 238.4 106 19ATO C19 Alkyl Toluene (ortho) 79.602 14102 3468 121.6 130.8 106 20A TM C20 Alkyl Toluene (meta) 82.294 23549 6065 203.0 ,2287 106 20A TO C20 Alkyl Toluene (ortho) 83.015 12410 3165 107.0 119.3 C21 Alkyl Toluene(m~ta) I ~'.', '\~;'" L"I', ',:.,",: 106 21ATM ;8R~496 .18151 4505: 156.5, ' 169.9 106 21ATO C21 Alkyl Toluene (ortho) 86.217 10275 2630 88.6 99.2 ," I. 106 22A TM C22 Alkyl Toluene (meta) 88.522 16252 .'4644 140.1 175.1 106 22ATO C22 Alkyl Toluene (ortho) 89.225 10642 2747 91.8 103.6 106 23A TM C23 Alkyl Toluene (meta) 91.372 12561 3118 108.3 117.6 106 23ATO C23 Alkyl Toluene (ortho) 92.075 7182 1940 61.9 73.1 106 24ATM C24 Alkyl Toluene (meta) 94.Q99 1 ()?~3; 2~¿}1 ,92.7 97.3 106 24A TO C24 Alkyl Toluene (ortho) 94.785 6468 1295 55.8 48.8 " 106 PHYTL Phytanyl Toluene 95.787 46835' '7414 403.8, 279.5 106 25A TM C25 Alkyl Toluene (meta) 96.702 8143 2056 70.2 77.5 106 25ATO C25 Alkyl Toluene (ortho) 97.,388 4599 1010 39.7, 38.1 106 26A TM C26 Alkyl Toluene (meta) 99.200 7271 1671 62.7 63.0 1"'1 '''.,,'J,'' , 29:9 106 26ATO C26 Alkyl Toluene (ortho) 9~.887 . " '3463, 828 31.2 134 15AI C 15 Aryl Isoprenoids 60.778 13970 2378 120.5 89.7 134 16AI C16 Aryl Isoprenoids 65.985 '1.2349 2336 106.5 88.1 134 17AI C17 Aryl Isoprenoids 70.630 4835 981 41.7 37.0 . "'." I 133 Ùj 134 18AI C18 Aryl Isoprenoids 74.799 2785 114.8 105.0 134 19AI C 19 Aryl Isoprenoids 77.104 14864 2618 128.2 98.7 134 20AI C20 Aryl Isoprenoids 80;922 ' '9390'· 2282 '81.0 86.0 134 21AI C21 Aryl Isoprenoids 83.736 4914 1211 42.4 45.7 134 22AI C22 Aryl Isoprenoids 134 ISOR Isorenieratane , I r I I I I I I ( I I I I I Company: Well Name: Depth: Sampling Point: CONOCOPHILLlPS PLACER 1 7556.5 - FT Client ID: Project #: LablD: File Name: US134019 04-223-A CP272564 M1040596.D ','. . Pèak ',,,' -.. .'\1 ~oi. Ret. ppm ppm ,. I".: .. i. ~ ~I ~.~_. ~a'" . II - Area Hei. ht (Area) (Hght) 142 142 149 156 156 156 156 156 156 156 156 156 156 161 168 168 168 168 168 170 170 170 170 170 170 170 170 170 170 178 184 184 184 184 184 184 184 184 184 184 191 191 191 191 192 192 192 192 2MN 1MN MTTC578 2EN 1EN 26DMN 27DMN 1317DMN 16DMN 23DMN 14DMN 15DMN 12DMN MTTC8 2MBP DPM 3MBP 4MBP DBF BB_EMN AB_EMN 137TMN 136TMN 146135T 236TMN 127TMN 167126T 124TMN 125TMN PHEN 1357 1367 1247 1257 2367 1267 1237 1236 1256 DBT BH32 BH33 BH34 BH35 3MP 2MP 9MP 1MP 2-MethylnaphthalEme 1-rvlethylnaphthalene 5,7,8,-triMe-MTTChroman 2-Ethylnaphthalene 1-Ethylnaphthalene 2,6-Dimethylnapht¡'àlene 2..7 -Dimethylnaphthalene 1,3 & 1,7 -Dimethyl naphthalenes 1,6-Dimethylnaphthalene 2,3-Dimethylnaphthalene 1 ,4-Dimethylnaphthalen~ 1,5-Dimethylnaphthalene 1,2-Dimethylnaphthalene 8-Me-MTTChroman 2-Methylbiphenyl Diphenylmethane 3-Methylbiphenyl 4-Methylbiphenyl Dibenzofuran Ethyl-methyl-Naphthalene Ethyl-methyl-Naphthalene 1,3,7- Trimethylnaphthéllene 1,3,6- Trimethylnaphthalene (1,4,6+1,3,5)-Trimethylnaphthalenes ' 2,3,6- Trimethylnaphth~lene 1,2,7 - Trimethylnap~thalene (1 ,6,7+1 ,2,6)-Trimethyln~phthalenes 1,2,4- Trimethylnaphthålene 1,2,5- Trimethylnaphthalene Phenanthrene 1,3,5,7-Tetramethylnaphthalene 1,3,6,7-Tetramethylnaphthalene (1,2,4,7+1,2,4,6+1,4,6})-Tetramethylnaphthalenes 1,2,5,7-Tetramethylnaþhthalene 2,3,6,7 - T etramethylnaphthale~e 1 ,2,6,7-Tetramethyln~phthalen~ 1,2,3,7- T etramethylnaphthalene 1 ,2,3,6- T etramethylnaphthal~ne 1,2,5,6- Tetramethvlnaphthalene Dibenzothiophene C32 Benzohopane C33 Benzohopane C34 Benzohopane C35 Benzohopane' 3-Methylphenanthrene 2-Methylphenanthrene 9-Methylphenanthr~n~ 1-Methylphenanthrène' ' 37.854 '39.068" 103.088 46.'035 46.123 46.950 47.108 48.111 48.357 . 4~ß7t 49.642 49.7,47 50.697 397374 /2à~?49.i( 1187 87139 20472 2a3983 245376 .589~30 420388 " i~~?~:;:· 154439 ... ".¡"' .' 7;4253". 93107 68368 46645 254 12461' 5719 40468 42108 81312 66759 1?(pa... ... 22584 .16367 . 14435 3426.3 2446.5···· 10.2 751.3 176.5 2276.2 2115.7 5080.a 3624.8 .,'.:'651.6:)' .... 1331.6 640.2 802.8 2577.7 175.8~6· 9.6 469.8 215.6 1525.8 1587.6 3065·7 : 2517.0 :.A79,;,~>; 851.5 617'.1 ., 544.2 46.492 ,.4ß.:r6~ . . 53.195 53':846 55.289 55;025 56.239 . .!j6.696q 57.083 58;139 58.420 ......:.,.',.. .1" 5~:;159 . 59.335 '60:250 . 60.707 70.225 64.666 65::827. . 66.583 . . 66:,759 ' 67.129 6i.~69 67.762 , 6~':q26, " 68.747 68;~41' 115.878 ,,116~916 117.849 119.010 75.169 ',.:' 'i5~34:5 I,i' i,' 76.048 76.224:' ., 11613 \::;:¡J ,?9êê '..', ..:.'. 210392 '·<7.~~ß$.: 58229 , 1'4~44't:)" 66899 ",.',1, '.'..:.;,,"'1,',-1,,',':' ·232~~g",. . 316127 2i~Ô5':t': . 214715 ··..··::~'~§~i4·i. 267939 ',á#92Ô' .. 139363 285510 88825 109}47 96601 ·5~031·· 22313 .4f9Qq······ 17061 . ·"·'3~i6~.:. 96630 ø470?~ ........ 9536 '9435.' 3781 3198 152755 ..1~99~~ 223196 ·':".16~ªªÖ" I 1917 .",22.18';- 33228 11597:: . 8896 '20046, 10272 36,43ª.:,,: '. 49758 40536 37375 111¡{i': : 38973 ,'·.Så19.·.·.·: 23349 55523 14695 21607 17260 1()142 '. 4342 :ß.44,~. 3576 65:67' 19210 . 't5349:., 3120 2484 1082 748 32183 ,3501 i 44745 ····337.1:~'·:':;i::·.··· 100.1 ..", ··::.11.1..r:"',· 1814.1 .' '·"'652:1:,,' 502.1 1288.6: 576.8 2003:2:. 2725.8 '2380.3 1851.4 568.9 2310.3 ·····'301'..1. 1201.6 2461.8, 765.9 94ft 832.9 474.5 192.4 361.3 . 147.1 2,?,3.9·. 833.2 730~9 82.2 81:4 32.6 27.6 1317.1 1465.7' 1924.5 ..1~08.7·.··· 72.3 ··.·âß:.~,::' 1252.8 .. 437.2"; 335.4 7,55,8.: 387.3 1373.8· 1876.0 1528.3 '. 1409.1 42Q,?·' 1469.4 '2Ú~.4,:' 880.3 2093~4 554.0 814~6, 650.7 382.4 163.7 318:6 134.8 ,247.6,. 724.3 578..7. ' '. 117.6 93,7 40.8 28.2 1213.4 1320.2 . 1687.0 ·127~.1,:· .. Company: Well Name: Depth: Sampling Point: CONOCOPHILLlPS PLACER 1 7556.5 - FT Client ID: Project #: Lab ID: File Name: US134019 04-223-A CP272564 M1040596.D --. ,. I , . .. . ... ";: :.. ,P.·j.... ~ 'd-,.' . .. \ ;\' '~ . . ," . .' '. . . Ret.· . ppm ppm" ~~.,..,.,- : . ,..' "...... .. Time Area -'. I (Area) (Hght) . 198 CAD Cadalene 66.179 8387 1647 72.3 62.1 198 12467PMN 1,2,4,6,7-Pentamethylnaphthalene 73.040 13323, "2973 114.9/ 112:1 198 12357PMN 1,2,3,5,7 -Pentamethylnaphthalene 73.357 9008 1826 77.7 68.8 198 4MDBT 4 Methyl Dibenzothiophene 73.497 '135153 ' 27731 1165.3 1045.5 198 23MDBT 2 & 3 Methyl Dibenzothiophenes 74.289 99216 19261 855.5 726.2 198 1 MDBT 1 Methyl Dibenzothiophene 75.098 f)516~ 12832 561.9 '/483.8 206 36DMP 3,6-Dimethylphenanthrene 79.409 27929 5669 240.8 213.7 206 26DMP 2,6-Dimethylphenanthren~ " 79),65~' ,.,129913, '·'4;95.1:.- 488,~ .'. 206 27DMP 2,7 -Dimethylphenanthrene 79.760 33983 7392 293.0 278.7 (3,9+3,10+2, 1 0+1,3).Dimethylph~l1a~thren~s .' ". 206 39DMP 80.~?1 2~,9~~6,: . '. '. 48.659 2325.~" 1834·9 206 29DMP (2,9+1,6)-Dimethylphenanthrenes 80.464 135248 21660 1166.2 816.6 206 17DMP 1 ,7 -Dimethylphenanthrene 80.622 ' , 24189 '922.8: " 912.0 1p7026 206 23DMP 2,3-Dimethylphenanthrene 80.886 38243 7912 329.7 298.3 206 19DMP 1,9-Dimethylphenanthrene ,81:010- ··'.~2457 134-45 538.5 506.9, ' 206 18DMP 1,8-Dimethylphenanthrene 81 .432 29996 5520 258.6 208.1 206 12DMP 1,2-Dimethylphenanthrene 81:942 20395 4510 175.9 170.0 206 9_ 10DMP 9,10-Dimethylphenanthrene 82.575 3566 928 30.7 35.0 212 DMDBT Dimethyldibenzothiophene 78.247 620057 ~5523, 5346.4 962.3 219 RET Retene 86.199 30483 6507 262.8 245.3 T rimethyldibenzothiophene ' .,..':81;:590, '. .",''', 17;304' '5259:0 'i' . 652:4:, 226 TMDBT ' ,.'. 6Q~~27, 231 231A20 cio Triaromatic Steroid 92.234 34503 7885 297.5 297.3 ."",:,:""":"",',,.'", ,'7256 ,'280:9', 231 231B21 C21 T riaromatic 94.732 :32573 273.6; 231 231 C26 C26 20S Triaromatic 103.880 32268 7304 278.2 275.4 231 231026 C27 20S & C26 20R Triaromatic 105.464 71836 14411 619.4 543.3 231 TAOMD1 C28 23,24-Cholestane Triaromatic 106.026 1105 333 9.5 12.6 231 TADMD2 C28 23,24-Cholestane Triaromatic·, 106.589 :34p1 846 29.8 31.9 231 231E28 C28 20S Triaromatic 106.801 57479 9324 495.6 351.5 r' :'"", 231 231F27 C27 20R Triaromatic 107.416 ·38450 6787 331.5 255.9 231 TADMD3 C28 23,24-Cholestane Triaromatic 107.504 3771 984 32.5 37.1 231 C29TA1 é29 Triaromatic 107.768 10587 1863 91.3 70.2 231 C29TA2 C29 T riaromatic 107.979 6546 1563 56.4 58.9 C28 23,24-CholestanE~ Triarom~tic ..'. ''''0''','''. 740.' 27.;9 231 TADMD4 108;806 ..... 31.()5· .", 26.8 231 231 G28 C28 20R Triaromatic 109.017 50025 9940 431.3 374.8 C28 23,24-Cholestane Tri::¡rorTIåtic . " ,'",1,." 1595. 19.9 231 T ADMD5 109.105 230~. 60:1 231 C29TA3 C29 Triaromatic 110.319 12192 2872 105.1 108.3 245 C3S C27 20S 3-Methyl Triaromatic Steroid 106.554 5110 1032 44.1 38.9 245 C4S C27 20S 4-Methyl Triaromatic Steroid 107.170 6904 1590 59.5 59.9 245 E2S C28 20S 2-Methyl TriaromaticSteroid 107.715 3003 566 25.9 21:3 245 E3SC3R C28 20S 3-Methyl & C27 2qH 3-MethylT AS 108.067 14915 2555 128.6 96.3 .. 245 E4SC4R C28 20S 4-Methyf & C27 20R 4:-Methyl TAS 10ª:66q 21573 3410 186.0 128.6 245 S2S C29 20S 2-Methyl Triaromatic Steroid 108.894 3922 559 33.8 21.1 245 DA Triaromatic Dinosteröid a 109.088 3795 871 32.7 32.8 245 S3S C29 20S 3-Methyl Triaromatic Steroid 109.281 11499 1710 99.1 64.5 245 DB Triaromatic Dinosteroid b 1 Q9.686·. 8182 1924 70.5 72.5 245 S4SE2R C29 20S 4-Methyl & ~28 20H 2:Me.~hyl T AS 109.862 15336 2300 132.2 86.7 245 E3R C28 20R 3-Methyl Triaromatic Steroid 109.985 10789, 1542· 93.0. 58.1 245 E4R C28 20R 4-Methyl Triaromatic Steroid 110.583 11671 2313 100.6 87.2 245 DC Triaromatic Dinosteroid c 110.777 8560 .1983 73.8 74.8 245 DO Triaromatic Dinosteroid d 110.882 11984 2631 103.3 99.2 I 'I Company: Well Name: Depth: Sampling Point: CONOCOPHILLlPS PLACER 1 7556.5 - FT Client ID: Project #: LablD: File Name: US134019 04-223-A CP272564 M1040596.D I ;-"':': ',Peak' ~" -, c.-. ~T' .' .', - .., Ret. ppm ppm' - '!! . . . . ,.' ~ . .. . ," . .. . Area Hei. ht (Area) (Hght)· 245 S2R C~9 20R 2-Methyl Triaromatic ~teroid 111.304 2688 564 23.2 21.3 , - 245 S3R C.29 20R 3-Methyl Triaromatic Steroid 111.515 10468 " 21.22 90.3" 80:0, 245 DE Triaromatic Dinosteroid e 111.639 9323 1826 80.4 68.8 245 S4R C29 20R 4-Methyl Triaromatic Steroid 112.078 9446 1804 81.4 68.0 I 245 DF Triaromatic Dinosteroid f 112.219 14714 3442 126.9 129.8 253 S253A C21 Ring-C Monoaromatic Steroid 84.493 13369 2988 115.3 112.7 253 S253B C22 Monoaromatic steroid 86.938 9778 2071 84.3 78.1 253 S253C C27 Reg 5ß(H),1 Oß(CH3) 20S 96.896 3868 951 ' 33.4 ' ,35.9 I 253 S253D C27 Dia 10ß(H)5ß(CH3~ 20S 97.037 12898 3495 111.2 131.8 , , : 253 S253E C27 Dia10ßH,5ßCH3 20R+Reg5ßH,10ßCH320R ' 98.514 " " 12452,' ,2764 107.4 ' 104.2 ,253 S253F C27 Reg 5a(H),10ß(CH3)20S , .. 98.655 4715 1066 40.7 40.2 [ 253 S253G C28 Dia 10aH,5a.CH3 20s+Reg5ßH,10ß'CH3 20S 99.060 17363 3237,' , '149-7 122.0 253 S253H C27 Reg 5a.(H),10ß(CH3)20~ 100.326 3345 853 28.S 32.2 253 S2531 C28 Reg 5a(1),1 Oß(CH3) 20S 100.485, 3338,,' ",'. .714,',,', ' 28.S'" ' 2.6.9' 253 S253J C28 Dia 1 OaH,5a.CH3 20R+Reg5ßH, 10,ß~H3 20R 100.661 13181 2905 113.7 109.5 253 S253K C29 Dia 1 OßH,5ßCH3 20S+Reg5ßH, 1 ÒPCH3 20S 100.784 18483 ' '3894 " 159.:4 146.8 253 S253L C29 Reg 5a.(H),10ß(CH3) 20S 102.086 3110 646 26.S 24.4 253 S253M C2S Reg 5a.(H),1 Oß(CH3) 20R '102.367 ,5730 931 49.4 ' 35.1, 253 S253N C29 Dia 1 OßH,5ßCH3 20R+Reg5ßH,1 OßCH3 20R 102.473 12875 2420 111.0 ' 91.2 253 S2530 C29 Reg 5a.(~),10ß(CH3) 20R.' 104:091 3:422 '666' ,29.5' 25.1 [ [ [ I I " l Company: Well Name: Depth: Sampling Point: CONOCOPHILLlPS PLACER 1 7556.5 - FT Client ID: Project #: Lab ID: File Name: US134019 04-223-A CP272564 M1040596.D ,~~:':~:J--:' ..'.' :: ~ :~:',~;::'~.:.'?;".:'~ ,-Mis~.~II~~'~ous_ Ratio~ . I, . By Areas By Heights - I' ~. ''','.- t. ~ I. ~\ '" "'''. " .!..... '... I , , , . r . Triaromatic Steroids, m/z 231 ' (C20+C21 )/2: TAS 0.20 0.23 TAS #1 20/20+27 0.47 0.54' TAS #2 21/21+28 0.39 0.42 %26T AS ' 24.3 ,27.1 %27T AS 28.9 25.2 %28T AS 37.6 36:9 %29TAS 9.2 10.7 C28/C26 20S T AS ,1.78 ,1~28 C28/C27 20R T AS 1.30 1.46 Monoaromatic Steroids m/z 253 Dia/Regular C27 MAS """3.6W %27 MAS 37.2 %28 MAS 31:7': ' %29 MAS 31.1 (C21 +C22)Œ MAS 0.17 TAS/(MAS+ TAS) 0.69 T A28/(T A28+MA29) 0.72 Triaromatic Methylsteroids m/z 245 Dinosteroid Index 0.31 0.36 C4/C3+C4 Mester 0.52 0.55 Phenanthrenes and Naphthalenes MPI-1 0.72 0.75 MPI-2 0.76 0.78 Rc(a) if Ro < 1.3 (Ro%) 0.80 0.82 Rc(b) if Ro > 1.3 (Ro%) 1.87 1.85 DNR-1 6.86 5.05 DNR-2 2.21' 2.34; TNR1 0.78 0.92 TDE-1 3.99 4.01 TDE-2 0.25 0:29 MDR 2.07 ' '2.16 Rm(Ro%) 0.72 0.72 MDR23 1.17 1.25 MDR1 0.77 0.84 DBT /Phenanthrene 0.30 0.28 - - -- - - ~ - - - ----- - - Sampl e: US134019 Ion Mass 142+156+170+184 100000_ z ::;:: Q r- rl C'1 rl 8 0 0 0 0_ :z; ::;:: Q \D rl z ~ N z ::;:: rl z ~ ~ \D N z ::;:: E-o \D C'1 rl E-o U) C'1 E-o rl \D \D N '<I' rl rl r- \D Z Z rl ::;:: ::;:: E-o E-o r- \D C'1 C'1 rl N ~ E-o U) N rl Z ::;:: r>1 en en ~ ~ r>1 E- r- ~ " Z ~ E-o qo N rl r- \D C'1 rl \D Lfl N rl 6 0 0 00_ 4 0 0 0 0_ ~ Q qo rl 2; E Z 20 0 0 0_ fj ::;:: Q Z N r>1 " rl N C' r- Lfl C'1 rl r- '<I' N rl r- .n N r-i E-o a¡ Q r- \D N rl\D r-C'1 ~~ C'1 N Il } L _ 40'. 0 I ~ I.A! LJLJAk) u, 50'.0 .>-1 h J rJ· ~ \. ~ J \A J \ ^ 'y, ~ l...-J "-----' 60'.0 70',0 Retention Time (min) File: M1040596. D\data. IUS Date & Time: 1 ADr 04 9: 09 am ( M3) 30000_ 20000_ 1 0 0 0 0_ Sample: US134019 Ion Mass 184+198+212+226 1 File: M1040596. D\data. rns Date & Time' or 04 9: 09 am 64',0 E-< ¡:Q o :E q' E-< ¡:Q ~ o r- I.D (') r-I E-< I.D ¡:Q If) 0 N :E r-I (') E-< N ¡:Q ~ E-< r- q' N r-I E-i ÇQ o r- If) f"j r-I E-i ÇQ o :E r-I r- r- If) I.D N N r-I r-I I.D (') N r-I r- r- M I.D r~ (') d N z :E A< r-z I.D:E q'p.. N r- r-IlI) (') N r-I I, \ \ ~I ~/, r ~) ~!M'~\J 1\1 ~~ ~ JylA~^ J 68',0 72',0 76',0 Retention Time (min) (M4) , I \ .j,JA A, tf 80', 0 ,N WM~ 84'.0 7 0 0 0 0_ 6 0 0 0 0_ 50 0 0 0_ 4 0 0 0 0_ 3 0 0 0 0_ 2 0 0 0 0_ 1 0 0 0 0_ - Sampl e: US134019 Ion Mass 178+192+206 ~ 70'.0 File: H1040596. D\data. ms Date & Time: 1 Apr 04 9: 09 am - -... - - z ¡i] :r: P< ~^~ ~ P< ~ N P< ~ M )v - ~ ;--. P< ~ P< ~ ...... 72'.0 74'.0 76'.0 Retention Time (min) 78'.0 (M1 ) - P< ~ o '" M P< ~ 0 §: '" ...... 0 <.D N ~ ~ 0 M §! 0 N t- O N <.D M f I,J j' f'¡ 80'.0 - -" =~~- -~ §! o t- §!...... ~ N ~ ~ ro 0 ...... N p< ~l~~ 82'.0 Sampl e: US134019 Ion Mass 226 21 000_ 1 8000_ 1 50 0 0_ 1 2 0 0 0_ 9000_ 6 0 0 0_ 30 0 0_ o ro N r-- r-- 78'.0 80',0 File: H1040596. D\data. ms Date & Time: r 04 9:09 am llf E-i a:¡ CI ;:;:: E-i Ii\¡ V / r ~ 82',0 Retention Time (minj ( 1 9) v AJ 84'. 0 ro ffi ro "" ro N 86', 0 - ----------------~' Sample: US134019 Ion Mass 245 5000_ Cï; <:1' U ~ W Q <:1' ~ 4 0 0 0_ Cï; Q 8 Q ~ Cï; ~ N ~ Cï; w "'" <:1' ~ W Cï; f') 300Q W u ~ 0\ ~ Cï; o <:1' W en f') \ en en Cï; <:1' M U ~ \ 2000_ U) M U f't ~ m II': rl 10 N 1 ~ ~~ Cï; r-: m ~ "' ~ "' œ ~ &. M¿ :;: M ~ N CD :;; r-- N ~ ~ f O~:9~ 10 rl rl 0\ f'"TI CD ~ 0\ tiI \~ "'" C ...... ri--\ ~ rl <:1' N 10. . ~ 10 0 W ~ \ jJ "': ~ r. rl CD N ~ <'Ì n % 8 ~;:';o . M "' 0"' o· m {\ ., .< rl Orl rl N 0 1000~ J ~~~~\A;Lwk~\_/ _~~_ ~_I_~_rl 3r ~ ~ I 102.0 104.0 106.0 108.0 110.0 112.0 Retention Time Iminl File: MI040596. D\data. rns Date & Time: 7 ADr 04 9: 09 am 21 - - - -- ~ ~ - ..-- ---. ~ - - - Samp1 e: US134019 Ion Mass 231 16 000_ \D N o rl M N 1 2 000_ 0 N .( rl rl N M III N rl 80 0 O- M N co N ~ rl M N co N ~ rl M N \D N U rl M N e- N fx< rl M N ~ ~ -, -,0 ~ N ~~ qo" rl ~ 5V'J ~ ~ JJ CU ~. ~ ~ .)~~~ M .( ð:{ 4 0 0 0_ N U 85'.0 90'.0 95'.0 100.0 105.0 110.0 6 0 0 0_ Ion Mass 253 50 0 0_ :.:; M U) N 0 en M ~ U) M N U) en N I-J en M ~ U) M N Z U) CIJ M N U) en N en 4 0 0 0_ 1'1; (Y) U) N en 3 0 0 0_ III (Y) U) N en 2 0 0 0_ 1 00 0_ ~ ~~I~m Í< ~ ~ ~ ~ H~ g ~~~"J~~II J¡ A~~ 85'.0 90'.0 95'.0 100.0 Retention Time (minI 105.0 110.0 File: MI040596.D\data. ms Date & Time: 1ADr04 9:09am ( M2) 16 0 0 0_ 1 2 0 0 0_ Sampl e: US134019 Ion Mass 91 +92 2 4 0 0 0_ 20000 8 0 0 0_ 4 000_ . .' r~, 1#\ ~~. ~MÅ h ¡ \ 1M Á It J N \, II' ~ I 40',0 50',0 60',0 70',0 file: M1040596 "\data. ms Dale & Time: "04 9:09 am J, I~~ I~I~>~ I \#~~~\J<\\,~"",,~ 80'.0 Retention Time (min) 90'.0 100. 0 110.0 120.0 \11 3) 2 8 0 0 0_ 24000_ 20000_ 16 000_ 1 2 0 0 0_ Sampl e: US134019 Ion Mass 105+106 8000_ 4000_ .'"~~, wij ~I' ~ 40'.0 50'.0 File: HI040596. D\data. rns Date & Time: 7ADr04 9:09am - j.,J I 60'.0 - - - .....--¡ I ~ , ~~ ~1~ ~I..~)r~,' ~, .~ ~.~ ~~'~Å~I u.- 70'.0 80'.0 Retention Time (minI 90'.0 100.0 ( M1 4 ) , ...--- 110.0 120.0 Sampl e' Ion M . US13401 ass 133 9 +134 1 0000_ 8000. 60 0 0_ 4 0 0 O~ I ' ' , 2000 " 'I . ,I , I . I I'd I ,,/' d ,/1/ ! Ii " . I I' ' I I . I 'I J j J ¡Iii j I ¡ ~ I ¡I 11 f I ' / ' : 11/ " I ,,",' Ii, ¡,! I 'I I I' :" I ,'" I IJ ' I t I V< , ' /1 } f1 (/I¡J, , '" " . ,JJ )Ilk 't.J~ ~Iill~ Út /¡II!; I }t i I / /11 ~ I II! ' I II¡'AI ,,~t~I.,~,~¡I}~j\~~~I\~M 50. 0 60. 0 70. 0 Retel1t' 80.0 ~OI1 T' ~me (min) 90.0 100. 0 110.0 File: 111040" Dat,.. r "'~ _~ data. m.s -- f'\.f 9: 0 Q _ 11.116) , 1\ r~~ 120. 0 I I I I I I I I I I I I I I I I I I I ~æ.. May 2004 HGS Reference: 04-2371 Ii Humble Geochemical Services Division of Humble Instruments & Services, Inc. 218 Higgins Street Humble, Texas 77338 P.O. Box 789 Humble, Texas 77347 Telephone: 281-540-6050 Fax: 281-540-2864 ConocoPhillips Placer #1 Well, North Slope, AK ;)Öt.{ - 0 I c-f Summary Geochemistry Report: ConocoPhillips Placer-l Well, North Slope, Alaska Executive Summarv Wet, bagged cuttings collected at 5 ft. intervals over 7525-7590 ft. at the Placer-I, Alaska, well were delivered to Humble Geochemical on 14 March 2004 for pyrolytic analysis and assessment of reservoir and oil quality. Also delivered was a sample of the drilling fluid additive identified as Lubtex. The following data and conclusions were delivered via e-mail on 15 March 2004, based on pyrolytic and gas chromatographic study of those samples: Reservoir Quality: · Based on the pyrolytic response of the cuttings, the most oil-productive interval is 7545-50 ft., where about 60% of the hydrocarbon pyrolytic response is from "oil." Within the reservoir, that response drops to 40% from 7540-45 ft. and 7550-55 ft., and to about 25% from 7555-60 ft. The remaining hydrocarbon response is due to kerogen (from shale), and to tar. Oil Quality: · The overall hydrocarbon response is low for all these cuttings, which makes the oil quality assessment more difficult. The pyrolytic signature from the 7545-50 ft. is atypical to that of other oil-productive intervals studied at Kuparuk and West Sak. Specifically, it has a higher proportion of light hydrocarbons, and lower levels of thermally distillable (higher boiling oil). Using compositional modeling, we determine that the oil quality is ~20 API. However, the elevated light components do not appear to be consistent with this calculated API, implying a higher API may be closer to reality due to possible mixing with a lighter oil. · Extracts from two intervals, 7550-55 ft. and 7560-65 ft., show clear oil signatures. The former yielded very little extract and the signature carries an odd over even preference from n-C15-2I. while the latter sample yielded much more extract, and carries a signature more typical of a mature oil. The light hydrocarbon portions of these oils were not preserved, likely due to sample handling. Some mud additive contamination is evident, but it is minor. Humble Geochemical Services Page 1 of9 I I I I I I I I I I I I I I I I I I I May 2004 HGS Reference: 04-2371 ConocoPhillips Placer #1 Well, North Slope, AK Introduction Wet, bagged cuttings collected at 5 ft. intervals over 7525-7590 ft. at the Placer-I, Alaska, well were delivered to Humble Geochemical on 14 March 2004 for pyrolytic analysis and assessment of reservoir and oil quality. Also delivered was a sample of a drilling fluid additive identified as Lubtex. The objective of this work was to quickly characterize both oil and reservoir quality based on the patented "POPI" (pyrolytic oil productivity index) technology (Jones and Tobey, 1999), and based on the recently introduced CoMod (compositional modeling) technology developed at Saudi Aramco by Jones and Halpern (2003). These assessments were to be used in operational decision-making at the well site, and hence the rapid turn-around requirement. The samples were received at Humble Geochemical at 14:15 on 14 March and an assessment of oil and reservoir quality was delivered at 19: 15 on 15 March. Our assessment was based on calibration data compiled from numerous Kuparuk and West Sak oil and core samples. The Kuparuk oils are nearly pure Triassic (Shublik) oil, rich in asphaltenes (5-8%), and with API gravities in the 24-30 degree range if not biodegraded. The West Sak oils are ~60% Triassic (Shublik) sourced, ~40% Cretaceous sourced. The Cretaceous oil is lighter and contains ~ 1 % asphaltenes. The calibration work was initiated in 2003. The pyrolytic technique must be calibrated to the oil types present in the system studied, because oils that differ genetically can yield different pyrolytic profiles. It is the pyrolytic profile of the oil stained rock on which these technologies are based. These profiles are comprised of a light volatiles component (L V - the oil that is thermally desorbed from the rock at 195°C), a thermally desorbed component (TD - the oil that is thermally desorbed from the rock between 195°C and approximately 400°C, before oil asphaltenes and/or kerogen crack), and a thermally cracked component (TC - the asphaltenes and/or kerogen that cracks at temperatures approximately> 400°C) (Jones et al., 2003). Obstacles to these objectives were the quality of the cuttings themselves, the presence of organic additives in the mud system, the presence of shale particles intermixed with samples from reservoir zones, and an auto-sampler malfunction that delayed analyses for 6 hours overnight. Surprisingly, the PDC bit cuttings taken within the suspected reservoir zone were only lightly oil-stained compared to the core samples we calibrated to. Further, much of the pyrolytic response in these samples was found to be due to bits of overlying shale which caved/were carried with the mud system into the reservoir zone. The techniques applied are based on the pyrolytic response of the oil within the reservoir, and therefore interference from mud additives and kerogen must be mathematically "removed" via the compositional modeling process. Sample Preparation Cuttings were water-washed and sieved through a 20 mesh sieve to remove the largest pieces, which were suspected to be cavings, and the material that passed through 20 mesh was sieved again through a 60 mesh sieve to isolate even smaller particles. The <60 mesh cuttings were dried at 50°C, and then ground to a powder and pyrolyzed on the Humble Humble Geochemical Services Page 2 of9 I I I I I I I I I I I I I I I I I I I May 2004 HGS Reference: 04-2371 ConocoPhillips Placer #1 Well, North Slope, AK Instruments Source Rock Analyzer. The samples were heated isothermally at 195°C for 3 minutes, and then to 630°C at 25°C/min., under a stream of helium. Thermally desorbed and thermally cracked hydrocarbons were monitored via flame ionization detector (FID). The cuttings which did not pass through the 60 mesh sieve, but did pass through the 20 mesh sieve were treated identically as the <60 mesh samples. We observed no difference in the pyrolytic response of the > 60 mesh and < 60 mesh samples, and the conclusions drawn are based on the < 60 mesh sample data. Two cuttings, 7550-7555 ft., « 60 mesh) and 7560-7565 ft., « 20, > 60 mesh) were selected for extraction in methylene chloride and examined by gas chromatography (GC). Likewise, the Lubtex drilling fluid additive was examined by GC. Results and Discussion The pyrolytic yields for these cuttings are presented in Table 1. Most striking is the low level of hydrocarbons encountered (LV + TD+ TC) compared to Kuparuk core samples examined earlier (Table 2). The total yield for the Placer-1 cuttings varied from 0.66-1.41 mg HC/g rock compared to an average of approximately 12 mg HC/g rock for core samples from four Kuparuk wells. Some dilution is to be expected for cuttings, however, particularly with PDC drill cuttings. Also striking is the prominence of the TC component in the yields. As is discussed below, this is undoubtedly the result of shale contamination (i.e., kerogen) in the reservoir sand cuttings. The pyrolytic profiles of cuttings samples are presented in Appendix A. All the samples yielded profiles more characteristic of a source rock, such as a shale (dominated by a large thermally cracked [TC] component), rather than an oil-stained reservoir rock, with the possible exception of samples from 7530-35 ft., 7540-45 ft., 7545-50 ft., and perhaps 7550- 55 ft. This attests to the high degree of shale contamination intermixed with the sandstone reservoir cuttings. Thus, reservoir quality and oil quality assessments made strictly on the POPI values will not be valid. Under these circumstances, we must apply the compositional modeling algorithms developed by Jones and Halpern (2003) to "remove" the shale and drilling additive contaminants from the pyrolytic profile. Additionally, we extracted two samples to obtain a GC fingerprint of the oil to assist us in assessing oil quality. Appendix B presents the extract GC signatures for samples at 7550-7555 ft. and 7560-7565 ft., as well as the GC signature of the drilling additive Lubtex. The extract chromatograms yielded high quality oil signatures with n-alkanes extending from approximately n-Cg through n-C31. The light ends of the extract have been removed, presumably during sample handling. The extracted oil does not appear to be biodegraded. However, tar was identified within the reservoir when compositional modeling algorithms were applied to the pyrolytic data (see Figure 1 below), suggesting that some alteration by anaerobic biodegradation may have occurred. While contamination from Lubtex is evident in the oil signatures, at least one other contaminant, eluting at approximately 44 minutes, is also present. Based on the chromatographic signatures, we would expect this oil to be among the higher quality oils encountered at Kuparuk / West Sak - API gravity in the 27-33 range. Humble Geochemical Services Page 3 of9 I I I I I I I I I I I I I I I I I I I May 2004 HGS Reference: 04-2371 ConocoPhillips Placer #1 Well, North Slope, AK Applying the compositional modeling algorithms of Jones and Halpern (2003) to the pyrolytic data illustrated in Appendix A, the most oil-productive interval is 7545-50 ft., where about 60% of the hydrocarbon pyrolytic response is from "oil (Figure 1)." Within the reservoir, that response drops to 40% from 7540-45 ft. and 7550-55 ft., and to about 25% from 7555-60 ft. The remaining hydrocarbon response is due to kerogen (from shale) and to tar. Using the CoMod algorithms to assess the oil quality at 7545-50 ft., one notes that the pyrolytic signature from the 7545-50 ft. is atypical to that of other oil-productive intervals studied at Kuparuk (Figure 2). Specifically, it has a higher proportion of light hydrocarbons, and lower levels of thermally distillable (higher boiling oil). Using compositional modeling, we determine that the oil quality is ~20 API. However, the elevated light components do not appear to be consistent with this calculated API, implying a higher API may be closer to reality due to possible mixing with a lighter oil. Summarv These Placer-l cuttings presented multiple difficulties because of the low residual oil staining within the cuttings, the high levels of shales mixed with the sandstone reservoir intervals, and the presence of a lighter oil in greater proportion than observed in the Kuparuk and West Sak oils, to which we had calibrated our pyrolytic response. Nevertheless, using CoMod technology, we determine that the most productive reservoir interval occurs at 7545-50 ft. Using the calibrations based on Kuparuk and West Sak oils, the oil quality was assessed at ~ 20 API. However, we note that the presence of an excess of light volatiles in the oil, as shown by the pyrolytic profile, suggests that either (1) a light drilling additive contaminant has been introduced, or (2) a lighter, higher API oil, to which we did not calibrate, exists in the reservOIr. Mark H. Tobey Brian Jarvie W. David Weldon Dan M. Jarvie 25 May 2004 Humble Geochemical Services Page 4 of9 I I I I I I I I I I I I I I I I I I I May 2004 HGS Reference: 04-2371 ConocoPhillips Placer #1 Well, North Slope, AK References Jones, Peter J. and Mark H. Tobey (1999), The Pyrolytic Oil Productivity Index, US Patent 5,866,814 Jones, Peter J. and H.I. Halpern (2003), Compositional Modeling, Provisional Patent application Jones, Peter J., H.I. Halpern, D.M. Jarvie, D.W. Weldon, J.M. AI-Dubaisi, and S.M. AI- Qathami (2003), New Applications to Assess Reservoir Quality in Oil Reservoirs Using Pyrolytic Techniques, Presented at the AAPG Annual Convention, May 2003, Salt Lake City, UT Humble Geochemical Services Page 5 of9 I I I I I I I I I I I I I I I I I I I May 2004 HGS Reference: 04-2371 ConocoPhillips Placer #1 Well, North Slope, AK Table 1. Pyrolytic yields for Placer-l cuttings. Inmal uepm Final uepm LV IU 1(; (ft.) (ft. ) (mg HC/g rock) (mg HC/g rock) (mg HC/g rock) LV+TD+TC 7525 7530 0.11 0.10 1.03 1.24 7530 7535 0.10 0.42 0.90 1.41 7535 7540 0.08 0.23 0.57 0.89 7540 7545 0.13 0.18 0.93 1.23 7545 7550 0.30 0.27 0.82 1.39 7550 7555 0.10 0.13 0.83 1.06 7555 7560 0.11 0.12 0.76 1.00 7560 7565 0.11 0.13 1.08 1.32 7565 7570 0.10 0.12 0.98 1.20 7570 7575 0.05 0.06 0.59 0.70 7575 7580 0.06 0.07 0.70 0.83 7580 7585 0.05 0.06 0.55 0.66 7585 7590 0.04 0.06 0.61 0.71 Humble Geochemical Services Page 6 of9 I I I I I I I I I I I I I I I I I I I May 2004 HGS Reference: 04-2371 ConocoPhillips Placer #1 Well, North Slope, AK Table 2. Pyrolytic yields for core samples from selected Kuparuk wells. LV IU Ie HGSID Client ID Well Depth (ft.) (mg HC/g rock) (mg HClg rock) (mg HC/g rock) LV+TD+TC 03-2126-68960 US039268 2E-10 6263.9 1.15 3.0 3.77 7.96 03-2126-68961 US039269 2E-10 6265.9 1.18 2.3 2.71 6.15 03-2126-68962 US039270 2E-10 6302.6 2.07 7.5 7.45 17.01 03-2126-68963 US039271 2E-10 6306.8 2.07 7.0 5.29 14.38 03-2126-68964 US039272 2E-10 6313.2 2.44 9.8 8.86 21.08 03-2126-68965 US039273 2E-10 6315.7 2.11 6.0 6.43 14.56 03-2126-68966 US039274 2E-10 6317.7 2.14 9.2 8.82 20.19 03-2126-68967 US039275 2E-10 6339.8 1.53 6.0 4.83 12.30 03-2126-68968 US039276 2E-10 6354.5 1.34 4.3 4.63 10.25 03-2126-68969 US039277 2E-10 6371.2 1.70 5.1 5.15 11.92 03-2126-68987 US039295 3H-09 6869.7 2.04 1.8 6.41 10.24 03-2126-68988 US039296 3H-09 6873.6 1.20 2.8 2.23 6.23 03-2126-68989 US039297 3H-09 6881.7 1.14 2.2 1.98 5.29 03-2126-68990 US039298 3H-09 6884.0 1.29 2.6 2.10 5.99 03-2126-68991 US039299 3H-09 6885.3 1.69 4.6 3.27 9.60 03-2126-68992 US039300 3H-09 6888.2 1.28 4.7 2.06 8.06 03-2126-68993 US039301 3H-09 6897.2 1.39 4.1 2.61 8.08 03-2126-68994 US039302 3H-09 6900.9 1.78 5.9 3.55 11.24 03-2126-68995 US039303 3H-09 6907.8 1.51 3.7 2.61 7.82 03-2126-68996 US039304 3H-09 6914.0 2.40 6.9 4.67 14.00 03-2126-68997 US039305 3H-09 6919.7 1.46 3.7 3.14 8.30 03-2126-68998 US039306 3H-09 6921.5 0.58 1.6 1.65 3.83 03-2126-69019 US039791 38-14 6304.4 1.80 4.8 4.52 11.11 03-2126-69020 US039792 3B-14 6315.5 1.46 4.9 4.77 11.10 03-2126-69021 US039793 3B-14 6339.5 1.34 3.1 3.12 7.57 03-2126-69022 US039794 3B-14 6486.2 3.19 17.1 7.94 28.19 03-2126-69023 US039795 3B-14 6517.8 3.41 13.2 9.56 26.19 03-2126-69039 US039824 2E-17 5918.0 1.39 1.8 5.24 8.46 03-2126-69040 US039825 2E-17 5930.0 1.57 2.6 4.14 8.35 03-2126-69041 US039826 2E-17 5935.7 3.58 8.4 15.14 27.16 03-2126-69042 US039827 2E-17 5942.0 1.98 3.6 7.16 12.74 Humble Geochemical Services Page 7 of9 ------------------- March 2004 HGS Reference: 03-2130/03-2217 Ouachita Exploration, LLC Schramm/Worley #1 WeB, Milam County, TX Figure 1. Relative percent of pyrolytic hydrocarbon response at the Placer 1 well, based on the compositional modeling work of Pete Jones. Composition of Residual Staining: %Oil .%Tar D %Sh 100.0 90.0 80.0 70.0 ..... 60.0 s:: Q) f: 50.0 - Q) '!I\ ~:~ ~ a.. 40.0 ., " ª' ! > _ ~ 1L » ~,-.,~ . ',~. " . -... - , . 30.0 ' . 20.0 10.0 0.0 I I I I &0 Q &0 Q &0 Q &0 Q &0 Q &0 N M M <lit <lit &0 &0 to to ..... ..... &0 &0 &0 &0 &0 &0 &0 &0 &0 &0 &0 ..... ..... ..... ..... ..... ..... ..... ..... ..... ..... ..... Measured Depth Humble Geochemical Services Page 8 of9 - - - - - March 2004 HGS Reference: 03-2130 / 03-2217 - - - - - - - - - - - - - - Ouachita Exploration, LLC Schramm/Worley #1 Well, Milam County, TX Figure 2. Oil quality at the Placer 1 well 7545-50 ft., based on the compositional modeling work of Pete J. Jones: The Magenta curve is the pyrolytic response of the sample, which is shown to have a relatively high TC peak. CoMod utilized an Oil End-Member from a core sample (Light blue curve, Kuparuk 2Z-18 well, #69013, ~29 API), a Tar End-Member from the asphaltene fraction of an oil sample (Red curve, Kuparuk 2G-07 well, West Sak A3 Sand, 14.7 API, #68938 ), a Kerogen End-Member (Brown curve, Palm-1A well, #75764, 9040-60 ft.), and a Mud-Additive End- Member from a Lubtex sample (Turquoise curve). The green curve is the Recalculated pyrolytic curve that represents the response expected from the modeled end-member components (in this case 74 % oil and 26 % tar) and is fit to the sample's response in Magenta; however, the fit is not very good. Finally, the Blue curve is the CoMod Corrected pyrolytic response that is obtained by taking the actual pyrolytic response and subtracting the portion due to non-migrated components (i.e., kerogen, in this sample's case, the modeled % of kerogen was 0%). The pyrolytic response shown by the blue curve is not similar to the oil End-Member utilized in CoMod and the estimated API Gravity 20.1 API. It is also observed that the actual sample (Magenta curve) has an excess of light components that could be the result of a light drilling additive or a lighter hydrocarbon that is not consistent with the 20.1 API oil staining as assessed by CoMod. The interpretation from CoMod therefore reflects the existence of very light oil-staining with API in the lower range of productive wells in the area. These results seem to be compromised by sample quality (dilution from cavings) and may be more pessimistic for this reason. 0.01 0.009 0.008 -- 0.007 0.006 ¡¡ 0.006 ;; 0.004 0.003 0.002 0.001 0 -20 Humble Geochemical Services - Original - Recalculated """,w'~Oil End-Member: 29 API -Tar End-Member - Mud Additive - Corrected - Kerogen in Shale 7545-50 ft. pyrogram 30 80 230 280 330 Data Step 630 680 380 430 480 130 180 Page 9 of9 0.016 0.013 0.011 0.009 0.007 ¡¡ ;; 0.005 - 0.003 0.001 -0.001 630 J I I I I I I I I I I I I I I I I I I I May 2004 HGS Reference: 04-2371 Humble Geochemical Services ConocoPhillips Placer #1 Well North Slope, AK APPENDIX A: Cuttings Pyrograms Appendix A Page 1 of 5 ConocoPhillips Placer #1 Well, North Slope, AK .. .. .. .. ............................ May 2004 HGS Reference: 04-2371 ConocoPhillips Placer #1 Well, North Slope, AK 4.00E+06 4.00E+06 3.50E+06 Placer-l Cuttings: 3.50E+06 7525-7530 ft. 3.00E+06 3.00E+06 II) II) II> 2.50E+06 II> 2.50E+06 c c 0 0 Q.. Q.. II> 2.OOE+06 II> 2.OOE+06 II) II) D:: 1.50E+06 - D:: 1.50E+06 c c ¡¡ 1.00E+06 ¡¡ 1.00E+06 5.00E+05 5.00E+05 - O.OOE+OO O.OOE+OO 0 100 200 300 400 500 600 700 0 Time Interval Placer-l Cuttings: 7530-7535 ft. 100 200 300 400 500 600 700 Time Interval 4.00E+06 4.00E+06 3.50E+06 Placer-l Cuttings: 3.50E+06 7535-7540 ft. 3.00E+06 3.00E+06 II) II) II> 2.50E+06 II> 2.50E+06 c c 0 0 Q.. Q.. ~ 2.00E+06 II> 2.00E+06 II) D:: 1.50E+06 D:: 1.50E+06 c c ¡¡ 1.00E+06 ¡¡ 1 .OOE+06 - 5.00E+05 5.00E+05 O.OOE+OO O.OOE+OO 0 100 200 300 400 500 600 700 0 Time Interval Placer-l Cuttings: 7540-7545 ft. 100 200 300 400 500 600 700 Time Interval Humble Geochemical Services Appendix A Page 2 of 5 ------------------- 4.00E+06 4.00E+06 3.50E+06 Placer-l Cuttings: 3.50E+06 7555-7560 ft. 3.00E+06 3.00E+06 G) G) II) 2.50E+06 II) 2.50E+06 c c 0 0 Q. c.. g¡ 2.00E+06 g¡ 2.00E+06 0::: 1.50E+06 0::: 1.50E+06 c c ¡:¡: 1.00E+06 ¡:¡: 1.00E+06 5.00E+05 - 5.00E+05 O.OOE+OO O.OOE+OO 0 100 200 300 400 500 600 700 0 Time Interval May 2004 HGS Reference: 04-2371 4.00E+06 3.50E+06 3.00E+06 G) II) 2.50E+06 c 0 c.. ~ 2.00E+06 C 1.50E+06 - ¡:¡: 1.00E+06 5.00E+05 O.OOE+OO 0 Placer-l Cuttings: 7545-7550 ft. 100 200 300 400 500 600 700 Time Interval ConocoPhillips Placer #1 Wen, North Slope, AK 4.00E+06 3.50E+06 3.00E+06 Placer-l Cuttings: 7550-7555 ft. G) II) § 2.50E+06 c.. g¡ 2.00E+06 0::: C 1.50E+06 ¡:¡: 1.00E+06 5.00E+05 O.OOE+OO o 100 200 300 400 500 600 700 Time Interval Placer-l Cuttings: 7560-7565 ft. 100 200 300 400 500 600 700 Time Interval Humble Geochemical Services Appendix A Page 3 of 5 ------------------- May 2004 HGS Reference: 04-2371 4.00E+06 4.00E+06 3.50E+06 Placer-l Cuttings: 3.50E+06 7565-7570 ft. 3.00E+06 3.00E+06 ' <II <II III 2.50E+06 III 2.50E+06 c c 0 0 Q. Q. III 2.00E+06 III 2.00E+06 <II <II 0:: 1.50E+06 0:: 1.50E+06 c c ¡:¡: 1.00E+06 ¡:¡: 1.00E+06 5.00E+05 5.00E+05 - O.OOE+OO O.OOE+OO 0 100 200 300 400 500 600 700 0 Time Interval 4.00E+06 3.50E+06 3.00E+06 4.00E+06 3.50E+06 3.00E+06 -- <II III 5 2.50E+06 Q. !ß 2.00E+06 0:: C 1.50E+06 ¡:¡: 1.00E+06 5.00E+05 O.OOE+OO o Placer-l Cuttings: 7575-7580 ft. <II III c 2.50E+06 o Q. III <II 0:: C ¡:¡: 2.00E+06 1.50E+06 1.00E+06 5.00E+05 - O.OOE+OO o 100 200 300 400 500 600 700 Time Interval Humble Geochemical Services Appendix A Page 4 of 5 ConocoPhiHips Placer #1 Wen, North Slope, AK Placer-l Cuttings: 7570-7575 ft. 100 200 300 400 500 600 700 Time Interval Placer-l Cuttings: 7580-7585 ft. 100 200 300 400 500 600 700 Time Interval ...................................... May 2004 HGS Reference: 04-2371 Humble Geochemical Services 4.00E+06 3.50E+06 3.00E+06 () In s:: o c. m " c ü: 2.50E+06 2.00E+06 1.50E+06 1.00E+06 5.00E+05 O.OOE+OO o Placer-l Cuttings: 7585-7590 ft. 100 200 300 400 Time Interval 600 500 Appendix A Page 5 of 5 700 ConocoPhillips Placer #1 Well, North Slope, AK I May 2004 ConocoPhillips HGS Reference: 04-2371 Placer #1 Well, North Slope, AK I I ConocoPhillips I Placer #1 Well North Slope, AK I I I APPENDIX B: I Extract GC Data I I I I I I I I I I I Humble Geochemical Services Appendix B Page 1 of5 .. .. .. .. .. .. .. .. May 2004 HGS Reference: 04-2371 .. .. .. .. .. .. .. .. .. .. Figure 1. Gas chromatogram of standard oil for the purpose of peak identification and comparison to the Placer # 1 Well extracts. pA 1000 800 600 400 200 o D.. :2 N :L t() :;¡: .R cO"" ~ ~~~ '111:; ,[ o Ü f3 ~ .!: N Ü <') è: Ü .!: , I ro o .!: -0 o "W :.) .!: !'- o .!: <') Y"<t ·~o i .~ I [ I J: o :2 "<t ~t() o~ '0 e , e <D Ü .!:!'- Ü Ç: ~d t.: ~I ,0 0"':" ...!.. ro ;:. ~ õ: ~ a:¡ -0 ù5 Humble Geochemical Services Appendix B Page 2 of5 ConocoPhillips Placer #1 Well, North Slope, AK o <') o .!: <D <') o .!: !'- "" o .!: (J) roü UC: . f i 0 ci: I I G , cN o cgj y"" eN o c~ o .!:t() G .!:<D N y,- c::'i "-fro eN o .!: 90 ro "" o .!: (J) "" o .!: --------------- - -- May 2004 HGS Reference: 04-2371 ConocoPhillips Placer #] Well, North Slope, AK Figure 2. Gas chromatogram of Lubtex drilling mud additive used at the Placer #1 welL Ä, pA 1000 800 600 400 200 o 30 60 80 Humble Geochemical Services Appendix B Page 3 015 .. .. .. .. .. .. .. .. .. May 2004 HGS Reference: 04-2371 .. .. .. Figure 3. Gas chromatogram of Placer #1 cuttings, 7550-7555 ft., «60 mesh fines) extract. pA CD o C: ~ q ~ ~ 60 50 40 "" ü C: 30 I <') I t; c: N Ü C: 20 10 It) t?<o~ c:~o !t(t:o:)Q) ¡ c , __ ~ '00 ~ C:c:~ð~ I c.;> Jc.;><') i c: if C:N~ II 00 Ii C: Ci.(') II N o It C:~ ~ c.;>¡:;;¡ ä: C:o C: 40 60 Humble Geochemical Services Appendix B Page 4 of5 .. .. .. .. ConocoPhillips Placer #1 Well, North Slope, AK "" <') o C: <0 <') c.;> c: .. .. - - - - - - - .. - May 2004 HGS Reference: 04-2371 - .. .. .. pA Figure 4. Gas chromatogram of Placer #1 cuttings, 7560-7565 ft., «20, >60 mesh fines) extract. 140 120 100 - 80 60 CL 0 ~ N rh Ý ~ . c: 40 <::> t; ie 20 20 I{) «<tY 0C:~~ ¿, yy ~C:<:O ü~ coo Cf3NN cS'f3M C:c:f3~ I..- e:<..? t.O CL c:~ ~ c:æ ö: or- e: f3 co 0) eN N Yo c: ¿, 40 Humble Geochemical Services Appendix B Page 5 of5 .. .. .. - - - ConocoPhillips Placer #1 Well, North Slope, AK 80 I I I I I I I I I I I I I I I I I I I . [ore Lab PHRDLEUM SERVI[ES CORE LABORATORIES ¡ () "'Í" 0 I '"'f ,AO~t:..C- CORE ANALYSIS RESULTS c-:> C.::J -~rï CONOCOPHILLlPS ALASKA, INC. PLACER #1 WELL COLVILLE RIVER FIELD CL FILE 57111-104080 Performed by: Core laboratories 3430 Unicorn Road Bakersfield, CA 93308 (661) 392-8600 I I I I I I I I I I I I I I I I I I I A [ore LaI:Ï RESERVOIR OPTIMIZATION Petroleum Services Division 3430 Unicorn Road Bakersfield, California 93308 Tel: 661-392-8600 Fax: 661-392-0824 www.corelab.com Ms Justine Boccanera/Andreas Andreou ConocoPhillips Alaska Inc. PO Box 100360 Anchorage, AK 99510-0360 April 19, 2004 Subject: Transmittal of Sidewâll Core Analysis Data Placer #1 Well Colville River Field CL File No. 57111-104080 Dear Ms Boccanera: Twenty-one rotary sidewall core samples from the subject well were submitted to our Bakersfield, California laboratory for standard Dean-Stark permeability, porosity, and saturation (PKS) determinations. Upon receipt, one sample, that from 7556.5', was immediately forwarded to Baseline DGSI for geochemical analysis. The remaining twenty samples were trimmed to right cylinders for the PKS analysis and the end-trims were forwarded to Mark Mercer for thin-section preparation. The partially extracted geochemical analysis sample was returned by Baseline DGSI and is reported along with the initial samples but with fluid saturations excluded. Accompanying this letter, please find the results of this study. We appreciate this opportunity to be of service to you and to ConocoPhillips Alaska, Inc. If you have any questions, or if we may be of further assistance in the future, please contact us. truly yours, -; JLS:nw 1 original report, 5 cc report, 6 diskettes: Addressee . ------------------- Â\ Company: ConocoPhillips Alaska Location: Sec 32-12N-07E File No.: 104080CP Well: Placer 1 Elevation: API No.: 50-103-20481 Core Lab Field: Colville River Drlg Fluid: Gel Date: 4\14\2004 Rotary Sidewall Cores Core Analysis Results Sample Depth Rec Perm. Porosity Fluid Saturation No. Inches Kair Oil I. w:er I OIW 1 Total Grain Smpl ft met % % Ratio. % Den Wt. Mthd Description 7539.0 2.0 0.02 6.3 0.0 99.2 0.00 99.2 3.30 24.6 (4) Sst gry vfgr vsIty sIcalc no stn no flor 2 7540.0 1.8 0.01 8.6 4.5 93.3 0.05 97.9 3.15 35.4 (4) Sst gry-Ibrn vf-cgr vsIty slcalc Isp stn vdorng flor 3 7541.0 1.8 0.01 13.0 0.4 95.4 0.00 95.9 3.18 44.4 (4) Sst gry-Ibrn vf-mgr vsIty slca1c Isp stn vdorng flor 4 7542.0 1.8 0.05 11.4 16.3 78.9 0.21 95.2 3.21 20.4 (4) Sst brn vf-cgr vsIty m stn vdorng flor 5 7543.0 1.6 0.01 8.3 8.8 80.9 0.11 89.7 3.17 36.9 (4) Sst Ibrn-gry vf-cgr vsIty msp stn vdorng flor 6 7544.0 1.7 1.46 19.1 17.9 76.4 0.23 94.3 2.82 34.2 (4) Sst brn vf-cgr vsIty m stn vdorng flor 7 7545.0 1.0 F/5.63 ILl 24.7 75.0 0.33 99.7 3.24 16.1 (4) Sst brn vf-fgr vsIty/ mdst incl m stn vdorng flor 8 7546.0 1.4 0.19 14.4 22.6 70.6 0.32 93.2 3.06 23.8 (4) Sst brn vf-fgr/mgrs vsIty m stn vdorng flor 9 7547.0 1.5 0.05 13.7 16.8 79.3 0.21 96.0 3.13 19.0 (4) Sst brn vf-fgr vsIty m stn vdorng flor 10 7548.0 1.7 0.06 12.0 24.1 74.2 0.32 98.3 3.14 40.9 (4) Sst brn vf-fgr/cgrs vsIty m stn vdorng flor 11 7549.0 1.7 0.08 17.1 7.4 63.4 0.12 70.7 3.18 38.3 (4) Sst brn vf-fgr/cgrs vsIty I-m stn vdorng flor 12 7550.0 1.5 0.34 15.4 17.2 6Ll 0.28 78.3 3.20 22.5 (4) Sst brn vf-fgr vslty m stn vdorng flor 7551.0 No recovery 13 7552.0 1.8 0.01 7.6 26.4 60.0 0.44 86.4 3.16 42.8 (4) Sst Ibrn-gry vfgr vsIty mstrk stn gId flor 14 7553.0 1.6 F/5.50 10.1 32.0 50.1 0.64 82.1 3.18 35.7 (4) Sst brn vf-fgr vslty mod stn gId flor 15 7554.0 1.3 2.87 26.1 56.5 25.8 2.19 82.4 2.93 25.0 (4) Sst dbrn vf-fgr slty/ mdst lam d stn dorng flor 16 7555.0 1.6 35.46 25.0 33.7 40.8 0.83 74.5 2.93 28.7 (4) Sst dbrn vf-fgr sIty d stn dorng flor 17 7556.0 1.4 3546.32 28.8 35.7 33.7 1.06 69.4 2.69 15.2 (4) Sst dbrn vf-fgr slslty d stn dorng flor 18 7556.5 1.5 552.53 26.2 2.74 19.5 (5) Sst brn vf-fgr slty d stn dorng flor 19 7557.0 1.6 0.16 10.5 48.7 23.8 2.05 72.5 2.91 21.5 (4) Sst Ibrn-brn vfgr vsIty d-m stn dgId flor 20 7558.0 1.6 61.04 23.7 32.1 33.6 0.95 65.7 2.77 31.6 (4) Sst dbrn vfgr sIty d stn dorng flor For Mthd Definition See Procedures Page ------------------- Â\ Cure I.Bb Company: Co no coP hill ips Alaska Well: Placer 1 Field: Colville River Location: Sec 32-12N-07E Elevation: Drlg Fluid: Gel File No.: 104080CP API No.: 50-103-20481 Date: 4\14\2004 Rotary Sidewall Cores Core Analysis Results Sample Depth Rec Perm. Porosity Fluid Saturation No. Inches Kair Oil I w::er I O/w I Total Grain Smpl ft me! % % Ratto % Den wt. Mthd Description 21 7559.0 1.3 1681.36 25.6 32.6 37.8 0.86 70.5 2.65 24.6 (4) Sst dbm vf-fgr slslty d stn domg flor FI Indicates visable fractures present. For Mthd Definition See Procedures Page ------------------- A Core Lab Sampling Method Drill Coolant Jacket Material Saturation Method Company: ConocoPhillips Alaska Well: Placer 1 Field: Colville River Procedure (1) Percussion N/A Lead Dean Stark (Toluene) Porosity Method Grain Volume Boyle's Law (Helium) Pore Volume Boyle's Law (Helium) Bulk Volume Pore Vol + Grain Vol Permeability Method Air File No.: 104080CP API No.: 50-103-20481 Date: 4\14\2004 Core Type: Rotary Sidewall Cores CORE ANALYSIS PROCEDURES AND CONDITIONS Procedure (2) Procedure (3) Procedure (4) Procedure (5) Percussion Percussion Rotary Rotary N/A N/A N/A N/A Aluminum None None N/A Dean Stark (Toluene) Dean Stark (Toluene) Dean Stark (Toluene) N/A Boyle's Law (Helium) Boyle's Law (Helium) Boyle's Law (Helium) Bulk Vol-Pore Vol Boyle's Law (Helium) Bulk Vol-Grain Vol Bulk Vol-Grain Vol Summation Of Fluids Pore Vol + Grain Vol Mercury Displacement Mercury Displacement Mercury Displacement Air Air Air Air Common Conditions Sleeved Sample Seating Pressure: N/ A Confining Pressure Pore Vol & Permeability: 400 psig Samples Dried At 235 Degrees Fahrenheit Additional Extraction by Soxhlet with Methylene ChlorideIMethanol Oil Density used in Calculation: 0.97 grms/cc For Mthd Definition See Procedures Page I I I I I I I I I I I I I I I I I I I Date: 12/1/2004 Scb umberger Fluid Analysis on MDT Samples ConocoPhillips Field: Exploration Well: Placer #1 co~!r! 'it! "~-I _ \4- .1 " ~.~ ~~ èS t Black Oil Full PVT Study Report ~ Prepared for Dennis Wegener ConocoPhillips ~ ....... ~ ~ ~~ ~N Standard Conditions Used: Pressure: 14.696 psia Temperature: 60°F Prepared by: Meisong Van Reviewed by: Dennis D'Cruz Schlumberger WCP Oilphase-DBR 2315 Schlumberger Street, Building 15 Houston, Texas, 77023 (713) 921-9500 Report #200400086 I I I Client: Well: Installation: Schlumberger ConocoPhillips Placer #1 Nordic #3 Field: Sand: Job #: Exploration KUPARUK 200400086 Table of Contents List of Figures .............................................................................................................................. . . . . . . . . . . . . . . . . . . . . . . List of Tables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I EXECUTIVE SUMMARy........................................................................................................................ ........... Objective . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Introduction ............................................................................................................................... ..................... Scope of Work........................................................................................................................... ......................... Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Sequence of Evsnts......................................................................................................................... .................... Chain of Sample .Custody....................................................................................................................... ............... I I RESULTS AND. DiSCUSSiONS.................................................................................................................... .... Fluids Preparation .and.Analysis . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Reservoir Fluid.Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I I PVT Analysis on Sampie.I.07~ Cylinder SSB .12120:-.GA; .Depth. 7558.1.ft.. MD................................................................ Constant CompositioD. ExpaDSion.at Tres.................................................................................................................... Differential Vaporization. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Oil Phase Properties................................................... ................................................................................................ Gas Phase Properties. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Compositions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Dead Oil Viscosil¥ at. Tr.es........................................................................................................................... ............ Multi-Stage Separation .Test................................................................................................................ ................... I I PVT Analysis on Sample 1.09; Cylinder SSB 12169-QA; Depth 7558.1 ft. MD Reservoir Oil Viscosil¥ at. Trøs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S10 Viscosity at.Diflerønt Temperatures................................................................................................................... . HTGC ............................................................................................................................................. I I Appendix A: Nomenclature. and. Definitions................................................................................................. Appendix B: Molecular. Wei.ghts .and.Densities.Used...... ...... ...... ...... ............ ............ ...... ...... ...................... Appendix C: EQUiPMENT..................................................................................................................... .......... Fluid Preparation. and .Validation................................................................................................................... ........ Fluid Volumetric.fPVfJ and. 'iscosily.Equipment.................................................................................................... Appendix D: PROCEDURE...................................................................................................................... ......... Fluids Preparation .and. Validation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Constant Composition .Expansion .Procedure. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Differential Vaporization .Procsdure. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Multi-Stage Separation. Test.......................................................................................................................... ...... Liquid Phase Viscosity. ami Density. Measurements DULing. D.V Step......................................................................... Stock- Tank Dil.{STOJ .Viscosity.and.Density.Measurements..................................................................................... Asphaltene, Wax.aod. Sulfur.Content.Measurements............................................................................................... SARfPJA Analysis...................................................................................................................... .......................... High-Temperature High.Pressure.FiltralÏnn. Test................................................. ,................................................... I I I I I I I WCP Oilphase-DBR 2 3 4 4 4 4 4 5 5 6 6 6 16 16 18 18 18 18 25 26 34 34 36 38 42 43 44 44 45 47 47 47 47 48 48 48 49 49 49 Job #: 200400086 I I I Client: Well: Installation: ConocoPhillips Placer #1 Nordic 113 Field: Sand: Job I: Exploration KUPARUK 200400086 Schlumberger List of Figures I Figure 1: Stock Tank O.il Chromatogram tSample .1.01).. ...... ....... .... .............. ...... ............. ..... ....... ............ ......... ....... 11 Figure 2: Stock Tank Oil.Chromatogram tSample.1.09).. ............ ...... ......... ...... ......... ........... ...... .... ....... .............. ....... 14 Figure 3: Constant.Composiiion.Expansion.at .155°.F.~.RelatiYe.Volwne .(Sample .1.0.1).................................................. 17 Figure 4: Differential.Liberatioo. 155°f."li.quid .Properties. {Sample. 1.01)................................................................... 20 Figure 5: Differential.Liberation 155°f.".Gas. Properties. .(Sample.1.07l...................................................................... 22 Figure 6: Separation. Corrected. Oil volume .Factor .(80). (Sample. un ....................................................................... 31 Figure 7: Separation. Corrected. Solution G.D.R {Rs). .(Sample.1.01).. ...... ........ ....... ......... ............... ...... ............... .......... 31 Figure 8: Reservoir. Fluid.Vis.cosity. 155°f.(Sample.1.09)... . ............ ...... ......... ...... ......... ........ ....... ..................... ...... .... 35 Figure 9: Stock Tank Oil Viscosity .YS. Temperature. .(Sample .1.09). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . 37 Figure 10: HTGC. tSample .1.09)........... ...... ............ ...... ...... .... ..... ......... ...... ...... ............ ............ ...................... ......... 40 I I I I I I I I I I I I I I I WCP Oilphase-DBR 2 Job I: 200400086 I I I Client: Well: Installation: ConocoPhillips Placer #1 Nordic #3 Field: Sand: Job #: Exploration KUPARUK 200400086 Schlumberger List of Tables Table 1: Well and Sample. Identification. ............................................................................................. Table 2: Sampling.and.Traosfer.Summal:'{............................................................................................ Table 3: Reservoir.Fluid Properties. . . .. . ..................... ........ . .................................................... ........... . Table 4: Stock-Tank Oil Proper.ties.................................................................................................... Table 5: C30+ Compositioo..GOR. ~APtb.y.Single.-Stage.Flasl1 {Sample.1.07.)............. ....................................... Table 6: Calculated fluid.P.roperties............................................................. ..................................... Table 7: C3O+ Compositioo..GOR. ~API.b.y.Single.-Stage.Flasl1 {Sample.t09)................ p.................................. Table 8: Calculated fluid.P.roperties............................................................. ..................................... Table 9: Summary.ofBesultsotSample.1.01...................................................... ................................... Table 10: Constant Composition Expaosionat.1S5°f.{Sample .1.01)...... ...... ............... ...... ........................................... Table 11: Differential Lib.erationTest.155~F .-.liquid. Properties. .{Sample.1.071........................................................... Table 12: Differential Lib.erationTest.155°F .-. Gas.P.roperties. .(Sample.1.O.1)............................................................... Table 13: Differential Lib.eration.155°F.~ Vapor.Composition.{mol%).{Sample .1.07)...................................................... Table 14: Differential Lib.erationTest.155~F .-. Vapor.&.SIO.Composition.(mol. %) .(Sample.1.O.1).................................... Table 15: Dead Oil Visc.osity 155°.F.{Sample.1.071........ ........... ..... ...... ..... ...... .......... ...... ......... ...... ...... ............... ....... Table 16: Multi~Stage.Separation.Test.vapor.& liquid. Properties. .{Sample.1.07)........................................................ Table 17: Multi~Stage.Separator. Jest Vapor .Composition .(mol.%). {Sample. un ....................................................... Table 18: Multi~Stage.Separator. Jest Residual.Liquid .Composition .(mol.%). {Sample. tOn ......................................... Table 19: Separation .Corrected.GOR.and.fVF..{Sample.1.07).................. ...... ... ...... ...... ........ .... ...... ...... ............... ....... Table 20: Comparison. Data. (Sample. 1.01) .... ...... ............... .................. ...... ... ...... ...... ............. ..... ............ ................ Table 21: Summary.of.Results ofSample.1.09...... ............... ............ ...... ......... ...... ...... ............ ........ .......................... Table 22: Reservoir .Fluid .Viscosity.155°F (Sample. 1.09) ........................................................................................... Table 23: Stock.Iaok.Oil.Viscosity.vs..Iemperature. (Sample.1..09).. ............ ...... ......... ...... ......... ...... ..................... .... Table 24: HTGC. .(Sample .1.09)......................................................................................................................... ...... Table 25: SARA. and. WAT Analysis. (Samp.le. 1.09). . ...... ......... ... ...... ............ ...... ...... ......... ......... ...... ...... ...... ... .......... I I I I I 'I I I I I I I I I I I WCP Oilphase-DBR 3 7 7 8 8 9 10 12 13 15 16 19 21 23 24 25 27 28 29 30 32 33 34 36 39 41 Job #: 200400086 I I I I I I I I I I I I I I I I I I I Client: Well: Installation: ConocoPhillips Placer #1 Nordic #3 Field: Sand: Job #: Exploration KUPARUK 200400086 Schlumberger EXECUTIVE SUMMARY Objective To evaluate the composition and phase behavior of the bottomhole fluid samples collected during the modular formation dynamics testing (MDT). Introduction At the request of ConocoPhillips, Oilphase has conducted a fluid analysis study on bottomhole fluid samples collected during the modular formation dynamics testing (MDT) of Well Placer #1 drilled during Exploration. Scope of Work . Homogenize bottomhole hydrocarbon fluid samples at the reservoir conditions with rocking for five days. · Conduct preliminary evaluation on bottomhole hydrocarbon samples that include single-stage flash Gas- Oil Ratio IGOR). reservoir fluid composition, stock-tank oiIISTO) and monophasic fluid properties. · Select representative samples for the PVT study. · Conduct a Constant Composition Expansion (CCE) test at the reservoir temperature. · Conduct differential vaporization at the reservoir temperature. · Conduct a multi-stage separation test at the specified conditions. · Conduct viscosity measurements of the oil at the reservoir temperature. · Also conduct the various measurements on the STO of sample 1.09. Results The following bullets summarize the PVT analysis conducted on the bottomhole hydrocarbon samples: · Three bottom hole samples were used for validation purposes. They were homogenized at the reservoir conditions for five days. · The bottomhole samples were validated, by measuring their bubblepoint pressure at the reservoir temperature. The bubblepoint pressure varied from 2.790 - 2,914 psia whereas the reservoir pressure was 3,152 psia.Thus all samples were considered valid for further analyses. · The zero flash GOR was determined to be from 514 - 533 SCF/STB, and the STO density to be from 0.894 - 0.894 glee. · Subsequently, sample 1.07 was selected for full PVT study. The bubble point pressure at reservoir temperature was determined to be 2,914 psia. · Sample 1.07 ran out of volume during the viscosity testing. Due to the similiarity between sample 1.07 and 1.09, client agreed to use sample 1.09 for the full range viscosity test. The reservoir fluid viscosity of sample 1.09 was measured to be 1.512 cP at bubblepoint pressure and 1.481 cP at the initial pressure. The stock tank oil viscosity at 155°F was measured as 5.881 cP. WCP Oilphase-DBR Job #: 200400086 4 I I I I I I I I I I I I I I I I I I I Client: Well: Installation: ConocoPhillips Placer #1 Nordic #3 Field: Sand: Job#: Exploration KUPARUK 200400086 Schlumberger Sequence of Events 3/29/2004 The sampls were received. 3/30/2004 The work scope of the prelim study was finalized. 4/5/2004 Confirmed de-emulsify 1.09, hold 1.08's testing and start 1.0Ts restoration. 4/16/2004 Prelim report (electronic copy) sent to client. 4/22/2004 Invoice for the prelim study sent. 8/16/2004 Sample 1.07 ran out of volume during the viscosity test. 8/20/2004 PVT results of sample 1.07 was sent via e-mail. 8/26/2004 Viscosity result of sample 1.09 was sent via e-mail. 9/14/2004 STO viscosity result of sample 1.09 was sent via e-mail. 9/27/2004 HTGC result of sample 1.09 was sent via e-mail. 10/26/2004 SARA result of sample 1.09 was sent via e-mail. Chain of Sample Custody The samples collected from the well of Placer#l in Alaska were sent to Oilphase-DBR in Houston, Texas. The samples were used to preliminary measurements and subsequent full PVT analysis. The measurement details are in the following text. Samples remaining after measurements are stored in Oilphase-DBR storage unless otherwise instructed. WCP Oilphase-DBR Job #: 200400086 5 I I I I I I I I I I I I I I I I I I I Client: Well: Installation: ConocoPhillips Placer #1 Nordic #3 Field: Sand: Job #: Exploration KUPARUK 200400086 Schlumberger RESUL 1S AND DISCUSSIONS Fluids Preparation and Analysis Three bottomhole samples collected during the MDT were transferred to Oilphase-DBR. The well and formation data with their respective reservoir conditions for the bottom hole samples are summarized in Table 1. The quality check for the bottomhole samples were conducted and the results are summarized in Table 2. After 5-days of homogenization, sample validation test was conducted to evaluate the validity of the samples, and sample 1.07 and 1.09 were good candidates for PVT analysis while sample 1.08 had high BS&W content. Based on the preliminary results, sample 1.07 and sample 1.09 were selected for PVT analysis. The reservoir fluid and stock-tank oil properties for all the samples are presented in Table 3 and Table 4. Reservoir Fluid Analysis The gas and liquid from zero flash were subjected to chromatography and their compositions were determined. These compositions were recombined mathematically according to single-stage flash Gas-Oil Ratio (GaR) to calculate the reservoir fluid composition. The reservoir fluid analysis is summarized in Table 5 and 7. The molecular weight of the stock-tank oil (STO) was measured. Other properties such as the plus fraction properties and heat content for the flash gas were calculated from the compositions and are listed in Table 6 and 8. WCP Oilphase-DBR Job #: 200400086 6 I I 'I I I I I I I I I I I I I I I I I Client: Well: Installation: ConocoPhillips Placer #1 Nordic #3 Field: Sand: Job#: Exploration KUPARUK 200400086 Schlumberger Table 1: Well and Sample Identification Client: ConocoPhillips Job# 200400086 Field: Exploration Well: Placer #1 Study Samples Sample 10 Reservoir Conditions Pressure Temperature (psia) (OF) Cylinder # Depth (ft) Sampling Date 1.07 1.08 1.09 SSB 12120-QA SSB 11809-QA SSB 12169-QA 155 155 155 7558 7,558 7558 3/13/2004 3/13/2004 3/13/2004 3,152 3,152 3,152 Table 2: Sampling and Transfer Summary Opening Transfer Opening Initial Sample 10 Chamber # conditions Cylinder conditions BS&W FS&W Sample in the field 10 in the Lab Volume (psia;oF) (psia;oF) (v/v %) (cc) (cc) 1.07 SPMC 041 6,500/82 SSB 12120-QA 5515/68 0.02 5 240 1.08** SPMC 229 7,000/80 SSB 11809-QA 6015/68 15 135 240 1.09 SPMC 126 7,000/80 SSB 12169-QA 5515/68 0.5* 8 240 * Sample 1.09 has 5% (v/v) BS&W before the deemulsification. ** Due to high FS&W and BS&W content. no further tests were done on sample 1.08. WCP Oilphase-DBR 7 Job #: 200400086 I I I I I I I I I I I I I I I I I I I Client: ConocoPhillips Field: Exploration Schlumberger Well: Placer #1 Sand: KUPARUK Installation: Nordic #3 Job': 200400086 Table 3: Reservoir fluid Properties Zero Flash Saturation Molar Mass of Sample 10 Cylinder' Depth GOR* Bo** Pressure monophasic at Tres fluid (ft) (set/bbl) (psia) 1.07 SSB 12120-QA 7,558 533 1.266 2914 134.2 1.09 SSB 12169-QA 7,558 514 NID 2790 138.2 * Flashed gas volume (set) per barrel of stock tank liquid @ 60°F ** Volume of live oil at it's bubble point pressure per flashed stock tank liquid volume @ 60°F Table 4: Stock-Tank Oil Properties STO Properties Sample 10 Cylinder' Depth Molar Mass Density API (ft) (glee) 1.07 SSB 12120-QA 7,558 271.5 0.894 26.8 1.09 SSB 12169-QA 7,558 278.8 0.894 26.8 WCP Oilphase-DBR Job .: 200400086 8 I Client: ConocoPhillips Field: Exploration Schlumberger I Well: Placer #1 Sand: KUPARUK Installation: Nordic #3 Job #: 200400086 I Table 5: C30+ Composition, GOR, °API, by Single-Stage Flash (Sample 1.07) Sample 1.07; Cylinder SSB 12120-QA; Depth 7558.1 ft. MD Component MW Flashed Gas Flashed Liquid Monophasic Fluid (g/mole) WT% MOLE % WT% MOLE % WT% MOLE % I Carbon Dioxide 44.01 0.49 0.24 0.00 0.00 0.04 0.13 Hydrogen SulfidE 34.08 0.00 0.00 0.00 0.00 0.00 0.00 Nitrogen 28.01 0.23 0.18 0.00 0.00 0.02 0.10 I Methane 16.04 58.97 78.57 0.00 0.00 5.16 43.14 Ethane 30.07 14.98 10.65 0.00 0.00 1.31 5.85 Propane 44.10 12.34 5.98 0.07 0.44 1.14 3.48 I I - Butane 58.12 2.81 1.03 0.04 0.20 0.29 0.66 N - Butane 58.12 5.42 1.99 0.14 0.64 0.60 1.39 I - Pentane 72.15 1.99 0.59 0.17 0.62 0.32 0.60 I N - Pentane 72.15 1.81 0.53 0.24 0.90 0.38 0.70 C6 84.00 0.39 0.10 0.65 2.09 0.62 0.99 M-C-Pentane 84.16 0.21 0.05 0.26 0.84 0.26 0.41 I Benzene 78.11 0.04 0.01 0.07 0.26 0.07 0.12 Cyclohexane 84.16 0.14 0.04 0.35 1.11 0.33 0.52 C7 96.00 0.05 0.01 0.98 2.77 0.90 1.26 I M-C-Hexane 98.19 0.08 0.02 0.80 2.22 0.74 1.01 Toluene 92.14 0.02 0.00 0.44 1.30 0.40 0.59 C8 107.00 0.03 0.01 1.54 3.91 1.41 1.77 E-Benzene 106.17 0.00 0.00 0.09 0.23 0.08 0.11 I M/P-Xylene 106.17 0.00 0.00 0.48 1.24 0.44 0.56 a-Xylene 106.17 0.00 0.00 0.16 0.40 0.14 0.18 C9 121.00 0.00 0.00 1.69 3.79 1.54 1.71 I pseudo Cl OH22 134.00 0.01 0.00 2.56 5.18 2.33 2.34 pseudo Cll H24 147.00 0.00 0.00 2.50 4.62 2.28 2.08 pseudo C12H26 161.00 0.00 0.00 2.75 4.64 2.51 2.09 I pseudo C13H28 175.00 0.00 0.00 3.25 5.05 2.97 2.28 pseudo C14H30 190.00 0.00 0.00 3.51 5.01 3.20 2.26 pseudo C15H32 206.00 0.00 0.00 3.63 4.79 3.32 2.16 I pseudo C16H34 222.00 3.54 4.33 3.23 1.95 pseudo C17H36 237.00 3.34 3.83 3.05 1.72 pseudo C18H38 251.00 3.49 3.77 3.18 1.70 I pseudo C19H40 263.00 3.25 3.36 2.97 1.51 pseudo C20H42 275.00 2.92 2.88 2.66 1.30 pseudo C21 H44 291.00 2.80 2.61 2.55 1.18 I pseudo C22H46 300.00 2.51 2.27 2.29 1.02 pseudo C23H48 312.00 2.37 2.07 2.17 0.93 pseudo C24H50 324.00 2.19 1.84 2.00 0.83 I pseudo C25H52 337.00 2.28 1.83 2.08 0.83 pseudo C26H54 349.00 1.72 1.34 1.57 0.60 pseudo C27H56 360.00 1.89 1.43 1.73 0.64 pseudo C28H58 372.00 1.74 1.27 1.59 0.57 I pseudo C29H60 382.00 1.74 1.23 1.58 0.56 C30+ 750.00 37.85 13.70 34.54 6.18 Total 100.00 100.00 100.00 100.00 100.00 100.00 I MW 21.37 271.47 134.15 MOLE RATIO 0.5491 0.4509 I WCP Oilphase-DBR 9 Job #: 200400086 I Client: ConocoPhillips Field: Exploration Schlumberger I Well: Placer #1 Sand: KUPARUK Installation: Nordic #3 Job#: 200400086 I Table 6: Calculated fluid Properties Sample 1.07; Cylinder SSB 12120-QA; Depth 7558.1 ft. MD Properties Flashed Gas Flashed Liquid Monophasic Fluid I Cn+ Composition Mass % Mole % Mass % Mole% Mass % Mole% C7+ 0.58 0.14 98.70 95.11 90.11 42.96 C12+ 0.00 0.00 86.77 67.24 79.18 30.32 I C20+ 60.01 32.47 54.76 14.64 C30+ 37.85 13.70 34.54 6.18 I Molar Mass C7+ 88.13 281.72 281.37 C12+ 350.36 350.36 I C20+ 501.79 501.79 C30+ 750.00 750.00 I Density C7+ 0.8989 C12+ 0.9189 0.9189 I C20+ 0.9608 0.9608 C30+ 1.0128 1.0128 Fluid at 60°F 0.8939 I Gas Gravity (Air = 1) 0.738 Dry Gross Heat Content (BTU/scf) I 1,289 I Wet Gross Heat Content (BTU/scf) 1,267 OBM Contamination level (wt%) ISTO Basis I Live Oil Basis Stock Tank Oil Properties at Standard Conditions: C30+ Properties I MW I 271.47 I I 750.00 I Density (g/cm3) 0.894 1.013 I Single Stage Flash Data Original STO De-Contaminated GOR (scf/stb) 533 I I STO Density (g/cm3) 0.8939 STO API Gravity 26.8 I OBM Density (g/cm3) @60°F I I I WCP Oilphase-DBR 10 Job #: 200400086 I I I I I I I I I I I I I I Client: Well: Installation: ConocoPhillips Placer #1 Nordic #3 pA . <I> '" " ^' " 500 - I 400- fJ:! 300 - ° '" 6 '" '" š8 ü '" >, ..&?ç;¡:; ~ ~ X 200 - 'fiŒ6 :;;: '" '"'-'" ~lll ~ co ~t' u c:- 100 - l~l 0 , 0 10 I I I I WC!' Oilphase-DBR Field: Sand: Job#: Exploration KUPARUK 200400086 Figure 1: Stock Tank Oil Chromatogram (Sample 1.1)1) Sample 1.07; Cylinder SSB 12120-QA; Depth 7558.1 ft. MD ... N ~ U ~ to ~üõu Ülo~~~BN"'01 . ü~fj~~LO" ÜÜ~N~ 00(..) , 20 , 30 11 , 50 min Job It: 200400086 I Client: ConocoPhillips Field: Exploration Schlumberger I Well: Placer #1 Sand: KUPARUK Installation: Nordic #3 Job #: 200400086 I Table 7: C30+ Composition, GOR, °API, by Single-Stage Flash (Sample 1.09) Sample 1.09; Cylinder SSB 12169-QA; Depth 7558.1 ft. MD Component MW Flashed Gas Flashed Liquid Monophasic Fluid I (g/mole) WT% MOLE % WT% MOLE % WT% MOLE % Carbon Dioxide 44.01 0.37 0.18 0.00 0.00 0.03 0.10 Hydrogen SulfidE 34.08 0.00 0.00 0.00 0.00 0.00 0.00 Nitrogen 28.01 0.40 0.31 0.00 0.00 0.03 0.17 I Methane 16.04 58.13 78.07 0.00 0.00 4.95 42.66 Ethane 30.07 14.96 10.72 0.00 0.00 1.27 5.86 Propane 44.10 12.46 6.09 0.04 0.25 1.10 3.44 I I - Butane 58.12 2.87 1.06 0.03 0.15 0.27 0.65 N - Butane 58.12 5.58 2.07 0.11 0.51 0.57 1.36 I - Pentane 72.15 2.10 0.63 0.14 0.55 0.31 0.59 I N - Pentane 72.15 1.99 0.59 0.21 0.80 0.36 0.69 C6 84.00 0.47 0.12 0.60 1.99 0.59 0.97 M-C-Pentane 84.16 0.24 0.06 0.25 0.82 0.25 0.41 I Benzene 78.11 0.04 0.01 0.07 0.25 0.07 0.12 Cyclohexane 84.16 0.17 0.04 0.33 1.10 0.32 0.52 C7 96.00 0.07 0.02 0.93 2.70 0.86 1.24 I M-C-Hexane 98.19 0.10 0.02 0.78 2.21 0.72 1.01 Toluene 92.14 0.02 0.00 0.42 1.28 0.39 0.58 C8 107.00 0.02 0.00 1.47 3.84 1.35 1.74 I E-Benzene 106.17 0.00 0.00 0.09 0.23 0.08 0.11 M/P-Xylene 106.17 0.00 0.00 0.47 1.23 0.43 0.56 O-Xylene 106.17 0.00 0.00 0.15 0.40 0.14 0.18 C9 121.00 0.00 0.00 1.62 3.73 1.48 1.69 I pseudo C1 OH22 134.00 0.00 0.00 2.51 5.22 2.30 2.37 pseudo C11 H24 147.00 0.00 0.00 2.50 4.74 2.29 2.15 pseudo C12H26 161.00 0.00 0.00 2.66 4.61 2.44 2.09 I pseudo C13H28 175.00 0.00 0.00 3.14 5.00 2.87 2.27 pseudo C14H30 190.00 0.00 0.00 3.38 4.96 3.09 2.25 pseudo C15H32 206.00 0.00 0.00 3.50 4.74 3.20 2.15 I pseudo C16H34 222.00 3.41 4.28 3.12 1.94 pseudo C17H36 237.00 3.22 3.78 2.94 1.72 pseudo C18H38 251.00 3.36 3.73 3.07 1.69 I pseudo C19H40 263.00 3.14 3.33 2.87 1.51 pseudo C20H42 275.00 2.83 2.87 2.59 1.30 pseudo C21 H44 291.00 2.70 2.59 2.47 1.17 I pseudo C22H46 300.00 2.44 2.26 2.23 1.03 pseudo C23H48 312.00 2.31 2.07 2.11 0.94 pseudo C24H50 324.00 2.12 1.83 1.94 0.83 I pseudo C25H52 337.00 2.20 1.82 2.02 0.83 pseudo C26H54 349.00 1.68 1.34 1.54 0.61 pseudo C27H56 360.00 1.85 1.43 1.69 0.65 pseudo C28H58 372.00 1.69 1.27 1.54 0.57 I pseudo C29H60 382.00 1.69 1.23 1.54 0.56 C30+ 750.00 39.97 14.86 36.56 6.74 Total 100.00 100.00 100.00 100.00 100.00 100.00 I MW 21.54 278.77 138.22 MOLE RATIO 0.5464 0.4536 I WCP Oilphase-DBR 12 Job #: 200400086 I Client: ConocoPhillips Field: Exploration Schlumberger I Well: Placer #1 Sand: KUPARUK Installation: Nordic #3 Job#: 200400086 I Table 8: Calculated fluid Properties Sample 1.09; Cylinder SSB 12169-QA; Depth 7558.1 ft. MD Properties Flashed Gas Flashed liquid Monophasic Fluid I Cn+ Composition Mass % Mole % Mass % Mole % Mass % Mole % C7+ 0.67 0.16 98.87 95.75 90.51 43.52 C12+ 0.00 0.00 87.27 67.98 79.84 30.83 I C20+ 61.47 33.56 56.24 15.22 C30+ 39.97 14.86 36.56 6.74 I Molar Mass C7+ 87.64 287.87 287.46 C12+ 357.89 357.89 I C20+ 510.68 510.68 C30+ 750.00 750.00 I Density C7+ 0.8979 C12+ 0.9170 0.9170 I C20+ 0.9554 0.9554 C30+ 0.9993 0.9993 Fluid at 60°F 0.8937 I Gas Gravity (Air = 1) 0.744 Dry Gross Heat Content (BTUlscf) I 1.298 I Wet Gross Heat Content (BTU/scf) 1,275 OBM Contamination level (wtOfo) STO Basis I Live Oil Basis Stock Tank Oil Properties at Standard Conditions: C30+ Properties I MW I 278.77 I I 750.00 I Density (g/cm3) 0.894 0.999 I Single Stage Flash Data Original STO De-Contaminated GOR (scf/stb) 514 I I STO Density (g/cm3) 0.8937 STO API Gravity 26.8 I OBM Density (g/cm3) @60°F I I I WCP Oilphase-DBR 13 Job #: 200400086 I I I I I I I I I I I I I I I I I I I Client: Well: Installation: ConocoPhil1 ips Placer #1 Nordic #3 field: Exploration Sand: KUPARUK Job #: 200400086 figure 2: Stock Tank Oil Chromatogram (Sample U)9) Sample 1.09; Cylinder SSB 12169-QA; Depth 7558.1 ft. MD pA : 900 c 800 ~ 700 ~ 500 ~ 500 ~ 4ûO~ 300 ~ 200 ~ 100 ~ o o WCP Oilphase-DBR N ~ ~ ~ to t--.. [) U Uu"-COm uo..-a..-("\ I u [j [j ?J ~ ~þQw¡--...co ÜUü~¿j[jÔ 14 , 50 Job #: 200400086 I I I I I I I I I I I I I I I I I I I Client: Well: ConocoPhillips Placer #1 Field: Sand: Exploration KUPARUK Schlumberger Table 9: Summary of Results of Sample 1.01 Sample 1.07; Cylinder SSB 12120-QA; Depth 7558.1 ft. MD Reservoir Conditions: Temperature: Summary of Fluid Properties: OBM Contamination: OBM Contamination: Bubble Point Pressure At Tres Gas-Oil Ratio Single-stage Flash: Total Differential Liberation: Total Separator Flash: Properties at 60°F Single-stage STO: Differential Liberation STO: Separator STO: Properties at Reservoir Conditions Viscosity: Compressibillity (Co): Density: Properties at Saturation Conditions Viscosity: Compressibillity (Co): 9.2 Density: 0.772 Formation Volume Factor @Pres & Tres Single-stage Flash: 1.266 Total Differential Liberation: 1.257 Total Separator Flash: 1.238 Note: Standard conditions are 14.696 psia and 60°F Pressure: WCP Oilphase-DBR 3152 155 2,914 533 524 500 STO °API 26.8 27.2 28.9 9.1 0.774 15 psia of Wt% STO Basis Wt% RF Basis pSla scf I stb scf/stb scf I stb Gas Gravity (Average) 0.738 0.706 0.699 cP 10.£ Ipsi glee cP 10.£ Ipsi glee @Psat & Tres 1.269 1.260 1.241 Job #: 200400086 I I I I I I I I I I I I I I I I I I I Client: Well: ConocoPhillips Placer #1 Field: Sand: Exploration KUPARUK Schlumberger PVT Analysis on Sample 1.07; Cylinder SSB 12120-QA; Depth 7558.1 ft. MD Constant Composition Expansion at Tres The CCE study was initiated by charging a sub-sample of live reservoir fluid into the PVT cell at a reservoir temperature of 155.0°F and at a pressure of 8,015 psia. Sequential pressure decrease in steps and the corresponding volume changes are presented in Table 10. The pressure-volume P-V¡ plots of the CCE data are presented in Figure 3. The intersection of the single-phase and two-phase lines in the P-V plot and the visual observation was used to define the bubblepoin1. For the subject fluid, the bubblepoint was determined to be 2,914 psia at the reservoir temperature of 155.0 oF. Also, calculated relative volume and oil compressibility is presented in Table 10. As seen in the table, the compressibility of this oil is 9.2 x 10e-6 l/psia at the saturation pressure. Table 10: Constant Composition Expansion at 155°F (Sample 1.07) Sample 1.07; Cylinder SSB 12120-QA; Depth 7558.1 f1. MD Pressure Relative Vol % Liquid % Liquid Liquid Density Y Function Compressibilty (psia) (Vr=VNsat) (VlNsat) (VINtotal) (g/cm3) (10-6/psia) 1 8015 0.9600 0.8044 6.9 2 7015 0.9668 0.7987 7.3 3 6015 0.9741 0.7927 7.8 4 5015 0.9819 0.7864 8.2 5 4015 0.9902 0.7798 8.6 6 3515 0.9946 0.7764 8.9 7 3315 0.9964 0.7750 9.0 Pi 3152 0.9978 0.7739 9.1 Pb 2914 1.??oo 100.0 100.0 0.1722 9.2 10 2880 1.0020 100.0 99.8 5.9 11 2780 1.0084 99.5 98.7 5.7 12 2689 1.0149 99.3 97.8 5.6 13 2526 1.0284 98.7 96.0 5.4 14 2196 1.0663 97.6 91.5 4.9 15 1733 1.1623 95.8 82.4 4.2 16 1289 1.3454 94.5 70.2 3.7 17 1058 1.5353 93.5 60.9 3.3 18 826 1.8438 92.7 50.3 3.0 19 644 2.2958 92.1 40.1 2.7 WCP Oilphase-DBR Job #: 200400086 16 I I I I I I I I I I I I I I I I I I I Client: Well: ConocoPhillips Placer #1 Field: Sand: Exploration KUPARUK Schlumberger Figure 3: Constant Composition Expansion at 155°F - Relative Volume (Sample 1.07) Sample 1.07; Cylinder SSB 12120-QA; Depth 7558.1 f1. MD 2.4 2.2 2.0 := 1.8 A. @) ~ ~ ~ 1.6 = ;: 0 I) > ''¡:: IV ¡; II: 1.4 1.2 1.0 0.8 o WCP Oilphase-DBR o o 2000 8000 10000 4000 6000 Pressure (psial 17 Job #: 200400086 I I I I I I I I I I I I I I I I I I I Client: Well: ConocoPhillips Placer #1 Field: Sand: Exploration KUPARUK Schlumberger Oifferential Vaporization Results of the differential vaporization test are presented in Tables 11 through 14 and graphically presented in Figures 4 through 5. Oil Phase Properties The oil properties such as oil formation volume factor, oil density and solution Gas-ail-ratios are summarized in Table 11. The oil formation volume factor is presented as afunction of differential pressures in Figure 4. As expected, the oil formation volume factor increases with decreasing pressure until the bubblepoint. and subsequently, decreases with decreasing pressure. Solution GaR shows a decreasing trend with decreasing pressures Figure 4). Oil densities were measured at the initial and the saturation pressure conditions and the intermediate values are calculated based on known mass and measured volume. The liquid density is measured to be 0.772 g/cc at the bubblepoint pressure (Table 11). The liquid density decreases with decreasing pressure until the bubblepoint. and increases with further decrease in pressure (Figure 4). Gas Phase Properties The calculated differentially vaporized gas properties are summarized in Table 12 and graphically presented in Figures 5. As seen in the table and figures, gas volume factor shows an increasing trend with a decrease in pressure. The Gas deviation factor and gas relative density values of the liberated gas tend to decrease slightly and then increase with a decreasing function of pressure. However, the gas viscosity that is calculated at the differential pressure steps from gas composition decrease with decrease in pressure as seen in Figure 5. Compositions Compositions of the differentially liberated gas at each differential pressure step are presented in Table 13 along with calculated molecular weights. As seen in the table, and as expected, the concentrations of the heavier components in the liberated gas decreases with a decrease in pressure due to the inability of the gas to supercritically extract heavy ends at lower pressures. However, below 2329.696 psia, the concentration of intermediate/heavy components (>C3) of the liberated gas increases as their partial pressures become significant. Composition of the residual oil obtained from the differential vaporization is presented in Table 14. The API Gravity of the residual oil is measured to be 27.2. WCP Oilphase-DBR Job #: 200400086 18 I I I I I I I I I I I I I I I I I I I Client: Well: ConoeoPhillips Placer #1 Field: Sand: Exploration KUPARUK Schlumberger Table 11: Differential Liberation Test 155°F - Liquid Properties (Sample 1.07) Sample 1.07; Cylinder SSB 12120-QA; Depth 7558.1 ft. MD Pressure (psia) 1 8015 2 7015 3 6015 4 5015 5 4015 6 3515 7 3315 Pi 3152 Pb 2914 10 2330 11 1890 12 1515 13 1165 14 815 15 415 STO 15 Residual oil density at 60 of (glee) API Gravity WCP Oilphase-DBR Oil Volume Factor Bo (bbl/stb) 1.209 1.218 1.227 1.237 1.247 1.253 1.255 1.257 1.260 1.220 1.193 1.169 1.148 1.125 1.095 1.040 0.892 27.2 Solution Gas GOR Rs (scf/bbl) 524 524 524 524 524 524 524 524 524 429 352 289 229 171 101 o 19 Calculated Liquid Density (g/cm3) 0.804 0.798 0.792 0.786 0.779 0.776 0.775 0.773 0.772 0.786 0.795 0.804 0.812 0.821 0.834 0.857 Job #: 200400086 I I I I I I I I I I I I I I I I I I I Client: Well: ~ 1.25 - ..!!!. ::æ¡ :!! 1.20 CI ca ::; 1.15 Ü III 1.1. CD E 1.10 :::I Õ > i:5 1.05 ¡- 500.0 ~ U III :2 400.0 1ií a:: is 300.0 III III ~ 200.0 .! :::I ~ 100.0- ¡;;- ~ 0.83 .... ~ ~ .~ 0.81 CD Q ~ 'g. 0.79 ::¡ ConocoPhillips Placer #1 Field: Sand: Exploration KUPARUK Schlumberger Figure 4: Differential Liberation 155°F - Liquid Properties (Sample 1.07) Sample 1.07; Cylinder SSB 12120-QA; Depth 7558.1 ft. MD 1.30 1.00 o 2000 4000 600.0 0.0 o 2000 4000 0.87 0.85 0.77 0.75 o 2000 4000 Pressure (psia) WCP Oilphase-DBR 20 6000 8000 10000 6000 10000 8000 ~ 6000 10000 8000 Job #: 200400086 I I I I I I I I I I I I I I I I I I I Client Well: Pb 1 2 3 4 5 6 STO Table 12: Differential Liberation Test 155°F - Gas Properties (Sample 1.07) Sample 1.07; Cylinder SSB 12120-QA; Depth 7558.1 ft. MD (1)Gas FVF Z (2lpredicted Vapor Bg Factor Gas Gravity (bbl/mm ft3) Viscosity (cP) (air=1) ConocoPhillips Placer #1 Pressure (psia) 2914 2330 1890 1515 1165 815 415 14.696 Field: Sand: Exploration KUPARUK 6573 8167 10292 13587 19858 40227 1182422 0.881 0.888 0.897 0.911 0.931 0.960 1.000 0.622 0.622 0.626 0.630 0.646 0.686 0.993 0.02 0.02 0.01 0.01 0.01 0.01 0.01 1. Bg = Reservoir gas at P & T per 1 million equivalent ft 3 gas at 15.025 psi a & 60°F 2. Lee & Gonzalez Correlation 3. Bt = Oil FVF + [(T otalliberated gas)*Gas FVF]*1 0-6 WCP Oilphase-DBR 21 Schlumberger (31y ota I FVF Bt (bbl/stb) 1.260 1.847 2.600 3.589 5.156 8.144 18.131 620.691 Job #: 200400086 I Client: ConocoPhillips Field: Exploration Schlumberger I Well: Placer #1 Sand: KUPARUK I Figure 5: Differential Liberation 155°F - Gas Properties (Sample 1.07) Sample 1.07; Cylinder SSB 12120-QA; Depth 7558.1 f1. MD 1.1 I 8 ... 1.0 I CI Q ca 1.1. = .S! ãi I 1. eD -0...-...- c; 0.9 a. a ca 0 c.:I I 0.8 0 500 1000 1500 2000 2500 I 1.00 I 0.90 I ... !! ~ ~ -¡;;: 0.80 I ca ð III ca c.:I 0.70 I 0- a p 0 0 0.60 I 0 500 1000 1500 2000 2500 0.020 I 0.018 I ~ 0.016 ~ ~ .(j ~ ~ '¡¡¡ 8 0.014 ~ I III :;: III ~ 0.012 I 0.010 I 0.008 0 500 1000 1500 2000 2500 Pressure (psial I WCP Oilphase-DBR 22 Job #: 200400086 I Client ConocoPhillips Field: Exploration Schlumberger I Well: Placer #1 Sand: KUPARUK I Table 13: Differential Liberation 155°F - Vapor Composition (mol%) (Sample 1.07) Sample 1.07; Cylinder SSB 12120-QA; Depth 7558.1 f1. MD Component MW Mol % at Specified Pressure (psial I (g/mol) 2330 1890 Carbon Dioxide 44.01 0.26 0.26 Hydrogen Sulfide 34.08 0.00 0.00 Nitrogen 28.01 0.38 0.34 I Methane 16.04 90.75 90.66 Ethane 30.07 5.58 5.80 Propane 44.10 1.89 1.88 I I - Butane 58.12 0.28 0.25 N - Butane 58.12 0.47 0.41 I - Pentane 72.15 0.13 0.11 I N - Pentane 72.15 0.17 0.17 C6 84.00 0.03 0.03 M-C-Pentane 84.16 0.01 0.02 I Benzene 78.11 0.01 0.01 Cyclohexane 84.16 0.01 0.01 C7 96.00 0.01 0.01 I M-C-Hexane 98.19 0.01 0.01 Toluene 92.14 0.02 0.02 C8 107.00 0.00 0.00 I E-Benzene 106.17 0.00 0.00 M/P-Xylene 106.17 0.00 0.00 O-Xylene 106.17 0.00 0.00 C9 121.00 0.00 0.00 I C10 134.00 0.00 0.00 C11 147.00 0.00 0.00 C12 161.00 0.00 0.00 I C13 175.00 0.00 0.00 C14 190.00 0.00 0.00 C15 206.00 0.00 0.00 I C16 222.00 0.00 0.00 C17 237.00 0.00 0.00 C18 251.00 0.00 0.00 I C19 263.00 0.00 0.00 C20 275.00 0.00 0.00 C21 291.00 0.00 0.00 I C22 300.00 0.00 0.00 C23 312.00 0.00 0.00 C24 324.00 0.00 0.00 I C25 337.00 0.00 0.00 C26 349.00 0.00 0.00 C27 360.00 0.00 0.00 C28 372.00 0.00 0.00 I C29 382.00 0.00 0.00 C30+ 750.00 0.00 0.00 Total 100.00 100.00 I Calculated MW 18.03 18.01 Relative Density (air= 1) 0.622 0.622 Dry Gross Heat Content (BTU/scf) 1106 1106 I WCP Oilphase-DBR 23 Job #: 200400086 I Client: ConocoPhillips Field: Exploration Schlumberger I Well: Placer #1 Sand: KUPARUK I Table 14: Differential Liberation Test 155°F - Vapor & STO Composition (mol %) (Sample 1.07) Sample 1.07; Cylinder SSB 12120-0A; Depth 7558.1 ft. MD Component MW Mol % at Specified Pressure (psia) Mol % at Pressure = 15 psia I I (glmo) 1515 1165 815 415 Vapor Residual Liquid Carbon Dioxide 44.01 0.28 0.30 0.35 0.41 0.35 0.00 Hydrogen Sulfide 34.08 0.00 0.00 0.00 0.00 0.00 0.00 Nitrogen 28.01 0.29 0.24 0.17 0.10 0.02 0.00 I Methane 16.04 90.13 89.39 87.34 81.88 49.41 0.00 Ethane 30.07 6.20 6.84 8.11 11.65 23.99 0.00 Propane 44.10 1.99 2.13 2.71 4.06 16.27 0.70 I I - Butane 58.12 0.27 0.27 0.35 0.49 2.56 0.39 N - Butane 58.12 0.42 0.43 0.50 0.79 4.61 1.17 I - Pentane 72.15 0.12 0.11 0.15 0.19 1.22 0.91 I N - Pentane 72.15 0.19 0.18 0.19 0.25 0.96 1.17 C6 84.00 0.03 0.03 0.04 0.05 0.17 2.38 M-C-Pentane 84.16 0.01 0.02 0.02 0.03 0.13 0.89 I Benzene 78.11 0.01 0.01 0.01 0.01 0.03 0.23 Cyclohexane 84.16 0.01 0.01 0.02 0.02 0.10 1.20 C7 96.00 0.01 0.01 0.01 0.01 0.05 2.91 I M-C-Hexane 98.19 0.02 0.02 0.02 0.02 0.07 2.25 Toluene 92.14 0.02 0.02 0.02 0.02 0.03 1.13 C8 107.00 0.00 0.00 0.00 0.00 0.02 4.09 I E-Benzene 106.17 0.00 0.00 0.00 0.00 0.00 0.34 M/P-Xylene 106.17 0.00 0.00 0.00 0.00 0.00 0.87 O-Xylene 106.17 0.00 0.00 0.00 0.00 0.00 0.34 I C9 121.00 0.00 0.00 0.00 0.00 0.00 4.03 C10 134.00 0.00 0.00 0.00 0.00 0.00 4.91 C11 147.00 0.00 0.00 0.00 0.00 0.00 4.30 C12 161.00 0.00 0.00 0.00 0.00 0.00 4.64 I C13 175.00 0.00 0.00 0.00 0.00 0.00 4.70 C14 190.00 0.00 0.00 0.00 0.00 0.00 4.70 C15 206.00 0.00 0.00 0.00 0.00 0.00 4.71 I C16 222.00 0.00 0.00 0.00 0.00 0.00 4.24 C17 237.00 0.00 0.00 0.00 0.00 0.00 3.73 C18 251.00 0.00 0.00 0.00 0.00 0.00 3.55 I C19 263.00 0.00 0.00 0.00 0.00 0.00 3.33 C20 275.00 0.00 0.00 0.00 0.00 0.00 2.71 C21 291.00 0.00 0.00 0.00 0.00 0.00 2.51 I C22 300.00 0.00 0.00 0.00 0.00 0.00 2.33 C23 312.00 0.00 0.00 0.00 0.00 0.00 2.03 C24 324.00 0.00 0.00 0.00 0.00 0.00 1.82 I C25 337.00 0.00 0.00 0.00 0.00 0.00 1.65 C26 349.00 0.00 0.00 0.00 0.00 0.00 1.48 C27 360.00 0.00 0.00 0.00 0.00 0.00 1.43 I C28 372.00 0.00 0.00 0.00 0.00 0.00 1.31 C29 382.00 0.00 0.00 0.00 0.00 0.00 1.26 C30+ 750.00 0.00 0.00 0.00 0.00 0.00 13.68 Total 100.00 100.00 100.00 100.00 100.00 100.00 I Calculated MW 18.13 18.25 18.71 19.86 28.75 268.83 Relative Density (air= 1) 0.626 0.630 0.646 0.686 0.993 Dry Gross Heat Content (BTU/scf) 1112 1119 1144 1205 1684 I WCP Oilphase-DBR 24 Job #: 200400086 I I I I I I I I I I I I I I I I I I I Client: Well: ConocoPhillips Placer #1 Field: Sand: Exploration KUPARUK Schlumberger Dead Oil Viscosity at Tres The dead oil viscosity was measured at the reservoir temperature of 155°F. It is 7.39 cPo Sample ran out of the volume during the live oil analysis. Hence, no data is available for the live oil viscosity. Table 15: Dead Oil Viscosity 155°F (Sample 1.07) Sample 1.07; Cylinder SSB 12120-QA; Depth 7558.1 ft. MD Pressure Viscosity @ Tres (psia) (cP) STO 14.696 7.39 WCP Oilphase-DBR Job #: 200400086 25 I I I I I I I I I I I I I I I I I I I Client: Well: Exploration KUPARUK Schlumberger ConocoPhillips Placer #1 Field: Sand: Multi-Stage Separation Test Multi-stage separation test results are presented in Tables 16 - 18. The fluid properties (i.e., GaR. density and oil formation volume factor) are presented in Table 16. Multi-stage separation test conditions are: STAGE Pb 2914 psia 155 of STAGE 1 80 psia 130 of STAGE STO 15 psia 60 of As seen in Table 16, the GaR value obtained from the multi-stage separation test is 500 SCF/STB and the formation volume factor is 1.241. The compositional analyses of separator gas and tank gas are summarized in Table 17 and the composition of tank liquid is tabulated in Table 18. The total dry gross heat content of the separation gases is calculated to be 1,228 BTU/scf whereas the total wet gross heat content is calculated to be 1,206 BTU/scf. With reference to the assumption made in "The Properties of Petroleum Fluids" (McCain, 1990). the assumption made in generating reservoir fluid properties from a PVT study is that at pressures below the bubblepoint, the process in the reservoir can be mimicked by differential vaporization, while the process in the well bore is simulated by the separator test. Hence, fluid properties at pressures below saturation pressure can be calculated by combining the data from the differential vaporization and a separator test. The differential vaporization flashes that occur in the reservoir at the reservoir temperature (155.0°F) would liberate more gas than flashes that occur during multi-stage separation test conducted at variable temperatures lower than the reservoir temperature. This expectation held true in this study and the overall solution GaR and Bo did see a significant decrease when the liberated data were combined with results of the separation test. Results are summarized in Table 19 and graphically presented in Figures 6 and 7. As seen in these figures, GaR and Bo values are decreased as the liberated reservoir oil is produced at the surface. WCP Oilphase-DBR Job #: 200400086 26 I I I I I I I I I I I I I I I I I I I Client Well: Exploration KUPARUK Schlumberger ConocoPhillips Placer #1 Field: Sand: Table 16: Multi-Stage Separation Test Vapor & Liquid Properties (Sample 1.07) Sample 1.07; Cylinder SSB 12120-QA; Depth 7558.1 ft. MD PROPERTY STAGE Pb STAGE 1 STAGE STO Pressure (psia) 2914 80 15 Temperature (OF) 155 130 60 Liq. Den (g/cm3) 0.772 0.858 0.882 Vap. Gravity8 0.689 1.043 Vap. Mwt 19.94 30.21 Vap HeatVal.b 1211 1761 GORc 485 15 GORd 470 15 Sep. FVF' 1.032 1.000 a) Calculated, at 60°F (air= 1) b) Calculated, Dry basis BTU/scf c) scf gas/bbl of oil at STD conditions d) scf gas/bbl of oil at separator conditions e) fluid volume at sep conditions/fluid volume at STD conditions Residual oil density at standard conditions 0.882 g/cc Sep gas gravity (average) Sg = ~RjSg¡œRj 0.699 Where: R: GOR (scf gas/bbl of oil at STD conditions). j: separator stages Sep gas gross heating value (a' Lc =~R¡*Lc¡ltRi 1228 BTU/scf (dry basis) Where: R: GOR (scf gas/bbl of oil at STD conditions), j: separator stages SEPARATION TEST SUMMARY BTotal Separation Test GOR 500 Separation Test STO Gravity 28.9 bSeparation Test FVF 1.241 a) scf gas/bbl of condensate at STD conditions b) Fluid volume at Psat & Tres/Fluid volume at STD WCP Oilphase-DBR Job #: 200400086 27 I Client: ConocoPhillips Field: Exploration Schlumberger I Well: Placer #1 Sand: KUPARUK I Table 11: Multi-Stage Separator Test Vapor Composition (mol %) (Sample 1.07) Sample 1.07; Cylinder SSB 12120-QA; Depth 7558.1 ft. MD Component MW Mole % I (g/mol) STAGE Pb STAGE 1 STAGE STO Carbon Dioxide 44.01 0.27 0.35 Hydrogen Sulfide 34.08 0.00 0.00 Nitrogen 28.01 0.22 0.09 I Methane 16.04 82.65 46.25 Ethane 30.07 9.95 22.90 Propane 44.10 4.64 18.58 I I - Butane 58.12 0.60 2.94 N - Butane 58.12 0.94 5.36 I - Pentane 72.15 0.24 1.29 I N - Pentane 72.15 0.26 1.26 C6 84.00 0.08 0.32 M-C-Pentane 84.16 0.03 0.16 I Benzene 78.11 0.01 0.04 Cyclohexane 84.16 0.03 0.15 C7 96.00 0.02 0.09 I M-C-Hexane 98.19 0.03 0.14 Toluene 92.14 0.01 0.04 C8 107.00 0.03 0.03 I E-Benzene 106.17 0.00 0.00 M/P-Xylene 106.17 0.00 0.00 O-Xylene 106.17 0.00 0.00 C9 121.00 0.00 0.00 I ClO 134.00 0.00 0.00 Cll 147.00 0.00 0.00 C12 161.00 0.00 0.00 I C13 175.00 0.00 0.00 C14 190.00 0.00 0.00 C15 206.00 0.00 0.00 I C16 222.00 0.00 0.00 C17 237.00 0.00 0.00 C18 251.00 0.00 0.00 I C19 263.00 0.00 0.00 C20 275.00 0.00 0.00 C21 291.00 0.00 0.00 I C22 300.00 0.00 0.00 C23 312.00 0.00 0.00 C24 324.00 0.00 0.00 I C25 337.00 0.00 0.00 C26 349.00 0.00 0.00 C27 360.00 0.00 0.00 I C28 372.00 0.00 0.00 C29 382.00 0.00 0.00 C30+ 750.00 0.00 0.00 Total 100.00 100.00 I MW 19.94 30.21 Relative Density (air= 1) 0.69 1.04 Dry Gross Heat Content (BTU/scf) 1211 1761 I WCP Oilphase-DBR 28 Job #: 200400086 I I I I I I I I I I I I I I I I I I I Client: Well: ConocoPhillips Placer #1 Field: Sand: Exploration KUPARUK Schlumberger Table 18: Multi-Stage Separator Test Residual Liquid Composition (mol %) (Sample 1.07) Sample 1.07; Cylinder SSB 12120-QA; Depth 7558.1 ft. MD WCP Oilphase-DBR COMPONENT Carbon Dioxide Hydrogen Sulfide Nitrogen Methane Ethane Propane I - Butane N - Butane I - Pentane N - Pentane C6 M-C-Pentane Benzene Cyclohexane C7 M-C-Hexane Toluene C8 E-Benzene M/P-Xylene O-Xylene C9 C10 C11 C12 C13 C14 C15 C16 C17 C18 C19 C20 C21 C22 C23 C24 C25 C26 C27 C28 C29 C30+ Total MW MW (g/mol) 44.01 34.08 28.01 16.04 30.07 44.10 58.12 58.12 72.15 72.15 84.00 84.16 78.11 84.16 96.00 98.19 92.14 107.00 106.17 106.17 106.17 121.00 134.00 147.00 161.00 175.00 190.00 206.00 222.00 237.00 251.00 263.00 275.00 291.00 300.00 312.00 324.00 337.00 349.00 360.00 372.00 382.00 750.00 Residual Liquid (mol%) 0.00 0.00 0.00 0.00 0.00 1.09 0.53 1.51 1.05 1.35 2.57 0.93 0.24 1.24 3.00 2.29 1.22 4.11 0.35 0.94 0.33 3.92 4.87 4.25 4.55 4.63 4.59 4.69 4.15 3.67 3.51 3.29 2.67 2.46 2.28 1.99 1.79 1.63 1.46 1.43 1.32 1.21 12.92 100.00 262.07 29 Job #: 200400086 I I I I I I I I I I I I I I I I I I I Client: ConocoPhillips Field: Exploration Schlumberger Well: Placer #1 Sand: KUPARUK Table 19: Separation Corrected GOR and FVF (Sample 1.07) Sample 1.07; Cylinder SSB 12120-QA; Depth 7558.1 ft. MD Pressure Measured GOR Corrected GOR Measured FVF Corrected FVF (psia) (scf/bbl) (scf/bbl) Single Phase Data 1 8015 524 500 1.209 1.191 2 7015 524 500 1.218 1.200 3 6015 524 500 1.227 1.209 4 5015 524 500 1.237 1.219 5 4015 524 500 1.247 1.229 6 3515 524 500 1.253 1.234 7 3315 524 500 1.255 1.237 Pi 3152 524 500 1.257 1.238 Pb 2914 524 500 1.260 1.241 1 2330 429 406 1.220 1.202 2 1890 352 331 1.193 1.176 3 1515 289 269 1.169 1.152 4 1165 229 210 1.148 1.131 5 815 171 152 1.125 1.108 6 415 101 83 1.095 1.079 STO 15 0 1.040 1.025 WCP Oilphase-DBR Job #: 200400086 30 I I I I I I I I I I I I I I I I I I I Client: Well: ConocoPhillips Placer #1 Field: Sand: Exploration KUPARUK Figure 6: Separation Corrected Oil volume Factor (Bo) (Sample U»1) Sample 1.07; Cylinder SSB 12120-QA; Depth 7558.1 ft MD -0- Measured FVF Corrected FVF 1.3 1.3 1.2 ..... 1.2 ?l: 1.1 1.1 1.0 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 Pressure (psial figure 7: Separation Corrected Solution GOR (Rs) (Sample 1.(7) Sample 1.07; Cylinder SSB 12120-QA; Depth 7558.1 ft MD -e- Measured GOR Corrected GOR 600.0 0 0 0 0 0 500,0 ::¡; 400.0 ~ (,, ~ ex:: 300.0 Q 1'.!7 ::: .2 ií ëi 200.0 en 100.0 0,0 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 Pressure (psisl WC!' Oilphase-DBR 31 Job #: 200400086 I I I I I I I I I I I I I I I I I I I Client: Well: WCP Oilphase-DBR ConocoPhillips Placer #1 FLASHING OPERATION Field: Sand: Exploration KUPARUK Table 20: Comparison Data (Sample 1.07) CUMULATIVE API Gas Relative **FVF *GOR GRAVITY Density (air=1) Single-stage Flas 533 26.8 0.738 1.266 DL Flash @Tres 524 27.2 0.706 1.257 Separator Test 500 28.9 0.699 1.238 *scf gas/bbl of oil at STD conditions **Fluid volume at Pres & Tres/fluid volume at STD conditions ***Fluid volume at Psat & Tres/Fluid volume at STD conditions 32 Schlumberger ***FVF 1.269 1.260 1.241 Job #: 200400086 I I I I I I I I I I I I I I I I I I I Client: Well: ConocoPhillips Placer #1 Field: Sand: Exploration KUPARUK Schlumberger Table 21: Summary of Results of Sample 1.09 Sample 1.09; Cylinder SSB 12169-QA; Depth 7558.1 ft. MD Reservoir Conditions: Pressure: Temperature: Summary of Fluid Properties: OBM Contamination: OBM Contamination: Bubble Point Pressure At T res Gas-Oil Ratio Single-stage Flash: Total Differential Liberation: Total Separator Flash: Properties at 60°F Single-stage STO: Differential Liberation STO: Separator STO: Properties at Reservoir Conditions Viscosity: Compressibillity (Co): Density: Properties at Saturation Conditions Viscosity: 1.481 Compressibillity (Co): Density: Formation Volume Factor Single-stage Flash: Total Differential Liberation: Total Separator Flash: Note: Standard conditions are 14.696 psia and 60°F 3152 155 2,790 514 STO °API 26.8 1.512 @Pres & Tres WCP Oilphase-DBR 33 pSla of Wt% STO Basis Wt% RF Basis pSla scf/stb scf I stb scf/stb Gas Gravity (Average) 0.744 cP 10'£/psi glee cP 10.£ Ipsi glee @Psat & Tres Job #: 200400086 I I I I I I I I I I I I I I I I I I I Client: Well: ConocoPhillips Placer #1 Field: Sand: Explorati on KUPARUK Schlumberger PVT Analysis on Sample 1.09; Cylinder SSB 12169-QA; Depth 7558.1 ft. MD Reservoir Oil Viscosity at Tres The liquid phase viscosity was measured at the reservoir temperature of 155°F. These values as a function of selected pressure steps are summarized in Table 22. The liquid phase viscosity values are graphically presented in Figure 8. As seen in the figures and as expected, the viscosity values decrease with decreasing pressure up to the bubblepoint and increase with further reduction in pressure below the bubblepoint. Table 22: Reservoir fluid Viscosity 155°f (Sample 1.09) Sample 1.09; Cylinder SSB 12169-0A; Depth 7558.1 ft. MD Pressure Viscosity @ Tres (psia) (cP) 1 2 3 4 5 6 7 Pi Pb 9 10 11 12 13 14 15 WCP Oilphase-DBR 8000 7000 6004 5017 4504 4008 3516 3152 2790 2670 2335 2038 1739 1453 1172 15 2.27 2.10 1.94 1.79 1.72 1.65 1.58 1.51 1.48 1.52 1.69 1.81 1.99 2.16 2.46 5.88 34 Job #: 200400086 I I I I I I I I I I I I I I I I I J I Client: ConocoPhillips Well: Placer #1 WCP Oilphase-DBR Field: Exploration Sand: KUPARUK figure 8: Reservoir fluid Viscosity 155°f (Sample 1.09) Sample 1.09; Cylinder SSB 12169-QA; Depth 7558.1 ft. MD 8 6 L ..E ~ ';;¡ 4 o U III :> 2 o o 2000 ~ 4000 6000 Pressure (psial 35 Schlumberger 8000 10000 Job #: 200400086 I I I I I I I I I I I I I I I I I I I Client: Well: ConocoPhillips Placer #1 Field: Sand: Exploration KUPARUK Schlumberger 5TO Viscosity at Different Temperatures The STD viscosity was measured at different temperatures. The viscosity values are graphically presented in Figure 9. As seen in the figures and as expected, the viscosity values decrease with increasing temperatures. Table 23: Stock Tank Oil Viscosity vs. Temperature (Sample 1.09) Sample 1.09; Cylinder SSB 12169-QA; Depth 7558.1 ft. MD Temperature Viscosity@ Tres (OF) (cP) 1 2 3 4 5 45 75 105 135 155 65.1 24.6 13.3 8.4 5.9 WCP Oilphase-DBR 36 Job #: 200400086 I I I I I I I I I I I I I I I I I I I Client: Well: 70 60 50 ¡:- 40 E. ~ ïñ o u III :;: 30 20 10 o o WCP Oilphase-DBR ConocoPhillips Placer #1 Field: Sand: Exploration KUPARUK Schlumberger Figure 9: Stock Tank Oil Viscosity ys. Temperature (Sample 1.09) Sample 1.09; Cylinder SSB 12169-QA; Depth 7558.1 ft. MD Q 20 40 60 80 100 Temperature (OF) 37 ~ 120 160 180 140 Job #: 200400086 I I I I I I I I I I I I I I I I I I I Client: Well: ConocoPhillips Placer #1 Field: Sand: Exploration KUPARUK Schlumberger HTGC Analysis of the wax content was performed by high temperature gas chromatography (HTGCI. HTGC analysis yields a carbon number distribution of the wax In-paraffin I composition. This analysis is quantitative and can detect low ppm levels at higher carbon numbers. In conclusion, quantitative analysis of wax is accomplished by proprietary extraction procedures and high temperature gas chromatography. The weight% of the n-paraffins are graphically presented in Figure 10. WCP Oilphase-DBR 38 Job #: 200400086 I Client: ConocoPhillips field: Exploration I Well: Placer #1 Sand: KUPARUK I Table 24: HTGC (Sample 1.(9) Sample 1.09; Cylinder SSB 12169-QA; Depth 7558.1 ft. MD Cílrbòn I C21 3547.4 0.35474 079327 I C23 27407 0.27407 1.36821 C25 2052.6 0.20526 1.79822 I C27 1382.3 o 13823 2.10406 C29 974.4 0.09744 2.30457 I C31 518.3 0.05183 2.42358 C33 353.6 0.03536 2.50019 C35 208.3 0.02083 2.54099 I C37 138.4 0.01384 2.57016 C39 107.1 0.01071 2.59450 I C41 73.2 0,00732 2.61024 C43 49.3 0.00493 2.62262 I C45 32.8 0,00328 2.63031 C47 23.2 0.00232 2.63605 I C49 15.4 0.00154 2.63987 CSO C51 13.4 0,00134 2.64304 I C53 10,1 0,00101 2.64521 C55 9,0 0,00090 2.64711 I C57 7.0 0,00070 2.64856 C59 6.4 0,00064 2.64983 I C61 5.9 0,00059 2.65107 CB3 5.0 0,00050 2.65204 I CB5 0.0 0,00000 2.65249 CB7 0.0 0.00000 2.65249 I C69 0.0 0,00000 2.65249 C71 0,0 0,00000 265249 I C73 0.0 0.00000 2.65249 C74 C75 0.0 0.00000 2.65249 I cn 0.0 0,00000 2.65249 C79 0.0 0.00000 2.65249 I Total 26524.9 2.65249 WCP Oilphase-DBR 39 Job #: 200400086 I I I I I I I I Client: Well: I I I I I I I I I I I ~ ¡ c IE !! '" Q. .!; ConocoPhillips Placer #1 Field: Sand: Exploration KUPARUK Figure 10: HTGC (Sample 1.(9) Sample 1.09; Cylinder SSB 12169-0A; Depth 7558.1 ft. MD 0.1 s I-+- Conoco Phillips 1.09 sse 0.01 0.001 0,0001 o N v ~ œ 0 N ~ ~ ø 0 N ~ ~ Ù Ð ~ ~ ~ G ~ ~ 8 8 Õ 0 Õ Ö carbon number '" " ü o '" ü N '" ü " '" ü WC!' Oilphase-DBR 40 4~ -It ~ '" '" ü '" '" ü o '" ü N '" ü " '" ü Job #: 200400086 I I I I I I I I I I I I I I I I I I I Client: ConocoPhillips Field: Exploration Schlumberger Well: Placer #1 Sand: KUPARUK Table 25: SARA and WAT Analysis (Sample 1.09) Sample 1.09; Cylinder SSB 12169-QA; Depth 7558.1 ft. MD SARA Analysis Sample 10 Cylinder # WAY Saturates Aromatics Resins Asphaltenes Inorganics (OF) % (w/w) % (w/w) % (w/w) % (w/w) % (w/w) 1.09 SSB 12169-QA 48 57.44 25.26 14.78 2.49 0.03 WCP Oilphase-OBR 41 Job #: 200400086 I I I I I I I I I I I I I I I I I I I Client: Well: Installation: API Gravity Bg Bo CCE DV GLR GaR La n OBM P Pb PV Pi R Rs T V Vr STL sm %,w/w Z ConocoPhillips Placer #1 Nordic #3 Field: Sand: Job#: Exploration KUPARUK 200400086 Schlumberger Appendix A: Nomenclature and Definitions American Petroleum Institute gravity Gas formation volume factor Oil formation volume factor Constant composition Expansion Differential Vaporization Gas Liquid Ratio Gas Oil Ratio Live Oil Number of moles Oil Based Mud Absolute pressure Bubble point pressure Pressure-Volume Method Initial Reservoir Pressure Universal gas constant Solution gas oil ratio Temperature Volume Relative volume Stock Tank Liquid Stock Tank Oil Weight Percent Gas deviation factor Dry Gross Heating Value is defined as the total energy transferred as heat in an ideal combustion reaction at a standard temperature and pressure in which all water formed appears as liquid. Wet Gross Heating Value is defined as the total energy transferred as heat in an ideal combustion reaction of water saturated gas at a standard temperature and pressure in which all water formed appears as liquid. Molar masses, densities and critical values of pure components are from CRC handbook of Chemistry and Physics and those of pseudo components are from Katz data. Gas viscosity is calculated from the correlation of Carr, Kobayshi and Burrows as given in the "Phase Behavior of Oilfield Hydrocarbon Systems" by M.B. Standing Compressibility in constant mass study is obtained from mathematical derivation of relative volume. Gas gravity is calculated from composition using the perfect gas equation (Gas deviation factor, Z=1) The Stiff and Davis Stability Index is an extension of the Langlier Index and is used as an indicator of the calcium carbonate scaling tendencies of oil field brine. · A positive index indicates scaling tendencies. · A negative index indicates corrosive tendencies. An index of zero indicates the water is in chemical equilibrium and will neither deposit nor dissolve calcium carbonates. WCP Oilphase-DBR 42 Job #: 200400086 I I I I I I I I I I I I I I I I I I I Client: Well: Installation: WCP Oilphase-DBR ConoeoPhillips Placer #1 Nordic #3 Field: Sand: Job#: Exploration KUPARUK 200400086 Schlumberger Appendix B: Molecular Weights and Densities Used Components MW Density (glee) 0.827 0.993 0.808 0.300 0.356 0.508 0.567 0.586 0.625 0.631 0.660 0.753 0.884 0.781 0.688 0.773 0.871 0.749 0.870 0.866 0.884 0.768 0.782 0.793 0.804 0.815 0.826 0.836 0.843 0.851 0.856 0.861 0.866 0.871 0.876 0.881 0.885 0.888 0.892 0.896 0.899 0.902 C02 H2S N2 C1 C2 C3 I-C4 N-C4 I-C5 N-C5 C6 MCYC-C5 BENZENE CYCL-C6 C7 MCYCL-C6 TOLUENE C8 C2-BENZEN M&P-XYLEN O-XYLENE C9 C10 C11 C12 C13 C14 C15 C16 C17 C18 C19 C20 C21 C22 C23 C24 C25 C26 C27 C28 C29 44.01 34.08 28.013 16.043 30.07 44.097 58.124 58.124 72.151 72.151 84 84.16 78.11 84.16 96 98.19 92.14 107 106.17 106.17 106.17 121 134 147 161 175 190 206 222 237 251 263 275 291 300 312 324 337 349 360 372 382 43 Job #: 200400086 I I I I I I I I I I I I I I I I I I I Client: Well: Installation: ConocoPhillips Placer #1 Nordic #3 Field: Sand: Job #: Exploration KUPARUK 200400086 Schlumberger Appendix C: EQUIPMENT Fluid Preparation and Validation The opening pressure of the cylinder is measured using a Heise pressure gauge soon after the sample arrives in the laboratory. Subsequently, the sample bottle is pressurized to the reservoir pressure using water-glycol mixture at the bottomside of the piston cylinder. Custom made heating jacket is wrapped around the cylinder to heat the sample bottle to the reservoir temperature. The sample bottle is then placed into a rocking stand and rocked for 5 days to homogenize the reservoir fluid. Live reservoir fluid analysis is necessary in the sample validation process as well as during the completion of various fluid studies. A description of the experimental equipment used for these analysis follows. All live fluid analyses are completed with a JEFRI Gasometer. This unit in conjunction with GC analysis (see below) provides the full fluid compositional analysis, GaR, density at sampling P& T corrected to standard conditions. The JEFRI gasometer consists of a motor-driven piston in a stationary cylinder. The piston displacement is monitored to determine the swept volume of the cylinder. The cylinder pressure is automatically held at ambient pressure. Piston motion is tracked by a linear encoder, which is subsequently, converted to measure the gas volume in the cylinder. The total Gasometer volume is 10 L. The evolved gas can be re-circulated through the system to facilitate equilibrium at a maximum flow rate of 40 L/hr. The operating pressure of the Gasometer is ambient pressure (up to a maximum of 40 psia) and the operating temperature ranging from room temperature to 40°C. Following the flash of the live fluid sample to ambient conditions in the gasometer, compositional analysis of residual hydrocarbon liquid and evolved gas phase is conducted using gas chromatography (GC). Analysis of hydrocarbon liquids is conducted using an HP6890 liquid injection gas chromatograph equipped with flame ionization detector (FIO). In this system, separation of individual components is carried out in a 30m long, 530mm diameter "Megabore" capillary column made of fused silica with 2.6-micrometer thick methyl silicone as the stationary phase. The operating temperature range of the stationary phase is 60 to 400°C. Over this temperature range, the components eluted are from C1 to C36 along with naphthenes and aromatics components. Based on the physical properties, these components are retarded in a segregated fashion by the stationary phase during the flow of carrier gas (helium) through the column. With prior knowledge of the amount of "retention" for known compounds contained in calibration standards, the same compounds can be identified in the unknown hydrocarbon sample by matching "retention" times. The relative concentration of each component is determined by the concentration of ions hitting the FID upon the elution of each component. The analysis of hydrocarbon gases is carried out using an HP6890 gas injection GC equipped with two separation columns. The first column is a combination of a 100 mesh packed column and 100 mesh molecular sieve using high purity helium as a carrier gas. The molecular sieve is used to achieve separation of the light gaseous components (nitrogen, oxygen, and methane) while the packed column serves to separate ethane, propane, butanes, pentanes, and hexanes along with carbon dioxide and hydrogen sulfides. The second column is a packed column as described previously in liquid analysis. This column is capable of achieving separation of components up to C12+, along with the associated naphthenes and aromatics that are lumped into the C6+ fraction during analysis and reporting. Components up to C4 are analyzed using a thermal conductivity detector (TCO) while the C5+ components are analyzed for using a FIO detector. The instrument has programmable air actuated multi port valves that allow the flow of the sample mixture to be varied between the two columns, and hence, allowing for the correct separation and analysis of the injected gas. WCP Oilphase-DBR Job #: 200400086 44 I I I I I I I I I I I I I I I I I I I Client: Well: Installation: ConocoPhillips Placer #1 Nordic #3 Field: Sand: Job #: Exploration KUPARUK 200400086 Schlumberger Fluid Volumetric (PVT) and Viscosity Equipment The preliminary saturation pressure, constant composition expansion (CCE), differential vaporization (DV), multi-stage separation tests (MSST) are measured using a pressure-volume-temperature (PVTj apparatus. The PVT apparatus consists of a variable volume, visual JEFRI PVT cell. The main component of the cell consists of a Pyrex glass cylinder 15.2-cm long with an internal diameter of 3.2 cm. An especially designed floating piston and a magnetically coupled impeller mixer are mounted inside the Pyrex cylinder to allow for mercury-free operation. The bottom section of the piston is furnished with o-rings to isolate the hydraulic fluid from the cell content. The piston allows liquid level measurements as small as 0.005 cc. The magnetically coupled impeller mixer, mounted on the bottom end cap of the PVT cell, allow quick equilibration of the hydrocarbon fluid. The effective volume of the cell is approximately 120 cc. The Pyrex cylinder is housed inside a steel shell with vertical tempered glass plates to allow visual observation of the internal tube contents. A variable volume JEFRI displacement pump controls the volume, and hence, the pressure of the fluids under investigation by means of injection or withdrawal of transparent hydraulic fluid connected to the floating piston from the top of the JEFRI PVT cell. The same hydraulic fluid is also connected to the outer steel shell to maintain a balanced differential pressure on the Pyrex cylinder. The PVT cell is mounted on a special bracket. which can be rotated 360°. The bracket along with the PVT cell is housed inside a temperature controlled, forced air circulation oven. The cell temperature is measured with a platinum resistance thermal detector (RTD) and displayed on a digital indicator with an accuracy of 0.2°F. The cell pressure is monitored with a calibrated digital Heise pressure gauge precise to ± 0.1 % of full scale. The temperature and pressure ratings of this PVT system are 15,000 psi (103 MPa) and 360°F (182°C). The fluid volume in the PVT cell is determined using a cathetometer readable to the nearest 0.01 mm. The cathetometer is equipped with a high-resolution video camera that minimizes parallax in readings and uses a high- resolution encoder producing both linear and volumetric readings. The height measurements by the cathetometer have been precisely calibrated with the total cell volume prior to the start of the test. The floating piston is designed in the shape of a truncated cone with gradually tapered sides, which allows measurement of extremely small volumes of liquid (0.005 cc) corresponding to roughly 0.01 % of the cell volume. The viscosity of the live reservoir fluid is measured at the reservoir temperature and pressure conditions using Cambridge SPL440 electromagnetic viscometer, which consists of one cylindrical cell containing the fluid sample and a piston located inside the cylinder. The piston is moved back and forth through the fluid by imparting an electromagnetic force on the piston. Viscosity is measured by the motion of the piston, which is impeded by viscous flow around the annulus between the piston and the sample cylinder wall. Various sizes of pistons are used to measure the viscosity of various fluids having different levels of viscosity. The temperature is maintained at the experimental condition using a re-circulating fluid heating system. The internal temperature is monitored using an internal temperature probe. The temperature rating of the viscometer is 190°C and pressure rating is 15,000 psig. The accuracy is ±1.5% of full scale for each individual piston range. The total volume of fluid sample required for viscosity measurement is 5 cc. A cylindrical piston cell (carrier chamber) with a maximum internal volume of 25 mL is attached at the top of the viscometer. The purpose of this cell is to allow the operator to conduct the differential vaporization pressure steps within the viscometer. The back and forth motion of the piston within a narrow clearance provides sufficient agitation to achieve phase equilibration and allow gases to escape and accumulate at the top of the carrier chamber. The heating jacket is wrapped around the viscometer and the carrier chamber and maintains experimental temperature uniformly throughout the system. WCP Oilphase-DBR 45 Job #: 200400086 I I I I I I I I I I I I I I I I I I I Client: ConocoPhillips Field: Exploration S hi b Well: Placer #1 Sand: KUPARUK C um eruer Installation: Nordic #3 Job #: 200400086 The JEFRI PVT cell is also equipped with fiber optic light transmittance probes to measure the onsets of hydrocarbon solids nucleation (OHSPI due to changes in the temperature, pressure and/or composition. These fiber optic probes are mounted across the windows of the visual cell. The principle behind the measurement is based on the transmittance of a laser light in the near infra red (NIRI wavelength through the test fluid undergoing temperature, pressure or the fluid composition changes. In this system, a computerized pump is controlled to maintain the system pressure during isobaric temperature sweeps for wax nucleation, isothermal pressure drop and/or isobaric injections of precipitating solvents for asphaltene nucleation studies. The process variables (i.e., temperature, pressure, solvent volume, time and transmitted light power levell are recorded and displayed from the detector. The fiber optic light transmittance system referred to here that detects the conditions of OHSP is termed as the light scattering system (LSSI. High pressure filters are also used during the asphaltene nucleation study to quantify the amount of asphaltene in the fluid at the specified conditions. The filter manifold used is rated for 10,000 psia. The filter assembly consists of two plates screwed together with the hydrophobic filter sandwiched between them. WCP Oilphase-DBR Job #: 200400086 46 I I I I I I I I I I I I I I I I I I I Client: Well: Installation: ConocoPhillips Placer #1 Nordic #3 Field: Sand: Job#: Exploration KUPARUK 200400086 Schlumberger Appendix D: PROCEDURE Ruids Preparation and Validation After homogenizing, a small portion of the single-phase reservoir fluid is first subjected to a single stage flash experiment to determine flash Gas-Oil-ratio (GOR). The flashing is conducted from some pressure above the bubblepoint pressure at reservoir temperature into an atmospheric Gasometer and measuring the corresponding volumes of gas and liquid. The atmospheric flash also provides parameters such as GOR and stock tank oil density. The flashed fluids (gas and liquid) are then subjected to compositional analysis using gas chromatographic technique. Subsequently, live oil composition is calculated based on the measured gas and liquid compositions and GOR values. In addition, a sub-sample taken from each cylinder is isobarically transferred into the PVT cell at the reservoir temperature. Subsequently, a quick P-V relationship is established to determine the saturation pressure. Constant Composition Expansion Procedure A sub-sample of the test fluid is initially charged to the PVT apparatus and the system temperature stabilized at the reservoir temperature. The CCE experiment is then conducted by incrementally reducing the pressure from some pressure above the bubblepoint pressure to a pressure well below the bubblepoint pressure in a number of discrete steps. At each pressure step, the magnetic stirrer is used to make sure that the subject fluid achieved equilibrium. Total fluid volume (with visual observation of a single or two phase condition in the cell) is measured at each pressure stage, and subsequently, a pressure-volume (P-V) plot is created identifying the phase state at each P-V condition. The intersection of the two lines plotted using the pressure and volume data above and slightly below the observed phase change corresponded to the measured saturation pressure of the fluid. In this manner, the P-V plot confirms the saturation pressure observed visually in the PVT cell. The measured pressure and volume data are then used to compute live oil compressibility above the bubblepoint pressure and relative oil volumes over the entire pressure range. Differential Vaporization Procedure Subsequent to the completion of the CCE experiment, another sub-sample of the test fluid is charged to the PVT apparatus and the cell contents are then mixed with the magnetic mixer to allow for phase equilibration at the reservoir temperature and pressure conditions. A differential vaporization (OV) experiment is then conducted by incrementally reducing the pressure in the PVT cell in discrete steps. In these steps, the pressure is reduced below the saturation pressure, and hence, allowing the gas phase to evolve. A typical pressure stage in a OV test is described below: · The pressure in the PVT cell is reduced to a pressure just above the bubblepoint pressure of the oil. This is the starting point of the OV test. · The pressure of the fluid is then reduced to the first pressure stage (below the bubblepoint pressure) of the OV test allowing free gas to evolve. The magnetic mixer is then used to achieve equilibration between the free gas and the pressurized liquid. · The evolved gas phase is then isobarically removed from the PVT cell into an evacuated pycnometer for gravimetric density and compositional analysis by the flash procedure (see Fluid Analysis Equipment Section) · The previous two steps are repeated until either an atmospheric pressure or a predetermined abandonment pressure is reached. WCP Oilphase-DBR Job #: 200400086 47 I I I I I I I I I I I I I I I I I I I Client: Well: Installation: ConocoPhillips Placer #1 Nordic #3 Field: Sand: Job #: Exploration KUPARUK 200400086 Schlumberger Multi-Stage Separation Test Subsequent to the completion of the DV experiment. another sub-sample of the test fluid is charged to the PVT apparatus and the cell contents are then mixed with the magnetic mixer to allow for phase equilibration at the reservoir temperature and pressure conditions. A multi-stage separation experiment is then conducted by incrementally reducing the pressure and temperature conditions in the PVT cell in discrete steps. In these steps, the pressure is reduced below the saturation pressure, and hence, allowing the gas phase to evolve. A typical pressure stage in a separation test is described below: · The pressure in the PVT cell is reduced to a pressure just above the bubblepoint pressure of the oil. This is the starting point of the separation test. · The temperature of the PVT cell are then reduced to the first-stage separation test temperature and allowed the cell content to equilibrate. The pressure of the fluid is then reduced to the first pressure stage (below the bubblepoint pressure) of the separation test allowing free gas to evolve. The magnetic mixer is then used to achieve equilibration between the free gas and the pressurized liquid. · The evolved gas phase is then isobarically removed from the PVT cell into an evacuated pycnometer for gravimetric density and compositional analysis by the flash procedure (see Fluid Analysis Equipment Section) The previous two steps are repeated in five stages to stock tank conditions. Liquid Phase Viscosity and Density Measurements During DV Step Prior to measuring the viscosity, a suitable size piston is selected with the proper viscosity range and the electromagnetic viscometer is calibrated using a fluid with known viscosity. A portion of the live reservoir fluid used in the DV test is then transferred into a high-pressure high-temperature electromagnetic viscometer. The viscometer is initially evacuated and kept at the same temperature as that of the PVT cell. During the transfer of approximately 15 cc of live hydrocarbon liquid to the evacuated viscometer, flashing of oil takes place, and hence, the viscometer system is flushed with live oil twice to make sure a representative live oil sample is taken. Subsequent to transfer of live reservoir fluid into the viscometer, the fluid system is allowed to achieve thermal and pressure equilibration. Then, the viscosity reading is taken. Following the viscosity reading, incremental pressure reduction steps are repeated as those used in DV steps. At each pressure point, the piston was allowed to run back and forth for sufficient time to achieve pressure equilibration and allow the liberated gas to migrate vertically upwards and accumulate at the top of the carrier chamber. Experiments are also conducted independently using a PVT cell for phase equilibration. The viscosity measurements done on liquid sample transferred from the PVT cell after equilibration compares very well with the measurements done on liquid sample subjected to pressure steps within the viscometer. Stock- Tank Oil (STO) Viscosity and Density Measurements A sample of STD is taken in a known capillary tube to measure the STD viscosity at a preset temperature. The temperature bath is maintained at the preset temperature. A small sample of the liquid is also transferred into the Anton Paar DMA45 densitometer to measure the density of the liquid phase. The viscosity and density measurements are repeated for data consistency check. WCP Oilphase-DBR 48 Job #: 200400086 I I I I I I I I I I I I I I I I I I I Client: Well: Installation: ConocoPhillips Placer #1 Nordic #3 Field: Sand: Job #: Exploration KUPARUK 200400086 Schlumberger Asphaltene, Wax and Sulfur Content Measurements Asphaltene content of stock-tank oil samples is conducted using the IP-143 (French Institute of Petroleuml procedure. In this procedure, the asphaltenes are characterized as the n-heptane insoluble fractions of the crude oil. Wax content of the STO is measured using UOP (Universal Oil Productl 46-64 procedure. The sulfur content of the STO is measured using ASTM D 2494 procedure. . All other STO analysis were measured according to industrial standards. SAfi(P)A Analysis A spinning band distillation was carried out on the original sample to establish two fractions. The initial boiling point to 300°C fraction was then ana lysed using a supercritical fluid chromatographic (ASTM 5186-911 method to determine the saturates and aromatics content. The greater than 300°C fraction first subjected to a gravimetric analysis to determine the pentane insoluble content (asphaltenesl. This method dissolves the fraction in an equal weight of toluene, then 40 volumes of pentane were added to precipitate the insoluble portion of the sample. The precipitate was filtered, dried and weighed. The solvent was removed from the soluble portion of the sample, which was referred to as the maltenes. The maltenes were then redissolved in pentane and were chromatographically separated into saturates, aromatics and resins (polarsl fraction by elution from a column filled with activated alumina, using various solvents and solvent mixtures. The solvents were then removed from each fraction and the amount of material weighed. The data from the three methods were combined to determine the amount of each component type in the original sample. Mass balances were calculated throughout the procedure to assure accurate data. High- Temperature High Pressure filtration Test During the filtration process, it is important that the monophasic fluid remains monophasic as it passes through the filter manifold. Hence, high pressure nitrogen is used on the back side of the filter so that the equal pressure is maintained on both sides of the filter. This procedure prevents any flashing of the fluid in the filter manifold and assures filtration of a representative fluid. WCP Oilphase-DBR 49 Job #: 200400086 · · Approved by : · '~,/ ConocoPhillips r ~ J ,~" FINAL WELL REPORT PLACER #1 CONOCOPHILLlPS ALASKA, INC. Compiled by: Tim Smith Howard Lamp Fletcher England Date: 3/17/04 ( Revised: 01/07105) AVG~C. Zot{ -V/~ "",' ConocOPhillips PLACER #1 · TABLE OF CONTENTS · 1 MUDLOGGING EQUIPMENT & CREW ........................................................................................2 1.1 Equipment Summary .................................................................................................................2 1.2 Crew......... ... ... ... ... ................. ...... ... ... ... ... ... ... ... ... ... ... ..... ... ........................ ............ ... ... ................ 2 2 GENERAL WELL DET AILS ........................................................................................................... 3 2.1 Objectives......... ...... ........... ......... ...... ...... ... ...... ......... ..... ......... .................. ...... ......... ........... ........ 3 2.2 Well Summary............................................................................................................... ............. 3 3 GEOLOGICAL OAT A........................................................................................................... ........... 4 3.1 Lithostratigraphy..... ........ ... ... ... ... ... ...... ... ... ... ... ... ...... ... ....................... ............ ........ ... ......... ........ 4 3.2 Mudlog Summary ................. .................................... ... ... ........ ......... ...... ......... ... ...... ...... ..... ... ..... 5 3.3 Gas Samples. ......... ..... ... ...... ... ... ... ... ............ ...... ... ... ........ ... ......... ......... ... ............................. ..... 9 3.4 Connection Gasses ........ ........ .... ............ ............ .............. ............ ......... ... ...... ... ................. ........ 9 3.5 Sampling Program / Sample Dispatch.................................................................................... 10 4 PRESSURE/ FORMATION STRENGTH OAT A....................................................................... ..11 4.1 Formation Integrity/Leak Off Tests .......................................................................................... 11 4.2 Wireline Formation Tests.. ......... ... ...... '" ............ '" ........... ......... ...... ...... ............ .............. ......... 11 4.3 Pore Pressure Evaluation Introduction .................................................................................... 11 4.4 Pore Pressure Evaluation ........................................................................................................ 12 5 DRILLING DATA........ ...... ...... ......... ............................................ ... ... ... ... ...... ...... ... ... .................... 13 5.1 Survey Information .................................... ................................... .................. ...... .................... 13 5.2 Bit Record....................... ... '" ... ...... ...... ......... ... ...... .................... ........................................ ....... 16 5.3 Mud Record ......... ................................... ............ ................................ ..................... ........... ...... 16 Enclosures 2"/100' Formation Log 2"/100' Drilling Dynamics Log 2"/100' LWD / Lithology Log 2"/100' Gas Ratio Log · r:I FJPOCH 1 . . Conocc)fJhillips PLACER #1 1 MUDLOGGING EQUIPMENT & CREW 1.1 Equipment Summary Parameter Equipment Type / Position Gas trap (flowline/possum belly position) Flame ionization total gas & chromatograph detectors Primary drawworks block position indicator Optical encoder on drawworks Magnetic proximity sensor Ditch gas Rate of penetration (ROP) Pump stroke counter (SPM) Hook Load (HL) / Weight on bit (WOB) Hydraulic pressure transducer Mudlogging unit computer system HP Compaq Pentium 4 (X2, DML & Rigwatch) Mudlogging unit DAC box In-unit data collection/distribution center 1.2 Crew Unit Type Artie Series 10 Skid Unit Number ML015 Mudloggers Y~rs D~¥s Fletcher England 3 1 Tim Smith 8 15 Howard Lamp 1 15 " Years experience as Mudlogger '2 Days at wellsite between spud and total depth of well Additional Comments Technician days represent separate visits over 4 days. Sample Catchers Eamon Kuklok Garrett Abbott Years Days 0.5 15 0.5 15 [:I EPOCH Total Downtime 2:12 4:30 Technician Pete Ramsey . Comments Sheared agitator blade = 96 minutes. Crushed sample line = 36 minutes. Corrupted software + ill-seated miranova card = 210 minutes. Undetermined DAC failures (X2) = 60 minutes total. Days 4 2 . 2 GENERAL WEll DETAilS 2.1 Objectives . . Conoc;Phillips PLACER #1 The primary target of the Placer #1 exploratory well was the Kuparuk C Sand. The well is located in the Kuparuk River Unit approximately 6 miles SW of the Palm /3S development drill site. The well was drilled to 7761 feet where a retainer was set and the well temporarily abandoned. 2.2 Well Summary Well Placer #1 AFE WCD.E02.x047 Classification Exploration License Rig Name I Nordic 3 / Arctic Triple Surface 70020' 47.02" N Water Depth N/A RT Elevation 56' AMSL Type Co-Ordinates 1500 23' 43.41" W Primary Target Kuparuk C Sand Primary Target 7538' MDRT Secondary None Secondary N/A Depth (-6053' TVDSS) Target Target Depth Spud Date 2/27/04 TD Depth 7761' MDRT TD Formation Kuparuk C TD Date 3/12/04 (-6234' TVDSS) Sand Completion Suspended Suspension 3/16/04 Days Drilling 15 Days Testing 3 Status Date Hole Maximum Depth Section MDRT TVDSS (ft) (ft) Conduc 115 -59 tor 121/4" 2548 -2228 8 1/2" 7477 -6004 6 1/8" 7761 -6234 Additional Comments Mud weight increased while drilling the 8 112" hole in response to rising background gas levels. Drill rate controlled through target formation to enable sampling program. TD Formation Mud Weight (ppg) Casing Shoe Depth FIT Coring I MDRT TVDSS (ppg) Liner (ft) (ft) 16" 115 -59 N/A 9 5/8" 2528 -2213 16.0 7" 7467 -5997 14.0 Deviation (oinc) Undifferentiated N/A 10.1 11.1 11.0 o Claystone/siltstone Claystone/siltstone Shale/siltstone 41.3 37.6 35.8 [:I EPOCH 3 . . . ..... ConocoPhillips PLACER #1 3 GEOLOGICAL OAT A 3.1 LithostratiqraDhy Drilling picks and actual wireline tops are the provisional and then corrected picks by the Wellsite Geologist. PROGNOSED DRILLING PICK ACTUAL WIRELlNE PICK HIGH/LOW FORMATION MDRT TVDSS MDRT TVDSS MDRT TVDSS (ft) (ft) (ft) (ft) (ft) (ft) (ft) Base Permafrost 1435 -1360 1470 -1392 1477 -1400 40L Top West Sak 1678 -1570 1657 -1568 1655 -1557 13H Base West Sak 2269 -2025 2270 -2021 2271 -2020 5H C80 (K-10) 2691 -2348 2667 -2317 2667 -2317 31H C40 K-5 3284 -2800 3617 -3048 3617 -3049 238L C50 Not Present Not Present Not Present Not Present Not Present Not Present N/A (K-3) 4800 -3975 4873 -4008 4873 -4008 33L Moraine (K-2) 6553 -5300 6526 -5267 6525 -5267 33H C30 (Base Moraine) 6684 -5400 6698 -5401 6695 -5398 2L Top HRZ 7145 -5752 7055 -5674 7054 -5674 78H C20 (mid-upper HRZ) 7371 -5925 7308 -5871 7328 -5887 38H Base HRZ 7442 -5975 7374 -5924 7374 -5923 52H K-1 7552 -6040 7429 -5967 7429 -5967 73H Top Kuparuk (Kuparuk D) 7626 -6120 7539 -6054 7538 -6053 67H Kuparuk C 7626 -6120 7539 -6054 7535 -6053 67H Miluveach (LCU) 7652 -6140 7559 -6070 7561 -6071 69H (1 EPOCH 4 ",,' ConocoPhillips PLACER #1 · 3.2 Mudloa Summary The following are brief summaries of the lithology and drilling parameters for the successive lithostratigraphic intervals. Tabulated data for each interval does not factor data lost to equipment failure or rig problems (e.g.: unrecorded footage lost due to OAC box failure in the case of drill rate, or gas readings affected by a packed off possum belly/gas trap). For more detail refer to the printed Logs included with this report. T ophole to Base of Permafrost 110' (Surface)to 1477' MORT (-54' to -1400' TVDSS) Cuttings returns were dominated by unconsolidated sand and conglomeratic sand. The mostly siliclastic fragments ranged from lower very fine quartz to metalithic pebbles in excess of 20 mm. Clay and claystone had highly variable silt content, were secondary in abundance, ranged from medium gray in the upper interval to brownish gray in the lower interval, hydrophilic, easily hydrated and adhesive. The very adhesive nature of the clay returns, especially when exacerbated by fast rates of penetration, caused the rig solids equipment to pack-off despite frequent jetting, inhibited the flow of returns, reduced the overall effectiveness of gas detection and occasionally caused gas trap blockages despite frequent cleaning. The blockages caused gaps in the recorded data. Drill Rate (ftlhr) Maximum Minimum Average Maximum Total Gas (%) Minimum Average 741.3 3.1 128.7 60.3 0.5 5.4 · Base of Permafrost to Top West Sak 1477' to 1655' MORT (-1400' to -1567' TVDSS) Clay characteristics differed little from that observed above, but the continuing dominant clay/claystone has discernible increases in siltstone and silt content. Sand and conglomeratic sand are markedly decreased. Drill Rate (ftIhr) Maximum Minimum Average Maximum Total Gas (%) Minimum Average 152.3 10.7 98.4 121.3 9.0 69.7 Top West Sak to Base West Sak 1655' to 2271' MORT (-1567' to -2020' TVDSS) Claystone/clay dominates this section. Locally silty and locally interbedded with thin sandstones. Drill Rate (ftIhr) Maximum Minimum Average Maximum Total Gas (%) Minimum Average 213.8 6.3 143.6 101.8 3.2 56.7 · r:I F,POC:H 5 ""'. ConocoPhillips PLACER #1 · Base West Sak to CBO (K-10) 2271' to 2667' MORT (-2020' to -2317' TVDSS) Claystone/clay becomes more massively bedded and homogenous. Silt and sand decreased toward the bottom of the interval. The 9 518" casing shoe was set at 2528' in this section. Drill Rate (ftlhr) Maximum Minimum Average Total Gas (%) Maximum Minimum Average 220.5 12.9 137.9 83.6 2.2 42.1 CBO (K-10) to C40 (K-5) 2667' to 3617' MORT (-2317' to -3048' TVDSS) This interval was dominated by light gray to light yellowish gray claystone, and has moderate to abundant silt. Sand is rare overall, and localized in thin zones. Drill Rate (ftlhr) Maximum Minimum Average Maximum Total Gas (%) Minimum Average 213.0 11.9 152.3 92.4 0.1 39.0 · C40 (K-5) to (K-3) 3617' to 4873' MORT (-3048' to -4008' TVDSS) Claystone continues to dominate, and continues to be massive, amorphous and adhesive. Overall returns are increasingly less silty and nearly sand-free. Minor poorly developed shale is in the lower part of the interval. Drill Rate (ftlhr) Maximum Minimum Average Maximum Total Gas (%) Minimum Average 239.4 13.3 180.4 136.4 0.2 44.2 (K-3) to Moraine (K-2) 4873' to 6525' MORT (-4008' to -5267' TVDSS) Claystone continues to dominate. Localized interbeds of carbonaceous shale are moderately common. There is an increase in silt content, particularly in the upper portion of this interval. Drill Rate (ftlhr) Maximum Minimum Average Maximum Total Gas (%) Minimum Average 233.4 15.6 151.9 387.2 1.9 78.1 · r:I FPOCH 6 "",' ConocoPhillips PLACER #1 · Moraine (K-2) to C30 (Base Moraine) 6525' to 6695' MORT (-5267' to -5398' TVDSS) Lithologically indistinguishable from the previously described interval. Drill Rate (ftIhr) Maximum Minimum Average Maximum Total Gas (%) Minimum Average 197.1 23.9 124.7 208.3 10.0 120.0 C30 (Base Moraine) to Top HRZ 6695' to 7054' MORT (-5398' to -5674' TVDSS) Interbedded with carbonaceous shale at the top, grading to poorly developed argillaceous shale in the middle, and grading back to carbonaceous shale at the base. While silty throughout, sand appeared in the lower half in estimated amounts up to 30 percent. Drill Rate (ftIhr) Maximum Minimum Average Maximum Total Gas (%) Minimum Average 206.3 7.1 122.7 151.2 6.1 64.8 · Top HRZ to C20 (mid-upper HRZ) 7054' to 7328' MORT (-5674' to -5887' TVDSS) The top of this section was distinctive due to abundant sand and relatively little carbonaceous material. The lower half became increasingly rich in carbonaceous material and lost the sand abundance. The interval was silty throughout. Drill Rate (ftIhr) Maximum Minimum Average Maximum Total Gas (%) Minimum Average 195.4 29.2 142.9 462.3 29.2 259.5 C20 (mid-upper HRZ) to Base HRZ 7328' to 7374' MORT (-5887' to -5923' TVDSS) Nothing distinctive in this section from drilling response, gas returns, or cuttings samples. It appeared as a continuation of the previous interval. Drill Rate (ftIhr) Maximum Minimum Average Maximum Total Gas (%) Minimum Average 163.4 50.9 130.7 531.6 64.7 433.1 · a EPOCH 7 ....'. ConocoPhillips PLACER #1 . Base HRZ to (K-1) 7374' to 7429' MORT (-5923' to -5967' TVDSS) The base appeared as the C20 discussed above, Drill Rate (ftIhr) Maximum Minimum Average Maximum Total Gas (%) Minimum Average 169.4 106,6 146.4 543.7 258.1 397.1 (K-1) to Kuparuk 7429' to 7538' MORT (-5967' to -6053' TVDSS) Claystone, siltstone, and shale comprised the returned lithologies ofthis interval. The shale had become bereft of the previous carbonaceous material and more simply argillaceous. The 7 inch casing shoe was set in this interval. Drill Rate (ftIhr) Maximum Minimum Average Maximum Total Gas (%) Minimum 248.6 9.0 100,9 598.0 30,5 Average 209.2 Kuparuk to Miluveach (LCU) 7538' to 7561' MORT (-6053' to -6071' TVDSS) . Cutting returns through this interval \Nere primarily sand with shale and claystone. The poorly sorted sand ranged from very fine to coarse. Samples displayed 5 to 10 percent yellowish orange fluorescence with a bright yellow flash cut Drill Rate (ftIhr) Maximum Minimum Average Maximum Total Gas (%) Minimum Average 158.6 33,5 90.3 841.1 69.0 401.1 Miluveach (LCU) to T.D. 7561' to 7761' (TO) MORT (-6071' to -6234' TVDSS) This interval was comprised of moderately indurated shale. Soft amorphous clay was seen throughout the interval. A small percentage of sand was seen in the upper half of the section. Drill Rate (ftIhr) Maximum Minimum Average Maximum Total Gas (%) Minimum Average 187.8 36.4 62.1 227.0 56.0 104.2 . r:J F,POCH 8 Cono~illips PLACER #1 · 3.3 Gas SamPles Depth Units C1 C2 C3 C4 C5 1412 51 8918 0 0 0 0 1839 100 19496 0 0 0 0 2103 63 12492 0 0 0 0 2375 45 13230 0 0 0 0 2600 32 5984 15 0 0 0 2865 36 6724 44 0 0 0 3120 54 10334 94 0 0 0 3375 30 5139 61 0 0 0 3650 53 10179 178 0 0 0 3900 92 17184 411 0 0 0 4150 49 8584 298 0 0 0 4400 102 21118 837 279 101 0 4650 23 4198 264 128 52 0 4769 44 6757 520 215 46 0 4888 314 51335 4077 1818 562 5 4900 228 36552 3034 1445 498 48 5150 49 6368 800 736 570 279 5400 33 2983 343 265 189 117 5650 72 11816 978 635 346 139 5900 40 6790 748 634 387 186 6105 112 17184 1692 1359 783 359 6150 35 3581 342 280 168 77 6400 68 6862 668 528 400 207 6659 206 23807 2851 1692 819 368 6900 69 7126 737 493 313 200 · 7200 322 44682 3215 1554 706 271 7475 258 36226 2757 1103 455 158 3.4 Connection Gasses Depth Units C1 C2 C3 C4 C5 3560 25 3193 54 0 0 0 5170 60 5379 662 572 112 306 5266 50 2559 265 217 43 128 5361 62 5615 680 610 126 351 5460 82 9662 870 586 93 275 7060' 81u 9978 975 574 81 190 7155' 184u 25471 1877 960 135 342 7250' 860u MISSED PEAK 0 0 0 7345' 871u 126746 10818 4650 604 1192 7441' 1020u 164188 12527 5001 627 1342 · [:I 'EPOCH 9 . . . ..... ConocoPhillips PLACER #1 3.5 Samplina PrOQram I Sample Dispatch Set Type I Purpose Interval Frequency Dispatched to Unwashed Biostratigraphy Bayview Warehouse Four set owners: 115' - 1410' 60' ConocoPhillips Alaska, Inc. ABV 100 A CPAI, Exxon Mobil, Chevron, 1410' - 7470' 30' 8105 Eleusis Drive 7470' -7761' 10' Anchorage, AK 99502 ASRC Attn: D. Przywojski/M. McCracken Washed, screened & dried Bayview Warehouse Reference Samples 115' - 1410' 60' ConocoPhillips Alaska, Inc. ABV 100 B Five set owners; 1410' - 7470' 30' 8105 Eleusis Drive CPAI, Exxon Mobil,Chevron, 7470' -7761' 10' Anchorage, AK 99502 AOGCC, ASRC Attn: D. Przywojski/M. McCracken Gas bags 250'& Isotech Laboratories, Inc. C Routine intervals and significant 1412' -7750' as gas returns 1308 Parkland Court peaks above background dictated Champaign,IL 61821 Bayview Warehouse USGS Gas Hydrate Samples 115' - 3040' ConocoPhillips Alaska, Inc. ABV 100 D 60' 8105 Eleusis Drive (single grab sampling) Anchorage, AI< 99502 Attn: D. Przywojski/M. McCracken Wellsite Pyrolysis Evaluation Hand carried off location by M. Wood, wellsite geologist M. Tobey E Washed Samples 7050' - 7625' 5' Humble Instruments & Services, Inc. Two-time (2) Mud Samples 218 Higgins Street Above Kuparuk C Sand Humble, TX 77338 115' -1410' 60' F Onsite Samplex Samples 1410' -7470' 30' Retained in unit pending directive 7470' - 7761' 10' . Sample frequency was locally altered according to drill rate constraints. (1 EPOCH 10 ~. ConocoPhillips PLACER #1 · 4 PRESSURE I FORMATION STRENGTH DATA 4.1 Formation IntearitvlLeak Off Tests Equivalent mud weight (EMW) is calculated from rotary table (RT). MDRT (ft) 2568 7487 TVDSS (ft) -2243 -6013 LOT IFIT (ppg EMW) 16.0 14.0 FORMATION Claystone Claystone LOT (Leak Off Test) in bold italics. 4.2 Wireline Formation Tests Equivalent mud weight (EMW) is calculated from rotary table (RT). · TEST MDRT TVDSS PRESSURE EMW No. (ft) (ft) (psi) (ppg) 1 7558 6069 3152 9.9 2 7553 6066 3152 9.9 3 7558 6069 3152 9.9 4.3 Pore Pressure Evaluation Introduction Trend Indicators COMMENTS Good Permeability Fair Permeability Good Permeability The following pore pressure parameters are considered to provide reliable indicators for pore pressure trends during the drilling of a well; Background Gas (8G) Resistivity (RES) Hole Conditions (He) Trip Gas (TG) Mud Weight (MW) Corrected D exponent (DXC) Connection Gas (CG) Quantitative Methods During the drilling of the well no quantitative estimates were made from derived Corrected D exponents (DXC). Factors such as controlled drill rates, hole inclination, and absence of clean shale baselines to establish compaction trends precluded reliable estimation. Qualitative estimation was limited to consideration of increases in background gas, appearance and trends of connection gasses, and surface manifestations of hole conditions. Results Summary Final wellsite derived pore pressure evaluation is summarized in table form (Section 4.4). · a FPO~H 11 . . . Conoc~Pt,illips PLACER #1 4.4 Pore Pressure Evaluation Formation Primary Interval Tops Pore Pressure'EMW) Source of Quantitative MDRT TVDSS Min Max Trend Indicators Interval Lithology (ft) (ft) (ppg) (ppg) Trend Estimate Base Permafrost Clyst/Sd 1477 -1400 9.0 8.5 +ve BG N/A Top West Sak ClystlSd 1655 -1551 9.0 8.5 +ve BG N/A Base West Sak ClystlSltst 2071 -2020 8.5 +ve BG F.IT C80 (K-10) ClystlSltst 2667 -2317 8.5 BG N/A C40 K-5 ClystlSltst 3617 -3048 8.5 +ve BG,CG N/A (K-3) ClystlSltstlSh 4873 -4008 8.5 +ve BG,CG N/A Moraine (K-2) C lystlSltstlSh 6525 -5267 8.5 +ve BG N/A C30 (Base Moraine) ClystlSltst 6695 -5398 8.5 BG N/A Top HRZ ClystlSltstlSd 7054 -5674 8.5 +ve BG,CG N/A ISh C20 (mid-upper HRZ) ClystlSh/Sltst 7328 -5887 8.5 +ve CG,BG N/A Base HRZ C lystlSh/Sltst 7374 -5923 8.5 +ve CG,BG N/A K-1 C lystlShlSltst 7429 -5967 8.5 +ve CG,BG N/A Kuparuk SstlSh 7538 -6053 9.9 +ve MDT MDT Miluveach (LCU) Sh/Clyst 7561 -6071 8.5 -ve BG N/A Total Depth Sh/Clyst 7761 -6234 8.5 BG N/A NOTE: Clyst=Claystone/clay Sd=Sand Sltst=Siltstone Sh=Shale Sst=Sandstone ~ EPOCH 12 ....... ConocoPhillips PLACER #1 · 5 DRilLING DATA 5.1 Survey Information Depth Inel. Azim. Depth Northings Eastings 8ection Rate (ft) (ft) (ft) (ft) (ft) (-/10Oft) 0 0 0 0 O.OON O.OOE 0 0 110.00 0.00 0.00 110.00 O.OON O.OOE 0.00 0.00 240.17 0.22 49.46 240.17 0.16N 0.19E -0.14 0.17 333.33 0.31 31.52 333.33 0.49 N 0.46E -0.43 0.13 420.37 0.31 58.57 420.37 0.82N 0.78E -0.72 0.17 513.23 0.39 53.43 513.23 1.14 N 1.25 E -0.98 0.09 604.56 0.44 65.82 604.55 1.47 N 1.82E -1.24 0.11 697.19 0.78 123.25 697.18 1.27 N 2.67E -0.93 0.71 788.62 2.07 127.28 788.58 0.088 4.51 E 0.62 1.41 878.88 3.28 141.16 878.74 3.088 7.42 E 3.95 1.51 972.93 5.88 163.13 972.49 9.788 10.51 E 10.98 3.29 1064.51 8.97 175.58 1063.29 21.398 12.42 E 22.73 3.79 1156.33 14.10 176.62 1153.23 39.71 8 13.63 E 41.06 5.59 1247.72 16.36 176.68 1241.40 63.67 8 15.03 E 65.02 2.47 1343.1 18.47 173.70 1332.41 92.108 17.47 E 93.54 2.40 · 1437.28 24.02 171.77 1420.16 125.93 8 21.85 E 127.65 5.94 1530.95 26.06 171.46 1505.02 165.15 S 27.64 E 167.28 2.18 1626.78 30.67 173.56 1589.32 210.28 8 33.51 E 212.78 4.92 1721.16 37.43 175.94 1667.48 262.878 38.25 E 265.56 7.30 1816.21 40.80 176.25 1741.21 322.69 8 42.32 E 325.44 3.55 1911.23 42.11 174.53 1812.43 385.38 S 47.39 E 388.29 1.83 2005.29 43.25 173.85 1881.58 448.82 S 53.85 E 452.04 1.31 2100.54 43.68 174.55 1950.71 514.008 60.47 E 517.55 0.68 2195.11 42.49 173.54 2019.78 578.25 8 67.17 E 582.13 1.45 2289.87 41.32 172.75 2090.30 641.098 74.71 E 645.42 1.35 2385.38 41.52 172.45 2161.92 703.75 8 82.85 E 708.60 0.30 2478.78 41.77 171.67 2231.72 765.22 8 91.43 E 770.66 0.62 2554.67 41.29 171.50 2288.53 814.998 98.79 E 820.96 0.65 2649.05 40.86 170.94 2359.68 876.28 8 108.25 E 882.94 0.60 2743.51 39.60 172.62 2431.80 936.65 8 116.99 E 943.92 1.76 2838.47 38.75 172.9 2505.41 996.168 124.55 E 1003.91 0.91 2933.43 39.02 173.46 2579.33 1055.358 131.63 E 1063.52 0.47 3026.06 39.77 172.63 2650.91 1113.708 138.75 E 1122.31 0.99 3122.42 39.38 173.18 2725.19 1174.628 146.33 E 1183.69 0.54 3216.77 38.71 173.10 2798.46 1233.638 153.43 E 1243.13 0.71 · r:I F,POCH 13 Conocc;'ittillips PLACER #1 · Depth I net. Azim. Depth Northings Eastings Section Rate (ft) (ft) (ft) (ft) (ft) (0/1ooft) 3311.70 40.17 173.91 2871.78 1293.55 S 160.25 E 1303.43 1.63 3405.60 39.88 172.38 2943.68 1353.50 S 167.45 E 1363.81 1.09 3500.76 40.92 172.13 3016.15 1414.61 S 175.76 E 1425.48 1.11 3596.03 40.73 171.72 3088.24 1476.28 S 184.51 E 1487.75 0.34 3690.02 40.46 171.50 3159.61 1536.78 S 193.44 E 1548.89 0.33 3784.87 41.83 172.69 3231.04 1598.59 S 202.01 E 1611.29 1.66 3879.48 41.69 173.07 3301.61 1661.12 S 209.82 E 1674.30 0.31 3973.89 41.36 173.21 3372.29 1723.26 S 217.30 E 1736.89 0.36 4068.79 40.86 172.52 3443.79 1785.17 S 225.04 E 1799.28 0.71 4163.27 40.25 172.68 3515.58 1846.09 S 232.96 E 1860.71 0.65 4258.08 39.54 172.6 3588.32 1906.40 S 240.75 E 1921.52 0.75 4352.61 38.79 172.3 3661.61 1965.58 S 248.59 E 1981.21 0.82 4447.50 37.97 172.24 3735.99 2023.96 S 256.51 E 2040.12 0.87 4542.14 39.29 174.63 3809.93 2082.65 S 263.25 E 2099.19 2.10 4636.02 39.33 175.20 3882.57 2141.89 S 268.52 E 2158.64 0.39 4730.47 40.77 174.65 3954.86 2202.42 S 273.90 E 2219.38 1.57 4825.04 40.17 174.74 4026.81 2263.54 S 279.58 E 2280.73 0.64 · 4920.07 39.32 174.13 4099.88 2324.01 S 285.46 E 2341.47 0.98 5014.32 40.03 173.42 4172.42 2383.83 S 291.99 E 2401.64 0.89 5108.61 39.39 173.26 4244.95 2443.66 S 298.98 E 2461.88 0.69 5204.21 40.74 174.30 4318.12 2504.83 S 305.64 E 2523.41 1.58 5299.08 40.34 173.98 4390.21 2566.17 S 311.93 E 2585.06 0.48 5394.22 39.51 174.13 4463.17 2626.90 S 318.26 E 2646.11 0.88 5488.56 40.98 174.12 4535.18 2687.53 S 324.50 E 2707.05 1.56 5581.47 40.22 174.25 4605.72 2747.68 S 330.62 E 2767.50 0.82 5675.79 42.57 173.71 4676.48 2809.70 S 337.17 E 2829.85 2.52 5772.13 42.11 173.23 4747.69 2874.17 S 344.55 E 2894.74 0.58 5867.00 41.03 173.51 4818.66 2936.69 S 351.82 E 2957.69 1.16 5961.79 40.15 173.35 4890.64 2997.96 S 358.87 E 3019.36 0.93 6053.73 41.51 172.66 4960.21 3057.62 S 366.20 E 3079.47 1.56 6151.24 40.64 172.5 5033.72 3121.15 S 374.47 E 3143.54 0.90 6246.05 39.66 171.98 5106.18 3181.73 S 382.72 E 3204.66 1.09 6341.02 38.41 171.79 5179.95 3240.94 S 391.16 E 3264.46 1.32 6435.16 39.52 172.42 5253.15 3299.58 S 399.29 E 3323.65 1.25 6530.45 ~8.61 172.51 5327.13 3359.11 S 407.17 E 3383.70 0.96 6625.43 39.76 173.03 5400.75 3418.64 S 414.71 E 3443.7 1.26 6719.50 41.05 172.66 5472.38 3479.14 S 422.31 E 3504.68 1.39 6813.89 40.41 172.90 5543.91 3540.24 S 430.05 E 3566.26 0.70 · 6908.78 39.10 172.66 5616.86 3600.44 S 437.68 E 3626.94 1.39 7003.16 38.47 172.54 5690.43 3659.07 S 445.29 E 3686.06 0.67 r:I 'EPOCH 14 ,.... ConocoPhillips PLACER #1 . Depth Inet. Azim. Depth Northings Eastings Section Rate (ft) (ft) (ft) (ft) (ft) (-/100ft) 7098.76 38.12 172.83 5765.46 3717.83 S 452.84 E 3745.30 0.41 7193.08 40.20 172.41 5838.59 3776.89 S 460.49 E 3804.86 2.22 7288 39.01 171.79 5911.72 3836.83 S 468.80 E 3865.36 1.32 7383 37.86 171.87 5986.13 3895.28 S 477.20 E 3924.40 1.21 7419.83 37.60 171.84 6015.26 3917.59 S 480.39 E 3946.93 0.71 7504.96 36.82 172.54 6083.06 3968.60 S 487.39 E 3998.41 1.04 7598.67 36.70 172.58 6158.14 4024.20 S 494.65 E 4054.49 0.13 7695.08 35.76 172.57 6235.91 4080.71 S 502.01 E 4111.47 0.98 7761.00 35.12 172.57 6289.61 4118.61 S 506.95 E 4149.69 0.97 . . r:I RPOCH 15 . . . Conoc;Phillips PLACER #1 5.2 Bit Record Depth Total Bit Avg. WOB PP Bit Make Type Jets I TFA In Footage Hrs ROP (klbs) RPM (psi) Wear BHA (ft) (ftlhr) 12 114" Hole 1 HTC MX-C 1 3x15, 1x10 110 2438 23.7 I 103 20-25 80 2950 1-3-WT -A-E-I-NO- TD 1 8 1/2" Hole 2 HTC HCM-605 5x14 2548 4423 32.1 I 145 8-20 82 2989 NO GRADING 2 2rr1 HTC HCM-605 5x14 6971 506 4.3 130 15-25 79 3586 O-O-NO-A-X-I-NO- TD 3 6 118" Hole 3 Reed I DS69FNPV I 5x11 7477 284 4.8 I 59 10 80 3025 1-1-CT-NG-X-I-ER-TD 4 5.3 Mud Record Contractor MI Mud Type Spud/LSND MW I ECD VIS PV I YP Gels I FL I FC Sols OIW Sd CI Ca (ppg) (ppg) (s/qt) (cc) (%) Ratio (%) (mill) (mill) 121/4" Hole: 115' -2548' MDRT 9.6-10.3 I 180 - 256 28-44 I 40-60 24/39/68 - I 6.8-5.8 I 2 7-12 /88-93 I 2.0-4.0 I 500- 40-60 30/56/74 600 81/2" : 2548' -7476' MDRT 10.1-11.1 I 47-55 15-44 I 22-32 9/13/21 - I 3.4-4.2 I 2 11-14 1/84 - 1/89 I .01-.25 I 550- 40-80 12/27/37 950 6118" : 7476' -7761' MDRT 11.0 I 54-58 16-17 1 21-24 8/22/27 - I 4.5-4.8 1 2 14 1/85-2/84 1 .01-.25 I 600 120 1 0/28/34 Abbreviations MW = Mud Weight Gels = Gel Strength Sd = Sand content ECD = Effective Circulating Density WL = Water or Filtrate Loss CI = Chlorides VIS = Funnel Viscosity FC = Filter Cake Ca = Hardness Calcium. PV = Plastic Viscosity Sols = Solids YP = Yield Point OIW = Oil to Water ratio [:I EPOCH 16