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Zot - 21 °1 ,IF • II �,....: 17%ijZ a 9 United States Department of the Interior '` " 9 BUREAU OF SAFETY AND ENVIRONMENTAL ENFORCEMENT 4,gRC�309 Alaska OCS Region 3801 Centerpoint Drive,Suite 500 Anchorage,Alaska 99503-5823 FEB 2 7 2018 RECEIVED John A. Barnes MAR n 1 min Senior Vice President and North Slope Asset Team Leader Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Dear Mr. Barnes: During the inspection out-briefing at Northstar Production Island on July 20, 2017, Hilcorp Alaska, LLC (HAK), requested clarification concerning our approach to the inspections of federal wells at Northstar. This topic has come up in various meetings with HAK in recent years. Therefore, this letter provides updated guidance to HAK regarding how we will approach inspections related to the federal wells at Northstar. Our goal here is to provide better clarity for HAK by setting down in writing what we have been relating verbally to HAK since you took over as operator of Northstar in 2014, and by drawing clear distinctions around our inspection parameters where it is practical for us to do so. Please be advised that this letter explicitly supersedes the February 1, 2005 letter from this office to BP Exploration Alaska, Inc. (Jeffrey Walker to Gray Herring). BSEE will conduct inspections related to all North Star federal wells (currently including NS-6, NS-9,NS-12,NS-22,NS-30,NS-32, and NS-34A) according to the following. The federal wells are subject to applicable federal regulations from bottom hole through Safety and Pollution Prevention Equipment(SPPE) and any devices that protect the wellhead. SPPE and devices that protect the wellhead will be generally defined as, but may not be limited to: a. Subsurface Safety Valve (SSSV) and their control system/actuators to include any component in the process stream establishing set points. b. Surface Safety Valve (SSV) and related actuators(e.g. a Pressure Safety High/Low, or PSHL)to include components establishing set points such as: tubing and annular pressures (static and flowing), first flowline segment pressure ratings, and first stage separator vessel pressure ratings. c. Injection Valve. d. Tubing/annular subsurface and surface safety devices. e. Emergency Shut Down (ESD) system and related controls. f. Any Temperature Safety Elements (TSE), Temperature Safety High (TSH) or other heat/fire detector installed at the well related to the actuation of well safety devices. g. Wellhead Injection Lines and Gas Lift Wellhead Injection Lines and related safety devices to include: Pressure Safety Valves (PSV), Flow Safety Valve (FSV), and PSHL. • • This letter sets forth the current BSEE regional policy for conducting federal well inspections at Northstar; however it does not represent a binding statement on the extent of BSEE's jurisdiction over facilities in state waters with wells that reach the OCS. If you have any questions about this guidance please contact Michael Jordan at michael.jordan@bsee.gov or at(907) 334-5300. Sincerely, 1 Z'''/ !A11011,10 Kevin J. Pendergast, PE/PG Regional Supervisor, Field Operations cc: James Regg, Inspections Supervisor, AOGCC UNSCANNED, OVERSIZED MATERIALS AVAILABLE: bed / :;, I ? FILE # /- ~~·oC;~1¥~J To request any/all of the above information, please contact: Alaska Oil & Gas Conservation Commission 1333 W. 7th Ave., Ste. 100 I Anchorage, Alaska 99501 Voice (907) 279-1433 ¡Fax (907) 276-7542 GDF arm �� I//7, `fiTHE STATE d+ C '�__6 �_ -,1 S !p"� 5 9 (J�' \ �- 1J �i- .\ ' ) .J'n.\\4�_ J.� 4 S - - - it -= ^_� — 333 ',Nest Se./enth Allenue 7j, GONER\OR SEAN I'AR\LLL Anchorogo Alcsku 9950[ 3572 . 1\40,1 90/.279 1433 A As,,'� Fa; 9)7 i7 . /:,/,') Mark Sauve SCANNED AUG 0 6 2014 Petroleum Engineer 0 1- g-11 BP Exploration(Alaska), Inc. oil P.O. Box 196612 Anchorage, AK 99519-6612 Re: Northstar Field,Northstar Oil Pool, NSTR NS09 Sundry Number: 314-106 Dear Mr. Sauve: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, 1°--; ?Vt — e Cathy P. oerster Chair DATED this 2- day of February, 2014. Encl. RECEIVED • STATE OF ALASKA FEB Q 4 20 4 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 073-- 2(`276 20 AAC 25.280 AO�^ 1.Type of Request: Abandon❑ Plug for RedrilI❑ Perforate New Pool❑ Repair Well❑ Change Approved Program❑ Suspend❑ Plug Perforations❑ Perforate❑ Pull Tubing❑ '/ )Iq Time Extension❑ Operations Shutdown❑ Re-enter Susp.Well❑ Stimulate❑ Alter Casing❑ 21Other:lPa k2 Set 1:1, 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. BP Exploration(Alaska),Inc. Development ❑✓ - Exploratory ❑ 201-219-0 • 3.Address: Stratigraphic ❑ Service ❑ 6.API Number. P.O.Box 196612,Anchorage,AK 99519-6612 50-029-23052-00-00 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order govems well spacing in this pool? 458A• - NSTR NS09 • Will planned perforations require a spacing exception? Yes ❑ No III• 9.Property Designation(Lease Number): N6, 10.Field/Pool(s): ADL03127991 GCS If-018 NORTHSTAR, NORTHSTAR OIL - 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth TVD(ft): Plugs(measured): Junk(measured): 13429 • 11228 . 13383 . 11182 • None None Casing Length Size MD ND Burst Collapse Structural Conductor None None None None Surface 3354 13-3/8"68#L-80 44-3398 44-3216.36 5020 2260 Intermediate None None None None None None Production 11477 9-5/8"47#L-80 42-11519 42-9423.07 6870 4760 Liner See Attachment See Attachment See Attachment See Attachment See Attachment See Attachment Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attachment I See Attachment 4-1/2"12.6#13Cr80 13Cr80 40-12767 Packers and SSSV Type: See Attachment for Packer Types Packers and SSSV MD(ft)and ND(ft): See Attachment for Packer DeAs/ 4-1/2"Camco WRDP-2 SSV• - 2030',2027.92' 12.Attachments: Description Summary of Proposal ❑ 13.Well Class after proposed work: Detailed Operations Program 0 • BOP Sketch ❑ Exploratory ❑ Development ❑� ' Service ❑ 14.Estimated Date for 15.Well Status after proposed work: 3/3/14 Commencing Operations: Oil 0• Gas ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Mark Sauve Email Mark.SauvpaaP, om Printed Name Mark Sauve Title PE Signature ® Phone Date rC/-•e.---r-.../ 564-4660 2/24/2014 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3\''-4,'- \U� Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: RBDMS MAY 1 0 2014 Spacing Exception Required? Yes ❑ No Irl Subsequent Form Required: /19 _ 4.d 4 4 r^� / APPROVED BY ! Approved by: ; �.j,�(/j✓) COMMISSIONER THE COMMISSION Date: 2 -2:7 /_/ '1� e44 I A iths 21.2417 Form 10-403 'evised 1/2010 Ap o i i li r 2 months fr m the date of approval. Submit in Duplicate 1/1 /z4/1z)- his/r</ • ALASKA WELL ACTIVITY STATEMENT OF REQUIREMENTS(V1.2,DBR,LHD 11/20/13) General Information Well Name: NS-09 Well Type: NATURAL FLOW PRODUCER Activity Description: GSO Well Activity Classification: CONVENTIONAL 4 Field/Reservoir: NORTHSTAR Cost Code/AFE: ANSNRWOS Job Type: GSO-LTP 12 Month Avg 10R,bopd: 10 AWGRS Job Scope: PROFILE MODIFICATION Estimated Cost,SM: Sundry Form 10--403 Reqd? Yes Sundry Form 10-404 Required? Yes Other regulatory requirements? APM from BSEE Primary Secondary Base Management Engr: Mark Sauve Contact numbers: 19071 564-4352 19071 748-2865 Well Intervention Engr: Bethany Freel Contact numbers: (907)564-4661 (907)378-6493 Lead BM Engineer: Mark Sauve Contact numbers: 1907)564-4660 (907)748-2865 Date Created: January 8,2014 Revisions(date,who,what changed): Current Well Status Information Current Status: Operable Recent Well Test or Injection Rate and Pressure: 12/10/13 1 451 bopd I 53 bwpd 155 6 MMscfpd 1123,408 GOR 1165 beans' 807 psi I No GL Recent H2S (date,ppm) 6/13/20091 7 ppm If inoperable or under evaluation, why? N/A Datum depth,ft TVDss 11,100'TVDss Maximum Deviation tangle and depth) 46° 16,169'MD Reservoir pressure,psig 5,100 psi Minimum ID and Depth 3.725'®12,754'MD Reservoir temperature,F 252°F Last downhole operation(date,operation) SL-10/29/13 set SSSV Shut in wellhead pressure 3,812 psi Most recent TD tag,(date,depth,toolstring ODI SL-05/17/13 Drifted w/1.875'stem&XN locator Tag TD®13,373'ELMD(corrected) Known mechanical integrity problems(specifics) None Comments,well history, NS09 was completed in early 2002 and is a high GOR well.In an attempt to make this well a competitive,low GOR producer,it was squeezed and reperfed in July 2006 but the GSO failed to background information,etc: make a significant improvement to the producing GOR.A follow-up P-prof in December 2006 indicated the squeeze to be leaking gas in two separate places. Since that time very little intervention work has been done on NS09.A GSO using a Slickline deployable liner patch with swell packer elements was deployed in May 2013 but since that time the GOR fron NS09 has returned to previous levels and it is suspected that the patch is leaking It is the intent of this program to detemine if the patch is leaking,specifically allowing gas up the backside of the patch and if so then to deploy a liner top packer to shut off that leak path. Well Intervention Details Suspected Well Problem: 'High GOR at present. Specific Intervention or Well Objectives: 1 Determine if the GSO patch deployed last May has failed and if so where the major gas entry points are. 2 Deploy a liner top packer(LTP)to the top of the liner patch if the logging results indicate that by doing so the primary gas entry point would be isolated. 3 Key risks,critical issues: Mitigation plan: 1 Real-time log interpretation accurately identifiing the primary gas entry point. Have PE's standing by to interpret log and decide on LTP deployment without rigging down a-line 2 Successfully deploy the LTP Run dummy LTP prior to deployent&have LTP service hand on site for actual deployment. 3 Successfully deploy the SSSV IBSEE certified with oversize packing)after LTP is set. Summary Step# Service Line Activity 1 S Pull SSSV,D&T for logging tool deployment and run dummy LTP to ensure seals will engage fully if real LTP is run. 2 E Run P-prof into liner,determine primary gas entry point(s). 3 S Deploy LTP into top of liner patch if P-prof indicates a high likelyhood of GSO success.Re-run WRDP-2 SSSV with oversize packing IBSEE certified) Detailed work scope 11f no recommended practice or standard procedure exists for the intervention type,a well specific procedure is required in addition to the SOR): 1 2 3 Performance Expectations(may be NA if no change anticipated due to the intervention) Expected Production Rates: BOPD_ 450 MMSCFD 35 BWPD 100 FTP(psi): 850 Choke setting: 176 Post job POP instructions: I Attachments-include in separate excel worksheets Required attachments:Current wellbore schematic As needed depending on type of work: Perforating form,logging form,well test chart, annotated mini log, annotated log section,tubing/casing tallies,wellhead info,etc Approvals Base Mgmt Approval: Date: Wells Approval: Date: PRODUCTION PROFILE LVer HD 3.0210/02/13 Well: NS-09 Prop.Code: GSO-LTP CC or AFE:ANSNRWOS API#: 50-029-23052-00 Name:Mark Sauve(Nstr PE) Contact numbers: 907-564-4660(H) Proc.Dist. Date: Contact numbers: 907-748-2865(M) Town: Contact numbers: APE Well File Objectives(In order of importance): Slope: Determine primary gas entry point(s) W/L(3) Deploy Liner Top Packer if primary gas entry point is determined to be at top of patch(coming from backside) FE Lostging Notes: Velocities are potentially very high inside of 2-7/8"liner patch. Well will need to be severely choked to prevent being blown up hole.. Accurate 3-phase splits are not the primary objective,we just need to know if there is a large gas entry at top of patch indicating flow from backside •Make sure well is in test during logging and attach WS30 Tie-In Log: GR/CCL Co. Schlum Date: 1/12/2002 Tie-In Method: @ Min ID: 2.205"in NX nipple @ 13,153'MD Stable Producer? yes Produce For: 0 days before logging. Gas Jetting Expected? Yes Expected H2S: 7 ppm Date of Last PPROF: 12/22/2006 Last Tag: 13,373 ft ELM/SLM: ELMD RH/Fill Date of Tag: 5/17/2013 FCO if tag above: 1)RIH with: GR/CCL/TEMP/PRESS/DUAL SPINNERS 0.0° 2)Other Info: Well produces 55+MMSCFD of gas at full open choke. PPROF Logging Summary-Tie-In Log:Schlumberger GR/CCL dated 1-12-02 Pass Direction Speed(fpm) Depth(ft,md) ( Notes PPROF Flowing Pass Up/Down 40 13,000'-TD Well Flowing Flowing Pass Up/Down 60 13,000'-TD Well Flowing Flowing Pass_ Up/Down _ 80 13,000'-TD Well Flowing Stop Counts Stops - 13,100 Well Flowing 13,200 13,300 13,340 Jewelry Log Up 80 12,600'-TD Well SI LOG PRESENTATIONS 1.Job Comments-operating steps in sequence,flow rates for logging passes and basic field interpretation including production and injection splits. 2.Flowing Overlay—Spinner,temperature and pressure data from the 60 fpm up passes. Presented on a 5"/100ft. Note flow rates for flowing pass in log header. 3.Flowing UP Pass Overlay—Spinner,temperature and pressure for 40 fpm,60 fpm,and 80 fpm passes. 4.Flowing UP/Down Pass Overlay—Spinner,temperature and pressure for 60 fpm passes. 5.Production/Injection Overlay—Spinner,temperature and pressure for 60 fpm up passes. 6.Baseline Injection/Borax Overlay 7.GHOST Log TFPF. ATESVGI5-1/6"51119 WELLHEAD= A88413113.1*'al nBow_511331 NS09 I SAT 9 1101E8 WELL RELLUELE$A SEMI. ',AWE- ACTLATOR= EAI1B CIMEMI E TEE I LW".NO70 80131RE V413.1 Pa MEV 6 56 V IN ILL-V- 402/:29 1601 KCP- 820. 2030'. '(-41 12-/ 0969 t0010 SLVO MP.0-1.413'I MN Anips- 46' 61664 FrIO - r1 M0' 1277S '. I MY H11-34T 51A0t 00L-Mt I 13 3Itr 724I.81*L INDIC.Ita".12 4 Ir H laser ruts FT!AA WIWI A It NC) IVU [XV I rep.1 VLV LAIC14 POql I 'AIL Minimum ID=2.20S-fa 13153' Ell I I 5150'Ittsel AS I ,*•1314 I PUY BK ' 0 100101121 2-718"X N NIP Tor,or 7'LNII I I flaw ] IT 1132V -9 91 4 7.LPI, 101610k ID-7 I sec 1.-aa utra-c,u-am- --I 11611T 6. I 12671P)128917 ELM)-4-11?PIPER omic i TPANSCI.X39;CI-,.3 Mr I 111 inar H4-1/2"it15 X Kw,0-3.0121 12716' --,7"44 172'MRS'S R(q,Cr a 3 Ali. I I 12742 -14 112-11(1 X MR 0-7413'I I I 1273V(12756'ELI1)I-4-1112.111M)(NW LE-3.'25- r01i=18G.-ii 810.13CRVAN-ACE. H 1276t' }-,....,...„...,„ 52 Opt,17-3.956. 1276T 1-.4 112-PA-ft/ID 3 ASV ICP Of 4.18-11411 7 127$6. I • , 0276$ H7'XE'TOR 7XP I T. 13-2 I -1,,. mew -4,-.,0/0•1112A uout as.mat,13-T ..------.... 12761' .....-9.A 4-117.613,U.'3 PRP r_MI.07/71,113RIC-nt ----TAW-I, 0383 bp,0-4216. .. '-'41 IL 0--.4-o1611041 S1/911/1147 . 467101.yowl,OVEN IWELATIVEY 111412111E1 (NSW LOG.GEPC0A-61111 13153' -.z-mr PVE w1 SWELL 141PW1041. ANOLEAT TOPPER- 6.61 133117 .1)0116'ELA 1 Mr WAS013; t.TAA Wtirar to PracJeat OH for 11101ono al pert data ji I SVC 3l7 INITRVAL11/13)/L#/Stz, 1161T ' WV 2-716. 6 13193.13333 S 0.415/02 , mi.. H._1,7.OM 4,102.014 II r 7 S'(0112613) I 2-716' 0 13714.EV14/3 0 MAW"; GNU 11111=411 4.172't Nsx,17 Mt 13CR VAIII-ACE. H 13429• 0'52 Apt CI 3 4311- CATE !FEN 331 COMIENTS 081E NOV 67 c ,AENTs NO67116TAR ,.'71041/62 847941.COMPLETION 021711 14840.0 AWED S....1/SAFETY 1431t YELL 0 ')7127116,CALLWAG WANT SOZ PEWS 092101.1 5(71 721.SCT W.L.ANTI- 0 1E3161114.'2012160 /38138/06 waprpx FERFORATONS 11111/13 IPA&R.V7219111 NCR WRAP(arsita) Am.&5*020 now co 11112747'workPic intl....J.40w'LOCATION SEC 11-11.4,0138,1124001.lt 642 RR 965iii.is 1 wgfigtic rstnotiNa ccovii-s---- 10/20/10 WEL'SIC SAM NOTE 14/13/A -TE OP Etpierstles Alaska) • Minilog for Well Techl®g Fiop<1 NORTNSTAR NS09 AUroi LAURAJ.LARSON S c.,.1575 Cale 621@012 Producer Weil:N509 uvvz 500893308100 Elevate,.SSA S 6.101.e ,OVID date ENve0se cloture Di est*:24702. 0, 02 O1Dtt 000:90 FwN[VOrtfNSTAR tay room.MR1hSTAR X009 Patel 9ep.:11039 lases Coordinate.sister.1.027 An lane...70.a9oam w operator:6988 Corps.6088 • 6R NOSS MO _ eHa�5«°tt PE Notes h. PE (FEET) (Ai '^ ^ o I 57 t.srs - „...40,1.7,11.'..—Y ... ,.',aI,OPP /VOS'""e .., SWT MIT x • OM+JG i 1�� 9i9 .991 `_ s • • s. • ao _ i • • 11S0 ' 99 —I '11 :„.. 13250- SDP c: '7► 11 It • 9 illi'. ❑ Subsea(Wet Tree-Semi Submersible, Intervention Vessel) or Offshore Under-balanced U Well rate ?15 mboed (or Operations(Snubbing) 90 mmscfd'I or • Multiple challenges, associated with high uncertainty (low predictability) and low Incremental added / manageability relating to a complex combination of well integrity, reservoir / wellbore restored production $ 5 conditions,production chemistry/flow assurance challenges. mboed(30 mmscfd`)." ❑ Technology/Technique new to Industry. U Activity costs as per ❑ Well Activity performed on a Tier 1 or Tier 2 well, defined in GWO Wells Classification Regional VP Resource Delegation of Authority (UP 4.1-003) (DoA). Conventional 2 Complexity Criteria Conventional 2 Production/ Regional DoA Criteria U Single or multiple element integrity test failures with identified moderate potential to U Well rate ?3 mboed and impact or be impacted by the Well Activity; e.g. acid treatment/flowback in a well with 15 mboed (or 18 and 90 corroded tubing. mmscfd`) or Incremental ❑ Highly dynamic or poorly understood reservoir or wellbore conditions or complex added/restored production production chemistry challenges which may involve additional (beyond local norm) 1 rnboed and �5 mboed measures to effectively manage the impact on the planned Well Activity. (6 and 30 mmscfd•)." U Challenging wellbore trajectory which may involve additional (beyond local norm) U Activity costs as per measures to effectively manage the impact on the planned well intervention. Regional Base Offshore Platform Rig (Dry Tree), Offshore Jack-up Rig (Dry Tree), Offshore Hydraulic Management Manager Workover Unit(Over-balanced operations), Land Drilling Rig. Delegation of Authority ❑ Technology/Technique new to BP. ( Al Conventional 3 Production/ Conventional 3 Complexity Criteria Regional DoA Criteria U Single element well integrity failure is known to exist or uncertain integrity status with U Well rate 3 1 n boed and = potential to impact or be impacted by the planned activity e.g.production log on well with 3 mboed (or 6 and 18 no Well Activity history but report of failed tree valve. mmscfd'1 or Incremental U Dynamic but well understood reservoir or wellbore conditions with well understood added/restored production production chemistry issues (e.g. hydrates, scale, wax, asphaltenes). Addressed by ? 0.25a boed and 5 established local work measures land proven track record) to effectively manage the mboed (1.5 and 6 impact on the planned Well Activities_ mmscfd•)." ❑ Well trajectory access issues covered by established local work measures (and proven U Activity costs as per track record)that effectively manage the impact on the planned Well Activities_ Regional Base Management Team Lead ❑ Land operations with a Hydraulic Workover Unit(Over-balanced operations) Delegation of Authority ❑ H25 concentration in reservoir/wellbore fluids > 10 ppm, partial pressure H25 > 0,05psia or iron sulfide scale present(unless SoP exists). ❑ Technology/Technique new to Region/Team. U Hazardous Materials in use during Well Activities or generation of hazardous materials during Well Activities, including corrosive (acids and caustics), toxic, cryogenic and flammable materials,explosives and radioactive sources/materials.(unless SoP exists). • Simultaneous Operations (SIMOPS): Well Activity may impact or be impacted by other work in the immediate vicinity e.g. a Well Activity conducted adjacent to a new well commissioning operation. U Production Facility Impacts: Either safety and operational risk impacts to or resulting from the production facility (e.g. returned fluids, pressures, etc. are likely to cause facility impacts,or facility shutdown,start-up, etc.are likely to impact the well activity). Conventional 4 Production/ Conventional 4 Complexity Criteria Regional DoA Criteria Single element integrity "anomaly" is known to exist and being managed within existing U Well rate 1 mboeo for 6 acceptance criteria but not expected to directly impact or be impacted by the planned mmscfd`) or Incremental Well Activity; e.g. slickline gauge run on a well with annulus sustained casing pressure added/restored production anomaly. s 0.25mboed/12 months • Static or benign reservoir or wellbore conditions with no significant production chemistry (1.5 mmscfd')." issues which might impact the planned Well Activity. U Activity costs as per • Well trajectory poses no access issues that might impact the planned Well Activity. Regional PE Delegation of Non-rig(Land and Offshore),Land Service Rig/Pulling Unit(unless SoP exists). Authority(DoA). All references to ges production refer to commercial gas only "Added/restored production refers to average over following 12 months Perforation Attachment ADL0312799 Well _ Date Perf Code MD Top MD Base TVD Top _ TVD Base NS09 8/5/06 SQZ 13193 13318 10994 11118 NS09 8/5/06 APF 13318 13320 11118 11120 NS09 - 8/5/06 APF 13320 n 13333 11120 11133 NS09 8/5/06 - APF 13333 13338 11133 11138 NS09 - 8/5/06 APF 13338 n 13340 11138 - 11140 AB ABANDONED MIR MECHANICAL ISOLATED REMOVED APF ADD PERF MIS MECHANICAL ISOLATED BPP BRIDGE PLUG PULLED MLK MECHANICAL LEAK BRIDGE BPS PLUG SET OH OPEN HOLE FCO FILL CLEAN OUT STC STRADDLE PACK, CLOSED FIL FILL STO STRADDLE PACK, OPEN SQF SQUEEZE FAILED SPS SAND PLUG SET SQZ SQUEEZE SL SLOTTED LINER PER PERF SPR SAND PLUG REMOVED RPF REPERF � O O -0C2 OE) 0 co O O 02 co 0 0 co J J J co a) Q O O O O O (0 OO N- N OLO p N- L.0 V' N N- N U o 0 0 0 .- c) ' N-0 N M �f N CO O 'Sr CO co co Lo co a) • O coCo co N M N N N- 0 a M Q O CO LO N 'Cr O O N V V 'Cr I- C (T3 0) a) E rn N � � a) co co E ~ m rn 0 `F° N Q c7 N M ( ) CO O 0) J Q (p HN V o (l3 Q 0 (N - U 2 0 0 ao 0 0 °o U co o rco i 4t J 4 co 4# NO V CO O Cn CO _ Co N N O V 4 - N-co r s N N C Oix) V CO N J CO CN z 0 a, w 1.0 Q U CC C Q L z w w 0 CC m z z rxD D J J Q Cn F- r Packers and SSV's Attachment ADL0312799 Well Facility Type MD Top Description TVD Top NS09 SSSV 2030 4-1/2" Camco WRDP-2 SSV 2028 NS09 PACKER 11326 7" Top Packer 9254 NS09 PACKER 12718 4-1/2" Baker S-3 Perm Packer 10530 NS09 PACKER 12768 5" Baker ZXP Top Packer 10578 1 STATE OF ALASKA AKA OIL AND GAS CONSERVATION COMAION REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon U Repair Well U Plug Perforations U Perforate U Other U Performed: Alter Casing ❑ Pull Tubing❑ Stimulate-Frac ❑ Waiver ❑ Time ExtensionD Change Approved Program ❑ Operat.Shutdown❑ Stimulate-Other ❑ Re-enter Suspended Well❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: BP Exploration(Alaska),Inc Development 151 Exploratory ❑ 201-219-0 . 3.Address: P.O.Box 196612 Stratigraphic Service ❑ 6.API Number: Anchorage,AK 99519-6612 50-029-23052-00-00• 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0312799 NSTR NS09 • 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): To Be Submitted NORTHSTAR,NORTHSTAR OIL • 11.Present Well Condition Summary: Total Depth measured 13429 feet Plugs measured None feet true vertical 11228.2 feet Junk measured None feet Effective Depth measured 13383 feet Packer measured See Attachment feet true vertical 11182.45 feet true vertical See Attachment feet Casing Length Size MD TVD Burst Collapse Structural None None None None None None Conductor None None None None None None Surface 3354 13-3/8"68#L-80 44-3398 44-3216.36 5020 2260 Intermediate None None None None None None Production 11477 9-5/8"47#L-80 42-11519 42-9423.07 6870 4760 Liner See Attachment See Attachment See Attachment See Attachment See Attachment See Attachment Perforation depth Measured depth 13193-13318 feet 13318-13320 feet 13320-13333 feet 13333-13338 feet 13338-13340 feet True Vertical depth 10993.93-11117.7E feet 11117.79-11119.71 feet 11119.78-11132.71 feet 11132.71-11137.6 feet 11137.69-11139.6t feet Tubing(size,grade,measured and true vertical depth) 4-1/2"12.6#13Cr80 40-12767 40-10577.52 Packers and SSSV(type,measured and true vertical depth) See Attachment See Attachment See Attachment Packer None None None SSSV 12.Stimulation or cement squeeze summary: Intervals treated(measured): Treatment descriptions including volumes used and final pressure: NOV 0 b 803 13. Representative Dai reduction or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 390 37500 87 0 2676 Subsequent to operation: 0 0 0 0 0 14.Attachments: 15.Well Class after work: Copies of Logs and Surveys Run Exploratory❑ Development In Service❑ Stratigraphic ❑ Daily Report of Well Operations X 16.Well Status after work: Oil El Gas ❑ WDSPIU GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 313-025 Contact Nita Summerhays Email Nita.Summerha s• BP.com Printed Name Nita Summerha Title Petrotechnical Data Technician i_= i.I , Signat .1 7 r!!Pr- _.od1-i1,w., ai Phone 564-4424 Date 6/26/2013 -'-'--- RBDMS JUL -2 1 7-13' ) 1 5 '-' ' ,411?/0 Form 10-404 Revised 10/2012 Submit Original Only • • Daily Report of Well Operations ADL0312799 CTU #3 1.75" Coil Job Scope: Log GR/CCL, Mill, Drift MIRU CT, rig up in progress. 4/4/2013 ************Continued on 04/05 WSR*************** CTU#3 1.75'rCoil Job Scope:Log GR/CCL, Mill, Drift. Perform BSEE BOP Test. MU 2 7/8" carrier w/3.5" JSN. Kill well. RIH and tag at 13322'. Begin logging up and paint coil flag at 13260'. End logging pass at 12,650' and POOH. 4/5/2013 ...Continued on WSR 4-6-13... CTU#3- 1.75" ***Continued from WSR 4-6-13*** Job Scope: Mill obstruction and Liner patch drift Continue milling operations once fluids arrive. Begin motor work at 13235' and mill ahead. Tie in at flag and correct to 13303.8' and continue milling until consistent hard stalls at 13364', believed to be PBTD. Pump final gel sweep while recip across liner patch interval and POOH chasing with SafeLube. Circ bottoms up. FP coil, run back in hole for dry drift. Drift clear to tag @ 13362' (ctm up). Re-tag, same. POOH. Make up 4" GS spear w/drift tool. Open well and RBIH. RIH to flag and correct to 13315.8' at bottom of drift. Continue to RIH to 13361'when we had a solid tag. Target drift depth of 13360. Retagged to confirm and POOH. Pumped displacement while POOH, 56 bbl 60/40 methanol as freeze protect. Rig down CTU. 4/7/2013 ...Continued on WSR 4-8-13... CTU#3 - 1.75" Coil ***Continued from WSR 4-7-13*** Job Objective: Mill obstruction and drift tubing patch Continue rig down CTU. Pull coil out of the way while CH2 re-rigs for next well. Job complete. 4/8/2013 ***WELL S/I ON ARRIVAL*** (profile mod) DRIFT W/4-1/2" XN NIP LOCATOR, WORK PAST OBSTRUCTION @ 11,062' SLM & LOC XN NIP @ 12,710' SLM (+46' corr to elmd), SET DOWN HIGH @ 13259' CORRECTED DEPTH (recovered small sample of what appears to be fine cement). DRIFT W/ BRUSH & 3.70" BARBELL ASSEMBLY, WORK PAST OBSTRUCTION @ 13237' SLM & TAGGED TD @ 13,327' SLM (13,373' CORRECTED ELM) (MADE FINAL PASS THRU PROBLEM AREAS WHILE RUNNING @ 50 FPM WITHOUT ANY ISSUES) 5/17/2013 ***WELL TURNED OVER TO WELL TENDER*** T/I/0=3500/80/60 Temp= SI Assist E-line ( set anchor) Standby as 5/28/2013 contingency. ***JOB CONTINUED--ROM 5/28/13***(E-LINE PACKER SET) INITIAL T/I/O = 3800/0/0 PSI SET 4-1/2" QCLL LOWER ANCHOR AT 13318', DID NOT TAG TD DEPTH CORRECTED TO SLB CBL LOG DATED 12-JAN-02 TAGGED ANCHOR AFTER SETTING NO SIGNIFICANT TIGHT SPOTS NOTED RIH OR POOH HAND OVER WELL TO DSO PRIOR TO DEPARTURE WELL LEFT S/I ON DEPARTURE FINAL T/I/O = 3800/0/0 PSI 5/28/2013 ***JOB COMPLETE*** • • Daily Report of Well Operations ADL0312799 ***WELL S/I ON ARRIVAL***(profile-mod) DRIFTED W/A 3.70" CENT &TAGGED TOP OF QCLL TBG ANCHOR @ 13,260' SLM (13,318' ELM) SET SECTION #1 OF 2-7/8" BASE PIPE &3.5" SWELL PKR WRAP & QCLL SNAP LATCH @ 13,275' SLM CURRENTLY RIH W/SECTION#2 6/4/2013 ***CONT ON 06/05/13 WSR*** Y *** 6/4/2013 LRS Unit 38 Well Control Contingency WSR continued on 6/5/13*** ***WSR continued from 5/4/T3 ***well control contingency for slickline 6/5/2013 ***WSR continued on 6/6/13*** ***CONT FROM 06/05/13 WSR*** rofile-mod (P ) SET SECTION #2 OF 2-7/8" BASE PIPE W/3.5" SWELL PKR WRAP & QCLL SNAP LATCH @ 13,242' SLM SET SECTION #3 OF 2-7/8" BASE PIPE W/3.5" SWELL PKR WRAP & QCLL SNAP LATCH @ 13,207' SLM SET SECTION#4 OF 2-7/8" BASE PIPE W/3.5" SWELL PKR WRAP & QCLL SNAP LATCH @ 13,173' SLM SET SECTION#5 OF 2-7/8" BASE PIPE W/3.5" SWELL PKR WRAP & QCLL SNAP LATCH © 13,140' SLM TAGGED SVLN W/3.84" NOGO &4-1/2" BRUSH @ 1994' SLM (2030' MD) ATTEMPT TO SET 4-1/2" OCS CERTIFIED BBE (SER#OCS-2) IN SVLN, UNABLE TO GAIN CNTRL/BAL LINE INTEGRITY PULLED 4-1/2" OCS CERTIFIED BBE (SER#OCS-2) FROM SLVN 6/5/2013 ***CONT ON 06/06/13 WSR*** ***WSR continued from 6/5/13 *** Well control contingency for slickline, Assist slickline pump as directed, T/I/0=3660/0/0, Temp= S/I Pumped 50 bbls of 42*diesel down TBG thru kill line Rig down. SV,SSV, WV= 6/6/2013 closed, MV= open, IA, OA= OTG. FWHP's= 3800/0/0 ***CONT FROM 06/05/13 WSR***(profile-mod) MADE 2ND UNSUCCESSFUL ATTEMPT TO SET 4-1/2" OCS CERTIFIED BBE (SER#OCS-1) IN SVLN, BTM PIN PRE-SHEARED IN X-LINE PULLED 4-1/2" OCS CERTIFIED BBE (SER#OCS-1) FROM SVLN AND RIGGED DOWN LRS PUMPED 50 BBLS OF DIESEL DOWN TBG 6/6/2013 ***LRS IN CONTROL OF WELL ON DEPARTURE, WELL TENDER NOTIFIED*** FLUIDS PUMPED BBLS 232 1% SLICK KCL W/SAFELUBE 184 60/40 METH 317 1% SLICK KCL 30 POWERVIS 55 DIESEL • • Daily Report of Well Operations ADL0312799 818ITOTAL Casing / Tubing Attachment ADL0312799 Casing Length Size MD TVD Burst Collapse LINER 1578 7"26# L-80 11326 - 12904 9254.2 - 10710.6 7240 5410 LINER 661 4-1/2" 12.6# 13Cr80 12768 - 13429 10578.49 - 11228.2 8430 7500 PRODUCTION 11477 9-5/8"47# L-80 42 - 11519 42 - 9423.07 6870 4760 SSV 5 4-1/2" NSB-14 SSV 2030 - 2035 2027.92 - 2032.89 SURFACE 3354 13-3/8"68# L-80 44 - 3398 44 - 3216.36 5020 2260 TUBING 12727 4-1/2" 12.6# 13Cr80 40 - 12767 40 - 10577.5 8430 7500 • • 0 • Packers and SSV's Attachment ADL0312799 SW Name Type MD TVD Depscription NS09 PACKER 11326 9198.1 7" Top Packer NS09 PACKER 12718 10474 4-1/2" Baker S-3 Perm Packer NS09 PACKER 12768 10522.39 5" Baker ZXP Top Packer • TREE= ABB-VG15-118" WELLHEAD= ABB-VGI 13-5/8"MITHOWL 5 4111 NS09 AIX NOTES: WELL REQUIRES A SSSV. ""4-1/2" ACTLIA TOR= BAKER CHROME TBG&LW** NOTE BOEMHE WELL 03.B_EV= 56.1' 13f.aEV= 402'((B 15.91 KOP= _ 820' 2030' 4-1/2'SSSV w/HXO M',, =3,813" M3X Angle= 46;4-siieT Datum MD= 12275" = =--1 1693' I-1 13-3/8"STAGE COLLAR 1 Datum 1VD= 10500'SS 113-3/8"CSG,68#,L-80 BTC,ID=12.415" H 3398' I—A GAS LFT MANDRELS ST PA) TVD DEV TYPE VLV LATCH FORT DATE Minimum ID =2.45" @ 13316' 1 5150 4468 45 SPAR DM/ BK 0 01/16102 4-1/2"QCLL ANCHOR 1TOP OF r LNR H 11326' J 11326' 1-19-5/8"X 7"LTP w/LNR HGR,D=? I 19-5/8'CSG,47#,L-80 BTM-C,0=8.681' H 11519' I • ii I 12676'(12690'ELM) 1-4-1/2"FLIER OPTIC TRANSDUCER, =3.958" ir1 12697' H4-1/2"HES X NF, =3.813" I I 12718' Hr X 4-1/2"BKR S-3 FKR,0=3.875' 1 inar H4-11T l- X NP,0=3.813' 1 • 1 12754'(12756"ELM) H4-1/2"FES XN142,0=3725' 1 4-1/2"TBG,12.66,13CR VAN-ACE, H 1276T .0152 bpf,D=3.95fr 1276T 4-1/2"VILEG,D-3.958" I ITOP OF 4-1/2"LNILti-1 12768' I 12768' 1--17'X 5"BKRZXP LIP•0=? 1 12782' H7"X5"BKR FLEX LOCK L14111 HGR,D=? 12791' H5"X 4-1/2"X0,ID=3.958* I 7"LNR,2611,L-80 BTC-M, H 12904' .0383 bpf,0=6.276" L PERFORATIM SUMMARY REF LOG: LIMP VISION RESISTIVITY ON 12/30/01 (TE-IN LOG:GRICCUUSIT) ANGLEAT TOP FERF: 6° 13318' Note:Refer to Production DB for historical pert data SIZE SW INTERVAL(PA)) Opn/Sqz SHOT SQZ 2-7/8' 6 13193-13333 S 01/15102 I 13316' H4-112"QCLL ANCHOR,D=2.45'(05/28/13) 1 2-7/8" 6 13318-13348 0 08/05/06 PBTD 13383' 4-1/2"LNR,12.8#,13CR .0152 bpf,0=3.958" DATE REV BY COMMENTS I DATE FEV BY COMMENTS NORTHSTAR 01/09/02 INITIAL COMPLETION 02/17/11 M13/JMD ADDED SSSV SAFETY NOTE VLL NSO9 07127/06 GLMJPAG GWENT SQZ PERM 05/29/13 SET/PJC SET QCLL ANCHOR PETIMT NO:52012190 08/08/06 WRR/PJC PERFORATIONS I API Pb: 50-029-23052-00 11/27/07 INWRIPJC WELLHEAD/LOCATION SEC 11,TI3N,R13E,1129'FSL&643'Fa 06/28/08 WRR/PJC DRAWING CORRECTIONS 10/26110 BSE/PJC SAFTY NOTE MATE BP Exploration(Alaska) • Py OF To • � \ \ % %yIs, THE STATE Alaska Oil and Gas ofALAsKA Conservation Commission GOVERNOR SEAN PARNELL 333 West Seventh Avenue OF ALASY' Anchorage, Alaska 99501 -3572 Main: 907.279.1433 Fax: 907.276.7542 Mark Sauve HEQ FEB 2 213' Petroleum Engineer SC BP Exploration (Alaska), Inc. P.O. Box 196612 O Anchorage, AK 99519 -6612 Re: Northstar Field, Northstar Oil Pool, NS09 Sundry Number: 313 -025 Dear Mr. Sauve: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, a. Cathy V. Foerster Chair DATED this day of January, 2013. Encl. • • I STATE OF ALASKA JAN 1, 8 2013 ALASKA OIL AND GAS CONSERVATION COMMISSION 07 1 / 2J /y AOGCC APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Change Approved Program ❑ Suspend ❑ Plug Perforatiort&O 6a-5 s Perforate ❑ Pull Tubing ❑ Time Extension ❑ ❑ p t�LF /i Operations Shutdown 3/ Re -enter Sus p. Stimulate ❑ Alter Casing ❑ Other: Liner Patch El • 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number BP Exploration (Alaska), Inc. Development Ei . Exploratory ❑ 201 -219-0 ' 3. Address: Stratigraphic ❑ Service ❑ 6. API Number. P.O. Box 196612, Anchorage, AK 99519 - 6612 50 -029- 23052 -00 -00 • 7. If perforating: 8. Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? 458A NSTR NS09 • Will planned perforations require a spacing exception? Yes ❑ No ❑ 9. Property Designation (Lease Number): 10. Field /Pool(s): ADL0312799 005- V 0 D/ '2,1 I:5 NORTHSTAR, NORTHSTAR OIL 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 13429 • 11228 , 13383 11182 None None Casing Length Size MD TVD Burst Collapse Structural Conductor None None None None Surface 3354 13-3/F 68# L -80 44 - 3398 44 - 3216.36 5020 2260 Intermediate None None None None None None Production 11477 9 -5/8" 47# L -80 42 - 11519 42 - 9423.07 6870 4760 Liner See Attachment See Attachment See Attachment See Attachment See Attachment See Attachment Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attachment See Attachment 4 -1/2" 12.6# 13Cr80 13Cr80 40 -12767 Packers and SSSV Type: See Attachment for Packer Types Packers and SSSV MD (ft) and TVD (ft): See Attachment for Packer Depths No SSSV Installed No SSSV Installed 12. Attachments: Description Summary of Proposal ❑ 13. Well Class after proposed work: Detailed Operations Program 0 BOP Sketch ❑ Exploratory ❑ Development 0 ' Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: Oil El . Gas ❑ WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Mark Sauve Email Mark Sauve.@BP.Com Printed Name Mark Sauve / Title PE Signature / Phone 564 -4660 Date 1/17/2013 M COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: II-- - 02..s Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: or .o..7" RBDMS JAN 2 8 20 _ Spacing Exception Required? Yes ❑ No ❑ Subsequent Form Required: /C — 404 APPROVED BY Approved by: ,,,,,.. / COMMISSIONER THE COMMISSION Date: / -- 2S-/3 f /v� t c� O cJ1j'. �. N it_, Approved application is valid for 12 months from the date of approval. � t S m p �-' it in Dulicat l '/ vt.— l /23 /l3 `' � • • • by Date: Jan 17, 2013 To: Jerry Bixby /Rob Liddelow - Well Operations Supervisor From: Mark Sauve — Northstar PE Bob Harris - Northern Solutions Wells Intervention Specialist Subject: NS09 Slickline Deployed Swell Packer Patch GSO ANSNRWOS IOR: 250 bopd Step Unit Operation 1 S Pull SSSV. Drift and tag TD for patch deployment 2 E Set KB anchor @ 13,325' MD 3 S Deploy 3.5" swell packer patch w /snap latch QCLL system. Re -set SSSV 4 F Pump 50 bbls diesel into tubing Current Status: Producer Last Test: 12/18/11: 390 BOPD, 87 BWPD, 37 MMSCFPD Max Inclination: 45.9° at 6,169' md; 6° at Perfs Max Dog Leg: 4.2° at 2,840' and Perforations: 13,193' — 13,348' and Minimum ID: 2" SSSV @ 2030' MD 3.725" XN nipple @ 12,754' and Last TD tag: 4/17/12: 1.92" swedge & bailer tagged TD @ 13,316' MD Last Downhole Op: 4/17/12: SBHP survey. Latest H2S value: Field Produced Gas 4 ppm - Taken from HP Separator 06/11/07 BHP: 5,097 psi @ 11,100 ft ss, 4/17/12 NS09 was completed in early 2002 and is a high GOR well. In an attempt to make this well a competitive, low GOR producer, it was squeezed and reperfed in July 2006 but the GSO failed to make a significant improvement to the producing GOR. A follow -up P -prof in December 2006 indicated the squeeze to be leaking gas in two separate places. Since that time very little intervention work has been done on NS09. This GSO attempt will be using segmented swell packer elements with snap latch connections that are fully slickline deployable. Objectives 1) Shut off gas production from all but the bottom -most 20' of existing perforations and significantly reduce the producing GOR from the well. 1 • • Slickline Drift Procedure: 1. Hold PJSMs. Monitor and record all T /I /O pressures throughout all stages of the job. 2. SI Well, MIRU slickline unit and PT wellhead Pressure Control Equipment per SOP. 3. RIH and pull SSSV from SLVN nipple @ 2030' MD. 4. POOH and MU slickline tools with 2" bailer and XN locator. 5. RIH, locate XN nipple @ 12,576' ELMD, corrected depth, tag TD and POOH. 6. MU dummy patch consisting of (3) 10' pups, (1) 3.65" OD Round Nose Guide (1) 3.65" OD Fish neck. 7. RIH with dummy patch and tag TD. Target depth is 13,330' ELMD. If TD tags shallower than target depth then contact pad engineer and discuss options for broaching or bailing. 8. Once target TD is achieved RDMO wireline unit and return NS09 to operations. E -line Anchor Set Procedure: 9. Hold PJSM. Monitor and record all T /I /O pressures throughout all stages of the job. 10. SI Well, MIRU E -line unit and PT wellhead Pressure Control Equipment per SOP. 11. RIH with 3.70" OD Baker Single Set KB tubing anchor with 2.45" ID. (will need Baker -10 setting tool) 12. Set Baker KB tubing anchor @ 13,318 ELMD. • Reference Log: Schlumberger GR/CCL log dated 01/12/2002 13. POOH and confirm setting tool operation. 14. RDMO E -line unit. Slickline Patch Deployment Procedure: 15. Hold PJSMs. Monitor and record all T /I /O pressures throughout all stages of the job. 16. SI Well, MIRU slickline unit and PT wellhead Pressure Control Equipment per SOP. 17. Pick up first segment of —33' 2 -7/8" base pipe with 3.5" OD swell packer wrap & QCLL snap latch system. (note: first patch segment will have 2 -7/8" XN nipple on bottom and QCLL snap latch system on top) 2 • • 18. RIH with patch assembly until first segment tags up with KB anchor @ 13,318' ELMD and then release patch from running tool. 19. POOH and pick up second segment of -33' 2 -7/8" base pipe with 3.5" OD swell packer wrap & QCLL snap latch system. (Note: all remaining patch segments with have QCLL snap latch system on top & bottom of assembly) 20. RIH with patch assembly to liner. Engage bottom element of QCLL snap latch system to top element from previously deployed assembly then release patch from running tool. 21. POOH and pick up next segment of -33' 2 -7/8" base pipe with 3.5" OD swell packer wrap & QCLL snap latch system. 22. Repeat Step #19 and continue deploying patch segments until a total of five 33' segments have been deployed. (final top of stacked patch elements is expect to be at approximately 13,155' MD). 23. Set SSSV in SLVN nipple @ 2030' MD. 24. POOH and RD slickline unit. Arrange for pump truck to bullhead 30 bbls diesel into tubing within 24 hours. 25. KEEP WELL SHUT -IN FOR AT LEAST 20 DAYS BEFORE POP. Please see attachments for downhole tool specifications and packer swell time & differential pressure ratings. Contacts For questions, please call Mark Sauve at 564 -4660 (W), 748 -2865 (C), 336 -6128 (H) or Bob Harris at 564 -4080 (0), 240 -0427 (C). cc: w /a: Well File 3 17 ( uolINNIth3 da I MOM AL3114S A= 433Day WIWI 1 t/Ltg0 TIM MI • 31434 M.'S 910:93111 MN IM 31.143313143N MAYS 3rd 4 MEV 1 59.30031103 Al0 3111 NNW 11 1:11.1109 9 lad MO 1 3E IV 1E11 ' t t 3E/S 1143M330403 ONIV14110 3RMI914 tiON7-490 GAL 9 POMO NEM 14711 901319 MreSINZIZOLIN 17 01 WV 9 t&1110011(1.441 3181119M Matt 1 CEII311 GM 33 MS UM= 06 1 13W 3 91 lilted SPELLNKNIRd ardaitIN BMW ABM MB OM Id IV 101341 7 113M SAEld ZOS 2€9133 0911113 6I1Z490 14313111103191111 MOM 1POSHIMON M= AB AMI Kva SZ4311140 AB Aald 31113 496 -01 El e rif,"1: SY inloalvika gi H 3:114114,A V= VITO Iffi .3 VP ant i Med I MIAMMO 0 WPM ° 9 =1 9 3931 It 0 S ESES 1 ME 1 9 Mee 3L110 :taw° twthwikatra Ads WE ItRP 1 40 44 44110 1 4 1 ON Ii0 MIZIN VI APPti Mct9 Jima • A :dial dauv TREWPM 4113111113310 Z10119910 143MUL l W3 ALiMi9 NORA 0390 OMAN AVINOVISNO.LIMOSEM N -stre- a 'A ow IFNN Pagl 1- Waal owl 'me Ion .4. 1 - 119fit -a 'lox zit" x AFLAMI1--_____ I 4.- a 'Hai 1341 mai xEni tea .4; x.,L I L .443' dric1042339 Z x.,LH .1041 1 1 I IOW Han ze1l'410 dal 1 MAT ' a 'aB11 c.avri-1 ism Mina a 44 as ur ma. 1 112 19913 IMO 'S4LL Idt ° I dszrt - a 314 xx sai x 'AA OM 260:4 Ica 11 1 1 X WC a 43 All XEN .111 Arai I—I 1 I . save - a 194d L'S19418 z#1 x .0 am' 1 I5 Z 1 .x Lore- a CAN x ea.' zn -11-1 Jain I-I 1 .1196E a a 1133113SMIRIL li 1 Oid13 tam zit" Ors am) Am i I SW; 1 H Jere =at 'Dille owl Iwo Nam M391 i 1 L 44 CI 713411141 i an .4 x as RD 1 I IL 1 - 1 airi 1.10 c9X1 31ddN NX .Zil 771 WTI ri.711M71111171 MI min = I inlgigil JELT 211 GI U. IRWIN I 31911 JAW 4 191 A1A 3dAL MO 41AL 431 IS 3131341111.41S1S w Segt I-1 Jtt 147 t 4 .43 OA IM9 sse Vso avl i 1 SS DOM at/AL 4 i■ SECO a QIN 4 I Immo 3991S MT'S 11-1 an ... B919 0 JP a ON 1 X We .. 3111 HMS OM a Asssz.4-41 440C 1 GO OLV ad) (AV t ez■Lrar a /WEI A - A 39 a A313 'V TIMA 3013011 .4.1119114 MU MOM 60SN 130198 I a woriruzi atom :-..g. - • - 1 , .,. 4 , - .i ... , z .ill: ,.. ag &two MSS I sartrear 773M 13 LON AL3M/S EM9 ,Mt'S IONGSV 44331.1. • 1111/ . • • 25.5' HES Swell (5) 1320x` ® : x-3.0' Snap Latch Assembly (5) lil II 13208 " —o. I I: } i 2M' HES Swell (4) -- 13237 -5`—+1- 1? I • •-3.0' Snap Latch Assembly (4) I 13240. ,._ 1 al WM 29 -6' HES Swell (3) 13270 ` -- I 43 3.4 -'3A' Snap Latch Assembly (a) 3273 4 29.3' HES Swell (2) l! .! —1 33a2, 5' , 1 L____ -3.0' Snap Latch Assembly (2) , HES Swell & Snap Latch Running BHA 11 j - 133tJ5.5"- 29 HES Sw€ll(1) - -- 13335' --0►?` , ; II -1 .0' ` I " ..1 HES "XN" g f 2.195 ",4 -Vn § '; 1.66' I 1 1.66' Snap Latch Assembly {1) i 5 • • SWELLSIM* Ceasywell ook -10.000.10..04.40000 Swelipacker OS — , Project: Northstar Alaska Design Ely: Mike Beleau Date: 2/24/2011 Easywell Contact: Customer Contact: Bob Harris Packer Type: Sweilpacker OS L 28 Area: Northstar Pr:Ape Bay Location: we slot #13 Application: Gasaane4 isolation Comments: " e PP Design Nam& 2.875 in x 3.5 in x 29.528 ft Fluid Viscosity (co): 0.736 Required DeltaP (psi): 5000 Temp at Packer Depth (T): 250: HT application Case ID (in): 3.958 Pipe 00 (in): 2.875 Packer OD (in): 3.5 Element Length (ft): 29,528 Water Cut (%): No ak. - Z II P Cased Hole Design Name: 2,975 in x 3.5 in x 29.528 ft Volume Swell % at Hole ID: 83 Time to Fully Set Max DP (days): 23.2 Time to Operational DP (days): 21.7 Time to First Seal (days): 9.8 Differential Pressure at Hole ID (bar): 389 Differential Pressure at Hole ID (psi): 5638 Created on 212412011 3:4837 PM Paae 1 of 2 HALLIBUPTON 6 . . • • : • 1 I 1 SCIIIUMberger Company: BP Exploration (Alaska). Inc . . Well: NS-09 Field Northstar BoroJoh. North Slope St., Alaska .._. Gamma Ray-CCL Log • ._--- _ .c al 6 12-JAN-2002 L.. ...„.- 11211rFSLEt 642 0404.: KB. 55,52ft as 8 7 Al Surfaoe (L. 15,67 ft D-1_ 555211. • w U 11. 9- P 1 t.. .e R.' • Permanent Datum: _1112.__ .. . Elev,: Oft z Z - Z o3 S Log Measured From : _ RKB _ _ 565 ft above Pm. Datum _ _ _ . , t =" G Drilling Measured From: RKB , ^""' API Si! No. - . cation Township Range cg ir 11 t 8 50-04-23052-00 11 13N 13E 12.Jan-2002 Bun Number I Depth Order t342 ft _ , _ • - SenIumbergor Depth 13382 _ .. ---- -- -- - ,,. tiottora Log interval I 1332 - /W __ _.-- __ ........— — .. , – - — "---- " - - - ICC, Log rnte i rval Casing Fluid Type enrke Salinity . fil 51bn- ._, __ _ . _... . . Fluid Level 0 ft , _ — sra -4.1 ' • . BIT/CASRC-JTURING STRING Be Srzn 5 12 in _ _ From 291O It ___ -- !` To I - 1 342t 9 f Casing,r_f utriq Size - , 4,500tr _ _ _ _ _ Wegil 126 - - 1 : Tbm/ft - it_.._ _ _ - - _ ,.... Grade _ _ From Oft To Maxim orri Recorded Teriiiiiistunii 247 degF _ L____ _I 1 - 0 ' 1 B cft°" _ - - - - `-- y Tiine 19:15 0 0ta',' .),,.%. , - -- - - -- --- - -- - , - - lied N.Ombe _ - r i Lo r 4101, FILichcatiiene Bay _ __ 1 _ Fiecorckd By - i■ntilOrlyiDecktert Witsvmd El hbreneniaiblis I ..'. 7 . . • • • . . GAMMA RAY CCL UP PASS 1. 1I," LOGGED 5000 FPH Output DLIS Files EFAULT USLSONIC_0141.1if fIN:12 PRODUCER 12-Jan-2002 21:22 13382.0 FT 114.0 FT OP System Version: 1000-306 mom 31T-A 1000-306 SDT-L 100O306 141S-A 1000-306 PTA-A 1000406 M.T.23 1000-30$ DIC41 1000406 01-Y 1 (044.0-400 N.v.................--- --... Casing Coltar Locator (COL) Tension frEt , 1 11000 (Lefl 0 Ithrd tantEeratura _ _M Mud tainparahue (aTEM) — — (DEGF) 220 0 (0E0F) 2V Gamma Ray (GM ACTS Downdede POMO. 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INIIIIir.. . l Gamma Ray (QA) I ACTS Down hole Force (D _ Q (GAP1) 700 200 (1 1000 r - Mud tamparaturteaTEML. _ 1 Mud temperature (MTEM) (DEGF) 2201 0 (DEAF) 20 ■ 1.,.m._ . .�_ _ r .,.�,,.. rrcuc _ Casino r`4 jur I nrainr 11.1:11 9 • • Perforation Attachment ADL0312799 Well Date Perf Code MD Top MD Base TVD Top TVD Base NS09 8/5/06 SQZ 13193 13318 10994 11118 NS09 8/5/06 APF 13318 13320 11118 11120 NS09 8/5/06 APF 13320 13333 11120 11133 NS09 8/5/06 APF 13333 13338 11133 11138 NS09 8/5/06 APF 13338 13340 11138 11140 AB ABANDONED MIR MECHANICAL ISOLATED REMOVED APF ADD PERF MIS MECHANICAL ISOLATED BPP BRIDGE PLUG PULLED MLK MECHANICAL LEAK BRIDGE BPS PLUG SET OH OPEN HOLE FCO FILL CLEAN OUT STC STRADDLE PACK, CLOSED FIL FILL STO STRADDLE PACK, OPEN SQF SQUEEZE FAILED SPS SAND PLUG SET SQZ SQUEEZE SL SLOTTED LINER PER PERF SPR SAND PLUG REMOVED RPF REPERF Casing Summary ADL0312799 Casing Length Size MD Top MD Base ND Top ND Base Burst Collapse Grade LINER 661 4 -1/2" 12.6# 13Cr8( 12768 13429 10578 11228 8430 7500 13Cr80 LINER 1578 7" 26# L -80 11326 12904 9254 10711 7240 5410 L -80 PRODUCTION 11477 9 -5/8" 47# L -80 42 11519 42 9423 6870 4760 L -80 SURFACE 3354 13 -3/8" 68# L -80 44 3398 44 3216 5020 2260 L -80 TUBING 12727 4 -1/2" 12.6# 13Cr8( 40 12767 40 10578 8430 7500 13Cr80 • • • . Packers and SSV's Attachment ADL0312799 Well Facility Type MD Top Description TVD Top NS09 PACKER 11326 7" Top Packer 9254 NS09 PACKER 12718 4 -1/2" Baker S -3 Perm Packer 10530 NS09 PACKER 12768 5" Baker ZXP Top Packer 10578 ` c l . ?! II C . - 1 Y\ U.S. Department of the Interior Submit original plus THREE copies,with ONE copy OMB Control No. 1014 -0018 Bureau of Safety and Environmental marked "Public Information." OMB Approval Expires 10/31/2014 Enforcement (BSEE) Application for Permit to Modify (APM) 1. WELL NAME (CURRENT) 2. SIDETRACK NO. 3. BYPASS NO. (CURRENT) 4. OPERATOR NAME and ADDRESS ( Cb I �U) NS09 BP00 (Submitting office) 5. API WELL NO. (12 digits) 6. START DATE (Proposed) 7. ESTIMATED DURATION (DAYS) BP Exploration (Alaska) Inc. 900 E. Benson Blvd. 50- 029 - 23052 -00 02/01/2013 30 Anchorage, AK 99519 -6612 8. 9 . If revision, please ❑ Revision list changes: WELL AT TOTAL DEPTH WELL AT SURFACE 10. LEASE NO. 13. LEASE NO. OCS -Y -0181 ADL0312799 11. AREA NAME 14. AREA NAME Beechy Point Beechy Point 12. BLOCK NO. 15 51 6 K NO. 516 Proposed or Completed Work 16. PROPOSED OR COMPLETED WORK (Describe in Section 17) PLEASE SELECT ONLY ONE PRIMARY TYPE IN BOLD AND AS MANY SECONDARY TYPES AS NECESSARY. ❑ Enhance Production ❑ Workover: ❑ Completion: ❑ Acidize ❑ Change Tubing ❑ Initial Completion ❑ Attica! Lift ❑ Casing Pressure Repair ❑ Reperforation B D / ❑ Wash /Desand Well ❑ Change Zone 4 E' V / ❑ Jet Well ❑ ❑ Modify Perforations of Well Bore: JAN ! 18 2013 ❑ Utility ❑ Permanent Abandonment ❑ Initial Injection Well ❑ Temporary Abandonment ❑ Information: ❑ Additional Fluids for Injection ❑ Plugback to Sidetrack /Bypass ❑ Surface Location Plat CS ^ Q Other Operations El A Site Clearance ❑ Change Well Name /\.•.:1 /C(C ❑ Describe Operation(s) 17. BRIEFLY DESCRIBE PROPOSED OPERATIONS (Attach prognosis): 18. LIST ALL ATTACHMENTS (Attach complete well prognosis and attachments required by 30 CFR 250.513(8) through (d); 250.613(a) through (d); 250.1712(a) through (g); 250.1721(a) through (h); 250.1722(8) through (d); or 250.1743(a). 19. Rig Name or Primary Unit (e.g., Wireline Unit, Coil Tubing, Snubbing Unit, etc.) 20. The greater of SITP or MASP (psi): 121. Type of Safety Valve (SV): _ SCSSV _ SCCSV N/A I 22. SV Depth BML (ft): 23. Rig BOP (Rams) 24. Rig BOP (Annular) Size: Working Pressure Test Pressure Working Pressure Test Pressure (inches) (psi) (psi) (psi) (psi) Low /High: Low /High: 25. Coiled Tubing BOP: 126. Snubbing Unit BOP: 127. Wireline Lubricator: Working Pressure BOP Test Pressure Working Pressure Test Pressure Working Pressure Test Pressure (psi) (psi) (psi) (Psi) (psi) (Psi) Low /High: Low /High: Low /High: 28. CONTACT NAME: (29. CONTACT TELEPHONE NO.: 1 30. CONTACT E -MAIL ADDRESS: 31. AUTHORIZING OFFICIAL (Type or print name) 32. TITLE 33. AUTHORIZING SIGNATURE 34. DATE THIS SPACE FOR BSEE USE ONLY APPROVED BY TITLE DATE BSEE Form BSEE -0124 (March 2012 - Supersedes all previous versions of this form which may not be used.) Page 1 of 2 0 • • • Application for Permit to Modify (APM) Information Sheet 35) Question Information Questions Response Remarks a) Is H present in the well? If yes, ❑ YES then comment on the inclusion of a © NO Contingency Plan for this operation. ❑ N/A __________ a. b) Is this proposed operation the only ❑ YES _ �.�______ ___ _ _..v. _.v.._ lease holding activity for the subject ® NO lease? If yes, then comment. ❑ N/A c) Will all wells in the well bay and ❑ YES related production equipment be shut -in when moving on to or off of an offshore El NO platform, or from well to well on the LJ N/A platform? If not, please explain. ❑ YES _ __ d) If sands are to be commingled for this ❑ NO completion, has aproval been obtained? © N/A e) Will the completed interval be within ❑ YES 500 feet of a block line? If yes, then ❑ NO comment. © N/A f) For permanent abandonment, will ❑ YES casings be cut 15 feet below the ❑ NO mudline? If no, then comment. © N/A PAPERWORK REDUCTION ACT OF 1995 (PRA) STATEMENT. The PRA (44 U.S.C. 3501 et. seq.) requires us to inform you that we collect this information to obtain knowledge of equipment and procedures to be used in drilling operations. BSEE uses the information to evaluate and approve or disapprove the adequacy of the equipment and /or procedures to safely perform the proposed drilling operation. Responses are mandatory (43 U.S.C. 1334). Proprietary data are covered under 30 CFR 250.197. An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB Control Number. Public reporting burden for Form BSEE -0124 is estimated to average 17 hours per response. This includes the time for reviewing instructions, gathering and maintaining data, and completing and reviewing the form. Direct comments regarding the burden estimate or any other aspect of this form to the Information Collection Clearance Officer, Bureau of Safety and Environmental Enforcement, 381 Elden Street, Herndon, VA 20170. BSEE Form BSEE -0124 (March 2012 - Supersedes all previous versions of this form which may not be used.) Page 2 of 2 TREE = 4 ABB- VG! 5 -1/8" Y NOTES WELL REQUIRESA SSSV. ***4 -1/2" WELLHEAD = ABB -VGI 13 -5/8" MULTIBOWL 5K5I CHROMETBG &LNR*** NO BO EM RE W EL L ACTUATOR = BAKER N S 0 9 KB. ELEV = 56.1' BF. ELEV = 40.2' (CB 15.9') KOP = 820' I • 2030' 1-14-1/2" SSSV w /HXO SLVN NIP, ID = 3.813" I I Max Angle = g 46° @6169' Datum MD = 12275' -J 1593' H 13-3/8" STAGE COLLAR I Datum TV D = 10500' SS 113 -3/8" CSG, 68 #, L -80 BTC, ID = 12.415" H 3398' GAS LIFT MANDRELS ST MD TVD DEV TYPE VLV LATCH PORT DATE Minimum ID = 3.725" @ 12754' 1 1 5150 4468 45 SMOR DMY BK 0 01/16/02 4 -1/2" XN NIPPLE TOP OF 7" LNR H 11326' I I 11326' H 9 -5/8" X 7" LTP w / LNR HGR, ID = ? I 19-5/8" CSG, 47 #, L -80 BTM-C, ID = 8.681" I-1 11519' I 12676' (12690' ELM) I- 4 -1/2" FIBER OPTIC TRANSDUCER, ID = 3.958" ' I 12697' I-- I4 -1/2" HES X NIP, ID = 3.813" ( 12718' 1-17" X 4-1/2" BKR S -3 PKR, ID = 3.875" I I 12742' I I4 -1/2" HES X NIP, ID = 3.813" I 1 12754' (12756' ELM) H 4 -1/2" HES XN NIP, ID = 3.725" I 4 -1/2" TBG, 12.6 #, 13CR VAM -ACE, -1 12767' .0152 bpf, ID = 3.958" 12767' I-- I4 -1/2" WLEG, ID - 3.958" I 'TOP OF 4-1/2" LNR I-I 12768' I I 12768' H 7" X 5" BKR ZXP LTP , ID = ? 1:( ■ 12782' I-17" X 5" BKR FLEX LOCK LNR HGR , ID = ? I 12791' 1-15" X 4-1/2" XO, ID = 3.958" I 7" LNR, 26 #, L -80 BTC-M, -1 12904' I� .0383 bpf, ID = 6.276" \ L PERFORATION SUMMARY REF LOG: LWD? VISION RESISTIVITY ON 12/30/01 (TIE -IN LOG: GR/CCL /USIT) ANGLE AT TOP PERF: 6° @ 13318' Note: Refer to Production DB for historical perf data SIZE SPF INTERVAL (MD) Opn /Sqz DATE 2 -7/8" 6 13193 - 13333 S 01/15/02 2 -7/8" 6 13318 - 13348 0 08/05/06 PBTD I 13383' 4 -1/2" LNR, 12.6 #, 13CRVAM -ACE, 13429' * � * .0152 bpf, ID = 3.958" ���� DATE REV BY COMMENTS DATE REV BY COMMENTS NORTHSTAR 01/09/02 INITIAL COMPLETION 07/27/06 GLM/PAG CEMENT SQZ PERFS WELL: N509 01/17/02 EMF ADPERF 08/08/06 WRR/PJC PERFORATIONS PERMIT No: 2012190 12/20/02 EMF KB INFO UPDATED 11/27/07 WWR/PJC WELLHD/ LOCATION CORRECTIONS API No: 50- 029 - 23052 -00 10/06/05 /TLH NEW FORMAT & TV D CORRECT 06/28/08 WRR/PJC DRAWING CORRECTIONS SEC 11, T13N, R13E, 1129' FSL & 643' FEL 11/08/05 /TLH GLV CORRECTIONS 10/26/10 BSE/ PJC SAFTY NOTE UPDATE 02/15/06 RAC/PAG SAFETY NOTE- MMS WELL ' 02/17/11 MB /JMD ADDED SSSV SAFETY NOTE BP Exploration (Alaska) • BP Exploration (Alaska) Inc. Attn: Well Integrity Coordinator, PRB-20 Post Office Box 196612 Anchorage, Alaska 99519-6612 April 21, 2010 ~'&,.~a Mr. Tom Maunder Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Corrosion Inhibitor Treatments of Northstar Dear Mr. Maunder, by ~,~ I ~ ~1 ~ 'v~_~~ Enclosed please find a spreadsheet with a fist of wells from Northstar that were reated 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, 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, Jerry Murphy, at 659-5102. Sincerely, Torin Roschinger BPXA, Well Integrity Coordinator • BP Exploration (Alaska) Inc. Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top-off Report of Sundry Operations (10-404) Date Northstar 4/20/2010 Well Name PTD # API # Initial top of cement Vol. of cement um ed Final top of cement Cement top off date Corrosion inhibitor Corrosion inhibitor/ sealant date ft bbls ft na al NS05 2050090 50029232440000 1.7 na 1.7 na 10 4/30/2009 NS06 `2021010 50029230880000 0.5 na 0.5 na 1.7 4/30/2009 NS07 2020770 50029230810000 1.1 na 1.1 na 5.3 4/30/2009 NS08 202021 50029230680000 0.75 na 0.75 na 3.6 4/30/2009 NS09 2U12190 50029230520000 1.2 na 1.2 na 3.4 4/30/2009 NS10 2001820 50029229850000 0.25 na 0.25 na 3 4/30/2009 NSi 1 2060360 50029233030000 0.75 na 0.75 na 5.1 5/1/2009 NS12 2021100 50029230910000 1.2 na 1.2 na 3.2 5/1/2009 NS13 2010860 50029230170000 1.7 na 1.7 na 6.8 5/1/2009 NS14A 2052020 50029230260100 0.9 na 0.9 na 2.8 5/1/2009 NS16A 2061410 50029230960100 1.3 na 1.3 na 5.8 5/1/2009 NS17 2021690 50029231130000 1.2 na 1.2 na 2.6 5/1/2009 NS18 2021410 50029231020000 1.5 na 1.5 na 7.3 5/1/2009 NS19 2022070 50029231220000 1.5 na 1.5 na 10.2 5/2/2009 NS20 2021880 50029231180000 1.4 na 1.4 na 8.5 5/2/2009 NS21 2022180 50029231260000 1.7 na 1.7 na 4.3 5/2/2009 NS22 2022230 50029231280000 1.6 na 1.6 na 10.2 5/2/2009 NS23 2030500 50029231460000 0.75 na 0.75 na 3 5/2/2009 NS24 2021640 50029231110000 0.75 na 0.75 na 2.6 5/2/2009 NS25 2031660 50029231810000 * na na 2.6 5/2/2009 NS-26 2002110 50029229960000 at surface na na na na na NS27 2010270 50029230030000 0.6 na 0.6 na 1 5/3/2009 NS28 2050160 50029232480000 1.5 na 1.5 na 8.1 5/3/2009 NS30 2052070 50029232930000 0 na 0 na 4.3 5/3/2009 NS32 2031580 50029231790000 * na * na 1.7 5/3/2009 NS33A 2081890 50029233250100 Sealed conductor na na na na NS34A 2080170 50029233010100 0 na 0 na 2.2 5/3/2009 *Not measured due to rig proximity. ~ ~~ BPXA WELL DATA TRANSMITTAL Enclosed are the materials listed below. (D~ ~~`~~ a~~ a~°` ~~ ~ ~ l~ Tf vrn~ have anv nue~ti~n~_ nlease c~ntact .i~e Lastufka at (907)564-4091 Date: 09-03-2009 Transmittal Number: 93094 Delivery Contents Bottom SW Name Date Contracto Run To De th De th Descri tion BAKER PULSED NEUTRON NS24 03-31-2009 HUGHES 1 12150 12460 FORMATION EVALUATION BAKER RESERVOIR PERFORMANCE NS24 08-29-2008 HUGHES 1 12000 12500 MONITOR BAKER INTERPRETATION OF RPM NS24 08-29-2008 HUGHES DATA CD-ROM - FINAL FLUIDVIEW BAKER ANALYSIS ROP IN META, LAS NS24 08-19-2009 HUGHES AND PDF BAKER PULSED NEUTRON S09 03-31-2009 HUGHES 1 12930 13320 FORMATION EVALUATION BAKER RESERVOIR PERFORMANCE S09 08-28-2008 HUGHES 1 12800 • 13344 MONITOR BAKER INTERPRETATION OF RPM NS09 08-28-2008 HUGHES DATA CD-ROM - FINAL FLUIDVIEW BAKER ANALYSIS PRM IN META, LAS NS09 08- 9-2009 HUGHES AND PDF ~~ ~~ ~ Petrotechnical Data Center ~~. ~ ~ ~;~;~ µ: ~ ,~ ~r;., Please S~d Return one copy of this transmittal. Thank You, Joe Lastufka David Fair AOGCC Murphy Exploration DNR MNIS r~ L BPXA Christine Mahnken Ignacio Herrera Corazon Manaois Doug Chromanski Petrotechnical Data Center LRZ- L 900 E. Benson Blvd. PO Box t966t2 Anchorage, AK 99~ 19-6612 r~ ~ • ~ • BP Alaska Interpretation of RPM Data Well: NS09 Field: Northstar Report Status: Final Report Author: Rafay Ansari Reviewed: David Chace Logged Date: 28th Au ust 2008 Report Date: a 29th July 2009 (_. ri~~ BAKER FII~IES Baker Atlas ~ ~~ ~~. ~;r~x ~~;.~~~ ,>~ ~?:' ". " ,~'~~.~``~r . : :. „ ~' ~r '.r. . ~.:, . . ~ .a~ ,WE~~~..''*'. ,:... .~~ ~.. ,.. . y , ~,.. . :.,ii. " :. .~~ s sY~~2:. .. . . }.~s~±,..~.. ~ i:»3'..~, "-~"~~<a?~ ~ <' .~ ..H. ,.P ry;u~s~*~~ =r`.,.: ~~~~~~«~ ~. ~ _~ . : z~mfi ~ ~, , X_ ~., ~ ~ ~~ ~ ~r~;::~... #' ~http J/www.bakerhughes.com/bakeratlas i ~p~-~L`~ ~ ~ :~ ~ ~~ ~~:~ ti: Y~~~~~ ~, ~~;~~~ , ~., ,;_ ~ ., .'kY~~~_=:~R`~~Y.r. ~ <'~~'a~~~~~~~. , .:~..?" ..~~-~;;~, ,-' ~:r ^:.u,. i.Y:...,' ,x~f~~'n W # j tt ~~~~i." ~.:... ~a q ~ ..~.."~~~"~` . 52P~.XF,'~,~~.<~ .,„~„ ,,:~~'~ ~ , ,..,, .,~~,x~~a~~~?;.*.. ~~ , v.~".. ~ ~~ ~ `~ ~"~_i3~, ~ " rv~ ',~ ~ ~ • ~ IN MAKING INTERPRETATIONS OF LOGS OUR EMPLOYEES WILL GIVE THE CUSTOMER THE BENEFIT OF THEIR BEST JUDGEMENT, BUT SINCE ALL INTERPRETATIONS ARE OPINIONS BASED ON INFERENCES FROM ELECTRICAL OR OTHER MEASUREMENTS WE CANNOT AND DO NOT GUARANTEE THE ACCURACY OR THE CORRECTNESS OF ANY INTERPRETATION. WE SHALL NOT BE LIABLE OR RESPONSIBLE FOR ANY LOSS, COST, DAMAGES, OR EXPENSES WHATSOEVER INCURRED OR SUSTAINED BY THE CUSTOMER RESULTING FROM ANY INTERPRETATION MADE BY ANY OF OUR EMPLOYEES. ~ ~ BP Alaska - Northstar - Well NS09- RPM Satu n Analysis Page i ~ ., u CONTENTS INTRODUCTION 1.1 Objectives 1.2 Results 1.3 Data Set 1.4 Sequence of Events 2 ANALYSIS AND INTERPRETATION 2.1 RPM Overview 2.2 FluidView Analysis Methodology 3 DATA DISCUSSION 6 3.1 FluidView Analysis and Discussion 6 RPM REFERENCES 10 LIST OF TABLES AND FIGURES Table 2.1 Parameters Used for Input to FluidView Modelling Figure 2.1 Fluid Response Chart for RIN13 Figure 2.2 Fluid Response Chart for RAT013 Figure 2.3 Example of GasView Results Figure 3.1 Processed FluidView Results Figure 3.2 Cement Bond Log Baker Hughes Inc. ~ ~ 8P Alaska- Northstar - Well NS09- RPM Satur n Analysis Page 1 1 INTRODUCTION (Source: BP Logging Program) NS09 was completed in early 2002 and is a high GOR well. In an attempt to make this well a competitive, low GOR producer, it was squeezed and reperfed in July 2006. GOR and oil rates initially dropped to ~14,000 and ~1300 bopd respectively. During the 12/11/04 production log, the well had to be SI to pass through the SSSV. The 12/11/04 production profile was also aborted due to gas jetting; however the well has been squeezed since the 12/11/04 log and a successful production log was run 12/22/06. • Current Status: Cycle Producer • Last Test: 609 bopd, 37,045 GOR, 0% WC (7/10/08) • Deviation: 45.92 deg C~ 6,169' MD • Last TD Tag: 05/24/2008: TAGGED TD @ 13309' SLM • Last Well Op.: 05/25/2008: Set SSSV ~ • Min. Restriction: 2" through SSSV at 2030' MD 3.725" through 4-1/2" XN Nipple at 12,754' MD • H2S Info: Field Produced Gas 4 ppm - Taken from HP Separator 06/1 i/07 • Note: Tubing and Liner are both Chrome • Tie In Log: 01/12/02: GR/CCL/USIT 1.1 Objectives The objective of the slickline portion of this procedure is to ensure the logging tools will reach the logging zone of interest. The FluidView log will attempt to identify the fluid contacts in NS09. It will also influence design of future wellwork opportunities. 1.2 Results • The RPM data was of very good quality and repeatability, and an analytical result of good confidence has been achieved. • By utilizing FluidView methodology, a three phase saturation analysis has been carried out while an open hole water saturation curve provided by BP has been displayed for comparison. The open hole and FluidView water saturations match reasonably well from bottom of the log till about 13,150 ft. The bond Iog indicates bad cement with presence of gas in cement above 13,135 ft. This is indicative on the processed log in terms of higher gas saturation calculation. • An increase in gas saturation is observed just below the shale break at 13,262 ft. The increase ~ in gas saturation at this location is more obvious in well NS24. • FluidView processing results are displayed for the interval 12,930 to 13,325. Volumetric data was not available for the rest of logged interval. 1.3 Data Set This well was logged on 28th Aug 2008. The RPM data has been recorded through two different borehole%ompletion configurations. 1) 8.5inch borehole and 7inch casing (12,800-12,904 ft) 2) 6.125inch borehole and 4.5inch casing (12,904-13,340 ft) Three passes were recorded at 5 ft/min. The FluidView passes were recorded with a source output of 800,000 cps (counts per second). • Baker Hughes Inc. i BP Alaska - Northstar - Well NS09- RPM Satura n Analysis Page 2 1.4 Sequence of Events • Log was correlated to SWS/ULTRA SONIC IMAGER (reference log) DATE 12th Jan 2002. • Logging job started at 21:00 on 28th Aug 2008 and finished at 08:00 on the next day. • The top logged interval was 12,800 ft and the bottom logged interval was 13,344 ft. • 20:07 25 BBLS AWAY 5 BPM 3500 PSI • 20:12 50 BBLS AWAY 5 BPM 3200 PSI • 20:18 80 BBLS AWAY • 20:54 230 BBLS AWAY 2500 PSI • 21:01 CUT RATE TO 0.5 BPM • 21:05 240 BBL AWAY 0.5 BPM 700 PSI • 21:15 INCREASE RATE TO 3.6 BPM • 21:36 320 BBLS AWAY REDUCE RATE TO 0.5 BPM • 23:00 START UP 5 fpm PASS ~~ u ~ Baker Hughes Inc. ~ BP Alaska - Northstar - Well NS09- RPM Satur n Analysis Page 3 2 ANALYSIS AND INTERPRETATION 2.1 RPM Overview The Baker Atlas RPM is a pulsed neutron instrument capable of acquiring data in several modes. PNC (Pulsed Neutron Capture) data is used to evaluate the formation saturation in known high salinity formations and to identify gas, while C/O (Carbon/Oxygen) is used to evaluate the formation saturation in low- or unknown-salinity formations. Further to the water saturation calculation modes the tool can also be operated in AFL (Annular Flow Log) mode to quantify water velocity in both continuous passes and stations. Also, borehole holdup can be calculated utilizing the PNHI (Pulsed Neutron Holdup Indicator) mode; this is particularly useful in horizontal or highly deviated wells where the accuracy of conventional production logging instruments is greatly reduced. More recently, the modified RPM-C tool has allowed us to carry out gas saturation analysis ( GasViews"" ) and three phase saturation analysis (FluidView s"') analysis from three detector PNC data. ~ 2.2 FluidView Analysis Methodology ~ Baker Atlas has enhanced the Reservoir Performance Monitor (RPM) service by introducing three features: improved instrumentation, a new characterization, and advanced interpretive techniques. The FluidView service utilizes the improved resolution of the RPM-C tool, new fluid response characterisation (for gas, oil and water) and a new petrophysical algorithm to deliver a better method for identifying fluids and measuring saturations. The algorithm makes use of both inelastic ratio and capture ratio to determine fluid saturations. The three detector RPM-C instrument allows gamma ray measurements to be acquired over longer spacing than conventional instruments. These new measurements are substantially more sensitive to the change in neutron-gamma distribution that indicates a change in fluid saturations in porosity. This improved sensitivity allows the instrument to resolve the presence of different fluids where conventional instruments cannot, and it provides better resolution in saturation calculation of gas and light oil. Characterization of tool response allows more accurate quantification of saturation. A global tool response characterization database has been constructed for standard open hole and cased hole completions. This includes varying combinations of mineralogy, fluid densities and water salinities. New characterization for custom completion configuration and fluid properties can also be generated, if required. The following table states the parameters which have been used in the modelling of the predicted curve response for Northstar well NS09. Table 2.1 Parameters used in FluidView modelling of well NS09 Parameter Value Borehole Size 6.125 inch Casin Size 4.5 inch Borehole Content Water Matrix T e Sandstone Gas Densit 0.26 /cc Oil Densit 0.52 /cc Water Densit 1.00 /cc A FluidView job planner is available to design optimal logging programs. The following chart shows the expected response of the RIN13 and RAT013 curve (this chart is an example only and not relevant to this specific case of well NS09). ~ Baker Hughes Inc. ~ BP Alaska - Northstar - Well NS09- RPM Satur ~ n Analysis Page 4 Ddta Sigma vs Famaiian Pnosiry I Deke 5igna vs Fmne~ion Waler Safnpy I Gas Coeflicient Fde Input Ges ChaM1 I Palio' Plo[ Delector degme d fit: gAK~ ~~ gas chans ~ 1 ~ 3 ~ ~~ ~~~s Baker Atlas Bordmle iluid danutiy Famation Iluid density Fametion qes density 0.10 ~.69 Q69 S~.E~10" P~iM/Ew7ort Ccelf¢bMs RIN • 0.00 0.05 0.10 0.15 020 025 0.30 0.35 wet gas Porosiy ] Figure 2.1 Fluid Response Chart for inelastic Ratio, RIN13 DeYaSi~navsPo~mationPorositylDe11a5iqmavsfoimelionWeterSainitylBweMk/Fametionlrput RIN/RAiO/RICSvs.Pao I • I ~ Baker Hughes Inc. Figure 2.2 Fluid Response Chart for Capture Ratio, RAT013 ~ BP Alaska - Northstar - Well NS09- RPM Satu Analysis Page 5 The Dynamic Gas Envelope (DGE) interpretation explicitly accounts for variations in porosity and shale volume in the saturation result. While these effects must be removed from the saturation solution, they are included in the visual DGE representation for greater insight into the processing. See example GasView results below for illustration for dynamic envelop. For results of well NS09, see section 3.1. EXAMPLE C I• I • Baker Hughes Inc. Figure 2.3 Example of GasView Results ~ BP Alaska - Northstar - Well NS09- RPM Satu Analysis Page 6 3 DATA DISCUSSIONS 3.1 FluidView Analysis and Discussion A FluidView analysis has been carried out using the three passes logged on the 28th Aug 2008. All passes were recorded at 5 fUmin with a source output of 800,000 cps. All the passes have been shifted on depth using open hole GR provided by BP. All data looks to be of good quality and repeatability. Curves from three recorded passes have been averaged to create one final data set to be used for analysis. A result of good confidence has been achieved. The pre-modelling software for FluidView uses a number of lab test calibration points, these lab tests are carried out using pure quartzite for a sandstone environment and tombstone marble for limestone environment. It is very unlikely that this type of matrix would be present downhole therefore a single value calibration is made to the fluid indicator curves (RIN13 and RAT013) to correct for material differences in the matrix. This parameter should be used to normalize the fluid indicator curve in a zone of known saturation. ~ In the process of the FluidView analysis, RIN13 normalization value was used as -9.5 and the shale calibration value was 105. RAT013 normalization value was -21 and shale calibration value was 150. Normalization is performed in such a way that the measured indicator curves stay within the theoretical envelops. Also, note that the pick up depth is 13,325 ft based on the BKS change (BKS-short spaced background countrate). The results of this analysis can be observed in Figure 3.1. The presented results are analyzed with formation gas density of 0.26 g/cc, oil density of 0.52 g/cc and volumetrics provided by BP. The results show the Dynamic Gas Envelope (DGE explained in section 2.2) for both inelastic ratio (RIN13) and capture ratio (RAT013). The figure shows how the measured curve moves between the water, oil and gas lines and the resulting water, oil and gas saturations. The results show a possible gas contact at around 13,150 ft and gas saturation going out of scale above this depth. This anomaly is better explained when the FluidView interpretation is reconciled with the cement bond log shown in Figure 3.2. The bond log shows bad cement above the casing collar located at 13,135 ft with borehole-casing annulus filled with mostly gas. The RIN13 curve, shown in the inelastic analysis track, has two distinct shifts, one at 13,150 ft and the other at 13,135 ft. While the shift at 13,135 can be attributed to gas cut cement, the shift at 13,150 seems very likely to be caused by a gas-liquid contact within the formation. RAT013 with deeper depth of investigation sees only one shift as displayed in the capture analysis track. FluidView model is based on sandstone lithology; however, dolomite is present in Sag interval. The RIN13 and RAT013 matrix points are higher for dolomite compared to sandstone. Therefore, the presence of dolomite has been corrected by adjusting the RIN13 and RAT013 curves. J 8aker Hughes Inc. ~ BP Alaska - Northstar - Well NS09- RPM Satur n Analysis Page 7 I~ I~ Baker Hughes Inc. ~ BP Alaska - Northstar - Well NS09- RPM Satur n Analysis Page 8 I~ I~ Baker Hughes Inc. Figure 3.1 Processed FluidView Results ' BP Alaska - Northstar - Well NS09- RPM Satur n Analysis Page 9 I • I • Min of Internal Min of Internal radius llRfdN radius IRMN Micro-debon 2.J ;'.P~ii 1A 1.4 (IN) 2.4 Gamma External rodlua Internal radius Maximum of AI Ray (GR) Averofle Maximum qIMX GAPI} ERAV ~~RMX) Liquid 0 'I50 2.4 (INl tA ~.4 pN) 2.4 0 fMRAYI 10 ~ Cabl~ Incernal radius Int~rnal ratlius q~~ray~ of AI gppd (~g) Maximum Avarape A~A~ af Of ry iFIHRi (IRMX) IRAV _ _ 0 yppp 2.4 (INj 1.4 1.4 (IN) 2.4 0 (MRAY) 10 L t~mal ndius ~rnal rodiu ~ ~ o woo 1.0000 ~ ~ 2 0000 2500J 3 0000 3 5000 •~ nsooo ~ nimum of AI ,aaa o000 aoo ooao 0 3000 = ~ 3.0903 3 9Bi8 ~ 0"13] i.GS36 3 06a6 0 5~~J5 6.~3 n Am 6tude Max P (CCLU) Avsny~ IRAV Avenge ERAV z.omo AIMN ~~o,ez ~~~s, Bonded . ~___~ 55000 s~ 0(MRAY) 10 emoo Sonic VDL Curv~ (VDL) -20 20 2.4 (IN) 1.4 7.6 (IN) 2.4 s xoo ~ US 1200 ( ) '~0°°° r woo C~m~nt Ma P e o00o wlth Impedance Raw Acoustic Classification Impad. (AIBK) (AI MICRO_ DEBONDING (___) _ IMAGE) ~_W) +~ P}.~.yi I I I I JM.~.I~l ' . l'iQ F{ Figure 3.2 Cement Bond Log for NS 09 (Source: BP) Baker Hughes Inc. ~ BP Alaska - Northstar - Well NS09- RPM Satur n Analysis Page 10 RPM References Chace, D.M,, Trcka, D.E., and Dawe, B.A., "Application and interpretation of continuous oxygen activation logs for measuring complex water flow profiles in injection wells," SPE 69th Annual Technical Conference and Exhibition, New Orleans, Louisiana, Paper 28412, 1994. Trcka, D., van den Berg, F., Manan, W.A., Peeters, M., and Mickael, M., "Measuring three-phase holdups in horizontal wellbores using pulsed neutron instruments," SPE Annual Technical Conference and Exhibition, Denver, Colorado, Paper 36561, 1996. Gilchrist, W.A. Jr., Prati, E., Pemeper, R., Mickael, M.W., and Trcka, D., "Introduction of a New Through- Tubing Multifunction Pulsed Neutron Instrument," SPE paper 56803, Annual SPE Technical Conference and Exhibition, Houston, Texas, Oct. 1999. Trcka, D.E., and Chace, D.M., "Improved method for measuring annular water flow in injection wells using continuous oxygen activation logging," SPE 68th Annual Technical Conference and Exhibition, ~ Houston, Texas, Paper 26450, 1993. Chace, D.M., Trcka, D.E., Wang, J., Bousche, O., van der Spek, A., al Nasser, H., "A new production logging service for horizontal wells," SPWLA 39th Annual Symposium, Keystone, CO, 1998, Paper H. Mickael, M.W., Trcka, D.E., Pemper, R., "Dynamic Multi-Parameter Interpretation of Dual-Detector Carbon/Oxygen Measurements", SPE Annual Technical Conference and Exhibition, Houston, Texas, Oct. 1999. Chace, D., Trcka, D., Georgi, D., Wang, J., Bousche, O., van der Spek, A., al Nasser, H., "New instrumentation and methods for production logging in multiphase horizontal wells," SPE MEOS, Bahrain, Paper 53220, 1999. David Chace, Jianrong Wang, Roman Mirzwinski, Jorge Maxit, and Darryl Trcka, "Applications of a New Multiple Sensor Production Logging System for Horizontal and Highly-Deviated Multiphase Producers", SPE paper 63141, Annual SPE Technical Conference and Exhibition, Dallas, Texas, October, 2000. Trcka, D., Oliver, D., Mickael M., Chace, D., Georgi, D., and Wang, J., "Reservoir performance monitoring in the new millennium", Proceedings of the Tunisian Oil Conference, April, 2000. Riley, S., Guivarch, B., Chace, D.M., Trcka, D.E., Clark, J., "Production logging in horizontal gravel- packed highly viscous oil producers in the North Sea", SPE Annual Technical Conference and Exhibition held in Denver, Colorado, Oct. 2003. ~ ~ Baker Hughes Inc. by • Date: 06-16-2009 Transmittal Number: 93076 `~ 2G~ a BPXA WELL DATA TRANSMITTAL Enclosed are the materials listed below. ;. JUN 1 8 2009 Alaska ail & Gas Cons. Commissi®~ If you have anv questions. please contact Joe Lastufka at (9071564-4091 Anchorage \~ ~'~ ~ ~~ ~~ ~~ ~~,i~ i$!~~ ~~-~ 1 `~ ~~5~ 1~1~~ J Deliver Contents Bottom SW Name Date Com an Run To De th De th Descri tion S09 06-07-2009 PDS 1 12625 13349 CORRELATION LOG STATIC TEMPERATURE/ NS09 06-07-2009 PDS PRESSURE SURVEY CD-ROM -CORRELATION LOG AND STATIC TEMPERATURE/PRESSURE NS09 06-07-2009 PDS SURVEY MWD CALIPER MEASURED NS33A 04-16-2009 SCH 3-6 684 26090 DEPTH LOG MWD TRUE VERTICAL NS33A 04-16-2009 SCH 3-6 684 26090 DEPTH LOG MWD MEASURED DEPTH NS33A 04-16-2009 SCH 3-6 684 26090 LOG CD-ROM -MWD CALIPER MEASURED DEPTH LOG, MWD TVD LOG, AND MWD NS33A 04-16-2009 SCH MEASURED DEPTH LOG ULTRASONIC CEMENT/ NS33A 04-14-2009 SCH 1 200 14100 CORROSION EVALUATION CD-ROM -ULTRASONIC CEMENT/CORROSION NS33A 04-14-2009 SCH EVALUATION CD-ROM - LDWG EDIT OF USIT PDC GAMMA RAY IN TIF FORMAT W ITH FINAL PDS NS33 01-29-2009 SCH DISPLAY STETHOSCOPE 475 FORMATION PRESSURE NS33A 04-19-2009 SCH 6 25567 26045 WHILE DRILLING CD-ROM -STETHOSCOPE 475 FORMATION PRESSURE NS33A 04-14-2009 SCH WHILE DRILLING DIRECTIONAL SURVEY NS33A 04-18-2009 SCH 1 0 26090 REPORT CD-ROM -DIRECTIONAL NS33A 04-16-2009 SCH SURVEY REPORT Petrotechnical Data Center LR2-1 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 99519-6612 a.P ~Plo~at/o~ ~a/aska>.1~~. Static Temperature/ Pressure Survey NS-09 North Star - ~: i ~ ~ °~ n -~ North S/ope Surface -Before R/H Elapsed Time (Minutes) Temperature (Deg. F) Pressure (psia) 0.0 73.55 3713.21 0.5 73.61 3713.36 1.0 73.29 3713.41 1.5 73.20 3713.44 2.0 77.57 3712.48 2.5 71.71 3712.74 3.0 68.44 3713.43 3.5 66.36 3713.30 4.0 66.08 3713.35 4.5 71.26 3713.61 5.0 70.67 3713.61 5.5 71.03 3713.53 6.0 72.13 3713.06 6.5 71.83 3713.06 7.0 71.57 3713.06 7.5 70.73 3713.71 8.0 76.26 3712.78 8.5 74.93 3712.81 9.0 70.66 3713.74 9.5 70.49 3713.72 10.0 70.41 3713.71 AVERAGE 71.70 3713.29 Current Wellhead Read in s Wellhead Pressure (psig) : 3,700 Wellhead Temperature (deg. F.) : N/A Inner Annulus Pressure (psig) : 0 Outer Annulus Pressure si N/A Date: June 7, 2009 ob`~,M Wel(sA~ a ~: 4 W V' N P~oAcriv[ Di~gMOSric Scwvicn Start time: 14:54:00 Temperature Data 80 75 - - ---- 70 __.....------- LL ss _. ~, 60 55 -- - 50 0 1 2 3 4 5 6 7 8 9 10 Minutes Pressure Data 0 1 2 3 3720 3718 3716 g N a 3714 3712 3710 Page 1 ~l 1 -~ 4 Min~tes 6 7 8 9 10 •I B.P. Exploration (A/asks). lna .Stf~lt/C rE'/)7~DE!'c~tU/'@~ P!'ESSU/'e .SU/'VEJ/ NS-09 North Star North S/ope 90,994' TVDss M.D. = 93,250' Elapsed Time (Minutes) Temperature (Deg. F) Pressure (psis) 0.0 250.00 5092.23 1.0 250.60 5092.27 2.0 250.11 5092.42 3.0 250.13 5092.66 4.0 250.50 5092.97 5.0 250.25 5093.30 6.0 250.26 5093.65 7.0 250.23 5093.98 8.0 251.89 5094.30 9.0 250.44 5094.60 10.0 250.32 5094.87 11.0 250.72 5095.12 12.0 250.42 5095.36 13.0 250.35 5095.63 14.0 250.33 5095.80 15.0 250.42 5095.98 16.0 250.28 5096.16 17.0 250.61 5096.33 18.0 251.26 5096.50 19.0 250.98 5096.66 20.0 250.55 5096.80 21.0 250.56 5096.95 22.0 250.58 5097.08 23.0 250.56 5097.21 24.0 250.61 5097.33 25.0 250.60 5097.45 26.0 250.60 5097.56 27.0 250.61 5097.66 28.0 250.64 5097.76 29.0 250.47 5097.85 30.0 250.34 5097.87 AVERAGE 250.52 5095.56 Date: June 7, 2009 obtEM WE(( SAS a ~: Q ~~ i M N P~oAcrirE Di~y~.osric S~wvic~s Start time: 16:14:00 Temperature Data 252 251 LL 250 249 - -- -------- ------- - 248 - 247 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 Minutes s100 5095 ----- 5090 - a N a 5085 - so8o -- 5075 0 2 Page 2 Pressure Data 4 6 8 10 12 mutes 18 20 22 24 26 28 30 • B.P. Exploration (A/aska). lna Jrtalt~`i TB/np@/'c~tU/'@~ P!'@SSU/'L' SL//'VB~/ NS-09 North Star North Slope 10,945' TYDss M,D. = 93,200' Elapsed Time (Minutes) Temperature (Deg. F) Pressure (psia) 0.0 250.66 5092.71 0.5 250.26 5092.74 1.0 250.36 5092.77 1.5 250.19 5092.81 2.0 251.04 5092.84 2.5 249.93 5092.88 3.0 250.40 5092.92 3.5 250.27 5092.95 4.0 250.58 5092.99 4.5 250.41 5093.03 5.0 250.41 5093.06 5.5 250.41 5093.09 6.0 250.40 5093.12 6.5 250.39 5093.15 7.0 250.42 5093.18 7.5 250.40 5093.21 8.0 250.39 5093.23 8.5 250.40 5093.26 9.0 250.39 5093.28 9.5 250.39 5093.31 10.0 250.39 5093.33 10.5 250.40 5093.35 11.0 250.39 5093.37 11.5 250.40 5093.39 12.0 250.39 5093.41 12.5 250.39 5093.42 13.0 250.39 5093.44 13.5 250.12 5093.46 14.0 250.60 5093.47 14.5 250.41 5093.49 15.0 250.19 5093.50 A~ER~t.,E 25C 39 SOa3.1 , Date: June 7, 2009 `EM WE/[ SA Qao ~~~~ s ~ N P~oAcrfve Df~y+wtic Suvic[s Start time: 16:45:00 Temperature Data 252 251 LL 250 -- 249 ~--------------- ------......._. _ --__----...... 248 - 247 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Minutes Pressure Data 5100 5095 - ----.- -- 5090 Q N a 5085 5080 -._.-.-- --------------~---------....------ 5075 0 1 2 3 4 5 6 f~linutes 9 10 11 12 13 14 15 Page 3 e.P Exploration ~alaska>.1~~. Static Temperature/ Pressure Survey NS - 09 North Star North Slope 90,994' MJss M.O. = 93,250' Elapsed Time (Minutes) Temperature (Deg. F) Pressure (psia) 0.0 250.66 5098.76 0.5 250.64 5098.76 1.0 250.60 5098.77 1.5 250.64 5098.77 2.0 250.65 5098.78 2.5 250.64 5098.79 3.0 251.21 5098.79 3.5 250.65 5098.80 4.0 250.65 5098.81 4.5 250.66 5098.82 5.0 250.65 5098.83 5.5 250.66 5098.83 6.0 250.66 5098.84 6.5 250.67 5098.85 7.0 250.67 5098.85 7.5 250.81 5098.86 8.0 250.67 5098.87 8.5 250.67 5098.87 9.0 250.68 5098.88 9.5 250.68 5098.89 10.0 251.36 5098.89 10.5 250.69 5098.89 11.0 250.69 5098.90 11.5 250.70 5098.90 12.0 250.70 5098.91 1 Z.5 250.70 5098.91 13.0 250.70 5098.91 13.5 250.71 5098.92 14.0 250.71 5098.92 14.5 250.70 5098.92 15.0 250.64 5098.93 AVERAGE 25(7.; 1 5Q98.~5 Date: June 7, 2009 tEM WEl( SA a° `~~: 4 +~ I~ .w P~oAcrivr Di~ynosric Seaviccs Start time: 17:05:00 Temperature Data 252 251 --- aL 250 249 248 247 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Minutes Pressure Data 5100 5095 --- -._~.__..------------.^~_ 5090 ---- - - --------- -_.-_..~------- 5085 - solo 5075 0 1 2 3 4 5 6 11~linute~ 9 10 11 12 13 14 15 Page 4 • B.P. Exploration (A/askaJ. Inc. StiG1t~C TE/~7~t7B!'c~tU/'E~ P/'ESSU/'@ $U/'1/G'J/ NS-09 North Star North Slope X0,895' TVDss M.D. = 73, 750' Elapsed Time (Minutes) Temperature (Deg. F) Pressure (psia) 0.0 250.15 5088.73 0.5 250.10 5088.73 1.0 250.07 5088.74 1.5 250.06 5088.75 2.0 250.05 5088.76 2.5 250.06 5088.77 3.0 250.15 5088.77 3.5 250.28 5088.78 4.0 250.04 5088.78 4.5 250.14 5088.78 5.0 250.06 5088.79 5.5 250.11 5088.79 6.0 250.04 5088.79 6.5 250.02 5088.79 7.0 250.04 5088.79 7.5 250.04 5088.79 8.0 250.02 5088.79 8.5 250.02 5088.80 9.0 250.04 5088.79 9.5 250.02 5088.80 10.0 250.03 5088.80 10.5 250.02 5088.80 11.0 250.01 5088.80 11.5 250.02 5088.80 12.0 250.56 5088.80 12.5 250.02 5088.80 13.0 250.01 5088.79 13.5 250.17 5088.79 14.0 250.00 5088.80 14.5 250.43 5088.80 15.0 249.95 5088.80 AVERAGE 250.09 5088.78 Date: June 7, 2009 ob`EM We[( SAF a ~~• Q ~~ : M M P~oAcrive D4pnosric Sewviees Start time: 17:25:00 Temperature Data 252 251 -- - LL 250 249 --- 248 247 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Minutes 5100 5095 5090 5 y a 5085 so8o --- 5075 0 1 Page 5 Pressure Data 2 3 4 5 6 Minutes 9 10 11 12 13 14 15 • B.P. Exploration ~A/asks). Inc. Static r@/17~7E/'ca1tU!'@~ P!'BSSU/'B $U/'VEJ/ NS-09 North Star North Slope 90,795' TVDss M.D. = 93,04B' Elapsed Time (Minutes) Temperature (Deg. ~ Pressure (psis) 0.0 248.25 5078.51 0.5 248.29 5078.53 1.0 248.28 5078.56 1.5 248.30 5078.57 2.0 248.32 5078.59 2.5 248.09 5078.60 3.0 248.34 5078.61 3.5 248.79 5078.61 4.0 249.40 5078.61 4.5 249.06 5078.61 5.0 249.25 5078.61 5.5 248.38 5078.61 6.0 247.43 5078.61 6.5 249.08 5078.60 7.0 248.69 5078.60 7.5 248.60 5078.60 8.0 248.50 5078.59 8.5 248.21 5078.59 9.0 248.24 5078.58 9.5 248.24 5078.58 10.0 248.38 5078.58 10.5 248.68 5078.57 11.0 248.07 5078.57 11.5 248.47 5078.57 12.0 248.88 5078.56 12.5 248.29 5078.56 13.0 248.08 5078.56 13.5 248.25 5078.55 14.0 248.17 5078.55 14.5 248.20 5078.55 15.0 248.07 5078.55 AVERAGE 248.43 5078,58 Date: June 7, 2009 Ob~EM WE(~ sAE a ~: Q ~~ W !~ M P[oAcrivr Diw~~.osric Sewvicn Start time: 17:47:00 Temperature Data 252 251 ----- --- ----------- - 250 - --------- -- -- ---..~--- LL 249 ---- 248 247 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Minutes 5100 5095 5090 g H a 5085 so8o 5075 0 Page 6 Pressure Data 1 2 3 4 5 6 M1~inutes 9 10 11 12 13 14 15 U eP Exploration (Alaska) inc. Static Temperature/Pressure Survey ~-'Eu NS - 09 oob`EM 'riOF~ , North Star 4 ~'G North Slope ~ M Surface -After POOH P~eActivr ~I.aroaric S.~rieE~ Elapsed Time (Minutes) Temperature (Deg. F) Pressure (psia) 0.0 51.91 3715.64 0.5 52.11 3715.64 1.0 52.10 3715.62 1.5 52.08 3715.60 2.0 52.04 3715.57 2.5 52.01 3715.54 3.0 51.99 3715.50 3.5 51.92 3715.46 4.0 51.88 3715.42 4.5 51.83 3715.37 5.0 51.76 3715.32 5.5 51.71 3715.27 6.0 51.68 3715.20 6.5 7.0 7.5 8.0 8.5 9.0 9.5 10.0 AVERAGE 51.93 3715.47 Current Wellhead Read in s Wellhead Pressure (psig) : 3,700 Wellhead Temperature (deg. F.) : N/A Inner Annulus Pressure (psig) : 0 Outer Annulus Pressure ( si ) : N/A Date: June 7, 2009 Start time: 19:40:00 Temperature Data 80 75 70 LL 65 so 55 50 - 0 1 2 3 4 5 6 7 8 9 10 Minutes 3720 3718 3716 Q H a 3714 3712 3710 0 Page 7 Pressure Data 1 2 3 4 Minutes 6 7 8 9 10 B.P. Exploration (A/askaJ. lnc. NS-09 North Star North Slope Downha/e Temp/ Press Date: June 7, 2009 Static Temperature /Pressure Survey Start time: 14:54:00 End Time: 19:50:00 Ob~EM WEL( SpF o ~: Q ~~ ~ w PooAcriv[ Di~yvn~Tic 5[wvicn Temperature Data 252 251 -- 250 __-_ - a 249 __--- 248 247 -200 0 200 400 600 800 1000 1200 1400 1600 Minutes Pressure Data 5100 5095 ---_ --------- 5090 M~N - -- --------- - -- ------ ------------- a 5085 -- - ------- - -- - -- 5080 - - - -- -- 5075 -200 0 200 400 600 Minutes 800 1000 1200 1400 1600 Page 8 • • by BP Exploration (Alaska) Inc. ,~ ~~ ` - Attn: Well Integrity Coordinator, PRB-20 ~: Post Office Box 196612 Anchorage, Alaska 99519-6612 P g ~~~ ~~~~ May 26, 2009 I~~~C ail ~ 1~~~~9 ~~r~i~sion _ ~~1~)8pr~ Mr. Tom Maunder ~ ~ ~ - ~- Alaska Oil and Gas Conservation Commission 333 West 7th Avenue ~ / Anchorage, Alaska 99501 Subject: Corrosion Inhibitor Treatments of Northstar Dear Mr. Maunder, Enclosed please find a spreadsheet with a list of wells from Northstar 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, 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, ~'L~ ~~; ~`!~~'~'~~~ ~i fir' ~ ~ ~1~~ Andrea Hughes BPXA, Well Integrity Coordinator BP Exploration (Alaska) Inc. Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top-off Report of Sundry Operations (10-404) ~" ~- 6~ Date Northstar 5/26/2009 Well Name PTD # Initial top of cement Vol. of cement um ed Final top of cement Cement top off date Corrosion inhibitor Corrosion inhibitor/ sealant date ft bbls ft na al NS05 2050090 1.7 na 1.7 na 10 4/30/2009 NS06 2021010 0.5 na 0.5 na 1.7 4/30/2009 NS07 2020770 1.1 na 1.1 na 5.3 4/30/2009 NS08 2020210 0.75 na 0.75 na 3.6 4/30/2009 NS09 2012190 1.2 na 1.2 na 3.4 4/30/2009 NS10 2001820 0.25 na 0.25 na 3 4/30/2009 NS11 2060360 0.75 na 0.75 na 5.1 5/1/2009 NS12 2021100 1.2 na 1.2 na 3.2 5/1/2009 NS13 2010860 1.7 na 1.7 na 6.8 5/1/2009 NS14 A 2052020 0.9 na 0.9 na 2.8 5/1/2009 NS16 2061410 1.3 na 1.3 na 5.8 5/1/2009 NS17 2021690 1.2 na 1.2 na 2.6 5/1/2009 NS18 2021410 1.5 na 1.5 na 7.3 5/1/2009 NS19 2022070 1.5 na 1.5 na 10.2 5/2/2009 NS20 2021880 1.4 na 1.4 na 8.5 5/2/2009 NS21 2022180 1.7 na 1.7 na 4.3 5/2/2009 NS22 2022230 1.6 na 1.6 na 10.2 5/2/2009 NS23 2030500 0.75 na 0.75 na 3 5/2/2009 NS24 2021640 0.75 na 0.75 na 2.6 5/2/2009 NS25 2031660 na * na 2.6 5/2/2009 NS27 2010270 0.6 na 0.6 na 1 5/3/2009 NS28 2050160 1.5 na 1.5 na 8.1 5/3/2009 NS30 2052070 0 na 0 na 4.3 5/3/2009 NS32 2031580 na na 1.7 5/3/2009 NS34 2080170 0 na 0 na 2.2 5/3/2009 *Not measured due to rig proximity. LJUN0~2D09 ~) N ~~~ ~~ I ti,~~~;~ ~,~ _-_--... `Ll ~ r~ ~~~ 1 1 ~' r,~ ~' ,~~,~' t .~~ ..t~', ~~~ 1 ~~ 3, °1 ~' `~i~ ----- s z J`"`t~~\ >'~~' Date: 02-25-2009 Transmittal Number: 93041 BPXA WELL, DATA TRANSMITTAL Enclosed are the materials listed below. ,:~;; ~~~- ~ ~~-'~ ~~~~~ /~~~~~ 6~~ ~~~ If you have anv ctuestions, please contact Joe Lastufka at (907)564-4091 Delive Contents SW Name Date Contractor Run To De th Bottom De th Descri tion NS24 12-05-2008 SCH 12450 12490 PL ADVISOR NS24 12-05-2008 SCH CD-ROM - PL ADVISOR NS09 12-17-2008 SCH 1 13044 13339 MEMORY SBHPS LOG CD-ROM -MEMORY SBHPS NS09 12-17-2008 SCH LOG PRODUCTION PROFILE NS16A 02-12-2009 SCH 1 11150 11390 WITH DEFT AND GHOST ' CD-ROM -PRODUCTION PROFILE WITH DEFT AND NS16A 02-12-2009 SCH GHOST PRODUCTION PROFILE .NS05 02-13-2009 SCH 1 13551 13860 WITH DEFT AND GHOST CD-ROM -PRODUCTION PROFILE WITH DEFT AND NS05 02-13-2009 SCH GHOST ULTRASONIC CEMENT/CORROSION NS33 01-29-2009 SCH 1 100 15550 EVALUATION CD-ROM -ULTRASONIC CEMENT/CORROSION NS33 01-29-2009 SCH EVALUATION NS34A 12-16-2008 SCH 1 16088 17108 MEMORY SBHPS LOG CD-ROM -MEMORY SBHPS NS34A 12-16-2008 SCH LOG STATIC TEMPERATURE/ NS18 02-16-2009 PDS PRESSURE SURVEY NS18 02-17-2009 PDS 1 16250 16851 CORRELATION LOG CD-ROM STATIC TEMPERATURE/PRESSURE SURVEY/CORRELATION NS18 02-17-2009 PDS LOG ..~ . _- .~„ Please Sign nd turn one copy of this transmittal. Petrotechnical Data Center LR2-1 900 E, Benson Blvd. PO Box 196612 ._:r.- Anchorage, AK 99519-6612 J f~ r ~~~ Date: 03-11-2009 ~"t ~, Transmittal Number: 93048 ,~l ~,. i ~~~~ ~~'~ ~ ~Ui 1'~ ~;: l~-~ 1~ ~ ~`~ ;uc ~_~~~ BPXA WELL DATA TRANSMITTAL Enclosed are the materials listed below. Tf vnu have anv auestinns_ »lease contact Joe Lastuflca at (9071564-4091 Delive Contents SW Name Date Com an Run To De th Bottom De th Descri tion NS08 02-23-2009 PDS 1 11526 11926 CORRELATION LOG STATIC TEMPERATURE/ NS08 02-23-2008 PDS PRESSURE SURVEY CD-ROM -CORRELATION LOG AND TEMPERATURE/ NS08 02-23-2009 PDS PRESSURE SURVEY NS09 02-24-2009 PDS 1 12700 13349 CORRELATION LOG STATIC TEMPERATURE/ NS09 02-24-2009 PDS PRESSURE SURVEY CD-ROM -CORRELATION LOG AND TEMPERATURE/ NS09 02-24-2009 PDS PRESSURE SURVEY PL ADVISOR -PRODUCTION LOG INTERPRETATION NS16A 10-01-2008 SCH 14274 14339 WITH GHOST AND DEFT CD-ROM - PL ADVISOR PRODUCTION LOG INTERPRETATION WITH NS16A 10-01-2008 SCH GHOST AND DEFT P1~ease~ign and Return one copy of this transmittal. Thank You, Joe Lastuflca Petrotechnical Data Center r i r `. tf lI~ ..._,__ BP~ ~li~~N k'~t$ ~6'~F'.~ h ~..:: 1 ^4' AOGCC DNR Murphy Exploration MMS ~ _ ~ - !33. _ t 11 ~, ~.. David Fair Christine Mahnken Kristin Dirks Ignacio Herrera Doug Chromanski Petrotechnical Data Center LR2-1 `; . ~ ~ 900 E. Benson Blvd. PO Box 196612 ~~'. " Anchorage, AK 99519-6612 B.P. Exp/oration (A/askaJ. Jnc. NS-09 North Star North Slope Surface -Before R/H Static Temperature/ Pressure Survey ~~~INEC~ MAR 1 8 2009 Elapsed Time (Minutes) Temperature (Deg. F) Pressure (psis) 0.0 67.88 3704.62 0.5 66.55 3704.79 1.0 64.77 3704.76 1.5 63.08 3704.74 2.0 61.84 3704.73 2.5 60.83 3704.73 3.0 59.93 3704.74 3.5 59.24 3704.76 4.0 58.63 3704,78 4.5 58.00 3704.81 5.0 57.42 3704.84 5.5 56.83 3704.88 6.0 56.57 3704.92 6.5 56.19 3704.97 7.0 55.71 3705.01 7.5 55.33 3705.06 8.0 55.02 3705.11 8.5 54.64 3705.15 9.0 54.38 3705.20 9.5 54.10 3705.25 10.0 55.77 3705.94 AVERAGE 58.70 3704.94 Current Wellhead Read in s Wellhead Pressure (psig) : 3700 Wellhead Temperature (deg. F.) : N/A Inner Annulus Pressure (psig) : 0 Outer Annulus Pressure (si N/A ~,-al4 r~3~a Date: February 24, 2009 ob`EM WEI(sAf a ~~• Q ~` s ~ M P~oAc~ive D4y~mric SiRVkas Start time: 04:15:00 Temperature Data 80 70 ---- - ------- so ,-_.. _...__. LL 50 ------------ 40 --- 30 - 20 - - 0 1 2 3 4 5 6 7 8 9 10 Minutes Pressure Data 3720 3715 - ---- N 3710 d 3705 3700 0 1 2 3 4 Mio es 6 7 8 9 10 Page 1 . . . .. . . . ~ . . . ~ ~ ~ . r . . e.P ~Plo~at/o~ ~A/asks>.1~~. Static Temperature/ Pressure Survey NS - 09 North Star North S/ope 90,996' TI/Uss M.D. = 73,252' Elapsed Time (Minutes) Temperature (Deg. F) Pressure (psia) 0.0 251.61 5064.00 1.0 251.61 5064.01 2.0 251.61 5064.11 3.0 251.56 5064.26 4.0 251.48 5064.45 5.0 251.43 5064.65 6.0 251.38 5064.87 7.0 251.18 5065.09 8.0 251.05 5065.32 9.0 250.83 5065.54 10.0 250.86 5065.75 11.0 250.82 5065.97 12.0 250.82 5066.17 13.0 250.82 5066.37 14.0 250.83 5066.56 15.0 250.82 5066.75 16.0 250.87 5066.93 17.0 250.86 5067.11 18.0 250.87 5067.27 19.0 250.87 5067.42 20.0 250.87 5067.57 21.0 250.87 5067.71 22.0 250.91 5067.84 23.0 250.94 5067.96 24.0 250.97 5068.08 25.0 250.96 5068.19 26.0 251.00 5068.30 27.0 250.99 5068.40 28.0 250.98 5068.50 29.0 251.00 5068.59 30.0 250.98 5068.60 AVERAGE 251.05 5066.53 Date: February 24, 2009 Temperature Data 252 251 a 250 249 248 247 Ob`EM WE(( SAE a ~~• 4 ~~ W !r F~ .f. Pf10.,CT1VF Di~yr.osric SERVICE! Start time: 05:21:00 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 Minutes 5072 5067 5062 5 N a 5057 5052 - 5047 0 2 4 6 8 10 12 mutes 18 20 22 24 26 28 30 Page 2 Pressure Data e.p ~P~orat/o~ ~A/askaJ. 1~~. Static Temperature/ Pressure Survey NS-09 North Star North S/ope 90,946' TVDss M.D. = 93,209' Elapsed Time (Minutes) Temperature (Deg. F) Pressure (psia) 0.0 250.92 5063.37 0.5 250.90 5063.40 1.0 250.91 5063.45 1.5 250.88 5063.49 2.0 250.91 5063.53 2.5 250.87 5063.57 3.0 250.87 5063.61 3.5 250.85 5063.66 4.0 250.86 5063.70 4.5 250.87 5063.73 5.0 250.86 5063.77 5.5 250.83 5063.81 6.0 250.83 5063.84 6.5 250.86 5063.88 7.0 250.83 5063.91 7.5 250.86 5063.94 8.0 250.82 5063.97 8.5 250.86 5063.99 9.0 250.86 5064.02 9.5 250.82 5064.05 10.0 250.86 5064.07 10.5 250.82 5064.09 11.0 250.86 5064.11 11.5 250.83 5064.13 12.0 250.82 5064.16 12.5 250.82 5064.18 13.0 250.80 5064.19 13.5 250.86 5064.21 14.0 250.82 5064.23 14.5 250.83 5064.25 15.0 250.82 5064.26 AVERAGE 250.85 5063.89 Date: February 24, 2009 Temperature Data L.~L 251 LL 250 d 249 248 247 Ob`EM WE[[ SAf a ~~• Q ~~ s ~' ~"~ M PwoAcrivr Di~yhosric Srwviccs Start time: 05:51:00 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Minutes Pressure Data 5072 5067 - ----------- -- ----~ - 5062 Q 5057 --- - - ------ - - 5052 5047 8a 0 1 2 3 4 5 6 Nlinute3 9 10 11 12 13 14 15 Page 3 B.P. Exploration (A/askaJ. lnc. Static TB/77PB/'c~tU!'@~ P/'ESSU/'B /~' U/'VB~/ NS-09 North Star North S/ope 90,997' TVDss M.D. = 73,253' Elapsed Time (Minutes) Temperature (Deg. F) Pressure (psis) 0.0 251.02 5069.43 0.5 251.02 5069.43 1.0 251.01 5069.43 1.5 251.03 5069.43 2.0 251.03 5069.43 2.5 251.03 5069.43 3.0 251.02 5069.44 3.5 251.05 5069.44 4.0 251.07 5069.45 4.5 251.07 5069.45 5.0 251.07 5069.46 5.5 251.07 5069.46 6.0 251.07 5069.47 6.5 251.06 5069.48 7.0 251.07 5069.48 7.5 251.06 5069.49 8.0 251.07 5069.49 8.5 251.07 5069.50 9.0 251.08 5069.50 9.5 251.07 5069.51 10.0 251.07 5069.51 10.5 251.08 5069.52 11.0 251.07 5069.52 11.5 251.07 5069.53 12.0 251.07 5069.53 12.5 251.10 5069.54 13.0 251.09 5069.54 i 13.5 251.10 5069.54 14.0 251.07 5069.55 14.5 251.10 5069.55 15.0 251.07 5069.56 AVERAGE 251.06 5069.49 Date: February 24, 2009 Temperature Data 252 251 a 250 249 248 247 ob`EM WE[( SAF a ~~• Q ~~ W Z I~ N P~oAcriv[ Di~yao[Tic SeRVic[s Start time: 06:12:00 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Minutes Pressure Data 5072 5067 - 5062 -- --- -- - Q y a 5057 ------- -__--.-.- -- - -- ------ 5052 ---------___.._...---~------------------ ___-_..-.-.._-_---- 5047 0 1 2 3 4 5 6 Minutes 9 10 11 12 13 14 15 Page 4 B.P. Exploration ~A/askaJ. lnc. Stat~C Ten7pe~atu~e~ PlfBSSU1'e SU/'V@J/ NS-09 North Star North S/ope 90,906'TI/Dss M.D. = 93,969' Elapsed Time (Minutes) Temperature (Deg. F) Pressure (psia) 0.0 250.46 5060.49 0.5 250.37 5060.52 1.0 250.37 5060.55 1.5 250.34 5060.57 2.0 250.31 5060.60 2.5 250.27 5060.62 3.0 250.26 5060.64 3.5 250.23 5060.66 4.0 250.20 5060.68 4.5 250.24 5060.69 5.0 250.21 5060.70 5.5 250.21 5060.71 6.0 250.20 5060.71 6.5 250.15 5060.72 7.0 250.14 5060.72 7.5 250.16 5060.72 8.0 250.16 5060.72 8.5 250.14 5060.72 9.0 250.14 5060.72 9.5 250.13 5060.72 10.0 250.13 5060.72 10.5 250.12 5060.72 11.0 250.16 5060.72 11.5 250.12 5060.72 12.0 250.12 5060.71 12.5 250.13 5060.71 13.0 250.11 5060.71 13.5 250.12 5060.71 14.0 250.09 5060.71 14.5 250.12 5060.71 15.0 250.11 5060.71 AVERAGE 250.20 5060.63 Date: February 24, 2009 ob`EM WE(( SAF a ~: Q ~~ s N PROAGTIVF ~I~G~~YOfTI[ S[RVIG[f Start time: 06:33:00 Temperature Data 252 25t -- _ __ LL 250 249 - - _ _ - 248 ~-------- --- - 247 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Minutes 5072 5067 sos2 a a 5057 5052 5047 0 Page 5 Pressure Data 1 2 3 4 5 6 Nlinute~ 9 10 11 12 13 14 15 a.P ~Plo~st/o~ ~alBSka~ /~~. Static Temperature/ Pressure Survey NS-09 North Star North Slope 90,797' Tl/Dss M.D. = 93,050' Elapsed Time (Minutes) Temperature (Deg. F) Pressure (psia) 0.0 248.73 5049.38 0.5 248.54 5049.43 1.0 248.52 5049.48 1.5 248.42 5049.53 2.0 248.43 5049.57 2.5 248.39 5049.61 3.0 248.34 5049.63 3.5 248.30 5049.66 4.0 248.28 5049.67 4.5 248.29 5049.69 5.0 248.25 5049.69 5.5 248.24 5049.70 6.0 248.20 5049.70 6.5 248.19 5049.70 7.0 248.19 5049.70 7.5 248.15 5049.69 8.0 248.14 5049.69 8.5 248.14 5049.68 9.0 248.10 5049.67 9.5 248.13 5049.67 10.0 248.13 5049.66 10.5 248.09 5049.65 11.0 248.09 5049.65 11.5 248.08 5049.64 12.0 248.05 5049.63 12.5 248.04 5049.62 13.0 248.04 5049.62 13,5 248.04 5049.61 14.0 248.00 5049.60 14.5 248.03 5049.59 15.0 248.00 5049.58 AVERAGE 248.21 5049.63 Date: February 24, 2009 Temperature Data 252 251 ~ 250 249 248 247 ob`F,M WE« SAF Q ~~• Q v~ s N PROACT{Vf Diuyr~osric SFRYICfS Start time: 06:55:00 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Minutes Pressure Data 5072 5067 -- 5062 -------- - ---- _ - - 5 5057 - -------_----------------_ ------- 5052 - - 5047 0 1 2 3 4 5 6 I~linutes 9 10 11 12 13 14 15 Page 6 B.P. Exploration (AlaskaJ. lnc. Static TE/7')~7@/'c~tU/'@ ~ P/'BSSU1'@ J~U/'VE j/ NS - 09 North Star North S/ope Surface -After POOH Elapsed Time (Minutes) Temperature (Deg. F) Pressure (psia) 0.0 26.43 3708.40 0.5 26.38 3708.46 1.0 26.31 3708.51 1.5 26.24 3708.54 2.0 26.18 3708.57 2.5 26.13 3708.58 3.0 26.08 3708.58 3.5 26.01 3708.57 4.0 25.93 3708.56 4.5 25.91 3708.54 5.0 25.84 3708.51 5.5 25.81 3708.48 6.0 25.73 3708.45 6.5 25.68 3708.41 7.0 25.64 3708.37 7.5 25.61 3708.34 8.0 25.58 3708.32 8.5 25.54 3708.30 9.0 25.48 3708.23 9.5 25.48 3708.21 10.0 25.44 3708.17 AVERAGE 25.88 3708.43 Current Wellhead Read in s Wellhead Pressure (psig) : 3700 Wellhead Temperature (deg. F.) : N/A Inner Annulus Pressure (psig) : 0 Outer Annulus Pressure si N/A Date: February 24, 2009 Ob`EM WE(( sAf a ~~• 4 ~~ N PROActiVE Oi~yMOSiic SERVICES Start time: 03:19:00 Temperature Data 80 70 -- ----- so -- -- ------ -- 50 -- -------- ao 30 - 20 0 1 2 3 4 5 6 7 8 9 10 Minutes 3720 3715 N 3710 a 3705 3700 0 Page 7 Pressure Data 1 2 3 4 Minutes 6 7 8 9 10 B.P. Exploration (A/askaJ. lnc. NS-09 North Star North Slope Downho% Temp/Press Date: February 24, 2009 Static Temperature /Pressure Survey Start time: 04:15:00 End time: 07:50:00 ob`EM WE(( SAS Qa c~~ .+e M -- P~oAcrivr Diwywosric ScRVic~s Temperature Data 252 as1 - - 250 - -~ ----- ------ a i~ 249 - ----- 248 -- 247 -200 0 200 400 600 800 1000 1200 1400 1600 Minutes Pressure Data 5072 ~~ 5067 i~if --- - ------- --------- -- ---- --- --__. ---_-_ 5062 - -- -- ------- --- - -- -- N a 5057 -- -- 5052 - --- -- 5047 -200 0 200 `~ 600 Minutes 800 1000 1200 1400 1600 Page 8 • • ,~ o~ BPXA WELL DATA TRANSMITTAL Enclosed are the materials listed below. If you have anv questions. please contact Joe Lastufka at (9071564-4091 Date 06-02-2008 Transmittal Number:92976 Delivery Contents SW Name Date Contractor Run To De th Bottom De th Descri tion STATIC TEMPERATURE / NS09 05-24-2008 PDS 1 0 13247 PRESSURE SURVEY NS09 05-24-2008 PDS 1 12629 12833 CORRELATION LOG CD-ROM -CORRELATION NS09 05-24-2008 PDS LOG /STATIC SURVEY STATIC TEMPERATURE / NS24 05-23-2008 PDS 1 0 12480 PRESSURE SURVEY NS24 05-23-2008 PDS 1 11793 12196 CORRELATION LOG CD-ROM -CORRELATION NS24 05-23-2008 PDS LOG /STATIC SURVEY PERFORATION RECORD W/ NS16A 04-30-2008 SCH 1 14200 14400 GAMMA RAY CD-ROM -PERFORATION NS16A 04-30-2008 SCH RECORD W/GAMMA RAY MEMORY PRODUCTION NS15 05-10-2008 SCH 1 14726 15080 PROFILE CD-ROM -MEMORY NS15 05-10-2008 SCH PRODUCTION PROFILE Please Sign and Return one copy of this transmittal. Thank You, Joe Lastufka - _ _ Petrotechnical Data Center ~tX~- ~~~ ,~ ~~a3~O? c~oc~-o5y i~ 36y BPXA David Fair AOGCC wa~l bL( ~to3~~ Christine Mahnken Murphy Exploration -~'-' Ignacio Herrera D N R ~'p ~Ol-at°' l (~3 (o~O Kristin Dirks ~ ~ i\~'ii`~'iS ~, /V/y r O • DVUg Cllr olr1a11Jk1 ~~~~~~~ JUN ~ 200 Petrotechnical Data Center LR2-1 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 995 1 9-66 1 2 5 . Z . . . . . ~ . r . . . . . . . . ~ B.P. Exploration (A/askaJ. lnc. Static Temperature/ Pressure Survey NS - 09 ob~EM wE [l S,oF North Stan ~~ ,~ ~ ~ ~~ North Slope ~~~~,~ ~~~ 208 W Surface -Before R/H P^onc.ive Di~ynos.ic SEavicts Date: May 24, 2008 Start time: 15:51:00 Elapsed Time (Minutes) Temperature (Deg. F) Pressure (psia) 0.0 60.88 3724.95 0.5 60.57 3725.32 1.0 60.29 3725.24 1.5 60.02 3725.15 2.0 59.76 3725.08 2.5 59.50 3724.70 3.0 59.25 3724.64 3.5 59.01 3724.58 4.0 58.76 3724.52 4.5 58.53 3724.47 5.0 58.30 3724.41 5.5 58.07 3724.36 6.0 57.85 3724.31 6.5 57.64 3724.26 7.0 57.44 3724.21 7.5 57.24 3724.17 8.0 57.04 3724.12 8.5 56.86 3724.08 9.0 56.68 3724.04 9.5 56.50 3724.00 10.0 56.33 3723.97 AVERAGE 58.41 3724.50 Current Wellhead Read in s Wellhead Pressure (psig) : 3,690 Wellhead Temperature (deg. F.) : N/A Inner Annulus Pressure (psig) : 121 Outer Annulus Pressure sig) : 0 140 120 LL 100 ~' ~ 80 so 40 Temperature Data 0 1 2 3 4 5 6 7 8 9 10 Minutes 3800 3775 a rn 3750 a 3725 3700 Pressure Data 0 1 2 3 4 5 6 7 8 9 10 Minutes Page 1 • ~ o ~ - a~~ r ~~~~ B.P. Exploration (A/askaJ. lnc. Stat~C r@/77~78!'c7tU/'E~ P/'BSSU/'E SU/'V@~/ NS-09 North Star North S/ope 70,999' TVOss M.D. = 93,247' Elapsed Time (Minutes) Temperature (Deg. F) Pressure (psia) 0.0 214.19 5051.51 1.0 216.72 5051.62 2.0 219.13 5051.82 3.0 221.39 5052.07 4.0 223.51 5052.34 5.0 225.50 5052.60 6.0 227.36 5052.87 7.0 229.09 5053.11 8.0 230.70 5053.34 9.0 232.21 5053.56 10.0 233.60 5053.76 11.0 234.90 5053.95 12.0 236.10 5054.14 13.0 237.22 5054.32 14.0 238.25 5054.49 15.0 239.21 5054.66 16.0 240.10 5054.81 17.0 240.91 5054.96 18.0 241.67 5055.10 19.0 242.37 5055.24 20.0 243.02 5055.36 21.0 243.62 5055.48 22.0 244.18 5055.60 23.0 244.69 5055.70 24.0 245.17 5055.80 25.0 245.61 5055.90 26.0 246.02 5055.99 27.0 246.39 5056.07 28.0 246.75 5056.14 29.0 247.07 5056.21 30.0 247.37 5056.28 AVERAGE 236.26 5054.35 Date: May 24, 2008 ob`EM WE[( SAF Qa. °~9 W s PaoAcTive D4yMOfric Satviees Start time: 17:21:00 Temperature Data zso 250 ...................................................................................................................................................................................................................... LL 240 ................................................................................................................... ............................................................................................ ~' c 230 .................................................... .......................................................................................................................................................................... 220 ............. .................................................................................................................................................................... ............................. 210 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 Minutes so8o so~o Soso vgf 5050 a so4o 5030 5020 Pressure Data 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 Minutes Page 2 • B.P. Exploration (A/askaJ. lnc. Static Temperature/ Pressure Survey NS-09 North Star North S/ope 90,942' TYDss M.D. = 93, 997' Elapsed Time (Minutes) Temperature (Deg. F) Pressure (psia) 0.0 248.58 5051.17 0.5 248.68 5051.20 1.0 248.77 5051.23 1.5 248.85 5051.25 2.0 248.94 5051.28 2.5 249.02 5051.30 3.0 249.10 5051.33 3.5 249.17 5051.34 4.0 249.24 5051.36 4.5 249.31 5051.38 5.0 249.38 5051.40 5.5 249.44 5051.42 6.0 249.50 5051.44 6.5 249.56 5051.45 7.0 249.62 5051.47 7.5 249.67 5051.48 8.0 249.72 5051.50 8.5 249.77 5051.52 9.0 249.82 5051.53 9.5 249.87 5051.54 10.0 249.91 5051.55 10.5 249.95 5051.56 11.0 249.99 5051.58 11.5 250.03 5051.59 12.0 250.07 5051.60 12.5 250.11 5051.61 13.0 250.14 5051.62 13.5 250.17 5051.63 14.0 250.21 5051.64 14.5 250.24 5051.65 15.0 250.27 5051.66 AVERAGE 249.58 5051.46 Date: May 24, 2008 Temperature Data 0b~E~11 WE(( s`AF 4° c~v W ~- - PRO1ICTIVF ~IAC~NOSTIC sERVICEf Start time: 17:56:00 2so 250 ........... .... ........ ... .... .... ... ... LL 240 ............................. ....................................................................................................... .......................... .......... ~' ~ 230 ........................................................................................................................................................................... ~ ~ .......................................-.......... 220 ........................................................................................................................... ....................................................................................... 210 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Minutes Page 3 e.P ~Ploratlo~ ~AlaskaJ.1~~. Static Temperature/ Pressure Survey NS-09 North Star North Slope 90,997' TVDss M.D. = 93,247' Elapsed Time (Minutes) Temperature (Deg. F) Pressure (psia) 0.0 250.47 5057.09 0.5 250.49 5057.10 1.0 250.51 5057.10 1.5 250.53 5057.10 2.0 250.55 5057.10 2.5 250.57 5057.10 3.0 250.59 5057.10 3.5 250.61 5057.11 4.0 250.63 5057.11 4.5 250.65 5057.11 5.0 250.67 5057.11 5.5 250.69 5057.11 6.0 250.71 5057.12 6.5 250.73 5057.12 7.0 250.75 5057.12 7.5 250.76 5057.12 8.0 250.78 5057.13 8.5 250.80 5057.13 9.0 250.81 5057.13 9.5 250.83 5057.14 10.0 250.84 5057.14 10.5 250.86 5057.14 11.0 250.87 5057.15 11.5 250.89 5057.15 12.0 250.90 5057.15 12.5 250.91 5057.15 13.0 250.93 5057.15 13.5 250.94 5057.16 14.0 250.95 5057.16 14.5 250.97 5057.16 15.0 250.98 5057.17 AVERAGE 250.75 5057.13 Date: May 24, 2008 Ob`Ep1 wE (( s`A6' 4~ c~v W ~ N PROACTIVE Di~ynosric SERVic[s Start time: 18:14:00 Temperature Data 2so ~ 250 .. ... ... ... .... .... ... ... .... .... .... .... .... .. .... ... .... .... .... .... ....... LL. 240 .............................................................~-~--...........................................-~---.............................................................---........................................................ ~' ~ 230 .................................................. _............................................-.................................................... 220 .................................................................................................................................................................................................................................... 210 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Minutes 5080 5070 5060 a a 5050 5040 5030 solo Pressure Data 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Minutes Page 4 • B.P. Exploration (A/askaJ. lnc. Static Temperature/ Pressure Survey NS-09 North Star North Slope 70,892' TI/Dss M.D. = 73, 947' Elapsed Time (Minutes) Temperature (Deg. F) Pressure (psia) 0.0 250.97 5046.94 0.5 250.94 5046.97 1.0 250.91 5046.99 1.5 250.88 5047.01 2.0 250.85 5047.02 2.5 250.82 5047.02 3.0 250.79 5047.03 3.5 250.75 5047.03 4.0 250.72 5047.03 4.5 250.69 5047.03 5.0 250.65 5047.03 5.5 250.62 5047.02 6.0 250.59 5047.02 6.5 250.56 5047.01 7.0 250.52 5047.01 7.5 250.49 5047.00 8.0 250.46 5046.99 8.5 250.43 5046.99 9.0 250.40 5046.98 9.5 250.37 5046.97 10.0 250.34 5046.97 10.5 250.32 5046.96 11.0 250.29 5046.96 11.5 250.26 5046.95 12.0 250.24 5046.94 12.5 250.21 5046.94 13.0 250.19 5046.93 13.5 250.17 5046.93 14.0 250.14 5046.92 14.5 250.12 5046.92 15.0 250.10 5046.91 AVERAGE 250.51 5046.98 Date: May 24, 2008 ob`F.M WE[[ SAF QQ. c,9 _ ~. -- PROI~Ci1VE D4yNOSTic SEwvices Start time: 18:35:00 Temperature Data 2so ~ 250 .... .... .... ........ .... .... .... .... ... ... ... .... .... .... u. 240 ...... - -- ...................._.._.........._---- .. - ................._...... _................................_.............................. ~' ~ 230 ..................................................................................... ........................................................................................................... ...................... 220 ............._.............._ - --......... -......_.....- ....- - ~ - ....._......._.................................................................................................... 210 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Minutes 5080 so~o 5060 a in 5050 a so4o 5030 5020 Pressure Data 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Minutes Page 5 e.P ~Plo~at/o~ ~a/asks>.1~~. Static Temperature/ Pressure Survey NS-09 North Star North Slope 70,792' TYDss M.D. = 93,045' Elapsed Time (Minutes) Temperature (Deg. F) Pressure (psia) 0.0 249.83 5036.64 0.5 249.78 5036.67 1.0 249.72 5036.69 1.5 249.67 5036.70 2.0 249.61 5036.71 2.5 249.55 5036.71 3.0 249.50 5036.72 3.5 249.44 5036.71 4.0 249.39 5036.71 4.5 249.33 5036.70 5.0 249.28 5036.70 5.5 249.23 5036.68 6.0 249.18 5036.68 6.5 249.13 5036.66 7.0 249.08 5036.65 7.5 249.03 5036.65 8.0 248.98 5036.63 8.5 248.93 5036.62 9.0 248.89 5036.61 9.5 248.84 5036.60 10.0 248.80 5036.59 10.5 248.76 5036.58 11.0 248.72 5036.58 11.5 248.68 5036.57 12.0 248.64 5036.56 12.5 248.60 5036.55 13.0 248.56 5036.54 13.5 248.53 5036.53 14.0 248.49 5036.53 14.5 248.46 5036.52 15.0 248.43 5036.52 AVERAGE 249.06 5036.63 Date: May 24, 2008 Temperature Data Ob`f,M WE[[ SAF 4~ c~v _ s -- PlOACTIVF DIAfjNOSTIC SERVICES Start time: 18:54:00 2so 250 ... ... ... ... .... .... .... .... ... ........ .... .... ......................................... W 240 ......................................................................... ................................................................................................................................................................. ~' ~ 230 .................................................................................... ................................................................... ............................................................................ 2zo ............................................................ ................................................................................................................................... 210 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Minutes Page 6 • ~ ~ ~ ~ ~ ~ ~ r• ~ ~ ~ ~ ~ ' ~ ~ ~ ~ ~ B.P. Exploration (A/aska). Inc. SLfc~t/C TEn7~f7@/'c7tU/'E~ P/'ESSU/'B SU/'VEJ/ - North Star W c North Slope Surface -Afl'e~ POOH PRUAcrivE Di~gNOfTI[ sERVICEf Date: May 24, 2008 Start time: 20:15;00 Elapsed Time (Minutes) Temperature (Deg. F) Pressure (psia) 0.0 123.69 3719.83 0.5 122.31 3719.96 1.0 120.88 3720.07 1.5 119.43 3720.17 2.0 117.97 3720.27 2.5 116.50 3720.34 3.0 115.04 3720.41 3.5 113.58 3720.47 4.0 112.14 3720.52 4.5 110.71 3720.56 5.0 109.29 3720.58 5.5 107.90 3720.60 6.0 106.53 3720.61 6.5 105.18 3720.61 7.0 103.86 3720.61 7.5 102.56 3720.60 8.0 101.29 3720.59 8.5 100.05 3720.57 9.0 98.83 3720.55 9.5 97.64 3720.53 10.0 96.48 3720.50 AVERAGE 109.61 3720.43 Current Wellhead Readin s Wellhead Pressure (psig) : 3,693 Wellhead Temperature (deg. F.) : N/A Inner Annulus Pressure (psig) : 121 Outer Annulus Pressure sig) : 0 140 120 LL 100 ~' ~ ao so 40 Temperature Data 0 1 2 3 4 5 6 7 8 9 10 Minutes 3800 3775 a y 3750 a 3725 3700 Pressure Data 0 1 2 3 4 5 6 7 8 9 10 Minutes Page 7 I• . . bp Date 10-23-2007 Transmittal Number:92913 I] '; 'J ; -- BPXA WELL DATA TRANSMITTAL Enclosed are the materials listed below. If you have any questions, please contact me in the PDC at 564-4091. ;)od ./55 Log Top SW Name Date Contractor Run Depth Bottom Depth LOQ Type MEMORY MULTI-FINGER ....¡{IT CALIPER LOG RESULTS ~f..( NS16 09-11-2007 PDS 1 0 12110 SUMMARY MULTI-FINGER CALIPER 3D NS16 09-11-2007 PDS 1 0 12110 DATA AND VIEWER -é)b "}- NS30 09-16-2007 SCH 1 15900 16170 PERFORATING RECORD - MEMORY STATIC PRESSURE -leI NS06 07 -29-2007 SCH 1 13096 13694 AND TEMERATURE SURVEY - MEMORY STATIC PRESSURE - Il.f/ NS18 07 -30-2007 SCH 1 16290 16845 AND TEMERA TURE SURVEY - h~lq MEMORY STATIC PRESSURE NS09 07-31-2007 SCH 1 12666 1 3341 AND TEMERA TURE SURVEY ;)0'5" ,f)t;;) dOd =>0 t~ Please SIgn and Return one copy of this transmittal. Thank You, Andy Farmer Petrotechnical Data Center S~~ANNED NOV 0 1 2007 Attn: Doug Chromanski Ignacio Herrera Howard Okland Kristin Dirks Cheryl Ploegstra MMS Murphy Exploration AOGCC DNR BPXA Petrotechnical Data Center LR2-1 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 99519-6612 bp ~.". '4 ... .. .. ....... .. ........... ..-v..· Date 05-09-2007 Transmittal Number:92890 BPXA WELL DATA TRANSMITTAL Enclosed are the materials listed below. If you have any questions, please contact me in the PDC at 564-4091. Log Top SW Name Date Contractor Run Depth Bottom Depth Log Type ULTRASONIC CORRISION NS34 01-18-2007 SCH EVALUATION LOG COMPOSITE CEMENT NS34 01-18-2007 SCH EVALUATION LOG NS09 12-22-2006 SCH PRODUCTION PROFILE PERFORATION RECORD NS09 08-05-2006 SCH WITH GAMMA RAY ~_J~__ Please Sign and Return one copy of this transmittal. Thank You, Andy Farmer Petrotechnical Data Center MAY 1 0 Z007 Attn: Cheryl Ploegstra Doug Chromanski Kristin Dirks Christine Mahnken Ignacio Herrera ar:ANNED MAY 1 1 2007 ~Cll & Gas C.ems. Commission A~ _,~... .____.It ~)O I -é;){L1 Petrotechnical Data Center LR2-1 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 99519-6612 bp . RECE:IVED . Date 05-04-2007 Transmittal Number:92888 MAY 0 8 2007 Alaska Oil & Gas Cons. CommissiOn Anchorage Q öl-:;) I c:>¡ "# IS-I 03 BPXA WELL DATA TRANSMITTAL Enclosed are the materials listed below. If you have any questions, please contact me in the PDC at 564-4091. Log Top SW Name Date Contractor Run Depth Bottom Depth Log Type STATIC TEMP / PRESSURE NS07 07-23-2006 PDS SURVEY REPORT STATIC TEMP / PRESSURE NS12 07 -23-2006 PDS SURVEY REPORT STATIC TEMP / PRESSURE NS16 08-20-2006 PDS SURVEY REPORT STATIC TEMP / PRESSURE NS12 02-17 -2007 PDS SURVEY REPORT STATIC TEMP / PRESSURE NS09 02-19-2007 PDS SURVEY REPORT STATIC TEMP / PRESSURE NS24 02-15-2007 PDS SURVEY REPORT STATIC TEMP / PRESSURE NS06 02-18-2007 PDS SURVEY REPORT DEPTH DETERMINATION NS07 07 -23-2006 PDs..~ L .- LOG h J..i¡J V:J ~UUf DEPTH DETERMINATION NS12 07 -23-2006 PDS LOG DEPTH DETERMINATION NS16 08-20-2006 PDS LOG NS12 02-17 -2007 PDS JEWELRY LOG NS09 02-19-2007 PDS JEWELRY LOG NS24 02-15-2007 PDS JEWELRY LOG NS06 02-18-2007 PDS JEWELRY LOG NS24 04-1 0-2007 PDS PRODUCTION PROFILE NS08 04-10-2007 PDS PRODUCTION PROFILE NS13 04-07 -2007 PDS COIL FLAG NS07 07 -13-2006 PDS JEWELRY LOG / CD ROM t.JS12 07 -23-20û6 PÛS JEWELRY LOG / CD ROM DEPTH CORRELATION NS16 08-20-2006 PDS STATIC SURVEY CD ROM Petrotechnica1 Data Center LR2-1 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 99519-6612 bp . . Date 05-04-2007 Transmittal Number:92888 BPXA WELL DATA TRANSMITTAL JEWELRY LOG / STATIC NS12 02-17 -2007 PDS SURVEY CD ROM JEWELRY LOG / STATIC NS09 02-19-2007 PDS SURVEY CD ROM JEWELRY LOG / STATIC NS24 02-15-2007 PDS SURVEY CD ROM JEWELRY LOG / STATIC NS06 02-18-2007 PDS SURVEY CD ROM PRODUCTION PROFILE NS24 04-11-2007 PDS CD ROM PRODUCTION PROFILE NS08 04-1 0-2007 PDS CD ROM NS13 04-07-2007 PDS COIL FLAG CD ROM Please Sign and Return one copy of this transmittal. Thank You, Andy Farmer Petrotechnical Data Center Attn: Kristin Dirks Chistine Mahnken Ignacio Herrera Doug Chromanski Petrotechnical Data Center LR2-1 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 99519-6612 11II_____________ - - -- BP Exploration (Alaska) Inc. NS-09 North Star North Slope Surface - Before RIH Static Temperature/Pressure Survey Date: February 19, 2007 Start time: 10:32:00 Elapsed Time Temperature Pressure (Minutes) (Deg. F) (psia) 0.0 31 .43 3772.32 0.5 27.49 3772.43 1.0 24.36 3772.64 1.5 22.47 3772.70 2.0 19.81 3772.75 2.5 17.62 3772.77 3.0 15.98 3772.78 3.5 14.60 3772.79 4.0 13.83 3772.79 4.5 12.81 3772.79 5.0 11.74 3772.77 5.5 11.14 3772.76 6.0 10.35 3772.76 6.5 10.09 3772.73 7.0 9.48 3772.71 7.5 9.19 3772.69 8.0 8.49 3772.67 8.5 8.50 3772.64 9.0 7.78 3772.57 9.5 7.93 3772.52 10.0 7.34 3772.46 AVERAGE 14.40 3772.67 Temperature Data 40 30 IJ.. 20 dJ Q c 10 ---------------- -- ------------------- - o ------------------ ---------- -10 o 2 3 4 5 6 7 8 9 10 Minutes Pressure Data 3800 3790 --------------------------- ---- --- --. 3780 --------------------------- ------------ « ¡¡¡ CI.. Current Wellhead Readings Wellhead Pressure (psig) : Wellhead Temperature (deg. F.) : Inner Annulus Pressure (psi g) : Outer Annulus Pressure (psig) : 3770 3760 - - - - ----------------------------------- -- 3750 o 2 3 456 Minutes Page 1 ------------------- BP Exploration (Alaska) Inc, NS-09 North Star North Slope TVDss MD = 13,041' Static Temperature/Pressure Survey Elapsed Time Temperature Pressure (Minutes) (Deg, F) (psia) 0,0 248,04 5067,84 0,5 24T 98 5067,87 1.0 247,97 5067.89 1.5 247.92 5067,90 2.0 247.93 5067.92 2,5 247.90 5067.92 3.0 247.88 5067.93 3.5 247.90 5067.93 4.0 247.89 5067.93 4.5 247.85 5067,93 5.0 247.86 5067.92 5.5 247.86 5067.93 6.0 247.87 5067.92 6.5 247.86 5067.92 7.0 247.84 5067.92 7.5 247.85 5067.91 8.0 247.84 5067.91 8.5 247.84 5067.90 9.0 247.84 5067.90 9.5 247.83 5067.90 10.0 247.83 5067.89 10.5 247.82 5067.88 11.0 247.83 5067.88 11.5 247.83 5067.88 12.0 247.82 5067.88 12.5 247.81 5067.88 13.0 247.81 5067.88 13.5 247.81 5067.88 14.0 247.81 5067.87 14.5 247.80 5067.87 15.0 247.80 5067.87 AVERAGE 247.86 5067.90 Date: February 19, 2007 Start time: 13:30:00 Temperature Data 255 253 - ~~----- ----- --- --- - IJ.. 251 6 <II c 249 ---- - 247 ~ - ~ ~ - -- ~ - - -- ---- "---- --- 245 o 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Minutes Pressure Data 5100 5090 ----- --- 5080 « ¡¡¡ CI.. 5070 ----- --- 5060 - ~ ~ -- ~ - ~ ~ -- -- - - -- -- ~ -- -- ------- -- 5050 o 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Minutes Page 2 ------------------- BP Exploration (Alaska) Inc. NS-OB North Star North Slope 1D,88B'TVDss MD = 13, 143' Static Temperature/Pressure Survey Elapsed Time Temperature Pressure (Minutes) (Deg. F) (psia) 0.0 249.83 5078.57 0.5 249.78 5078.60 1.0 249.72 5078.62 1.5 249.69 5078.64 2.0 249.67 5078.66 2.5 249.66 5078.67 3.0 249.64 5078.68 3.5 249.63 5078.69 4.0 249.61 5078.69 4.5 249.60 5078.70 5.0 249.59 5078.70 5.5 249.58 5078.70 6.0 249.58 5078.70 6.5 249.57 5078.68 7.0 249.56 5078.69 7.5 249.56 5078.69 8.0 249.56 5078.69 8.5 249.54 5078.69 9.0 249.54 5078.69 9.5 249.54 5078.69 10.0 249.53 5078.69 10.5 249.53 5078.69 11.0 249.52 5078.69 11.5 249.52 5078.69 12.0 249.51 5078.69 12.5 249.51 5078.69 13.0 249.52 5078.69 13.5 249.51 5078.68 14.0 249.50 5078.68 14.5 249.49 5078.68 15.0 249.51 5078.68 AVERAGE 249.58 5078.68 Date: February 19, 2007 Start time: 13:13:00 Temperature Data 255 253 -.------------- - ------ IJ.. 251 ~ 6 <II c 249 - ----------------- ------- - - -------------- ---------- ------- 247 - - - u - -- ~ u ~ ------------ - ---------------- 245 o 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Minutes Pressure Data 5100 5090 --- -"--- -. - ---------- 5080 « ¡¡¡ CI.. 5070 ------- ---------- - ----- -- --- - -.--------- 5060 --------------- - ---- ------ --------- 5050 o 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Minutes L_ Page 3 ------------------- BP Exploration (Alaska) Inc. NS-OB North Star North Slope 1D,B3B'TVDss MD = 13, 193' Static Temperature/Pressure Survey Elapsed Time Temperature Pressure (Minutes) (Deg. F) (psia) 0.0 251 . 1 0 5083.71 0.5 251.11 5083.73 1.0 251.11 5083.74 1.5 251 .11 5083.76 2.0 251 .11 5083.77 2.5 251 .11 5083.79 3.0 251.10 5083.80 3.5 251 .11 5083.82 4.0 251 .11 5083.83 4.5 251 .11 5083.84 5.0 251.11 5083.85 5.5 251 .10 5083.86 6.0 251.11 5083.87 6.5 251.11 5083.88 7.0 251.11 5083.89 7.5 251.11 5083.90 8.0 251.11 5083.90 8.5 251 .11 5083.92 9.0 251.10 5083.92 9.5 251.11 5083.93 10.0 251 .10 5083.93 10.5 251 .11 5083.94 11.0 251.10 5083.95 11.5 251.11 5083.95 12.0 251 .11 5083.96 12.5 251 .11 5083.97 13.0 251 .11 5083.97 13.5 251 .11 5083.98 14.0 251.10 5083.98 14.5 251 .11 5083.99 15.0 251.12 5083.99 AVERAGE 251.11 5083.88 Date: February 19, 2007 Start time: 12:56:00 Temperature Data 255 253 ~-~~~-~-----~~~~~~~~~~~~-~~ ~~~~ ~ --- ----- --------- II.. 251 6 <II o 249 --------- -------------------------- 247 ---. --.-- ----------------- -- 245 o 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Minutes Pressure Data 5100 5090 5080 « ¡¡¡ CI.. 5070 -- -- ------------------- - -------------------- --- - -------- --- 5060 --------------- - - ---- ------------- 5050 o 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Minutes Page 4 ------------------- BP Exploration (Alaska) Inc, NS-OB North Star North Slope 10,9BB'TVDss MD = 13,243' Static Temperature/Pressure Survey Elapsed Time T emperatu re Pressure (Minutes) (Deg. F) (psia) 0.0 251.09 5086.43 1.0 251.05 5086.52 2.0 251.01 5086.66 3.0 251.01 5086.85 4.0 250.97 5087.06 5.0 250.94 5087.24 6.0 250.95 5087.43 7.0 250.96 5087.61 8.0 250.98 5087.78 9.0 251.00 5087.94 10.0 251.00 5088.08 11.0 251.02 5088.22 12.0 251 .05 5088.34 13.0 251.08 5088.45 14.0 251.08 5088.56 15.0 251.10 5088.65 16.0 251 11 5088.74 17.0 251.13 5088.81 18.0 251.13 5088.89 19.0 251.14 5088.94 20,0 251.15 5089.01 21.0 251.17 5089.07 22.0 251.17 5089.13 23.0 251.17 5089.17 24.0 251.18 5089.22 25.0 251.20 5089.26 26.0 251.20 5089.30 27.0 251.20 5089.34 28.0 251 .20 5089.37 29.0 251.22 5089.41 30.0 251.22 5089.44 AVERAGE 251.09 5088.35 Date: February 19, 2007 Start time: 12:24:00 Data 255 253 ~~-----~ ~~ -- ---------------------------- ------ - - IJ.. 251 6 <II c 249 ---- --- - ----------------- -------------- 247 - -------------- --------- ------- - --- 245 o 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 Minutes Pressure Data 5090 5080 - ~ - - -- ~ ~ ------------------ « ¡jj CI.. 5070 - ----------------- .-------------- 5060 ------ ------ ----- - - --- -------- 5050 o 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 Minutes Page 5 ------------------- BP Exploration (Alaska) Inc. NS-OB North Star North Slope 10,888' TVDss MD = 13, 143' Static Temperature/Pressure Survey Elapsed Time Temperature Pressure (Minutes) (Deg. F) (psia) 0.0 249.27 5078.86 0.5 249.29 5078.84 1.0 249.31 5078.82 1.5 249.30 5078.80 2.0 249.31 5078.79 2.5 249.31 5078.79 3.0 249.30 5078.78 3.5 249.32 5078.78 4.0 249.33 5078.78 4.5 249.33 5078.78 5.0 249.33 5078.78 5.5 249.34 5078.78 6.0 249.34 5078.79 6.5 249.34 5078.78 7.0 249.33 5078.79 7.5 249.34 5078.80 8.0 249.34 5078.80 8.5 249.35 5078.80 9.0 249.34 5078.81 9.5 249.35 5078.81 10.0 249.35 5078.81 10.5 249.35 5078.81 11.0 249.35 5078.82 11.5 249,36 5078.82 12.0 249.36 5078.82 12.5 249.35 5078.83 13.0 249.36 5078.83 13.5 249.36 5078.83 14.0 249.36 5078.83 14.5 249.36 5078.83 15.0 249.37 5078.83 AVERAGE 249.34 5078.81 Date: February 19, 2007 Start time: 13:48:00 Temperature Data 255 253 ----~---~~~ ~- - - ------------ - -------- IJ.. 251 - - - - ~ - - - ~ ~ - - ~ ~ ~ 6 <II c 249 -------- 247 -.-------------- ---------------- - ----- 245 o 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Minutes Pressure Data 5100 5090 5080 « ¡¡¡ CI.. 5070 -------- 5060 --------- ----- --- - .---- ----- -------- - ------------ ---------------- - ---------- 5050 o 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Minutes Page 6 ------------------- BP Exploration (Alaska) Inc. NS-OB North Star North Slope Surface - After POOH psed Time Minutes) 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 5.5 6.0 6.5 7.0 7.5 8.0 8.5 9.0 9.5 10.0 AVERAGE Temperature (Deg. F) 0.85 0.53 -0.27 -0.15 -0.44 -0.86 -0.75 -0.97 -0.95 -1.09 -1.26 -1 .23 -1.37 -1.58 -1 .43 -1.38 -1.35 -1.34 -1.69 -1 .42 -1.47 -0.93 Current Wellhead Readings Wellhead Pressure (psig) : Wellhead Temperature (deg. F.) : Inner Annulus Pressure (psig) Outer Annulus Pressure (psiQ) . Static Temperature/Pressure Survey Date: February 19, 2007 Start time: 15:26:00 Pressure (psia) 3774.76 3775.13 3775.39 3775.63 3775.90 3776.22 3776.57 3776.93 3777.27 3777 .61 3777.93 3778.20 3778.45 3778.65 3778.82 3778.94 3779.02 3779.06 3779.08 3779.06 3779.01 3777.51 Temperature Data 40 30 - ---------- - - ---------- -------- IJ.. 20 6 <II C 10 ----------- - ------ ------------ - ---------- --------- --------- -- -- - ------- - -------- o -10 o 2 3 4 5 6 7 8 9 10 Minutes Pressure Data -------- 3790 - ------ ------------- - ----- -- 3780 « ¡¡j CI.. 3770 - ------------- - - ------ ------ -- - - 3760 -------- -- ------ --- - ------ --------- 3750 o 2 3 4 5 6 Minutes 7 8 9 10 Page 7 ------ ------- - - - - - - BP Exploration (Alaska) Inc. NS-OB North Star North Slope Downhole Temp/Press Static Temperature/Pressure Survey Date: February 19, 2007 Start time: 12:24:00 End time: 15:26:00 Temperature Data 255 253 ~--- ~~--- ----- ----------- 1.1.. 251 6 <II c 249 --------- ----- ------ ---- - - ----- ---- ----- 247 ------- 245 -200 -_._.._~~~...~--~--~" --"~"_._.~--"-~_.._~."_._...,~--- , , o 200 400 600 800 1000 1200 1400 1600 Minutes Pressure Data 5100 5090 ----- ----- 5080 -~ _UU~_ ---- ------ ----------- - --- ----- « ¡¡¡ CI.. 5070 - ---- - - 5060 --- --- - -- --- ------ --- o 200 400 600 800 1000 1200 1400 1600 Minutes Page 8 bp ) . Date 02-08-2007 Transmittal Number:92874 BPXA WELL DATA TRANSMITTAL Enclosed are the materials listed below. If you have any questions, please contact me in the PDC at 564-4091. / )6d -;;¡ '/'1'1 í' O/-ot(., SW Name Date Contractor Log Run Top Depth Bottom Depth Log Type NS09 08-05-2006 SCH PEFORA TION RECORD NS11 12-10-2006 SCH PERFOATION RECORD NS11 12-20-2006 SCH PRODUCTION PROFILE MEMORY MULTI-FINGER NS15 02-04-2007 PDS CALIPER LOG SUMMARY MEMORY MULTI-FINGER NS13 12-16-2006 PDS CALIPER LOG SUMMARY NS15 02-04-2007 PDS MULTI-FINGER 3D DATA CD )ð{ -~Îq -- I 'ð{,-03~ " t~ Please Sign and Return one copy of this transmittal. Thank You, Andy Farmer Petrotechnical Data Center 5tANNED FES 1 3 2007 Attn: Kristin Dirks Howard Okland Ignacio Herrera Doug Chromanski RECEIVED r-ro'1 3 'JunO'7 reo .!J.' L , ~OiI&GasCOOS.~ Anchorage dDI-Q/CJ Petrotechnical Data Center LR2-1 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 99519-6612 . STATE OF ALASKA . RECE\VED ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONSEP 272006 1. Operations Performed: Abandon 0 Alter CasingD Change Approved ProgramD Repair WellŒ! Pull TubingD Operation ShutdownD PluQ PerforationsD Perforate New Pool 0 Perforate IKI Alaska Oil Stimulate 0 Anch~ft~ WaiverD Time ExtensionD Re-enter Suspended WellD 5. Permit to Drill Number: 2. Operator Name: 3. Address: BP Exploration (Alaska), Inc. 4. Current Well Class: Development 00 ExploratoryD P.O. Box 196612 Anchorage, Ak 99519-6612 7. KB Elevation (ft): 56.10 8. Property Designation: ADL-0312799 11. Present Well Condition Summary: StratigraphicD ServiceD 9. Well Name and Number: NS09 10. Field/Pool(s): Northstar Filed / Northstar Oil Pool Total Depth measured 13429 feet true vertical 11234.7 feet Effective Depth measured 13383 feet true vertical 11188.8 feet Plugs (measured) Junk (measured) None None Casing Length Size MD TVD Burst Collapse SURFACE 3354 13·3/8" 68# L·80 44 - 3398 44.0 . 3216.0 4930 2270 PRODUCTION 11477 9-5/8" 47# L-80 42 - 11519 42.0 - 9428.0 6870 4760 LINER 1578 7" 26# L-80 11326 - 12904 9259.0 - 10717.0 7240 5410 LINER 661 4·1/2" 12.6# 13Cr80 12768 - 13429 10585.0 - 11235.0 8430 7500 Perforation depth: Measured depth: 13318-13348 ",. ·.Þ\~~P~JI~\1 \it'C~In.": \.., ."1:,..,,,' True vertical depth: 11118-11148 TubinQ ( size, Qrade, and measured depth): 4-112" 12.6# 13Cr80 Packers & SSSV (type & measured depth): 7" Liner Top Packer 7" Baker S-3 Packer 4-1/2" Liner Top Packer 4-1/2" NSB-14 SSV @ 40 12767 ,<@. 11326 @ 12718 @ 12768 @ 2030 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: RBDMS 8Ft 0 CT 0 3 2006 13 Prior to well operation: Subsequent to operation: Oil-Bbl SI 518 Representative Dailv Averaae Production or Injection Data Gas-Met Water-Bbl Casing Pressure o 0 8,241 4 Tubing Pressure o 2425 14. Attachments: ~ 15. Well Class after proposed work: ExploratoryD 16. Well Status after proposed work: OilŒ] GasD Development[! ServiceD Copies of Logs and Surveys run _ Daily Report of Well Operations _ WAG 0 GINJD WINJD WDSPLD Prepared by DeWayne R. Schnorr (907) 564-5174 Sundry Number or N/A if C.O. Exempt: 305-041 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact DeWayne R. Schnorr Printed Name DeWayne R. Schnorr Signature Title Petroleum Engineer Phone 564-5174 Date 9/25/06 Form 10-404 Revised 4/2004 . . NS09 DESCRIPTION OF WORK COMPLETED NRWO OPERATIONS EVENT SUMMARY 08/09/2006 Set 41/2" BBE sssv # OCS-2 @ 1998' slm, performed closure test. ***Put well back on production. *** *** Job Complete*** 08/08/2006 Rig up to set sssv 08/05/2006 (Perforating) Add Perf - Re-perf 13318" to 13340' elmd using 2.875" HSD Power Jet 2906 HMX 6 spf. WHP pre-perf 0 psi, WHP post perf 400 psi. POP WELL *****Job Complete**** 08/04/2006 (Perforating) E-line crew arrive to Northstar Prep & spot equip on well Began rigging up to wellhead. ***In progress**** 08/02/2006 DRIFTED W/10' x 2.875" DUMMY PERF GUN, TAGGED BOTTOM @ 13330' SLM ***WELL LEFT S/I, NOTIFIED DSO*** 08/01/2006 ***WELL SII ON ARRIVAL*** (drift tubing) SPOT EQUIP, RU TO WELL 07/29/2006 ***CTU #5 Demobilize from North Star*** 07/28/2006 RIH w. Baker 3.7" 3 bladed mill, Dry tag cement top @ 13187' ctm start milling. Initially milled hard cement from from 13183' to 13187' ctm with 3 stalls. Milled to 13350' ctm, reciprocating 1 time up to 12550' ctm using 435 bbls of XS seawater and 25 bbls of 1.5 ppb Biozan. Opened circulation sub on BHA and chased out of hole making up-down-up wash passes on GLM and SSSV. Freeze protected well from 3000' with 50:50 MeOH. Final PT lost 7 psi over 10 minutes @ with 1000 psi overbalance on perfs. Trapped 500 psi on wellhead. RD CTU. Tagged well as freeze protected. *** Job complete *** 07/27/2006 Cement Squeeze. Fluid pack IA with diesel. Pumped 50 bbls of 12% HCI reciprocating from XN to 13334'. 40 psi breakdown seen when acid hit perfs. Pumped 20.5 bbls of 15.8 ppg Class G Latex slurry. Appeared to put 2 bbls behind pipe and then laid in 1: 1 with 1000 psi overbalance. Ramped pressure to 3400 psi at surface over 4- 10 minute intervals. Held final pressure (3500 psi overbalance at perfs) for 1 hour. Dropped ball and contmainated with Biozan at 2:1. Tagged hard cement at top perf. Unable to wash down into it. Laid in TEA on top then POOH washing well bore jewelry with 3 passes. At surface w. CT found no ball. Chase coil w. 1.25" ball 07/27/2006 Assist Coil Tubing with cement squeeze operations. Heating Seawater as needed. 07/26/2006 Finished BOPE test per MMS Regs, Kill well, RIH w. checks and 2.5" BON. Dry tag at 13346' CTM. Flagged CT 10' off bottom. Loaded IA with diesel using triplex pump. 07/26/2006 Assist CTU w/Cement Squeeze - Heat seawater & Load uprights as directed. 07/25/2006 CTU #5 MIRU, Spot equipment for job, BOPE Test for CAT II job per MMS Regs. Page 1 . . NS09 DESCRIPTION OF WORK COMPLETED NRWO OPERATIONS FLUIDS PUMPED BBLS 1 Diesel --- PT Surface Equipment 124 SO/50 Methanol Water 20 Diesel 20 Fresh water 1696 Seawater 467 Extra Slick Seawater 50 12% HCL (titrated value: 12.4%) 73 1.5# Biozan 20.5 15.8 ppg Class "G" Cement 2471.5 TOTAL Page 2 TREE = ABB-VGI5-1/8" 5K ~OTES: """4-1/2" CHROMETBG & LNR*.... WELLHEAD = ABB-VGI13-5/8" MUL TIBOWL 5KSI NS09 ACTUATOR = NOTE: MMS WELL KB. ELEV = 56.1' BF. ELEV = 40.2' (CB 15.9') r 1-14-1/2" SSSV w/HXO SLVN NIP, ID = 3.813" I KOP= . 2030' Max Angle = @ :~ ~ 1593' 1-113-3/8" STAGE COLLAR 1 Datum MD - Datum TVD- 10500' SS 113-3/8" CSG, 68#, L-80 BTC, ID = 12.415" I 3396' ~ .. GAS LIFT MANDR8.S I STI MD I TVD I DEV I TYPE I VLV I LATCHI PORT I DATE I L I 1 15150144681 I I DMY I BK I o 101/16/021 Minimum ID = 3.725" @ 12754' 4-1/2" XN NIPPLE I TOP OF 7" LNR 1 11326' 2S 18~ 19-5/8" CSG, 47#, L-80 BTM-C, ID = 8.681" I 11519' 1-----4 12676' -14-1/2" FIBER OPTIC TRANSDUCER, ID - 3.958" I 112690' ELM 1-14-1/2" FIBEROPTICTRANSDUCER.ID= 3.958" I I I 12697' -14-1/2" x NIP, ID = 3.813" 1 [8 .- 12718' -l7" x 4-1/2" BKR S-3 PKR. ID = ???? I RS I I 12742' H4-1/2" x NIP, ID = 3.813" I I . I 12754' -14-1/2" XN NIP, ID = 3.725" 1 ITOPOF 4-1/2" LNR I 12768' I 115< Ä 14-112" TBG, 12.6#, 13CR VAM-ACE. 12765' r 12765' H4-1I2" WLEG, ID - 3.958" I .0152 bpf, ID = 3.958" I H ELMD TT NOT LOGGED? I 17" LNR, 26#, L-80 BTC-M, 12904' ... .0383 bpf, ID = 6.276" PERFORA TION SUMMARY REF LOG: LWD? VISION RESISTIVITY ON 12/30/01 (TIE-IN LOG: GRlCCUUSIT) ANGLEATTOPÆRF: 60 @ 13318' INITIAL PERF - CHARGE 2906 POWERJET, HMX, PENETRATION: 27", HOLE 0.36", PHASE 60 DEG. Note: Refer to Production DB for historical perf data SIZE SPF INTERVAL (MD) Opn/Sqz DATE 2-7/8" 6 13193 - 13333 S 01/15/02 2-7/8" 6 13318 - 13348 0 08/05/06 PBTD I 13383' .4~ 4-1/2" LNR, 12.6#, 13CRVAM·ACE. 13429' .0152 bpf, ID = 3.958" DATE REV BY COMMENTS DATE REV BY COMMENTS NORTHSTAR 01109/02 INITIAL COMPLETION 07/27/06 GLMlPAG CEMENT saz PERFS WELL: NS09 01/17/02 EMF ADPERF 08/08/06 WRRlPJC PERFORATIONS PERMIT No: '2012190 12/20/02 EMF KB INFO UPDA TED API No: 50-029-23052-00 10/06/05 ITLH NEW FORMA T & TV D CORREC SEC T N R E 11/08/05 /TLH GL V CORRECTIONS 02115/06 RAClPAG SAFETY NOTE - MMS WELL BP Exploration (Alaska) FW: NS09 (2-28-05) Squeeze 305-041.pdf e ~o j ... 2' ~ e Subject: FW: NS09 (2-28-05) Squeeze 305-041.pdf From: "Younger, Robert 0" <Robert.Younger@bp.com> Date: Fri, 14 Jul 2006 11: 17:54 -0800 To: winton_aubert@admin.state.ak.us CC: "Garing, JohnD" <John.Garing@bp.com> Winton, Per our conversation, we are planning to perform a coil tubing squeeze on NS09. However, the procedure outlined in the February 2005 approved sundry has changed from a sand back squeeze to a squeeze of thé entire perforated interval followed by Ad-Re Perforations. Please let me know if any additional information is required, Thanks! Bob Major Steps of Updated Procedure · RU Coil Tubing · Squeeze Existing Perforations · E-Line Ad-Re Perforate 13318'-13340' MD · Return Well to Production OriQinal Sundry Information «NS09 (2-28-05) Squeeze 305-04"1 ,ZIP» '.·.··IÎ'.IL. M~,W,r.·. nU¡ "j (, j)OI\,"')' \:)\.I3-a~'t:~'V~L; J ì L .. ~} ~.. "VI,; BP Exploration, Alaska Northstar/Badami Production Engineer 907-564-5392. (Work) 907-677-2599 (Home) 907-830-4920 (Cell) younger2@bp.com Content-Description" NS09 (2-28-05) Squeeze " 305-041.ZIP NS09 (2-28-05) Squeeze 305-041.ZI~ Content-Type: application/x-zip-compressed Content-Encoding: base64 -------- ..-- 1 of 1 7/14/20061:25 PM . . MICROFILMED 07/25/06 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE F:\LaserFíche\CvrPgs _ Inserts\Microfilm_ Marker. doc , irfù..' ? i¡l~~, .\. V.!' f.'.f? \~ I: I ! / . \ ¡ r lLÇ:. L. (Q).,.. f h 'l \ i'i ¡ fU ¡ û ¡. I I ¡, I ¡ WI'" W ) ¡ in: 1 f?' .IM ¡n¡ ~./~,ll \.'\~ @.(1J¡rw [Æi;A I I I I "~ l.1d' r n I \, i \\\\ LJ lj¿; U lft\ l1 LrL cQ) U~! , ) .~ol- ;Äf9 A.I~A.SKA. OIL AND GAS CONSERVATION COMMISSION / / / ! FRANK H. MURKOWSK/, GOVERNOR 333 W. 7TH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Michael Francis Petroleum Engineer BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, Alaska 99519-6612 Re: Northstar NS09 Sundry Number: 305-041 Dear Mr. Francis: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. Please provide at least twenty-four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's petroleum field inspector at (907) 659-3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd d following the date of this letter, or the next working day if the 23rd day falls on a oli y or weekend. A person may not appeal a Commission decision to Superior ouct. less rehearing has been requested. é DATED this 1'1 day of February, 2005 Encl. SGAi'H"EJ~ MAH 0 2 2005 bp ) ') ... ,\.,f.'", ~~~ ~~. ~..- -..-. ....,..~ ~,.... .'i'~i\. .,. BP Exploration (Alaska) Inc. 900 East Benson Boulevard P. O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 February 16, 2005 , C' fEB 1 'ð 2-GÜ) Winton Aubert Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, AK 99501 Dear Winton: Re: Sundry Notice for NS09 to do a Gas Shut-off Squeeze (Ivishak) BP Exploration Alaska, Inc. proposes to perform a gas shut-off squeeze in the NS09 well. This well has experienced a steady increase in GaR. At its current GaR of 13,000 SCF/STB, this well is shut-in much of the time due to facility gas handling limitations. Production logging indicates a majority of the gas production is coming from the upper two-thirds of the perforations. The proposed procedure would isolate these perforations to reduce the GaR in this well so it can become a full-time producer again. /' The procedure includes the following major steps: . RU Coiled Tubing . Isolate the lower one third of the perforations with a sand plug . Squeeze the upper two thirds of the perforations using gel and cement . Clean out the well bore using coiled tubing /' . Return the well to production Sincerely, ~~ d :::£- L/Y1Á~ Mic1ael J. ~~s,P.É.-v # Senior Petroleum Engineer BPXA, ACT, Northstar r'\R"i('''¡l\lA\ L I I:"" t ~i í ~\ . L.I t \. \"..' J ~ luGA z... , ¿L{ 2.00 S ) STATE OF ALASKA ) .(j) S ¿, ¿0/~ ALASKA OIL AND GAS CONSERVATION COMMISSION :,'~ '::.: .,.' f:"" \',.1,1\ I','.'.. APPLICATION FOR SUNDRY APPROVA~~fP'~ 8 20 AAC 25.280 ~ ....J ..I. t; ',. ~:~" ':\ ~; '.' 1::'\' '. 'I Abandon D Suspend D Operation Shutdown D PerforateD W¥v~rD'A' Alter Casing D Repair Well D Plug Perforations Œ] StimulateD Time ExterisionD Change Approved Program D Pull Tubing D Perforate New Pool D Re-enter Suspended Well 0 4. Current Well Class: /" 5. Permit to Drill Nymber: BP Exploration (Alaska), Inc. 201-2190 /' Development Œ] Exploratory D ~64- Exploratory D Developmentæf Servicef&r 15. Well Statu~r proposed work: Oil ~ Gas n. Plugged 0 Abandoned 0 W6A- WAG 0 GINJD 1. Type of Request: 2. Operator Name: 3. Address: P.O. Box 196612 Anchorage, Ak 99519-6612 Stratigraphic D Service D 9. Well Name and Nu/mber: NS09 10. Field/Pool(s): Northstar Field / Northstar Oil Pool PRESENT WELL CONDITION SUMMARY Effective Depth MD (ft): Effective Depth TVD (ft): 13383 11132.7 MD TVD 7. KB Elevation (ft): 56.10 DF 8. Property Designation: ADL-312799 11. Presen1 Total Depth MD (ft): 13429 Casing Total Depth TVD (ft): 11234.7 Length Size LINER LINER PRODUCTION SURFACE Perforation Depth MD (ft): 13193 - 13333 Packers and SSSV Type: 4-1/2" Top Packer Baker S-3 Packer 4-1/2" NSB-14 SSV 7" Top Packer 12. Attachments: 1578 661 11477 3354 top 7" 26# L-80 11326 4-1/2" 12.6# 13Cr80 12768 9-5/8" 47# L-80 42 13-3/8" 68# L-80 44 Perforation Depth TVD (ft): 11 000 - 11139.1 bottom top 12904 13429 11519 3398 Tubing Size: 4-1/2 " 12.6 # Packers and SSSV MD (ft): 9258.9 10584.6 42.0 44.0 Description Summary of Proposal ŒI Detailed Operations ProQram D BOP Sketch D 14. Estimated Date for Commencing Operation: 13. Well Class after proposed work: April 1 2005 16. Verbal Approval: Commission Representative: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Date: Contact Printed Name Signature Michael Francis 'rI1t Aâ ,J ~ .J. ~ "" J"1} I;;>, Ë , Commission Use Only Conditions of approval: Notify Commission so that a representative may witness Title Phone Petroleum Engineer 564-4240 2/8/05 BOP TestD Mechanciallntegrity Test D Location Clearance D BY ORDER OF ,/" f. £O( THE COMMISSION Date: ~ry t RBDMS 8FL. MAR 0 1 2005 RBDMS 8Ft MAR 0 N t2òþJ) I (~ f\' Ij ,. ~ f\ f "-.,1 , ~ \j /- t l~~. , , i 0- 4 0 ~ . '-- Form 10-403 Revised 11/2004 Other D 6. API Number /"~ 50-029-23052-00-00 Plugs (md): Junk (md): None None Burst Collapse bottom 10716.8 11234.7 9427.9 3216.4 Tubing Grade: 13Cr80 6870 4930 7240 8430 Tubing MD (ft): 40 4760 2270 5410 7500 12767 12768 12718 2030 11326 WI~ WDSPLD Prepared by Garry Catron 564-4657. Michael Francis Sundry Number: ~S-- Ô 'fj SUBMIT IN DUPLICATE .. .' TREE: ABB-VGI 5 1/8" 5ksi "WELLHEAD: ABB-VGI 13-5/8" Multibowl 5ksi ) NS09 ~)KB. ELEV = 56.1' KB-BF. ELEV = 40.2' BASE FLANGE ELEV = 15.9' " SSSV @ 2030' MD wi HXO SVLN nipple - 3.813" ID (2028' TVD) 6.8PPG DIESEL FREEZE PROTECTION AT +1- 3913' TVD (4364'MD) 4.5" GLM @ 5150' MD (4468' TVD) wi 3.833" ID ... 13 3/8" Stage Collar at 1593'MD 13 3/8", 68#/ft, L-80, BTC @ 3396' MD ~ 4.5", 12.6#/ft, 13-Cr, Vam Ace TUBING ID: 3.958" CAPACITY: 0.01522 BBLlFT 9-5/8" 47# L-80 BTM-C @ 11519' ~ Jj- ~ - 7" LINER TOP @ 11326' , ~- L 4.5" Fiber Optic Transducer v 3.958" ID @ 12676' MD, t 10496' TVD (Sensor ELM TVD = 10507') - 7" Baker S-3 PACKER,13 Cr @ 12718' MD (10536' TVD) IE 4.5" LINER TOP @ 12768' (10585' TVD) 4.5" X NIPPLE, @ 12697' MD, (10516 'TVD) 3.813" ID 4.5" X NIPPLE, @ 12742'MD (10559' TVD) 3.813" ID 4.5" XN NIPPLE, @12754'MD (10571' TVD) 3.725" ID 4.5" WLEG, @ 12765MD' (10582' TVD) 3.958" ID - J 7", 26#/ft L-80, BTC-M @ 12904' iI .. FHfCR.\"OCN8..MJ!Rr' R:FLæ LV'D\AsicnR5islMly(12'3:r.ID1) [reinl.q;JŒCO..tl8l] Þl'G..EA~ N:ie Rt8"toRo::t..dk:n [Bfa tistaiŒI ¡:at d:ta rma Fàf - ~ JmR>NerJí, I-M< RrBrákn 'll'; !-tie .:Ð~ Fhæ EDdg S2E s:F NlER/ÞlM) NlER/Þl1VO C):n'3:¡z D\lE 2ffi 6 13193-13ID 11axJ-111:IJ Cþl V152X2 PBTD @ 13383' MD (11188' TVD) TD @ 13429' j l 4.5", 12.6#, 13CrVam Ace DATE 11/5/01 01/09/02 01/17/02 12/20/02 REV. BY BMH MJF EMF EMF COMMENTS ""NS09 Proposed Post Completion - pre perf Add Perf Updated KB Information Northstar WFI I :NS09 API NO: 50-029-2305~-OO BP Explorati6Y1' (Alaska) bp ~.",..",."~~f_~."..,,,. '~,," " .,"~.~.,,',","" '!f~\~ ) ') -¿Date: 0 I ~ 11-2005 Transmittal Number: t#91588NS21 ~61 ,,~lq BPXA WELL DATA TRANSMITTAL N S /oq Enclosed are the materials listed below. If you have any questions, please contact me in the Petrotechnical Data Center at (907) 564-4091 or by e-mailingtojohnsojh@bp.com \C6 SW Name Date Contractor Top Log Run Depth Bottom Depth Log Type /~S21 04-17-2004 SCH 7 201 22261 VISION DENSITY NEUTRON; (MD) "yV/ NS21 04-17-2004 SCH 7 201 22261 VISION DENSITY NEUTRON; (TVD) NS21 04-17 -2004 SCH 7 201 22261 VISION RESISTIVITY; (MD) NS21 04-17 ~2004 SCH 7 201 22261 VISION RESISTIVITY; (TVD) NS21 1 '1-16-2002 SCH 200 22200 LDWG EDIT OF LWD GR,ARC,CDR / AND IN TIFF FORMATON CD ROM; NS08 ./ 12-06-2004 SCH 11150 11898 PERFORA TING RECORD; 'ìDï ,;,-'1 '"' - C 2J ¡ 12~'11-2004 NS09 SCH '12950 13340 PRODUCTiON PROFILE; ~ól··2,tq' \J , 'NS08 12-07 -2004 SCH 1 11650 11928 PRODUCTION PROFILE; 2-01. ~'\ NS08 t/ I 12-07-2004 SCH 1500 11400 LEAK DETECTION LOG; 01-\ , " "'''"'j/ /J O::fÁ ~.. )1L~h~. Please Sign ahd'Return one copy of this transmittal. Thank You, James H. Johnson Petrotechnical Data Center >!;,(lhl, \i~-.í J.: rL ::. Ii /'pí\:"; Attn: Esther Fueg MB3-6 Attn: Ken Lemley MB3-6 Attn: Howard Okland (AOGCC) Attn: Jason Smith (Murphy Exploration Alaska), Inc Attn: Kristin Dirks (DNR) Attn: Doug Choromanski (MMS) ;D,*-",ü.,i\.h\'~[\ APB 1 8 2.D D5 Q\;;1!'U~n&o·,'" PClrotcchnìcal Dnla Ccnlcr LR2-1 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 99519-()612 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Performed: Repair Well 0 PluQ PerforationsD Stimulate 00 OtherO Abandon 0 Alter CasingD Pull TubingO Perforate New Pool D WaiverD Time ExtensionO Change Approved Program D Operation Shutdown 0 Perforate D Re-enter Suspended Well 0 2. Operator BP Exploration (Alaska), Inc. 4. Current Well Class: 5. Permit to Drill Number: Name: Development Œ] ExploratoryD 201-21QO 3. Address: P.O. Box 196612 6. API Number Anchorage, Ak 99519-6612 StratigraphicD ServiceD 50-029-23052-00-00 7. KB Elevation (ft): 9. Well Name and Number: 56.10 NS09 8. Property Designation: 10. Field/Pool(s): ADL-312799 Northstar Field / Northstar Oil Pool 11. Present Well Condition Summary: Total Depth measured 13429 feet true vertical 11234.7 feet Plugs (measured) None Effective Depth measured 13383 feet Junk (measured) None true vertical 11188.8 feet Casing Length Size MD TVD Burst Collapse Liner 1578 7" 26# L-80 11326 - 12904 9258.9 - 10716.8 7240 5410 Liner 661 4-112" 12.6# 13Cr80 12768 - 13429 10584.6 - 11234.7 8430 7500 Production 11477 9-5/8" 47# L-80 42 - 11519 42.0 - 9427.9 6870 4760 Surface 3354 13-3/8" 68# L-80 44 - 3398 44.0 - 3216.4 4930 2270 Perforation depth: Measured depth: 13193 -13333 True vertical depth: 11000.24 -11139.06 RE CE \\lED Tubing ( size, grade, and measured depth): 4-1/2" 12.6# 13Cr80 @ 40 - 12767 ? ~ 1 7..\)\)4 . Storon\""on Packers & SSSV (type & measured depth): 4-112" Liner Top Packer @ 12768 . Gaa COn,- C 4-112" NSB-14 SSV @ 2030 ~\,,~a 0\\ &. ~"tMfa98 7" LIner Top Packer @ 11326 Baker S-3 Packer @ 12718 12. Stimulation or cement squeeze summary: Intervals treated (measured): 13193 -13333 Treatment descriptions including volumes used and final pressure: 33 Bbls 12% DAD Acid @ 3488 psig 13 Reoresentative Dailv Averaae Production or Iniection Data Oil-Bbl Gas-Me! Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 6665 56.7 27 95 1146 Subsequent to operation: 6095 54.5 28 64 1945 14. Attachments: 15. Well Class after proposed work: ExploratoryD DevelopmentŒl ServiceD Copies of Logs and Surveys run - 16. Well Status after proposed work: Daily Report of Well Operations. ! Oil[!] GasD WAGD GINJD WINJD WDSPLD Prepared by Garry Catron (907) 564-4657. 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. ISUndry Number or N/A if C.O. Exempt: Contact Garry Catron 304-266 Printed Name Garry Catron Title Production Technical Assistant Signature ):1/7 ~- ('~.Á I. - Phone 564-4657 Date 9/16/04 ORIGINAL RBDMS BF L SEP a 1 100~ Form 10-404 Revised 4/2004 NSO9 DESCRIPTION OF WORK COMPLETED NRWO OPERATIONS EVENT SUMMARY 08/27/04 ACID TREATMENT:. PICKLE TBG WITH 12 BBLS 12% DAD ACID. DISPLACE WI 113 BBLS SEAWATER AND 68 BBLS DIESEL (TBG VOLUME TO PERFS 200.8 BBLS PERFS). FLOW BACK PICKLE.. PUMP MAIN TREATMENT: 33 BBLS 12% DAD ACID (WI NALCO SI), 199 BBLS SEAWATER, SOAK FOR 30 MIN., 217 BBLS SEAWATER FOR DISPLACEMENT AND OVERFLUSH., AND 68 BBLS DIESEL FOR DISPLACEMENT & UNDERBALANCE.. RETURN TO OPERATIONS TO LEAVE SI FOR 4 HOURS PRIOR TO FLOW BACK.. «JOB IS COMPLETED» FLUIDS PUMPED BBLS 45 12% DAD Acid 529 Sea Water 136 Diesel 710 TOTAL Page 1 bp #~ .... ',. .' '. .,1' " '-. '.- Date: 06-15-200'" Transmittal Number: #9265'" BPXA WELL DATA TRANSMITTAL Please replace the previously issued materials with the data listed below. This data has been depth corrected to the primary depth control gamma ray acquired 10-31-2003. I'm sorry for any inconvenient. If you have any questions, please contact me in the Petrotechnical Data Center at (907) 564-4091 or by e-mailingtojohnsojh@bp.com Log SW Name Date Contractor Run '2GI -0-(1 NS29 i / 04-13-2001 SCH S v NS29 -' 04-13-2001 SCH 8 NS29 L. 04-13-2001 SCH 8 NS29 v 04-13-2001 SCH 8 NS29 t/ 06-05-2001 SCH NS29 J 06-05-2001 SCI-l NS29 L/' 06-05-2001 SCH V NS29 04-13-2001 SCH 1-/ J.. {: I ,.. /! i 9 NS09. 05-25-2004 SCH ~/) / - (.)~¿ NSI3. ::20;t -CJ¿ I NS08. ~ j.t.J 2 -0.51- NSI5 ./ Top Depth Bottom Depth Log Type 165 13469 CDR',I: T\'IEASURED DEPTH LOG; FINAL DATA; T\IEASURED DEPTH; 13469 CDR* MEASURED DEPTH LOG; FINAL DATA; TRUE VERTICAL DEPTH; 13469 ADN* T\IEASURED DEPTH LOG; FINAL DATA; T\IEASURED DEPTH; 13469 ¡-\DN* MEASURED DEPTH LOG; FINAL DATA; TRUE VERTICAL DEPTH; 13666 PLATFORT\1 EXPRESS NEUTRON POROSITY LOG; 13666 DIPOLE SHEAR SONIC IT\IAGER: 165 165 165 4800 4800 4745 13680 CASED HOLE ALFS EDIT FOR .:ß / 0/7 G COJ\IPENSATED NEUTRON AND DIPOLE SONIC DATA ON CD ROT\1 I E:\; ~1~:~~~i~~~r~~\;~~~Er¿:ILLltt/o /6 À DATA ON CD ROT\1 lEA; ßP ALASKA NORTHSTAR PVT STUDY; FLUID STUDY; HARDCOPY; 161 13527 .....-. ..--...-. f~ ~ lJ ~ ;( 0) "' 0 ~ I ---......--.....--..--- .. Pelrolechnical Data Center LR2-1 900 E, Benson Blvo. PO Box 196612 Alh:horagc. AK 99519-6612 bp ~~:~. ..... ',. .'j' "'l: .- - --.,- BPXA WELL DATA TRANStvnTT AL ILj) O¡¡~ Please Sign and Return one copy of this transmittal. Thank You, James H. Johnson Petrotechnical Data Center Attn: Esther Fueg MB3-6 Attn: Ken Lemley MB3-6 Attn: Howard Okland (AOGCC) Attn: Jason Smith (Murphy Exploration Alaska), Inc Attn: Kristin Dirks (DNR) Attn: Doug Choromanski (MMS) Petrolechnical Data Centcr LR2-1 1)00 E. Bcnson Blvd. PO Box I tJ6612 Anchorage. A K 99519-6612 Dalc: 06-15-200"¡' Transmittal Numbcr: #92654 (3 kfo ^ ß Q i" DATA SUBMITTAL COMPLIANCE REPORT 1/26/2004 Permit to Drill 2012190 Well Name/No. NORTHSTAR UNIT NS-09 Operator BP EXPLORATION (ALASKA) INC Jpc..t..-¿ Ll kÀ1H:J/ API No. 50-029-23052-00-00 MD 13429,/ TVD 11235 / Completion Date 1/13/2002 / Completion Status 1-01L Current Status 1-01L UIC N REQUIRED INFORMATION Mud Log No Samples No Directional Survey No DATA INFORMATION Types Electric or Other Logs Run: Well Log Information: (data taken from Logs Portion of Master Well Data Maint) ~- Log/ Electr Data Digital Dataset ,Type ßed/Frmt ~er Name ~ C 10550 Log Log Run Scale Media No 1-6 Interval OH 1 Start Stop CH Received Comments 200 13433 Open 2/13/2002 Well Cores/Samples Information: Name Interval Start Stop Sent Received Sample Set Number Comments Well Cored? ADDITIONAL INFORMATION Y/~ Daily History Received? [)N G)N Chips Received? = Y 1 N Formation Tops Analysis Received? ~ ~.- Comments: tv (1-- ;.,... ~ t3 ù IYL í" \J,' )(11- ~ (V\.b ¡,t.ù <'>- I ~ ...¿.)) ~ r+ \f~ ¡ ~,~ ~ 'f-V Ò Â~~ - I") 't S ~ G /-to. \J~~~,-- ~ ~'~ MÙ 2..\0... () "l;:1, r ~ 01+ v-,.¿,",,-- \)..........,: ~ rll)) I).. 'tlO - ¡).] þ\ 6 tL JJ-o ~ l~/ tr~ t c - 11 18 ).. ()L-J-~ ß'- ~~ y,1 "-- t ~ (.h- ¡ ~ ) ).. <t l \:¡ - J 3)2 )- Compliance Reviewed By: Date: '7 ?~ ~-Y--- ~L~ ~ r~ f~~ -\ ~\-U ~. ß k ù---Lj bp ~,. '\I~.' I. ~:~ ~~. ..~ ~... ;¿ 0 !:E,pß{ /1."al Ine .;Ø~4\" 900 East Benson Boulevard P. O. Box 196612 Anchorage. Alaska 99519-6612 (907) 561-5111 "I '°.. .. ''10, . July 7, 2004 Winton Aubert Alaska Oil & Gas Conservation Commission 333 West ih Avenue Suite 100 Anchorage, AK 99501 ~. .:- j ~' /004 Dear Winton: Re: Sundry Notice for NS09 to Acidize (Ivishak) BP Exploration Alaska, Inc. proposes to acidize the NS09 well. This well has exhibited a steady decline and analysis of formation water indicates the formation of CaC03 scale is likely. Last summer's acidizing campaign at Northstar was very successful. The procedure includes the following major steps: . Pickle the tubing Bullhead HCI based acid treatment (which includes scale inhibitor) Flowback . . Sincerely, 0'Ý~~a~ Michael J. Frß.t~ls, P.E. Senior Petroleum Engineer BPXA, ACT, Northstar nQ1G'f\1AL 'v~(¡1t 1/ 14/2c'.}C 4 . .D~ ( STATE OF ALASKA ) ~S .7- Jt--þl~ ALASKA Oil AND GAS CONSERVATION COMMISSION . Jr --- APPLICATION FOR SUNDRY APPROVAL 20 AAC 25.280 1. Type of Request: Abandon D Alter Casing D Change Approved Program D 2. Operator Name: BP Exploration (Alaska), Inc. 3. Address: P.O. Box 196612 Anchorage, Ak 99519-6612 7. KB Elevation (ft): 56.10 DF 8. Property Designation: ADL-312799 11. Total Depth MD (ft): 13429 Casing Total Depth TVD (ft): 11234.7 Length Suspend D Repair Well D Pull Tubing D Operation Shutdown D Plug Perforations D Perforate New Pool D 4. Current Well Class: PerforateD WalverD Annular DisposalD StimulateŒ] Time ExtensionD OtherD Re-enter Suspended WellD 5. Permit to Drill ~mber: 201-2190 I Development Œ] Exploratory D Stratigraphic D Service D 9. Well Name and Number: NS09 / 10. Field/Pool(s): Northstar Field / Northstar Oil Pool PRESENT WELL CONDITION SUMMARY Effective Depth MD (ft): Effective Depth TVD (ft): 13383 11132.7 MD TVD Size 6. API Number /" 50-029-23052-00-00 Plugs (md): Junk (md): None None Burst Collapse 7" 26# L-80 4-1/2" 12.6# 13Cr80 9-5/8" 47# L-80 13-3/8" 68# L-80 Perforation Depth TVD (It): 11000.2 11139.1 top bottom top bottom 11326 12904 9258.9 10716.8 7240 12768 13429 10584.6 11234.7 8430 42 11519 42.0 9427.9 6870 44 3398 44.0 3216.4 4930 Tubing Size: Tubing Grade: Tubing MD (It): 4.5 " 12.6 # 13Cr80 40 Packers and SSSV MD (ft): Liner 1578 Liner 661 Production 11477 Surface 3354 Perforation Depth MD (It): 13193 - 13333 Packers and SSSV Type: 4-112" HES HXO SSV 4-112" Liner Top Packer 7" Liner Top Packer Baker S-3 Packer 12. Attachments: Description Summary of Proposal Œ) Detailed Operations Program D 5410 7500 4760 2270 12767 2030 12768 11326 12718 BOP Sketch D 13. Well Class after proposed work: ExploratoryD DevelopmentŒ) ServiceD 14. Estimated Date for Commencing Operation: 16. Verbal Approval: Commission Representative: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 15. Well Status after proposed work: Oil ŒJ GasD WAG D GINJD August 1 . 2004 Printed Name Signature Date: Contact Michael Francis Title ~,;h~.-e /J :!f'--,J.) ;. £. Phone (j Commission Use Only Petroleum Engineer 564-4240 7/8/04 Conditions of approval: Notify Commission so that a representative may witness Form 10-403 Revised 06/2004 BOP TestD Mechanciallntegrity Test D Location Clearance D .- 4c.4- Plugged D Abandoned D WINJD WDSPLD Prepared by Garry Calron 564-4657. Michael Francis Sundry Number: 30J/ -¿;J-" t. Date: ~A / / (i ~ . .;\\Y\~I¡ jU'¡ P 4'ul . lLkl' - "- BY ORDER OF THE COMMISSION ORIGINAL --~~~ SUBMIT IN DUPLICATE , STATE OF ALASKA J"" ALA5r\.A OIL AND GAS CONSERVATION CO I"II~SION REPORT OF SUNDRY WELL OPERATIONS 1. ODerations Performed: Abandon 0 Alter CasingD Change Approved Program 0 Suspend D Repair WeliD Pull TubingD Operation ShutdownD Plug PerforationsD Perforate New Pool D PerforateD varianceD Stimulate~ Time ExtensionD Re-enter Suspended WeliD Annular DisposalD OtherD 2. Operator BP Exploration (Alaska), Inc. Name: 4. Current Well Class: Development 00 ExploratoryD 5. Permit to Drill Number: 201-2190 3. Address: P, O. Box 196612 Anchorage, Ak 99519-6612 StratigraphicD ServiceD 9. Well Name and Number: NS-09 10. Field/Pool(s): Northstar 6. API Number 50-029-23052-00-00 7. KB Elevation (ft): 56.1 8. Property Designation: ADL-2799 11. Present Well Condition Summary: Total Depth Effective Depth Casing Structural Conductor Surface Intermediate Production Liner Perforation depth: / Northstar measured 13429 feet true vertical 11235 feet Plugs (measured) measured 13383 feet true vertical 11077 feet Junk (measured) Length Size TVD Burst Collapse MD 3354.1 13-3/8" 68# L-80 44 - 3398 44 - 3216.4 4930 2270 11476.75 9-5/8" 47# L-80 42 - 11519 42 - 9427.9 6870 4760 661.37 4-1/2" 12.6# 13Cr80 12768 - 13429 10584.6 - 11234.7 8430 7500 1578.07 7" 26# L-80 11326 - 12904 9258.9 - 10716.8 7240 5410 Measured depth: 13193' - 13213', 13213' -13243',13243' -13273',13273' -13303',13303' -13333' True vertical depth: 11000.24' -11020.02' , 11020.02' -11049.72' , 11049.72' -11079.46' , 11079.46' -11109.241 11109.24' -11139.06' Tubing: (size, grade, and measured depth) 4-1/2" 12.6# 13Cr80 @ 40.081 - 12766.631 MD Packers & SSSV (type & measured depth) Baker S-3 Packer @ 12718.341 MD /7" Liner Top Packer @.j ~"32,6.1,>Mg :.íi' 7";" 4-1/2" Liner Top Packer @ 127681 MD /4-1/2" HES HXO SS\l¡@.203d'~38'r.M[).." 12. Stimulation or cement squeeze summary: Intervals treated (measured): (See Attachment) Treatmentdescriptions including volumes used and final pressure: 13 Representative Daily Averaqe Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure 8,463 33,1 06 53 9,466 36,000 107 ,,~ " i'-, Prior to well operation: Subsequent to operation: 14. Attachments: Tubing Pressure 863 878 15. Well Class after proposed work: ExploratoryD DevelopmentŒ] Service D 16. Well Status after proposed work: Operational Shutdown D Oiloo GasD WAG 0 GINJD WINJD WDSPLD Prepared by Garry Catron (907) 564-4657. Sundry Number or N/A if C.O. Exempt: Copies of Logs and Surveys run - Daily Report of Well Operations - X 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Michael J. Francis, P.E. Printed Name Michael J. Francis Signature 303-241 Title Senior Petroleum Engineer Phone 564-4240 Date 9/26/03 OR' r,1 ~'^' R6DtA~ br '6 sf! 2,9 ~- Form 1 0-404 Revised 4/2003 ( ( NS-O9 DESCRIPTION OF WORK COMPLETED NRWO OPERATIONS EVENT SUMMARY 08/22/03 Acid treatment, well flowing at 830 psi prior to treatment. Pump Pickle per procedure, 1 bbls meth, 12 bbls 12% DAD Acid, 113 bbls SW, 68 bbls Diesel, flowback pickle to production. 08/23/03 Continue with main DAD Acid treatment per procedure, 33 bbls 12% DAD Acid, 199 bbls SW, shut down for 30 minute soak, 217 bbls SW, 68 bbls Diesel, leave well shut in for 4 hours, turn over to production FLUIDS PUMPED BBLS 1 Methanal 45 12% DAD acid 332 Sea Water 136 Diesel 514 TOTAL Page 1 bp (' ~l -~{Ct .,. .\It.,,,,, ........ ~ ~..-'- ~.- --:..~-- *.~ ~~.. . I'~~I\. ". ~ BP Exploration (Alaska) Inc. 900 East Benson Boulevard P. O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 August 7, 2003 Winton Aubert Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, AK 99501 Dear Winton: Re: Sundry Notice for NS09 to Acidize (Ivishak) BP Exploration Alaska, Inc. proposes to acidize the NS09 well. This well has exhibited a high rate of decline and analysis of formation water indicates the formation of CaCO3 scale is likely. Additionally, CaCO3 scale was recovered from the offset NS 13 wellbore using slickline. The procedure includes the following major steps: . Pickle the tubing . Bullhead HCI based acid treatment (which includes scale inhibitor) . Flowback Sincerely, ~d}~ ¿j '-~ Michael J. FranM's, P.E. Senior Petroleum Engineer BPXA, ACT, Northstar AUG 1 £ 2003 :' ..:: .. OR'GtNAL (' STATE OF ALASKA (' ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVAL 20 AAC 25.280 w¡.JqÆ ~ I L e{2..00I ¿pf~{~ Qj 1. Type of Request: D Suspend D Operation Shutdown D Perforate D VarianceD Annuar Disposal D Abandon Alter Casinq D Repair Well 0 Pluq Perforations D Stimulate IX! Time Extension 0 OtherD Chanqe Approved Proqram 0 Pull Tubinq 0 Perforate New Pool D Re-enter Suspended Well 0 2. Operator 4. Current Well Class: 5. Permit to Drill Number: Name: BP Exploration (Alaska), Inc. Development [XI Exploratory D 201-2190 // 3. Address: P.O. Box 196612 6. API Number /' Anchorage, Ak 99519-6612 Stratigraphic D Service D 50-029-23052-00-00 7. KB Elevation (ft): 9. Well Name and Number: AKB 56.10 NS09 /' 8. Property Designation: 10. Field/Pool(s): ADL-312799 Northstar 1 Northstar 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 13429 11234.71 13383 11076.64 Casing Length Size MD TVD Burst Collapse top bottom top bottom Conductor Surface 3354 13-3/8" 68# L-80 44 - 3398 44 - 3216.4 5020 2270 Intermediate 11477 9-5/8" 47# L-80 42 - 11519 42 - 9427.9 6870 4760 Liner 1578 7" 26# L-80 11326 - 12904 9258.9 - 10716.8 7240 5410 Production Liner 661 4-1/2" 12.6# 13Cr80 12768 - 13429 10584.6 - 11234.7 8430 7500 Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 13193' -13333' 11000.2' -11139.1' 4-112" 12.6# 13Cr80 40 - 12765 Packers and SSSV Type: Packers and SSSV MD (ft): 7" Baker Liner Top Packer 17" Baker S-3 Packer 11326/12718/12768/2030 4-1/2" Baker Liner Top Packer 1 BBE SSV w/13 chrome 12. Attachments: Description Summary of Proposal [XI 13. Well Class after proposed work: Detailed Operations Program D BOP Sketyh D Exploratory D Development 00 Service D 14. Estimated Date for 8/20/2003 / 15. Well Status after proposed work: Commencinq Operation: Oil[!g GasD PI ugged D Abandoned D 16. Verbal Approval: Date: WAGD GINJD WINJD WDSPLD Commission Representative: Perpared by S. Copeland 564-4424 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Mike Francis Printed Name Michael Francis Title Production Engineer Signature Phone 564-4240 Date 8/14/03 Commission Use Only Sundry Number: Conditions of approval: Notify Commission so that a representative may witness 3b3.. 2i.f( Plug Integrity D BOP TestD Mechanciallntegrity TestD Location clearanceD Other: RBDMS BFl AUG 1 5) 2003 AU6 1 B 2003 io ..- l./- 0 4- :'" Subsequent Form Required: k~ ~"'".<""::" ..,. " ., J'",.. " ,~. .,::' " '"' BY ORDER OF Approved by: ~~) ~ . COMMISIONER THE COMMISSION Date: 6// t¥D3 ~ ~ A.. Form 10-403 Revised 2/2003 OR\G\N SUBMIT IN DUPLICATE bp _~A ~.. ...,--\,.,~". ~~~ ~~.. ~.:. ~'-.. ""'8"'" '- ~..... ~ ßlII,.~\\.. ". ~. ~ To: Gary McBride/John Smart - Well Operations Supervisor August 8, 2003 From: Mike Francis and Patty Hill - Northstar Subject: NS09 DAD Acid/51 Treatments AFE NSZ832018 Est. Cost: $60 M lOR: Est 500 BOPD Please perform an acid stimulation/SIT with 12% DAD acid on the NS09: Type lOR PR N DSWL AFE Job Description Priority Comments/Other 0 500 NSO9 NSZ832018 Pump Acid and SIT NS09 has suffered significant decline since start-up. The water chemistry indicates CaCO3 scale formation is likely and the presence of scale has been confirmed in the offset NS13 well. This treatment will dissolve the scale and place scale inhibitor in the formation. The treatments are being combined to simplify logistics. Procedure 1. Mobilize pumps, tanks and acid transport to Northstar. 2. Order out volume of seawater and diesel to flush both the pickle and the acid job. See attached Volumes table. 3. AU pumping equipment. 4. Hold PJSM. Possible hazards on this job include bringing partially spent acid back to surface when the pickle is produced back. 5. Preheat seawater and diesel to 80°F. The heating of these displacement fluids will eliminate the need to hold backside pressure on the wells during treatment. 6. PT Dowell surface lines to 5000 psi 7. Pump the following fluids to pickle the production tubing at 3 bpm, 3500 psi max pressure. a) 12 Bbls 120/0 DAD acid b) 113 Bbls seawater c) 68 Bbls diesel 8. Produce pickle back to test separator and well clean up tank. The pickle volume to flowback is 193 Bbls. il¡ '\ '!, 9. Pump the following treatment at maximum rate or 3500 psi max pressure. a) 33 bbls 12% DAD Acid b) 199 bbls Seawater (To displace acid to peris) c) Shut down for 30 minutes and allow acid to soak d) 217 bbls Seawater (for over flush and displacement) e) 68 bbls Diesel (for displacement and under-balance) 10. Shut well in for 4 hours to allow scale inhibitor to precipitate. 11 . AD Schlumberger. 12. Flow back Procedure: For flow back, line up into the test separator and well cleanup tank. Produce clean-up volume of 517 bbls. After clean-up, divert back to the plant and get 2 6-hour tests. 13. Two days after well is cleaned up and stabilized, periorm a closure test on the SSSV. Fluid descriptions: 12% DAD Acid to contain: 10% Nalco Scale Inhibitor + 0.6% A261 + 4 ppt A 179 + 8 ppt A 153 + 0.2% F1 03 + 20 ppt L58 + 1.5% U74 + 10% Xylene Note: Acid strength to be verified and documented via titration before leaving Schlumberger. Results will be available on location. Procedure Contacts: Mike Francis WK: 564-4240 H M: 644-0534 Cell: 529-8678 Patty Hill WK: 564-4346 HM: 248-6262 Cell: 350-0742 4.5" Fiber Optic Transducer 3.958" ID @ 12676' MD, 10496' TVD (Sensor ELM TVD = 10507') - 7" Baker S-3 PACKER, 13 Cr @ 12718' MD (10536' TVD) .. TREE: ABB-VGI 5 1/8" 5ksi :(' WELLHEAD: ABB-VGI13-5/8" Multibowl 5ksi NSO9 13 3/8" Stage Collar at 1593'MD 13 3/8", 68#/ft, L-80, BTC @ 3396' MD 4.5", 12.6#/ft, 13-Cr, Vam Ace TUBING ID: 3.958" CAPACITY: 0.01522 BBL/FT 9-5/8" 47# L-80 BTM-C @ 11519' 4.5" X NIPPLE, @ 12697' MD, (10516 'TVD) 3.813" 10 4.5" X NIPPLE, @ 12742'MD (10559' TVD) 3.813" ID 4.5" XN NIPPLE, @12754'MD (10571' TVD) 3.725" 10 4.5" WLEG, @ 12765MD' (10582' TVD) 3.958" ID 7", 26#/ft L-80, BTC-M @ 12904' FEm:R\ lO.J 3.MvM" ÆF Læ LVD \Ækn RSsIMty (~) [T ¡e.¡, lqJCHalA..8l] ÞNlEA 1lCPFI:R? N:te Ate- to Raidicn CBfa HstaiŒI JEf Œta Htia Fèf - ~ :æœ FòNer J:í, f-M< Fè"àrétk:n 21'; HE .æ~ Fh:œ 6)d:g SZE s:F Nm./ It. M) Nm./lt.lVD Q1i~ IJ\lE 200 6 131ffi-13m 11axJ-1113:J qn 1/152))2 PBTD @ 13383' MD (11188' TVD) TD @ 13429' DATE 11/5/01 01/09/02 01/17/02 12/20/02 REV. BY BMH MJF EMF EMF .KB. ELEV = 56.1' KB-BF. ELEV = 40.2' BASE FLANGE ELEV = 15.9' SSSV @ 2030' MD wi HXO SVLN nipple - 3.813" ID (2028' TVD) 6.8PPG DIESEL FREEZE PROTECTION AT +/- 3913' TVD (4364'MD) 4.5" GLM @ 5150' MD (4468' TVD) w/3.833" 10 - 7" LINER TOP @ 11326' 4.5" LINER TOP @ 12768' (10585' TVD) 4.5", 12.6#, 13Cr Vam Ace Northstar WELL: NSO9 BP Exploration (Alaska) bp {' ~ July 29, 2002 It ,\t~~ . ..'~.... ,..~~. ~- ~~ *.~ ~~.. . ~,~\~ BP Exploration (Alaska) Inc. 900 East Benson Boulevard P. O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 Tom Maunder Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, AK 99501 Dear Tom: Re: Sundry Notice for NS09 to Add Perfs (Ivishak) BP Exploration Alaska, Inc. proposes to add perforations to increase production to,.. Northstar to meet plant compacity. The expected net oil benefit is 4,000 BOPD. / lOR The procedure includes the following major steps: T e Slickline 4,000 Electric Line Slickline Last Test: Max. Deviation: Perfs: Min.ID: Last TD tag: Last Downhole Ops: Latest H2S value: Reference Log: BHT & BHP: Work Desci tion Pull SSSV, Drift/ta wi dumm un // Perforate 30' of Ivishak 13,1631 - 13,1931 MDrkb, 10,971' - 11,000' TVDrkb Run SSSV July 25, 2002 - BOPD 16264, Gas 35766, FTP 805 psi. 42 deg @ 10,452' MD Max Dog Leg: 6.9 deg/100' @ 50' MD 13,1631 - 13,1931 MDrkb, 10,971' - 11,000' TVDrkb 3.725" at XN nipple @ 12754', see schematic 13382' MD ELM. 01/12/02 cia SSSV 05/17/02 0 PPM, none expected. Schlumberger LWD-Vision Resistivity 12/30/2001 2540 F & 5175 psia @ 13,330' MD .// Please call (Alex Yancey 564-5092, hm: 522-2539, cell: 301-3019) if there are any questions. ~j'ij 1'1"" ,f"" ~,"n' ~ ~ ~' >I"" 1,""1, " II ~ L ,! ,\ "'~ ,I" ;'I\~1J" 'j"" I (¡"", :'1 ~1 <I li--',v. ,~ 'I' ,) '~, 1, "" ,¡ 'I' ";!' :J ~ ' ,. ¡:. II.,..", "". I:."" '"I Ij !'::"'" t,) ~ Î 11 ,-") (' q fH' .1-> ¡,h i<"~/Jr!!\¡l o..,,-,".~ '-'" "'-"""'" (""'\ ',"'- \,' ~ """""', i1 ", j '~' l ' i ~) II i¡ I \, : , ), ~'< ,J ii,"'" II 11\ ¡ .:ï" ,,' . ,~ ,I \1, !J I) !J \\r l , '"II~~-'.,,)tl~'$\ìl,.. Alaska ŒJ &1 Gas Cons. C ~)n~¡,¡~hSítH Arl('~\""lra';' "',',:, , ,in", \.oIl:, (' (" B k dD ac ~groun ala: Well: NS-09 API: 50-029-23052-00 Tree: ABB-VGI13-5/8" x 4-1/2" 50 ksi Tubing: 4.5", 12.6 ppf, 13Cr-80, ACE Tubing Tail: NA - monobore SSSV Nipple: HXO SVLN @ 2000' MD, 3.813" ID (angle at SVLN = 6.3 deg) GLM: 4-1/2" x 1-1/2" GLM w/ sheared valve at 5,150' MDrkb Packer: Baker S-3 @ 12,718' MD, 3.875" ID Min ID: 4.5" XN Nipple @ 12,754' MD, 3.725" ID Surf Casing: 13-3/8" L-80 @ 3,396' MD (68#/ft. Intermed. CSQ: 9-5/8" L-80 @ 11,517' MD (47#/ft. Drilling Liner 7" L-80 @ 11,326' - 12,904' MD (26#) Prod Liner: 4.5" 13-Cr-80 12,768-13,429' MD, liner top ZXP packer, Flex Lock liner hanger (12.31 #/ft) PBTD: 13,425' MD // Max Deviation: 45.92 deg @ 6169' MD Max Dog Leg: 4.2 deg/100' @ 2,840' MD Tubing Fluid: Diesel to 4364' MD, Seawater below /' IA Fluid: Diesel to 1 4364ft MD, seawater below OA Fluid: Diesel to 11900 ft MD, mud below Proposed 13,1631 - 13,1931 MDrkb, 10,971' - 11,000' TVDrkb, LWD-Vision Resistivity Perforations: 12/30/2001, GR/CCL 1/12/2002 Reservoir Est. 5175 psi @ 11,100' TVD SS. EMW = 9.0 ppg / Pressure: WH Pressure: Last recorded, 720 psi, Max if all NS Formation gas - 4000 psi H2S ppm: none expected Current Status: Producing. Sincerely, Alex Yancey Alaska Consolidated Team Petroleum Engineer l', ,i"."',\. 1,,' ï' I ¡i !i Ii i !J ~ t.". ( ( tJj Git 7/"1.-0/ D 1- ~1!~/~ 075 ð/I/ÓC " STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of request: Abandon- Suspend- Alter casing - Repair well - Change approved program 2. Name of Operator BP Exploration (Alaska), Inc. 3. Address P. O. Box 196612 Anchora e, AK 99519-6612 4. Location of well at surface 1129' FSL, 643' FEL, Sec. 11, T13N, R13E, UM At top of productive interval 416' FNL, 271' FWL, Sec 18, T13N, R14E, UM At effective depth 416' FNL, 4882' FWL, Sec. 18, T13N, R14E, UM At total depth 417' FNL, 313' FWL, Sec. 18, T13N, R14E, UM 12. Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical Casing Length Conductor 202' Surface 3354' Intermediate 11477' Liner 1578' 661' Perforation depth: Operational shutdown - Plugging - Pull tubing 5. Type of Well: Development _X Exploratory - Stratigraphic - Service (asp's 659833, 6030902) (asp's 666059, 6029493) (asp's 666098, 6029493) (asp's 666102,6029493) 13429 feet 11235 feet 13383 feet 11189 feet Plugs (measured) Junk (measured) Re-enter suspended well - Time extension - Stimulate - Variance Perforate X 6. Datum elevation (DF or KB feet) RDF 55.52 feet 7. Unit or Property name Other measured 131931 - 13333' NORTHSTAR UNIT 8. Well number NS09 ,/ 9. Permit number / approval number 201-219 / 10. API number 50-029-23052-00 11. Field / Pool NORTHST AR POOL Size Cemented Measured Depth True vertical Depth 2011 Driven 202' 202' 13-3/811 710 sx PF 'L', 557 sx 3396' 3159' Class 'G' 601 sx Econolite, 691 sx 11519' 9372' 9-5/811 'G' 711 250 sx Class 'G' 12904' 10661' 4-1/211 107 sx Class 'G' 13429' 11179' true vertical 11000' - 111391 Tubing (size, grade, and measured depth 4.511 12.6# 13Cr Vam Ace @ 12656' MD Packers & SSSV (type & measured depth) 711 Baker S-3 Packer, 13 Cr @ 12718' MD 4.511 BBE SSSV @ 2030' MD 13. Attachments Description summary of proposal X Detailed operations program 14. Estimated date for commencing operat~ 15. Status of well classification as: Au ust 1 , 2002 16. If proposal was verbally approved Oil_X Date approved Service t to the best of my knowledge. Title: NorthStar Petroleum Engineer RE' , '<II ¡~,., I \ I' r" '. f, "" ¡¡.., n J, ~'"" ,\ ,..¡.,(.IC",t, ';,j !L,[ß JUIf :) 0 qOO,? - ,-,/ L 1(.. Araska on & Gas< CO¡'¡fp, L;Œi f~i¡~B,O,~ Anchoraoe BOP sketch Gas- Suspended - ~~§z Date Y° FOR COMMISSION USE ONLY Conditions of approval: Notify Commission so representative may witness Plug integrity - BOP Test - Location clearance- Mechanical Integrity Test - Subsequent form required 10- L/ 0 7- Approved by order of the Commission Form 1 0-403 Rev 06/15/88 . OrIginal Signed By' Camm Oechsli T a !.""~ ' Nil I: t"" II \1 ,'?"""'io ~ t"\, ¡~ ,f!J ~ I ,; 'I ':, ~ ¡, lJli.,"""~!i\¡,,~/,',,\i! Ii !, Ji I , \,;! ,r "",,:: ~ 'l,..'" 'i¡¡I ~ ~ "',1. Approval no. .. 2.3 z.. Commissioner ø) Date SUBMIT IN TRIPLICATE ( ( PERFORATING PROCEDURE , RDID I' IIWIIIUI.. a lIIO1I Well: Date: NS09 """""""""""""""""""""""""""""""'" 07/23/2002 API #: 50-029-23052-00 .................,.......,..................... Prod Engr .~~~:'<'.Y..~.~.~.~X................ """""""""""""""""""""""""""""""'" Office Ph: 564-5092 """"""""""""""""""""""""""""" Home Ph: 522-2539 """"""""""""""""""""""""""""" Pager: ..................~.~.~.~.~~.~..~.................. CC or AFC: NSWWEL 109 Detail Code: ..........................,........,............,................ ............................................,...................,................................................,...... Description: .P'.~.I.I...~.§.~'!!~9§§.!~.~/.~.!?e.~.~.f!.~~~..~~.§'!............................. WBL Entries Work Desciption lOR Type Va, 4.0 06/04/01 ~."".."~~~~~1,:",...,,,! S Pull SSSV, Drift/tag wI dummy gun 4,000 E LoQ GR/CCL, Perforate 30' (Bottom shot @ 13,193') S Run SSSV Well Objectives and LoQQinQ Notes: Pull SSSV @ 2030' MD. * Run GR/CCL, PBTD thru Jewelry for Tie In log. Reservoir fluids to surface. Monobore completion: 4.5" 13-Cr 12.6# tubing & liner SSSV Nipple @ 2030',3.813" ID, Baker S-3 Packer @ 12718' MD, 3.875" ID Attachment: Wellbore Schematic. Reference Log Tie in Log Log: ,~~R~y',i,~!9..IJ. ....,§,~(9.,9..k.... Date: 12/30/2001 1112/2002 ..,............"".........., ."...."........"............ Company: .§.~h!,~,r:!l.,Þ,~r..., ,§9.~,!~!!1..Þ,~.r:.... Depths (from-to) Depths (from-to) Feet SPF ......J.~,J.§~.~...... ......1~,..t~~.'..... """"""""""""""'" """""""""""""""" .....~9.~.... .........§........ ,...,..,....."....."".."...... """"""""""""""" ,."",.....,....."..,..,.",. ..............,.............,... ....,....,..,.... ...",.............. ,........,...,.............",.... """"""""""""""" "..,.....,..,.,...........,." ,............................." ................. .................... """"""""""""""""" .."....,....,.....,......".. """"""""""""""'" ....,...,.,.,....",......".." ..,....,........, """""""""" ........,.................,....... ,...........,.,............... .........",......,............ ..........."................... ,................ .................... Gas Jetting Expected? No At what Depth? """""""""""""""" Requested Gun Size: ,.?:,~.??'.'..!::!§.!? Charge: ...,?~9.~..P.~1...Ij,~X.., Desired Penetration: 27" """""'....,........,.",.........,.,. Is Drawdown Necessary/Desired/Unnecessary During Perforating Describe below how to achieve drawdown (check wi Pad Operator to see if necessary piping is installed) (e.g. N2 Lift, Hardline LIft Gas, Gas Lift. Flow Well. Backflow Through Drain or Hardline) Tie in to Jewelry @ Minimum ID: Tail Depth: MD Tie in using: Min ID Type: Casing Size: Est Res. Pres. @ ..".....,................,..... 3.725 in ................,..,...,.,.".,. 12765 ft MD "..,.,.......".......,.,,'.... Last Tag: 13382' ELM ft MD on 1/12/2002 ...,..........,......",....".. .............................., Well: Date: NS09 Perforation Summary NWWWWWWW__W----. API #: 50-029-23052-00 Add/Subtract 0 """""""""" to the tie-in log to be on depth with the reference log. Orient. Random Phasing 600 0 .................... 0 ..............,..... 0 ..............".... 0 ,.............".... 0 .................... feet Zone Ivishak Ad/Re/lperf AdPerf ,....,.,...,...........,... ..,.,."""............." """"""""""""'" ........................". """"""""""""'" Entry Hole Diam: No. """"'.......".......................................,...............,..........., """"'....".........,.."...,."..,.......,.."."............."....,........,..' ................................................................,.,......,.....,...... """""""""""""""""""""""""""""""""""...,....,....." ,..................."......................,..................,...........""""'" N/A """""""""" 0.36" ,..........,....,...........,."...................".......................,...""""""""""""""""""""""""""".......,...........,....,........... """"""""""""""" ....".......,........,.....................,..........."....,.,.........".."""""""""""""""",....."........,..............,...............,...."....,. ...........................................................................................,....""""""""""""""""""""""""""""""""""""" ...............~:§.':..~.~..~!p'p).~............... @ J?!.?9.1..'MD 4.5 in 12.6# 13-CR Liner ................,......,." .....).~,!~~Q..... MD is ................9.~..~.g.. psi """"""""""""""'" ................."......".......",..........".."...., On-Site Prod Engr: ................................................".......... General Comments: PBTD """""""""""""""""""""""""""""" """"""""""""""""""""",,""""""'""""""""""""""""......,.,......,...,.,.......,"""""""""""""""""""""""""""""""'"""""""""""""'.......,,"""""" Balance O/B/U O/B/U O/B/U O/B/U O/B/U Depths Referenced to BHCS SPF Orient. """""""""""""""""""""""""""""""""'"""""""""""""""""""",,"""""""""""""""""""""""""""""""""""'.........,...,,,.""""""""......,.............,.......,...,.....,...,............,.,.....,................,........." Zone Aperf/Reperf Feet """"""""""""""'" .............................., ,............................" """""""'" .............,...... ..,.....,........."........,., ".,.............,.........,..., .......,.......,.....,.....,.,., ...,....."...... .,.......,.,.....,.. """"""""""""""'" ,...........,......,............ ............,................." .........."..... """""""""" .,.....,.........,.,.......,... """""""""""""""" ..,......,.."""""""""" ......,...,.,..., """""""""" ..."...,.,."......,.,......., '......,.,...,.......,.,.......' """""""""""""""" ................. .................... Phasing ...........,....,.......... 00 00 0 ....,.,.,.........,.,...". ........................." """"""""""""'" .................,......... """""""""""""""""""""""""""",""""""""""""""" """""""""""""'..............................".,.,.."""""""""'" .............,...........,.....,.....,..."....,..........,..,.........."..,....,.., """""""""""""""""""""""""........".......""""""""'" """,,"""""""""""""""""""'.,.........,....""""""""""'" ~ ... TREE: ABB-VGI 5 1/8" 5ksi ( WELLHEAD: ABB-VGI13-5/8". Multibowl 5ksi .' 13 3/8" Stage Collar at 1593'MD 13 3/8", 68#/ft, L-80, BTC @ 3396' MD 4.5", 12.6#/ft, 13-Cr, Vam Ace TUBING ID: 3.958" CAPACITY: 0.01522 BBL/FT 9-5/8" 47# L-80 BTM-C @ 11519' 4.5" X NIPPLE, @ 12697' MD, (10516 'TVD) 3.813" ID 4.5" X NIPPLE, @ 12742'MD (10559' TVD) 3.813" ID 4.5" XN NIPPLE, @12754'MD (10571' TVO) 3.725" 10 4.5" WLEG, @ 12765MD' (10582' TVD) 3.958" 10 7", 26#/ft L-80, BTC-M @ 12904' ÆRFOAA TK>N SUMMARY REF LOG: LWD-Vision Resistivity (12/30/2001) [Tie-in Log:GRlCCL/USIT] ANGLEATTOPÆRF: Note: Refer to Production DB for historical perf data hitial Perf - Charge: 2606 PowerJet, HMX; Penetration: 27"; Hole: .36"; Phase: 60 deg SlZE SPF INTERVAL MD INTERVAL TVO Opn/Sqz DATE 2.88 6 13193'-13333' 11000'-11139' Opn 1/15/2002 PBTO @ 13383' MO (11188' TVD) TD @ 13429' DATE 11/5/01 01/09/02 01/17/02 REV. BY BMH MJF EMF NSO9 ( RIGINAL KB. ELEV = 55.77' r<B-BF. ELEV = 40.08' CB. ELEV = 15.9' SSSV @ 2030' MO wi HXO SVLN nipple - 3.813" ID (2028' TVO) 6.8PPG DIESEL FREEZE PROTECTION AT +1- 3913' TVD (4364'MD) 4.5" GLM @ 5150' MD (4468' TVD) wi 3.833" 10 - 7" LINER TOP @ 11326' 4.5" Fiber Optic Transducer 3.958" 10 @ 12676' MD, 10496' TVD (Sensor ELM TVD = 10507') - 7" Baker S-3 PACKER, 13 Cr @ 12718' MO (10536' TVD) >, 4.5" LINER TOP @ 12768' (10585' TVO) 4.5", 12.6#, 13Cr Vam Ace BP Exploration (Alaska) .bp ~. ( Date: 04-22-2002 Transmittal Number:92451 BPXA WELL DATA TRANSMITTAL Enclosed are the materials listed below. If you have any questions, please contact me in the PDC at 564-4091. SW Name Date Contractor Lo NS-09 01-12-2002 SCH ao/-d/g &~ Please Sign and Return one copy of this transmittal. Thank You, James H. Johnson Petrotechnical Data Center RECEIVED Ken Lemley MB3-6 Esther Fueg MB3-6 Attn: Lisa Weepie (AOGCC) Attn: Buford Bates (Murphy Exploration (Alaska), Inc Attn: Tim Ryherd (DNR) Attn: Doug Choromanski l, r;:-¡ 2 (,', 2002 :-ir 1\ i . Al88ka Oil & Gas COns. Commision Anchorage Petrotechnical Data Center LR2-1 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 99519-6612 bp ~.... S?:';";~ ~~..~...~..;. .......1.......... .,.w.:.;.Yc ~~. I { i, Date: 02-14-2002 Transmittal Number:92401 BPXA WELL DATA TRANSMITTAL Enclosed are the materials listed below. If you have any questions, please contact me in the PDC at 564-4091. (j-- Top SW Name Date Contractor Log Run Depth Bottom Depth Log Type NS09 12-05-2001 SCH 1-6 200 13433.50 VISION RESISTIVITY; (TVD) - ~ NS09 12-05-2001 SCH 1-6 200 13433.50 VISION DENSITY; (TVD) ~ ~ NS09 12-05-2001 SCH 1-6 200 13433.50 VISION RESISTIVITY; NS09 12-05-2001 SCH 1-6 200 13433.50 VISION DENSITY; (MD) Ô< NS14 02-05-2002 ANA - 0 13020 MWD SURVEY REPORT; (HARDCOPY) ......, MWD SURVEY REPORT; (DISKETTE) ........ .1.. 1J5=fe1 J:2- 3/- 2ðð( ~ C H a res NSog 1- t.ø 2~ðtSt 1'34,3:s.~-o LOWe.. Fof?~I\'ÆT (co) ease Sign and Return one copy of this transmittal. Thank You, James H. Johnson Petrotechnical Data Center Ken Lemley MB3-6 Esther Fueg MB3-6 Attn:HowardOkland (AOGCC):' Attn: Buford Bates (Murphy Exploration (Alaska), Inc Attn: Tim Ryherd (DNR) Attn: Doug Choromanski RECEIVED FEB l?J 2002 Alaska Oil & Gas Cons. Commission Anchorage Petrotechnical Data Center LR2-1 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 99519-6612 ( STATE OF ALASKA (' ALASKA UIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of Well Classification of Service Well IBI Oil 0 Gas 0 Suspended 0 Abandoned 0 Service 2. Name of Operator 7. Permit Number BP Exploration (Alaska) Inc. 201-219 3. Address 8. API Number P.O. Box 196612, Anchorage, Alaska 99519-6612 50- 029-23052-00 4. Location of well at surface-"'~'~ -'--~..~---.-,. -....-- , - --:- 9. Unit or Lease Name 1129' NSL, 643' WEL, SEC. 11, T13N, R13E, UM i-.~\\~~C _,~.::Cir,¡ l 3 LOCA i~{)N$\ Northstar Unit Att~ of prod~ctive interval ¡ . ,"i:D¿ ¡ ¡ v~ 413 SNL,271 EWL, SEC. 18, T13N, R14E, UM_: oj-:,,:,,=~,~:~---- ¡ SU '~..¡J 10. Well Number At total depth , "'~:',.,:,_,,! ,W; .','11 414' SNL, 314' EWL SEC. 18, T13N, R14E,UM :_~~_,_ð~~=:::.i b;...,..",,:;.) NS09 11. Field and Pool 5. Elevation in feet (indicate KB, DF, etc.) 6. Lease Designation and Serial No. Northstar Unit RKB = 55.77' Y0181 12. Date Spudded 13. Date T.D. Reached 14. Date Comp., Susp., or Aband. 15. Water depth, if offshore 16. No. of Completions 12-4-2001 12-30-2001 1-13-2002 391 MSL One 17. Total Depth (MD+TVD) 18. Plug Back Depth (MD+ TVD) 19. Directional Survey 20. Depth where SSSV set 21. Thickness of Permafrost 13429 11235 FT 13383 11189 FT 181 Yes DNo (Nipple) 2030' MD 1545' (Approx.) 22. Type Electric or Other Logs Run GR, PWD, RES, CNL, DEN, SONIC, US IT 23. CASING, LINER AND CEMENTING RECORD CASING SETTING DEPTH HOLE SIZE WT. PER FT. GRADE Top BOTTOM SIZE CEMENTING RECORD AMOUNT PULLED 20" 169# X-56 Surface 202' 20" Driven 13-3/8" 68# L-80 44' 3398' 16" 710 sx PF ILl, 557 sx Class IG' 9-5/8" 47# L-80 42' 115191 12-1/4" 601 sx Econolite, 691 sx 'G' 7" 26# L-80 113261 129041 8-1/2" 250 sx Class 'G' 4-1/2" 12.6# 13Cr 12768' 13429' 6-1/8" 107 sx Class 'GI 24. Perforations open to Production (MD+ TVD of Top and 25. TUBING RECORD Bottom and interval, size and number) SIZE DEPTH SET (MD) PACKER SET (MD) 2-7/8" Gun Diameter, 6 spf 4-1/2", 12.6#, 13-Cr 12765' 12718' MD TVD MD TVD 13193' - 13333' 11000' - 11139' 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED Freeze Protected with 293 Bbls of Diesel 27. PRODUCTION TEST Date First Production Method of Operation (Flowing, gas lift, etc.) January 16, 2002 Flowing Date of Test Hours Tested PRODUCTION FOR OIL -BBL GAs-McF WATER-BBL CHOKE SIZE GAS-OIL RATIO 1/20/2002 4 TEST PERIOD 4043 9326 0 20/64 Flow Tubing Casing Pressure CALCULATED OIL-BBL GAs-McF WATER-BBL OIL GRAVITy-API (CORR) Press. 24-HoUR RATE 28. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. No core samples were taken. RECEIVED FEB 0 6 2002 Alaska Oil & Gas Cons. Commission . "" 0,-, ", .... Form 10-407 Rev. 07-01-80 /""'~II,N,\Ø, II, '~i Ii iJ t ~ \1 !i, ' """"'," l""~,",' 1,1, \ ,r \ " " j I' 'II,:."":' II ',~ "',' , )'~), ~ n 11 IL....,,: ~ ~: '\ /j.".". R B 0 ~A ~ "C' I FFB 1 Submit In Duplicate r - þ- 1.:1 1 2002 \!J ( 29. Geologic Markers Measured True Vertical Depth Depth 7900' 6435' 11012' 8984' 11142' 9098' 11500' 9411' 12045' 9901' 13000' 10810' 13095' 10904' 13400' 11206' Marker Name Top of Schrader Bluff Top of Kuparuk Kuparuk C Top of Miluveach Top of Kingak Top of Shublik Top of Ivishak Top of Kavik 31. List of Attachments: (' 30. Formation Tests Include interval tested, pressure data, all fluids recovered and gravity, GOR, and time of each phase. Summary of Daily Drilling Reports, Surveys, Post Rig Work Summary and Leak Off Integrity Test 32. I hereby certify that the foregoing is true and correct to the best of my knowledge Signed Terrie Hubble ~ Title Technical Assistant Date . (k.O NS09 Well Number 201-219 Permit No. / A roval No. INSTRUCTIONS Prepared By Name/Number: Sandra Stewman, 564-4750 GENERAL: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. ITEM 1: Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. ITEM 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. ITEM 16 AND 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. ITEM 21: Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). ITEM 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. ITEM 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injecti~CiJ.VW ITEM 28: If no cores taken, indicate 'none'. Form 10-407 Rev. 07-01-80 1,""")1,:""",""," ~,.,', """"'1:., 1,1 II ¡ I; ~ If I' ~ " ,.J ¡j.,,( "I, ¡ ~'"" ¡: . 'I ~ I' \ '" II ¡"",(" ID '~ : ~).i FEB 0 6 2002 "I,?i~ 4 r'~ [J J("""(,I Ii 6 . """"." Alaska Oil & Gas Coos. Commission Anchorage Legal Name: NSO9 Common Name: NSO9 T estbatê 12/10/2001 12/21/2001 12/28/2001 .'T~st Type FIT LOT FIT ..'rê!¡.fQ~pt l(TMD) 3,397.0 (ft) 11,519.0 (ft) 12,094.0 (ft) BP . .'.. '. .' . . . . ... . .' . . . . .. .. . . . Leak~()ff.Te~t$lIrt)mary '. . .. ", - Test Depth (TVD) . 3,229.0 (ft) 9,428.0 (ft) 10,717.0 (ft) þ..MW. 9.00 (ppg) 11.20 (ppg) 11.80 (ppg) Suñace Pressure 600 (psi) 1,940 (psi) (psi) Leak Off Pressure (BHP) 2,110 (psi) 7,425 (psi) 6,569 (psi) - Page 1 of 1 EMW 12.58 (ppg) 15.16 (ppg) 11.80 (ppg) /-~. -. Printed: 111412002 10:09:00 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date 12/2/2001 12/3/2001 12/4/2001 12/5/2001 12/6/2001 (' ( BP Operations Summary Report NS09 NS09 DRILL +COMPLETE NABORS NABORS 33E From - To Hours Activity Code NPT 14:00 - 15:30 15:30 - 16:30 16:30 - 19:00 19:00 - 19:30 19:30 - 00:00 00:00 - 03:00 03:00 - 09:00 09:00 - 16:00 16:00 - 19:00 19:00 - 23:00 23:00 - 23:30 23:30 - 00:00 00:00 - 00:30 00:30 - 04:00 04:00 - 06:30 06:30 - 09:00 09:00 - 11 :00 11 :00 - 12:00 12:00 - 13:30 13:30 -16:30 16:30 -17:00 17:00 -18:00 18:00 - 18:30 18:30 -19:00 19:00 - 21:30 21 :30 - 22:00 22:00 - 23:00 23:00 - 00:00 00:00 - 02:00 02:00 - 05:00 05:00 - 06:30 06:30 - 18:00 18:00 - 18:30 18:30 -19:00 19:00 - 20:00 20:00 - 00:00 00:00 - 14:00 14:00 - 14:30 14:30 -19:00 1.50 MOB 1.00 MOB 2.50 MOB 0.50 MOB 4.50 MOB 3.00 MOB 6.00 MOB 7.00 RIGU 3.00 RIGU 4.00 RIGU 0.50 RIGU 0.50 RIGU 0.50 MOB 3.50 MOB 2.50 DRILL 2.50 DRILL 2.00 DRILL 1.00 DRILL 1.50 DRILL 3.00 DRILL 0.50 DRILL 1.00 DRILL 0.50 DRILL 0.50 DRILL 2.50 DRILL 0.50 DRILL 1.00 DRILL 1.00 DRILL 2.00 DRILL 3.00 DRILL 1.50 DRILL 11.50 DRILL 0.50 DRILL 0.50 DRILL 1.00 DRILL 4.00 DRILL 14.00 DRILL 0.50 DRILL 4.50 DRILL Phase P P P PRE PRE PRE P P PRE PRE P P P PRE PRE PRE P P PRE PRE P P P P PRE PRE PRE PRE P P P SURF SURF SURF P P P P P P P P P P P P P N P P SURF SURF SURF SURF SURF SURF SURF SURF SURF SURF SURF SURF SURF RREP SURF SURF SURF P N P SURF RREP SURF SURF P P P SURF SURF SURF Page 1 of 15 Start: 12/2/2001 Rig Release: 1/7/2002 Rig Number: 33E Spud Date: 12/4/2001 End: 1/7/2002 Description of Operations Prep pad & rig for move. Level pad utilizing laser level. PJSM on rig move. Sort out sub complex, synchronize steering, & move rig 10' to the north. PJSM on herculite & rig mat layout. Lay herculite & set mats for sub complex with crane, lay herculite & set mats for service complex with loader, & blow down service lines. Prep rig for move. Move rig & center over hole. Hook up hoses on piperack, button up PUTZ, move mats, hook up injection line. NIU riser, install riser through floor, skid floor. R/U geronimo line, install herculite & build berms, & bring BHA tools to rig floor. Pre-spud meeting. Continue bringing BHA tools to floor. Pre-spud meeting. Review D-7 procedure. Continue berming around rig, change shaker screens, P/U stabs, & tighten blades. P/U BHA to clean out conductor. Clean out conductor to 202'. Stand back 1 std HWDP, P/U 2 collars & 1 stab. Drill to 260'. Blow down top drive & mud lines, RIU Schlumberger gyro & run. POH to change BHA. Handle BHA # 1. Handle BHA # 2. RIH to 242' Gyro Drill from 260' to 303'. Gyro Drill from 303' to 452'. Gyro every 30'. POH, UD 1 jt. of HWDP. Handle BHA # 2. Handle BHA # 3. Orient MWD. Orient MWD & RIH. Slide, drill, & gyro. Drill from 452' to 640'. CIO swab on # 1 mud pump. Drill from 640' to 1485'. Run gyro. At 1385' gyro indicates - azimuth 107.09 deg, inclination 2.95 deg. RID gyro. C/O swab & liner on # 1 mud pump. Drill from 1485' to 1959'. No Drag, No Losses.Flowrate @ 700 GPM. Last 24 hrs. ART 7.0 hrs AST 1.9 hrs Drill & slide from 1959' MD to 3195'. Circulate sweep out of hole until clear of BHA and up hole. Drill from 3195' to 3415 MD. (TD). Section TD called by own Geologist as per prognosis. No drag, no losses. Some extra Printed: 1/14/2002 10:09:12 AM BP Page 2 of 15 Operations Summary Report Legal Well Name: NS09 Common Well Name: NS09 Spud Date: 12/4/2001 Event Name: DRILL +COMPLETE Start: 12/2/2001 End: 1/7/2002 Contractor Name: NABORS Rig Release: 1/7/2002 Rig Name: NABORS 33E Rig Number: 33E Date From - To Hours Activity Code NPT Phase Description of Operations 1216/2001 14:30 - 19:00 4.50 DRILL P SURF torque when backreamng thru slide section on each stand. 19:00 - 20:30 1.50 DRILL P SURF Circulate sweep around and clean hole@ 810 GPM/2000 psi. Circulated 2.112 times bottoms up. 20:30 - 23:30 3.00 DRILL P SURF Flowcheck. POOH. Wipe through build section from 2450 ft to 2070 ft. Dry wipe. Two tight intervals @ 2270ft and 2070 ft that required extra work. No need to put on pumps. Maximum drag 35-40 klbs. After wiping- hole good. 23:30 - 00:00 0.50 DRILL P SURF POH wi HWDP. 12/7/2001 00:00 - 03:00 3.00 DRILL P SURF Lay down BHA. Bit in good shape. Some congealed clay in water courses of stabilisers. 03:00 - 06:00 3.00 CASE P SURF Clear rigfloor of all non -essential tools and equipment. Change out bails.R IU to run 13.3/8" casing. 06:00 - 08:30 2.50 CASE P SURF PJSM. Make up 13.3/8" Landing joint and confirm spaceout , drift riser section and landout. ( First diverterless rig up, new riser section and modifications made to landing joint after incident with Frank's tool in June 2001) 08:30 - 09:30 1.00 CASE P SURF Conduct Safety Meeting with drillcrew. Discuss running procedures and Franks Modified tool. 09:30 - 13:00 3.50 CASE P SURF Make up Shoetrack. Crossed threads- resolve same. Collars hanging up @ Landing. Check floats. Run with hand slips. Collars hanging up on Landing ring. Rotate pipe past restiction with rig casing tongs. Rig oft alignment. 13:00 -16:00 3.00 CASE P SURF Run 13.3/8", 68 Ib/f, L-80 casing to 1200 ft ( 33 joints). Injury. 16:00 - 16:30 0.50 CASE N HMAN SURF Injury to Dean Johnson- floorhand. Pinched finger between jaws of casing tongs. Shut rig down and debriefl investigate incident. 16:30 - 20:00 3.50 CASE P SURF Run 13.3/8",68 Ib/ft casing to 2640 ft. Taking weight. 20:00 - 21 :30 1.50 CASE N DPRB SURF Work thru tight hole from 2640 ft to 2940 ft. Taking 75 klbs down weight to move pipe. Tight hole in region of higher doglegs ( 3-4 degs DLS). 21 :30 - 23:00 1.50 CASE P SURF Run pipe freely down to 3,940 ft. land out at 2300 hrs. Tight hole last 50 ft, some packing oft. PIU 400 klbs with no break over. Taking 100 klbs to land hanger. 23:00 - 23:30 0.50 CASE P SURF Rig down Franks tool. R/U Cement head. 23:30 - 00:00 0.50 CEMT P SURF Stage pumps up gradually and commence conditioning of wellbore for cementing operations. 12/8/2001 00:00 - 02:30 2.50 CEMT P SURF Condition mud for cementing operations. PJSM for cement job while circulating. C/O drive sprocket on cuttings drag chain. Ramp up circulating rate to 1.5 BPMI 370 psi. Circulate surface to surface x 2 while co-ordinating power contingencies, preparing cement tanks and preparing G & I . 02:30 - 05:00 2.50 CEMT P SURF Pump cement per program - 20 bbls. of water - 75 bbls. alpha spacer - 520 bbls 10.7 lead cement - 115 bbls. 15.8 tail cement. 05:00 - 06:30 1.50 CEMT P SURF Displace cement with 9.4 ppg mud at 6-10 BPM. Pumped a total of 5640 strokes. Did not bump plug. No losses. Cement returns after 2120 strokes, 285 bbls of excess cement. 06:30 - 08:30 2.00 CEMT P SURF Flush & drain stack. Flush & blow down cement lines. UD landing jt. 08:30 - 09:30 1.00 CEMT P SURF Clear tools oft of rig floor & clean up. 09:30 - 10:30 1.00 CEMT P SURF CIO bales & elevators. 10:30 - 13:30 3.00 CASE P SURF PJSM. LID riser assy. ( 3 pieces) & lay down mouse hole 13:30 -19:00 5.50 WHSUR P SURF NIU tubing spool -remove wing valves. Reset tubing spool. ( t, Printed: 1/14/2002 10:09:12 AM BP Page 3 of 15 Operations Summary Report Legal Well Name: NS09 Common Well Name: NS09 Spud Date: 12/4/2001 Event Name: DRILL +COMPLETE Start: 12/2/2001 End: 1/7/2002 Contractor Name: NABORS Rig Release: 1/7/2002 Rig Name: NABORS 33E Rig Number: 33E Date From - To Hours Activity Code NPT Phase Description of Operations 1218/2001 13:30 - 19:00 5.50 WHSUR P SURF Test gray lock to 1,000 psi for 5 min. Reinstall sweeps & wing valves. 19:00 - 19:30 0.50 BOPSUR P SURF P/U single gate with mud cross. 19:30 - 20:00 0.50 BOPSUR P SURF Training on Sweeny torque tool. (new) 20:00 - 22:00 2.00 BOPSUR P SURF N/U single gate & mud cross. 22:00 - 22:30 0.50 BOPSUR P SURF Clean up tools & cellar while NS-10 well kill operations are completed. 22:30 - 23:00 0.50 BOPSUR P SURF PJSM on lifting BOP's out of overhead cradle. 23:00 - 00:00 1.00 BOPSUF P SURF Move BOP'S to well & nipple up. 12/9/2001 00:00 - 04:00 4.00 BOPSUF P SURF Niple up BOPE, choke and kill lines, turn buckles 04:00 - 08:30 4.50 BOPSUF N SFAL SURF Unable to install riser, conductor and wellhead @ 1.9 degs, rig centred over well but because of angle at wellhead- unable to rig up. Pull mousehole. Skid rig to the North. 08:30 - 09:30 1.00 BOPSUF P SURF Install Riser and tighten turnbuckles. 09:30 - 10:30 1.00 BOPSUF P SURF Function BOP'sand run test plug. 10:30 -18:00 7.50 BOPSUF P SURF Test BOPE to 2501 5000 psi for 5/10 mins, Annular t0250/ 3500 psi. Blow down lines. Pull Test plug and install wear ring. AOGCC : CHuck Sheeve waived winess of test. 18:00 - 21:00 3.00 DRILL P SURF PJSM. Slip and Cut 102 ft of drilline 21 :00 - 22:00 1.00 DRILL P SURF PJSM. Service Top Drive. 22:00 - 00:00 2.00 DRILL P SURF M/U 12.1/4" Milled Tooth drilling assembly and surface test MWD. 12/10/2001 00:00 - 01 :30 1.50 DRILL P SURF MIU 12.1/4" BHA . Shallow test MWD, Motor. 01 :30 - 02:00 0.50 DRILL P SURF P/U 26 joints of HWDP 02:00 - 02:30 0.50 DRILL P SURF RIH to 2,810 ft 02:30 - 04:30 2.00 DRILL P SURF Wash down and tag cement at 3,280 ft ( 34 ft high). Drill to float collar @3,314 ft. 04:30 - 05:30 1.00 DRILL P SURF CBU until MWin=MWout @ 9.0 ppg. 05:30 - 07:00 1.50 DRILL P SURF R/U and Test 13.3/8" casing to 3,550 psi/ 30 minutes. 7 bbls pumpl return. Hold Well Control discussion with rig crews while testing. 07:00 - 08:30 1.50 DRILL P SURF Drill shoetrack and 20 f of new hole to 3,435 ft - cement firm. Commence displacement. 08:30 - 09:30 1.00 DRILL P SURF Displace to new 9.0 ppg mud. 09:30 - 10:00 0.50 DRILL P SURF Conduct FIT to 12.5 ppg EMW. 600 psi surface pressure. 3.9 bbls pump/return. 10:00 - 11 :00 1.00 DRILL P INT1 Empty L-tanks 11:00 -19:30 8.50 DRILL P INT1 Drill from 3435' to 4426. No drag, no losses. Flowrate 780 GPM. Pumping sweeps every 300 to 400 ft. 19:30 - 20:30 1.00 DRILL P INT1 Circulate out sweep. 20:30 - 21 :00 0.50 DRILL P INT1 Monitor well - blow down mud lines. 21 :00 - 22:00 1.00 DRILL P INT1 POH to shoe. Tight at 3950' to 3800'. Dry wipe. 25,000 overpull. 22:00 - 23:00 1.00 DRILL N RREP INT1 Work on IBOP air valve. ( Frozen solenoid) 23:00 - 23:30 0.50 DRILL P INT1 RIH to 4331' 23:30 - 00:00 0.50 DRILL P INT1 Fill pipe & wash down to 4427'. 12/11/2001 00:00 - 11 :00 11.00 DRILL P INT1 Drill ahead 12.114" hole from 4,426 ft to 5,661 ft. P-rates 200-350 ft/hr. Sweep Hole every 300 to 400 ft. Drag and Torque increase on last three connections. Vary parameters- no good. 11:00 -12:00 1.00 DRILL P INT1 Pump a weighted, viscous sweep to surface- noticeable increase in cuttings. Clean up shakers. Flowcheck. ( ( Printed: 1/14/2002 10:09:12 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date 12/11/2001 12/12/2001 12/13/2001 12/14/2001 { (' BP Operations Summary Report NS09 NS09 DRILL +COMPLETE NABORS NABORS 33E 12:00 - 14:00 From - To Hours Activity Code NPT INT1 14:00 - 00:00 00:00 - 09:00 09:00 - 10:30 10:30 - 13:30 13:30 - 15:30 15:30 - 18:00 18:00 - 19:00 19:00 - 19:30 19:30 - 23:00 23:00 - 23:30 23:30 - 00:00 00:00 - 01 :00 01 :00 - 03:00 03:00 - 05:00 05:00 - 06:00 06:00 - 07:30 07:30 - 08:30 08:30 - 10:00 10:00 - 00:00 00:00 - 14:30 14:30 - 15:30 15:30 -18:30 18:30 - 21:00 21 :00 - 00:00 2.00 DRILL 10.00 DRILL 9.00 DRILL 1.50 DRILL 3.00 DRILL 2.00 DRILL 2.50 DRILL 1.00 DRILL 0.50 DRILL 3.50 DRILL 0.50 DRILL 0.50 DRILL 1.00 DRILL 2.00 DRILL 2.00 DRILL 1.00 DRILL 1.50 DRILL 1.00 DRILL 1.50 DRILL 14.00 DRILL 14.50 DRILL 1.00 DRILL 3.00 DRILL 2.50 DRILL 3.00 DRILL P P INT1 P INT1 P P INT1 INT1 P P INT1 INT1 P P P P INT1 INT1 INT1 INT1 P N N P P P P INT1 DFAL INT1 DFAL INT1 INT1 INT1 INT1 INT1 P P INT1 INT1 P INT1 P INT1 P INT1 P P INT1 INT1 Page 4 of 15 Start: 12/2/2001 Rig Release: 1/7/2002 Rig Number: 33E Spud Date: 12/4/2001 End: 1/7/2002 Phase Description of Operations Make a check trip back to old hole @ 4,426 ft. Tight spots @ 5,361 ft, 5,160 ft and 5040 ft ( 25- 30 klbs overpull). Wipe thru- OK. RIH without problem. Drill ahead from 5,661 to 6,610 ft. Torque increases and slight overpulls off btm on first joint of each stand. Rih- no trouble. Pump 60 bbls high vis fiber sweep every 400 ft. Torque and ovepulls continuing 0 firs single of backreaming. No losses. 780 GPM and 110 RPM. Drill 12.1/4" hole from 6,610 ft to 7,187 ft. Still torque on connections- correlates to back to 2nd string stabiliser @ 48 ft from bit- after that OK. Average bit ROP trending downwards since midnight ( <85 ft/hr) Sweep Hole clean @ 780 GPMI 2300 psi. Flowcheck. POOH. Average drag 10-15 klbs. Maximum @ 25 klbs. Hole in good shape. Fllowcheck @ 13.3/8" shoe @ 3,397 ft. POOH to BHA. Layout motor, bit and MWD tool. Bit 2-3 and 1/16" UIG. ( 1/2 hour to flush tools with fresh water) Change out wear bushing. No obvious worn areas-looked OK. Clean up rigfloor and any uneccessary tools. MU BHA #5 -12.25" PDC bit. RIH wI BHA #5 to 377' for shallow test. Not functioning. Blow down mud-lines. TIH wI HWDP to 1020'. Begin retest of MWD. Shallow test Test MWD- No Good. POOH and changeout Tool. reorientate mtor. RIH to 13.3/8" shoe @ 3,397 ft Service Top Drive @ shoe RIH to 6,080 ft. Tight Wash/Ream thru tight hole from 6,080 ft to 6,248 ft. Circulate bottoms up and work/rotate pipe. Tight interval correlates with sandstones at top of Ugnu. ECD dropped from 10.7 ppg to 9.9 ppg after cleaning up. Run in hole and wash last two stands. Get ECD baseline. Drill ahead from 7,187 to 8,193 ft. Torque 14-15 kft/lbs @ 60 rpm (keeping rpm down through Schrader). Torque increasing to 17-18 kft/lbs on BR after sliding. Total ROP= 114 fph. Total steering time= 2.6 hrs I Total rotating time= 6.3 hrs. Total Flow running 750-780 gal/min. Pumping viscous sweeps every 500 ft. FV= 60-62 w/ MW running 9.4 to 9.6 ppg and ECD f/9.8-10.1. Directionally Drill 12.1/4" Hole from 8,193 ft to 9,201 ft. No Drag. No Losses. ECD holding steady @ 10.3 ppg at stand down. Flowrate 780 GPM. Asembly started dropping at 0.6 deg/100 ft in Colville shale. Tending to build above the Colville. Sweep Hole ready for wiper trip. Conducting wiper trip based on footage (2100 ft) and time (28 hrs). Circulate @ 780 GPMI 2600 psi. Conduct a wiper trip to 6,000 ft (Above previous tight spots). Average drag 10-15 Klbs. Pull 30 Klbs @ 8,023', 7,650' and 6,085'. Wipe out. Hole generally in good shape. RIH to 9201'. Wash last two stands to bottom. Drill ahead from 9,201' to 9390'. Torque on 14-15k / off 12k @ Printed: 1/14/2002 10:09:12 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date 12/14/2001 12/15/2001 12/16/2001 12/17/2001 12/18/2001 (' ( BP Operations Summary Report NS09 NS09 DRILL +COMPLETE NABORS NABORS 33E From - To Hours Activity Code NPT 21 :00 - 00:00 00:00 - 08:00 08:00 - 09:00 09:00 - 00:00 00:00 - 11 :00 11 :00 - 13:30 13:30 -17:00 17:00 -19:30 19:30 - 00:00 00:00 - 03:00 03:00 - 05:00 05:00 - 05:30 05:30 - 06:00 06:00 - 06:30 06:30 - 08:30 08:30 - 09:00 09:00 - 10:00 10:00 -15:00 15:00 - 15:30 15:30 - 00:00 00:00 - 02:00 02:00 - 03:00 03:00 - 03:30 03:30 - 06:00 3.00 DRILL 8.00 DRILL 1.00 DRILL 15.00 DRILL 11.00 DRILL 2.50 DRILL 3.50 DRILL 2.50 DRILL 4.50 DRILL 3.00 DRILL 2.00 DRILL 0.50 DRILL 0.50 CASE 0.50 CASE 2.00 CASE 0.50 CASE 1.00 CASE 5.00 CASE 0.50 CASE 8.50 CASE 2.00 CASE 1.00 CASE 0.50 CASE 2.50 CEMT p P INT1 INT1 N RREP INT1 P INT1 P INT1 P INT1 P INT1 P INT1 P INT1 P INT1 P INT1 P P INT1 INT1 P INT1 P INT1 P INT1 P P INT1 INT1 P INT1 P INT1 P INT1 P INT1 P P INT1 INT1 Page 5 of 15 Start: 12/2/2001 Rig Release: 1/7/2002 Rig Number: 33E Spud Date: 12/4/2001 End: 1/7/2002 Phase Description of Operations 110rpm. Drill 12.1/4" Hole from 9,390 ft to 9,729 ft. No Drag, No losses. Flowrate @ 780 GPM. Sliding about 10% to get required drop above HRZ. Washout on number 1 mud pump manifold. Work pipe and fix same. Drill ahead from 9,729 ft to 10,818 ft into HRZ. Peformed Baranex fluid bleed in treatment at 10,500 ft wi 9.6 ppg MW prior to entering HRZ. PDC Bit not dropping as DD figured while rotating, so angle running a little high @ 30.10 degrees. Total ROP running 102 fph while rotating ROP average 120 fph. Drilling w/15-17k WOB and torque running 17-19k. Drill 12.1/4" Hole from 1 0,818 ft to 11,545 ft- section TD. No Drag, No losses. 825 units of gas on bottoms up from Kup C. Off Bottom torque @ 18,000 ft Ibs with 2% lubricant. Drilling torque is 23000 ftlbs drilling with 400 psi differential motor pressure. Drilling with 800 GPM. Sweep Hole clean with a weighted sweep @ 800 GPMI 3000 psi. Conduct wiper trip back to 9,000 ft. Average drag 10-15 klbs. Hole in good shape. 20 ft of fill on bottom. Wash thru. Circulate bottoms up and condition mud @ 800 GPM/3050 psi. 1500 units of gas from circulated up after wiper trip. PTOH. On second stand, top of Miluveach @ 11,400', drag was 35-40 klbs over. Rih smooth. Work through area several times and TOH. Pull 10 stands, hole fill volume good. Pump dry-job. POOH. Prepare for liner job. POOH drillpipe and HWDP. SLM within 5 ft of tally. Hole fill correct Lay down 12.1/4" BHA. Bit in good shape-good candidate for rebuild. Clean rigfloor of all unwanted equipment. Pul Waer ring- no unusual wear indicating wellhead/alignment problems. Change control lines on stack to operate 9.518" casing rams- function same- good. PJSM and R/U to run 9.5/8" casing. Change out bails. RIU Franks Tool and handling equipment. Hold Safety Meeting on Running Casing. Review past incidents. Make up 9.5/8" shoetrack, bakerlok and check floats- OK. Run 80 joints of 9.5/8", L-80, BTC casing to the 13.3/8" shoe @ 3,397 ft. Circulate casing contents @ 11 BPM/ 500 psi. No Losses. Mud Fine. Continue to run 9.5/8" , L-80, BTC casing. Hole in good shape- correct displacement. Depth at midnight @ 10,500 ft. Continue to run 9.5/8", L-80, BTC casing. Hole good. Run 279 joints. Make up Casing Hanger to landing joint and land casing @ 0245 . Break circulation to ensure clear fluid paths. LID Franks Tool and R/U Cement head and lines. Circulate and condition pipe gradually staging up pumps to 10 Printed: 1/14/2002 10:09:12 AM BP Page 6 of 15 Operations Summary Report Legal Well Name: NS09 Common Well Name: NS09 Spud Date: 12/4/2001 Event Name: DRILL +COMPLETE Start: 12/2/2001 End: 1/7/2002 Contractor Name: NABORS Rig Release: 1/7/2002 Rig Name: NABORS 33E Rig Number: 33E Date From - To Hours Activity Code NPT Phase Description of Operations 12/18/2001 03:30 - 06:00 2.50 CEMT P INT1 BPMI 600 psi- good returns. Did not reciprocate due to cocked wellhead. Paremeters steady. Hold PJSM for cementing while circulating. Set up Power contingencies with Operations and fluff up cement tanks. Circulated casing contents/125% bottom up. 400 units gas on bottoms up. 06:00 - 08:30 2.50 CEMT P INT1 Pump 5 bbls water. Test Lines. 50 bbls weighted spacer, Drop Plug, 399 bbls Lead @ 11.2 ppg (691 sx), 123 bbls Tail @ 15.9 ppg ( 603 sx), drop Top PLug. 08:30 - 10:30 2.00 CEMT P INT1 Displace cement with 25 bbls water, 838 bbls mud @ 96% efficiency, 9670 strokes- good returns, no bump. Final pressure @ 3 BPMI 1250 psi. 10:30 - 11 :30 1.00 CEMT P INT1 Rig down Landing Joint, clear rigfloor and Break down lines. 11 :30 - 14:00 2.50 CASE P INT1 Install 9.5/8" Pack-off in wellhead and test to 5000 psi- OK 14:00 - 15:00 1.00 CASE P INT1 Switch BOP controls back to VBR's and function test. 15:00 -19:30 4.50 CASE P INT1 Test BOPE to 250/5000 psi. Lost Power x 4 times from Pipe rack ( Solonox testing). Resolve leak on Test PUmp. Fluid Pack 9.5/8" x 13.3/8" annulus with 205 bbls 9.8 ppg MUd @ 0.75 BPMI 800 psi. Took 1300 psi to break down formation. Pumped as soon as Pack-off was set ( 2.5 hrs after CIP) 19:30 - 00:00 4.50 CASE N FLUD INT1 Fluid packing NS29 for Production operations 12/19/2001 00:00 - 01 :00 1.00 CASE P INT1 Finish FP 9-5/8" x 13-3/8" w/120 bbls diesel. Hold PJSM for Fluid packing NS-29 for production ops. 01 :00 - 02:00 1.00 EVAL N FLUD INT1 NS-29 Fluid pack tubing for Production Operations: PT low w/ cement line wi neat methanol from rig manifold to NS-29 companion valve. No- good. Blow down cement line and fix leak. PT low 250 psig- good. PT high 4000 psig-- leak. 02:00 - 04:00 2.00 EVAL N SFAL INT1 Continue NS-29 Fluid pack tubing for Production Operations: Bleed and replace hardline seal. PT low again- leak. Bleed and replace 2" chicksan. PT low- good. PT high leak at NS-29 side hardline. Bleed and fix. PT low- good. PT high- good. 04:00 - 07:00 3.00 EVAL N FLUD INT1 Continue NS-29 Fluid pack tubing for Production Operations: Open up companion on NS-29. Start pumping diesel @ 1 bpm w/ positive pressure (plug set in tailpipe- tubing bleed off to atmosphere). Pump 115 bbls diesel. Switch to 3 bbls methanol spacer-- prevent hydrates. Switch to 100 deg F plus heated seawater from G&I. Fill tubing w/ approximately 350 bbls seawater. Shut-down Whp= 1200 psig. Clear cement line with methanol. Bleed and clear cmt line. Rig crew servicing top-drive while NS 29 pumping operations taking place. 07:00 - 07:30 0.50 CASE P INT1 Attempt to pull test plug. Stuck. Double-check LDS. 07:30 - 11 :30 4.00 CASE N SFAL INT1 Blow down stack. Reverse. 11 :30 - 12:30 1.00 CASE N SFAL INT1 R/U and test 9-5/8" casing to 2000 psig for 30 min. Good. 12:30 - 16:30 4.00 CASE N SFAL INT1 Hook up and test kill line. Pull test plug and drain stack. 16:30 -18:00 1.50 CASE N RREP INT1 Trouble shoot top-drive blower. 18:00 - 20:30 2.50 CASE P INT1 PJSM. Slip and cut drill line. (' ( Printed: 1/14/2002 10:09:12 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date 12/19/2001 12/20/2001 12/21/2001 12/22/2001 12/23/2001 (' ( Page 7 of 15 BP Operations Summary Report NS09 NS09 DRILL +COMPLETE NABORS NABORS 33E From - To Hours Activity Code NPT 20:30 - 00:00 00:00 - 00:01 00:01 - 00:30 00:30 - 01 :30 01 :30 - 02:00 02:00 - 07:30 07:30 - 21 :30 21 :30 - 00:00 00:00 - 01 :30 01 :30 - 02:00 02:00 - 02:30 02:30 - 03:30 03:30 - 04:00 04:00 - 06:00 06:00 - 07:00 07:00 - 09:30 09:30 - 11 :30 11 :30 - 13:30 13:30 -15:30 15:30 -16:00 16:00 - 18:00 18:00 - 00:00 00:00 - 15:00 15:00 - 16:30 16:30 - 18:00 18:00 - 22:00 20:00 - 22:30 22:30 - 00:00 00:00 - 02:00 02:00 - 12:00 3.50 CASE 0.02 CASE 0.48 CASE 1.00 CASE 0.50 CASE 5.50 CASE 14.00 CASE 2.50 CASE 1.50 CASE 0.50 CASE 0.50 CASE 1.00 CASE 0.50 CASE 2.00 CASE 1.00 CASE 2.50 CASE 2.00 CASE 2.00 CASE 2.00 CASE 0.50 CASE 2.00 DRILL 6.00 DRILL 15.00 DRILL 1.50 DRILL 1.50 DRILL 4.00 DRILL 2.50 DRILL 1.50 DRILL 2.00 DRILL 10.00 DRILL Phase P P INT1 INT1 INT1 HMAN INT1 INT1 INT1 RREP INT1 RREP INT1 RREP INT1 INT1 INT1 INT1 N P P N N N P N P P INT1 N RREP INT1 P INT1 P INT1 P P N INT1 INT1 HMAN INT1 P INT1 P P INT1 LNR1 P P P N LNR1 LNR1 LNR1 RREP LNR1 P LNR1 P P LNR1 LNR1 P LNR1 Start: 12/2/2001 Rig Release: 1/7/2002 Rig Number: 33E Spud Date: 12/4/2001 End: 1/7/2002 Description of Operations MU BHA #7 (8.5" Hycalog DS70 bit) TIH wI HWDP wI BHA#6. Thaw out Mudline. Surface test MWD and blow-down Jines. TIH to 10425'. Fill DP and blow-down mudlines. Change out Top Drive blower motor. Change out Top Drive oil pump motor. Replace oil motor. Safe Top Drive in and test. Ok. TIHt011185'. Adjust blower motor on Top Drive. Wash down from 11185' to 11430'. Cement stringers from 11258'. Collect rubber from plug off shakers wI a little cement coming back on shakers. Circulate until MW in = MW out= 9.9 ppg. Returns have cleaned up. Completed dumping cement contaminated mud. Perform 9-5/8" casing pressure test twice. First time load cell on sensor for chart recorder not pumped up enough. Pump up load cell. Repeat test - chart recorder still not reading the same as other pressure sensors. Conduct third try at casing test to 4300 psig w/ 9.2 ppg MW (20 psig fall off in 30 min). Hold safety meeting and discuss well control with rig crew before drilling out the shoe-track. Drill shoe-track adding mud lube to reduce the torque. Experience bit balling when drilling new formation. Pump walnutiSAPP sweep and cure bit balling problem by washing from 11518' to 11545'. Drill from 11545'- 11564' (Trying to packoff) Torque up to 28k. Bleed in 15.2 ppg spike mud and condition MW to 11.2 ppg. While performing the weight-up, pit 1 overran. This was a non-process leak that resulted in approximatly 2 hours of trouble time to clean up. Perform LOT. LO @ 1940 psig w/11.2 ppg MW. With a shoe depth of 11519' mdl 9428' tvd, LOT= 15.15 ppg EMW. Wash and ream back to bottom. Drill ahead through Miluveach from 11564' to 11942', just above Top of Kingak. Bit is dropping approximately 1 deg/1 00' through shales. Rotating 80 rpm. Drill from 11942 to 12910.7'. Pump sweep at 12430'. Circulate high vis sweep surface to surface. Wiper Trip. Replace swivel packing. Lubricate Top drive and drawworks. Test swivel. Rih w/15 stands. Tag fill @ 12871' (39' high). Wash to bottom. CBU. Recover splintered shale. Condition mud and circulate viscous sweep surface to surface. Have some splintered shales coming across shakers. Pump weighted sweep surface to surface- returns look much better. Small amount of shales return wI weighted sweep. Drop 2.25" hollow rabbit. POOH off bottom slow (30 fpm) being careful not to swab. PUW's through open hole much better than on wiper trip. Max Printed: 1/14/2002 10:09:12AM ( ( .. BP Page 8 of 15 Operations Summary Report Legal Well Name: NS09 Common Well Name: NS09 Spud Date: 12/4/2001 Event Name: DRILL +COMPLETE Start: 12/2/2001 End: 1/7/2002 Contractor Name: NABORS Rig Release: 1/7/2002 Rig Name: NABORS 33E Rig Number: 33E Date From - To Hours Activity Code NPT Phase Description of Operations 12123/2001 02:00 - 12:00 10.00 DRILL P LNR1 pull 370k. Flow check at shoe. TOH. 12:00 - 14:00 2.00 DRILL P LNR1 PJSM. Lay down BHA#7. 14:00 - 15:00 1.00 CASE P LNR1 RU to run 7" 26# L-80 MOD BTC casing. 15:00 -18:30 3.50 CASE P LNR1 PJSM. MU 7" liner assembly (Float shoe, float collar, 38 jts 7" 26# L-80 liner w/ RH turbolator and stop ring, 7"x 9-5/8" liner hanger, and 7" x 9-5/8" ZXP liner top packer). 18:30 - 00:00 5.50 CASE P LNR1 RIH w/5" DP and 7" liner assembly to 7300' by midnight. 12/24/2001 00:00 - 06:00 6.00 CASE P LNR1 RIH with liner on 5" dp to 9-5/8" casing shoe @ 11519' md. Filling every 11 stands. 06:00 - 07:00 1.00 CASE P LNR1 Circulate one dp and liner volume while MU cement head with TIW valve and one each 15' and 10' 5" dp pups. LD one single for circulating down the last joint. Note: PU and SO weights 285K and 225K, respectively. 07:00 - 08:00 1.00 CASE N DPRB LNR1 Run into openhole with liner to 11980' md. First 2 stands RIH with no problems and no drag; however, while RIH with stands 3, 4 and 5 the drag increased from 5K @ 11760' md to 125K @ 11980' md. Note: After reviewing mud log and geology with ADT Engineer and held discussion on rig floor with Core Rig Team -- decision to pull to shoe for further evaluation -- concern that the Kingak and fault were still to come and situation would only worsen risking a stuck liner above the Sag resulting in a junked well. See Remarks for details. 08:00 - 09:00 1.00 CASE N DPRB LNR1 POOH with stands 5, 4 and 3 while experiencing PU weights of as much as 41 OK which corresponds to 125K overpull. Pulled stands 2 and 1 into shoe with 5k to 10k overpull. Monitored well -- Static. Note: Definately tight hole from 11760' md to 11980' md -- See Remarks for details. 09:00 - 10:00 1.00 CASE N DPRB LNR1 Circ and Cond mud to verify that no gas was swabbed in while pulling out of tight hole -- no gas or influx at bottoms up. Notes: 1. Discussed situation with Anchorage Team -- Decision to POOH for cleanout run and weight up at least 0.5ppg. 2. Laid Down the cement head in the pipe shed. 10:00 -12:00 2.00 CASE N DPRB LNR1 Pump dry job and POOH to 9700' md. 12:00 - 17:30 5.50 CASE N DPRB LNR1 Tour Change. Continue POOH with liner on 5" dp. Trip speed dictated by trip tank -- good hole fill but pulling slower -- liner packer is 8.310" and only has 0.371" clearance in the 9-5/8" 47# casing. 17:30 - 18:00 0.50 CASE N DPRB LNR1 Change over from 5" to 7" handling equipment for laying down the liner. 18:00 -18:30 0.50 CASE N DPRB LNR1 PJSM for laying down the liner. Emphasized the importance of staying out of pinch points and keeping fingers and hands out of pinch points with the rig tongs providing back-up for the casing tongs while breaking 7" buttress collars. 18:30 - 20:30 2.00 CASE N DPRB LNR1 Lay down 35 joints of 7" 26# M-Btrc Liner. Inspected threads and found only one bad collar -- change out with spare joint from pipe tally. 20:30 - 22:00 1.50 CASE N DPRB LNR1 Issue Hot Work Permit and Heat up the Float Collar to back-out pin end of joint 3 -- successfully done without galling threads. Printed: 1/14/2002 10:09:12 AM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date 12/24/2001 12/25/2001 12/26/2001 (' ( Page 9 of 15 BP Operations Summary Report NS09 NS09 DRILL +COMPLETE NABORS NABORS 33E 20:30 - 22:00 From - To Hours Activity Code NPT N DPRB LNR1 22:00 - 22:30 22:30 - 00:00 00:00 - 06:30 06:30 - 10:30 10:30 - 00:00 00:00 - 01 :00 01 :00 - 03:30 03:30 - 04:30 04:30 - 06:30 06:30 - 08:30 1.50 CASE 0.50 CASE 1.50 CASE 6.50 CASE 4.00 CASE 13.50 CASE 1.00 CASE 2.50 CASE 1.00 CASE 2.00 CASE 2.00 CASE N N N DPRB LNR1 DPRB LNR1 DPRB LNR 1 N DPRB LNR1 N DPRB LNR1 N DPRB LNR1 N DPRB LNR1 N DPRB LNR1 N DPRB LNR1 N DPRB LNR1 Phase Start: 12/2/2001 Rig Release: 1/7/2002 Rig Number: 33E Spud Date: 12/4/2001 End: 1/7/2002 Description of Operations Clean off baker lock and lay down joint 3 in the pipe shed. Crossover a 15' 5' dp pup into the 7" float collar and set back with the derrick to be rerun. RD casing equipment and clear rig floor. MU BHA#8 ('Smith' Porcupine Hole-Opener). Finish RIH with clean-out BHA #8 to the 9-5/8" shoe @ 11519' md. Circulate and Condition Mud while increasing MW f/11.3 to 11.8 ppg. Wash and Ream the 8.5" hole interval across the Miluveach, Kingak and top of the Sag. Notes: 1. The returns from the Miluveach are fluted chips about 1/2" and hard. 2. The Kingak returns are a little larger flakes and chips of hard shale. Condition mud & circulate while pumping weighted sweeps. Notes: 1. Large cuttings continued to be circulated up from reaming. 2. Hole cleaned up somewhat prior to shutting down pumps. Wiper Trip to 9 5/8" shoe from 12910'. Notes: 1. Worked several tight spots. PU wt was 375K. Over pulls were intermittent throughout entire hole section with 50k to 1 OOK. 2. Pulled up to 500K to get by 12850' md after 3 attempts. 3. Once in shoe -- PU 330K and SO 225K. RIH to 12910'. Notes: 1. Stands 3 and 4 in the hole experience stack up to 100K. 2. Necessary increase running speed to 1 stand per 70 seconds to get back in hole from 11770' md to 12158' while taking wieght of 25 to 35K. Weight increased after this point while RIH with 210 to 220K or 5 to 15K drag -- maintained -1 stand per 70 seconds. Condition mud & ciculate hole clean while pumping 2 weighted sweeps. Notes: 1. Pump 2 weighted sweeps with 15 ppb barofiber. (25bbl. each). 2. Noticeable difference in the cuttings size between the 2 sweeps. 3. The hole cleaned up during the second sweep circulating across shakers. Monitor hole for flow, drop rabbit, & POH to shoe. Notes: 1. This trip out of open hole was much improved with average overpulls of 5 to 15K across the Kingak. 2. Swapped well from 12300' to 12247' md while pulling consistently with 25 to 45 over -- correlated to sand in Printed: 1/14/2002 10:09:12 AM BP Page 10 of 15 Operations Summary Report Legal Well Name: NS09 Common Well Name: NS09 Spud Date: 12/4/2001 Event Name: DRILL +COMPLETE Start: 12/2/2001 End: 1/7/2002 Contractor Name: NABORS Rig Release: 1/7/2002 Rig Name: NABORS 33E Rig Number: 33E Date From - To Hours Activity Code NPT Phase Description of Operations 12126/2001 06:30 - 08:30 2.00 CASE N DPRB LNR1 top of Kingak. Wiped oft during next stand and hole quit swabbing. 3. Pulled 50K over at 12125' and 12090' md -- wiped out. 4. Broke back at 12090 and pulled slick to shoe through the entire Miluveach section. 08:30 - 12:00 3.50 CASE N DPRB LNR1 Pump dry job & POOH. 12:00 - 14:00 2.00 CASE N DPRB LNR1 Stand back HWDP & LID BHA. 14:00 - 15:00 1.00 CASE N DPRB LNR1 PJSM on running casing, clean floor & R/U casing tongs. 15:00 - 16:00 1.00 CASE N DPRB LNR1 Service top drive. 16:00 - 18:30 2.50 CASE N DPRB LNR1 RIH with 7" liner. 18:30 - 19:00 0.50 CASE N DPRB LNR1 LID casing tongs & RIU to RIH wI drill pipe. 19:00 - 00:00 5.00 CASE N DPRB LNR1 RIH wI 7" liner. 12/27/2001 00:00 - 01 :30 1.50 CASE N DPRB LNR1 RIH wI 7" liner from 9581' - 11,480' MD. Fill pipe every 12 stands. 01 :30 - 02:30 1.00 CASE P LNR1 Condition mud & circulate 1 drill pipe & liner volume. 02:30 - 03:30 1.00 CASE P LNR1 RIH wI 7" liner from 11,480 - 12,904'. (1' above 5' of fill) Liner was run problem free with SIO weights between 195,000 & 215,000 in the open hole. Only exception to problem free occurred at -12,700' where liner stacked up on two different occasions. Liner went down on third attempt after picking back up. (P/U weight 375,000) 03:30 - 06:00 2.50 CASE P LNR1 Condition mud & circulate in preparation for cement job. 06:00 - 06:30 0.50 CASE P LNR1 Test cement lines to 4,000 psi. Pump 51 bbls. spacer followed by 67 bbls. 15.9 ppg class G cement 06:30 - 09:00 2.50 CASE P LNR1 Displace cement with 254 bbls of 11.8 mud. Plug bumped. Set liner top packer & release. Circulae B/U 09:00 - 10:00 1.00 CASE P LNR1 LID cement head 10:00 - 16:00 6.00 CASE P LNR1 Pump dry job & POH. 16:00 - 16:30 0.50 CASE P LNR1 LID packer setting tool. 16:30 - 17:30 1.00 CASE P LNR1 Break out safety valve in cement head & clean floor. 17:30 - 22:30 5.00 CASE P LNR1 Test BOP's. 22:30 - 23:00 0.50 CASE P LNR1 Test 7" liner to 3400 psi & hold for 30 min. 23:00 - 00:00 1.00 CASE P LNR1 Slip & cut 102' of drilling line. 12/28/2001 00:00 - 00:30 0.50 CASE P LNR1 Slip & cut drilling line. 00:30 - 01 :30 1.00 CASE P LNR1 PJSM, R/U to pick up BHA # 9. 01 :30 - 05:00 3.50 CASE P LNR1 MIU BHA # 9, PIU 14 jts of HWDP & rabbit, surface test MWD. 05:00 - 07:00 2.00 CASE P LNR1 Surface test of MWD failure. Blow down top drive & mud lines. PIU 12 jts. of 4" HT 40 drill pipe, surface retest of MWD okay. 07:00 - 14:00 7.00 CASE P LNR1 RIH with 4" DP & 5" DP to 12,817'. Tag landing collar at 12817' 14:00 - 18:00 4.00 CASE P LNR1 Drill shoe track from 12,817' to 12,904' 18:00 - 18:30 0.50 CASE P LNR1 Drill 20' of new hole from 12,910' to 12,930'. 18:30 - 19:00 0.50 CASE P LNR1 Pull to shoe & perform FIT. FIT performed by monitoring well for 10 minutes with 11.8 ppg mud. Hole static. 19:00 - 21 :30 2.50 P PROD1 Pump sweep. Displace 11.8 mud out with new 9.3 mud & condition. Rotate & reciprocate at 40 rpm & 340 gpm. 21 :30 - 22:30 1.00 DRILL P PROD1 Clean L pit. 22:30 - 00:00 1.50 DRILL P PROD1 Drill from 12,930' to 12,950' MD. 12/29/2001 00:00 - 08:30 8.50 DRILL P PROD1 Drlg fl 12950' - 13141' md. (' (' Printed: 1/14/2002 10:09:12 AM . Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date 12/29/2001 12/30/2001 ( { BP Operations Summary Report NS09 NS09 DRILL +COMPLETE NABORS NABORS 33E 00:00 - 08:30 From - To Hours Activity Code NPT PROD1 08:30 - 10:30 10:30 -11:30 11:30 - 20:30 20:30 - 00:00 00:00 - 09:00 09:00 - 10:30 Phase 8.50 DRILL P 2.00 DRILL N DPRB PROD1 1.00 DRILL N DPRB PROD1 9.00 DRILL N DPRB PROD1 3.50 DRILL P PROD1 9.00 DRILL P PROD1 1.50 DRILL P PROD1 Page 11 of 15 Start: 12/2/2001 Rig Release: 1/7/2002 Rig Number: 33E Spud Date: 12/4/2001 End: 1/7/2002 Description of Operations Note: Lost circulation @ 13141' md -- 60' md below top of Ivishak which came in @ 13081' md as per Sperry Sun ADT engineer. Evaluate Losses -- Losing 120 bph while pumping 6 bpm. Shut down pumps and line up on hole fill pump -- Losing 66 bph in static conditions. Monitor Well in static conditon -- Losses reduced to zero with no pumps on hole. Stand back one stand to position top drive below windwall and pump 5 bbls every 15 minutes to prevent freezing top drive. Mix LCM pills and additional surface volume to prepare to drill ahead while evaluating losses. Notes: 1. Pull motor into 7" shoe @ 12904' md. Position bit outside caisng to prevent damaging bit gauge while pumping. 2. Perform pump test @ 1430 hours while pumping 4 bpm for 5 minutes, 6 bpm for 5 minutes and 8 bpm for 10 minutes while observing well for losses -- zero losses. 3. NS-29 experienced losses while drilling near the base of the Shublik of -60 bph. After stopping these losses with Icm pills, the rig crew experienced total losses of >900 bph after drilling ahead 20' to to top of the Ivishak with 9.7 ppg fluid. Drlg ahead f/ 13141' to 13237' md. Notes: 1. Drilled f/13141' to 13193' md wi no loses. 2. Started losing while drilling @ 13194' md. Losses started at 60 bph and gradually increased to 360 bbls per hour. 3. Able to sustain adequate surface volume while drilling ahead. 4. Mixing drilling fluid in the Rig Pit 3 and G&I mix pits while continously adding the new mud to the active system L Pit + Pit 1 + Pit2. 5. The sea water line from the pipe rack is plumbed into rig for back up sea water contingency to fill the backside should losses become greater than the rig can keep up with mixing mud. Supply rate is -9 bpm. 6. The fire water deluge system is tied into the rig pits and the facilities has assigned an operator to start the pumps if needed. This system was MOC'ed after the NS-29 incident. Supply rate is 70 bpm. 7. While drilling ahead, pumped a 30 bbls 40 ppb Baracarb 600 pill -- almost plugged the MWD. The number one pit mud of -250 bbls was treated with 1 pallet of baracarb 150 and 2 pallets of baracarb 5/25 in attempt to heal the losses. The drill cuttings should also have provided plugging particles. Drlg f/ 13237' to 13429' md. 79' rathole below the owe at 13350' md. Notes: 1. Losses were persistent through out drilling between 120 and 180 bph. 2. Reduced fluid wieght to 9.1 ppg while drilling ahead. Wiper Trip to the 7" shoe -- No hole problems (slick). Printed: 1/14/2002 10:09:12 AM BP Page 12 of 15 Operations Summary Report Legal Well Name: NS09 Common Well Name: NS09 Spud Date: 12/4/2001 Event Name: DRILL +COMPLETE Start: 12/2/2001 End: 1/7/2002 Contractor Name: NABORS Rig Release: 1/7/2002 Rig Name: NABORS 33E Rig Number: 33E Date From - To Hours Activity Code NPT Phase Description of Operations 12130/2001 10:30 - 11 :30 1.00 DRILL P PROD1 Circ and Cond Mud for running the liner. Note: Contacted asset and confirmed that RFT wireline log is cancelled. 11 :30 - 13:00 1.50 DRILL P PROD1 POOH to 12000'. 13:00 -15:00 2.00 DRILL P PROD1 Spot 30 bbl 40 ppb baracarb 150 LCM pill and blow down top drive. 15:00 -18:00 3.00 DRILL P PROD1 POOH to 6000'. Note: Line up the hole fill pump on the backside with 9.1 ppg brine in anticipation of losses increasing as was the case on NS29. 18:00 -19:00 1.00 DRILL P PROD1 Bring casing tools to floor to warm up. 19:00 - 21 :00 2.00 DRILL P PROD1 Finish POOH with 5" dp. 21 :00 - 21 :30 0.50 DRILL P PROD1 Change over to 4" handling equipment. 21 :30 - 22:30 1.00 DRILL P PROD1 POOH with 4" dp. 22:30 - 00:00 1.50 DRILL P PROD1 LD 14 jonts of 4" HWDP and BHA #9. 12/31/2001 00:00 - 01 :30 1.50 DRILL P PROD1 LID Anadrill tools & BHA. Hughes 61/8" bit ( STX30CD) pulled graded as 3-5-BT -A-E-1 /16"-RG-PTD. 01 :30 - 04:00 2.50 CASE P PROD1 R/U to run 4 1/2" Vam Ace liner. 04:00 - 07:30 3.50 CASE P PROD1 Run 15 jts. of 4 1/2" liner. Check floats. Fill every 5 jts. P/U ZXP packer and liner hangar. 07:30 - 08:30 1.00 CASE P PROD1 R/D tubing handling equip't & R/U to run liner in the hole on DP. 08:30 - 09:00 0.50 CASE P PROD1 P/U 1 stand of 4" DP & circulate 1 liner volume PIU wi. 75K SIO wi. 85K 09:00 - 20:00 11.00 CASE P PROD1 RIH to 12758' with liner on DP filling pipe every 12 stands. Losses ranged from 70 - 110 bbls. per hour. 20:00 - 20:30 0.50 CASE P PROD1 PIU & drift 1 jt of DP between stands 109 & 110. Torque up cement head. 20:30 - 21 :00 0.50 CASE P PROD1 PJSM on cement job. 21 :00 - 21 :30 0.50 CASE P PROD1 RIH with liner to 13424' & tag 4' of fill. 21 :30 - 22:00 0.50 CASE P PROD1 M/U cement head with valves & hoses to top drive. 22:00 - 00:00 2.00 CASE P PROD1 Circulate 1 Drill pipe & liner volume. Stage up slowly from 1/2 BPM to a maximum of 5 BPM over 2700 Strokes. 1/1/2002 00:00 - 02:00 2.00 CEMT P PROD1 PJSM. Test Halliburton lines to 4,000 psi. Pump 35 bbls 10.0 ppg spacer followed by 28 bbls. 15.9 ppg. lead slurry. Bumped plug with 2482 stks. ( 100% efficiency) 02:00 - 02:30 0.50 CASE P PROD1 Disengage seal, circulate 20 bbls @ max. rate, set packer. 02:30 - 04:00 1.50 CASE P PROD1 Reciprocate while circulating B/U. Trace amount of cement seen at shakers. 11.5 PH was highest reading measured in shaker room. 04:00 - 05:00 1.00 CASE P PROD1 LID Drill pipe pup jts. & cement head. 05:00 - 05:30 0.50 CASE P PROD1 Pump dry job - blow down top drive & mud lines. 05:30 - 11 :00 5.50 CASE P PROD1 POH. LID liner hanger running tool. Note: Running tool was bent on the bottom with a horseshoe shaped piece of metal missing. Approximate size of metal missing was 2.5" in diameter. :( ( Printed: 1/14/2002 10:09:12 AM BP Page 13 of 15 Operations Summary Report Legal Well Name: NS09 Common Well Name: NS09 Spud Date: 12/4/2001 Event Name: DRILL +COMPLETE Start: 12/2/2001 End: 1/7/2002 Contractor Name: NABORS Rig Release: 1/7/2002 Rig Name: NABORS 33E Rig Number: 33E Date From - To Hours Activity Code NPT Phase Description of Operations 1/1/2002 11 :00 - 12:00 1.00 CASE P PROD1 Clean rig floor & prepare to P/U clean out ass'y. 12:00 - 13:00 1.00 CASE P PROD1 Pressure test 4 1/2" liner top x 7" liner top x 9 5/8" casing to 3700 psi. 13:00 - 13:30 0.50 CASE P PROD1 Blow down kill & mud lines. 13:30 -14:00 0.50 CLEAN P COMP R/U 2 3/8" BHA handling tools. 14:00 - 14:30 0.50 CLEAN P COMP PJSM on making up 2 3/8" tools & BHA. 14:30 - 19:00 4.50 CLEAN N HMAN COMP Waiting on polish mill and top dress mill with appropriate crossovers to RIH on clean out assembly to address possible damage to liner receptacle. Notes: 1. Damage caused when stinger on liner running/setting tool was stacked up on liner receptacle while reciprocating and circulating cement to surface. 2. Performed following tasks while waiting on tools. - Clean & clear rig floor. - Break circ sub and mill off motor to to achieve proper space out between landing collar and liner top receptacle. - Certify and adjust maximum weight for manriders. - Service Top Drive and Lubricate Rig. 19:00 - 22:00 3.00 CLEAN P COMP M/U BHA # 10. 22:00 - 22:30 0.50 CLEAN N RREP COMP Weld left side collar finger hinge on derrick board. Crack visually detected. Performed visual on the other finger flap -- ok. 22:30 - 23:00 0.50 CLEAN P COMP Continue RIH with HT-40 DP 23:00 - 23:30 0.50 CLEAN P COMP Swap over to 5" handling tools. 23:30 - 00:00 0.50 CLEAN P COMP MIU 9 5/8" scraper & RIH on 5" DP. 1/2/2002 00:00 - 09:00 9.00 CLEAN P COMP Continue to RIH with the 4.1/2" cleanout assembly. Observe positive tag at top of 4.1/2" liner @ 12,763 ft. Attempt to rotate through stringers inside 4.1/2" liner- limiting out @ 20,000 ftlbs. 09:00 - 10:30 1.50 CLEAN P COMP Add lubricants to mud. 10:30 -12:30 2.00 CLEAN P COMP Rotate and wash down assembly. Work mills on top of 4.1/2" liner. Tag Plugs on depth @ 12,376 ft which placed the liner mills on depth. 12:30 - 13:00 0.50 CLEAN P COMP Conduct PJSM for seawater displacement. 13:00 -14:00 1.00 CLEAN P COMP Install safety valve in string & mix casing flush sweeps in pits. 14:00 -19:30 5.50 CHEM P COMP Completion fluid displacement @ 10 BPMI 3000 psi. Reciprocate and rotate pipe @ 40 RPM. Pumped 50 bbls high vis, 50 bbls caustic, & 50 bbl baraklean spacers, & displaced' with sea water. Pumped until NTU levels were <85. Took two complete circulations. Final NTU was 80 with 25,150 Stks. (2127 bbls.) 19:30 - 20:00 0.50 CLEAN P COMP Blow down mud lines & monitor well. Well static. 20:00 - 00:00 4.00 CLEAN P COMP POH 1/3/2002 00:00 - 02:30 2.50 CLEAN P COMP Continue POH with liner clean out assymbly. 02:30 - 05:30 3.00 CLEAN P COMP UD 2 3/8" BHA. 05:30 - 06:30 1.00 CLEAN P COMP Pull wear bushing & flush wellhead. 06:30 - 10:00 3.50 WHSUR P COMP Make dummy run with tubing hangar to ensure sealing surface in tubing spool was not damaged in previously run test plug that hung up. Test to 5,000 psi. OK. Lubricate rig while making ( ( Printed: 1/14/2002 10:09:12 AM ( (' BP Operations Summary Report Page 14 of 15 Legal Well Name: NS09 Common Well Name: NS09 Spud Date: 12/4/2001 Event Name: DRILL +COMPLETE Start: 12/2/2001 End: 1/7/2002 Contractor Name: NABORS Rig Release: 1/7/2002 Rig Name: NABORS 33E Rig Number: 33E Date From - To Hours Activity Code NPT Phase Description of Operations 1/3/2002 06:30 - 10:00 3.50 WHSUR P COMP dummy run. 10:00 -10:30 0.50 CLEAN P COMP Clear floor of Baker tools. 10:30 -13:00 2.50 CLEAN P COMP PJSM - Cut & slip drilling line. 13:00 -15:00 2.00 CLEAN N RREP COMP Slip and cut a further 102 ft line due to kink in line. 15:00 - 16:30 1.50 CLEAN N RREP COMP Change out driller side tugger line. 16:30 - 17:00 0.50 RUNCO COMP PJSM for rigging up for 4.5" tubing run with Cidra fiberoptics. 17:00 - 20:30 3.50 RUNCO COMP C/O bails, rig up tubing tongs & completion equip't. Weatherford & Cidra. 20:30 - 21 :00 0.50 RUNCO COMP PJSM on running 4.5" completion. 21 :00 - 00:00 3.00 RUNCO COMP RIH wI WLEG, X & XN nipples, Packer assy, X Nipple, & Cidra Mandrell. Secure fiberoptics cable to mandrell & test. Continue RIH wI 4.5" tubing. 1/4/2002 00:00 - 00:00 COMP RIH with 4.5" 13CR Vam Ace tubing. 206 jts. out of 302 jts. have been run. Periodically stop & check fiberoptics signal at surface. OK. Signal too weak to detect while running in hole. Problem at surface not downhole. ( Back to continous monitorng at 0400 hrs) 1/5/2002 00:00 - 05:30 5.50 RUNCO COMP Run 254 joints of 4.1/2" L-80 Chrome tubing to SSSV periodically checking downhole status of CIDRA pressure mandrel ( Contino us monitoring from 0400 hrs) 05:30 - 06:30 1.00 RUNCO COMP Install Halliburton HXO SVLN safety valve and test connections 06:30 - 09:30 3.00 RUNCO COMP Continue to run a further 33 joints 4.1/2" L-80 Chrome Tubing 09:30 - 10:30 1.00 RUNCO SFAL COMP Trouble shoot software problems with CIDRA mandrel- OK. 10:30 - 12:00 1.50 RUNCO COMP Continue to run 4.1/2" Tubing. Tag 4.1/2" PBR on depth with 10 klbs. Pick up and confirm tag on downsroke. 12:00 - 14:00 2.00 RUNCO COMP Spaceout Tubulars. Pull Back and install Hanger. 14:00 - 16:00 2.00 RUNCO COMP INstall and test control lines. Land out Hanger @ 1520 hrs. RILDS and test hanger between seals to 5000 psi- good. 16:00 - 16:30 0.50 RUNCO COMP UD landing jt. - RID Weatherford sheaves from derrick. 16:30 - 19:00 2.50 RUNCO COMP RID & clear rig floor of all completion equip't. & tools. 19:00 - 20:00 1.00 RUNCO COMP PJSM - UD mouse hole and pull riser. 20:00 - 21 :00 1.00 RUNCO COMP Lock out accumulator & disconnect Koomey lines and turnbuckles. 21 :00 - 00:00 3.00 RUNCO COMP PJSM - N/D BOP's. Secure Hydril & double gate in overhead cradle. 1/6/2002 00:00 - 00:30 0.50 RUNCO COMP PJSM - Reviewed use of Sweeney Torque wrench with Nabors Safety Rep. 00:30 - 01 :00 0.50 RUNCO COMP Remove single gate & mud cross from cellar. 01 :00 - 01 :30 0.50 RUNCO COMP Remove annular valves from tubing head & install VR plugs. 01 :30 - 02:30 1.00 RUNCO COMP Clean cellar & wrap & run control lines through tubing spool. 02:30 - 07:00 4.50 RUNCO COMP Terminate Cidra fiberoptics cable, control lines and test. 07:00 - 09:00 2.00 RUNCO COMP Install valves & sweeps on annulus. 09:00 - 11 :00 2.00 RUNCO COMP NI U X-mas tree. 11 :00 - 12:00 1.00 RUNCO COMP R/U to test X-mas tree. 12:00 - 13:30 1.50 RUNCO COMP Test tubing head adaptor & tree to 5,000 psi. OK. 13:30 -14:00 0.50 RUNCO COMP Pull two way check valve. 14:00 - 14:30 0.50 RUNCO COMP PJSM on rigging up to u tube with circuating manifold. 14:30 -16:30 2.00 RUNCO COMP RlU circulating manifold. Printed: 1/14/2002 10:09:12 AM BP Page 15 of 15 Operations Summary Report Legal Well Name: NS09 Common Well Name: NS09 Spud Date: 12/4/2001 Event Name: DRILL +COMPLETE Start: 12/2/2001 End: 1/7/2002 Contractor Name: NABORS Rig Release: 1/7/2002 Rig Name: NABORS 33E Rig Number: 33E Date From - To Hours Activity Code NPT Phase Description of Operations 1/6/2002 16:30 - 17:00 0.50 RUNCO' P COMP Island muster drill 17:00 - 20:30 3.50 RUNCO' P COMP Complete rigging up circulating manifold & test to 4200 psi. 20:30 - 21 :00 0.50 RUNCŒ P COMP PJSM on freeze protection. 21 :00 - 00:00 3.00 RUNCŒ P COMP Pump freeze protect fluids down 4.5" x 9.625". Pumped 50 bbls. of sea water with 2 drums of corrosion inhibitor, followed by 4 bbls. of mineral oil, followed by diesel. Total diesel to be pumped is 293 bbls. followed by another 3 bbls. of mineral oil. Have pumped 72 bbls. of 293 bbls. as of midnight. 10- 11 SPM is maximum rate due to line restrictions coming off of pipe rack. 1/7/2002 00:00 - 04:30 4.50 RUNCO~ II' COMP Continue with Freeze Protection. 293 bbls of Diesel Pumped. 04:30 - 05:30 1.00 RUNCO~ II' COMP Allow diesel to U-tube. 05:30 - 06:00 0.50 RUNCO~ II' COMP Drop 1.7/8" ball. 06:00 - 13:00 7.00 RUNCO~ II' COMP Pressure up , set packer and and test tubing to 4200 psi for 30 minutes. Drop tubing pressure to 3000 psi and test annulus/ packer to 4200 psi. Problems bleeding off due to choke failure on bleed trailer. Bleed of diesel to Trip Tank. 13:00 - 16:00 3.00 RIGD P COMP Break down lines. Confirm zero psi on well. Blow down all lines and clean cellar area. Release rig @ 1600 hrs. (' ( Printed: 1/14/2002 10:09:12 AM Well: Field: API: Permit: (1'"- ~.. ( NS09 Northstar Field 50-029-23052-00 201-219 Rig Accept: Rig Spud: Rig Release: D ri iii n 9..B!.9 : ----- - ---- ------ -- ------ ------ - --. ------------ POST - RIG WORK 12-03-01 12-04-01 01-07-02 Nabors 33E 01111/02 - 01/16/02 PULL DSSSV FROM 1997' SLM. PULL B&R FROM 12733' SLM. PULL SHEAR VLV (1" BK) FROM 5128' SLM. ICE SLUSH FORMING ON TOOLS & IN TREE. PUMPED - 8 BBLS METHANOL (NEET) DOWN TBG - 3 BBLS RETURNED UP IA TO BLEED TANK. PULL 4-1/2" RHC @ 12735' SLM. RIH WI 2-7/8" DMY GUN. TAG TO @ 13352' SLM. RIH WITH GR - CCL I US IT I CBL LOG 2 PASSES FROM TO (13382' ELM) UP TO LINER TOP @ 700 PSI. FAIR CMT FROM 13382' - 13140', POOR CMT FROM 13140' - 12768'. LOG GR-CCL FROM TO TO SURFACE. MADE TWO 30' GUN RUNS & PERFORATED FROM 13273' - 13333' ELM WI 2-7/8" HMX PJ, 6 SPF, 60 DEGREE PHASING. (WHP INCREASED FROM 0 PSI TO 600 PSI AFTER FIRST GUN SHOT.) PERF 13243- 13273 WI 27/8" HMX PJ 6 SPF GUNS (RUN #3). NIGHT CREW RlU. RE-HEAD. RIH WI GUN # 4 (30') & GUN #5 (20') PERF 13193' - 13243' WI 27/8" HMX PJ 6 SPF. WELL-REMAINED FLUID PACKED @ 950 PSI WHP. RID E- LINE & RlU SLICK LINE. RIH WI 4-1/2" SS C-SUB. SET 4-1/2" SS C-SUB @ 5367' SLM. SET 1" DGLV WI BK LATCH @ 5129' SLM. PULLED C-SUB. SET 4-1/2" BBE SSSV (SER # BP 4-15) @ 1998' SLM. ANADRILL SCHLUMBERGER Survey report Client...................: BP Exploration (Alaska) Inc. Field....................: Northstar Well.....................: NS09 API number...............: 50-029-23052-00 Engineer.................: Leafstedt Rig:.....................: Nabors 33E State:...................: Alaska ----- Survey calculation methods------------- Method for positions.....: Minimum curvature Method for DLS...........: Mason & Taylor ----- Depth reference ----------------------- Permanent datum..........: Mean Sea Level Depth reference..........: Drill Floor GL above permanent.......: 15.57 ft KB above permanent.......: Top Drive DF above permanent.......: 55.52 ft ----- Vertical section origin---------------- Latitude (+N/S-).........: 0.00 ft Departure (+E/W-)........: 0.00 ft ----- Platform reference point--------------- Latitude (+N/S-).........: -999.25 ft Departure (+E/W-)........: -999.25 ft Azimuth from rotary table to target: 104.29 degrees [(c)2001 Anadrill IDEAL ID6_1C_l0] 30-Dec-200111:00:43 Spud date.. ..............: Last survey date.........: Total accepted surveys...: MD of first survey.......: MD of last survey........: 111/1111111111111 ~I~ 11111 11/111/1/1/1/11111111111/1111111111//1 10202646574 .M~ 11 -w:. \ ~ 1-(r::r <ÇV1 v ~l Page 1 of 6 05-Dec-01 30-Dec-Ol 150 0.00 ft 13429.00 ft ~'. ----- Geomagnetic data ---------------------- Magnetic model. ..........: BGGM version 2000 Magnetic date.. .... ......: 12-Dec-2001 Magnetic field strength..: 1149.89 HCNT Magnetic dec (+E/W-).....: 26.59 degrees Magnetic dip... ..........: 80.92 degrees ----- MWD Reference Reference Reference Tolerance Tolerance Tolerance survey Reference G..............: H..............: Dip............: of G...........: of H...........: of Dip.........: Criteria --------- 1002.69 mGal 1149.89 HCNT 80.92 degrees (+/-) 2.50 mGal (+/-) 6.00 HCNT (+/-) 0.45 degrees ----- Corrections --------------------------- Magnetic dec (+E/W-).. ...: 26.59 degrees Grid convergence (+E/W-).: 0.00 degrees Total az corr (+E/W-)....: 26.59 degrees (Total az corr = magnetic dec - grid conv) Sag applied (Y/N) ... ... ..: No degree: 0.00 -~ ANADRILL SCHLUMBERGER Survey Report 31-Dec-200114:22:32 Page 2 of 6 --- -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ 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 qual (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type type --- -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ 1 0.00 0.00 90.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 TIP 2 50.00 0.53 160.70 50.00 50.00 0.13 -0.22 0.08 0.23 160.70 1.06 GYR 3 100.00 1.08 176.60 50.00 99.99 0.40 -0.91 0.18 0.92 168.72 1.18 GYR 4 150.00 1.47 183.70 50.00 149.98 0.66 -2.02 0.17 2.02 175.26 0.84 GYR 5 188.00 1.76 185.80 38.00 187.97 0.84 -3.08 0.08 3.09 178.57 0.78 GYR 6 205.00 1.23 183.73 17.00 204.96 0.91 -3.53 0.04 3.53 179.37 3.13 GYR -~ 7 263.00 0.33 181.10 58.00 262.95 1.06 -4.31 -0.01 4.31 180.07 1.55 GYR 8 296.00 0.43 171.80 33.00 295.95 1.13 -4.53 0.01 4.53 179.86 0.36 GYR 9 326.00 0.03 188.50 30.00 325.95 1.17 -4.65 0.03 4.65 179.68 1.34 GYR 10 356.00 0.54 65.75 30.00 355.95 1.28 -4.60 0.15 4.60 178.09 1.86 GYR 11 416.00 0.34 60.00 60.00 415.95 1.63 -4.40 0.57 4.43 172.67 0.34 GYR 12 458.00 0.70 49.60 42.00 457.95 1.87 -4.17 0.87 4.26 168.22 0.88 GYR 13 549.00 1.04 53.61 91.00 548.94 2.71 -3.32 1.96 3.85 149.46 0.38 GYR 14 640.00 0.99 51.30 91.00 639.92 3.71 -2.34 3.24 3.99 125.82 0.07 GYR 15 731.00 0.73 51.80 91.00 730.91 4.54 -1.49 4.30 4.55 109.04 0.29 GYR 16 820.00 1.43 75.82 89.00 819.90 5.86 -0.86 5.83 5.89 98.42 0.92 GYR 17 910.00 2.93 93.20 90.00 909.83 9.10 -0.72 9.21 9.24 94.44 1.80 GYR 18 1000.00 3.21 90.30 90.00 999.70 13.81 -0.86 14.03 14.05 93.50 0.36 GYR 19 1101.00 3.37 89.63 101.00 1100.54 19.42 -0.85 19.82 19.84 92.46 0.16 GYR 20 1190.00 3.30 97.90 89.00 1189.39 24.50 -1.19 24.98 25.01 92.72 0.55 GYR 21 1280.00 3.45 100.78 90.00 1279.23 29.78 -2.05 30.20 30.27 93.88 0.25 GYR - - 22 1370.00 2.93 105.10 90.00 1369.09 34.78 -3.16 35.09 35.23 95.14 0.64 GYR 23 1385.00 2.95 107.10 15.00 1384.07 35.55 -3.37 35.82 35.98 95.37 0.70 GYR 24 1409.11 2.95 106.79 24.11 1408.15 36.79 -3.73 37.01 37.20 95.76 0.07 MWD 25 1505.56 2.99 106.39 96.45 1504.47 41.78 -5.16 41.80 42.12 97.03 0.05 MWD 26 1600.40 2.61 90.57 94.84 1599.20 46.35 -5.88 46.33 46.70 97.23 0.90 MWD 27 1694.11 2.70 84.91 93.71 1692.81 50.50 -5.70 50.66 50.98 96.42 0.30 MWD 28 1790.09 2.81 88.22 95.98 1788.68 54.90 -5.43 55.27 55.53 95.61 0.20 MWD 29 1887.92 3.42 92.34 97.83 1886.36 60.06 -5.47 60.58 60.83 95.16 0.66 MWD 30 1981.80 5.25 98.33 93.88 1979.97 67.07 -6.21 67.63 67.91 95.25 2.01 MWD [(c)2001 Anadrill IDEAL ID6_1C_10] ANADRILL SCHLUMBERGER Survey Report 31-Dec-200114:22:32 Page 3 of 6 --- -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ 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 qual (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type type -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ --- -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ 31 2078.33 7.49 109.58 96.53 2075.90 77.73 -8.96 77.93 78.44 96.56 2.65 MWD 32 2172.47 10.60 109.69 94 . 14 2168.86 92.46 -13.93 91.86 92.92 98.63 3.30 MWD 33 2269.98 13.76 106.72 97.51 2264.16 112.98 -20.29 111.42 113.25 100.32 3.30 MWD 34 2363.86 16.79 108.44 93.88 2354.72 137.67 -27.80 134.98 137.81 101.64 3.26 MWD 35 2458.34 19.85 107.19 94.48 2444.40 167.30 -36.86 163.26 167.37 102.72 3.27 MWD 36 2554.44 23.12 103.85 96.10 2533.81 202.48 -46.20 197.17 202.51 103.19 3.63 MWD 2649.09 -~--. 37 25.38 101.24 94.65 2620.10 241.32 -54.60 235.12 241.37 103.07 2.64 MWD 38 2743.96 28.57 103.89 94.87 2704.65 284.32 -64.0'1 277.09 284.39 103.01 3.59 MWD 39 2840.14 32.61 104.74 96.18 2787.42 333.25 -76.13 324.50 333.31 103.20 4.22 MWD 40 2936.35 35.99 105.05 96.21 2866.89 387.46 -90.07 376.89 387.50 103.44 3.52 MWD 41 3026.91 37.90 104.79 90.56 2939.26 441.88 -104.08 429.48 441.91 103.62 2.12 MWD 42 3123.22 40.12 105.06 96.31 3014.10 502.50 -119.70 488.06 502.52 103.78 2.31 MWD 43 3218.35 42.75 105.29 95.13 3085.41 565.44 -136.18 548.81 565.45 103.94 2.77 MWD 44 3311.68 43.45 105.83 93.33 3153.55 629.19 -153.29 610.24 629.20 104.10 0.85 MWD 45 3343.35 43.23 105.44 31.67 3176.59 650.92 -159.15 631.17 650.93 104.15 1.09 MWD 46 3504.37 43.63 105.20 161.02 3293.52 761.60 -188.39 737.93 761.60 104.32 0.27 MWD 47 3595.67 42.44 105.01 91.30 3360.26 823.90 -204.63 798.09 823.90 104.38 1.31 MWD 48 3692.17 42.74 104.91 96.50 3431.30 889.20 -221.49 861.18 889.21 104.42 0.32 MWD 49 3787.23 44.09 105.05 95.06 3500.35 954.53 -238.38 924.29 954.53 104.46 1.42 MWD 50 3881.95 43.66 104.64 94.72 3568.63 1020.18 -255.20 987.75 1020.18 104.49 0.54 MWD 51 3977.94 44.77 105.12 95.99 3637.43 1087.11 -272.39 1052.44 1087.12 104.51 1.21 MWD - ~, 52 4074.08 43.42 105.19 96.14 3706.47 1154.00 -289.88 1117.01 1154.01 104.55 1.41 MWD 53 4168.47 45.10 105.54 94.39 3774.07 1219.86 -307.33 1180.53 1219.88 104.59 1.80 MWD 54 4264.17 44.57 105.29 95.70 3841.94 1287.32 -325.27 1245.58 1287.35 104.64 0.58 MWD 55 4354.67 44.12 105.78 90.50 3906.66 1350.56 -342.21 1306.52 1350.60 104.68 0.62 MWD 56 4455.59 45.33 104.77 100.92 3978.36 1421.57 -360.91 1375.03 1421.61 104.71 1.39 MWD 57 4550.30 44.89 104.22 94.71 4045.20 1488.67 -377.71 1439.99 1488.70 104.70 0.62 MWD 58 4644.66 44.61 104.02 94.36 4112.21 1555.10 -393.92 1504.42 1555.13 104.67 0.33 MWD 59 4739.33 44.79 103.82 94.67 4179.50 1621.69 -409.94 1569.05 1621.72 104.64 0.24 MWD 60 4834.40 45.07 103.82 95.07 4246.81 1688.83 -425.97 1634.25 1688.85 104.61 0.29 MWD [(c)2001 Anadrill IDEAL ID6_1C_10] ANADRILL SCHLUMBERGER Survey Report 31-Dec-200114:22:32 Page 4 of 6 . --- -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ 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 qual (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type type --- -------- ------ ------- ------ -------- -------- ==~============= --------------- ----- ----- ------ -------- ------ ------- ------ -------- -------- --------------- ----- ----- ------ 61 4929.18 45.45 103.55 94.78 4313.53 1756.15 -441.90 1699.66 1756.17 104.57 0.45 MWD 62 5025.61 45.57 103.70 96.43 4381.10 1824.93 -458.11 1766.51 1824.95 104.54 0.17 MWD 63 5120.66 45.43 103.80 95.05 4447.72 1892.72 -474.22 1832.37 1892.74 104.51 0.17 MWD 64 5215.98 45.30 102.82 95.32 4514.69 1960.54 -489.83 1898.37 1960.55 104.47 0.74 MWD 65 5309.02 45.26 102.82 93.04 4580.16 2026.63 -504.50 1962.83 2026.63 104.41 0.04 MWD 66 5404.93 44.93 102.78 95.91 4647.87 2094.54 -519.55 2029.08 2094.54 104.36 0.35 MWD ~~'- 67 5500.05 44.60 103.00 95.12 4715.40 2161.50 -534.50 2094.37 2161.50 104.32 0.38 MWD 68 5595.85 44.19 103.52 95.80 4783.86 2228.51 -549.87 2159.61 2228.51 104.28 0.57 MWD 69 5690.67 43.79 104.33 94.82 4852.08 2294.36 -565.71 2223.53 2294.36 104.27 0.73 MWD 70 5786.37 43.51 103.82 95.70 4921.32 2360.42 -581.78 2287.60 2360.42 104.27 0.47 MWD 71 5881.62 43.59 104.38 95.25 4990.36 2426.04 -597.77 2351.25 2426.04 104.26 0.41 MWD 72 5978.50 45.40 103.91 96.88 5059.46 2493.94 -614.35 2417.08 2493.94 104.26 1.90 MWD 73 6072.97 45.66 104.14 94.47 5125.64 2561.35 -630.69 2482.49 2561.35 104.25 0.33 MWD 74 6169.23 45.92 103.83 96.26 5192.76 2630.35 -647.37 2549.44 2630.35 104.25 0.36 MWD 75 6265.00 45.81 103.63 95.77 5259.45 2699.08 -663.68 2616.21 2699.08 104.23 0.19 MWD 76 6359.87 45.73 104.28 94.87 5325.63 2767.06 -680.07 2682.18 2767.06 104.23 0.50 MWD 77 6455.86 45.42 104.96 95.99 5392.82 2835.61 -697.38 2748.52 2835.61 104.24 0.60 MWD 78 6550.63 45.13 104.93 94.77 5459.51 2902.94 -714.74 2813.57 2902.94 104.25 0.31 MWD 79 6644.71 45.03 105.68 94.08 5525.94 2969.54 -732.32 2877.83 2969.54 104.28 0.57 MWD 80 6740.40 44.76 105.45 95.69 5593.73 3037.07 -750.45 2942.89 3037.07 104.31 0.33 MWD 81 6834.54 44.30 105.74 94.14 5660.84 3103.07 -768.19 3006.48 3103.07 104.33 0.53 MWD - ~- 82 6929.93 44.27 105.95 95.39 5729.12 3169.65 -786.38 3070.55 3169.65 104.36 0.16 MWD 83 7026.29 43.27 105.20 96.36 5798.71 3236.29 -804.28 3134.76 3236.29 104.39 1.17 MWD 84 7122.04 42.95 105.78 95.75 5868.61 3301.71 -821.76 3197.82 3301.71 104.41 0.53 MWD 85 7216.23 43.13 105.92 94.19 5937.45 3365.97 -839.31 3259.66 3365.98 104.44 0.22 MWD 86 7311.24 43.49 105.02 95.01 6006.59 3431.12 -856.70 3322.47 3431.14 104.46 0.75 MWD 87 7406.20 43.45 105.36 94.96 6075.50 3496.45 -873.81 3385.52 3496.46 104.47 0.25 MWD 88 7502.12 43.82 105.49 95.92 6144.92 3562.62 -891.42 3449.32 3562.65 104.49 0.40 MWD 89 7597.90 43.61 104.04 95.78 6214.15 3628.81 -908.29 3513.32 3628.83 104.50 1.07 MWD 90 7692.37 43.32 103.02 94.47 6282.72 3693.79 -923.49 3576.50 3693.81 104.48 0.80 MWD [(c)2001 Anadrill IDEAL ID6_1C_10J ANADRILL SCHLUMBERGER Survey Report 31-Dec-200114:22:32 Page 5 of 6 --- -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ 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 qual (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type type -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ --- -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ 91 7785.98 42.82 101.76 93.61 6351.10 3757.68 -937.21 3638.94 3757.69 104.44 1.06 MWD 92 7880.93 42.41 100.88 94.95 6420.98 3821.88 -949.83 3701.97 3821.88 104.39 0.76 MWD 93 7975.73 42.00 100.90 94.80 6491.20 3885.45 -961.86 3764.51 3885.45 104.33 0.43 MWD 94 8069.25 41.61 101.16 93.52 6560.92 3947.69 -973.79 3825.70 3947.69 104.28 0.46 MWD 95 8166.60 41.39 100.86 97.35 6633.83 4012.09 -986.11 3889.02 4012.09 104.23 0.30 MWD 96 8260.83 40.60 101.33 94.23 6704.95 4073.81 -998.00 3949.68 4073.81 104.18 0.90 MWD 97 8355.19 40.09 101.55 94.36 6776.86 4134.82 -1010.12 4009.55 4134.83 104.14 0.56 MWD --, 98 8448.60 39.33 101.20 93.41 6848.72 4194.42 -1021.89 4068.06 4194.44 104.10 0.85 MWD 99 8544.73 38.41 102.38 96.13 6923.57 4254.69 -1034.21 4127.11 4254.72 104.07 1.23 MWD 100 8638.64 38.59 101.48 93.91 6997.06 4313.09 -1046.29 4184.30 4313.14 104.04 0.63 MWD 101 8732.64 37.76 103.77 94.00 7070.96 4371.16 -1058.98 4240.99 4371.21 104.02 1.75 MWD 102 8828.22 36.79 104.44 95.58 7147.02 4429.04 -1073.08 4297.13 4429.09 104.02 1.10 MWD 103 8923.39 36.25 104.89 95.17 7223.50 4485.68 -1087.42 4351.92 4485.72 104.03 0.63 MWD 104 9017.60 35.73 105.10 94.21 7299.73 4541.04 -1101.74 4405.40 4541.{)8 104.04 0.57 MWD 105 9113.03 35.36 105.01 95.43 7377.38 4596.51 -1116.15 4458.97 4596.55 104.05 0.39 MWD 106 9209.57 35.24 104.86 96.54 7456.17 4652.29 -1130.53 4512.88 4652.33 104.06 0.15 MWD 107 9303.34 35.22 106.15 93.77 7532.76 4706.37 -1144.99 4565.00 4706.40 104.08 0.79 MWD 108 9399.22 35.27 104.88 95.88 7611.07 4761.68 -1159.79 4618.31 4761.71 104.10 0.77 MWD 109 9493.19 35.26 105.52 93.97 7687.79 4815.93 -1174.01 4670.66 4815.95 104.11 0.39 MWD 110 9587.41 35.12 104.65 94.22 7764.79 4870.22 -1188.15 4723.09 4870.24 104.12 0.55 MWD 111 9682.41 34.38 104.95 95.00 7842.85 4924.37 -1201.98 4775.44 4924.39 104.13 0.80 MWD - _. 112 9777.15 33.63 104.98 94.74 7921.39 4977.35 -1215.66 4826.63 4977.37 104.14 0.79 MWD 113 9873.16 32.68 103.70 96.01 8001.77 5029.85 -1228.67 4877.50 5029.87 104.14 1.23 MWD 114 9969.34 31.64 103.16 96.18 8083.19 5081.04 -1240.56 4927.29 5081.06 104.13 1.12 MWD 115 10063.50 31.07 103.64 94.16 8163.60 5130.03 -1251.92 4974.95 5130.05 104.12 0.66 MWD 116 10159.90 30.62 103.54 96.40 8246.36 5179.45 -1263.53 5022.99 5179.48 104.12 0.47 MWD 117 10253.98 30.34 103.90 94.08 8327.44 5227.17 -1274.85 5069.35 5227.19 104.12 0.36 MWD 118 10348.63 30.42 103.69 94.65 8409.09 5275.04 -1286.26 5115.84 5275.06 104.11 0.14 MWD 119 10442.73 30.19 103.69 94.10 8490.34 5322.52 -1297.50 5161.97 5322.54 104.11 0.24 MWD 120 10537.51 30.11 104.00 94.78 8572.29 5370.12 -1308.89 5208.19 5370.15 104.11 0.18 MWD [(c)2001 Anadrill IDEAL ID6_1C_10J ANADRILL SCHLUMBERGER Survey Report 31-Dec-200114:22:32 Page 6 of 6 . --- -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ 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 qual (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type type -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ --- -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ 121 10632.90 30.29 104.19 95.39 8654.74 5418.10 -1320.58 5254.73 5418.13 104.11 0.21 MWD 122 10727.22 30.16 104.18 94.32 8736.23 5465.58 -1332.21 5300.76 5465.61 104.11 0.14 MWD 123 10822.87 30.09 104.53 95.65 8818.97 5513.59 -1344.11 5347.27 5513.62 104.11 0.20 MWD 124 10917.62 29.22 104.75 94.75 8901.30 5560.47 -1355.96 5392.63 5560.49 104.11 0.93 MWD 125 11012.48 28.59 104.22 94.86 8984.35 5606.32 -1367.43 5437.02 5606.34 104.12 0.72 MWD 126 11107.43 28.69 104.69 94.95 9067.68 5651.83 -1378.79 5481.09 5651.85 104.12 0.26 MWD -~ 127 11203.31 28.98 104.46 95.88 9151.67 5698.07 -1390.43 5525.84 5698.09 104.12 0.32 MWD 128 11297.42 29.20 105.66 94.11 9233.91 5743.82 -1402.32 5570.03 5743.84 104.13 0.66 MWD 129 11393.64 29.02 105.59 96.22 9317.98 5790.61 -1414.93 5615.10 5790.63 104.14 0.19 MWD 130 11454.60 28.66 106.06 60.96 9371.38 5820.01 -1422.94 5643.40 5820.02 104.15 0.70 MWD 131 11584.59 28.51 105.76 129.99 9485.52 5882.18 -1439.99 5703.21 5882.19 104.17 0.16 MWD 132 11681.65 27.50 105.83 97.06 9571.22 5927.74 -1452.40 5747.06 5927.75 104.18 1.04 MWD 133 11776.10 25.92 105.95 94.45 9655.58 5970.17 -1464.02 5787.89 5970.18 104.19 1.67 MWD 134 11868.54 24.49 105.26 92.44 9739.22 6009.52 -1474.61 5825.80 6009.53 104.20 1.58 MWD 135 11968.31 23.34 102.70 99.77 9830.43 6049.96 -1484.40 5865.04 6049.97 104.20 1.55 MWD 136 12061.52 22.57 102.53 93.21 9916.25 6086.30 -1492.34 5900.51 6086.31 104.19 0.83 MWD 137 12156.73 21.99 102.13 95.21 10004.36 6122.37 -1500.05 5935.77 6122.38 104.18 0.63 MWD 138 12251.34 21.11 101.65 94.61 10092.35 6157.09 -1507.22 5969.78 6157.11 104.17 0.95 MWD 139 12346.24 20.03 101.03 94.90 10181.20 6190.39 -1513.78 6002.47 6190.41 104.15 1.16 MWD 140 12441.21 18.48 100.87 94.97 10270.85 6221.66 -1519.73 6033.22 6221.68 104.14 1.63 MWD 141 12536.85 16.97 99.10 95.64 10361.95 6250.69 -1524.79 6061.89 6250.72 104.12 1.68 MWD - /""=-~ 142 12632.19 15.83 98.69 95.34 10453.41 6277.49 -1528.96 6088.48 6277.52 104.10 1.20 MWD 143 12727.21 14.64 97.16 95.02 10545.09 6302.30 -1532.41 6113.21 6302.35 104.07 1.32 MWD 144 12821.49 13.77 97.20 94.28 10636.49 6325.26 -1535.30 6136.16 6325.32 104.05 0.92 MWD 145 12837.53 13.49 97.36 16.04 10652.08 6329.01 -1535.78 6139.91 6329.07 104.04 1.76 MWD 146 12961.81 12.63 96.87 124.28 10773.14 6356.87 -1539.27 6167.78 6356.95 104.01 0.70 MWD 147 13058.42 11.11 95.45 96.61 10867.68 6376.55 -1541.41 6187.53 6376.63 103.99 1.60 MWD 148 13244.07 7.85 90.94 185.65 11050.77 6406.56 -1543.32 6218.02 6406.68 103.94 1.80 MWD 149 13335.65 5.85 89.51 91.58 11141.70 6417.16 -1543.38 6228.94 6417.30 103.92 2.19 MWD Survey Projected to Total Depth: 150 13429.00 3.90 87.42 93.35 11234.70 6424.80 -1543.20 6236.87 6424.95 103.90 2.10 MWD [(c)2001 Anadrill IDEAL ID6_1C_10J ( (' sper'I'Y- sun C R I I-L..I N Ci 5 E R V 1 c: E 55 aD/-dIe¡ BP EXPLORATION ALASKA END OF WELL REPORT NORTHST AR NSO9 f ( TABLE OF CONTENTS 1. General Information 2. Daily Summary 3. Daily Operations 4. Show Reports 5. Morning Reports 6. BHA's 7. Bit Record 8. Mud Reports 9. Survey Record 10. Formation Tops 11. Formation Evaluation Logs 5par-'r"'v- sun C RI L.L.I N Iii se fiiinJi t: e 55 I .1 I I I I { I I I I I I ( I I I I I t' ( GENERAL WELL INFORMATION Company: Rig: Well: Field: Borough: State: Country: API Number: Sperry-Sun Job Number: Job Start Date: Job End Date: North Reference: Declination: Dip Angle: Total Field Strength: Date Of Magnetic Data: Wellhead Coordinates N: Wellhead Coordinates W: Vertical Section Azimuth: SDl Engineers: Company Representatives: Company Geologist: lease Name: SSDS Unit Number: State: Borough: BP Exploration Alaska Nabors Alaska Drilling No. 33-E Northstar NS09 Northstar North Slope Alaska United States 50-029-23052-00 AKAM 11202 December 02, 2001 January 01, 2002 True 26.59 deg 80.92 deg 1149.89 HCNT December 12, 2001 North 70 deg 29 min 27.49 sec East 148 deg 41 min 35.81 sec 283.23 deg Doug Wilson Mark Lindloff Reg Wilson Tom Mansfield Gavin Kidd Bob Clump Joe Polya Mike Dinger Ken Lemley Northstar 107 Alaska North Slope 5peral""y - sun CRIL..I..I N 1:5 5EAVIC:E5 I I f I I [ [ I I [ I I I [ I [ [ I [ f (' 8P Exploration - Northstar NSO9 Daily Summary December 2, 2001: Prepared pad & rig for move to NS-09 by leveling pad utilizing laser level. Sorted out sub complex, synchronize steering, move rig 10 feet to the North. Perfonned a PJSM on Herculite & rig mat layout. Lay Herculite & set mats for sub complex with crane, lay Herculite & set mats for service complex with loader. Blew down services lines. December 3, 2001: Continued to prep rig for move to NS-09. Moved Rig and centered over the hole. Hooked up hoses on pipe rack, buttoned up the PUTZ, moved the mats and hooked up injection line. NIU Riser, installed riser through the floor and skidded the floor, R/U gerronlimo line, installed herculite & build beams, & bring BHA tools to rig floor. Held Pre-spud meeting. December 4,2001: Pre-spud meeting completed, Reviewed D-7 procedure. Continued benning around rig, changed shaker screens, PIU stabs, & tightened blades. PIU BHA to clean out conductor. Cleaned out conductor to 202' MD. Stand back one stand ofHWDP, PIU 2 collars & 1 stablizer, Drilled to 260'. Blowed down top drive & mud lines, R/U Schlumberger gyro & run. POOH to change BHA, Handle BHA # 1. Handle BRA #2. RIH to 242'. Ran Gyro. Drilled from 260' to 303'. Ran Gyro. Drilled from 303' to 452'. Ran Gyro every 30'. POOH, LID 1 joint ofHWDP. Handle BRA #2, Handle BHA #3, oriented MWD. December 5,2001: Oriented MWD & RIH. Slide, drill, & Gyro. Drill from 452' to 640'. C/O swab on #1 mud pump. Drilled from 640' to 1485'. Ran Gyro. At 1385' gyro indicated-azimuth 107.09 deg, Inclination 2.95deg. RID Gyro. C/o swap & liner on #1 mud pump. Drilled from 1485' to 1959'. No drag, or losses. Flow rate @ 700 GPM. December 6,2001: Drill & slide from 1959' MD to 3195'. Circulated sweep out of hole until clear ofBHA and up hole. Drilled from 3195' to 3415' MD. (TD). Section TD called by own Geologist as per prognosis. No drag, no losses. Some extra torque while backreaming thru slide section on stand. Circulated Sweep around and cleaned hole @ 810 GPMJ2000 PSI. Circulated 2.5 times bottoms up. Flowchecked. POOH. Wiped through build section from 2450 ft to 2070 ft. Dry Wiped. Two tight intervals @ 2270ft and 2070 ft that required extra Work. No Need to put on pumps. Maximum drag 35-40 klbs. After Wiping- hold good. POH W/HWDP. December 7, 2001: Layed down BRA and the bit was in good shape. Some congealed clay was found in water course stabilizers. Cleared the rig floor of all non-essential tools and equipment and changed out bails. Rigged up to run 13.375" casing. Did a PJSM on running casing. Made up 13.375" landing joint and confirmed space out. Drift riser section and landout. (First divertless rig up, new riser section and modifications made to landing joint after incident with Frank's tool in June 2001) Conducted a safety meeting with drill crew, Discussed running procedures and Frank's Modified tool. Made up Shoe track, crossed the threads and resolved , the same. Collars hanging up at the landing. Checked floats and they were okay. Ran with hand slips, again collars hanging up on landing ring. Rotated the pipe past the restriction with rig casing tongs. Found out the rig was off alignment. Ran 13.375" 681b/ft casing to 1200 ft (33 joints) and there was an injury. The injury was to Dean Johnson (floorhand) finger between the jaws of casing tongs. The rig was shut down and the crew debriefed and the incident was investigated. Ran 13.375" 681b/ft casing to 2640 ft, it began taking weight. Worked through tight hole from 2640 to 2940 ft. Taking 75 klbs of down weight to move pipe. Tight hole was in the region of higher dog legs. (3-4 degs DLS) After working through, the pipe ran freely down to 3490' and landed out at 2300 hrs. Tight hole the last 50 ft, some packing off was experienced. PIU 440 klbs with no break over. Took 100klbs to landing hanger. Rigged down Franks tool Rigged up cement head. Staged up pumps up gradually and commenced conditioning of well bore for cementing operations. Cement 13 3/8" casing per well plan. . I I ( I I I r ( I ( r ( I I ( I I I I ( ( SP Exploration - Northstar NSO9 Daily Summary December 8, 2001: Displace cement with 9.4 ppg mud. Did not bump plug. No mud losses. Flush and drain BOP's. Lay down riser assembly nipple up tubing spool. Nipple up BOP's. December 9, 2001: Attempt to nipple up riser- cannot align. Skid rig to north. Nipple up riser. Test BOP's. Pick up and make up BRA #4. December 10,2001: Continue to make up BRA #4 12 ~"assembly. Run in hole to 281 I' MD. Wash down from 2811-3314' MD. Top of cement ar 3280' MD. Test 13 3/8" casing to 3500 psi-OK. Drill out float, casing shoe and shoe track from 3314' to 3415' MD. Drilled 30' of new fonnation. Displace mud system with 9.1 ppg mud. Perfonn Fonnation Integrity Test -OK. Drilling 12 ~" hole from 3344 to 4427' MD. Maximum gas while drilling this interval was 48 units. Pump sweep. Pull out of hole to 13 3/8" casing shoe for short trip. Run in hole and circulate bottoms up with maximum short trip gas of 75 units. December 11,2001: Drilling from 4427-5661' MD. Circulate sweep. Short trip to 4427" MD with no problems. Run in hole. Maximum short trip gas 161 units. Drill from 5561-6596' MD. Maximum gas seen at 6315' MD of 294 units. December 12,2001: Drilling from 6596-7187' MD. Maximum gas 98 units at 7146' MD. Pumped high viscosity sweep and circulated bottoms up. Trip out of hole from 7187' MD to 5700' MD. Monitor well. Trip out of hole to 13 3/8" casing shoe. Monitor well. Continue trip out of hole . Lay down BRA #4. Change out wear ring in BOP. Make up BRA # 5. Trip in hole. Shallow test MWD-failed. Continue Trip in hole. Retest MWD-tàiled. Trip out of hole to change out MWD. December 13, 2001: Lay down MWD from BRA #5. Pick up new MWD and run in hole with BRA #6 to 7187' MD. Circulated bottoms up to condition mud and recorded maximum trip gas of229 units. Drill from 7187-8220' MD. Maximum gas 60 units at 8069' MD. December 14,2001: Drill from 8220-9202' MD. Maximum gas 127 units at 8910' MD. Short trip to 133/8" casing shoe. Run in hole to 9202' MD . Circulate bottoms with maximum short trip gas of 246 units. Drill from 9202-9390' MD. Maximum gas52 units at 9276' MD. December 15,2001: Drilling from 9390-10816' MD. Maximum gas 538 units at 10516' MD. December 16,2001: Drill from 10816-11545' MD. Maximum gas of837 units at 11015' MD. 9 5/8" casíng point picked by geologist at 11545' MD. Short trip to 9100' MD without problems. Run in hole to bottom at 11545' MD. Circulate bottoms up with maximum short trip gas of 1749 units. Trip out of hole. Pulled tight around 11300' MD. Continue pull out of hole. December 17,2001: Continue to pull out of hole to surface. Lay down BRA #6. Rig up to run 95/8" casíng. Run in hole with 9 5/*' casing Lost mud to Schrader Bluff fonnation. December 18, 2001: Finish running 9 5/8" casing. Landed casing at 11518" MD. Rig up cementing apparatus. Perfonn cement job as per well plan. Rig down cementer. Test BOP's. December 19,2001: Test BOP's. Cut and slip drilling line. Assist NS29 in fluid pac. Pick up BRA #7 for drilling 8 Y2" hole. I I I I I I I I ( I ( ( ( I ( I I I I ( ( 8P Exploration - Northstar NSO9. Daily Summary December 20,2001: Run in hole to 10422' MD. Stop to replace blower and solenoid on top drive. Run in hole. December 21, 2001: Perform 30 minute casing pressure test to 4300 psi-OK. Started drilling cement, torque problems while drilling cement in 9 5/8" casing. Drill out cement and 20 foot of new formation to 11565' MD. Perform Leak off test-OK. Circulate around new mud until 11.3 ppg was established in both MW in and MW out. Drill from 11565-11943' MD December 22,2001: Drilling 11943-12910' MD. 7" liner casing point picked by geologist at 12910' MD.Circulate bottoms up with maximum gas of78 units. Short trip to 11948' MD. Monitor well. Run in hole to 12890' MD. Circulated bottoms up with a weighted sweep to clean hole. Some splintered pressured shale seen on bottoms up. Maximum short trip gas of 554 units. December 23,2001: Trip out of hole. Laydown BRA. Rig up casing equipment. Run in hole with 7" liner on 5" drill pipe to 7963' MD. December 24,2001: Continue to run in hole with 7" liner. Ran to 9 5/8" casing shoe and established circulation. Continue to run in hole with 7" liner. Liner taking weight at approximately 11780' MD in Miluveach formation. Took lOOK of weight when going in and pulled 400K when pulling up. At 11958' MD decision to Pull out of hole with 7" liner on 5" drill pipe before sticking 7" liner. Pull out of hole with 7" liner on 5" drill pipe. Run in hole with 8 Y2" hole opener to 4740' MD. December 25,2001: Run in hole with 8 Y2" hole opener to 11555' MD. Circulate and weight up mud from 11.3 ppg to 11.8 ppg. At bottoms up 110 units of trip gas was observed. Start reaming to bottom. Tight reaming from 11780-11980' MD in Míluveach formation and around tàult in Kingak formation (approx 12340-12430' MD, Fault is at 12375' MD). From shaker samples in interval 12340-12500' MD large amount of shale cuttings observed-some I" diameter. Maximum gas while reaming was 190 units. Reamed to bottom at 12910' MD. Circulated a sweep with maximum gas of 102 units. December 26,2001: Reamed to bottom and circulated out sweeps. Ran wiper trip to 9 5/8" casing shoe. Ran to bottom. Pump 2 sweeps. Maximum short trip gas 133 units. Trip out of hole slowly first 15 stands. Trip out of hole and lay down hole opener. Pick up 7" liner and run in hole on 5" drill pipe to 9 5/8" casing shoe. Circulate liner and drill pipe volume. December 27, 2001: Run 7" liner to bottom and set at 12904' MD. Circulate and condition mud. Maximum gas 93 units. Perform cement job as per well plan for 7" liner. Trip out of hole with 5" drill pipe. Test BOP's. Slip and Cut drilling line. Prepare to pick up BRA #9. December 28, 2001: Pick up BRA #9 6 1/8" drilling assembly, 4" HWDP and 4" drill pipe. Run in hole with 5" drill pipe Drill out cement and 20' of new hole to 12930' MD. Perrow Formation Intergrity Test with 11.8 ppg mud-OK. Displace 11.8 ppg mud with 9.3 ppg Drill-in fluid. Drill from 12930-12968' MD. Maximum gas of 1258 units at 12938' Md from Sag River formation. December 29, 2001: Drill ahead from 12968-13141' MD. Began losing mud at 120 bblslhr while pumping. Pulled up into 7" casing shoe. Monitored welll, losing 60 bblslhr static. Stopped and rebuilt mud volume to 1200 bbls. Drilled from 13141-13235' MD with mud losses of250-300 bbls/hr and partial returns. Monitor well with static losses of 80 bbls/hr. I I ( I ( ( I I ( ( I I ( I I I I I I ( ( SP Exploration - Northstar NSO9 Daily Summary December 30, 2001:Build mud volume. Drill from 13235 to T.D. of 13425' MD while losing approx. 200 bblslhr. static losses of 100 bblslhr and partial returns. T.D. in Kavik formation picked by geologist. Build 9.1 ppg brine to keep back side filled. Pull out of hole. Pump LCM pill at 12000' rvID. Continue pull out of hole- hole fill requiring 60 to 110 bblslhr brine. December 31, 2001: Finish pull out of hole. Mud loss decreased to 30 bblslhr once out of hole. Rig up to run 4 Y2" liner. Mud loss continued at 30 bbls/hr while running liner until close to bottom, where losses were from 200-100 bbls/hr. Rig up cement head and staged up circulation. Returns were 80-900/0 . Cemented liner with brine returns to surface. Circulated bottoms up through drill pipe with cement ( 1-2 bbls.) to surface after 6500 strokes and a maximum gas of 76 units. f BP Exploration - Northstar NS09 Daily Operations (LA.D.C.) ( I Time El apsed Code Operations Breakdown (hrs) Time [ 12/02/01 I 1400-1530 1.50 P Prep pad & rig for move. Level pad utilizing laser level. 1530-1630 1.00 P PJSM on rig move 1630-1900 2.5 P Sort out sub complex, synchronize steering, move rig 10" to the North. l 1900-1930 0.5 P PJSM on Herculite & rig mat layout. 1930-0000 4.5 P Lay Herculite & set mats for sub complex with crane, Lay Herculite & set mats for service complex with loader & blow down services lines. I 12/03/01 0000-0300 3.0 P Prep Rig for Move I 0300-0900 6.0 P Move Rig and center over hole. 0900-1600 7 P Hook up hoses on pipe rack, button up PUTZ, move mats, hook up injection line. I 1600-1900 3 P NIU Riser, install riser through floor, skid floor 1900-2300 4 P RID gerronlimo line, install herculite & build beams, & bring BRA tools to rig floor. I 2300..2330 0.5 P Pre-spud meeting. 2330-0000 0.5 P Continue Bringing BRA tools to floor. I 12/04/01 0000-0030 0.5 P Pre..spud meeting, Review D- 7 procedure. I 0030..0400 3.5 P Continue benning aroun4 rig, change shaker screens, P /U stabs, & tighten blades. 0400-0630 3.5 P PIU BRA to clean out conductor. Clean out conductor to 202' MD I 0630..0900 2.5 P Stand back one stand ofHWDP, PIU 2 collars & 1 stablizer, Drill to 260'. 0900-1100 2.00 Blow down top drive & mud lines, RID Schlumberger gyro & run. 1100-1200 1 POOH to change BRA I 1200-1330 1.5 Handle BHA # 1. 1330-1630 3.0 Handle BHA #2. 1630-1700 0.5 Rill to 242' I 1700-1800 1.0 Gyro 1800-1830 0.5 Drill from 260' to 303' 1830-1900 0.5 Gyro. I 1900-2130 2.5 Drill from 303' to 452'. Gyro every 30'. 2130-2200 0.5 POOH, LID 1 joint ofHWDP. 2200-2300 1.0 Handle BRA #2 I 2300-0000 1.0 Handle BRA #3. Orient MWD. I I ¡ 12/05/01 I 0000-0200 2.0 0200-0500 3.0 0500-0630 1.5 I 0630-1800 11.5 1800-1830 0.5 1830-1900 0.5 I 1900-2000 1.0 2000-0000 4.0 I 12/06/01 0000-1400 14 1400-1430 0.5 ( 1430-1900 4.5 ( 1900-1030 1.5 2030-2330 3.0 ( ( 2330-0000 0.5 12/07/01 ( 0000-0300 3.0 0300-0600 3.0 ( 0600-0830 2.5 ( 0830-0930 1.0 ( 093-1300 3.5 f 1300-1600 3.0 1600-1630 0.5 I 1630-2000 3.5 2000-2130 1.5 I 2130-2300 1.5 I 2300..2330 .5 2330-0000 .5 I ~" '1~ BP Exploration - Northstar NSO9 Daily Operations (I.A.D. C.) ( Orient MWD & RIH Slide, drill, & Gyro. Drill from 452' to 640'. C/O swab on # 1 mud pump. Drill from 640' to 1485'. Run gyro. At 1385' gyro indicates-azimuth 107.09 deg, Inclination 2.95 deg. RID Gyro. C/o swap & liner on #1 mud pump. Drill from 1485' to 1959'. No drag, No Losses. Flow Rate @ 700 GPM. Drill & slide from 1959' MD to 3195' Circulate sweep out of hole until clear ofBHA and up hole. Drill from 3195' to 3415':MD. (TD). Section TD called by own Geologist As per prognosis. No drag, no losses. Some extra torque while back reaming thru slide section on stand.. Circulate Sweep around and clean hole @ 810 GPM/2000 PSI. Circulated 2.5 times bottoms up. Flowcheck. POOH. Wipe through build section from 2450 ft to 2070 ft. Dry Wipe. Two tight intervals @ 2270ft and 2070 ft that required extra Work. No Need to put on pumps. Maximum drag 35..40 klbs. After Wiping- hold good. POHW/HWDP. Lay down BRA, Bit in good shape. Some congealed clay in water course stabilizers. Clear rig floor of all non-essential tools and equipment. Change out bails R/U to run 13.375" casing. PJSM. MID 13.375" landing joint and confinn space out. Drift riser section and landout. (First divertless rig up, new riser section and modifications made to landing joint after incident with Frank's tool in June 2001) Conduct safèty meeting with drill crew, Discuss running procedures and Frank's Modified tool. MIU Shoe track. Crossed treads, resolved the same. Collars hanging up @ landing. Check floats. Run with hand slips. Collars hanging up on landing ring. Rotate pipe past restriction with rig casing tongs. Rig off alignment. Run 13.375" 681b/ft casing to 1200 ft (33 joints). Injury. Injury to Dean Johnson - floorhand. Pinched finger between jaws of casing tongs. Shut rig down and debrief/investigate incident. Run 13.375" 68 Ib/ft casing to 2640 ft. Taking weight. Work thru tight hole from 2640 to 2940 ft. Taking 75 klbs of down weight. To move pipe. Tight hole in region of higher dog legs. (3-4 degs DLS) Run pipe freely down to 3490. Land out at 2300 ms. Tight hole last 50 ft. Some packing off PIU 440 klbs with no break over. Taking 100kibs to landing hanger. Rig down Franks tool. RID cement head. Stage pumps up gradually and commence conditioning of well bore for cementing operations. [ I I I I I I I I I I I I I I I I I I 12/08/01 0000-0230 0230-0500 0500-0630 0630-0830 0830-0930 0930-1030 1030-1330 1330-1900 1900-1930 1930-2000 2000-2200 2200-2230 2230..2300 2300-0000 12/09/01 0000-0400 0400-0830 0830-0930 0930-1030 1030-1800 1800-2100 2100-2200 2200-0000 12/10/01 0000-0130 0130-0200 0200-0230 0230..0430 0430..0530 0530-0700 0700-0830 0830-0930 { ( BP Exploration - Northstar NS09 Daily Operations (LA.D.C.) 2.5 Condition mud for cementing operations. PJSM for cement job while circulating. C/O drive socket on cuttings drag chain. Ramp up circulating rate to 1.5 BPMI 370 psi. Circulate surface to surface X 2 while coordinating power contingencies, preparing cement tanks and prepare G & 1. Pump cement per program - 20 bbls, of water - 75 bbls alpha spacer - 520 bbls 10.7 lead cement - 115 bbls, 15.8 tail cement. Displace cement with 9.4 ppg mud at 6-10 BPM. Pumped a total of5640 strokes. Did not bump plug. No losses. Cement returns after 2120 strokes 285 bbls of excess cement. Flush & drain stack. Flush & blow down cement lines LID landing jt. Clear tools off of rig floor & clean up. C/O bales & elevators. PJSM. LID riser assy . (3 pieces) & lay down mouse hole. NIU tubing spool remove wing valves. Reset tubing spool. Test gray lock to 1,000 psi for 5 min. Reinstall sweeps & wing valves. P /U single gate with mud cross Training on Sweeney torque tool. NIU single gate & mud cross. Clean up tools & cellar while NS-l 0 well kill operations are completed. PJSM on lifting BOP's out of overhead cradle. Move BOP's to well & nipple up. 2.5 1.5 2.0 1.0 1.0 3.0 5.50 0.50 0.50 2.0 .50 .50 1.0 4.0 4.5 Nipple up BOPE, choke and kill lines, turn buckles. Unable to install riser, conductor and wellhead @1.9 degs, rig centred over. Well but because of angle at wellhead- unable to rig up. Pull mousehole. Skid Rig to the north. Install Riser and tighten turnbuckles. Function BOP's sand run test plug. Test BOPE to 250/5000 psi for 5/10 mins. Annular to 250/3500 psi. Blow down lines. Pull Test plug and install wear ring. AOGCC : Chuck Sheeve Waived witness of test. PJSM. Slip and cut 102 ft of drilline. PJSM. Service top Drive. M/U 12.114 Milled Tooth drilling assembly and surface test MWD. 1.0 1.0 7.5 3.0 1.0 2.0 1.5 .50 .5 2.0 MID 12. '14" BRA . Shallow test MWD, Motor. PIU 26 joints ofHWDP. RIH to 2,8190 ft. Wash down and tag cement at 3,280 ft (34 ft high). Drill to float collar @ 3,314 ft. CBU until Mwin Mwout @9.0ppg. R/U and test 13.3/8 casing to 3,500 psi / 30 minutes. 7 bbls pump/ return. Hold well control discussion with rig crews while testing. Drill shoetrack and 20 f of new hole to 3,435 ft- cement firm. Commenced displacement. Displace to new 9. a ppg mud. 1.0 1.5 1.5 1.0 [ [ I I I I I I I I I ( ( I ( ( I I I 0930-1000 1000-1100 1100-1930 1930-2030 2030-2100 2100-2200 2200-2300 2300-2330 2330-0000 12/11/01 0000-1100 1100-1200 1200-1400 1400-0000 12/12/01 0000-0900 0900-1030 1030-1330 1330-1530 1530-1800 1800-1900 1900-1930 1930-2300 2300-2330 2330-0000 12-13-01 0000-0 100 0100-0300 0300-0500 0500-0600 0600-0730 0730-0830 ( ~( BP Exploration - Northstar NS09 Daily Operations (LA.D.C.) .5 Conduct FIT to 12.5 ppg EMW. 600 psi surface pressure. 3.9 bbls pump! return. Empty L- tanks. Drill from 3435" to 4426. No drag, no losses. Flowrate 780 gpm. Pumping sweeps every 300to 400ft. Circulate out sweep. Monitor well- blow down mud lines. POR to shoe. Tight at 3950" to 3800". Dry wipe. 25,000 over-pull. Work on IBOP air valve. Frozen solenoid RIR to 04331" Fill pipe & wash down to 4427" 1.0 8.5 1.0 .5 1.0 1.0 .5 .5 11 Drill ahead 12.25" hole from 4426" to 5661'. P-rates of 200-350 ftlhr. Sweep hole every 300 to 400 ft. Drag and torque increase on last three connections. Vary parameters, no good. Pump weighted, viscous sweep to surface - noticeable increase in cuttings. Clean up shakers. Flow check. Make a check trip back to old hole @ 4,426 ft. Tight spots @ 5,361 Ft. 5160 ft and 5040 ft. (29-30 klbs over pull). Wipe thru - OK. RIH without problem. Drill ahead from 5,661 to 6,610 ft. Torque increases and slight over pulls ofT bottom on first joint of each stand. RIH No trouble. Pump 60 bbls high VIS fiber sweep every 400 ft.. Torques and over pulls continue on first single of back reaming. No losses, 780 GPM and 110 RPM. 1 2 10 9.0 Drill 12.1!4" hole from 6,610 ft to 7,187 ft. Still torque on connections- correlates to back to 2nd string stabilizer @ 48 ft from bit after that ok. Average bit ROP trending downwards since midnight Sweep hole clean @780 GPM/ 2300 psi. Flow check POOH. Average drag 10-15 klbs. Maximum @ 25 klbs. Hole in good shape. Flow check @ 13.3/8"shoe @ 3/397 ft. POOH to BRA. Layout motor, bit and MWD tool. Bit 2-3 and 1/16" DIG. (1/2 hour to flush tools with fresh water) Change out wear bushing. No obvious worn areas-looked ok. Clean up rig floor and any unnecessary tools. MU BRA # 5 - 12.25" PDC bit. RIH WI BRA #5 to 377' for shallow test. Not functioning. Blow down mud lines. TIH WI HWDP to 1020" . Begin retest ofMWD. 1.5 3.0 2.0 2.5 1.0 .5 3.5 .5 .5 1 2 2 1 1 1 Shallow test MWD - No good. POOH and change-out Tool. Reorient ate motor. RIH to 13.325" shoe @ 3397" Service Top Drive @ shoe. RIH to 6,080 ft. Tight Wash/Ream thru tight hole from 6,080 ft to 6,248 ft. Circulate bottoms up and work/rotate pipe. Tight interval correlates with sandstones at top of I l ( ~ BP Exploration - Northstar NS09 ! Daily Operations (LA.D.C.) Ugnu. ECD dropped from 10.7 to 9.9 ppg after cleaning up. I 0830-1000 1.5 Run in hole and wash last two stands. 1000-0000 14.0 Drill ahead from 7,187 to 8,193 ft. Torque 14-15 kft/lbs. @ 60 RPM Keeping RPM down through the Schrader). Torque increasing to 17-18 klb/ft I Total ROP = 114 fph. Total steering time + 2.6 hrs/ Total rotating time 6.3 hrs Total flow running 750-780 gal/min. Pumping viscous sweeps every 500 ft. FV = 60-62 WIMW running 9.4 to 9.6 ppg and ECD F/9.8 - 10.1. I 12/14/01 0000-1430 14.5 Directionally Drill 12.1/4" Hole trom 8,193 ft to 9,201ft. No drag, No losses. ECD holding steady @IO.3 ppg at stand down. Flowrate 780 GPM. Assembly I started dropping at 0.6 deg/100 ft in coville shale. Tending to build above the Colville. 1430-1530 1.0 Sweep hole ready for wiper trip. Conducting wiper trip based on footage I (2100) ft and time (28 hrs). Circulate @ 780 GPM/ 2600 psi. . 1530-1830 3.0 Conduct a wiper trip to 6,000 ft. Average drag 10- 15 Klbs 8,023",7,650??and 6,085". Wiper out. Hole generally in good shape. I 1830-2100 2.5 RIH to 9,201" Wash last two stands to bottom. 2100-0000 3.0 Drill ahead from 9,201" to 9390". Torque on 14-15k / off I2k @110 RPM. I 12/15/01 0000-0800 8.0 Drill 12.1/4 "hole from 9,390ft to 9,729 ft. No Drag, No losses. Flowrate@ I 780 GPM. Sliding about 10% to get required drop above HRZ. 0800-0900 1.0 Washout on number 1 Mud pump manifold. Work pipe and fix same. 0900-0000 15.0 Drill ahead from 9,729ft to 10,818ft into HRZ. Preformed Baranex fluid \ I bleed in treatment at 10,500 ft wi 9.6 ppg MW prior to entering HRZ. PDC Bit not dropping as dd figured while rotating, so angle running a little high @ 30.10 degrees. Total ROP running 102 fph while rotating Rap I average 120 fph. Drilling w/15-17k wob and torque running 17-19k. 12/16/01 I 0000-1100 11.0 Dri1112.25" hole from 10,818 to 11,545 ft - sectionTD. No drag, no losses 825 units of gas on bottoms up from Kuparuk C. Off bottom torque @ 18,000 ft lbs with 2% lubricant. Drilling torque is 23000 ft/lbs drilling with 400 psi ( differential motor pressure. Drilling with 800 GPM. 1100-1330 2.5 Sweep hole clean with a weighted sweep @ 800 GPMl3000 psi 1330-1700 3.5 Conduct wiper trip back to 9,000 ft. Average drag 10-15 klbs. Hole in good I shape, 20 ft of fill on bottom. Wash thru. 1700-1930 2.5 Circulate bottoms up and condition mud @ 800 GPMl3050 psi. 1749 units of gas circulated up from wiper trip. I 1930-000 4.5 POOH< on the second stand, top of the Miluveach @ 11,400, drag was 35-40 klbs over. RIH smooth, work thru area several times and TOH. Pull 10 stands, hole volume good. Pump dry job. POOH, prepare to run 9.625" casing. I 12/17/01 0000-0300 3 POOH drillpipe and HWDP. SLM within 5 ft of tally. Hole fill correct. I 0300-0500 2 Lay down 12.25" BHA. Bit in good shape - good candidate for rebuild. 0500-0530 0.5 Clean rig floor of all unwanted equipment. 0530-0600 0.5 Pull wear ring- no unusual wear indicating well head and alignment problems I 0600-0630 0.5 Change control lines on stack to operate 9.625" casing rams, function test I ( f BP Exploration - Northstar NS09 I Daily Operations (LA.D.C.) same, good. I 0630-0830 2.0 P JSM and RJU to run 9 5/8" casing. Change out bails. R/U Franks tool and handling equipment. 0830-0900 0.5 Hold safety meeting on running casing. Review past incidents. r 0900-1000 1.0 Make up 9.625" shoetrack, bakerlok and check floats, OK. 12/19/01 r 0000-0 100 1.0 Finish FP 9-5/8" x 13-3/8" wi 120 bbls diesel. Hold PJSM for Fluid packing NS-29 tor production ops. 0100-0200 1.0 NS-29 Fluid pack tubing for Production Operations: r 0200-0400 2.0 PT low wI cement line wI neat methanol from rig manifold to NS-29 companion valve. No- good. Blow down cement line and fix leak. PT low 250 psig- good. PT high 4000 psig-- leak. r Continue NS-29 Fluid pack tubing for Production Operations: Bleed and replace hardline seal. PT low again- leak. Bleed and replace 2" chicksan. PT low- good. PT high leak at NS-29 side hardline. Bleed I and fix. PI' low- good. PT high- good. 0400-0700 3.0 Continue NS-29 Fluid pack tubing for Production Operations: Open up companion on NS-29. Start pumping diesel @ 1bpm wI positive ( pressure (plug set in tailpipe- tubing bleed off to atmosphere). Pump 115 bbls diesel. Switch to 3 bbls methanol spacer-- prevent hydrates. Switch to 100 deg F plus heated seawater from G&I. Fill tubing wi approximately ( 350 bbls seawater. Shut-down Whp= 1200 psig. Clear cement line with methanol. Bleed and clear cmt line. Rig crew servicing top-drive while NS 29 I pumping operations taking place. 0700-0730 .05 Attempt to pull test plug. Stuck. Double-check LDS 0730-1130 4.0 Blow down stack. Reverse.. 1130-1230 1.0 R/U and test 9-5/8" casing to 2000 psig for 30 min. Good I 1230-1630 4.0 Hook up and test kill line. Pull test plug and drain stack. 1630-1800 1.5 Trouble shoot top-drive blower. r 1800-2030 2.5 PJSM. Slip and cut drill line. 2030-0000 3.5 MU BRA #7 (8.5" Hycalog DS70 bit) I 12/20/01 0000-0030 0.5 TIH w/HWDP wi BRA#6. 0030-0130 1.0 Thaw out mudline. I 0130-0200 0.5 Surface test MWD and Blow down lines. 0200-0730 5.50 TIH to 10425', Fill DP and Blow down lines. 0730-2130 14.00 Change out Top Drive blower motor. r 2130-0000 2.50 Change out Top Drive oil pump motor. 12/21/01 I 0000-0130 1.5 Replace oil motor. Safe Top Drive in and test. OK 0130-0200 0.5 TIH To 11185' 0200-0330 1.5 Wash down from 11185' to 11430'. Cement stringers from 11258'. Collect I rubber from plug off of shaker wi a little cement coming back on shakers. 0330-0400 0.5 Circulate until MW in = MW out 9.9 ppg. Returns have cleaned up. Completed dumping cement contaminated mud. I 0400-0600 2.0 Perform 9.625" casing pressure test twice. First time load cell sensor for [ ~" ( .~ BP Exploration - Northstar NS09 I Daily Operations (LA..D.C.) chart recorder still not reading the same as other pressure sensors. [ 0600-0700 1.0 Conduct third try at casing test to 4300 psi w/9.2 MW (20 PSIG fall off in 30 minutes) Hold safety meeting and discuss well control with rig crew before drilling out the shoe track. I 0700-0930 2.5 Drill from 11545' To 11564' (Trying to pack off) Torque up to 28K. 930-1130 2.0 Drill shoe-track adding mud lube to reduce the torque. Experience bit balling when drilling new formation. Pump walnut/SAPP sweep and cure bit balling I problem by washing from 11518' to 11545'. 1130-1530 4.0 Bleed in 15.2 ppg spike mud and condition MW to 11.2 ppg. 1530-1600 0.5 Perform LOT> LO @ 1940 w/11.2 ppg MW. With shoe depth of 11519' I MD 9428' TVD, LOT= 15.15 ppg EMW. 1600-1800 2.0 Wash and ream back. 1800-0000 6.0 Drill ahead though the Milueach from 11564' to 11942',just above the top I" Kingak, Bit is dropping approximately 1 degree/100' through shale. Rotating 80 rpm' s. I 12/22/01 0000-1500 15 Drill from 11942 to 12910.7'. Pump sweep at 12430'. 1500-1630 1.5 Circulate high vis sweep surtàce to surtàce. 1 1630-1800 1.5 Wiper trip. 1800-2000 4.0 Replace swivel packing. Lubricate Top drive and drawworks. Test swivel. 2000..2230 2.5 Rih w/ 15 stands. Tag fill @ 12871' (39' high). Wash to bottom. [ 2230-0000 2.5 CBU. Recover splintered shale. I 12/23/01 0000-0200 2.0 Condition mud and circulate viscous sweep surface to surface. Have 1 some splintered shales coming across shakers. Pump weighted sweep surface to surface- returns look much better. Small amount of shales return w/ weighted sweep. Drop 2.25" hollow rabbit. 0200-1200 10.0 POOH off bottom slow (30 fpm) being careful not to swab. PUW's [ through open hole much better than on wiper trip. Max pull 370k. Flow check at shoe. TOH. I 1200-1400 2.0 PJSM. Lay down BHA#7. 1400-1500 1.0 RU to run 7" 26# L-80 MOD BTC casing. 1500-1830 3.5 PJSM. MU 7" liner assembly (Float shoe, float collar, 38 jts 7" 26# L-80 I liner wI RH turbolator and stop ring, 7"x 9-5/8" liner hanger, and 7" x 9-5/8" ZXP liner top packer). 1830-0000 5.5 RIH w/ 5" DP and 7" liner assembly to 7300' by midnight. [ 12/24/01 [ 0000-0600 6.0 RIH with liner on %' DP to 9 5/8 casing shoe at 11519' MD. Filling every 11 stands. 0600-0700 1.0 Circulate one dp and liner volume while MU cement head with TIW valve [ and one each 15' and 10' 5" dp pups. LD one single for circ down the last joint. 0700-0800 1.0 Run in open hole with liner to 11908' MD. First 2 stands RIH with no [ problems and no drag; however, while RIH with stands 3,4 and 5 the drag I I I 0800-0900 1.0 I 0900-1000 1.0 1000-1200 2.0 I 1200-1730 5.5 I 1730-1800 0.5 1800-1830 0.5 1830-2030 2.0 I 2030-2200 1.5 I 2200-2230 0.5 [ 2230-2400 1.5 I 12/25/01 0000-0600 6.0 0600-1030 4.5 I 1030-2400 13.5 I 12/26/01 I 0000-0 100 1.0 I 0100-0330 2.5 I 0330-0430 1.0 I I 0430-0630 2.0 I 0630-0830 2.0 I f BP Exploration - Northstar NS09 Daily Operations (LA.D.C.) f increased from 5K @ 11760' IvID to 125K @ 11980' IvID. POOH with stands 5,4 and 3 while experiencing PU weights of as much as 410K which corresponds to 125K overpull. Pulled stands 2 and 1 into shoe with 5K and 10K overpull. Monitored well-Static. Cire and eond mud to verify that no gas was swabbed in while pulling out of tight hole no gas or influx at bottoms up. Pump dry job and POOH to 9700' md. Continue POOH with liner on 5" dp. Trip speed dictated by trip tank-good hole fill but pulling slower-liner packer is 8.310" and only has 0.371" clearance in the 9 5/8" 47# casing. Change over from 5" to 7" handling equipment for laying down the liner. PJSM for laying down liner. Lay down 35 jts ofT' 26# M-btrc liner. Inspected threads and found only one bad collar-change out with spare joint from pipe tally. Issue Hot Work Permit and heat up the Float Collar to back out pin end of joint 3-successfully done without galling threads. Clean offbaker lock and lay down joint 3 in pipe shed. Crossover a 15' 5" dp pup into the T' f10at collar and set back in derrick to be rerun. RD casing equipment and clear rig noor. MU BHA #8 ('Smith' Porcupine Hole-Opener) Finish RIH with clean-out BHA #8 to the 9 5/8" shoe @ 11519' md. Circulate and Condition Mud while increasing MW f/lI.3 to 11.8 ppg. wash and Ream the 8.5" hole interval across the Miluveach and Kingak and the top of the Sag-Returns from Miluveach are f1uted chips about Ÿ2" and hard. Kingak returns are a little larger flakes and chips of hard shale:. Condition mud & circulate while pumping weighted sweeps- large cuttings continue to be circulated up from reaming and hole cleaned up somewhat prior to shutting down pumps. Wiper trip to 95/8" shoe from 12910'. Worked several tight spots. PU weight was 375K. Overpulls were intermittent throughout entire hole section with 50K to lOOK. Pulled up to 500K to get by 12850' md after 3 attempts. Once in shoe-PU 330K to 225K RIH to 12910'. Stands 3 and 4 experienced stack up to lOOK. Necessary to increase running speed to 1 stand per 70 seconds to get back in hole from 11770' md to 12158' while taking weight of25 to 35K. Weight increased after this poiny whilt RIH with 21 0-220K or 5-15K drag-maintained- 1 stand per 70 seconds. Condition mud & circulate hole clean while pumping. Pumped 2 weighted sweeps with 15 ppb barotiber. Noticeable difference in the cuttings size between the 2 sweeps. Hole cleaned up during the second sweep circulating across shakers. Monitor hole for flow, drop rabbit, & POOH to shoe. This trip out of hole was much improved with average overpulls of5015K across the Kingak. Swabbed I I I I I I I I I I I I I I I I I I I 0830-1200 1200-1400 1400-1500 1500-1600 1600-1830 1830-1900 1900-2400 12/27/01 0000-0230 0230-0330 0330-0600 0600-0630 0630-0900 0900..1000 1000..1600 1600-1630 1630-1730 1730-2230 2230-2300 2300-2400 12/28/01 0000-0030 0030-0130 0130-0500 0500-0700 0700-1400 1400-1800 1800-1830 1830-1900 1900-2130 2130-2230 2230-2400 12/29/01 0000-0830 ( BP Exploration - Northstar NS09 Daily Operations (LA.D.C.) ( 3.5 2.0 1.0 1.0 2.5 0.5 5.0 well from 12300-12247' md while pulling consistently with 25-45 over- correlated to sand in top of Kingak. Wiped off during next stand and hole quit swabbing. Pulled 50K over at 12125' and 12090' rod-wiped out. Broke back at 12090 and pulled slick through the entire Miluveach section. Pump dry job & POOH. Stand back HWDP & LID BRA. PJSM on running casing, clean floor & RU casing tongs. Service top drive. RIH with 7" liner. LID casing tongs & RU to RIH wi drill pipe. RIH wI 7" liner. 2.5 1.0 RIH wi 7" liner. RIH wI 7" liner. Wt 215k in the open hole. Only exception to problem free occurred at ~ 12700' where liner stacked up on two different occasions. Liner went down on third attempt after picking back up. (PU wt 375K) Condition mud & circulate in preparation for cement job. Test cement lines to 4000 psi. Pump 51 bbls spacer followed by 67 bbls 15.9 class G cement. Displace cement with 254 bbls of 11.8 mud. Plug bumped. Set liner top packer & release. Circ B/U. LID cement head Pump dry job & POOH. LID packer setting tool. Break out safety valve in cement head & clean floor. Test BOP's Test 7" liner to 3400 psi & hold for 30 min. Slip & cut drilling line. 2.5 0.5 2.5 1.0 6.0 0.5 1.0 5.0 0.5 1.0 0.5 1.0 3.5 2.0 Slip & cut drilling line. PJSM, R/U to pick up BRA #9. M/U BHA #9, PIU 14 jts HWDP & rabbit, surface test MWD. Surface test ofMWD failed. Blow down top drive & mud lines. FlU 12 jts of 4" HT 40 drill pipe, surface test MWD-OK RIH with 4" DP & 5" DP tp 12817'. Tag landing collar at 12817' Drill shoe track from 12817' to 12904'. Drill 20' of new hole from 12910' to 12930'. Pull to shoe & perfonn FIT. FIT performed by monitoring well for 10 minutes with 11.8 ppg mud. Hole static. Pump sweep. Displace 11.8 ppg mud out with new 9.3 mud & condition. Rotate and reciprocate at 40 rpm & 340 gpm. Clean L-pit. Drill from 12930 to 12950' IvID. 7.0 4.0 0.5 0.5 2.5 1.0 1.5 8.5 Drilling fl 12950..13141' md. Lost circulation @ 13141' md-60' md below top of Ivishak which came in at 13081' md as per Sperry sun ADT engineer. r I 0830-1030 2.0 I 1030-1130 1.0 I 1130-2030 9.0 2030-2400 3.5 I I 12/30/01 0000-0900 9.0 r 0900-1030 1.5 1030-1130 1.0 I 1130..1300 1.5 1300..1500 2.0 1500.1800 3.0 I 1800-1900 1.0 1900-2100 2.0 2100-2130 0.5 [ 2130-2230 1.0 2230-2400 1.5 [ 12/31/01 0000-0130 1.5 I 0130-0400 2.5 0400-0730 3.5 I 0730..0830 1.0 0830..0900 0.5 0900..2000 11.0 I 2000-2030 0.5 2030..2100 0.5 I 2100..2130 0.5 2130-2200 0.5 2200..2400 2.0 I ( I I ( BP Exploration - Northstar NS09 Daily Operations (I.A.D.C.) ( Evaluate losses-losing 120 bph while pumping 6 bpm. Shut down pumps and line up on hole fill pump-losing 66 bph static. Monitor well instatic condition-Losses reduced to zero with no pumps on hole. Mix LCM pills and additional surface volume to prepare to drill ahead while evaluating losses. Drilling ahead fl 13141-13237' MD. Drilled from 13141-13193' md wi no losses. Started losing while drilling at 13193' md.losses started at 60 bph and gradually increased to 360 bph. Able to sustain surtàce volume while drilling. Drilling fromn 13237-13429' md. 79' rathole below OWC at 13350' md. losses were persistent through out drilling between 120 and 160 bph. Reduced fluid weight to 9.1 ppg while drilling. Wiper trip to the 7" shoe-no problems Circ and Cond Mud for running liner. POOH to 12000'. Spot 30 bbl 40 ppb baracarb 150 LCM pill and blow down top drive. POOH to 6000'. Bring casing tools to floor to warm up. Finish POOH with 5" dp. Change over to 4" handling equipment POOH with 4" dp LD 14 jts 4" HWDP and BHA #9. LID Anadrill tools & BHA. RID to run 4 '12" Vam Ace liner. Run 15 jts of 4 Yz" liner. Check floats. Fill every 5 jts. PIU ZXP packer and liner hanger. RID tubing handling equipment & RID to run liner in the hloe on DP. PIU 1 stand of 4" DP & circulate 1 liner volume. RIH to 12758' with liner on DP, filling pipe every 12 stands. Losses ranged from 70-110 bph. FlU & drift 1 jt ofDP between stands 109 & 110. Torque up cement head. PJSM on cement job. RIH with liner to 13424' & tag 4" offill. MID cement head with valves & hoses to top drive. Circulate 1 drill pipe & liner volume. Stage up slowly from Yz bpm to a maximum of 5 bpm over 2700 strokes. I r sperry-sun DRILLING SERVICES Show Report Well Name: NORTHSTAR NS09 Location: NORTHST AR AREA Operator: BP EXPLORATION ALASKA Report Prepared By: Mark Lindloff Report Delivered To: KEN LEMLEY I Depth (MD) 11139 to 11225 ft (TVD) 9095 to 9171 ft Show Report No. 1 DateITime: 12/18/01 1830 r Zone Production Analysis (From Steam-Still PPM Ratios) The production of this zone is deemed to be GAS . At approximately feet, there is a contact ( and a 1 contact at approximately feet) for a total of feet of GAS feet of show). r % Depth 11139 ft Gas x Units 156 Mud Chlorides (ppm) = 17K ---Fk)Ÿiiiñe------1;üëii(;ñ------štiõŸi--------------------------------------------- ppm ppm ppm (Steam Still PPM's in 1000's) C1 9.3 0.000" 9.3 C2 0.9 0.000:= 0,87 C3 0.310 0.000 == 0.310 C4 0.119 0.000 = 0.119 C5 0.069 0.000 == 0.069 r Hydrocarbon Ratios C1/C2 = 10.7 C1/C3 = 30.0 C1/C4 = 78.1 C1/C5 = 134.6 r r --Prõaücti~ni--------------------------------------------------------------------- Analysis Non-Producible Hydrocarbons 2 % Depth 11157 ft Gas x Units 185 Mud Chlorides (ppm) = 17K -------------------------------------==------------------------------------------ Flowline Suction Show ppm ppm ppm (Steam Still PPM's in 1000's) C1 18.2 0.000" 18.2 C2 1.70 0.000:= 1.70 C3 0.61 0.000 III 0.61 C4 0.210 0.000 == 0.210 C5 0.141 0.000 1:1 0.141 --------------------------------------------------------------------------------- Production Analysis 3 r Hydrocarbon Ratios C1/C2 = 10.7 C1/C3 = 29.8 C1/C4 = 86.9 C1/C5 = 129.4 r r- Non-Producible Hydrocarbons r % Depth 11211 ft Gas x Units 153 Mud Chlorides (ppm) = 17K ---Fiõ~rñe------1iüëik)ñ------Šh-õvv--------------------------------------------- ppm ppm ppm (Steam Still PPM's in 1000's) C1 12.9 0.000 == 12.9 C2 1.14 0.000 = 1.1 C3 0.40 0.000 == 0.4 C4 0.161 0.000 = 0.2 C5 0.130 0.000 0: 0.1 r Hydrocarbon Ratios C1/C2 = 11.3 C1/C3 = 32.2 C1/C4 = 79.9 C1/C5 = 98.9 r I --------------------------------------------------------------------------------- Production Analysis Non-Producible H drocarbons 4 % Depth 11225 ft Gas x Units 124 Mud Chlorides (ppm) = 17K --------------------------------------------------------------------------------- Flowline Suction Show ppm ppm ppm (Steam Stili PPM's in 1000's) C1 11.2 0.000 == 11.2 C2 0.97 0.000 = 0.97 C3 0.363 0.000 == 0.363 C4 0.144 0.000 == 0.144 C5 0.108 0.000 == 0.108 --Prõaüctlõñ---------------------------------------------------------------------- Analysis I Hydrocarbon Ratios C1/C2 = 11.5 C1/C3 = 30.9 C1/C4 = 77.8 C1/C5 = 103.8 I I I I show (and C1 - C2 Hydorcarbon Ratios C1 C1 - - C3 C4 1000.0 .-" ..~..~. .... "0""" ..-..... ..... """""_'_"0"" .... .... -- -- ---- .Jill"" - /' ~ I¿_:._~.. - - - - - - - ..- .. ... . .. .. . .. ... .. .. .... ..........-.. --.------... -....-...- - - - ---- NPH 100.0 Gas 10.0 Oil NPH 1.0 C1 - C2 Hydrocarbon Ratios C1 C1 - - C3 C4 1000.0 1--- "- -- - - . --" ......., I . ....-......... ..,..om.. ......, ._. ""'-. """"" ................. - .- " -- .JIll'" -- ....""... . " /' - - - . /---- - - - I ..............., no."'" ......-......,.......,... .m...., .............". - .- - - - - - - - - - - NPH 100.0 Gas 10.0 Oil NPH 1.0 I I I I I I I I r I I I ( ( I I I I I I sperry-sun DRILLING SERVICES Show Report Depth (MD) 11010 to 11030 ft (TVD) 8982 to 9000 ft Show Report No. 2 Date/Time: 12/28/01 1830 Well Name: NORTHSTAR NS09 Location: NORTHSTAR AREA Operator: BP EXPLORATION ALASKA Report Prepared By: Mark Lindloff Report Delivered To: KEN LEMLEY Zone Production Analysis (From Steam-Stili PPM Ratios) The production of this zone is deemed to be GAS . At approximately feet, there is a contact ( and a 1 contact at approximately feet) for a total of feet of GAS feet of show). 1 show (and % Depth 11020 ft Gas x Units 665 Mud Chlorides (ppm) = ---Fiõvvijñë------~üCfi()ñ------Sh-õvv--------------------------------------------- ppm ppm ppm (Steam Still PPM's in 1000's) C1 32.5 0.041 = 32.5 C2 2.9 0.028:or 2.83 C3 1.350 0.082 = 1.268 C4 0.604 0.144 = 0.460 C5 0.341 0.194 = 0.147 --------------------------------------------------------------------------------- Production Analysis 2 Hydorcarbon Ratios C1 C1 - - C3 C4 C1 - C5 C1 C2 1000.0 Hydrocarbon Ratios C1/C2 = 11.5 C1/C3 = 25.6 C1/C4 = 70.6 C1/C5 = 220.8 NPH ""," -- 100.0 ......,...............-... ......----_._..~... ....-- Non-Producible Hydrocarbons "'" Depth 11030 ft Gas x Units 361 Mud Chlorides (ppm) = ---Fiõvvlfi\ë------~üëtië)ñ------Sh()vv-==------------------------------------------ Gas ppm ppm ppm (Steam Still PPM's in 1000's) C1 36.2 0.041 == 36.2 C2 3.37 0.028 == 3.34 C3 1.50 0.082 III 1.42 C4 0.667 0.144 == 0.523 C5 0.396 0.194 == 0.202 --------------------,------------------------------------------------------------ Production Analysis 3 Hydrocarbon Ratios C1/C2 = 10.8 C1/C3 = 25.5 C1/C4 = 69.1 C1/C5 = 179.0 10.0 ""'" ................ -- ..., --... .._--,.,-....., :.:----....---------' .--.. 011 NPH 1.0 Non-Producible Hydrocarbons Hydrocarbon Ratios C1 C1 - - C3 C4 C1 - C5 % Depth ft Gas x Units Mud Chlorides (ppm) = --------------------------------------------------------------------------------- Flowline Suction Show ppm ppm ppm (Steam Still PPM's in 1000's) C1 III C2 = C3 = C4 \III CS = --Prõduõtiõñ---------------------------------------------------------------------- Analysis Non-Producible Hydrocarbons 4 % Depth ft Gas x Units Mud Chlorides (ppm) = --------------------------------------------------------------------------------- Flowline Suction Show ppm ppm ppm (Steam Still PPM's in 1000's) C1 - C2 --.-----. Hydrocarbon Ratios C1/C2 = C1/C3 = ClIC4 = C1/C5 = NPH 1000.0 -. - -- -- -- -- -. .. -- ..... - . --" ............ m...... m.. ..."",..-.II'!"..-......... ..",............. -- --"'" - - - - .. -- - -- ---- - - - - . .- - - - - - - - - .. . .. .. .. . ... .. .. . .. .. .. m ......................,.. ...................,...... - - - - - - - - - - - - -- 100.0 Gas Hydrocarbon Ratios C1/C2 = C1/C3 = C1/C4 = C1/C5 = NPH 1.0 10.0 C1 = C2 = C3 == C4 = C5 == --PrõduëÐõr¡--------------------------------------------------------------------- Analysis Oil [ sperry-sun DRILLING SERVICES Show Report Well Name: NORTHSTAR NS09 Location: NORTHSTAR AREA Operator: BP EXPLORATION ALASKA Report Prepared By: Doug Wilson Report Delivered To: KEN LEMLEY Depth (MD) 12930 to 12990 ft (TVD) 10742 to 10800 ft Show Report No. 3 DatefTime: 12/28/01 1830 I Zone Production Analysis (From Steam-Still PPM Ratios) The production of this zone is deemed to be OIL . At approximately feet, there is a contact ( and a / contact at approximately feet) for a total of feet of OIL feet of show). I show (and I % Depth 12937 ft Gas x Units 1258 Mud Chlorides (ppm) = ---Fk)vvirñe~-----1;üCtiC;ñ------Shë)vv--------------------------------------------- ppm ppm ppm (Steam Still PPM's in 1000's) C1 41.9 0.790 "" 41.1 C2 7,5 0.493 == 7.04 C3 5.990 1.140 = 4.850 C4 4.290 1.380 = 2.910 C5 3.040 1.150 "" 1.890 --------------------------------------------------------------------------------- Production Analysis 2 C1 C2 Hydorcarbon Ratios C1 C1 - - C3 C4 C1 - C5 Oil ... .. ... ..... '" h...m...m............ ..............._....... """",h""""""" - -;:;;-......- '" ... '" - - ~..~ ~ ... - ...............h.......h ............,......... ... - f------- - -- I Hydrocarbon Ratios C1/C2 = 5.8 C1/C3 = 8.5 C1/C4 = 14.1 C1/C5 = 21.8 1000.0 NPH 100.0 Non-Producible Hydrocarbons I Depth 12950 ft 494 Mud Chlorides (ppm) =171 ---Fiòvviiñë-------Šüëtk;ñ------Sih"ò¥i-==------------------------------------------ Gas I ppm ppm ppm (Steam Still PPM's in 1000's) C1 27.2 0.790 = 26.4 C2 6.83 0.493 "" 6.34 C3 6.88 1.140 == 5.74 C4 5.420 1.380 == 4.040 C5 4.330 1.150 "" 3.180 Hydrocarbon Ratios C1/C2 = 4.2 C1/C3 = 4.6 C1/C4 = 6.5 C1/C5 = 8.3 10.0 NPH 1.0 I --PrôaûëÐõñ---------------------------------------------------------------------- Non-Producible Hyd rocarbons I % Depth 12970 ft Gas x Units 305 Mud Chlorides (ppm) = ------------------------------ -------------------------------------------------- Flowline Suction Show ppm ppm ppm (Steam Stili PPM's in 1000's) C1 60.9 0.790 == 60.1 C2 11.60 0.493:: 11.1 C3 10.40 1.140 == 9.3 C4 7,690 1.380 == 6.3 C5 5.460 1.150 SOl: 4.3 C1 - C2 Hydrocarbon Ratios C1 C1 - - C3 C4 C1 - C5 I Hydrocarbon Ratios C1/C2 = 5.4 C1/C3 = 6.5 C1/C4 = 9.5 C1/C5 = 13.9 1000.0 Oil - -- -- -- ... ... ' ......" """""""""'h",,, m"""_'O'!"."'h""h 'h.h"""""",,'m' ... -- ... - . - ... '" - ....'" - ~ ... ", ......~ ,'h.h.....,............. --'"..hh..h""" - -- - - - - - - - NPH [ --Prõaüc[¡õñi--------------------------------------------------------------------- 100.0 Non-Producible Hydrocarbons [ % Depth 12990 ft Gas x Units 239 Mud Chlorides (ppm) = --------------------------------------------------------------------------------- Flowline Suction Show ppm ppm ppm (Steam Still PPM's in 1000's) C1 10,6 0.790 == 69.8 C2 11.96 0.493 == 11.47 C3 9.610 1.140 == 8.470 C4 6.800 1.380 == 5.420 C5 4.860 1.150'" 3.710 --------------------------------------------------------------------------------- Production Analysis Gas [ Hydrocarbon Ratios C1/C2 = 6.1 C1/C3 = 8.2 C1/C4 = 12.9 C1/C5 = 18.8 10.0 NPH 1.0 1 sperry-sun DRILLING SERVICES Show Report Well Name: NORTHSTAR NS09 Location: NORTHST AR AREA Operator: BP EXPLORATION ALASKA Report Prepared By: Doug Wilson Report Delivered To: KEN LEMLEY Depth (MD) 13080 to 13330 ft (TVD) 10889 to 11136 ft Show Report No. 4 Date/Time: 12/28/01 1830 I I I Zone Production Analysis (From Steam-Still PPM Ratios) The production of this zone is deemed to be OIL . At approximately feet, there is a contact ( and a I contact at approximately feet) for a total of feet of OIL feet of show). I show (and 1 Depth 13250 ft 65 Mud Chlorides (ppm) = ---FrõŸVifi1ë------1iüêtlë;ñ------Šh-õŸV--------------------------------------------- C1 - C2 Hydrocarbon Ratios C1 C1 - - C3 C4 C1 - C5 1 % Depth 13130 ft Gas x Units 76 Mud Chlorides (ppm) ::: ---FiõŸVifi1ë------1iüëtië)ñ------ših-õV¡-------------------------------------------- ppm ppm ppm (Steam Still PPM's in 1000's) C1 9.6 0.790 s 8.8 C2 1.9 0.493::0 1.39 C3 2.137 1.140:m 0.997 C4 1.836 1.380::0 0.456 C5 1.315 1.150::0 0.165 --prõaüCt¡õñ---------------------------------------------------------------------- Analysis Non-Producible Hydrocarbons 2 C1 - C2 Hydorcarbon Ratios C1 C1 - - C3 C4 C1 - C5 I Hydrocarbon Ratios C1/C2::: 6.3 C1/C3::: 8.8 C1/C4 = 19.3 C1/C5::: 53.3 1000.0 011 -" ..:.~.~.~../ .... ...."m. ....m..... ...........-.-....... - ./ -- /" ./ ../' / /' /' ./' ~ fo --- .":':'..:..=.~ """"""""'",,"'..m" .... - - - '------- - 1 NPH I 100.0 1 Depth 13150 ft Gas x Units 164 Mud Chlorides (ppm) = -------------------------------------==------------------------------------------ Flowline Suction Show ppm ppm ppm (Steam Still PPM's in 1000's) C1 9.4 0.790::0 8.6 C2 1.84 0.493::0 1.35 C3 1.83 1.140 = 0.69 C4 1.600 1.380 I: 0.220 C5 1.215 1.150 II: 0.065 Gas ( Hydrocarbon Ratios C1/C2::: 6.4 C1/C3::: 12.4 C1/C4::: 39.2 C1/C5::: 132.5 10.0 NPH 1.0 ( --Prõaüêtiõñ---------------------------------------------------------------------- Non-Producible Hydrocarbons -- ---- ( ppm ppm ppm (Steam Still PPM's in 1000's) C1 13.1 0.790 c: 12.3 C2 2.88 0.493 == 2.4 C3 3.09 1.140 >= 1.9 C4 2.670 1.380 == 1.3 C5 1.990 1.150::0 0.8 --Prõaüëtiõñ---------------------------------------------------------------------- Analysis Non-Producible Hydrocarbons 4 Hydrocarbon Ratios C1/C2 = 5.1 C1/C3 = 6.3 C1/C4::: 9.5 C1/C5::: 14.6 1000.0 I. Oil -. - --- ------ ------ -. - - ' --" .........................., ..............to!!".........,.. """'....'m~:,:":::,::::,, "---:::-;;;0 - -- - - " .- - --- - - - - -II - - m..... ..m.. ...... ...... """m"""'" ......mm.."""" - -- - - - - - - - - - - NPH I 100.0 Depth 13270 ft Gas x Units 97 Mud Chlorides (ppm)::: ---Ffi)~rn~------1iüë~ë)ñ------šiiõŸV--------------------------------------------- Gas I ppm ppm ppm (Steam Stili PPM's in 1000's) C1 19.0 0.790::0 18.3 C2 3.81 0.493 I: 3.32 C3 3.600 1.140::0 2.460 C4 3.120 1.380 == 1.740 C5 2.400 1.150 =: 1.250 --Prõaüëtiõñ---------------------------------------------------------------------- Analysis Hydrocarbon Ratios C1/C2::: 5.5 C1/C3::: 7.4 C1/C4 = 10.5 C1/C5 = 14.6 10.0 NPH 1.0 I I I I r I I I I I I [ r ( [ I I I I I sperry-sun DRilliNG SERVICES Zone of Interest Report Well Name: NORTHSTAR NS09 Location: NORTHSTAR AREA Operator: BP EXPLORATION ALASKA Report Prepared By: Mark Lindloff Report Delivered To: KEN LEMLEY Depth (MD) 11139 to 11225 ft (TVD) 9095 to 9171 ft Zone Of Interest Report No. --L Show Report No. 1 DatefTime: 12/1812001 18:30:00 AM Hole Diameter: Max ROP @ 12.25 inches 159.96 ft Max Gas @ 835.00 ft Max CI @ ft Bit Type: 0 Mill Tooth ~PDC 0 Diamond 0 Other Dlnsert Avg. ROP Avg. Gas MW MW Avg. Avg. Avg. ~ ftIhr Runits Avg. Avg. PPM (in 1000's) In Out WOB RPM GPM min/ft Max % Max CI- Max C1 C2 C3 C4 C5 PPM at Max Gas - ROP Gas CI- C1 C2 C3 C4 C5 I I I I I Before During After Formation Data At MAX GAS the visual sample percentages were: 80 % Shale, 10 % The reservoir rock was a CLR-TRNSL T, L T BRN IP -c~ SANDSTOÑE the grain shape was ANGULAR TO SUB ROUNDED. Approximate visual porosity was GOOD Grain sorting was WELL and the rock cement was was INTERGRANDULAR and the secondary components in the rock fragments were: The rock hardness was FRIABLE and the sample contamination was Clyst I....1£.. % SL TST I - % The grain (crystal) size was UFN - VF and FRI % and the visual permeability was SILICEOUS/SL TY The porosity type GLAUCONITE, PYRITE NUT PLUG Depth Gas BuniU % Preliminary Gas-In-Air Show Data Oil Cut Gas Fluor? Fluor? Bun~~ C5 Y/N Y/N Depth 7t Y/N Oil Fluor? Cut Fluor? (PPM's in 1000's) C2 C3 C4 (PPM's in 10oo's) C2 C3 C4 C1 C1 C5 Y/N ------- ------- ----- ------- -------- ------- ------- ------- ------- ------- -------- ------- -------- ------- Liquid Hydrocarbon Data The liquid hydrocarbon was first detected at feet and continued through feet. The liquid phase of the mud was The liquid hydrocarbon occurred in the form of SEE BELOW and was present in the When the (waslwere) mixed with water and studied in the UV box, the liquid hydrocarbon covered % of the in color, exhibited a fluorescence and had an approximate and staining (was/was not) present. The cuttings exhibited a cut that was fluorescence. surface of the water. The oil was API gravity of ; odor was in color with a Logger's Opinion of the Show Interval TOP OF ZONE - SAMPLE EXAMINATION AND CUT - (F/11139' MD T/11157'MD) HAD TRACE OF PALE YELLOW FLUORESCENCE BUT NO CUT. MIDDLE TO BOTTOM ZONE (11157' MD-11230' MD) HAD TRACES OF DULL WHITE YELLOW FLUORESCENCE WITH A VERY SLOW MILKY WHITE CUT , TRACES OF VERY WEAK OIL STAIN WAS FOUND. PRIMARILY GAS DATA SHOWS THAT ZONE PRODUCES GAS. 100% Gas-ln~Air = 10000 units I I I ( I I ( [ [ r [ I I I I I I I I sperry-sun DRilLING SERVICES Zone of Interest Report Depth (MD) 11010 to 11030 ft (TVD) 9095 to 9171 ft Zone Of Interest Report No. -L Show Report No. 2 Date/Time: 1212812001 18:30:00 AM Well Name: NORTHSTAR NSO9 Location: NORTHSTAR AREA Operator: BP EXPLORATION ALASKA Report Prepared By: Doug Wilson Report Delivered To: KEN LEMLEY Hole Diameter: ft Max CI @ 12.25 inches Max ROP @ ft Max Gas @ ft Bit Type: DMill Tooth ~PDC 0 Insert DDiamond DOther Avg. ROP Avg. Gas MW MW Avg. Avg. Avg. rl ftlhr R Units Avg. Avg. PPM (in 1000's) In Out WOB RPM GPM mlnlft Max % Max CI- Max C1 C2 C3 C4 C5 PPM at Max Gas - ROP Gas CI- C1 C2 C3 C4 C5 I I I I I Formation Data At MAX GAS the visual sample percentages were: 60 % SST , 20 % The reservoir rock was a CLR-TRNSLT, LT BRN IP -c~ SANDSTO~ the grain shape was ANGULAR TO SUB ROUNDED. Approximate visual porosity was GOOD Grain sorting was WELL and the rock cement was was INTERGRANULAR and the secondary components in the rock fragments were: The rock hardness was FRIABLE and the sample contamination was Clyst .2Q.... % SL TST , - % The grain (crystal) size was VF FRI % and the visual permeability was SILICEOUS/SL TV The porosity type GLAUCONITE, PYRITE NUT PLUG and Preliminary Gas-In-Air Show Data Gas 011 Cut Gas 011 Cut Bun~ (PPM's in 1ooo's) Fluor? Fluor? BUN~ (PPM's in 1000's) Fluor? Fluor? Depth % C1 C2 C3 C4 C5 Y/N Y/N Depth C1 C2 C3 C4 C5 Y/N Y/N ------- -------- ------- -------- ------- -------- ------ -------- ------- -------- ------- --- --- ------- ----- Liquid Hydrocarbon Data The liquid hydrocarbon was first detected at feet and continued through feet. The liquid phase of the mud was The liquid hydrocarbon occurred in the form of SEE BELOW and was present in the When the (was/were) mixed with water and studied in the UV box, the liquid hydrocarbon covered % of the in color, exhibited a fluorescence and had an approximate and staining (was/was not) present. The cuttings exhibited a cut that was fluorescence. surface of the water. The oil was API gravity of ; odor was in color with a Logger's Opinion of the Show Interval SAMPLE EXAMINATION AND CUT - (F/11 020' MD T/11 030'MD) HAD TRACE OF PALE YELLOW FLUORESCENCE 1 VERY WEAK OIL STAIN, VERY SLOW MILKY WHITE CUT FLUORESCENCE. KUPARUK STEAM STILL GAS ANALYSIS SHOWS THAT ZONE PRODUCES GAS. 100% Gas-In-Air = 10000 units I I r (' I ( Before ( I I I ( I r I I I I sperry-sun DRILLING SERVICES Zone of Interest Report Well Name: NORTHSTAR NS09 Location: NORTHST AR AREA Operator: BP EXPLORATION ALASKA Report Prepared By: Doug Wilson Report Delivered To: KEN LEMLEY Depth (MD) 12930 to 12990 ft (TVD) 10742 to 10800 ft Zone Of Interest Report No. -L Show Report No. 3 Date/Time: 12/28/2001 18:30:00 AM Hole Diameter: ft Max CI @ Max ROP @ ft Max Gas @ 12.25 inches ft Bit Type: D Mill Tooth ~PDC D Diamond D Other Dlnsert Avg. Rap Avg. Gas MW MW Avg. Avg. Avg. R ftIhr R Units Avg. Avg. PPM (in 1000's) In Out WOB RPM GPM min/ft Max % Max CI- Max C1 C2 C3 C4 C5 PPM at Max Gas - Rap Gas CI- C1 C2 C3 C4 C5 I I I I I Formation Data At MAX GAS the visual sample percentages were: 80 % SST , 20 % The reservoir rock was a L T-DKGY, GYBRN -c~ SANDSTONE the grain shape was SUBANG TO SUB ROUNDED. Approximate visual porosity was POOR Grain sorting was POOR-MOD and the rock cement was was INTERGRANULAR and the secondary components in the rock fragments were: The rock hardness was FRIABLE and the sample contamination was Clyst '_% '_% The grain (crystal) size was VF FRI % and the visual permeability was CLAY The porosity type GLAUCONITE/CARBONACEOUS and Preliminary Gas-In-Air Show Data Gas Oil Cut Gas Oil Cut Bun: (PPM's in 1000's) Fluor? Fluor? Bun~ (pPM's in 1000's) Fluor? Fluor? Depth C1 C2 C3 C4 C5 Y/N Y/N Depth °Æ C1 C2 C3 C4 C5 YIN Y/N ------- ------- ------- ------- ------- ------- -------- ------- ------- ------- ------- -------- ------- ------- Liquid Hydrocarbon Data The liquid hydrocarbon was first detected at feet and continued through feet. The liquid phase of the mud was The liquid hydrocarbon occurred in the form of SEE BELOW and was present in the When the (was/were) mixed with water and studied in the UV box, the liquid hydrocarbon covered % of the in color, exhibited a fluorescence and had an approximate and staining (was/was not) present. The cuttings exhibited a cut that was fluorescence. surface of the water. The oil was API gravity of ; odor was in color with a Logger's Opinion of the Show Interval SAMPLE EXAMINATION AND CUT - (F/12930' MD T/12990'MD) HAD 20% MODERATELY BRIGHT ORANGE-YELLOW FLUORESCENCE. MODERATE TO FAINT YELLOW-WHITE CUT FLUORESCENCE. SAG RIVER STEAM STILL GAS ANALYSIS SHOWS THAT ZONE PRODUCES OIL 100% Gas-In-Air = 10 000 units I I I I I I r I I ( ( I I ( I I I I I sperry-sun DRILLING SERVICES Zone of Interest Report Well Name: NORTHSTAR NS09 Location: NORTHSTAR AREA Operator: BP EXPLORATION ALASKA Report Prepared By: Doug Wilson Report Delivered To: KEN LEMLEY Depth (MD) 13080 to 13330 ft (TVD) 10889 to 11136 ft Zone Of Interest Report No. --L Show Report No. 4 DateITime: 12/2812001 18:30:00 AM Hole Diameter: Max ROP @ ft Max Gas @ ft Max CI @ 12.25 inches ft Bit Type: 0 Mill Tooth DpDC 0 Diamond 0 Other ~Insert Avg. ROP Avg. Gas MW MW Avg. Avg. Avg. ~ Whr Runits Avg. Avg. PPM (in 1000's) In Out WOB RPM GPM min/ft Max % Max CI- Max C1 C2 C3 C4 C5 PPM at Max Gas - ROP Gas CI- C1 C2 C3 C4 C5 I I I I I Formation Data At MAX GAS the visual sample percentages were: 80 % SST , 20 % The reservoir rock was a TRANSL. L T -MGRY, TN -c~ SST ICON~ the grain shape was ANG TO SUB ROUNDED Approximate visual porosity was GOOD Grain sorting was POOR-MOD and the rock cement was was INTERGRANULAR and the secondary components in the rock fragments were: The rock hardness was LOOSE and the sample contamination was GONG '_% ,_% The grain (crystal) size was VF-PEB 15 % and the visual permeability was NONE The porosity type CHERT/MICPOR CHT BARACARB and Depth Gas B"": Preliminary Gas-In-Air Show Data Oil Cut Gas Fluor? Fluor? Dun~ C5 YIN Y/N Depth 0 11: Y/N 011 Fluor? Cut Fluor? (PPM's in 1000's) C2 C3 C4 (PPM's in 1000's) C2 C3 C4 C1 C1 C5 YIN ------- -------- ------- ------- ------- ------- ------- ------- -------- ------- ------- ------- ------- ------- Liquid Hydrocarbon Data The liquid hydrocarbon was first detected at feet and continued through feet. The liquid phase of the mud was The liquid hydrocarbon occurred in the form of SEE BELOW and was present in the When the (was/were) mixed with water and studied in the UV box, the liquid hydrocarbon covered % of the in color, exhibited a fluorescence and had an approximate and staining (was/was not) present. The cuttings exhibited a cut that was fluorescence. surface of the water. The oil was API gravity of ; odor was in color with a Logger's Opinion of the Show Interval SAMPLE EXAMINATION AND CUT - (F/13080' MD T/13330'MD) HAD 10% VERY DULL FAINT YELLOW FLUORESCENCE. VERY FAINT DULL ORANGE CUT FLUORESCENCE. IVISHAK LOST CIRCULATION AT 13141-PARTIAL RETURNS. STEAM STILL GAS ANALYSIS SHOWS THAT ZONE PRODUCES OIL 100% Gas-in-Air = 10000 units r I ( ( ( ( ( ( ( ( ( ( I I I I I I I ';ustomer: BP Alaska Report No.: 1 Well: Northstar NS 09 Date: 121212001 5pe....r'V- sun Area: North Slope Depth 201 . 9..--'1". !-~-LN ~-- 81!.A V Ie.. Lease: Northstar NS 09 Footage Last 24 hrs: 0 Rig: Nabors 33E Rig Activity: Move Ri~ Mudlogger's Morning Report Job No.: AK AM 11202 Report For: Polya I Clum~ Shows: Current 24 hr Avg 24 hr Max Pump and Flow Data ftIhr ftlhr ( ftIhr @ ) Pump 1 spm DH flow units unit~ ( units @ ) Pump 2 spm Total flow Deg F ( deg F @ ) Pump 3 spm AV @ rsr Pump Pres psi AV@ DC Trip Depth: Short Trip Depth Tight Spots: ppg Trip CI: ppg Short Trip CI: Feet of Fill on Bottom: Connection Gas and Mud Cut ft units ppg ft units ppg ft units ppg Drilling Breaks Depth Drill Rate during Cgl % Lithology Sst Ls Sh Gas during before after before after to to ---- ---- ---- ---- ,,:,. ~t¿i~ it Logging Engineer: Mansfield / Wilson -...;,', * 10000 units = 100% Gas In Air I I r r r I I I r [ r [ I I I I I I I ~ustomer: BP Alaska ~eport No.: 2 Well: Northstar NS 09 Date: 121312001 5pE!r'r'V- sun Area: North Slope Depth 201 Q~~'- I ~ m .....VIC.. Lease: Northstar NS 09 Footage Last 24 hrs: 0 Rig: Nabors 33E Rig Activity: Prep for S~ Mudlogger's Morning Report Job No.: AK AM 11202 Report For: Polya I Clume..- Shows: Current 24 hr Avg 24 hr Max Pump and Flow Data ftIh r ftlhr ( ftIhr @ ) Pump 1 spm DH flow units unit~ ( units @ ) Pump 2 spm Total flow Deg F ( deg F @ ) Pump 3 spm AV @ rsr Pump Pres psi AV@ DC Trip Depth: . Short Trip Depth Tight Spots: ppg Trip CI: ppg Short Trip CI: Feet of Fill on Bottom: Connection Gas and Mud Cut ft units ppg ft units ppg ft units ppg Drilling Breaks Depth Drill Rate during Cgl % Lithology Sst Ls Sh Gas during before after before after to to ---- ---- ---- ---- ~ ~~ Logging Engineer. Mansfield I Wilson 11 10000 units = 100% Gas In Air I I I I I I I [ I I I I I I I I I I I ~ustomer: BP Alaska tteport No.: 3 Well: Northstar NS 09 Date: 12/412001 Eip~r'V- sun Area: North Slope Depth 468 c flit I L.L.I N C8 .....VIC.. Lease: Northstar NS 09 Footage Last 24 hrs: 267 .--------- Rig: Nabors 33E Rig Activity: Drilling Mudlogger's Morning Report Job No.: AK AM 11202 Report For: Polya I ClumfL Shows: Current 24 hr Avg 24 hr Max Pump and Flow Data 200 ftIhr 200 ftIhr ( 550 ftIhr @ 390ft ) Pump 1 85 spm DH flow 4 units 4 unit~ ( 8 units @ 300ft ) Pump 2 85 spm Total flow 604 Deg F ( deg F @ ) Pump 3 spm AV @ rsr Pump Pres psi A V @ DC Trip Depth: Short Trip Depth Tight Spots: ppg Trip CI: ppg Short Trip CI: Feet of Fill on Bottom: Connection Gas and Mud Cut ft untts ppg ft units ppg ft units ppg Drilling Breaks Depth Drill Rate during Cgl % Lithology Sst Ls Sh Gas during before after before after to to ---- ---- ---- ---- ,"" ,~ Logging Engineer. Mansfield / Wilson * 10000 units = 100% Gas In Air r r r r r r r I [ r [ [ [ r I [ I I I ';ustomer: BP Alaska Report No.: 4 Well: Northstar NS 09 Date: 12/5/2001 5i 1:1 E!r""" V - 5iU n Area: North Slope Depth 1959 C A I L..L. t N .. . . R V Ie. . Lease: Northstar NS 09 Footage Last 24 hrs: 1,491 -------------_. Rig: Nabors 33E Rig Activity: Drilling Ahead Mudlogger's Morning Report Job No.: AK AM 11202 Report For: Gavin Kidd Shows: Current 24 hr Avg 24 hr Max Pump and Flow Data 228 ftlhr 184 ftIhr ( 578 ftIhr @ 922' ) Pump 1 spm DH flow 12 units 10 unit~ ( 18 1591 ) Pump 2 96 spm Total flow 341 Deg F ( deg F @ ) Pump 3 spm AV @ rsr Pump Pres 1650 psi AV@ DC Trip Depth: Short Trip Depth Tight Spots: ppg Trip CI: ppg Short Trip CI: Feet of Fill on Bottom: Connection Gas and Mud Cut ft units ppg ft unRs ppg ft units ppg Drilling Breaks Depth Drill Rate during Cgl % Lithology Sst Ls Sh Gas during before after after before to to ---- ---- ---- ---- RIH wI MWD, drill and slide to 1485'. 1>1 ;; Logging Engineer: T. Mansfield / R. Wilson * 10000 units = 100% Gas In Air I I r I I I I I I I [ [ I I I I I I I ~ustomer: BP Alaska ...teport No.: 5 Well: Northstar NS 09 Date: 12/612001 sper'r'V- sun Area: North Slope Depth 3415 C A I '-'-I N C8 .....VIC.. Lease: Northstar NS 09 Footage Last 24 hrs: 1,456 ------ Rig: Nabors 33E Rig Activity: POOH Mudlogger's Morning Report Job No.: AK AM 11202 Report For: Gavin Kidd Shows: Current 24 hr Avg 24 hr Max Pump and Flow Data 0 ftlhr 180 ftIhr ( 603 ftIh r @ 1986 ) Pump 1 100 spm DH flow 0 units 17 unitf ( 37 2434 ) Pump 2 100 spm Total flow 710 Deg F ( deg F @ ) Pump 3 spm AV @ rsr Pump Pres 1700 psi AV@ DC Trip Depth: Short Trip Depth Tight Spots: ppg Trip CI: ppg Short Trip CI: Feet of Fill on Bottom: Connection Gas and Mud Cut ft unRs ppg ft unös ppg ft unös ppg Drilling Breaks Depth Drill Rate during Cgl % Lithology Sst Ls Sh Gas during after before before after to to ---- ---- ---- ---- , 24 hr ReCé Continued to drill F/1959' T13195', Cir Swee out of hole, Drill ahead F13195' TI3415", Max Gas 37 units 2434' MD. Cir Swee to clean hole 817 GPM, 230 SPM, POOH, Current! La in down BHA. ,r ~ '- ";" C' Logging Engineer. R. Wilsonll M. Lindloff units = 100% Gas In Air I I r [ I I I I I I [ ( I I I I I I I Customer: BP Alaska Report No.: 6 Well: Northstar NS 09 Date: 12(112001 Sp~r-'V-sun Area: North Slope Depth 3415 C flU ....'- I N C8 . . " V Ie. . Lease: Northstar NS 09 Footage Last 24 hrs: 0 ---------. Rig: Nabors 33E Rig Activity: Cementin~ Mudlogger's Morning Report Job No.: AK AM 11202 Report For: Gavin Kidd Shows: Current 24 hr Avg 24 hr Max Pump and Flow Data 0 ftIhr 0 ftlhr ( ftlhr @ ) Pump 1 spm DH flow 0 units a unit~ ( ) Pqmp 2 spm Total flow 56 Deg F ( deg F @ ) Pump 3 spm AV @ rsr Pump Pres psi AV@ DC Trip Depth: Short Trip Depth Tight Spots: ppg Trip CI: ppg Short Trip CI: Feet of Fill on Bottom: Connection Gas and Mud Cut ft unfts ppg ft units ppg ft units ppg Drilling Breaks Depth Drill Rate during Cgl % Lithology Sst Ls Sh Gas during before after before after to to ---- ---- ---- ---- "I,~ ;'\ if. ~:. Logging Engineer: R. Wilson; ; M. Lindloff '" 10000 units = 100% Gas In Air I I r r r I I r I I I ( I r I [ I I I ':ustomer: BP Alaska Report No.: 7 Well: Northstar NS 09 Date: 1218/2001 ~pE!r""'v- sun Area: North Slope Depth 3415 C ... I L.L. I N aI .."VIC.. Lease: Northstar NS 09 Footage Last 24 hrs: 0 Rig: Nabors 33E Rig Activity: Testing BOPS Mudlogger's Morning Report Job No.: AKAM 11202 Report For: Gavin Kidd Shows: Current 24 hr Avg 24 hr Max Pump and Flow Data 0 ftIh r 0 ftlhr ( ft/h r @ ) Pump 1 spm DH flow 0 units 0 unit~ ( ) Pump 2 spm Total flow 55 Deg F ( deg F @ ) Pump 3 spm AV @ rsr Pump Pres psi A V @ DC Trip Depth: Short Trip Depth Tight Spots: ppg Trip CI: ppg Short Trip CI: Feet of Fill on Bottom: Connection Gas and Mud Cut ft units ppg ft units ppg ft . units ppg Drilling Breaks Depth Drill Rate during Cgl % Lithology Sst Ls Sh Gas during before after before after to to ---- ---- ---- ---- ~ ~; \ Logging Engineer. R. WilsonJ / M. Lindloff ,,'. * 10000 units = 100% Gas In Air I I r I I I I I I ( I I I I I I I I I ~ustomer: BP Alaska Report No.: 8 Well: Northstar NS 09 Date: 12/912001 SpE!r'r'V- sun Area: North Slope Depth 3415 c fit I L.L. I N C8 .....VIC.. Lease: Northstar NS 09 Footage Last 24 hrs: 0 Rig: Nabors 33E Rig Activity: RIH Mudlogge(s Morning Report Job No.: AK AM 11202 Report For: Gavin Kidd Shows: Current 24 hr Avg 24 hr Max Pump and Flow Data 0 ftIhr 0 ftIhr ( ftIh r @ ) Pump 1 spm DH flow 0 units a unit~ ( ) Pump 2 spm Total flow 55 Deg F ( deg F @ ) Pump 3 spm AV @ rsr Pump Pres psi AV@ DC Trip Depth: Short Trip Depth Tight Spots: ppg Trip CI: ppg Short Trip CI: Feet of Fill on Bottom: Connection Gas and Mud Cut ft units ppg ft units ppg ft unRs ppg Drilling Breaks Depth Drill Rate during Cgl % Lithology Sat Ls Sh Gas during before after before after to to ---- ---- ---- ---- :- Logging Engineer: Reg. Wilson / Mark Lindloff * 10000 units = 100% Gas In Air I I ," I I [ I I [ I I [ I I I I I I I ~ustomer: BP Alaska Report No.: 9 Well: Northstar NS 09 Date: 12/1012001 5pE!r'r'V- sun Area: North Slope Depth 4425 C ... I L..L.. I N r8 . . ... V Ie. . Lease: Northstar NS 09 Footage Last 24 hrs: 1,010 --.-. ----.-----.-----.--------.------ Rig: Nabors 33E Rig Activity: RIH Mudlogger's Morning Report Job No.: AK AM 11202 Report For: Gavin Kidd Shows: Current 24 hr Avg 24 hr Max Pump and Flow Data 313 ftIhr 98.66 ftIhr ( 728 ftlhr @ 3685 ) Pump 1 110 spm DH flow 34 units 6 unit~ ( 48 4406 ) Pump 2 110 spm Total flow 710 52 Deg F ( deg F @ ) Pump 3 spm A V <m rsr Pump Pres 18500 psi AV @ DC Trip Depth: Short Trip Depth Tight Spots: ppg Trip CI: ppg Short Trip CI: 17000 Feet of Fill on Bottom: Connection Gas and Mud Cut ft unös ppg ft unös ppg ft unös ppg Drilling Breaks Depth Drill Rate during Cgl % Löhology Sst Ls Sh Gas during before after before after to to ---- ---- ---- ---- 24 hr Rea Cont to M/U BHA#4 - RIH to 2811', wash down 2811'-3314'. To cement 3280', test 13.38" casin to 3500 si, assad, drill out shoe track from 3314' to 3415'. Drilled 30' of new formatiom, dis laced mud system. Perform FIT, passed. drill FI3344 T/4427'. Pump sweep, POOH for Short Trip. RIH circulate STG 75 units. * 10000 units = 100% Gas In Air I ( r ~l I: r BP Alaska Northstar NS 09 North Slope Northstar NS 09 Nabors 33E AK AM 11202 Report No.: Date: Depth Footage Last 24 hrs: Rig Activity: Report For. Shows: Customer. Well: Area: Lease: Rig: Job No.: 1 5p~rv- sun ~Fi I L..LI Ñ'i8--.-~ Fiv I c: .~ 1 Mudlogger". Morning Report 10 12/1112001 6596 2,171 Drilling Gavin Kidd Current 24 hr Avg 24 hr Max Pump and Flow Data 47 ftIhr 227 ftIhr ( 424 ftIhr @ 5225 ) Pump 1 110 spm DH flow 59 units 40 unit~ ( 294 6315 ) Pump 2 110 spm Total flow 765 78 Deg F ( deg F @ ) Pump 3 spm AV @ rsr Pump Pres 2030 psi AV@ DC Mud Wt In 9.30 ppg Vise ~secs API tilt 7.2 ml HTHP ml Mud Wt at Max Gas 9.3 ppg Mud Wt Out 9.30 ppg PV -11 cP YP ~lbs/100ft2 Gels 9 \ 14 Ibs/100ft2 pH 8.0 Sd 0.25 % - - - I" 1 [ 4 Type: HTC MXC1DT Bit Size: 121/4 20.00 RPM: 80 Hrs. On Bit: 19.7 Jets: ...1§... \ ...1§... \ .1Q.. \ ~ \ - \ - TF A: 1.0060 Total Revs on BIt: 272k Footage for Bit Run 3181 1 Trip Depth: ft Trip Gas: Mud Cut: ppg Trip CI: Short Trip Depth 5661 ft Short Trip Gas: 181 Units Mud Cut: ppg Short Trip CI: 17 000 Tight Spots: to to to Feet of Fill on Bottom: Current Lithology: 90 % SO 10 % SLT % % %LCM ( 1 ConnectIon Gas and Mud Cut 1t units ppg 1t units ppg it units ppg ft ft ft ( I Drilling Breaks Gas during Depth Drill Rate during after before before after I to to I I units units units Cgl % Lithology Sst Ls Sh ---- ---- ---- -- I [ r I' 1 1 1 1 1 1 1 1 1 1 I I I I I ':ustomer: BP Alaska Report No.: 11 Well: Northstar NS 09 Date: 1211212001 5pE!r'r-'V- sun Area: North Slope Depth 7187 C A I L.L. I N C8 .."'VIC.~ Lease: Northstar NS 09 Footage Last 24 hrs: 591 --,,----- Rig: Nabors 33E Rig Activity: RIH Mudlogger's Morning Report Job No.: AKAM 11202 Report For: Gavin Kidd Shows: Current 24 hr Avg 24 hr Max Pump and Flow Data 0 ftIhr 167 ftIhr ( 414 ftIhr @ 7096 ) Pump 1 0 spm DH flow 0 units 48 unit! ( 118 6315 ) Pump 2 0 spm Total flow a 85 Deg F ( deg F @ ) Pump 3 spm AV @ rsr Pump Pres psi AV@ DC ppg Trip CI: ppg Short Trip CI: Feet of Fill on Bottom: Connection Gas and Mud Cut ft untts ppg ft untts ppg ft untts ppg Drilling Breaks Depth Drill Rate during Cgl % Lithology Sst Ls Sh Gas during before after before after to to ---- ---- ---- ---- 24 hr ReCé Drillin F16596 T17187, Totall circulated hi h VIS swee . POOH Fr1187 T/5700. Monitor well. , POOH to the shoe, monitor well cent POOH, UD BHA #4, chan e out wear rin . M/U BHA #5, RIH, Shallow test MWD, failed, Cant RIH, Retest MWD, failed, POOH to change out MWD. ~: Logging Engineer. REG WILSON I MARK LlNDLOFF .. 10000 units = 100% Gas In Air I r r- I I r I I I I I I I I I I I I [ ":ustomer: BP Alaska Report No.: 12 Well: Northstar NS 09 Date: 12/1312001 !5pE!r"r'V-!5LJn Area: North Slope Depth 8220 C " I L..L..I N" .....VIC.. Lease: Northstar NS 09 Footage Last 24 hrs: 1,033 Rig: Nabors 33E Rig Activity: Drilling- Mudlogger's Morning Report Job No.: AKAM 11202 Report For: Gavin Kidd Shows: Current 24 hr Avg 24 hr Max Pump and Flow Data 60 ftIhr 151 ftIhr ( 414 ftIhr @ 7096 ) Pump 1 113 spm DH flow 50 units 48 unit~ ( 118 6315 ) Pump 2 112 spm Total flow 800 85 Deg F ( deg F @ ) Pump 3 spm AV @ rsr Pump Pres 2600 psi A V @ DC Trip Depth: Short Trip Depth Tight Spots: ppg Trip CI: ppg Short Trip CI: Feet of Fill on Bottom: Connection Gas and Mud Cut ft units ppg ft units ppg ft units ppg Drilling Breaks Depth Drill Rate during Cgl % Lithology Sst Ls Sh Gas during before after before after to to ---- ---- ---- ---- 24 hr ReCé RIH with new BHA# 6, Circulated to condition mud, 229 units of Tri Drill Ff7178' T18220' .. < , '.. .. Logging Engineer. REG WILSON I MARK LlNDLOFF * 10000 units = 100% Gas In Air I r r I ( (' I I I I I I I I I I I I I ":ustomer: BP Alaska Report No.: 13 Well: Northstar NS 09 Date: 12/14f2001 SpE!r'r'V- sun Area: North Slope Depth 9390 I:!~~~L. U~ aI_-~ . fit V I c: . . Lease: Northstar NS 09 Footage Last 24 hrs: 1,170 Rig: Nabors 33E Rig Activity: Drillin~ Mudlogger's Morning Report Job No.: AK AM 11202 Report For: Gavin Kidd Shows: Current 24 hr Avg 24 hr Max Pump and Flow Data 72 ftIh r 111 ftIhr ( 194 ftIhr @ 8918 ) Pump 1 116 spm DH flow 29 units 62 unit~ ( 246 9202 ) Pump 2 112 spm Total flow 800 85 Deg F ( deg F @ ) Pump 3 spm AV @ rsr Pump Pres 2750 psi AV@ DC Trip Depth: Short Trip Depth Tight Spots: ppg Trip CI: ppg Short Trip CI: 17000 Feet of Fill on Bottom: Connection Gas and Mud Cut ft unfts ppg ft unns ppg ft URnS ppg Drilling Breaks Depth Drill Rate during Cgl % Lithology Sst Ls Sh Gas during before after before after to to ---- ---- ---- ---- , 24 hr ReCé Drill ahead F/8220 T19202, Short Tri to shoe, RIH, circulated out 246 units of STG. Cont drillin F/9202' Tf9390. ':', Logging Engineer: REG WILSON I MARK LlNDLOFF ~: * 10000 units = 100% Gas In Air r r r r r r r r r [ [ [ [ r r r I I [ ;ustomer: BP Alaska ~eport No.: 14 Well: Northstar NS 09 Date: 12/1512001 SpEr'r'v- sun Area: North Slope Depth 10816 C ,. I '-'- I N aI ..,.VIC.. Lease: Northstar NS 09 Footage Last 24 hrs: 1 ,426 Rig: Nabors 33E Rig Activity: ~ Mudlogge(s Morning Report Job No.: AK AM 11202 Report For: Gavin Kidd Shows: Current 24 hr Avg 24 hr Max Pump and Flow Data 101 ftIh r 119 ftIhr ( 218 ftIh r @ 10248 ) Pump 1 112 spm DH flow Gas. 164 units 129 unit~ ( 538 10516 ) Pump 2 112 spm Total flow 800 , Temp Out 85 Deg F ( deg F @ ) Pump 3 spm AV @ rsr ,;. Pump Pres 3100 psi AV@ DC Trip Depth: Short Trip Depth Tight Spots: ppg Trip CI: ppg Short Trip CI: 17000 Feet of Fill on Bottom: Connection Gas and Mud Cut ft unns ppg ft unfts ppg ft units ppg Drilling Breaks before Drill Rate during after before Gas during after Cgl % Lithology Sst Ls Sh Depth to to ---- ---- ---- ---- , '¡ , .. r. Logging Engineer. REG WILSON I MARK LlNDLOFF , * 10000 units = 100% Gas In Air I I I [ I I [ I [ I [ I I I I I I I I ;ustomer: BP Alaska Report No.: 15 Well: Northstar NS 09 Date: 12/1612001 5pE!r"'-'V- sun Area: North Slope Depth 11545 C ... I '-'- I N C8 .."VIC.. Lease: Northstar NS 09 Footage Last 24 hrs: 729 ----- RIg: Nabors 33E RIg Activity: POOH Mudlogger's Morning Report Job No.: AK AM 11202 Report For: Gavin Kidd Shows: Trip Depth: Short Trip Depth Tight Spots: Depth Current 24 hr Avg 24 hr Max Pump and Flow Data 0 ftIhr 117 ftIhr ( 245 ftIhr @ 11232 ) Pump 1 0 spm DH flow 0 units 154 unit~ ( 1749 11545 ) Pump 2 0 spm Total flow 0 85 Deg F ( deg F @ ) Pump 3 spm AV @ rsr Pump Pres psi AV@ DC ppg Trip CI: ppg Short Trip CI: 17000 Feet of Fill on Bottom: Connection Gas and Mud Cut ft untts ppg ft untts ppg ft unns ppg Drilling Breaks before Drill Rate during Gas during Cgl % Lithology Sat Ls Sh after after before to to -,--- ---- ---- ---- ;~, ;~ Logging E~gineer. REG WILSON I MARK LlNDLOFF * 10000 units = 100% Gas In Air I I I I I I I I [ [ [ [ I I I I ,z. ,: I ' I I ';ustomer: BP Alaska Report No.: 16 Well: Northstar NS 09 Date: 12/1712001 Sp~""V-!5LJn Area: North Slope Depth 11545 ÇI pit I ~'- I N aI .....VIC.. Lease: Northstar NS 09 Footage Last 24 hrs: 0 Rig: Nabors 33E Rig Activity: 9.625 casing- Mudlogge(s Morning Report Job No.: AKAM 11202 Report For: Gavin Kidd Shows: Current 24 hr Avg 24 hr Max Pump and Flow Data 0 ftlhr ftlhr ( ftlhr @ ) Pump 1 0 spm DH flow 0 units unit~ ( ) Pump 2 0 spm Total flow 0 85 Deg F ( deg F @ ) Pump 3 spm AV @ rsr Pump Pres psi AV@ DC Trip Depth: Short Trip Depth Tight Spots: ppg Trip CI: ppg Short Trip CI: 17000 Feet of Fill on Bottom: Connection Gas and Mud Cut ft units ppg ft unns ppg ft un"s ppg Drilling Breaks Depth Drill Rate during Gas during Cgl % Lithology Sst Ls Sh after after before before to to ---- ---- ---- ---- 24 hr ReCé Continue to POOH, Laid down BHA #6. Ri u for 9.625" casin run. RIH with 9.625" casin . Lost fluids in the Schrader formation. , Logging Engineer. REG WILSON I MARK LlNDLOFF * 10000 units = 100% Gas In Air I I I I I [ I [ I [ [ [ ( I [ [ I I I ":ustomer: BP Alaska Report No.: 17 Well: Northstar NS 09 Date: 12/1812001 5pEr'r'V- sun Area: North Slope Depth 11545 C ... I L..L.. I N C8 .."'VIC.. Lease: Northstar NS 09 Footage Last 24 hrs: 0 Rig: Nabors 33E Rig Activity: Testing BOP's Mudlogge"'s Morning Report Job No.: AK AM 11202 Report For. Gavin Kidd Shows: Trip Depth: Short Trip Depth Tight Spots: Depth Current 24 hr Avg 24 hr Max Pump and Flow Data 0 ftIhr ftfhr ( ftIhr @ ) Pump 1 0 spm DH flow 0 units unit~ ( ) Pump 2 0 spm Total flow 0 49 Deg F ( deg F @ ) Pump 3 spm AV @ rsr Pump Pres psi AV @ DC ppg Trip CI: ppg Short Trip CI: Feet of Fill on Bottom: Connection Gas and Mud Cut ft unäs ppg ft unns ppg ft unäs ppg Drilling Breaks before Drill Rate during CgI % Lithology Sst Ls Sh Gas during after before after to to ---- ---- ---- ---- ..< " z~ : . Logging Engineer. REG WILSON / MARK LlNDLOFF * 10000 units = 100% Gas In Air I I [ [ I I I I I ( ( I [ I I I I I I ":ustomer: BP Alaska Report No.: 18 Well: Northstar NS 09 Date: 12/1912001 5pE!r'~V- sun Area: North Slope Depth 11545 ..----.----------- Lease: Northstar NS 09 Footage Last 24 hrs: 0 c fit I L.L. I N CII ..~VIÇ~. Rig: Nabors 33E Rig Activity: RIH Mudlogger's Morning Report Job No.: AKAM 11202 Report For: Joe Polya Shows: Current 24 hr Avg 24 hr Max Pump and Flow Data 0 ftIhr ftIhr ( ftIhr @ ) Pump 1 0 spm DH flow 0 units unitf ( ) Pump 2 0 spm Total flow 0 85 Deg F ( deg F @ ) Pump 3 spm AV @ rsr Pump Pres psi A V @ DC Trip Depth: Short Trip Depth Tight Spots: ppg Trip CI: . ppg Short Trip CI: Feet of Fill on Bottom: Connection Ga. and Mud Cut ft untts ppg ft unRs ppg ft unns ppg Drilling Breaks Depth Drill Rate during Cgl % Ltthology Sat Ls Sh Gas during before after before after to to ---- ---- ---- ---- i~ Logging Engineer. DOUG WILSON / MARK LlNDLOFF < * 10000 units = 100% Gas In Air I I r I I I I I ( ( I I I ( I I I I I ';ustomer: BP Alaska Report No.: 19 Well: Northstar NS 09 Date: 12/2012001 EiPE!r"""V - sun Area: North Slope Depth 11545 c ~!..~L.I N C8 .....VIC.. Lease: Northstar NS 09 Footage Last 24 hrs: 0 Rig: Nabors 33E Rig Activity: Fixin9...!2PDrive Mudlogger's Morning Report Job No.: AK AM 11202 Report For: Joe Polya Shows: Current 24 hr Avg 24 hr Max Pump and Flow Data 0 ftIhr ftIhr ( ftIhr @ ) Pump 1 0 spm DH flow 0 units unit! ( ) Pump 2 0 spm Total flow 0 85 Deg F ( deg F @ ) Pump 3 spm AV @ rsr Pump Pres psi AV@ DC Trip Depth: Short Trip Depth Tight Spots: ppg Trip CI: ppg Short Trip CI: Feet of Fill on Bottom: Connection Gas and Mud Cut ft units ppg ft units ppg ft units ppg Drilling Breaks Depth Drill Rate during Cgl % Lithology Sst Ls Sh Gas during after after before before to to ---- ---- ---- - - --..: - ~I~ Logging Engineer. DOUG WILSON I MARK LlNDLOFF 11 10000 units = 100% Gas In Air r I I . r r r ( [ I [ I [ r r [ I I I I ';ustomer: BP Alaska Report No.: 20 Well: Northstar NS 09 Date: 12/2112001 5pE!r'r'v- sun Area: North Slope Depth 11545 c fit I '-'- IN" .....VIC.. Lease: Northstar NS 09 Footage Last 24 hrs: 398 Rig: Nabors 33E RIg Activity: Drillin~ Mudlogger's Morning Report Job No.: AKAM 11202 Report For: Joe Polya Shows: Current 24 hr Avg 24 hr Max Pump and Flow Data 71 ftIh r 90 ftlhr ( 216 ftIh r @ 12028 ) Pump 1 83 spm DH flow 34 units unit~ ( 54 116 ) Pump 2 73 spm Total flow 550 85 Deg F ( deg F @ ) Pump 3 spm AV @ rsr Pump Pres 2400 psi AV@ DC Trip Depth: Short Trip Depth Tight Spots: ppg Trip CI: ppg Short Trip CI: Feet of Fill on Bottom: Connection Ga. and Mud Cut ft unäs ppg ft unäs ppg ft unäs ppg Drilling Breaks Depth Drill Rate during Gas during Cgl % Lithology Sst Ls Sh before after after before to to ---- ---- ---- ---- 24 hr ReCé Perform 30 minute casin rassura test, 4300 PSI, assad. Started drillin cement. to ue roblems, continue to drill out cement and 20ft of new formation. Perform LOT, Passed, circulate around new mud to 11.3 was achieved on both MW In and Out. Drill F/11545 T/11943. Currently drilling at 12036. i' Logging Engineer. DOUG WILSON I MARK LlNDLOFF * 10000 units = 100% Gas In Air I I I I I I I I I ( I ( I I I I :- I ,~ I :~ I ';ustomer: BP Alaska Report No.: 21 Well: Northstar NS 09 Date: 12/2212001 SpE!r'r'\,'- sun Area: North Slope Depth 12910 C II' I '-'-I N GI .....VIC.. Lease: Northstar NS 09 Footage Last 24 hrs: 1,365 Rig: Nabors 33E Rig Activity: POOH Mudlogger's Morning Report Job No.: AK AM 11202 Report For: Joe Polya Shows: Trip Depth: Short Trip Depth Tight Spots: Depth Current 24 hr Avg 24 hr Max Pump and Flow Data ftlhr 84.9 ftlhr ( 242 ftIh r @ 12520 ) Pump 1 80 spm DH flow 33 units 59 unit~ ( S54 12898 ) Pump 2 70 spm Total flow 530 85 Deg F ( deg F @ ) Pump 3 spm AV @ rsr Pump Pres 2850 psi AV @ DC ppg Trip CI: ppg Short Trip CI: Feet of Fill on Bottom: Connection Gas and Mud Cut ft unns ppg ft unns ppg ft unns ppg Drilling Breaks before Drill Rate during Cgl % Lithology Sst Ls Sh Gas during after before after to to ---- ---- ---- ---- 'I Logging Engineer. DOUG WILSON I MARK LlNDLOFF * 10000 units = 100% Gas In Air I I I I I I I I I I I I I I I I I I I Customer: BP Alaska Report No.: 22 Well: Northstar NS 09 Date: 12/2312001 sper--rav- sun Area: North Slope Depth 12910 c fit 1 '-'-I N aI .....VIC.. Lease: Northstar NS 09 Footage Last 24 hrs: 0 Rig: Nabors 33E Rig Activity: RIH W/Casing Mudlogge"'s Morning Report Job No.: AK AM 11202 Report For: Joe Polya Shows: Current 24 hr Avg 24 hr Max Pump and Flow Data ftJhr 0 ftlhr ( 0 ftJhr @ 0 ) Pump 1 0 spm DH flow 0 units 0 unit! ( 0 0 ) Pump 2 0 spm Total flow 0 0 Deg F ( deg F @ ) Pump 3 spm AV @ rsr Pump Pres psi AV@ DC Trip Depth: Short Trip Depth Tight Spots: ppg Trip CI: ppg Short Trip CI: Feet of Fill on Bottom: Connection Gas and Mud Cut ft unls ppg I ft unRs ppg ft unRs ppg Drilling Breaks Depth Drill Rate during Cgl % Lithology Sst Ls Sh Gas during after before after before to to ---- --~- ---- ---- tr. ;;' w., ,h~{ Logging Engineer. DOUG WILSON I MARK LlNDLOFF . 10000 units = 100% Gas In Air I !~ .' I I .:: ?, I .' R.O.P. I :' (" ""ustomer: . Well: sper--"""V-!5I..Jn Area: CA' L.L.I N C8 . . ... V I c:: . . Lease: Rig: Job No.: Mudlogger's Morning Report BP Alaska Northstar NS 09 North Slope Northstar NS 09 Nabors 33E AK AM 11202 ( Report No.: Date: Depth Footage Last 24 hrs: Rig Activity: Report For: Shows: 23 12/24/2001 12910 0 RIH W/REAMER Joe Polya I . I [ I [ ( ( I I I " I ' ~)~ "" I ,f' :ë~ .~~~ Logging Engineer DOUG WILSON I MARK LlNDLOFF :~~ .~ I . I Current 24 hr Avg 24 hr Max Pump and Flow Data ftIhr 0 ftlhr ( 0 ftIhr @ 0 ) Pump 1 0 spm DH flow 0 units 0 unit~ ( 0 0 ) Pump 2 0 spm Total flow 0 0 Deg F ( deg F @ ) Pump 3 spm AV @ rsr Pump Pres psi AV@ DC Trip Depth: Short Trip Depth Tight Spots: Depth Drill Rate during ppg Trip CI: ppg Short Trip CI: Feet of Fill on Bottom: Connection Gas and Mud Cut ft units ppg ft units ppg ft units ppg Drilling Breaks after Gas during Cgl % Lithology S,st Ls Sh before to to before after ---- ---- ---- ---- 24 hr ReCé Continue to RIH with 7" liner, Ran to shoe and established circulation Continue to RIH and started. ti htenin toward the end of the Miluveach. Took 100K off wie ht when oin in and ulled at 400K when ullin out . At 11 958' it was decided to POOH with casing before sticking the casinQ. POOH hole with casing and RIH with Hole opener. Currently at 4740'MD MERRY CHRISTMAS * 10000 units = 100% Gas In Air I r " ~ , 1 "Gas. Temp Out 1 I' '.. I I I ( I ( , I I :, , 24 hr Rea Ran to the bottom of the shoe 11555' MD. Circulated and wei hted u the mud from 11.3 to 11.8. I' At bottoms u there was 110 units of to as. Started reamin to the bottom, Ti ht around the fault area , 12340'-12500' MD, a lot of shale came over the shakers while reaming. Companyman Joe Polya came took pies of samplesthroughout the reaming area. Max gas while drilling was 190 units. Reamed to bottom, circulated a . sweep, Max gas at bottoms up was 102 units I j~i,; Ch~nge o~t day, Mark Lindloff and Steve Snelson are g.2!!2g in, Tom Mansfield and Paul Lavelle co':'1ing out. . ',~{ Logging Engineer. DOUG WILSON I MARK LlNDLOFF * 10000 Units = 100% Gas In Air " [ :; ('.. "'ustomer: Well: 5pE!r'~V-!5LJn Area: c "'lJ~'-!J~L~- . . ... V Ie. . Lease: Rig: Job No.: ( Report No.: Date: Depth Footage Last 24 hrs: Rig Activity: Report For: Shows: 24 1212512001 12910 1355(ReaminQ2.. Reaming Hole Joe Polys BP Alaska Northstar NS 09 North Slope Northstar NS 09 Nabors 33E AKAM 11202 Mudlogger's Morning Report Current 24 hr Avg 24 hr Max Pump and Flow Data ftlhr 0 ftlhr ( 0 ftlhr @ 0 ) Pump 1 70 spm DH flow units 47 unit~ ( 190 12720 ) Pump 2 75 spm Total flow 515 Deg F ( deg F @ ) Pump 3 spm AV @ rsr Pump Pres 2250 psi AV@ DC 102 0 Trip Depth: Short Trip Depth Tight Spots: ppg Trip CI: ppg Short Trip CI: Feet of Fill on Bottom: Connection Gas and Mud Cut ft units ppg ft units ppg ft units ppg Drilling Bnaks Depth Drill Rate during Cgl % Lithology Sst Ls Sh Gas during after before after before to to ---- ---- ---- , ---- I . I I ( I ( ( I I I 24 hr ReCà Reamed to bottom and eirc. Out wI swee s. Ran wi er tri to shoe. Ran back to bun. Pum two I ~, swee s. STG 133u. POOH, slowl first 15 stnds. UD hole 0 ener. P/U 7" liner and RIH. Ran to 9 518" shoe. ,~ Circ. Liner and drill elPe vol. Prep to run 7" to bottom. ". I"~ '~t *4:00 Update - Liner to bottom. I ~ Logging Engineer. DOUG WILSON I TOM MANSFIELD If, I;'~' [ I ( (". ( I " (' ~ustomer: Well: SipE!!r'r'v-sun Area: t;I," I L..L..I N C8 1!I_8 fll!v I c: ._~ Lease: Rig: Job No.: (' Report No.: Date: Depth Footage Last 24 hrs: Rig Activity: Report For: Shows: 25 12/26/2001 12910 RIH wI?" liner Reaming Hole Joe Paiva BP Alaska Northstar NS 09 North Slope Northstar NS 09 Nabors 33E AK AM 11202 Mudlogger's Morning Report Current 24 hr Avg 24 hr Max Pump and Flow Data ftIhr ftIhr ( ftIhr @ ) Pump 1 spm DH flow 17 units unit~ ( 133 12910 ) Pump 2 66 spm Total flow 234 Deg F ( deg F @ ) Pump 3 spm AV @ rsr Pump Pres 715 psi AV@ DC Trip Depth: Short Trip Depth Tight Spots: ppg Trip CI: ppg Short Trip CI: Feet of Fill on Bottom: Connection Gas and Mud Cut ft units ppg ft units ppg ft units ppg Drilling Breaks Depth Drill Rate during Cgl % Lithology Sst Ls Sh Gas during after before before after to to ---- ---- ---- ---- * 10000 units = 100% Gas In Air I 'i I [ ~ [ [ [ [ , [ I- I [ [ I I " I i... ,'~, <,"""'ustomer: BP Alaska (" ~eport No.: 26 Well: Northstar NS 09 Date: 1212712001 sp~r'v- sun Area: North Slope Depth 12910 c fit I L.L I N C8 .."'VIC.. Lease: Northstar NS 09 Footage Last 24 hrs: 0 Rig: Nabors 33E RIg Activity: Cut & SIiEL- Mudlogger's Morning Report Job No.: AKAM 11202 Report For: Joe Polya Shows: Current 24 hr Avg 24 hr Max Pump and Flow Data ftlhr ftlhr ( ftIhr @ ) Pump 1 spm DH flow units 7 unit~ ( 93 12910 ) Pump 2 spm Total flow' DegF ( deg F @ ) Pump 3 spm AV @ rsr Pump Pres psi AV@DC na .. Temp Out Trip Depth: Short Trip Depth Tight Spots: ppg Trip CI: ppg Short Trip CI: Feet of Fill on Bottom: Connection Gas and Mud Cut ft units ppg ft units ppg ft units ppg Drilling Breaks Depth Drill Rate during Cgl % Lithology Sst Ls Sh Gas during before after before after to to ---- ---- ---- ---- '. 24 hr ReCé Ran 7" liner. Cire. & Condo Max Gas 93 units. Cement 7" liner. POOH wI drill Sli and Cut drill line. Pre to ick u BHA. * 10000 units = 100% Gas In Air "f8'o"~stomer: BP Alaska (. ~eport No.: 30 Well: Northstar NS 09 Date: 1213112001 !51:1Er'r'V- sun Area: North Slope Depth 13429 TO. g"_LL.~1 N C8 .....VIC.. Lease: Northstar NS 09 Footage Last 24 hrs: 0 Rig: Nabors 33E RIg Activity: GMT 4.5" LINER Mudlogger's Morning Report Job No.: AKAM 11202 Report For: Joe Polya Shows: Current 24 hr Avg 24 hr Max Pump and Flow Data NA ftIhr NA ftlhr ( NA ftIhr @ ) Pump 1 spm DH flow 5 units 3 unih( 76 units @ while cmtg ) Pump 2 spm Total flow DegF ( deg F @ ) Pump 3 spm AV @ rsr Pump Pres psi AV@ DC Trip Depth: Short Trip Depth Tight Spots: ppg Trip CI: ppg Short Trip CI: Feet of Fill on Bottom: Connection Gas and Mud Cut It units ppg ft units ppg It units ppg Drilling Breaks before Drill Rate during after before Gas during after Cgl % Lithology Sst Ls Sltst Depth to to ---- ---- ---- ---- * 10000 units = 100% Gas In Air r.. I Schlumberger , eHA# 2 I I ~ f I Job # Date In 04-Dec-01 Date Out Hole Size 16 Customer BP AOW Time In Time Out Hole Sect Surface Well NS09 Depth In 260 Depth Out Bha Type Steerable Field Northstar TVD In TVD Out Hrs BRT I Rig Nabors 33E Drlg Hrs Drlg Ft Avg ROP AFE# 831308 Slide Hrs Slide Ft Slide ROP DD's Rot Hrs Rot Ft Rot ROP I Co. Men Pump Hrs Rotate % Slide % r PDM Run # 1 R/S 5/6 PDM Jet Blk Inclln Az In Bit>Svy PDM Ser# I 962-3561 I Stages 3.0 Bearing Mud Incl Out Az Out T/F CO" . PDM Size 9 9/16 Rev/Gal 0.100 Rubber RM 1000 A vg Dis Max Dls Plan Dls I Mud Type Sea H2O Spud Mud Wt Sand % RPM GPM SPP On: BHT F Mud Vis Solids % RotTQ WOB SPP Off: Item Description Vendor SIN OD ID Stab OD F.N. Connection Length Cum Length I MX-C1 1 TFA=1.031 HTC T250C 16 3x20,1x12 7 5/8 Reg P 1.35 1.35 9 5/8 Std PDM 1.83 7 5/8 Reg B . 2 *Float Ana 962-3561 9 9/16 Tool 15 7/8 15.70 6 5/8 H-90 B 26.60 27.95 .1 MONELLC 6 5/8 H-90 P 3 Ana 810-001-LC 8 1/16 2 13/16 6 5/8 H-90 B 10.45 38.40 MONEL LC 6 5/8 H-90 P 1 4 Ana 810-009-LC 8 2 7/8 6 5/8 H-90 B 9.74 48.14 J MONEL STAB 6 5/8 H-90 P 5 Ana 800-011-SB 8 2 7/8 16 2.40 6 5/8 H-90 B 5.87 54.01 ï MWD 6 5/8 H90 6 *Muleshoe Ana 169 8 1/4 3 1/4 1.27 6 5/8 H90 28.38 82.39 .." Orienting Sub 6 5/8 H-90 P 7 Ana GLOD-105 8 2 1/2 6 518 H-90 B 1.66 84.05 I MONEL STAB 6 5/8 H-90 P 8 Ana 800-007 -sa 8 2 7/8 16 2.39 6 5/8 H-90 B 5.62 89.67 MONEL DC 6 5/8 H-90 P "I 9 Ana 831-009DC 7 15/16 2 13/16 6 518 H-90 B 30.84 120.51' J MONEL DC 6 5/8 H-90 P 10 Ana 831-002DC 7 7/8 2 13/16 6 5/8 H-90 B 30.70 151.21 MONEL STAB 6 5/8 H-90 P "I 11 Ana 800-010-SB 8 2 7/8 16 2.40 6 5/8 H-90 B 5.63 156.84 . ( MONEL DC 6 5/8 H-90 P 12 *Corrosion Ring Ana 831-019DC 8 2 13/16 6 5/8 H-90 B 30.51 187.35 HYDJARS 6 5/8 H90 " 13 DAILEY 1417-1119 7 5/8 3 1.66 4 1/2 IF 31.50 218.85 26 Jts. HWDP 5" 4 1/2 IF P - 14 NAD 26 HWDP 5 3 4 1/2 IF B 788.89 1007.74 i DP 5" to Surface 4 1/2 IF P 15 NAD DP 5 4 8/29 4 1/2 IF B 1007.74 , al I' ., r I I !HA Expected Behavior: Bit Data Tool Hrs. In Hrs. Out IADC # Motor "I IBHA Actual Behavior: Footage Jars I :omments / Reason for Trip: Hrs Bit #1 k Revs I Grade J Comment I [ I ( I I I I I Schlurnbel'gef1 (' ~~ H A # 3 I ~ ~< Job # Date In 04-0ec-01 Date Out Hole Size 16 Customer BP AOW Time In 14:00 Time Out Hole Sect Surface. Well NSO9 Depth In 260 Depth Out Bha Type Steerable Field Northstar TVD In 260 TVD Out Hrs BRT Rig Nabors 33E Drlg Hrs Drlg Ft Avg ROP AFE # 831308 Slide Hrs Slide Ft Slide ROP DD's Rot Hrs Rot Ft Rot ROP Co. Men Pump Hrs Rotate % Slide % °DM Run # 1 R/S 5/6 PDM Jet Blk Inclln Azln Bit>Svy PDM Ser# I 962-3561 I Stages 3.0 Bearing Mud Incl Out Az Out T/F Corr POM Size 9 9/16 Rev/Gal 0.100 Rubber RM1000 Avg Dls Max Dls Plan D's Mud Type Sea H2O Spud Mud Wt Sand % RPM GP1rI SPP On: BHT F Mud Vis Solids % RotTQ WOB SPP Off: Item Description Vendor SIN OD ID Stab OD F.N. Connect/on Length Cum Length MX-C1 1 TFA=1.031 HTC T250C 16 3x20,1 x12 7 5/8 Reg P 1.35 1.35 9 5/8 Std PDM 1.83 7 5i8 Reg B 2 *Float Ana 962-3561 9 9/16 Tool 15 7/8 15.70 6 5/8 H-90 B 26.60 27.95 MONEL LC 6 5/8 H-90 P 3 Ana 810-001-LC 8 1/16 2 13/16 6 5/8 H-90 B 10.45 38.40 MONELLC 6 5/8 H-90 P 4 Ana 810-o09-LC 8 2 7/8 6 5/8 H-90 B 9.74 48.14 MONEL STAB 6 5/8 H-90 P 5 Ana 8ûO-011-SB 8 2 7/8 16 2.40 6 5/8 H-90 B 5.87 54.01 MWO 6 518 H90 6 Ana 169 8 1/4 3 1/4 1.27 6 518 H90 28.38 82.39 Orienting Sub 6 5/8 H-90 P 7 Ana GLDD-105 8 2 1/2 6 518 H-90 B 1.45 83.84 MONEL STAB 6 518 H-90 P 8 Ana 800-007 -S8 8 2 7/8 16 2.39 6 518 H-90 B 5.62 89.46 MONEL DC 6 518 H-90 P 9 Ana 831-OO9DC 7 15/16 2 13/16 6 518 H-90 B 30.84 120.30 MONEL DC 6 5/8 H-90 P 10 Ana 831-OO2DC 7 7/8 2 13/16 6 5/8 H-90 B 30.70 151.00 MONEL STAB 6 5/8 H-90 P 11 Ana 8O0-010-SB 8 2 7/8 16 2.40 6 518 H-90 B 5.63 156.63 MONEL DC 6 5/8 H-90 P 12 *Corrosion Ring Ana 831-o19DC 8 2 13/16 6 5/8 H-90 B 30.51 187.14 HYOJARS 6 5/8 H90 13 DAILEY 1417-1119 7 5/8 3 1.66 4 1/2 IF 31.50 218.64 26 Jts. HWDP 5" 4 1/2 IF P 14 NAD 26 HWDP 5 3 4 1/2 IF B 788.89 1007.53 DP 5" to Surface 4112 IF P 15 NAD DP 5 4 8/29 4 1/2 IF B 1007.53 9HA Expected Behavior: Bit Data Tool Hrs. In Hrs. Out IADC # Motor 9HA Actual Behavior: Footage Jars Hrs Bit #1 :omments / Reason for Trip: k Revs Grade Comment [ I [ I [ I [ r I I r r I I c urn erger ( (" ~HA # PROPOSED 4 Job # 40006992 Date In Date Out Hole Size 12 1/4 Customer BP ADW Time In Time Out Hole Sect Intermediate Well NS09 Depth In Depth Out Bha Type Steerable Field Northstar TVD In TVD Out Hrs BRT Rig Nabors 33E Drlg Hrs Drlg Ft A vg ROP ! AFE # 831308 Slide Hrs Slide Ft Slide ROP DD's Rinke Rot Hrs . Rot Ft RotROP Co. Men KiddlDinger Pump Hrs Rotate % Slide % I PDM Run # 2 R/S 3/4 PDM Jet Blk Inclln Azln Bit>Svy PDM Ser# 962-1056 Stages 4.5 Bearing Mud Incl Out Az Out T/F Corr PDM Size 9 5/8 Rev/Gal 0.200 Rubber RM100D A vg Dis Max Dis Plan Dls Mud Type Mud Wt Sand % RPM GPM 700 SPP On: I BHT F Mud Vis Solids % Rot TO WOB SPP Off: I Item Description Vendor SIN OD ID Stab OD F.N. Connection . Length Cum Length i MXC1DT 1 TFA=1.006 HTC M221 DR1111 12 1/4 2X 16 2X20 6 5/8 Reg P 1.00 1.00 95/8 Std PDM 1.15 6 5/8 Reg B 2 Ana 962-1056 9 5/8 Tool 12 1/8 17.78 6 5/8 H-90 B 26.74 27.74 MONEL LC 6 5/8 H-90 P 3 Ana 805-004-LC 8 2 7/8 6 5/8 H-90 B 5.00 32.74 MONEL LC 6 5/8 H-90 P 4 Ana 810.003-LC 8 2 7/8 6 5/8 H-90 B 9.72 42.46 I MONEL STAB 6 5/8 H-90 P 5 Ana 800-002-SB 8 2 7/8 12 1/8 2.40 6 5/8 H-90 B 5.55 48.01 II MWD 6 5/8 H90 6 Ana 169 8 1/4 3 1/4 1.27 6 5/8 H90 28.38 76.39 MONEL STAB 6 5/8 H-90 P 7 Ana 800-017-SB 8 2 7/8 12 1/16 2.40 6 5/8 H-90 B 5.49 81.88 I MONEL DC 6 5/8 H-90 P 8 Ana 831.009DC 715/16 2 13/16 6 5/8 H-90 B 30.84 112.72 MONEL DC 6 5/8 H-90 P I 9 Ana 831.002DC 7 7/8 2 13/16 6 5/8 H-90 B 30.70 143.42 J MONEL STAB 6 5/8 H-90 P 10 Ana 800-013-SB 8 2 7/8 12 2.45 6 5/8 H-90 B 5.44 148.86 I MONEL DC 6 5/8 H-90 P 11 Ana 831-019DC 8 2 13/16 6 5/8 H-90 B 30.51 179.37 ~.. HYDJARS 6 5/8 H90 12 DAI LEY 1417-1119 7 5/8 3 1.66 4 1/2 IF 31.50 210.87 26 Jts. HWDP 5" 4 1/2 IF P 13 NAD 26 HWDP 5 3 4 1/2 IF B 788.86 999.73 l Dart Valve Sub 4 1/2 IF P 14 BPX GM7996 6 5/16 3 1/16x4 1/2 4 1/2 IF B 2.37 1002.10 II DP 5" to Surface 4 1/2 IF P 15 NAD DP 5 4 8/29 4 1/2 IF B 1002.10 1 r I [, .I I ~HA Expected Behavior: Hold while rotating Bit Data Tool Hrs. In Hrs. Out 'I IADC # Motor ,ISHA Actual Behavior: Footage Jars 22.6 I. ':omments / Reason for Trip; Hrs Bit #2 k Revs I Grade Comment S hi b I Schlumberger ( . . . . ('lHA # 5 . ( Job # 40006992 . Date In 12-Dec-01 Date Out Hole Size 12 1/4 Customer BP ADW Time In 19:00' Time Out Hole Sect Intermediate Well NS09 Depth In 7187 Depth Out Bha Type Steerable Field Northstar TVD In 5916 TVD Out Hrs BRT Rig Nabors 33E Drlg Hrs Drlg Ft A vg ROP AFE # 831308 Slide Hrs Slide Ft Siide ROP DD's Rinke Rot Hrs Rot Ft Rot ROP Co. Men KiddlClump Pump Hrs Rotate % Slide % ~DM Run # 3 R/S 3/4 PDM Jet Blk Inclln Azln Bit>Svy 83.68 , PDM Ser# 962-1049 Stages 6.0 Bearing Mud InclOut Az Out T/F Corr 300.6 PDM Size 9 5/8 Rev/Gal 0.200 Rubber RM1000 Avg Dls Max Dls Plan Dls 0.5 Mud Type KCI-Polymer Mud Wt Sand % RPM GPM SPP On: 2400 BHT F Mud Vis Solids % Rot TO woe SPP Off: 2900 Item Description Vendor SIN OD ID StàbOD F.N. Connection Length Cum Length DS69HFGLNPUV 1 TFA=1.035 HvcaloQ 201675 12 1/4 6X15 6 5/8 Reg P 1.00 1.00 95/8 XP PDM 1.15 6 5/8 Reg B 2 *Float Ana 962-1049 9 5/8 Tool 12 1/8 16.29 6 5/8 H-90 B 31.10 32.10 MONELLC 6 5/8 H-90 P I 3 Ana 810-003-LC 8 2 7/8 6 5/8 H-90 B 9.72 41.82 I MONEL STAB 6 5/8 H-90 P 4 Ana 800-013-SB 8 2 7/8 12 2.45 6 5/8 H-90 B 5.44 47.26 I LWD 6 5/8 H90 P 5 Ana 8044 8 5/16 15.13 6 5/8 FH B 22.79 70.05 MWO 6 5/8 FH P 6 Ana 196 8 1/4 3 1/4 2.11 6 5/8 H90 8 28.25 98.30 MONEL STAB 6 5/8 H-90 P 7 Ana 800-002-SB 8 2 7/8 12 1/8 2.40 6 5/8 H-90 B 5.55 103.85 MONEL DC 6 5/8 H-90 P (I 8 Ana 831-009DC 7 15/16 2 13/16 6 5/8 H-90 8 30.84 134.69 MONEL DC 6 5/8 H-90 P 9 Ana 831-002DC 7 7/8 2 13/16 6 5/8 H-90 8 30.70 165.39 ( MONEL STA8 6 5/8 H-90 P 10 Ana 800-017-S8 8 2 7/8 12 1/16 2.40 6 5/8 H-90 8 5.49 170.88 (I MONEL DC 6 5/8 H-90 P 11 *Corrosion Ring Ana 831-019DC 8 2 13/16 6 5/8 H-90 8 30.51 201 .39 HYDJARS 6 5/8 H90 12 DAI LEY 1417-1119 7 5/8 3 1.66 41/2 IF 31.50 232.89 II 26 Jts. HWDP 5" 4 1/2 IF P 13 NAD 26 HWDP 5 3 4 1/2 IF B 788.86 1021.75 Dart Valve Sub 41/2 IF P 'I 14 BPX GM7996 6 5/16 3 1/16x4 1/2 41/2 IF 8 2.37 1024.12 II DP 5" to Surface 4 1/2 IF P 15 NAD DP 5 4 8/29 41/2 IF 8 1024.12 I I I I BHA Expected Behavior: Bit Data Tool Hrs. In Hrs.Out I IADC # M421 Motor I BHA Actual Behavior: Footage Jars 47.4 Hrs Bit #2 I Comments / Reason for Trip: Bit to GR= 81.69 PWD=55.24 RES=53.39 k Revs \ I Grade Comment [ I I Schlumberger (' ( BHA # 6 I I I Job # 40006992 Date In 12/113/2001 Date Out Hole Size 12 114 Customer BP ADW Time In Time Out Hole Sect Intermediate Well NS09 Depth In 7187 Depth Out Bha Type Steerable I Field Northstar TVD In 5916 TVD Out Hrs BRT Rig Nabors 33E Drlg Hrs Drlg Ft A vg ROP AFE # 831308 Slide Hrs Slide Ft Slide ROP I DO's Rinke Rot Hrs Rot Ft Rot ROP Co. Men Kidd/Clump Pump Hrs Rotate % Slide % . PDM Run # 3 RlS 3/4 PDM Jet Blk Inclln Azln Bit>Svy 83.68 PDM Ser# 962-1049 Stages 6.0 Bearing Mud Incl Out Az Out T/F Corr I PDM Size 9 5/8 Rev/Gal 0.200 Rubber RM100D Avg Dis Max Dls Plan Dis 0.5 I Mud Type Seawater Pol. Mud Wt Sand % RPM GPM SPP On: BHT F Mud Vis Solids % Rot TO WOB SPP Off: . Item Description Vendor SIN OD ID Stâb'OD F.N. Connection Length Cum Length I DS69HFGLNPUV 1 TFA=1.035 HycaloQ 201675 12 1/4 6X15 6 5/8 Reg P 1.00 1.00 9 5/8 XP PDM 1.15 6 5/8 Reg B I 2 *Float Ana 962-1049 9 5/8 Tool 12 1/8 16.29 6 5/8 H-90 B 31.10 32.10 I MONELLC 6 5/8 H-90 P 3 Ana 81 0-OO3-LC 8 2 7/8 6 5/8 H-90 B 9.72 41.82 I MONEL STAB 6 5/8 H-90 P 4 Ana 800-013-SB 8 2 7/8 12 2.45 6 5/8 H-90 B 5.44 47.26 . LWD 6 5/8 H90 P 5 Ana 8044 8 5/16 15.13 6 5/8 FH B 22.79 70.05 I MWD 6 5/8 FH P 6 Ana 173 8 1/4 3 1/4 1.30 6 5/8 H90 B 27.30 97.35 MONEL STAB 6 5/8 H-90 P I 7 Ana 800-002-SB 8 2 7/8 12 1/8 2.40 6 5/8 H-90 B 5.55 102.90 .I. MONEL DC 6 5/8 H-90 P 8 Ana 831-009DC 7 15/16 2 13/16 6 5/8 H-90 B 30.84 133.74 MONEL DC 6 5/8 H-90 P I 9 Ana 831-002DC 7 7/8 2 13/16 6 5/8 H-90 B 30.70 164.44 .1 MONEL STAB 6 5/8 H-90 P 10 Ana 800-0 17-SB 8 2 7/8 12 1/16 2.40 6 5/8 H-90 B 5.49 169.93 I MONEL DC 6 5/8 H-90 P 11 *Corrosion Ring Ana 831-019DC 8 2 13/16 6 5/8 H-90 B 30.51 200.44 HYDJARS 6 5/8 H90 12 DAI LEY 1417-1119 7 5/8 3 1.66 4 1/2 IF 31.50 231.94 .I 26 Jts. HWDP 5" 4 1/2 IF P 13 NAD 26 HWDP 5 3 4 1/2 IF B 788.86 1020.80 Dart Valve Sub 41/2 IF P 1 14 BPX GM7996 6 5/16 3 1/16x4 1/2 4 1/2 IF B 2.37 1 023. 17 J DP 5" to Surface 4 1/2 IF P 15 NAD DP 5 4 8/29 4 1/2 IF B 1 023. 1 7 I . . I I I 3HA Expected Behavior: Bit Data Tool Hrs. In Hrs. Out I IADC # M421 Motor 0.5 I' 9HA Actual Behavior: Footage Jars 47.4 Hrs Bit #2 .1 Comments / Reason for Trip: Bit to GR= 81.69 PWD=55.24 RES=53.39 k Revs I Grade Comment I I ( ( [ [ [ [ I ( [ [ I . Schlumberger ( f lHA# 7 Job # 40006992 Date In Date Out Hole Size 8 1/2 ~ Customer BP ADW Time In Time Out Hole Sect Intermediate Well NS09 Depth In 11545 Depth Out Bha Type Field Northstar TVD In TVD Out Hrs BRT Rig Nabors 33E Drlg Hrs Drlg Ft A vg ROP AFE # 831308 Slide Hrs Slide Ft Slide ROP DD's Rinke Rot Hrs Rot Ft Rot ROP Co. Men Kidd/Clump Pump Hrs Rotate % Slide % PDM Run # 4 RlS 4/5 PDM Jet Blk Incl In Azln Bit>Svy PDM Ser# 675-1333 Stages 7.0 Bearing Mud Incl Out Az Out TIF Corr PDM Size 6 3/4 Rev/Gal 0.500 Rubber RM100D A vg Dls Max Dls Plan Dls Mud Type Mud Wt Sand % RPM 80 GPM 550 SPP On: I BHT F Mud Vis Solids % RatTO woe SPP Off: Item Description Vendor SIN OD ID Stàb OD F.N. Connection Leri'gth Cum Length Bit #4 DS70FNPV I 1 RR#1 TFA=.907 Hycalog 200347 8 1/2 3x15,3x13 4112 Reg P 1.00 1.00 63/4 XP .780 4 1/2 Reg B 2 "Float Ana 675-1333 6 3/4 Tool 8 3/8 4 1/2 XH B 28.97 29.97 NM STABILIZER 4 1/2 XH P 3 Ana 675-004SB 6 3/4 2 13/16 8 1/2 2.42 4 1/2 XH B 5.70 35.67 CDR (PWD) 4 1/2 XH P 4 Ana 7130 6 3/4 Tool 11.87 5 1/2 FH B 22.53 58.20 MWD 5 1/2 FH P 5 Ana 217 6 3/4 Tool 4 1/2 XH B 27.80 86.00 NM STABILIZER 4 1/2 XH P 6 "baffle plate Ana 675-011 SB 6 3/4 2 13/16 8 1/2 2.45 4 1/2 XH B 5.62 91.62 NM FLEX 4 1/2 XH P 7 675-31-016FC 6 3/4x 5 2 13/16 2.50 4 1/2 XH B 31.01 122.63 NM FLEX 4 1/2 XH P 8 675-31-014FC 6 11/16x5 2 13/16 2.50 4 1/2 XH B 31.02 153.65 NM FLEX 4 1/2 XH P 9 675-31-021 FC 6 3/4x 5 2 13/16 2.50 4 1/2 XH B 31.02 184.67 X-OVER 4 1/2 XH P 10 .Corrosion Ring Ana GLDD1042 6 3/4 2 3/4 4 1/2 IF B 1.98 186.65 3 Jts HWDP 5" 4 1/2 IF P 11 NAD 3 HWDP 5 3 4 1/2 IF B 91.02 277.67 HYDJARS 4 1/2 IF P 12 DAILEY 1416-1574 6 1/2 2 3/4 169.00 4 1/2 IF B 32.63 310.30 23 Jts. HWDP 5" 4 1/2 IF P 13 NAD 23 HWDP 5 3 4 1/2 IF B 697.84 1008.14 Dart Valve Sub 4 1/2 IF P 14 BPX GM7996 6 5/16 3 1/16x4 1/2 4 1/2 IF B 2.37 1010.51 DP 5" to Surface 4 1/2 IF P 15 NAD DP 5 4 8/29 4 1/2 IF B 1010.51 ~HA Expected Behavior: Bit Data Tool Hrs.ln Hrs. Out IADC # Motor BHA Actual Behavior: Footage Jars Hrs Bit #2 15.1 "':omments / Reason for Trip: k Revs Grade I Comment I Schlumberger (" ( JHA # 8 Job # 40006992 Date In 24-Dec-10 Date Out Hole Size 8 1/2 Customer BP ADW Time In 23:00 Time Out Hole Sect Intermediate Well NS09 Depth In 12910 Depth Out Bha Type Clean out Field Northstar TVD In 9450 TVD Out Hrs BRT Rig Nabors 33E Drlg Hrs Drlg Ft A vg ROP AFE # 831308 Slide Hrs Slide Ft Slide ROP DD's Rinke Rot Hrs Rot Ft Rot ROP Co. Men PolyalClump Pump Hrs Rotate % Slide % I PDM Run # RlS PDM Jet Inclln 13.50 Az In 96.83 BibSvy PDM Ser# Stages Bearing Incl Out Az Out T/F Corr PDM Size Rev/Gal Rubber A vg Dls Max Dls Plan Dls Mud Type KCL Polymer Mud Wt 11.3 Sand % tr RPM GPM 550 SPP On: i BHT F 154 Mud Vis 55 Solids % 10 RatTO woe SPP Off: Item Description Vendor SIN OD ID StabOD °F.N. Connëct'pn. Length Cum Length Hole Opener 1 TFA=.784 STC HO 123 6 3/4 2 13/16 8 1/2 1.87 4 1/2 IF B 6.60 6.60 X-OVER 41/2 IF P 2 Ana AFS301 6 1/2 2 3/4 4 1/2 XH B 1.35 7.95 FLOAT SUB 4 1/2 XH P 3 *Float Ana GLDD01S 6 15/16 2 15/16 4 1/2 XH B 1.67 9.6L NM STABILIZER 4 1/2 XH P 4 *baffle plate Ana 67S-004SB 6 3/4 2 13/16 8 1/2 2.42 4 1/2 XH B 5.70 15.32 NM FLEX 4 1/2 XH P 5 67S-31-016FC 6 3/4x 5 2 13/16 2.50 4 1/2 XH B 31.01 46.33 NM STABILIZER 4 1/2 XH P 6 Ana 675-011 SB 6 3/4 2 13/16 8 1/2 2.45 4 1/2 XH B 5.62 51.95 NM FLEX 4 1/2 XH P 7 675-31-014FC 6 11/16x5 2 13/16 2.50 4 1/2 XH B 31.02 82.97 NM FLEX 4 1/2 XH P 8 675-31-021 FC 6 3/4x 5 2 13/16 2.50 4 1/2 XH B 31.02 113.99 X-OVER 4 1/2 XH P 9 *Corroslon Ring Ana GLDD1042 6 3/4 2 3/4 4 1/2 IF B 1.98 115.97 3 Jts HWDP 5" 4 1/2 IF P 10 NAD 3 HWDP 5 3 4 1/2 IF B 91.02 206.99 HYDJARS 4 1/2 IF P 11 DAILEY 1416-1574 6 1/2 2 3/4 1.69 4 1/2 IF B 32.63 239.62 23 Jts. HWDP 5" 4 1/2 IF P 12 NAD 23 HWDP 5 3 4 1/2 IF B 697.84 937.46 DP 5" to Surface 4 1/2 IF P 13 NAD DP 5 4 8/29 4 1/2 IF B 937.46 I I IHA Expected Behavior: Bit Data Tool Hrs.ln Hrs. Out IADC # Motor f:JHA Actual Behavior: Footage Jars 16.1 Hrs Bit #4 ":omments / Reason for Trip: k Revs r Grade Comment I Job # 40006992 Date In Date Out Hole Size 6 1/8 r Customer BP ADW Time In Time Out Hole Sect Production I Well NS09 Depth In Depth Out Bha Type Rotary F,eld Northstar TVD In TVD Out Hrs BRT I Rig Nabors 33E O,lg Hrs Drlg Ft A vg ROP AFE # 831308 Slide Hrs Slide Ft Slide ROP DO's Rinke Rot Hrs Rot Ft Rot ROP Co. Men PolyalClump Pump Hrs Rotate % Slide % :JOM Run # 4 R/S 7/8 PDM Jet 8 Inclln Azln Bit>Svy PDM Ser# 475-025 Stages 2.0 Bearing OS8 InclOut Az Out TIF Corr PO,., Size 4 3/4 Rev/Gal 0.300 Rubber RM100D Avg Dis Max Dis Plan Dis Mud Type Mud Wt Sand % RPM GPM 340 SPP On: BHT F Mud Vis Solids % RotTQ WOB SPP Off: Item Description . Vendor SIN OD ID StâbOD F.N. Connection- .. Length., . . C::üm,1ength Bit#5 STX30CD 1 TFA=.516 HTC R72JL 6 1/8 3 x15 3 1/2 Reg P 0.75 0.75 4 3/4 PDM SSS 0.0 3112 Reg 8 2 .Float Ana 475-025 43/4 Tool 6 3 1/2 IF B 23.47 24.22 NM Lead DC 31/2 IF P 3 Ana 475-10-005LC 4 3/4 2 3/8 3 1/2 IF 8 10.05 34.27 NM IB Stab 3 1/2 IF P 4 Ana 60060811SZ 4 3/4 2 1/4 6 2.15 3 1/2 IF 8 4.87 39.14 , 4.75 ARC 3 1/2 IF P 5 Ana 475-061 4 3/4 TOOL 1.70 3 1/2 IF 8 24.10 63.24 I SLIM PLUSE MWD 3 1/2 IF P 6 Ana SPRM-û4582 4 3/4 2 1/2 1.41 3 1/2 IF 8 33.87 97.11 NM 18 Stab 3 1/2 IF P I 7 Ana 60060807SZ 4 3/4 2 1/4 6 2.15 3 1/2 IF B 4.90 102.01 I 4.75 ADN 3 1/2 IF P 8 Radioactive source Ana ADN-9801 4 13/16 TOOL 5 3/4 17.85 3 1/2 IF B 25.25 127.26 NMDC 3 1/2 IF P I 9 Ana 475-31-QO3DC 4 3/4 2 1/4 3 1/2 IF 8 31.00 158.26 t NM 18 Stab 3 1/2 IF P 10 Ana 475-00118 4 3/4 2 1/4 6 2.55 3 1/2 IF 8 5.91 164.17 I 11 NMDC 3 1/2 IF P Ana 475-31-Q04DC 4 3/4 2 1/4 3 1/2 IF B 31.02 195.19 NMDC 3 1/2 IF P 12 .Corrosion Ring Ana 475-31-DO1DC 4 3/4 2 1/4 3 1/2 IF B 31.02 226.21 I HYDJAR 3 1/2 IF P 13 DAILEY 1400-1412 4 3/4 2 1/4 1.82 3 1/2 IF B 29.62 255.83 XO 3 1/2 IF P I 14 NAD NR400 001B 5 1/8 1 5/8 HT 40 8 2.54 258.37 ( 14 Jts HWDP HT 40 P 15 NAD 4M HWDP 4 2 11/16 HT40 8 429.76 688.13 I 54 Jnts. DP 4M HT4Q P 16 NAD 54DP 4 4 3 5/16 HT 40 8 1697.22 2385.35 I XO HT40 P 17 BPX HT27872 6 1/4 2 1/2 4 1/2 IF 8 2.47 2387.82 DP 5" to Surface 4 1/2 IF P 18 NAD DP 5 4 8/29 4112 IF 8 2387.82 BHA Expected Behavior. Bit Data Tool Hrs. In Hrs. Out IADC # 547 Motor BHA Actual Behavior. Footage Jars 16.9 Hrs Bit #5 Comments / Reason for Trip: k Revs Grade Comment Schlumberger ( (~HA # 9 I I r I I r I I r I I I I - - ......=~.3~1IIl BHA BIT Bit Bit I:: I Nozzels I TFA I Depth I Hours' Feet Run # Make Type Out 1,2,3 1 Hughes MX-C1 16.00 1x16,3x20 1.031 3415 23.60 3216 4 2 Hughes MXC1 OT 12.25 2x16,2x20 1.006 7187 24.80 3772 5,6 3 Hycalog 0S69HFGNPUV 12.25 6x15 1.032 11545 42.60 4358 7 4 Hycalog OS70FNPV 8.50 3x15,3x13 0.907 12910 16.10 1365 9 5 Hughes STX3OCD 6.125 3x15 0.516 13429 16.40 335 - - -- - - WELL NAME: OPERATOR: CONTRACTOR: NS09 BP Exploration Alaska Nabors 33E Avg. W.O.S RP.M. Pump Flow T S R.O.P. (klbs) Pres. (gpm) I 0 D L S 137.0 30-35 40-45 1700 700-725 1 1 WT A E 152.0 35-45 75~ 2325 775 2 3 WT A E 102.0 20-30 50-85 3275 785 1 2 WT T X 85.0 15 45-50 2450 550 0 0 CT N X 31.0 15 40 1925 350 3 5 8T A E - - LOCA nON: AREA: STATE: - - Northstar North Slope Alaska G Res Pullt REMARKS G 0 R IN PJ TO Could be rerun 1/16 8T 8HA Pulled at 80 feet per hour Rap IN PJ TO TO intermediate in Miluveach IN ER TO TO at Top Sag River 1/16 RG PTO TO at 13429' MO - - -, "~ , -, - - ~ - ~ --- - -- ...--. - -- ~ - - n_n- NORTHSTAR NSO9 BEAUFORT SEA, ALASKA DRilliNG SERVICES NORTHST AR NABORS DRILLING RIG 33E BAROID DRILLING FLUIDS AK-AM 11202 Depth MW VIs PV YP Gels FItr HTHP Cake Sol au Water Sd CEC pH Pm Pf / Mf Chtor1des Calcium Comments Date I 11: Ib/gal see La/100 1OSJ10M m 1130 ml@degF 32's % % % % mg<Iihg ppm ppm 12/02101 201 9.2 50 18 51 22/27 12.0 2 5.1 0.0 94.0 0 25.0 8.3 0.00 0/3.0 15000 70 12103101 201 9.2 240 22 86 35/48 10.0 2 5.3 0.0 93.8 0 25.0 8.1 0.00 013.0 15000 65 12/04101 468 9.2 150 23 65 29/46 10.0 2 5.1 0.0 94.0 1.25 25.0 8.9 0.00 0/3.0 15000 80 12/05101 1959 9.2 115 26 44 17/34 6.8 2 5.1 0.0 94.0 1.0 12.0 8.6 0.00 .1/1.8 16000 650 12/0610 1 3415 9.3 76 16 37 11121 7.7 2 6.1 0.0 93.0 .25 12.0 8.3 0.00 011.6 16000 625 12107101 3415 9.4 68 20 27 11121 9.0 2 6.9 0.0 92.2 0 3.0 8.2 0.00 012.6 16000 1200 12/08101 3415 9.0 70 14 26 7/12 3.7 1 3.8 0.0 95.2 0 3.0 9.4 0.05 .2511.4 17000 1000 12109101 3415 9.0 55 15 22 7111 5.7 1 3.9 0.0 95.2 0 1.0 9.3 0.10 .411.2 16500 800 12/10101 4418 9.1 48 16 20 9/13 0.0 1 4.5 0.0 94.5 .25 3.5 9.0 0.05 .2/.9 17000 1000 12/11101 6571 9.3 58 11 24 9/14 7.2 1 6.1 0.0 93.0 .05 7.5 8.0 0.00 011.2 17000 1200 12/12/01 7187 9.3 58 12 28 11/20 6.8 1 6.1 0.0 93.0 .25 3.0 8.4 0.00 .0512 17000 1200 I 12/13101 7905 9.5 62 16 29 15122 6.9 2 6.0 1.0 92.0 .25 7.6 7.4 0.00 012.4 18000 1800 12/14101 9303 9.8 60 13 26 16/27 10.0 1 8.1 2.0 89.0 .25 13.5 8.0 0.00 011.7 17000 1150 I 12/15101 10BOO 9.7 47 11 17 8/17 5.4 1 8.1 2.0 89.0 .01 12.5 8.0 0.00 012.0 16000 1000 12/16/01 11545 9.8 57 15 27 18/35 5.0 11.3 1 8.6 2.5 88.0 .25 15.0 8.0 0.00 012.0 17000 1480 12/17101 11545 9.8 52 10 21 6/17 6.0 12.0 1 8.6 2.5 88.0 .25 15.0 8.0 0.00 012.1 17000 1600 I 12/18101 11545 9.8 49 10 18 12/27 6.2 12.5 1 9.1 2.0 88.0 .25 15.0 8.2 0.00 012.2 18000 1080 12/19101 11545 9.9 52 11 15 11/25 6.4 13.0 1 9.1 2.0 88.0 .25 15.0 8.1 0.00 012.6 17000 980 12/20101 11545 10.1 43 15 12 5/24 6.8 1 7.8 2.0 88.0 .25 10.0 8.0 0.00 012.0 29000 1320 12121/01 11936 11.3 57 20 23 11/35 5.0 11.7 1 10.6 2.0 85.0 .25 6.9 9.3 0.65 .1512.2 33000 1120 12/22/01 12910 11.3 51 17 24 9/27 5.2 11.8 1 11.7 2.0 84.0 .25 11.0 8.3 0.00 0/2.6 32000 1200 12123/01 12910 11.3 54 17 22 9125 5.6 42.0 1 11.8 2.0 84.0 .25 11.0 6.7 0.00 0/3.0 30000 1480 12124101 12910 11.3 51 16 22 8/22 5.6 12.6 1 11.9 2.0 84.0 .25 10.0 8.6 0.40 . 2512 . 6 29000 1240 12/25101 12910 11.8 57 21 22 11132 5.0 11.5 1 13.5 2.0 82.0 0 10.0 8.8 0.20 .1/3.8 35000 800 12/26101 12910 11.8 61 22 22 10131 4.5 11.1 1 14.7 2.0 81.0 0 10.0 8.6 0.20 .15/3.9 32000 880 12/27101 12910 11.8 60 22 20 9/25 4.7 11.4 1 14.7 2.0 81.0 0 10.0 8.6 0.18 .16/3.95 33000 840 12/28101 12963 9.3 64 15 35 14116 3.8 1 5.5 2.0 91.5 0 0.0 9.5 0.04 .02/.32 18000 600 12/29101 13235 9.2 52 13 26 10/12 4.2 1 5.4 3.5 90.2 .1 0.5 9.0 0.10 .02/.24 16000 740 12130101 13425 9.1 54 11 21 10/12 6.8 1 4.6 0.0 94.6 0 0.0 9.5 0.20 . 041. 34 15500 1200 12/31101 13425 9.1 49 9 22 7/9 9.2 1 4.3 0.0 94.8 0 0.0 9.0 0.10 .02/.25 16000 1440 - -" .--. -" - - - - ANADRILL SCHLUMBERGER Survey report Client...................: BP Exploration (Alaska) Inc. Field....................: Northstar Well.....................: NS09 API number...............: 50-029-23052-00 Eng1neer.................: Leafstedt Rig:.....................: Nabors 33E State:...................: Alaska ----- Survey calculation methods------------- Method for positions.....: Minimum curvature Method for DLS...........: Mason & Taylor ----- Depth reference ----------------------- Permanent datum..........: Mean Sea Level Depth reference..........: Drill Floor GL above permanent.......: 15.57 ft KB above permanent.......: 0.00 ft DF above permanent.......: 55.52 ft ----- Vertical section origin---------------- Latitude (+N/S-).........: 0.00 ft Departure (+E/W-)........: 0.00 ft ----- Platform reference point--------------- Latitude (+N/S-).........: -999.25 ft Departure (+E/W-)........: -999.25 ft Azimuth from rotary table to target: 104.29 degrees [(c)2001 Anadrill IDEAL ID6_1C_10] - - - ~ - 30-Dec-200111:00:43 Spud date................: Last survey date... ......: Total accepted surveys...: MD of first survey.......: MD of last survey........: - - --.¡ Page 1 of 6 05-Dec-01 30-Dec-01 150 0.00 ft 13429.00 ft ----- Geomagnetic data ---------------------- Magnetic model...........: BGGM version 2000 Magnetic date............: 12-Dec-2001 Magnetic field strength..: 1149.89 HCNT Magnetic dec (+E/W-).....: 26.59 degrees Magnetic dip.... .........: 80.92 degrees ----- MWD Reference Reference Reference Tolerance Tolerance Tolerance survey Reference G. . . . . . . . . . . . . . : R..............: Dip............: of G...........: of R...........: of Dip.........: Criteria --------- 1002.69 mGal 1149.89 RCNT 80.92 degrees (+/-) 2.50 mGal (+/-) 6.00 RCNT (+/-) 0.45 degrees ----- Corrections --------------------------- Magnetic dec (+E/W-).....: 26.59 degrees Grid convergence (+E/W-).: 0.00 degrees Total az carr (+E/W-)....: 26.59 degrees (Total az carr = magnetic dec - grid conv) Sag applied (Y/N)........: No degree: 0.00 - .....->; ~, .-. - - - - - ~ - - - - - - - - ANADRILL SCHLUMBERGER Survey Report 31-Dec-200114:22:32 Page 2 of 6 -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ --- -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ Seq Measured Inel 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 qual (ft) (deg) (deg) (ft) (ft) (it) (it) (ft) (ft) (deg) 100f) type type -~- -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ 1 0.00 0.00 90.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 TIP 2 50.00 0.53 160.70 50.00 50.00 0.13 -0.22 0.08 0.23 160.70 1.06 GYR 3 100.00 1.08 176.60 50.00 99.99 0.40 -0.91 0.18 0.92 168.72 1.18 GYR 4 150.00 1.47 183.70 50.00 149.98 0.66 -2.02 0.17 2.02 175.26 0.84 GYR 5 188.00 1.76 185.80 38.00 187.97 0.84 -3.08 0.08 3.09 178.57 0.78 GYR 6 205.00 1.23 183.73 17.00 204.96 0.91 -3.53 0.04 3.53 179.37 3.13 GYR - .-'-co 7 263.00 0.33 181.10 58.00 262.95 1.06 -4.31 -0.01 4.31 180.07 1.55 GYR 8 296.00 0.43 171.80 33.00 295.95 1.13 -4.53 0.01 4.53 179.86 0.36 GYR 9 326.00 0.03 188.50 30.00 325.95 1.17 -4.65 0.03 4.65 179.68 1.34 GYR 10 356.00 0.54 65.75 30.00 355.95 1.28 -4.60 0.15 4.60 178.09 1.86 GYR 11 416.00 0.34 60.00 60.00 415.95 1.63 -4.40 0.57 4.43 172.67 0.34 GYR 12 458.00 0.70 49.60 42.00 457.95 1.87 -4.17 0.87 4.26 168.22 0.88 GYR 13 549.00 1.04 53.61 91.00 548.94 2.71 -3.32 1.96 3.85 149.46 0.38 GYR 14 640.00 0.99 51.30 91.00 639.92 3.71 -2.34 3.24 3.99 125.82 0.07 GYR 15 731.00 0.73 51.80 91.00 730.91 4.54 -1.49 4.30 4.55 109.04 0.29 GYR 16 820.00 1.43 75.82 89.00 819.90 5.86 -0.86 5.83 5.89 98.42 0.92 GYR 17 910.00 2.93 93.20 90.00 909.83 9.10 -0.72 9.21 9.24 94.44 1.80 GYR 18 1000.00 3.21 90.30 90.00 999.70 13.81 -0.86 14.03 14.05 93.50 0.36 GYR 19 1101.00 3.37 89.63 101.00 1100.54 19.42 -0.85 19.82 19.84 92.46 0.16 GYR 20 1190.00 3.30 97.90 89.00 1189.39 24.50 -1.19 24.98 25.01 92.72 0.55 GYR --, 21 1280.00 3.45 100.78 90.00 1279.23 29.78 -2.05 30.20 30.27 93.88 0.25 GYR 22 1370.00 2.93 105.10 90.00 1369.09 34.78 -3.16 35.09 35.23 95.14 0.64 GYR 23 1385.00 2.95 107.10 15.00 1384.07 35.55 -3.37 35.82 35.98 95.37 0.70 GYR 24 1409.11 2.95 106.79 24.11 1408.15 36.79 -3.73 37.01 37.20 95.76 0.07 MWD 25 1505.56 2.99 106.39 96.45 1504.47 41.78 -5.16 41.80 42.12 97.03 0.05 MWD 26 1600.40 2.61 90.57 94.84 1599.20 46.35 -5.88 46.33 46.70 97.23 0.90 MWD 27 1694.11 2.70 84.91 93.71 1692.81 50.50 -5.70 50.66 50.98 96.42 0.30 MWD 28 1790.09 2.81 88.22 95.98 1788.68 54.90 -5.43 55.27 55.53 95.61 0.20 MWD 29 1887.92 3.42 92.34 97.83 1886.36 60.06 -5.47 60.58 60.83 95.16 0.66 MWD 30 1981.80 5.25 98.33 93.88 1979.97 67.07 -6.21 67.63 67.91 95.25 2.01 MWD [(e)2001 Anadrill IDEAL ID6_1C_10] ~ - - - - - - - - - - - ~ ANADRILL SCHLUMBERGER Survey Report 31-Dec-200114:22:32 Page 3 of 6 --- -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ 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 qual (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type type --- -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ 31 2078.33 7.49 109.58 96.53 2075.90 77.73 -8.96 77.93 78.44 96.56 2.65 MWD 32 2172.47 10.60 109.69 94.14 2168.86 92.46 -13.93 91.86 92.92 98.63 3.30 MWD 33 2269.98 13.76 106.72 97.51 2264.16 112.98 -20.29 111.42 113.25 100.32 3.30 MWD 34 2363.86 16.79 108.44 93.88 2354.72 137.67 -27.80 134.98 137.81 101.64 3.26 MWD 35 2458.34 19.85 107.19 94.48 2444.40 167.30 -36.86 163.26 167.37 102.72 3.27 MWD 36 2554.44 23.12 103.85 96.10 2533.81 202.48 -46.20 197.17 202.51 103.19 3.63 MWD - "~-', 37 2649.09 25.38 101.24 94.65 2620.10 241.32 -54.60 235.12 241.37 103.07 2.64 MWD 38 2743.96 28.57 103.89 94.87 2704.65 284.32 -64.01 277.09 284.39 103.01 3.59 MWD 39 2840.14 32.61 104.74 96.18 2787.42 333.25 -76.13 324.50 333.31 103.20 4.22 MWD 40 2936.35 35.99 105.05 96.21 2866.89 387.46 -90.07 376.89 387.50 103.44 3.52 MWD 41 3026.91 37.90 104.79 90.56 2939.26 441.88 -104.08 429.48 441.91 103.62 2.12 MWD 42 3123.22 40.12 105.06 96.31 3014.10 502.50 -119.70 488.06 502.52 103.78 2.31 MWD 43 3218.35 42.75 105.29 95.13 3085.41 565.44 -136.18 548.81 565.45 103.94 2.77 MWD 44 3311.68 43.45 105.83 93.33 3153.55 629.19 -153.29 610.24 629.20 104.10 0.85 MWD 45 3343.35 43.23 105.44 31.67 3176.59 650.92 -159.15 631.17 650.93 104.15 1.09 MWD 46 3504.37 43.63 105.20 161.02 3293.52 761.60 -188.39 737.93 761.60 104.32 0.27 MWD 47 3595.67 42.44 105.01 91.30 3360.26 823.90 -204.63 798.09 823.90 104.38 1.31 MWD 48 3692.17 42.74 104.91 96.50 3431.30 889.20 -221.49 861.18 889.21 104.42 0.32 MWD 49 3787.23 44.09 105.05 95.06 3500.35 954.53 -238.38 924.29 954.53 104.46 1.42 MWD 50 3881.95 43.66 104.64 94.72 3568.63 1020.18 -255.20 987.75 1020.18 104.49 0.54 MWD --" 51 3977.94 44.77 105.12 95.99 3637.43 1087.11 -272.39 1052.44 1087.12 104.51 1.21 MWD 52 4074.08 43.42 105.19 96.14 3706.47 1154.00 -289.88 1117.01 1154.01 104.55 1.41 MWD 53 4168.47 45.10 105.54 94.39 3774.07 1219.86 -307.33 1180.53 1219.88 104.59 1.80 MWD 54 4264.17 44.57 105.29 95.70 3841.94 1287.32 -325.27 1245.58 1287.35 104.64 0.58 MWD 55 4354.67 44.12 105.78 90.50 3906.66 1350.56 -342.21 1306.52 1350.60 104.68 0.62 MWD 56 4455.59 45.33 104.77 100.92 3978.36 1421.57, -360.91 1375.03 1421.61 104.71 1.39 MWD 57 4550.30 44.89 104.22 94.71 4045.20 1488.67 -377.71 1439.99 1488.70 104.70 0.62 MWD 58 4644.66 44.61 104.02 94.36 4112.21 1555.10 -393.92 1504.42 1555.13 104.67 0.33 MWD 59 4739.33 44.79 103.82 94.67 4179.50 1621.69 -409.94 1569.05 1621.72 104.64 0.24 MWD 60 4834.40 45.07 103.82 95.07 4246.81 1688.83 -425.97 1634.25 1688.85 104.61 0.29 MWD [(c)2001 Anadrill IDEAL ID6_1C_10J - - - - - ~ - - ---. - - - - ANADRILL SCHLUMBERGER Survey Report 31-Dec-200114:22:32 Page 4 of 6 -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ --- -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ 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 qual (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) typ~ type -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ --- -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ 61 4929.18 45.45 103.55 94.78 4313.53 1756.15 -441.90 1699.66 1756.17 104.57 0.45 MWD 62 5025.61 45.57 103.70 96.43 4381.10 1824.93 -458.11 1766.51 1824.95 104.54 0.17 MWD 63 5120.66 45.43 103.80 95.05 4447.72 1892.72 -474.22 1832.37 1892.74 104.51 0.17 MWD 64 5215.98 45.30 102.82 95.32 4514.69 1960.54 -489.83 1898.37 1960.55 104.47 0.74 MWD 65 5309.02 45.26 102.82 93.04 4580.16 2026.63 -504.50 1962.83 2026.63 104.41 0.04 MWD 66 5404.93 44.93 102.78 95.91 4647.87 2094.54 -519.55 2029.08 2094.54 104.36 0.35 MWD - ~. 67 5500.05 44.60 103.00 95.12 4715.40 2161.50 -534.50 2094.37 2161.50 104.32 0.38 MWD 68 5595.85 44.19 103.52 95.80 4783.86 2228.51 -549.87 2159.61 2228.51 104.28 0.57 MWD 69 5690.67 43.79 104.33 94.82 4852.08 2294.36 -565.71 2223.53 2294.36 104.27 0.73 MWD 70 5786.37 43.51 103.82 95.70 4921.32 2360.42 -581.78 2287.60 2360.42 104.27 0.47 MWD 71 5881.62 43.59 104.38 95.25 4990.36 2426.04 -597.77 2351.25 2426.04 104.26 0.41 MWD 72 5978.50 45.40 103.91 96.88 5059.46 2493.94 -614.35 2417.08 2493.94 104.26 1.90 MWD 73 6072.97 45.66 104.14 94.47 5125.64 2561.35 -630.69 2482.49 2561.35 104.25 0.33 MWD 74 6169.23 45.92 103.83 96.26 5192.76 2630.35 -647.37 2549.44 2630.35 104.25 0.36 MWD 75 6265.00 45.81 103.63 95.77 5259.45 2699.08 -663.68 2616.21 2699.08 104.23 0.19 MWD 76 6359.87 45.73 104.28 94.87 5325.63 2767.06 -680.07 2682.18 2767.06 104.23 0.50 MWD 77 6455.86 45.42 104.96 95.99 5392.82 2835.61 -697.38 2748.52 2835.61 104.24 0.60 MWD 78 6550.63 45.13 104.93 94.77 5459.51 2902.94 -714.74 2813.57 2902.94 104.25 0.31 MWD 79 6644.71 45.03 105.68 94.08 5525.94 2969.54 -732.32 2877.83 2969.54 104.28 0.57 MWD 80 6740.40 44.76 105.45 95.69 5593.73 3037.07 -750.45 2942.89 3037.07 104.31 0.33 MWD -.'. 81 6834.54 44.30 105.74 94.14 5660.84 3103.07 -768.19 3006.48 3103.07 104.33 0.53 MWD 82 6929.93 44.27 105.95 95.39 5729.12 3169.65 -786.38 3070.55 3169.65 104.36 0.16 MWD 83 7026.29 43.27 105.20 96.36 5798.71 3236.29 -804.28 3134.76 3236.29 104.39 1.17 MWD 84 7122.04 42.95 105.78 95.75 5868.61 3301.71 -821.76 3197.82 3301.71 104.41 0.53 MWD 85 7216.23 43.13 105.92 94.19 5937.45 3365.97 -839.31 3259.66 3365.98 104.44 0.22 MWD 86 7311.24 43.49 105.02 95.01 6006.59 3431.12 -856.70 3322.47 3431.14 104.46 0.75 MWD 87 7406.20 43.45 105.36 94.96 6075.50 3496.45 -873.81 3385.52 3496.46 104.47 0.25 MWD 88 7502.12 43.82 105.49 95.92 6144.92 3562.62 -891.42 3449.32 3562.65 104.49 0.40 MWD 89 7597.90 43.61 104.04 95.78 6214.15 3628.81 -908.29 3513.32 3628.83 104.50 1.07 MWD 90 7692.37 43.32 103.02 94.47 6282.72 3693.79 -923.49 3576.50 3693.81 104.48 0.80 MWD (c)2001 Anadrill IDEAL ID6_1C_10J - - - - - - - - - ----'I - - - - ANADRILL SCHLUMBERGER Survey Report 31-Dec-200114:22:32 Page 5 of 6 --- -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ 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 qual (ft) (deg) (deg) (ft) (ft) (ft) (it) (ft) (it) (deg) 100f) type type --~ -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- --.---- -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- --.---- 91 7785.98 42.82 101.76 93.61 6351.10 3757.68 -937.21 3638.94 3757.69 104.44 1.06 MWD 92 7880.93 42.41 100.88 94.95 6420.98 3821.88 -949.83 3701.97 3821.88 104.39 0.76 MWD 93 7975.73 42.00 100.90 94.80 6491.20 3885.45 -961.86 3764.51 3885.45 104.33 0.43 MWD 94 8069.25 41.61 101.16 93.52 6560.92 3947.69 -973.79 3825.70 3947.69 104.28 0.46 MWD 95 8166.60 41.39 100.86 97.35 6633.83 4012.09 -986.11 3889.02 4012.09 104.23 0.30 MWD 96 8260.83 40.60 101.33 94.23 6704.95 4073.81 -998.00 3949.68 4073.81 104.18 0.90 MWD _. 97 8355.19 40.09 101.55 94.36 6776.86 4134.82 -1010.12 4009.55 4134.83 104.14 0.56 MWD 98 8448.60 39.33 101.20 93.41 6848.72 4194.42 -1021.89 4068.06 4194.44 104.10 0.85 MWD 99 8544.73 38.41 102.38 96.13 6923.57 4254.69 -1034.21 4127.11 4254.72 104.07 1.23 MWD 100 8638.64 38.59 101.48 93.91 6997.06 4313.09 -1046.29 4184.30 4313.14 104.04 0.63 MWD 101 8732.64 37.76 103.77 94.00 7070.96 4371.16 -1058.98 4240.99 4371.21 104.02 1.75 MWD 102 8828.22 36.79 104.44 95.58 7147.02 4429.04 -1073.08 4297.13 4429.09 104.02 1.10 MWD 103 8923.39 36.25 104.89 95.17 7223.50 4485.68 -1087.42 4351.92 4485.72 104.03 0.63 MWD 104 9017.60 35.73 105.10 94.21 7299.73 4541.04 -1101.74 4405.40 4541.08 104.04 0.57 MWD 105 9113.03 35.36 105.01 95.43 7377.38 4596.51 -1116.15 4458.97 4596.55 104.05 0.39 MWD 106 9209.57 35.24 104.86 96.54 7456.17 4652.29 -1130.53 4512.88 4652.33 104.06 0.15 MWD 107 9303.34 35.22 106.15 93.77 7532.76 4706.37 -1144.99 4565.00 4706.40 104.08 0.79 MWD 108 9399.22 35.27 104.88 95.88 7611.07 4761.68 -1159.79 4618.31 4761.71 104.10 0.77 MWD 109 9493.19 35.26 105.52 93.97 7687.79 4815.93 -1174.01 4670.66 4815.95 104.11 0.39 MWD 110 9587.41 35.12 104.65 94.22 7764.79 4870.22 -1188.15 4723.09 4870.24 104.12 0.55 MWD -, 111 9682.41 34.38 104.95 95.00 7842.85 4924.37 -1201.98 4775.44 4924.39 104.13 0.80 MWD 112 9777.15 33.63 104.98 94.74 7921.39 4977.35 -1215.66 4826.63 4977.37 104.14 0.79 MWD 113 9873.16 32.68 103.70 96.01 8001.77 5029.85 -1228.67 4877.50 5029.87 104.14 1.23 MWD 114 9969.34 31.64 103.16 96.18 8083.19 5081.04 -1240.56 4927.29 5081.06 104.13 1.12 MWD 115 10063.50 31.07 103.64 94.16 8163.60 5130.03 -1251.92 4974.95 5130.05 104.12 0.66 MWD 116 10159.90 30.62 103.54 96.40 8246.36 5179.45 -1263.53 5022.99 5179.48 104.12 0.47 MWD 117 10253.98 30.34 103.90 94.08 8327.44 5227.17 -1274.85 5069.35 5227.19 104.12 0.36 MWD 118 10348.63 30.42 103.69 94.65 8409.09 5275.04 -1286.26 5115.84 5275.06 104.11 0.14 MWD 119 10442.73 30.19 103.69 94.10 8490.34 5322.52 -1297.50 5161.97 5322.54 104.11 0.24 MWD 120 10537.51 30.11 104.00 94.78 8572.29 5370.12 -1308.89 5208.19 5370.15 104.11 0.18 MWD [(c)2001 Anadrill IDEAL ID6_1C_10J r--- - - - - - - - -....... - - - - -- -. ANADRILL SCHLUMBERGER Survey Report 31-Dec-200114:22:32 Page 6 of 6 --- -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- __0___- -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- ------ 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 qual (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type type --- -------- ------ ------- ------" -------- -------- ---------------- --------------- ----- ----- __0___- -------- ------ ------- ------ -------- -------- ---------------- --------------- ----- ----- --'---- 121 10632.90 30.29 104.19 95.39 8654.74 5418.10 -1320.58 5254.73 5418.13 104.11 0.21 MWD 122 10727.22 30.16 104.18 94.32 8736.23 5465.58 -1332.21 5300.76 5465.61 104.11 0.14 MWD 123 10822.87 30.09 104.53 95.65 8818.97 5513.59 -1344.1"1 5347.27 5513.62 104.11 0.20 MWD 124 10917.62 29.22 104.75 94.75 8901.30 5560.47 -1355.96 5392.63 5560.49 104.11 0.93 MWD 125 11012.48 28.59 104.22 94.86 8984.35 5606.32 -1367.43 5437.02 5606.34 104.12 0.72 MWD 126 11107.43 28.69 104.69 94.95 9067.68 5651.83 -1378.79 5481.09 5651.85 104.12 0.26 MWD - ---, 127 11203.31 28.98 104.46 95.88 9151.67 5698.07 -1390.43 5525.84 5698.09 104.12 0.32 MWD 128 11297.42 29.20 105.66 94.11 9233.91 5743.82 -1402.32 5570.03 5743.84 104.13 0.66 MWD 129 11393.64 29.02 105.59 96.22 9317.98 5790.61 -1414.93 5615.10 5790.63 104.14 0.19 MWD 130 11454.60 28.66 106.06 60.96 9371.38 5820.01 '-1422.94 5643.40 5820.02 104.15 0.70 MWD 131 11584.59 28.51 105.76 129.99 9485.52 5882.18 -1439.99 5703.21 5882.19 104.17 0.16 MWD 132 11681.65 27.50 105.83 97.06 9571.22 5927.74 -1452.40 5747.06 5927.75 104.18 1.04 MWD 133 11776.10 25.92 105.95 94.45 9655.58 5970.17 -1464.02 5787.89 5970.18 104.19 1.67 MWD 134 11868.54 24.49 105.26 92.44 9739.22 6009.52 -1474.61 5825.80 6009.53 104.20 1.58 MWD 135 11968.31 23.34 102.70 99.77 9830.43 6049.96 -1484.40 5865.04 6049.97 104.20 1.55 MWD 136 12061.52 22.57 102.53 93.21 9916.25 6086.30 -1492.34 5900.51 6086.31 104.19 0.83 MWD 137 12156.73 21.99 102.13 95.21 10004.36 6122.37 -1500.05 5935.77 6122.38 104.18 0.63 MWD 138 12251.34 21.11 101.65 94.61 10092.35 6157.09 -1507.22 5969.78 6157.11 104.17 0.95 MWD 139 12346.24 20.03 101.03 94.90 10181.20 6190.39 -1513.78 6002.47 6190.41 104.15 1.16 MWD 140 12441.21 18.48 100.87 94.97 10270.85 6221.66 -1519.73 6033.22 6221.68 104.14 1.63 MWD -"'. 141 12536.85 16.97 99.10 95.64 10361.95 6250.69 -1524.79 6061.89 6250.72 104.12 1.68 MWD 142 12632.19 15.83 98.69 95.34 10453.41 6277.49 -1528.96 6088.48 6277.52 104.10 1.20 MWD 143 12727.21 14.64 97.16 95.02 10545.09 6302.30 -1532.41 6113.21 6302.35 104.07 1.32 MWD 144 12821.49 13.77 97.20 94.28 10636.49 6325.26 -1535.30 6136.16 6325.32 104.05 0.92 MWD 145 12837.53 13.49 97.36 16.04 10652.08 6329.01 -1535.78 6139.91 6329.07 104.04 1.76 MWD 146 12961.81 12.63 96.87 124.28 10773.14 6356.87 -1539.27 6167.78 6356.95 104.01 0.70 MWD 147 13058.42 11.11 95.45 96.61 10867.68 6376.55 -1541.41 6187.53 6376.63 103.99 1.60 MWD 148 13244.07 7.85 90.94 185.65 11050.77 6406.56 -1543.32 6218.02 6406.68 103.94 1.80 MWD 149 13335.65 5.85 89.51 91.58 11141.70 6417.16 -1543.38 6228.94 6417.30 103.92 2.19 MWD Survey Projected to Total Depth: 150 13429.00 3.90 87.42 93.35 11234.70 6424.80 -1543.20 6236.87 6424.95 103.90 2.10 MWD [(c)2001 Anadrill IDEAL ID6_1C_10J I I I r I I I I [ I I I ( ,..1' ( NS09 ProJlnosed Tops Actual Deoths Delta Days since Formation TVDss TVDrkb MDrkb TVDss TVDrkb MDrkb TVD Spud Top Permafrost 1149 1205 1205 1149 1205 1205 0 1 Base Permafrost 1499 1555 1556 1499 1555 1556 0 1 SV6 - top confining zone 3010 3066 3186 3010 3070 3190 -4 1 Surface casing point 3170 3226 3408 3170 3216 3398 10 1 SV5 - base confining zone 3280 3336 3562 3279 3335 3560 1 6 SV4 3600 3656 4012 3604 3660 4010 -4 6 SV2 - top upper injection zone 4000 4056 4574 4014 4070 4585 -14 6 SVI - top major shale barrier 4400 4456 5135 4419 4475 5163 -19 6 TMBK - top lower injection zone - Top Ugnu 4770 4826 5655 4770 4845 5678 -19 7 Top Schrader Bluff - Base Ugnu 6360 6416 7870 6360 6440 7900 -24 9 Base lower injection zone (top Colville) 6995 7051 8691 7006 7062 8724 -11 10 THRZ-TopHRZ 8740 8796 10755 8800 8856 10867 -60 12 BHRZ - Base HRZ 8800 8856 10823 8859 8915 10936 -59 12 Top Kuparuk 8870 8926 10902 8929 8985 11 012 -59 12 Kuparuk C 8970 9026 11015 9044 9100 11142 -74 12 Top Miluveach 9310 9366 11400 9356 9412 11500 -46 12 Intermediate casing point 9410 9466 11514 9410 9470 11545 -4 12 Intermediate logging point 9410 9466 11514 94.10 9470 11545 -4 12 Top Kingak 9830 9886 11989 9844 9900 12045 -14 18 Fault #50 throw = ~ actual throw = 240' 9800 9856 11955 10154 10210 11955 -354 18 Top Sag River 10654 10710 12923 .10652 10708 12896 2 18 Geol t~rget #1 10654 10710 12923 10654 10710 12898 0 18 Intermediate casing point 10694 10750 12968 10667 10723 12911 27 18 Top Shublik 10740 10796 13020 10754 10810 .13000 -14 24 Top Ivishak 10830 10886 13122 10834 10890 13095 -4 24 Top Kavik 11150 11206 13484 11149 11205 13400 1 25 Current Depth 11179 11235 13429 -11235 27 Total Depth 11200 11256 13541 11179 11235 13429 Top lisburne 11250 11306 13600 11250 11306 t, L Date: 01-18-2002 Transmittal Number: 92381 BPXA WELL DATA TRANSMITTAL Enclosed are the materials listed below. This data is being sent separate because of the f d . I If h t' I t t . th PDC t 564 4091 con I entIa nature. au aye any ques Ions, pJ ease can ac me In e a - . SW Name Date Media Title NS09 01-01-2002 COLOR LOGS (MUD); END OF WELL REPORT; aDJ"'d.IQ HARDCOPY WELL DATA; NS13 07 -03-2001 COLOR LOGS (MUD); END OF WELL REPORT; . ".'.. ,. . HARDCOPY WELL DATA; NS13 .. 12-30-2001 HARDCOPY; ANADRILL DIRECTIONAL ÒD/..O<l'to SURVEY; ~(~ Please Sign and Return one copy of this transmittal. Thank You, James H. Johnson Petro technical Data Center Ken Lemley MB3-6 Esther Fueg MB3-6 Attn: Howard Okland (AOGCC) Attn: Buford Bates (Murphy Exploration (Alaska), Inc Attn: Tim Ryherd (DNR) Attn: Doug Choromanski RECEIVED J.~N 1 [J 2002 AI8I8 (I & Gas Cons. Commi8ion Andlorage Petro technical Data Center LR2-1 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 99519-6612 , ! t\JS-LF¡ ( ( Unitea States Department of the Interior MINERALS MANAGEMENT SERVICE Alaska Outer Continental Shelf Region 949 East 36th A venue, Suite 308 Anchorage, Alaska 99508-4363 2 3 NOV tOil Mr. Floyd Hernandez Senior Drilling Engineer BP Exploration (Alaska) Inc. 900 East Benson Blvd. Anchorage, AK 99508 RIECIEIVIED NOli 2 Alasks 01/ 9 2001 &Gasa Ancho:!;" COlT1rnitOl.\' ""'8 "'"IOn The Application for Permit to Drill (APD) for NS-09, Northstar Development Project, is hereby approved, subject to the conditions stated in this letter. Also enclosed is a signed copy of the APD (enclosure 1). The API number is 50-029-23052-00 for the NS-09 development well. Dear Mr. Hernandez: State approval of an APD for this well is required prior to the start of operations for NS-09. This well meets the criteria established for the diverter departure approved on October 13,2001, therefore no diverter will be required during the drilling of the surface hole portion of the well. The Northstar reservoir has been classified, as required under 30 CFR 250.417 (c), as hydrogen sulfide absent, therefore no hydrogen sulfide contingency plan is required for this well. Well information for this well will be submitted as specified in our letter of March 26, 2001 and modified on November 15,2001 (enclosures 2 and 3). We understand that BPXA and Phillips have an agreement to make available any rig on the North slope in the event a well control incident occurs. However, as a condition of the September 3, 1999, approval of the Northstar Development and Production plan, this office requires the name and status of a rig that would be used for this purpose. BPXA will need to submit the name and status of such a rig prior to drilling out of the surface casing shoe. i (' Mr. Floyd Hernandez BP Alaska Exploration Alaska, Inc. il , 2 This office plans to conduct periodic inspections of the drilling operations and anticipates the need to utilize BP transportation and lodging. As allowed in 30 CFR 250.133, BP may request reimbursement for the cost of transportation and lodging provided for MMS personnel. Your request must be submitted within 90 days of the inspection. After office hours, weekends, and holidays, all calls related to drilling activities or changes to the approved APD should be made to Mr. Kyle Monkelien at the following numbers: Home Cell Phone 907-349-5083 907-250-0546 or 907-229-0542 If you should have any questions regarding this approval during normal business hours please call Mr. Monkelien at 907-271-6431. Enclosures cc: Tom Maunder, Senior Petroleum Engineer, AOGCC ee.~ ) ,/ f "I I~ Enclosure 1 United States Department of the Interior MINERALS MANAGEMENT SERVICE Alaska Outer Continental Shelf Region 949 East 36th A venue, Suite 308 Anchorage, Alaska 99508-4363 13 OCt. .. Mr. Floyd Hernandez Northstar Sr. Drilling Engineer BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK. 99519-6612 Dear Mr. Hernandez: RECEIVED NQV 2 9 2001 AlaskaO¡I&Gascons Comm' . Anchoragå 188100 On August 21, 2001, you submitted a request for a departure from 30 CFR 250.409 "Diverter Systems," to allow drilling and setting the ~urface casing for Federal OCS wells on the Northstar production island in the SV6 formation without a surface diverter. As reflected in your letter and . discussed with Mr. Joe Polya on October 10, 2001, the basis for this request is the absence of gas being detected from any of the previous 6 wells drilled; personnel and equipment safety concerns' in installing a complex divert configuration under current facility constraints; and the precautionary plans BP has in place to monitor and control minor gas in the unlikely event it occurs. In accordance with 30 CFR 250.1 03(b), I hereby approve your request for a departure from the requirements of 30 CFR 250.409 to maintain a diverter on the surface portion of the federally approved Northstar wells. This approval is conditioned upon BPXA maintaining the same casing and cementing program currently being used for the Northstar wells and no indication that gas has migrated into the area covered by the surface casing. In the event that significant gas is observed during these drilling operations, the MMS is to be notified as soon as possible and this departure may be withdrawn. Mr. Floyd Hernandez BP Exploration (Alaska) Inc. 2 As discussed with Mr. Joe Polya, I am requesting that BPXA provide this office with a narrative protocol which describes the process and conditions under which emergency actions would be taken in the unlikely event an unexpected gas release is encountered during drilling operations. If you have any questions, please contact Kyle Monkelien at (907) 271-6065. Sincerely, . Regional Supervisor, Field Operations Cc: Commissi oner Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 ~'p . , , Ii ( ~ United States Department of the Interior Enclosure MINERALS MANAGEMENT SERVICE Alaska Outer Continental Shelf Region 949 East 36th A venue, Suite 308 Anchorage, Alaska 99508-4363 I 6 hWi. 1601 Mr. David W. Douglas Petrotechnical Data Center BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, Alaska 99519-6612 RECEIVED . Dear Mr. Douglas: NOV 2 9 2001 Alaska Oil & Gas Cons. Commission Anchorage On December 12,2000, you spoke with Mr. David Roby of my staff regarding data submission requirements for the Northstar Development Project, and subsequent activity on the Alaska Outer Continental Shelf. This letter outlines the Minerals Management Service's (MMS) requirements for type of information, the number of copies, and the formats required for the data submission. Since first production is still several months away this letter deals only with drilling related data requirements, a later letter will outline our data submission requirements for production related activities. The following lists the various types of data that are required and how that data should be submitted to the MMS for both State and Federal wells. Where possible the MMS and/or AOGCC fonn number is listed to aid you. Copies of all the referenced MMS forms are enclosed for your information. Application for Permit to Drill . For Federal Wells (Form MMS-123 see MMS regulations 30 CFR 250.414) Four copies total Two complete copies with appropriate supporting information, or reference to previously submitted information. One copy that will be signed and returned to BPXA after MMS review is completed. Since this copy will be returned to you it is not necessary to attach all of the supporting information that is attached to the copie~ mentioned above. One "Public Infonnation" copy with data specified in MMS regulations 30 CFR 250.1 1-7 & 118 . For State Wells (Permit to Drill (Form 10-401)) Four copies total Two complete copies of original application submitted to AOGCC. Two copies of AOGCC approval. Mr. David W. Douglas BP Exploration (Alaska) Inc. 2 Sundry Notices . For Federal Wells (Form MMS-124 see MMS regulations 30 CFR 250.415) Four copies total Two coll1plete copies with appropriate supporting information, or reference to previously submitted infonnation. One copy that will be signed and returned to BPXA after MMS review is completed. Since this copy will be returned to you it is not necessary to attach all of the supporting infonnation that is attached to the copies mentioned above. One "Public Infonnation" copy with data specified in MMS regulations 30 CFR 250.117 & 118 . For State Wells (Application for Sundry Approvals (Fonn 10-403)) Four copies total Two complete copies of original application submitted to AOGCC. Two copies of AOGCC approval. Well Summary Report . For Federal Wells (Fonn MMS-125 see MMS regulations 30 CFR 250.416) Three copies total Two complete copies with appropriate supporting information, or reference to previously submitted infonnation. One "Public Infonnation" copy with data specified in MMS regulations 30 CFR 250.117 & 118 . . For State Wells (Well Completion or Recompletion Report and Log (Form 10-407)) Two complete copies of what was submitted to the AOGCC. Daily Driller's Reports . For Federal Wells (See MMS regulations 30 CFR 250AI6(c)(3» Daily Either fax a copy to 907-271-6504; or provide the MMS with access to the Shared Services Drilling website that contains the daily drilling reports. When well is completed Two copies total - A complete set of Daily Driller's Reports should be attached to each of the proprietary inf~rmation copies of the Well Summary Report (Fonn MMS-125). . For State Wells Two copies, if the AOGCC requires their submission. . (' Mr. David W. Douglas . BP Exploration (Alaska) Inc. ( 3 Geological and Engineering Reports Prepared by BPXA or Service Companies Types of reports include: Paleontological, Core Analysis, Perforating Activities, Cementing Activities, Well Testing, Fluid Analysis, Etc... . For Federal Wells (See MMS regulations 30 CFR 250.416(c)(4» Two paper copies of these reports and, if readily available, one electronic copy (these reports are not necessarily required, but if they are prepared must be submitted.) . For State Wells Two paper copies of these reports and, if available, one electronic copy. Submission of these reports for State wells is only necessary if the infonnation is also submitted to the AOGCC. Well Logs . For Federal Wells Mud Logs and Other Drilling Logs Collected While Drilling Daily Either fax a copy of the previous days logs along with the Daily Driller's Report, or allow the MMS access to Shared Services Drilling website if this infonnation is available there. When well is completed Submit in same manner as Final Composite Logs below. Wireline and Other Logs Not Collected While Drilling Field Prints One paper copy for each logging run Final Composite Prints Three copies total One paper copy. One sepia copy. One digital copy on CD-ROM that can be read on both UNIX and PC systems. Include verification listing so that we can ensure the integrity of the . digital data. . F or State Wells For all types of logs two copies total . One paper copy One digital copy on CD-ROM that can be read on both UNIX. and PC systems. Include verification listing so that we can ensure the integrity of the digital data. Mr. David W. Douglas BP Exploration (Alaska) Inc. 4 Directional Surveys . For Federal Wells Three copies total Two paper copies One electronic copy on diskette . For State Wells Two copies total One paper copy One electronic copy on diskette The MMS retains the right to request other reports and records in accordance with 30 CFR 250.416(f). Well data and information submitted to the MMS for OCS wells is protected and will only be released to the public in accordance with the provisions of 30 CFR 250.196 and 30 CFR 252. Please note that these regulations include specific instructions for submitting and retaining various forms and other information, which may differ from the State of Alaska's requirements. Well data and information submitted to the MMS for State wells is provided in accordance with Article 3.9 of the Northstar Unit Agreement and shall be protected from disclosure pursuant to governing law and regulations. Please let this office know what digital data format will be utilized for submitting log infonnation so that we can verify that the fonnat is supported by our computer systems. If you have any questions or comments please feel to contact Mr. Dave Roby at (907) 271-6557. Sincerely, ~\\~ Regional Supervisor Field Operations Enclosures cc: Mr. Floyd Hernandez, BPXA Mr. Bill Turnbull, BPXA ChaÜH1~n Alaska Oil and Gas Conservation Commission 333 West ih Avenue, Suite 1000 Anchorage, Alaska 99501 c¡. " (RECEIVED ( u.s. Department of the Interior SUbmilOrig;n81~~~'8~C~P;~Ow~~ . \ R ~~~~.1010.0044 Minerals Management Service one co~aSká'ðiï & ~tón'~~on . p mber 30,2002 APPLICATION FO~~RMIT TO DRIL~OV 15 2001 S ð - a '-'1 - ~ ~C 5~... () á 3. WELL NO. NS09 11. O~~P. ESS (Subm_~ERA TIO NERALS MANAGEMfNT SERVICE MI '-BPExproration Alaska, Inc 900 E. Benson Blvd. Anchorage, AK 99508 1. 1&1 ORIGINAL 0 CORRECTION 2. API WELL NO. 8. FIELD NAME 9. UNIT NO. 10. MMS OPERATOR NO. L A 1129' FSL 642' FEL S11 T13N R13E UM ADL 312799 14. AREA NAME Beechey Point 20. RIG NAME 6-03 18. WATER DEPTH (Estimated) 40' 19. Elevation at KB RKB = 55.77' Nabors 33E 21. RIG TYPE Rotary 22. TYPE OF WELL EXPLORATORY 24. TOTAL DEPTH (Proposed) DEVELOPMENT x 11/27/01 MD 13,540' TVD 11 ,256' 25. ATTACHMENTS (Attach complete well prognosis and attachments required under 3OCFR 250.414(b) through (g) or 30CFR 250. 1617(c) and (d), as appropriate.) 1. MMS form 123 2. Approved proposed directional survey including vertical view, plan view, and travelling cylinder 3. BOP Schematic with pressure ratings and dimensions 4. Plot of pore pressure, mud weight, and frac gradient versus casing setting depth (TVD) 5. Spider map of existing wells and proposed NS09 6. NS09 Statement of Requirements 7. Well Plan Summary including anticipated surface pressures, zone characteristics, casing program, logging plans, formation tops, cement program, and mud program. 8. Proposed Completion Diagram 9. Stress test calculations 26. CONTACT NAME 27. TELEPHONE NO. Floyd Hernandez (907) 564-5960 28. AUTHORIZING OFFICIAL (Type Name) Floyd Hernandez 30. AUTHORIZING SIGNATURE 29. TITLE 5(.11,'6 r Drilling Engineer 31. DATE ~:29:G~ \\ (15/0 \ THIS SPACE FOR MMSUSE 0 LY. APPROVED: ~th Attached Conditions DWithout Conditions BY API WELL NO. ASSIGNED TO THIS WELL ~. ð ... C e. 'R. e.."ð ' 0 ~ c...\ ~ V ~.e. ~V \~ a ï TITLE ç \ -e..\ ~ è ~ -t.~~+ 16~,:j DATE ~ I /7.J IGJ { PAPERWORK REDUCTION ACT STATEMENT: The Paperwork Reduction Act of 1995 (44J.S.C. 3501 et seq.) requires us to inform you that we collect this information to obtain knowledge of equipment and procedures to be used in drilling operations. MMS uses the information to evaluate and approve or disapprove the adequacy of the equipment and/or procedures to safely perform the proposed drilling operation. Response to this request Is mandatory (43J.S.C. 1334). Proprietary data are. covered under 30 CFR 250.118. An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valiCÐMB Control Number. Public reporting burden for this form is estimated to average 3 1/2 hours per response, including the time for reviewing Instructions, gathering and maintaining data, and completing and reviewing the form. Direct comments regarding the burden estimate or any other aspect of this form to the Information Collection Clearance Officer, Mail Stop 4230, Minerals Management Service, 1849 C Street, NW, Washingtoo, DC 20240. M M S FORM MMS-123 (September 1999) (Rep/aces all previous editions of Form MMS-123 lNhich may nd be used) u.s. Department of the Interior Minerals Management ServIce ~ .. MMS Supplementãl APD Information Sheet OMB CONTROl NO. 101~131 expiration Date: September 30. 2002 1. DESIGNATED OPERATOR: ..B.IX---¡r--- 5. AREA/BLOCK: ~€€( Ht=y -¡:>¿lllLr I:TI u, -- . fL &~ 2. CONTACTIPHONE NO..JJr¡yJ).L!&ll!!.I'f1t!~..2Z"(J 8. SURFACE LOCATION: II ;1 feet from ~ Le.se Line and lit¡ 2- feet from E- Lt..t Lint 3. LEASE: OCS_=.y..:::: 1;>1 'If I - T. BOTTOM HOLELOCA 110N: '17'12 ".t f<om oS t". Lln. on. '/ ¿,œ- f... &om LL.... LInn 4. WELLNo:_~.5 -ð~ - - a.RIGNAMElTYPE:--Al.tlOOr<.'s--3p-F- j?ðTElßJ(- , - 9. WATER DEPTH: ----Yfl ' 10. RKB: ~ 7"7 ., 11. TYPE WELL: C EXP Ç{ DEV 12. APPROXIMATE DATE WORK WILL START: 11~5/CJ1 Hole SIze (In.) Clling (Indlc.te If liner) Casing SIze (In.) Drive' Structural ~o 1.0 Conductor lie I Surfac. II)}'? - 1'Z~ F~-reø?1s) 'I q~k () if 1D.tllLl /J'> 0 1ê-ILlllleL 7 1/ I PfZ.cOfJl:rÌtJ. 1/ ø Ii" LIIJEt2. Lf Iz,. Weight Grade i~/; '(. 5'~ - ~-t: - t..... ?() il. l. - 'ti'O .:.t4' ¿--gO /,2. l(' /3C!..¡¿ Burst Rating - ---------- Type of Connection Safety Factor. Clling Depth Rated BOP Working Pressure Cement (ft') BOP Tt.t Pressures Drflllng fluid 1---- Typt (011 bast, water bast, synthetic) Well. head Rating (psi) Shoe BOP Size MASP (pII) Annular Annular MD TVD Casing I Shot Tttt (psi) (ppg) PP MW FG Ram Ram c T Co"'." ."'n. ~T>,:...;."J... '<'.::"-'" L! I¡':',';;;::'~L:-:;;:):'.::{:;-,;':~':;';::-~>::::'::-,- -... ,.,n. .'.t-.-.:--.'.-.:¡".'.-.-..,':--.:.1'.'.:'.-'.--..:.::.'1".-:'-",<,t..":,--'.-.',--'.,,'.".:.,;'"..'k-.:"."""" ,.1" _c,-,c:':J~~,u'::;::;-":':'-";',-;::/;J>:~"::,-:~,:::~-':.:,>-:::-;';'-:, :-.-' '-'-",-' """ uJ T:U) () t.61 z1>( - þe.IVG tV 3?/O 2fi' 00 5l; z.O 2:2. 7 C> fÞ~"b 47¿,f) 7~40 5"110 "440 ï S-fJ() - - .- - - - - - - - - - - - 8""c. 1671' 1..34> þ.'7 ),-,;t I'3lID7 11."51 ~,S-I J~ I ~ØfI' Ir~1, I swo 13-~-m::> 21~ ~ ~ClJV 51S7JtJ wR-T~ ßR5li' ?15?f!) (),,) '3 51.P'1 GiL-:fI1 '343~ ),5"4 II"'~ ¡,qLlI"~13 1'11~{, 11.*' liS" Is-CØ"D ql/lIl# 1,C¡,1,.I"ll2\1.)] 1~111"71í'.95"'ltI,31/S.3I.5"ao lÞ"75"D ~k I~~qwð ØlfO ~ 1,9r~ 1J)J4 -rt:f<.. ß¡CJ~ 3.J15D /~,) Y!:> ð' 7 f/3ð!J 37ðD 11,3 31P! .tJ Þ'H""Ëi? .BFbt""" fò TC -/31 - V JI1 ¡)f ,«-F- 30¡/9 - IA/r'I T~ 101/, 'II ¡3/}~. C¡,2ðZ> l¡ lS& --- I MINIMUM DRILLING FLUID QUANTITIES: L'?!.~___--- SAC}<S BARITE and ----'::-c!p------- SACKS GEL ZONE PROTECTION STATEMENT: tf.lYlr-A!.L_l'"ð..2-.tJ{:.ð.1.1:- (/ ?>¥..s'lLtr....1'-'!.e:/!-!LLa. 5J!..Z..{151cr) ..fu' <-:"Y--~ç1'LrE.lJ.- ( 7 r. _<f::_-~ (2. Y L I Ncìr S L..------------------- DRILUNG FLUID DISPOSAL STATEMENT: ¿~~--':!!:. ~~~d..~~ C1= ";'..J ¡Vs.ID f)/~PO~L WE't.L. AfI,fS FORM MMS-123S (September 1999) "- : :-,' ---' , " - . :' --, u -,..-',- - -, --, - ,-- :- - - - -- " - PAP.-ERWORK'REOVCil0N ACT'STATEMEr-n:: n,.:Pi~ ReducÍlon ACt of ~995~..'U.S;(t_3SO,1~8eq:) ;.qu1rt8 U8 JO.In1onnYoultlll WI - collkl:lh'l:lritOC!1ÌIIIO(llo OI:illln wen 8IälVì;.wèl1,i'nd C8ilðO;~tt:;nd.weU cairng,øonflouflilöo dl1....MMs:u'iI:11iI8,I"f0nn8t1ot1tö,htYl,~ -, ;" ,d_II~:81'itÌ:J~fiStri'lii~~"0Ì'I..--thi"Wel1á;!lndir-.IriJ1r--.JÜ.~Iän:~,i1:~ö1¡;¡.ü~i~~pninC8;Wiil!.~a~;þ!ïh~i:l:ti. )OnI" ~~,~(4~~',C. ,~~.: ';"~ : ;}~:~r:t~. ,tt~,~~;~~~'j'~~,f~~-~~~~~~~;~~~~~=m:g~r~:~J:::rt:1.~7;~~;:~: ~~ ':, . ríä~ì.f: .' tng,)tiè>tliniTó't':~~~~~'gäìtítrmg¡iíÎl~;m'¡Jnlí1r:í1rig-d¡¡I.;':iiìdlë:~Øli1l'~11d:~t"'~':CIí'8ä:éÖ""~ . '- ' ' "-': : -- re9l.ri:l1"gåfit;tiurilen.iil'tlriiitërOt'órot'iiei-a.~oNht(~'Ij1;ti:f.~hIJ\'ifõrmlillOtI;þolleclIÒft,Cliininci.ofIJcer; Mirr:.-$tÖp:<f23Ò;'MinmttMánegtintnt -- .-:; '--,~~;! i%r;;IT'#!;~7pr;~¡;~;~¿~~{[Ç;.,: ;;-': ,:' ;1Þ¡~':', ": :';,;:;.. ~~j¡':;!T ;',: ".. '.;.' ,C'I ;'.,.;- .~j .. ..:~"':: "'-~~:"";~~%~':" ,f, ":~':.;':'7e;n£;::-:t"-"';N':~~'..- ?"/"~t:~~>~- "~~~~'ß. ;'!";:;O-'~":""i'?),c Y'"F"'X~5~~~ ~- ~m.-~~~~!"'..:~~:<f~"""--_....... JStatement of Requirements (1) G('neral I nfnrmation f)('liv('ry ..nil: I'ro lo~('d W('II :'II:lIIll': W('IIT}p(': ,\ Fl.: "IIllI1lh('r: :'- orr!l~I~r NSO9 I'rC'llllœr Northstar ;~~ ~~~ ...~ S:\^N )\NI!r1h~l~r\I¡UnSt:RF^CE\Wcll fik's\I'<S.OI}\C;;OR Filcnamc OJ?; P7 SOR Vcrsionll I NS.09 SOR 10.3.01 ~ . 'kJ;,P. - -<.,,: ,'-,,- -'".. .._",'~,'-~;O~i.~....:~"!'~"'~o:!o;!Wl'-.~~'iq.:t..."";IW.~-iI".~;..~"?~f-~;;'~;¡"""(¥'*-~~~~I!~¡;)Ç,t~,.: ~ .'f~ Wen Clas~mcatlon PmdaC<'r I~ t) NSO9 10/2/01 Date: l'alhw:IY Welll'lan -' . - . - ,- --.'- ,,' ,-,,_.' .,... - ,,¡; > "!'::.~ .'-",:, Tllr;,:,'1 \)('~i;.:n:llinn: Ivishak I'rllpo~ed Tlllal f)cplh Min. f)('C;in'd ColO lMinn Sill': I'rn ln~.'d SllIId f)lIle: D!'41 Mf)rkh 4 112" Tar !;('t lfori7.nn: Iyi~hak Proposed RI !;: NJ3E ... .. -', . ./;.-'- .,.---,.-c. --O-'.<,'.f---",-.-----",-..... I . PrimAry 2 . S.'rondllry 3 - S.'roOllllry (3) Critirnllssu('s I 2 3 4 ):ill an;! ;;¡1mpk'le w\'11 :!~ a 4-1/2" F~mlllCl'r wirh:nlhc his!l:ïk rc~er 'toir ¡'('qllirc r<,~crvoir llal:t in S:lg :lr.cllvi~h:!k Acqllire rc~.:rvoir dala in KlIl'anrk ~~ ."""-,:~:"i;;,,"~;'<.,""'-c1Y-,~'I,«o"",~<;"4..;7-:!~';.'t!!'~dt'i"",,':r,*-'i'~-:;!-~ii""""""'+.."r"';õ~~ .;.~~- JI'~~." .,~~ ;.~ ._..-,...-C_,_.--,~,o,,-,-;""~o..r"-. - .- "-"';""'- "-'.."-"';-"'.N._"._",..".;:~;-;¡;_.,,_.."',.'- --;.,-; ,. ----,-~ c._,,_'.-,---.'~.__._..-' -. --- .'.'---,' ". -- , . ,- '.-.."--F---.-"~"'.". ". ~.. .~ S .i:~ ¡~ ,;,-0,-., -<,...:'" (, >..~-~~t".:-t¥'j,~~.;,~~.~...:f~;i':'.'" .....t",-!A.l.¡¡,,',~'¡"".;;o-.I~ '~""'~~'_.~"'1~,}M~.v.Ñ~MlWof<.~. ~ ..' ~ ~ .; ~ I,; Sllc;;e~~rlllly ccmcnt acro~s :111 rcCJllin'¡ zC'.ncs Rcm:lin within drillinj:! I:lrgcl Ev:llilale Kllparuk 10 dclcrmine prodllclivily O~I:lin rc~ervnir I're~~\!rt's in I...i~h:lk u - Genl'ral \Jl'~rrillli"n: SlIñllre ASP ColJrd: ~lIrf:lre TUS Coord: CrJlldllrlnr SI:!I..,: SlIrfare ("II-in!! \Jl'plh: Inl('rlllcdi:lle Ca!'in~ f)('plh: InlcrnK'diale Liller \)('plh: Prodllrlion Linrr }rplh: Target Informatiul1 -- Ih,f.'n'nc.' \)IIrlllll<'lIl: Tllr:;:el Typ(': Ih'!!inninl! of horizonllli s('rli"n (III IS): End of hnri7onlal scrlinn (F:IIS): (',rnrrir Tllr~('1 ShApe IIori7onlall.t'nclh Appro\ll1Inle Slel)olll: Tnrl!('1 ASI' C'"oordinllll"ò: - '(2) Ohjectives - .<4) Well Specifics Tllr~,'1 Pllly!:"n AsrrrRS C:llordinnl(": :,</orlh Tar:::.'1 Asr ('nortlinlllr<;: \.\'1."'1 Tnr¡:el Asr' CIJordinal~: Smith Tl1r:::el ASr ("¡Hlrdinnl<"i: Ellsi Tar:::<,1 ,\SI' f".lHlrdln:II('!': .- Drill rrom ~kl ( I) I:e:!dinl! E:I~lward hI I:lrr-CI X .:nord 6!"),R.\3.4") WELL PAD Pl..J\NT TkO; (~"') 27) I I I T. 13 N., R. 13 E., Se:: 11 1..1¡~"r;h! I 1...>n.!IWco,) NORTH:I 4,990,09 I EAST: I 992.20 1121)' I'SL &. {,4J' 1':-.1. 70.4909686 T 148,6932816 NIA N!^ rn)m !\lIrfacc Joe X cOl~rd Y cnord TVOes ';<J/A ~/A ~iA ~/^ N/^ Y c.!I!rd (,.IIJII.9\I1.K ";~ -.~ ,-. 3.41111 Mf)rld, 3.22(, TVnrkh 11.514 Ml>rkh 1).466 TYl>rkh 12,'J6R .Unrkh 1II.'!'11 TVl>r1.h 1~.!'41 Ml>rkh 11.2!!(, Tvnrkh ,--' ',." '" l~ '~l ,'-"' .)1 ~, e ..~-. T:¡r~,~1 1- ,blll,....."ol Targ"1 2 I ¡"I'P""! ;-.~ (k'nln !ical N/A Circle 400' radill~ cir::l.: (¡.-BI ESE 666,0% 5.029,449 10,654 .-. ;"~ .~; :~J ;::~ -',~ :~ ;¡ ,.~t ,! ~(¡ t ',~ . --. ..~ _--0 --- - - - --- .- -- - --- ',' ,!, ~~ ~ :;"~ }i .~:} ~-'. . --'- ",:-: - ::.-:-:"':;,,~ ;~ ::,~'t:j~..:-~':~~ rt'(t'!~~l"::¡~"7;::;.,. ~~;;"-"..: ',"-0..;-; .' ~; -:t!\"f-"":¡,(,"'~~"':;" )...;!"tr'",~,;,:.:~_.~~,.-.r-~:,,~...-.,-,-~ NS-09 SOR IOJ,OI Page I . (5) Formation Tops(TVDss) and Estimated Pore Pressures KB SS.S Estimated Depths Directional data IIJdrocarbon Estimated Comments Top (TVDss) Uncertain" TVÐrkb MDrkb Inclination A 'dm uth Bearing fIN Pore Press. Formation TVD e.ftimated (Psi) (ppg EMW) Top Permafrost 1,149 +1- 25' 1205 1205 4.1 90 N >.542, .,,8'.65:: '.,~' .','" . . . I, Base Permafrost 1.499 +1- 25' 15S5 1556 2.4 90 N :"69Q,,,: ,,8,65 ...., .., ,. .,. SV6 . top confining zone 3,010 +1- 25' 3066 31116 41.6 104 N :]UIS( '..: . ,> :.: , Suñace casing point 3,170 +1- 25' 3226 3408 44.6 104 N ..,'0:., ';.()',OO ""': .'~... I: SV5 . ba.'iC confinin~ zone 3.2110 +1- 25' 3336 3562 44.6 104 N . .1500. : BiaS " ::., ,. ...'.. .. .. SV4 3.600 +1- 25' 3656 4012 44.6 104 N 'B,'6&: . ...'.' ,... .,. , SV2 - top upper h1fection zone 4.000 +1- 25' 4056 4574 44.6 104 N 1824 :,_:,~l~S.~.: ::., ::'.' '.: . , : . ..;: SVI . top ma or shale barrier 4.4CX) +1- 25' 4456 5135 44.6 104 N ,:':::'2004,,;. ..,. .;"1I,'6S: .. ::.':.'..:.,: ,.. . . ' TMBK - top lower In ectlon zone - Top U~nll 4,770 +1- 25' 41126 5655 44.6 104 N .u ,.:.'B,6S..: ,. :..'.'.. .. .,....". .. M87'" . top Schrader 81uff - ßa.o;e Ul!nu 6,360 +1- 25' 6416 71170 41.4 104 N .."'.".:2886....'.:..' ',.:.8;65 ": ' MtiOT. 8ase lower Inlectlon 7.one (top Colville) 6,995 +1- 25' 7051 8691 37.3 104 N . ...~8ÆS, .. , '" ..:,. . THRZ. Top HRZ 11,740 + 1 - 50' 11796 10755 28.0 104 N ,;.395G: B;6S. .; . í BIIRZ - Base HRZ 8.IIUO + 1 - 50' 81156 10823 28.0 104 N :398.3' 'Jj;~5':: ::"",,;...,.:.. ,.' . ,. ... ~. I, Top Kuparuk 11,1170 + 1- 50' 11926 111902 28.0 104 Y .",,:' ..~ ",.:' ,,).. :.. ..:. .. I Kuparuk C 11.970 +1-60' 9026 11015 28.0 104. Y ':;4333::' ;,:9'.23,' .. .:.., ... . Top Mlluveach 9.310 + I- 70' 9366 11400 28.0 104 N ..0.00: :u.. .': ' Intermediate C8slnlZ point 9,410 + 1- 70' 9466 IIS]4 28.0 104 N ...,...,.0 ...: a.oo, ..'.. .. Intermediate IORRln!! point 9,410 +1-70' 9466 11514 28.0 104 N 4396' ,.8;93,. .".."..':.'.: .... ., .,' I' Fault #50 throw = 200' 9,800 + 1 -.400' 9856 11955 ..28.0 104 N ::::::::::'1:3~7::::'.\:~:: . BiSSu ,. ."'. .' . :......,:,::' .,.,: Top KlnlZak 9,830 + 1- 75' 9886 11989 28.0 104 N '.','46.90 ':~, ::.:'9';1.2.. ::. '.:',,"..":: ..,: . I> Top SaR River 10,654 +1- 80', 10710 12923. 28.0 . 104 Y :u. :A98'if¡';;-':' .. 'Sk95'.. . ," "..,.":,,., '"... .'. . ',:",::,: ,.. :::.:'ë.:,: I' Genl target 1t1 10,654 +/-110' 10710 12923 28.0 104 N ,:,8;5![..: GeoluliicTaril:ët#1400'radius ' Intennediate C8!!ing point 10,694 +1-90' 10750 12968 28.0 104 N ,0... ' .O.O<F., .", .., .,' ...;., ....', '.. Top Shublik 10,740 +/-9{)' 10796 13020 28.0 104 Y .::5024.: 8,95 . ",.:.. .:. .. Top JvL~hak 10.1130 +1-9{)' 10886 ~ 13122 28.0 104 Y .. .'.5066.:.., 8;9s, ,. '.. . .,.. Top Kavik 11.150 +1-90' 11206 ~ 13484 28.0 104 N ~;S215~; ,:,,8,95:<. "",:.":."" ,.,"..'.: .... . Total Depth 11 ,200 +1-90' 11256 13541 28.0 104 N .".:"...' ,". ,'.. .. .. Too Lisburne 11,250 +1-90' 11306 13600 28.0 104 ? ;~;19:.. F.'-, ."'.""':..,':" ..,'. I Comments Note: Anomalous high gas readings reported in Seal A-Ot mud log at the following Interval. 3690.3775; 3925 - 4050; 4140.4425,4510.4700 MD - No significant Gas shows In NS10 through NSt3 through this Interval- max gas = 70 units Depth predictions based on Seal A-2A well and comparison to 3D seismic volume Pore pressures estimated using RFf I DST data in offset Seal Wells, NS27, and NS31 wells .. 1>_"~~~!Wi'$::. .- " "); . - ~ : ( , : I 1 1 ' 1 1 ~ : , r , NS-09 SOR 10.3.01 Page 2 1" 1(7) Permittil1~ Re(IUirements: , ~'¡,~,!","':'-;o;;~~~~1-~~"'!'f;~-<2r,,'K~r~~J\¡; ~ ~""~ ~C::;:b_;'f~.¡c""t!"'!) ~",,",,'~~~-'}~~4< ~;w..~- _~",..~T ;~ }~;~À~~~':~~~ ~~:'r~¡!"'IZH"," - ..: -d.-'" '-~, ,-- ,'- ,-. ; 1(8) Offset Well Pore Pressures W('IIName Seoll\.III Seoll\.lIl Sel1l 1\-111 I'\S27 I'\S27 "'S.H ;o.;S2') , - ,._,",,_.>c. --..~":--",,-..-.,- -... -- (9) Nearhy Well Stntus \'tell nome Seal.I\.III. .112,-\. .11.' nod ..114. :'</S2h :-;S13 NS27. :'liS.\! NSIII. NS2') --'~"'~.' --":.'-., .-,:,,~.,y,-,-.'--'-:"'~"""b->'.- ( 1 0) Contin~ency J(equirements I . Prim.'ry -- -'~--;"".---- -, -. -'c- -- (J I) Drillin~ Ha7.ards Coherency F,IU:I Inl . 'Seis W:o::Jle trace Nrhy 011-;""9 Probs Ga'!l SI"-ows Targel Coord fv'ax Oog:og ~/ax Ho:e anGle Comments: Nole 1 . Med Risk Nole 2 . Ml!d i1isk Note 3 High Risk ~o~e 4 Med Risk No!1! 5 Me::! Risk No~e 6 Med Risk No~e 7 Me::! Risk No~e B Med Risk No:e 9 Med Risk Nole 10 Med Risk Nole 11 Mod Ris!\. Note 12 Med nisk Note 13 High Risk Additillnal cllllllllcnls I 2 J 4 I Permil 10 drill 2 North~t:Jr eomplionrc manllal ! 3 ~-- :i1 i~~ , -...._nO.,""",_"","",. ,...~.....<~_.-P<- . . .- --1.. ~~ ~;o ï~ ~i~ ~ iÐ ~ ~ :. "'-_"',,-~-",_. '.'~',-,o;;;-...~~-.-.;',- hC.:- ~~--.,,- ..'.,:,.,,- ,- _.'--"'~:;"',.~..,...--'~"<---'-\'--'."'I', _.,'~', ' -'/ " ~;'ê _~jÞ"~_r,",-.x;,,,~~~vv...f~'f.~:"""~~"">:~.\f(II!I'-~... E~lill ¡lle" Hcnt" (ìrmlil'nt MCD~IJn'd Tn!c "f l'n'-"~IIn: TV!>!;... (I'ilrt !>¡Ilc Ml'O!illn'Rlent I !i!111-22I1,~ l om.4lJ1XI 1I.4~1I 1I1/lII/K3 nunc ('¡11,;;;11I.45 '151m 22511-23¡ !J 5[11.11.1-52111.1 11.4511 111/11 ilK 3 nCl/lc Iwr NS2i. Calc :111J.4~ ,,~ilfl ~2"'1I-5J2C¡ 11I1\~1I.111511 :1.471\ 1I11111/K3 UST (ìlKIIi - ¡;Cln~i~lcnIIU'l' II;I!" SIï5 11.1111.1 11.1(,(, 02.111/111 RI:" n,,(! IRF1"~ 4423.4470 KK55-'JCI!16 1I,4'j(, 112/111 /III 'WI' c.ì'K!d - RFI'~ 517:; II iOO 1I.4'j(, 11;,111/111 MDT MDT f1n:~~lIn: Il'c:"lIrcn'crl Sli5 1111)1.1 11.4(,(, 1~1!1II/1J1 Ml:D 'HIPI'~c" p"rc I're~'lIrc CornnwlJl!I -.-...'-'- ".~....>.""-_.-_c-""'~-""'~',",.t~;,",,,-',- --~-,>---:,-~-"".;-,,=>--;:;.;,-<,:-.,_.~..~.,;,,~,._, .~ , .., - '.-,., /"";. ."- .'0 -¡-._;-~.., "ó " ," +-- ~.',> ,~;'-'.þ.;,o- if<"~_'i';.':r.,;!l-"'~~""':~~< ~,~~;'~)Id~"', ¡¡"9õ>:u,";'*~J~:,;;,..>.c ',: i~i:;"-",,\ . . ,..' ..~~ .~ ::~. .'" ~,;: ~ . .~~.....ïM. .-~~. - .,~~ '.;91 ')'1 ä "':',j':'---o:';'~'~- -,(-'--';,:"._-'~'--,-,..'--- ~,....,).-ÚJ't,'4 ;;;"i~,~.~~~~"¡-,.~~~-,;rt~w~~;~~~~.~~.~.t-O1tt.~:J;:....~~!!!o!:"".i'1~ "!;,I ~ ~ :~~ idl ~~ ~ ~ ~); æ ~ Cllrrf'n/ statll,~ l'r"'/lIl'Ii"n NS2" srl,ç.""n¡fr,/ at ,mrfare .ç/w" (/"nnd,,",d. enf"d .11 "tin!: rnm"/""d raç"d nn injre/inn I'rf!Cnlltinnr _."'- .-,~ -. lI/S27. NS.I/llr" enmp/"/I'I/ and prlll/rlrin!: NS2'J nn Injutinn ""tenti;,1 pn:~~"n: 111::0.5 thc Sdmu:cr BluW due 10 inicclI,'n -:...>-O;~,_.-.~..,"...",,~,:-.-i.'.-_,--.',.- . ~_c-.:...C',"'.c--, J,."")",~-~..-,."~,_._>.=,,,,,:;:.-,,---.<"""'."" ':~.~-¡'.!_~,',"""""",.....:".~.:~!iI!L~~~.~)J~-' .",.- ~ If p"ur ¡'u!c ¡;nnliil:oM ah:JOllllo c-I:nc wllr!!. ,--,.--.. ..,-~-_..,,"'.'-':,!.""'-~/.-'_._"".-.-.. Surtace süif:Svs note 5 nole 7 no:a 10 SV5.Shrd r:ote9 nole 9 3degreesi1 CO 41 0 44]' 0.5 ii2 0 iã 0 28 0 28 -10654 0 28 laul: I P apcrex 11CO' south (Ioull 50) laui: t p ap¡:rox 600' soulh (fau:1 50) Inlersectlon of faull 50 uplhrown to 181;11 50: dl)wn~hrown 10 lauil 5-1 ( 1200' from faui! M) stuck wireline in Kup due 10 high mud ....1 .. Seal A2 ::m~ e:>isode riohl hole. one ep:sode sloug:'!=1g . Seal A2 4 episodes ollighf hele, Seal A2 . no prohlerrs S!!I!J A2A . 2 episodes cllight hele Seal A2, 1 episode lighll'.o!e Seat A2A .. losl h::J!e Seal A2 10SII,sh Gas shows in SV 4 to Sv1, also Ugnu a!'ld shrader bluff. coal associated. 260 ur.ils above HnZ in Seal A.2A Mud log shows NS3i 10::>0 un:l: 600 unils in Seal A.2A 5000 unil mud log show NS 13; 2600 urHs in Sp.1'I1 A-2A 1900 unil mud log show NS29 5000 unit mild Ig show NS29 )robably assoc wi faultl!l9 or frli.cturlng Porel,I;:,1 lilr ('Ucoullk'rill!! ,~h:JlJ()w 1'-;1< from ~!i( O-; .'iOO' ¡;\Jh~t':J L( ~! cir¡;ul:!lion i'l Shll~l:k and Ivi~hak Kin.p.:!k ir.5lahil!ly . 1051 cin:III:Jlilln. dirrl'rl'llIi:t1 ¡;Iickinr- dllc 10 hi!,-h mild wd¡!I:1 rr.'IlIir~I!1Cnl~ Fallltin !. - ~~C fallltin '., di~clI~~ion NS-OIJ SOR 10.3.01 Prod Sag R . Shub ,SnJ):Tsad I Tsad. Kvk Commenl Kvk note 8 not08 Rep~ocessed seismic vo!ume Reprocessed seismic volume Reprocessed seismic volume Seal 2, Seal 2.A note 12 :'1õ'654 0 2ã 'H: 'n- ,.' 400' rall'us Circles -::~; 0 28 0 29 0 2ã ,="> >'~ ~ '::. -><J »: .],,1 :,,': ~~.~ ,', ~(I ..'.' ." k J ~:'- " DfllI R"k Low ~1",kralc ('lImn,'nl' .,;: .-; . ~( }: ~~cd , F-~ J/I !h ;:r, ,:' -:",.-. _::':~"-/~:~'->.,~-;>:-'-----,;~ -;;"-;_\::.~~-:-:;,-~~~,:,;_..r,'7.J..":,)".;;:':."';:':'r;::~'.!!:",:.~!;"<¿"..,.~~":-. Ol>.,,-vc,! in 1'152" . n" nrher well Page 3 (12) Completion Strate~y -r;~;"'-'-~~:--' "'l.":~~~',"~.¡:~.; -!'t~~;~~~~ ~ c-'" "~~"::!,,,,,": ' -:!","":;:,¿,~,-'J' ;.~r.~;.'!",,~~" T'o-~"";~"".;?"'T'?;-;..' n . "v:;:n'":;:<~'",:,,~~,," ,.: - . :~,--¡:;~~'-t~O:;-~;"j1>".~:1"~~~"""~'~~r~;;;~~.' J>rlH'"ctinn Lincr: Lirll'r Cllnri¡:unJlinn: "rnrlllclioll Tllhill !: Tllhulllr COllllllrnl.~: "rndurlinn rock,'r: ,\rtiriri:ll Lin: Tllhinl: TlliIJli Il': Cidrt' ('a hie - fiber nrlir!! RIA Tal!. Lnrotinll: ('nll1rlrlinll Fillirl~: ~1:Irkt'r Jnilll.~ Olherl('oIl1I1K'nl!!: SSSV . '(13) Stimulation Strate~y TrealllK'nl Tyre: r.,I. ~111"illlllll1 rn"'~lIre: AFr. 'IIIrnl'l: COni IllI'n 1 4-1;2" œrn~nlcd with top of liI;cr ~ct -150' inlo 7" c~~in;!. ~hoe 150' ovrrl:! 1 wi!h 1'01. p:lcker :In:! han!!l'r d-I/2", 12.fll!. :~ Cr V^~1 ACE 1 - "X" Nipple :lh!wc packer :lnd I - "X" &. I."X:-';" nipi) ¡' int:lilpipc. 4-1/2" 't 7" 13 Cr production p:lcker required (i1.M al 4500' TVDrkh (51 r¡T MDrkl'l) -40' willI tuhin~ sl:lhhl.'¡J inlo top of liner I¡)P To þ¡~ ¡n~!;¡lIe¡ wilh l~omp":tion, No RA ':II: nC"'lh'¡ Per Dave Wil~lIn fflnn:!lion d:lm:l~e ~I!ldy 4-1/2" Ener lop c:ln !'Ie u~ed for corrcl,rion PIII'P"Cl'C (;1.\-1 ~ :!round 511)7' MDrkl'l 4-1/2" nipr-le:1\ +1- 2000', S:lfcty valve will 1'1.: ~Ii.:k line rctri,~vah!c --.- - '. ' '-"~' '-'J:, ":.~-::-,.:,:>I.;~)o.";..,..¡.."..~,,..¡,:...,>:,<-<..,,,;..;,~,~,:,p."<"'::~'~~"..t '~'o"", ;.o;"'~"-"-;fr-,"'."-~"~~""-:-'_'~" -', '" :"lone :lllIicipa'('d Column of ga~ 10 slIrface (0.12 p5i/fl). inilir.1 ~esl'rvoir elll1l~il ion (5175 p~i «t 11.100 ftTVSS5) ..,- .,-.,:,:.~.:-:;.,-:j,"'¿:~~.~¡f~~-:.:"pY~'.~" -,. " ;~;~: ,~;:i:-:_.' ~:t1E~t~~~~~:~{~' ' :: :'~-~.:; - ":J f{~{_,~l:::~~~~1~F~--;:'~:~1!F~¡;è~;;~~~E~~ j~:~~*,~-~~~. -' ,- . ..(14) Perforation Strat('~y Lu('alion~ r'rrrnralinn 'nlt'nlll: 7.on:lII~..I:lliun: "rrr (:lIn Si7rITyrt.: )l'livrry Methnd: '>rrr ~1elh KI: FlnwhaC'k: Cnmm,:nl~: Ivi5!I:1k 1M) ft, (a- 5 spf for co5tin ,! rurpnsl~-;. :I::llIal depend" 0:1 op¡'nholc IO¡!5 Cl'l11l'ntNl4 1/2"" liner 27/H" c-Lin¡' l'-Um' :'-lone PC" ~nra1ion 10 occur after rig mn\'(,'5 niT Inc::1 ion (15) Drilling Fluids, LCM I{estrictions . , .. -. . -" ,. ,-. '. ,. .'-' - ..-. .- .-, -"~"'-"~~~~~"~;~~",.rt.,-,-.<'~_.........._~,...~,t;;.~"....-.~.,,~...,:."~:t'-",->--,;,~",,,,-,"':"J",.~-""¡"...,.' :'1~ ;A JJ ',~ :~ -,,< }~ ~:.. ,.., ~~ \'"~ .'!l-= l;; r: SlIrrncr 1I1I'l'. Intcrmedillie IIr,ll'. III 01111 P2 '>roollrtiun Iinle I-:~Iinmlecl nilI': E~lilll:lh'd HilT: ),',ir,'d 'rnrrrlir. I.C~1 R ,'4;trirtinn~: Cnnlin¡:elll'j('<;: ..' ~;..>.. S,':lw;lIcr 5plll! mild KCf. 1 polYl11c'r inhibited Scawall'r I Calcillm carbonate (I'er Dave Wil~(Jn formation dama~c 5!lItly) 5175 p~i (ri'. II.IOO'TVD~~ NOTE: SAG MAY BE I\T I1IGfI~R PRESSURE EQUIV TO 5:'\00 PSI Ø!II.IOO l-ìTVDSS 2~4 (ll'grl.'l'5 F Cr.) 11.1 o(r TV )5<: In prmlllclion hole only use the ADW LCM decision tree with Drilling Team Leader apjlroval ~ .. _:,,: . )~-~'-;-~'~~~'-:åf':J!;¡~::.i:f..;;;:.~-;-:~'!o\'i~~),~ii:t.~',~ ,":,l...~!!;::: .:. ~!~,":=¡"...~':.fI:f: :~~~;;"':-";;'~~ ..,,->~" ~.: -rd '!- i'¡ -- J, ,;;~ ~ ~i ;,;' :'~ ~~ '-,. {~ .', t ""': ..; ,,"J ;. .~ ~-""., ..', .'~ "'-.\ :.:~ I. '.~i " ',': .~, I-'; '00: .." 1-~ . . ~ '.. ., !~~ ~.~ ... ...~ ., .C ,. ,. _.- - ,-. .' ~- ~ -'- -, ,', .'. NS-09 SOR 10,3.01 Page 4 ;~~~':::"ry.!:,~~jè~'5':"~~~~~~t<7. ':':~ :¡;; ,.;~;.. ~~-;;; ~-;;::-j'!"". "; :,;.~~}~.:.~~;~-"!:7::"~:'~>~~"-i>:",,~l;i"i.)~:~~1'..~"':;"'~.'k (16) Well Evuhmtion Pro~rnm Inl,rval loIW/>II, WI) (ilv( >ire¡;lII!nai ~esl<livlly 1 "WI> . 2,"<1 hillll ' I>cn~ily f":lIlron Son:.: ( ISONIC¡ (Jp,n Unl, f,,~~ -- (j~ ~,"mllvlly 1 HAI.S! '=':llIrnn (((CiNS! Dcn-II)' IIIR~1S) . , SOIllC (l>1i'OLE! (,~11 14 ~rm c.,lii~r) . , C\-1R RFI ~1DT C:l~l'd IIlIle lugging. l;SIT Mlldlo!:ging (in~ Ucl,'clion Cllllin!:!! S'II11 1Il"õ In,"rem,'nl' C:ent"hl'm enn~ Inl'rcnl('n" " ("lImml'nl.~ SlIñnre lIole ('rum (\-11>1"1(0) ITO (~1nrkh) Inlrrml.'dinle hole. I ('rowl (\-Wrkh) 11 0 (~lI>,kh¡ Inlernlfllinle hole. II ('nlln (MDrkh) I ["0 (Ml>rkh) 11514 11.51,1 Inlcrmed >hlle 12,'J~IX In;erracd ,hoe 12,'H,X :-;on.: :-'011': ..",..~'M-~ "...-.x.-;",-~<" SlIrf:",:c J.40X S:¡rf:,œ sh.c 7,1\7\1 t.."mc I'mle I'm!.: ~ Nonc NI!nC' Nonc Nom: Non.: I'nnc h~1. Tn 11,5:4 11.5 ~ 4 11.514 "lUl" 1111. ~I\I.c ~ ;::n '/2\1' ~:a¡w< I'rllduetlon 1I0te ('rum (MIJrkh) ITO (MDrkh) 12,')(,X 12.')61< 12.%11 12.')(,1i ~ IbM' III<Z "n:~;;lIrcS \\dy I'nne TI> 12.%11 ~ 12.')r.1< TOe' ~ 12.')(,X 4n' i 2:1" ~hnw~ 12,%1i ,1\1'/20' shoy,~ /101111': :-';onc Nunc 11514 tln'l 20' ~hllw~ 12,')('!! 'rndlll'linn holr: M \YO rrsislivily, em nlllll>WO eliminated dm'ln 1os.<ihlr "I'i.~ cirl'lIl:llinn in Shllhlik nnd h-i<hnk I>rndllclinn 11(llr . Rlln I = C'.r, Rc~i.~Ii"il). 'IIelllron, )rl1~ily :ll1d Snnir. Tn he nlll from TJ) 10 shor r"rl'JlI !!Imir 10 hr nrn Ihrnlll,!h rn~il1l,! IIJllo ha'(' I mz '>r,..llIrlion Iinle . Rlln 2 = RFT Jln""~lIrl"õ (Inly . if limr Jlermil!! coller I nllirl~ >rndlll'lion lIole . nole: Work lownrd~ elimil1nlin~ Ihe J.WO I MWn 'o !~ dllrln~ Ihe prlldllrlinn hole . \tllll1l'rcl di~pel1':llinn fur !!lIne)il1¡: . ". .- --- .':"- '--~ . ,"." '- -- .-.'- (17) Cementin~ Uequirement SlIrf~('I' inl('rvnl: 133111 Inll.rmrdiale I: I) !:tI1 Il1lrrnK'dialr II: '" l'rndlll'lilll1 Inlrrvnl: J)('!Iirelll>IITD: )e~irrd I'roprrlil"l: C("lInK'nl~: (IS) Re(IUiremcnts at Ri~ Release Frrr7r Jlrllh'rlion Flnirl: lJnclrr halal1re: l>rnJln~l'd rll~1 Iti¡: \Ynrk: t:~limnlrd 01,1: Ons:oin ! Fnrilily \tnrk: C','mmrl1lc: :-':,':1e No:l~ IJ5<i I Nunc Nlln.: Nunc None 1.1,541 IJ,~41 IJ.541 l.t~41 13.54\ SlInc :-;nnc 1'1> ~ ~ IJ,541 IJ.541 D.541 ,~-" l"'lmrlllm" V. lIigh V.lllgh Med Met! Met! V.lllr.h V.IIII!h --- V.lli~h V. High V. hil!h - Cnrrclaliol1, h~7ard eval. I.lIh. pred Corrclalilln, ha/art! eval, rnd prup I'nrm"li"n eV¡lllIalinn Furrnalian evilhnllun Fnrrn"lian ev,,1. 1 Sel~miL: eval V,hid'. Clrrel"lion, rud I'":p Corre!~lIon, ruck prIOr l'urn~lIy ev;IIII~linn, IIC 1)11<: Pur. Ev..l. Sei~mic anal.. nllne:-aln!!y lOur. Ev"I, Sei~mle "n.11.. curreliliion Krnl!ak SllIIlv - . I'crme~hlhly. lllIid, & pnro~i:v r\al l're~~I:rc. lllIid analY"i~ l're~~lIrc. nult! a'lalY"l~ Cernenl c:vahmlian Carrel, Lllh eval, IIC ev"I, PremJre 4 \\rct ¡lilt! 4 dry ~e!s 1.:111 eval. ruck r-rnn :1 ~els Gc,'Chell1 an.II)'SI~ V.lli~h V, lligh lIi!!h -'"- lIigh Mct! ~ '~'.T-O. ---' 'K .'~;-, - ,~c .ll' ,-"",..o"..~" -"'. :, "¡¡ -.- ~ -' ," - ,,;,.7,~~i,;i...,' ,..;!' ...{'¿t~k:::J\i.:..w>..¡;;.aì_o!\"',~..?~.~~~~~;:. ~ I'"rf'{ ,f~ 1;<3 1J ~ -,¡; ~1 ~ >'>10 ?& .'",:~ ~:: "!",I -~.: .r. ;¡Š ~..e .v. " ?:: -n Dil'h'II') 4.0GO' TVOrkh (4.41)5' M Drkh) in lI,h:lIJ! and ;1':r1!lhl~ 1'1:.' "",dl is !n ~:: pt'l fnr:1h:d ancr Ihe ri¡! mow<, The lìl~id Il'fl (Se:¡w:lIl'r nlld nh'<l'l) III 'he w~"I1") }r.: will ;'iV:' 11;lr~erh:ll:m~'e -- .~ ii ..-' ,c,' -;,:. \- {~; ~: i'oJ ¡ò ~1 r; 1~ ,.~ .~~-'(¥~:;~ !~ ., -" . :-; -; ~\ 1} . ,- :'~1- .""~ -,;"--<,,~,, ~~:;! ,.ç;>'J<'"","f:...~..r:.¡~{.~"...:'~~. ~"'i~_~,p.- "-"~~J,"¡'~~,,,,,To .,;~d,¡l:~.wN~ ,,~;.~Jr.,:¡¿.I.Þ;rf"'Øt1~¡~"":;it~ .,... -, ~~~ :--. ,~-¡ q '. :'.-- . ,-",,~>,-,-, : -;¿:/,~'S':"'~':;"f~",il;"~:¡~'~'~;<;:.-~.- ,.;~';. !!.,~...tJ::: ,";~"",>..,~- :),:r..,"",~, "'-~;ì.""-",,-".: ' .-: :--~{.,: ;>,~) ." -, - '.- o. .'-- I'.."le N..ne I J'Io..:iC I'l!!le ~ ~ N..nc N..ne N..nc Nun.: :-I line N,'n.: ~ ~ ~ 1'0';: J'Io..:IC ;";"11" r-;one I'n:¡¡~"rð on Iv NIII:e I'..n.: SurrilC': Surr,!c.: ~ J,10K Sur':!cc ;;);"'-, -1 100' IO,i\~5 ~o'~"y,~ O,tl55 ~ :"/nl1': 10 1 20' ~hnw¡¡ -. ,~_._-:,",,~.~;'._,,-:.c-:"";':""" .....,.,.,.-,-..-..:;~o.c". Celnl'l1( 10 ¡¡urJ"acc \-1il1imlll11 500' of ('Cinelli ahove Kuparllk. TOC In SV2 marker :11 457'1' MDrkh Cl"l1!l'111 10 IlIlcrnh'diale ¡¡hOt' I . ncl'cbl for (":t~l'd hn!t' ~onic iurOrl11alinl1 TD 10 lop 4-1/2" liner See Ilallih~lrlon rl'commcndalion .'0...' "" ., ~~. '. -..' , ---"._"'..' h '-~-- ,-- --'. ' , -., ..- .- f'IIIIIÙIj! from p:!::h"r ~rllinl'- o X'r:ïlifln,: 1'1111 ~h::~r v~I"e frml1 CìI.\1 :III" run ,hlll1my val V," -, -'.. . . NS-09 SOR 10.3.01 Page 5 " "1f!".3iI'.:\ ,l î ',¡ :'1 - " ,]. ~:' s':: :. :,,:~~'D;<:;;1¡'~~~""':~:;:.r:'"J:'!'~'~~~~~~:-; ~';O:~: . "'.iô"", ~-~-"",,-....~,.~ ~""~-"'C,"J~~'~ }~~':'":~'"-~~~-~ ' '~?"!~þ~'~~~""~~~',;oI'!i'"¥"" (19) Ecnnumics I nfnrmation E\prrll'rllnili:lIl-lllw n:lle: F.\prrlrd 6 mllnlh Avl!,: E\prrlrd Nt"'rrn'~: n&c ('o~1 F.slilll:lh': Dev. C".I per 11111.: Prlldllrlioll Tie.ln Tllr~I'I: I~ m""p,~ I ~ III~"!"! -:-his :-':S(jI well i;; iIlL!I~n:d in l:IIII!ICI.:!:1I1I willI Ihe ~1Ir1h'!ar r:( :~ l'ro;cLI ¡,nIl will he II<I~¡ i,.~ I:'C P',,¡h!diO>õ1l1r EOR n"erv.:,- >"'".f....." ,~""""-'~;"";"",,._,-, .~.....,.. -1 , 'i::_')t:)~~ ,->:;~1*~X"i:t:;ili\t~4~'3~~~~t;~:t'-¿;-'~ ' - ,'1 r - --. -, ':,. :.:_~':') ~---~':': ::.:rt,,-':>" ," .. ,., (21)) As'iet Cuntncts ;V"", I' ¡'",ili'ln ,0;,0; "1'1"'111 ¡"l'</«(~r ¡'r:. I:"nl: n#'v. (;(II¡"l:içt (;i"'pl'y,,'iri,' Rr,~. F"I: 01", nT/;:. ¡~'nl:. (Jf". nT/;:, I.'n;:. ST. nTl1: F"I:. nTl1: SlIpl, ¡'rIT"p{,y,(iri,'1 Hili Tllrllhllil :\1ikr Fr:lI1ri" ,",,'n L.'ml.,y I(kk :\1:1I~..n fury Wlkll\ lIarh:1(:I 11,,11 A 11"11 SIII.rrill FI"y.1 1\('1'11:111111'7 \1iri.c ShullI'. )a~c (¡..",htill ('" ld b/irl/Í/~ (21) Approvals --,. , , . .-.", - -, -',':;'.' '" (22) Rcvisions after final si~nntures \.'IIICII "'m' r.'vi,,'d OfJir, 5fJ4.4Y.2 5M.42.111 5M.522~ 564-~ 1(:1) 5M.5X14 5M.~7';1 ~M.~21~1 :;1..1':;')('11 5M.4;¡11(' 5/.1.5:1411 :ti:5r-:,~" I/Iml#' ,H~.!.1!1,~ I,t,t. ,0:;,14 ,\i',('-1.2'J2 (,1)/..2-111 :\71,.2(.117 24,1.6%,1 :M-1..ìlo2 (,1;(, !i'nl :\.16- ¡1:!Xi .-." ., ::(-, /tr~prrl( ',.{ t,i',O-K:\ III 52"),)11>711 -~"'O-II:II(! N/A N/,\ 2,10-XI144 2¡ O-XII70 240.x\J:;r 44 i -11\1)4 (hIe i l Co ( 0 ( - ,~t~~,<:;..;;:,~~.,~',::: -..:': ::'~, ¡'-',_r I 0111" 'iM-,'i200 'i/>;: .:;20i) 5M.~210 ~M.:'i20( 5601 -:\2\JO 5M-~2(XI ~M-'i2IX) 5M.~2m 'i('; .:;1!~) ~64.,'i2\Ji.J .' -.. -', ,',.", ..,', --:¡'--:.~.....::"..»..,,~. :,.""...c>;.~j'.:::~-'(~~X..~J;~:,'""",""'.wt'!f~~"Y,!"~~.~~;qr..'¡: '~..... :\'~~"", -.,~. , , SS/) Operational Approval , '.. ..~ 9~- .JÌ , ~::-.:.;i .>:';~f:~>.'~"'~':;';':~ :~.':';':;;"':c~4~,,::~':);' Wli" Tn'i,i,'d NS-09 SOR 10.3,01 ihll,' Wiry rr'vHlml n~I"',(,(ll" 'f-, ';"'~iY- -"-\,"",-.¡~,,~, ~,;;;,;~',~: --¡ :'£-..;..:.i;.~~::;:~.t,fo::~i.<':';:";::~'- .':J~';7~:::" .;¡.,-:.'.. .. ,'-' Page 6 \ . ì ( ( NS09 Permit to Drill NSO9 Well Plan Summary lIïpe of Well (producer or injector): I Producer I Northstar Slot: NS09 Surface Location: 1129' FSL, 642' FEL, Sec. 11, T13N, R13E, UM X ::;: 659833 Y ::;: 6030901 Target (top of SAG): 4819' FSL, 4884' FEL, Sec. 18, T13N, R14E, UM 250' Radius X ::;: 666098 Y ::;: 6029449 10709' TVDrkb Bottom Hole Location: 4747'FSL,4603'FEL,Sec.18,T13N,R14E,UM X ::;: 666381 Y ::;: 6029383 11255' TVDrkb 1 AFE Number: 1831308 I Estimated Start Date: 111/27/01 1 MD: 1 13540 I I TVDrkb: 1112551 I I I RKB/Surface Elevation: (a.m.s.l.)-.J 55.7' / 15.67' I I I lB!s.=.J Nabors 33E lQperating days to complete: 142.5 I Well Desi9!!...(conventional, slimhole, etc.U Modified Bi~ Bore ~ective: ¡Ivishak Producer with fiber optic surveillance control line Mud Program: Surface Hole Mud Properties: eawa er iPU U oe ectlon From Surface to -3407' MD / 3226' TVD (-150' TVD below top SV6). Interval Density Viscosity YP Tauo Gel API FL pH (PPQ) (seconds) 10 sec Initial 8.8-9.0 100 - 200 50 - 70 >8 25 - 40 15 - 20 8.5 - 9.5 from -1555' *9.0 - 9.5 100 - 200 30 - 45 >6 15 - 25 4-10 8.5 - 9.5 SV6 @ Interval TD *9.5 75 -100 20 - 35 >6 1 0 - 25 4-10 8.5 - 9.5 S t S dM d 16" HIS * Should gas hydrates be encountered, mud densities up to 10.2 ppg may prove necessary. I t d' t HIM d P rt' I h'b't d KCI 12 1/4" HIS r n erme la e oe u rope les: n I I e - oe eclon From Surface Casing Shoe to 11513' MD / 9466' TVD (-top Miluveach). Interval Densitv (PPQ) PV YP Tauo APII HTTP FL pH Initial 8.7-9.3 10 -16 20 - 30 4-7 6-10 8.5 - 9.5 Top HRZ 9.6 10 - 16 20 - 25 4-7 4-6/<12 8.5- 9.5 Top Kuparuk to Miluveach 9.8 10-18 20 - 28 4-7 4-6/<12 8.5-9.5 Drillin Liner Hole Mud Pro erties: Inhibited KCL 8-1/2" Hole Section From Intermediate Casing Shoe to 12967' MD / 10750' TVD (top of Sag) Interval Densit PV YP Tauo API FL Miluveach & Kin ak to to of Sa 11.3 10 - 25 20 - 25 4 - 7 4-6 / <10 H 8.5 - 9.5 P d HIM dP S t IC CO3 D "II I FI . d 6 1/8" HIS r ro uctlon oe u ropertles: eawa er a n - n UI - oe eclon From Intermediate Casing Shoe to 13540' MD / 11256' TVD Interval Density' .\ PV YP Tauo APIFL pH Initial/Final 9.3 8 -12 20 - 25 4-7 3-5 8.5 - 9.5 1 ( ( NSO9 Permit to Drill Di rectional: (P7) KOP: :t1800. MD Cantenary curve 3°/100' build Maximum Hole Angle: :t44.6° Close Approach Well: Surface- 10' well spacing with NS10- 9.86' displacement at 40' MD. Gyro will be used for initial surveys and kickoff Survey Program: Gyros as required from surface to +/-1300'. Standard MWD surveys from +/-1300' to TD. DRilliNG CLOSE APPROACH: No close approach issues exist while drilling NS09 except for surface proximity to NS10. NS10 has 19.22' of separation at 1049' MD. NS09 passes anticollision criteria with all wells identified as a "major risk." Gyros will be run from surface to -1300' MD or until reliable MWD surveys can be taken. L . p ogglng rogram: 16" Section: Drilling: GR/Directional Mud Logging - Gas analysis/detection, show kit with indexed sample bottles, lithology samples.(100' intervals) Open Hole: None Cased Hole: None 12-1/4" Section: Drilling: GR/Directional, Res, PWD Mud Logging - Gas analysis/detection, show kit with indexed sample bottles, lithology samples (40' intervals - 20' intervals at shows), Geochem samples from 10544' MDrkb (40' intervals - 20' intervals at shows), CFM (connection flow monitorinq) Open Hole: RFT pressures only Cased Hole: None 8-1/2" Section: Drilling: GR/Directional, Res, PWD Mud Logging - Gas analysis/detection, show kit with indexed sample bottles, lithology samples (40' intervals - 20' intervals at shows), Geochem samples (40' intervals - 20' intervals at shows), CFM (connection flow monitorinq) Open Hole: None Cased Hole: None 6-1/8" Section: Drilling: GR/Directional . Mud Logging - Gas analysis/detection, show kit with indexed sample bottles, lithology samples (40' intervals - 20' intervals at shows), Geochem samples (40' intervals - 20' intervals at shows), CFM (connection flow monitorinq) Open Hole: Quad Combo (GR/Res/Den/Neu/Sonic), RFT pressures only Cased Hole: USIT (after rig release) 2 ( (" NS09 Permit to Drill Formation Markers: Formation Tops MD TVDss Pore EMW Comments Press. (ppg) (psi) Top Permafrost 1205 1149 517 8.65 Base Permafrost 1556 1499 674 8.65 SV6 3185 3010 1353 8.65 Set surface casino 150' tvd below top of SV6 SV5 3562 3280 1478 8.65 SV4 4011 3600 1620 8.65 SV2 4573 4000 1791 8.65 SV1 5135 4400 1972 8.65 Top Ugnu (UG4A) 5655 4770 2131 8.65 TMBK Top Schrader 7870 6360 2842 8.65 Top Seabee (CM3) 8691 6995 3112 8.65 Colville Shales Too HRZ 10754 8740 3874 8.65 Base H RZ 10822 8800 3906 8.65 Top Kuparuk 10902 8870 4233 9.29 Hydrocarbon bearina main Iv aas . Top Kuparuk C 11015 8970 4333 9.31 Hydrocarbon bearina main Iv aas . Top Miluveach 11400 9310 4395 9.12 Set intermediate casing into the top of the Miluveach Too Kinaak 11989 9830 4690 9.26 Top Sag River 12922 10654 4979 8.95 Set drilling liner into the top of the Sag River to cover up the Kinaak. Hvdrocarbon bearina. Top Shublik 13019 10740 5023 8.95 Hydrocarbon bearing. Possible loss circulation zone. Top Ivishak 13121 10830 5060 8.95 Hydrocarbon bearing. Possible loss circulation zone. Anticioated OWC 13428 11100 Too Kavik 13484 11150 5212 8.95 Proposed TD 13541 11200 5230 8.95 Too Lisburne 13600 11250 5249 8.95 Possible loss circulation zone c 8 IT b8 P asln~ U Inl 9 rogram: Hole Size Casing! WtlFt Grade Conn Casing Casing Top Hole 8tm Tbg O.D. Length MDITVDrkb MDITVDrkb 20" 20" 169# X-56 WELD 161' Surface 201 '/201' 16" 13 3/8" 68# L-80 BTC 3367' Su rface 3407'/3226' 12%" 95/8" 47# L-80 BTC-Mod 11473' Surface 11513'/9466' 8 Y2" 7" 26# L-80 BTC-Mod 1604' 11363'/9333' 12967'/10750' 6-1/8" 4-1/2" 12.6# 13Cr Vam Ace 723' 12817'/10616' 13540'/11256' Tubina 4-1 /2" 12.6# 13Cr Vam Ace 12775' Surface 12815'/10614' Permafrost: The 13-3/8" surface casing will be run approximately 1500' TVD below the permafrost to -3407' MD / 3226' TVD. The casing will be cemented to surface with a Premium 'G' with 2% calcium chloride tail slurry and a Permafrost 'L' lead slurry. The tail slurry allows sufficient compressive strength to prevent the shoe from breaking down as well as an accelerator to decrease thickening time. The lead slurry is light slurry that contains a freezing point depressant which enables the cement to set up rather than freeze. 3 ( ~. (' NSO9 Permit to Drill Cement Calculations: The followin cement calculations are based upon a single stage job. Casin 13-3/8" Surface Basis: Stage 1: Lead: Based on 2658' of Open Hole + 2500/0 excess from the permafrost to suriace + 50% excess for the remainder of the hole volume down to 750' above the shoe. Lead TOC: Suriace Tail: Based on 750' of 16" open hole x 13 3/8" casing with 500/0 excess + 80' shoe joint. Tail TOC: -2658' MD Total Cement / S acer Preflush S acer Lead 20 bbl sea water 50 bbl AI ha S acer wei hted to 1.0 over mud wei ht 521 bbl 1704 sk I 2921 ft of 10.7 ppg Permafrost 'L' Cement. 4.15 cf/sk, BHST 500 I BHCT 500, TT = 6.0 hrs 115 bbl 1554 sk I 643 ft of 15.8 ppg Premium 'G' wI 2% CaCI2. 1.16 cf/sk, BHST 500 I BHCT 500, TT = 4.0 hrs Tail cement calculations are based upon a single stage cement job. -5/8" Intermediate tage 1: Lead: Based on 5900' of 12 1/4" open hole x 9 5/8" csg with 30% excess Lead TOC: At -4411' MD 3941' TVD ail: Based on 1613' of 12 %" open hole x 9 5/8" csg with 30% excess + 80' shoe joint. ail TOC: At -9911' MD 8128' TVD tage 1: Total Cement / Spacer Preflush S acer Lead Tail The followin Casin Basis: cement calculations are based upon a single stage cement job. "Drillin Liner tage 1: Slurry: Based on 1454' of 8 1/2" open hole x 7" csg with 50% excess + 150' 95/8" csg x 7" csg liner lap + 00' 9-5/8" csg x 5" drillpipe above TaL + 80' shoe joint. lur TOC: At -11180' MD 9172' TVD ta e 1: Total Cement / S acer Spacer 0 bbl Alpha Spacer weighted to 1.0 p over mud MW Slurry 5.5 bbl 1245 sk I 368 ft of 15.8 ppg Premium 'G'. 1.50 cf/sk, BHST 2500 I BHCT 1500, IT = 4.0 hrs cement calculations are based upon a single stage cement job. -1/2" Prod Liner tage 1 : Slurry: Based on 573' of 6 1/8" open hole x 4 1/2" csg with 500/0 excess + 150' 7" csg x 4 1/2" csg liner la 200' 7" csg x 4" drillpipe above TaL + 80' shoe joint. lur TOC: At -12663' MD 10481' TVD ta e 1: Total Cement / S acer Spacer 0 bbl Alpha Spacer weighted to 1.0 ppg over mud MW Slurry 18.6 bbl I 69.6 sk I 104.4 ft of 15.8 ppg Premium 'G'. 1.50 cf/sk, BHST 2500 I BHCT 1500, TT = 4.0 hrs 4 I . , ( ( NSO9 Permit to Drill Well Control: ~ A Diverter waiver has been requested on NS09. To date, BP has drilled six development wells through the Northstar upper stratagraphic intervals and has not experienced any difficulty with shallow gas. All six surface holes have been drilled and cemented to a common depth of approximately 3,170' tvdss depth. Each surface shoe has been set in the competent shale horizon approximately 150' TVD below the top of the SV6 formation marker. Well mud logs and seismic data do not indicate the presence of a shallow gas hazard. ~ Equipment to be Installed and capable of handling maximum potential surface pressures ~ 5000 psi working pressure pipe rams (2) ~ Blind/shear rams ~ Annular preventer ~ Based upon the calculations below, BOP equipment will be tested to 5000 psi. Surface Section: . Maximum anticipated BHP: 1379 psi @ 3010' TVDss - SV6 . Maximum surface pressure: 1078 psi @ surface (Based on BHP and a full column of gas from TD @ 0.10 psi/H) Intermediate Section: . Maximum anticipated BHP: 4333 psi @ 8970' TVDss - Kuparuk IC' . Maximum surface pressure: 3436 psi @ surface (Based on BHP and a full column of gas from TD @ 0.10 psi/ft) Drilling Liner Section: . Maximum anticipated BHP: 4984 psi @ 10654' TVDss - Sag River . Maximum surface pressure: 3919 psi @ surface (Based on BHP and a full column of gas from TD @ 0.10 psi/H) Production Section: . Maximum anticipated BHP: 5376 psi @ 11200' TVDss - Total Depth . Maximum surface pressure: 4256 psi @ surface (Based on BHP and a full column of gas from TD @ 0.10 psi/H) . Planned BOP test pressure: 5000 psi (annular to 3500 psi) . Planned completion fluid: 8.5 ppg Seawater /6.8 ppg Diesel Dri II i ng Hazards/Conti ngencies: HYDROGEN SULFIDE - H2S: ./ Northstar is not designated as an H2S drill site, however Standard Operating Procedures for H2S precautions should be followed at all times. ./ No H2S was detected at Northstar while drilling or testing the Seal Island A-01, A-02, or A-03 exploration/appraisal wells. ./ No H2S was detected while drilling the NS10 waste disposal well, NS27, NS29, NS31 or NS13. Reference information below on file with AOGCC: ~ Northstar/Nabors 33E H2S contingency plan. ~ Well test hydrocarbon analyses for Seal Island A-O1, A-O2, and A-O3. DISPOSAL: Annular Injection: There will be no annular injection in this well. Cuttings Handling: Cuttings generated from drilling operations will be processed in the Grind and Inject Facility on Nabors 33E and will be disposed of in the NS10 Class I Waste Disposal Well. Fluid Handling: All Class I and Class II fluids will be processed by the Grind and Inject Facility on Nabors 33E and will be disposed of in the Northstar NS1 0 Class I Waste Disposal Well. 5 J ( (" NSO9 Permit to Drill SUMMARY DRilliNG OPERATIONS Pre-Ria Work: 1. Set 20" conductor and weld an ABB Vetco landing ring for the ABB Vetco Multibowl Wellhead on the conductor. (Already performed.) 2. Install 7' x 7' cellar and polyshield same. (Already performed.) Ria Operations: 1. MIRU Nabors 33E. 2. Nipple up and function test 21-1/4" diverter system, if required. NOTE: A diverter dispensation has been requested. Confirm dispensation decision with the Drilling Engineer. 3. MU 16" drilling assembly with MWD/GR and directionally drill surface hole to +/-150' TVD below the top of the SV6 marker at approximately 3185' MD. POOH. 4. Run 13-3/8", 68# surface casing. Cement the casing to surface in 1 stage. A TAM port collar will be run at +/- 1600' MD. In the event the cement does not circulate to surface, this port collar will be utilized to ensure a successful cement job is performed. 5. NO diverter / riser system and NU casing / multi-bowl wellhead. NU BOPE and test to 250/5000 psi. 6. MU 12-1/4" directional assembly. RIH to float collar. Test the 13-3/8" casing to 3500 psi with 9.3-ppg mud for 30 min. This test pressure may change based on actual mud weight in the hole. 7. Drill out remaining cement. Drill 20' of new formation below 13-3/8" shoe and perform FIT to 12.5 ppg. (FIT/LOT procedure on file with AOGCC). 8. Drill 12-1/4" intermediate hole to casing point (approximately 11,514'MD) at the top of the Miluveach. Minimum mud weight of 9.6 ppg at the top of HRl and 9.8 ppg at the top of Kuparuk. POOH. 9. RU Schlumberger. Run open hole RFT's for pressures only. POOH and RD Schlumberger. 10. Make a clean out run, if required, and condition the hole for casing. POOH. 11. Run 9-5/8", 47# intermediate casing. Cement the casing to the top of the SV2 sand in a single stage. Set the 9 5/8" pack off. Perform a down-squeeze on the 9-5/8" x 13-3/8" annulus with 1 annular volume of mud upon installing and testing the packoff. Down-squeeze diesel to 2000' MD for freeze protection after WOC. 12. MU 8-1/2" directional assembly and RIH to float collar. Pressure-test the 9-5/8" casing to 4300 psi with 9.8 ppg mud for 30 min. This test pressure may change based on the actual mud weight in the hole. 13. Drill out remaining cement. Drill 20' of new formation below 9-5/8" shoe and perform a Leak Off Test. (FIT/LOT procedure on file with AOGCC). 14. Weight up to 11.3 ppg prior to drilling ahead. Drill the drilling liner hole to the top of the Sag at approximately 12922' MD. POOH. 15. Run and cement a 7" 26# drilling liner. Set the liner hanger and liner top packer. Circulate off any excess cement. POOH with liner setting string. . 16. RIH wI 6-1/8" directional assembly and clean out to the landing collar. Pressure-test the liner to a minimum of 500 psi over the leak off pressure. This would be 3700 psi with 11.3-ppg mud assuming a LOT of 14.5 ppg. This test pressure may change based on the actual mud weight in the hole and the actual LOT. 17. Drill out remaining cement. Drill 20' of new formation below 9-5/8" shoe with 11.3-ppg mud and perform a Formation Integrity test. (FIT/LOT procedure on file with AOGCC). Since the mud weight will be lowered to 9.3 ppg after the FIT, monitor the wellbore for 10 minutes. If no losses occur, displace with the 9.3 ppg drill-in fluid. 18. Drill 6-1/8" production interval to the proposed TO at 13540' MD. POOH. 19. RU Schlumberger E-line unit. Run open logs (GR/RES/NEU/DEN/Sonic/RFT) in two logging runs. POOH and RD Schlumberger. 6 NS09 Permit to Drill (' f .. 20. Make a clean out run, if required, and condition the hole for a liner. POOH. 21. Run and cement the 4-1/2" 12.6# 13Cr liner. Set the liner hanger and liner top packer. Circulate oft any excess cement. POOH with liner setting tool. 22. Close the blind rams and pressure-test the liner lap to 3400 psi with 9.3 ppg fluid in the well for 30 minutes. 23. Cleanout the 4 %" liner to the float collar. Wash down and circulate prior to displacing to seawater. 24. Circulate to clean seawater (less than 40 NTU's) using spacers as per Bariod recommendation 25. POOH with the clean out assembly and prepare to run the 4 %" completion. 26. Run the 4 %", 13Cr Vam Ace completion assembly with CIDRA fiber optics. The fiber optic cable will be run from packer setting depth to suriace. 27. RIH to packer setting depth. Dual SSSV control lines will be run from the SVLN at +1- 2000' TVD (2002' MD) to suriace. 28. Run space out pups and terminate the 2 - 0.25" control lines and 0.25" fiber optic line. All lines will be secured using collar cable clamps. Pressure test the control lines and tubing hanger seals. Function test the fiber optic line. 29. Set the TWC. ND BOP's. NU Tree. Test the tubing head adapter and tree to 5000 psi. 30. Circulate in corrosion inhibitor. 31. Set packer. Increase the tubing pressure to 4200 psi (maximum anticipated suriace pressure) with 8.65-ppg completion fluid and hold for 30 minutes. Monitor tubing pressure for leaks. Record on chart. 32. Contact AOGCC andlor MMS inspector to witness test. Bleed tubing to 3000 psi and maintain during MIT. Pressure test annulus to 4200 psi (maximum anticipated suriace pressure) with 8.65 ppg completion fluid for AOGCC/MMS required mechanical integrity test (MIT). Monitor tubing pressure for leaks. Maintain pressure for 30 minutes and record as annulus test on chart. Email or fax chart and AOGCC/MMS MIT form to Drilling Engineer. 33. Bleed down the annulus to 3500 psi. Bleed down the tubing to 0 psi. This will shear the RP valve. 34. Pump diesel down the 4 Y2" x 9 5/8" annulus equivalent to the annulus capacity plus tubing capacity to a depth of 4000' TVD (4494' MD). 35. RU the U-tubing manifold and allow the Freeze Protection fluid to u-tube through the GLM. 36. Bleed off annulus to 0 psi. Ensure both the tubing and annulus pressures are 0 psi. 37. Install (dry rod in) BPV. Ensure all valves are closed. RD and move oft well. Post-Ria Work: 1. MIRU slickline. Pull the ball and rod I RHC profile from 'XN' nipple below the new production packer. 2. Pull the shear valve in the GLM and replace with a dummy valve. 3. MIRU Schlumberger Wireline. Run USIT. RD Schlumberger Wireline. 4. Periorate interval based on PE recommendation. Estimated Spud Date: November 27, 2001 Barbara M. Holt Operations Drilling Engineer 564-5791 7 <' (' ( NSO9 Permit to Drill SURFACE HOLE SECTION: . Mudloggers will be rigged up throughout the entire section. No significant drilling problems have been identified in the surface hole interval based on offset data. Good hole cleaning and management of required mud properties are key to a successful interval. Minor tight hole conditions have been noted in the shale intervals immediately below the permafrost during short trips. Differential sticking could be problematic in this hole section adjacent to the permeable SV Sands. Avoid leaving drill string stationary for extended periods, tighten fluid loss properties of mud, and string in Barofibre as required prior to penetrating sand intervals. Lost circulation has only been noted while drilling during hole opening runs and was most likely induced by poor hole cleaning. Losses have occurred while running and cementing surface casing. The NS27 experienced losses on the surface cement job at a rate of 12 BPM. The displacement rate was lowered to 10 BPM and full returns were re-established. Be sure to condition and thin mud appropriately prior to pulling out of the hole to run casing, and once on bottom with casing, bring circulation up slowly and reduce mud viscosities before pumping cement. Minor losses were seen on NS29 while running the 13 3/8" surface casing. Reduced running speed eliminated losses and the casing was cemented at 10 BPM displacement rate. Hole stabilization in the shallow unconsolidated intervals can be problematic if mud properties are relaxed. Hi viscosities as used elsewhere on the North Slope should be sufficient to control any potential running gravels. Gas hydrates may be present near the base of the permafrost. Wells drilled in the 2000-2001 drilling season have not experienced hydrates. Mudloggers will be used continuously on NS09 to help identify and trend any increase in background gas readings. If gas hydrates are encountered, mud weight may be increased to 10.2 ppg and treated with 2 ppb Driltreat (Lecithin). Additional measures include reducing flow rates to -450 to 500 gpm and keeping the mud temperature cool. . . . . . . INTERMEDIATE SECTION: . Mudloggers will be rigged up throughout the entire section. Minor gas shows have been reported in the four (4) Seal Island wells and have been identified as coal associated methane. No indications of shallow gas were seen while drilling during the 2000-2001 drilling season. Mudloggers will be used continuously on this well to help identify and trend any increase in background gas readings. Surface casing will be set prior to any intervals with previously noted gas shows to facilitate nippling up the BOP's. A minimum of 9.0 ppg is recommended. The shallow intervals beneath Northstar are, by interpretation, not faulted. However, if faults are encountered, the possibility of losses still exists. To be prepared for any potential lost circulation, a copy of the 'Lost Circulation Decision Tree' can be found in the last section of the Master Well Plan, which can be found on the rig. Pressure While Drilling (PWD) will be used to monitor the annular pressure. The pressure data will be used to minimize the equivalent circulating density (ECD), minimize lost circulation due to packing off due to loading up the wellbore with solids and provide for an additional well control tool to make sure the well does not become under-balanced. Differential sticking can 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 SV Sands. Gas in the Kuparuk is likely (5000 unit mud log show in NS13). Circulate as required. High mud weight should minimize the gas entry from the Kuparuk. The kick tolerance for the 12 1/4" open hole section would be 78 bbls assuming an influx from the Kuparuk interval at -9466' TVD. This is the worst-case scenario based on a 9.73 ppg (0.5 ppg over the known pore pressure) pore pressure gradient, a fracture gradient (based on a FIT) of 12.5 ppg at the 13-3/8" shoe, and 9.8 ppg mud in the hole. . . . . . . 8 i (' ( NS09 Permit to Drill DRilliNG liNER SECTION: . Mudloggers will be rigged up throughout the entire section. The directional targets has been designed to intersect a fault at the top of the Kingak interval. To be prepared for any potential lost circulation, a copy of the 'Lost Circulation Decision Tree' can be found in the last section of the Master Well Plan, which can be found on the Rig. Pressure While Drilling (PWD) will be used to monitor the annular pressure. The pressure data will be used to minimize the equivalent circulating density (ECD), minimize lost circulation due to packing off due to loading up the wellbore with solids and provide for an additional well control tool to make sure the well does not become under-balanced. Full returns were lost while weighting up the mud system from 11.3 ppg to 11.6 ppg on NS27. PWD indicated an on bottom ECD of 11.8 ppg when the losses occurred. The new casing design isolates the weaker formations above by top setting in the Miluveach. Though initial mud weight will be 11.3 ppg, the new casing design allows flexibility to increase mud weight, as required, in the Jurassic shale interval. Gas in the SAG is possible. Circulate as required. According to Geology, the top of the SAG is poor, not porous/permeable rock. This, along with the higher mud weight should minimize the gas in the top of the SAG. The kick tolerance for the 8-1/2" open hole section is infinite (due to limited amount of open hole) assuming an influx from the Sag River interval. This is the worst-case scenario based on a 9.62 ppg (0.5 ppg over the anticipated pore pressure) pore pressure gradient, a fracture gradient of 12.5 ppg at the 9-5/8" shoe, and 11.3 ppg mud in the hole. . . . . . PRODUCTION SECTION: . Mudloggers will be rigged up throughout the entire section. Gas in the Sag River or Ivishak will be circulated out as required. The drilling liner shoe will be drilled out with the 11.3 ppg mud. The mud will then be displaced with a 9.3 ppg drill-in fluid. Differential sticking is not anticipated but the drill string should not be left stationary for any length of time. Losses are not expected but calcium carbonate (CaCO3) will be maintained in the system. Severe lost circulation was encountered on the NS29. A copy of the 'Lost Circulation Decision Tree' can be found in the last section of the Master Well Plan. The Ivishak is a conglomerate section. Directional control will be maintained with MWD surveys to minimize doglegs. The well is not planned to penetrate the Lisburne limestone. On offset wells, losses have been encountered in the Lisburne. The project Geologist will be in charge of picking the base of the Ivishak and only rathole sufficient to bury the open hole logs will be drilled. However, if the Lisburne is penetrated, the LCM Decision Tree will be in place on the rig. The kick tolerance for the 6 1/8" open hole section is infinite (due to limited amount of open hole) assuming an influx from the proposed TD. This scenario is based on a 9.69 ppg (0.5 ppg over the anticipated pore pressure) pore pressure gradient, a fracture gradient of 11.3 ppg (based on FIT) at the 7" shoe, and 9.3 ppg mud in the hole. . . . . . . 9 " . NSO9 Permit to Drill ( (" NSO9 Riq-site Summary of DrillinQ Hazards POST THIS NOTICE IN THE DOGHOUSE ~ Gas hydrates may be present near the base of the permafrost. Mudloggers will be used continuously on NSO9 to help identify and trend any increase in background gas readings. If gas hydrates are encountered, mud weight may be increased to 10.2 ppg and treated with 2 ppb Driltreat (Lecithin). Additional measures include reducing flow rates to -450 to 500 gpm and keeping the mud temperature cool. ~ Differential sticking could be problematic in both the surface and intermediate hole sections adjacent to the permeable SV Sands. Avoid leaving drill string stationary for extended periods, tighten fluid loss properties of mud, and string in Barofibre prior to penetrating sand intervals. ~ Minor gas shows have been reported in the four (4) Seal Island wells and have been identified as coal associated methane. No indication of shallow gas was seen in NS10, NS27, N829, NS31, or NS13. Mudloggers will be used continuously on NSO9 to help identify and trend any increase in background gas readings. Surface casing will be set prior to any intervals with previously noted gas shows to facilitate nippling up the BOP's. ~ Severe losses have been seen in the intermediate section with a higher mud weight (11.6 ppg). The well design has been changed to alleviate this problem. The new casing design sets the 9 5/8" casing in the Miluveach and drills out with an 8 ¥2" assembly to the Top Sag to allow an appropriate cushion for mud weight increases in the Jurassic shale interval. To be prepared for any potential lost circulation, the 'Lost Circulation Decision Tree' can be found in the last section of the Master Well Plan, which can be found on the Rig. ~ Packing off due to improper hole cleaning can lead to stuck pipe. The PWD data, pick- up/slack-off weights and other drilling parameters must be monitored at all times. If in doubt, stop and condition the hole prior to drilling ahead or tripping. ~ Bit balling on the NS29 was experienced in the Miluveach. The mud properties and PDC bit selection will be closely monitored to minimize potential balling. ~ The Kingak shale, in the offset Seal Island wells drilled by Shell, experienced severe hole instability. The casing shoe at the base of the Kuparuk, higher mud weight and lower angles will help with hole conditions. ~ Conglomerate drilling in the Ivishak can lead to lost circulation, packing off due to unconsolidated formation and directional problems due to deflection of the drill string off of large rocks. Key drilling parameters must be monitored at all times. Do not drill ahead if a potential problem is detected. Severe lost returns were experienced on the NS29 in the Shublik and Ivishak. The LCM decision tree will be maintained on the rig as well as in the Master Well Plan. ~ Northstar is not a designated H2S pad. ~ CONSULT THE NORTHST AR PAD DATA SHEET AND THE WELL PLAN FOR ADDITIONAL INFORMATION 10 ", . .. (' ( Oilfield Services, Alaska Schlumberger Drilling & Measurements Schlumberge~ 3940 Arctic Blvd, Site 300 Anchorage, AK 99503 Tel (907) 273-1766 Fax (907) 561-8357 Wednesday, October 24,2001 Barbara Holt Northstar NS09 (P7) Alaska Drilling & Wells Close Approach Analysis We have examined the potential intersections of subject well with all other potentially conflicting wells, according to the BPA Directional Survey handbook (BPA-D-004) dated 09/99. Nabors 33E Method of analvsis: 1. A list of wells to be analyzed is created in Compass by performing a global scan with an initial search radius of two thousand feet with an increment of one hundred feet for every one thousand feet of measured depth in the subject well. 2. Wells are analyzed using the Compass Anti-collision module (BP Company setup) with major risk safety factors applied. For problem wells that are plugged and abandoned or that can be shut in, risk-based safety factor may be used, with client notification. 3. All depths are relative to the planned well profile. Survey Proqram: Instrument Type GYD-GC-SS MWD - Standard (declination corrected) Start Depth 40.20' md 1,300' md End Depth 1,300' md 13,540.41' md Close Approach Analysis results: Under method (2), all wells may flow, however see notes below. Note1: In reference to NS10, the island's waist disposal well, the closest approach is at 1 ,049'md with an allowable deviation of 2.5' under the conventional rule. Since the well cannot be shut in during drilling operations on the island, great care will need to be used in drilling from surface to 1500'md on the planned well. All data documenting these procedures is available for inspection at the Anadrill Directional Planning Center. Close Approach Drillinq Aids to be provided: A drilling map, with offset wells on the plan view, and traveling cylinder will be provided. Checked by: Scott Delapp 10/24/01 " . ( (" TREE: ABB-VGI 5 1/8" 5ksi WELLHEAD: ABB-VGI13-5/8" Multibowl 5ksi 133/8" TAM Port Collar at +1-1600'M D 13 3/8", 68#/ft, L-80, BTC @ 3407' 4.5", 12.6#/ft, 13-Cr, Vam Ace TUBING ID: 3.958" CAPACITY: 0.01522 BBLIFT 9-5/8" 47# L-80 BTM-C @ 11513' 4.5" X NIPPLE, @ 12762" 3.813" ID 4.5" X NIPPLE, @ 12787' 3.813" ID 4.5" XN NIPPLE, @ 12800' 3.725" ID 4.5" WLEG, @ 12815' 3.958" ID 7", 26#/ft L-80, BTC-M @ 12967' PBTD @ 13460' TD @ 13540' DATE REV. BY BMH COMM ENTS 11 5 01 NSO9 - Proposed ORIG INAL KB. ELEV = 55.77' KB-BF. ELEV = 40.2' ca. ELEV = 15.57' SSV @ 2000' MD wi HXO SVLN nipple - 3.813" ID 6.8PPG DIESEL FREEZE PROTECTION AT +1- 4000' TVD (4494'MD) 4.5" GLM @ 4500' TVD (5130' MD) wi 3.833" ID - 7" LINER TOP @ 11363' 4.5" Fiber Optic Transducer 3.958" ID 4.5" LINER TOP @ 12817' Proposed Perforation Interval: 13,115'-13,307'MD 10,880' - 11,050' TVD 4.5", 12.6#,13CrVam Ace Northstar WELL:NSO9 API NO: BP Exploration (Alaska) r,' ( ( bp Memorandum To: Floyd Hernandez cc: Tim Burns From: Alfred Eustes Date: 8/1/2001 Re: Casing Basis of Design for Northstar Bigbore Producer well A casing basis of design review was completed for the Bigbore Producer. In summary, the absolute minimum safety factors for the pipe design of this well is: Absolute Minimum Safety Factors Pipe Name and Type Burst Collapse Axial Triaxial 13-3/8" Surface Casing 1.36 3.47 3.32 1.63 9-5/8" Production/Intermediate Casing 1.54 1.76 1.94 1.35 7" Production/Intermediate Liner 1.42 1.42 3.57 1.74 4-1/2" Production Liner 1.83 1.33 2.44 1.77 Based on the input as listed from you and your team, there doesn't appear to be any issues regarding this well. 1 , . (' ( . -.' '.- -.--- _. 1 Permit to Drill MMS Section 250.414 (f) (5) (iv) (9) Estimated Values (ppg) 8 9 10 11 12 13 14 15 16 0 i .- - '_n_----_.'-'- ... . ---.'-'- -.' -L.._...:--....._..l '. -_--d.. , 1000 ¡ ... '...-.. . - ." -"... ..--...--..---.-..__.._.n,".'_d_...__--..--- -"'.--'ì -+- Pore Pressure (ppg) I --II- Mud Weight (ppg) I ~-~~~c~~~_~.i~n~.(p~~)_... J. I 2000:. ! 3000 ... ...--d._.' . d"'.........-.......... ... ....n.. -......... -.... 11000! ,. - C i ~ 40001 I .... ! (þ .. i ~ I i - 5000: .c .... Co (þ . C 6000 ¡ C) t: ;: ! ã) 7000 ¡ 1m C) t: .- 80001 tn ns 0 9000 .~ .. 10000 i 12000 . , . 8000 6000 4000 ^ ^ ^ ~ IX: 0 Z 2000 ~ b -2000 0 en v v v -4000 -6000 -8000 ( ( -4000 2000 6000 -2000 0 4000 0 -4000 NSO9 - Northstar Surface Location 1129 FSL 642 FEL S11 T13N R13E UM Lat: N70 29 27.487 Lon: W148 41 35.814 North: 6030901.76 ftUS East: 659833.49 ftUS Grid Conv: 1.2317° Scale Fact:O.9999 8000 Miscellaneous Slot NS09 Plan#: NS09 (P7) Elev Ref: KB(55.77ft above MSL) Date Drawn: 09:54:25AM 24-Oct-2001 6000 SPIDER VIEW Scale (1 in = 2000 it) 4000 Default Color - Proposal - Survey 2000 True North Mag Dee ( E 26.59° ) 0 ~ -2000 NSO9 (P7) ... - -6000 .... Schlumberger Seal-A-O3 -8000 -4000 -2000 2000 6000 4000 0 «< WEST EAST »> ,~ . a ~ .. 'q- "t"- 311 CHOKE tJNE --- ( .... ... (' ClAMP COW W [c:roR 13 j/BJI 5/JOOJ HYDRIL A NNU Wl BOP 13-5/8" SOOO¡ SlWfER V iRWJ l£ R4 M S LOWER CIWflY NlJr IN USE ... lJ-5/8" 50fJD/ HYDRIL 8UND STEARS -------- 2~ KIU UN£ I I I I I I G::I:!~ ... t 3-5/8" S(JtJDf SHNTER VÆt48l£ RAM ...n:""'~','~~"::.n:.,.~'\.p,' - ~ MIõ /IIJM1 - . -". ø ß I .. 1& D'i4I" ~ Report Date: Client: Field: Structure I Slot: Well: Borehole: UWI/API#: Survey Name I Date: Tort I AHD I DDII ERD ratio: Grid Coordinate System: Location Lat/Long: Location Grid N/E YfX: Grid Convergence Angle: Grid Scale Factor: NSO9 Proposed Well Profile - Geodetic Report October 5, 2001 Alaska Drilling & Wells Northstar Northstar PF 1 NS09 NS09 NS09 50-029- NS09 (P7) 1 October 24, 2001 71.192° 1 6722.89 ftl 5.760 10.59ï NAD27 Alaska State Planes, Zone 4, US Foot N 70.49096864, W 148.6932815€ N 6030901.760 ftUS, E 659833.490 ftUS +1.23172211 ° 0.99992902 Survey I DLS Computation Method: Vertical Section Azimuth: d 1 0/24/0 1 ~~c;:~:;; ~:~: -" TVD Reference Elevation: Sea Bed I Ground Level Elevation: Magnetic Declination: Total Field Strength: Magnetic Dip: Declination Date: Magnetic Declination Model: North Reference: Total Corr Mag North .> True North: Local Coordinates Referenced To: '" Schlumberger Minimum Curvature 1 Lubinski 104.290° N 0.000 ft, E 0.000 ft KB 55.77 ft relative to MSL 15.670 ft relative to MSL 26.589° 57494.708 nT 80.916° December 12,2001 BGGM 2000 True North +26.589° Well Head MD ft - 0.00 800.00 900.00 1000.00 1100.00 1200.00 4.00 90.00 1199.68 13.53 0.00 13.96 1.00 6030902.06 1205.11 4.05 90.00 1204.77 13.87 0.00 14.32 1.00 6030902.07 1300.00 5.00 90.00 1299.37 21.13 0.00 21.80 1.00 6030902.23 1400.00 4.00 90.00 1399.06 28.73 0.00 29.65 1.00 6030902.40 1500.00 3.00 90.00 1498.87 34.65 0.00 35.75 1.00 6030902.53 1555.96 2.44 90.00 1554.77 37.22 0.00 38.41 1.00 6030902.59 1600.00 2.00 90.00 1598.77 38.87 0.00 40.12 1.00 6030902.62 1700.00 1.00 90.00 1698.74 41.41 0.00 42.73 1.00 6030902.68 1800.00 0.00 104.38 1798.73 42.26 0.00 43.61 1.00 6030902.70 1900.00 3.00 104.38 1898.69 44.87 -0.65 46.14 3.00 6030902.10 2000.00 6.00 104.38 1998.37 52.72 -2.60 53.74 3.00 6030900.32 2100.00 9.00 104.38 2097.50 65.77 -5.84 66.38 3.00 6030897.35 2200.00 12.00 104.38 2195.81 83.99 -10.37 84.03 3.00 6030893.20 2300.00 15.00 104.38 2293.04 107.33 -16.17 106.64 3.00 6030887.89 2400.00 18.00 104.38 2388.91 135.73 -23.22 134.15 3.00 6030881.43 Station ID KB Bid 1/100 Top Permafrost Drp 1/100 Base Permafrost KOP Build 3/100 NS09 (P7) report. xis ppr ¥ Page 1 of 3 659847.45 659847.81 659855.28 659863.13 659869.23 659871.89 659873.60 . 659876.21 659877.09 659879.63 659887.27 659899.98 659917.72 659940.45 659968.10 --., Geo ra hic Coordinates Latitude Longitude N 70.49096864 W 148.69328156 N 70.49096864 W 148.69328156 N 70.49096864 W 148.69327445 N 70.49096864 W 148.69325304 N 70.49096864 W 148.69321740 N 70.49096864 W 148.69316745 N 70.49096864 W 148.69316451 N 70.49096864 W 148.69310337 N 70.49096864 W 148.69303920 N 70.49096864 W 148.69298934 ~, N 70.49096864 W 148.69296760 N 70.49096864 W 148.69295362 N 70.49096864 W 148.69293228 N 70.49096864 W 148.69292509 N 70.49096686 W 148.69290441 N 70.49096153 W 148.69284229 N 70.49095268 W 148.69273897 N 70.49094031 W 148.69259470 N 70.49092446 W 148.69240988 N 70.49090520 W 148.69218501 10/25/2001-10:27 AM .. Grid Coordinates Station ID I MD TVD Northing Easting I Lamuae I LonOlluoe I '- ft ft ftUS ftUS 2500.00 21.00 104.38 2483.16 6030873.84 660000.60 N 70.49088255 W 148.69192074 2600.00 24.00 104.38 2575.54 6030865.13 660037.86 N 70.49085657 W 148.69161773 2700.00 27.00 104.38 2665.79 6030855.34 660079.77 N 70.49082736 W 148.69127696 2800.00 30.00 104.38 2753.66 6030844.47 660126.23 N 70.49079496 W 148.69089916 2900.00 33.00 104.38 2838.92 6030832.60 660177.09 N 70.49075952 W 148.69048556 3000.00 36.00 104.38 2921.32 407.01 -90.61 396.92 3.00 6030819.71 660232.24 N 70.49072107 W 148.69003714 3100.00 39.00 104.38 3000.64 467.88 -105.74 455.88 3.00 6030805.85 660291.50 N 70.49067973 W 148.68955520 SV6 3185.37 41.56 104.38 3065.77 523.07 -119.45 509.34 3.00 6030793.29 660345.24 N 70.49064227 W 148.68911823 3200.00 42.00 104.38 3076.68 532.81 -121.87 518.78 3.00 6030791.08 660354.73 N 70.49063566 W 148.68904107 End Bid 3286.53 44.60 104.38 3139.65 592.15 -136.61 576.26 3.00 6030777.58 660412.51 N 70.49059538 W 148.68857124 ~ 13-3/8" Csg Pt 3407.48 44.60 104.38 3225.77 677.07 -157.70 658.51 0.00 6030758.26 660495.19 N 70.49053774 W 148.68789894 SV5 3561.95 44.60 104.38 3335.77 785.52 -184.65 763.57 0.00 6030733.58 660600.80 N 70.49046409 W 148.68704021 SV4 4011.34 44.60 104.38 3655.77 1101.04 -263.03 1069.20 0.00 6030661.79 660908.02 N 70.49024987 W 148.68454211 SV2 4573.08 44.60 104.38 4055.77 1495.44 -361.01 1451.23 0.00 6030572.05 661292.04 N 70.48998202 W 148.68141962 SV1 5134.82 44.60 104.38 4455.77 1889.84 -458.99 1833.27 0.00 6030482.31 661676.07 N 70.48971412 W 148.67829714 TMBK 5654.43 44.60 104.38 4825.77 2254.65 -549.62 2186.65 0.00 6030399.31 662031.29 N 70.48946627 W 148.67540897 Drp 0.5/100 7222.84 44.60 104.38 5942.60 3355.84 -823.19 3253.31 0.00 6030148.75 663103.50 N 70.48871785 W 148.66669160 7300.00 44.21 104.38 5997.72 3409.83 -836.60 3305.61 0.50 6030136.47 663156.08 N 70.48868116 W 148.66626419 7400.00 43.71 104.38 6069.71 3479.24 -853.85 3372.85 0.50 6030120.67 663223.67 N 70.48863395 W 148.66571469 7500.00 43.21 104.38 6142.29 3548.03 -870.93 3439.48 0.50 6030105.02 663290.64 N 70.48858720 W 148.66517017 7600.00 42.71 104.38 6215.47 3616.18 -887.86 3505.49 0.50 6030089.52 663357.00 N 70.48854087 W 148.66463073 7700.00 42.21 104.38 6289.25 3683.68 -904.64 3570.88 0.50 6030074.15 663422.73 N 70.48849494 W 148.66409636 7800.00 41.71 104.38 6363.61 3750.54 -921.25 3635.65 0.50 6030058.94 663487.84 N 70.48844948 W 148.66356705 Top Schrader 7869.68 41.36 104.38 6415.77 3796.75 -932.72 3680.40 0.50 6030048.43 663532.82 N 70.48841809 W 148.66320135 7900.00 41.21 104.38 6438.55 3816.75 -937.69 3699.78 0.50 6030043.88 663552.30 N 70.48840448 W 148.66304298 8000.00 40.71 104.38 6514.07 3882.31 -953.98 0.50 6030028.96 663616.13 N 70.48835990 W 148.66252405 _. 3763.28 8100.00 40.21 104.38 6590.15 3947.20 -970.10 3826.13 0.50 6030014.20 663679.31 N 70.48831577 W 148.66201045 8200.00 39.71 104.38 6666.80 4011.42 -986.06 3888.35 0.50 6029999.58 663741.85 N 70.48827208 W 148.66150199 8300.00 39.21 104.38 6744.01 4074.98 -1001.84 3949.91 0.50 6029985.13 663803.73 N 70.48822888 W 148.66099892 8400.00 38.71 104.38 6821.77 4137.86 -1017.46 4010.81 - 0.50 6029970.82 663864.95 N 70.48818612 W 148.66050126 . 8500.00 38.21 104.38 6900.07 4200.05 -1032.92 4071.06 0.50 6029956.66 663925.51 N 70.48814380 W 148.66000891 8600.00 37.71 104.38 6978.91 4261.56 -1048.20 4130.64 0.50 6029942.66 663985.40 N 70.48810197 W 148.65952203 Top Colville 8690.55 37.71 104.38 7050.77 4316.67 -1061.89 4184.02 0.50 6029930.13 664039.06 N 70.48806449 W 148.65908582 8700.00 37.21 104.38 7058.29 4322.38 -1063.31 4189.56 0.50 6029928.83 664044.63 N 70.48806060 W 148.65904055 8800.00 36.71 104.38 7138.20 4382.51 -1078.24 4247.80 0.50 6029915.15 664103.17 N 70.48801972 W 148.65856463 8900.00 36.21 104.38 7218.62 4441.94 -1093.01 4305.36 0.50 6029901.62 664161.03 N 70.48797928 W 148.65809426 9000.00 35.71 104.38 7299.57 4500.66 -1107.59 4362.24 0.50 6029888.27 664218.21 N 70.48793936 W 148.65762946 9100.00 35.21 104.38 7381.02 4558.67 -1122.01 4418.44 0.50 6029875.06 664274.70 N 70.48789988 W 148.65717021 9200.00 34.71 104.38 7462.97 4615.97 -1136.24 4473.94 0.50 6029862.03 664330.49 N 70.48786091 W 148.65671669 NS09 (P7) report.xls Page 2 of 3 10/25/2001-10:27 AM Station ID 9300.00 9400.00 34.21 33.71 104.38 104.38 7545.42 7628.37 4672.55 -1150.30 4728.42 -1164.18 4528.75 4582.86 0.50 6029849.15 0.50 6029836.44 664385.59 N 70.48782241 W 148.65626881 664439.98 N 70.48778440 W 148.65582664 9500.00 33.21 104.38 7711.79 4783.55 -1177.87 4636.27 0.50 6029823.90 664493.67 N 70.48774691 W 148.65539020 9600.00 32.71 104.38 7795.70 4837.96 -1191.39 4688.97 0.50 6029811.52 664546.64 N 70.48770989 W 148.65495957 9700.00 32.21 104.38 7880.07 4891.63 -1204.72 4740.96 0.50 6029799.31 664598.90 N 70.48767338 W 148.65453473 9800.00 31.71 104.38 7964.92 4944.56 -1217.87 4792.23 0.50 6029787.27 664650.44 N 70.48763737 W 148.65411578 9900.00 31.21 104.38 8050.22 4996.75 -1230.84 4842.78 0.50 6029775.39 664701.25 N 70.48760185 W 148.65370272 10000.00 30.71 104.38 8135.97 5048.19 -1243.62 4892.62 0.50 6029763.68 664751.35 N 70.48756685 W 148.65329546 10100.00 30.21 104.38 8222.17 5098.89 -1256.21 4941.72 0.50 6029752.15 664800.71 N 70.48753236 W 148.65289425 ~ 10200.00 29.71 104.38 8308.80 5148.83 -1268.62 4990.09 0.50 6029740.78 664849.33 N 70.48749837 W 148.65249900 10300.00 29.21 104.38 8395.87 5198.01 -1280.84 5037.73 0.50 6029729.59 664897.22 N 70.48746490 W 148.65210972 10400.00 28.71 104.38 8483.37 5246.43 -1292.87 5084.64 0.50 6029718.57 664944.37 N 70.48743195 W 148.65172641 10500.00 28.21 104.38 8571.28 5294.08 -1304.70 5130.80 0.50 6029707.74 664990.77 N 70.48739955 W 148.65134922 End Drp 10542.03 28.00 104.38 8608.35 5313.88 -1309.62 5149.97 0.50 6029703.23 665010.04 N 70.48738607 W 148.65119258 Top HRZ 10754.29 28.00 104.38 8795.77 5413.53 -1334.38 5246.50 0.00 6029680.56 665107.08 N 70.48731824 W 148.65040382 Base HRZ 10822.24 28.00 104.38 8855.77 5445.44 -1342.30 5277.40 0.00 6029673.30 665138.14 N 70.48729655 W 148.65015133 Top Kuparuk 10901.52 28.00 104.38 8925.77 5482.66 -1351.55 5313.46 0.00 6029664.83 665174.39 N 70.48727121 W 148.64985668 Kuparuk C 11014.78 28.00 104.38 9025.77 5535.83 -1364.76 5364.96 0.00 6029652.73 665226.15 N 70.48723502 W 148.64943587 Top Miluveach 11399.85 28.00 104.38 9365.77 5716.61 -1409.67 5540.07 0.00 6029611.60 665402.18 N 70.48711198 W 148.64800504 9-5/8" Csg Pt 11513.11 28.00 104.38 9465.77 5769.78 -1422.88 5591.58 0.00 6029599.50 665453.95 N 70.48707579 W 148.64758415 Top Kingak 11988.79 28.00 104.38 9885.77 5993.10 -1478.36 5807.90 0.00 6029548.69 665671.40 N 70.48692377 W 148.64581662 12407.84 28.00 104.38 10255.77 6189.83 -1527.23 5998.46 0.00 6029503.93 665862.95 N 70.48678985 W 148.64425960 Top Sag River 12922.02 28.00 104.38 10709.76 6431.22 -1587.20 6232.28 0.00 6029449.00 666097.99 N 70.48662550 W 148.64234914 Target 12922.03 28.00 104.38 10709.77 6431.22 -1587.20 6232.29 0.00 6029449.00 666098.00 N 70.48662550 W 148.64234905 7" Csg Pt 12967.33 28.00 104.38 10749.77 6452.49 -1592.49 6252.89 0.00 6029444.16 666118.71 N 70.48661100 W 148.64218074 Top Shublik 13019.43 28.00 104.38 10795.77 6476.95 -1598.56 6276.58 0.00 6029438.60 666142.52 N 70.48659436 W 148.64198718 ~ Top Ivishak 13121.36 28.00 104.38 10885.77 6524.80 -1610.45 6322.94 0.00 6029427.71 666189.12 N 70.48656177 W 148.64160839 Top Kavik 13483.78 28.00 104.38 11205.77 6694.95 -1652.72 6487.75 0.00 6029388.99 666354.79 N 70.48644591 W 148.64026181 TD /4-112" Lnr Pt 13540.41 28.00 104.38 11255.77 6721.54 -1659.32 6513.50 0.00 6029382.95 666380.68 N 70.48642782 W 148.64005143 Legal Description: Surface: 1129 FSL 642 FEL S11 T13N R13E UM Target: 4819 FSL 4884 FEL S18 T13N R14E UM BHL: 4747 FSL 4603 FEL S18 T13N R14E UM Northina (Y) rftUSl 6030901.76 6029449.00 6029382.94 Eastina eX) rftUSl 659833.49 666098.00 666380.68 NS09 (P7) report.xls Page 3 of 3 10/25/2001-10:27 AM , . (" ( VERTICAL SECTION VIEW Client: Well: Field: BPXA NS09 (P7) Schlumbepger Northstar Structure: Northstar PF Section At: 104.29 deg Date: October 24, 2001 0 . . . . """""""""""""""""""""""""'" ........................................,......,..........,...,.......1..,.................................................................;.......,.............................................................¡....................................................,...............;............. .... ...., ..... ..... ..... ...... Bid 1/100 àoo MD 744 TVD ~ 0.00' go'f' az 0 departure Dip 1/10011300 MD 1244 TVD . ':-;:-'~ ,~:OO:... ~r ,~: 2~..~e~~~ur~.. , ! i ¡ - - ~ ~ ~ ~ J ~ ~ iT"pPelln~fr".¡ 1205MD Ig9TVD .... .;.. j. ..... ..,.. .. ... ..... ..... 1 .. KOP B,illd 3/1001800 MD 1743 TVD i (¡me f'wn"lm.t 'I:H:6 MI) 1499 ß'V ) ~ ¡ I 0,00" 1jO4.38' az 42 departure ¡ ¡ , , .............¡....... ..... .......~~~..~;~.~~~;..~.~...~~ ~.... ...... j k/ 44.60' 104.38' az 592 departure ¡ ~ 13-318" Cia Pt3407 MD 3170 ~D I ..... .... .. ..... ..... ...., ..I.,44.,~.0' ..~O4',~.~' ~,~, 67,~,de~~rtut ..... ...., ...... ...... ...., ..... ...1. ...'þ. .... ...., ...., ..... + ...... ,..,. ,.... ..... ..... .....!:~:..:~:~. ;::~.. ::~~ .~~~ ...1 ":':;vij"'.\Ofi"MÖ"'GÖÖ ~ÿ'ö ...., .j , , ..... ..... "1 ....' J .. ! - .I 2000 "i" I ! "'" ...., .... ..... "1 i, ¡ .; .... ..... ..... ..... ..... ...... ..., ..... ...., ..... ..... i.$V:¡ 4~ïr:\ MO 4<)(10 lVD i , i""""'" I "1' ..... ..... ..... ..... , I .+ I , ! ..\.. .- .... ()) .- ())....J '+-CI) O~ 0 ()) ~ > II .8 c: CO .- 4:: ~O -0 .c: . .... 0 0.- Q)....J OCl) ~ 4000 ~ ~ ~ - ~ ~ ~ ~ - ~ ~ i:,;VI!;1:\SMI),1400rv() ..... ..,¡' ..... ..... "'" "'" .1. "'" ..... ..... ..... ..... ...., iTME\K SB5~ MD 477ú ~\lD i ..... ..... .... ..... ¡ i Hold Angle 44.60r ! 6000 ........................... j I ........................................................1.... """""".'" "'" .... ... ..." ...j. ¡or Sc'h"'óer ï[.,O MD 6360 TV! I ..... ..... ',"'" ..... .."" ..... .[ ~<'P '::,)1,11;';, ~\""1 f><O ïO:,'I TVD ¡ ........................".. , ¡ Dip 0.51100 i /¡' 7223 MD 5887 TVD I ¡ 44.60' 104.38' az ! : 3356 departure ! .........,......,.¡.....,...............................................+................,....................... :1 I I I ! I i '1 CO U.¡...: .- Q) ~cr: > > Q) ()) :JW ~ I- :::: ::::: ::::: ...., ..... ..... :¡'j,,:::;;j"E:lv~j~~~9"~MQ W¡¡'~4'tVD::::: ,J."t!..;;1'V¡¡~ 1';'¡'>jr~H")';\~;'.II1'I];r ...... I,)., 'n' I.) "I. . 0 "0.." l' i . ¡ i ............................¡.;::;.....EndOIp.'O54<MO""8553"tv°"""" /¡. 28.00' 104.38' az 5314 dfparture / I 9.5J8"CIgPt11513MD 9410TVD i i I 28.00' 104.38' a~ 5770 departure :::' ::::: :::': :'::",¡¿:.i:,1r~Z:.::1()ä:ï::~:ii.) ci8:Oüi:iÏl<p:"p:RRZ:JO'I.r.>4to1g.:,~'!{Dl:iÞ ::F ':.:.:: .... ... ' ::::':'.%: ! ïi'lJr,ïi~Kë;"~1'i)i"Mb f.'ho'i'Ÿo"i"I"'f"KuP<""lk""t'!¡¡!~MD'S~1("r~o "'" ..... "'" :.::: ::.:.::', :::::!: ::::l~~2 ii.::::': '::~:::, :::::::::: ::::::::' ~:l I::::::::: ..... ..... .............. . ";'~ Ki'iiu'¡;j:'cl,"ï 14ÖÖ f"¡ëï ~:j1o fi\ib ..'" "'" "'" ..... ..... ......... ""'þ' \f ...., ...... ...., ""', ..... /"'" .. '~;~~;iMD 10654 TVD I; i,. :i8.00' 104.38' az ......................................................:ií:;?!'S;:¡:1i;:~...I.~~'~,~:~;ij:)...!~~.:\!)::~y',(~:[.::.................................... ,. 6431 d : ....:::::..,.,:::::,..,.:::::..,...::::,.....:::::.....:::::.....::'1' ":::::"""::::""":::::";;:">::""':::::""":::i:"<~:~a~~~e Pt Hold Angle 28.00° ¡ \ /. ..,./ -........--¡-- 12967MD 10694TVD i ¡ \.. ,~---- i 28,00' 104.38' az ..................,.. """"¡"I>~.~"":"""""""""¡""'6452departure ~~~:~=== ~i~~:::j: TO /4-112" ¡In. PI 13540MD 111200TVD 28.00' 104.38' az 6722 depa~ure ..... '1'<iPK'VŒ"'13;¡'ð4 MD fl'15Ü"1VlT' I ¡ I ¡ : : """"""""""""""""""""""""""'T"""""""""""""""""""'""""""""""""""[""""""""""""""""""""""""""""""""""1'""""""""""""""""""""""""""""""""""1"""""" ¡ I I """"""""""""""""""""""""""""""""""""'" 8000 """"""""""""""""""""""""""""""""""""""""""""1.....,...........................................,..... 10000 12000 0 2000 4000 6000 8000 Vertical Section Departure at 104.29 deg from (0.0, 0.0). (1 in - 2000 feet) ^ ^ ^ I I- 0:: 0 Z -1000 I I- ::> 0 (/) -2000 V V V -3000 0 1000 0 \i/ \/ A KOP Build 3/100 1800 MO: 1743 TVO 0.00" 104.38' az 0 N 44 E: ---"--- -~-_._-_. PLAN VIEW Client: BPXA Well: NS09 (P7) Field: Northstar Structure: Northstar PF Scale: 1 in = 1000 ft Date: 24-0ct-2001 1000 3000 4000 2000 -----_0..--'-.--.---" '0.0..._---'0..+_. Drp 0.5/100 : --.- -- --7223" MO--SM7 Wo-I --- --- 44.60' 104.38' az : "" "'" I ~\l 13-3I8f Csg Pt 3407 ~O 31701VD 44.60': 104.38' az 158 5 ¡ 659 E , -------- ,- .-- ----- - ------ _no - -- ------- - -- - - ---------- r - - - - --------- ---------------- _m______--..-- .-- ------ ~--_. --- -- ---. -- ---_._---- 0 - - - ~-~._--~-~-_......_---- ..- ----.----.--..---------- 1000 3000 4000 EAST »> 2000 «< WEST Schlumberger 5000 6000 -_0. -- -- -. - --.--. 0.---7 --- ----0. _0._- - -- - -- -. - ----.;.--- .----... _0. ---- -- 0.-------0. 0.0. h_' h---- -- - __h -! h'h__.'_'- ---- - .------ .----- --+- ------ -- ---------- ------- - __h'_- h - -.- Bid 11100: - 800 MO 144 TVO Drp 11100 : 0_00' 90.'00' az 1300 MO 1244 TVO ¡ 0 N 0 E ; 5.00' 90.00' az 0 N 22 E : End Bid : 3287 MD 3084 1VD ;/ 44.60' 104.38' az ~ 1375 576E ---~---_hh_---L.h---_---_h- True North Mag Dec ( E 26.59° ) ~'_h_.'-'------- .@ _.......---.------....-. _..------- 9-518" Csg PI Enid Drp 11513 MO 9410 TVD 10¡;"2 MO 8553 TVO 28.00" 10Ü8' az 28;00' 104.38' az 14235 5592 E Tsrget 13~0 5. 5150 E / : 12922 M.. O. 10654 TVD : I ; 28.00' 104.38' az ---j........ ........_..:..._!-"'?"" .- ~~ : 7:\J ~ r,.",Á ;o;~,~,;""," 12967 MO 10694 1VD. 13540 MO 11200 TVO 28.00' 104.38' az 28.00' 104.38' az 1592 5 6253 E 16595 6514 E ----..._----- --. 5000 6000 7000 --. 1000 0 -1000 .--. -2000 -3000 7000 ; Company: Field: . Reference Site: Reference Well: Reference Wellpath: BP Amoco Northstar Northstar PF NS09 Plan NS09 (' Schlumberger Anticollision Report NO GLOBAL SCAN: Using user defined selection & scan criteria Interpolation Method: MD Interval: 50.00 ft Depth Range: 39.87 to 13540.41 ft Maximum Radius: 10000.00 ft Date: 10/25/2001 (' Co-ordinate(NE) Reference: Vertical (fVD) Reference: ------.---- Page: 1 Well: NS09, True North N33E 55.8 Tool Name Gyrodata gyro single shots MWD - Standard CtrrCtrl'lo,,(;o ... DistanceAt~å .. .. . . ft.. .. > it . 19.22 16.68 38.58 17.44 174.13 18.72 164.75 35.80 200.64 7.10 219.32 30.78 420.74 31.45 413.60 30.21 414.72 28.36 305.56 79.81 452.46 26.72 . .. ÁÜo",åb~e .öeyilltion ..... ... ...tt............ ... 2.54 21.15 155.42 130.00 193.54 188.55 389.30 383.47 386.45 241.23 425.76 Reference: Error Model: Scan Method: Error Surface: Db: Sybase -- Principal Plan & PLANNED PROGRAM ISCWSA Ellipse Trav Cylinder North Ellipse + Casing Survey Program for Definitive Wellpath Date: 10/18/2000 Validated: No Planned From To Survey ft ft 40.20 1300.00 1300.00 13540.41 Version: Toolcode 8 Planned: Plan #7 V1 Planned: Plan #7 V1 Diameter .. ..In. . 10.750 7.000 4.500 NS10 NS13 NS26 NS27 NS29 NS31 SEAL-A-01 SEAL-A-02 SEAL-A-02 SEAL-A-03 SEAL-A-04 H()le Siz~ ~ .In 12.250 8.500 6.000 Name GYD-GC-SS MWD --- Casing Points 1 >MD .. . ft 3309.18 12883.90 13540.40 TVD ...ft . 3155.77 10675.77 11255.42 Summary ...:-::... . Site . . 103/4" 7" 4-1/2" . . ... . .OffsetWellpath ~-+- .. ..>... ... WëU ...... . WeUpat~ Northstar PF Northstar PF Northstar PF Northstar PF Northstar PF Northstar PF Seal Island Seal Island Seal Island Seal Island Seal Island NS10 V17 NS13V11 NS26 V22 NS27 V29 NS29 V22 NS31 V14 SEAL-A-01 V4 SEAL-A-02 VO SEAL-A-02A V4 SEAL-A-03 V4 SEAL-A-04 V4 Reference. ... .1\1D .ff . 1048.50 1099.75 1198.78 2374.37 399.99 1897.28 1941.61 1847.54 1847.55 3184.17 1601.19 - Offset . MD. .ff.. . 1050.00 1100.00 1200.00 2400.00 400.00 1900.00 1950.00 1850.00 1850.00 3350.00 1600.00 ---------. -------.---.----.--.------ .l .1 ... . Warüing Pass: Major Risk Pass: Major Risk Pass: Major Risk Pass: Major Risk Pass: Major Risk Pass: Major Risk Pass: Major Risk Pass: Major Risk Pass: Major Risk Pass: Major Risk Pass: Major Risk ( ---------------- ---.. ----..--- - -.-..------..-------------- --------..-- ----- ----------------------- ____n____-- ---------------- (" ____n_~____-----~---"----_......_--- Field: Site: Well: Wellpath: Northstar N orthstar PF NSO9 Plan NSO9 337 0 - 300 -200 0 -\00 --""200 -"300 337 180 - 300 -"- -100- - 0 -100 - 200 300 -- Travelling Cylinder Azimuth (TFO+AZI) [deg) vs Centre to Centre Separation [100ft/in) --..---------...--- --------.--...-----------------. -"--.--------------..---.....-----------------,,----..-----___--__n----___n_--____-------..---- -.. - ---..------------------- - ----..----.---.----------.------ -.- -----.. ------------ ---- _n_- ._--- , . Target: NS09 (S-l 0) Site: Northstar PF (' Drilling Target Conf.: 99% Centre Location: Ivishak Tgt Map Northing: 6029449.00 ft Map Easting : 666098.00 ft Latitude: 70°29' 11.852N Shape: Circle f ¡ell: NS09 Based on: Planned Program Vertical Depth: 10654.00 ft below Mean Sea Level Local +N/-S: -1586.18 ft Local +E/-W: 6232.54 ft Longitude: 148°38'32.457W Radius: 400 ft ~ ~ / ~ ~ / ~ 0 / / /~ ,/ , / ' '" / , / ~ / ~~. ,,-./'- ~----------- /~ ~ '--, '~, - ~/' --------- \,~,/// "'-..' ~'/~7¿' , "'-..----- ~/ -"--,,,- CJ CJ CO Ln CJ CJ CJ LO CJ CJ J LO CJ CJ N LO CJ CJ LO LO CJ CJ CO LO -800 -1000 -1200 -lltOO -1500 -1800 -2000 -2200 CJ CJ CJ I < ~ " File: Northstar Bigbore Producer Casing Design.sck WELL SUMMARY String urface Casing roduction Liner 10 roduction Liner 11 12 13 14 Conn Leak 15 F Conn Fracture 16 Altemate Drift WELL SCHEMATIC ODNI eighVGrade Connection MD Interval (ft) 13 318., 68.00 Ibmlft, L -80 BTC, L-80 0-3493 95/8.,47.00 Ibmlft, L-80 BTC, L-80 0-12480 7.,26.00 Ibmlft, L-80 BTC, L-80 12330-14045 41/2.,12.60 Ibmlft, L-80 BTC, L-80 3493 ft 12330 ft 12480 ft 13831 ft 14045 ft 14586 ft Northstar Producer Casing Design 13831-14586 ( Date: August 01, 2001 Page: 1 8.625 A 1.54 1.76 1.94 1.35 6.151 : 1.42 1.42; 3.57 1.74 : ! 3.833 i 1.83 1.33' 2.44' 1.77 AKB 133/811 Surface Casing TaL 9 5/811 Production Casing TaL T' Production Liner 4 1/211 Production Liner Design Cost ($) 150,303 Total = 150,303 348,712 Total = 348,712 27,783 Total = 27,783 6.349 Total = 6,349 Total = 533,147 StressCheck 1998.7 ( Build 6 ) File: Northstar Bigbore Producer Casing Design.sck GENERAL DATA Date: August 01, 2001 Page: 2 Description: Well Options, Deviated: Well Options, Offshore: Well TO (MD): Reference Point: Elevation: Origin N: Origin E: Azimuth: Northstar Producer Casing Design Yes No 14586 ft RKB Oft 0 ft I I Oft' 295.00 de9_J ---~-_.. -.-.-. ...... ..-.----.-..--..--....--------..--.---..-.....-.-.---. .---..--.-. -.--.- _...- -----.'-'..... -----.- .--...------.- ------- - -...... - -.. .-...-- -.- .---------.....- .-.--....-.-. .-- -... .--.-..-- .-.-.--------.... .-................. __00' -.-..-.....-.....-.--.-..-.-. ...-.... ..-..........-...-......---.--.-----.. ---I I I i I I OFFSHORE DATA Invalid General Data CASING SCHEME ---..--- -....-.-..--. -...-.-.-.------....-..----..-.----......-------.-- ----..---.--.--.-.--.--- ---¡ I I Ho I~ n ~ j ~___L_- -~~g~~_.__1~~~h ~::1 16.000 0 12.250 0 8.500 12330 6.000 13831 TOC Mud at j Shoe (ppgL- 9.50 9.80 11.30 9.30 ~D (in!....__._l N a m e_._.__-_J_-~~~-_. 13 3/8" Surface k:;asing 518" Production rasing Production ¡Liner 1/2" Production Liner 3493 12480 14045 14586 0 0 12330 13831 -..-.---.--..-...- --- -..-----.--.-.- --..- .---.. .-. ---- ------ -- --.-..----. ------ '_00 -.-.--..-..-... __me ------ - ---- -. PRODUCTION DATA ---...-.-.---.-.-.---.... ....-- -....-.-.. .-.......-....-...--------.-.--.--..........-.-..-.... .....-..........-....-.-..-.--.....------..---. ____00_.."-,.,-,-,-"-.,.""'.,.,-,-"-"--' -..-...--.-........-.....-.........---.-..-. .-.-..... "'--"----------.-----"'---"'--------'-"'--"'..-'.-......-...... ..... . .......---.--.-........ ".,."..".-,""""."__.._m.___-"'-'--"..".""..-... .....-.-.....-......... .... i i 9.60 ppg I 141 00 ft ! 14200 ft i .._..._Q_JQQO psi~Hj Packer Fluid Density: Packer Depth, MD: Perforation Depth, MD: Gas/Oil Gradient: --SlJRVEY EDITOR ....-..-..---.---..-.-...-.-.-..-------....-.-...-----.-__._._n._- ...-.... .....-.........--.--.-. ...-..-..---.--.-.. .....---....-...-----. "'-'--'----"---------'-'-'----1 I Data-Entry Mode D-INC-AZ D-INC-AZ D-INC-AZ MD-INC-AZ MD-INC-AZ MD-INC-AZ MD-INC-AZ MD-INC-AZ MD-INC-AZ 10 MD-INC-AZ 11 MD-INC-AZ 12 MD-INC-AZ ...._._--_._~ft~ .___l__....i~~~) __1____- (~~_l_.._._J};L- 0 0.00 0.00 500 0.00 280.00 1000. 5.00 280.00 1500 0.00 280.00 16001 1.00 280.00 1750' 4.00 289.00 31751 46.73 295.00 11743 47.63 295.00 12301 30.00 295.00 14011 30.00 295.00 14045 30.00 295.00 14586 30.00 295.00 ..- ]__J?e~~~!L[~ ~ea;;?~~~._._~_..._--~ S~~i:.~ [-~~~~~~-_..J 0 0 0 500 0.00 0.00 0 0 999 1.00 1.00 21 22 1499 1.00 1.00 42 44 1599 1.00 1.00 43 44 1749 2.01 2.01 49 51 3007 3.00 3.00 646 646 8830 0.01 0.01 6930 6930 9263 3.16 3.16 7278 7278 10744 0.00 0.00 8133 8133 10774 0.00 0.00 8150 8150 11242 0.00 0.00 8421 8421 -.....----..--......... -..-...-......-... - ....--.-...-.......-...-... ....- --.-.-...-----.-.....- ...-............--.-.-......-.. ..... -......-.- .......-..-.....--.."'---' Northstar Producer Casing Design StressCheck 1998.7 ( Build 6 ) : (' (' File: Northstar Bigbore Producer Casing Design.sck DEVIATION PROFILE Date: August 01, 2001 Page: 3 1 I I 10 11 12 13 14 15 16 17 18 SECTION VIEW 1500 3000 --. ~ - .s:::. - Cl. Q) 0 -æ 0 t Q) > Q) :::s ~ t- 4500 6000 7500 9000 10500 12000 0 MD (ft) INC AZ. (deg) (deg) 0.00 0.00 5.00 280.00 0.00 1.00 4.00 289.00 46.73 46.76 47.63 TVD (ft) DLS Max DLS (degl100ft) (degl100ft) 0.00 0.00 1.00 1.00 2.01 2.01 3.00 3.00 0.01 0.01 3.16 3.16 Vsection (ft) i I 01 22~ 1 I 441 I 51 ! 646' 8771 6930 72781 72931 7368 8043 8133 8150 8178 8228 8421 Departure (ft) 0 500 999 1499 1599 1749 3007 3225 8830 9263 9288 9418 10588 10744 10774 10821. 10908 11242 0 500 1000 1500 1600 1750 3175 3493 11743 12301 12330 12480 13831 14011 14045 14100 14200 14586 295.00 0 21 42 43 , 49 646 877 6930 7278 7293 7368. 8043 8133 8150. 8178, 8228 8421 30.00 0.00 0.00 ... 0 .+=- 0 O~ > + Section View I I I 1 I I 1 I I I I I I 1 I 1 1 I I 1 I I t 1 1 1 I 1 1 I I I , 1 I 1 1 I 1 1 I 1 1 , , I t t - - - - ~ - - - - _1- - - - - L - - - - .J - - - - _1- - - - - L - - - - ..J - - - - -I- - - - - J. - - - - -1- - - - - L. - - - - ~ - - - - -1- - - - - L - 1 1 1 1 1 1 I 1 1 1 , 1 I 1 1 1 1 1 1 1 , I 1 I 1 1 1 1 , I 1 1 1 I 1 1 1 I I I 1 tit I I 1 I 1 I I I I 1 1 I 1 I , 1 1 , 1 I , I 1 - - - 1 - - - - -1- - - - - ï - - - - ï - - - - -1- - - - - ï - - - - -, - - - - -1- - - - - ï - - - - -1- - - - - ,- - - - - 1 - - - - -1- - - - - ï - , 1 I 1 1 1 I 1 , 1 , 1 1 I 1 I 1 1 I 1 1 1 1 1 I I t 1 I I 1 , 1 1 1 , t I I , I I 1 1 1 1 , 1 I lit t , 1 - - - - of - - - -1- - - - - I- - - - - -+ - - - - -1- - - - - to - - - - -i - - - - -1- - - - - + - - - - ~ - - - - - .... - - - - of - - - - -1- - - - - I- - 1 1 1 1 1 I 1 1 1 I I 1 1 , I 1 I I 1 I 1 I I I 1 I 1 I I , I lit' 1 , , lIt 1 , I , 1 1 , 1 , 1 I I 1 1 - - - _1- - - - _1- - - - -1.. - - - - J - - - - _1- - - - - L - - - _.J - - - - -'- - - - - -'- - - - - _1- - - - - '- - - - _1- - - - -'- - - - -1..- I I 1 1 1 I I I , I 1 1 I I t I , 1 I , 1 I I 1 1 1 I I 1 1 , 1 I 1 I I 1 , , I , t 1 1 1 , , , , , I , , 1 1 1 1 I 1 , 1 1 1 1 I , I I - - - - , - - - - -,- - - - - r - - -, - - - - -,- - - - - r - - - - ï - - - - -,- - - - - T - - - - -1- - - - - r - - - - "T - - - - -,- - - - - r - 1 1 1 1 , 1 1 I 1 1 I 1 I I , 1 1 1 I I 1 1 1 I , , I I I 1 I I , 1 1 1 , I I I 1 I 1 1 I I t 1 1 I 1 I I , , I - - - - .1 - - - - -'- - - - - L - - - - .J - - - -,- - - - - L - - - - .J - - - - _1- - - - - .L - - - - _1- - - - - L - - - - .1 - - - - -,- - - - - L - I , I 1 , 1 1 , 1 1 I I 1 I 1 I I 1 1 I 1 1 I 1 1 I 1 I t I I t I 1 I I I I 1 1 t 1 1 I , , I I 1 I 1 I I t I I I I 1 1 I 1 lit I 1 - - - - ì - - - - -.- - - - - r - - - - , - - - - -,- - - - r - - - - ï - - - - -,- - - - - T - - - - -,- - - - - r - - - - ï - - - - -1- - - - - r - I I 1 1 1 1 I 1 I I , 1 1 I I I I I '+' lit I lit I 1 1 I 1 1 1 1 I 1 1 1 1 , I 1 1 I 1 , I 1 I I 1 I I 1 1 1500 4500 9000 1 0500 12000 13500 15000 16500 18000 19500 21 000 VSection (ft) 6000 3000 7500 .----l DOGLEG SEVERITY OVERRIDES DLS (degl100ft) 1--+....__._--_-I~P. MD (ft) I .-_n_-.- ....---- 8as~, MD eft) 0 I 14586 ------' 0.75 Northstar Producer Casing Design StressCheck 1998.7 ( Build 6 ) File: Northstar Bigbore Producer Casing Design.sck I PORE PRESSURE ! Date: August 01, 2001 Page: 4 I ---~------ Vertical Depth (ft) Pore PressurelEMW ~) ----- .------. {ægl Penneable Zones -------.. 0 0 3150 1415 8760 4237 9250 4382 I 9740, 4685 10700 4975 11350 5277 - -...-.....-------.---.------.....--.....-..--------..----.1..-..----_.-_._-_...__.---_._-----~--- --.-.. 8.65 8.65 9.31 9.12 9.26 8.95 8.95 ____-n_.-- ........--------------------------.------------------------------- rFRAC GRADIENT -_._-----------~-_.__._---_.._-- - ---------. ------.---- ..---- --- ----'-----1 -_. .~---~---~~~~ c~) --n-- --------- ---___.._L____~_--------- ---. -_..__.__JP._sJ_g )-- .- -- -- -------- .- ._.~~~~:~:L~- ~:__.__._-- .------- -_J~P9t- ----------- 0 0 9.00' 3150 2127 13.00: 4699, 3173 13.001 4700 2832. 11.601 6900 4158 11.601 9250; 7208 15.001 10700 8504 15.30 --_~___!E5O:- ---------------- -- --- -------------------_.._~~!.__. -----------......-------. -.-..--- ._---_.._-----_._---_!~:~..2j .-- -------.------_.._--------- PORE, FRAC & MW PROFILE 0 ----- +-" - ------ T -- -: ~-""--"-----""'----":"""-'-"""---'-'--"--~'--.-...-..----- ..--..-..--.:.---.-.... : : I I 1 I '.".'" I 1 1 1 1 I"'" I I 1500 + - - - - - t - - _1- - - - - - - - - ...I - - - - - - - - - L - - - - - - - - _1- - - - - .. - ""\ - ...J - - - - - - - - - J. - - - - I I I I \ 1 I 1 I I I '.. I I I I 1 I I \ I I I 1 I 1 I \, I 1 3000 -+- - - - - - ~ - - --:- - - - õ - - - - ~ - - - - - - - - .. ~ - - - -. - -. - - -:- - - - - - - - - ~- - - -. - - - - - + - - - - - - - - -:- - - - - - - - - - I I I I I I , I I I : I I 1 I I I 'I' I I 1 I I 1 1 I , 4500 -+- - - -. - - - - - 1- - - - - - - - - -f - - - - - - - - - 1-1 - - - - - -~--- - -I., --.. - - - - - - ~.- - -- -. - - - - - +1 - - - - - - - - -f- - - - - - _. - -- I l - -, I 6000 + - - - m - --i- ; - - - - - - - ) - - - - _I - - -j- - - - - - - - - j - - - - - - - - - ¡ - - - - - - - - - 1- - - - - - - - - - 1 I I I I I I 1 I 1 I I I I I 1 1 X ..-L I I 1 7500 -t - - - - - - - - -1- - - - - - - - j - - - - - - - - - ~ - - - - - - - - - !--~ _:"O"--="~==-::'~=~~..- - i - - - - - - - - - ~ - - - - - .. - - .. I I I I , ........,..-. I I + I I I 1 I ..~..._-._-.-.. I 9000 + - - - - - - -.. -;- Z- - - -- - ~ -: - - - - -.. - - -: - - -. -.- --- - -;'- -. - - - - - - --: - - - -. - - - - -: - - -_.. -':::._'_-:'--~~,- - - - - -- -..- I + I I I I , I \ 1 0500 + no - - - - - r-- .. no .. .. - ; .. no - - .. - + .. ¿ .. .. .. - .. - ¡- - -- - .. - - - ~ - - .. - - .. - -- i no .. - .. - .. - ~ -\ -- - - .. - + 0 1 1 I I I 1 X , I 1 1 I I 1 , , I I I I + Pore Pressure " F rac Gradient 0 Mud Weiaht ...c 1i Q) 0 ro u t Q) > Q) ::J ...... I- 12000 . 8.00 I 9.00 j 10.00 I 'î---¡ 11.00 12.00 13.00 Equivalent Mud Weight (ppg) -r-- 14.00 15.00 16.00 --- ------- ----- .-.--.---.---------.. r- .--......-.-...-.--.----.----.----....---...-.---..----------------.--.------.- - I SQUEEZING SAL T/SHALE I ....- ---- ---.--. ---------..----. --------.--- ---.----.--------..-- --------- Overburden Pressure at Top Overburden Pressure at Base (psig) (ppg) (psig) (ppg) -~ Zone Top TVD (ft) Base TVD (ft) Northstar Producer Casing Design StressCheck 1998.7 ( Build 6 ) , . (' ( File: Northstar Bigbore Producer Casing Design.sck UNDISTURBED TEMPERATURE DATA Date: August 01, 2001 Page: 5 Surface Ambient: Bottomhole Temperature - 11242 ft TVD: Bottomhole Gradient - 11242 ft TVD: Vertical Depth (ft) 793 ft 1441 ft 2828 ft 4100 ft 5721 ft 7583 ft 8769 ft 8818 ft 9087 ft 9423 ft 10503 ft 10685 ft 11083 ft 11409 ft --- I 12.0 deg F I 155.2 deg F ! 2.18 deg F/100ft I Temperature (deg F) I , 30.0 deg F ! 46.0 deg F 60.0 deg F 90.0 deg F 120.0 deg F 150.0 deg F 180.0 deg F ' 187.0 deg F 196.0 deg F 210.0 deg F 240.0 deg F 245.0 deg F 251.0 deg F 261.0 deg F DESIGN PARAMETERS DATA 133/8" Surface Casin Design Factor (Pipe) - Axial: Design Factor (Coupling) - Axial: Design Factor (Pipe) - Burst: Design Factor (Coupling) - Burst: Design Factor (Pipe) - Collapse: Design Factor (Pipe) - Triaxial: Minimum Internal Drift Diameter: Single External Pressure Profile: Temperature Deration: Limit to Frac at Shoe: Bucklin: ---. 1.400 1 .400 1.100 1.100 1.000 1.250 12.250 in Yes Yes Yes Yes Northstar Producer Casing Design StressCheck 1998.7 ( Build 6 ) File: Northstar Bigbore Producer Casing Design.sck INITIAL CONDITIONS (13 3/8" Surface Casin~l Date: August 01, 2001 Page: 6 Mix-Water Density: 8.50 ppg Lead Slurry Density: 12.20 ppg Tail Slurry Density: 15.90 ppg Tail Slurry Length: 750 ft Displacement Fluid Density: 9.50 ppg Float Collar Depth, MD: ' 3413 ft Slackoft Force: 0 Ibf Temperatures: Default ----.-- ------...----.-- ------------------..-----.--------.--.-.- ---.---------------- Vertical Depth (ft) Temperature (deg F) ---------_._-_.__._-_.._.._._.~----- -- ------------.----.----------..----..--- .----.,-..----..- --.-- -.-----------------.-------,--.--.-..------.-.----- ---------.----- ----- 0 ft 12.0 deg F 500 ft 23.3 deg F 793 ft 30.0 deg F 1442 ft 46.0 deg F 1750ft 49.1degF 2930 ft 60.0 deg F 3175 ft 64.2 deg F 3493 ft 69.4 deg F --...-. ----------,. ----.--..-.------------.-------..-,.-.--.....- --..----.-. ----......,. ,...---.--....--- .-.--..- -.---...--..--------------- ---..--- .-- . ----.- --.. -.----.------ ----- ..,------------ ---,--_._----- ----"--- -------.-----.-.". --- BURST LOADS DATA í13 3/8" Surface Casin~l Drilling Load: Test Pressure: Mud Weight: Assigned External Pressure: Alternate Design Factor (Pipe) - Burst: Alternate Design Factor (Coupling) - Burst: Pressure Test 3500 psig 9.50 ppg Fluid Gradients (wI Pore Pressure) 1.000 1.000 Drilling Load: Gas Gradient: Shoe Depth, MD: Frac Pressure at Shoe: Frac Margin of Error: Frac @ Shoe wI Gas Gradient Above 0.1000 psilft 3493 ft 2178 psig 0.00 ppg Drilling Load: Test Pressure: Mud Weight at Shoe: TOC, MD: Lead Slurry Density: Tail Slurry Density: I Tail Slurry Length: Displacement Fluid Density: Float Collar Depth, MD: Green Cement Pressure Test 2500 psig 9.50 ppg Oft 12.20 ppg 15.90 ppg 750 ft 9.50 ppg 3413 ft External Pressure: TOC, MD: Fluid Gradients (wI Pore Pressure) Oft Prior Shoe, MD: f'\ . :~ Vil Mud Weight Above TOC: I Fluid Gradient Below TOC: i Por~ ..p~~§~l}-~~-~Qp-~_t!Q!~: . 9.50 ppg 8.33 ppg Yes Northstar Producer Casing Design StressCheck 1998.7 ( Build 6 ) l' " ,( File: Northstar Bigbore Producer Casing Design.sck COLLA~LOADS DATA 03 3/811 Surface Casinç,l Date: August 01, 2001 Page: 7 Drilling Load: Mud Weight at Shoe: TOC, MD: Lead Slurry Density: Tail Slurry Density: Tail Slurry Length: Displacement Fluid Density: Float Collar Depth, MD: Assigned External Pressure: Cementing 9.50 ppg Oft 12.20 ppg 15.90 ppg 750 ft 9.50 ppg 3413 ft Fluid Gradients (wI Pore Pressure) Drilling Load: Lost Returns Depth, MD: Pore Pressure at Lost Returns Depth: Pore Pressure Gradient at Lost Returns Depth: Mud Weight: Mud Drop Level, MD: Assigned External Pressure: Lost Returns with Mud Drop 12286 ft 4382 psig 9.12 ppg 9.80 ppg 642 ft Fluid Gradients (wI Pore Pressure) External Pressure: TOC, MD: Prior Shoe, MD: Fluid Gradient Above TOC: Fluid Gradient Below TOC: Pore Pressure In 0 en Hole Below TOC: Fluid Gradients (wI Pore Pressure) 0 ft 0 ft 9.50 ppg 9.50 ppg No AXIAL LOADS DATA (133/811 Surface Casino) Running in Hole - Avg. Speed: Overpull Force: Pre-Cement Static Load: Pickup Force: Post-Cement Static Load: Green Cement Pressure Test: Service Loads: 2.0 ft/s 100000 Ibf Yes 0 Ibf Yes 2500 psig Yes BURST LOADS TABLE 133/811 Surface Casin Depth (TVD) Pressure Test Frac @ Shoe wI Gas ¡ Green Cement Pres.Test Green Cement Pres. Test Fluid Gradients wi Pore Gradient Above I (Int) (Ext) Press (ft) (psig) (psi g) i (psig) (psig) . (psig) --L 0; 3500; 1855 2500. 0 0 5OO¡ 3747 1905 2747 317 225 1749; 4363: 2030 33631 1108 786 3OO7i 4984: 2156 3984 1969 1351 I 3150: 5055: 2170 4055 2087 1415 I : 4064 3170; 5064 2172 2103 2103 1425 : 3225 5091 2178 2149 2149 1453 ~------- ---- - ~-~_._---_. Northstar Producer Casing Design StressCheck 1998.7 ( Build 6 ) File: Northstar Bigbore Producer Casing Design.sck I COLLAPSE LOADS TABLE (13 3/8" Surface Casinql ___no Depth (TVD) (ft) Cementing (Int) (psig) Cementing (Ext) (psig) Date: August 01, 2001 Page: 8 Lost Retums (psig) - 0.-"'----.--'- - ------------. .-.--------Ô---------..-.......--.----.-----..-..-------(i-----------'---'-' 500 247. 31i 642 317 407; 1749 863 11081 2678 1321 1697: 3007 1484 19691 1564: . 2103' 3225 --- --------------.___.__n 2149: -------..---------------- --~_._----- -'------'---. 3170 2103: ¡ 2149, Fluid Gradients wi Pore Press (psig) 0 --. -.- ---.--.----..---------- 563 1036. I 1204 1287 1315: 0 247 317 863 1321 14841 -------..----------..- ..-.--.--.-------.-..--.----- 1564 1591 '-------- -.---.-------------- ---- -.-.. ----.---'-------.-'--'----'."----'-'..'---'--.-.-.---.-... --------'----- -----.- AXIAL LOADS TABLE {13 3/8" Surface Casinql ---~----_.. 10 11 12 13 14 Depth (TVD) I Apparent I (ft) (w/Bending) 0' I 5001 6421 I 1749; 2678. 28921 3358511 315482, 316025' 310350 288440; 344531, 300323: 279908: 276665: , 276664 264652: , 262983 262982 258330 Overpull Force (Ibf) Actual Apparent (I (w/Bending) B Wd? ) en ang_....1 288324. 267955 2679541 261531 201715 , 201714 143798 , 122030 I 118573: 118572' 106354 104673. 104672' 1 00000 Pre-Cement St~!ic LoadlPost-Cement Static Loa Green Cement Pressur Actual J ( I Apparent B Wd? ) (W/Ben. ding) en 109 -- ------ 112216 457377 I 78217 423378 78216 437551: 68571 427907 -6686 409966' -6687 466057 -69861 402882: -89167 383576 -92234 380510' I -92235 252926 -101984 243177¡ -103324 241836 -38056 -80579 -41782 -84305 Actual ( I~' I, Apparent Be~d~~:/Ben~in~J 414854 457377 380855' 423378 380853 437551 371209 427907 295952 409966 295951 466057 232776, 402882 213470 388329 210404 384160 210403 256577 200654 251380 199313 250576 -38056 276683 -41782: 273126 Service Loads (Ibf) Actual (w/o Bending) 414854 380855 380853 3712091 295952 295951 232776 218223 214055 214054 2088571 208053¡ 234160 2306031 .--....-.-1 330847, 310478 311021 : 305346 283436 3395271 295319 274904 2716611 271660' 259648 257979 257978 253326 --..---.-------.-------. -------------.... Running in Hole (Ibf) . 'T---- Actual (w/o Be~ding) . 293328, 272959' 272958 266535' 206720' 206718 148802 I 127035 123577' 123576. 111358 109677 109676 105004 , I 3O07! i 3150¡ 3170' I 3225: Northstar Producer Casing Design A~tual 1 Apparent / Apparent KWlBendingj B~~;'ng) (wlBending), 188324 154739 154325; 1207401 154324 134913: 144679 125269: 69423: -1206991 69421: -1767931 6247: -2399671 -13917: -2592731 -16126, -2623401 -161271 -134758. -25876 -1445071 -27216 -1458471 -27217' -80579' -30944 -843051 ...-.----...--..--.-.------------. -.-.".."'-..'.-.-'.-------.-----.-.-..-1.-....- 230847: 196848: 2110211 , 201377, 183436' 239527' 17635...1 -184023 -186232: -58650. -68399 -69739 -69740 -73467 StressCheck 1998.7 ( Build 6 ) . , (' ~.. File: Northstar Bi bore Producer Casin Desi n.sck BURST DESIGN (13 3/811 Surface Casing) 1000 - ~ '-'" £ 1500 0- Q) 0 ~ 2000 t Q) > Q) 2500 :J '- I- 3000 3500 4000 3000 Date: August 01, 2001 Pa e: 9 0 500 X I I I . 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()) 0 .~ 2000 t ()) > ()) 2500 ::J ..... r- t-----------t--- 50.0 55.0 I I 60.0 65.0 VME Stress (ksi) 80.0 85.0 ¡--- 70.0 .--- ,_.--------- --------.----- Northstar Producer Casing Design StressCheck 1998.7 ( Build 6 ) ( l I,. Date: August 01, 2001 Page: 11 File: Northstar Bi bore Producer Casing Design.sc~_- TRIAXIAL SAFETY FACTORS (13 3/8" Surface Casing) 1000 - ~ - -£ 1500 a. w 0 ~ 2000 :e Q) > Q) 2500 :J ~ I- 3000 3500 4000 0.00 0 v - - ....'. I '-' , ¡ jil 1 1 I '+Burst I' ; 1 1 I I 1 I:;' I 1 1 1 "-Collapse I;" I 1 1 1 - - - - - - - - _L - - +... - - - :...,- -... - - - - - - _I_... - - - - - -,- - - - - - - - - -,- - - - - - - - - _I_... - - - 0 Axial I' I I I I I I; +." 1 , I 1 ..... T. . I I : j' 1 I I 1 1 .... naxla : i ; : : : : : ^ ~ailure Criteria mmurT m r u- - muim ur mium_uui-uuu - -r U- i. - - - - - - - - -~ - - t - - - - ~ -~ - - - - - - - - -i- - - - - J - - - -i- - - - - - - - - -j- - -- - - - - - ~- - - - - - - - - ~- - - -- - - -- 1 ¡ [I, 1 S; I I 1 I , : : 1 1 1 1 , I - - - - - - - - -:- - - t - - - -r -:- - - ... - - - ... - -:- - ... - - - ... - -:- - - - - - - - ... -:- - - - - - - - - -: - - - - - - - - - -: - - - - - ... - - - 1 J ¡I, I 0 I I I I 'I ;-"11 1 \t I I I I , ,..., 1 1 1 I 1 1 - - - - - - - - -: - - r - - -l!-:- - - - - ... - - - -:- - - - - - - - - -¡- - - - - - - - ... -¡- - -. - - - - - - : - - - - -._~ :- - - : - - - - - - - - - , i..:.., I I I ._-.¡.-X-'-" I Ii :...Jj' I I ,/--,--'--"--, I - - - - - - - - - ~ - - t - - - 1¡ -:- - - - - - - - - -:- - - - - - - - I 0 -.or- / "0- - - - - -: - - - - - - - - - ~ - - - - - - - - - I ! /.., 1 , I ~,"-:':_..._..-'t---~ ...:::::...........----+-----.......-.-.......... x 1 I <) I..." 1 I I 0 I I , I I I , I I I , I I I I I - - - - - - ... - - r - - - - - - - - -,- - - ... ... - - - - -,- - - - - ... - - - -1- - - - - - - - - -,- - - - - - - - - -1- - - - - - - - - -,- - - - - - - - - I I I , I I I 1 I I I I I I I I I I I I I I I I I I I I 500 0.75 2.25 3.00 3.75 Normalized Safety Factor 4.50 6.00 5.25 1.50 .MLNIMUM SAFETY FACTORS {:13 3/8" Surface Casi.!lg} 1 10 11 12 13 14 15 16 17 18 19 0 Depth (TVD) (ft) Connection Burst 1.41L Factor (Abs) Axial Triaxial 3.38 F 1.81 9.17 3.65 F 1.80 3.53F 7.15 3.61 F 1.79 6.66 3.77F 1.72 3.32 F 1.69 6.53 3.59 F 1.66 5.10 3.84F 1.64 4.81 3.95F 3.94 3.98F 1.63 3.83 4.02 F 5.58F 1.70 3.48 5.84 F 1.69 3A7 5.88F 6.11 5.58F 1.71 6.09 5.66F 1.70 OD/Weight/Grade 133/8",68.00 Ibm/ft. L-80 BTC, L-80 0 500 1.40 L 642 1749 1.38 L 1.37 L 1974 2678 2743 2892 3007 3150, 3170 1.36 L 3224 3225 L F Connection Leak Connection Fracture .--.--.-..-...----.--.-. '-'.""".--""'.-"- Northstar Producer Casing Design StressCheck 1998.7 ( Build 6 ) File: Northstar Bigbore Producer Casing Design.sck I MAXIMUM ALLOWABLE WEAR (133/8" Surface Casin~l Date: August 01, 2001 Page: 12 I 10 11 Depth (TVD) (ft) .-...--...-.-.-.--...- ODIW eighVGrade Max- Wear (% of Wall Thick.) Burst --.-1 Collapse 30_3 No Collapse load 29.9 52.1 29.7 48.0 28.8 46.8 28.2 46.4 27.9 40.8 27.7 36.2 34.2 34.1 45.3 45.2 ..-...----........-.. 0 500 642 1749 1974 2743 3007 3150 3170 133/8",68.00 Ibmlft, l-80 27.6 3225 ----..-...-...-.- "---'.--'-'.'----------------"-'",---",-,-----,---,--...-'------ - ----.--. ..-.---.-.- ---.-- --------- --.----- -----.-.---- -- - ....-..--.- -. ---.----- ~._- - -----------------....-.--- MAXIMUM ALLOWABLE OVER PULL (133/8" Surface Casin~l 1 10 11 12 13 14 15 16 17 18 19 0 ~._.. .---....-.--.-----..----.. Running Depth (TVD) (ft) ---.--. --...- --"-'-.---".'-------'------- Burst 0.146, 0.144 0.143. 0.138 0.135 0.134' 0.133, I I 0.132 I 0.164 0.217 ----"'-~-"-'------_.----'l I 0 269 -------- Max. Overpull (Ibf) 500 537 806 999 1073 1341 1610 1749 1877 1992 2133 2371 2582 2763 2789 2911 3007 3170 3225 1061092 1045400 1031891 1031890 1029707 1014031 1002762 998424 982775 967086 958970 950289 942816 936055 927811 913932 901594 891056 889497 882399 876815 876814 867289 864088 --...-.--.-....----.. ---- . ...- - ..-.--..--.....-..---------- ""'--'-'--"-----..'- - ----. -. -.-----.----.-----------------. ....- .-.---.-------..-----------.....---.-------..-----.-.--.---...-...---.-.......-.----------.----.------....-..-----.--...-..-. .- IJRiAXi"Ai-RESUL TS (13 3/8" s~;:fu~-~--C;~g)~-P-;~.;sure Test --------~------_.._-------_._-------_._-_.._--_.._------.-'--1 i : Axial Force (Ibf) Bending Absolute Safe Factor emperatu1 J :! I Depth (TV D) A A I St ¡ Addt'l Pickup To Buckled I pparent ctua ress. . . e : 11~~J.' ..-. -(~ --)J~~:: ~~~~32~t~~~}- ~_na;'~'i I ...""';'i. _~~I~__A;;8 FJ<le9 ~:ö _~en~~- ~en~;~~ 1 500 382729, 340206 1.80 4.04 F 396902 340205 1 79 1 .40 l 3.89 F 389463 332765 2.9 . ~ 388727 274714 444819 274713 396087, 225981 384160 214055 256577 214054 251380 208857 250576 208053 276683 234160 273126 230603 -=~=:_] 5 . -:, -,,"',',,"-,,""""'1 I 1':-." 8 : ~""',, -,,"""""1" f}~" -- 12 13 14 15 16 642 1749 2678 3007 3150 3170 3225 5.9 3.97 F 3.47 F 3.90 F 4.02 F 6.02 F 6_15 F 6,,17 F 5.58 F 5.66 F 1.72 1.69 1.64 1.63 1.70 1.38 l N/A 8.7 ?? 1.69 1.71 1.70 1_36 l L Conn leak F Conn Fractur .."-",, ...-.....-...-."---.."""--..,, , Northstar Producer Casing Design 23.3 26.6 49.1 58.5 64.2 67.6 68.1 69.4, ... -.'" .....-_.....,,- - "...,," StressCheck 1998.7 ( Build 6 ) (" I' '. File: Northstar Bigbore Producer Casing Design.sck Date: August 01, 2001 IRIAXIAL ~ESUL TS (13 3/8" Surface Casinal.:.Yrac @ Shoe wI Gas Gradjent Above Page: 13 i I Buckled ~ Length (ft) 1 Ii I I I Depth (TVD) Axial Force Ibf) Bending Addt' Pickup To (ft) Apparent Actual Stress Triaxial Prevent Buck. (Ibf) (wlBending) (w/o Bending) at 00 (ksi) 1 0' 111777 69254 3.16 2.66L 13.82 F N/A 97657 55134 2.2 3.47 15.82 F 500 111831 3.43 . 2.93 L 13.82 F 60.9 55133 2.9 642: 107825 51128 3.52 3.02L 14.33 F 62.3 , I 123480 9467 5.9 4.07 12.51 F 1749, 179571 8.6OF 72.9 : 3.74 : 3.96L 18681 170106 9465 9.08 F 74.1 I -170106 8.7 N/A 26781 -234013 -63907 4.05 . 5.36L 6.6OF 81.8 10 ; -244966 4.28 6.31 F 11 3OO7¡ -117384 -74861 5.74 6.13 L 13.16 F 85.0 12 3150 -118598 -76075 6.03 : 6.53L 13.03 F 86.3 ¡ 6.07; 13 ! -118854 -76331 2.2 13.00 F 14 3170; -92746 -50223 6.52 : 6.6OL 16.66 F 86.5 I 15 3225: -94781 -52258 6.66 ! 6.81 L 16.30 F 87.0 16 I, ' 17 It Conn Leak 18 FI Conn Fractur TRIAXIAL RESULTS 133/8" Surface Casin - Green Cement Pressure Test N/A Depth (TVD) Axial Force (Ibf) Bending emperatu Addt'l Pickup To Buckled (ft) Apparent Actual Stress Triaxial e Prevent Buck. (Ibf) , Length (ft) (wlBending) (w/o Bending) at 00 (ksi) (deg F) I 01 457377 414854 2.2 2.48 ¡ 1.97 L 3.38F N/A N/A I 423378 380855 2.57 : 2.03L 3.65F 500' I 437551 380853 2.9 2.55 3.53 F 642: 427907 371209 2.58 . 2.05L 3.61 F 17491 409966 295952 5.9 2.73 : 2.19 L 3.77 F I 466057 295951 2.66 , 3.32 F 26781 402882 232776 8.7 2.86 : 2.32 L 3.84 F I 3007! 380510 210404 3.01: 2.45L N/A 4.06 F 47.7 252926 210403 3.16 6.11 F 10 3150: 243177 200654 3.24 ' 2.51 L 6.35 F 11 241843 199320 3.25 2.52 L 6.39 F 12 3170' 241836 199313 2.2 13 ! -80579 -38056 36.41 , 14 I -80611 -38088 36.39 + 100.00 19.17 F I 15 3225: -84305 -41782 34.13 , 18.33 F 16 I I 17 ~ Conn Leak 18 FI Conn Fractur Northstar Producer Casing Design StressCheck 1998.7 ( Build 6 ) File: Northstar Bigbore Producer Casing Design.sck TRIAXIAL RESULTS (13 3/8" Surface Casing) - Cementing Date: August 01, 2001 Page: 14 Depth (TVD) Axial Force (Ibf) Bending emperatu, Addt'l Pickup To J Buckled (ft) Apparent Actual Stress Triaxial e preve_~~.~uc:(~~.. ~ength ..(ft) J~/Bending! - (w/~Bendin~t at 00 (ksi) (deg F) -r----'" --...---- -..... 1 0 154739 112216 10.05 + 100.00 9.98F N/A N/A 2.2 500 120740 78217 11..42 25.57 12.80 F 134913 78216 2.9 10.35 ' 11..45 F 642 125269 68571 10..71 19.94 12.33 F 1650 114050 37 9.18 7.81 13.55 F 1651 -114034 -21 5.9 16.75 1749 -120699 -6686 15.88 .. 12.80 F -176793 -6687 10.36 , N/A 7.37 8.74 F 47.7 2678 -239967 -69861 8.7 7.93 4.81 6.44F ----- 10 -262340 -92234 7.30 5.89F, --- 3007 3.83 11 -134758 -92235 12..46 .. 11..47 F -.- 12 3150 -144507 -101984 11..40 3.51 10.69 F -.- 13 3170 -145847 -103324 2.2 11.27 3..47 10.59 F 14 -80579 -38056 36..41 14.99 19.17 F ---- 15 3225 -84305 -41782 34.13 14.68 18.33 F¡ - 16 171 F Conn Fractur .._--_. --- ....----...-.---.....-........ --.-..--...-----.----- -----------.... --------..----.----...- ....-._--~_. "-"-'-------"'-'-'-'-~-,----- TRIAXIAL RESULTS í13 3/8" Surface Casing) - Lost Returns with Mud Drop Depth (TVD) Axial Force (Ibf) Bending emperatu~ Addt'l Pickup To Buckled (ft) Apparent Actual Stress Triaxial e Prevent Buck. (Ibf) length (ft) (w/Bending) ._J"'!/o Bending). at 00 (ksi) (deg F) --- - .-. 1 I 0 -107596 -65073 14..46 : + 100.00 14.36 F! 56.0 N/A N/A 2.2 500 -126927 14..47 . 9.17 12.17 F.. -141102 -84404 13.11 I 10.95 F 60.8 642' -146585 -89888 2.9 12..48 ! 7.15 10.54 F 62.1 1749 -216173 -102160 5.9 8.89 ! 6.66 7.15 F 72.6 -272267 -102161 6.81 5.67F 2678 -320969 -150863 8.7 5.79 . N/A 6.29 4.81 F 81.3 3007 -323186 5.80 4.78F -195603 -153080 10.56 6.17 7.90F 84.4 -.- IT=: 3150 -193010 -150487 10.81 6.12 8.01 F 85.8 3170 -192653 -150130 2.2 10.85 6.11 8.02 F 86.0 12 -166546 -124022 12.87 9.28 F ~_.. :13 3225 -166878 -124355 12.89 6.09 9.26 F 86.5 .-..-- I 14 -.-.- 15 F Conn Fractur --""--'--'-~-----'-'--_.._-..,--... ... -.-------..... -......---....--..--.-----...-..--..-----------.. ...-..-.----------........ - - --..---.---.....---.-..-............--.-----.-------..--...-..---.-- '-"-'----"-"----"-"'-'---'-'-------,-,,- .. --------.. ------..---------......--...----.-----------------------....-..--.........-.-..... .......---........---.------...-.--.---...---.-- TRIAXIAL RESULTS (13 3/8" Surface Casing) - Running in Hole --_.._~------ --- 10 11 12 ~n Axial Force (Ibf) Bending Depth (TVD) (ft) (:~~~~~~)_L(~~t~~~n~~~L --~!....~~(~~2..__. 0 335851 293328 315482 272959 316025 272958 310350 266535 288440 206720 344531 206718 300323 148802 276665 123577 276664 123576 264652 111358 262983 109677 262982 109676 258380 105054 258330 105004 500 642 17491 2678 3007 3150 3170 3224 3225 F Conn Fractur Northstar Producer Casing Design 2.2 Triaxial -..---.-- 4.63 4.86 .. + 100.00 4.85 4.91 96.58 5.10 . 35.86 4.31 ! 4.77 + 100.00 23.55 21.03 5.09 20.68 5.28 19.77 19.66 5.30 1965 19.34 5.38 19.33 - ~:~1P~:~~~~~~~~~_L~;('~ 4.60 F N/A N/A 4.90F: 4.89F.. 4.98 F 5.36F I 4..48 Fi 5.14 F 5.58 F 2.9 5.9 8.7 47.7 5.84 F 2.2 5.88 F 5.98 F - --- -----.--. -...............- StressCheck 1998.7 ( Build 6 ) ,{ ( File: Northstar Bigbore Producer Casing Design.sck I.RIAXIAL RESUL T..§l13 3/811 Surface Casina) - Overpu,1 Force 10 11 12 13 14 15 16 Axial Force (Ib Depth (TVO) Apparent Actual (It) (wlBending) (w/o Bending) 0, 330847: 288324 310478 267955 311021: 267954 305346 261531 283436, 201715 339527 201714, 295319: 143798. 27166f 118573 271660' 118572 259648; 106354 257979: 104673 257978' 104672 3224: 253376' 100050 3225: 253326; 100000 , I F Conn Fractur' Bending Stress at 00 (ksi) 2.2 Date: August 01,2001 Page: 15, I i Triaxial Buckled Length (It) N/A 500 642: 1749' 2678: i 3007~ 3150 , 3170! emperatu e (deg F) Addt'l Pickup To Prevent Buck. (Ibf) N/A 4.70 4.93 Axial 4.67F + 100.00 4.98F 4.97 F, 96.66 5.06F 35.88 5.45 F 4.55F 23.56 , 5.23F, I 21.04 . 5.69F 20.69 19.79 5.95 F 19.67 5.99F 19.35 i 6.10 F; I 47.7 2.9 5.9 4.99 5.18 4.37 4.85 + 100.00 5.18 5.37 . 5.39 5.47 8.7 2.2 ~RESUL TS (13 3/811 Surface Casi.!!9L:..Pre-Cement Static Load Depth (TVO) Axial Force (Ibf) Bending emperatu Addt' Pickup To Buckled (ft) Apparent Actual Stress Triaxial e Prevent Buck. (Ibf) Length (ft) (wlBending) (w/o Bending) at 00 (ksi) (deg F) 1 0; 230847; 188324, 2.2 6.74 . 6.69F: N/A N/A 5001 196848' 154325 7.71 : + 100.00 7.85F : 7.32 F: 1 211021 154324: 7.21 1 2.9 6421 201377 144679 7.50 i 98.06 i 7.67F 17491 183436! 69423 5.9 7.77 36.30 ! 8.42 F: , 2395271 69421 6.07 , 6.45 F 2678. 176353 6247 7.70 23.85 I 8.76F¡ 2769: : 23.08 ' 170143, 37 8.7 7.91 + 100.00 9.08F 47.7 2770 -170115, -9 9.99 23.07: 10 3007. -186232 -16126 9.17 21.25 8.30F 11 -58650: -16127 47.36 26.34 F 12 3150: -68399' -25876 37.74 20.29 22.59 F 13 3170 -69739 -27216 2.2 36.71 20.16 22.15 F 14 -69740 -27217 15 3225; -73467 -30944 34.13 19.82 21.03 F 16 i 17 F' Conn Fractur Northstar Producer Casing Design StressCheck 1998.7 ( Build 6 ) File: Northstar Bigbore Producer Casing Design.sck TRIAXIAL RESULTS 1133/8" Surface Casing}- Post-Cement Static Load Depth (TVD) Axial Force (Ibf) Bending (ft) Apparent Actual Stress .. Jw/Bending) (w/o Bendin~L.._.. _.a~ ~~)J~:~2 ..L~nax'a' 0 154739 112216 120740 78217 134913 78216 125269 68571 114050 37 -114034 -21 -120699. -6686 -176793 -6687 -239967 -69861 -262340, -92234 -134758 -92235 -144507 -101984 -145847 -103324 -80579' -38056 -84305 -41782 + 1oo.oo! ._--¥-.._~ + 100.00 + 100.00 2.2 10.05 11.42 10.35 10.71 9.18 16.75 15.88 . 10.36 ¡ 7.93 7.30 12.46 11.40 11.27 36.41 34.12 ' 2.9 25.57 19.94 500 642 1650 1651 5.9 1749 N/A I 2678 3007 8.7 10 11 12 13 14 15 16 17 3.83 3.51 3.47 14.99 14.68 i 3150 3170 2.2 3225 F Conn Fractu~ ---- --.-..---...---.--.-.-. - -.---.---- --- - - -- .---..- ----.---- -..... --.-- ..-.--------.----------.- -- ---.-..---- - ------- -.-- .-----.----- - - - --.. --- ----- ------ Date: August 01, 2001 Page: 16 emperatu,¡ Addt'l Pickup To I Buckled ._._Jd~ F) -- Prevent Buck. (Ibf) -. .__=~ngth ~~~-- 9.98 F 12.0 N/A N/A 12.80 F 11.45 F 12.33 F 13.55 F 7.81 7.37 : 4.81 12.80 F 8.74 F 6.44 F 5.89F 11.47F 10.69 F 10.59 F 19.17 F 18.33 F TRIAXIAL RESULTS {13 3/811 Surface Casinq}- Green Cement Pressure Test 1 10 11 12 13 14 15 16 17 18 L Conn Leak F Conn Fractur, ,..-..--------------------------_._--------,------ ----.,----.--.----.......-.---..------------------------------_.------..-- -..---------....--....-------..-------.---------------- --- 23.3 26.6 48.1 49.1 58.5 I 64.2 67.6 68.1 69.4, emperatu e (deg F) Addt'l Pickup To Prevent Buck. (Ibf) ----- N/A Buckled Length (ft) N/A -----------~--------------_.._----" - ---- " --- -------...----------- -----------------------.-....--.-.--.....-.--"..--------- ...----- Depth (TVD) Axial Force (Ibf) Bending Apparent Actual Stress .. (ft) ~w/Bending) (w/o Bending) at 00 (ksi) ¡ Tnaxlal -.-,.------....- ----, ----- 0 457377. 414854 2.48 1.97 L: 3.38 F 423378, 380855 2.2 I 3.65 F 500 2.57 2.03 L' 437551 380853 2.9 2.55 3.53F 642 427907 371209 2.58 2.05 U 3.61 F 1749 409966 295952 5.9 2.73 2.19 L 3.77 F 466057 295951 2.66 3.32 F 2678 402882 232776 8.7 2.86 2.32 L 3.84 F 3007 380510 210404 3.01 2.45 L N/A 4.06 F 252926 210403 3.16 6.11 F 3150 243177 200654 3.24 2.51 L 6.35 F 241843 199320 3.25 2.52 L 6.39 F 3170 241836 199313 2.2 -80579 -38056 36.4 1 19.17F -80611 -38088 36.39 + 100.00 3225 -84305 -41782 34.13 18.33 F DESIGN PARAMETERS DATA {9 5/8" Production Casing} Design Factor (Pipe) - Axial: Design Factor (Coupling) - Axial: Design Factor (Pipe) - Burst: Design Factor (Coupling) -- Burst: Design Factor (Pipe) - Collapse: Design Factor (Pipe) -- Triaxial: Minimum Internal Drift Diameter: Single External Pressure Profile: Temperature Deration: ~~I~:rac at~:~e: - ----- -.--- , Northstar Producer Casing Design 47.7 1 AOO 1AOO 1.100 1.100 1.000 1.250 8.500 in Yes Yes No II y~~ StressCheck 1998.7 ( Build 6 ) ( I , File: Northstar Bigbore Producer Casing Design.sck nÐJlAL CO~9 5/811 production Casing), Mix-Water Density: Lead Slurry Density: Tail Slurry Density: Tail Slurry Length: Displacement Fluid Density: Float Collar Depth, MD: Slackoff Force: Temperatures: Vertical Depth (ft) Oft 500 ft 793 ft 1442 ft 1750 ft 2930 ft 3175 ft 4773 ft 7150 ft 9896 ft 11652 ft 11725 ft 11743 ft 12090 ft 12301 ft 12480 ft Northstar Producer Casing Design Date: August 01, 2001 Page: 17 ¡ 8.50 ppg : 13.30 ppg : \ 15.90 ppg , I 1154 ft I 9.80 ppg I I 12400 ft I 0 Ibf Default I Temperature (deg F) 12.0 deg F 23.3 deg F 30.0 deg F 46.0 deg F 49.1 deg F 60.0 deg F 64.2 deg F 90.0 deg F 120.0 deg F 150.0 deg F 180.0 deg F 187.0 deg F 187.4 deg F 196.0 deg F 203.3 deg F 209.8 deg F 1 I StressCheck 1998.7 ( Build 6 ) File: Northstar Bigbore Producer Casing Design.sck BURST LOADS DATA í9 5/811 Production Casinql Date: August 01, 2001 Page: 18 Drilling Load: Influx Depth, MD: Pore Pressure: Gas Gradient: Frac at Shoe: Gas/Mud Interface, MD: Mud Weight: Assigned External Pressure: Displacement to Gas 14586 ft 5227 psig 0.1000 psi/ft 8563 psig Oft 9.30 ppg Fluid Gradients (w/ Pore Pressure) Drilling Load: Test Pressure: Mud Weight: Assigned External Pressure: Pressure Test 3500 psig 9.80 ppg Fluid Gradients (w/ Pore Pressure) Production Load: Packer Fluid Density: Packer Depth, MD: Perforation Depth, MD: Gas/Oil Gradient: Reservoir Pressure: Assigned External Pressure: Tubing Leak 9.60 ppg 14100 ft 14200 ft 0.1000 psi/ft 5071 psig Fluid Gradients (w/ Pore Pressure) Drilling Load: Test Pressure: Mud Weight at Shoe: TOC, MD: Lead Slurry Density: Tail Slurry Density: Tail Slurry Length: Displacement Fluid Density: Float Collar Depth, MD: Green Cement Pressure Test 3000 psig 9.80 ppg Oft 13.30 ppg 15.90 ppg 1154 ft 9.80 ppg 12400 ft External Pressure: TOC, MD: Prior Shoe, MD: Mud Weight Above TOC: Fluid Gradient Below TOG: _e_or~..Ere~sl~LE?_I_Q- °p§D__t-1q!~:_- Fluid Gradients (wI Pore Pressure) Oft 3493 ft 9.80 ppg 8.33 ppg Yes ......-........-..---- ---.. ......... .. --..... -.--.,.---..-..--.----.-.----..----.-..-.-- -"",.,-"",.."-,-"""",-,,.- .--.....-..-..--_u_--.-.-- Northstar Producer Casing Design StressGheck 1998.7 ( Build 6 ) r , { File: Northstar Bigbore Producer Casing Design.sck ~LLAPSE LOADS DATA (95/818 Production CasinQl Drilling Load: Mud Weight at Shoe: TOC, MD: Lead Slurry Density: Tail Slurry Density: Tail Slurry Length: Displacement Fluid Density: Float Collar Depth, MD: Assigned External Pressure: Drilling Load: Lost Returns Depth, MD: Pore Pressure at Lost Returns Depth: Pore Pressure Gradient at Lost Returns Depth: Mud Weight: Mud Drop Level, MD: Assigned External Pressure: Production Load: Packer Depth, MD: Perforation Depth, MD: Pore Pressure at Perforation Depth: Density Above Packer: Density Below Packer: Fluid Drop Above Packer: Assigned External Pressure: External Pressure: TOC, MD: Prior Shoe, MD: Fluid Gradient Above TOC: Fluid Gradient Below TOC: Pore Pressure In a en Hole Below TOC: ...' ~. Date: August 01, 2001 Page: 19 Cementing: I 9.80 ppg ¡ 0 ft I 13.30 ppg ! 15.90 ppg , 1154 ft 9.80 ppg I 12400 ft Fluid Gradients (wI Pore Pressure) Lost Returns with Mud Drop 14586 ft 5227 psig 8.95 ppg 9.30 ppg 423 ft Fluid Gradients (wI Pore Pressure) Above/Below Packer 14100 ft 14200 ft 3134 psig 9.60 ppg 0.00 ppg Yes Fluid Gradients (wI Pore Pressure) I I Fluid Gradients (wI Pore Pressure) 0 ft 3493 ft ¡ 9.80 ppg I 9.80 ppg ! Noi AXIAL LOADS DATA (95/818 Production Casinal Running in Hole - Avg. Speed: Overpull Force: Pre-Cement Static Load: Pickup Force: Post-Cement Static Load: Green Cement Pressure Test: Service Loads: 2.0 ft/s 100000 Ibf Yes a Ibf Yes i : 3000 psig i Yes ¡ Northstar Producer Casing Design StressCheck 1998.7 ( Build 6 ) OisPlaceme." n. t To Ga. s ¡ . P.. reo .ssure T. est J Tubing leak ! Green Cement ,Green Cement Pres. (pSI~~-_.__.-----_..__._._~PSig~__..._-----_._.~~~i.=~_.._-_J . presi~~~; (Int) . T(~~~~xt) 4103 3500 3981 -------- 3000 . 4153 3755 4230 3255 4278 4390 4853 3890 4404 5031 5480 4531 File: Northstar Bigbore Producer Casing Design.sck BURST LOADS TABLE {9 5/8" Production CasinQl Depth (NO) I (ft) 0 500 1749 3007 3225 8760 I 8830 9250 9263: 9349' 9418 4425 5142 5589 4642 4979 7960 8350 7460 4986 7995 8385 7495 5028 8209 8594 7709 5029 8216 8601 7716 5038 8259 8643 7759 6567 5045 8295 8678 6625 Date: August 01, 2001 Page: 20 I ¡Fluid Gradients wI Pore 'I Press .1 (psig) 0 at 345 2161 1208 I 7571 2077 1301 , 1395. 2228 14d 6081 42371 6139 4258 6486 4382 6497 4391 6567 4444! ! 6625 4483 -----..----..--- .-..------.-.----.---- .--------.-...-------.--.---.--.-....-....-.--.-..... ....- .--- ...... .--------......- ...-- -.-.-------------.--------------. ._. -.-----...- .- .--..- -.---..-..- --------. ---- COLLAPSE LOADS TABLE {9 5/8" Production CasinQl oep~~~~_~__~m(~~~~~ (I~~___. 0 0 423 215 500 255 1749 890 I 3007: 1531 3225 1642 4624 2354 8549 4352 8830 4495 9263 4716 9349 4759 6567 9418 6625 cem?~~oo~_-.l__::~;:~~Cd ~ wi PO:] 0 0 0 292 21~ ~ ~ ~ 1~ ~ 0 ~ 2077 1248 1531 2228 1353 1642 3195 2029 2354 5907 3926 1958 4352! I 6139 4062 2098 4495' 6497 4271 2314 47161 6567 4312 2356 4759! I 2391 47951 ...-.....- -....-......------.-......-.-.-...-.----------.-.-.1 10 11 12 13 6625 4346 ..-------...----.-----.---...-..-.....-...-.....-....--....................-..-.....--. ................-.-.--- ....................-....... . ...-..--...-.....-..... .-.-.---..--..--...--.--..-..---. ....- ...... Northstar Producer Casing Design StressCheck 1998.7 ( Build 6 ) , ( (' . File: Northstar Bigbore Producer Casing Design.sck Date: August 01, 2001 Page:21 I AXIAL LOADS T~(9 5/811 Production Casillill I Runnin in Hole Ibt) Overpull Force (Ibt) Pre-Cement Static Loa Post-Cement Static Loa Green Cement Pressur Service Loads (Ibt) I Depth (TVD) Actual Actual Apparent Actual Actual ' Actual Actual \ (ft) Apparent (w/o Apparent (w/o . (w/o ( 10 Apparent I (I Apparent (w/o wlBending Bending) (wlBending Be d" ) (wlBendlOg Bending) B~' ) (wlBending B ~~ ) (wlBending Bending) ~ n Ing e log en 109 1 0 472233 450875 498942 477584 398942: 377584 267105 245746 444667 423308 -439660 -418302 423 457898 436539 484607 463249: 379057: 357698 247219 225861 424782 403423 -436855 -41549 G 500 455500 434141 482209 460851 375443, 354084 243605 222247 421167 399809 -436345 455852 482562 460850 382562: 354083 250724 222246 428286 399805 -443465 -41498 1749 425959 399902 452669 426611, 3526691 295402 220831 163564 398393 341126 -471240 : I -413973 454133 399901 480842 426610 3808421 295401 249005 163563 426567 341125 -499415 3OO7! 411956 361268 438665 387977' 3217141 . 236273 189876 104435 367439 281997 -528856 2576311 236272 125793 1 04434 303355 281996, -464773 -4434 14 , 3225: 403350 352632 430059 379341. 2473901 226031 115552 94194 293114 271756 -462786 403349 352631 2473891 94193 271755 -462785 -441427 3501 386011 335233 412720 361942 226853, 205494 95015 73657 272578 251219 -461092 -440381 4274 380985 330189 407694 356898, 220900: 199541 89062 67703 266624 245265 -458389 -437462 4624; 347824 296913 374533 323622' 181622: 160264 49785 28426 227347 205988 -457497 -436139 8549 189104. 119513 215814, 146222, -455811 -24223 -177419 -156060 42860 21502 -402289 -380930 8760 178708 107006 205417: 133715j -554951 -34136 -187333 -165974 32947 11588 -394372. -373014 ! -587951 8830, 175009: 102835: 201718 129544¡ -37436 -190632 -169274 29647 -375273 -353915 , -1274131 : 8288 175008: 102834 201717! 1295431 -37437 -259251 98265 -443891 -353914 90231 155162 81904 181871 1O8614¡ -1463981 -56421' -278236 -188259 -100987 -11010' -430774 -340526 ; -1471431 9250; 154383 81083 181092 107792: -57166 -278981 -189004 -101419 -11442 -414751 -324774 153776 107177: I -57790 -279605 -189628 -102042 9263 80467 180485, -1477671 -12066, -413642 -323665 I -57791: -210987 -189629 153775 80466 180484 107176; -791491 -33425 -345022 -323664 9349 149845 76498 176554 103208 -83178: -61820 -215016 -193657 -37454 -16095 -337863 -316504 149844: I 176553 103207: -831791 -108014 -86655 -108014 -86655 -295060 -273701 9350, 146701: 73341 173410: 1ooo51! -86414 -65056 -111249 -89891 -111249 -89891 -294781 -273622 9418 146650 73291 173360' 100000: -86435, -65076. -111270 -89911 -111270 -89911 -290054 -268695 BURST DESIGN (9 5/811 Production Casing) - ~ --- -£ 4500 0.. Q) 0 ~ 6000 t Q) > Q) 7500 :::J L. I- 0 1500 ..,.. X I î I I , I I 'i I , I I I I ¡ I I I I , I i I I , ---------1- ------_J_--__~___L--__-----~--------~---______L______-_-L______--- I I' 1 1 I I , I 1 I 1 I I 1 , I I I I I I , I I I I t 1 1 I ¡ I I , I , - - - - - - - - -,- - + - - - - - - ï - - - - - r- - - - ï - - - - - - - - -,- - - - - - - - - 1- - - - - - - - - ï - - - - - - - - -,- - - - - - - - - - , '! ' 1 , I , , " , 1 I , I 1 I. 1 1 , , 1 I I 1 I , , --------~---------4-----~---~---------~--------~---------+---------~--------- I I , I 1 1 , 1 1 , 1 , 'j' , , I , j , , 1 , - - - - - - - - _1- - - - - - - - - J - - - - - L - - - L - - - - - - - - -'- - - - - - - - - J - - - - - - - - - 1 - - - - - - - - -'- - - - - - - - - - 1 ill I I 1 , 1 I , I , I , 1 I , I I I I , , , I , , - - - - - - - - -1- - - - - - - - , - - - - - r - - - r - - - - - - - - -,- - - - - - - - -., - - - - - - - - - T - -'- - - - - - -r - - - - - - -- : I I I 1 ¡ 1 1 I 1 1 1 f I t + I . 1 I I , - - - - - - - - -: - - \- - - - - - - ~ - - - - - ~ - - - ~ - - - - - - - - -:- - - - - - - - - ~ - - - - - - - - - ; - - - - - - - - - ~ - - - - - - - - - ,+ , x I I I I I , , 1 . , , 1 , I I I I I 1 - - - - - - - - -,- - - - - - - - - 1 - - - - - - - - - r - - - - - - - - -,- - - - - - - - - ï - - - - - - - - - T - - - - - - - - -1- - - - - - - - - - I I I 1 I I 1 I f I I I I , 1 I I , I I 1 I I I , + Design Load Line x Pipe ~ating 3000 9000 10500 12000 3000 6000 7500 9000 10500 Burst Rating (psig) 4500 12000 13500 15000 Northstar Producer Casing Design StressCheck 1998.7 ( Build 6) File: Northstar Bigbore ~!oduc~Ç_~sin9...Design.sc~___._._._.-------_._--_._---------.--- COLLAPSE DESIGN (9 5/8" Production Casing) 1500 3000 ..-... .::= ---- -£ 4500 0... <D 0 <tS u t <D > <D ::J ...... 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I- 4500 6000 7500 9000 12000 +-- 400000 0 1--------,-- 600000 800000 ----.-.--.--.,-.--..-..-----.--,--,.----., ------------.---- _.___n_._'.....,., ,...-....-.,---------.- Northstar Producer Casing Design StressCheck 1998.7 ( Build 6 ) (' ( File: Northstar Bi bore Producer Casin Desi n.sck TRIAXIAL LOAD LINE (9 5/8" Production Casing) Date: Au ust 01, 2001 Pa e: 23 1500 3000 ...- .1= ......... -5 4500 c.. CD 0 ~ 6000 t <1> > CD 7500 ::J '- J- 9000 10500 12000 40.0 0 " 1 I : I 1 1 1 I "; I 1 1 1 I \ I I 1 1 1 X I 1 1 - - - - - - - _1- - - - - - - - .J - - - - - - . - L. - - - - - - - _1- - - - - - - - ..J - - - - - 1 1 i......,..~" I 1 I 1 ,\ 1 1 1 0 1 1 1 I \ 1 I 1 1 - - - - - - - -:- - - - - - - - ~ - - - - r- X :~ - - - - - - -:- - - - - - - - ~ - - - - - - - J- 0 ~ -:- - - - - - ~ - - - - - - - - - - I 1 IF" I Il/""l 1 I I, 1 1 I 0 1 I -.... - - - - -:- - - -.. -.. -,V - - - - - - ~ - - - - -.. - -:- - - - -...... "/: -- -- -- + - - --- - + -- -- --- - - --- - - -- 1 : I 1 1 1 1 1 1 / I 1 1 1 I - - - - - - - _1- - - - - - ./ - ..! - - - - - - - - !.. - - - - - - - _1- - - - - - - 01 - - - - - - - - .!. - - - - - - - _1- - - - - - - - - - - - - - - - - 1 : I 1 I I 1 I 1 ,/ I 1 1 I 1 I 1 / I 1 1 1 I 1 1 : I 1 1 1 I I 1 '., 1 1 1 I 1 I - - - - - - - -1- - - -/- - - - , - - - - - - - - r - - - - - - - -1- - - - - - - ., - - - - - - - - T - - - - - - - - r- - - - - - - - - - - - - - - - - I í I 1 1 I 1 I 1,1 1 1 1 1 1 I I / 1 1 1 1 1 I I /,' I 1 1 I 1 I -----~~~:~1---~--------~---~oõ~--~--------7--------~---------------- x I 1 I 0 1 1 I 1 + I 1 I 1 I I 1 I I I 1 1 I I 1 I I I 1 I I I I - - - - - - - -1- - - - - - - - , - - - - - - - - r - - - - - - - -1- - - - - - - - ï - - - - - - - - T - - - - - - - -1- - - - - - - - -1- - - - - - - - I 1 1 1 I 1 I , 1 I I I I I I 1 I 1 I , 1 I I I I 1 1 1 1 + Pipe Yield Strength , Apparent Load Profile (w/Bending) 0 Desi n Load Line 45.0 50.0 60.0 65.0 VME Stress (ksi) 85.0 70.0 75.0 80.0 55.0 TRIAXIAL SAFETY FACTORS (95/811 Production Casing) 1500 3000 ...- .1= ......... -5 4500 c.. CD 0 ~ 6000 t CD > CD 7500 ::J '- J- 9000 10500 12000 0.00 0 V',..,-,\..I I ¡:,. +1... I , 1 I + Burst I ..,J 11 0 I I I I - - - --- - -- ~ -- ~ - - . V--- - --- ~ - - - - - - - - - ~ - - - - -- - -- i - --- - - - - - ~ - --- ~ ~i~~pse I ' I I I I ,--,--,...., ['::.1 Triaxial -- - - . m - jm - 'Î\ -- r 1-- -- -- -- ~ -- - ;-=~ x :-o-i~~:c:::::~::-~-=-::-=-:'-'-~~~ - -- "F a!IU re Criteria ........ .!... ~. L ,In.... o__lx!..... .1........ .1.... --... ~... --....~.......-- . 1 + I Î ro" I I 1 1 I , : i Iii I 1 1 I , ! : I X I I 1 1 I , . ¡, . I I I , I ---______L__~__~--~----j---_J_--______l______--_.!._--------L__--_____L______--- -- .. .. u -- L .. ". m'!' J - - O~[ - - - - j - - - - - - - - - ; - - - - - - - - -1- - - - - - - - -l- - - - - - - - -l- - - - - - - - - I: I' 1 I I 1 I 1. 1 I I , 1 I I. I; 1 I I , I I : .;", 1 ",....."io-' I I I I - - - - - - - - -:- - - ~ - - -'t [",:-: - - ~. ,- - - õ : - - - ; - - - - - : - - - - - - - - - : - - - - - - - - - : - - - - - - - - - : - - - - - - - - - I 1 , 1 1 I I I I , I I 1 I I I , 1 I I I - - - - - - - - - 1- - - - - - - - - -1- - - - - - - - - ï - - - - - - - - - , - - - - - - - - - T - - - - - - - - - r - - - - - - - - - ,- - - - - - - - - - I I I I I I I I I I I I I I I I , I I 1 1 I 1 I I I 0.75 1.50 2.25 3.00 3.75 Normalized Safety Factor 6.00 4.50 5.25 Northstar Producer Casing Design StressCheck 1998.7 ( Build 6 ) File: Northstar Bigbore Producer Casing Design.sck MINIMUM SAFETY FACTORS í9 5/8" Production CasinÇll Depth (TVD) (ft) ODlWeight/Grade Connection Burst Date: August 01, 2001 Page: 24, I I , I ---,----_..- Triaxial --.- + 100.00 2.18 1.40 21.50 2.24 1.42 18.19 2.25 15.71 ' 2.28 1.41 14.33 2.27 5.20 2.18 1.40 2.06 1.37 3.03 1.94 1.35 2.21 1.43 2.82 1.44 2.22 1.45 2.49 2.41 1.47 2.40 2.24 1.97 1.51 1.88 2.37 1.56 1.79 2.55 1.63 2.60 ' 1.65 1.78 2.74 1.67 2.31 , 1.58 2.38 ' 2.39 1.60 1.54 2.48 . 1.61 1.76 2.98 1.69 3.04 1.71 1.76 1.55 3.48 , 1.77 3.54 1 o~ 306 423 ----,--.._---_._._---~--_. ,--------,--_..__. 95/8",47.00 Ibm/ft, L-80 BTC, L-80 1.63 500: 1.62 791 1346: 1749: 1.61 1.59 3007 1.55 3225 3420 I 4229 4258' I 4624; 46771 8549 I 8760, ! 8830, 1.57 1.58 1_57 9022; 9027 9250, 9263 9349: 9353 9418 .--..--- ,-------.-----,--..-.,-----.---..-----------,.-------.---------.---------..----.-----....-,,--..--.--------...----.---------- m....._...-..-- -- ,.,.,." -..--..--,---,..--....-...-,----..-,.-..----- . .. ---..---.........-.-...--.-.... ------..--,,_.. --.. MAXIMUM ALLOWABLE WEAR í9 5/8" Production Casin~l ._-- 1 DePt~ftrD) l______........._-----~D~-~i~'~~~r~~~- -.-,.,..- -.......-.--.--.--------() 95/8",47.00 Ibm/ft, L-80 423 500 1749 I 3007 Max. Wear (% of Wall Thick.) ¡ Max. Wear (in) - ----,_._!3..~rst --.-____._L___.- ColI~ps~_--,-,.----_c=...I:3~,~!._------ ._J==---~~~~~-_._---_. 32.6' No Collapse Load No Collapse Load ; 0.154 32.5 66.2 0.312 I 32.0¡ 64.3 0.151 0.303 30.6 46.1 0.144 0.218 29.2: 35.7 0.138 0.168 29.d 0.137 ; 34.2 29.9, 0.141 i 30.1! 24.9 0.142 21.8 21.6 30.3; I 30.11 28.6' I 28.71 28.8 ..,-, ,---_._-... -_.._-_?§J:~1._.._..__..__._.._,...__..._.?_1:L 0.143 0.161 0.117 0.103 10 11 12 13 14 15 3225 4624 8549 8760 8830 9250 9263 9349 9418 21.3 0.142 0_135 0.102 21.2 0.136 0.137 0.100 ----..--.--..-.-..--......".----.,. --'-'-'-'------""'----"'--------" ....--.. -..---------.....----. ..-...-...--.-..------.---... Northstar Producer Casing Design StressCheck 1998.7 ( Build 6 ) ( File: Northstar Bigbore Producer Casing Design.sck MMLMUM ALLOWABLE OVEBPULL {9 5/811 production Casin~d. Running Depth (TVD) (ft) 1 (' 0 255 500 509 764 999 1017 1271 1526 1749 1780 1992 2028. 2263 2476 ~663 2789 2822 2954 3007 3075 3194 3278 3314 3433 3552 3671 3746 3790 3909 4028 4147 4213 4265 4384 4502 4620 4678 4739 4857 4975 5093 5141 5210 5328 5446 5563 5603 5681 5798 5915 6032 6063 6149 6266 6383 6500 6522 6616 6733 6849 6972 -'------" ----' -,-,,-- -" ----.....--.-.. .. .. ._- ---_u.--- ~----, ...---,----- Northstar Producer Casing Design Date: August 01, 2001 Page: 25 Max. Overpull (Ibf) 754205 743994 734160 734159 733783 723580 714165 713418 703248 693042 684104 682852 674332 672892 663497 654944 647431 642374 641068 635775 633668 633667 630938 626148 622772 621361 616578 611800 607025 604012 602254 597488 592725 587966 585314 583212 578461 573714 568972 566678 564233 559498 554768 550041 548103 545318 540600 535885 531174 529590 526468 521765 517066 512371 511138 507681 502994 498311 493632 492748 488958 484287 479620 474681 '----'~ StressCheck 1998.7 ( Build 6 ) File: Northstar Bigbore Producer Casing Design.sck MAXIMUM ALLOWABLE OVER PULL {9 5/8" Production CasinQl ""--""----"'" .--.---..-.--...-"'-, l. ".. , .'.-_.._-,,- .._--..-.-,,- . , Northstar Producer Casing Design Running Depth (TVD) (ft) Date: August 01, 2001 Page: 26 .-- ... -""-------------~--'-UO' -,~.----,---.. Max. Overpull (Ibf) 9263 9349 9418 400197 382836 382835 379399 379398 376621 .""-.- ,...- ,,- ",--- ,--c. """'....--""--...-,,..,- ,... StressCheck 1998.7 ( Build 6 ) ( f t, File: Northstar Bigbore Producer Casing Design.sck Date: August 01, 2001 Page:27 IBIAXIAL RESULTS (9 5/811 Production Casinql.:..Qjsplacement to Gas Depth (TVD) Axial Force (Ibf) Bending em~ratu1 Addt'l Pickup To Buckled (ft) Apparent Actual Stress Triaxial Prevent Buck. (Ibf) Length (ft) (wlBenárng) (w/o Bending) at 00 (ksi) (deg F) - 0 287552 266194 2.09 1.67 3.78 56.6 N/A NIA 423 280250 258892 1.6 2.17 1.73 3.87 61.2 500 278923 257565 2.18 1.74 3.89 62.1 286042 257564 2.1 3.80 1749 286020 228753 4.2 2.40 ' 1.95 3.79 75.7 314194 228752 6.3 2.37 3.45 3OOt 254701 169260 2.70 2.20 . 4.24 89.5 190618 169259 2.75 5.66 3225 187400 166042 2.82 2.25 5.75 91.9 184886: 163527 2.87 I 2.29 5.83 4624 152462: 131103 1.6 3.51 : 2.82 N/A 7.04 107.2 8549, 32366 11008 9.56 8.10 32.72 150.2 8760 30862 9504 10.31 9.02 34.29 152.5 883d 47456. 26097 9.65 9.19 22.29 153.3 116074 26098 6.93 9.11 9250, 130234 40258 6.6 6.39 10.35 : 8.11 157.9 9263 130683 40706 6.37 10.46 8.08 158.0 62066, 40707 9.21 i 17.02 . 9349~ 64965 43607 1.6 9.14 ~ 11.24' 16.26 . 159.0 107767. 86408 7.01 ¡ 9.80 9418: 109330 87972 6.93 . 11.96 9.66 159.7 I TRIAXIAL RESULTS 9 5/811 Production Casin - Pressure Test Depth (TVD) Axial Force Ibf) Bending emperatu Addt'l Pickup To Buckled (ft) Apparent Actual Stress Triaxial e Prevent Buck. (Ibf) Length (ft) (wlBending) (w/o Bending) at 00 (ksi) (deg F) 1 0 391398 370040 1.96 2.77 12.0 N/A N/A 423 376282 354923 1.6 2.28 2.89 21.6 500 373534 352176 1.94 2.91 23.3 380653 352175 2.1 2.27 . 2.85 1749' 364833 307566 4.2 2.25 . 1.89 2.98 49.1 393007 307565 6.3 2.21 ' 2.76 3007 348058 262617 2.22 1.84 3.12 64.2 283975 262616 2.28 3.82 , 3225 276190 254831 2.27 1.83 3.93 69.4 273675 252316 2.31 1.86 3.97 4624 219394 198035 1.6 2.30 1.84 N/A 4.90 99.7 8549 67127 45768 2.15 1.79 15.66 174.4 8760, 60188 38830 2.14 1.78 17.43 . 179.8 8830 58509 2.12 17.89 187.4 127127 37150 2.03 I 1.77 8.23 9250 117085 27108 6.6 1.96 : 8.90 : 202.8 9263 116582 26605 8.93 . 203.3 47963 26604 2.05 1.72 21.72 9349' 44711 23352 1.6 23.27 206.9 87511 66153 11.89 9418: 62745 2.10 . 1.73 12.36 ! 84104 209.8 Northstar Producer Casing Design StressCheck 1998.7 ( Build 6 ) File: Northstar Bigbore Producer Casing Design.sck TRIAXIAL RESULTS í9 5/8" Production Casinq) - Tubinq leak Depth (TVD) Axial Force (Ibf) Bending (ft) Apparent Actual Stress 1 (wlBending~ (w/o Bending) -- at 00 (ksi)- . 0 -298288 -276930 423 -286580 -265221 -284452 -291571 -293072 -321247 -324213 -260130 -253558 -256071 -225623 -169351 -161378 -141630 -210247 -177226 -176180 -107561 -100810 -58007 -53331 500 1749 3007 3225 4624 8549 8760 8830 9250 9263 9349 9418 -263093 -235805 -23877i -238771 -232199 -234713 -204264 -147992 -140019 -120271 -120270 -87249, -86204 -86202 -7945l -36649 -31973 .------.----. .-. ..--.-. - .-----.------------ Absolute Safety Factor collapseJ- Axial 3.44 3.58 3.61 3.52 3.50 3.20 3.17 3.95 4.05 4.01 4.55 6.06 6.36 7.25 4.88 5.79 5.83 9.55 10.19 17.70 19.25 --- --.--..-- _.... .... .-. .'.. -- --..--.--...--. -. -...- ------.-...---.- -- .__J 1.6 1.40 1.63 1.42 1.62 1.41 1.40 1.59 1.37 1.35 1.43 i 1.55 1.44 1.45 . 1.57 1.51 : N/A 1.63 1.58 1.65 I 1.67 I 1.58 I 1.57 1.60 1.61 I 1.54 1.69 : , 1.71 ! I 1.55 1.76 ! 1.77 ¡ .._-~-_._-_.__.._-_. 2.1 4.2 6.3 1.6 6.6 1.6 _._-~_.._-- - -----.----------------'.- Date: August 01,2001 Page: 28 emperatuj .. A. ddt'.1 PiCkUP.. To . I . Buckled e Prevent Buck. (Ibf) 1 Length (ft) (deg F)._--_.. .------ -------.'N'/A - N/A 248.4 TRIAXIAL RESULTS í9 5/811 Production Casinq}- Green Cement Pressure Test ._-_._.~-_._--- --......-..-..-......... .....-- ---..--- ----------...-....--... Depth (TVD) Axial Force (Ibf) Bending emp.ra,"] Addt" Pkkup To l Budded (ft) Apparent Actual Stress Triaxial Jde~~. ---~.~~.~~_~BUCk. ~~~~_._._~:9th~~_J (wlBending) (w/o Bending) at 00 (ksi) ...-..-----..-.-..----....- -. . 0 444667 423308 2.35 : 2.29 56.2 N/A N/A 423 424782 403423 1.6 2.43 i 2.35 60.2 500 421167 399809 2.44 i 2.36 60.9 428286 399808 2.1 2.42 i 398393 341126 4.2 2.58 i 2.56 1749 72.9 426567 341125 6.3 2.49 ~ 367439 281997 2.75 2.78 3007 281996 3.00 . 85.0 303355 3225 293114 271756 3.06 2.83 3.68 87.0 271755 4624 227347 205988 1.6 3.51 3.15 4.73 100.5 8549 42860 21502 5.73 4.65 N/A 24.80 138.1 8760 32947 11588 6.01 4.87 32.24 140.1 8830 29647 8288 6.12 : 4.95 35.82 140.8 98265 5.46 10.81 9006 89985 8 5.68 5.16 11.80 142.4 9007 -89996 -20 6.6 5.67 ' 11.79 142.5 9250 -101419 -11442 5.86 5.48 10.46 144.8 -102042 5.87 5.50 10.39 9263 -12066 ' 144.9 -33425 6.85 i 31.73 -37454 -16095 1.6 6.99 5.62 28.31 9349 50.56 . 9.82 145.7 -108014 -86655 + 100.00 9418 -111270 -89911 45.20 9.53 146.4 -.--..-..---.-... -....--.-..-.---........- -.. -- ---'----.'.---'-'-.--.--.-----------.---'.----- Northstar Producer Casing Design .-..-..-.-.-.. -....--......-..--- --...--...-. - .----..-.--.--........- StressCheck 1998.7 ( Build 6 ) ( ( File: Northstar Bigbore Producer Casing Design.sck Date: August 01, 2001 Page:29 ~ESUL TS (95/8" production CasinQ) - Cementinq Depth (TVD) Axial Force (Ibf) Bending Absolute Safe Factor emperatu Addt'l Pickup To Apparent Actual Stress i Collapse e Buckled (ft) (wlBending) (w/o Bending) at 00 (ksi) Triaxial Burst Axial (deg F) Prevent Buck. (Ibf) length (ft) .J 1 0 267105 245746 4.07 + 100.00 4.07 56.2 N/A NJA 423 247219 225861 1.6 4.24 45.54 4.39 60.2 500 243605 222247 4.28 38.59 4.46 60.9 250724 222246 2.1 4.16 4.33 1749 220831 163564 4.2 4.20 11.24 4.91 72.9 249005 163563 6.3 3.79 4.35 3OOi 189876 104435 4.21 6.64 5.69 85.0, ! 125793' 104434' 5.49' 8.59 3225 115552' 94194, 5.59 6.20 9.34 87.0 94193 4624 49785' 28426 6.10 4.39 21.60 100.5 5228 21373 14 1.6 6.21 N/A 3.90 50.22 106.2 I 5229 -21369 -10 7.40 50.23 106.3 8549. -177419, -156060 5.42 2.38 5.99 138.1: 8760' -187333' -165974 5.19 2.29 5.67 140.11 -1906321 : 5.12 5.57 I I 8830; -2592511 -169274 4.72 2.26 4.10 140.8 ! 9250; , -189004' 144.8' -2789811 6.6 4.36 3.80 , I -189628' I -279605: 4.35 2.10 3.79 9263' -2109871 -189629, 4.71 5.03 144.9, 9349' -215016 -193657 4.63 2.07 4.93 ¡ -108014: -86655' 1.6 50.56 7.30 9.82 145.7, I 1 9418 -111270 -89911 45.20 7.24 9.53 146.4. I I ~ESUL TS (9 5/811 Production CasinQ) - Lost Beturns w¡th Mud Q!QQ. Depth (TVD) Axial Force (Ibf Bending emperatu Addt' Pickup To Buckled (ft) Apparent Actual Stress Triaxial e Prevent Buck. (Ibf) length (ft) (wlBending) (w/o Bending) at 00 (ksi) (deg F) 1 0 141848; 120489 7.65 + 100.00 7.65 56.6, N/A N/A 423 131633: 110275 1.6 7.29 21.50 8.25 61.2' 500 131096: 109738 7.28 20.95 8.28 62.1. 1382161 109737 2.1 6.95 7.86 1749 151019: 93752 4.2 6.03 14.86 7.17 75.7. 179193 93751 6.3 5.22 6.05 3007 132623, 47182 6.25 11.58 8.13 89.5 68540 9.81 15.74 3225 67561 46202 9.72 11.14 15.96 91.9 10 4624 53797 9.69 8.97 19.94 107.2 11 21359, 32439 ' 6503 1.6 9.63 9.00 49.92 127.8 12 -21359 ' N/A 13 8549 -56671 -35312 12.19 5.79 18.69 150.2 14 8760 -55362 -34003 11.79 5.68 19.11 152.5 15 8830 -38462 -17104 10.14 5.64 27.51 153.3 16 -107080 -17103 6.39 9.88 17 9250. -91090 -1113 6.6 5.72 5.44 11.60 157.9 ' 18 9263 -90397 -420 5.69 11.69 158.0, 19 -21778 48.51 5.43 I 0 9271 -21359 -419 8.61 49.46 158.1 1 21359 25414 4055 1.6 8.28 5.39 41.55 9349, 68216 46857 6.32 5.33 15.48 159.0 9418 71053 49694 6.20 5.30 14.86 159.7, --.- - "'--'--'--.---.--.-.----- ........--_u-o. ---.---. Northstar Producer Casing Design StressCheck 1998.7 ( Build 6) File: Northstar Bigbore Producer Casing Design.sck TRIAXIAL RESULTS {9 5/8" Production Casinç,}- AbovelBelow Packer Date: August 01, 2001 Page: 30 Bending Stress at 00 (ksi) Triaxial emperatu Collaps~l- Axial I (d~ F) "-:;-100.00 2.34 21.50 Axial Force (Ibt) Depth (TVD) (ft) Apparent Actual ""~+-,,~-~---~--.. (~/Bending) (w/o Bending) 0 -439660: -418302 423 -436855: -415497 -436345, -443465 -471240' , -499415~ -5288561 -464773, -462786,1 -462785, -4574971 1 -402289, -394372: -375273' -4438911 , -414751: ¡ -413642~ , -3450221 -3378631 -295060, -290054¡ I .---...'....--..-..."'- ......._..._-_..._..-L.__.._.._....__.~ ,.-....,-----.---- .-1--.--.., 2.34 2.43 2.45 2.41 2.46 2.31 2.27 , 2:56 ' 2.57 1.6 500 -414987 2.1 4.2 6.3, 1749 -413973 3007, -4434 14 3225 4624 8549 8760 -441427 -436139' -380930 -373014 -353915 -353914: -324774 -323665' -323664 -316504: -273701 -2686951 1.6 2.50 2.84 2.88 2.96 2.69 2.83 2.84 3.09 . 3.12 3.26 3.28 8830 9250 6.6 9263 1.6 9349 9418 2.35 18.19 2.32 5.20 2.18 , 2.06 ' 3.03 1.94 ! 2.21 ~ 2.82 2.22 . N/A 1.97 2.24 ' 248.4 1.79 2.55 , 2.60 . 1.78 2.74 , 2.31 i 2.48 I ! Addt' Pickup To Prevent Buck. (Ibt) Buckled Length (ft) N/A N/A 2.98 i 3.04 , 3.48 ; 3.54 . .._-~-_---L_._._--_._-- -- ,---.---- 1.76 emperatUi e (deg F) ....-........-_.___.L...._..-...---....,,--.. 2.30 : 56.2 2.37 ' 60.2 + 100.00 2.38 60.9 I 48.07 2.55 72.9 2.39 28.46 2.62 85.0 27.56 25.81 2.68 . 87.0 18.44 3.09 100.5 10.54 5.62 138.1 10.32 5.94 140.1 10.25 6.07 140.8 10.45 10.03 6.87 144.8 10.01 6.90 144.9 9.82 9.74 7.08 145.7 9.68 7.23 , 146.4 TFïïAXïAI=-RESUL TS .(9 5/8"' Pr~ducti~-~-C~~in~)--=-~~~'Çï"'-i~HoI;-"---._--------_.----..----------------1 I Addt'l Pickup To Prevent Buck. (Ibt) Buckled Length (ft) N/A Depth (TVD) Axial Force (Ibf) Bending (ft) Apparent Actual ~~?~J~~~,L I.._~~~~~I ,---_,..-_n ...,.--","..-----.. . (w/Bending) (w/o Bending) 0 472233: 450875 2.30 423 457898, 436539 1.6 2.36 455500' 434141 2.37 ~ 500 455852] 2.1 2.36 425959; 399902 4.2 2.48 1749 454133; 399901 2.33 6..3 3007 411956; 361268 2.50 18 ~_.- 403350: 352632 ~g_...." 3225 403349 352631 2,54 ~::: 4624 347824 296913 1.6 2.83 + 100,00 8549 189104, 119513 4.28 ~~ 8760 178708 107006 4.44 8830 1750091 102835: 4,50 175008, 102834 ' 9250 154383' 81083 6.6 4.86 [!~-_.... 9263 153776' 80467 4.87 ~t-= 1537751 80466 9349 149845~ 76498 4.94 0 149844; 1.6 .----..- 146681 1 73321 5.01 --.-.. 9418 ' 732911 2 146650, ---..... 3 .....""--"'" .w......"..,..-.... .........._........._..__.__...__....~-_._--_.__._-_...-_.._..-,.........,-...--.-"..-.--..-'" _c- m...._' c....... ...'..c-.....c..'..c........_- N/A -"--"",,,.,,- ............-_c.-....---------.......--.-..-....L---..-.--..----...--....--...........-..........-. .--....-.---'---....-.-.-..-.---.. .... Northstar Producer Casing Design StressCheck 1998.7 ( Build 6 ) ( File: Northstar Bigbore Producer Casing Design.sck !BIAXIAL ~ESUL TS ~811 Production CasinQ) - Overpull Force Axial Force (Ibf) Depth (lVD) Apparent Actual (ft) (wlBending) (w/o Bending) 0 498942 477584 423 484607 463249 482209 460851 482562 460850 452669 426611 480842, 426610 1 500 1749 3007 3225 4624 8549 8760 438665 430059 3745331 215814 205417 201718 , 201717' 181092: 180485: 180484: 176554: 176553: 173390: 173360 I i 387977, 379341 323622 146222 133715 129544 129543 107792 107177 107176' 103208: 103207 100031 1 00000; Bending Stress at 00 (ksi) (' Date: August 01, 2001 Page: 31 , I Triaxial Buckled length (ft) N/A 1.6 2.18 ' 2.23 2.24 2.23 2.33 2.20 2.35 47.40 28.10 27.15 25.43 18.21 10.45 10.23 10.16 10.38 9.96 9.94 9.74 2.18 2.24 2.25 2.40 2.25 2.46 ' I 2.51 2.87 4.93 5.17 5.26 5.86 5.88 9.66 6.01 : 6.11 6.12 8830 9250 9263 9349: 9418 + 100.00 2.1 4.2 6.3 1.6 2.39 2.65 3.87 3.99 4.04 . + 100.00 9.60 !BIAXIAL RESUL T...§J9 5/811 Production Casina) - Pre-Cement Static Load 1 500 1749 3007 3225 4624 8033 8034 8549 8760 8830 9250 9263 9349 9418 226031' 160264 15, -9 -24223 -34136 -37436 -37437 -57166 -57790 -57791 Northstar Producer Casing Design -61820' -65076 Bending Stress at 00 (ksi) 6.6 4.33 , 4.34 : 1.6 4.40 ! I 4.45 1.6 Triaxial 2.72 : 2.84 ' 2.87 : 2.81 . 2.97 ; 2.76 3.15 . 3.88 29.54 Axial Force Ibf) Depth (lVD) (ft) Apparent Actual (wlBending) (w/o Bending) 0: 398942 377584 423 379057 357698: 375443 354084. 382562 354083, 352669 295402 380842 295401 321714 236273 257631 236272: 247390 247389 181622, 21374 -21367 -45581 -55495 -58795, -127413 -147143 -147767 -79149' -83178 -83179. -86435 + 100.00 2.1 4.2 6.3 49.73 1.6 4.00 5.03 13.85' + 100.00 31.18 78.80 11.74 11.03 10.76 27.64 19.66 + 100.00 6.6 14.12 11.52 : 11.46 61.53 51.29 10.67 10.18 10.17 1.6 10.07 10.00 45.20 2.72 2.86 2.89 2.84 3.07 2.85 3.36 . 4.19 4.36 5.92 49.80 , 49.82 . 23.32 19.14 18.06 8.34 7.21 7.18 13.40 12.75 . 12.27 emperatur Addt'l Pickup To i e : I (deg F) ; Prevent Buck. (Ibf) 56.2 N/A 60.2 60.9 72.9 85.0 87.0 100.5 138.1 140.1 140.8 144.8 144.9 145.7 146.4 emperatu~ e (deg F) 56.2 60.2 60.9 Addt'l Pickup To Prevent Buck. (Ibf) N/A Buckled Length (ft) N/A 72.9 85.0 87.0 100.5 133.1 138.1 140.1 140.8 144.8 144.9 145.7 146.4 ---- ,.-....----,-,- StressCheck 1998.7 ( Build 6 ) File: Northstar Bigbore Producer Casing Design.sck TRIAXIAL RESULTS í9 5/8" Production CasinÇl} - Post-Cement Static Load Axial Force (Ibf) Depth (NO) (ft) Apparent Actual (wlBending) (w/o Bending) ----t-"'~-----, -----.------ .-- -------. 0 267105 245746 423 247219 225861 243605 222247, 250724 222246, 220831 163564 249005 163563: 189876 104435 125793 104434: 94194: 94193 28426: 14 -10 -156060: -1659741 -1692741 ! 1749 3007 3225 4624 5228 5229 8549 8760 8830 9250 9263 9349 9418 500 115552 49785 21373 -21369 -177419 -187333 -190632 -259251 -278981 -279605 -210987 -215016 -108014 -111270 -_._--,- ----,--.-------.---------- ----- -189004: -1896281 I -189629; -1936571 -86655, , -89911 Bending Stress at 00 (ksi) --_._-_.~_.__._-, Triaxial 1.6 + 100.00 + 100.00 45.54 38.59 2.1 4.2 4.07 4.24 4.28 4.16 4.21 3.80 4.23 5.52 + 100.00 N/A 11.25 6.66 6.22 4.39 3.90 2.36 2.27 2.24 2.08 2.05 7.24 7.17 4.07 4.39 4.46 4.33 4.92 4.36 5.72 8.63 9.39 21.60 50.15 50.16 5.92 5.60 5.49 4.04 3.73 ' 4.94 4.84 9.63 . 9.34 Date: August 01, 2001 Page: 32 emperatu (d~ F) I .---.- 12.0 21.6 23.3 Addt' Pickup To Prevent Buck. (Ibf) N/A Buckled Length (ft) .----------- N/A 49-1 64.2 69.4 99.7 110.9 174.4 179.8 187.4 202.8 , 203.3 206.9 209.8 .-----.--.-----------,,------ 2.29 2.35 2.36 2.56 2.78 2.83 3.15 4.65 4.87 4.95 5.16 5.48 5.50 5.62 + 100.00 2.44 : 2.56 2.58 2.54 2.72 , 2.54 2.94 3.56 3.68 N/A 4.73 24.80 : 32.24 ¡ 35.82 10.81 11.80 11. 79 10.46 10.39 31.73 28.31 9.82 9.53 6.3 1.6 5.62 6.10 6.20 7.39 5.36 5.13 . 5.05 4.66 4.29 4.28 4.62 4.55 49.60 44.32 TRIAXIAL RESULTS (9 5/8" Production CasinÇl} - Green Cement Pressure Test Axial Force (Ibf) Depth (TVO) (ft) Apparent Actual --,,-~'-------~-- (~lBending) (w/o Bending) 1 0 444667 423308: - 423 424782 403423' "---'- I 421167 399809, ----. 500 428286 399808' 398393 341126 426567 341125 367439 281997 303355 281996 271756 271755 205988 21502 11588 10 11 12 13 14 15 16 17 18 19 0 1 2 3 4 3007 3225 4624 8549 8760 8830 9006 9007 9250 9263 9349 9418 1749 293114 227347 42860 32947 29647 98265 89985 -89996 -101419 -102042 -33425 -37454 -108014 -111270 8288 8 -20 -11442 -12066 -16095 -86655 -89911' Bending Stress at 00 (ksi) 6.6 1.6 Triaxial Buckled Length (ft) N/A 1.6 2.35 2.43 2.44 2.42 2.58 2.49 2.75 3.00 3.06 2.1 4.2 6.3 1.6 3.51 5.73 6.01 6.12 5.46 5.68 5.67 5.86 5.87 6.85 6.99 50.56 45.20 6.6 1.6 "...n_----- .."..-. ".-- ..... -"". -- --.- -" Northstar Producer Casing Design ...-- -- .-..,,------ 60-9 72.9 85.0 87.0 100.5 138.1 140.1 140.8 142.4 142.5 144.8 144.9 145.7, 146.4 n__._."".---. ---...-.--.....--" --..-.""...-...-.- StressCheck 1998.7 ( Build 6 ) , . (' ( File: Northstar Bigbore Producer Casing Design.sck ~N PAI3AMETERS pAT A (711 Production Linerl Date: August 01, 2001 Page: 33 Design Factor (Pipe) - Axial: Design Factor (Coupling) - Axial: Design Factor (Pipe) - Burst: Design Factor (Coupling) - Burst: Design Factor (Pipe) - Collapse: Design Factor (Pipe) - Triaxial: Minimum Internal Drift Diameter: Single External Pressure Profile: Temperature Deration: Limit to Frac at Shoe: Bucklin: 1.400 1 .400 1.100 1.100 1.000 1.250 6.000 in Yes Yes No Yes !NII!AL CONDITIONS (711 Production Linerl Mix-Water Density: 8.50 ppg Lead Slurry Density: 15.90 ppg Displacement Fluid Density: 11.30 ppg Float Collar Depth, MD: 13965 ft Slackoff Force: 0 Ibf T emperatu res: Default Vertical Depth (ft) Temperature (deg F) 12330 ft 204.4 deg F 12485 ft 210.0 deg F 13733 ft 240.0 deg F 13943 ft 245.0 deg F 14045 ft 246.3 deg F 14045 ft 246.3 deg F Northstar Producer Casing Design StressCheck 1998.7 ( Build 6 ) File: Northstar Bigbore Producer Casing Design.sck BURST LOADS DATA (7" Production Liner), Date: August 01, 2001 Page: 34 Drilling Load: Influx Depth, MD: Pore Pressure: Gas Gradient: Frac at Shoe: Gas/Mud Interface, MD: Mud Weight: Assigned External Pressure: Displacement to Gas 14586 ft 5227 psig 0.1000 psi/It 8563 psig . Oft 9.30 ppg Fluid Gradients (w/ Pore Pressure) Drilling Load: Test Pressure: Mud Weight: Assigned External Pressure: Pressure Test 3500 psig 11.30 ppg Fluid Gradients (w/ Pore Pressure) Production Load: Packer Fluid Density: Packer Depth, MD: Perforation Depth, MD: Gas/Oil Gradient: Reservoir Pressure: Assigned External Pressure: Tubing Leak 9.60 ppg 14100ft 14200 ft 0.1000 psi/It 5071 psig Fluid Gradients (w/ Pore Pressure) Drilling Load: Test Pressure: Mud Weight at Shoe: TOC, MD: Lead Slurry Density: Displacement Fluid Density: Float Collar Depth, MD: Green Cement Pressure Test 3000 psig 11.30 ppg 12330 ft 15.90 ppg 11.30 ppg 13965 ft External Pressure: TOC, MD: Prior Shoe, MD: Mud Weight Above TOC: Fluid Gradient Below TOC: p.9!-~Ere§.§ u r~J.Q_QI?_~-QJJQ~~...- Fluid Gradients (wI Pore Pressure) 12330 ft 12480 ft 11 .30 ppg 8.33 ppg Yes ........... .....---..,...-.............-.--....-.-..----,---.---.-.. .......-..,.....,.-..,.-...-..------....--....-----.------..-..--.------'--..-.-...-' Northstar Producer Casing Design StressCheck 1998.7 ( Build 6 ) I . (' ( File: Northstar Bigbore Producer Casing Design.sck £Q,bbAPSE LOADS DA"'(A1Lproduction Liner\ Date: August 01, 2001 Page: 35 Drilling Load: Mud Weight at Shoe: TOC, MD: Lead Slurry Density: Displacement Fluid Density: Float Collar Depth, MD: Assigned External Pressure: Cementing: I 11 .30 ppg : 12330 ft ¡ I 15.90 ppg I 11 .30 ppg ¡ 13965 ft ! Fluid Gradients (wI Pore Pressure) Drilling Load: Lost Returns Depth, MD: Pore Pressure at Lost Returns Depth: Pore Pressure Gradient at Lost Returns Depth: Mud Weight: Mud Drop Level, MD: Assigned External Pressure: Production Load: Packer Depth, MD: Perforation Depth, MD: Pore Pressure at Perforation Depth: Density Above Packer: Density Below Packer: Fluid Drop Above Packer: Assigned External Pressure: Lost Returns with Mud Drop 14586 ft 5227 psig ! 8.95 ppg i 9.30 ppg t I 423 ft II Fluid Gradients (wI Pore Pressure) I Above/Below Packer I 14100 ft ¡ 14200 ft I 3007 psig I 9.60 ppg 0.00 ppg Yes Fluid Gradients (wI Pore Pressure) External Pressure: TOC, MD: Prior Shoe, MD: Fluid Gradient Above TOC: Fluid Gradient Below TOC: Pore Pressure In 0 en Hole Below TOC: I Fluid Gradients (wI Pore Pressure) 11 12330 ft I 12480 ft 11 .30 ppg I 11 .30 ppg . I No! M!Ab..LOADS DATA (711 Production Liner\ Running in Hole - Avg. Speed: Overpull Force: Pre-Cement Static Load: Pickup Force: Post-Cement Static Load: Green Cement Pressure Test: Service Loads: 2.0 ft/s 1 00000 Ibf Yes 0 Ibf Yes 3000 psig Yes Northstar Producer Casing Design StressCheck 1998.7 ( Build 6 ) File: Northstar Bigbore Producer Casing Design.sck BURST LOADS TABLE {7" Production Linerl Date: August 01 , 2001 Page: 36 Pressure Test (psig) Tubin. Leak l Green c.. eme. nt 1 G. reen Cement P. reS'jl.Uid Gradients wI Pore ( ~ ) Pres, Test (Int) Test (Ext) Press pslg (psig) (psig) (psig) ------------- -------------- .--. _._~ - 8613 8452 5452 Depth (TVD) I Displacement To Gas (ft) (psig) 9288 9418 9740 10700 10704 10774 -----------.----- 5032 5045 8952 9029 5452 5509 4486 4685 4975 8678' 8529 5560 5825, 6618' 5077 9218 9781 8838 9317 9319; 4977 5009 8718 9281 9284 6622 6679 5173 6622 6679: 9784 5180 9824 9354 ------ --------.-- ---- ._.:-. -- ------- ---- -- -=_:'L- ----- -----, --------------.-------.---.---,.---. -,.----..--.-..---------- _._----,-- ,_.,,-- COLLAPSE LOADS TABLE {7" Production Liner} 1 ...:e~~ftr~___c:~~~~ (Inl) l cem(;~~os~:~. J~bov4:~ pa~e' 92881 5452, 5452 4283 2199: 9418 5529, 5560 4346 2264 I 107M 6284 6622 4967 2905 : 6622' : -----------2 0 77 L_..__.._,-,----------~~~:"_-------_._---,_.- __~679__,___------------_."._,------ 500 ~,,-"---- ._---_._----___.3.~0' Fluid Gradients wI Pore Press (psig) 5452 5529 6284 6324 AXIAL LOADS TABLE (7" Production Linerl -------."--- --.-.-, ---------_.------,--- -.---------.------ Running in Hole (Ibf) Overpull Force (Ibf) IPre-Cement Static Load Post-Cement Static Loa Green Cement Pressur Service Loads (Ibf) Actual Actual Actual Actual Actual Actual ( I Apparent (I Apparent (I Apparent (I Apparent (I Apparent (I Be~dfng) ~~~:~~:=t~e~dr~~~L (~~en~~_~,,~ _.,,~~~dr~~l..~~~~_~~i::j_.~~_~~r~~L- ~:~-~:~~:~l.~~~l~~) (~~~nding _--E3~.;fng)_- 77726 158235 136961 -17766 -9126 -30913 -22273 79173 70533 -160009, -151369 , , 77676 158201 136911 -17837 -9197 -30983 -22343 79121 70482 -159994 -150390 74493 1 60 133728 -21144 -12 04 -34290 -25650 75796 67156i -154425, -145785 74492 5 18 133727 5 -34291 -25651 . -154424 -145784 91080 66484 150315 125719 -29508 -20868 -42655 -34015 67432 58792 -147475 -138835 i ' 69405 42599 128640 101834 -54468 -45828 -67615 -58975 42472 33832 -127425 -118785 , 69298 42491 101726 I -67727 -59087 42359 33719 -127419 -118779 128532 -54581 -45941 . 69297 42490 101725 -57261 -48621 -57261 -48621! -123232 -114592 1 .---------- _._~!~!~------ --~~.?.~§---, '" -_!?_~~.~:£______.J...OOO9O ._-----=~?~~-~-----~~~~?_-----=-~~?_-_.___-504~?__~~~~::~-~~-- -123439,-.::.!~ 48_~ Depth (TVD) I Apparent I (ft) (wlBending)j ",_.__.._------,---,-- !.._.J 9288 9311 9418 9740 10700 10704 10774 99000 98966 96783 Northstar Producer Casing Design StressCheck 1998.7 ( Build 6 ) ( ( Date: Au ust 01, 2001 Pa e: 37 File: Northstar Bi bore Producer Casing Design.sck BURST DESIGN (7" Production Liner) 9200 9400 9600 - ~ -5 9800 c.. Q) 0 ~ 10000 t Q) > Q) 1 0200 :::J '- I- 10400 10600 10800 3000 , I I I , 1 + Design Load Line + I I X I 1 I 1 - - - - - -1- - _:- - - - - - - _1- - - - - - -1- ~ - - - - - - - - _:- - - - - - - - _1- - - - - - - - - ~ - - -~ ~i~~ f~t~n?- - - - - - - - - - - - - -!- - - - ì - - - - ~ - - - - - - - ~ - ~ - - - - - - - - -[- - - - - - - - - ~ - - - - - - - - - ~ - - - - - - - - ~:- - - - - - - -- 1 1 I ! I 1 1 I 1 1 + I I 1 1 ,I , 1 1 1 , 1 1 , I - - - - - - - - -:- - - - - - - -: - - - - - - -1-: - - - - - - - - -:- - - - - - - - - : - - - - - - - - - : - - - - - - - - -:- - - - - - - - - - - - - - - - - _:- - - - - - - - i - - - - - - _1- ~ - - - - - - - - _:- - - - - - - - - i - - - - - - - - - ~ - - - - - - - - _:- - - - - - - -- I I I' I 1 1 1 I , I I I , 1 I , I I 1 1 , I I I I I I 1 1 1 1 I I I , I 1 1 -- -- --- - r --- - --1-- - - ---1- f - - - - - - - - T - - - - - - - -1- - - - - - - - - f - - - - - - - - T - - - - - - -- - - - - - - - - _1- - - - - - - -.1 - - - - - - - - L - - - - - - - - _1- - - - - - - - - .1 - - - - - - - - - L - - - - - - - - _1- - - - - - - -- I t I 1 1 1 I 1 I 1 1 1 1 I , I 1 1 1 1 1 I I I 1 1 , 1 I I 1 1 1 1 , - - - - - - - - -1- - - - - - - - 1 - - - - - - - - r - - - - - - - - -,- - - - - - - - - , - - - - - - - - - r - - - - - - - - -,- - - - - - - -- 1 I 1 , , 1 , I + I 1 1 1 1 I I I I 1 1 1 I I I +' x ' I I I I 4500 6000 7500 9000 10500 Burst Rating (psig) 15000 12000 13500 COLLAPSE DESIGN (T' Production Liner) 9200 9400 9600 - .:t= - -5 9800 c.. Q) 0 ~ 10000 t Q) > Q) 1 0200 :::J '- I- 10400 10600 10800 3000 I I 1 I 1 + Design Load Line + ' ,,' 1 1 , , I I I' , , 1 I x Pipe Rating I I 1 , 1 I I . - - - - - - - - -,- - - - - -1 - - - ..L - - - - - - - - - L - - - - - - - - -1- - - - - - - - - ..L - - - - - - - - - L. - - - - - - - - -,- - - - - - - - - , i I I 1 1 1 I , I I I 1 I 1 1 , ¡, I I , 1 1 j 1 I , I 1 1 1 ¡ 1 I , , 1 1 - - - - -1- - - - - ¡ - - - ï - - - - - - - - - ï - - - - - - - - -1- - - - - - - - - ï - - - - - - - - - ï - - - - - - - - -1- - - - - - - -- 1 i' I I 1 , I 1 I 1 1 1 1 I 1 1 ,I 1 1 I I , 1 ill 1 I 1 I - - - - - - - -1- - - - - -1- - - of - - - - - - - - - I- - - - - - - - - -1- - - - - - - - - ..¡ - - - - - - - - - I- - - - - - - - - -1- - - - - - - - - 1 ¡I' 1 , 1 1 ! 1 , 1 I 1 , 1 , , , I , 1 Iii I I 1 , , Ii' I 1 1 I 1 - - - - - - - -,- - - - -l- - -"'j - - - - - - - - -1- - - - - - - - -1- - - - - - - - - ï - - - - - - - - -I - - - - - - - - -,- - - - - - - -- 1 !, I 1 I . I t 1 1 I 1 I I I , 1 1 1 I I ,I 1 1 , , 1 - - - - - - - - -,- - - - - -1 - - -"T - - - - - - - - - r- - - - - - - - - -1- - - - - - - - - "T - - - - - - - - - r- - - - - - - - - -1- - - - - - - -- , ¡ I , I 1 I 1 I 'I I , 1 I , 1 ! 1 I 1 I , , 1 ! 1 , 1 1 - - - - - - - - -'- - - - - j - - -.1 - - - - - - - - - L - - - - - - - - _1- - - - - - - - - .1 - - - - - - - - - L - - - - - - - - _1- - - - - - - -- I ! 1 1 1 1 1 I 1 1 1 1 I 1 I ,I 1 I 1 1 1 I j 1 , I 1 I 1 Iii 1 1 1 1 I - - - -,- - - - - ¡ - - - 1 - - - - - - - - - r - - - - - - - - -,- - - - - - - - - , - - - - - - - - - r - - - - - - - - -1- - - - - - - - - I !, , , , I I I , I 1 , I 1 I , 1 , I 1 I Xliii I 1 + 4500 6000 15000 7500 9000 10500 Collapse Rating (psig) 12000 13500 Northstar Producer Casing Design StressCheck 1998.7 ( Build 6 ) File: Northstar Bigb9feproduç~~ Casing Design:sc!5..__-----------------------------------_____pate: Aug~~t 01_, 2001 Pag~: 38 AXIAL DESIGN (7" Production Liner) 1 , I 1 , 1 + I I / I I , t I , I; , I 1 I I ,; , I , 9400 -+ - - - - - - - -' - - - - - - - - - L - - - - - - - - -':- - - - - - - - - .L - - - - - - - - - 1- - - - - - - - - .1 - - - - - - - - - L - - - - - - - - I I I; , I I , I , ': ' I I I , , ,i , I I , I 1 Ii , I I , , , ,; I , I It 9600 -+ - - - -1- - - - -I - - - - - - - - - ï - - - - - - - - -I: - - - - - - - - ï - - - - - - - - -,- - - - - - - - - I - - - - - - - - -,- - - - - - - - - I , " I , I , I , 1: I , I 1 + I , 'i I I 1 -' I I , " ' , , , - - - - ~ - - - - - - - - - r - - - - - - - - -,~ - - - - - - - - + - - - - - - - - -1- - - - - - - - - ~ - - - - - - - - -~ - - - - - - -- I , If I I , , , I ': I I I , I , I[ I I I , I I ': I I I I I I Ii I , I I - - -,- - - - - - - - - - - - - - - - - - - - - - - - -~ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- I I Ii I I I 1 I I I' I I I 1 I I I: I I I , I , 1; , 1 1 1 I , I: ' I 1 I -- - - - -, - - - - - - - - - r - - - - - - - - -I: - - - - - - - - r - - - - - - - - -,- - - - - - - - - õ - - - - - - - - -õ - - - - - - -- I , I, I , I , I , I: I , , I I , r¡ I , , I I I 1: ' I , , 10400 -t- - - L - - - - - .J - - - - - - - - - L - - - - - - - - -':- -- - - - - - - - .l - - - - - - - - _1- - - - - - - - - .1 - - - - - - - - - '- - - - - - - - - I I , Ii ' , , , , I Ii I I I I I I ': I I I 1 I , ,; I I I 1 I , ,i I I , , 10600 -+ - -1- - - - - - -, - - - - - - - - - r - - - - - - - - -'!- - - - - -- - - - T - - - - - - - - -1- - - - - - - - - ì - - - - - - - - -,- - - - - - - - - I , ,; I I , , I 1 ': I I , , , , '; I I 1 , , I X I I , I 9200 £ '-" £ 9800 -+- - - - D- Q) 0 ro 1 0000 - u t Q) > Q) 1 0200 -+- - - ::J l- I- + , 10800 : + 150000 + Design Load Line / Pipe ~ating 300000 600000 750000 900000 Axial Force (Ibf) 1350000 1050000 1200000 450000 TRIAXIAL LOAD LINE (7" Production Liner) I I I I l+ Pipe Yield Strength I 0 I 1 1 , - - - - - - - ~:_::1~~ ~ ~-=-=~-=~--=-L- - - - - - - - - ~ - - - - - - - - - -~ ~~~:~~~~~a~i~:ofile (w/Bending) , I I I I , , I I I I , 1 I 10 I , , , 9600 -+ - - - - - - - - -:- - - -'-~ - - - -: - - - - - - - - - f t - - - - - -- -- : - - - - - -- - - -:- - - - - - - - - -; - - - - - - - - - f - - - - - - - -- ¡ 9800 t m -- m -im - m - ~ -- -- m - )\- - - - - - - - ~ - - - - - - - - -!- - - - - - - - - ~ - - - - - - - - ~ - - - - - - - - - Q) 1 1 , , , , I 0 1 I , \ I I 1 1 , , , I I I 1 - - - - - - - - -'- - -- - - - - - _1- - - - - - - - - -'. - --\- - - - - - - ~ - - - - :. - - - _1- - - - - - -- - -'- - - - - - - - J - - - - - - - - - , 1 ,. I I , , 1 I I 0 I I , , I , I \ I , I , 1 0200 + - - - - - - - - -:- - - - - - - ~ - - - - - - - - - j - - - \ - - - - - f - - - - - - - - + - - - - - - - - + - - - - - - - i - - - - - - - - - , 1 1 \' I , 1 I , , I I , 1 10400 -+- - - -- - - - - - -:- - - - - - x- --: - - - - - -- - - -: - - - - \ - - - -:- - - - - -- - -- - -:-- -- -- - - - --- - - -: - - - - - - - -: - - - - - - - -- 1 I 1 \ I I I , , , I I I I , 10600 -+ - -- - - - -- - --:- --- -- - -- - - ~ - - - - - - - - - ~ - - - - - \ - - - ~- - - - - - - - --:- - - -- "" - --- - -: - - - -- - - - - ~ - - - - - - - - - ~ : : \: : : ' ~ ; ; ; f; , ; I I X I '0 I I I + 1 0800 ----------¡------------------t-------i- I -- -¡----------------¡- 30.0 37.5 45.0 52.5 60.0 67.5 75.0 VME Stress (ksi) 9200 9400 ~ 10000 t Q) > Q) ::J l- I- j 82.5 90.0 ----------------- ---.----- ----- .-----.--------.---- ---------- --.-------------------------- Northstar Producer Casing Design StressCheck 1998.7 ( Build 6 ) { ( File: Northstar Bigt?pre Produ~er Casing Design.sck TRIAXIAL SAFETY FACTORS (7" Production Liner) 9200 9400 9600 - ~ - £ 9800 a. m 0 ~ 10000 t m > m 1 0200 ::J ...... t- 10400 10600 10800 0.00 - Date: August 01, 2001 Pa e: 39 I I I I + Burst I ,.) ... + C I 0 I I ,I :' I ¡ : \: : : 'Collapse ~ ~ ~ ~ ~ ~ ~ ~ r 1 ~ ~ ~ +t t': ::~: : : j : : : : - : - : : I : : - : : : : : : [ : : : : - - : : I : : :: ~ ~:~:I Cmeria I ¡ U I I I I I I l! I I I I I Ii! I I I I I I ¡ + I' I I I I, I I I I I I I I - - - - - - - - -:- - - ! - - - - ~ - - - - - - - - - : - - - - - - - - : - - - - - - - - - : - - - - - - - - -: - - - - - - - - -:- - - - - - - - - I ¡ 'i' I I I I I I ¡ >j:, I I I I I - - - - - - - - -¡- - - r - - - --ii- - - - - - - - - t - - - - - - - t -- -- - - - - - r - - - - - - -- -~ - - -- - - - - -i- - - - - - --- - - - - - - - -+ - - f - -- {- - - - - --- ~u - - u - -~: u u -- - - - f - - -- -- - -+ - - - - - - - -+ - u - ---- I! 01 I I I I 1 - - - - - - - - -i- - -1- - - t - - - - - - - - i - - - - - - - - - t - - - - - - - - i - - - - - - - - - i - - - - - - - - -i- - - - - - - - - - - - - - - - - -¡- - - ~ - - - 11-:- - - - - - - - - ~ - - - - - - - - - f - - - - - - - - ~ - - - - - - - - -¡- - - - - - - - - -¡- - - - - - - -- I I ¡II I , I I I I I I I I I I I I (> + CJ: I I I 0 I I I 0.75 1.50 2.25 3.00 3.75 Normalized Safety Factor þIIlNIMUfVI SAEETY FACTORS (711 Production Liner\ 10 11 12 13 14 4.50 5.25 6.00 Depth (TVD) (ft) Burst Triaxial OD/W eight/Grade 7", 26.00 Ibm/ft, l-80 Connection 9288: 9308: 9312 9357 9418 BTC, l-80 1.98 1.97 1.53 1.52 9740 I 10700 10704 1.43 10747 10773 10774 1.42 MAXIMUM ALLOWABLE WEAR CL.Production Liner), Depth (TVD) (ft) OD/Weight/Grade 7". 26.00 Ibm/ft, l-80 44.5- 44.1 27.9 14.6 14.3 9288 9418 9740 10700 10704 10774, 13.8 12.8 12.7, 22.9 22.7 --- ......,-......- '.-.---.... Northstar Producer Casing Design 1.51 1.50 1.48 1.43 1.42 Burst 3.57 : I 3.59 ! 3.60 : 3.70 i 2.46 2.44 1.88 3.87 4.48 4.59 I 4.63 I 1.74 0.053 0.052 0.161 0.160 0.101 0.050 0.083 0.082: 0.046 StressCheck 1998.7 ( Build 6 ) File: Northstar Bigbore Producer Casing Design.sck MAXIMUM ALLOWABLE OVERPULL (¡" Production Liner) Date: August 01, 2001 Page: 40 Running Depth (TVD) Max. Overpull 00 ~ -----_._. --.------. ,"'-,,"---'-- --" '..---.. """ -.--.--......--...---...-------.....--.---.----'---.---.-------. "--.---.-----.----- 0 422738 251 417328 411954 411953 411919 406513 401196 401128 395742 390336 385777 * 385934 * 385952 * 387075 * 387106 * 385482 * 386876 * 384541 * 381183 * 381060 *378171 * 376499 * 375582 * 373044 * 373250 * 373335 * 374959 * 376501 * 377928 *379131 . 379208 * 380310 * 381207 * 381870 . 407543 * 407565 *396211 * 385106 * 385399 * 385669 * 385695 * 385997 * 386305 . 386622 *386915 * 386949 * 387288 * 387640 . 388240 . 388676 . 388717 * 389194 * 389792 * 390392 . 390699 . 390745 *391341 *414756 500 502 752 999 1002 1252 1502 1714 1749 1753 1992 1998 2231 2445 2634 2789. 2795 2929 3007 3049 3167 3278 3284 3402 3519 3637 3746 3754 3871 3988 4105 4213 4222 4338 4455 4572 4678 4688 4804 4921 5037 5141 5153 5269 5385 5500 5603 5616 5732 5847 5962 6063 6078 6193 6308 6423 6522 6538 6653 6767 6882 * 415117 . 415426 * 415477 . 415837 * 416197 . 416557 --...""-' """"...-....' ...... ...---.--...-...------...-...----'" -.. ........ .._--- ,,", ..___-0._.",-""""",-",-"--'" .. .. ----- Northstar Producer Casing Design StressCheck 1998.7 ( Build 6 ) t { I File: Northstar Bigbore Producer Casing Design.sck MAXIMUM ALLOWABLE OVER PULL (7" Production Liner\ Running Depth (TVD) (ft) 7295 7442: 7565 7589: , 7736 7883 8030: 8150: 8830' I 9263 9288: 107O4! 107741 , " Based on Casing Strength: Only. Running String not; Included! I Northstar Producer Casing Design -------..-""". Date: August 01, 2001 Page: 41 ¡ Max. Overpull (Ibf) 8417852 " 418313 8418697 8418774 " 419235 8419695 8420156 8 420533 8 422667 8414075 8414074 8413533 " 392577 " 420536 . ..-.----- ,. -.-.-.....---------'--- StressCheck 1998.7 ( Build 6 ) File: Northstar Bigbore Producer Casing Design.sck TRIAXIAL RESULTS fT' Production liner) - Displacement to Gas Date: August 01, 2001 Page: 42 I Depth (TVD) Axial Force (Ibf Bending 1 i emperatu Addt'l Pickup To I Buckled (11) Apparent Actual Stress Triaxial (d~ F)- ~~ven~ Bu~~_:_~~~___L Length (11) (wlBending) (w/o _~~.!:!.ding) at 00 (ksi) --- --.-------- --..------------ -------------- 9288 50552: 41912 5.46 N/A 158.3 N/A N/A , 534141 44774 5_21 9418 77018 68378 5.88 12.61 159.7 9740 75848 , 67208 1.1 5.77 17.97 N/A 163.3 10700 78690' 70050 5.29 35.43 : 78603 69963 173.8 10704 82789: 74149 5.09' 35.71 , 10774' 81078. 72438 5.13 40.98 174_6 -- ------------ ------- ---------------------------------------- ---- _.._------------ ----- - -----------------------------------.. --------------~--- ---- -----------<--------------------~..__.._--- ----------------------------------------------------------------- ----_.._.._--------- -- ---- - ----- --------------------- ----- ----------------------------- --..-------------------- ------ TRIAXIAL RESULTS fT' Production liner) - Pressure Test Axial Force (Ibf) Depth (TVD) (11) Apparent Actual (wlBending) (w/o Bending) 9288; 51331: 42691 , 49134[ 40494 72737, 64097 65915; 57275 52580, 43940 525041 43864 56690' 48050 55159, 46520 9418 9740 10700 10704 10774 Bending Stress at 00 (ksi) Triaxial 2.46 2.44 1.98 1.97 1.53 1.52 N/A 11.28 ' 11.77 , 7.95 8.75 10_87 10.89 10.08 10.36 emperatu (d~ F) I 204.4 i , 209.8 Buckled Length (11) N/A 1.1 1.88 1.74 1.43 1.42 Addt'l Pickup To Prevent Buck. (Ibf) -- N/A : 218.8 245_2 245_3 ---------------------------------------------------------- -..- --- -----------------..-- --- ----- ----------- ---- ------------..--------------------------------------..------------..--------------------------- ---- ------------------------------- 246_3 ---------- --- - - -- -------------------- --------- ----- --------- TRIAXIAL RESULTS fT' Production liner) - TubinQ leak 1 10 11 Axial Force (Ibf) Depth (TVD) (11) Apparent Actual (wlBending) (w/o Bending) 9288 -40955 -32315 , -34908 -26268 -11304 -8640. 864d 12693 39071' 39089 43276 43264 , 9418 9546 9740 10700 10704 10774 Bending Stress at 00 (ksi) Triaxial 2.46 2.49 Absolute Safety Factor ~urst I collapse_t_- Axial 2_17 13.95 2_16 16.36 50.53 Add!" Pickup To l Buckled preven~ Buck- (Ibf) ~ength (11) N/A N/A --- 4053 30431 30449 34636 34624 1.91 1.63 66.11 1.1 N/A 248.4 1.95 1--65 45.00 L91 14.62 1.58 14.61 1.92 13.20 -2664 ---------------------------------------------------------------------------..--------------------------------------------- - _____m____- ----- - -------------------------..--------------------- ----------------------- --- ------ -- - ------------------ ___On--___------------------ -----------~--------------------- - -------------------- ------------- - ----------------..-- --------- ---- --- -- ----....------------------------ TRIAXIAL RESULTS fT' Production liner) - Green Cement Pressure Test Axial Force (Ibf) Bending Depth (TVD) 11 Apparent Actual Stress T" I ---------.-----------~--)--------- J~~en_ding) ..J~{?~~nding)____o_~t_<?!>J~~~.L_---~~~~~-- 9288, 79173: 70533 2_92 9418 75796: 67156 2-95 9740 67432: 58792 3.03 ¡ 10700 42472 33832 42367i 33727 42359: 33719 -57261 [ -48621 -57270, -48630 -59062: -50422 ~_=----1 EJ 10704 10705 10774 -----..-- ----..---------..---------------- --- Northstar Producer Casing Design 1.1 71.69 71_63 61.38 -----..--------- - 2-35 2_37 2.43 3-29 N/A 2.64 + 10000 7.43 7.76 8.71 13.78 13.82 e;;;~p ~;~~~~~~~I) -- __l-=~~~~ 155.3-- N/A N/A 156.6. 160.1 , 170.3 10.22 9.91 __I 171.0 -- ----- ..----------------- -- -------- StressCheck 1998.7 ( Build 6 ) (' f File: Northstar Bigbore Producer Casing Design.sck TRIAXIAL RESUL ""C§..fl:Productjon L~ - Cementing Date: August 01, 2001 Page: 43 Depth (TVD) Axial Force (Ibf) Bending emperatu Addt'l Pickup To Buckled (ft) Apparent Actual Stress Triaxial e Prevent Buck. (Ibf) Length (ft) (wlBending) (w/o Bending) at CD (ksi) (deg F) 9288 -30913 -22273; 57.38 9.46 19.02 155.3 N/A N/A 9289 -30932 -22292 57.43 19.01 9418 -34290 -25650 66.80 8.85 17.14 156.6 -34291 -2565t 9740 -42655. -34015' 1.1' 72.32: N/A 7.62 13.77 160.1 10700 -67615 -58975: 24.49 ' 5.39 8.66 10704 .f37727: -59087: 24.40 ; 5.38 8.64 170.3 : -57261 -486211 71.69 : 7.77 10.22 10774 -59062 -5O422! 61.38 : 7.70 9.91 171.0 I 10 !BIAXIAL RESUL T.§J711 Production LilliID - Lost Returns with Mud Drop TRIAXIAL RESULTS 711 Production Liner - Above/Below Packer Depth (TVD) Axial Force (Ibf) Bending Addt'l Pickup To Buckled (ft) Apparent Actual Stress Triaxial Prevent Buck. (Ibf) Length (ft) (wlBending) (w/o Bending) at CD (ksi) 1 9288 -160009 -1513691 2.63 ; 1.51 3.57 NJA N/A 9418 -154425 -1457851 2.62 1.50 3.70 -154424 -145784' 9740 I 2.60 1.48 3.87 -147475 -1388351 i N/A' 1.1; 248.4 10700 -127425 -118785' i 2.50 4.48 10704 -127419 -118779¡ 1.43 -123232 -114592i 2.49 ' 4.63 10774 -123439 -1148oo¡ 2.48 1.42 I.RIAXIAL RESULTS <z:product~on Liner) - RunninQ in Ho~ Depth (TVD) Axial Force (Ibf) Bending emperatu Addt' Pickup To Buckled (ft) Apparent Actual Stress Triaxial e Þrevent Buck. (Ibf) Length (ft) (wlBending) (w/o Bending) at OD (ksi) (deg F) 9288 99000 77726: 4.20 . 9.00 5.94 155.3 N/A N/A 9418 96783 74493: 4.24 8.88 6.07 156.6 7 4492! 9740 91080 664841 4.37 I 8.61! 6.45 160.1 10700 69405 425991 1.1' , + 100.00; 8.43 69298 42491¡ 5.01 ' 7.93 , 170.3 10704 8.45 69297 42490: 10773 67597 407831 5.07 7.89 8.66 171.0 10774 67579 40765! 10 i .n__.----..- _._n___-__-.- -.-----..-- ..-----....--.-----..-..---- 1 Depth (TVD) Axial Force Ib Bending Apparent Actual Stress (ft) (wlBending) (w/o Bending) at CD (ksi) 9288 36658: 280181 39981: 313411 39982 313421 41332: 32692; 44673, 36033¡ 44604: 35964' 48790: 401501 47377 387371 Buckled Length (ft) N/A emperatu Addt'l Pickup To (d~ F)prevent Buck. (Ibf) 158.3' N/A 159.7. Triaxial 4.28 : i 14.69 14.19 13.09 13.11 11.98 12.34 4.15 4.02 3.22 3.12 9418 9740 10700 ! 1.1j I N/Ai i 163.3 3.69 3.61 ; 3.62 i 2.83 2.85 173.8 10704 10774 174.6 Northstar Producer Casing Design Stress Check 1998.7 ( Build 6 ) File: Northstar Bigbore Producer Casing Design.sck TRIAXIAL RESULTS (l" Production Liner) - Overpull Force Depth (TVD) Axial Force (Ibf) Bend;ng [ _n_--[;__- r,,~,.,ul . Apparent Actual (ft) (wlBending) (w/o Bending) at ~~(;~~J___~~a)å~ Burst -- colla~~j- ---- A~i_~~___---~~~-~---- -_~~~~~i~cu~~ _~~f) l__~~~~~~~-- 1 T-- - - ----9288 158235 136961: 2.95 8.61 3.72 155.3 N/A N/A 9418 156018 133728: 2.97 8.50 3.77 156.6 133727: I 9740 150315 125719: 3.03 8.25 3.91 160.1 : 101834! 10700 128640 1.1 3.32 + 100.00 I 101726; 7.62 4.55 170.3 10704' 128532; 101725; 3.33 I , 10773, 126832 100018: 3.35 7.58 4.61 171.0 I 10774 126814 1 00000: I 10 Date: August 01, 2001 Page: 44 ------------------ ----- -------- --------------------------------------.------- ---~------------- ----------------------------------- ---- -------- --------------------.-------..-----------------.----.--.------ ---------.------- ------------.------ --.------------------- ------- ---- -----------~--_._-----_.--------------------------- ------- TRIAXIAL RESULTS {l" Production Linerl- Pre-Cement Static Load 1 A)åal Force (Ibf) Depth (TVD) (ft) Apparent Actual (wlBending) (w/o !3ending) 9288' -17766 -9126: 92891 -17785~ -9145i 94181 -21144 -12504: I -20868; -45828 -4594 11 I -47742' I Bending Stress at 00 (ksi) Buckled Length (ft) 1.1 Triaxial ----1 25.14; 9.46 33.10 155.3 25.15 ¡ 33.07 - 28.54 : 9.33 27.80 156.6 28.55 ¡ + 100.00 I 43.01 i 9.01 19.90 160.1 I 73.67 8.19 10.75 170.3 72-81 10.72 61.38 i 8.13 10.38 171.0 I 9740 10700' i 10704' 10774 -29508 -54468 -54581 -56382 -,----- N/A -----_._--------~------------- I , --------------L---- ---------.----- - ------ --- - -- - - - ---.---'------------- -------------------------------- .-----------.----------------------------------------------------.------------------------------ --,--_._----- ---- - ----, ---"'------------------------------~------- TRIAXIAL RESULTS {l" Production Linerl- Post-Cement Static Load Axial Force (Ibf) Depth (TVD) (ft) Apparent Actual (w/Bending) (w/o Bending) ~--_._- ------ 9288 -30913 -22273 56.51 + 100.00 9289 -30932 -22292 56.56 -34290 -25650 65.70 -34291 -25651, 65.71 N/A 9740 -42655 -34015 1.1 71.00 7-55 13.52 ',----- " 10700 --67615 -58975 23.92 5.32 8.46 ~ -67727 -59087 23.84 5.31 8.44 10704 ----- -57261 -48621¡ 70.02, + 100_00 7.67 9.98 10774 -59062 -50422 59.95 - 7.60 9.68 1 0------------------------------------------------.----------------------_._--_._--------~---- -----------------,--------------------- ------------- ------ ------------,,----- - - ---------",- -~------------ 1 Bending Stress at 00 (ksi) 9418 Triaxial Buckled Length (ft) emperatu e (deg F) Addt') Pickup To Prevent Buck. (Ibf) --------~._------------------ ---~----------------_._.,_._----~ 9.38 18.73 18-72 16.86 N/A N/A 204.4 8.77 209.8 218.8 245.2 245.3 246-3 ___n___- - -------------------------------.----------------- -- -------- ----- T R I Ax I A L-R E S ULT.S r¡';P;~~~~-L¡~~-~)'-:--G;;;;Ce men t p;~-~;.~~-'=;;~t'---------'-'._-------------_._-----------.----- -- '---1 I Axial Force (Ibf) Bending Depth (TVD) ft Apparent Actual Stress T" I _._....._---_.~--~--------- J~2:~~~P jw/o ~er:~ngl - at O.~~~=-i)J --~~~~~--~---_._--_._----~-----_.._-----___.'_n__.._- _n-- 9288 79173 70533' 2.92 2-35 7.43 9418 75796- 67156: 2.95 2.37 7.76 9740 67432 58792: 3.03 2.43 8.71 1 10700 42472. 33832, 13.78 42367 33727: 1_1 3.29 2_64 N/A 42359 33719 -57261 -48621 .57270 -48630, -59062 -50422 1 ~_=-_I EJ 10704 10705 10774 ----- ------------------------------------.-----.---...------- Northstar Producer Casing Design _L:;~] N/A emperatuj ..' .A- _d. d.t'l PiC.kU. P.TO- e Prevent Buck. (Ibf) (deg F) - ------------------.-- ----1--55-~3- - N/A 156.6 160.1 13.82 170.3 71.69 71_63 61.38 + 100_00 10_22 9.91 171.0 --- ----- _m - ----______n - -,,--- - - StressCheck 1998.7 ( Build 6 ) (' t '\ File: Northstar Bigbore Producer Casing Design.sck ~ETERS DATA (41/211 Production Liner), Date: August 01, 2001 Page: 45 Design Factor (Pipe) - Axial: Design Factor (Coupling) - Axial: Design Factor (Pipe) - Burst: Design Factor (Coupling) - Burst: Design Factor (Pipe) - Collapse: Design Factor (Pipe) - Triaxial: Minimum Internal Drift Diameter: Single External Pressure Profile: Temperature Deration: Limit to Frac at Shoe: Bucklin: 1.400 1.400 1.100 1.100 1.000 1.250 3.516 in Yes Yes No Yes. !!fILIAL CONDITIONS (4 1/211 Production L~ Mix-Water Density: 8.50 ppg Lead Slurry Density: 15.90 ppg Displacement Fluid Density: 9.30 ppg Float Collar Depth, MD: 14506 ft Slackoff Force: 0 Ibf Temperatures: Default Vertical Depth (ft) Temperature (deg F) 13831 ft 242.3 deg F 13943 ft 245.0 deg F 14045 ft 246.3 deg F 14402 ft 251.0 deg F 14586 ft 257.1 deg F 14586 ft 257.1 deg F 14586 ft 257.1 deg F Northstar Producer Casing Design StressCheck 1998.7 ( Build 6 ) File: Northstar Bigbore Producer Casing Design.sck BURST lOADS DATA (41/2" Production liner} Drilling load: Test Pressure: Mud Weight: Assigned External Pressure: Production load: Packer Fluid Density: Packer Depth, MD: Perforation Depth, MD: Gas/Oil Gradient: Reservoir Pressure: Assigned External Pressure: Drilling load: Test Pressure: Mud Weight at Shoe: TOC, MD: Lead Slurry Density: Displacement Fluid Density: Float Collar Depth, MD: External Pressure: TOC, MD: Prior Shoe, MD: Mud Weight Above TOC: Fluid Gradient Below TOC: Pore Pre_~_~.~re ..In...9p§ŒJjoL~_............. _n__'.__,-"-.."'""-"",,, ....-.-..-............ Northstar Producer Casing Design Date: August 01, 2001 Page: 46 Pressure Test 3500 psig 9.30 ppg Fluid Gradients (w/ Pore Pressure) Tubing leak 9.60 ppg 14100 it 14200 it 0.1000 psi/it 5071 psig Fluid Gradients (wi Pore Pressure) Green Cement Pressure Test 3000 psig 9.30 ppg 13831 it 15.90 ppg 9.30 ppg 14506 it Fluid Gradients (w/ Pore Pressure) 13831 it 14045 it 9.30 ppg 8.33 ppg Yes """""---------"-.--.-.--.--........--.-..'-'-"'-""..n.. ...-.-.-......-.. ....- StressCheck 1998.7 ( Build 6 ) t' { \ File: Northstar Bigbore Producer Casing Design.sck COLLAPSE LOADS DATA (41/211 Production Liner\ Date: August 01,2001 Page: 47 Drilling Load: Mud Weight at Shoe: TOC, MD: Lead Slurry Density: Displacement Fluid Density: Float Collar Depth, MD: Assigned External Pressure: Cementing 9.30 ppg 13831 ft 15.90 ppg 9.30 ppg 14506 ft Fluid Gradients (wI Pore Pressure) Production Load: Packer Depth, MD: Perforation Depth, MD: Pore Pressure at Perforation Depth: Density Above Packer: Density Below Packer: Fluid Drop Above Packer: Assigned External Pressure: Above/Below Packer 14100 ft 14200 ft 3007 psig 9.60 ppg 0.00 ppg Yes Fluid Gradients (wI Pore Pressure) External Pressure: TOC, MD: Prior Shoe, MD: Fluid Gradient Above TOC: Fluid Gradient Below TOC: Pore Pressure In 0 en Hole Below TOC: Fluid Gradients (wI Pore Pressure) 13831 ft 14045 ft 9.30 ppg 9.30 ppg No AXIAL LOADS DATA (41/211 Production Liner} Running in Hole - Avg. Speed: Overpull Force: Pre-Cement Static Load: Pickup Force: Post-Cement Static Load: Green Cement Pressure Test: Service Loads: 2.0 ft/s 1 00000 Ibf Yes 0 Ibf Yes 3000 psig Yes .ê.Y..RST LOADS TABLE (4 1/211 Production Liner\ Depth (TVD) Pressure Test I Tubing Leak Green Cement Pres.Test Green Cement Pres. Test Fluid Gradients wI Pore (ft) (psi g) (psig) (Int) (Ext) Press I (psig) (psig) (psig) 1 10588 8615 9261 8115 5115 5115 9354 8205 5268 5196 10774 8705 5009 I 10821 8728 9377: 8228 5308 5031 5063: I 10908 8770 5071: 8270 5379 5071 ; 8398 5195 11173 8898 5204 5598 5598 11242 8931 5238. 5655 5655 5227 ---_.-... --.--- --...... -..-.-.----.- Northstar Producer Casing Design StressCheck 1998.7 ( Build 6 ) File: Northstar Bigbore Producer Casing Design.sck COLLAPSE LOADS TABLE ,(41/211 Production Liner} Date: August 01, 2001 Page: 48 Depth (TVD) (ft) Cementing (Int) (psig) Cement;ng (Ext) I (psig) ~-_.. ~~~--'-"""~5115 5268 AbovelBelow Packer (psig) Fluid Gradients wI Pore Press (psig) --.-----...-.----.---...--.- -_._-_....~------- -.. ---.....--- --------_.._------ 10588 10774 5115, 5205 5228 2847 2940 2%3 I 5308 5228 - :;: -----~~~- d 5115 5205 10821 --.--..-----------.-..--------- 11173 1124~L.__.__-- 5398 5598 5655 --------------------..-- --. ....-.----.----,--------....--------- AXIAL LOADS TABLE ,(4 1/211 Production Liner} . Running in Hol~JlI:?.~ -- ~er¡:>_':I~~f~~e (Ibf) Pre-Gement Static Load Post-Cement Static Loa Green Cement Pressur Service Loads (Ibf) Depth (TVD) 1 ~ctual Actual Actual J Actual ! Actual Actual (ft) Apparent (I Apparent (I Apparent (I Apparent (I Apparent! (I Apparent (I (wlBending) B Wd~ ) (wlBending) B Wd~ ) (wlBending) B Wd~ ) (w.lBendin~) B Wd~ ) (wlBending)~' B Wd~ ) (wlBending B Wd~ ) en 109 en 109 en 109 en 109 en log en log --..------ ----- -- -- --.-----.- 10588 34855 27641 1154131 1081~9, -13966 -11316 -17239 -14590 24971 22322 -38467, -358181 10774 32724 25318 113281'1' 1058 6, -16301 -13652 -19574 -16925 22636 19987" -37199 -345501 105875 . I ¡ 112718' 105278! -16901 -14252 -20174 -17525 22036 19387 -37103 -344531 I I 1 -58979, -56330 111680. 104192 -17992 -15343 -21265 -18616 20945 18295 -59123 -56474 I ' , 109385: 101852 -20343 -17694 -23616 -20%7 185% 15947 -58192' -55884 -21331 -18682 -24604 -21955 17606 14957, -58014' -55365 -22138 -19489 -22138 -19489 -57027 -54378 -19555 -----=~-~!_--, -20362 -23011 -20362' -56124 -53475] 10821 10908' 11049 32160 31122, I 28827: 24721 23635 21295 10 11173 11242 27863 26998 20311 19442. 1084211 107555; 100869, 1 00000 -22204 ----.----------- BURST DESIGN (4 1/2" Production Liner) 10500 ...--.. ....... -..- ---- 1 , 1 , I 1 + D . L 1 : ' , 1 : esign oad Line , I +' ,. 'I X P. R. 10600+------"-"-1-'---------_.1_--'~-----~----- 1 , I' Ipe ,atlng : I ,----:----------~---______L__________I______--- I' I I I I " I I 1 , , : I 10700+--------~:----------~--- -----~-- : : I : I : : ------'-'----------'-i---------~----------:--------- I I , ' 1 I , I I , 1 I 1 ~ " I ------------ I 1 I 1 I I --------+--- -- . I r t. ---1----------1---------"'-'-------- I 1 , 1--------- I I I r ---------- I I I " I I 'I I , : 1 I I ' ----- I 'I I - -- - -:- - - - - - - - - ~ - - - -- -- -- - - ~ - - - - - - - - -~- - - - - - - - - ~ - - - - - - - - - ~ - - - - - - - - -~- - - - - - - -- : I , , r I I 'I 'I I -------- 1 , I : I I , -:- - - - - - - - - ~ -- - - - - - - - ~ - - - - - - - - -:- - .. - - - - - - ~ - - - - - - - - - ~ - - - - - - - - -:- - - - - - - -- , , I I I I , I 'I I 1 I " " 11100+---___~__1______---_.1_-- -----~-------- : I : : : : : --:-_.._-----~---------~-_.._-----:--------- " I 1 + I , : 1 , I : 11200+------~--:---------~---- _____1 --------_: : I I I, I ~ 1---------1---------~---------:---------- + I I Xl' I I " ' I' 'I' I I , : ' I , I 1 I :5 1 0800 0. <l> 0 ~ 1 0900 t <l> > <l> 11000 ::J L. r 11300 2500 I 5000 7500 I I I 10000 12500 15000 Burst Rating (psig) 17500 20000 ---_._,------ 22500 . J -------, --------..-.---.. Northstar Producer Casing Design StressCheck 1998.7 ( Build 6 ) { l \ File: Northstar Bi bore Producer Casin Desi n.sck COLLAPSE DESIGN (41/2" Production Liner) I: ; + Design Load Line . 1 I I I 1 x Pipe Rating + 1 Xliii . 10600 - - - - - - - - - _1- - - - - - - - - - - - - - - - - - L - - - - - - - - _1- - - - - - - - - .J - - - - - - - - - L - - - - - - - - -1- - - - - - - - - 1 1 1 I I 1 1 1 I I I 1 1 1 1 I I I I 1 1 I 1 1 1 I 1 I I 'I 10700 - - - - - - - - - -.- - - - - - - - - - - - - - - - - - ï - - - - - - - - -1- - - - - - - - - "'j - - - - - - - - - ï - - - - - - - - -1- - - - - - - -- I 1 I I I 1 I I 1 I 1 I I 1 I I I 1 I I 1 I 1 1 - - - - - - - - -1- - - - - - - - - - - - - - - - - - I- - - - - - - - - -1- - - - - - - - - ... - - - - - - - - - I- - - - - - - - - -1- - - - - - - - - I I 1 I I I I 1 I 1 I I I 1 1 1 I 1 I I - - - - - - - - - - - - - - - - !... - - - - - - - - _1- - - - - - - - - J - - - - - - - - - !... - - - - - - - - _1- - - - - - - - - I I 1 I 1 1 I I 1 1 1 1 1 I 1 I I I 1 1 1 1 I 1 1 - - - - - - - - - r- - - - - - - - - -1- - - - - - - - - , - - - - - - - - - r- - - - - - - - - -1- - - - - - - - - I I I . 1 1 1 I 1 1 1 1 I 1 1 1 1 I 1 1 - - - - - - - - - L - - - - - - - - _1- - - - - - - - - .J - - - - - - - - - L - - - - - - - - -L - - - - - - - - 1 1 lit 1 I I I 1 1 1 I 1 1 1 I I 1 I 1 1 I I I - - - - - - - - - - - - - - - r - - - - - - - - -1- - - - - - - - - 1 - - - - - - - - - r - - - - - - - - -1- - - - - - - - - I 1 1 , 1 1 1 1 , , I I I I 1 1 1 1 I 1 . I I I 10000 12500 15000 Collapse Rating (psig) 10500 - ~ - £ 10800- c- O> 0 ~ 10900- t 0> > 0> 11000- ::J L.. J- 11100 - 11200 - 11300 2500 Date: Au ust 01, 2001 Pa e: 49 1 I I ---______1- 1 1 1 I . --------~--------- 1 1 1 1 --------~--------- . I I I 1 - - - - - - - - -1- - 1 , + 1 t X I I I 5000 I 7500 I 17500 I 20000 22500 AXIAL DESIGN (4 1/211 Production Liner) 10500 10600 10700 - ~ - £ 10800 c- O> 0 ~ 10900 .E 0> > 0> 11000 ::J L.. J- 11100 11200 11300 150000 I I 1 , I I + Design Load Line 1 1 I I 1 1 I I 1 I I 'x Pipe Rating + I x I 1 I 1 I . - -------~---------L---------~--------~-------_-L__-___--~---~_____L______--- I 1 I I I I 1 , I 1 I I I 1 I 1 1 I I I 1 1 1 1 I 1 I 1 I I 1 I I I . --------~---------T---------~--------l---------ï---------.---------T--------- 1 1 1 I 1 I 1 1 1 1 , 1 I I I 1 1 , 1 1 I I 1 I I 1 I - - - - - - - -I - - - - - - - - - + - - - - - - - - -1- - - - - - - - - .... - - - - - - - - - I- - - - - - - - - -1- - - - - - - - - + - - - - - - - - - 1 lit 1 I t , 1 , I 1 1 I 1 I , 1 1 , 1 1 1 I I t 1 1 1 , , 1 t +-------~---------i---------~--------~---------~---------,---------1--------- I 1 I 1 I 1 1 1 1 1 I I I 1 1 I 1 1 I I I I 1 1 1 I I 1 -------'---------T---------r--------,---------r---------- ---------T--------- I 1 1 I 1 I . I 1 1 1 I I 1 I I 1 I I 1 1 I 1 I 1 1 1 1 I --------~----_____L-________L______--~----_____L_____----I---______L__--__--- I I 1 1 I 1 I I I 1 I I I 1 I I 1 I I I 1 + I 1 I I I I 1 I--------~---------t---------~--------~---------~---------¡---------f--------- + 1 XII I I 1 , 1 I I I 1 I 1 1 I I I I 1 I 225000 300000 375000 450000 525000 Axial Force (Ibf) 675000 750000 600000 Northstar Producer Casing Design StressCheck 1998.7 ( Build 6 ) ~ïl~_:l'!ort~sta~ Bigb9re _P~Qdu~~L Casin9-Qesign.sc~__---_._--_...._----------------------_.Q_ate~Aug~st 01,- 2001 Page: 59 TRIAXIAL LOAD LINE (4 1/2" Production Liner) 10500 10600 10700 £ '--'"' -£ 10800 0.. <D 0 ~ 1 0900 t <D > <D 11 000 :J L.. r- 11100 11200 11300 , 30.0 + Pipe Yield Strength " Apparent Load Profile (w/Bending) 0 Desian Load Line I I I I I I I , I I 1 I " I 0 1 I --------I'---------~--- -----~--------_L______--- 'I I I , ! I 1 I I 1 I ¡ I I I I I , ¡ , I I I I I ! I 1 I I I I --------~------------- ----------------------------------------- i' I I I I 1 ; 1 1 1 I I I ! 1 , , I , I ¡ I I 1 I , , 1 I I I , I - - - - - - - -! -1- - - - - - - - - ~ - - - - - - - - -+ - - - - - - - - - I- - - - - - - - - -1- - - - - - - - - ~ - - - - - - 1...,,1.. "'" ,,\ ", I 0----1-- I I I , \' , , , I I !' I , I I , ! I I I , I - - - - - - - - -'- - - - j - - - - .J - - - - - - - - - .! - - -- - - - - - L - - - - - - - - -'- - - - - - - - - -'- - - - - - , \ I I I , 1 I \, , , , I , \, I , , I I ! , , I I , ! 1 I I I - - - - - - - - -,- - - - - \- - - - ., - - - - - - - - - T - - 0 - - - - - - r - - - - - - - - -1- - - - - - - - - ., - - - - - - , \, I \ I , , I \ I , I , I , \ I I I , I , X I , , , , - - - - - - - - _1- - - - - -. - - - ...J - - - - - - - - - J. - - - - - - - - L - - - - - - - - _1- - - - - - - - - -.! - - - - - - , ¡ I I , , I I \ I , , , I ! I 1 I , I \ I 1 1 I , , \, 1 I , , - - - - - - - - -,- - - - - - t - - Î - - - - - - - - - T - - - - - - - - r - - - - - - - - -,- - - - - - - - - -, - - - - - - I \ I I I , 1 , X I I 0, 1 , I I I I , , , , , 1 I I I 1 I -~~--------- I , , --~--------- , I I , J - - - - - - - -- - - 1 I , I --~--------- I , I , --- --.1------ I , I , --~--------- I I , , + I 37.5 I 45.0 t 52.5 I 60.0 VME Stress (ksi) 67.5 75.0 82.5 90.0 TRIAXIAL SAFETY FACTORS (4 1/2" Production Liner) 10500 1 0600 - 10700 ---.. +-" '+- '--'"' 1 , I 1 I I + Burst 1 , I I I 1 1 I I I 1 x Collapse I, I ""-J ' X I , - - - - - - - - -:- - - ,.: - - - - - -: - -'!'~ - - - - - - ~ - - - - - -' - - ~ - - - - - -- - - - ~ - - - - - - - - -- ~ - - - - 0 Axial I I, 1 , I '[]Triaxial , I I I 1 I 1 I I' I ¡ ¡ ¡ L<> Failure Criteria 1 I I I , , - - - - - - - - -1- - - - - - - - -,- - - - - - - ï - - - - - - - - ï - - - - - - - - - ï - - - - - - - - -1- - - ,- - I 1 , , , , , I , , I , I I I I I , , , I I ': 1 , , I I - - - - - -- -- - -1- -.- -- -- -. - - - - - ~o- -. - - - '" - - - - - - - - + - o. - - - - - - - - - - -... - - -... -I- - - - - - - - - -1- - - - - - - -- ".." " I X I I 1 , : r"".~ """TJ"""""""""'r"-""""':'-""'" : : : : I ! 'I , I 1 1 1 - - - - - - - - -:- - - - - - -1- t:-- - - +- - - ~ - - - - - - - - - + - - _... - - - - - ~ - - - - - - - - -:- - - - - - -- - - -:- - - - - - - -- I I il I I I I , 1 ' " I 1 I 1 I I X :, 1 I I I I Ii, I 1 , I , - - -... - - - - -1- - - - - - -!-o- - - - - - - - -, - - - - - - - - - T - - - - --..- - - - r - - - - - - - ,- -r- -... - - - - - - -1- - - - - - - -- , i' 0 1 I I , I I 'I I I I I I , ""'01 I , I I , I "";1 I , , , , ----------:--- --- - ,---- ---~---------~-------_._--~--"--------:------------:--------- , 1 I 1 1 1 , , I I 1 I I 1 1 I I 1 1 , 1 1 I I I 1 , I ----------1--- --- -,------ ---l-----"-------"'--"'--------- ('"---------'----"---'----1---------- I I I I I 1 I ,,- '-,I."J I 0+ I , 1 I :S 1 0800 -0- - - - ... - -- - 0.. <D 0 <ú 10900- 0 t <D > <D 11000 ::J L.. r- 11100 11200 I 11300~- 0.00 ------.- -¡-----.---t 0.75 1.50 I +---+~ 2.25 3.00 3.75 4.50 5.25 6.00 Normalized Safety Factor -------- ---- --------... -------- ---,,---_.._-- Northstar Producer Casing Design StressCheck 1998.7 ( Build 6 ) ( { \ File: Northstar Bigbore Producer Casing Design.sck MiNIMUM SAFETY FACTORS (411211 production Liner} Date: August 01, 2001 Page: 51 Depth (TVO) (ft) 1 10588 10774 10821 10908 11173 11242 OON/ eight/Grade 4 112", 12.60 IbmJft, L-80 Connection Factor (Abs) Burst Axial Triaxial BTC, L-80 1.92 2.44 2.08 2.76 1.84 2.48 2.11 1.83 2.75 2.50 2.12 1.38 1.85 2.16 1.36 . 2.52 1.84 1.34 2.59 1.79 2.15 1.33 2.61 1.77 ,MAXIMUM ALLOWABLE WEAR (ij1211 Production Liner), 1 Depth (TVO) (ft) 10588 10774: 10821 10908: 11173: 112421 CON/eight/Grade 4 1/2", 12.60 Ibm/ft, L-80 Burst 42.8, 35.7 0.116 , 42.6' 0.097 40.1: 35.6 0.109: 40.0 0.096 49.0' 14.0 0.133, 0.038 13.4 , 0.036 48.8 12.8 0.132: 0.035 12.5 I 0.034 Northstar Producer Casing Design StressCheck 1998.7 ( Build 6 ) File: Northstar Bigbore Producer Casing Design.sck MAXIMUM AllOWABLE OVER PUll (4 1/2" Production liner\ Running Depth (TVD) (ft) 1 ..--...--.-----.- -"-----'--"'------"""'-'-""'-"--- --..._-------------- ~. f [::::.::.:".-.-....-.--...--..----------...........-...--..--... . Northstar Producer Casing Design 0 251: 500 503 , 754: 755¡ 999, 1005; 1255! 1506' 17491 I 1757: 1992; 2004~ I 2237: 24501 2639: 2789, 28oo! I 2933¡ 3ooi I 3054 3172 , 3278 3290, 3407, 3525' 3643, 3746; 3760 3878 3995 4112 4213 4229 4346 4463 4580 4678 4697 4814 4930 5047 5141 5163' 5279 5395 5511 5603 5627 5743 5859, 5975 6063. 6090 6206 6321 6436 6522 6552 6667 6782 6897 6988 Date: August 01, 2001 Page: 52 Max. Overpull -------------.. ---.. - ~ I b fL. . --..-..---..---.-.-- 203091 200360 197661 197629 194899 194892 . 195323 . 195334 . 194893 . 195330 * 195747 . 195762 . 195059 . 194935 * 192402 . 190084 * 190306 . 190813 * 190852 . 191404 . 191752 * 191982 * 192500 * 192887 * 192922 * 193235 * 201374 * 201501 * 201613 * 201628 .201754 * 201881 * 202007 * 202116 * 199102 . 195697 . 195788 . 195880 * 195959 . 195975 . 196073 .196176 * 196284 . 196376 * 196398 .196519 .196746 * 196973 .197176 * 197200 . 203767 .203892 .204017 *204112 . 204142 . 204266 * 204391 .204515 . 204607 . 204640 .204764 . 204888 * 205013 .205110 ......-....-. .. ..----- .. .....----- . -.-- ".... -.-..._-.. ........... StressCheck 1998.7 ( Build 6 ) ._._---- (' File: Northstar Bigbore Producer Casing Design.sck fJlAXIMUM ALLOWABLE OVERPULL (4 11211 Production Lmm Running Depth (TVD) (ft) { 7463 7565 7610 7757 7904 8051 8150 8199 8346 8830 9263 10588 10774 11173 11242 . Based on Casing Strength Only. Running String not Included . ...__n____- ---~.._.-...__.._.. ..-.-.--..... -".--' Northstar Producer Casing Design "- Date: August 01, 2001 Page: 53 Max. Overpull (Ibf) . 205623 . 205733 . 205782 . 205941 .206100 . 206258 . 206365 .206417 . 206576 .207099 . 204659 . 199956 . 207240 .207437 . 207861 . 207934 --.---- ...- . ....... ". ---...-.---.-----------------.--.---- StressCheck 1998.7 ( Build 6 ) File: Northstar Bigbore Producer Casing Design.sck TRIAXIAL RESULTS (4 1/2" Production Liner}- Pressure Test Date: August 01 , 2001 Page: 54 Axial Force (Ibf) Bending Depth (TVD) (ft) Apparent Actual Stress IT' . I -_._-- .Lw/Be~ding) . (w~o Bending) at 00 (ksi) naxla --.....-..-.--........ 1 I 10588 13898: 11248 2.79 10774 12258 9609 2.78 14038 11389 10821 13602 10953 2.63 2.16 N/A1 10908 12809, 10160 0.7 : 10383 7734, I 11173 I 11369 8720 2.61 2.15 i I : 7911' I 11242 10560 ' I I ----...--.----.-.- ----.- ----... ---- .'-------------.--...---'--..-..-.. ----------.-'----'- _.__..._..L_.__.~._-_.J..__._.__--l ..---....-------- --- ------...-.--... --.------- TRIAXIAL RESULTS (4 1/2" Production Liner) - Tubin~ Leak empe"'tul Addt'l PK:kup To (d~ F) . Prevent B~Ck. (Ibf) 19.64 , 242.3~ N/A 22.24 246.3 19.42 , 20.04 247.1 21.27 248.4 26.18 254.4 23.91 : , 25.72 I 257.1: I Buckled Length (ft) N/A ----.---------. -.---.----------,----- 1 Axial Force (Ib Depth (TVD) (ft) Apparent Actual (w~ending).. _tw/o Bending) - 10588 14182 11533 10774: 15539 12890; '17320 14670 17424 2649 -2649, -19726 -19791 -17661. -16674 -15504 Bending I Absolute Safe Stress J T' . I I Burst at 00 (ksi) - naxla I : I I 19_21 2.34 1.92 I I 17.53 1.84 I I 15.73 2-23 1.83 I 15.63 ! I + 100.00: 0.7 N/A' 80.94 ~ 13.81 72.33 I I 13.76 ' 43.70 + 100.00: I 15.42 I ! I 37.73 I 16.34 , 32.13 . 17.57 I 14775' 10821 -17077 10908 -17142 -15012 -14025 -12855 11173 11242 10 11 12 --___~__m__- -------- --- .--..-----.----------------- TRIAXIAL RESULTS .(4 1/2" Production Liner}- Green Cement Pressure Test emperatu e (deg F) Addt'l Pickup To Prevent Buck. (Ibf) --- N/A Buckled Length (ft) N/A 248.4, -------.---. Axial Force (Ibf) Bending Depth (lVD) (It) l~;~~~~~_.. _.......J~~;"~~~;~~L ._~~~~;~_iL1._~~a~~__.__._..._--~~._--"------ 10588 24971 22322 3_37 2.72 : 11.17 10774 22636 19987 3.44 2_78 12.32 10821 22036 19387 3.46 2.79 12.65 ' 10908 20945 18295 3.49 2.82 13.31 17609 14960 0.7 1 N/A 17606 14957 3_6 2.91 15.81 -22138' -19489 -22142 -19493 -23011 -20362 11173 + 100.00 + 100.00 11242 93-78 ____m,______'__._m____-----""-"-'_"m----_-'-------'--"---...----........-...-. _.m_--__.--""-----' ..----------------.---...l.--..---.-------.---..-..---.-....-----.-----....--..........------..---..-.. 179.7 10 12.58 ' 12.57 12.10 .. emperatuj Addt'l P.. ickup To e Prevent Buck. (Ibf) (deg_~- .--- ---- 172_6 174.6 175.1 176.1 Buckled Length (ft) _mm_._-.-m__----' N/A N/A 179.0 TRIAXIAL RESULTS {4 1/2" Production Liner) - CementinQ - ------------.--------..... - ..--.. --------- -- ------......--.....---. - -_.._-------_..~----------- --..- .------------- -- ---- ---------- Bending Stress at 00 (ksi) Triaxial Axial Force (Ibf) Depth (TVD) (ft) Apparent Actual --.----------- .t~/Bendin~t-- (w/o_~endjng) 10588 -17239 -14590' 10589 -17247 -14598 10774 -19574 -16925 10821 -20174 -17525 10908 -21265 -18616 -24604 -21955 -22138 -19489 -23011 -20362 + 100_00 11.91 ¡ 11.90 ! 10.62 i 10_34 ! I 9.85 .. 8.61 ¡ 10.87 ' 10.76 I 0.7 88.73 46.55 + 100_00 93_78 N/A ~----I 11173 D____....._.._---~-~-~~-~_..--. emperatu1 Addt'l Pickup To J BUCk~ J~e~ ~_J..._~revent Buck. (Ibf) - __~er~gt~~...J 16.18 172_6 N/A N/A. 14.24 13.82 13.10 11.32 12.58 12.10 174_6 175_1 176.1 179_0 179.7 .-.....-- -------.---......---..... --.......-- --...._...._..__.._..-----......_--..~..._-_.....-...---....... --.. ---........-....... ....-................_--h Northstar Producer Casing Design StressCheck 1998.7 ( Build 6 ) , , ( (' \ File: Northstar Bigbore Producer Casing Design.sck ~ESU L ~roduction Liner) - Abovelßelow Packer Date: August 01, 2001 Page: 55 Depth (TVD) Axial Force Ibf) Bending Absolute Safe Factor Apparent Actual Stress I (ft) Triaxial Collapse ¡ Axial (wlBending) (w/o Bending) at 00 (ksi) I 1 0588 ~38467: -35818 4.27: 2.76 7.08 10774; -37199' -34550, ' 7.32 -37103~ -34453; 4.25 : 2.75 7.34 10821 -58979: -56330: 1.85 : 1.38 4.62 1 0908: ¡ 0.7 1.84 ¡ N/A -59123, -56474: 1.37 4.61 I -55365' 11173' -58014: ' 4.70 -57027 I 1.79 ! 1.34 4.78 I -54378: ¡ : , I 1.77 i 11242; -561241 -53475: 1.33 4.85 , I I emperatu e (deg F) Addt'l Pickup To Prevent Buck. (Ibf) N/A Buckled Length (ft) NlA 248.4 TRIAXlAb..RESUL TS (4 1/211 production Linerl.:-Runnina in Hotg 1 Axial Force (Ib Depth (TVD) Apparent Actual (ft) (wlBending) (w/o Bending) 10588: 348551 27641 107741 32724\ 25318 108211 321601 247211 109081 31122í 23635' 111731 278631 203111 i 270061 194501 112421 26998; 19442[ Buckled Length (ft) N/A Bending Stress at 00 (ksi) Addt' Pickup To Prevent Buck. (Ibf) N/A Triaxial 5.24 i 11.38 8.00 5.42 11.22 8.52 5.47 11.18 8.67 5.56 + 100.00 11.10 8.95 5.89 10.89 9.99 5.98 10.83 10.31 179.7 i 0.7! IBIAXIAL flESUL 1§J!j/211 Production ÿ.!!w - Overpull Force Depth (TVD) Axial Force (Ibf) Bending emperatu Addt'l Pickup To Buckled (ft) Apparent Actual Stress Triaxial Collapse I Axial e Prevent Buck. (Ibf) Length (ft) (wlBending) (w/o Bending) at 00 (ksi) (deg F) 1 10588: 115413' 1081991 2.08 ! 9.53 2.42 172.6 N/A N/A I ! 105876¡ 10774l 113281: 1058751 2.11 ! 9.42 2.46 174.6 I 105278: 10821! 112718: 2.12 : : 9.40 2.47 175.1' , 0.7 + 100.00 10908, 111680: 104192: 2.13 ! 9.35 2.50 176.1 11173~ 108421¡ 100869: 2.18 i 9.20 2.57 179.0 , 11242, 107563: 100008, 2.19 ¡ 9.16 2.59 179.7 107555: 1 OOOOO! , IBJAXIAL BESUL 1§J4 1/211 Production Li~ - Pre-Cement Static Load Depth (TVD) Axial Force (Ibf) Bending (ft) Apparent Actual Stress (wlBending) (w/o Bending) at 00 (ksi) 10588 -13966; -11316: 10589 -13974] -11325: , I 10774 -16301, -136521 10821 -16901! -14252: 10908' -17992\ -153431 11173! -21331' -18682 11242: -22204: -19555' ifemperatu Addt'l Pickup To Buckled e Prevent Buck. (Ibf) Length (ft) (deg F) 11.91 19.98 172.6 N/A N/A 19.96 11.70 17.10 174.6 + 100.00 11.65 16.49 175.1 11.55 15.49 176.1 11.27 13.05 179.0 11.20 12.54 179.7 Triaxial 62.661 62.76 0.7: + 100.001 93.78 I I ---,------_._.".,,--- Northstar Producer Casing Design StressCheck 1998.7 ( Build 6 ) File: Northstar Bigbore Producer Casing Design.sck TRIAXIAL RESULTS ,(4 1/2" Production Liner}- Post-Cement Static Load Axial Force Ibf) Depth (TVD) (ft) Apparent Actual ----4----- - (wIB~nding)-- - (w(?., Bending) - 10588 -17239 -14590 10589 -17247 -14598 10774; -19574 -16925 10821' -20174 -17525, 10908 -21265 -18616, -24604 -21955, -22138 -19489; -23011' -20362) Bending Stress at 00 (ksi) Date: August 01, 2001 Page: 56 ----------~----"---'----' Triaxial Buckled Length (ft) 11173 11242: + 100.00 + 100.00 0.7 N/A 86.74 45.45 + 100.00 I + 100_00 91.52 - 11.73 11.72 10.46 10.17 ' 9.70 I 8.47 , 10.69 10.57 ' ----------------"----"---"----------------------"'--'--.---..-----.--.- _..-_L.._____-..----.. ------ ..-.--------------------.-- ---... -- -- -" "----- empe"'tul Add" Pickup To (d~ F)_~re~~t BUCk.~bf)- 15.83 242_3 N/A 15.82 242.4 13.93 246.3 13.51 247.1 12.81 248.4 11.05 254.4 12.28 I 11.81 . 257.1 ----_. N/A . ."'" ---------------"--'-"----------------. TRIAXIAL RESULTS ,(41/2" Production Liner}- Green Cement Pressure Test -------..-......------------- Depth (TVD) Axial Force (Ibf) Bending (ft) Apparent Actual Stress (wIBending) (w/o Bending) at 00 (ksi) -- !--..J 10588: 24971 22322: 10774: 22636 19987! , 108211 22036: 19387¡ 10908: 20945 18295' 17609 14960 ' 0.7 I 17606 14957 11173 I -22138 -19489 -22142 -19493 11242 -23011 -20362: 1ol ____.L______---------- Triaxial 3.37 : 3.44 : I 3.46 . I 3.49 2.72 ' 2.78 ì 2.79 ! 2.82 2.91 3.61 ! ¡ + 100.00 + 100.00, 93.78 ' "-----"-"-------'----------- N/A: empe",uL Addfl P;ckup To I Buckled J..d!~ F) - p~~~ent Buck- (Ibf) Length (ft) 11.17 : 172.6 N/A N/A I 12.32 ¡ 174.6 12.65 ¡ 175.1 I 176.1 13.31 : 15.81 : I 179.0 12.58 12.57 I I 12.10 I 179.7 --------..---------.------.-..."""" . .--..._.____m...____-..--------...--.-....-----------'- '-"'-"---""-"--------- COMPRESSION LOAD CHECK DATA Wellhead (or BOP) Weight: Tubing Weight: Tubing Stability (or Setting) Load: Conductor Casing: Axial Compressive Force: -----__.ðb~oLtJJe SafetY...F a_cto.!;------------------_._--------- 0 Ibf 0 Ibf 0 Ibf .-----...--. --------....-...--.---....-----.--------..------..-----...---... '--------------"----------------------"""------"-"'~ 0 Ibf 0.00 ---------- ----- - -.. _. -. '--.---------- SPECIAL CONNECTIONS -- - -.------.___.__m___._.----------.-'-----"'------..'------"'-...---.'----.--------"',,-,-----------,----- Northstar Producer Casing Design $IJoint StressCheck 1998.7 ( Build 6 ) . , . ( Name: Northstar Bigbore Producer Burst Loads - Drilling Displacement to Gas Gas Kick Profile Frac @ Shoe with Gas Gradient Above Frac @ Shoe with 1/3 BHP at Surface Lost Returns With Water Surface Protection Pressure Test Green Cement Pressure Test Burst Loads - Production Tubing Leak Stimulation Surface Leak Injection Down Casing Gas Migration Burst Loads - External Mud and Cement Mix Water Permeable Zones Above/Below Prior Shoe Minimum Formation Pore Pressure Pore Pressure with Seawater Gradient Fluid Gradients with Pore Pressure Casing Load Inputs f ~ Type: 13-3/811 Surface Casing Collapse Loads - Drilling ~ Full/Partial Evacuation .x.... Lost Re~ums With Mud Drop X Cementing Collapse Loads - Production I "t'[ Full Evacuation ....:..'...'........ Above~Bel~w Packer :; .:. Gas Migration Collapse Loads - External Mud and Cement Mix Water Permeable Zones Mud and Cement Slurry Frac @ Prior Shoe with Gas Gradient Above Fluid Gradients with Pore Pressure Axial Loads ~. ~' Running in Hole Speed j~!ii Overpull Force ~ :1~~i¡i Pre-cement Static Load ~ :~ii'¡ Post-cement Static Load ~. i~:1; Green Cement Pressure Test ~: Service Loads ........' Page 1 of 5 Burst Loads Northstar Bigbore Producer 13-3/8" Surface Casing Burst Loads - Drillini Infouts Value Default Displacement to Gas Mud on top of gas Gas Kick Profile Limited kick design Frac @ Shoe with Gas Gradient Above l!. Gas on top of mud Frac @ Shoe with 1/3 BHP at Surface Surface pressure is 1/3 of BHP Lost Returns With Water Underground blowout with seawater Surface Protection i Full displacement of gas with a seawater gradient to surface similar to lost returns with water or displacement to gas Influx Depth Pore Pressure Gas Gradient/Gravity Frac at Shoe Frac Margin of Error Gas/Mud Interface Mud WeiQht Influx Depth Kick Volume Kick Intensity Maximum Mud Weight Kick Gas Gravity Frac at Shoe Frac Margin of Error Drill Pipe 00 Drill Collar 00 Collar Lel1Q1h Pore Pressure Pore Pressure 0.1 psi/ft or 0.7 SG Frac Gradient 0.0 ppg Surface Casinc¡ Scheme Casing Scheme 50 bbl . '0.5 ppg Casing Scheme 0.7 Frac Gradient 0.0 ppg popular sizes Frac at Shoe.2118 .. Frac Gradient Frac Margin of Error 0.0 ppg Gas Gradient/Gravity 0.1 psi/ft or 0.7 SG Shoe Depth <3493. Bottom Hole Pressure Shoe Depth Frac at Shoe Frac MarQin of Error Frac at Shoe Frac Margin of Error MudIW ater Interface Mud WeiQht Pore Pressure Casing Scheme Frac Gradient 0.0 ppg Frac Gradient '0.0 ppg Casing Scheme Casinc¡ Scheme Frac Gradient 0.0 ppg 0.1 psi/ft or 0.7 SG Notes Limits Multiple liner designs need review Edit here affects all other edits for this item Multiple liner designs need review Edit here affects all other edits for this item . TO of open hole Downhole conditions EMW - OMW Mud at shoe Multiple liner designs need review Edit here affects all other edits for this item Optional Optional ReQuired if drill collar Ie Multiple liner designs need review Edit here affects all other edits for this item Edit here affects all other edits for this item Pressure based on deepest open hole Multiple liner designs need review Multiple liner designs need review Edit here affects all other edits for this item Multiple liner designs need review Edit here affects all other edits for this item Depth of shoe above open hole section Mud at shoe in deepest OPen hole Multiple liner designs need review Edit here affects all other edits for this item Edit here affects all other edits for this item Casing Frac at Shoe Frac Margin of Error Gas GradienVGravity Pressure Test I X Green Cement Pressure Test I X Pressure test before emt set Test Pressure Mud Weight at Shoe TOC Lead SlurryDensity Tail Slurry Density Tail Slurry Length Displacement Ruid Density Roat Collar Lel1Q1h j2500 0.0 psig )9;5.; Casing Scheme Casing Scheme <122.. Cementing and landing "15.9 Cementing and landing 750 . Cementing and landing . >9.5: Cementing and landing "3413 Cementinc¡ and Landi Shoe depth Affects axial value Burst Loads - Production Tubing Leak A surface tubing leak over packer fluid Stimulation Surface Leak D Same as tubing leak except for injection Gas Miaration n . . J . '--' Gas between prod. and intr. Packer Fluid Density Packer Depth Perforation Depth Gas/Oil Gradient or Gas Gravity Reservoir Pressure Production Data Production Data Production Data Production Data Gas default is 0.1 psi/ft or 0.7 SG Pore Pressure or Production Data .... Production Data Production Data 0.0 psig 8.33 atTD between ¡ntr. and prod. @ mud at shoe Gas Pressure[ Internal Fluid Density Frac at Shoe [Pore Pressure Casing Scheme Frac Gradient Burst Loads - External Mud and Cement Mix WaterD Toci ICasing Scheme Page 2 of 5 , . ( Burst Loads ( \ Mud and cement mix water BBG LImits Permeable Zones If no permeable zones specificed in open hole, same as mud and cement mix-water profile Above/Below Prior Shoe Split mud weights across casing shoe for liner Minimum Formation Pore Pressure U Mud and cement mix water BBG Pore Pressure wjfJ¡ Seawater Gradient Seawater from MSL to mudline and then a linear profile to pore pressure Ruid Gradients with Pore Pressure X Default Casing Scheme Cement and Landi Number of Permeable Zones > Pore Pressure Zone Geometry ::,:;c','f.. Pore Pressure TOC >,~::: Casing Scheme Prior Shoe <: ;i'¡"1:-f~, Casing Scheme Mud Weight \'~"{:j;',;. Casing Scheme Cement Mix-Water Density'F~";;: Cement and Landing Poor Cement '::\i;atiF. T Ie t.nnarked Prior Shoe >;¡f'~F;. Casing Scheme Min EMW in Open Hole ,;:;U,\t\:; Pore Pressure Cement Mix-Water Densi;f\:i:~j+J' Cement and Landi TOC Casing Scheme Prior Shoe Casing Scheme Min EMW in Open Hole !;dm;~~;. Pore Pressure Mud Density ~\::<:~~;;, Casing Scheme Cement Mix-Water Density ':,;:~~,,~..: Cement and Landing Allow Mud Drop ': '.,~:::, Toggle Apply Min EMW in Open Hole at i',;¡:;'>U Toggle Previous Shoe or Top of Cement Notes Depths if one zone, number if multiple zones Deteriated mud has an effect zonal isolation vs none Prod Uners Casing only incorporates deteriorated density Only over open hole sections Only over open hole sections Seawater Gradient .,;';,~;;, 8.6 ppg Pressure at Mudline (offshore) "',:~,,;,;: 0.0 psig onshore or seawater pressure offshore or MGL (onshore) Shoe Depth Pore ressure at Shoe Page 3 of 5 Tiebacks Collapse loads Northstar Bigbore Producer 13-3/8" Surface Casing Collapse loads - Drilling Inputs Value Default Tæe: FulVParlial Evacuation lost circulation, air drilli Lost Returns With Mud Drop I X Mud Weight Mud level lost Returns Depth Pore Pressure @ lost Returns Depth or Pore Pressure EMW @ lost Returns Depth .- .... Mud \'\leu/hi I !J.U Mud Dol) Le~e,rJ;':¡2' Casing Scheme 100% Evacuation Notes limits Based on last open hole section Open hole depth that has greatest mud drop Pressure or EMW Cementing ~ Mud Weight at Shoe :;{9$: Casing Scheme TOC <:..0 ... Casing Scheme lead Slurry Density .\12:2 Cementing and landing Tail Slurry Density .:<t5L9.' Cementing and landing Tail Slurry length ;\750<. Cementing and landing Displacement Ruid Density ';:;'9;5': Cementing and landing Roat Collar Depth b34l3' Cementing and landing Casing Scheme Pore Pressure Ca~.III':J Scht:llle C;:dculat('d Collafse loads - Production Full Evacuation 0 low pressure, gas lift, temperature de~ndent I :<:.'YIToggle AbovelBelow Packer U Packer Depth Production Data Different values below and above the packer Perforation Depth Production Data Pore Pressure at Perforation Depth Pore Pressure Density above Packer' Production Data Density below Packer 0-0 ppg Ruid Drop Above the Packer - - Gas Migration Gas between prod. and intr. Gas Pressure Internal Ruid Density Frac at Shoe Pore Pressure Casing Scheme Frac Gradient at TO between intr. and prod. @ mud at shoe Collafse Loads - External Mud and Cement Mix Water Mud and cement mix water load TOC Mud Weight Cement Mix-Water Densit Casing Scheme Casing Scheme Cement and Landi Permeable Zones Number of Penneable Zones Pore Pressure If no penneable zones specificed in open Zone Geometry Pore Pressure Depths if ooe zone, number if multiple zones hole, same as mud and cement mix-water TOC Casing Scheme profile Prior Shoe Casing Scheme Mud Weight Casing Scheme Deteriated mud has an effect Cement Mix-Water Density Cement and landing Poor Cement To Ie unmarked zonal isolation vs none Mud and Cement Slurry Same as cement load case except can be in other load cases Frac @ Prior Shoe with Gas Gradient Above Gas flow behind casing Ruid Gradients with Pore Pressure L19 Collapse pressures based on pore pressures Mud Weight at Shoe TOC Lead Slurry Density Tail Slurry Density Tail Slurry Len<rth Frac Pressure at Prior Shoe Frac Margin of Errorh' Gas G_radient/Gravity .'~:, Pnor Shoe Depth :.. Fluid Gradient Below Prior Shoe TOC Prior Shoe Mud Weight Above TocL)Qa; Ruid Gradient Below TOC Pore Pressure in ~11 Holel>iìò Casing Scheme Casing Scheme Cementing and landing Cementing and landing Cementino and landi Frac Gradient "'10.0 _¡o.1 psi/ft or 0- 7 SG . Casing Scheme Casino Scheme Casing Scheme Casing Scheme Casing Scheme Casing Scheme no Page 4 of 5 Changing this does not affect other load cases Edit here affects all other edits for this item Tiebacks Mud at Shoe Axial Loads (" \. , . ( Inputs Value Default Notes Limits Northstar Bigbore Producer 13-3/8. Suñace Casing Axial Loads Rlming in Hole Speed(]] RlX\nÏng loads Overpull Force [!] Casing nrnng overpull Rlming SpeedCD2 ftlsec Overpull Force(!QQQQQ]1()O,OOO Ibf Same as above without shock loads Pre-cement Static Load[]] Applies to axial load prior to ant job Applied ForceL:QJJo Ibf Slack off (-) or Pick ~ (+) not part of pick up force Post-cement Static Load[]] Applies to axial load after ant job but prior to ant set Green Cement Pressure Test[]] Pressure test before ant set Test Pressure~o.o psig Affects burst value Service Loads[]] Axial loads during production or injection after cement sets includes psuedo-Ioads from bending or dogleg overides Page 5 of 5 Name: Northstar Bigbore Producer Burst Loads - Drilling !Xl Displacement to Gas Gas Kick Profile Frac @ Shoe with Gas Gradient Above Frac @ Shoe with 1/3 BHP at Surface Lost Returns With Water Surface Protection Pressure Test Green Cement Pressure Test X :X Burst Loads - Production "Xl Tubing Leak Stimulation Surface Leak Injection Down Casing Gas Migration Burst Loads - External Mud and Cement Mix Water Permeable Zones Above/Below Prior Shoe Minimum Formation Pore Pressure Pore Pressure with Seawater Gradient Fluid Gradients with Pore Pressure x Casing Load Inputs Type: 9-5/811 Production Casing Collapse Loads - Drilling ~ Full/Partial Evacuation X. Lost Returns With Mud Drop X Cementing Collapse Loads - Production ~ Full Evacuation X Above/Below Packer Gas Migration Collapse Loads - External r--I Mud and Cement Mix Water Permeable Zones Mud and Cement Slurry Frac @ Prior Shoe with Gas Gradient Above Fluid Gradients with Pore Pressure ~ tJ ~ X L...:...:... Axial Loads . X Running in Hole Speed X Overpull Force X Pre-cement Static Load X Post-cement Static Load . X Green Cement Pressure Test I X Service Loads Page 1 of 5 , .. ( Burst Loads ('" " Northstar Bigbore Producer 9-518" Production Casing Burst Loads - Drilling Inputs Value Default Displacement to Gas X Mud on top of gas Gas Kick Profile ümited kick design Frac 0 Shoe wffh Gas Gradient Above U Gas on top of mud Influx Depth Pore Pressure Gas Gradient/Gravity Frac at Shoe Frac Margin of Error GaslMud Interface Mud Wei Pore Pressure Pore Pressure 0.1 psilft or 0.7 SG Frac Gradient 0.0 ppg Surface .; Casi Scheme Notes LImits Multiple liner designs need review Edit here affects all other edits for this item Multiple liner designs need review Edit here affects all other edits for this item TO of open hole Downhole conditions EMW - OMW Mud at shoe Multiple liner designs need review Edit here affects all other edits for this item Optional Optional R uired if drill collar Ie ifled Influx Depth Kick Volt.me Kick Intensity Maximum Mud Weight Kick Gas Gravity Frac at Shoe Frac Margin of Error Drill Pipe 00 Drill Collar 00 .. Collar Le h ::" Frac at Shoe Frac Gradient Frac Margin of Error 0.0 ppg Gas Gradient/Gravity . . .. 0.1 psi/ft or 0.7 SG Shoe Depth " .":' Multiple liner designs need review Edit here affects all other edits for this item Edit here affects all other edits for this item Frac @ Shoe wffh 1/3 BHP at Surface U Bottom Hole Pressure ::i~;UiiWù" Pore Pressure Pressure based on deepest open hole Surface pressure is 1/3 of BHP Shoe Depth iLU;:¡;;::;,;; Casing Scheme Multiple liner designs need review Frac at Shoe Frac Gradient Multiple liner designs need review Frac Margin of Error 0.0 ppg Edit here affects all other edits for this item Lost Returns With Water Underground blowout with seawater Surface Protection Full displacement of gas with a seawater gradient to surface similar to lost retums with water or displacement to gas Pressure Test X Green Cement Pressure Test W Pressure test before emt set Frac at Shoe Frac Margin of Error' Gas Gradient/Gravity Frac Gradient 0.0 ppg 0.1 psilft or 0.7 SG Multiple liner designs need review Edit here affects all other edits for this item Depth of shoe above open hole section Mud at shoe in dee st 0 n hole Multiple liner designs need review Edit here affects all other edits for this item Edit here affects all other edits for this item Casing Test Pressure 3000' 0.0 psig Mud Weight at Shoe ,. 9;8 ' Casing Scheme TOC 0 Casing Scheme Lead SlurryDensity 13.3 Cementing and Landing Tail Slurry Density 15.9 Cementing and Landing Tail Slurry Length 1154 Cementing and Landing Displacement Auid Density ""9.S;~ Cementing and Landing Aoat Collar Length 12400 Cementing and Landing Shoe de th Affects axial value Burst Loads - Production Tubing Leak X A surface tubing leak over packer fluid Packer Fluid Density ;9.6'; Production Data Packer Depth 141QO Production Data Perforation Depth 14200 Production Data Gas/Oil Gradient or Gas Gravity"~,O.1: '. Production Data Gas default is 0.1 psiift or 0.7 SG Reservoir Pressure '5071 Pore Pressure or Production Data Stimulation Surface Leak 0 Same as tubing leak except for injection Gas Migration U Gas Pressure ', ,i. Pore Pressure atTD Gas between prod. and intr. Internal Fluid Density . Casing Scheme between intr. and prod. @ mud at shoe Frac at Shoe Frac Gradient Burst Loads - External Mud and Cement Mix WaterD TOCc=:=JCasing Scheme Page 2 of 5 Burst Loads Mud and cement mix water BBG LImits Permeable Zones I If no penneable zones specificed in open hole. same as mud and cement mix-water profile AlxJveIBelow Prior Shoe I Split mud weights across casing shoe for liner Default - Casing Scheme Cement and Landi Notes Pore Pressure Pore Pressure Casing Scheme Casing Scheme Casing Scheme Cement and Landing TOQQle unmarked Depths if one zone, number if multiple zones Oeteriated mud has an effeCt zonal isolation vs none Casing Scheme Pore Pressure Cement and Landi Prior Shoe Min EMW in Open Hole Cement Mix-Water Densit-- Prod Liners Minimum Formation Pore Pressure U TOC Casing Scheme Casing only Mud and cement mix water BBG Prior Shoe Casing Scheme Min EMW in Open Hole Pore Pressure Mud Density Casing Schem~~ incorporates deteriorated density Cement Mix-Water Density . Cement and Landing Allow Mud Drop Toggle Only over open hole sections Apply Min EMW in Open Hole at Toggle Only over open hole sections Pore Pressure wit/, Seawater Gradient ¡ Seawater from MSL to mudline and then a linear profile to pore pressure Fluid Gradients with Pore Pressure I X Previous Shoe or Toe. of Cement Seawater Gradient Pressure at Mudline (offshore) or MGL (onshore) Shoe Depth. . Pore pressure at Shoe 8.6 ppg 0.0 psig onshore or seawater pressure offshore Casing Scheme Pore Pressure TOC Prior Shoe Mud Weight Above TOC Ruid Gradient Below TOC Pore Pressure in Open Hole Tiebacks Page 3 of 5 , . ('r (" " Collapse Loads Inputs Value Default Type: Notes limits Northstar Bigbore Producer 9-5I8M Production Casing Collapse Loads - Drilling FulVPartiaf Evacuation Lost circulation, air drilli Lost Returns With Mud Drop X Mud Weight , Mud Level Based on last open hole section Lost Returns Depth Pore Pressure @ Lost Returns Depth or Pore Pressure EMW @ Lost Returns Depth Mud Weight Mud Do Level Open hole depth that has greatest mud drop Pressure or EMW Cementing L!J Mud Weight at Shoe '9.8 Casing Scheme TOC 0' Casing Scheme Lead Slurry Density ,13;3 Cementing and landing Tail Slurry Density 15.9' Cementing and landing Tail Slurry Length 1154 Cementing and landing Displacement Auid Density ,,9:8:, Cementing and landing Aoat Collar Depth ,12400 Cementing and landillQ Collapse Loads - Production Full Evacuation D Low pressure, gas lift, temperature dependent Above/Befow Packer X Different values below and above the packer ~Toggle Packer Depth Perioration Depth Pore Pressure at Perioration Depth Density above Packer Density below Packer Auid Dro Above the Packer ',141()() Production Data 44200 Production Data :'3134: Pore Pressure 9.6 Production Data 0 0.0 ppg S)} ---- Gas Migration U Gas between prod. and intr. at TO between intr. and prod. @ mud at shoe Gas Pressure :""", , Pore Pressure Intemal Auid Densityii1i':':,' Casing Scheme Frac at Shoe Frac Gradient Collapse Loads - External Mud and Cement Mix Water Mud and cement mix water load Permeable Zones If no permeable zones specificed in open hole, same as mud and cement mix-water profile Mud and Cement Slurry Same as cement load case except can be in other load cases TOC Mud Weight Cement Mix-Water Densit Casing Scheme Casing Scheme Cement and Landi Number of Permeable Zones Zone Geometry TOC Prior Shoe Mud Weight Cement Mix-Water Density Poor Cement Pore Pressure Pore Pressure Casing Scheme Casing Scheme Casing Scheme Cement and landing To Ie unmar1<ed zonal isolation vs none Depths if one zone, number if multiple zones Deteriated mud has an effect Frac @ Prior Shoe with Gas Gradient Above U Frac Pressure at Prior Shoe '" Frac Gradient Changing this does OC!t affect other load cases Gas flow behind casing Frac Margin of Error "': ' '", 0.0 Edit here affects all other edits for this item Gas Gradient/Gravity 0.1 psi/ft or 0.7 SG Prior Shoe Depth Casing Scheme Auid Gradient Below Prior Shoe ',. ',':, Casino Scheme Fluid Gradients with Pore Pressure X Collapse pressures based on pore pressures Tiebacks Casing Scheme :3493" Casing Scheme 9.8 Casing Scheme 9.8 Casing Scheme no Mud at Shoe Page 4 of 5 Axial Loads Ineuts Value Default Notes Limits Northstar Bigbore Producer 9-5/8" Production Casing Axial Loads Running in Hole SpeedI]J Runni~ loads Running Speedr:=Ð2 ftlsec Overpull ForceI]J Casing running overpull Pre-cement Static Load[RJ Applies to axial load prior to ant job Overpull ForceJ100000[1O0,OOO Ibf Same as above without shock loads Applied Force~O Ibf Slack off (-) or Pick up (+) not part of pick up force Post-cement Static loadI]J Applies to axial load after ant job but prior to ant set Green Cement Pressure TestI]J Pressure test before ant set Test pressureJ3000 (0.0 psig Affects burst value Service loadsI]J Axial loads during production or injection after cement sets includes psuedo-Ioads from bending or dogleg overides Page 5 of 5 I' ('" Name: Northstar Bigbore Producer Burst Loads - Drilling i~'; Displacement to Gas Gas Kick Profile Frac @ Shoe with Gas Gradient Above 5~: Frac @ Shoe with 1/3 BHP at Surface Lost Returns With Water Surface Protection Pressure Test Green Cement Pressure Test Burst Loads - Production Tubing Leak Stimulation Surface Leak Injection Down Casing Gas Migration Burst Loads - External . Mud and Cement Mix Water Permeable Zones Above/Below Prior Shoe Minimum Formation Pore Pressure Pore Pressure with Seawater Gradient Fluid Gradients with Pore Pressure Casing Load Inputs f \ Type: 711 Production Liner Page 1 of 5 Collapse Loads - Drilling ~....; Full/Partial Evacuation .X. ;. Lost Returns With Mud Drop X Cementing Collapse Loads - Production 1...x...'.....'......~.1 ~~:~~:O~aCker :'.' Gas Migration Collapse Loads - External Mud and Cement Mix Water Permeable Zones Mud and Cement Slurry Frac @ Prior Shoe with Gas Gradient Above Fluid Gradients with Pore Pressure Axial Loads ::1:1' Running in Hole Speed i~! Overpull Force ;i~¡!: Pre-cement Static Load Post-cement Static Load Green Cement Pressure Test Service Loads Burst Loads Northstar Bigbore Producer 7" Production liner Burst Loads - Drillin~ Infouts Value Default Displacement to Gas I X Mud on top of gas Gas Kick Profile Limited kick design Frac @ Shoe with Gas Gradient Above Gas on top of mud Frac @ Shoe with 1/3 BHP at Surface Surface pressure is 1/3 of BHP Lost Returns With Water Underground blowolrt with seawater Surface Protection Full displacement of gas with a seawater gradient to surface similar to lost returns with water or displacement to gas Pressure Testl X Green Cement Pressure Test L!. Pressure test before cmt set Influx Depth Pore Pressure Gas Gradient/Gravity Frac at Shoe Frac Margin of Error GaslMud Interface Mud WeiQht Pore Pressure Pore Pressure 0.1 psilft or 0.7 SG Frac Gradient 0.0 ppg Surface CasifIQ Scheme Notes Limits Multiple liner designs need review Edit here affects all other edits for this item MuHiple liner designs need review Edit here affects all other edits for this item TO of open hole Downhole conditions EMW - OMW Mud at shoe Multiple liner designs need review Edit here affects all other edits for this item Optional Optional Required if drill collar Ie 'lied Multiple liner designs need review Edit here affects all other edits for this item Edit here affects all other edits for this item Pressure based on deepest open hole Mulliple liner designs need review Multiple liner designs need review Edit here affects all other edits for this item Multiple liner designs need review Edit here affects all other edits for this item Depth of shoe above open hole section Mud at shoe in deepest open hole Multiple liner designs need review Edit here affects all other edits for this item Edit here affects all other edits for this item Casing Influx Depth Kick VoIumeL Kick Intensity Maximum Mud Weight Kick Gas Gravity Frac at Shoe Frac Margin of Error Drill Pipe 00 Drill Collar 00 Collar Lel'lQth Casing Scheme 50 bbl 0.5 ppg Casing Scheme 0.7 Frac Gradient 0.0 ppg popular sizes Shoe depth Affects axial value Burst Loads - Production Frac Gradient 0.0 ppg 0.1 psilft or 0.7 SG Pore Pressure Casing Scheme Frac Gradient 0.0 ppg Frac at Shoe Frac Margin of Error Gas Gradient/Gravity Frac Gradient 0.0 ppg 0.1 psi/It or 0.7 SG TubingLeak~ Packer Fluid Density .'.9.6 :.. Production Data A surface tubing leak over packer fluid Packer Depth 14100 Production Data Perforation Depth 14200 Production Data GaslOiIGrac"":rll ',C'I. .:', 01 Production Data Gas default is 0.1 psi/It or 0.7 SG i ': ;'",,: i '" " ", :"',1;1 Pore Pressure or Production Data Stimulation Surface Leak D Same as tubing leak except for injection Gas Migration Gas ileiween prod. and iniL Test Pressure Mud Weight at Shoe TOC lead SIurryDensity Tail Slurry Density Tail Slurry Length Displacement Auid Density Float Collar LenQth 3000 11.3 12330 15.9 0.0 psig Casing Scheme Casing Scheme Cementing and landing Cementing and Landing Cementing and Landing Cementing and Landing CementifIQ and Landi 11.3 13965 Production Data Production Data 0.0 psig 8.33 Burst Loads - External ,... . .~~~~~ssu.~e~~or~Pr;s~ure- IIHemal n\J1U uensny~.. .', . , vasmg ;::>cnerne Frac at ShoeL--JFrac Gradient at TO between intI. and prod. @ mud at shoe Mud and Cement Mix WaterD TOCc=JCasing Scheme Page 2 of 5 Burst loads ( \ , " ( Mud and cement mix water BBG In Mud Weight Cement Mix-Water Notes LImits Permeable Zones U Number of Permeable Zones ".',L::;; Pore Pressure If no penneable zones specificed in open Zone Geometry ,;~t;;; Pore Pressure Depths if one zone. number if multiple zones hole, same as mud and cement mix-water TOC '.' '" Casing Scheme "",' profile PriorShoe :" ,:CO,i,;:: Casing Scheme Mud Weight c,.;~(: Casing Scheme Deteriated mud has an effect Cement Mix-Water Density " ',""," Cement and Landing ,', ,.,. . Poor Cement ,,', ".," Tooole unmarked zonal isolation vs none AboveIBelow Prior Shoe Split mud weights across casing shoe for liner Prior Shoe i,,;~!,;ój Casing Scheme Min EMW in Open Hole Pore Pressure Cement Mix-Water Densi':.n~',% Cement and Landi Prod Uners Minimum Fonnation Pore Pressure Mud and cement mix water BBG TOC ;::'~:;:/;". Casing Scheme Prior Shoe Casing Scheme Min EMW in Open Hole ',:7Ft:: Pore Pressure Mud Density Casing Scheme Cement Mix-Water Density Cement and Landing Allow Mud Drop;:V#hit;t: Toggle Apply Min EMW in Open Hole at ;Ld,i%i::Œ Toggle Previous Shoe or Top of Cement Casing only incorporates deteriorated density Only over open hole sections Only over open hole sections Pore Pressure with Seawater Gradient Seawater from MSL to mudline and then a linear profile to pore pressure Seawater Gradient 8.6 ppg Pressure at Mudline (offshore) :;: j:i:S. 0.0 psig onshore or seawater pressure offshore or MGL (onshore) Shoe Depth ' , ',";', Casing Scheme Pore ressure at Shoe ' ", ': Pore Pressure Fluid Gradients with Pore Pressure X Tiebacks Page 3 of 5 Collapse Loads Northstar Bigbore Producer 7" Production Liner Collapse Loads - Drilling Inputs Value Default Tæe: FulVPartial Evacuation lost circulation, air drilli Lost Returns With Mud Drop I X Mud Weight Mud level Notes LImits Based on last open hole section Open hole depth that has greatest mud drop Pressure or EMW Cementing L!J Mud Weight at Shoe '11;3< Casing Scheme TOC .12330 Casing Scheme lead SillilY [kllsity 1~j.9 Cerrwntu~ alld I <.111<1111\1 Tail ~;Iuny Dml:illy 0 Cementing ,.111<1 l,)IIdul~ Tail Slurry Length 0 , Cementing and Landing Displacement Auid Density "11.3,,, Cementing and Landing Aoat Collar Depth 13965 Cementing and Landing Casing Scheme 100% Evacuation lost Returns Depth Pore Pressure @ lost Returns Depth or Pore Pressure EMW @ lost Returns Depth Mud Weight Mud DOD levell. Casing Scheme "Pore Pressure Collapse loads - Production Full Evacuation 0 low pressure, gas lift, temperature de~ndent 1 "<fToggfe AboveÆelow packerL!J Packer Depth 14100 Production Data Different values below and above the packer Perforation Depth 14200 Production Data Pore Pressure at Perforation Depth :,3007 Pore Pressure Density above Packer 9.6 Production Data Density below Packer 0 , 0.0 ppg Fluid Drop Above the Packer ves --n Gas Migration Gas between prod. and intr. Gas Pressure Intemal Auid Density Frac at Shoe at TO between intr. and prod. @ mud at shoe Col/aese loads - External Mud and Cement Mix Water Mud and cement mix water load Permeable Zones If no penneable zones specificed in open hole, same as mud and cement mix-water profile Mud and Cement Slurry Same as cement load case except can be in other load cases Frac @ Prior Shoe with Gas Gradient Above Gas flow behind casing TOC Mud Weight Cement Mix-Water Densit Casing Scheme Casing Scheme Cement and Landi Depths if one zone, number if multiple zones Deteriated mud has an effect zonal isolation V$ none Changing this does not affect other load cases Edit here affects all other edits for this item Page 4 of 5 Ruid Gradients with Pore Pressure L!J TOC 12330 Casing Scheme Tiebacks Collapse pressures based on pore pressures Prior Shoe 12480 Casing Scheme Mud Weight Above i.", Ii:, ':: """,: I.,: ~, Mud at Shoe Auid Gradient Below" t;:. ", 'I 'J I ,, " Pore Pressure in Open Hole ,no no Number of Penneable Zones Zone Geometry TOC Prior Shoe Mud Weight Cement Mix-Water Density Poor Cement Pore Pressure Pore Pressure Casing Scheme Casing Scheme Casing Scheme Cement and Landing Tooqle unmarked F.., p,",,"," at Prio' Shoe ',:""",'.,',., """,.."',,,,' ,',,',,'.,.', ",'",.,',:",',r<ac G""';en1 Frac Margin of Error '.'.'" '. 0.0 Gas Gradient/Gravity/. . .'". 0.1 psilft or 0.7 SG Prior:'"I::"1 I':.,,',..II~' Fluid Gradient Belo,^ I , I:'",.~:"I'B", Axial Loads (' , , " ' I ( Inputs Value Default Notes LImits Northstar Bigbore Producer 7M Production Liner Axial Loads Rooning in Hole Speed(]j Rooning loads Overpull Force~ Casing ruming overpull Rooning SpeedLB2 ftlsec Overpull Force~100.000 Ibf Same as above without shock loads Pre-cement Static Load[]] Applies to axial load prior to ant job Applied Force~o Ibf Slack off (-) or Pick up (+) not part of pick up force Post-cement Static Load[]] Applies to axial load after emt job but prior to emt set Green Cement Pressure Test[!j Pressure test before ant set Test Pressure~o.o psig Affects burst value Service Loads[!j Axial loads during production or injection after cement sets includes psuedo-Ioads from bending or dogleg overides Page 5 of 5 Name: Northstar Bigbore Producer Burst Loads - Drilling Displacement to Gas Gas Kick Profile Frac @ Shoe with Gas Gradient Above Frac @ Shoe with 1/3 BHP at Surface Lost Returns With Water Surface Protection Pressure Test Green Cement Pressure Test Burst Loads - Production .~ Tubing Leak . Stimulation Surface Leak Injection Down Casing Gas Migration Burst Loads - External Mud and Cement Mix Water Permeable Zones Above/Below Prior Shoe Minimum Formation Pore Pressure Pore Pressure with Seawater Gradient Fluid Gradients with Pore Pressure :x. Casing Load Inputs Type: 4-1/211 Production Liner Collapse Loads - Drilling ~ Full/Partial Evacuation ....... Lost Returns With Mud Drop X Cementing Collapse Loads - Production ~......... Full Evacuation x.. Above/Below Packer Gas Migration Collapse Loads - External Mud and Cement Mix Water Permeable Zones Mud and Cement Slurry Frac @ Prior Shoe with Gas Gradient Above Fluid Gradients with Pore Pressure x Axial Loads X Running in Hole Speed X Overpull Force X Pre-cement Static Load X Post-cement Static Load X Green Cement Pressure Test X Service Loads Page 1 of 5 ~ , .' ( ... Burst Loads ("' \ Northstar Bigbore Producer 4-112" Production Liner Burst Loads - Drilling Inputs Value Default Notes LImits Displacement to Gas U Influx Depth ':,"':'~:".! Pore Pressure Multiple liner designs need review Mud on top of gas Pore Pressure .:.,t'~\:~:. Pore Pressure Gas Gradient/Gravity ., "".', 0.1 psilft or 0.7 SG Edit here affects all other edits for this item :<:::,'~'" Frac at Shoe ";'3#.;~ Frac Gradient Multiple liner designs need review Frac Margin of Error ""',..,,,.,,' 0.0 ppg Edit here affects all other edits for this item .""'",,.. GaslMud Interface ~+~Më\ Surface , Mud Weicht '..' "",'. Casino Scheme ..,,",.,," Gas Kick Profile ümited kick design Frac @ Shoe with Gas Gradient Above Gas on top of mud Influx Depth ;;:i,i~j;gfä Casing Scheme Kick Volume :!f;t!*i!~", 50 bbl Kick Intensity 0.5 ppg Maximum Mud Weight';":>'.: Casing Scheme Kick Gas Gravity:., ,~~, 0.7 Frac at Shoe .' "c,' Frac Gradient Frac Margin of Error 0.0 ppg Drill Pipe 00 ii?:mi)f' popular sizes Drill Collar 00 Collar Le Frac at Shoe ':::.,j¡;;': Frac Gradient Frac Margin of Error". ~<;~ " ,y, 0.0 ppg Gas Gradient/Gravity 0.1 psi/ft or 0.7 SG Shoe De TO of open hole Downhole conditions EMW - OMW Mud at shoe Multiple liner designs need review Edit here affects all other edits for this item Optional Optional R uired if drill collar Ie Multiple liner designs need review Edit here affects all other edits for this item Edit here affects all other edits for this item Frac @ Shoe with 1/3 BHP at Surface U Bottom Hole Pressure "-.,"~,, Pore Pressure Pressure based on deepest open hole Surface pressure is 1/3 of BHP Shoe Depth ""'.::;""', Casing Scheme Multiple liner designs need review Frac at Shoe ," Frac Gradient Multiple liner designs need review Frac Marcin of Error ., ,0.0 ppg Edit here affects all other edits for this item Lost Returns With Water Underground blowout with seawater Frac at Shoe Frac Gradient Frac Margin of Error ,wœ@;;:¡B:; 0.0 ppg MudlWater Interface' , . Casing Scheme MudWei ht '" : ',' Casi Scheme Multiple liner designs need review Edit here affects all other edits for this item Depth of shoe above open hole section Mud at shoe in dee est 0 n hole Surface Protection U Frac at Shoe " "" Frac Gradient Multiple liner designs need review Casing Full displacement of gas with a seawater Frac Margin of Error ',', 0.0 ppg Edit here affects all other edits for this item gradient to surface similar to lost returns with Gas Gradient/Gravity , 0.1 psi/ft or 0.7 SG Edit here affects all other edits for this item water or displacement to gas Pressure Test X Green Cement Pressure Test X Pressure test before emt set 0.0 psig Casing Scheme Casing Scheme . Cementing and Landing Cementing and Landing Cementing and Landing , Cementing and Landing Cementi and Landi Shoe de th Affects axial value Burst Loads - Production Tubing Leak X A surface tubing leak over packer fluid Packer Fluid Density "X:9:ff'!i' Production Data Packer Depth:14tOO: Production Data Perforation Depth!t42()(): Production Data Gas/Oil Gradient or Gas Gravity Production Data Gas default is 0.1 psiift or 0.7 SG Reservoir Pressure 'ii:SO'7li; Pore Pressure or Production Data Stimulation Surface Leak D Packer Fluid Density Production Data Same as tubing leak except for injection Packer Depth Production Data Injection Presure ., 0.0 psig Injection Densitv 8.33 DDa Gas Migration Gas between prod. and intr. Injection Pressure hection Densit Burst Loads - External atTD between intr. and prod. @ mud at shoe Gas Pressure Internal Fluid Density Frac at Shoe Pore Pressure Casing Scheme Frac Gradient Mud and Cement Mix Water 0 TOC~Casing Scheme Page 2 of 5 Burst Loads Mud and cement mix water BBG LImits In uts Value Default Mud Weight Casing Scheme Cement Mix-Water Density Cement and Landi Notes Penneable Zones: If no permeable zones specificed in open hole, same as mud and cement mix-water profile Number of Permeable Zones Zone Geometry TOG Prior Shoe Mud Weight Cement Mix-Water Density Poor Cement Pore Pressure Pore Pressure Casing Scheme Casing Scheme Casing Scheme Cement and Landing T ooole unmarked Depths if one zone, number if multiple zones Deteriated mud has an effect zonal isolation vs none AbovelBelow Prior Shoe Prior Shoe Casing Scheme Prod üners Split mud weights across casing shoe for Min EMW in Open Hole Pore Pressure liner Cement Mix-Water Densit Cement and Landi Minimum Formation Pore Pressure Mud and cement mix water BBG Pore Pressure wfth Seawater Gradient Seawater from MSL to mudline and then a linear profile to pore pressure TOC Prior Shoe Min EMW in Open Hole Mud Density Cement Mix-Water Density Allow Mud Drop Apply Min EMW in Open Hole at Previous Shoe or T 02 of Cement Seawater Gradient Pressure at Mudline (offshore) or MGL (onshore) Shoe Depth' Pore pressure at Shoe Casing Scheme Casing Scheme Pore Pressure Casing Scheme Cement and Landing Toggle Toggle Casing only incorporates deteriorated density Only over open hole sections Only over open hole sections 8.6 ppg 0.0 psig onshore or seawater pressure offshore Casing Scheme Pore Pressure Ruid Gradients wfth Pore Pressure L!J TIebacks ¡c.,; I ;~( ;. 'Ii,.. ,', I, " ',. ! ,. ". ' . " . .'" " Pnor.I",. 1..1',,: ',,',.10', :...': MudWeightAbovE.IC,¡' !I:; :,',:'I"~:"'" Ruid Gradient Ek~l<jw I 0<:: -~.::.!~ - n :1:1 ppr¡ Pore Pressure in Open Ho'c yes no Page 3 of 5 þ '<'" ( \ ( \ Collapse Loads Inputs Value Default Type: Notes Limits Northstar Bigbore Producer 4-1/2" Production Liner Collapse Loads - Drilling FulVPartiaJ Evacuation Lost circulation, air drilli Lost Returns With Mud Drop Mud Weight Mud Level Open hole depth that has greatest mud drop Pressure or EMW Based on last open hole section Lost Returns Depth Pore Pressure @ Lost Returns Depth or Pore Pressure EMW @ Lost Returns Depth Mud Weight~Casing Scheme Mud Dop Level<';-,,<'~~;:'~ Calculated Cementing ~ Mud Weight at Shoe ':>!t3. Casing Scheme TOC :13831 Casing Scheme Lead Siuny Density .]5;9: . Cementing and landing Tail Siuny Density ,, ~O' Cementing and landing Tail Siuny Length 0 Cementing and landing Displacement Auid Density ,, 9.3 Cementing and Landing Roat Collar Depth ;14~.' Cementing and landing Collapse Loads - Production Full Evacuation 0 Low pressure, gas lift, temperature dependent Above/Below Packer X Different values below and above the packer ~Toggle Packer Depth);141()()" Production Data Perforation Depth ¡;1i4~öØ: Production Data Pore Pressure at Perforation Depth ;\$007,\:: Pore Pressure Density above Packer 'iH:9JßU:i Production Data Density below Packer 0.0 ppg Auld Dro Above the Packer Gas MigrationU Gas Pressure Pore Pressure atTD Gas between prod. and intr. Intemal Fluid Density "" " Casing Scheme between intr. and prod. @ mud at shoe Frac at Shoe " Frac Gradient Collapse Loads - External Mud and Cement Mix Water Mud and cement mix water load Casing Scheme Casing Scheme Cement and Landi TOC Mud Weight Cement Mix-Water Densi Permeable Zones U Number of Permeable Zones Pore Pressure If no permeable zones specificed in open Zone Geometry ..,'.' ... . 'Pore Pressure Depths if one zone, number if multiple zones hole, same as mud and cement mix-water TOC . Casing Scheme profile Prior Shoe Casing ,Scheme Mud Weight \. Casing Scheme Deteriated mud has an effect Cement Mix-Water Density ~ Cement and landing Poor Cement Tooale unmarked zonal isolation vs none Mud and Cement Slurry Same as cement load ease except ean be in other load eases Frac @ Prior Shoe with Gas Gradient Above Gas flow behind easing Fluid Gradients with Pore Pressure L!J Collapse pressures based on pore pressures Mud Weight at Shoe TOC Lead Slurry Density Tail Siuny Density Tail Slur Le h Frac Pressure at Prior Shoe Frac Margin of Error Gas Gradient/Gravity Prior Shoe Depth Auid Gradient Below Prior Shoe Changing this does not affect other load eases Edit here affects all other edits for this item TOC ..1.3831 Prior Shoe 14045 Mud Weight Above TOC),9;3 .'. Fluid Gradient Below TOC <>9:3, Pore Pressure in Open Hole'. n<> TIebacks Casing Scheme Casing Scheme Casing Scheme Casing Scheme no Mud at Shoe Page 4 of 5 Axial Loads Infuts Value Default Notes Limits Northstar Bigbore Producer 4-1/2" Production Liner Axial loads Running in Hole Speed{]J Runni!]l loads Running Speed~2 ftlsec Overpull Force{]J Casing running overpull Pre-cement Static Load Œ Applies to axial load prior to Gmt job OverpuU Force 100000 1O0,OOO Ibf Same as above without shock loads Applied Force I o. 'JO Ibf Slack off (-) or Pick up (+) not part of pick up force Post-cement Static Load{]J Applies to axial load after Gmt job but prior to Gmt set Green Cement Pressure Test{]J Pressure test before Gmt set Test pressurel'3000 10.0 psig Affects burst value Service Loads{]J Axial loads during production or injection after cement sets includes psuedo-Ioads from bending or dogleg overides Page 5 of 5 { ~~~1TŒ (ill~ ~~~~[\~ ( ALAS KA 0 IL AND GAS CONSERVATI ON COMMISSION TONY KNOWLES, GOVERNOR 333 W. TH AVENUE. SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Floyd Hernandez Senior Drilling Engineer BP Exploration (Alaska) Inc. PO Box 196612 Anchorage AK 99519-6612 Re: Northstar Unit NS 09 BP Exploration (Alaska) Inc. Permit No: 201-219 Sur Loc: 1129' NSL, 643' WEL, SEC. 11, TI3N, RI3E, UM Btmhole Loc. 458' SNL, 591' EWL, SEC. 18, TI3N, RI4E, UM Dear Mr. Hernandez: Enclosed is the approved application for permit to drill the above referenced well. The permit to drill does not exempt you ftom obtaining additional permits required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permitting determinations are made. Under separate cover, you have requested a waiver of the diverter requirements at 20 AAC 25.035 (c). Your request for waiver of the diverter requirements is granted for NS 09. Annular disposal has not been requested as part of the Permit to Drill application for NS 09. Blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25 035. Sufficient notice (approximately 24 hours) must be given to allow a representative of the Commission to witness a test of BOPE installed prior to drilling new hole. Notice may be given by contacting the Commission petroleum field inspector on the North Slope pager at 659-3607. Sincerely, ~~.~ C~~ fu. Taylor Chair BY ORDER OF THE COMMISSION DATED this~ day of November, 2001 jjcÆnclosures cc: Department ofFish & Game, Habitat Section wlo encl. Department of Environmental Conservation wlo encl. ALAS KA C(' STATE OF ALASKA ~ND GAS CONSERVATION COMMI~ PERMIT TO DRILL 20 AAC 25.005 Jt\AH 111;;310 .¡¡ dl kr \'\. IN Lp.nnth 161' 3361' 11473' 1604' 723' 0 Exploratory 0 Stratigraphic Test II Development Oil 0 Service 0 Development Gas Gtsin~ll~ Zone 0 Multiple Zone 5. Datum Elevation (OF or KB) 10. Field and Pool Planned RKB = 55.7' Northstar Unit 6. Proger!Y Designation AP4 31 m; Y0181 7. Unit or Property Name Northstar Unit 8. Well Number NS09 9. Approximate spud date '\~~I-D I 1~t Amount $200,000.00 14. Number of acres in property 15. Proposed depth (MD and TVD) 2560 13540' MD / 11255' TVD 17. Anticipated pressure {see 20 AAC 25.035 (e) (2)} 0 44.6 Maximum surface 4256 psig, At total depth (TVD) 11200' / 5376 psig Setting Depth T( n Bottom MD TVD MD TVD Surface Surface 201' 201' Surface Surface 3407' 3226' Surface Surface 11513' 9466' 11363' 9333' 12967' 10750' 12811' 10616' 13540' 11256' 11. Type Bond (See 20 AAC 25.025) 1 a. Type of work II Drill 0 Redrill 0 Re-Entry 0 Deepen 2. Name of Operator BP Exploration (Alaska) Inc. 3. Address P.O. Box 196612, Anchorage, Alaska 99519-6612 4. Location of well at surface 1129' NSL, 643' WEL, SEC. 11, T13N, R13E, UM At top of productive interval 458' SNL, 309' EWL, SEC. 18, T13N, R14E, UM At total depth 530' SNL, 591' EWL SEC. 18, T13N, R14E,UM 12. Distance to nearest property line 13. Distance to nearest well ADL 312809,2285' MD NS10 19.22' away at 1049' MD 16. To be completed for deviated wells Kick Off Depth 1800' MD Maximum Hole Angle 18. Casin~ Program Specifications ( Ize Hole Casino Weiaht Grade Counlinn 20" 20" 169# X-56 WELD 16" 13-3/8" 68# L-80 BTC 12-1/4" 9-5/8" 47# L-80 BTC-Mod 8-1/2" 7" 26# L-80 BTC-Mod 6-1/8" 4-1/2" 12.6# 13Cr Vam Ace 1 b. Type of well Number 2S 100302630-277 Ouantitv of :omont (include staae data) Driven 704 sx PF 'L'. 554 sx Class 'G' 566 sx Econolite. 1091 sx 'G' 45 sx Class 'G' 70 sx Class 'G' 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical feet feet feet feet Junk (measured) Plugs (measured) Casing Structural Conductor Surface Intermediate Production Liner Length Size Cemented MD TVD I ~. ¡--.,'., /é""), :",':,<:~." !;' , :, "',",.,"" IJ ::: ',,'I";:,,:::: r:., ""';", , ;:""", ~, ~b"", U",:J.~' I~ ~"q¡ 1 'I '1',11 ", I l:. ?"O:,:lÎi .-.1",," -,c.. ..., l.U"..,,~ Perforation depth: measured true vertical /;':.L~~:'~2: 0;[ I:~:, C:-:¡;:: Cons. O)r;~m¡¡:3¡on i;.;; ¡(\fd~,e 20. Attachments II Filing Fee 0 Property Plat 0 BOP Sketch 0 Diverter Sketch II Drilling Program IBI Drilling Fluid Program 0 Time vs Depth Plot 0 Refraction Analysis 0 Seabed Report 020 AAC 25.050 Requirements Contact Engineer Name/Number: Barbara Holt, 564-5791 Prepared By Name/Number: Sondra Stewman, 564-4750 21. I hereby certify that the foregoing is true and correct to the best of my knowledge Signed Floyd Hernandez "-~~ \~-_.. Title Senior Drilling Engineer Date \ \ \ \'3 i ~ " ',' ,.." " '~'~:,,': ,,>«',;::,::Cô,,"lni:~,¡:~nlJ~~::ØnIY<:::,':",: ,,:,;':::>:,';;, .. ': "". ,.,:>:.,> ."" .,' , ' Permit Number API Number Approval Date See cover letter 2-D I~- 21e¡ 50- D2-CJ ~ 2- 3052 - 6L:) ~h~ d ~ õ~ù \ for other reQuirements Conditions of Approval: Samples Required 0 Yes ~ No Mud Log Requirèd &rYes 0 No Hydrogen Sulfide Measures 0 Yes IE No Directional Survey Required JxrYes 0 No Required Working Pressure for BOPE 0 2K 0 3K 0 4K <JIl5K 0 10K 0 15K 0 3.5K psi for CTU Other: Original Sìgned By ... nl I ,. Commissioner by order of the commission Date)} ';;>3 r Ô J Subtnit In Triplicate Approved Bv Form 10-401 Rev. 12-01-85 ORIGINAL NSO9 Permit to Drill ( f NSO9 Well Plan Summary lJ:ïpe of Well (producer or injector): I Producer I Northstar Slot: NS09 Surface Location: 1129' FSL, 642' FEL, Sec. 11, T13N, R13E, UM X = 659833 Y = 6030901 Target (top of SAG): 4819' FSL, 4884' FEL, Sec. 18, T13N, R14E, UM 250' Radius X = 666098 Y = 6029449 10709' TVDrkb Bottom Hole Location: 4747FSL,4603'FEL,Sec.18,T13N,R14E,UM X = 666381 Y = 6029383 11255' TVDrkb lB!9:.J Nabors 33E l.Qperating days to complete: 142.5 I AFE Number: 1831308 I Estimated Start Date: 111/27/01 1 MD: 113540 I 1 TVDrkb: 1112551 I RKB/Surface Elevation: (a.m.s.l.)--' 55.7' / 15.67' I 1 Well Desig~Jconventional, slimhole, etc.).:..j Modified Big Bore I I ~ective: 1 Ivishak Producer with fiber optic surveillance control line Mud Program: S rf HIM dP S t S dM d 16" HIS r u ace oe u ropertles: eawa er ¡PU U oe eclon From Surface to -3407' MD / 3226' TVD (-150' TVD below top SV6). Interval Density Viscosity VP Tauo Gel API FL pH (ppg) (seconds) 1 0 sec Initial 8.8- 9.0 100 - 200 50 - 70 >8 25 - 40 15 - 20 8.5 - 9.5 from -1555' *9.0 - 9.5 100 - 200 30 - 45 >6 15 - 25 4-10 8.5 - 9.5 SV6 @ Interval TD *9.5 75 -100 20 - 35 >6 1 0 - 25 4-10 8.5 - 9.5 * Should gas hydrates be encountered, mud densities up to 10.2 ppg may prove necessary. I t d. t HIM d P ft. I h"b"t d KCI 12 1/4" HIS r n erme la e oe u rope les: n I I e - oe eclon From Surface Casing Shoe to 11513' MD /9466' TVD (-top Miluveach). Interval Density PV VP Tauo API/ HTTP FL pH Initial 8.7-9.3 10-16 20 - 30 4-7 6-10 8.5 - 9.5 Top HAl 9.6 10 - 16 20 - 25 4-7 4-6/<12 8.5- 9.5 Top Kuparuk to Miluveach 9.8 10 - 18 20 - 28 4-7 4-6/<12 8.5-9.5 Drillin Liner Hole Mud Pro erties: Inhibited KCL 8-1/2" Hole Section From Intermediate Casing Shoe to 12967 MD / 10750' TVD (top of Sag) Interval Densit PV VP Tauo API FL Miluveach & Kin ak to to of Sa 11.3 10 - 25 20 - 25 4 - 7 4-6 / <10 H 8.5 - 9.5 Production Hole Mud Pro erties: Seawater/Barite/CaCOa Drill-In Fluid From Intermediate Casing Shoe to 13540' MD / 11256' TVD Interval Densit PV VP Tauo Initial/Final 9.3 8 - 12 20 - 25 4 - 7 6-1/8" Hole Section API FL 3-5 H 8.5 - 9.5 1 NS09 Permit to Drill (' ~. Directional:(p7) KOP: :t1800' MD Cantenarycurve 3°/100' build Maximum Hole Angle: :t44.6° Close Approach Well: Surface- 10' well spacing with NS10- 9.86' displacement at 40' MD. Gyro will be used for initial surveys and kickoff Survey Program: Gyros as required from surface to +/-1300'. Standard MWD surveys from +/-1300' to TO. DRilliNG CLOSE APPROACH: No close approach issues exist while drilling NS09 except for surface proximity to NS10. NS10 has 19.22' of separation at 1049' MD. NS09 passes anticollision criteria with all wells identified as a "major risk." Gyros will be run from surface to -1300' MD or until reliable MWD surveys can be taken. L . p ogglng rogram: 16" Section: Drilling: G RIDirectional Mud Logging - Gas analysis/detection, show kit with indexed sample bottles, lithology samples (100' intervals) Open Hole: None Cased Hole: None 12-1/4" Section: Drilling: GR/Directional, Res, PWD Mud Logging - Gas analysis/detection, show kit with indexed sample bottles, lithology samples (40' intervals - 20' intervals at shows), Geochem samples from 10544' MDrkb (40' intervals - 20' intervals at shows), CFM (connection flow monitorinQ) Open Hole: RFT pressures only Cased Hole: None 8-1/2" Section: Drilling: GR/Directional, Res, PWD Mud Logging - Gas analysis/detection, show kit with indexed sample bottles, lithology samples (40' intervals - 20' intervals at shows), Geochem samples (40' intervals - 20' intervals at shows), CFM (connection flow monitorinQ) Open Hole: None Cased Hole: None 6-1/8" Section: Drilling: GR/Directional Mud Logging - Gas analysis/detection, show kit with indexed sample bottles, lithology samples (40' intervals - 20' intervals at shows), Geochem samples (40' intervals - 20' intervals at shows), CFM (connection flow monitoring) Open Hole: Quad Combo (GR/Res/Den/Neu/Sonic), AFT pressures only Cased Hole: USIT (after rig release) 2 NSO9 Permit to Drill ( (" Formation Markers: Formation Tops MD TVDss Pore EMW Comments Press. (ppg) (psi) Top Permafrost 1205 1149 517 8.65 Base Permafrost 1556 1499 674 8.65 SV6 3185 3010 1353 8.65 Set surface casing 150' tvd below top of SV6 SV5 3562 3280 1478 8.65 SV4 4011 3600 1620 8.65 SV2 4573 4000 1791 8.65 SV1 5135 4400 1972 8.65 Top Ugnu (UG4A) 5655 4770 2131 8.65 TMBK Top Schrader 7870 6360 2842 8.65 Top Seabee (CM3) 8691 6995 3112 8.65 Colville Shales Top HAl 10754 8740 3874 8.65 Base HRl 10822 8800 3906 8.65 Top Kuparuk 10902 8870 4233 9.29 Hydrocarbon bearing I mainly gas. Top Kuparuk C 11015 8970 4333 9.31 Hydrocarbon bearing I mainly gas. Top Miluveach 11400 9310 4395 9.12 Set intermediate casing into the top of the Miluveach Top Kingak 11989 9830 4690 9.26 Top Sag River 12922 10654 4979 8.95 Set drilling liner into the top of the Sag River to cover up the Kingak. Hydrocarbon bearing. Top Shublik 13019 10740 5023 8.95 Hydrocarbon bearing. Possible loss circulation zone. Top Ivishak 13121 10830 5060 8.95 Hydrocarbon bearing. Possible loss circulation zone. Anticipated OWC 13428 11100 Top Kavik 13484 11150 5212 8.95 Proposed TD 13541 11200 5230 8.95 Top Lisburne 13600 11250 5249 8.95 Possible loss circulation zone c 8 IT b8 P aslng u In 9 rogram: Hole Size Casing! WtlFt Grade Conn Casing Casing Top Hole 8tm Tbg O.D. Length M DrrVDrkb M DITVDrkb 20" 20" 169# X-56 WELD 161' Surface 201'/201' 16" 13 3/8" 68# L-80 BTC 3367' Su rface 3407'/3226' 12 %" 9 5/8" 47# L-80 BTC-Mod 11473' Surface 11513'/9466' 8 Y2" 7" 26# L-80 BTC-Mod 1604' 11363'/9333' 12967'/10750' 6-1/8" 4-1/2" 12.6# 13Cr Vam Ace 723' 12817'/10616' 13540'/11256' Tubing 4-1/2" 12.6# 13Cr Vam Ace 12775' Surface 12815'/10614' Permafrost: The 13-3/8" surface casing will be run approximately 1500' TVD below the permafrost to -3407' MD / 3226' TVD. The casing will be cemented to surface with a Premium 'G' with 2% calcium chloride tail slurry and a Permafrost 'L' lead slurry. The tail slurry allows sufficient compressive strength to prevent the shoe from breaking down as well as an accelerator to decrease thickening time. The lead slurry is light slurry that contains a freezing point depressant which enables the cement to set up rather than freeze. 3 NSO9 Permit to Drill ( ( Cement Calculations: The followin cement calculations are based upon a single stage job. Casin 13-3/8" Surface Basis: Stage 1: Lead: Based on 2658' of Open Hole + 250% excess from the permafrost to surface + 50% excess for the remainder of the hole volume down to 750' above the shoe. Lead TOG: Surface Tail: Based on 750' of 16" open hole x 13 3/8" casing with 50% excess + 80' shoe joint. Tail TOG: -2658' MD Total Cement / S acer Preflush S acer Lead 20 bbl sea water 50 bbl AI ha S acer wei hted to 1.0 over mud wei ht 521 bbl 1704 sk I 2921 ft of 10.7 ppg Permafrost 'L' Cement. 4.15 dIsk, BHST 50° I BHCT 50°, TT = 6.0 hrs 115 bbl I 554 sk I 643 ft of 15.8 ppg Premium 'G' wI 2% CaGb. 1.16 dIsk, BHST 50° I BHGT 50°, TT = 4.0 hrs Tail cement calculations are based upon a single stage cement job. -5/8" Intermediate tage 1 : Lead: Based on 5900' of 12 1/4" open hole x 9 5/8" csg with 30% excess Lead TOG: At -4411' MD 3941' TVD ail: Based on 1613' of 12 %" open hole x 9 5/8" csg with 30% excess + 80' shoe joint. ail TOC: At -9911' MD 8128' TVD tage 1: Total Cement / Spacer Preflush S acer Lead Tail cement calculations are based upon a single stage cement job. -1/2" Prod Liner tage 1: lurry: Based on 573' of 6 1/8" open hole x 4 1/2" csg with 50% excess + 150' 7" csg x 4 1/2" csg liner la 200' 7" csg x 4" drillpipe above TaL + 80' shoe joint. lur TOG: At -12663' MD 10481' TVD ta e 1: Total Cement / S acer Spacer 0 bbl Alpha Spacer weighted to 1.0 pp over mud MW Slurry 18.6 bbl 169.6 sk I 104.4 ft of 15.8 ppg Premium 'G'. 1.50 dIsk, BHST 250° I BHCT 150°, TT = 4.0 hrs 4 NSO9 Permit to Drill ( (' Well Control: ~ A Diverter waiver has been requested on NS09. To date, BP has drilled six development wells through the Northstar upper stratagraphic intervals and has not experienced any difficulty with shallow gas. All six surface holes have been drilled and cemented to a common depth of approximately 3,170' tvdss depth. Each surface shoe has been set in the competent shale horizon approximately 150' TVD below the top of the SV6 formation marker. Well mud logs and seismic data do not indicate the presence of a shallow gas hazard. ~ Equipment to be Installed and capable of handling maximum potential surface pressures ~ 5000 psi working pressure pipe rams (2) ~ Blind/shear rams ~ Annular preventer ~ Based upon the calculations below, BOP equipment will be tested to 5000 psi. Suñace Section: . Maximum anticipated BHP: 1379 psi @ 3010' TVDss - SV6 . Maximum surface pressure: 1078 psi @ surface (Based on BHP and a full column of gas from TD @ 0.10 psi/ft) Intermediate Section: . Maximum anticipated BHP: 4333 psi @ 8970' TVDss - Kuparuk IC' . Maximum surface pressure: 3436 psi @ surface (Based on BHP and a full column of gas from TD @ 0.10 psi/ft) Drilling Liner Section: . Maximum anticipated BHP: 4984 psi @ 10654' TVDss - Sag River . Maximum surface pressure: 3919 psi @ surface (Based on BHP and a full column of gas from TD @ 0.10 psi/ft) Production Section: . Maximum anticipated BHP: 5376 psi @ 11200' TVDss - Total Depth . Maximum surface pressure: 4256 psi @ surface (Based on BHP and a full column of gas from TO @ 0.10 psi/ft) . Planned BOP test pressure: 5000 psi (annular to 3500 psi) . Planned completion fluid: 8.5 ppg Seawater /6.8 ppg Diesel Dri II i ng Hazards/Conti ngencies: HYDROGEN SULFIDE - H2S: ./' Northstar is not designated as an H2S drill site, however Standard Operating Procedures for H2S precautions should be followed at all times. ./' No H2S was detected at Northstar while drilling or testing the Seal Island A-01, A-02, or A-03 exploration/appraisal wells. ./' No H2S was detected while drilling the NS10 waste disposal well, NS27, NS29, NS31 or NS13. Reference information below on file with AOGCC: ~ Northstar/Nabors 33E H2S contingency plan. ~ Well test hydrocarbon analyses for Seal Island A-O1, A-O2, and A-O3. DISPOSAL: Annular Injection: There will be no annular injection in this well. Cuttings Handling: Cuttings generated from drilling operations will be processed in the Grind and Inject Facility on Nabors 33E and will be disposed of in the NS10 Class I Waste Disposal Well. Fluid Handling: All Class I and Class II fluids will be processed by the Grind and Inject Facility on Nabors 33E and will be disposed of in the Northstar NS1 0 Class I Waste Disposal Well. 5 NSO9 Permit to Drill (' ( SUMMARY DRilliNG OPERATIONS Pre-RiQ Work: 1. Set 20" conductor and weld an ABB Vetco landing ring for the ABB Vetco Multibowl Wellhead on the conductor. (Already performed.) 2. Install 7' x 7' cellar and polyshield same. (Already performed.) Ria Operations: 1. MIRU Nabors 33E. 2. Nipple up and function test 21-1/4" diverter system, if required. NOTE: A diverter dispensation has been requested. Confirm dispensation decision with the Drilling Engineer. 3. MU 16" drilling assembly with MWD/GR and directionally drill surface hole to +/-150' TVD below the top of the SV6 marker at approximately 3185' MD. POOH. 4. Run 13-3/8", 68# surface casing. Cement the casing to surface in 1 stage. A TAM port collar will be run at +/- 1600' MD. In the event the cement does not circulate to surface, this port collar will be utilized to ensure a successful cement job is performed. 5. ND diverter / riser system and NU casing / multi-bowl wellhead. NU BOPE and test to 250/5000 psi. 6. MU 12-1/4" directional assembly. RIH to float collar. Test the 13-3/8" casing to 3500 psi with 9.3-ppg mud for 30 min. This test pressure may change based on actual mud weight in the hole. 7. Drill out remaining cement. Drill 20' of new formation below 13-3/8" shoe and perform FIT to 12.5 ppg. (FIT/LOT procedure on file with AOGCC). 8. Drill 12-1/4" intermediate hole to casing point (approximately 11 ,514'MD) at the top of the Miluveach. Minimum mud weight of 9.6 ppg at the top of HRl and 9.8 ppg at the top of Kuparuk. POOH. 9. RU Schlumberger. Run open hole RFT's for pressures only. POOH and RD Schlumberger. 10. Make a clean out run, if required, and condition the hole for casing. POOH. 11. Run 9-5/8", 47# intermediate casing. Cement the casing to the top of the SV2 sand in a single stage. Set the 9 5/8" pack off. Perform a down-squeeze on the 9-5/8" x 13-3/8" annulus with 1 annular volume of mud upon installing and testing the packoff. Down-squeeze diesel to 2000' MD for freeze protection after WOC. 12. MU 8-1/2" directional assembly and RIH to float collar. Pressure-test the 9-5/8" casing to 4300 psi with 9.8 ppg mud for 30 min. This test pressure may change based on the actual mud weight in the hole. 13. Drill out remaining cement. Drill 20' of new formation below 9-5/8" shoe and perform a Leak Off Test. (FIT/LOT procedure on file with AOGCC). 14. Weight up to 11.3 ppg prior to drilling ahead. Drill the drilling liner hole to the top of the Sag at approximately 12922' MD. POOH. 15. Run and cement a 7" 26# drilling liner. Set the liner hanger and liner top packer. Circulate off any excess cement. POOH with liner setting string. 16. RIH w/ 6-1/8" directional assembly and clean out to the landing collar. Pressure-test the liner to a minimum of 500 psi over the leak off pressure. This would be 3700 psi with 11.3-ppg mud assuming a LOT of 14.5 ppg. This test pressure may change based on the actual mud weight in the hole and the actual LOT. 17. Drill out remaining cement. Drill 20' of new formation below 9-5/8" shoe with 11.3-ppg mud and perform a Formation Integrity test. (FIT/LOT procedure on file with AOGCC). Since the mud weight will be lowered to 9.3 ppg after the FIT, monitor the wellbore for 10 minutes. If no losses occur, displace with the 9.3 ppg drill-in fluid. 18. Drill 6-1/8" production interval to the proposed TD at 13540' MD. POOH. 19. RU Schlumberger E-line unit. Run open logs (GR/RES/NEU/DEN/Sonic/RFT) in two logging runs. POOH and RD Schlumberger. 6 NS09 Permit to Drill ( f 20. Make a clean out run, if required, and condition the hole for a liner. POOH. 21. Run and cement the 4-1/2" 12.6# 13Cr liner. Set the liner hanger and liner top packer. Circulate off any excess cement. POOH with liner setting tool. 22. Close the blind rams and pressure-test the liner lap to 3400 psi with 9.3 ppg fluid in the well for 30 minutes. 23. Cleanout the 4 ¥2" liner to the float collar. Wash down and circulate prior to displacing to seawater. 24. Circulate to clean seawater (less than 40 NTU's) using spacers as per Bariod recommendation 25. POOH with the clean out assembly and prepare to run the 4 ¥2" completion. 26. Run the 4 ¥2", 13Cr Vam Ace completion assembly with CIDRA fiber optics. The fiber optic cable will be run from packer setting depth to surface. 27. RIH to packer setting depth. Dual SSSV control lines will be run from the SVLN at +1- 2000' TVD (2002' MD) to surface. 28. Run space out pups and terminate the 2 - 0.25" control lines and 0.25" fiber optic line. All lines will be secured using collar cable clamps. Pressure test the control lines and tubing hanger seals. Function test the fiber optic line. 29. Set the TWC. ND BOP's. NU Tree. Test the tubing head adapter and tree to 5000 psi. 30. Circulate in corrosion inhibitor. 31. Set packer. Increase the tubing pressure to 4200 psi (maximum anticipated surface pressure) with 8.65-ppg completion fluid and hold for 30 minutes. Monitor tubing pressure for leaks. Record on chart. 32. Contact AOGCC andlor MMS inspector to witness test. Bleed tubing to 3000 psi and maintain during MIT. Pressure test annulus to 4200 psi (maximum anticipated surface pressure) with 8.65 ppg completion fluid for AOGCC/MMS required mechanical integrity test (MIT). Monitor tubing pressure for leaks. Maintain pressure for 30 minutes and record as annulus test on chart. Email or fax chart and AOGCC/MMS MIT form to Drilling Engineer. 33. Bleed down the annulus to 3500 psi. Bleed down the tubing to 0 psi. This will shear the RP valve. 34. Pump diesel down the 4 ¥2" x 9 5/8" annulus equivalent to the annulus capacity plus tubing capacity to a depth of 4000' TVD (4494' MD). 35. RU the U-tubing manifold and allow the Freeze Protection fluid to u-tube through the GLM. 36. Bleed off annulus to 0 psi. Ensure both the tubing and annulus pressures are 0 psi. 37. Install (dry rod in) BPV. Ensure all valves are closed. RD and move off well. Post-RiQ Work: 1. MIRU slickline. Pull the ball and rod I RHC profile from 'XN' nipple below the new production packer. 2. MIRU Schlumberger Wireline. Run USIT. RD Schlumberger Wireline. 3. Perforate interval based on PE recommendation. Estimated Spud Date: November 27, 2001 Barbara M. Holt Operations Drilling Engineer 564-5791 7 NSO9 Permit to Drill { (, SURFACE HOLE SECTION: . Mudloggers will be rigged up throughout the entire section. No significant drilling problems have been identified in the surface hole interval based on offset data. Good hole cleaning and management of required mud properties are key to a successful interval. Minor tight hole conditions have been noted in the shale intervals immediately below the permafrost during short trips. Differential sticking could be problematic in this hole section adjacent to the permeable SV Sands. Avoid leaving drill string stationary for extended periods, tighten fluid loss properties of mud, and string in Barofibre as required prior to penetrating sand intervals. Lost circulation has only been noted while drilling during hole opening runs and was most likely induced by poor hole cleaning. Losses have occurred while running and cementing surface casing. The NS27 experienced losses on the surface cement job at a rate of 12 BPM. The displacement rate was lowered to 10 BPM and full returns were re-established. Be sure to condition and thin mud appropriately prior to pulling out of the hole to run casing, and once on bottom with casing, bring circulation up slowly and reduce mud viscosities before pumping cement. Minor losses were seen on NS29 while running the 13 3/8" surface casing. Reduced running speed eliminated losses and the casing was cemented at 10 BPM displacement rate. Hole stabilization in the shallow unconsolidated intervals can be problematic if mud properties are relaxed. Hi viscosities as used elsewhere on the North Slope should be sufficient to control any potential running gravels. Gas hydrates may be present near the base of the permafrost. Wells drilled in the 2000-2001 drilling season have not experienced hydrates. Mudloggers will be used continuously on NS09 to help identify and trend any increase in background gas readings. If gas hydrates are encountered, mud weight may be increased to 10.2 ppg and treated with 2 ppb Oriltreat (Lecithin). Additional measures include reducing flow rates to -450 to 500 gpm and keeping the mud temperature cool. . . . . . . INTERMEDIATE SECTION: . Mudloggers will be rigged up throughout the entire section. Minor gas shows have been reported in the four (4) Seal Island wells and have been identified as coal associated methane. No indications of shallow gas were seen while drilling during the 2000-2001 drilling season. Mudloggers will be used continuously on this well to help identify and trend any increase in background gas readings. Surface casing will be set prior to any intervals with previously noted gas shows to facilitate nippling up the BOP's. A minimum of 9.0 ppg is recommended. The shallow intervals beneath Northstar are, by interpretation, not faulted. However, if faults are encountered, the possibility of losses still exists. To be prepared for any potential lost circulation, a copy of the 'Lost Circulation Decision Tree' can be found in the last section of the Master Well Plan, which can be found on the rig. Pressure While Drilling (PWD) will be used to monitor the annular pressure. The pressure data will be used to minimize the equivalent circulating density (ECO), minimize lost circulation due to packing off due to loading up the well bore with solids and provide for an additional well control tool to make sure the well does not become under-balanced. Differential sticking can 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 SV Sands. Gas in the Kuparuk is likely (5000 unit mud log show in NS13). Circulate as required. High mud weight should minimize the gas entry from the Kuparuk. The kick tolerance for the 12 1/4" open hole section would be 78 bbls assuming an influx from the Kuparuk interval at -9466' TVD. This is the worst-case scenario based on a 9.73 ppg (0.5 ppg over the known pore pressure) pore pressure gradient, a fracture gradient (based on a FIT) of 12.5 ppg at the 13-3/8" shoe, and 9.8 ppg mud in the hole. . . . . . . 8 NS09 Permit to Drill ( ( DRilliNG liNER SECTION: . Mudloggers will be rigged up throughout the entire section. The directional targets has been designed to intersect a fault at the top of the Kingak interval. To be prepared for any potential lost circulation, a copy of the 'Lost Circulation Decision Tree' can be found in the last section of the Master Well Plan, which can be found on the Rig. Pressure While Drilling (PWD) will be used to monitor the annular pressure. The pressure data will be used to minimize the equivalent circulating density (ECD), minimize lost circulation due to packing off due to loading up the wellbore with solids and provide for an additional well control tool to make sure the well does not become under-balanced. Full returns were lost while weighting up the mud system from 11.3 ppg to 11.6 ppg on NS27. PWD indicated an on bottom ECD of 11.8 ppg when the losses occurred. The new casing design isolates the weaker formations above by top setting in the Miluveach. Though initial mud weight will be 11.3 ppg, the new casing design allows flexibility to increase mud weight, as required, in the Jurassic shale interval. Gas in the SAG is possible. Circulate as required. According to Geology, the top of the SAG is poor, not porous/permeable rock. This, along with the higher mud weight should minimize the gas in the top of the SAG. The kick tolerance for the 8-1/2" open hole section is infinite (due to limited amount of open hole) assuming an influx from the Sag River interval. This is the worst-case scenario based on a 9.62 ppg (0.5 ppg over the anticipated pore pressure) pore pressure gradient, a fracture gradient of 12.5 ppg at the 9-5/8" shoe, and 11.3 ppg mud in the hole. . . . . . PRODUCTION SECTION: . Mudloggers will be rigged up throughout the entire section. Gas in the Sag River or Ivishak will be circulated out as required. The drilling liner shoe will be drilled out with the 11.3 ppg mud. The mud will then be displaced with a 9.3 ppg drill-in fluid. Differential sticking is not anticipated but the drill string should not be left stationary for any length of time. Losses are not expected but calcium carbonate (CaCO3) will be maintained in the system. Severe lost circulation was encountered on the NS29. A copy of the 'Lost Circulation Decision Tree' can be found in the last section of the Master Well Plan. The Ivishak is a conglomerate section. Directional control will be maintained with MWD surveys to minimize doglegs. The well is not planned to penetrate the Lisburne limestone. On offset wells, losses have been encountered in the Lisburne. The project Geologist will be in charge of picking the base of the Ivishak and only rathole sufficient to bury the open hole logs will be drilled. However, if the Lisburne is penetrated, the LCM Decision Tree will be in place on the rig. The kick tolerance for the 6 1/8" open hole section is infinite (due to limited amount of open hole) assuming an influx from the proposed TO. This scenario is based on a 9.69 ppg (0.5 ppg over the anticipated pore pressure) pore pressure gradient, a fracture gradient of 11.3 ppg (based on FIT) at the 7" shoe, and 9.3 ppg mud in the hole. . . . . . . 9 ( ( NS09 Permit to Drill NSO9 Riq-site SUmmary of DrillinQ Hazards POST THIS NOTICE IN THE DOGHOUSE ...¡ Gas hydrates may be present near the base of the permafrost. Mudloggers will be used continuously on NSO9 to help identify and trend any increase in background gas readings. If gas hydrates are encountered, mud weight may be increased to 10.2 ppg and treated with 2 ppb Driltreat (Lecithin). Additional measures include reducing flow rates to -450 to 500 gpm and keeping the mud temperature cool. ...¡ Differential sticking could be problematic in both the surface and intermediate hole sections adjacent to the permeable SV Sands. Avoid leaving drill string stationary for extended periods, tighten fluid loss properties of mud, and string in Barofibre prior to penetrating sand intervals. ...¡ Minor gas shows have been reported in the four (4) Seal Island wells and have been identified as coal associated methane. No indication of shallow gas was seen in NS10, NS27, NS29, NS31, or NS13. Mudloggers will be used continuously on NSO9 to help identify and trend any increase in background gas readings. Surface casing will be set prior to any intervals with previously noted gas shows to facilitate nippling up the BOP's. ...¡ Severe losses have been seen in the intermediate section with a higher mud weight (11.6 ppg). The well design has been changed to alleviate this problem. The new casing design sets the 9 5/8" casing in the Miluveach and drills out with an 8 Y2" assembly to the Top Sag to allow an appropriate cushion for mud weight increases in the Jurassic shale interval. To be prepared for any potential lost circulation, the 'Lost Circulation Decision Tree' can be found in the last section of the Master Well Plan, which can be found on the Rig. ...¡ Packing off due to improper hole cleaning can lead to stuck pipe. The PWD data, pick- up/slack-off weights and other drilling parameters must be monitored at all times. If in doubt, stop and condition the hole prior to drilling ahead or tripping. ...¡ Bit balling on the NS29 was experienced in the Miluveach. The mud properties and PDC bit selection will be closely monitored to minimize potential balling. ...¡ The Kingak shale, in the offset Seal Island wells drilled by Shell, experienced severe hole instability. The casing shoe at the base of the Kuparuk, higher mud weight and lower angles will help with hole conditions. ...¡ Conglomerate drilling in the Ivishak can lead to lost circulation, packing off due to unconsolidated formation and directional problems due to deflection of the drill string off of large rocks. Key drilling parameters must be monitored at all times. Do not drill ahead if a potential problem is detected. Severe lost returns were experienced on the NS29 in the Shublik and Ivishak. The LCM decision tree will be maintained on the rig as well as in the Master Well Plan. ...¡ Northstar is not a designated H2S pad. ~ CONSULT THE NORTHSTAR PAD DATA SHEET AND THE WELL PLAN FOR ADDITIONAL INFORMATION 10 /' ( ORIl5INAL KB. ELEV = 55.77' KB-BF. ELEV = 40.2' ca. ELEV = 15.57' SSV @ 2000' M D wi HXO SVLN nipple - 3.813- ID 6.8PPG DIESEL FREEZE PROTECTION AT +1- 4000' TVD (4494'MD) 4.5" GLM @ 4500' TVD (5130' M D) wi 3.833" ID TREE: ABB-VGI 5 1/8" 5ksi WELLHEAD: ABB-VGI13-5/S" Multibowl5ksi 13 3/S" TAM Port Collar at +1-1600'MD 13 3/S", 6S#/ft. L-SO, BTC @ 3407' 4.5", 12.6#/ft, 13-Cr, Yam Ace TUBING 10: 3.95S" CAPACITY: 0.01522 BBLIFT 9-5/8" 47# L-8D BTM-C @ 11513' 4.5" X NIPPLE, @ 12762" 3.S13" ID 4.5" X NIPPLE, @ 12787' 3.S13" 10 4.5" XN NIPPLE, @ 12S00' 3.725" 10 4.5"WLEG,@ 12815' 3.958" 10 7", 26#/ft L-SO, BTC-M @ 12967' PBTO @ 13460' TO @ 13540' OATE REV. BY BMH 11 5 01 NSO9 - Proposed - 7" LINER TOP @ 11363' 4.5" Fiber Optic Transducer 3.958" 10 COMMENTS 4.5" LINER TOP @ 12S17' Proposed Perforation Interval: 13,115'-13,307'MO 10,880' - 11,050' TVO 4.5", 12.6#. 13Cr Yam Ace Northstar WELL:NS09 API NO: BP Exploration (Alaska) ~C!- ,/ ,7 t. ./ ( ( United States Department of the Interior Enclosure MINERALS MANAGEMENT SERVICE Alaska Outer Continental Shelf Region 949 East 36th Avenue, Suite 308 Anchorage, Alaska 99508-4363 1 5 NOV 20m Esther Fueg Data Manager BP Exploration (Alaska) Inc.' 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 Reference: Request to Change the Well Log Reporting Requirements for Federal Wells for the Northstar Project Dear Ms. Fueg: Regarding your request to have the well data requirements modified for Northstar Project's Federal wells, we agree to the following modifications to our well data requirements: Well Log requirements for Federal wells 1. Submit final composites with reproducible sepias and digital copies for the mudlog, Measurement While Drilling (MWD), and engineering logs within thirty (30) days of completion. 2. Wireline and other logs not collected while drilling shall also be submitted within thirty (30) days of completion. 3. Final Composite Prints include: One paper copy (Blueline) One Sepia One digital copy on CD-ROM (For the Mudlog, please submit a *.pdf file) We still require a sepia copy of all final well logs and mudlogs. The requirement for Daily Mudlogs and MWD logs is dropped. If you have any additional questions please call Douglas Choromanski at (907) 271-6448. Sincerely, . ~\w~' IJe ~a~r , Re ional Supervisor Field Operations .r ( ( Oilfield Services, Alaska Schlumberger Drilling & Measurements ScblullblPUIf 3940 Arctic Blvd, Site 300 Anchorage, AK 99503 Tel (907) 273-1766 Fax (907) 561-8357 Wednesday, October 24,2001 Barbara Holt Northstar NS09 (P7) Alaska Drilling & Wells Close Approach Analysis We have examined the potential intersections of subject well with all other potentially conflicting wells, according to the BPA Directional Survey handbook (BPA-D-004) dated 09/99. Nabors 33E Method of analysis: 1. A list of wells to be analyzed is created in Compass by performing a global scan with an initial search radius of two thousand feet with an increment of one hundred feet for every one thousClld feet of measured depth in the subject well. 2. Wells are analyzed using the Compass Anti-collision module (BP Company setup) with major risk safety factors applied. For problem wells that are plugged and abandoned or that can be shut in, risk-based safety factor may be used, with client notification. 3. All depths are relative to the planned well profile. Survey Program: Instrument Type GYD-GC-SS MWD - Standard (declination corrected) Start Depth 40.20' md 1 ,300' md End Depth 1 ,300' md 13,540.41' md Close Approach Analysis results: Under method (2), all wells may flow, however see notes below. . Note1: In reference to NS10, the island's waist disposal well, the closest approach is at 1,049'md with an allowable deviation of 2.5' under the conventional rule. Since the well cannot be shut in during drilling operations on the island, great care will need to be used in drilling from surface to 1500'md on the planned well. All data documenting these procedures is available for inspection at the Anadrill Directional Planning Center. Close Approach Drilling Aids to be provided: A drilling map, with offset wells on the plan view, and traveling cylinder will be provided. Checked by: Scott DeLapp 10/24/01 NSO9 Schlumbørgør Proposed Well Profile - Geodetic Report Report Date: Client: FIeld: Structure I Slot: Well: Borehole: UWUAPII: Survey Name I Date: Tort I AHD I 0011 ERD ratio: Grid Coordinate System: LOCItIon LltlLong: Location Grid HIE YIX: Grid Convergence Angle: Grid Scale Factor: October5,2001 Alaska Drilling & Wells Northstar =tar PF f NS09 d 1 0/ :- APprove NS09(P7)/~ber24,2001 71.192° 16722.89 ft 15.760 I 0.597 NAD27 Alaska State Planes, Zone 4, US Fool N 70.49096864, W 148.6932815€ N 6030901.760 ftUS, E 659833.490 ftUS +1.23172211° 0.99992902 Survey I DLS Computation Method: Vertical SectIon AzImuth: Vertical SectIon Origin: TVD Reference Datum: TVD Reference Elevation: Sea Bed I Ground Level Elevation: Magnetic Declination: Total FIeld Strength: Magnetic Dip: Declination Date: Magnetic Declination Model: North Reference: Total Corr Mag North -> True North: Local Coordinates Referenced To: Minimum Curvature I Lubinski 104.290° N 0.000 ft, E 0.000 ft KB 55.77 ft relative to MSL 15.670 ft relative to MSL 26.589° 57494.708 nT 80.916° December 12, 2001 BGGM 2000 True North +26.589° Well Head -~, StatIon 10 Ie Coordlnatn Incl I Azlm I TVD I VSee I NI-6 I EJ.W I DLS I Northing I Ealtlng I LatJtu de I longitude i I a.o-ö --- -- 0.00-----0.00 ____un <UfO - 0.00 6030901.76 659833.49 N 70.49096864 W 148.69328156 800.00 0.00 0.00 0.00 0.00 6030901.76 659833.49 N 70.49096864 W 148.69328156 899.99 0.85 0.00 0.87 1.00 6030901.78 659834.36 N 70.49096864 W 148.69327445 999.96 3.38 0.00 3.49 1.00 6030901.84 659836.98 N 70.49096864 W 148.69325304 1099.86 7.61 0.00 7.85 1.00 6030901.93 659841.34 N 70.49096864 W 148.69321740 1200.00 4.00 90.00 1199.68 13.53 0.00 13.96 1.00 6030902.06 659847.45 N 70.49096864 W 148.69316745 1205.11 4.05 90.00 1204.77 13.87 0.00 14.32 1.00 6030902.07 659847.81 N 70.49096864 W 148.69316451 1300.00 5.00 90.00 1299.37 21.13 0.00 21.80 1.00 6030902.23 659855.28 N 70.49096864 W 148.69310337 1400.00 4.00 90.00 1399.06 28.73 0.00 29.65 1.00 6030902.40 659863.13 N 70.49096864 W 148.69303920 1500.00 3.00 90.00 1498.87 34.65 0.00 35.75 1.00 6030902.53 659869.23 N 70.49096864 W 148.69298934 .~ 1555.96 2.44 90.00 1554.77 37.22 0.00 38.41 1.00 6030902.59 659871.89 N 70.49096864 W 148.69296760 1600.00 2.00 90.00 1598.77 38.87 0.00 40.12 1.00 6030902.62 659873.60 N 70.49096864 W 148.69295362 1700.00 1.00 90.00 1698.74 41.41 0.00 42.73 1.00 6030902.68 659876.21 N 70.49096864 W 148.69293228 1800.00 0.00 104.38 1798.73 42.26 0.00 43.61 1.00 6030902.70 659877.09 N 70.49096864 W 148.69292509 1900.00 3.00 104.38 1898.69 44.87 -0.65 46.14 3.00 6030902.10 659879.63 N 70.49096686 W 148.69290441 2000.00 6.00 104.38 1998.37 52.72 -2.60 53.74 3.00 6030900.32 659887.27 N 70.49096153 W 148.69284229 2100.00 9.00 104.38 2097.50 65.77 -5.84 66.38 3.00 6030897.35 659899.98 N 70.49095268 W 148.69273897 2200.00 12.00 104.38 2195.81 83.99 -10.37 84.03 3.00 6030893.20 659917.72 N 70.49094031 W 148.69259470 2300.00 15.00 104.38 2293.04 107.33 -16.17 106.64 3.00 6030887.89 659940.45 N 70.49092446 W 148.69240988 2400.00 18.00 104.38 2388.91 135.73 -23.22 134.15 3.00 6030881.43 659968.10 N 70.49090520 W 148.69218501 KB Bid 1/100 Top Permafrost Drp 1/100 Base Permafrost KOP Build 3/100 NS09 (P7) report.xls Page 1 of 3 10/25/2001-10:27 AM Geogl"lphlc Coordlnlttl StatIon I D I MD NloS I EI.W I DLS I Northing I Elating I latitude I Longitude ft ft 2500.00 21.00 104.38 2483.16 169.11 -31.51 166.48 3.00 6030873.84 660000.60 N 70.49088255 W 148.69192074 2600.00 24.00 104.38 2575.54 207.37 -41.02 203.55 3.00 6030865.13 660037.86 N 70.49085657 W 148.69161773 2700.00 27.00 104.38 2665.79 250.42 -51.71 245.24 3.00 6030855.34 660079.77 N 70.49082736 W 148.69127696 2800.00 30.00 104.38 2753.66 298.13 -63.57 291.46 3.00 6030844.47 660126.23 N 70.49079496 W 148.69089916 2900.00 33.00 104.38 2838.92 350.37 - 76.54 342.06 3.00 6030832.60 660177.09 N 70.49075952 W 148.69048556 3000.00 36.00 104.38 2921.32 407.01 -90.61 396.92 3.00 6030819.71 660232.24 N 70.49072107 W 148.69003714 3100.00 39.00 104.38 3000.64 467.88 -105.74 455.88 3.00 6030805.85 660291.50 N 70.49067973 W 148.68955520 SV6 3185.37 41.56 104.38 3065.77 523.07 -119.45 509.34 3.00 6030793.29 660345.24 N 70.49064227 W 148.68911823 3200.00 42.00 104.38 3076.68 532.81 -121.87 518.78 3.00 6030791.08 660354.73 N 70.49063566 W 148.68904107 End Bid 3286.53 44.60 104.38 3139.65 592.15 -136.61 576.26 3.00 6030777.58 660412.51 N 70.49059538 W 148.68857124 13-3/8" Csg Pt 3407.48 44.60 104.38 3225.77 677.07 -157.70 658.51 0.00 6030758.26 660495.19 N 70.49053774 W 148.68789894 ,~ SV5 3561.95 44.60 104.38 3335.77 785.52 -184.65 763.57 0.00 6030733.58 660600.80 N 70.49046409 W 148.68704021 SV4 4011.34 44.60 104.38 3655.77 1101.04 -263.03 1069.20 0.00 6030661.79 660908.02 N 70.49024987 W 148.68454211 SV2 4573.08 44.60 104.38 4055.77 1495.44 -361.01 1451.23 0.00 6030572.05 661292.04 N 70.48998202 W 148.68141962 SV1 5134.82 44.60 104.38 4455.77 1889.84 -458.99 1833.27 0.00 6030482.31 661676.07 N 70.48971412 W 148.67829714 TMBK 5654.43 44.60 104.38 4825.77 2254.65 -549.62 2186.65 0.00 6030399.31 662031.29 N 70.48946627 W 148.67540897 Drp 0.5/100 7222.84 44.60 104.38 5942.60 3355.84 -823.19 3253.31 0.00 6030148.75 663103.50 N 70.48871785 W 148.66669160 7300.00 44.21 104.38 5997.72 3409.83 -836.60 3305.61 0.50 6030136.47 663156.08 N 70.48868116 W 148.66626419 7400.00 43.71 104.38 6069.71 3479.24 -853.85 3372.85 0.50 6030120.67 663223.67 N 70.48863395 W 148.66571469 7500.00 43.21 104.38 6142.29 3548.03 -870.93 3439.48 0.50 6030105.02 663290.64 N 70.48858720 W 148.66517017 7600.00 42.71 104.38 6215.47 3616.18 -887.86 3505.49 0.50 6030089.52 663357.00 N 70.48854087 W 148.66463073 7700.00 42.21 104.38 6289.25 3683.68 -904.64 3570.88 0.50 6030074.15 663422.73 N 70.48849494 W 148.66409636 7800.00 41.71 104.38 6363.61 3750.54 -921.25 3635.65 0.50 6030058.94 663487.84 N 70.48844948 W 148.66356705 Top Schrader 7869.68 41.36 104.38 6415.77 3796.75 -932.72 3680.40 0.50 6030048.43 663532.82 N 70.48841809 W 148.66320135 7900.00 41.21 104.38 6438.55 3816.75 -937.69 3699.78 0.50 6030043.88 663552.30 N 70.48840448 W 148.66304298 8000.00 40.71 104.38 6514.07 3882.31 -953.98 3763.28 0.50 6030028.96 663616.13 N 70.48835990 W 148.66252405 8100.00 40.21 104.38 6590.15 3947.20 -970.10 3826.13 0.50 6030014.20 663679.31 N 70.48831577 W 148.66201045 8200.00 39.71 104.38 6666.80 4011.42 -986.06 3888.35 0.50 6029999.58 663741.85 N 70.48827208 W 148.66150199 ,-, 8300.00 39.21 104.38 6744.01 4074.98 -1001.84 3949.91 0.50 6029985.13 663803.73 N 70.48822888 W 148.66099892 8400.00 38.71 104.38 6821.77 4137.86 -1017.46 4010.81 0.50 6029970.82 663864.95 N 70.48818612 W 148.66050126 8500.00 38.21 104.38 6900.07 4200.05 -1032.92 4071.06 0.50 6029956.66 663925.51 N 70.48814380 W 148.66000891 8600.00 37.71 104.38 6978.91 4261.56 -1048.20 4130.64 0.50 6029942.66 663985.40 N 70.48810197 W 148.65952203 Top Colville 8690.55 37.71 104.38 7050.77 4316.67 -1061.89 4184.02 0.50 6029930.13 664039.06 N 70.48806449 W 148.65908582 8700.00 37.21 104.38 7058.29 4322.38 -1063.31 4189.56 0.50 6029928.83 664044.63 N 70.48806060 W 148.65904055 8800.00 36.71 104.38 7138.20 4382.51 -1078.24 4247.80 0.50 6029915.15 664103.17 N 70.48801972 W 148.65856463 8900.00 36.21 104.38 7218.62 4441.94 -1093.01 4305.36 0.50 6029901.62 664161.03 N 70.48797928 W 148.65809426 9000.00 35.71 104.38 7299.57 4500.66 -1107.59 4362.24 0.50 6029888.27 664218.21 N 70.48793936 W 148.65762946 9100.00 35.21 104.38 7381.02 4558.67 -1122.01 4418.44 0.50 6029875.06 664274.70 N 70.48789988 W 148.65717021 9200.00 34.71 104.38 7462.97 4615.97 -1136.24 4473.94 0.50 6029862.03 664330.49 N 70.48786091 W 148.65671669 NS09 (P7) report. xis Page 2 of 3 10/25/2001-10:27 AM StatIon I D I MD I Inet I Azlm I TVD I VSee N/-5 I EI.W I DLS I Northing I Easting I ~ Coordlnltn latitude Longitude 'ft ft' 4672.55 -1150.30 4528.75 0.50 6029849.15 664385.59 N 70.48782241 W 148.65626881 4728.42 -1164.18 4582.86 0.50 6029836.44 664439.98 N 70.48778440 W 148.65582664 9500.00 33.21 104.38 7711.79 4783.55 -1177.87 4636.27 0.50 6029823.90 664493.67 N 70.48774691 W 148.65539020 9600.00 32.71 104.38 7795.70 4837.96 -1191.39 4688.97 0.50 6029811.52 664546.64 N 70.48770989 W 148.65495957 9700.00 32.21 104.38 7880.07 4891.63 -1204.72 4740.96 0.50 6029799.31 664598.90 N 70.48767338 W 148.65453473 9800.00 31.71 104.38 7964.92 4944.56 -1217.87 4792.23 0.50 6029787.27 664650.44 N 70.48763737 W 148.65411578 9900.00 31.21 104.38 8050.22 4996.75 -1230.84 4842.78 0.50 6029775.39 664701.25 N 70.48760185 W 148.65370272 10000.00 30.71 104.38 8135.97 5048.19 -1243.62 4892.62 0.50 6029763.68 664751.35 N 70.48756685 W 148.65329546 10100.00 30.21 104.38 8222.17 5098.89 -1256.21 4941.72 0.50 6029752.15 664800.71 N 70.48753236 W 148.65289425 10200.00 29.71 104.38 8308.80 5148.83 -1268.62 4990.09 0.50 6029740.78 664849.33 N 70.48749837 W 148.65249900 10300.00 29.21 104.38 8395.87 5198.01 -1280.84 5037.73 0.50 6029729.59 664897.22 N 70.48746490 W 148.65210972 , -.... 10400.00 28.71 104.38 8483.37 5246.43 -1292.87 5084.64 0.50 6029718.57 664944.37 N 70.48743195 W 148.65172641 10500.00 28.21 104.38 8571.28 5294.08 -1304.70 5130.80 0.50 6029707.74 664990.77 N 70.48739955 W 148.65134922 End Drp 10542.03 28.00 104.38 8608.35 5313.88 -1309.62 5149.97 0.50 6029703.23 665010.04 N 70.48738607 W 148.65119258 Top HRZ 10754.29 28.00 104.38 8795.77 5413.53 -1334.38 5246.50 0.00 6029680.56 665107.08 N 70.48731824 W 148.65040382 Base HRZ 10822.24 28.00 104.38 8855.77 5445.44 -1342.30 5277.40 0.00 6029673.30 665138.14 N 70.48729655 W 148.65015133 Top Kuparuk 10901.52 28.00 104.38 8925.77 5482.66 -1351.55 5313.46 0.00 6029664.83 665174.39 N 70.48727121 W 148.64985668 Kuparuk C 11014.78 28.00 104.38 9025.77 5535.83 -1364.76 5364.96 0.00 6029652.73 665226.15 N 70.48723502 W 148.64943587 Top Miluveach 11399.85 28.00 104.38 9365.77 5716.61 -1409.67 5540.07 0.00 6029611.60 665402.18 N 70.48711198 W 148.64800504 9-5/8- Csg Pt 11513.11 28.00 104.38 9465.77 5769.78 -1422.88 5591.58 0.00 6029599.50 665453.95 N 10.48101519 W 148.64158415 Top Kingak 11988.79 28.00 104.38 9885.77 5993.10 -1478.36 5807.90 0.00 6029548.69 665671.40 N 70.48692377 W 148.64581662 12407.84 28.00 104.38 10255.77 6189.83 -1527.23 5998.46 0.00 6029503.93 665862.95 N 70.48678985 W 148.64425960 Top Sag River 12922.02 28.00 104.38 10709.76 6431.22 -1587.20 6232.28 0.00 6029449.00 666097.99 N 70.48662550 W 148.64234914 Target 12922.03 28.00 104.38 10709.77 6431.22 -1587.20 6232.29 0.00 6029449.00 666098.00 N 10.48662550 W 148.64234905 1- Csg Pt 12967.33 28.00 104.38 10749.77 6452.49 -1592.49 6252.89 0.00 6029444.16 666118.71 N 70.48661100 W 148.64218074 Top Shublik 13019.43 28.00 104.38 10795.77 6476.95 -1598.56 6276.58 0.00 6029438.60 666142.52 N 70.48659436 W 148.64198718 Top Ivishak 13121.36 28.00 104.38 10885.77 6524.80 -1610.45 6322.94 0.00 6029427.71 666189.12 N 70.48656177 W 148.64160839 ~ ; Top Kavik 13483.78 28.00 104.38 11205.77 6694.95 -1652.72 6487.75 0.00 6029388.99 666354.79 N 70.48644591 W 148.64026181 TD /4-1/2" Lnr Pt 13540.41 28.00 104.38 11255.77 6721.54 -1659.32 6513.50 0.00 6029382.95 666380.68 N 70.48642782 W 148.64005143 Le~aLDescriDtion : Surface: 1129 FSL 642 FEL S11 T13N R13E UM Target: 4819 FSL 4884 FEL S18 T13N R14E UM BHL: 4747 FSL 4603 FEL S18 T13N R14E UM Northing M fftUSl 6030901.76 6029449.00 6029382.94 Eastlng IX) fftUSl 659833.49 666098.00 666380.68 NS09 (P7) report. xis Page 3 of 3 10/25/2001-10:27 AM PLAH VXBW Client: BPXA Well: NS09 (P7) Field: Northstar Schlumberger Structure: Scale: Date: Northstar PF 1 in = 1000 ft 24-0ct-2001 0 1000 2000 3000 4000 5000 6000 7000 True Borth Mag Dec ( E 26.59° ) 1000 '-"'. 1000 . BId 11100 800 MO 744 1VD DIp moo 0.00' 90.00' 8Z 1300 Me 1244 1VD ON OE 5.00' 90.00' az ^ I ON 22E End BId ^ 3287 MD 3084 1VD ^ " 44.60" 104.38' az 1375 576 E J: ~ 0 0 z I KOP 8"'1t 31100 1800 Me 17431VD 1~3Ir Csg Pt 0.00' 104.38" 8Z 3-407 MD 31101VD ON 44E 44.60' 104.38" az -1000 - 1585 65I1E ~ :r.: ..... :J 0 en -2000 V V V DIp 0.11100 . 7223 MD 58871VD . 44.60' 104.38" 8Z . 823 5 3253 E 0 ~518"' C8 fit End Drp 11513 t.Ð 14101VD 10542 MO 85531VD 28.00- 104.88" 8Z 28.00- 104.38' 8Z 1423 S 5592 E TWVIt 13105 5150 E 12922 MD 10854 lVD 28.00" 104.38" 8Z 1587 S 8232 E -1000 ~. -2000 rcsgPt 12116 7 Me 1 0804 1VD 28.00- 104.38' 8Z 1592 S 6253 E TO '401fT Lnr fit 135040 Me 11 200 1VD 28.00" 104.38' az 16SG 5 6514 E -3000 -3000 0 1000 2000 «< WEST 3000 4000 EAST »> 5000 6000 7000 - .... (1)- Jeæ o~ 0 (I) ~ > II .8 c: ttJ .- -= ~o -0 ..c: . ....0 0.- (I)..J DC/) -~ ttJ .. (.)'t- .- (I) i~ > > (I)~ 2W I- 0 2000 4000 6000 8000 10000 12000 End DIp 10542 MD 8663 D 28.00' 104,38" 8Z 5314 d 16. NIrC8llPt116 3MD 9410TVD 28,00. 104.38" 6770 departU'. ,. , " (' (" Schlumbøruer .. --, .... .. t 22 MD 10654 TVD ,00" 104.38. az -, 3i'd.pertur. rcl8Pt 12967 MD 10694 lVD 28.00" 104,38' az ::. 8452 deP8/tUre VD'l'XCAL SJ:C"1'XOR VI:J:W Client: BPXA Well: NS09 (P7) Field: Northstar Structure: Northstar PF Section At: 104.29 deg Date: October 24, 2001 MD 744 TVD 1Z0d8p8ture --'-----""'------------'-""_m'_'___,,- , Top Pern1afrost 1205 MD 1149 D -- --- -- - . ..--....---'..-" .. .. m KOP 0,00. 1/1001800 MD 1743 TVD .38" 8Z 42 depwture n. -, ..... -- '- - - Base Permafros! 1556 MD 1499 D TDI4-112" nrPt 13ð40MD 112ooTVO 28,00' 1 .38' az 8722 de ure Vertical Section Departure at 104.29 deg from (0.0, 0.0). (1 in = 2000 feet) 8000 ,- -- .... ... -.. .. . "" ,.... ""'-.- ,,_., .-... ... .. -. BId 3287 MO 3084 TVD .80" 104.38" az 582 d8pIr1ure ,:a.3II" C8t Pt3407MD 3170 ." .' ,-"" 44.60' 104.38" IZ 677 d8p8rtur .-.-, -.. - _... -- - SVir31 Bš'MD30îô Till) ,m '" ".. ..., .., .-- -- SVŠ--356:iMÖ"32ïjô Tiiö n -, .... ..- .-- -, - . SV440i'1 MD' 3õOÕ Tiiò ,... .., ... ., , -- -- -- - n- '- ..- ...- ".. .- "'- -., '- - -.. .... SV2 4573 MD 4000 TVD ,.., --'- -,,- .. _.. -- -- ,_. ,... .-- .. j Hold Angle 44.60 SV1 5135 MD 4400 TVD .- 'n ..- ,-, .. ..... -- ,n --. .. TMBK 5654 MD 4770 TVD DIp UI1DO " '7223MD 6887TVO 44.80" 104,38' az 33æ dep8rtIn ,'OP Schräder )'87ÓrvlD'ï¡360'rv .. -- -1"°""" .", .Ö i;;, iVo . I I I I. - ,. .'.. - ~'Z"'07"" ,'" ..^"""'. ,.. , ' pose:J- RZ:'0822K4D8SO0ìVD,.o.o:nR~- ,~,~8,~,~', ',-: '.. '" !Kup,ïruk C 1'0;5 ~1b ã970 NO -.Top,Kuparuk,.10902 MD 881'<) D ..., .. ,.... .... .., -., .., ... .., .0.0 Mdu";;';lch11400 MD 93;0 . b .- .... ..' .- ..- o.o~jn9äk ,,1989,;';;0 983~TVD " ..- ,- ..- ,.. ".. ., Hold Angl 28.00° g~~¡¡.~vef~),f¡æ~ ,~9~ op'Wisn'ã'l(' ,~1'2 f'tïb'f8é~ò' D::-' ..- --- .... -..., ... -.. ..- --. .... -_. ..... Top K"VIK'.13484 f..10 111 50TVD .... -, .., .,. 0 2000 4000 6000 (' 8chl urn berger Anticollision Report ( , ..-... -.... - . _..n' ". .-.... : Company: BP Amoco Field: Northstar Reference Site: Northstar PF Co-ordlnate(NE) Reference: Well: NS09. True North Reference Well: NS09 Vertical (TVD) Reference: N33E 55.8 Reference Wellpath: Plan NS09 Db: Sybase . --'...d_--""" -"-""""""-,-"",-""-"""",,,-,,,,__..0,,,--,,_.....--._--.0-",""""-,,"'..--.......' .. """ "'.. . . ".--. . - . - . .. -. .. . . NO GLOBAL SCAN: Using user defined selection & scan criteria Reference: Principal Plan & PLANNED PROGRAM Interpolation Method: MD Interval: 50.00 ft Error Model: ISCWSA Ellipse , Depth Range: 39.87 to 13540.41 ft Scan Method: Trav Cylinder North : Maximum Radius: 10000.00 ft Error Surface: Ellipse + Casing Date: 10/2512001 Time: 09:38:28 Page: I . Survey Program for Definitive Well path : Date: 10/18/2000 Validated: No , Planned From To Survey ft ft 40.20 1300.00 1300.00 13540.41 Version: Toolcode 8 Tool Name Planned: Plan #7 V1 Planned: Plan #7 V1 GYD-GC-SS MWD Gyrodata gyro single shots MWD - Standard Casing Points ",., """""",-,-,-,,""'..-..........-.. ---""""""------,---"-------"---""'-----'-"-""-,,,,,,,-.--..--..--............_...0'_""""---'0'-'--'--'-'-----""-..-..-..' '........ ..--........_,-.'n.... ! MD TVD Diameter Hole Size Name ft ft in in ,...........- ....... ..-..'" """"" ......'...,.....-, .....--......-....-----..-....---....-..--.--......-........,..................-",--,-""---,,,"""--........---....---.... ..... . ....... .........."" ! 3309.18 3155.77 10.750 12.250 103/4" : 12883.90 10675.77 7.000 8.500 7" i 13540.40 11255.42 4.500 6.000 4-1/2" ...--.., .... n."'" '" ..-- Summary '--"""'..............---.. ..""'-"'" .-. ""--""'_'_---"""'-""'--_"-"_---"""""'-'~-"'-""-""'-'",--------"",-,--"""_"'_--"'0...........""""""""",-""",,-,,....,...... ",,"n ,..".. ....... < Offset Wellpatb >- Reference Offset Ctr-Ctr N o-Go Allowable ; Site Well Wellpath MD MD Distance Area Deviation Warning , I ft ft ft ft ft . . .."""-'" ----,.. -' -" .......0... ,....... '.....--....... ...... ......-.......-'....-..---..-.-..-".""""'_""'0......'.'" ...... --."......-...""""" -"""-"'--"""'" ..... _... ""--"""---,,,,,,'.----""""'-'-"'--""" "" -- .... _._.........-...." .......... ......, '. ....... ! Northstar PF NS10 NS10 V17 1048.50 1050.00 19.22 16.68 2.54 Pass: Major Risk I Northstar PF NS13 NS13 V11 1099.75 1100.00 38.58 17.44 21.15 Pass: Major Risk ! Northstar PF NS26 NS26 V22 1198.78 1200.00 174.13 18.72 155.42 Pass: Major Risk Northstar PF NS27 NS27 V29 2374.37 2400.00 164.75 35.80 130.00 Pass: Major Risk Northstar PF NS29 NS29 V22 399.99 400.00 200.64 7.10 193.54 Pass: Major Risk i Northstar PF NS31 NS31 V14 1897.28 1900.00 219.32 30.78 188.55 Pass: Major Risk Seal Island SEAL-A-01 SEAL-A-01 V4 1941.61 1950.00 420.74 31.45 389.30 Pass: Major Risk Seal Island SEAL-A-02 SEAL-A-02 VO 1847.54 1850.00 413.60 30.21 383.47 Pass: Major Risk : Seal Island SEAL-A-02 SEAL-A-02A V4 1847.55 1850.00 414.72 28.36 386.45 Pass: Major Risk , , Seal Island SEAL-A-03 SEAL-A-03 V4 3184.17 3350.00 305.56 79.81 241.23 Pass: Major Risk Seal Island SEAL-A-04 SEAL-A-04 V4 1601.19 1600.00 452.46 26.72 425.76 Pass: Major Risk ..". .._.. .. (' ----- -----. u--- . Field: Site: Well: WeUpath: N orthstar N orthstar PF NSO9 Plan NSO9 - ---. _....---- 337 0 200 300 300 100 - - 0 27 100 200 i .-/ 300 337 180 . ( 100 100 200 300 Tnlvelling Cylinder Azimuth (TFO+AZI) [dcg] YS Centre to Centre Separation [100ft/in] ~ ~ / Site: Northstar PF ( Drilling Target Conf.: ()9OÆ> .. Centre Location: Ivishak Tgt Map Northing: 6029449.00 ft Map Easting : 666098.00 ft Latitude: 70o29'11.852N Shape: Circle Target: NSO9 (S-lO) t NSO9 Ba:.ed on: Planned Program Vertical Depth: 10654.00 ft below Mean Sea Level Local +N/-S: -1586.18 ft Local +EI-W: 6232.54 ft Longitude: 148°38'32.457W Radius: 400 ft -'- -..-, _'_h___..__.------.-----... -..----....----.-. -- -- ---- -. h--__h_-__-n -- .---.-.. ---'-----"- I I \ \ ~ ~ / ~ ~ / / CJ CJ CD L.n .-""'---""----'-------'--""'--- ./. "--. CJ CJ CJ LD --'-, . .., CJ CJ N LD CJ CJ J LD -800 -1000 -1200 -14-00 -1500 -1800 -2000 -2200 0 CJ LD LD CJ 0 CD LO CJ CJ CJ I ( I( 1Þ DATE 09/28/01 ~ 10014 H 198739 DATE INVOICE / CREDIT MEMO DESCRIPTION GROSS 100.00 VENDOR DISCOUNT 092701 CKO92701C PYMT OMMENTS: HANDL NG INST: Per it to Drill ee 5tH - Terri Hubb e X4628 I., YLSoC) THE ATTACHED CHECK IS IN PAYMENT FOR ITEMS DESCRIBED ABOVE. TOTAL ~ 100.00 1 BP EXPLORATION, (ALASKA) INC. P.O. BOX 196612 ANCHORAGE, ALASKA 99519-6612 FIRST NATIONAL BANK OF ASHLAND AN AFFILIATE OF NATIONAL CITY BANK CLEVELAND, OHIO No.H 198 CONSOLIDATED COMMERCIAL 56-389 412 00198739 PAY , ' ' ONE HUNDRED & OO/100,,**~****************~,*.************** US DOLLAI , DATE, 09/28/01 II AMOUNT $100. To The ORDER Of ALASKA OIL AND Gi\S CONSERVATION "COMMISSION" 333 WEST 7TH AVENUE SU I TE 100 ANCHORAGE NOTVALID AFTER t~ODAYS ' AK 99501 Ç("".,,""', ,'.' ",..,.", ""','-.'.".".""".,-., ',-',', "'-.."',-.'-", '"",,', "'."". "","".,','.".,'"".'.".'". ' , " ' , ,. Î '~ ' ',', .:-..J1 /!;/K ^"- , ," ~'.,l'~.,........-" III ~ ~ a ? j ~ III I: 0 ~ ~ 20 :I at¡ 51: 00 a ~... . t¡ III ( TRANSMIT AL LETTER CHECK LIST CIRCLE APPROPRIATE LETTERIP ARAGRAPHS TO BE INCLUDED IN TRANSNßTTAL LETTER ¿ -(fl CHECK 1 STANDARD LETTER DEVELOPMENT j DEVELOPMENT RED RILL EXPLORA TION INJECTION WELL INJECTION WELL RED RILL WELL NAME CHECK WHAT APPLIES ADD-ONS (OPTIONS) MULTI LATERAL (If api number last two (2) digits are between 60-69) PILOT HOLE (PH) / ANNULAR nlSPOSAL . ( 1/) NO ANNULAR DISPOSAL l--> YES ANNULAR DISPOSAL THIS WELL DISPOSAL INTO OTHER ANNULUS l--> YES + SP ACING EXCEPTION Templates are located m drive\jody\templates ( ~ \ "CLUE" The permit is for a new well bore segment of existing well . Permit No, API No. . . Production should continue to be reported as a function of the original API number stated above. In accordance with 20 AAC 25.005(1), all records, data and logs acquired for the pilot hole must be clearly differentiated in both name (name on permit plus PH) and API number (50 -70/80) from records, data and logs acquired for well (name on permit). Annular disposal has not been requested. . . Annular Disposal of drilling wastes will not be approved. . . Annular Disposal of drilling wastes will not be approved. . . Please note that an disposal of Ouids generated.. . Enclosed is the approved application for permit to drill the above referenced well. The permit is approved ,sùbject to full compliance with 20 AAC 25.055. Approval to perforate and produce is contingent upon issuance of a conservation order approving a spacing exception. (Companv Name) will assume the liability of any protest to the spacing exception that may occur. WELL PERMIT CHECKLIST COMPANY WELL NAMEA./5-Cf} PROGRAM: exp - dev ~ redrtl serv wellbore seg _ann. disposal para req- FIELD & POOL 'S9'O¡{)C) INIT CLASS ~ 6"(./ L GEOLAREA ~}7Ò UNIT# 01 ( 5C.L~ ON/OFF SHORE óPF ADMINISTRA TlON 1. Pennit fee attached. . . . . . . . . . . . . . . . . . . . . . . 2. Lease number appropriate~. . . . . . . . . . . . . . . . . . 3. Unique well name and number. .. . . . . . . . . . . . . . . . 4. Well located in a defined pool.. . . . . . . . . . . . . . . . . 5. Well located proper distance from drilling unit boundary. . . . 6. Well located proper distance from other wells.. . - . . . . . . 7. Sufficient acreage available' in drilling unit.. . . . . . . . . . . 8. If deviated, is wellbóre plat included.. . . . . . . . . . . . . . 9. Operator only affected party.. . . . . . . . . . . . . . . . . . 10. Operator has appropriate bond in force. . . . . . . . . . 11. Pennit can be issued without conservation order. . . . . . . . 12. Pennit can.be issued without administrative approval.. . . . . 13. Can permit be approved before 15-day wait.. . . . . . . . . . 14. Conductor string provided .. . . . . . . .. . . . . . . . . . 15. Surface casing protects all known USDWs. . . . . . . . . . . 16. CMT vol adequate to circulate on conductor & surf csg. . . . . 17. GMT vol adequate to .tie-in long string to surf csg. . . . . . . . 18. CMT will cover all known productive horizons. . . . . '. . . . . 19. Casing designs adequate for C, T, 8 & permafrost. . . . . . . 20. Adequate tankage or reserve pit.. . . . . . . . . . . . . . . - 21. If a re-drill, has a 10-403 for abandonment been approved. . . 22. Adequate wellbore separation proposed.. . . . . . . . . . . . 23. If diverter required, does it meet regulations. . . . . . . . . . 24. Drilling .fluid program schematic & equip list adequate. . . . . N 25. BOPEs, do they meet regulation. . . . . . . . . . . . . . . . N "- . 26. BOPE press rating appropriate; test to .~~O psig. N ~~~ ~,\ ~ '-\~~ ~">\ 27. Choke manifold complies w/APIRP-53 (May 84). . . . . . . . . N . ~~: ~~~::~::rH~h:: ~~::f; ~~u~~n: : : : : : : : : : : y @ --v: ' , , 30. Pennit can be issued wlo hydrogen sulfide measures. . . . .. rv N ð h<s 1.45 k.:e-h. d¿/~ t:::L ¡.. ;z Ii. ' '. $1. 31. Data presented on potential overpressure zones . . . . . . . (Y)N Il> ~i.¡;',l.crrP)t.qIIVJ 4,e6'.r/'r-e...ss,-;~1 $~'7~ -L't-I?~k, $Y!.-4y":5 ,,$ 32. Seismic analysis of shallow gas zones. . . . . . . . . . . . . Y ~ v U V APPR DATE /' 33. Seabed condition survey (if off-shore). . . . . . . . . . . . .AJ/t V--N ~ 1//): D ' 34. Contact name/phone for weekly progress reports [explorat9Pr6ñfy] Y N ANNULAR DISPOSAL35. With proper cementing records, this plan . (A) will contain waste in a suitable receiving zone; . . . . . . . (B) will not contaminate freshwater; or cause drilling waste. .. to surface; , (C) will not impair mechanical integrity pf the well used for disposal; Y N (D) will not damage producing formation or impair recovery from a Y N pool; and E will not circumvent 20 MC 25.252 or 20 MC 25.412. Y N GEOLOGY: ENGINEERING:.' UIC/Annuiar COMMISSION: ~~ " w~~. '9~S APPR Jtl! .( 6tJ ' ~ 'Q ...- ENGINEERING DATE It(,~ GEOLOGY APPR DATE c:\msoffice\wordian\diana\checklist (rev. 11/01/100) ~ Sur~ (DC!-Cc-h~ . ~ A:D'-3f2 /79 . hfoÇ ('r~d~dz~ ~-fe..rt/~..f ~ d ¡; 'J). i..;.... I' !.d¿ Y'Q! ~ 5 cL '-10) ý ¡, .£Þ c 0 Z 0 -t :E ::a .( N~MS~. ~ - -t m - Z -t ,:I: - en :Þ ::a m > ( Y N Y N ~\I"-.. ,,~\~, Ç),\~,\>~~o.. ,) // . Commentsllnstructions: ... . / /Ú U&/ /o~ J-if~ f-j'11-è.d -Ä. l'V(c-::n / .¡cry -k~ /{;;6$-1 ¿(6> 2# () I 4 ,$ ~ .::5IJrd ( b'1V ~- h ;"7\- k~ .è-y u ,-) ~ $4.. ~ ( Well Histol)' 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 APPEN.DIX. No special effort has been made to chronologically organize this category of information. SCANNED NOV 1 8 2004 CONFIDENTIAL SCIII8IIIePger BP Alaska Northstar PVT Study Wells: NS-09, NS-13, NS-08 and NS-15 Surface Separator Samples )ùj-)l"t J Àòl-að'~> Àò),,-t).ll/ .t ;).ó)..-())-V ~J...((\ t t~~f r:k A Report for: By: ( File#: Date: BP Exploration (Alaska) Inc. 900 East Benson Boulevard Anchorage, AK 99519-6616 U.S.A. Oilphase - DBR Schlumberger 9419 - 20 Avenue Edmonton, Alberta T6N 1 E5 Canada (780) 463-8638 www.dbrQroup.com 20023132 May 25,2004 SCANNED NOV 1 8 2004 .. OILPHASE . DBR ~" ; . Quality Assurance Process" Oilphase-DBR has a continuing commitment to provide the highest quality fluid property data and service to all its clients. The Company's philosophy is that all property measurements and calculations be performed to a level of accuracy and repeatability that is unsurpassed in the industry. This objective is achieved by continually improving and developing new state of the art measurement techniques and equipment. The key to maintaining this ability is a rigorous program of quality control and suitable management systems to maintain them. In particular, it is a requirement that all laboratory measurements be performed by qualified engineering technologists and be supervised by an experienced Research Engineer/Scientist at a Ph.D. or M.Sc. level. Open lines of communication are maintained so that qualified staff at all levels can provide input. The results of all the work are interpreted and reported by a Researcher supervising the project. Finally, following the completion of each report, an independent review is made by senior technical staff to confirm the technical consistency and readability of the report. All property measurements and calculation procedures for a particular study are maintained in the company Archives for a period of 3 years. These notes are available for review by clients if requested. All measurements are made following the most appropriate procedures for obtaining accurate and repeatable data. All measurement instruments are calibrated periodically as required, to maintain accuracy. Rigorous quality assurance programs are in place to insure and maintain the accuracy of our analytic procedures. Details of these calibrations are also available at the clients' request. Effective December 8, 1999, after meeting the International Organization for Standardization (ISO) quality assurance standards, Quality Certification Bureau Inc. has granted the Oilphase-DBR registration of our Quality Management System to the requirements of ISO 9001 :1994. To achieve ISO certification, Oilphase-DBR underwent an extensive and lengthy training and review process of operational procedures that culminated with the required third-party quality audits performed by Quality Certification Bureau Inc (QCB). Oilphase-DBR's certification was granted by QCB upon the successful completion of the audits. The ISO 9001 certification further strengthens Oilphase-DBR's position of industry leadership. The company has a stated philosophy that shortcuts in accuracy or technically appropriate procedures are not acceptable under any circumstances. The staff continuously strives to develop and maintain superior experimental procedures and quality control. Reference information indicated below provides traceability to the raw data related to this project. To answer any -questions, clients are requested to contact the Project Manager indicated below. Oilphase-DBR File No: 20023132 Oilphase-DBR Notebooks: 6/2001 & Trentl/2001 1. Laboratory Procedures for This study 2. Data Correlation and Reporting ~ A~ ./-- ,.L - c,ß Craig Borman tl"- . Lab Supervisor .".~ "",..,j -°- Jinglin Gao, M.Sc. (Ch. E. Project Manager " 3. Report Reviewing ( t ( (t..-+ Moin Muhammad, M.Eng. Manager - Research And Fluid Analysis Services J ._.,.,,",..._u-.-...._~.~_._._- ----"'--~"'---~-~.-'."''''~'' ... -..,---- Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 0 Oilphase-DBR ..._..~ -..-.-..,. -. ......,... .--........ -..... ..... . .. ........ .. . ......" ........ .._...n.. -,... --... . . ... .. .....-. -" -... -- ..... . "" .....-........--.--.......- -----......--- '-'. ... ... -"--". ....... ....-...... ...- ..---....--,..-... ------...... "'- EXECUTIVE SUMMARY ., ...-... .....".............,,-.----.---...... ...........".-.........-.."'- Field: Wells: Sample Depth: Reservoir: Location: Northstar NS-09, NS-13, Ns..oa & NS-15 Surface Separator Samples Ivishak Alaska Oilphase-DBR completed a series of PVT studies for BP Exploration (Alaska) Inc. on recombined reservoir fluids collected from NS-13, NS-09, NS-08 and NS-15 wells in its Northstar field. The major results are summarized below: Pressure: Temperature: Estimated - 5175 psia 254.5 of GOR STO API By single stage ambient flash: 2304 SCF/STB By DL test @ Tres: 2515 SCF/STB By 5-stage separator test: 2049 SCF ISTB Single-phase viscosity at Psat & Tres: 0.131 cp 39.6 39.2 41.7 FVF 2.360 2.537 2.218 ( ( ( [ ( ( ( l ( ( ( ( " ( l ( (. ( Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 1 Oilphase-DBR _.~.-._.,_." ." ..... "". ..,.,. "". ",," .---".-. ",... ,. "" "'"'''---'-...---".-'-''' ..."",, ,..- ....". ..n,.."" ..,--------...--...." ".. ,." ,- ,'.,n,'" ,.. ..---"-" --. , " ''''''''m ,....",,--,--,,---, .~-,,,. ,-, '.n_n...._.""".-....... ....- . ,..,..." .m".,,_"'-""."'''.'''''''' . . "...".",..,,-- -,." ..---.-......,-'...".._n.m .n.', ".,. ,..," ,.......""" .. ......" .-. """...- '0'''--' , ,_..., ".n,.... ,,-.. __--m__'__---",,,, .... '''. " " ,., ..." """"..,,, .. ...."...."'......" "n"... - "'-""..-, TABLE OF CONTENTS -~,~,...J QUALITY ASSURANCE PROCESS.. ........ ....... ........ ............... .... ................... ..... ......... ......... ....0 EXECUTIVE SUMMARY............. ............................... ....... ................. ........................................1 1.0 INTRODUCTION....... ...................................................... ....... ..................... .............. ...........6 2.0 SCOPE OF WORK... ..... ....... .................... ...... ........................ ......... ........... ...... ..... ............... 7 2.1 Sample Preparation and Analysis............................................................................. 7 2.2 Sample Recombination.............................................................................................. 7 2.3 Phase Behavior Analysis..........................................................................................8 2.4 Dead Oil Wax Test & Formation Water Analysis........................................................8 2.5 Interfacial Tension Measurement...............................................................................8 3.0 FLUID PREPARATION & COMPOSITIONAL ANALYSIS .................................................8 3.1 Compositional Analysis............................................................................................. 8 3.2 Reservoir Fluid Recombination and Analysis ............................................................9 3.3 Dead Oil Wax Test & Formation Water Analysis ......................................................9 3.4 Interfacial Tension Measurement ....... ........... ............ ......... ............... .....................10 4.0 PHASE BEHAVIOR MEASUREMENT ..............................................................................11 4.1 NS-09, NS-08 and NS-15 Reservoir Fluid Partial PVT Measurement ....................11 4.2 NS09/NS-13 Reservoir Fluid Full PVT Study ..........................................................12 Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 2 Oilphase-DBR TABLES Table 3.1: C30+ Composition of NS-13 Separator Oil TC-1137 .................................................16 Table 3.2: C30+ Composition of NS-13 Separator Oil TC-1119 .................................................17 Table 3.3: C30+ Composition of NS-09 Separator Oil TC-1136 .................................................18 Table 3.4: C30+ Composition of NS-09 Separator Oil TC-1120 .................................................19 Table 3.5: C30+ Composition of NS-08 Separator Oil TC-1126 .................................................21 Table 3.6: C30+ Composition of NS-08 Separator Oil TC-1142 .................................................22 Table 3.7: C30+ Composition of NS-15 Separator Oil TC-1124 .................................................23 Table 3.8: C30+ Composition of NS-15 Separator Oil TC-1141 .................................................24 Table 3.9: C15+ Composition of NS-09 & NS-13 Separator Gases ...........................................26 Table 3.10: C15+ Composition of NS-08 & NS-15 Separator Gases .........................................27 Table 3.11: C30+ Composition of Recombined 5100psia Psat NS-09 Oil .................................28 Table 3.12: C30+ Composition of Recombined 4850 psia Psat Oil ...........................................29 Table 3.13: C30+ Composition of Recombined NS:-08 Oil .........................................................30 Table 3.14: C30+ Composition of Recombined NS-15 Oil .........................................................31 Table 3.15: C30+ Composition of Recombined 5100 psia Psat NS-13 Oil ................................32 Table 4.1: CCE of Recombined 5100 psia Psat NS-09 Oil @ 254.5°F .....................................35 Table 4.2: CCE of Recombined NS-08 Oil @ 254.5°F .............................................................37 Table 4.3: CCE of Recombined NS-15 Oil @ 254.5~F .............................................................39 Table 4.4: Separator Test of Recombined 5100 psia Psat NS-09 Oil ......................................41 Table 4.5: Compositions of Produced Gas by Separator Test on 5100 psia Psat NS-09 Oil ...42 Table 4.6: CCE of Recombined 4850 psia Psat NS-09 + NS-13 Oil @ 254.5°F.......................44 Table 4.7: DL of Recombined 4850 psia Psat NS-09 + NS-13 Oil @ 254.5°F - Liquid Phase Properties.......................................................................................................... ..46 Table 4.8: DL of Recombined 4850 psia Psat NS-09 + NS-13 Oil @ 254.5°F - Vapor Phase Properties..................... ...... ..................... ... . .. ........ . ................ .... ... .......... . . .......... 50 Table 4.9: Viscosity of Recombined 4850 psia Psat NS-09 + NS-13 Oil @ 254.5°F ...............52 Table 4.10: Compositions of Produced Vapor by DL Test on 4850 psia Psat NS-09 + NS-13 Oil @ 254.5°F ....................................................................................... ..52 Table 4.11: Separator Test of Recombined 4850 psia Psat NS-09 + NS-13 Oil ......................54 Table 4.12: Compositions of Produced Vapor by Separator Test on 4850 psia Psat NS-09 + NS-13 Oil ........................................................................................... ..55 Table 4.13: Separator Corrected GaR & FVF .........................................................................57 Table 4.14: Summary of PVT Test on 4850psia Psat NS-09 + NS-13 Oil ..............................59 Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 3 Oilphase-DBR FIGURES Figure 3.1: C30+ Composition Comparison - NS-09 & NS-13 Samples ...................................20 Figure 3.2: C30+ Composition Comparison - NS-08 & NS-15 Samples ...................................25 Figure 3.3: LP Separator Water Composition ........... """""""""'" ......................... ..................32 Figure 3.4: HP Separator Water Composition ..... ....... '''''''''''' ....... ............... ......... ................ ...33 Figure 4.1: CCE of Recombined 5100 psia Psat NS-09 Oil @ 254.5°F....................................36 Figure 4.2: CCE of Recombined NS-08 Oil @ 254.5°F ............................................................38 Figure 4.3: CCE of Recombined NS-15 Oil @ 254.5°F ............................................................40 Figure 4.4: CCE of Recombined 4850 psia Psat NS-09 + NS-13 Oil @ 254.5°F .....................45 Figure 4.5: DL of Recombined 4850 psia Psat NS-09 + NS-13 Oil @ 254.5°F - GaR as Functions of Pressure........................................................................................4 7 Figure 4.6: DL of Recombined 4850 psia Psat NS-09 + NS-13 Oil @ 254.5°F - Liquid Phase Properties as Functions of Pressure........................ ""'"'''''''''''''''''''.''''''''''' ....48 Figure 4.7: DL of Recombined 4850 psia Psat NS-09 + NS-13 Oil @ 254.5°F - Vapor Phase Properties as Functions of Pressure......... .... ""'''''''' ................................... ..... ..49 Figure 4.8: Viscosity of Recombined 4850 psia Psat NS-09 + NS-13 Oil @ 254.5°F ..............51 Figure 4.9: Separator Corrected GaR & FVF ...... ..... ...... ........ """"" .......................................58 Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 4 Oilphase-DBR APPENDICES Appendix A: Summary of Oilphase-DBR Capabilities........................................................ A1 A.1 Fluid Preparation of Compositional Analysis..................................................................... A 1 A.2 Techniques & Apparatus................................................................................................... A 1 A.2.1 PVT Cell.................................................................................................................... A 1 A.2.2 ODBR Solids Detection System................................................................................ A2 A.2.3 ODBR High Pressure Microscope (HPM) ................................................................ A2 A.2.4 ODBR Particle Size Analysis (PSA) ......................................................................... A3 A.2.5 Cambridge Electromagnetic Viscometer (EMV)........................................................ A4 A.2.6 Capillary Viscometer (CV).... ............... ....... ...... .............................................. ...... ..... A5 A.3 Procedures... ..................................................................................................................... A6 A.3.1 Constant Composition Expansion (CCE) ................................................................. A6 A.3.2 Differential Liberation (DL) .. ..................................................................................... A7 A.3.3 Constant Volume Depletion (CVD)........................................................................... A7 A.3.4 Multi-Stage Separator.................. ......................................... ....... ............................ A7 A.3.5 Viscosity Measurement Using EMV ......................................................................... A7 A.3.6 Discrete Isothermal De-Pressurization........ ............ ................................................. A8 A.3.7 Isobaric & Isothermal Titration.................................................................................. A9 A.3.8 Isobaric Temperature Sweep (Live Oil Cloud Point) .............................................. A12 A.4 Live Oil Bulk Filtration..................................................................................................... A 13 A.5 Dead Oil Pour Point....................................................................................................... A 13 A.6 Live Oil Pour Point..................................................... .................................................... A 14 A.7 Model Pipeline Test for Gel Strength............................................................................. A 14 A.8 Wax Appearance Temperature by Cross Polar Microscopy.......................................... A16 A.9 Core Flooding Apparatus.............................................................................................. A 17 A.10 Asphaltene Content by Modified Syncrude Method..................................................... A 18 A.11 SARA Analysis................................. ............................................................................ A 18 Appendix B: Determination of Oil/Brine Inteñacial Tension ............................................. 81 Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 5 Oilphase-DBR _.... .._-, -,,,. ""..--".---.-".---"......--.----"...----...-.. ,--.... .."n, "...,,----..... ,._".. ~ BP .ALASKA NORTHST AR PVT STUDY -....,,,,,--.,,,,,, -... ,."." _.,-"'"---- -0-"'''' " ,-",,--.... ..----...., --." "....., " ,." .. .,_,."n,... .."."",... ,.. ,,------. ----,. ,..".."""'.""'n'''.'..''...--....''''...,....",..--....-.--..".. .,,, "'.''''''--'-'--'.'''''' ."., ,.- Field: Wells: Sample Depth: Reservoir: Location: Northstar NS-09, NS-13, NS-08 & NS-15 Surface Separator Samples Ivishak Alaska ~¡{.I.III'lU!UJ BP Exploration (Alaska) Inc. was interested in conducting a series of PVT studies on recombined reservoir fluids collected in its Northstar field located in Alaska. Oilphase-DBR, Edmonton, Canada was commissioned to perform the experiment. A scope of work is summarized in Section 2. Oilphase-DBR received the first batch of separator oil and gas samples in February 2002, which consisted of samples from NS-09 and NS-13 wells. In May, 2002, the second batch of samples consisting of separator oil and gas from wells NS-08 and NS-15 arrived. These separator samples were used to reconstitute a series of reservoir fluid. A complete inventory of samples received at Oilphase-DBR, Edmonton is summarized below in a tabular form: Summary of Separator Samples Sample Cylinder Well Fluid Description Sample Separator Receiving Number Designation Volume Conditions Date Psig/oF 1 st batch Feb., 2002 TC 1138 NS-09 Separator Oil 800cc 725/125 Feb., 2002 TC 1120 NS-09 Separator Oil 800cc 725/125 Feb., 2002 TC 1136 NS-09 Separator Oil 800cc 725/125 Feb., 2002 MM33085 NS-09 Separator Gas 20liter 725/125 Feb., 2002 MM38865 NS-09 Separator Gas 20liter 725/125 Feb., 2002 MM33082 NS-09 Separator Gas 201 iter 725/125 Feb., 2002 TC 1119 NS-13 Separator Oil 800cc 740/128 Feb., 2002 TC 1137 NS-13 Separator Oil 800cc 740/128 Feb., 2002 MM38810 NS-13 Separator Gas 20liter 740/128 Feb., 2002 MM33040 NS-13 Separator Gas 20liter 740/128 April, 2002 LP separator water 1 liter April, 2002 HP separator water 1 liter 2nd batch May, 2002 TC 1126 NS-08 Separator Oil 800cc 711/108 May, 2002 TC 1142 NS-08 Separator Oil 800cc 710/105 Oilphase-DBR FILE #: 20023132 Oilphase-DBR BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 6 May, 2002 0342 NS-08 Separator Gas 20 liters 711/108 May, 2002 0327 NS-08 Separator Gas 20 liters 710/105 May, 2002 TC 1141 NS-15 Separator Oil 800cc 700.7/92 May, 2002 TC 1124 NS-15 Separator Oil 800cc 700.4/94 May, 2002 0329 NS-15 Separator Gas 800ce 700.7/92 May, 2002 0343 NS-15 Separator Gas 800cc 700.4/94 ~'l'I.]:~¡~ 2~1.. ;'.;.~.~Såínpl'fPre~rátlöRf.;Aî1alysls a) Sample conditioning and restoration by heating, pressurizing and mixing. b) Separator gas analysis to C15+. c) Separator oil analysis to C30+ includes GaR and density. d) Dead oil molecular weight by freezing point depression. 2.2 '" "",'SämPti:'RIiê6Jnbl~~tfb" ( ( ( ( ( ( ( ( ( ( ( ( ( ( ( ( (. ( ( ( ( ( ( a) Reservoir fluid #1 - NS-09 reservoir fluid with saturation pressure of 5100 psia at Tres: Recombine -2 liters of reservoir fluid # 1 to a specified saturation pressure of 5100 psia at Tres (254.5°F) using NS-09 separator oil and gas samples. b) Reservoir fluid #2 - NS-09 and NS-13 mixture with saturation pressure of 4850 psia at Tres: Add NS-13 separator oil into about 1 liter of the recombined reservoir fluid #1 (NS- 09 reservoir fluid) to have recombined reservoir fluid #3 with a saturation pressure of 4850 psia at Tres of 254.5 of. c) Reservoir fluid #3 - NS-08 reservoir fluid with GaR of 1602scf/sep. bbl: Recombine -1 liter of reservoir fluid # 6 to a separator GaR of 1602 scf/sep. bbl using NS-08 separator oil TC 1142 and gas 0327. d) Reservoir fluid #4 - NS-15 reservoir fluid with GaR of 1441scf/sep. bbl: Recombine -1 liter of reservoir fluid # 7 to a separator GaR of 1441 scf/sep. bbl using NS-15 separator oil TC 1124 and gas 0343. e) Reservoir fluid #5 - NS-13 reservoir fluid with saturation pressure of 5100 psia at Tres: Recombine -2 liters of reservoir fluid #2 to a specified saturation pressure of 5100 psia at Tres (254.5°F ) using NS-13 separator oil and gas samples. f) Compositional analysis of the above recombined reservoir fluids #1 to #5 to C30+ 2.3,PbasEtBehëlviQr;AnalySis On recombined fluid #1, which is the NS-9 reservoir fluid with saturation pressure of 5100 psia at Tres (254.5 OF): a) Perform a Constant Composition Expansion (CCE) test at Tres. b) Perform a 5-stage separator test. c) Measure single-phase viscosity at Tres at two different pressures. Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 7 Oilphase-DBR On recombined fluid #2, which is a NS-9 and NS-13 mixture that has a saturation pressure of 4850 psia at Tres (254.5 OF): d) Perform a Constant Composition Expansion (CCE) test at Tres. e) Perform a 6-step Differential Liberation (DL) test at Tres, including oil viscosity at each step. f) Perform a 5-stage separator test. g) Measure single-phase viscosity at Tres at two different pressures. On recombined fluid #3 and #4, which are the NS-08 and NS-15 reservoir fluids: h) Perform Constant Composition Expansion (CCE) Tests at Tres. 2~tf!,,;"..'D.1iiÎ!ØII;iWiXcr_t¡*,êI:Poiii.~;_ätir:,Änalyšt. a) Measure Wax Appearance Temperature 0NAT) of NS-09, NS-13, NS-08 and NS-15 dead oils using Cross Polar Microscopy (CPM). b) Wax content of dead oils using UOP 46-64 method. c) Compositional analysis of formation water samples. d) Prepare -200cc of dead oil from NS-13 separator samples and send to US Geological Survey in Denver, USA. 2~5', . :lnteøaCJ.I:,'FêlbslO~,_...._e"t a) Prepare and send 25cc of NS-13 dead oil and 50cc of recombined fluid #5 to the Petroleum Recovery Institute (PRI) in Calgary for interfacial tension measurement. b) Measure the interfacial tension (1FT) of the NS-13 dead oil with the formation water collected from the high-pressure separator at 200psia and 122°F. c) Measure the interfacial tension (1FT) of the recombined fluid #5 (NS-13 reservoir fluid with a saturation pressure of 5100psia at Tres) with the formation water collected from the high-pressure separator, at 5175 psia and Tres (254.5°F). After receiving the separator oil and gas samples in the laboratory, the first batch of samples was conditioned at 176°F and the second batch was conditioned at 122°F. The oil samples were allowed to gently and continuously rock for over 48 hours while maintaining the pressure at -1000 psi. The gas samples were hand-rocked occasionally. During conditioning, oil samples TC1138 and TC1126 were lost due to an unexpected release of the safety valve on the sample cylinders. 3~ 1 C()mpositional An~,lysis The procedure is described in the fluid preparation and analysis section in Appendix A. The compositional results for the separator fluids are presented in Tables 3.1 to 3.8 and are compared in Figures 3.1 and 3.2 respectively for the first and second batches of samples. Oi/phase-DBR FILE #: 20023132 Oilphase-DBR BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 8 ( ( ( [ ( ( ( ( ( , ( l These Tables include the measured and/or calculated molecular weight, and the compositions of the vapor and the liquid generated from the flash for each sample, and also contain the calculated properties of the C7+, C12+ and C30+ fractions including mole 0/0, weight 0/0, molecular weight, specific gravity and boiling point. Separator gas samples were analyzed to C15+. The results are presented in Tables 3.9 and 3.10 respectively for the first and second batches of samples. 3.2 Reservoir Fluid. Recombination and' Analysis Reservoir Fluid #1: NS-09 reservoir fluid with saturation pressure of 5100 psia at Tres (254.5°F). Separator gas from well NS-09 was recombined with the separator oil from the same well in such a way that the recombined fluid had a saturation pressure of 5100 psia at reservoir temperature of 254.5°F. This was achieved by adding a certain amount of gas and oil into a recombination cylinder. This cylinder was equipped with a mixing ring and placed inside a forced air circulation, thermostated oven. After addition of the gas and oil, a sub-sample was charged into a PVT cell where a pressure-volume relation test was performed to determine the saturation pressure. If the saturation pressure was higher than the specified pressure, more liquid was added. If the saturation pressure was lower than the specified pressure, more gas was added. This process was repeated until the measured saturation pressure was within an acceptable range of the specified value. The analyzed C30+ compositional data of this recombined fluid are presented in Table 3.11. Reservoir Fluid #2: This fluid was obtained by adding NS-13 separator oil into the recombined reservoir fluid #1 (NS-09 reservoir fluid). The resulting mixture had a saturation pressure of 4850 psia at Tres (254.5°F). The C30+ compositional data of this recombined fluid are presented in Table 3.12. Reservoir Fluid #3: NS-08 reservoir fluid. Separator oil and gas samples from well NS-08 were recombined to a separator GaR of 1602 scf/sep bbl. This corresponds to the producing GaR at the time of sampling (gas rate at standard conditions: 7.848 mmscfd; oil rate at separator c~nditions: 4898 bbl/d). The C30+ compositional data of this recombined fluid are presented in Table 3.13. Reservoir Fluid #4: NS-15 reservoir fluid. Separator oil and gas samples from well NS-15 were recombined to a separator GaR of 1441 scf/sep bbl. This corresponds to the producing GaR at the time of sampling (gas rate at standard conditions: 8.179 mmscfd; oil rate at separator conditions: 5674 bbl/d). The C30+ compositional data of this recombined fluid are presented in Table 3.14. Reservoir Fluid #5: NS-13 reservoir fluid with saturation pressure of 5100 psi a at Tres (254.5°F). The NS-13 separator oil and gas samples were recombined into reservoir fluid that had a saturation pressure of 5100 psia at Tres (254.5°F). The C30+ compositional data of this recombined fluid are presented in Table 3.15. Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 9 Oilphase-DBR 3f;~:i,-:%{;~~t~âèJI}'wt;;W_;]~,*;~6Vg'fiM.t,(jJl'!~Wit't~M'Pt. Wax Appearance Temperature (WAT): Cross Polar Microscopy (CPM) was used to measure the wax appearance temperature 0N AT) of the dead oil resulting from flashing the separator oil at 176 of to ambient conditions. The sample is taken hot at 140°F and then cooled at a rate of 2°F/min to 32°F while the CPM photomicrograph is being recorded. The results are reported below: NS-09 dead oil W AT NS-13 dead oil WAT NS-08 dead oil W AT NS-15 dead oil WAT 89.0 OF 92.1 OF 96.0 of 92.7 of Wax Content: Wax content of NS-09 and NS-13 dead oils was analyzed by Maxxam Analytical Inc., Edmonton, Alberta using UOP-46-64 standard method. Briefly, this method involves dissolving about 2 grams of sample in petroleum naphtha. The solution is clarified using fuller's earth. The petroleum naphtha is evaporated and the clarified oil redissolved in an acetone-petroleum naphtha mixture. This solution is then chilled to 0 of and filtered through a cold filter funnel, the wax being collected on an asbestos mat in the funnel. The wax is then washed from the mat into a weighing flask, using hot petroleum naphtha. The naphtha is evaporated and the wax weighed. Probably because of sample mishandling (temperature was lower than the wax appearance temperature while sampling or transfer), the analyzed results were lower than expected: NS-09 dead oil wax content NS-13 dead oil wax content 0.26 wt% 0.16 wt% After discussions with Mr. Terry Wilcox of BP Exploration (Alaska) Inc., another sample was taken by flashing NS-13 recombined reservoir fluid (recombined fluid #2) at 176 of and sent to Maxxam. The sample was heated to 104 of for 10 minutes prior to sub-sampling for wax content analysis. The wax content of this sample was analyzed to be 3.36 wt%. I NS-13 dead oil wax content, 2nd analysis 3.36 wt% Wax content of NS-08 and NS-15 dead oils was analyzed by Norwest Labs, Edmonton, Alberta using the same method. The samples were heated to 104 of for 10 minutes prior to sub-sampling for wax content analysis. The results are reported in the table below. NS-08 dead oil wax content NS-15 dead oil wax content 3.9 wt°lo 3.7 wt°lo Formation Water Analysis: Compositional analysis of formation waters collected at low- pressure separator (LP separator) and high-pressure separator (HP separator) was also performed by Maxxam Analytical Inc. The results are presented in Figures 3.3 and 3.4. Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 10 Oilphase-DBR 3.4, . 'Intèrfa.élål.Ten~iõn(lféT)::Meaš"'~~l)t After review the compositional data of the water samples, Mr. Terry Wilcox of BP Exploration (Alaska) Inc. decided to use the high-pressure separator (HP separator) water to conduct the interfacial tension (I FT) measurement. The measurement was performed by the Petroleum Recovery Institute of the Alberta Research Council in Calgary, Alberta using a pendant drop method. Both dead and live oils with formation water systems were measured. The dead oil was flashed from the NS-13 separator fluid, and the live oil was the NS-13 reservoir fluid with a saturation pressure of 5100 psia at Tres (recombined fluid #5). The 1FT of dead oil and formation water was measured at 122°F and 200psig in order to keep the system above the wax appearance temperature; while the live oil and formation water system was measured at Tres (254.5°F) and 5175 pisa. The results are presented below in the tabular form. A detailed report on 1FT measurement may be found in Appendix B. 1FT of NS-13 STO & formation water @ 214 psia &122°F 16.0 dyne/cm 1FT of NS-13 live oil & formation water @ 5175 psia & 254.5°F 25.9 dyne/cm J:~::8~'d:t~1S The phase behavior measurements were performed using the techniques & procedures described in the fluid phase behavior measurement section in Appendix A. ~~':.,'.,".::r....'..N'$~$~;:""$~~:...'"~.."N§:~1~:.;~~~<@liglr',:Eïg~~"f~~nl,jJle~~::~"li8r.gj_Ì1t ( ( CCE Test: A Constant Composition Expansion (CCE) test was performed on the recombined reservoir fluid #1 (NS-09 samples recombined to a saturation pressure of 5100 psia at Tres), #3 (NS-08 samples recombined to the producing GaR of 1602 scf/sep bbl), and #4 (NS-15 recombined to the producing GaR of 1441 scf/ sep bbl). The results are presented in Tables 4.1 to 4.3 and are plotted in Figures 4.1 to 4.3. The bubble point pressures were determined from the volumetric data and were also visually confirmed using a high magnification cathetometer. Psat of NS-09 Reservoir Fluid @ 254.5°F Psat of NS-08 Reservoir Fluid @ 254.5°F Psat of NS-15 Reservoir Fluid @ 254.5°F 5095 :t 15 psia 4885 :t 15 psia 4640 :t 15 psia These tables also contain the measured/calculated liquid densities and compressibility values in the single-phase region. The pressure relative-volume data in the single-phase region was curve fitted using the "TableCurve" software package (Windows based; developed by Jandel Scientific). The selected functions and the V-function values are provided in the table; the compressibility values were calculated using the derivative of the selected function. Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 11 Oilphase-DBR Live Oil Viscosity: The viscosity of recombined reservoir fluid #1 (NS-09 samples recombined to a saturation pressure of 5100 psia at Tres) was measured using an electromagnetic viscometer (Cambridge) at reservoir temperature. The results are reported in the table below. Live fluid viscosity @ 5500 psia and 254.5°F Live fluid viscosity @ 5200 psi a and 254.5°F 0.106 cp 0.097 cp Separator Test: A 5-stage separator test was performed on recombined reservoir fluid #1 (NS-09 samples recombined to a saturation pressure of 5100 psia at Tres). The results are presented in Tables 4.4 and 4.5. Table 4.4 provides the equilibrium vapor and liquid phase densities, the individual GaR and formation volume factor values for each stage. Additionally, this table contains a summary of the cumulative GaR and residual oil properties for the complete separator test. Presented in Table 4.5 are the compositional data of produced vapor at each stage and the residual oil. The separator conditions are provided below in a tabular form. Pressure - psia Temperature - of Stage 1 750 160 Stage 2 Stage 3 Stage 4 Stage 5 325 70 20 15 157 157 157 60 4~~,~,<..,:',."N$~'lN$~1;~,;,R_$~rvtiJir.J;IQict.;Fqlli.'PVt¿$I~~Y A full PVT study was performed on the recombined reservoir fluid #2, which was NS-09 and NS-13 mixture with a saturation pressure of 4850psia at Tres. CCE: The CCE test results are presented in Table 4.6 and plotted in Figure 4.4. The bubble point pressure was determined from the volumetric data and was also visually confirmed using a high magnification cathetometer. I Psat of NS-09+NS-13 Reservoir Fluid @ 254.5°F I 4855 :!:: 15 psia Differential Liberation (DL) Test: A 6-step Differential Liberation (DL) test was conducted at reservoir temperature (254.5°F) from the bubble point pressure to 1500psia. After completion of the last step, the equilibrium liquid phase at 1500 psia was flashed to ambient pressure at room temperature. As such, a total of 7 steps of the DL test were performed with the last step being conducted at room temperature. The data from differential liberation test are supplied in Tables 4.7 and 4.8. Table 4.7 provides the cumulative liberated and solution GaR, calculated liquid phase density, formation volume factor (FVF), and liquid viscosity values at each pressure step. The GaR data is also presented in Figure 4.5. The GaR was calculated by taking the total gas phase mass generated at each pressure step and converting it to a standard condition gas volume using the ideal gas law. The liquid density, FVF, and viscosity data are also presented in Figure 4.6. The liquid density at the bubble point pressure was previously determined from the CCE test and was used to initiate the calculations. The liquid density at each pressure step was calculated by mass Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 12 Oilphase-DBR balance. The viscosity of liquid at each step was measured using the Cambridge in-line viscometer. These data along with the single-phase viscosity of the original reservoir fluid are also presented in Table 4.9 and Figure 4.8. Presented in Table 4.8 are the measured equilibrium vapor phase properties at each step. As expected the vapor density decreases with decreasing pressure. Figure 4.7 shows the vapor density, gravity and deviation factor (compressibility) dependence with pressure. The compositional data of produced vapor at each step and the residual oil are presented in Table 4.10. Separator Test: A 5-stage separator test data are summarized in Tables 4.11 and 4.12. Table 4.11 provides the equilibrium vapor and liquid phase densities, the individual GaR and formation volume factor values for each stage. Additionally, this table contains a summary of the cumulative GaR and residual oil properties for the complete separator test. Presented in Table 4.12 are the compositional data of produced vapor at each stage and the residual oil. The separator conditions are provided below in a tabular form. ( r ( ( C ( ( ( ( ( ( ( ( ( C ( ( ( ( ( ( ( l t Pressure - psia Temperature - of Stage 1 750 160 Stage 2 Stage 3 Stage 4 Stage 5 325 70 20 15 157 157 157 60 Reservoir Fluid Properties From Differential Liberation Test & Separator Data: As stated in the Ihe Properties of Petroleum Fluids. (McCain~ 1990)~ the underlying assumption in generating reservoir fluid properties from a PVT study is that at pressures below the bubble point, the process in the reservoir can be simulated by differential liberation, while the process from the bottom of the well to the stock tank can be simulated by the separator test. Based on this assumption, fluid properties at pressures below saturation can be calculated by combining the data from the differential liberation and a separator test. The measured and the adjusted solution gas GaR and formation volume factor data are shown in Tables 4.13. In each case, the fluid properties at a particular pressure step were calculated by drawing on the differential liberation flash at reservoir temperature followed by the change in fluid properties as that reservoir oil is produced through the separator train to the stock tank. However, at pressures above the bubble point, solution GaR is constant, while the FVF is reduced due to oil compressibility. Shown in Figure 4.9 are the separator corrected GaR and FVF data as the liberated reservoir oil is produced at the surface. PVT Study Summary and Discussion: Table 4.14 contains summary information for the experimental study comparing GaRs, formation volume factor and residual liquid properties from each of the three flashing procedures in the study. These include: . the single stage flash of the reservoir fluid in the GaR apparatus at room temperature. Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 13 Oilphase-DBR . the differential liberation of the reservoir fluid at reservoir temperature. . the separator tests. Usually, an increased number of flashes at a fixed temperature down to atmospheric pressure results in a decreased total volume of evolved gas. That is, if an oil is flashed down over multiple stages, it is expected that the overall GaR and FVF should be lower than if the same oil was flashed in a single stage process at the same temperature. This behavior is important to consider when comparing the three different flashes in this study; however, it is equally important to recognize that the single stage GaR flash, differential liberation and separator test were completed at different temperatures which also has an effect on the resulting properties. As can be seen in Table 4.14, the DL flash has the highest GaR due to the relatively high temperature used for this test. Similarly, the FVF from the DL is also the highest and the corresponding residual liquid is the heaviest. Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 14 Oilphase-DBR TABLES & FIGURES ( ( ( l ( ( r ( [ ( ( ( ( c ( ( ¡ l ( Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 15 Oilphase-DBR Table 3.1 BP Alaska Northstar Separator Fluid Well: NS-13; Cylinder TC1137 C30+ Composition Gas Mole % Liquid Wt% Wt% Overall Mole % Group Mole % C13 16.70 C18 C19 ø:~êi!r.~ C21 èÜ:;, C23 Ç2( C25 ç~' C27 ë28' C29 ë3Qf,; , . ~ai'ÍlI!ClIIftV(g¡~)'. ~¡¡Iculat~~ M~ (g/mol) $ingié $táp,F'lasItGO~ @ STD ' API Graýity . ÄverãgeGas GrâvkY ' Contaniil1åtiön(Wt'%)~ '. Contamination Corrected GOR Contamination Corrected API C., ~, (SCF/BBL) Compositional Data for Different Groupings Mole % Wt% MW ~2,~ ~ 81;8 186.4 25.3 54.9 258.3 1JÍ47.0 580.0 . Estimated with the Skimming Method. (Gozalpour F., Danesh A., Tehrani A. -H., Todd A. C., Tohidi B., SPE Technical Paper # 56747, 1999) .. Boiling Points Calculated using the Twu Correlation, (Twu, C. H., Fluid Phase Equilibria, 16, 137-150 (1984)) Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 16 Oilphase-DBR Table 3.2 BP Alaska Northstar Separator Fluid Well: NS-13; Cylinder TC1119 C30+ Composition Gas Liquid Overall Group Component MW Mole % Wt % Wt % Mole % Mole % -cQ~;.,,~', .'.::'. .:.. .'~.c~~~,01't~ ,',~,:::_,,"'::;15~L',~L::L -~:::,~l~P'Pjl::~,f::;: ',::i'2,:Q.;~J~;t5t::2'~ê':;~'11fL. :3: )~,t"I@f?::~.;";r.L H2S 34.08 0.00 0.00 0.00 0.00 0.00 ~~' , .' . 28~Ot,' :",:r: 'g:,~.", ",':Jt:9P::,)X ",}:~~ó,b§,;,:~,,,;...:;.,_:;~iiZ?;>., ,iw :,.,dt~¿~.~.:. C1 16.04 43.09 0.00 1.91 14.20 14.20 cC2';..~ . .,' ': '~9t~"". ',:\1 ~:34 ':- . . ,<': QioQ;:,"".; y: ':;.~::21~~t?::":.,r". :'.';'i~~;~:,¿. ;".:;!i;ót}'~,.~: .~:; C3 44.10 16.82 0.44 2.45 6.63 6.63 1~.f. :,. "~~1~'~;, ,::':.:;;~;4Ø.~<': .,' . "";,~Q..~",..,:.~.. :';I',';"O;~(~;;':/:;'S~t\i~.f":-':':~.~, ..1~!~:,;:' N-C4 58.12 7.63 1.20 2.31 4.76 4.76 .~. ...' .' ,,7?-;~t., .;',i.>~~\'.,' n,>.-.,::~,~..:\Y:",:,;'~;::::,f:.2.(f::n{~?'~.~}':\".2:1:2~:,', ',~j~": '" ,;. N-C5 72.15 2.10 1.51 1.79 2.96 2.96 'ê~'>' .:>.,:;. ,~;20:f :,. ' , ,>~ .21 " . ':<3.22' ~':. .>:":.:3,2~, ,,;-:>,',o~..4,45.', ' MCYC-C5 84.16 0.19 0.83 0.80 1.14 BENZENE. ' 18.11. .:;.::().ot .i,"¡;([2,2)i O' /'~o;~ .. . ;'0.33' CYCL-C6' 84.16' - ' . 'o:Ù~' '1".16 - 1.09 ' 1-.59 . CT" " 10020' '0;33 :;':.3JJ7"" ,.. ':3;1)0 "o~>4,;30, MCYCL-C6" 98. Ù~ -- Õ.14 .- 2.54 '2.34 ' 2.86 . TOLliE~E' '.~2;44""J).Q4 'L";;.O,~{;':'. :' .~75 ,~. 0.'97!, C8 114.23 0.10 5.25 4.80 5.03 C2-BENZENE' 106:11' :0;00 ~'>O;31, 0.29 '.JO.32 M&P-XYLENE 106.17 0.Ó1 . 0.80 0.73 0.82 O.XYLENE 106.17 '0;00 0.49 0;45 0.51' C9' 128.30' 0.03 4.71 4.29 4.00 C10 134.00 0.01S.90' 5.36.4:18 . C11 147.00 0.00 4.87 4.42 3.59 oC:12 161.0Q' 0.00 4.00 cn 175.00 0.00 4.49 C14 . 190;00 , , 0.00 4.06 C15 206.00 0.00 C21 C22 C23 C24 C25 C26 C27 C28 C29 C30+ MeasuredMW (g/mol) Calculated MW (g/mol) Single Stag! FlêlS", GOR @ STP API Gravity Averave Gas Gravity Contamination (wt %)* Contamination Corrected GOR Contamination Corrected API '0.00 0.00 , 0.00 0.00 0.00 0.00 .0.00 0.00 0.00 0.00 0,00 0.00 ';.O.OÓ. 359.00 374.00 388.00 402.00 580.00 33.5 57.0 42.0 1.158 . Dead on Basis 3.52, 3.35 2.73 2.58 2.34' 2.24 "'2.00 . 1.94 1.65 1.72 1.62. 1A8 '8.02 165.0 161.9 (M3/M3) .3.19 3.04 . 2.48 2.34 2.12 2.03 1'.82 1.76 '1.50 1.56 1..47 1.35 7.28 Livè Oil Basis (SCF/BBL) Group C7+ C12+ C30+ Compositional Data for Different Groupings Mole % Wt % MW 52.6 82.0 186.2 25A 55.0 258.1 1.50 7.3 580.0 1,.52 1.38 ,1".08 0.96 0.83 0.76 0.68 0.61 0.50 0.50 :'0;45 ' OAO 1;50 119.6 320 SG 0.83 0.87 1.03 . Estimated with the Skimming Method. (Gozalpour F.. Danesh A., Tehrani A. -H.. Todd A. C., Tohidi B., SPE Technical Paper # 56747, 1999) .. Boiling Points Calculated using the Twu Correlation, (Twu, C. H" Fluid Phase Equilibria, 16, 137-150 (1984» Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 17 ~. .:;~;-~ " ~~i:~ 7.51 18.80 .16.97 8.60 6.76 1;50 . (SCFfBBL) B.P. (OF)** 461 610 981 Oilphase-DBR Table 3.3 BP Alaska Northstar Separator Fluid Well: NS-09; Cylinder TC1136 C30+ Composition Component Gas Mole % Wt% Group Mole % Liquid Wt% MW Overall Mole % 58.12 7.82 ~5"72..15 'sl.99 .1,02 '1.33' '2..17 N-C5 72.15 2.18 1.55 1.86 3.02 :<:6 86.20' 1;2~ 3.33 ,3:31 4:52 MCYC-C5 84.16 0.20 0.86 0.82 1.15 8èNZENE.' "78.11 ' ' 0,07 0.22 . 022 '0.33 CYCL-C6 84.16 0.20 1.19 1.12 1.61 7.60 ~~~~~66" (':Ù"i;X;:¡; '{þ::sc;:A,~~~"<'-:""';; :;:1;'~;'J:'i;;j~~;1%1i{Ú:~:J" é#H:~;¥'~~~8~\~i;:¿:~,j2j!~:f;;e¡;~~~Uj\A,i ;':::~~:',c:j,{i~~~:&:;~\),,::_:;'f,;\0;j:~~!~;\,f~:'~';k~ C8 114.23 0.11 5.35 4.87 5.01 C2-BENZENE' 1(Mk17 '0.00 . 0:31' Ò28 0,31 M&P-XYLENE 106.17 0.01 0.84 0.76 0.84 ~~Et4l:~:"":<t" ,',' "::~,~:~~::,,:(~~~~,}::;::~;;,,J!:<::~~f~': dÒ":?~i "".,(;'.",,c!, ":";::'13400::> ';: s " ';::?'i);Ô1:?,,-,':'7 '>:- :';:;::::'5t9ãi;;ri?:(' C11 147.00 0.00 4.87 C12 161;00 0.00 ~.40 C13 175.00 0.00 4.93 '<:14 190.00 0:00 4.44 C15 206.00 0.00 4.28 'C16 222,00-' 0.00 ' 3.72 C17 237.00 0.00 3.46 C18 251.00, 0.00 ' 3,49 C19 263.00 0.00 3.32 Ç20 'L'" , }?l§~Øè);,Ji,Ò¡øø:)..' r:- , ::;:::2~72 C21 291.00 0.00 2.54 Çfitr:: ,. :_,,:~< :'; "::'~lW,:,";'" ,:::;;~:tö';QÓ~f":;~;''<: '.i;fi~~:~~>: C23 318.00 0.00 2.21 -(:24,'. ,æl,()Q, ,',: O:O() , ,,<};áß'" é25 345.ÔO 0.00 " '1.91 ë26': ':~~:OO' ":-':~;~èP~Ø(V ,'f:æ'f,'" ' C27 374.00 0.00 1.68 -C28 388.00 0.00 ' 1.59 C29 402.00 0.00 1.51 C30+ 580.00 0.00 7.73 Measured MW (glmol) 165.0 Calculated MW (g/mol) 33.9 160.5 'S,i~gleStà9øFJåsJ1GOR@$Tp.' '60,3"".:;"', '(M~iMÌr API Gravity 41.8 A"érag~Gæd~rà9itY">e. ' ,",1')t:i2c,;'¿:/1 ", >;,:,~ "', ~" , ~",¡Z~:~,:i;h;j'C Q':'., ,: ,:,'; ..,," ':":~ :'>, ' COntami~atiori(Wt;~)* , :, DeádQitBa~is"':', ',' , ,,' .,lwè'OilBasi!t Contamination Corrected GOR ~támïnauòn'CórrêètêaAPI" ' ," 3.97, 4.45 -4:01 3.86 3,36 3.12 3.15 2.99 ~~5:',-, , 2.29 "'~"; :;,:2)tm?:;r' 1.99 t.l~f 1.72 " <.:i?4t:;>: . 1.51 1.43 1.36 6.97 3.52 ,2.90 2.99 2.48 2.20 1]8 1.55 1.48 1.34 ,../ :,J;Q~:'; ,<'i' 0.93 "ßJ~:1'\: ", 0.74 o:~, 0.59 ;': 0;48 ; 0.48 0.43 0.40 1.41 117.6 16.58 8.34 6.53 r:41 ".~ ' ',-. :S~~F/~_BL~., ',../ - -,,, ."" Group C7+ C12+ , '~:":C3Ö+' Compositional Data for Different Groupings Mole "10 Wt"lo MW 51.6 81.2 185~0 24.7 54.0 257.4 , . ,. " . -. '~1.41' "''1:0''s8Ò~Ò: ' . Estimated with the Skimming Method, (Gozalpour F.. Danesh A" Tehrani A. -H., Todd A, C., Tohidi 8., SPE Technical Paper # 56747,1999) - Boiling Points Calculated using the Twu Correlation, (Twu, C, H" Fluid Phase Equilibria, 16, 137-150 (1984)) Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 18 SG 0.83 0.88 1;03' ::'{SCFIBBt;.), .' B.P. (OF)** 458 609 001 Oilphase-DBR Table 3.4 BP Alaska Northstar Separator Fluid Well: NS-9; Cylinder TC1120 C30+ Composition ( ( ( ( ( C ( ( ( ( ( ( ( ( ( ( [ ( ( ( ( [ ( ( ( Group C7+ C12+ C30+ Compositional Data for Different Groupings Mole % Wt % MW . 51:0 81.0 185~2 24.3 53.8 258.0 1.44 7.1 580.0 SG 0.83 0.87 1.03 B.P. (OF)- 459 610 981 . Estimated with the Skimming Method. (Gozalpour F., Danesh A., Tehrani A. -H., Todd A. C., Tohídi B., SPE Technical Paper # 56747, 1999) .. Boiling Points Calculated using the Twu Correlation, {Twu, C. H., Fluid Phase Equilibria, 16, 137-150 (1984» Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 19 Oilphase-DBR Figure 3.1 BP Alaska North Star Separator Fluid Well: NS-13 & NS-09; Cylinders TC-1137, TC-1119, TC 1136, TC 1120 C30+ Composition Comparison 100.00 -:-'----'---' ----_H_'- - -----------_. -. - -_._._.._._-----------_._._~._-~-~-- ~--- -----. --~.__.,. --- - - ---------------- --------- -...-_.- --- -------- -----------.--.. ----------------'-~- ----'- n__- -. ---.-.---------- '.-.--- ---_._._-~ -----'-~- ---,-"-,--,--,---------,--- ----_...u---- -- - --- -______n___- ----------------------- -+- NS-13, TC-1137 =~~~~=-~~~~==::.:.:~~~=:~~~==- -----~--------- .--..---.. '-'-------~~---'---'-----'---"-'--'---~- ~ ~ --------_'-__UM_'____-- ----- - -.. """-NS-13, TC-1119 -- -----------------,------------~-------------- - NS-09, TC 1136 ----------- ___n_- --- --- ---------- - ------ ______n____._----.------..------- ----------- -e-- NS-09, TC 1120 ---- ------.,------ ,----------~------ ---- ---~ -- - ------ ----------------------- ---------",--______n -------- 10.00 -: ... c CÞ CJ ... CÞ D. ... s::. C) ë¡; ~ 1.00 ~I 0.10 -: ~ 0.01 . . . , . , . . . . . . . . . . . . . . . . . . . . . . . . , . , . . . . . , . , . . . . . . , , , . 6''' .[J-'o ~" ú~ ú'" ú., .¡J' .;J" /f' jJ' ð' d-" .kt'" " ú~ " It'" ð' ,$'" ,.fý+'" ,.fý~'" .ë qj>.@T ¡jrY .¡;.ë ~&.::; , .é" CI~ <:Ji ~'tr ~ ~ ~ # ~ ~ ~ ~ ~ ~ ~ d' ð~ r!P' ¿p ct cP ú~ éP c? ¿f #' Components Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples Oilphase-DBR 20 Table 3.5 BP Alaska Northstar Separator Fluid Well: NS-GS; Cylinder TC1126 C30+ Composition C29 C30+', ' ,h ,', '.~~'V(9.I!JI,9J) , Calcu~ate~",~ (,gl,m~l) .. ..' " Sln91ë'Stàge:Flàsli:ØOR@~TD API Gravity Aveiïigê:'Gas'.GråŸlty' , Çp~~I11II.'~tlCNI(~%)~. " , Contamination Corrected GOR Contåmlnåtfori CôrreCted ÂPI ' C12+ C30+, Compositional Data for Different Groupings Mole % Wt% MW ,~~~ , ,8iLO' '18~~5i! 24.0 53.8 262.2 1~79 8.9 580.0 Group . Estimated with the Skimming Method, (Gozalpour F., Danesh A" Tehrani A. -H., Todd A. C., Tohidi B., SPE Technical Paper # 56747, 1999) .. Boiling Points Calculated using the Twu Correlation, (Twu, C. H., Fluid Phase Equilibria, 16, 137-150 (1984» Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 21 Oilphase-DBR Table 3.6 BP Alaska Northstar Separator Fluid Well: NS-08; Cylinder TC1142 C30+ Composition ~,~?!}j~'M~~~~t??:~~i~~:~t~!t:~ : MW Gas Mole % Liquid Wt% Wt% Overall Mole % Group Mole % '.,....., ".r .-g.. ~~,.t~- \~:~; ::.; ,.~;<~ j-"~~'':;): ."- - - -- ~ ,- - .; ~;:~; 5-;l~-~~:-':'~Íi\~~;;~~~~!~~~~ 18.77 Group C12+ C30+ . Estimated with the Skimming Method. (Gozalpour E, Danesh A., Tehrani A. -H., Todd A. C., Tohidi B., SPE Technical Paper # 56747, 1999) .. Boiling Points Calculated using the Twu Correlation, (Twu, C. H" Fluid Phase Equilibria, 16, 137-150 (1984» Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 22 Oilphase-DBR Table 3.7 BP Alaska Northstar Separator Fluid Well: NS-15; Cylinder TC1124 C30+ Composition 7.44 (SCF/BBL) Compositional Data for Different Groupings Mole % Wt% MW 50.9 81,0 186.2 . Estimated with the Skimming Method. (Gozalpour F., Danesh A., Tehrani A. -H., Todd A. C" Tohidi B., SPE Technical Paper # 56747, 1999) - Boiling Points Calculated using the Twu Correlation, (Twu, C. H., Fluid Phase Equilibria, 16, 137-150 (1984» Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 23 Oilphase-DBR Table 3.8 BP Alaska Northstar Separator Fluid Well: NS-15; Cylinder TC1141 C30+ Composition C12+ t30+ Group . Estimated with the Skimming Method. (Gozalpour F., Danesh A., Tehrani A. -H., Todd A. C., Tohidi B., SPE Technical Paper # 56747, 1999) .. Boiling Points Calculated using the Twu Correlation, (Twu, C, H" Fluid Phase Equilibria, 16, 137-150 (1984)) Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 24 Oilphase-DBR ,~ ~ 1"'""""\ ~. ~\ .~ 1"""'"". r-"\ ,,,,,",",,\ ~ r-'\ ,,......., ,.....-" ,"""-" ¡--", ,-..~ ,...,...., f"""""'; r-"""I r-x ~. ,.......". .~ .~ ~ F~ Figure 3.2 BP Alaska Northstar Separator Fluid Well: NS-08 & NS-15; Cylinders TC-1126, TC-1142, TC 1124, TC 1141 C30+ Composition Comparison 100. 00 -::'~"~_.,--,.._"--"---"'--_._-'---,.--'-----~-------- .-..- NS-08, TC-1126 .....-. NS-08, TC-1142 _NS-15, TC-1124 -ll-NS-15, TC-1141 10.00 -= ... t: CI) ~ CI) Q. ... .r:. C) .¡ ~ 1.00 -:8 0.10 -= . 0.01 . . . . , . . , , . , . . , , . , . I . . . . , , . , . . . . . . . .. '.,,"" _._-~-------- . . .. . " ' ##~Çð~~~~~~~/~ð//~///~~~~~~~~~~~~$&$ð~~&~&ð ~ð 'bif (}ò' ~v ,,0 # q:1- (iT c:J ~ Components Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 25 Oilphase-DBR Table 3.9 BP Northstar Separator Gas; Wells: NS-13 & NS-09 C15+ Composition Component MW -§gg~' "'~';"~"j'~,o17:;ij~'-:;f:.: H2S 34.08 -øÎ};¿,-~({" ' ' '-F:<~:; N,H~28.:Q1" " C1 16.04 ~~~\ > , i3g~q?: : C3 44.10 .~'" :'58]2, N-C4 58.12 '~Ì:~:, ,,7¡:;72~'15<~ ' N-C5 72.15 IQ.::'j?c;-';\,- ,::86.;~():" MCYC-C5 84.16 I¡Í~NZEN~' , t8~11, CYCL-C6 84.16 7~~\r"â'ii, ,"" . . 'fôo.2ó' MCYCL-C6 98.19 î~ijiNE' , :'92:~,~, C8 114.23 Ç2~N2EN "~'::~Ð&;,~t,.;, M&P-XYLEN 106.17 O..XVLENE106~17' C9 128.30 ~fO' . \l3Ät~OO C11 147.00 ~î~ 1'6t~OO C13 175.00 <:14 ,190~()O C15+ 206.00 Averói~e Molecular Wei~ht Gas Mole % NS-13 NS-09 MM38810 MM33040 MM33085 MM38865 MM33082 ; &$2"/!£{i;4> :W,; 0.00 ,';~~Y;J';' <;: 78.14 .1~tf4 . 4.02 'oIs't 1.11 .'0;26 . 0.29 'O~1~ . 0.03 0.01 0.02 "ôrör .:,. 0.02 :~': :(5;ÖQ" 0.02 ,,-:0.000.:, "'.":> ; 0.00 O~OO 0.00 0.00' 0.00 Q~OO.: ", 0.00 O~OO 0.00 21.49 : 66!Sà«,,; , 0.00 ':;.~~:" 78.15 'r:~ ' 4.00 .: Ø:57 1.12 'Òi26: " 0.30 :'<è,O~: 0.03 OJ~1 0.03 "0;Ø7,' 0.03 './ " Ói'OQ: 0.03 ,Q~ø,p,< 0.00 "0.00 0.01 0:00 0.00 . cum: ' 0.00 O~OO , 0.00 21.53 Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 26 . .'-';:;"j;'if61&ff'" 0.00 :;'$~n,:~;c'~,.' 78.44 ,;t//!!. . 3.81 0.53 . 1.02 . ;"0.;24:';"" 0.27 "O.l'~" 0.03 O;Ot 0.03 O:öt, 0.03 'Ö¡ÓÖ 0.03 O.QQ'''',. . 0.00 0:00 0.01 0:00 0.00 ,0.00" 0.00 O~OO 0.00 21.40 '.: '~~~~~.xqw~rt:i¿~';'i<;~i~:I!:::<'}':.'! 0.00 0.00 , : ',';(!Itf??}':t'~:';;:Hc;i91§~t; 78.34 78.61 )~;.=f ' . ~.:1¿63 " ' 3.85 3.94 O~5S , O~55 1.05 1.01 -:~26( ,> Ó;23' < 0.30 0.26 'Q;24: ,:: iO..'9.:>. ' . 0.04 0.03 . ~U),1 O,P'. 0.04 0.03 'ö~1-f d.œ ' 0.05 0.03 ,. . 0:01 ' ,'O~ó(r 0.06 0.04 ,f);Q(t-- -' Oi.OO' 0.00 0.00 , 0.00 O~OO 0.02 0.01 '0.00 .0;00 0.00 0.00 ø~OO ' 'O~OO." 0.00 0.00 0.00 0.00 0.00 0.00 21.58 21.41 Oilphase-DBR Table 3.10 BP Northstar Separator Gas; Wells: NS-15 & NS-08 C15+ Composition Gas Mole % Component MW NS-15 0329 0343 NS-08 0342 0327 g,~:;:::'N. " ':: '<',:~: ,,' ",'j' '; :,:';\; .:'::':;~6g1;;~:¿:{ 2:';(::;'?:;§~§§:,)1:\~'i2". \':c,:,',):,':ø}z~.r2~:r~L} .~,;"lÜ;¥!~g@~j::~'!s;¡~i',(::i/-;,~,;,.!,g.ä~~;i:i,~;~5;j,; H2S 34.08 0.00 0.00 0.00 0.00 ",'i;¿~~Ö1~~}Y~.,;' :';"," "";~:iQO;,~;;;;/ i;,," ';::;r;~::~~~i':' ,,{t!\:';';Ai:'qlØ',;:'~h,):'~ ' ' t:f¡:;ô'¡~~t't:~=+:?Y¡ 16.04 79.20 79.14 78.36 78.53 44.1 0 '.''';i~~~~2:.:')<;:':- :, :,,"..~~~~.>::::,}" ;,~'~~~~::;, ',:, .,;,;;': .<,~~~~':~;:::,';;:::;, ,g,:,:' :, ':' , >::f5Ø~~2:;:::~'" ",:.o;4~ ~~"";,"" "",',Ø:4~;):¿ ;':' , ,,'::;:'::i~ø:~~j,}:ki;;; "', "" <.',;:;',P;4Q:\,,;,,yg: N-C4 58.12 0.81 0.79 0.96 0.94 Î~~\"" ":: " <'::!~~,~J:[>r '\;',:,,,Q~~i-r'.;/\::;; ,', ,.:.:,9::17~,;/::::':!": ,'l ,"f:g~~~~>.t::e,2:., ~<o~2l' ,,', '~:;':~ N-C5 72.15 0.19 0.18 0.25 0.23 C6::!:~" . , , "':';::":).86~~O:;.;:;;: ,,':,p:'tà+>:i;', ',,;O~tl" ,'j''',;,9~'16?;(. ':0;15,', MCYC-C5 84.16 0.02 0.02 0.03 0.02 ~ì;"~i;NE:'/ ::,,;, "."jZ8.:',1;',':'~>" ":Ø;01?~~;:i",' ,,' ,""/:,.;~;O;),:f:;"" '::OiQ1,::,' CYCL-C6 84.16 0.02 0.02 0.03 0.03 (:.1:;',";""::"':'" >',:,' :\:1'OO~20:"'~'{'ø~a5::;':":' : "~~Ofi?:':'{':">+::<"Ølœ~':;,¡'!: ",-();(1a'> ,,< MCYCL-C6 98.19 0.02 0.02 0.03 0.03 rQL~~~,Ë': ' " ~2:~14, ',Ò~()1 , " O.~'ø1. .:: ,"Ø;O~f ' , ;. '();P1' C8 114.23 0.02 0.02 0.03 0.02 g~~,§,~~t;N:, ',' ,,: ',,:, ,>:',1,qØ~,tz~ ' ,'Q:~Q~t'"" ", : 'Q':9P '"::.;,, '" ,9~QØ~' :, .J~.()(),:: ',: M&P-XYLEN 106.17 0.00 0.00 0.00 0.00 ø~xYa;ENE, ":10~A7, ,'o.OO;"Ò~OQ, ' ,(tOO, "O.pO C9 128.30 0.01 0.00 0.01 0.01 Ç10:,:t34..000~09 ' Q;ÒO': ',' ,':,O~QO'i:::," I,' ' 0;00, C11 147.00 0.00 0.00 0.00 0.00 C1'2' '1~t1ÓÓ' 0;00. '0.00" J~.O()'. :::::',O.OP'i" C13 175.00 0.00 0.00 0.00 0.00 Ç1~".j9Q:JjQ ',,0.00,. ;'O~Q(f':; "~I :"O~qQ :.;,::(:g;.Q~[L';',~' C15+ 206.00 0.00 0.00 0.00 0.00 AveraQe Molecular Weight I 21.07 I 20.99 I 21.38 I 21.30 C1 , t [ [ ( ( l ( r ( r Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 27 Oilphase-DBR Table 3.11 BP Alaska Recombined Reservoir Fluid #1: NS-09, 5100 psia Psat C30+ Composition Component (SCF/BBL) . Estimated with the Skimming Method. (Gozalpour F" Danesh A., Tehrani A. -H" Todd A. C" Tohidi B., SPE Technical Paper # 56747, 1999) .. Boiling Points Calculated using the Twu Correlation, (Twu, C, H" Fluid Phase Equilibria, 16, 137-150 (1984)) Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 28 Oilphase-DBR Table 3.12 BP Alaska Recombined Reservoir Fluid: NS-09+NS-13, 4850psia Psat C30+ Composition Component C9~ -~' " H2S ~2 ' C1 C2, C3 J.pI:' ,', N-C4 i~~':' N-C5 C~<';:ê', MCYC-C5 ~E~E' CYCL-C6 C~:"-', MCYCL-C6 TOLUENE C8 C2..aENZENE. M&P-XYLENE MW ,~,Qt.' 34.08 .:'~.91 16.04 :,30.07 . 44.10 :/'~sâj2, 58.12 . .,.7;1..1.5 72.15 ':.: 8t)!2.° , ' 84.16 ,; 7.8.11, 84.16 .'.,"'100.20 98.19 .$2.1~ ' 114.23 , 106.17 106.17 106.17 Gas Mole % ., :, ~i13 ,',:- 0.00 ."o.~' 69.25 ,:"-'.8,85,",- 6.31 _:;~:',:,'t2.3 .- 2.87 <' ,0.98'" 1.23 ,,:':';1105 0.19 :,.t07 :," , 0.20 ,0:39 ' 0.18 0.05 0.15 0.90 .',. 0.01 Liquid Wt% - :,-'~:q,og;: 0.00 'CXoo:, 0.00 :~'.:::":rQ.gg~'... '. 0.13 ,..\;.~;'(t09:~: ',:,<,' 0.39 >'il51c"" 0.92 -:;~:";2.~3:;: - 0.73 . :,:0.21' 1.04 , ".:.3.-eo . 2.23 0.E~9 ' 5.05 0.15, 0.84 Overall Wt% Mole % , '" .~:>';~~.;->,,::.,'...,_~4,~- ,', _.':. ' 0.00 0.00 :,.Q:30-.'-' :0.6~ -. 15.15 54.53 ',\: ~.63- ; .~':.: ~,".: .~.97:':,:,-, ': 3.88 5.08 , . f03 '."' '- ,:~¡ Ü~:}, : 2.53 2.51 '1:3Q '; 1..04 : 1.80 1.44 , . ,:\'~.95,'_:' ';j;~~:r-:-,>~:; 0.69 0.47 ,0,2,1,0 - ~ ,p.:1.~.',\":?':'" 0.90 0.63 '2;88, ',,:.:Eæ.':', ". 1.70 1.00 '., 0.5~ ,0.32, . 3.52 1.78 0.10' ..,0;06 0.57 0.21 ' Group Mole % '. "4j!S~:" "':~". 0.00 Ji.6?:. " 54.53 , ,:;:,6~?:.:'.;.~': ':' 5.08 .~;:;:r~:{-Q3 ..,~_.:' 2.51 :' <.1:~}" 1.44 C14 ( t r ( 0.00 0.00 ,<:.0:00, :',: 5.88 1.62 1.06 0.16 Group ,C7~ ' C12+ C30+- Compositional Data for Different Groupinqs Mole % Wt% MW , ,1.8.7:, :62,0, " , 1~1>q 9.1 42.2 267.1 0.76 ' ,7.7 ' 5ào;0 SG (U~3 . 0.87 ,1'~03 ' 25.6 ':410:4:':, 39.6 , :Q,885:-;"': ' , P~d()il~~~i~,:: ~ ~:';..'~; ,,~, ,: ,: ,: :~:::t .'.,}:~;~' ~'. 176.7 , (M~IM5\:' , , (êÇf~~~~)-' . Estimated with the Skimming Method. (Gozalpour F., Danesh A., Tehrani A. -H., Todd A. C., Tohidi B., SPE Technical Paper # 56747,1999) .. Boiling Points Calculated using the Twu Correlation, (Twu, C. H., Fluid Phase Equilibria, 16, 137-150 (1984)) C28 388.00 C29 402.00 ë3(f1;:,'<;':~: ': :'"",, ,,:::'šàõ:ùØ, :,:, "'~a~Hrcft,cl.~YV~.(èlmpJ),'¿:::..:,,:.>;:n'J;D: ,~:, Calculate,~PJlW(g/mol) .. ". " ' ~1"g1~$~9!,:fl~h'~()~,@:~'rD::' , API Gravity Averøge:OasGravitÿ:':::,', :',' COI'1~rn'lJ,a~.9!) (W:t~)~::[:L, " :;" ' , Contamination Corrected GOR cc;ntiriiinå'tiôl1côtTêCt8d API '; ( Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 29 B.P. (OF)** :47Z, 626 ,:981' Oilphase-DBR Table 3.13 BP Alaska Northstar Recombined Reservoir Fluid, Well: NS-08 C30+ Composition Liquid Overall Wt% Wt% Mole % 0.00 ' 4.04, 5.09 0.00 0.00 0.00 0;00 0.32 0.63 0.00 15.98 55.16 , 0.00 3.82 7.03 0.07 4.03 5.06 0.07 ' 1.06 1,01 0.27 2.56 2.44 0:35 1.23 0.95 0.61 1.66 1.28 2.14 2.711.74' 0.64 0.65 0.43 0;16 0.18 '0.13 0.99 0.88 0.59 3.62 2.91 ' 1\61 . 2.48 1.85 1.04 0.7&- 0~55 0.33 5.58 3.79 1.84 0.33 0.21 0:11 0.83 0.54 0.28 :~: ;(!j~52~' ,: ~ ~;r~;:~Y~.~~~:(ji~~'~~~~(~~::~:,'-:<~ ;-\ :.~:~')~q~l:1~~;~~ ~~. '~~ ~\~'~".~'f[0:Y:~7~~f~ ~ - ,: , ~ 5.27 3.40 1.47 '. f);~,'.,'" ",;ifi~';::f~kt4:f:<'~:, :,)F;æì'E:!,:~"Y'~,,, )':ï~r~;",:,,?::~: 5.42 3.40 1.28 - :4:83>, ,,', > : \:.3:03 '1~ò4~:,; " ~ 5.41 3.39 1.07 t ' /'.: '. ¡fŠ2 .' :,:.' ;~: ,;~¡;.::~~:;ji:ö3;:X[(~/':/;;t::. .:; :;'0;$8'\;);: .t",:;:, t;';:;5.'99:1;:"ë{;~:<; 4.65 2.92 0.79 '/, "A~oo::",. '; ¡;;::~4;t.17(':~<'::\>j,:h;g;~;,,:c: "", ' ". ., ¡., " 3.72 2.33 0.55 ;3~71, "2~3a}-' ',O;S{, ~1 2~ O~ '~)::.;;t.:2~æ'"f ,':':' ;': "'7;:.;:;'~1~t~~;/i;;:;;;~;:::' ,:"f~~;;5:i,C:' :';D;f;;i:,;; " ;i'- 2.68 1.68 0.32 2.:4'3'1:52':, <,>\þ;2~ ' 2.30 1.45 0.25 , 2.0~' . " '> ,1;31 ' i 'Ô.22 " 1.99 1.25 0.20 c, ",>:!.' ""I:~1:6&,: , 1;0$:':,,:0.:16:"' , 1.78 1.12 0.17 , .1.68: {OO"Ó:15 1.57 0.99 0.14 2.24 ".c{2':Y:'::(,'(:T.6S" .;, >4~Ò';2> ",.~j::¡::b:4ß<;¡;'J, "~:O:46" '1;.< ,','/:" \', ',,'I": Gas Component MW Mole % CO2 44,0.1 6.36 H2S 34.08 0.00 , N2 28.01' '0,79 ' C1 16.04 68.99 a '30.0.7 ~.79 C3 44.10 6.26 I-C4 58.12 1.22 N-C4 58.12 2.84 1..cs72,15 0.98 N-C5 72.15 1.23 'C6 SE).20 1.10, , MCYC-C5 84.16 0.20 BIj:NZENE 78.11 0:0.8 CYCL-C6 84.16 0.22 C1 100.20 0.44 MCYCL-C6 98.19 0.21 ToLuENE 1Ì2.14c. 0..05 ' C8 114.23 0.17 C2..s~NZENE ,106.17 0.00 M&P-XYLENE 106.17 0.01 Q!XYîtEfÆJ:i~!~";S,':' ;:F;'11T';:~Ifffß6H';;;,:"}'¡;: , !,;':;'/7ijÕt'QõY~~:nT,::I~' ; C9 128.30 0.05 cÇ1;~~:~?t:: " '.,; , :"~~i~,ÐQ':)'§):': ,i:,: ,:f;?Lp;Ø'2:~;;;fi"; :;':,_. C11 147.00 0.00 Ç12': ,. ,. "'61.øo,, ,'HÜ,IÒ, ~3 1~m om c~~4i; ': '" ;<~;;, ,.~4'§d:tJ(F¡::~,c ;~, :-:'j?;;'Ø;Q(r~i''-:, C15 206.00 0.00 ~jØf;:,'; , :> 'i, , ";;2~:Q9:. ,.':Ö;~Ó:;~¥: C17 237.00 0.00 (:18' ' " ':25,1iOO::,0..oo '" C19 263.00 0.00 ç~oT:: ,', " ,:;." )';1 ,":-. ':);;;/~7~ôQr:,\;:l>:f;{;':ii}%[ctOô(fi:t;.:.';;: C21 291.00 0.00 C22" ',/3Q5:òO :" ': ',0;00 ". C23 318.00 0.00 è~": ::'ãàHQØ" . ','O:OÖ: C25 345.00 0.00 þa',:', . ,~9~oø:" "i'. :'\0,'90:', C27 374.00 0.00 ë28' - '~;(){} , ,': 0;0.0 " C29 402.00 0.00 -ê.::,::(:f~;;0,,":,F' c'" ;;ssoiÔ(F;;" ~'::.';;&xjQ'/!;:;'" ~~ur~:MW~(gJm';I). ' Calculated MW (gfmol) -$iri91è\~:F¡~:èriR@"sm"'"F , API Gravity . Avw.gé:OaSGravlly¡ ",' ÇÖl1bl,rr)il)~.()~;(~,%)~ ',:'.' " , , ' Contamination Corrected GOR CÓnt8mlnatrôitCom.Ct8dAPa' 25.8 ':c45ø~9 ,c; 39.6 ,;o..891L:, , >QeadOil Bä$is 173.4 "'(M~JM3)' ~~ ,',':"- 55.4 ";'::25~':~' ~..<':~> " .. , - "1 .">~;':-' ~-:,~ " .}.....,;~~~'-~: or.: (~CFfBBL) . ': [;i~:,OítSäSis , , ,. ' Group "C7+- C12+ C30+ Compositional Data for Different Groupings Mole "10 Wt% MW , 18:5 " 60.9 ' , ;18~.4: 8.6 39.8 254.9 0:46 4.8 " .580:0,' SG , '0:83 0.87 '" ,,1,03 , . Estimated with the Skimming Method. (Gozalpour F., Danesh A., Tehrani A. -H., Todd A. C., Tohidi B., SPE Technical Paper # 56747, 1999) ... Boiling Points Calculated using the Twu Correlation, (Twu, C. H., Fluid Phase Equilibria, 16, 137-150 (1984» Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 30 Group Mole % 5.09 0.00 0.63 55.16 7.03, 5.06 -1.01 2.44 0,95 , 1.28 2.89 6.85 , ,r, . ~ 2.93 , "(SCfl)iBt) :' ",- B.P. (OF).. 452 605 , 981 Oilphase-DBR Table 3.14 BP Alaska Northstar Recombined Reservoir Fluid, Well: NS-15 C30+ Composition Gas Liquid Overall Group MW Mole % Wt % Wt % Mole % Mole % ;~1~1t:~Ç';i~'M,:t: :~'j)é'!"¡~~~§~:¥~:'jf'~\1~;' ~1:Ktrf~:~~'~~~~~~te.:::~';;\i~:~;~i1~j;i:';~!::¡;}Ì~;i~[::\~~:1:§"T:;~i¿~!;~~tm~;~ 34.08 0.00 0.00 0.00 0.00 0.00 ','.' .". ': ..;~"2àj)f'~' :~'..~.. .~>." "';ö;"~::.', :";: i: :f ;Ó:òØ:;':<c.c:~::<:);~H:,;,r:S:<~;:'(Ò~/c :::..,':. ,.;','¡""\Ó;~?'-:'~: 16.04 70.11 0.00 14.34 53.07 53.07 C3 44.10 6.57 0.13 3.78 5.09 5.09 ~'I~~~ï~&~~:i~i~~i~fi~~D?i1gq~{iI~~~~~1~9~~'tMiil~~~~\~;lfiìII'.~Ji\~~IJ~i~1i~t8f~~ N-C4 58.12 2.88 0.49 2.47 2.52 2.52 1~5~~;,;'~::.;.f:i ":'1?2;1p' :':i: :::. > >o;tli,: ,', ¡. , . ~:Q:69::/:,(:,'~~:-,:i'.)j-;'19~;.;;:::~)\: ':J:(),~~'T" ,;~'.":';~Q:Ø!i:,;'-":,~ N-C5 72.15 0.88 1.17 1.61 1.33 1.33 B.~i!t1l;¡1ii1i\1~¡¡i.~.~§rÆii!UI~\till!.'11ll~~¡'I.~i1i~1f1F.~..'i'I$.ll~~III1II~I\_B' MCYC-C5 84.16 0.09 0.83 0.67 0.47 BENZE~, "7~,11:' ,,-,.0,03- :":':O~2',:'-- ':0.18'::', O;1{ . CYCL-C6 84.16 0.09 1.17 0.90 0.65 3.13 c'f,.;~?:::~':',~~:':"':';" ":--':":¡OO:ïó ,'..., :... ,~.. "c'Õ:t7'-;"" ":-, "-"~:':':''¡:98:;.'::''~:'~' '; ,c,' .:~:Z:~:;'::':,~'-': :,'::t::'~1:1'jF;::7::~;:":::":::::':';-;:;': "'::T MCYCi.:C6 ' 98~ 19 ' . 0.08 2.63 '1.90"" 92.14 . ' . O.~ ().a4 ':.à~60'- '. , ( [ ( ( ( C28 C29 C30+ ' Measured MW (gImol) Calc'ulated MW (g/mol) Single Stage. Flash GOR@STD API Gravity Average Gas Gravity Contamination (wt "10)* Contamination Corrected GOR Contamfnatiòn Corrected API 1.02 5.81 0.15 ,0.59 2.51 0.59 24.6 362:7 40.2 0.850 Dead Oil Basis 167.5 (M3/~ 59.4 2036 (SCFIBBL) Uve Oil Basis (SCF/BBL) ( l ( ( Compositional Data for Different Groupinqs Mole % Wt % MW ,':':~P;5 '63~7 ',;1'84,$. 258.1 "'58tÜ),', SG ,O;8~, 0.87 , ,~)1:03' B.P. (OF)** '4!)S'. ' 610 .<;;,,981: :' , ' '. ..;.' ( , r ( ( ( ( ( l l. * Estimated with the Skimming Method. (Gozalpour F.. Oanesh A., Tehrani A. -H., Todd A. C.. Tohidi B., SPE Technical Paper # 56747, 1999) ** Boiling Points Calculated using the Twu Correlation, (Twu. C. H., Fluid Phase Equilibria. 16, 137-150 (1984)) Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 31 Oilphase-DBR Table 3.15 BP Alaska Recombined Reservoir Fluid, NS-13, 5100 psia Psat C30+ Composition Component CO2 H2S ,~2};;d;,:", ';:' ',;-\ ',> C1 -d C3 ~, N-C4 l;.cs N-C5 ~_:'" MCYC-C5 ä.í;Ñ~E::c;)yt;:; "~;" CYCL-C6 C7.' , , MCYCL-C6 :t9~Ø~~tf1"k;'?;'.i!;;:; C8 .cZ-BENZENE M&P-XYLENE O-XYLENE.. c C9 ÇfQi,;,«:i,t,,;,:,;,{t :; C11 C~2,;::' "\,, ::,';',,, C13 Compositional Data for Different Groupin~s Mole % Wt% MW 17.5 60.7, 189.3 8.4 41.0 264.6 , 0~66 7.0 ' 580~O SG 0.84 0.87 , 1~03 B.P. (OF)** 468 622 981 . Estimated with the Skimming Method. (Gozalpour F., Danesh A., Tehrani A, -H., Todd A. C,. Tohidi 8., SPE Technical Paper # 56747, 1999) *. Boiling Points Calculated using the Twu Correlation, (Twu, C, H., Fluid Phase Equilibria, 16, 137-150 (1984)) Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 32 Oilphase-DBR Figure 3.3 BP Alaska Northstar Formation Water Collected at LP Separator Compositional Analysis MAXXAM Analytics Inc. Glass NJA '':::':'.~::\'IQ,..~;.1~l ';~",,¡:..:;:: ~':>.~"I".J:'! (.',\o:!1I:D DBR Re5êau:tJ Inc. C'r'~'...:'\\' N.;~;"G¡ DBR RESEARCH --~~-,- ~t~~~'~",:,~r¡!~, WATER ANALYSIS 02.28273-02 i.~~:",~.:t:O,""'~~~!I~r t:3-C' 1-;'...NC' N/A DBR --~~---_._---~ ---~ N.i..~"~'':,~.(,\¡?f ¡:;"':~\'i¡~,~:-;" :;;,~1'\',t\r""r.:~r.( DBR 2Q02.63JOB:20023132 :~;;;~;~;-~~~~;~~;~~:;;;;t_.m--_.....m.....m...m............ 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""""'1"'"....................................t................................., 1670 ¡ 47.1 Ion '......... Na 1280 55.6 K 10.4 0.3 Ca 19.4 1.0 Mg 5.8 0.5 Ba 0.31 <0.1 Sr 2.81 <0.1 I Fe 0.1 <0.1 B H+ CI HC03 2481 4.1 504 I 53.41 1.1 C03 <1 i <:0.1 OH I <11 <:0.1 I I H2S I ABSENT I 104 Na-' 'I: Logarithmic Patterns of Oissolved Ions (meq/L) 10 Q1 " " . ¡'.. 1~ "!_.. I , I ~ " ..---- - .-. "f ~ ~ 'w;,;::;";¡;'''''''''''''''''''''''''''''''''''''' """""""'"'''''''''''''''''''''''' MHIRWJtDL .J...1,5.t"~1 Tota! QissoiVed Soil\:ls i.m~1.) ...--...............~.1Q, form $\lSpended Solids (rog.'l.i ....................................... ,----..-..LQ~ 1.333 .r1f..-iativ,e aan~'Cy R"",....1ff" ind". 6.8 ........................................ 1.73 --................................... O/;t$e,~<1d )r'¡ fìesb~.i!ym"'i ,#25'( -- 72.3 ---- 203. 1<-ta;¡'¡(1rdr~5 11..10 C;¡ijr.ì,. (!IIfJiL) 1 (.t..;AJJ4;ci'rat~. /¡$ (;;<(.'0.... I"'ý/!..,I ~~-~ ------~- M-;.~óaoof {~.t-"4J (M"'; Or;.""" ~r~'tJ '~"n'--"'....n..n.n_.. r,,!;«/'<> {1<I¡Iit) Total Mn {t>1\l,C --_.--.~- ~~,,~ - 1~ II":, CI I : ; I , I ~~ S04 C03 &~(J\)\1a!ß¡;:.~;!!(I ¡;~~ mMllfl1(~'~'r", af~ re( !Sß¡I!<)< f: tit) ,paSfÌ'l1 s f\d\.~I¡; !~hIe OOV1úikll\;;1('stN flemar!.:s: LPSEPAAATORV1ATER Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 33 Oilphase-DBR Figure 3.4 BP Alaska Northstar Formation Water Collected at HP Separator Compositional Analysis Mt\_X!Ç~ M ~_~_!'lï!!~!J~~ Glass N/A "~".- --- --- ..."- ----------, ~';~:<;! ~~ (:':'.'11;::1~"".\.v,;t~,, -~..r(..."..: '<:1.>,' ,,;~! ¡Ç{'¡¡ ?,JJ.<¡ ,'L DBR Resea!dì Inc. ..... ~;¥..".- ~--- - >,.,.,_.~,-...............- ¡~\.:.>"$f,":";:'¡!i~ DBR RESEA RCH ---...... WATER ANALYSIS 02*28273-01 L.5:... N/A ,'),fo~)¡~ ç( -,"'o'(:.pt¡'< ~:~i"iP..;< t-,;.<;r:c DBR 2002-ô2JOB:20023132 ~~~.!.:) t;'~!~ .:o'-''l~ ,r.-,~~~ ---~-~---_._------_._-~ ---_."----,-,-~.--'-'-'-"~ -------------.-..--" __'_._A.___._-~._---------~----------------~._.__.~._-~.._-----------~---~-~-----_.-._--_._~-,"-~--" 't"c;:>;j t~...,:::o,'(;,'}' .~:~';::."rñ.,} ~\{¡:í)~''';:'' .~\'~.-.. ,X~ ,"'{'YJi.\.'r~,:.\" ~M"':~ 2002/04/11 2002/04í1 t CATIONS Ion Na 6390 278 K 42.3 1.1 Ca 87.0 4.4 Mg 12.4 1.0 Sa 1.0 <0.1 Sr 13.0 0.3 Fe <0.1 <0.1 B H+ ANIONS Ion mgll. i meq/L "-------------------l"--' CI 8450; 238 HC03i 1360! 22.4 ; 804 ì 154 ¡ 3.2 ! ! C03 <1! <0.1 i OH <1 : <0.1 H2S ABSENT I 104 Na Logarithmic Patterns of Dissolved Ions (meq/l) 10 0.1 1 C.3 1(;2 Cð -;-;-.-- I ' ~ Mg -,-.. -- - ... I - ~, - Fe };~~'~(;~;;.{í,;;:;,-'-- - ---_.._------~~.~-.__. . n'".;; .St,H~f- ..~~'" MHIRWILDL ~ ~1 !:V'.'.1 )f'l1\'tr¡::,,~~ ¡:i'.,>¡.1¡;. DBR -'------"'."-~,_-----~---- H.-~_r,.~ ::~-':'3'::~'V.'1 16700 -------~--~p--- T Ofaf OIswivecl SQ/i¡'js (!>1gtp T.xa! Susper.æcl SoiiJs (mg;1.,i 1.011 --. _._- - -.,,--------..'..- pl>t-\J~r.-<.'f" r:~..~~t¡, {~~l)I',¡V.~;flh , ._--~~ 'r"1I~I¡'f(l:'dn(-<$.('Jt:; (~.'f/~':.o~. r'¡¡£i.{j M..,JÍ1an~1 {wn¡) Jok~í h. ~~;~",-) 10 !()2 ~j;-~œfj~n~~:'S~(1~ï.aB mfu~d(tç~'\~vm::,f-iì'i)'1 wr¡¡t,fr.¡~~4)t [1,ln ,~ItIS I~t¡ S n('!,~:¡!lk'j. HPSEÞARATOR'NATER Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 34 ------,._~------- 1.335 - --,,------.,-------- fìeb at.'tiYt. ir;.jë~ 7.6 0.403 fi(.~::'\r,~Y {Um' ,t!:25 '( - -----_--1)1(2 r orar A'''af'r,J.~ {' A~ t-~;;¡CÙ), ÙHf.vU O!I~ Gr~'{;í19l.' r~t;11 ,,".1n (fJ~p.'t ()'"..¡k- r~! 103 ---..--,..~-. ,-- I , ' I . . H<!.'"$ul~ :e~f,~ l:~W!U ?¡~lj1$ k ~J.:.~~ Oilphase-DBR Table 4.1 BP Alaska Recombined Reservoir Fluid Well: NS-09, Field: Alaska Northstar Constant Composition Expansion @ 254.5°F Pressure (psia) Liquid Volume % (%) Relative Volume V ,=V fDlV sat Liquid Density (g/cm3) Compressibility Co (10"psï1) y- Function Value .,-:. ; Psat ( r ( r ( r [ ( r ( ( ( ( ( ( ( ( ( l ( l ( Vr = a+ b exp(-P/c) a= 0.87315985 b= 0.66771594 c= 3063.5963 V-Function is only valid for Pressures < Psat Equations for the Relative Volume and Fluid Compressibility are only valid for Pressures> Psat P - psia Psat - P Y = P(VNsat - 1) Co= - d(lnVr) dP Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 35 Oilphase-DBR 2.90 2.70 2.50 2.30 CD E ~ "õ > CD > ;:¡ ca CD a:: 2.10 1.90 1.70 Figure 4.1 B P Alaska Recom bined Reservoir Flu id Well: NS-09, Field: Alaska Northstar Constant Com position Expansion @ 254.5°F - - - ~ - - _:- - - ~ - - ~ - - - - - - ~ - - _: - - - ~ - - ~ - - -1- - - ~ - - -; - - - ~ - - ~ - - -1- - - ~ - - ~ - - - L- - - -1 - - - , , " , ---I---'---'--'------T--'1.05 ----1---1-- --1- l I I I I - - - ì - - -,- - - I - -, - - - - - - T - - . I " I I I I I 1-- --I -~ ---1 ----+---I---+- ---J-~-- +--- I I I I , - - - ï - - -,- - - ï - -, - - - - - - ï - - , - - - ~ - - -:- - - ~ - ~ - - - - - - ~ - -,1 .00 , , " I - - - -t - - -1- - - r - -! - - - - - - + - -. I I I I I - - - ï - - -,- - - ï - - ,- - - - - - ï - - , - --j- -,- -t--- t-- --_J_- --~-- i_- I I I " , ---~-- --¡--¡ -----f--0.95 ---4---1- r----j ------T--' --_J --'--_L- -----J-- 4800 I I I I - - - ï - - -1- - - r - --, - - - - - I - '- -1- - - r - - Î - - - - - - T - - -I - - - r - - ""t - - - - - - ,.. - - ¡ - - - r - - .,.. - - - I I I I " 1 1 1 1 1 1 I, I I I I I I I I I I I I - - -, - -,- - - í - - -, - - - - -. T - - -,- - - í - ì - - - - - - T - - -, - - - , - - , - - - - - - T - - , - - -- - - -: - - - J - - - 1- - - L - - ..J - - - - - J. - - _I - - - L - - ..J - - - - - - .L - - _I - - - L - - .J - - - - - - 1. - - ..J - - - - - - ..:. - - - I I I I I I I I I I I I I I - - - , - - -1- - -, - - ,- - - - - T - - -,- - - r - - ì - - - - - - T - - -,- - -, - - -'1 - - - - - - T - - -, - - - ,- - - -, - - - ---.1 --1---.1.. ---1-- -1- -1---.1.. --1-- -__1-___I___L__.J___-- .1.. _--I_--~,-_c._-- 1 1 1 1 "" 1 1 1 1 I I 1 1 1 "I 1 I 1 1 1 1 - - - .J - - -1- - L - - -l - - - - - .J - - -1- - - L - - --I - - - - - - 1- - - _1- - - L - - .J - - - - - - L - - --I - - - - - - -'- - I I I I I I I I I I ¡ I - - - I - - -1- - f - -I - ¡ I - I - -- - - - ï - - 1- - I -- - - -- - ï - - -, - - - - - - -! -- - --1- - - .).... - --I - - - ..l. - - 1- - - -I - - - - -!- - - -1- - - I- - - -+ - - - - - - .).... - - - - -. - - - I I I I I I I I I I I I I ï - - -1- - - I" - - -I - - - - - ï - - -1- - - ï - - - - - - - - ï - - -, - - - ï - - ï - - - - - - ï - - -I - - - - - - -;- - - - I 1 1 I , 1 I 1 1 1 1 1 1 I I 1 1 I 1 1 I - - - I ~ 1 - I 'I 1- - ~ I - - -. - - "I -] -. - 1- - I - - - - - - ï - - - -4---1-- ¡. +- ~ + -t- -4- ~ I 1 I I I I I ---I--'-ï- -- ----- ---ï--i------ï------------- + + f- -+ t , I I I I I I I I - - t- -. - --i - - - - - -+ - -I - - - t- - - -1 - - - - - + - - -I - - - ~ - - , - - - - - +- - - -1 - - - - - - -+ - - - 1 I I I 1 I lit I I I --~--~------~- --~--~------7---I---~--~------T------------- - - t- .- - Î - - - --'1 - - r ~ "1 ì I I ¡ -: i- -: ~: I I I 1 :: ¡ - ---~--_:_--~--_:_-----~-__:___' -_J_-----~---:---L Psat = 5095 psia 1 ! 1 I I 1 I I I - Î ., 1-- r -I -- -~ - -- '-"1 - r ~- T - ---I - - ~- r - - ~ - - -. I - ~ - - - -1 - - _,- .1.. - - J -- - - - - -1 - - -'- - .1.. - .1 - - -' - - - L - - -1 - - - - - - .1.. - - -' - - - - - - -'- - - - I I I I 1 1 I I I I I I - - - -'1 - - -,- - - , - - -, - - - - - - ì - - -1- - - r - - ì - - - - T - - -, - - - r - - -'1 - - - - - - T - - - - - - - - - ì - - - " , " , - '-1- I Two Phase Data c 1 I ~ 1.50 1.30 1 .10 0.90 -....... Single Phase Data I 5000 5200 5400 I + - -----.-- , , -I ~I ~ - - - ..1 - - _1- - - L - -.l - - - - - - .1 - - _!- - - L - _..J - - - - - - 1 1 I I I I 1 1 1 - - - ï - - -1- - - ï - - -I - - - - - - ï - -1- - - I - - I - - - - - - T - j j 1 J 1. L I ----'---- 0 2000 4000 Pressure (psia) 6000 8000 Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 36 Oilphase-DBR Table 4.2 BP Alaska Recombined Reservoir Fluid Well: NS-ÐS, Field: Alaska North Star Constant Composition Expansion @ 254.5°F Pressure (psia) Liquid Volume % (%) Relative Volume V r=V",1V sat Liquid Density (g/cm3) Compressibility Co (10-6psï1) y- Function Value Psat Vr = a+ b exp(-PIc) a= 0.87904361 b= 0.66593913 c= 2865.8933 V-Function is only valid for Pressures < Psat Equations for the Relative Volume and Fluid Compressibility are only valid for Pressures> Psat P - psia Psat - P Y = P(VNsat - 1) Co= - d(ln Vr) dP '" l. ( [ Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 37 Oilphase-DBR CD 2.50 E ::::J Õ 2.30 > CD > .. 2.10 ftS ãi a: 1.90 Figure 4.2 BP Alaska Recombined Reservoir Fluid Well: NS-08, Field: Alaska North Star Constant Composition Expansion @ 254.5°F 3.50 , , -"1 ri-;---r-j-i- ---I-î-;-î = : = = : = : - = : =: = : -1- - -1- ~ ::= 1.05 _.J- _I_L L_I_L_I___I_.l_!- , " 1 1 I 1 I 1 I I I I I I I I I --I-~-I--- ¡ ï-I--- -ï-- --,----,--- r r 1-- --'-rï-~- r-¡-r-¡--- -ì-'- --i-t--j-:--- r t- --1-1"-:- I I I I! I I! ì - -J - L-J -- 1- -1- J- =j=~=:=t== =:=i=:===:=i=:=1.00 , 'I I 1 I I I I - -I - ï -1- ï - - I -1- T -1- - -1- ï -,- I I I 1 I I -I-:-I-:---¡ I-¡- ---¡-¡-;- - -i .- r- -- - :- - -- t- -- -t- - -1- + -;- -~-'-~-'---+- ,-+-_,---,-..-,- _-.J_~-.J_L--L I-L_I_- __1,_1._- I I I I I I I I I h: - ~ -: - ~ -- ~ -- ~ + - '- 0.95 --I-ï-I----r-I ï --1-1-- -,-"-,--,-,, --,-T-,- 4000 -1-j"4-r---1""-1 1""-1---1-1"-- I , I, I 1 1 I " 1 I 1 1 I I 1 , I I 1 1 , I - ... - J.... ..J - ~ - - J,.. -I .J.. -1- - -1- ..l - '- ~ - - ..l - I- ...I - I- - - I- ....J - i- -1 - - _I - J.. _: - ..L.. - - .J.. -1- ..J. -1- _-.J_~-.J_-- L_'_L_I__._',_l__.l__J__'_J_1 L-1_L ___'_L_'_L__l_I_.l_'- --'- _1_:""__l_I_1 __1_1 J.__J_I_J_I___~_!_L_I_- .L_I_1__1_1_.1_I- I I I I I I ¡ I ! I I t I ¡ I 1 1 I 1 I I - -I - -I .- - - .- "I -I - - - I - I" I - ! I~' I - 1- - 1- -¡ - I" - I T - - "I - 1- I - I - 1 ¡ 1 I 1 1 ¡ , I I! I I 1 I I J t 1 1 1 1 --'-'I-'---I-t- -¡---I-T-:-T--ì-¡-ì-r--rì-r ---I-r-'-T- T T'" '- - -1 - -..., - ~ - - -r -1- -1- - -1- + -:-"1' - - -t - ¡- -t - ¡- - - r- -1 - t- -; - - -1- -r -, - t- - - + -(-"1' -1- - ~ - '- ~ - i-- - - +- +- ,,-, - -1- -> -!- -> - - -I - 1- -I -, I- - - I- -j I- --I - -, - +- -1- + - - + -1- +- 1- - ...J - L ....J - J... - - .J... -1- J.. 1- - _1- ..1. - '- ..l - - -l - L- .J - L. - - L ..J - L _I - - _1 - .J... -; - J.. - - .1.. -1- ..l -I- I I 1 1 I 1 " I '" I " 1 ", , , - _I - '- _\ - ~ - - !... .!... 1- - - - J - 1- ...! - 1- - - 1- _1 - !.... -' - - _1.- !... - - .! ~ I 1 1 1 ¡ I 1 1 1 I 1 1 1 1 - -1 - - -I 1""1 -- - I - 1- -ï 1- I" t I - I I-I -, -I r -',- r - - -,- T - ,- ,- - l - ,- l ,- - - I -, - r -, - - -, ¡ T - T - ,- T -î---I-r--r T-I --I-¡-:-I---,--I-ì r---rì-r r T -T l' 1 '" I " I "" 1 " ., 1 " 1 , - --i I- -j - +- - - +- -1- -+- -I - -1- -+ _1- --I- - - ~ -I- --4 -I- - - I- -i - I- -i - - _f- +- _.- + - - + -1- -+ -1- -....1____1 ~__L_I_.L_I_- ~~.-.l-.1- 1 l L__J L __.._L 1 _1_1_- _-1_,-_' ___L_'_L_'- -'-~-_-1__J_'_J_I___I__!_L_____L-_l__-L_'_J I ¡ 1 ¡ 1 1 I 1 1 1 I I 1 1 I I I 1 1 1 --I -I ï "-1 I-I 1-1-1-'1-1-- 1-- ---1--1--1-1-'1-1- I 1 1 I 1 1 1 I 1 1 1 1 I I 1 1 1 1 1 I I 1 - l - - -, r-, T 1- T T - - T - '-1 r r -I, - -, - , ,- r -! - T - ,- - --¡ - r- -, - - - - r -1- r 1- 1 - - 'T - - ì - 1-' -, - r - - r -, - r -. - - _. - ï -r - r - - T -1- 'T -1- ---I 1 !--I +--1- + -t I-.---f--I-_n_';--i-I--------t- +--+-1---+-1 - -I - - -I - .... - - .J... -I - J.. -1- - -I .J. -- -L ...J - I- -! - I- _I - I-- -I - 1- -i - - -: - ~ _I - ..¡.. - - .. .. -1- ~ -1- = = ~ -' - - = = ~ =: = t' I ~ = ~ = = ~ = ¡= ~ <~ = - ~ ~> ~ - ~ - ~ Psat = 4885 psia - -I - - -I - - - - ï -I - ï ï - - - I - ¡- - 1- - - 1- -I - I - - - -I - :- - - r -¡ - T T - - ì - 1 r -1 r I 1 I 1 I 1 1 I I I I - ----1 - - -I - - - +- -I -- +- - - 1 + -+ - --I 1- --I 1-- -j I - ..J - :.... -J - .... - - 1.. _i - .L _!- - -1- ,J. _.- ....!. - - - 1- -J - L- - - L -J - L _:- _I L _I - 1.. - I - - --- 1 -- 1 .1 - - .-l - - L - - L -' - L -; - J.__J.__J- 1__- I I 1 I I I 1 I I 1 1 - -I - - -I - - - - ï -I - ï -I - - -1- ï - - ï - - ï - t- ï - 1- - - - -l-l í -I ï -I -. t- Ti - - ì - 1- -, - r ~ - r = ~ - ~ ~ - ~ =- ~ ~: - ~ -: I -:- : - ,- ~ = 1= ~ -:- ~ - ~ 1- ~ ~ - ~ -, ~ - ~ ~ - ~ ~ - ~ ~ - ~ -I - ~ -: - ~ -: - ~ T -1- Î - 1- 3.30 I Two Phase Data I ,- 3.10 I- I- i-- 1- ,- 2.90 ,- 1- 2.70 Single Phase Data I 4500 5000 5500 = 1 1 I I - 1- -!. - I- ~ - - 1- -' - ,- J - - 1- - 1- .J - I I I ,- -, ,- ï - I , , , -1--:-1-'- -1-;-1-'"'1- -1- --I - 1.-- -i -I-...!._L..J- 1 " ~ - 1- ~ - , , - ,- I ,- I - r T- I ,- ""';'-1----1- - 1- --- ,_... -.J - '- -' - '- J - , , 1.70 1.50 ,F 1.30 1.10 0.90 0 3000 4000 5000 Pressure (psia) 7000 8000 1000 2000 6000 Oilphase-DBR Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 38 Table 4.3 BP Alaska Recombined Reservoir Fluid Well: NS-15, Field: Alaska North Star Constant Composition Expansion @ 254.5°F Pressure (psia) Liquid Volume % (%) Relative Volume V r=V tDlV sat Liquid Density (g/cm3) Compressibility Co (10"psï1) y- Function Value >0.. .'0",';'..'., Psat [ t. r ( r ( t [ ( ( ( Vr = a+ b exp(-P/c) a= 0.89097759 b= 0.5691499 c= 2805.7273 Y -Function is only valid for Pressures < Psat Equations for the Relative Volume and Fluid Compressibility are only valid for Pressures> Psat P - psia Psat - P Y = P(VNsat - 1) Co= - d(ln Vr) dP ( ( ( ( l (. ( ( ( ( ( Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 39 Oilphase-DBR Q) E ::::s Õ > Q) > .. cu ãi a:: Figure 4.3 BP Alaska Recombined Reservoir Fluid Well: NS-15, Field: Alaska North Star Constant Composition Expansion @ 254.5°F 2.30 2.10 I I I I I I I r -I - r- - -- r- -1- , -I- I I I I I I I - --, - t- -I - t- - - t- -1- + -I- I 1 I I ) I I I - --j - I- -I I- - - -, .-1 - j- -I- I I I I I I I I - ~ - ~ -: - ~ - - ~ -.-:- I I I I I I I I I I I I I I I - _I - L _1,- L - l... _1- - _I- I I I I ¡ 1 I I I I I I -----------.--- I I I I I I I , I I I I I I I - - - ï -,- ï - -I -,- ï -,- I I I ¡ I I I ï -, - ï - - I -,- ï -,- I I I I I I I I I I I I I I , I I I I I I - ï - ï -, - ï - - r -1- r - - I I I I ! I I I ,--I-I- -I--I-t--I- I I I I I I ---.1- ---I-t- +--I-+-J- I I I I I I I I - -' - ¡.,. -I - .... - - L -1- ~ -I- I I I I I I I I , I I I I I I I - -.! - L _1- L - - L _,- L _I_- I I I I I I I - _I _!... _I - !.... - - 1.. _1- l.. _I- I I I I I I I I I I ---ï --ï Î I I I I I -1- I , T I I I I J I I I I I I I I I I I I I ---r"-I-r -r -1- T -I- I I I I I I I - .- .- r -I - r - - r -I - T I I I I I I - -i - I- -I - t- - - +- -1- + -I- I 'I I I I I ~ 1-, - ~ -I - l- I I I I I I : : ; j : -:- ~ -:- 1.05 -1- -t- -I- I I I --1-. + -I- I I I -1- + -I- I I I I I I I I I __,- J. _1- _:_l I 1.00 I I I I 1 -,- ï -,- I I I -1-'-1- I I I I I , I I I -:- ~ -:- 0.95 I I I 1.90 1.70 1.50 1.30 I I , _-,_L_'_L I I I , I I : 1.10 0.90 '" u 1000 I Two Phase Data ~ -1- -t -I- I I I -1-+-1- I I I I I I , I ,I I I I I -I-.J. -1- -l - -.J - L.. -J - ~ - - '- -J - L -1- - -1- ¡.. -I-...L I ¡ I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I -'- J. _,- i - - J - ,- --1 - L - - -.! - L _, - - _,- .L _1- 1 I I I I I I I I I I I I I _I_.J._I_J.-__J_I_J_~____I_~ --I_.!..._I_l 1 ! 1 I I 1 I. I 1 1 1 I I I I I I I I I I 1- I I ,- -,- - ~ -,- Î 1 I 1 1 I 1 1 1 - - T I -- -I 1 - -I 1 I T 1 I 1 I I I ¡ 1 I I I 1 1 I I I I I I 1 1 I 1 1 I I 1 ,. -I~' ì - - T -1 - - - -I T -, r < 1 1 1 1 1 1 1 1 - -1 - 1- --1 - >--- --1 t- -I - - -I - r -I -. T I I 1 1 1 1 1 1 I 1 -1- -t 1- -+ - - -+ - f- -f -- - -. ~ ~ - ~ -1- - -1- +- -1- + I I 1 1 1 I 1 I 1 I 1 1 ./. ~ ./. ¡ -I ¡ 1-+ I I I I I I 1 I I 4000 4500 Single Phase Data I 5000 5500 I I I I I I I ~ - i- -!. -1- - - 1- ~ - L- - - I ' I I I I I I I I I I I I I i - ,- - - ,- J - ,- -' - I I 1 I I I ..!.. _1- ..!.. - 1- - - 1- J - 1- - - 1 1 1 1 I 1 I I I I I I - - ï - - 1- - I I I I I I 1- 1- - 1 I 'I I I I I I I I T T - 1-- ï r- 1 I 1 I 1 T - t - 1'- - - !-- -1 I' I I + -.- ..,. -1- - - 1- -I - f- -I - I L I I , I I j l- I , I I I I I 1 I -L - - 1 _,_- - ,- J - ,- ..: - ~ ~ I I ~ 1 1 Psat = 4640 psia [ 2000 4000 5000 3000 Pressure (psia) Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 40 6000 7000 a"''''''' uuu Oilphase-DBR Table 4.4 BP Alaska Recombined Reservoir Fluid, N5-09, 5100 psi a Psat Five-Stage Separator Test PROPERTY STAGE #1 STAGE t2 STAGE #3 STAGE #4 STAGE #5 STAGE #6 "'; ;.'W:~iP~"r ';'-~':3~'<'t~~9::?:::': .:;'~: :"'~::;~~;;-{§è:,;:}li "":;:-::'~;~~.'::;'l:~1. '~0fl':;'\L~::-o;,"~r :::,~è. ~;/: . 'i" ":"'.' . . ,c..-".. . ;f~~;~'f~'B~ T~#.~~p~~ifl~~~J¡l:t{B\~5áf{.~~~1~~~~%~-i£t.~~'f~ri~fo/% 1~i;;g;;f.~11.:r.r'Ffi.(~~~tf1Z~~9(f.~'Z"'f;(;'j~:f~:~\;..!;;y,:.,.~S!{;: , GOR 1650 106 103 59 0 }iX~i~~~1f:%~~~~1~~1?~;tff~f1:~~~:m~~1R~~~f~~.~~~~f#Æ~~~~~~ij~~~l~IPJ~~~f¡~ '~i~1~0~~~(~i~~~~ .~1fþ~~{F~f~~,'~~'~~~:~~!~~?i\~~:f.~~:?~~~:¥~t~: :- a) Calculated, at 6O'F (811"1) b) Calculated, Dry ba8is BTU/scf c) scf gaslbbl of 011 at STO conditions d) scf gaslbbl of 011 at separator conditions e) fluid volume at sap conditions/fluid volume at STO conditions Residual 011 density at standard conditions 0.821 gIcm~ Sep gas gravity (average) S. = ŒR¡*S8IŒR,J Where: R: GOR (scf gaslbbl of 011 at STD conditions), j: separator stages 0.815 Sep gas heating value (average) ~ . ŒR¡*~1IRiJ Where: R: GOR (scf gaslbbl of oil at STD conditions), j: separator stages 1239 BTUlscf (dry basis) Shrinkage FVF ~"'ÐII......_-tllMfte;:1ì ( r ( r ( ( ( ( r ( ( ( ( ( ( ( ( " ( ( ( ( a) scf gas/bbl of condensate at STO conditions b) Fluid volume at Psat & TreslFluid volume at STD JI')(_"l=\''''''I('J'''''JlI'IJI''I~ Pressure - psia Temperature - F Stage 1 750 160 Stage 2 325 157 Stage 3 70 157 Stage 4 20 157 Stage 5 15 60 Stage 6 Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 41 Oilphase-DBR Table 4.5 BP Alaska Recombined Reservoir Fluid, NS-G9, 5100 psia Psat Five-Stage Separator Test Vapor Composition 1 at Stage 2nd Stage 3rd Stage mole % 4th Stage 5th Stage COMPONENT AfW Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 42 Oilphase-DBR Table 4.5 Confd BP Alaska Recombined Reservoir Fluid, NS~9, 5100 psia Psat Five-Stage Separator Test Vapor & Residual Liquid Composition 6th Stage Vapor Residual Liquid COMPONENT MW mole % r ,. ~. . - , - .. .:. ~ - . , . .~<- . , ""_¥VI 0:..'" ..,. .... '0, ..; ':0".. ..,.,,,.,'....',,..,'..;, ...;.'" CI '~',-.;o.;~.,.~ ;:'¡""""".'..'./' '.,..'.V, 1,;'11 :1! Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 43 Oilphase-DBR Table 4.6 BP Alaska Recombined Reservoir Fluid, NS-09 + NS-13 , 4850 psia Psat CONSTANT COMPOSITION EXPANSION @ Tres (254.5°F) Pressure (psia) Liquid Volume % (%) Relative Volume V r=V tDlV sat Liquid Density (g/cm3) Compressibility Co (10"psï1) y- Function Value Psat Vr = a+ b exp(-P/c) a= 0.88992846 b= 0.58080472 c= 2926.866 Y-Fundion is only valid for Pressures < Psat Equations for the Relative Volume and Fluid Compressibility are only valid for Pressures> Psat P - psia Psat - P Y = P(VNsat - 1) Co= - d(InVr) dP Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 44 Oilphase-DBR [ ( [ ( ( ( ( c ( ( ( ( ( C l ( ( ( ( ( l ( Ë 2.30 ::s Õ > CD > ;::¡ CG ~ 1.80 Figure 4.4 BP Alaska Recombined Reservoir Fluid, NS-09 + NS-13 , 4850 psia Psat CONSTANT COMPOSITION EXPANSION @ Tres (254.5°F) 3.30 1.30 I I I I I I I ! : ! : --:-~-:-~--~ I ~ I --:-~-:-1.05 - I I I I I I I I I I : I I I I I I I I I 1.04 = --I-¡- ¡---I-I-T --1-'-1- : I I I I I I I I I I 1.03 = I I I I I I I I I I : --I-¡--I-¡---¡- ¡--'---'-'-1-1.02- I I [I I I I I ¡ I I I I I I I I I I 'I - -I - ï -,- ï - - ï -,- ï -1- - -1- ï I I 'I I I I 1 1 1 I I I I I I I 1 1 I I I I I I I I I I I I I I I I 1 I I ¡ -~-~-:-~--~ :-~-:---:-f-:-O.98 ~ -~-~_: ~--~ :_~_:--_:_l_:_0.97 ~ : : :: : :: ::: 0.96 ~ -~-~-:-~--~-: ~-:---:-~-:-0.95 :, I , I I I I I I I I I ---1-L-I-L_-L-I.L --I-.l.-I- ! I I I t I I I I I 1 I I I I 1 I I I 1 I I I I I I I I I 1 I I I II! I I! I 1 I I I I 1 1 I I I I 1 I I I I I I I 1 I I I I I I I I I 1 I I I I I I I 1 I 1 I 1 I I I I I I I I I 1 I I' I I I I I I I I I I I I - -1 -- I- -I - I- - -- 1- -1- ... -1- - -1- -+ -1- -! - -- -I - 1- -I I- - - I- -I - 1--1 - -I - 1- -1- +- -- + -!- 1- - 1- -I I- -1 - I I I' 'I I I '" 1 I' I I I I I I I I I 1 1 I I I I I I I I I I I 1 I I I 1 I I I I I I I I 1 I 1 I I I I I I I I I I I I - -1- t- -1- t- - -... -1- + 1- - -1- +- -1- +- - - -t -I- -I-I- - - t- -1- t- -1- - -1- +- -1- + - - + -1- +- -1- - -1- -1-1--1- I I I I I I I 1 I 'I I' I I 1 I 1 1 I I I I I I I' I'" I I I I I I I I 1 I I I I I' I 1 'I I I I I I I I I I I I 1 - -I - t- -1- t- - - t- -1- t- -I - -1- +- -1- -t - - -t - 1- -t - t- - - t- -I - t- -I - - -1- t- -1- + - - +-1- -t -1-- - - 1- -t - t- -I - I I I I I I I I 1 I 1 I I I I I I I 1 I I I I I I I I I I I I I I I I I I I I I I I I I 1 1 I I I I 1 I I I I I I I I I I I I I - -I - ¡- -I - ¡- - - r -1- r -I - -1- ,. -1- ,. - - -r -- ¡- -r - ¡- - - ¡- -I - ¡- -I - - -1- r -1- T - - -¡- -1- -¡- -1- - - 1- -r - ¡- -I - I I I I I I I I I 1 I I 1 I I 1 I I I I I I I I I I I I I I I I I I I I I I I I I I 1 I I I I 1 1 I 1 I 1 I I I I I I I I I I I I I ¡ I I j ¡ I ¡ r I I ¡ I I I I I ¡ I I I r I I I j I ¡ 1 I I I I ¡ t I I I I ¡ I I I I I I I I I 1 I I I I I I I I I I I I I I I I I I 1 I 1 I 1 I I - -, - r 1- r - - r -,- r -1- - 1- T -1- , - - -¡ - r "l - r - - r -, - r ,- - -1- r -1- T - - T -1- T -1- - - 1- -¡ - r "l - 1 I I I I I I 1 I I I I I I I I I I I I I 1 I I I I I 1 1 1 I I 1 1 I I I I 1 I I I I I I I I I I I I I 1 1 I I I I I I I I I - -, - r -I - r --- r. -1-- T -1- - - T -1- ì .- - '1 - 1- ì - r - - r -I - r -I -- - -1- T -1- T - - T -1- ì -1-- - -1-1 - 1- "l - I 1 I I 1 I I I I I I I I I I I 1 I I I I I I I I I I 1 I I I I 1 I I I I I I I 1 I I I I I I I I I I I I I 1 1 I I I I I - -I - I -I - I - - 1 -1- 1 -1- - -1- -1-' - - ï - 1- ï - ï - - ï -I - I -I - - -1- 1 -1- T - - T , - - 1- ï - 1- ï - I I I I I I I' I I I I 1 I I I I I I I I I I I 1 I I I' I I I I I I I I I I I I 1 I I I I I I I I 1 I I I I I I 'I I I I I - -I - ï -1- ï - - ï -1- ï -1- - -¡- 1 - ï - - ï - 1- ï - ï - - -I - ï -,- - -1- T -1- T - - I" -,- ï -1- - - 1- ï - ¡- ï - I I I I I' I I 1 I I I I' I I I I 1 II Psat = 4855 pSl8a II I I I' I I I I I I I I I I I I I 1 I I I , I I I I I " I I I I I I 'I I I I I "., ,." "I i'-- I I 'I 'I' I' I I I I I I I I I I I I I I I I I I I I I , I I 'I , I I I I I I I I I I' I I I I 'I I I 1 I I I I 1 - -I - ï -, - ï - - ï ï -,- - -1- ï -1- ï - - ï - - - 1- - - ï -, - ï -I - - -I - ,- -1- ï - - ï -1- ï -,- - - 1- ï - 1- -I - ¡ ¡ I i I I I I I I I I I I I I I I I ! ¡ I I I I I I I L_-L l_-J_I_J- L~-L_I- 1 1_! 1 __I_J L I I I I I I' I I I I I I I I I' I I , I' I' I I I I I I I I I' 'I I I 1 I 1 I 1 1 1 I I - .J - L _1- L - - L _1- 1. _1- - _1- -1 _1- .1 - - .J - 1- .J - L - - L .J _1- 1- 1. - - .L _1- -1 _1- - _1- .J - 1- .J - I I I I I I I I "I I I I I I I 1 I I I I I 1 I I I I 'I 1 I I I 1 1 1 I I I I 1 I I 'I I 1 I I I 1 1 I I -~ ~-:-~--~-:-7 -: --:-~-:-~--~-:-7-;- ~~-~-:---:-~-:-~ -7-:-~-:-1-:- -¡ :--~- 1 I 'I I 1 I' I I I I 1 1 ,I 1 I 'I I I 1 I 1 1 'I 1 I , , I I 1 I f I : ¡ ¡ I ¡ ¡ I I ¡ I ¡ 1 I I Two Phase Data 2.80 1.01 - 1.00 ~ 0.99 : ~ Single Phase Data I 4000 4500 5000 5500 6000 - 0.80 0 1000 2000 3000 4000 5000 Pressure (psia) 6000 7000 8000 Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 45 Oilphase-DBR TABLE 4.7 BP Alaska Recombined Reservoir Fluid, NS-09 + NS-13, 4850 psia Psat DIFFERENTIAL LIBERATION TEST @ 254.5°F - LIQUID PHASE PROPERTIES GOR Data Pressure Cumulative Produced Solution Gas GOR (psia) GOR1 RS1 (scf/STB) (scf/STB) Calculated 011 Density (g/cm3) Liquid Data Oil FVF2 (bbI/STB) Oil Viscosity (cp) Viscosity Ratio 01l/Gas3 . This step was performed at room temperature Dead Oil Density at STD Conditions (60°F & 15.0 psia) 1Gas Volume @ STD I Residual Oil @ STD 280, Reservoir Oil Volume @ P, T per Unit Volume of Residual Oil @ STD 3Gas Viscosity Calculated from Lee et at conelation 0.829 gtem'; 39.2 °API TABLE 4.8 BP Alaska Recombined Reservoir Fluid, NS-09 + NS-13, 4850 psia Psat DIFFERENTIAL LIBERATION TEST @ 254.5°F - VAPOR PHASE PROPERTIES Pressure (psia) Vapor Vapor Density MW (g/cm3) (g/gmol) Vapor Data Vapor Gravity1 (air=1 ) Z Factor' Total Gas Total Two Phase FVF3 FVF" Co (bbl/mm set) (bbI/STB) (10"PSr1) Calculated Gas Viscosity6 (cp) . This step was performed at room temperature 1 Vapor Phase tNoNlMWAJr 2 Z=PV/nRT 3 Btõ, Reservoir Gas Volume @ P, T I Gas Volume @ STD 4 Sr. Oil FVF + [(Total liberated gas)* Gas FVF] 5 Co=-1/Bo[(dBJdP)-BG(dRJdP)) 6 Lee et at Conelation (Lee A., Gonzales M.H., Eakin BE, JPT, 997-1000, Aug., 1966) Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 46 Oilphase-DBR Figure 4.5 BP Alaska Recombined Reservoir Fluid, NS-09 + NS-13, 4850 psia Psat DIFFERENTIAL LIBERATION TEST @ 254.5°F 3000 2500 ( r [ ( ( ( ( ( ( ( ( ( ( ( ( ( ( ( ( ( ( ( ( ( 2000 - m .... U) ¡¡: U In - 0 1500 ;:¡ as 0:: Õ In as C) 1000 500 " I I ¡ I I I I I I I I I I 1. ' , ~ I I I I I I! I j I I I i I I I ! - - ..J - - L - ~ - - - - - - -1- - .L - _1- - L - - - - L - -l - - L - J. - - - - ..1. - -1- - .L - _1- - - - -.J - - L - ..J - - L - - I I I I I I I I I J I I I I I I I I I I I I ! 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I 0.0 0 1000 2000 3000 4000 5000 Pressure (psia) Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 48 Oilphase-DBR FIGURE 4.7 BP Alaska Recombined Reservoir Fluid, NS-09 + NS-13, 4850 psia Psat DIFFERENTIAL LIBERATION TEST @ 254.5°F - VAPOR PHASE PROPERTIES 0.40 .::-- .. + -4 -I -1- - + --t -I -1- - +-4 -I ~ -+- - -! - 1- - ..:... -I -I -!- - -+- -I -I - 1- - - -I -1-- - + ~ -) - 1- ~- 4--1 -1- 1-- - -+ -I --! I- E - t ~ _1 _1- - ~ ~ -: -:- - 7 ~ -: -_! - -. ~ ~ _I _1- - ~ ~ ~ ~I ~:- - ~ _I - - - ~ ~ ~ ~ -: -:- - 1 U - T ï - T "I --, - 1- - ï -: -, - ï ï - - I Ii 1- - - ï - - T - T -¡ -1- - T-I œ 0.30 - I It, I I ), I I I I t I I I ,I I I ) II! ,I I, I, I 1 I J I I I I I - -.L .1_'_'- -.L .1_1_1- -.L .1_1._'- -.L .1_,_,- - - .1_1_1- -.L .1_,_,- - - .1_'_'- -.L - _,_, :J _,_,- _.L..J _,_,- ~ -+~-:-:--+~-:-:--+~ -+~-:-:---~ -+~-;-:--7~ -+~: ¡-.-+~-:-:--+-:-:-:- .- .. T ì -I -1- - T ì -I -1- - T ï -I - 1- - T , -I - 1- - ;- , -1- 1- - T ï -¡ - 1- - ï ï -¡ T -; -1- ¡- r T .., -1- 1- - T --, -1- 1- ~ 0.20 . I 'I ! I ,! I' 1 It' I 1 I I 1 I ¡ I , I I I I I I 'I I I I I ,! : t ~ =: =:= = t ~ =: =:= = t ~ = t ~ -, - 1- = ~ ~ T - ~ ~ =: -:= = i ~ =: =:= = t j -,- ,- t ~ =: =:= - t ~ =: = := ... . + -t -I -1- - + -t -I - 1- - + -t -I - 1- - + -t -I - 1- - -1 - 1- - + -t -I - 1- - + -t -1- 1- - + -t -1-. 1- + -t -1- 1- - + -t -1- 1- 8. 0.10 -: : :: :::: ::: 1 ::; 1 '::: :::: :::: :::: :::: :::: ca - T I -, -,- - T I -'-1- - - - 1- T I -,- ,- - -;- I -'-1- - T ï -,-,- - ï I -1- ,- - ï ï -'-1- ï ï -,- ,- - ï -, -,- 1- > :: = =:-1- - T .1-1_1- =: = =:=:= : = =:=:= = = = =:=:= =: = =:=:= =: = =:=:= =: = =:=:= :: =:=:= =:: =:=:= ¡ ¡ ¡ ¡ ¡ ¡ ¡ ¡ ¡ ¡ ¡ ¡ ¡ ¡ ¡ ¡ ¡ ¡ ¡ ¡ ¡ ¡ ¡ 0.00 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 ~ .S: I! C) ... 0 Q. ca > 1.3 I I I I I ( I I I I j I I I I I I I I I I I I I ¡ I I I I I I I I I I I I I - + -! -I -1- - + -! -I - 1- - + -! -I - 1- - + -! -I - 1- - -'- -! -1- 1- - + -I -1- 1- - + -t -1- 1- - + -t -1- 1- L + -I -1- 1- - + -t -1- 1- 1 2 . I 1 I 1 I 1 I 1 I I I I I I I I I I I I I I 1 I 1 1 I I! I I I I I I I I 1 I . . + ~ -: -:- - + ~ -: -:- - + ~ -: -:- - + ~ -: -:- - ~ ~ -: -:- - + ~ -: -:- - + -: - :- - + ~ -: - :- ~ + ~ -: - :- - I I -: - :- 1.1 . 1 I I 1 I 1 1 I 1 1 1 I 1 I 1 1 ,I I I I I I 1 I 1 I 1 I I 1 1 I I 1 1 I 1 I .1 -I -1- - .L .1 -I _1- - 1- .1 -I -1- - 1- -1 -1- 1- - 1- .1 -1-1-, - .L ..J -1- 1- - .L ..J -1- 1- - .L --I -1- 1- .L..J - - - .L ..J -1- 1- 1.0 -: I 1 I :::: :::: :::: :::: :::: :::: :::: I I :: :::: - T ì -, -,- - -I - ,- - T ì -I - ,- - T I -1- 1- - T I -, - ,- - T I -,- ,- - T I -,- r -.. ! -1- ,- T I -1- 1- T -, ,- 0.9 . 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I I I 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 Pressure (psia) Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 49 Oilphase-DBR TABLE 4.9 BP Alaska Recombined Reservoir Fluid, NS-09 + NS-13, 4850 psia Psat VISCOSITY DATA @ Tres (254.5°F) Pressure (psia) Liquid Viscosity (cp) Status Psat , ~5ØQ , 5175 ,48$5' .OJ~8 0.135 , 0:131 .:$i,hgr~;.~þ<~l.!ig\Jiø Si"gle.. ~~~~~Liquid , ': ,~~po.at8d', " Psat 4855 0.131 :: >,'",:,c;;;,ii-i?~¡S!Õ~~'ât, ,. 0.156 , ",:,: i;i;:,¡Qi~~Z;:,> 0.235 ) . , ':"ø.:3Q~' Extrapolated ;' ,;:;;:;;;&,gb.\":;:::~fii!(t!jr¡m\~~f~~:'¥': ,', Li9~i~fr?":'D~. T~~t " ''',..,'.' >;;~qt;l,kt;ftQmQÞ;Iø$t ' Liquidfrorn DL Test "J;.~w~f[Q'6r[)ÞT~St':'X: , " ; ,,~i3u.!d,.~fr~m:,Pr~~j:0~~!;~;t:'? ' ; " ,-~ 4400 ",:".,~Q" 3400 2~: Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 50 Oilphase-DBR Figure 4.8 BP Alaska Recombined Reservoir Fluid, NS-09 + NS-13, 4850 psia Psat OIL VISCOSITY @ Tres (254.5°F) Q: ~ ~ 0.3 ,¡ 0 CJ 0 :> " 0.2 'S cr ::¡ 0.5 = ~ = ~ i =:= = =:= i =:= ~ =1= ~ =: = ~ j = = j = ~ i =:= = =:= = == ~ = = ~ =: = ~ j = = ~ = ~ i = ~ = =:= i =:= ~ =1= ~ =: = = =: = = j = ~ j = ~ ~ I I I j I I I I I I I J I I I I ! ¡ I ! 1 I I I I ¡) I I I I : I I ¡ I - ""1 - r- ; - 1- - - 1- 1" -1- 1'" - - t- -I - t- """1 - - -! - - -t - 1- - - 1- ~ - - 1'" - - T" -I - t- ""i - - ""1 - - ., - ¡- - - 1- ,. -1- T - - .,.. -I - - -t - - -j - - ""1 - r- - - .J - L .J _1- - _1- .L _1- 1 - - L _I - L .J - - .J - L .J - 1- - _1- ~ -- .L - - L _1- L _I - - .J - L .J - 1- - - 1- J. _1- .L - - 1 _1- - _, - - _I - L .J - '- - 1111--""1111111 I'll I "111 II" 1111 11"111 ¡ J I I I I ¡ I ¡ ¡ ¡ I I I I I I I I I I J I I I I I ¡ I J I I I ¡ I I - -! - ¡- --1 .- 1- -1- + - - + - -- +- --I I-- -1 - - -I -- I- -4- 1-- - ~ -, ~ + - - +- -I -' f- -1 .- _. --i - I- -! - 1- - - 1- -+ + - ~ .¡.. -I -" - -I - - -j - 1-. -i I _J_I_J_I_.___I_.!-_I_- _i.._I- _I__J_I_J- 1- 1. 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T -, - - -, - r -, - 1- - - ,- T -,- T - - T -I - T -I - - -, - r -, - 1- - - ... - '- -I - 1- - - 1- -I- -1- -I- - - .¡.. -I - !- -I - - ... - '- -I - 1- - - 1- -'- -! - -I- - - -I - .¡.. -I - - -I - I- ... - '- - - 1- -I -1- -I- - - .¡. -I - - -I - - -I - '- -I - '- - I I I I I I I I I I I I I I 1 I I: I I I I I I I' I I I 1- ; I I I I I I , I I I I I I I I I I I I I I I!' I I I I I I I I I' I I 1 I ! 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I 1 \ 1 1 I - -, -. r- -1 - 1- -,- T -1-- T - - T -I - r -, - -. -, -- r -¡ - 1- - -1- T -,- T - -- T T -I - - -, - r -, - 1--- ,- , -,- T - - T ~ -I - -, -- r '1 .- 1-. - - -I -I- -I -1- - -1- -!- -1- -!- - -- ~-I 1 -I - -J - I- -I -1- - -1-, -1- -!- - - ... -1- !- -1- - -I-I- -I -1- - -1- -!- -1- -!- - -- ... -I '- --1- - -J - I-..l l- I ¡ 1 ! I 1 I I 1 1 1 1 I! I 1 I I 1 II! ¡ 1 J I 1 1 1 1 -1-'-1 '-I-ï--ï-I-I-I--I-I-ï--I---,-,-,-,--T-I-I-I---I-'-I-I-- , ,--T -,---,-¡- -1- - - - r- - -1- - -1- + -1- + - - + -I - - -- - - - r- - 1- - -1- T + - - + -I - - -I - - - - r- - - r- - - ,- + -1- -¡- - - -¡- -I - t- -I - - -- - r- - - 1-- - 0.0 'I I I I 1 I I I I 'I "I I 1 I ¡ I 1 I I I I I I I 1 I I ¡ I I i I I I I , 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 Pressure (psia) 0.4 0.1 ( r' L ( ( ( ( ( ( ( ( l Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 51 Oilphase-DBR Table 4.10 BP Alaska Recombined Reservoir Fluid, NS-G9 + NS-13, 4850 psla Psat DIFFERENTIAL LIBERATION TEST @ 254.5°F Produced Vapor Composition 1 st Stage 2nd Stage 3rd Stage mole 0/0 4th Stage 5th Stage COMPONENT MW ~_. Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 52 Oilphase-DBR Table 4.10 (Continued) BP Alaska Recombined Reservoir Fluid, NS..09 + NS-13, 4850 psla Psat DIFFERENTIAL LIBERATION TEST @ 254.5°F Produced Vapor & Residual 011 Compositions COMPONENT MW 6th Stage mole"- 7th Stage Residual Uquid mole 0/0 ( ( ( ( t r [ ( £. r (, ( ( ( ( ( ( ( ( ( ( ( ( (, ( ( ( ( ( l :, '.\;~-::,.' .>.-' .:.:::.'::~ ':.:.:::',:: -V'" ..t!> 3 ... VVI ""'" 16.17 18.30 ( 17.00 175.0 I !06.0 [) 3~ [) c > "i:i'<' , \~~ Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 53 Oilphase-DBR Table 4.11 SP Alaska Recombined Reservoir Fluid, NS-09 + NS-13, 4850 psla Psat Flve-Stage Separator Test PROPERTY STAGE #1 STAGE #2 STAGE #3 STAGE #4 STAGE #5 STAGE #6 a) Calculated, at 60°F (ai...1) b) Ca1culated, Dry basis BTU/set c) set gaslbbl of oil at STD conditions d) set gas/bbl of oil at separator conditions e) fluid volume at sep conditionslfluid volume at STD conditions Residual oil density at standard conditions 0.817 g/cm" Sep gas gravity (average) SII .. ŒRtSIIIŒRj) Where: R: GOR (set gaslbbl of oil at SID conditions), j: separator stages 0.823 Sep gas heating value (average) L" = ŒR¡*L,,¡ŒRj) Where: R: GOR (set gaslbbl of 011 at SID conditions), j: separator stages 1254 BTU/scf (dry basis) Shrinkage FVF From Psat & Tres to first Sep conditions From first to second Sep conditions From second to third Sep conditions From third to fourth Sep conditions From fourth to fifth Sep conditions From f'1fth to sixth Sep conditions 0.549 0.948 0.951 0.950 0.960 1.822 1.055 1.051 1.053 1.042 ~::t:l.:-.':J.:-.~{.J:""i.I~I'¡'.:-.':¥ a) set gaslbbl of condensate at STD conditions b) Fluid volume at Psat & T reslFluid volume at SID 11'IC_l..~r.'r.'('J"''''Jlllr('III: Pressure - psia Temperature - F Stage 1 750 160 Stage 2 325 157 Stage 3 70 157 Stage 4 20 157 Stage 5 15 60 Stage 6 Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 54 Oilphase-DBR Table 4.12 BP Alaska Recombined Reservoir Fluid, NS.()9 + NS.13, 4850 psla Psat Flve-Stage Separator Test Vapor Composition 1 at Stage 2nd Stage 3rd Stage mole % 4th Stage 5th Stage COMPONENT MW Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 55 Oilphase-DBR Table 4.12 Continued BP Alaska Recombined Reservoir Fluid, NS-09 + NS-13, 4850 psla Psat Flve-Stage Separator Test Vapor & Residual Liquid Composition 6th Stage Vapor Residual Liquid COMPONENT MW mole % > .. 9 2.. Cal~l~dÌ1C..~:,~è\ C'é ., o:;¡11:"i,:,' Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 56 Oilphase-DBR TABLE 4.13 BP Alaska Recombined Reservoir Fluid, NS.Q9 + NS-13, 4850 psia Psat Separator Corrected GOR and FVF Pressure Measured GOR (Rs) Corrected GOR (Rs)1 Measured FVF (Bo) Corrected FVF (BO)2 (psia) (scflbbl) (scflbbl) Two Phase Data . ""~';:/ :.':~5s' 4700 "'..' ::44oo;,::i); , ,40QQ ^ ' ..',~;,<:,:';, 2500 : ,,1500' ",i?~1':.:,,¡ 2239 ,i/;Çì85è ' 1514 ,:?",¡;:<à;;:::;F~;~jM' , 794 . :\:::';,;,:/'~4Ø;{ :,S. ,~':,::;,\: 1807 ',t4t~.' ,,';-' ,1t?~ , -jIQß: 544 " '.2!i4:." ,".. <,{,; ~ .' r ,2,:~7: 2.368 '2.1~ ' 1.933 , j:'t~}¡",: 1.544 '::1\~Ø:: .:. - " ' ,2,"1. ," 2.070 ',,~ii~:,' 1.690 ,'" '<1~516: . 1.350'" : 1<~$~:>';" . , . '. Notes: 1. R. = R.Sb - (RsOb - R.o)(BoSbl BoOb) 2. Bo = BoD (BoSb I BoOb) [ ( ( ( ( ( ( ( ( ( ( ( ( ( ( ( ( ( ( l W~R. Bo R.o R.st. R.Db Boo BoSb BoOb - Separator Corrected Solution Gas GOR - Separator Corrected FVF - Gas in Solution at Specified Pressure - Gas in Solution at Saturation by Separator Test - Gas in Solution at Saturation by Differential Liberation - FVF at Specified Pressure - FVF at Saturation from Separator Test - FVF at Saturation from Differential Liberation Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 57 Oilphase-DBR Figure 4.9 BP Alaska Recombined Reservoir Fluid, NS-Ð9 + NS-13, 4850 psia Psat Separator Corected GOR AND FVF 3000 ::- 2500 .CI .CI ¡¡: .!. 2000 0:: 0 C) 1500 (I) ca C) 5 1000 :¡:¡ ::s Õ (I) : I I - - - - ..., - - - - - - - - "'T - - - - - - - - T - - - - - - - - r - - - - - - - - r - - - - - - - -1- - - - - - - - -1- - - - . - - - - - - - - - - - - -t - - - .- - T - - - - - - - r - - - r - - 1- - -1- - - - - ~ - - - - - - - - -t - - - - - - - - T - - - - - - - - t- - - - - - - - - I- - - -. - - .- - -1- - - - - - - -1- - - - - ~-+------ -+----- ---- ---------I---------I-- ------1----- I ¡ I I t ------'---------'----------1---------1-- ----L-_- ---_1---- ----1_---- ---------.1- --- L . L ____L__- .1 - - 1. - - -. L - L - - 1- 1 -----'--------f--------+--------~ ____, ----,--- ----:---_. 1 1 1 1 ----~--------~--------T------- ------~--------I-------- ----~--------1--------T------ ------r-------- ------- , - - - - - - I" - T - 1- -. - - - - - - - - - - - - , - - - - - - - - ì - - - - - - - - T - - - - - - - - - - - - r - - - - - - - - ,- - - - - - - - -,- - - - - I I I I ¡ - - - - - - - - -¡ - - - - - .- - -;- - - - r - - - - r - - .. ,- - - - - - - -,- - - - - - -: - - - - - - - - -r - - - - - - - - T - - r - - - - - - - - r- - - - - - - - - 1- - - - - - - - -1- - - - - ----....,---------+------- ---t-------- . '----1----- - ~ - - - - - - - ~ --~ - - - - - ---Unadjusted -=--=-=-=~==-=-=-~ -'- I- - - - _1- - - - - = = = = ~ = = = = = = = = - ~ = = =,= ~ ~ = ~ = = = = = = = = ~ = = = = = = = = L ~~~!~S.t~~ - - - = = = =:= = = -. - - - - 1. - L - - - - - - - L... - - - - - - - ,- - - - - - - - , 1 1 1 I I I ! I I - - - - " -- - í -- I - .-. - 1- - ------1--------T--------r--------r--------r------- - - - - - - - - - - - - - ï - - - - - - - - T - - - - - - - - ï - - - - - - - - I - - - - - - - - 1- - - - - - - - -,- - - - . - - - :- - - - - - - - T - - - - - - - - :- - - - - - .. - -:- - - - - - -!- -!...- - - 0 1000 2000 3000 4000 5000 6000 7000 8000 2.8 I I 1 I' I 1 I --------------~-- -------~- ~----------------- --- - -------- - - - - ..... - - - - - - - - ..... - - - - - - - -! - - - - - - - - -i - - - - - - - - -I - - - - - - - - -J - - - - - - - - -I - - - - ......... Î ..- - - - - -, - - - - - - - -I - -I - - - - - - .-1 - - - - - - - - -,- - - - - - - - -1- - ~ 2.6 = = = = ~ = = = = = = = = ~ = = = = = = = = ~ = = = = = = = = =,' = = - - - - - - -, - - - - - - - - -, - - - - - - - - -, - - - - - ..... I I I -----1---------1---------1----- ::::: :: : : : J : : : : :: : : : J : : : : :: : : : :1: : : : : : : : :,: - - - - - - - - - - - = :1:: :: : : : - :: :: :,: :: - - - .CI 2 -- ---1---------1---------1---------1-- ---1----- :S. .4 =-=-:'-:=.J - - - - - - - -' - - - - - - - --r - - - - - - - _, - - - - - - _1- - - - - - - - - - - - - - - - -'- - - - - - - -I - - - - - - - - -I - - - - - - - - -I - - - - - - - -1- - - - - - - -,- - - - - - - -1- -- - - .š 2.2 ::::: ~ :: : : : :: : : : ~ : - : : F : : : :: :: :: = : : :: :: =:1 : - - - = = :: :': : : : : : = = ::: : ::: - - - =, = : : - : U ::-::J::--:::::__J::::_::::::J:---:_- --. -- -- ca -----1-- --------1- . -,---... - ,- LI. 2.0 - - - = = = = = = = - = = = = = = = = = = = = = = = = - = - = =: - - = = = = = = =:= = = = = = = = =:= = = = = = = = =:= = = =: cu -------1--- ----1--- ---------'---------'--------1 E - - - - - -. :, :: - ,.:. - - :: - - - :: ::,:: - - - - ::s 1.8 --- , 1 1 I , ; ::: ¡ = - : ~ - ¡ ~ - ¡ : ; ~ : : ¡ ¡ ~ ~ - : ~ ; - ¡ ~ ~ ~ = - - ~ ~ = - ~ ; ~ ~ - ~,~ : : : : ~:~:~t:~~ : ~ ~ ~! ~ ~ - - . E - - : - --1 - - - - - - --1 - - - - - - - ~ - - - - ~ : : = -, - - - - .:. - - - -I - - - - - - :: : :;: : : : : : - - . 0 1.2 = = = = .= = - = = = = = = = - - ~ - = = - =: = = = = = - - - =: = = = = = = =- =: - - - - = - - = =: =- LI. 1.0 :: == == == r : : : :: : - - ~ == == == == :: :: : == ==l == == == == ~ : - - = == == == f == : == - :: - - -= :: :: ==;:: :: :: -- 1000 2000 3000 4000 5000 6000 7000 Pressure (psia) 8000 Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 58 Oilphase-DBR TABLE 4.14 BP Alaska Recombined Reservoir Fluid, NS-09 + NS-13, 4850 psia Psat PVT STUDY SUMMARY DATA Gas-OiI Ratio 1: Type of Liberation Total Solution Gas Stock Tank Oil Gravity (° API) Formation Volume Formation Volume Facto,z Factor3 '::'.'._.:~.:})'.:,L~';i);,:~:.';¥~~,.. Differential Liberation 39;~' . 2.360 ., -...-, . , , 2515 39.2 2.509 2.537 (1) Gas-Oil Ratio: set of Gas per bbl STO at 60°F (2) Volume of Reservoir Oil @ Pres, Tres per volume STO @ STD conditions (3) Volume of Reservoir Oil @ Psat, Tres per volume STO @ STD conditions ( ( f C r [ C ( ( ( ( ( ( t ( Oilphase-DBR FILE #: 20023132 BP Alaska Northstar PVT Study Wells NS-09, NS-13, NS-08, NS-15 Separator Samples 59 Oilphase-DBR --- -- -------- -------- ----- - ____n___- -- --- --- ----- ----- - -- -- - ---- APPENDIX A SUMMARY OF ODBR SERVICE CAPABILITIES OOBR retains a number of specialized pieces of equipment to complete high pressure and temperature measurements on petroleum fluid systems. In addition, OOBR retains advanced GC-based analytical capabilities for completing hydrocarbon fluid analyses. For detailed compositional work other than GC (e.g. SARA & HTGC), we call on the extensive expertise of the analytic chemistry department of the Alberta Research Council (ARC) in Edmonton. For organic solids (wax and/or asphaltene) stability evaluation in crude oil systems at realistic production conditions of pressure, temperature and/or composition (e.g. lift gas operation), ODBR offers two state of the art techniques, namely a laser-based solids detection system (SOS) and a high pressure microscope (HPM) equipped with cross polars. While the SDS (rated to 15,000 psi and 390°F) is an established near infra-red (NIR) light transmittance method, the HPM (rated to 20,000 psi and 390°F) is a recently developed visual technique which enables direct detection of organic solids onset conditions and, more importantly, makes it possible to monitor the associated morphological changes. A distinguishing feature of the HPM technique is its capability to discern the nature of precipitated solids such as waxes (when viewed under polarized light mode) versus asphaltenes (when viewed under normal light mode). Descriptions of the aforementioned and other key flow assurance techniques, procedures, and typical results are provided below. _&,::t~~.[.)~~.~..[.)~,&,~ Upon arrival, a sample bottle is connected to a 20,000 psi pump from the water side to check the opening pressures at room temperature. Next, the sample bottle is heated to Tres, pressurized to at least Pres and allowed to equilibrate under continuous rocking for about five days. This process would help disperse deposited/coagulated asphaltene particles, if any, into solution. Following the sample preparation and conditioning described above, a sample of each equilibrated live fluid is isobarically displaced, one at a time, into a pre-cleaned and evacuated pycnometer for density, GOR, and C30+ compositional analysis using a flash procedure. In this technique, an accurately measured volume of the single-phase fluid is isobarically displaced into a pycnometer where its density and mass are evaluated. The pycnometer is then connected to a GOR single stage flash apparatus where the oil is flashed to ambient pressure and temperature conditions. Next, the evolved gas phase is circulated through the residual liquid for a period of time to achieve equilibrium between phases. Following circulation, the volume of equilibrium vapor and the mass of liquid remaining in the pycnometer are measured. The vapor phase is resolved to C15 by natural gas GC, while the residual liquid is analyzed to C30+. From the measured composition and total mass of each phase, the composition of the original live oil may be calculated by mass balance. ~1::(1I:1~1[.lIJ::I-""A.':¥&~_I~ ~2~~%i;;e~::IE~1lli Figure A.1 is a schematic of the ODSR visual PVT Cell. The main body of the cell consists of a Pyrex tube housed inside a steel shell with vertical tempered glass plates to permit visual observation of the internal tube contents. The Pyrex glass tube is 15.2 cm long with an internal diameter of 3.2 cm. This translates into an effective working volume of approximately 120 cm3. A specially designed floating APPENDIX A Oilphase-DBR SUMMARY OF ODSR CAPABILITIES PVT & SOLIDS DETECTION SYSTEM Page A 1 piston (described below) and a magnetically coupled impeller mixer are mounted inside the Pyrex tube to allow for a mercury-free operation. The volume, and hence the pressure of the fluids under investigation, are controlled by a variable volume ODBR displacement pump which allowed for the injection or the removal of the transparent hydraulic fluid. The same transparent displacement fluid is connected to the outer steel shell to maintain a balanced (minimal) differential pressure on the Pyrex tube. Equilibration of the fluid under investigation is achieved by means of a magnetically coupled impeller mixer mounted on the bottom end cap. It should be noted that the bottom end cap is specially designed to achieve two main goals: (i) shield the cell contents from any magnetic effects/flux and (ii) provide for charging and sampling the test fluid. ( l [ ( ( ( ( ( ( ( ( ( ( f ( (" ( ( C C l t ( ( ( ( C ( r PC } - - - - - JEFRI fl " .,." --- -.. -- ....... VISU~ ,. "- Oven Boundaries PVT Cell I I" , -. ~- -~- T. -:;: -. ID~~~~~~~..I If" ", I ./,mmL., /1, .J, :.!'. 'Z \ I /'1 .- ~ \ I ~~ ~ ~ ~ 0lI8l8.... \ . 10 10 I ' I Þ '. ' , .. Plstoned I / . () 0 I ~1.~.?~ - I 0 yUnd.... ~ I I g g I ~; ~ ~ - I I . \ I ~._~ I ~ -- ""----1 ...- ~ rJ. " u--::::' ?~ ,--- " I k-' ~ 'iI" ,--", --- I 7"~ f \ ~" ' ., ...J ... ~ - '- ~..,~ \ 1: ~ ~¿;.. --.... " L_-.-- -~~J \ . " DBR Magnetic \ I ~ MbuII"System , ¡' ... .;' ... " " ./ I - "'./ ..... .-' ------~- Constant Rate JEFRI Pump r;;;] ~ Pressure I~ØI Side View of PVT Cell Figure A.1 - Schematic Diagram of ODBR PVT Cell Equipped with SDS The entire PVT cell is mounted on a special bracket, which can be rotated through 360°. Accordingly, the PVT cell can be inverted to sample any liberated gas when/if required (for gas diluent studies, the cell is kept inverted at all times, Le. the floating piston is positioned on the bottom and the magnetic mixer at the top of the cell). The bracket and PVT cell are housed inside a temperature controlled, forced air circulation oven. The cell temperature is measured with a platinum RTD and is displayed on a digital indicator with an accuracy of 0.2°F or 0.1°e. The cell pressure is monitored with a calibrated digital Heise pressure gauge accurate to :t 0.1 °,10 of full scale. The maximum operating pressure and temperature for this PVT system is 15,000 psia and 392°F, respectively. ~~~2....;/.'().Q~ft.$dJ1Ç1s(,J.;\êt~iôn~.$Y$tÉ!t11:I$ØS) The visual ODBR PVT cell described above is equipped with fiber optic light transmission probes (source and detector) to measure the onset of organic solids precipitation (due to temperature, pressure and/or compositional change) concurrently with fluid volumetric data. These fiber optic probes are mounted across the windows of the visual ODBR PVT cell as illustrated schematically in Figure A.1. The visual ODBR PVT cell along with the optical probes and the computerized pump are termed Solids Detection System (SDS). The measurement principle of the SDS is based on the transmittance of a laser light through the test fluid while either the temperature, the pressure or the fluid composition was being changed. The entire system is controlled by a proprietary software package that accomplishes two significant objectives. Firstly, a computerized pump is used to control and maintain the system pressure during isobaric temperature sweeps for wax precipitation experiments, isothermal pressure drop and/or isobaric injections of solvents/titrants for asphaltenes precipitation studies. Secondly, the APPENDIX A SUMMARY OF ODBR CAPABILITIES PVT & SOLIDS DETECTION SYSTEM Oilphase-DBR Page A2 software (in real time) records and displays the system temperature, pressure, solvent volume, time, and most importantly, the power of transmitted light (PTL) through the test fluid. 5~~~~šÞJR~tJllfíb,~~~~_-~;(ØIM} The standard SDS configuration discussed above has been further improved with the addition of ODBR high-pressure microscopy (HPM) in series. A schematic diagram of the set-up is shown below in Figure A.2. The HPM cell is a small sapphire prototype with variable internal diameter and, in turn, working volume. It is connected to the bottom of the PVT cell inside the same air-bath oven. The total dead volume in the HPM cell, tubing and fittings has been minimized and estimated to be 1 cm3. Video L--J,J Recorder Oven Boundary i------------------~ . . ; Iln-line : I HPM . . . . . . . I . I . . . . . t--t- n : I ~ . . . . . . u V . : 10.0 : I 0 0 . : 0 0 : . 0 0 . ¡;;;;:;¡ :DBRn'ft :~. I PVT . . Cell . I L--.J . Solvent Storage L--__- ----------_J SCyfinder ~tylnder Insulated Transfer Lines ~~lO 8 ~p Q ~. ---, I t- '---i Q ~ Positive Displacement Pump Figure A.2 - Schematic of the OCBR High Pressure Microscope (HPM) A.~io~...()DI3Ji-PattiÇfeßiteÄn..lysis.(~A) ODBR retains a particle size analysis (PSA) capability based on proprietary imaging software that operates as a synchronous feature of the HPM system. The system was calibrated using particle standards of varying concentrations and size (1-50 Jlm) as well as micro-scale objectives. The PSA software scans digital HPM photomicrograph images in real time at a high sampling rate and simultaneously discretizes such images within a restricted field of view, on a pixel-by-pixel basis. From these data, histograms of particle size distribution are produced continuously and frequently over the residence time of an experimental sample contained by the HPM cell, thus providing information regarding relative abundance, morphology changes and onset conditions. Figure A.3 exhibits a sample PSA report generated during discrete depressurization of an unstable live oil at reservoir temperature. The reported particle diameter is the diameter of a circle with an area equivalent to the projected area of an asphaltene particle. The number counts are cumulative value obtained from analysis of 20 images at a given pressure. APPENDIX A SUMMARY OF ODSR CAPABILITIES PVT & SOLIDS DETECTION SYSTEM Oilphase-DBR Page A3 L~ 10000 1000 .1.. 100 ~ 1 ~ 1ßWmn .. 10000, '~ t~ ~ 1 J 10000 .: I 1000j 100 .; 1~ . ~.rA1- - . - -I P = 10000 psi I ! '. - ..... - - - u- -.§ i P = 9000 psi I ~, _. ... - -. -, - -. n. ,- ---'-----'--'- +J C :::s 0 Ü 100001 1000 .In .~ h 100 -Ikh, 1~ -llllrm ~ n 10000, 1000 + 100 .i'.' 10' "'C _. ~ 1 /I nflnl 100001 1000 J 1 00+--- ~ - 1 ~tlmlñ" .~.. ,. 10000 T .. ". . 1000 ~ ,..:..; ...;.;. -'- '- '-... -'-~: ,~.-. ,--~-,-.;..;- 100 ~-,-- -:-,- 1~ îWnnnn 10000 1000 ~ '-' .~ 1 00 '~lF.;.'" 1~ lllmn-njj&~~' '-, ~- 10000 1~gg ~~:~..'" :.;'nrm~nn~ 1 ~ ~1~11111 lIImgnDmllnriim- 1000 r: . . 100 I '".:. . :.: .. . . 'd"'.M~Ú",~, CC;Cê~ 1000 T~-.' '~ ¡ i ~1ÎILJI¡,.in¡¡¡"."..I. 1~~ lii~:;.m ....~~... 10000 ì 1000 -+'. 1~~t__"~~ ,,;;, 1 11 21 31 41 51 P = 4000 psi I 0 n¡¡n 1111 OOAn n 61 71 81 91 101 111 121 Size (~m) Figure A.3 - Sample PSA Histograms for a Discrete Depressurization Experiment APPENDIX A SUMMARY OF ODBR CAPABILITIES PVT & SOLIDS DETECTION SYSTEM Oilphase-DBR Page A4 ~a~5c;:..:;«fmÞitf;JØ'e~.-þ"'M..Qê;:"l'~~.",(I;Mv) For viscosity measurements, ODBR retains a Cambridge EMV model SPL440 (See Figure A.4). Such a High Pressure Viscometer is a precision instrument designed to accurately measure the viscosity of petroleum fluids. It was developed in cooperation with Cambridge Applied Systems and capable of continuous operation to 138 MPa (20,000 psi) and 190°C (374°F). The SPL440 system can be configured as a stand-alone system or as an in-line component with the ODBR Visual PVT Phase Behavior system. Performing viscosity measurements over the range of 0.1 to 10,000 cP on very small volumes of fluid makes this instrument an ideal component for petroleum fluid laboratory studies. A number of electronics options are available for operating the SPL440 Viscometer, including the ViscoPr02000, a device that is able to provide unparalleled accuracy over the greatest measurement range. Even with this outstanding degree of precision, accuracy and functionality, the SPL440 Viscometer is still easy to install, operate and service. It has only one moving part, a small magnetic stainless steel piston located inside the sensor that is driven up and down using coils, simplifying installation and servicing. The measurement chamber, connected to both top and bottom system lines, allows for easy introduction, measurement, and removal of a fluid from the Viscometer. Measurement Chamber piston Figure A.4 - Schematic Diagram of Cambridge Electromagnetic Viscometer ~2.6....q.Pillâry,Visêornetet..(CV) ODSR also retains a capillary viscometer (CV) rated to 10000 psi and 374°F. The CV set-up consists two high pressure cylinders (32 ml each) connected to a 1.83 m (6 ft) in length and 0.076 cm (0.03 inches) in diameter capillary coil. A differential pressure transducer is used to monitor the pressure drop across the capillary coil. The fluid sample is pumped from one cylinder to the other through the capillary coil by an opposed pump (See Figure A.5). From the measured fluid flow rate and pressure drop, the viscosity can be determined using the Hagen-Poiseuille relationship for laminar flow in tubes, namely: APPENDIX A SUMMARY OF ODBR CAPABILITIES PVT & SOLIDS DETECTION SYSTEM Oilphase-DBR Page AS ~=~(~~:=~k Where .1 is the fluid viscosity, ßp is the pressure drop across the capillary tube of length, L, and a radius r, and Q is the volumetric flow rate. The tube constant k is determined by calibrating the viscometer using standards of known viscosity at test pressures and temperatures. Oven Boundary ~ .-------------------. In-line - . Densitometer . . Magnetic Coupled . DP Mixer Assembly ~ . Transducer Tl 1 ~--------. . Ä. ,.., . \jJDJ . ; ;+-~r~XTUbe . ;-J--lIqUld Level . . /~ .;..;- Tapered Piston Vent\Vac. Line. . /;-/; . DBR JEFRI . . Capillary Viscometer . . . L---.J : ' Sample / DBR JEFRI : Cylinders PVT Cell .- - - - - - - - - - - - - - - - - - - -. ) ... Vent\Vac. Line r~~- -a= === =D- F - DBR JEFRI Sample Cylinder DBR JEFRI Opposed Pump =e===9WP - L -.J f- ( ( ( ( l l ( [ ( l ( ( ( l l ( ( DBR JEFRI Injection Pump Figure A.5 - Schematic of Capillary Viscometer Setup Œ8i¡{.IIt=-.)'J::~~ ~~i~1iç.g~_i(tI~Q:.~_Q,~~{(~~eJ The CCE test is initiated by charging a known volume of the equilibrated fluid to the PVT cell at T res and Pres. At these conditions, the fluid density is measured and the initial mass of the fluid in the cell is calculated. Thereafter, the fluid is expanded isothermally to a lower pressure, which is still in the single- phase region. The total system volume is measured after equilibration at this pressure, and this volume is used to calculate the single-phase density at this pressure. This procedure is repeated a number of APPENDIX A SUMMARY OF ODBR CAPABILITIES PVT & SOLIDS DETECTION SYSTEM Oilphase-DBR Page A6 times until the bubble point pressure is reached. Subsequently, the pressure is reduced further by selected pressure intervals into the two-phase region, and at each pressure point the vapor and liquid phases are equilibrated, phase volumes measured and plotted as a function of pressure. The intersection of the single phase and two-phase lines in the PV plot and the visual observations in the PVT cell are used to define the bubble point. A.3.2Dlfferehtiäl.Llberatlolt: (DL) Following the CCE test, the fluid is pressurized slightly above the measured bubble point pressure and is allowed to equilibrate at such conditions for about one hour. The single-phase fluid is then flashed to the first specified pressure condition of the differential liberation study and equilibrated for at least 30 minutes. Subsequently, the equilibrium vapor and liquid volumes are measured using the cathetometer. A portion of the liberated vapor phase is isobarically displaced into an evacuated pycnometer for gravimetric density determination and compositional analysis. After collection of the vapor phase sample, the remaining portion of the vapor is isobarically displaced from the cell. Next, about 5 to 6 cm3 of the liquid are charged into the Cambridge electromagnetic viscometer for viscosity evaluation. Finally, the remaining liquid volume is measured and subsequently flashed to the next specified pressure condition. This procedure is repeated for a total of the specified pressure steps. Æ~..~...'.'êóì\S~b'...\i_~ì!tèi,,,þl8tiorfl~VD) The CVD test is initiated by charging a known volume of the equilibrated fluid to the PVT cell at Tres and Pres. This volume is important as it is used to establish the reservoir volume to which the PVT cell contents are returned after each depletion step. The CVD test involves reducing the system pressure from Pres to the first specified pressure step at which the fluid is equilibrated. Next, the resulting vapor and liquid volumes are determined. In addition, a portion of the equilibrium vapor is displaced from the top of the PVT cell and analyzed for its C30+ composition and density. Finally, additional vapor is displaced to return the fluid system to the initial single-phase reservoir volume as defined above. The system pressure is then reduced to the next specified depletion pressure step and the above measurements are repeated. In all, measurement procedures are completed at 6 to 10 depletion steps. g~4,':';"q"~-$t8ge$êpal"âtôr A known mass of homogenized fluid is transferred into the PVT cell and equilibrated at the bubble point pressure and reservoir temperature. The pressure and temperature are then set to the first specified separator condition and the system is allowed to equilibrate. Subsequently, the equilibrium vapor and liquid volumes are measured using a cathetometer. A metered sample of equilibrium vapor is isobarically displaced into an evacuated pycnometer for gravimetric density determination and compositional analysis. The remaining portion of the vapor phase is then isobarically displaced from the PVT cell. Next, a metered sample of the liquid is isobarically collected into an evacuated pycnometer for gravimetric density and compositional analysis by the flash procedure. After measuring the remaining liquid volume in the cell, the system conditions are adjusted to the second specified stage. Again the liquid and vapor phase volumes are measured and a sample of each fluid is taken for density determination and compositional analysis. This procedure is repeated a number of times until the last separator stage has been reached. A.3,¡~,. .YjscosityMeasuremer¡tUsingEMV The test fluid is charged to the vessel and the piston is surrounded by fluid. Subsequently, the piston is moved inside the vessel by imparting a force on the piston using two electromagnetic coils inside the sensor body. After travelling the length of the test vessel, the piston is returned to its starting location by APPENDIX A SUMMARY OF ODBR CAPABILITIES PVT & SOLIDS DETECTION SYSTEM Oilphase-DBR Page A 7 [ ( c ( ( ( ( f [ C l ( ( C ( ( l ( ( reversing the magnetic field of the electromagnet. The motion of the piston inside the vessel is impeded by viscous flow around the annulus between the piston and the measurement chamber wall. Viscosity is determined by measuring the piston transit time for a complete cycle of piston movement and comparing this to times obtained using calibrated standards. Æ3..6[)iscr.~I$()tM~IOt.It..'.ÎQ'" After charging the reservoir fluid to the PVT cell at T res and Pres or higher, the SDS components are mounted across the full length PVT cell windows. A reference scan of the light transmittance through the fluid is then performed at the initial system pressure. The pressure of the cell is then lowered isothermally at discrete pressure steps (100 psi) with -5 minutes of equilibration time at each pressure step while the cell contents are mixed continuously and vigorously (-1,400 rpm). The experiment is stopped soon after a sharp and dramatic drop in the power of transmitted light (PTL) is observed. This drop in PTL corresponds to the onset formation of a solid phase and/or gas phase. To this end, it is useful to summarize some of the main factors known to influence the light transmittance (L T): . L T is inversely proportional to density; hence, if the density decreases then L T increases. Density is proportional to pressure (above bubble point); hence, if the pressure decreases then PTL increases. L T is inversely proportional to particle size (PS); hence, if the PS increases then L T decreases. L T is inversely proportional to the nucleation density of solids (NDS); hence, if the NDS increases then the L T decreases. . . It is also useful to present and describe (qualitatively) typical SOS de-pressurization traces measured for two low content asphaltenic crude oils with (OIL 2) and without (OIL 1) asphaltene precipitation problems at respective reservoir temperatures. These are depicted as Figure A.6 for ease of comparison [Hammami et al., Energy & Fuels 14 (2000) 14-18]. In the case of OIL 1, the power of transmitted light (PTL) increases more or less linearly as the pressure is decreased isothermally from 62 MPa to 34 MPa. This is likely due to the decrease in fluid density with decreasing pressure within this pressure range. At about 34 MPa, the PTL signal drops dramatically to noise level. This drop is visually confirmed to correspond to the formation of a vapor phase (Le., bubble point is reached). The emerging liquid-gas interfaces cause instantaneous and significant scattering of the laser light at and below 34 MPa. With the removal of the liberated vapor phase below the bubble point, the PTL signal through the liquid phase decreases nearly linearly as the pressure is depleted to about 2 MPa. This is plausible because with decreasing pressure, the residual oil density increases as the dissolved light ends continue to evaporate. In the case of OIL 2, on the other hand, the PTL signal increases linearly from 62 MPa to an intermediate pressure of about 50 MPa. With further reduction in pressure, the PTL curve exhibits a plateau (initially) and then commences to decrease gradually and progressively. At about 39 MPa, a vapor phase starts to emerge (Le., bubble point is reached) and, in turn, the PTL signal drops to noise level. The point of departure of the PTL curve from the linear behavior at approximately 50 MPa is interpreted as the onset of asphaltene precipitation for this oil. Below the bubble point, the PTL curve decreases (initially), but then starts to level off at about 24 MPa. The observed break in the curve is likely the net effect of two competing processes. Opposing one another are the effect of liquid density, which increases with decreasing pressure, and the effect of asphaltene re-dissolution, which also increases with decreasing pressure. Accordingly, the increase in liquid density causes the PTL to decrease, whereas, the simultaneous decrease in size and/or amount of precipitated asphaltenes tends to increase the PTL. APPENDIX A SUMMARY OF ODBR CAPABILITIES PVT & SOLIDS DETECTION SYSTEM Oilphase-DBR Page A8 - fI) := = ;;;J ~ "'" e - :s "'" ~ b ~ £ "'" ï ~ _OIL 1 @ 80.6 C) ........ ° IL 2 @ 68.3 C) I As¡iIakene Onset { - 50.4 MPa I , . I I I I I I I , I , "If Bubble Point ..¿,,~'Jt III~IIII'I I I I I I I I , 0 10 20 30 40 50 ffi 70 Press ore (MPa) Figure A.6 - SDS Depressurization Traces of Live Oils With & Without Asphaltene Instability [Hammami et al., Energy & Fuels 14 (2000) 14-18] Figure A.7 depicts an SDS depressurization trace for a South American crude at corresponding reservoir temperature. HPM photomicrographs taken simultaneously during the isothermal pressure depletion experiment are superimposed on the same figure for ease of comparison. As can be seen, the HPM photomicrographs are consistent with the SDS trace; they help explain the observed trend and provide visual evidence (at the microscopic level) of the nucleation and agglomeration of asphaltenes during the isothermal depressurization process. APPENDIX A SUMMARY OF ODBR CAPABILITIES PVT & SOLIDS DETECTION SYSTEM Oilphase-DBR Page A9 300 ------.------------.--..-..-.- ...- '..-.-. . -----.--.----..-.,-"-".-",,-, """---'--'--"""-- 250 ~ Q. - - s::. i;' ~ 200 ... .:1.'".'.''' ...I . . '". ~ J. " '~".'. i;- . .;.1 ::...>. ' E 150 .. ; :tlC'::.. '- '.-.- ~.." - ~ ~;pi t! : t- ' . . ~I ~ 100 . . .i~:.I... ~ I 0 1 0.. 50 ! r ! I '.""+411 ......,,~ ': '--1--.-'- -.- Y....'''......'~. 'f.I.,;;,....1..........~...'... , ".. ,.,"" ~',:;''':. ',." "" ,," ',.~ .. f\ ..1>t;~..~ :"'.'."."I\..'t'~. .... {,' "~"~?f:~:~~:'~ 0 " 1500 3500 5500 7500 Pl'8ssure (psia) 9500 11500 13500 Figure A. 7 - SDS Depressurization Trace of South American Live Oil & Corresponding HPM Photomicrographs at Tres [ ~~,~r;¡;'ì.J!fçj~';t$qtÞê_"~_,~tj The SDS can be used to identify the onset of solids formation from a given crude oil due to isobaric and/or isothermal solvent/gas injection. The procedure involves charging a known amount of oil sample to the pre-cleaned and evacuated PVT cell. Thereafter, the PTL is measured and recorded continuously (in real time) while the solvent/titrant is being injected at the desired rate (continuous or discrete) and the resulting cell content is mixed vigorously. The experiment is stopped when a dramatic drop in PTL is observed as illustrated in example A.B. Qualitative description and/or interpretation of such a trace is provided below. ( ( r ( r c ( ( The PTL increases more or less linearly as the concentration of solvent/titrant is increased isothermally and isobarically from zero 01'10) to an intermediate level 01'1*). This increase in PTL is likely caused by the decrease of fluid density with increasing concentration of the lighter n-alkane (making it easier for the laser light to pass through). Above W*, the PTL signal starts to decrease gently and progressively to noise level with further increase of n-alkane concentration. ( [ The drop of the PTL curve starting at W* is believed to correspond to the onset of asphaltene precipitation from the liquid. Hence, the onset point is defined to be the maximum concentration of solvent prior to the observed drop in PTL. APPENDIX A SUMMARY OF ODBR CAPABILITIES PVT & SOLIDS DETECTION SYSTEM Oilphase-DBR ( ~ Page A10 L --..."""".......,.,.,,.,..'"~,,"-,",,",,.. :J"' to- ' a.. ' - ' .. .c ' 0)' ~ : 'a ' I : E : I! ' I! : to- ' ~ : j ~ 0 ' a.. ' Wo -"......._-,....",_...."".__........~- W* OIset of Asphlltane I Precipitation i I I I I I I . I I I . . . I . I . . .. . . I . . I .. . I . I. . . . . Wei g-.t Percent of Solvent Figure A.S - Typical SDS Titration Trace Depicting Onset of Asphaltene Precipitation Typical HPM Photomicrographs taken during titration of an asphaltenic crude oil with n-alkane are superimposed on the simultaneously measured SDS titration trace for the same oil as illustrated in Figure A.9. It is evident from this graphical comparison that the HPM is noticeably more sensitive than the laser-based SOS technique. This is plausible because the registered light transmittance represents the net effect of oil dilution with lighter n-alkane (resulting in decreased mixture density; hence, L T tends to increase) and formation of a dark solid "asphaltene" phase (L T tends to decrease). The maximum in the SDS titration curve occurs when the latter effect (solids formation) surpasses that of the dilution. This usually occurs when the asphaltene particles grow to a critical size and/or increase in concentration at a critical n-alkane concentration. i' 'ë ::J ~ ~ :ë '- ~ .... .c en :.:; " .$ .. .e II) s:: e .... - 0 i 0 a. I Asphaltene Onset l determined by HPM ~ ~ '-- Volume % n-C5 in n-C5-0il Mixture (arbitrary units) Figure A.9 - SOS Titration Trace and Corresponding HPM Photomicrographs of Fluid Mixtures Prone to Asphaltene Instability APPENDIX A SUMMARY OF ODBR CAPABILITIES PVT & SOLIDS DETECTION SYSTEM Oilphase-DBR Page A 11 A..3"8,tlìiii~"h~~';:rÂriift¡;~;¡j~cn.;~Tae+:'::(~,~f88) ~"....~,.,.,,--.Ii;.~~~.",M~'~ oJ" ...: '.'. ,.~'!*~~._Z~.l~:~~.t..;:I....-...¡._.0è..~ð-- - .... ."', The SDS can be used to measure the cloud point temperature of the fluid (both live and dead) at constant pressure. The maximum cooling rate is - 1°C/min. procedure involves charging a known amount of oil sample to the pre-cleaned and evacuated PVT cell. Thereafter, the PTL is measured and recorded continuously (in real time) while the cell temperature is being lowered continuously at constant pressure (using the computerized ODBR pump). The experiment is stopped when a dramatic drop in PTL is observed (see example Figure A.10). The temperature at which the drop occurs is interpreted as being the cloud point temperature for the fluid at the test pressure. -250 ( : ! ,COOling, ~.:; 200 -... ,..... ... ...........¡........ ...... '"''''''''r''''';''''';''' ........ ':'" ........;..... ;.... ..:..... ... ..- , .. , ., , .. . . . . . . . . "C ,',., "5 : ~ j ¡ : ü: 11 50 ...,.... .~.... 'I""""~" I~ 1 ~ '~'1 ~~'6:~II""""""""'" '1"'" ,- "Ë ~ 100 -"""""""",'. """""""""["""""""""'[""""""'",...~....,..- ~ 5: ~::'~mD~DI::r:::I:::::I:~ I I I I I 80 100 120 140 160 Tern perature (OF) Figure A.10 - Typical SDS Cooling Trace Depicting Onset of Wax Precipitation [Hammami and Rajnes~ SPE Jouma/~ 4 (1999) 1-10] r l Typical partially cross-polarized HPM Photomicrographs taken during isobaric (15,000 psi) cooling of waxy crude oil are illustrated in Figure A.11. Asphaltene particles are also evident in the HPM photomicrographs for this crude. The atmospheric wax appearance temperature for the same sample was measured to be 48°C/118°F. APPENDIX A SUMMARY OF ODBR CAPABILITIES PVT & SOLIDS DETECTION SYSTEM Oilphase-DBR Page A12 Wax Cf)stalS \ ~ .~ ~J I Tnnpemlltre =: 75.5"CJI68"F Temperature"'" 66. ¡OCiI52" F fef11peratllrc = 66.5"C/15l. -'0 F Figure A. 11 - Cross Polarized HPM Photomicrographs of Waxy Crude Oil Taken During Cooling @ 15000 psi (1034 bar) [Karan et al., SPE Paper 62945, 2000J A.4 Live Oil Bulk h~li1(.]11 For filtration of live oil, ODBR retains a bulk precipitation/deposition apparatus, which may be used simply for removal of suspended solids in live oil or for quantification of solids precipitated at high pressures. Briefly, the apparatus consists of two stainless steel ODBR high-pressure cylinders (1 litre capacity) equipped with floating pistons. The cylinders are suitably connected to each other and a high- pressure 0.2 f.1m Silver Millipore filter is placed in-line such that the contents of both cylinders can be displaced through it. A mineral oil hydraulic fluid and a motorised ODBR high-pressure displacement pump are used to displace the cylinder contents from one cylinder to the other through the filter for separation and analysis. The entire apparatus (excluding the displacement pump) is enclosed in a constant temperature controlled air-bath. The filtration can also be performed directly from the PVT cell by displacing the test fluid through a high-pressure 0.2 f.1m Silver filter. This alternative is significantly cheaper than the bulk deposition apparatus described above, but the sample volume involved is barely sufficient to yield reproducible results. A.S Dead Oil Pour Point In the modified ASTM D97 method, the oil is initially heated to a temperature 10°C above the wax disappearance temperature (determined by CPM) as opposed to heating the oil to a temperature 9 °C (for oils with pour point> 33°C) above the expected pour point required by ASTM D97. Briefly, this test involves the visual examination of the sample during cooling. At each temperature step (3°C/5.4 of decrement) the ASTM sample vial is poured or tipped to determine if the oil has any mobility. APPENDIX A SUMMARY OF ODBR CAPABILITIES PVT & SOLIDS DETECTION SYSTEM Oilphase-DBR Page A13 A.6 Live Oil Pour Point A new experimental apparatus has been developed to measure Live Oil Pour Point (Karan et al., SPE Paper 62945, 2000). The live oil pour point will be measured by a method similar to that described in section A.5 above. The live oil will be introduced in a sapphire cell (approximately 35 mm diameter and 150 mm high) initially filled with synthetic gas mixture at test pressure. Sample oil will be transferred to fill in up to a height of 50 mm. The oil is allowed to be cooled according to the ASTM D-97 method. The fluidity of the oil is checked every 2-3 °C by tilting the cell slightly and observing the movement of the interface. The temperature at which the interface ceases to move is deemed as the live oil Pour Point. I I Back Pressure Y Regulator .~ II Pressure Gauge Rotatabole I Shaft I i I I Temperature Indicator ~ ----------------. ._-------------. ! I~,' ! " . . . : .~ "'"'" : : I I : : ' Mnrl J.I : ! ! ¡Ii JL' Gas : : n J H~ : . ! \ ;¡ :¡, I:!: :' I : i II ~i I : : r I ..1 II j'" Oil: : . ::;t . . L 'I' ¡ :, :11 : . ~. :' .: . : I: I'~ I ! i I I ~ i : I...: , l....-t:kJ, , . . . , . , , ~----------------------------_... Temperature Controlled Air Bath ~ I ~ Gas Cytinder ~ ~U§U ~~ Positive Displacement Pump ! e! ~ I ! [ i ~ Oil Cylinder I I L-¡ Figure A.12 depicts the live-oil pour point apparatus schematically. Q1mJ I e~ Positive Displacement Pump Figure A.12 - Schematic Diagram of the Live Oil Pour Point Apparatus The gel strength or yield strength of waxy crude oils have been successfully determined using the model pipeline test (MPT) apparatus. A high pressure MPT apparatus was recently developed and tested (Karan et aI., SPE Paper 62945, 2000). A schematic diagram of the model pipeline test apparatus is shown in Figure A.13 below. APPENDIX A SUMMARY OF ODBR CAPABILITIES PVT & SOLIDS DETECTION SYSTEM Page A14 Oilphase-DBR Heated Lines r-=="---' I____L___---l 1 1 1 1 1 1 J J J J J J I 1 I 1 I I 1 I 1 I 1 I 1 I 1 I 1 I 1 I I 1 1 I 1 I 1 1 1 1 I 1___________1 High Pressure Ci:.~ump . I ...1 þ Back-Pressure Regulator / --1 ~ JEFRI Pu~ ..~ Test Coil Figure A. 13 - Schematic Diagram of the Model Pipeline Test Apparatus The apparatus consists of two stainless steel coils - each 7.04 mm I.D. x 6.10 m long - that are placed in a temperature-controlled bath. The total volume of each coil is -240 cm3. However, for each experiment approximately 350 and 700 cm3 of oil sample are required depending on the whether one or both coils are used. The thermal pretreatment of the oil is an important part of the experiment. The oil sample is maintained at a temperature higher than the Wax Dissolution Temperature (WDT) in an oven for at least 12 hours to erase the thermal history. Dead Oil Charging: For dead oil testing, the experiment was initiated with the evacuation of the cleaned coils and the heating of the water-bath to the "Starting Temperature" (generally 10°C above WDT). After the bath temperature attained the starting temperature, the oil is charged in the coils and the connecting lines. The oil is then circulated through the coils for at least 30 minutes. This method helps to remove any trapped air bubbles from the coils, which could drastically affect the gel strength value. Upon completing the circulation, the pump is isolated from the coils whereas the flow line connecting the oil container/reservoir (containing oil at starting temperature) to the coil inlet is left open. Live Oil Charging: For live oil testing, the experiment is initiated with the evacuation of the cleaned coils and heating the water bath to the starting temperature. This is followed by charging the saturation gas (separator gas) to the coils and to the connecting lines. Next, the gas is pressurized to the test pressure, which is controlled by the back-pressure regulator. After the water bath attained the starting temperature, the live oil is filled in the coils and the connecting lines in a pre-determined sequence. The gas in the transfer/connecting lines and the coils is displaced through the back-pressure regulator. Cooling and Aging: The oil cooling under static condition is done under specified cooling rate. An example of the cooling rate profile to simulate the pipeline situation is demonstrated in Figure A.14. After the target test temperature or aging temperature is reached, the oil in the coils is allowed to age for at least 6 hours (or any specified period of time) to let the oil develop its gel strength. APPENDIX A SUMMARY OF ODSR CAPABILITIES PVT & SOLIDS DETECTION SYSTEM Oilphase-DBR Page A15 Ungelling: After the aging, the ungelling of oil is started by pressurizing the coils with nitrogen gas. For this purpose, the pump and the reservoir is isolated from the coils by closing the relevant valves. Nitrogen pressure is increased in steps of 1 psi over 0-10 psi range, 2 psi over 10-30 psi range and 5 psi thereafter. Exactly 5 minutes are allowed between each pressure increase for oil to ungel. The pressure at which the oil is observed to have started to move is deemed as the Yield Pressure. Gel Strength Calculation: The yield strength ('t) can be calculated from the measured Yield Pressure using a force balance equation and is reported below. 1: = PD/4L P = ungelling pressure D = tube inside diameter L = coil length Note: The procedure (stress loading rate, aging time etc.) may be modified according to the requirements for a specific project. 60 Estimated pipeline cooling profile Simulated cooling profile [ ( ¡' u 45 ~ 30 E-t ~ 0.6 C/hr Aging ~ 15 ~ ~ ~ E-t 0 ( ( l ( ( ( ( ( r ( c l ( ( ( ( , TIME, hr Figure A.14 - Experimental Simulation of Pipeline Cooling Profile _1~1iIII~~~lt.I'_~'JI("'L'~'"1I1'J~1~ The use of CPM for the study of wax crystallization is based on the fact that all crystalline materials rotate the plane of polarization of transmitted polarized light. Hence, by crossing two prisms on opposite sides of the oil sample, all light is initially blocked and the entire field of view appears black. On cooling, the crystallizing material appears as bright spots against this black background. This technique usually provides the most conservative (or highest) value of the crude oil cloud point temperature due the CPM's abaility to detect small crystals, Le. during early stages of wax crystallization. ( [ r l The experimental procedure involves preheating the dead oil sample in a water bath to 65°C for 30 minutes to melt the waxes and homogenize the sample. Next, the corresponding sample container is hand-rocked prior to transferring one drop of the oil to a special glass slide, which is then covered with a cover slip. The glass slide containing the oil sample is inserted in the CPM hot stage and the field of APPENDIX A Oilphase-DBR SUMMARY OF ODBR CAPABILITIES PVT & SOLIDS DETECTION SYSTEM Page A16 view was brought into focus. The temperature of the programmable hot stage was then increased at a constant rate of 10 °C/min from ambient temperature to 10°C above the wax disappearance temperature (WDT). The WDT is defined as the temperature at which the last trace of wax disappears from the field of view upon heating. Next, the sample is allowed to equilibrate at the maximum temperature for 1 minute. Finally, the sample was cooled at 2°C/min from the equilibration temperature to O°C. The corresponding wax appearance temperature (WAT) is identified (off-line) as the temperature at which the first detectable bright spots (Le., wax crystal size in the order of 1 J!m) emerged in the black field of view. An example of the W ATtesting using CPM is shown below in Figure A.15. Te.81:bé4lre = EIre WAT=24°e T&Ipeèttre = ere OIL A CD .... ::s .. ca .... CD a. E CD I- TeltJE;rdtJ'e = tUe MT=41°e .. . ... ., . -... - a.... '. .... .-. . ..... .. - ... ~.. ,.;. J. .. ~""'-4'-, ,. - ~- ,. . ~ ... .... 4'. .,... . -' . TetlJØ"c4lIe = ere OILS Figure A.15 - Example photomicrographs of crude oil depicting wax crystals (bright spots) under polarized light. ODBR retains three (3) ODBR Core Flooding Apparatus rated to 10000 psi and 390°F. Each apparatus is divided into four subsystems: Injection System, Core Holder System, Production System, and Instrumentation. One of the Core Holder Systems consists of a stainless steel 316 cylinder 54.9 inches long with an internal diameter of 7 inches. The other two Core Holder Systems consist of a stainless steel 316 cylinder, 8 inches long with an internal diameter of 3 inches. The fluid pressure inside the core is controlled by movement of the displacement fluid to and from the apparatus using a ODBR positive displacement pump. Confining pressure is applied using water in the annular space between the sleeve and the stainless steel cylinder. Each Core Flooding apparatus is housed inside a steel shell equipped with a temperature controlled water bath. A re-circulation system insured constant temperature along the entire length of the system. APPENDIX A SUMMARY OF ODBR CAPABILITIES PVT & SOLIDS DETECTION SYSTEM Page A17 Oilphase-DBR The temperature is measured with a thermocouple and displayed on a digital temperature indicator, which is accurate within 0.1 °C. Each Core Flooding system is mounted on a support system, which allows for variability in the angle of dip, and is also mounted on an axially rotating mechanism that eliminated fluid segregation effects caused by gravity. Briefly, the procedure involves dissolving 2.5 g of dead oil/residue sample in an equal amount of toluene in a 300-cm3 flask. When the oil is fully dissolved, 40 cm3 of n-C7 is slowly introduced for each cm3 of toluene previously added. The flask is then capped and shaken thoroughly for 5 minutes and the precipitate is allowed to settle in subdued light for 2 hours with occasional shaking. Next, the contents of the flask are filtered through a filtering funnel (using a 0.22 J.lm filter) into a filtering flask under slight vacuum. The flask is then rinsed with n-C7 and the washings were transferred to the filtering funnel. The precipitate is then washed until the effluent is colorless. The filtering funnel and the original flask are then dried at 105°C. Finally, the filtering funnel and the flask are re-weighed to quantify the asphaltenes (n-C7 insolubles). f - [ Figure A.16 depicts saturates-aromatics-resins-asphaltene (SARA) fractionation protocol. Briefly, the procedure involves fractionation of a dead oil into two cuts by distillation at 270°C (i.e., the boiling point of C1s). The C15- fraction «270°C) is then subjected to supercriticaI fluid chromatography (SCF) to determine the aromatics-to-saturates ratio. The C1s+ residue (> 270°C) fraction, on the other hand, is dissolved in n-heptane solvent at 50°C; the mixture is filtered hot (i.e., at 50°C) to remove undissolved asphaltenes (defined as hot n-heptane insolubles). Following this, the filtrate is cooled and filtered at - 10°C. The resulting precipitate (essentially wax insoluble at -10°C) is then weighed and denoted as the wax content. The wax fraction may be dissolved in CS2 and analyzed by high temperature gas chromatography (HTGC) to C100+. The assignment of the weight percent data to the appropriate n- paraffin and iso-paraffins will be based on the measured retention times of the calibration standard n- alkanes. The weight percent of iso-paraffins for a given carbon number will correspond to the sum of the area percent values of the peaks in between two consecutive (neighboring) n-alkanes. ( ( C ( ( ( ( ( ( ( Subsequently, the solvent is evaporated from the de-waxed and de-asphalted filtrate. The remaining maltenes are dissolved in n-Cs (i.e., carrier solvent) and injected into a packed column filled with silica and alumina. The silica section of the column strips out the polars (i.e., resins), the alumina section removes the aromatics and, hence, only the saturates initially elute through along with the carrier solvent (Le., Cs). The column is then washed with a medium strength polar solvent to remove the trapped aromatics. Finally, the column is washed one last time with a fairly strong polar solvent to recover the remaining polars/resins. Typically, the saturate fraction recovered is observed to be white and opaque, like candle wax, whereas the aromatic fraction appears to be brownish and the resins have a very dark color. ( L ( ( ( ( ( APPENDIX A SUMMARY OF ODBR CAPABILITIES PVT & SOLIDS DETECTION SYSTEM Oilphase-DBR t [ ( [ Page A18 ~ < 270°C «518°F) ~ SFC ~turates~ CAromatics~ ~ WAX .. C§ATURATE§) G~v DISTILLATION I ~ HOT N_HEPTANE SOLUBLES I COOL TO -100C/14Of & FILTER I ~ > 270°C (> 518°F) I ADD N_HEPT ANE HEAT TO 50oC/1220F & FILTER I ~ dOT N_HEPTA~E INSOLUBLES "Asphaltenes" ¡ De-Waxed + De-apshalted Oil (Maltene) COLUMN CHROMATOGRAPHY - + C RESINS :> ~ROMATICj) Figure A.16 - SARA Fractionation Protocol APPENDIX A SUMMARY OF ODBR CAPABILITIES PVT & SOLIDS DETECTION SYSTEM Page A19 Oilphase-DBR APPENDIX B DETERMINATION OF OIUBRINE INTERFACIAL TENSION r- APPENDIX B Determination of Oil/Brine Interfacial Tension Oilphase-DB R Page BO 07/10/2002 WED 15:52 FAX 7804501668 OILPHASE - DBR I4J 0011009 ~ðt~~- DETERMINATION OF OIUBRINE INTERFACIAL TENSION Prepared by PRI business unit of Alberta Research Council June 2002 Confidential APPENDIX B Determination of Oil/Brine Interfacial Tension Oilphase-DBR Page B 1 07/10/2002 WED 15:52 FAX 7804501668 OILPHASE - DBR ( ( ( ( (" ( ( [ ( [ r c [ l APPEND Determination of Oil/Brine Interfacial Tension DBR group5 IFI' PtojectNo.3700016 lwe 2002 TABLE OF CONTENT 1.0 EXECUTIVE SUMMARY --.....................-............................................,..." ,..._1 2.0 EXPERIMENTAL PROCEDURES .............................-. .. ... ....".....-....u... ... ... - - , ..1 2.1 OIL AND BRINE SAMPLES ."'-_.6.-"'-'''''.''--''.- . -_.--3 3.0 . . - -......-.....3 RESULTS.- __li- ---.---.-.----- 3.1 IFI' OF ÐEAD-O~ SYS1'EM ."""-''''''''''''''''''''''''''"''~''''I';''I.~'''''I'&''~'''''I~'"''II.''''',,",.....3 3.2 1FT OF LIVE OILlBRINE SYSTEM ......_.....3 4.0 ,- ,-'Om' ''O'-- - .- nn- - -5 REFERENCE ...- LIST OF TABLES TABLE 1: FLUID DENSITIES m._m. . -.n_. .... -- - -. .. n -. --.. --.-..,----.- .-..4 TABLE 2: DEAD OIIJBRINE INTERFACIAL TENSION AT 122 CT AND 200 PSIG .......................4 TABLE 3: LIVE OILlBRlNE INTERFACIAL ~SJ:OJ.'ll AT 254 r ANn 5175 ~.._..._.............4 UST OF FIGURES FIGURE 1: DROP SHAPE OF DEAD OIL IN BRINE AT 200 PSI AND 122 QF .............-....-,....-6 FIGURE 2: DROP SHAPE OF LIVE on. IN BRINE AT 5175 PSIA AND 2S4.5 CT .......-..._.......7 PRIlARC Page B2 141 002/009 -DBR 07/10/2002 WED 15:53 FAX 7804501668 OILPHASE - DBR DBR groups IFf Project No. 3700016 June 2002 1.0 Executive Summary Intedàcial tension (IFT) between a crude oil sample and produced brine had been determined using Axisymmetric Drop Shape Analysis (ADSA) technique. The IFrbetween stock tank oil and produced brine at 122 OP and 200 psig was determined to be 16 mN/m. The 1FT between the saturated oil and produced brine at 5175 psia and 254.5 "F was determined to be 25.9 mN/m 2.0 Experimental proçedures The experimental system consists of a high pressure high temperatlU'e cell, made up of Titanium and Hastelloy parts with glass windows on opposite sides. The cell is capable of openiting at pressures up to 70, MPag and temperatures up to 200 Cle. The glass windows allow the capture of droplbubble profile images by using a light source on one side and a camera system on the opposite side. Elevated pressures are achieved through the use of fluids handling system consisting of pistoned pressUf(>-vessels, high pressure pumps and a back-pressure regulator. Elevated temperatures are achieved by the use of a Blue M oven as a source of heat. The camera system is connected to an NTSC monitor and a personal computer equipped with an image capture board and the image analysis software including the Axisymmetric Drop Shape Analysis (ADSA) program to iteratively calculate the interfacial tension. The optical cell details are quite similar to the contact angle cell described elsewhere!. The pendant drop technique was used in this study which consists of oil drops hanging from a capillary tube within the surrounding brine solution. The bottom part of the optical table supporting the test cell and the camera system is loaded with sandbags to minimize vibrations and enhance clarity of the profiles of the drops and bubbles captured on the computer hard-drive. The cell housing also contains a live oil reservoir equipped with a piston driven by high pressure water to enable the maintenance of the fluids at reservoir temperatures and pressures at all times during the course of the experiments as well as to flow the oil in the fonn of droplets within the field of view of the camera which sends the drop profile images to be captured by the computer. PRIlARC APPENDIX B Determination of Oil/Brine Interfacial Tension Page B3 ~ 003/009 Oilphase-DBR 07/10/2002 WED 15:53 FAX 7804501668 OILPHASE - DBR DBR gro. 1FT Project No. 3700016 J~ 2002 Interfacial tension, being vecy sensitive to fluids contamination. imposes cleanliness as a basic requirement during experimentation. The titafiiurn and Hastelloy lines and valves were flushed with ]arge amounts of water to remove any excess brine or salt which may have accumulated within the system. A dilute solution of nitric acid and hydtochloric acid can be used when required. The lines werc then flushed with acetone to remove residual water. The lines were then flushed with methylene chloride (to remove trace hydrocarbons). and with acetone to remove any nm:uWrlng methylene chloride. A final flushed with high purity HPLC grade isopropyl alcohol was used to remove any remaining contë-mina$. The lines were then dried by purging with high grade nitrogen. The titanium parts of the cell and injection needles were cleaned using the same sequence of solvents. The quartz windows, the ruby calibration sphere was cleaned in a heated bath of suIphmic acid and ammonium persu1fatc for two hours. These components were subsequently rinsed with deionized water. ( Images are acquired using the digitization apparatus in the following manner. Drop images are displayed and centered on the NTSC monitor. The video camera, optical cell, and light 50UICC are arranged in it collinear fashion. When the light intclliiity is at the appropriate level, so that it is within the dynamic range of the video camera, the drop profile can be brought into focus. The image of the drop profile is then captured in a ftame buffer and its digital representation is then saved on the computer bard-drivc. After a set of images have been saved on the computer hard-drive, each image is individually recalled and analyzed. This is done by reading the desired image back into the video board's ftamc buffer. First a low pass digital filter is used to smooth out the jagged interface. Then a Laplacian low dimensional second derivative is applied to the filtered image to identify the drop edge. The image is now sèanned along the drop edge. This supplies the x-y co-ordinate data for a representation of the drop interface. The c0- ordinate data are converted into polar co-ordinates and then fitted using the method of cubic splines. Once the data has been appropriately fitted. the fitted function Ï5 then converted back illto Cartesian co-ordinates. It is this fitted function that is used. to obtain up to 50 or 60 points on the inteñaçe as input to the ADSA program for calculating the PRIlARC APPENDIX B Determination of Oil/Brine Interfacial Tension ( Page B4 141 0041009 2 Oilphase-DBR 07/10/2002 WED 15:54 FAX 7804501668 OILPBASE - DBR DBR group' 1FT Project No. 3700016 June 2002 interfacial tension using equation 1. Details of tho ADSA program and its use in lFI measurement can be obtained fi:om the reference of Cheng et al2 . ðP = Y (l/R) + l/Rz) where Y is the interfacial tension, (1) Rl and R2 are tho principal UIrlii of curv~ of the oil drop AI> is the pressure difference across the interface 2.1 Oil and Brine Samples The stock tank crude oil, saturated live oil and produced brine samples were supplied to us by D.B. Robinson Research I1d. The density of the stock tank crude oil and produced brine were detennined with an Anton Paar densitometer. Density of the live oil was provided to us by DBR Research limited. 3.0 Results 3.1 1FT of Dead-oll/brlne system The values of the interfacial tension between the produced brine solution and the stock tank cmde oil are presented in Table 2. The average value of the measurements is 16 mNIm. Tlris value is significantly smaller than the normal 1FT value of of between 3Q..40 mNlm for crude oil and water. An image of the oil drop captured during the te5t is p¡esented in Figure 1. 3.2 1FT of Uve Oillbrine system The interfacial tension between the produced brine solution and the live oil at 5175 psi and 254 F are presented. in Table 3. The average value of the measurements is 25.9 mNlm. An image of the oil drop captured during the measurement of the liveoillbrine system is presented in Figure 2. PRI/ARC APPEND.. . - Determination of Oil/Brine Interfacial Tension Page B5 141 005/009 - "I"" .___-DBR 07/10/2002 WED 15:54 FAX 7804501668 OILPBASE - DBR ( ( [ ( APPEND Determin Interfacial Tension DBR groups 1FT Table 1: Ftuid Densities s~ tank oil density at 200 psi and 122 ~ (gmtml) Produced brine density at 200 psi and 122°F (gmIm1) Uve oil density at 5175 psi and 254 Op' (gm/ml) - ProdÜced ~e density ~ 5175 psi and 2540p' (gm/ml) 0.814 1.009 0.52 0.97 Projec;tNo.3700016 June 2002 Drop # 1 2 3 4 ..~- 6 7 8 Average IFf Table 2: Dead OillBrlne IDteñãcial Tension at 122'" and 200 psig Calculated IFT mN/m 16.3 16.2 16.~ 15.8 15.8 15.7 IS.7 15.8 16.0 . . . Table 3: Live OßIBrine ~D~rfaeialTensiori åt 254 'F and 5175 psla DRQP# 1 2 3. , 4 5 6 7 8 A-verage IFf . - ... PRJlARC Page B6 26.7 26.2 25.7 25.6 25.6 25.8 25.8 26.0 25.9 141 006/009 4 -DBR 07/10/2002 WED 15:54 FAX 7804501668 OILPHASE - DBR APPEND Determin Interfacial Tension DBR groups IFf Project No. 3700016 June 2002 4.0 REFERENCE 1. A new technique for reservoir wettability characterization, D.N. Rao M.G. Girard, CanadianJoumal ofPetrolewn Technology. Jan. 1996 Vol. 3St NO.1 2. Cheu& P.. Li D., Bomvka, L., Rotenber& Y., and Neumæm. A.W., ((Automation of Axisymmetric Drop Shape Analysjs for Measurement of Interfåcial Tensions and Contact Angles", Colloids and Surfaces, 43, pp. 151-167, 1990. PRIlARC Page B7 ~ 007/009 5 -DBR 07/10/2002 WED 15:54 FAX 7804501668 OILPBASE - DBR ~ 008/009 DBR groups 1FT Project No- 3700016 J\DIe 201n ~r." ,. . "" .....t. ." "'""'" .. ., "'",'" . '", ........- ."..,..." -....... '1- . . ; : . t '\ ( ( (' ( ( ( ( ( ( r ( ( ( ( ( ( ( ( ( , . , ~ Eo" ,". ; . \, ,,' ",', " . to. . ¡ .' . . ". :., ; . . ' I . """. . . : ", ; I ":.. I " . . .,. , ~, . .':, .. :-,. '. J"': Figure 1; Drop shape of dead oil in brine at 200 pei and 122 of PRIlARC 6 ( ( ( APPE~ Determination of Oil/Brine Interfacial Tension , ~e-DBR Page B8 07/10/2002 WED 15:55 FAX 7804501668 OILPBASE - DBR DBR groups IFf Project No. 3700016 June 2002 Figure 2: Drop Shape of Live Oil in brine at 5175 psia and 254.5 of PRI!ARC APPENDIX B Determination of Oil/Brine Interfacial Tension Page B9 ~ 009/009 7 Oilphase-DBR
