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Home My WebLink About204-065CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: NOT OPERABLE: Injector L-216 (PTD #2040650) MIT-IA due September 2025 Date:Monday, September 8, 2025 7:33:43 AM From: PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Sent: Sunday, September 7, 2025 9:39 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; Torin Roschinger <Torin.Roschinger@hilcorp.com> Subject: NOT OPERABLE: Injector L-216 (PTD #2040650) MIT-IA due September 2025 Mr. Wallace, Injector L-216 (PTD #2040650) is due for AOGCC witnessed MIT-IA by the end of September 2025. The well will not be put on injection and is now classified as NOT OPERABLE due to lapse in the 4 year required AOGCC MIT-IA. A witnessed MIT-IA will be performed once the well is on stable injection. Please call with any questions or concerns. Ryan Holt Hilcorp Alaska LLC Field Well Integrity / Compliance Ryan.Holt@Hilcorp.com P: (907) 659-5102 M: (907) 232-1005 From: AK, GWO Well Integrity Engineer <AKGWOWellSiteEnginee@bp.com> Sent: Monday, September 18, 2017 2:46 PM To: AK, GWO Well Integrity Engineer <AKGWOWellSiteEnginee@bp.com>; 'Regg, James B (DOA) (jim.regg@alaska.gov)' <jim.regg@alaska.gov>; AK, OPS EOC Specialists <AKOPSEOCSpecialists@bp.com>; AK, OPS GC2 Facility OTL <AKOPSGC2FacilityOTL@bp.com>; AK, OPS GC2 Field O&M TL <AKOPSGC2FieldOMTL1@bp.com>; AK, OPS GC2 OSM <AKOPSGC2OSM@bp.com>; AK, OPS GC2 Wellpad Lead <AKOPSGC2WellpadLead@bp.com>; AK, OPS PCC Ops Lead <AKOPSPCCOpsLead@bp.com>; AK, OPS Prod Controllers <akopsprodcontrollers1@bp.com>; AK, OPS Well Pad HUQ <AKOPSWellPadHUQ@bp.com>; AK, OPS Well Pad LV <AKOPSWellPadLV@bp.com>; AK, OPS Well Pad MN <AKOPSWellPadMN@bp.com>; AK, OPS Well Pad RJ <AKOPSWellPadRJ@bp.com>; AK, OPS WELL PAD S <AKOPSWELLPADS@bp.com>; AK, OPS Well Pad SW <AKOPSWellPadSW@bp.com>; AK, OPS WELL PAD W <AKOPSWELLPADW@bp.com>; AK, OPS Well Pad Z <AKOPSWellPadZ@bp.com>; Ak, Ops West Area TL <AkOpsWestAreaTL@bp.com>; AK, RES GPB East Wells Opt Engr <AKRESGPBEastWellsOptEngr@bp.com>; AK, RES GPB West Wells Opt Engr <AKRESGPBWestWellsOpt@BP.com>; Bergene, Matthew <Matthew.Bergene@bp.com>; Frankenburg, Amy <Amy.Frankenburg@bp.com>; Peru, Cale <Cale.Peru@bp.com>; Rupert, C. Ryan <Ryan.Rupert@BP.com>; Shriver, Tyson <Tyson.Shriver@bp.com>; Wellman, Julie <Julie.Wellman@bp.com>; Youngmun, Alex <younak@BP.com>; Zoesch, Eric <zoese0@BP.com>; AK, GWO DHD Well Integrity <AKD&CDHDWellIntegri@bp.com>; AK, GWO SUPT Well Integrity <AKDCWellIntegrityCoordinator@bp.com>; AK, OPS FF Well Ops Comp Rep <AKOPSFFWellOpsCompRep@bp.com>; AKIMS App User <akimsuser.service@bp.com>; Cismoski, Doug A <CismosDA@BP.com>; Daniel, Ryan <Ryan.Daniel@bp.com>; Dempsey, David G <David.Dempsey1@bp.com>; Hibbert, Michael <Michael.Hibbert@BP.com>; Janowski, Carrie <Carrie.Janowski@bp.com>; Montgomery, Travis J <Travis.Montgomery@bp.com>; Munk, Corey <Corey.Munk@bp.com>; Obrigewitch, Beau <BEAU.OBRIGEWITCH@bp.com>; O'connor, Katherine <Katherine.O'connor@bp.com>; Sternicki, Oliver R <Oliver.Sternicki@bp.com>; Tempel, Joshua <Joshua.Tempel@bp.com>; Worthington, Aras J <Aras.Worthington@bp.com> Subject: OPERABLE: Injector L-216 (PTD #2040650) MIT-IA Passed All, L-216 (PTD #2040650) passed its state witnessed MIT-IA on 09/17/17. Additional follow up monitors have shown the IA pressure is now stable. The well is reclassified as Operable at this time. Please reply with any questions, Matt Ross (Alternate: Josh Stephens) Well Integrity Engineering Office 907-659-8110 Cell 907-980-0552 Harmony 4530 From: AK, GWO Well Integrity Engineer Sent: Friday, September 15, 2017 1:49 PM To: 'Regg, James B (DOA) (jim.regg@alaska.gov)'; AK, OPS EOC Specialists; AK, OPS GC2 Facility OTL; AK, OPS GC2 Field O&M TL; AK, OPS GC2 OSM; AK, OPS GC2 Wellpad Lead; AK, OPS PCC Ops Lead; AK, OPS Prod Controllers; AK, OPS Well Pad HUQ; AK, OPS Well Pad LV; AK, OPS Well Pad MN; AK, OPS Well Pad RJ; AK, OPS WELL PAD S; AK, OPS Well Pad SW; AK, OPS WELL PAD W; AK, OPS Well Pad Z; Ak, Ops West Area TL; AK, RES GPB East Wells Opt Engr; AK, RES GPB West Wells Opt Engr; Bergene, Matthew; Frankenburg, Amy; Peru, Cale; Rupert, C. Ryan; Shriver, Tyson; Wellman, Julie; Youngmun, Alex; Zoesch, Eric; AK, GWO DHD Well Integrity; AK, GWO SUPT Well Integrity; AK, GWO Well Integrity Well Information; AK, OPS FF Well Ops Comp Rep; AKIMS App User; Cismoski, Doug A; Daniel, Ryan; Dempsey, David G; Hibbert, Michael; Janowski, Carrie; Montgomery, Travis J; Munk, Corey; Obrigewitch, Beau; O'connor, Katherine; Sternicki, Oliver R; Tempel, Joshua; Worthington, Aras J Subject: UNDER EVALUATION: Injector L-216 (PTD #2040650) Due for AOGCC Compliance MITIA All, L-216 (PTD #2040650) is an PWI well with no known integrity issues. The well was made not operable 9/19/13 for not being placed on injection before its 4 year AOGCC MIT-IA was due. The well is now ready to be placed back on injection and is reclassified as Under Evaluation. An AOGCC witnessed MIT-IA will be conducted once the well is online and stable. Please reply with any questions, Matt Ross (Alternate: Josh Stephens) Well Integrity Engineering Office 907-659-8110 Cell 907-980-0552 Harmony 4530 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 11/28/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20231128 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU-13 50133205250000 203138 11/13/2023 HALLIBURTON RMT3D MPU B-28 50029235660000 216027 11/20/2023 HALLIBURTON LDL MPU B-28 50029235660000 216027 11/21/2023 HALLIBURTON MFC MPU C-20 50029219140000 189015 11/21/2023 HALLIBURTON LDL NS-24 50029231110000 202164 11/20/2023 READ LeakPointSurvey PBU 13-20 50029207050000 182009 11/16/2023 HALLIBURTON WFL-TMD3D PBU L-216 50029232060000 204065 7/20/2023 PROBE MSIL (CBL) PBU S-09A 50029207710100 214097 7/7/2023 PROBE MSIL (CBL) PBU S-32A 50029220990100 212082 7/13/2023 PROBE MSIL (CBL) PBU S-124 50029233230000 206136 7/15/2023 PROBE MSIL (CBL) Please include current contact information if different from above. T38150 T38151 T38151 T38152 T38153 T38154 T38155 T38156 T38157 T38158 11/29/2023 PBU L-216 50029232060000 204065 7/20/2023 PROBE MSIL (CBL) Kayla Junke Digitally signed by Kayla Junke Date: 2023.11.29 11:22:45 -09'00' 7. Property Designation (Lease Number): 1. Operations Performed: 2. Operator Name: 3. Address: 4. Well Class Before Work:5. Permit to Drill Number: 6. API Number: 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): Susp Well Insp Install Whipstock Mod Artificial Lift Perforate New Pool Perforate Plug Perforations Coiled Tubing Ops Other Stimulate Fracture Stimulate Alter Casing Pull Tubing Repair Well Other: Change Approved Program Operations shutdown 11. Present Well Condition Summary: Casing Length Size MD TVD Burst Collapse Exploratory Stratigraphic Development Service 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 16. Well Status after work: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. OIL GAS WINJ WAG GINJ WDSPL GSTOR Suspended SPLUG Authorized Name and Digital Signature with Date: Authorized Title: Contact Name: Contact Email: Contact Phone: PBU L-216 Patch Tubing Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 204-065 50-029-23206-00-00 8490 Conductor Surface Intermediate Production Liner 4867 80 3979 8453 8021 20" X 34" 9-5/8" 7" 4601 28 - 108 27 - 4006 26 - 8479 28 - 108 27 - 2686 26 - 4861 8212 770 3090 5410 8021 2280 5750 7240 7465 - 8180 4-1/2" 12.6# x 3-1/2" 9.3# L80 24 - 8045 4295 - 4690 Structural 3-1/2" Baker Premier Packers 7984, 4581 7328, 7599, 7782, 7984 4222, 4368, 4469, 4581 Stan Golis Sr. Area Operations Manager Brodie Wages David.Wages@hilcorp.com 907.564.5006 PRUDHOE BAY, SCHRADER BLUFF OIL, Orion Total Depth Effective Depth measured true vertical feet feet feet feet measured true vertical measured measured feet feet feet feet measured true vertical Plugs Junk Packer Measured depth True Vertical depth feet feet Perforation depth Tubing (size, grade, measured and true vertical depth) Packers and SSSV (type, measured and true vertical depth) 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a.Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: Subsequent to operation: 15. Well Class after work: Exploratory Development Service StratigraphicDaily Report of Well Operations Copies of Logs and Surveys Run Electronic Fracture Stimulation Data Sundry Number or N/A if C.O. Exempt: ADL 0028239 24 - 4615 N/A N/A Well Not Online 1638 1400 250 125 400 322-605 13b. Pools active after work:Schrader Bluff Oil, Orion 4-1/2" Baker S3 Packer 7328, 4222 / 7599, 4368 / 7782, 4469 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS Sr Pet Eng: Sr Pet Geo: Form 10-404 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Sr Res Eng: Due Within 30 days of Operations By Meredith Guhl at 7:21 am, Jan 23, 2023 Digitally signed by Stan Golis (880) DN: cn=Stan Golis (880), ou=Users Date: 2023.01.20 16:53:45 -09'00' Stan Golis (880) DSR-1/23/23 RBDMS JSB 012623 204-065 A subsequent MIT-IA was not stipulated in the sundry. The patch set is shown on the new WBS, below. -WCB PRUDHOE BAY, SCHRADER BLUFF OIL, Orion WCB 11-3-2023 Repair Well 322-605 Patch Tubing PBU L-216 Sundry Number ACTIVITY DATE SUMMARY 11/18/2022 T/I/O = 1100/330/65 Well SI on arrival. (WAG SWAP) Pumped 120 bbls 180*F diesel down TBG @ 1 bpm. DSO notified. FWHP's= 350/500/75 12/11/2022 (PATCH TUBING / LINER) Assist SL. Got pulled for higher priority job. 12/11/2022 ***WELL S/I ON ARRIVAL*** R/U POLLARD #58 RAN 10' x 2-1/4" P. BAILER(msfb) TO 7,926' SLM AND RECVOVERED 1/2 GAL SCHMOO ***WSR CONT ON 12-12-22*** 12/11/2022 T/I/O = 400/313/65. Temp - SI. Assist SL w/ Brush and Flush. *** Job continued to 12- 12-2022 *** 12/12/2022 *** Job continued from 12-11-2022 *** Assist SL. Pumped 148 bbls 180* DSL into TBG to assist SL w/ Brush and Flush. SL in control of well upon departure. FWHP's = -4/481/73 12/12/2022 ***WSR CONT FROM 12-11-22*** RAN 10' x 2-1/4" P. BAILER (msfb) TO 7,926' SLM, RECOVERED 1/2 GAL SCHMOO & HARD PACK CRUD BRUSHED w/ 4-1/2" BLB, 3.75" G-RING, BRUSH 4-1/2" TBG FROM SURFACE TO 3-1/2" XO @ 7,310' SLM (LRS pumped 115bbls, 190~ degrees @ 1bpm) BRUSHED w/ 3-1/2" BLB, 2.73" G-RING, BRUSH 3-1/2" TBG FROM 7,310' SLM TO 7,925' SLM (LRS pumped 32bbls, 190~ degrees @ 1bpm) RAN 20' X 2.78'' DMY WHIPSTOCK DRIFT S/D HIGH @ 7415'SLM PULLED READ CASED HOLE 24 ARM CALLIPER FROM 7900'SLM TO SURFACE(GOOD DATA) BRUSHED W/ 3-1/2 BLB & 2.80'' G-RING, BRUSH 3-1/2'' TBG FROM 7327'MD TO 7925'SLM LRS PUMPED 20BBLS @ 5BPM TO FLUSH AREA AROUND 7,415' SLM ATTEMPTED TO DRIFT w/ 20' x 2.78" D. WHIP THROUGH 7,415' SLM (st#6) w/OUT SUCCESS LRS PUMP ASSISTED DRIFT w/ 20' x 2.78" D. WHIP THROUGH 7,415' SLM (st#6) SUCCESSFULLY 3X ( RATE OF 2BPM @ 12OFPM) TO 7,647' SLM (see log) ***WELL LEFT S/I*** ***will return at a later date to bail down to prong and recover missing roller wheel before setting patch across hole*** 12/12/2022 T/I/O = 214/328/56 Temp - SI. Assist SL. Pumped 37 bbls DSL into TBG. SL in control of well upon departure. FWHP's = -5/290/50 Daily Report of Well Operations PBU L-216 ***will return at a later date to bail down to prong and recover missing roller wheel before setting patch across hole*** Daily Report of Well Operations PBU L-216 12/17/2022 ***WELL S/I ON ARRIVAL*** RAN 2 1/2" BAILER S/D @ 7,865' SLM DOWN TO 7,895' SLM (1 GAL. SCHMOO) RAN 2 1/2" BAILER S/D @ 7,895' SLM DOWN TO 7,915' SLM (1 GAL. SCHMOO) RAN 2 1/2" BAILER S/D @ 7,913' SLM DOWN TO 7,920' SLM (1/2 GAL. OF SCHMOO) RAN 2 1/2" BAILER S/D @ 7,919' SLM DOWN TO 7,922' SLM (1/2 GAL. SCHMOO) RAN KJ, 3 1/2" BLB, 2.79" GAUGE RING, S/D @ 7,918' SLM ( BRUSH 3 1/2" PIPE) RAN 2 1/2 BAILER, S/D @ 7,918' SLM, BAIL DOWN TO 7,922' SLM (1 GAL. SCHMOO) ***CONTINUE 12/18/22*** 12/18/2022 ***CONTINUE FROM 12/17/22*** BAILED @ 7,920' SLM (hard packed schmoo, not making much hole) RAN 1.75" DRIVE DOWN BAILER, MADE PILOT HOLE DOWN TO 7,944' SLM RAN 2" PUMP BAILER TO SAME DEPTH RAN 3 1/2" BRUSH, 2.79" GAUGE RING TO 7,942' SLM RAN 2" PUMP BAILER TO 7,945' SLM (recovered 1 gal. sandy schmoo) RAN 2" PUMP BAILER TO 7,948' SLM (recovered 1 gal. sandy schmoo) RAN 2" PUMP BAILER TO 7,951'' SLM (recovered 1 gal. sandy schmoo) ***CONTINUE 12/19/22*** 12/19/2022 ***CONTINUE FROM 12/18/22*** BAILED SCHMOO FROM 7,952' SLM TO 7,988' SLM ***CONTINUE 12/20/22*** 12/20/2022 ***CONTINUE FROM 12/19/22*** BAILED FROM 7,989' SLM TO 7,999' SLM (marks on btm of blr) RAN 2.70" MAGNET TO PRONG @ 8,021' MD NO RECOVERY RAN 2 1/2" DECENTRALIZER, 2.70" LIB TO PRONG (shows top of prong being pushed to ~07:30) RAN 2.25" WIRE GRAB W/ 1 PRONG ORIENTED TO 02:00 RAN 2.70" MAGNET, NO RECOVERY PUMP 120 BBLS DIESEL W/ THUNDERBIRD UNABLE TO LATCH WITH 2-1/2" JUC S/D AT 7,997' SLM RAN 2 1/2" P-BLR S/D AT 7,997' SLM RAN 2 1/2" JUC S/D AND LATCH AT 7,999' SLM ***CONTINUE 12/21/22*** 12/20/2022 T/I/O=400/300/50 Assist SLickline Pumped 120 bbls diesel down TBG for load. Job continues next day 12/21/2022 ***CONTINUE FROM 12/20/22*** MADE A COUPLE ATTEMPTS TO LATCH PRONG @ 8,021' MD RAN 2 1/2" PUMP BAILER TO PRONG (empty) LATCH & PULL PRONG FROM 8,021' MD FISHED MISSING ROLLER WHEEL FROM TOP OF RMX BODY @ 8,021' MD SET DUMMY RMX PRONG IN RMX BODY @ 8,021' MD DRIFTED W/ 20' x 2.78" DUMMY WHIPSTOCK TO 7,600' SLM, PUMP ASSISST GETTING BY SPOT @ 7,405' SLM (see log) ***WELL LEFT S/I ON DEPARTURE, PAD OP NOTIFIED OF STATUS*** 1/2/2023 T/I/O=60/300/60 ***Assist S-Line*** No fluids pumped. Continued on 01-03-2023 SL bailed sand and schmoo down to the lowest nipple, pulled the prong, and fished the stem wheel. -WCB BAILED FROM 7,989' SLM TO 7,999' SLM (marks on btm of blr) RAN 2" PUMP BAILER TO 7,945' SLM (recovered 1 gal. sandy schmoo)(gy) RAN 2" PUMP BAILER TO 7,948' SLM (recovered 1 gal. sandy schmoo)(gy) RAN 2" PUMP BAILER TO 7,951'' SLM (recovered 1 gal. sandy schmoo) ( LATCH & PULL PRONG FROM 8,021' MD MADE A COUPLE ATTEMPTS TO LATCH PRONG @ 8,021' MD SET DUMMY RMX PRONG IN RMX BODY @ 8,021' MD FISHED MISSING ROLLER WHEEL FROM TOP OF RMX BODY @ 8,021' MD Daily Report of Well Operations PBU L-216 1/2/2023 ***WELL S/I ON ARRIVAL***(patch tbg) R/U HES 759 SLICKLINE UNIT ***CONT WSR ON 1/3/23*** 1/3/2023 Continued from 01-02-2023 ***Assist S-Line***. S-Line able to make it down hole without assistance. No fluids pumped. FWHP=60/300/30 S-Line on location upon departure 1/3/2023 ***CONT WSR FROM 1/2/23*** ( DRIFTED W/ 44' DUMMY PATCH DRIFT (2.78" max od), SD @ 7,662' SLM (bobble ~7,415' slm @ 100fpm) ***WELL LEFT S/I UPON DEPARTURE, PAD OP NOTIFIED OF WELL STATUS*** 1/14/2023 ***WELL SHUT IN ON ARRIVAL*** (PATCH SET) MIRU E-LINE PT PCE 300PSI LOW, 2000PSI HIGH SET OWENS X-SPAN PATCH 7498'-7530' CCL-TOP ME=15.4', CCL STOP 7482.6' RDMO E-LINE ***WELL SHUT IN ON DEPARTURE*** JOB COMPLETE. 1/14/2023 T/I/O= 50/275/50 Temp=S/I (TFS Unit 4 Assist E-Line with pump down) Pumped 2 bbls of 60/40 followed by 32 bbls of DSL down TBG to assist E-Line with making TD. E-Line in control of well upon TFS departure. Final WHPS= 50/275/50 1/15/2023 T/I/O=0/292/59 Assist Slickline with WFRs Pumped 15 bbls 180* DSL down Tbg ***Job Cont to 01/16/2023 WSR*** 1/15/2023 ***WELL S/I ON ARRIVAL*** HES UNIT 759 R/U LRS PRESSURE UP TUBING TO AND PUMPED 15 BBLS OF DIESEL TO CONFIRM INJECTIVITY ATTEMPT TO PASS THRU X SPAN PATCH W/ 2-7/8 KOT @ 7498' MD (tray s/d) ATTEMPT TO DRIFT THRU X SPAN PATCH W/ 2.29" SWAGE @ 7498' MD unable to pass 7519' SLM ***CONT, WSR ON 1/16/2023*** 1/16/2023 ***CONT, WSR FROM 1/15/2023*** RAN 2.25" CENT, 1-3/4" S.BAILER, THRU PATCH TO FILL AT 7972' SLM PULL STA #3 RK-AL-WFR @ 7736' MD (2-7/8 OM-1) SET RK-DMY GLV IN STA #3 @ 7736' MD (0 psi w/ diesel) PULL STA #1 RK-AL-WFR @ 7933' MD SET RK-DMY GLV IN STA #1 @ 7933' MD (0 psi w/ diesel) LRS ATTEMPT TO PT TBG TO 2500#, UNABLE TO REACH TEST PRESSURE ESTABLISH LIQUID LEAK RATE OF .78BPM @ 2000#. ATTEMPT TO JAR DOWN ON RK-DUMY GLV IN STA #1 @ 7933' MD, RK-1 TT PINS UNTOUCHED. ****CONT, WSR ON 1/17/2023**** 1/16/2023 ***Job Cont from 01/15/23 WSR*** Assist Slickline (PATCH TUBING / LINER). Pumped 115 bbls DSL assisting SL. Identified a LLR of .78 bpm at 2000 psi. *** Job continued to 01-17-2023 *** 1/17/2023 ***Job Cont from 01/16/23 WSR*** Assist Slickline (PATCH TUBING / LINER) Pumped 27 bbls DSL down Tbg. ***Job Cont to 01-18-2023 WSR*** RAN 2.25" CENT, 1-3/4" S.BAILER, THRU PATCH TO FILL AT 7972' SLM EL set patch. Patch is shown on the new WBS, below. -WCB MIRU E-LINE RDMO E-LINE ( DRIFTED W/ 44' DUMMY PATCH DRIFT (2.78" max od), SD @ 7,662' SLM (bobble ~7,415' slm @ 100fpm) @(y) ATTEMPT TO DRIFT THRU X SPAN PATCH W/ 2.29" SWAGE @ 7498' MD unable to pass 7519' SLM Assist Slickline SET OWENS X-SPAN PATCH 7498'-7530' Daily Report of Well Operations PBU L-216 1/17/2023 ****CONT, WSR FROM 1/16/2023**** RAN 1.48" LIB TO OBTAIN IMPRESSION OF LATCH IN STA #3, GOOD IMPRESSION OF RK LATCH, DMY VALVE THERE. MAKE SEVERAL ATTEMPTS TO PULL RK DMY GLV IN STA #1. RAN 1.58" LIB TO OBTAIN IMPRESSION OF LATCH IN STA #1, GOOD IMPRESSION OF RK LATCH, DMY VALVE THERE. PULLED & RE-SET RK- DMY GLV IN STA #1 @ 7933' MD BAILED 8 GAL OF FINE SAND FROM 7939' TO 7950' SLM. ****CONT, WSR ON 1/18/2023**** 1/18/2023 ***Job Cont from 01-17-2023 WSR*** Assist Slickline w/ WFR (PATCH TUBING / LINER) Pump 190 bbls diesel for LDL FWHPs=0/240/50 1/18/2023 ****CONT, WSR FROM 1/17/2023**** BAILED TOTAL OF 9.5 GALS OF SCHOOM/FINE SAND FROM 7939' TO 7961' SLM RAN HES LDL LOG FROM 7951' SLM TO 7300' SLM, SEE AWGRS FOR DETAILS. 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Supervisor FROM: Bob Noble Petroleum Inspector NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Monday, October 11, 2021 SUBJECT: Mechanical Integrity Tests Hilcorp North Slope, LLC L-216 PRUDHOE BAY UN ORIN L-216 Src: Inspector Reviewed By- P.I. Supry Comm Well Name PRUDHOE BAY UN ORIN L-216 API Well Number 50-029-23206-00-00 Inspector Name: Bob Noble Permit Number: 204-065-0 Inspection Date: 9/12/2021 Insp Num: mitRCN210912153240 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well L-216 -Type Inj G 'TVD 4222 _ Tubing 1 2394 - 2412- 2405 2392 PTD 2040650 Type Test SPT'Test psi 1500 - IA 384 1848 - 1790 1778 _ -- BBL Pumped: 1.4 BBL Returned: 1.2 OA 75 75 j75 75 - Interval 4YRTST p/F P Notes: Monday, October 11, 2021 Page 1 of 1 • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: DATE: Friday,September 22,2017 Jim Regg P.I.Supervisor \ e 7/ q 1 i SUBJECT: Mechanical Integrity Tests l BP EXPLORATION(ALASKA)INC. L-216 FROM: Lou Laubenstein PRUDHOE BAY UN ORIN L-216 Petroleum Inspector Src: Inspector Reviewed By: P.I.Supry NON-CONFIDENTIAL Comm Well Name PRUDHOE BAY UN ORIN L-216 API Well Number 50-029-23206-00-00 Inspector Name: Lou Laubenstein Permit Number: 204-065-0 Inspection Date: 9/17/2017 V Insp Num: mitLOL170918160349 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well L-216 Type Inj W -ITVD 4222 Tubing 1577 - 1586 ' 1580 1583 - PTD 2040650 Type Test SPT !Test psi 1500 IA 2 2398 2327 ' 2324 - BBL Pumped: 2 BBL Returned: 2 - OA 67 68 69 - 69 , Interval 4YRTST P/F P �--- -- ------ Notes: �e-a 6e S C � Z.Cj I L SCANNEV i- 4 4,0d Friday,September 22,2017 Page 1 of 1 Schl~nherger Alaska Data & Consulting Services 2525 Gambell Street, Suite 400 Anehorage,AK 99503-2838 ATTN: Beth Well Job # ,. ., ~; ~ ` ~~. ~. } ~ (11(1 „. ce. '~~ LOO IJCSCflntlnn NO. 5447 Company: State of Alaska Alaska Oil & Gas Cons Comm Attn: Christine Mahnken 333 West 7th Ave, Suite 100 Anchorage, AK 99501 ~( • ~•• ~,,,ucai ua[a center l_R2-1 Alaska Data 8 Consulting Services 900 E. BenSOn Blvd. -, .. ~ ~~~ ~ ~ ~i f! i~ 2525 Gambell Street, SuBe 400 M U tb ~'~~~~~' Anchorage, AK 99503-2838 MEMORANDUM Toy Jim Regg P.I. Supervisor ~~ ~ z~' ~~ ~~ FROM: Bob Noble Petroleum Inspector State of Alaska Alaska Oil and Gas Conservation Commission DATE: Thursday, December 03, 2009 SUBJECT: Mechanical Integrity Tests BP EXPLORATION(ALASKA)INC L-216 PRUDHOE BAY IJN ORIN L-216 Src: Inspector NON-CONFIDENTIAL Reviewed By: P.I. Suprv~J~~- Comm Well Name: PRUDHOE BAY UN ORIN L-216 API Well Number: 50-029-23206-00-00 Inspector Name: Bob Noble Insp Num: mitRCN091202065046 Permit Number: 204-065-0 Inspection Date: 11/30/2009 Rel Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well L-216 Type Inj. ~ W TVD -~ 4222 IA 330 1615 1580 1580- -~ ~ P.T.D zoao6so JTypeTe is T Test~psi 161s ° OA o o ~ 0 0 Interval 4YRTST ~ p~F P ~ Tubing ]470 1470 I 1470 1470 Notes: ~,~~~ ,~,E~~c}-- I~u~,.~ = i50DPSi Thursday, December 03, 2009 Page 1 of 1 L-212 (PTD#2050300) and L-2~PTD#2040650) Request for 4-Year re~atory testing ... Page 1 of 2 Maunder, Thomas E (DOA) From: NSU, ADW Well Integrity Engineer [NSUADWWeIIlntegrityEngineer@BP.com] Sent: Saturday, October 10, 2009 8:56 AM To: Maunder, Thomas E (DOA) Subject: RE: L-212 (PTD#2050300) and L-216 (PTD#2040650) Request for 4-Year regulatory testing extension Thank you Mr. Maunder. ~L~~ `-~ ~~~~'~~~ ~~i~-~'~ ~ ~~ ~~~~ Torin From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] _ Sent: Saturday, October 10, 2009 6:42 AM To: NSU, ADW Well Integrity Engineer Cc: Regg, James B(DOA); Schwartz, Guy L(DOA) Subject: RE: L-212 (PTD#2050300) and L-216 (PTD#2040650) Request for 4-Year regulatory testing extension Torin, I agree that better scheduling would be preferred. Since there is not indication of integrity loss, it is acceptable to delay until the rig moves. Keep us informed as to the timing. I am not totally familiar with the upcoming schedule on other pads, but it would seem appropriate to look forward and determine if there could be some conflicts out there. Tom Maunder, PE AOGCC From: NSU, ADW Well Integrity Engineer [mailto:NSUADWWeIIIntegrityEngineer@BP.com] Sent: Fri 10/9/2009 3:11 PM To: Maunder, Thomas E(DOA); NSU, ADW Well Integrity Engineer Cc: Regg, James B(DOA); Schwartz, Guy L(DOA) Subject: RE: L-212 (PTD#2050300) and L-216 (PTD#2040650) Request for 4-Year regulatory testing extension Tom, The plan was to wait until two or three days before the L-212 and L-216 witnessed MITIAs were do to group them with the MITIAs for L-115, L-215, and V-104 (due 11/28/09) to save a trip for the AOGCC field inspector. In the past, the inspector had made the trip all the way out to L or V-Pad for one well inspection and we are trying to do a better job at scheduling these to respect their time. Unfortunately, the rig trucks began staging equipment and the activity on the pad became to congested to perform the work. The reason for not performing the MITIAs until the rig moves is because the area is extremely congested with the rig, rig camps, trucks, pipe racks, etc. The team is not comfortable conducting this work with the current activity on the pad and most of the current obstacles can be eliminated after the rig moves. There is rig equipment directly in front of wellhouses L-212 and L-216. Close proximity to Rig N-7ES is 45-90 feet in this case. I too would much rather have had these tested prior to the rigs arrival and I am embarrassed these have not been completed. Thank you, 10/12/2009 L-212 (PTD#2050300) and L-2~TD#2040650) Request for 4-Year re~atory testing ... Page 2 of 2 Torin From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Friday, October 09, 2009 1:45 PM To: NSU, ADW Well Integrity Engineer Cc: Regg, James B(DOA); Schwartz, Guy L(DOA) Subject: RE: L-212 (PTD#2050300) and L-216 (PTD#2040650) Request for 4-Year regulatory testing extension Torin, Some questions ... Why were these injectors not tested in advance of moving N7ES to L-223? Were there some extenuating circumstances that prevented the wells from testing earlier than the 4 yr anniversary date? Testing earlier is something that we clearly would not refuse. - What is it about performing the MIT that prevents you from testing with the rig in "close proximity"? - What is close proximity? Thanks in advance. I look forward to your reply. Tom Maunder, PE AOGCC From: NSU, ADW Well Integrity Engineer [mailto:NSUADWWeIIIntegrityEngineer@BP.com] Sent: Friday, October 09, 2009 11:40 AM To: Regg, James B(DOA); Maunder, Thomas E(DOA); Schwartz, Guy L(DOA) Subject: L-212 (PTD#2050300) and L-216 (PTD#2040650) Request for 4-Year regulatory testing extension Jim/Tom/Guy, Injectors L-212 (PTD#2050300) and L-216 (PTD#2040650) were due for their 4-year regulatory MITIA's on 10/04/09. Currently, Rig N-7ES is drilling L-223 and will follow by drilling L-222. These two injectors are in close proximity to the rig and do not allow enough space to safely perform AOGCC MITIA's at this time. I would like to ask permission to inject in both L-212 and L-216 until the rig has moved off L-Pad toward the end of October at which time the MITIA's will be immediately conducted. I have attached the TIO plot and wellbore schematic for each injector. «L-212.pdf» «L-212 TIO Plot.doc» «L-216.pdf» «L-216 TIO Plot.doc» Please let me know if you require anything else. Thank you, Torin Roschinger (alt. Anna Dube) Well Integrity Coordinator Office (907) 659-5102 Cell (406) 570-9630 Pager (907) 659-5100 Ext. 1154 10/12/2009 L-216 (PTD# 2040650) TIO Plot . a~ 3 ~ ~ a~ a 0.4 IA MOASP 7C31 f~009 8M SI2009 8C31 /2009 9M SC2009 9f30C2009 +Tubing Pressure (psi) tIA Pressure (psi) ~-OA Pressure (ps) OOA Pressure (psi) f OOOA Pressure (psi) ~ • BP Exploration (Alaska) Inc. Attn: Well Integrity Coordinator, PRB-20 Post Office Box 196612 Anchorage, Alaska 99519-6612 August 14, 2009 ~~~MiL Y • ~ .t .4 '''~~~ L~~V • bp ~,~~~~~~~ Mr. Tom Maunder Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Corrosion Inhibitor Treatments of GPB L-Pad Dear Mr. Maunder, 0 C T 0~ 20Q9 ~Ilas~C~ ~ii ~ Gas Cons. Conxnis~ion Anchorage a p~^ ~ Cos- L-~ ~ ~ Enclosed please find multiple copies of a spreadsheet with a list of wells from GPB L- Pad that were treated with corrosion inhibitor in the surface casing by conductor annulus. The corrosion inhibitor is engineered to prevent water from entering the annular space and causing external corrosion that could result in a surface casing leak to atmosphere. The attached spreadsheet represents the well name, API and PTD numbers, top of cement depth prior to filling and volumes of corrosion inhibitor used in each conductor. As per previous agreement with the AOGCC, this letter and spreadsheet serve as notification that the treatments took place and meet the requirements of form 10-404, Report of Sundry Operations. If you require any additional information, please contact me or my alternate, Anna Dube, at 659-5102. Sincerely, Torin Roschinger BPXA, Well Integrity Coordinator i BP Exploration (Alaska ) Inc. ~ Surtace Casing by Conductor Mnulus Cement, Corrosion inhibitor, Sealant Top-oft Report of Sundry Operations (10-404) Date L pad B/t 3/2009 Well Name PTD # API # Initial to of cement Vol. of cement um ed Final top of cement Cement top off date CoROSion inhibitor Corrosion inhibitor/ sealant date ft bbis ft na al L-01 2010720 50029230110000 NA 6 NA 61.2 6/25/2009 L-02A 2041490 50029230480100 NA 1.4 NA 14.5 6/27/2009 L-03 2051030 50029232690000 NA 2.8 NA 24.7 6/25/2009 L-04 2061200 50029233190000 NA 1.7 NA 15.3 6/25/2009 L-100 1980550 50029228580100 NA 6.2 NA 57.8 6/29/2009 1-101 1980320 50029228650000 NA 3.3 NA 30.6 6/29/2009 L-102 2020360 50029230710000 37' NA Need To Job? NA L-103 2021390 50029231010000 NA 1.6 NA 10.2 6/26/2009 L-104 2012380 50029230600000 NA 3.5 NA 47.6 5/6/2009 L-105 2020580 50029230750000 NA 1.75 NA 24.65 516/2009 L-106 2012230 50029230550000 NA 2.75 NA 28.05 5/6/2009 L-107 2011510 50029230360000 NA 4.8 NA 57.8 5/6/2009 L-108 2021090 50029230900000 NA 12 NA 13.8 6/25/2009 L-109 2012010 50029230460000 NA 2.9 NA 32.3 6/27/2009 L-110 2011230 50029230280000 NA 27 NA 316.2 6/29/2009 L-111 2020300 50029230690000 NA 4.7 NA 54.4 6/29/2009 L-112 2022290 50029231290000 NA 5.5 NA 51 6/27/2009 L-114A 2051120 50029230320100 NA 2.5 NA 25.5 6/29/2009 L-115 2011400 50029230350000 NA 0.5 NA 3.4 6/27/2009 L-116 2011160 50029230250000 NA 5 NA 54.4 6/28/2009 L-117 2011670 50029230390100 NA 2.9 NA 28.9 6/27/2009 L-118 2011870 50029230430000 NA 1.4 NA 15.3 6/27/2009 L-119 2020640 50029230770000 NA 2.25 NA 28.9 5/6/2009 L-120 2020060 50029230640000 NA 0.75 NA 6.8 5/5/2009 L-121A 2030390 50029231380100 NA 2.2 NA 25.5 6/27/2009 L-122 2030510 50029231470000 NA 2 NA 20.4 6/27/2009 L-123 2051940 50029232900000 NA 2 NA 18.7 6/27/2009 L-724 2050430 50029232550000 NA 1.8 NA 77 6/27/2009 L-200 2040010 50029231910000 NA 1.8 NA 13.5 6/26/2009 L-201 2040460 50029232020000 NA 1.75 NA 15.3 5/6/2009 L-202 2041960 50029232290000 NA 2 NA 17 6l26I2009 ~-204 2060920 50029233140000 NA 1.5 NA 5.95 5/6/2009 L-205 2080530 50029233880000 NA 1 NA 12.75 1/10/2009 L410 2031990 50029231870000 NA 3.25 NA 31.4 5/5/2009 L-211 2040290 50029231970000 NA 1.8 NA 17 6/27/2009 L-212 2050300 50029232520000 NA 1.8 NA 17 6/26/2009 L-213 2060530 50029233080000 NA 2 NA 17 6/25/2009 L-214A 2060270 50029232580100 NA 0.25 NA 10.2 5/6/2009 L-215 2051270 50029232740000 NA 1.5 NA 30.6 5/6/2009 L-216 2040650 50029232060000 NA 1.3 NA 11.9 6/26/2009 L-217 2060750 50029233120000 late blockin conductor NA NA L-218 2051190 50029232720000 NA 1.7 NA 15.3 6/27/2009 L-219 2071480 50029233760000 surtace NA NA L420 2080470 50029233870000 NA 2 NA 20.4 6/28/2009 L-221 2080310 50029233850000 NA 1.7 NA 16.2 6/25/2009 L-250 2051520 50029232810000 NA 3.4 NA 34 6/26/2009 L-50 2051360 50029232770000 NA 1.8 NA 20.4 6/27/2009 L-51 2060590 50029233090000 NA 1.8 NA 17 6/27/2009 09/29/08 ..Irlf Y41iFp~Yfi~~G1 Alaska Data & Consulting Services 2525 Gambell Street, Suite 400 Anchorage, AK 99503-2838 ATTN: Beth WPII .Inh !t 1 .... n.. N0.4908 Company: State of Alaska Alaska Oil & Gas Cons Gomm Attn: Christine Mahnken 333 West 7th Ave, Suite 100 Anchorage, AK 99501 17-12 11978484 ---- ----- PRODUCTION PROFILE - __.~ 09/19/08 ..~ 1 ........ vv 1 P2-27 12017505 PRODUCTION PROFILE ~ _ 09/08/08 1 18-OSA 11999048 FREE POINT INDICATOR LOG 09/16/08 1 1 E-36 12034922 SCMT 09/13/08 1 1 06-13A 12066547 MEM PROD PROFILE b(p- ~(] 09/05/08 1 1 12-09 12083409 MEM DENSITY LOG ( 09/06/08 1 1 13-14 11978482 PROD PROFILE ~ - ~ 09/13/08 1 1 L-214A 11970843 INJECTION PROFILE 2 ~~~ 09/05/08 1 1 L-210 12031511 INJECTION PROFILE 09/02/08 1 1 L-216 11970842 INJECTION PROFILE ~ _ 09/04/08 1 1 V-221 12034920 INJECTION PROFILE 1 09/09/08 1 1 L-205L4 40016965 OH MWD/LWD EDIT 06/26/08 (2 PRINTS & 1 CD HAND DELIVERED SEPARATELY) DI CACC A~ve.ln\~II ~nn~ n~ n~Inr n --_._-________._.._~_... ~. ~............-,.-r •.r•v.......~n v..~vvrl LI1V1~ IV. BP Exploration (Alaska) Inc. Petrotechnical Data Center LR2-1 900 E. Benson Blvd. Anchorage, Alaska 99508 Date Delivered: ~- J(,, ~ ~`p Alaska Data & Consulting Services 2525 Gambell Street, Sui 400 Anchorage, AK 9~-2 8 - ATTN: Beth 44 Received by: • • .,~ ~~i~~~~U~~~~~ Alaska Data & Consulting Services 2525 Gambell Street, Suite 400 Anchorage, AK 99503-2838 ATTN: Beth won ~..w a P^ r h3 ~. ~r._, i, r ~~~e2~ ~ f N0.4903 Company: State of Alaska Alaska Oil & Gas Cons Comm Attn: Christine Mahnken 333 West 7th Ave, Suite 100 Anchorage, AK 99501 09/23!08 L-216 10687773 -- ---- - MDT 05/09/04 ~.~ a.vw~ 1 vu 1 L-204 11212880 MDT ~- 07/24/06 1 1 14-22A 11999036 PPROF W/FLOW SCAN IMAGER / '3(~ 08/17/08 1 1 H-11 12017507 USIT 08/09/08 1 1 D-22C 11963190 USIT _ '17 (~ 08/20/08 1 1 NK-10 12066549 MEM I(VJECTION PROFILE G) - ( J g'~ 09/11/08 1 1 09-28A 12031499 RST - 08/01/08 1 1 N-10A 12005225 MCNL ~ ~ 08/20/08 1 1 05-23B 40016995 OH MWD/LWD EDIT - 05/27/08 2 1 PI Gecc eritnin~nn cnr_o oo romr nv ~~~. ~~.~.~. . BP Exploration (Alaska) Inc. Petrotechnical Data Center LR2-1 900 E. Benson Blvd. Anchorage, Alaska 99508 Date Delivered: Alaska Data & Consulting Services 2525 Gambell Street, Suite 400 Anchorage, AK 99503-283 ATTN: Beth Received by: ~ ~" C ~~ ~~~~ • • -.,..,, ~. r .. MICROFILMED 03/01/2008 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE F:~LaserFicheiC~rPgs_InsertsiMicrofilm_Marker.doc 10/24/06 SclllulJlbel'gel' Schlumberger-DCS 2525 Gambell St, Suite 400 Anchorage, AK 99503-2838 ATTN: Beth 2. ;»fln(lle" I" _) NOe 4013 If., Company: Alaska Oil & Gas Cons Comm Alln: Christine Mahnken 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Fìe}d: Aurora Orion Well Job# Log Description Date BL Color CD 5-123 40010951 OH EDIT OF MWDILWD 09119/04 2 1 5-119 40010957 OH EDIT OF MWDILWD 10/11/04 2 1 L-216 40010478 OH EDIT OF MWD/LWD 05/07/04 2 1 . PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COPY EACH TO: BP Exploration (Alaska) Ince Petrotechnical Data Cenler LR2-1 900 E Benson Blvd Anchorage AK 99508-4254 Schlumberger-DCS 2525 Gambe" Ste Suite 400 Anchorage, AK 99503-2838 ATTN: Beth Received by Date Delivered" . SCANNED OCT 2 (3 2DDO c_) I C- [)oL./ - 0(0 $- #: J L../10 .5- 06/28/06 Scblumberger Sì, NO. 3873 Schlumberger-DCS 2525 Gambell St, Suite 400 Anchorage, AK 99503·2838 A TTN: Beth (~{)¿I-ò~S- Company: Alaska Oil & Gas Cons Comm Attn: Christine Mahnken 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: Onon, Aurora, Borealis, Polaris Well Job# Log Description Date BL Color CD V·212 1 1225953 INJECTION PROFILElWFL 04108/06 1 L·212 11217240 INJECTION PROFILE 04116/06 1 L·216 11217241 INJECTION PROFILE 04117/06 1 L-215 11217242 INJECTION PROFILE 04118/06 1 V-213 REDO) 1 1 076450 INJECTION PROFILE 07/01/05 1 e PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COPY EACH TO: BP Exploration (Alaska) Inc. Petrotechnical Data Center LR2- 1 900 E Benson Blvd. Anchorage AK 995084254 Date Delivered: /las/oG { I Schlumberger-DCS 2525 Gambel! St. Suite 400 Anchorage, AK 99503-2838 ~ ATTN Beth il Received by: Q _ ^-- e Andy, No open hole logging data was submitted for PBU Orion L-216 API 50-029-23206-00. Please send over bluelines, reproduceables, and digital logging data for this well. TNX Howard ( 7 J W\.A- ). þ~ ~ DATA SUBMITTAL COMPLIANCE REPORT 5/25/2006 Permit to Drill 2040650 Well Name/No. PRUDHOE BAY UN ORIN L-216 Operator BP EXPLORATION (ALASKA) INC MD 8490 r- TVD 4867"/ Completion Date 5/17/2004'/ Completion Status WAGIN Current Status WAGIN REQUIRED INFORMATION Sfl~ ~~ ~ 'f API No. 50-029-23206-00-00 ~Y~'~- Mud Log No Samples No Directional surv~_.~ ~ DATA INFORMATION Types Electric or Other Logs Run: MWD / GR, MWD / GR / RES / DEN / NEU / PWD, MDT, USIT Well Log Information: (data taken from Logs Portion of Master Well Data Maint Log/ Electr Data Digital Dataset Log Log Run T;6 Med/Frmt Number Name Scale Media No D Asc Directional Survey ~ Directional Survey Pds 13006 Cement Evaluation / -~ 13006 Cement Evaluation Blu ""t See Notes Interval OH/ Start Stop CH Received 5/19/2004 0 0 5/19/2004 5780 8375 2/11/2005 5780 8375 2/11/2005 0 0 5/26/2005 Well Cores/Samples Information: Name Interval Start Stop Sample Set Number Comments Sent Received ADDITIONAL INFOR~OI. ION Well Cored? ~ ~ Daily History Received? íßtN ~ Chips Received? ¿( / r~ Formation Tops Analysis Received? ~ Comments: /'16 OftM {~ ,h þ R....VY\tl; I L I ~ 1ì \ 1{~ / ß L I If-V\(~~ kui~j,; {J~¿Î ~. Date: Compliance Reviewed By: . Comments ULTRASONIC IMAGER- CEMENT EVALUATION ULTRASONIC IMAGER- CEMENT EVALUATION Black Oil PVT Study Report . \~v-.-~~ · MEMORANDUM State of Alaska - Alaska Oil and Gas Conservation Commission TO: ~~ S~::~isor Ke17 It I b D5" DATE: Wednesday, October 05,2005 SUBJECT: Mechanical Integrity Tests BP EXPLORATION (ALASKA) INC L-216 PRUDHOE BA Y UN ORIN L-216 FROM: John Crisp Petroleum Inspector Src: Inspector Reviewed By: P.I. Suprv J13lz- Comm NON-CONFIDENTIAL Well Name: PRUDHOE SAY UN ORIN L-216 API Well Number 50-029-23206-00-00 Insp Num: miUCr051004115033 Permit Number: 204-065-0 Rei Insp Num Inspector Name: John Crisp Inspection Date: 10/4/2005 Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. I L-216 IType Inj. ! W IA Well ; TVD 4222 480 1610 1590 1590 ITypeTest I SPT i P.T. I 2040650 Test psi 1055.5 1 OA 180 230 230 230 I Interval INITAL P/F P Tubing 900 880 880 880 Notes Wednesday, October 05,2005 Page 1 of 1 Schlumhepgep Schlumberger-DCS 2525 Gambell St. Suite 400 Anchorage, AK 99503-2838 ATTN: Beth Well Log Description Job # . /}Atf- 005 '"L-216 ¿;IJ/ I l '1 ..,0 V-211 I') 0"1 - Á/-o. L-210 cr- 0..7 -/:1<1 V-216 ~D4 /13D 10687775 USIT (PDC) 10919914 USIT 10687666 USIT 10687707 USIT 05/14/04 11/19/04 01/14/04 09/09/04 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COPY EACH TO: BP Exploration (Alaska) Inc. Petrotectnicai Data Center LR2-1 900 E Benson Blvd. Anchorage AK 99508-4254 ¥Js' Date Delivered: . C;?ð 0- CJ(;; 5-- 02/11/05 NO. 3335 Company: Alaska Oil & Gas Cons Comm Attn: Helen Warman 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: Orion Date Color CD BL · STATE OF ALASKA . ALASKA~L AND GAS CONSERVATION COMMISSION WELL COMPLETION OR REcOMPLETION REPORT AND LOG o GINJ 0 WINJ 0 WDSPL 2. Operator Name: BP Exploration (Alaska) Inc. 3. Address: P.O. Box 196612, Anchorage, Alaska 99519-6612 4a. Location of Well (Governmental Section): Surface: 2586' NSL. 3632' WEL, SEC. 34, T12N, R11 E, UM Top of Productive Horizon: 2169' NSL, 918' WEL, SEC. 27, T12N, R11E, UM Total Depth: 9. Plug Back Depth (MD+ TVD) 2906' NSL, 484' WEL, SEC. 27, T12N, R11E, UM 8394 + 4812 Ft 4b. Location of Well (State Base Plane Coordinates): 10. Total Depth (MD+ TVD) 16. Property Designation: Surface: x- 583282 y- 5978309 Zone- ASP4 8490 + 4867 Ft ADL 028239 TPI: x- 585932 y- 5983202 Zone- ASP4 11. Depth where SSSV set 17. Land Use Permit: Total Depth: x- 586357 y- 5983943 Zone- ASP4 (Nipple) 3573' MD t:::., 19. Water depth, if offshore rf~,",fkl1j¡ss of Permafrost 18. Directional Survey 181 Yes 0 No N/A MSL &;;;'\.JCJ I~Approx.) 21. Logs Run: V' C:U MWD / GR, MWD / GR / RES / DEN / NEU / PWD, MDT, US IT . J!l'V 7 22 ~~;~~-=G;:":~¡Z=~.ieß~ 20" x 34" 215.5# A53 SUrfacea~~~M s~~:~eB~~~M i~~~< 260 sx.A.rctië "". """ i~ 9-5/8" 40# L-80 29' 4006' 29' 2686' 12-1/4" 588 sx Arcticset Lite, 379 sx 'G' 7" 26# L-80 26' 8479' 26' 4861' 8-3/4" 379 sx Class 'G' 1a. Well Status: 0 Oil 0 Gas 0 Plugged 0 Abandoned 0 Suspended 181 WAG 20AAC 25.105 20AAC 25.110 No. of Completions One Other 5. Date Comp., Susp., or Aband. 5/17/2004 6. Date Spudded 5/2/2004 7. Date T.D. Reached 5/7/2004 8. KB Elevation (ft): 78.4' 23. Perforations open to Production (MD + TVD of Top and Bottom Interval, Size and Number; if none, state "none"): 4-1/2" Gun Diameter, 5 spf 4-1/2" Gun Diameter, 5 spf MD TVD MD TVD 7465' - 7525' 4295' - 4327' 8080' - 8180' 4634' - 4690' 7690' - 7760' 4418' - 4457' 7805' - 7865' 4481' - 4514' 7890' - 7920' 4528' - 4545' SIZE 4-1/2", 12.6#, L-80 3-1/2",9.2#, L-80 1b. Well Class: 181 Development 0 Exploratory o Stratigraphic Test 0 Service 12. Permit to Drill Number 204-065 13. API Number 50- 029-23206-00-00 14. Well Name and Number: PBU L-216 15. Field / Pool(s): Prudhoe Bay Field / Orion DEPTH SET (MD) 7327' 7327' - 8045' PACKER SET (MD) 7328', 7599', 7782', 7984' DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED Freeze Protect with 105 Bbls of Diesel 26. Date First Production: June 1, 2004 Date of Test Hours Tested PRODUCTION FOR TEST PERIOD .. Flow Tubing Casing Pressure CALCULATED ....... Press. 24-HoUR RATE7 PRODUCTION TEST Method of Operation (Flowing, Gas Lift, etc.): Water Injection OIL-BsL GAs-McF WATER-BsL OIL -BSL GAs-McF W A TER-BsL CHOKE SIZE I GAS-OIL RATIO OIL GRAVITY-API (CORR) 27. CORE DATA 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". None s' ß1}d~~ V~¡5I' I." ~·~t Form 10-407 Revised 12/2003 CONTINUED ON REVERSE SIDE _Bfl JUN 2. Z ~f 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". Ugnu Ugnu MA Ugnu MB 1 Ugnu MB2 Ugnu MC 4430' 6954' 7029' 7192' 7337' 2880' 4037' 4073' 4153' 4227' MDT was ran, log supplied for detail. Schrader Bluff NA Schrader Bluff NB Schrader Bluff NC 7418' 7461' 7534' 4270' 4293' 4332' Schrader Bluff OA Schrader Bluff OBa Schrader Bluff OBb Schrader Bluff OBc Schrader Bluff OBd Schrader Bluff OBe Schrader Bluff OBf Base Schrader Bluff OBf 7691' 7807' 7893' 7989' 8082' 8201' 8274' 8357' 4419' 4483' 4530' 4583' 4635' 4702' 4743' 4791' 30. List of Attachments: Summary of Daily Drilling Reports, Well Schematic Diagram, Surveys 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed Terrie HUbble~~ e. ~tM& Title Technical Assistant PBU L-216 204-065 Well Number Permit NO.1 Approval No. Date 0 ~ ../ Co ·Ot( Prepared By Name/Number: Terrie Hubble, 564-4628 Drilling Engineer: Thomas Schaefer, 564-4685 INSTRUCTIONS GENERAL: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. ITEM 1a: Classification of Service Wells: Gas Injection, Water Injection, Water-Altemating-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 above 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, or Other (explain). ITEM 27: If no cores taken, indicate "None". ITEM 29: List all test information. If none, state "None". Form 10-407 Revised 12/2003 e L-216i MDT Analysis_State_Report.xls e BPX L-216 MDT Results 7467.0 4217.7 Nb 1913.0 7481.0 4225.2 Nb 1915.0 7491.0 4230.6 Nb 1912.0 7492.0 4230.6 Nb 1914.0 Yes 200.0 1 x 450 ml 7715.0 4353.6 OA 1958.0 7715.0 4353.6 OBa 2064.0 Yes 167.0 2 x 450 ml: sample collected 7718.0 4355.0 OA 1957.0 Yes 252.0 1 gallon: sample collected 7734.0 4364.1 OA 1976.0 7823.0 4413.0 OBa 1981.0 7823.0 4413.0 OBb 1980.0 Yes 120.0 1 x 450 ml: sample collected 7847.0 4426.1 OBa 1988.0 7847.0 4426.1 OBa 1992.0 Yes 156.0 1 gallon 7902.0 4456.6 OBb 2000.0 7902.0 4456.6 OBd 2043.0 Yes 194.0 2 x 450 ml: sample collected 7911 .5 4461.9 OBb 2000.0 7993.0 4507.1 OBc 2021.0 8102.0 4568.0 OBd 2043.0 8120.0 4578.0 OBd 2054.0 Note: Oil ravi Page 1 Legal Name L-216 Common Name: L-216 5/6/2004 LOT 3.13 (ppg) ,837 (psi 550 (psi 9.20 (ppg) ft 2,693.0 (ft 4,038.0 e e 11 :03:38 AM Printed: 5/24/2004 Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: L-216 L-216 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 9ES Start: 4/30/2004 Rig Release: 5/17/2004 Rig Number: Spud Date: 4/30/2004 End: 5/15/2004 4/30/2004 22:00 - 00:00 2.00 RIGU P PRE Release rig from L-201 at 22:00 hrs on 4/30/2004. Held PJSM with Rig Crew & Peak. Move Shop & Mud Pits to side of location out of the way. Prepare to move Sub-base off L-201. 5/112004 00:00 - 04:00 4.00 RIGU P PRE PJSM. Move Sub off well L-201 & Spot on Pad. Tool Service shoot grade on Pad. Prep location. Level Pad & cellar area. 04:00 - 06:00 2.00 RIGU P PRE N/U 21-1/4" 2M Diverter on L-216 pre-installed 20" Conductor. Install diverter line & related equipment. ** Accept Rig @ 06:00 Hrs on 5/01/2004 due to extended waiting time while Pad was being leveled & prepped for Rig ** 06:00 - 07:00 1.00 RIGU P PRE Finish N/U Diverter line. 07:00 - 11 :00 4.00 RIGU P PRE Lay Herculite & mats. Move rig's sub-base & spot over L-216, level rig. Spot pit module & cuttings tank. 11 :00 - 15:00 4.00 RIGU P PRE Take on Drill water. Mix spud mud. N/U 21-1/4" Bell-Nipple. 15:00 - 17:00 2.00 RIGU P PRE TIH with one Std of 4" HWDP to clear Ice Plug. POOH & rack back HWDP. Prepare BHA & bring bit, stablizers & subs to Rig Floor. 17:00 - 18:30 1.50 RIGU P PRE P/U 10 Stds of 4" DP + Jars & 3 x 7-1/16" NMDC & rack in derrick. 18:30 - 19:30 1.00 BOPSUF P PRE Function test 21-1/4" Diverter system (18 seconds to close element) & perform accumulator test. *** John Spaulding with the AOGCC wavied witnessing the 21-1/4" Diverter test ***. 19:30 - 21 :00 1.50 RIGU P PRE Slip & cut 98' of drill line. Reset & check C-O-M. service & check brakes. Service TDS. 21 :00 - 23:30 2.50 RIGU P PRE M/U 12-1/4" Tri-Cone Bit on 9-5/8" Mud-motor. M/U MWD & UBHO sub. Orient same. 23:30 - 00:00 0.50 RIGU P PRE SAFETY--- Held Pre-Spud meeting with all rig site personnel. 5/212004 00:00 - 00:30 0.50 RIGU P PRE SAFETY--- Held Pre-Spud meeting with oncoming Drill Crew. 00:30 - 01 :00 0.50 RIGU P PRE PJSM. R/U Sperry-Sun wireline & Gyro-Data equipment. 01 :00 - 01 :30 0.50 DRILL P SURF Fill stack. Circulate mud system checking for leaks-OK. 01 :30 - 02:30 1.00 DRILL P SURF Spud well @ 01 :30 hrs. Clean out 20" conductor pipe T/108'. Drill 12-1/4" hole from 108' to 263'. WOB = 5k RPM = 50 + Mud-motor (Motor factor = 0.2216 rpm/gal) GPM = 565 @ 790 psi Off Btm with 250-350 psi Diff Torque off Btm = 1100 FtLb. Torque on Btm = 2500 FtLb PIU 53k SIO 53k ROT 53k 02:30 - 03:00 0.50 DRILL P SURF POOH one Std & P/U Drilling Jars. 03:00 - 03:30 0.50 DRILL P SURF Run Gyro check shot. 03:30 - 12:30 9.00 DRILL P SURF Drill 12-1/4" directional hole from 263' to 1559'. Slide as required to build angle & azimuth. WOB = 20-35k RPM = 50 + Mud-motor (Motor factor = 0.2216 rpm/gal) Torque off Btm = 2300 FtLb Torque on Btm = 5800 FtLb GPM = 600 @ 1850 psi Off Btm w/250-300 psi Diff. P/U 78k SIO 69k ROT 74k AST = 4.80 Hrs ART = 2.75 Hrs 12:30 - 13:00 0.50 DRILL P SURF Circulate & condition mud prior to taking Gyro Survey. 13:00 - 14:00 1.00 DRILL P SURF Run Gyro survey. Take survey every 100'. POOH with Gyro. RID Gyro equipment. 14:00 - 15:00 1.00 DRILL P SURF Circulate & condition mud prior to POOH. 15:00 - 16:30 1.50 DRILL P SURF POOH with drill string from 1559' to BHA with no problems. Printed: 5/24/2004 1 1 :03:51 AM e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: L-216 L-216 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 9ES Start: 4/30/2004 Rig Release: 5/17/2004 Rig Number: Spud Date: 4/30/2004 End: 5/15/2004 5/212004 16:30 - 17:00 0.50 DRILL P SURF Change bits. Adjust Mud-motor to 1.50 deg bend. 17:00 - 17:30 0.50 DRILL P SURF Clean rig floor. 17:30 - 19:30 2.00 DRILL P SURF TIH with BHA on 4" DP to 1465' with no problems. Hole in good shape. Establish circulation. Precautionary wash to bottom @ 1559'. No fill. 19:30 - 00:00 4.50 DRILL P SURF Drill 12-1/4" directional hole from 1559' to 1998'. Slide as required to build angle & azimuth. WOB = 20-35k RPM = 50 + Mud-motor (Motor factor = 0.2216 rpm/gal) Torque off Btm = 3500 FtLb Torque on Btm = 6500 FtLb GPM = 680 @ 2600 psi Off Btm w/150-250 psi Diff. PIU 85k S/O 67k ROT 74k AST = 2.25 Hrs ART = 0.5 Hrs 5/3/2004 00:00 - 10:30 10.50 DRILL P SURF Drill 12-1/4" directional hole from 1998' to 4018'MD I 2693'TVD (Surface Csg TD). Slide as required to build angle & azimuth. WOB = 30-40 klbs RPM = 80 Torque off Btm = 6.3k FtLb, Torque on Btm = 8-11k FtLb GPM = 599 @ 3250 psi on Btm with 150-250 psi differential pressure PIU 98k S/O 65k ROT 84k On Bottom Drilling Time = 5.91 hrs ART = 3.86 Hrs AST = 2.05 Hrs. Survey & Connection time = 4.59 Hrs 10:30 - 13:00 2.50 DRILL P SURF Circulate & condition mud/hole from 4018' with 590 gpm @ 2800 psi. Circulate hole clean (3 x Btms-up). Reciprocate & rotate (100 rpm) while circulating. 13:00 - 18:30 5.50 DRILL P SURF POOH for wiper trip. Pulled 20 stands up to 1900' with no problems. Hole started pulling tight from 1900' with 20K-30K drag (P/U off btm wI no pump = 121 K). MIU TDS. Pump & pull drill string from 1900' to 1500'. POOH 5 Std without pumping to 1030'. Hole pulling tight. Pump & pull drill string to 850' with 530 gpm @ 1800 psi. POOH with no pump to 650'-OK. 18:30 - 21 :00 2.50 DRILL P SURF TIH with drill string from 650' to 1089'. Tag up. Work string down to 1460'. MIU TDS. Break circulation. Work pipe & circulate 10 minutes with 500 gpm @ 2400 psi. Continue TIH to 2280' with no problems. Tagged up @ 2280'. Work string down to 2776'. MIU TDS. Circulate 10 minutes. TIH to 3431'. Tag up. M/U TDS. Wash down to 3523'. Finish TIH to 3929'. M/U TDS. Precautionary washlream last Std to bottom @ 4018'. 21 :00 - 23:30 2.50 DRILL P SURF Once reaching bottom pumped a 40 bbl Mix II + Super-Sweep pill. Circulate hole clean with 4 x Btms-up. Pump rate = 610 gpm w/ 3200 psi. Reciprocate & rotate (100 rpm) drill string while circulating. NOTE: No significant increase in cuttings observed when the Super-Sweep came across shale shakers. 23:30 - 00:00 0.50 DRILL P SURF POOH to from 4018' to 3549' (5 Std) with no problems. Max drag 10k. 5/4/2004 00:00 - 01 :45 1.75 DRILL P SURF Continue POOH from 3549' to 1437' with no problems. Hole Printed: 5/24/2004 11:03:51 AM e e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: L-216 L-216 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 9ES Start: 4/30/2004 Rig Release: 5/17/2004 Rig Number: Spud Date: 4/30/2004 End: 5/15/2004 5/412004 00:00 - 01 :45 1.75 DRILL P SURF started pulling tight from 1437' with 30-35k drag. 01 :45 - 02:30 0.75 DRILL P SURF MIU TDS. Establish circulation. Pump & pull drill string from 1437' to 1119'. Flow rate = 500 gpm @ 1300 psi. 02:30 - 03:30 1.00 DRILL P SURF Finish POOH to BHA. 03:30 - 05:00 1.50 DRILL P SURF Stand back Jars & NMDC. UD MWD tool, Mud-motor & bit. 05:00 - 05:30 0.50 DRILL P SURF Clean & clear Rig Floor. 05:30 - 07:30 2.00 CASE P SURF Change elevator bails. RIU Franks Fill-up tool. Made dummy run with 9-5/8" Casing Hanger. Finish RIU to run 9-5/8" casing. 07:30 - 08:00 0.50 CASE P SURF SAFETy---- Held PJSM with Rig Crew, MI Mud Engineer & TAM Service Rep on running 9-5/8" casing. 08:00 - 15:00 7.00 CASE P SURF MIU 9-5/8" Shoetrack Joints. Check floats. Ran 96 Jts of 9-5/8" 40 ppf, L-80, BTC Casing to 3969'. PIU Hanger. Establish circulation. Wash down last 37'. Land out on hanger. Shoe @ 4006', Float Collar @3923' , Tam collar @ 1017'. Centralized as per program (27 Bow Spring). M/U Torque = 8000 FtLb. 15:00 - 15:30 0.50 CASE P SURF RID Franks Fill-up tool. Install Dowell Cement Head & circulating lines. 15:30 - 20:30 5.00 CASE P SURF Break circulation. Stage pumps to 350 gpm with 550 psi. Circulate & condition mud to lower vis from 300 slqt to 75 slqt. Reciprocate pipe 10' with circulating. Held PJSM regarding cement operations with all personnel while circulating. PIU Wt 190k S/O Wt 84k 20:30 - 23:30 3.00 CEMT P SURF Line up to cement. Dowell pump 5 bbl water & test cement lines to 3500 psi. Cement 9 5/8" csg as follows:. Pump 75 bbl of 10 ppg Mud-push II spacer. Drop Btm plug. Mix & pump 466 bbl (590 sks) of 10.7 ppg ASL III lead slurry + 79 bbl (390 sks) of 15.8 ppg Class G tail slurry. Release Top plug. Dowell pump 10 bbl of water. Switch over to Rig pump & displace cement with 288 bbl of 9.5 ppg mud @ 8.5 bpm with 650 psi. Bump plug on schedule with 1500 psi. Cement in place @ 23:22 hrs. Release pressure. Floats held. Full returns throughout the entire job. Got back 144 bbl of cement returns to surface. NOTE: Landed casing on hanger after pumping 405 bbl of lead slurry. Hole was getting sticky. 23:30 - 00:00 0.50 CEMT P SURF Flush through all surface lines & equipment. 5/5/2004 00:00 - 01 :00 1.00 CEMT P SURF Flush Flow-line & Bell-nipple. RID Cement Head. 01 :00 - 02:00 1.00 CEMT P SURF Function Knife valve on Diverter. Clean out same. UD 9-5/8" Landing Joint. Clean out Rotary Table Drip Pan. 02:00 - 02:15 0.25 BOPSUF P SURF SAFETy---- Held PJSM with Drill Crew on Nippling down Diverter. 02: 15 - 04:00 1.75 BOPSUF P SURF N/D 21-1/4" Diverter & related equipment. 04:00 - 05:00 1.00 WHSUR P SURF Move casing head and tubing spool into cellar. 05:00 - 06:00 1.00 WHSUR P SURF Install FMC "GEN-5" 11" 5M Unihead system and test to 1000 psi. 06:00 - 08:00 2.00 BOPSUP P SURF NIU 13-5/8" 5M BOP, Bell-nipple & related equipment. 08:00 - 14:00 6.00 BOPSUP P SURF Held PJSM. RIH with BOP Test Plug on 4" DP & seat in wellhead. Rig Up Testing Equipment - Test BOP & Surface related equipment: Upper And Lower VBR, Blind/Shear Rams, Manual & HeR Valves on CIK Lines, Choke Manifold, TIW Valve, DSIBOP Valve, TDS Upper & Lower IBOP Valves to 250/4000 Psi. Test Hydril Annular BOP to 250/3500 psi. RID Printed: 5/24/2004 11 :03:51 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: L-216 L-216 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 9ES Start: 4/30/2004 Rig Release: 5/17/2004 Rig Number: Spud Date: 4/30/2004 End: 5/15/2004 5/512004 08:00 - 14:00 6.00 BOPSUP P SURF Test Equipment. Pull test plug. Install wear bushing. Blow down surface lines. Witness of BOP Test Waived By AOGCC Inspector Jeff Jones 14:00 - 14:30 0.50 DRILL P PROD1 SAFETY m Held PJSM with Rig Crew on picking up drill pipe. 14:30 - 17:30 3.00 DRILL P PROD1 P/U 54 Joints of 4" HT-40 DP & rack in derrick. 17:30 - 18:00 0.50 DRILL P PROD1 SAFETYm Held PJSM with Rig Crew & Anadrill personnel regarding picking up BHA tools & installing RA Source. 18:00 - 20:30 2.50 DRILL P PROD1 M/U 8-3/4" Steerable Drilling assembly with MWD/PWD. Shallow test MWD-OK. 20:30 - 00:00 3.50 DRILL P PROD1 TIH with 8-3/4" BHA to 3745'. P/U 84 Joints of 4" DP. Break circulation. 5/6/2004 00:00 - 01 :00 1.00 DRILL P PROD1 Bit depth = 3745'. Pressure test 9-5/8" casing to 3500 psi. Hold for 30 minutes. Test was API. Bleed off pressure. Blow down surface lines. 01 :00 - 01 :30 0.50 DRILL P PROD1 Service TDS. 01 :30 - 04:15 2.75 DRILL P PROD1 Precautionary wash down from 3739' to 3919'. Tag-up on cement. Drill out cement to the top of 9-5/8" Float Collar @ 3923'. Drill out 9-5/8" Shoe Track (Hard Cement) from 3923' to 4006' (9-5/8" Casing Shoe @ 4006'). Clean out 12-1/4" Rat Hole to 4018' and drill 20' of new formation to 4038'. WOB 10-18k RPM 50 + Mud-motor (Mud-motor factor = 0.500 Rev/Gal) Torque on Btm = 6.5k GPM 525 with 2125 psi P/U 102k SIO 68k Rot Wt 84k 04:15 - 05:00 0.75 DRILL P PROD1 Displace hole from 4038' with 9.2 ppg WBM. Pump rate 580 gpm with 1625 psi. Reciprocate & rotate (75 RPM) while displacing. 05:00 - 05:30 0.50 DRILL P PROD1 Perform LOT from 2693' TVD. Pressure up on formation with 9.2 ppg mud to Leak-off @ 830 psi. EMW = 13.1 PPG. 05:30 - 06:00 0.50 DRILL P PROD1 Circulate to establish baseline ECDs. Take SPA. ECD with DP Stationary @ 575 gpm = 10.23 ppg ECD with 100 RPM @ 575 gpm = 10.33 ppg 06:00 - 07:30 1.50 DRILL P PROD1 Drill 8-3/4" directional hole from 4038' to 4436'. Sliding as required to maintain inclination and azimuth. WOB = 10-15 klbs RPM = 100-110 Torque off Btm = 5.5k FtLb, Torque on Btm = 8.0k FtLb GPM = 600 @ 2140 psi on Btm with 300-375 psi differential pressure P/U 105k S/O 76k Rot Wt 86k Backream every stand at 600 gpm and 110 rpm, reducing flow rate to 450 gpm on down stroke. Calculated ECD = 10.34 ppg Actual ECD = 10.75 ppg 07:30 - 09:00 1.50 DRILL N SFAL PROD1 Circulate & condition mud at a reduced rate due to Heavy oil on drill cuttings which were blinding off the shale shakers. 09:00 - 10:30 1.50 DRILL P PROD1 Continue drilling 8-3/4" directional hole from 4436' to 4647', using the same drilling parameters as above. 10:30 - 12:00 1.50 DRILL N SFAL PROD1 Circulate & condition mud at a reduced rate due to Heavy oil on drill cuttings which were blinding off the shale shakers. Change Printed: 5/24/2004 11 :03:51 AM e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: L-216 L-216 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 9ES Start: 4/30/2004 Rig Release: 5/17/2004 Rig Number: Spud Date: 4/30/2004 End: 5/15/2004 5/6/2004 10:30 - 12:00 12:00 - 17:30 1.50 DRILL N 5.50 DRILL P SFAL PROD1 PROD1 17:30 - 18:00 0.50 DRILL P PROD1 18:00 - 00:00 6.00 DRILL P PROD1 out shaker screens. Drill 8-3/4" directional hole from 4647' to 5984'. Sliding as required to maintain inclination and azimuth. WOS = 10-15 klbs RPM = 100-110 Torque off Stm = 8.5k FtLb, Torque on Btm = 9-11k FtLb GPM = 590 @ 2700 psi on Stm with 250-300 psi differential pressure P/U 115k S/O 76k Rot Wt 92k Sackream every stand at 590 gpm and 110 rpm, reducing flow rate to 450 gpm on down stroke. Calculated ECD = 10.17 ppg Actual ECD = 10.98 ppg Circulate to reduce ECD. Reciprocate & rotate (100 rpm) drill string while circulating with 580 gpm @ 2350 psi. ECD after Circulating = 10.26 ppg Drill 8-3/4" directional hole from 5984' to 6733'. Sliding as required to maintain inclination and azimuth. WOS = 10-15 klbs RPM = 100-110 Torque off Stm = 8.5k FtLb, Torque on Stm = 9-11 k FtLb GPM = 590 @ 2800 psi on Stm with 200-250 psi differential pressure P/U 143k SIO 80k Rot Wt 100k Sackream every stand at 590 gpm and 110 rpm, reducing flow rate to 450 gpm on down stroke. Calculated ECD = 10.13 ppg Actual ECD = 10.81 ppg 5/7/2004 00:00 - 00:45 0.75 DRILL P PROD1 Drill 8-3/4" directional hole from 6733' to 7013'. Sliding as required to maintain inclination and azimuth. WOS = 10-15 klbs RPM = 100-110 Torque off Stm = 9k FtLb, Torque on Stm = 10-12k FtLb GPM = 590 @ 2900 psi on Stm with 200-300 psi differential pressure P/U 142k S/O 80k Rot Wt 102k Sackream every stand at 590 gpm and 110 rpm, reducing flow rate to 450 gpm on down stroke. Calculated ECD = 10.13 ppg Actual ECD = 10.82 ppg 00:45 - 01 :15 0.50 DRILL P PROD1 Pump sweep. Circulate to reduce ECD. Reciprocate & rotate (100 rpm) drill string wihile circulating with 590 gpm @ 2600 psi. Had a significant increase in drill cuttings when sweep reached surface. ECD after Circulating = 10.6 ppg 01:15 - 06:15 5.00 DRILL P PROD1 Continue drilling 8-3/4" hole from 7013' to 7663'. Sliding as required to maintain inclination and azimuth. Printed: 5/24/2004 11 :03:51 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: L-216 L-216 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 9ES Start: 4/30/2004 Rig Release: 5/17/2004 Rig Number: Spud Date: 4/30/2004 End: 5/15/2004 5/7/2004 01:15 - 06:15 5.00 DRILL P PROD1 WOB = 10-15 klbs RPM = 100-110 Torque off Btm = 9k FtLb, Torque on Btm = 11-12k FtLb GPM = 590 @ 3150 psi on Btm with 200-300 psi differential pressure P/U 168k S/O 82k Rot Wt 1 06k Backream every stand at 590 gpm and 110 rpm, reducing flow rate to 450 gpm on down stroke. Calculated ECD = 10.01 ppg Actual ECD = 10.70 ppg 06:15 - 15:00 8.75 DRILL P PROD1 Drill ahead from 7663' maintaining ECD within prescribed limits of 0.6 ppg over calc - max allowable. Circ for ECD management as needed. Drill ahead to TD at 8490' MD I 4866' TVD. Calculated ECD @ TD = 10.25 ppg Actual ECD = 10.92 ppg On Bottom Drilling Time = 5.87 Hrs ART = 4.13 Hrs AST = 1.74 Hrs. Survey & Connection time = 5.38 Hrs Circulate for ECD = 3.5 Hrs 15:00 - 18:00 3.00 DRILL P PROD1 Pump a 40 bbl Hi-Vis sweep. Circulate hole clean from 8490' with 590 gpm @ 3240 psi + 120 rpm. Reciprocate drill string while circulating. 18:00 - 18:30 0.50 DRILL P PROD1 Flow check. Well static. POOH to 8228'. Hole pulling tight & swabbing. Max overpull 35k. TIH to 8413'. 18:30 - 20:15 1.75 DRILL P PROD1 M/U TDS. Establish circulation. Backream from 8413' to 8039'. RPM 110 Torque 10-14k FtLb & Spiking at 16k GPM 565 with 3240 psi 20:15 - 20:30 0.25 DRILL P PROD1 POOH to 7945'. Hole pulling tight & swabbing. TIH to 8039'. 20:30 - 22:00 1.50 DRILL P PROD1 M/U TDS. Continue backreaming from 8039' to 7853'. ECD exceeding 0.8 ppg over calculated ECD of 10.25 ppg. 22:00 - 23:00 1.00 DRILL P PROD1 Pump a Lo vis-high weighted sweep. Circulate sweep surface to surface. Reciprocate & rotate (100 RPM) Drill String from 7853' to 7945' while circulating. Minimal increase in cutting observed. Calculated ECD = 10.25 ppg Actual ECD = 10.56 ppg 23:00 - 00:00 1.00 DRILL P PROD1 Continue backreaming from 7835' to 7664'. 5/8/2004 00:00 - 00:30 0.50 DRILL P PROD1 Continue backreaming out of hole from 7664' to 7477'. RPM 110-120 Torque 10-14k FtLb GPM 565 with 3050 psi 00:30 - 02:30 2.00 DRILL P PROD1 POH from 7477' to 4897' with no problems. At 4897' hole swabbing with increased drag. RIH to 4947'. 02:30 - 07:00 4.50 DRILL P PROD1 M/U TDS. Backream out of hole from 4947' to surface casing shoe. Note: Hole trying to pack-off at the start of backreaming from 4947'. Lost +/- 65 bbl mud throughout backreaming. Try to pull too fast and the torque will rapidly increase & formation will start taking mud. Backream very slow to avoid packing off and minimise fluid being pumped away. RPM 110-120 Printed: 5/24/2004 11:03:51 AM legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: l-216 l-216 DRlll+COMPlETE NABORS ALASKA DRilLING I NABORS 9ES Start: 4/30/2004 Rig Release: 5/17/2004 Rig Number: Spud Date: 4/30/2004 End: 5/15/2004 5/8/2004 02:30 - 07:00 4.50 DRILL P PROD1 Torque 7-11k FtLb Spiking to 16k GPM 432 to 565 with 1445-2250 psi. 07:00 - 07:30 0.50 DRILL P PROD1 CBU X 1.5 at shoe to clean casing. Calc ECD 10.1 vs Act 10.2 ppg. 07:30 - 08:00 0.50 DRILL P PROD1 Service top drive & crown sheaves. Continue to bleed back mud from hole breathing. 08:00 - 09:00 1.00 DRILL P PROD1 Slip & cut drilling line - 63'. Have got back +1- 25 bbls mud from breathing hole so far. 09:00 - 11 :00 2.00 DRILL P PROD1 RIH to 8415' wlo problems. Precautionary wash last stand to btm at 8490'. 11 :00 - 14:00 3.00 DRILL P PROD1 Circ and cond hole for logs. Stage up to full rate at 580 gpm. Circ hi vis sweep surface to surface - no increase in cuttings. Follow with 2 additional BU precautionary eirc. Final ECD within 0.1 ppg of calculated. 14:00 - 14:30 0.50 DRILL P PROD1 Flow check prior to POOH. Slight initial flow with what appears to be hydrates breaking out at bell nipple - diminished considerably within 20 min. 14:30 - 17:30 3.00 DRILL P PROD1 Pull 5 stands - OK. 10-15 klbs overpull. Pump dry job. Continue POOH to 9-5/8" casing shoe. Hole in good condition and taking correct fill. Max over-pull 10k. 17:30 - 18:00 0.50 DRILL P PROD1 Flow check. Well static. 18:00 - 21 :00 3.00 DRILL P PROD1 POOH from 4006' to top of BHA. 21 :00 - 21 :15 0.25 DRILL P PROD1 SAFETY--- Held PJSM with Rig Crew & Anadrill personnel regarding removing RA Source & UD BHA. 21:15 - 23:30 2.25 DRILL P PROD1 Stand back 4" HWDP & Jars. UD 8-3/4" Directional BHA. 23:30 - 00:00 0.50 DRILL P PROD1 Remove excess drilling equipment & clean rig floor. 5/9/2004 00:00 - 00:30 0.50 EVAL P PROD1 SAFETY--- Held PJSM with Rig Crew & Schlumberger E-Line crew on rigging up & running procedures for DPC Logging. 00:30 - 02:00 1.50 EVAL P PROD1 P/U MDT Logging tools. R/U Schlumberger E-line, sheaves & related equipment. Perform surface checks on all logging tools & equipment. 02:00 - 07:30 5.50 EV AL P PROD1 MIU MDT-GR-RES-ROP Logging tools onto the bottom of 4" DP. TIH with DPC Logging tools to 6900'. Break circulation every 2000' in cased hole & every 1000' in open hole. 07:30 - 10:00 2.50 EV AL P PROD1 Install Schlumberger SDES in the 4" drill pipe. RIH with e-line + PDWC inside the 4" drill pipe. Pump down at 4 bpm with 376 psi. Latch up to DHWC sub on MDT tool. Clamp & secure e-line. Test MDT tool-OK. 10:00 - 00:00 14.00 EVAL P PROD1 Start logging operations with DPC MDT-GR logging down from 6901' taking formation pressure readings (14) starting @ 7473' to 8120'. No hole problems encountered while logging down to 8120', but the MDT Tool became stuck while attempting to take the 1st fluid sample @ 8105'. Deflated packers & worked free. Reset & repeat fluid sample from 8104'. BHP at 8104' MD/4647'TVD = 2043 PSI. BHST = 96 deg 5/10/2004 00:00 - 22:30 22.50 EV AL P PROD1 Continue DPC Logging operations using MDT-GR Tool. Finish taking fluid sample @ 8104'. Pull up to next Fluid sample point. Take fluid samples @ 7902',7823',7717',7491' & 7846'. NOTE: Hole taking fluid @ 0.5 bph while logging. 18 bbl total losses. 22:30 - 23:00 0.50 EVAL P PROD1 After taking final fluid sample @ 7846' the MDT Tool was stuck. Deflated packers & worked free. 23:00 - 00:00 1.00 EVAL P PROD1 POOH slowly with 4" DP & MDT Logging Tool from 7846' to Printed: 5/24/2004 11 :03:51 AM e e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: L-216 L-216 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 9ES Start: 4/30/2004 Rig Release: 5/17/2004 Rig Number: Spud Date: 4/30/2004 End: 5/15/2004 5/1 0/2004 23:00 - 00:00 1.00 EVAL P PROD1 7180' with no problems. PIU 183k. 5/11/2004 00:00 - 00:30 0.50 EVAL P PROD1 POOH slowly with 4" DP & MDT Logging Tool from 7180' to the SDES @ 6900' with no problems. NOTE: Hole taking fluid @ 0.5 bph while logging. 00:30 - 01 :30 1.00 EVAL P PROD1 Schlumberger POOH with e-line & DHWC. RID e-line, sheaves & related equipment. 01 :30 - 02:00 0.50 EVAL P PROD1 Pump slug. Blow down TDS. 02:00 - 04:45 2.75 EVAL P PROD1 POOH from 6900' with 4" DP & MDT Logging tool with no problems in open hole. Logging tool at surface @ 04:45 hrs. 04:45 - 06:30 1.75 EVAL P PROD1 UD Schlumberger MDT Logging tools. 06:30 - 07:00 0.50 EVAL P PROD1 Clear and clean rig floor 07:00 - 07:30 0.50 EVAL P PROD1 Make up hole opener and near-bit stabilizer, jars 07:30 - 10:00 2.50 EVAL P PROD1 Trip in to 2000 ft, break circulation and stage pumps to 300 gpm, 350 psi, continue to shoe at 4006 ft 10:00 - 10:30 0.50 EVAL P PROD1 Circulate bottoms up at casing shoe, 400 gpm, 840 psi, 105K UP, 65K DN 10:30 - 12:00 1.50 EVAL P PROD1 Trip in to 6000 ft, break circulation, stage pumps to 400 gpm, 1210 psi, 140K UP, 66K DN 12:00 - 13:30 1.50 EVAL P PROD1 Trip in to 8310 ft 13:30 - 16:30 3.00 EV AL P PROD1 Make up Top Drive, fill pipe, stage pumps up to 590 gpm, 2940 psi, 120 rpm, 110K RT WT, 11-12.5K TO, 450 gpm on downstroke, pump bottoms up, circulate hi-vis sweep, pump bottoms up, spot 10 ppb G-Seal across open hole, 183K UP, 76K DN with pumps 16:30 - 20:00 3.50 EV AL P PROD1 Monitor wellbore, pump dry job, POOH, 188K UP, 80K DN, pull15K - 25K over from 8320 to 8190 ft, work pipe, POOH to shoe, well bore in good condition, hole fill displacement correct 20:00 - 21 :00 1.00 EVAL P PROD1 Stand back HWDP, lay down BHA 21 :00 - 21 :30 0.50 EV AL P PROD1 Clear and clean rig floor 21 :30 - 22:00 0.50 CASE P PROD1 Pull wear bushing, make dummy run with 7" landing jt and hanger 22:00 - 23:00 1.00 CASE P PROD1 Install test plug and change out upper pipe rams to 7" 23:00 - 00:00 1.00 CASE P PROD1 Change out to long bails, make up Franks tool 5/12/2004 00:00 - 00:45 0.75 CASE P COMP RU casing tongs, slips elevators for 7" casing. 00:45 - 01 :00 0.25 CASE P COMP PJSM for running casing - BPX, Nabors rig crew, NA Casing. 01:00 -11:30 10.50 CASE P COMP MU shoe track & check floats - OK. Run 7" casing. Hole started taking fluid on first 10 its run. Slow running speed to 4 ftImin and still only getting back approx 1/2 casing displacement (2 bbl/10 jts vs 4 bbl calc). Circ at -2000' (50 jts in) with no loss/no gain - pipe stationary. Continue running casing slowly (4-5 fpm) with returns diminishing from 2 bbll10 jts to zero by 60 jts away to an overall loss of 4 bbls per 10 jts run by it #90. Cont RIH to it #96 - 9 5/8" shoe. 11 :30 - 13:00 1.50 CASE P COMP Circ at shoe - initial rate 4 bpm. 1 minute loss of 2 bbls. 10 min loss of 7.5 bbls (loss rate diminishing with time) and reciprocating pipe at 4 fpm. Increase rate to 6 bpm. 1 min loss of 1 bbl. 10 min loss of 2.5 bbls. 20 min loss of 3 bbls. Reciprocate pipe at 4 fpm. 13:00 - 15:00 2.00 CASE P COMP Continue running casing in to open hole. Increase run speed to 10 fpm. Run 10 jts with no real increase in losses when running in. 15:00 - 18:00 3.00 CASE P COMP Increase running speed to 20 fpm (2 min/jt) again with no appreciable change to losses when running. At 140 jts in hole, Printed: 5/24/2004 11 :03:51 AM e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: L-216 L-216 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 9ES Start: 4/30/2004 Rig Release: 5/17/2004 Rig Number: Spud Date: 4/30/2004 End: 5/15/2004 5/12/2004 15:00 - 18:00 3.00 CASE P COMP have lost pipe displacement + 70 bbls (-120 bbls total). Continue running at 2 minljt. 18:00 - 19:00 1.00 CASE P COMP Circulate bottoms up from 590 to 6200 ft, 4 bpm 280 psi, 5 bpm 347 psi, 6 bpm 440 psi, 166K up, 83K DN 19:00 - 00:00 5.00 CASE P COMP Continue running speed at 2 min/jt to 6605 It, 5 bpm 400 psi 2 min/jt to 7015 It, 5 bpm 420 psi, 190K UP, 85K DN 2 min/jt to 7428 It, 5 bpm 460 psi, 197K UP, 86K DN 2 min/jt to 7839 It, 5 bpm 480 psi, 205K UP, 90K DN 2 min/jt to 8451 It, 5 bpm 500 psi, 220K UP, 95K DN Mud losses for entire casing job = 142 bbls. Make up 7" landing jt, ran total of 205 jts, wI float shoe, float collar, total length 8451 .40 It, shoe at 8479'. 5/13/2004 00:00 - 00:30 0.50 CASE P COMP Rig down Franks tool, rig up cement head, Co man witnessed the loading of plugs 00:30 - 01 :30 1.00 CASE P COMP Circulate casing, stage pumps up to 6 bpm at 500 psi, 220K UP, 95K DN, circulate 3 bottoms up, well bore took an inital 20 bbls while circulating then stabilised at approx 1 bpm loss. 01 :30 - 02:30 1.00 CASE P COMP PJSM with rig crew and cementers, continue to circulate 02:30 - 04:30 2.00 CEMT P COMP Flush mud pumps, pump 5 bbls CW100, PT lines to 4500 psi, pump 10 bbls CW100, pump 30 bbls mud push at 10.3 ppg, drop bottom plug, pump 81 bbls (370 sx) class "G" at 15.8 ppg, displace with warm seawater, 115 degrees F, bump plug 1000 psi over to 1900 psi, plug down at 04:30 hrs. Losses throughout cement job = 146 bbls. Chart shows cement rise in annulus during displacement. Reciprocate pipe throughout cementing and displacement. 04:30 - 05:00 0.50 CEMT P COMP Pressure test casing to 4000 psi for 30 minutes, charted. Lost 175 psi in 30 min - test acceptable. 05:00 - 07:00 2.00 CEMT P COMP Rig down cement head, lay down landing joint, rig down casing equipment 07:00 - 08:00 1.00 CEMT P COMP Run packoff, RILDS, pressure test to 5000 psi 08:00 - 08:30 0.50 CEMT P COMP Clean out under rotary table. 08:30 - 09:00 0.50 CEMT P COMP Rig service, top drive, crown 09:00 - 09:30 0.50 CEMT P COMP Pick up, make up BHA, bit, casing scraper, bit sub, XIO 09:30 - 11 :00 1.50 CEMT P COMP Trip in to 3000', fill pipe 11 :00 - 13:30 2.50 CEMT P COMP Trip in to 8337', 13:30 - 14:00 0.50 CEMT P COMP Break circulation, wash at 4 bpm from 8337 to 8393', tag float collar on depth. 182K UP, 79K DN 14:00 - 15:00 1.00 CEMT P COMP Displace casing from sea water to brine at 9.3 ppg, 490 gpm, 2150 psi, 40 rpm, 10K TO UP, 8K TO DN, 165K UP 67K DN with pumps 15:00 - 17:30 2.50 CEMT P COMP Trip out to 3000'. While tripping, inject 60 bbl mud down OA at 1-3 bpm to ensure clear. 17:30 - 18:30 1.00 CEMT P COMP Slip and cut 91' drilling line, inspect drawworks, inspect brakes and linkage 18:30 - 20:00 1.50 CEMT P COMP Trip out, lay down BHA 20:00 - 20:30 0.50 EV AL P COMP Clear and clean rig floor, install 7" lubricator, shut in w/7" pipe rams and annular preventer 20:30 - 23:30 3.00 EVAL P COMP PJSM, rig up Schlumberger pump in sub, double stack, and single stack BOPs, E-line, USIT logging tools, packoff 23:30 - 00:00 0.50 EVAL P COMP Run USIT log on E-line 5/14/2004 00:00 - 04:00 4.00 EVAL P COMP Run US IT log, log on bottom at 01 :00 hrs, log up, top of cement at 6170 It. POH & lay down USIT logging tools. Printed: 5/24/2004 11 :03:51 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: L-216 L-216 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 9ES Start: 4/30/2004 Rig Release: 5/17/2004 Rig Number: Spud Date: 4/30/2004 End: 5/15/2004 5/14/2004 04:00 - 04:45 0.75 EVAL P COMP Forward USIT logs to Anchorage engineers for evaluation while re-heading line to make first perf gun run. 04:45 - 06:30 1.75 EVAL P COMP PJSM. RU firing head, MU gun # 1 06:30 - 07:00 0.50 EVAL P COMP Pressure test 7" lubricator, BOPs, surface equipment to 1000 psi, packoff failed, change out packoff, pressure test to 1000 psi,OK 07:00 - 10:00 3.00 EVAL P COMP RIH with gun #1, 4.5"HMX power-jet guns loaded at 5 spf, set guns on depth, fire, from 7890 to 7920 ft, POOH wI guns, no loss to perforations, 100 % fired 10:00 - 11 :00 1.00 EVAL P COMP Lay down spent guns, rearm firing head 11 :00 - 13:00 2.00 EVAL P COMP RIH with gun # 2, 4.5"HMX power-jet guns loaded at 5 spf, set guns on depth, fire, from 7835 to 7865 ft, POOH wI guns, no loss to perforations, 100 % fired 13:00 - 13:30 0.50 EVAL P COMP Lay down spent guns, rearm firing head, change out shooting bridle 13:30 - 15:30 2.00 EVAL P COMP RIH with gun # 3, 4.5"HMX power-jet guns loaded at 5 spf, set guns on depth, fire, from 7835 to 7805 ft, POOH wI guns, loss of 3 bbls to perforations, 100 % fired 15:30 - 16:00 0.50 EVAL P COMP Lay down spent guns, rearm firing head 16:00 - 18:00 2.00 EVAL P COMP RIH with gun # 4, 4.5"HMX power-jet guns loaded at 5 spf, set guns on depth, fire, from 7760 to 7720 ft, POOH wI guns, loss of 2 bbls to perforations, 100 % fired 18:00 - 18:30 0.50 EVAL P COMP Lay down spent guns, rebuild and rearm firing head, 18:30 - 20:00 1.50 EVAL P COMP RIH with gun # 5, 4.5"HMX power-jet guns loaded at 5 spf, set guns on depth, fire, from 7720 to 7690 ft, POOH wI guns, loss of 3 bbls to perforations, 100 % fired 20:00 - 20:30 0.50 EVAL P COMP Lay down spent guns, rearm firing head 20:30 - 22:00 1.50 EVAL P COMP RIH with gun # 6, 4.5"HMX power-jet guns loaded at 5 spf, set guns on depth, fire, from 7525 to 7495 ft, POOH wI guns, loss of 2 bbls to perforations, 100 % fired 22:00 - 22:30 0.50 EVAL P COMP Lay down spent guns, rebuild and rearm firing head 22:30 - 00:00 1.50 EVAL P COMP RIH with gun # 7, 4.5"HMX power-jet guns loaded at 5 spf, set guns on depth, fire, from 7495 to 7465 ft, POOH w/ guns, loss of 2 bbls to perforations, 100 % fired 5/15/2004 00:00 - 03:00 3.00 EV AL P COMP PJSM, lay down spent guns, lay down wireline equipment, sheaves, BOPs, pump sub, 7" lubricator 03:00 - 05:00 2.00 CLEAN P COMP PJSM, Change out upper pipe rams from 7" to 3 1/2" x 6" VBR's. Pressure test to 4000 psi. 05:00 - 05:30 0.50 CLEAN P COMP Rig service, service top drive 05:30 - 08:30 3.00 CLEAN P COMP PJSM, make up BHA, bit, junk subs, scraper, Des, jars, HWDP 08:30 - 14:30 6.00 CLEAN P COMP RIH slow due to open perfs, break circulation at 2500 ft, fill pipe every 3000 ft, tag up at 8393 ft, 175K UP, 80K DN 14:30 - 15:30 1.00 CLEAN P COMP Make up top drive, stage pumps to 490 gpm, 2636 psi, 30 rpm, 9000 TO, pump hi vis sweep, after 1600 strokes, low level H2S alarm went off, in process of monitoring returns, high level H2S alarm went off at 20 PPM, well shut in, notified TP / CO Rep, open well up to choke, circulate through choke at 1 bpm, monitor returns 0 PPM H2S & 5% LEL, appears to be sulfur by-products from detonation of shots from perf guns, open well up and monitor returns, OK. Checking throughout with hand held monitor in addition to rig sensors. 15:30 - 16:30 1.00 CLEAN P COMP Continue to pump sweep S/S, 490 gpm, 2520 psi, after sweep to surface circulate bottoms up at same rate, 30 rpm, 9000 Printed: 5/24/2004 11 :03:51 AM e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: L-216 L-216 DRILL+COMPLETE NABORS ALASKA DRILLING I NABORS 9ES Start: 4/30/2004 Rig Release: 5/17/2004 Rig Number: Spud Date: 4/30/2004 End: 5/15/2004 5/15/2004 15:30 - 16:30 1.00 CLEAN P COMP TO, 165K UP, 70K DN, 100K RT, 16:30 - 17:00 0.50 CLEAN P COMP Momitor well, pump dry job 17:00 - 22:00 5.00 CLEAN P COMP POOH, LDDP 22:00 - 23:00 1.00 CLEAN P COMP Lay down HWDP and BHA 23:00 - 23:30 0.50 CLEAN P COMP Clean out junk baskets, very small amount of metal debris recovered 23:30 - 00:00 0.50 CLEAN P COMP Pull wear bushing 5/16/2004 00:00 - 00:30 0.50 RUNCOtvP COMP Make up 4.5" tubing hanger dummy run 00:30 - 03:30 3.00 RUNCOMP COMP Rig up floor to run completion string, run 4.5" power jet perf guns. 03:30 - 04:30 1.00 RUNCOMP COMP PJSM. Run10 jts 3.3" 9.2# L-BO TC-II tubing, dope wI jet lube seal guard, TO to 2300 ftllbs, run jewelry as per program 04:30 - 05:30 1.00 RUNCOMP COMP Rig down 3.5" tubing equipment and rig up 4.5" tubing equipment 05:30 - 18:30 13.00 RUNCOMP COMP Run 4.5" 12.6# L-80, TC-II, dope same, TO to 3850 ftllbs, run jewelry as per program, land tubing, 120K UP, 70K DN Inject dead crude in lower annulus 7" x 9 5/8", test lines to 3500 psi, bullhead 85 bbls at 3 bpm, 500 psi 18:30 - 19:30 1.00 RUNCmtP COMP Rig down tubing equipment, rig up DP elevators and lubricator for SWS 19:30 - 20:30 1.00 RUNCOMP COMP PJSM with SWS and rig crew, rig up wireline 20:30 - 21 :30 1.00 RUNCOMP COMP RIH with Gamma ray I CCL 21 :30 - 22:00 0.50 RUNCOMP COMP Logging up wI Gamma ray I CCL RA pip logged at 7753 ft, tally 7756 ft, no space out required 22:00 - 22:30 0.50 RUNCOMP COMP Rig down SWS 22:30 - 23:00 0.50 RUNCOMP COMP Rig down tubing equipment, RILDS with FMC to 450 ft Ibs 23:00 - 00:00 1.00 RUNCOMP COMP Reverse circulate 22 bbls clean 9.3 ppg brine in tubing annulus, chase with 135 bbls corrosion inhibited 9.3 brine 5/17/2004 00:00 - 03:00 3.00 RUNCOtvP COMP Drop 1 5/16" ball I rod assembly to seat in RHC plug, rig down landing jt, close blind rams, pressure tubing to 2800 psi, continue to pressure to 4200 psi, hold for 30 minutes on chart, bleed tubing to 1500 psi, pressure annulus to 4000 psi, tubing rose to 2400 psi, hold for 30 minutes, charted, bleed annulus then tubing to zero 03:00 - 03:30 0.50 RUNCOtvP COMP Pressure annulus to 2500 psi, DCK valve sheared, 2 bpm pump rate 03:30 - 04:00 0.50 RUNCOMP COMP Install TWC with T bar, pressure test to 2800 psi from below 04:00 - 09:00 5.00 BOPSUP P COMP Nipple down BOPs, NU tree, test tubibg hanger adapter to 5000 psi, tree to 5000 psi 09:00 - 11 :00 2.00 WHSUR P COMP Pull TWC w/lubricator, rig up U-Tube and return line, rig in Hot Oil, PJSM, test line to 3500 psi, pump 105 bbls diesel down 7" x 4.4" tubing annulus, pump at 3 bpm at 1400 psi, end at 1650 psi 11 :00 - 12:00 1.00 WHSUR P COMP Allow U-Tube, install BPV with DSM, test to 1000 psi from below, install VR plugs in annulus valves, secure tree Rig released at 12:00 hrs from L-216i Printed: 5/24/2004 11 :03:51 AM e e L-216i Prudhoe Bay Unit 50-029-23206-00-00 204-065 Accept: Spud: Release: 05/01/04 05/02/04 05/17/04 Nabors 9ES POST RIG WORK 06/10/04 PULLED ROLLER STEM/BALL AND ROD ASSEMBLY FROM 7,972' SLM. PULLED 1" DCK SHEAR VLV, STA #7 @ 7183' SLM. 06/11/04 SET 1" DGLV IN STA #7 @ 7186' SLM. P.T TUBING TO 2000 PSI. HELD @ 2000 PSI FOR 30 MIN. (T/IA/OA = 2000/0/200). PULLED 3 1/2" RHC BODY @ 7972' SLM. RAN SIMULATED SLB/ HDF TOOL WITH LIB ASSEMBLY ON BOTTOM. RAN SLB/HDF FIRING MECHANISM SET IN FIRING HEAD @ 8,016' SLM. TOOK 3 HOURS FOR GUNS TO FIRE, GOOD INDICATION AT SURFACE. PERFORMED AN INJECTIVITY TEST W/ APPROX. 8 BBLS DIESEL. SET 31/2" RHC PLUG BODY @ 7,988' SLM FOR CATCHER SUB. PULLED 1 1/2" DGL V FROM ST A #2 @ 7822' SLM. 06/12/04 PULLED 1 1/2" DGLV FROM STA #1. RIH W/2.60" BELL GUIDE W/1 5/8" JDS. PULLED 1 1/2" DGLV FROM CATCHER. SET 1 1/2" FLOW THRU VALVES IN STA'S #1 & #2. PULLED RHC PLUG BODY. RUN WITH 2.50 LIB, AND GOT GOOD IMPRESSION OF SLB/HFD FIRING TOOL @ 8206' SLM. (FELL BELOW PERFS). PULLED SLB/ HDF FIRING HEAD. (ALL PARTS ARE THERE) LEFT WELL SHUT-IN, NO FLOW LINE INSTALLED. 06/13/04 SET 31/2" RHC PLUG BODY @7,984' SLM. PULL 1 1/2" FLOW VALVE IN STA#2 @ 7,817' SLM. PULLED 1 1/2" DGLV FROM STA#3 @ 7,710' SLM. SET 1 1/2" FLOW SLEEVE IN STA#3 @7,710 SLM. RETRIEVED 1 1/2" DGLV FROM STA #2 IN CATCHER. SET 1 1/2" DGLV IN STA #2 @ 78178' SLM. 06/14/04 PULLED 3 1/2" RHC CATCHER @ 7985' SLM. (EMPTY). WELL LEFT SHUT-IN, SSV DUMPED & PAD OP NOTIFIED. bp L-216 Survey Report Schlumberger Report Date: 7-May-04 Survey I DLS Computation Method: Minimum Curvature 1 Lubinski Client: BP Exploration Alaska Vertical Section Azimuth: 29.300· Field: Prudhoe Bay Unit· WOA Vertical Section Origin: N 0.000 It, E 0.000 ft Structure I Slot: L-PAD 1 N-R TVD Reference Datum: KB Well: L-216 TVD Reference Elevation: 78.40 ft relative to MSL Borehole: L-216 Sea Bed f Ground Level Elevation: 49.90 ft relative to MSL UWIIAPI#: 500292320600 Magnetic Declination: 24.974· Survey Name f Date: L-216 1 May 7, 2004 Total Field Strength: 57563.094 nT Tort f AHD DDI ERD ratio: 128.737· 16443.94 ft/6.161/1.324 Magnetic Dip: 80.824· Grid Coordinate System: NAD27 Alaska State Planes, Zone 04, US Feet Declination Date: May 04, 2004 Location Lat/Long: N 70.35070667, W 149.32383138 Magnetic Declination Model: BGGM 2003 Location Grid NfE Y/x: N 5978309.190 ftUS, E 583281.610 ftUS North Reference: True North Grid Convergence Angle: -+D.63679766· Total Corr Mag North -> True North: +24.974· e Grid Scale Factor. 0.99990788 Local Coordinates Referenced To: Well Head I Comments Measured Inclination I Azimuth I Sub·Sea TVD I TVD Vertical I Along Hole I NS EW I DLS I Build Rate I Walk Rate I Northing Easting Latitude Longitude Survey Tool I Depth Section Departure Model (It) (deg) (deg) (It) (It) (It) (It) (It) (It) ( degf100 It) ( degf100 It) ( degf100 It) (flUS) (ltUS) Tie-In 0.00 0.00 0.00 -78.40 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 5978309.19 583281.61 N 70.35070667 W 149.32383138 BP _UNKNOWN 100.00 0.17 174.31 21.60 100.00 -0.12 0.15 -0.15 0.01 0.17 0.17 0.00 5978309.04 583281.63 N 70.35070627 W 149.32383126 BP _GYD GC MS 200.00 0.14 164.00 121.60 200.00 -0.33 0.42 -0.41 0.06 0.04 -0.03 -10.31 5978308.78 583281.68 N 70.35070554 W 149.32383087 BP _GYD GC MS 300.00 2.57 21.84 221.57 299.97 1.81 2.58 1.55 0.93 2.68 2.43 -142.16 5978310.75 583282.52 N 70.35071091 W 149.32382382 BP _GYD GC MS 400.00 5.73 13.16 321.29 399.69 8.83 9.81 8.50 2.90 3.21 3.16 -8.68 5978317.72 583284.42 N 70.35072988 W 149.32380782 BP _GYD GC MS 500.00 8.17 11.30 420.55 498.95 20.38 21.90 20.33 5.43 2.45 2.44 -1.86 5978329.57 583286.81 N 70.35076220 W 149.32378729 BP _GYD GC MS 600.00 10.80 17.42 519.18 597.58 36.31 38.37 36.24 9.63 2.81 2.63 6.12 5978345.53 583290.84 N 70.35080566 W 149.32375321 BP _GYD GC MS 700.00 11.97 11.63 617.21 695.61 55.36 58.09 55.33 14.53 1.63 1.17 -5.79 5978364.68 583295.52 N 70.35085784 W 149.32371347 BP _GYD GC MS 800.00 14.24 13.69 714.60 793.00 77.09 80.76 77.44 19.53 2.32 2.27 2.06 5978386.84 583300.27 N 70.35091824 W 149.32367286 BP _GYD GC MS 900.00 16.73 8.32 810.97 889.37 102.38 107.44 103.64 24.52 2.87 2.49 -5.37 5978413.09 583304.98 N 70.35098981 W 149.32363231 BP _GYD GC MS 1000.00 20.05 9.23 905.85 984.25 131.93 138.98 134.81 29.36 3.33 3.32 0.91 5978444.31 583309.46 N 70.35107496 W 149.32359307 BP _GYD GC MS 1100.00 24.75 9.29 998.28 1076.68 167.72 177. 08 172.41 35.49 . 4.70 4.70 0.06 5978481.97 583315.18 N 70.35117768 W 149.32354328 BP _GYD GC MS 1200.00 28.64 11.65 1087.60 1166.00 210.24 221.99 216.56 43.71 4.03 3.89 2.36 5978526.20 583322.91 N 70.35129829 W 149.32347653 BP _GYD GC MS 1300.00 31.64 14.02 1174.08 1252.48 258.40 272.19 265.49 54.91 3.23 3.00 2.37 5978575.25 583333.56 N 70.35143197 W 149.32338563 BP _GYD GC MS 1400.00 36.10 11.85 1257.09 1335.49 311.83 327.90 319.80 67.32 4.62 4.46 -2.17 5978629.69 583345.36 N 70.35158033 W 149.32328488 BP _GYD GC MS Last Gyro Survey 1474.00 39.15 13.19 1315.69 1394.09 355.08 373.07 363.89 77.13 4.27 4.12 1.81 5978673.88 583354.68 N 70.35170078 W 149.32320523 BP GYD GC_ 1597.12 44.42 22.83 1407.56 1485.96 435.37 454.97 441.58 102.76 6.74 4.28 7.83 5978751.84 583379.44 N 70.35191302 W 149.32299714 BP _MWD+IFR 1690.74 47.46 25.44 1472.66 1551.06 502.36 522.24 502.94 130.29 3.81 3.25 2.79 5978813.50 583406.29 N 70.35208065 W 149.32277358 BP _MWD+IFR+MS 1783.89 46.66 27.65 1536.12 1614.52 570.47 590.43 563.94 160.76 1.94 -0.86 2.37 5978874.83 583436.07 N 70.35224730 W 149.32252624 BP _MWD+IFR+MS 1877.63 52.63 28.98 1596.80 1675.20 641.86 661.83 626.78 194.66 6.46 6.37 1.42 5978938.03 583469.27 N 70.35241896 W 149.32225102 BP _MWD+IFR+MS 1971.34 54.49 29.15 1652.46 1730.86 717.24 737.21 692.67 231.28 1.99 1.98 0.18 5979004.32 583505.15 N 70.35259897 W 149.32195367 BP _MWD+IFR+MS 2065.17 56.42 29.73 1705.66 1784.06 794.52 814.49 759.97 269.27 2.12 2.06 0.62 5979072.03 583542.39 N 70.35278282 W 149.32164523 BP _MWD+IFR+MS 2157.76 60.50 30.84 1754.09 1832.49 873.40 893.39 828.09 309.07 4.52 4.41 1.20 5979140.58 583581 .43 N 70.35296891 W 149.32132206 BP _MWD+IFR+MS 2250.58 64.00 30.56 1797.30 1875.70 955.51 975.52 898.71 351.00 3.78 3.77 -0.30 5979211.66 583622.56 N 70.35316184 W 149.32098162 BP _MWD+IFR+MS 2344.55 62.63 30.64 1839.50 1917.90 1039.45 1059.48 970.98 393.74 1.46 -1.46 0.09 5979284.39 583664.49 N 70.35335926 W 149.32063459 BP _MWD+IFR+MS 2438.39 62.01 31.08 1883.09 1961.49 1122.52 1142.58 1042.31 436.36 0.78 -0.66 0.47 5979356.19 583706.32 N 70.35355414 W 149.32028848 BP _MWD+IFR+MS 2532.04 62.96 31.46 1926.35 2004.75 1205.52 1225.63 1113.30 479.47 1.08 1.01 0.41 5979427.65 583748.64 N 70.35374807 W 149.31993840 BP _MWD+IFR+MS 2624.96 62.23 30.80 1969.12 2047.52 1287.97 1308.13 1183.91 522.12 1.01 -0.79 -0.71 5979498.72 583790.49 N 70.35394096 W 149.31959209 BP _MWD+IFR+MS 2717.54 61.27 30.57 2012.94 2091.34 1369.50 1389.68 1254.05 563.74 1.06 -1.04 -0.25 5979569.31 583831.32 N 70.35413255 W 149.31925414 BP _MWD+IFR+MS 2811.81 61.49 30.86 2058.10 2136.50 1452.23 1472.43 1325.19 606.01 0.36 0.23 0.31 5979640.91 583872.79 N 70.35432690 W 149.31891091 BP _MWD+IFR+MS SurveyEditor Ver 3.1 RT-SP3.03-HF4.00 Bld( d031 rt-546 ) N-R\L-216\L-216\L-216 Generated 5/18/2004 10:14 AM Page 1 of 3 Comments Measured I Inclination I Azimuth I Sub·Sea 1VD I 1VD Vertical I Along Hole I NS EW I DLS I Build Rate I Walk Rate I Northing Easting Latitude Longitude Survey Tool Depth Section Departure Model (It) (dog ) (deg ) (It) (It) (It) (It) (It) (It) ( degl100 It) ( degl100 It) ( deg/100 It) (ltUS) (ltUS) 2904.91 63.35 30.97 2101.20 2179.60 1534.71 1554.95 1395.98 648.40 2.00 2.00 0.12 5979712.16 583914.40 N 70.35452029 W 149.31856663 BP_MWD+IFR+MS 2997.86 62.74 31.10 2143.33 2221.73 1617.52 1637.80 1466.98 691.12 0.67 -0.66 0.14 5979783.62 583956.32 N 70.35471422 W 149.31821975 BP _MWD+IFR+MS 3091.14 62.34 30.58 2186.35 2264.75 1700.26 1720.57 1538.04 733.55 0.65 -0.43 -0.56 5979855.14 583997.95 N 70.35490836 W 149.31787516 BP _MWD+IFR+MS 3184.68 63.03 30.74 2229.27 2307.67 1783.35 1803.68 1609.53 775.93 0.75 0.74 0.17 5979927.09 584039.53 N 70.35510365 W 149.31753097 BP _MWD+IFR+MS 3278.87 62.82 30.25 2272.14 2350.54 1867.20 1887.55 1681.80 818.49 0.51 -0.22 -0.52 5979999.82 584081.28 N 70.35530107 W 149.31718533 BP _MWD+IFR+MS 3372.42 62.00 30.03 2315.47 2393.87 1950.10 1970.46 1753.50 860.12 0.90 -0.88 -0.24 5980071.98 584122.11 N 70.35549693 W 149.31684722 BP_MWD+IFR+MS 3464.85 63.70 32.06 2357.65 2436.05 2032.30 2052.70 1823.95 902.54 2.68 1.84 2.20 5980142.89 584163.74 N 70.35568939 W 149.31650270 BP _MWD+IFR+MS 3557.84 63.34 32.42 2399.11 2477.51 2115.42 2135.93 1894.35 946.94 0.52 -0.39 0.39 5980213.77 584207.35 N 70.35588170 W 149.31614208 BP _MWD+IFR+MS 3652.10 62.45 31.92 2442.06 2520.46 2199.23 2219.84 1965.38 991.62 1.06 -0.94 -0.53 5980285.28 584251.23 N 70.35607572 W 149.31577923 BP _MWD+IFR+MS 3746.17 61.62 32.29 2486.17 2564.57 2282.21 2302.92 2035.76 1035.77 0.95 -0.88 0.39 5980356.14 584294.60 N 70.35626797 W 149.31542059 BP _MWD+IFR+MS 3840.19 62.75 34.03 2530.04 2608.44 2365.17 2386.08 2105.36 1081.26 2.03 1.20 1.85 5980426.24 584339.31 N 70.35645811 W 149.31505114 BP _MWD+IFR+MS 3939.85 61.95 33.96 2576.29 2654.69 2453.15 2474.36 2178.55 1130.62 0.81 -0.80 -0.07 5980499.97 584387.84 N 70.35665804 W 149.31465024 BP MWD+IFR+MS 4045.67 62.16 34.05 2625.88 2704.28 2546.32 2567.84 2256.05 1182.90 0.21 0.20 0.09 5980578.03 584439.25 N 70.35686972 W 149.31422560 BP =MWD+1FRe 4137.91 62.11 34.21 2668.99 2747.39 2627.58 2649.38 2323.55 1228.65 0.16 -0.05 0.17 5980646.03 584484.25 N 70.35705411 W 149.31385397 BP _MWD+IFR 4230.89 63.32 33.50 2711.62 2790.02 2709.95 2732.01 2392.17 1274.68 1.47 1.30 -0.76 5980715.15 584529.51 N 70.35724156 W 149.31348007 BP _MWD+IFR+MS 4324.50 63.05 33.30 2753.84 2832.24 2793.28 2815.56 2461.92 1320.67 0.35 -0.29 -0.21 5980785.40 584574.72 N 70.35743208 W 149.31310651 BP_MWD+IFR+MS 4416.79 63.39 32.75 2795.43 2873.83 2875.49 2897.95 2531.00 1365.58 0.65 0.37 -0.60 5980854.97 584618.85 N 70.35762077 W 149.31274176 BP _MWD+IFR+MS 4511.18 63.98 32.66 2837.27 2915.67 2959.95 2982.56 2602.19 1411.29 0.63 0.63 -0.10 5980926.66 584663.76 N 70.35781525 W 149.31237041 BP _MWD+IFR+MS 4604.15 63.37 33.23 2878.50 2956.90 3043.11 3065.88 2672.12 1456.61 0.86 -0.66 0.61 5980997.08 584708.29 N 70.35800626 W 149.31200229 BP _MWD+IFR+MS 4699.72 63.31 33.59 2921.38 2999.78 3128.30 3151.29 2743.42 1503.64 0.34 -0.06 0.38 5981068.89 584754.52 N 70.35820101 W 149.31162026 BP _MWD+IFR+MS 4792.70 62.87 33.54 2963.46 3041.86 3210.98 3234.21 2812.50 1549.48 0.48 -0.47 -0.05 5981138.47 584799.59 N 70.35838972 W 149.31124787 BP_MWD+IFR+MS 4885.42 63.54 33.05 3005.26 3083.66 3293.55 3316.97 2881.68 1594.91 0.86 0.72 -0.53 5981208.15 584844.25 N 70.35857869 W 149.31087879 BP _MWD+IFR+MS 4979.66 64.38 31.16 3046.64 3125.04 3378.11 3401.64 2953.40 1639.90 2.01 0.89 -2.01 5981280.36 584888.44 N 70.35877460 W 149.31051325 BP _MWD+IFR+MS 5073.13 63.73 30.86 3087.53 3165.93 3462.12 3485.69 3025.44 1683.20 0.75 -0.70 -0.32 5981352.86 584930.93 N 70.35897137 W 149.31016146 BP _MWD+IFR+MS 5166.40 63.50 30.70 3128.98 3207.38 3545.65 3569.24 3097.22 1725.96 0.29 -0.25 -0.17 5981425.11 584972.88 N 70.35916745 W 149.30981407 BP _MWD+IFR+MS 5259.49 63.05 30.60 3170.84 3249.24 3628.77 3652.39 3168.75 1768.35 0.49 -0.48 -0.11 5981497.10 585014.47 N 70.35936283 W 149.30946969 BP _MWD+IFR+MS 5351.64 61.87 30.27 3213.45 3291.85 3710.46 3734.10 3239.20 1809.74 1.32 -1.28 -0.36 5981568.00 585055.07 N 70.35955526 W 149.30913340 BP _MWD+IFR+MS 5443.99 61.73 29.29 3257.09 3335.49 3791.85 3815.48 3309.84 1850.16 0.95 -0.15 -1.06 5981639.07 585094.70 N 70.35974821 W 149.30880495 BP _MWD+IFR+MS 5536.73 62.70 27.34 3300.32 3378.72 3873.87 3897.53 3382.07 1889.07 2.13 1.05 -2.10 5981711.72 585132.80 N 70.35994551 W 149.30848881 BP _MWD+IFR+MS 5630.79 62.22 27.15 3343.81 3422.21 3957.22 3980.93 3456.22 1927.25 0.54 -0.51 -0.20 5981786.28 585170.15 N 70.36014805 W 149.30817856 BP _MWD+IFR+MS 5724.12 63.12 27.09 3386.66 3465.06 4040.07 4063.84 3530.01 1965.05 0.97 0.96 -0.06 5981860.49 585207.12 N 70.36034962 W 149.30787143 BP _MWD+IFR+MS 5817.43 63.65 27.94 3428.47 3506.87 4123.46 4147.26 3604.00 2003.59 0.99 0.57 0.91 5981934.89 585244.83 N 70.36055171 W 149.30755825 BP _MWD+IFR+MS 5910.29 62.82 27.57 3470.28 3548.68 4206.34 4230.17 3677.37 2042.20 .0.96 -0.89 -0.40 5982008.68 585282.62 N 70.36075213 W 149.30724448 BP _MWD+IFR. 6005.04 61.89 27.70 3514.25 3592.65 4290.23 4314.11 3751.72 2081.13 0.99 -0.98 0.14 5982083.46 585320.72 N 70.36095523 W 149.30692812 BP _MWD+IFR 6098.25 60.88 27.46 3558.89 3637.29 4372.02 4395.93 3824.25 2119.01 1.11 -1.08 -0.26 5982156.39 585357.79 N 70.36115334 W 149.30662025 BP _MWD+IFR+ 6192.53 61.72 27.79 3604.16 3682.56 4454.68 4478.63 3897.52 2157.36 0.94 0.89 0.35 5982230.08 585395.32 N 70.36135347 W 149.30630863 BP _MWD+IFR+MS 6286.64 62.93 27.62 3647.87 3726.27 4537.99 4561.97 3971.31 2196.11 1.30 1.29 -0.18 5982304.28 585433.24 N 70.36155502 W 149.30599374 BP _MWD+IFR+MS 6379.95 63.43 27.87 3689.97 3768.37 4621.23 4645.24 4045.00 2234.87 0.59 0.54 0.27 5982378.40 585471.18 N 70.36175632 W 149.30567868 BP _MWD+IFR+MS 6472.72 62.78 27.99 3731.93 3810.33 4703.94 4727.98 4118.10 2273.63 0.71 -0.70 0.13 5982451.92 585509.12 N 70.36195599 W 149.30536373 BP _MWD+IFR+MS 6565.28 61.93 28.32 3774.88 3853.28 4785.92 4809.97 4190.39 2312.31 0.97 -0.92 0.36 5982524.63 585546.99 N 70.36215345 W 149.30504931 BP _MWD+IFR+MS 6659.91 61.03 28.15 3820.06 3898.46 4869.05 4893.11 4263.65 2351.65 0.96 -0.95 -0.18 5982598.31 585585.51 N 70.36235354 W 149.30472961 BP _MWD+IFR+MS 6752.49 61.99 28.76 3864.22 3942.62 4950.41 4974.48 4335.18 2390.42 1.19 1.04 0.66 5982670.26 585623.48 N 70.36254893 W 149.30441450 BP _MWD+IFR+MS 6845.72 62.09 29.26 3907.94 3986.34 5032.75 5056.83 4407.20 2430.36 0.49 0.11 0.54 5982742.71 585662.61 N 70.36274564 W 149.30408992 BP _MWD+IFR+MS 6938.87 61.84 30.21 3951.72 4030.12 5114.97 5139.05 4478.59 2471.13 0.94 -0.27 1.02 5982814.54 585702.59 N 70.36294064 W 149.30375849 BP _MWD+IFR+MS 7031.78 61.32 30.67 3995.94 4074.34 5196.67 5220.76 4549.04 2512.53 0.71 -0.56 0.50 5982885.44 585743.20 N 70.36313306 W 149.30342203 BP _MWD+IFR+MS 7125.28 60.60 30.53 4041.32 4119.72 5278.39 5302.51 4619.40 2554.14 0.78 -0.77 -0.15 5982956.25 585784.02 N 70.36332524 W 149.30308382 BP _MWD+IFR+MS 7219.16 60.45 32.18 4087,52 4165.92 5360.06 5384.23 4689.19 2596.67 1.54 -0.16 1.76 5983026.51 585825.76 N 70.36351586 W 149.30273820 BP _MWD+IFR+MS SurveyEditor Ver 3.1 RT -SP3.03-HF4.00 Bld( d031 rt-546 ) N-RIl-216\L-2161l-216 Generated 5/18/2004 10:14 AM Page 2 of 3 Comments Measured I Inclination I Azimuth I Sub-Sea TVD I TVD I Vertical I Along Hole I NS EW I DLS I Build Rate I Walk Rate I Northing Easting Latitude Longitude Survey Tool Depth Section Departure Model (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (degf100 ft) (deg/100ft) (deg/100ft) (ftUS) (ftUS) 7311.94 58.00 32.12 4134.99 4213.39 5439.67 5463.94 4756.68 2639.08 2.64 -2.64 -0.06 5983094.45 585867.42 N 70.36370019 W 149.30239345 BP _MWD+IFR+MS 7404.81 57.77 32.61 4184.36 4262.76 5518.22 5542.60 4823.12 2681.19 0.51 -0.25 0.53 5983161.35 585908.78 N 70.36388165 W 149.30205121 BP _MWD+IFR+MS 7499.14 57.32 32.15 4234.98 4313.38 5597.70 5622.20 4890.34 2723.82 0.63 -0.48 -0.49 5983229.03 585950.66 N 70.36406525 W 149.30170474 BP _MWD+IFR+MS 7593.67 56.78 31.68 4286.40 4364.80 5676.94 5701.52 4957.67 2765.75 0.71 -0.57 -0.50 5983296.82 585991.84 N 70.36424915 W 149.30136387 BP _MWD+IFR+MS 7687.14 56.14 29.46 4338.04 4416.44 5754.82 5779.43 5024.74 2805.38 2.09 -0.68 -2.38 5983364.32 586030.71 N 70.36443234 W 149.30104179 BP _MWD+IFR+MS 7779.74 56.83 29.66 4389.17 4467.57 5832.03 5856.63 5091.89 2843.46 0.77 0.75 0.22 5983431.89 586068.05 N 70.36461576 W 149.30073217 BP _MWD+IFR+MS 7873.08 56.40 30.15 4440.54 4518.94 5909.96 5934.57 5159.45 2882.32 0.64 -0.46 0.52 5983499.87 586106.14 N 70.36480029 W 149.30041631 BP _MWD+IFR+MS 7966.88 56.14 30.47 4492.62 4571.02 5987.96 6012.58 5226.80 2921.69 0.40 -0.28 0.34 5983567.64 586144.76 N 70.36498423 W 149.30009627 BP _MWD+IFR+MS 8060.78 56.01 30.41 4545.03 4623.43 6065.86 6090.49 5293.98 2961.17 0.15 -0.14 -0.06 5983635.25 586183.48 N 70.36516770 W 149.29977537 BP _MWD+IFR+MS 8154.64 55.85 30.63 4597.61 4676.01 6143.59 6168.24 5360.95 3000.65 0.26 -0.17 0.23 5983702.65 586222.22 N 70.36535063 W 149.29945439 BP _MWD+IFR+MS 8248.23 55.67 30.09 4650.27 4728.67 6220.94 6245.61 5427.71 3039.75 0.51 -0.19 -0.58 5983769.84 586260.57 N 70.36553297 W 149.29913648 BP _MWD+IFR+MS 8340.76 55.04 30.39 4702.87 4781.27 6297.06 6321.74 5493.48 3078.09 0.73 -0.68 0.32 5983836.02 586298.17 N 70.36571259 W 149.29882482 BP _MWD+IFR+MS Last Corrected MWD 8416.06 54.95 30.20 4746.07 4824.47 6358.72 6383.41 5546.73 3109.20 0.24 -0.12 -0.25 5983889.61 586328.69 N 70.36585804 W 149.29857187 BP MWD+IFR+MS - e TO 8490.00 54.95 30.20 4788.53 4866.93 6419.25 6443.94 5599.05 3139.65 0.00 0.00 0.00 5983942.26 586358.55 N 70.36600093 W 149.29832433 BP _BLIND Survey Type: Definitive Survey NOTES: GYD GC MS - ( Gyrodata - gyro compassing m/s -- Older Gyrodata gyro multlshots-plus all battery/memory tool surveys (RGS-BT). Replaces ex-BP "Gyrodata multlshot Into open hole" model. ) MWD + IFR + MS - ( In-field referenced MWD with mult-statlon analysis and correction applied In post-processing. Assumes a BHA sag correction Is applied to enhance Inclination accuracy. ) Lellal DescriPtion: Surface: 2586 FSL 3632 FEL 534 T12N RII E UM BHL: 2905 FSL 482 FEL S27 T12N RII E UM NorthlnlllYl rftUSl 5978309.19 5983942.26 Eastlnll (X) rnUSl 583281.61 586358.55 e SurveyEditor Ver 3.1 RT-SP3.03-HF4.00 Bld( d031 rt-546 ) N-RIL-216IL-216IL-216 Generated 5/18/2004 10: 14 AM Page 3 of 3 e e L-216i Com pletion From DRLG - DRAFT Cellar Elevation = 49.9' Nabors 9ES RKB = 78.4' .. 9-5/8", 40 #/ft, L-80, BTC 14006' I .. 7" Short Joints & RA Tags 7636 & 6959' RATagin31/2" 7755' ~TBD' TVDss - - - - - - - - - - ~ TREE: FMC 4-1/16" 5M W ELL HEAD: F M C G en 5 S ys te m 11". 5M esg.head wi 7" mandrel hanger & paekoff 11" x 11", 5M, tbg spool wi l 11" x 4-1/2" tubing hanger 11" X 4-1/16" Adaptor Flange 20"X34"215.5Ib/ft,A53ERWlnsulated 114" I 4-1/2" 'X' Landing Nipple with 3.813" seal bore. 3513' MD 1 2 Jts_ above I Cameo gas lift mandreI4-1/2" x 1" KBG-2 With DCK Shear Valve- 7205' .( 112" x-nipple -4-1/2" 'X' Landing Nipple" 3.813" bore -7316'. 4-1/2" X 3-1/2" Tell xo 7" x 3-1/2" Baker' PRM' Prod Packer - 7328' 3-1/2" 'X' Landing Nipple - 7386'. ameo 3-1/2" x 1-1/2" Mandrels 7560 & 7407' b Perfs:7465-7525' 3-1/2" 'X' Landing Nipple -7589'. 7" x 3-1/2" Baker' PRM' Prod Packer - 7599' 3-1/2" 'X' Landing Nipple" 7625'. am co 3-1/2" x 1-1/2" Mandrels 7736 & 7646' o A Perfs: 7690-7760' 3-1/2" 'X' Landing Nipple - 7771 '. 7" x 3-1/2" Baker 'PRM' Prod Packer-7782' 3-1/2" 'X' Landing Nipple -7798'. Camco 3-1/2" x 1-1/2" Injection Mandrels 7933 and 7840' ::.-----OBa/OBb Perfs 7805-7865' = 7890-7920' 3-1/2" 'X' Landing Nipple-7972'. 7" x 4-1/2" Baker'S-3' Prod Packer-7984' 3-1/2" 'X' Landing Nipple 8021 & 8010'. 3-1/2" Wire Line Entry Guide - 8045' f ~ - ~Bd sand Perf 8080- = 8180' 7" PBTD 8,393' MD I ~ 7< 26 #/ft, L80, BTC-Mod I 8479' MD 83/4", TD 8490' MD Date 02/23/04 05/17104 Rev By Tom S Dick M Comments Proposed Completion Initial Completion G 4-1/2", 12.6Ib/ft, L-80, TCII Drift / 10 : 3.833"/3.958" 3-1/2",9.3Ib/ft, L-80, TCII Drift /10 : 2.867"/2.992" WELL: L-216i API NO:50-029-23206 SCHLUMBERGER Survey report Client.. ..... ............: BP Exploration (Alaska) Inc. Field. . . . . . . . . . . . . . . . . . . .: Orion Well. . . . . . . . . . . . . . . . . . . . .: L-216 API number..... ..........: 50-029-23206-00 Engineer.. ...............: M. St. Amour RIG Label:.. ... ........ ..: NABORS 9ES STATE: . . . . . . . . . . . . . . . . . . .: Alaska ----- Survey calculation methods------------- Method for positions.....: Minimum curvature Method for DLS....... ....: Mason & Taylor ----- Depth reference ----------------------- Permanent datum....... ...: MEAN SEA LEVEL Depth reference.. ...... ..: Driller's Pipe Tally GL above permanent.......: 49.90 ft KB above permanent..... ..: N/A (Top Drive) ft DF above permanent.......: 78.40 ft ----- Vertical section origin---------------- Latitude (+N/S-). ........: 0.00 ft Departure (+E/W-).... ....: 0.00 ft ----- Platform reference point--------------- Latitude (+N/S-) .... .....: N 70.35070667 ft Departure (+E/W-). .......: W 149.32383138 ft Azimuth from rotary table to target: 29.30 degrees [(c)2004 IDEAL ID8_1C_02J I ~ (v1 µNb ~ ). C) v[-o ~J~ 7-May-2004 19:20:35 Spud date...... .. .. . ... . . : Last survey date.. .......: Total accepted surveys. . . : MD of first survey. ......: MD of last survey. .......: Page 1 of 5 01-May-2004 07-May-04 91 0.00 ft 8490.00 ft . ----- Geomagnetic data ---------------------- Magnetic model... ........: BGGM version 2003 Magnetic date.... ..... ...: 01-May-2004 Magnetic field strength..: 1151.28 HCNT Magnetic dec (+E/W-) .....: 24.98 degrees Magnetic dip..... ........: 80.82 degrees ----- MWD survey Reference Reference G..............: Reference H.. ...... ......: Reference Dip. ....... ....: Tolerance of G...... .....: Tolerance of H....... ....: Tolerance of Dip.........: Criteria --------- 1002.68 mGal 1151. 28 HCNT 80.82 degrees (+/-) 2.50 mGal (+/-) 6.00 HCNT (+/-) 0.45 degrees . ----- Corrections --------------------------- Magnetic dec (+E/W-)... ..: 24.98 degrees Grid convergence (+E/W-).: 0.00 degrees Total az corr (+E/W-)....: 24.98 degrees (Total az corr = magnetic dec - grid conv) Survey Correction Type ...: I=Sag Corrected Inclination M=Schlumberger Magnetic Correction S=Shell Magnetic Correction F=Failed Axis Correction R=Magnetic Resonance Tool Correction D=Dmag Magnetic Correction SCHLUMBERGER Survey Report 7-May-2004 19:20:35 Page 2 of 5 -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ Seq Measured Incl Azimuth Course TVD Vertical Displ Displ Total At DLS Srvy Tool # depth angle angle length depth section +N/S- +E/W- displ Azim (deg/ tool Corr (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type (deg) -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ 1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 TIP None 2 100.00 0.17 174.31 100.00 100.00 -0.12 -0.15 0.01 0.15 174.31 0.17 GYD-GC-SS 3 200.00 0.14 164.00 100.00 200.00 -0.33 -0.41 0.06 0.42 171.31 0.04 GYD-GC-SS 4 300.00 2.57 21.84 100.00 299.97 1. 81 1. 55 0.93 1. 81 30.97 2.68 GYD-GC-SS 5 400.00 5.73 13 .16 100.00 399.69 8.83 8.50 2.90 8.98 18.86 3.21 GYD-GC-SS 6 500.00 8.17 11. 30 100.00 498.95 20.38 20.33 5.43 21. 04 14.96 2.45 GYD-GC-SS . 7 600.00 10.80 17.42 100.00 597.58 36.31 ~6.24 9.63 37.49 14.88 2.81 GYD-GC-SS 8 700.00 11. 97 11.63 100.00 695.61 55.36 55.33 14.53 57.21 14.71 1. 63 GYD-GC-SS 9 800.00 14.24 13.69 100.00 793.00 77.09 77.44 19.53 79.87 14.15 2.32 GYD-GC-SS 10 900.00 16.73 8.32 100.00 889.37 102.38 H3.64 24.52 106.50 13 .31 2.87 GYD-GC-SS 11 1000.00 20.05 9.23 100.00 984.25 131. 93 12.4.81 29.36 13 7.97 12.28 3.33 GYD-GC-SS 12 1100.00 24.75 9.29 100.00 1076.68 167.72 172.41 35.49 176.02 11.63 4.70 GYD-GC-SS 13 1200.00 28.64 11.65 100.00 1166.00 210.24 2J.6.56 43.71 220.93 11. 41 4.03 GYD-GC-SS 14 1300.00 31. 64 14.02 100.00 1252.48 258.40 265.49 54.91 271.11 11. 68 3.23 GYD-GC-SS 15 1400.00 36.10 11.85 100.00 1335.49 311 . 83 3J.9.80 67.32 326.81 11. 89 4.62 GYD-GC-SS 16 1474.00 39.15 13.19 74.00 1394.09 355.08 363.89 77.13 371.97 11.97 4.27 MWD-IFR-MS 17 1597.12 44.42 22.83 123.12 1485.96 435.37 4'=1.58 102.76 453.38 13.10 6.74 MWD-IFR-MS 18 1690.74 47.46 25.44 93.62 1551.06 502.36 5(2.94 130.29 519.54 14.52 3.81 MWD-IFR-MS 19 1783.89 46.66 27.65 93.15 1614.52 570.47 563.94 160.76 586.40 15.91 1. 94 MWD-IFR-MS 20 1877.63 52.63 28.98 93.74 1675.20 641.86 626.78 194.66 656.31 17.25 6.46 MWD-IFR-MS 21 1971 . 34 54.49 29.15 93.71 1730.86 71 7.24 692.67 231.28 730.26 18.46 1. 99 MWD-IFR-MS . , 22 2065.17 56.42 29.73 93.83 1784.06 794.52 759.97 269.27 806.26 19.51 2.12 MWD-IFR-MS 23 2157.76 60.50 30.84 92.59 1832.49 873.40 828.09 309.07 883.88 20.47 4.52 MWD-IFR-MS 24 2250.58 64.00 30.56 92.82 1875.70 955.51 898.71 351.00 964.82 21. 33 3.78 MWD-IFR-MS 25 2344.55 62.63 30.64 93.97 1917.90 1039.45 970.98 393.74 1047.77 22.07 1.46 MWD-IFR-MS 26 2438.39 62.01 31.08 93.84 1961.49 1122.52 10'=2.31 436.36 1129.97 22.72 0.78 MWD-IFR-MS 27 2532.04 62.96 31.46 93.65 2004.75 1205.52 1113.30 479.47 1212.16 23.30 1. 08 MWD-IFR-MS 28 2624.96 62.23 30.80 92.92 2047.52 1287.97 lIt 3.91 522.12 1293.93 23.80 1. 01 MWD-IFR-MS 29 2717.54 61. 27 30.57 92.58 2091.34 1369.50 1254.05 563.74 1374.93 24.21 1. 06 MWD-IFR-MS 30 2811.81 61. 49 30.86 94.27 2136.50 1452.23 13:<5.19 606.01 1457.18 24.57 0.36 MWD-IFR-MS [(c)2004 IDEAL ID8_1C_02] SCHLUMBERGER Survey Report 7-May-2004 19:20:35 Page 3 of 5 -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ Seq Measured Incl Azimuth Course TVD Vertical Displ Displ Total At DLS Srvy Tool # depth angle angle length depth section +N/S- +E/W- displ Azim (deg/ tool Carr (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type (deg) -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ 31 2904.91 63.35 30.97 93.10 2179.60 1534.71 1395.98 648.40 1539.22 24.91 2.00 MWD-IFR-MS 32 2997.86 62.74 31.10 92.95 2221.73 1617.52 1466.98 691.12 1621. 62 25.23 0.67 MWD-IFR-MS 33 3091.14 62.34 30.58 93.28 2264.75 1700.26 1538.04 733.55 1704.01 25.50 0.65 MWD-IFR-MS 34 3184.68 63.03 30.74 93.54 2307.67 1783.35 1609.53 775.93 1786.80 25.74 0.75 MWD-IFR-MS 35 3278.87 62.82 30.25 94.19 2350.54 1867.20 16&1.80 818.49 1870.39 25.95 0.51 MWD-IFR-MS 36 3372.42 62.00 30.03 93.55 2393.87 1950.10 1753.50 860.12 1953.09 26.13 0.90 MWD-IFR-MS . 37 3464.85 63.70 32.06 92.43 2436.05 2032.30 1823.95 902.54 2035.04 26.33 2.68 MWD-IFR-MS 38 3557.84 63.34 32.42 92.99 2477.51 2115.42 1894.35 946.94 2117.85 26.56 0.52 MWD-IFR-MS 39 3652.10 62.45 31.92 94.26 2520.46 2199.23 1965.38 991.62 2201.37 26.77 1. 06 MWD-IFR-MS 40 3746.17 61.62 32.29 94.07 2564.57 2282.21 20::'5.76 1035.77 2284.10 26.97 0.95 MWD-IFR-MS 41 3840.19 62.75 34.03 94.02 2608.44 2365.17 2105.36 1081. 26 2366.79 27.18 2.03 MWD-IFR-MS 42 3939.85 61.95 33.96 99.66 2654.69 2453.15 2178.55 1130.62 2454.46 27.43 0.81 MWD-IFR-MS 43 4045.67 62.16 34.05 105.82 2704.28 2546.32 2256.05 1182.90 2547.35 27.67 0.21 MWD-IFR-MS 44 4137.91 62.11 34.21 92.24 2747.39 2627.58 2323.55 1228.65 2628.40 27.87 0.16 MWD-IFR-MS 45 4230.89 63.32 33.50 92.98 2790.02 2709.95 2392.17 1274.68 2710.59 28.05 1.47 MWD-IFR-MS 46 4324.50 63.05 33.30 93.61 2832.24 2793.28 2461. 92 1320.67 2793.78 28.21 0.35 MWD-IFR-MS 47 4416.79 63.39 32.75 92.29 2873.83 2875.49 25::'1. 00 1365.58 2875.89 28.35 0.65 MWD-IFR-MS 48 4511.18 63.98 32.66 94.39 2915.67 2959.95 2602.19 1411.29 2960.26 28.47 0.63 MWD-IFR-MS 49 4604.15 63.37 33.23 92.97 2956.90 3043.11 2672.12 1456.61 3043.34 28.60 0.86 MWD-IFR-MS 50 4699.72 63.31 33.59 95.57 2999.78 3128.30 27'=3.42 1503.64 3128.46 28.73 0.34 MWD-IFR-MS 51 4792.70 62.87 33.54 92.98 3041. 86 3210.98 28:'2.50 1549.48 3211.08 28.85 0.48 MWD-IFR-MS . 52 4885.42 63.54 33.05 92.72 3083.66 3293.55 28S1.68 1594.91 3293.60 28.96 0.86 MWD-IFR-MS 53 4979.66 64.38 31.16 94.24 3125.04 3378.11 2953.40 1639.90 3378.15 29.04 2.01 MWD-IFR-MS 54 5073.13 63.73 30.86 93.47 3165.93 3462.12 3025.44 1683.20 3462.15 29.09 0.75 MWD-IFR-MS 55 5166.40 63.50 30.70 93.27 3207.38 3545.65 3097.22 1725.96 3545.66 29.13 0.29 MWD-IFR-MS 56 5259.49 63.05 30.60 93.09 3249.24 3628.77 3168.75 1768.35 3628.78 29.16 0.49 MWD-IFR-MS 57 5351. 64 61.87 30.27 92.15 3291.85 3710.46 32::'9.20 1809.74 3710.47 29.19 1.32 MWD-IFR-MS 58 5443.99 61.73 29.29 92.35 3335.49 3791.85 33(9.84 1850.16 3791.85 29.20 0.95 MWD-IFR-MS 59 5536.73 62.70 27.34 92.74 3378.72 3873.87 3382.07 1889.07 3873.88 29.19 2.13 MWD-IFR-MS 60 5630.79 62.22 27.15 94.06 3422.21 3957.22 3456.22 1927.25 3957.24 29.14 0.54 MWD-IFR-MS [(c)2004 IDEAL ID8 1C_02] SCHLUMBERGER Survey Report 7-May-2004 19:20:35 Page 4 of 5 -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ Seq Measured Incl Azimuth Course TVD Vertical Displ Displ Total At DLS Srvy Tool # depth angle angle length depth section +N/S- +E/W- displ Azim (deg/ tool Corr (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type (deg) -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ 61 5724.12 63.12 27.09 93.33 3465.06 4040.07 3530.01 1965.05 4040.10 29.10 0.97 MWD-IFR-MS 62 5817.43 63.65 27.94 93.31 3506.86 4123.46 3604.00 2003.59 4123.49 29.07 0.99 MWD-IFR-MS 63 5910.29 62.82 27.57 92.86 3548.68 4206.33 3677.37 2042.20 4206.38 29.05 0.96 MWD-IFR-MS 64 6005.04 61.89 27.70 94.75 3592.65 4290.23 3751.72 2081.13 4290.28 29.02 0.99 MWD-IFR-MS 65 6098.25 60.88 27.46 93.21 3637.28 4372.02 3824.25 2119.01 4372.08 28.99 loll MWD-IFR-MS 66 6192.53 61.72 27.79 94.28 3682.56 4454.68 3897.52 2157.36 4454.76 28.97 0.94 MWD-IFR-MS . 67 6286.64 62.93 27.62 94.11 3726.27 4537.99 3971. 31 2196.11 4538.08 28.94 1. 30 MWD-IFR-MS 68 6379.95 63.43 27.87 93.31 3768.37 4621. 23 4045.00 2234.87 4621.33 28.92 0.59 MWD-IFR-MS 69 6472.72 62.78 27.99 92.77 3810.33 4703.94 41:..8.10 2273.63 4704.06 28.90 0.71 MWD-IFR-MS 70 6565.28 61. 93 28.32 92.56 3853.28 4785.92 4190.39 2312.31 4786.04 28.89 0.97 MWD-IFR-MS 71 6659.91 61. 03 28.15 94.63 3898.46 4869.05 4263.65 2351. 65 4869.18 28.88 0.96 MWD-IFR-MS 72 6752.49 61.99 28.76 92.58 3942.62 4950.41 4335.18 2390.42 4950.55 28.87 1.19 MWD-IFR-MS 73 6845.72 62.09 29.26 93.23 3986.34 5032.76 4407.20 2430.35 5032.89 28.87 0.49 MWD-IFR-MS 74 6938.87 61.84 30.21 93.15 4030.12 5114.97 44'78.59 2471.13 5115.10 28.89 0.94 MWD-IFR-MS 75 7031.78 61. 32 30.67 92.91 4074.34 5196 . 67 45'=9.04 2512.53 5196.79 28.91 0.71 MWD-IFR-MS 76 7125.28 60.60 30.53 93.50 4119.72 5278.39 46:"9.40 2554.14 5278.50 28.94 0.78 MWD-IFR-MS 77 7219.16 60.45 32.18 93.88 4165.92 5360.06 4689.19 2596.67 5360.15 28.98 1. 54 MWD-IFR-MS 78 7311. 94 58.00 32.12 92.78 4213.39 5439.67 4756.68 2639.08 5439.74 29.02 2.64 MWD-IFR-MS 79 7404.81 57.77 32.61 92.87 4262.76 5518.22 4823.12 2681.19 5518.26 29.07 0.51 MWD-IFR-MS 80 7499.14 57.32 32.15 94.33 4313.38 5597.70 4890.34 2723.82 5597.73 29.12 0.63 MWD-IFR-MS 81 7593.67 56.78 31. 68 94.53 4364.80 5676.94 4957.67 2765.75 5676.96 29.16 0.71 MWD-IFR-MS . 82 7687.14 56.14 29.46 93.47 4416.45 5754.82 5024.74 2805.38 5754.84 29.18 2.09 MWD-IFR-MS 83 7779.74 56.83 29.66 92.60 4467.57 5832.03 5091.89 2843.47 5832.04 29.18 0.77 MWD-IFR-MS 84 7873.08 56.40 30.15 93.34 4518.94 5909.96 5159.45 2882.32 5909.97 29.19 0.64 MWD-IFR-MS 85 7966.88 56.14 30.47 93.80 4571.02 5987.96 5226.80 2921.69 5987.96 29.20 0.40 MWD-IFR-MS 86 8060.78 56.01 30.41 93.90 4623.43 6065.86 5293.98 2961.17 6065.86 29.22 0.15 MWD-IFR-MS 87 8154.64 55.85 30.63 93.86 4676.01 6143.59 5360.95 3000.65 6143.59 29.24 0.26 MWD-IFR-MS 88 8248.23 55.67 30.09 93.59 4728.67 6220.94 5427.71 3039.75 6220.95 29.25 0.51 MWD-IFR-MS 89 8340.76 55.04 30.39 92 .53 4781.27 6297.06 5493.48 3078.09 6297.06 29.26 0.73 MWD-IFR-MS 90 8416.06 54.95 30.20 75.30 4824.47 6358.73 55'=6.73 3109.20 6358.73 29.27 0.24 MWD-IFR-MS [(c)2004 IDEAL ID8_1C_02J SCHLUMBERGER Survey Report 7-May-2004 19:20:35 Page 5 of 5 -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ Seq Measured Incl Azimuth Course TVD Vertical Displ Displ Total At DLS Srvy Tool # depth angle angle length depth section +N/S- +E/W- displ Azim (deg/ tool Corr (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type (deg) -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ 91 8490.00 54.95 30.20 73.94 4866.93 6419.25 55J9.05 3139.65 6419.25 29.28 0.00 proyected to TD [(c)2004 IDEAL ID8_1C_02J . . · r~-~ ¡Î ~ ~ { f""j U ~ / , i FRANK H. MURKOWSK/, GOVERNOR / AI,ASIiAOILANDGAS ¡ CONSERVATION COMMISSION 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Lowell Crane Senior Drilling Engineer BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, Alaska· 99519-6612 Re: Prudhoe L-216 BP Exploration (Alaska) Inc. Permit No: 204-065 Surface Location: 2586' NSL, 3632' WEL, SEe. 34, Tl2N, RIlE, UM Bottomhole Location: 2803' NSL, 537' WEL, SEC. 27, T12N, RIlE, UM Dear Mr. Crane: Enclosed is the approved application for permit to drill the above referenced service well. This permit to drill does not exempt you ITom obtaining additional permits or approvals required by law ITom other governmental agencies, and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative 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 terms and conditions of this permit may result in the revocation or suspension of the permit. Please provide at least twenty-four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's North Slope petroleum field inspecto a 659-3607 (pager). f7c ~ ~[~. No Chair BY ORDER OF THE COMMISSION DATED thisØ'ay of April, 2004 cc: Department ofFish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. vJ41r 4[2-D{2-ð0t B Drill 0 Redrill 1 a. Type of work 0 Re-Entry 2. Operator Name: BP Exploration (Alaska) Inc. 3. Address: P.O. Box 196612, Anchorage, Alaska 99519-6612 4a. Location of Well (Governmental Section): Surface: 2586' NSL, 3632' WEL, SEC. 34, T12N, R11E, UM Top of Productive Horizon: 2332' NSL, 808' WEL, SEC. 27, T12N, R11E, UM Total Depth: 2803' NSL, 537' WEL, SEC. 27, T12N, R11E, UM 4b. Location of Well (State Base Plane Coordinates): Surface: x- 583282 y- 5978309 Zone- ASP4 16. Deviated Wells: Kickoff Depth 16. Casing Program Size Casing 20" x 34" 9-5/8" . STATE OF ALASKA . ALASKA Oil AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 MC 25.005 1b. Current Well Class 0 Exploratory 0 Development Oil 0 Multiple Zone o Stratigraphic Test B Service /' 0 Development Gas 0 Single Zone 5. Bond: 181 Blanket 0 Single Well 11. Well Name and Number: . Bond No. 2S100302630-277 PBU L-216 /' 6. Proposed Depth: 12. Field / Pool(s): MD 8392 TVD 4868 Prudhoe Bay Field / Orion 7. Property Designation: ADL 028239 8. Land Use Permit: 13. Approximate Spud Date: ..' May 1,2004 / 14. Distance to Nearest Property: 2610' 9. Acres in Property: 2560 7" Length 85' 3900' 8363' 10. KB Elevation 15. Distance to Nearest Well Within Pool (Height above GL):Plan 78.4 feet L-118 is 2150' away at 7692' MD 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.~) Downhole: 2140 psig Surface: 1668 psig Setting ·DePth Top . ·.<ßottom MD TVD MD TVD 29' 29' 114' 114' 29' 29' 3929' 2638' 29' 29' 8392' 4868' Hole 48" 12-1/4" 8-3/4" Weight 215.5# 40# 26# Maximum Hole Angle $pecifiéations Grade Coupling A53 Welded L-80 BTC L-80 BTC-M 62° 300 ft (including stage data) 260 sx Arctic Set (Approx.) 603 sx Arcticset Lite, 348 sx 'G' .,./ 346 sx Class 'G' .,/ 19. PRESENTWE:Ll. CQND/l10N. SUMMAR'(T 0 þecompletedfor RedrillANO Re-entry Op~rªti()l1s) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effective Depth MD (ft): Depth TVD (ft):1 Junk (measured): Structural Conductor Surface Intermediate Production Liner 20. Attachments 181 Filing Fee, $100 0 BOP Sketch 181 Property Plat 0 Diverter Sketch perfOration Depth TVD (ft): 181 Drilling Program 0 Time vs Depth Plot o Seabed Report 181 Drilling Fluid Program o Shallow Hazard Analysis 181 20 AAC 25.050 Requirements Date: Contact Thomas Schaefer, 564-4685 Perforation Depth MD (ft): 21. Verbal Approval: Commission Representative: 22. I hereby certify that the foregoing is true and correct to the best of my knowledge. Printed Crane Title Senior Drilling Engineer Phone 564-4089 Prepared By Name/Number: Terrie Hubble, 564-4628 Other: T.¿ st o-\- Permit APEro al 0 I See cover letter for 50- 02..9 - Z ~ z 06 Date: 9-; ',?;:r 0C¡ otherrequirements Samples Require~ E~~ No Mud Log equire 0 Yes JgNo Hydrogen Sulfide t'(¡g,G ~..LNO d DirectRnal Survey Required ]:g. Yes 0 N~ 1.+'" 1So P E ~ 4-000 p~~ 0 i:9 (.J'" L.ee~~ -.- \ -týeêt·~ . pev tt.< sf'P¡,{, Þ...:ttÇY¡,<;' ~ oýd~ ~J(J. )to.. Mrlj etVl-1-~t óUc,-li~l [OJ reõt.U I"-lJ. Alaska Oil & Gas Cons. Commission I ~ Anchorage BY ORDER OF hh ~ ----- 0 R I G , ....I A ·LTHE COMMISSION Date -¿.. . V'..' t 11 ubmlt n D plicate l...... Permit To Drill Number: :1 0 '1_ 0 Conditions of Approval: Approved Form 10-40 . . "t~J,. bp ~~~ ~~. ~..- -........ --..~ ~,-- ';I'~~§\" ". To: Winton Aubert, AOGCC Date: April 16, 2004 From: Thomas Schaefer Subject: Extension of Re2ular BOP Testin2 FreQuencv to 14 days on L-216i BP Alaska Drilling and Wells requests your consideration of an extension of the usual 7 day BOP test frequency to a 14 day interval for Nabors 9ES on L-216i as per order No. 516 for the Prudhoe Oil Pool. The well is to be completed as part of the Orion Development in the Schrader Bluff Nb and 0 sands as a high angle injector with surface casing set below the SV sands and production casing past the base of the OBf sand. The hydrocarbon sands that will be penetrated are considered nonnal pressure and will be drilled and perforated with a minimum 0.5 ppg overbalance. Attached are the well summary, completion schematic, and directional program for further consideration. Your consideration of the extension is appreciated. Sincerely, ~~d7- 'ih~~as Schaefer GPB Rotary Drilling Engineer 564-4685 · Great.udhoe Bay Orion L-216i Permit Well Plan Summary I Type of Well (producer or injector): 1 USH Injector Surface Location: I AFE Number: I 5M3554 2,586' FSL, 3,632' FEL, Sec. 34, T12N, R11 E X = 583,282 Y = 5,978,309 2,332' FSL, 808' FEL, Sec. 27, T12N, R11E X = 586,040 Y = 5,983,365 Z = -4,350' TVDss 2,803' FSL, 537' FEL, Sec. 27, T12N, R11E X = 586,305 Y = 5,983,840 Z = -4,790' TVDss I Rig: 1 Nabors 9ES / / I / I Operating days to complete: 115.32 / L-211 i Polygon 1 Target 1 Top Nb: L-211i Polygon 1 BHL: I Estimated Start Date: I May 1$1 2004 I Inj MD 18,392' I I TVDrkb: TD 1 4,868' I I Max Inc. I 62° I I KBE I 78.40' Well Design: USH Grassroots Schrader Injector. 4-%" X 3-%" TCII Completion. The Nb sand will be completed in addition to Schrader 0 sands. MDTsamples will be taken from both Nand 0 sands prior to completing the well. Current Well Information General Distance to Nearest Property: -2,610' at TD to the nearest PBU property line Distance to Nearest Well in Pool: 2,150' from L-216i top of OA at 7,692' MD to L-118 top OA at 7,691 'MD API Number: Well Type: Current Status: BHP: BHT: 50-029- ????? Development - Orion Schrader Injector New well, 20" X 34" insulated conductor 2,140 psi @ 4,727' TVDss (8.7 ppg EMW). Normal pressure gradient. 99°F @ 4,790' TVDss Estimated (from L-pad Temp Log) Mechanical Condition L-216i: Nabors 9ES: Conductor: Cellar Box above MSL = 49.9' KB / MSL = 28.5' 20" X 34", 215.5Ib/ft, A53 ERW set at 109' RKB % Mile Wellbore Near Wellbore Mechanical Integrity Summary: / There are no other wells within 1&1 mile of this injector at its penetration at the Top OA structure. No Wellbore Near Wellbore integrity issues. Target Estimates Estimated Reserves: 1,212 mstb Final Materials Needed Suñace Casing: Intermediate Casing: L-80 Completion: . 3,929' 1 each 1 each 25 each 1 assembly 1 lot 8,392' 1 each 75 each 2 lots 2 each 2 each 7,437' 650' 3 each 1 each 2 each 8 each 1 each 1 each 1 each 6 each 1 each Greateedhoe Bay Orion L-216i Permit 9-%", 40#, L-80 BTC Casing 9-%", BTC Float Shoe and Float Collar 9-%",40#, BTC Type TAM Port Collar 9-%" x 12 W Bow Spring Centralizers FMC 11" 5m Gen 5 Wellhead System 9-%" casing pups 5', 10', 20'. 7" 26# L -80 BTC-M Casing 7" BTC-M Float Shoe and Float Collar 7" x 8 W Rigid Straight Blade Centralizers 7" casing pups 5', 10', 20' 7" RA Tag 7" 26# L-80 BTC-M Casing Short Joint 4 W' 12.60 Ibltt, L-80, Tell tubing 3 W' 9.30 Ibltt, L-80, TCII tubing Baker PRM Production Packer 7" X 3-%" Baker S-3 Production Packer 7" X 3-%" Halliburton 4-%" X-Nipple (3.813" ID) Halliburton 3-W' X-Nipple (2.813" ID) 11" X 4- W FMC tubing hanger 4-1/16", 5m Cameron Tree 4-%" x 1" KBG-2 GLM 3-%" x 1-W' MMG Waterflood Mandrels 3 W' RA Tag 2 · Surface and Anti-Collision Issues Suñace Shut-in Wells: Nearby Wells Distance to Target Well Rig N9FS Wellhead Separatil L-200 75.14 45.14 L-103i 15.29 -14.71 L-201 44.78 19.78 Greateedhoe Bay Orion L-216i Permit / Separation of the target wellhead from nearest well is 15.29 feet. Surface close approach limit for Nabors 9ES is 60 feet separation from rig structure to wellhead. Maximum rig width from centerline is 30'. Smallest rig to wellhead separation is therefore -14.71'. L-103 will therefore require surface shut-in and well house removal in order to move over well. L-201 should be evaluated before rig move as to whether it will require well house removal and shut in for rig move. Close Well List: Close Approach Shut-in Wells: There are NO close approach wells requiring subsurface isolation for this profile. 12-%" Hole Section: Surface Gyro will be needed (run to 900-1,200' as conditions dictate) Open Hole: MWD 1 GR Cased hole: None 8-%" Hole Section: MWD 1 GR 1 Res 1 Den 1 Neu 1 PWD (Den Neu recorded only) o & Nb sand drillpipe conveyed MDT fluid samples Cased Hole: USIT Bond Log L-103i L-201 L-119 16.53-ft 53. 74-ft 59.36-ft 500.00-ft 1600.00-ft 652. 32-ft Survey and Logging Program Mud Program 12 %" Suñace Hole Mud Properties: Interval Density (ppg) Initial 8.5 - 9.0 Base Perm 8.5 - 9.0 Interval TD 8.5-9.0 8 %" Intermediate Hole Mud Properties: Funnel vis 250-300 250-200 200-250 Interval Mainbore 8,392' MD I Den~)1 YP 26-35 8.83-ft 21.61-ft 48.83-ft Use Traveling Cylinder (Gyro) Use Traveling Cylinder Use Traveling Cylinder I Spud - Freshwater Mud YP PH FL 50-70 8.5-9.0 NC-8.0 30-45 8.5-9.0 8.0 30-40 8.5-9.0 5.0-7.0 Freshwater Mud (LSND) PH: 9.0-9.5 <600 Chlorides PV API Filtrate I MBT 12-18 4-6 < 20 3 · Great.udhoe Bay Orion L-216i Permit Formation Markers (Based on Schlumberger WP6/P11) SV6 -895 989 973 412 8.8 No Fault 1 ('L Pad Fault') -1330 1486 1408 SV5 -1475 1703 1553 679 8.8 No SV4 -1600 1907 1678 736 8.8 Poss. Gas Hydrates Base Permafrost -1640 1982 1718 754 8.8 No SV3 -1970 2678 2048 906 8.8 Poss. Gas Hydrates .p SV2 -2150 3017 2208 989 8.8 Poss. Gas Hydrates SV1 -2485 3717 2538 1143 8.8 Poss. Free Gas UG4 -2775 4375 2648 1260 8.7 Thin coal UG4A -2805 4438 2878 8.7 75' heavy oil betw 1275 2805 and 2900' SS Fault 2 -3085 5040 3163 UG3 -3125 5223 3248 1412 8.7 Thin coals UG1 -3570 6241 3728 8.8 130' heavy oil betw 1625 3780 -3940' SS Top Schrader Bluff/Ma 6867 4023 Heavy Oil betw 3940 - Sand -3940 1810 8.8 3980' SS Mb1 -3985 6962 4068 8.8 Heavy Oil betw 3985 - 1830 4055' SS Mb2 -4055 7111 4138 8.7 Heavy Oil betw 4055 - 1840 4150' SS Mc -4150 7312 4233 8.7 Possible Heavy Oil 1880 betw 4150 - 4200' SS. Na -41 95 7397 4273 1905 8.7 No Nb -4215 7438 4293 1910 8.7 No Nc -4262 7536 4343 1925 8.7 No OA -4350 7692 4428 1960 8.7 No OBa -4415 7795 4488 2020 8.8 No OBb -4462 7877 4538 2050 8.8 No OBc -4520 7964 4593 2070 8.8 No OBd -4570 8042 4643 2080 8.8 No OBe -4640 8151 4713 2105 8.7 Yes OBf -4675 8221 4758 2110 8.7 Yes OBCBase -4725 8291 4803 2140 8.7 No T.D. -4790 8392 4868 Casingrrubing Program 48" 20" X 34" 215.5# A53 Welded 85' 29' 1 29' 114' 1114' 12-%" 9-%" 40# L-80 BTC 5,750 3,090 3,900' 29' 1 29' 3,929' / 2,638' 8-%" 7" 26# L-80 BTC-M 7,240 5,410 8,363' 29' / 29' 8,392' / 4,868' Tubing 4%" 12.60# L-80 TCII 8,430 7,500 7,663' 29' / 29' 7,692' / 4,428' Tubing 3%" 9.30# L-80 TCII 10,160 10,530 349' 7,692' / 4,428' 8,041' /4,643' 4 · Greate9dhoe Bay Orion L·216i Permit Cement Calculations Casin~ Size I 9-%-in 40-lblft L-80 BTC - Single Stage Basis I 250% excess over gauge hole in permafrost interval, 30% excess over gauge hole below permafrost Total Cement Volume: Tam Port collar located at 1,000' (as contingency only if losses/running gravel) S...........p........a.....ce..........r... ............8.............0..................b........b...........I...S........~O.....f.V................'...............s...........I....fi........I.....e............d..........S..........p.....a.....c......e..........r.........w............e.............I.....g.........h........t......e....d..............t..o..............1.......0............6............o................p.........p.........g..........(....M............U.....d................p.............u.........s.......~....h.................... Lead 459 bbls ~ks) 10.7Ib/gal ASL (G + adds) - 4.28 cuftlsk ./ Tail 73 bbls sks) 15.8 Ib/gal Class G + adds - 1.17 cuftlsk ,r Temp I BHST =='68° Ffrom Temp Log, BHCT8Ô~ F'èstÙnat~d by'S~hlumb;;g;;···· In the event that cement is not circulated to surface during the initial surface casing cement job, notify the AOGCC of the upcoming remedial cement work for possible witness of cement to surface. Casine Size I 7" 26 Ib/tt L-80 BTC-M - Single Stage Basis I 30% excess - TOC: 600' MD above the Ma sands (planned Top Ma: 6,962' MD) => 6,267' MD Total Cement Volume: Wash 20 bbls CW100 Spacer 35 Tail 74 Temp BHST Spacer (Mud push II Design) Weighted tQ 10.3 ppg 15.8 G + Gasblok - 1.20 cuftlsk " Temp Log, BHCT 80° F estimated by Schlumberger 9-%" Casing Centralizer Placement a} Run (25) 9-%" Bow-spring centralizers attached over the collar of each joint of casing from the casing shoe up to 3,506' MD (1,000' MD above the shoe). b} Run 2 Bow-spring centralizers on either side of the TAM Port Collar (contingency only). c} This centralizer program is subject to change due to actual hole conditions. 7" String Centralizer Placement a} Place 2 rigid straight blade centralizers back to back at the very bottom of the shoe joint. Do not run any centralizers on the next two full joints. b} With the exception stated above, run one centralizer per joint, floating across the entire joint up to 6,267' MD (600' MD above Ma sand). Zonal isolation with cement is required across the Ma sands. The centralizer program is subject to change pending modeling and hole conditions. Bit Recommendations Surface Surface Interm. 12- y.¡" 12-X" 8-% 0' - 1 ,982' 1 ,982' - 3,929' 3,929' - 8,392' Hughes MXC-1 Hughes MXC-1 Hycalog DS70NPV 18/18/18/16 18/18/18/16 6x14 Motors and Required Doglegs 3 9-%" Anadrill A962M3445 Mud Motor, 1.5° ABH with 12- y.¡" string stabilizer (gyro to 900-1 ,200') 6-%" Anadrill A675M4570XP Mud motor, with 1.15° ABH with 7.0" string stabilizer 400 - 700 60-80 gpm 500 - 600 60-120 gpm 1.5°/100' initial build 4.0°/100' final build 62° Max in Tangent 1&2 5 . Greate.dhoe Bay Orion L-216i Permit Well Control Well control equipment consisting of 5,000 psi working pressure pipe rams(2}, blind/shear rams, and annular preventer will be installed and are capable of handling the maximum poten~ surface pressures. Based upon calculations below, BOP equipment will be tested to 4,000 psi. Due to test pressures not exceeding 5,000psi it will not be necessary to have two sets of pipe rams installed at all times. A BOP regular test frequency extension for the L-216i is requested. // Diverter, BOPE and drilling fluid system schematics on file with the AOGCC. Production Section- · Maximum anticipated BHP: 2,140 psi @ 4,725' TVDss - Schrader OBf sand · Maximum suñace pressure: 1,668 psi @ surface (based on BHP and a full column of gas from TD @ 0.10 psi/ft) · Planned BOP test pressure: · Planned completion fluid: 4,000 psi (the 7" casing will be tested to 4,000 psi) Estimated 9.3 ppg Brine / 6.8 ppg Diesel 4,000/250 psi Rams & Valves 3,500/250 psi Annular Disposal · No annular injection in this well. · Cuttings Handling: Cuttings generated from drilling operations will be hauled to grind and inject at DS- 04. Any metal cuttings will be sent to the North Slope Borough. · Fluid Handling: Haul all drilling and completion fluids and other Class II wastes to DS-04 for injection. Haul all Class I waste to Pad 3 for disposal. 6 . Greate.dhoe Bay Orion L-216i Permit Drillina Hazards and Continaencies POST THIS NOTICE IN THE DOGHOUSE I. Well Control A. The Schrader in the Polygon 1 a fault block is expected to be normal pressured at 8.7-8.8 ppg EMW. This pressure is estimated based on offset well pressure tests and MDT pressures. II. Hydrates and Shallow gas A. Gas Hydrates are present at L-pad and have been encountered in wells as close as L-117 and 118 and /' throughout the SV4, SV3, SV2, and SV1. Setting casing through the SV1 should keep hydrate exposure from extending past the surface hole, however recommended practices and precautions for drilling hydrates should be followed in the surface hole. III. Lost Circulation/Breathing A. Lost circulation is not expected due to the benign nature of L Pad fault and the second deeper fault in the UG4A. . Note: Massive losses were encountered in L-118 due to high penetration rates (1100-1300 fph) and inadequate hole cleaning strategy. Again in L-119 losses prevented circulation and continuous returns while cementing the 7". B. We do not expect breathing on this well. IV. Kick Tolerance/Integrity Testing A. The 9-%" casing will be cemented to surface. B. The 7" casing will be cemented with 15.8Ib/ I ce ent to 600' MD above the Ma sand -6,267' MD. / C. The Kick Tolerance for the surface casing' 60.0 Is with 9.3 ppg mud, 11.5 ppg LOT, and an 8.8 ppg pore pressure. If the LOT is 11.2 ppg or le- W, then the kick tolerance will be < 50 bbls. D. Integrity Testing LOT 11.5 minimum 9-%-in shoe V. Stuck Pipe A. We do not expect stuck pipe. L-119 did however stick pipe while reaming tight hole at 2,687 TVD in the intermediate section due to hole not being adequately clean. The pipe was backed off and recovered. VI. Hydrogen ~Ifide L Pad is nor designated as an H2S site, however Standard Operating Procedures for H2S precautions should be followed at all times. No measurable H2S is being produced from the formation at this time. However 10 ppm has been measured as recently as January 2003 at both L and V pads as a result of the use of Ivishak gas lift gas. All V and L pad gas lift wells will likely have H2S in this concentration. Note that all injection has been with produced water not seawater. H2S levels are expected to remain low until the waterflood matures. Recent H2S data from the pad is as follows: o Adjacent producers at Surface: L-119 10 ppm L-200 10 ppm o Adjacent producers at TD: L-200 10 ppm 7 · Greateedhoe Bay Orion L-216i Permit VII. Faults A. Fault 1 is the 'L-Pad Fault' and has been intersected in the surface hole by most wells drilled from L Pad to date. Fault #2 has been penetrated several times without incident in wells including L-110, L-119, L-210. The fault details are listed below for reference: Fault 1 (SV6): 1486' MD Fault 2 (UG4A): 5,040' MD 1408' TVD 3,163' TVD 1330' TVDss 3,085' TVDss Throw: 100' West Throw: 60' Southwest CONSULT THE L PAD DATA SHEET AND THE WELL PLAN FOR ADDITIONAL INFORMATION 8 · Greateedhoe Bay Orion L-216i Permit Drill and Complete Procedure Summary Pre-Rig Work: 1. The L-216i Conductor has been set in slot L-NR. See As-Built for coordinates. 2. Weld an FMC landing ring for the FMC Gen 5 Wellhead on the conductor if not already complete. 3. If necessary, level the pad and prepare location for rig move. 4. Prepare neighboring wells for the rig move and simops production. Shut in L-103i. ***AII pre-rig work should be charged off against the predrill AFE # ORD5M3554*- Rig Operations: 1. MIRU Nabors 9ES. / 2. Nipple up diverter spool and function test diverter. PU 4" DP as required and stand back in derrick. /' 3. MU 12-X" drilling assembly with MWD/GR and directionally drill surface hole to approximately 3,929' MD. The actual surface hole TD will be +1-100' TVD below the top of the SV1 sands. 4. Run and cement the 9-%", 40.0-lb/ft. surface casing back to surface. A TAM Port Collar or stage tool should be / on location. If losses are encountered while drilling surface or large washouts are anticipated the port collar/stage tool will be run in the casing string to allow secondary cementing, (in the event cement is not circulated to surface during primary cementing operations). ~ 5. ND diverter spool and NU casing / tubing head. NU BOPE and test to ,00 psi. 6. MU 8-%" drilling assembly with MWD/GR/Res/Den/Neu(recorded}/P . and RIH to float collar. Test the 9-%" casing to 3,500 psi for 30 minutes. 7. Circulate and condition cement contaminated mud. Displace over to new 9.3 ppg mud 8. Drill new formation to 20' below 9-%" shoe and perform LOT (minimum 11.5 ppg EMW). / 9. Drill ahead to Polygon 1A Schrader injection target and continue to TD at 8,392' MD (base of OBd target plus 250'). 10. Circulate and condition hole, make a short trip, TOOH to run casing. / 11. Run and cement the 7" production casing as required to cover all significant hydrocarbon intervals. Displace the casing with 9.3 ppg mud or seawater during cementing operations. Pressure test casing to 4,000 psi for 30 minutes at plug bump. Freeze protect the 7" x 9-%" annulus. 12. PU used bit and scraper and RIH with 4" DP while waiting on cement to PBTD ±8,310' MD. Displace out the mud / seawater with 9.3 ppg brine. POOH and LD BHA. Note: It is not necessary to change to pipe rams fyr scraper run as casing has been tested. 13. RU Schlumberger E-line and run a USIT/GR log. /' 14. RU Schlumberger and perforate Nb, OA, OBa wI 185' of 4.5" 40' each Power Jet Guns set at 5 spf in 5runs. / Depths based on USIT/GR logging run. (GR only used on first run if 40' guns are used.) 15. RIH w/ gage ring and junk basket to recover any perf debris. Repeat until clean. 16. M/U Schlumberger SXAR Gun Drop assembly consisting of 90' of 4-1/2" PowerJet Guns at 5 spf. /" 17. Run the 4-Y2" X 3-Y2", L-80 TCII completion with a 7" x 3-Y2" straddle packer assembly and injection mandrels (torque turn connections). 18. Make GR e-line correlation run, correct gun setting depth and tubing hanger spaceout. 19. Run in the lockdown screws and set the packers. Test the production casing/tubing annulus and tubing to 4,000 psi each. Shear the DCK shear valve. 20. Install FMC TWCV. Nipple down the BOPE. Nipple up and test the tree to 5,000 psi. / 21. Freeze protect the well to -2,500' TVD. Install BPV in tubing hanger. Install a VR plug in the 7"x 4-Y2" annulus valve and secure the well. 22. Rig down and move off. Post-Rig Work: 1. R/U Slickline and pull ball and rod I RHC from the tailpipe. 2. Replace the DCK shear valve with a dummy GL V. 9 · Greate.dhoe Bay Orion L-216i Permit 3. Install tiring head on SXAR system and tire guns. 4. Pull dummy valves in injection mandrels and replace with injection valves. 5. Pull VR plug. 10 · Greateedhoe Bay Orion L-216i Permit Job 1: MIRU Hazards and Contingencies: ~ Ensure the starting head has been welded on the conductor at the right height and there is adequate space to NU the diverter and subsequently the BOP once the rig is spotted (LL on W-212i). ~ Ensure the AOGCC receives 24-hour advance notification of the diverter test and subsequent BOP tests. ~ L-103i and possibly L-201 will have to be shut in and require well house removal before rig can be moved over the well. Job 2: Dril/12W' Surface Hole Hazards and Contingencies: ~ At L-Pad, no significant surface hole drilling problems have been identified. Tight hole, bridging, and obstructions have been encountered while drilling the Permafrost. In only one case has an obstruction caused the well to be sidetracked. Lost circulation has not been a problem on L-pad. Some minor tight hole has also been encountered below the Permafrost. ~ Hydrates: Hydrates are present at L-pad from the base of the Permafrost all the way through the SV-1 sand and should be treated with conventional practices: pretreating mud, cooling mud, increasing weight, etc as per MI program recommendations. On the L-115 hydrates were encountered at 1667' SS at the base of the Permafrost with gas showing as high as 2400 units. The section was TD'd without incident after traditional methods for treating hydrates were incorporated. The mud did however remain light after drilling through the hydrates. ~ Close Approach: The L-103i and L-201 are required to be shut in and have their well houses removed due to surface location proximity to the L-216i. In addition there are several close tolerance wells in the surface interval. Follow the traveling cylinder / no-go plot per established procedures. A gyro should be run to at least 900'-1200'. ~ Directional: Every effort should be made to ensure a 'smooth' well profile that will benefit torque / drag in the later hole sections and allow for easier 9 5/8" casing running. A graduated build profile is planned. It is preferred that DLS are pushed ahead of plan on the suñace hole, (but no higher than ;t5 deg/100), so as to lower the tangent angle and facilitate post well work. L-211 i surface hole did not build fast enough with a 1.5 deg bent housing and had to be tripped for a 1.83. It is felt that this was a surface geology anomaly, however similar practices should be followed in angle is not being built quickly enough. ~ Hole Cleaning: Good hole cleaning practices will be critical to the success of the well. Surface rotary speeds should be maximized wherever possible. The BHA is limited to 60 to 80-rpm while drilling because of the 1.50 motor bend. Vary flowrates 400-650 GPM to achieve the required directional response. However it will be possible at TD to raise the rotary speed to +100-rpm prior to POOH to run casing. At this time flow rates should be increased to 650 - 700 GPM to increase hole cleaning. ~ Tight spots: During short trips, work out any tight spots as they are seen while pulling out of the hole instead of waiting and reaming them out after running back in the hole as this could lead to accidental sidetracking. Consider back-reaming across initial tight spots only if washing does not alleviate the problem. If tight spot is thought to be cuttings, run back in the hole at least the length of the BHA and circulate and condition the hole for a minimum of 30 minutes at max RPM's and GPM's. ~ Critical LWD Tools: It is critical for the landing of this hole section to have the GR to pick the base of the SV1 sand. If this tool fails, it will require an immediate trip out of the hole to replace. It is 11 · Greateedhoe Bay Orion L-216i Permit imperative that the surface casing isolates all of the SV1 sands. --- ~~ Job3: Install Surface CasinQ Hazards and Contingencies: > Casing to bottom: It is imperative the casing is set in the shale below the SV1 sands to ensure wellbore integrity for the intermediate interval. It may be desirable to stop and roll the mud over half way in the hole to break the gels and reduce surging intensity on the SV sands. This will also help to ensure circulation is attained at TD at the desired cementing rates without losses. Make sure that the hole is clean and obstructions are minimized before running casing as higher doglegs and aggressive directional work could make casing running more difficult. > Casing drift: 9-%" special drift casing is being used (8.835" drift required). Ensure that casing equipment is properly drifted to ensure adequate ID for the 8-%" bit, Le. float equipment, casing hanger, etc. > Cement to surface: A single-stage job will be done on this well using 250% excess in the permafrost and 30% excess below the permafrost. A TAM Port collar can be placed at 1,000-ft MD if losses are encountered or indications are that gravel is running or the whole is washing out. (Port Collar was run on L-210i, but not used due to higher shale content on surface hole section. L-216i will have similar lithology). > Losses during cement job: At L-Pad lost circulation has not been experienced while running and cementing surface casing on past wells. The expected frac gradient for the shale below the SV1 sands is at least 12.7 -Ib/gal EMW. Follow the Schlumberger recommended pumping rates as they have modeled the expected ECD's during the entire cement job to help mitigate the potential for breaking down the formations. Job 4: Drill 8*" Production Hole Hazards and Contingencies: > Differential Sticking could be a problem if lost circulation is occurring or if the drill string is left stationary for an extended period or time across the permeable Schrader Sands. > LOT: Perform a L inimum 11.5 ppg EMW to satisfy kick tolerance). KICK TOLERANCE: Based upon the max e ected/Schrader reservoir pressure of 8.8 ppg, 9.3 ppg mud, and an 11.5 ppg leak-off will provide ov r JR/. 5 of kick tolerance. Contact Anchorage personnel if LOT is less than 11.5 ppg. Based u -set drilling data on L-Pad, a minimum leak-off of 13.3 ppg is expected at the 9-%" shoe. t:.ø W61t" > Penetration Rate: Penetration rates should not exceed 600 fph instantaneous. This should allow for ECDs not to exceed 0.6ppg above calculated. If ECDs exceed this threshold, stop and circulate before continuing. ECD should not exceed 11.0 ppg once the M sand has been penetrated. > 7" casing landing point: The 7" casing setting point will be determined by depth based on changes in GRlRes curves associated with the base OBd sand. After seeing the base OBd, TD will be picked based on drilling 250' MD past this base. This footage is critical for future well work. If tops are coming in 100' or more out from proposed, then conduct a short trip and notify town. A Rigsite Geologist will be required on site to pick casing point. > Torque: Modeling indicates that high torque values, as high as 12,000 ft-Ibs can be expected by section TD. Use lubricants as per the MI program as necessary. If weight transfer problems are encountered during sliding, attempt to circulate and rotate for a minimum of 2 bottoms up to test if lubricants are truly needed or if the hole is loading up with cuttings. /' 12 · Greateedhoe Bay Orion L-216i Permit ~ Critical LWD Tools: It is critical to have the GR tool in order to pick the landing pOints for the intermediate hole sections. As mentioned above in the landing point discussion, the landing of this well depends on picking the base of the OBf and OBd sands using the Gamma Ray. Therefore if the GR tool is lost, a trip will have to be made to change it out. ~ Faults: Two faults will be crossed in the L-216i with one in the SV6 and one in the Ugnu UG4a. Fault 1 is the 'L-Pad' fault and has been crossed in the surface hole by most wells drilled from L Pad to date. Fault #2 has been penetrated several times without incident in wells including L-110, L-119, L-210. The fault details are listed below for reference: Fault 1 (SV6): 1486' MD Fault 2 (UG4A): 5,040' MD 1408' TVD 3,163' TVD 1330' TVDss 3,085' TVDss Throw: 100' West Throw: 60' Southwest ~ Directional Constraints: It is important to not let the angle get much higher than planned, due to high angle tangent angle and the difficult slickline access. It is important to design a BHA to minimize inclination walking tendencies thus minimizing wellbore tortuousity. DLS should be kept as close as possible to ::;;10 over planned. Dogleg will take priority over angle as long as tangent angle does not approach 68 degrees. --.,.- - Job 6: Install 7" Production Casinø Hazards and Contingencies: ~ Tight hole, packing off and lost circulation have been experienced while drilling though this interval. Good hole cleaning, mud conditioning, and drilling practices are required for trouble free drilling. In numerous cases tight hole has made backreaming necessary with stuck pipe and lost returns on only two wells. ~ Centralization/Differential Sticking: See centralizer strategy on page 5. Differential Sticking could be a problem if lost circulation is occurring or if the casing is left stationary for an extended period or time across the permeable sands. Ensure the casing is centralized across any permeable zones if the casing is left stationary while running in the hole. ~ RA Tags: There will need to be 2 RA tags placed in the 7" casing for depth control. Placement strategy is: o Pip #1: Top Ma Sand o Pip #2: 40-60' above top OA sand ~ Cement Job: It is imperative to achieve a good cement job on this well to achieve zonal isolation and effective injection control. Therefore reciprocate pipe as long as possible while cementing. A USIT log will be run to confirm the quality of the cement job and height of cement top above the Ma sand. Keep cementing ECD's below 12.5 ppg EMW during the displacement. ~ Mud Requirements: Thin the mud as per Ml's Mud Program before cementing. The thinner the mud the better displacement is achieved and the better the cement jOb will be. Extra time spent circulating is warranted to ensure optimum mud properties and hole cleaning prior to the cement job. ~ Franks Casing Fill-up tool: Make sure that a casing fill up tool is on location prior to PU 7" casing. ~ 7" Casing Specifications: 7", 26#, L-80 BTC 100% 80% ID 6.276 6.151 (drift) Collapse 5,410psi 4,328psi Burst 7,240psi 5,792psi Tensile 667,OOOlbs 533,600lbs ~ TIW Valve: Ensure that a TIW valve with a cross over to 7" BTC casing is on the rig floor for casing running. 13 · Greateedhoe Bay Orion L-216i Permit Job 10: Perforate Well (DPC/SXARJ Hazards and Contingencies ~ The well will be perforated ±130 psi over-balanced. Ensure all personnel are well briefed on Schlumberger's perforating procedures and that all responsibilities are understood. ~ It should be stressed that while picking up and running the perforating guns, only essential personnel should be on the rig floor. Normally "essential personnel" will consist of the driller, floorhands, perforating crew and the Schlumberger hand. All other personnel will stay off the rig floor and out of the cellar until the perforating string is at least 100-ft below the rotary table. ~ Contact Schlumberger to prepare for approximately 185' of 4-112" Power Jet guns at 5 spf to be run on wire, and 90' of 4 Y;¡" Power Jet guns at 5 spf to be run with the completion using the SXAR gun drop system. Exact perforation depths will be provided after reviewing the lWD logs. ~ Be prepared for fluid losses to the formation after perforating. Have ample seawater on location and be prepared with lCM if necessary. Follow the lCM decision tree for "After Perforating". ~ Perf guns should be logged on depth initially using GR and subsequently only with CCl so as to lessen the stress on the tools and prevent failure. This is especially important when using 40' guns. Position guns by E-line measurement from USIT run for e-line perforating and by utilizing the Schlumberger GR tool in the string and RA tags for SXAR perforating. Reference RP: .:. 'Schlumberger E-line and SXAR Procedures' .~ -.c. ú, __ Job 12: Run Comø/etion Hazards and Contingencies: ~ Dirty Hole: It is critical to have a clean hole to run this completion due to the production packer. Take time if deemed necessary to run a GRlJB. If the packer partially prematurely sets, set it all the way and run in and chemical cut and remove the completion. ~ Torque turn Tell completion connections to help assure that they doesn't leak when the well is put on MI. Reference RP: .:. 'Completion Design and Running' RP Job 13: ND/NU/Re/ease Ria Hazards and Contingencies: ~ Diesel will be used to freeze protect the well. The diesel flash point Is 1000 F. Diesel vapor pressure is - 0.1 psia at 1000 F. 14 I tr.. 3-1/2" x 1-1/2" injection Mandrels MD .. s ."'~._'_. ._~,-- _._- _..._ H..__ . . w a:: I -~~ I PLANT L1S'OO'OO' GRID L -PAD . N-L (NWE-1) L-111i. · N-A (NWE-2) · L-113 L-114. · L-124 L-SD · · L-112i · L-02 L-121 . · L-122 L-110. · L-211i L-SI · · L-115i L-116 . · L-117 L-109 . · L-118 f L-SL · L-01 · L-200+ L-107 . I SKID 502 I œ; / L-108i. '" L-2161 L-105i. ¡: L-103i L-106 . D_ · L-201 L-104 . · L-119i s-w · ,L-210i L-102 . D~ L-120 VICINITY MAP N.T.S. LEGEND -+- AS-BUILT CONDUCTOR . EXISTING CONDUCTOR SkID 513 ~ ) SURVEYOR'S CERTIFICATE I HEREBY CERT1FY THAT I AM PROPERLY REGISTERED AND UCENSED TO PRACT1CE LAND SURVEYING IN THE STATE OF ALASKA AND THAT THIS PLAT REPRESENTS A SURVEY MADE BY ME OR UNDER MY DIRECT SUPERVISION AND THAT ALL DIMENSIONS AND OTHER DETAILS ARE CORRECT AS OF JANUARY 4, 2004. .""Ot ~ /;/ ç"" NOTES .. , :! I 1. DATE OF SURVEY: JANUARY 4, 2004. 2. REFERENCE FIELD BOOK: W004-01 PAGES 01-03. 3. ALASKA STATE PLANE COORDINATES ARE ZONE 4, NAD 27. GEODEllC POSI1l0NS ARE NAD 27. 4. BASIS OF HORIZONTAL LOCAllON IS L-PAD OPERATOR MONUMENTAT10N. 5. BASIS OF ELEVA1l0N IS L-PAD OPERATOR MONUMENTS. ELEVA1l0NS ARE BP MSL DAlUM. 6. MEAN PAD SCALE FACTOR IS 0.999907827. h j ... 3 ;; > .. 5 ~ " 0/ ... " > .. i ~ > LOCATED WITHIN PROTRACTED SEC. 34, T. 12 N., R. 11 E.. UMIAT MERIDIAN, ALASKA WELL A.S.P. PLANT GEODETIC GEODETIC CELLAR SECTION NO. COORDINATES COORDINATES POSITION(DMS) POSITION(D.DD) BOX ELEV. OFFSETS L-216i y= 5,978,309.19 N= 10,000.15 70'21'02.544" 70.3507067" 499' 2,586' FSL X= 583,281.61 E= 5,294.89 -149'19'25.793" -149.3238.314' . 3,632' FEL L-200 Y= 5,978,289.74 N= 10,000.09 70'21'02..361" 70.3506558' 49.1' 2,568' FSL X= 583,209.27 E= 5,219.97 -149'19'27.914" -149..3244206' 3,704' FEL I r' 1Œ:~' ORA...., ObP COTTON CHECKEO'O'HANl£Y DATE: 3/22/04 ORAWlNG: GPB WOA L-PAD SHEET: FRB04 WOl 04--00 ¡~O JOB NO: SCAlE: AS-BUILT CONDUCTORS 1 OF 1 CNIiIICUIIMG.....~ YÆUS L-200 & L-216i JJG LOH ., tEaT IImIIŒD LAM[ 1'· 130' BY CHI< - ..... -. ~-- ~ i ! ~ í 0 ,3/22/04 ISSIJ£\) FOR _AlION ., NO. DAlE RE'AS1ON L-216 (P2) Proposal S Report Oats: March 22, 2004 Survey I DLS Computation Method: Minimum Curvature / Lubinski Client: BP Exploration Alaska Vertical Section Azimuth: 29.300° Field: Prudhoe Bay Unit - WOA d Vertical Section Origin: N 0.000 ft, E 0.000 ft Structure I Slot: L·PAD /N-R '"ty Stll Y TVD Reference Datum: KB Plan L·216 (N·R) .. II TVD Reference Elevation: 78.40 ft relative to MSL Well: Feas. bill Sea Bed I Ground Level Elevation: Borehole: Plan L-216 49.90 ft relative to MSL UWl/API#: 50029 Magnetic Declination: 24.971" Survey Namel Oats: L -216 (P2) / March 22, 2004 Total Field Strength: 57563.343 nT Torti AHD I DDI/ERD ratio: 76.113° /6320.29 ft/5.919/1.298 Magnetic Dip: 80.824° Grid Coordinate System: NAD27 Alaska State Planes, Zone 04, US Feet Declination Dste: May 07, 2004 Location LatJLong: N 70.35070667, W 149.32383138 Magnetic Declination Model: BGGM 2003 Location Grid NlE Y/X: N 5978309.190 ftUS, E 583281.610 ftUS North Referenca: True North Grid Convergence Angle: ..{).63679766° Total CorrMag North -> True North: +24.971" . Grid Scale Factor: 0.99990788 Local Coordinates Referenced To: Well Head Comments Measured , Inclination , Azimuth , TVD I Sub-Sea TVD I Vertical I Along HOle, NS EW I DLS 'BUild Rats I Walk Rats , Tool Face I Northing Easting Latitude Longitude I Depth Section Departure (II) (dog ) (deg) (II) (II) (II) (II) (II) (II) (dog/100 II) (deg/100 II) (degl100 II) (dog) (IIUS) (IIUS) RTE 0.00 0.00 10.00 0.00 -78.40 0.00 0.00 0.00 0.00 0.00 0.00 0.00 10.00M 5978309.19 583281.61 N 70.35070667 W 149.32383138 KOP Bild 1.5/100 300.00 0.00 10.00 300.00 221.60 0.00 0.00 0.00 0.00 0.00 0.00 0.00 10.00M 5978309.19 583281.61 N 70.35070667 W 149.32383138 Bid 3/100 400.00 1.50 10.00 399.99 321.59 1.24 1.31 1.29 0.23 1.50 1.50 0.00 10.00M 5978310.48 583281.82 N 70.35071019 W 149.32382954 500.00 5.00 10.00 499.81 421.41 6.59 6.98 6.87 1.21 3.50 3.50 0.00 10.00M 5978316.07 583282.75 N 70.35072544 W 149.32382155 600.00 8.50 10.00 599.10 520.70 17.68 18.73 18.44 3.25 3.50 3.50 0.00 O.OOG 5978327.67 583284.66 N 70.35075706 W 149.32380498 700.00 12.00 10.00 697.49 619.09 34.47 36.52 35.97 6.34 3.50 3.50 0.00 O.OOG 5978345.22 583287.55 N 70.35080493 W 149.32377990 800.00 15.50 10.00 794.61 716.21 56.90 60.29 59.37 10.47 3.50 3.50 0.00 O.OOG 5978368.67 583291.42 N 70.35086886 W 149.32374640 900.00 19.00 10.00 890.10 811.70 84.88 89.94 88.57 15.62 3.50 3.50 0.00 O.OOG 5978397.92 583296.24 N 70.35094863 W 149.32370460 1000.00 22.50 10.00 983.60 905.20 118.31 125.36 123.45 21.77 3.50 3.50 0.00 O.OOG 5978432.87 583302.00 N 70.35104394 W 149.32365466 Cry 4/100 1100.00 26.00 10.00 1074.76 996.36 157.07 166.42 163.90 28.90 3.50 3.50 0.00 30.12G 5978473.38 583308.68 N 70.35115442 W 149.32359677 1200.00 29.52 14.07 1163.24 1084.84 201.55 212.98 209.40 38.70 4.00 3.52 4.07 26.51G 5978518.99 583317.98 N 70.35127873 W 149.32351720 1300.00 33.15 17.34 1248.65 1170.25 252.09 264.97 259.42 52.84 4.00 3.62 3.26 23.72G 5978569.15 583331.56 N 70.35141537 W 149.32340237 1400.00 36.84 20.02 1330.56 1252.16 308.45 322.30 313.70 71.26 4.00 3.69 2.68 21.52G 5978623.64 583349.38 N 70.35156367 W 149.32325284 1500.00 40.58 22.28 1408.58 1330.18 370.34 384.82 371.99 93.87 4.00 3.74 2.25 19.76G 5978682.17 583371.33 N 70.35172292 W 149.32306933 1600.00 44.36 24.21 1482.33 1403.93 437.47 452.33 434.01 120.54 4.00 3.78 1.93 18.34G 5978744.47 583397.31 N 70.35189233 W 149.32285275 1700.00 48.17 25.90 1551.45 1473.05 509.52 524.58 499.44 151.16 4.00 3.81 1.69 17.17G 5978810.23 583427.20 N 70.35207108 W 149.32260414 e SV5 1702.93 48.29 25.94 1553.40 1475.00 511.70 526.76 501.40 152.12 4.00 3.82 1.58 17.14G 5978812.21 583428.13 N 70.35207646 W 149.32259638 1800.00 52.01 27.39 1615.59 1537.19 586.13 601.27 567.97 185.58 4.00 3.83 1.49 16.21G 5978879.13 583460.85 N 70.35225830 W 149.32232472 1900.00 55.86 28.74 1674.46 1596.06 666.92 682.08 639.27 223.62 4.00 3.85 1.35 15.41G 5978950.84 583498.09 N 70.35245308 W 149.32201584 SV4 1907.04 56.13 28.83 1678.40 1600.00 672.76 687.92 644.38 226.43 4.00 3.86 1.28 15.36G 5978955.99 583500.85 N 70.35246706 W 149.32199301 2000.00 59.72 29.97 1727.76 1649.36 751.51 766.67 712.98 265.11 4.00 3.86 1.23 14.76G 5979025.01 583538.75 N 70.35265446 W 149.32167901 End Cry 2055.55 61.87 30.61 1754.86 1676.46 799.98 815.15 754.84 289.56 4.00 3.87 1.16 O.OOG 5979067.13 583562.74 N 70.35276882 W 149.32148043 SV3 2678.10 61.87 30.61 2048.40 1970.00 1348.84 1364.16 1227.33 569. 14 0.00 0.00 0.00 O.OOG 5979542.65 583837.02 N 70.35405956 W 149.31921031 SV2 3017.43 61.87 30.61 2208.40 2130.00 1648.01 1663.41 1484.87 721.53 0.00 0.00 0.00 O.OOG 5979801.85 583986.52 N 70.35476311 W 149.31797280 SVI 3717.32 61.87 30.61 2538.40 2460.00 2265.05 2280.61 2016.05 1035.83 0.00 0.00 0.00 O.OOG 5980336.44 584294.87 N 70.35621414 W 149.31542016 9-5/8" Csg PI 3929.41 61.87 30.61 2638.40 2560.00 2452.04 2467.64 2177.02 1131.07 0.00 0.00 0.00 O.OOG 5980498.44 564388.31 N 70.35665384 W 149.31464657 UG4 4374.79 61.87 30.61 2848.40 2770.00 2844.70 2860.40 2515.04 1331.08 0.00 0.00 0.00 O.OOG 5980838.63 584584.54 N 70.35757720 W 149.31302190 UG4A 4438.41 61.87 30.61 2878.40 2800.00 2900.79 2916.51 2563.33 1359.66 0.00 0.00 0.00 O.OOG 5980887.23 584612.57 N 70.35770910 W 149.31278980 UG3 5223.13 61.87 30.61 3248.40 3170.00 3592.62 3608.53 3158.89 1712.05 0.00 0.00 0.00 O.OOG 5981486.62 584958.29 N 70.35933593 W 149.30992690 WellDesign Ver 3.1RT-SP3.03-HF4.00 Bld( d031rt-546) N-RIPlan L-216 (N-R)IPlan L-216IL-216 (P2) Generated 3/22/2004 2:44 PM Page 1 of 2 I Comments Measured I Inclination I Azimuth I TVD , Sub-Sea TVD I Vertical I Along HOle, NS EW , DLS 'BUild Rate I Walk Rate , Tool Face I Northing Easting Latitude Longitude Depth Section Departure (It) (dog ) (deg) (It) (It) (It) (It) (ft) (It) (dogI1001t) (deg/100 It) (degI1001t) (dog ) (ltUS) (ftUS) UG1 6241.14 61.87 30.61 3728.40 3650.00 4490. 14 4506.27 3931.52 2169.22 0.00 0.00 0.00 O.OOG 5982264.20 585406.80 N 70.36144635 W 149.30621220 Ma 6866.80 61.87 30.61 4023.40 3945.00 5041.73 5058.01 4406.36 2450.19 0.00 0.00 0.00 O.OOG 5982742.09 585682.45 N 70.36274333 W 149.30392882 Mb1 6962.24 61.87 30.61 4068.40 3990.00 5125.87 5142.18 4478.80 2493.05 0.00 0.00 0.00 O.OOG 5982814.99 585724.50 N 70.36294118 W 149.30358049 Mb2 7110.70 61.87 30.61 4138.40 4060.00 5256.76 5273.10 4591.47 2559.72 0.00 0.00 0.00 O.OOG 5982928.39 585789.90 N 70.36324893 W 149.30303861 Me 7312.18 61.87 30.61 4233.40 4155.00 5434.39 5450. 78 4744.39 2650.20 0.00 0.00 0.00 O.OOG 5983082.29 585878.67 N 70.36366659 W 149.30230319 Orp 2/100 7365.85 61.87 30.61 4258.71 4180.31 5481.71 5498.11 4785.12 2674.30 0.00 0.00 0.00 -175.34G 5983123.28 585902.32 N 70.36377786 W 149.30210727 Na 7396.70 61.25 30.56 4273.40 4195.00 5508.84 5525.24 4808.48 2688. 11 2.00 -1.99 -0.19 -175.31G 5983146.79 585915.86 N 70.36384165 W 149.30199508 7400.00 61.19 30.55 4274.99 4196.59 5511.72 5528.13 4810.96 2689.57 2.00 -1.99 -0.19 -175.31G 5983149.29 585917.30 N 70.36384844 W 149.30198314 Nb 7437.76 60.43 30.48 4293.40 4215.00 5544.68 5561.09 4839.36 2706.31 2.00 -1.99 -0.19 -175.27G 5983177.87 585933.72 N 70.36392600 W 149.30184711 7500.00 59.19 30.36 4324.70 4246.30 5598.47 5614.89 4885.76 2733.55 2.00 -1.99 -0.19 -175.21G 5983224.56 585960.44 N 70.36405272 W 149.30162568 Ne 7536.14 58.47 30.29 4343.40 4265.00 5629.39 5645.82 4912.45 2749.17 2.00 -1.99 -0.20 -175.17G 5983251.43 585975.76 N 70.36412563 W 149.30149876 7600.00 57.20 30.16 4377.39 4298.99 5683.44 5699.88 4959.16 2776.38 2.00 -1.99 -0.20 -175.11G 5983298.43 586002.44 N 70.36425321 W 149.30127756 L-216 Tgt 1 OA 7691.90 55.37 29.97 4428.40 4350.00 5759.87 5776.32 5025.31 2814.67 2.00 -1.99 -0.21 O.OOG 5983365.00 586040.00 N 70.36443390 W 149.30096626 . OA 7691.92 55.37 29.97 4428.41 4350.01 5759.89 5776.33 5025.33 2814.68 2.00 -2.00 -0.08 -178.19G 5983365.01 586040.01 N 70.36443394 W 149.30096620 7700.00 55.21 29.96 4433.01 4354.61 5766.53 5782.97 5031.08 2818.00 2.00 -2.00 -0.08 -178.19G 5983370.80 586043.26 N 70.36444966 W 149.30093922 OBa 7794.83 53.31 29.89 4488.40 4410.00 5843.50 5859.94 5097.79 2856.40 2.00 -2.00 -0.08 -178.14G 5983437.93 586080.91 N 70.36463185 W 149.30062708 7800.00 53.21 29.88 4491.49 4413.09 5847.64 5864.09 5101.38 2858.46 2.00 -2.00 -0.08 -178.14G 5983441.54 586082.94 N 70.36464166 W 149.30061030 OBb 7876.95 51.67 29.82 4538.40 4460.00 5908.63 5925.08 5154.28 2888.83 2.00 -2.00 -0.08 -178.10G 5983494.77 586112.71 N 70.36478615 W 149.30036347 7900.00 51.21 29.80 4552.77 4474.37 5926.66 5943.11 5169.92 2897.79 2.00 -2.00 -0.09 -178.09G 5983510.51 586121.49 N 70.36482887 W 149.30029063 End Orp 7960.42 50.00 29.75 4591.11 4512.71 5973.34 5989.80 5210.45 2920.97 2.00 -2.00 -0.09 O.OOG 5983551.29 586144.22 N 70.36493955 W 149.30010215 OBe 7963.98 50.00 29.75 4593.40 4515.00 5976.07 5992.53 5212.82 2922.33 0.00 0.00 0.00 O.OOG 5983553.67 586145.55 N 70.36494603 W 149.30009113 OBd 8041.77 50.00 29.75 4643.40 4565.00 6035.67 6052. 12 5264.56 2951.90 0.00 0.00 0.00 O.OOG 5983605. 73 586174.54 N 70.36508734 W 149.29985075 OBe 8150.68 50.00 29.75 4713.40 4635.00 6119.09 6135.55 5336.99 2993.30 0.00 0.00 0.00 O.OOG 5983678.61 586215.13 N 70.36528518 W 149.29951421 OBf 8220.69 /50.00 29.75 4758.40 4680.00 6172.73 6189.18 5383.56 3019.91 0.00 0.00 0.00 O.OOG 5983725.47 586241.22 N 70.36541237 W 149.29929785 TD/7"Csg pt 8391.83 . 50.00 29.75 4868.40 4790.00 6303.83 6320.29 5497.38 3084.96 0.00 0.00 0.00 O.OOG 5983840.00 586305.00 N 70.36572326 W 149.29876898 Leç¡al Description: Northinq IV) IftUSl Eastinq IX) IftUSl Surraee 2586 FSL 3632 FEL 534 T12N R11E UM 5978309.19 583281.61 L-216 Tgt 1 OA 2331 FSL 808 FEL 527 T12N R11 E UM 5983365.00 586040.00 TO I BHL 2803 FSL 537 FEL 527 T12N R11 E UM 5983640.00 586305.00 e WeliOesign Ver 3.1RT-SP3.03-HF4.00 Bld( d031rt-546) N-RIPlan L-216 (N-R)IPlan L-216IL-216 (P2) Generated 3/22/2004 2:44 PM Page 2 of 2 g o o o ...-- ~ ...-- II Q) -æ o C/) o ~ Schlumbørger WEll FIELD Prudhoe Bay Unit - WOA STRUC1\IRE L-PAD L-216 (p2) _""'"'"- Model; BGGM 2003 SulfaceLocation lat N7D212.544 Lon: W1491925.793 TVD Ref: KB (78.40 n. above MSL) SNyDate: Mard122,2004 NAD27 Alaska Stale PtanB$. Zooe 04. US Feet Northing: 5978309.19nUS GridConv: +0.63679766" Easting: 583281.61 !'IUS 8caI9Fact; 0.9999078789 Miscellaneous Slot: N-R Plan: L-216 (P2) Dip: 80.824' Mag Dee: +24.971' """, FS: May 07. 2004 57563.3nT o 2000 7000 5000 6000 1000 3000 4000 o . . . . . , . , , . m_~~.;~=~m'm_m-Immmlmm_ml . . . . -r-m¡mm 1000 .u",.................... ,.... 2000 -_....-_..:=..:-_....-_:~:::::.-_....-_....-_....:...._.._. t:.··_··_··...··_··...··...··_··_H...~................_.._.._..........··...·r··...··...··...··...··...··...··...··...··1··-··...··....··...··...··...··...··...··...1·...··...··...··...··...··...··...··...··-··r··...··...··...··-··...··...··...··...··1··...··...··...··...· - - -"1"'-"-" -"-00_00_" _oo-"T-" -..-.. -"-"-"-"-"-r,,-,,-,,-,,_oo_"-"-"-'T'-' .-..-..-..-.. -.. -. 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'::':::::":'::';';':::" :::':':':'::::':~:;':<: :::.:.:.:.::.:.:::::.:.:.:':'::::~.::.::':::::::': ~;;~;;~;;~;;~;!~;;~;:~;;~;;~;;~;;~;;~;;~;t~;;~;;~;;~;;~:;~;;~;;~;;~t~;;~;;~;;~;;~;;~;;~;;~;;~;t;;~;;~:;~;;~;;~;;~;;~;;~:;t~;;~:;~;;~;;~:;~;;~;;~;;~¡;~;;:;;;;;=:·-·;;;;~;;~;;:::~:¡~J~;Ç§i;~;;~;;~;;~;;~;;~;;~;;~;:~; ~~~~~!~~~~~~~~~~~.¡~~~·~~~~~~~~¡~~~·~~~~~~~i~~~~~~~.~~~~~~~~~.~~¡~~~~~¡~~~:F:~!~~~~~~I~~~~ ¡ ¡ ¡ ¡ ,/" ¡ ......................i. ....................... ..........._. . ..,.............................1........................... ........L..................................L....................TJ?!J:·.ç~s~t.............. ..................L.............. 3000 4000 5000 ......'n........,.... o 1000 2000 3000 4000 5000 Vertical Section (ft) Azim = 29.3°, Scale = 1(in):1000(ft) Origin = 0 N/-S, 0 E/-W 6000 7000 o . 1000 2000 3000 e 4000 5000 . . SchluDlberger WELL L-216 (P2) FIELD Prudhoe Bay Unit - WOA STRUCTUf<E L-PAD _Po.......... Model; BGGM2003 ~; 80.824' Mag Dee: +24.971' Dale: May07,2004 FS: 57563.3nT SulfaceLocation Lat: N70 21 2.544 Lon; W1491925.193 NAD27 Alaska SIaIe Planes, Zone 04, us Feet Northing; 5978309.19I1US GrldConv; +0.63679766" EastIng: 583281.61 nus Scale Fact 0.9999078789 M......... SIoI.: N-R Plan: L-216(P2) TVD Ref; KB (78.40 II. above MSl) SlYyDate: Marm22,2004 o 800 1600 2400 3200 5600 5600 4800 4800 :N A~_._ --~þ 4000 f 4000 ^ ^ ^ z 3200 3200 e- O 0 c:q g ~ II Q) ëõ u en 2400 2400 en V V V o ................"........... 1600 1600 800 800 o RTE o 800 1600 2400 «< W Scale = 1(in):800(ft) E >>> 3200 . BPX AI( Anticollision Report . NO GLOBAL SCAN: Using user defined selection & scan criteria Interpolation MethodMD Interval: 50.00 ft Depth Range: 28.50 to 8391.83 ft Maximum Radiu~DOOO.OO ft Reference: Error Model: Scan Method: Error Surface: Principal Plan & PLANNED PROGRAM ISCWSA Ellipse Trav Cylinder North Ellipse + Casing Survey Program for Definitive Well path Date: 3/22/2004 Validated: No Planned From To Survey ft ft 28.50 8391.83 Planned: Plan #2a V1 Version: 4 Toolcode Tool Name MWD+IFR+MS MWD + IFR + Multi Station Casing Points 3929.41 2638.40 8391.83 4868.40 9.625 7.000 12.250 8.750 95/8" 7" Summary PB L Pad L-01 L-01 V14 300.00 300.00 195.53 4.71 190.82 Pass: Major Risk PB L Pad L-01 Plan L-01 L 1 V2 Plan: P 300.00 300.00 195.53 4.71 190.82 Pass: Major Risk PB L Pad L-02 L-02 V1 487.75 500.00 234.80 8.04 226.76 Pass: Major Risk PB L Pad L-02 L-02PB1 V21 487.75 500.00 234.80 8.15 226.65 Pass: Major Risk PB L Pad L-101 L-101 V4 1075.53 1150.00 298.88 19.11 279.77 Pass: Major Risk PB L Pad L-102 L-102 V2 299.39 300.00 202.43 4.57 197.86 Pass: Major Risk PB L Pad L-102 L-102PB1 V10 299.39 300.00 202.43 4.66 197.77 Pass: Major Risk PB L Pad L-102 L-102PB2 V2 299.39 300.00 202.43 4.66 197.77 Pass: Major Risk PB L Pad L-103 L-103 V23 500.00 500.00 16.53 7.71 8.83 Pass: Major Risk PB L Pad L-104 L-104 V7 347.56 350.00 188.83 5.70 183.13 Pass: Major Risk PB L Pad L-105 L-105 V4 347.61 350.00 183.11 6.03 177.07 Pass: Major Risk PB L Pad L-106 L-106 V14 578.97 600.00 177.60 9.25 168.35 Pass: Major Risk PB L Pad L-107 L-107 V14 348.56 350.00 189.78 7.18 182.60 Pass: Major Risk PB L Pad L-108 L-108 V18 487.01 500.00 176.67 8.57 168.10 Pass: Major Risk PB L Pad L-109 L-109 V12 300.00 300.00 230.45 6.04 224.41 Pass: Major Risk PB L Pad L-110 L-110 V11 300.00 300.00 262.67 5.29 257.38 Pass: Major Risk PB L Pad L-111 L-111 V24 252.19 250.00 346.74 4.34 342.40 Pass: Major Risk PB L Pad L-112 L-112V8 345.11 350.00 252.15 6.99 245.16 Pass: Major Risk PB L Pad L-114 L-114V15 395.31 400.00 320.06 6.01 314.06 Pass: Major Risk PB L Pad L-115 L-115V7 447.02 450.00 173.38 7.22 166.16 Pass: Major Risk PB L Pad L-116 L-116V10 349.22 350.00 241.74 5.30 236.44 Pass: Major Risk PB L Pad L-117 L-117 V11 400.00 400.00 160.77 6.07 154.70 Pass: Major Risk PB L Pad L-118 L-118V9 593.46 600.00 139.81 10.58 129.23 Pass: Major Risk PB L Pad L-119 L-119 V9 652.32 650.00 59.36 10.53 48.83 Pass: Major Risk PB L Pad L-120 L-120 V8 299.28 300.00 92.31 4.95 87.36 Pass: Major Risk PB L Pad L-121 L-121 V14 251.97 250.00 286.43 4.39 282.04 Pass: Major Risk PB L Pad L-121 L-121A V1 251.97 250.00 286.43 4.39 282.04 Pass: Major Risk PB L Pad L-122 L-122 V5 350.28 350.00 205.85 5.55 200.30 Pass: Major Risk PB L Pad L-200 L-200 V7 1718.28 1750.00 82.26 36.61 45.65 Pass: Major Risk PB L Pad L-200 L-200L 1 V3 1718.28 1750.00 82.26 36.61 45.65 Pass: Major Risk PB L Pad L-200 L-200L2 V6 1718.28 1750.00 82.26 36.61 45.65 Pass: Major Risk PB L Pad L-201 current L-201 V5 1619.90 1600.00 53.74 32.13 21.61 Pass: Major Risk PB L Pad L-210 L-210 V6 249.09 250.00 75.39 4.06 71.33 Pass: Major Risk PB L Pad L-210 L-210PB1 V8 249.09 250.00 75.39 4.06 71.33 Pass: Major Risk PB L Pad L-211 L-211 V6 494.80 500.00 182.67 8.69 173.98 Pass: Major Risk PB L Pad L-211 L-211PB1 V6 494.80 500.00 182.67 8.69 173.98 Pass: Major Risk PB L Pad NWE1-01 L-100 V2 251.39 250.00 403.98 4.23 399.75 Pass: Major Risk PB L Pad NWE1-01 NWE1-01 V5 251.39 250.00 403.98 4.23 399.75 Pass: Major Risk PB L Pad Plan L-03 Plan L-03 V3 Plan: Pia 534.78 550.00 195.16 9.19 185.97 Pass: Major Risk PB L Pad Plan L-113 (N-B) Plan L-113 V5 Plan: PI 354.16 350.00 280.31 7.57 272.74 Pass: Major Risk PB L Pad Plan L-124 (N-C) Plan L-124 PB1 V1 Plan 400.00 400.00 265.62 6.99 258.63 Pass: Major Risk PB L Pad Plan L-124 (N-C) Plan L-124 V1 Plan: PI 400.00 400.00 265.62 6.99 258.63 Pass: Major Risk PB L Pad Plan L-212 (N-O) Plan L-212 V3 Plan: PI 498.27 500.00 45.84 8.53 37.31 Pass: Major Risk PB L Pad Plan L-212 (N-O) Plan L-212PB1 V3 Plan: 498.27 500.00 45.84 8.53 37.31 Pass: Major Risk Field: Site: Well: Wellpath: Prudhoe Bay PB L Pad PIau L-216 (N-R) Plan L-216 -277 L-1OO~n{lOODœ) 277 "''''--200 . I .. '100 -0 270 PlanlllaJ\Ja-~~W'I~D2HBl) 90 Planl'Jdl2i,~I'JdI2i,HB4) . 100 . . '200 -277 TraveIJing Cylinder Azimuth (TFO+AZI) [deg] vs Centre to Centre Separation [100ft/in] P055265 DATE . DESCRIPTION . DATE 3/2/2004 ~~ I 055265 I 3/2/2004 PR022604G INVOICE I CREDIT MEMO PERMIT TO DRILL PPL/CATIONS GROSS VENDOR DISCOUNT NET POUCH TO TERRI U88LE M87~5 H THE ATTACHED CHECK IS IN PAYMENT FOR ITEMS DESCRIBED ABOVE. RECEIVED APR 1 9 2004 Alaskt Oil & Gas Cons. Comm ssion Anchorage BP EXPLORATION, (ALASKA) INC. PRUDHOE BAY UNIT PO BOX 196612 ANCHORAGE, AK995J9-6612 NATIONAL CITY BANK Ashland, Ohio PAY: CONSOLIDATED COMMERCIAL ACCOUNT No. P 055265 ~ 412 f'; 'jl'" ,1I1"¡ .. .!J ...ll.. .. fttu~~ TO THE ORDER OF: STATE Of ALASKA AOGCC 333 WEST7THAVENUESUITE 100 ANCHORAGE AK 99501 [ DATE 3/2I~ NOTV.~AYS ":' ...... ....::....M.,.....;.,...:- :':¿:+':':;:'::;~M"j;''''i',~;t~ ß/W",,~::~ :;'£;'~\:~~:~~'1 .... ....%...,................./ :··:::··.:i::::~:;:j~~·::!~::'·:,::.::~t:L:) AMOUNT ......"'**$100.00**..*.. "'055 ¿I; 5", 1:01, ¡ ¿O:JB q 51: 0 ¡ ¿?B ql;,,' . . Well bore seg 0 Annular Disposal 0 Program SER On/Off Shore On Field & Pool PRUDHOE BAY, ORION SCHR BL OIL - 640135 _ Well Name: PRUDHOE BAY UN ORIN L-216 PTD#: 2040650 Company BP EXPLORATION (ALASKA) INC Initial ClasslType SER /1WINJ GeoArea Unit Administration 1 Pem)it. fee attache.d. - - - - - - - - -- Yes - - - - - - - - - 2 .LeasenumberappropriSit.e. . . - - - -- · .Yes 3 .U.nique well. n.ame .aod lJulT!ber . . . . . . . . . _ . . . . . . _ . . . . . . . . _....... Yes - - - - - - - - - - - - - - - - - - - - - - - - . 4 Well/QC<lted in.a.define.dpool. . . · Yes 5 WellJQcated proper .distance. from driJling unit.bound.a'Y. . . · Yes 6 WellJQcated pr.operdistance. from otlJer welJs . . Y.es - - - -- 7 .S.u{fiçient açreageaYailable in.dJilIing unjt - - - - · .Yes 8 Jtdeviated, js. weJlbQre platincJu.ded . . - - - - '..' Yes 9 .Oper.ator only affeçted party. . . . - - -- - - - - · Yes 10 .Qper.ator bas.appropriate.b.ond inJorce . _ . . . . _ . . . . . . . . . . . . . ........ Yes - - - - - - - - - - . - - - - - - - - - - - - - - 11 Pe rlT! it. c.an be issued witlJQut co.nserva.tion order. . . . .. Yes - - - - - - Appr Date 12 Peonit. can be issued witlJQut adlT!ioistrati\leappr~¡Yal . .. Yes - - - - RPC 4/20/2004 13 Can permit be approved before 15-day wait Yes 14 Well/Qcated within area and strata .authorized by. Injection Order # (put.lQ# in.c.9mments). (For. Yes · 810.2.4 - - - - - - 15 .AJlwel!s.witnin.1l4.mite.area.ofreYielo~¡jdelJtifjed(F.9r$ervjcewe[lonl}/L.............. Yes . . . . . ~O~I; . . . _ . . . . . . . . . . . . 16 .Pre-produced injector; .durat.ion.of pre-pro.ductioo tes$ than. 3 mootlJs (For.service well onJy) . .NA - - - - - 17 ACMP ¡::indingof CQn$i$tency h.as been J$sued. for tbis pr.ojeçt NA. Engineering 18 .C.onductor string.pJQvided . . . - - - - - - - - - - - - - Yes 19 .Surface .cas.Îng pJQte~t$. all known USDWs . . · Yes 120 .CMT. v.ot adequate. to çircutate.oncond.uçtor. 8. su.rf~g . . Yes · Me~uate exce$s. . 21 .CMT. v.ot adequate. to tie-inJQng .string to.surf csg. __ .No 22 CMT. will coyerajl koown .pro.ductiYe bQrizon.s. . Yes - - - - -- 23 C.asing de.signs ad.eQuate f.9r c,r, B.&.permafr.ost . . . - - - - - · .Yes 24 A.dequatetankage.oJ re.serve pit. .Yes · ~ab.9["S9.ES. . . . . . 25 .Ita re-.drilt l1as a. to,403 for abandonme.nt been SiPPJQved . . . NA ~ew well. 26 A.dequat.e.wellbore$eparSitjo.n.propose.d. . . . _ . . . . _ . _ . . . . . . _ ... Yes - - - - - - - - - - - - - - - - - - - - - - - - - 27 Jf.djverter Jequired, does it .meet. reguJations. . . . . . . Yes - - - - - - - - - - - Appr Date 28 DJilling fjuid. program schematic.&. eq.uip JistadequSite. . - - -- Yes . . Max MW9,3 ppg.. . . . . WGA 4/20/2004 29 .BOPEs,.d.oJhey meel.reguJation . . . Yes - - - - - - - - - - - - - - - - 30 B.Opçpress rating appropriate; .test to (pu.t psig i.n .commeots). . . · Yes · Test t.9.40QO psi. .MSP. 16.68 psi.. 31 .Chokemanjfold CQlT!pJie$ w/API. RP.-53 (May 84) . . . Yes - - - - - - 32 Work will Occ.ur without.operation .shutdown. . . . Yes - - - -- 33 .Is. pres.ence. Qf H2S gas. prob.able. . . . - - - - - - No. · ~otan H2S pad. 34 Mecl)a.nicaLcoodjtion.9t wells within ,;oa yerified (For.s.ervjce welJ only) · Yes ~o wells jn.AQR. - Geology 35 .PerlT!it. c.ao be issued wID. hydr.ogen. s.utfide meas.ure$ . - ~ - - Yes 36 .Datapreseoted on. pote.ntial ove.l'Qre$$urezone$. . . . NA - - - - Appr Date 37 Seismic.analys.is. Qf $lJaJlow gaszooes. . . . . . . . . . . __ . NA RPC 4/20/2004 38 Seabedcondjtioo survey .(if off-shore) . NA. - - - - - - 39 . Conta.ct namelpnoneJorweekly progress.reports [explorato'Y .only]. NA Geologic +~E"";"ee""" Date ~þ/~ Commissioner: 1/;¡ 1-- ~ Comml"',"e, bT~ 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 Date: 04/11/2005 Schlum ler[er Fluid Analysis on Bottomhole Samples BP Field: Orion Well: L-216 CONFIDENTIAL Black Oil PVT Study Report Prepared for Greg Bernaski BP CONFIDENTIAL Standard Conditions Used: Pressure: 14.696 psia T ernperature: 60°F Prepared by: Meisong Van Reviewed by: Dennis D'Cruz Schlumberger WCP Oilphase-DBR 16223 Park Row, Suite 170 Houston, Texas, 77084 (281) 829-2225 Report #200400128 I I Client: BP Well: L-216 Installation: Orion SchlumblPll1' Field: Sand: Job #: 200400128 I Table of Contents List of Figures ... . List of Tables I EXECUTIVE SUMMARY.. Objective Introduction Scope of Work.... Results Sequence of Events. . Chain of Sample. Custody. ... ........ ...... .........."... I .................... . I RESULTS AND..DIS.CUSSIONS.. . Fluids Preparation .and.Analysis . . . Reservoir Fluid.Analysis . . Sample#: 1.02; CSB. 7478"MA; .OBdSa.nd;MD.:;: 81.05:ft; IVD:;:;4648ft IVDSS.:;:;"4569ft.. ReselVoir Oil Viscosity at. Tres . . Sample#: 1.03; CSB. 8173"QA;OBbSand;MD:;:;7902.ft;. IVD:;:;4535ft; JVOSS ;:;d456. ft.. ReselVoir Oil Viscosity at.Tres.. Sample#: 1.04; SSB.11288:-MA; o.Ba~Upper.Saod;.MD.:;:;.7823.ft;. IVD;:;:.4491ft; TVOSS ;:;:74413ft.... ReselVoirOil Viscosity aares.. ................... Sample#: 1.07; CSB.7321"MA; OASaod; MD.:;:; 7718.ft; IVD;:;:4435ft .TVOSS ;:;:74355 ft.. ReselVoir Oil Viscosityaares .. Sampl e#: 1.11; SSB. .11200"MA; o.Ba~Lower Sand; MD ;:;:.7847 ft; .TV.D:;: 4504 fI; .TVDSS:;: ".4426 .fI.. . ReselVoir Oil Viscosity at. Tr.es . . .................. I I I I Appendix A: Nomenclature and Definitions.. Appendix B: Mol.e.cular Weig.h.ts .andDensitiesUsed.... Appendix C: EQUIPMENT.. ........................ Fluid Preparation. and .Validation. . . Fluid Volumetric (PVT) and. Viscosity. Equipment. .... Appendix D: PROCEDURE.. Fluids Preparation .and. Validation.. . Constant Composition Expansion Proc.edure. . Differential Vaporization Procedure. . Multi-Stage Separation. Test... Liquid Phase Viscosity. and. Density. Measurements During. D.V Step. . . Stock-Tank Oil.(STO) .Viscosity.and.Density.Measurements... Asphaltene, Wax.and Sulfur.Content.Measurements... SAR(P)A Analysis.. High- Temperature High Pressure.Filtr:ation. Test. . ..... ....................". I I I I I I I I I WCP Oilphase-DBR 2 3 4 4 4 4 4 5 5 6 6 6 27 27 30 30 33 33 36 36 39 39 41 42 43 43 43 46 46 46 46 46 47 47 47 48 48 Job #: 200400128 I I Client: BP Well: L-216 Installation: Field: Sand: Job #: I List of Figures I Figure 1: Stock Tank ŒIChromatogram (Sample .1.02).. Figure 2: k-PloUor .Equilibrium Check (Sample.1..02).. Figure 3: Stock Tank D.il.Chromatogram (Sample 1.03) . Figure 4: k-PloUor .Equilibrium Check (Sample.t03) Figure 5: Stock Tank D.il.Chromatogram .(.Sample1.01l).. Figure 6: k-PloUor .Equilibrium Check. (Sample. tOO) ... Figure 7: Stock Tank ŒI.Chromatogram .(Sample1.01)... . Figure 8: k-PloUor .Equilibrium Check (Sample 1.07).... Figure 9: Stock Tank D.il.Chromatogram .(Sample.1. 11). Figure 10: k-Plotfor. Equilibri.um.Ch.eck.(Sample .1.1.1).. Figure 11: Reservoir .fluid Viscosity .95°F.. Figure 12: Reservoir .fluid Viscosity .93?F... Figure 13: Reservoir Huid Viscosity .93?F.. Figure 14: Reservoir .fluid Viscosity.92?F... Figure 15: Reservoidluid Viscosity.9.1°F.. I I I I I I I I I I I I I I I WCP Oilphase-DBR Orion 200400128 ....."........ SchlumblPllP .... .............. ....................... ...... ............ . .... ...... 2 13 13 16 16 19 19 22 22 25 25 28 31 34 37 40 Job #: 200400128 Table 1: Well and .Sample Identification.......... ............................. ............................................. Table 2: Sampling. and Transfer. Summary... ..... ... . .. ... ... ... . ... ..... . .. . ... ............................................. Table 3: Reservoir. FI.uid.Pr.operties ... . ...... .. ... ... . ..... ... ... . ... ..... . ... .. . ... .. . .. ... . ..... ... ... . .. . ... .. ... ... ... . .. .. Table 4: Stock-Tank .0il.Properties. ... . ... ... ... .. ... . .. ... ... ... . ... ..... . .. . ... ... .. .... .................................... Table 5: C30+ Compositi.oß..GOR..oAPI..by.Single"Stage.FIash .(Sample1.02) ........................... Table 6: Calculated .F1.uid.Properti.es.. Table 7: C30+ Compositi.oß..GOR..oAPI,.bySingle"Stage.Flash .(Sample1.03). Table 8: Calculated.FI.uid.Properti.es .............. Table 9: C30+ Compositi.oß.GOR.~API. by Single"Stag.e. Flash (Sample .1.04).. Table 10: Calculated Fluid Properties.. Table 11: C30+ Composition, GaR, °API, .by .Single"Stage .Flasb. (Sample.t07J.. Table 12: Calculated Fluid Pr.operties Table 13: C30+ Composition, GaR, ~API, .by.Single"Stage .Flasb. (Sample. 1.11).. Table 14: Calculated Fluid Pr.operties.. Table 15: Summary.of.ResultsofSample.1.0L Table 16: ReservoirfluidVi.scosity.95°F ........ ......... ................. Table 17: Summary.of.Results ofSample.1.03 ............ . ....................... Table 18: Reservoir.FluidVi.scosity.93°F.. ... ............. Table 19: Summary.of.Results ofSample.1.04... Table 20: Reservoir .Fluid Yiscosity.93°F.. Table 21: Summary.of.Results ofSample.1.01.. Table 22: Reservoir .Fluid Vi.scosity.92°F.. Table 23: Summary.of.Results ofSample.1.1.1.. Table 24: Reservoir .Fluid Vi.scosity.9.eF.. I I Client: BP Well: L-216 Installation: 200400128 Field: Sand: Job #: Orion I List of Tables I I I I . ............. I I ................. I Schlumbepg8P ................... ...................".........." . .. ... ........... ..... ............... ... ... ......... ...... ... .........., I I I I I I I I I WCP Oilphase-DBR 3 7 8 9 10 11 12 14 15 17 18 20 21 23 24 26 27 29 30 32 33 35 36 38 39 Job #: 200400128 I I I I I I I I I I I I I I I I I I I Client: BP Well: L-216 Installation: Field: Sand: Job#: Orion Schlumb8Pger 200400128 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 BP, Oilphase has conducted a fluid analysis study on bottomhole fluid samples collected during the modular formation dynamics testing (MDT) of Well L-216 drilled in the field Orion. 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 (GOR). reservoir fluid composition, stock-tank oil (STO) and monophasic fluid properties. · Select representative samples for the PVT study. · Conduct the bubble point check · Conduct the HPHT density check · Also conduct viscosity measurements of the oil at the reservoir temperature. Results The following bullets summarize the PVT analysis conducted on the bottomhole hydrocarbon and water samples: · Five bottomhole 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 1,536 - 1,973 psi a whereas the reservoir pressure was from 1,914 - 2,064 psia. Thus, all samples were considered valid for further analyses. The zero flash GOR was determined to be from 194 - 266 SCFjSTB, and the STO density to be from 0.917 - 0.961 gjcc. · · WCP Oilphase-DBR 4 Job #: 200400128 I I I I I I I I I I I I I I I I I I I Client: BP Well: L -216 Installation: Field: Sand: Job#: Orion Schlumb8Pger 200400128 Sequence of Events 6/3/2004 The samples arrived in Oilphase-DBR Houston lab 6/17/2004 Tweleve samples' quality check was sent bye-mail 6/28/2004 Five samples were chosen for the PVT prelim work 7/21/2004 Full PVT report was sent bye-mail. 7/29/2004 Invoice sent. Invoice#: 9091236064. 8/30/2004 Client requested the composition data for all five samples. 9/13/2004 Composition results added to the report and sent to client. 9/15/2004 Invoice sent. Invoice#: 9091261752. Chain of Sample Custody The samples collected from the well L-216 from Alaska were sent to Oilphase-DBR in Houston, Texas. The samples were used to preliminary measurements and subsequent PVT study to obtain reservoir fluid. The measurement details are in the following text. Samples remaining after measurements are stored in Oilphase-DBR storage unless otherwise instructed. WCP Oilphase-DBR 5 Job #: 200400128 I I Client: BP Well: L·216 Installation: Field: Sand: Job#: Orion SCbllJlØ~"'llr 200400128 RESULTS AND DISCUSSIONS I Fluids Preparation and Analysis Five 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 bottom hole 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 all the samples were good candidates for PVT analysis. Based on the preliminary results, we can select the representative samples for PVT analysis. The reservoir fluid and stock-tank oil properties for all the samples are presented in Table 3 and Table 4. I I 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 (GOR) to calculate the reservoir fluid composition. The reservoir fluid analysis is summarized in Tables 5, 7, 9, 11 and 13. The molecular weight of the stock-tank oil (STO) was measured. Other properties such as the plus fraction properties and heat content for the flashed gas were calculated from the compositions and are listed in Tables 6, 8,10,12 and 14. I I I I I I I I I I I I I I WCP Oilphase-DBR 6 Job #: 200400128 I I Client: BP Field: Orion SChl.III~8P11ør Well: L·216 Sand: Installation: Job#: 200400128 Table 1: Well and Sample Identification Client: BP Job# 200400128 Field: Orion Well: L·216 Study Samples Reservoir Conditions Sample ID Cylinder # Sand Name Sampling Date Pressure Temperature MD TVD TVDSS Ipsia) (OF) 1ft) (ft) (ft) 1.01 CSB 7281·MA DBd 05/09/04 2,043 95 8,105 4,648 ·4,569 1.02 CSB 7478·MA DBd 05/09/04 2,043 95 8,105 4,648 ·4,569 1.03 CSB 8173·QA DBb 05/09/04 1,980 93 7,902 4,535 ·4.456 1.04 SSB 11288·MA DBa_Upper 05/09/04 2,064 93 7,823 4.491 ·4.413 1.05 SSB 11313·MA DBa_Upper 05/09/04 2,064 93 7,823 4.491 ·4.413 1.06 CSB 7473·MA DA 05/09/04 1,957 92 7,718 4.435 ·4,355 1.07 CSB 7321·MA DA 05/09/04 1,957 92 7718 4435 ·4,355 1.08 SSB 10712·MA DA 05/09/04 1,957 92 7,718 4.435 ·4,355 1.10 SSB 11283·MA Nb 05/09/04 1,914 89 7.492 4,309 ·4,231 111 SSB 11200·MA DBa_Lower 05/10/04 1,992 91 7,847 4,504 ·4.426 1.12 SSB 11191·MA DBa_Lower 05/10/04 1,992 91 7,847 4,504 ·4.426 1.13 SSB 11197·MA DBa_Lower 05/10/04 1,992 91 7,847 4,504 ·4.426 I I I I I I I I I I I I I I I I I WCP Oilphase-DBR 7 Job #: 200400128 I I Client: BP Field: Orion SChllllllbll".' Well: L·216 Sand: Installation: Job#: 200400128 Table 2: Sampling and Transfer Summary Opening Transfer Opening Initial Final Sample ID Chamber # Sand Name conditions Cyl inder conditions FS&W BS&W Sample Sample in the field ID in the Lab Volume Volume (psia¡OFI (psia¡OFI (eel (v/v%1 (eel (eel 1.01 MPSR 1397 OBd CSB7281·MA 1415/75 45 0.0 425 350 102 MPSR 1398 OBd CSB 7478·MA 1415/75 6 Trace 380 Blowdown 1.03 MPSR 1399 OBb CSB 8173·QA 1215/75 2 0 430 210 1.04 MPSR 1400 OBa_Upper SSB 11288·MA 1465/75 15 0 430 Blowdown 1.05 MPSR 1401 OBa_Upper SSB 11313·MA 1415/75 20 Trace 420 350 1.06 MRSC 292 OA CSB 7473·MA 1515/75 47 0.3 600 520 1.07 MRSC 292 OA CSB 7321·MA 1415/75 35 Trace 600 Blowdown 1.08 MRSC 292 OA SSB 10712-MA 1415/75 40 1 600 520 1.10' MPSR 1402 Nb SSB 11283·MA 1015/75 420 Blowdown 1.11 MRSC 242 OBa_Lower SSB 112oo·MA 1515/75 15 0.0 600 Blowdown 1.12 MRSC 242 OBa_Lower SSB 11191·MA 1615/75 20 0.1 600 550 1.13 MRSC 242 OBa_Lower SSB 11197·MA 1515/75 0 0.5 600 570 'Mud sample I I I I I I I I I I I I I I I I I WCP Oilphase-DBR 8 Job #: 200400128 I I Client: BP Field: Orion SeIIIßlbø.gl, Well: L·216 Sand: Installation: Job#: 200400128 Table 3: Reservoir Fluid Properties Zero Flash Saturation Molar Mass of Viscosity of Sample ID Cylinder # Sand Name MD TVDSS GOR* Bo** Pressure monophasic Res. Fluid at Tres fluid at Pres. T res (ftl 1ft) Iscf/bbll (psial (cP) 102 CSB 7478·MA OBd 8105 ·4569 266 N/D 1799 188.3 9.0 1.03 CSB 8173·MA OBb 7902 ·4456 234 N/D 1536 188.2 16.6 1.04 SSB 11288·MA DBa_Upper 7823 ·4413 218 N/D 1973 218.3 26.8 1.07 CSB 7321·MA OA 7718 ·4355 194 N/D 1776 241.2 90.1 1.11 SSB 11200·MA DBa_Lower 7847 ·4426 205 N/D 1766 246.7 118.9 I I I I . Flashed gas volume (scf) 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 ... Calculated from oil·based mud contamination in STO I I I I I I I I I I I I I WCP Oilphase-DBR 9 Job #: 200400128 I I Client: BP Field: Orion SChllDl~el'aør Well: L·216 Sand: Installation: Job#: 200400128 Table 4: Stock-Tank Oil Properties S10 Properties Sample ID Cylinder # Sand Name MD lVDSS Molar Mass Density API (ft) (ft) Ig/ee) 1.02 CSB 7478·MA OBd 8105 ·4569 296.3 0.924 21.6 103 CSB 8173·MA OBb 7902 ·4456 278.8 0.917 22.8 1.04 SS811288-MA OBa_Upper 7823 ·4413 335.7 0.941 18.9 1.07 CSB 7321·MA OA 7718 ·4355 366.4 0.958 16.3 1.11 SSB 11200·MA OBa_Lower 7847 ·4426 390.0 0.961 15.8 I I I I I I I I I I I I I I I I I WCP Oilphase-DBR 10 Job #: 200400128 I I Client: BP Field: Orion Seblombergep Well: L-216 Sand: OBd SAND I Table 5: C30+ Composition, GOR, °API, by Single-Stage Flash (Sample 1.02) Sample#: 1.02; CSB 7478-MA; OBd Sand; MD = 8105 ft; TVD = 4648 ft; TVDSS = -4569 ft Component MW Flashed Gas Flashed Liquid Monophasic Fluid I (g/mole) WT% MOLE % WT% MOLE % WT% MOLE % Carbon Dioxide 44.01 0.99 0.45 0.00 0.00 0.04 0.17 Hydrogen SulfidE 34.08 0.00 0.00 0.00 0.00 0.00 0.00 I Nitrogen 28.01 1.60 1.14 0.00 0.00 0.07 0.44 Methane 16.04 70.11 86.94 0.00 0.00 2.90 33.98 Ethane 30.07 6.43 4.26 0.00 0.00 0.27 1.66 Propane 44.10 5.86 2.65 0.03 0.17 0.27 1.14 I I - Butane 58.12 2.52 0.86 0.03 0.15 0.13 0.43 N - Butane 58.12 5.32 1.82 0.11 0.54 0.32 1.04 I - Pentane 72.15 2.64 0.73 0.16 0.64 0.26 0.67 I N - Pentane 72.15 2.68 0.74 0.23 0.95 0.33 0.87 C6 84.00 0.67 0.16 0.70 2.46 0.70 1.56 M-C-Pentane 84.16 0.43 0.10 0.29 1.02 0.29 0.66 I Benzene 78.11 0.05 0.01 0.04 0.14 0.04 0.09 Cyclohexane 84.16 0.32 0.08 0.36 1.28 0.36 0.81 C7 96.00 0.10 0.02 1.02 3.15 0.98 1.93 M-C-Hexane 98.19 0.21 0.04 0.73 2.21 0.71 1.36 I Toluene 92.14 0.03 0.01 0.19 0.62 0.19 0.38 C8 107.00 0.02 0.00 1.58 4.38 1.52 2.67 E-Benzene 106.17 0.00 0.00 0.20 0.57 0.19 0.34 I M/P-Xylene 106.17 0.01 0.00 0.29 0.80 0.28 0.49 a-Xylene 106.17 0.00 0.00 0.15 0.41 0.14 0.25 C9 121.00 0.00 0.00 1.66 4.08 1.60 2.48 I pseudo C1 OH22 134.00 0.00 0.00 2.51 5.55 2.41 3.38 pseudo C11 H24 147.00 0.00 0.00 2.35 4.73 2.25 2.88 pseudo C12H26 161.00 0.00 0.00 2.74 5.05 2.63 3.08 I pseudo C13H28 175.00 0.00 0.00 2.89 4.90 2.77 2.98 pseudo C14H30 190.00 0.00 0.00 2.98 4.64 2.85 2.83 pseudo C15H32 206.00 0.00 0.00 2.80 4.03 2.68 2.45 pseudo C16H34 222.00 2.85 3.80 2.73 2.32 I pseudo C17H36 237.00 2.44 3.05 2.34 1.86 pseudo C18H38 251.00 2.41 2.85 2.31 1.74 pseudo C19H40 263.00 2.48 2.79 2.37 1.70 I pseudo C20H42 275.00 2.19 2.36 2.10 1.44 pseudo C21 H44 291.00 2.04 2.08 1.95 1.26 pseudo C22H46 300.00 1.94 1.91 1.86 1.16 I pseudo C23H48 312.00 1.86 1.77 1.79 1.08 pseudo C24H50 324.00 1.95 1.78 1.87 1.09 pseudo C25H52 337.00 1.38 1.21 1.32 0.74 pseudo C26H54 349.00 1.49 1.27 1.43 0.77 I pseudo C27H56 360.00 1.43 1.18 1.38 0.72 pseudo C28H58 372.00 1.38 1.10 1.32 0.67 pseudo C29H60 382.00 1.54 1.19 1.47 0.73 I C30+ 750.00 48.59 19.20 46.58 11.69 Total 100.00 100.00 100.00 100.00 100.00 100.00 MW 19.89 296.31 188.26 I MOLE RATIO 0.3909 0.6091 I WCP Oilphase-DBR 11 Job #: 200400128 I I I I I I I I I I I I I I I I I I I Client: Well: BP L-216 Field: Sand: Orion OBd SAND Seblumberger Properties Table 6: Calculated Fluid Properties Sample#: 1.02; CSB 7478-MA; OBd Sand; MD = 8105 ft; TVD = 4648 ft; TVDSS = -4569 ft Flashed Gas Flashed Liquid Monophasic Fluid 87.87 Mole% Mass % Mole % 0.27 98.76 95.09 0.00 87.38 66.15 65.79 35.05 48.59 19.20 307.73 391.37 556.23 750.00 0.9293 0.9545 1.0015 1.0511 0.9240 Mass % 94.72 83.77 63.07 46.58 Mole% 58.03 40.29 21.35 11.69 Cn+ Composition C7+ C12+ C20+ C30+ Mass % 1.18 0.00 Molar Mass C7+ C12+ C20+ C30+ 307.33 391.37 556.23 750.00 Density C7+ C12+ C20+ C30+ Fluid at 60°F 0.9545 1.0015 1.0511 Gas Gravity (Air = 1) 0.687 Dry Gross Heat Content (BTU/scf) I Wet Gross Heat Content (BTU/scf) 1,188 1,167 OBM Contamination level (wt%) ISTO Basis Live Oil Basis Stock Tank Oil Properties at Standard Conditions: Measured Calculated 296.31 MW I Density (g/cm3) 0.924 C30+ Properties I 750.00 I 1.051 Single Stage Flash Data GOR (scf/stb) STO Density (g/cm3) STO API Gravity Original STO 266 0.9240 21.6 De-Contaminated I OBM Density (g/cm3) @60°F WCP Oilphase-DBR 12 Job #: 200400128 I I I I I I I I I I I I I I I I I I I Client Well: BP L-216 field: Sand: Orion OBd SAND figure 1: Stock Tank Oil Chromatogram (Sample 1.(2) Sample#: 1.02; CSB 7478-MA; OBd Sand; MO 8105 ft; TVO := 4648 ft; TVOSS = -4569 ft p,t.. _ " c ] 500 4üO 300 , 30 Figure 2: k-Plot for Equilibrium Check (Sample 1.(2) Sample#: 1.02; CSB 7478-MA; OBd Sand; MO := 8105 ft; TVO = 4648 ft; TVOSS = -4569 ft ._--~ 100 --_._-_.~--~.__.~.~.....,_.._~~ . C3 2.00 . 100 000 ~~-,--~ + C7 -$- CG --,-_.._.~_....-'- ·100 ·2.00 + C9 --_.._.."".~~._~.._~ ·100 ·100 ·2.00 -100 000 100 200 1JO -400 ·5.00 "~---~ ~----- --'~'- F _...~-_._-~ WCP Oilphase-DBR 13 Job #: 200400128 -- I Client: BP Fièld: Orion ScblumbøPI8P I Well: L-216 Sand: OBb SAND I Table 7: C30+ Composition, GOR, 0 API, by Single-Stage flash (Sample 1.03) Sample#: 1.03; CSB 8173-0A; OBb Sand; MD = 7902 ft; TVD = 4535 ft; TVDSS = -4456 ft Component MW Flashed Gas Flashed liquid Monophasic Fluid I (gjmole) WT% MOLE % WT% MOLE % WT% MOLE % Carbon Dioxide 44.01 1.33 0.56 0.00 0.00 0.05 0.19 Hydrogen SulfidE 34.08 0.00 0.00 0.00 0.00 0.00 0.00 Nitrogen 28.01 0.35 0.23 0.00 0.00 0.01 0.08 I Methane 16.04 81.08 93A2 0.00 0.00 2.77 32.50 Etha ne 30.07 2.35 1.44 0.00 0.00 0.08 0.50 Propane 44.10 1.73 0.73 0.01 0.08 0.07 0.31 I I - Butane 58.12 1.72 0.55 0.02 0.11 0.08 0.26 N - Butane 58.12 3.74 1.19 0.08 OAO 0.21 0.67 I - Pentane 72.15 2.77 0.71 0.18 0.71 0.27 0.71 I N - Pentane 72.15 2.95 0.76 0.29 1.13 0.38 1.00 C6 84.00 0.88 0.19 1.00 3.31 0.99 2.23 M-C-Pentane 84.16 OA2 0.09 0.36 1.19 0.36 0.81 I Benzene 78.11 0.03 0.01 0.02 0.08 0.02 0.05 Cyclohexane 84.16 0.29 0.06 OA4 1A7 OA4 0.98 C7 96.00 0.13 0.03 1.50 4.35 1A5 2.85 M-C-Hexane 98.19 0.19 0.04 1.03 2.92 1.00 1.91 I Toluene 92.14 0.02 0.00 0.14 0.41 0.13 0.27 C8 107.00 0.02 0.00 2.19 5.71 2.12 3.72 E-Benzene 106.17 0.00 0.00 0.20 0.53 0.20 0.35 I MjP-Xylene 106.17 0.00 0.00 0.25 0.66 0.24 0.43 a-Xylene 106.17 0.00 0.00 0.12 0.32 0.12 0.21 C9 121.00 0.00 0.00 2.09 4.80 2.01 3.13 I pseudo C1 OH22 134.00 0.00 0.00 2.95 6.14 2.85 4.00 pseudo C11 H24 147.00 0.00 0.00 2.52 4.78 2.44 3.12 pseudo C12H26 161.00 0.00 0.00 2.59 4.48 2.50 2.92 pseudo C13H28 175.00 0.00 0.00 2.87 4.57 2.77 2.98 I pseudo C14H30 190.00 0.00 0.00 2.97 4.36 2.87 2.84 pseudo C15H32 206.00 0.00 0.00 2.78 3.77 2.69 2.46 pseudo C16H34 222.00 2.83 3.55 2.73 2.31 I pseudo C17H36 237.00 2A2 2.85 2.34 1.86 pseudo C18H38 251.00 2.39 2.65 2.31 1.73 pseudo C1 9H40 263.00 2A6 2.61 2.38 1.70 I pseudo C20H42 275.00 2.19 2.22 2.12 1.45 pseudo C21 H44 291.00 1.94 1.86 1.88 1.21 pseudo C22H46 300.00 2.06 1.92 1.99 1.25 pseudo C23H48 312.00 1.86 1.66 1.80 1.08 I pseudo C24H50 324.00 1.65 1.42 1.59 0.92 pseudo C25H52 337.00 1.55 1.29 1.50 0.84 pseudo C26H54 349.00 1.56 1.25 1.51 0.81 I pseudo C27H56 360.00 1A6 1.13 1.41 0.74 pseudo C28H58 372.00 1.50 1.13 1.45 0.74 pseudo C29H60 382.00 1.47 1.07 1.42 0.70 I C30+ 750.00 46.04 17.11 44A6 11.16 Total 100.00 100.00 100.00 100.00 100.00 100.00 MW 18.48 278.79 188.22 MOLE RATIO 0.3479 0.6521 I I WCP Oilphase-DBR 14 Job #: 200400128 I I I I I I I I I I I I I I I I I I I Client: Well: BP L-216 Field: Sand: Orion OBb SAND Scblumberger Table 8: Calculated fluid Properties Sample#: 1.03; CSB 8173-QA; OBb Sand; MD = 7902 ft; TVD = 4535 ft; TVDSS = -4456 ft Flashed Gas Flashed Liquid Monophasic Fluid Properties Cn+ Composition C7+ C12+ C20+ C30+ Molar Mass C7+ C12+ C20+ C30+ Density C7+ C12+ C20+ C30+ Fluid at 60°F Gas Gravity (Air = 1) Dry Gross Heat Content (BTU/scf) I Wet Gross Heat Content (BTU/scf) OBM Contamination Level (wt%) Mass % 1.11 0.00 88.01 0.638 1,124 1,105 Mole % Mass % Mole% 0.23 98.41 94.25 0.00 84.59 60.89 63.29 32.05 46.04 17.11 291.08 387.33 550.45 750.00 0.9236 0.9552 1.0038 1.0575 0.9172 ISTO Basis Live Oil Basis MW I Density (g/cm3) Stock Tank Oil Properties at Standard Conditions: Measured Calculated 278.79 C30+ Properties I 750.00 I 1.058 0.917 Single Stage Flash Data GOR (scf!stb) STO Density (g/cm3) STO API Gravity OBM Density (g/cm3) @60°F WCP Oilphase-DBR Original STO 234 0.9172 22.8 De-Contaminated I 15 Mass % 95.08 81.70 61.13 44.46 Mole % 61.54 39.70 20.90 11.16 290.81 387.33 550.45 750.00 0.9552 1.0038 1.0575 Job #: 200400128 I I I I II I I I Client Well: BP L-216 Field: Sand: Orion OBb SAND 3: Stock Tank Oil Chromatogram (Sample 1.03) Sample#: 1.03; CSB 8173-QA; OBb Sand; MD 7902 ft; TVD = 4535 ft; TVDSS = -4456 ft pA _ 500 - 400- -100 - , '10 , 20 , 30 , 40 300 - 200 Figure 4: k-Plot for Equilibrium Check (Sample 1.03) Sample#: 1.03; CSB 8173-QA; OBb Sand; MD = 7902 ft; TVD = 4535 ft; TVDSS = -4456 ft I I I I I I I I 3.00 2.00 100 000 ·100 ·2.00 ·3.00 ·400 ·3.00 ·4.00 ·5.00 C3 . 4IÞ C7 to C9 ·2.00 ·100 000 100 2.00 3.J0 F WCP Oilphase-DBR 16 Job 'It: 200400128 I I CIi ent: BP Field: Orion Scblumbepger Well: L-216 Sand: OBa_Upper SAND I Table 9: C30+ Composition, GOR, °API, by Single-Stage flash (Sample 1.04) Sample#: 1.04; SSB 11288-MA; OBa_Upper Sand; MD = 7823 ft; TVD = 4491 ft; TVDSS = -4413 ft Component MW Flashed Gas Flashed liquid Monophasic Fluid I (g/mole) WT% MOLE % WT% MOLE % WT% MOLE % Carbon Dioxide 44.01 1.10 044 0.00 0.00 0.03 0.16 Hydrogen SulfidE 34.08 0.00 0.00 0.00 0.00 0.00 0.00 I Nitrogen 28.01 0.53 0.33 0.00 0.00 0.02 0.12 Methane 16.04 88.60 95.81 0.00 0.00 2.60 35.32 Ethane 30.07 2.21 1.28 0.00 0.00 0.06 0.47 Propane 44.10 1.37 0.54 0.01 0.07 0.05 0.24 I I - Butane 58.12 0.92 0.28 001 0.07 0.04 0.14 N - Butane 58.12 1.95 0.58 0.04 0.23 0.10 0.36 I - Pentane 72.15 1.09 0.26 0.06 0.29 0.09 0.28 I N - Pentane 72.15 1.14 0.28 0.09 0.43 0.12 0.37 C6 84.00 0.36 0.08 0.35 1.39 0.35 0.90 M-C-Pentane 84.16 0.24 0.05 0.15 0.61 0.16 0.40 I Benzene 78.11 0.02 0.01 0.02 0.07 0.02 0.05 Cyclohexane 84.16 0.19 0.04 0.21 0.82 0.20 0.53 C7 96.00 0.08 0.01 0.62 2.16 0.60 1.37 M-C-Hexane 98.19 0.13 0.02 0.44 1.50 0.43 0.96 I Toluene 92.14 0.02 0.00 0.12 0.45 0.12 0.29 C8 107.00 0.02 0.00 1.05 3.29 1.02 2.08 E-Benzene 106.17 0.00 0.00 0.12 0.37 0.11 0.23 I M/P-Xylene 106.17 0.00 0.00 0.16 0.51 0.16 0.32 O-Xylene 106.17 0.00 0.00 0.08 0.27 0.08 0.17 C9 121.00 0.00 0.00 1.16 3.22 1.13 2.03 I pseudo ClOH22 134.00 0.00 0.00 1.67 4.18 1.62 2.64 pseudo C11 H24 147.00 0.00 0.00 1.70 3.88 1.65 2.45 pseudo C12H26 161.00 0.00 0.00 2.04 4.26 1.98 2.69 I pseudo C13H28 175.00 0.00 0.00 2.44 4.68 2.37 2.95 pseudo C14H30 190.00 0.00 0.00 2.62 4.63 2.55 2.92 pseudo C15H32 206.00 0.00 0.00 2.59 4.23 2.52 2.67 pseudo C16H34 222.00 2.71 4.10 2.63 2.59 I pseudo C17H36 237.00 2.47 3.50 2.40 2.21 pseudo C18H38 251.00 2.55 3.41 2.47 2.15 pseudo C19H40 263.00 2.68 3.43 2.61 2.16 I pseudo C20H42 275.00 2.37 2.89 2.30 1.82 pseudo C21 H44 291.00 2.60 3.00 2.52 1.89 pseudo C22H46 300.00 1.98 2.22 1.92 1.40 I pseudo C23H48 312.00 2.15 2.32 2.09 1.46 pseudo C24H50 324.00 2.04 2.12 1.98 1.34 pseudo C25H52 337.00 2.10 2.09 2.04 1.32 pseudo C26H54 349.00 1.36 1.30 1.32 0.82 I pseudo C27H56 360.00 1.80 1.68 1.75 1.06 pseudo C28H58 372.00 1.75 1.58 1.70 1.00 pseudo C29H60 382.00 1.72 1.51 1.67 0.95 I C30+ 750.00 5196 23.26 50.44 14.68 Total 100.00 100.00 100.00 100.00 100.00 100.00 MW 17.35 335.68 218.32 I MOLE RATIO 0.3687 0.6313 I WCP Oilphase-DBR 17 Job #: 200400128 I I I I I I I I I I I I I I I I I I I Client: Well: BP L-216 Field: Sand: Orion OBa_Upper SAND Scblumbergep Table 10: Calculated Fluid Properties Sample#: 1.04; SSB 11288-MA; OBa..,Upper Sand; MO = 7823 ft; TVO = 4491 ft; TVOSS = -4413 ft Properties Flashed Gas Flashed liquid Monophasic Fluid Cn+ Composition C7+ C12+ C20+ C30+ Molar Mass C7+ C12+ C20+ C30+ Density C7+ C12+ C20+ C30+ Fluid at 60°F Gas Gravity (Air = 1) Dry Gross Heat Content (BTU/scf) I Wet Gross Heat Content (BTU/scf) OBM Contamination Level (wt%) Mass % 0.71 0.00 88.27 0.599 1,065 1,047 Mole % Mass % Mole % 0.14 99.44 97.53 0.00 91.94 76.19 71.83 43.95 51.96 23.26 342.26 405.08 548.53 750.00 0.9435 0.9608 1.0022 1.0563 0.9410 STO Basis Live Oil Basis MW I Density (g/cm3) Stock Tank Oil Properties at Standard Conditions: Measured Calculated 335.68 C30+ Properties I 750.00 I 1.056 0.941 Single Stage Flash Data GOR (scf/stb) STO Density (g/cm3) STO API Gravity OBM Density (g/cm3) @60°F WCP Oilphase-DBR Original STO 218 0.9410 18.9 De-Contaminated I 18 Mass % 96.55 89.25 69.72 50.44 Mole% 61.62 48.10 27.75 14.68 342.05 405.08 548.53 750.00 0.9608 1.0022 1.0563 Job #: 200400128 I I I I II I I I I I I I I I Client: Well: BP L-216 Field: Sand: Orion DBa_Upper SAND Figure 5: Stock Tank Oil Chromatogram (Sample 1.(4) Sample#: 1.04; SSB 11288-MA; DBa_Upper Sand; MD 7823 ft; TVD = 4491 ft; TVDSS = -4413 ft pA '" '" co "' '" J: 500 41)0 300 200 '100 Nír¡:;!~~~~~R o :;: '( ~ 0 ü 0 ü<.;;ü , 10 , 20 , 30 , 4() Figure 6: k-Plot for Equilibrium Check (Sample 1.04) Sample#: 1.04; SSB 11288-MA; DBa_Upper Sand; MD = 7823 ft; TVD = 4491 ft; TVDSS = -4413 ft 300 .. 200 100 000 C .. C6 4> 7 ·100 il il ! I I II I I , il I I I ·200 . C9 ·300 ·400 -400 ·300 ·2.00 ·100 000 100 2.00 3JO + ·500 F WCP Oilphase-DBR 19 Job #: 200400128 I Client: BP Field: Orion Schlumb8Pl8P I Well: L-216 Sand: OA SAND I Table 11: C30+ Composition, GOR, °API, bV Single-Stage Flash (Sample 1.07) Sample#: 1.07; CSB 7321-MA; OA Sand; MO = 7718 ft; TVO = 4435 ft; TVOSS = -4355 ft Component MW Flashed Gas Flashed Liquid Monophasic Fluid I (g/mole) WT% MOLE % WT% MOLE % WT% MOLE % Carbon Dioxide 44.01 1.30 0.49 0.00 0.00 0.03 0.17 Hydrogen SulfidE 34.08 0.00 0.00 0.00 0.00 0.00 0.00 Nitrogen 28.01 2.09 1.23 0.00 0.00 0.05 0.44 I Methane 16.04 94.40 97.41 0.00 0.00 2.32 34.86 Ethane 30.07 0.93 0.51 0.00 0.00 0.02 0.18 Propane 44.10 0.34 0.13 0.01 0.05 0.01 0.08 I I - Butane 58.12 0.10 0.03 0.00 0.01 0.00 0.02 N - Butane 58.12 0.28 0.08 0.01 0.04 0.01 0.06 I - Pentane 72.15 0.15 0.03 0.01 0.05 0.01 0.04 I N - Pentane 72.15 0.18 0.04 0.02 0.10 0.02 0.08 C6 84.00 0.07 0.01 0.11 0.46 0.11 0.30 M-C-Pentane 84.16 0.04 0.01 0.03 0.13 0.03 0.09 I Benzene 78.11 0.01 0.00 0.00 0.02 0.00 0.01 Cyclohexane 84.16 0.04 0.01 0.04 0.19 0.04 0.13 C7 96.00 0.02 0.00 0.18 0.69 0.18 0.45 M-C-Hexane 98.19 0.03 0.01 0.08 0.32 0.08 0.20 I Toluene 92.14 0.01 0.00 0.01 0.04 0.01 0.03 C8 107.00 0.01 0.00 0.31 1.07 0.30 0.69 E-Benzene 106.17 0.00 0.00 0.05 0.17 0.05 0.11 I M/P-Xylene 106.17 0.00 0.00 0.08 0.29 0.08 0.19 O-Xylene 106.17 0.00 0.00 0.02 om 0.02 0.05 C9 121.00 0.00 0.00 0.46 1.39 0.45 0.89 I pseudo C1 OH22 134.00 0.00 0.00 0.95 2.60 0.93 1.67 pseudo C11 H24 147.00 0.00 0.00 1.31 3.26 1.27 2.09 pseudo C12H26 161.00 0.00 0.00 1.84 4.18 1.79 2.69 pseudo C13H28 175.00 0.00 0.00 2.27 4.76 2.22 3.06 I pseudo C14H30 190.00 0.00 0.00 2.58 4.97 2.51 3.19 pseudo C15H32 206.00 0.00 0.00 2.99 5.33 2.92 3.42 pseudo C16H34 222.00 3.03 5.01 2.96 3.22 I pseudo C17H36 237.00 2.88 4.46 2.81 2.86 pseudo C18H38 251.00 2.98 4.35 2.90 2.79 pseudo C19H40 263.00 3.17 4.42 3.09 2.84 I pseudo C20H42 275.00 2.78 3.70 2.71 2.38 pseudo C21 H44 291.00 3.07 3.86 2.99 2.48 pseudo C22H46 300.00 2.33 2.84 2.27 1.82 pseudo C23H48 312.00 2.55 3.00 2.49 1.93 I pseudo C24H50 324.00 2.38 2.69 2.32 1.73 pseudo C25H52 337.00 2.14 2.32 2.08 1.49 pseudo C26H54 349.00 2.05 2.15 2.00 1.38 I pseudo C27H56 360.00 2.00 2.03 1.95 1.31 pseudo C28H58 372.00 2.04 2.01 1.99 1.29 pseudo C29H60 382.00 2.05 1.97 2.00 1.26 I C30+ 750.00 51.17 25.00 49.92 16.05 Total 100.00 100.00 100.00 100.00 100.00 100.00 MW 16.56 366.37 241.20 MOLE RATIO 0.3578 0.6422 I I WCP Oilphase-DBR 20 Job #: 200400128 I Client: BP Field: Orion Scblumberger I Well: L-216 Sand: OA SAND I Table 12: Calculated fluid Properties Sample#: 1.07; CSB 7321-MA; OA Sand; MO = 7718 ft; TVO = 4435 ft; TVOSS = -4355 ft Properties Flashed Gas Flashed Liquid Monophasic Fluid I Cn+ Composition Mass % Mole% Mass % Mole% Mass % Mole% C7+ 0.17 0.03 99.85 99.29 97.40 63.77 I C12+ 0.00 0.00 96.32 89.06 93.95 57.19 C20+ 74.56 51.59 72.73 33.13 C30+ 51.17 25.00 49.92 16.05 I Molar Mass C7+ 89.98 368.44 368.40 C12+ 396.24 396.24 I C20+ 529.56 529.56 C30+ 750.00 750.00 I Density C7+ 0.9583 C12+ 0.9665 0.9665 C20+ 1.0113 1.0113 I C30+ 1.0827 1.0827 FI u id at 60°F 0.9576 I Gas Gravity (Air = 1) 0.572 Dry Gross Heat Content (BTU/scf) I 1,007 I Wet Gross Heat Content (BTU/scf) 989 OBM Contamination level (wt%) I STO Basis Live Oil Basis I Stock Tank Oil Properties at Standard Conditions: Measured Calculated C30+ Properties MW I 366.37 I 750.00 I I Density (g/cm3) 0.958 1.083 Single Stage Flash Data I Original STO De-Contaminated GOR (scf!stb) 194 I STO Density (g/cm3) 0.9576 I STO API Gravity 16.3 OBM Density (g/cm3) @60°F I I I I WCP Oilphase-DBR 21 Job #: 200400128 I I I I I I I I I I I I I I I I I I I Client Well: BP L-216 Field: Sand: Orion OA SAND Figure 7: Stock Tank Oil Chromatogram (Sample Um Sample#: 1.07; CSB 7321-MA; OA Sand; MD 7718 ft; TVD 4435 ft; TVDSS 0= -4355 ft pA. 500 - <:100 - 300 200·- 100 Figure 8: k-Plot for Equilibrium Check (Sample 1,(m Sample#: 1.07; CSB 7321-MA; OA Sand; MD 7718 ft; TVD 0= 4435 ft; TVDSS 0= -4355 ft ".~_....- 2.00 ~ rtP ~ C3 100 + 000 . C7 · C6 ·100 ·200 . C9 ·300 ·300 +C10·200 ·100 0.00 100 2.00 3)0 -400 F -~-~.,_.~ WCP Oilphase-DBR 22 Job #: 200400128 I I Client: BP Field: Orion Scblulberger Well: L-216 Sand: OBa_Lower SAND I Table 13: C30+ Composition, GOR, °API, by Single-Stage Flash (Sample 1.11) Sample#: 1.11; SSB 11200-MA; DBa_Lower Sand; MD = 7847 ft; TVD = 4504 ft; TVDSS = -4426 ft Component MW Flashed Gas Flashed Liquid Monophasic Fluid I (g/mole) WT% MOLE % WT% MOLE % WT% MOLE % Carbon Dioxide 44.01 1.32 0.52 0.00 0.00 0.04 0.20 Hydrogen SulfidE 34.08 0.00 0.00 0.00 0.00 0.00 0.00 I Nitrogen 28.01 3.03 1.86 0.00 0.00 0.08 0.71 Methane 16.04 88.63 95.02 0.00 0.00 2.38 36.53 Ethane 30.07 2.13 1.22 0.00 0.00 0.06 0.47 Propane 44.10 1.04 0.41 0.01 0.10 0.04 0.21 I I - Butane 58.12 0.57 0.17 0.01 0.07 0.03 0.11 N - Butane 58.12 1.17 0.35 0.03 0.21 0.06 0.26 I - Pentane 72.15 0.56 0.13 0.04 0.20 0.05 0.17 I N - Pentane 72.15 0.61 0.14 005 0.29 0.07 0.24 C6 84.00 0.34 0.07 0.25 1.17 0.25 0.75 M-C-Pentane 84.16 0.18 0.04 0.08 0.38 0.08 0.25 I Benzene 78.11 0.03 0.01 0.01 0.07 0.01 0.05 Cyclohexane 84.16 0.14 0.03 0.09 0.41 0.09 0.27 C7 9600 0.06 0.01 0.25 1.00 0.24 0.62 M-C-Hexane 98.19 0.12 0.02 0.15 0.58 0.15 0.37 I Toluene 92.14 0.04 0.01 0.07 032 007 0.20 C8 107.00 0.02 0.00 0.28 1.02 0.27 0.63 E-Benzene 106.17 0.00 0.00 0.04 0.15 0.04 0.09 I M/P-Xylene 106.17 0.00 0.00 0.05 0.19 0.05 0.12 O-Xylene 106.17 0.00 0.00 0.04 0.13 0.04 0.08 C9 121.00 0.00 0.00 0.41 1.32 0.40 0.81 I pseudo C10H22 134.00 0.00 0.00 0.58 1.68 0.56 1.03 pseudo C11 H24 147.00 0.00 0.00 0.79 2.09 0.77 1.29 pseudo C12H26 161.00 0.00 0.00 118 2.87 1.15 1.76 pseudo C13H28 175.00 0.00 0.00 1.60 3.56 1.56 2.19 I pseudo C14H30 190.00 0.00 0.00 1.95 4.00 1.90 2.46 pseudo C15H32 206.00 0.00 0.00 2.25 4.27 2.19 2.63 pseudo C16H34 222.00 2.50 4.38 2.43 2.70 I pseudo C17H36 237.00 2.44 4.01 237 2.47 pseudo C18H38 251.00 2.56 3.97 2.49 2.44 pseudo C19H40 263.00 2.76 4.10 2.69 2.52 I pseudo C20H42 275.00 2.68 3.80 2.61 2.34 pseudo C21 H44 291.00 2.67 3.58 2.60 2.21 pseudo C22H46 300.00 2.65 3.45 2.58 2.12 I pseudo C23H48 312.00 2.52 3.16 2.46 1.94 pseudo C24H50 324.00 2.20 2.64 2.14 1.63 pseudo C25H52 337.00 2.22 2.57 2.16 1.58 pseudo C26H54 349.00 2.13 2.38 2.07 1.46 I pseudo C27H56 360.00 2.03 2.20 1.98 1.36 pseudo C28H58 372.00 2.30 2.41 2.24 1.48 pseudo C29H60 382.00 2.07 2.12 2.02 1.30 I C30+ 750.00 56.05 29.15 54.55 17.94 Total 100.00 100.00 100.00 100.00 100.00 100.00 MW 17.20 390.01 246.68 I MOLE RATIO 0.3845 0.6155 I WCP Oilphase-DBR 23 Job #: 200400128 I I I I I I I I I I I I I I I I I I I Client: Well: BP L-216 Field: Sand: Orion OBa_Lower SAND SchlulbePglP Table 14: Calculated fluid Properties Sample#: 1.11; SSB 11200-MA; OBa_Lower Sand; MD = 7847 ft; TVD = 4504 ft; TVDSS = -4426 ft Properties Flashed Gas Flashed Liquid Monophasic Fluid Cn+ Composition Mass % Mole % Mass % Mole % C7+ 0.61 0.12 99.61 97.97 C12+ 0.00 0.00 96.77 88.62 C20+ 79.53 57.45 C30+ 56.05 29.15 Molar Mass C7+ 88.99 396.53 C12+ 425.89 C20+ 539.87 C30+ 750.00 Density C7+ 0.9627 C12+ 0.9696 C20+ 1.0030 C30+ 1.0627 Fluid at 60°F 0.9608 Gas Gravity (Air = 1 ) 0.594 Dry Gross Heat Content (BTU/scf) I 1,030 Wet Gross Heat Content (BTU/scf) 1,012 OBM Contamination Level (wt%) I STO Basis #VALUE! Live Oil Basis Stock Tank Oil Properties at Standard Conditions: Measured Calculated C30+ Properties MW I 390.01 I 750.00 I Density (g/cm3) 0.961 1.063 Single Stage Flash Data Original STO De-Contaminated GOR (scf/stb) 205 I STO Density (g/cm3) 0.9608 STO API Gravity 15.8 OBM Density (g/cm3) @60°F WCP Oilphase-DBR 24 Mass % 96.95 94.17 77 .40 54.55 Mole% 60.35 54.55 35.37 17.94 396.30 425.89 539.87 750.00 0.9696 1.0030 1.0627 Job #: 200400128 I I I I I I I I I I I I I I I I I I I I Client: Well: BP L-216 Field: Sand: Orion DBa_Lower SAND Figure 9: Stock Tank Oil Chromatogram (Sample 1.11) Sample#: 1.11; SSB 11200-MA; OBa_Lower Sand; MD = 7847 ft; TVD = 4504 ft; TVDSS -4426 ft pA. 500 -, o -.- ('- 01 :::~~~~~R üGÜÕüOÜ , 20 , 30 , 4ú , 50 Figure 10: k~Plotfor Equilibrium Check (Sample 1.11) Sample#: 1.11; SSB 11200-MA; OBa_Lower Sand; MD 7847 ft; TVD = 4504 ft; TVDSS = -4426 ft 100 2.00 100 . 000 4> C7 ~ C6 .. C8 ·100 ·200 ·100 ·300 .. Cl0 ' ·2.00 ·100 000 100 2.00 3)0 -4.00 . C12 ·500 f WCP Oilpl1ase-DBR 25 Job #: 200400128 I I Client: Well: I I I I I I I I I I I I I I I I I WCP Oilphase-DBR BP L-216 Field: Sand: Orion OBd SAND Scblumb8Pger Table 15: Summary of Results of Sample 1.02 Sample#: 1.02; CSB 7478-MA; OBd Sand; MD = 8105 ft; TVD = 4648 ft; TVDSS = -4569 ft Reservoir Conditions: 2043 95 Pressure: Temperature: Summary of Fluid Properties: 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): Density: Formation Volume Factor Single-stage Flash: Total Differential Liberation: Total Separator Flash: Note: Standard conditions are 14.696 psia and 60°F 1.799 266 STO °API 0.924 9.0 8.7 0.863 @Pres & Tres 26 psia OF psia scf Istb scf/stb scf/stb Gas Gravity (Average) 0.687 CP 1O.6/psi glee cP 1 06 Ipsi glee @Psat & Tres Job #: 200400128 I I I I I I I I I I I I I I I I I I I Client: Well: BP L-216 Field: Sand: Orion OBd SAND Scblumb81'18P Sample#: 1.02; CSB 7478-MA; OBd Sand; MO = 8105 It; TVO = 4648 It; TVOSS = -4569 It Reservoir Oil Viscosity at Tres The liquid phase viscosity was measured at the reservoir temperature of 95°F. These values as a function of selected pressure steps are summarized in Table 16. The liquid phase viscosity values are graphically presented in Figure 11. 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 16: Reservoir fluid Viscosity 95°f Sample#: 1.02; CSB 7478-MA; OBd Sand; MD = 8105 ft; TVD = 4648 ft; TVDSS = -4569 ft Pressure Viscosity @ Tres (psia) (cP) 1 2 3 4 5 6 7 Pi Pb 10 11 12 13 14 15 16 17 STO WCP Oilphase-DBR 8035 7015 6011 5037 4037 3049 2512 2043 1799 1653 1544 1464 1283 1146 1030 789 535 14.696 18.1 16.1 14.4 12.9 11.5 10.2 9.5 9.0 8.7 9.3 9.8 10.2 11.1 11.9 12.4 14.0 16.3 39.9 27 Job #: 200400128 I I I I I I I I I I I I I I I I I I I Client: Well: BP L-216 Field: Sand: Orion OBd SAND Schlumbergep Figure 11: Reservoir Fluid Viscosity 95°F Sample#: 1.02; CSB 7478-MA; OBd Sand; MD = 8105 ft; TVD = 4648 ft; TVDSS = -4569 ft ii:" ~ ~ .¡;¡ 25 CI u <II :; WCP Oilphase-DBR 45 400 35 30 20 15 10 5 o 2000 4000 Pressure (psia) 28 ~ 6000 8000 10000 Job #: 200400128 I I I I I I I I I I I I I I I I I I I Client: Well: BP L-216 Orion OBb SAND Field: Sand: Schlumb8Pl8P Table 17: Summary of Results of Sample 1.03 Sample#: 1.03; CSB 8173-QA; OBb Sand; MO = 7902 ft; TVO = 4535 ft; TVOSS = -4456 ft Reservoir Conditions: Pressure: Temperature: Summary of Fluid Properties: 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: 16.00 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 1980 93 1,536 234 STO °API 0.917 16.61 0.866 @Pres & Tres WCP Oilphase-DBR 29 psia OF psia scf Istb scf Istb scf Istb Gas Gravity (Average) 0.638 CP 1O.6/psi glee CP 1O.6/psi glee @Psat & Tres Job #: 200400128 I I I I I I I I I I I I I I I I I I I Client: Well: BP L-216 Field: Sand: Orion OBb SAND Schlulb8Pger Sample#: 1.03; CSB 8173-0A; OBb Sand; MD = 7902 It; TVD = 4535 It; TVDSS = -4456 It Reservoir Oil Viscosity at Tres The liquid phase viscosity was measured at the reservoir temperature of 93°F. These values as a function of selected pressure steps are summarized in Table 18. The liquid phase viscosity values are graphically presented in Figure 12. 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 18: Reservoir Fluid Viscosity 93°F Sample#: 1.03; CSB 8173-QA; OBb Sand; MO = 7902 ft; TVO = 4535 ft; TVOSS = -4456 ft Pressure Viscosity @ Tres (psial (cPI 1 2 3 4 5 6 7 Pi Pb 10 11 12 13 STO WCP Oilphase-DBR 8005 6991 5979 4918 3987 3017 2535 1980 1536 1382 1113 922 634 15 31.7 28.5 25.4 22.5 20.2 18.2 17.5 16.6 16.0 17.4 20.5 22.7 28.6 62.4 30 Job #: 200400128 I I I I I I I I I I I I I I I I I I I Client: Well: BP L-216 Orion OBb SAND Scblumb8Pl8P figure 12: Reservoir fluid Viscosity 93°f Sample#: 1.03; CSB 8173-QA; OBb Sand; MD = 7902 ft; TVD = 4535 ft; TVDSS = -4456 ft 70 o 60 50 ~ E. .æ:- 'w 40 CI U <II :> 30 20 10 o WCP Oilphase-DBR Field: Sand: I , I , 2000 4000 6000 Pressure (psia) 31 8000 10000 Job #: 200400128 I I Client: Well: I I I I I I I I I I I I I I I I BP L-216 Field: Sand: Orion OBa_Upper SAND Scblumberger Table 19: Summary of Results of Sample 1.04 Sample#: 1.04; SSB 11288-MA; DBa_Upper Sand; MO = 7823 ft; TVO = 4491 ft; TVOSS = -4413 ft Reservoir Conditions: Pressure: Temperature: Summary of Fluid Properties: 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: Compressibillity (Co): Density: Formation Volume Factor 2064 93 psia OF 1,973 psía 218 scf/stb scf/stb scf/stb Gas Gravity (Average) 0.599 STO °API 0.941 26.82 CP 1O.6/psi g/cc 26.49 cP 10·6/psi g/cc @Psat & Tres 0.890 @Pres & Tres Single-stage Flash: Total Differential Liberation: Total Separator Flash: Note: Standard conditions are 14.696 psia and GO°F I WCP Oilphase-DBR 32 Job #: 200400128 I I I I I I I I I I I I I I I I I I I Client: Well: BP L-216 Field: Sand: Orion OBa_Upper SAND Scblumberger Sample#: 1.04; SSB 11288-MA; OBa_Upper Sand; MO = 7823 ft; TVO = 4491 ft; TVOSS = -4413 ft Reservoir Oil Viscosity at Tres The liquid phase viscosity was measured at the reservoir temperature of 93°F. These values as a function of selected pressure steps are summarized in Table 20. The liquid phase viscosity values are graphically presented in Figure 13. 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 20: Reservoir fluid Viscosity 93°f Sample#: 1.04; SSB 11288-MA; OBa_Upper Sand; MD = 7823 ft; TVD = 4491 ft; TVDSS = -4413 ft Pressure Viscosity @ Tres (psia) (cP) 1 2 3 4 5 6 7 8 Pi Pb o o o o STO WCP Oilphase-DBR 6957 6019 5031 4519 4029 3529 3026 2530 2064 1973 1677 1429 1107 826 14.696 53.0 47.0 41.1 38.3 35.8 33.4 31.1 29.0 26.8 26.5 27.9 29.4 33.0 39.4 118.8 33 Job #: 200400128 I I I I I I I I I I I I I I I I I I I Client: Well: BP L -216 Field: Sand: Orion DBa_Upper SAND Scblumberger figure 13: Reservoir fluid Viscosity 93°f Sample#: 1.04; SSB 11288-MA; OBa_Upper Sand; MO = 7823 ft; TVO = 4491 ft; TVOSS = -4413 ft 1200 100 80 A:" ~ Ç:- '¡¡¡ CI .... en :;: 60 40 20 o WCP Oilphase-DBR 2000 4000 6000 8000 Pressure (psia) 34 Job #: 200400128 I I I I I I I I I I I Client: Well: I I I I I I I I WCP Oilphase-DBR BP L -216 Field: Sand: Orion OA SAND Scblumberger Table 21: Summary of Results of Sample 1.07 Sample#: 1.07; CSB 7321-MA; OA Sand; MD = 7718 ft; TVD = 4435 ft; TVDSS = -4355 ft Reservoir Conditions: Pressure: 1957 92 Temperature: Summary of Fluid Properties: Bubble Point Pressure AtTres 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: 87.76 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 1.776 194 STO °API 0.958 90.12 0.913 @Pres & Tres 35 psia OF psia scf/stb scf/stb scf/stb Gas Gravity (Average) 0.572 CP 1O.6/psi g/cc CP 1O.6/psi g/cc @Psat & Tres Job #: 200400128 I I I I I I I I I I I I I I I I I I I Client: Well: BP L-216 Field: Sand: Orion OA SAND Scblumbepgep Sample#: 1.07; CSB 7321-MA; OA Sand; MD = 7718 ft; TVD = 4435 It; TVDSS = -4355 It Reservoir Oil Viscosity at Tres The liquid phase viscosity was measured at the reservoir temperature of 92°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 14. 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 92°F Sample#: 1.07; CSB 7321-MA; OA Sand; MD = 7718 ft; TVD = 4435 ft; TVDSS = -4355 ft Pressure Viscosity @ Tres (psia) (cP) 1 2 3 4 5 6 7 8 Pi Pb 11 12 13 14 15 16 STO WCP Oilphase-DBR 8000 7053 6114 5035 4041 3531 3007 2523 1957 1776 1522 1356 1119 946 770 587 14.696 214.8 193.1 172.0 148.3 127.4 117.2 107.3 98.8 90.1 87.8 96.3 105.9 122.6 138.8 162.3 191.3 340.8 36 Job #: 200400128 I I I I I I I I I I I I I I I I I I I Client: Well: BP L-216 Orion OA SAND Scblumb8rg8P figure 14: Reservoir fluid Viscosity 92°f Sample#: 1.07; CSB 7321-MA; OA Sand; MO = 7718 ft; TVO = 4435 ft; TVOSS = -4355 ft 350 b 300 250 iL:" E. ~ '¡¡¡ 200 CI u en s: 150 100 WCP Oilphase-DBR Field: Sand: 50 o , I , 2000 4000 BODO Pressure (psial 37 BODO 10000 Job #: 200400128 I I I I I I Client: Well: I I I I I I I I I I I I BP L-216 Field: Sand: Orion o Ba_Lower SAND Schlulberger Table 23: Summary of Results of Sample 1.11 Sample#: 1.11; SSB 11200-MA; OBa_Lower Sand; MD = 7847 ft; TVD = 4504 ft; TVDSS = -4426 ft Reservoir Conditions: Pressure: Temperature: Summary of Fluid Properties: 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: 118.93 Compressibillity (Co): Density: Properties at Saturation Conditions Viscosity: 114.64 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 1992 91 psia of 1)66 psia 205 scf/stb scf/stb scf Istb Gas Gravity (Average) 0.594 STO °API 0.961 cP 10'6¡psi glee cP 106/psi glee @Psat & Tres 0.917 @Pres & Tres I WCP Oilphase-DBR 38 Job #: 200400128 I I I I I I I I I I I I I I I I I I I Client: Well: BP L-216 Field: Sand: Orion DBa_Lower SAND ScblumberglP Sample#: 1.11; SSB 11200-MA; DBa_Lower Sand; MD = 7847 It; TVD = 4504 It; TVDSS = -4426 It Reservoir Oil Viscosity at Tres The liquid phase viscosity was measured at the reservoir temperature of 91°F. These values as a function of selected pressure steps are summarized in Table 24. The liquid phase viscosity values are graphically presented in Figure 15. 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 24: Reservoir fluid Viscosity 91°f Sample#: 1.11; SSB 11200-MA; OBa_Lower Sand; MD = 7847 ft; TVD = 4504 ft; TVDSS = -4426 ft Pressure Viscosity @ Tres (psia) (cP) 1 2 3 4 5 6 7 Pi Pb 10 11 12 13 14 15 STO WCP Oilphase-DBR 8000 7078 6067 5027 4042 3078 2560 1992 1766 1653 1340 1129 922 712 534 14.696 291.1 256.0 221.6 190.4 164.2 141.4 130.3 118.9 114.6 119.2 141.2 160.9 188.2 220.0 259.7 555.1 39 Job #: 200400128 I I I I I I I I I I I I I I I I I I I Client: Well: BP L-216 Field: Sand: Orion DBa_Lower SAND Schlumb8rger Figure 15: Reservoir Fluid Viscosity 91°F Sample#: 1.11; SSB 11200-MA; DBa_Lower Sand; MD = 7847 ft; TVD = 4504 ft; TVDSS = -4426 ft ~o 1 500 - 400 ~ ~ ~ .¡¡¡ CI U CII :;; 300 200 100 o WCP Oilphase-DBR 2000 4000 6000 Pressure (psial 40 8000 10000 Job #: 200400128 I I I I I I I I I I I I I I I I I I I Client: BP Well: L-216 Installation: API Gravity Bg Bo CCE DV GLR GaR La n OBM P Pb PV Pi R Rs T V Vr STL STO %,w/w Z Field: Sand: Job#: Orion Schlumbepgep 200400128 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 41 Job #: 200400128 I Client: BP Field: Orion SchlulbePlep I Well: L-216 Sand: Installation: Job#: 200400128 I Appendix B: Molecular Weights and Densities Used Components MW Density (glee) I CO2 44.01 0.827 H2S 34.08 0.993 N2 28.013 0.808 C1 16.043 0.300 I C2 30.07 0.356 C3 44.097 0.508 I-C4 58.124 0.567 I N-C4 58.124 0.586 I-C5 72.151 0.625 N-C5 72.151 0.631 I C6 84 0.660 MCYC-C5 84.16 0.753 BENZENE 78.11 0.884 I CYCL-C6 84.16 0.781 C7 96 0.688 MCYCL-C6 98.19 0.773 TOLUENE 92.14 0.871 I C8 107 0.749 C2-BENZEN 106.17 0.870 M&P-XYLEN 106.17 0866 I O-XYLENE 106.17 0.884 C9 121 0.768 C10 134 0.782 I C11 147 0.793 C12 161 0.804 C13 175 0.815 C14 190 0.826 I C15 206 0.836 C16 222 0.843 C17 237 0.851 I C18 251 0.856 C19 263 0.861 C20 275 0.866 I C21 291 0.871 C22 300 0.876 C23 312 0.881 C24 324 0.885 I C25 337 0.888 C26 349 0.892 C27 360 0.896 I C28 372 0.899 C29 382 0.902 I I I WCP Oilphase-DBR 42 Job #: 200400128 I I I I I I I I I I I I I I I I I I I Client: BP Well: L-216 Installation: Field: Sand: Job#: Orion Scblumberger 200400128 Appendix C: EOUIPMENT Ruíd Preparatíon and Va/ídatíon 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 Ljhr. 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 (FID). In this system, separation of individual components is carried out in a 30m long, 530mm diameter "Mega bore" 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 (TCD) while the C5+ components are analyzed for using a FID 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. Ruíd Vo/umetflc (PVT) and Víscosíty Equipment WCP Oilphase-DBR 43 Job #: 200400128 I I I I I I I I I I I I I I I I I I I Client: BP Field: Well: L -216 Sand: Installation: Job #: 200400128 The preliminary saturation pressure, constant composition expansion (CCE), differential vaporization (DV), multi-stage separation tests (MSST) are measured using a pressure-volume-temperature (PVT) 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. Orion Scblumberger 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 44 Job #: 200400128 I I I I I I I I I I I I I I I I I I I Client: BP Field: Well: L-216 Sand: Installation: Job #: 200400128 The JEFRI PVT cell is also equipped with fiber optic light transmittance probes to measure the onsets of hydrocarbon solids nucleation (OHSP) 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 (NIR) 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 level) 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 (LSS). Orion ScbluIDb8PD8P 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 45 Job #: 200400128 I I I I I I I I I I I I I I I I I I I Client: BP Well: L-216 Installation: Field: Sand: Job#: Orion Schlumberger 200400128 Appendix D: PROCEDURE Fluids Preparation and Valtdation After homogenizing, a small portion of the single-phase reservoir fluid is first subjected to a single stage flash experiment to determine flash Gas-ail-ratio (GaR). 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 GaR 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 GaR 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 GeE 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. · · · Multi-Stage Separation Test WCP Oilphase-DBR 46 Job #: 200400128 I I I I I I I I I I I I I I I I I I I Client: BP Field: Well: L -216 Sand: Installation: Job #: 200400128 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. Orion ScblulDbepgep . · 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 OJ! (STOJ Viscosity and Density Measurements A sample of STO is taken in a known capillary tube to measure the STO 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. Asphaltene, Wax and Sulfur Content Measurements Asphaltene content of stock-tank oil samples is conducted using the IP-143 (French Institute of Petroleum) 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 Product) 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. WCP Oilphase-DBR 47 Job #: 200400128 I I I I I I I I I I I I I I I I I I I Client: BP Well: L -216 Installation: Field: Sand: Job#: Orion SchluDlberger 200400128 SAR(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 5186-91) 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 (asphaltenes). 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 (polars) 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 48 Job #: 200400128 www.slb.com/oilfield WT_03_137_0 December 2003 ©Schlumberger *Mark of Schlumberger Schlumberger