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208-036
Image Project Well History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. ~~~ - ~~~ Well History File Identifier Organizing (done) ^ Two-sided III II IIII II III II III ^ Rescan Needed III IIIIII II II III III RE CAN DIGITAL DATA OVERSIZED (Scannable) Color Items: ^ Diskettes, No. ^ Maps: ^ Greyscale Items: ^ Other, No/Type: ^ Other Items Scannable by a Large Scanner ^ Poor Quality Originals: OVERSIZED (Non-Scannable) ^ Other: ^ Logs of various kinds: NOTES: ^ Other:: BY: Maria Date: ,~~ ' ~ Q ~ /s/ Project Proofing I II I IfI II VI II I I I II BY: Maria Date: ~~ ~ /s/ Scanning Preparation __~ x 30 = + =TOTAL PAGES~t~ BY: Maria Dater r ® ~ (Count does not include cover sheet) /s/ ~-- ~ r Production Scanning II I II ~I II I I III I I III Stage 1 Page Count from Scanned File: ~_ (Count does include cov sheet) Page Count Matches Number in Scanning Pre aration: YES NO BY: Maria Date: ~ / ~ ~ ~ /s/ '~~ Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: /s/ Scanning is complete at this point unless rescanning is required. II I II II II I II II I I III ReScanned BY: Maria Date: /s/ Comments about this file: Quality Checked III IIIIIIIIIII~I III 10!6/2005 Well History File Cover Page.doc Page 1 of 1 Maunder, Thomas E (DOA) From: Eller, J Gary [J.Gary.Eller@conocophillips.com] Sent: Thursday, May 01, 2008 9:09 AM To: Maunder, Thomas E (DOA) Subject: RE: 30-02A (207-158) - 30-02AL(one half) Tom - It is long read, isn't it? And that spaghetti bowl of laterals sure gets a little tough to keep up with. That was supposed to be lateral AL3 (permit #208-036) Basically, we were going to break the AL1 lateral into two shorter segments. But when we couldn' get o e billet at 11,170' MD, we bagged that plan and cancelled the AL3 permit, and ultimately drilled the AL1 lateral more or less as we originally intended. Thanks, and please caA if you have any questions. -Gary -~ v ~-- O a--/~ L- ~ From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Wednesday, April 30, 2008 5:10 PM To: Eller, J Gary Subject: 30-02A (207-158) - 30-02AL(one half? Gary, I have just reviewed the L-O-N-G report for 30-02A, et al. After drilling to TD on the initial penetration, the liner was run in 2 sections and it appears that it was attempted to kickoff at about 11170'. Problems were encountered and another section of liner was run and the AL1 penetration was kicked off at about 10329'. According to the spreadsheet I did when examining the permits, this was the planned KO depth for AL1. What was attempted at 11170'? That depth does not correspond to any KO depths I have for the various laterals. Thanks in advance. Tom Maunder, PE AOGCC ao x-03 c~ 5/1/2008 1 ~a-~ • BP AMERICA, Page 15 of 36 Operations :Summary Report Legal Well Name: 30-02 Common Well Name: 30-02 Spud Date: 10/2/1988 Event Name: REENTER+COMPLETE Start: 2/1/2008 End: 3/31/2008 Contractor Name: NORDIC CALISTA Rig Release: 3/31/2008 Rig Name: NORDIC 2 Rig Number: __ - Date From - To Hours Task Code NPT Phase Description ofi Operations -.--- 3/11/2008 14:00 - 15:40 1.67 CASE N DFAL LNR1 to window. Up wt 21.5K, do 9.5K. 15:40 - 16:45 1.08 CASE N bFAL LNRi RIH to 10510'. Tie-in to GR marker at 9550'. +1' SLB correction. RIH w! liner. ~ 11000', do wt SK ~ 11500', do wt 7.8K ~ 12132', do wt 7k. PUH, incr rate to 1.58/4550, zero DHWOB, up wt 24K. Surface weight indicates we are dragging liner. RIH Tag TD at i 2132' CTD. PN at 21.5K, 2K DHWOB, surface weight is pulling smooth. Indicates liner has released. 16:45 - 19:30 2.75 CASE N DFAL LNRi POOH following pressure schedule. Bring rate down to 0.5/2200. PUH to above window. Up wt 18K, do wt 7.5K. POOH following pressure schedule. PJSM while POH regarding pressure undeployment. 19:30 - 22:30 3.00 CASE N DFAL LNR1 Start pressure undeployment procedure. Appears checks are not holding, regroup & discuss. Continue to pressure undeploy BHA. 22:30 -00:00 1.50 RIGU P PROD2 Liner is not attached to tool string. LD BHI tools on catwalk, blow down same w/ water & air. RU new BHI tool string. Simultaneously conduct slack management. C/O injector stripping rubber. BHf upper check valves appear ok, lower dart style are gummed up w/ bits of Alpine beads. 3/12/2008 00:00 - 00:15 0.25 RIGU P PROD2 Continue to pump slack into coil. Tum on centrifuge 'B' & use gun Line to remove Alpine beads from pits. 00:15 - 01:00 0.75 RIGU P PROD2 PJSM regarding cutting coil & reherding coil. Cut 142ft of coil. Test wire -good test. 01:00 - 01:40 0.67 RIGU P PROD2 Install new Kendall CTC. Pull test CTC to 35k -good. 01:40 - 03:15 1.58 RIGU P PROD2 Rehead BHI tools. Test 8H1 head -bad. C/O flow sub & re-test - good. 03:15 - 03:25 0.17 RIGU P PROD2 P.T. CTC &BHI UOC to 4000 psi -good. 03:25 - 04:20 0.92 RIGU P PROD2 Stab injector onto well & P.T. injector packoffs per AOGCC regs. Test BHI check va ves w 1500psi i press -goal. PJSM while testing packoffs regarding pressure deploying BHA. 04:20 - 06:00 1.67 STWHIP P PROD2 Begin pressure deploying BHA. M/U Aluminum billet kick-off BHA #13. 1.5 deg motor and HCC 2.73" STR bit. 06:00 - 06:30 0.50 STWHIP P PROD2 Crew change. PJSM for finishing pressure deployment procedure. 06:30 - 07:50 1.33 STWHIP P PROD2 Continue pressure deploying kick-off BHA. 07:50 - 09:35 1.75 STWHIP P PROD2 RIH w/ WO BHA #13 following pressure schedule. 09:35 - 09:50 0.25 STWHIP P PROD2 Log tie-into GR. +11' correction. 09:50 - 10:00 0.17 STWHIP P PROD2 R1H to 9950' 10:00 - 12:30 2.50 STWHIP N RREP PROD2 Having problems w/mud pump #1. Troubleshoot pump. Replace valves and seats in MP#1. Clean out suction. 13:40 - 14:15 0.58 STWHIP P PROD2 P/U. Orient 50 deg ROHS. Incr rate to 1.511.5 bpm at 3950 psi. RIH, tag top of billet. Time drill off billet 0.1' every 5 min for 0.3'. Lost communicatron w B toots. 1 ~ 14:15 -16:30 2.25 STWHIP N DFAL PROD2 POH to troubleshoot BHI tools followirig pressure schedule. ~ 1~- - 16:30 - 17:00 0.50 STWHIP N DFAL PROD2 PJSM for pressure undeploying BHA #i3 17:00 - 17:50 0.83 STWHIP N DFAL PROD2 Pressure undeploy AI billet WO BHA #13. After P/U injector, close double ball valves and test BHt UOC and LQC. Appears ~`Z(~ to be in the tool string. Continue to pressure undeploy. ~~~ ~~~`~ 5 rnneea: aiirzuun 7C:4U:47 YM • BP AMERICA- `.Page 1 s of 36 Operations Summary :Report Legal Well Name: 30-02 Common We11 Name: 30-02 Spud Date: 10/2/i 988 Event Name: REENTER+COMPLETE Start: 2/112008 End: 3!31/2008 Contractor Name: NORDIC CALISTA Rig Release: 3131!2008 Rig Name: NORDIC 2 Rig Number: Date From - To Hours Task Code NPT ' Phase Descl•iption of Operations 3/12!2008 17:50 - 18:25 0.58 STWHIP N DFAL PROD2 Stop for night shift. PJSM regarding pressure undeploying. 18;25 - 19:30 1.08 STWHIP N DFAL PROD2 Continue to pressure undeploy BHA. 19:30 - 21:00 1.50 STWHIP N DFAL PROD2 LD BHI tools on catwalk. Purge & blow down BHA on catwalk. Remove power & comms & test tools -still more tool problems. Continue to RU new tool string on catwalk, configure & test same. LD motor on RF & scribe same. 21:00 - 21:20 0.33 STWHIP N DFAL PROD2 PJSM regarding pressure deployment. 21:20 - 23:40 2.33 STWHIP N DFAL PROD2 Pressure deploy new BHI tool string into well. 23:40 - 00:00 0.33 STWHIP N DFAL PROD2 RIH w/ K/O BHA #14 following pressure schedule. 3/13/2008 00:00 - 01:30 1.50 STWHIP N DFAL PROD2 Continue to RIH wl BHA # 14 following pressure schedule. Inspect previous BHI tool string & found that the EDC was the culprft for the failure. 01:30 - 01:40 0.17 STWHIP N DFAL PROD2 Log down for tie-in ~ 9565' (+5ft corr. 01:40 - 02:30 0.83 STWHIP N DFAL PROD2 RlH. Annular pressure = 4400psi &WHP = 700psi, w/out pumps while going through cement ramp/window area. 02:30 - 02:45 0.25 STWHIP P PROD2 D to aluminum billet ~ 11169'. PU 8~ get drilling parameters while slowly creeping in hole. 02:45 - 03:40 0.92 STWHIP P PROD2 Begin time drilling from 11168.4' ~ 0.1' every 5min for 1 ft w/ TF 50R HS. Op = 1.50 / 1.45 bpm Pt = 3800psi fs w/ 50 psi motor work. DHWOB = 0.4-1.4k# VP =198 bbl ECD =13.15 WHP = 260 03:40 - 04:20 0.67 STWHIP P PROD2 Time drill from 11169.4' ~ 0.1' every 3min for 1 ft w! TF 50R HS. Op = 1.50 / 1.45 bpm Pt = 3800psi fs w/ 100 psi motor work. DHWOB = 0.75-1.4k# VP =197 bbl ECD = 13.23 WHP = 230 04:20 - 04:35 0.25 STWHIP P PROD2 Stalled while at 11170.4'. Aluminum coming over shaker now. Time drill from 11169.2' ~ 0.1' every 3min for 1 ft w/ TF 50R HS. Op = 1.50 ! 1.45 bpm Pt = 3800psi fs w/ 100 psi motor work. DHWOB = 0.75-2.Ok# VP = 196 bbl ECD = 13.23 WHP =230 04:35 - 05:35 1.00 STWHIP P PROD2 Stalled while at 11169.3'. Time drill from 11169.2' ~ 0.1' every 3min for 1 ft w/ TF 50R HS. Op = 1.50 / f .45 bpm Pt = 3800psi fs w/ 50 psi motor work. DHWOB = 0.75-2.Ok# VP=196bb1 ECD=13.12 WHP=230 05:35 - 09:00 3.42 STWHIP N STUC PROD2 Kee s statlin Shallower a snanower on each nuem < < bottom. Last stall was at 11154'. PU & stop pumping, close choke. RIH & dry tag at 11156'. PU -clean. RIH & dry tag at 11171'. PU & pulling heavy, stop at 11126'. Try to move pipe up $ down. Can circulate no problem & orientate w/ no problem. Work pipe. Seem to be mechanically stuck between DPS and HOT. Discuss w/ town on plan forward. 09:00 - 10:50 1.83 STWHIP N STUC PROD2 Pump 40 bbl low vis sweep followed by 20 bbl high vis sweep. Work pipe, try different orientations and pump rates. When orienting, appears that BHA above the HOT output shaft is rotating, but cannot get TF to change. 10:50 - 11:00 0.17 STWHIP N STUC PROD2 Discuss w/ town. Decide to use EDC to disconnect. Spot high vis pill. Send command to EDC and disconnect from BHA. 11:00 - 13:15 2.25 STWHIP N STUC PROD2 POOH to surface following pressure schedule. PJSM for a.;~~• an1t9009 12.40:41 PM • • BP AMERICA :Page 17 of 36 Operations Summary Report Legal Well Name: 30-02 Common Well Name: 30-02 Spud Date: 10/211988 Event Name: REENTER+COMPLETE Start: 211 /2008 End: 3/31/2008 (Contractor Name: NORDIC CAUSTA Rig Release: 3/31/2008 ,Rig Name: NORDIC 2 Rig Number: Date. From - To Hours Task Code NFT Phase Description of Operations. 3/13/2008 11:00 - 13:15 2.25 STWHIP N STUC PROD2 pressure undeploy_ 13:15 - 14:00 0.75 STWHIP N STUC PROD2 Pressure undeploy BHA using mod'rfied pressure undeploy 14:00 - 15:00 I 1.001 FISH ~ N ~ STUC I PROD2 15:00 -22:00 7.00 `(( BOPSU P 1 PROD2 22:00 - 22:50 ~ 0.83 f FISH ~ N ~ STUC ~ PROD2 22:50 - 00:00 ~ 1.17 ~ FISH ~ N ~ STUC ~ PROD2 412008 ~ 00:00 - 01:00 ~ 1.00 ~ FISH , N ~ STUC ! PROD2 01:00 - 03:50 ~ 2.83 ~ FISH ~ N ~ STUC ~ PROD2 03:50 - 04:20 ~ 0.50 ~ FISH ~ N ~ STUC ~ PROD2 - 06:15 ~ 0.42 (FISH (N ~ STUC ~ PROD2 06:15 - 08:30 2.25 FISH N STUC PROD2 08:30 - 09:15 0.75 FISH N STUC PROD2 09:15 - 09:40 0.42 FISH N STUC PROD2 09:40 - 11:00 1.33 FISH N STUC PROD2 11:00 - 12:15 1.25 FISH N STUC PROD2 12:15 - 12:45 0.50 F1SH N STUC PROD2 12:45 - 15:15 2.50 FISH N DPRB PROD2 15:15 - 15:30 0.25 FISH N DPRB PROD2 15:30 - 16:45 1.25 FISH N DPRB PROD2 16:45 - 18:35 1.83 FISH N DPRB PROD2 18:35 - 18:45 0.17 FISH N DPRB PROD2 18:45 - 19:10 0.42 FISH N DPRB PROD2 procedure. BHA is 15.9' long, short enough to tag up and close swab valve while using mud pump 2 to circulate through managed pressure loop. Prep for BOP test. P/U BTT fishing tools to rig floor thru beaver slide. Test BOPE. 250 psi low, 4500 psi high. Test witness waived by AOGCC inspec#or Chuck Scheve. Pop off well. Close TRSSSV w/ 1200psi below & flow check. PJSM regarding pumping slack out of reel. Simultaneously place injector over bung hole & pump slack out of reel, recovered 280ft. MU BOT CTC, pull test same to 35k -good. PJSM regarding handling BHA. Well stooped flowing ~ 23:50. MU fishing BHA. Continue to MU fishing BHA. MU fishing BHA to coil. Stab onto well. Set counters. RIH w/ fishing BHA, circ 0.35bpm/2000psi. Pressure up & open TRSSSV, WHP = 1179psi. Stop pumping ~ 9960'. WT ck (~ 9960' = 24k. RIW = 8k. Clean through window. WT ck ~ 11000' = 24.5k. RIW = 6.3k. Clean hole to TD. Latch into fish ®11097'. Jar down 2 times & have movement. Jar up 6 times. Popped free, however we are dragging something up hole. POH. Putts fine for 20'-30' then 7k to 20k overpulls. Stop PUH 10365'. Discuss with town. Work fish down hole. 2 jar licks down & moved 5ft. 1 jar lick & moves down hole smooth. RIH to 10400' -clean. PUH to 10380' -pulled heavy. RIH to 10395' & set down. 1 jar lick down. RIH to 10425' -clean. PUH to 10350' -clean. RIH to .10478' & set down. Continue to work up & down the hole from 10325ft to 10500ft. Clean without overpulls or set downs for 3 ~ attempts. Decide to PUH through window. PUH through the window w/ no overpulls. POH keeping pressure on well. POOH to 1500'. Close TRSSSV. Flow check. POOH to surface. PJSM for LlD fishing BHA. L!D fishing BHA #15. 1.5' of aline hanging out of end of CTC. Recovered 100°~ of fish. No clear indication of any damage or scarring on fish from debris. R/U to perform a-line slack management. Reverse circulate at 2.8 bpm at 3600 psi. Heard e-line moving in coil. Cut 308' of coil to expose a-line. M/U SLB Kendall CTC and pull test to 35K. M!U BHI UOG and rehead a-line. Meg a-line, good test. PT CTC to 4000 psi. PJSM for M/U cleanout BHA C/O injector packoffs. M/U open hole cleanout BHA #16. Test coiITRAK tools. Increase W HP to 1300 psi. Open TRSSSV. RIH following pressure schedule. Log down for tie-in from 9560ft (+9ft corr. RIH. Linhtly tan up at 10065ft. PU clean. RIH. LightEy tag up at a....~eel. A/11MMf! 19•dMdt P-A • ! - BP AMERLCA Page 18 of 36` Operations Summary Report Legal Well Name: 30-02 Common Well Name: 30-02 Spud Date: 10/2/1988 Event Name: REENTER+COMPLETE Start: 2/1!2008 End: 3/31/2008 Contractor Name: NORDIC CALISTA Rig Release: 3!31/2008 Rig Name: NORDICI 2 Rig Number: Date From - To ~ Hotars k Task ~ Code NPT ~ Phase I Description of Operations 311412008 18:45 -19:10 0,42 FISH N DPRB PROD2 19:10 - 19:30 0,33 FISH N DPRB PROD2 19:30 - 19:50 0.33 FISH N DPRB PROD2 19:50 -20:15 0.42 FISH N DPRB PROD2 20:15 - 23:15 3.00 FISH N DPRB PROD2 23:15 -00:00 0.75 FISH N DPRB PROD2 3/15/2008 00:00 - 01:45 1.75 FISH N DPRB PROD2 01:45 - 03:00 1.25 FISH N DPRB PROD2 03:00 - 05:20 2.33 FISH N DPRB PROD2 6 00 - 06:45 ~ 0.75 i FISH I N 06:45 - 07:50 I 1.081 FISH I N 07:50 - 09:30 ~ 1.67 ~ FISH ~ N 09:30 - 09:45 0.25 FISH N 09:45 - 10:20 0.58 FISH N 10:20 - 10:35 I 0.251 FISH I N 10:35 - 11:00 0.42 FISH N 11:00 - 11:20 0.33 FISH N 11:20 - 12:20 1.00 FISH N 12:20 - 13:50 1.50 FISH N 13:50 - 17:15 3.42 FISH N DPRB PROD2 DPRB PROD2 DPRB IPROD2 DPRB PROD2 DPRB PROD2 DPRB PROD2 DPRB iPROD2 DPRB PROD2 DPRB PROD2 DPRB PROD2 DPRB IPROD2 10064ft. PU clean. PUH & re-Iog for depth confrimation. Log down for tie-in from 9545ft {+1 ft Corr}. RIH. Lightly tag up at 10064ft. While setting 1 k, try to orientate past problem area, w/out pumping. Tums fine 45 deg L & R of HS wfth no increase in amps to tool. Orientate back to drilled TF & PU -clean. PUH white discuss w/town. Slightly gassy returns. Stop POH ~ 9200ft. Slowly RIH & increase rate to 1.5bpm. CBU while POH. Inform town concerning current issue. PJSM regarding pressure undeploying of BHA. Tag up. Begin pressure undeploying BHA. Continue to pressure undeploy BHA. LD BHI tools on catwalk & C/O o-ring en LOC. Inspect mill, 2.74 go & 2.73 no-go (no wear/marks on mill/motor/toots). Dial up motor to 2.4 AKO & turn wear pad to inside of bend (for ease of pressure deployment}. PU injector & stab onto well. Test injector paekaffs per AOGCC r s 250/4500 -PASS. Pop off well & place in bung hole. Pressure deploy BHA. Having great difficulties getting larger bend motor through tree/hanger _ 40 min to get BHI tools into position. Continue with deployment procedure. Inspect CTC. CTG MT connection is loose. Remove flow sub & UQC & anchor. Re-lock fife & torque up CTC MT connection. Install anchor, flow sub & UOC. Cannot get anchor back into UOC due to slack. Rehead BHI UOC. Crew Change. SAFETY MEETING. Review hazards, mitigation, and procedures for pressure deployment. Finish reheading BHt UOC. Finish pressure deploy window dressing BHA #i7. CoiITRAK tools, 2.4 deg motor, 2.74° D331 mitt w/cut right backreaming cutters. RIH w/ lateral cleanout BHA following pressure schedule. Tie-in to GR at 9565'. -3' correction. RtH to top of cement ramp w/ no pumps and holding 1200 psi WHP. Orient LS. RIH to 10050' and orient HS. RIH, tag at 10063.5', 3.5K WOB. P/U, RIH slow, tag at 10062.9', 1 K woe. Kick on pumps, WOB dropped to 0.4K. S/D pumps. RIH to see ff we can pass thru window. RIH thru window clean to 10073'. Discuss w/ town. PUH clean thru window to 9545'. Tie-in in GR at 9545'. +2' correction. RIH to window w/ no pumps. Tag at 10063.6', 1.2K WOB. PIU to 10050', RIH, tag at 10063.1', 0.6K WOB. P/U and try to get thru multiple times with kicking on pumps to 0.5 bpm. BHA is fuming around bit. Finally able to work thru window. Discuss w/ town. Cleanout openhols at 1.57 bpm, 3900 psi, 12-15 fpm. RIH DPRB I PROD2 ~ POOH, swap well to new mud. Slight overpulls from 10500'-10480'. Ream and backream hole thru this section. Hole cleaned up. PUH clean thru window. POOH following Primed: 4/11/2008 12:40:41 PM • • BP AMERICA - Page 19 of 36 Operations Summary Report LegaLWell Name: 30-02 Common Well Name: 30-02 Spud Date: 10/2/1988 Event Name: REENTER+COMPLETE Start: 2/1/2008 End: 3/31/2408 Contractor Name: NORDIC CALiSTA Rig Release: 3!31/2408 Rig Name: NORDIC 2 Rig Number: Date I From - To ~ Hours ~ Task ~ Code ~ NPT' Phase I Description of Operati©ns 3!15/2008 13:50 - 17:15 3.42 FISH N DPRB PROD2 17:15 - 17:45 0.50 FISH N DPRB PROD2 17:45 - 18:00 0.25 FISH N DPRB PROD2 18:00 - 18:30 0.50 FISH N DPRB PROD2 18:30 - 19:40 ~ 1.17 ~ FISH (N ~ DPRB I PR002 20:00 - 23:05 I 3.251 CASE I N ~ DPRB I LNR1 1 3/1 6120 0 8 23:15 - 00:00 0.75 CASE N DPRB LNR1 00:00 - 01:00 1.00 CASE N DPRB LNR1 01:00 - 02:05 1.08 CASE N DPRB LNR1 pressure schedule. Stop at 1500' and close TRSSSV. Flow Check. POH to surface. C/O w/ day crew. PJSM regarding LD BHA. Flow check well while conducting PJSM. Pop off well & place injector over bung hole. Purge/blow down BHI tools. LD tools on catwalk & reconfigure same for running liner, C/O o-rings on LQC. No marks on milUmotor 2.73" no-go/2.74" go. MU safety jt for running liner. C/O elevators. PJSM regarding MU liner. Start MU liner consisting of unique guide shoe+26jts slotted liner+Al billet w/GS profile (non-splined), torqued w/little jerk tongs. PU BHi's coif track tools+knuckle jt+hyd GS & MU to liner. PU injector & MU to tools (had trouble MU UQC due to angle). Stab onto well. Power up & tes# tools. Set counters. Simultaneously C/O MPD hose & install a tee (used to blow down chokes). P.T. 250/4500 -pass. RIH w/ liner following pressure schedule. Continue to RIH w/liner following pressure schedule. Wt ck ~ 10000ft 23.5k, RIW = 7.1 k. Continue to RIH wl liner. Smooth through ramp/arindow area. Log down for tie-in (-3.6ft). RIW = 5.4k ~ 11170ft. Tag up ~ 11170ft. Up Wt = 25k. RIH & tai up ~ 11170ft & set 6k down. Start pumping ~ 1.5bpm / 4i00psi & release from liner, 21.7k up Wt (w/out pumps). TOL 02:05 - 04:20 2.25 CASE N DPRB LNR1 POH following pressure schedule while pumping 0.4bpM2100psi. PJSM while POH regarding pressure undeploying BHA. 04:20 - 06:00 1.67 CASE N DPRB LNRi Pressure undeploy BHA. 06:00 - 06:30 0.50 CASE N DPRB LNRt Crew Change. PJSM to finish pressure undeploying liner running BHA. 06:30 - 07:00 0.50 CASE N DPRB LNR1 Continue pressure undeploying liner running BHA. 07:00 - 08:30 1.50 STWHIP N DPRB PROD2 M/U BHI Toolstring on catwalk. Test tools. 08:30 - 08:40 0.17 STWHIP N DPRB PROD2 PJSM for pressure deploying WO BHA. 08:40 - 11:45 3.08 STWHIP N DPRB PROD2 Pressure deploy Aluminum Billet WO BHA #19. Rehead slickline rope socket. Cut 4' of slickline. Slickline was slightly kinked right above rope socket. 11:45 - 13:30 1.75 STWHIP N DPRB PROD2 RIH following pressure schedule 13:30 - 13:45 0.25 STWHIP N DPRB PROD2 Tie-in to GR at 9565'. +4' correction. 13:45 - 15:00 1.25 STWHIP N DPRB PROD2 RiH to window. Tag window 3x at 10063.8' going 3 fpm. P/U and run thru window at 8 fpm, 2.5K WOB. RIH to bottom. 15:00 - 15:10 0.17 STWHIP P PROD2 Orient 30 ROHS. Dry tag aluminum billet ~ 10329'. PU & get drilling parameters while slowly creeping in hole. Up wt 25K. 15:10 - 16:15 1.08 STWHIP P PROD2 Tag billet at 10328.5'. 3850 psi FS. Time drill off billet, 30 ROHS, 1.5 bpm, 4000 psi, 1.5K WOB. lime drill at 1 fph. Getting aluminum in returns. Drilled to 10329.5' 16:15 - 16:50 0.58 STWHIP P PROD2 Time drill off billet, 0.1' every 3 min. i.5 bpm, 4000 psi, 1.2K WOe. Drilled to 10330.5' 16:50 - 17:10 0.33 STWHIP P PROD2 Time drill off billet, 0.1' every 2 min. 1.5 bpm, 3950 psi, 0.4K WOB. Drilled to 10331.5' Printed; 4/11!2008 12:40:41 PM • • BP AMERICA Page 20 of 36 4peratians Summary Report Legal Well Name: 30-02 Common Well Name: 30-02 Spud Date: 10/2/1988 Event Name: REENTER+COMPLETE Start: 2/1/2008 End: 3/31/2008 Contractor Name: NORDIC CALISTA Rig Release: 3/31/2008 Rig Name: NORDIC 2 Rig Number: Date: ~ From - To ~ Hours ~ Task , Code I NPT ~ Phase ( Description of Operations (3/16/2008 117:10 - 18:00 18:00 - 19:30 19:30 - 20:45 0.83 STWHIP P PROD2 1.50 STWHIP P PROD2 1.251 STWHiPI P 20:45 - 23:20 2.58 STWHIP P 23:20 - 00:00 0.67 STWHIP P 3/17/2008 1010:100 - 02:00 I 0.831 DRILL IP~ P PROD2 PROD2 PROD2 PROD2 PROD2 02:00 - 02:15 0.25 DRILL P PROD2 02:15 - 04:30 2.25 DRILL P PROD2 04:30 - 06:30 2.00 DRILL P PROD2 06:30 - 06:45 0.25 DRILL P PROD2 06:45 - 07:20 0.58 DRILL P PROD2 07:20 - 09:15 I 1.921 DRILL 1 P ( I PROD2 09:15 - 10:30 I 1.251 DRILL I P I I PROD2 Time driN off billet, 10-15 fph. 1.5 bpm, 3925 psi, 0.8K WOB. Stacking wt, P/U several times and RIH to bottom. Drilled to 10336.0' Continue drilling at 10336.0'. Time drill from 10336.0' ~ 5'/hr w/ TF 30R HS. Op = 1.551 1.55 bpm Pt = 4000psi fs w/ 100 psi motor work. DHWOB = 0.75-1.5k# VP = 55 bbl ECD = 13.1 WHP =300 DHT= 136 ST = 87 Had to PU start over due to stacking & had numerous 2k overpulls at 10336ft. DriN to 10350'. NBI shows that we are KO'd but shows a larger than expected jump in inclination. Ream 45 deg L&R of dri!!ed TF to open up sidetrack until section is clean. Op = 1.55 / 1.55 bpm Pt = 4000psi fs w/ 25 psi motor work. DHWOB = 025-0.5k# 'VP=53bb1 ECD=13.1 WHP=300 Repeat 6 times. Smooth RIH & OH. PU through window to 10040'. RIH ~ i5ft/min to 10070'. No set downs in the window. POH following pressure schedule. Tag & trap 1200psi on well. Blow down chokes. Begin pressure undeploying BHA. C/O high pressure filter on the hardline in the reel house -filter was eroded & cracked, replace same. Circulate coil volume to purge reel w/ clean mud. Turn on gun lines & return mud across shaker to remove aluminum/debris from piss -fair quantity of aluminumldebris removed from active pits. Continue to pressure undeploy BHA. LD BHI coi1TRAK tools on catwalk & purge/blow down same ~ reconfigure for resistivity. Bit was 2.73"go, partially plugged w/ aluminum from pumping ft around from the pits. MU new 2-3/8" Xtreme mud motor w/ 0.9 AKO setting w/new Hughes BC bit. C/O o-rings on LOC & clean out aluminum debris from LQC. Simultaneously, turn on guns lines from active pits returning across shaker again to remove solids from pits, recovered more aluminum/debris. PJSM regarding pressure deploying BHA. Begin pressure deploying lateral BHA. RIH w! lateral BHA following pressure schedule. Tie-in to GR, +16' correction. RIH, slight weight bobble when passing thru window, but went thru w/ no problems. RIH to bottom. Ta bottom at 10349.5'. Drill ALi lateral at 1.55!1.55 bpm, 4100 psi, 60 fph , 1.3k W B, 98 deg inci, 15L TF, 13.5 EGD. Holding 300 psi WHP, BHP at 4590 psi. Drilled to 10427' Drill ALi lateral at 1.6/1.6 bpm, 4300 psi, 45-80 fph ROP, 0.6k WOe, 95 deg inG, 90L TF, 13.6 ECD, 300 psi WHP, BHP at 4630 psi. 10:30 -10:50 I 0.33 ~ DRILL ~ P I I PROD2 ~ W iper to window. 10:50 - 11:30 0.67 DRILL N DPRB PROD2 RIH, tag 3x at 10140'. Stall everytime we tag. S!D pumps, RIH dry and tag at 10140', stack wt and cant get thru. P/U, incr Printed: 4/11/2006 12:40:47 PM Maunder, Thomas E (DOA) • Page 1 of 1 From: Maunder, Thomas E (DOA) Sent: Friday, April 18, 2008 2:06 PM To: Davies, Stephen F {DOA) Subject: FW: XL Permit #208-036 Steve, Do we need something more formal than this? Tom From: Hubble, Terrie L [mailto:Terrie.Hubbie@bp.com] Sent: Tuesday, April Oi, 200$ 1:06 PM To: Maunder, Thomas E (DOA) Subject: XL Permit #208-036 Hi Tom, ~~'~( We have finished drilling this multilateral well at Kuparuk for ConocoPhiiiips. One of the legs was not drilled. Per Gary Eller (Drilling Engineer, ConocoPhillips), we need to cancel the Permit to Drill for that leg. Permit #: 208-036 API#: 50-029-21837-63-00 Well Name: 30-02AL3 Thanks! ~~ Terrie ~~ ~_~. ~ ~~~ ' `~ ~ ~ 4/28/2008 • • Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Tuesday, March 18, 2008 1:47 PM To: 'Eller, J Gary' Cc: Perfetta, Patrick J; Nordic 2 Company Man; Staudinger, Garret; Michaelson, Bill(Baker Hughes Inteq); Venhaus, Dan E; Hubble, Terrie L; jon.mapes1@inteq.com Subject: RE: Lateral Naming in Weli 30-02 Galy, I confirm our disc:ussinn end you have captured it correctly. Good loci: wifih the r~:rnaining operations. I wiil piece a copy of this n~e~arJe in the -02A (2fl7-1ai3), -02AL1 (2Q7-159 and -02AL3 208-fl36 flex. You are correct that #:he -02AL3 permit shoo#rJ be cancel#ed since it wi#! ngt be ~~~ e . Gall or message with any questions. Tam Mal.lnder, pE At~GGG From: Eller, J Gary [mailto:].Gary.Eller@conocophillips.com] Sent: Tuesday, March 18, 2008 1:21 PM To: Maunder, Thomas E (DOA) Cc: Perfetta, Patrick J; Nordic 2 Company Man; Staudinger, Garret; Michaelson, Bill(Baker Hughes Inteq); Venhaus, Dan E; Hubble, Terrie L; jon.mapesi@inteq.com Subject: Lateral Naming in Welt 30-02 Tom - As per our phone conversation yesterday afternoon, we unintentionally sidetracked from well 30-02A while drilling the AL1 lateral. That lateral had been drilled to 10,500' MD, but we accidentally sidetracked at 10,140' MD during a wiper trip. We were unable to re-enter the original borehole last night in order to run slotted liner. We have instead continued drilling ahead from the sidetrack point that we were given at 10,140' MD. I propose that the unlined lateral from 10,330' MD to 10,500' MD off of the `A' sidetrack be named the AL1 PB1 lateral. It crosses the AZ shale shortly after kickoff and is not likely to remain productive without a slotted liner in place. The lateral that we are currently drilling will be the AL1 lateral (PTD #207-159) with a kickoff point of 10,140' from the `A' sidetrack. The `A' sidetrack (PTD #207-158) that was drilled from 10,060' MD to 13,120' MD is lined with slotted liner from TD up to 10,330' MD. It is unlined (i.e. barefoot) from 10,330' to 10,140' MD, but since this is in clean sandstone it is our hope that this sidetrack will remain viable for production. We will be unable to drill the AL3 lateral (PTD # 208-036) that was intended to kickoff at 11,170' MD, and we will cancel that PTD in the near future. Please let me know if you need any other info at this time. Of course, our completion notice will contain a wellbore diagram to help keep track of these many laterals in 30-02, but in the meantime I will be glad to answer any questions that you might have. 7. Gary Eller Wells Engineer ConocoPhillips -Alaska work: 907-263-4172 cell: 907-529-1979 fax: 907-265-1535 3/18/2008 Page 1 of 2 Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Wednesday, March 12, 2008 5:10 PM To: 'Eller, J Gary' Subject: RE: Oral Approval of 30-OZAL3 PTD Gary, I have confirmed with Commissioner Norman, that continuing operations is acceptable according to 20 AAC 25.005 (a). Best regards, Tom Maunder, PE AOGCC m: Eller, J Gary [mailto:J.Gary.Eller@conocophillips.com) '~ Sen • Wednesday, March 12, 2008 2:41 PM ; To: Ma der, Thomas E (DOA) f Subject: :Oral Approval of 30-02AL3 PTD ~l Tom -Just mo is ago we were preparing to mill off of the aluminum billet at 11 V1~0' MD in the 30-02A sidetrack, but they d a downhole communications failure. Plan forward is to repair that tool string, mill off of the billet, perform a BOP st, and begin drilling the AL3 lateral sometime tomorrow. -Gary , ~~ From: Maunder, Thomas E (DOA mailto:tom.maunder@alaska Sent: Wednesday, March 12, 2008 6 PM To: Eller, J Gary Subject: RE: Oral Approval of 30-02AL3 Gary, Where are the rig operations at? Tom Maunder, PE AOGCC From: Regg, James B (DOA) Sent: Tuesday, March 11, 2008 10:04 AM To: Eller, J Gary Cc: Maunder, Thomas E (DOA) Subject: RE: Oral Approval of 30-02AL3 PTD Gary -Thank you f~f the info. I believe in this case the reference to 20 AAC 25.015 i of correct -the unplanned sidetrack is a new lateral (wellbore) that requires a 10-401 and is not a Chan of operations. 20 AAC 25.005 is the -r`oper reference, and paragraph (a) gives us the ability to grant oral approva redrill below conductor casing to avoid interruption of operations. To/m ~ back in the office today so he will likely be handling your request. J,ixh Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 3/12/2008 Page 1 of 2 • • Maunder, Thomas E (DOA) Fram: Eller, J Gary [J.Gary.Ellerr7a conocophitlips.com] Sent: Wednesday, March 12, 2008 2:41 PM To: Maunder, Thomas E (DOA) Subject: RE: Oral Approval of 30-02AL3 PTD Tom -Just moments ago we were preparing to mill off of the aluminum billet at 11,170' MD in the 30-02A sidetrack, but they had a downhole communications failure. Plan forward is to repair that tool string, mill off of the billet, perform a BOPE test, and begin drilling the AL3 lateral sometime tomorrow. -Gary From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Wednesday, March 12, 2008 2:36 PM To: Eller, J Gary Subject: RE: Oral Approval of 30-02AL3 PTD Gary, Where are the rig operations at? Tom Maunder, PE AOGCC From: Regg, James B (DOA) Sent: Tuesday, March 11, 2008 10:04 AM To: Eller, ]Gary Cc: Maunder, Thomas E (DOA) Subject: RE: Oral Approval of 30-02AL3 PTD Gary -Thank you for the info. I believe in this case the reference to 20 AAC 25.015 is not correct -the unplanned sidetrack is a new lateral (wellbore) that requires a 10-401 and is not a change of op rations. 20 AAC 25.005 is the proper reference, and paragraph (a) gives us the ability to grant oral approval to r rill below conductor casing to avoid interruption of operations. ~,'~ ~ Tom is back in the office today so he will likely be handling your request. Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 phone: 907-793-1236 fax: 907-276-7542 From: Eller, J Gary [mailto:J.Gary.Eller@conocophillips.com] Sent: Monday, March 10, 2008 3:26 PM To: Regg, James B (DOA) Subject: Oral Approval of 30-02AL3 PTD 6,~ Q~,~ . ~''~'o Jim - I looked up the details of 20 AAC 25.015(b). I believe that this change in the Permit to Drill falls under ifiem (2). Therefore, ConocoPhilGps will require verbal approval from the AOGCC for drilling this unplanned lateral. As I said over the phone, we will run liner in the `A' sidetrack today and miA a kickoff point on the aluminum billet tomorrow. We'll then test BOPE, which means we should not start drilling the AL3 lateral until Wednesday, March 12. Verbal approval prior to that time is requested. 3/12/2008 30-02AL3 Plan 9 Plot • • Maunder, Thomas E (DOA) From: Eller, J Gary [J.Gary.Eller@conocophillips.com] Sent: Wednesday, March 12, 2008 4:10 PM To: Maunder, Thomas E (DOA) Subject: FW: 30-02AL3 Plan 9 Plot Attachments: 30-02AL3 Plan 9 Plot.pdf Page 1 of 1 Tom - I got a call from Art (AOGCC) saying that he needed a plot of the directional plan. See attached. Please call if we need to discuss. -Gary From: Michaelson, Bill G [mailto:William.Michaelson@bakerhughes.com] Sent: Wednesday, March 12, 2008 4:04 PM To: Eller, ]Gary Subject: 30-02AL3 Plan 9 Plot ~C Gary, here you go ~ °~~ J-~.C\ ,~ \~o G~-S b ~ ~, Bill Michaelson `~~ Baker Hughes INTEQ office: 907-267-6654 cell: 907-301-3570 «30-02AL3 Plan 9 Plot.pdf» 3/12/2008 Page 1 of 1 • Regg, James B (DOA) From: Regg, James B (DOA) Sent: Tuesday, March 11, 2008 10:04 AM ~~~ ~ ` (~ ~~' To: 'Eller, J Gary' t, Cc: Maunder, Thomas E (DOA) Subject: RE: Oral Approval of 30-02AL3 PTD Gary -Thank you for the info. I believe in this case the reference to 20 AAC 25.015 is not correct -the unplanned sidetrack is a new lateral (wellbore) that requires a 10-401 and is not a change of operations. 20 AAC 25.005 is the proper reference, and paragraph (a) gives us the ability to grant oral approval to redrill below conductor casing to avoid interruption of operations. Tam is back in the office today so he will likely be handling your request. Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage; AK 99501 phone: 907-793-1236 fax: 907-276-7542 From: Eller, J Gary [mailto:J.Gary.Eller@conocophillips.com] Sent: Monday, March 10, 2008 3:26 PM To: Regg, James B (DOA) Subject: Oral Approval of 30-02AL3 PTD Jim - I looked up the details of 20 AAC 25.015(b). I believe that this change in the Permit to Drill falls under item (2). Therefore, ConocoPhillips will require verbal approval from the AOGCC for drilling this unplanned lateral. As I said over the phone, we will run liner in the `A' sidetrack today and mill a kickoff point on the aluminum billet tomorrow. We'll then test BOPE, which means we should not start drilling the AL3 lateral until Wednesday, March 12. Verbal approval prior to that time is requested. Thanks much, and please call if you need more information. J. Gary Eller ells Engineer ConocoPhillips -Alaska work: 907-263-4172 cell: 907-529-1979 Pax: 907-265-1535 3/11/2008 Page 1 of 1 • • Maunder, Thomas E (DOA) From: Eller, J Gary [J.Gary.Eller@conocophillips.com] Sent: Monday, March 10, 2008 3:0$ PM To: Regg, James B (DOA} Cc: Maunder, Thomas E (DOA); Hubble, 7errie L Subject: AL3 Lateral in KRU 30-02 Attachments: 30-02 proposed CTD completion 03-10-08.pdf Jim - I'm following upon the message that I left on your voice mail earlier today. Nordic #2 is currently drilling CTD laterals in well 30-02 at Kuparuk. We just TD'd the 'A' sidetrack (207-158) at 13,180' MD and are currently running slotted liner. We would tike to drill an unplanned lateral, AL3, to access additional A-sand pay since the geology came in significantly different than we expected. This AL3 lateral will kick off of an aluminum billet at 11,165' MD in the A-sidetrack and will drill to a proposed TD of 13,200' MD. The other proposed laterals in this well, AL1 (207-159), AL2(207-160), and AL2-01 (207-161) will be drilled as planned. An updated wellbore schematic diagram is attached, and I expect to be able to provide you with an updated directional plan by tomorrow morning. The 10-401 will likely be submitted by tomorrow afternoon. The targeted formation has not changed, so BOPE test pressure should remain at 4500 psi just like the other laterals. Thanks, and please call if you have any questions. 7. Gary Eller Wells Engineer ConocoPhillips -Alaska work: 907-263-4172 Celt: 907-529-1979 fdx: 907-265-1535 3/12/2008 KRU 30-02 Producer Proposed A-sand CTD Completion Updated 3/10/2008 9%' surface casing shoe at 5930' 2'/d' slotted liner top 9950' Cement ramp exit, top of cement 9970' MD AL2-01 lateral (northern, upper) A2/3 Sand, TD @ 11,625' _ ~ ~_ ~ _~ A sand perfs: - - - - _ ~ '~ ~ ~~ 10,052' - 10,148' - - -- - \ \~ ~ (Plu99ed) AL2 lateral (northern, lower) \ Aluminum billet Al Sand, TD @ 11,630' @ 10,960' • 3'/=" TRDP SSSV at 1787' • 3Y=", 9.3#, EUE 8rd Mod tubing wl 3Y=" gas lift mandrels (six) • 3'/=' x 7" Baker RHS packer with PBR at 9891" • 2.75" D-nipple at 9928' • 3'/z' tubing tail at 9963' AL1 Lateral (western. upper) WindownT'26fkJ55casing ~ A2/3 Sand, TD @ 13,200' @ 10,060' MD Aluminum billet @ 10,225' AL3 Lateral (western, upper) A2/3 Sand, TD @ 13,200' Aluminum billet @ 11,165' 'A' sidetrack (western, lower) Al Sand, TD @ 13,180' • • 7", 26 ppf, J-55 casing shoe at 10,392' a ~~ '~~'~ I ICE ~~ ~ ~' ~ ~~ ALASSA OII, A1~TD GAS COI~TSERQATI011T COl-IIrII5SIOrT Gary Eller CT Drilling Engineer Conoco Phillips Alaska Inc. C/o PO Box 196612 Anchorage, Alaska 99519-6612 SARAH PAL/N, GOVERNOR 333 W. 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Re: Kuparuk River Field, Kuparulc River Pool, 30-02AL3 Conoco Phillips Alaska Inc. Permit No: 208-036 Surface Location: 745' FNL, 1855' FWL, SEC. 22, T13N, R09E, UM Bottomhole Location: 2240' FSL, 1342' FEL, SEC. I7, T13N, R09E, UM Dear Mr. Eller: Enclosed is the approved application for permit to redrill the above referenced development well. The permit is for a new wellbore segment of existing well KRU 30-02A, Permit No 207-158, API 50- 029-21837-01. Production should continue to be reported as a function of the original API number stated above. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). i`~/ Daniel T. Seamount, Jr. Chair DATED this day of March, 2008 cc: Department of Fish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. ~~ 1 a. Type of work ^ Drill ®Redrill ^ Re-Entry 1 b. Current Well Class ^ Exploratory ^ Development Gas ^ Service ^ Multiple Zone ^ Stratigraphic Test ®Development Oil ^ Single Zone 1 c. Specify if well is pr ^Coalbed Methane as rates ^ Shale Gas 2. Operator Name: Conoco Phillips Alaska Inc. 5. Bond: ®Blanket ^ Single Well Bond No. 59-52-180 11. Well Name and Number: 30-02AL3 3. Address: c/o P.O. Box 196612, Anchorage, Alaska 99519-6612 6. Proposed Depth: MD `R 13120 TVD 6477ss 12. Field /Pool(s): Kuparuk River Unit / Kuparuk 4a. Location of Well (Governmental Section): Surface: 7 ' FW T1 9E ' F L SEC UM 7. Property Designation: `!, ADL 025512 River Pool , 45 N ; 1855 L, . 22, 3N, R0 Top of Productive Horizon: 3274' FSL, 4156' FEL, SEC. 16, T13N, R09E, UM 8. Land Use Permit: 13. Approximate Spud Date: March 11, 2008 Total Depth: 2240' FSL, 1342' FEL, SEC. 17, T13N, R09E, UM 9. Acres in Property: 2560 14. Distance to Nearest Property: 10,600' 4b. Location of Well (State Base Plane Coordinates): Surface: x-525491 y-6022072 Zone-ASP4 10. KB Elevation (Height above GL): ~ 59' feet 15. Distance to Nearest Well Within Pool: 1,400' 16. Deviated Wells: Kickoff Depth: ~ 11170 feet Maximum Hole An le: :, 95 de rees 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Downhole: ~ 4995 Surface: ~ 4335 18. Ca in Pr ram: S cifi f s To - ettin D th -Bo ttom Quantit of Cement c.f. or sacks Hole Casin Wei ht Grade Cou lin Len th MD TVD MD TVD includin sta a data 3" 2-3/8" 4.6# L-80 STL 2820' 10300' 6513' 13120' 6477'ss Uncemented Slotted Liner 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-entry Operations) Total Depth MD (ft): 13200 Total Depth TVD (ft): 6518 Plugs (measured): None Effective Depth MD (ft): 13200 Effective Depth TVD (ft): 6518 Junk (measured): None asing Length ize Cement Volume MD TVD Conductor /Structural 115' 16" 199 x Arcti set I I 115' 115' Surface 5930' 9-5/8" 1400 sx AS III, 400 sx'G', To Job: 100 sx AS I 5930' 4002' Intermediate Product n 10392' 7" 315 sx lass'G' 175 sx CSI 103 2' 6773' Liner 2010' 3" Uncemented Slotted Liner 30-02A 11170' - 13180' 6533' - 6518' Perforation Depth MD (ft): None Perforation Depth TVD (ft): None 20. Attachments ^ Filing Fee, $100 ®BOP Sketch ®Drilling Program ^ Time vs Depth Plot ^ Shallow Hazard Analysis ^ Property Plat ^ Diverter Sketch ^ Seabed Report ®Drilling Fluid Program ®20 AAC 25.050 Requirements 21. Verbal Approval: Commission Representative: Date: 22. I hereb ity that the fore ing is true and correct. Contact Gary Eller, 529-1979 (Cell) Printed Gary Eller Title CT Drilling Engineer Prepared By Name/Number: Si nature Phone 263-4172 Date 3 ~ Terrie Hubble, 564-4628 Commission Use Onl Permit To Drill Number ~D.~fcr~ API Number: 50-029-21837-63-00 Permit c val Date: See cover letter for other re uirements Conditions of Approval: If box is checked, well may not be used to explore for, test, or produce Coalbed met1hane, gas hydrates, or gas contained shales: Samples Req'd: Yes LCI No Mud Log Req'd: ~es ~No ;~,~ H2S Measures: Yes ^ No Directional Survey Req'd: Yes ^ No Other: W S~~ Q~'~ ~~ /~ ~ APPROVED BY THE COMMISSION Date ,COMMISSIONER STATE OF ALASKA ~~v~'~~~ ALAS~IL AND GAS CONSERVATION COMMI~N MAR 1 1 20(l$ PERMIT TO DRILL ~~~~~ 20 AAC 25.005 - -,~ Form 10-461 Revised`12/2005 ~ O ^ ~ ^ ~ ~ ~ ~ Submit In Duplicate Y KRU 30-02 Quint Sidetrack/Laterals - Coi~ Tubing Drilling Summary of Ouerations: A coiled tubing drilling rig will drill five sidetracks & laterals in well KRU 30-02 using the managed pressure drilling technique. These horizontal laterals will target Kuparuk A2/3 and Al sand reserves to access unswept and trapped oil. The perforations in the motherbore will be plugged with cement. 1. The A sidetrack will exit the motherbore at 10,060' MD and be a 3140' horizontal targeting the Al sand to the southwest. It will be completed with 23/8" slotted liner to a TD of 13,200' MD. 2. The AL3 lateral will kick off from the A sidetrack at 11,170' MD targeting A2/3 Sands to the southwest. The AL3 lateral will be 1950' in length and will be completed with 23/8" slotted liner to a TD of 13,120' MD. 3. The AL1 lateral will kick off from the A sidetrack at 10,300' MD targeting A2/3 Sands to the southwest. The ALl lateral will be 2900' in length and will be completed with 23/8" slotted liner to a TD of 13,200' MD. 4. The AL2 lateral will kick off from the A sidetrack at 10,225' MD and will target Al Sand to the north. The AL2 lateral will be 1405' in length and will be completed with 23/8" slotted liner to a TD of 11,630' MD. 5. The final lateral, AL2-O1, will kick off from the AL2 lateral at 10,960' MD and will target the A2/3 Sands to the north. The AL3 lateral will be 665' in length and will be completed with 23/8" slotted liner to a TD of 11,625' MD. Only the final drilled lateral will remain accessible through-tubing. CTD Drill and Complete 30-02 program: March 2008 Pre-Rig Work 1. Obtain updated static BHP on A sand. 2. Test Packoffs - T & IC. 3. Positive pressure and drawdown tests on MV and SV. 3d~ ~~~ r 4. Drawdown test on SCSSV. \ 5. Slickline tag fill and drift 3%2" tubing. 6. Install dummy valves in GLMs 7. MIT-IA, MIT-OA. 8. Coil tubing plug existing A sand perfs with 17 ppg cement up to tubing tail at 9963' MD. 9. Slickline tag top of cement. Rig Work 1. MIRU Nordic Rig #2 using 2" coil tubing. NU 7-1/16" BOPE, test. 2. Drill low-side pilot hole and cement ramp for exit at 10,060' M .74" window and 10' of open hole from 10,060' MD. 3. 30-02A Sidetrack (Western Lower) a. Drill pilot and cement ra igh-side exit at 10,060' MD. b. Mi112.74" wi ith high-side orientation. The planned KOP is at 10,060' MD in the A Dri113" bi-center horizontal `A' sidetrack southwest in the Al sand from the window to TD at 13,200' MD. d. Kill well. Run 23/8" slotted liner with aluminum billet from TD up to f 11,170' MD. 4. 30-02AL3 Lateral (unplanned Western Upper) ~~`- , ~ a. Dri113" bi-center horizontal AL3 lateral southwest in the A2/3 sand from 11,170' to TD at ~~ca'`` 13,120' MD. b. Kill well. Run 23/8" slotted liner with aluminum billet from TD up to (10,300' MD. 5. 30-02AL1 Lateral (Western Upper) a. 3" bi-center horizontal AL1 lateral southwest in the A2/3 sand from 10,300' to TD at 13,200' b. Kill well. Run 23/8" s o r with aluminum billet from TD up to f 10,225' MD. 6. 30-02AL2 Lateral (Northern Lower) a. Drill 3" bi-center horizontal AL2 lateral north in nd from 10,225' to TD at 11,630' MD. Page 1 of 3 March 11, 2008, FINAL • KRU 30-02 Quint Sidetrack/Laterals - Coil• Tubing Drilling ill well. Run 23/8" slotted liner with aluminum bille D up to 110,960' MD. 7. 30-02 ateral (Northern Upper) a. Dri113" bi-cente ontal AL a north in the A2/3 sands from 10,960' to TD at 11,625' MD. b. Kill well. 8' slotted liner with a m billet from TD up into the 3'/z" tubing tail at D. reeze protect. ND BOPE. RDMO Nordic 2. Post-Rig Work 1. Run GLVs 2. Obtain static BHP 3. Produce well to sales. Mud Program: • Will use chloride-based Biozan brine (10.0 ppg) for milling operations, and chloride-based Flo-Pro mud 010.0 ppg) for drilling operations. Since there is an SCSSV installed in 30-02, we should not have to kill the well to deploy 23/8" slotted liner. Disposal: • No annular injection on this well. • Class II liquids to KRU 1R Pad Class R disposal well • Class II drill solids to Grind & Inject at PBU Drill site 4 • Class I wastes will go to Pad 3 for disposal. Casing Program: • 30-02A: 23/8", 4.6#, L-80, STL slotted liner from 11,170' MD to 13,200' MD • 30-02AL3: 23/8", 4.6#, L-80, STL slotted liner from 10,300' MD to 13,120' MD • 30-02AL1: 23/8", 4.6#, L-80, STL slotted liner from 10,225' MD to 13,200' MD • 30-02AL2: 23/8", 4.6#, L-80, STL slotted liner from 10,960' MD to 11,630' MD • 30-02 AL2-O1: 23/8", 4.6#, L-80, STL slotted liner from 9960' MD to 11,625' MD Existing Casing/Liner Information Surface: 9s/8", J-55, 36 ppf Burst 3520 psi; Collapse 2020 psi. Production: 7", J-55, 26 ppf Burst 4980 psi; Collapse 4320 psi Well Control: • Two well bore volumes 0180 bbl) of KWF will be available to the rig during drilling operations. The kill weight fluid may or may not be stored onsite, but if it is stored offsite it will be in the Kuparuk Field within a short drive to the rig. • BOP diagram is attached for operations with 2" coil tubing. • Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 4500 psi. Maximum potential surface pressure is 4335 psi assuming a gas gradient to surface and maximum potential formation pressure based on the highest pressure measured in offset injectors (i.e. 4995 psi in 3Q-15 in July 2006). • The annular preventer will be tested to 250 psi and 2500 psi. Page 2 of 3 March 11, 2008, FINAL • KRU 30-02 Quint Sidetrack/Laterals - Coil• Tubing Drilling Directional: • See attached directional plans. • Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. • 30-02A: 10,600' to property line, 1400' to 3Q-16 at the toe • 30-02AL3: 10,600' to property line, 1400' to 3Q-16 at the toe • 30-02AL1: 10,600' to property line, 1400' to 3Q-16 at the toe • 30-02AL2: 9000' to property line, 1000' to 3R-19 at the toe • 30-02 AL2-O1: 9000' to property line, 1000' to 3R-19 at the toe Logging • MWD directional, resistivity, and gamma ray will be run over the entire open hole section. Hazards Expect to encounter increased pressure in the western laterals, particularly beyond a fault that will be encountered at 11,500' MD. The static reservoir pressure in the 3Q-16 injection well which the western laterals are drilling towards is approximately 14.5 ppg EMW. Lost circulation is a risk due to the likelihood of encountering increased formation pressure at major fault crossings, particularly in the western laterals. We1130-02 has 145 ppm HZS as measured on 1/22/07. Wells 30-01 and 30-03 are adjacent to 30-02. 30-01 has 265 ppm HZS as measured on 1/22/07, and 30-03 has 140 ppm HZS as measured on 1/25/07. The maximum HZS level on the 30 pad is 265 ppm from we1130-01. All HZS monitoring equipment will be operational. Reservoir Pressure • The most recent static pressure measured in 30-02 is 3703 psi on 10/02/07 (i.e. 10.9 ppg EMW at 6567' TVD). Prior to that, the survey taken in January 2005 showed that reservoir pressure was 3006 psi (i.e. 8.8 ppg EMW). Managed Pressure Drilling Managed pressure drilling (MPD) techniques will be employed to provide constant bottom hole pressure by using 10.0 ppg drilling fluid in combination with annular friction losses and applied surface pressure. Constant BHP will be utilized to reduce pressure fluctuations to help with hole stability. Applying annular friction and choke pressure also allow use of less expensive drilling fluid and minimizes fluid losses and/or fracturing at the end of the long well bores. A hydraulic choke for regulating surface pressure will be installed between the BOPE choke manifold and the mud pits, and will be independent of the BOPE choke. Using this technique will require deployment of the BHA under trapped wellhead pressure. Pressure deployment of the BHA will be accomplished utilizing the 23/8" pipe/slip rams. The annular preventer will act as a secondary containment during deployment and not as a stripper. There is a functional SCSSV in we1130-02, so the well should not have to be killed prior to running 23/8" slotted liner. Operating parameters and fluid densities will be adjusted based on real-time bottom hole pressure measurements while drilling and shale behavior. The following scenario is expected at TD: • Estimated reservoir pressure: 3703 psi at 10,101' MD (6562' TVD), or 10.9 ppg EMW. • Expected annular friction losses while circulating: 905 psi (assuming friction of 90 psi/1000 ft). • Planned mud density: 10.0 ppg equates to 3412 psi hydrostatic bottom hole pressure at 6562' TVD • While circulating 10.0 ppg fluid, bottom hole circulating pressure is estimated to be 4317 psi or 12.7 ppg EMW without holding any additional surface pressure. • When circulation is stopped, it is anticipated that 300 psi of additional surface pressure shall have to be applied to balance reservoir pressure. 905 psi of additional surface pressure must be held to maintain the same bottom hole pressure as during drilling operations. Page 3 of 3 March 11, 2008, FINAL KRU 30-02 Producer Proposed A-sand CTD Completion Updated 3/11/2008 AL2-01 lateral (northern, upper) A2/3 Sand, TD @ 11,625' 9°/s" Surface casing shoe at 5930' 2'/a" slotted liner top -9950' Cement ramp exit, top of cement -9970' MD A sand perfs: 10,052' - 10,148' ~ (plugged) • 3'/z' TROP SSSV at 1787' • 3'/z", 9.3#, EUE 8rd Mod tubing w/ 3'/z' gas lift mandrels (six) • 3'/z' x 7" Baker RHS packer with PBR at 9891" • 2.75" D-nipple at 9928' • 3'/i' tubing tail at 9963' AL1 Lateral (western, upper) WFxlownT'26/~J55casn9 A2/3 Sand, TD @ 13,200' @ 10,060' MD Aluminum billet / @ 10,225' ~~_= tl /~___ AL3 Lateral (western, upper) A2/3 Sand, TD @ 13,120' Aluminum billet @ 11,170' • AL2 lateral (northern, lower) \ Aluminum billet 'A' sidetrack (western, lower) Al Sand, TD @ 11,630' @ 10,960' A7 Sand, TD @ 13,180' 7", 26 ppf, J-55 casing shoe at 10,392' ,~+~ by BP Alaska '~w~ Baker Hughes INTEQ Planning Report ~.r s ,lr ~ ~~ 'Company: ConocoPhillips Alaska lnc. Date: 3/10/2008 Time: 18:36:37 Page: 1 Field: Kuparuk River Unit Co-ordinate(NE) Reference: Well: 30-02, True North `Site: Kuparuk 30 Pad Vertical (TVD) Reference: 30-02 59.0 Well: 30-Q2 Section (VS} Reference: Well (O.OON,O.OOE,225.OOAzi) Wellpath: Plan 9, 30-02AL3 Survey Calculation Method: Minimum Curvature Db: Sybase Field: Kuparuk River Unit North Slope Alaska United States Map System:US State Plane Coordinate System 1927 Map Zone: Alaska, Zone 4 Geo Datmn: NAD27 (Clarke 1866) Coordinate System: Well Centre Sys Datum: Mean Sea Level Geomagnetic Model: bggm2007 Site: Kuparuk 30 Pad Site Position: Northing: 6022094.67 ft Latitude: 70 28 17.333 N From: Map Easting: 525478.25 ft Longitude: 149 47 30.897 W Position Uncertainty: 0.00 ft North Reference: True Ground Level: 0.00 ft Grid Convergence: 0.20 deg Well: 30-02 Slot Name: Well Position: +N/-S -20.83 ft Northing: 6022073.89 ft Latitude: 70 28 17.128 N +E/-W 12.62 ft Easting : 525490.94 ft Longitude: 149 47 30.526 W Position Uncertainty: 0.00 ft Wellpath: Plan 9, 30-02AL3 Drilled From: 30-02A 500292183760 Tie-on Depth: 11147.03 ft Current Datum: 30-02 Height 59.00 ft Above System Datum: Mean Sea Level Magnetic Data: 11/29/2007 Declination: 23.01 deg Field Strength: 57629 nT Mag Dip Angle: 80.91 deg Vertical Section: Depth From (TVD) +N/-S +E/-W Direction ft ft ft deg 59.00 0.00 0.00 225.00 Plan: Plan #9 Date Composed: 11/29/2007 target depth changes on first four targets Version: 20 Principal: Yes Tied-to: From: Definitive Path Targets Name :Description Dip. Dir. TVD :: ft +N/-S ft +E/-W ft ...Map Northing ft Map Easting ft <°-- Latitude ----> Deg Min Sec <--- Deg Longitude ---> Alin Sec 30-02A Western Polygon 59.00 4078.15 -6314.65 6026129.99 519162.99 70 28 57.209 N 149 50 36.270 W -Polygon 1 59.00 4078.15 -6314.65 6026129.99 519162.99 70 28 57.209 N 149 50 36.270 W -Polygon 2 59.00 4148.80 -6501.42 6026199.99 518975.99 70 28 57.902 N 149 50 41.765 W -Polygon 3 59.00 4141.07 -6874.49 6026190.99 518602.99 70 28 57.823 N 149 50 52.739 W -Polygon 4 59.00 4042.11 -7178.86 6026090.99 518298.99 70 28 56.847 N 149 51 1.689 W -Polygon 5 59.00 3960.83 -7393.16 6026008.99 518084.99 70 28 56.045 N 149 51 7.990 W -Polygon 6 59.00 3847.27 -7525.56 6025894.99 517952.99 70 28 54.927 N 149 51 11.881 W -Polygon 7 59.00 3573.30 -7832.53 6025619.99 517646.99 70 28 52.230 N 149 51 20.902 W -Polygon 8 59.00 3317.05 -8060.44 6025362.99 517419.99 70 28 49.707 N 149 51 27.597 W -Polygon 9 59.00 2768.30 -8442.36 6024812.99 517039.99 70 28 44.306 N 149 51 38.812 W -Polygon 10 59.00 2872.01 -8648.02 6024915.99 516833.99 70 28 45.324 N 149 51 44.864 W -Polygon 11 59.00 3058.03 -8647.38 6025101.99 516833.99 70 28 47.153 N 149 51 44.851 W -Polygon 12 59.00 3484.09 -8359.90 6025528.99 517119.99 70 28 51.347 N 149 51 36.410 W -Polygon 13 59.00 3915.05 -7749.36 6025961.99 517728.99 70 28 55.592 N 149 51 18.466 W -Polygon 14 59.00 4057.00 -7438.84 6026104.99 518038.99 70 28 56.991 N 149 51 9.337 W -Polygon 15 59.00 4213.15 -7185.28 6026261.99 518291.99 70 28 58.529 N 149 51 1.883 W -Polygon 16 59.00 4322.27 -6924.87 6026371.99 518551.99 70 28 59.605 N 149 50 54.226 W -Polygon 17 59.00 4381.41 -6672.65 6026431.99 518803.99 70 29 0.188 N 149 50 46.808 W -Polygon 18 59.00 4327.63 -6445.81 6026378.99 519030.99 70 28 59.661 N 149 50 40.134 W -Polygon 19 59.00 4255.96 -6253.03 6026307.99 519223.99 70 28 58.958 N 149 50 34.462 W -Polygon 20 59.00 4123.48 -6116.47 6026175.99 519360.99 70 28 57.656 N 149 50 30.441 W -Polygon 21 59.00 3991.73 -6192.93 6026043.99 519284.99 70 28 56.360 N 149 50 32.687 W 30-03AL3 Target 6 TD 6536.00 2982.46 -8482.62 6025026.99 516998.99 70 28 46.412 N 149 51 40.003 W 30-03AL3 Target 5 6537.00 3331.49 -8188.40 6025376.99 517291.99 70 28 49.848 N 149 51 31.361 W 30-03AL3 Target 4 6552.00 3656.75 -7962.26 6025702.99 517516.99 70 28 53.049 N 149 51 24.720 W CJ by BP Alaska s Baker Hughes INTEQ Planning Report iNTEQ Company: ConocoPhil{ips Alaska lnc. Date: 3/10/2008 Time: 18:36:37 Page: 2 Field: Kuparuk River'Unit Co-ordinate(NE) Reference: W ell: 30-02, True North Site: Kuparuk 30 Pad '.Vertical (TVI)) Reference: 30-02 59.0 Well: 30-02 Section (VS)Iteference: W ell (O.OON,O.OOE,225.OOAzi) Wellpath: Plan 9, 30-02AL3 Survey Calculation Alethod: Mi nimum Curvature Db: Sybase Targets Mag Map <---- Latitude ----> <--- Longitude ---> Name Description TVD +N/-5 +E/-W Northing Easting Deg 1VIin Sec Deg blin Sec - Dip. Dir. ft ft ft ft ft 30-03AL3 Target 2 6559.00 3946.1 1 -7474.22 6025993.99 518003.99 70 28 55.900 N 149 51 10.374 W 30-03AL3 Target 3 6561.00 3796.93 -7719.76 6025843.99 517758.99 70 28 54.430 N 149 51 17.592 W 30-03AL3 Target 1 6566.00 4063.58 -7317.80 6026111.99 518159.99 70 28 57.057 N 149 51 5.777 W Annotation MD TVD ft ft 11147.03 6591.45 TIP -Ti e to 30-02A 11170.00 6591.72 KOP 11207.00 6590.31 End of 25 Deg/100' DLS 11407.00 6572.93 4 11447.00 6569.66 5 11614.52 6561.43 6 11719.00 6560.00 7 11869.00 6559.93 8 12019.00 6562.71 9 12169.00 6558.59 10 12279.00 6551.98 11 12499.00 6543.69 12 12679.00 6536.37 13 12864.00 6533.11 14 13120.00 6535.67 TD Plan Section Information MD Incl Azim TVD +N/-S +E/-W DLS Build Turn TFO Target ft deg deg ft ft ft deg/100ft deg/100ft deg/100ft deg 11147.03 89.48 227.28 6591.45 4175.69 -6991.57 0.00 0.00 0.00 0.00 11170.00 89.20 233.40 6591.72 4161.04 -7009.24 26.67 -1.22 26.64 92.65 11207.00 95.14 240.50 6590.31 4140.89 -7040.19 25.00 16.05 19.19 50.00 11407.00 94.69 264.59 6572.93 4081.58 -7228.87 12.00 -0.22 12.04 90.00 11447.00 94.68 259.77 6569.66 4076.16 -7268.35 12.00 -0.04 -12.04 270.00 11614.52 90.90 240.00 6561.43 4018.87 -7424.64 12.00 -2.25 -11.80 259.77 11719.00 90.66 227.46 6560.00 3957.19 -7508.70 12.00 -0.23 -12.00 269.00 11869.00 89.39 245.42 6559.93 3874.62 -7633.19 12.00 -0.84 11.97 94.00 12019.00 88.50 227.44 6562.71 3792.03 -7757.63 12.00 -0.60 -11.99 267.00 12169.00 94.63 244.38 6558.59 3708.30 -7881.28 12.00 4.09 11.29 70.00 12279.00 92.24 231.37 6551.98 3650.02 -7974.05 12.00 -2.17 -11.82 260.00 12499.00 92.00 204.95 6543.69 3478.69 -8108.68 12.00 -0.11 -12.01 270.00 12679.00 92.60 226.56 6536.37 3333.60 -8213.15 12.00 0.33 12.01 88.00 12864.00 89.40 204.59 6533.11 3184.08 -8320.08 12.00 -1.73 -11.88 262.00 13120.00 89.48 235.31 6535.67 2990.18 -8482.49 12.00 0.03 12.00 90.00 by BP Alaska g Baker Hughes INTEQ Planning Report 1NTEQ -Company: ConocoPhillips:Alaskamc. Date: 311 012 0 08 Time: 18:36:37 Page: 3 Field: Kuparuk River Unit Co-ardinate(NE) Reference: Well: 3 0-02, True North Site: Kuparuk 30 Pad Vertical {TVD) Reference: 30-02 59.0 Well: 30-02 Section (VS) leference: Well (O .OON,O.OOE,225.OOA zi) Wellpath: Plan 9, 30-02AI_3 Survey Calculation Method: Minimu m Curvature Db: Sybase Survey MI) Tncl Azim , SS TVD N/S E/W MapN MapE DLS VS 'fF0 Too ft 'deg deg ft ft ft ft ft deg/10oft ft deg 11147.03 89.48 227.28 6532.45 4175.69 -6991.57 6026225.20 518485.81 0.00 1991.12 0.00 MWD 11150.00 89.44 228.07 6532.48 4173.69 -6993.76 6026223.20 518483.62 26.67 1994.09 92.65 MWD 11170.00 89.20 233.40 6532.72 4161.04 -7009.24 6026210.49 518468.19 26.67 2013.98 92.65 MWD 11175.00 90.00 234.36 6532.75 4158.09 -7013.28 6026207.53 518464.16 25.00 2018.92 50.00 MWD 11200.00 94.02 239.15 6531.87 4144.40 -7034.16 6026193.77 518443.33 25.00 2043.37 49.99 MWD 11207.00 95.14 240.50 6531.31 4140.89 -7040.19 6026190.24 518437.31 25.00 2050.11 50.16 MWD 11225.00 95.13 242.67 6529.70 4132.36 -7055.96 6026181.66 518421.57 12.00 2067.30 90.00 MWD 11250.00 95.12 245.68 6527.47 4121.52 -7078.37 6026170.74 518399.20 12.00 2090.81 90.19 MWD 11275.00 95.08 248.69 6525.25 4111.87 -7101.32 6026161.01 518376.28 12.00 2113.87 90.46 MWD 11300.00 95.04 251.71 6523.04 4103.43 -7124.75 6026152.49 518352.89 12.00 2136.39 90.73 MWD 11325.00 94.98 254.72 6520.86 4096.24 -7148.59 6026145.22 518329.07 12.00 2158.34 91.00 MWD 11350.00 94.91 257.73 6518.70 4090.31 -7172.78 6026139.21 518304.91 12.00 2179.64 91.26 MWD 11375.00 94.82 260.74 6516.58 4085.65 -7197.25 6026134.47 518280.46 12.00 2200.23 91.52 MWD 11400.00 94.72 263.75 6514.50 4082.29 -7221.93 6026131.02 518255.79 12.00 2220.06 91.77 MWD 11407.00 94.69 264.59 6513.93 4081.58 -7228.87 6026130.29 518248.85 12.00 2225.47 92.02 MWD 11425.00 94.69 262.42 6512.46 4079.55 -7246.69 6026128.20 518231.04 12.00 2239.51 270.00 MWD 11447.00 94.68 259.77 6510.66 4076.16 -7268.35 6026124.73 518209.39 12.00 2257.22 269.82 MWD 11450.00 94.61 259.42 6510.42 4075.62 -7271.29 6026124.18 518206.45 12.00 2259.68 259.77 MWD 11475.00 94.07 256.46 6508.52 4070.41 -7295.67 6026118.89 518182.10 12.00 2280.60 259.74 MWD 11500.00 93.52 253.50 6506.87 4063.94 -7319.76 6026112.34 518158.03 12.00 2302.21 259.52 MWD 11525.00 92.96 250.55 6505.46 4056.24 -7343.50 6026104.56 518134.32 12.00 2324.44 259.32 MWD 11550.00 92.39 247.60 6504.29 4047.32 -7366.82 6026095.56 518111.03 12.00 2347.24 259.16 MWD 11575.00 91.82 244.65 6503.37 4037.21 -7389.66 6026085.38 518088.23 12.00 2370.54 259.02 MWD 11600.00 91.24 241.71 6502.70 4025.94 -7411.96 6026074.03 518065.97 12.00 2394.28 258.91 MWD 11614.52 90.90 240.00 6502.43 4018.87 -7424.64 6026066.92 518053.32 12.00 2408.24 258.83 MWD 11625.00 90.88 238.74 6502.27 4013.53 -7433.66 6026061.55 518044.32 12.00 2418.40 269.00 MWD 11650.00 90.82 235.74 6501.90 4000.01 -7454.68 6026047.95 518023.35 12.00 2442.82 268.98 MWD 11675.00 90.77 232.74 6501.55 3985.40 -7474.96 6026033.28 518003.12 12.00 2467.49 268.94 MWD 11700.00 90.71 229.74 6501.23 3969.75 -7494.45 6026017.56 517983.68 12.00 2492.34 268.89 MWD 11719.00 90.66 227.46 6501.00 3957.19 -7508.70 6026004.96 517969.48 12.00 2511.29 268.86 MWD 11725.00 90.61 228.18 6500.94 3953.16 -7513.15 6026000.91 517965.04 12.00 2517.29 94.00 MWD 11750.00 90.40 231.17 6500.72 3936.99 -7532.21 6025984.67 517946.04 12.00 2542.20 94.01 MWD 11775.00 90.19 234.17 6500.59 3921.83 -7552.09 6025969.45 517926.22 12.00 2566.98 94.03 MWD 11800.00 89.98 237.16 6500.55 3907.73 -7572.73 6025955.28 517905.63 12.00 2591.54 94.05 MWD 11825.00 89.77 240.15 6500.61 3894.73 -7594.08 6025942.21 517884.33 12.00 2615.83 94.05 MWD 11850.00 89.55 243.15 6500.76 3882.86 -7616.07 6025930.26 517862.37 12.00 2639.78 94.05 MWD 11869.00 89.39 245.42 6500.93 3874.62 -7633.19 6025921.96 517845.29 12.00 2657.71 94.03 MWD 11875.00 89.36 244.70 6501.00 3872.09 -7638.63 6025919.41 517839.85 12.00 2663.35 267.00 MWD 11900.00 89.20 241.70 6501.31 3860.82 -7660.94 6025908.07 517817.58 12.00 2687.09 267.01 MWD 11925.00 89.05 238.71 6501.69 3848.40 -7682.63 6025895.57 517795.94 12.00 2711.21 267.05 MWD 11950.00 88.90 235.71 6502.14 3834.86 -7703.64 6025881.97 517774.98 12.00 2735.64 267.09 MWD 11975.00 88.75 232.71 6502.66 3820.25 -7723.91 6025867.29 517754.76 12.00 2760.31 267.15 MWD 12000.00 88.60 229.72 6503.23 3804.59 -7743.39 6025851.57 517735.33 12.00 2785.15 267.21 MWD 12019.00 88.50 227.44 6503.71 3792.03 -7757.63 6025838.96 517721.14 12.00 2804.11 267.28 MWD 12025.00 88.74 228.12 6503.86 3787.99 -7762.08 6025834.91 517716.71 12.00 2810.10 70.00 MWD 12050.00 89.77 230.93 6504.18 3771.77 -7781.09 6025818.62 517697.75 12.00 2835.02 69.98 MWD 12075.00 90.80 233.75 6504.06 3756.50 -7800.88 6025803.28 517678.02 12.00 2859.81 69.95 MWD 12100.00 91.83 236.57 6503.48 3742.22 -7821.39 6025788.94 517657.56 12.00 2884.41 69.96 MWD 12125.00 92.85 239.39 6502.46 3728.98 -7842.57 6025775.62 517636.43 12.00 2908.75 70.03 MWD 12150.00 93.86 242.22 6501.00 3716.81 -7864.35 6025763.38 517614.69 12.00 2932.76 70.14 MWD 12169.00 94.63 244.38 6499.59 3708.30 -7881.28 6025754.81 517597.79 12.00 2950.74 70.31 MWD 12175.00 94.50 243.66 6499.12 3705.68 -7886.66 6025752.17 517592.42 12.00 2956.40 260.00 MWD 12200.00 93.97 240.70 6497.27 3694.04 -7908.71 6025740.46 517570.42 12.00 2980.22 259.94 MWD ~L~ g - ~ ,~+~ by BP Alaska '~w~ Baker Hughes INTEQ Planning Report u. _ ~,,t .Company: ConocoPhillips:Alaska inc. Date: 3/10/2008 Time: 18:36:37 Yage: 4 Field: Kuparuk River 7nit Co-ordinatefNE) Reference: Well: 30-02, True North Site: Kuparuk 30 Pad Vertical (TVD) Reference: 30-02 59.0 Well: 30-02 Section (VS) Reference: Well (O.OON,O.OOE,225.OOAzi) Wellpath: Plan 9,30-02AL3 -.Survey Calculation Method; Minimum Curvature Db: Sybase Survey MD Incl Azim SS TVD N/S E/W ft deg ..:,deg ft ft ft 12225.00 93.43 237.75 6495.65 3681.28 -7930.14 12250.00 92.88 234.79 6494.27 3667.42 -7950.89 12275.00 92.33 231.84 6493.14 3652.50 -7970.92 12279.00 92.24 231.37 6492.98 3650.02 -7974.05 12300.00 92.24 228.85 6492.16 3636.56 -7990.15 12325.00 92.23 225.85 6491.18 3619.64 -8008.52 12350.00 92.21 222.84 6490.21 3601.78 -8025.98 12375.00 92.19 219.84 6489.25 3583.02 -8042.48 12400.00 92.17 216.84 6488.30 3563.43 -8057.98 12425.00 92.13 213.84 6487.36 3543.05 -8072.42 12450.00 92.10 210.84 6486.44 3521.95 -8085.79 12475.00 92.05 207.83 64B5.54 3500.17 -8098.02 12499.00 92.00 204.95 6484.69 3478.69 -8108.68 12500.00 92.01 205.07 6484.65 3477.78 -8109.11 12525.00 92.11 208.07 6483.75 3455.44 -8120.28 12550.00 92.21 211.07 6482.81 3433.71 -8132.61 12575.00 92.30 214.07 6481.83 3412.66 -8146.06 12600.00 92.38 217.08 6480.81 3392.35 -8160.59 12625.00 92.46 220.08 6479.75 3372.83 -8176.16 12650.00 92.53 223.08 6478.67 3354.14 -8192.74 12675.00 92.59 226.08 6477.55 3336.36 -8210.26 12679.00 92.60 226.56 6477.37 3333.60 -8213.15 12700.00 92.25 224.06 6476.48 3318.84 -8228.07 12725.00 91.82 221.09 6475.59 3300.45 -8244.97 12750.00 91.39 218.12 6474.89 3281.20 -8260.90 12775.00 90.96 215.15 6474.38 3261.14 -8275.82 12800.00 90.52 212.19 6474.06 3240.34 -8289.67 12825.00 90.08 209.22 6473.93 3218.85 -8302.44 12850.00 89.64 206.25 6473.99 3196.72 -8314.07 12864.00 89.40 204.59 6474.11 3184.08 -8320.08 12875.00 89.40 205.91 6474.22 3174.13 -8324.77 12900.00 89.40 208.91 6474.48 3151.94 -8336.28 12925.00 89.40 211.91 6474.75 3130.38 -8348.93 12950.00 89.41 214.91 6475.01 3109.52 -8362.69 12975.00 89.41 217.91 6475.26 3089.40 -8377.53 13000.00 89.42 220.91 6475.52 3070.09 -8393.40 13025.00 89.43 223.91 6475.77 3051.63 -8410.25 13050.00 89.44 226.91 6476.02 3034.09 -8428.05 13075.00 89.45 229.91 6476.26 3017.49 -8446.75 13100.00 89.47 232.91 6476.49 3001.90 -8466.29 13120.00 89.48 235.31 6476.67 2990.18 -8482.49 MapN NiapE DLS VS T[%O Too ft ft degl100ft ft deg 6025727.63 517549.03 12.00 3004.40 259.72 MWD 6025713.70 517528.32 12.00 3028.87 259.53 MWD 6025698.71 517508.35 12.00 3053.58 259.37 MWD 6025696.22 517505.23 12.00 3057.55 259.24 MWD 6025682.71 517489.18 12.00 3078.45 270.00 MWD 6025665.73 517470.87 12.00 3103.41 269.90 MWD 6025647.80 517453.47 12.00 3128.39 269.78 MWD 6025629.00 517437.04 12.00 3153.31 269.67 MWD 6025609.35 517421.61 12.00 3178.12 269.55 MWD 6025588.93 517407.23 12.00 3202.75 269.44 MWD 6025567.78 517393.94 12.00 3227.12 269.33 MWD 6025545.96 517381.78 12.00 3251.17 269.22 MWD 6025524.45 517371.20 12.00 3273.90 269.11 MWD 6025523.54 517370.78 12.00 3274.84 88.00 MWD 6025501.16 517359.68 12.00 3298.54 88.00 MWD 6025479.39 517347.43 12.00 3322.62 88.11 MWD 6025458.30 517334.05 12.00 3347.01 88.23 MWD 6025437.94 517319.59 12.00 3371.65 88.34 MWD 6025418.36 517304.09 12.00 3396.47 88.47 MWD 6025399.63 517287.58 12.00 3421.40 88.59 MWD 6025381.78 517270.11 12.00 3446.37 88.72 MWD 6025379.02 517267.24 12.00 3450.36 88.86 MWD 6025364.21 517252.37 12.00 3471.35 262.00 MWD 6025345.76 517235.53 12.00 3496.31 261.89 MWD 6025326.46 517219.67 12.00 3521.18 261.79 MWD 6025306.35 517204.83 12.00 3545.91 261.71 MWD 6025285.51 517191.04 12.00 3570.42 261.64 MWD 6025263.97 517178.35 12.00 3594.64 261.61 MWD 6025241.81 517166.80 12.00 3618.51 261.59 MWD 6025229.15 517160.84 12.00 3631.69 261.60 MWD 6025219.18 517156.18 12.00 3642.05 90.00 MWD 6025196.95 517144.75 12.00 3665.88 89.99 MWD 6025175.36 517132.17 12.00 3690.07 89.95 MWD 6025154.45 517118.48 12.00 3714.55 89.92 MWD 6025134.28 517103.71 12.00 3739.27 89.89 MWD 6025114.92 517087.91 12.00 3764.15 89.86 MWD 6025096.40 517071.12 12.00 3789.12 89.83 MWD 6025078.80 517053.38 12.00 3814.11 89.80 MWD 6025062.14 517034.75 12.00 3839.06 89.77 MWD 6025046.49 517015.26 12.00 3863.90 89.74 MWD 6025034.71 516999.10 12.00 3883.65 89.71 3" Q~~a ~ B ~ ~~ ~~~~ _~ o ~~4 w ~~ w some J BOSS" Q. .Q f Y i ~ ~~'~~~~ Q x ~ }~ m ~: ~~ ~s ~~ 7 i ~.vawu w..a i.rn.n .•.a «+ws Alaska Department of Natural Resources Land Administration System Page 1 of 2 . . ,~r~., ,t={~ ~ eats ~~cordsr`s Saarci~ State Cabins Al~turra ~+D~>I'~es ~..._,,. a File Type: ADL ', File Number: 25512 ~ Printa.ble Case File_Summ.ary See Township, Range, Section and Acreage? New Search ~` Yes ~ No ~ ._ ~___ .. ___ ~_ i-.AS Men~~ i Case Abstract I Case Detail ~ Land Abstract Frlcr: ~DL Z~~12 ~ ''~' Starch for Status Plat Updates ,~~ cif l ;1 ~'~'0(IS Customer: 000106346 CONOCOPHILLIPS ALASKA, INC. ATTENTION: LAND MANAGER. PO BOX 100360 ANCHORAGE AK 995100360 Case Type: 7s~ OIL & GAS LEASE COMP DNR Ur1it: 780 OIL AND GAS Fr1e Location: DOG DIV OIL AND GAS Case Status: 35 ISSUED Status Date: 01/25/1965 Total Acres: 2544.000 Date Initiated: 1 1 /02/ 1964 Office ofPrimarv Responsibility: DOG DIV OIL AND GAS Last Transaction Date: I?/07/2005 Case Subtype. NORTH SLOPE Last Transaction: DR DOCUMENT RECORDED 'Mericlrujr.~ l_~ Tawn:chiJ~~ OliN Range: 009E Sr~c~run.~ 17 .~~~~~~lrun_Ic~rer: fi-tO Scarclt P~~ats Lk~~~i~~r~rn ~ L TU~r~t.ef~r/~: OL3N Runge: 009E Sc~ctiujr.~ 1 S S'eclio~t ,9crt~.c: 6 ~ 1 Mc~rr~l<<u~.~ L Tn~rrt~/ttJ~: Ol ~N Iiu~~,ge: 009E Scc'linrt.~ 19 S~ c~~nn .~lc~r~~e.~ 63 MeriX~in.~ l~ Tr~~rjr.~lti~~: O1 ~N Runge: 009E S'ec•tira~.~ 2(1 S"~~~~li~~i~_1C~rc~e: (i-~0 Legal Description 11 -U2-196 *'~` * SALE NOTICE LEGAL DESCRIPTION * ~ U-3-1-7 FRAG SECTION 17, T13N, R9~ UM ~0 EXCL. PLO 1~?I FRAC. SECTION 18, " " " ~ 91 ALL SECTION 19, " " " 633 FRAC SECTION 20, " " " S00 EXCL. PLO 1571 CO,~~TAL'VING 1. ''~l ACRES. MORE nR LESS http://www.dnr.state.ak.us/las/Case_Summary.cfm?FileType=ADL&FileNumber=25 512&... 3/12/2008 Alaska Department of Natural Resources Land Administration System Page 2 of 2 • I Z-'?3-1961 AND 01-29-196 * * * AMENDED LEASE AWARD NOTICE AND AMENDED LEASE ISSUED LEGAL DESCRIPTION T13N, K9E, UM SECTION 17: ALL, 6~0 ACRES SECTION 18: ALL. 631 ACRF_S .SECTION 19: ALL, 633 ACRES SECTION 20: ALL, 6=10 ACRES CONTAINING 2,5=1-~ ACRES, MOKE OR LL'SS. It Off` GaS~ Sly Ir Last updated on 03/12/2008. Not sure who to Contact? Have a question about DNR? Visit the t~~~~biic Irsforrnatior~ Center. Report technical problems with this page to the tltlebrr~aster• Site optimized for Netscape 7, IE 6 or above. This site also requires that all CC}CtIL must be accepted. State of Alaska Natural. Resources LAS Horne Copyright Privacy System Status http: //www. dnr. state. ak.us/las/Case_Summary. cfm?FileType=ADL&FileNumber=25 512&... 3/ 12/2008 TRANSMITTAL LETTER CHECKLIST WELL NAME 3D - ~.~?~C3 PTD# ~0~03r~ / Development Service Exploratory Stratigraphic Test Non-Conventional Well FIELD: /~~0~~le/'.l/,~.~/~'G~' POOL: ~~~.9.~1P.~ .~'/t~~ ~OC. Circle Appropriate Letter /Paragraphs to be Included in Transmittal Letter CHECK ADD-ONS WHAT (OPTIONS} TEXT FOR APPROVAL LETTER APPLIES MULTI LATERAL The permit is for a new wellbore segment of existing well ,~~-~.a~s'r~. , (If last two digits in permit No. , API No. 50- - - API number are between 60-69) Production should continue to be reported as a function of the original API number stated above. PILOT HOLE In accordance with 20 AAC 25.005(f}, all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name ( PH) and API number (50- - -_) from records, data and logs acquired for well SPACING The permit is approved subject to full compliance with 20 AAC EXCEPTION 25.055. Approval to perforate and produce /inject is contingent upon issuance of a conservation order approving a spacing exception. assumes the liability of any protest to the spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the Commission must be in SAMPLE no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals throu h tar et zones. Non-Conventional please note the following special condition of this permit: Well production or production testing of coal bed methane is not allowed for (name of well) until after (Company Name) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the Commission to obtain advance approval of Such water well testing ro ram. Rev: I!1 I/2008 ~ ~ [~ ^ - ~ ~ ~ +, ~ ~ ~ , , o, o ~ , o ~ ~ ~ °, g , , m , m , w ~ , y, m, - , c m 3 ~ ~ m , , ~, ~ , r!) a E. ~ c. , w ~ ~ ~ o' ~ 'u~ c. ~ y , o: 7 yam.. ~' a' , m' ~ - ~ ~ tll Q. ° « ~ a ~, ~ ~ m 3, ~ . m, ~ t , , , _, ~ _ .ai `~ ~ m 'd c, d, ~, a m c' , J ~ ~ ~ ~ fQ L, >~, m~ gym, _, , N ; , w, m ' , ~ Q O ~ ~' ' 0 y ~' ° ' z ~ .~ m ua O' - ~ ° err d, 3 ~, , ~ ~ O ~ ~ ~ V Z Qr y, 4 ~ , 0' , , , , pp, ~ ~ V p Q 2 :: ~ ~ O m c ~ ~ 4 7. 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